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ARC-FLASH

SERIES III

ANDBOOK

ARC-FLASH HANDBOOK

SERIES III

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ARC-FLASH HANDBOOK

Published by

InterNational Electrical Testing Association

ARC-FLASH HANDBOOK TABLE OF CONTENTS Verify Performance and Safety of Arc-Flash Detection Systems................................. 5 William Knapek and Mark Zeller

Electrical Safety – A Program Development Guide............................................... 10 Terry Becker

Low-Voltage Metal Enclosed Bus Duct Wetting Events............................................ 18 Dan Hook

Arc-Flash Hazard Mitigation by Transformer Differential Relay Protection................ 24 Randall Sagan and Mose Ramieh III

Safety Aspects of Breaker Protection and Coordination......................................... 29 Bruce M. Rockwell

Arc-Flash Mitigation Using Differential Protection................................................. 32 Brian Cronin

Metal Enclosed Medium-Voltage Air Switches: .................................................... 36 Condition Analysis and Hazard Awareness Scott Blizard and Paul Chamberlain

Electrical Hazard Facts.................................................................................... 38 James R. White

Make Your Electrical Safety Program Your Own, Part One: Why Won’t a Generic Program Work?................................................ 43 Don Brown

Published by

InterNational Electrical Testing Association 3050 Old Centre Avenue, Suite 101, Portage, Michigan 49024

269.488.6382

www.netaworld.org

Make Your Electrical Safety Program Your Own, Part Two: What Should be in an Electrical Safety Program?.................................. 45

Don Brown

Make Your Electrical Safety Program Your Own, Part Three: Implementation of an Electrical Safety Program................................... 48 Don Brown

Arc-Flash Analysis is Going Global.................................................................... 50 Lynn Hamrick

Arc-Rated Clothing and Electrical Hazard Footwear............................................. 53 Paul Chamberlain

Methods to Limit Arc-Flash Exposure on Low-Voltage Systems................................. 55 Scott Blizard

Why Do a Risk Assessment?............................................................................. 57 James R.White

Do I Need to Wear Arc-Rated PPE When Working Around Energized Equipment?.......................................................................... 60 Ron Widup and James R.White

Published by

InterNational Electrical Testing Association 3050 Old Centre Avenue, Suite 101, Portage, Michigan 49024

269.488.6382

www.netaworld.org

Published by InterNational Electrical Testing Association 3050 Old Centre Avenue, Suite 101, Portage, Michigan 49024 269.488.6382 www.netaworld.org

NOTICE AND DISCLAIMER NETA Technical Papers and Articles are published by the InterNational Electrical Testing Association. Opinions, views, and conclusions expressed in articles herein are those of the authors and not necessarily those of NETA. Publication herein does not constitute or imply any endorsement of any opinion, product, or service by NETA, its directors, officers, members, employees, or agents (hereinafter “NETA”). All technical data in this publication reflects the experience of individuals using specific tools, products, equipment, and components under specific conditions and circumstances which may or may not be fully reported and over which NETA has neither exercised nor reserved control. Such data has not been independently tested or otherwise verified by NETA. NETA makes no endorsement, representation or warranty as to any opinion, product or service referenced in this publication. NETA expressly disclaims any and all liability to any consumer, purchaser or any other person using any product or service referenced herein for any injuries or damages of any kind whatsoever, including, but not limited to, any consequential, special incidental, direct or indirect damages. NETA further disclaims any and all warranties, express or implied, including, but not limited to, any implied warranty or merchantability or any implied warranty of fitness for a particular purpose. Please Note: All biographies of authors and presenters contained herein are reflective of the professional standing of these individuals at the time the articles were originally published. Titles, companies, and other factors may have changed since the original publication date.

Copyright © 2019 by InterNational Electrical Testing Association, all rights reserved. No part of this publication may be reproduced in any form or by any means, electronic or mechanical, without permission in writing from the publisher.

5

Arc-Flash

VERIFY PERFORMANCE AND SAFETY OF ARC-FLASH DETECTION SYSTEMS PowerTest 2014 William Knapek, OMICRON Electronics Corp. Mark Zeller, Schweitzer Engineering Laboratories, Inc.

ARC-FLASH HISTORY Protecting workers from electrical hazards is not a novel idea. Since the first power generating station was built in 1877, the benefits and hazards of electricity have been recognized. The top engineers in the power industry have continuously worked to make electric power more economical and reliable, as well as safer. There have been many papers highlighting the hazards and possible prevention of electrical arc flash; a new focus was initiated in 1985, when Ralph Lee published the paper “The Other Electrical Hazard: Electric Arc-Blast Burns.” The National Fire Protection Association (NFPA) published NFPA 70E®: Standard for Electrical Safety in the Workplace® to document electrical safety requirements.1 It defines specific rules for determining the category of electrical hazards and the personal protective equipment (PPE) required for personnel in the defined and marked hazard zones. The United States Occupational Safety and Health Administration enforces the NFPA arc-flash requirements under its general rule that a safe workplace must be maintained. These regulations are forcing employers to review and modify their electrical systems and work procedures to reduce arc-flash hazards. IEEE 1584-2002 provides information on how to calculate arc energy and establish boundary distances for personnel when working around energized electrical equipment. IEEE 1584 provides an incident energy2 calculation method using the following formula: where:

E = 4.184 (Cf ) (En)

(1)

E is the incident energy in joules/cm2. Cf is a calculation factor (1.0 for voltages above 1 kV, and 1.5 for voltages below 1 kV). En is the normalized incident energy. t is the arc duration in seconds. D is the distance from the arc in millimeters. x is the distance exponent. As shown by (1), the energy produced by an arc-flash event is proportional to the voltage, current, and duration of the event (V • I • t). IEEE 1584-2002 concluded that arc time has a direct effect on incident energy. Therefore, reducing fault-clearing times proportionately reduces arc-flash hazards.

There are several key elements in clearing an electrical arc. The first step is detecting the flash, second is accurately determining if the flash is part of an electrical fault, third is signaling the circuit interrupting breaker, and the last is interrupting the current flow to the fault. Each step in the process contributes time to the overall time needed to clear the fault; therefore, a significant amount of research has been invested in each part. Many of the safe work practices, personal protective equipment, approach boundaries, and warning labels are dependent on the protection system that is in place to perform at the speed and sensitivity specified by the equipment manufacturer. A performance (by any of the components) that is slower than specified can dramatically increase the available incident energy. Personnel protection and procedures are based on properly working and performing equipment. Until recently, no proper test system was in place to evaluate the arc-flash detection equipment performance. Users are now able to verify not just the performance of the arc-detection equipment but also the system as a whole by including the breaker in the commissioning circuit. Although this paper only evaluates arc-flash detection systems, it is a straightforward extrapolation to include feeder and main breakers as well as communications links in the system while commissioning the arc-detection system.

TYPES OF ARC-FLASH DETECTION SYSTEMS Arc-hazard detection systems have been evaluated that are triggered from sound, pressure, current, and light, as well as predictive systems based on ion detection or thermal imaging. This paper focuses on arc-flash detection methods and leaves the predictive methodologies to present their own merits. Although an arc blast contains considerable sound and pressure waves, in the race to fastest detection, these waves are much slower than light. The fastest detection systems on the market today all use light as the primary arc-detection medium. They include the following: ●● Light detection ●● Current detection ●● Combined light and current detection Light detection systems have been commercially available for many years and have proven to be reliable and effective. Arc-flash

6

Arc-Flash

safety considerations over the last few years have elevated an interest in detecting and interrupting arc-flash incidents faster and with high security. Table I provides a general range of response times published by arc-flash detection system manufacturers. Table 1: Detection Technology in Arc-Detection Systems Detection Technology

Published Response Time

Light only

1 to 7 ms

Current only, instantaneous

24 ms

Light with current supervision

1 to 7 ms

Light and overcurrent

1 to 3 ms

Light-Only Detection Systems Light detection systems are based on the principle that during an arc-flash event, enough light will be detected by the receptor to indicate a flash. This is generally accepted as a sound principle because the amount of light given off during an arc flash is significant and contains nearly the entire light spectrum. Light is fast and relatively easy to detect.3 Generally, there are two types of light detectors. The first is a remote-mounted receiver that converts the light given off by the flash to some other form of signal that is transmitted to the tripping device. This type of sensor often uses a copper conductor for the transmission signal carrier, as shown in Fig. 1. Copper wire is common, reliable, and flexible but also has the capability to carry current in the event of contact with the bus bars or other current-carrying conductors. The second type of detector acts as a lens to collect the light produced from the flash and channel it back to a receptor in the tripping device. This channeling of the light is accomplished through fiber-optic cables (see Fig.  2). Fiber-optic cables have the advantage of not conducting electricity, thereby avoiding the installation of a conductor in the electrical gear. Fiber optic also has the advantages of electrical isolation between the receptor and the tripping device, easy installation, online complete functional testing, and choice of sensors. The disadvantages of fiber-optic cables include that they are easy to damage during installation, with either a too-tight bending radius or scarring of the fiber wall, and the possible need for special splicing tools.

Fig. 2: Fiber-optic cable and arc-flash point sensor The main disadvantage of a light-only detection system is the risk of tripping from a light source not related to an arc flash. These sources include arc-welding reflections, camera flashes, spotlights, and even light fixture failures. Any source of light exceeding the detection level in the relay will initiate a trip. Because of the very highspeed trip times of light-only systems, security is a serious concern.

Over-Current Only Detection Systems Over-current only detection schemes, although not intended specifically for this purpose, were the first arc-flash detection systems invented. Generally, they were built to protect the equipment, not the people in the area. Because they were initially installed for equipment protection, settings were normally chosen based on equipment damage, not personnel safety. As personnel safety has become a higher priority, the trip settings have been modified to provide separate levels of protection for equipment and personnel. A common practice today is to implement a maintenance switch (Fig.  3) that changes the protection settings in a relay from time-coordinated protection (equipment-level protection) to instantaneous (personnel-level protection) settings while people are working in or around the energized equipment. Although instantaneous settings can reduce the arc-flash hazard under some conditions, they can also create hazards if misapplied.

Fig. 3: Breaker control with maintenance switch

Fig. 1: Arc-flash sensor with copper wires

IEEE defines an instantaneous setting as having no intentional delay in the output.4 Notice, however, that this does not specify how fast a trip element needs to respond in order to qualify as instantaneous. This allows for significant variation in the response times of instantaneous elements between manufacturers and even from model to model of protective relays. All instantaneous trip elements are not created equal. Instantaneous trip response times are dependent on the magnitude and duration of the overcurrent. Internal

7

Arc-Flash signal filtering and the speed of the processing logic within the relay result in variations in instantaneous responses. Historic testing has found that traditional instantaneous elements have a pickup time of two cycles. When protection engineers build protective relays, they must balance the often competing characteristics of sensitivity and security. For a protective relay, security is defined as the ability to trip when needed and not trip when not needed. Although this is a simplistic definition of security, differentiating between an overcurrent signal and noise on the input channel must be carefully considered. Protective relay manufacturers have a detailed understanding of current transformer signal variation and the effects of saturation on the current signal; this may not be true of all manufacturers of arc-flash detecting devices. Therefore, when selecting a relay to be used for arc-flash hazard mitigation, carefully evaluate each manufacturer for experience, speed, sensitivity, and security. One challenge of a current-only detection system is selecting the proper trip settings. The settings must be high enough to ignore normal variation in current, yet low enough to quickly detect an event. Instantaneous settings that are too high endanger personnel and provide a false sense of safety. For example, by changing the settings on a feeder relay from the time-coordinated delay of 0.5 seconds to an instantaneous setting of 0.12 seconds, you could assume the arc-hazard energy dropped from 29 cal/cm2 to 4.5 cal/cm2 .5 This assumes that the current remains at the calculated available fault current. If the fault current is reduced (because of higher-than-expected impedance) to below the instantaneous setting, the relay would not trip on the instantaneous element. In that case, even with a lower fault current, the available arc-flash energy would be higher than the previously calculated level and personnel working in PPE rated for the lower hazard would be in jeopardy. A second issue with this method is determining the trip time to use in the incident energy calculations. Since the trip time varies with the magnitude of the fault, the protection engineer is left without fixed time duration to use for incident energy, approach boundary conditions, safety procedures and personal protective equipment.

Light With Current Supervision Systems Any arc-detection scheme that only evaluates a single quantity has serious security concerns. One security improvement is to supervise the light detection with a current element. This system measures the current and only enables the light detection trip element if the current is above some predetermined level. This application does not monitor for a fault current; it only disables the light trip element when the current is below a preset point. Supervision systems typically recommend current enable levels just below the expected normal operating load. Setting the supervision level too high disables the light portion of the arc detection. Setting it too low removes the security benefit of current monitoring. Current supervision systems only provide a modest improvement in security during low-current conditions.

Light and Overcurrent Detection Systems Modern protection systems make full use of both overcurrent and light detection to create a scheme that is both fast and secure. Combining fault current detection AND logic manner with the light detection element, tripping only when both are present, create a very secure scheme. One of the challenges of combining the two elements is to make sure the fault detection element for the current is as fast as the light detection element. This is accomplished by using special high-speed sampling and logic to match the response times of both elements with no delay. Although there is some reduced security with the faster current detection element, the combination of overcurrent and light detection more than compensates for any sacrifice in the current security.

Consequences of Misoperation The consequences of misoperation of the arc-flash detection scheme depend on the process and arc-suppression system. When isolating the fault with a standard circuit breaker, the result of a false trip (tripping when no fault is present) can be evaluated based on the consequences of the load lost. Failure of the system to trip when a fault is present will result in normal circuit protection with the associated incident energy. If personnel working in an area with PPE expect high-speed arc detection and the system responds with slower overcurrent protection, serious injury may result. Therefore, it is imperative that the system is reliable and tested often. Self-checking systems can increase confidence and provide warning in the event of a failure before personnel enter the risk zone. Modern arc-flash systems continuously test not just the relay, but the continuity and function of the sensors as well. Some systems, rather than just isolating the faulted circuit, also provide an alternate path to ground for the fault circuit. These systems use a crowbar circuit or an arc-containment system to redirect the current. In addition to the concerns previously stated, a false trip (tripping when no fault exists) creates a strain on all the equipment in the system. Fault current, although not from a fault, is created by the system itself as it attempts to divert the system current to ground while isolating the presumed circuit.

TESTING PROCEDURES Arc-flash detection systems were tested in the configurations designated in the respective manufacturer instruction manuals. The testing was executed with the same test system and used a single arc-flash test device to generate the flash. The block diagram of the testing setup is shown in Fig. 4. The purpose of the tests was to demonstrate the performance of each type of arc-flash detection system. Testing included subjecting the systems to a light flash, an overcurrent surge, and a combination of both light and overcurrent.

8

Arc-Flash

IRIG Clock for Synchronization

Multifunction Relay Test Device

Current to Relay Trip Outputs From Relay

Arc-Flash Relay

Synchronized IRIG Flash

Flash Test Device

Arc Flash

ArcDetection Unit

Fig. 4: Test system block diagram In setting up the tests a multifunction test set was used that provided current output, IRIG-B synchronization, high speed binary/analog inputs to measure the contact response time, and binary outputs to control the IRIG-B signal to the flash. The test set also provided a DC power supply to the relays that needed power. A single-phase test set, current output, was connected to the current input of the relay. The high-speed output contact of the relay was connected to the test set. The high-speed outputs required a wetting voltage and a load so a DC relay was used as the load and 110vdc was applied. This required that the test set inputs be configured to trigger on a wetted contact.

Fig. 5: Typical test screen showing fault initiation and time to trip One of the variables in setting up the testing procedure was the use of analog adjustment knobs (shown in Fig. 6) on some of the arc-flash detection systems. Modern relays avoid this subjectivity by using digital settings to exactly program the sensitivity. The adjustment knobs on some of the systems made the sensitivity setting inexact and nonrepeatable.

The tests were set up using a state sequencer program; prefault, fault, and post-fault states were used. The flash was synchronized so that it was applied with the current at the start of the fault state. A current value above the pickup level was used in the tests that evaluated current supervision. After the first tests, it was found that the flash generator would flash with each IRIG pulse. This led to misoperations, so a binary output contact from the test set was inserted in the IRIG signal to the flash generator. This caused a delay in the activation of the flash generator, so a two-pulse delay state was inserted before the fault state. The first test performed was an overcurrent surge test or normal overcurrent event. This test included a prefault state, a IRIG-B starting state, a fault state that included the fault current and a post fault state for timing purposes. This test did not produce a flash when the current was applied. The second test was a flash without current. In this test sequence, the same set up was used but no current was applied to the relay. The third test performed was a flash and overcurrent fault applied to the relay using the same test sequences. Finally, a test was performed with nominal load current, one amp secondary, and a flash to confirm the security of the relay with current supervision. This setup was used for all the relays in the study. The timing was evaluated using the time signal view of the test set software. The beginning of the IRIG pulse to the initiation of the output contact was measured, and the results are shown in Fig. 5 and in Table 2 (later in this paper).

Fig. 6: Arc protection analog setting knob

TESTING RESULTS The response times from the tests are shown in Table 2. Overall, the systems tested matched the actual performance with published specifications from the manufacturers. Each system was tested for possible false trips by subjecting the systems to flashes of light without the corresponding current, as well as current without light. Detection Technology

Device

Published Response Time

Actual Response Time

A

Light only

2µ

Particles >25 µ

1

41915

88

476.3

2.7

0.8

1.1

526000

60900

2

340

20

17.0

0.2

0.1

0.2

26900

176

3

5796

26

222.9

0.4

0.0

0.1

27100

1990

Table 5: DGA, Metal, and Particle Count Data for GM4S

10

Insulating Oils

The ratings for these tanks are as follows: Tanks 1, 2 and 3: ●● Condition Code: 1 ●● Action: Remove from service Immediately ●● Remedial Action: Replaced components that were either broken or those not operating properly

Fig. 10: Interrupter Tank 1, Intermediate and Crank Arm Contacts

Fig. 11: Interrupter #5 Intermediate Contact Findings: ●● Lack of contact compression and damaged intermediate contacts ●● Numerous line switching operations due to recent line construction ●● Coking and wear found in all tanks. Tanks 1 and 3 were the most severe.

CONCLUSION Analytical testing of mineral oils used in oil circuit breakers is a cost effective way to identify necessary condition-based maintenance. Failure and forced outages can be minimized by implementing an effective oil circuit breaker maintenance program resulting in significant savings. This paper presented information

on the key analytical tests used to identify abnormal conditions within oil circuit breakers and as detailed by the three case studies. Strong correlation exists between analytical testing techniques and findings in the field. By examining analytical test data, effective inspection and maintenance intervals can be established along with resampling frequencies.

REFERENCES 1

“ IEEE PES Circuit Breaker Tutorial”, Pittsburgh, PA, July 24, 2003.

2

“ Annual Book of ASTM Standards Volume 10.03”, 236 pp, 2012.

David Koehler received his Bachelor’s Degree in Chemistry from Indiana University and obtained his M.B.A. He is the Business Development Manager-Professional Services for Doble Engineering Company. He has 20 years of experience in the testing of insulating liquids and management of analytical laboratories. He has provided numerous technical presentations and published technical articles within the power industry. David is a member of the ASTM D-27 Technical Committee on Electrical Insulating Liquids and Gases. In 2011, David was an Executive Committee Member of the Indiana American Chemical Society. In 2019-2020 David will serve as the IEEE Region 4 Director, while also serving on the Board of Directors for IEEE. Paul Griffin is Doble Engineering Company’s Vice President of Consulting and Testing Services. He has been with Doble since 1979 and prior to his current role has held various positions including Laboratory Manager and Vice President of Laboratory Services. Since joining Doble, Mr. Griffin has published over 50 technical papers pertaining to testing of electrical insulating materials and electric apparatus diagnostics. He is a Fellow of ASTM and a member of Committee D-27 on Electrical Insulating Liquids and Gases. He was formerly ASTM Subcommittee Chairman on Physical Test, ASTM Section Chairman on Gases-in-Oil, and the Technical Advisor to the U.S. National Committee for participation in the International Electrotechnical Commission, Technical Committee 10 and Fluids for Electrotechnical Applications. Mr. Griffin is a member of the IEEE Insulating Fluids Subcommittee of the Transformer Committee. Rick Youngblood worked for Cinergy Corporation (now Duke Energy) as the Supervising Engineer in Substation Services before taking early retirement in May 2004. Rick joined American Electrical Testing Company in August 2004 as Regional Manager, heading up its Midwest office located in Indiana. After obtaining his NETA Level 3 certification, he and his crew performed maintenance and testing in utility and industrial environments. In 2010, Rick moved to his present position as Principal Engineer in the Client Service group for Doble Engineering, where he shares client issues for the western half of the Great Lakes Region 5 with Jael Jose.

Insulating Oils Lance Lewand is the Laboratory Director for the Doble insulating materials laboratory and is also the product manager of the Doble DOMINO, a moisture-in-oil sensor. The Insulating Materials Laboratory is responsible for routine and investigative analyses of liquid and solid dielectrics for electric apparatuses. Since joining Doble in 1992, Mr. Lewand has published over 75 technical papers pertaining to testing and sampling of electrical insulating materials and laboratory diagnostics. Mr. Lewand received his Bachelors of Science degree from St. Mary’s College of Maryland. He is actively involved in professional organizations including the American Chemical Society and ASTM D-27. The authors wish to thank Ameren Missouri for the case study data and pictures.

11

12

Insulating Oils

NICHE MARKET – DATA CENTER MAINTENANCE – PART 4 – ELECTRICAL DISTRIBUTION SYSTEM MAINTENANCE NETA World, Fall 2013 Issue Lynn Hamrick, Shermco Industries This article is Part 4 of a 4-part series on data center maintenance. In Part 3, we discussed electrical maintenance activities associated with the key electrical systems for most data centers: UPS systems and their battery systems and the backup generation systems. In Part 4, we will discuss maintenance activities associated with the electrical distribution system that ties all of these key systems together: cables, transformers, breakers, and automatic transfer switches. This article will focus on electrical tests that should be performed during scheduled predictive and preventive maintenance activities.

PREDICTIVE MAINTENANCE The Predictive Maintenance activities below will be the basis for implementing a condition-based maintenance program. These activities are to be performed while the facility is operating. To obtain maximum benefit from these inspections, samples, and surveys, knowledge of the equipment, systems, and indications of potential failure modes is required.

Physical Inspections Physical Inspections should be performed on high and low voltage equipment. The inspector should be aware of the visual evidence associated with installation errors, equipment subassembly failures, poor equipment condition, overheating, and corona. Further, where digital readouts of electrical parameters are available (i.e., solid-state protective relays, trip units, power-quality meters, etc.), the inspector should regularly monitor status and other available data for system condition. In addition, periodic walk-throughs should be performed to evaluate general equipment condition and changes to operating parameters. For some equipment, a periodic maintenance route should be developed to ensure that an adequate physical inspection is performed: ●● Transformers. Most liquid-filled transformers have liquid level, temperature, and pressure indicators. These should be monitored periodically to ensure that the transformer is operating within acceptable parameters. For temperature, the high temperature indicator should be noted and reset. For pressure, the value should always be slightly positive. In addition, the route should include inspections for oil leaks and spills. ●● Breakers. Protective settings for breakers should be periodically reviewed to ensure that the appropriate settings are in place.

Oil Sample Analysis Oil sample analysis, including a dissolved gas analysis, should be performed on all liquid-filled transformers and oil circuit breakers. To obtain maximum benefit from this analysis, a qualified person should pull the samples and the samples should be sent to a qualified laboratory for analysis. As a minimum, the analysis should include testing for dielectric breakdown, acid neutralization number, interfacial tension, color, moisture, and dissipation or power factor. Suggested quality limits for mineral oil are provided in IEEE C57.106-1991 Guide for Acceptance and Maintenance of Insulating Oil in Equipment, Table 5. Additionally, the dissolved gas analysis (DGA) should be performed in accordance with ASTM D3612/IEC 60567. Suggested key gas limits are provided in ANSI/ IEEE C57.104. Once the key gas limits are exceeded, the ratios of many of the key gases provided through a DGA are indicative of the type of issue you may have internal to the transformer. The suggested key gas ratio limits are provided in the attached Table 1.

Table 1: Key Gas Ratio Limits for Service Aged Insulating Fluids The ratio of CO2/CO is sometimes used as an indicator of the thermal decomposition of cellulose. The rate of generation of CO2 typically runs 7 to 20 times higher than CO. Therefore, it would be considered normal if the CO2/CO was above 7. If the CO2/CO ratio is 5 or less, there is probably a problem. If cellulose degradation is the problem, CO, H2, CH4, and C2H6 will also be increasing significantly. At this point, it is recommended that additional furan testing be performed. If the CO2/CO ratio is 3 or under with increased furans, severe and rapid deterioration of cellulose is occurring and consideration should be given for taking the transformer out-ofservice for further inspection.

13

Insulating Oils When cellulose insulation decomposes due to overheating, chemicals, in addition to CO and CO2, are released and dissolved in the oil. These chemical compounds are known as furanic compounds, or furans. In healthy transformers, there are no detectable furans in the oil (1500 ppb having a high risk of insulation failure.

Infrared Inspection Infrared Inspections, or thermographic surveys, should be performed on high- and low-voltage equipment. The survey will include surveying electrical equipment for thermal differences or high limits, which are indicative of problems that could result in equipment failures. Suggested actions based on temperature rises are available in ANSI/NETA MTS-2011. This type of survey is very useful in identifying loose or bad connections and terminations and overloading conditions and should be applied to electrical equipment (i.e., breakers, transformers, automatic transfer switches, buses, and cable terminations). Additionally, this survey is useful in confirming liquid-filled transformer level.

Ultrasonic Emission (UE) Surveys UE surveys should be performed on high-voltage equipment, only. The survey will include surveying electrical equipment for ultrasonic variations which are indicative of problems that could result in equipment failures. This type of survey is very useful in identifying possible corona and arcing conditions. A UE survey is considered an optional test that can be performed in support of further investigation of identified issues.

Partial Discharge (PD) Testing The integrity of high-voltage insulation systems can be assessed through partial discharge testing and analysis on-line. PD is an electrical phenomenon that causes insulation deterioration. Partial discharge can be described as an electrical pulse or discharge in a gasfilled void or on a dielectric surface of a solid or liquid insulation system. This pulse or discharge partially bridges phase-to-ground insulation or phase-to-phase insulation in an electrical apparatus. PD testing and analysis can be the foundation for a viable predictive maintenance program for high-voltage equipment. Periodic use of the technology allows the identification of problem areas with higher voltage terminations and splices prior to failure.

PREVENTIVE MAINTENANCE The preventive maintenance activities below should be scheduled and performed in conjunction with a condition-based maintenance program. These activities are to be performed during a planned outage while associated portions of the data center are shutdown. To obtain maximum benefit from these electrical tests, knowledge of the equipment, systems, and indications of potential failure modes is required. It is important that job plans and

procedures indicate acceptance criteria to the inspector and that as-found and as-left reports are recorded. To determine test voltage levels and the acceptability of the electrical test results, it is recommended that either manufacturer’s recommendations or ANSI/ NETA MTS-2011, Standard for Maintenance Testing Specifications for Electrical Power Equipment and Systems, recommendations are used.

Cables ●● VLF Tan Delta Test. Very low frequency (VLF) testing can be performed to verify a cable’s ac voltage withstand capability. It is simply a pass/fail ac stress test using an instrument with a 0.1 HZ (or lower) output frequency rather than 50/60 Hz. A tan delta test is a diagnostic test that indicates the degree of cable insulation degradation. Rather than using only a VLF instrument to perform a go/no-go proof test, the tan delta unit, used in conjunction with a VLF source, permits the user to grade the deterioration level of many cables in order to prioritize replacement or rejuvenation, or to determine what additional tests may be useful. It is recommended that the voltage levels presented in IEEE 400.2, IEEE Guide for Field Testing of Shielded Power Cable Systems Using Very Low Frequency (VLF), be used for this test.

Transformers ●● Dielectric Absorption Ratio (DAR)/Polarization Index (PI). DAR and PI tests are used for determining insulation condition for apparatus with complex insulation systems, such as transformers. The polarization index is performed to judge the rate of disappearance of charging and absorption currents. The DAR is the ratio of the insulation resistance at the end of one minute to that at the end of 30 seconds at a constant voltage. The PI is a ratio of the insulation resistance at the end of 10 minutes to that at the end of one minute at a constant voltage. For transformers, a polarization index of greater than 1.0 is acceptable. However, the higher the value, the better. ●● Power Factor/Dissipation Factor. This test measures the insulation’s ac dielectric loss (consists of dielectric absorption, conductivity, and ionization loss components) and power factor and provides a measure of the overall condition of an apparatus’s insulation system. The power-factor test is the most effective field test for evaluating the condition of an oilfilled transformer’s solid insulation and its bushings. The test is useful in detecting moisture, contamination, and/or insulation deterioration. Test data is typically evaluated by comparison to prior results from similar equipment and/ or databases. One of the largest equipment power-factor databases and related technical information is that acquired and maintained by Doble Engineering Company. Because of this it is often referred to as Doble testing.

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Insulating Oils

●● Winding Resistance. Winding resistance measurements for transformers are used to determine if the connections are correct and if there are any severe mismatches or opens within the transformer. Electrical testing instruments are basically digital low-resistance ohmmeters (DLROs). Regardless of the transformer configuration (i.e, either wye or delta), the winding resistance measurements are made phase-to-phase and are considered acceptable if all readings are within 1 percent of each other. Because of the enormous amount of energy that can be stored in a magnetic field, precautions should be taken before disconnecting the test leads from the transformer that is under test. Never remove the leads during the testing process and always allow for enough time to completely discharge the transformer being tested. Large transformers can require several minutes to discharge. ●● Turns Ratio Test. The purpose of a transformer turns ratio (TTR) test is to measure the turns ratio and exciting current of windings in transformers. A transformer’s turns ratio is equal to the ratio of turns of wire in the primary winding of a transformer to the number of turns of wire in the secondary winding. Deviations in turns-ratio readings indicate problems in one or both windings or the magnetic core circuit of a transformer. The ratio measured with this test includes the losses normally found in the transformer, which will result in a ratio greater than that of the physical turns but reflects the real voltage ratio expected for the transformer. ANSI Standard C57.12 specifies that turns ratio be no more than 0.5 percent from nameplate rating of the transformer.

Breakers ●● Insulation Resistance. The purpose of measuring insulation resistance is to determine if the equipment’s insulation system is suitable for operation or even for a high potential test. An insulation resistance test set (typically referred to as a Megger) must be used to perform this test. This test should be performed phase-to-phase and phase-to-ground with the breaker contacts closed and across the open contacts. Evaluating and trending insulation resistance is important in identifying deterioration as quickly as possible so you can take the necessary corrective measures. Testing voltages and acceptable test results are provided in the attached Table 2.

Table 2: Insulation Resistance Test Values Electrical Apparatus and Systems A cautionary note, insulation resistance measurement is temperature sensitive; therefore, ambient temperatures should be considered when evaluating test results. A suggested temperature correction table is included in ANSI/NETA MTS-2011. ●● Contact/Connection Resistance. The purpose of measuring contact and connection resistance is to verify that contacts, or associated circuit segments, in the electrical distribution system are at a low resistance. A digital low-resistance ohmmeter (DLRO also known as a Ductor) must be used to perform this test. This test should be performed from line-to-load terminals of the contacts with the breaker closed. The values should be within 50 percent of each other and comparable to similar devices. The resistance values vary with the size of the breaker with typical values of less than 100 microhms, with some manufacturers suggesting values of less than 30 microhms. Evaluating and trending contact resistance is important in identifying contact deterioration as quickly as possible so you can take the necessary corrective measures. ●● Vacuum Bottle Integrity. For medium- and high-voltage vacuum breakers (>1000 V), overpotential tests have proven successful in detecting vacuum bottle integrity. The test should be performed across each vacuum bottle with the contacts in the open position. Additionally, this test should only be performed after an insulation resistance test has been performed successfully to ensure adequate contact separation prior to performing an overpotential test. Use of ac high potential test sets is typically recommended by manufacturers. If a dc high potential test set is used, a full-wave rectified model is to be used; a half-wave rectified test set can potentially create peak voltages which can damage the vacuum bottle. ●● Electrical Operability Test, Adjustment, Calibration. Electrical operability testing shall be provided for each device which can be electrically operated. This means that for

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Insulating Oils breakers, switches, starters, etc., which can be operated using remote devices (i.e., are equipped with shunt trips, protective relays, or trip units) the electrically operated circuitry should be tested for operability. For protective relays and trip units this will require the use of test equipment which either primary injects (the tested circuitry includes associated instrument transformers, control wiring, and trip unit) or secondary injects (the trip circuitry only includes the control wiring and trip unit) currents and/or voltages to simulate various trip conditions for each applicable operating mode. It is preferred that device-specific, time-current-curves (TCCs) for the equipment being tested are developed and used to evaluate the acceptability of the results. Where a power system study has been performed using a modeling software (i.e., SKM), the device-specific TCCs should be readily available. When no manufacturer’s recommendations are provided, information available in ANSI/NETA MTS-2011 can be used for evaluating breaker performance. Care shall be taken to note and reinstall appropriate set points, adjustments, and calibration information for each device prior to placing back in service. ●● Mechanical Operability Test, Adjustment, Lubrication. Mechanical operability testing shall be provided for each device. For electrical equipment with mechanical components, most mechanical problems are due to the environmental conditions, improper or lack of cleaning, and improper lubrication of the device. Cleaning activities should include complete removal of existing lubricating greases and deposits from moving parts and contact surfaces. Cleaning surfaces should not include the use of solvents which may leave residues on surfaces or the use of abrasive cloths (i.e., emery cloths, etc.) due to the potentially harmful effects on the surfaces. In most cases, the electrical contact surfaces are plated and using abrasive materials to clean the surfaces may remove or damage that plating. Application of a very thin layer of new lubricant should be provided in accordance with manufacturer’s recommended instructions using recommended lubricants. Where no lubricant recommendations are specified by the manufacturer, use Mobilgrease 28® on both the contact surfaces and the hinge points of the device. Further, blade alignment, blade penetration, and the mechanical open/trip and close operations should be verified. Most manufacturers recommend opening and closing these devices at least annually as part of the preventive maintenance activities.

Automatic Transfer Switch (ATS) Automatic transfer switches are installed in a data center to transfer the electrical loads from the normal power sources to the standby and emergency power sources upon failure of normal power. The ATS must transfer and retransfer the load automatically. Maintenance programs for transfer switches include checking of connections, inspection or testing for evidence of overheating and excessive contact erosion, removal of dust and dirt, and re-

placement of contacts when required. The maintenance procedure and frequency should follow those recommended by the manufacturer. Automatic transfer switches should also be operated periodically. The periodic test consists of electrically operating the transfer switch from the normal position to the emergency position and then a return to the normal position.

SUMMARY For data centers, the electrical distribution system ties together the key electrical systems and consists of cables, transformers, breakers, and automatic transfer switches. Maintaining this distribution system should include the performance of scheduled predictive and preventive maintenance activities. The predictive maintenance activities should be the basis for implementing a condition-based maintenance program. These activities are performed while the facility is operating. To obtain maximum benefit from these inspections, samples, and surveys, knowledge of the equipment, systems, and indications of potential failure modes is required. The preventive maintenance activities should be scheduled and performed based on and in conjunction with the condition-based maintenance program. These activities should be performed during a planned outage while associated portions of the data center are shut down. To obtain maximum benefit from these electrical tests, knowledge of the equipment, systems, and indications of potential failure modes is required. It is important that job plans and procedures indicate acceptance criteria to the inspector and that as-found and as-left reports are recorded. To determine test voltage levels and the acceptability of the electrical test results, it is recommended that either manufacturer’s recommendations or ANSI/NETA MTS-2011, Standard for Maintenance Testing Specifications for Electrical Power Equipment and Systems recommendations are used. Lynn Hamrick brings more than 25 years of working knowledge in design, permitting, construction, and startup of mechanical, electrical, and instrumentation and controls projects as well as experience in the operation and maintenance of facilities. He is a Professional Engineer, Certified Energy Manager, and has a BS in Nuclear Engineering for the University of Tennessee.

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Insulating Oils

TRANSFORMER DIAGNOSTIC AND CONDITION ASSESSMENT USING LIQUID INSULATION TESTING PowerTest 2013 Mel Wright, LICA Transformer Consulting

ABSTRACT Transformer diagnostics using fluid testing is a critical tool for utility maintenance of large power transformers. Unfortunately common sampling procedural errors, sampling at the wrong time, improper sample containers, collected samples undergoing numerous or large temperature changes before arriving at the lab and lax testing procedures prevent consistent and reproducible lab results. Often clients are perplexed by lab data, especially dissolved water and dissolved gases that “seesaw” up and down from test to test. These variable lab results are confusing at best and prevent accurate diagnostic trending of data. Accurate historical test data that can be trended is the foundation of fault risk assignment and condition assessments. Erroneous and expensive maintenance decision can be made or critical problems may be overlooked due to “lack of faith in the lab”.

There are 6 components of a valid and actionable condition assessment using liquid insulation testing (see Graphic 1). ●● Record and track the equipment’s operational parameters at time of sampling. ●● Proper sampling procedures; Critical do’s and don’ts. ●● Fluid Quality “FQ” tests. (Dielectric, dissolved water, IFT, etc.) ●● Furan analysis and calculation of paper strength and aging rate. ●● Dissolved Gas Analysis (DGA). ●● Proper application of DGA key gases, rates of formation, IEEE or IEC Fluid guides.

This brief presentation will address specific issues critical to valid dielectric fluid test results and discusses 6 components necessary to make valid and actionable transformer condition assessments.

THE SIX COMPONENTS OF VALID AND ACTIONABLE CONDITION ASSESSMENT A common misperception is that dissolved gas analysis (DGA) is the sole test for detecting and identifying internal issues in transformers, load tap-changers (LTCs) and other Liquid Filled Electrical Equipment (LFEE). Frequently consultants are sent a DGA lab report or large spreadsheets of DGA data and little else to evaluate the condition of transformers. The reasons for concern are numerous but some examples are minor or major changes in one or more gases or a computer generated diagnostic comment on the laboratory report. I’ve seen perfectly operating transformers show up at a transformer test and repair facility based only on a laboratory computer generated DGA condition assessments. The key to preventing this type of diagnostic error and thousands of dollars in unnecessary expense, is an understanding of the relationship of equipment operating parameters on the concentration changes of dissolve gases and dissolved water in the fluid. Hot oil holds more water, gases and other soluble components. As oil heats it expands and in units with head space, the pressure increases driving volatile gases into the oil thus increasing the concentration detectable gases in oil analysis. There is a diagnostic relationship between loading, temperatures, pressures and changes in the fluid quality, furan and DGA tests results.

Graphic 1: LICA’s six components of condition assessment.

Recording and tracking equipment’s operational parameters The observation and recording of the transformers operating parameters is a critical part of the condition assessment. The collection and comparison of loading levels, headspace pressure, oil level, cooling system status as well as the top oil, winding and ambient temperatures form the foundation of condition assessment. Abnormal temperatures, pressures or cooling system operations provide the first confirmation of normal or abnormal conditions. This information along with any external events such as power surges, tripped protection systems, abnormal loading operations provide information that will assist in validation of laboratory test data. For example a decrease in loading should be reflected in a decrease in the oil and winding temperatures, reduction in headspace pressure and a decrease in the volatile DGA gases detected

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Insulating Oils in the oil. When the DGA results, dissolved water content and furans tests are evaluated the operating parameters and changes are used to validate any changes in the lab test results.

sulation of your transformer with high water or contaminated fluid it is extremely difficult to undo the effects. (DGA, FQ and Furans)

When a client supplies a set of DGA test data with a lab generated IEEE condition code of 3 or 4, often my first request is for the a list of the operating parameters at the time of each DGA sample taken. Often the client has never considered colleting this data and nearly as often the only time they test the fluid is after a suspected event. Unless a particular key gas is extremely elevated indicating a failure has already occurred, it can be difficult to detect or quantify conditions in time to prevent a failure. The goal of liquid insulation testing is to detect liquid and solid insulation contamination, oxidative degradation, operation errors, harmful external events or internal defects at the earliest stages. Frequently the maintenance required to prevent a major loss of equipment or production is quick and inexpensive when identified at a very early stage.

●● Test the fluid as it is being vacuum treated, filtered and pumped into a transformer. The purpose is to validate that the processor has not contaminated the fluid in some manner such as residual fluid in the system or poor quality hoses that leach contaminates into the fluid. (DGA, FQ)s

PROPER SAMPLING PROCEDURES; CRITICAL DO’S AND DON’TS

●● During the first month: DGAs at weekly intervals to detect manufacturing defects, loose contacts and many other defects that will show up at full loading during this time period.

The Sampler Sampling of dielectric fluids requires a trained person who understands the effects of sampling procedures on the sample integrity. The sampler has the largest effect on the accuracy of the representative sample and thus the reproducibility of sample results. It is the sampler who has the first set of eyes on the equipment, the environment, the operational condition of the transformer. It is the sampler that determines how to obtain a representative sample of fluid based on the equipment’s load and sampling history. It is the sampler who collects the proper amount of fluid, in a manner preventing the loss or gain of diagnostic constituents and in the proper sample container. Training is important.

Sampling Program The sample program should be a combination of time based and operational changes. One of the more frequent question is how often or when to sample and what type of sample to take. Unfortunately this has a lot of “it depends” associated with the answer. What is the class and size of the transformer? What is the loading, the type of load and is the unit critical to the business. A detailed guide is beyond the scope of this presentation but for large power transformers but in general the following is the minimum. The following suggested sampling program is for transformers that are operated at a near constant loading level. For seasonally loaded (irrigation) or highly variably loaded units that may be loaded only Monday thru Friday and on-line, No-load during the weekend, see the suggest plan that follows. Constant Load Units: ●● Test the fluid while still in the tanker. Do not process or use unless it passes all ASTM minimums standards for new dielectric grade fluids. One you contaminate the cellulose in-

●● Between 24 to 72 hours after filling and before energizing, retest to validate that the fluid meets industry standards (IEEE or IEC) for new fluid in new equipment. (DGA) ●● After the transformer has been energized at load for 24 to 72 hours, retest. The object is to detect contaminates that the circulating oil has picked up in the radiators, pumps and elsewhere in the transformer. This validates that the tank was clean, dry and free of debris. (DGA and FQ).

●● Monthly DGAs for the next 5 months, then at 9 months. ●● At 9 months perform DGA. ●● After one year of on-line operation test Furans, Inhibitors, Fluid Quality and DGA. This will validate the oil preservation system, the quality of the cellulose insulation, the fluid quality and any issue that may cause premature aging or oxidation of the fluid and insulation. If the unit has been operated at it typical loading level and frequency during this first year then this data can be used as a baseline indicator of expected annual changes and rates of gas formation. ●● After the first year: Testing frequency and types of fluid tests performed are determined by loading levels, type of load supplied, operational changes and external events that may have affected the transformer. Seasonal or highly variably loaded units: ●● Seasonally loaded like irrigation units that are loaded May to September then off-line during the winter. ○○ Take at least two (2) samples during the loaded season. For example one week after the unit reaches full loading, take FQ, DGA and Furan samples. Repeat just prior to the end of the season. These samples are used to compare rates of for diagnostic interpretation. ○○ Do not try to compare samples taken with unit off-line or very lightly loaded to the result obtained during full loading. ●● Weekly loaded units, such as a factor in operation Monday to Friday. Take samples in the middle of the work week, such as Tue, Wed. or Thurs., where the loading and oil temperatures are at constant levels. Only take and compare samples taken

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Insulating Oils during the same time period, with nearly the same loading levels and top oil temperatures. This will provide the best consistency in dissolve water and DGA results, usable in creating a valid diagnostic condition assessment.

REPRESENTATIVE SAMPLE; DEFINITION AND FLUSHING REQUIREMENT For the sample to provide the necessary diagnostic information to make timely and valid condition assessments the sample taken must have been in circulation through the core, coils and radiators of the unit. In highly loaded units this only requires flushing 500 mls (pint) of fluid from the sampling valve. For transformers that are lightly loaded or on-line no load, it can be a challenge to obtain a sample that is not “dead oil” since the fluid is only slightly circulated or not in circulation. The general guide line is to flush several liters (quarts) of fluid from the large end cap valve. Obtaining a representative sample is the key to reproducible lab results which is the foundation of valid fluid evaluation and internal fault detection. Once the sample value has been sufficiently flushed to remove “dead oil” in or near the valve a representative sample can be taken.

moisture. (See photo #1) A common error is to let the oil free fall into the container which entraps air and can cause false high dissolve water results. Fill the 1 liter (quart) glass bottle to with-in one (1) inch of the bottle neck. ●● Perform a visual examination of the sample collected before proceeding with the DGA or additional samples. Examine the sample for free water or plating out of water (looks like small silver beads on the container walls), sediment and small clear fibers suspended in the fluid. This is one of several reasons for taking the FQ sample in a glass bottle and not plastic. Plastic containers prevent this initial examination of the sample. If free water, sediment or suspended fibers are observed, re-flush the valve with twice the initial flush volume and resample in a new, clean glass bottle. Label as Re-sample and submit both samples to the lab. ●● Prepare to take the DGA sample.

PROPER SAMPLING AND COMMON SAMPLING ERRORS This session is designed to point out the critical points and common procedural errors I’ve observed laboratory or utility personal make. The typical fluid quality (FQ) errors cause increased dissolved water results and addition of particles causing decreased dielectric strength. The errors in DGA sampling cause the loss of some Hydrogen (H2) and an increase in Oxygen (O2) ppm. Methane (CH4) and Carbon Monoxide (CO) may also be reduced in the sample due to sampling errors. ●● Check head space pressure gage for positive pressure. Do not open valve if there is negative pressure which will cause air bubble to be drawn into the unit. Follow additional ASTM D923 safety procedures as well as OSHA high voltage requirements. ●● Clean the valve of dirt, oil or rust. Do not use solvents to clean the valve. ●● Flush the appropriate amount of flush fluid from the large end cap, not from the small sampling port. High volume flushing is required to remove all the dead oil from the valve. Flushing from the small sample port cannot achieve the desired flow rate necessary for complete flushing. This is especially important for lightly loaded, large transformers. ●● Attach 1/4 inch I.D. PVC tubing to the sampling port with sufficient length to reach the bottom of the glass (preferred sample material) sample container. It is important for the tubing to touch the bottom of the container to prevent splashing which entraps atmospheric air in the sample with associated

Photo 1: Tubing reaches bottom of sample container to prevent splashing.

DGA SAMPLING ●● Never re-use tubing between different transformers and especially between LTCs and transformers due to the risk of acetylene (C2H2) carry over. ●● To quickly obtain a bubble free sample, disassemble the syringe, start a flow of oil from the tubing, wet the syringe plunger and the inside of the syringe barrel with oil, reassemble and then connect the tubing to the top port of the 30way stopcock on the syringe. (See Photo 2) The oil creates a seal between the barrel and plunger, preventing small air bubbles from being drawn into the sample when filling. ●● Connect a waste tube to the side port of the 3-say stopcock, orient the syringe vertically with the stop cock up, and open the valve to the appropriate position to fill. DO NOT PULL on the plunger. The pressure of the oil will push the plunger, filling the syringe. (See Photo 3). If pin head size bubbles are

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Insulating Oils observed, expel out of the waste (side) port. If a bubble larger than a marble is observed, expel all oil and refill. ●● After filling the syringe, check the stop cock making sure it is in the closed position and the luer fitting is tight before placing in the shipping box. ●● Correctly and completely fill out the data sheets making sure you have collected all of the equipment operating parameters. (Loading %, Temps, Pressure, etc.)

Photo 2: Disassemble and coat with oil.

Photo 3: Hold vertical while filling syringe.

FLUID QUALITY “FQ” TESTS Fluid quality test are a set of tests that confirm that the fluid is capable of performing its primary function (heat transfer and insulate), if the fluid is new or aged/oxidized and several physical tests to identify the type of fluid. The fluid quality tests are often broken down into 3 categories.

FURANS, DEGREE OF POLYMERIZATION “DP” OF PAPER Chendong in the early 1960’s discovered a relationship between Kraft paper (55̊ᵒC rise paper) cellulose degradation, furan production and concentration in mineral oil. Paper is composed of millions of long polymers of glucose molecules called cellulose. The longer the cellulose, measured in degree of polymerization (DP), the greater the mechanical strength of the paper. As paper degrades due to high heat and high moisture causing breakage of cellulose bonds, with each bond cleavage a furan molecule is formed. Chendong’s challenge was to find a non-invasive method to evaluate the mechanical strength (Degree of Polymerization) of winding insulation using the formation of furans. His research lead to the use of Furans in oil concentration, specifically 2FAL, as an excellent tool in the diagnostic evaluation of Kraft (55C rise) paper (his original formula) and TUK (65C rise) paper using the modified Chendong equation. In addition he developed a formula for estimating the “Apparent Age” of the cellulose based on the calculated DP from the 2FAl concentration. I’ve found that the two formulas, calculated DP of the TUK and the Apparent Age of the cellulose are invaluable in identifying abnormal loading levels or the effects of harmonics on the life of the cellulose. Comparing the ratio of Apparent Age to the actual “On-line with normal loading” or Chronological age of the transformer provides a valid tool in identifying abnormal heating of the windings. (See Chart 1: Apparent Age verse On-Line Age). Comparison of the over-all degradation of the cellulose insulation using furans to the formation of DGA detected Carbon Monoxide (CO) due to localized burning/charring of cellulose is an important diagnostic tool to discriminate the type, cause and location of cellulose degradation.

●● Critical tests: Dielectric, water, visual. ●● Oxidation (ageing) tests: Neutralization number (acid), color (ASTM scale) and interfacial surface tension (IFT), oxidation inhibitors. ●● Physical tests: Specific gravity, viscosity, refractive index, pour point. Hot oil coupled with excess oxygen (O2) and or water (H2O) content will oxidize (age) faster than oil at the same temperature having low O2 and H2O levels. Oxidized components formed in the oil are detected by a combination of the three oxidative test listed above. They also attack the cellulose winding insulation causing paper degradation (see Furans). Oil that is over heated with excess oxygen increases in color while some of the oxidized products are acidic (increasing neutralization number) and chemically polar (decrease in IFT). Thus the three tests: Color, acid, IFT have a unique relationship in determining the oxidative state of mineral oil. As oxidative degradation increases the color and neutralization number increase while the IFT decreases.

DISSOLVED GAS ANALYSIS (DGA) The identification, detection and quantitation of gases produced from various liquid insulating fluids at specific heat energies is the single most important diagnostic tool in all liquid filled

20 electrical equipment (LFEE). From the introduction of oils as a cooling medium in transformers the production of gases was known to be of diagnostic value. The introduction of Gas Chromatography in the identification and quantitation of gases in the early 1960’s has transformed the detection of transformer faults and condition assessments. The understanding of the key gases formed at specific temperatures and the ratios of key gases formed by specific fault types has provide a means of identifying incipient faults before failure. Coupled with a detailed understanding of the construction and loading operations of a transformers allows DGA experts to evaluate not only internal defects, operational errors and some external faults but to assign a degree of risk suspected fault. Some examples are the generic rates of formation and individual gas concentrations found in IEEE C57.104, IEC guides and other risk assessments tools. One of the most accurate DGA risk assessment tool is the “Factor 10” rate of formation calculation and risk table. The formula was created by GE Pittsfield Large Power Transformer lab in the early 70’s as a go/no-go factory heat run tests. The GE Denver Liquid Insulation Laboratory created a six level risk assessment table which proved to be highly accurate in classifying transformer failure risks and action plans. IEEE published the formula in the 1991 revision of C57.104. (See formula below) and modified it to use liters in the 2008 revision. IEEE C57.104, Table 3 guide is the accepted guide in North America for action plans based on an idealized 10,000 gallon transformer. I’m presenting the “Factor 10” risk assessment guide lines for discussion and hopefully many of you will try it out for a few years to see how it works for you. (See the power point presentation for the risk assessment guide.) The key to the success of the GE formula and the “Factor 10” Risk Assessment guide is the inclusion of a correction factor for the volume of fluid in the transformer. This method is far superior that the “normalization” of gases in real transformers to the idealized 10,000 tank that had been used for a number of years. For discussion, let’s compare two transformers, one with 10,000 gallons of oil and the other with 1,000 gallons of oil. If each had the same fault, with the same surface area, time of fault and same heat generated, then the formation of gases will be identical in each transformer. However the gases will be dissolved in different volumes of oil. The difference between the two units is a factor of 10 and thus the concentration in ppm of gases will be 10 times greater in the 1,000 gallon unit than in the 10,000 gallon unit. The rates of formation of TDCG will follow this ratio. The IEEE Table 3 guide does not provide a means to adjust the condition codes or action plans to a real transformer. The “Factor 10” formula adjusts for the volume allowing the risk and action plans to adjust to any size or class of transformer. “Factor 10” Rate of formation formula: Rate of TDCG = [(TDCG2 – TDCG1) (V) (10-6)] / [(7.5) (number of days between tests)]

Insulating Oils - Rate = Cubic feet of combustible gases per day. - TDCG1 = TDCG in ppm on first test date. - TDCG2 = TDCG in ppm on second test date. - V = volume of oil (Gal): (1 liter = 0.26417 US gallons, 3.78541 liters = 1 US Gallon)

PROPER USE OF DIAGNOSTIC TOOLS, GUIDES AND TRANSFORMER OPERATIONAL PARAMETERS TO CREATE A VALID AND ACTIONABLE CONDITION ASSESSMENT An expert in transformer diagnostics and condition assessment can use the 6 components as follows: ●● Key Gas or Duval’s Triangle diagnostic tool to identify the type of fault. ●● Use of the “Factor 10” risk guide (based on the GE formula) to assign a valid risk assessment to the fault. ●● Comparing changes in lab results over time with changes in equipment’s operational parameters (temps and loading data collected at the time of sampling). ●● A useful tool to validate the lab’s test results and the quality of the sample taken. ●● Evaluating cellulose using furans. ●● Using fluid quality (FQ) results to cross check for causative agents or associated changes in the fluid or cellulose. When the 6 steps are performed with each transformer sampling creating a valid and actionable condition assessment is a very logical process. Mel Wright has over thirty years of experience as an expert in transformer diagnostics using liquid insulation analysis. Mel designed, equipped, and managed the General Electric Energy Services transformer oil laboratory in Denver, CO from 1980 to 2008. The Denver LIL performed DGA, Furans, PCBs and fluid quality tests for all GE facilities in North and South America. Mel was the GE expert resource for GE transformer engineers, field service technicians, customers, and utilities regarding transformer condition assessment, fluid evaluation and fault identification. In addition to managing the laboratory, Mel was the GE Polychlorinated Biphenyls (PCB) testing, management, DOT shipping, and EPA Commercial PCB facility manager in Denver as well as the environmental, health, and safety coordinator and the manager of Hazardous Materials and Hazardous Waste for the Denver facility.

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Insulating Oils

EXAMINATION OF TRANSFORMER OIL MOISTURE MEASUREMENTS NETA World, Fall 2014 Issue Don Genutis, No-Outage Electrical Testing, Inc.

Moisture can be one of the most damaging factors to transformer insulation and one of the more difficult factors to understand. Excessive moisture will cause transformer insulation to degrade at a much faster rate than normal, and this degradation process can generate additional moisture which will increase the degradation process even more. Some studies indicate that doubling paper insulation moisture content will result in reducing transformer life in half; therefore, it is important to know the insulation moisture content of the paper in order to maintain transformer reliability.

Even though the dryness of the paper cannot be measured directly with an oil sample test, it can be determined indirectly by calculating the percent saturation of the oil using the ASTM D1533 moisture-in-oil test results along with the transformer temperature to provide a better indication of insulation dryness. Percent saturation can be determined by using a nomograph such as the one shown in Figure 1. Percent saturation guidelines shown in Figure 2 show that levels greater than 30 percent indicate an extremely wet transformer that should probably be dried out.

Moisture migrates from the oil into the winding paper insulation based upon the temperature of the transformer which is largely influenced by transformer loading. At 20°C, the paper contains about 3,000 times the amount of moisture that the oil does and at 60°C, the paper contains only 300 times the amount of moisture that the oil does. This is because the higher temperatures drive the moisture out of the paper and into the oil. Therefore, the ASTM D1533 Standard Test Method for Water in Insulating Liquids by Coulometric Karl Fischer Titration test is not necessarily a good indication of the dryness of the transformer.

Fig. 2: IEC Guide for Insulation Condition Based on Percent Saturation Present guidelines also state that acceptable moisture levels for in-service mineral oil transformers operating at voltages less than 69 kV is 35 ppm. Looking at the nomograph of Figure 1, one can see that a transformer with 30 ppm (acceptable moisture-in-oil level) and operating at 20°C has a percent saturation level of over 50 percent which is extremely wet. Therefore, we should not rely solely on the moisture-in-oil test but should instead look closer at the percent saturation in order to estimate transformer dryness. Trending or continuous monitoring of moisture in oil along with temperature parameters can of course provide even more accurate percent saturation results as compared to a one time test since transformer loading operation and atmospheric temperatures can vary significantly over time. The following case study illustrates the importance of considering percent saturation results when evaluating transformer condition. Fig. 1: Nomograph for Determining Percent Saturation

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Insulating Oils

Table 1: Transformer Test Results Displaying Percent Saturation Correlation with Missing Bushings

In this particular case, a client had 19 pad-mount transformers in an outdoor storage yard for a few years. All transformers were pad mount compartmental type, 4,800 V delta primary and either 480/277Y or 208/120Y secondary. All transformers contained approximately 100-300 gallons of mineral oil. Over time, 10 of the transformers were vandalized by copper thieves that removed many of the low voltage bushings which left large openings and allowed the mineral oil to be exposed to atmosphere. Although the overall climate condition at this location is relatively dry, wet weather periods allowed ample moisture entrance into the oil. Since the transformers were not in service, they were not warm and the winding paper insulation absorbed much of the moisture. After careful oil sampling was completed and the samples tested, it can be seen from Table 1 that in all 19 cases the moisture in oil results were acceptable (< 35 ppm). Nine of the first 10 transformers on the list, which were relatively well-sealed, exhibited relatively low percent saturation values. Whereas, of the nine poorly sealed transformers, eight exhibited high saturation values which is indicative of a wet transformer. Based on this data, percent saturation calculations correlate much better with expectations than the moisture results. Although the moisture in oil test results are valuable since this information is used to calculate percent saturation, the percent saturation values are a much better indication of wet windings and, therefore, a much better indication of transformer condition.

Don A. Genutis holds a Bachelor of Science degree in Electrical Engineering and has been a NETA Certified Technician for more than 15 years. He has held various principal positions during his 30-year career in the electrical testing fieldand has primarily focused on advancing no-outage-testing techniques for the last 15 years. Don presently serves as President of Halco Testing Services in Los Angeles, California.

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Insulating Oils

TRANSFORMER MAINTENANCE: THE OVERLOOKED ITEMS NETA World, Winter 2015 Issue Rick Youngblood, Doble Engineering Company

In my 35 years of involvement with substation transformer maintenance, I have witnessed widely varying perspectives on what maintenance should include. Too often, it is limited to nothing more than inspections. The techs involved might look at the top oil and hot spot indicators, observe the nitrogen pressure or conservator levels, check for leaks — and maybe, if they are thorough — log the load tap changer (LTC) counter. Most technicians comment that the transformer is electrically tested every three to six years by performing the standard regiment of power factor, TTR, excitation, and winding resistance tests; but the majorities are completely unaware of what I call the “overlooked items.” Ignoring the items below can seriously compromise the overall reliability of the transformer.

FAILURE MODES To properly perform transformer maintenance, it is important to identify all, not just some, of the possible failure modes: Electrical, Mechanical, and Dielectric. These can further be broken down into internal tank and external tank. This article highlights the often-overlooked external failure modes rather than the typical internal modes identified in most maintenance programs.

While they are a virtual short circuit at the moment they are energized, that quickly changes as they approach normal operating speed. The twisting force or torque is dependent on the strength of the magnetic flux formed between the stator or stationary winding as compared to the rotating winding or rotor. The rotor then has a shaft connected to the load extending from the middle of the rotor. The flux requirement and the current required to produce it are determined by the load on the shaft. Although polyphase motors do not require any help to rotate, single-phase motors (Figure 1) can require three additional parts to begin rotation: (1) the start winding, (2) a centrifugal switch, as in Figure 2, used to disconnect the start winding when the motor reaches approximately 85% of rated speed, and (3) a starting capacitor, as shown in Figure 3. When a motor is first energized, the current drawn is equivalent to the stalled current and is large enough to quickly overheat the winding. This heat, if it persists, will destroy the winding insulation and eventually the motor. The current reduces rapidly as the motor picks up speed and develops a counter EMF to oppose the source; ac induction motors behave as transformers with a shorted secondary until the rotor begins to move.

EXTERIOR MAINTENANCE Exterior maintenance centers on the LTC drive mechanism, cooling fans, pumps, controls, and gauges. The heart of the LTC drive system is a motor. Some are threephase, but most are typically single-phase fractional horsepower, and they have many failure modes, which can result in LTC failure. While most of us think we understand motors, do we really? Motors are rotating and repelling electromagnets that require current to produce the electromagnetic flux that generates the twisting force known as torque and voltage to push that current. They are very proportional; if the voltage drops, the current will climb, and if the voltage climbs, the current drops. Motors are obedient in the sense that under some circumstances, they will destroy themselves trying to rotate the load by drawing the current they need to generate the torque required to rotate, if not protected by a current limiter such as a fuse or breaker. Their internal impedances are variable.

Fig. 1: Single-Phase Motor

Fig. 2: Centrifugal Switch

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Fig. 5: Externally Mounted Start-Up Caps

Fig. 3: Starting Capacitor

Bearing wear, improper lubrication, or rust in jack shafts, sprockets, gears chains, and levers all increase the torque requirements and the measured current (Figures 6 and 7).

COMMON MOTOR PROBLEMS (LTC FANS AND PUMPS) The most common motor problems are related to improperly applied voltage and current. As connections get old and loosen due to thermal cycling, corrosion, and poor crimping, their resistance increases and results in voltage drop. It is easy to determine if this occurs by measuring the voltage before startup and while running at full speed using a good voltmeter. If the voltage drops by more than 10%, one of the previously mentioned conditions exists. Slow start-up can be caused by excessive load or bad start capacitors (Figures 4 and 5). The capacitance of the latter can be measured with any number of good capacitance measurement meters. If the capacitance has changed more than 5% from the tolerance printed on the can, or 10% from the rated value, it should be changed. Because ac capacitors are not polarity sensitive like dc capacitors, the two types cannot be interchanged. If the capacitor is satisfactory, mechanical issues are the next areas to investigate.

Fig. 6: Rusty Chains Due to Leaking Explosion Diaphragm and Lid Gaskets

Fig. 7: Frozen Universal Joint Due to Aged and Broken Rubber Joint Cover Any mechanical or electrical problem that slows the operation of the LTC causes extended transition times, and ultimately, failure in the selector, transfer, and reversing switch contacts. While it might be assumed that the failure is due to bad contacts, the original problem could actually be in the drive motor and mechanism.

Fig. 4: Capacitor Located Under the Cover

Other LTC failure modes are directly attributed to poor maintenance in the controls of the LTC. The contacts must not only move in a timely fashion, but also must stop with precision directly on their stationary mates. The moveable contact can’t stop short, nor can it coast past the proper position. Therefore, one of the following must be employed: ●● Mechanical braking using drums or bands ●● Dynamic braking where the motor is short circuited momentarily ●● Plugging where the motor is electrically reversed to stop its forward motion

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Insulating Oils All are required to occur exactly on step, in time, every time. The cam and position switches, which control these functions, need maintenance and lubrication on a regular basis as well. Lastly, the LTC must recognize when it has reached the last step and protect the motor from trying to rotate past the mechanical stops. Step 17 on a 16-step changer is not good (Figure 8)! Fig. 8: End of stroke stops are mechanical stops to prevent the LTC contacts from moving past the last step End of stroke limit switches are used to electrically disengage the motor drive when step 16 is reached

Threaded bar step positioner requires regular lubrication

Mechanical brakes require adjustment to ensure the brake releases when the operating solenoid is engaged to let the motor rotate but must re-engage exactly at the correct spot required to position the contacts. Brake bands wear over time and need adjustment or replacement (Figure 9). Fig. 9: Brake release solenoid is electrically energized to release the brake, but when de-energized, uses a spring to reapply the brake. Timing is critical. Brake bands use friction to stop the LTC motor in the correct position and must be adjusted periodically.

In closing this section on LTC mechanisms, a failure example is illustrated in Figure 10. Although the failure is located in the LTC tank, the cause is lack of maintenance in the control section, possibly due to binding, low torque, low voltage, high current, bad starting capacitor, etc. Good maintenance procedures should include servicing these parts on a regular basis, which can prevent failures in the LTC tank.

Fig. 10: Damaged Moveable Contact Due to Malfunctioning Brake Circuit in the Motor Control

ELECTRICAL CONTROLS Electrical maintenance is normally only thought of as the in-depth testing of the core and coils, such as power factor, TTR, excitation, winding, and resistance, etc. Seldom are the external controls for the pumps and fans tested to see if they function properly, much less checking calibration for accuracy. It is widely accepted that a continuous increase of 8°C to 10°C above rated temperature can reduce operating life by 50%. Therefore, it is very important that the cooling system on a transformer works as designed to turn on the fans and pumps before the oil temperature reaches the rated upper limit. Top oil and hot spot gauges need calibration using a calibrating oven to see if the needle tracks the actual oil temperature or drifts as the temperature increases (Figure 11). It’s not uncommon for the error in reading to change as the temperature increases. Adding or subtracting a fixed amount to the actual reading compensates for a linear change. A non-linear change requires a replacement

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Insulating Oils

of the temperature gauge. Additionally, determine if the switch set points close at the desired temperature and can be adjusted up or down to compensate for gauge errors. The final check is to see if the electrical switch actually changes state when the set points are reached (Figure 12).

amounts of brass and cast iron in the transformer. These filings will be distributed everywhere, including the windings, eventually causing winding failure (Figure 13).

Fig. 13: Thrust Washer Failure Modes Fig. 11: Transformer Temperature Gauge with Electrical Set Points to Bring Pumps and Fans On- Line In a situation where the fans turn on late by 10 degrees, the windings can be continually subjected to temperatures past their design limit, thereby reducing insulation life. If the transformer is set to trip on high temperature, a bad gauge can trip the unit for no actual reason below the desired temperature, causing collateral damages or an unplanned outage. Fig. 14: Visual Representations of Bearing Wear Using Ultrasonics

Fig. 12: Capillary Tube Temperature Well Calibration Oven

MECHANICAL PROBLEMS Pump problems have negative consequences as well. If a pump starts at a higher temperature than planned, it may be difficult to return the transformer to the desired temperature during hot weather or when the load is above normal. A pump that fails to start leads to insulation degradation. If a pump fails completely, the transformer may fail in a very short period of time. Most transformers have an operational capability less than the OA rating with no pumps running and can overheat with minimum load. Pump failures can be mechanical as well as electrical. Pump motors use a spacer called a thrust washer to center the impeller in the cast iron housing to prevent drag. As a pump ages, the thrust washer wears and eventually permits the impeller to drag on the housing, depositing large

Fig. 15: Use of Ultrasonic Detector to Determine Bearing Wear in Pumps and Fans Using an ultrasonic detection device (Figure 14) can quickly identify a number of failure modes, such as gas leaks, partial discharge, vacuum leaks, and mechanical wear (Figure 15), by converting vibration into audible sound the inspector can hear and record in his head set. Fan failure is common in a majority of companies. In the case of forever-sealed bearings, little maintenance is required other than keeping them clean and unobstructed. Fans are designed for free, unrestricted airflow that loads the motor to a specific torque

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Insulating Oils and current draw. When the fan bearings become dry or the blades obstructed, the current rises to compensate for the increased torque requirements, resulting in overheating and shortened motor life. Simple maintenance such as adding grease to bearings, removing debris from the blade guards, and checking the start capacitor all add many years to the life of the fan and transformer (Figures 16 and 17).

Considering many problems are slow to evolve, taking OQ samples yearly provides adequate protection. But in the case of problems typically caught by DGA, take oil samples from the main tank and LTCs more often. It is recommended to pull DGA samples twice a year due to the speed at which an LTC or winding problem can progress. The cost per sample is marginal compared to a transformer or even just an LTC failure and can be cost justified with one LTC save.

CONCLUSION As explained, what constitutes correct transformer maintenance is not always clear. To provide 100% equipment protection, it is important that technicians and maintenance engineers are aware of all failure modes on each specific equipment type. Suitable tests and service procedures, and the appropriate intervals between them, can then be developed. Once a comprehensive plan is devised to address all three failure modes — electrical, mechanical, and dielectric — the next important step is to implement it. Fig. 16: Bird nests play a primary role in fan failure and overheating of transformers.

Fig. 17: Fan failures due to debris also contribute to transformer overheating.

DIELECTRIC QUALITY The final category of overlooked items involves rigorous and regular oil quality testing. Oil testing falls into two basic categories: dissolved gas analysis (DGA) and oil quality testing (OQ). DGA is used to look for health issues, ranging from basic overheating to partial discharge and internal arcing. By understanding the differences in how gas is generated, it can be determined if the internal problem is serious or can be controlled by load. The results can also point to what electrical tests to perform if the problem proves to be more than operating issues. Typically, OQ screens are ordered in groups of five, seven, or eight separate tests that include dielectric strength, moisture, interfacial tension, acidity, power factor, and color. Other more stringent tests include furanic compounds to determine the remaining life of the insulation, and power factor at 100˚C to look for polar contaminants closer to the true operating temperature of the equipment under test.

Rick Youngblood worked for Cinergy Corporation (now Duke Energy) as the Supervising Engineer in Substation Services before taking early retirement in May 2004. Rick joined American Electrical Testing Company in August 2004 as Regional Manager, heading up its Midwest office located in Indiana. After obtaining his NETA 3 certification, he and his crew performed maintenance and testing in utility and industrial environments. In 2010, Rick moved to his present position as Principal Engineer in the Client Service group for Doble Engineering, where he shares client issues for the western half of the Great Lakes Region 5 with Jael Jose.

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WORKING SAFELY WITH POWER TRANSFORMERS IN THE UTILITY SECTOR NETA World, Winter 2015 Issue Ray Curry, American Transmission Company

Here’s a reflection on power transformers/accessory equipment, installation work methods, rigging/moving, and safety practices from the 1970s to today. When examining America’s electrical grid, power transformers are a key component. They are required for generator step-up (GSU), transmission, and distribution duty. In many locations, the Internet Age has caused a large increase in power demand. The bulk of the grid load is handled by aging power transformers, most of which were built in the 1970s and 1980s, with a few even older. These transformers were expected to have a 30- to 35-year life, but many are beyond 45 years. While many utilities are adding new transformers, the planning, purchase, and installation time is very long. Planning can be as long as five to seven years with the actual purchase taking 12 to 18 months. Installation for most transformers will take as long as three weeks. The fact is that everything is speeding up with no end in sight, and many changes and improvements concern power transformers as well. To list a few: ●● Better designs for longer life cycle ●● OEM components manufactured with ISO 9000 standards ●● Better nondestructive testing ●● Insulation materials suited for higher voltages and thermal stresses ●● Improved installation and oil processing/handling ●● Enhanced shipping and GPS tracking Workforce skills and equipment are also improving. The major part of any transformer installation involves moving a large, heavy piece of equipment that can be badly damaged by rough handling. To meet today’s utility specifications, many rigging and heavy hauling companies have invested in the best equipment as well as a skilled, trained workforce versed in an established safety program with a proven track record. Many of the larger transformers that need to be shipped a great distance (250MVA up to 800MVA) must be shipped by rail. With very few substations having a rail siding, a transfer vehicle is required to move the transformer from the rail siding to the transformer pad within the electrical substation. From the 1970s to now, these drayage vehicles have been re-engineered to be more

versatile with hydraulic systems to raise, lower, or level the working platform. Each vehicle has 16 axles that can be steered independently of one another. Self-propelled vehicles are a great advantage over older equipment, which required a tractor. In many older substations, space surrounding a large transformer can be very restrictive. Newer cranes are equipped with digital readers, giving the operator real-time, out-of-limits alarms for different parts of the crane, such as boom loading and outrigger position. For many years, utilities have been associated with having strong safety programs. Today, more and more utilities require all contractors to have a positive safety program and a strong compliance record with OSHA regulations. Qualified Crane Operators are now the norm. The use of fire-resistant clothing is now required by most utilities, along with consistent use of PPE. In the 1970s and 1980s, this would not have been the case with many rigging and hauling contractors. Today, the movement of the transformer, whether by rail or truck, is tracked using a real-time GPS device. The most popular device is a Lat-Lon, which uses a self-contained battery pack. This device records all movement in the X, Y, and Z axis with adjustable alarm levels. An important added feature with this device is its ability to record the main transformer tank pressure. Most transformers are shipped with two to three pounds of certified dry air in the main tank. The premature loss of this air pressure will cause, in most cases, additional vacuum/oil process time. From the 1960s through the 1980s, a mechanical clock recorded all impacts to the transformer during shipping. This impact recorder used paper on a roll to make the recordings. When the shipped load reached a destination, the paper roll was analyzed for any impacts. Compared to where the technology is now with real-time GPS, the old instrumentation was very unreliable and often failed to provide accurate data. The only backup to this was to check the core ground of the transformer and compare to the factory test measurement before shipping. Today, there is an additional test called Sweep Frequency Response Analysis (SFRA), which will be covered in the next article in this series. A valuable aid for today’s commissioning engineer planning a large transformer move is the ability to hire a logistics management firm. Now, contractors will arrange all the services and order a special rail car. The agent will also take care of interaction with

Insulating Oils railroad agents, schedule a heavy hauling company, and file all state and local permits to accomplish a safe and coordinated move. Along with the permits, an over-the-highway move may require a state patrol inspection of the load and on-road escort, all of which is taken care of by the logistics company. Now that the transformer is in the substation and on the pad, the next article in this series will cover assembly, vacuum/oil processing, testing, and placing the transformer in service. This article will also address Maintenance Zero Steps and the use of Behavior Based Safety Observation (BBSO). Ray Curry graduated from Penn State University in 1969. He joined Westinghouse Electric in the East Pittsburgh Division and the PCB Division at Trafford, Pennsylvania. In 1977, Ray relocated with Westinghouse to St. Louis, Missouri, working in the E&ISD Division as a Field Service Engineer specializing in high-voltage switchgear and construction/commissioning power substations. After retiring from Westinghouse in 1994, Ray managed two Municipal Electrical Systems for the cities of Chanute and Garden City, Kansas, from 1994-2000. From 2007 to the present, Ray has been a Commissioning Engineer with American Transmission Company, building and maintaining over 500 69kV138kV to 345kV electrical substations, including more than 200 power transformers within the ATC Service Footprint. He sits on ATC’s Safety Committee and has maintained an active affiliation with NETA for six years.

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TRANSFORMER INSULATION DEGRADATION NETA World, Winter 2015 Issue Lynn Hamrick, Shermco Industries

Hartford Steam Boiler Insurance Company has been collecting information on transformer failures for years and periodically issues reports on the causes of such failures. Table 1 represents a compilation of those study results for 1975, 1983, and 1998. Note that “Deterioration of Insulation” was the second most frequent cause of transformer failure in 1998. This article will focus on internal failures of transformers, with a focus on the chemical processes that can cause insulation deterioration as well as how overloading and moisture accelerate the degradation process. Cause of Failure

1975

1983

1998

Line Surges/External Short Circuit 

13.6%

18.6%

21.5%

Deterioration of Insulation

10.4%

8.7%

13.0%

Lightning Surges

32.3%

30.2%

12.4%

Inadequate Maintenance

6.6%

13.1%

11.3%

Moisture

7.2%

6.9%

6.3%

Loose Connection

2.1%

2.0%

6.0%

Poor Workmanship — Manufacturer     

10.6%

7.2%

2.9%

Overloading

7.7%

3.2%

2.4%

Sabotage, Malicious Mischief

2.6%

1.7%

0.0%

All Others

6.9%

8.4%

24.2%

*Results of Hartford Steam Boiler Insurance Company studies on the causes of transformer failures.

Table 1: Causes of Transformer Failures* Basically, insulation within a transformer consists of cellulose (or paper) and insulating oil. A large amount of research has looked at the factors that affect cellulose and mineral oil. Cellulose ages and degrades through three basic chemical processes: oxidation, acid-hydrolysis, and pyrolysis. These processes are caused by the presence of oxygen, the presence of water, and operating at elevated temperatures. The result is a weakening of the cellulose’s mechanical and electrical integrity, as well as sludging and contamination of the insulating oil.

OXIDATION Oxidation is defined as the interaction between oxygen molecules and all the different substances they may contact. Technically, oxidation is the loss of at least one electron when two or more substances interact. Those substances may or may not include oxygen. (Incidentally, the opposite of oxidation is reduction — the

addition of at least one electron when substances come into contact with each other.) In a transformer, oil and paper degrade as a result of oxidation. The most common insulating liquid used in transformers is mineral oil. Some transformer oils, referred to as uninhibited oils, possess a degree of natural protection against oxidation. However, mineral oil, which is known as inhibited oil, requires the addition of an antioxidant to protect against oxidation. For mineral oil, aging and oxidation are synonymous. The aging process begins slowly, as the antioxidants work to neutralize the harmful peroxides and radicals as they are formed. However, with time, the antioxidants decrease in quantity and the aging process increases exponentially. This leads to the formation of acids, aldehydes, ketones, esters, and eventually sludge (a mixture of long insoluble hydrocarbon molecules and particles). The process occurs in the presence of peroxides (unstable oxygen compounds) and free radicals and is accelerated by catalysts such as water and copper. If allowed to continue, oxidized oil will continue to deteriorate and will transport contamination to the cellulose insulation within the transformer. Here the effects are much more serious. Transformer oil can be changed; unfortunately, cellulose cannot be changed. If the oil is not maintained, the condition of the cellulose will deteriorate to the point where the transformer has reached the end of its working life. Cellulose degrades (oxidizes) much faster than oil because it contains oxygen within its molecular structure. The degradation process generates water, carbon dioxide, and furfurals, and is accelerated by external sources of oxygen, high temperature, and high levels of oil acidity. The water that is generated combines with dissolved moisture in the oil to further accelerate the degradation process. The end result is broken molecular chains, a lower degree of polymerization (DP), and loss of mechanical strength. In the absence of oxygen, decomposition occurs more slowly through the process of pyrolysis.

ACID-HYDROLYSIS Acid-hydrolysis is the breakdown of the cellulose using H+ ions in water as a reactant. In hydrolysis, a larger molecule, like molecules of cellulose, is broken down into simpler substances by the addition of water molecules. When this process is carried out in the presence

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Insulating Oils of a small amount of acid, like that produced through the oxidation process, it is called acid-hydrolysis. The acid acts as a catalyst by providing H+ ions to facilitate the cellulose’s intake of water (H2O) molecules. To give an idea of the effects of water in the cellulose, it has been suggested that if the moisture content in cellulose doubles, transformer life expectancy is immediately halved.

PYROLYSIS Pyrolysis is the breakdown of the cellulose at elevated temperatures. Simply stated, the higher the temperature the cellulose operates in, the faster the cellulose will degrade. Operating temperature increases can be the result of operating in overloaded conditions, some type of failure or limitation in the transformer cooling process, or elevated ambient temperature. Any of these situations can result in elevated temperatures of cellulose. It has been suggested that a thermal increase of just 10o C will lead to cellulose lifetime being cut by over 50%. The best way to combat each of these degrading processes is to monitor transformer health by establishing a transformer maintenance routine and performing periodic oil analysis.

TRANSFORMER MAINTENANCE The following should be monitored as part of regular transformer maintenance: ●● Physical and mechanical condition. This should include an evaluation of the paint condition and cleanliness of the outside of transformer compartments and radiator cooling fins. Look at the LTC counter log and record the value. This inspection should also include a determination that no hindrance exists in getting air to the radiator cooling fins. Any suspected problem that could result in an oil leak or reduced system cooling should be recorded and brought to the attention of management for corrective action. ●● Oil leaks and spills. Oil seepage from within the transformer typically appears as a discoloration of the painted surface around a bushing or penetration. All suspected oil leaks should be recorded and brought to the attention of management for corrective action. ●● Correct operation of cooling fans, if applicable. Transformer cooling fans are typically controlled with thermostats, turning on and off based on a temperature setting. If the fans are not running, it should be noted with the as-found thermostat settings recorded. The system should then be exercised by adjusting the thermostat settings to cause the system to operate. With subsequent operation, the thermostat settings should be returned to the original settings with the as-left settings recorded. If the system does not operate, this condition should be recorded and brought to the attention of management for a repair of the system.

MONITOR TRANSFORMER INDICATORS Examination of these indicators is also part of transformer maintenance: ●● Transformer temperature. For an OA 55/65 Class Transo former, operating temperature limits of the windings are 55 o o o C or 65 C (131 F or 149 F, respectively), dependent on the kVA ratings of the transformer. Determine if the sensor is for top oil or winding temperature. It should be noted that the top oil temperature is probably lower than the winding temperature. Also, note the high temperature indicator and reset with each inspection. ●● Transformer pressure. This measures the pressure of the nitrogen blanket above the oil. The gauge usually indicates negative and positive pressure. The pressure can vary from slightly negative to slightly positive due to ambient temperature and operating conditions. For sealed transformers, the pressure should always be maintained at a slightly positive pressure. This is indicative of a proper seal and also ensures that moisture from the air does not leak into the nitrogen-filled gap at the top of the transformer. ●● Transformer oil level. There is usually a mark on the gauge that indicates the 25° C level, which is the proper oil level for the transformer at that temperature. Maintaining the proper oil level is extremely important because if the oil level falls below the level of the radiator inlet, natural circulating flow through the radiator will cease and the transformer will overheat.

PERIODIC TRANSFORMER OIL ANALYSIS The insulation system is typically evaluated by performing the following oil sample tests: ●● Dielectric breakdown voltage. The dielectric breakdown voltage is a measurement of electrical stress that an insulating oil can withstand without failure. It is measured by applying a voltage between two electrodes under prescribed conditions under the oil. The dielectric test measures the voltage at which the oil breaks down, which is indicative of the amount of contaminant (usually moisture) in the oil. ●● Moisture content. Oil moisture is measured in parts per million (ppm), using the weight of moisture divided by the weight of oil. Water can be present in oil in a dissolved form, as tiny droplets mixed with the oil (emulsion), or in a free state at the bottom of the tank holding the oil. Demulsification occurs when the tiny droplets unite to form larger drops, which sink to the bottom and form free water. When the moisture in oil exceeds the saturation value, there will also be free water precipitated from the oil in suspension or drops. ●● Power factor. The power factor of insulating oil equals the cosine of the phase angle between an ac voltage applied and the resulting current. Power factor indicates the dielectric

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Insulating Oils loss of the insulating oil, and thus, its dielectric heating. The power-factor test is widely used as an acceptance and preventive maintenance test for insulating oil. A high power factor in service-aged oil indicates deterioration, contamination, or both, with moisture, carbon, or deterioration products.

●● Interfacial tension. The interfacial tension (IFT) test is employed as an indication of the sludging characteristics of power transformer insulating oil. It is a test of IFT of water against oil, which differs from surface tension in that the surface of the water is in contact with oil instead of air. The attraction between the water molecules at the interface is influenced by the presence of polar molecules in the oil in such a way that the presence of more polar compounds causes lower IFT. The test measures the concentration of polar molecules in suspension and in solution in the oil, giving an accurate measurement of dissolved sludge precursors in the oil long before any sludge is precipitated. ●● Acid neutralization number. The acid neutralization number, or acid number, is the amount of potassium hydroxide (KOH in mg) required to neutralize the acid in one gram of oil. It is indicative of the acid content in the oil. With service-aged oils, it is also indicative of the presence of contaminants, like sludge. The acidity test alone determines conditions under which sludge may form but does not necessarily indicate that actual sludging conditions exist. New transformer oils contain practically no acids. The acidity test measures the content of acids formed by oxidation. The oxidation products polymerize to form sludge, which then precipitate out. Acids react with metals on the surfaces inside the tank and form metallic soaps, another form of sludge. ●● Color. The color of an insulating oil is determined by means of transmitted light and is expressed by a numerical value based on comparison with a series of color standards. It is recognized that color by itself could be misleading in evaluating oils for service quality. The primary significance of color is to observe a change or darkening of the oil from previous samples of oil from the same transformer. Noticeable darkening in short periods of time indicates either contamination or that arcing is taking place. A darkening color with no significant change in neutralization value or viscosity usually indicates contamination. As the transformer ages, the sampling program should also include checking for the oxygen inhibitor level. Oxygen inhibitors should be in the oil at acceptable levels, which is typically in the 0.3% to 0.4% range. DBPC, 2,6-di-tertrybutyl-paracresol, is the most commonly used antioxidant, but there are many types. As you monitor depletion rates, note the type and level for future reference. Additionally, furanic acids should be monitored when you have other indicators that the cellulose has degraded. When cellulose insulation decomposes due to overheating, chemicals are released and dissolve in the oil.

These chemical compounds are known as furanic compounds, acids, or furans. In healthy transformers, no detectable furans are in the oil (1,500 ppb have a high risk of insulation failure. With regard to performing dissolved gas analysis (DGA) and using the results for evaluating cellulose and insulating oil degradation, the ratio of CO2/CO can be used as an indicator of the thermal decomposition of cellulose. The rate of generation of CO2 typically runs seven to 20 times higher than CO. Therefore, it is normal if the CO2/CO ratio is above seven. If the CO2/CO ratio is five or less, there is probably a problem. If cellulose degradation is the problem, CO, H2, methane (CH4), and ethane (C2H6) will also be increasing significantly. At this point, additional furan testing should be performed. If the CO2/CO ratio is three or under with increased furans, severe and rapid deterioration of cellulose is occurring, and consideration should be given to taking the transformer out of service for further inspection.

REFERENCES A Guide to Transformer Maintenance, S. Myers, J. Kelly and R Parish (ISBN-13 978-0939320004) IEC 60076-14 ed 1.0 (September 2013) Power Transformers – Part 14: Liquid-Immersed power transformers using high temperature insulation materials. Lynn Hamrick brings more than 25 years of working knowledge in design, permitting, construction, and startup of mechanical, electrical, and instrumentation and controls projects as well as experience in the operation and maintenance of facilities. He is a Professional Engineer, Certified Energy Manager, and has a BS in Nuclear Engineering for the University of Tennessee.

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ESTABLISHING MAINTENANCE ZERO FOR LARGE POWER TRANSFORMERS IN TODAY’S ELECTRICAL UTILITY SECTOR NETA World, Summer 2016 Issue Ray Curry, American Transmission Company

“Use the best of the past to build the future.” — Unknown In the previous article (see NETA World Journal, Winter 2015), I touched on items that affect transformer installation and testing. Now, I want to focus on two items that have changed the field assembly of these transformers. Both have their origin in the 1970s and continue to have a strong influence today.

FALL PROTECTION AND CONFINED SPACE First and foremost was the establishment of OSHA, and in particular, CFR 1910. Perhaps the most influential thing to happen in the 1970s was the establishment of OSHA. The development of OSHA Regulation CFR 1910 on Fall Protection and Confined Space has had a major influence on how the assembly of large power transformers is accomplished. Before any assembly work is started, the best practice is to ground the transformer to the ground grid of the substation. It is also a good practice to ground all cranes, lifts, processing trailers, and tankers. In the area of fall protection, enhancements to and development of man lifts, work platforms, and body harnesses are designed to comply with OSHA regulations. When assembling large transformers, workers operate anywhere from 10 to 40 feet above the ground. Some transformers have attachments on top of the main tank for the placement of railing systems. Some manufacturers provide an attachment area for installing a May Pole (see picture). This pole is rated to have up to four workers attached at one time and still meet OSHA code. Today’s power transformer is designed with a smaller main tank. The intent of this design is to aid shipping the largest MVA transformer over the road versus railroad shipment. The length and width of today’s transformer has not changed much, but the height has been greatly reduced. This reduction creates two challenges for the assembly crew: (1) more field assembly on top of the transformer’s main tank and (2) in most designs, very restricted work space for any inside tank work required to connect the high- and low-side bushings. To address the inside work, draw lead bushings are sometimes used. Side wall access flanges allow employees to make up winding connections on the bottom of the bushings.

By OSHA regulation, should any assembly work be required inside of the main transformer tank, this entry point and workspace must be treated as a confined space. The regulation states that the entry is by permit only. Another part of the regulation requires that the contractor have extraction equipment present while workers are in the permitted space.

DESIGN AND ENGINEERING CHANGES The second influential item of the 1970s affecting transformer field assembly is design and engineering changes. Advancements that began in the 1970s have become global today. Transformer manufacturers must use the building blocks of the past to compete successfully today. The advancement of computer-aided design (CAD), for example, gave rise to computer-aided engineering (CAE), which allowed the engineer to build with modeling software. These programs grew in many directions and gave birth to new support services and ancillary equipment. Start-up companies provided polymers, epoxy resins, and new dielectric insulations, which in turn allowed the transformer to be built with a higher basic insulation level or basic impulse level (BIL), which led to higher kilovolt (kV) levels.

34 When fully loaded, these large transformers produce a tremendous amount of heat. To dissipate this heat, mineral oil is used with pumps and radiators. Silicone and other fluids were developed through the 1970s, but mineral oil still provides the best heat transfer in the large transformer. However, mineral oil can have a negative impact on the environment. To counter this, new products for containment and engineered systems have been initiated for most transformers, new and old. With respect to ancillary equipment, Reinhausen developed the vacuum tap changer and grew its world market share in the 1970s. Most distribution and transmission class transformers have load tap changers. The vacuum tap changer requires far less maintenance compared to older tap changers. Likewise, companies such as Ohio Brass and Qualitrol, among others, developed and improved transformer products through the 1970s and 1980s. Microprocessor-based protective relays — a vast improvement over the electro-mechanical relay — now protect this expensive capital equipment. Computer modeling software has also provided design engineers with the ability to build a transformer that operates with more efficiency, heavier load cycle, and longer operating life. To gain this capability, field assembly and oil processing has been improved from the 1970s to now. Companies such as Barron have designed vacuum/oil processing trailers that are also computer controlled. All transformers in the high-voltage class (50kV and above) are designed to withstand full vacuum. The high vacuum is used to dry or pull moisture out of the transformer. In the 1970s, this processing equipment would attain 800 to 1,000 microns or 0.8 to one Torr. Today’s equipment will typically reach 40 to 200 microns. To put this in better perspective: 1,000 microns = 1 Torr = 1 millimeter of mercury Because of improved design and assembly, today’s transformers use neoprene and nitrile rubber gaskets, compared to units built in the 1960s and 1970s, which used cork or cork-neoprene. On the older transformer, oil leaks occurred early as the cork dried out, which in turn affected annual maintenance work. The preferred gasket or O-ring rubber is Nitrile 70 or Nitrile 90. Many transformers of the late 1980s are in service today with Nitrile 70 and have had little or no oil leak issues caused from degradation of the nitrile. When these units were first assembled and processed, the benefit of having the advanced gaskets and O-rings was a tighter transformer with respect to vacuum/pressure leaks. In turn, this reduced the vacuum processing time. Even with the higher vacuum, the processing and oil filling of a large transformer takes time. Typically, most of these transformers will hold 10,000 to 26,000 gallons of oil. As part of the processing, oil is heated and degassed as it flows through the processing equipment at a rate of 20 to 30 gallons per minute, heated again, and injected into the transformer tank. Some transformer manufacturers also require oil recirculation to obtain lower moisture levels. After

Insulating Oils all, in most installations, the manufacturer is providing a warranty that may last several years. Another aspect of today’s transformer is the preservation of the oil. Many transformers of the 1970s used a nitrogen blanket to control oil moisture buildup. Today’s transmission class transformer will use the conservator oil preservation system (COPS). With the use of COPS, today’s transformer now has a very sensitive dissolved gas analyzer (DGA) system. With the use of another protective relay — a gas-sensing relay that will detect explosive gases — the transformer now has enhanced protection against electrical faults that occur inside the transformer main tank. When an electric arc happens in an oil transformer, explosive gasses are produced; if allowed to accumulate, further damage or transformer failure may occur. An objective of every large power transformer assembly and installation is to maximize its life cycle by establishing a sound maintenance program. A term used today is Maintenance Zero. By obtaining the proper installation, vacuum/oil processing, and detailed final in-service testing, the transformer owner lays the foundation for 40-plus years of useful transformer life. In the next article in this series, I will outline how power transformer testing, test equipment, and record keeping have changed from the 1970s to today. There are challenges going forward. One is maintaining a skilled workforce that can deliver quality technical workmanship safely to the customer. Another is building a strong working relationship between the manufacturer and the field assembler/processor/testing company. As a result, many NETA Certified Companies have formed strong working relationships with Hyundai, GE, ABB, and Siemens to name a few. These relationships are strengthened with factory training, technical seminars, and new product engineering updates. With many of today’s transformers built overseas, reliability to the end customer has taken on a whole new meaning and significance. Ray Curry graduated from Penn State University in 1969. He joined Westinghouse Electric in the East Pittsburgh Division and the PCB Division at Trafford, Pennsylvania. In 1977, Ray relocated with Westinghouse to St. Louis, Missouri, working in the E&ISD Division as a Field Service Engineer specializing in high-voltage switchgear and construction/commissioning power substations. After retiring from Westinghouse in 1994, Ray managed two Municipal Electrical Systems for the cities of Chanute and Garden City, Kansas, from 1994-2000. From 2007 to the present, Ray has been a Commissioning Engineer with American Transmission Company, building and maintaining over 500 69kV138kV to 345kV electrical substations, including more than 200 power transformers within the ATC Service Footprint. He sits on ATC’s Safety Committee and has maintained an active affiliation with NETA for six years. 

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Insulating Oils

GAUGING TRANSFORMER CONDITION NETA World, Fall 2016 Issue Don Genutis, Halco Testing Services

Fluid-filled transformers are unique compared to other electrical equipment in that basic visual inspections can often provide a wealth of condition-related information. The fluid in a liquid-filled transformer provides several critical functions, including electrical insulation and cooling. The high dielectric strength of the fluid allows more consistent insulating capabilities compared to air and also functions as a coolant to allow heat transfer away from the windings. Cooling fins allow the warm fluid to cool and help preserve the paper winding insulation. Fluid-filled transformers are typically equipped with three primary gauges that can provide important operating information. ●● Vacuum-pressure gauge. Large substation transformers are filled with mineral oil that typically does not have oxygen inhibitors or other additives. It therefore is more critical to maintain a positive nitrogen blanket so that oxygen does not have a chance to cause adverse effects on the oil and create corrosion of internal metallic components. A slight positive pressure is desired when inspecting the top gas-pressure gauge. The pressure can fluctuate because of temperature variations due to loading and ambient temperature changes. A gauge that is always at zero may be an indication of a leak that can allow moisture and other contaminants to enter the transformer. ●● Oil-level gauge. This gauge only displays the 25 degrees C mark which is related to present fluid level indicated by the needle. If the present transformer temperature is not 25 degrees C, the needle will fluctuate accordingly; however, if the fluid temperature is near 25 degrees C, the needle should be near this mark. This gauge is very useful to spot low coolant levels, which can impede proper cooling functions and create transformer overheating, which can substantially reduce operating lifetime. ●● Temperature gauge. The temperature gauge provides the present oil temperature. Since fluid temperature can vary, the maximum temperature indicator (if equipped) is useful to determine how hot the transformer got since the indicator was last reset. This indication should be compared to the rating of the transformer to spot possible overheating.

WINDING-TEMPERATURE GAUGE There is another less common and slightly more complex gauge to consider when performing transformer inspections. The winding-temperature gauge is often used to control auxiliary cooling systems such as fans and pumps, which operate when a set winding temperature is reached. The winding-temperature gauge typically determines the winding temperature indirectly by measuring the top oil temperature plus the temperature produced by a small internal heater circuit in close proximity to the temperature bulb. This heater circuit is connected by a current transformer (CT) to one of the low-voltage phases. As the transformer secondary current and thus CT current increase, the heater circuit elevates the temperature of the bulb, thus simulating actual winding temperature. Other transformer gauges may include the bushing oil-level gauge and the conservator tank oil-level gauge. Collectively, transformer gauges provide a simple overview of transformer operating conditions and should be considered when performing no-outage transformer inspections. Don A. Genutis holds a Bachelor of Science degree in Electrical Engineering and has been a NETA Certified Technician for more than 15 years. He has held various principal positions during his 30-year career in the electrical testing fieldand has primarily focused on advancing no-outage-testing techniques for the last 15 years. Don presently serves as President of Halco Testing Services in Los Angeles, California.

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Insulating Oils

TRANFORMER LIQUID SAMPLING DANGERS: WHERE DOES THE AIR GO? NETA World, Winter 2016 Issue Don Platts, Omicron and Dave Hanson, Tj/H2b Analytical Services, Inc.

In many companies, test technicians are assigned tasks that do not involve electrical tests. One commonly performed test is transformer oil sampling for laboratory tests of DGA or oil quality. The typical transformer owner assumes there is little or no risk involved if the oil sampling is done according to any of the many sampling procedures available from ASTM, transformer manufacturers, service providers, and oil testing laboratories. This article addresses potentially catastrophic safety issues encountered while sampling. The tests performed for this report modeled sampling procedures and monitoring device installation. The tests identified the cases where air will always enter the transformer and several other cases where bubble ingress is very likely. Since oil samples are normally taken with the transformer in service, there is a risk of an in-service failure. The energized winding, leads, bushings, etc. could be in the path this bubble will take as it floats up through the oil volume.

REVIEW OF VALVE TYPES Before discussing the issues involved with sampling, let’s review the variety of valves used as transformer drain valves (Figure 1).

tem, the pressurized air moves back through the valve into the transformer.

Fig. 2: These sketches illustrate the danger of a gate valve when used as a transformer drain valve because when the valve outlet is blocked or connected to a closed sampling system, the trapped air moves back through the valve into the transformer. ●● Ball Valve. The ball valve (Figure 3) also provides a full-bore opening. It requires a 90-degree handle rotation between fully open and closed. A ball with a hole through it sits in the center of the valve body and rotates on its vertical axis as the handle is moved. When the ball starts to rotate from its closed position, a small opening in the shape of a football appears. It is oriented vertically, allowing the liquid to move under pressure, displacing the air in the valve cavity. When the output is blocked, the pressurized air in the valve moves back through the opening into the transformer.

Fig. 1: Shown left to right are the globe, ball, and gate valves. Note the construction of the valve bodies. ●● Gate valve. The gate valve (Figure 2) can provide a full-bore opening through the valve to allow maximum oil surface exposure or insertion of a probe. A gate in the center of the valve body moves up and down on its vertical axis as the handle is rotated. As the gate lifts from its closed position, a small opening in the base of the valve cavity appears. It is oriented horizontally so that it allows the liquid to move, under pressure, and to compress the air in the valve cavity. When the valve outlet is blocked or connected to a closed sampling sys-

Fig. 3: These sketches illustrate the danger of using a ball valve as a transformer drain valve because when the output is blocked, the pressurized air in the valve moves back through the opening into the transformer.

37

Insulating Oils ●● Globe Valve. The globe valve (Figure 4) provides a restricted flow path, resulting in turbulent flow. A valve disk sits in a valve seat in the center of the valve body and moves up and down on its vertical axis as the handle is rotated, regulating the liquid flow rate. As the valve disk lifts from its closed position, it allows the liquid to move vertically, under pressure, and to compress the air in the valve cavity. With an unrestricted opening, the air will be forced out of the valve along with the liquid. When the valve outlet is blocked (or restricted), the air is trapped in the valve cavity and cannot move back into the transformer.

on the outcome of these experiments. (Note: SAE 10 motor oil has a viscosity of 85 – 140 cSt, and honey is 10,000 cSt.) The different configurations of sampling equipment studied can be broadly categorized into restricted and unrestricted groups. An oil sampling procedure may include a step to open a drain valve while there is a closed system component (or just a pipe plug) attached to the outlet side of the valve (restricted), or a different case where the sampling equipment does not close the outlet (unrestricted). Chamber air pressures used for the trials in each study ranged from -100KPa to 175KPa. As each valve was opened, the entire assembly was observed for bubble ingress (Figure 5).

Fig. 4: There is minimal danger with a globe valve used as transformer drain valve because the trapped air floats above the liquid and remains in the valve.

TEST PLAN TJ|H2b and OMICRON have both conducted tests using the various valves mounted on models of a transformer tank. Test protocols were developed to address:

Fig. 5: As the valve was opened during each of the test trials, the entire assembly was observed for bubble ingress. The results of the trials are summarized in Table 1.

●● Will air enter the tank when the valve is opened and the valve outlet: ○○ Is sealed by a pipe plug? ○○ Has a sampling port with the connected tubing free of restrictions? ○○ Is closed by a second valve in the sampling equipment? ●● Can one safely test for transformer tank positive pressure using the documented procedures? ●● Does pressure level inside the tank affect the results? ●● Do procedures for installing monitoring products prevent air ingress?

SAMPLING EXPERIMENTAL SETUP A pressure chamber was built to test a variety of sampling conditions. Gate valves, globe valves, and ball valves were connected to the chamber filled with water and air for these studies. Pressure in the chamber was varied using fittings on the top. The authors chose to use water rather than an insulating liquid primarily for the convenience and safety of the experiments. Each of the hundreds of trials required that the test assembly be disconnected and all of the liquid drained out before another trial could be started. Since water has a viscosity of 1 cSt and mineral (insulating) oil measures at 2.3 @100C, 9.6 @ 40C and 19 @15C, using water has no affect

Table 1: Results for Cases Where Air Cannot Escape (Restricted) and Where Air Can Escape (Unrestricted).

EVALUATION OF THE TEST RESULTS A review of valve descriptions shows that each valve type presents a different degree of opportunity for air ingress under the tested scenarios. The ball valve loses all restraint at the valve face the moment it is opened. The gate valve loses restraint at the valve face by degree as the gate is raised. The globe valve uses buoyant forces provided by the liquid to maintain restraint as the valve is opened. ●● Sampling with an unrestricted valve outlet. With positive pressure inside the main tank, and with only unrestricted or

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Insulating Oils open-vented components of sampling equipment on the drain valve, no bubbles will enter when the valve is opened.

●● Sampling with a closed valve in the sampling fittings or tubing. Some sampling equipment components may completely close the airspace external to the valve. When sampled through a ball or gate valve, air is forced into the transformer tank, even against positive tank pressure. The procedure may need modification. As seen in Table 1, only the globe valve will allow this procedure without bubble ingress. ●● Sampling with vacuum or negative gauge pressure in the transformer tank. There is no way to safely sample a transformer while it has negative gauge pressure. The tests demonstrated that with any sampling procedure, and with any valve type, for cases with negative gauge pressures, air will always enter the transformer when the drain valve is opened.

TESTING FOR VACUUM IN THE TRANSFORMER TANK Most sampling procedures include a test to verify positive pressure in the tank before sampling, based on ASTM D923-07, Standard Practices for Sampling Electrical Insulating Liquids. The objective is to ensure that air will not enter the transformer during the sampling process. However, if a negative pressure is present in the tank at the valve, air bubbles will enter the tank, and the condition to be avoided is actually caused by following this testing procedure. The authors recommend that the test for positive pressure (ASTM D923-07, Clause 7.2) be modified — or eliminated — to prevent air from entering the transformer with a negative pressure at the valve.

CONCERNS ABOUT VALVE TYPE If someone attempts to take an oil sample from a ball or gate valve using standard techniques and equipment, air bubbles could very likely enter the transformer. If you must sample from one, carefully review the procedure to ensure there is a path for the air to escape when the drain valve is opened. The globe drain valve was required by IEEE standards until the 1980s, when some customers started to require a full bore-opening valve to accommodate monitoring devices. Since many manufacturers’ standard drain valve is still the globe valve, with a positive pressure inside the tank, most transformers will not have these issues of air ingress.

OIL PRESERVATION SYSTEM AND TANK PRESSURE Test results show that we must address verification of the tank pressure. Therefore, let’s review the three oil preservation systems currently used to allow volume for the expansion and contraction of the transformer oil.

●● The sealed tank design has a blanket of nitrogen above the transformer oil. This design has a pressure/vacuum gauge and a pressure/vacuum bleeder to regulate the pressure inside the tank to a range of -8 to +10 psi. To ensure safe sampling, rely on the pressure gauges. ●● The inert gas pressure system uses a nitrogen bottle to supply pressure to the nitrogen blanket. Through adjustable regulators, it maintains the pressure in a range of approximately 3-8 psi. Alarms alert to high and low tank pressure and for low nitrogen bottle pressure. If the system is functioning, there will be a pressure above the oil. ●● The conservator tank mounts above the main tank allowing expansion of the oil. Usually, a rubber bag separates the oil from the oxygen and moisture in the atmosphere. With normal oil flow in and out of the conservator, static head pressure at the sampling valve is always present. If you cannot rely on the readings of the gauges and regulators, or a chance exists of a negative pressure in the main tank, the safest recommendation is to not take a sample.

INSTALLATION OF MONITORING SYSTEM COMPONENTS Similar tests confirm that installation procedures for some oil-contact monitoring products produce the same restricted case when the drain valve is opened, allowing ingress of air bubbles. Before installing a monitoring system on an energized transformer, investigate the possible results of the manufacturer’s installation procedures.

CONCLUSIONS Sampling should not be attempted if there is a negative gauge pressure inside the tank. The authors recommend that organizations publishing a sampling procedure should study this article, conduct their own experiments, and revise their sampling procedures as necessary. Even with a valid sampling procedure, a simple error of opening the wrong valve first could introduce air bubbles into the oil with serious consequences. The authors recommend that relevant IEEE standards should again require globe valves for drain valves as well as for any other valve specified for sampling access. The authors urge all transformer owners, operators, and service contractors to be cautious when performing oil sampling or installing monitoring devices on valves of energized transformers, and to review their existing procedures. Each worker should: ●● Be aware of the conditions that can lead to air entering a transformer. ●● Be able to identify the type of sampling valve. ●● Know how to determine the pressure inside the main tank. ●● Take all precautions to ensure that sampling can be done safely.

Insulating Oils For many workers, this will require new training, using a modified training program and revised sampling procedures. Donald W. Platts is a Senior Engineer with OMICRON Electronics Corp., providing technical support and training related to transformer applications and testing. He is the past Chair of the IEEE PES Transformers Committee. Dave Hanson is the President and CEO of TJ|H2b Analytical Services, Inc. He has been active in the field of insulating materials testing since 1978 and has been involved with the development of test methods and diagnostic criteria for high-voltage electric equipment. Dave’s experience extends to transformers, tap-changers, bushings, and gas- and oil-filled circuit breakers.

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NETA Accredited Companies Valid as of Jan. 1, 2019

For NETA Accredited Company list updates visit NetaWorld.org

Ensuring Safety and Reliability Trust in a NETA Accredited Company to provide independent, third-party electrical testing to the highest standard, the ANSI/NETA Standards. NETA has been connecting engineers, architects, facility managers, and users of electrical power equipment and systems with NETA Accredited Companies since1972.

UNITED STATES

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alabama 1

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AMP Quality Energy Services, LLC 352 Turney Ridge Rd Somerville, AL 35670 (256) 513-8255 [email protected] www.ampqes.com Brian Rodgers Premier Power Maintenance Corporation 3066 Finley Island Cir NW Decatur AL 35601-8800 (256) 355-1444 [email protected] www.premierpowermaintenance.com Johnnie McClung

arkansas 5

Premier Power Maintenance Corporation 7301 E County Road 142 Blytheville, AR 72315-6917 (870) 762-2100 [email protected] www.premierpowermaintenance.com Kevin Templeman

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Utility Service Corporation PO Box 1471 Huntsville, AL 35807 (256) 837-8400 Fax: (256) 837-8403 [email protected] www.utilserv.com Alan D. Peterson

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arizona

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Premier Power Maintenance Corporation 4301 Iverson Blvd Ste H Trinity, AL 35673-6641 (256) 355-3006 [email protected] www.premierpowermaintenance.com Kevin Templeman

Sentinel Power Services, Inc. 1110 West B Street, Ste H Russellville, AR 72801 (918) 359-0350 www.sentinelpowerservices.com

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ABM Electrical Power Services, LLC 2631 S. Roosevelt St Tempe, AZ 85282 (602) 722-2423 www.abm.com Electric Power Systems, Inc. 1230 N Hobson St., Ste 101 Gilbert, AZ 85233 (480) 633-1490 www.epsii.com Electrical Reliability Services 221 E. Willis Road Chandler, AZ 85286 (480) 966-4568 [email protected] www.electricalreliability.com Hampton Tedder Technical Services 3747 West Roanoke Ave. Phoenix, AZ 85009 (480) 967-7765 Fax:(480) 967-7762 www.hamptontedder.com Linc McNitt Southwest Energy Systems, LLC 2231 East Jones Ave., Suite A Phoenix, AZ 85040 (602) 438-7500 Fax: (602) 438-7501 [email protected] www.southwestenergysystems.com Dave Hoffman

Western Electrical Services, Inc. 5680 South 32nd St. Phoenix, AZ 85040 (602) 426-1667 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Craig Archer

california 13

ABM Electrical Power Services, LLC 720 S. Rochester Ave., Suite A Ontario, CA 91761 (301) 397-3500 [email protected] www.abm.com Rob Parton

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ABM Electrical Power Services, LLC 6940 Koll Center Pkwy, Ste 100 Pleasanton, CA 94566 (408) 466-6920 www.abm.com

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ABM Electrical Power Services, LLC 3585 Corporate Court San Diego, CA 92123-1844 (858) 754-7963

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Accessible Consulting Engineers, Inc. 1269 Pomona Rd, Ste 111 Corona, CA 92882-7158 (951) 808-1040 [email protected] www.acetesting.com Iraj Nasrolahi

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Apparatus Testing and Engineering 11300 Sanders Dr, Ste 29 Rancho Cordova, CA 95742-6822 (916) 853-6280 [email protected] www.apparatustesting.com Harold (Jerry) Carr

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Apparatus Testing and Engineering 7083 Commerce Cir., Suite H Pleasanton, CA 94588 (916) 853-6280 www.apparatustesting.com

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Applied Engineering Concepts 894 N Fair Oaks Ave. Pasadena, CA 91103 (626) 389-2108 [email protected] www.aec-us.com Michel Castonguay

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Applied Engineering Concepts 8160 Miramar Road San Diego, CA 92126 (619) 822-1106 [email protected] www.aec-us.com Michel Castonguay Electric Power Systems, Inc. 7925 Dunbrook Rd., Ste G San Diego, CA 92126 (858) 566-6317 www.epsii.com

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Electrical Reliability Services 5909 Sea Lion Pl, Ste C Carlsbad, CA 92010-6634 (858) 695-9551 www.electricalreliability.com

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Electrical Reliability Services 6900 Koll Center Pkwy., Ste 415 Pleasanton, CA 94566 (925) 485-3400 Fax: (925) 485-3436

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Electrical Reliability Services 10606 Bloomfield Ave. Santa Fe Springs, CA 90670 (562) 236-9555 Fax: (562) 777-8914 Giga Electrical & Technical Services, Inc. 2743A N. San Fernando Road Los Angeles, CA 90065 (323) 255-5894 [email protected] www.gigaelectrical-ca.com Hermin Machacon Halco Testing Services 5773 Venice Boulevard Los Angeles, CA 90019 [email protected] (323) 933-9431 www.halcotestingservices.com Don Genutis

Hampton Tedder Technical Services 4563 State St Montclair, CA 91763 (909) 628-1256 x214 [email protected] www.hamptontedder.com Chasen Tedder

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Industrial Tests, Inc. 4021 Alvis Ct., Suite 1 Rocklin, CA 95677 (916) 296-1200 Fax: (916) 632-0300 [email protected] www.industrialtests.com Greg Poole

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Pacific Power Testing, Inc. 38 14280 Doolittle Dr. San Leandro, CA 94577 (510) 351-8811 Fax: (510) 351-6655 [email protected] www.pacificpowertesting.com Steve Emmert

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Power Systems Testing Co. 4688 W. Jennifer Ave., Suite 108 Fresno, CA 93722 (559) 275-2171 x15 Fax: (559) 275-6556 [email protected] www.powersystemstesting.com David Huffman

RESA Power Service 2390 Zanker Road San Jose , CA 95131 (800) 576-7372 [email protected] www.resapower.com Toby Ramsey Tony Demaria Electric, Inc. 131 West F St. Wilmington, CA 90744 (310) 816-3130 Fax: (310) 549-9747 [email protected] www.tdeinc.com Neno Pasic Western Electrical Services, Inc. 5505 Daniels St. Chino, CA 91710 (619) 672-5217 [email protected] www.westernelectricalservices.com Matt Wallace

colorado 39

ABM Electrical Power Services, LLC 9800 E Geddes Ave Unit A-150 Englewood, CO 80112-9306 (303) 524-6560 www.abm.com

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Power Systems Testing Co. 6736 Preston Ave., Suite E Livermore, CA 94551 (510) 783-5096 Fax: (510) 732-9287 www.powersystemstesting.com

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Electric Power Systems, Inc. 11211 E. Arapahoe Rd, Ste 108 Centennial, CO 80112 (720) 857-7273 www.epsii.com

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Power Systems Testing Co. 600 S. Grand Ave., Suite 113 Santa Ana, CA 92705-4152 (714) 542-6089 Fax: (714) 542-0737 www.powersystemstesting.com

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Electrical Reliability Services 7100 Broadway, Suite 7E Denver, CO 80221-2915 (303) 427-8809 Fax: (303) 427-4080 www.electricalreliability.com

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RESA Power Service 13837 Bettencourt Street Cerritos, CA 90703 (800) 996-9975 [email protected] www.resapower.com Manny Sanchez

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Magna IV Engineering 96 Inverness Dr. East, Suite R Englewood, CO 80112 (303) 799-1273 Fax: (303) 790-4816 [email protected] Aric Proskurniak

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Precision Testing Group 5475 Hwy. 86, Unit 1 Elizabeth, CO 80107 (303) 621-2776 Fax: (303) 621-2573

For additional information on NETA visit netaworld.org

44

RESA Power Service 19621 Solar Circle, 101 Parker, CO 80134 (303) 781-2560 [email protected] www.resapower.com Jody Medina

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CE Power Solutions of Florida, LLC 3502 Riga Blvd., Suite C Tampa, FL 33619 (866) 439-2992

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CE Power Solutions of Florida, LLC 3801 SW 47th Avenue, Suite 505 Davie, FL 33314 (866) 439-2992

connecticut 45

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Advanced Testing Systems 15 Trowbridge Dr. Bethel, CT 06801 (203) 743-2001 Fax: (203) 743-2325 [email protected] www.advtest.com Pat MacCarthy American Electrical Testing Co., Inc. 34 Clover Dr. South Windsor, CT 06074 (860) 648-1013 Fax: (781) 821-0771 [email protected] www.aetco.com Gerald Poulin EPS Technology 29 N. Plains Highway, Suite 12 Wallingford, CT 06492 (203) 679-0145 [email protected] www.eps-technology.com Sean Miller

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Electric Power Systems, Inc. 4436 Parkway Commerce Blvd. Orlando, FL 32808 (407) 578-6424 Fax: (407) 578-6408 www.epsii.com

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Electrical Reliability Services 11000 Metro Pkwy., Suite 30 Ft. Myers, FL 33966 (239) 693-7100 Fax: (239) 693-7772

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Electrical Testing, Inc. 2671 Cedartown Highway Rome, GA 30161-6791 (706) 234-7623 Fax: (706) 236-9028 [email protected] www.electricaltestinginc.com Jamie Dempsey

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Nationwide Electrical Testing, Inc. 6050 Southard Trace Cumming, GA 30040 (770) 667-1875 Fax: (770) 667-6578 [email protected] www.n-e-t-inc.com Shashikant B. Bagle

illinois 62

Dude Electrical Testing, LLC 145 Tower Dr., Ste 9 Burr Ridge, IL 60527 (815) 293-3388 Fax: (815) 293-3386 [email protected] www.dudetesting.com Scott Dude

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Electric Power Systems, Inc. 54 Eisenhower Lane North Lombard, IL 60148 (815) 577-9515 www.epsii.com

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High Voltage Maintenance Corp. 941 Busse Rd. Elk Grove Village, IL 60007 (847) 640-0005 www.hvmcorp.com

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Midwest Engineering Consultants, Ltd. 2500 36th Ave Moline, IL 61265-6954 (309) 764-1561 [email protected] www.midwestengr.com Monte Moorehead

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Shermco Industries 112 Industrial Drive Minooka, IL 60447-9557 (815) 467-5577 [email protected] www.shermco.com

RESA Power Service 1401 Mercantile Court Plant City, FL 33563 (813) 752-6550 www.resapower.com

georgia 56

High Voltage Maintenance Corp. 150 North Plains Industrial Rd. Wallingford, CT 06492 (203) 949-2650 Fax: (203) 949-2646 www.hvmcorp.com Southern New England Electrical Testing, LLC 3 Buel St., Suite 4 Wallingford, CT 06492 (203) 269-8778 Fax: (203) 269-8775 [email protected] www.sneet.org David Asplund, Sr.

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florida 50

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C.E. Testing, Inc. 6148 Tim Crews Rd. Macclenny, FL 32063 (904) 653-1900 Fax: (904) 653-1911 [email protected] www.cetestinginc.com Mark Chapman

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ABM Electrical Power Services, LLC 1005 Windward Ridge Pkwy Alpharetta, GA 30005 (770) 521-7550 www.abm.com Electric Power Systems, Inc. 6679 Peachtree Industrial Dr., Suite H Norcross , GA 30092 (770) 416-0684 www.epsii.com Electrical Equipment Upgrading, Inc. 21 Telfair Place Savannah, GA 31415 (912) 232-7402 Fax: (912) 233-4355 [email protected] www.eeu-inc.com Kevin Miller Electrical Reliability Services 2275 Northwest Parkway SE, Suite 180 Marietta, GA 30067 (770) 541-6600 Fax: (770) 541-6501

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indiana 67

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CE Power Engineered Services, LLC 3496 E. 83rd Place Merrillville, IN 46410 (219) 942-2346 www.cepower.net

Shermco Industries 2100 Dixon Street, Suite C Des Moines, IA 50316-2174 (515) 263-8482

75

Shermco Industries 5145 NW Beaver Dr. Johnston, IA 50131 (515) 265-3377 www.shermco.com

Electric Power Systems, Inc. 7169 East 87th St. Indianapolis, IN 46256 (317) 941-7502 www.epsii.com Daniel Douglas

kentucky

69

Electrical Maintenance & Testing, Inc. 12342 Hancock St. Carmel, IN 46032 (317) 853-6795 Fax: (317) 853-6799 [email protected] www.emtesting.com Brian K. Borst

70

High Voltage Maintenance Corp. 8320 Brookville Rd., Ste E Indianapolis, IN 46239 (317) 322-2055 Fax: (317) 322-2056 www.hvmcorp.com

71

Premier Power Maintenance Corporation 4035 Championship Drive Indianapolis, IN 46268 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

72

Premier Power Maintenance Corporation 4537 S Nucor Rd. Crawfordsville, IN 47933 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

iowa 73

74

Shermco Industries 1711 Hawkeye Dr. Hiawatha, IA 52233 (319) 377-3377 [email protected] www.shermco.com

76

77

78

Electrical Reliability Services 9636 St. Vincent, Unit A Shreveport, LA 71106 (318) 869-4244 [email protected]

83

Saber Power Services, LLC 14617 Perkins Road Baton Rouge, LA 70810 (225) 726-7793 www.saberpower.com

84

Tidal Power Services, LLC 8184 Highway 44, Suite 105 Gonzales, LA 70737 (225) 644-8170 Fax: (225) 644-8215 www.tidalpowerservices.com Darryn Kimbrough

CE Power Engineered Services, LLC 1803 Taylor Ave. Louisville, KY 40213 (800) 434-0415 [email protected] 85 Tidal Power Services, LLC www.cepower.net 1056 Mosswood Dr. Bob Sheppard Sulphur, LA 70665 (337) 558-5457 Fax: (337) 558-5305 High Voltage Maintenance Corp. www.tidalpowerservices.com 10704 Electron Drive Steve Drake Louisville, KY 40299 (859) 371-5355 maine www.hvmcorp.com 86 CE Power Engineered Services, LLC Premier Power Maintenance 72 Sanford Drive Corporation Gorham, ME 04038 2725 Jason Rd (800) 649-6314 Ashland, KY 41102-7756 [email protected] (606) 929-5969 www.cepower.net [email protected] Jim Cialdea www.premierpowermaintenance.com 87 Electric Power Systems, Inc. Jay Milstead 56 Bibber Pkwy #1 Brunswick, ME 04011-7357 (207) 837-6527 louisiana www.epsii.com

79

Electric Power Systems, Inc. 1129 East Highway 30 Gonzalez, LA 70737 (225) 644-0150 Fax: (225) 644-6249 www.epsii.com

80

Electrical Reliability Services 245 Hood Road Sulphur, LA 70665-8747 (337) 583-2411 [email protected]

81

82

Electrical Reliability Services 3535 Emerson Pkwy, Ste A Gonzales, LA 70737 (225) 755-0530 [email protected]

88

POWER Testing and Energization, Inc. 303 US Route One Freeport,ME 04032 (207) 869-1200 www.powerte.com

maryland 89

ABM Electrical Power Solutions 3700 Commerce Dr., #901- 903 Baltimore, MD 21227 (410) 247-3300 Fax: (410) 247-0900 www.abm.com

For additional information on NETA visit netaworld.org

90

ABM Electrical Power Solutions 4390 Parliament Pl., Suite S Lanham, MD 20706 (301) 967-3500 Fax: (301) 735-8953 [email protected] www.abm.com Christopher Smith

91

Harford Electrical Testing Co., Inc. 1108 Clayton Rd. Joppa, MD 21085 (410) 679-4477 [email protected] www.harfordtesting.com Vincent Biondino

92

High Voltage Maintenance Corp. 9305 Gerwig Ln., Suite B Columbia, MD 21046 (410) 309-5970 Fax: (410) 309-0220 www.hvmcorp.com

93

High Voltage Maintenance Corp. 14300 Cherry Lane Court, Ste 115 Laurel, MD 20707 (410) 279-0798 www.hvmcorp.com

94

95

97

Electrical Engineering & Service Co. Inc. 289 Centre St. Holbrook, MA 02343 (781) 767-9988 [email protected] www.eescousa.com Joe Cipolla

99

High Voltage Maintenance Corp. 24 Walpole Park S Walpole, MA 02081-2541 (508) 668-9205 www.hvmcorp.com

100

Infra-Red Building and Power Service, Inc. 152 Centre St Holbrook, MA 02343-1011 (781) 767-0888 [email protected] www.infraredbps.com

106

Premier Power Maintenance Corporation 7262 Kensington Rd. Brighton, MI 48116 (517) 230-6620 [email protected] www.premierpowermaintenance.com Brian Ellegiers

108

RESA Power Service 46918 Liberty Dr Wixom, MI 48393-3600 (248) 313-6868 [email protected] www.resapower.com Bruce Robinson

109

Shermco Industries 12796 Currie Court Livonia, MI 48150 (734) 469-4050 [email protected] www.shermco.com

michigan 101

CE Power Engineered Services, LLC 10338 Citation Drive, Ste 300 Brighton, MI 48116 (810) 229-6628 [email protected] www.cepower.net Ken L’Esperance

104

American Electrical Testing Co., LLC 25 Forbes Boulevard, Ste 1 Foxboro, MA 02035 (781) 821-0121 [email protected] www.aetco.us Scott Blizard CE Power Engineered Services, LLC 40 Washington St Westborough, MA 01581-1088 (508) 881-3911 www.cepower.net

Northern Electrical Testing, Inc. 1991 Woodslee Dr. Troy, MI 48083-2236 (248) 689-8980 Fax: (248) 689-3418 [email protected] www.northerntesting.com Lyle Detterman

105 POWER

PLUS Engineering, Inc. 47119 Cartier Court Wixom, MI 48393-2872 (248) 896-0200

Powertech Services, Inc. 4095 South Dye Rd. Swartz Creek, MI 48473-1570 (810) 720-2280 Fax: (810) 720-2283 [email protected] www.powertechservices.com Kirk Dyszlewski

107

Potomac Testing, Inc. 1610 Professional Blvd., Ste A Crofton, MD 21114 (301) 352-1930 Fax: (301) 352-1936 110 [email protected] 102 Electric Power Systems, Inc. www.potomactesting.com 11861 Longsdorf St. Ken Bassett Riverview, MI 48193 (734) 282-3311 Reuter & Hanney, Inc. www.epsii.com 11620 Crossroads Cir., Suites D-E Middle River, MD 21220 103 High Voltage Maintenance Corp. (410) 344-0300 Fax: (410) 335-4389 24371 Catherine Industrial Dr., Ste 207 [email protected] Novi, MI 48375 www.reuterhanney.com (248) 305-5596 Fax: (248) 305-5579 Michael Jester www.hvmcorp.com 111

massachusetts 96

98

112

Utilities Instrumentation Service, Inc. 2290 Bishop Circle East Dexter, MI 48130 (734) 424-1200 Fax: (734) 424-0031 [email protected] www.uiscorp.com Gary E. Walls

minnesota CE Power Engineered Services, LLC 7674 Washington Ave. S Eden Prairie, MN 55344 (877) 968-0281 [email protected] www.cepower.net Jason Thompson RESA Power Service 3890 Pheasant Ridge Dr. NE, Ste 170 Blaine, MN 55449 (763) 784-4040 [email protected] www.resapower.com Mike Mavetz

For additional information on NETA visit netaworld.org

113

Shermco Industries 998 E. Berwood Ave. Saint Paul, MN 55110 (651) 484-5533 [email protected] www.shermco.com

121

122

missouri 114

115

116

117

Electric Power Systems, Inc. 6141 Connecticut Ave. Kansas City, MO 64120 (816) 241-9990 Fax: (816) 241-9992 www.epsii.com Electric Power Systems, Inc. 21 Millpark Ct. Maryland Heights, MO 63043-3536 (314) 890-9999 Fax:(314) 890-9998 www.epsii.com

123

Electrical Reliability Services 124 400 NW Capital Dr Lees Summit, MO 64086 (816) 525-7156 Fax: (816) 524-3274 [email protected] POWER Testing and Energization, Inc. 12755 Olive Blvd., Ste 100 Saint Louis, MO 63141 (314) 851-4065 www.powerte.com

125

nebraska 118

Shermco Industries 4670 G. Street Omaha, NE 68117 (402) 933-8988 [email protected] www.shermco.com

120

126

Control Power Concepts 353 Pilot Rd, Suite B Las Vegas, NV 89119 (702) 448-7833 Fax: (702) 448-7835 [email protected] www.controlpowerconcepts.com John Travis Electric Power Systems, Inc. 5850 Polaris Ave., Suite 1600 Las Vegas, NV 89118 (702) 815-1342 www.epsii.com

Electrical Reliability Services 1380 Greg St., Suite 217 Sparks, NV 89431 (775) 746-8484 Fax: (775) 356-5488 www.electricalreliability.com Hampton Tedder Technical Services 4113 Wagon Trail Ave. Las Vegas, NV 89118 (702) 452-9200 www.hamptontedder.com Roger Cates National Field Services 3711 Regulus Ave. Las Vegas, NV 89102 (888) 296-0625 [email protected] www.natlfield.com Howard Herndon National Field Services 2900 Vassar St. #114 Reno, NV 89502 (775) 410-0430 www.natlfield.com Howard Herndon [email protected]

Electric Power Systems, Inc. 915 Holt Ave., Unit 9 Manchester, NH 03109 (603) 657-7371 www.epsii.com

Eastern High Voltage 11A South Gold Dr. Robbinsville, NJ 08691-1606 (609) 890-8300 Fax: (609) 588-8090 [email protected] www.easternhighvoltage.com Robert Wilson

130

High Energy Electrical Testing, Inc. 515 S. Ocean Ave. Seaside Park, NJ 08752 (732) 938-2275 Fax: (732) 938-2277 [email protected] www.highenergyelectric.com Charles Blanchard

131

132

American Electrical Testing Co., Inc. 91 Fulton St. Boonton, NJ 07005 (973) 316-1180 [email protected] www.aetco.com Jeff Somol

J.G. Electrical Testing Corporation 3092 Shafto Road, Suite 13 Tinton Falls, NJ 07753 (732) 217-1908 www.jgelectricaltesting.com Howard Trinkowsky M&L Power Systems, Inc. 109 White Oak Ln., Suite 82 Old Bridge, NJ 08857 (732) 679-1800 Fax: (732) 679-9326 [email protected] www.mlpower.com Milind Bagle

133

RESA Power Service 311 Bay Avenue A Highlands, NJ 07732 (888) 996-9975 [email protected] www.resapower.com Trent Robbins

134

Scott Testing, Inc. 245 Whitehead Rd Hamilton, NJ 08619 (609) 689-3400 [email protected] www.scotttesting.com Russ Sorbello

new jersey 127

Burlington Electrical Testing Co., Inc. 198 Burrs Rd. Westampton, NJ 08060 (609) 267-4126 [email protected] www.betest.com Walter P. Cleary

129

new hampshire

nevada 119

Electrical Reliability Services 128 6351 Hinson St., Suite A Las Vegas, NV 89118 (702) 597-0020 Fax: (702) 597-0095 www.electricalreliability.com

For additional information on NETA visit netaworld.org

135

Trace Electrical Services 142 & Testing, LLC 293 Whitehead Rd. Hamilton, NJ 08619 (609) 588-8666 Fax: (609) 588-8667 www.tracetesting.com Joseph Vasta

new mexico 136

137

138

143

Electric Power Systems, Inc. 8515 Cella Alameda NE, Suite A Albuquerque, NM 87113 (505) 792-7761 www.eps-international.com Electrical Reliability Services 8500 Washington Pl. NE, Suite A-6 Albuquerque, NM 87113 (505) 822-0237 Fax: (505) 822-0217 www.electricalreliability.com Western Electrical Services, Inc. 620 Meadow Ln. Los Alamos, NM 87547 (505) 469-1661 [email protected] www.westernelectricalservices.com Toby King

144

145

new york 139

140

141

BEC Testing 50 Gazza Blvd Farmingdale, NY 11735-1402 (631) 393-6800 [email protected] www.bectesting.com Daniel Devlin Elemco Services, Inc. 228 Merrick Rd. Lynbrook, NY 11563 (631) 589-6343 [email protected] www.elemco.com Courtney Gallo High Voltage Maintenance Corp. 1250 Broadway, Suite 2300 New York, NY 10001 (718) 239-0359 www.hvmcorp.com

149

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152

HMT, Inc. 6268 Route 31 Cicero, NY 13039 (315) 699-5563 Fax: (315) 699-5911 [email protected] www.hmt-electric.com John Pertgen

A&F Electrical Testing, Inc. 80 Broad St., 5th Floor New York, NY 10004 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Florence Chilton American Electrical Testing Co., Inc. 76 Cain Dr. Brentwood, NY 11717 (631) 617-5330 Fax: (631) 630-2292 [email protected] www.aetco.com Billy Fernandez

146

147

148

ABM Electrical Power Services, LLC 6541 Meridien Dr, Suite 113 Raleigh, NC 27616 (919) 877-1008 www.abm.com ABM Electrical Power Services, LLC 3600 Woodpark Blvd., Suite G Charlotte, NC 28206 (704) 273-6257 Fax: (704) 598-9812 [email protected] www.abm.com Ernest Goins ELECT, P.C. 375 E. Third Street Wendell, NC 27591 (919) 365-9775 [email protected] www.elect-pc.com Barry W. Tyndall

Electrical Reliability Services 6135 Lakeview Road, Suite 500 Charlotte, NC 28269 (704) 441-1497 [email protected] www.electricalreliability.com Power Products & Solutions, LLC 6605 W WT Harris Blvd, Suite F Charlotte, NC 28269 (704) 573-0420 x12 [email protected] www.powerproducts.biz Adis Talovic Power Test, Inc. 2200 Hwy. 49 S Harrisburg, NC 28075 (704) 200-8311 Fax: (704) 455-7909 [email protected] www.powertestinc.com Richard Walker

ohio 153

ABM Electrical Power Solutions 1817 O’Brien Road Columbus, OH 43228 (724) 772-4638 www.abm.com

154

CE Power Engineered Services, LLC 4040 Rev Drive Cincinnati, OH 45232 (800) 434-0415 [email protected] www.cepower.net Brent McAlister

155

CE Power Engineered Services, LLC 8490 Seward Rd. Fairfield, OH 45011 (800) 434-0415 [email protected] www.cepower.net Tim Lana

156

Electric Power Systems, Inc. 2888 Nationwide Parkway, 2nd Floor Brunswick, OH 44212 (330) 460-3706 www.epsii.com

north carolina

A&F Electrical Testing, Inc. 80 Lake Ave. S., Suite 10 Nesconset, NY 11767 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Kevin Chilton

Electric Power Systems, Inc. 319 US Hwy. 70 E, Suite E Garner, NC 27529 (919) 210-5405 www.eps-international.com

For additional information on NETA visit netaworld.org

157

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161

Electrical Reliability Services 610 Executive Campus Dr. Westerville, OH 43082 (877) 468-6384 Fax: (614) 410-8420 [email protected] www.electricalreliability.com High Voltage Maintenance Corp. 5100 Energy Dr. Dayton, OH 45414 (937) 278-0811 Fax: (937) 278-7791 www.hvmcorp.com

oklahoma 165

166

High Voltage Maintenance Corp. 7200 Industrial Park Blvd. Mentor, OH 44060 (440) 951-2706 Fax: (440) 951-6798 www.hvmcorp.com Power Solutions Group Ltd. 425 W Kerr Rd Tipp City, OH 45371-2843 (937) 506-8444 [email protected] www.powersolutionsgroup.com Barry Willoughby

RESA Power Service 4540 Boyce Parkway Stow, OH 44224 (800) 264-1549 www.resapower.com

163

Shermco Industries 4383 Professional Parkway Groveport, OH 43125 (614) 836-8556 [email protected] www.shermco.com

164

Utilities Instrumentation Service - Ohio, LLC PO Box 750066 998 Dimco Way Dayton, OH 45475-0066 (937) 439-9660

Shermco Industries 4510 South 86th East Ave. Tulsa, OK 74145 (918) 234-2300 [email protected] www.shermco.com

174

167

168

Electrical Reliability Services 4099 SE International Way, Suite 201 Milwaukie, OR 97222-8853 (503) 653-6781 Fax: (503) 659-9733 www.electricalreliability.com

169

ABM Electrical Power Solutions 317 Commerce Park Drive Cranberry Township, PA 16066-6407 (724) 772-4638 www.abm.com

170

American Electrical Testing Co., Inc. Green Hills Commerce Center 5925 Tilghman St., Suite 200 Allentown, PA 18104 (215) 219-6800 [email protected] www.aetco.com Jonathan Munley

171

172

176

Reuter & Hanney, Inc. 149 Railroad Dr. Northampton Industrial Park Ivyland, PA 18974 (215) 364-5333 Fax: (215) 364-5365 [email protected] www.reuterhanney.com Michael Jester

south carolina 177

Power Products & Solutions, LLC 13 Jenkins Ct. Mauldin, SC 29662 (800) 328-7382 [email protected] www.powerproducts.biz Raymond Pesaturo

178

Power Products & Solutions, LLC 9481 Industrial Center Dr. Unit 5 Ladson, SC 29456 (844) 383-8617 www.powerproducts.biz

179

Power Solutions Group Ltd. 5115 Old Greenville Highway Liberty, SC 29657 (864) 540-8434 [email protected] www.powersolutionsgroup.com Anthony Crawford

Burlington Electrical Testing Co., Inc. 300 Cedar Ave. Croydon, PA 19021-6051 (215) 826-9400 Fax: (215) 826-0964 www.betest.com Electric Power Systems, Inc. 1090 Montour West Industrial Blvd. Coraopolis, PA 15108 (412) 276-4559 www.epsii.com

High Voltage Maintenance Corp. 355 Vista Park Dr. Pittsburgh, PA 15205-1206 (412) 747-0550 Fax: (412) 747-0554 www.hvmcorp.com North Central Electric, Inc. 69 Midway Ave. Hulmeville, PA 19047-5827 (215) 945-7632 Fax: (215) 945-6362 [email protected] www.ncetest.com Robert Messina

Taurus Power & Controls, Inc. 9999 SW Avery St. Tualatin, OR 97062-9517 (503) 692-9004 Fax: (503) 692-9273 [email protected] www.tauruspower.com Rob Bulfinch

pennsylvania

EnerG Test, LLC 204 Gale Lane, Bldg. 2 – 2nd Floor Kennett Square, PA 19348 (484) 731-0200 Fax: (484) 713-0209 [email protected] www.energtest.com Dennis Buehler

175

oregon

Power Solutions Group Ltd. 2739 Sawbury Blvd. Columbus, OH 43235 (614) 310-8018 [email protected] www.powersolutionsgroup.com Stuart Spohn

162

Sentinel Power Services, Inc. 7517 E Pine St Tulsa, OK 74115-5729 (918) 359-0350 [email protected] www.sentinelpowerservices.com Greg Ellis

173

180

POWER Testing and Energization, Inc. 1041 Red Ventures Dr., Suite 105 Fort Mill, SC 29707 (803) 835-5900 www.powerte.com

For additional information on NETA visit netaworld.org

tennesee 181

182

183

184

185

186

187

188

189

Electrical Reliability Services 1057 Doniphan Park Cir Ste A El Paso, TX 79922-1329 (915) 587-9440 [email protected]

CE Power Engineered Services, LLC 480 Cave Rd Nashville, TN 37210-2302 (615) 882-9455 190 Electrical Reliability Services [email protected] 1426 Sens Rd Ste 5 www.cepower.net La Porte, TX 77571-9656 Bryant Phillips (281) 241-2800 CE Power Engineered Services, LLC [email protected] 10840 Murdock Drive 191 Grubb Engineering, Inc. Knoxville , TN 37932 2727 North Saint Mary’s St. (800) 434-0415 San Antonio, TX 78212 [email protected] (210) 658-7250 www.cepower.net [email protected] Don William www.grubbengineering.com Electric Power Systems, Inc. Robert D. Grubb Jr. 684 Melrose Avenue 192 Magna IV Engineering Nashville, TN 37211-3121 4407 Halik Street Building E, Suite 300 (615) 834-0999 www.epsii.com Pearland, TX 77581 (346) 221-2165 Electrical & Electronic Controls [email protected] 6149 Hunter Rd. www.magnaiv.com Ooltewah, TN 37363 Aric Proskurniak (423) 344-7666 Fax: (423) 344-4494 193 National Field Services [email protected] Michael Hughes 651 Franklin Lewisville, TX 75057-2301 Electrical Testing and (972) 420-0157 Maintenance Corp. www.natlfield.com 3673 Cherry Rd Ste 101 Eric Beckman Memphis, TN 38118-6313 (901) 566-5557 194 National Field Services [email protected] 1890 A South Hwy 35 www.etmcorp.net Alvin, TX 77511 Ron Gregory (800) 420-0157 [email protected] Power Solutions Group, Ltd. www.natlfield.com 172 B-Industrial Dr. Jonathan Wakeland Clarksville, TN 37040 195 National Field Services (931) 572-8591 www.powersolutionsgroup.com 1405 United Drive, Suite 113-115 San Marcos, TX 78666 Chris Brown (800) 420-0157 [email protected] texas www.natlfield.com Matt LaCoss Absolute Testing Services, Inc. 8100 West Little York 196 Power Engineering Services, Inc. Houston, TX 77040 9179 Shadow Creek Ln (832) 467-4446 Converse, TX 78109-2041 www.absolutetesting.com (210) 590-4936 [email protected] Electric Power Systems, Inc. www.pe-svcs.com 1330 Industrial Blvd., Suite 300 Daniel Staudt Sugar Land, TX 77478 (713) 644-5400 www.epsii.com

197

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199

200

201

POWER Testing and Energization, Inc. 16825 Northchase Drive Houston, TX 77060 (281) 765-5536 www.powerte.com Saber Power Services, LLC 9841 Saber Power Ln Rosharon, TX 77583-5188 (713) 222-9102 [email protected] www.saberpower.com Saber Power Services, LLC 4703 Shavano Oak, Suite 104 San Antonio, TX 78249 (210) 267-7282 www.saberpower.com Saber Power Services, LLC 1315 FM 1187, Suite 105 Mansfield, TX 76063 (682) 518-3676 www.saberpower.com Shermco Industries 2425 E Pioneer Dr Irving, TX 75061-8919 (972) 793-5523 [email protected] www.shermco.com

202

Shermco Industries 1705 Hur Industrial Blvd Cedar Park, TX 78613-7229 (512) 267-4800 [email protected] www.shermco.com

203

Shermco Industries 33002 FM 2004 Angleton, TX 77515-8157 (979) 848-1406 [email protected] www.shermco.com

204

Shermco Industries 12000 Network Blvd, Buidling D Suite 410 San Antonio, TX 78249-3354 (210) 877-9090 [email protected] www.shermco.com

205

Shermco Industries 3807 S Sam Houston Pkwy W Houston, TX 77056 (281) 835-3633 [email protected] www.shermco.com

For additional information on NETA visit netaworld.org

206

207

208

209

210

Shermco Industries 1301 Hailey St. Sweetwater, TX 79556 (325) 236-9900 [email protected] www.shermco.com

214

Shermco Industries 2901 Turtle Creek Dr. Port Arthur, TX 77642 (409) 853-4316 [email protected] www.shermco.com

215

216

Tidal Power Services, LLC 4211 Chance Ln Rosharon, TX 77583-4384 (281) 710-9150 [email protected] www.tidalpowerservices.com Monty C. Janak

Titan Quality Power Services, LLC 7630 Ikes Tree Drive Spring, TX 77389 (281) 826-3781 www.titanqps.com

utah 211

212

ABM Electrical Power Solutions 814 Greenbrier Cir., Suite E Chesapeake, VA 23320 (757) 364-6145 www.abm.com Mark Anthony Gaughan, III

223

Reuter & Hanney, Inc. 4270-I Henninger Ct. Chantilly, VA 20151 (703) 263-7163 Fax: (703) 263-1478 www.reuterhanney.com 224

Electrical Reliability Services 2222 West Valley Hwy. N., Suite 160 Auburn, WA 98001 (253) 736-6010 Fax: (253) 736-6015 [email protected] www.electricalreliability.com 225

219

226 Sigma Six Solutions, Inc. 2200 West Valley Hwy., Suite 100 Auburn, WA 98001 (253) 333-9730 Fax: (253) 859-5382 [email protected] www.sigmasix.com John White

Western Electrical Services, Inc. 220 3676 W. California Ave.,#C-106 Salt Lake City, UT 84104 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Rob Coomes

Western Electrical Services, Inc. 4510 NE 68th Dr., Suite 122 Vancouver, WA 98661 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Tony Asciutto

wisconsin

POWER Testing and Energization, Inc. 14006 NW 3rd Ct, Ste 101 Vancouver, WA 98685-5793 (360) 597-2800 [email protected] www.powerte.com Chris Zavadlov

221

213

222

218

Electrical Reliability Services 9736 South 500 West Sandy, UT 84070 (801) 975-6461 [email protected]

virginia

Electric Power Systems, Inc. 306 Ashcake Road, Suite A Ashland, VA 23005 (804) 526-6794 www.epsii.com

washington 217

Titan Quality Power Services, LLC 1501 S Dobson Street Burleson, TX 76028 (866) 918-4826 www.titanqps.com

Electric Power Systems, Inc. 120 Turner Road Salem, VA 24153-5120 (540) 375-0084 www.epsii.com

Electrical Energy Experts, Inc. W129N10818, Washington Dr. Germantown,WI 53022 (262) 255-5222 Fax: (262) 242-2360 [email protected] www.electricalenergyexperts.com Tim Casey Electrical Testing Solutions 2909 Green Hill Ct. Oshkosh, WI 54904 (920) 420-2986 Fax: (920) 235-7136 [email protected] www.electricaltestingsolutions.com Tito Machado Energis High Voltage Resources, Inc. 1361 Glory Rd. Green Bay, WI 54304 (920) 632-7929 Fax: (920) 632-7928 [email protected] www.energisinc.com Mick Petzold High Voltage Maintenance Corp. 3000 S. Calhoun Rd. New Berlin, WI 53151 (262) 784-3660 Fax: (262) 784-5124 www.hvmcorp.com

Taurus Power & Controls, Inc. 19226 66th Ave S. #L102 Kent, WA 98032-2197 (425) 656-4170 www.tauruspower.com Western Electrical Services, Inc. 14311 29th St. East Sumner, WA 98390 (253) 891-1995 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Dan Hook

For additional information on NETA visit netaworld.org

CANADA

236

227

Magna IV Engineering Suite 200, 688 Heritage Dr. SE Calgary, AB T2H 1M6 Canada (403) 723-0575 Fax: (403) 723-0580 www.magnaiv.com

228

Magna IV Engineering 1103 Parsons Rd. SW Edmonton, AB T6X 0X2 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Virginia Balitski

229

230

231

232

233

234

235

Magna IV Engineering 106, 4268 Lozells Ave. Burnaby, BC VSA 0C6 Canada (604) 421-8020

237

238

Magna IV Engineering 141 Fox Cresent Fort McMurray, AB T9K 0C1 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Ryan Morgan Shermco Industries Canada 3434 25th Street NE Calgary, AB T1Y 6C1 (403) 769-9300 [email protected] www.shermco.com

239

240

Shermco Industries Canada 241 3731-98 Street Edmonton, AB T6E 5N2 Canada (780) 436-8831 Fax: (780) 463-9646 [email protected] www.shermco.com Shermco Industries Canada 1033 Kearns Crescent RM of Sherwood SK S4K 0A2 (306) 949-8131 [email protected] www.shermco.com Shermco Industries Canada 1375 Church Ave. Winnipeg, MB R2X 2T7 Canada (204) 925-4022 Fax: (204) 925-4021 www.shermco.com Orbis Engineering Field Services Ltd. #300, 9404 - 41st Ave. Edmonton, AB T6E 6G8 Canada (780) 988-1455 Fax: (780) 988-0191 [email protected] www.orbisengineering.net Lorne Gara

REV 01.19

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244

Pacific Powertech, Inc. 245 #110, 2071 Kingsway Ave. Port Coquitlam, BC V3C 6N2 Canada (604) 944-6697 Fax: (604) 944-1271 [email protected] www.pacificpowertech.ca Josh Konkin REV Engineering Ltd. 3236 - 50 Ave. SE Calgary, AB T2B 3A3 Canada (403) 287-0156 Fax: (403) 287-0198 [email protected] www.reveng.ca Roland Nicholas Davidson, IV Rondar Inc. 333 Centennial Parkway North Hamilton, ON L8E2X6 (905) 561-2808 www.rondar.com Gary Hysop

BRUSSELS 246

Magna IV Engineering 7, 3040 Miners Ave. Saskatoon, SK S7K 5V1 (306) 713-2167 www.magnaiv.com Adam Jaques [email protected] Pace Technologies, Inc. #10, 883 McCurdy Place Kelowna , BC V1X 8C8 (250) 712-0091 www.pacetechnologies.com

Shermco Industries Boulevard Saint-Michel 47 1040 Brussels, Brussels, Belgium +32 (0)2 400 00 54 Fax: +32 (0)2 400 00 32 [email protected] www.shermco.com

CHILE 247

Magna IV Engineering Avenida del Condor Sur #590 Officina 601 Huechuraba, Santiago 8580676 Chile +(56) -2-26552600 [email protected] Henry Mendoza

248

Orbis Engineering Field Services Ltd. Badajoz #45, Piso 17 Las Condes, Santiago +56 2 29402343 www.orbisengineering.net

Rondar Inc. 9-160 Konrad Crescent Markham, ON L3R9T9 (905) 943-7640 www.rondar.com Shermco Industries Canada 233 Faithfull Cr. Saskatoon, SK S7K 8H7 (306) 955-8131 www.shermco.com [email protected]

Pace Technologies, Inc. 9604 - 41 Avenue NW Edmonton, AB T6E 6G9 (780) 450-0404 [email protected] www.pacetechnologies.com Craig Leavitt

PUERTO RICO 249

Phasor Engineering Sabaneta Industrial Park #216 Mercedita, PR 00715 Puerto Rico (787) 844-9366 Fax: (787) 841-6385 [email protected] www.phasorinc.com Rafael Castro

Advanced Electrical Services 4999 - 43rd St. NE, Unit 143 Calgary, AB T2B 3N4 (403) 697-3747 [email protected] www.aes-ab.com Zachary Houk Orbis Engineering Field Services Ltd. #228 - 18 Royal Vista Link NW Calgary, AB T3R 0K4 (403) 374-0051 www.orbisengineering.net

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ABOUT THE INTERNATIONAL ELECTRICAL TESTING ASSOCIATION The InterNational Electrical Testing Association (NETA) is an accredited standards developer for the American National Standards Institute (ANSI) and defines the standards by which electrical equipment is deemed safe and reliable. NETA Certified Technicians conduct the tests that ensure this equipment meets the Association’s stringent specifications. NETA is the leading source of specifications, procedures, testing, and requirements, not only for commissioning new equipment but for testing the reliability and performance of existing equipment.

CERTIFICATION Certification of competency is particularly important in the electrical testing industry. Inherent in the determination of the equipment’s serviceability is the prerequisite that individuals performing the tests be capable of conducting the tests in a safe manner and with complete knowledge of the hazards involved. They must also evaluate the test data and make an informed judgment on the continued serviceability, deterioration, or nonserviceability of the specific equipment. NETA, a nationally-recognized certification agency, provides recognition of four levels of competency within the electrical testing industry in accordance with ANSI/NETA ETT2018 Standard for Certification of Electrical Testing Technicians.

QUALIFICATIONS OF THE TESTING ORGANIZATION An independent overview is the only method of determining the long-term usage of electrical apparatus and its suitability for the intended purpose. NETA Accredited Companies best support the interest of the owner, as the objectivity and competency of the testing firm is as important as the competency of the individual technician. NETA Accredited Companies are part of an independent, third-party electrical testing association dedicated to setting world standards in electrical maintenance and acceptance testing. Hiring a NETA Accredited Company assures the customer that: • The NETA Technician has broad-based knowledge — this person is trained to inspect, test, maintain, and calibrate all types of electrical equipment in all types of industries. • NETA Technicians meet stringent educational and experience requirements in accordance with ANSI/NETA ETT-2018 Standard for Certification of Electrical Testing Technicians. • A Registered Professional Engineer will review all engineering reports • All tests will be performed objectively, according to NETA specifications, using calibrated instruments traceable to the National Institute of Science and Technology (NIST). • The firm is a well-established, full-service electrical testing business.

Setting the Standard

54

Insulating Oils

VOLUME 1

MAINTENANCE

SERIES III

HANDBOOK

MAINTENANCE Vol. 1 HANDBOOK

SERIES III

Published By Sponsored by

Shermco Industries

Oil Analysis Services

from

Available 24 hours a day for emergency needs, Shermco’s analytics services include preventative maintenance and recommendations from three in-house analysts, who offer more than 60 years of experience with transformer oil analysis, testing and chemistry. The oil lab offers the electrical maintenance and testing industry a credible partner in insulating oil analysis. Further, Shermco can provide a timely turnaround and accurate testing of mineral, silicone and FR3 oils, including test values, trends and recommended repair.

Maintenance Services Furanic Compounds (cellulose degradation)

Specific Gravity

Degree of Polymerization of Insulating

Corrosive Sulfur Test

Passivator Inhibitor Test

Dissolved Metal Analysis

Particle Count Test

Polychlorinated Biphenyls (PCB) Analysis

Temperature and Viscosity Tests

Power Factor Tests at Both 25°C and 100°C

Wear Debris Using Analytical Ferrography

Essential Tests Acid Number

Dissolved Gas Analysis

Interfacial Tension

Dielectric

Color Comparison

Visual & Sediment Exam

Moisture

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MAINTENANCE VOLUME 1

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InterNational Electrical Testing Association

MAINTENANCE–Vol. 1 TABLE OF CONTENTS Dual Ground.................................................................................................... 5 Jeff Jowett

Maintenance Strategies and Their Applications..................................................... 7 Kerry Heid

Testing Rotating Machinery – Partial Discharge Interpretation.................................. 9 Vicki Warren

Technologies for Outdoor Substation and Switchyard Testing................................. 12 Don Genutis

Data Center Maintenance – Part 3 – Battery and Backup Generator Maintenance................................................................................... 14 Lynn Hamrick

Testing Rotating Machinery - Synchronous Rotor Winding Common Electrical Tests...................................................................... 18 Vicki Warren

Maintenance Testing of Wind Farm Distribution Systems....................................... 21 Don Genutis

Wind Farm Collector System – Predictive Maintenance Practices........................... 23 Paul Idziak

Wind Turbine Generator Electrical Failures......................................................... 27 William Chen

Published by

InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024 269.488.6382

www.netaworld.org

Up-Tower Electrical Testing of Wind Turbine Generator Stator and Rotor Main Windings................................................................................ 30

Kevin Alewine, Casey Gilliam

Electrical Power System Testing – A Quantum Change in our Field has Arrived........ 33 John Hodson

Synchronous Rotor Winding – Common Electrical Monitoring................................ 37 Vicki Warren

Switchgear Partial Discharge Location................................................................ 41 Don Genutis

VLF-MWT – How To Apply the New Way of Cable Condition Assessment............... 43 Martin Jenny, Alexander Gerstner, and Timothy Daniels

Detecting Common Power Quality Issues............................................................ 49

Andrew Sagl

Published by

InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024 269.488.6382

www.netaworld.org

Published by InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024 269.488.6382 www.netaworld.org

NOTICE AND DISCLAIMER NETA Technical Papers and Articles are published by the InterNational Electrical Testing Association. Opinions, views, and conclusions expressed in articles herein are those of the authors and not necessarily those of NETA. Publication herein does not constitute or imply any endorsement of any opinion, product, or service by NETA, its directors, officers, members, employees, or agents (hereinafter “NETA”). All technical data in this publication reflects the experience of individuals using specific tools, products, equipment, and components under specific conditions and circumstances which may or may not be fully reported and over which NETA has neither exercised nor reserved control. Such data has not been independently tested or otherwise verified by NETA. NETA makes no endorsement, representation or warranty as to any opinion, product or service referenced in this publication. NETA expressly disclaims any and all liability to any consumer, purchaser or any other person using any product or service referenced herein for any injuries or damages of any kind whatsoever, including, but not limited to, any consequential, special incidental, direct or indirect damages. NETA further disclaims any and all warranties, express or implied, including, but not limited to, any implied warranty or merchantability or any implied warranty of fitness for a particular purpose. Please Note: All authors and presenters contained herein are reflective of the professional standing of these individuals at the time the articles were originally published. Titles, companies, and other factors may have changed since the original publication date.

Copyright © 2019 by InterNational Electrical Testing Association, all rights reserved. No part of this publication may be reproduced in any form or by any means, electronic or mechanical, without permission in writing from the publisher.

5

Maintenance Vol. 1

DUAL GROUND NETA World, Winter 2016 Issue By Jeff Jowett, Megger

Testing circuit breakers for contact resistance is a vital part of many electrical maintenance programs. It requires a high level of sophistication in the test equipment.

the resistance. The tester then measures the voltage drop between the two potential probes. It now has measured the test current and voltage drop. Ohm’s Law does the rest.

First, test currents, which are far more robust than those of ordinary multimeters, are necessary to ensure full working contact across the contact surface. Most utilities specify a 100 A test. Second, resistance measurements must be made to a level of accuracy and precision far beyond that of many common applications. Utility standards generally require no more than 100 μΩ.

But in testing installed circuit breakers, physical and electrical impediments abound. The test connections may be 20 feet in the air and require a bucket truck or other means of ascension. Prohibitively long leads and grounding cables increase time and effort on the job. If dual grounds are in place on opposite sides of the breaker, protection is at a peak. The line being tested is, of course, de-energized. But in power systems, live lines nearby can inductively apply thousands of volts to the adjacent line. Current may sometimes be minimal, but the voltage is still dangerous for its shock value, especially to anyone working at elevation. And this interference current, if directed through the tester, can seriously distort the measurement.

The formula: W = I 2R where watts equal current squared times resistance, indicates how even relatively small changes in resistance can have a profound effect upon energy, which, as heat, can be both wasteful and dangerous. It is obvious that effective testing requires a level of instrumentation above and beyond the familiar DMM. To ensure high accuracy, safety is a high priority along with rigor in instrumentation and measurement. Industry standards, safe working practices, and the effective employment of personal protective clothing and equipment are indispensable. Furthermore, where worker safety is concerned, redundancy is a valuable ally. When high-voltage circuit breakers are taken out of service for maintenance, safety and system protection rules make it very difficult to allow removal of the temporary ground leads from 20 feet in the air, with power lines nearby that are subject to dangerous events like lightning strokes. Maximum safety is achieved by grounding both sides of the breaker, but that introduces another problem: a parallel current path.

A standard test setup is illustrated in Figure 1. Current is injected by the tester on one side of the breaker and returns to the tester via the ground on the opposite side. Once the safety ground is lifted, all of the test current must pass through the breaker to complete a circuit. The two potential connections are made across the contacts and inside of the current clamps. The tester itself is grounded for safety but does not take part in the measurement circuit. Inductive interference can be picked up by the test circuit and influence the reading.

LOW RESISTANCE TESTING VS. INSTALLED CIRCUIT BREAKER TESTING A brief review of low-resistance testing is in order. To achieve the accuracy and precision necessary to test circuit-breaker contact resistance — where a single ohm is far too much and even a few micro ohms can represent an unacceptable deterioration in performance — the tester must not incorporate lead- and probecontact resistance into the measurement. This is accomplished by four-wire (Kelvin bridge) measurement. The tester injects a DC test current through the specimen being measured. It can accurately measure this current to provide a basis for calculating

Fig. 1: Traditional Breaker Test Employing Single Ground Applying a second ground (Figure 2) keeps the operator safe and effectively diverts interference currents, but at the cost of accuracy in the measurement. There is now a parallel current path through the earth from one ground to the other, bypassing the circuit breaker entirely.

6

Maintenance Vol. 1 Fig. 3: Aerial Test with Lightweight, Handheld Instrument Employing Duplex Leads The earth is part of the circuit, but all test current passes through the breaker. There is no alternate path. As substations are typically shut down for a maximum four-hour period and must go back on line, the time saved in not having to lift the protective ground is significant. While the operator remains protected, this configuration would not do for an on-line substation as interference current would travel on the dual ground and degrade the measurement. For a de-energized station, it’s fine.

Fig. 2: Typical Dual Ground Test Typically, ground resistance is at least 2 mΩ — about 20 times the maximum acceptable contact resistance — which introduces a serious error into the measurement. This error can be eliminated by use of a current clamp built into the tester. The current clamp measures the parallel current and subtracts it from the value used to calculate the contact resistance. Only the current passing through the circuit breaker contact is then part of the measurement calculation, and the parallel path is effectively eliminated as a source of error. Meanwhile, the parallel path keeps the operator safe and diverts the interference. Meeting the rigorous demands of a circuit-breaker contact test requires a current clamp of maximum quality, specially designed and interfaced with the tester. Do not try a jerry-rigged test with an ordinary clamp-on ammeter used in building wiring applications.

DUAL GROUNDING Dual grounding can also be applied successfully without the necessity of a specialized ohmmeter with built-in clamp. In situations where inductive interference is not ever-present, as in a de-energized substation shut down for maintenance, valuable time can be saved by testing with dual grounds in place that do not have to be lifted for the test. The operator is run up in a bucket truck, the tester connected across the test item, and the test conducted (Figure 3).

Contact resistance is a comparatively simple test in concept. Circuit breakers are also subjected to more sophisticated tests: timing, motion, and dynamic resistance measurement (DRM), and vibration. Timing is critical so that too much voltage does not develop across the contacts as the breaker opens; it is generally limited to 2 ms. The speed of the breaker’s motion must be sufficient to break the arc and prevent it from re-striking. It can be expressed in length, degrees, or percentage of movement, and generally takes from 10 to 20 ms (1 to 2 zero crossovers). DRM is also a measurement of contact resistance, but it is measured dynamically over an open or close operation. Vibration analysis can be made over one open-close operation. Corrosion and other metal-to-metal issues can affect the outcome of this test, so it is a good test to run after long standing in the same position. All of these tests can be performed with circuit-breaker analyzer systems available on the market, and with maximum operator safety and minimal test time using dual grounding.

CONCLUSION An additional safety consideration is in order. Because safety is the prime parameter in all electrical testing, some substations have two separate grounding systems, and this must be taken into account when setting up a circuit breaker test. Either the two systems must be connected with a temporary bond or the test instrument must be powered from an isolating transformer. If neither of these protective steps is employed, the test instrument’s protective ground becomes a connection between the two grounding systems. This could provide a path for high current through the protective ground leads for which the system is not designed. Jeffrey R. Jowett is a Senior Applications Engineer for Megger in Valley Forge, Pennsylvania, serving the manufacturing lines of Biddle, Megger, and multi-Ampfor electrical test and measurement instrumentation. He holds a BS in Biology and Chemistry from Ursinus College. He was employed for 22 years with James G. Biddle Co. which became Biddle Instruments and is now Megger.

7

Maintenance Vol. 1

MAINTENANCE STRATEGIES AND THEIR APPLICATIONS NETA World, Spring 2013 Issue Kerry Heid, Magna Electric Corporation

Electrical equipment maintenance is crucial for a number of reasons. First and foremost, maintenance and testing of critical protection systems is required to ensure that worker safety is not in jeopardy. Also, electrical maintenance is critical in ensuring that uptime is maximized and that electrical power system equipment reaches its intended life cycle. Many approaches can be taken toward the various equipment and systems, and this article will take a look at five varying strategies and their applications.

Some disadvantages of preventative maintenance are that catastrophic failures are still possible. Also, this maintenance approach is labor intensive and often includes activities that are unnecessary.

REACTIVE MAINTENANCE

Predictive maintenance or condition-based maintenance uses measurements to detect failure at the onset of degradation. This allows for small issues to be eliminated or controlled prior to system failure. Predictive maintenance uses tools to determine maintenance task requirements based on quantifiable equipment conditions.

Reactive Maintenance is sometimes called run to fail and allows systems and equipment to operate with little or no maintenance. The advantage to reactive maintenance is that maintenance dollars will not be expended until something fails. This means while the equipment is running, a smaller maintenance staff will be required and equipment can operate without the need to organize maintenance outages. There are some disadvantages to reactive maintenance. When power system equipment fails, the failure is often catastrophic and usually requires much capital and labor hours including overtime to make the repairs. The failure often cascades into surrounding equipment as well. These failures can create a major disruption to production or uptime within the facility. It should be noted that reactive maintenance is not recommended for critical switching and protection schemes in electrical power system applications. Some application examples are noncritical systems or systems with built in redundancy.

PREVENTIVE MAINTENANCE Preventative Maintenance uses a time-based or machine run-based schedule to predetermine degradation with the aim of extending the useful life. Expending time and resources to increase the system reliability, control degradation, and extend equipment life are main goals. There are a number of advantages to the preventative maintenance approach. The equipment life will be extended if the manufacturer’s maintenance requirements are heeded. Also, timebased maintenance allows for maintenance work to be scheduled for flexibility in maintenance periods.

Preventative maintenance works well with a skilled maintenance staff and equipment that can be regularly shut down to perform the work.

PREDICTIVE MAINTENANCE

This type of maintenance has many advantages. This approach pinpoints what activities are required and then allows those activities to be scheduled. This increases uptime and reduces unnecessary maintenance while optimizing the operation of the equipment. Disadvantages are the initial costs associated with diagnostic equipment and training of maintenance personnel. Another disadvantage is that management may not see all the benefits in the initial investment of personnel and equipment. This has wide application in the electrical power system business. Transformer oil analysis and switchgear partial discharge analysis are just two of the many applications.

RELIABILITY CENTERED MAINTENANCE The approach to reliability centered maintenance (RCM) uses a number of factors including the probability of equipment failure and a combination of other maintenance practices including predictive maintenance. RCM provides a high level of reliability and cost effectiveness by using a systematic approach to the facility’s equipment and resources. There are many advantages to RCM. This approach recognizes that not all equipment in a facility is of equal importance. It also recognizes that some equipment is more reliable and requires a different methodology. RCM also strives to optimize the available personnel and financial resources. There are some disadvantages of the RCM method. The cost for training, equipment, and startup are significant before the real savings can be appreciated.

8 The RCM approach works best where a mix of philosophies will bring the most benefit to the facility’s budget and resource availability.

RISK-BASED MAINTENANCE Risk Based Maintenance (RBM) uses a process where risk can be quantified and prioritized so other types of maintenance can be established. Owners use risk assessment and criticality to manage the maintenance and inspection programs involving reactive, preventative and predictive philosophies. RBM has a few advantages particularly from a business perspective. This approach allows the asset owners to maximize the resources and can be the most cost effective manner to establish a maintenance program. Maintenance is based on risk factor and vitality. RBM requires special expertise to assess the risk. This process requires extensive data and failure calculations to effectively apply.

CONCLUSION Electrical maintenance is critical for worker safety, facility uptime, and for equipment to reach its full life cycle. Many approaches can be taken based on the availability of equipment outages, facility design, and the availability of resources. However, electrical power system equipment such as critical switching and isolation devices as well as protective relaying systems should always be given a high priority for maintenance as the safety of personnel depend on its correct operation.

Kerry Heid is the President of Magna Electric Corporation, a Canadian-based electrical projects group providing NETA Certified Test Technicians and related products and solutions for electrical power distribution systems. Kerry is a past President of NETA (Inter- National Electrical Testing Association) and has been serving on its board of directors since 2002. Kerry is chair of NETA’s training committee and is a Senior Certified Test Technician Level IV. Kerry was awarded NETA’s 2010 Outstanding Achievement Award for his contributions to the association. Kerry is the chair of CSA Z463 Technical Committee on Maintenance of Electrical Systems. He is also a member of the executive on the CSA Z462 technical committee for Workplace Electrical Safety in Canada and is chair of Working Group 6 on safety-related maintenance requirements as well as a member of the NFPA 70E – CSA Z462 harmonization working group. Kerry has performed electrical engineering, testing, maintenance, commissioning, and training activities throughout North America for the past 23 years with Westinghouse Service and Magna Electric Corporation. He resides in Regina, Saskatchewan, with wife Pam and sons Brendan and Colby.

Maintenance Vol. 1

9

Maintenance Vol. 1

TESTING ROTATING MACHINERY – PARTIAL DISCHARGE INTERPRETATION NETA World, Spring 2013 Issue Vicki Warren, Iris Power LP.

Partial discharges (PD) are small electrical sparks that occur when voids exist within or on the surface of high-voltage insulation of stator windings in motors and generators. These PD pulses can occur because of the thermal deterioration, manufacturing/installation processes, winding contamination, or stator bar movement during operation.

PARTIAL DISCHARGE SENSORS Permanently mounted PD sensors block the AC power signal (50/60 Hz) but pass the high frequency PD pulses (50-250 MHz). The type of sensor installation and test instrument depends on the machine or equipment being monitored. The first step of PD detection is the placement of a sensor somewhere near the source of the PD. Two types of sensors referenced in IEEE 1434-2000 and IEC/TS 60034-27-2 are ●● Capacitive couplers, epoxy mica capacitors (EMC) - for motors, hydros, and small turbos. [Figure 1, Figure 2] ●● Stator slot couplers (SSC) - for large turbos (>100 MW). [Figure 3]

Fig. 1: EMC at Terminals

Fig. 3: SSCs in Turbo

PD DETECTION During normal operation, a continuous PD monitoring or portable PD instrument connected to the sensors separates noise and correctly classifies the PD. Until recently such an on-line PD test had been difficult to implement due to the presence of electrical disturbances that have PD-like characteristics. This can lead to healthy windings being misdiagnosed as deteriorated, which lowers confidence in the test results. “Noise is defined to be nonstator winding signals that clearly are not pulses.” [IEC/TS 60034-27-2] Electrical noise from power tool operation, corona from the switchgear and RF sources, etc., is easily confused with PD from the machine windings. “Disturbances are electrical pulses of relatively short duration that may have many of the characteristics of stator winding PD pulses – but in fact are not stator winding PD.” [IEC/TS 60034-272] Some of these disturbances are synchronized to the AC cycle, and some are not. Sometimes synchronized disturbance pulses can be suppressed based on their position with respect to the AC phase angle. A good on-line PD test reduces the influence of noise and disturbances, leading to a more reliable indication of machine insulation condition. Three methods of noise and disturbance separation include: ●● Band-pass filtering of PD between 50-300 MHz, whereas noise is less than 35 MHz. [Figure 4] ●● Separation based on direction-of-arrival to two sensors connected to a single phase [Figure 5, Figure 6]

Fig. 2: EMCs on Bus Bar

●● Separation based on pulse characteristics [Figure 7]

10

Maintenance Vol. 1 other similar machines, this is an indicator that visual inspections and/or other testing methods are needed to confirm the insulation condition [IEEE 1434-2000].

TREND

Fig. 4: Band-Pass Filter 40-350 MHz

If the unit operating parameters – voltage, load, winding temperature, and gas pressure – are similar to those of the previous test, then a direct comparison can be made between the two test results. Environmental conditions such as humidity may have a very noticeable impact, especially if the surface contamination becomes to some extent conductive when damp, so it should be recorded from one test to the next. When a trend line is established for PD tests taken over a period of time, it will be obvious that most show small up and down variation between successive tests [Figure 8]; however, a sustained upward trend indicates developing problems.

Fig. 5: PD coming from Machine

Fig. 8: Typical PD Trend

COMPARE TO SIMILAR MACHINES

Fig. 6: PD coming from System

If the PD magnitudes by the same test method from several similar windings are compared, the windings exhibiting higher PD activity are generally closer to failure. Due to the influence of the test arrangement on the results, the test setup (sensors and test instrument) must be the same for all comparisons. One example is the statistical summaries of the peak magnitude, Qm, values based on the most recent Iris Power database that contains several thousands of test results. Each table shows the average, maximum, and the 25th, 50th, 75th, 90th, and 95th percentile ranks [Table 1]. The 25th percentile is the Qm magnitude for which 25 percent of the test results are below, similarly for the other percentiles. Normally, there is concern for a winding if the Qm in a machine is higher than the 75th percentile and increasing. Rated kV

6-9

10-12

13-15

16-18

25%

29

34

50

41

50%

70

77

113

77

ANALYSIS

75%

149

172

239

151

Although the magnitude of the PD pulses cannot be directly related to the remaining life of the winding, if the rate of PD pulse activity increases rapidly, or the PD levels are high compared to

90%

288

376

469

292

Fig. 7: PD Pulse Characteristics

Table 1: PD Statistics for Turbos and Motors (Qm in mV)1

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Maintenance Vol. 1 PD DISTRIBUTIONS

CONCLUSIONS

The pulse distribution with respect to the AC phase position in the 3D plots can assist in determining the source of any problems in the stator winding. Normal pulse distributions are Gaussian, negative pulses clustered between 0-90° and positive pulses between 180270°, and are indicative of spherical shaped voids within the slot section of the core [Figure 9].

When using a PD measuring system that adequately separates noise and disturbances, monitoring of the PD activity in a running motor or generator stator winding can be as simple as evaluating the trend, comparing to a statistical database, and evaluating the polarity predominance of the pattern. With this configuration, monitoring for most of the failure mechanisms common to stator winding insulation can be quickly and easily evaluated while the machine is subjected to normal thermal, electrical, ambient and mechanical stresses.

Fig. 9: Normal PD Distribution

Fig. 10: PD Polarity Predominance Due to space charge effects, a pulse will occur in a specific direction based on the proximity of the void to a metallic substance [Figure 10]. No polarity predominance is normally the result of internal delamination (overheating) of the insulation system that has forced the organic bonding material of the insulation to lose its adhesive strength. Negative PD predominance may be the result of voids created due to either improper manufacturing or thermal cycling that has stressed the bonds between the conductor and the first layers of insulating tape. Due to pulse behavior, positive PD predominance normally indicates PD originating on the surface of the insulation system, such as slot discharge, endwinding tracking, and gradient or semicon coating deterioration. Surface PD happens when a coil does not have intimate contact with the core due to shrinkage, improper installation, bar/coil movement, or perhaps degradation of the voltage stress control coatings.

Vicki Warren, Senior Product Engineer, Iris Power LP. Vicki is an electrical engineer with extensive experience in testing and maintenance of motor and generator windings. Prior to joining Iris in 1996, she worked for the U.S. Army Corps of Engineers for 13 years. While with the Corps, she was responsible for the testing and maintenance of hydrogenerator windings, switchgear, transformers, protection and control devices, development of SCADA software, and the installation of local area networks. At Iris, Vicki has been involved in using partial discharge testing to evaluate the condition of insulation systems used in medium- to high-voltage rotating machines, switchgear and transformers. Additionally, she has worked extensively in the development and design of new products used for condition monitoring of insulation systems, both periodical and continual. Vicki also actively participated in the development of multiple IEEE standards and guides and was Chair of the IEEE 43-2000 Working Group.

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Maintenance Vol. 1

TECHNOLOGIES FOR OUTDOOR SUBSTATION AND SWITCHYARD TESTING NETA World, Spring 2013 Issue Don A. Genutis, No-Outage Electrical Testing, Inc.

INTRODUCTION Nearly all utilities and many major facilities utilize open-bus outdoor substation equipment to distribute power. A combination of thermographic, ultrasonic, corona camera, and radio-frequency antenna technologies can be used effectively to detect various problems before they cause failure. This article will review the advantages of these technologies to help determine the best solution for finding problems.

REVIEW OF TECHNOLOGIES Although several no-outage technologies exist for outdoor equipment, the following short list summarizes the most popular and successful instruments used today. Thermographic – Infrared imaging is a very good tool for the detection of thermal problems, especially those related to poor connections (see Figure 1). This technology does well for detecting problems with high resistance under load but does not detect voltage (insulation) problems very well if at all. Fig. 2: Ultrasonic Detector with Parabolic Dish Contact Ultrasonics – Placement of ultrasonic sensors against oil-filled equipment tanks has been successful in detecting internal insulation problems. However, this technique is often unreliable due to noise created by normal mechanical vibration. Additionally, internal components may obstruct the signal so that it cannot reach the sensor. One approach to remove greater amounts of noise is to use higher frequency sensors. Another approach is to utilize multiple sensors to triangulate the PD source in order to obtain better location. Fig. 1: A thermal image of an overheated connection Airborne Ultrasonic – Listening to ultrasonic signals from substation equipment surfaces can help detect potential insulation problems. By adding a parabolic dish to concentrate the signals, distant objects can also be surveyed (see Figure 2). One difficulty with this technology is the inability to distinguish between serious insulation defects and benign corona occurring from sharp protrusions on conductors or hardware.

Corona Camera – This technology detects the ultraviolet light associated with surface partial discharge or corona and provides an image of the precise location of the activity (See Figure 3). Unlike airborne ultrasonic instruments, benign corona can be distinguished from more serious problems using the corona camera. These instruments are very directional, and defects can be hidden from detection if they occur underneath or on rear component surfaces. Therefore, airborne ultrasonics should be used to supplement corona camera surveys. Except for contact ultrasonics, none of the above instruments can detect internal defects.

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Maintenance Vol. 1

Smaller substations can be quickly scanned in minutes, often from outside of the fence, while large switchyards require briefly walking around the equipment in a pattern to ensure nothing is missed.

CONCLUSION By utilizing a combination of technologies, it is possible to identify all common types of equipment failure modes in outdoor substations and switchyards including thermal related, corona, surface tracking, and internal partial discharge defects. Reliability will be increased and operating costs will be reduced significantly by employing a condition-based maintenance strategy that implements these supplemental instruments. Fig. 3: The red cloud at the top of the center bushing represents ionized air as seen in this corona camera image. RF Antenna Technology - Antenna based instruments, such as the one shown in Figure 4 have been developed using a variablefrequency, wide-band, electromagnetic signal receiver connected to a unique directional antenna assembly to detect and pinpoint internal and surface defects in outdoor, open-bus substation and switchyard equipment. This instrument has helped fill some of the gaps left open by the other instruments by having the unique capability to detect internal problems. Used as a stand-alone technology or better yet in combination with the other technologies, a new level of reliability can be achieved.

Fig. 4: A variable-frequency, wide-band, electromagnetic signal receiver with a directional antenna RF antenna instruments are lightweight and relatively easy to use. To survey a substation, the technician merely walks through the yard while pointing the instrument at the various equipment while listening for partial discharge (PD) activity and observing the phase resolved display for PD activity patterns. In substations and switchyards where a lot of benign corona activity exists, a frequency can be selected above the level in which the majority of corona activity ceases. This allows the technician to only detect defects while ignoring benign corona.

Don A. Genutis received his BSEE from Carnegie Mellon University. He was a NETA Certified Technician for 15years and is a Certified Corona Technicians. Don’s technical training and education are complemented by twenty-five years of practical field and laboratory electrical testing experience. Don serves as President on No-Outage on No-Outage Electrical Testing, Inc., a member of the EA technology group.

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Maintenance Vol. 1

DATA CENTER MAINTENANCE – PART 3 – BATTERY AND BACKUP GENERATOR MAINTENANCE NETA World, Summer 2013 Issue Lynn Hamrick, Shermco Industries This article is Part three of a four-part series on data center maintenance. Key electrical systems for most data centers are the UPS systems and their battery systems and the backup generation systems. The UPS systems are designed to provide primary power to downstream equipment with immediate switching to battery systems with loss of power. Failed or discharged batteries mean the data center’s UPS won’t be able to supply the temporary backup power needed in the event of a power sag or outage. Even though UPSs are not designed to keep the data center running during a long-term outage, they do provide the carry-over capability that accommodates a seamless transfer to an alternate power source like a backup generator. This article will focus on the key attributes of battery and backup generation maintenance and how they can affect data center reliability.

UPS BATTERY MAINTENANCE The battery is by far the most vulnerable and failure-prone part of a UPS system. Because of this, much time and effort is allocated to maximizing a battery’s reliability and life within the data center. At a minimum, annual testing, verification, and inspection of a battery system should be performed. As with all electrical systems, infrared thermographic surveys should also be performed on battery systems on at least an annual basis. Additional quarterly or semi-annual inspections should be performed if the age and condition of the battery warrant the activity. Watering is the single most important factor in maintaining a flooded lead acid battery. The frequency of watering depends on usage, charge method, and operating temperature. A new battery should be checked every few weeks to determine the watering requirement. This prevents the electrolyte from falling below the plates. Avoid exposed plates at all times, as exposed plates will sustain damage, leading to reduced capacity and lower performance. Battery charging is probably the second most important factor in maintaining a battery system. A correctly functioning battery charging system with a healthy battery condition will result in a fully charged and reliable battery system that is available when called upon for service. The following checks are a quick way of determining a correctly and fully charged battery: ●● Stabilized charging currents. ●● Stabilized charging voltage.

●● Consistent specific gravity. ●● Normal gassing. An excessive amount of charge results in high battery temperature and a reduced battery service life. To obtain maximum service life from a battery, it should be charged and operated within temperature ranges recommended by the manufacturer. Overheating can damage the battery and shorten its normal expected service life. The extent of the damage and service life loss depends on the higher temperature, how often the overheating occurs, and how long the batteries are subjected to high temperatures. A healthy battery charged on a correctly functioning charger will have a 10 to 20 degrees F rise in temperature when fully charged. This temperature rise is affected by several variable factors: ●● Battery age and condition. ●● Battery temperature versus ambient temperature. ●● Charger rate. ●● Charger voltage level. In support of good battery health, the electrical maintenance program for the battery system should include the following: ●● Visual inspection of the battery cells. ●● Verify battery charging performance. ●● Cleaning battery posts and connections. ●● Periodic electrical testing.

VISUAL INSPECTION OF BATTERY CELLS Batteries should be visually inspected under normal float conditions. ●● Inspect the electrolyte level. Flooded cells have translucent or transparent jars, so the electrolyte level can easily be compared to a recommended level that is marked on the cells. ●● Inspect the positive plates. The positive plates are typically the first to wear out and are located toward the center of the jar. They should be dark brown or black. Sparkle is evidence of sulfation or undercharge. Look for cracks, breaks, and pieces hanging on the side. This indicates that the cell may need to be replaced and that other cells may also have a similar problem.

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Maintenance Vol. 1 ●● Inspect the negative plates. The negative plates are thinner than the positive plates and sit toward the outside of the jar. These should have a clean lead color from top to bottom. Pink discoloration indicates copper contamination. ●● Look at the sediment. Inspection of the sediment should provide a general idea of the battery conditional trend from the last inspection. Accumulation of gray material under the negative plates accompanied by sparse black sediment is indicative of an undercharging condition. Excess black sediment under the positive plates with little negative sediment is indicative of an overcharging condition or excess temperature. If excess sediment covers the bottom of the jar, the battery has been cycled heavily or operated at high temperature. ●● Inspect the outside of the jar. A crusty trail or accumulation is evidence of electrolyte leakage. Signs of corrosion on the terminal connections, intercell connections, and racks are also indicative of electrolyte leakage. ●● Verify presence and condition of flame arresters. ●● Verify battery area ventilation is operable and that suitable eyewash equipment is present.

VERIFY BATTERY CHARGING PERFORMANCE There is more to verifying battery charging performance than just recording the voltage levels. ●● Measure each cell voltage and the total battery voltage. The cell voltage value should be in accordance with manufacturer’s published data. Low cell voltage is indicative of a problem with the cell. ●● Verify appropriate charger float and equalizing voltage levels. Charger float voltage is the typical voltage output for a normal charging process. This voltage should be in accordance with the manufacturer’s recommendations but may need to be increased as the battery ages or degrades. An equalizing charge is nothing more than forced overcharge. Applying an equalizing charge periodically brings all cells to similar levels by increasing the voltage to ~ 10 percent higher than the recommended float voltage. This process removes sulfation that may have formed during lowcharge conditions. One method of evaluating sulfation is to compare the specific gravity readings on the individual cells of a flooded lead acid battery. Only apply equalization if the specific gravity difference between the cells is greater than 0.030. During equalizing charge, check the changes in the specific gravity reading every hour and stop the equalizing charge when the specific gravity no longer rises. This is the time when no further improvement is possible, and a continued charge will cause damage. The battery must be kept cool and under close observation for unusual heat rise and excessive venting. Some venting is normal and the hydrogen emitted is highly flammable.

●● Test each cell for specific gravity and temperature. Specific gravity is useful in evaluating charger float voltage, as well as cell internal health. For most UPS-related battery systems, a specific gravity of 1.250 is typical for each cell. If the specific gravity drops by 0.015 to 0.020 from these values, it is usually indicative of inadequate charger float voltage or a problem with a cell holding a charge. Remember, specific gravity should always be adjusted for internal cell temperature differences from 25 degrees C at a rate of 0.001 for every 1.67 degrees C difference. Also, electrolyte levels should be taken into consideration when evaluating specific gravity. Cells with low electrolyte levels typically need water added and, therefore, will have a higher specific gravity.

CLEANING BATTERY POSTS AND CONNECTIONS Before cleaning, note the condition of posts and connectors. Except for a light coating of grease, these should look new. Consider the following colors: ●● Black. This is lead peroxide, indicating an acid leak around the positive post. ●● Green. This is corroded copper, indicating connectors need cleaning and close inspection — they may no longer be serviceable. ●● White. This is lead hydrate, indicating a leak around the negative post. The jars surfaces can be cleaned any time, but cleaning connectors and posts requires opening the battery circuit. If the cleaning requires that the battery be taken out of service without a parallel system, the UPS will not respond to a power loss. Therefore, cleaning should be coordinated with the operator. This following cleaning procedure should be performed when required. ●● Wipe the grease off the posts and connectors, and then neutralize them with a suitable solution like baking soda and water. ●● Clean with a scouring pad or brass brush until clean lead is exposed. Do not clean too vigorously or with a steel wire brush because it may remove too much lead. ●● Degrease the bolts, washer, and nuts. Neutralize electrolyte with a suitable solution. Replace corroded hardware. Replace lock washers, regardless of condition. Use only lead-plated or 316-stainless steel bolts, washers, and nuts. ●● Regrease posts and contact areas of connectors with a light layer of antioxidant grease approved for battery use. ●● Install washers with the sharp side facing away from the connector. If possible, install lock washers on the nut side, not the bolt side. ●● Retorque connections to manufacturer’s specifications. Turn the nut, not the bolt, if possible.

16 ●● Check post-to-post resistance with a micro-ohmmeter. If resistance is high, check the torque — overtorquing degrades the connection. If the torque is correct but the value is high, disassemble and inspect contact surfaces for correct polishing.

PERIODIC ELECTRICAL TESTING In addition to the periodic visual inspections and battery system checks discussed above, specific electrical tests should be performed. The addition of an occasional load test of the battery system should be considered as the battery system ages or other problems are identified. In support of this recommendation for load testing, there are some other more sophisticated testing methods that can and should be performed more regularly to accurately determine battery health. These methods measure the internal ohmic values of the battery or associated cells. Ohmic measurement using a DC voltage is one of the oldest and most reliable test methods for battery systems. A cell’s internal resistance provides useful information in detecting problems and can be used for indicating when a battery or battery cell should be replaced. However, resistance alone does not provide a linear correlation to the battery’s capacity. The increase of cell resistance only relates to aging and provides some failure indications. Rather than relying on an absolute resistance reading, service technicians take a snapshot of the cell resistances when the battery is installed and then measure the subtle changes as the cells age. An increase in resistance of 25 percent over an initial baseline (100 percent) or compared to similar cells indicates a performance drop to about 80 percent. Ohmic measurement using ac voltage is also a generally accepted test method for battery systems. From this method the batteries conductance is derived in terms of mhos, or siemens. A major benefit to using conductance is the ability to calculate a battery’s capacity without performing an extensive discharge or load test. A battery’s measured conductance correlates linearly with its ability to deliver current. As conductance declines, so does a battery’s ability to meet its specified capacity and supply energy. A decrease in conductance of 25 percent over an initial baseline (100 percent) or compared to similar cells indicates a performance drop to about 80 percent.

BACKUP GENERATORS Backup generators should be checked and tested periodically to ensure that they will function as designed and when required. As with the UPS batteries, this testing should include occasional load testing. Backup generators are usually stationary units that are interconnected into the data center’s electrical infrastructure. Automatic transfer switches (ATS) are the most common type of interconnection device used for these applications. An ATS can provide a signal for the generator to start and transfer the load from the normal supply to the generator.

Maintenance Vol. 1 Incorrectly or poorly maintained backup generator sets are more prone to failure and are more likely to fail when needed most. The most common engine failures can be attributed to the starting, cooling, lubrication, or fuel delivery systems. These types of failures can be minimized or prevented by implementing regularly scheduled, comprehensive, engine-generator maintenance and testing programs. The key components of a good backup generation maintenance program include: ●● Regular exercise of the engine generator. ●● Visual inspection of the engine generator, surrounding area, and fluid levels. ●● Fluid maintenance including changing the lubrication, coolant, and fuel on a regular basic. ●● Electrical system testing of the starting system, including the batteries.

EXERCISE THE ENGINE GENERATOR The engine generator should be run under a load on a periodic basis. During dynamic testing engine parts become lubricated, oxidation is prevented, old fuel is consumed, and overall functionality is ensured. Therefore, periodic operation of the generator at a load of at least 30 percent of the nameplate rating for no shorter than 30 minutes should be performed. The generator should be operated for a minimum of one hour at 100 percent of the nameplate capacity at least annually. When testing a stationary unit, testing should be done through the ATS to ensure the entire system works correctly. If it is not possible or practical to use a site load for the test, a load bank should be used. Sometimes problems only become noticeable during operation; therefore, it is important that maintenance personnel remain attentive for unusual circumstances, e.g. abnormal sights, sounds, vibration, excessive smoke, or changes in fuel consumption.

VISUAL INSPECTION The area around the engine generator should always be kept free of debris to ensure sufficient ventilation during operation; therefore, periodic inspections should be performed. The radiator should be cleaned regularly to remove any dust and/or debris, taking care not to damage the fins. These inspections should also be performed to ensure fluids, such as oil and coolant, are not leaking. Further, there should be inspections of the exhaust system, including the manifold, muffler, and exhaust pipe with all connecting gaskets, joints, and welds being checked for potential leaks. Also, check that the engine jacket water heater is operating correctly by monitoring the discharge temperature. The fuel delivery system should also be inspected periodically for leaks and correct pressure during exercise. This includes checking fittings and connections; tighten them as needed. Drain

Maintenance Vol. 1 and clean fuel filters on a regular basis. Where applicable, examine charge-air piping and supply hoses for leaks, holes, and damaged seals. The fuel system and charge-air cooler should also be free of dirt and debris.

FLUID MAINTENANCE Fuel maintenance is another important aspect of generator maintenance. Diesel fuel degrades over time, separating and even growing microbiological organisms. A fuel sample, taken from the bottom and from the supply line, should be visually examined monthly. The fuel should look like new fuel; otherwise it should be filtered or replaced. Fuel tanks should be sized so that the fuel is turned over on a regular basis. As a rule of thumb diesel fuel should be turned over or replaced on an annual basis. This maintenance should also include fluids, such as oil and coolant, are at the correct mix and levels.

ELECTRICAL SYSTEM TESTING Electrical connections should be tight and free from corrosion. Batteries should also be checked to make sure they are fully charged. The batteries must be tested under load. Simply checking the voltage is an inaccurate method of testing power, as batteries change internally over time. Where appropriate, check the specific gravity and electrolyte levels. All engine wiring should have tight connections and be free of corrosion or damage. Check with your generator manufacturer for their recommended battery and wiring practices, cleaning agents, and solutions.

SUMMARY Key electrical systems for most data centers are the UPS systems and their battery systems and the backup generation systems. The UPS systems are designed to provide primary power to downstream equipment with immediate switching to battery systems with loss of power. The UPSs and battery systems are typically designed to keep the data center running long enough for a seamless transfer to an alternate power source like a backup generator. The battery is by far the most vulnerable and failure-prone part of a UPS system. Because of this, much time and effort should be allocated to maximizing a battery’s reliability and life within the data center. At a minimum, annual testing, verification, and inspection of a battery system should be performed. Backup generators should also be inspected and tested periodically to ensure that they will function as designed and when required. As with the UPS batteries, this testing should include occasional load testing.

17 Lynn Hamrick brings more than 25 years of working knowledge in design, permitting, construction, and startup of mechanical, electrical, and instrumentation and controls projects as well as experience in the operation and maintenance of facilities. He is a Professional Engineer, Certified Energy Manager, and has a BS in Nuclear Engineering for the University of Tennessee.

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Maintenance Vol. 1

TESTING ROTATING MACHINERY SYNCHRONOUS ROTOR WINDING COMMON ELECTRICAL TESTS NETA World, Summer 2013 Issue Vicki Warren, Iris Power LP Since operating voltage of most insulated rotor windings is less than 1000 V, the recommend test voltage is 500 V DC. Per IEEE 43, the minimum acceptable values are 100 megohms for formwound armatures and 5.0 megohms for random wound types when corrected to 40 degrees C.

When the motor application requires low speed, power-factor control, high-operating efficiency, direct connection to lowspeed equipment or high horsepower, a synchronous motor may be appropriate. The primary difference between a squirrel-cage induction motor and a synchronous motor is the rotor construction. A synchronous rotor winding has insulated pole windings, and, if it has laminated poles, a damper winding embedded in the pole tips. The damper winding is similar to that of a squirrel-cage rotor type. It is used during starting to create asynchronous torque and to damp out oscillations from an unsteady load during normal operation. If the motor has solid steel poles the pole tips act as a crude damper winding for starting. The field winding is excited from a dc source, which in modern machines is a brushless exciter and provides additional electromagnetic flux to lock the stator’s rotating field to the rotor. The two most common types of rotor designs found in mediumto high-voltage synchronous motors are salient pole and round (or cylindrical) rotor. The round rotor design is used for two- pole motors because it has the ability to withstand the very high “g’ forces imposed on the rotor winding by centrifugal forces. On the other hand for four poles and above, the salient pole design is suitable for motor ratings up to at least 60 MW. This article describes some of the common tests used for salient pole rotor windings in synchronous motors.

INSULATION RESISTANCE This test should be performed in accordance with IEEE Std. 431 to confirm that the rotor winding is clean and dry and that there are no major flaws in its ground insulation on the coils and leads.

The test voltage should be applied for one minute, and the insulation resistance recorded at that time. It may take a number of cleaning and baking cycles to bring the insulation resistance up to an acceptable value. Carbon should be removed before performing this test. If a winding does not have an acceptable insulation resistance reading, it is inadvisable to perform electrical tests that can potentially stress the insulation (such as the growler, highpotential or surge-comparison tests). Caution: A successful 500V IR test between the rotor winding and shaft should be performed before conducting additional tests

FIELD WINDING RESISTANCE The resistance of the armature winding shall be measured between the leads to the brushgear assembly, with all brushes down. This measurement shall be taken with a resistance bridge, digital microhmmeter, or low resistance digital ohmmeter having four-digit accuracy. The recorded values shall be within 2.0% of the prerepair, or factory test values.

ROTOR VOLTAGE DROP The voltage drop test is used to identify shorts between turns in dc field coils of salient pole rotors. It can be performed by exciting the coils with AC or DC, then measuring the voltage between adjacent turns. The equipment required for this test is an AC or DC source and an accurate voltmeter (or millivoltmeter) and current meter. The energizing source must be capable of providing enough current to produce a measurable voltage between turns. For this reason an ac source is preferred. A low voltage (usually 120 V) ac voltage is applied across the complete winding and the voltage across each pole winding is measured. Since the impedance of a pole winding reduces much more than its resistance when a turn short is present, if there are turn-to-turn shorts, the ac voltage drop will be significantly less. If no shorted turns exist, the measured voltage across each coil should be within the tolerances given in Table 1.

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resonant damped sine wave response is stable as the test voltage is increased, the coil does not have any shorts. When the resonant response or ringing increases in frequency or decays very rapidly, a shorted turn is likely in the coil.

Fig. 1: Low-cycle Fatigue (Salient Pole) If the motor has brushless excitation, then the field winding has to be disconnected from the rotating rectifier for this test. One limitation of this test is that it may not detect turn shorts that are only present when operating centrifugal forces are present. This may be overcome by mounting the rotor horizontally and performing the test with it in four positions, 90 degrees apart. When there are significant differences in the iron distribution around the coils, the results of an AC drop test may be misleading. In those cases, a DC drop test is useful to determine whether the AC results are due to shorted turns or interaction with the iron. Using higher frequencies (120 hz to 400 hz) can be very beneficial in that the current requirements are greatly reduced. DROP TEST

TOLERANCE

AC

± 10% of the average voltage drop

DC

± 5% of the average voltage drop

Table 1: Voltage Drop Test2 When the condition of pole windings is being considered, an alternative test can be used where the power factor or losses in the coils are measured. This is a comparative test where the power factor or losses in each coil are compared. When a coil is identified with higher losses, it likely has a shorted turn. Equipment requirements for the power-factor test are a power supply and a watt meter or pentameter capable of measuring low power factors.

SURGE TEST FOR SHORTED TURNS The surge test may detect shorted turns, ground faults, and high resistance connections in salient pole and wound rotor windings. This test requires the same type of surge tester as is used to detect shorted turns in multi-turn stator coils. Since a complete winding will have a large number of turns to be effective, this test should be performed on individual coils. The test involves injecting fast rise-time pulses with a peak voltage magnitude indicated in Table 2 into each end of the coil and overlaying the resulting waveforms to check for similarity in accordance with IEEE Std 5221. The pulse rise time and repetition rate produce a resonant response in the coil. A series of pulses is injected into a coil, and if the

Fig. 2: Fatigue and Thermal Damage (Salient Pole) Comparison of surge voltage waveforms for all coils of the same type can be effective, but may not detect shorted turns if the impulse dissipates too quickly or only exist when under the influence of centrifugal forces during rotor operation. When comparison is made, the responses should match exactly if the coils do not have shorts. If there are differences in the waveform frequencies, an experienced operator can determine the type of fault present. WINDING TYPE

PEAK VOLTAGE

New

10 x Field Winding Rated Voltage

Refurbished or Repaired

6 x Field Winding Rated Voltage

Table 2: Surge Test for Shorted Turns2

HIGH POTENTIAL TEST This test should be performed on all new field windings and those that have been repaired. A 1.0 minute test shall be performed at the voltage levels indicated in Table 3. When a dc high potential test is performed, usually in voltage steps, the result of each step must be assessed (IEEE 954). This means plotting the curve of insulation resistance (or leakage current, in microamperes) versus applied voltage. If the plotted value at any step begins to trend upward, indicating excessive nonlinear current (or drop in insulation resistance in a nonlinear manner), the test should be aborted immediately.

Fig. 3: Mechanical Damage to Interturn Insulation (Salient Pole)

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Maintenance Vol. 1 WINDING DC VOLTAGE RATING

AC TEST VOLTAGE

DC TEST VOLTAGE

1000 V

1700 V

New Windings > 240 Volts

1000 V + (2 Times Rated Winding Voltage)

1700 V + (3.4 Times Rated Winding Voltage)

Refurbished Windings > 240 Volts

600 V

1020 V

Refurbished Windings > 240 Volts

[1000 V + (2 Times Rated Winding Voltage)] x 0.6]

[1700 V + (3.4 Times Rated Winding Voltage)] x 0.6]

New Windings < 240 Volts

Table 3: Field Winding AC and DC High Potential Test Values2

REFERENCES 1 I EEE Std. 43-2000, IEEE Recommended Practice for Testing Insulation Resistance of Rotating Machinery 2 I EEE Std. 522-2004, IEEE Guide for Testing Turn Insulation Testing of Form-Wound Stator Coils for Alternating-Current Electric Machines 3 Electric Power Research Institute’s (EPRI’s) Large Electric Motor Users Group (LEMUG) Repair and Reconditioning Specification Guidelines for AC Squirrel-Cage and Salient Pole Synchronous Motors with Voltage Ratings of 2.3 to 13.2 kV Report 1000897 (dated July 2008) 4 I EEE Std. 95-2002, IEEE Recommended Practice for Insulation Testing of AC Electric Machinery (2300 V and Above) with High Direct Voltage. Vicki Warren, Senior Product Engineer, Iris Power LP. Vicki is an electrical engineer with extensive experience in testing and maintenance of motor and generator windings. Prior to joining Iris in 1996, she worked for the U.S. Army Corps of Engineers for 13 years. While with the Corps, she was responsible for the testing and maintenance of hydrogenerator windings, switchgear, transformers, protection and control devices, development of SCADA software, and the installation of local area networks. At Iris, Vicki has been involved in using partial discharge testing to evaluate the condition of insulation systems used in medium- to high-voltage rotating machines, switchgear and transformers. Additionally, she has worked extensively in the development and design of new products used for condition monitoring of insulation systems, both periodical and continual. Vicki also actively participated in the development of multiple IEEE standards and guides and was Chair of the IEEE 43-2000 Working Group.

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MAINTENANCE TESTING OF WIND FARM DISTRIBUTION SYSTEMS A NO-OUTAGE APPROACH NETA World, Summer 2013 Issue Don Genutis, No-Outage Electrical Testing, Inc.

INTRODUCTION Wind farm electrical distribution system design is quite unique in comparison to typical power plants, and these systems, therefore, require a nontraditional maintenance testing approach. This article examines how a cost effective, no-outage testing program can be implemented to reduce failures and increase reliability.

SYSTEM DESIGN Wind farm distribution design can vary but in the US the typical design utilizes low-voltage wind turbines to generate power. The low-voltage output is connected to a pad-mounted, fluid-filled distribution transformer located near the base of each turbine tower which steps up the voltage to 34.5 kV. The output of the transformer is then connected to the next turbine transformer using a three-wire, direct-buried, underground cable segment. Molded-cable accessories are used to terminate the cables to the transformers. Additional transformers are successively cascaded on the same string, and the cable load increases as it makes its way towards the collector substation. The load continues to increase until the maximum standard cable size is reached. The last segment of the string is usually quite lengthy in order to reach the substation, since the strings are far apart physically and thus often require several splices. Several strings typically terminate into one large collector substation which then steps up the voltage to subtransmission or transmission voltages. These substations consist of various designs but can include 35 kV switchgear or substation breakers, large power transformers, lightning arresters, instrument transformers, and often high voltage breakers with sophisticated protective relaying.

PAD-MOUNTED TRANSFORMERS The transformers located at the base of each turbine are critical to the operation of the string. If the transformer located near the collector substation fails, the entire string is down until repairs can be performed which often requires replacement. If a spare is not available, it may be best to replace the damaged transformer with a transformer located as close as possible to the far end of the string, thus getting as many turbines as possible back in operation.

The best overall way to ensure the reliability of these transformers is to perform regular fluid testing in accordance with the NETA Standard for Maintenance Testing Specifications. These relatively routine tests reveal a great deal of information related to both the condition of the fluid and internal transformer components in a cost effective manner.

CABLES The medium-voltage cable system is next to be considered. Ideally, a robust acceptance testing program including partial discharge testing in accordance with the NETA Standard for Acceptance Testing Specifications would have been performed so that problems are much less likely. However, failures will occur because of many factors, and regular testing is essential to maintaining integrity. A cable failure near the collector substation can take down an entire string the same as a pad-mounted transformer failure can, but it is likely that the cable failure will take much longer to repair, especially if it occurs somewhere along the final lengthy segment route to the collector substation. Failures here usually occur at splices and require bringing in an outside specialty splicing contractor equipped with cable fault locating instruments to precisely determine the exact failure point. Once identified, excavation would be necessary before repairs can begin. Although regular on-line cable partial discharge testing may be effective for ensuring good cable condition, it may be better to consider using off-line VLF partial discharge cable testing to evaluate the condition of the segment nearest the substation as the long cable lengths can make on-line PD location difficult. Besides the splices, cable system failure is common at the terminations which connect to the pad-mounted transformers. The condition of these terminations can be determined accurately by on-line cable PD test methods using radio frequency sensors. Unfortunately the turbine output converter electronics create massive noise signals that interfere with the on-line PD test results, so it becomes necessary to temporarily take a string of turbines off-line while this test is performed. Performing online cable PD testing also has the advantage of testing the other components immediately connected to the terminations including the transformer bushing well inserts, surge arresters, the internal transformer switch and bus insulation, and the transformer itself.

22 Recent testing was performed at a major wind farm in Minnesota using handheld PD testing instruments equipped with transient earth voltage (TEV) sensors. The TEV sensor was placed on the outside of the pad-mounted transformer enclosure as shown in Figure 1 to obtain an immediate health condition indication. The TEV test data was then compared to parallel on-line cable PD test results and found to correlate very well as shown in Figure 2. These results are very encouraging because it proves that terminations and all other connected components within the enclosure can be routinely and efficiently tested nonintrusively using the TEV method. If a problem is detected using the handheld detector, additional testing using on-line or off-line testing methods can be used to pinpoint the precise defect location so that appropriate repairs can be planned well before complete failure occurs.

SUBSTATIONS Collector substations are usually similar to traditional generation substations, so typical no-outage testing technologies usually apply. Outdoor open bus connections should be inspected with infrared imaging equipment and RFI surveys should be performed with antenna-based instruments to detect partial discharge activity inside bushings, substation breakers, instrument transformers, lightning arresters and insulators. External insulation surface tracking can be detected using airborne ultrasonics, corona cameras or RFI techniques. Outdoor switchgear insulation condition should be surveyed using ultrasonic and TEV sensors, while infrared cameras should be used to inspect connection integrity. Finally, transformer fluid should be sampled and tested regularly, and high voltage SF6 breakers should have gas samples taken and tested regularly as well.

CONCLUSION Wind farm distribution system design offer some unique differences compared to traditional power plant design, and these differences present some unique maintenance testing challenges. Employing a maintenance program consisting of no-outage testing techniques will minimize outages and provide the owner with increased reliability. Don A. Genutis received his BSEE from Carnegie Mellon University. He was a NETA Certified Technician for 15years and is a Certified Corona Technicians. Don’s technical training and education are complemented by twenty-five years of practical field and laboratory electrical testing experience. Don serves as President on No-Outage on No-Outage Electrical Testing, Inc., a member of the EA technology group.

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WIND FARM COLLECTOR SYSTEM – PREDICTIVE MAINTENANCE PRACTICES NETA World, Summer 2013 Issue Paul Idziak, Shermco Industries

Power generating facilities, and more specifically wind power generation facilities, avoid downtime to maintain consistent output of their prized product: electricity. Some of the facilities will stay on line for extended time frames skipping recommended maintenance cycles until an outage occurs. Within the wind farm owner’s key performance indicators, availability and production are at or near the top of the list. So how can wind farm owners perform necessary maintenance on their collector system and reduce downtime? How can wind generation sites develop an acceptable maintenance strategy using national consensus standards?

MAINTENANCE METHODOLOGIES Reliability-centered maintenance (RCM) and predictive maintenance (PdM) are two key maintenance concepts used to reduce downtime while providing the level of maintenance needed to keep generators on line and producing power. Developing a maintenance program based on these two concepts is not an easy task and will be revised constantly. A task that is even more difficult is finding the personnel with the needed skills and training to perform the maintenance. Figure 1 illustrates the issues the industry faces with a rapidly aging workforce. Where are skilled replacement workers going to come from?

process is to identify how the equipment is operated, define its purpose, and write a failure mode effects and criticality analysis (FMECA). The second part of the process is to determine the appropriate maintenance tasks for the identified failure modes in the FMECA. Once those tasks are identified for all elements in the FMECA, the resulting list of maintenance tasks is given specific maintenance intervals and bundled together. RCM reduces costs by concentrating on the monitoring and correction of root causes of equipment failures (also known as root cause analysis). This will help establish minimum levels of maintenance, point to required changes to operating procedures, and guide the development of capital maintenance regimens and plans.

Predictive Maintenance (PdM) PdM is the process of evaluating the condition of equipment by performing periodic or on-line continuous equipment monitoring. PdM is based on performing the right maintenance at the right time using on-line continuous monitoring techniques, whereas preventive (or phased) maintenance (PM) is performed strictly based on time. PdM is used as a part of a RCM program. One example of PdM is the use of partial discharge/acoustic emissions testing. The detection equipment is installed on cables or equipment and continuously monitors the system. Partial discharge (PD) is a localized electrical discharge that only partially bridges the insulation between conductors. PD is a phenomenon caused by imperfections inside cable insulation resulting from cable aging, thermal, mechanical, and electrical stresses, or manufacturing defects.

MAINTENANCE PLANNING Numerous factors need to be considered while developing an RCM program. Some of these factors include: ●● age of the electrical equipment ●● equipment condition ●● environment Fig. 1: Percentage of Workers by Age Range

Reliability Centered Maintenance RCM enables sites to monitor, assess, predict, and generally understand the working of their physical assets which are their generators, strings, and substations. The initial part of the RCM

●● loading ●● criticality ●● reliability ●● requirements of the power purchase agreement with local utility

24 Long-term trending, auditing, and staying current with changes in standards and methods of testing and evaluation must also be considered. These programs should be based on national consensus standards to bring credibility to the program. Sources such as NFPA 70B, Recommended Practice for Electrical Equipment Maintenance, the InterNational Electrical Testing Association (NETA) MTS-2011, Standard for Maintenance Testing Specifications for Electrical Power Equipment and Systems, and several IEEE standards should be referenced. The NETA testing standard also offers guidelines for the frequency of maintenance tests within Annex B of the document. Figure 2 shows some available standards, although there are many more that should be consulted.

Maintenance Vol. 1 qualified contractor with an industry-recognized electrical testing accreditation such as NETA Accredited Companies will help ensure that a qualified and competent testing organization will perform the needed testing. Regardless of which contractor is chosen, due diligence to the testing contractor’s capabilities and qualifications is essential. The wind generation site’s owners and third party contractors need to be cautious of the arc-flash hazard particularly on padmount transformers, wear proper PPE, and employ a qualified safety backup, if necessary.

THE GENERATOR, COLLECTOR, COLLECTOR SUBSTATION AND INTERCONNECTION SUBSTATION Infrared scanning (IR) accurately identifies the presence of abnormal heat in electrical and mechanical systems which can help predict equipment trouble. The infrared (thermographic) survey gives a detailed thermal and photographic record of any problems detected, so action can be taken before breakdowns occur. Infrared inspections routinely discover issues with loose cable and control wire terminations, electrical connections, and electrical insulation. This same technology can be used in the turbine as well as the collector system to identify thermal issues involving electrical components such as the step-up transformer insulating oil flow/ level, collector cabling connections/terminations, and generator circuit breaker connections.

Fig. 2: NETA, NFPA and IEEE all have Standards that will Assist in Developing a Maintenance Program

IN-HOUSE OR CONTRACTED PERSONNEL? Monthly and quarterly checks on the collector system make up part of the PdM/RCM program. These tasks can be performed by in-house personnel if they are qualified or by a third party contractor if the work is beyond the abilities and training of the in-house personnel. On-line testing can present additional risks and hazards with which in-house personnel may not be familiar. However, the overall impact to operations is minimal, and typically outages and down-time are not required.

Infrared cameras have come down in cost significantly over the last few years, so many sites are purchasing cameras for in-house, routine scanning of the equipment. Training and qualifying the parttime thermographer is usually performed by the manufacturer’s representative in a few hours. Infrared scanning of these machines and collector equipment on at least an annual basis is extremely important. If the reliability requirement is higher than average an infrared survey can be performed more often. Biannual or even quarterly infrared surveys are often justified. Figure 3 is an example of an infrared image. ANSI/NETA MTS-2011 provides infrared guidelines in Table 100.18.

In order to have a successful PdM program the wind generation site must employ trend analysis of the data. By trending such factors as generator heat, vibration, and oil data patterns over time, it is possible to determine when issues are beginning and plan for the required maintenance long in advance of failure. This results in minimum downtime and disruption to generation.

QUALIFYING THE TESTING CONTRACTOR Technicians performing electrical tests and inspections should be trained and qualified to understand the hazards associated with operating, switching, and maintaining electrical power equipment. Utilizing an independent, third party contractor can provide the necessary expertise required to perform on-line testing, interpret and trend the data, and create an RCM program. Selection of a

Fig. 3: Infrared Image of a Pad-Mounted Transformer. Note the temperature variation between C2 and the other phases

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Maintenance Vol. 1 An infrared camera is unable to see electrical corona, which is the ionization of the air surrounding a high voltage component. Several factors can affect a conductor’s electrical surface gradient and its corona performance, including conductor voltage, shape, diameter, and surface irregularities, such as scratches, nicks, dust, or water drops. Corona cameras can detect insulation and connection issues associated with the higher voltage equipment in the collector substation and interconnection substation by detecting corona emissions. Annual corona scanning is the minimum recommended frequency for detection of corona issues. Corona scanning combined with any ultrasound and partial discharge analysis yields valuable data about the health of the insulation system.

Transformer Insulating Oil Sampling and Analysis The majority of power transformers in operation at wind generation sites are filled with mineral oil. The primary function of the oil is to provide a high dielectric insulating material and provide an efficient method of cooling to dissipate heat. The effectiveness of the oil as an insulating material is reduced as the moisture level increases, while cooling is reduced as the oil deteriorates. Paper insulation absorbs moisture from the oil. The balance of moisture between the oil and paper insulation is affected by temperature and is constantly changing. Oil quality and dissolved gas analysis (DGA) tests are tools to determine the suitability of the oil for continued service. DGA measures the levels and ratios of dissolved combustible gasses in electrical insulating fluids. It is a very effective tool to diagnose potential problems in the transformer caused by loose connections, overloading, arcing, hot spots, and case or seal leaks that let moisture or air into the unit. Transformer insulating fluid sampling, testing, and analysis is another inexpensive line item in the maintenance budget. The average cost for oil quality tests and DGA ranges from $150.00 to $250.00 dollars per sample plus the cost of obtaining the sample. The variance in prices is based on which tests are included in the testing program. It is recommended that collector transformers be sampled on an annual basis, while the substation transformers should be tested twice annually, and possibly even three times per year, based on the number of load tap-changer operations. Figure 4 shows a typical oil-filled, pad-mounted transformer.

THE COLLECTOR SYSTEM Partial Discharge (PD) Sampling and Analysis Because a significant percentage of cable failures are associated with partial discharge, cable systems are typically tested after installation for manufacturing defects, improper installation and other related problems that can cause partial discharge. On-line PD testing provides crucial information on the integrity of an electrical system on a continuous basis. Using the appropriate equipment and techniques, partial discharge can be located, measured, and recorded, identifying cables, switchgear, and transformers that are beginning to fail.

On-Line Partial Discharge Testing On-line PD testing is performed while the equipment is energized at normal operating voltages. At various times a snapshot sample is pulled and sent to a third party expert for analysis. The testing is conducted during real operating conditions, under typical temperature, voltage stresses, and vibration levels. On-line PD is a nondestructive test and does not use overvoltages that could adversely affect the equipment. On-line partial discharge testing is relatively inexpensive compared to off-line testing that requires interruption of service and production. PD is most often used to detect and locate accessory and cable defects, but it can also detect failures in other areas (i.e., switchgear and bus). Similar hazards exist as discussed earlier in the on-line generator testing discussion. Direct interaction of personnel with an energized and operating generation system is extremely hazardous and the qualifications of the testing contractor or employee cannot be overstated. Prior installation of PD sampling boxes or cable/equipment test access panels will reduce the risk of exposure and expedite the on-line testing program. These boxes allow the routing of the cable/equipment shields or RF current transformers leads outside the equipment and mitigates exposure to the electrical hazards. They create a low risk environment to perform the sampling.

SUMMARY Just like any power generating facility, electrical maintenance of the wind farm is essential to high performance. While it is difficult to create and implement a RCM program, national consensus standards such as ANSI/NETA MTS 2011 can guide the wind generation site owner. Implementing predictive maintenance strategies are important to reducing downtime and maintenance costs. Even more important is maintaining the RCM schedule and comparing results with baseline values. By performing a predictive maintenance plan, the generation site will be able to take minimum planned outages to perform maintenance instead of experiencing expensive, unplanned outages. A predictive maintenance plan will also ensure the

Fig. 4: Oil-Filled, Pad-Mounted Transformer

26 safety of the site’s personnel, along with maintaining compliance requirements on the site. A qualified third party contractor will be able to perform the required testing and provide recommendations for the equipment when in-house personnel do not have the expertise.

REFERENCES O’Neil, Jim, “Industry Trends Impacting Maintenance & Testing of Electrical Assets” Keynote address at 2013 NETA PowerTest Conference. Paul Idziak is the Director of Renewable Energy Services of Shermco Industries, a leader in maintenance and repair of electrical machines and electrical power systems in the renewable energy industry. Paul’s responsibilities include the promotion of safety and reliability-centered repair and maintenance practices of renewable energy systems to include wind, biomass, geothermal and wind energy generation, collection and substations. Paul is also a qualified electrical worker, trainer, and consultant working with OEM’s, O&M’s, and electrical construction contractors that provide reliability-centered construction and repair services.

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WIND TURBINE GENERATOR ELECTRICAL FAILURES NETA World, Summer 2013 Issue William Chen, TECO Westinghouse Motor Company

Utility scale wind turbines have been a growing part of the global landscape for 20 years or more, but the industry is still maturing. The application for the generator itself is demanding, and the conditions are varied and complex. A quantitative review of the failure modes of over 1200 wind turbine generators repaired or replaced from 2005 to 2010 has uncovered that fewer than half of the failures were electrical in nature and the majority of those were due to mechanical failures of the insulation support structure that probably would not have been located using traditional testing methods. Many of the failures appear to be of a serial nature due to inadequate original design of the machine and/or the insulation system. These generators are exposed, at least in some part, to the typical voltage irregularities and mechanical stresses of any machine that operates 100 meters in the atmosphere in a wide variety of weather conditions. However, they are also sometimes affected by poor power quality from the IGBT based converters used in most turbines. These failures could result from voltage stresses created by the converter in the turbine or from neighboring turbines or, as has been suggested, even from neighboring wind parks. Several common failure modes for these generators have been identified, many of which can be traced to identifiable root causes. However, many failures remain difficult to trace as minor failures can lead to catastrophic electrical failures not directly related to the root cause. Understanding the types of failures and how often they might occur in a fleet of turbines is instrumental to developing a proper maintenance procedure and testing regimen. By reviewing these failures, we have been able to isolate the electrical material failures from the pure mechanical failures. The study covered damaged generators from a wide variety of manufacturers and represented a fairly reasonable sample of the industry. Three categories were set up based on the nameplate rating of the machine. As turbines have generally gotten larger as the industry developed, it can be assumed the largest category represents the more current designs. The failure modes identified represent the best estimate of the initial failure, keeping in mind that the root cause might be varied. The modes collected were: ●● Rotor insulation damage (strand/turn/ground) ●● Stator insulation damage (strand/turn/ground) ●● Bearing failures

●● Rotor lead failures ●● Shorts in collector rings ●● Magnetic wedge failures ●● Cooling system failures ●● Other mechanical damage Earlier designed, smaller machines show a high number of failures in rotor insulation. These are due to both electrical and mechanical failure of the conductors and the failure of the banding as designed. Many stator winding failures were actually due to contamination and issues with under designed bracing. The occurrence of bearing failures in generators between one and two MW is dramatically illustrated. These generators are generally more robust than their antecedents, but proper installation and good maintenance practices are critical to good reliability. The root cause of the majority of these failures is improper maintenance, although early failures could have also resulted from transient shaft currents. Very few insulation failures were recorded, and most were due to overheating issues created by improper cooling system design. Most wind energy generators have output voltages of 550-690 V ac. Some in the 1.5-2 MW class are high voltage machines ranging from 12-13.8 kV ac, but no statistics are available regarding specifically HV related failures. Again, in the class of generators greater than 2 MW, the bulk of the failures are from bearings for the same reasons as the 1-2 MW machines, but there is a dramatic rise in stator failures resulting from the loss of magnetic wedges utilized to improve the size/ output functionality of the generator. Where this failure mode has been seen in industrial applications, it is almost a universal failure point across manufacturers in this class of turbines. Based on new, unpublished data being compiled by Dr. Peter Tavner and his team at Durham University, Durham, UK, bearing damage is the leading root cause of failure in both wind and industrial rotating electrical machinery. In fact, with these large studies, there is actually little variation in types of major failure, only in specific machine design areas of vulnerability.

COMMON INSULATION FAILURES Rotor Banding It is thought that many of the older wind turbines and generators were originally designed to operate at 50 Hz, but were placed in

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service in North America at 60 Hz without proper redesign based on the increased electrical and mechanical stresses. Catastrophic failures were very common. This has been rare in the newer generator designs, and several redesigns of the older machines appear to have alleviated the problem. For remanufacturing purposes, most have also been redesigned using additional banding and other reinforcing materials, and this failure is no longer common among remanufactured machines (see Figures 1 and 2).

loosely in the slot, the wedge is very dependent on the resin to hold it in place. The ferrous nature of these wedges allows for oxidation where moisture and especially corrosive salts are present, and this may have contributed to the bond failures (see Figure 3).

Fig. 3: Missing magnetic wedges

Cooling System Failures

Fig. 1: Rotor Banding Failure

Since most wind generators are typically enclosed inside a notso-spacious nacelle along with many other components, ventilation can be hindered. Both rotor and stator windings need adequate ventilation in order to keep them cool and functioning correctly, especially if air-cooled design is used. Poor ventilation might lead to higher winding temperatures which in turn reduces the service life of those generators. Therefore, in addition to proper design considerations, the cooling/ventilation system should also be inspected and maintained on a regular basis.

Bearing and Rotor Lead Damage

Fig. 2: Rotor Failures

Conductive Wedges The loss of conductive slot wedges results in both grounding failures due to the conductive nature of the wedge material as well as mechanical damage to the coils. Both penetration of the coil by shards of wedge material as well as loose coil damage have been observed as causes of immediate and dramatic failures. As a general observation, several additional styles of generators have surfaced with this problem since the statistics were gathered, and this is becoming a serious problem for the industry. It is assumed that since the wedges have a high ferrous content, they react to the revolving electrical fields and will vibrate or shift under the influence. All of the machines studied appear to be manufactured using very low viscosity epoxy or polyesterimide resins. If the coil dimensions and slot filling materials are designed to fit too

A characteristic design for the popular double-fed induction generators (DFIG) is that the power converter is connected directly to the rotor winding through lead wires that pass through the hollow rotor shaft over which the bearing inner housing is fitted. The coupling effects of these and other harmonics can create an electrical current that passes along the shaft and through uninsulated bearing creating premature bearing failures. Also, peak voltage spikes generated from converters can reach several times the rated voltage and could cause flashover at the rotor leads. These effects require that the shaft grounding system design be more robust than is normally required for machines designed for normal operating conditions. In addition, because the entire generator is mounted at an angle from the horizontal plane, additional thrust force might act on the bearing structures. All these lead to higher bearing temperatures, or even bearing failure, which create enough heat to severely damage rotor leads, leading to eventual generator failures. Improper lubrication and normal bearing failure modes can also create this type of failure.

Under-designed Materials and Systems Extreme hot or cold conditions can dramatically affect machine service life. Unfortunately, those temperature extremes are quite common in many areas of the world where the wind blows the

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Maintenance Vol. 1 strongest. In addition, as opposed to most traditional motor/generator operations, wind generators experience frequent load changes due to the very dynamic nature of wind. As a result, those generator windings are often subjected to higher thermal cycling and mechanical stresses. Insulation materials, winding structures (such as lead connection/crimping), carbon brushes, etc., all sustain higher stresses and require higher standards in order to maintain their design integrities during operation. Therefore, extra allowance for all those conditions must be taken into consideration during the design process.

Catastrophic Failure Due to Surges Voltage irregularities, either from traditional grid related sources or from converter failures have continued to create issues with the generators. Proper protection from these problems as well as effective grounding of electrical system is critical. These phenomena might also contribute to the loss of magnetic wedges described earlier. As mentioned previously, many wind generators are connected to the grid through power converters. Although the rated operation voltage of the rotor winding is generally low (such as 690 V for most DFIG machines), those power converters will generate much higher peak voltage spikes (up to 2.5 kV peak and several kHz switching frequency). These greater stresses affect rotor winding insulation (including turn-to-turn, phase-to-phase, and main insulation) significantly. Proper design allowance and adequate protection should be implemented in order to achieve the optimal service life.

Contamination Issues Typically, wind turbines are operated in remote and difficult-tocontrol environments, and they typically are not totally enclosed. At those high elevations (many towers are around 100 meters high) and with unpredictable wind directions, moisture, dust, and sand can penetrate into the nacelle or even inside the generator frame. As a result, failures will occur. Proper materials and processes should be selected during the design and manufacturing of these machines in order to reduce or even eliminate most problems. Of course, regular checkups and maintenance are key elements of strategies to prolong service life. Another issue to be addressed here is the effect of saline contaminated environments such as those of offshore or near shore. Those corrosive conditions are generally bad for materials with ferrous content such as the generator frame, steel core laminations, or even the magnetic wedges. If left unprotected, those oxidation processes might lead to possible problems or even rapid failures; therefore, an adequate protective coating should be used to help for protection. Proper maintenance is critical to all rotating machinery. However, from some industry sources, incorrect lubrication of bearings leads to more service calls and catastrophic failures than all other factors combined. Following the manufacturers’ suggestion to use the correct lubricant is quite important. In addition, all lubrication

equipment needs to be monitored, serviced, and properly adjusted on a regular basis to assure predictable performance. Although lubrication overflow on the windings may not be damaging on its own, it does attract other contaminates, including conductive particles that may shorten the expected life of the system.

CONCLUSIONS Several of the failure modes of wind turbine generators might be trended and predictable, but most seem to be immediate and catastrophic. New monitoring schemes and more advanced vibration testing or even visual inspections might be required to adequately predict potential failures in time to schedule repairs. As the size of wind turbine generators continues to grow from the current 3.0 MW to the proposed 10-12 MW offshore behemoths, new challenges will be encountered involving the design and execution of proper electrical insulation systems. Larger machines, although they seem to be more robust and reliable, actually suffer from different failure modes but not necessarily fewer failures. The mechanical stresses of the newer machines are higher than in the first few generations of turbines. Some of today’s 2.5 MW generators are not much larger than the 660 kW machines of five years ago. High-voltage, synchronous generators with output voltage of up to 13.8 kV will bring their own issues although they have had a long successful history in industrial and commercial applications. Whatever direction the industry takes in the next few years, predictive and proactive maintenance will be required to assure profitable operations. William Chen holds degrees in material science and chemical engineering from the University of Utah and the University of Texas at Austin, respectively. He joined TECO-Westinghouse Motor Company in 1996 and has extensive experience in several departments. He is currently an Advanced Insulation System Engineer at its R&D Headquarters. William specializes in insulation development, qualification, and testing for large motors and generators and is a member of several IEEE standards working groups.

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UP-TOWER ELECTRICAL TESTING OF WIND TURBINE GENERATOR STATOR AND ROTOR MAIN WINDINGS NETA World, Summer 2013 Issue Kevin Alewine and Casey Gilliam - Shermco Industries As the wind turbine fleet in North America ages and the equipment moves out of the manufacturer’s warranty period, owner/ operators are beginning to learn how to maintain the turbines to optimize their uptime performance. Wind turbines are, by their very nature, a series of mechanical and electrical components (see Figure 1). Although the root causes of many wind turbine generator failures are mechanical in nature (alignment, vibration, lubrication, etc.), some are electrical in nature, and normal end-of-life events nearly always result in dielectric breakdown of the electrical insulation or related supporting materials. Given the wide variety of generator types and sizes currently in use, it is difficult to establish predictable failure modes across the industry, but certain tests can be performed while the unit is in service (on and off line) that will prove useful to the maintenance crew in predicting and minimizing downtime in order to improve profitability.

Fig. 2: Tools, equipment, and technicians must all travel to the top of wind turbines to perform work

WHAT IS ACTUALLY BEING TESTED?

Fig. 1: The mechanical heart of the wind turbine: The Gear Box A standard insulation-resistance test is the normal protocol for the wind turbine technician, but what are they looking for and what do they do if they find it? In fact, is it even a helpful test on an operational wind turbine generator? And when you are 80-100 meters in the air, the electrical test results to determine overall health of the machine become even more important (see Figure 2). This article helps explain what testing might be performed as part of scheduled maintenance and what further testing can be done to determine whether the status of a generator is at a critical point. It is typically better to identify issues as early as possible and schedule a generator change out at a convenient time rather than undergo an unexpected and possibly spectacular generator failure. Let’s start with a quick review of what we are testing – the electrical insulation system of the generator.

Most wind turbine generators operate in the low-voltage range (less than 1000 volts). The windings of the generators come in two styles: random-wound (using many small, round conductors in parallel) or in form-wound coils where larger rectangular conductors are preformed and, normally, insulated with ground wall insulation before being inserted into the stator or rotor (see Figures 3 and 4). Random-wound machines normally use enamel insulated conductors which are wound into coils and inserted into slots which are already insulated with an appropriate high temperature paper or laminated material. Phase insulation of the same or similar material is placed between the coils in the slots as well as on the overhanging portions. The coils are then wedged into place, reinforced with cords and blocking materials, connected, and finally varnished with a high temperature resin. While most machines using this insulation system design are less that 1,000 kW, there are a few up to a rating of 2.0 MW that will use random-wound coils in the stator only. Almost all rotors above 660 kW are designed using form-wound systems.

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levels, and electrical surges. The basic concept of periodic electrical testing of the EIS is to monitor and/or trend the factors that lead to premature failures. Let’s consider the basic testing that can be done at regular maintenance checks.

UP-TOWER PERIODIC TESTING

Fig. 3: Wind turbine stator with form-wound coils

Firstly, safe work practices concerning electrical devices, whether in operation or under test, are paramount. All LOTO and arcflash rules should be carefully followed, and only qualified electrical workers should undertake this testing. Additional hazards may exist due to the small work space and close clearances with the turbine nacelle (see Figure 5). The InterNational Electrical Testing Association and National Fire Protection Association, as well as other organizations, have recommended guidelines for safely testing electrical components and should be consulted if there are any questions regarding safety.

Fig. 4: Wind turbine rotor and insulation system shown during assembly In a form-wound system the larger insulated conductors are often insulated with a mica paper/polyester film tape that is common in European and Asian designs for high voltage machines. In the USA, it is also common to use enameled conductors, sometimes with a glass filament covering. These conductors are shaped into coils, then additional layers of tape are applied over the bundled conductors to provide both phase and ground insulation. These tapes are normally a laminate of mica paper with some combination of polyester film, polyester fleece, or glass cloth. These finished coils are then inserted into the stator or rotor core with or without additional ground insulation. They are wedged into place, tied, and otherwise supported and then varnished, typically utilizing a vacuum and pressure cycle impregnation system. All of these insulation and conductor components (and there are actually many more ancillary materials utilized in the winding process) are designed to function together as an electrical insulation system (EIS) to provide long lasting, reliable performance at a designed and tested operating temperature. The thermal life expectancy is normally calculated for 20,000 operating hours and includes thermal cycling, vibration, and electrical stress testing. In normal end-of-life events, the insulation has broken down at some tiny point due to mechanical abrasion or thermal weight loss so that it is no longer functional. These natural and foreseeable failures can be accelerated by environmental conditions including moisture and chemical contamination, high machinery vibration

Fig. 5: The Nacelle often has close quarters and tight working conditions

Insulation Resistance Insulation resistance (IR) testing is one of the oldest maintenance procedures developed for the electrical industry and is covered in detail in IEEE Standard 43-2000. This test is fairly simple to perform and can provide information regarding the condition of the electrical insulation in the generator as well as contamination and moisture. It is recommended that this test be performed before energizing a machine that has been out of service or where heating elements have failed to keep the winding temperature above the dew point, which might have resulted in condensation on the windings. Insulation-resistance testing is also useful whenever there is doubt as to the integrity of the windings and before any overvoltage testing is performed. An accurate IR test requires a correction factor for the winding temperature to create useful data. The methods and expected result data for this test are listed in the IEEE standard. While the test results from IR testing are not normally trended, it is possible to do so to illustrate a gross degradation of the insulation systems. It is, however, very important that the duration of the test, the temperature of the windings, and relative humidity be consistent for the trend data to be meaningful.

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Polarization Index

WHAT’S AHEAD?

Another test described in IEEE Standard 43-2000 is the polarization index that is useful in some applications to identify contaminated and moist windings. In most modern machines, however, where the insulation resistance is above 5000 megohms, the test might not prove meaningful. Recently there has also been a consideration of collecting depolarization data as well as analyzing the shape of the polarization curve. Refer to the IEEE standard for additional applications and details.

Although power-quality testing can be performed for energy from the generator as well as excitation power to the rotor, in the near future, simplified on-line testing of electrical circuits will become more available, and acceptable standards of performance will be better defined. Based on either SCADA information versus industry standards or on actual measurements of power quality into and out of the generator, these tests will allow first line maintenance teams to monitor and trend data more effectively from the ground and provide more root cause failure information than is currently available. As most generators currently in use are double fed induction types, the quality of the power from the converter IGBTs feeding the rotor as well as voltage issues from the grid can be questionable, and either could be a major contributor to early insulation failure.

WHAT IF THE TESTS ARE INCONCLUSIVE? If the results gathered during a periodic testing cycle are inconclusive or out of the normal range, additional testing is recommended. Normally a generator specialist, either internal or from a consulting service company, is called in to perform these advanced tests as there are some possibilities of further damage to the windings if they are not carefully tested. Some electrical testing is by nature destructive and should only be performed for diagnostics reasons.

SURGE COMPARISON TESTING The normal advanced test for analyzing the insulation integrity is based on fairly innocuous testing performed by electrically stressing the insulation at a reduced voltage level and recording anomalies between phases of the insulation. This surge comparison testing can be performed manually; however, automated test equipment with digital reporting is available. This is not a trending test, nor does it answer all of the possible questions, but it provides a snapshot of the current condition that can support a decision to remove the generator for repair.

High-Potential Testing If testing is required to make an immediate decision regarding replacement of a generator, high-voltage testing, normally dc highpotential testing, is useful, but care should be taken as insulation weaknesses (cracking, contamination, carbon tracking, etc.) can be advanced to failure. Sometimes referred to as overpotential testing, the high-potential test is designed to stress the electrical insulation beyond its normal operating voltages to expose potential failures at a convenient time. The dc test methods are described in IEEE Standard 95. Trending is possible with this test, but it is considered a destructive test and probably should be used sparingly and only if the site is prepared to repair or replace the machine.

Most wind turbine generators operate at 575 or 690 V ac (a very few are in the 12 kV range) and do not normally generate partial discharges (corona) in the range to be monitored. However, in conjunction with the surge comparison test, there is auxiliary equipment available to ride the high-voltage impulse signal and collect PD information at the peak of the signal. In the future, this data might be useful as a trending tool to help predict normal end-of-life conditions or to identify damage too small for other detection methods. All good testing stratagems are designed to assure the profitability of the operation. Periodic electrical testing, vibration testing, and alignment of the drive train are time consuming operations and are sometimes difficult to perform on a regular basis. However, the cost of unplanned outages including cranes, staffing and emergency generator repairs can also dramatically affect the bottom line. Good planning, proper testing methods, and clear decisions regarding the condition of the equipment will always pay off with reduced overall maintenance costs. Kevin Alewine is currently Director of Renewable Energy Services at Shermco Industries with a focus on business development in the wind energy business sector. He has extensive global experience with the application of electrical insulation materials, systems, and processes for both the manufacture and repair of electrical machinery. Kevin is an active member of several IEEE and American Wind Energy Association working groups including chairing the AWEA Operations and Maintenance Working Group developing recommended practices for wind energy asset maintenance.

Step Overvoltage Test Using the same equipment as used for the high-potential test, the step overvoltage test stresses the insulation at rising levels of voltage over a set time scale. This is a very useful trending test and can be used in periodic predictive maintenance testing. The same concerns exist as for high-potential testing.

Casey Gilliam has thirteen years of experience in the mechanical industry that includes testing, maintenance and management. He has worked in both field and shop setting in his career. As a technician he has a background in quality improvement, troubleshooting, and repairs while mentoring and leading a team. Casey is currently the Sweetwater Service Center Manager at Shermco Industries.

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ELECTRICAL POWER SYSTEM TESTING – A QUANTUM CHANGE IN OUR FIELD HAS ARRIVED NETA World, Summer 2013 Issue John Hodson I look back over 30 years involvement in the electrical testing industry and realize that many changes have occurred that are now the accepted norm. It is quite similar in our normal day to day activities….I still marvel at the day my 21 year old daughter could not find the remote for the TV and suggested we needed to get a new remote (or TV)…. she had no idea a television could be turned on at the screen. Some of the lost skills or technology I remember as I reflect back in time:

Some of the new technology I have seen: ●● Relay sets that do not weigh 80 pounds (but need a laptop ●● Vacuum bottle interrupters ●● Something not needing to be done by yesterday ●● Test technicians without a specialty (testing was the specialty) ●● Test sets that do everything for you…. Simplified push button testing ●● Better stop…..could get confrontational…. Back to the Future -- Decade Two / Century 21….

Fig. 1: Good Ole SR51 Relay Test Set ●● Relay sets that did not require software, but a relay bulletin to figure out how to test it ●● Typewritten reports and invoices with carbons (way back) ●● Having to figure things out on site without the benefit of cell phones or (site phones) ●● Drawing coordination curves on log-log paper ●● Electronic [not microprocessor] relays ●● Hand taped rather than heat/cold shrink HV terminations

Many influences affect our present day life and future, arguably the most impactive may be our world of instant communication/ information, data storage and processing capability, and short description computers. Computers with email, calendars, appointments, and reminders have absorbed our life planning with web-based connectivity. It is a natural step then, as technology advances on all fronts, that we should find it becoming integral to the electrical industry. On point, the electrical industry is one of the most advanced and technically challenging based on the control and custody of a very powerful energy. Before we move forward we should review our electrical testing basics. I suggest that the main purpose of our work is to measure the performance and condition of power equipment. In addition, we bring our experience and knowledge to drive improvements and efficiencies, but in the final analysis the question to be answered is “Does the device do what it is supposed to, reliably, safely, and within design and application parameters?”

Fig. 2: The Generation of Microprocessor Relay Sets Fig. 3: ATS 2009 Cover

34 We, as NETA member companies, have a well-developed set of tests and a huge selection of test equipment to work with. The majority of these require the equipment be de-energized to allow the tests to be performed. This not only creates a set of concerns regarding safe access and re-energization but also takes the equipment out of its normal or dynamic state. Once we have the equipment in its deactivated condition the majority of our tests try to simulate the energized condition to evaluate performance. Some examples of this are conductivity, ratio testing, insulation testing, and power-factor testing. In many cases we are utilizing estimates and dc conversions to allow us to have equipment that is portable and more manageable regarding power requirements. Balancing electrical testing procedures with practicality has always led to some level of compromise. This has typically led to very good but not optimum diagnostics and with some room for error in evaluation of all conditions. With advances in technology, we now have the capability to not only monitor power systems for protection and control in upset condition but to actually evaluate equipment performance and serviceability. The first integration of microprocessors into metering and protection equipment has provided for waveform capture, harmonic analysis, voltage and current monitoring, and more. The key to this is the ability to digitize information and store massive amounts of data over long periods of time. [Perhaps I should have included pen chart recorders in my list of lost technology]. Much of this information was initially overlooked and the new instrumentation was underutilized as strictly a replacement for what now seem archaic, electromechanical relays and analogue meters. With improved communications the data can now to be centralized as a minimum for real time analysis review after upset. As we experience more and more smart relays, meters and now even networks and grids, the full potential is becoming much more evident. The availability of new devices that measure, monitor, and evaluate electrical power apparatus and accessories is growing monthly and exponentially. Devices to perform tests normally done in the laboratory on insulating oils are readily available at reasonable cost. ●● Breaker contact timing and wear evaluation measurements-available. ●● Real time temperature monitoring by direct contact with energized parts--available.

Maintenance Vol. 1 The following identifies some of the presently available technology.

Fig. 4: Advanced Diagnostic Waveform Analysis

ONLINE MAINTENANCE DIAGNOSTIC OPTIONS Temperature Monitoring ●● Oil / Liquid - Winding - Ambient - Contacts ●● Tank//Internal - External/Infrared Gas in Liquid Monitoring ●● Acytelene – Hydrogen – High Gas Fluid Chemical Analysis ●● Moisture - Acidity Pressure ●● Tank - Atmospheric - Gas – Loss of Gas Voltage / Current ●● Power Functions – Fault Current - Waveforms ●● Impulse – Harmonics DC Voltage ●● Level – Motor Signature ●● Trip / Close Coil Signature Digital I/O ●● Contact / Device Status – Timing Functions ●● System Operating Mode – Clock Functions ●● Equipment Mechanical Position - Travel Power Factor / Capacitance

●● Online partial discharge levels--available.

●● Transformer Busing Monitoring ●● Cable Monitoring

●● Online ultrasonic detection--available.

Partial Discharge

●● Battery condition monitoring--available.

●● Cable Accessories – Rotating Machinery ●● Switchgear

●● Rotating machinery vibration and winding diagnostics--yes available and the list grows.

Ground Resistance ●● GPR Under Fault – Ground Rod Condition

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Maintenance Vol. 1 Arc and Pressure ●● In Oil – In Air – In Enclosure Far from complete but certainly comprehensive this list will continue to grow monthly. Some existing and new startup companies are focusing on this area of real time diagnostics further driving advances. One very interesting field of experimentation is driven by light and fiber optic communication. It has been proven that light is affected in a measurable and consistent manner when exposed to certain energies such as heat, pressure, and electromagnetic fields. As light and fiber optics has no discernible conductivity, it is a perfect control and protection medium to be integrated into electrical power systems. As new products and monitoring devices are installed in our electrical systems and as their capabilities for diagnostics improve, it will be less necessary to shut equipment down to evaluate condition. The opportunity to operate equipment in a dynamic or operational state with online equipment measuring and storing all manner of data regarding performance is already here. One of the large inhibitors to this integration comes from a shortage of resources to manage the copious amounts of information gathered and what to do with it. There is also some push back in installing more equipment than necessary, as that becomes not only additional asset cost but also a further maintenance concern. The reality is that we need to balance benefits vs cost. I believe the tipping point has arrived and a paradigm change in how we do our work is imminent. The era of smart meters and relays has evolved into the smart grid and ultimately the smart transmission and distribution system. This has reinforced what we might call smart software which not only stores data but analyzes and reports on power system components and overall network reliability. These are operated via flexible historian software such as OS π, which when coupled with specialized and complex algorithms can evaluate condition on a continuous basis. Some systems are less complicated and are partnered only with specific products such as gas in oil measurements with tolerable limits for quantity and evolution rates. The full potential of real time diagnostics is realized when numerous devices input to a common register and all data is available in common format for input to extremely powerful custom algorithms. The most powerful of these analysis macros allows not only for the input of on line data from numerous devices but for input from off line test information gathered from FAT and through acceptance and commissioning and maintenance testing. As manufacturers specifications and safe limits are added to the equation for more precise and accurate determination of condition. When economics are to be added to the technical decision, coming back to benefit vs cost, many analysis formula include a risk factor of failure and process consequences related to monetary and safety impact. That is if a component and or system fails, what will be the impact on facility process or throughput be and for how long? In some cases

the risk analysis may indicate that a component is not critical at all and failure may be just an inconvenience until repairs are effected, this is often called run to failure or RTF. A sample situation may be a lighting transformer and panel. In many cases, monitoring of larger assets is easy to justify simply because of cost of asset and replacement. Exceptions are certainly possible whereby small components such as a lube oil pump can have catastrophic effect on much larger components and finally result in a massive impact on operations. The determination of equipment criticality is established by FMECA procedures comprising of failure mode modeling and impact analysis. This is usually supported by software of its own such as AMR and assigns a criticality value to equipment based on many criteria but typically very important is how likely is this to happen, how much are we doing to prevent it, and what is the worst case impact of failure. This topic really warrants a discussion on its own merits. The process of executing a complete electrical CBM/RBM program is significant. Certainly the most key component is an acceptance and change in attitude and understanding at all levels of management, operations, and engineering. This cannot be done in a short period of time and would typically take place over years and then be further enhanced by means of a continuous improvement plan. Critical components for switching from TBM to CBM include knowledge, usually via a competent and trusted electrical partner. Corporate acceptance and support at all levels and the resolve to see the project through. A budget to support the initial efforts, and then an ability to track and evaluate performance as the benefits are realized. The end goal is to show that the program pays for itself over time in more focused maintenance efforts and improved reliability and efficiencies.

Fig. 5: The CBM Process Many companies have taken the first steps towards CBM through necessary improvements in protection and control technology that are being carried out industry wide. Certainly the utility companies have seen the future with companies like Doble, GE, IBM and SKF working diligently to provide the next software platform for

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equipment maintenance. In many cases it is only necessary to start utilizing and processing the available information already available in your electrical system in a coordinated and effective manner. As these first steps show their value the addition of more sophisticated and powerful diagnostics can be added along with the required data storage and analytics to ensure the most comprehensive evaluation is available. Then based on indicated condition and criticality, the equipment can be scheduled for routine or emergency inspections and testing. The most advanced algorithmic analysis will even provide the recommended tests, estimated time to failure, and follow up monitoring and testing necessary to confirm corrective actions have been properly executed. This new frontier in electrical testing is just starting as many of us baby boomers are leaving the industry. The day of a daily/ hourly condition report based on a simplistic traffic signal with green indicating all is ok, yellow indicating potential concerns, and red indicating a serious problem are possible today. How long will it be until this is the operational norm-time will tell. It is fitting in many ways that generation X, raised on video games and iPads will be monitoring the health and condition of our electrical systems with apps on their iPhones.

Fig. 6: The CBM Traffie Lite = GO / INVESTIGATE / SHUT DOWN It is also fitting that until we come up with an app for turning a wrench, connecting a test lead correctly, or doing a proper cut back on the semiconductor there will still be a requirement for hands on field service technicians. John Hodson has spent over 30 years in the field service industry with Magna IV Engineering Ltd. He served as the NETA representative for Magna Group of Companies for several years. He is still active in the industry by mentoring, training, and working to promote advanced diagnostics hardware and software and their integration.

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SYNCHRONOUS ROTOR WINDING – COMMON ELECTRICAL MONITORING NETA World, Fall 2013 Issue Vickie Warren The rotor windings of synchronous motors and generators are usually very reliable. However, the turn insulation in such machines will eventually degrade and puncture due to thermal aging, load cycling and/or contamination. Although turn shorts do not directly lead to machine failure, they can lead to high bearing vibration, may damage synchronizing systems within brushless motors, and may limit output. Off-line tests are available to detect rotor winding shorted turns; however, they may be unreliable since the rotor is not spinning for the test. If only a few shorts are present, the shorts may disappear once the rotor is spinning (or vice versa). In the last edition of the NETA World, several of the common off-line electrical tests for synchronous rotors were described. This article will explain flux monitoring, which is a common on-line condition monitoring test for both round and salient pole synchronous rotors.

SHORTED TURNS Shorted turns are the result of failed insulation between individual windings in generator rotors. These shorted turns can cause: ●● Load sensitive vibration ●● Undetected local winding hot spots ●● Excessive excitation currents ●● Possible forced outages When an insulation system is exposed to overheating, the bonding material tends to lose its mechanical strength and the insulation layers delaminate. As the insulation bond weakens and the layers delaminate, the conductors can become free enough to move with respect to each other. This weakened bonding affects not only the mechanical stability of the field winding, but any vibration or movement will result in mechanical abrasion and may lead to strand/turn shorts and eventually ground insulation failure. Additionally, thermal aging can lead to shrinkage of bracing materials causing winding looseness. Insulation breakdown from simple thermal overheating may take years depending on the temperature and thickness of the insulation. Thermal deterioration can occur as a result of overloads, defective cooling, unbalanced phase voltages, overexcitation and poor design/manufacture. [Figure 1]

Fig. 1: Thermally Damaged Turn Insulation The following are the most common causes of thermal aging in rotor windings1: ●● Overloading leading to operating temperatures well above expected design values. Rotors always run hotter than the stator winding. ●● High cooling temperatures or inadequate cooling which can be general, e.g., insufficient cooling air or cooling water, or local dead spots (especially at the blocking between poles) due to poor design, manufacturing or maintenance procedures. ●● The use of materials that have inadequate thermal properties and consequently deteriorate at an unacceptable rate when operated within design temperature limits. ●● Over excitation of rotor windings for long periods of time. ●● Negative sequence currents in rotor windings due to system voltage unbalance, etc. Due to the different linear coefficients of thermal expansion for the materials in insulated rotor windings, one of the negative impacts of frequent changes to a machine’s load or starts and stops are the cyclical shear stresses placed on the insulation. As the copper linearly expands due to the increase in temperature from I2R losses, the insulation, which is bonded to the copper and wedged between the conductor and the pole body, tends not to follow the copper due to a lower coefficient of thermal expansion and lower temperature. This stress can cause a weakening of the bond between the copper and the insulation or between the pole body and the insulation. Relative movement between the two, over time, can lead to turn shorts or the field grounding to the rotor. [Figure 2]

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Maintenance Vol. 1 reduces the effective ampere-turns of that pole and thus the signal from the flux probe.

Fig. 2: Damage from Thermal Expansion When any kind of conductive contamination from moisture, oil, chemicals, dust/dirt pollutes a machine, or a mixture of these, it is possible for electrical tracking to develop between conductors and ground in salient pole and round rotor windings. Severe contamination and some chemicals can results in both turn and ground insulation failures from tracking as well as winding overheating. Abrasive particles such as coal dust, sand, and iron ore can enter the interior of motors with open enclosures. When these particles impinge on the rotor winding they wear away the insulation and can cause both turn and ground faults. Oil tends to dissolve and loosen insulation system components and can attract dust that reduces heat transfer from the winding surface and reduces insulation life. In open enclosure machines, oil in combination with dust can clog up rotor cooling air passageways to cause winding overheating. Salient pole rotor windings, especially the strip-on-edge type, can experience turn-to-turn shorts and ground faults from contamination that cause tracking. Also, if a salient pole motor has slip rings brush dust, which is conductive, it can contaminate both the stator and rotor windings.

FLUX MONITORING OF ROUND ROTORS Round (or cylindrical) rotor poles are used in large two-pole or four-pole synchronous motors and generators. The round rotor field windings have concentric windings made from rectangular copper strips with turn insulation consisting of strips of insulation such as Nomex™, fiberglass/resin laminate, flake mica sheets, or Kapton™ sheets. The slot ground insulation is usually molded “L” shaped pieces made from epoxy or polyester/glass. Flux probes have long been used to measure the voltage signal created by the flux surrounding each slot in each rotor pole on synchronous motors and generators rated 4160 volt and above2. The radial magnetic flux is detected by means of a flat coil (or probe) consisting of several dozen turns that is glued to stator teeth4. [Figure 3] As each rotor pole sweeps by the flux probe, a voltage is induced in the coil that is proportional to the flux from the pole that is passing the coil. By analyzing the waveforms and comparing them pole to pole, it is possible to identify slots with shorted turns. Any turn short in a pole

Fig. 3: Flux Probe Usually, coils that have peak-to-peak difference larger than 3 percent compared to the same coil on another pole, are considered to have shorted turns. [Figure 4]

Fig. 4: Flux Difference of Shorted Turn Historically, for a thorough analysis, it was imperative that flux data be collected at various output load conditions2. As such, it was often necessary for the data collector to invest long hours, often at odd times, to gather data during generator startup or shutdown. Recently, a second generation of rotor flux analyzers has emerged with the advantage that, in most cases, it is no longer required to maneuver the load from 0 to full power4. This makes the test much easier and cheaper to do. [Figure 5 and Figure 6]

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flux profile across each rotor pole depends on the MW and MVAr loading of the machine. After corrections for variations in the airgap, any change in the flux profile within a pole at a given load must be due to shorted turns6. Changes in the flux pattern and differences from those from other poles gives an indication of the presence and number of shorted turns.[Figure 9]

Fig. 5: Flux Data - Round Rotor

Fig. 7: Flux Probe for a Salient Pole Rotor

Fig. 6: Flux Data - Round Rotor

FLUX MONITORING OF SALIENT POLE ROTORS Salient pole rotors are used in machines with slow speeds that make cylindrical (round) rotors impractical. Each field pole consists of laminated steel core, which looks rectangular when viewed from the rotor axis. Around the periphery of each pole core are the copper windings. Each field pole is an electromagnet, and the rotor winding is made by mounting the poles in pairs on the rotor rim. The poles are then electrically connected to the dc supply (normally up to a few hundred volts) in such a way as to create alternating north and south poles around the rim. The inside shape of stacked turns conforms approximately to the width, length, and height of the pole body. The winding has turn insulation while pole body insulation may simply be air. Similar to the round rotor, rotor flux monitoring involves measuring the magnetic flux in the generator or motor air gap to determine if field winding shorts have occurred in the rotor poles. [Figure 7] As each rotor pole sweeps by the flux probe, a voltage is induced in the coil that is proportional to the flux from the pole that is passing the coil. [Figure 8] The voltage is measured by electronic instruments. In a salient pole machine, the radial magnetic

Fig. 8: Flux Measured in Salient Pole

Fig. 9: Shorted Turns in Poles 8 & 48

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REFERENCES G. Stone et al. Using Magnetic Flux Monitoring To Detect Synchronous Machine Rotor Winding Shorts IEEE PCIC 2011-17.

1



2



3

D. R. Albright Interturn Short-Circuit Detector for TurbineGenerator Rotor Windings, IEEE Transactions on Power Apparatus and Systems, Vol. PAS-90 Number 2, March/April 1971.  .P. Jenkins, D.J. Wallis Rotor Shorted Turns: Description M and Utility Evaluation of a Continuous On-line Monitor, EPRI Predictive Maintenance and Refurbishment Conference, December 1993.

4 M. Sasic, B. Lloyd, A. Elez Finite Element Analysis of Turbine

Generator Rotor Winding Shorted Turns IEEE Transactions on Energy Conversion, Vol. 27, Number. 4, December 2012

5

S. Campbell et al. Detection of rotor winding shorted turns in

turbine generators and hydrogenerators CIGRE A1_206_2010 6

M.

Sasic et al. Tools for Monitoring Generators, Hydro Review Worldwide, Oct 2009, pp 12-19.

Vicki Warren, Senior Product Engineer, Iris Power LP. Vicki is an electrical engineer with extensive experience in testing and maintenance of motor and generator windings. Prior to joining Iris in 1996, she worked for the U.S. Army Corps of Engineers for 13 years. While with the Corps, she was responsible for the testing and maintenance of hydrogenerator windings, switchgear, transformers, protection and control devices, development of SCADA software, and the installation of local area networks. At Iris, Vicki has been involved in using partial discharge testing to evaluate the condition of insulation systems used in medium- to high-voltage rotating machines, switchgear and transformers. Additionally, she has worked extensively in the development and design of new products used for condition monitoring of insulation systems, both periodical and continual. Vicki also actively participated in the development of multiple IEEE standards and guides and was Chair of the IEEE 43-2000 Working Group.

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SWITCHGEAR PARTIAL DISCHARGE LOCATION NETA World, Fall 2013 Issue Don Genutis, No-Outage Electrical Testing Inc.

More and more service companies are finding success with No-Outage field Partial Discharge (PD) testing and monitoring methods and as the use and awareness of these techniques continue to expand, it becomes important to determine the location of the PD source so that it can be eliminated. In this article, we shall review the three basic types of PD sensors used for switchgear testing and monitoring then discuss how probable PD location can be identified on-line and how it can be pinpointed off-line.

TYPES OF PD SENSORS Airborne ultrasonic sensors are the most sensitive type of sensor for detecting surface insulation PD. These sensors detect the minute pressure waves which are created from the PD "sparking" activity. Switchgear vents or openings must be present in order for the pressure wave to reach the sensor from outside of the enclosure. Ultrasonic sensors also cannot detect problems internal to components. Transient Earth Voltage (TEV) sensors detect electromagnetic signals created by internal PD activity through capacitive coupling. The TEV sensor consists of a metal plate assembly, which when placed against the switchgear, forms a temporary capacitor with the enclosure acting as the other plate of the capacitor. This test method compliments the ultrasonic sensor by allowing the detection of internal component PD flaws or detection of surface discharges that ultrasonic sensors cannot "see" due to inhibited airway access paths. Since the ultrasonic sensor is more sensitive to surface PD, the TEV sensor will often pickup when surface activity becomes more severe. High Frequency Current Transformer (HFCT) sensors consist of a split core ct with high frequency characteristics that detect conducted electromagnetic signals from cable PD by placing the sensor around the cable shield. This sensor detects PD at the cable termination and can detect PD further down the cable as well.

WHAT DO THE SENSORS TELL US ON-LINE? By examining Diagram 1 we can see what each sensor alone and collectively tell us in regards to PD location in switchgear. For this example, the sensors can be either permanently mounted, in the case of monitors, or temporarily mounted in the case of spot testing. The "H" circle represents the HFCT sensor, the "T" circle represents the TEV sensor and the "U" circle represents the Ultrasonic sen-

sor. Non-intersecting circles are straight forward to figure out: "H" by itself represents a cable problem, "T" by itself represents an internal switchgear problem and "U" by itself represents a surface switchgear problem. Moving along, where is the PD located if two sensors indicate a problem? Taking a look at Diagram 1 again, the area labeled "HU" displays a condition where both the HFCT ("H") and the Ultrasonic ("U") sensors pick up PD signals. This would be indicative of a surface cable termination problem. "HT" represents an internal termination problem and "UT" represents a severe surface switchgear problem - the surface tracking has reached a point where TEV signals are being generated as well as explained above. Finally, the "HUT" part of the diagram [Figure 1] indicates the condition of all three sensors picking up PD signals. This is likely related to a severe surface termination problem. It should be noted at this time that once any sensor picks up an abnormal signal, it should be investigated. Do not wait until multiple sensors alarm before taking action. This is especially true for the Ultrasonic sensor as surface PD damage can escalate rapidly and the signal path can be impeded by obstructions.

Diagram 1

HOW DO WE PINPOINT PD LOCATION OFFLINE? Very valuable information can be obtained when equipment is being shut down for maintenance and this applies to a much broader scope than just PD alone. For instance, obtaining breaker "first trip" condition allows valuable mechanical condition data to be recorded which also ties in protective device coordination and arc-flash compliance. Tripping medium voltage breakers from

42 protective relays can ensure proper function of the trip circuit, battery, wiring and associated components including the breaker trip coil and linkage. For pinpointing PD, an orderly shut down or "selective switching" can help rule out components by the process of elimination. Lets take a typical medium voltage switchgear assembly for instance, where PD has been located in one cell. First begin by tripping the breaker (don't forget to record the first trip data if possible), then check to be if the PD is gone. If so, the activity is located on the load side of the breaker which usually would involve cable terminations or load side bus insulation and could involve breaker load side connection insulation. If the PD persists, the next step would be to rack out the breaker using a remote breaker racking device to ensure personnel safety. Once the breaker has been racked out, check for PD activity. If gone, the problem is in the breaker. If the problem remains, it is associated with bus insulation or line side breaker connection insulation. After the switchgear has been completely deenergized, locked out, tagged out and grounded, visual inspections can proceed. Keep in mind that unless Ultrasonic signals where detected, the problem is likely to be internal to a component or deep in the switchgear where the airborne signals cannot escape. Look for surface tracking, the presence of white powder or other color powder buildup, discoloration, corrosion or other usual signs. If the problem is internal or if its difficult to visually locate a surface problem, carefully energize individual components using a PD-free a.c. Hypot and use the applicable PD sensor(s) to identify the faulty component through the process of elimination.

CONCLUSION Switchgear should operate PD-free and detecting the presence of switchgear PD activity is the first step in the process of ensuring reliability. The next step of the process is to locate the PD source on-line using information gleaned from the different types of sensors available. The next step is to perform "selective switching" to further locate the problem area by eliminating components through the process of elimination and the final step involves outage-based inspection and testing to pinpoint the faulty component. By utilizing this simple step by step methodology, PD can be detected, located, pinpointed and eliminated. Don A. Genutis received his BSEE from Carnegie Mellon University. He was a NETA Certified Technician for 15years and is a Certified Corona Technicians. Don’s technical training and education are complemented by twenty-five years of practical field and laboratory electrical testing experience. Don serves as President on No-Outage on No-Outage Electrical Testing, Inc., a member of the EA technology group.

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VLF-MWT – HOW TO APPLY THE NEW WAY OF CABLE CONDITION ASSESSMENT PowerTest 2013 Martin Jenny, Alexander Gerstner, and Timothy Daniels

INTRODUCTION Operators of medium voltage networks and distribution networks worldwide are facing similar challenges: Existing cable systems must be maintained most economically and investments in new lines must be secured while maintaining or improving the quality of the network. Many operators today use diagnostic procedures to resolve the conflicts in these objectives in the best manner from technical and economic perspectives. Simple cable testing is a common method described in various IEC, IEEE, CENELEC and other national standards. Various test levels and times are used which depend on the voltage type (Direct Current DC, Very Low Frequency VLF, 50/60Hz). Faulty locations are forced to breakdown by application of a test voltage higher than nominal voltage (x*Uo). The wide acceptance of this method and the years of testing experience have also shown its limitations. The simple “passed” or “failed” statement allows no estimation about the remaining lifetime of the cable. This circumstance has led to a broader acceptance of cable diagnostics, which provides information on the cable's condition. As [1] indicates, VLF testing, tan-delta measurement and partial discharge measurement have become established methods for this.

VLF CABLE TESTING – A FIELD PROVEN METHOD VLF (Very Low Frequency) was introduced to test the insulation of Medium Voltage (MV) underground cables after new installations, after repairs or as a routine measure at regular intervals. It became important when it was recognized, that testing of PE/ XLPE-insulated cables with DC voltages is ineffective in detecting hidden defects in XLPE insulations. It was found, that DC testing could induce trapped space charges in the polymeric material. After successfully passing the DC voltage test, these cables would breakdown shortly after being re-energized. This behavioural pattern was observed for medium voltage cables failures. [4] The reasons for voltage testing are according to [5]: ●● Detection of weak points which put reliable operation at risk using low test voltage levels ●● Conversion or evolution of conductive inhomogeneous defects (water treeing) at low test levels into first partial discharge channels (electrical treeing) ●● Bringing partial-discharge defects rapidly to breakdown by means of high channel growth speeds

Evaluation of single measurement results and the combination of tan-delta and partial discharge (PD) measurement provides the operator with important information about the condition of a particular cable. Although cable diagnostics provides more relevant information for decision-making than a simple cable test, it cannot reveal how the cable would respond to the application of an increased test voltage over a longer period (15 minutes to an hour). Section 3 shows a practical example of how this can lead to misinterpretations in specific cases. Up to now, cable testing has lacked the ability to adapt the test duration to the condition of the cable and thus reduce overstress by the increased test voltage and save time and money. To avoid the disadvantages of these individual methods, the National Electric Energy Test, Research and Applications Centre (NEETRAC) developed the VLF Monitored Withstand Test (MWT). A combination of VLF cable testing and diagnostics enables the measurement limitations described to be compensated in the best manner and significant additional value to be generated through additional information with a flexible test period.

Fig. 1: Development of electrical tree out of a water tree By comparing different voltage sources (VLF Sinus, VLF Cos-Rect, 50/60Hz AC, Oscillating Voltage) it was found, that especially the VLF Sinus voltage is suitable for testing medium voltage- and especially PE/XLPE cables. The combination of a low PD incipient voltage, high channel growth speed and the

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capability to perform diagnostics must be considered [5]. These are the preconditions, to convert inhomogeneous defects and to bring partial-discharge defects rapidly to breakdown.

The tan-δ is ratio between the resistor current and the capacitor current. If the resistor current is 0 due to a perfect insulation material, the tan δ also becomes 0.

A typical VLF withstand test is performed with voltages between 2 and 3*Uo for the maximum time of one hour. Due to the representation in different standards (IEC60060-3 (horizontal standard), CENELEC HD620/HD621, IEEE 400.2) and the easy application on site, VLF cable testing became a widely adopted method worldwide.

It is also possible to measure different tan-delta values at different voltage stages (e.g. 0.5, 1.0, 1.5 and 2.0*Uo)

But voltage withstand testing has its limitations. The simple result (Pass/Fail) only offers the statement that the cable was ready for operation or damaged at the time of testing. But it provides no estimate of how long the cable can remain in operation nor when the next check should be performed. That’s the reason, why diagnostic methods like tan-delta- or partial discharge measurement became more popular in the last few years.

VLF TAN-DELTA DIAGNOSTICS – MORE VALUABLE INFORMATION The tan-delta measurement is an important extension to the simple withstand test, because more information about the cable condition is available. This can be used, to optimize the maintenance strategy of a utility.

●● MTD: Mean tan-delta: Average or mean value of tan-delta values at constant test voltage ●● ΔTD: Delta tan-delta: Change in tan-delta with changing test voltage ●● SDTD: Stability or standard deviation of tan-delta values at constant test voltage The measurement of these values allows an interpretation of different types. A high MTD value is an indicator of the presence of water trees. If the ΔTD is high (increasing TD over test voltage), this could be an indicator for partial discharges or also for water trees. A negative ΔTD (decreasing TD over test voltage) could be an indicator for a vaporisation effect, e.g. in terminations. And the SDTD (stability at a voltage level) is another helpful indicator. A low SDTD indicates that the cable is in a good condition. An increasing SDTD indicates the presence of partial discharges. High SDTD values are an indicator for water ingress in joints.

The tan-delta method is an integral measurement which can be adopted for all cable types and gives a statement about the condition of the whole cable line. Although there is no location information available, the interpretation of various tan-delta parameters allows differentiating between different types of defects of the cable line. These measurements allow the system operator to define followup measurements like partial discharge- or cable sheath testing. With the combination of these methods it is possible, to interpret and locate different types of defects.

THE MONITORED WITHSTAND TEST (MWT) – AN INGENIOUS COMBINATION

For modelling, the cable insulation system is simply represented by a capacitor (representing the cable with a perfect insulation material) and a resistor (representing the defective insulation).

●● No estimate can be made of how well the cable test was passed nor whether the cable will fail in an hour or in ten years.

Before describing the MWT, let us examine the disadvantages of simple cable testing once again. As [2] explains, there are essentially three disadvantages: ●● No estimate of the cable line's quality can be made before the test voltage is applied. ●● The duration cannot be adapted to the condition of the cable.

Combining VLF cable testing and VLF tan-delta diagnostics can avoid these limitations. It makes sense, to perform the MWT in two stages: ●● a “ramp-up”- and ●● a "MWT"-or "hold" stage

Ramp-up stage Fig. 2: Equivalent Cable Circuit When a voltage is applied to the cable, the total current is the sum of the capacitive- (Ic) and resistive current (IR) through the cable. (Figure 2) The measured angle δ increases with decreasing value of R, which represents the imperfections of an insulation material.

Non-destructive tan-delta measurement as described before is performed prior to the actual MWT stage. Continuous monitoring of the measurement values (mean tan-delta, tan-delta stability, delta tan-delta) enables an initial estimation of the cable's condition to be made. As Figure 3 shows, tan-delta measurements are performed typically at 0.5xUo, 1.0xUo and 1.5xUo.

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Fig. 3: Sequence of the ramp-up stage Various tan-delta indicators are determined and evaluated at each stage:

RAMP-UP STAGE INDICATOR

CALCULATION

tan δ stability (SDTD)

Standard deviation of 6-10 measurements at Uo

delta tan δ (ΔTD)

Difference of the average values at 1.5 Uo and 0.5 Uo

mean tan δ (MTD)

Average value of 6-10 measurements at Uo

Table 1: Indicators during the ramp-up state The advantages of the ramp-up stage are apparent: ●● An initial assessment of the cable line's condition is enabled. ●● Excessive stress from high test voltages on aged cable lines can be avoided by an initial condition evaluation. ●● Tan-delta measurement is an established, commonly used method. Application experience and limit values are available.

INDICATOR

CALCULATION

tan δ stability (SDTD)

Standard deviation of 6-10 measurements at Uo

mean tan δ (MTD)

Average value of 6-10 measurements at Uo

Change in tan δ vs. time (tΔTD)

The difference in the tan δ value from 0 to 10 minutes.

Table 2: Indicators during the MWT stage Continuous evaluation of the measurement data from the rampup and MWT stages enables the optimum test duration for the cable line to be determined during testing. The user can adapt the time to the cable's condition based on the measurement results or the test system can suggest optimal test duration. In addition to the time saved, shorter tests have the advantage of exposing the cable to the higher test voltage only for the time actually necessary. But the user can also extend the test to cause existing weak points in the insulation to break down. The benefits of the MWT stage can be summarized as follows: ●● The condition of the cable line can be evaluated. ●● The test duration can be adjusted to the cable's condition ●● The influence of the higher test voltage on the cable can be assessed. ●● MWT is a useful combination of established, accepted methods.

CASE STUDY

MWT or Hold Stage

Here is a practical example of why monitored withstand testing represents an important advance of previous testing and Cable testing and diagnostics are combined in the MWT stage. diagnostic measurements. According to [2], the MWT is only passed if: The cable tested (11 kV) has a total length of 234 metres and ●● No breakdown occurred during the MWT. is composed of various cable types (in other words, a mixed ●● The tan-delta values determined prove to be stable cable line). (i.e. have a low standard deviation). ●● The average tan-delta value is low.

Fig. 5: Structure of the cable line tested prior to the first repair in June 2010 In June 2010, there was a cable fault in an XLPE-insulated cable line produced in 1989 (first generation). Cables produced during Fig. 4: Sequence of the MWT Stage this period are known to develop water trees. An 11 metre section Figure 4 shows the sequence of the MWT stage. Various tan- of this line was replaced by an XLPE cable of a newer type. delta measurement values are also determined and evaluated during application of the voltage. (See Table 2.)

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Fig. 6: Structure of the cable line tested after the first repair in June 2010 Diagnostic measurements (VLF tan-delta and partial discharge measurement) were performed after the repair. The tan-delta results showed that the cable line was heavily aged by service. (See Figure 7). Although the measurement values were below the TD limits for mixed cable lines, for the section of line at risk for water trees, the delta tan-delta (DTD) limit for XLPE cable was applied (DTD > 1.0E-3 as high operating risk). Here L2 and L3 showed a strong rise with increasing voltage, indicating water

The PD measurement data show partial discharges at the transition joints (on the PILC cable line) at 199 and 224 metres. Evaluation of the partial discharge and tan-delta measurement revealed that the high tan-delta values were caused by water trees. This is indicated by higher TD standard deviations for L2 and L3 at voltages below 1.0xUo and the increasing trend of tan-delta without partial discharge. Moreover, the partial discharge level is of an order of magnitude which does not affect the delta tan-delta. Afterwards, a 15 minute VLF cable test was performed at 2xUo. The result was that all three conductors passed the test despite the high tan-delta values. So the cable was put back into operation. Four days later there was a cable fault at 125 metres, i.e. in the section endangered by water trees. Severe water tree damage was found in this part of the line (Figure 10).

tree damage to the cable.

Fig. 10: Cable line severely damaged by water trees This example shows quite clearly how a VLF Monitored Withstand Test would have been helpful at this location to avoid the cable fault shortly after restoration of service. Fig. 7: Tan-delta measurement after repair

The TD standard deviations (SDTD) for L1, L2 and L3 were also used to assess the situation (Figure 8).

●● The 15 minute VLF test made the water trees more severe, but at the end of the test the progress could not be determined. Here a VLF sinusoidal MWT would have indicated by the progression of the mean tan-delta (rising TD values) and tan-delta standard deviation that the faults had been exacerbated. ●● The test duration could have been extended during the measurement (to 30 minutes, for example). The weak points (water trees in this case) would have grown worse and finally led to breakdown.

Fig. 8: SDTD – tan-delta standard deviation for conductors L1-L3 In Figure 8 it can be seen that the SDTDs for L2 and L3 increase. This indicates the presence of water trees. Partial discharge measurement was carried out afterwards (Figure 9).

●● Thus the MWT could have shown the influence of the test voltage on the cable. ●● It would have been possible to estimate the "margin" of passing from the condition of the cable at the end of the MWT. ●● Tan-delta measurement and cable testing as described in the example would have been possible in a single automated run.

APPLICATION

Fig. 9: PD measurement result

It is important for the application of the VLF MWT, that the measurement is simple and automated. This requires a VLF sine voltage, because this voltage shape allows a precise and combined tan-delta measurement. Additionally it is possible to perform the tan-delta measurement at a constant frequency, where limits are available and where a comparison of different measurement results

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Maintenance Vol. 1 is possible. This fact allows the electric utility system operator to gain the experience with cable diagnostics. As seen from Section V, it is useful to split the MWT into two stages: Ramp-up and MWT (or hold). For an easy application in the field it is necessary to automate the whole measurement sequence. An example of how these requirements can be implemented is the portable VLF truesinus® generator with an integrated tan-delta measurement like frida TD from BAUR (Figure 11). Fig. 13: Application example: Collection and consideration of unwanted surface currents

CONCLUSION AND OUTLOOK The Monitored Withstand Test (MWT) is being promoted in North America and has already found a place in various standards.

Fig. 11: MWT application with the BAUR frida TD Here an integrated tan-delta measurement function enables the same connection to be used for cable testing and tan-delta diagnostics. This facilitates fully automated measurement runs without additional external devices. It is also important for the various measurement results to be displayed clearly and continuously so the user can make decisions (for example, regarding the length of the MWT) during measurement. An example can be seen in the screenshot in Figure 12. The evaluation of results is also displayed continuously (with smileys) along with the details of individual measurement results.

The latest revision of IEEE400-2012 [3] (the IEEE Guide for Field Test and Evaluation of the Insulation of Shielded Power Cable System Rated 5kV and above) defines and describes the Monitored Withstand Test. The IEEE400.2-2004 standard (IEEE Guide for Field Testing of Shielded Power Cable Systems Using Very Low Frequency (VLF)) is also currently undergoing revision, and MWT will play a role in it as well. A key factor for evaluating the condition of various cable types is comparison with defined limit values (see the examples in Section VI as well). Limits for various types of cable are shown in [2]. These were developed recently for the North American region and will probably be included in the latest version of IEEE400.2. The prerequisites for using the tan-delta MWT have been met. The first versions of the standards and the necessary measurement technology are available. Now it is a matter of using tan-delta MWT in the field and applying the experience from this in future discussions of limit values, also for various regions.

REFERENCES

Fig. 12: Screen display during MWT measurement (BAUR frida TD) frida TD also allows to consider surface currents in open terminations (subject to pollution, humidity and mechanical damage) during the tan-delta measurement. These unwanted surface currents can heavily influence the tan-delta result, especially for XLPE cables.

1

 iagnostic Testing of Underground Cable Systems (Cable DiD agnostic Focused Initiative, CDFI), December 2010

2

 letcher, Hampton, Hernandez, Hesse, Pearman, Perkel, Wall, F Zenger: First practical utility implementations of monitored withstand diagnostics in the USA, Jicable 11, A.10.2

3

IEEE400-2012 IEEE Guide for Field Testing and Evaluation of the Insulation of Shielded Power Cable Systems Rated 5kV and Above

4

 .C. Moh: Very Low Frequency Testing – it´s effectiveness in S detecting hidden defects in cables. CIRED 17th international Conference on Electricity Distribution, Barcelona 2003

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Maintenance Vol. 1  ach: Testing and Diagnostic Techniques for assessing mediB um-voltage service aged cables and new cable techniques for avoiding cable faults in the future.

Martin Jenny was born in Austria in 1972 and is Product Manager for Cable Testing & Diagnostics.Martin is leading the product management for BAUR’s cable testing and diagnostics product portfolio since more than four years. BAUR’s portable VLF testers were one of the innovations that Martin drove forward in the last years. He has more than ten years of experience in testing and measurement in different industries. Alexander Gerstner was born in Germany in 1969 and is the Head of Global Marketing and Product Managementat Baur in Austria. Alexander is an Electrical Engineer with more than 16 years of experience in Product Management and Product Development for technology products in global markets. For more than four years he is responsible for BAUR’s innovation initiatives, Product Management and global customer communication. His special focus is on customer value focused solution design, User Experience, Communication and Information Technology. Timothy “Tad” Daniels is currently the HV Sales and Marketing Manager for HV TECHNOLOGIES Inc. in Manassas, VA. Tad has worked in the Electric Utility Industry since 1984 with McGraw Edison, Cooper Power Systems, SPX Transformer Solutions formerly Waukesha Electric, and Weidmann Electrical Technology. Tad holds a BSEE from Tulane University. He is a member of the IEEE and is active in ICC IEEE PES and IEEE Transformers Committee Standards Groups.

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DETECTING COMMON POWER QUALITY ISSUES PowerTest 2013 Andrew Sagl

VOLTAGE SAGS AND SWELLS Voltage sags and swells are two of the most common power quality events. Voltage Sags and Swells cannot be prevented on the power system. As impedances change during the course of a day the voltage will momentarily change as well. The goal of power quality is to limit the number of sags and swells as well as the magnitude of these events such that they do not cause equipment malfunction or failure. The malfunction or failure of this equipment can cause large financial losses to various manufacturers. This paper will define the various types of Voltage Sags and Swells that occur and the effect they have on various types of equipment. Voltage Sags and Swells are defined in different manners based on their individual characteristics.

Voltage Swells are typically due to large loads turning off. This causes a sudden change in load impedance which can cause the voltage to swell. These loads can include such things as large motors, arc furnaces and large welders. In addition switching of capacitor banks and network sections can also cause voltage sags and swells. In addition intermittent loose connections can also cause voltage sags and swells. There are also events that are referred to as Long Duration Variations; these are voltage sags and swells that last for more than 1 minute. Voltage variation disturbances can cause equipment to malfunction such as computers locking up or data getting garbled. Process equipment can trip off line and breakers can trip. Commercial electronics can trip off line, clocks can get reset and electric arc lighting can trip off. These are just some examples of some of the problems that can be caused by voltage variations. There are many types of Power Quality Analyzers that will allow operators to program various limits and perform high resolution recordings to capture these types of voltage variations. The challenge is how do we determine if the recorded voltage variation is causing the condition that the customer is reporting and how do we locate the root cause?

Instantaneous Sag is a short duration voltage variation that will last from 0.5 cycles to 30 cycles. The voltage during an instantaneous sag will vary from 10% to 90% of nominal. An interruption is a short duration voltage variation that will last from 0.5 cycles to 3 seconds. The voltage during an interruption will fall to less than 10% of nominal. Momentary Sag is a short duration voltage variation that will last from 30 cycles to 3 seconds. The voltage during a momentary sag will vary from 10% to 90% of nominal. A temporary interruption Instantaneous Sag is a short duration voltage variation that will last from 3 seconds to 1 minute. The voltage during will fall to less than 10% of nominal. Short duration voltage variations are typically caused by large loads that draw high inrush current. These high inrush currents will cause the voltage to sag.

One of the tools available to help determine if a measured voltage variation is causing equipment to malfunction is the ITIC (CBEMA) Curve. This curve was published by the Information Technology Industry Council (formerly known as the Computer & Business Equipment Manufacturer's Association). The ITIC (CBEMA) Curve describes an acceptable AC voltage window that can be tolerated by most Information Technology Equipment (ITE).

50 The ITIC (CBEMA) curve describes several ranges for voltage variation events. The voltage variation can be plotted on the graph as a point. The magnitude of the event as referenced to the nominal voltage is the X coordinate and the duration of the event in either cycles or seconds is the Y coordinate. Once the point is plotted it is easy to see if the event could be the cause of information technology equipment malfunction. (Computers, Faxes, routers, modems, internet, televisions...etc.)

Maintenance Vol. 1 sag. In the case of voltage swells this would mean the current is sagging. (Opposite the voltage which is swelling) This means that there has been an increase in load impedance such as a large load turning off that is causing the voltage to swell.

Another type of curve is the SEMI F47 curve. This curve was developed by the industry association for the semiconductor industry known as Semiconductor Equipment and Materials International (SEMI). This curve was developed to place standards on semiconductor processing, metrology, and automated test equipment. The SEMI F47 curve defines a region of acceptable voltage variations on the AC power line of semiconductor processing equipment. The equipment should be able to tolerate voltage variations within this region. They must be able to tolerate sags to 50% of equipment nominal voltage for durations of up to 200 ms as well as sags of 70% for up to 0.5 seconds, and sags of up to 80% for up to 1.0 second.

If the current is in the same direction as the voltage, then the event is coming from the source side. In the case of a voltage sag this would mean the current is sagging. (The same as the voltage which is sagging) This means that there has been a reduction in the voltage on the source side and the reduced difference of potential across the load has reduced the current. In the case of a voltage swell this would mean the current is swelling. (The same as the voltage which is swelling) This means that there has been an increase in voltage on the source side and the increased difference of potential across the load has increased the current.

These types of curves can be a great asset in helping determine if a measured voltage variation is causing equipment to malfunction. When reviewing recorded events it is also important to try to determine the direction the fault is coming from. The fault can either be coming from the load side or the source side. In order to determine this it is required to analyze the voltage magnitudes during the fault as well as the current magnitude that occurred during the fault. A good rule of thumb to follow when trying to determine the source of a voltage sag or swell examine the minimum voltage recorded during the event against the maximum current recorded during the event. If the current is in the opposite direction from the voltage then generally the event is coming from the load side. In the case of voltage sags, this would mean the current is swelling. (Opposite the voltage which is sagging) This means that there is a reduction in load impedance such as a large load turning on that is drawing an inrush current that is causing the voltage to

When problems are found that cause equipment malfunction or equipment failure there are several simple possibilities that should be examined before resorting to expensive conditioning equipment. A common cause of voltage sags and swells is loose or poor connections. Before investing in conditioning equipment it is wise to check for loose or poor connections. Poor connections will have higher impedance, so they will have a larger voltage drop across them. A larger voltage drop across these connections will generate more heat. A quick way to search for poor connections is to look for this heat using an infra-red camera. A common cause of equipment tripping off line is an incorrect nominal voltage being applied to that equipment. These incorrect voltages can include 230 volt equipment being fed from 208 volts or vice versa as well as 460 volt equipment being fed from 480 volts.

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Since incorrect nominal voltages are applied to the equipment, relatively small voltage variations could cause controllers to trip the equipment off line.

extremely fast transients they are rapidly damped out by just a few meters of distribution wiring. Standard line filters, included on almost all electronic equipment, filter EFT's.

Note: Some 460 volt equipment have over-voltage, undervoltage and phase loss relays. When 460 volt equipment gets to 10% or about 506 volts it causes an over-voltage trip or alarm. A utility voltage can be at the upper limit of 504 volts and when a utility cap comes on the voltage may go to 508 for less than a cycle and cause an over-voltage trip.

Transients can be responsible for various component failures. These components can include fuses, surge protectors, automatic transfer switches, cables, switchgear, CT’s or PT’s etc. Transient voltages caused by lightning or switching operations can result in degradation or immediate dielectric failure in all classes of equipment. High magnitude and fast rise time contribute to insulation breakdown in electrical equipment. Repeated lower magnitude transients can cause slow degradation and eventual insulation failure, decreasing equipment mean time between failures.

In addition the grounding methodology used can affect the performance of sensitive equipment.

TRANSIENTS A transient is defined per IEEE 1159 as a phenomenon or a quantity which varies between two consecutive steady states during a time interval that is short compared to the time scale of interest. A transient can be a unidirectional impulse of either polarity or a damped oscillatory wave with the first peak occurring in either polarity. Transients are responsible for many power quality related malfunctions and failures. Transients can cause component to fail such as fuses, surge protectors, automatic transfer switches, cable switch gear, CT’s and PT’s. Transient voltages can result in degradation or immediate dielectric failure in all classes of equipment. High magnitude and fast rise time contribute to insulation breakdown in electrical equipment like switchgear, transformers and motors. Repeated lower magnitude application of transients to equipment can cause slow degradation and eventual insulation failure, decreasing equipment mean time between failures. Transients can cause back up UPS systems to turn on and off excessively. This can reduce the life span of a UPS system. Generally there are two different types of transient over-voltages: low-frequency transients and high-frequency transients. Low Frequency transients have frequency components in the few-hundred-hertz region and are typically caused by capacitor switching.

High-frequency transients have frequency components in the few-hundred-kilohertz region and are typically caused by lightning and inductive loads There is also the phenomenon known as extremely fast transients, or EFT's. Extremely fast transients have rise and fall times in the nanosecond region. They can be caused by arcing faults, such as bad brushes in motors. Due to the rapid rise and fall times of

Transients can damage insulation because insulation, like that in wires has capacitive properties.

Both capacitors and wires have two conductors separated by an insulator. If a transient pulse with a high enough frequency reaches a component, the capacitance of that conductor - insulation junction will present a path. If the transient pulse has enough energy it could damage that section of insulation. Transients can cause the insulation to break down in motors and transformers.

When a transient reaches the coil of a motor or a transformer it will dissipate the majority of its energy in the first few coils. Each successive coil presents more resistance and capacitance to the transient. This will reduce its magnitude and increase its period, reducing the energy. Since the majority of the energy is transferred to the first few coils, this is where the damaged insulation will typically appear.

52 In motors, fast-changing PWM voltage pulses can interact with the distributed inductance and capacitance of motor leads. This can result in an amplified peak voltage at the motor terminals. This peak voltage further stresses and degrades the insulation around the stator winding of the motor. The peak voltage magnitude at the motor terminals depends on the motor lead characteristics and the surge impedance of the motor; the smaller the motor and longer the leads, the greater the peak voltage. This is for this reason that it is recommended to avoid long motor leads.

Transient voltages can cause computer equipment to lockup and data to get garbled or even damage computer equipment. When a transient strikes your computer, it can cause internal noise spikes that can disrupt data. If the transient has sufficient energy, it can cause an arc within the internal components of the computer.

Transients can also affect fluorescent lighting. A fluorescent light illuminates because the gas inside of the light is ionized when voltage is applied across the electrodes. Transients can produce excessive energy that can displace the material within the electrodes. This will eventually reduce the amount of light given off by the fluorescent light and reduce the efficiency of the light. The reduced efficiency will reduce the life of the fluorescent light. Some of the common causes of transients include lightning, load switching, capacitor switching as well as loose wiring.

Maintenance Vol. 1 Lightning is the leading cause of power-line disruptions and outages. If facilities are not properly equipped, lightning can cause millions of dollars in damage and downtime of critical equipment. A bolt of lightning can be over 5 miles long, and reach temperatures in excess of 20,000 degrees Celsius. The currentcarrying capability of a lightning bolt can be upwards of 90,000A. Lightning can affect distribution equipment causing the equipment to burn out, catch on fire, or even explode. Direct lightning strikes or high electromagnetic fields produced by lighting can induce voltage and current transients in electric power lines and signal carrying lines. These will typically be seen as unidirectional transients, either positive or negative. When an inductive load is turned on or off a transient is produced. Transformers can also produce large transients when energizing. The transient is produced as a result of the collapse of the magnetic field of the coil.

Capacitor banks are switched in and out on circuits to compensate for reactive power caused by inductive loads. When the capacitor bank is switched into the circuit there is an initial inrush of current. The added capacitance causes a phase shift. This will cause a lowfrequency transient that will have a characteristic ringing. These types of transients are referred to as oscillatory transients. These types of transients can cause sensitive equipment to trip out and cause UPS backup systems to turn on and off multiple times. This can reduce the life of UPS systems. Since capacitor banks are used to compensate for reactive power caused by large inductive loads, they are switched on and off frequently. This makes oscillatory transients a very common power quality phenomenon. Transients are one of the leading causes of equipment malfunctions and failures. Understanding the cause of transients and how they affect various types of equipment will allow companies to improve quality and reliability of their equipment. Monitoring of incoming power, using Power Quality recording devices, can help identify potential power quality problems before they cause costly malfunctions.

UNBALANCE Unbalance refers to the asymmetrical components of a polyphase network. An ideal 3 phase system will have perfectly symmetrical components as shown below. All phases would have the same magnitude with proper phasing.

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sequence and the ratio of the zero sequence to the positive sequence. The benefit of this method is it takes into account both the magnitude and the phase shift of the poly-phase system. Typical limits on voltage unbalance range from 1% to 3% pending the application. Some standards to reference include EN50160 as well as IEC61000-2-4 and IEEE1159.

HARMONICS

Unbalanced phases will have asymmetrical qualities such as variations in magnitude or deviations in phasing. Voltage unbalance can cause heating in transformers. In general, utility supply voltage is maintained at a relatively low level of phase imbalance since even a low level of imbalance can cause heating effects on the generation, transmission, and distribution system equipment.

Harmonics are another power quality phenomenon that can cause equipment to malfunction. Harmonics are a sinusoidal component of periodic waves that have frequencies that are multiples of the fundamental frequency. Harmonics can cause computer equipment to lock up or cause the data to become garbled as well as causing transformers, motors and neutral lines to overheat. Linear Loads such as incandescent lights draw current equally throughout the waveform. Non-Linear loads such as switching power supplies draw current only at the peaks of the wave. It is these non-linear loads that cause harmonics.

Voltage unbalance more commonly emerges in individual customer loads due to phase load imbalances, especially where large, single phase power loads are used, such as single phase arc furnaces. In these cases, overheating of customer motors and transformers can readily occur if the imbalance is not corrected. There are generally three ways in which unbalance is measured, the NEMA method, the IEEE method and the IEC method. The NEMA method calculates the average of the line voltages then compares each individual line voltage to the average. This method assumed that the average voltage is equal to the rated value. In addition it does not take into account phasing.

If your fundamental frequency is 60Hz then the second harmonic would be 60Hz x 2 = 120Hz. The third harmonic would be 60Hz x 3 = 180Hz, and so on. Typically current harmonics will not propagate through a system. Voltage harmonics will propagate through a system, as they can pass through transformers. When non-linear loads get high enough they will cause harmonics in the voltage.

The IEEE method calculates the average of the phase voltages then compares each individual phase voltage to the average.

The IEC method of unbalance transposes the waveforms into 3 sets of symmetrical components based on phase rotation. These symmetrical components are the positive sequence rotation, negative sequence rotation and the zero sequence. The unbalance is then defined as the ratio of the negative sequence to the positive

Harmonics orders are characterized in different sequences, based on the rotation of their magnetic field. Positive sequence harmonics creates a magnetic field in the direction of rotation. NOTE: The fundamental is considered a positive sequence harmonic. Negative sequence harmonics develop magnetic fields in the opposite direction of rotation. This reduces torque and increases the current required for motor loads.

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Zero sequence harmonics creates a single-phase signal that does not produce a rotating magnetic field of any kind. These harmonics can increase overall current demand and generate heat. In three phase systems, the fundamental currents at any instant will always add up to zero in the neutral. The presence of zero sequence harmonics, such as the third harmonic on one phase will be in phase with the other phases of the 3 phase system.

Since they are in phase, rather than canceling each other (as is the case with the fundamental), they will sum together and can lead to high neutral currents. To determine the sequence of different harmonic order is relatively simple. Positive, Negative and Zero sequence harmonics repeat in a sequential order. (Positive, Negative then Zero) Since the fundamental frequency is positive this means the second order harmonic is a negative sequence harmonic. The third harmonic is a zero sequence harmonic. Below is a table of harmonics.

Although, Total Harmonic Distortion (THD) can be calculated for both current and voltage it can be misleading when analyzing current harmonics. This is because THD is referenced to the amplitude of the fundamental value. This does not typically cause any issues when analyzing voltage THD since the fundamental is always present in non-fault conditions. However, the same is not true for current. The current amplitude will fluctuate with the loads impedance. As loads turn off the fundamental current amplitude decreases. If the Current draw is very low (near zero) the THD value could appear to be quite high. This is deceiving because the current THD levels can be high while there is little to no current draw. Therefore, it is recommended that the Total Demand Distortion (TDD) measurement should be used for total current harmonic measurements. The Total Demand Distortion (TDD) references the total root-sum-square harmonic current distortion, to the percent of the maximum demand load current. (This is based on either a 15 or 30 min demand interval per IEEE 519). Therefore the reference value is the same throughout the test interval and it is a valid value. The power quality industry has developed certain index values to assess the distortion caused by the presence of harmonics. The two values most frequently indexed are total harmonic distortion (THD) and total demand distortion (TDD), although individual harmonic values are also indexed in different specifications, such as IEEE 519 and EN50160.

Problems associated with harmonics. Neutral Wires Overheating: Neutral Wires will over heat in 3 phase systems generally when the 3 phase system is unbalanced or there is an excess of Harmonic Triplens. (Harmonics divisible by 3 / Zero Sequence Harmonics) Zero sequence harmonics do not cancel out, instead they add together on the neutral. This can cause neutral currents that exceed the line current. This is commonly seen in single phase systems that are dedicated to electronic loads.

Zero Sequence harmonics will also be referred to as triplens at times. This is because zero sequence harmonics are always multiples of 3. One measure of harmonics is called THD, or Total Harmonic Distortion. THD is a measure of the harmonic components of a distorted waveform. THD can be calculated for either current or voltage. Total harmonic distortion is the RMS sum of the harmonics, divided by one of two values: either the fundamental value, or the RMS value of the total waveform. This is typically represented as a percentage of the fundamental.

Motor Overheating: Excessive voltage harmonics can cause motors to overheat. The rotation of the rotor depends on the torque produced by the phase sequence of the applied 3-phase power. Positive-sequence frequencies work to push the rotor in the proper direction. Negative-sequence frequencies oppose the direction of the rotor's rotation. Excessive of negative-sequence harmonics on a three-phase AC motor will result in a decreased performance and potential overheating. Higher-order harmonics tend to be attenuated more by system inductances and magnetic core losses; the primary harmonic of concern is the 5th, which is 300 Hz in 60 Hz power systems and 250 Hz in 50 Hz power systems. Zerosequence harmonics do not have a major effect on the rotor's torque; however they can cause increased current on neutral lines.

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Maintenance Vol. 1 Transformer De-rating: Waveform distortion can also cause heating in transformers. Harmonic current injection from customer loads into the utility supply system can cause harmonic voltage distortion to appear on the utility system supply voltage. The heating effect of harmonics is proportional to the square of the current and the square of the harmonic. In other words, an amp of 13th harmonic current creates far more heat than an amp of 5th harmonic current.

INTER-HARMONICS Inter-harmonics are defined as non-integer multiples of the fundamental frequency. The order of the inter-harmonic is defined as the ratio of the inter-harmonic frequency to the fundamental frequency. For example is the inter-harmonic frequency is 100Hz on a 60Hz system then the order of the inter-harmonic is 90 / 60 o r 1.5. If the inter-harmonic frequency is below the fundamental frequency then this may also be referred to as a sub-harmonic. Sources of inter-harmonics can include arcing loads, such as arc furnaces and welding machine, variable drives, static converters and power line signaling. Rapid changes in voltage or phase angle can generate inter-harmonics. These can changes can be highly depended on rapid load changes which can make inter-harmonics random in nature. Renewable energy sources can also cause rapid voltage changes that can generate inter-harmonics. This is because of their inconsistent output due to the random changes in the conditions that drive them. Some of the problems that can be caused by inter-harmonics include incandescent lamp flicker, low frequency oscillations in mechanical systems, fluctuations in the output of fluorescent lamps, interference with control and protection signals in power supply lines, telecommunication interference as well as thermal effects in equipment

grid line voltage. The same is true of wind energy. Wind energy output will vary with the amount of wind present. The intermittent nature of these energy sources can cause rapid voltage changes on the grid. Besides the power quality implications, renewable are causing some energy costing issues. The use of privately owned photovoltaic cells is causing a costing issue. They are connected to the grid so they use the grid almost as a battery. When they are producing electricity they supply voltage to the grid but when they are not producing power they pull power from the grid. This can lead to the charge to the customer being near $0. However they are still utilizing the grid 24 hours. Per European standards, low voltage systems rapid voltage changes generally do not typically exceed 5 % of nominal, however short duration changes of up to 10 % may occur sometimes.

FLICKER Flicker is a very specific problem concerning the human perception of the light variation emitted from incandescent light bulbs. It is not a general term for voltage variations. Humans can be very sensitive to light flicker that is caused by voltage fluctuations. Studies have found that voltage fluctuations in the frequency range 5-15 Hz is visible to the human eye. The peak sensitivity occurs at approximately 8 Hz. A light flicker modulation of just 0.25% at 8Hz can be noticeable. Modulations around 1% can be irritating. Human perception of light flicker is almost always the limiting criteria for controlling small voltage fluctuations. The figure below illustrates the level of perception of light flicker from a 60 watt incandescent bulb for rectangular variations. The sensitivity is a function of the frequency of the fluctuations and it is also dependent on the voltage level of the lighting.

RAPID VOLTAGE CHANGE (RVC) A rapid voltage change is a quick transition in RMS voltage between two steady-state conditions. The voltage during a rapid voltage change must not exceed the voltage sag or swell threshold. If it does then it would be considered as a voltage sag or swell. The characteristic parameter of the rapid voltage change is the difference between the steady- state value reached after the change and the initial steady-state value. Any load that has significant cyclic variations can cause voltage fluctuations. Arc furnaces are the most common cause of voltage fluctuations on the transmission and distribution system. Other causes of rapid voltage change include inconsistent renewable energy sources, such as solar energy and wind energy. With the expansion of photo-voltaic cells on roof tops voltage regulation becomes a greater problem. The intermittent output nature of the photo-voltaic cells will cause an intermittent rise and fall in the

In general today, flicker is measured using the IEC 61000-415 method. In this method we take the instantaneous voltage and compare it to a rolling average voltage. The deviation between these two is multiplied by a weighted curve. This curve is based on the sensitivity of the human eye at 120V 60Hz or 230V 50Hz. The end value is called a percentile unit. The percentile units go through a statistical analysis in order to calculate 2 values.

56 Short Term flicker or Pst; based on a 10 minute interval. Long Term flicker or Plt; based on a 2 hour interval. The basic criteria are simple. If the Pst is less than 1.0 then flicker levels are good. If Pst is greater than 1.0 then the flicker levels could be causing irritation. A couple of important things to remember about Flicker are it applies to incandescent lighting ONLY. Fluorescent lighting cannot be tested in this manner in this manner until weighted curves are developed for them. Since it uses a weighting curve it applies only to 120V 60Hz and 230V 50Hz.Voltages outside this range must be normalized to 120V at 60Hz or 230V 50Hz in order to analyze flicker based on the IEC61000-4-15 method. Common Causes of Flicker can include Source voltage variations, Inrush/surge currents as well as inadequate wiring and inter-harmonics. In general power quality plays an ever increasing role in today’s modern society. As technology advances maintaining a good power quality will become even more important. New renewable energy sources such as solar and wind in addition to new technologies such as EV automobiles present new challenges in maintaining good power quality. Understanding how different power quality events affect different types of equipment is essential in today’s world. Andrew Sagl has worked with Megger for 12 years. He is currently Product Manager, Power Quality and Battery Testing, and a specialist in power quality and battery testing technology and application. Andrew develops and supports power quality equipment, writes power quality and battery publications, and teaches training and seminars courses. He has a degree in Electronics and is a member of the IEEE Power Engineering Society and Battery Standards Group.

Maintenance Vol. 1

NETA Accredited Companies Valid as of Jan. 1, 2019

For NETA Accredited Company list updates visit NetaWorld.org

Ensuring Safety and Reliability Trust in a NETA Accredited Company to provide independent, third-party electrical testing to the highest standard, the ANSI/NETA Standards. NETA has been connecting engineers, architects, facility managers, and users of electrical power equipment and systems with NETA Accredited Companies since1972.

UNITED STATES

6

alabama 1

2

3

4

AMP Quality Energy Services, LLC 352 Turney Ridge Rd Somerville, AL 35670 (256) 513-8255 [email protected] www.ampqes.com Brian Rodgers Premier Power Maintenance Corporation 3066 Finley Island Cir NW Decatur AL 35601-8800 (256) 355-1444 [email protected] www.premierpowermaintenance.com Johnnie McClung

arkansas 5

Premier Power Maintenance Corporation 7301 E County Road 142 Blytheville, AR 72315-6917 (870) 762-2100 [email protected] www.premierpowermaintenance.com Kevin Templeman

7

9

10

Utility Service Corporation PO Box 1471 Huntsville, AL 35807 (256) 837-8400 Fax: (256) 837-8403 [email protected] www.utilserv.com Alan D. Peterson

12

arizona

8

Premier Power Maintenance Corporation 4301 Iverson Blvd Ste H Trinity, AL 35673-6641 (256) 355-3006 [email protected] www.premierpowermaintenance.com Kevin Templeman

Sentinel Power Services, Inc. 1110 West B Street, Ste H Russellville, AR 72801 (918) 359-0350 www.sentinelpowerservices.com

11

ABM Electrical Power Services, LLC 2631 S. Roosevelt St Tempe, AZ 85282 (602) 722-2423 www.abm.com Electric Power Systems, Inc. 1230 N Hobson St., Ste 101 Gilbert, AZ 85233 (480) 633-1490 www.epsii.com Electrical Reliability Services 221 E. Willis Road Chandler, AZ 85286 (480) 966-4568 [email protected] www.electricalreliability.com Hampton Tedder Technical Services 3747 West Roanoke Ave. Phoenix, AZ 85009 (480) 967-7765 Fax:(480) 967-7762 www.hamptontedder.com Linc McNitt Southwest Energy Systems, LLC 2231 East Jones Ave., Suite A Phoenix, AZ 85040 (602) 438-7500 Fax: (602) 438-7501 [email protected] www.southwestenergysystems.com Dave Hoffman

Western Electrical Services, Inc. 5680 South 32nd St. Phoenix, AZ 85040 (602) 426-1667 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Craig Archer

california 13

ABM Electrical Power Services, LLC 720 S. Rochester Ave., Suite A Ontario, CA 91761 (301) 397-3500 [email protected] www.abm.com Rob Parton

14

ABM Electrical Power Services, LLC 6940 Koll Center Pkwy, Ste 100 Pleasanton, CA 94566 (408) 466-6920 www.abm.com

15

ABM Electrical Power Services, LLC 3585 Corporate Court San Diego, CA 92123-1844 (858) 754-7963

16

Accessible Consulting Engineers, Inc. 1269 Pomona Rd, Ste 111 Corona, CA 92882-7158 (951) 808-1040 [email protected] www.acetesting.com Iraj Nasrolahi

17

Apparatus Testing and Engineering 11300 Sanders Dr, Ste 29 Rancho Cordova, CA 95742-6822 (916) 853-6280 [email protected] www.apparatustesting.com Harold (Jerry) Carr

For additional information on NETA visit netaworld.org

18

Apparatus Testing and Engineering 7083 Commerce Cir., Suite H Pleasanton, CA 94588 (916) 853-6280 www.apparatustesting.com

21

Applied Engineering Concepts 894 N Fair Oaks Ave. Pasadena, CA 91103 (626) 389-2108 [email protected] www.aec-us.com Michel Castonguay

22

23

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Applied Engineering Concepts 8160 Miramar Road San Diego, CA 92126 (619) 822-1106 [email protected] www.aec-us.com Michel Castonguay Electric Power Systems, Inc. 7925 Dunbrook Rd., Ste G San Diego, CA 92126 (858) 566-6317 www.epsii.com

24

Electrical Reliability Services 5909 Sea Lion Pl, Ste C Carlsbad, CA 92010-6634 (858) 695-9551 www.electricalreliability.com

25

Electrical Reliability Services 6900 Koll Center Pkwy., Ste 415 Pleasanton, CA 94566 (925) 485-3400 Fax: (925) 485-3436

26

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Electrical Reliability Services 10606 Bloomfield Ave. Santa Fe Springs, CA 90670 (562) 236-9555 Fax: (562) 777-8914 Giga Electrical & Technical Services, Inc. 2743A N. San Fernando Road Los Angeles, CA 90065 (323) 255-5894 [email protected] www.gigaelectrical-ca.com Hermin Machacon Halco Testing Services 5773 Venice Boulevard Los Angeles, CA 90019 [email protected] (323) 933-9431 www.halcotestingservices.com Don Genutis

Hampton Tedder Technical Services 4563 State St Montclair, CA 91763 (909) 628-1256 x214 [email protected] www.hamptontedder.com Chasen Tedder

36

37

30

Industrial Tests, Inc. 4021 Alvis Ct., Suite 1 Rocklin, CA 95677 (916) 296-1200 Fax: (916) 632-0300 [email protected] www.industrialtests.com Greg Poole

31

Pacific Power Testing, Inc. 38 14280 Doolittle Dr. San Leandro, CA 94577 (510) 351-8811 Fax: (510) 351-6655 [email protected] www.pacificpowertesting.com Steve Emmert

32

Power Systems Testing Co. 4688 W. Jennifer Ave., Suite 108 Fresno, CA 93722 (559) 275-2171 x15 Fax: (559) 275-6556 [email protected] www.powersystemstesting.com David Huffman

RESA Power Service 2390 Zanker Road San Jose , CA 95131 (800) 576-7372 [email protected] www.resapower.com Toby Ramsey Tony Demaria Electric, Inc. 131 West F St. Wilmington, CA 90744 (310) 816-3130 Fax: (310) 549-9747 [email protected] www.tdeinc.com Neno Pasic Western Electrical Services, Inc. 5505 Daniels St. Chino, CA 91710 (619) 672-5217 [email protected] www.westernelectricalservices.com Matt Wallace

colorado 39

ABM Electrical Power Services, LLC 9800 E Geddes Ave Unit A-150 Englewood, CO 80112-9306 (303) 524-6560 www.abm.com

33

Power Systems Testing Co. 6736 Preston Ave., Suite E Livermore, CA 94551 (510) 783-5096 Fax: (510) 732-9287 www.powersystemstesting.com

40

Electric Power Systems, Inc. 11211 E. Arapahoe Rd, Ste 108 Centennial, CO 80112 (720) 857-7273 www.epsii.com

34

Power Systems Testing Co. 600 S. Grand Ave., Suite 113 Santa Ana, CA 92705-4152 (714) 542-6089 Fax: (714) 542-0737 www.powersystemstesting.com

41

Electrical Reliability Services 7100 Broadway, Suite 7E Denver, CO 80221-2915 (303) 427-8809 Fax: (303) 427-4080 www.electricalreliability.com

35

RESA Power Service 13837 Bettencourt Street Cerritos, CA 90703 (800) 996-9975 [email protected] www.resapower.com Manny Sanchez

42

Magna IV Engineering 96 Inverness Dr. East, Suite R Englewood, CO 80112 (303) 799-1273 Fax: (303) 790-4816 [email protected] Aric Proskurniak

43

Precision Testing Group 5475 Hwy. 86, Unit 1 Elizabeth, CO 80107 (303) 621-2776 Fax: (303) 621-2573

For additional information on NETA visit netaworld.org

44

RESA Power Service 19621 Solar Circle, 101 Parker, CO 80134 (303) 781-2560 [email protected] www.resapower.com Jody Medina

51

CE Power Solutions of Florida, LLC 3502 Riga Blvd., Suite C Tampa, FL 33619 (866) 439-2992

52

CE Power Solutions of Florida, LLC 3801 SW 47th Avenue, Suite 505 Davie, FL 33314 (866) 439-2992

connecticut 45

46

47

48

49

Advanced Testing Systems 15 Trowbridge Dr. Bethel, CT 06801 (203) 743-2001 Fax: (203) 743-2325 [email protected] www.advtest.com Pat MacCarthy American Electrical Testing Co., Inc. 34 Clover Dr. South Windsor, CT 06074 (860) 648-1013 Fax: (781) 821-0771 [email protected] www.aetco.com Gerald Poulin EPS Technology 29 N. Plains Highway, Suite 12 Wallingford, CT 06492 (203) 679-0145 [email protected] www.eps-technology.com Sean Miller

53

Electric Power Systems, Inc. 4436 Parkway Commerce Blvd. Orlando, FL 32808 (407) 578-6424 Fax: (407) 578-6408 www.epsii.com

54

Electrical Reliability Services 11000 Metro Pkwy., Suite 30 Ft. Myers, FL 33966 (239) 693-7100 Fax: (239) 693-7772

55

Electrical Testing, Inc. 2671 Cedartown Highway Rome, GA 30161-6791 (706) 234-7623 Fax: (706) 236-9028 [email protected] www.electricaltestinginc.com Jamie Dempsey

61

Nationwide Electrical Testing, Inc. 6050 Southard Trace Cumming, GA 30040 (770) 667-1875 Fax: (770) 667-6578 [email protected] www.n-e-t-inc.com Shashikant B. Bagle

illinois 62

Dude Electrical Testing, LLC 145 Tower Dr., Ste 9 Burr Ridge, IL 60527 (815) 293-3388 Fax: (815) 293-3386 [email protected] www.dudetesting.com Scott Dude

63

Electric Power Systems, Inc. 54 Eisenhower Lane North Lombard, IL 60148 (815) 577-9515 www.epsii.com

64

High Voltage Maintenance Corp. 941 Busse Rd. Elk Grove Village, IL 60007 (847) 640-0005 www.hvmcorp.com

65

Midwest Engineering Consultants, Ltd. 2500 36th Ave Moline, IL 61265-6954 (309) 764-1561 [email protected] www.midwestengr.com Monte Moorehead

66

Shermco Industries 112 Industrial Drive Minooka, IL 60447-9557 (815) 467-5577 [email protected] www.shermco.com

RESA Power Service 1401 Mercantile Court Plant City, FL 33563 (813) 752-6550 www.resapower.com

georgia 56

High Voltage Maintenance Corp. 150 North Plains Industrial Rd. Wallingford, CT 06492 (203) 949-2650 Fax: (203) 949-2646 www.hvmcorp.com Southern New England Electrical Testing, LLC 3 Buel St., Suite 4 Wallingford, CT 06492 (203) 269-8778 Fax: (203) 269-8775 [email protected] www.sneet.org David Asplund, Sr.

57

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florida 50

60

C.E. Testing, Inc. 6148 Tim Crews Rd. Macclenny, FL 32063 (904) 653-1900 Fax: (904) 653-1911 [email protected] www.cetestinginc.com Mark Chapman

59

ABM Electrical Power Services, LLC 1005 Windward Ridge Pkwy Alpharetta, GA 30005 (770) 521-7550 www.abm.com Electric Power Systems, Inc. 6679 Peachtree Industrial Dr., Suite H Norcross , GA 30092 (770) 416-0684 www.epsii.com Electrical Equipment Upgrading, Inc. 21 Telfair Place Savannah, GA 31415 (912) 232-7402 Fax: (912) 233-4355 [email protected] www.eeu-inc.com Kevin Miller Electrical Reliability Services 2275 Northwest Parkway SE, Suite 180 Marietta, GA 30067 (770) 541-6600 Fax: (770) 541-6501

For additional information on NETA visit netaworld.org

indiana 67

68

CE Power Engineered Services, LLC 3496 E. 83rd Place Merrillville, IN 46410 (219) 942-2346 www.cepower.net

Shermco Industries 2100 Dixon Street, Suite C Des Moines, IA 50316-2174 (515) 263-8482

75

Shermco Industries 5145 NW Beaver Dr. Johnston, IA 50131 (515) 265-3377 www.shermco.com

Electric Power Systems, Inc. 7169 East 87th St. Indianapolis, IN 46256 (317) 941-7502 www.epsii.com Daniel Douglas

kentucky

69

Electrical Maintenance & Testing, Inc. 12342 Hancock St. Carmel, IN 46032 (317) 853-6795 Fax: (317) 853-6799 [email protected] www.emtesting.com Brian K. Borst

70

High Voltage Maintenance Corp. 8320 Brookville Rd., Ste E Indianapolis, IN 46239 (317) 322-2055 Fax: (317) 322-2056 www.hvmcorp.com

71

Premier Power Maintenance Corporation 4035 Championship Drive Indianapolis, IN 46268 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

72

Premier Power Maintenance Corporation 4537 S Nucor Rd. Crawfordsville, IN 47933 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

iowa 73

74

Shermco Industries 1711 Hawkeye Dr. Hiawatha, IA 52233 (319) 377-3377 [email protected] www.shermco.com

76

77

78

Electrical Reliability Services 9636 St. Vincent, Unit A Shreveport, LA 71106 (318) 869-4244 [email protected]

83

Saber Power Services, LLC 14617 Perkins Road Baton Rouge, LA 70810 (225) 726-7793 www.saberpower.com

84

Tidal Power Services, LLC 8184 Highway 44, Suite 105 Gonzales, LA 70737 (225) 644-8170 Fax: (225) 644-8215 www.tidalpowerservices.com Darryn Kimbrough

CE Power Engineered Services, LLC 1803 Taylor Ave. Louisville, KY 40213 (800) 434-0415 [email protected] 85 Tidal Power Services, LLC www.cepower.net 1056 Mosswood Dr. Bob Sheppard Sulphur, LA 70665 (337) 558-5457 Fax: (337) 558-5305 High Voltage Maintenance Corp. www.tidalpowerservices.com 10704 Electron Drive Steve Drake Louisville, KY 40299 (859) 371-5355 maine www.hvmcorp.com 86 CE Power Engineered Services, LLC Premier Power Maintenance 72 Sanford Drive Corporation Gorham, ME 04038 2725 Jason Rd (800) 649-6314 Ashland, KY 41102-7756 [email protected] (606) 929-5969 www.cepower.net [email protected] Jim Cialdea www.premierpowermaintenance.com 87 Electric Power Systems, Inc. Jay Milstead 56 Bibber Pkwy #1 Brunswick, ME 04011-7357 (207) 837-6527 louisiana www.epsii.com

79

Electric Power Systems, Inc. 1129 East Highway 30 Gonzalez, LA 70737 (225) 644-0150 Fax: (225) 644-6249 www.epsii.com

80

Electrical Reliability Services 245 Hood Road Sulphur, LA 70665-8747 (337) 583-2411 [email protected]

81

82

Electrical Reliability Services 3535 Emerson Pkwy, Ste A Gonzales, LA 70737 (225) 755-0530 [email protected]

88

POWER Testing and Energization, Inc. 303 US Route One Freeport,ME 04032 (207) 869-1200 www.powerte.com

maryland 89

ABM Electrical Power Solutions 3700 Commerce Dr., #901- 903 Baltimore, MD 21227 (410) 247-3300 Fax: (410) 247-0900 www.abm.com

For additional information on NETA visit netaworld.org

90

ABM Electrical Power Solutions 4390 Parliament Pl., Suite S Lanham, MD 20706 (301) 967-3500 Fax: (301) 735-8953 [email protected] www.abm.com Christopher Smith

91

Harford Electrical Testing Co., Inc. 1108 Clayton Rd. Joppa, MD 21085 (410) 679-4477 [email protected] www.harfordtesting.com Vincent Biondino

92

High Voltage Maintenance Corp. 9305 Gerwig Ln., Suite B Columbia, MD 21046 (410) 309-5970 Fax: (410) 309-0220 www.hvmcorp.com

93

High Voltage Maintenance Corp. 14300 Cherry Lane Court, Ste 115 Laurel, MD 20707 (410) 279-0798 www.hvmcorp.com

94

95

97

Electrical Engineering & Service Co. Inc. 289 Centre St. Holbrook, MA 02343 (781) 767-9988 [email protected] www.eescousa.com Joe Cipolla

99

High Voltage Maintenance Corp. 24 Walpole Park S Walpole, MA 02081-2541 (508) 668-9205 www.hvmcorp.com

100

Infra-Red Building and Power Service, Inc. 152 Centre St Holbrook, MA 02343-1011 (781) 767-0888 [email protected] www.infraredbps.com

106

Premier Power Maintenance Corporation 7262 Kensington Rd. Brighton, MI 48116 (517) 230-6620 [email protected] www.premierpowermaintenance.com Brian Ellegiers

108

RESA Power Service 46918 Liberty Dr Wixom, MI 48393-3600 (248) 313-6868 [email protected] www.resapower.com Bruce Robinson

109

Shermco Industries 12796 Currie Court Livonia, MI 48150 (734) 469-4050 [email protected] www.shermco.com

michigan 101

CE Power Engineered Services, LLC 10338 Citation Drive, Ste 300 Brighton, MI 48116 (810) 229-6628 [email protected] www.cepower.net Ken L’Esperance

104

American Electrical Testing Co., LLC 25 Forbes Boulevard, Ste 1 Foxboro, MA 02035 (781) 821-0121 [email protected] www.aetco.us Scott Blizard CE Power Engineered Services, LLC 40 Washington St Westborough, MA 01581-1088 (508) 881-3911 www.cepower.net

Northern Electrical Testing, Inc. 1991 Woodslee Dr. Troy, MI 48083-2236 (248) 689-8980 Fax: (248) 689-3418 [email protected] www.northerntesting.com Lyle Detterman

105 POWER

PLUS Engineering, Inc. 47119 Cartier Court Wixom, MI 48393-2872 (248) 896-0200

Powertech Services, Inc. 4095 South Dye Rd. Swartz Creek, MI 48473-1570 (810) 720-2280 Fax: (810) 720-2283 [email protected] www.powertechservices.com Kirk Dyszlewski

107

Potomac Testing, Inc. 1610 Professional Blvd., Ste A Crofton, MD 21114 (301) 352-1930 Fax: (301) 352-1936 110 [email protected] 102 Electric Power Systems, Inc. www.potomactesting.com 11861 Longsdorf St. Ken Bassett Riverview, MI 48193 (734) 282-3311 Reuter & Hanney, Inc. www.epsii.com 11620 Crossroads Cir., Suites D-E Middle River, MD 21220 103 High Voltage Maintenance Corp. (410) 344-0300 Fax: (410) 335-4389 24371 Catherine Industrial Dr., Ste 207 [email protected] Novi, MI 48375 www.reuterhanney.com (248) 305-5596 Fax: (248) 305-5579 Michael Jester www.hvmcorp.com 111

massachusetts 96

98

112

Utilities Instrumentation Service, Inc. 2290 Bishop Circle East Dexter, MI 48130 (734) 424-1200 Fax: (734) 424-0031 [email protected] www.uiscorp.com Gary E. Walls

minnesota CE Power Engineered Services, LLC 7674 Washington Ave. S Eden Prairie, MN 55344 (877) 968-0281 [email protected] www.cepower.net Jason Thompson RESA Power Service 3890 Pheasant Ridge Dr. NE, Ste 170 Blaine, MN 55449 (763) 784-4040 [email protected] www.resapower.com Mike Mavetz

For additional information on NETA visit netaworld.org

113

Shermco Industries 998 E. Berwood Ave. Saint Paul, MN 55110 (651) 484-5533 [email protected] www.shermco.com

121

122

missouri 114

115

116

117

Electric Power Systems, Inc. 6141 Connecticut Ave. Kansas City, MO 64120 (816) 241-9990 Fax: (816) 241-9992 www.epsii.com Electric Power Systems, Inc. 21 Millpark Ct. Maryland Heights, MO 63043-3536 (314) 890-9999 Fax:(314) 890-9998 www.epsii.com

123

Electrical Reliability Services 124 400 NW Capital Dr Lees Summit, MO 64086 (816) 525-7156 Fax: (816) 524-3274 [email protected] POWER Testing and Energization, Inc. 12755 Olive Blvd., Ste 100 Saint Louis, MO 63141 (314) 851-4065 www.powerte.com

125

nebraska 118

Shermco Industries 4670 G. Street Omaha, NE 68117 (402) 933-8988 [email protected] www.shermco.com

120

126

Control Power Concepts 353 Pilot Rd, Suite B Las Vegas, NV 89119 (702) 448-7833 Fax: (702) 448-7835 [email protected] www.controlpowerconcepts.com John Travis Electric Power Systems, Inc. 5850 Polaris Ave., Suite 1600 Las Vegas, NV 89118 (702) 815-1342 www.epsii.com

Electrical Reliability Services 1380 Greg St., Suite 217 Sparks, NV 89431 (775) 746-8484 Fax: (775) 356-5488 www.electricalreliability.com Hampton Tedder Technical Services 4113 Wagon Trail Ave. Las Vegas, NV 89118 (702) 452-9200 www.hamptontedder.com Roger Cates National Field Services 3711 Regulus Ave. Las Vegas, NV 89102 (888) 296-0625 [email protected] www.natlfield.com Howard Herndon National Field Services 2900 Vassar St. #114 Reno, NV 89502 (775) 410-0430 www.natlfield.com Howard Herndon [email protected]

Electric Power Systems, Inc. 915 Holt Ave., Unit 9 Manchester, NH 03109 (603) 657-7371 www.epsii.com

Eastern High Voltage 11A South Gold Dr. Robbinsville, NJ 08691-1606 (609) 890-8300 Fax: (609) 588-8090 [email protected] www.easternhighvoltage.com Robert Wilson

130

High Energy Electrical Testing, Inc. 515 S. Ocean Ave. Seaside Park, NJ 08752 (732) 938-2275 Fax: (732) 938-2277 [email protected] www.highenergyelectric.com Charles Blanchard

131

132

American Electrical Testing Co., Inc. 91 Fulton St. Boonton, NJ 07005 (973) 316-1180 [email protected] www.aetco.com Jeff Somol

J.G. Electrical Testing Corporation 3092 Shafto Road, Suite 13 Tinton Falls, NJ 07753 (732) 217-1908 www.jgelectricaltesting.com Howard Trinkowsky M&L Power Systems, Inc. 109 White Oak Ln., Suite 82 Old Bridge, NJ 08857 (732) 679-1800 Fax: (732) 679-9326 [email protected] www.mlpower.com Milind Bagle

133

RESA Power Service 311 Bay Avenue A Highlands, NJ 07732 (888) 996-9975 [email protected] www.resapower.com Trent Robbins

134

Scott Testing, Inc. 245 Whitehead Rd Hamilton, NJ 08619 (609) 689-3400 [email protected] www.scotttesting.com Russ Sorbello

new jersey 127

Burlington Electrical Testing Co., Inc. 198 Burrs Rd. Westampton, NJ 08060 (609) 267-4126 [email protected] www.betest.com Walter P. Cleary

129

new hampshire

nevada 119

Electrical Reliability Services 128 6351 Hinson St., Suite A Las Vegas, NV 89118 (702) 597-0020 Fax: (702) 597-0095 www.electricalreliability.com

For additional information on NETA visit netaworld.org

135

Trace Electrical Services 142 & Testing, LLC 293 Whitehead Rd. Hamilton, NJ 08619 (609) 588-8666 Fax: (609) 588-8667 www.tracetesting.com Joseph Vasta

new mexico 136

137

138

143

Electric Power Systems, Inc. 8515 Cella Alameda NE, Suite A Albuquerque, NM 87113 (505) 792-7761 www.eps-international.com Electrical Reliability Services 8500 Washington Pl. NE, Suite A-6 Albuquerque, NM 87113 (505) 822-0237 Fax: (505) 822-0217 www.electricalreliability.com Western Electrical Services, Inc. 620 Meadow Ln. Los Alamos, NM 87547 (505) 469-1661 [email protected] www.westernelectricalservices.com Toby King

144

145

new york 139

140

141

BEC Testing 50 Gazza Blvd Farmingdale, NY 11735-1402 (631) 393-6800 [email protected] www.bectesting.com Daniel Devlin Elemco Services, Inc. 228 Merrick Rd. Lynbrook, NY 11563 (631) 589-6343 [email protected] www.elemco.com Courtney Gallo High Voltage Maintenance Corp. 1250 Broadway, Suite 2300 New York, NY 10001 (718) 239-0359 www.hvmcorp.com

149

150

151

152

HMT, Inc. 6268 Route 31 Cicero, NY 13039 (315) 699-5563 Fax: (315) 699-5911 [email protected] www.hmt-electric.com John Pertgen

A&F Electrical Testing, Inc. 80 Broad St., 5th Floor New York, NY 10004 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Florence Chilton American Electrical Testing Co., Inc. 76 Cain Dr. Brentwood, NY 11717 (631) 617-5330 Fax: (631) 630-2292 [email protected] www.aetco.com Billy Fernandez

146

147

148

ABM Electrical Power Services, LLC 6541 Meridien Dr, Suite 113 Raleigh, NC 27616 (919) 877-1008 www.abm.com ABM Electrical Power Services, LLC 3600 Woodpark Blvd., Suite G Charlotte, NC 28206 (704) 273-6257 Fax: (704) 598-9812 [email protected] www.abm.com Ernest Goins ELECT, P.C. 375 E. Third Street Wendell, NC 27591 (919) 365-9775 [email protected] www.elect-pc.com Barry W. Tyndall

Electrical Reliability Services 6135 Lakeview Road, Suite 500 Charlotte, NC 28269 (704) 441-1497 [email protected] www.electricalreliability.com Power Products & Solutions, LLC 6605 W WT Harris Blvd, Suite F Charlotte, NC 28269 (704) 573-0420 x12 [email protected] www.powerproducts.biz Adis Talovic Power Test, Inc. 2200 Hwy. 49 S Harrisburg, NC 28075 (704) 200-8311 Fax: (704) 455-7909 [email protected] www.powertestinc.com Richard Walker

ohio 153

ABM Electrical Power Solutions 1817 O’Brien Road Columbus, OH 43228 (724) 772-4638 www.abm.com

154

CE Power Engineered Services, LLC 4040 Rev Drive Cincinnati, OH 45232 (800) 434-0415 [email protected] www.cepower.net Brent McAlister

155

CE Power Engineered Services, LLC 8490 Seward Rd. Fairfield, OH 45011 (800) 434-0415 [email protected] www.cepower.net Tim Lana

156

Electric Power Systems, Inc. 2888 Nationwide Parkway, 2nd Floor Brunswick, OH 44212 (330) 460-3706 www.epsii.com

north carolina

A&F Electrical Testing, Inc. 80 Lake Ave. S., Suite 10 Nesconset, NY 11767 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Kevin Chilton

Electric Power Systems, Inc. 319 US Hwy. 70 E, Suite E Garner, NC 27529 (919) 210-5405 www.eps-international.com

For additional information on NETA visit netaworld.org

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Electrical Reliability Services 610 Executive Campus Dr. Westerville, OH 43082 (877) 468-6384 Fax: (614) 410-8420 [email protected] www.electricalreliability.com High Voltage Maintenance Corp. 5100 Energy Dr. Dayton, OH 45414 (937) 278-0811 Fax: (937) 278-7791 www.hvmcorp.com

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High Voltage Maintenance Corp. 7200 Industrial Park Blvd. Mentor, OH 44060 (440) 951-2706 Fax: (440) 951-6798 www.hvmcorp.com Power Solutions Group Ltd. 425 W Kerr Rd Tipp City, OH 45371-2843 (937) 506-8444 [email protected] www.powersolutionsgroup.com Barry Willoughby

RESA Power Service 4540 Boyce Parkway Stow, OH 44224 (800) 264-1549 www.resapower.com

163

Shermco Industries 4383 Professional Parkway Groveport, OH 43125 (614) 836-8556 [email protected] www.shermco.com Utilities Instrumentation Service - Ohio, LLC PO Box 750066 998 Dimco Way Dayton, OH 45475-0066 (937) 439-9660

Sentinel Power Services, Inc. 7517 E Pine St Tulsa, OK 74115-5729 (918) 359-0350 [email protected] www.sentinelpowerservices.com Greg Ellis Shermco Industries 4510 South 86th East Ave. Tulsa, OK 74145 (918) 234-2300 [email protected] www.shermco.com

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Electrical Reliability Services 4099 SE International Way, Suite 201 Milwaukie, OR 97222-8853 (503) 653-6781 Fax: (503) 659-9733 www.electricalreliability.com

169

ABM Electrical Power Solutions 317 Commerce Park Drive Cranberry Township, PA 16066-6407 (724) 772-4638 www.abm.com

170

American Electrical Testing Co., Inc. Green Hills Commerce Center 5925 Tilghman St., Suite 200 Allentown, PA 18104 (215) 219-6800 [email protected] www.aetco.com Jonathan Munley

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Reuter & Hanney, Inc. 149 Railroad Dr. Northampton Industrial Park Ivyland, PA 18974 (215) 364-5333 Fax: (215) 364-5365 [email protected] www.reuterhanney.com Michael Jester

south carolina 177

Power Products & Solutions, LLC 13 Jenkins Ct. Mauldin, SC 29662 (800) 328-7382 [email protected] www.powerproducts.biz Raymond Pesaturo

178

Power Products & Solutions, LLC 9481 Industrial Center Dr. Unit 5 Ladson, SC 29456 (844) 383-8617 www.powerproducts.biz

179

Power Solutions Group Ltd. 5115 Old Greenville Highway Liberty, SC 29657 (864) 540-8434 [email protected] www.powersolutionsgroup.com Anthony Crawford

Burlington Electrical Testing Co., Inc. 300 Cedar Ave. Croydon, PA 19021-6051 (215) 826-9400 Fax: (215) 826-0964 www.betest.com Electric Power Systems, Inc. 1090 Montour West Industrial Blvd. Coraopolis, PA 15108 (412) 276-4559 www.epsii.com

High Voltage Maintenance Corp. 355 Vista Park Dr. Pittsburgh, PA 15205-1206 (412) 747-0550 Fax: (412) 747-0554 www.hvmcorp.com North Central Electric, Inc. 69 Midway Ave. Hulmeville, PA 19047-5827 (215) 945-7632 Fax: (215) 945-6362 [email protected] www.ncetest.com Robert Messina

Taurus Power & Controls, Inc. 9999 SW Avery St. Tualatin, OR 97062-9517 (503) 692-9004 Fax: (503) 692-9273 [email protected] www.tauruspower.com Rob Bulfinch

pennsylvania

EnerG Test, LLC 204 Gale Lane, Bldg. 2 – 2nd Floor Kennett Square, PA 19348 (484) 731-0200 Fax: (484) 713-0209 [email protected] www.energtest.com Dennis Buehler

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oregon

Power Solutions Group Ltd. 2739 Sawbury Blvd. Columbus, OH 43235 (614) 310-8018 [email protected] www.powersolutionsgroup.com Stuart Spohn

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oklahoma

180

POWER Testing and Energization, Inc. 1041 Red Ventures Dr., Suite 105 Fort Mill, SC 29707 (803) 835-5900 www.powerte.com

For additional information on NETA visit netaworld.org

tennesee 181

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Electrical Reliability Services 1057 Doniphan Park Cir Ste A El Paso, TX 79922-1329 (915) 587-9440 [email protected]

CE Power Engineered Services, LLC 480 Cave Rd Nashville, TN 37210-2302 (615) 882-9455 190 Electrical Reliability Services [email protected] 1426 Sens Rd Ste 5 www.cepower.net La Porte, TX 77571-9656 Bryant Phillips (281) 241-2800 CE Power Engineered Services, LLC [email protected] 10840 Murdock Drive 191 Grubb Engineering, Inc. Knoxville , TN 37932 2727 North Saint Mary’s St. (800) 434-0415 San Antonio, TX 78212 [email protected] (210) 658-7250 www.cepower.net [email protected] Don William www.grubbengineering.com Electric Power Systems, Inc. Robert D. Grubb Jr. 684 Melrose Avenue 192 Magna IV Engineering Nashville, TN 37211-3121 4407 Halik Street Building E, Suite 300 (615) 834-0999 www.epsii.com Pearland, TX 77581 (346) 221-2165 Electrical & Electronic Controls [email protected] 6149 Hunter Rd. www.magnaiv.com Ooltewah, TN 37363 Aric Proskurniak (423) 344-7666 Fax: (423) 344-4494 193 National Field Services [email protected] Michael Hughes 651 Franklin Lewisville, TX 75057-2301 Electrical Testing and (972) 420-0157 Maintenance Corp. www.natlfield.com 3673 Cherry Rd Ste 101 Eric Beckman Memphis, TN 38118-6313 (901) 566-5557 194 National Field Services [email protected] 1890 A South Hwy 35 www.etmcorp.net Alvin, TX 77511 Ron Gregory (800) 420-0157 [email protected] Power Solutions Group, Ltd. www.natlfield.com 172 B-Industrial Dr. Jonathan Wakeland Clarksville, TN 37040 195 National Field Services (931) 572-8591 www.powersolutionsgroup.com 1405 United Drive, Suite 113-115 San Marcos, TX 78666 Chris Brown (800) 420-0157 [email protected] texas www.natlfield.com Matt LaCoss Absolute Testing Services, Inc. 8100 West Little York 196 Power Engineering Services, Inc. Houston, TX 77040 9179 Shadow Creek Ln (832) 467-4446 Converse, TX 78109-2041 www.absolutetesting.com (210) 590-4936 [email protected] Electric Power Systems, Inc. www.pe-svcs.com 1330 Industrial Blvd., Suite 300 Daniel Staudt Sugar Land, TX 77478 (713) 644-5400 www.epsii.com

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POWER Testing and Energization, Inc. 16825 Northchase Drive Houston, TX 77060 (281) 765-5536 www.powerte.com Saber Power Services, LLC 9841 Saber Power Ln Rosharon, TX 77583-5188 (713) 222-9102 [email protected] www.saberpower.com Saber Power Services, LLC 4703 Shavano Oak, Suite 104 San Antonio, TX 78249 (210) 267-7282 www.saberpower.com Saber Power Services, LLC 1315 FM 1187, Suite 105 Mansfield, TX 76063 (682) 518-3676 www.saberpower.com Shermco Industries 2425 E Pioneer Dr Irving, TX 75061-8919 (972) 793-5523 [email protected] www.shermco.com

202

Shermco Industries 1705 Hur Industrial Blvd Cedar Park, TX 78613-7229 (512) 267-4800 [email protected] www.shermco.com

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Shermco Industries 33002 FM 2004 Angleton, TX 77515-8157 (979) 848-1406 [email protected] www.shermco.com

204

Shermco Industries 12000 Network Blvd, Buidling D Suite 410 San Antonio, TX 78249-3354 (210) 877-9090 [email protected] www.shermco.com

205

Shermco Industries 3807 S Sam Houston Pkwy W Houston, TX 77056 (281) 835-3633 [email protected] www.shermco.com

For additional information on NETA visit netaworld.org

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Shermco Industries 1301 Hailey St. Sweetwater, TX 79556 (325) 236-9900 [email protected] www.shermco.com

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Shermco Industries 2901 Turtle Creek Dr. Port Arthur, TX 77642 (409) 853-4316 [email protected] www.shermco.com

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Tidal Power Services, LLC 4211 Chance Ln Rosharon, TX 77583-4384 (281) 710-9150 [email protected] www.tidalpowerservices.com Monty C. Janak

Titan Quality Power Services, LLC 7630 Ikes Tree Drive Spring, TX 77389 (281) 826-3781 www.titanqps.com

utah 211

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ABM Electrical Power Solutions 814 Greenbrier Cir., Suite E Chesapeake, VA 23320 (757) 364-6145 www.abm.com Mark Anthony Gaughan, III

223

Reuter & Hanney, Inc. 4270-I Henninger Ct. Chantilly, VA 20151 (703) 263-7163 Fax: (703) 263-1478 www.reuterhanney.com 224

Electrical Reliability Services 2222 West Valley Hwy. N., Suite 160 Auburn, WA 98001 (253) 736-6010 Fax: (253) 736-6015 [email protected] www.electricalreliability.com 225

219

226 Sigma Six Solutions, Inc. 2200 West Valley Hwy., Suite 100 Auburn, WA 98001 (253) 333-9730 Fax: (253) 859-5382 [email protected] www.sigmasix.com John White

Western Electrical Services, Inc. 220 3676 W. California Ave.,#C-106 Salt Lake City, UT 84104 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Rob Coomes

Western Electrical Services, Inc. 4510 NE 68th Dr., Suite 122 Vancouver, WA 98661 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Tony Asciutto

wisconsin

POWER Testing and Energization, Inc. 14006 NW 3rd Ct, Ste 101 Vancouver, WA 98685-5793 (360) 597-2800 [email protected] www.powerte.com Chris Zavadlov

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Electrical Reliability Services 9736 South 500 West Sandy, UT 84070 (801) 975-6461 [email protected]

virginia

Electric Power Systems, Inc. 306 Ashcake Road, Suite A Ashland, VA 23005 (804) 526-6794 www.epsii.com

washington 217

Titan Quality Power Services, LLC 1501 S Dobson Street Burleson, TX 76028 (866) 918-4826 www.titanqps.com

Electric Power Systems, Inc. 120 Turner Road Salem, VA 24153-5120 (540) 375-0084 www.epsii.com

Electrical Energy Experts, Inc. W129N10818, Washington Dr. Germantown,WI 53022 (262) 255-5222 Fax: (262) 242-2360 [email protected] www.electricalenergyexperts.com Tim Casey Electrical Testing Solutions 2909 Green Hill Ct. Oshkosh, WI 54904 (920) 420-2986 Fax: (920) 235-7136 [email protected] www.electricaltestingsolutions.com Tito Machado Energis High Voltage Resources, Inc. 1361 Glory Rd. Green Bay, WI 54304 (920) 632-7929 Fax: (920) 632-7928 [email protected] www.energisinc.com Mick Petzold High Voltage Maintenance Corp. 3000 S. Calhoun Rd. New Berlin, WI 53151 (262) 784-3660 Fax: (262) 784-5124 www.hvmcorp.com

Taurus Power & Controls, Inc. 19226 66th Ave S. #L102 Kent, WA 98032-2197 (425) 656-4170 www.tauruspower.com Western Electrical Services, Inc. 14311 29th St. East Sumner, WA 98390 (253) 891-1995 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Dan Hook

For additional information on NETA visit netaworld.org

CANADA

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Magna IV Engineering Suite 200, 688 Heritage Dr. SE Calgary, AB T2H 1M6 Canada (403) 723-0575 Fax: (403) 723-0580 www.magnaiv.com

228

Magna IV Engineering 1103 Parsons Rd. SW Edmonton, AB T6X 0X2 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Virginia Balitski

229

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Magna IV Engineering 106, 4268 Lozells Ave. Burnaby, BC VSA 0C6 Canada (604) 421-8020

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Magna IV Engineering 141 Fox Cresent Fort McMurray, AB T9K 0C1 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Ryan Morgan Shermco Industries Canada 3434 25th Street NE Calgary, AB T1Y 6C1 (403) 769-9300 [email protected] www.shermco.com

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Shermco Industries Canada 241 3731-98 Street Edmonton, AB T6E 5N2 Canada (780) 436-8831 Fax: (780) 463-9646 [email protected] www.shermco.com Shermco Industries Canada 1033 Kearns Crescent RM of Sherwood SK S4K 0A2 (306) 949-8131 [email protected] www.shermco.com Shermco Industries Canada 1375 Church Ave. Winnipeg, MB R2X 2T7 Canada (204) 925-4022 Fax: (204) 925-4021 www.shermco.com Orbis Engineering Field Services Ltd. #300, 9404 - 41st Ave. Edmonton, AB T6E 6G8 Canada (780) 988-1455 Fax: (780) 988-0191 [email protected] www.orbisengineering.net Lorne Gara

REV 01.19

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Pacific Powertech, Inc. 245 #110, 2071 Kingsway Ave. Port Coquitlam, BC V3C 6N2 Canada (604) 944-6697 Fax: (604) 944-1271 [email protected] www.pacificpowertech.ca Josh Konkin REV Engineering Ltd. 3236 - 50 Ave. SE Calgary, AB T2B 3A3 Canada (403) 287-0156 Fax: (403) 287-0198 [email protected] www.reveng.ca Roland Nicholas Davidson, IV Rondar Inc. 333 Centennial Parkway North Hamilton, ON L8E2X6 (905) 561-2808 www.rondar.com Gary Hysop

BRUSSELS 246

Magna IV Engineering 7, 3040 Miners Ave. Saskatoon, SK S7K 5V1 (306) 713-2167 www.magnaiv.com Adam Jaques [email protected] Pace Technologies, Inc. #10, 883 McCurdy Place Kelowna , BC V1X 8C8 (250) 712-0091 www.pacetechnologies.com

Shermco Industries Boulevard Saint-Michel 47 1040 Brussels, Brussels, Belgium +32 (0)2 400 00 54 Fax: +32 (0)2 400 00 32 [email protected] www.shermco.com

CHILE 247

Magna IV Engineering Avenida del Condor Sur #590 Officina 601 Huechuraba, Santiago 8580676 Chile +(56) -2-26552600 [email protected] Henry Mendoza

248

Orbis Engineering Field Services Ltd. Badajoz #45, Piso 17 Las Condes, Santiago +56 2 29402343 www.orbisengineering.net

Rondar Inc. 9-160 Konrad Crescent Markham, ON L3R9T9 (905) 943-7640 www.rondar.com Shermco Industries Canada 233 Faithfull Cr. Saskatoon, SK S7K 8H7 (306) 955-8131 www.shermco.com [email protected]

Pace Technologies, Inc. 9604 - 41 Avenue NW Edmonton, AB T6E 6G9 (780) 450-0404 [email protected] www.pacetechnologies.com Craig Leavitt

PUERTO RICO 249

Phasor Engineering Sabaneta Industrial Park #216 Mercedita, PR 00715 Puerto Rico (787) 844-9366 Fax: (787) 841-6385 [email protected] www.phasorinc.com Rafael Castro

Advanced Electrical Services 4999 - 43rd St. NE, Unit 143 Calgary, AB T2B 3N4 (403) 697-3747 [email protected] www.aes-ab.com Zachary Houk Orbis Engineering Field Services Ltd. #228 - 18 Royal Vista Link NW Calgary, AB T3R 0K4 (403) 374-0051 www.orbisengineering.net

For additional information on NETA visit netaworld.org

ABOUT THE INTERNATIONAL ELECTRICAL TESTING ASSOCIATION The InterNational Electrical Testing Association (NETA) is an accredited standards developer for the American National Standards Institute (ANSI) and defines the standards by which electrical equipment is deemed safe and reliable. NETA Certified Technicians conduct the tests that ensure this equipment meets the Association’s stringent specifications. NETA is the leading source of specifications, procedures, testing, and requirements, not only for commissioning new equipment but for testing the reliability and performance of existing equipment.

CERTIFICATION Certification of competency is particularly important in the electrical testing industry. Inherent in the determination of the equipment’s serviceability is the prerequisite that individuals performing the tests be capable of conducting the tests in a safe manner and with complete knowledge of the hazards involved. They must also evaluate the test data and make an informed judgment on the continued serviceability, deterioration, or nonserviceability of the specific equipment. NETA, a nationally-recognized certification agency, provides recognition of four levels of competency within the electrical testing industry in accordance with ANSI/NETA ETT-2018 Standard for Certification of Electrical Testing Technicians.

QUALIFICATIONS OF THE TESTING ORGANIZATION An independent overview is the only method of determining the long-term usage of electrical apparatus and its suitability for the intended purpose. NETA Accredited Companies best support the interest of the owner, as the objectivity and competency of the testing firm is as important as the competency of the individual technician. NETA Accredited Companies are part of an independent, third-party electrical testing association dedicated to setting world standards in electrical maintenance and acceptance testing. Hiring a NETA Accredited Company assures the customer that: • The NETA Technician has broad-based knowledge — this person is trained to inspect, test, maintain, and calibrate all types of electrical equipment in all types of industries. • NETA Technicians meet stringent educational and experience requirements in accordance with ANSI/NETA ETT-2018 Standard for Certification of Electrical Testing Technicians. • A Registered Professional Engineer will review all engineering reports • All tests will be performed objectively, according to NETA specifications, using calibrated instruments traceable to the National Institute of Science and Technology (NIST). • The firm is a well-established, full-service electrical testing business.

Setting the Standard

Circuit Breaker Services

from

For Circuit Breaker Maintenance Solutions, Shermco Industries offers fast turnarounds, reliable repairs and state-of-the-art upgrades performed by knowledgeable, NETA certified technicians at multiple locations. From high voltage substations to industrial distribution needs, our comprehensive services and a “zero defects” approach assures trouble free operation and reliable performance. Our new mobile services include on-site reconditioning and remanufacturing for most breaker styles and our SF6 and oil processing trailers can get you up and running faster than fast.

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VOLUME 2

MAINTENANCE Vol. 2 HANDBOOK

SERIES III

HANDBOOK

Published By

MAINTENANCE

SERIES III

MAINTENANCE VOL. 2

Published by

InterNational Electrical Testing Association

MAINTENANCE VOL. 2 SAFETY HANDBOOK TABLE OF CONTENTS Testing Rotating Machinery: Dielectric Characteristic AC Test...................................... 5 Vicki Warren

Why You Should Use the Guard Circuit................................................................... 8 James White

Testing Rotating Machinery Polarization/Depolarization Current (PDC)...................... 11 Vicki Warren

The NFPA 70B – One of the Industry’s Best-Kept Secrets........................................... 14 Ron Widup and Jim White

The Benefits of Applying High Resistance Grounds for an Ungrounded Power System..................................................................................................... 18 Jim Vermeer

Best Practices for Impact Bump Testing Stator End Windings..................................... 21 Vicki Warren and John Letal

64S Protection Guide Theory, Application, and Commissioning of Generator 100 Percent Stator Ground Fault Protection Using Low Frequency Injection................ 24 Steve Turner

Get the Most Bang for Your Buck: Top Five Tests for Best Return on Investment............. 32 Don Genutis

Avoiding Metal-Clad Switchgear Failure Through Use of Partial Discharge Detection............................................................................................ 34 Tony McGrail, Jay Garnett, Matthew Lawrence

Published by

InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024

269.488.6382

www.netaworld.org

Testing Rotating Machinery: QA Tests for MV GVPI Stator Windings...................... 38 Vicki Warren

Role of On-Line Condition Monitoring for Power Transformer Operation and Maintenance............................................................................. 42 Kenneth Elkinson and Tony McGrail

Smaller Commissioning Assignments Require Great Detail.................................... 45 Brian S. Moores

Deploying Thermal Cameras to Your Utility’s Best Advantage: A Tow-Pronged Approach................................................................................. 50 Brad Risser

Influence of the Test Voltage Wave Shape of the PD Characteristics of Typical Defects in Medium-Voltage Cable Accessories.......................................... 55 Hein Putter, Daniel Götz, Frank Petzold, Marco Stephan, Henning Oetjen

Optimize Stator Endwinding Vibration Monitoring with Impact Testing.................... 61 John Letal and Vicki Warren

Process Analysis – Your Path to System Knowledge.............................................. 67 Noah Bethel

Published by

InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024

269.488.6382

www.netaworld.org

Published by InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024 269.488.6382 www.netaworld.org

NOTICE AND DISCLAIMER NETA Technical Papers and Articles are published by the InterNational Electrical Testing Association. Opinions, views, and conclusions expressed in articles herein are those of the authors and not necessarily those of NETA. Publication herein does not constitute or imply any endorsement of any opinion, product, or service by NETA, its directors, officers, members, employees, or agents (hereinafter “NETA”). All technical data in this publication reflects the experience of individuals using specific tools, products, equipment, and components under specific conditions and circumstances which may or may not be fully reported and over which NETA has neither exercised nor reserved control. Such data has not been independently tested or otherwise verified by NETA. NETA makes no endorsement, representation or warranty as to any opinion, product or service referenced in this publication. NETA expressly disclaims any and all liability to any consumer, purchaser or any other person using any product or service referenced herein for any injuries or damages of any kind whatsoever, including, but not limited to, any consequential, special incidental, direct or indirect damages. NETA further disclaims any and all warranties, express or implied, including, but not limited to, any implied warranty or merchantability or any implied warranty of fitness for a particular purpose. Please Note: All biographies of authors and presenters contained herein are reflective of the professional standing of these individuals at the time the articles were originally published. Titles, companies, and other factors may have changed since the original publication date.

Copyright © 2019 by InterNational Electrical Testing Association, all rights reserved. No part of this publication may be reproduced in any form or by any means, electronic or mechanical, without permission in writing from the publisher.

5

Maintenance Vol. 2

TESTING ROTATING MACHINERY: DIELECTRIC CHARACTERISTIC AC TEST NETA World, Spring 2014 Issue Vicki Warren, Iris Power LP Generators and motors typically enjoy 20 years or more of operation in utility and industrial applications before either the rotor or stator windings need to be replaced. However, if the machine is overloaded or subjected to a polluted environment, or was poorly constructed, failure may occur in just a few years due to premature aging. Over the past several years, off-line direct-voltage (dc) and alternating voltage (ac) tests have been used to locate and determine the severity or risk of failure and whether repairs are possible. Off-line tests have the advantages of accessibility, noise-free environments, ease of repair, and test variety. The disadvantages are that there are abnormal mechanical, thermal, and electrical stresses, and that they require a machine outage which can be timeconsuming. With dc, the voltage distribution is based on insulation resistance, while with an ac, the voltage distribution is based on capacitance. Therefore, dc tests are suitable for locating cracks and contamination, whereas ac tests are used to evaluate how well the insulation system is consolidated during manufacturing and the impact of thermal aging. A thorough condition-assessment evaluation should include dc and ac testing as well as a visual inspection.

DIELECTRIC CHARACTERISTIC AC TESTS Capacitance Insulation systems are by design a capacitor with a dielectric of organic resin, glass, and mica that separates the copper conductors from the core iron. As an insulation system ages, the organic resin is slowly replaced with air-filled voids that change the dielectric constant, or capacitance, of the insulation system. In pre-1970 machines, the change in the dielectric constant was often significant enough that it was possible to detect the effects of aging by measuring the total capacitance of a winding. Though still possible on severely deteriorated newer windings, the change in capacitance is often so subtle that until the winding is nearing failure it is difficult to observe any changes. The capacitance can be measured at a low voltage and best done with a bridge that will eliminate the effect of the stray capacitance of the test supply.

Fig. 1: Thermal Delamination Fig. 2: Contamination A variation on the capacitance test is the capacitance tip-up test, which is performed on complete windings or preferably individual winding phases with an accurate capacitance bridge. At a relatively high voltage, the gas within voids ionizes to produce sufficiently high conductivity to short the void out causing partial discharge. This produces an increase in capacitance between low- and highvoltage tests. The capacitance Clv is measured at 0.2E where E is the rated phase-to-phase voltage and Chv is measured at line-toground voltage which is about 0.58E. The capacitance tip-up is: ΔC = (Chv – Clv)/Clv The higher ΔC is, the more voids there are in the winding groundwall. For a well bonded groundwall insulation:

ΔC < 1% for modern epoxy mica insulation ΔC < 3 or 4% for older asphaltic mica windings ΔC = (Chv – Clv)/Clv ΔC = (690 – 688)/688 = 0.3%

●● Delamination ⇒ capacitance decreases (1% change) [Figure 1] ●● Moisture contamination ⇒ capacitance increases (5% change) [Figure 2] Fig. 3: Capacitance Tip-Up (W-phase is notably lower than the other two phases indicating minor delamination on this phase)

6

Maintenance Vol. 2

It should be noted that if the coils have semiconducting and grading voltage stress control layers, these influence the results of this test. At the higher voltage, the grading layers of silicon carbide material conduct to increase the effective surface area and thus the capacitance of the sections of winding being tested, and so may give a false indication of high void content. However, if the results are trended against time, an increase in ΔC may give a true indication of increased void content in the groundwall insulation.

DISSIPATION FACTOR/POWER FACTOR Dissipation Factor (DF or tan δ) Like the capacitance test, the dissipation factor test also looks for changes in the insulation system of the winding. This test, however, is done at high voltage steps that increase from zero to normal line-to-ground voltage. The test compares the real power loss (IR) due to the presence of voids in a delaminated insulation as a ratio to the capacitance power (IC), or the tangent of δ (IR / IC) as shown in Figure 4. The absolute value of the dissipation factor is also useful in determining the extent of curing in a new insulation system.

DF = tan δ = mW / mVar = IR / IC

●● Delamination ⇒ tan δ increases ●● Moisture contamination ⇒ tan δ increases

DFepoxy ≤ 0.5%



DFasphaltic ≤ 3 to 5%.

Trending the results against time makes the best use of this test. As with the Δ capacitance test, voltage stress coatings can lead to ambiguous results obtained at high voltage.

IC = capacitance current IT = total current IR = resistive current DF = Tan d = IR / IC PF = Cos q = IR / IT

it possible for comparing the results to other machines. This is a valuable test for determining the extent of curing in new coils or winding. Because the presence of the voltage stress control in a complete winding greatly affects the results, tests on complete windings can be ambiguous.

PF = cos Ѳ = mW / mVA = IR / IT

●● Delamination ⇒ cos Ѳ increases ●● Moisture contamination ⇒ cos Ѳ increases

PFpolyethylene ≤ 0.01%



PFepoxy ≤ 0.5%



PFasphalt ≤ 3 - 5%

TIP-UP TESTS The tip-up test (Δ tan δ or Δ cos θ) done at two voltages, one below the inception of partial discharge activity (25% line-toground) and one at line-to-ground voltage may provide some information regarding the integrity of the stator insulation system [Figure 5]. The intention of the test is to observe the increase in real power loss (ΔIR) due to partial discharges within voids of a delaminated insulation, and therefore investigate the quality of the resin bond. This test is widely used by manufacturers of resin rich and individual VPI coils as a quality check. As with the capacitance tip-up test, the results of this test are influenced by the presence of voltage stress coatings on the coils, since at high lineto-ground voltage currents flow through it to produce additional power losses. Because this test method measures total energy it is only sensitive to widespread delamination and not how close the winding is to failure (worst spot). - Tip-up = DF/PF high - DF/PF low (typical results: 0.5% for epoxy) - High at 100% line-to-ground rated voltage (above partial discharge inception voltage - PDIV) - Low at 25% line-to-ground rated voltage (below PDIV) ΔDF=(1 - 0.74)/0.74 = 35%

Fig. 4: DF and PF Tests

POWER FACTOR (PF OR COS Ѳ) Similar to the dissipation-factor test (tan δ) the power factor (cos Ѳ) test is looking for any changes in the insulation system of the winding. The test compares the real power loss (IR) due to the presence of voids in a delaminated insulation as a ratio to the total power (IT), or the cosine of qq (IR / IT) as shown in Figure 4. The test is normally done at a specific applied voltage that makes

Fig. 5: Dissipation Factor (DF) Tip-Up

7

Maintenance Vol. 2 OFF-LINE TEST EFFECTIVENESS AC VS DC Voltage

11 kV

KVA

1 to 7 ms

Insulation Class

F

Cooling

Air/water

Date Manufactured

208

The winding is global VPI design meaning that the winding was placed in the core in a green or resin free-state and then the entire winding and core subjected to a vacuum-pressure-impregnation process to consolidate the winding insulation layers and anchor the winding in the core. As shown in the table below, the dc test results for the IR/PI and dc insulation tests were acceptable, but both the power-factor and tip-up tests were elevated. A visual inspection of the winding revealed notable damage to the voltage stress coatings (Figure 6) as well as possible areas of coil overheating (Figure 7). This suggests dc tests were not adequate to fully evaluate the condition of the winding and the need for ac dielectric characteristic tests. 2013 Results

Test

Insulation Resistance (IR) at 5 kV

Polarization Index (PI) at 5 kV

DC Insulation Test at 25 kV

Power Factor at 2 kV

Power Factor Tip-UP (2 kV to k kV)

U

17 GΩ

V

17.2 GΩ

W

17.1 GΩ

U

5.01

V

5.04

W

4.26

U

Pass

V

Pass

W

Pass

U

1.00%

V

0.99%

W

0.98%

U

0.65%

V

0.66%

W

0.65%

Fig. 6: Voltage Stress Coating Damage

IEEE reference (acceptable limit)

IEEE 43 - 2000 (100 MΩ)

IEEE 43 - 2000 (>2)

IEEE 95 - 2002 (Pass)

IEEE 286 - 2002 (0.5%)

IEEE 286 - 2002 (0.5%)

Fig. 7: Overheated Coil

Vicki Warren, Senior Product Engineer, Iris Power LP. Vicki is an electrical engineer with extensive experience in testing and maintenance of motor and generator windings. Prior to joining Iris in 1996, she worked for the U.S. Army Corps of Engineers for 13 years. While with the Corps, she was responsible for the testing and maintenance of hydrogenerator windings, switchgear, transformers, protection and control devices, development of SCADA software, and the installation of local area networks. At Iris, Vicki has been involved in using partial discharge testing to evaluate the condition of insulation systems used in medium- to high-voltage rotating machines, switchgear and transformers. Additionally, she has worked extensively in the development and design of new products used for condition monitoring of insulation systems, both periodical and continual. Vicki also actively participated in the development of multiple IEEE standards and guides and was Chair of the IEEE 43-2000 Working Group.

8

Maintenance Vol. 2

WHY YOU SHOULD USE THE GUARD CIRCUIT NETA World, Spring 2014 Issue James White, Shermco Industries, Inc.

WHAT’S IN A NAME? Every field technician knows what a megohmmeter is. Usually we just refer to it as a megger, although that’s like calling all tissue paper Kleenex or all copiers Xerox machines. The correct name is megohmmeter as Megger is a trademark. Whatever you want to call it, megger, insulation resistance test set, or megohmmeter, it is the most commonly-used insulation test set in the field. Small, lightweight, and relatively easy to use, various models of megohmmeters produce voltages from 250 to 15,000 volts so that the quality of insulation can be measured and trended. One of the problems in the common use of this little wonder is that the third terminal on the test set, known as the guard circuit, is rarely used because many people do not understand its function. Figure 1 shows a typical megohmmeter with a range from 500 volts to 5,000 volts. It is suitable for testing smaller insulation systems including motors, control wiring, instrument transformers, and small dry-type power transformers of up to about 15 kV, depending on the mass of the insulation system. A megohmmeter can also be used on larger transformers and liquid-insulated transformers, but typically an insulation power-factor test set is also used.

Fig. 1: Typical Megohmmeter with a guard circuit marked as Terminal G

VERIFYING INSTRUMENT FUNCTION At a customer’s site we were preparing to perform field testing of a small transformer as part of the training. The customer brought out his megohmmeter which looked as if it had been run over by a pickup truck. When asked if it worked, he proceeded to operate it, causing sparks to fly to the extent that I started looking for a fire extinguisher.

I suggested we try a simple test to see if it really worked. The megohmmeter, of course, had no output. The customer exclaimed that they had been using it for years and had always gotten good readings; no wonder! The test described below takes only a few minutes and will prove whether the megohmmeter actually works, and if it does, what its output voltage is. By the way, many thanks to Mark Lautenschlager for showing me this little trick many years ago. This test requires a volt/ohmmeter, such as a DVOM or even an analog VOM. I often use a Fluke or Simpson 260. The actual meter does not matter, but the input impedance should be known. All meters of this type use a resistor behind the input terminal. Less expensive meters may have an input impedance of just a few thousand ohms, while more expensive meters may have input impedances of 10 megohms to 20 megohms. Meters with high input impedances limit current flow through them, preventing problems when troubleshooting. In the example shown in Figure 2 the megohmmeter is connected from the “-“ terminal (marked as LINE) to the “-“ terminal of the VOM. The “+” (marked as EARTH) terminal on the megohmmeter is connected to the “+” terminal on the VOM. Those of us in our declining years remember using megohmmeters marked LINE and EARTH and assumed EARTH was the negative terminal. Actually, the negative terminal should be connected to the conductor under test and the positive terminal should be connected to ground.

Fig. 2: Megohmmeter test circuit figure courtesy American Technical Publishing from “A Technician’s Guide to Low- and Medium-Voltage Circuit Breakers” By James R. White A typical Fluke DVOM has an internal resistance of 10 megohms, while a Simpson 260 has 20 megohms. Connect the megohmmeter to the highest voltage terminal on the DVOM/VOM and set the megohmmeter output voltage to match. Do not exceed the DVOM/VOM’s

9

Maintenance Vol. 2 maximum voltage or you will get a brand new meter – at a cost, of course. In the example shown in Figure 2, a Simpson 260 is being used with a 1,000-volt maximum voltage rating. The megohmmeter’s output voltage is set to 1,000 volts and turned on. The DVOM/VOM should read 1,000 volts and the megohmmeter should read 20 megohms (or whatever the input impedance should be). As a double-check, reduce the output voltage from the megohmmeter to 500 volts. The DVOM/ VOM should read 500 volts, but the megohmmeter should still read 20 megohms. The input impedance will not change unless the terminal is changed to the 500 V input terminal on the DVOM/VOM as there is a different resistor behind that terminal. In the case of a Simpson 260 the 500 V terminal has a 10 megohms input impedance. Be aware that line and battery-powered megohmmeters will have voltage outputs close to their ratings, but hand-cranked megohmmeters will not. This is due to the clutch used on hand-cranked megohmmeters to limit their output. They will often have an output voltage of 90 percent to 95 percent of their rating. This does not affect the test, but can cause some concern if you are not ready for it.

WHAT DOES THE GUARD DO? The guard circuit is a means to eliminate unwanted return currents from the measurements being taken. It is very similar to the unmetered return on dc high-potential test sets. Any test current that returns via the guard terminal bypasses the measurement circuit. This allows a much more accurate measurement to be taken. There are two ways a guard can be used, by dividing the insulation system into smaller pieces and by eliminating surface leakage.

Fig. 4: Guards Daisy-Chained In Figure 4, not only are the bushings guarded from surface leakage, but the guard is also being used for testing the transformer. Multiple Guards can be tied together and any return current from the guard circuit is routed above the metering and not measured. At this point, you should be slapping yourself in the forehead and making a Homer Simpson-like sound. Circuit breakers can also benefit from using the guard circuit. When performing the dc overpotential or insulation resistance tests when humidity is high, using the guard can provide more accurate results. Figure 5 shows the guard circuit used when testing a circuit breaker. The guard collars are placed just below the primary disconnect (on the insulator), daisy-chained, then connected to the guard terminal. On a high potential test set, this would be the unmetered return terminal.

ELIMINATING SURFACE LEAKAGE Another very practical use for the guard circuit is to eliminate the effects of surface leakage on bushings. Figure 3 shows a bushing with a guard connected to a conductive collar located beneath the top petticoat. Any surface leakage current is now diverted above the meter by the guard. By daisy-chaining the collars around the bushings on the energized winding, all of the bushings can be guarded against surface leakage and a more accurate test can be made (see Figure 4). The conductive collars do not have to be the rubber collars included in the Doble® insulation power-factor test sets. Tie wire, screw-type hose clamps, or, in a pinch, aluminum foil, can be used. However, the closer the guard collar conforms to the surface of the bushing, the better.

Fig. 5: Using the Guard Circuit on a Circuit Breaker

SMALLER SECTIONS OF INSULATION EQUALS BETTER TEST RESULTS A two-winding transformer can be tested with or without using a guard. The standard test connections for testing a two-winding transformer are: ●● HV winding to LV winding and ground ●● LV winding to HV winding and ground Fig. 3: Guard Being Used to Eliminate Surface Leakage

●● LV winding and HV winding to ground

10

Maintenance Vol. 2

Note that the untested winding is connected to ground, not left floating. Why not leave the untested winding ungrounded? The energized winding will induce a charge into the untested winding and could present a safety hazard or affect the test results by discharging at some point during the test. Always ground the untested winding. When using a guard the connections are somewhat different. Any leakage current returning through the guard circuit is routed around the metering and is not measured. Figures 6, 7, and 8 illustrate the connections for using a guard when testing a twowinding transformer.

Fig. 8: High-voltage to low-voltage, ground guarded

THERE ARE GUARDS, AND THEN THERE ARE GUARDS

Fig. 6: High-voltage winding to low voltage and ground

There are two types of guard circuits that may be found on megohmmeters, the hot guard and the cold guard. The hot guard terminal on the megohmmeter is at or near line voltage, while the cold guard terminal is at or near zero volts. Why does this matter? The hot guard cannot be connected to ground, since it shorts out the meter. This means the high-to-low, ground guard test cannot be performed with a hot guard megohmmeter. The easiest method for determining whether your megohmmeter has a hot or cold guard circuit is to connect the guard to ground and turn on the megommmeter. If your meter goes to zero, you have a hot guard. An open meter reading (or one of these ∞) indicates a cold guard. Cold guard circuits require the use of an isolation transformer, so they will not be found on inexpensive megohmmeters.

SUMMARY

Fig. 7: Low-voltage winding to high-voltage and ground In Figure 6, the leakage current has two paths: from winding-towinding and then winding-to-ground. The guard is connected to the low-voltage winding, and any current to that winding is routed above the metering and is not measured. Only the current from the high-voltage winding to ground is measured. In Figure 7 the low-voltage winding is energized and any leakage current from the high-voltage winding is routed above the metering by the guard and is not measured. Figure 8 shows the winding-to-winding test. The guard is connected to ground, and the transformer is tested from the high-voltage winding to the low-voltage winding. Everything seems to be going swimmingly, but when the guard is connected to ground the meter reads zero. What’s up with that?

Guards are useful for testing most types of insulation systems. The next time an insulation resistance test is needed, think about the return paths and see if the guard can cut that insulation system into smaller pieces. If you are measuring lower insulation resistance values than you think should be read, use the guard to eliminate leakage from affecting the measurements. The guard can make your insulation testing a little easier and more accurate. James White is the Training Director for Shermco Industries, Inc. located in Irving, Texas. He is a Senior member of the IEEE, the recipient of the 2011 IEEE/PCIC Electrical Safety Excellence Award, the 2008 IEEE Electrical Safety Workshop Chairman, Alternate interNational Electrical Testing Association (NETA) representative on NFPA 70E®, Primary NETA representative on NEC Code Making Panel 13, Primary representative on NFPA 70B®, and is the Primary NETA representative to ASTM F18®. James is also a certified Level IV Senior Substation Technician with NETA, an inspector member of IAEI and serves on the NETA Safety and Training Committees. James is the author of Electrical Safety, A Practical Guide to OSHA and NFPA 70E and Significant Changes to NFPA 70E – 2012 Edition both published by American Technical Publishers.

11

Maintenance Vol. 2

TESTING ROTATING MACHINERY POLARIZATION/DEPOLARIZATION CURRENT (PDC) NETA World, 2014 Issue Vicki Warren, Iris Power LP The insulation resistance (IR) and polarization index (PI) tests [IEEE Std. 43-2000, ANSI/NETA ATS/MTS], should be done prior to application of any high voltage tests or return to service to assure that the winding is not wet or dirty enough to pose a risk of failure that might be averted by a cleaning and drying-out procedure. IR/ PI is a useful indicator of contamination and moisture on the exposed insulation surfaces of a winding, especially when there are cracks or fissures in the insulation. These tests are easily done (see NETA World Winter 2011 and Spring 2012 issues). Since squirrel cage induction motor rotor windings are not insulated, these tests are not appropriate. Resistance testing is principally a pass/fail criterion and cannot be relied upon to predict the condition of the main insulation except when the insulation has already faulted. Experience has shown that IR/PI is a useful indicator of contamination and moisture on the exposed insulation surfaces of a winding, especially when there are cracks or fissures in the insulation. However, as discussed in IEEE 43, the IR/PI test does not seem to be sensitive to many other stator winding insulation problems such as: ●● Loose coils in the slot that lead to insulation abrasion

THEORY The new draft standard (IEEE Std. 43 draft revision 2012) has an annex that deals with additional information that can be obtained by applying a stable dc voltage to a complete stator winding or individual phases for 1000 to 2000 seconds and recording the polarizing current IP versus time. The voltage is then removed and the discharge current ID is monitored as a function of time using a suitable discharge circuit. When the voltage is removed, reverse current flows and the molecules in the insulation become disorientated and the space charge dissipates. This discharge current ID has two main components: a capacitive discharge current component, which decays nearly instantaneously, depending upon the discharge resistance; and the absorption discharge current, which will decay from a high initial value to nearly zero with the same characteristics as the initial charging current but with the opposite polarity. Normally, neither the surface leakage IL nor the conduction current IG affects the discharge current. Differences in the IP and ID [Figure 1] may indicate winding lack of curing, moisture absorption, surface contamination, damage to the voltage stress coatings, or severe thermal deterioration of the bulk of the insulation.

●● Delamination of the insulation due to operation at high temperature ●● Separation of the copper from the groundwall insulation due to load cycling ●● Deterioration of the stress relief coatings ●● Partial discharge (PD) between coils in different phases due to insufficient spacing in the endwindings AC tests, such as partial discharge (described in NETA World Winter/Spring 2013) are effective in finding these issues, but are cumbersome to do in an offline configuration due to the need of a large ac power supply; therefore, more sophisticated dc tests that some have proposed may detect more kinds of problems than the simple IR/PI test. Included in the NETA World spring 2012 issue was a section about the dielectric response analysis (DRA) or polarization/depolarization current-measurement (PDC). This measures the charging and discharging currents of the winding insulation of stator or rotor winding. Reportedly, the results of the measurement provide information about the condition of machine insulation (cleanliness, humidity, ageing, corrosion, resin decomposition, and similar characteristics).

Fig. 1: Charging and Discharging Curves

EXAMINATION OF THE PDC TEST Since the IEEE 43 standard suggests that the PDC test is valid for testing windings for thermal deterioration, tests were done on a motor stator rated 13.2 kV, 6000 HP known to be thermally aged, but clean and dry. Both the PDC test and the ac offline partial discharge test were done, as the latter has proven to be effective for evaluating insulation delamination. The stator had an asphaltic mica

12

Maintenance Vol. 2

insulation system and was several decades old. The three phases in the stator could be isolated from each other to facilitate testing of each phase.

POLARIZATION/DEPOLARIZATION TEST For these tests, a PDTech DRA 3 was used to record the polarizing and depolarizing dc currents. It applies a positive dc voltage to the test object at a selected voltage (usually 5 or 10 kV for these experiments) and for a selected time (usually 1000 s – about 16.7 minutes), while measuring the charging current. The dc supply is then removed from the test object and the test object is grounded. The discharge current-to-ground is then measured for the same amount of time. Software records these currents, inverts the discharge current, and displays both the charge and discharge currents in the same plot against time, with the plot time origin starting from either the start of the charge cycle, or the start of the discharge cycle (Fig. 2). The difference in the charge and absolute value of the discharge current can also be displayed. The instrument also calculates the IR and PI. All tests were done at 20°C.

Fig. 3: LF PD plot for phase A, which had the highest PD at 8 kV. Note that the polarity of the PD plotted between 0 and 180 degrees has been inverted. The linear scale ranges from 0 to 11 nC.

Fig. 2: PDC plot for A-phase with a 10 kV charge cycle (other phases were identical). The charge current is the upper line and the discharge current is the bottom line. The logarithmic vertical scale goes from 0.1 μA to 1000 μA and the horizontal axis ranges from 1 to 1000 seconds.

Fig. 4: PD response from stator phase A, which had the highest PD at 8 kV.

PARTIAL DISCHARGE TEST

CONCLUSION

Partial discharge tests were conducted using a conventional IEC 60270 PD detector, a PDTech DeltaMaxx, working in the low frequency (T E S T 87L E nt e r i ng 87L T e s t Mode . S e l e c t T e s t : Cha r a c t e r i s t i c or L oopba c k ( C, L ) L oopba c k T e s t Cha nne l : ( 1, 2) L oopba c k Dur a t i on: ( 1- 60 mi nut e s )

? L ? 1 ? 5

Ar e y ou s ur e ( Y/ N) ? Y T he 87L e l e me nt i nhi bi t e d, a ddr e s s c he c k i ng ov e r wr i t t e n, T e s t i ng i s e na bl e d T y pe “ COM 87L ” t o c he c k t he l oopba c k s t a t us Wa r ni ng! Ct r l X doe s not e x i t t e s t mode T y pe “ T E S T 87L OF F ” t o e x i t

Fig. 8: Entering 87L Test Mode.

11

Protective Relay Vol. 2 During maintenance testing, for example, a technician can put the local relay into relay test mode via a front-panel pushbutton and put the 87L protection scheme into 87L test mode. The normal tripping output contacts will be isolated. Further, this disables 87L tripping at the local and remote terminals and allows element testing in the local relay using the specific testing output contacts. Remote relay backup elements, such as distance and directional overcurrent elements, remain functional.

87L Test Mode 1: Loopback Test A single relay and single test set can be used, either in the lab or in the field, to test an 87L element to a minimal degree. No working channel to the remote line terminal is available in this scenario. Therefore, the relay is tested with a loopback test, where the single relay transmit output is looped back to its own receive input (see Fig. 9). When a loopback test is active, the local relay ignores channel transmit and receive addresses to allow the 87L element to respond to the data it transmits. A loopback duration is added to prevent the relay from being stuck in loopback mode indefinitely. Alternately, a communications command can be used to disable loopback testing when complete. Test Set

V, I

Locally injected currents represent local and remote currents via an analog substitution used only during testing. Internally, the locally injected remote current is placed into an alignment table in the correct order for proper operation. Because local and remote currents are measured and phase magnitudes and angles can be independently controlled, the restraint characteristic of the 87L element can be fully tested 17 18. Differential and Alpha Plane restraint ratio (k) results are observed in metering commands for the element under test (see Fig. 10). Note that the angle of k is always displayed in positive degrees for simplicity. The idea for the single-terminal test comes from the fact that each of the phase elements does not require information from other phases in order to operate; the phases are segregated. Therefore, a particular phase (A, for example) can be chosen as the local test phase, and an unused phase (B, in this case of the 87LA element) can be used to simulate the current coming from the remote terminal (see Fig. 11). =>>ME T DI F Rel a y 1 S t a t i on R

87L

87L Communi c a t i on: Ma s t er 87L F unc t i on: Av a i l a bl e S t ub Bus : Di s a bl ed

Fig. 9: Loopback Test. Because any current injected into the local relay is measured as local and remote current, it is not possible to test restraint characteristics with a loopback test. There is no way to vary the angle of local and remote currents with respect to one another. The Alpha Plane in the differential metering is inactive during loopback tests. However, simple pickup sensitivity tests of the differential element can be performed; any current injected is viewed as operate or difference current. While loopback tests are not so good at checking the characteristics of the differential element in detail, they are handy for determining where a communications channel or network problem exists. Use all channel monitoring and statistics to determine root cause. In loopback mode, we physically apply an external loopback connection or condition. We can perform the loopback test at several points, such as at the relay terminals, at a local patch panel, at a local or remote multiplexer, and so on. The placement of the loopback at various locations allows testers to troubleshoot and isolate communications problems systematically.

87L Test Mode 2: Single-Relay Characteristic Test Another innovative testing scheme involves a single relay with no need for a working channel or loopback connection. Test currents are injected at one terminal with one test set. 87L test mode is used to specify and allow a single-relay characteristic test.

Da t e: 05/ 11/ 2012 T i me: 10: 42: 35. 698 S er i a l Number : 1111240304

MAG ( pu) ANG ( DE G) T HROUGH ( pu)

IA 1. 634 0. 00 1. 634

IB 0. 000 37. 44 0. 000

L oc a l T er mi na l 3I 0 3I 2 I1 IC 1. 634 1. 634 0. 545 0. 000 0. 00 0. 00 0. 00 37. 44 0. 000 0. 000 0. 000

MAG ( pu) ANG ( DE G) T HROUGH ( pu)

IA 6. 535 79. 97 6. 534

IB 0. 000 37. 44 0. 000

Remot e T er mi na l 1 3I 0 3I 2 I1 IC 6. 535 6. 535 2. 178 0. 000 79. 97 79. 97 79. 97 37. 44 0. 000 0. 000 0. 000

MAG ( pu) ANG ( DE G)

IA 7. 007 66. 70

IB 0. 000 37. 44

k a l pha ( DE G)

Al pha Pl a ne 87L C 87L B 87L A 1. 000 1. 000 0. 250 79. 94 180. 00 180. 00

Di f f er ent i a l IC 0. 000 37. 44

3I 0 3I 2 7. 007 7. 007 66. 70 66. 70 87L Q 0. 000 0. 00

87L G 0. 000 0. 00

Fig. 10: Operate and Restraint Quantities— Single-Relay Test. NORMAL TEST

Ia Ib

LOC

87L A

REM

To Trip Output To Test Output

NORMAL TEST

Fig. 11: Single-Relay Characteristic Test.

Remote Relays

12

Protective Relay Vol. 2

This methodology enables tests to be conducted using the 87L element logic in its entirety and allows testers to gain familiarity with the relay and prove scheme operation before a working end-toend channel is in place. A simple analog substitution table defines which terminal currents to use for specific differential element tests (see Table 1). 87L Quantity

Local IA

A

Local IB

B

Local IC

C

Q

G

IA

IA

IC

Remote IC

87L

87L

87L

IB

Remote IB

V, I

Fault Element IA

Remote IA

Test Set

IB

IB

IB

IC IA

Table 1: Single-Relay Analog Substitution When performing a characteristic test, specify the phase (A, B, or C) or sequence element (3I0, 3I2) under test and either normal or secure mode. Specifying the phase or sequence element eliminates confusion that can occur when multiple elements pick up and operate for the same test or fault condition. When in secure mode, the Alpha Plane restraint region becomes larger and the protection becomes more secure to protect against misoperation with extreme CT saturation during an external fault. No channel is required for a single-relay characteristic test. This testing method is therefore useful in the lab for settings and scheme testing, without need for a channel or even a second relay. If a channel is in place and working, remote terminals ignore locally injected test quantities based on a signal that is permanently keyed over the channel to all remote relays, which blocks the normal 87L element in those devices. Other protection functions, such as the distance elements, are free to operate at the remote terminals. Single-relay characteristic tests can also be performed at multiple terminals simultaneously.

87L Test Mode 3: Multiple-Relay Characteristic Test A third test mode involves multiple relays, one at each terminal of the line, and a working channel. This test can also be done in the lab, but still, a working channel is required. 87L test mode in the relay is used to specify and allow a multiple-relay characteristic test. Currents can be injected at one terminal with one test set or at multiple terminals at the same time (see Fig. 12). If testing is performed in the lab, a single test set can be used to simultaneously inject currents into multiple relays. By definition, the test signals provided to each relay from the common test source are synchronized; the current phase angles are absolutely referenced to one another.

Fig. 12: Multiple-Relay Characteristic Test With One Test Set. If the test is done in the field, satellite synchronization of the test sets must be used so that the current phase angles in different test sets are absolutely referenced to one another (see Fig. 13). Disturbance detection and watchdog logic dramatically improve the security of the 87L function. Disturbance detection requires that local and remote currents change before differential elements and transfer trip signals are acted on. Watchdog logic inhibits 87L tripping after a number of persistent close calls. Close calls are momentary pickups of the raw differential element without accompanying disturbance detection and can indicate significant channel or hardware problems. The watchdog logic has two levels. The first stage is correlated with channel activity in order to provide an actionable alarm to the user. When the counted illegitimate 87L pickup events are associated with the channel problems, the channel is suspected as the root cause and should be inspected. The second stage counts all unexpected 87L pickup events. Stage 2 inhibits only the 87L function and does not inhibit other local protection functions of the relay. Test Set

V, I

87L

Test Set

V, I

87L

V, I

Test Set

87L

Satellite Time

Fig. 13: Characteristic Test with Multiple Relays and Test Sets. While improving system security during real-world operation, these features complicate traditional, simple test methods. Ramping currents during testing can quickly generate many pickups and dropouts, increment the watchdog counters, and disable the 87L element. Without a specific 87L test mode, a communications command would be needed to reset watchdog counters, but this could become a tedious process after each test 19. Fig. 14 shows a traditional test where one terminal is held constant while another terminal is modified. This is an unrealistic power system fault simulation and will increment watchdog counters without 87L test mode.

13

Protective Relay Vol. 2

The Alpha Plane result defaults to 0 per unit at 0 degrees when the differential and restraint currents are nearly equal. The reason for this is that the (IRST – Ix) term in the denominator of the generalized Alpha Plane k calculation converges to zero for this condition and the calculation is therefore unsolvable. This is always the case when we use one injected current in a multiterminal test. When the differential current is less than 50 percent of pickup, the Alpha Plane is forced to 1 per unit at 180 degrees. This makes the relay more secure by forcing the relay to the ideal blocking point. Fig. 14: Unrealistic Power System Fault Simulations Require 87L Test Mode. When performing a multiple-relay characteristic test in 87L test mode, currents at one terminal can be held constant while currents at the other terminal(s) are changed. In 87L test mode, the relay ignores local and remote disturbance detectors and watchdog logic to allow simpler testing. While ramping one terminal current while holding another current constant does not simulate a realistic power system fault, it works well to test the 87L operate and restraint characteristics. The advantage to multiterminal testing is that the 87L protection can be treated as a complete system. It allows charging current compensation and in-line transformer functions to be tested as well. Multiterminal testing ensures that the communications system is running properly and that the dynamic behavior of the communication is reliable enough for the protection. Differential element metering can be observed. The operate and Alpha Plane restraint results are valid for the element under test. Fig. 15 shows a C-phase element under test, using multiterminal characteristic testing. =>>ME T DI F Rel a y 1 S t a t i on R

Da t e: 05/ 11/ 2012 T i me: 13: 59: 54. 456 S er i a l Number : 1111240304

87L Communi c a t i on: Ma s t er 87L F unc t i on: Not Av a i l a bl e S t ub Bus : Di s a bl ed

MAG ( pu) ANG ( DE G) T HROUGH ( pu)

IA 0. 001 - 88. 10 0. 000

IB 0. 000 2. 56 0. 000

L oc a l T er mi na l IC I1 3I 0 3I 2 0. 327 0. 109 0. 326 0. 328 120. 15 0. 00 - 119. 78 120. 21 0. 327 0. 327 0. 327

MAG ( pu) ANG ( DE G) T HROUGH ( pu)

IA IB 0. 000 0. 000 - 80. 87 - 118. 66 0. 000 0. 000

Remot e T er mi na l 1 IC I1 3I 0 3I 2 0. 409 0. 137 0. 408 0. 409 119. 57 - 0. 48 - 120. 47 119. 64 0. 408 0. 408 0. 410

MAG ( pu) ANG ( DE G)

IA 0. 001 - 86. 09

Di f f er ent i a l IB IC 3I 0 3I 2 0. 000 0. 736 0. 735 0. 737 - 120. 16 119. 89 - 108. 81 119. 83

k a l pha ( DE G)

87L A 1. 000 180. 00

87L B 1. 000 180. 00

Al pha Pl a ne 87L C 0. 000 0. 00

87L Q 0. 000 0. 00

87L G 0. 000 0. 00

Fig. 15: Operate and Restraint Quantities— Multiple-Relay Test.

Real-World Testing—No Use of 87L Test Mode The last method of testing the 87L element is by simulating a realistic power system event and not using 87L test mode at all. 87L test mode can be disabled if all relays at all terminals are available, the channel is working and available, and we have the ability to synchronously inject test signals into all relays simultaneously. Note that realistic test values must be injected. In other words, we cannot inject current into only one terminal to simulate a fault; on a real power system, all closed and in-service terminals would assert a disturbance detector during internal and external faults. Some testers will be philosophically opposed to using any sort of test mode. They may want to challenge the relay as it exists in service. This method can be used; however, problems can arise by using test sets at each end of the line that are not applying realistic test values (i.e., current is changed at one terminal only) or using test sets that are not perfectly synchronized. For example, the authors have witnessed problems with satellite-synchronized test equipment that does not turn off state simulations simultaneously. In these cases, the tester must reset the watchdog counters manually after each test. For multiterminal system testing, we apply signals at each end of the line simultaneously for complete system testing. Multiterminal testing verifies the overall performance of the relays and the associated channel equipment.

CONCLUSION Modern digital relays offer dramatic improvements in capabilities, sensitivity, speed, and security. Improvements include enhanced channel monitoring, satellite time-based time alignment, disturbance detection, the generalized Alpha Plane, external fault detection, adaptive characteristics, charging current compensation, in-line and tapped transformer compensation, watchdog counters, improved relay self-test diagnostics, and more. Security failures are rare. Still, every undesired operation is cause for concern. Three real-world cases are shared in this paper. In one, an SEU caused a misoperation; improved diagnostics and memory storage prevent this from reoccurring. In the second, a communications error produced a misoperation; disturbance detection would prevent this from reoccurring. In the third, another communications error produced a misoperation, in spite of disturbance detection being enabled; monitoring channel alarms and performance, in addition to allowing watchdog counters to disable the 87L element after a number of close calls, improves security.

14 As 87L protection has advanced, so have testing capabilities and requirements. Channel statistics and monitoring help diagnose problems more easily today. Loopback test mode allows channel problems to be pinpointed quickly and allows simple relay testing to be done without the need of a working channel. Full characteristic testing in the lab is allowed with new test modes, including the ability to substitute a locally injected current for a remote terminal current. Traditional, simple tests using ramped currents or changing currents at only one terminal are still allowed, but test mode must be used. If this is not done, disturbance detection and watchdog counters may log 87L element assertions without accompanying disturbance detection as close calls and eventually disable the 87L element. If real-world testing is preferred without altering settings or using special test modes, the tester must simultaneously inject realistic power system values into all terminals. If this is not done, disturbance detection and watchdog counters may log 87L element assertions without accompanying disturbance detection as close calls and eventually disable the 87L element.

Protective Relay Vol. 2 6

 . Alexander, D. Costello, B. Heilman, and J. Young, “Testing G the SEL‑487E Relay Differential Elements,” SEL Application Guide (AG2010-07), 2010. Available: http://www.selinc.com.

7

 . O. Schweitzer, III, D. Whitehead, H. J. Altuve Ferrer, E D. A. Tziouvaras, D. A. Costello, and D. Sánchez Escobedo, “Line Protection: Redundancy, Reliability, and Affordability,” proceedings of the 64th Annual Conference for Protective Relay Engineers, College Station, TX, April 2011.

8

 . Normand, “Single Event Upset at Ground Level,” IEEE TransE actions on Nuclear Science, No. 6, Vol. 43 (December 1996): 2742–2750.

9

 . E. Shannon and W. Weaver, The Mathematical Theory of ComC munication. Board of Trustees of the University of Illinois, 1998.

10

 . Ward and W. Higinbotham, “Network Errors and Their InfluS ence on Current Differential Relaying,” proceedings of the 64th Annual Conference for Protective Relay Engineers, College Station, TX, April 2011.

11

ACKNOWLEDGMENTS

 . Miller, J. Burger, N. Fischer, and B. Kasztenny, “Modern H Line Current Differential Protection Solutions,” proceedings of the 63rd Annual Conference for Protective Relay Engineers, College Station, TX, March 2010.

12

The authors wish to gratefully acknowledge Normann Fischer, Doug Taylor, Dale Finney, Brian Smyth, Héctor Altuve, Bogdan Kasztenny, and Bin Le for their assistance and contributions in developing this paper.

J . J. Kumm, M. S. Weber, E. O. Schweitzer, III, and D. Hou, “Philosophies for Testing Protective Relays,” proceedings of the 48th Annual Georgia Tech Protective Relaying Conference, Atlanta, GA, May 1994.

13

 . Zimmerman and D. Costello, “Lessons Learned From ComK missioning Protective Relaying Systems,” proceedings of the 62nd Annual Conference for Protective Relay Engineers, College Station, TX, March 2009.

14

 . Zimmerman, “SEL Recommendations on Periodic MainteK nance Testing of Protective Relays,” December 2010. Available: http://www.selinc.com.

As protective relay algorithms and capabilities adapt and evolve, so must the engineer, technician, and test practices.

REFERENCES 1

J . Roberts, D. Tziouvaras, G. Benmouyal, and H. Altuve, “The Effect of Multiprinciple Line Protection on Dependability and Security,” proceedings of the 55th Annual Georgia Tech Protective Relaying Conference, Atlanta, GA, May 2001.

2

 . Kasztenny, N. Fischer, K. Fodero, and A. Zvarych, “CommuB nications and Data Synchronization for Line Current Differential Schemes,” proceedings of the 38th Annual Western Protective Relay Conference, Spokane, WA, October 2011.

15

I . Voloh, B. Kasztenny, and C. B. Campbell, “Testing Line Current Differential Relays Using Real-Time Digital Simulators,” IEEE/PES Transmission and Distribution Conference and Exposition, Atlanta, GA, October 2001.

3

 . Benmouyal and J. B. Mooney, “Advanced Sequence EleG ments for Line Current Differential Protection,” proceedings of the 33rd Annual Western Protective Relay Conference, Spokane, WA, October 2006.

16

 . Lee, D. Finney, N. Fischer, and B. Kasztenny, “Testing ConK siderations for Line Current Differential Schemes,” proceedings of the 38th Annual Western Protective Relay Conference, Spokane, WA, October 2011.

4

 . Kasztenny, G. Benmouyal, H. J. Altuve, and N. Fischer, “TuB torial on Operating Characteristics of Microprocessor-Based Multiterminal Line Current Differential Relays,” proceedings of the 38th Annual Western Protective Relay Conference, Spokane, WA, October 2011.

17 A. Rangel and D. Costello, “Setting a Two-Terminal SEL-311L Re-

5

 . Zeller, A. Amberg, and D. Haas, “Using the SEL-751 and M SEL-751A for Arc-Flash Detection,” SEL Application Guide (AG2011-01), 2011. Available: http://www.selinc.com.

lay Application With Different Nominal Currents,” SEL Application Guide (AG2012-12), 2012. Available: http://www.selinc.com.

18  A.

Rangel and D. Costello, “Setting and Testing a Two-Terminal SEL‑311L Application With Different CT Ratios,” SEL Application Guide (AG2012-10), 2012. Available: http://www.selinc.com.

19

 . Zimmerman, “Viewing and Resetting the Watchdog Counters K in the SEL-411L Relay,” SEL Application Guide (AG2013-01), 2013. Available: http://www.selinc.com.

Protective Relay Vol. 2 Karl Zimmerman is a Regional Technical Manager with Schweitzer Engineering Laboratories, Inc. in Fairview Heights, Illinois. His work includes providing application and product support and technical training for protective relay users. He is an active member of the IEEE Power System Relaying Committee and chairman of the Working Group, “Tutorial on Application and Setting of Distance Elements on Transmission Lines.” He is also vice chairman of the Line Protection Subcommittee. Karl received his BSEE degree at the University of Illinois at Urbana-Champaign and has over 20 years of experience in the area of system protection. He is a registered Professional Engineer in the State of Wisconsin. Karl is a recipient of the 2008 Walter A. Elmore Best Paper Award from the Georgia Institute of Technology Protective Relaying Conference, a past speaker at many technical conferences, and author of over 40 technical papers and application guides on protective relaying. David Costello graduated from Texas A&M University in 1991 with a B.S. in Electrical Engineering. He worked as a system protection engineer at Central Power and Light and Central and Southwest Services in Texas and Oklahoma and served on the System Protection Task Force for ERCOT. In 1996, David joined Schweitzer Engineering Laboratories, Inc. as a field application engineer and later served as a regional service manager and senior application engineer. He presently holds the title of technical support director and works in Fair Oaks Ranch, Texas. David has authored more than 30 technical papers and 25 application guides and was honored to receive the 2008 Walter A. Elmore Best Paper Award from the Georgia Institute of Technology Protective Relaying Conference. He is a senior member of IEEE, a registered professional engineer in Texas, and a member of the planning committees for the Conference for Protective Relay Engineers at Texas A&M University, the Modern Solutions Power Systems Conference, and the I-44 Relay Conference.

15

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Protective Relay Vol. 2

WHY APPLY PROTECTIVE RELAYS? PowerTest 2013 Karl Zimmerman, Schweitzer Engineering Laboratories, Inc.

“Protective relaying is a vital part of any electric power system: unnecessary during normal operation but very important during trouble, faults, and abnormal disturbances. Properly applied protective relaying initiates the disconnection of the trouble area while operation and service in the rest of the system continue.” —January 1987; J. Lewis Blackburn

ABSTRACT Protective relays have been applied for decades. During this time, most of the basic functions and applications have not changed a great deal. Protection is still required to detect faults and electrical disturbances to safely and securely isolate the affected part of the power system. One of the most important advancements of the past 25 years is event data provided by relays and with them, the ability to discover root cause of power system disturbances. In this paper, we show a basic approach to analyzing field data and then show several real-world events and practical solutions that improve the safety and reliability of the power system. We also show how advancements in technology produce challenges in applying and testing protection systems.

PHILOSOPHY OF SYSTEM PROTECTION In general, the basic objective of system protection has not changed. In short, it is to isolate the problem area of the power system as quickly as possible, while allowing the rest of the power system to remain in service. Protective relays measure the system parameters (usually voltage and/or current) and work together with circuit breakers and other circuit interrupters to isolate faulted or damaged portions of the power system. The foundational principles of protection are the following: ●● Reliability. In protection, reliability has two parts: security and dependability. Security is the degree to which protection does not operate incorrectly. Dependability is the degree to which protection operates correctly. Both security and dependability are important, and protection engineers must weigh the advantages and disadvantages of each when selecting and applying relays. ●● Selectivity. Selectivity maximizes the availability of the power system. For example, Figure 1 shows a system one-line diagram with many power system components. Each component is subdivided into a zone of protection, highlighted for the generator, transformers, a bus, a motor, a capacitor, and several lines. In practice, protection systems are designed to operate the breakers that isolate only the part of the system affected by the problem. ●● Speed of operation. Protection is designed to operate as quickly as possible, as long as it does not compromise the security of the power system. Many relays operate within 1 or 2 cycles

1

(e.g., differential protection relays), and others operate with a time delay (e.g., inverse overcurrent relays that must coordinate with downstream fuses). In Figure 2, the relay Zone 1 distance element (M1P) asserts in about 1 cycle, and the total clearing time is under 4 cycles. ●● Simplicity. Protection should be as straightforward as possible and include only what is necessary. For example, microprocessor-based relays provide many benefits to the protection of the power system and significantly reduce and simplify wiring compared with traditional relays, but may require more settings. If we evaluate only protection functions, for example, adding up all the discrete relays and settings and comparing them with the settings of a microprocessor-based relay, the actual number of settings is similar. However, adding more functions (programmable logic, communications ports, supervisory control and data acquisition [SCADA], IEC 61850 Sampled Values and/or Generic Object-Oriented Event [GOOSE] messages, metering, monitoring, satellite time synchronization, synchrophasors, and so on) results in adding more settings and complexity. Engineers should evaluate all of the factors.

Ring Bus

Generator

Plant Distribution Feeder

Transformer

Transmission Line Bus

Motor

Single Bus Distribution Lines

Transformer Capacitor

Fig. 1: Example Power System One-Line Diagram with Several Zones of Protection

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Protective Relay Vol. 2

Fig. 2: Instantaneous Trip for Transmission Line Fault The challenge for protection engineers and technicians is to weigh all of these factors, while also considering the life-cycle cost of the protection (installation, maintenance, and so on) in light of the cost of repairing or replacing the protected lines and apparatus, if protection is not applied or reduced. Protection is not called upon to operate very often, but can pay for itself with one fault, if the protected equipment is isolated properly. Moreover, newer relays have greatly improved the ability to find root cause when faults and electrical disturbances do occur, as discussed next.

Fig. 3: Event Report Capture of an Evolving Fault on a Distribution Feeder This detailed information allows users to have an excellent understanding of the fault, which would have been impossible in the past. In addition, engineers and technicians have discovered and corrected countless numbers of wiring, setting, and application errors through event report analysis during commissioning. Fortunately, many technical specialists are using improved testing and commissioning practices, resulting in an increasing number of problems found before relays are placed into service 2.

THE EVENT REPORT

ADVANCEMENTS IN PROTECTION

Of all the advancements in the protection industry the past 25 to 30 years, perhaps the one with the most impact is the ability of relays to take a snapshot of the power system during a disturbance or fault. Older electromechanical and solid-state relay designs performed the actual protection task admirably, but it was often difficult or not possible to determine the cause of failure for many power system disturbances. Microprocessor-based relays that produce event reports now provide engineers the ability to identify root cause of operations on nearly 100 percent of system occurrences. It has truly been a revolution in improving the safety and reliability of power systems and providing data, not only for postfault analysis, but for actually preventing problems during testing and commissioning.

In addition to determining root cause for system events and during commissioning, relay designers have used the lessons learned and new technologies to dramatically improve protection and control.

Figure 3 shows a screen capture of an evolving fault on a distribution line. In this event, we see the fault start out as an A-phaseto-ground fault, then evolve to an A-phase-to-B-phase-to-ground fault, then to a three-phase fault. We can see the zero-sequence current (IGMag) increase initially and cause the ground overcurrent element (51G) to pickup and start timing toward trip. Then, when the fault evolves, IGMag decreases and eventually drops close to nearly zero for the three-phase fault. The phase overcurrent (51P) stays picked up the entire time.

●● Adaptive relay settings on distribution relays for cold load inrush, feeder switching, or distribution automation.

The improvements include the following: ●● Settable transformer differential protection to allow flexible application for varying power transformer connections, current transformer (CT) ratios, and grounding practices. ●● Motor protection using adaptive elements that emulate the thermal characteristics of the motor. ●● Directional elements that have better sensitivity to detect high-resistive faults.

●● Programmable time-overcurrent characteristics to allow better coordination between distribution protection devices. ●● Light sensing in protection schemes to detect arc-flash events. ●● Improvements in security for differential protection to avoid operations for external faults due to CT saturation without losing the ability to detect internal faults. ●● Addition of disturbance detection to supervise high-speed tripping.

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Protective Relay Vol. 2

All of these advancements and innovations contribute greatly to the improvement of system protection. At the same time, new technologies create challenges in keeping up with the changes of how to properly apply, set, test, and commission these relaying schemes. In the following subsections, we highlight three protection advancements and the challenges to engineers and technicians who apply them.

Directional Elements Detect High-Resistance Faults In the event shown in Figure 4, a utility crew was installing new structures for a 115 kV line on an existing right of way. One of the trucks was in close enough proximity to the in-service transmission line to cause a flashover. One of the line terminals took approximately 55 cycles to clear the fault while personnel were in a truck engulfed in the fault. Even though the fault was close in, the relay did not pick up on its Zone 1 or Zone 2 distance elements. Figure 4 shows the phasors. In this case, the relay used the Zone 2 distance elements in a permissive overreaching transfer trip (POTT) scheme with only overreaching phase and ground distance set to trip.

where: 45

135

Re[V2•(1 Z1ANG•I2)*]

|I2|2

(1)

V2 is the measured negative-sequence voltage. I2 is the measured negative-sequence current.

IC

Z1ANG is the positive-sequence line angle. VB(kV)

180

IA

225

In 1993, the directional element referenced in Figure 5 using the calculated negative-sequence impedance was introduced that lies collinearly to the protected positive-sequence line impedance. Z2measured=

90

VA(kV)

Fig. 5: High-Resistance Fault Would Have Been Detected by Ground Directional Overcurrent Element

VC(kV)

IB

0

315

270

* indicates complex conjugate. In practice, a forward fault yields a Z2measured equal to –ZS2 (the source impedance behind the relay). A reverse fault yields a Z2measured equal to ZL2 + ZR2 (the line impedance plus the remote source impedance). This is shown graphically in Figure 6. The relay compares Z2measured with thresholds ZR2 (reverse) and ZF2 (forward) to declare whether the fault is forward or reverse.

Fig. 4: Fault Currents and Voltages During the HighResistance Fault on a 115 kV Line A more sensitive relay (specifically, a ground directional overcurrent relay), if applied, could have detected this fault and reduced the trip time to nearly instantaneous tripping. Ground overcurrent elements are comprised of two main components: an overcurrent (50) threshold and a directional element (32) to torque control the overcurrent element. Figure 5 shows a screen capture of the zero-sequence current magnitude (IGMag) and the directional element (32QF) that would have asserted and cleared this fault, if applied. Fig. 6: Measured Negative-Sequence Impedance Yields Fault Direction

19

Protective Relay Vol. 2 Similarly,3 provides more evidence of the need for improved sensitivity through a case study of a 500 Ω fault on a 525 kV transmission line in Brazil. The cause of the fault was a flashover from the transmission line to trees near a river crossing. There was practically no voltage dip on the faulted phase, and with such high fault impedance, the angular difference between the faulted phase voltage and current was less than 10 degrees, as shown in Figure 7.

tic implementation, as shown in Figure 9. The minimum operate threshold is defined by a pickup setting (O87P). When the magnitude of the restraint quantity is greater than IRS0 and less than IRS1, the relay operates based on the Slope 1 (SLP1) setting. When the magnitude of the restraint quantity is greater than the setting IRS1, the operating characteristic changes from Slope 1 to Slope 2 (SLP2). Iop (pu)

90 U87P

135

VC(kV)

45

87R Restrained Element Operate Region SLP2

IC(A) IA(A) VA(kV)

180

SLP1

0

Restraint Region O87P

IG(A)

IRS0

VB(kV) 225

IRS0 =

315

IB(A)

Irst (pu)

IRS1

O87P • 100 SLP1

270

Fig. 9: Dual-Slope Differential Characteristic

Fig. 7: Voltage and Current Phasors for 525 kV BG Fault with 500 Ω Fault

When testing this element, we can use steady-state currents in the winding inputs to determine whether the relay is performing within its specification. To test the minimum pickup, the restraint current must be less than IRS0. To test SLP1, the restraint must be within IRS0 and IRS1. To test SLP2, the restraint current must be greater than IRS1. Test U87P by applying an operate current, regardless of restraint current.

Figure 8 shows a screen capture of the directional overcurrent element (67G2) asserting and producing a trip for this fault.

Next we consider one of the challenges of current differential protection: the impact of CT saturation. Figure 10 shows a fault external to the zone of protection. Ideally, all of the CTs (CT-1, CT-2, and CT-3) perform well and produce a replica of the primary current to the relays. Strong Source CT-1

Power Transformer

Remote Source CT-3

CT-2

Fig. 8: Directional Overcurrent Element (67G2) Detects 500 Ω Fault Challenge: Testing the thresholds for this directional element challenges the technician to be more proficient in understanding symmetrical components to generate proper test values and to understand how these elements torque control directional overcurrent elements.

Adaptive Slope Characteristic Many current differential relays use a dual-slope characteris-

Fig. 10: External Fault Produces Through-Fault Current However, if the fault current is severe enough, it is possible for CT-2 to saturate, as shown in Figure 11. This could produce a false differential (operate) current and could lead to a misoperation. The false differential current occurs in the secondary CT circuit but is shown on the primary side in Figure 11 for illustrative purposes. This is why many relay designs offer a higher slope characteristic with higher restraint currents.

20

Protective Relay Vol. 2 Strong Source CT-1

Power Transformer

Remote Source CT-3

CT-2

CT-2 saturates, causing false differential current

An example of why this is important in the power system was observed in an actual system fault, as shown in Figure 14. A feeder relay and transformer differential relay both operated, which started an investigation of the event reports. The initial report from the field was that a transformer differential relay incorrectly tripped for an external feeder fault. However, after examining the event reports, the fault turned out to be an external feeder fault that evolved into an internal differential zone fault.

Fig. 11: External Fault Causes CT-2 to Saturate There have been instances where, even with the higher Slope 2, differential relays have misoperated 4. Figure 12 shows a case where a current differential relay operated incorrectly due to CT saturation.

Simultaneous Faults?

87

50/51

Fig. 14: Transformer Relay and Feeder Relay Operate for Fault If we examine the feeder relay screen capture in Figure 15, we observe that the C-phase voltage decays as the C-phase current increases. About 1 cycle later, the B-phase voltage decays. Fig. 12: Current Differential Element (87U) Operates for External Fault During Severe CT Saturation As a result, relay designers have developed a scheme whereby the relay dynamically switches between SLP1 or SLP2, depending on fault-sensing logic, as shown in Figure 13. This allows increased security for external faults, without sacrificing sensitivity for internal faults. Iop (pu)

U87P 87R Restrained Element Operate Region

SLP2

Fig. 15: Simultaneous Faults SLP1

Restraint Region

O87P IRT2 IRT2 =

Irst (pu)

IRT1

O87P • 100 SLP2

IRT1 =

O87P • 100 SLP1

Fig. 13: Adaptive Slope Characteristic

This is hard to comprehend until we see a photograph of the substation, shown in Figure 16. The differential zone bus work is physically above the feeder bus work, so when the C-phase-toground fault occurred on the feeder, the energy of the flash caused the B-phase on the differential zone to flash over.

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Protective Relay Vol. 2

Fig. 16: Distribution Substation Shows Transformer Zone Bus Work Physically Above Feeder Bus Work In order to demonstrate this, we performed some post-fault analysis, asking what might happen if we applied the adaptive slope characteristic relay from Figure 13. Figure 17 shows the restraint currents (IRTA, IRTB, and IRTC) increase before the operate currents (IOPA, IOPB, and IOPC) and the control bits CONA and CONC assert. This switches the relay to Slope 2 but still allows a differential trip (87RB, 87RC) when the fault evolves to an internal fault.

Fig. 18: Overcurrent and Light Sensors Together Produce Lower Fault Clearing Times Challenge: Testing and commissioning the arc-flash combined light and current element requires testing the light-sensing fiber cables and sensors, along with conventional current injection to validate the performance of the scheme 9. This discussion highlights just three significant advancements in technology that affect relay engineers and technicians, but almost all protective relaying applications are changing. For example, many motor protection relays may require testing a thermal element that emulates the thermal characteristic of the motor 10; some line current differential relays employ a test mode, which allows characteristic testing from a single end of the line; and virtually all relays are programmable multifunction devices that have multiple elements directed to produce a trip output.

CONCLUSIONS Fig. 17: COMTRADE Playback of Evolving Fault Through Adaptive Slope Characteristic Relay Challenge: Testing current differential relays with an adaptive characteristic, as found in many new bus and transformer differential relays, requires a new approach to testing. In order to validate the precise threshold of Slope 2 (SLP2), we now must perform dynamic state simulation, whereby we apply an external fault initially to force the relay into the higher security SLP2 setting, then switch to an internal fault within a few cycles 5.

When we ask, “Why apply protective relays?,” we recognize that the basic philosophy of protection, reliability, selectivity, simplicity, and speed, are all still very similar to what they were 50+ years ago. It is sometimes easy to reminisce about the good ol’ days of protection, when all relays were single function devices and could be easily isolated and tested. But while we look back to keep perspective, we should recall the complexity of external wiring required in the electromechanical relay panels built in the past decades, such as the one shown in Figure 19.

Arc-Flash Mitigation: Using Overcurrent and Light Sensing Together Personnel safety regarding arc-flash hazards has always been of utmost concern to engineers 6 7. In recent years, protection engineering and philosophy has moved beyond solely the protection of electrical power lines and apparatus to how protection can improve personnel safety by mitigating arc-flash hazards 8. Relays can now be applied using light sensors and fiber cables within switchgear to detect an arc-flash event. Figure 18 shows an event capture with the overcurrent and light sensors. Note that the combined overcurrent and light element (50PAF) operates in 0.25 cycles.

Fig. 19: Electromechanical Relay Panel

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Protective Relay Vol. 2

The invention of the relay event report has created a new ability and, now, expectation to find root cause of virtually every power system disturbance. Data found in event reports can assist in commissioning to prevent problems before they occur. We can debate whether testing modern relays is easier or more difficult but, at the very least, the shift in complexity requires a modern technician to have a stronger understanding of protection fundamentals such as symmetrical components, good computer literacy, and a broad command of test equipment capabilities. Moreover, a modern technician needs to adapt to the challenges that new and changing technology brings.

D. Costello, “Lessons Learned Through Commissioning and Analyzing Data From Transformer Differential Installations,” proceedings of the 33rd Annual Western Protective Relay Conference, Spokane, WA, October 2006.

Regardless of advancements, do not overlook the following fundamentals:

7 NFPA

●● Make documentation complete and up to date. ●● Perform as many tests in the laboratory as possible ●● Create thorough checklists for commissioning. ●● Use peer reviews for test plans and work performed. ●● Perform primary and secondary current and voltage injection when appropriate. For example, when testing power transformers, budget time and resources to perform primary injection of current signals to test transformer differential relay settings and CT ratios and connections for both three-phase and single-phase events. ●● Test inputs and outputs, including dc control wiring and communications links. ●● When developing test plans, say what you do, and do what you say. ●● Invest in training. ●● Make commissioning a separate line item for budgeting and planning. ●● Go beyond compliance and ask questions. Lessons learned from system operations, advancements in processing capability, and overall technological advancements have led to many industry changing improvements. It is a challenge for relay professionals to stay current with new and changing technology, but the best advice is to “stay curious, my friends.”

REFERENCES J. L. Blackburn, Protective Relaying Principles and Applications, 1st ed. Marcel Dekker, Inc., New York, NY, 1987. 1

2 K.

Zimmerman and D. Costello, “Lessons Learned From Commissioning Protective Relaying Systems,” proceedings of the 62nd Annual Conference for Protective Relay Engineers, College Station, TX, March 2009. 3 P. K. Maezono, E. Altman, K. Brito, V. A. dos Santos Mello Maria,

and F. Magrin, “Very High-Resistance Fault on a 525 kV Transmission Line – Case Study,” proceedings of the 35th Annual Western Protective Relay Conference, Spokane, WA, October 2008.

4

5 G. Alexander,

D. Costello, B. Heilman, and J. Young, “Testing the SEL-487E Relay Differential Elements,” SEL Application Guide (AG2010-07), 2010. Available: http://www.selinc.com. IEEE Standard 1584-2002, IEEE Guide for Performing ArcFlash Hazard Calculations. 6

70E®: Standard for Electrical Safety in the Workplace®, 2004 Edition. 8 J.

Buff and K. Zimmerman, “Application of Existing Technologies to Reduce Arc-Flash Hazards,” proceedings of the 60th Annual Conference for Protective Relay Engineers, College Station, TX, March 2007.

M. Zeller, A. Amberg, and D. Haas, “Using the SEL-751 and SEL-751A for Arc-Flash Detection,” SEL Application Guide (AG2011-01), 2011. Available: http://www.selinc.com. 9

G. Alexander and S. Patel, “Testing the Thermal Model in the SEL-710 Motor Protection Relay,” SEL Application Guide (AG2011-12), 2011. Available: http://www.selinc.com.

10

Karl Zimmerman is a Regional Technical Manager with Schweitzer Engineering Laboratories, Inc. in Fairview Heights, Illinois. His work includes providing application and product support and technical training for protective relay users. He is an active member of the IEEE Power System Relaying Committee and chairman of the Working Group, “Tutorial on Application and Setting of Distance Elements on Transmission Lines.” He is also vice chairman of the Line Protection Subcommittee. Karl received his BSEE degree at the University of Illinois at Urbana-Champaign and has over 20 years of experience in the area of system protection. He is a registered Professional Engineer in the State of Wisconsin. Karl is a recipient of the 2008 Walter A. Elmore Best Paper Award from the Georgia Institute of Technology Protective Relaying Conference, a past speaker at many technical conferences, and author of over 40 technical papers and application guides on protective relaying.

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Protective Relay Vol. 2

WHY WE SHOULD MEASURE LINE IMPEDANCE? PowerTest 2013 W. Knapek, OMICRON electronics, USA U. Klapper, OMICRON electronics GmbH – Austria

ABSTRACT The paper analyzes the impact of errors in the line impedance parameters on the accuracy of the short circuit currents and voltages calculation, the settings of the distance and overcurrent relays and the fault clearing times for different line lengths and fault locations. The accuracy of the fault location calculation is also affected. This paper explains the difficulty of k-Factor settings and points out cost effective solutions for preventing incorrect behaviour of distance protection schemes. The inaccurate values of the mutual coupling of parallel transmission lines are another important factor that may affect the operation of the relays for faults involving ground. This is also discussed in the paper. Actual measurement of the fault-loop impedance is the best way to ensure that the distance and overcurrent relay settings are correct. The second part of the paper describes an advanced method for these measurements and calculations that provide the impedance data for the different applications that use it. Comparisons of estimated and measured line impedances are presented at the end of the paper.

The transmission line impedances used for short circuit currents calculation and the setting of distance relays are normally derived from the results of a line constants program calculation or systems studies. Due to the large number of influencing factors (e.g. wire types, spiraling and average sag of the wires, shield handling on cables, specific soil resistivity) these calculations can be prone to error. Actual measurement of the fault-loop impedance is the best way to ensure that the distance and overcurrent relay settings are correct. The second part of the paper describes an advanced method for these measurements and calculations that provide the impedance data for the different applications that use it. Comparisons of estimated and measured line impedances are presented at the end of the paper. Measuring mutual coupling between power lines can be done using a similar method.

IMPORTANCE OF K-FACTORS

INTRODUCTION

To protect an overhead line or a power cable protective relays are needed. When a fault occurs on the line, such as an arc between phases or against ground, it has to be cleared safe, selective and fast. Selectivity means that the line is only switched off, if the fault is really on this very line 1.

The performance of transmission line protection relays when a fault occurs in the system is important for improvements in the stability of the system and reduction of their effect on sensitive loads. Reducing the fault clearing time for more possible fault conditions is one of the main goals in the development, application and setting of such relays.

There are two basic methods to obtain selectivity on power lines, differential protection or distance protection. The better principle is the first one, but there is by far more effort involved, because the relays on both ends of the line need to communicate with each other. This paper does not further discuss this method. For cost reasons on most power lines distance protection relays are used.

The operating time of a transmission line protection relay is a function of many different factors. Some of them are related to the operating principle and the design of the relay itself. The paper analyzes the impact of errors in the line impedance parameters on the accuracy of the short circuit currents and voltages calculation, the settings of the distance and overcurrent relays and the fault clearing times for different line lengths and fault locations. The accuracy of the fault location calculation is also affected. This paper explains the difficulty of k-Factor settings and points out cost effective solutions for preventing incorrect behaviour of distance protection schemes.

One of the most important settings of a distance protection relay is the Positive Sequence Impedance, which is half of the complex impedance of the phase to phase loops (Figure 1).

The inaccurate values of the mutual coupling of parallel transmission lines are another important factor that may affect the operation of the relays for faults involving ground. This is also discussed in the paper.

Fig. 1: Impedance loop between two phases

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When a fault occurs the distance relays on both ends measure the impedance. If the impedance is (typically) below 80% or 90% of the line impedance they switch off as fast as possible (zone 1), because it is for sure that the fault is on this very line. If the impedance is higher the relay switches off delayed (≥  zone  2), to give another relay that might be closer to the fault the chance to clear it first.

in zone 1 and trip, a second power line is dead. The customer lost power for no reason. Besides the damage of customers having no power, the risk of loosing system stability becomes also higher by such false trips.

On faults of one or more phases against ground, the impedance of the fault loop is different (Figure 2). Because the impedance of the ground path, or to be more precise, of this ground loop, is different, a factor within the relay gives the relation between the line and the ground impedance. This factor is called ground impedance matching factor or simply k-factor, as it is often referred to.

Unfortunately the k-factor does not exist. There are various formats out there; the three major types are discussed here. For all types it is to say that they are constants of the line, in general independent from the length. They express the relationship of the impedance of a phase-to-phase loop and a three-phase-to-ground loop. Half of a phase-to-phase loop (i.e. the impedance of one line) is referred to as Positive Sequence Impedance (Z1); three times the impedance of a three phase to ground loop is referred to as Zero-sequence Impedance (Z0).

DIFFERENT K-FACTOR FORMATS

One common format is the complex ratio of the Zero-sequence Impedance and the Positive Sequence Impedance. (1) Z0

k0 =

Z1

Because Z1 is the impedance of one line it is also referred to as ZL quite often. (2) Fig. 2: Impedance loop on a single phase ground fault If the relay settings are done properly a customer that is supplied from two ends (Figure 3) continues to receive energy from one line if the other trips.

ZL = Z1

The ground (or British “earth”) impedance ZE can be calculated from the Zero-sequence Impedance as follows: Z0 – ZL ZE = 3

Fig. 3: Relays with optimum zone 1 reach If the impedances or k-factors of a relay are not set properly, zone over- or under-reaches will occur (Figure 4).

(3)

Defining the ground impedance this way, obviously leads to strange results with a negative inductive component in ZE, as soon as the three-phase-to-ground inductance is much smaller than the inductance between two phases. This is the case on some power cables when the shield is close to the conductors but the conductors are relatively far from each other. This fact is of no further concern; it is just good to know that it can happen. Another possibility to express the relationship is the ratio of ground-to-line impedance. (4)

kL =

ZE ZL

kE or sometimes referred to as k0 are other common names for this definition. One has to be careful how a k-factor is defined before using it.

Fig. 4: Relays with zone 1 over-reach In the example above three relays instead of two see the fault

Splitting the complex impedances ZE and ZL into their real and imaginary parts R and X defines real ratios, this leads us to the third commonly used definition. (5, 6)

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RE X — and —E RL XL

(7)

Conversions between the different k-factor formats are possible. (8)

k 0 = 1 + 3k L

For converting from the format (5) and (6) to the other formats the other line constants (or at least the line angle) have to be known. kL =



RE/RL XE/XL ________ + _______ 1+jXL/RL 1–jRL/XL

(9)

The line angle can be used to obtain the ratio XL / RL that is needed for the conversion in (8). Distance protection relays use algorithms that make use of these different k-factors to convert all phase-to-ground faults, so they can be assessed as if they were phase-to-phase faults. This allows using the same zone polygons independent from the line geometry. Because different relays can use different algorithms, identically measured voltages and currents may lead to different calculated impedances depending on the algorithm used. Details of these algorithms 2 are not further discussed in this paper; it is only to mention that the entry format of the k-factor does not allow deducing which algorithm is used by the relay.

CALCUALTION OF K-FACTORS Up to now the effort to measure line impedances and k-factors was so great that it has hardly been done. To obtain this data it had been calculated manually using physical constants, or by using appropriate software tools 3 like PowerFactory from DIgSILENT, PSS from Shaw PTI or CAPE from Electrocon, to name a few. The parameters needed to calculate the line impedance are many. The geometrical configuration is needed (Figure 5): ●● height above ground and horizontal distance for each phase conductor and each ground wire ●● average sag of the line and ground wires at mid-span

Fig. 5: Overhead line geometry

Several electrical parameters have to be known: ●● ground/soil resistivity ●● DC resistance of all conductors ●● spiralling construction of the conductors ●● geometrical mean radius of the conductors ●● overall diameter of the conductors Similar parameters are needed for calculating line impedances of power cables; on a first glance they might seem even simpler, but as this may be the case for new cables it might be the opposite for old installations where often a mixture of different cable types is used – and not documented too well either. In general it can be said that the calculation of the Positive Sequence Impedance works quite well and in general sufficient for the Zero-sequence Impedance as long as the ground or ground wire is a consistent good one. When the ground wire or shield is not a very good conductor and a large component of the fault current is flowing back through the soil, things tend to become complicated. The influence of the ground/soil resistivity, pipes, other buried metal structures, and the accurate distance of the wires above ground, make it very difficult to determine the impedance along the whole length of the line (especially in complicated landscape geometry and multiple infrastructure crossings). Another cause for concern is that a huge number of parameters are involved in the calculation of line parameters. If one parameter is wrong this might cause a substantial error. In the Positive Sequence Impedance there are several, but even more prone to error is the Zero-sequence Impedance or k-factor, because they need accurate parameters for their calculation. On several occasions when our team found incorrect relay settings it was the Zero-sequence Impedance or the k-factor that was in error. But we also had the situation that two similar lines were just mixed up.

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MEASUREMENT OF K-FACTORS

Compared to the effort for accurate calculations, the actual measurement of line parameters including the k-factor is today relatively simple. The measurement of the line impedance requires the use of specialized equipment that includes several components: ●● test set comprising a frequency variable amplifier ●● signal coupling unit ●● ground protection device

Fig. 6: Test equipment for line Z measurement

The measurement is performed with currents between 1 and 100A depending on the line length. Using frequency selective measurement allows using injected currents a fraction of the size of the nominal currents. To ensure high accuracy of the measurement the highest current range for the given line length is chosen. Measurements on lines up to 270km (123 miles) have been performed so far. Overall seven measurements per system are made, three for each combination of phase to phase loops, three for each phase against ground and one for all three phases against ground. There is some redundancy in these measurements, allowing reliability crosschecks and calculation of individual k-factors for each phase. The latter seems strange at a first glance, but especially for short lines having a symmetrical line is not a priority, leading to very different values for the phases. This results in smaller k-factors and avoids zone overreaches in most cases. The actual measurement results can be loaded into Microsoft Excel allowing easy post processing; the results are displayed in a format for direct usage in relay settings (Fig. 7).

The test set used for the line impedance measurements is multi functional, frequency variable device for various tests on primary equipment. It may be required to generate currents up to 800A or voltages up to 2000V. Support for various automated tests on CTs, VTs, power transformers or other primary equipment is necessary to improve the efficiency of the primary testing process. In the application of line impedance measurement it is used as a frequency variable power generator, measurement tool and analyzer. Due to the variable frequency generation it is possible to generate signals first below then above mains frequency. Using a digital filter algorithm allows measuring frequency selective at the frequency that is currently generated, this means all other frequencies but the generated one are filtered out. Any disturbances at the mains frequency from nearby equipment or lines are therefore ignored during the testing. The coupling unit is used for galvanic decoupling of the generated signals in the output direction and analyzed signals in the input direction. The decoupling is needed mainly for safety reasons. For optimization of the performance it is an advantage to have a range selector switch and a built in voltmeter for a quick check of any induced voltages or high burdens. The protection device is a safety tool for easy connection to the overhead line or power cable. Existing grounding sets of the substation may be used. In case of unexpected high voltage on the power line due to faults on a parallel system, lightning discharges or transients due to switching operations, the protection device should be capable of discharging short transients or permanently shorting fault currents of up to 30kA for at least 100ms. These safety features are necessary to allow the user safe operation even in critical situations.

Fig. 7: Major measurement results

CASE STUDY This US utility had experienced some unexpected trips of unfalted line sections on their sub-transmission network. Investigations had lead to a suspicion of incorrect relay settings leading to zone over reaching, but the reason was not evident. Utilizing this method of directly measuring the line parameters, they were able to isolate the cause of the over reaching problem. So far, 16 lines have been tested and documented with actual measurements. A review of the results show 15 of 16 lines with consistent higher values for the calculated zero-sequence impedance as compared to the measured zero-sequence impedance. In fact, the average percentage error was 51%. (with a range of 10% to 107% error) Results are shown in the graph of Figure 9, and it is interesting to note that the positive sequence impedance measured values matched the calculated values within 3.5% on average. This validated the overall measurement results in the mind of the utility.

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●● The ground resistivity “assumption” of 100 ohm-meters may be in error.

Comparison of Z Meas to Calc

●● How often the cable circuits are actually bonded to ground and where.

16.000 14.000 12.000

Ohms

10.000 8.000

Z1 Meas

6.000

Z0 Meas

Z1 Calc Z0 Calc

4.000

●● Neutral wires are not run on overhead construction; however no consideration is given to under-built distribution (4 or 13kV with a neutral cable). ●● Is there a big water pipe, gas pipe, railway, or other infrastructure in the ROW?

2.000 0.000

Z0 Meas B- U- O- DZ1 Meas VL- O-93 GZU- A-27 O-67 I-269 Z-26 262 151 301 212 568 272 AQ163 182 411 573 225 Line Name

If these variables can be accounted for then the calculated values may become closer to the measured values results.

Fig. 9: Measured impedance versus calculated impedance per line tested To put this in relaying settings perspective, the graph of Figure 10 shows the comparison of the k0 values of each line using the existing calculated results and those based on the measured results. It easily shows that 12 lines are exposed to serious over-reaching conditions and 3 lines to minor under-reaching conditions. The average error is 59% with a range of -15% to 147% error. So the overall effect on the relay settings was dramatic and points to the need for performing further testing. The utility has since implemented a program for testing all of the sub-transmission system and making the necessary settings changes based on the measured results. Murphy has not yet provided any tests of these new settings on the lines tested, but that’s just the way he works. Comparison of k0 Meas to Calc

CONCLUSION Today the costs and effort for Line Impedance and k-Factor measurements are a fraction of what they used to be. Measurements showed that for several reasons calculations often gave wrong results. Therefore, both measurement and calculation will be done in the future. Safe, selective and fast failure clearance is only possible, if all relay parameters are set properly. Line impedance and k-factor are of highest importance for a fully operational distance protection relay.

REFERENCES W. Doemeland, Handbuch Schutztechnik, Huss-Medien GmbH, Berlin, Germany, 48-49.

1

S. Kaiser, 2004, “Different Representation of the Earth Impedance Matching in Distance Protection Relays,” Proceedings OMICRON User Conference in Germany 2004, OMICRON electronics GmbH, 11.1-11.5. 2

A. Dierks, 2004, “Accurate Calculation and Physical Measurement of Transmission Line Parameters to Improve Impedance Relay Performance,” Proceedings Southern African Power System Protection Conference 2004, Eskom Enterprises, 143-149. 3

2.50

2.00

Mag

1.50

k0 Meas

1.00

k0 Calc

0.50

0.00 BUODV262 151 301 212 568

L- O-93 G272 163 Line Name

ZU- A-27 O-67 I-269 Z-26 182 411

k0 Meas A573

Q225

Fig. 10: Comparison of k0, measured versus calculated per line tested In the analysis of the results the utility wanted to arrive at a conclusion as to why the traditional method of calculated zero-sequence was so far off. It was previously thought that the physical data was accurate and sufficient for good results. The conclusions drawn were:

William Knapek received a BS degree in Industrial Technology from East Carolina University in 1994. He retired from the US Army as a Chief Warrant Officer after 20 years of service in 1995. During his time with the Army Corps of Engineers, he held positions as a power plant instrumentation specialist, a writer/instructor for the Army Engineer School, and a Facility Engineer for a Special Operations compound. He has been active in the electrical testing industry since retiring in 1995. He worked for NETA companies in the Nashville, TN area until joining OMICRON electronics as an application engineer in April of 2008. He is currently the Sales Manager for the Southeast Area of North America for OMICRON electronics Corp, USA. He is certified as a Senior NICET Technician and a former NETA Level IV technician. Will is a member of IEEE and vice chair of WG I23 of the PSRC.

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Protective Relay Vol. 2

BASIC TRANSFORMER DIFFERENTIAL PROTECTION PowerTest 2015 Jay M. Garnett, Principal Engineer, Doble Engineering Company

ABSTRACT This paper will cover the basics of transformer differential protection. Topics will include the components that contribute to the relay protection, the transformers themselves, basic ratings, and the different variables involved. Also covered will be how to correctly wire the current transformers to prevent zero-sequence currents from inadvertently operating the differential relays. The basic process of setting the differential relays will also be discussed.

INTRODUCTION Basic transformer relay protection takes into account many variables when designing a protection circuit. Because there are different voltages on each side of the transformer, as well as a phase shift in most cases, there are many things to consider when designing the relay protection. For instance, protecting only the transformer, or zone of protection. The components of the differential protection will be covered, as well as how an engineer must look at the ratings of the current transformers (CTs) and how they are connected, to protect from inadvertently producing operations from unwanted currents. Current transformer class ratings will be explained. Also, polarity markings, why they are important, and how they need to be wired when using electromechanical relays as compared to microprocessor relays. Symmetrical components, inrush, and harmonics will be touched upon. And lastly, how to calculate a simple relay setting for a differential scheme using a GE BDD relay, and some microprocessor relay setting features. Figuring out the currents using the base MVA ratings of the transformer and applying them to a relay setting. (Example is a GE BDD relay).

for "calculated". So, C400 means the value is calculated at 400. Breaking it down, 400 is the voltage which can be delivered at 20 times the rated secondary current without exceeding a one percent (1%) ratio error. This is important when the protection engineer is doing his system fault studies to determine what class of CT to use, and the tap setting so it will operate correctly during fault conditions—such as the impedance of the relays attached to the current transformers. In this example, a current transformer class C400 with a 500:5 ratio will be used. The product of the current multiplied by the impedance should not exceed 400 volts. So if we take 20 x 5A that equals 100A. That means that a C400 CT that has a full ratio output of 5 ampere, would mean 400V÷100A=4 ohms (maximum impedance). So the impedance of the wiring and relays connected to the current transformer cannot exceed 4 ohms or else another class CT must be used. This was very important in the earlier days when electromechanical relays were used, as they had a much higher burden on the circuit than newer microprocessor relays do in today’s world. Next up is the polarity markings on current transformers. Each CT usually has a high side and a low side polarity mark. This indicates how the current will flow in the secondary winding based on the direction of current flow on the primary winding of the current transformer. This is extremely important when wiring up the relays to the CT’s in differential schemes, or even in directional relays used for line or ground fault protection. In figure 1, is a representation of primary current flow and secondary current flow.

SECTION 1 - CURRENT TRANSFORMERS (CTS) First, how the rating of the CT is determined will be explained. Then how the current flows in relation to the secondary current of the CT, and lastly how a very simple differential scheme works. Current transformers (CTs) used in transformer differential protection (and in other relaying schemes) are rated differently than metering class CTs. Older CTs used to have a “T” in the prefix of the class rating which meant a tested value. Most used today for relaying have a “C” in the prefix which stands

Fig. 1

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Protective Relay Vol. 2 Polarity marks–sometimes referred to as the Spot and Non-spot– on current transformer may also be labled H1 and X1 as the polarity mark. This dictates that when primary current flows from the polarity side of the CT towards the non-polarity side of the CT, the secondary current will flow out the polarity of the CT and returns to the non-polarity of the CT. Figure 2 shows the polarity marking on the primary part of the CT. If the primary current enters the non-polarity of the CT, then the secondary current will leave through the non-polarity of the secondary CT and return to the polarity of the secondary. Keep in mind that what leaves the secondary of the CT needs to come back to the secondary of the CT and it doesn’t care where that current comes from. This will be discussed in Figure 3.

Fig 2: Standard bushing current transformer with polarity marking “H1” for primary current direction. In Figure 3, the primary current runs through the opening of the doughnut style CT via the conductor in a breaker or transformer bushing, inducting a field in the CT primary turns. This builds a field in the secondary winding until the fields become saturated. Once saturated, the CT cannot resist current flow in the secondary winding. If the secondary is open, it will develop extremely high voltages trying to achieve the primary voltage. This is a very dangerous condition so never energize the primary of the CT without making sure the secondary is shorted or has a closed loop. The closed loop can be the relays attached to the circuit. If the secondary winding is a closed circuit, current will flow proportional to the ratio of the primary current to the secondary current based on the nameplate ratio. So as the primary current enters the polarity side of the CT, the secondary current leaves the polarity of the secondary winding. If primary current entered the non-polarity side of the primary winding of the CT, then current would flow out the non-polarity side of the secondary winding of the CT.

leaving the station with 100 amperes of current. As mentioned earlier, the secondary current will be based on the CT ratio on one side of the secondary winding and is looking for the same amount of current returning to the other side of the secondary winding. In this case the primary current is 100 amperes with the CT ratio being 500/5, which equals 100:1. So there is 1 ampere secondary leaving the polarity of the secondary winding of the CT on Line 1. As the primary current continues through the station bus and heads out line 2, the primary current is entering the primary winding of the CT on line 2 on the non-polarity side of the CT. Thus, the secondary current leaves the secondary winding on the non-polarity of that CT on Line 2

Fig 3: Shows polarity marks with primary, as well as secondary current flow in a bushing mounted current transformer. If you notice in Figure 4, the polarity of the CT on Line 1 is tied to the polarity or Line 2 CT and the non-polarity on Line 1 CT is tied to the non-polarity of Line 2 CT. Bridged across these two circuits is the differential relay. So, during normal bus flow conditions the secondary currents in each CT satisfy each other and no current will flow through the differential relay. (This is also due to the impedance of the differential relay). Please note that this assumes a normal configuration. If CT on Line 1 is located on the bus side of the breaker these can be wired differently to make the circuit function correctly. It’s all about understanding how current flows in current transformers. What leaves the CT has to see the same amount of current return.

The next section will show how the current will flow in a differential circuit when in operation during a bus fault. In Figure 4 there is primary current flowing into the bus from Line 1 of a transmission line. In this instance, 100 amperes of primary current flows through the bus and out the other transmission line (Line 2),

Fig 4: Normal current flow in a basic bus differential relay scheme with CT secondary currents.

30 When a bus fault is introduced into the system, the primary current will now feed the fault from both Line 1 and Line 2 as seen in Figure 5. So both CTs on Line 1 and Line 2 will have the secondary current flowing out of the polarity side of the secondary windings. These current can’t push to the other CT since they are in opposing directions. So they total up and are driven through the differential relay element operating the relay. Once through, the currents hit the connection point, and they split up and equal amounts go to satisfy each secondary CT current back to the non-polarity connections.

Fig 5: Primary and secondary current flow during a bus fault in a basic bus differential scheme.

SECTION 2 - SYMETRICAL COMPONENTS Next up are fault sequences and why they are important. There are three types of sequence currents and voltages; positive, negative, and zero-sequence. All three will be discussed for the differential relay circuit. Most people are familiar with the phasor relation diagram on the nameplate of a transformer. Figure 6 shows a typical phasor drawings, except in this case, magnitude and direction arrows to the opposite end of the origins for the Star (or Wye) connection and the Delta connection.1 Note: these are sometimes referred to as vector diagrams. However, vectors describe direction and velocity in reference to physics. Electrical and mathmatical references to the term "phasor" indicates direction and magnitude. The angular difference when comparing the two against each other is a 30° shift in phase relations when comparing the high side phasor phase relationships to the low side phasor phase relationships. It is assumed the reader already understands this concept.

Protective Relay Vol. 2 International standard for phasor rotation is a 1-2-3 counter-clockwise rotation.2 It does not matter what you call each phase, they are all a counter clockwise rotation. For this case study we will call them A phase for phasor 1, B phase for phasor 2 and C phase for phasor 3. Looking at the Star connected phasors in Figure 7, the rotation marking is showing normal rotation for a stable balanced three-phase current. During a three-phase fault, not to ground, the current phasors increase in magnitude but remain in the same relationship with B phase lagging A phase by 120° and C phase lagging B phase by 120°. These are called positive sequence currents.

Fig 7: Phaser diagram showing positive sequence currents. During a three-phase fault, not to ground, the sequence remains the same. In a phase-to-phase fault involving B and C phase currents, the current flows out on the line away from the station on B phase but returns back to the station on C phase. Thus the phasor is 180° out of phase from the original C phase phasor prior to the fault. This now changes the order in the phase sequence. It still is counterclockwise but now C phase comes after A phase instead of B phase. These are called a negative sequence currents as shown in Figure 8.

Fig 8: A phase-to-phase fault involving B and C phases produce negative sequence currents. Fig 6: Star (or Wye) phasor diagram and Delta phasor diagram for transformers.1

During a three-phase fault to ground, all the currents leave the station on the line, but now go to ground. These currents go through the earth ground and return to the station and enter the ground grid in the station. They then return back to the neutral

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Protective Relay Vol. 2 part of the transformer. These currents all have the same direction of phasors as they return back to the neutral. These are called zero-sequence currents as shown in Figure 9.

But, if the secondary CT is wired in a Delta configuration on the Wye (Star) connection side of the transformer low-side winding, we can prevent the zero-sequence currents from flowing into the relay circuit. Figure 11 shows that the secondary currents for a through fault now just circulate inside the Delta connected secondary wiring of the CT’s and no zero-sequence currents are allowed to operate the relay.

Fig 9: Faults that go to ground create zero-sequence currents. In this figure, this represents a three phase to ground fault. So why are we looking at current sequences and why are they important? The answer is the relay wiring in the scheme. The current circuit in a differential scheme should have only one ground connection. The reason it does not have two ground connections– one from each contributing CT– is to prevent circulating currents in the ground connections that could stop the currents from being forced through the differential relay during a fault. Having the one ground connection allows negative-sequence currents to enter the differential scheme. And remember, the current will take any and all paths to return to its source. This creates a problem on through faults that are not inside the differential zone of protection. This is why they wire the CT secondary wiring in the opposite configuration as the primary configuration of the transformer phaser diagram. It is not because of the 30° shift, it is to keep zero-sequence currents from entering the differential scheme and falsely operation the relay for through faults. In Figure 10, you will see a Delta-Star connected transformer for the high voltage to low voltage windings and the secondary wiring of the CTs wired both in the Star (Wye) configuration. During a through fault, the zero-sequence currents can enter the differential single-point ground and cause the relay to misoperate for external faults.

Fig 10: If both secondary CT circuits are wired Star (Wye) connection, the through fault zero-sequence currents can return through the ground and enter the differential circuit causing the relay to have a misoperation for a through fault outside the zone of protection.2

Fig 11: With the secondary wiring of the CTs on the Star (Wye) side winding of the transformer wired Delta, the through currents circulate inside the Delta connections, satifying the current returns without needing the zero-sequence current that would be trying to enter the differential scheme. This prevents the relay from operating on zero-sequence currents on through faults outside the zone of protection.2

SECTION 3 – INRUSH CURRENTS AND HARMONICS When a transformer is first energized, you get transient magnetizing or excitation current to flow. This is called inrush current. There are many factors involved on how big the inrush current is and how long it can last. This is determined by the size of the transformer and the system, the type of core steel used in the transformer and the flux density, the resistance of the power system from the source to the transformer, the history or residual flux in the transformer, and how many other transformers may be in parallel with it. There are many papers written on this subject of inrush currents and what affects it.3 These papers are well worth reading. But, for the purpose of this paper, only the fact that these factors influence inrush current is mentioned. These inrush currents, depending on all those factors mentioned, can have instantaneous currents of eight to more than thirty times the full load rating of the transformer, and the inrush currents can last from around ten cycles to several minutes depending on the circumstances.1,2,3 Detailed system studies are required to see how your system can be affected by this phenomenon. There are also formulas for calculating inrush currents. 1,3 Harmonics are developed during CT saturation on inrush as well as faults. These harmonics can delay the operation of relays using harmonic restraint or harmonic blocking features in the relays. It takes about one cycle or longer to saturate a CT. Current transformers repro-

32 duce the primary current for a given time after the fault. The worst CT saturation is produced by the DC component of the primary current. During this saturation, the secondary current of the CT can contain DC offsets, odd and even harmonics. When the DC offset dies out, the saturation has only AC saturation that is dominated by odd harmonics and very little even harmonics in the secondary current. Fault currents tend to have high odd harmonics and inrush current tends to have high even harmonics, especially second harmonics at 120Hz. Second harmonics increase as the inrush current increases. That is why they use harmonic restraint relays. They use second harmonics to help restrain the operation on inrush. Other harmonics can also be used such as in microprocessor relays. The restraint coils prevent the relay from operating until the operating current at 60Hz increases enough to override the effect of the restraint coils. Figure 12 shows the location in the circuit where the restraint coils reside.

Protective Relay Vol. 2 Harmonic restraint relays, the 15 percent tapsetting for some relays, is based on an inrush current of 1.40 pu (per unit) at zero degrees closing angle. Modern transformers can have saturation density values as low as between 1.30 and 1.20 with some as low as 1.15 pu. What this means is that some modern transformers with these low density levels may not have enough second harmonics content to restrain the relay and can trip on inrush when energizing. This is not a common occurance but does happen. Newer microprocessor relays allow the engineer more options for restraint or blocking features to prevent false tripping. They may use second and fourth harmonics to restain or block tripping, which can be added together. Fifth harmonic blocking may be used to prevent undesired operation during over excitation.4 In the microprocessor relays, the harmonic restaint, or blocking setting, is referred to as the “K” factor. The restaint element is typically based on the inverse of the percent harmonic setting where the percent value is entered as a setting for each selected harmonic.5 See Figure 14.

Fig 12: Harmonic restraint coils use 120Hz to help restrain the operating coil during inrush currents until the 60Hz operating current increases enough throught the operating coil to override the restraint current. Most restraint relays have several tap setting to set the amount of restraint. They have 10, 25 or 50 percent tap settings. Generator differential relay usually use the 10 or 25 percent tap. Transformers use the 50 percent restraint tap because the current transformers on each side of the transformer have different voltage ratings. Harmonic restraint relays also have what is called a slope setting. The slope setting allow you to push, or increase, the restraint region while decreasing the operate region by pushing the operating slope line up, as seen in Figure 12, when there is increasing harmonics.5,6

Fig 14: Microprocessor relay logic for percent restraint with harmonic blocking element There are advantages and disadvantages when it comes to using harmonic restraint verses harmonic blocking. The advantage of using harmonic restraint is that it tends to be more secure than harmonic blocking. This is because any harmonic content, even small amounts, will increase the restraint. The disadvantage of harmonic restraint is that it may operate slightly slower for internal faults.5 Harmonic blocking needs enough harmonics to pick up the setting in the relay in order to operate. So, small amounts of harmonics may not block the relay from operating.

SECTION FOUR – HOW TO DETERMINE DIFFERENTIAL RELAY SETTINGS

Fig 13: Relay slope settings increase the restraint region while reducing the operate region.

For this example, General Electric BDD differential relays are used to protect a transformer configured Delta-Star (Delta-Wye), 115kV to 13.8kV and rated at 33.6MVA. But in this senerio, the low side bus normally runs at not 13.8kV but at 13.2kV. I use this example to show how engineers determine the settings on the relay, not based on the nameplate data, but more on how the system voltages run in their area.

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Protective Relay Vol. 2 So first, the full load currents in the CT circuits for the high side and low side of the transformer will need to be calculated. To do this we use the formula shown in Figure 15. By looking at the diagram in Figure 16, we have all the information to calculate the primary currents for the high side and the low side of the transformer.

With loop circuits, not all of the current would get to the relay, thus preventing operation when needed. Newer microprocessor relays can convert the configurations inside the relay using software, so there is no need to wire the delta and star (wye) configurations. They can be wired either both star (wye), or both delta, but you still need to keep track of setting the relay to prevent zero-sequence currents from operating the relay as described earlier.5

Fig 15: The formula for calculating the full load current for either side of the transformer.3 Figure 16 shows the results of the following calculations: The high side primary current is: 33,600,000 ÷ (115,000 x √3) = 168.69A. The low side however needs to use the voltage that the bus normally runs at in this calculation. So the low side primary current is the result of the formula: 33,600,000 ÷ (13,200 x √3) = 1,469.62A. Fig 16: Transformer current differential circuits and calculations.

Now to find the secondary current in the CTs, we use the ratio of the CTs to determine the current. On the high side star (wye) connected CT, the ratio is 200/5 or 40:1. So 168.69A ÷ 40 = 4.22A secondary current. The current going through the CTs, that the secondary wiring is connected delta on the low side of the transformer, has a ratio of 2000/5 or 400:1. So the calculation is 1,469.62A ÷ 400 = 3.76A inside the delta connected secondary. To find the current going to the differential relay outside the delta connected secondary wiring, we have to multiply this amount by the square root of three (√3). So 3,76A x √3 = 6.36A. We now know the currents going to the GE BDD relay. From the high side, it is 4.22A and from the low side it is 6.36A. Obviously this in an imbalance current so the taps on the BDD relay will act as a current balancing transformer to balance the currents. The ratio of the current is 4.22 ÷ 6.36 = 0.66. So we have to select the correct taps to either match or as closely match that ratio. In this case selecting tap 3.2 and 5.0 gives us the closest match so looking at the ratio of the taps we get 3.2 ÷ 5.0 = 0.64 for a ratio. See Figure 16. Some utilities will install current balancing transformers in the circuit to balance the currents before they get to the differential relays so the relay will not have any mismatch and the taps can be set on the same tap settings. This allows almost no current to flow in the differential relay during normal operation. The current transformer circuits that feed the differential relay are only grounded at one point, usually at the relay. The reason for one ground is to prevent loop circuits in the multiple grounds.

SUMMARY: I hope this has given the reader insight on how current transformers work in a differential relay scheme and what happens during faults. I have tried to give you enough information to understand how a basic differential relay setting is done, as well as let you know some of the effects that inrush and fault currents can differ, thus effecting the operation of the relays. This is just an overview of the basic differential protection schemes. There are many more complex types of protection schemes that I did not cover in this paper. Other schemes such as wave form blocking, cross blocking, and negative sequence based internal and external discriminators are used.

REFERENCES: Electrical Transmission and Distribution Reference Book, ABB Power T&D Company Inc., 1997. 1

Applied Protective Relaying, Westinghouse Electric Corporation., 1982 2

Transform Interaction Caused by Inrush Current, H. S. Bronzeado, Companhia Hidro Elétrica do Sãn Francisco – CHESF – Recife, Brazil and R. Yacamini, University of Aberdeen, Department of Engineering, Aberdeen Scotland.

3

Differential Protection for Arbitrary Three-Phase Transformers. Zoran Gaji, Department of Industrial Electrical Engineering and Automation, Lund University.

4

34 Considerations for Using Harmonic Blocking and Harmonic Restraint Techniques on Transformer Differential Relays. Ken Behrendt, Normann Fisher, and Casper Labushagne, Schweitzer Engineering Laboratories, Inc., 2006 Western Protective Relay Conference. 5

6 "Transformer

Differential Relay with Percentage and Harmonic Restraint," in General Electric Relay Manual GEH-1816, BDD15B/BDD16B.

Jay M. Garnett has worked for Doble Engineering since 2011 as a principal engineer in the Client Services Department based in the Sacramento, California offices. Jay has worked in the utility industry for over thirty-four years and has experience in substations, hydroelectric, geothermal, fossil fuel, nuclear generation, construction, maintenance, and testing. He worked as a substation maintenance engineer for National Grid USA in the Substation O&M Services NE/NY Department from 2007 to 2011. Before that he was a supervisor overseeing the relay department for over five years. He also was a relay technician for National Grid (formerly Niagara Mohawk) in the Albany, NY area starting in 1992. Jay worked for Pacific Gas and Electric Company from 1983 until 1992, in the General Construction Department as an electrician and then as an electrical technician before moving to Albany, NY in December of 1992. Jay is a graduate from Napa Community College where he studied geology and received an Associate of Arts degree. Jay has also completed six years of apprenticeships, holding certificates as a journeymen Electrician and a journeymen Electrical Technician in the State of California. He has vice-chaired and chaired the Bushings Insulators and Instrument Transformer (BIIT) Committee at Doble while working at National Grid and is currently the assistant secretary of the Asset Management and Maintenance (AMM) committee at Doble. Jay has been a member of IEEE since 2007.

Protective Relay Vol. 2

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Protective Relay Vol. 2

CURRENT TRANSFORMER SATURATION AND RESIDUAL MAGNETISM PowerTest 2014 Will Knapek, OMICRON electronics Corp.

ABSTRACT The understanding of current transformers and the knowledge of all relevant current transformer data is of particular importance to optimize the performance of protection relays as well as the entire power system. For current transformers subjected to high fault currents or DC components the magnetic cores may saturate. For protection CT's this is an undesirable effect since particularly under heavy fault conditions a correct replica of the primary current is required for the protection relay to function properly. This paper will explore the effects of CT saturation and the resulting residual magnetism left in the current transformer. Techniques of how to measure residual magnetism and the consequences of residual magnetism will also be discussed. Current transformers are sometimes overlooked as a critical component of the fault clearing system. Their importance has been recognized by NERC in the recent issue of PRC 005-2. Current Transformers (CT’s) have been added as critical components to be tested on a periodic basis. However, the testing outlined by NERC, does not address a hidden problem that a CT can have. That problem is residual magnetism. To fully understand what residual magnetism is and how to avoid it, let’s examine CT basics. CT’s are designed to transform a high current to a lower current that can be used by relaying or metering devices. The following three basic principles are important to remember: ●● When AC current flows through a wire (Primary) an Electric Field is created. ●● Current passes through toroid made of ferromagnetic material such as iron; magnetic flux is generated in the iron core. ●● Wire is wrapped around the iron core, with a number of turns (N). This causes a current flow that is proportional to the magnitude of the primary current divided by the number of turns on the secondary winding. Looking at the CT from an equivalent current perspective we can better understand how the CT works. In Figure 1, is the CT equivalent circuit.

Fig. 1 Ip = Primary Current Np, Ns = Number of Turns in Ideal Transformer Lmain = Main Inductance RH = Hysteresis Resistance Reddy = Eddy-Current Resistance Rct = Resistance of the Secondary Winding RB = Resistance of the Burden VT = Terminal Voltage From this circuit we can look the CT from a testing perspective. In the core for the characteristics of ratio and polarity are found. In the parallel equivalent circuit, excitation characteristics are defined. And finally, the Rct is the area that defines the secondary winding resistance. CT’s can fall into two main classifications: metering and protection. A metering CT is designed to work accurately within the rated current range. In case of overcurrent, the metering CT shall become saturated (with sufficient burden), in order to protect the connected metering and measurement devices from overloading. Accurate representation of current is not a concern above saturation. A protection CT is designed to transform an ideally distortion-free signal even in the overcurrent range. This enables the connected protection relay for measuring the fault current value correctly. In a protection application the accurate representation of the high current level is of extreme importance to the correct operation of the fault clearing system. The remainder of this paper will focus on the protection CT.

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Protective Relay Vol. 2

A protection CT must exhibit the following characteristics: ●● The need to operate at high fault current with acceptable accuracy ●● Must have high excitation voltage to avoid saturation ●● Multiple ratios for different applications ●● Transient characteristic is important ●● Testing mainly concerned with saturation level ●● Burden is important In the North American market, IEEE C57.13-2008 defines the performance of CT’s and sets classes defining the performance. This standard defines three accuracy classes: C, T, and X. IEC uses a different system. The C classes of CT’s are the most common in North America. The C class of CT is defined as having a less than 3% ratio error at rated current, less than 10% ratio error at 20 times rated current, and a standard burden 200V/ (5A x 20) = 2Ω. The three numbers after the class designation means, secondary terminal voltage which the CT must maintain within the C Rating. The saturation of the CT occurs when the core has reached its maximum flux density, thereby causing a distortion of the secondary current. For C class transformers, typical excitation curves are drawn on log−log coordinate paper. The knee is defined as the point where the tangent is at 45° to the abscissa.

Fig. 3 It can be seen in the following figures the effects of saturation has on the secondary current seen by the protective relay. As the core is excited above saturation, the distortion becomes unacceptable.

Fig. 4: Non Saturated CT

Fig. 2 When trying to understand the concept of saturation, a BH curve allows us to visualize this very easily. H is the magnetic force generated by the primary current and is directly proportional to the instantaneous value of the excitation current. B is the flux density which is proportional to the time-integral of the Ve (or the area underneath the Ve sinusoid), and has the unit of Tesla. See Figure 3. Fig. 5: Saturated CT

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Protective Relay Vol. 2 Now this leads us to the phenomena of residual magnetism. When the primary current is suddenly cut-off, H drops to zero, but B drops to a value that is positive or negative tesla. This value also known as residual magnetism and has effects on relaying applications. In the ideal CT, the magnetism should always start at the zero, zero point on the BH curve. This is not the case when there is any magnetism left in the core. Residual magnetism in CTs can be quantitatively described by the amount of flux stored in the core as shown in the following equation.

Eq. 1 Look at the following diagrams and see how the residual magnetism effects the time that a CT will saturate under fault conditions. In Figure 6, the normal primary current is flowing in the CT. Under a fault condition you have 20 times that value in reserve before you saturate the core. In Figure 7, the core has residual magnetism, so the nominal operation current is at a higher level on the Flux Density axis of the BH curve. In a fault condition, the CT will now saturate much faster due to the loss of the reserve Flux Density. See Figure 8.

Fig. 6: Normal Operation

Fig. 8: Loss of flux density reserve with residual magnetism Typical residual magnetism effects in CT cores appear after being confronted with very high transient fault currents during fault conditions. Another cause of residual magnetism is from the circuit breaker not extinguishing the electrical arc at zero crossing of the current signal. And the most common cause is the failure to demagnetize the CT after testing. The DC winding resistance measurement with magnetize the core. The demagnetization process is done by applying at least the same electrical force as that which caused the magnetization effect. To perform this process it is recommended to start with similar force as the force which drove the core into saturation than reducing step by step to demagnetize the core. In other words, apply a DC current to the core in a higher value than it would take to saturate the core. Then reverse the current with a slightly less current. Repeat this until the current used is at zero. To determine residual flux it is essential to calculate voltage and current time integrals taken over the measurement duration. If calculation of these integrals can be made real-time (i.e. simultaneously with input sampling), there is no need to store input data of current and voltage channels. Thus, even if saturation process is very long, it will still be possible to calculate residual flux, which allows applying this method to residual remanence measurement for both CTs and transformers. The residual magnetism can be determined relatively precisely using simple test apparatus. A DC source such as a car battery and a recording device that will monitor current and voltage over time is all that is needed. The test is performed in three steps: ●● Load is applied until I0 and V0 are constant. ●● This is then repeated with opposite polarity. ●● This is then repeated once more with opposite polarity.

Fig. 7: CT with residual magnetism

●● Once the measurements are performed the complicated evaluation must be done. With voltage V0 applied, the current I0 increases. The internal load of the transformer Z0 drops until V0, I0 and Z0 are constant. As the flux in the core increases, the main inductance LH of the transformer changes. At maximum flux, the unsaturated inductance LS becomes the saturated inductance LS. The reactance XLS of the saturated main induc-

38

Protective Relay Vol. 2 tance LS is several times lower than the DC internal resistance RCT of the transformer. As such, Z0 = RCT at constant current flow. If RCT is known, the voltage can be calculated via the main inductance LH. The area below the voltage VLH is the magnetic flux [Φ in Vs] in the current transformer's core. Calculation of the flux via the integral of the voltage VLH is the next step in the evaluation.

Eq. 2



This needs to be done for all three measurements. Conclusions regarding the flux of the transformer at the start of the measurement are determined by the difference between Φ3 and Φ1; this is the flux level prior to starting the measurement.

Eq. 3

"Guide for the Application of Current Transformers Used for Protective Relaying Purposes," IEEE Standard C37.110-2008. 6

"Failure diagnostic at CTs for unwanted parallel primary impedance, IMTF 2011, Florian Predl, OMICRON. 7

"Explore new paths with the CT Analyzer – Extended testing benefits for your applications," IMTF 2010, Florian Predl, OMICRON, Austria. 8

William Knapek received a BS degree in Industrial Technology from East Carolina University in 1994. He retired from the US Army as a Chief Warrant Officer after 20 years of service in 1995. During his time with the Army Corps of Engineers, he held positions as a power plant instrumentation specialist, a writer/instructor for the Army Engineer School, and a Facility Engineer for a Special Operations compound. He has been active in the electrical testing industry since retiring in 1995. He worked for NETA companies in the Nashville, TN area until joining OMICRON electronics as an application engineer in April of 2008. He is currently the Sales Manager for the Southeast Area of North America for OMICRON electronics Corp, USA. He is certified as a Senior NICET Technician and a former NETA Level IV technician. Will is a member of IEEE and vice chair of WG I23 of the PSRC

Eq. 4 As you can see this is an involved process to measure and then perform the calculations to determine the residual magnetism of a CT in the field. There is a test set that can perform this task for you.

SUMMARY Residual magnetism will affect how a CT performs during a fault. How much of an effect will be determined by how much residual magnetism is in the core. It is a recommended practice to Demag after all tests. Especially after any DC test such as a winding resistance test of a CT. It would also be recommended to Demag after faults on critical circuits.

REFERENCES 1

CT Analyzer Theoretical Background, OMICRON electronics.

2

CT Analyzer User Manual, OMICRON electronics.

"Instrument Transformers, Part 1: Current Transformers," IEC 60044-1 Edition 1.2 / 2003-02: Reference number CEI/IEC 60044-1:1996, A1:2000, A2:2002. 3

"Instrument transformers, Part 6: Requirements for protective current transformers for transient performance," IEC 60044-6 First Edition / 1992-03: Reference number CEI/IEC 44-6:1992. 4

"Standard Requirements for Instrument Transformers," IEEE Standard C57.13-2008.

5

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Protective Relay Vol. 2

HOW DISRUPTIONS IN DC POWER AND COMMUNICATIONS CIRCUITS CAN AFFECT PROTECTION PowerTest 2016 Karl Zimmerman and David Costello, Schweitzer Engineering Laboratories, Inc.

ABSTRACT Modern microprocessor-based relays are designed to provide robust and reliable protection even with disruptions in the dc supply, dc control circuits, or interconnected communications system. Noisy battery voltage supplies, interruptions in the dc supply, and communications interference are just a few of the challenges that relays encounter. This paper provides field cases that investigate protection system performance when systems are subjected to unexpected switching or interruptions in dc or communications links. The discussion emphasizes the importance of environmental and design type testing, proper dc control circuit design and application, reliable and safe operating and maintenance practices with respect to dc control circuits and power supplies, and considerations for reliable communications design, installation, and testing. Some practical recommendations are made with regard to engineering design and operations interface with equipment to improve protection reliability and reduce the possibility of undesired operations.

THE ROLE OF DC AND COMMUNICATIONS IN PROTECTION SYSTEMS Fig. 1 shows a one-line diagram of a typical two-terminal line protection system using distance relays in a communicationsassisted pilot scheme. Bus S

Bus R 52

21

52

Communications Equipment

Communications Equipment

21

Channel

125 Vdc

48 Vdc

48 Vdc

125 Vdc

Fig. 1: Two-Terminal Digital Line Pilot Protection Scheme. To successfully clear all faults on the line within a prescribed time (e.g., less than 5 cycles), all of the elements in Fig. 1—breaker, relay, dc supplies, communications, current transformers (CTs), voltage transformers (VTs), and wiring—need to perform correctly. It is not unusual for lines to have redundant and backup protection schemes, often using different operating principles, with multiple channels and/or dc supplies.

Human factors (such as design, settings, procedures, and testing) are not shown in Fig. 1 but must also perform correctly. Additionally, security is as important a consideration as dependability. All of the elements and human factors must perform correctly to ensure that the protection scheme correctly restrains for out-ofsection faults or when no fault is present.

THE EFFECT OF DC AND COMMUNICATIONS DISRUPTIONS ON OVERALL RELIABILITY Protection systems must be robust even with transients, harsh environmental conditions, and disruptions in dc supply, dc circuits, or interconnected communications. These disruptions include loss of dc power due to failure or human action, noise on the battery voltage, dc grounds, interruptions in dc supply, and subsequent restart or reboot sequences. In the case of communications, these disruptions include channel noise, channel delays, interruptions due to equipment problems or human action, unexpected channel switching, and restart or resynchronization sequences. Fault tree analysis has been beneficial in analyzing protection system reliability, comparing designs, and quantifying the effects of independent factors. For example, the rate of total observed undesired operations in numerical relays is 0.0333  percent per year (a failure rate of 333 • 10–6). By comparison, the rate of undesired operations in line current differential (87L) schemes where disturbance detection is enabled is even lower at 0.009 percent per year (a failure rate of 90 • 10–6). However, undesired operations caused by relay application and settings errors (human factors) are 0.1 percent per year (a failure rate of 1,000 • 10–6) 1. Unavailability, which is the failure rate multiplied by the mean time to repair, is another measure used to compare reliability. The unavailability of dc power systems is low at 30 • 10–6, compared with 137 • 10–6 for protective relays and 1,000 • 10–6 for human factors. These data assume a faster mean time to repair a dc power system problem (one day) compared to relays and human factors (five days). Communications component unavailability indices are similar to those of protective relays 2. The North American Electric Reliability Corporation (NERC) State of Reliability 2014 report found that from the second quarter of 2011 to the third quarter of 2013, 5 percent of misoperations involved the

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Protective Relay Vol. 2

dc system as the cause, compared with 15 percent for communications failures, 21 percent for relay failures, and 37 percent for human factors 3. From these data, we can see that dc and communications failures are a small but significant factor in reliability.

The protection system, and the entire power system, is very similar to the aviation industry. Fault trees and high-level apparent cause codes do not necessarily make these subsystem interdependencies apparent.

Fault trees allow us to see how the failure rate of one device impacts the entire system (see Fig. 2). Fault trees also allow us to evaluate how hidden failures, common-mode failures, improved commissioning tests, and peer reviews impact reliability.

For example, in December 2007, while performing maintenance testing, a technician bumped a panel and a microprocessor-based, high-impedance bus differential relay closed its trip output contact (87-Z OUT1 in Fig. 4), tripping the bus differential lockout relay (86B in Fig.  4). Fortunately, due to testing that was being performed that day, the lockout relay output contacts were isolated by open test switches that kept it from tripping any of the 230 kV circuit breakers.

1178 Note: Numbers shown are unavailabilities • 106

Protection Fails to Clear In-Section Fault in the Prescribed Time

3

589

589

Protection at S Fails

Protection at R Fails

Same as Protection at S 2

17 203

4

Common-Mode Common-Mode Hardware/ Settings/Design Firmware Errors Failures 500 5

Breaker at S Fails to Interrupt Current 80 1969

2219

Main 1 Protection at S Fails

18

204 13

TS 87-Z OUT 1 TS

Main 2 Protection at S Fails

14 1

Relay Fails 137

Relay App. or Settings Errors 1000

Breaker Trip Coil Fails 120

DC System Fails 30

CT Fails 3•9 = 27

VT Fails 3 • 15 = 45

CT Wiring Errors 50

VT Wiring Errors 50

DC Wiring Errors 50

Hidden Microwave Microwave Microwave Comm. Failures Channel Tone Transceiver DC 10 Fails Equipment Fails System 100 Fails 200 Fails 100 50

G F

Fig. 2: Dependability Fault Tree for Dual-Redundant Permissive Overreaching Transfer Trip (POTT) Scheme 2. However, fault trees do not easily identify how a failure or activity in one subsystem affects another subsystem. Inspired by Christopher Hart, acting chairman of the National Transportation Safety Board, we wanted to investigate the interaction of components, subsystems, and human factors on the reliability of the entire protection system. At the 2014 Modern Solutions Power Systems Conference, Mr. Hart spoke of the aviation industry as a complex system of coupled and interdependent subsystems that must work together successfully so that the overall system works. In aviation, a change in one subsystem likely has an effect throughout other subsystems (see Fig. 3) 4.

Fig. 3: Aviation Safety Involves Complex Interactions Between Subsystems.

86B C B

Fig. 4: DC Control Circuit Showing Bus Differential Trip Output. The bus differential relay contact closure was easily repeated by bumping the relay chassis. The simple apparent cause could have been classified as human error, product defect (failure to meet industry shock, bump, and vibration standards), or relay hardware failure. However, subsequent analysis by the relay manufacturer showed momentary low resistance across the normally open contact when the chassis was bumped. Additionally, visual inspection noted evidence of overheating in the contact area (the outside of the plastic case was slightly dimpled). The contact part was x-rayed while it was still mounted on the main printed circuit board. The adjacent, presumed-healthy contact was x-rayed for comparison. The x-ray images are shown in Fig. 5, with the adjacent, healthy Form-C contact on the left and the damaged Form-C contact on the right. In each contact, there is a stationary normally open contact surface (top), a moving contact surface (center), and a stationary normally closed contact surface (bottom). Note the difference in contact surfaces and spacing. The relay manufacturer estimated that the output contact was likely not defective but rather had been damaged due to interrupting current in excess of the contact’s interruption rating.

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It is important at this point to persist in analysis and examine testing mandates, procedures, and work steps to find root cause. In this case, commissioning testing, represented as one human factor subsystem in the fault tree (relay application), performed to improve reliability was flawed in such a way that the protective relay hardware was damaged and induced a failure in that subsystem. In addition, maintenance testing, mandated by NERC and intended to improve reliability, was flawed in such a way that the relay was damaged and could have potentially caused a misoperation.

Fig. 5: X-Ray Images of the Healthy, Adjacent Contact (Left) and Damaged Contact (Right). The output contact manufacturer further inspected the output contact part. The output relay cover was removed and the inside of the part was observed and photographed (see Fig.  6). The plastic components were melted, the spring of the contact point was discolored and deformed by heat, and the contact surfaces were deformed, rough, and discolored. The root cause of the contact damage was confirmed: at some point prior to the misoperation, the interrupting current was in excess of the contact’s interruption rating.

In this example, the failure mode was a relay contact closing when the relay chassis was bumped. According to NERC data, 60 percent of rootcause analyses stop at determining the mode 5. True root-cause analysis requires us to dig deeper to understand the failure mechanism or process that led to the failure. Then, we can educate others and ensure that improvements prevent the problem from reoccurring. In NERC contributing and root-cause vernacular, this incident would be due to a defective relay (A2B6C01) caused by an incorrect test procedure (A5B2C07) caused by a failure to ensure a quality test procedure (A4B2C06). An important theme in the case studies that follow is how an action or failure in one subsystem affects other subsystems and overall reliability.

TRADITIONAL DC PROBLEMS The dc control circuits used in protection systems have always been complex. Problems that need to be mitigated include circuit transients, sneak or unintended paths, stored capacitance, letthrough and leakage currents, and more 6. For example, electromechanical auxiliary relays were once commonly used for local annunciation, targeting, or contact multiplication. Some of these relays were high speed and quite sensitive. Care was taken to ensure that let-through currents from connected output contacts did not inadvertently cause these auxiliary relays to pick up. Especially when used with transformer sudden pressure relays with poor dielectric withstand capability, extra security measures were taken to prevent auxiliary relays from operating in case a voltage surge caused a flashover in the normally open contacts of the pressure relay. In Fig. 7, the normally closed contact from the sudden pressure relay (63) shunts the auxiliary relay operating coil (94) so that if the normally open contact flashes during a voltage transient, the auxiliary relay will not operate 7. (+) 63

63

94

94

94

86

Fig. 6: Pictures From Contact Manufacturer Confirming Heat Damage From Exceeding Current Interruption Rating.

(–)

Fig. 7: Typical Security Precaution for Dielectric Strength Failure of a Sudden Pressure Relay Contact.

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Protective Relay Vol. 2

Precautions must be taken to avoid these same dc circuit anomalies as we transition to new technology platforms and design standards. As auxiliary relays are replaced by microprocessor-based relays, pick-up time delays are required on relay inputs that are used to directly monitor these same sudden pressure relay normally open contacts to maintain security 8.

TRADITIONAL COMMUNICATIONS PROBLEMS Communications that are used for protection systems perform well but are not perfect. One well-known communications component problem involves the application of power line carrier for transmission line protection schemes. In directional comparison blocking (DCB) schemes, high-frequency transients can produce an undesired momentary block signal during an internal fault. Fig. 8 shows one such incident. Engineers must adjust frequency bandwidths, add contact recognition delay, or tolerate the possibility of a slight delay in tripping for internal faults. Conversely, if an external fault occurs, the momentary dropout of the carrier blocking signal, referred to as a “carrier hole,” can produce an undesired trip, as shown in Fig. 9. These dropouts are often attributed to a flashover of the carrier tuner spark gap and can be avoided by improved maintenance of the carrier equipment or can be dealt with by adding a dropout delay on the received block input.

Protection system communications options today include many media in addition to power line carrier, such as microwave, spread-spectrum radio, direct fiber, multiplexed fiber networks, Ethernet networks, and more. Each medium has its own set of potential problems, such as channel noise, fault-induced transients, channel delays, dropouts, asymmetry, security, buffers and retry, interruptions due to equipment problems or human action, unexpected channel switching, and restart or resynchronization sequences. The trends in our industry include communicating more, exploring new and creative applications for communications, and replacing intrastation copper wiring with microprocessor-based devices and communications networks. As more and more communications and programmable logic are used, it is critical to analyze, design, and test for potential communications problems.

TRADITIONAL PROCEDURE PROBLEMS The sequence in which work tasks are performed is important. A familiar example will highlight this concept. A primary microprocessor-based line relay had been taken out of service for routine maintenance testing. Trip and breaker failure initiate output contacts, as well as voltage and current circuit inputs, had been isolated by opening test switches. After successful secondary-injection testing, the relay tripped the circuit breaker during the process of putting the protection system back into service 9. Event data showed only one current (A-phase) at the time of trip. This indicated that the technician had reinstalled the trip circuit first by closing the trip output test switch. Next, a single current was reinstalled by closing its test switch. Because there was load flowing through the in-service breaker and CTs, the relay, at this step in the sequence of events, measured A-phase current and calculated 3I0 current and no voltages. It issued a trip.

Momentary Carrier Block

Fig. 8: Momentary Carrier Block Input Produced by FaultInduced Transient.

This was a valuable lesson for this utility in the early adoption phase of these relays and led to a specific procedure and sequence that is used when returning a relay to service. The sequence of steps used to restore the system to service is the reverse of that used to remove the system from service and is as follows. 1. Place all three voltage circuits back into service (i.e., close the voltage test switches). 2. Place all three current circuits back into service. 3. Use meter commands or event data to verify the proper phase rotation, magnitude, and polarity of the analog measurements. 4. Reinstall the dc control inputs.

Carrier Holes

Fig. 9: Carrier Holes in a DCB Scheme.

5. Use target commands or event data to verify the statuses of control inputs. 6. Reset relay targets and verify that trip and breaker failure outputs are reset. 7. Place the trip and breaker failure output circuits back into service.

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Protective Relay Vol. 2 Similarly, when disrupting communications circuits or dc power, we must thoughtfully consider what parts of the protection system should be isolated and the careful order of steps to take in the process of returning the system to service. Analysis, design, and testing should be devoted to this, considering our increased dependence on interdevice communications and programmable logic. The following section highlights some interesting system events where disruptions in dc and/or communications directly affected protection.

PROTECTION SYSTEM EVENTS CAUSED BY DC OR COMMUNICATIONS SYSTEM DISRUPTIONS Case Study 1: Breaker Flashover Trip After Relay Restart Fig.  10 shows the simplified one-line diagram of a 161  kV substation for an event in which a breaker failure flashover logic scheme operated after a relay restart (i.e., dc power supply to the relay was cycled off and on), causing a substation bus lockout. Remote I/O Module

The user applied the I/O module to eliminate extra wiring and inherent noise and hazards associated with long (i.e., several hundred feet) runs of copper wire. Also, the fiber connection was continuously monitored. The monitored communications link can be set to default to a safe state, as specified by the engineer. In this case, if communications were lost (e.g., fiber was disconnected or damaged or there was an I/O module failure), the breaker status would default to its last known state before the communications interruption. The breaker failure flashover logic is shown in Fig. 12. It detects conditions where current (50FO) flows through an open breaker (NOT 52a). When a breaker trips or closes, the logic is blocked with a 6‑cycle dropout delay. The user can define a time delay for breaker failure to be declared. In this case, it was 9 cycles. 50FO 52a Trip or Close

Dropout Delay 0

S

Q

6

Breaker Failure Flashover Timer 9 0

Breaker Failure Flashover

Communications Link

R 21, 67, etc. 50BF With Breaker Flashover Logic

161 kV

12.47 kV Lockout Relay

Fig. 12: Breaker Failure Flashover Logic. The event data in Fig. 13 show the status of the relay elements immediately after the power cycle. Current is already present, but the breaker status (52AC1) is a logical 0 (not asserted). Thus, the breaker failure flashover element (FOBF1) asserts and produces the breaker failure output (BFTRIP1), which subsequently operates the substation lockout relay.

Fig. 10: Case Study 1 System One-Line Diagram Uses Remote I/O Module for Breaker Interface. In this system, the breaker status auxiliary contacts (52a and 52b) and other monitored breaker elements are connected to a remote I/O module. The I/O module converts hard-wired inputs and outputs to a single fiber link from the module at the breaker to the relay located in a remote control house (see Fig. 11). 52 Trip 1 52 Trip 2 52 Close Communications Link

52 Low Gas Alarm 52 Low Gas Trip I/O Module Alarm

Remote I/O Module

Relay

52 Spring Charge Alarm 52 Trip Coil Monitor 1 52 Trip Coil Monitor 2 52a 52b

Fig. 11: Monitored Points From the 161 kV Circuit Breaker Using a Remote I/O Module and Fiber Interface to the Relay.

Fig. 13: Breaker Failure Flashover Logic Asserts Due to Current Measured While Breaker is Sensed Open. The undesired trip occurred because the breaker failure flashover logic began processing before the communications link between the I/O module and the relay was reestablished. We can see the communications link status between the relay and the I/O module (ROKB) asserted about 14 cycles later.

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Protective Relay Vol. 2

The event report does not show much about what happened before the trip during the relay restart process. However, from an internal sequential event record, we were able to assemble the timeline, as shown in Fig. 14. Pre-Event Report Relay Restart

dc power to the relay was switched off and on, the lockout logic output asserted, causing a substation trip and loss of supply to several customers.

Event Report 9 Cycles

22 Cycles

87 S

Line Switch (89)

R

86

9b

8

Q FOBF1

1/4 Cycle

BFTRIP1

T

52AC1

Alternate Source

ROKB

Communications Link Reestablished

Fig. 14: Event Timeline Shows Relay Restart and Arming of Flashover Logic Before Breaker Status Is Recognized. The relay restart sets the latch (Q) and starts the 9‑cycle breaker failure flashover timer. At 9 cycles, FOBF1 asserted. By the time the communications link was established (at 22  cycles), the trip had already occurred. Important lessons were learned in this case study. Relays and I/O modules might reboot, operators may cycle power to relays when looking for dc grounds or performing other troubleshooting, relays may employ diagnostic self-test restarts, and so on. There is no default state for most logic during a relay restart. In a relay restart, all of the logic resets and begins processing from an initial de-energized state, as is the case when a relay is powered up and commissioned for the first time. In this case, designers considered a loss of communications but did not consider how a loss of dc supply or relay power cycle would affect the communications status and the logic processing order during a start-up sequence. In the breaker failure flashover logic, the breaker status is used directly in a trip decision. We should supervise the breaker failure flashover logic with the monitored communications bit (i.e., FOBF1 AND ROKB) to prevent the flashover logic from being active until communication is established. To further avoid such undesired operations, commissioning tests should include power cycles to test for secure power-up sequences in logic processing.

Case Study 2: Protective Relay Applied as a Lockout Relay Operates Due to a Power Cycle In Case Study 2, a microprocessor-based transformer differential relay was applied as a lockout relay, as shown in Fig. 15. When

Fig. 15: One-Line Diagram of Relay Applied as a Transformer Differential Relay and Lockout Relay Together. Discrete lockout and auxiliary relays are widely used in protection systems. Why not use a discrete lockout relay here instead of building these functions inside the microprocessor-based relay? The decision to do this was driven by several factors. One factor was reduced cost—fewer relays and less panel space and wiring. In addition, periodic maintenance testing was reduced by having fewer devices and by extending the maintenance intervals due to the inherent self-monitoring capability of the microprocessor-based relay versus the electromechanical lockout relay. Additionally, some system events have also led engineers away from using discrete auxiliary and lockout relays. One infamous event that is often cited for this change in design was initiated by a failed auxiliary relay at Westwing substation 10. The internal relay lockout logic for Case Study 2 is shown in Fig. 16. External Trip

LT1 S R

Q

LT2 87T Trip

S R

Q

86 (Lockout)

LT3 63 Trip

S R

Manual Reset

Q

89b (Line Switch Open)

0.5 0.5 Debounce Timer

Fig. 16: Internal Lockout Logic.

45

Protective Relay Vol. 2 The “latch” functions (LT1, LT2, and LT3) are all retained in nonvolatile memory. That is, even if the relay loses control power, it retains the status of the latch functions. In this case, an actual internal transformer fault occurred. The transformer protection (87T) and internal lockout function (86LO) operated to clear the fault. Dispatchers were able to switch load to an alternate source. All operations were correct up to this point. The timeline in Fig. 17 shows the sequence.

DC Off

External Trip

S R

Q

LT2 87T Trip

S R

86 (Lockout)

Q

LT3 63 Trip

S R

86 Lockout Reset Pushbutton

Dispatchers Close Breaker T Initial Fault and Trip

Relay Enabled

LT1

Q

DC On

87T Trip

89b (Line Switch Open)

LT2 (Latch) 89b Asserted (When Line Switch Open) 86LO

0

0 0

Debounce Timer

12 Dropout Delay

Fig. 18: Modified Lockout Function Logic.

DC Supply Relay Enabled 86 Lockout Reset Pushbutton

Fig. 17: Event Timeline Shows 86LO Trips for DC Off and On. When the maintenance crew arrived at the station, the correct procedure was to reset the lockout using a pushbutton on the relay. Instead, as stated earlier, the dc supply was switched off and on. The 86LO function asserted incorrectly when dc was switched off and asserted incorrectly again when dc was switched on. On power down, the relay stayed enabled for several cycles after the point at which logical inputs deasserted. Thus, the 89b input was sensed as deasserted (line switch closed) before the relay was disabled, producing the 86 lockout. On power up, the relay enabled before the 89b input was sensed, thus producing the 86 lockout again. The first and most obvious lesson learned in this case study is that, as technology changes, engineers and operators must strictly adhere to updated operating procedures for resetting lockout functions. Well-understood interfaces, such as physical lockout relays, are being mimicked or replaced, and it is important to document and train field personnel. Another lesson learned is to test the impact of cycling dc power off and on. Protection systems should be robust, relays and I/O modules might reboot, and operators may cycle power to relays when looking for dc grounds or performing other troubleshooting. In this case, designers did not consider how a loss of dc supply or relay power cycle would affect the programmable logic processing order during a power-down or power-up sequence. The user has since added logic so that the lockout function is supervised by a healthy relay (Relay Enabled). In addition, the line switch status is now supervised by a dropout delay that is longer than the relay power-down enable time (see Fig. 18).

Case Study 3: Direct Transfer Trip Due to a Noisy Channel Fig. 19 shows the protection one-line diagram for a 138 kV system with two-ended transmission. The line is protected by distance and directional elements in a permissive overreaching transfer trip (POTT) scheme, along with a direct transfer trip (DTT) scheme if either end trips. T M2

M1

POTT and DTT A

21/67

Relay-to-Relay Digital Communications Link Multiplexer

Multiplexer

21/67

Network

Fig. 19: One-Line Diagram of a 138 kV Transmission Line. In this case, the communications channel is a multiplexed digital network. The channel was abnormally noisy, with about 10 channel dropouts per minute and an overall channel unavailability around 0.5 percent. One of the noise bursts and associated channel dropouts resulted in a momentary assertion of the DTT input (see Fig. 20). Note that the protection system also experienced an unrelated breaker failure. Significant efforts are made to secure protective relays that use channels; these efforts include data integrity checks, debounce delays, disturbance detectors, watchdog counters, and more. In this case, even with a 50 percent bit error rate, the probability of a bad message getting through the relay data integrity checks was one in

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49 million 11. Although the probability was low, it was not zero, and if enough bad messages were sent, it was still possible for one to get through the integrity check, as in this case. In this example, we see how monitoring a noisy channel may provide a leading indicator for detecting problems. Also, regardless of media and integrity checks, it is prudent to add security on schemes that use direct transfer tripping. In this case, requiring two consecutive messages (an 8‑millisecond delay) instead of one (a 4-millisecond delay) improved security by an additional 104 factor.

Important lessons were learned in this case study. Channel performance must be monitored, and alarms, reports, and other notifications of noise and channel dropouts must be acted on with urgency. In modern 87L relays, regardless of data integrity checks, disturbance detection should be applied to supervise tripping. If disturbance detection had been enabled in this case, the 87L element would have been secure and the undesired operation would have been avoided.

Case Study 5: Relay Trips During Power Cycle While Performing Commissioning An older microprocessor-based relay was being commissioned. During testing, the dc control power was cycled and the relay tripped by directional ground overcurrent. The problem was repeatable.

Communications Drop Out

DTT BFI

Fig. 20: Channel Noise Results in a Momentary DTT Assertion.

Case Study 4: Communications Channel Problem on 87L Another two-terminal transmission line was protected by an 87L scheme. In the event data shown in Fig. 21, the system experienced a degradation of one of the optical fiber transmitters used in the 87L scheme. This failing component injected continuous noise into the channel and its connected equipment.

The relay power supply produces two low-voltage rails from its nominal input voltage for use by various hardware components. A 5 V rail, in this case, was used by the analog-to-digital (A2D) converter, and a 3.3 V rail was used by the microcontroller (µP) and digital signal processor (DSP). Protective circuits reset components when their respective supply voltages drop below acceptable operating limits. Recall from a previous case study that, due to ride-through capacitance, the power supply stays active for several cycles after input power is removed. Fig. 22 provides a graphical representation of how the power supply rails decay at a certain ramp rate, rather than an instantaneous step change, after power is turned off at time T1. Supply Voltage Nominal

5.0 V 3.3 V

T1

�t

Time

Fig. 22: DC Supply Voltage Ramp Down to 0 V After a Power Cycle at Time T1.

Fig. 21: 87L Produced Undesired Trip Due to Communications Failure With Disturbance Detection Not Enabled. In Fig. 21, we can observe the channel status (ROKX) chattering—it should be solidly asserted. Eventually, bad data, in this case erroneous remote terminal current (IBX), made it through data integrity checks and caused an undesired 87L operation. Disturbance detection was not enabled.

The root cause for this case study was a hardware design that allowed the µP and the DSP to remain enabled for several milliseconds after A2D disabled. As A2D disabled, it sent erroneous data to the µP and the DSP, which appeared as a false 3I0 current pulse, which caused the trip. Fortunately, this design issue was found during commissioning tests instead of much later when pulling relay dc power (with trips enabled) to find a dc ground.

47

Protective Relay Vol. 2 Important lessons were learned in this case study. Cycling control power, while replicating as accurately as possible in service conditions, is invaluable and as important as industry standard environmental tests. In this case, the criticality of the power-down sequence of components common to one piece of hardware was revealed.

tions link statuses. Logic should be forced to a secure state during communications interruptions. Status dropout delays should be included as a necessity for security margin. DTT signals should be supervised with debounce delays. Received analog values should be supervised with disturbance detectors.

Consider that the North American Northeast Blackout of 2003 was aggravated by a lack of up‑to-date information from the supervisory control and data acquisition (SCADA) system. A remote terminal unit (RTU) was disabled after both redundant power supplies failed due to not meeting industry dielectric strength specifications. Independent testing (simple high-potential isolation testing) had not detected this product weakness. Self-test monitoring did not alert the operators that the RTU was dead. Fail-safe design practices, such as reporting full-scale or zero values for all data fields during loss of communications or for watchdog timer failures, were not in place. Redundant power supplies, installed to improve the availability of the system, did not overcome these larger handicaps 2 12. These problems are not “hidden failures” just because we do not test or check for them.

Include the ability to isolate trip circuits and devices, whether by physical test links or virtual links for communicated signals. Especially when implementing new technology platforms, strive to make the operator interface familiar and ensure that operating procedures are clear, documented, and proven.

As the industry moves toward more complicated and interdependent Ethernet IEC 61850-9-2 systems, power cycling tests become even more critical. Such systems may employ a data acquisition and merging unit built by one manufacturer, a subscribing protective relay built by a second manufacturer, and an Ethernet network built by a third manufacturer. What if the data acquisition shuts down at 5 V and outputs erroneous data to the rest of the components that remain active for a few cycles more?

CONCLUSION Protection systems and the power industry have much in common with the aviation industry. Both are complex systems of coupled and interdependent subsystems that must work together successfully so that the overall system works. We must continue to understand root cause and that changes in one subsystem have an effect throughout other subsystems. DC control circuits and communications channels have always had complexity and problems to overcome. Our work instructions and procedures have always had to be carefully considered. However, as we transition to new technology platforms and design standards, special precautions must be taken to avoid the types of pitfalls discussed in this paper. When disrupting dc control circuits or communications channels, we must thoughtfully consider what parts of the protection system should be isolated from trip circuits. Isolate trip circuits before indiscriminately cycling power in relay panels when, for example, troubleshooting dc grounds. Analysis, design, and testing should be devoted to understanding what happens when power is cycled on systems and subsystems, especially considering our increased dependence on interdevice communications and programmable logic. Critical communicated logic inputs should be supervised with device and communica-

Test, test, test; avoid undesired operations by including power cycle and logic processing sequence checks in design and commissioning tests.

REFERENCES 1

K. Zimmerman and D. Costello, “A Practical Approach to Line Current Differential Testing,” proceedings of the 66th Annual Conference for Protective Relay Engineers, College Station, TX, April 2013. 2

E. O. Schweitzer, III, D. Whitehead, H. J. Altuve Ferrer, D. A. Tziouvaras, D. A. Costello, and D. Sánchez Escobedo, “Line Protection: Redundancy, Reliability, and Affordability,” proceedings of the 37th Annual Western Protective Relay Conference, Spokane, WA, October 2010. 3

North American Electric Reliability Corporation, State of Reliability 2014, May 2014. Available: http://www.nerc.com/pa/ rapa/pa/performance analysis dl/2014_sor_final.pdf.

4

D. Costello (ed.), “Reinventing the Relationship Between Operators and Regulators,” proceedings of the 41st Annual Western Protective Relay Conference, Spokane, WA, October 2014.

5

B. McMillan, J. Merlo, and R. Bauer, “Cause Analysis: Methods and Tools,” North American Electric Reliability Corporation, January 2014.

6

T. Lee and E. O. Schweitzer, III, “Measuring and Improving the Switching Capacity of Metallic Contacts,” proceedings of the 53rd Annual Conference for Protective Relay Engineers, College Station, TX, April 2000. 7

GE Multilin, HAA Auxiliary or Annunciator Instruction Leaflet. Available: https://www.GEindustrial.com/Multilin.

8

D. Costello, “Using SELogic® Control Equations to Replace a Sudden Pressure Auxiliary Relay,” SEL Application Guide (AG97-06), 1997. Available: https://www.selinc.com.

9

D. Costello, “Lessons Learned by Analyzing Event Reports From Relays,” proceedings of the 49th Annual Conference for Protective Relay Engineers, College Station, TX, April 1996.

10

North American Electric Reliability Corporation, “Transmission System Phase Backup Protection,” Reliability Guideline, June 2011. Available: http://www.nerc.com.

48 11

"Teleprotection Equipment of Power Systems – Performance and Testing – Part 1: Command Systems," IEC 60834-1, 1999.

12

IEEE Power System Relaying Committee, Working Group I 19, “Redundancy Considerations for Protective Relaying Systems,” 2010. Available: http://www.pes-psrc.org. Karl Zimmerman is a Regional Technical Manager with Schweitzer Engineering Laboratories, Inc. in Fairview Heights, Illinois. His work includes providing application and product support and technical training for protective relay users. He is an active member of the IEEE Power System Relaying Committee and chairman of the Working Group, “Tutorial on Application and Setting of Distance Elements on Transmission Lines.” He is also vice chairman of the Line Protection Subcommittee. Karl received his BSEE degree at the University of Illinois at Urbana-Champaign and has over 20 years of experience in the area of system protection. He is a registered Professional Engineer in the State of Wisconsin. Karl is a recipient of the 2008 Walter A. Elmore Best Paper Award from the Georgia Institute of Technology Protective Relaying Conference, a past speaker at many technical conferences, and author of over 40 technical papers and application guides on protective relaying. David Costello graduated from Texas A&M University in 1991 with a B.S. in Electrical Engineering. He worked as a system protection engineer at Central Power and Light and Central and Southwest Services in Texas and Oklahoma and served on the System Protection Task Force for ERCOT. In 1996, David joined Schweitzer Engineering Laboratories, Inc. as a field application engineer and later served as a regional service manager and senior application engineer. He presently holds the title of technical support director and works in Fair Oaks Ranch, Texas. David has authored more than 30 technical papers and 25 application guides and was honored to receive the 2008 Walter A. Elmore Best Paper Award from the Georgia Institute of Technology Protective Relaying Conference. He is a senior member of IEEE, a registered professional engineer in Texas, and a member of the planning committees for the Conference for Protective Relay Engineers at Texas A&M University, the Modern Solutions Power Systems Conference, and the I-44 Relay Conference.

Protective Relay Vol. 2

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Protective Relay Vol. 2

ENERGY-BASED TRIPPING AND ITS EFFECTS ON SELECTIVE COORDINATION NETA World, Fall 2013 Issue John Carlin, Schneider Electric Engineering Services

INTRODUCTION

COMPARISON OF TIME-CURRENT CURVES

Changes to the 2005 and 2008 National Electric Code (NEC) forced more careful examination of overcurrent protective device (OCPD) selective coordination, particularly at high-fault current levels approaching system maximum bolted three-phase values. This paper examines selective coordination methods for circuit breakers, beyond the traditional plotting of time-current curves (TCCs) alone, for high-fault currents. Specifically, an energy-based circuit breaker tripping system, which can provide improved selectivity, series rated combinations, and favorable arcflash performance, is presented and examined.

Time-current curves for OCPDs show how long it will take the device to operate under overcurrent conditions. These curves are typically developed by conducting interruption tests on sample devices at various overcurrent levels – overload and fault currents. The device curves account for manufacturing tolerances and are plotted under specific conditions – standalone operation and at a given ambient temperature. Typical circuit breaker time-current curves can be divided into two distinct protection zones – overload and fault current as shown in Figure 1. (This protection zone concept is not common in North America; however, it helps to clarify the remaining discussion.) Circuit breakers respond to overcurrents differently in the two protection zones. In the overload protection zone, the circuit breaker has an inverse-time operating characteristic, indicating the circuit breaker trip time decreases as the overload current increases. In the fault protection zone, the circuit breaker operates with no intentional delay in the case of thermal-magnetic trip circuit breakers or with well-defined short-time segment delays in the case of electronic circuit breaker trip units as shown Figure 2.

BACKGROUND AND HISTORY The 2011 NEC includes six references to selective coordination, which have driven more rigorous examination of OCPD performance and interaction – Articles 100, 517, 620, 700, 701, and 708 all mention “coordination” or “selective coordination.” The general definition in Article 100 defines selective coordination as, “Localization of an overcurrent condition to restrict outages to the circuit or equipment affected, accomplished by the choice of overcurrent protective devices and their ratings or settings”. Articles 700, 701, and 708 further emphasize the requirements for selective coordination for particular systems when fed by an alternative source or sources. Article 517, for Health Care Facilities, extends the requirements of Article 700 to apply to the Health Care Facility essential electrical systems (life safety, critical care, and equipment branches). Article 620 requires selective coordination for elevators, dumbwaiters, escalators, moving walks, wheelchair lifts, and stairway chair lifts “where more than one driving machine disconnecting means is supplied by a single feeder.” While the rationale for selective coordination is self-evident – clearing and isolating faults as quickly as possible without disturbing the unaffected portions of the system – the methods for determining OCPD to OCPD selectivity are not as apparent. Industry standards which define device-to device selectivity for their full operating ranges do not exist and no consensus has been developed among protection engineers or inspecting authorities for device-to-device selectivity thresholds. Discussions continue over the “practicable” selectivity criteria – years of engineers overlaying time-current characteristics of OCPDs to determine selectivity complicated by examining the current-limiting interactions of OCPDs at maximum available fault currents – it is against this background that various alternative selective coordination criteria have been introduced.

Fig 1: Circuit Breaker Time-Current Curve Operating Zones Comparing time-current characteristics of two or more OCPDs on a single graph is the traditional method for determining selective coordination. The relative position of individual device toler-

50 ance bands on a TCC can illustrate the degree of coordination and it is common for the instantaneous trip characteristics to overlap one another. Visually an engineer may conclude that these circuit breakers do not selectively coordinate up to the maximum available fault current when in fact they do, given more precise examination of circuit breaker operation. While TCCs are required to verify the coordination of circuit breaker tolerance bands in the overload protection zone, new examination methods will be presented to verify total selectivity in the fault protection zone even though on a TCC they do not appear to selectively coordinate.

TOTAL SELECTIVE COORDINATION

Protective Relay Vol. 2 range of the OCPDs up to the maximum fault current. While TCCs are excellent analytical tools for determining selectivity among devices in the long-time and short-time regions of the circuit breaker operating characteristics, additional methods are required to determine total selectivity. Selective coordination may be required in a variety of systems which are discussed in NEC Articles 517, 620, 700, 701, & 708. Various adoptions, clarifications, and enforcement practices exist in the US; as such, interpretation of the NEC is out of the scope of this paper. Only circuits that have already been determined to require total selective coordination shall be discussed.

Total selective coordination can be defined by modifying 2011 NEC Article 100 language to include the entire operating ranges of the OCPDs up to the maximum available fault currents. In the system shown in Figure 3, only the loads affected by fault (If) shall be taken out of service by CB4, the circuit breaker directly upstream of the fault. All other line-side circuit breakers shall remain closed. This prevents the interruption of power to all equipment where no fault occurred.

Fig 3: CB4 Operate to Clear Fault without Disturbing the Rest of the System Up to the Maximum Available Fault Current (Total Selectivity)

CONSIDERATIONS OUTSIDE OF SCOPE OF PAPER

Fig 2: Short-Time Delays for Solid-State Trip Circuit Breakers Common definitions of selective coordination have been interpreted as either 0.1 seconds, involving comparing time-current curves, or total selectivity, which includes time-current curves but also requires comparing OCPD behaviors and interaction for fault currents or short-circuit currents. There are variations on how total selectivity is described [e.g., 0.01 seconds], but the intent is selectivity for the entire operating

Ground Faults Certain instances of the NEC, Article 517.17(B) for example, require multiple levels of ground fault protection in health care facility installations. While coordination among ground fault devices is desirable, only the overload and fault protection zones of phase overcurrent devices is considered to be in the scope of this paper. Fault conditions other than overloads and short-circuits were not considered. Arcing faults Arc-flash analysis and mitigation are not considered in this paper. If the duration of an arc-flash event is limited, then the amount of incident energy produced by the event will also be reduced. Protective devices should be set as low as possible to limit incident energy to a minimum level while still providing selective coordination. While circuit breaker settings can be intentionally set to mitigate incident energy levels, which results in a system that is not coordinated, selective coordination for the system was determined to be of paramount importance for the purposes of this paper, given that the NEC does not allow for any circumstances to sacrifice coordination. The energy-based method described can provide high levels of selectivity while lowering incident energy levels.

Protective Relay Vol. 2 NEW EXAMINATION METHODS FOR DETERMINING SELECTIVITY CONSIDERATION OF LOAD-SIDE OCPD LET-THROUGH AND DYNAMIC IMPEDANCE In order to understand the new examination methods, a mastery of interpreting TCCs is first required. Once TCC fundamentals have been mastered, further exploration of the TCC will reveal limitations in determining selective coordination. A more precise examination of circuit breaker operation is required to properly apply the new selective coordination examination methods.

REVIEW OF TIME-CURRENT CURVES AND METHODOLOGY FOR PLOTTING TCCs show how a circuit breaker will respond to I2t in the overload region and to peak current in the fault current regions, on a log-log graph. Ideally an OCPD could be set precisely to trip at an exact value; however, due to various limitations for OCPD’s, tolerance bands must be plotted instead of lines to show the values at which a device could possibly trip. These values are conservative and can have a broad range of trip times for various current levels for different types of circuit breakers. Historically, electronic trip circuit breakers have been shown to have smaller tolerances than thermal-magnetic trip circuit breakers as shown in Figure 4; CB1 and CB2 are electronic trip circuit breakers while CB3 and CB4 are thermal-magnetic circuit breakers.

51 and in the fault current zone. The curves plotted by the software do not account for the current-limiting capabilities that may be available in some circuit breaker trip units. An engineer could conclude that two circuit breakers do not coordinate in the fault current zone, albeit based on limited information contained in time-current curves, when in fact they do. The current-limiting effects of circuit breakers can play a large role in the response of other OCPDs to fault currents throughout an electrical system. For the purposes of this discussion, only the current-limiting effects of two circuit breakers and their interaction with each other will be considered. Referring again to the system in Figure 3, we will only consider CB3 and CB4. When the downstream circuit breaker, CB4, operates an arc will form which introduces an element of impedance to the system that did not previously exist. The amount of this impedance is based on environmental, mechanical and electrical conditions, and can vary for different circuit breakers. This is referred to as dynamic impedance. Dynamic impedance can greatly reduce the amount of fault current detected by the upstream circuit breaker, CB3. The time is also increased to trip for the amount of current that is let-through by the downstream circuit breaker. The current detected by CB3, for a fault on the load-side of CB4, is referred to as let-through current. This current-limiting behavior is advantageous when determining total selective coordination; it is a more accurate description of circuit breaker interactions operating on fault level currents in their instantaneous trip region. It is important to differentiate and not confuse this dynamic impedance current-limitation from UL-defined current-limitation, which is limiting I2t let-through to less than ½-cycle wave of the maximum prospective fault current. Overload trip times can range from seconds to hours but typical device TCC characteristics are cut off at 1000 seconds. TCCs provide a visual indication that coordination has been achieved for three-phase faults and though these circuit breakers are subject to the same dynamic impedance discussed earlier, for practical purposes the devices are said to coordinate if it can be visually verified on a TCC. Because time differences in the overload zone are seconds, not cycles, establishing overload zone coordination with TCCs is not nearly as difficult.

Fig 4: Solid-State (CB1 & CB2) and Thermal-Magnetic (CB3 & CB4) Trip Characteristics The device curves shown on TCCs, produced by power system analysis software, are taken from manufacturer published curves developed from lab tests that show the tolerance bands of trip values when exposed to three-phase bus faults in the overload zone

Some circuit breakers can be equipped with trip units that have an intentional time delay, when a fault is detected, to allow the downstream circuit breaker to interrupt a fault. When these shorttime functions are used, it can be easily observed from a TCC that coordination has been achieved when there is no overlap in the device bands for the short-time region of the devices. Compare CB1 and CB2 in Figure 2. The instantaneous regions of the device bands tend to show an overlap on a TCC for many circuit breakers because the curves have been based on the standalone characteristics for maximum three-phase bus fault values. If dynamic impedance is considered for this region, then the fault current observed at the upstream cir-

52 cuit breaker may not be high enough to cause a trip before the downstream circuit breaker reaches its maximum trip time for the manufacturer’s tolerances for instantaneous faults. Different combinations of circuit breakers can be evaluated to show coordination at or below certain fault values even though the TCC device bands overlap each other in the instantaneous region.

PEAK CURRENT LET-THROUGH CONSIDERATIONS TCC curves cannot accurately account for dynamic system impedance, so another method will need to be used to determine if two circuit breakers coordinate. As long as the let-through current of the downstream circuit breaker is less than the minimum value at which the upstream circuit breaker may trip the two circuit breakers selectively coordinate. Two methods of calculating the level of selective coordination between a pair of circuit breakers are discussed further. These methods are: (1) the peak current point method and (2) the peak let-through curve method. Some assumptions must be made in order to use these methods. If the upstream circuit breaker has an adjustable instantaneous setting, it is assumed that it is set at its highest value. If an electronic trip circuit breaker is used, then it is assumed the long and short time functions being used are set to coordinate throughout the long and short time region of both devices. Given some circuit breakers are equipped with an instantaneous override, which must also be taken into account. Lastly, the load-side circuit breaker current let-through values, for circuit breakers not UL-defined as current-limiting, are not typically published; instead circuit breaker manufacturers instead publish tables listing line- and load-side circuit breaker combinations, and the maximum fault current level to which those combinations are selective.

Protective Relay Vol. 2 If the peak let-through current of the downstream circuit breaker is less than the peak minimum instantaneous trip level of the upstream circuit breaker, then the selective coordination level is the lesser of the upstream and downstream circuit breaker interrupting ratings (in RMS). If the peak let-through current of the downstream circuit breaker is greater than the peak minimum instantaneous trip level of the upstream circuit breaker, then the selective coordination level is the minimum instantaneous trip level of the upstream circuit breaker (in RMS). This method uses data readily available to circuit breaker manufacturers (and, for UL-classified current-limiting circuit breakers, the data is published), but it yields conservatively low selectivity results.

PEAK LET-THROUGH CURVE METHOD The other peak current comparison method is the peak letthrough curve method, which also involves converting the minimum instantaneous trip level of the upstream circuit breaker from RMS to peak current, as described in the peak current point method. The value can be plotted as a horizontal line on the same graph as the peak let-through curve of the downstream circuit breaker which can be obtained from data test points. The intersection point of these two lines indicates the level of selective coordination.

PEAK CURRENT POINT METHOD The peak current point method calculations are based on peak currents so the minimum instantaneous trip level of the upstream circuit breaker must be calculated for peak fault conditions. Many instantaneous trip settings are based on RMS values; therefore, the continuous rating must be increased by a factor of 1.4142. For example, a thermal-magnetic circuit breaker rated at 250A may have a maximum setting of 10 times the continuous current rating of the circuit breaker. UL 489 requires a minimum tolerance for this circuit breaker of 80%. The peak minimum instantaneous trip for this circuit breaker would be: 250A x 10 x 0.8 x 1.4142 = 2,828A Other considerations and adjustments must be taken into account for more complex circuit breaker functions and testing conditions such as power factor and X/R ratio. This information can be obtained from UL 489 interrupting tests.

Fig 5: Peak Let-Through Current Curve Selectivity for a LineSide Circuit Breaker with a 20 kA Instantaneous Override As shown on the peak let-through curve of the particular circuit breaker in Figure 5 the actual selective coordination level is much higher than it would have been assumed to be when a non-current-limiting circuit breaker would have been used. The dynamic impedance introduced by the current-limiting circuit breaker forces the fault current to be greater than 40kA to allow the let-through current to reach the minimum instantaneous trip of the upstream circuit breaker at 20kA.

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Protective Relay Vol. 2 ENERGY-BASED TRIP SYSTEM An energy-based tripping system, while it relies on load-side circuit breaker current limitation, is able to discriminate between load-side faults and loadside let-throughs of other circuit breakers. This method employs two trip systems working in conjunction – a conventional circuit breaker trip and a specially designed primary trip system. The primary trip system will not trip during the first half-cycle of a fault regardless of the fault current level. This delay is accomplished by using various methods. One method uses a weight and spring system to block the electro-magnetic forces that would otherwise be used to immediately trip the circuit breaker. Another uses an electronic unit to determine the duration of the fault and then trips accordingly if the fault has existed too long. The delay allows the power contacts to “pop”, or open, due to magnetic repulsion and then reclose. This develops impedance which limits the peak let-through current and energy to line-side OCPDs. In typical trip units, this reclosing action is prevented, because it can erode the circuit breaker power contacts over time. For this reason a supplemental trip system is used to monitor the energy let-through and trip the circuit breaker if necessary. Tripping due to let-through energy is called REFLEX tripping because the circuit breaker is protecting itself by reacting to energy levels that can damage it. Two different methods can be used to measure I2t values. One method uses a pressure trip system that is connected to the arc chamber through exhaust valves shown in Figure 6. When the contacts pop, the arc created generates heat as the current passes through the air. The heat erodes the ablative material inside the arc chamber in a controlled manner, which releases gases and creates pressure. The pressure trip system detects an increase in pressure and can be calibrated to trip at certain pressure levels, which can be correlated to I2t. Another method to measure the energy letthrough is by electronic means, by which the sensor continually monitors the level of energy let-through during a fault. If a certain level of energy is exceeded, the trip unit is activated to prevent the contacts from reclosing.

Fig 6: Mechanical Pressure Trip System

Fig 7: Energy-Based Selective Coordination Diagram Figure 7 shows how energy-based selectivity works. A fault on a branch circuit (A) will eventually rise to a level that will pop the contacts of the branch and main circuit breaker. Due to the relative sizes and designs of the circuit breakers, the branch circuit breaker contacts will separate more than those of the main. The greater the distance the arc must travel, the more impedance it introduces into the system, which in turn also generates more heat. When enough heat and pressure is built up, the supplemental trip system in the branch circuit breaker is activated. For electronic versions of these trip units, the total energy reaches a certain level and the trip system is activated. Once the trip system is activated the branch circuit breaker contact is open and prevented from reclosing, clearing the fault. The main circuit breaker did not reach a sufficient level of energy to trip and remains closed; however, the contact separation in the main provides additional impedance that reduces stresses in other parts of the electrical system and allows an upstream circuit breaker to assist in clearing a fault downstream and remain closed, providing continuous service to other branch circuits. Because both circuit breakers are working together to clear the fault a series rating can also be achieved for circuit breakers with a supplemental trip unit. The energy that these circuit breakers will let-through during interruption is typically more consistent than standard circuit breakers, because the actual trip is activated by a more consistent and measureable quantity – the loadside energy, rather than a peak current. Since the energy let-through is more predictable, coordinating these circuit breakers with others that trip based on the same principle is easier. The energy-based tripping circuit breakers can also selectively coordinate to higher fault current levels with load-side standard circuit breakers, due to the current-limiting capabilities of standard circuit breakers discussed earlier. The energy-based method with its load-side energy consistency, allows the line-side circuit breaker to effectively distinguish between load-side faults and let-throughs of load-side breakers operating on faults further downstream. The intentional delay

54 that allows the reflex tripping to see loadside energy does not reduce overall clearing time, resulting in higher levels of selective coordination without necessarily unleashing higher levels of fault energy, including arc flash incident energy. As a rule of thumb, line-side breakers should be selected that are 2 times the current rating of the downstream device to achieve coordination. If fault coordination can be verified using one of the methods discussed in this paper and overload coordination can be visually confirmed by a TCC, then the devices will achieve total selectivity. This simple rule and the use of the supplemental trip units discussed not only greatly simplifies coordination studies and system design, but also reduces the stress and possible damage experienced during a fault in the system. These benefits can be cascaded over several levels of a power system to provide even greater protection and coordination.

SUMMARY To achieve total selective coordination, as required by some authorities having jurisdiction enforcing the specific NEC articles, additional criteria beyond traditional circuit breaker time-current curves must be applied. This paper discussed methods used to accomplish total selectivity at high-fault current levels - methods that recognize circuit breaker current-limiting capabilities, even for circuit breakers not defined as current-limiting by UL. Most importantly, an energy-based tripping method was described, which provides consistency by using load-side energy and achieves high levels of fault selectivity. In addition, energy-based tripping is easy to apply (the results are compiled in look-up tables and on-line tools) and does not introduce additional fault clearing times or increase system arc flash incident energy levels.

REFERENCES Short-Circuit Selective Coordination by Gavin Button and Mike Tobin, Schneider Electric internal, September 24, 2008 A New Approach to Low-Voltage Circuit Breaker Short-Circuit Selective Coordination by Ed Larsen, IEEE ICPS08XP21 Energy-based discrimination for LV protective devices by Marc Serpinet and Robert Morel, Schneider Electric Cahier Technique ECT167

John Carlin, PE, is an Engineering Supervisor with Schneider Electric Engineering Services Central Studies group in Lexington, Kentucky. He received a BS degree in electrical engineering from University of Arkansas in 1987. John’s experience includes 19 years with the Central Studies group performing medium- and low-voltage power system studies for commercial, industrial, and institutional projects, both new construction and existing facilities. Analysis types performed include fault, coordination, arc flash, load flow, harmonics and dynamic motor starting. Facilities

Protective Relay Vol. 2 analyzed include automotive manufacturing, automotive testing, oil refineries, utility power stations, military weapon destruction plant, water/wastewater treatment plants, and other commercial and institutional projects. Reprinted with permission of Square D by Schneider Electric; copyright 2013. All rights reserved.

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MICROPROCESSOR-BASED RELAYS: OUT WITH THE OLD, IN WITH THE NEW NETA World, Spring 2014 Issue Dennis Moon, AVO Training Institute The question is often asked by both technicians and engineers, “Why are we replacing perfectly good electromechanical protective relays with microprocessor-based devices?” The answer is both multifaceted and interesting. It can be easily shown that electromechanical relays operate as fast as, and in some cases faster than, microprocessor-based relays. Electromechanical relays can detect complex system abnormalities and take sophisticated actions. Electromechanical relays have been in service at every level of power generation and delivery for many years, so why replace them? Here are some of the reasons that electromechanical and electronic relays are going away and why microprocessor-based relays are being specified as replacements and in new builds.

cility and allows scarce money to be spent on other needs. The maintenance needs of microprocessor based relays are also substantially less than their electromechanical counterparts, and the maintenance period can be extended thus reducing the man hours needed to test, calibrate, and maintain the relay. The FERC and NERC standard for microprocessor-based relay testing requires only tests of the metering functions, inputs and outputs, and a check of the settings.

First and foremost is the vast amount of data that can be retrieved from microprocessor-based relays that can be used to determine what prefault, fault, and postfault conditions exist at a specific relay and how those conditions affect larger system operating parameters. As system reliability becomes more and more important (think Smart Grid), more and more data is necessary to ensure constant and reliable power delivery. We can now retrieve fault data not only in numeric form, but also in sinusoidal and phasor formats. In most cases, the relay is capable of determining where system faults occurred and how far from the relay the fault was located. Highly accurate timing data can be measured because the relay can be connected to a system time clock that provides synchronization to other system devices. In this way, breaker operations, breaker reclosing, communications signals, and other timing information is correct and in proper sequence. Other information that can be gleaned from microprocessor-based relays is real time quantities such as complete system voltage, amperage, frequency, associated angles, watts, vars, power, and breaker status. This data can be sent to dispatch centers in real time to be used for load calculations, power flow, and other desired uses. Multiple events can be stored, recalled, and even replayed on modern test equipment. Relay data is now the king of system protection.

As grid stability becomes more and more important, the versatility of microprocessor-based relays becomes increasingly more vital. The availability of multiple settings groups, the precise and accurate measurement of system quantities, and the ability of the relay to communicate data between stations and control centers makes the microprocessor-based relay the best option for system protection and control.

Next is the economic impact of microprocessor-based relays. For the cost of a single mechanical impedance relay, a microprocessor-based relay can be specified which will replace a complete panel of line protection at one fifth the cost or less. Five microprocessor-based relays mounted in a single nineteen-inch rack mount panel replace as many as ten full panels in a typical substation. This significantly reduces the per foot cost of a fa-

Microprocessor relays can play a vital role in arc-flash hazard mitigation as well. These relays may implement a change in device settings via front panel push buttons so that, when technicians are working on a protected bus, arc-flash incident energy can be reduced.

In summary, microprocessor-based relays are the absolute present and future of system protection and reliability. Accurate and plentiful data, significant cost savings, arc-flash protection, and versatility are just a few of the reasons that combine to make these relays the choice of protection for engineers and technicians. We will see more and more of these relays as older relays become obsolete and are retired. Equipment specifications will nearly always be designed for microprocessor-based devices so new installation will be almost one hundred percent digital. Dennis Moon has over 32 years experience in the Electrical Industry. His varied areas of expertise includes positions such as Electronic Instrument Repair Technician, Maintenance Electrician, Senior Relay Technician and Senior Training Specialist. Additional areas of expertise includes the repair and calibration of oscilloscopes, ammeters, frequency generators, voltmeters, ohmmeters, and flatwave meters; the development and implementation of computerized relay testing programs to fit testing and calibration needs, and development, marketing, and presentation of AVO Training Institute’s specialized courses.

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EVOLUTION OF POWER SYSTEM PROTECTION TESTING NETA World, Fall 2015 Issue Ed Khan, Doble Engineering Company

In any electrical system, protection plays a very important role in ensuring reliability and continuity of power to the end user. Improper operation or non-operation of protective relays or other elements of the protection system can cause havoc in any electrical distribution system. Hence, the relays must be selected, set, and maintained in strict compliance with specific rules and standards. There is no room for slack or error. In years past, it was not uncommon to see cascading failures that started with misoperation of relays within a grid at a specific location and soon engulfed a large portion of the electrical system. Widespread blackouts were the result. Figure 1 below shows the impact of various blackouts in terms of affected customers.

Fig. 2: Progression of Relay Technology Over Time Hand-in-hand with the progression of relay technology is a similar progression of relay test sets. Refer to Figure 3.

Fig. 3: Progression of Relay Test Sets Over Time

Fig. 1: Impact of Blackouts in Terms of Affected Customers Although, not all blackouts can be attributed to misoperation of the protection system, the latter does contribute its share toward cascading events. Maintenance of protective relays has evolved from what used to be a simple task to what is often a relatively complex procedure. Relay maintenance has kept pace with technological advancements, new automation standards, and to some extent, government regulations in the United States and Europe. The first electromechanical induction disk relay was introduced around 1910. That was followed by the introduction of solid-state (static) relays around 1955. Early digital relays were introduced in 1982, and since that time have continued to advance tremendously in features and capabilities.

Assuring correct operation of protective relays is often difficult because under normal operating conditions, the protection provides little or no indication of its operational status. Relays that are not operational or set incorrectly may not prevent a system from operating. For example, if all settings on the relays are set too high, the system will operate correctly until a fault occurs, effectively defeating the protection. Furthermore, protective systems can be very complex and require careful attention to achieve meaningful testing. Protective relay and system testing can be divided into three main types, with a fourth added in some cases: 1. 2. 3. 4.

Factory Tests Commissioning Tests Pre-Commissioning (in some instances) Periodic Maintenance Tests

Each of these can utilize different tools, procedures, and methods of testing.

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Protective Relay Vol. 2 FACTORY TESTS Factory tests are divided into two parts. The first part consists of tests in which the operating parameters of the relay are simulated. A good setup to perform these types of tests uses real-time simulations.

Fig. 4: Test Setup Using Real-Time Digital Simulators Figure 4 shows the test setup using real-time simulators. These simulators provide accurate simulation of power system conditions and enable relay testing under a wide range of system conditions. The real-time simulators simulate real systems in digital form, with actual voltage and current output in the form of analog signals. Because these simulators provide a low signal level, amplifiers are needed to bring the signals to levels suitable for relays. Relay response is fed back to the simulator; the simulator accounts for this status change and modifies the calculation. This process continues in a loop, and hence, is called a closed-loop process. Real-time simulators are used extensively at large relay manufacturing facilities to perform real-time transient testing and simulation for their products. Manufacturers also use conventional test sets when required as part of overall factory testing. The second part of the factory tests addresses a devices capability to withstand vibration, stress due to temperature, electromagnetic compatibility, and impact. Many of these relay factory tests are also termed type testing since they are performed on one relay which represents a specific product line.

COMMISSIONING TESTS Commissioning tests are performed to achieve the following: ●● Ensure that equipment has not been damaged in transit and is in acceptable condition to be placed in service ●● Confirm that equipment is installed correctly and as per specifications ●● Verify the settings are installed correctly and the relay/protection system operates as intended ●● Document all drawings, references, and settings for future use

Fig. 5: Panel Wiring Testing methods can involve steady-state, dynamic, or transient tests. One item that differentiates commissioning tests from factory and preventative maintenance is the scope of work. Commissioning tests deal with not only the protective relays and associated controls, auxiliary relays, but also with the related primary equipment such as breakers, CTs, and VTs. In commissioning tests, all wiring must be ringed, or traced out, to verify conformity with applicable drawings. Figure 5 shows a typical installation that requires such verification.

PRE-COMMISSIONING TESTS For some large and critical projects such as 500 kV to 1000 kV transmission lines or lines that have series compensation, another level of tests is frequently utilized. These tests are performed using real-time simulations with actual relays wired to a simulator. These tests can include several simulations involving different types of faults at different locations under different system and fault configurations. Pre-commissioning tests makes commissioning tests easier and can save time during that stage. Various bugs related to items such as settings, relay design, and application. can be identified and resolved during pre-commissioning tests.

PERIODIC MAINTENANCE TESTS This type of maintenance is very important and has gained significant attention due to preventable blackouts that have taken out large areas of transmission systems. Protection is a very sensitive component in any power system. On an installed cost basis, a substation’s protection is a small expense compared to the cost

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of other system components, such as transformers, breakers, etc. However, from the impact point of view, the protection can have very significant importance. Statistics show that protective relay misoperations are often attributed to the following: ●● Limitations in the design of protective scheme ●● Faulty relays ●● Defects in the secondary wiring ●● Incorrect connections ●● Incorrect settings ●● Known application shortcomings accepted as improbable ●● Faulty pilot wires due to previous damage of which the maintenance staff was unaware ●● Various other causes of misoperation, such as switching errors, testing errors, and the operation of relays from mechanical shock Periodic maintenance testing is conducted using three methods: 1. Steady-State Testing 2. Dynamic Testing 3. Transient Testing

Fig. 6: Test Set with Front-Panel Controls As technology progressed, newer test sets appeared. These had either a more sophisticated front panel located on the instrument itself, a separate hand-held controller, or operational control via a computer. In a test set controlled by computer, a control panel program normally provides a virtual screen. This screen has all the looks of the controls available on held-held devices or mimics the controls available on the instrument itself. Figure 7 shows a test set controlled by a computer program that emulates all the controls.

Steady-state testing is the simplest and was performed by early generation test sets. As newer and more complex relays entered the market, test sets and testing methods progressed into dynamic and transient testing. Even though advanced test sets are readily available, not all utilities perform dynamic and transient testing. The size of the utility, the sophistication of the testing staff, and funds available determine the type of periodic testing selected.

STEADY-STATE TESTING A steady-state test is defined as applying phasors to confirm relay settings and correct operation by varying relay inputs. This testing method often involves a relay being placed on a test bench, then subjected to sinusoidal currents and/or voltages. Depending on the relay type, the operating quantity is ramped up or ramped down until the relay operates. There are several ways in which these quantities are varied. The variable(s) can be one or a combination of the following: voltage, current, frequency, or phase angle depending on the relay or element under test. In the early days, before sophisticated relay test sets were marketed, the steady-state test was conducted with manually operated instruments. The test sets had all controls on the front panel with few limited display screens. For example, the control was done via control knobs, thumbwheels, toggle switches. Figure 6 shows one such test.

Fig. 7: Controlling Test Set via Computer Steady-state testing is not automated. Measured variables such as current are manually ramped up or down; when the contact status changes, an audio or visual indication is provided. Once the contact transitions, the current or voltage injection is usually terminated. Some test sets are provided with an enhanced front panel that is part of the test set or a separate hand-held device employed by various manufacturers. Touch screen options may also be available. During the last 20 years, various manufacturers have enhanced steady-state testing by providing software that performs all the manual steps in a batch-mode form, which makes the test automated. The user has to define several variables, and then the program performs all the required steps without any manual intervention. Figure 8 shows an automated test to determine the pickup of an overcurrent element.

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Protective Relay Vol. 2 The user enters the following values: ●● Expected pickup ●● Tolerance ●● Offset Current ●● Offset Duration ●● Delta current ●● Delta Time ●● Current limit

Basically, the entire testing cycle is divided into three states: pre-fault, fault, and post-fault. All three can be imported into the dynamic program. The test set runs the three fault states, and relay response is recorded. This type of testing is implemented by various manufacturers under different names. The transition from one state to the other can be based on a maximum time allowed to run that state or conditioned upon transition of a contact. For example, in the case of three states, the prefault could be allowed to run for a period of several cycles or seconds. The fault state could be allowed to run until relay contact operation is sensed by the test set. The software receives this information on contact transition and operation and changes to the next state. The final state, post fault, can run for several cycles or be terminated by some specified contact transition. While this dynamic test description is a very simple example, the testing could expand to more states, allowing for simulation of a variety of sequential system events. One example of a type of testing is to simulate the multiple operations of a recloser. Figure 9 shows a three-state test setup.

Fig. 8: Screen Capture of an Automated Test to Determine Relay Pickup The first entry needed is a definition of the expected pickup, and this is directly obtained from the relay setting. A setting of five ampere pickup means the expected pickup is five amperes, and the tolerance can be defined as plus or minus five percent. The tolerance is obtained from the relay instruction manual or from a specific industry standard. The offset setting is needed to start the test at some point close to the expected pickup; in a manual test, the same approach is employed. Current injection is not started at one ampere if the expected pickup is five amperes; a starting point close to the expected pickup is selected. In this case, four amperes is selected as the starting point, and the test set will run at four amperes for some time (offset duration). As in the manual test, the value of current injection is increased by increments. In the automated test, this is defined as delta current; the time at each level of current is the delta time. The last entry is the current limit, which is the point at which the test is terminated if the relay does not pick up. This entire process is automated. The same types of macros or batch mode commands are built for other types of tests. As stated earlier, these tests are steady-state. The relay is not subjected to actual system conditions that could appear during a fault.

DYNAMIC TESTING In dynamic testing, the intent is to come closer to actual system conditions while using sinusoidal quantities at normal system frequency. Typically, a steady-state, short-circuit program output related to a specific fault can be obtained and mated with a dynamic testing program.

Fig. 9: Dynamic Tests Using States

TRANSIENT TESTING Transient testing is the most realistic testing type and can be used for an entire protection system as well as individual microprocessor or electro-mechanical relays. The main advantage of transient testing is that it comes closest to simulating exact system conditions and does not have the inherent limitations of the more commonly used steady-state waveforms. However, transient testing can be expensive since it can be elaborate and requires careful planning and analysis. The first step in conducting a transient relay test is to model the system under study in a transient relay testing software program. Once the system is modeled, various faults are simulated on the line or lines under study. The system could involve two, three, or four terminals. Results of the fault analysis are saved in COMTRADE or PL4 format. The behavior of the relays applied at the terminals of the lines under study is of most interest. Thus, the values of the voltages, currents, and phase angles at the terminals are determined as the system moves from a pre-

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fault state to a fault state and then to a post-fault state. The relevant information is captured in a COMTRADE format file used by the transient program of a relay test set manufacturer. The file can be viewed as a waveform, and Figure 10 shows a waveform as viewed by one such program. The next step is to modify the file in terms of assignment of sources, logic inputs, outputs, etc. After preparing this file, it is saved and downloaded to the test set. The test set starts putting out voltages and currents with correct phase angles in accordance with what is contained in the software. Figure 10 shows the waveform obtained by one relay test set manufacturer’s program. Fig. 11: End-to-End Testing End-to-end testing can be expensive since it involves a significant amount of preparation time; the time to conduct the test can also be considerable. However, this type of test has many advantages, and can be a valuable tool when performing periodic maintenance testing as well as during acceptance and commissioning of equipment and systems. End-to-end testing can verify that: Fig. 10: Transient Testing Using COMTRADE Files This type of transient testing can be used for testing each element of a microprocessor relay or a specific electromechanical relay. However, it is more typically used for conducting end-to-end testing as described in the next section.

●● The protection scheme is working correctly and as designed ●● Communication signals are sent and received correctly ●● Protection operates correctly for faults in all parts of the line ●● The entire scheme is functional at the component level as well as a system

END-TO-END TESTING

SUMMARY

End-to-end testing is a very sophisticated type of protective device testing used as a commissioning test or a routine test to ensure the integrity and design compliance of a communication-assisted protection scheme, also referred to as teleprotection. The test is conducted using dynamic tests that use sinusoidal waveforms with pre-fault, fault, and post-fault states, or using COMTRADE files under the transient test.

In summary, the industry has seen significant changes and advances in testing regimens for protection assets over the last 30 years. Changes were driven by advances in relay technology and new testing requirements such as dynamic and transient testing. Testing and maintenance of protection assets is a very robust and every developing field. There are significant changes to the execution and methodology of relay protection, and these changes are occurring both now and most likely in the not-so-distant future. Some of the changes occurring and those that are expected to occur over a period of time are being driven by the following:

Figure 11 illustrates the setup required to conduct an end-to-end test. As shown, a test set with the appropriate files is downloaded to the relays at each end. The two test sets are synchronized via global positioning satellite inputs. The test sets start at the same time to simulate a specific fault along the line, and the behavior of each relay is recorded; the test either passes or fails depending on the performance of the relays at each end.

●● Government regulations. NERC (North American Electric Reliability Corporation) is mandating testing procedures and maximum maintenance intervals for protection assets. Audits verify that utilities are following the mandate. This is forcing utilities to create centralized databases for all of their protection assets. Testing is no longer a standalone function. Test results and related data must be controlled and consolidated. Hence, testing now involves strict database management in addition to the technical aspects.

Protective Relay Vol. 2 ●● New substation automation standard. One communication/ substation automation standard that is expanding at varying rates in the U.S., Canada, and rest of the world is IEC 61850. Relays complying with this standard have very different testing procedures from those associated with conventional relays. Relays complying with IEC 61850 do not have hardwired contacts, and they accept digitized voltage and current signals instead of conventional analog voltage and current. There are test sets available to test these relays associated with what is called a digital substation. ●● Rapid replacement of electromechanical relays with microprocessor relays. On average, the current U.S. utility has approximately 60% electromechanical relays. This percentage is expected to drop significantly in coming years with corresponding increase in microprocessor relays. Testing microprocessor relays is best done using dynamic and transient testing. This will result in increased use of dynamic and transient testing. Going forward, we are sure to see many more changes and advances that will require testing procedures to be more integrated with the communication aspects of a power system. Also, as part of smart grid initiatives, we are seeing integration of microgrids and distributed power systems tied through communication links. This will lead to a new area of testing - testing components as an entire system, a system in which circuit protection will be an important part. Ed Khan has been with Doble Engineering Company for 10 years working in various capacities including Product Manager for protection test related instruments. Currently, he is the Director of Protection R&D and Training. Prior to Doble, Ed worked for GE, ABB, SEL, KEMA, and others in various capacities. He has 36 years of experience in system studies, protection applications, relay design, power plant design, teaching, and product management. He has a thorough knowledge about product development, protection, harmonic analysis, harmonic filter design, stability studies, real-time digital simulations, generator protection, and more. He has presented courses on behalf of GE and Doble in the U.S., Southeast Asia, the Middle East, Mexico, India, and China, and has taught the GE protection course on a few occasions. Ed is a CIGRE member, is currently a member of CIGRE Working Group B5.56 (Optimization of Protection, Automation and Controls), and has written and presented papers and articles on protection and testing related topics. Ed holds an MS in Electrical Engineering from Texas A&M University.

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MODERN ADVANCES IN TESTING MULTIFUNCTION NUMERICAL TRANSFORMER PROTECTION RELAYS NETA World, Winter 2015 Issue Steve Turner, Beckwith Electric Company, Inc.

This article demonstrates different techniques to test multifunction numerical transformer protection relays, so that these techniques can easily be incorporated into automated test software. The Common Format for Transient Data Exchange (COMTRADE) for power systems is a file format for storing oscillography and status data related to transient power system disturbances. COMTRADE is an excellent tool for testing relays because it can replay actual operating conditions or simulate a very complex event such as transformer energization when there is remnant flux on the core of a winding. The first two techniques demonstrate how to use COMTRADE records to test 2nd harmonic restraint for phase differential protection. The first case is playback using an actual event captured by a numerical transformer protection relay, while the second case was created using the Electromagnetic Transient Program (EMTP). Lastly, automated testing of the boundary of the phase differential operating characteristic is illustrated to properly test the relay settings.

COMTRADE SIMULATION – 2ND HARMONIC RESTRAINT ON INRUSH COMTRADE records captured by numerical relays and digital fault records from actual system events are of particular interest since these provide the ability to test protection for critical faults or disturbances that are difficult to create using off-the-shelf, test-set software. Utilities consultants and equipment manufacturers can build a library of test cases.

Fig. 1: Auto Transformer High Side Energization This is an excellent case to use the COMTRADE record captured by the relay since you can test transformer differential protection to ensure it does not operate during inrush for many applications —that is, most two-winding transformers and auto banks with five-amp, secondary-rated CTs on the high side. Figure 2 shows very little restraint current and high magnitude differential current in B Phase during the transformer energization. The trip occurred when the ratio of B Phase 2nd harmonic to fundamental current dropped too low.

The first example is the case of transformer differential protection operating during energization due to low 2nd harmonic current content in the inrush current. This event was recorded by the numerical relay protecting a 400 MVA 230/115 kV auto-transformer that was energized from the high side while the low side was open (Figure 1). The auto-transformer is connected to a 230 kV straight bus through a motorized disconnect switch. The CTs are wye-connected on both sides. The 230 kV CTs are on the transformer bushings connected with the full ratio (1200:5). Fig. 2: High Side CT Secondary Fundamental Versus 2nd Harmonic Current

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Protective Relay Vol. 2 The relevant current phasors measured by the relay at the time of the trip along with the 2nd harmonic contents are listed in Figure 3.

Fig. 4: Current 2nd Harmonic Restraint Logic

Fig. 3: Current Phasors Measured at the Relay with 2nd Harmonic Current The numerical transformer differential relay that tripped uses internal zero-sequence current compensation to prevent unwanted operations during external ground faults since the current transformers are wye-connected, and the transformer is an auto bank. Calculating the phase-to-phase current automatically eliminates zero-sequence current as follows: Ia = I1 + I2 + I0 Ib = a2 I1 + a I2 + I0 Ic = a I1 + a2 I2 + I0 Iab = Ia – Ib = I1 (1 – a ) + I2 (1 – a) 2

Ibc = Ib – Ic = I1 (a2 – a) + I2 (a – a2) Ica = Ic – Ia = I1 (a – 1) + I2 (a2 – 1) If the transformer differential relay uses phase-to-phase current to eliminate zero-sequence current, then Ibc is the most depleted of 2nd harmonic content and also corresponds to the phase that actually tripped (B-Phase). Figure 4 illustrates the following signals:

Fig. 5: Current Phasors Measured at the Relay with 2nd and 4th Harmonic Current

TEST REQUIREMENTS You will need a three-phase test set that can playback COMTRADE records. Three current channels are required. Connect the three-phase test set to the relay as shown in Figure 6A.

●● Ibc ●● Fundamental component ●● 2nd harmonic component ●● Ratio of 2nd harmonic to fundamental The ratio decreases in magnitude over the first two cycles following energization. The relay tripped at the point when the ratio dropped to 14%. Note that transformer differential relays are typically set to restrain at 15%. Figure 4 illustrates how the phase differential protection is restrained using 2nd harmonic current.

Fig. 6A: Test Connections

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Figure 6B shows off-the-shelf software available to play back this particular COMTRADE record through the test set to the relay.

1. Isolate the fundamental component and 2nd harmonic component in B-Phase current (IB). 2. Multiply the 2nd harmonic content by a factor to reduce its magnitude to the pickup level selected for the 2nd harmonic restraint. For this particular case, the minimum pickup is 10% 10%. Therefore, the multiplication factor is 0.7 (i.e., 14% ). 3. Re-assemble the B-Phase current by adding the fundamental and 2nd harmonic back together (depleted IB in the case of Figure 8). 4. Inject the adjusted current into the relay.

Fig. 6B: Test Software

TEST PROCEDURE 1. Play back the inrush case to the relay with harmonic restraint disabled. 2. The relay should trip when harmonic restraint is disabled. 3. If the relay trips, then play back the inrush case again with harmonic restraint enabled. 4. The relay should not trip when harmonic restraint is enabled. Figure 7 shows the corresponding flowchart.

Fig. 8: Adjusted Inrush Current

EVEN HARMONIC RESTRAINT DURING TRANSFORMER INRUSH

Fig. 7: Transformer Inrush Test Procedure Flowchart

ADVANCED TEST—ADJUSTING THE LEVEL OF 2ND HARMONIC CONTENT It is possible to reduce the amount of 2nd harmonic content present in the inrush current during the injection test. You can reduce the level of 2nd harmonic current until the restraint no longer blocks the differential protection. For example, 10% is typically the minimum level acceptable to set the 2nd harmonic restraint; if it were set lower, tripping might be significantly delayed for heavy internal faults due to harmonics generated by CT saturation. The software shown in Figure 8 illustrates this process:

Events such as transformer energization can be captured by utilities using digital fault recorders or numerical relays and then later played back via COMTRADE to observe relay performance. Some customers have access to software such as the Alternative Transients Program (ATP) and can build their own transformer models to simulate inrush. This is a practical method to check that the relay is properly set. One example of playback is to evaluate the performance of the restrained differential protection for transformer inrush with varying levels of harmonic content in the current waveforms. Transformer differential protection has historically used the 2nd harmonic content of the differential current to prevent unwanted operation during transformer inrush. It is advantageous to use both the 2nd and 4th harmonic content of the differential current. The relay can internally calculate the total harmonic current per phase as follows: I2-4 =

I 22 + I 42

The sum of the two even harmonics per phase helps to prevent the need to lower the value of restraint, which could cause a delayed operation if an internal fault were to occur during transformer energization.

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Protective Relay Vol. 2 Cross-phase averaging also helps prevent unwanted operation during transformer inrush. Cross-phase averaging averages the even harmonics of all three phases to provide overall restraint. The cross-phase averaged harmonic restraint can be internally calculated by the relay as follows:

FIRST CASE — BALANCED INRUSH Energized Line with Bank from Single End (No residual flux)

The transformer relay with even harmonic restraint and crossphase averaging tested for the following cases did not malfunction. The inrush currents presented here were created using EMTP and have a very slow rate of decay. Figure 9 is a one-line diagram illustrating the 600 MVA auto-transformer.

Fig. 10A: Total Phase Currents for Balanced Inrush

Fig. 9: 600 MVA Auto-Transformer Single-Line Diagram (Delta Winding DAC)

87T RELAY SETTINGS The auto-transformer differential protection settings are as follows:

Fig.10B: 2nd Harmonic Component Currents for Balanced Inrush

Fig. 10C: 4th Harmonic Component Currents for Balanced Inrush

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SECOND CASE — BALANCED INRUSH

THIRD CASE — UNBALANCED INRUSH

Energized Bank from Winding Two with Winding One Open (No residual flux)

Energized Line with Bank from Single End (Severe A-phase residual flux)

Fig. 11A: Total Phase Currents for Balanced Inrush

Fig. 12A: : Total Phase Currents for Unbalanced Inrush

Fig. 11B: 2nd Harmonic Component Currents for Balanced Inrush

Fig. 11C: 4th Harmonic Component Currents for Balanced Inrush

Fig. 12B: 2nd Harmonic Component Currents for Unbalanced Inrush

Fig. 12C: 4th Harmonic Component Currents for Unbalanced Inrush

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FOURTH CASE — BALANCED INRUSH Energized Bank from Winding Two with Winding One Open (Severe A-phase residual flux)

Fig. 13A: Total Phase Currents for Unbalanced Inrush

TRANSFORMER DIFFERENTIAL CHARACTERISTIC BOUNDARY TEST A simple procedure can automate testing the phase differential operating characteristic. A common practice for commissioning distance protection is to test along the boundary of the operating characteristic — for example, circles, lenses or quadrilaterals. This practice can also be applied to transformer differential protection. Consider the simple example of a two-winding transformer with both sets of windings wye-connected. To keep the example simple, also assume both sets of CTs are wye-connected and have the same CT ratios — that is, both windings are at the same potential. If you connect the current leads from the test set such that the test currents I1 and I2 are flowing through the transformer windings, then the perphase differential and restraint currents can be expressed as follows:

Where I1 =

Winding 1 per unit current (A, B, or C-phase)

I2 =

Winding 2 per unit current (A, B, or C-phase)

Express equations 1 and 2 using matrices as follows:

Where

Fig. 13B: 2nd Harmonic Component Currents for Unbalanced Inrush

Invert the matrix M in equation 3 to determine the two equations for the test currents:

Calculate the test currents based on an operating point on the differential characteristic as follows:

Note: This test simulates through current, so the second test current should actually be represented as follows when injecting current: Fig. 13C: 4th Harmonic Component Currents for Unbalanced Inrush

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First Example: Consider a transformer differential characteristic for the two-winding transformer described earlier with the following settings: Pickup =

0.2 per unit

Slope =

28.6%

9

10

10

11

11

12

Where IA1, IB1, IC1, IA2, IB2 and IC2 are the CT currents. Use the following equations to test the A-Phase differential element at point ② of the characteristic shown in Figure 14:

Fig. 14: Phase Current Differential Characteristic for Two-Winding Transformer Table 1 lists the four operating points on the characteristic along with the corresponding test currents. All values are in per unit.

➀ ➁ ➂ ➃

Id

Ir

I1

I2

0.2

0.3

0.4

-0.2

0.2

0.7

0.8

-0.6

0.4

1.4

1.6

-1.2

0.6

2.0

2.3

-1.7

Table 1: Test Currents for Transformer Differential Characteristic Boundary Remember that the test currents are connected at 180 degrees out of phase (i.e., through current). Second Example: Now consider a transformer differential characteristic for a two-winding transformer connected delta (DAB) — wye with wye connected CTs on both sides. A numerical transformer differential relay internally compensates the CT currents as follows:

CONCLUSION This article demonstrates different techniques to test the multifunction numerical transformer protection relays and shows how to incorporate them using automated test software. COMTRADE for power systems is a file format for storing oscillography and status data related to transient power system disturbances. COMTRADE is an excellent tool for testing relays since it can be used to replay actual operating conditions or simulate very complex events, such as transformer energization when there is remnant flux on the core of a winding. The first two techniques demonstrate how to use COMTRADE records to test 2nd harmonic restraint for phase differential protection. The first case is playback using an actual event captured by a numerical transformer protection relay, while the second case was created using EMTP. The first case can be used to test harmonic restraint for any transformer differential protection relay that has phase current inputs rated 5 amps 60 Hz; therefore, it is a universal test. The second case shows that by using the RMS value of both the 2nd and 4th harmonic current, it is possible to have proper restraint for a difficult case of transformer energization where the core has significant remnant flux. Finally, it is shown how to automate testing the boundary of the phase differential operating characteristic to properly test the relay settings; at least four points are tested, which verifies the minimum pickup, break point, and both slopes.

Protective Relay Vol. 2 Steve Turner is a Senior Application Engineer at Beckwith Electric Company, Inc. He has more than 30 years of experience, including working as an application engineer with GEC Alstom for five years, primarily focusing on transmission line protection across the United States. He was an application engineer in the international market for SEL, Inc., again focusing on transmission line protection applications including single pole tripping and series compensation around the world. Steve wrote the protection-related sections of the instruction manual for SEL line protection relays, as well as many application guides on various topics such as transformer differential protection, out-of-step blocking during power swings, and properly setting ground distance protection to account for mutual coupling. Steve also worked for Duke Energy (formerly Progress Energy) in North Carolina, where he developed a patent for double-ended fault location on transmission lines and was in charge of all maintenance standards in the transmission department for protective relaying. Steve has both a BSEE and MSEE from Virginia Tech University. He has presented at numerous conferences including Georgia Tech Protective Relay Conference, Texas A&M Protective Relay Conference, Western Protective Relay Conference, ECNE, and Doble User Groups, as well as various international conferences. Steve is a senior member of IEEE and serves in the IEEE PSRC.

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MOVING FROM ELEMENT TESTING TO PROTECTION SYSTEM TESTING NETA World, Spring 2016 Issue Christopher Pritchard, OMICRON electronics Corp. USA

When it comes to commissioning and testing the protection system, many testing tools, methods, and approaches are available to meet every goal. To make an informed decision on the best testing strategy to apply, organizations must define and constantly review their goals. Inherently, every engineer and technician tries to do a good job. Therefore, the goal is to minimize misoperations of the protection system so that equipment is protected and power system stability is maintained. To effectively minimize misoperations, recognize their causes. Why? Because when typical causes are identified, the testing effort can be efficiently focused. As with all complex systems, the cause of every misoperation cannot be predicted, but organizations should learn from detail misoperation studies of the past. The NERC "Misoperations Report" can serve as such a reference. This article will briefly discuss the misoperation causes identified by the report and discuss how different test approaches will uncover them. Also, a novel test approach is introduced to identify major misoperation causes.

NERC REPORT OVERVIEW The NERC report on misoperations gives an overview of misoperations by cause code (Figure 1) and holds two major findings: ●● A misoperation can be caused by literally every component that is part of the protection system and is categorized by relays, communications, ac systems, and dc systems failure. While each component is often tested in isolation, it’s time to move forward toward a protection system testing approach. ●● Incorrect settings and logic and design errors are the biggest causes for misoperations. This is not likely to decrease by itself, as growing demands on cost and automation forces engineers to use more functions and logic inside modern microprocessor protection relays. The challenge lies in the fact that technicians have not had sufficient information to uncover errors in the design, since it is part of a different process step. To move forward in protection testing system design — in addition to testing components — a holistic view of the process is needed. Here is a closer look at these findings.

Fig. 1: NERC Wide Misoperations by Cause Code from 2011-2013

MOVING FORWARD TO SYSTEM TESTING Making sure the complete protection system is tested is not a new concept, and it has been highlighted in several papers and standards over the past years. NERC Standard PRC-005-2 provides detailed tables for testing protection components. Other examples as described in K. Zimmerman’s “Advanced Event Analysis Tutorial Part 2: Answer Key” show that although components are tested individually, severe issues in the interfacing between components are not uncovered. A simple example to illustrate: A current transformer (CT) has been tested, and its grounding has been verified according to the scheme drawing. Also, during commissioning, the relay has been tested with the CT polarity settings of the relay. Both components passed their test, but the CT polarity settings of the relay can still be wrong. The scope of protection system testing includes testing interfaces of multiple components of the system, as shown in Figure 2. In this case, a primary injection of the CT with a primary test set — while simultaneously comparing the injected current to measured values of the relay — would have uncovered issues with polarity, ratio, and the CT wiring.

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While relays contain multiple elements, modern protection systems contain multiple relays communicating with each other to build a larger, distributed logic scheme. Again, focusing just on the individual relays would not uncover any miscoordination of the bigger protection system. But testing a system of relays, like an end-to-end test, can be a complex and time-consuming task. Therefore, here are some improvements that together build a novel testing tool.

Power System Simulation Instead of SteadyState Sequences

Fig 2: Different Tests Types of One or More Components The same pattern applies to relay testing where pure element testing is still a common approach. As the name already suggests, the objective of element testing is to prove that an element inside the relay is working correctly. The origin of element testing comes from testing and calibrating electromechanical relays containing only one or two elements — still viable for these relay types. Presently, microprocessor relays contain multiple elements that are combined with logic and may reach up to 1,000 single settings or more. During an element test, each element of a relay is routed to a test contact to test for its threshold values and time delays. As shown in Figure 3, this bypasses the internal logic, ignoring the NERC misoperation study’s finding that logic errors are a major cause of misoperation.

The most common method for testing a relay protection system is to create one steady-state sequence for each relay and test set, which are then synchronously executed. One sequence contains a minimum of two states — a pre-fault state and a fault state — but can also contain more steps such as when reclosing or restoration are tested. These states have to be calculated for each end, and most likely, for different fault positions and loops. This is a labor-intensive and error-prone task. By using a power system simulation instead, this effort is reduced to a minimum. The simulation takes care of the signal calculation, with the effort being independent from the number of relays or elements involved. Defining a test case is as easy as placing a fault in the model’s topology. Another downside of steady-state signals is that the waveform detection in modern protection relays might drive a relay to lockout on signals that have unrealistic signal shapes. Because a transient power system model can simulate realistic signals, it does not have this issue.

Power System Simulation Onsite Instead of COMTRADE Replay Another common approach for end-to-end tests is to hand over transient recordings (e.g. COMTRADE) to the technician for a synchronized injection. It is advisable to go a step further and provide the system parameters with fault and non-fault test cases to run the simulation onsite for the following reasons:

Fig. 3: Element Testing Bypassing — Not Testing — the Relay Logic An element that is missing in the trip logic could still pass its test. Also, there is a risk of making setting changes to the relay under test, which can actually cause misoperations when they are not reverted. As electromechanical relays are steadily replaced by microprocessor relays, using testing methods designed for electromechanical relays to test their microprocessor replacements is rather questionable.

●● A fault scenario communicates the intention and empowers the technician to review the test cases beyond the thoughts of the protection design engineer. This follows the four-eye (peer review) principle. ●● In case of failed tests, the technician can alter test settings to determine the sensitivity of the failed test. This is common when working close to the tolerance band. ●● It provides the ability to tune the test setup to the latest data on site with measured line impedances, measured CT parameters, transformer data from the nameplate, CT, and PT ratios as installed, etc.

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Central Point of Control Instead of Verbal Coordination Most end-to-end tests are executed by handing over test files for each location of a test set or relay to a technician. They start the execution by coordinating via phone and agree on the next possible timeslot to start. An overall assessment is only possible after the test results have been returned to the engineer. An easier method is to control multiple test sets from software on one PC. Preferably, this master PC communicates to the test sets via a direct network connection, e.g. a substation-to-substation network. If this is not available, all test sets still can be controlled from one master PC while other PCs act as a proxy (Figure 4). The proxy PCs hand over control of their test sets to the master PC.

simulation, which adapts the current and voltage signals according to the new state. As a hard, real-time simulation cannot run on distributed test sets, a step-wise approach where the software learns the sequence from the relay’s reactions is a clever alternative. This is called an iterative closed-loop test., and its advantages include: ●● Simple test definition by just placing a fault independent from the complexity of the protection system. ●● False-coordination is visualized, which otherwise would be overlooked in a predefined steady-state sequence. Also, one can assess the severity of an error as it displays the misbehavior from a power system point of view.

SETTINGS, LOGIC, AND DESIGN ERRORS General protection element-setting errors, improper timing coordination, and zone overreaching are the main cause inside the setting-error cause code. While improper coordination timing and zone overreaches can be reduced by thorough system studies, the vast amount of relay functions and settings and their effect on the system protection is extremely challenging. Quality assurance often falls to the system design process, as an element test at best is able to test that a wrong setting is transferred to the relay. To avoid the error propagation from the design step to the commissioning step, apply protection system testing. Extend the concept of covering multiple components, their interfaces, and interactions to covering multiple process steps and their data exchanges. This is extremely important, especially if one or more steps in the process are outsourced to a service company, as this makes a good data exchange between the steps more demanding. A protection system test should be an important step in a final field acceptance test by the operator. The same tool capabilities as described previously are key to this approach.

Fig. 4: Test Setup for a Three-Terminal Line Protection In addition to not starting the test verbally, this has the added advantage of results presented immediately after execution. Paired with a power system simulation, the user can easily adapt the test cases at site for all locations with almost no effort. For troubleshooting reasons, making changes to a setup that is not centralized can be extremely difficult.

Protection system design is based on power system simulations of fault and non-fault scenarios. By using the same power system data for the model used inside the testing tool to calculate currents and voltages, protection of the power system is more easily assessed. Figure 5 shows how an application-oriented test spans across the process.

Relay in the Loop Instead of Predefined Event Sequence Very often, misoperations can be found when testing beyond the first trip command of the protection system, e.g. unequally coordinated reclosing sequences or current reversal in parallel line circuits. Both cause unwanted trips or breaker failure trips. These issues are usually classified as settings, logic, and design errors, which will be discussed in the next section. Creating a predefined sequence of states can again be very complex; therefore, use a testing tool that can react to each possible trip or close command by simulating the breaker inside the power system

Fig. 5: Uncovering Design Errors by Using ApplicationOriented Testing

Protective Relay Vol. 2 THE RIGHT TOOL AT THE RIGHT TIME From a systematic point of view, it is still important to test each component before testing larger parts of the protection system. The more relays, custom logic, or complex coordination that are required, the more focus should be on application-oriented or protection system testing. The tools for application-oriented testing are already available and have shown their usefulness, e.g. for busbar, distribution scheme, and line protection testing.

REFERENCES Protection System Misoperations Task Force, “Misoperations Report,” North American Electric Reliability Corporation (NERC), Atlanta, 2013. “Protection System Maintenance,” NERC Standard PRC-005-2, 2012. K. Zimmerman, “Advanced Event Analysis Tutorial Part 2: Answer Key,” www.selinc.com, 2013. K. Zimmerman and D. Costello, “A Practical Approach to Line Current Differential Testing,” 66th Annual Conference for Protective Relay Engineers, 2013. T. Hensler and C. Pritchard, “Test and Analysis of Protection Behavior on Parallel Lines with Mutual Coupling,” Australian Protection Symposium, Sydney, 2014. OMICRON Energy, OMICRON Electronics, April 1, 2015, www.youtube.com/watch?v=a_lRgJ9_Gcc. C. Pritchard and T. Hensler, “Test and Verification of a Busbar Protection Using a Simulation-Based Iterative ClosedLoop Approach in the Field,” Australian Protection Symposium, Sydney, 2014. D. Bowman, B. Walker, C. Wright, A. Smit, A. Stinskiy, S. Chanda, T. Houseknecht, C. Pritchard, and S. Geiger, “Distributed Synchronous Coordination Field Testing of an Actual Automated Distribution Feeder System,” PAC World US, Raleigh, 2015. Christopher Pritchard was born in Dortmund, Germany. He started his career in power as an electrical energy technician. Christopher received a diploma in Electrical Engineering at the University of Applied Science in Dortmund in 2006. He joined OMICRON electronics in 2006 where he worked in application software development in the field of testing solutions for protection and measurement systems. Christopher is now the responsible Product Manager for simulation based testing solutions.

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ELECTRICAL COMMISSIONING FOR IMPROVED AVAILABILITY, SAFETY AND COST SAVINGS NETA World, Spring 2015 Issue Michael Donato, Emerson Network Power, Electrical Reliability Services While commissioning has existed as a building construction industry discipline for nearly three decades, the commissioning industry is evolving. Commissioning activities are continually being refined and updated by practitioners and industry organizations. In fact, the American National Standards Institute (ANSI) together with the InterNational Electrical Testing Association (NETA) is currently developing the new Standard for Electrical Commissioning Specifications for Electrical Power Equipment and Systems (ANSI/NETA ECS).

Additionally, it verifies that the testing organization is a well-established, full-service electrical testing business.

For critical facilities, commissioning often involves much more than just the electrical power equipment. However, the purpose of this article is to clearly define electrical system commissioning, highlight the need for this commissioning within critical facilities, and explain some of the many commissioning benefits.

While CxAs do not have any decision-making power relative to the owner, a quality CxA will offer the expertise, guidance, and direction the owner needs to make informed decisions and realize the most value from electrical system commissioning.

DEFINITION AND SCOPE The definition of commissioning varies greatly from one commissioner to the next and one building owner to the next. However, industry experts generally concur with the American Society of Heating, Refrigerating and Air-Conditioning Engineers (ASHRAE), which asserts that the focus of commissioning is “verifying and documenting that the facility and all of its systems and assemblies are planned, designed, installed, tested, operated, and maintained to meet the needs of the owner.” More specifically, the electrical system commissioning is the systematic process of documenting and placing into service newly-installed or retrofitted electrical power equipment and systems. The scope of ANSI/NETA ECS is to assure that tested electrical systems are safe, reliable, and operational; are in conformance with applicable standards and manufacturers’ tolerances; and are installed in accordance with design specifications. Additionally, the standard specifically states that “only qualified and authorized persons with adequate and relevant commissioning experience should conduct the work” described in the standard. One of the best ways for commissioners to ensure that the full scope of electrical system testing is met and that their commissioning team is meeting regulatory requirements is to work with a NETA Accredited Company. This designation confirms that technicians have the proper knowledge, training, and equipment.

Another approach that many complex, critical facilities such as data centers, use to ensure successful electrical system commissioning is to hire a Commissioning Authority (CxA) to oversee and execute the entire process. ANSI/NETA ECS outlines the responsibilities of the owner’s representative, a role that the CxA would fulfill.

Ideally, a CxA would be brought on to a project at the very beginning—during the predesign or design phase. This gives a CxA the ability to influence the details of the owner’s project requirements (OPR). The OPR becomes the keystone of the electrical system commissioning project, and the CxA makes sure that all activities align with meeting these requirements. An OPR should always be developed in order to streamline design time, establish performance targets and measure project success. One recommendation for ensuring the creation of a comprehensive, user-friendly document is to hold an OPR workshop that brainstorms project requirements and gets buy-in and involvement from all the key stakeholders. During this workshop is an opportune time to discuss the roles and responsibilities of all involved, as often commissioning is confused with other types of testing and processes. For example, some firms consider just acceptance testing and/or equipment startup to be commissioning. While those tasks are part of electrical system commissioning, much more is involved for a complete commissioning project. As stated in ANSI/NETA ECS, the commissioning standard should be used in conjunction with the most recent edition of the acceptance testing standard. Furthermore, the NETA standards should be used together with other commissioning documents to expand the scope to include all applicable systems such as mechanical instrumentation, heating and refrigeration, and building systems.

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Full System Integration

A major impetus behind commissioning electrical systems of critical facilities is the increasing complexity of the systems themselves, which presents more opportunities for problems, and the fact that there is virtually zero tolerance for unplanned downtime due to the staggering financial and reputational costs of outages.

For maximum availability, all critical systems—electrical, mechanical and controls—must function together and be a fully integrated system. Historical approaches to testing and startup verified only that each individual system’s components functioned independently. Today, a CxA employs more sophisticated processes and tests to verify that all electrical components work together to support an integrated system.

Appropriate electrical system commissioning activities can ensure uptime by identifying the causes of failures and outages. Nearly 70 percent of early equipment failures can be traced to design, installation, or startup deficiencies. Electrical system commissioning can help to detect and correct these problems before the failures or outages occur. Commissioning is also the answer to a wide variety of other owner concerns. Issues such as ensuring the operations and maintenance (O&M) staff has adequate resources, improving safety, and boosting efficiency of critical facilities can all be addressed by specifying the right commissioning activities. Therefore, the appropriate scope of commissioning relates directly to owners’ requirements for their critical facilities . It is the opinion of Electrical Reliability Services (ERS) that a comprehensive approach to commissioning—one that encompasses a wide range of building systems and spans the entire design/ build process—results in the greatest value to project owners. However, even if commissioning activities only include the electrical equipment and systems, owners can still realize many of the following benefits when critical facility commissioning best practices are incorporated.

BENEFITS Less Unplanned Downtime and Fewer Repairs Preventing or greatly reducing the possibility of unplanned downtime is perhaps the greatest value electrical system commissioning provides for critical facilities. Commissioning activities ensure that mission-critical equipment is correctly installed and that systems are fully integrated. The process checks for redundancy and single points of failure. It includes comprehensive system testing to verify availability in all operating modes. These activities help identify potential system-related problems so they can be resolved before leading to major equipment damage or disruption of service. Commissioning can also ensure a well-trained and well-equipped O&M staff that is less likely to make mistakes that lead to system failure.

Reduced Life Cycle Costs Done correctly, electrical system commissioning improves system performance throughout the facility life cycle. In addition to optimized performance, it also decreases operation and maintenance costs and cuts down on energy consumption for smaller utility bills.

Benchmarking Data Electrical system commissioning creates extensive documentation for benchmarking system changes and trends. The data can be used to identify future problems with the system, maintain optimal operations, and evaluate future maintenance decisions.

Improved Efficiency If efficiency features have been designed and built into the electrical system, commissioning activities can verify that the features function as intended. Therefore, the owner will be able to realize the resulting energy cost savings.

Enhanced Safety and Compliance The electrical system commissioning process produces a safer facility and reduces owner liability by uncovering safety problems before, during, and after energization. Commissioners can verify compliance with National Fire Protection Association’s safety-related maintenance practices (NFPA 70E). They can also ensure that owners and O&M staff have all equipment manuals and operation instructions pertaining to electrical equipment.

Return on Investment The benefits of electrical system commissioning can create a return on investment that exceeds its cost. In a recent study of commissioning projects performed by Electrical Reliability Services, the analysis revealed that the key issues discovered and corrected during the commissioning process resulted in cost savings and/or revenue earning potential for the owner that well exceeded the total cost of commissioning. Additionally, proper commissioning extends equipment life and lowers operation and maintenance costs for a lower total cost of ownership.

Speed to Deploy Under the CxA’s oversight, projects experience fewer change orders, delays, and rework, avoiding the considerable costs of late occupancy, liquidated damages, extended equipment rentals, and other costs associated with delays. Commissioned facilities are more likely to be deployed on time and on budget.

CONCLUSION Commissioning is verifiably a critical step when placing newly-installed or retrofitted electrical power equipment into service

76 within a critical facility. To realize the greatest value, owners should look for a CxA that has the knowledge and experience needed to streamline the project. Owners should also seek the electrical system testing expertise of a NETA Accredited Company to help execute the commissioning plan. When done right, commissioned electrical power equipment and systems offer a number of benefits including improved availability and safety, as well as cost savings. Ultimately, commissioning produces a higher level of owner satisfaction at the time of turnover and for many years to follow. Michael Donato has more than 24 years experience performing and managing electrical testing, maintenance and engineering services for Emerson’s Electrical Reliability Services group.In his current role and for the past 13 years, his particular expertise is in commissioning data center facilities. Michael has successfully commissioned hundreds of data centers ranging from small telecom sites to large Tier IV data centers including some LEED certified facilities. His focus has been to provide measurable value to owners at all phases of the commissioning process. Michael has earned his QCxP and LEED AP certifications and continues his education in commissioning theory and implementation through the University of Wisconsin.

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IEC 61850 —A TALE OF TWO DECADES NETA World,Winter 2016 Issue Joseph Menezes, ABB Grid Automation Products

The first version of IEC 61850 was published in 2004, though it was three years later when the final part of the standard saw print. Before the first document was approved, the Herculean work had already taken about 10 years. The final version consisted of 14 parts laying down the technical standards, and, perhaps more importantly, the semantic language for creating digital substations. The adoption of IEC 61850 has enabled a new generation of substations, more reliable and better managed, while driving suppliers to create compelling (but compatible) equipment to solve old problems in new ways. Ten years from that original publication, IEC 61850 Edition 2 is now appearing in devices, bringing another decade of accumulated experience and knowledge to the standard and broadening the reach, refining the language, and extending the functionality to reflect an industry that has changed dramatically over the last two decades. IEC 61850 was always a broad standard; it not only specified the logical architecture of a substation and the communication protocols to be used, but also the format of the messages and the functional capabilities. The standard even covers the naming conventions, the way that applications interact with devices, and how those devices are tested to ensure conformity. The major parts alone run more than a thousand pages. But the standard abstracted the content of the communications from the protocol used to convey it, allowing an evolution of networking technologies independent from the management systems. It created an object model describing what information was available and from where, as well as how devices could be configured with a standard substation configuration description language (SCL). IEC 61850 kick-started the transition to digital substations, an ongoing process that would not have come nearly this far without an internationally recognized standard behind it. Updating IEC 61850 is an epic task, but at least the standard is split into parts that can be addressed individually. Those parts are, therefore, updated separately (with one being added), and each has its own Edition 2 publication date. For basic enhancements like fixing the mistakes and ambiguities of the first version, that’s easy enough; but where new capabilities have been added, support was needed across the parts, and working groups had to cooperate to ensure interoperability was maintained. The additional breadth of the standard is obvious from the title, which has changed from Power Utility Automation to Commu-

nication Networks and Systems for Power Utilities. This reflects the use of IEC 61850 with wind and hydro power as well as distributed energy resources, where the challenges are different but the solutions may be the same. Many companies have already deployed IEC 61850 in these environments with great success, but when a system manages non-electrical quantities, then proprietary formats and language have to be used — or had to be used until Edition 2 extended the options available. Other than adding those options, the extension of the standard is just a matter of tightening up a few details and rubber-stamping the approval-for-use in these new industries. Even in traditional substations, the standard has become more broad, thanks to the increasingly complicated management systems being deployed. Modern IEDs now support several functions at once, meaning they can operate as multiple devices within a single physical enclosure. Such a device requires a hierarchical control structure, as the logical devices will share some configuration parameters and should thus be addressed as a group, while other parameters will need to be set individually and require individual referencing. Communicating new properties means extending SCL, the XML-derived language used to describe delivered parameters and reported data, which (with Edition 2) can now better support engineering processes and retrofitting, as well as provide an exchange of mandatory and optional features between IEDs and the tools that use them. IEC 61850 has become more literally broad, with the ability to communicate data between substations as well as within them. Edition 2 extends SCL so it can be used between substations creating a single management network. Initially, that will be over a low-bandwidth link; taking IEC 61850 beyond the switch yard to the point where the substation automation systems merge may take an addendum to Edition 2 — or even wait for a new edition before it is properly agreed — but Edition 2 has laid the groundwork for that to happen.

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PROTECTIVE RELAY MISOPERATIONS AND ANALYSIS NETA World, Winter 2016 Issue Steve Turner, Beckwith Electric Company, Inc. This paper provides detailed technical analysis of two relay misoperations and demonstrates how to prevent them from occurring. An unwanted breaker failure operation tripped a large generator during high load, resulting in an outage in the adjoining downtown area of a large city. A transformer differential trip protecting the generator step-up transformer at a process plant occurred due to sympathetic inrush when a large nearby GSU was energized via the interconnecting high-voltage transmission line, resulting in an extended outage.

Fig. 2: Breaker Failure Logic

Original Protection Settings Figure 3 shows the original relay settings for this breaker failure scheme.

Each individual analysis ends with a conclusion stating why the relay misoperated and providing a recommendation on the best practice for the particular application.

CASE 1: UNWANTED BREAKER FAILURE OPERATION — LARGE GENERATOR TRIPPED DURING HIGH-LOAD PERIOD Synopsis During a period of high load, a breaker failure trip occurred in a large offline generator located in the downtown area of a large city resulted in an outage. Figure 1 shows the system topology at the time of the trip. Note that the generator is connected to the transmission grid via a high-voltage breaker. The links connecting the generator to the GSU were open as well as the high-side breaker. The low-side winding of the GSU drew excitation current since it was energized via the auxiliary station service.

Fig. 3: Breaker Failure Settings

Fault Current Signals Figure 4 shows the oscillography captured by the relay at the time of the trip.

Fig. 1: System Operating Conditions

Original Breaker Failure Scheme Logic Figure 2 shows the original logic used for this breaker failure protection scheme.

Fig. 4: Fault Event Oscillography

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Fig. 7: System Operating Conditions (Arrows Indicate Direction of Inrush Current)

ORIGINAL PROTECTION SETTINGS Fig. 5: Fault Current Phasors

Figure 8 shows the original settings for the transformer differential protection.

Case 1 Conclusion The breaker failure trip occurred because IC was above the current detector pickup setting and input 4 (BFI) was asserted. The breaker failure function may be used for a unit breaker rather than a generator breaker. It is limited in that no fault detector is associated with the unit breaker. Output contact operation would occur if any of the initiate contacts close, and the 52b contact indicated a closed breaker after the set time delay. The corresponding logic is shown in Figure 6.

Fig. 8: 87T Settings

Fault Current Signals Figure 9 shows the oscillography captured by the relay at the time of the trip. Note that current input IAW1 is almost completely offset, and there is some distortion in other current inputs as well.

Fig. 6: Fault Current Phasors

CASE 2: TRANSFORMER DIFFERENTIAL TRIP DUE TO SYMPATHETIC INRUSH Synopsis The transformer differential relay protecting the step-up transformer at a processing plant tripped when a nearby large GSU at a power plant was energized from the high side. The trip was due to sympathetic inrush current flowing through the step-up transformer (Figure 7).

Fig. 9: Fault Event Oscillography (Raw Waveforms)

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Figure 10 shows the second harmonic content of the current inputs at the time of the trip.

Case 2 Conclusion For several decades, electro-mechanical relays had a fixed harmonic inhibit level of 20 percent. This worked well for a period of time until transformer manufacturers began making better transformers that used less material and were designed with smaller tolerances. Therefore, modern laminated-steel-core transformers will not reliably produce 20 percent second harmonic current during inrush. Based upon this particular event, an 11 percent setting for the second harmonic restraint would be the most reliable. Note that the multi-function numerical relay in this application actually uses the root mean square (RMS) of the second and fourth harmonic differential current, but that still was not enough to restrain the protection.

FINAL CONCLUSION

Fig.10: Fault Event Oscillography (Second Harmonic Content) The second harmonic differential current present when the trip occurred was as follows: A-Phase = 17 percent B-Phase = 13 percent C-Phase = 13 percent The ratio of harmonic to fundamental differential current used to restrain the transformer differential protection is calculated as follows (Figure 11):

Fig. 11: Even Harmonic Restraint Equation If the ratio is greater than the restraint setting, then the transformer differential protection is blocked (Figure 12).

Fig. 12: Even Harmonic Restraint Logic The original second harmonic restraint setting was 20 percent for the electro-mechanical transformer differential relay. The customer used the same setting for the multi-function numerical relay that replaced the original electro-mechanical relay. Figure 10 shows that a setting of 20 percent was not sensitive enough to detect the sympathetic inrush current flowing through the step-up transformer.

The technical analysis of these two relay misoperations, along with examples of how to use the data recorded by a relay during these types of conditions, should help you understand why each misoperation occurred and how to implement best practices for each particular application. Knowing that the first misoperation was due to an incorrect relay setting, while the second was due to an incorrect application, should clarify the need for careful attention during the design and initial work stages. Joseph Menezes is the Global Product Manager for ABB Grid Automation Products, responsible for the Relion® 670 series protection and control products. He has 25 years of experience in automation, control, and protection of power systems with a background in product development and product management.

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THE FUTURE OF INTEGRATED POWER AND PROCESS AUTOMATION NETA World, Winter 2016 Issue David C. Mazur and John A. Kay, Rockwell Automation As technology continues to drive innovations, industrial enterprises must continue to keep pace to remain competitive in an ever-changing marketplace. The technology trend is to replace yesterday’s systems with higher-performance, low-cost, option-rich devices that shorten the return on investment and offer more flexibility. As control system technology evolves, systems migrate to functions that are being increasingly distributed to smarter, more granular, control-system components capable of performing localized operations. Industrial facilities are under increasing pressure to reduce overall costs, boost productivity and quality, and improve personnel safety. One systematic approach for reaching these goals is automating and integrating facilities from the plant floor through the management of process information. Device-level integration through digital communication is the key to unlocking the full potential in the electronic controls being installed in industrial plants today. New advancements in device-level status monitoring and communications have boosted process throughput, system practicality, and affordability of complete plant-level integration. Furthermore, while the industrial automation space was being transformed by networks and communications, so, too, was the electrical infrastructure market. The challenge that remains is how to effectively integrate these two systems in an optimized, intuitive fashion. If one compares the evolution of heavier-than-air vehicles, adding more powerful engines was not a solution when there was lack of proper and efficient flight controls. Without a review of the entire system, such as with the power and process systems of a modern facility, the overall system will lack high performance.

Fig. 1: Process and Power Models Figure 2 shows that, although the process and power automation systems have been logically isolated by industry, they are closely coupled to each other. It is very difficult to logically separate power from process, as they are intermingled within each other. The figure represents the power automation network in red and the process automation network in green. The red arrow suggests the linkage needed to realize the full potential of these industrial systems.

POWER AND PROCESS TRENDS TODAY Today, many industrial processes are controlled by a combination of systems working together (hopefully, in sync) to produce a target yield or product. Examples of these systems include continuous and discreet process control systems, electrical protection, SCADA, historian for archiving, and reporting tools for data trending. Traditionally, these subsystems have been logically separated as seen in Figure 1. The red boxes in Figure 1 depict the process automation system with intelligent motor control (IMC) devices — e.g., variable frequency drives, overloads, starters, etc. — feeding a process controller. This process controller feeds data to higher level systems to archive and report on the data. The blue boxes represent the power automation system where intelligent electrical devices (IEDs) feed a power automation controller. This controller, in turn, feeds similar higher-level systems to archive and report on the data. Although these two systems are within the same facility, they are logically isolated.

Fig. 2: Power and Process Systems

THE EVOLUTION OF POWER AND PROCESS AUTOMATION Advancements in technology have created a society where companies want to collect a large amount of real-time data, sort this data — and with the advent of the discrete event data — turn this into actionable information. Today, there is a push to archive this discrete data so that it can be trended at a later time, as well as used for modeling of the overall process. From an industrial manufacturing standpoint, electrical protection and SCADA data is crucial to identify operating points, create predictive mainte-

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nance models, identify load-shedding opportunities, and manage energy consumption and root-cause analysis. As the information age has evolved, so has the technology used to transmit data from the electrical protection system to SCADA systems. Power system and industrial-based electrical protection devices have evolved over the past three decades from electromechanical to microprocessor-based relays. In parallel, the communication networks for electrical protection have also evolved. Electrical protection architectures have developed from hard-wired contacts to communication networks using serial protocols, such as Modbus. Serial communication has evolved to communication protocols over the TCP/IP stack, such as Modbus TCP and DNP3 LAN/WAN, which then allowed substation devices to communicate in a peer-to-peer manner to share data. The IEC 61850 standard has become more prevalent in recent years. These examples and applications show that an Ethernet-based standard, such as IEC 61850, can be used for protection, command and control, and SCADA gathering of data over the same redundant wire pair. As this real-time data is provided to the central controller or SCADA master in the system, graphics can be populated to alert engineers and operations to system status in a time-synchronized fashion. Additionally, this data can be used to make command-and-control decisions in an industrial application. Furthermore, leveraging power and process in a unified solution provides users many benefits while reducing the overall total cost of ownership.

A UNIFIED SOLUTION FOR POWER AND PROCESS By using data from process and power controllers, an iterative evaluation of overall system efficiency, process-stage efficiency, and product quality can be performed. The result can help eliminate process bottlenecks and inefficient process steps, and reduce energy usage while maximizing overall system or plant output performance. Installing more efficient machines in one process step may actually be detrimental to the overall system performance without the review and collaboration of data from both data sources. Furthermore, harmonizing the upper layers of visualization, archiving, reporting, and enterprise services reduces cost and overhead for industrial process owners. The value of the unified system can be realized in the visualization, archiving, and reporting systems.

VISUALIZATION Although automation control companies have developed solutions for process visualization, this solution takes process visualization one step further into the electrical distribution system. The IEC 61850 standard allows for the visual representation of reports and alarms at the process control level. With the development of more sophisticated human-machine interface (HMI) screens, global objects have been introduced into the automation graphics. The use of these global objects has allowed for the creation of faceplates, defined as reusable standard objects.

Fig. 4: Graphical Faceplates Examples of process faceplates can be seen in Figure 4. The left side of Figure 4 shows the representation of a low-voltage power circuit breaker with its command-and-control functions. The right side of Figure 4 depicts a faceplate of a low-voltage, variable-frequency drive. Each faceplate was constructed with multiple tabs to change between home, engineering, and diagnostic screens. Graphics were designed to provide a user experience similar to interacting with the physical device. The advantage of the faceplate is that it is a familiar, standard, prebuilt object that can be implemented repeatedly for similar engineering designs. The common naming convention and logical model of IEC 61850 allow for a vendor-independent implementation of electrical distribution equipment, e.g., circuit breakers, relays, power monitors, etc. This information can be simultaneously displayed with process information provided by IMC devices, e.g., drives, overloads, starters, etc. Providing a unified visualization environment allows all pertinent information to be displayed in one place where data can be effectively acted on as actionable information.

ARCHIVING

Fig. 3: Unified Visualization, Archiving, and Reporting

Time stamping of event data can be placed in a process historian, even if the act of event detection is a distributed system component. This enables reporting and key performance indicator (KPI) calculations based on energy data, as well as manufacturing processes variables. The impact of manufacturing intelligence with power systems data will yield relationships that, to date, have not been available in typical reporting environments. IEDs are critical to the management and control of industrial and commercial power systems, and can provide value in an environment with process historians.

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Protective Relay Vol. 2 Highly accurate and time-synchronized energy consumption and energy balance data can be used to determine overall process efficiencies for various production or process operations. Data from trip and alarm events can be deterministically used to establish maintenance schedules to prolong equipment life. Additionally, machine or production-flow characteristics can be refined and monitored to enhance production rates and maximize specific machine capabilities.

ASSET-BASED MODELING The Industrial Internet of Things (IIoT) has created an environment where more data from assets is available than ever before. KPIs have traditionally been used to define metrics of industrial petrochemical facilities. The IIoT can present a number of KPIs for facility assets that are not uniform across similar types of equipment. Consequently, users have been seeking consistent application of KPI solutions across their enterprise assets. The definition of an asset template allows for consistent representation of a device across the industrial enterprise. Furthermore, this allows for comparison between assets or control processes in a standard fashion, thus optimizing reporting capabilities. Asset models for equipment remove the concept of flat tags in a historian, replacing it with an object-oriented model. Tags that are monitored and archived are now associated with a physical piece of equipment or process, allowing context to be immediately applied. Furthermore, analytics can now be trended on each asset. Additionally, asset performance can now be compared at multiple levels: asset to asset, process line to process line, and facility to facility. The concept of asset modeling can be applied to power and process automation, thus providing standardization across the industrial enterprise.

Fig. 5: Asset Model Example

REPORTING The large quantity of data generated by modern automation systems makes it possible to apply a broad range of plant analytics to the automation systems and processes that make up an industrial enterprise or business. Reports, charts, and other human-readable formats are often available or may be created for plant personnel and others to monitor and review the generated data in either a real-time mode or at a later time after the data has been stored.

A report created to display the data of a given industrial automation system may find it difficult to find and display similar data of another industrial automation system. Objects and other components of the other system may be similar or even identical to the first system. However, due to even slight variations in component names (for example, during the system setup stage), a disconnect can exist between the data stored in the system and a pre-generated report designed to look for specifically named objects in the system. Thus, reports previously created may not display all the data they were designed to show. Creating new reports or even fixing pre-generated reports to show the data generated by a particular system can be a laborious and tedious manual process. This process can require setting up individual connections between system data points and the parameter value to be reported for hundreds of parameters or more. The benefit of the IEC 61850 standard is that the logical model allows for standard reporting across vendors in a specific format. This means that an IED of a specific type from Vendor A can be reported on the same way as an IED of the same type from Vendor B. IEC 61850 allows for asset-based reporting models and type-based reporting, where reporting systems have the context of devices on which they are reporting. By creating type-based reports, users can associate content in the form of trends, graphs, and analysis on a particular type of device. When it is instantiated within the enterprise system, the reports come pre-populated and wired to system tags due to the common naming convention of the standard. This provides a substantial design time savings for implementers of a unified system.

UNIFIED POWER AND PROCESS REPORTING Even more powerful reports can now be created in a unified environment. These reports may provide additional insight into cause and effect of how changes in the power automation system affect process automation and vice versa. These reports will allow process owners to provide better predictive and preventive maintenance, as well as optimize their overall process to new levels. The ability to obtain electrical information within the unified system allows for energy inputs into the facility optimization state space equation. For example, in Figure 6, a unified system, a process owner can realize instantaneous profit, as they know all of the process yields (gross profit blue line), as well as the total costs to produce (red line). The area between these two curves provides the owner the instantaneous system profit in a timely fashion. This information can feed additional control loops to take corrective action and further optimize the process. Now, electrical distribution parameters can be effectively used in process optimization schemes. Furthermore, this electrical data can now be used in overall efficiency calculations and asset liability, and can be presented in dashboard format as seen in Figure 7. This data can be used to compare not only process line data, but also can be extrapolated in a facility-to-facility comparison providing a true enterprise comparison for process owners.

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Protective Relay Vol. 2 S. H. Horowitz and A. G. Phadke, Power System Relaying: John Wiley & Sons, 2008. D. C. Mazur, R. D. Quint, and V. A. Centeno, “Time Synchronization of Automation Controllers for Power Applications,” IEEE Transactions on Industry Applications, vol. 50(1) (January 2014): 25-32.

Fig. 6: Simulated Profit of an Oil Pumping Station

D. C. Mazur, J. A. Kay, and J. H. Kreiter, “Benefits of IEC 61850 standard for power monitoring and management systems in forest products industries,” in Pulp and Paper Industry Technical Conference (PPIC), Conference Record of 2013 Annual IEEE (2013): 69-75. D. L. Ransom and C. Chelmecki, “Using GOOSE messages in a main-tie-main scheme,” in Industry Applications Society Annual Meeting (IAS), 2012 IEEE, 2012, pp. 1-8. D. Dolezilek, “IEC 61850: What You Need to Know About Functionality and Practical Implementation,” in Power Systems Conference: Advanced Metering, Protection, Control, Communication, and Distributed Resources, 2006. PS ‘06 (2006): 1-17.

Fig. 7: Process System Dashboard

CONCLUSION A common connected architecture across the process control and power control infrastructure creates a straightforward method for an organization to securely integrate and manage information flow across the entire connected enterprise. Captured enterprise-wide data — starting from the most critical assets to the smallest shop-floor sensors — can provide the most relevant working data capital needed to deliver complete plant- and enterprise-wide automation and process efficiency. The true value of this enterprise-wide data lies not in the data itself, but in which analytics can be applied to the data. In this way, the raw information reveals areas where process and control transformation can be applied to identify points where power and process optimization can be employed. This working data capital is easily displayed and analyzed by those decision makers, at many levels of the enterprise, who can put it to best use. Using the most relevant interconnected technologies enables more efficient analysis, communication, and visualization of this valuable and scalable working data capital across the entire enterprise.

REFERENCES D. C. Mazur, J. A. Kay, and K. D. Mazur, “Intelligent motor control, a definition and value add to process control,” in Industry Applications Society Annual Meeting, 2013 IEEE (2013): 1-7. D. C. Mazur, “An Electrical Mine Monitoring System Utilizing the IEC 61850 Standard,” Doctor of Philosophy, Mining and Minerals, Virginia Polytechnic Institute and State University, 2013.

V. M. Flores, D. Espinosa, J. Alzate, and D. Dolezilek, “Case Study: Design and Implementation of IEC 61850 From Multiple Vendors at CFE La Venta II,” in Protective Relay Engineers, 2007. 60th Annual Conference for Protective Relay Engineers (2007): 307-320. T. Zhao, L. Sevov, and C. Wester, “Advanced bus transfer and load shedding applications with IEC61850,” in Protective Relay Engineers, 2011 64th Annual Conference for Protective Relay Engineers, (2011): 239-245. L. Sevov, T. Zhao, and I. Voloh, “The power of IEC 61850 for bus transfer and load shedding applications,” in Petroleum and Chemical Industry Conference (PCIC), 2011, Record of Conference Papers Industry Applications Society 58th Annual IEEE (2011): 1-7. David C. Mazur is System Architect for Rockwell Automation in Milwaukee, Wisconsin, and currently focuses on SCADA communications and substation automation. David received his B.S. in Electrical Engineering from Virginia Polytechnic Institute and State University, Blacksburg, Virginia, in 2011. He graduated from Virginia Polytechnic Institute and State University with his M.S. in Electrical Engineering in 2012 for his work based on rotor angle measurement of synchronous machines. David received a Ph.D. in mining engineering from Virginia Polytechnic Institute and State University in September 2013 for his work with automation and control of the IEC 61850 standard. John A. Kay, received his degree in electrical/electronic engineering technology from Conestoga College, Kitchener, Ontario in 1977. He has authored a wide variety of award-winning technical papers and other articles and manuals related to medium-voltage electrical control and protection systems, arc-resistant equipment, and infrared technologies. John is a Fellow of IEEE and the Industry Application Society. He is also actively involved with the IEEE Pulp and Paper Industry Committee, serving on its main executive board, its conference committee, and on several subcommittees. He is a Certified Engineering Technologist in the province of Ontario.

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USING TEST PLANS AS A TOOL FOR PROTECTION TESTING SPECIFICATIONS NETA World, Summer 2016 Issue Benton Vandiver III, OMICRON electronics Corp. Over the past 30-plus years, I have had numerous conversations with technicians, engineers, and managers on how to create the best test plan for many of the relays, protection schemes, and protection-and-control (PAC) systems used in the utility industry. The discussion generally turned into a lengthy laundry list of what they actually wanted to accomplish during their test process. Some of the tasks mentioned included:

3. The user’s final configuration/settings of the Intelligent Electronic Device (IED) or system (Figure 1)

●● Proof of calibration ●● Proof of proper settings ●● Proof of the ac system components ●● Proof of the dc system components ●● Verify the interconnections ●● Verify the functions ●● Verify the scheme logic ●● Verify the overall protection system coordination For these tasks, the test plan comprised a specific list of the test methods and steps required to accomplish them. For the proofof tasks in electromechanical devices and systems, the steps were essentially specified by the manufacturer in the device instruction manual and any special publications dealing with maintenance tasks or calibration. For newer technologies, these specifications evolved to more black-box testing designed to prove the device specifications or troubleshoot the device’s components and calibration, since typically, the setting parameters were directly set or displayed physically on the device. In the newest digital technologies, this has been supplanted by software programming of the parameters and firmware updates, self-diagnostics, observational testing, logs, and reports. Most often, what was actually desired from the test plan was the least amount of work to satisfy a testing compliance requirement. In addition, they wanted an assurance that the testing performed was sufficient for the task(s) that the tester executed, and that the test procedure was correct, accurate, and repeatable. It was a bonus if the test procedure was self-instructing or automated so that training was minimized, the ultimate goal being the one-button test. In the past, a working test plan for a PAC device or system was not automatically delivered with it, nor was it made by accident. It evolved from three distinct steps driven by the utility user: 1. The test philosophy implemented by the user 2. The user’s protection philosophy and a generic test plan structure developed from it

Fig. 1: An IED-Specific Test Plan A user’s test philosophy is often based on operational history — usually scenarios of specific device misoperations from a variety of causes — as well as compliance issues, manufacturer guidelines, and industry standards. Often, the philosophy was known but not always documented effectively and was internally perpetuated through on-the-job knowledge (e.g., “We always test at 2x, 3x, 4x pickup.”). As PAC technology changed, the testing philosophy adapted slowly or not at all, resulting in unnecessary or improper testing of the new PAC device or system. This also extended to: ●● Test equipment used ●● Tolerance definitions and performance expectations ●● Test methods applied ●● Proper training (knowledge and skills) ●● Documentation of the objectives (compliance, calibration, etc.) Some examples would be using a one-phase test set on a relay using three-phase algorithms and logic; using electromechanical tolerances on a precision digital device; step-change injections expecting dynamic performance; or no PC/software user skills and expecting one-day training to master the PC-controlled test kit. The proactive user would take all these points into consideration and craft a protection system specification(s) that would clearly convey how the devices and systems should be applied, the test philosophy employed, and how it was to be achieved. It was a living document continually updated based on current PAC devices and systems in use, compliance requirements, training requirements, and performance expectations.

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When a specific protection philosophy was applied, it refined the definition of what was to be tested. Using a basic fourzone step distance scheme as an example, we could construct a generic four-zone step distance test plan of the functions (reclosing, loss of potential, etc.); protection elements (21P, 21G, 50/51, 59, etc.); interfaces (physical I/O, control, etc.); and logic (permissive overreach transfer trip {POTT} and breaker failure, etc.) that should be tested and should include the test equipment, tolerances, and test methods stated in our test specification. At this point, the test plan could be used as a functional test specification (Figure 2) for this type PAC device or system because the What, Why, and How questions should now be known.

Today, many utilities have lost expertise and cannot follow these steps; they increasingly rely on other sources to bridge these gaps. With modern software solutions, the specific IED can be data modeled and parameters imported, then recalculations made and mapped to the functional test module performing the specific defined testing task, including the required hardware interfaces (Figure 3). Additionally, modern test software can use purpose-built test modules or a power system mathematical model to relieve the task of defining individual test methods for each function, element, or logic scheme. Since the beginning of my career and regardless of the protection devices/systems and technology used, there has never been a perfect tool for creating such test plans. The fact is that it requires a deep knowledge and understanding of what it is you are testing. Whether it is an auxiliary dc relay or a modern HV digital line protection IED, or an application like a permissive overreach transfer trip scheme over fiber, understanding what it is designed to do and how it does it is necessary for organizing any of the previous testing tasks successfully.

Fig. 2: Test Specifications However, we still do not have an executable test plan because we are missing the specific manufacturer device(s) used, the specific configuration parameters, and the specific protection settings that finally dictate the exact testing to be performed. For instance, the specific line being protected may not require a fourth-zone element, so the configuration information would indicate it is not used or required. This would mean only three-zone elements need to be tested, and any scheme, function, or logic associated with only the fourth zone would be ignored. So a mechanism to get these configuration parameters/protection settings into the generic test plan was needed, as these were typically entered manually. (Today, of course, they are possibly imported electronically.) Often, the parameters used in a specific PAC device vary from manufacturer to manufacturer, even when they perform identical functionality. Further, the actual parameters used to define the test method can be a different data type or mathematical equivalent. So translation of these specific device parameters into test-method parameters was another task necessary to create the executable test plan.

Fig. 3: The Hardware Setting Parameters Some may disagree, citing that a good generic test specification can be written from a common denominator (generic) practice, an approach that in turn can generate the required test plan. But I see this as a chicken-and-the-egg discussion or Schrodinger’s cat situation: If you do not know the actual device details, how can you possibly test it? Even in the case of the simplest network model, you must understand how it works, its limitations, and the data it requires to function correctly. However, there is no argument in the industry that device technology dictates the test tools and techniques required and that the objective is the proof of the device as applied in situ. So taking the device out of its commissioned state to make functional or element tests indicates lack of good specifications and systems engineering. A properly engineered IED or PAC system will be testable with the correct tools and simulations. The fact is, there is nothing to test until there is a device or system design, and no design until there is a specification to build it a certain way. So we are back to the specification

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Protective Relay Vol. 2 again. Naturally, one would conclude that whatever this specification is, it should then be used to define the test plan. If we are talking design absolutes like the strength of an I-beam made from different materials, then yes, it could be. For instance, a 10-foot-long oak I-beam may have a design-loading factor of 100 pounds, whereas one made from cold steel might be 1,000 pounds. To prove the design, a simple test would anchor one end of the beam and apply an increasing dead load at the other end until the beam failed. This would be destructive, but necessary to prove the design and specification, and many industries perform these tests.

This methodology could be seen as backwards but for one key point: With the knowledge of the application and the specific parameters of the configured devices, we are able to define a whitebox testing environment, one in which we know the output based on the internal responses of the system based components/devices from known application-based input simulations. In other words, we have a detailed understanding of the devices and system, and therefore, can prepare a proper test plan to prove it. (Figure 5)

In PAC systems, we do not typically test them until they fail (we let Murphy take care of that), but we do need to apply best practices in verifying their design and operation prior to implementation and during service life. The other consideration for PAC systems and their devices is the variable nature of designing/applying them. Most of today’s devices are digital, use communications, and are programmable in configuration and scheme logic, making their testing dependent on their intended application and the specific parameters used (Figure 4 below). The device specification cannot be used directly for defining the test plan because there are too many variables, overlapping functions, and implementations unique to the manufacturer. Further, when we take multiple devices and use them together in PAC systems, the aggregate specifications of all those devices could create conflicting test requirements across the system and, in some cases, damage them if not properly considered. The specific settings/parameters applied based on the intended application restricts them and blends these devices to work together within the PAC system. This provides the details necessary for developing the test plan. Once the test plan is derived according to our required task list and proven against the PAC system configuration, then it can be the basis for extracting the test specification for this specific PAC system implementation.

Fig. 5: IED Test Results — Distance Zone Elements

Fig. 4: IED Test Plans Adapting to Actual Settings and Creating Specific Functional Tests

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DEVELOPMENT METHODOLOGY — TEST SPECIFICATION The multifunctional design of modern numerical protection devices usually requires different methods to test the different functions integrated in each of them. It is obvious that to define the test specification, we need to start with the type of protection being tested. As mentioned, the test specification depends on the user’s testing philosophy and the regulator’s compliance requirements. It defines what types of tests need to be performed for different types of function elements, schemes, or applications as well as any characteristics of the test method used depending on the purpose of the test: type, acceptance, commissioning, maintenance, etc. (Figure 6).

Fig. 7: Completed IED-Specific Test Plan The test specifications must define: Fig. 6: IED Zone Characteristic Test Results Based on the testing philosophy, a generic test plan can be structured that defines the required test hardware and specific implementation considerations based on the PAC device or protection IED dependent: ●● Interfaces: hardwired voltage, current, I/O or IEC 61850 GOOSE, or sampled values ●● Bay configuration (for example, breaker-and-a-half) or application configuration (two-ended line model) Once the generic test specification for a protection type is created as a generic test plan, it can be customized to meet the specific functionality of a selected manufacturer’s IED used for the protection type under consideration and represented then by an IED-specific test plan (Figure 7).

●● The functionality of the tested multifunctional protection IED represented by different protection function elements, such as distance, differential, overcurrent, etc. ●● The required test devices needed to execute the tests ●● The interfaces between the test equipment and the test object ●● The test modules (methods) to be executed as required by the testing philosophy Such an approach allows improvement of the testing process efficiency by defining the required hardware configuration only once at the beginning of the test specification. The hardware configuration represents the signal path between the testing tool and the test object and contains complete information about: ●● The assignments between the inputs and outputs of the test software and the test object terminals ●● The used test hardware as well as its configuration ●● The wiring between the test hardware and the test object terminals

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Protective Relay Vol. 2 The setting parameters of the test object are also not specified individually for each test module, but only once at the beginning of the executable test plan configuration (Figure 8). The same applies to the generation of a single test report that covers all test results. Any number and type of test modules can be combined into one central document to form a complete test plan that matches the requirements of the functions tested.

that differ only in their parameter settings (e.g. relays of the same type on different feeders) is substantially simplified since a test plan, once created, only needs minor adjustments. The fundamental difference between a test plan and a test specification is that a test plan not only tells us how to perform the test, but it also has knowledge of what the test results should be. A generalized test specification cannot contain the specific expected results, only relative parameters like tolerances. When describing to a technician, contractor, or test company via a test specification, the information must be as specific as possible and derived by extracting that specification from successful test plans. If an independent way existed to describe all the devices, interfaces, communications, logic, and settings used in PAC systems, then our industry could evolve engineering tools to define its many unique applications in a standardized way. In fact, it would be possible to not only self-describe the PAC system as designed, but also provide a mechanism to self-define its test plan based on those defined relationships. You guessed it: That’s IEC 61850. Although long-coming, IEC 61850 (Ed 2) is approaching a new level of maturity. In Part 6, the Substation Configuration Language (SCL) has grown to encompass more information on PAC devices. This substantially increases the self-description details where the key data and relationships of the configured devices from the SCL can be used. If combining application/test tool knowledge with the existing SCL data, test plans could be defined directly. Expansion of the SCL to include test devices described as logical nodes with data objects and data attributes would enable the goal of creating test plans and test specifications.

Fig. 8: IED Functional Model with Specific Configuration and Settings The test plan can be executed as an automatic sequence. When running it, the defined test functions of each selected module are executed before the program automatically switches to the next one, until all the modules have been completed. After the completion of the test, the software enters the results into the test plan document, which creates a comprehensive overall test report. The test report still contains all of the test settings (protection device parameters, test modules used, test points, etc.). Using a protection IED-specific test specification for testing several relays

A utility using the IEC 61850 data model can define the single line diagram, all functions used, and their logical nodes/data types. From this, a device-independent specification can be made using the System Specification Description (SSD) file with a top-down design that will constrain vendors and system integrators to the utility’s system specification. This means the supplier is not free to make a non-conformant, bottom-up design using their own tags and architecture. Further, with test tool/device extensions of the SCL, the utility could also include the test plan from the SSD with all test processes defined (what to test with expected values) and then easily formalize a conformant test specification from it (an annotated report).

CONCLUSIONS The ability to create a properly constrained test specification that has value has always been a challenge, but IEC 61850 is poised to deliver on a long-awaited capability — creating a test specification from the top down that includes the functional test plan, too. The best specification is one that: ●● Exists ●● Describes what, not how ●● Cites relevant industry standards

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●● Clearly defines testing tasks such as acceptance, commissioning, routine, and maintenance ●● Has only one interpretation ●● Is available to all parties ●● Is the spec agreed to by all parties involved ●● Only includes what is necessary ●● Is consistent (avoid using “it” or “which” and clearly specify “what”) ●● Defines the jargon and abbreviations common within the industry ●● Describes the test objectives so a novice can understand them ●● Is updated regularly as requirements change with maintainable title, control number, and revision history The best test plan is one that does all the above and: ●● Adapts to the device or system, using their parameters ●● Defines the test kit used and required interfaces ●● Does not compromise the device’s commissioned integrity ●● Adapts the test listed parameters

methods

based

on

the

previously

●● Defines tolerances of the object’s performance ●● Automatically assesses test results ●● Distinguishes maintenance from calibration conditions and circumstances ●● Describes test objectives so a novice can understand them ●● Executes clearly

REFERENCES Apostolov, Alexander, “Functional Testing of System Integrity Protection Schemes,” PAC World, March 2014. Bastigkeit, Boris, Thomas Schossig, and Fred Steinhauser. “Efficient Testing of Modern Protection IEDs,” PAC World, Winter 2009. Reuter, Jorg, “Device Independent Specification of a PAC System,” PAC World, December 2014. Vandiver, Benton, “Why Do We Still Test in the Digital World?” PAC World, September 2014. Benton Vandiver III received BSEE from the University of Houston in 1979. He began his career with the Substation Division of Houston Lighting & Power, in 1978 engineering relay protection systems for all levels of transmission, distribution, and generation. His main interests were in computer design automation of protection schemes and substation projects. He developed extensive knowledge in the application, setting, testing, modeling, and design of traditional and digital relaying systems used in all types of power system protection, control,

and monitoring. In 1991 he joined Multilin Corp. as a Project Manager on a team responsible for designing and developing the hardware and software for a new family of utility grade digital relays. In 1995 he joined OMICRON electronics as a Sales & Application Engineer with primary responsibilities of sale, training, and promotion of the revolutionary CMC Universal Test Set to North & South America. He is currently Technical Director for OMICRON electronics Corp. USA in Houston, TX. He is a long time member of IEEE and is Chairman of Working Group H5-C Common Data Format for IED Sampled Data. He holds a US Patent and has authored or co-authored numerous technical papers for various conferences in North America.

NETA Accredited Companies Valid as of Jan. 1, 2019

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Ensuring Safety and Reliability Trust in a NETA Accredited Company to provide independent, third-party electrical testing to the highest standard, the ANSI/NETA Standards. NETA has been connecting engineers, architects, facility managers, and users of electrical power equipment and systems with NETA Accredited Companies since1972.

UNITED STATES

6

alabama 1

2

3

4

AMP Quality Energy Services, LLC 352 Turney Ridge Rd Somerville, AL 35670 (256) 513-8255 [email protected] www.ampqes.com Brian Rodgers Premier Power Maintenance Corporation 3066 Finley Island Cir NW Decatur AL 35601-8800 (256) 355-1444 [email protected] www.premierpowermaintenance.com Johnnie McClung

arkansas 5

Premier Power Maintenance Corporation 7301 E County Road 142 Blytheville, AR 72315-6917 (870) 762-2100 [email protected] www.premierpowermaintenance.com Kevin Templeman

7

9

10

Utility Service Corporation PO Box 1471 Huntsville, AL 35807 (256) 837-8400 Fax: (256) 837-8403 [email protected] www.utilserv.com Alan D. Peterson

12

arizona

8

Premier Power Maintenance Corporation 4301 Iverson Blvd Ste H Trinity, AL 35673-6641 (256) 355-3006 [email protected] www.premierpowermaintenance.com Kevin Templeman

Sentinel Power Services, Inc. 1110 West B Street, Ste H Russellville, AR 72801 (918) 359-0350 www.sentinelpowerservices.com

11

ABM Electrical Power Services, LLC 2631 S. Roosevelt St Tempe, AZ 85282 (602) 722-2423 www.abm.com Electric Power Systems, Inc. 1230 N Hobson St., Ste 101 Gilbert, AZ 85233 (480) 633-1490 www.epsii.com Electrical Reliability Services 221 E. Willis Road Chandler, AZ 85286 (480) 966-4568 [email protected] www.electricalreliability.com Hampton Tedder Technical Services 3747 West Roanoke Ave. Phoenix, AZ 85009 (480) 967-7765 Fax:(480) 967-7762 www.hamptontedder.com Linc McNitt Southwest Energy Systems, LLC 2231 East Jones Ave., Suite A Phoenix, AZ 85040 (602) 438-7500 Fax: (602) 438-7501 [email protected] www.southwestenergysystems.com Dave Hoffman

Western Electrical Services, Inc. 5680 South 32nd St. Phoenix, AZ 85040 (602) 426-1667 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Craig Archer

california 13

ABM Electrical Power Services, LLC 720 S. Rochester Ave., Suite A Ontario, CA 91761 (301) 397-3500 [email protected] www.abm.com Rob Parton

14

ABM Electrical Power Services, LLC 6940 Koll Center Pkwy, Ste 100 Pleasanton, CA 94566 (408) 466-6920 www.abm.com

15

ABM Electrical Power Services, LLC 3585 Corporate Court San Diego, CA 92123-1844 (858) 754-7963

16

Accessible Consulting Engineers, Inc. 1269 Pomona Rd, Ste 111 Corona, CA 92882-7158 (951) 808-1040 [email protected] www.acetesting.com Iraj Nasrolahi

17

Apparatus Testing and Engineering 11300 Sanders Dr, Ste 29 Rancho Cordova, CA 95742-6822 (916) 853-6280 [email protected] www.apparatustesting.com Harold (Jerry) Carr

For additional information on NETA visit netaworld.org

18

Apparatus Testing and Engineering 7083 Commerce Cir., Suite H Pleasanton, CA 94588 (916) 853-6280 www.apparatustesting.com

21

Applied Engineering Concepts 894 N Fair Oaks Ave. Pasadena, CA 91103 (626) 389-2108 [email protected] www.aec-us.com Michel Castonguay

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23

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Applied Engineering Concepts 8160 Miramar Road San Diego, CA 92126 (619) 822-1106 [email protected] www.aec-us.com Michel Castonguay Electric Power Systems, Inc. 7925 Dunbrook Rd., Ste G San Diego, CA 92126 (858) 566-6317 www.epsii.com

24

Electrical Reliability Services 5909 Sea Lion Pl, Ste C Carlsbad, CA 92010-6634 (858) 695-9551 www.electricalreliability.com

25

Electrical Reliability Services 6900 Koll Center Pkwy., Ste 415 Pleasanton, CA 94566 (925) 485-3400 Fax: (925) 485-3436

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27

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Electrical Reliability Services 10606 Bloomfield Ave. Santa Fe Springs, CA 90670 (562) 236-9555 Fax: (562) 777-8914 Giga Electrical & Technical Services, Inc. 2743A N. San Fernando Road Los Angeles, CA 90065 (323) 255-5894 [email protected] www.gigaelectrical-ca.com Hermin Machacon Halco Testing Services 5773 Venice Boulevard Los Angeles, CA 90019 [email protected] (323) 933-9431 www.halcotestingservices.com Don Genutis

Hampton Tedder Technical Services 4563 State St Montclair, CA 91763 (909) 628-1256 x214 [email protected] www.hamptontedder.com Chasen Tedder

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Industrial Tests, Inc. 4021 Alvis Ct., Suite 1 Rocklin, CA 95677 (916) 296-1200 Fax: (916) 632-0300 [email protected] www.industrialtests.com Greg Poole

31

Pacific Power Testing, Inc. 38 14280 Doolittle Dr. San Leandro, CA 94577 (510) 351-8811 Fax: (510) 351-6655 [email protected] www.pacificpowertesting.com Steve Emmert

32

Power Systems Testing Co. 4688 W. Jennifer Ave., Suite 108 Fresno, CA 93722 (559) 275-2171 x15 Fax: (559) 275-6556 [email protected] www.powersystemstesting.com David Huffman

RESA Power Service 2390 Zanker Road San Jose , CA 95131 (800) 576-7372 [email protected] www.resapower.com Toby Ramsey Tony Demaria Electric, Inc. 131 West F St. Wilmington, CA 90744 (310) 816-3130 Fax: (310) 549-9747 [email protected] www.tdeinc.com Neno Pasic Western Electrical Services, Inc. 5505 Daniels St. Chino, CA 91710 (619) 672-5217 [email protected] www.westernelectricalservices.com Matt Wallace

colorado 39

ABM Electrical Power Services, LLC 9800 E Geddes Ave Unit A-150 Englewood, CO 80112-9306 (303) 524-6560 www.abm.com

33

Power Systems Testing Co. 6736 Preston Ave., Suite E Livermore, CA 94551 (510) 783-5096 Fax: (510) 732-9287 www.powersystemstesting.com

40

Electric Power Systems, Inc. 11211 E. Arapahoe Rd, Ste 108 Centennial, CO 80112 (720) 857-7273 www.epsii.com

34

Power Systems Testing Co. 600 S. Grand Ave., Suite 113 Santa Ana, CA 92705-4152 (714) 542-6089 Fax: (714) 542-0737 www.powersystemstesting.com

41

Electrical Reliability Services 7100 Broadway, Suite 7E Denver, CO 80221-2915 (303) 427-8809 Fax: (303) 427-4080 www.electricalreliability.com

35

RESA Power Service 13837 Bettencourt Street Cerritos, CA 90703 (800) 996-9975 [email protected] www.resapower.com Manny Sanchez

42

Magna IV Engineering 96 Inverness Dr. East, Suite R Englewood, CO 80112 (303) 799-1273 Fax: (303) 790-4816 [email protected] Aric Proskurniak

43

Precision Testing Group 5475 Hwy. 86, Unit 1 Elizabeth, CO 80107 (303) 621-2776 Fax: (303) 621-2573

For additional information on NETA visit netaworld.org

44

RESA Power Service 19621 Solar Circle, 101 Parker, CO 80134 (303) 781-2560 [email protected] www.resapower.com Jody Medina

51

CE Power Solutions of Florida, LLC 3502 Riga Blvd., Suite C Tampa, FL 33619 (866) 439-2992

52

CE Power Solutions of Florida, LLC 3801 SW 47th Avenue, Suite 505 Davie, FL 33314 (866) 439-2992

connecticut 45

46

47

48

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Advanced Testing Systems 15 Trowbridge Dr. Bethel, CT 06801 (203) 743-2001 Fax: (203) 743-2325 [email protected] www.advtest.com Pat MacCarthy American Electrical Testing Co., Inc. 34 Clover Dr. South Windsor, CT 06074 (860) 648-1013 Fax: (781) 821-0771 [email protected] www.aetco.com Gerald Poulin EPS Technology 29 N. Plains Highway, Suite 12 Wallingford, CT 06492 (203) 679-0145 [email protected] www.eps-technology.com Sean Miller

53

Electric Power Systems, Inc. 4436 Parkway Commerce Blvd. Orlando, FL 32808 (407) 578-6424 Fax: (407) 578-6408 www.epsii.com

54

Electrical Reliability Services 11000 Metro Pkwy., Suite 30 Ft. Myers, FL 33966 (239) 693-7100 Fax: (239) 693-7772

55

Electrical Testing, Inc. 2671 Cedartown Highway Rome, GA 30161-6791 (706) 234-7623 Fax: (706) 236-9028 [email protected] www.electricaltestinginc.com Jamie Dempsey

61

Nationwide Electrical Testing, Inc. 6050 Southard Trace Cumming, GA 30040 (770) 667-1875 Fax: (770) 667-6578 [email protected] www.n-e-t-inc.com Shashikant B. Bagle

illinois 62

Dude Electrical Testing, LLC 145 Tower Dr., Ste 9 Burr Ridge, IL 60527 (815) 293-3388 Fax: (815) 293-3386 [email protected] www.dudetesting.com Scott Dude

63

Electric Power Systems, Inc. 54 Eisenhower Lane North Lombard, IL 60148 (815) 577-9515 www.epsii.com

64

High Voltage Maintenance Corp. 941 Busse Rd. Elk Grove Village, IL 60007 (847) 640-0005 www.hvmcorp.com

65

Midwest Engineering Consultants, Ltd. 2500 36th Ave Moline, IL 61265-6954 (309) 764-1561 [email protected] www.midwestengr.com Monte Moorehead

66

Shermco Industries 112 Industrial Drive Minooka, IL 60447-9557 (815) 467-5577 [email protected] www.shermco.com

RESA Power Service 1401 Mercantile Court Plant City, FL 33563 (813) 752-6550 www.resapower.com

georgia 56

High Voltage Maintenance Corp. 150 North Plains Industrial Rd. Wallingford, CT 06492 (203) 949-2650 Fax: (203) 949-2646 www.hvmcorp.com Southern New England Electrical Testing, LLC 3 Buel St., Suite 4 Wallingford, CT 06492 (203) 269-8778 Fax: (203) 269-8775 [email protected] www.sneet.org David Asplund, Sr.

57

58

florida 50

60

C.E. Testing, Inc. 6148 Tim Crews Rd. Macclenny, FL 32063 (904) 653-1900 Fax: (904) 653-1911 [email protected] www.cetestinginc.com Mark Chapman

59

ABM Electrical Power Services, LLC 1005 Windward Ridge Pkwy Alpharetta, GA 30005 (770) 521-7550 www.abm.com Electric Power Systems, Inc. 6679 Peachtree Industrial Dr., Suite H Norcross , GA 30092 (770) 416-0684 www.epsii.com Electrical Equipment Upgrading, Inc. 21 Telfair Place Savannah, GA 31415 (912) 232-7402 Fax: (912) 233-4355 [email protected] www.eeu-inc.com Kevin Miller Electrical Reliability Services 2275 Northwest Parkway SE, Suite 180 Marietta, GA 30067 (770) 541-6600 Fax: (770) 541-6501

For additional information on NETA visit netaworld.org

indiana 67

68

CE Power Engineered Services, LLC 3496 E. 83rd Place Merrillville, IN 46410 (219) 942-2346 www.cepower.net

Shermco Industries 2100 Dixon Street, Suite C Des Moines, IA 50316-2174 (515) 263-8482

75

Shermco Industries 5145 NW Beaver Dr. Johnston, IA 50131 (515) 265-3377 www.shermco.com

Electric Power Systems, Inc. 7169 East 87th St. Indianapolis, IN 46256 (317) 941-7502 www.epsii.com Daniel Douglas

kentucky

69

Electrical Maintenance & Testing, Inc. 12342 Hancock St. Carmel, IN 46032 (317) 853-6795 Fax: (317) 853-6799 [email protected] www.emtesting.com Brian K. Borst

70

High Voltage Maintenance Corp. 8320 Brookville Rd., Ste E Indianapolis, IN 46239 (317) 322-2055 Fax: (317) 322-2056 www.hvmcorp.com

71

Premier Power Maintenance Corporation 4035 Championship Drive Indianapolis, IN 46268 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

72

Premier Power Maintenance Corporation 4537 S Nucor Rd. Crawfordsville, IN 47933 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

iowa 73

74

Shermco Industries 1711 Hawkeye Dr. Hiawatha, IA 52233 (319) 377-3377 [email protected] www.shermco.com

76

77

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Electrical Reliability Services 9636 St. Vincent, Unit A Shreveport, LA 71106 (318) 869-4244 [email protected]

83

Saber Power Services, LLC 14617 Perkins Road Baton Rouge, LA 70810 (225) 726-7793 www.saberpower.com

84

Tidal Power Services, LLC 8184 Highway 44, Suite 105 Gonzales, LA 70737 (225) 644-8170 Fax: (225) 644-8215 www.tidalpowerservices.com Darryn Kimbrough

CE Power Engineered Services, LLC 1803 Taylor Ave. Louisville, KY 40213 (800) 434-0415 [email protected] 85 Tidal Power Services, LLC www.cepower.net 1056 Mosswood Dr. Bob Sheppard Sulphur, LA 70665 (337) 558-5457 Fax: (337) 558-5305 High Voltage Maintenance Corp. www.tidalpowerservices.com 10704 Electron Drive Steve Drake Louisville, KY 40299 (859) 371-5355 maine www.hvmcorp.com 86 CE Power Engineered Services, LLC Premier Power Maintenance 72 Sanford Drive Corporation Gorham, ME 04038 2725 Jason Rd (800) 649-6314 Ashland, KY 41102-7756 [email protected] (606) 929-5969 www.cepower.net [email protected] Jim Cialdea www.premierpowermaintenance.com 87 Electric Power Systems, Inc. Jay Milstead 56 Bibber Pkwy #1 Brunswick, ME 04011-7357 (207) 837-6527 louisiana www.epsii.com

79

Electric Power Systems, Inc. 1129 East Highway 30 Gonzalez, LA 70737 (225) 644-0150 Fax: (225) 644-6249 www.epsii.com

80

Electrical Reliability Services 245 Hood Road Sulphur, LA 70665-8747 (337) 583-2411 [email protected]

81

82

Electrical Reliability Services 3535 Emerson Pkwy, Ste A Gonzales, LA 70737 (225) 755-0530 [email protected]

88

POWER Testing and Energization, Inc. 303 US Route One Freeport,ME 04032 (207) 869-1200 www.powerte.com

maryland 89

ABM Electrical Power Solutions 3700 Commerce Dr., #901- 903 Baltimore, MD 21227 (410) 247-3300 Fax: (410) 247-0900 www.abm.com

For additional information on NETA visit netaworld.org

90

ABM Electrical Power Solutions 4390 Parliament Pl., Suite S Lanham, MD 20706 (301) 967-3500 Fax: (301) 735-8953 [email protected] www.abm.com Christopher Smith

91

Harford Electrical Testing Co., Inc. 1108 Clayton Rd. Joppa, MD 21085 (410) 679-4477 [email protected] www.harfordtesting.com Vincent Biondino

92

High Voltage Maintenance Corp. 9305 Gerwig Ln., Suite B Columbia, MD 21046 (410) 309-5970 Fax: (410) 309-0220 www.hvmcorp.com

93

High Voltage Maintenance Corp. 14300 Cherry Lane Court, Ste 115 Laurel, MD 20707 (410) 279-0798 www.hvmcorp.com

94

95

97

Electrical Engineering & Service Co. Inc. 289 Centre St. Holbrook, MA 02343 (781) 767-9988 [email protected] www.eescousa.com Joe Cipolla

99

High Voltage Maintenance Corp. 24 Walpole Park S Walpole, MA 02081-2541 (508) 668-9205 www.hvmcorp.com

100

Infra-Red Building and Power Service, Inc. 152 Centre St Holbrook, MA 02343-1011 (781) 767-0888 [email protected] www.infraredbps.com

106

Premier Power Maintenance Corporation 7262 Kensington Rd. Brighton, MI 48116 (517) 230-6620 [email protected] www.premierpowermaintenance.com Brian Ellegiers

108

RESA Power Service 46918 Liberty Dr Wixom, MI 48393-3600 (248) 313-6868 [email protected] www.resapower.com Bruce Robinson

109

Shermco Industries 12796 Currie Court Livonia, MI 48150 (734) 469-4050 [email protected] www.shermco.com

michigan 101

CE Power Engineered Services, LLC 10338 Citation Drive, Ste 300 Brighton, MI 48116 (810) 229-6628 [email protected] www.cepower.net Ken L’Esperance

104

American Electrical Testing Co., LLC 25 Forbes Boulevard, Ste 1 Foxboro, MA 02035 (781) 821-0121 [email protected] www.aetco.us Scott Blizard CE Power Engineered Services, LLC 40 Washington St Westborough, MA 01581-1088 (508) 881-3911 www.cepower.net

Northern Electrical Testing, Inc. 1991 Woodslee Dr. Troy, MI 48083-2236 (248) 689-8980 Fax: (248) 689-3418 [email protected] www.northerntesting.com Lyle Detterman

105 POWER

PLUS Engineering, Inc. 47119 Cartier Court Wixom, MI 48393-2872 (248) 896-0200

Powertech Services, Inc. 4095 South Dye Rd. Swartz Creek, MI 48473-1570 (810) 720-2280 Fax: (810) 720-2283 [email protected] www.powertechservices.com Kirk Dyszlewski

107

Potomac Testing, Inc. 1610 Professional Blvd., Ste A Crofton, MD 21114 (301) 352-1930 Fax: (301) 352-1936 110 [email protected] 102 Electric Power Systems, Inc. www.potomactesting.com 11861 Longsdorf St. Ken Bassett Riverview, MI 48193 (734) 282-3311 Reuter & Hanney, Inc. www.epsii.com 11620 Crossroads Cir., Suites D-E Middle River, MD 21220 103 High Voltage Maintenance Corp. (410) 344-0300 Fax: (410) 335-4389 24371 Catherine Industrial Dr., Ste 207 [email protected] Novi, MI 48375 www.reuterhanney.com (248) 305-5596 Fax: (248) 305-5579 Michael Jester www.hvmcorp.com 111

massachusetts 96

98

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Utilities Instrumentation Service, Inc. 2290 Bishop Circle East Dexter, MI 48130 (734) 424-1200 Fax: (734) 424-0031 [email protected] www.uiscorp.com Gary E. Walls

minnesota CE Power Engineered Services, LLC 7674 Washington Ave. S Eden Prairie, MN 55344 (877) 968-0281 [email protected] www.cepower.net Jason Thompson RESA Power Service 3890 Pheasant Ridge Dr. NE, Ste 170 Blaine, MN 55449 (763) 784-4040 [email protected] www.resapower.com Mike Mavetz

For additional information on NETA visit netaworld.org

113

Shermco Industries 998 E. Berwood Ave. Saint Paul, MN 55110 (651) 484-5533 [email protected] www.shermco.com

121

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missouri 114

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116

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Electric Power Systems, Inc. 6141 Connecticut Ave. Kansas City, MO 64120 (816) 241-9990 Fax: (816) 241-9992 www.epsii.com Electric Power Systems, Inc. 21 Millpark Ct. Maryland Heights, MO 63043-3536 (314) 890-9999 Fax:(314) 890-9998 www.epsii.com

123

Electrical Reliability Services 124 400 NW Capital Dr Lees Summit, MO 64086 (816) 525-7156 Fax: (816) 524-3274 [email protected] POWER Testing and Energization, Inc. 12755 Olive Blvd., Ste 100 Saint Louis, MO 63141 (314) 851-4065 www.powerte.com

125

nebraska 118

Shermco Industries 4670 G. Street Omaha, NE 68117 (402) 933-8988 [email protected] www.shermco.com

120

126

Control Power Concepts 353 Pilot Rd, Suite B Las Vegas, NV 89119 (702) 448-7833 Fax: (702) 448-7835 [email protected] www.controlpowerconcepts.com John Travis Electric Power Systems, Inc. 5850 Polaris Ave., Suite 1600 Las Vegas, NV 89118 (702) 815-1342 www.epsii.com

Electrical Reliability Services 1380 Greg St., Suite 217 Sparks, NV 89431 (775) 746-8484 Fax: (775) 356-5488 www.electricalreliability.com Hampton Tedder Technical Services 4113 Wagon Trail Ave. Las Vegas, NV 89118 (702) 452-9200 www.hamptontedder.com Roger Cates National Field Services 3711 Regulus Ave. Las Vegas, NV 89102 (888) 296-0625 [email protected] www.natlfield.com Howard Herndon National Field Services 2900 Vassar St. #114 Reno, NV 89502 (775) 410-0430 www.natlfield.com Howard Herndon [email protected]

Electric Power Systems, Inc. 915 Holt Ave., Unit 9 Manchester, NH 03109 (603) 657-7371 www.epsii.com

Eastern High Voltage 11A South Gold Dr. Robbinsville, NJ 08691-1606 (609) 890-8300 Fax: (609) 588-8090 [email protected] www.easternhighvoltage.com Robert Wilson

130

High Energy Electrical Testing, Inc. 515 S. Ocean Ave. Seaside Park, NJ 08752 (732) 938-2275 Fax: (732) 938-2277 [email protected] www.highenergyelectric.com Charles Blanchard

131

132

American Electrical Testing Co., Inc. 91 Fulton St. Boonton, NJ 07005 (973) 316-1180 [email protected] www.aetco.com Jeff Somol

J.G. Electrical Testing Corporation 3092 Shafto Road, Suite 13 Tinton Falls, NJ 07753 (732) 217-1908 www.jgelectricaltesting.com Howard Trinkowsky M&L Power Systems, Inc. 109 White Oak Ln., Suite 82 Old Bridge, NJ 08857 (732) 679-1800 Fax: (732) 679-9326 [email protected] www.mlpower.com Milind Bagle

133

RESA Power Service 311 Bay Avenue A Highlands, NJ 07732 (888) 996-9975 [email protected] www.resapower.com Trent Robbins

134

Scott Testing, Inc. 245 Whitehead Rd Hamilton, NJ 08619 (609) 689-3400 [email protected] www.scotttesting.com Russ Sorbello

new jersey 127

Burlington Electrical Testing Co., Inc. 198 Burrs Rd. Westampton, NJ 08060 (609) 267-4126 [email protected] www.betest.com Walter P. Cleary

129

new hampshire

nevada 119

Electrical Reliability Services 128 6351 Hinson St., Suite A Las Vegas, NV 89118 (702) 597-0020 Fax: (702) 597-0095 www.electricalreliability.com

For additional information on NETA visit netaworld.org

135

Trace Electrical Services 142 & Testing, LLC 293 Whitehead Rd. Hamilton, NJ 08619 (609) 588-8666 Fax: (609) 588-8667 www.tracetesting.com Joseph Vasta

new mexico 136

137

138

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Electric Power Systems, Inc. 8515 Cella Alameda NE, Suite A Albuquerque, NM 87113 (505) 792-7761 www.eps-international.com Electrical Reliability Services 8500 Washington Pl. NE, Suite A-6 Albuquerque, NM 87113 (505) 822-0237 Fax: (505) 822-0217 www.electricalreliability.com Western Electrical Services, Inc. 620 Meadow Ln. Los Alamos, NM 87547 (505) 469-1661 [email protected] www.westernelectricalservices.com Toby King

144

145

new york 139

140

141

BEC Testing 50 Gazza Blvd Farmingdale, NY 11735-1402 (631) 393-6800 [email protected] www.bectesting.com Daniel Devlin Elemco Services, Inc. 228 Merrick Rd. Lynbrook, NY 11563 (631) 589-6343 [email protected] www.elemco.com Courtney Gallo High Voltage Maintenance Corp. 1250 Broadway, Suite 2300 New York, NY 10001 (718) 239-0359 www.hvmcorp.com

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HMT, Inc. 6268 Route 31 Cicero, NY 13039 (315) 699-5563 Fax: (315) 699-5911 [email protected] www.hmt-electric.com John Pertgen

A&F Electrical Testing, Inc. 80 Broad St., 5th Floor New York, NY 10004 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Florence Chilton American Electrical Testing Co., Inc. 76 Cain Dr. Brentwood, NY 11717 (631) 617-5330 Fax: (631) 630-2292 [email protected] www.aetco.com Billy Fernandez

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ABM Electrical Power Services, LLC 6541 Meridien Dr, Suite 113 Raleigh, NC 27616 (919) 877-1008 www.abm.com ABM Electrical Power Services, LLC 3600 Woodpark Blvd., Suite G Charlotte, NC 28206 (704) 273-6257 Fax: (704) 598-9812 [email protected] www.abm.com Ernest Goins ELECT, P.C. 375 E. Third Street Wendell, NC 27591 (919) 365-9775 [email protected] www.elect-pc.com Barry W. Tyndall

Electrical Reliability Services 6135 Lakeview Road, Suite 500 Charlotte, NC 28269 (704) 441-1497 [email protected] www.electricalreliability.com Power Products & Solutions, LLC 6605 W WT Harris Blvd, Suite F Charlotte, NC 28269 (704) 573-0420 x12 [email protected] www.powerproducts.biz Adis Talovic Power Test, Inc. 2200 Hwy. 49 S Harrisburg, NC 28075 (704) 200-8311 Fax: (704) 455-7909 [email protected] www.powertestinc.com Richard Walker

ohio 153

ABM Electrical Power Solutions 1817 O’Brien Road Columbus, OH 43228 (724) 772-4638 www.abm.com

154

CE Power Engineered Services, LLC 4040 Rev Drive Cincinnati, OH 45232 (800) 434-0415 [email protected] www.cepower.net Brent McAlister

155

CE Power Engineered Services, LLC 8490 Seward Rd. Fairfield, OH 45011 (800) 434-0415 [email protected] www.cepower.net Tim Lana

156

Electric Power Systems, Inc. 2888 Nationwide Parkway, 2nd Floor Brunswick, OH 44212 (330) 460-3706 www.epsii.com

north carolina

A&F Electrical Testing, Inc. 80 Lake Ave. S., Suite 10 Nesconset, NY 11767 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Kevin Chilton

Electric Power Systems, Inc. 319 US Hwy. 70 E, Suite E Garner, NC 27529 (919) 210-5405 www.eps-international.com

For additional information on NETA visit netaworld.org

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Electrical Reliability Services 610 Executive Campus Dr. Westerville, OH 43082 (877) 468-6384 Fax: (614) 410-8420 [email protected] www.electricalreliability.com High Voltage Maintenance Corp. 5100 Energy Dr. Dayton, OH 45414 (937) 278-0811 Fax: (937) 278-7791 www.hvmcorp.com

oklahoma 165

166

High Voltage Maintenance Corp. 7200 Industrial Park Blvd. Mentor, OH 44060 (440) 951-2706 Fax: (440) 951-6798 www.hvmcorp.com Power Solutions Group Ltd. 425 W Kerr Rd Tipp City, OH 45371-2843 (937) 506-8444 [email protected] www.powersolutionsgroup.com Barry Willoughby

RESA Power Service 4540 Boyce Parkway Stow, OH 44224 (800) 264-1549 www.resapower.com

163

Shermco Industries 4383 Professional Parkway Groveport, OH 43125 (614) 836-8556 [email protected] www.shermco.com

164

Utilities Instrumentation Service - Ohio, LLC PO Box 750066 998 Dimco Way Dayton, OH 45475-0066 (937) 439-9660

Shermco Industries 4510 South 86th East Ave. Tulsa, OK 74145 (918) 234-2300 [email protected] www.shermco.com

174

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Electrical Reliability Services 4099 SE International Way, Suite 201 Milwaukie, OR 97222-8853 (503) 653-6781 Fax: (503) 659-9733 www.electricalreliability.com

169

ABM Electrical Power Solutions 317 Commerce Park Drive Cranberry Township, PA 16066-6407 (724) 772-4638 www.abm.com

170

American Electrical Testing Co., Inc. Green Hills Commerce Center 5925 Tilghman St., Suite 200 Allentown, PA 18104 (215) 219-6800 [email protected] www.aetco.com Jonathan Munley

171

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Reuter & Hanney, Inc. 149 Railroad Dr. Northampton Industrial Park Ivyland, PA 18974 (215) 364-5333 Fax: (215) 364-5365 [email protected] www.reuterhanney.com Michael Jester

south carolina 177

Power Products & Solutions, LLC 13 Jenkins Ct. Mauldin, SC 29662 (800) 328-7382 [email protected] www.powerproducts.biz Raymond Pesaturo

178

Power Products & Solutions, LLC 9481 Industrial Center Dr. Unit 5 Ladson, SC 29456 (844) 383-8617 www.powerproducts.biz

179

Power Solutions Group Ltd. 5115 Old Greenville Highway Liberty, SC 29657 (864) 540-8434 [email protected] www.powersolutionsgroup.com Anthony Crawford

Burlington Electrical Testing Co., Inc. 300 Cedar Ave. Croydon, PA 19021-6051 (215) 826-9400 Fax: (215) 826-0964 www.betest.com Electric Power Systems, Inc. 1090 Montour West Industrial Blvd. Coraopolis, PA 15108 (412) 276-4559 www.epsii.com

High Voltage Maintenance Corp. 355 Vista Park Dr. Pittsburgh, PA 15205-1206 (412) 747-0550 Fax: (412) 747-0554 www.hvmcorp.com North Central Electric, Inc. 69 Midway Ave. Hulmeville, PA 19047-5827 (215) 945-7632 Fax: (215) 945-6362 [email protected] www.ncetest.com Robert Messina

Taurus Power & Controls, Inc. 9999 SW Avery St. Tualatin, OR 97062-9517 (503) 692-9004 Fax: (503) 692-9273 [email protected] www.tauruspower.com Rob Bulfinch

pennsylvania

EnerG Test, LLC 204 Gale Lane, Bldg. 2 – 2nd Floor Kennett Square, PA 19348 (484) 731-0200 Fax: (484) 713-0209 [email protected] www.energtest.com Dennis Buehler

175

oregon

Power Solutions Group Ltd. 2739 Sawbury Blvd. Columbus, OH 43235 (614) 310-8018 [email protected] www.powersolutionsgroup.com Stuart Spohn

162

Sentinel Power Services, Inc. 7517 E Pine St Tulsa, OK 74115-5729 (918) 359-0350 [email protected] www.sentinelpowerservices.com Greg Ellis

173

180

POWER Testing and Energization, Inc. 1041 Red Ventures Dr., Suite 105 Fort Mill, SC 29707 (803) 835-5900 www.powerte.com

For additional information on NETA visit netaworld.org

tennesee 181

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Electrical Reliability Services 1057 Doniphan Park Cir Ste A El Paso, TX 79922-1329 (915) 587-9440 [email protected]

CE Power Engineered Services, LLC 480 Cave Rd Nashville, TN 37210-2302 (615) 882-9455 190 Electrical Reliability Services [email protected] 1426 Sens Rd Ste 5 www.cepower.net La Porte, TX 77571-9656 Bryant Phillips (281) 241-2800 CE Power Engineered Services, LLC [email protected] 10840 Murdock Drive 191 Grubb Engineering, Inc. Knoxville , TN 37932 2727 North Saint Mary’s St. (800) 434-0415 San Antonio, TX 78212 [email protected] (210) 658-7250 www.cepower.net [email protected] Don William www.grubbengineering.com Electric Power Systems, Inc. Robert D. Grubb Jr. 684 Melrose Avenue 192 Magna IV Engineering Nashville, TN 37211-3121 4407 Halik Street Building E, Suite 300 (615) 834-0999 www.epsii.com Pearland, TX 77581 (346) 221-2165 Electrical & Electronic Controls [email protected] 6149 Hunter Rd. www.magnaiv.com Ooltewah, TN 37363 Aric Proskurniak (423) 344-7666 Fax: (423) 344-4494 193 National Field Services [email protected] Michael Hughes 651 Franklin Lewisville, TX 75057-2301 Electrical Testing and (972) 420-0157 Maintenance Corp. www.natlfield.com 3673 Cherry Rd Ste 101 Eric Beckman Memphis, TN 38118-6313 (901) 566-5557 194 National Field Services [email protected] 1890 A South Hwy 35 www.etmcorp.net Alvin, TX 77511 Ron Gregory (800) 420-0157 [email protected] Power Solutions Group, Ltd. www.natlfield.com 172 B-Industrial Dr. Jonathan Wakeland Clarksville, TN 37040 195 National Field Services (931) 572-8591 www.powersolutionsgroup.com 1405 United Drive, Suite 113-115 San Marcos, TX 78666 Chris Brown (800) 420-0157 [email protected] texas www.natlfield.com Matt LaCoss Absolute Testing Services, Inc. 8100 West Little York 196 Power Engineering Services, Inc. Houston, TX 77040 9179 Shadow Creek Ln (832) 467-4446 Converse, TX 78109-2041 www.absolutetesting.com (210) 590-4936 [email protected] Electric Power Systems, Inc. www.pe-svcs.com 1330 Industrial Blvd., Suite 300 Daniel Staudt Sugar Land, TX 77478 (713) 644-5400 www.epsii.com

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POWER Testing and Energization, Inc. 16825 Northchase Drive Houston, TX 77060 (281) 765-5536 www.powerte.com Saber Power Services, LLC 9841 Saber Power Ln Rosharon, TX 77583-5188 (713) 222-9102 [email protected] www.saberpower.com Saber Power Services, LLC 4703 Shavano Oak, Suite 104 San Antonio, TX 78249 (210) 267-7282 www.saberpower.com Saber Power Services, LLC 1315 FM 1187, Suite 105 Mansfield, TX 76063 (682) 518-3676 www.saberpower.com Shermco Industries 2425 E Pioneer Dr Irving, TX 75061-8919 (972) 793-5523 [email protected] www.shermco.com

202

Shermco Industries 1705 Hur Industrial Blvd Cedar Park, TX 78613-7229 (512) 267-4800 [email protected] www.shermco.com

203

Shermco Industries 33002 FM 2004 Angleton, TX 77515-8157 (979) 848-1406 [email protected] www.shermco.com

204

Shermco Industries 12000 Network Blvd, Buidling D Suite 410 San Antonio, TX 78249-3354 (210) 877-9090 [email protected] www.shermco.com

205

Shermco Industries 3807 S Sam Houston Pkwy W Houston, TX 77056 (281) 835-3633 [email protected] www.shermco.com

For additional information on NETA visit netaworld.org

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Shermco Industries 1301 Hailey St. Sweetwater, TX 79556 (325) 236-9900 [email protected] www.shermco.com

214

Shermco Industries 2901 Turtle Creek Dr. Port Arthur, TX 77642 (409) 853-4316 [email protected] www.shermco.com

215

216

Tidal Power Services, LLC 4211 Chance Ln Rosharon, TX 77583-4384 (281) 710-9150 [email protected] www.tidalpowerservices.com Monty C. Janak

Titan Quality Power Services, LLC 7630 Ikes Tree Drive Spring, TX 77389 (281) 826-3781 www.titanqps.com

utah 211

212

ABM Electrical Power Solutions 814 Greenbrier Cir., Suite E Chesapeake, VA 23320 (757) 364-6145 www.abm.com Mark Anthony Gaughan, III

223

Reuter & Hanney, Inc. 4270-I Henninger Ct. Chantilly, VA 20151 (703) 263-7163 Fax: (703) 263-1478 www.reuterhanney.com 224

Electrical Reliability Services 2222 West Valley Hwy. N., Suite 160 Auburn, WA 98001 (253) 736-6010 Fax: (253) 736-6015 [email protected] www.electricalreliability.com 225

219

226 Sigma Six Solutions, Inc. 2200 West Valley Hwy., Suite 100 Auburn, WA 98001 (253) 333-9730 Fax: (253) 859-5382 [email protected] www.sigmasix.com John White

Western Electrical Services, Inc. 220 3676 W. California Ave.,#C-106 Salt Lake City, UT 84104 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Rob Coomes

Western Electrical Services, Inc. 4510 NE 68th Dr., Suite 122 Vancouver, WA 98661 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Tony Asciutto

wisconsin

POWER Testing and Energization, Inc. 14006 NW 3rd Ct, Ste 101 Vancouver, WA 98685-5793 (360) 597-2800 [email protected] www.powerte.com Chris Zavadlov

221

213

222

218

Electrical Reliability Services 9736 South 500 West Sandy, UT 84070 (801) 975-6461 [email protected]

virginia

Electric Power Systems, Inc. 306 Ashcake Road, Suite A Ashland, VA 23005 (804) 526-6794 www.epsii.com

washington 217

Titan Quality Power Services, LLC 1501 S Dobson Street Burleson, TX 76028 (866) 918-4826 www.titanqps.com

Electric Power Systems, Inc. 120 Turner Road Salem, VA 24153-5120 (540) 375-0084 www.epsii.com

Electrical Energy Experts, Inc. W129N10818, Washington Dr. Germantown,WI 53022 (262) 255-5222 Fax: (262) 242-2360 [email protected] www.electricalenergyexperts.com Tim Casey Electrical Testing Solutions 2909 Green Hill Ct. Oshkosh, WI 54904 (920) 420-2986 Fax: (920) 235-7136 [email protected] www.electricaltestingsolutions.com Tito Machado Energis High Voltage Resources, Inc. 1361 Glory Rd. Green Bay, WI 54304 (920) 632-7929 Fax: (920) 632-7928 [email protected] www.energisinc.com Mick Petzold High Voltage Maintenance Corp. 3000 S. Calhoun Rd. New Berlin, WI 53151 (262) 784-3660 Fax: (262) 784-5124 www.hvmcorp.com

Taurus Power & Controls, Inc. 19226 66th Ave S. #L102 Kent, WA 98032-2197 (425) 656-4170 www.tauruspower.com Western Electrical Services, Inc. 14311 29th St. East Sumner, WA 98390 (253) 891-1995 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Dan Hook

For additional information on NETA visit netaworld.org

CANADA

236

227

Magna IV Engineering Suite 200, 688 Heritage Dr. SE Calgary, AB T2H 1M6 Canada (403) 723-0575 Fax: (403) 723-0580 www.magnaiv.com

228

Magna IV Engineering 1103 Parsons Rd. SW Edmonton, AB T6X 0X2 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Virginia Balitski

229

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234

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Magna IV Engineering 106, 4268 Lozells Ave. Burnaby, BC VSA 0C6 Canada (604) 421-8020

237

238

Magna IV Engineering 141 Fox Cresent Fort McMurray, AB T9K 0C1 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Ryan Morgan Shermco Industries Canada 3434 25th Street NE Calgary, AB T1Y 6C1 (403) 769-9300 [email protected] www.shermco.com

239

240

Shermco Industries Canada 241 3731-98 Street Edmonton, AB T6E 5N2 Canada (780) 436-8831 Fax: (780) 463-9646 [email protected] www.shermco.com Shermco Industries Canada 1033 Kearns Crescent RM of Sherwood SK S4K 0A2 (306) 949-8131 [email protected] www.shermco.com Shermco Industries Canada 1375 Church Ave. Winnipeg, MB R2X 2T7 Canada (204) 925-4022 Fax: (204) 925-4021 www.shermco.com Orbis Engineering Field Services Ltd. #300, 9404 - 41st Ave. Edmonton, AB T6E 6G8 Canada (780) 988-1455 Fax: (780) 988-0191 [email protected] www.orbisengineering.net Lorne Gara

REV 01.19

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Pacific Powertech, Inc. 245 #110, 2071 Kingsway Ave. Port Coquitlam, BC V3C 6N2 Canada (604) 944-6697 Fax: (604) 944-1271 [email protected] www.pacificpowertech.ca Josh Konkin REV Engineering Ltd. 3236 - 50 Ave. SE Calgary, AB T2B 3A3 Canada (403) 287-0156 Fax: (403) 287-0198 [email protected] www.reveng.ca Roland Nicholas Davidson, IV Rondar Inc. 333 Centennial Parkway North Hamilton, ON L8E2X6 (905) 561-2808 www.rondar.com Gary Hysop

BRUSSELS 246

Magna IV Engineering 7, 3040 Miners Ave. Saskatoon, SK S7K 5V1 (306) 713-2167 www.magnaiv.com Adam Jaques [email protected] Pace Technologies, Inc. #10, 883 McCurdy Place Kelowna , BC V1X 8C8 (250) 712-0091 www.pacetechnologies.com

Shermco Industries Boulevard Saint-Michel 47 1040 Brussels, Brussels, Belgium +32 (0)2 400 00 54 Fax: +32 (0)2 400 00 32 [email protected] www.shermco.com

CHILE 247

Magna IV Engineering Avenida del Condor Sur #590 Officina 601 Huechuraba, Santiago 8580676 Chile +(56) -2-26552600 [email protected] Henry Mendoza

248

Orbis Engineering Field Services Ltd. Badajoz #45, Piso 17 Las Condes, Santiago +56 2 29402343 www.orbisengineering.net

Rondar Inc. 9-160 Konrad Crescent Markham, ON L3R9T9 (905) 943-7640 www.rondar.com Shermco Industries Canada 233 Faithfull Cr. Saskatoon, SK S7K 8H7 (306) 955-8131 www.shermco.com [email protected]

Pace Technologies, Inc. 9604 - 41 Avenue NW Edmonton, AB T6E 6G9 (780) 450-0404 [email protected] www.pacetechnologies.com Craig Leavitt

PUERTO RICO 249

Phasor Engineering Sabaneta Industrial Park #216 Mercedita, PR 00715 Puerto Rico (787) 844-9366 Fax: (787) 841-6385 [email protected] www.phasorinc.com Rafael Castro

Advanced Electrical Services 4999 - 43rd St. NE, Unit 143 Calgary, AB T2B 3N4 (403) 697-3747 [email protected] www.aes-ab.com Zachary Houk Orbis Engineering Field Services Ltd. #228 - 18 Royal Vista Link NW Calgary, AB T3R 0K4 (403) 374-0051 www.orbisengineering.net

For additional information on NETA visit netaworld.org

ABOUT THE INTERNATIONAL ELECTRICAL TESTING ASSOCIATION The InterNational Electrical Testing Association (NETA) is an accredited standards developer for the American National Standards Institute (ANSI) and defines the standards by which electrical equipment is deemed safe and reliable. NETA Certified Technicians conduct the tests that ensure this equipment meets the Association’s stringent specifications. NETA is the leading source of specifications, procedures, testing, and requirements, not only for commissioning new equipment but for testing the reliability and performance of existing equipment.

CERTIFICATION Certification of competency is particularly important in the electrical testing industry. Inherent in the determination of the equipment’s serviceability is the prerequisite that individuals performing the tests be capable of conducting the tests in a safe manner and with complete knowledge of the hazards involved. They must also evaluate the test data and make an informed judgment on the continued serviceability, deterioration, or nonserviceability of the specific equipment. NETA, a nationally-recognized certification agency, provides recognition of four levels of competency within the electrical testing industry in accordance with ANSI/NETA ETT-2018 Standard for Certification of Electrical Testing Technicians.

QUALIFICATIONS OF THE TESTING ORGANIZATION An independent overview is the only method of determining the long-term usage of electrical apparatus and its suitability for the intended purpose. NETA Accredited Companies best support the interest of the owner, as the objectivity and competency of the testing firm is as important as the competency of the individual technician. NETA Accredited Companies are part of an independent, third-party electrical testing association dedicated to setting world standards in electrical maintenance and acceptance testing. Hiring a NETA Accredited Company assures the customer that: • The NETA Technician has broad-based knowledge — this person is trained to inspect, test, maintain, and calibrate all types of electrical equipment in all types of industries. • NETA Technicians meet stringent educational and experience requirements in accordance with ANSI/NETA ETT-2018 Standard for Certification of Electrical Testing Technicians. • A Registered Professional Engineer will review all engineering reports • All tests will be performed objectively, according to NETA specifications, using calibrated instruments traceable to the National Institute of Science and Technology (NIST). • The firm is a well-established, full-service electrical testing business.

Setting the Standard

104

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105

VOLUME 1

SAFETY

SERIES III

HANDBOOK

SAFETY Vol. 1 HANDBOOK

SERIES III

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SAFETY VOL. 1 HANDBOOK

Published by

InterNational Electrical Testing Association

SAFETY VOL. 1 HANDBOOK TABLE OF CONTENTS Service Entrance Switchboards: Design Considerations to Enhance Safety and Reliability ....................................... 7 Robert P. Hansen, P.E., PhD

Electrical Safety: A New Paradigm ................................................................... 11 David I. Windley

Electrical Safety Through Design, Installation, and Maintenance ........................... 16 Dennis K. Neitzel

Electrical Safety Myths, Legends and Misconceptions .......................................... 23 James R. White

Industrial Electrical Safety Compliance Assessments ............................................ 28 Dennis Neitzel

Developing an “Electrical” Multi-Employer Worksite Protection Program ................. 34 Don Brown

Personal Protective Grounding ......................................................................... 37 Jeff Jowett

Human Error and Safety .................................................................................. 40 Paul Chamberlain

Power Transformer Hazard Awareness .............................................................. 42 Scott Blizard

Understanding and Implementing the ANSI/NETA ECS-2015 ............................... 46 Lorne Gara and Ron Widup

Published by

InterNational Electrical Testing Association 3050 Old Centre Avenue, Suite 101, Portage, Michigan 49024

269.488.6382

www.netaworld.org

Pre-Job Briefings; An Indispensable Safety Tool ................................................... 51 Paul Chamberlain

First Rule of Troubleshooting; Trust, but Verify ..................................................... 53 Don Genutis

Distracted Driving ........................................................................................... 54 Paul Chamberlain

Test Equipment: Managing the Hidden Defects ................................................... 56 Ashley Harkness

Beliefs Drive Behaviors .................................................................................... 58 Daryld Ray Crow and Danny P. Liggett

Published by

InterNational Electrical Testing Association 3050 Old Centre Avenue, Suite 101, Portage, Michigan 49024

269.488.6382

www.netaworld.org

Published by InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024 269.488.6382 www.netaworld.org

NOTICE AND DISCLAIMER NETA Technical Papers and Articles are published by the InterNational Electrical Testing Association. Opinions, views, and conclusions expressed in articles herein are those of the authors and not necessarily those of NETA. Publication herein does not constitute or imply any endorsement of any opinion, product, or service by NETA, its directors, officers, members, employees, or agents (hereinafter “NETA”). All technical data in this publication reflects the experience of individuals using specific tools, products, equipment, and components under specific conditions and circumstances which may or may not be fully reported and over which NETA has neither exercised nor reserved control. Such data has not been independently tested or otherwise verified by NETA. NETA makes no endorsement, representation or warranty as to any opinion, product or service referenced in this publication. NETA expressly disclaims any and all liability to any consumer, purchaser or any other person using any product or service referenced herein for any injuries or damages of any kind whatsoever, including, but not limited to, any consequential, special incidental, direct or indirect damages. NETA further disclaims any and all warranties, express or implied, including, but not limited to, any implied warranty or merchantability or any implied warranty of fitness for a particular purpose. Please Note: All biographies of authors and presenters contained herein are reflective of the professional standing of these individuals at the time the articles were originally published. Titles, companies, and other factors may have changed since the original publication date.

Copyright © 2019 by InterNational Electrical Testing Association, all rights reserved. No part of this publication may be reproduced in any form or by any means, electronic or mechanical, without permission in writing from the publisher.

7

Safety Vol. 1

SERVICE ENTRANCE SWITCHBOARDS DESIGN CONSIDERATIONS TO ENHANCE SAFETY AND RELIABILITY NETA World, Winter 2013 Issue Robert P. Hansen, P.E., PhD, GE Specification Engineer

INTRODUCTION Switchboards are a widely used type of equipment in low voltage electrical distribution systems. They are typically used as the service entrance equipment for a variety of facility types. While consideration of safety and reliability must be given to all parts of an electrical distribution system design, the impact of choosing the correct design options to enhance safety and reliability is magnified at a service entrance. This article will discuss simple switchboard configuration and equipment options that, when incorporated in the design phase of a project, can cost-effectively reduce arc flash incident energy or reduce worker exposure to arc flash energy without reducing reliability. The scope of NPFA 70E (reference 1) does not include design of distribution systems, but it does contain references to design practices and equipment options aimed at reducing arc flash energy or worker exposure.

Article 130 – Work Involving Electrical Hazards 130.5 Arc Flash Hazard Analysis, informational note #3: “... Equipment and design practices are available to minimize the energy levels and the number of at-risk procedures that require an employee to be exposed to high energy sources.”

Informative Annex O – Safety Related Design Requirements O.1.2 “… The facility owner or manager, or the employer, should choose design options that eliminate or reduce exposure risks and enhance the effectiveness of safety related work practices.” O.2.3 Arc Energy Reduction. “Where a circuit breaker that is rated for, or can be adjusted to, 1000 amperes or more is used, one of the following or equivalent means has proven to be effective in reducing arc flash energy:

to set the circuit breaker back to a normal setting after the potentially hazardous work is complete.” This article will describe some of the design practices and options that can be applied to commonly used non-compartmented, service entrance switchboards. The application of zone selective interlocking (ZSI), including the newer instantaneous ZSI, and maintenance switching will be among the specific strategies discussed.

BACKGROUND In the one-line below (figure 1), a utility, or end-user owned, transformer is connected to a service entrance switchboard. The switchboard has a main breaker, and any number of group or individually mounted feeder breakers. The overcurrent protective device (OCPD) that is upstream of the transformer would typically be a fused switch or a MV breaker. The protection settings (in the case of the MV breaker), or fixed time-current characteristics (in the case of the MV fuse) determine how quickly an arcing fault will be cleared on the transformer secondary side down to the LV main device terminals. For a given system, that upstream device clearing time will determine the arc flash energy on the line-side of the LV main breaker. The LV main breaker protection settings are typically chosen to protect the bus on its load side, and back-up the protection afforded by the feeder breakers to parts of the system below the switchboard. The LV main breaker settings will determine how quickly a load-side arcing fault will be cleared, which in turn influences the amount of arc flash energy on the load-side bus. In many cases, the low voltage main device line-side and load-side arc flash energies are of different values, in some cases by a large amount, with the line-side energy being the higher of the two.

● Zone-selective interlocking ● Differential relaying ● Energy-reducing maintenance switching with a local status indicator An energy-reducing maintenance switch allows a worker to set a circuit breaker trip unit to operate faster while the worker is working within an arc flash boundary, as defined in NFPA 70E, and then

Fig. 1: Typical service entrance

8 As an example, on a 480V service entrance fed by a 2000kVA transformer with standard impedance, the LV main breaker can limit incident energy to below 4 cal/cm2 when the LV main breaker is allowed to clear arcing faults using its instantaneous response1. The incident energy on the LV main breaker line-side would be over 130 cal/cm2, and have a corresponding arc flash boundary of 36 feet when the transformer primary is protected by a fuse. For non-compartmented switchboards, the highest incident energy calculated anywhere within the switchboard would typically be reflected on the arc flash labels for all sections in that continuous line-up. This can render the entire switchboard unapproachable while it is energized. A complete approach for safe design will attempt to minimize both the line-side and load-side arc flash energies. In cases where the owner of the service entrance switchboard owns the transformer and decides what primary protection to apply, protection strategies as explained in reference 2 can be used to reduce the line-side arc flash energy. In all other cases where the service entrance switchboard owner may not have authority to select the substation transformer primary protection device/settings, the strategy of placing the low voltage main section remote from the feeder sections, as discussed in the next section, can be used to reduce worker exposure to the higher line-side arc flash energy. Independent of the substation transformer primary protection ownership, the equipment options (ZSI and maintenance switching) discussed in the following section can be used to enhance safety for workers. In the case of a service entrance switchboard with no main device (a “six handle rule” service entrance per NEC Article 230.71), the distinction between line-side and load-side arc flash energy as described above is lost. The low voltage arcing fault clearing time of the protective device upstream of the transformer will determine the amount of arc flash energy for the entire service entrance bus. For service entrance switchboards without main devices, the protection techniques needed to minimize arc flash energy at the low voltage service entrance bus are beyond the scope of this article. References 2 and 3 describe some of the options that could be used. In a conventional switchboard service entrance design, the main breaker and the feeder breakers are connected by hard bus such that the main section is in a continuous line-up with the feeder section(s). While this is convenient from the perspective of installation, it does have disadvantages when the arc flash energy at the line-side of the main breaker is greater than the load-side arc flash energy. High line-side arc flash energy can increase risks to workers interacting with other parts of the switchboard that are not part of the incoming section. The arc flash boundary for sufficiently high line-side arc flash energy can easily extend past the feeder sections. Main circuit breaker trip unit settings or temporary settings, such as used by a maintenance switch, only influence the load-side. The elevated line-side energy potentially increases the frequency and duration of exposure for personnel who interact

Safety Vol. 1 only with feeder sections. In the conventional configuration there is greater impetus to employ line-side energy reduction methods. The following section will discuss some options for improving upon the conventional switchboard design.

OPTIONS FOR IMPROVING THE CONVENTIONAL DESIGN Remote Main Breaker Section Many users now recognize the simplicity and effectiveness of employing a switchboard with a remote main circuit breaker section. In this design strategy, the section that receives the incoming feed from the utility transformer contains only the main circuit breaker, and this single breaker section is cabled to a separate lineup containing the feeder breakers. The concept is to provide distance between the higher arc flash energy normally found on the line-side of the low voltage main device and the sections on the load-side. With sufficient distance between the main section and the feeder sections, the feeder breaker sections can be outside of the main section’s line-side arc flash boundary. This reduces the risk to personnel who interact with the feeder sections, when the main breaker is appropriately set to clear arcing fault currents, and allows workers within the arc flash boundary of the feeder sections to wear personal protective equipment (PPE) appropriate for the incident energy at that location. When interacting with the remote main breaker section, the appropriate PPE for the higher line-side incident energy is still required. A remote main breaker section can also be used in a retrofit situation. For an existing switchboard using a conventional layout with a main device, a new main breaker section can be inserted between the transformer secondary and the existing main. The protection settings of the new main breaker will determine the amount of arc flash energy at switchboard sections of the original conventional line-up. A service entrance with a main-lug-only switchboard (“six handle rule”) can be converted to a single disconnect service entrance by adding a remote main section. For new construction or retrofit situations, using a circuit breaker in the remote main section helps the owner to take advantage of maintenance switching and zone selective interlocking (with circuit breaker feeders). Electrical operation of the main breaker with remote control is also an option to reduce exposure of personnel to arc flash energy. Line-side arc flash energy reduction methods can be applied to the remote main section to further enhance safety for anyone interacting with the incoming section. Even if no personnel interact with the remote main section while it is energized, line-side arc flash energy reduction can be desirable to help protect the equipment.

Maintenance Switching A maintenance switch controls a temporary protection setting on a circuit breaker electronic trip unit and can provide benefits

Safety Vol. 1 for any switchboard configuration. The temporary setting can be enabled to reduce the archyphenate-flash energy of an arcing fault on the LV bus downstream of the breaker that has the maintenance switch function. A maintenance switch is typically enabled when an operator has to perform a task inside of the arc-flash boundary. When the task is complete, the switch is set back to its default position which turns off the temporary protection setting. The temporary setting is a second instantaneous pick-up setting that must be pre-selected by the user. An arc-flash study would determine the appropriate pick-up level for the maintenance setting. Because the maintenance setting should be set to a lower instantaneous pick-up relative to the normal instantaneous setting, coordination is generally reduced while the maintenance setting is enabled. The local status indicator (or optional remote status indicator) provides visual confirmation (usually in the form of a light) of the maintenance setting state. Maintenance switching can be used on the main breaker in the conventional or remote main switchboard layouts. Maintenance settings can also be used on feeder breakers to improve protection on other downstream switchboards, motor control centers, or panelboards. The switch can be provided on the face of the switchboard section, or wired to a location outside of the arc-flash boundary. On trip units that communicate with monitoring and control software, the maintenance setting may also be enabled or disabled over the network. The amount of incident energy reduction that is achieved by using a maintenance mode is dependent on the particular system and on the breaker protection settings before the maintenance mode is enabled. A maintenance switch can be provided with new equipment or retrofit to existing equipment with a trip unit upgrade.

Zone-Selective Interlocking General Zone-selective interlocking (ZSI) is available as an optional feature on selected electronic trip units in specific breakers. For arc-flash safety, the two forms of low voltage ZSI of primary interest are short-time ZSI and instantaneous ZSI. Each form may be used individually, or concurrently with each other. Both forms of ZSI are a specialized protection scheme between two breakers in series, such as a main and a feeder. Multiple feeders may be in a ZSI scheme with one main. The ZSI scheme may also be extended to main-tie-main configurations. Similar to the maintenance switch, ZSI can be provided in new equipment or in a retrofit to existing equipment. The safety benefit of a ZSI scheme is its potential to reduce arc flash energy on the system between the upstream and downstream breakers in the scheme. An arc flash study is needed to determine the appropriate protection settings to achieve the maximum benefit from the scheme. While maintenance switching is designed as a temporary arc flash energy reduction method (applied at specific times when operators interact with the equipment), ZSI is intended

9 to be active continuously. The details of any ZSI implementation will be specific to the particular vendor and the particular generation of equipment. In the context of a switchboard, a ZSI scheme created between the main breaker and feeder breakers will allow lower pick-ups (and delays in the case of short-time ZSI) to be set on the main breaker without loss of selectivity. If the feeder breaker senses a fault within the pick-up range of the ZSI scheme, a signal informs the main breaker and it will adjust its protection response, allowing the downstream breaker to clear the fault first and preserve selective coordination in the range of fault current where the ZSI is employed. The arc flash energy reduction potential of ZSI is derived from the lower settings (relative to traditional nesting techniques) that can be used on the main breaker. These lower settings allow for the main breaker to respond quicker to arcing faults on the switchboard bus. Short-time ZSI While the NFPA-70E reference to ZSI does not differentiate between short-time and instantaneous ZSI, there are important differences. A trip unit on the upstream breaker with short-time ZSI will use two short-time delay bands that are set by the user. One of these bands is the normal short-time delay band called the unrestrained position. The second short-time band, called the restrained position, is a longer delay band that does not overlap the unrestrained band. If the downstream breaker senses a fault within the range of the short-time pick-up, it sends a signal that switches the short-time delay band of the upstream breaker to the restrained position. When applied to a main and a feeder, this allows the main breaker unrestrained short-time delay to be set at a low band without loss of coordination. This can facilitate a lower arc flash energy for arcing faults on the switchboard bus, compared to using coordinated short-time settings without ZSI. The amount of arc flash energy reduction possible is, in part, limited by the intentional time delay in the unrestrained short-time delay band. While the short-time ZSI can enhance protection without affecting the short-time coordination, it has no effect on any lack of selective coordination that may exist in the instantaneous range. Disabling the instantaneous response of the main breaker is not an option for switchboards that do not have a 30-cycle withstand rating. Thus, using short-time ZSI by itself in a typical switchboard still leaves the designer with the issue of how to coordinate the main and feeder breakers in the instantaneous region. Instantaneous ZSI Instantaneous ZSI coordinates the instantaneous response of the breakers in the ZSI scheme. The upstream breaker in an instantaneous ZSI scheme uses its normal (unrestrained) instantaneous protection setting (without intentional delay) when there are no faults on the system or a fault occurs in the zone between the breakers in the ZSI scheme. The upstream breaker response moves from instantaneous to a fixed short-time delay band (restrained position) only if the downstream breaker senses a fault in the instantaneous range of pick-up. The restrained position of

10 the upstream breaker gives the downstream breaker time to clear a fault before the upstream breaker commits to tripping. In this way, instantaneous ZSI provides for improved safety by helping the main breaker to clear a fault on the main bus at its instantaneous clearing speed, while improving instantaneous coordination with feeder breakers by shifting the main breaker response if the fault is below the feeder. As described above, a ZSI scheme manages the delays used by the upstream breaker. In the case of instantaneous ZSI, the instantaneous response of the upstream breaker moves from no delay to a delay when the downstream breaker also senses the fault. In the case of short-time ZSI, the upstream breaker response moves from one delay band to a longer delay band when the downstream breaker also senses the fault. In the traditional implementation of ZSI, the instantaneous and short-time pick-ups of the upstream breaker would normally be set above the corresponding pick-ups of the downstream breakers in the scheme to maintain selectivity (the pick-ups would be nested). This nesting of pick-ups forces the upstream breaker to be less sensitive to dangerous arcing currents. A recent new development in ZSI permits the nominal pickup settings of the upstream breaker to be set to the same value as the downstream breaker without loss of selectivity (reference 4). In the context of a service entrance switchboard, this means the pick-ups (short-time, instantaneous, or both) of the main breaker can overlap the corresponding pick-ups of the downstream breaker where ZSI is enabled. In most systems, this will help the main breaker instantaneous to be set low enough to clear load-side arcing faults predicted by an arc flash study in the shortest amount of time possible for that main breaker. For a given system, clearing an arcing fault on instantaneous results in lower arc flash energy compared to clearing using short-time. The most comprehensive application of ZSI would use short-time and instantaneous ZSI simultaneously. Additional information about instantaneous ZSI, including application examples, may be found in references 4 and 5.

SUMMARY Each of the design options discussed can be considered as a discrete layer of improvement to the conventional switchboard design. The options can be applied individually or combined in various ways to best meet the needs of a particular situation. This article has elaborated on just a few of the design choices and equipment options that can be used to enhance the safety and reliability of service entrance switchboards. Options such as drawout mounting with remote racking, remote breaker operation, and remote monitoring should also be considered. While service entrance switchboards have been the focus of the article, the strategies discussed here can also be applied to non-service entrance switchboards to improve safety and reliability.

Safety Vol. 1 REFERENCES 1. National Fire Protection Association, NFPA-70E, Standard for Electrical Safety in the Workplace, 2012 Edition. 2. Maurice D’Mello, “Arc Flash Hazard Reduction on Incoming Terminals of LV Equipment”, IEEE PCIC 2014, San Francisco, CA, to be published September 2014. 3. Clapper, M., “GE Arc Vault Protection System”, GE White Paper, http://www.geindustrial.com/publibrary/checkout/ArcAbsorber?TNR=White%20Papers|ArcAbsorber|generic. 4. Valdes, M., Dougherty, J., “Advances in Protective Device Iterlocking for Improved Protection and Selectivity”, IEEE PCIC 2013-30, September 2013. 5. Wright, B., D’Mello, M., Cuculic, R., “Zone Selective Interlocking On Instantaneous (I-ZSI) and Waveform Recognition (WFR)”, GE White Paper, http://www.geindustrial.com/ publibrary/checkout/IZSI-WFR?TNR=White%20Papers|IZSI-WFR|generic Robert Hansen is a Specification Engineer for GE’s Industrial Solutions business, working in Overland Park, Kan. He has been in this role since 2007 and provides application and technical support for engineers designing commercial and industrial power distribution systems throughout his area of responsibility which includes Kansas, Missouri, Oklahoma, and parts of Arkansas and Illinois. Robert has more than 30 years of design experience and 26 years active military service which includes teaching undergraduate engineering for six years at the United States Military Academy. Robert graduated from the United States Military Academy, West Point, N.Y. in 1981 with a Bachelor of Science degree, and also graduated from the Pennsylvania State University with an Master of Science degree in aerospace engineering (1992) and a PhD in mechanical engineering (2001). His academic work was heavily focused on numerical simulation using high performance computers. He is an IEEE member and a licensed professional engineer (P.E.).

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Safety Vol. 1

ELECTRICAL SAFETY: A NEW PARADIGM PowerTest 2013 David I. Windley, P.Eng., WINTEK Engineering Limited

ABSTRACT This paper will briefly cover the state of the industry with regard to electrical safety practices from design to testing, maintenance, and operations and demonstrate that out thinking needs to be changed and directed toward new ways of addressing traditional electrical safety challenges. A new paradigm is required in the best practices of electrical power and control system design, commissioning, maintenance, operation, and management so that work on energized equipment can be eliminated or reduced to a level where exposure is minimised. Faced with the fact that this work is sometimes necessary, new methods, equipment, and procedures need to be developed and put in place to enable those doing the work to proceed confidently and safely. This paper will endeavour to outline the opportunities and potential strategies to evolving to a new paradigm.

DEFINITION: par·a·digm /ˈparəˌdīm/ Noun: A typical example or pattern of something; a model. A worldview underlying the theories and methodology of a particular scientific subject.

Introduction Testing, troubleshooting, and commissioning activities provide the highest risk for workers as these tasks imply partially complete or non-functioning systems. These conditions require exposure to elevated voltages and high energy equipment which could result in electrocution or serious life threatening burn injuries. Everyone is encouraged to work safely when it comes to energized electrics but sometimes it is not possible to perform the required tasks without exposure. However, we need to innovate and establish a new paradigm of design which will minimise exposure and to develop new testing and troubleshooting techniques which will minimise injury should an unexpected event were to occur. There needs to be a “discovery” of the real issues affecting worker safety and a paradigm shift in attitude and due diligence to embrace safer design and methods of working.

General State of the Industry So what are we talking about? The business of design, operation, and maintenance of power and control systems has been with us a long time. Not much has changed. Organizations like NEC, NFPA, and IEEE among others have developed numerous

standards, codes, and guidelines to enable us to produce optimum designs incorporating best practices for safe and reliable power systems. Primarily, this has been to protect equipment and systems from being damaged and causing fires, explosions, and other catastrophes which could directly or indirectly injure people or destroy property. We have taken comfort in the fact that our electrical systems are enclosed in boxes or fences to keep unauthorized people out and away from electrical shock or blast. We have also assumed that people will not purposely expose themselves to live voltages and that the equipment will function and can be operated and maintained without any live interaction. The fallacy of this, of course, is that the equipment doesn’t always work the way it was intended and that some level of intimacy with live conductors and parts is required to effect troubleshooting and in some cases on-line repairs. It also doesn’t consider the fact the equipment will be incomplete during construction and that all the designed safety provisions may not be in place. It is not fair or practical to say that equipment shall not be energized on entry unless special provisions have been made to perform the required duties in some other way. Organizations like NETA have given us ways and means to test and evaluate electrical systems. Again, the focus of this is to keep our power systems healthy and functional. Manufacturers are continually developing new and more intuitive methods and test devices to quantitatively determine the state of the electrical equipment. Safety is a factor in the design as it is necessary in almost every case to be intimate with the equipment during this testing. But the ultimate responsibility is with the user and it is imperative that a trained individual is performing the testing and that all procedures and necessary isolations are in force. So given all this, we have systems out there which have followed the best of design intentions at the time, but when we take a closer look, fall short when applied to the potential hazards. We also have systems which are in a poor state of maintenance and have been subjected to operating conditions which will eventually lead to failure. We are also the victims of traps set by poor design and inexperienced designers. A 10 year study by the Electrical Safety Authority in Ontario (2009 Ontario Electrical Safety Report by ESA) has concluded that almost 75% of the fatalities due to electrocution were primarily due to failure to follow procedures and to human error. This shows we have some work to do in developing procedures that can and will be followed and also ensuring that workers are trained and alert when approaching live work.

12 Design Considerations The design of power systems has been studied, analyzed, and practiced for many years. We have always had sense of electrical safety but we generally felt that those doing the work would do it in a safe fashion. Today, even following the best design practices and all the rules we find that unsafe situations evolve and continue to be created. So what has changed? As seasoned architects of electrical power systems and equipment, we still hold the values and beliefs of bygone days. However, as the gauntlet is passed, there is more emphasis on reducing cost and shortening schedules than solid design practices and avoiding serious mistakes. The younger engineers aren’t held in the same high regard as the old experts and they are challenged to do things faster, cheaper, and with fewer adherences to recognized standards. You can see the degradation everywhere you look. The theory at educational institutions doesn’t replace the years of hands-on experience and the advice and guidance of valued mentors. We have evolved to an “electronics and computers can do everything” attitude and now with a smaller number of talented power engineers, the design of power systems is not treated in the same regard as before. Chances are taken and injuries occur. On a positive note, we have got smarter and more risk-avoidant these days with the adoption of new design practices which consider equipment access under live conditions. We are starting to better understand the risks taken by those who work on the equipment. We need to make sure the word is spread regarding the new approach to electrical safety. I have outlined some of the opportunities for design excellence. ● Arc Flash – This new consideration of a well-known hazard will have profound effects on design. There is very little in the Codes and Standards which relate to this potential danger. The reason for this is that it doesn’t relate so much to the equipment and installation, but more to maintenance and operation. Hence, a perfectly acceptable power design may be deficient with respect to arc flash exposure and incident energy levels. As electrical equipment is designed for three phase bolted fault levels, and that the arc flash current is rarely of the same magnitude, we can be fairly confident that an arc fault will not be an issue with equipment damage. However, knowing there may be access required under energized conditions in order to troubleshoot or repair, we cannot ignore the potential energy levels and the injuries that could occur. It is therefore necessary that design engineers consider access and incident energy levels in their design and adjust if appropriate. ● Protective Coordination – Traditional protective coordination sets the power system protection to act in a predictable and logical way to isolate a system fault quickly but to minimise the effect to other areas of the facility. This may cause upstream devices to allow a high level of incident ener-

Safety Vol. 1 gy which increases the arc flash hazard at this location. This can force a contradiction between protective coordination and worker safety and therefore requires an experienced power engineer to analyze and choose the correct settings for the particular installation. Sometimes optical devices responding to “flash” can speed response time or “maintenance” selections programmed into protective devices. ● Transformer Secondary Protection – It has been accepted by most codes that a secondary protective device is not required as long as the primary device provides the necessary protection. Most experienced power engineers will design the power system with this protection anyway because it allows a convenient isolation point for maintenance and helps avoid operating a primary device which may be more difficult to get at. However, cost is many times the factor in not installing these secondary devices. The end result of this is, that almost always, the transformer secondary and associated switchgear is a high arc flash hazard because the primary device is too slow in interrupting the arc flash current. ● Switchgear Design – Over the years we have evolved from metal enclosed technologies to relatively open design and buses. Now we are forced to consider live access to the line side of protective devices forcing us to re-consider the more robust designs which have been long since abandoned. Service entrance type equipment effectively barriers off the line side of the protective device on switchgear and effectively isolates it. Using this same philosophy, it allows safer access to feeder breakers in all areas of the plant. Another consideration is testing. Can I test the cable in a redundant system safely while it is running? If I can’t, then what is the point? Is there a possibility of test voltages flashing to live equipment? ● Arc Resistant Switchgear – Switchgear is designed to handle the large forces which occur in a three-phase bolted fault. However, directing the blast away from the front of the switchgear where someone would be standing is an effective way to prevent injury in the unlikely event a fault will occur and compromise the enclosure. There are still many facilities, mostly industrial, where the main distribution boards are out in the open. The new way will insist on large and medium sized distribution boards in controlled access rooms. ● Instrumentation – Very few switchboards are installed today which allow the plant electrician to verify voltage, current, power flow, and other variables which aid in the maintenance and troubleshooting of the power system. To perform these duties requires expensive portable equipment and connection to live circuits. New switchboards should be designed with the ability to perform load monitoring voltage detection, power quality and harmonics studies without exposure. This equipment is much easier to implement and is cost-effective at the design stage.

Safety Vol. 1 ● New Installations and Control of Change – There are many times when a new line or distribution panel is installed and because it is a simple change, a qualified design engineer is not consulted. With the more complex arc flash design criteria, it is easy to install a trap for an unwitting operator or plant electrician. These traps are caused by poor design or by inexperienced designers or contractors not knowing all the design considerations. A review of all power system changes must be undertaken by competent designer engineers to ensure that all relevant factors are considered in the change. ● Fuses vs. Circuit Breakers – The choice of the most appropriate protective device for an application isn’t quite as simple as it used to be. Proponents of either side will argue the advantages and disadvantages of each. The point is, speed is important when it comes to incident energy and arc flash potential. Sometimes a fuse will respond faster than a circuit breaker, sometimes not. It takes an evaluation by an engineer to determine the appropriate device for the specific application. The openness of a fusible disconnect during fuse checking and replacing can also expose personnel to line side energies of a magnitude much higher than with resetting a circuit breaker where the bus is effectively isolated. ● Isolation of Controls – We have come full circle. Many original designs would separate high voltage from lower voltage controls. With the popularity of PLC and computer based control systems, more access is required for programming and troubleshooting. Yet, many controls are now installed within inches of high voltage motor starters or wiring. Many multi-starter panels are being built which don’t allow the isolation afforded by modular motor control centres. The design engineer must be thinking about what access is required after the fact. For instance; ○ How do I check for voltage? ○ How do I isolate a motor? ○ How do I reset an overload? ○ How do I check or change a fuse or reset a circuit breaker? ○ How do I read diagnostic information? ○ How do I program or configure a drive? ○ How do I diagnose or make changes to a PLC program? There are many options for dealing with the above to remove the need for opening the cabinet. Some of these include: ○ Complete isolation of controls from power (separate cabinets). ○ HMIs, indicators, or instruments for diagnostics. ○ A PLC connection port is a means for accessing the controls. ○ Plunger type or electronic overload resets.

13 In any case, care must be taken, safe procedures developed, and qualified individuals assigned to these tasks to reduce the risk.

Equipment Testing and Commissioning Considerations Electrical testing and commissioning is a high hazard task and not well understood by anyone not associated with the industry. It is easy to discount the necessary requirements to do the job safely. Although unpopular, maybe de-energizing to perform testing or commissioning is the best option. ● Test Equipment – As with any other high hazard task, it is imperative to have the right equipment and trained individuals that know how to use it safely. The manufacturers have developed more sophisticated and intuitive equipment over the years to be able to give the service professional the best window on electrical equipment condition as possible so that a proactive repair can be achieved prior to system failure and facility outage or damage. Equipment must be designed and rated for the task at hand. Use of inappropriate or underrated equipment has and will cause injuries and death. ● Qualifications – Because there are very few ways to accomplish this testing without some risk, it is absolutely necessary that the testing professional is well versed in the safe operation of the test equipment and that there will be procedures plus facility and equipment specific rules to control the hazard. An inexperienced operator may second guess his results or the way to operate the instrument resulting in more time in the energized equipment or perhaps having to do it all over again. This increases exposure and likelihood of injury. ● Barriers and Isolation – Barriers to keep unauthorized personnel away from energized equipment during testing and commissioning is absolutely necessary. The area must be completely secured so that no one goes inside. Coordination with Utility or other parts of a large system can create confusion. Any out-ofsequence or omitted step can result in death or serious injury. It is so easy to jump ahead or ignore the procedures under emergency or production loss conditions. It may be necessary for additional isolation of the equipment under test to avoid flashovers or dangerous conditions in other parts of the facility. Temporary grounding may be appropriate to ensure the workers safety. ● Instrumentation – Sometimes it is necessary to troubleshoot system for power quality or harmonics. Voltage levels, load levels or power factor may need to be measured to assess system performance and to justify system improvements or investigate energy savings. Installing permanent monitoring will allow these types of studies to be performed on an ongoing basis with exposure and for a fraction of the cost. ● Protective Device Testing – Of paramount importance is the setting and maintenance of protective devices and systems. In an aggressive preventative maintenance program in a large chemical facility, we found that 50% of the equipment that we opened had either a faulty condition or inaccurate wiring such

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Safety Vol. 1 that a significant failure or misoperation could be expected with a year. This underlines the need for complete verification and testing of protective device settings and operation on a regular basis. It also emphasizes the importance of control of change.

Operational and Maintenance Considerations In addition to the factors involved in design and testing, the way se operate, troubleshoot, and maintain electrical equipment affects the safety of our people and processes. We must be diligent in ensuring that any new installation is designed and performed with a new vision. However, there are still many existing installations that don’t stand up to present standards or are poorly maintained. Operating and maintenance procedures may or not be in place and they may not be appropriate for the hazards as we know them today. Plant management must be committed to an entirely new of looking at electrical safety. ● Environment – When we walk around a facility, the environment we are in is most obvious. It can be hot, cold, wet, dry, dusty, or clean and pleasant. We can also see where the electrical equipment sits and what conditions it must operate under. It doesn’t take a wise man to know that electrical equipment will not function reliably for very long in adverse conditions. Failure will cause plant outages and production losses which will likely require someone to repair or replace equipment or components under the gun. If the equipment was clean and looked after access to the equipment would be minimised and therefore the exposure significantly reduced. ● Integrity of Equipment – Cabinets with doors open or loose can mean only one thing. This cabinet requires frequent access due to some operational problem or difficulty. So, the very features of design which protect us from an explosion are compromised or are completely bypassed. So what is the solution? Go find the problem! Fix it, and then shut the door and re-install the fasteners to reinstate the original enclosure integrity. If fixing the problem is not possible or not economically feasible, find a way to avoid leaving the cabinet integrity compromised. Holes in equipment, frayed cords, missing pushbuttons, or damaged connectors seem pretty innocuous, but these are the seeds to a poorly maintained system. Not addressing these issues condones this and de-sensitizes workers to these hazards. It is also a signal that maintenance and testing is not being done. Cleaning and dusting is crucial. Moisture and animal ingression to equipment must be prevented. ● HVAC – What, for the equipment? Yes and no. What a better way to keep the equipment dry and clean than to dehumidify the air and keep a reasonable temperature in the switchroom. Getting rid of wide temperature changes avoids condensation planting itself on electrical equipment. But another factor affects the worker. When we force an electrician to work on a piece of equipment, whether simply PM or not, in adverse conditions, the quality of the work reduces and the chance for mistakes increase. We don’t have to make it cozy, but it needs

to consider the comfort of the worker with the PPE he will have to wear. ● Switching Operation – Switching, racking, drawing out electrical equipment performed with doors closed and latched puts an additional barrier between the arc energy and the equipment operator. Still, the enclosure may not contain the tremendous energy that is released on a fault within the equipment. Switching any equipment with an open door is hazardous and foolish. Switching – Is there a safe way to do this? Absolutely. ○ Once appropriate PPE is worn. Always use dry gloves and basic PPE. Establish a corporate procedure for the level of PPE to be used. ○ The first step is to evaluate the equipment. Does it look safe to operate? If not, de-energize and clean or dry or repair it so that it can operated in a safe fashion. ○ Ensure the load is minimised though the switch. It will be less likely to draw an arc. ○ Close and latch the equipment door. Use the designed handle and do not use a wrench or other contrivance to operate it with the door open. ○ Step to the side and, with non-working hand, operate the switch. If it is difficult to operate or won’t go, stop. Do not force a switch or circuit breaker. De-energize and repair. ○ Never try to stop part way though. Go all the way. Too Much PPE? - How can this be? We have taken great pains in the last ten years to identify the location and extent of the hazards. And in addition the manufacturers have joined in the fight by bringing to market many varieties of PPE and tools and other contrivances to deal with the high hazard areas. However, the worker is not always considered, even though he or she is the one who has to wear the PPE and use the tools when very little thought is made to actually changing the conditions or the way in which the task is completed in order to minimize exposure. ● Procedures – An interesting fact (2009 Ontario Electrical Safety Report by ESA) is that almost 75% of the causes of electrocutions can be attributed to not following procedures or human error. Equally interesting was the fact that most of the trades involved were not electricians. So does this let us off the hook? Can we just blame the victim for their own misfortune? Not really, if we look at why these occurred. So why does this happen? Perhaps policies and rules that were in place were neither feasible nor practical. Perhaps the pressure was intense to get the equipment back in production. Perhaps there was nobody else there to do the work and they were pressed into service even though unqualified. Documents like NFPA70E go a long way to describe many of the factors that need to be considered in the maintenance and operation of electrical equipment in any facility. Strict adoption of the relevant guideline will ensure that safety is preserved. Use of

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Safety Vol. 1 Energized Electric Permits and the development and use of Electrical Safety Procedures is paramount to any electrical safety program. Strict adherence to procedures must be mandatory for live work. No exceptions. The idea is not to have to work on energized equipment. Find a way not to. ● Attitudes – Some attitudes need to change. Production is not more important than someone’s safety. Scheduled outages are necessary for all equipment. Live work should only be carried out when absolutely necessary and only by qualified professionals using the right tools and following well thought out procedures. If you can’t find a way to justify working on equipment live, find another way of performing the task. It’s not worth it. The electrical industry is no place for cowboys. It is not cool to work live. You may get away with it but the young apprentice watching in earnest and awe may not be so lucky when he or she tries it. ● Electrician Survey – An excerpt from the 2009 Ontario Electrical Safety Report by ESA summarized the results from a survey of 1200 IBEW electricians carried out in 2008. The purpose of the survey was to obtain a baseline measure of the electrical trades’ safety awareness when working with 347V. Some of the more interesting responses: ○ 42% of respondents associated a high risk with working on energized circuits. ○ 57% indicated that they almost always take precautions concerning electrical safety (such as using personal protective equipment). ○ 83% indicated that they almost always test with meters before working on electrical systems. ○ 64% of those who worked energized did so to test. ○ 36% of those who worked energized did so because they; – believe that they can manage the risk – want to save time – are asked to do so ○ 88% indicated they have been educated to minimize the risk of working energized. ○ 49% indicated they are requested to work outside established safe work practices. ○ 89% indicated that information on electrical safety requirements would have an average to high impact on improving safety on the job. ○ 92% indicated more information and effort is required to support worker safety.

CONCLUSIONS We have reached a point in the workplace that electrical safety has become high profile and we will force workers to comply with the rules. This is excellent, but little thought has been spent on how

the work is going to get done without violating the rules. Chances will be taken because the work “has to be done.” The power systems engineers must begin by taking a new look at how system are designed and installed. Our engineers need to become aware of the “new” right way to do things. They must now consider how the equipment will be tested and commissioned. The will also need to consider how the equipment will be accessed and maintained and “design-in” innovative ways to remove the need for live work. We need to spend the money and time to do it right the first time. Design is not where to save money. Spend the time. Do it right. Downtime, repairs, equipment damage, quality issues and injuries and deaths are expensive. Testing and commissioning personnel need to understand that their trade is very specialized, and the nature of the work is hazardous at all times. Strict adherence to procedures and using the correct equipment will go a long way to ensuring the safety of all involved. Operations and maintenance personnel need to analyze and determine the need for accessing equipment under energized conditions. If equipment needs constant attention, replace or re-design it so it doesn’t. Don’t abuse equipment so that it is guaranteed to fail. Create innovative ways to perform the task that was traditionally performed live. In cases where live work is necessary, develop procedures which are practical and can be followed without breaking the rules. Once the rules are in place, enforcement is a critical final step. All the stakeholders from engineer, commissioner, trouble-shooter, and to management must step back and re-evaluate the whole process and develop workable and safe solutions to everyday electrical challenges. They need to adopt a new way of thinking, being proactive and not reactionary to electrical safety issues. Cost-effective and practical solutions must be embraced by management; not rigid and unthinking ones forced on those doing the work. Money and time needs to be spent up front to avoid “built-in” mistakes which can create traps down the road. Let’s “think outside the box” and visualize a new paradigm in which we will perform in a way that will allow people to work safely without hazards. After the fact is not good enough—it’s too late.

REFERENCES 2009 Ontario Electrical Safety Report – Electrical Safety Authority, Ontario, Canada

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ELECTRICAL SAFETY THROUGH DESIGN, INSTALLATION, AND MAINTENANCE PowerTest 2013 By Dennis K. Neitzel, C.P.E., AVO Training Institute, Inc.

INTRODUCTION

ELECTRICAL HAZARDS

Owners, operators, installers, and maintainers of commercial and industrial electric power systems and equipment, along with design consultants and manufacturers, should be concerned with the electrical safety aspects associated with these systems and equipment. Electrical safety must be an integral part of all electrical equipment and systems design and installations. An in-depth knowledge and understanding of all applicable codes, standards, and regulations is a must for electrical safety in design. Safety professionals and officers, knowledgeable in electrical equipment and systems as well as electrical safety, must be included in the planning and design phases of all projects to ensure that safety is discussed and included in the design.

In order to fully understand the electrical safety issues associated with design, installation, and maintenance, there must be an understanding of the hazards of electricity, identified through completing the electrical hazard analysis required by OSHA 1910.132(d) (1) and NFPA 70E Section 130.3(B)(1), specifically 130.4 Shock Hazard Analysis and 130.5 Arc Flash Hazard Analysis. One very important point to make here is that the physics of electricity are the same for everyone who has any kind of interaction with electricity or electrical equipment, even something as simple as plugging in an electrical appliance or portable tool; the physics are the same and do not change from the installer to the maintenance employee, or for that matter anyone else.

Electrical safety in the design, installation, and maintenance or electrical equipment and systems is critical because statistics reveal that there are approximately 400 electrocutions each year in industry with more than half of them occurring at less than 600 volts. There are also more than 2000 people admitted to burn centers each year from arc flash related burns. Additionally, over 800 people die annually due to fires caused by electrical faults, mainly due to faulty design, installation, or maintenance of the electrical equipment and/ or systems. Each year, electrical mishaps account for thousands of people sustaining shock and burn injuries. Electrical failures also result in billions of dollars in property damage each year; the vast majority of these incidents could have been prevented by applying electrical safety in the design, installation and maintenance of the electrical equipment and systems.

The three main hazards of electricity; electrical shock, electrical arc flash, and electrical arc blast, along with the physiological effects on the human body, must be understood by everyone who designs, installs, maintains, or works on, near, or interacts with, electrical circuits and equipment. These hazards must be understood by designers to help them better understand what needs to be done and why, when it comes to designing hazards out and safety in.

Current standards and regulations place minimum requirements on electrical system designers, installers, and manufacturers, which yields functional, reasonably safe electrical installations. Knowledge of the electrical hazards will assist in going beyond the minimum requirements and providing a safe and reliable electrical power system. Effective electrical preventive maintenance begins with good design. When designing a new facility, a conscious effort should be made to ensure optimum maintainability of the installed system and equipment. Design and installation of dual or redundant circuits, tie circuits, auxiliary power sources, and drawout protective devices make it easier to schedule maintenance activities and to perform the required maintenance work, with minimum interruption of production. Other effective design techniques that should be considered include, but are not limited to, equipment rooms to provide environmental protection, grouping of equipment for more convenience and accessibility, and standardization of equipment and components.

Designing and installing electrical equipment and systems in accordance with applicable standards, such as the National Equipment Manufacturer’s Association (NEMA), the National Electrical Code (NEC), the National Electrical Safety Code (NESC), the IEEE Color Book series for industrial and commercial power systems, and where applicable the Canadian Standards Association (CSA), the International Electrotechnical Commission (IEC), or the UK Electrical Industry British Standards (BS) (including the City and Guilds electrical standards) for design, manufacture, and installation of the electrical equipment and systems, will provide the minimum requirements for safety by design. Complying with these standards for design and installation, along with properly maintaining electrical equipment in its original condition can dramatically reduce the risk of the electrical shock and/or arc flash hazards. Adhering to safe work practices for personnel, along with complying with the maintenance recommendations for electrical equipment, provided by the Occupational Safety and Health Administration (OSHA), the National Fire Protection Association (NFPA; using NFPA 70E, Standard for Electrical Safety in the Workplace and NFPA 70B, Recommended Practice for Electrical Equipment Maintenance), the InterNational Electrical Testing Association (NETA) Standard for Maintenance Testing Specifications for Electric Power Distribution Equipment and Systems

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Safety Vol. 1 (MTS), and the NESC, along with the manufacturer’s instructions, can significantly reduce the risk of a person making contact with energized conductors or circuit parts and can reduce the risk of an arc flash event occurring, as well as significantly increasing the reliability of the electrical equipment and system.

Electrical Shock Electrical shock occurs when a person’s body completes the current path between two energized conductors of a circuit or between an energized conductor and a grounded surface or object. Essentially, when there is a difference in potential (voltage) from one part of the body to another, current will flow. The effects of an electrical shock on the human body can vary from a slight tingle to immediate cardiac arrest. The severity depends on several factors: ● Body resistance (wet or dry skin are major factors of resistance) ● Circuit voltage (50 volts to ground or more is considered by OSHA, IEEE, and NFPA as being hazardous voltage) ● Amount of current flowing through the body [determined by the circuit voltage divided by the body resistance I (current) = E (voltage) / R (resistance) or I = E/R] ● Current path through the body (if it passes through an vital organ it can be fatal) ● Area of contact ● Duration of contact The “Shock Hazard Analysis” required by NFPA 70E Section 130.4 provides the guidance needed to determine the level of shock hazard (voltage). This analysis also determines the shock protection boundaries, as well as the approach limits for qualified and unqualified employees, along with the required shock protection PPE, i.e., rubber insulating gloves with leather protectors, rubber insulating sleeves, rubber insulating blankets, etc.

Electrical Arc Flash An electrical arc flash is the rapid release of energy due to an arcing fault of either phase-to-phase, phase-to-neutral, or phaseto-ground. Typically when one of these three conditions is initiated it will end up with all three occurring because the air becomes a conductor due to ionization, along with the plasma created from the vaporized metals, particularly copper. Simply put, an arc flash is a phenomenon where a flashover of electric current leaves its intended path and travels through the air from one conductor to another, or to ground. The results are often violent and when a person is in close proximity to the arc flash, serious injury and even death can occur. Because of the violent nature of an arc flash exposure, when an employee is injured, the injury is serious – even resulting in death. It’s not uncommon for an injured employee to never regain their past quality of life. There are various studies on the causes of electrical injuries that show that a large number these injuries involve burns from elec-

trical arcs. There are actually three different issues with the arc flash hazard; 1) the arc temperature; 2) the incident energy; and 3) the pressure developed by the arc. The main concern with the arc temperature, which can be as high as 36,000ºF, is the flash flame and ignition of clothing. At approximately 203ºF (96ºC) for one-tenth of a second (6 cycles), the skin is rendered incurable or in other words a third-degree burn, and at approximately 172ºF (78ºC) for one-tenth of a second (6 cycles) a person could receive a second degree burn. The incident energy threshold for the onset of a third-degree burn is approximately 10.7 cal/cm2 and the incident energy threshold for a second-degree burn is approximately 1.2 cal/cm2. As can be seen by this, it does not take a very high temperature or very much incident energy to cause severe injury, which can result in extreme pain and discomfort or even death to the worker. The “Arc Flash Hazard Analysis” required by NFPA 70E Section 130.5 is used to determine the incident energy of an electrical arc, establish the Arc Flash Boundary, and for determining the level of arc-rated clothing and PPE required for protecting employees.

Electrical Arc Blast Another major hazard of electricity is the rapid expansion of the air caused by an electrical arc. This occurrence is referred to as an electrical arc blast or in other words an explosion. According to studies on the subject, the pressures from an electric arc are developed from two sources; the expansion of the metal in boiling and vaporizing, and the heating of the air by passage of the arc through it. Copper, when vaporized, expands by a factor of approximately 67,000 times; therefore, one inch3 of copper converts to 1.44 yards3 of vapor instantly, which causes this rapid expansion and the resulting blast or explosion. The arc flash coupled with the arc blast presents a very serious and dangerous situation for anyone working on or near, or otherwise interacting with the electrical equipment. While there is PPE for protecting employees from the shock and arc flash hazards, there is no PPE for the arc blast hazard. The best practice for protection from the arc blast is to incorporate safe work practices that include correct body positioning when operating or otherwise interacting with the electrical equipment. A good practice is to never stand where the body would be in the direct “line-of-fire” should an arc flash/blast occur. Ralph Lee’s paper, entitled “Pressures Developed by Arcs” (IEEE 1987), discusses methods that can be used to determine the amount of damage that a short circuit can cause in switchgear and the buildings where the switchgear is located.

ELECTRICAL SAFETY DESIGN CONSIDERATIONS With the above information, concerning the hazards of electricity, the electrical equipment and systems engineers and designers are better equipped to design out the electrical hazards and design

18 in electrical safety. There has been an increased effort over the last few decades to design electrical equipment with greater emphasis on safety, not only for the equipment and installation, but also for the personnel who operate and maintain, or otherwise interact with the equipment. Another consideration would be to include the maintenance supervisor and plant or facility engineer, along with the facility safety professional, in the design of electrical systems and equipment. These individuals are generally not considered or included in the design, when they should have an open line of communication with design engineering and supervision. Frequently, an unsafe installation or one that requires excessive maintenance can be traced to improper design or construction methods or misapplication of hardware and equipment. Everyone who can be affected by the design and installation of electrical equipment and systems should be consulted early in the design, preferably starting with the conceptual design phase of the project. Although electrical systems are typically designed and installed according to the NEC, and other applicable standards, the real safety emphasis was placed on the design and installation of electrical equipment and systems when OSHA issued the Final Rule of 29 CFR 1910 Subpart S, Electrical Standards, 1910.302-.308, Design Safety Standards for Electric Utilization Systems, on January 16, 1981. This regulation was recently revised and updated on February 14, 2007. This provided a Federal mandate on design and installation issues that related to the safety of employees working on, near, or with the electrical systems and equipment. This emphasis increased for electrical equipment when OSHA published the Final Rule of 29 CFR 1910.147, The Control of Hazardous Energy (lockout/tagout) on September 1, 1989, which required that machines and equipment be manufactured with energy isolating devices (lockout/tagout). Effective energy isolation is a key to electrical safety because it provides a means to deenergize the equipment so that it can be worked on in an electrically safe working condition. This regulatory requirement is quoted below: OSHA 29 CFR 1910.147(c)(2)(iii) requires all electrical equipment be capable of being locked out. OSHA states: “After January 2, 1990, whenever replacement or major repair, renovation or modification of a machine or equipment is performed, and whenever new machines or equipment are installed, energy isolating devices for such machine or equipment shall be designed to accept a lockout device.” Additional emphasis, placed on electrical safety, that would have a dramatic influence on the design, manufacturing, and installation of electrical equipment and systems, was increased with the publication of OSHA 29 CFR 1910.331-.335, Electrical Safety-Related Work Practices on August 6, 1990; OSHA 29 CFR 1910.269, Electric Power Generation, Transmission, and Distribution on January 31, 1994 (OSHA Proposed Revision June 15, 2005); and the revisions of NFPA 70E, Standard for Electrical Safety in the Workplace over the past twenty years, that includes the 1995, 2000,

Safety Vol. 1 2004, 2009, and 2012, as well as recent revisions to the ANSI/ IEEE C2, National Electrical Safety Code, all of which are dedicated to electrical safety. NFPA 70E-2012, Informative Annex O, titled Safety-Related Design Requirements, provides some general design considerations for electrical systems that include: ● Owners, managers, and employers are responsible for performing an electrical hazard analysis during the design of electrical systems and installations in order to more effectively choose design options that would reduce or eliminate employee exposure to hazard risks and to enhance the effectiveness of electrical safety. ● Factors that have an impact on safety-related work practices to protect employees must be considered. ● The NFPA 70E, 130.3(B)(1), Electrical hazard Analysis results, should be used to compare design options and choices to facilitate decisions in the design of the electrical equipment and systems, and serve to: ○ Eliminate electrical hazards risk ○ Reduce frequency of exposure to electrical hazards ○ Reduce the magnitude and severity of hazard exposure ○ Enable the ability to achieve an electrically safe work condition as noted in the requirements of OSHA 29 CFR 1910.147, stated above. Also to enable the use of the electrical energy control requirements of NFPA 70E Article 120, Establishing an Electrically Safe Work Condition and OSHA 29 CFR 1910.333(b), Working on or near exposed deenergized parts for performing an electrical lockout/ tagout. ○ Enhance the effectiveness of the electrical safety-related work practices ● Arc energy reduction is another consideration through the use of: ○ Zone-selective interlocking ○ Differential relaying ○ Energy-reducing maintenance switching with local status indicator – This feature sets the circuit breaker trip unit to a faster operating time, which will reduce the incident energy if an arc flash were to occur while the worker is working within the arc flash boundary. ● High speed microprocessor based protective relaying ● High speed optic sensors Always keep in mind that no matter how fast the sensors or relaying are, the end device is still an electro-mechanical circuit breaker that can fail to open in the time specified. Mechanical devices, such as circuit breakers, must be maintained in accordance

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Safety Vol. 1 with the manufacturer’s specifications. Even this is not a 100% guarantee, but it is the best we can do to minimize the risk of an unintentional time delay or total failure of the device. There is more information on this in the section titled Electrical Equipment Maintenance. There is a new IEEE Std 1814 Recommended Practice for Electrical System Design Techniques to Improve Electrical Safety being developed that will address some of the common concerns related to safety by design. The following information is provided in order to provide a better understanding of this new standard; the Scope, Purpose, Need for the Project, and Stakeholders for the Standard is provided below: ● Scope: This recommended practice addresses system and equipment design techniques and equipment selection that will improve electrical safety. The techniques in this Practice are intended to supplement the minimum requirements of installation codes and equipment standards. It does not include communications, programming, or life safety systems such as fire alarm and security. ● Purpose: This Recommended Practice provides a “tool kit” of techniques to enable the system designer to specify equipment features, apply protective schemes, and make informed system installation design choices. ● Need for the Project: There is currently no publication by an accepted standards entity that effectively communicates “electrical safety by design” concepts and their benefits. Current standards place only minimum requirements on electrical system designers and manufacturers that yield functional, reasonably safe electrical installations. There is a need to capture, in one location, the wealth of “electrical safety by design” concepts that have been published in recent IEEE papers and in other industry sources. ● Stakeholders for the Standard: Owners, operators, installers and maintainers of industrial, commercial, power generation facilities, design consultants, and manufacturers. The standard will address the following topics: ○ System Design – General ○ System Design – Operations & Maintenance ○ System and Equipment Grounding and Bonding ○ Power System Protection ○ Electrical Equipment ○ Environment (under consideration) ○ Heat Tracing (under consideration) ○ Labeling & Signage ○ Lighting Electrical equipment and systems must be designed such that there are no exposed energized conductors or circuit parts when

they are under normal operating conditions. When energized parts are exposed for maintenance purposes, they must be suitably guarded to prevent contact by personnel who are in the vicinity of the equipment or system. A short-circuit current study must be performed in order to ensure that electrical equipment and systems have a sufficient interrupting rating for the available short-circuit current. This study should be evaluated at least every five years or after any system or equipment modifications to ensure that nothing has changed that would cause an increase in the available short-circuit current. High impedance devices such as current-limiting reactors can be installed in an electrical system to reduce the available short-circuit current. If these devices are installed, the coordination of the circuit protective devices must be verified and adjusted in order to prevent longer clearing times that may increase the available incident energy of an arc flash. Installing current-limiting devices requires a complete electrical equipment and system coordination study to ensure that all components work together to decrease electrical hazards, especially the arc flash hazard. Manufacturers have designed electrical equipment, particularly metal-clad switchgear, to be “arc safe” or “arc resistant” in order to protect workers or operators when interfacing with the equipment (opening or closing the device). This type of equipment is designed with enclosure doors and latching mechanisms that are much more substantial than older equipment and are intended to help ensure that the door remains closed during an arc flash event. These enclosures also have a pressure relief venting mechanism on the top of the equipment that will open and vent the arc flash pressures and vapors up and through a duct system to a location outside of the electrical equipment room. This is a significant improvement for designing in electrical safety in the equipment. This section of the paper has emphasized equipment and systems design used to minimize the electrical hazards to personnel. There is another major design issue that is all too often overlooked and that is the working space around electrical equipment. This working space includes the spaces required by OSHA 1910.303(g) and NEC Article 110, Part II for 600 volts or less and OSHA 1910.303(h) and NEC Article 110, Part III for over 600 volts. This work space must be designed into a facility in order to provide a safe working space for electrical workers who are required to maintain the equipment and operators who are required to operate (open or close) switches, circuit breakers, or otherwise interface with the equipment. This space must not be confused with the required electrical shock or arc flash boundaries, which must also be considered.

ELECTRICAL EQUIPMENT MAINTENANCE Maintenance, lubrication and testing are essential to ensure proper protection of equipment and personnel. NFPA 70E Section 205.1 requires all persons who maintain electrical equipment to be a qualified person and Section 205.3 requires electrical equipment

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to be maintained according to the manufacturer’s instructions or industry consensus standards such as NFPA 70B, Recommended Practice for Electrical Equipment Maintenance and the InterNational Electrical Testing Association (ANSI/NETA) Standard for Maintenance Testing Specifications for Electric Power Distribution Equipment and Systems (MTS). Section 205.4 of NFPA 70E also requires that the maintenance, tests, and inspections be documented. With regard to personnel protection, NFPA 70E requires that a shock hazard analysis and an arc flash hazard analysis be performed before anyone approaches exposed electrical conductors or circuit parts that have not been placed in an electrically safe work condition. In addition it requires shock protection boundaries and an arc flash boundary to be established. All arc flash hazard analysis calculations, for determining the incident energy of an arc, and for establishing an arc flash boundary, require the arc clearing time, available short-circuit current, and the distance from the potential arc to the worker. The clearing time is derived from the engineering protective device coordination study which is based on what the protective devices are supposed to do. If, for example, a low-voltage power circuit breaker had not been operated or maintained for several years and the lubrication had become sticky or hardened, the circuit breaker could take several additional cycles, seconds, minutes, or longer to clear a fault condition. The following is a specific example: Two Arc Flash Hazard Analyses will be performed using a 20,000-amp short-circuit with the worker 18 inches from the arc: ● Based on what the system is supposed to do: ○ 0.083 second (5 cycles) ● Due to a sticky mechanism the breaker now has an unintentional time delay: ○ 0.5 second (30 cycles) Example #1: EMB = maximum 20 in. cubic box incident energy, cal/cm2 DB = distance from arc electrodes, inches (for distances 18 in. and greater) tA = arc duration, seconds F = short circuit current, kA (for the range of 16 kA to 50 kA) (1) DA = 18 in. (2) tA = 0.083 second (5 cycles) (3) F = 20kA EMB = 1038.7DB-1.4738 tA [0.0093F2 - 0.3453F + 5.9675] = 1038 x 0.0141 x 0.083[0.0093 x 400 - 0.3453 x 20 + 5.9675] = 1.4636 x [2.7815] = 3.5 cal/cm2 NFPA 70E, 130.5(B)(1) requires arc-rated clothing and other PPE are to be selected based on this incident energy level exposure. Therefore, the arc-rated clothing and PPE must have an arc rating of at least 3.5 cal/cm2.

Example #2: EMB = maximum 20 in. cubic box incident energy, cal/cm2 DB = distance from arc electrodes, inches (for distances 18 in. and greater) tA = arc duration, seconds F = short circuit current, kA (for the range of 16 kA to 50 kA) (1) DA = 18 in. (2) tA = 0.5 second (30 cycles) (3) F = 20kA EMB = 1038.7DB-1.4738 tA [0.0093F2 - 0.3453F + 5.9675] = 1038 x 0.0141 x 0.5[0.0093 x 400 - 0.3453 x 20 + 5.9675] = 7.3179 x [2.7815] = 20.4 cal/cm2 NFPA 70E, 130.5(B)(1) requires arc-rated clothing and other PPE to be selected based on this incident energy level exposure. Therefore, the arc-rated clothing and PPE must have an arc rating of at least 20.4 cal/cm2. If the worker is protected based on what the system is supposed to do, in this case 0.083 second or 5 cycles, and an unintentional time delay occurs, and the time is increased to 0.5 second or 30 cycles, the worker could be seriously injured or killed because he/ she was under protected. As can be seen, maintenance is extremely important to an electrical safety program. Maintenance must be performed according to the manufacturer’s instructions in order to minimize the risk of having an unintentional time delay, or complete failure, of the operation of the circuit overcurrent protective device(s). Maintenance is more than just performing the required preventive or predictive maintenance that is recommended by the manufacture. Other maintenance practices related to electrical safety include, but are not limited to: ● Effectively closing unused openings in electrical equipment and devices, such as: ○ When conduit is removed from an enclosure, plug the hole with an approved plug ○ When a molded case circuit breaker is removed from a panelboard, the opening must be closed using a panel compatible snap in device ○ When a low-voltage power circuit breaker is removed from the enclosure, the opening in the door must be effectively closed ● All electrical panels (includes power and control panels), receptacles, light switches, junction boxes, conduit bodies, etc. must have the covers securely and properly installed (all screws or bolts installed and/or all latches securely fastened) ● All electrical panels must have danger signs installed and maintained, as identified below:

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Safety Vol. 1 ○ 600 volts or less OSHA and NFPA requires: “Entrances to rooms and other guarded locations containing exposed live parts shall be marked with conspicuous warning signs forbidding unqualified persons to enter.” This would require a sign that states: “Warning–Hazardous Voltage–Unqualified PersonNEL Keep Out” or similar.

immediately prior to placing the equipment back in service. When equipment is taken out of service for maintenance, performance of both an as-found and an as-left test is highly recommended. The as-found tests will show any deterioration or defects in the equipment since the last maintenance period and, in addition, will indicate whether corrective maintenance or special procedures should be taken during the maintenance process. The as-left tests will indicate the degree of improvement in the equipment during the maintenance process and will also serve as a benchmark for comparison with the as-found tests during the next maintenance cycle.

SUMMARY ○ Over 600 volts OSHA and NFPA requires: “The entrances shall be kept locked unless they are under the observation of a qualified person at all times; and permanent and conspicuous warning signs shall be provided, reading substantially as follows: “DANGER–HIGH VOLTAGE–KEEP OUT”

The work space around electrical equipment must be maintained clear as required by OSHA and NFPA: “Working space required by this subpart may not be used for storage. When normally enclosed live parts are exposed for inspection or servicing, the working space, if in a passageway or general open space, shall be suitably guarded.” Many of the electrical equipment maintenance tasks require the equipment to be placed in an electrically safe work condition for effective safety prior to working on it. There are other maintenance tasks that might specifically require or permit equipment to be energized and in service while the tasks are being performed. Examples include taking voltage or current readings, troubleshooting, taking an oil sample from a transformer or oil circuit breaker for analysis, observing and recording operating characteristics such as temperatures, load conditions, corona, noise, or performing thermographic surveys while the equipment is under normal load and operating conditions. Coordinating maintenance and inspection with planned or scheduled production outages can provide an added safety environment for employees and may also provide a means to avoid major disruptions of operations. When performing the required maintenance and testing of electrical equipment there are two sets of values or readings that must be recorded, namely the “as-found” and “as-left” values. The asfound tests are tests performed on equipment when initially installed and before being energized or after it has been taken out of service for maintenance but before any maintenance work is performed. The as-left tests are tests performed on equipment after preventive or corrective maintenance has been completed and

Each of the three hazards of electricity (electrical shock, electrical arc-flash and electrical arc-blast) has its own unique characteristics that require special attention to hazard assessments, electrical safety programs and procedures, personal protective equipment, and the design, installation, and maintenance of electrical equipment and systems. Personnel safety should be a primary consideration in electrical systems design and in establishing safety-related work practices when performing preventative maintenance for electrical systems and equipment. Maintenance must be performed only by qualified persons trained in safe maintenance practices and the special considerations necessary to maintain electrical equipment. Safe work practices must be instituted and followed to prevent injury or death to those who are performing tasks, as well as others who might be exposed to the hazards. Among the hazards associated with working on energized electrical conductors or circuit parts are hazards of electricity, any of which may result in severe injury or death to the employee(s). Preventive maintenance should be performed only when equipment is in an electrically safe work condition. Equipment should always be deenergized for all inspections, tests, repairs, and other servicing. Where maintenance tasks must be performed when the equipment is energized, provisions are to be made to allow maintenance to be performed safely as required by NFPA 70E, Standard for Electrical Safety in the Workplace. For the purposes of this paper, deenergized means the equipment has been placed in an electrically safe work condition in accordance with NFPA 70E, Article 120, OSHA 1910.147, and 1910.333(b) requirements. The best way to avoid exposure to electrical hazards is to keep as far away as possible from electrical equipment and systems that have exposed energized parts or where the electrical equipment is being operated or maintained.

REFERENCES Ralph H. Lee, “Electrical Safety in Industrial Plants,” IEEE Transactions on Industry and General Applications, Vol. IGA-7, p. 10-16, Jan. /Feb. 1971. Ralph H. Lee, “The Other Electrical Hazard; Electric Arc Blast

22 Burns”, IEEE Transactions on Industry Applications, Vol. IA18, No. 3, May/June 1982. Ralph H. Lee, “Pressures Developed by Arcs”, IEEE Transactions on Industry Applications, Vol. IA-23, No. 4, p. 760, July/ Aug. 1987. National Fire Protection Association, NFPA 70E, Standard for Electrical Safety in the Workplace, 2012 Edition. National Fire Protection Association, NFPA 70B, Recommended Practice for Electrical Equipment Maintenance, 2010 Edition. Occupational Safety and Health Administration (OSHA), Federal Register, 29 CFR 1910, Subpart S, “Electrical Standards”, Friday, February 14, 2007. Occupational Safety and Health Administration (OSHA), Federal Register, 29 CFR 1910.331-.335, Electrical Safety-Related Work Practices, August 6, 1990. Occupational Safety and Health Administration (OSHA), Federal Register, 29 CFR 1910.147, “Control of Hazardous Energy Source (Lockout/Tagout)”, September 1, 1989. Dennis K. Neitzel, CPE, Director Emeritus of AVO Training Institute, Inc., Dallas, Texas, has over 45 years experience in Electrical Utility, Industrial facility, and shipyard/shipboard electrical equipment and systems maintenance and testing experience, with an extensive background in electrical safety and power systems analysis. He is an active member of IEEE, ASSE, AFE, IAEI, and NFPA. He is a Certified Plant Engineer (CPE) and a Certified Electrical Inspector-General. Mr. Neitzel earned his Bachelor’s degree in Electrical Engineering Management and his Master’s degree in Electrical Engineering Applied Sciences. He is a Principle Committee Member and Special Expert for the NFPA 70E, Standard for Electrical Safety in the Workplace; member of the Defense Safety Oversight Council, Electrical Safety Working Group – DoD Electrical Safety Special Interest Initiative; Working Group Chairman of IEEE 3007.1-2010 Recommended Practice for the Operation and Management of Industrial and Commercial Power Systems, 3007.2-2010 Recommended Practice for the Maintenance of Industrial and Commercial Power Systems, & 3007.3-2012 Recommended Practice for Electrical Safety of Industrial and Commercial Power Systems; Working Group Chairman of IEEE P45.5 Recommended Practice for Electrical Installations on Shipboard - Safety Considerations; and co-author of the Electrical Safety Handbook, McGraw-Hill Publishers. Mr. Neitzel has also authored, published, and presented numerous technical papers and magazine articles on electrical safety, maintenance, and training. For more information, contact Mr. Neitzel by e-mail at [email protected].

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ELECTRICAL SAFETY MYTHS, LEGENDS AND MISCONCEPTIONS PowerTest 2013 James R. White, Shermco Industries, Inc.

INTRODUCTION It’s amazing how many field-trained electrical workers believe common electrical safety misconceptions and myths. These have to be smart people, or they wouldn’t last long in a trade like electrical testing and maintenance, but many still cling to their “tribal knowledge” and put themselves and those they work with at risk. This paper reviews some of the more common myths and misconceptions electrical workers may have concerning electricity and electrical safety. Readers are encouraged to use all or parts of the presentation as considered necessary to enlighten field workers and possibly prevent accidents that may be caused by them.

I ONLY NEED CHAPTER 1 IN NFPA 70E I agree that most of the electrical safety work practices are in Chapter 1, but the other chapters also contain information that is important to working safely. For example, NFPA 70E Chapter 2, “Safety-Related Maintenance Requirements” (2) contains a wealth of information required to keep an electrical power system safe to maintain. What these same people don’t seem to realize is that Chapter 1 is of no value without the Chapter 2 requirements being met. Electrical system equipment must be properly engineered, properly installed and properly maintained in order for the requirements in Chapter 1 to be met. Chapter 2 provides the bare minimum requirements. How can the incident energy of a system or circuit be estimated if the overcurrent protective device does not respond to a fault in accordance with the manufacturer’s specifications? It’s simply not possible. Throw away your fancy and expensive incident energy analysis, toss the tables and forget choosing PPE that will effectively protect workers from the arc flash hazard. Everything goes out the door! Chapter 2, Section 205 has many important requirements as: “205.2 Single-Line Diagram. A single-line diagram, where provided for the electrical system, shall be maintained in a legible condition and shall be kept current. 205.3 General Maintenance Requirements. Electrical equipment shall be maintained in accordance with manufacturers’ instructions or industry consensus standards to reduce the risk of failure and the subsequent exposure of employees to electrical hazards. 205.4 Overcurrent Protective Devices. Overcurrent protective devices shall be maintained in accordance with the manufacturers’ instructions or industry consensus standards. Maintenance, tests, and inspections shall be documented.”

Don’t forget to study the annexes. Even though they are not mandatory, they provide additional information on the reasoning behind some of the more difficult sections in NFPA 70E and much more detail.

ELECTRICAL EQUIPMENT IS UNSAFE TO WALK BY, MUCH LESS WORK ON One statement I often hear is, “You need arc flash PPE to just walk through a room with operating electrical equipment.” I think it’s amazing how many people think this way. I received several phone calls arguing that I don’t care about electrical safety because I don’t think it’s necessary to wear arc-rated PPE whenever a worker is near energized equipment. Is there a possibility that the equipment could fail? Yes, there is always that possibility. The risk, however, is very small and, even though it should not be ignored, it does not create the need for arc-rated PPE, unless you are interacting with the equipment in a manner that could cause failure. The definition of an arc flash hazard in Article 100 of NFPA 70E states, “Arc Flash Hazard. A dangerous condition associated with the possible release of energy caused by an electric arc. Informational Note No. 1: An arc flash hazard may exist when energized electrical conductors or circuit parts are exposed or when they are within equipment in a guarded or enclosed condition, provided a person is interacting with the equipment in such a manner that could cause an electric arc. Under normal operating conditions, enclosed energized equipment that has been properly installed and maintained is not likely to pose an arc flash hazard.” There are a couple of things that stand out in this definition: ● An arc flash hazard may exist even if the equipment is in a guarded condition. This would apply when the work is interacting with the equipment in a manner that could cause failure. Racking circuit breakers, inserting or removing MCC buckets are two tasks that would apply. ● Normally operating equipment (properly installed and maintained) does not present an increased risk of an arc flash. The 2015 edition of NFPA 70E will reinforce this informational note both in the text and the manner in which the new task tables (130.7(C)(15) are structured. Also, reference NFPA 70E Section 130.7, Informational Note No. 2, “It is the collective experience of the Technical Committee on Electrical Safety in the Workplace that normal operation of enclosed electrical equipment, operating at 600 volts or less, that has been properly installed and maintained by qualified persons is not likely to expose the employee to an electrical hazard.”

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I’M GRANDFATHERED “We are exempt from 70E because we were built before the standard was written” or “We follow the 2004 (or some earlier) edition of NFPA 70E”. Really? Are you exempt from reality? Do the physical laws of nature really flow around you without touching you? I’m sure that’s the case on Mt. Olympia, but for the rest of us stuck on terra firma, we have no such exemption. NFPA 70E is revised every three years to keep pace with new findings and improve its language so it is more usable and easily understood. Because it is a safe work practice, when a new edition is released, prior editions are no longer valid for use in the field. Reference NFPA 70E page 1, where NFPA states, “….It was issued by the Standards Council on August 11, 2011, with an effective date of August 31, 2011, and supersedes all previous editions.” Once the revised edition of NFPA 70E is issued, previous editions are no longer effective. The NEC contains the same language, but has a different meaning. With the NEC, since it is a code that is enforceable, it supersedes the previous edition, but is not retroactive. It is one of the differences between a code and a safe work practice.

I’M A (MASTER ELECTRICIAN, JOURNEYMAN, ENGINEER, CERTIFIED FINANCIAL PLANNER) There is a difference between being qualified to OSHA 29CFR1910.332 and .333 and being experienced. I’m not discounting the worth of those years of experience (or education), but they are not adequate to keep you safe in the electrical workplace. Field-trained workers and technicians, and even those with degrees, receive little or no training about electrical safety. Apprenticeship programs, up until three years ago, did not include electrical safety in their curriculum. The idea that 15, 20 or even 30 years of field experience makes a worker qualified is exposed as a falsehood by the statistics. In a paper presented at the 2004 IEEE/IAS Electrical Safety Workshop (1), it was revealed that the workers most often injured were laborers with less than two years of experience and maintenance personnel and supervisors with more than ten years of experience. Figure 1 is a slide from that presentation.

Fig. 1: Workers Involved in Most Accidents

OSHA defines a qualified person in 29CFR1910.399, which states, “One who has received training in and has demonstrated skills and knowledge in the construction and operation of electric equipment and installations and the hazards involved.” There are two parts to satisfy, technical skills and knowledge and safety skills and knowledge. Both must be demonstrated. Whereas the technical skills portion may be accomplished through apprenticeships, degrees and field experience the safety side must be accomplished through training and a demonstration of those skills. A degree, license, job position or permit in no way qualifies an electrical worker in OSHA’s eyes.

ONLY “ELECTRICIAN” NEED ELECTRICAL SAFETY TRAINING This is probably one of the most common misconceptions that supervisors and companies have. These companies don’t realize that HVAC, instrumentation and control technicians, as well as multi-craft workers and even laborers may require some amount of electrical safety training, if they are exposed to the hazard. OSHA does not look at a job title to determine whether they require electrical safety training; they look at whether they are exposed to electrical hazards. Both OSHA regulations and NFPA 70E state that anyone who is exposed to an electrical hazard will require training. The level of training will depend on their job tasks and risks to the hazards. Specifically, OSHA states, “The training requirements contained in this section apply to employees who face a risk of electric shock that is not reduced to a safe level by the electrical installation requirements of 1910.303 through 1910.308. Note: Employees in occupations listed in Table S-4 face such a risk and are required to be trained. Other employees who also may reasonably be expected to face comparable risk of injury due to electric shock or other electrical hazards must also be trained.”

IF I’M SHOCKED, THE HOSPITAL KNOWS HOW TO CARE FOR ME One would think so, but that may or may not be the case. This is one of those situations that really depends on who is there when you are admitted. Some hospitals may have one or more doctors specially trained for electrical shock victims, but smaller hospitals may not. Emergency rooms physicians see hundreds, if not thousands of cases each year from vehicle accidents, domestic disputes, gang activity and home accidents that result in broken bones, cuts, lacerations, contusions, concussions, gun shots, and other types of non-electrical injuries. Electrical shock victims are not nearly as common, so when one arrives in the ER, the attending physician may need some help. Dr. A.G. Soto has recommended a one-page (front and back) form (7) to both gather important information concerning the accident and victim (if possible) and to provide some basic information on electrical shock effects and how to manage them.

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Safety Vol. 1 HIRE CONTRACTORS FOR ALL HAZARDOUS ELECTRICAL WORK

○ Minimum arc rating of clothing

This is a true statement if you don’t have the in-house expertise to handle high-voltage or high-risk electrical tasks. However, contracting work out does not typically absolve your company of liability should an accident occur. OSHA’s Multi-Employer Worksite Policy CPL 2-0.124 Rev 15.00 ensures that in most cases the host employer (equipment or facility owner) will be held partially responsible.

○ Highest Hazard/Risk Category (HRC) for the equipment

This policy, in effect since 1999, allows OSHA to split responsibility for an accident in four roles: ● Controlling employer ● Exposing employer ● Correcting employer ● Creating employer OSHA will determine if your company should be assigned one of these roles, then determine if you fulfilled your responsibilities for that role. Citations follow soon after. NFPA 70E also contains requirements regarding both the Host and contracting employers in Section 110.1. Section 110.1(C) requires the pre-job planning meeting be documented.

LABEL MANIA Figure 3 is a typical arc flash hazard warning label required by the NEC Section 110.16 (4). The label in Figure 3 actually has more information than that required by 110.16, as the NEC requirement is to only warn against the arc flash hazard, and Figure 3 has shock warnings and PPE advisements, as well.

○ Required level of PPE ● Nominal system voltage ● Arc flash boundary” NFPA 70E requires this additional information because it is clear that electrical workers are not able to determine appropriate PPE requirements as mandated by 29CFR1910.335. This is most often due to the information not being readily available. For those who appreciate exceptions, there is an exception for this requirement in NFPA 70E, “Exception: Labels applied prior to September 30, 2011 are acceptable if they contain the available incident energy or required level of PPE. The method of calculating and data to support the information for the label shall be documented.”

OSHA DON’T WORRY ME OSHA generally does not pursue legal action against individuals. They follow the Golden Rule – He Who Has the Gold makes the Rules, which are the companies that employ workers. They control the paychecks and working conditions, and therefore bear workplace responsibility. However, if you are a supervisor or manager and are responsible for someone’s death, through a decision or policy you implemented, that can all change. The information below is from the OSHA website: “Referrals or Significant Aid to Prosecutors Addressing OSHA-Related Matters” Criminal Referrals

2007

2008

2009

2010

10

14

11

145

“These actions include referrals under Title 29 of the United States Code, Section 666(e), for employee deaths caused by willful conduct violating an OSHA standard, obstruction of justice, state and local investigations and prosecutions, and fraud related to other OSHA matters, such as training verification.” Fig. 3: Typical Arc Flash Hazard Warning Label The wording in NEC 110.16 is mirrored in NFPA 70E Section 130.5(C), Equipment Labeling where it states “Electrical equipment such as switchboards, panelboards, industrial control panels, meter socket enclosures, and motor control centers that are in other than dwelling units and are likely to require examination, adjustments, servicing or maintenance while energized shall be field marked with a label.” NFPA 70E adds the following requirements: “containing all the following information: ● At least one of the following: ○ Available incident energy and the corresponding working distance

Ten to 14 cases a year may not seem like a large number, especially compared to the thousands of cases OSHA prosecutes. That is, unless you happen to be one of those being charged. Note also that these criminal referrals also include obstruction of justice and fraud, such as altering training records. Oh, now I see why I should have been spending that money to train my people. Too late!

OSHA ENFORCES NFPA 70E This is another very common myth, one that refuses to die. I guess it’s because it would make sense, but in reality, OSHA cannot enforce anything but Federal regulations. That confines them to writing citations for violating 29CFR1910 (General Industry) or 29CFR1926 (Construction) regulations. In a letter of interpretation(5), OSHA states, “Industry consensus standards, such as NFPA 70E, can be used by employers as guides to making the assess-

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ments and equipment selections required by the standard. Similarly, in OSHA enforcement actions, they can be used as evidence of whether the employer acted reasonably.” Federal courts have found that NFPA 70E is “standard industry practice.” OSHA may not be able to enforce NFPA 70E, but they can certainly use it against you when they haul you into court.

IF YOU TOUCH THAT 20A CIRCUIT BREAKER, YOU’LL HAVE 20A FLOW THROUGH YOUR BODY That’s a real statement I overheard one day while on a construction site. I hope he was just trying to scare them into complying with safety rules, but maybe he didn’t know the facts. This situation is similar to a safety instructor I once heard tell students that “3mA of current directly across a person’s heart would kill them”. Statements such as these may achieve the desired effect initially, but once the person who hears such misinformation gets the truth, credibility is gone forever. OHM’s Law shows us that only a limited amount of current would actually flow through our bodies. That’s the good news. The bad? It really doesn’t take very much current to injure or kill us. The current from a 120-volt circuit is more than enough to do the job. The typical resistance of our body is about 1,000Ω(6) for the average man. Factors that will modify that value up or down are things such as bone mass, walking surface, shoe material, wet environment, etc., but is a fair number to begin with. At 120V and having 1,000Ω resistance in the circuit, current flow would be limited to a maximum of 120mA. At 75mA a person has a risk of going into ventricular fibrillation. As the current increases, that risk increases until even an instantaneous contact could cause fibrillation. I always tell students in our classes that low voltage does not mean low hazard. Studies consistently show that in the workplace, low-voltage is the number one killer.

LOW-VOLTAGE MEANS NO ARC FLASH HAZARDS For some reason, people downplay the hazards and risks associated with working around low-voltage equipment and systems. Maybe it’s because we aren’t immediately killed or injured by it on the first contact, so now it’s not a big deal. The same rationale seems to apply itself to the arc flash hazard. “If it was dangerous, I’d know it by now”. Good logic! An arc flash hazard can exist as low as 208V; it just requires a large short circuit source. At 480V there is more than enough voltage to push current through the arc(3). Figure 2 is from the TEST NUMBER 4 conducted as prior to the IEEE 1584 working group tests to help establish some criteria. In Test No. 4 the line-side of a 480V 30A circuit breaker was shorted to ground, simulating a phase-to-ground short circuit. There was 480V, 22,000A available short circuit current with an operating time of 6 cycles. The incident energy was estimated at 5.8 cal/cm2. The results were impressive!

Fig. 2: Test Number Four Results

ONE SIZE FITS ALL PROTECTION Do you want to save money, Bunkie? A number of otherwise intelligent people seem to have found a way to do that. Make everyone wear the same super-sized arc flash PPE for all electrical tasks. That will show them how much we love them! Let’s look at what OSHA says. 29CFR1910.335 states, “Employees working in areas where there are potential electrical hazards shall be provided with, and shall use, electrical protective equipment that is appropriate for the specific parts of the body to be protected and for the work to be performed.” Wearing too much protection can be as hazardous as too little, if it interferes with performing the task. Workers not being able to perform the task, or passing out due to heat stress is not making them safer. A super high-rated arc flash suit and PPE does nothing to protect the worker from the arc blast hazard. A person can be protected from the thermal hazard, but when incident energy exceeds 40 cal/ cm2, there’s a good chance the arc blast hazard will be a greater hazard than the thermal hazard. NFPA 70E Section 130.7(A) Informational Note No. 1 states, “The PPE requirements of 130.7 are intended to protect a person from arc flash and shock hazards. While some situations could result in burns to the skin, even with the protection selected, burn injury should be reduced and survivable. Due to the explosive effect of some arc events, physical trauma injuries could occur. The PPE requirements of 130.7 do not address protection against physical trauma other than exposure to the thermal effects of an arc flash.” At this time the arc blast hazard cannot be accurately estimated. This means that when working on or near energized electrical equipment that has a high short circuit available current extra caution is required.

THE GROUND WIRE DOESN’T DO ANYTHING If I had to vote for the most misunderstood electrical component, this would be it. The number of electricians who believe this is pretty amazing. Some (certainly not all) electricians have used the ground wire as another energized conductor, as neutral and,

Safety Vol. 1 in numerous instances they have just cut it off (it doesn’t do anything). This misguided action causes fires, injuries and fatalities. Proper grounding and bonding, as required by the National Electrical Code is critical to worker safety, but people continue to cut ground pins off or use cords that have broken ground pins, disconnect grounds or ignore grounding requirements, all to their harm.

SUMMARY Misinformation causes an unsafe work environment and exposes electrical workers and others to risk of injury and death. It can undo years of training and damage a person’s credibility to the point that nothing he or she says will improve it. Credibility is like trust; once it’s lost it is very hard to recover. Workers exposed to electrical hazards must have accurate information in order to make acceptable and safe decisions when working in the field. One of the most important aspects of NFPA 70E is that it requires an electrical system to be properly engineered, properly installed and properly maintained. If these three requirements are not met in accordance with NFPA 70E Chapter 2, none of Chapter 1 would apply. Chapter 2, and to a lesser degree Chapter 3, are critical to maintaining a safe work environment as mandated by OSHA 5(a)(1), General Duty Clause.

REFERENCES Kowalski-Trakofler, Ph.D. Kathleen, Non-Contact Electric Arc-Induced Injuries in the Mining Industry; a Multi-Disciplinary Approach, 2004 IEEE/IAS Electrical Safety Workshop NFPA 70E®, “Standard for Electrical Safety in the Workplace”, 2012 edition, Chapters 1 and 2 Lee, Ralph H., The Other Electrical Hazard, Electrical Arc Blast Burns, IEEE Transactions on Industry Applications, volume I-A-18, No. 3, May/June 1982 NFPA 70®, National Electrical Code, 2011 edition. Pg. 70-37 Letter of Interpretation, OSHA, General Duty Clause (5)(A)(1) Citations on Multi-Employer Worksites; NFPA 70E Electrical Safety Requirements and Personal Protective Equipment, 0725-2003 ANSI/IEEE, Guide for Safety in AC Substation Grounding, Std. 80-2000, pg. 16 Soto, A.G. MD., Electrical Injuries Management, 2004 IEEE/ IAS Electrical Safety Workshop James White is the Training Director for Shermco Industries, Inc. located in Irving, Texas. He is a Senior member of the IEEE, the recipient of the 2011 IEEE/PCIC Electrical Safety Excellence Award, the 2008 IEEE Electrical Safety Workshop Chairman, Alternate interNational Electrical Testing Association (NETA) representative on NFPA 70E®, Primary NETA representative on NEC Code Making Panel 13, Primary representative on NFPA

27 70B®, and is the Primary NETA representative to ASTM F18®. James is also a certified Level IV Senior Substation Technician with NETA, an inspector member of IAEI and serves on the NETA Safety and Training Committees. James is the author of Electrical Safety, A Practical Guide to OSHA and NFPA 70E and Significant Changes to NFPA 70E – 2012 Edition both published by American Technical Publishers.

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INDUSTRIAL ELECTRICAL SAFETY COMPLIANCE ASSESSMENTS (INSPECTIONS) PowerTest 2014 Dennis K. Neitzel, C.P.E., AVO Training Institute, Inc.

INTRODUCTION The Occupational Safety and Health Administration (OSHA) concluded that effective management of worker safety and health protection is a decisive factor in reducing the extent and the severity of work-related injuries and illnesses. Effective management addresses all work-related hazards, including those potential hazards which could result from a change in worksite conditions or practices. It addresses hazards whether or not they are regulated by government standards. OSHA has reached this conclusion in the course of their evaluation of worksites in their Enforcement Programs, their State-Operated Consultation Programs, and their Voluntary Protection Programs (VPP). These evaluations have revealed a basic relationship between effective management of worker safety and health protection, and a low incidence and severity of employee injuries. Such management also correlates with the elimination or adequate control of employee exposure to toxic substances and other unhealthful conditions. OSHA’s experience in the VPP has also indicated that effective management of safety and health protection improves employee morale and productivity, as well as significantly reducing workers’ compensation costs and other less obvious costs of work-related injuries and illnesses.

ELECTRICAL INSPECTION PROGRAM There is an effective tool that management can use in their efforts to establish and maintain their electrical safety program and that is by incorporating an electrical safety inspection program. The OSH Act of 1970 requires the employer to provide a safe and healthful workplace for every working man and woman. Section 5(a)(1) of the OSH Act, referred to as the “General Duty Clause”, requires each employer to furnish to each of his employees employment and a place of employment which are free from recognized hazards that are causing or are likely to cause death or serious physical harm to his employees and requires the employer to comply with occupational safety and health standards promulgated under the OSH Act. To assist in accomplishing this, the employer can implement a self-assessment or inspection program to ensure that the electrical systems and equipment are properly designed, installed, operated, and maintained in a safe and reliable condition. To be effective the electrical safety inspections should be conducted to verify full compliance with OSHA 29 CFR 1910 electrical related regulations, which include the following:

● 29 CFR 1910, Subpart I, Personal Protective Equipment ○ 1910.132, General Requirements ○ 1910.137, Electrical Protective Equipment ● 29 CFR 1910, Subpart J, General Environmental Controls ○ 1910.146, Permit-Required Confined Spaces (as applicable) ○ 1910.147, The Control of Hazardous Energy (lockout/ tagout) ● 29 CFR 1910, Subpart R, Special Industries (as applicable) ○ 1910.269, Electric Power Generation, Transmission, and Distribution ● 29 CFR 1910, Subpart S, Electrical Standards: ○ 1910.302-.308, Design Safety Standards for Electrical Systems ○ 1910.331-.335, Electrical Safety-Related Work Practices ○ 1910.399, Definitions There are also several industry consensus standards that should be considered as well, such as: ● NFPA 70, National Electrical Code ● NFPA 70E, Standard for Electrical Safety in the Workplace ● NFPA 70B, Recommended Practice for Electrical Equipment Maintenance ● ANSI/IEEE C2, National Electrical Safety Code (NESC) (as applicable) Compliance with these regulations and standards will help to ensure that employers are installing and maintaining electrical systems and equipment in proper and safe working condition, as well as verifying each employee’s utilization of safe work practices and appropriate personal protective equipment for shock and arc flash. Inspections also assist supervisors and managers in meeting electrical safety goals set by the company for regulatory compliance. NFPA 70E, Section 110.3(H) Electrical Safety Auditing, provides additional direction on auditing the electrical safety program and field work on a frequency not to exceed three (3) years and must be documented. This audit is required to contain at least the following four components: ● Employee implementation of the electrical safety program ○ Understanding the program ○ Identify how much supervision emphasizes the program

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Safety Vol. 1 ○ Describe the condition of the program ● Does the electrical safety program address all hazards ○ Determines if employees are exposed to other risks not addressed in the program ● The audit must address the process for revising procedures as needed ○ Where incidents or injuries occur, a review of procedures must take place ○ Procedure revisions or a new procedure may be needed ● Define how procedure revisions are communicated to employees The inspection and audit programs should be carried out by an electrically knowledgeable, qualified person in order to identify deficiencies in electrical equipment or systems, and to correct or properly document any deficiencies found. One way to ensure that the inspection program is on target is to have electrically qualified company safety personnel conduct the inspections, or another option is to contract a third party electrical safety inspector. Using a person from outside the company or facility will often lead to discovery of issues and deficiencies that may be overlooked by self-inspecting. The written electrical safety inspection program should be reviewed on a periodic basis, by electrically qualified persons, to ensure that the check-lists are current and are being utilized. Inspections should include a review of the entire electrical safe work program for energized and deenergized work, which includes the energy control or lockout/tagout program. Written work practices (programs and procedures), personal protective equipment (PPE), and installed electrical equipment and systems physical condition and maintenance should be inspected for compliance with regulations and industry consensus standards. Inspections should also include “work in progress” to ensure that each worker understands and is implementing electrical safe work practices and procedures, and utilizing the proper PPE and insulated tools. This reflects directly on the qualified person training programs. A root cause analysis of the deficiencies identified should be a part of the inspection program. Changes or corrections in processes, practices, and procedures should be analyzed to help prevent a reoccurrence. Any items identified in the inspection or lessons learned should be communicated to others in the organization that may benefit from the information.

MANAGEMENT ROLE Management ultimately bears the burden of effectively administering the electrical safety inspection programs. Their involvement in the development and implementation of these programs is vital to their success. There are several areas that must be considered when developing the inspection program; they include, but are not

limited to: hazard assessments, inspections and audits, electrical safety training for all personnel (qualified and unqualified or electrical and non-electrical personnel), and evaluation of the existing safety management system. To assist employers and employees in developing effective safety and health management systems, OSHA published recommended Safety and Health Program Management Guidelines (Federal Register 54(16): 3904-3916, January 26, 1989). These voluntary guidelines can be applied to all places of employment covered by OSHA. The guidelines identify four general elements that are critical to the development of a successful safety and health management system. ● Management leadership and employee involvement ● Worksite analysis ● Hazard prevention and control ● Safety training

INSPECTION GUIDELINES Employers should perform a self-assessment or inspection to determine the adequacy of their written electrical safety program and procedures and to ensure that they are being implemented. The inspection should also include an inspection of the facility electrical systems and equipment to ensure compliance with the installation and maintenance regulations and standards. There are numerous subjects and items that should be addressed in an electrical safety inspection. The list below identifies several typical deficiencies that are commonly found during electrical safety and compliance inspections of industrial and commercial facilities: ● Operations and electrical safety one-line diagrams, drawings, and identification tags ○ Must be up-to-date per the requirements of NFPA 70E, Section 120.1(1), ○ Must be maintained up-to-date per NFPA 70E, Section 205.2, Single-Line Diagram ● Electrical Hazard Analysis performed ○ OSHA 1910.132(d)(1) requires an overall hazard assessment to determine if hazards are present or are likely to be present ○ NFPA 70E, Section 130.3 requires an electrical hazard analysis be performed ○ NFPA 70E, Section 130.4 provides the requirements for the Shock Hazard Analysis ○ NFPA 70E, Section 130.5 provides the requirements for the Arc Flash Hazard Analysis and arc flash hazard warning label requirements

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● Trained and qualified operators and maintenance technicians ○ OSHA 1910.399 Definitions – Qualified Person

● Grounding and bonding of electrical equipment and systems

○ OSHA 1910.332, Training

○ Per NEC Article 250, Grounding and Bonding

○ OSHA 1910.269(a)(2), Training

○ Per NESC Section 9, Grounding Methods for Electric Supply and Communications Facilities

○ OSHA 1910.132(f), Training (PPE) ○ NFPA 70E, Section 110.2, Training Requirements ● De-energized work procedures ○ Lockout/tagout policy and procedures per OSHA 29 CFR 1910.147, The Control of Hazardous Energy (Lockout/ Tagout) ○ Additional requirements for electrical lockout/tagout per OSHA 29 CFR 1910.333(b), Working on or near exposed deenergized parts ○ The requirements of NFPA 70E, Article 120 for Establishing an Electrically Safe Work Condition ● Electrical safety program ○ NFPA 70E, Section 110.3, Electrical Safety Program ○ OSHA 29 CFR 1910.333(a)(2), Energized Parts ○ Additional resource – The NFPA Electrical Safety Program Book ● Energized safe work procedures ○ OSHA 29 CFR 1910.333(a)(2), Energized Parts ○ OSHA Instruction STD 1-16.7, Directorate of Compliance Programs, paragraph I(2)(d)(2)… ”suitable safe work practices for the conditions under which the work is to be performed shall be included in the written procedures and strictly enforced. These work practices are given in 1910.333(c) and 1910.335.” ● Energized Electrical Work Permit ○ NFPA 70E, Section 130.2(B), Energized Electrical Work Permit ● Shock and Arc Flash Personal Protective Equipment (PPE)

○ IEEE Standard 80, IEEE Guide for Safety in AC Substation Grounding ○ IEEE Standard 142, IEEE Recommended Practice for Grounding of Industrial and Commercial Power Systems ● Corrosion of electrical equipment ○ NEC 110.11, Deteriorating Agents ● Maintenance practices (maintenance frequency, methods, and testing) ○ Manufacturer’s Instructions ○ NFPA 70E, Chapter 2, Safety-Related Maintenance Requirements ○ NFPA 70B, Recommended Practice for Electrical Equipment Maintenance ○ ANSI/NETA MTS, Standard for Maintenance Testing Specifications for Electrical Power Distribution Equipment and Systems ● Exposed live (energized) parts – covers left off or doors left open ○ OSHA 1910.303(g)(2), Guarding of live parts ○ NEC 110.27(A), Live Parts Guarded Against Accidental Contact ● Unused openings not effectively closed ○ OSHA 1910.303(b)(7), Mechanical execution of work ○ NEC 110.12(A), Unused Openings ● Working space around electrical equipment, 600-volts or less ○ OSHA 1910.303(g)(1), Space about electric equipment ○ OSHA 1910.303(g)(1)(ii) – “may not be used for storage”

○ OSHA 1910.132(d) requires a hazard assessment to determine what PPE is required

○ NEC 110.26, Spaces About Electrical Equipment

○ OSHA 335, Safeguards for Personnel Protection provides the minimum requirements to provide PPE for electrical hazards and the required use of insulated hand tools

○ ANSI/IEEE C2, NESC, Section 125.A., Working space about electric equipment

○ NFPA 70E, Section 130.4 determines what shock protection PPE is required ○ NFPA 70E, Section 130.5 provides information for selecting arc flash clothing and PPE ○ NFPA 70E, Section 130.7 provides specific PPE requirements for all parts of the body for shock and arc flash

○ NEC 110.26(B), Clear Spaces

● Working space around electrical equipment, over 600-volts ○ OSHA 1910.303(h)(3), Work space about equipment ○ NEC 110.34(A), Working Space ○ ANSI/IEEE C2, NESC, Section 125.B., Working space about electric equipment ● Identification of disconnecting means

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Safety Vol. 1 ○ OSHA 1910.303(f), Disconnecting means and circuits ○ NEC 110.22, Identification of Disconnecting Means ● Improper or unapproved extension cords ○ OSHA 1910.303(a), Approval – See definition of Approved in OSHA 1910.399 – See OSHA Letter Acceptable Job-Made extension cords, June 17, 1992 ○ OSHA 1910.303(b)(1)(i), “suitability for installation and use” ○ OSHA 1910.305(g), Flexible cords and cables ○ OSHA 1910.305(g)(1), Use of flexible cords and cables ○ NEC 110.2, Approval – See definition of Approved in NEC Article 100

† Do you specify compliance with OSHA for all contract electrical work? † Are all employees required to report as soon as practicable any obvious hazard to life or property observed in connection with electrical equipment or lines? † Are employees instructed to make preliminary inspections and/or appropriate tests to determine what conditions exist before starting work on electrical equipment or lines? † When electrical equipment or lines are to be serviced, maintained or adjusted, are necessary switches opened, locked-out and tagged whenever possible? † Are portable electrical tools and equipment grounded or of the double insulated type?

○ NEC 110.3(A)(1), “suitability for installation and use”

† Are electrical appliances such as vacuum cleaners, polishers, and vending machines grounded?

○ NEC 400.8, Uses Not Permitted

† Do extension cords being used have a grounding conductor?

○ NEC 400.9, Splices

† Are multiple plug adaptors prohibited?

○ NEC 400.10, Pull at Joints and Terminals

† Are ground-fault circuit-interrupters (GFCI) installed on each temporary 15 or 20 ampere, 120 volt AC circuit at locations where construction, demolition, modifications, alterations or excavations are being performed?

● Damaged extension cords ○ OSHA 1910.305(a)(2)(x), “Flexible cords and cables shall be protected” ○ OSHA 1910.305(g)(1), Use of flexible cords and cables ○ OSHA 1910.334(a), Portable electric equipment ○ NEC 400.8, Uses Not Permitted ○ NFPA 70E, 205.13, Single and Multiple Conductors and Cables ○ NFPA 70E, 205.14, Flexible Cords and Cables ○ NFPA 70E, 110.4(B), Portable Electric Equipment ● Damaged cord- and plug-connected equipment ○ All references for “damaged extension cords” also applies ○ NFPA 70E, 245.1, Maintenance Requirements for Portable Electric Tools and Equipment ● Availability and condition of electrical PPE ○ OSHA 1910.132, PPE General Requirements ○ OSHA 1910.137, Electrical Protective Equipment ○ OSHA 1910.335, Safeguards for Personnel Protection ○ NFPA 70E, 130.7, Personal and Other Protective Equipment

† Are all temporary circuits protected by suitable disconnecting switches or plug connectors at the junction with permanent wiring? † Do you have electrical installations in hazardous dust or vapor areas? If so, do they meet the National Electrical Code (NEC) for hazardous locations? † Is exposed wiring and cords with frayed or deteriorated insulation repaired or replaced promptly? † Are flexible cords and cables free of splices or taps? † Are clamps or other securing means provided on flexible cords or cables at plugs, receptacles, tools, equipment, etc., and is the cord jacket securely held in place? Are all cord, cable and raceway connections intact and secure? † In wet or damp locations, are electrical tools and equipment appropriate for the use or location or otherwise protected? † Is the location of electrical power lines and cables (overhead, underground, under floor, other side of walls) determined before digging, drilling or similar work is begun?

OSHA ELECTRICAL SELF-INSPECTION CHECKLIST

† Are metal measuring tapes, ropes, handlines or similar devices with metallic thread woven into the fabric prohibited where they could come in contact with energized parts of equipment or circuit conductors?

The following is an OSHA Electrical Self-Inspection Checklist for additional guidelines on what OSHA will likely look for when conducting an electrical safety inspection.

† Is the use of metal ladders prohibited in areas where the ladder or the person using the ladder could come in contact with energized parts of equipment, fixtures or circuit conductors?

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† Are all disconnecting switches and circuit breakers labelled to indicate their use or equipment served?

ufacturer’s instructions, will provide a means to reduce accidents, injuries, and fatalities in all segments of industry.

† Are disconnecting means always opened before fuses are replaced?

It is always important to ensure that employees are properly trained and qualified for a job. Not understanding the circumstances about the job or task can lead to accidents and injuries. Even properly qualified electrical workers are susceptible to accidents. That is why it is important to make safety an integral part of the planning process for every job.

† Do all interior wiring systems include provisions for grounding metal parts of electrical raceways, equipment and enclosures? † Are all electrical raceways and enclosures securely fastened in place? † Are all energized parts of electrical circuits and equipment guarded against accidental contact by approved cabinets or enclosures? † Is sufficient access and working space provided and maintained about all electrical equipment to permit ready and safe operations and maintenance? † Are all unused openings (including conduit knockouts) in electrical enclosures and fittings closed with appropriate covers, plugs or plates? † Are electrical enclosures such as switches, receptacles, and junction boxes, provided with tight fitting covers or plates? † Are disconnecting switches for electrical motors in excess of two horsepower, capable of opening the circuit when the motor is in a stalled condition, without exploding? (Switches must be horsepower rated equal to or in excess of the motor hp rating.) Is low voltage protection provided in the control device of motors driving machines or equipment which could cause probable injury from inadvertent starting? † Is each motor disconnecting switch or circuit breaker located within sight of the motor control device? † Is each motor located within sight of its controller or the controller disconnecting means capable of being locked in the open position or is a separate disconnecting means installed in the circuit within sight of the motor? † Is the controller for each motor in excess of two horsepower, rated in horsepower equal to or in excess of the rating of the motor it serves?

Important safety tips to help avoid injuries include, but are not limited to: ● Identify the electric shock and arc flash hazards, as well as other hazards that may be present. ● Use the right tools for the job. ● Isolate equipment from energy sources. ● Test every circuit and every conductor every time before you touch it. ● Work on electrical equipment and conductors only when de-energized. ● Turn off, try, test, lockout/tagout, and ground before working on equipment. ● Treat de-energized electrical equipment and conductors as energized until properly lockout/tagout, tested, and ground procedures are implemented. ● Wear protective clothing and equipment and use insulated tools for electrical hazards. Adherence to these basic inspection and safety tips can help avoid serious, or even life-threatening, injuries while working with electrical equipment and systems.

REFERENCES National Fire Protection Association, NFPA 70, National Electrical Code, 2011 Edition National Fire Protection Association, NFPA 70E, Standard for Electrical Safety in the Workplace, 2012 Edition

† Are employees who regularly work on or around energized electrical equipment or lines instructed in the cardiopulmonary resuscitation (CPR) methods?

National Fire Protection Association, NFPA 70B, Recommended Practice for Electrical Equipment Maintenance, 2010 Edition

† Are employees prohibited from working alone on energized lines or equipment over 600 volts?

Occupational Safety and Health Administration (OSHA), Federal Register, 29 CFR 1910, Subpart S, “Electrical Standards”, Friday, February 14, 2007

SUMMARY Electrical safety inspections are necessary in order to verify compliance with regulations and standards, as well as to help ensure that electrical installations and equipment are safe. Compliance with the OSHA regulations and NFPA standards, along with other industry consensus standards and electrical equipment man-

ANSI/IEEE C2, National Electrical Safety Code, 2012 Edition

Occupational Safety and Health Administration (OSHA), Federal Register, 29 CFR 1910.331-.335, Electrical Safety-Related Work Practices, August 6, 1990 Occupational Safety and Health Administration (OSHA), Federal Register, 29 CFR 1910.147, “Control of Hazardous Energy Source (Lockout/Tagout)”, September 1, 1989

Safety Vol. 1 Occupational Safety and Health Administration (OSHA), Federal Register, 29 CFR 1910.269, “Electric Power Generation, Transmission, and Distribution”, January 31, 1994 Occupational Safety and Health Administration (OSHA), Subpart I, Personal Protective Equipment, 1910.132, General Requirements, (1st publication) 39 FR 23502, June 27, 1974, (most recent - 76 FR 33606, June 8, 2011 Dennis K. Neitzel, CPE, Director Emeritus of AVO Training Institute, Inc., Dallas, Texas, has over 45 years experience in Electrical Utility, Industrial facility, and shipyard/shipboard electrical equipment and systems maintenance and testing experience, with an extensive background in electrical safety and power systems analysis. He is an active member of IEEE, ASSE, AFE, IAEI, and NFPA. He is a Certified Plant Engineer (CPE) and a Certified Electrical Inspector-General. Mr. Neitzel earned his Bachelor’s degree in Electrical Engineering Management and his Master’s degree in Electrical Engineering Applied Sciences. He is a Principle Committee Member and Special Expert for the NFPA 70E, Standard for Electrical Safety in the Workplace; member of the Defense Safety Oversight Council, Electrical Safety Working Group – DoD Electrical Safety Special Interest Initiative; Working Group Chairman of IEEE 3007.1-2010 Recommended Practice for the Operation and Management of Industrial and Commercial Power Systems, 3007.2-2010 Recommended Practice for the Maintenance of Industrial and Commercial Power Systems, & 3007.3-2012 Recommended Practice for Electrical Safety of Industrial and Commercial Power Systems; Working Group Chairman of IEEE P45.5 Recommended Practice for Electrical Installations on Shipboard - Safety Considerations; and co-author of the Electrical Safety Handbook, McGraw-Hill Publishers. Mr. Neitzel has also authored, published, and presented numerous technical papers and magazine articles on electrical safety, maintenance, and training. For more information, contact Mr. Neitzel by e-mail at [email protected].

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DEVELOPING AN “ELECTRICAL” MULTI-EMPLOYER WORKSITE PROTECTION PROGRAM PowerTest 2014 Don Brown, Sr. Program Developer, Shermco Industries Before we start talking about the development of an “electrical” multi-employer worksite policy, we have to determine whether or not you are responsible for the safety of employees other than your own. In order to do this, you must ask yourself a couple of simple questions. ● Are you the ONLY employer on your property? ● Are you responsible for any contract employees on your property? In most cases, you are not the only employer on the jobsite, and you could be working as a subcontractor for another company. In either case, you are always responsible for the safety of your own employees. How could you be held responsible for the safety of employees that are not your own? In order to determine this, we must look at the definition of a multi-employer worksite. According to the Advisory Committee on Construction Safety and Health (ACCSH): Multi-employer Worksites: A worksite at which two or more entities are performing tasks that will contribute to the completion of a common project. The entities may or may not be related contractually. The contractual relationship may or may not be in writing. On multi-employer worksites, both in construction and industry, more than one employer may be citable for the same condition. In a Letter of Interpretation dated July 20, 2012, OSHA does not use the definition suggested by ACCSH, as that committee advises OSHA on only construction related issues. However, in a more broad sense, a multi-employer worksite is one that has more than one employer performing work toward a common goal, whether that is a daily function of operations, or on a construction site. Now that we have determined that you are on a multi-employer worksite, let’s see what type of employer you are. There are four classifications of employers in this scenario – the creating employer, the exposing employer, the correcting employer, and the controlling employer. Let’s define each one before getting into developing the electrical portion of the program. ● The Creating Employer – The employer that causes a hazardous condition that violates an OSHA standard. ● The Exposing Employer – An employer whose own employees are exposed to the hazard. ● The Correcting Employer – An employer who is engaged in a common undertaking, on the same worksite, as the exposing employer and is responsible for correcting a hazard. This usually

occurs where an employer is given the responsibility of installing and/or maintaining particular safety/health equipment or devices. ● The Controlling Employer – An employer who has general supervisory authority over the worksite, including the power to correct safety and health violations itself or require others to correct them. Control can be established by contract or, in the absence of explicit contractual provisions, by the exercise of control in practice. Now that we have the definitions clarified, let’s look into the liability, or the potential for citations to be issued in each case. In order to have an employer issued a citation by OSHA for a hazardous condition, there must be a two-step process to determine whether only one employer will be cited, or if more than one employer will receive the citation. Keep in mind that a single employer may fall into multiple categories with regard to the same scenario. ● Step One – The first step is to determine whether the employer is a creating, exposing, correcting, or controlling employer. Since we have already defined each of these, you can determine relatively easily which category the employer falls under. ● Step Two – Step two is to determine if the employer’s actions were sufficient to meet the obligations under the OSHA requirements. The extent and type of action required by an employer will vary depending on the category that applies. In many cases, you will fall under more than one category of employer. That is, a creating, correcting, or controlling employer will most likely also be an exposing employer. Also, if you are an exposing, creating or controlling employer, you may also be a correcting employer if you have the contractual authorization to correct the hazard. Let’s look at a couple of generic scenarios to see what would happen in a given situation.

Scenario #1a You are installing a new 480 VAC distribution panel at a facility for some new equipment. The panel has been properly mounted in accordance with NEC and local codes, power supply wiring has been pulled and has been terminated in the new panel, but has not been terminated at the supply, or feeder, source. No covers are in place, no barricades are set up, and no hazard boundaries have been established to prevent the exposure to other employees in the area. Let’s look at the site of the new panel first. Is there a hazard present, and if so, what is that hazard?

Safety Vol. 1 Since the power has not been connected as yet, there is no exposed energized source of electrical energy, and there is no electrical hazard. In this part of the scenario, there is no liability or citation to be issued.

Scenario #1b However, let’s continue the same scenario. Wiring has been pulled, no covers in place, no barricades and no boundaries have been established. Now we are connecting the source of electrical energy to the feeder breaker. Proper LOTO procedures have been followed as far as the source of energy, all of the proper PPE and electrical safe work practices have been established, and boundaries have been established at the source side of the feeder. All proper work practices have been addressed here, but there are still exposed electrical parts at the new panel. The source wiring is now terminated and the breaker has been closed, feeding power to the new panel. What, if any, is the type and extent of the exposure? What classification type of employer do you fall into at this point? Creating, exposing, correcting, or controlling? Identify the hazard first. There is the hazard of exposed, energized parts at 480 VAC, so there is a shock hazard, as well as an arc flash hazard. As you are the employer that energized the conductors without proper barricading, leaving the panel covers off and the internal parts exposed, you fall into two different categories – creating and correcting. What about exposing? At this point you are not an exposing employer as none of your employees are at the new panel location. However, there are potentially other employees at that location. Once your employees arrive at the new panel, you are now an exposing employer. Can you be considered the controlling employer at this point? By definition, if you are the primary, or general, contractor, you could be considered the controlling employer. If you are a subcontractor, no you cannot be considered the controlling employer. So at what level does the citation come in? In this situation, if you are not the controlling employer, you would be cited as the creating employer. You created the exposure, or hazard, therefore you would receive the citation as such.

Scenario #2 You have contracted to perform work at XYZ refinery during one of their periodic shut-down/turnaround overhauls. During this turnaround, it is the responsibility of your company to test substation transformers, switchgear, breakers, and relaying equipment. You have performed this type of testing many times before, and several times with this particular company. While testing one of the substation transformers, one of your testing technicians sets up all of the appropriate barricades, signage, and completes all of the required pre-testing paperwork, such as the JHA, LOTO, etc. The technician connects the test leads to the transformer properly and energizes the test set. When he began the test, he was sitting on one of the bushings, and when he pushed the test buttons to begin the test, he received an electrical shock to the buttocks.

35 What, if any, is the type and extent of the exposure? What classification type of employer do you fall into at this point? Creating, exposing, correcting, or controlling? What classification does XYZ refinery fall into at this point? What type of citation, if any, will XYZ Refinery receive after this incident? Why? Your company would fall into the creating and exposing categories, and could likely receive a citation as the creating employer. XYZ refinery is the controlling employer. However, they exercised reasonable care and determined that your company had the technical expertise, safety knowledge and had implemented safe work practices. They were relying on you, the industry expert, to exercise all of the proper precautions for the testing and provide trained, qualified persons to conduct the tests. They were therefore not citable for the violation of improper work practices. These are just two potential scenarios that arise on a fairly frequent basis. There are many other possibilities that could arise during this type of work environment. However, one thing to be concerned with is your level of responsibility during a visit from an OSHA compliance officer following an accident, or worse, a fatality on your worksite. One thing we have all heard about time and time again is the necessity for documentation. This is not only true for your employees, but for any contractors that work for you, whether they are job-specific or imbedded within your company. Job-specific contractors are those that come onto the site for a particular job, finish the work, then leave. They are on site for a relatively short amount of time. That could be anywhere from one day to several weeks, depending on the scope of work. Imbedded contractors are those whose normal place of work is your facility. These types of contractors could be those such as facility security, facilities maintenance, or any of a number of other contractors. How can you be held responsible for those employees? Aren’t they being paid by someone else? Isn’t their company responsible for their safety? Let’s take a look at just how you can be held accountable for someone else’s employee. One of the first things you should do when setting out to find a contractor to perform work at your facility, whether it is temporary or long-term, is to make sure that their safety program at least meets your safety program requirements. You do this by having them provide you with a copy of it! If your review of their safety program meets your company’s safety program, it is time to move to the training program to make sure that the employees have had all of the required safety and equipment training that is necessary for your facility. Make sure the training is all documented and it meets the most recent standards and regulations. For example, if someone has a copy of a certificate in their training record that proves they attended NFPA 70E training, but it is from the 2004 edition, the training is out of date, since the standard has gone through two additional revisions since that time. NFPA 70E-2012 Article 110.2(D)(3) states that “Retraining shall be performed at intervals not to exceed 3 years.” Likewise, if someone says they

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have attended the NFPA 70E – 2012 training, but there is no clear documentation in their training record, then they did not attend the class. If they can’t prove that they attended the class, then they did not attend the class. Additionally, if someone is supposed to perform testing on a particular piece of electrical equipment, they need to have been trained in the use of the test equipment, and that training has to be documented in their training record per NFPA 70E-2012 Article 110.2(E) Otherwise, there is no way to prove that they are performing the testing properly and will be able to interpret the testing and diagnostics properly. This could lead to a failure of the equipment and potentially an injury, or worse, to an employee. Once the training documentation has been verified, one of the next steps is to inform each of the contractors of the hazards that they may be facing. Whether this is created by them during the work, or by other contractors performing work in the vicinity, these hazards, or potential hazards, must be communicated. NFPA 70E-2012 Article 110.1 discusses the relationships with contractors and the responsibilities of both the host employer and the contract employer with regard to electrical related work practices. One of the easiest ways to communicate the hazards on the worksite is by holding daily safety meetings among the safety personnel. Each company safety representative comes to the meeting before work starts each day with a scope and location of work that their company will be performing. That way, everyone is aware of the potential hazards in a given area and that information can be relayed to their respective companies. This is then used during each work team’s JHA before work begins. Communicating all of the training and hazards on a jobsite is a primary concern not only for facility owners, but for on-site contractors as well. Failure to communicate, or ignoring the hazards can not only cause injuries to workers and damage to equipment; it can also result in criminal and civil actions. Post fatality inspections conducted by OSHA during the period of 2007 through 2010 have resulted in 49 criminal referrals or significant aid to prosecutors. These are broken down as follows: ○ 2007 – 10 referrals ○ 2008 – 14 referrals ○ 2009 – 11 referrals ○ 2010 – 14 referrals In an article in The National Law Review, December 12, 2013 (Criminal Charges Follow Fatal Workplace Accidents), stiff OSHA fines are not the only thing facing employers following fatal workplace accidents. The owner of one company is going to prison, while another owner faces multiple murder charges! In one case, the president and owner of a business in New Hampshire was sentenced to 10 to 20 years in prison after a conviction of two counts of manslaughter. These counts stem from an explosion at a gunpowder-substitute manufacturer that resulted in the deaths of two employees.

In another case, which is being investigated, the district attorney has filed murder charges against a contractor over a building collapse that killed six people and injured 13 others. The contractor faces six counts of third-degree murder, six counts of manslaughter, and 13 counts of recklessly endangering another person. The contractor is not the only person facing criminal prosecution. Charges are also being made in the same case against an excavating contractor. The charges in this part of the case are six counts of involuntary manslaughter and 13 counts of reckless endangerment. In this case, in addition to the criminal prosecution, OSHA has proposed $397,000.00 in penalties against the two companies. Criminal prosecutions are not limited to the construction and general industry business sector. Charges have been brought and convictions have been obtained in connection with a mining tragedy in 2010 that killed 29 West Virginia miners. You see, not only do businesses get fined and sanctioned because of unsafe work place situations and actions. The business owners and other responsible parties are being held accountable as well. These criminal charges and convictions do not take into consideration the civil litigation that could take place. In conclusion, let’s look at not only the safety of the workers, as that itself should be enough to make someone be concerned. You must also look at the impact that a violation could have on the owner and safety professional on a jobsite or facility. Criminal prosecution, incarceration, and civil penalties are all possibilities that could arise from an accident or fatality. Add to that the legal action that could be taken by the families of the victim and you just end up complicating the problem. Keep everyone’s safety at the forefront each and every day. Look out for them and maybe, just maybe, they will look out for you.

REFERENCES OSHA Instruction CPL 02-00-124, OSHA’s Multi-Employer Citation Policy NFPA 70E-2012, Standard for Electrical Safety in the Workplace OSHA Regulations, 29CFR1910.331 - .335, Electrical Safety Related Work Practices National Law Review, December 12, 2013, Criminal Charges Follow Fatal Workplace Accidents Don Brown is the Senior Programs Developer for Shermco Industries in Irving, Texas. He has been in the electrical industry for over 40 years and has been implementing and training electrical safety for the last 15-plus years. Mr. Brown just completed his certification through NFPA as a Certified Electrical Safety Compliance Professional (CESCP). He has written electrical safety programs for large data centers, petrochemical facilities, and manufacturing facilities, and is in the process of updating many of these to include the upcoming changes in the NFPA 70E—2015 Edition.

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PERSONAL PROTECTIVE GROUNDING NETA World, Fall 2015 Issue Jeff Jowett, Megger It is a common expression in firearm safety that many a person has been killed by an unloaded gun. This, of course, refers to the consequences of carelessness or inattention to detail. The electrical industry has a clear parallel in the de-energized circuit; in ordinary speech, the equipment or circuit that has been (supposedly) turned off. Even when effectively isolated from its own power source, electrical equipment in high-energy environments like switchyards and substations can still develop dangerous voltages from induction by nearby live circuits, as well as what the utilities refer to as an “event” — an unexpected rise in voltage from a disturbance on the line such as a lightning stroke. An indispensable safeguard against such contingencies is the installation of protective grounds. The description and implementation of protective grounding has been well established by organizations such as OSHA. Personal protective grounds provide maximum safety for personnel working on de-energized systems or equipment by equalizing voltage differences at the worksite (Figure 1). The aim is to keep the voltage across the worker at a safe level in the event of the equipment or system becoming accidentally energized from any possible source. Personal protective grounds dissipate static voltages and protect against induced voltages from adjacent energized systems. In addition, they enable protective devices to trip as quickly as possible. Personal protective grounding prevents accidental death or injury by minimizing the magnitude and duration of shock hazard.

OSHA 1910.333(c)(3) states: If work is to be performed near overhead lines, the lines shall be de-energized and grounded, or other protective measures shall be provided before work is started. If the lines are to be de-energized, arrangements shall be made with the person or organization that operates or controls the electric circuits involved to de-energize and ground them. The requirements for compliance on transmission and distribution lines are addressed in OSHA 1910.269(n). The application of grounds shall create an equipotential zone protecting the employee. The grounds shall be capable of conducting the maximum available fault current at the grounded point for the time necessary to clear the fault; the ampacity of a 2 AWG copper conductor is the minimum. The circuit must be de-energized and tested for absence of nominal voltage before grounds are installed. The ground end of the grounding conductor must always be installed first, and then the other end is connected to the equipment to be serviced, using a live-line tool. Conversely, when the protective grounds are removed upon completion of the task, the conductor-end connection is removed first, again using a live-line tool. When working on cables at a location remote from the terminal end, the terminal end may not be grounded if the possibility of hazardous transfer of potential exists. During testing procedures, if grounds need to be removed for test implementation, workers must use insulating equipment and be isolated from any hazard. Situations may also arise where the installation of protective grounds is impracticable or would present greater hazards than working without. In such cases, the installation of protective grounds may be excused. As described in 1910.269(n)(2)(i)-(iii), lines and equipment may be treated as de-energized, provided three conditions are met: (1) Assurance that lines and equipment are de-energized under the provisions of paragraph (m) of this section, (2) no possibility of contact with another energized source exists, and (3) the hazard of induced voltage is not present. Proper sizing of personal protective grounds is critical and must be implemented in detail because protective grounding doesn’t merely contend with nominal current but also must be adequate for all available fault current. Protective grounds must be capable of withstanding all electrical and electromagnetic stresses. The requirement can be implemented with a three-step process:

Fig. 1: Consequences of Protected and Unprotected Circuits

● Step One – Calculate the maximum available fault current for all interconnection points throughout the electrical system in question. Relative information includes the utility interconnection, transformer sizes and impedances, and conductor sizes and lengths. It may be presented in the form of a single

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Safety Vol. 1 line diagram, with symmetrical and asymmetrical fault currents noted for each bus.

● Step Two – Determine the appropriate type and size of grounding conductors for each system part. Appropriate grounding conductor size is then incorporated into the Lock Out/Tag Out procedures. ● Step Three – Thoroughly inspect grounding equipment prior to each use. Clamps, ferrules, serrated jaw inserts and the like should be inspected for tightness. The standard for inspection and test is ASTM F-2249, Standard Specification for In-Service Test Methods for Temporary Grounding Jumper Assemblies Used on De-Energized Electric Power Lines and Equipment. This consists of three parts: (1) Testing grounding jumper assemblies on a time interval established by the user to ensure defective assemblies are removed from service in a timely manner; (2) retesting after performing any maintenance that may have affected the integrity of the assembly; and (3) retesting again after any assembly may have been subjected to short circuit or lightning surge. Sometimes conflicting information exists in the literature on the effects of current on the human body, but significant early research conducted by Charles Dalziel in the 1940s culminated in the formula:





I = k/√t

Where I = current (amps), k is a function of shock energy, and t is time (seconds). The formula indicates a time/current relationship, which is expressed as function of shock energy. The effect on the human body is based on the amount of current and the duration of exposure, such that k50 is 116 for a 110-lb body, and k70 is 157 for a 155-lb body. The formula can calculate current magnitude for heart fibrillation, producing a time/current curve as seen in Figure 2. Human body resistance is placed from 500 to 1000 ohms, hand to foot or hand to hand. This figure is profoundly affected in work situations by the wearing of insulating gloves and boots. But a contravening factor is that reclosers may not have been disabled, with short intervals between reclose not allowing the body to recover from a first shock before receiving a second. Shocks above the 600 V level may further reduce body resistance by puncturing the skin, thereby exposing internal organs, which have less resistance to higher current levels.

Fig. 2: Heart Fibrillation Time vs. Current An example: A worker with a 110-lb body weight could receive a shock of 67 mA for three seconds before going into heart fibrillation, whereas a 155-lb worker would tolerate 91 mA for three seconds.

Fig. 3: Electrical Equivalent of Jumper

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Safety Vol. 1 Accordingly, the protection afforded by Personal Protective Equipment (PPE) grounds is designed to reduce voltage drop across the worker’s body well below the value that would produce fibrillation, burns, or other injury. A successful equipotential grounding method places the worker in a parallel path with a jumper of sufficiently low resistance to divert all but a harmless level of current around, as opposed to through, the worker (see Figure 3). Voltage rise across the worker is minimized, while fast clearing of protective devices is effectively implemented. The jumper must have adequate ampacity to maintain a low resistance during the fault clearance. The design of PPE grounding, therefore, must ensure that heart fibrillation current will never be reached under system fault conditions. Critical data is provided in Table 1, regarding the ampacity and resistance of various sizes and types of grounding conductors. A worst-case scenario is also provided in Table 1 because it would require significant calculations to determine dc offset and X/R ratio for various load and short-circuit situations. Updated Short Circuit and Coordination Studies are necessary to determine adequate sizing.

Table 1: Current Carrying Capabilities of Copper Grounding Cable The next column in NETA World will continue with description of the parameters for safe and effective grounding equipment.

REFERENCES Dalziel, Charles F., The Effects of Electric Shock on Man, IRE Trans. on Medical Electronics (PGME-5), May 1956. AVO Training Institute, Dallas, Texas Jeffrey R. Jowett is a Senior Applications Engineer for Megger in Valley Forge, Pennsylvania, serving the manufacturing lines of Biddle, Megger, and multi-Amp for electrical test and measurement instrumentation. He holds a BS in Biology and Chemistry from Ursinus College. He was employed for 22 years with James G. Biddle Co. which became Biddle Instruments and is now Megger.

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HUMAN ERROR AND SAFETY NETA World, Fall 2015 Issue Paul Chamberlain, American Electrical Testing Co., Inc. What is human error? Human error is the outcome of an action that does not produce the human’s intended result(s). It can be summed up by saying things did not go as planned. James Reason stated, “Human error is a consequence, not a cause. Errors are shaped by upstream workplace and organizational factors… Only by understanding the context of the error can we hope to limit its reoccurrence.”

No matter where the need to rush comes from, there must always be the need to push back and realize that this time pressure can lead to a mistake. Take the time to slow things down; it is quicker to do things right once, then to do it wrong and have to do it a second time.

The 6 P rule (Proper Prior Planning Prevents Poor Performance) can go a long way to preventing a human error, but there is still that human factor. Human beings are fallible and make mistakes. Those mistakes are usually caused by only a few factors.

Being distracted either mentally or physically can lead to a lapse of judgement or a missed step. When doing something critical that requires intense awareness, always ensure that distractions are kept to a minimum. In this technological day and age, cellular phones are a major distraction. Make it a habit to power them down or put them elsewhere and on vibrate whenever doing something critical. Cell phones are a good example of mental and physical distraction. Using a phone requires a physical interaction to enable a call and to have a conversation with the caller. Mentally, a caller is required to engage in the conversation and make judgement calls or opinions based upon the information the caller is sending or receiving.

TIME PRESSURE When employees rush to complete a project or a task, they can have a lapse of judgement. Missing steps, improper communication, and failing to recognize warning signs are just a few of the issues that can occur when rushing. Being in a rush is caused by either internal or external forces. Internal could mean a need to get home at the end of the day or scheduling conflicts with the individual’s personal life. A good example of external forces is a critical project that needs to be completed by the end of the week, but has been delayed due to rain. Perhaps internal forces are in play for the employee working on the project because his son is scheduled to pitch his first high school baseball game that Friday evening, but the work is still unfinished. To make it to the game for the first pitch, the employee completes his tasks for the day quickly. Hopefully, rushing through the work does not produce any mistakes — but it can. And those mistakes can lead to incorrectly operated equipment, potential injuries, or worse.

DISTRACTIONS

Other distractions can include a change in work shift, which can contribute to tiredness and dulled senses. If the weather changes drastically from hot to cold or vice versa, it can be a distraction. Distractions can also come from outside the work environment. Trouble at home, kids getting bad grades, and money issues all contribute to a mental distraction, which can be detrimental in the work environment. It is a good idea to always ensure that any distraction, whether a phone or not, is minimized during any act where improper action can cause significant consequences.

External time pressure can occur when a boss or peer is pressuring another employee to complete the work quickly. Maybe they need to move on to another location or task, or maybe there is only a limited outage window that was impacted by some external force (e.g. other contractors eating up outage time). Be aware of Mondays and Fridays. On Mondays, some employees may not be fully recovered from a full and exciting weekend. This can cause mental lapses in judgement due to being tired or not fully engaged in the work. On Fridays, they may be in a rush to get out the door and start an exciting weekend, causing mental disengagement with the task. Mental disengagement is not exclusive to Mondays and Fridays; it also applies after any prolonged absence from work, such as before and after long weekends, vacations, layoffs, etc.

Table 1: Phonetic Alphabet

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Safety Vol. 1 COMMUNICATION

THE BIG PICTURE

Ensuring that a message is properly sent and received is critical. Using the phonetic alphabet and numerals is necessary when communicating equipment identifications or other nomenclature (see Table 1). This prevents peers and other employees from going to the wrong equipment or potentially using incorrect or misheard settings.

All of the previous human conditions contribute to an employee or peer making an error. The first and most effective means of reducing that error is to first be fully engaged in the task at hand. Identify those things that may be a distraction or may contribute to a mistake, and eliminate those items from the work task. Many accidents occur because the employee continued blindly on in a task without heeding any of the little warning signs that may occur. When something doesn’t seem right, stop, take a step back to reevaluate, and ask questions of the team performing the work. Find out why things aren’t right, and heed those little warnings. Be cognizant of any internal problems and acknowledge that they may affect the work — and discuss that with fellow workers. Doing this will minimize the possibility of a problem occurring.

It is always a good idea to use a three-part communication when doing critical tasks. Three-part communication consists of: ● A sender saying a direction or information ● A receiver repeating the information verbatim ● The sender acknowledging that the information is correct If the information is repeated back incorrectly, then the sender states that the information is incorrect, and then repeats step 1. Using three-part communication ensures that the message sent is the message received. As a receiver of information, it is also important to get all the information needed to successfully complete the task. This means that everything needs to be questioned. Question why certain test procedures are used, question why there was a lockout performed and by whom and when. To ensure that the big picture is achieved, get an understanding of all aspects of the job. As the sender of information, ensure that the receiver truly understands what is necessary. Emphasize and repeat the steps needed and the results expected. Write it down and give notes to the receiver. This ensures that there is complete understanding, whether it is between members of a work crew or if turnover of work is conducted from one work group to another.

PLACE KEEPING Place keeping is used to mark the steps in a procedure or work document that have been completed so that steps are not accidentally omitted or repeated. Use place keeping when using a procedure or work document to perform critical activities. When suspending performance of a procedure, place keeping is used to identify the last step completed. Prior to restarting the work, conduct a thorough re-review of the procedure.

FLAGGING AND OPERATIONAL BARRIERS Flagging involves highlighting a component to improve the chances of performing actions on the correct component. Operational barriers are used to mark or cover components that are not to be worked on or manipulated during an evolution. Flagging and operational barriers are particularly helpful when several similar components are in close proximity to those affected by the work activity. Research indicates that several events can be attributed to an individual starting an activity on one component, taking a break or becoming otherwise distracted from the component, and returning only to perform manipulations on the wrong component.

Simple, everyday tools can help mitigate human fallibility. Taking notes with pen and paper is the old-school, tried-and-true method. Using laptops and scheduling programs are a newer methodology. Write things down so they won’t be forgotten, either on paper or electronically. Come up with plans and procedures for the task, and write them down step by step before the work begins. This helps ensure that the right skills, tools, equipment, and personnel are present for the work. Pre-job briefings are an effective means of documenting and communicating steps as well as hazards on the job. The more complex or unfamiliar a task is, the more complex the pre-job briefing must be. Ensure that all people affected by the task attend the pre-job briefing. This can include other contractors not directly involved in the scope of work but who are in or near the work area where the task is being performed. Being aware of all contributing factors and planning for their mitigation helps make the work environment safer for all. Everyone makes mistakes, but we can identify and minimize the factors that contribute to those mistakes. Paul Chamberlain has been the Safety Manager for American Electrical Testing Company Inc. since 2009. He has been in the safety field for the past 12 years, working for various companies and in various industries. He received a Bachelor’s of Science degree from Massachusetts Maritime Academy.

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POWER TRANSFORMER HAZARD AWARENESS NETA World, Winter 2015 Issue Scott Blizard, American Electrical Testing Co., Inc. Performing a condition analysis or maintenance on a power transformer and auxiliary devices is a hazardous task that requires an experienced individual with a solid ability to identify potential hazards and mitigate risks. Condition analysis of a power transformer may be performed using methods and products designed to test and diagnose the equipment when it is operating, such as infrared survey, partial discharge detection equipment, and online oil analysis. The Personal Protective Equipment (PPE) required should be appropriate and adequate for all tasks performed. This article is an overview of some of the potential hazards of a power transformer and various means of safeguarding as well as mitigation of those hazards. This article does not include every potential hazard, but rather, explores some potentially hazardous situations that can occur while performing work on a power transformer and auxiliary equipment. Additional hazards may exist, depending on the type or condition of the equipment. Take all procedures and instructions seriously, and verify that the instruction or equipment operation and maintenance manuals used are for the correct equipment. Check for and identify potential hazards prior to beginning every task by using a Pre-Job Brief worksheet.

ELECTRICAL AND MECHANICAL HAZARDS Improper Lock Out/Tag Out (LO/TO) is a major contributing factor to injuries caused by power transformers and auxiliary devices. Controlling hazardous energy is essential, and many forms of energy may be involved. To determine the proper LO/TO procedures, always refer to the appropriate OSHA regulation or required procedure, such as 29 CFR 1910.147 and .333, as well as manufacturer instructions. Electricity is the most obvious hazardous energy source. Electrically de-energize the power transformer and auxiliary devices from their primary energy source and ensure the equipment is disconnected from all sources of power, both ac and dc, if applicable. Once de-energized, verify that the equipment is at a zero energy state using the manufacturer’s approved method. Verify the accuracy of the detection or voltage measuring device against a known source, check for zero energy on the de-energized equipment, and then test the detection equipment against a known source again. This will verify that the detection meter used was functioning properly during the initial check. Testing for voltage will require its own level of PPE, depending both upon the voltage level and arc-flash hazard level and test procedures per NFPA 70E 2015 — Standard for Electrical Safety in the Workplace or OSHA 29 CFR 1910.269 — Electric Power Generation, Transmission, and Distribution regulation.

Electrical energy isn’t the only energy that requires LO/TO. Devices such as motor-operated switches and circuit breakers and others may contain a large amount of mechanical energy. This energy must be dissipated prior to servicing the equipment or serious injury could occur. Once the energy has been discharged or dissipated, LO/TO the source of the stored energy, if feasible. Ensure that remote operating handles are tagged in a local or manual mode. This will prevent someone from inadvertently operating the equipment.

CHEMICAL HAZARDS Certain types of power transformers may also pose a chemical hazard; take caution with gases, chemicals, and liquids. Use proper containment of liquids (e.g. spill containment pads) and address environmental concerns. Ensure compliance with all owner, state, and federal regulations. Beware of units containing Polychlorinated Biphenyls (PCBs) or other hazardous fluids. When working on such units, follow appropriate state and federal guidelines for fluid handling and disposal, and avoid skin contact. Some cleaners may pose a respiratory and skin irritant if used in enclosed areas or on bare skin. Gain knowledge of the material and check the applicable Safety Data Sheet (SDS) to identify any potential health effects from its use. Once again, proper PPE is necessary for using some cleaners; for example, nitrile gloves, safety glasses, face-shield, and even respiratory protection may be needed.

CONFINED SPACE When performing the visual inspection, mechanical inspection, maintenance, or repairs on a power transformer, personnel may be required to enter the actual tank. Entering into a confined space requires the entrant to be aware of the conditions within that space. The entrant needs to first ask: Is this confined space located at a facility regulated by the OSHA 1910.269 Electric Power Generation, Transmission, and Distribution regulation, or is it a commercial entity or space regulated under OSHA 1910.146 (permit-required confined spaces regulation)? These OSHA regulations have different requirements, depending on the location of the space and its hazards. OSHA has created a flow chart to help with that determination, located within OSHA 1910.269 Appendix A. This flow chart is shown in Figure 1 and can also be viewed at http://tinyurl.com/ p329zxo.

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● The entrant must also determine if, under 1910.269, the space is considered an “enclosed space.” ○ Enclosed space: A working space, such as a manhole, vault, tunnel, or shaft, that has a limited means of egress or entry, that is designed for periodic employee entry under normal operating conditions, and that, under normal conditions, does not contain a hazardous atmosphere, but may contain a hazardous atmosphere under abnormal conditions.

Fig. 1: Appendix A-5 to §1910.269 — Application of §§1910.146 and 1910.269 to Permit-Required Confined Spaces To answer the questions on the flow chart, the entrant must know the following from the OSHA regulations. ● OSHA 1910.146(b) defines a confined space. ○ “Confined space” means a space that: – Is large enough and so configured that an employee can bodily enter and perform assigned work; – Has limited or restricted means for entry or exit (for example, tanks, vessels, silos, storage bins, hoppers, vaults, and pits are spaces that may have limited means of entry.); – Is not designed for continuous employee occupancy. ● OSHA 1910.146(b) describes when the confined space requires a permit to enter. ○ “Permit-required confined space (permit space)” means a confined space that has one or more of the following characteristics: – Contains or has a potential to contain a hazardous atmosphere; – Contains a material that has the potential for engulfing an entrant; – Has an internal configuration such that an entrant could be trapped or asphyxiated by inwardly converging walls or by a floor which slopes downward and tapers to a smaller cross-section; – Contains any other recognized serious safety or health hazard. ● The entrant must know if the work to be performed falls under the scope of the 1910.269 regulation — put simply, if that work is conducted during the operation and maintenance of electric power generation, control, transformation, transmission, and distribution lines and equipment. Specific information on that definition may be found in all of 1910.269(a)(1).

○ Note to the definition of “enclosed space”: The Occupational Safety and Health Administration does not consider spaces that are enclosed but not designed for employee entry under normal operating conditions to be enclosed spaces for the purposes of this section. Similarly, the Occupational Safety and Health Administration does not consider spaces that are enclosed and that are expected to contain a hazardous atmosphere to be enclosed spaces for the purposes of this section. Such spaces meet the definition of permit spaces in §1910.146, and entry into them must conform to that standard. ● The entrant must also know the potential hazards within the space that must be controlled prior to entry in a 1910.269 regulated enclosed space. For more information regarding those hazards, see all of 1910.269(e).

OTHER PHYSICAL HAZARDS When performing the visual inspection, mechanical inspection, maintenance, or electrical tests on a power transformer, gravity is an energy that may also need to be controlled. The size and weight of panel covers and inspection plates may make them difficult to handle. Should gravity be a potential energy source, ensure that the energy is dissipated and controlled as part of the LO/TO procedure.

IMPROPER PPE HAZARDS After verification that the power transformer is de-energized, the method of disconnecting the equipment may require a different form or class of PPE. Ensure that proper PPE is used for the class of disconnecting means. Refer again to the NFPA 70E 2015 or OSHA 1910.269. They will indicate what level of protection is required, depending on the task and within certain levels of exposure. Identifying the correct level of PPE and gloves will aid in the mitigation of injury from a potential arc flash. However, the table within NFPA 70E only provides information based on known values of the short circuit current available, the clearing time in cycles, and minimum working distance. If those factors are unknown, more information must be gathered prior to performing the work to ensure personnel safety. Table 1 provides the approach boundaries from NFPA 70E. It indicates at what proximity to the alternating-current, energized equipment that the PPE must be donned.

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(1)

(2)

Nominal System Voltage Range, Phase to Phasea

(3) Limited Approach Boundaryb

(4) Restricted Approach Boundaryb; Includes Inadvertent Movement Adder

Exposed Movable Conductorc

Exposed Fixed Circuit Part

Not Specified

Not Specified

Not Specified

50 V to 150 V

3.00 m (10 ft. 0 in.)

1.0 m (3 ft. 6 in.)

Avoid Contact

151 V to 750 V

3.00 m (10 ft. 0 in.)

1.0 m (3 ft. 6 in.)

0.3 m (1 ft. 0 in.)

751 V to 15 kV

3.00 m (10 ft. 0 in.)

1.5 m (5 ft. 0 in.)

0.7 m (2 ft. 2 in.)

15.1 kV to 36 kV

3.00 m (10 ft. 0 in.)

1.8 m (6 ft. 0 in.)

0.8 m (2 ft. 7 in.)

36.1 kV to 46 kV

3.00 m (10 ft. 0 in.)

2.5 m (8 ft. 0 in.)

0.8 m (2 ft. 9 in.)

46.1 kV to 72.5 kV

3.00 m (10 ft. 0 in.)

2.5 m (8 ft. 0 in.)

1.0 m (3 ft. 3 in.)

72.6 kV to 121 kV

3.00 m (10 ft. 0 in.)

2.5 m (8 ft. 0 in.)

1.0 m (3 ft. 4 in.)

138 kV to 145 kV

3.4 m (11 ft. 0 in.)

3.0 m (10 ft. 0 in.)

1.2 m (3 ft. 10 in.)

161 kV to 169 kV

3.6 m (11ft. 8 in.)

3.6 m (11ft. 8 in.)

1.3 m (4 ft. 3 in.)

230 kV to 242 kV

4.0 m (13 ft. 0 in.)

4.0 m (13 ft. 0 in.)

1.7 m (5 ft. 8 in.)

345 kV to 362 kV

4.7 m (15 ft. 4 in.)

4.7 m (15 ft. 4 in.)

2.8 m (9 ft. 2 in.)

500 kV to 550 kV

5.8 m (19 ft. 0 in.)

5.8 m (19 ft. 0 in.)

3.6 m (11 ft. 10 in.)

765 kV to 800 kV

7.2 m (23 ft. 9 in.)

7.2 m (23 ft. 9 in.)

4.9 m (15 ft. 11 in.)

>50 V d

Table 1: NFPA 70E 2015 Table 130.4(D)(a)) — Approach Boundaries to Energized Electrical Conductors or Circuit Parts for Shock Protection for Alternating Current Systems Note 1: For arc flash boundary, see 130.5(A). Note 2: All dimensions are distance from exposed energized conductors or circuit part to employee. ● For single-phase systems, select the range that is equal to the system’s maximum phase-to-ground voltage, multiplied by 1.732. ● See definition in Article 100 and text in 130.4(D)(2) and Annex C for elaboration. ● Exposed movable conductors describe a condition in which the distance between the conductor and a person is not under the control of the person. The term is normally applied to overhead line conductors supported by poles. ● This includes circuits where exposure does not exceed 120V. Again, the PPE must be adequate for the task and energy levels, and worn prior to entering within the Restricted Approach Boundary. Additional tables exist for direct-current energized equipment.

INSTALLATION OF TEMPORARY PROTECTIVE GROUNDS Grounds are an excellent secondary means of protecting the worker from inadvertent energization. Refer to any applicable

OSHA regulation such as 29 CFR 1910.269, NFPA 70E, and ASTM F855 for specific guidance on grounding locations and sizing of grounds required for the task. Grounds must always be applied upstream and downstream of the equipment and as close to the work as possible. Using correctly sized and applied grounds is an additional safeguard for employees should there be a form of electrical energy introduced into the system or equipment being worked on. Induced voltage or back-feed are just two forms of energy that may be inadvertently introduced into a system that has been properly Locked Out/ Tagged Out.

IN CONCLUSION When performing maintenance and testing on a power transformer, take care of the following: ● Obtain all service bulletins, maintenance documents, arc-flash studies, and manuals prior to working on that specific device. ● Review all prints and one-lines associated with the equipment. ● Establish a safe work area, and barricade off the work area. ● Perform a pre-job brief with all employees on-site. ● Wear proper PPE.

Safety Vol. 1 ● Disconnect the electrical feed and control circuit(s), verify mechanical interlocks are properly engaged, and test equipment before performing visual or mechanical inspections. ● If applicable, verify that there is zero energy (test, check, test), and discharge all stored energy, including pressurized gasses and gravity. ● Complete the Lock Out/Tag Out (for all energy sources). ● Connect grounds where and /if applicable. ● Identify, visually mark, or flag the equipment being worked on. Being aware of and mitigating the hazards listed here can lead to a safer work environment while performing inspection, maintenance, and testing of a power transformer. Scott Blizard has been the Vice President and Chief Operating Officer of American Electrical Testing Co., Inc. since 2000. During his tenure, Scott acted as the Corporate Safety Officer for nine years. He has over 25 years of experience in the field as a Master Electrician, Journeyman, Wireman, and NETA Level IV Senior Technician.

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UNDERSTANDING AND IMPLEMENTING THE ANSI/NETA ECS-2015 STANDARD FOR ELECTRICAL COMMISSIONING SPECIFICATIONS PowerTest 2015 Lorne Gara, Orbis Engineering and Ron Widup, Shermco Industries Whether installing, upgrading, or expanding an electrical system the ultimate goal is for the system to be safe and reliable. All components in the system have to be safe and reliable, this includes the design, engineering, equipment, wiring, and construction. Although there are many different methods to safeguard the installation and prove safety and reliability, the most important is the acceptance tests and commissioning. The International Electrical Testing Association (NETA) recognized that electrical commissioning has not been well defined in the industrial and utility markets, though there is a greater degree of documentation and guidance within the building and data center sectors. This was one of the motivations for NETA to develop an electrical commissioning specification that was apt to apply on a global basis to many industries, and thus the NETA commissioning standard was developed and approved as a consensus-based standard. NETA has developed a new electrical testing standard, the ANSI/ NETA ECS-2015 Standard for Electrical Commissioning Specifications for Electrical Power Equipment and Systems (NETA ECS). No matter what type of industry sector you are in, when it comes to electrical power equipment it is important that you understand the processes and procedures that take place from a system’s initial concept to final acceptance and energization at your facility. Whether it is a steel mill, refinery, paper mill, electrical utility, data center, hospital, commercial building…the list goes on and on. Regardless of the industry, all require the individual pieces of electrical equipment to interconnect with each other and work together as a system if safety and reliability is to be assured. The difference becomes the complexity of the system and how much interconnection of equipment is required to complete “the system”. After design, procurement, and installation one of the first steps in the commissioning process is performing electrical acceptance testing. It is also important to understand what acceptance testing tasks are meant to accomplish. This is clarified within the scope of the ANSI/NETA document Standard for Acceptance Testing Specifications for Electrical Power Equipment and Systems (NETA ATS). The NETA standard states: “These specifications cover the suggest-

ed field tests and inspections that are available to assess the suitability for initial energization of electrical power equipment and systems.” And goes on to say “The purpose of these specifications is to assure that tested electrical equipment and systems are operational, are within applicable standards and manufacturer’s tolerances, and are installed in accordance with design specifications.” The NETA ATS has a section that addresses system functional tests but does not completely address the complexity and requirements of a comprehensive electrical commissioning process. This contributed to the need to develop the new commissioning standard. Acceptance testing tasks are very important, and provide the data necessary to assure the owner that he has electrical equipment that has not only been installed properly but is also functioning as intended and designed. Factory Acceptance Testing ● Manufacturer tests at the factory usually witnessed by the commissioning agent. ● Individual equipment tests very similar to the ANSI/NETA ATS. ● System commissioning tests at this stage will be restricted to how much equipment is connected together and what amount of interconnection wiring is complete. ● It may be possible to get a large amount of the pre-energization tests completed at this stage (example: a switchgear building complete with switchgear, relays, and SCADA systems). Field Acceptance Testing ● Many problems can be created from disassembly, storage, shipping, installation, and construction following the factory tests, all reasons why tests need to be competed in the field. ● It may be necessary to complete some of the field inspections and tests several times during the shipping routes and construction phases. ● Inspections and tests should be completed after lengthy storage times or when poor storage facilities are used (ie: poor weather or poor environment such as salt water or hazardous gases in the atmosphere). ● Inspections and tests should be completed at points of transfer of shipping company or shipping method (ie: barge to rail, rail to truck, truck to laydown yard, laydown yard to final placement).

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Safety Vol. 1 ● Final field tests include individual equipment tests as per ANSI/NETA ATS. ● Complete all of the applicable tests listed in the ANSI/NETA ATS. ● Inspections and tests are completed to assure that tested electrical equipment and systems are operational, are within applicable standards and manufacturer’s tolerances, and are installed in accordance with design specifications.

ELECTRICAL COMMISSIONING Commissioning is the systematic process of verifying, documenting, and placing into service newly installed, or retrofitted electrical power equipment and systems.

DIVISION OF RESPONSIBILITY The NETA ECS states the division of responsibility between the owner and the commissioning organization.

The Owner’s Representative The owner’s representative shall provide the commissioning organization with the following: ● A short-circuit analysis, a coordination study, an arc-flash hazard analysis, and a protective device setting sheet as described in ANSI/NETA ATS, Section 6. ● Most recent version of the electronic setting files for intelligent electronic devices and relay logic diagrams.

Commissioning is critical for all new or retrofit installation projects to verify the correct system operation to the design, thus contributing to the safe and reliable operation of the system.

● Complete set of as built electrical plans and specifications.

THE BASIC FRAMEWORK:

● The factory and field acceptance test reports.

PRE-DESIGN STAGE

● Notification of when equipment becomes available for commissioning work. Work shall be coordinated to expedite project scheduling.

At this stage, the owner should select the commissioning team. The team would work with the owner to develop the owner’s project requirements (OPR), a project schedule, and the commissioning scope and budget.

QUALIFICATIONS The NETA ECS highlights some of the requirements for the qualifications of the commissioning organization and personnel.

Commissioning Organization ● The commissioning organization shall be an independent, third-party entity which can function as an unbiased authority, professionally independent of the manufacturers, suppliers, and installers of equipment or systems being evaluated. ● The commissioning organization shall be regularly engaged in the commissioning of electrical equipment, devices, installations, and systems. ● The commissioning organization shall use personnel who are regularly employed for electrical commissioning services. ● The commissioning organization shall submit appropriate documentation to demonstrate that it satisfactorily complies with these requirements.

Commissioning Personnel Personnel performing these commissioning activities shall be trained and experienced concerning the apparatus and systems being evaluated. These individuals shall be capable of conducting the tests in a safe manner and with complete knowledge of the hazards involved. They must evaluate the test data and make a judgment on the serviceability of the specific equipment.

● Drawings and instruction manuals applicable to the scope of work.

● Project schedule. ● Site-specific hazard notification and safety training. ● Owner’s project requirements (OPR). ● Basis of design (BOD) document. ● Designated representative(s) for the project commissioning activities.

The Commissioning Organization The commissioning organization shall provide the following: ● All necessary services and technical expertise to conduct electrical commissioning. ● Notification to the designated representative(s) prior to the commencement of any electrical commissioning activity. ● Timely notification of deficiencies based on the results of the commissioning activities. ● Written record of all electrical commissioning activities and a final report.

COMMISSIONING PROCESS The NETA ECS defines the commissioning intent and the owner’s project requirements. Commissioning is the systematic process of verifying, documenting, and placing into service newly-installed, or retrofitted electrical power equipment and systems. Commissioning is critical for all new or retrofit installation projects to verify the correct system operation to the design, thus contributing to the safe and reliable operation of the system.

48 The commissioning process involves owner’s project requirements (OPR), basis of design (BOD), factory acceptance tests, field acceptance tests, verification of the component interconnections, and functional testing of the system in part and in whole. Acceptance tests and commissioning work provides baseline results for routine maintenance of the system and related components.

Safety Vol. 1 ● Documentation of the general communication channels and project hierarchy. ● Detailed schedule of the project, including design, construction, acceptance testing, commissioning, and energization stages and milestones. ● General description of commissioning activities that will occur during construction, energization, and post-energization.

OWNER’S PROJECT REQUIREMENTS (OPR)

● Commissioning checklists and test forms specific to the project.

OPR are a written document that details the functional requirements of a project and the expectations of how it will be used and operated. This includes project goals, measureable performance criteria, cost considerations, benchmarks, success criteria, and supporting information. (The terms project intent or design intent are used by some owners for their commissioning process owner’s project requirements.) (ASHRAE Guideline 0-2005)

● A process for approval by the owner and operator to allow the equipment to be energized.

DESIGN STAGE At this stage, the basis of design is created. The commissioning team should verify the basis of design meets the OPR, develop a commissioning plan, develop checklists, and perform the design review.

Basis of Design (BOD) The BOD is a document that records the concepts, calculations, decisions, and product selections used to meet the OPR and to satisfy applicable regulatory requirements, standards, and guidelines. The document includes both narrative descriptions and lists of individual items that support the design process. (ASHRAE Guideline 0-2005)

COMMISSIONING PLAN The NETA ECS highlights the commissioning plan and the contents. A commissioning plan is a document that outlines the organization, schedule, allocation of resources, and documentation requirements of the commissioning process. The commissioning plan should be developed by the commissioning authority during the design stage of the project. The commissioning plan should be updated and expanded during the construction, acceptance testing, and functional testing phases of the project by the commissioning team. Parties involved in the execution of the commissioning plan shall work from the most up-to-date version of the plan. The commissioning plan should include the following information: ● Overview of the commissioning stages and activities. ● Roles and responsibilities for the commissioning team throughout the project.

● A process for approval by the owner and turnover of the project and equipment from the commissioning team to the owner.

CONSTRUCTION STAGE At this stage, the commissioning team verifies equipment complies with the OPR, executes the factory acceptance testing, field acceptance testing, and pre-energization commissioning inspections and tests.

INSPECTIONS AND COMMISSIONING PROCEDURES There are three voltage classes of equipment detailed within the NETA ECS: ● Low-Voltage Systems (less than 1,000 volts) ● Medium-Voltage Systems (greater than 1,000 volts and less than 100,000 volts) ● High-Voltage and Extra-High Voltage Systems* (greater than 100 kV and less than 1,000 kV) Within each voltage class many of the commissioning tasks are the same, however there are some differences in execution between equipment classes due to different types of construction or complexity of operation. By breaking the standard into voltage classes, NETA is able to address the various nuances and requirements of commercial, industrial, and utility grades of equipment, independent of the industry at which the equipment is located. *Note: High and extra-high voltage systems are combined into one category in the NETA ECS. For instance, the commissioning of a low-voltage power circuit breaker and related system is typically not as complex as a medium-voltage circuit breaker and the related system[s]. Regardless of the voltage class of the electrical system or systems being commissioned, there are some basic aspects that apply to all. Listed below are several of the basic steps that will be applied globally to all systems, but be aware there are many voltage and project specific tasks that are not listed below. Refer to the NETA ECS for a more comprehensive listing.

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Safety Vol. 1 Typical Commissioning Inspections and Tests (Common To All Voltage Levels) Pre-Energization Prior to complete system energization, assure the following pre-energization tasks have been completed. ● Review the owner’s project requirements (OPR), basis of design (BOD), project specifications, and regulatory requirements for information specifically related to the commissioning of the electrical system. ● Review factory and field acceptance test data, documentation, results, and deficiencies to verify acceptable condition and suitability for initial energization and final acceptance. ● Verify all equipment has been tested according to the most recent edition of the ANSI/NETA Standard for Acceptance Testing Specifications for Electrical Power Equipment and Systems (ANSI/NETA ATS). ● Verify nameplate and equipment ratings are documented and correct in accordance with the most current drawings. ● Review drawings, logic diagrams, protective device settings, engineering studies, and other pertinent information to verify accuracy and completeness. ● Visually inspect equipment. ● Verify equipment is clearly labeled with unique designations and match designations on drawings, documentation, programming, and communication protocols. ● Verify equipment, doors, and fences are labeled with appropriate safety labeling and have the correct information in accordance with applicable regulations. ● Verify equipment and circuits are correctly bonded and grounded in accordance with applicable regulations. ● Confirm that correct electrical equipment clearances have been met. ● Verify correct operation of mechanical, electrical, and safety interlocks on electrical power equipment. Verify duplicate keys are destroyed or retained by authorized personnel in accordance with manufacturer’s recommendations.

● Verify intelligent electronic devices, communication protocols, and SCADA systems are connected to an adequate time synchronization source and all devices display the correct date and time. ● Verify applicable communication points to end device(s). ● Verify transformers are in the correct DETC and LTC tap position(s) for energization. ● Verify and document correct start-up procedures on UPS and battery system components. ● Confirm batteries have been equalized and float charged in accordance with manufacturers’ requirements. ● Verify that indications and records are cleared for faults, alarms, and meters. ● Create as-left setting files. ● Submit test data, as built drawings and relay as left files to owner prior to energizing equipment. ● Create a written energization plan.

ENERGIZATION AND TRANSFER TO OWNER STAGE At this stage, the commissioning team completes the final inspections, energizes the equipment, monitors equipment, completes reports and transfers the facility to the owner or operator.

Energization ● Restrict access to the substation and components during energization and commissioning activities. ● Verify removal of temporary protective grounding equipment. ● Verify correct position of switches, circuit breakers, and transfer switches for control circuits, instrument transformer circuits, and power circuits. Verify test switches and terminal block disconnects/switches are in the correct position in accordance with energization plan. ● Follow and document the steps of the energization plan. ● Verify correct current and voltage values to protective devices and metering.

● Verify current transformer circuits are complete and do not have an open-circuit. Shorting devices should be in the intended position.

● Verify correct operate and restraint values to differential protection.

● Verify instrument transformer tap connections are correct and match documentation, most current drawings, and protective device settings.

● Verify equipment phasing.

● Verify protective device settings are correct and match documentation, drawings, and engineering studies. ● Verify correct operation of applicable devices for protection and control schemes, SCADA, and communication protocols. ● Verify intelligent electronic devices, communication protocols, and SCADA systems properly trigger events and disturbance records.

● Verify correct system phase angle and sequence. ● Verify correct motor rotation for motors on electrical equipment and associated equipment. ● Verify transformer load tap changer and automatic voltage regulator operation. ● Verify battery and UPS systems are free of alarms and are in the specified operating mode. ● Verify monitoring devices are functioning properly. ● Verify no alarms or fault indications are present.

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● Obtain post-energization oil and gas analysis on applicable devices.

Applicable equipment manuals and operational instructions shall be readily available for the owner and operator.

● Create and submit NERC compliance and any regulatory requirement reports (NERC requires this within 30 days of energization).

SUMMARY

● The manufacturers of installed equipment should be notified of the actual energization date for warranty purposes. ● Perform thermographic survey of equipment. ● Monitor equipment loading and compare to design criteria. ● Complete commissioning report and supply documentation.

TRANSFER TO OWNER/OPERATOR ● A formal and documented turnover of the project and the facility shall be performed. ● The operator receiving the turnover shall be informed of any outstanding deficiencies and any abnormal operating conditions. ● The turnover shall include all documentation, drawings, and operational responsibilities required. ● All contractor locks shall be removed from the facility and the operator place locks where required.

DOCUMENTATION The commissioning organization shall furnish a copy or copies of the complete documentation as specified in the commissioning contract. The commissioning documentation shall include the following: Report ● Summary of project. ● Description of electrical system. ● The final commissioning plan and the results of the implementation of that plan. ● A copy of the commissioning design review records and logs and submittal review logs. ● A complete copy of the testing and performance test forms. ● Identification of systems or assemblies that do not meet the owner’s project requirements. ● Analysis and recommendations. ● Resolution plan for incomplete tasks. ● As-left relay logic diagrams and setting files. Drawing packages ● All applicable drawing packages shall be as-built. ● A complete as-built drawing package shall be left on site and a duplicate as-built package shall be submitted to the owner/operator.

One of the more common problems found during energization or system loading is the misoperation of differential protection. If the equipment was only acceptance tested and the components tested individually without looking at the protection system as a whole, it would be easy to miss a design error or setting error especially on more complex protection schemes. This can be easily avoided with proper commissioning. Simple primary injection tests of differential protection circuits will verify correct connection and settings of the protection scheme. By defining the commissioning process, the NETA ECS will help guide the owner and the commissioning team to work together to develop the OPR, BOD, and commissioning plan. It is important to note the commissioning work starts early in the project and continues throughout the project. Fundamental documents such as the OPR and BOD, are valuable tools that should be the focus of commissioning tests. So whether you have a low-voltage, medium-voltage, or high-voltage electrical power system, it should be part of the project plan to create a commissioning team early in the project and include specifications for both acceptance testing and commissioning to assure safe and reliable performance of your electrical system. Lorne Gara is a Technical Manager for Orbis Engineering. He provides technical support for the engineering, field services, and automation departments of Orbis and many of its Clients. Lorne has a wide range of experience in engineering, commissioning, maintenance, fault analysis, and start-up of utility and industrial power systems across North America. He has extensive experience with protective relay setting development, commissioning, and testing protection and control systems. Ron Widup is the CEO of Shermco Industries in Dallas (Irving) Texas and has been with Shermco since 1983. Shermco provides electrical power system testing, maintenance, commissioning, engineering, and training in the United States and Canada as well as electric rotating machinery remanufacturing and service. Ron has a degree in Electrical Power Distribution from Texas State Technical College in Waco, Texas. He is a NETA Certified Level IV Senior Test Technician, State of Texas Journeyman Electrician, a member of the IEEE Standards Association, an Inspector Member of the International Association of Electrical Inspectors, and an NFPA Certified Electrical Safety Compliance Professional (CESCP).

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PRE-JOB BRIEFINGS: AN INDISPENSABLE SAFETY TOOL NETA World, Fall 2016 Issue By Paul Chamberlain, American Electrical Testing Co., Inc. Protection from hazards always begins with proper prior planning. An important aid to planning a job correctly and thoroughly includes using a tool known throughout the industry as a pre-job briefing (PJB). These tools are commonly called tailgates or tailgate meetings in construction parlance, but no matter what they are called, they are designed to do the same thing: identify relevant hazards on the jobsite or during performance of a task and communicate those hazards to all persons on the job who may be affected. Per the NFPA 70E 2015, Standard for Electrical Safety in the Workplace, Article 110.1(H) clarifies when a job briefing should be conducted: Before starting each job, the employee in charge shall conduct a job briefing with the employees involved. The briefing shall cover such subjects as hazards associated with the job, work procedures involved, special precautions, energy source controls, PPE requirements, and the information on the energized electrical work permit, if that might affect the safety of employees occur during the course of the work. The NFPA also includes a sample Job Briefing and Planning Checklist under Informative Annex I (Table 1). Although this specific form is not required, a similar form should be created to aid the employee in the identification and mitigation of potential hazards.

Identity

Hazards Voltage levels involved Skills required Any “foreign” (secondary source) voltage source ❏ Any unusual work conditions ❏ Number of people needed to do the job ❏ ❏ ❏ ❏

Ask

❏ Can the equipment be de-energized? ❏ Are backfeeds of the circuits to be worked on possible?

Check

❏ Job plans ❏ Single-line diagrams and vendor prints ❏ Status board ❏ Information on plant and vendor resources is up to date

Know

❏ What the job is ❏ Who else needs to know — Communicate!

Think

❏ About the unexpected event... What if? ❏ Look — Tag — Test — Try ❏ Test for voltage — FIRST ❏ Use the right tools and equipment, including PPE

Prepare for an emergency ❏ Is the standby person CPR trained? ❏ Is the required emergency equipment available? Where is it? ❏ Where is the nearest telephone? ❏ Where is the fire alarm? ❏ Is confined space rescue available?

❏ Shock protection boundaries ❏ Available incident energy ❏ Potential for arc flash (Conduct an arc flash hazard analysis.) ❏ Arc flash boundary

❏ Is a standby person required?

❏ Safety procedures ❏ Vendor information ❏ Individuals are familiar with the facility

❏ Who is in charge

❏ Install and remove temporary protective grounding equipment ❏ Install barriers and barricades ❏ What else...?

❏ What is the exact work location? ❏ How is the equipment shut off in an emergency? ❏ Are the emergency telephone numbers known? ❏ Where is the fire extinguisher? ❏ Are radio communications available?

Table 1: Sample Job Briefing and Planning Checklist Source: NFPA 70E 2015, Article 110.1(H), Informative Annex I

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Even the Occupational Safety and Health Administration (OSHA), under 29 CFR 1910.269 - Electric Power Generation, Transmission, and Distribution Standard, specifies the requirement for a PJB.

performer, it is hard to develop a form that encapsulates all of those needs. The employer should be able to identify which hazards are greatest or are a more pressing need to address within the workforce, and develop a PJB adequate enough to identify those hazards.

● 1910.269(c)(1)(i): In assigning an employee or a group of employees to perform a job, the employer shall provide the employee in charge of the job with all available information that relates to the determination of existing characteristics and conditions.

One item of concern that should be addressed in every PJB is the need to identify the means of preventing the inadvertent or unexpected release of electrical energy. Since that is one of the greater and most prevalent hazards within the testing industry, it is also a good idea to identify how it will be controlled. Whether it is controlled via individual lock out/tag out, switching and tagging, live-line clearances, and/or the use of grounding, it should be indicated on the PJB. Additionally, it is wise to allow the performer a space within the form to indicate lock or tag or ground locations to ensure the proper removal when the work is completed.

● 1910.269(c)(1)(ii): The employer shall ensure that the employee in charge conducts a job briefing that meets paragraphs (c)(2), (c)(3), and (c)(4) of this section with the employees involved before they start each job. OSHA also requires that the PJB cover “hazards associated with the job, work procedures involved, special precautions, energy-source controls, and personal protective equipment requirements.” Additional PJBs may be required should the task or workplace location change significantly enough to change the hazards involved in performing the work. The more potential hazards, the more detailed the PJB should be. Additionally, more extensive PJBs may be required for inexperienced employees. The only time a PJB does not need to be conducted, per OSHA 1910.269(C)(5), is if an employee will be working alone. It states: “However, the employer shall ensure that the tasks to be performed are planned as if a briefing were required.” OSHA’s website, under its e-tools, suggests that a checklist be used to facilitate the PJB: Keeping a written record of job briefings is not specifically covered by the standard, but it is a best practice to do so. A written checklist can include the hazards, procedures, precautions, and PPE requirements associated with a job, as well as a column for employee signatures indicating they are knowledgeable about job hazards and safety procedures. Such documentation can help ensure that proper briefings are held at the right times (for example, beginning of a shift) and that everyone has been informed. For an example checklist, see the Job Briefing and Planning Checklist in Annex I of the National Fire Protection Association’s NFPA 70E, Standard for Electrical Safety in the Workplace, 2004 Edition. As seen in this quote, even OSHA refers back to the sample PJB in the NFPA 70E. PJBs come in a variety of versions and styles. They come from utilities, large manufacturers, and from individual testing companies. All of them are designed to do one thing, and they do it fairly well: They aid the task performer(s) in identifying and minimizing risks associated with the hazards of performing the task. Some PJBs focus strongly on physical hazards, others focus on task-specific procedures, and some help identify human-error traps. Since a PJB is designed to be a quick and simple-to-use tool for the task

Addressing and indicating the limited, restricted, and arc-flash boundaries on the form is also recommended. This will make it easier for performers to advise visitors to the work location of the various approach distances. Additionally, the hazard/risk category level, PPE level category, and any additional PPE required to complete the task should be indicated on the form. The person in charge who fills out a PJB form should review all hazards with the performer(s) of the task and give them ample opportunity to ask questions. A PJB should be a give-and-take discussion, not a dictation. The review of the PJB should be conducted with all personnel who may be affected by task performance or with anyone else whose work may impact the task. This includes contractors, subcontractors, and peripheral workers on the jobsite. Once the review is complete, the names of all persons attending the PJB review should be noted. It may be as simple as printing each name on the PJB itself, or the PJB may have a separate signin sheet. Should the task or the job location significantly change, a new PJB or review/amendment of the old PJB form may be necessary. Should a visitor arrive on-site, they should be immediately stopped from encroaching upon the work area, and the PJB should be discussed, apprising them of the potential hazards on the job site. Identifying and mitigating potential job hazards is important in the prevention of possible injuries or accidents. It is up to the employer to provide an adequate means of identifying and addressing those hazards. A PJB form is required in most cases, and is an easy and effective means of identification. The employer should ensure it is adequate for the tasks the employees will be performing, and the employee should use the provided form to help prevent potential injuries. Should an employee have suggestions on improving the form, they should voice those suggestions to the employer. After all, it is the employee’s form to use. Paul Chamberlain has been the Safety Manager for American Electrical Testing Company Inc. since 2009. He has been in the safety field for the past 12 years, working for various companies and in various industries. He received a Bachelor’s of Science degree from Massachusetts Maritime Academy.

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FIRST RULE OF TROUBLESHOOTING: TRUST, BUT VERIFY NETA World, Winter 2016 Issue By Don Genutis, Halco Testing Services It can be difficult to piece together a puzzle when troubleshooting — but when the information provided by the client is incomplete or just incorrect, the task is even more difficult. As we began our ascent up the steep, winding, two-lane mountain road, we were already 30 minutes late due to circumstances beyond our control. We were on our way to a remote, high-power radio broadcasting tower to troubleshoot a problem when our technician stated, “I probably should have gotten gas back there in that little town.” Our destination was another 25 miles away. Going back to the town would put us another 30 minutes behind schedule; however, based on the fuel-gauge level, it was a reasonable assumption that we would make it to the job site and back to town later, so we pushed on. This adventure actually began the evening before when we received a call from a customer requesting help to troubleshoot his Automatic Voltage Regulator (AVR). Because we were unfamiliar with this apparatus, we did an Internet search and found some information about AVRs. Though there wasn’t much, at least we found enough to gain a better feel for the equipment. One photo online showed three motor-operated variacs connected to a three-phase isolation transformer and three single-phase buck/ boost transformers. Essentially, an AVR’s job is to provide a stable output voltage. In this particular case, the load primarily consisted of the 30kv transmitter with a couple of additional minor loads. Considering that the customer is at the very end of a long, rural overhead distribution line, voltage regulation along with emergency power is a necessity. When we arrived at the customer’s site, we looked past the mammoth radio towers and had a tremendous view of the sprawling Los Angeles basin. After a deep breath, it was time to meet our customer. Our new customer was a likable guy with a great deal of knowledge and experience with keeping the station operational. We quickly learned that much of the basic troubleshooting was complete, and there wasn’t much information to go on regarding possible causes of the problem. Essentially, a utility event tripped a circuit breaker on the critical load panel, and now, the AVR did not function properly under load. The voltage was fine without load. Upon removing the apparatus covers, we were pleased to see that the basic component layout closely resembled the Internet photos. Almost immediately, we spotted six large fuses that seemed to be associated with the variacs. Our customer informed us that he had

already checked all of the fuses. In most cases, checking the fuses and incoming power is the first rule of troubleshooting. We began operating the variacs manually, checking voltages, applying load, and then finally speaking to the manufacturer. The manufacturer provided great support, and after being brought up to speed, asked if we had checked the fuses. We replied that they were checked by the customer, and the manufacturer suggested other checks. We dug deeper, but no problems were uncovered. What initially may have been a microprocessor problem now began to look like an isolation transformer failure. We determined that removal of the six variac fuses would provide good isolation for the connection of our test equipment. Our technician removed the fuses and found that all six fuses were blown. Problem solved. We all had a good-hearted laugh with the customer, wrapped up, and proceeded down the mountain and off to the next adventure. By the way, we did make it back to town for gas. Troubleshooting is often performed while the equipment remains energized. As always when troubleshooting, first adhere to proper safety procedures. The customer’s explanation of the problem usually provides valuable key facts that help point the troubleshooting technician in the right direction. Before going too far down the wrong path, it’s best for the technician to first verify everything, which is the basis for the first rule of troubleshooting. Always remember that the customer may not be 100 percent accurate with either recollection of the failure events or their initial troubleshooting results. Oh, and the second rule of troubleshooting: Always remember to check the fuses twice. Don A. Genutis holds a Bachelor of Science degree in Electrical Engineering and has been a NETA Certified Technician for more than 15 years. He has held various principal positions during his 30-year career in the electrical testing fieldand has primarily focused on advancing no-outage-testing techniques for the last 15 years. Don presently serves as President of Halco Testing Services in Los Angeles, California.

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DISTRACTED DRIVING NETA World, Winter 2016 Issue By Paul Chamberlain, American Electrical Testing Co., Inc.

In this day of modern technology, it is easy to get overwhelmed with the number of distracting devices in our world, and these devices are encroaching upon the driving environment. Cell phones are an awesome way to communicate over long distances, but couple them with texting, email, Internet, and mobile video or audio, and they are an absolute attention grabber. Smartphones can be coupled with hands-free Bluetooth devices that allow a driver to talk with limited interaction, and they can display directions when used as a GPS. However, even when using these safer methods of interaction, they divert the attention of the driver from their primary task — driving a vehicle. Cell phones aren’t the only distractions inside a vehicle. People still eat or drink while driving, play with the radio, read papers or magazines, talk on CB radios, and perform personal grooming like shaving or brushing their hair. It is amazing what people will do while driving and the risks they are willing to accept.

LATEST INFORMATION ON DISTRACTED DRIVING The National Highway Transportation and Safety Administration, which is part of the United States Department of Transportation, has created a website for distracted driving information at www.distraction.gov. It is loaded with statistics and information that can be disseminated to co-workers, teen drivers, and used by employers for employee distracted-driving awareness training. Here are some key facts and statistics from that website: ● In 2014, 3,179 people were killed and 431,000 were injured in motor vehicle crashes involving distracted drivers. ● As of December 2014, 169.3 billion text messages were sent in the U.S. (includes Puerto Rico, Guam, and the Philippines) every month. ● Ten percent of all drivers age 15 to 19 involved in fatal crashes were reported as distracted at the time of the crash. This age group has the largest proportion of drivers who were distracted at the time of the crash. Drivers in their 20s are 23 percent of drivers in all fatal crashes, but are 27 percent of the distracted drivers and 38 percent of the distracted drivers who were using cell phones in fatal crashes. ● The percentage of drivers text messaging or visibly manipulating handheld devices increased from 1.7 percent in 2013 to 2.2 percent in 2014. Since 2007, young drivers (age 16 to 24) have been observed manipulating electronic devices at higher rates than older drivers.

● At any given daylight moment across America, approximately 660,000 drivers are using cell phones or manipulating electronic devices while driving, a number that has held steady since 2010. ● A 2015 Erie Insurance distracted-driving survey reported that drivers do all sorts of dangerous things behind the wheel, including brushing teeth and changing clothes. The survey also found that one-third of drivers admitted to texting while driving, and three-quarters say they’ve seen others do it. ● Five seconds is the average time your eyes are off the road while texting. When traveling at 55 mph, that’s enough time to cover the length of a football field blindfolded. ● Smartphone ownership is growing: In 2011, 52 percent of drivers reported owning a smartphone; by 2014, that number had grown to 80 percent. The greatest increases in smartphone ownership are among adults age 40 and older.

HOW EMPLOYERS CAN REDUCE DISTRACTED DRIVING Employers are certainly not powerless to prevent distracted driving by employees on company time or in a company vehicle. The U.S. DOT encourages employers to create a distracted-driving policy, and will provide videos, posters, and sample policies to encourage better driving habits. Hands-free technology can be provided for employees, or it can be encouraged to purchase it. First, however, be aware of which states allow the use of such devices. See Figure 1 on the next page for more information regarding hands-free device use and texting bans or allowances. There are many things that can divert a person’s attention while driving, and in this digital age, the cell phone is probably the most prevalent. Communicate with employees about distracted driving and follow your state laws. Make it a point to be a better, more attentive driver, and you should realize improvements in your own driving ability and safety. Paul Chamberlain has been the Safety Manager for American Electrical Testing Company Inc. since 2009. He has been in the safety field for the past 12 years, working for various companies and in various industries. He received a Bachelor’s of Science degree from Massachusetts Maritime Academy.

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Fig. 1: State laws govern cell-phone use and texting while driving.

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TEST EQUIPMENT: MANAGING THE HIDDEN DEFECTS NETA World, Winter 2016 Issue By Ashley Harkness, Emerson Electrical Reliability Services You are testing a modern, digital protective relay. Your testing device is a modern, top-of-the-line, computer-driven, digital relay test set. The reliability of the protected power system is on the line. You think that your test equipment is at 100 percent. Then, in the middle of the job, it fails. Could this have been avoided? Perhaps it could. In this article, we will consider test equipment condition issues, steps to reduce their unplanned outage, and ways of managing test equipment’s hidden effects.

THE CHALLENGE OF REAL LIFE In the real-life rush to get to the job, do we give our test equipment a good look over? NFPA-70E requires handheld test equipment to be inspected before use. The reason is simple: If there are broken test leads, damaged probes, or cracked meters, you might have a serious safety issue on your hands. The same goes for more costly and important capital equipment. Many of the newer test equipment devices are highly reliable, computer-driven instruments. They are designed to perform complex testing such as on protective relays. Left undisturbed on a lab bench in a clean, warm, safe environment, they are expected to perform well for many years. However, is that how a testing company actually uses them? Is the actual field environment safe and warm? Perhaps not. A typical field scenario might go like this: Test equipment is manhandled into the back of a bouncing pickup truck; driven to the job site over rough construction roads; connected to a noisy, erratic generator; and carried from location-to-location or pushed on a stiff-wheeled, jolting cart. This environment can really shake things up! After over 40 years repairing test equipment, I have learned a few simple rules: Shake up the equipment and it will fall apart. Loose screws and hardware, disconnected cable assemblies, broken switches, jammed relays, and broken internal wires are very common; in fact, 95 percent of repairs are mechanical in nature. Mechanical degradation is the killer of test equipment. And there are other issues to consider: What about those instrument cooling fans that suck in all manner of dirt and bugs? Is this another recipe for future trouble? You can bet on it. Dirt can be very conductive. Combined with high humidity, internal tracking and short circuits can kill your equipment. What about bugs? Consider spider webs inside your expensive test set — not to mention the surprise as their eggs, hatching at your job site, flood your work area with hungry, active baby black

widow spiders. Bugs can also damage insulation. They can slime their way around inside the equipment, leaving nasty substances on circuit boards with serious consequences. If it can fail, it will fail — always when least expected and when needed most. What is a testing company to do? Simple applications of the same skills we bring to the job are the first line of defense. ● Look at the test equipment. Inspect it regularly. Anything out of the ordinary is a sure clue. Are all the handles, knobs, and other mechanical parts complete, secure, and intact? If not, report it. ● Listen for strange noises when you pick it up or move it. Loose hardware will talk to you if you listen. That is a signal to check it out. ● Check for proper accessories. A missing power cord, test leads, or programmer dongle will mean delays as replacements are sought. ● Make sure the manufacturer’s instruction manual is with the equipment. There are too many stories of test equipment not working, only to find that instructions were not followed. Instruction manuals have the parts list and, more important, the manufacturer’s contact information. ● Encourage notification from your team when an instrument is suspicious. Back on the shelf for another team member to grab later is not the correct procedure. ● Do not blame people for damage or breakage unless it is a clear habit. Instead, concentrate on finding and solving the problems.

SERVICE-TO-SERVICE PROVIDERS Talk to your instrument calibration/maintenance service providers. They are test instrument experts and will tell you if significant changes are occurring. We often forget that while we deliver service to our clients, we need their service, too. Our calibration vendors are our partners in our ultimate success. They need to better understand our needs. Does your commercial calibration laboratory understand your harsh work environment? They will often calibrate your equipment, find it working properly, and return it to you. Internal inspection is not always a standard procedure. Remember that they, too, are in a competitive business where extra effort means extra cost.

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Safety Vol. 1 You may need them to routinely open and complete an internal inspection. They can clean it out and look for obvious defects. This is the same as lifting the hood of your truck to inspect the engine. This may only be appropriate for limited equipment in your inventory, but the cost of this ounce of prevention will be cheaper than having equipment fail on the job site. During the vendor visit, ask a few other related questions: ● Does the calibration service use manufacturer’s specifications and procedures or produce its own? Often, even the manufacturer’s information is sparse and lacking detail or full testing requirements. Your provider can make necessary provisions. ● Does the calibration service test each function of the test equipment? In some cases, the proper operation of mechanical switches and lamps is as important as the accuracy of the metering. This is especially true for test sets that test circuit breaker trip units. Communication is the key. If they do not know your needs, will this service be provided? Probably not.

RECORD KEEPING We know from wide experience in the electrical maintenance and testing industry that all systems, electronic and mechanical, will age and degrade over time. Similarly, we need to track changes in our test equipment. ● Do you keep the maintenance history of your test equipment? Repair orders and calibration certificates are critical. With them, the insight to the future serviceability of equipment can be revealed. When more repairs are needed or increasing close-to- or out-of-tolerance conditions are found, a replacement decision must be made. Review the records on a frequent basis. ● Too often, we continue to use obsolete test equipment long after its day is done. Yes, I have a beloved, old-friend analog meter, too. And, in some rare situations, it is the correct tool. However, we need to focus on technology changes. Sometimes, that means sending our old friends out to pasture. Records will give us the information we need to make even these tough decisions. Say goodbye, and purchase new equipment. ● If new technology requires more training, keep records. OSHA clearly states that if there is no paperwork, i.e. records, it did not happen. No records may lead to increased liability. Records can be easily kept electronically. They may also be required by clients as part of a bid package. Attention to test-equipment recordkeeping is an important part of the service that we, as testing companies, provide to our clients.

CONCLUSION Our ability to continue providing successful service to our clients depends on how we maintain and service our tools. Improving test-equipment reliability is a matter of observation and communication. Make sure to give your test equipment the inspections it needs. Make sure to communicate your expectations and needs to company users and service vendors. Keep good records. Take proactive steps. It is the best way to manage the hidden defects of your test equipment. Ashley Harkness, Jr. is an Electrical System Specialist at Electrical Reliability Services. He joined the company (then known as Electro-Test, Inc.) in 1982. Until 2013, his duties included operation and management of the internal calibration laboratory program. During these years, he also managed the manufacturing department making specialized test equipment and led specialized electrical projects including European Community Machinery and EMC Electromagnetic Compatibility Directive testing, basic insulation level (BIL) impulse testing, process and control instrumentation acceptance and testing, electrical equipment forensic investigations, and electrical product safety testing. In 2005, Ashley became manager of the ERS medium-voltage systems (switchgear and cables) on/off line partial discharge/cable testing program. In 2014, his assignment changed to NFPA 70E trainer for ERS client organizations and internal training.

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BELIEFS DRIVE BEHAVIORS PowerTest 2016 D. Ray Crow, Senior Member, IEEE and Danny P. Liggett, Senior Member, IEEE

ABSTRACT For more than 50, years research has shown that a correlation exists between the number of incidents, injuries, and fatalities. Investigation into electrical incidents indicates there is more to understand about the causal effect of the number of incidents occurring. Many electrical incidents are caused by undesirable actions of people. These are called unsafe acts. Why do people perform unsafe acts? Lack of experience, knowledge, or skills often come into play. What people believe about safety is another important component. The intent of this paper is to explore these relationships and to focus on unsafe behaviors and beliefs about safety. By investigating and using the actions outlined in this paper fewer incidents will occur resulting in a decrease in injuries and fatalities.

As shown in Fig. 2 “Elements of Human Performance”, there are three primary things that impact what people do. What they know, the level of their skill, and their willingness to do it1. The lack of skill, experience or knowledge has been a significant factor in every incident investigation in the past couple of decades. To improve personal safety employees require continuing knowledge and training to perform their tasks in a safe manner.

Index Terms – Beliefs, Behaviors, Electrical Safety

INTRODUCTION Fig. 1 “Incidents Lead to Fatalities” shows the relationship between incidents, injuries, and fatalities. Understanding the behavioral-based components involved when incidents occur is important information to study to change the safety culture. This element of study has been missing from the data available to assist in improving workplace safety. Most often, this type of information has never been compiled and reviewed.

Fig. 2: Elements of Human Performance What is typically ignored is what people think and believe about the standards and procedures they are asked to follow. More time and focus on understanding why people resist accepting new requirements needs to be explored2. Every person has thoughts about the things they are asked to do. One common factor not recognized is everything we see, read and hear is filtered through our beliefs. At least one other filter applies and that is experience. Experience plays a significant role in what people tend to accept. Dr. Mary Capelli-Schellpfeffer told the authors, “We can perceive only what we experience.” Everyone molds information that is received into an understanding that fits into his or her previous experience. In some instances, the information is completely new and cannot be molded into previous experience. When that happens, a person’s basic beliefs and principles play a role in how the person interprets the data.

Fig. 1: Incidents Lead to Fatalities

Neuroscience tells us everything we can know is our version of it3. We try to make our experiences and what we see, read and hear fit into “our world”. “Our world” is built around our beliefs. We seek information that aligns with what we already believe and

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Safety Vol. 1 discount or ignore information that goes against what we already believe, a process called “confirmation bias”. So strong is this bias that we are unable to pay adequate attention to information that goes against our beliefs even when enticed by monetary incentives4 or evidence that blatantly disconfirms our position5. This can, and many times does, lead us to interpret standards and procedures differently from other people when we read them. We also do this with what we see. Two people can watch an event and will have different understandings of what occurred. As you read this paper you will most likely have a different understanding of the material from what the authors intended. You will filter the material through your beliefs and experiences. Most people arrive at work with the intention of doing a good job, doing the right things and being a productive employee. People do what they believe is the right thing to do based on their experiences and beliefs. What needs to be explored and understood is what people believe about safety and how to influence those beliefs.

How Do They Impact Performance? A lot of time is spent identifying unsafe acts and not enough time is spent on why people choose to perform unsafe acts. Unsafe acts or inappropriate behaviors contribute to incidents and injuries. It is estimated that 91% of incidents are caused by inappropriate behaviors6. Unsafe acts and inappropriate behaviors are key areas that need attention. Fig. 3 “Behavior – A Leading Indicator for Safety”6 provides another layer to the chart shown in Fig. 1. This does not mean that the incidents are the fault of the employees. Equipment can fail and set up a situation or an unsafe condition where an employee can be injured as a result of this failure if the condition is not recognized. An example of this is a disconnect switch where all of the blades failed to open. Failure to test for the absence of voltage has contributed to numerous incidents, injuries and fatalities.

It is important to understand that different experiences and beliefs exist in every person at every level of an organization. The beliefs of management will drive behaviors that may create some of the issues causing incident rates to remain high. For example, an emphasis on meeting deadlines can be perceived to be more important than safety.

BEHAVIORS What Are They? Behaviors can be defined in many ways. Behaviors of people can be observed. They are actions that people do or do not do. Some examples of behaviors are: testing for the absence of voltage, wearing voltage rated gloves while testing for voltage, and wearing your seatbelt while driving or riding in a vehicle. If we perceive people in this way (as a collection of responses to a collection of stimuli), it fosters an understanding that behavior is predictable and thus changeable. We just have to understand how to do it. Not taking appropriate actions is also a behavior. Not wearing your seatbelt or failing to test for the absence of voltage are also behaviors. In either context inappropriate behaviors are called unsafe acts. Observation data related to behaviors that was not recorded previously is a new way to find your leading indicators of possible incidences. Collecting and reviewing multiple behavioral actions is valuable to locate beliefs about safety that are impeding the implementation of a new or changed safe work practice. The importance of collecting and reviewing behavior-based data on an on-going basis must be stressed within organizations. Behaviors will tell you what people believe.

Fig. 3: Behavior – A Leading Indicator for Safety When incidents occur there is generally something missing in the company’s safety program. Placing blame for the incident on the employee is a behavior that managers or supervisors might take. Safety supervisors should focus efforts on root cause analysis with employee involvement to solve safety issues. Fault finding or placing blame for an incident is the weakest form of changing behavior. The effect of placing blame usually teaches people to understand that they should not get caught6. Fault finding or placing blame has little to do with changing beliefs or behaviors. Incidents, injuries and fatalities are typically the consequences of inappropriate behaviors. We need to understand what behaviors are occurring, both appropriate and inappropriate. But we need to continue to move upstream and get into leading indicators. In order to move upstream we need to understand why people engage in inappropriate behaviors.

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What Drives Behaviors?

BELIEFS

The prevention of electrical incidents and injuries is hampered by the attitude that “Good workers don’t get hurt”7.

What Are Beliefs?

Even the most qualified and experienced person makes mistakes in the workplace. Thankfully, most mistakes do not result in injury. What we learn from these mistakes are a part of our experiences. Our experiences play a large role in driving beliefs and behaviors. All behaviors are either intrinsically driven or extrinsically driven8. Intrinsically driven behaviors come from our internal beliefs. If we believe that seatbelts will save our lives or prevent injury we will use them. If we don’t believe in seatbelts, we won’t wear them. Section III will cover, in more detail, how beliefs impact our behaviors. Abraham Maslow developed the Hierarchy of Needs9, and it has been used to help understand people’s behaviors. See Fig. 4 “Maslow’s Hierarchy of Needs”.

Beliefs are a conviction of the truth of something. This is derived from consideration or examination of the evidence available to us. It is a mental attitude of acceptance toward a proposition10. It is an opinion. A person can and often does accept an idea as the truth based on the person’s experiences and knowledge. If the idea is work related, then experience plays a significant role in how a worker’s belief is generated. An example of an old belief that changed through experience was the belief that the world was flat. This belief was based on the existing evidence available at that time. This belief changed as new experiences proved the world was round. A more recent example is the arc flash phenomenon associated with electricity. There are still people who do not believe that this is a hazard or that an arc flash will ever happen to them. So they believe they do not need to take any action, such as putting on arc flash PPE. The lack of experience often leads to the lack of belief in a rule or requirement related to safety. Therefore, a person’s belief may lead to the rule or requirement being ignored or not followed.

Where Do Beliefs Come From?

Fig. 4: Maslow’s Hierarchy of Needs Sometimes our needs and beliefs are aligned. When this occurs then our behaviors are intrinsically driven. When our needs and beliefs are not aligned, then our behaviors become extrinsically driven. It is important to understand that our “needs” can have more of an impact on our behaviors than our beliefs. An example of this extrinsically driven behavior is peer pressure. Our desire to “fit in” can overrule even our own natural internal sense for being safe. Extrinsically driven behaviors are usually driven from needs or from people following requirements that are imposed upon them. They may not necessarily believe that is it the right thing to do or they may not want to do it. They engage in these behaviors because it is necessary to keep their job or get a raise. Extrinsically driven behaviors are unreliable and intermittent and may not be performed at 2 a.m. when no one is around.

From the moment we are born, we begin to have experiences. As we collect these experiences, we begin to form beliefs. We touch the hot stove and get burned. We make a connection between the hot stove and getting burned. Our belief becomes that we should not touch the hot stove and if we do we will get burned. When we go to school, teachers begin to provide us with knowledge and our classmates give us new experiences. We go out into the world and have experiences. Listening to the news on TV or the radio provide us with different opinions. We take all of this information and we build beliefs. Each of us will have different experiences and this knowledge will drive us to create different beliefs. The social culture we experience impacts our beliefs. What may be acceptable in one culture may not be acceptable in another culture. Cultures exist at multiple levels. A culture can exist in a country, a state, a city or even in the electrical shop at a facility. These cultures impact our beliefs. To some degree, we will adopt the beliefs of the culture we are in. Sometimes this acceptance is immediate and some times it takes time to alter our own belief system. An example of this is that welders believe that getting shocked is just part of the job. It is a culture that has existed in the welding community for so long that shocks are not reported and continue to be ignored The environment we are in also impacts our beliefs. While culture and environment can be related they are different. The culture has more to do with the values of the people. The environment relates more to the physical environment we are in. For example, good housekeeping and safety go hand-in-hand. If we are assigned

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Safety Vol. 1 to a clean environment we will find ourselves behaving in a safe manner to maintain that environment. Conversely if we find a disorganized, unclean environment, we may adopt the belief that it is acceptable to have disorganized environments. The environment may have created a belief that drives a behavior of carelessness. These three things, experiences, social culture and environment, all impact our beliefs. Collectively, these concepts constitute a worker’s experience. These concepts on a work site are likely different from the person’s off-site experience. Two beliefs might be maintained as they are in different environments. People are likely to follow safety rules at work but may ignore them in the home environment even though the hazard is the same. For example, ladder safety, eye protection, hearing protection, etc. Connections about the hazard being similar or the same can be missed as there may be no job briefings, training, or discussions taking place at home.

How Do Beliefs Impact Behaviors? The relationship between beliefs and behaviors is like a tree. You see the leaves (behaviors) but not the roots (beliefs)11,12. Similarly, beliefs and behaviors are much like an iceberg, where most of the iceberg is below the surface of the water, beliefs are not visible. As mentioned before, if we do not believe that a requirement or an appropriate behavior has any value then we will not perform that behavior unless we are forced to. While we are being watched we will perform that behavior. But it is unlikely that we will perform the appropriate behavior if we think we can get away with not doing it. Why? Because we do not believe it is necessary or has any value. It is not about being lazy or a lack of regard for the rules, it is about what we believe. One example of a belief impacting behavior is using voltage rated gloves. Many electricians do not think they are necessary. When asked why, several common responses are heard. “I have been doing this for 25 years and I never needed them.” “I am not touching anything hot so I don’t need them.” “Good electricians don’t need them.” All of these reasons are based upon their belief. Their experience has reinforced their belief that gloves are not necessary. Beliefs will drive a person to make a decision that will either be an appropriate behavior or an inappropriate behavior. See Fig. 5 “Beliefs Drive Behaviors”.

Fig. 5: Beliefs Drive Behaviors If an inappropriate behavior is chosen, then it becomes a roll of the dice whether an incident will occur. If an incident does not occur, then that result will reinforce the inappropriate behavior. As this cycle continues without adverse results it can easily become a belief and a habit. A habit is an acquired pattern of behavior that becomes almost involuntary or automatic. Under pressure or stress people will always default to their beliefs or habits regardless of procedures and training. Habits can be developed for appropriate behaviors in the same way. See Attachment A “Appropriate vs. Inappropriate Beliefs”, at the end of this chapter, for a model representing this process.

How Do Beliefs Change? Is it possible? Yes. Is it easy? No. Changing beliefs must follow certain steps. Some beliefs are so strong that people will cling to those beliefs at all costs. This needs to be considered when we set out to change a person’s beliefs and behaviors. John Maynard Keynes stated, “The difficulty lies, not in the new ideas, but in escaping the old ones.” We are resistant to change because it causes a change in our world and our beliefs. Telling people what to think will not change their beliefs13. We have to influence how they think and what they believe. Workers must be provided with some experience that challenges all previous experience. The trick then is to find that new experience and provide it to the worker. Consequences also drive beliefs and behaviors. It is important to understand what consequences are controlling behaviors. Soon, certain, and positive consequences are the most effective in driving our behaviors. Timing is important. A consequence that follows soon after a behavior will control behavior more effective than a consequence that may never occur. Consistency is also important. A significant consequence that is certain to follow a behavior con-

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trols behaviors more powerful than an uncertain consequence. The significance of the consequence plays a large role on behaviors. A positive consequence controls behavior more powerfully than a negative consequence6.

world. This is how we end up with different interpretations of the same concept, idea, or thought.

Management and peer pressure can set a positive (or negative) belief structure in an organization. A management system that accepts unsafe behaviors to get the job done can drive negative belief systems. A manager that rewards a person for getting a job done even though it is understood that unsafe behaviors were taken will influence workers to believe that taking short cuts with safety is acceptable. However, management that immediately addresses unsafe behaviors in the workplace will drive a positive belief system.

There are many thoughts and ideas on how to change people’s beliefs. One concept is storytelling. Stories attract attention and are easier to remember. People relate to stories. Stories impact us emotionally. If we can move the person’s heart, we can move their head14. Important information told through a situational story that explains the old conditions and introduces a new belief or desired outcome enables people to recall the information to mind. The story must be convincing and connect to recent situations clearly understood by the audience15. The desired change must have a worthwhile benefit and must be seen as possible. Telling a story is one way of providing a new experience for some workers. The story must align with the worker’s previous experience to be of value.

Peer pressure is one of the most powerful consequences that effect behaviors in an organization. Peer pressure offers soon, certain, and positive feedback that can and will effect beliefs and behaviors. The feeling that one is accepted by others in the workplace is a powerful factor in driving behaviors. A person’s acceptance in the work group may be more important to them than the possibility of injuries that may or may not occur due to evading or ignoring safety requirements. Ensure that employees are involved and participate in safety. Employee involvement in safety is a key element to developing a positive peer pressure that will not tolerate unsafe behaviors. All safety efforts that work, are effective because they influence employee behaviors6.

How the Brain Incorporates New Beliefs Our brain is made up of about 100 billion cells called neurons. All of these neurons make connections with other neurons. All in all the brain is capable of making 40 quadrillion connections. Each second our brain is creating new connections. As we have experiences, doing, seeing or hearing, our brain makes these new connections. As mentioned earlier these experiences become the basis for our beliefs. As experiences are repeated the connections for these become layered with additional connections, making these connections strong. In turn the beliefs become stronger and more powerful. Studies of professional athletes’ brains has shown that they use less “brain power” when playing than a normal person performing the same actions11. The reason for this is the repetition. Professional athletes practice these actions over and over so that the actions become an automatic habit or behavior. The repetition provides more experiences for the athlete and strengthens the connection in the brain.

Storytelling Method of Changing Beliefs

Autonomy, Competence, and Relatedness Method of Changing Beliefs Another concept discussed by both Edward Deci8 and Daniel Pink15 contains three elements; autonomy, competence, and relatedness. Each of these elements must be addressed in order to change a belief. Autonomy is about being involved and having influence on the outcome. It is not about allowing a person to do whatever they please. For some time now the concept of involving people in creating requirements has been used successfully. One of the principles put forth by Stephen Covey1, seek first to understand then to be understood, is an example of how one needs to understand the issues and concerns of people when implementing a new requirement. This is a form of supportive autonomy where people are engaged in the process. If requirements are not gaining support by the people who have to implement them, then they probably were not involved in creating the requirements. By engaging people in the process, we gain buy-in from the people who need to follow the requirements.

Changing Beliefs

Everyone wants to be recognized as being good at what they do. By encouraging people to be competent we are building understanding in what the requirements need to be. In doing numerous audits of facilities the authors have learned that one of our great failings is that we assume people already know what is required and why. This is simply not true. We need to constantly encourage learning and provide education to people to allow them to be competent.

Each of us build a mental representation of our own reality, our own world, based upon our beliefs. We try to fit what we see, read or hear into our world based on what we already believe. Sometimes the fit is not very good and we will have a tendency to reject any idea that does not fit into our world or belief system. If we do accept a new concept we may alter the concept to fit into our

As with storytelling, we need to build a connection with the current situation and provide a benefit to the requirements. People need to be able to clearly see a purpose in any requirement. The requirement needs to be directly connected to their job and to a goal. The goal has to be something they believe in. Safety is always important.

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Safety Vol. 1 Education and Training Method of Changing Beliefs Change is probably the only thing that is consistent in our world today. Codes are constantly being updated. New technology is being introduced. People will feel left behind if training and educating is not provided. Training may be required to take place in different forms. Some people learn best by reading or in a class room environment. Some people learn best by doing “hands-on” work. Ongoing training is mandatory in the workplace to stay on the leading edge of safety.

PEOPLE For the last couple of decades we have worked on safe work practice procedures and improving electrical equipment. Fig. 6 “Critical Elements of Electrical Safety”16 shows three critical elements for addressing electrical safety. However, the third critical element of “people” and their underlying safety beliefs have not been an area of focus and study. People are exposed to the electrical hazards and are involved in the incidents, injuries and fatalities. If the safety beliefs of people interfere with using the “improved equipment” or following the “best procedures”, then electrical safety performance will continue to suffer. Electrical safety performance will improve by focusing on the critical third element of “People”.

To understand what a worker believes, it is necessary to become familiar with the worker’s experience. For instance, to communicate with a worker about “hot work”, it is necessary to reach a common understanding of what the term means. A worker’s understanding of the term is almost completely dependent upon his or her previous experience. What people believe can be seen by observing their behaviors, even if the behavior is a non-action. Observations can help identify critical behaviors that are tied to a belief that leads to unsafe acts. These observations are leading indicators to show underlying or hidden beliefs that will counter the desired safe work practices. As seen in Fig. 2, the shift in “Will” is vital to accepting new beliefs, creating new knowledge, and building new skills. With new or changed beliefs, the behavior can now move from an extrinsic behavior to an intrinsic behavior. Step Two: Hold open discussions with all stakeholders. Include all organizational levels for acceptance of changes. Open discussions are critical in order to understand the counter currents to a new requirement12. By understanding these issues, changes in beliefs can begin. By openly addressing issues and beliefs with all levels of the organization, people will align more readily with the new requirement due to involvement and a deeper understanding. Step Three: Reinforce new beliefs and behaviors. Explain the value of new requirements. Once beliefs have been changed, they must stay in place. There has to be continuous reinforcement regarding the value of new requirements2. Job briefings, classroom training, hands-on training, storytelling and use of analogies all provide the reinforcement and strengthening that is needed. Similar to professional athlete training that builds strong connections and behaviors that lead to automatic habits, this level of safety behaviors and habits can be implemented into the workplace. Building and strengthening the connections in our brains through continual training and education will result in strong beliefs becoming intrinsic safe behaviors and leading to automatic safe work habits.

Fig. 6: Critical Elements of Electrical Safety

ACTIONS Steps to Changing Beliefs Step One: Understand people’s beliefs about safety. Only after we understand what people believe can we begin to impact those beliefs. Observe and record behaviors showing resistant beliefs. Don’t attempt to change every behavior. Pick the safety behaviors that are most critical for your company or site first, then move on to others.

CONCLUSIONS Making changes in electrical safety performance requires shifting beliefs about electrical safety and the work practices used. Understanding how to discover and then change beliefs of people is the key missing piece to improvement in electrical safety performance. Observing, compiling data, studying the leading indicators, implementing change through inclusive methods, and sharing a unified belief about Safe Work Practices will fill in this missing element. The next step change in electrical safety performance must address the safety beliefs of people. It takes time, but is time well spent. Workers must be provided with new experiences which

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they recognize as a benefit. In order to create an intrinsic reaction from people (one that they believe is the right thing to do), the beliefs and behaviors of people must be willingly changed. Consequences drive beliefs and behaviors. Soon, certain, and positive consequences are the most effective in driving our behaviors. Peer pressure is one of the most powerful drivers that effect behaviors in an organization. Employee involvement in safety is a key element to developing a positive peer pressure that will not tolerate unsafe behaviors.

8. Edward L. Deci, Why We Do What We Do, New York, NY, Penguin Group. 1996

Changing beliefs comes through study, measurement, including people, and evaluating results. Providing reinforcement for intrinsic safety behaviors will create the desired outcome of improved electrical safety performance.

12. Kerry Patterson, Joseph Grenny, David Maxfield, Rn McMillan, Al Switzler, Influencer, New, NY, McGraw Hill, 2008

Appropriate Behavior

Hierarchy of Needs

Nothing Happened

I/B Re-enforcement

En ro vi t en nm

Experiences

cia l

Beliefs So

11. David Rock, Quiet Leadership, New, NY, Haper Collins, 2007

13. John Maxwell, Thinking for a Change, New York, NY, Center Street

15. Daniel Pink, Drive, New York, NY, Riverhead Books, 2009

Behaviors

A/B Re-enforcement

10. Encyclopedia Britannica, Inc. Encyclopedia Britannica, Inc. 07 Nov. 2010

14. Peter Guber, Tell to Win, New York, NY, Crown Business, 2011

Inappropriate Behavior

Safe Execution

9. A.H., Maslow, A Theory of Human Motivation, Psychological Review 50(4) (1943)

Attachment A: Appropriate vs. Inappropriate Behaviors

REFERENCES 1. Stephen R. Covey, The 7 Habits of Highly Effective People, New York, NY, Fireside, 1990 2. Howard Gardner, Changing Minds, Boston, Massachusetts, Harvard Business School Press, 2006 3. Charles S, Jacob, Management Rewired, New York, NY, Penguin Group, 2009 4. Snyder, M., & Swann, W. B., Jr. (1978). Hypothesis-testing processes in social interaction. Journal of Personality and Social Psychology, 36, 1202–1212 5. Snyder, M., & Campbell, B. H. (1980). Testing hypotheses about other people: The role of the hypothesis. Personality and Social Psychology Bulletin, 6, 421–426 6. Krause, Hidley, and Hodson, The Behavior-Based Safety Process,1990 7. Dr. Mary Capelli-Schellpfeffer et al, “Correlation Between Electrical Accident Parameters and Sustained Injury”, IEEE PCIC Conference Record, 1996, Paper No. IEEE-PCIC-96-3

16. Danny Liggett, Refocusing Electrical Safety, in the IEEEIAS Transactions Sept/Oct 2006 Daryld Ray Crow (S’68, M’72, SM’03, LSM’07) graduated from the University of Houston in 1969 with a BSEE degree. After graduation Ray went to work for the Aluminum Company of America where he provided engineering support for Alcoa plants worldwide on the design, installation, and operation of power and rectifier systems, provided plant engineering support which included electrical safety, served as team leader for writing a number of Alcoa electrical standards including the development of and training for Alcoa’s electrical safe work practice standard. He retired from Alcoa in 1996. After retiring from Alcoa, Ray worked for Fluor Global Services and Duke Energy as a Principal Technical Specialist providing design and consulting electrical engineering for plant power distribution systems and safe work practice programs, standards, and assessments/audits. Ray presently is the Principal Technical Specialist for DRC Consulting Ltd. and performs consulting work on electrical safe work practices standards, assessments/audits, electrical safe work practice training, and electrical engineering projects. He was chair of the Petroleum and Chemical Industry (PCIC) Safety Subcommittee 2004-2006, chair of the 2004 IEEE IAS Electrical Safety Workshop, is an alternate member on the NFPA 70E technical committee “Standard for Electrical Safety in the Workplace”, a member of the IEEE 1584 Committee, and was the working group vice chair for the 2007 revisions to IEEE 463 “Standard for Electrical Safety Practices in Electrolytic Cell Line Working Zones”. Ray has co-authored and presented papers and tutorials on electrical safety and auditing for the PCIC and has presented safety topics and tutorials at the IEEE Industry Applications Society Electrical Safety Workshops and IEEE IAS Pulp and Paper Industry Conference. In 2010 Ray received the IEEE IAS Petroleum and Chemical Industry Committee Electrical Safety Excellence award.

Safety Vol. 1 Danny P. Liggett (M’91, SM’98) has been employed by DuPont since 1989. He was employed by an engineering/construction firm from 1968 until his employment with DuPont. During his employment with the engineering/construction firm he worked as an electrical superintendent for 15 years. During his employment with DuPont he has worked as an Electrical Consultant with primary focus on construction activities and electrical safety. His work also involves work with maintenance activities at the DuPont sites. He is a member of the DuPont Corporate Electrical safety Team, Senior Member of IEEE, Past Chair of the IEEE IAS PCIC Safety Subcommittee and Past Chair of the PCIC Tutorials Subcommittee. He currently serves as Chair of the PCIC IAS Electrical Safety Workshop Subcommittee. Danny served as Chair of the 2000 IEEE IAS Electrical Safety Workshop. He has served on the NFPA National Electrical Code Panel 8 representing the Cable Tray Institute and the NFPA National Electrical Code Panel 6 representing the American Chemistry Council. He currently represents the American Chemistry Council on the National Electrical Code Technical Correlating Committee, as an alternate on National Electrical Code Panel 3 and as an alternate on NFPA 70E. He has authored or co-authored 15 papers on electrical safety, 10 of which have been published.

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UNITED STATES

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ALABAMA 1

2

3

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AMP Quality Energy Services, LLC 352 Turney Ridge Rd Somerville, AL 35670 (256) 513-8255 [email protected] www.ampqes.com Brian Rodgers Premier Power Maintenance Corporation 3066 Finley Island Cir NW Decatur AL 35601-8800 (256) 355-1444 [email protected] www.premierpowermaintenance.com Johnnie McClung

ARKANSAS 5

Premier Power Maintenance Corporation 7301 E County Road 142 Blytheville, AR 72315-6917 (870) 762-2100 [email protected] www.premierpowermaintenance.com Kevin Templeman

7

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Utility Service Corporation PO Box 1471 Huntsville, AL 35807 (256) 837-8400 Fax: (256) 837-8403 [email protected] www.utilserv.com Alan D. Peterson

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ARIZONA

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Premier Power Maintenance Corporation 4301 Iverson Blvd Ste H Trinity, AL 35673-6641 (256) 355-3006 [email protected] www.premierpowermaintenance.com Kevin Templeman

Sentinel Power Services, Inc. 1110 West B Street, Ste H Russellville, AR 72801 (918) 359-0350 www.sentinelpowerservices.com

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ABM Electrical Power Services, LLC 2631 S. Roosevelt St Tempe, AZ 85282 (602) 722-2423 www.abm.com Electric Power Systems, Inc. 1230 N Hobson St., Ste 101 Gilbert, AZ 85233 (480) 633-1490 www.epsii.com Electrical Reliability Services 221 E. Willis Road Chandler, AZ 85286 (480) 966-4568 [email protected] www.electricalreliability.com Hampton Tedder Technical Services 3747 West Roanoke Ave. Phoenix, AZ 85009 (480) 967-7765 Fax:(480) 967-7762 www.hamptontedder.com Linc McNitt Southwest Energy Systems, LLC 2231 East Jones Ave., Suite A Phoenix, AZ 85040 (602) 438-7500 Fax: (602) 438-7501 [email protected] www.southwestenergysystems.com Dave Hoffman

Western Electrical Services, Inc. 5680 South 32nd St. Phoenix, AZ 85040 (602) 426-1667 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Craig Archer

CALIFORNIA 13

ABM Electrical Power Services, LLC 720 S. Rochester Ave., Suite A Ontario, CA 91761 (301) 397-3500 [email protected] www.abm.com Rob Parton

14

ABM Electrical Power Services, LLC 6940 Koll Center Pkwy, Ste 100 Pleasanton, CA 94566 (408) 466-6920 www.abm.com

15

ABM Electrical Power Services, LLC 3585 Corporate Court San Diego, CA 92123-1844 (858) 754-7963

16

Accessible Consulting Engineers, Inc. 1269 Pomona Rd, Ste 111 Corona, CA 92882-7158 (951) 808-1040 [email protected] www.acetesting.com Iraj Nasrolahi

17

Apparatus Testing and Engineering 11300 Sanders Dr, Ste 29 Rancho Cordova, CA 95742-6822 (916) 853-6280 [email protected] www.apparatustesting.com Harold (Jerry) Carr

For additional information on NETA visit netaworld.org

18

Apparatus Testing and Engineering 7083 Commerce Cir., Suite H Pleasanton, CA 94588 (916) 853-6280 www.apparatustesting.com

21

Applied Engineering Concepts 894 N Fair Oaks Ave. Pasadena, CA 91103 (626) 389-2108 [email protected] www.aec-us.com Michel Castonguay

22

23

29

Applied Engineering Concepts 8160 Miramar Road San Diego, CA 92126 (619) 822-1106 [email protected] www.aec-us.com Michel Castonguay Electric Power Systems, Inc. 7925 Dunbrook Rd., Ste G San Diego, CA 92126 (858) 566-6317 www.epsii.com

24

Electrical Reliability Services 5909 Sea Lion Pl, Ste C Carlsbad, CA 92010-6634 (858) 695-9551 www.electricalreliability.com

25

Electrical Reliability Services 6900 Koll Center Pkwy., Ste 415 Pleasanton, CA 94566 (925) 485-3400 Fax: (925) 485-3436

26

27

28

Electrical Reliability Services 10606 Bloomfield Ave. Santa Fe Springs, CA 90670 (562) 236-9555 Fax: (562) 777-8914 Giga Electrical & Technical Services, Inc. 2743A N. San Fernando Road Los Angeles, CA 90065 (323) 255-5894 [email protected] www.gigaelectrical-ca.com Hermin Machacon Halco Testing Services 5773 Venice Boulevard Los Angeles, CA 90019 [email protected] (323) 933-9431 www.halcotestingservices.com Don Genutis

Hampton Tedder Technical Services 4563 State St Montclair, CA 91763 (909) 628-1256 x214 [email protected] www.hamptontedder.com Chasen Tedder

36

37

30

Industrial Tests, Inc. 4021 Alvis Ct., Suite 1 Rocklin, CA 95677 (916) 296-1200 Fax: (916) 632-0300 [email protected] www.industrialtests.com Greg Poole

31

Pacific Power e tin , Inc. 38 14280 Doolittle Dr. San Leandro, CA 94577 (510) 351-8811 Fax: (510) 351-6655 [email protected] www.pacificpowertesting.com Steve Emmert

32

Power Systems Testing Co. 4688 W. Jennifer Ave., Suite 108 Fresno, CA 93722 (559) 275-2171 x15 Fax: (559) 275-6556 [email protected] www.powersystemstesting.com David Huffman

RESA Power Service 2390 Zanker Road San Jose , CA 95131 (800) 576-7372 [email protected] www.resapower.com Toby Ramsey Tony Demaria Electric, Inc. 131 West F St. Wilmington, CA 90744 (310) 816-3130 Fax: (310) 549-9747 [email protected] www.tdeinc.com Neno Pasic Western Electrical Services, Inc. 5505 Daniels St. Chino, CA 91710 (619) 672-5217 [email protected] www.westernelectricalservices.com Matt Wallace

COLORADO 39

ABM Electrical Power Services, LLC 9800 E Geddes Ave Unit A-150 Englewood, CO 80112-9306 (303) 524-6560 www.abm.com

33

Power Systems Testing Co. 6736 Preston Ave., Suite E Livermore, CA 94551 (510) 783-5096 Fax: (510) 732-9287 www.powersystemstesting.com

40

Electric Power Systems, Inc. 11211 E. Arapahoe Rd, Ste 108 Centennial, CO 80112 (720) 857-7273 www.epsii.com

34

Power Systems Testing Co. 600 S. Grand Ave., Suite 113 Santa Ana, CA 92705-4152 (714) 542-6089 Fax: (714) 542-0737 www.powersystemstesting.com

41

Electrical Reliability Services 7100 Broadway, Suite 7E Denver, CO 80221-2915 (303) 427-8809 Fax: (303) 427-4080 www.electricalreliability.com

35

RESA Power Service 13837 Bettencourt Street Cerritos, CA 90703 (800) 996-9975 [email protected] www.resapower.com Manny Sanchez

42

Magna IV Engineering 96 Inverness Dr. East, Suite R Englewood, CO 80112 (303) 799-1273 Fax: (303) 790-4816 [email protected] Aric Proskurniak

43

Precision Testing Group 5475 Hwy. 86, Unit 1 Elizabeth, CO 80107 (303) 621-2776 Fax: (303) 621-2573

For additional information on NETA visit netaworld.org

44

RESA Power Service 19621 Solar Circle, 101 Parker, CO 80134 (303) 781-2560 [email protected] www.resapower.com Jody Medina

51

CE Power Solutions of Florida, LLC 3502 Riga Blvd., Suite C Tampa, FL 33619 (866) 439-2992

52

CE Power Solutions of Florida, LLC 3801 SW 47th Avenue, Suite 505 Davie, FL 33314 (866) 439-2992

CONNECTICUT 45

46

47

48

49

Advanced Testing Systems 15 Trowbridge Dr. Bethel, CT 06801 (203) 743-2001 Fax: (203) 743-2325 [email protected] www.advtest.com Pat MacCarthy American Electrical Testing Co., Inc. 34 Clover Dr. South Windsor, CT 06074 (860) 648-1013 Fax: (781) 821-0771 [email protected] www.aetco.com Gerald Poulin EPS Technology 29 N. Plains Highway, Suite 12 Wallingford, CT 06492 (203) 679-0145 [email protected] www.eps-technology.com Sean Miller

53

Electric Power Systems, Inc. 4436 Parkway Commerce Blvd. Orlando, FL 32808 (407) 578-6424 Fax: (407) 578-6408 www.epsii.com

54

Electrical Reliability Services 11000 Metro Pkwy., Suite 30 Ft. Myers, FL 33966 (239) 693-7100 Fax: (239) 693-7772

55

Electrical Testing, Inc. 2671 Cedartown Highway Rome, GA 30161-6791 (706) 234-7623 Fax: (706) 236-9028 [email protected] www.electricaltestinginc.com Jamie Dempsey

61

Nationwide Electrical Testing, Inc. 6050 Southard Trace Cumming, GA 30040 (770) 667-1875 Fax: (770) 667-6578 [email protected] www.n-e-t-inc.com Shashikant B. Bagle

ILLINOIS 62

Dude Electrical Testing, LLC 145 Tower Dr., Ste 9 Burr Ridge, IL 60527 (815) 293-3388 Fax: (815) 293-3386 [email protected] www.dudetesting.com Scott Dude

63

Electric Power Systems, Inc. 54 Eisenhower Lane North Lombard, IL 60148 (815) 577-9515 www.epsii.com

64

High Voltage Maintenance Corp. 941 Busse Rd. Elk Grove Village, IL 60007 (847) 640-0005 www.hvmcorp.com

65

Midwest Engineering Consultants, Ltd. 2500 36th Ave Moline, IL 61265-6954 (309) 764-1561 [email protected] www.midwestengr.com Monte Moorehead

66

Shermco Industries 112 Industrial Drive Minooka, IL 60447-9557 (815) 467-5577 [email protected] www.shermco.com

RESA Power Service 1401 Mercantile Court Plant City, FL 33563 (813) 752-6550 www.resapower.com

GEORGIA 56

High Voltage Maintenance Corp. 150 North Plains Industrial Rd. Wallingford, CT 06492 (203) 949-2650 Fax: (203) 949-2646 www.hvmcorp.com Southern New England Electrical Testing, LLC 3 Buel St., Suite 4 Wallingford, CT 06492 (203) 269-8778 Fax: (203) 269-8775 [email protected] www.sneet.org David Asplund, Sr.

57

58

FLORIDA 50

60

C.E. Testing, Inc. 6148 Tim Crews Rd. Macclenny, FL 32063 (904) 653-1900 Fax: (904) 653-1911 [email protected] www.cetestinginc.com Mark Chapman

59

ABM Electrical Power Services, LLC 1005 Windward Ridge Pkwy Alpharetta, GA 30005 (770) 521-7550 www.abm.com Electric Power Systems, Inc. 6679 Peachtree Industrial Dr., Suite H Norcross , GA 30092 (770) 416-0684 www.epsii.com Electrical Equipment Upgrading, Inc. 21 Telfair Place Savannah, GA 31415 (912) 232-7402 Fax: (912) 233-4355 [email protected] www.eeu-inc.com Kevin Miller Electrical Reliability Services 2275 Northwest Parkway SE, Suite 180 Marietta, GA 30067 (770) 541-6600 Fax: (770) 541-6501

For additional information on NETA visit netaworld.org

INDIANA 67

68

CE Power Engineered Services, LLC 3496 E. 83rd Place Merrillville, IN 46410 (219) 942-2346 www.cepower.net

Shermco Industries 2100 Dixon Street, Suite C Des Moines, IA 50316-2174 (515) 263-8482

75

Shermco Industries 5145 NW Beaver Dr. Johnston, IA 50131 (515) 265-3377 www.shermco.com

Electric Power Systems, Inc. 7169 East 87th St. Indianapolis, IN 46256 (317) 941-7502 www.epsii.com Daniel Douglas

KENTUCKY

69

Electrical Maintenance & Testing, Inc. 12342 Hancock St. Carmel, IN 46032 (317) 853-6795 Fax: (317) 853-6799 [email protected] www.emtesting.com Brian K. Borst

70

High Voltage Maintenance Corp. 8320 Brookville Rd., Ste E Indianapolis, IN 46239 (317) 322-2055 Fax: (317) 322-2056 www.hvmcorp.com

71

Premier Power Maintenance Corporation 4035 Championship Drive Indianapolis, IN 46268 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

72

Premier Power Maintenance Corporation 4537 S Nucor Rd. Crawfordsville, IN 47933 (317) 879-0660 [email protected] www.premierpowermaintenance.com Kevin Templeman

IOWA 73

74

Shermco Industries 1711 Hawkeye Dr. Hiawatha, IA 52233 (319) 377-3377 [email protected] www.shermco.com

76

77

78

Electrical Reliability Services 9636 St. Vincent, Unit A Shreveport, LA 71106 (318) 869-4244 [email protected]

83

Saber Power Services, LLC 14617 Perkins Road Baton Rouge, LA 70810 (225) 726-7793 www.saberpower.com

84

Tidal Power Services, LLC 8184 Highway 44, Suite 105 Gonzales, LA 70737 (225) 644-8170 Fax: (225) 644-8215 www.tidalpowerservices.com Darryn Kimbrough

CE Power Engineered Services, LLC 1803 Taylor Ave. Louisville, KY 40213 (800) 434-0415 [email protected] 85 Tidal Power Services, LLC www.cepower.net 1056 Mosswood Dr. Bob Sheppard Sulphur, LA 70665 (337) 558-5457 Fax: (337) 558-5305 High Voltage Maintenance Corp. www.tidalpowerservices.com 10704 Electron Drive Steve Drake Louisville, KY 40299 (859) 371-5355 MAINE www.hvmcorp.com 86 CE Power Engineered Services, LLC Premier Power Maintenance 72 Sanford Drive Corporation Gorham, ME 04038 2725 Jason Rd (800) 649-6314 Ashland, KY 41102-7756 [email protected] (606) 929-5969 www.cepower.net [email protected] Jim Cialdea www.premierpowermaintenance.com 87 Electric Power Systems, Inc. Jay Milstead 56 Bibber Pkwy #1 Brunswick, ME 04011-7357 (207) 837-6527 LOUISIANA www.epsii.com

79

Electric Power Systems, Inc. 1129 East Highway 30 Gonzalez, LA 70737 (225) 644-0150 Fax: (225) 644-6249 www.epsii.com

80

Electrical Reliability Services 245 Hood Road Sulphur, LA 70665-8747 (337) 583-2411 [email protected]

81

82

Electrical Reliability Services 3535 Emerson Pkwy, Ste A Gonzales, LA 70737 (225) 755-0530 [email protected]

88

POWER Testing and Energization, Inc. 303 US Route One Freeport,ME 04032 (207) 869-1200 www.powerte.com

MARYLAND 89

ABM Electrical Power Solutions 3700 Commerce Dr., #901- 903 Baltimore, MD 21227 (410) 247-3300 Fax: (410) 247-0900 www.abm.com

For additional information on NETA visit netaworld.org

90

ABM Electrical Power Solutions 4390 Parliament Pl., Suite S Lanham, MD 20706 (301) 967-3500 Fax: (301) 735-8953 [email protected] www.abm.com Christopher Smith

91

Harford Electrical Testing Co., Inc. 1108 Clayton Rd. Joppa, MD 21085 (410) 679-4477 [email protected] www.harfordtesting.com Vincent Biondino

92

High Voltage Maintenance Corp. 9305 Gerwig Ln., Suite B Columbia, MD 21046 (410) 309-5970 Fax: (410) 309-0220 www.hvmcorp.com

93

High Voltage Maintenance Corp. 14300 Cherry Lane Court, Ste 115 Laurel, MD 20707 (410) 279-0798 www.hvmcorp.com

94

95

97

Electrical Engineering & Service Co. Inc. 289 Centre St. Holbrook, MA 02343 (781) 767-9988 [email protected] www.eescousa.com Joe Cipolla

99

High Voltage Maintenance Corp. 24 Walpole Park S Walpole, MA 02081-2541 (508) 668-9205 www.hvmcorp.com

100

Infra-Red Building and Power Service, Inc. 152 Centre St Holbrook, MA 02343-1011 (781) 767-0888 [email protected] www.infraredbps.com

106

Premier Power Maintenance Corporation 7262 Kensington Rd. Brighton, MI 48116 (517) 230-6620 [email protected] www.premierpowermaintenance.com Brian Ellegiers

108

RESA Power Service 46918 Liberty Dr Wixom, MI 48393-3600 (248) 313-6868 [email protected] www.resapower.com Bruce Robinson

109

Shermco Industries 12796 Currie Court Livonia, MI 48150 (734) 469-4050 [email protected] www.shermco.com

MICHIGAN 101

CE Power Engineered Services, LLC 10338 Citation Drive, Ste 300 Brighton, MI 48116 (810) 229-6628 [email protected] www.cepower.net Ken L’Esperance

104

American Electrical Testing Co., LLC 25 Forbes Boulevard, Ste 1 Foxboro, MA 02035 (781) 821-0121 [email protected] www.aetco.us Scott Blizard CE Power Engineered Services, LLC 40 Washington St Westborough, MA 01581-1088 (508) 881-3911 www.cepower.net

Northern Electrical Testing, Inc. 1991 Woodslee Dr. Troy, MI 48083-2236 (248) 689-8980 Fax: (248) 689-3418 [email protected] www.northerntesting.com Lyle Detterman

105 POWER

PLUS Engineering, Inc. 47119 Cartier Court Wixom, MI 48393-2872 (248) 896-0200

Powertech Services, Inc. 4095 South Dye Rd. Swartz Creek, MI 48473-1570 (810) 720-2280 Fax: (810) 720-2283 [email protected] www.powertechservices.com Kirk Dyszlewski

107

Potomac Testing, Inc. 1610 Professional Blvd., Ste A Crofton, MD 21114 (301) 352-1930 Fax: (301) 352-1936 110 [email protected] 102 Electric Power Systems, Inc. www.potomactesting.com 11861 Longsdorf St. Ken Bassett Riverview, MI 48193 (734) 282-3311 Reuter & Hanney, Inc. www.epsii.com 11620 Crossroads Cir., Suites D-E Middle River, MD 21220 103 High Voltage Maintenance Corp. (410) 344-0300 Fax: (410) 335-4389 24371 Catherine Industrial Dr., Ste 207 [email protected] Novi, MI 48375 www.reuterhanney.com (248) 305-5596 Fax: (248) 305-5579 Michael Jester www.hvmcorp.com 111

MASSACHUSETTS 96

98

112

Utilities Instrumentation Service, Inc. 2290 Bishop Circle East Dexter, MI 48130 (734) 424-1200 Fax: (734) 424-0031 [email protected] www.uiscorp.com Gary E. Walls

MINNESOTA CE Power Engineered Services, LLC 7674 Washington Ave. S Eden Prairie, MN 55344 (877) 968-0281 [email protected] www.cepower.net Jason Thompson RESA Power Service 3890 Pheasant Ridge Dr. NE, Ste 170 Blaine, MN 55449 (763) 784-4040 [email protected] www.resapower.com Mike Mavetz

For additional information on NETA visit netaworld.org

113

Shermco Industries 998 E. Berwood Ave. Saint Paul, MN 55110 (651) 484-5533 [email protected] www.shermco.com

121

122

MISSOURI 114

115

116

117

Electric Power Systems, Inc. 6141 Connecticut Ave. Kansas City, MO 64120 (816) 241-9990 Fax: (816) 241-9992 www.epsii.com Electric Power Systems, Inc. 21 Millpark Ct. Maryland Heights, MO 63043-3536 (314) 890-9999 Fax:(314) 890-9998 www.epsii.com

123

Electrical Reliability Services 124 400 NW Capital Dr Lees Summit, MO 64086 (816) 525-7156 Fax: (816) 524-3274 [email protected] POWER Testing and Energization, Inc. 12755 Olive Blvd., Ste 100 Saint Louis, MO 63141 (314) 851-4065 www.powerte.com

125

NEBRASKA 118

Shermco Industries 4670 G. Street Omaha, NE 68117 (402) 933-8988 [email protected] www.shermco.com

120

126

Control Power Concepts 353 Pilot Rd, Suite B Las Vegas, NV 89119 (702) 448-7833 Fax: (702) 448-7835 [email protected] www.controlpowerconcepts.com John Travis Electric Power Systems, Inc. 5850 Polaris Ave., Suite 1600 Las Vegas, NV 89118 (702) 815-1342 www.epsii.com

Electrical Reliability Services 1380 Greg St., Suite 217 Sparks, NV 89431 (775) 746-8484 Fax: (775) 356-5488 www.electricalreliability.com Hampton Tedder Technical Services 4113 Wagon Trail Ave. Las Vegas, NV 89118 (702) 452-9200 www.hamptontedder.com Roger Cates National Field Services 3711 Regulus Ave. Las Vegas, NV 89102 (888) 296-0625 [email protected] www.natlfield.com Howard Herndon National Field Services 2900 Vassar St. #114 Reno, NV 89502 (775) 410-0430 www.natlfield.com Howard Herndon [email protected]

Electric Power Systems, Inc. 915 Holt Ave., Unit 9 Manchester, NH 03109 (603) 657-7371 www.epsii.com

Eastern High Voltage 11A South Gold Dr. Robbinsville, NJ 08691-1606 (609) 890-8300 Fax: (609) 588-8090 [email protected] www.easternhighvoltage.com Robert Wilson

130

High Energy Electrical Testing, Inc. 515 S. Ocean Ave. Seaside Park, NJ 08752 (732) 938-2275 Fax: (732) 938-2277 [email protected] www.highenergyelectric.com Charles Blanchard

131

132

American Electrical Testing Co., Inc. 91 Fulton St. Boonton, NJ 07005 (973) 316-1180 [email protected] www.aetco.com Jeff Somol

J.G. Electrical Testing Corporation 3092 Shafto Road, Suite 13 Tinton Falls, NJ 07753 (732) 217-1908 www.jgelectricaltesting.com Howard Trinkowsky M&L Power Systems, Inc. 109 White Oak Ln., Suite 82 Old Bridge, NJ 08857 (732) 679-1800 Fax: (732) 679-9326 [email protected] www.mlpower.com Milind Bagle

133

RESA Power Service 311 Bay Avenue A Highlands, NJ 07732 (888) 996-9975 [email protected] www.resapower.com Trent Robbins

134

Scott Testing, Inc. 245 Whitehead Rd Hamilton, NJ 08619 (609) 689-3400 [email protected] www.scotttesting.com Russ Sorbello

NEW JERSEY 127

Burlington Electrical Testing Co., Inc. 198 Burrs Rd. Westampton, NJ 08060 (609) 267-4126 [email protected] www.betest.com Walter P. Cleary

129

NEW HAMPSHIRE

NEVADA 119

Electrical Reliability Services 128 6351 Hinson St., Suite A Las Vegas, NV 89118 (702) 597-0020 Fax: (702) 597-0095 www.electricalreliability.com

For additional information on NETA visit netaworld.org

135

Trace Electrical Services 142 & Testing, LLC 293 Whitehead Rd. Hamilton, NJ 08619 (609) 588-8666 Fax: (609) 588-8667 www.tracetesting.com Joseph Vasta

NEW MEXICO 136

137

138

143

Electric Power Systems, Inc. 8515 Cella Alameda NE, Suite A Albuquerque, NM 87113 (505) 792-7761 www.eps-international.com Electrical Reliability Services 8500 Washington Pl. NE, Suite A-6 Albuquerque, NM 87113 (505) 822-0237 Fax: (505) 822-0217 www.electricalreliability.com Western Electrical Services, Inc. 620 Meadow Ln. Los Alamos, NM 87547 (505) 469-1661 [email protected] www.westernelectricalservices.com Toby King

144

145

NEW YORK 139

140

141

BEC Testing 50 Gazza Blvd Farmingdale, NY 11735-1402 (631) 393-6800 [email protected] www.bectesting.com Daniel Devlin Elemco Services, Inc. 228 Merrick Rd. Lynbrook, NY 11563 (631) 589-6343 [email protected] www.elemco.com Courtney Gallo High Voltage Maintenance Corp. 1250 Broadway, Suite 2300 New York, NY 10001 (718) 239-0359 www.hvmcorp.com

149

150

151

152

HMT, Inc. 6268 Route 31 Cicero, NY 13039 (315) 699-5563 Fax: (315) 699-5911 [email protected] www.hmt-electric.com John Pertgen

A&F Electrical Testing, Inc. 80 Broad St., 5th Floor New York, NY 10004 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Florence Chilton American Electrical Testing Co., Inc. 76 Cain Dr. Brentwood, NY 11717 (631) 617-5330 Fax: (631) 630-2292 [email protected] www.aetco.com Billy Fernandez

146

147

148

ABM Electrical Power Services, LLC 6541 Meridien Dr, Suite 113 Raleigh, NC 27616 (919) 877-1008 www.abm.com ABM Electrical Power Services, LLC 3600 Woodpark Blvd., Suite G Charlotte, NC 28206 (704) 273-6257 Fax: (704) 598-9812 [email protected] www.abm.com Ernest Goins ELECT, P.C. 375 E. Third Street Wendell, NC 27591 (919) 365-9775 [email protected] www.elect-pc.com Barry W. Tyndall

Electrical Reliability Services 6135 Lakeview Road, Suite 500 Charlotte, NC 28269 (704) 441-1497 [email protected] www.electricalreliability.com Power Products & Solutions, LLC 6605 W WT Harris Blvd, Suite F Charlotte, NC 28269 (704) 573-0420 x12 [email protected] www.powerproducts.biz Adis Talovic Power Test, Inc. 2200 Hwy. 49 S Harrisburg, NC 28075 (704) 200-8311 Fax: (704) 455-7909 [email protected] www.powertestinc.com Richard Walker

OHIO 153

ABM Electrical Power Solutions 1817 O’Brien Road Columbus, OH 43228 (724) 772-4638 www.abm.com

154

CE Power Engineered Services, LLC 4040 Rev Drive Cincinnati, OH 45232 (800) 434-0415 [email protected] www.cepower.net Brent McAlister

155

CE Power Engineered Services, LLC 8490 Seward Rd. Fairfield, OH 45011 (800) 434-0415 [email protected] www.cepower.net Tim Lana

156

Electric Power Systems, Inc. 2888 Nationwide Parkway, 2nd Floor Brunswick, OH 44212 (330) 460-3706 www.epsii.com

NORTH CAROLINA

A&F Electrical Testing, Inc. 80 Lake Ave. S., Suite 10 Nesconset, NY 11767 (631) 584-5625 Fax: (631) 584-5720 [email protected] www.afelectricaltesting.com Kevin Chilton

Electric Power Systems, Inc. 319 US Hwy. 70 E, Suite E Garner, NC 27529 (919) 210-5405 www.eps-international.com

For additional information on NETA visit netaworld.org

157

158

159

160

161

Electrical Reliability Services 610 Executive Campus Dr. Westerville, OH 43082 (877) 468-6384 Fax: (614) 410-8420 [email protected] www.electricalreliability.com High Voltage Maintenance Corp. 5100 Energy Dr. Dayton, OH 45414 (937) 278-0811 Fax: (937) 278-7791 www.hvmcorp.com

OKLAHOMA 165

166

High Voltage Maintenance Corp. 7200 Industrial Park Blvd. Mentor, OH 44060 (440) 951-2706 Fax: (440) 951-6798 www.hvmcorp.com Power Solutions Group Ltd. 425 W Kerr Rd Tipp City, OH 45371-2843 (937) 506-8444 [email protected] www.powersolutionsgroup.com Barry Willoughby

RESA Power Service 4540 Boyce Parkway Stow, OH 44224 (800) 264-1549 www.resapower.com

163

Shermco Industries 4383 Professional Parkway Groveport, OH 43125 (614) 836-8556 [email protected] www.shermco.com

164

Utilities Instrumentation Service - Ohio, LLC PO Box 750066 998 Dimco Way Dayton, OH 45475-0066 (937) 439-9660

Shermco Industries 4510 South 86th East Ave. Tulsa, OK 74145 (918) 234-2300 [email protected] www.shermco.com

174

167

168

Electrical Reliability Services 4099 SE International Way, Suite 201 Milwaukie, OR 97222-8853 (503) 653-6781 Fax: (503) 659-9733 www.electricalreliability.com

169

ABM Electrical Power Solutions 317 Commerce Park Drive Cranberry Township, PA 16066-6407 (724) 772-4638 www.abm.com

170

American Electrical Testing Co., Inc. Green Hills Commerce Center 5925 Tilghman St., Suite 200 Allentown, PA 18104 (215) 219-6800 [email protected] www.aetco.com Jonathan Munley

171

172

176

Reuter & Hanney, Inc. 149 Railroad Dr. Northampton Industrial Park Ivyland, PA 18974 (215) 364-5333 Fax: (215) 364-5365 [email protected] www.reuterhanney.com Michael Jester

SOUTH CAROLINA 177

Power Products & Solutions, LLC 13 Jenkins Ct. Mauldin, SC 29662 (800) 328-7382 [email protected] www.powerproducts.biz Raymond Pesaturo

178

Power Products & Solutions, LLC 9481 Industrial Center Dr. Unit 5 Ladson, SC 29456 (844) 383-8617 www.powerproducts.biz

179

Power Solutions Group Ltd. 5115 Old Greenville Highway Liberty, SC 29657 (864) 540-8434 [email protected] www.powersolutionsgroup.com Anthony Crawford

Burlington Electrical Testing Co., Inc. 300 Cedar Ave. Croydon, PA 19021-6051 (215) 826-9400 Fax: (215) 826-0964 www.betest.com Electric Power Systems, Inc. 1090 Montour West Industrial Blvd. Coraopolis, PA 15108 (412) 276-4559 www.epsii.com

High Voltage Maintenance Corp. 355 Vista Park Dr. Pittsburgh, PA 15205-1206 (412) 747-0550 Fax: (412) 747-0554 www.hvmcorp.com North Central Electric, Inc. 69 Midway Ave. Hulmeville, PA 19047-5827 (215) 945-7632 Fax: (215) 945-6362 [email protected] www.ncetest.com Robert Messina

Taurus Power & Controls, Inc. 9999 SW Avery St. Tualatin, OR 97062-9517 (503) 692-9004 Fax: (503) 692-9273 [email protected] www.tauruspower.com Rob Bulfinch

PENNSYLVANIA

EnerG Test, LLC 204 Gale Lane, Bldg. 2 – 2nd Floor Kennett Square, PA 19348 (484) 731-0200 Fax: (484) 713-0209 [email protected] www.energtest.com Dennis Buehler

175

OREGON

Power Solutions Group Ltd. 2739 Sawbury Blvd. Columbus, OH 43235 (614) 310-8018 [email protected] www.powersolutionsgroup.com Stuart Spohn

162

Sentinel Power Services, Inc. 7517 E Pine St Tulsa, OK 74115-5729 (918) 359-0350 [email protected] www.sentinelpowerservices.com Greg Ellis

173

180

POWER Testing and Energization, Inc. 1041 Red Ventures Dr., Suite 105 Fort Mill, SC 29707 (803) 835-5900 www.powerte.com

For additional information on NETA visit netaworld.org

TENNESEE 181

182

183

184

185

186

187

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189

Electrical Reliability Services 1057 Doniphan Park Cir Ste A El Paso, TX 79922-1329 (915) 587-9440 [email protected]

CE Power Engineered Services, LLC 480 Cave Rd Nashville, TN 37210-2302 (615) 882-9455 190 Electrical Reliability Services [email protected] 1426 Sens Rd Ste 5 www.cepower.net La Porte, TX 77571-9656 Bryant Phillips (281) 241-2800 CE Power Engineered Services, LLC [email protected] 10840 Murdock Drive 191 Grubb Engineering, Inc. Knoxville , TN 37932 2727 North Saint Mary’s St. (800) 434-0415 San Antonio, TX 78212 [email protected] (210) 658-7250 www.cepower.net [email protected] Don William www.grubbengineering.com Electric Power Systems, Inc. Robert D. Grubb Jr. 684 Melrose Avenue 192 Magna IV Engineering Nashville, TN 37211-3121 4407 Halik Street Building E, Suite 300 (615) 834-0999 www.epsii.com Pearland, TX 77581 (346) 221-2165 Electrical & Electronic Controls [email protected] 6149 Hunter Rd. www.magnaiv.com Ooltewah, TN 37363 Aric Proskurniak (423) 344-7666 Fax: (423) 344-4494 193 National Field Services [email protected] Michael Hughes 651 Franklin Lewisville, TX 75057-2301 Electrical Testing and (972) 420-0157 Maintenance Corp. www.natlfield.com 3673 Cherry Rd Ste 101 Eric Beckman Memphis, TN 38118-6313 (901) 566-5557 194 National Field Services [email protected] 1890 A South Hwy 35 www.etmcorp.net Alvin, TX 77511 Ron Gregory (800) 420-0157 [email protected] Power Solutions Group, Ltd. www.natlfield.com 172 B-Industrial Dr. Jonathan Wakeland Clarksville, TN 37040 195 National Field Services (931) 572-8591 www.powersolutionsgroup.com 1405 United Drive, Suite 113-115 San Marcos, TX 78666 Chris Brown (800) 420-0157 [email protected] TEXAS www.natlfield.com Matt LaCoss Absolute Testing Services, Inc. 8100 West Little York 196 Power Engineering Services, Inc. Houston, TX 77040 9179 Shadow Creek Ln (832) 467-4446 Converse, TX 78109-2041 www.absolutetesting.com (210) 590-4936 [email protected] Electric Power Systems, Inc. www.pe-svcs.com 1330 Industrial Blvd., Suite 300 Daniel Staudt Sugar Land, TX 77478 (713) 644-5400 www.epsii.com

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POWER Testing and Energization, Inc. 16825 Northchase Drive Houston, TX 77060 (281) 765-5536 www.powerte.com Saber Power Services, LLC 9841 Saber Power Ln Rosharon, TX 77583-5188 (713) 222-9102 [email protected] www.saberpower.com Saber Power Services, LLC 4703 Shavano Oak, Suite 104 San Antonio, TX 78249 (210) 267-7282 www.saberpower.com Saber Power Services, LLC 1315 FM 1187, Suite 105 Mansfield, TX 76063 (682) 518-3676 www.saberpower.com Shermco Industries 2425 E Pioneer Dr Irving, TX 75061-8919 (972) 793-5523 [email protected] www.shermco.com

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Shermco Industries 1705 Hur Industrial Blvd Cedar Park, TX 78613-7229 (512) 267-4800 [email protected] www.shermco.com

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Shermco Industries 33002 FM 2004 Angleton, TX 77515-8157 (979) 848-1406 [email protected] www.shermco.com

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Shermco Industries 12000 Network Blvd, Buidling D Suite 410 San Antonio, TX 78249-3354 (210) 877-9090 [email protected] www.shermco.com

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Shermco Industries 3807 S Sam Houston Pkwy W Houston, TX 77056 (281) 835-3633 [email protected] www.shermco.com

For additional information on NETA visit netaworld.org

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Shermco Industries 1301 Hailey St. Sweetwater, TX 79556 (325) 236-9900 [email protected] www.shermco.com

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Shermco Industries 2901 Turtle Creek Dr. Port Arthur, TX 77642 (409) 853-4316 [email protected] www.shermco.com

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Tidal Power Services, LLC 4211 Chance Ln Rosharon, TX 77583-4384 (281) 710-9150 [email protected] www.tidalpowerservices.com Monty C. Janak

Titan Quality Power Services, LLC 7630 Ikes Tree Drive Spring, TX 77389 (281) 826-3781 www.titanqps.com

UTAH 211

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ABM Electrical Power Solutions 814 Greenbrier Cir., Suite E Chesapeake, VA 23320 (757) 364-6145 www.abm.com Mark Anthony Gaughan, III

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Reuter & Hanney, Inc. 4270-I Henninger Ct. Chantilly, VA 20151 (703) 263-7163 Fax: (703) 263-1478 www.reuterhanney.com 224

Electrical Reliability Services 2222 West Valley Hwy. N., Suite 160 Auburn, WA 98001 (253) 736-6010 Fax: (253) 736-6015 [email protected] www.electricalreliability.com 225

219

226 Sigma Six Solutions, Inc. 2200 West Valley Hwy., Suite 100 Auburn, WA 98001 (253) 333-9730 Fax: (253) 859-5382 [email protected] www.sigmasix.com John White

Western Electrical Services, Inc. 220 3676 W. California Ave.,#C-106 Salt Lake City, UT 84104 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Rob Coomes

Western Electrical Services, Inc. 4510 NE 68th Dr., Suite 122 Vancouver, WA 98661 (888) 395-2021 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Tony Asciutto

WISCONSIN

POWER Testing and Energization, Inc. 14006 NW 3rd Ct, Ste 101 Vancouver, WA 98685-5793 (360) 597-2800 [email protected] www.powerte.com Chris Zavadlov

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Electrical Reliability Services 9736 South 500 West Sandy, UT 84070 (801) 975-6461 [email protected]

VIRGINIA

Electric Power Systems, Inc. 306 Ashcake Road, Suite A Ashland, VA 23005 (804) 526-6794 www.epsii.com

WASHINGTON 217

Titan Quality Power Services, LLC 1501 S Dobson Street Burleson, TX 76028 (866) 918-4826 www.titanqps.com

Electric Power Systems, Inc. 120 Turner Road Salem, VA 24153-5120 (540) 375-0084 www.epsii.com

Electrical Energy Experts, Inc. W129N10818, Washington Dr. Germantown,WI 53022 (262) 255-5222 Fax: (262) 242-2360 [email protected] www.electricalenergyexperts.com Tim Casey Electrical Testing Solutions 2909 Green Hill Ct. Oshkosh, WI 54904 (920) 420-2986 Fax: (920) 235-7136 [email protected] www.electricaltestingsolutions.com Tito Machado Energis High Voltage Resources, Inc. 1361 Glory Rd. Green Bay, WI 54304 (920) 632-7929 Fax: (920) 632-7928 [email protected] www.energisinc.com Mick Petzold High Voltage Maintenance Corp. 3000 S. Calhoun Rd. New Berlin, WI 53151 (262) 784-3660 Fax: (262) 784-5124 www.hvmcorp.com

Taurus Power & Controls, Inc. 19226 66th Ave S. #L102 Kent, WA 98032-2197 (425) 656-4170 www.tauruspower.com Western Electrical Services, Inc. 14311 29th St. East Sumner, WA 98390 (253) 891-1995 Fax: (253) 891-1511 [email protected] www.westernelectricalservices.com Dan Hook

For additional information on NETA visit netaworld.org

CANADA

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Magna IV Engineering Suite 200, 688 Heritage Dr. SE Calgary, AB T2H 1M6 Canada (403) 723-0575 Fax: (403) 723-0580 www.magnaiv.com

228

Magna IV Engineering 1103 Parsons Rd. SW Edmonton, AB T6X 0X2 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Virginia Balitski

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Magna IV Engineering 106, 4268 Lozells Ave. Burnaby, BC VSA 0C6 Canada (604) 421-8020

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Magna IV Engineering 141 Fox Cresent Fort McMurray, AB T9K 0C1 Canada (780) 462-3111 Fax: (780) 450-2994 [email protected] www.magnaiv.com Ryan Morgan Shermco Industries Canada 3434 25th Street NE Calgary, AB T1Y 6C1 (403) 769-9300 [email protected] www.shermco.com

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Shermco Industries Canada 241 3731-98 Street Edmonton, AB T6E 5N2 Canada (780) 436-8831 Fax: (780) 463-9646 [email protected] www.shermco.com Shermco Industries Canada 1033 Kearns Crescent RM of Sherwood SK S4K 0A2 (306) 949-8131 [email protected] www.shermco.com Shermco Industries Canada 1375 Church Ave. Winnipeg, MB R2X 2T7 Canada (204) 925-4022 Fax: (204) 925-4021 www.shermco.com Orbis Engineering Field Services Ltd. #300, 9404 - 41st Ave. Edmonton, AB T6E 6G8 Canada (780) 988-1455 Fax: (780) 988-0191 [email protected] www.orbisengineering.net Lorne Gara

REV 01.19

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Pacific Powertech, Inc. 245 #110, 2071 Kingsway Ave. Port Coquitlam, BC V3C 6N2 Canada (604) 944-6697 Fax: (604) 944-1271 [email protected] www.pacificpowertech.ca Josh Konkin REV Engineering Ltd. 3236 - 50 Ave. SE Calgary, AB T2B 3A3 Canada (403) 287-0156 Fax: (403) 287-0198 [email protected] www.reveng.ca Roland Nicholas Davidson, IV Rondar Inc. 333 Centennial Parkway North Hamilton, ON L8E2X6 (905) 561-2808 www.rondar.com Gary Hysop

BRUSSELS 246

Magna IV Engineering 7, 3040 Miners Ave. Saskatoon, SK S7K 5V1 (306) 713-2167 www.magnaiv.com Adam Jaques [email protected] Pace Technologies, Inc. #10, 883 McCurdy Place Kelowna , BC V1X 8C8 (250) 712-0091 www.pacetechnologies.com

Shermco Industries Boulevard Saint-Michel 47 1040 Brussels, Brussels, Belgium +32 (0)2 400 00 54 Fax: +32 (0)2 400 00 32 [email protected] www.shermco.com

CHILE 247

Magna IV Engineering Avenida del Condor Sur #590 Officina 601 Huechuraba, Santiago 8580676 Chile +(56) -2-26552600 [email protected] Henry Mendoza

248

Orbis Engineering Field Services Ltd. Badajoz #45, Piso 17 Las Condes, Santiago +56 2 29402343 www.orbisengineering.net

Rondar Inc. 9-160 Konrad Crescent Markham, ON L3R9T9 (905) 943-7640 www.rondar.com Shermco Industries Canada 233 Faithfull Cr. Saskatoon, SK S7K 8H7 (306) 955-8131 www.shermco.com [email protected]

Pace Technologies, Inc. 9604 - 41 Avenue NW Edmonton, AB T6E 6G9 (780) 450-0404 [email protected] www.pacetechnologies.com Craig Leavitt

PUERTO RICO 249

Phasor Engineering Sabaneta Industrial Park #216 Mercedita, PR 00715 Puerto Rico (787) 844-9366 Fax: (787) 841-6385 [email protected] www.phasorinc.com Rafael Castro

Advanced Electrical Services 4999 - 43rd St. NE, Unit 143 Calgary, AB T2B 3N4 (403) 697-3747 [email protected] www.aes-ab.com Zachary Houk Orbis Engineering Field Services Ltd. #228 - 18 Royal Vista Link NW Calgary, AB T3R 0K4 (403) 374-0051 www.orbisengineering.net

For additional information on NETA visit netaworld.org

ABOUT THE INTERNATIONAL ELECTRICAL TESTING ASSOCIATION The InterNational Electrical Testing Association (NETA) is an accredited standards developer for the American National Standards Institute (ANSI) and defines the standards by which electrical equipment is deemed safe and reliable. NETA Certified Technicians conduct the tests that ensure this equipment meets the Association’s stringent specifications. NETA is the leading source of specifications, procedures, testing, and requirements, not only for commissioning new equipment but for testing the reliability and performance of existing equipment.

CERTIFICATION Certification of competency is particularly important in the electrical testing industry. Inherent in the determination of the equipment’s serviceability is the prerequisite that individuals performing the tests be capable of conducting the tests in a safe manner and with complete knowledge of the hazards involved. They must also evaluate the test data and make an informed judgment on the continued serviceability, deterioration, or nonserviceability of the specific equipment. NETA, a nationally-recognized certification agency, provides recognition of four levels of competency within the electrical testing industry in accordance with ANSI/NETA ETT2018 Standard for Certification of Electrical Testing Technicians.

QUALIFICATIONS OF THE TESTING ORGANIZATION An independent overview is the only method of determining the long-term usage of electrical apparatus and its suitability for the intended purpose. NETA Accredited Companies best support the interest of the owner, as the objectivity and competency of the testing firm is as important as the competency of the individual technician. NETA Accredited Companies are part of an independent, third-party electrical testing association dedicated to setting world standards in electrical maintenance and acceptance testing. Hiring a NETA Accredited Company assures the customer that: •

The NETA Technician has broad-based knowledge — this person is trained to inspect, test, maintain, and calibrate all types of electrical equipment in all types of industries.

•

NETA Technicians meet stringent educational and experience requirements in accordance with ANSI/NETA ETT-2018 Standard for Certification of Electrical Testing Technicians.

•

A Registered Professional Engineer will review all engineering reports

•

All tests will be performed objectively, according to NETA specifications, using calibrated instruments traceable to the National Institute of Science and Technology (NIST).

•

The firm is a well-established, full-service electrical testing business.

Setting the Standard

Circuit Breaker Services

from

For Circuit Breaker Maintenance Solutions, Shermco Industries offers fast turnarounds, reliable repairs and state-of-the-art upgrades performed by knowledgeable, NETA certified technicians at multiple locations. From high voltage substations to industrial distribution needs, our comprehensive services and a “zero defects” approach assures trouble free operation and reliable performance. Our new mobile services include on-site reconditioning and remanufacturing for most breaker styles and our SF6 and oil processing trailers can get you up and running faster than fast.

Breaker Services Molded and Insulated Case Circuit Breakers Low Voltage Power Circuit Breakers Medium Voltage Circuit Breakers Load Break Switches Motor Starters Contactors Primary and Secondary Injection Testing Acceptance Testing Preventative Maintenance Testing Limited Overhauls/Reconditioning Remanufacturing

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Contact Replacement & Resurfacing Repairs Rental Breakers Core exchange Trip Unit Retrofits Medium Voltage Vacuum Retrofits and Replacements Warehouse of Parts, Breakers and Surplus Items Warranty Coverage Emergency/After-Hour Service and Support

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(be_this_guy!) Train with the Experts. Train with Shermco. www.shermco.com 888-SHERMCO

VOLUME 2

SAFETY Vol. 2 HANDBOOK

SERIES III

HANDBOOK

Published By

SAFETY

SERIES III

SAFETY VOL. 2 HANDBOOK

Published by

InterNational Electrical Testing Association

SAFETY VOL. 2 HANDBOOK TABLE OF CONTENTS Finding and Retaining Qualified Electrical Workers: It’s About Safety in the Workplace ...................................................................... 5 Mike Moore

The Importance of an Effective Electrical Safety Program...................................... 10 Daryld Ray Crow

Internal Electrical Safety Audit .......................................................................... 14 Terry Becker

How OSHA and the NFPA Work Together ......................................................... 21 Ron Widup and Jim White

Safety Tips for Qualified Persons ...................................................................... 23 Jim White

Rotating Machinery Hazard Awareness............................................................. 27 Scott Blizard and Paul Chamberlain

Electrical Safety Myths and Rumors ................................................................... 31 David K. Kreger

Determining Maintenance Intervals for Safe Operation of Circuit Breakers ............. 34 Jim White

Reduce Risk with PESDs Making NFPA 70E Compliance Safer .............................. 40 Phil Allen

The Electrical Safety Trifecta ............................................................................. 46 Terry Becker

Published by

InterNational Electrical Testing Association 3050 Old Centre Kà] ¡ , Suite 101, Portage, Michigan 49024

269.488.6382

www.netaworld.org

Planning and Performing a Power Quality Survey ............................................... 48 Ross Ingall and Richard Bingham

Hand Protection ............................................................................................. 53 Paul Chamberlain

Commissioning Progress Communication ........................................................... 57 Michael Lewark

Extension Cord Safety ..................................................................................... 61 Dennis Neitzel

Significant Change to OSHA’s 1910.26 and 1926 Regulations ........................... 67 Jim White

The Impact of Electrical Safety to Maintenance: NFPA 70B and CSA Z463 ............ 73 Jim White and Jarret Solberg

Protective Devices Maintenance and the Potential Impact on Arc Flash Incident Energy ............................................................................ 80 Dennis Neitzel

Potential Impact of ISO 55000 on Maintenance Critical to Electrical Safety ........... 87 H. Landis Floyd

Published by

InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024

269.488.6382

www.netaworld.org

Published by InterNational Electrical Testing Association 3050 Old Centre Road, Suite 101, Portage, Michigan 49024 269.488.6382 www.netaworld.org

NOTICE AND DISCLAIMER NETA Technical Papers and Articles are published by the InterNational Electrical Testing Association. Opinions, views, and conclusions expressed in articles herein are those of the authors and not necessarily those of NETA. Publication herein does not constitute or imply any endorsement of any opinion, product, or service by NETA, its directors, officers, members, employees, or agents (hereinafter “NETA”). All technical data in this publication reflects the experience of individuals using specific tools, products, equipment, and components under specific conditions and circumstances which may or may not be fully reported and over which NETA has neither exercised nor reserved control. Such data has not been independently tested or otherwise verified by NETA. NETA makes no endorsement, representation or warranty as to any opinion, product or service referenced in this publication. NETA expressly disclaims any and all liability to any consumer, purchaser or any other person using any product or service referenced herein for any injuries or damages of any kind whatsoever, including, but not limited to, any consequential, special incidental, direct or indirect damages. NETA further disclaims any and all warranties, express or implied, including, but not limited to, any implied warranty or merchantability or any implied warranty of fitness for a particular purpose. Please Note: All biographies of authors and presenters contained herein are reflective of the professional standing of these individuals at the time the articles were originally published. Titles, companies, and other factors may have changed since the original publication date.

Copyright © 2019 by InterNational Electrical Testing Association, all rights reserved. No part of this publication may be reproduced in any form or by any means, electronic or mechanical, without permission in writing from the publisher.

5

Safety Vol. 2

FINDING AND RETAINING QUALIFIED ELECTRICAL WORKERS: IT’S ABOUT SAFETY IN THE WORKPLACE PowerTest 2013 Mike Moore, Shermco Industries Do you believe that positive safe behaviors and actions are inherently programmed into each human from birth or that these traits are learned as we progress in life? Do you think that some workers may not have the mental faculties to learn these positive safe behaviors and actions due to their life origin or life status? To offer any answers to these questions we must delve into some controversial topics and conversations that will surely create more questions, but it’s a much needed effort when as industry leaders that actually engage in electrical safety techniques and practices multiple times per day; we may have to make life or death decisions on the behalf of our subordinates. Electrical workers that interact with energized equipment face some very unique hazards not found in any other occupation. These electrical hazards such as electric shock, arc blast and arc flash can offer disabling injuries, traumatic burns and even worse, death. Since the late 1990’s a heightened awareness has been placed on the protection of electrical workers worldwide. Training, clothing, regulatory language, equipment labeling, hazard documentation and communication, procedures, maintenance planning/ cycles and electrical equipment engineering enhancements have positively changed the electrical workers life for the better, but we still have numerous ideological challenges to overcome with our fellow electrical workers. In this litigious society we live in today we as managers and leaders in the electrical industry have to make very unique and complicated decisions about our fellow electrical workers and the electrical contractors we hire every day. Just knowing the “electrical business”, and asking a few questions about safety practices and electrical skills isn’t going to cut it anymore. This paper will challenge the way in which you qualify electrical workers prior to their employment and how you qualify the electrical contractors that work in and around your electrical workers every day. As the manager or leader of a crew performing electrical work you have to be in the know about all the workers on your site and have the ultimate goal of keeping all of the site’s electrical workers safe. Sometimes you may just have to say no, not today, maybe you can do this task another day!

THE LABOR EPIDEMIC Before we get too far into this paper, let’s discuss the compounding challenges of retaining your current electrical workers.

The pool for skilled, safe, qualified electrical workers is basically tapped out. You have to recruit them from somebody else with better wages, better benefits or some other special deal. Hiring, training and qualifying newer electrical workers is like herding cats, it isn’t going anywhere fast. There are numerous challenges you have to think through with the newly hired workers. Why, do you ask? Read below. Purge your mind of all politics and preconceived notions about labor, the economy, the President and whatever conspiracy theory you may have and let’s look at some statistics. The United States of America is in a national labor emergency of epidemic proportions; yes, it’s an emergency when you can’t fill your ranks with skilled, qualified and ready to work technicians and engineers. The unemployment rate has consistently stayed over or around 8.2% for the last 17 months. The jobless rate has been as high as 9.2% in the last 3 years and close to 23 million people are either underemployed, out of work or have completely given up looking for work. New jobless claims are still over 350,000 per month, incomes for workers are spiraling downward, and millions of recent college graduates have nothing to look forward to after clearing the last step of their graduation stage. Additionally the current skilled workforce is losing its qualified and experienced workers at an average rate of ten thousand per year. These are the senior, experienced, knowledgeable, qualified workers that will turn 65 years of age, every day, for the next 20 years and as these 73 million workers leave the marketplace so do their skills, talents, knowledge, and inherent trade techniques. Since the end of World War II there has been an accelerating decline in skilled workers. This decline was not evident as the American economic engine revved up in the 50’s, 60’s, 70’s, 80’s, and into the roaring 90’s. The Baby Boomers were the largest contributor to the skilled labor pool while the most recent generations of “X” and emerging generation of “Y” have not met the demand of the industry to date. To further the question concerning the lack of talent in the labor pool, the streets of many of our great cities are full of the young 99%’ers’. The 99%’ers are the unemployed, twenty-somethings who are college educated, seem motivated to work and demand high paying jobs that are at a near riot status in our major cities. We constantly heard the back and forth rhetoric from our political representatives during our recent political debates about how America is moving towards a “landmark general election” and that

6 “the need for jobs” is at the center of the debate. The old class warfare debate is as strong as ever with snarling attacks from both sides. With these kinds of numbers, facts and opportunities left open, who would ever have thought that there was such a large unmet demand for skilled labor. Who would ever have thought that the need for skilled labor would be in a niche market sector like the electrical installation, maintenance, testing & repair of electrical systems and equipment? How do the newer generations of Americans fit into the demand for skilled labor and safety?

GENERATIONAL TRENDS The “Baby Boomers” The Baby Boomer Generation, by definition are people who were born between the years 1946 and 1964. As of right now Baby Boomers are between the ages of 44 and 62. The Boomer generations are the folks who built and motivated the American economy for the last 60 years. Their social, cultural and economic impact on the United States has been unprecedented in its history and is currently the single largest economic group in the United States today. The Boomers’ “work hard, play hard” mentality allowed them to have one of the highest discretionary income levels (wealth) over any other age group and they account for 45% of all consumer demand. As these Boomers retire and leave the workforce, the demands they place on the goods producers and service providers will create some challenges as there are fewer qualified workers to produce and service the retiring Boomer society. However, the Baby Boomers as a whole did not save very effectively for retirement and some may be retiring too early, or moving into a less demanding working pattern, working less rigid jobs, playing golf on weekends and dining at leisure all while still possessing their skills, talents, knowledge, and inherent trade techniques from a lifetime of hard work and no way to pass these skillsets. The exit of the Baby Boomer generation compounds an already looming crisis with the lack of qualified and skilled workers that has existed over the last 30 years. Skill levels in the US workforce have stagnated with Americans 25–34 years of age who do not possess the higher skills that their Baby Boomer parents do.

The “X Generation” The 46 million X Generation of sons and daughters of the Baby Boomers did not wholly move into the skilled trade sectors, but instead went to college, sought professional degrees, jobs and technical assignments overall, making much less income than their Boomer parents. They are officially the first generation to challenge the notion that each generation will be better off than the one that preceded it. A study, “Economic Mobility: Is the American Dream Alive and Well?” focuses on the income of males 30-39 in 2004 (those born April, 1964 – March, 1974) and is based on Census/BLS CPS March supplement data. The study, which was

Safety Vol. 2 released on May 25, 2007, emphasized that in real dollars, this generation’s men made less (by 12%) than their fathers had at that same age in 1974, thus reversing a historical trend. The study also suggests that per year increases in the portion of father/son family household income generated by fathers/sons have slowed (from an average of 0.9% to 0.3%), barely keeping pace with inflation, though increases in overall father/son family household income are progressively higher each year because more women are entering the workplace, contributing to family household income. In the next 5 years the X Generation will make up the largest majority of the workforce in America replacing the roughly 20 million skilled Boomers with only a third of the skilled workforce required to support the demands for goods and services. The balance of the X Generation will continue to work in the professional services sector.

The “Y Generation” The roughly 80 million Y Generation folks entering the workforce today are the most technologically diverse generation in American history, but they barely make the global top ten of educated and trainable workers. America is no longer a skill-abundant country compared with an increasing share of the rest of the world. As a result, in the coming decade, America will face broad and substantial skill shortages. The Y Generation prefers to work independently with self-directed projects; prefers learning that provides interaction with their colleagues who they also consider as their friends and require much more structure and direction. Many Y Generation children were born from teenagers to middle-aged moms who postponed childbearing to establish a career. One third of this generation was born to single, unwed mothers. This generation is polite, believes in manners, adheres to strict moral codes, and believes in civic action. This is a generation that places a generally high value on making money - more than any previous generation - and they see education as a means to this goal.

Workforce Challenges Like the X Generation before them, they seek professional careers. Studies predict that Generation Y will switch jobs frequently and will not have the passion for “the company” that the older and more career established employees do. They require learning to be entertaining and fun, and become quickly bored in a learning environment that is not highly active and interactive. With the global booming numbers of Y Generational workers added to the employment pool, economic prospects for the Y generation look bleak due to the late 2000 and 2008 recessions. As of July 2012, the seasonally adjusted jobless rate for people 20 to 24 years old was 13.5 percent. For workers aged 25 to 29, the rate (available only on an unadjusted basis) was 9.3 percent, a full percentage point above the national rate. As the Boomers exit the workforce over the next 10 years, the small in scale X generation will try to fill the gap. The X generation

7

Safety Vol. 2 will never stand a chance to meet the needs of the demands of the industry, it was just too small. As the Y generation moves into the workforce they do not seem to be as motivated to take skilled labor or “hands-on” jobs. The industrial sector does not seem appealing to the Y Generation who chose to attend college and graduated with expectations of hitting the labor pool at the same income level as their parents. It remains to be seen where this generation will end up, but whatever the outcome, working long distances from home in remote isolated areas with limited communications and long workdays away from social circles may create a challenge in retaining these folks. The question arises; who in the heck is going to move this country forward in the next 10 – 20 years?

Generations and Change With that said, it’s time to start off with a shot across the bow while trying to write a politically correct paper. The generational classes may affect work ethic; how generations think and react about how their personal safety and the safety of those that work around them? It’s done, I said it; the successful development of a safety minded culture may be affected by age! One example, younger workers may consider themselves as bulletproof and invincible and may exhibit a complete lack of fear and awareness. They may not have the intensity or faculties to evaluate their task and the hazards involved with the task at hand as an older experienced worker would who may feel he has more to live for and chooses not to take unreasonable risks. This generational related risk-taking behavior is not new among workers in any organization. A second example of this behavior is that Baby Boomers may be more likely to cut corners to save money or get the job done on time. As the loyal and faithful worker the Boomer is concerned with fulfilling the profit potential of an organization, so they may take more risks. So are these statements real or just some arbitrary gut feeling? The American Society of Safety Engineers is urging business to modify their workplace safety efforts to accompany a changing workforce. Currently the workplace injury rates for older workers are the lowest of any age group, but their fatality rate is the highest. The U.S. Dept. of Labor’s (DOL) workplace statistics for 2004 show that those 64 and older had the lowest number of workplace injuries, but the fatality rate for those 55 and older rose by 10 percent. In 2003, workers 65 and older “continued to record the highest fatality rate of any other age group, more than three times the rate of fatalities for those aged 25-34,” according to the DOL. Most of these fatalities were transportation-related, from falls, from being struck by an object and from homicides. This leaves another question that is usually bypassed, discussed in another manner, or worse never addressed. How do you communicate the very real challenges utilizing the skills of the workers in each scenario? As an electrical worker they are reviewed and receive salary advances based off of their performance, skills and

safety culture. Sometimes you just have to say no, not today; if a worker does not have the skills or the ability to perform a high risk task, reassignment is needed!

SAFETY AND BEHAVIORS Behavior Based Safety Culture The behavior-based safety culture on any worksite is based on the notion that the “safety culture” is a learned culture and that culture is a product of organizational learning through behavioral awareness and training. If these behaviors are the ‘ingredient’ that pulls everything together to lead to a safe and healthful job completion, then the additional ingredients must be high quality management policies, job planning documents, quality project materials, serviceable job related equipment and qualified workers. When all the correct ingredients are in place they trigger people’s safe behavior on the job. For example, if quality equipment was missing from the job site, people will typically become innovative and either use make-shift equipment, or take short-cuts just to get the job done. This would be a key ingredient for unsafe behaviors. In other words, the lack of quality ingredients will lead to unsafe or risky behaviors. The negative aspect of a behavior-based safety culture is based on the notion that some people often find that unsafe behavior is rewarding in some way. For example you hear “safety practices and paperwork make the job slower and take more people to the job” or that the use of PPE is a punishment for prior poor performance, “PPE is too burdensome to work in, this task will only take a minute, let’s get it done before the boss gets in and sees us without PPE”. The more this risky behavior goes on and workers are injured, the more the behavior is reinforced in the minds of the workers. Jim White, who is an electrical safety and skills trainer at Shermco Industries, always comments in safety discussions similar to this one, “that the reason that folks survive situations like this is that they are either lucky or good”. With this said, it sounds as if you buy the best project and safety stuff, employ the very best folks, have the very best management policies and procedures, have the best job and safety skills and the very best safety training that coincidentally you will have the better safety culture than that of a less fortunate company that performs similar work. This just goes to show that companies that are truly safety driven and actually instill safety in the minds of their workers have the best overall safety records, lower incident rates and higher morale in the ranks. When hiring experienced electrical workers from other employers in the industry you must understand the safety culture from which they came. Asking questions about the qualifications and work experiences of the electrical worker is a given, additionally direct and specific questions about their past employers management policies, practices, job planning documents and how they maintained their job-related equipment can give you a view into the behavioral practices of that worker. Electrical workers that

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are moving from lower tier companies may require a more robust approach acclimating them to the safety culture that you have in place. It makes all the sense in the world to pair new electrical workers with the best-of-the best in your organization so that your safety culture is rubbed into the newer electrical worker on the job.

cal limits of approach, electrical personal protective equipment (PPE), servicing energized equipment, Lock Out/Tag Out, alerting techniques, test instruments calibration, how to understand NFPA Labeling of electrical gear, responsibilities for Electrical Safety and responsibilities for the training requirements.

When hiring contractors a much bigger set of responsibilities and liabilities are introduced to the worksite, as well as new risks exposed to your employees. The introduction of third-party contractors to the worksite is one of the biggest exposures of liability and risk that you face regardless whether your company is the host employer or a subcontractor to the host. The electrical contractor is usually recognized as “knowledgeable” and usually gives the impression that “they know what they are doing”. Most owners trust the contractor completely based off of some perception they have endless labor resources and capabilities. Additionally qualifications such as “Journeyman” & “Master” electrician are sometimes viewed and accepted as being highly qualified to perform high-risk tasks with no regard to questioning the safety and skills training of the electrical workers, the company’s management policies, practices, job planning documents or how they maintained their job-related equipment. If the worker will need additional training and evaluation he may be a hazard to himself. Sometimes you just have to say no, not today, maybe never to a contractor, even if you have had a long term relationship with them!

Now that the company has been evaluated, let’s move to the workers, and evaluate them before they ever hit the worksite. Request copies of the resumes of all workers especially the managers. Request copies of training certificates for skills and safety training and start asking questions of all the electrical workers about electrical hazard identification and mitigation and how they work within the management policies and practices. Once the contractors arrive on the worksite, be involved in the contractor’s hazard risk analysis/ job safety analysis process. Inspect the contractor’s tools and equipment for calibration, serviceability and “prior use”. Once the contractors are on site continue to inspect the worksite, ask questions and look for hazards, as well as communicating and mitigating any hazards that may be found.

How do you ensure you’re getting a safe contractor in the door that has the desired safety culture and technical depth and talent? Prior to the performance of any work you should qualify the company to make sure their safety goals align with yours, and then qualify the electrical workers to ensure that they can safely perform their services for your customer and lively hood, as well as safely interact with your electrical workers. ● As the owner or host of an electrical contractor it’s time to start the game of show and tell. At the very minimum you need to see the following from the contractor prior to the performance of any work. Always start by asking for specific information about the company such as OSHA 300 records of which can tell you a lot about past illnesses and injuries that arise from exposures in the work environment.

Be in touch with the contractors at an almost personal level. There are some factors that affect how frequently and how closely you as the controlling employer must inspect them in order to meet the legal case standards of reasonable care. Reasonable Care is the legal obligation imposed on an employer by OSHA. It requires they adhere to a standard of reasonable care to “foresee hazards that could potentially harm others”. That’s legal language meaning that you are responsible for your contractors and what they do and you have to show that you clean up after them or keep them safe and healthful. First thing you have to show is how much the controlling employer knows both about the safety history and safety practices of the employer it controls and about that employer’s level of expertise. This should be documented prior to hiring the contractor. Second you have to show how you will enforce the other employer’s compliance with your safety and health requirements. Third you have to show that you have a plan to enforce the other employers’ compliance with safety and health requirements with an effective, graduated system of enforcement and follow-up inspections. Better said, yet better proven by documentation in a safety plan prior to the start of the project

● Ask for their recordable rate, also known as the TRIR which is a measure of the rate of recordable workplace injuries, normalized per 100 workers per year.

If the contractor balks at these requests, sometimes you just have to say no to them, not today, you’re not qualified to work for the owner or host!

● You need to also request to review their experience modifier or “EMR,” which is the number used by insurance companies to gauge the past cost of injuries, as well as the future chances of risk. Usually an EMR of 1.0 is considered the industry average, but anything over .5 to .6 deserves some Q & A. Lastly, obtain copies of the contractor’s management policies and practices such as their ESP or electrical safety program.

Rational and Emotional Intelligence

● Key points of review need to be their policies and procedures that cover their electrical safe work practices, electrical energized work practices, electrical shock approach boundaries, electri-

Emotional intelligence (EI) refers to the ability to perceive, control and evaluate emotions. Some researchers suggest that emotional intelligence can be learned and strengthened, while others claim it is an inborn characteristic. Though at first, the thought you may have is how does EI have anything to do with safety and safety culture? It has much to do with how we perceive, reason, understand and manage the verbal or nonverbal external information we receive and how it’s delivered and how we accept this verbal or nonverbal information and mentally process that in-

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Safety Vol. 2 formation. We all perceive others through the filter or perspective of our own cultural upbringing, often without being aware of it: communication can go wrong without our understanding why. Think about it, if you are worried, having a bad day, frightened, or even happily excited, your thought processes can be impacted as they would be if you were engaged in an intense phone call or after having consumed several alcoholic drinks. Think how “off your game” you would be if your boss had just chewed you out, your significant other just left you or your dog died and you were in the midst of performing high risk energized work, your thoughts would not be 100% on the task at hand. Keeping emotions in control while in the performance of electrical work isn’t easy, but taking steps to clear the mind makes a huge difference. These distractions are huge and could be documented on the JHA or alternate sources as a mental release, or a way to communicate that added hazard that you may need a little help in switching to your “A game”. Regardless how you feel about the situation you can’t allow yourself or other workers to fall into your trance. Emotional development plays a key role in electrical safety as well. If the developmental level of a person, which is controlled by and usually the same as the highest parent, is that of a teenager, then some thoughts about the emotional maturity of the electrical worker need to be thought through. We know of workers that seem to peek at a low to moderate skillset and never have higher aspirations or achieve what they ought to be capable of as their tenure grows. This may be an ED or EI issue. Much research is underway on the subjects of emotional intelligence and emotional development and there is key evidence emerging about the impact these two subjects have on the workforce. When managing electrical workers being involved in their personal life is tough and it is usually sacred ground not to be crossed, but when the performance of their duties can be affected by their current life challenges the intrusion is justified and legally required. Sometimes you just have to say no, not today, reassignment!

Programming the Change Changing the safety culture in any company involves some very critical elements. One major element is leadership! Senior management has to be in the lead and the prime influence to make the safety culture change a reality. This means creating, directing, reinforcing, and enforcing management policy at all levels of the organization with full visibility, best indicated by the time they devote to safety matters. The middle management down through the supervisor and line management have to be empowered and have some degree of autonomy for safety initiatives. Leaders have to stay relevant and keep abreast of new skills and techniques to operate in this new era, and the challenges they will face if they decide to remain stagnant. Leaders must be challenging, engaging, inspiring and influencing, but most of all they must have high credibility in the organization, meaning that you are

willing to admit mistakes to yourself and others, give honest information about safety performance even if it is not well received, and follow through on safety-related commitments. Excellence in safety performance easily correlates with excellence in other performance metrics such as productivity, profitability, quality, moral and customer service. Work place demographics are changing, with employee populations growing more diverse in background, belief, and geography. So too are business practices. The second critical element for changing the safety culture in any company involves acknowledging that safety is a “core business value” and integral to the very existence of the organization. This key element must be communicated and instilled in the individual employee at work and at home. This means it’s a functional lifestyle change from risk taking behaviors at home and with the family. The employee actually becomes an active part of building a safety culture and will be able to protect what really matters to them at work and away.

SUMMARY Once again, when discussing the topics of life origin and life status controversy ensues almost every time and someone cries afoul, but when it comes to the safe performance of your duties in and around electrical installations, some people just don’t get it. As a leader you make a determination if a person is not qualified to work for the day, un-trainable or un-savable and these decisions are especially tough when it’s nearly impossible to find a trained and qualified replacement worker to take up the slack, but not having a preventable injury, or worse a death on your conscience is huge! Just a note of reference about generational workers; at times stereotypical references are made about the generational aspects of the American culture and it’s important not to make assumptions about individuals based on age. Not every boomer is ignorant of technology and not every Generation Y worker is lazy and uncommitted. Blending the experience of the older generations with the freshness of younger generations can yield positive results for employers. Multigenerational viewpoints can enrich the workplace, so organizations should use this as a strength. The employment contract of the 21st century is different from when the baby boomers first entered the workforce. The relationship is more fluid for both employer and employee – younger employees may be more mobile and appear less loyal, but the same is true of most organizations and has been for the last 70 years.

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THE IMPORTANCE OF AN EFFECTIVE ELECTRICAL SAFETY PROGRAM PowerTest 2013 Daryld Ray Crow, DRC Consulting, Ltd.

ABSTRACT The purpose of this paper is to cover the importance of developing, implementing, and maintaining an electrical safety program. It includes key elements of an electrical safety program and provides information on where the gaps may be in your existing program. Index Terms — Electrical Safety Program, Key Program Elements, Safe Work Practices

INTRODUCTION Developing, implementing, and maintaining an electrical safety program is critical to help ensure the safety of personnel working in your facility. Having an electrical safe program is a mandatory requirement in NFPA 70E “Standard for Electrical Safety in the Workplace” and CSA Z462 “Workplace Electrical safety”.12 Both standards require the employer to implement and document an overall electrical safety program that directs activity appropriate for the voltage, energy level, and circuit conditions. The electrical safety program must be written, published, and available to all employees. The electrical safety program must be appropriate for the conditions that exist on the site. Electrical safety training of your personnel and auditing of your electrical safety program as well as auditing of field work should be a requirement in your electrical safety program.

REASONS TO HAVE AN ELECTRICAL SAFETY PROGRAM Most incidents and injuries related to electrical systems can be avoided by following the safe work practices outlined in an effective electrical safety program. Besides the personal pain of suffering an injury, incidents can result in lost time, medical costs, equipment damage, production loss, and legal costs. Four important reasons to have an electrical safety program are: it’s the right thing to do, the legal aspects, it documents rules, policies and practices, and the economic issues.3

It’s The Right Thing To Do The electrical safety program should be based on and require an attitude of caring. It should include concern about the well-being and safety of employees and their co-workers. An effective electri-

cal safety program provides written direction to workers, establishes safe work requirements, and provides performance measures. It includes guidelines to ensure a safe workplace for all employees who work in an environment where an electrical hazard may exist.

Legal Aspects Meeting the requirements of local regulation and consensus standards including safe guarding employees from shock and flash hazards is mandatory. U.S. OSHA regulations, Canadian Provincial and Federal OH&S Regulations, ANSI Z10, CSA Z1000, EN 50110-1, NFPA 70E, and CSA Z462 are examples of these documents.

Documents Rules, Policies, and Practices The program should provide clear guidance and requirements that include documented work rules, policies and practices. The employer is responsible to ensure that all hazards in the workplace are understood. The employer must work with employees to generate procedures for implementation by employees and train employees to understand and implement the electrical safety program and associated procedures. Documentation should include single line drawings that are up-to-date and readily available. The employees are responsible for implementing the electrical safety program principles, controls, and procedures. An effective electrical safety program is a powerful resource for arc flash & shock hazard management and allows for enforcement.

Economic Issues Economics is another reason for implementing an effective electrical safety program. A written program that provides clear guidance for accepted work practices to employees will help prevent low morale and productivity in the workplace. The policy should include a requirement for investigating and reporting all incidents from a fact finding not fault finding concept to find the root causes of incidents. This concept will help prevent these issues from happening in the future. Preventing future incidents will provide a safer work place for employees, lead to minimizing medical costs, legal costs, insurance costs, and repair and replacement of failed equipment, as well as loss production due to failure of equipment. Dollars spent on implementing an effective electrical safety program reportedly results in a 400 percent return on Investment.4

Safety Vol. 2 DIFFERENT APPROACHES TO CREATING AN ELECTRICAL SAFETY PROGRAM There are different approaches to creating an effective electrical safety program. One can use existing company resources. This approach could utilize a key safety expert within the company or it could use a companywide safety team/committee consisting of cross functional and facilities personnel to write the program. One can also use an outside consultant that specializes in providing electrical safety programs for different companies. If an outside source is used, the written document should be reviewed and approved by a company safety team/committee.5 Establish an electrical safety team/committee to manage the electrical safety program, Implement electrical safe work practice training, and provide overall guidance for the electrical safety program. For an electrical safety program to be successful it requires sponsorship from key upper management. The program must be written, be readily available to all employees, and require training to ensure understanding of the requirements in the document. The program should mandate electrical safe work practice training and refresher training that includes class room training and on-the-job training. The electrical safety program needs a champion(s) at the worker level. Employee involvement in safety is a key element to developing a positive peer pressure that will not tolerate unsafe behaviors. 6

KEY ELEMENTS OF AN ELECTRICAL SAFETY PROGRAM The purpose and scope of the electrical safety program should be clearly defined. Identify the objective and limitations of the program including the support by management and basic corporate beliefs. (Example: “All injuries are preventable. Sound safety practices are a condition of employment”).5 The program should identify the roles and responsibilities of management and supervisors, employees, contractors, and visitors. Program principles, preventive and protective measures, and the requirement for documented work procedures should be included. The program needs to have a requirement to ensure the qualification of employees that includes demonstration of understanding and proficiency to perform required tasks. Competency must be demonstrated. The requirement should include a review of the employee’s current roles and responsibilities and define clear responsibilities and requirements (Ensure the right worker is doing the right work) 7 Mandate periodic audits of the electrical safety program and its rules, policies, and practices to ensure compliance and to verify that the preventive and protective control measures are working. Auditing should include periodic audits at the supervisory level, annual internal audits, and external audits not to exceed once every three years.8 A safety program should include a requirement for holding a meeting with contractors before allowing them to work on your

11 site. The meeting should include discussions on hazards that may exist during the contract employer’s work and the safe work practice requirements that must be followed during work at your facility. The meeting should also include feedback from the contractor of any hazards that may be created by the contactor’s work. The meeting should be documented by the employer.12 A job briefing should be required before start of work. Effective job briefings save lives. Include the requirement that single line drawings are up-to-date and readily available. Guidance on the requirements and rules for switching procedures should also be provided. Include the requirements for working inside the Limited Approach Boundary of energized electrical conductors or circuit parts and the requirement to create an electrically safe work condition before start of work (exceptions: diagnostic testing, trouble shooting, infeasibility). The program should include other electrical safety issues specific to your facility such as specialized equipment and the associated work tasks related to that equipment.9 Only electrically qualified persons should be allowed to work on exposed energized electrical conductors or exposed parts above 50 volts. Working on exposed energized electrical conductors and circuit parts should only be allowed as a last resort. Energized work should only be allowed when an energized electrical work permit (EEWP) is issued by upper management. The EEWP should include the requirement for a hazard risk evaluation procedure before start of work on energized conductors or circuit parts. The hazard risk analysis should include a shock hazard analysis and an arc flash hazard analysis (see annex F in NFPA 70E and CSA Z462). Identify the training requirements for electrically qualified and unqualified persons. Training should include but is not limited to working near un-insulated overhead power lines, the use of barricades/work zones, understanding the shock boundaries (limited, restricted, and prohibited), the arc flash boundary and requirements for arc rated clothing and PPE, emergency procedure training, the requirements for first aid and emergency procedures including CPR, methods of release of victims from contact with exposed energized electrical conductors or circuit parts, and training on the care, use, and maintenance of electrical specific PPE, tools, and equipment including the use of temporary protective grounds where required. Lockout/tagout training is mandatory. All training must be documented.10 Only qualified people should be allowed to use electrical test instruments and equipment. Identify the type of meters and equipment that can be used at the facility. The program should identify required test procedures and documentation requirements for rubber insulating protective equipment and insulated tools and equipment including insulated bucket trucks. Include the requirement to use GFCIs or an assured grounding program on all cord-and-plug connected equipment. Consider the use of battery operated tools where appropriate.

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HIERARCHY OF CONTROLS

Training and Refresher Training

Safety-related work practices and PPE requirements are just two components of an overall electrical safety program. ANSI/AIHA Z10, CAN/CSA Z1000, ISO 14001, and OSHA 18001 provide additional information on the elements that should be included in an overall safety program. “Hierarchy of Controls” should be considered when creating a holistic safety program. The key elements include Engineering Controls, Policies and Procedures, Training – Classroom and On-The-Job training and Refresher Training, and Personal Protective Equipment.11 All these elements are important; however, the most effective element is engineering controls. Design the equipment and electrical system to prevent or minimize people being exposed to electrical hazards.

Training should include classroom training and on-the-job training. Both types of training are important. Classroom training provides an overview of current electrical safe work practices and procedures. Classrooms allow for discussions to clarify the material being presented. Classroom training also provides the opportunity for a greater depth of understanding and a better grasp of the principles behind the information being presented. On-the-job training uses a hands-on training method to ensure understanding of the safe work practices and gives the opportunity to demonstrate proficiency in the work practices involved.

Engineer Control Some elements of engineering controls are listed below:

Employees should receive additional training (or retraining) if any of the following conditions exist: ● If the supervision or annual inspections indicate that the employee is not complying with the safety-related work practices

● Remote racking of breakers

● If new technology, new types of equipment, or changes in procedures necessitate the use of safety-related work practices that are different from those that the employee would normally use, or

● The use of maintenance switches to minimize the time employees may be exposed to an arc flash

● If he or she must employ safety-related work practices that are not normally used during his or her regular job duties

● Arc-resistant switchgear ● Remote switching of breakers

● Additional use of differential relays ● Zone selective interlocking (Smart relays to minimize tripping time) ● High resistant grounding ● Hi-Speed Light Sensitive Relays ● Hi-Speed Light Sensitive Relays With Current Detection ● The use of two tie breakers in series ● The use of 3-cycle breakers ● Type 2 low voltage starters ● Ground and Test Devices ● Integral ground switches interlocked with associated breakers ● Hi-Speed Grounding Switch - “Crowbar” Switch ● The use of Ground Ball Studs ● Installation of “Mimic Bus” on switchgear ● “Fed From/ Feed To” information on equipment labels

Policies and Procedures Policies and procedures include: 1. Program Principles – the principles on which the program is based, 2. Program Controls – the controls set how the program is to be measured and monitored, and 3. Program Procedures – the procedures to be used during performance of work.

Refresher training should be conducted no less often than every three years. In today’s rapidly changing environment refresher training may need to be provided more frequently. Refresher training is important to ensure employees are informed on the leading edge thinking of safety.12

Personal Protective Equipment Personal protective equipment is required to help prevent shocks and burns. If things go wrong during a task, the PPE may prevent injuries from occurring.

CONCLUSION Creating and maintaining an electrical safety program that documents and meets your company’s specific needs and the needs of the various stakeholders is a key to success. Your electrical safety program should include key elements such as holding effective job briefings, creating an electrical safe work condition before start of work, and requiring the use of appropriate personal protective equipment for the task. The program should also include well-defined roles and responsibilities of management and employees, training and retraining requirements, holding safety meetings with contractors, and auditing of the program and field work. Ensuring a thorough knowledge and understanding of these rules, principles, and procedures by upper management, supervisors, and employees will reduce risk and save lives. Including these elements will ensure a strong electrical safety program.

Safety Vol. 2 REFERENCES 1

NFPA 70E, Standard for Electrical Safety in the Workplace, 2012

2

CSA Z462, Workplace electrical safety, 2012

3

Ray and Jane Jones, Electrical Safety in the Workplace, 2000

4

R.L. Doughty, R.A. Epperly, and R.A. Jones, Maintaining Safe Work Practices in a Competitive Environment, IEEE Transactions 1991

5

D. Ray Crow, Your Electrical Safety Culture Starts With Your Electrical Safety Program, Tomas A. Edison Institute Conference, 2005

6

Krause, Hidley, and Hodson, The Behavior-Based Safety Process, 1990

7

James R. White, Electrical Safety, A Practical Guide to OSHA and NFPA 70E, 2012

8

John D. Aeiker, D. Ray Crow, Shahid Jamil, The Importance and Process of auditing an Electrical Safety Program, IEEE PCIC 2008

9

Kenneth G. Mastrullo, Ray A. Jones, Jane G. Jones, The Electrical Safety Program Book, 2003

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Cooper Bussmann, Safety Basics – Handbook for Electrical Safety, 2004

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ANSI Z10, Occupational Health and Safety Management Systems, 2005

Daryld Ray Crow (S’68, M’72, SM’03, LSM’07) graduated from the University of Houston in 1969 with a BSEE degree. After graduation Ray went to work for the Aluminum Company of America where he provided engineering support for Alcoa plants worldwide on the design, installation, and operation of power and rectifier systems, provided plant engineering support which included electrical safety, served as team leader for writing a number of Alcoa electrical standards including the development of and training for Alcoa’s electrical safe work practice standard. He retired from Alcoa in 1996. After retiring from Alcoa, Ray worked for Fluor Global Services and Duke Energy as a Principal Technical Specialist providing design and consulting electrical engineering for plant power distribution systems and safe work practice programs, standards, and assessments/audits. Ray presently is the Principal Technical Specialist for DRC Consulting Ltd. and performs consulting work on electrical safe work practices standards, assessments/audits, electrical safe work practice training, and electrical engineering projects. He was chair of the Petroleum and Chemical Industry (PCIC) Safety Subcommittee 2004-2006, chair of the 2004 IEEE IAS Electrical Safety Workshop, is an alternate member on the NFPA 70E technical committee “Standard for Electrical Safety in the

13 Workplace”, a member of the IEEE 1584 Committee, and was the working group vice chair for the 2007 revisions to IEEE 463 “Standard for Electrical Safety Practices in Electrolytic Cell Line Working Zones”. Ray has co-authored and presented papers and tutorials on electrical safety and auditing for the PCIC and has presented safety topics and tutorials at the IEEE Industry Applications Society Electrical Safety Workshops and IEEE IAS Pulp and Paper Industry Conference. In 2010 Ray received the IEEE IAS Petroleum and Chemical Industry Committee Electrical Safety Excellence award.

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INTERNAL ELECTRICAL SAFETY AUDIT PowerTest 2013 Terry Becker, P.Eng., ESPS Electrical Safety Program Solutions Inc..

OUTLINE Occupational health and safety management systems include a requirement for audit. Safety in the workplace must be measured. If you implement preventive and protective control measures, how do you know they are providing the safety performance and reducing risk related to workplace hazards? With respect to electrical hazards, have you developed and implemented an Electrical Safety Program? If you have an Electrical Safety Program does it include a requirement for Auditing and Corrective Actions? New in NFPA 70E-2012, is Article 110.3(H) and CSA Z462, Clause 4.1.7.8 Electrical Safety Auditing. This new content outlines a requirement for auditing a developed Electrical Safety Program every three years. It indicates that the controls used in the “field” need to be verified as being followed. The best due diligence for an employer for electrical hazards management is to implement a comprehensive Electrical Safety Program. The best method to determine the performance of your Electrical Safety Program is by completing an audit and implementing prioritized corrective actions against the findings.

QUESTIONS TO ASK YOURSELF? There is a lot of activity in industry in the United States and Canada with respect to Workplace Electrical Safety. Employers are taking more of a reactive approach to “dealing with” arc flash and are neglecting shock. Employers are taking a “bottom up” approach to the implementation of preventive and protective control measures to mitigate or reduce the risk of exposure to workers to arc flash and shock hazards. Electrical Specific PPE, Tools & Equipment are been procured first without understanding why it is required and how a Qualified Electrical Worker would determine when they need it. Engineering incident energy analysis studies are been completed when workers have not training and there is no arc rated PPE procured yet. Engineering incident energy analysis studies are being complete and reports issued to companies been reviewed to validate that they are correct. There is a lack of the development and implementation of Electrical Safety Programs in industry. Implementing and auditing the Electrical Safety Program is the best way to sustainably manage electrical hazards. When companies do implement Electrical Safety Programs they may miss three critical elements: Incident Reporting, Management and Investigation, Electrical Incident Emergency Response, and Electrical Safety Audit. An Internal

Electrical Safety Audit identifies opportunities for improvement in the application of preventive and protective control measures. ● Have you implemented an Electrical Safety Program? ● Do your Qualified Electrical Workers “Establish an Electrically Safety Work Condition?” Do you have a LOTO Program and is it being followed? ● Have you considered Engineering “Safety by Design” controls? Have you had an Engineering Incident Energy Analysis completed? Was incident energy mitigation recommended and was it implemented and is it working? If you installed detailed Arc Flash & Shock labels as the employer, did you confirm the design of the label or did you let the engineer use the software to determine the label? ● Do your Qualified Electrical Workers establish an Electrical Work Zone with red “Danger” tape? Are other Warning signs in place when required? Have you implemented the requirements for a Safety Watch for high risk work tasks? ● Are your Qualified Electrical Workers following the requirements of your Electrical Safety Program? ● Do you have Electrical Safe Work Procedures developed and are they utilized? Have they been updated recently to align with NFPA 70E-12 or CSA Z462-12? ● Is the Electrical Specific PPE, Tools & Equipment you procured the right PPE, has it been inventoried, was it the right size for workers, stored properly, performing as intended, tested to acceptable frequencies, and properly cared for, used and maintained? Have you checked the laundering of the arc rated clothing? ● Do you complete electrical equipment maintenance? Do you manage any environmental contamination related to your energized electrical equipment? Have you identified the most critical electrical protective equipment and completed maintenance for it at an acceptable frequency? ● If you have an Electrical Safety Program, have you completed an Internal Electrical Safety Audit, identified gaps and prioritized corrective actions?

WHAT IS AN ELECTRICAL SAFETY AUDIT? Occupational health and safety management systems identify auditing and provide guidance on what is required. Auditing can

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Safety Vol. 2 be completed in different forms, Supervisory Level, Peer to Peer, Internal Electrical Safety Audit, External Electrical Safety Audit, and Qualified Electrical Worker Electrical Safety Competency Validation. Safety auditing follows a structured process to ensure consistent and defendable results. Verification and validation to measure performance is accomplished by: Interviewing management, supervisors and workers, Reviewing documentation, and Observations/ Inspections. Findings by performing an audit can be defended and corrective actions implemented to improve performance and ensure risk reduction measures are working as intended.

WHY SHOULD I PERFORM AN INTERNAL ELECTRICAL SAFETY AUDIT? Without completing an Internal Electrical Safety Audit you have no way to confirm that the preventive and protective control measures you have invested time, money and human resources to implement are working at all or as intended to reduce risk of exposure of workers to arc flash and shock?

WHAT DO I DO WITH THE RESULTS? Completing an Internal Electrical Safety Audit without prioritizing the findings to implement corrective actions will defeat the purpose of the Internal Electrical Safety Audit. Ensure that you review the findings with the Electrical Safety Steering Committee that you constituted for review and management of electrical hazards. The Electrical Safety Program Manager should then present to Management the findings and recommended prioritized corrective actions.

CONCLUSION Without performing an Internal Electrical Safety Audit you have no way to measure electrical safety performance and ensure your investment of time, money and human resources is effective and mitigating or reducing worker risk of exposure to electrical hazards.

A PICTURE IS WORTH A THOUSAND WORDS:

How do you know if you don’t check?

HOW CAN I COMPLETE AN INTERNAL ELECTRICAL SAFETY AUDIT? Internal Electrical Safety Audits are typically completed on an annual basis. A formal project is initiated and a schedule created for the Internal Electrical Safety Audit. A project manager should be assigned the responsibility; this is typically the Electrical Safety Program Manager. The Electrical Safety Program Manager will notify management, supervisors and workers that a scheduled Internal Electrical Safety Audit is planned and will involve their participation for interviews and retrieval of documentation. Communication to workers that work task observations will be completed either planned or unplanned. Electrical power distribution equipment and Electrical Specific PPE, Tools & Equipment inspections will be scheduled. Permission must be received to take digital pictures of findings, good or bad. The Internal Electrical Safety Audit should also identify “best practices” and recognition provided.

Should there be tags on these locks?

WHO PERFORMS THE INTERNAL ELECTRICAL SAFETY AUDIT? An Internal Electrical Safety Audit can be implemented by an individual or a team. The Internal Electrical Safety Audit needs a “Lead Auditor” identified. Qualified Electrical Workers should be engaged to participate in the audit as part of the audit team.

Is this an approved set of Temporary Protective Grounds?

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Safety Vol. 2

Is this an approved set of Temporary Protective Grounds?

Is this an approved set of Temporary Protective Grounds?

Installing engineering incident energy mitigation is a good practice.

Is that wiring energized? Is it properly abandoned?

Does this meet the CEC or NEC? Would you stick your hands into this enclosure?

How far should temporary power go? Where does it go, do we know? How long is temporary?

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Safety Vol. 2

Are the wiring methods approved in this energized enclosure? Is this an acceptable condition? Would you stick your hands into this “magic box?”

Is the VFD cooled properly sticking out of the MCC? Don’t worry about all of the other open doors on this energized 600V MCC? Is this a normal condition for this energized equipment?

To the right is a cable tray penetration through the wall and there is a blizzard and snow is blowing into the electrical room and melting? Is that ok? Does the cable tray wall penetration meet the NEC or CEC?

If I told you there was a vent above this energized 480V MCC and there was a blizzard outside and snow was blowing backwards through the vent would you believe me? Yes, that is a small snow drift accumulating on top of the energized MCC.

If the electrical equipment to the right of the snow was energize, would there be a problem?

It may be tough to see it, but there is a pool of water in the middle of the picture on top of this high voltage energized switchgear. Is that ok?

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Safety Vol. 2

Is this detailed Arc Flash & Shock label really correct? Did a software program create it? Did a lawyer create it? Did the Professional Engineering endorse the use of this label?

Is this detailed Arc Flash & shock label correct? Does the Professional Engineer that included it in his “Stamped” report know if it is correct? What information is wrong on this label and is this same information wrong in the “Stamped” report?

Over 3 foot long rack in, rack out tool. This is good and extends the Working Distance.

Is the information on this label correct to IEEE 1584? Would the Qualified Electrical Worker know what it means and be able to ask his Supervisor?

Is all of the Electrical Specific PPE, Tools & Equipment inventory present in this locker?

Are any of these arc flash suits fit for use? What sizes are available? Where are the arc flash suit hoods and do they have fans and is the lens dark brown or very light greet tint?

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Safety Vol. 2

Would I throw my own personal clothes into a closet or would I fold them and or hang them?

Is the leather protector glove the right leather protector glove for the rubber insulating glove?

Will this “lab coat style” arc flash suit jacket protect me?

Should I use this insulated hand tool?

Is “electrician’s tape” supposed to be used on the shaft of a screwdriver? Is it approved?

Which arc rated face shield would you use if you had to choose, the one on the left or the one on the right?

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Safety Vol. 2

Would you use this? Do you pre-use inspect your Electrical Specific PPE, Tools & Equipment?

Does your company own one or more of these Rescue Hot Sticks?

Would you use this for arc flash protection for your face?

Terry Becker, P.Eng., is the owner of ESPS Electrical Safety Program Solutions Inc. in Calgary, Alberta, Canada. Terry has over 24 years experience as an Electrical Engineer, working in both engineering consulting and for large industrial oil and gas corporations. He is a Professional Engineer in the Provinces of Alberta, British Columbia, Saskatchewan, and Ontario. Terry is the past Vice Chair of the CSA Z462 Workplace Electrical Safety Standard Technical Committee, and currently an Executive Committee member, voting member, and leader of Working Group 8 Annexes, as well as a member of the IEEE 1584 Committee, the CSA Z463 Guideline for Electrical Equipment Maintenance Standard Committee, and a member of the NFPA 70E Annexes Working Group.

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Safety Vol. 2

HOW OSHA AND NFPA 70E WORK TOGETHER NETA World, Spring 2014 Issue Ron Widup and Jim White, Shermco Industries

In 1970, President Richard Nixon signed into law the Occupational Safety and Health Act (OSHA). At that time 14,000 work-related fatalities and 2.5 million disabling injuries were reported each year. The workforce was approximately one-half what it is today, maybe a bit less. Yet still today, according to the latest data from the Bureau of Labor Statistics, 4,690 workers were killed on the job in 2010, an average of 13 workers per day. The cost of job-related injuries and illnesses is a staggering 250 billion dollars to 300 billion dollars per year. With data from the U.S. Bureau of Labor Statistics and compiled by the Electrical Safety Foundation International, electrical-related fatalities have shown decreases since 1992, the first year data was available. See Figure 1. In 2010 there were 163 fatalities resulting from contact with electricity, a huge decrease from 1994 when there were 348 fatalities. This is not to downplay the significance of those fatalities. No worker should be given the death sentence for the crime of working. This is to point out the change in the electrical culture that has been taking place over the last 20 years. The combination of OSHA enforcement and the implementation, and probably more significantly, a better understanding of NFPA 70E, Standard for Electrical Safety in the Workplace accounts for a good portion of the improvement.

Fig. 1: Trending of Electrical Fatalities. Courtesy Safety Foundation International.

HOW DID THE 70E COME TO BE? In the 1970’s OSHA decided that an industry-based consensus process would be the best method for developing such a highly-technical regulation regarding a hazardous substance. In 1976 OSHA called upon the National Fire Protection Association (NFPA) to develop an industry consensus standard for electrical safe work practices. In 1979 the first edition of NFPA 70E was published. In 1990 OSHA issued a new standard (1910.331.335) on electrical safety- related work practices for general industry. The intent was for this regulation to complement existing electrical installation standards and included requirements for work performed on or near exposed energized and deenergized parts of electric equipment, use of electrical protective equipment, and the safe use of electric equipment. The 70E provided much of the basis for the new OSHA regulation, modifying the language to fit the regulatory requirements. Since that time the NFPA 70E has been updated to reflect the latest thinking and findings on the subject of electrical safe work practices. Where the OSHA regulations must use broad regulatory, nonprescriptive language, NFPA 70E can be very prescriptive and by design is such a document. As an example, 29CFR1910.335 states, “Employees working in areas where there are potential electrical hazards shall be provided with, and shall use, electrical protective equipment that is appropriate for the specific parts of the body to be protected and for the work to be performed.” This broad language does not actually identify any specific PPE, only that the PPE chosen be appropriate. Contrast that statement with NFPA 70E, Article 130, which provides very specific recommendations for what PPE the worker is to use and also provides requirements for the construction, wear and ratings of arc-rated and shock PPE. As the industry matures and new information is evaluated, NFPA 70E will also change to keep pace. The OSHA regulations take much longer to change, which they should, and since OSHA regulations are federal law, they should not be subject to trends, opinions or outside influences. OSHA has representation on the NFPA 70E technical committee. Currently it is David M. Wallis, Director, OSHA Directorate of Standards and Guidance, Office of Engineering Safety; Washington, DC. The OSHA representatives provide insight to the technical committee on OSHA’s views about proposals and comments being considered by the committee, as well as advising the committee when their actions don’t exactly line up with OSHA’s mandates. One such example was eliminated in the 2012 edition. Previous editions of NFPA 70E had a lockout/ tagout procedure called the “Individual Qualified Employee Control Procedure”.

22 Essentially, this procedure allowed for minor servicing, repair or adjusting without the placement of locks and tags if the disconnecting means is adjacent to the conductor or circuit parts, is clearly visible to the qualified individual performing the work and the work does not extend beyond one shift. OSHA did not think much of the Individual Qualified Employee Control Procedure. That being said, OSHA has posted on their website a Letter of Interpretation, General Duty Clause (5)(A)(1) Citations on Multi- Employer Worksites; NFPA 70E Electrical Safety Requirements and Personal Protective Equipment, dated 07-25-2003, that states “Industry consensus standards, such as NFPA 70E, can be used by employers as guides to making the assessments and equipment selections required by the standard. Similarly, in OSHA enforcement actions, they can be used as evidence of whether the employer acted reasonably.” OSHA uses the 70E as a guide for justification of its citations, as NFPA 70E is the industry safe work practices standard.

MOVING FORWARD NFPA 70E is on a three-year cycle, although it was delayed for a year from the 2004 to the 2009 edition. This delay was caused by some serious disagreement among the committee members concerning the Hazard/Risk Category Tables, similar to some of the discussions concerning the tables in the 2015 cycle. The issues in the 2015 cycle were settled among the committee members without any intervention by the NFPA, but in the 2009 cycle extra committee meetings had to be conducted to resolve the issues. NFPA 70E is a consensus standard, which means that two-thirds of its committee members must approve the changes before it can be approved. The makeup of the technical committee has changed some over the years, and the committee has grown somewhat. The NFPA is careful to appoint a technical committee that represents the different interests and a comprehensive overview within industry and to not let one interest become dominant. And while there have been strong differences of opinion between the various committee members, it is clear that all members have a common goal and interest at heart–protecting the electrical worker. Protecting the electrical worker is the single most important factor that makes the 70E technical committee the best we have served on. No member or interest seeks to use the 70E for monetary advantage; if it is the right thing to do, we all can agree to it. And while sometimes how to do the right thing is not completely agreed upon, the committee voting on proposals and comments this cycle shows almost unanimous agreement among its members on virtually every issue. That is not to say the proposals or comments were accepted carte blanche...quite the opposite! The committee discussed and debated the merits and shortcomings of each and every proposal, modified the language when necessary to meet the consensus, and then voted as a group.

Safety Vol. 2 SUMMARY Workplace fatalities from all causes have been decreasing steadily over the years, and like it or not, this is due to the formation of OSHA and the rules they mandate for the workplace. Although there is more to be done, electrically- related fatalities have dropped considerably. StricterenforcementofOSHAregulationsdefinitely helps. NFPA 70E has certainly played a huge role in the reduction of fatalities and injuries and will continue to do so as more companies and workers understand and adopt it. OSHA and the 70E – not a bad combination. Ron Widup and Jim White are NETA’S representatives to NFPA Technical Committee 70E (Electrical Safety Requirements for Employee Workplaces). Both gentlemen are employees of Shermco Industries in Dallas, Texas a NETA Accredited Company. Ron Widup is President of Shermco and has been with the company since 1983. He is a Principal member of the Technical Committee on “Electrical Safety in the Workplace” (NFPA 70E) and a Principal member of the National Electrical Code (NFPA 70) Code Panel 11. He is also a member of the technical committee “Recommended Practice for Electrical Equipment Maintenance” (NFPA 70B), and a member of the NETA Board of Directors and Standards Review Council. Jim White is nationally recognized for technical skills and safety training in the electrical power systems industry. He is the Training Director for Shermco Industries, and has spent the last twenty years directly involved in technical skills and safety training for electrical power system technicians. Jim is a Principal member of NFPA 70B representing Shermco Industries, NETA’s alternate member of NFPA 70E, and a member of ASTM F18 Committee “Electrical ProtectiveEquipment for Workers”.

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Safety Vol. 2

SAFETY TIPS FOR QUALIFIED PERSONS NETA World, Spring 2014 Issue Jim White, Shermco Industries

According to the U.S. Bureau of Labor Statistics, 52 percent of electrical fatalities from 2003 through 2010 occured in the construction industry (Figure 1). As electrical contractors, we face many safety challenges that other trades may not. The chance of electrical shock, arc-flash burns, arc blast, projectiles, and high acoustic levels are why electrical safety needs to be at the top of your list and the top of your supervisor’s list.

exposure. We have added resistance, due to our shoes and socks and carpet, tile, or dry concrete, dropping the amount of current that would flow through us.

Fig. 2: Fatalities by Voltage Range. Fig. 1: Electrical Fatalities by Industry. Courtesy Electrical Safety Foundation International. Companies are taking electrical safety much more seriously than they used to. Here are a few misconceptions and tips to help you understand and appreciate the importance of electrical safety training.

MISCONCEPTION ONE: LOW VOLTAGE IS NOT AS DANGEROUS AS HIGH VOLTAGE I once had a student who said “Low voltage doesn’t worry me. High voltage does.” I asked him the reasoning behind that statement and he replied “If you get hit with low voltage, everyone can come by your coffin and say how natural you look. With high voltage, they have to close the coffin.” I hope he was kidding, but he was correct in his assessment that low voltage can be just as deadly as high voltage. H. Landis Floyd and Danny Liggett once presented the slide in Figure 2 as part of their presentation. This slide was only for industrial plants and did not account for utility workers. It clearly shows that, even though 277/480 V caused the most fatalities, the number of fatalities caused by 120/208/240 V is right behind it. When we are shocked, it is usually a hand-to-foot

The only difference between being shocked at a higher voltage and a lower voltage is how long it takes for the voltage to kill you. Low voltage just takes a bit longer, but as Figure 2 shows, it is every bit as lethal. Dr. Charles Dalziel conducted a study in 1960 where he subjected student volunteers to electrical shocks of varying strength. Dr. Dalziel demonstrated that a 75-mA electrical shock to an average-sized man could cause him to go into ventricular fibrillation in about five seconds. That sounds like a long time, unless you cannot extract yourself. Dr. Dalziel also showed that women have a greater risk of injury from electrical shock due to their lower body resistance. Lower body resistance equals more current flowing through the body. One example of this is the no-let-go threshold (where a person cannot release an electrically-energized conductor or circuit part). For the average woman, it would require a current of about 10 mA, while for the average man it would require a current of about 16 mA. 100 mA of current flowing through the body can cause fibrillation in three seconds, while a 2.5 A contact could cause fibrillation in about four milliseconds. Figure 3 shows a hand injury caused when a worker could not release a 110 V portable electric power tool due to muscular contractions and received a serious burn from the current flow.

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Safety Vol. 2 OSHA goes on to say “OSHA urges employers to be wary of relying solely on generic, ‘packaged’ training programs in meeting their training requirements. For example, training under HAZWOPER includes site-specific elements and should also, to some degree, be tailored to workers’ assigned duties.” OSHA applies this LOI to any hazardous job, including those for qualified persons.

Fig. 3: Hand Injury Caused by 110 V Tool. Courtesy OSHA eCat Website. Safety Tip 1: Do not be the guy that has to learn everything by experience. As my Dad would often say “Experience is what you get just after you need it.” Be smart; accept new safety practices; and change whatever bad habits you might have. Safety Tip 2: Be aware that a low-voltage electrical shock can be fatal.

MISCONSPECTION TWO: EXPERIENCE ALONE MAKES YOU A QUALIFIED PERSON “I’ve got 17 years on the job. Of course I’m qualified.” Certainly your years of experience are important, and the knowledge and skills you have developed are critical to being a qualified person, but technical skills are only half the equation. You have to meet OSHA’s definition of a qualified person: “Qualified person. One who has received training in and has demonstrated skills and knowledge in the construction and operation of electric equipment and installations and the hazards involved.” 29CFR1910.332 and .333 provide minimum required safety skills and knowledge, and NFPA 70E Section 110.2 gives more detail. There are three parts to being a qualified person; ● Training in the technical skills required ● Having knowledge of the construction and operation of electrical equipment (the technical side) and installations and the hazards involved (the safety side) ● Demonstrating those skills and knowledge (practical demonstrations) Companies may provide inadequate initial training for qualified persons by relying solely on video or computer-based training or one-day training sessions. These methods alone do not meet the requirement of OSHA/NFPA 70E requirements. OSHA, in a Letter of Interpretation (LOI) dated 11/22/94 says, “In OSHA’s view, self-paced, interactive computer-based training can serve as a valuable training tool in the context of an overall training program. However, use of computer-based training by itself would not be sufficient to meet the intent of OSHA’s training requirements….” Instructor-led training by a qualified instructor is required to meet this requirement.

Another excerpt from that same LOI states, “Equally important is the use of hands-on training and exercises to provide trainees with an opportunity to become familiar with equipment and safe practices in a non-hazardous setting.” Again, demonstration of skills is needed to become a qualified person. The minimum electrical safety training has to cover the following items: ● Demonstrating knowledge and skills in: ● Determining nominal voltage ● Determining what conductors or circuit parts are energized or not ● Minimum safe approach distances for shock (and arc flash) ● Use of special precautionary techniques ● Use of insulating materials and shielding ● Use of insulated hand tools Use of does not only mean picking up something and using it. Use of includes: ● Choosing the proper tool, clothing, or PPE ● Inspecting it to ensure it is safe to use ● Using the tool safely and wearing the protective clothing and PPE properly ● Storing tools and PPE safely so they do not get damaged ● Caring for tools and equipment, including any testing, calibration, and maintenance required NFPA 70E Article 110 provides more clarity on these requirements: ● Safety-related work practices and procedures necessary to protect workers while performing hazardous tasks ● Identify and understand the relationship between electrical hazards and possible injury ● Methods of release from contact with energized conductors or circuit parts ● First-aid and emergency procedures, such as CPR ● Decision-making process necessary to determine the degree and extent of the hazard, PPE, and job planning to perform the task safely ● Select the proper voltage detector and verify the absence of voltage, interpreting its indications, and the limitations of each specific device.

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Safety Vol. 2 Do you really think that can be done in a one-day session? Safety Tip 1: To be qualified you must have the technical skills and experience, as well as safety training and skills, necessary to perform the job. Safety Tip 2: Get training that meets OSHA and NFPA 70E minimum training requirements. If OSHA investigates an accident, the first thing they look at are the training records.

MISCONCEPTION THREE: YOUR JOB TITLE DETERMINES WHETHER OR NOT YOU MUST BE QUALIFIED “Your job title or job description does not have to include the word electrician before you are required to be a qualified person.” OSHA does not care what your job title is. OSHA looks at what you do on the job to determine whether or not you need to be qualified. Anyone who works on or near exposed, energized electrical circuits or conductor parts rated above 50 volts is required to be a qualified person. That could include instrumentation and control technicians, HVAC technicians, electrical engineers, or others who may not think of themselves as needing to meet that requirement. Safety Tip 1: The magic number is 50 volts, not 100 volts nor 120 volts. Safety Tip 2: If you have access to exposed energized conductors or circuit parts, you probably need to be qualified to 29CFR1910.332 and .333 and NFPA 70E Article 110.

MISCONCEPTION FOUR: PPE ELIMINATES RISK “I’m protected if I wear my PPE.” PPE does not eliminate the hazard, nor does it eliminate the risk. PPE can reduce the risk, but the hazard will remain the same whether PPE is used or not. OSHA does not accept that working with energized equipment with PPE is as safe as working with deenergized equipment. Safety Tip 1: Never trust your life to a mechanical device. My dad would say this when I would be under a car supported by a hydraulic jack. It’s good advice, especially when wearing PPE. Always wear your PPE, but work like you don’t have any on. Safety Tip 2: Turn it off! The only way to work safely is to work with deenergized equipment. Once the equipment or circuit is tested and found absent of voltage, no PPE is needed and the risk disappears. OSHA and NFPA 70E tell us to do just that. So the three most important rules of electrical safety are 1) turn it off, 2) turn it off and 3) turn it off.

MISCONCEPTION FIVE: ARC FLASH IS THE BIGGEST HAZARD FOR ELECTRICAL WORKERS “I hear so much about arc flash; it has to be the biggest hazard for electrical workers.” The Bureau of Labor Statistics (BLS) data reveals that shock is the greater hazard than arc flash by about a two-to-one margin. In some industries, it is higher.

Fig. 4: Shock vs Burn Injuries. From “Trends in Electrical Injury” James Cawley presented a paper titled, “Trends in Electrical Injury” at the 2006 IEEE/IAS Petroleum and Chemical Industry Committee (PCIC). Figure 4 is from that presentation. The Electrical Burns numbers include internal electrical burns caused by current flow through the body (contact burns), as well as arc-flash (non-contact) thermal burns. The injuries in Figure 4 also represent lost-time injuries, so the shock injuries were still very serious. Safety Tip: Arc-flash injuries often cause more serious injuries than electrical shock.

MISCONCEPTION SIX: ARC FLASH IS NOT A THREAT AT LOW VOLTAGES “I only work on low-voltage, low-energy lighting panels and the like, so arc flash isn’t a problem for me.” One rule-of-thumb for incident energy is that incident energy decreases by the inverse square of the distance. As you move away from an arc source, the heat created by an electrical arc flash decreases very quickly. The opposite is also true. Incident energy increases by the square of the distance as you move closer to an arc source. If I receive 1 cal/cm2 incident energy to my face and chest area (which is where incident energy is calculated), my hands, which are likely to be much closer to the source, will receive more. In some cases, my hands may only be one or two inches from an arc source. My hands could very easily be exposed to enough incident energy to cause severe second- and third-degree burns. Safety Tip 1: Don’t think that you cannot be seriously injured at lower voltages. There have been several reported incidents where workers received serious injuries to the hands and arms from safe voltages. Safety Tip 2: NFPA 70E recommends wearing leather gloves if hands will be exposed to an arc flash. Even lighting panels can cause severe burns to unprotected hands and fingers.

26 MISCONCEPTION SEVEN: EXPERIENCE WORKERS CAN SAFELY CUT CORNERS “I’ve done it this way for years and never had a problem.” We become accustomed to working on electrical equipment, and we feel comfortable. Our experience and field knowledge tell us how to evaluate those risks, and we tend to trust them. The problem is that one day, maybe years from now, something will not be as it seems. The insulation may be weakened. Someone may not have tightened the lug properly during the last maintenance cycle. The contractor who installed the equipment may have had a bad day. These are factors completely outside your control. Any one of these, not to mention dozens of other variables, can cause an accident. Safety Tip 1: Follow safety procedures and safe work practices, such as NFPA 70E not because you know something is going to happen, but because we do not know when it is going to happen. If not for yourself, think of the grief and loss your family would experience if you were seriously injured or killed. Think of the impact on your children. Safety Tip 2: Do not overestimate your skills. Being lucky is not the same as being skilled.

SUMMARY The vast majority of workers performing electrical tasks want to do what is right. But we get task-focused, losing sight of the fact that if there is an accident, not only could we (or someone close by) be injured or killed, but whatever we were working on will probably be damaged to the point that it must be replaced. Companies that are committed to working only on deenergized equipment have found that once the initial adjustment period is over, turning electrical equipment and circuits off does not have nearly the impact on operations that they had feared. Be smart: follow the OSHA regulations and NFPA 70E.

Safety Vol. 2 James White is the Training Director for Shermco Industries, Inc. located in Irving, Texas. He is a Senior member of the IEEE, the recipient of the 2011 IEEE/PCIC Electrical Safety Excellence Award, the 2008 IEEE Electrical Safety Workshop Chairman, Alternate interNational Electrical Testing Association (NETA) representative on NFPA 70E®, Primary NETA representative on NEC Code Making Panel 13, Primary representative on NFPA 70B®, and is the Primary NETA representative to ASTM F18®. James is also a certified Level IV Senior Substation Technician with NETA, an inspector member of IAEI and serves on the NETA Safety and Training Committees. James is the author of Electrical Safety, A Practical Guide to OSHA and NFPA 70E and Significant Changes to NFPA 70E – 2012 Edition both published by American Technical Publishers.

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Safety Vol. 2

ROTATING MACHINERY HAZARD AWARENESS NETA World, Summer 2014 Issue Scott Blizard and Paul Chamberlain, American Electrical Testing Co., Inc.

Performing a condition analysis or maintenance on rotating machinery is a hazardous task which requires an experienced individual capable of performing the duty and possessing an ability to identify potential hazards and mitigate risks. A number of tragic, inadvertent injuries can occur, such as crushed hands or arms, severed fingers, or blindness if extreme caution is not exercised when working with rotating machinery. The use of lockout /tagout, personal protective equipment (PPE), and other means of safeguarding will mitigate possible injuries. Condition analysis of rotating equipment may be performed by employing equipment designed to be used to access rotating equipment when operating, such as infrared camera, partial discharge detection equipment, and vibration analysis equipment. PPE should be appropriate and adequate for all tasks to be performed. Long sleeves, long hair, jewelry, and other loose articles are an invitation for disaster when one is around rotating machines. Make sure sleeves are tight, hair is pulled back and any other sources of entanglement are removed. Any machine part, function, or process which many cause injury must be safeguarded. When the operation of a machine or accidental contact with a machine can injure the operator or others in the vicinity, the hazards must be either controlled or eliminated. When performing a visual inspection of rotating machinery make sure that all guards are correctly installed according to the manufacturer’s instruction and that they comply with the Machinery and Machine Guarding OSHA Regulations 29 CFR 1910.212 - General Requirements for All Machines, and 29 CFR 1910.219 - Mechanical Power-Transmission Apparatus. Depending on the type of machinery being inspected, other OSHA regulations may apply. The following paragraphs identify and examine hazards and their means of safeguarding and mitigating the associated risks. As always, this article does not include every potential hazard of performing a task, but explores potentially hazardous situations. Additional hazards may exist, depending upon the type or condition of the equipment. Take all procedures seriously and verify that the instruction manuals used are specific to the equipment present. Check for and identify potential hazards prior to beginning every task by using a pre-job brief worksheet.

ELECTRICAL AND MECHANICAL HAZARDS Improper lockout/tagout is a major contributing factor to injuries caused by rotating machinery. Controlling the hazardous energy of the motor is essential, and there are many forms of energy that may be involved. Always refer to the appropriate OSHA regulation or required procedure, such as 29 CFR 1910.147 and .333, and the manufacturer’s instructions to determine the correct or required lockout/tagout procedures. The most obvious hazardous energy source that could cause injury is electrical. Electrically de-energize the rotating machinery from its primary energy source and ensure the equipment is disconnected from all sources of power, both ac and dc, if applicable. Once de-energized, verify that the equipment is at a zero energy state using the manufacturer’s approved method. Verify the accuracy of the detection or voltage measuring device against a known source, then check for zero energy on the de-energized equipment, and finally test the detection equipment against a known source again. This will verify that the detection meter used was functional during the check. Testing for voltage will require its own level of PPE depending upon the voltage and test procedure per NFPA 70E 2012 Table 130.7(C)(15)(a) - Hazard/Risk Category Classifications and Use of Rubber Insulating Gloves and Insulated and Insulating Hand Tools-Alternating Current Equipment (Formerly Table 130.7(C) (9) in the NFPA 2009). However, as previously stated, electrical energy is not the only energy that requires lockout/tagout. Rotating machinery may also contain a large amount of mechanical energy. This energy must be dissipated prior to servicing or serious injury could occur. Once the energy has been discharged or dissipated, it is also advisable to lockout/tagout the source of the stored energy, if feasible. Ensure that remote operating handles are tagged in a local or manual mode. This will prevent someone from inadvertently operating the machinery. Machinery operating mechanisms may also be pressurized. Ensure that the unit is depressurized and/or discharged and the source of the pressure is disabled. Ensure that any valves both upstream or downstream of the device are closed and lockout/tagout each valve. Once disabled this source must also be locked out and tagged out prior to performing maintenance.

28 CHEMICAL HAZARDS Chemicals can be a hazard, depending upon the type of rotating machinery and the process that the machine is associated with. Caution must be taken with gases, chemicals, and liquids. Many processes can produce gases that may be denser than air, so it displaces oxygen in lower lying areas. Ventilation must be used to avoid these gasses from being trapped. Some lubricants and cleaners may cause a respiratory and skin irritant if used in enclosed areas or on bare skin. Knowledge of the material, reading its label, and checking the Safety Data Sheet (SDS) is advised to identify any potential health effects from its use. Once again, use of proper PPE is necessary for using some cleaners and lubricant. For example, nitrile gloves, safety glasses, faceshield, and even in some cases respiratory protection may be needed.

OTHER PHYSICAL HAZARDS When performing the visual inspection, mechanical inspection, maintenance, or electrical tests on rotating machinery, gravity is an energy that may also need to be controlled. The size and weight of panel covers and inspection plates may make them difficult to handle. Should gravity be a potential energy source, through an inclined loaded conveyor belt for example, ensure that the energy is dissipated and any flywheels or other sources of energy or moving parts are chained or locked in position prior to performing lockout/ tagout and maintenance.

HUMAN ERROR HAZARDS Human error, simply put, is a person (or persons) making a mistake. To prevent an error, follow a procedure or checklist while performing the task. If one doesn’t exist, create one. Nomenclature should be verified, and reverified upon approaching a piece of equipment. Perform a self check and a peer check to ensure that the task is being performed on the correct component. Utilize markings such as flagging when working around similar looking pieces of equipment to identify the components that should not be touched. Flagging can take several forms depending upon the company’s or client’s policy and procedures. Do not forget to identify, mark, then lockout/tagout all associated equipment (i.e., associated cables and compartments). Flagging could be utilized to indicate a component that is not operating normally. Barricading off a safe work zone prevents other workers from inadvertently entering the work area. This will ensure that maintenance and testing is conducted in a controlled area; utilize a test stand in this area if applicable. Ensure that any control voltage required to operate the equipment during testing is within a secured area.

Safety Vol. 2 HAZARDS OF IMPROPER PERSONAL PROTECTIVE EQUIPMENT HAZARDS After verification that the rotating machinery is de-energized, the method of disconnecting the equipment may require a different form or class of PPE. Ensure that correct PPE is utilized for the class of disconnecting means. Refer to the NFPA 70E 2012 - Table 130.7(C)(15)(a) for the required PPE and hazard/risk class. It will indicate what level of protection that is required for the disconnecting means to be worked on. Identifying the correct level of PPE and gloves will aid in the mitigation of injury from a potential arc flash. However, this table provides information based upon known values of the short-circuit current available, the clearing time in cycles, and minimum working distance. If those factors are unknown, more information must be gathered prior to performing the work in order to ensure personnel safety. The following are examples of the PPE requirements per the NFPA 70E for some tasks involving one type of 600 volt class motor control centers (MCCs);

Tasks Performed on Energized Equipment

Hazard/Risk Category

Rubber Insulating Gloves

Insulated and Insulating Hand Tools

600 V class motor control centers (MCCs) Parameters: • Maximum of 65 kA short circuit current available; maximum of 0.03 sec (2 cycle) fault clearing time; minimum 18 in. working distance • Potential arc-flash boundary with exposed energized conductors or circuit parts using above parameters: 53 in. CB or fused switch or starter operation with enclosure doors closed

0

N

N

CB or fused switch or starter operation with enclosure doors open

1

N

N

Work on energized electrical conductors and circuit parts, including voltage testing

2

Y

Y

Table 1: NFPA 70E 2012 - Table 130.7(C)(15)(a) As can be seen in Table 1, depending on the task, various levels of protection may be required. This protection level includes some combination of the clothing indicated in Table 2, which is taken from NFPA 70E 2012 – Table 130.7(C)(16). Examination of Table 2 indicates that there are several notes. Always reference these notes when identifying PPE requirements. (See Table 3)

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Hazard / Risk Category Protective Clothing and PPE

AN: as needed (optional). AR: as required. SR: selection required. Notes:

0

Protective Clothing, Nonmelting or Untreated Natural Fiber (i.e., untreated cotton, wool, rayon, or silk, or blends of these materials) with a fabric weight of at Least 4.5 oz./yd2 • Shirt (long sleeve) • Pants (long) Protective Equipment • Safety glasses or safety goggles (SR) • Hearing protection (ear canal inserts) • Heavy duty leather gloves (AN) (See Note 1.)

1

Arc-Rated Clothing, Minimum Arc Rating of 4 cal/cm2 (See Note 3.) • Arc-rated long-sleeve shirt and pants or arc-rated coverall • Arc-rated face shield (see Note 2) or arc flash suit hood • Arc-rated jacket, parka, rainwear, or hard hat liner (AN) Protective Equipment • Hard hat • Safety glasses or safety goggles (SR) • Hearing protection (ear canal inserts) • Heavy duty leather gloves (See Note 1.) • Leather work shoes (AN)

(3) Arc rating is defined in Article 100 and can be either the arc thermal performance value (ATPV) or energy of break open threshold (EBT). ATPV is defined in ASTM F 1959, Standard Test Method for Determining the Arc Thermal Performance Value of Materials for Clothing, as the incident energy on a material, or a multilayer system of materials, that results in a 50 percent probability that sufficient heat transfer through the tested specimen is predicted to cause the onset of a second-degree skin burn injury based on the Stoll curve, in cal/cm2. EBT is defined in ASTM F 1959 as the incident energy on a material or material system that results in a 50 percent probability of breakopen. Arc rating is reported as either ATPV or EBT, whichever is the lower value.

Table 3

2

Arc-Rated Clothing, Minimum Arc Rating of 8 cal/cm2 (See Note 3.) • Arc-rated long-sleeve shirt and pants or arc-rated coverall • Arc-rated flash suit hood or arc-rated face shield (See Note 2) and arc-rated balaclava • Arc-rated jacket, parka, rainwear, or hard hat liner (AN) Protective Equipment • Hard hat • Safety glasses or safety goggles (SR) • Hearing protection (ear canal inserts) • Heavy duty leather gloves (See Note 1.) • Leather work shoes

Table 2: PPE Requirements

(1) If rubber insulating gloves with leather protectors are required by Table 130.7(C)(9), additional leather or arc-rated gloves are not required. The combination of rubber insulating gloves with leather protectors satisfies the arc flash protection requirement. (2) Face shields are to have wrap-around guarding to protect not only the face but also the forehead, ears, and neck, or, alternatively, an arc-rated arc flash suit hood is required to be worn.

IN CONCLUSION There are many things to be aware of when performing maintenance and testing on rotating machinery. ● Obtain all service bulletins, maintenance documents, arc-flash studies, and manuals prior to beginning work on that specific device ● Review all prints and one lines associated with the equipment ● Establish a safe work area, and barricade off the work area

INSTALLATION OF TEMPORARY PROTECTIVE GROUNDS

● Perform a pre-job brief with all employees on-site

Grounds are an excellent secondary means of protecting the worker from inadvertent energization. Refer to any applicable OSHA regulations such as 29 CFR 1910.269, NFPA 70E, and ASTM F855 for specific guidance on grounding locations and sizing of grounds required for the task. Grounds must always create an equipotential zone around the equipment and as close to the work as possible. Using correctly sized and applied grounds are an additional safeguard for employees should there be a form of electrical energy introduced into the system or equipment where the work is being performed. Induced voltage or back-feed are just two of the forms of energy that may be inadvertently introduced into a system that has been correctly locked out/tagged out.

● Disconnect the electrical feed and control circuit(s), verify mechanical interlocks are properly engaged and test equipment for absence of voltage before performing visual or mechanical inspections

● Wear proper PPE

● If applicable, verify that there is zero energy (test, check, test) and discharge all stored energy, including pressurized gasses and gravity ● If possible, lockout/tagout all energy sources ● Connect grounds where and/if applicable ● Identify, visually mark and/or flag the equipment being worked on Being aware of, and mitigating the hazards listed above can lead to a safer work environment while performing inspection, maintenance, and testing of rotating machinery.

30 Scott Blizard has been the Vice President and Chief Operating Officer of American Electrical Testing Co., Inc. since 2000. During his tenure, Scott acted as the Corporate Safety Officer for nine years. He has over 25 years of experience in the field as a Master Electrician, Journeyman, Wireman, and NETA Level IV Senior Technician. Paul Chamberlain has been the Safety Manager for American Electrical Testing Company Inc. since 2009. He has been in the safety field for the past 12 years, working for various companies and in various industries. He received a Bachelor’s of Science degree from Massachusetts Maritime Academy.

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ELECTRICAL SAFETY— MYTHS AND RUMORS NETA World, Winter 2014 Issue David K. Kreger, Electrical Reliability Services

When it comes to electrical safety, much has changed over the past 10 years. The National Fire Protection Association has made a number of updates to NFPA 70E, including the most recent publication of NFPA 70E-2015. Occupational Safety and Health Administration (OSHA) also recently published its first-ever arc flash protection requirements for the electric power generation, transmission, and distribution industry, making significant changes to electrical safety requirements for utilities and industrial establishments. Unfortunately, many of the major misconceptions related to these standards have not changed. I’m still flabbergasted by comments and questions I hear from trainees and “qualified” electrical workers alike regarding requirements to maintain a safe work environment. Below is my attempt to debunk and demystify some of the most common myths about electrical safety standards, so that everyone can be on the same page when it comes to keeping electrical workers safe.

OSHA HAS A NEW REQUIREMENT TO PERFORM A HAZARD OR RISK ANALYSIS BEFORE BEGINNING EACH JOB. Technically speaking, this one is half true. In April 2014, OSHA did publish revisions to standard 1910.269 requiring high-voltage utilities and facilities to assess the workplace for potential flame or electric-arc hazards, to estimate the incident heat energy of those hazards, and to provide exposed workers with the appropriate personal protective (PPE) equipment. However, CFR 29, 1910.132(d)(1), which requires employers to assess the workplace for hazards and provide affected employees with PPE, has been in place for decades. What’s more, since OSHA’s inception in the early 1970s, the entire premise has been to ensure, as much as possible, a safe work environment for employees. Each employer has an obligation to determine what hazards an employee may face on the job. Once the hazard has been identified, the employer has further obligation to provide the appropriate training, PPE, or other work procedures that would allow the employee to perform the task safely. Several hazards are specific to the electrical industry—primarily shock and arc-flash burns. Qualified workers need to be aware of these hazards in order to be considered qualified. Therefore, the employer has always had an obligation to identify possible shock

hazards, identify possible flash-burn hazards, and provide the appropriate tools, PPE, or work procedures to mitigate these hazards. The new OSHA 1910.269 simply makes that official. I will add that, even though the appropriate tools and PPE are available, the supposedly qualified worker may not know what to do with them. For example, I once witnessed a 20-year veteran pull the insulating rubber gloves on over the leather gauntlets. When questioned, he responded, “I always wears them like that since the rubber part is the shock protection part and the leather inside keeps my hands from getting sticky.”

INSULATED GLOVES SHOULD NEVER BE WORN WHEN USING INSULATED LIVE-LINE TOOLS. IF THE INSULATION ON THE TOOL IS BAD, THE WORKER WOULD NEVER KNOW IT WHILE WEARING INSULATED GLOVES. This statement also was posed by a 20-year veteran. I had to think about that a moment. Hmm, would I want to find out the tool is bad by not wearing gloves? Those of you who have ever watched insulation break down when performing high-potential testing will testify that the breakdown happens quickly — faster than you could drop a bad switch stick!

WE WOULD LIKE TO ADOPT NFPA 70E AS OUR WORKING ELECTRICAL SAFETY POLICY, BUT IT IS ENTIRELY TOO CUMBERSOME. I have advocated NFPA 70E in its forms throughout the years and do admit, in some cases, the recommendations may be a bit cumbersome. However, realizing the intent of the publication should shed light on how to implement the appropriate policies. There is not, to my knowledge, a single safety document covering every possible scenario in the electrical industry, nor will there ever be, since ours is such a dynamic field. In the absence of specific rules from OSHA, the intent should still be to protect the workforce from hazards. Therefore, a site-specific or activity-specific policy would be appropriate, as long as it meets the intent of protecting the workforce. I keep a keen eye on the citations and violations of federal and many state OSHA organizations, and have yet to see a citation for not following an NFPA 70E recommendation verbatim. While OSHA continues to publish updates to its standards that do reflect specific NFPA 70E recommendations, such as the recent update to

32 OSHA 1910.269, NFPA 70E is not, in its entirety, an enforceable document. Yet. It is a guideline for developing a safe electrical work environment and has many practical applications the employer could use or modify, if necessary, to meet specific needs. If an employer were to adopt the new NFPA 70E-2015 in its entirety, I am certain it would be following all the OSHA rules.

IF I WERE ACTUALLY TO DEVELOP A RISK ASSESSMENT AND ENERGIZED ELECTRICAL WORK PERMIT BEFORE PERFORMING EVERY TASK, AS RECOMMENDED IN NFPA 70E, I WOULD SPEND ALL DAY DOING RISK ASSESSMENTS AND NEVER GET THE WORK DONE. If you are not already doing some form of risk assessment before performing electrical work, I would say you should find a different occupation. The recommendation to perform a risk assessment and develop a written energized electrical work permit plan for hazard mitigation applies to those tasks that are not routine in nature (not routine being less frequently than annually). The system will not be locked and tagged, and the system will be energized or possibly energized. If the task is performed frequently, an original risk assessment with successful mitigation techniques should already be in place in one form or another. Thus, another assessment is not required. To give an example, a qualified worker should already know the hazards involved in taking current measurements in a motor control center. Would the hazards change from one bucket to another? I would say no. Therefore, the same techniques found to be successful in one application of shock and flash protection would be successful in other similar applications. There is no reason to perform multiple (written) hazard assessments and mitigation procedures for basically the same task. Further, the newer versions of NFPA 70E limit areas where electrical work permits are required to those areas within the limited-approach boundary or arc-flash boundary. In addition, NFPA 70E, 2015, Article 130.2(B)(3) Exemptions to Work Permit says that an energized work permit is not required for work performed on or near live parts when qualified persons are performing tasks such as testing, troubleshooting, or voltage measuring; thermography and visual inspection up to the Restricted Approach Boundary; access/egress with no electrical work up to the Restricted Approach Boundary ; and general housekeeping up to the Restricted Approach Boundary , as long as appropriate safe work practices and PPE are provided and used in accordance with Chapter 1.

OSHA HAS A NEW REQUIREMENT TO PERFORM AN ARC-FLASH HAZARD ASSESSMENT AND TO MARK THE EQUIPMENT. Yes and no. The new OSHA 1910.269 requirements mandate that high-voltage utilities and facilities need to estimate the

Safety Vol. 2 incident heat energy of arc hazards and provide exposed workers with the appropriate protective clothing and equipment. However, for many years there has been an existing requirement to perform a hazard analysis for any hazard an employee may face on the job (see 1910.132(d)(1) in #1 above). The new requirement provides guidance on tools and methods that can be used to estimate available heat energy. The 2014 National Electrical Code (NEC) Article 110.16 requires the marking of flash hazards on electrical equipment. This is not an OSHA mandate, it is an NEC requirement.

ANYTHING THAT’S ELECTRICAL IN THE WORKPLACE NEEDS TO BE LABELED. Since the 2002 edition of the NEC introduced the requirement for marking flash hazards on electrical equipment in the field, the issue has been a hot and somewhat misunderstood topic. Adding to the confusion was the fact that NEC and NFPA 70E did not specify which electrical equipment needed to be labeled, but only that electrical equipment should be marked wherever the possibility of energized work exists. However, the intent of Article 110.16 has always been to arm the qualified worker with enough information to make an intelligent choice when selecting the appropriate PPE. The fine print note associated with NEC Article 110.16 says to refer to NFPA 70E for additional guidance. New updates to NFPA 70E-2015 and NEC shed light on the topic by spelling out the types of equipment that need to be labeled (i.e., switchboards, switchgear, panelboards, industrial control panels, meter socket enclosures, and motor control panels). Today’s requirements also make it clear that only electrical equipment that is likely to require examination, adjustment, servicing, or maintenance while energized needs to be field marked. Additionally, NFPA 70E section 130.5(B) includes an exception that permits continued use of labels applied prior to September 30, 2011, as long as those labels contain the available incident energy or required level of PPE. New language in 130.5 also says that labels need to be updated if the arc-flash hazard risk assessment shows that the labels are inaccurate and that the owner of the electrical equipment is responsible for documentation, installation, and maintenance of the field-marked labels.

IF THERE WERE A SIGN ON A PIECE OF EQUIPMENT THAT SAID, “DANGER — VOLTAGE,” WOULD THAT BE SUFFICIENT INFORMATION FOR A QUALIFIED WORKER TO SELECT THE APPROPRIATE INSULATED GLOVES OR TOOLS? I think not. The voltage level is what quantifies the hazard so the appropriate PPE and tools can be selected. The intent of the arc-flash protection program should be the same. Simply

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Safety Vol. 2 putting a sign on a piece of equipment that says, “DANGER — FLASH HAZARD” would not be sufficient information for a qualified worker to select the appropriate fire-retardant materials or flash-protection equipment. One of the requirements to be considered qualified to perform electrical work is the ability to identify exposed energized equipment and to identify the nominal voltage of that equipment. The purpose of this training requirement is twofold: provide the ability to determine when a shock hazard exists, and the ability to determine level of insulating tools or gloves required. There should also be a training requirement associated with arc-flash protection. Never have I seen so many blank stares from supposedly qualified electrical workers as when I show an example of an arc-flash warning sign indicating magnitude of hazard at a working distance. To help with this problem, changes to NFPA 70E-2015 make it clear what information needs to be included on field labels. Specifically, it states that the label should include: ● Nominal system voltage ● Arc flash boundary ● At least one of the following: ○ Incident energy and working distance ○ PPE category from NFPA 70E table ○ Minimum PPE arc rating ○ Site-specific level of PPE

THAT SIGN SAYS THERE ARE 11.4 CALORIES AT 18 INCHES. I ATE 10 TIMES THAT MANY CALORIES FOR BREAKFAST THIS MORNING! This is undoubtedly the most significant training challenge I continue to face. How do you take a group of electricians or instrument technicians from volts, amperes, and time to calories per square centimeter (or, worse yet, Joules per square centimeter) at a given working distance? Don’t blame it on the aptitude of the audience either. I once received much the same response from the audience at an IEEE meeting. A thorough explanation is needed of the transition from watt-seconds (which most understand) through Joules (which some understand) to calories applied to square centimeters of bare skin (which no one understands). Such an explanation usually results in positive head nods or the I get it! looks. Of course, showing the gory electrical burn victim movies helps to drive home the point. I would hope that those engineers performing incident energy studies will keep in mind the target audience for the results. Providing a report in Joules per square centimeter as well as recommendations for arc-rated PPE with ratings of calories per square centimeter will not help those that are already confused. Help them out — provide some training along with the results of the incident energy study correlating study findings with mini-

mum arc thermal protection values and maybe try to explain heat attenuation factor percentages too.

THE NFPA 70E ARC-FLASH PPE TABLES ARE CONFUSING AND MAKE IT DIFFICULT TO KNOW WHICH ARC-RATED CLOTHING TO CHOOSE. In the past, the NFPA 70E table method for choosing arc-rated clothing was somewhat cumbersome. In the 2015 version of the standards, new task-based tables have been added for determining when arc-flash PPE is necessary for AC and DC systems. For each task, the table indicates if there is an arc-flash hazard (yes or no). If yes, further engineering analysis must be performed to determine what level of arc flash protection will be required.

I HAVE LONGER ARMS THAN YOU. DOES THAT MEAN I CAN WEAR DIFFERENT FLAME RETARDANT CLOTHES? No, because I sweat more than you do… David K. Kreger has nearly three decades of experience with high, medium-, and low-voltage power generation, transmission, and distribution systems. His formal education includes a BS in physics from New York State University and an AA from the University of Maryland. He gained extensive experience as a field engineer through testing, troubleshooting, commissioning, and repairing power systems as well as through high-voltage work as a utility lineman. He is a licensed power engineer, NETA Level III Certified Technician,member of the NFPA (electrical section), and master instructor for the training group of Emerson’s Electrical Reliability Services.

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DETERMINING MAINTENANCE INTERVALS FOR SAFE OPERATION OF CIRCUIT BREAKERS PowerTest 2014 James R. White, Shermco Industries, Inc.

ABSTRACT NFPA 70E states in several sections in Articles 130, 200 and 205 that maintenance of overcurrent protective devices (OCPD) is critical to ensure a safe work environment. This paper discusses factors that may affect the operation of circuit breakers and other types of OCPDs and may cause misoperation when these devices are needed the most.

“(3) For the purpose of Chapter 2, maintenance shall be defined as preserving or restoring the condition of electrical equipment and installations, or parts of either, for the safety of employees who work where exposed to electrical hazards…...” Maintenance is defined in this section and notes that maintenance is performed for the safety of employees who work where exposed to electrical hazards. Electrical hazards are present anytime electrical equipment is energized.

NFPA 70E REQUIREMENTS

205.3 General Maintenance Requirements.

The 2012 edition of NFPA 70E makes some strong statements about how the condition of maintenance can affect the operation of OCPDs, and how that will cause the incident energy from an arc flash to increase. A summary of those sections is below:

“Electrical equipment shall be maintained in accordance with manufacturers’ instructions or industry consensus standards to reduce the risk of failure and the subsequent exposure of employees to electrical hazards.” This section very clearly states that failing to maintain electrical equipment and devices exposes employees to electrical hazards.

(1)

130.5 Arc Flash Hazard Analysis. “The arc flash hazard analysis shall take into consideration the design of the overcurrent protective device and its opening time, including its condition of maintenance.” Informational Note No. 1: “Improper or inadequate maintenance can result in increased opening time of the overcurrent protective device, thus increasing the incident energy.” Informational Note No. 4: “For additional direction for performing maintenance on overcurrent protective devices, see Chapter 2, Safety-Related Maintenance Requirements.” The chapter no one reads. Section 130.5 reflects the level of concern the 70E Committee has concerning how maintenance affects the arc flash study. IN No. 1 is very clear in stating the Technical Committee’s concern.

200.1 Scope. Informational Note: “Refer to NFPA 70B, Recommended Practice for Electrical Equipment Maintenance, and ANSI/NETA MTS-2007, Standard for Maintenance Testing Specifications for Electrical Power Distribution Equipment and Systems, for guidance on maintenance frequency, methods, and tests.” The 70E Technical Committee recognizes that the manufacturer’s instructions may not always be available, especially for obsolete equipment. The two primary industry standards are provided to give additional guidance. The 2015 edition of NFPA 70E will add IEEE Recommended Practice for the Maintenance of Industrial and Commercial Power Systems to the list. Figure 1 shows both the ANSI/NETA and NFPA documents.

Fig. 1: ANSI/NETA MTS-2011 and NFPA 70B – 2013

205.4 Overcurrent Protective Devices. “Overcurrent protective devices shall be maintained in accordance with the manufacturers’ instructions or industry consensus standards. Maintenance, tests, and inspections shall be documented.” OCPDs are singled out in this section as they have a disproportionate impact on worker safety. Note that where OCPDs are concerned, the maintenance, tests and inspections must be documented. OSHA, where are you on this? In addition, 130.7(C)(15) states, “The assumed maximum short-circuit current capacities and maximum fault clearing times for various tasks are listed in Table 130.7(C)(15)(a). For tasks not listed, or for power systems with greater than the assumed max-

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Safety Vol. 2 imum short-circuit current capacity or with longer than the assumed maximum fault clearing times, an incident energy analysis shall be required in accordance with 130.5.” If OCPD’s aren’t being maintained, Table 130.7(C)(15)(a) won’t provide the level of protection needed and that expensive arc flash study won’t be much better. During the last three cycles of NFPA 70E, there have been prolonged discussions about how the condition of maintenance of OCPDs can be determined. This is not usually as much an issue for employees of a facility, but when contractors come in to operate or maintain electrical equipment, they may not have immediate access to the needed information. The testing and maintenance records need to be part of the pre-job planning

of maintenance is so prominent of NFPA 70E. Without proper maintenance, OCPDs won’t function in accordance with their manufacturer’s specifications, PPE selection becomes problematic and the electrical power system is unsafe.

2015 EDITION NFPA 70E During the 2015 cycle of NFPA 70E(2), due to be released in October of 2014, the NFPA 70E Technical Committee will add the following (note that section numbers may not be accurate):

SR4 – 110.1(B) “Maintenance. The electrical safety program shall include elements that consider condition of maintenance of electrical equipment and systems.” For the first time, condition of maintenance is required to be part of the electrical safety program (ESP).

SR5 – 110.1(A) “General. Informational Note No. 1: Safety-related work practices such as verification of proper maintenance and installation, alerting techniques, auditing requirements, and training requirements provided in this standard are administrative controls and part of an overall electrical safety program.” This section clarifies that condition of maintenance is considered to be a safety-related work practice. SR4 and SR5 integrate condition of maintenance into the ESP and puts emphasis on its importance.

SR32 – 130.5 “Arc Flash Risk Assessment. (3) Take into consideration the design of the overcurrent protective device and its opening time, including its condition of maintenance.” “Informational Note No. 1: Improper or inadequate maintenance can result in increased opening time of the overcurrent protective device, thus increasing the incident energy. Where equipment is not properly installed or maintained, PPE selection based on incident energy analysis or the PPE category method may not provide adequate protection from arc flash hazards.” Section 130.5 is rewritten so that the requirements for an arc flash risk assessment are in a list format, and rewords the requirement slightly from the 2012 edition. IN No.1 is expanded from the 2012 edition to alert the user that if electrical equipment is not properly installed or maintained, the methods for choosing arc flash protective equipment may not be accurate, leaving the worker underprotected. It’s no accident or quirk of fate that condition

Fig. 2: Partial PPE Selection Table 130.7(C)(15)(A)(a) From NFPA 70E, Standard for Electrical Safety in Employee Workplaces Second Revision Draft “*The phrase “properly installed”, as used in this table, means that the equipment is installed in accordance with applicable industry codes and standards and the manufacturer’s recommendations. The phrase “properly maintained”, as used in this table, means that the equipment has been maintained in accordance with the manufacturer’s recommendations and applicable industry codes and standards. The phrase “evidence of impending failure”, as used in this table, means that there is evidence of arcing, overheating, loose or bound equipment parts, visible damage, deterioration, or other damage.” For the first time in NFPA 70E, condition of maintenance is a part of Table 130.7(C)(15)(A)(a) and a footnote is added to clarify what is meant by the phrase “properly maintained”. Condition of maintenance is such an integral part of the electrical safety process that it cannot be separated from it. Figure 2 shows the proposed 2015 version of the PPE selection table, 130.7(C)(15)(A)(a).

205.3 “General Maintenance Requirements. Informational Note: Common industry practice is to apply test or calibration decals to equipment to indicate the test or calibration date and overall condition of equipment that has been tested and maintained in the field. These decals provide the employee immediate indication of last maintenance date and if the tested device or system was found acceptable on the date of test. This local information can assist the employee in the assessment of overall electrical equipment maintenance status.” The NFPA 70E Technical Committee grappled with how condition of maintenance could be verified and agreed that it would not be an easy thing to do. Maintenance records and test results could be reviewed prior to the start of work, if they are available. If the equipment was maintained, those records should be available.

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The other method used by some service companies, such as many NETA-member companies, is to place calibration and test labels on their equipment, as shown in Figure 4. NFPA 70B(3) “Recommended Practice for Electrical Equipment Maintenance” 2013 edition added section 11.27 ‘Test or Calibration Decal System. It states, “11.27.1 General. After equipment testing, device testing, or calibration, a decal on equipment, in conjunction with test records, can communicate the condition of electrical equipment to maintenance and service personnel. This can be important for assessing the hazard identification and risk assessment for electrical safety procedures as well as the condition of electrical equipment.” Such labels are shown in Figure 3. These labels are supposed to be color coded as red, yellow or white.

The Reliability Subcommittee of the IEEE Industrial and Commercial Power Systems Committee, in IEEE Standard 493(4) “Recommended Practice for the Design of Reliable Industrial and Commercial Power Systems” (the Gold Book) conducted a survey that included 1,469 failures of electrical equipment. In the survey, respondents were asked to describe their opinion of the maintenance quality in their plant. Inadequate maintenance was blamed for 16.4% of the failures of electrical equipment overall. Table 5-2 (Figure 5) in Std. 493 shows the percentage of failures of electrical equipment vs. the time they had been in service without being maintained. Note that circuit breaker failures increased substantially after they had been in service for more than 24 months without being serviced.

Fig.3: Test or Calibration Decal System From NFPA 70B-2013, Recommended Practice for Electrical Equipment Maintenance The red label indicates the equipment has a major defect and should not be placed into service. The yellow label indicates a minor issue that does not affect operation or safety and the white label indicates equipment that is fully serviceable. Since NFPA 70B is printed in black-and-white, the colors are described in the text, but not shown in the figure. Figure 4 shows how the labels would be color-coded in the field.

Fig. 4: Test and Calibration Decal as Specified by NFPA 70B – 2013 Edition

STUDIES THAT INDICATE THE NEED FOR MAINTENANCE Numerous studies have shown that if circuit breakers are left in service without maintenance, their chances of operating correctly become less and less each year. Gary Donner with Tony Demaria Electric in Wilmington, CA., who is a friend and former Shell Oil Company employee, related to me that years ago, Shell had performed a study that indicated when circuit breakers sat undisturbed for years, they would not meet manufacturer’s specifications. After three to five years of service approximately 30% of the circuit breakers malfunctioned, after seven to ten years approximately 50% of the circuit breakers malfunctioned and after 17 to 20 years the number was in the high ninety percentile. Gary says that study was lost during some work site transitions and is no longer available. This does not negate the importance of the study, as it correlates to the next two studies very well.

Fig. 5: From IEEE Standard 493, Recommended Practice for the Design of Reliable Industrial and Commercial Power Systems In the largest survey of its kind to date, NETA-member (interNational Electrical Testing Association) companies were asked to participate in a survey on the causes of circuit breaker failures. The survey data and conclusions were provided in a paper presented at the 2008 NETA PowerTest Conference and the 2011 IEEE PCIC Conference(5) . The survey contained 340,000 results. The NETA survey showed that 22% of the circuit breakers had an issue with the overcurrent protective device that would have affected its operation. 10.5% of the circuit breakers did not function at all! Of the circuit breakers that had performance issues, 42.8% had mechanical issues and over half of those were related to lubrication. All three surveys point in the same direction and support each other. How often should circuit breakers be maintained and what should be done to them? There are two sources for answers; ANSI/NETA MTS-2011(6), Standard for Maintenance Testing Specifications for Electrical Power Distribution Equipment and Systems and NFPA 70B-2013, Recommended Practice for Electrical Equipment Maintenance. Both make recommendations as to frequency and what maintenance is required of electrical devices, but ANSI/NETA MTS also provides specifics on what the results should be.

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Safety Vol. 2 Figures 6 and 7 show a portion of the ANSI/NETA MTS Maintenance Frequency Matrix in Annex B. By choosing the criticality and condition, a multiplier is derived from the table. As an example, equipment that has a low criticality and is in good condition would have a multiplier of 2.0. Using molded-case circuit breakers as an example (Figure 7) each of the recommended intervals in Figure 7 is multiplied by 2x. Be aware that there are other criteria that should be used to determine maintenance frequency, such as environment, loading, how the circuit breaker is being used, number of operations, etc.

Fig. 6: Frequency of Maintenance Matrix, Annex B ANSI/NETA MTS-2011

Fig. 7: Section 7.6.1.1 from ANSI/NETA MTS-2011

FACTORS THAT CAN AFFECT THE OPERATION OF OCPDS Circuit Breakers. There are several factors that have a detrimental effect on all types of circuit breakers. One of the most damaging factors is lack of lubrication. Since a circuit breaker, regardless of type or voltage rating, is primarily a mechanical device, it needs lubrication in pivots, latches and rollers. 80% of the circuit breakers that are serviced by Shermco’s Circuit Breaker Shops show signs of inadequate lubrication. This is caused by the heat created from electrical current flowing through the circuit breaker. Loading is another important factor to be considered when evaluating a circuit breaker’s condition of maintenance. Heavily-loaded circuit breakers produce more heating than lightly-loaded circuit breakers and require maintenance more frequently. Other factors that generally affect a circuit breaker’s condition of maintenance are: ● Specific manufacturer and model. Not all circuit breakers are created equal. Anyone who has serviced circuit breakers knows there are some that are excellent, and some that are quite a bit less than excellent. ● Environment. Circuit breakers that are in a climate-controlled environment fare much better than those outdoors. Humidity, heat, cold and dirt and other contaminants can seriously degrade a circuit breaker’s operation. Circuit breakers used in water, wastewater treatment or pulp and paper facilities may also be subjected to chlorine, H2S (hydrogen sulfide) or other corrosive or reactive atmospheres. ● Age/Construction. Organic insulating materials, such as epoxy-covered paper, ceramic, asbestos and phenolic plastics can absorb moisture, begin to weaken dielectrically and be subject to carbon tracking. Many people don’t realize that fiberglass redboard, once cut, will absorb moisture and after 5 to 7 years can begin to breakdown and track. Vacuum circuit breakers that have been in service for 20+ years are beginning to fail due to leakage into the bottle. These circuit breakers had an expected service life of 20 years and many of those breakers have exceeded that. There are now field tests that can determine the remaining life that can be expected from individual vacuum bottles.

Fig. 8: Table L.1, Maintenance Intervals, Partial From NFPA 70B-2013, Recommended Practice for Electrical Equipment Maintenance Figure 8 is an excerpt from NFPA 70B, Annex L, Maintenance Intervals. Generally, circuit breakers are recommended to have service performed annually and tested every three years. The actual service conditions will affect the frequency of maintenance and the MTS and 70B recommendations are only guidelines.

Molded-case circuit breakers can seize due to corrosion and wear to the trip latch. The NRC conducted a study at Davis-Besse Nuclear Power Plant (7) and found that 80% of the molded-case circuit breakers that had been in service for 5 years would not function according to the manufacturer’s specifications. My personal experience has been that, after 3 to 5 years, approximately 50% of molded-case circuit breakers would not meet manufacturer’s specifications. The NRC recommended operation of the Pushto-Trip or Twist-to-Trip mechanism (usually marked in red) every year or, if no such mechanism is available, toggling the breaker off and on several times twice a year. ●

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● Duty cycle. It’s a little like Goldilocks; too much is not good, and neither is too little. Circuit breakers must be exercised to keep the lubricants mixed, but constant operation will take its toll. Circuit breakers used as across-the-line starters are one example of severe duty-cycles that can cause rapid deterioration. ● Loose connections. Even properly-installed electrical equipment can suffer from loose connections. All AC electrical equipment is subjected to the vibration caused by the current alternating. This vibration, plus the expansion and contraction of the metal caused by load changes will loosen connections over time. This is one reason why all electrical equipment and systems require routine maintenance. ● Experience and training of the personnel operating it. Unqualified or careless workers account for a fair percentage of damaged and nonfunctional electrical equipment in industry. OSHA and NFPA 70E both state that a qualified worker must be trained in and demonstrate their ability to both operate and recognize the hazards associated with that piece of equipment. Each month (or more often) I hear of an electrical accident caused by a worker who did not understand the limitations of his/her equipment. Stupidity can also be lumped into experience and training. As the old saying goes, “You can’t fix stupid”, no amount of training will save some people from themselves. Some people seem to try to live stupid to its fullest. Figure 9 is an actual photo taken during a service call by Rick Eynon. In order to prevent this LVPCB from opening, a board was jammed into the breaker so the contacts could not open, no matter what. Production managers often reward this type of dangerous behavior, without understanding the consequences of their decisions.

point where arcing takes place between the fuse and the clips. Medium-voltage fuses can absorb moisture, causing misoperation. Probably the biggest offender is workers replacing fuses with the incorrect type or size. Here’s a hint – if a fuse blows it’s not the fuse at fault. Figure 10 shows a 100A replaceable-element fuse with a 400A element installed. This type of misapplication is a hazard to workers and will cause unplanned outages.

Figure 10: Why I Don’t Like Replaceable-Element Fuses

Protective Relays. Electromechanical relays can be affected by several factors including age and wear on bearings, corrosion, contaminants, vibration (damaging the bearings), covers being left off, glass being broken, defective seals, etc. Solid-state and digital protective relays are not as affected by those factors, but can have loose connections caused by vibration, damage to their power supplies from voltage spikes or lightning, sudden failure of components and misprogramming by inept technicians. Since protective relays are often used in conjunction with auxiliary relays, interconnecting wire and instrument transformer issues can cause misoperation, as well.

SUMMARY AND CONCLUSIONS It’s a harsh world for the devices and equipment we depend on to keep us safe and our power system functioning reliably. Regular maintenance and testing of electrical equipment and systems ensures they will function safely and will reduce unplanned outages.

REFERENCES 1. NFPA 70E – 2012, Standard for Electrical Safety in the Workplace Fig: 9: How to Prevent Nuisance Tripping Photo Courtesy Rick Eynon

Fuses. Many people think fuses are maintenance free. There’s no such thing as free in this life. Dirt and contaminants can cause tracking on the fuse surface. Moisture can degrade fuse components. Vibration can cause loose connections, just as in all other types of electrical equipment. Load cycling can loosen fuse clips to the

2. NFPA 70E – 2015, Second Revision ballot 3. NFPA 70B – 2013, Recommended Practice for Electrical Equipment Maintenance 4. IEEE Standard 493, Recommended Practice for the Design of Reliable Industrial and Commercial Power Systems 5. Widup, R. and Heide, K., NETA Maintenance Testing Research On Electrical Power System Equipment Performance, PCIC-2011-40

Safety Vol. 2 6. ANSI/NETA MTS-2011, Standard for Maintenance Testing Specifications for Electrical Power Distribution Equipment and Systems 7. NUREG/CR-5762, Comprehensive Aging Assessment of Circuit Breakers and Relays, Wylie Laboratories James White is the Training Director for Shermco Industries, Inc. located in Irving, Texas. He is a Senior member of the IEEE, the recipient of the 2011 IEEE/PCIC Electrical Safety Excellence Award, the 2008 IEEE Electrical Safety Workshop Chairman, Alternate interNational Electrical Testing Association (NETA) representative on NFPA 70E®, Primary NETA representative on NEC Code Making Panel 13, Primary representative on NFPA 70B®, and is the Primary NETA representative to ASTM F18®. James is also a certified Level IV Senior Substation Technician with NETA, an inspector member of IAEI and serves on the NETA Safety and Training Committees. James is the author of Electrical Safety, A Practical Guide to OSHA and NFPA 70E and Significant Changes to NFPA 70E – 2012 Edition both published by American Technical Publishers.

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Safety Vol. 2

REDUCE RISK WITH PESDS MAKING NFPA 70E COMPLIANCE SAFER PowerTest 2014 Philip B. Allen, Grace Engineered Products, Inc.

ABSTRACT Electrical safety does not mean zero risk, but rather it is a process of decreasing electrical risks and their probability of occurrence to acceptable level. Since the 2000 edition of the NFPA 70E was published, it has fundamentally transformed practices regarding troubleshooting and electrical/mechanical lock-out/tag-out procedures by focusing on ways to lessen electrical risks. Yet, many end-users are choosing to exceed and go beyond the minimum safety standard prescribed in NFPA 70E and they are opting to install Permanent Electrical Safety Devices (PESDs) to curtail risk even further. The byproduct is an electrically safer work condition. An electrically safer work condition is achieved by an automobile manufacturer and Cintas Corporation when they utilize Permanent Electrical Safety Devices (PESDs), which reduce risks and increase the likelihood that zero voltage exists. Permanent Electrical Safety Devices (PESDs) are an example of safety by design. They incorporate electrical safety functionality directly into electrical equipment. While PESDs cannot be used as the sole device to check for the absence of voltage, when partnered with a voltmeter, they create an electrically safer work condition. This allows for workers’ exposure to shock and arc flash hazards to be further diminished during LOTO procedures because workers have no susceptibility to voltage.

bels on a panel fed with three-phase 480VAC and 120V separate control. Proper implementation and selection of PESDs greatly increases the prospect that a worker performing LOTO will have no exposure to voltage, and in some cases, requires no additional personal protection equipment (PPE) beyond the normal 8 cal/ cm2 daily wear. A PESD mounted on the outside of the panel provides workers with the ability to see and check all possible voltage sources 1. Depending on which PESD is installed on the panel, the combination of visual, audible and physical action required by the worker creates an electrically safer work condition.

Understanding the unique properties, functionality and installation requirements of each kind of PESD is essential to empowering users in the process of selecting the most suitable device for their specific application.

Warning: Before working on an electrical conductor, verify zero electrical energy with proper voltage testing instrument and the proper procedure as per NFPA 70E 120.1 (5), 120.2 (F)(2)(f) (1-6), OSHA 1910.333(b)(2)(iv)(B). Index Terms: Permanent Electrical Safety Devices, PESD, NFPA-70E, Voltage detection, Safety Device, Voltage Portal, Test Point Assembly

INTRODUCTION Permanent Electrical Safety Devices (PESDs) are a family of electrical components hardwired to a source of voltages and installed into electrical systems. They enable workers to verify the voltage status of equipment without exposure to the hazard. PESDs reduce the likelihood of arc flash and shock hazard because they diminish voltage exposure, provide voltage labeling on all sources and allow for 24/7/365 visual and/or audible indication of voltage. Figure 1 shows an example of the voltage source la-

Fig. 1: Voltage Source Labels

TYPES OF PESDS Creating an electrically safer work condition can be achieved with either a single-or three-phase source, which can be extended to the outside of an electrical enclosure through an encapsulated non-conductive housing called a voltage portal. The voltage portal is designed for use with a non-contact voltage detector (NCVD) to sense voltages from 50-500/90-1000VAC when placed into an energized voltage portal. The NCVD is a battery operated voltage

41

Safety Vol. 2 detector pen that senses AC (but not DC) voltage without actually touching an energized conductor. Figure 2 outlines the fundamental concept of a voltage portal and the associated NCVD.

● Designed and built solely to indicate the voltage status of a three-phase system. ● Always connected to the source and testing between L1-L2L3-GRD as per NFPA 70E 120.1(5) ● Powered from the line voltage (no batteries or maintenance) ● Wide operating AC/DC voltage range (20/40-750VAC/301000VDC) ● Senses stored energy as per NFPA 120.1(6) ● Meets 50-volt threshold as per NFPA 70E 110.6 (D)(1)(b), 110.7(E)5

Fig. 2: Cut away of three phase voltage portal NCVDs rely on a capacitive coupling to ground, which makes the NCVD less versitile than a phase-phase/phase-ground voltmeter test. However, with voltage portals installed and the panel energized, workers can test the voltage portal with the NCVD to ensure it works. This means a capacitive ground connection exists and will always exist because panels do not move and workers stand in the same place when they test. (Figure 3)2.

● Cat IV surge immunity and UL Certified to UL/ANSI 61010-1 as per NFPA 70E 120.1(5) Informational Note. Additionally, a zero-energy optical cable voltage indicator as shown in Figure 4 provides the same functionality as per above, but utilizes a non-conductive optical cable for transmitting the LED light. With no voltage to the outside of the electrical enclosure, this system meets the ANSI C37.20.1(7.1.3.7) switchgear specification limiting voltage to the outside of the enclosure to less than 254VAC.

Fig. 4: Zero Energy Voltage Indicator System

Fig. 3: Voltage portal to NCVD to GRD functionality Alternatively, a light emitting diode (LED) type of voltage indicator can be permanently hardwired to the phases and ground. This external device will illuminate when a voltage greater than 20-40VAC/30VDC is applied or when a voltage deferential exists between two lone inputs creating an electrically safer work condition. ● The risk reduction characteristics of a three-phase/four-wire voltage indicator include:

Figure 5 shows a three-phase test point device with built-in impedance on each phase, which provides another method of checking voltage with a standard voltmeter without exposing workers to the risk of an arc flash or electrocution. When a LOTO procedure includes both a three-phase test point device and a voltage indicator mounted into panel-mount housing, it increases the likelihood that the workers’ voltmeter test will yield only a zero voltage reading. The built-in impedance of 56K ohms on L1, L2, and L3 affects voltage readings by approximately 10% when using a typical digital voltmeter, however this is not applicable at the zero voltage range. Yet, the benefit of this approach is it limits the current outside of the enclosure to approximately 10mA. This reduces the propensity of a worker inadvertently causing a short circuit while performing a voltmeter test, which could result in an arc flash. The 10mA current threshold is below 17-99mA range that could cause death 3. In addition, depending on the installation and local codes, limiting the current to 10mA may eliminate the need for short circuit protection of a test point device.

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Fig. 5: Test Point with Energy Limiting Impedance A test point assembly with no impedance is a variation on this same concept with its own unique advantages and disadvantages. Without built-in impedance, the energy to the outside of the panel is limited only by the fuses and lead-wires to the test points. On the other hand, these test points provide a more direct connection to the source, which is an advantage. This is yet another example of creating an electrically safer work condition.

PESDS INSTALLATION REDUCES RISKS Because PESDs hardwire to the primary source disconnect and install on the exterior of the electrical equipment, they require an environmental type rating identical to the enclosure on which they are affixed and a minimum 600-volt component rating. When PESDs are installed on the enclosure flange in close proximity to the main disconnect, the installation eliminates the hazard of having 480 volt conductors on the door. The close proximity of a PESD to the main disconnect also reduces the lead wire length and minimizes potential electrical interference with other components inside the enclosure. Providing short circuit protection on PESDs is another choice users must make between electrical safety and electrical integrity of their installation. Short circuit protection means that 12 additional connections - or failure points - are added between the source voltage and the PESD as per Figure 6. These failure points increase the likelihood of a false positive voltage indication. In most cases, the only risk is the failure of the PESD lead-wires, not the PESD 4. In addition, manufacturers of electrical equipment are providing more reliable termination points for PESDs on their equipment. Article 430.72 of the National Electrical Code also allows for the omission of short circuit protection if opening of a circuit would create a hazard. One last minor point; some facilities decide to fuse PESDs because they believe workers should use them as a presence-of-voltage indication, while others believe PESDs should be used for absence-of-voltage. In the latter case, PESDs should be installed without fuses.

Fig. 6: Potential failure when fusing a PESD

EXAMPLES OF PESDS REDUCING RISKS A large automobile manufacturer had concern over the level of PPE and the presence of voltage on the line side of their switchgear. This concern encouraged a common practice of requiring workers first to locate then isolate the correct upstream source disconnect when necessary. Figure 7 shows a PESD installed on the line side of the equipment disconnect reduces risks in two ways. First, it provides an indication that the proper upstream source has been disconnected. Second, it statistically increases the likelihood that a zero electrical energy state exists inside the equipment electrical panel. Without a PESD, the worker must assume that voltage exists both on the line and load side of the equipment disconnect unless proven otherwise. In order to prove this without a PESD, the worker dons PPE and performs a voltmeter test on the conductors in question. Alternatively, with a voltage indicator installed, the worker verifies its proper operation and then witnesses a changeof-state immediately after opening the upstream disconnect. It is important to note that the worker is not exposed to voltage during this process.

Fig. 7: PESDs on the line and load side of equipment disconnect

Safety Vol. 2 The next step is to open the equipment disconnect. With the upstream source isolated and the equipment disconnect opened, the change-of-state on the voltage indicator (illuminated to non-illuminated) ensures a high probability for zero voltage to exists inside the equipment enclosure. It would require three device failures in close succession for voltage to be present, so a worker verifying with a voltmeter will likely show zero volts. Using a risk assessment procedure, the automobile manufacturer would conclude that there is a reduction in risk under this scenario that may allow workers to enter an equipment enclosure and verify zero electrical energy with a voltmeter while utilizing a reduction in PPE. In a similar example, Cintas Corporation installed PESDs to protect its employees and to increase productivity in their automated plants. In these types of plants, Cintas’ laundry equipment resides behind a restricted safety fence. Cintas’ procedures require that all the equipment within the restricted area be put into a safe state whenever a worker enters this area. After Cintas evaluated their maintenance-related downtime, they determined their electrical maintenance procedures disproportionality affected their productivity-especially in the automated plants. It took workers a significant amount of time to retrieve and suit up in PPE each time a maintenance task required access to the inside of an electrical panel. Once workers established zero energy inside the panel, they would remove their PPE to comfortably perform the maintenance task, which also added to the downtime.

43 Cintas developed a two-part PESD assembly that included a voltage indicator and fused hard-wired test points (no built-in impedance) in a clear-cover housing as shown in Figure 8. With the power on and the panel door closed, the worker has a visual indication that voltage exists and a test point to confirm the voltage indicator is functioning properly. Once the isolator is opened, the worker witnesses the voltage indicator change-of-state from illuminating to non-illuminating; this provides the first indication that the power has been disconnected, which reduces the likelihood that the test points have voltage. The test points are specifically designed to accept standard voltmeter probes, and the clear cover prevents inadvertent access to voltage by a non-qualified employee. Next, the worker uses the live-dead-live procedure with a voltmeter to verify zero voltage exists between L1, L2, L3 and GRD as per the procedure below and NFPA 70E 120.1(5). Like the automobile manufacturer example, a failure of the isolator, the test points with the meter, and the voltage indicator need to occur in close succession for voltage to exist inside the panel. Using this process, which includes the steps in NFPA 70E 120.1(1-6), is not only more efficient, but creates an electrically safer work condition. This process is inherently safer because it eliminates the likelihood for maintenance employees to test potentially live conductors inside an electrical enclosure using a voltmeter. The process is at the same more time efficient because maintenance employees do not have to take additional time to gather, don and remove electrical PPE. The far reaching result of this approach is the ability to achieve safety improvements along with productivity increases that benefit both Cintas and their employees. When a facility has properly maintained electrical equipment installed with available short circuit current ratings and interrupting times that do not exceed the maximum as described in NFPA 70E Table 130.7(C)(15)(a), they can use those tables for determining the PPE required for performing each specific task. In this case, smaller companies with a less skilled electrical maintenance staff can also benefit from PESDs. The mechanical maintenance workers receive a huge benefit with PESDs when these devices are used in mechanical LOTO procedures. Workers performing mechanical LOTO - work involving no contact with conductors or circuit parts - procedures must still isolate electrical energy. PESDs provide a means of checking voltage inside an electrical panel without exposure to that same voltage. Without these devices, a worker performing mechanical LOTO in some facilities would be required to work in tandem with an electrician using a voltmeter to physically verify zero voltage inside an electrical panel before work begins. In that case, the electrician is exposed to voltage. With PESDs, the mechanic can single-handedly check for zero electrical energy without any exposure to voltage, which makes the LOTO procedure safer and more productive.

Fig. 8: Test Point Voltage Indicator Assembly and Housing with Clear Cover

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Safety Vol. 2

SUMMARIZING THE RISK REDUCTION PROPERTIES OF EACH PESD Every time workers create an electrically safe work condition as per NFPA 70E 120.1, they subject themselves to multiple hazards. The risk exposure directly correlates with the procedures and devices used in their LOTO program. Each of the devices used – from a voltmeter to the varied PESDs - have their own unique risk characteristics that are both good and bad. Table 1 lists each risk characteristic compared to a voltmeter and assigns a rating that allows users to graphically see the risk factors for each type of PESD5. The goal is ensuring a worker’s voltmeter measures zero voltage once he accesses the inside of the enclosure. For example, “testing duration” is the first risk characteristic listed in Table 1. The voltage indicator is colored green for reduced risk because this device is hardwired to the source and constantly tests all three phases and ground simultaneously all the time. On the other hand a voltmeter is colored yellow for moderate risk because a worker with a voltmeter performs one test at a time by touching each conductor with the voltmeter leads and testing be-

Notes:

tween each phase and ground. Therefore, the “test duration” is a risk characteristic of a voltage indicator that increases the safety of a LOTO procedure as compared to a voltmeter. In the second row of Table 1, the risk characteristic “ability to test other circuit parts” gives the voltage indicator a red rating because it is hardwired to a single set of conductors and cannot test other circuit parts within the enclosure. In this example, the voltmeter is assigned a moderate risk because it can test other circuit parts but the worker may be exposed to voltage. Since PESDs are inexpensive, many times users choose selected combinations of PESDs to further reduce their risks. Table 1 also provides the ability for users to see and select the right PESD combinations, not only to meet the requirements of their electrical safety program, but also to accommodate different installation and environmental issues. For instance, a user would select a voltage portal over a test point assembly in a harsh environment because test jacks will eventually fail due to the corrosive atmosphere and a voltage portal would not.

Table 1: PESD Risk Assessment Chart

Note 1: Some voltage indicator designs have as much as 2mA ground leakage current that increases as more voltage indicators are installed. Note 2: Fuses add additional connections and failure points that increase the likelihood for a false negative voltage reading (voltage exists and not indicated on test instrument).

See: http://www.graceport.com/assets/files/Data%20Sheets/ SafeSide_OvercurrentProtection_2013(2).pdf Note 3: The likelihood that voltage exists after opening the isolator and/or used in conjunction with a voltage indicator is very low. Note 4: Mechanical LOTO has a lower burden of proof for electrical energy isolation.

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Safety Vol. 2

Characteristics

REFERENCES

Test Point Assembly (impedance limited in housing)

Voltage Portal

Voltmeter

Typical Industrial Multimeter

20-750VAC/30-1000VDC design specific

600V

0-1000VAC (50/901000VAC)

1000V (Typical)

2 Phases tested at a time

3 Phase with no Ground

2 Test leads

3 Phase & Ground

Number of Phases

CAT III/IV

CAT III/IV

Cat III/IV

Cat III/IV

Voltage Indication

Visual

Digital Readout

Visual and Audible

Digital

Batteries Required

NO

YES

Portal-NO, NCVD-YES

YES

Type 12/13/4/4X

Type 12/13/4/4X with housing door closed

Type 12/13/4/4X

N/A

Lmag. A resonance point comprises a network of capacitances and inductancesand can be described using Formula 4. The lower the inductance becomes, as reflected by a state of higher residual magnetism, the more the resonance points move toward higher frequencies.

To counteract this problem, the current can be additionally triggered while the test is still running to start the next hysteresis cycle. However, since the magnetization current increases very rapidly when the transformer core reaches saturation, this process is fairly inaccurate. Various experiments have shown that small transformers, particularly, become re-magnetized during the final cycle, which leads to high inrush currents at energization. Demagnetization based on the measurement of the magnetic flux has proven to be the safest and most efficient approach, as it works reliably with both small and large transformers. However, this approach places very strict measuring requirements on the test equipment as the voltage needs to be continuously measured over time and the integral of voltage with respect to time calculated. [See Formula 5]. It is important to avoid any secondary hysteresis during demagnetization. The occurring residual magnetism can lead to an apparent demagnetization.

DEMAGNETIZATION MEASUREMENT PROCEDURE

Fig. 6: Demagnetization using a sinusoidal signal Demagnetization of single-phase and three-phase transformers can be performed in a similar way. When working on a threephase transformer, it is important to consider that magnetic coupling takes place between the phases. Therefore, the phase or limb used during the demagnetization procedure is extremely important and deliberately chosen. It also makes sense to use the high-voltage side for demagnetization as there are more turns associated with this winding to generate the magnetic flux. Hence, the total time for demagnetization can be reduced. Experiments have shown that the middle limb is the most suitable for demagnetization with a single-phase source. Thereby, the flux is distributed symmetrically over the two outer limbs. To determine which winding is associated with the middle limb in a delta winding, the transformer’s vector group is required.

Since the voltage and thereby also the magnetic flux of the main inductance LH cannot be measured directly, this voltage needs to be calculated (Figure. 7, [Formula 6]). Therefore, the winding resistance R must be measured in advance and the voltage drop of the winding resistance then subtracted from the measured voltage. Formula 7 shows the calculation of the magnetic flux on the main inductance. Thereby фR(0) represents the initial flux, which corresponds to the residual magnetism.

Fig. 7: Simplified equivalent electric circuit for the measurement procedure The test equipment for demagnetization is very simple. If a switchbox is used, rewiring is not necessary after measuring transformer’s ratio or winding resistance. The transformer’s vector group must be known and the test current chosen. Then the procedure can reduce the residual magnetism to virtually zero.

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Transformers Vol. 1

The core can be saturated in both directions. The specific hysteresis parameters per transformer are then determined and the initial flux is calculated. On the basis of these parameters, an iterative algorithm is then used to change both the voltage and the frequency. While this is taking place, the test equipment is constantly measuring the flux ф in the core. Using multiple iterations, the core is demagnetized to below 1 percent of its maximum value. Following the demagnetization procedure, several magnetic domains revert back into their preferred orientation. This procedure is also referred to as magnetic viscosity. The effect can be determined when performing demagnetization once again, although it is actually negligible and therefore is not really important in practice.

Phase A

Phase B

EXAMPLE BASED ON A 350 MVA TRANSFORMER A 350 MVA-YNyn0 power transformer manufactured in 1971 and rated 400/30kV was tested. For verification of state purposes, SFRA measurements were conducted. The transformer’s condition was recorded immediately after removing it from service with an initial SFRA measurement. Subsequently, a dc winding resistance measurement was carried out on phase B, (which was wound on the middle core limb), and another SFRA measurement was taken. Lastly, the transformer was demagnetized using the previously described method and checked by performing a final SFRA measurement. The results after the demagnetization procedure are shown in Table 1.

Table 1: Results following demagnetization of the 350 kV transformer When comparing the SFRA results of the individual phases, one can see that the transformer displays residual magnetism after being isolated from the power system (Figure. 8). After the demagnetization procedure, all resonance points moved towards lower frequencies as expected, and the typical SFRA pattern of a threelimb transformer can be seen. The transformer can therefore be considered as demagnetized.

Phase C

Fig. 8: Phase comparison of the SFRA results with different remanence conditions

CONCLUSION This article highlights the importance and the effect of residual magnetism. It should also increase the awareness of the associated risks with reenergizing transformers after an outage. Within the last few years, the first testing devices have been developed to allow reliable on-site demagnetization of transformers without any major additional effort. Demagnetized transformer cores minimize the risk to personnel and equipment during installation. The SFRA measurement method is described in IEC 60076-18 and IEEE C57.149-2012 and has become increasingly accepted as a diagnostic method. To gain reliable and reproducible measurement results, we recommend demagnetizing the transformer core before performing SFRA measurements.

Transformers Vol. 1

Markus Pütter is product manager for OMICRON electronics GmbH, Austria. He has 14 years of experience in the field of power transformer testing. Markus received a Dipl-Ing. in Electrical Engineering from the University Paderborn in 1997. Michael Rädler (November 27, 1987) works for OMICRON electronics GmbH as a Product Manager for testing and diagnostic solutions for primary assets, mainly focusing on power transformer applications since January 2008. He graduated at the Federal Higher Technical Institute in Bregenz, Austria with focus on electrical engineering.

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Transformers Vol. 1

DC WINDINGS RESISTANCE: THEORY VS. PRACTICE PowerTest 2013 Charles Sweetser, OMICRON electronics Corp.

ABSTRACT

MEASUREMENTS

DC Winding Resistance is a simple concept that relies on the fundamental application of Ohm’s Law. DC Winding Resistance is a powerful tool for determining continuity in power transformer winding circuits; specifically, connections and tap changer contacts. However, performing DC Winding Resistance tests often presents several technical difficulties that must be overcome. The magnetizing inductance of power transformers must be removed through saturation of the core steel. To accomplish saturation, DC voltage or DC current must be applied or injected, respectively. The magnitude of DC signals will directly affect the time to saturation. Various techniques can be applied, such as winding assist, to speed-up and increase the effectiveness of the saturation process. This paper will present the obstacles associated with performing DC Winding Resistance tests, saturation techniques, safety considerations, demagnetization, and case studies.

The goal is to isolate and measure only the winding resistance for a specific phase and winding. However, depending on the winding configuration, Delta (open or closed), Wye, Auto, and Zig-Zag, and the fact that winding resistance measurement can only be performed between terminals, the measured result may be a combination of windings and not a specific winding. All Delta winding configuration measurements often cause confusion because a single winding cannot be isolated by any terminal pair. Also, in specific applications, such as tertiary or stabilizing windings, the open or closed status of the Delta winding creates additional confusion.

INTRODUCTION The DC Winding Resistance test is used routinely in the field to validate and assess the continuity of the current carrying path between terminals of a power transformer winding. The DC Winding Resistance test is looking for a change in the continuity or real losses of this circuit, generally indicated by high or unstable resistance measurements. The diagnostic reach of the DC Winding resistance test is to identify problems such as loose lead connections, broken winding strands, or poor contact integrity in tap changers. In addition to the winding, there are several more components that are part of the transformer’s current carrying path: ●● Bushings and Bushing Connections ○○ Draw Leads ○○ Draw Lead Pins ○○ Pad Connections ●● Tap Changers (LTC and DETC) ○○ Barrier Boards

The Winding Resistance measurement circuit includes 3 components - a DC source (V or I), a Voltmeter, and a Current meter, and by simultaneously measuring voltage and current determines resistance by Ohm’s Law. As simple as the DC Winging measurement appears, several factors should be considered.

Measurement Ranges Understanding the expected resistance values is important for setting up and performing a DC Winding Resistance measurement. Most modern winding resistances instruments have the ability to measure very low resistances values in the microOhm (µΩ) range up to notably higher resistance values in the kilo-Ohm (kΩ) range. However, typical transformer winding resistances generally range from a few milli-Ohms (mΩ) to several Ohms (Ω). It is recommended to review previous results or consult the factory test report for determining the expected results. This will allow the optimum ranges on the test instrument to be selected. It is always best to run all meters close to full range, above 70%, if possible. In the case of auto-ranging instrumentation, always verify that an overload condition has not occurred; this could greatly affect accuracy in the reading.

○○ Selector Switches

Static and Dynamic Measurement Types

○○ Diverter Switches

There are two distinctive types of DC Winding Resistance measurements that can be applied, Static (Standard) and Dynamic (Advanced).

○○ Reversing Switches ●● Windings ○○ Strands ○○ Cross-Overs ○○ Tap Leads

Static–This is the standard test that is performed to measure the actual resistance value of a transformer winding and associated series components. The static measurement produces a single, temperature dependent value in Ohms (Ω).

25

Transformers Vol. 1 Dynamic–This measurement is typically applied to load-tap changing (LTC) transformers. The dynamic winding resistance measurement tracks the changing resistive behavior as the LTC operates. Knowing that a LTC follows the “make before break” concept, any unusual changes, such as, loss of continuity, may indicate premature wear or fault with the LTC, specifically the diverter contacts.

The transformer winding appears to be a simple RL circuit. However, L, or the inductive component is made up of the leakage reactance of the winding, and the magnetizing reactance of the core. It is these inductive components that must be minimized through saturation. Figure 2 illustrates the RL basic components.

Kelvin Connections The Kelvin 4-wire method is the most effective method used to measure very low resistance values. The Kelvin 4-wire method will exclude the resistance from the measurement circuit leads and any contact resistance at the connection points of these leads. The concept of the Kelvin 4-wire method is to apply the voltage and current leads separately. This is shown in Figure 1.

Fig. 2: Basic transformer impedance model These inductances work in conjunction with the DC Winding Resistance and create a “not so simple” time constant. This time constant could be seconds or it could be minutes. Figure 3 shows a typical voltage and current response for a transformer winding, where 12 VDC has been applied.

Fig. 1: The Kelvin 4-wire method Connection points P1 and P2 are associated with the current injection and current measurement, and points P3 and P4 isolate the voltage measurement across the test specimen. Another subtle application of the Kelvin 4-wire method that should be noted is the placing of voltage sense leads (P4 and P4) ‘inside’ the current leads (P1 and P2). This helps ensure that any undesired voltage drops remain outside the intended resistance measurement.

Saturation The implication of the transformer core’s state of saturation makes the “simple in concept” test much more troublesome to users. Understanding the influence of the transformer core on the DC Winding Resistance measurement and why core saturation is a prerequisite for this test is challenging. To obtain the desired DC Winding Resistance measurement, the resistive component of the winding must be isolated; this requires saturation of the transformer’s magnetic circuit. Saturation occurs when all of the magnetic domains are successfully aligned in the same direction. By using Faraday’s Law: , it can be stated that the saturation process is dependent on the voltage applied across the terminals of a transformer. Intuition often leads us to believe it is current. However, higher currents produce greater voltage drops. From an application standpoint, it is important to understand the volt-amperes (VA) relationship, so that V can be maximized.

Fig. 3: Saturation response: voltage and current signals There are techniques and good practices that will improve the saturation process. If normal current injection methods are not sufficient and effective, there are additional advanced techniques to aid in saturation. Time to saturation can be shortened by either applying more current, re-directing current flow in Yn or yn windings, or using a combination of HV and LV windings. Recommended Techniques ●● Apply the highest possible terminal voltage without exceeding the recommended winding rating limits. To increase saturation performance, it is important to maximize the terminal voltage. However, there are some limitations. The current through a winding should not exceed 15% of the rated current. Limiting the current minimizes the chance of overheating, which could cause a change in resistance or thermal instability. ●● Maintain the direction of the magnetic domains between tests. Be aware of the terminal polarity. This may not be optimal when testing a Delta winding. ●● Re-directing current flow in a Wye windings with an accessible neutral takes advantage of the use of all 3 phases to align magnetic domains. Aligns flux direction in core by tying together 2 terminals. ○○ X1-X0: Inject into X1 and return through (X2 and X3) tied together; measure voltage across X1-X0

26

Transformers Vol. 1 ○○ X2-X0: Inject into X2 and return through (X3 and X1) tied together; measure voltage across X2-X0 ○○ X3-X0: Inject into X3 and return through (X1 and X2) tied together; measure voltage across X3-X0

Figure 4, shown below, is an example of re-direct current in Wye winding with an accessible neutral: “X1-X0: Inject into X1 and return through (X2 and X3) tied together; measure voltage across X1-X0”.

Fig. 5: Combining both H and LV winding

Safety ●● Strictly follow all local safety policies and procedures ●● Potential high voltage is present when applying the DC out put to test objects with a high inductance ●● As long as energy is flowing in the measurement circuit, NEVER connect or disconnect test objects and/or cables. Fig. 4: Redirecting current through a wye winding with accessible neutral ●● Use the HV and LV windings at the same time to assist in saturation; must be same phase and direction. ○○ X1-X0: Inject into H1 and tie (H3 and X1) together and return through X0; measure voltage across X1-X0 ○○ X2-X0: Inject into H2 and tie (H1 and X2) together and return through X0; measure voltage across X2-X0 ○○ X3-X0: Inject into H3 and tie (H2 and X3) together and return through X0; measure voltage across X3-X0 Figure 5, shown below, is an example of using both HV and LV windings: “X1-X0: Inject into H1 and tie (H3 and X1) together and return through X0; measure voltage across X1-X0”.

●● Always swap leads at bushing terminals and never at test equipment. ●● Use separate clamps for current and voltage connections on both sides of the test object to avoid hazards in case one clamp falls off during the test.

Magnetization The saturation process leaves the transformer core in a magnetized state. For most transformer applications, this is usually considered benign; however, magnetized transformers produce higher inrush currents upon energization. When in doubt, the manufacturer should be consulted. One side effect of core saturation is that it can influence other diagnostic tests, such as Turns Ratio and specifically, Exciting Currents and Sweep Frequency Response Analysis (SFRA). It is recommended to perform the DC Winding Resistance last to avoid contaminating the above mentioned test results. At the same time, exciting current tests and SFRA tests can be used to confirm and validate the presence or absence of magnetization. Figure 6 illustrates how magnetization can affect exciting currents results. In this example, the expected pattern of two similar high and one low is slightly distorted. As it is in this case, Phase C is often the worse because that is the phase that DC was last applied to during testing.

27

Transformers Vol. 1 ●● Poor Connections ●● Shorted Circuited Turns ●● Open Circuits and Turns

Such problems can generate significant heat during normal operation. It is recommended to review DGA results to provide supporting information that a heating condition exists.

Recommended Limits

Fig. 6: Exciting current patterns (with and without magnetization) At times, it may be required to demagnetize the transformers. There are two techniques that can be used to demagnetize a transformer. ●● Apply a decreasing AC voltage. This method is not practiced often due to the cost, size and complexity of such equipment for field use. This method would pull the BH curve, see Figure 7, to zero. ●● Apply DC power to the transformer windings and reverse the polarity of the applied source a number of times while reducing the voltage, current, and applied time until the core is demagnetized. Again, the focus is to pull the BH curve to zero.

Winding resistance test results are interpreted based on comparison. Individual phase measurements (Wye) or terminal measurements (Delta) are compared. Comparisons may also be made with the original factory results or previous test results. When comparing data from different test dates, the results should be normalized to a common reference temperature. It is expected that the measurements should be within 2% of each other 1.

Temperature Correction The temperature conversion formula is as follows 2:

where: Rs = resistance at desired temperature Ts Rm = measured resistance Ts = desired reference temperature (°C) Tm = temperature at which resistance was measured (°C) Tk = 234.5° C (copper) Tk = 225° C (aluminum)

Identifying Saturation Integrity

Fig. 7: BH curve

ANALYSIS OF RESULTS Failure Modes Detected by Winding Resistance Winding resistance is a diagnostic tool that focuses on Thermal and Mechanical failure modes. The winding resistance test is very useful in identifying: ●● Defective DETC or LTC (contacts)

To obtain valid winding resistance measurements, core saturation must occur. Often, experience is the best option for knowing how to identify saturation. The behavior of the measurement is generally inconsistent depending on the transformer design and configuration. Delta windings and preventative autotransformers in the LTC circuit are a few examples of obstacles that will affect the saturation process. Even after several minutes, saturation may appear complete, just to then change again. It is important on difficult units to document test parameters including approximate saturation time if the unit has been tested before. Once the testing is complete, an analysis is often enhanced by plotting the data, which in many cases is more helpful than viewing the data in tabular form. Figure 8, shown below, illustrates winding resistance data on a LTC that is exhibiting incomplete saturation. In both examples, early measurements are higher than expected. By viewing the plotted data, it is clear that core saturation has not occurred, and several measurements at the beginning of the test should be considered invalid.

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Transformers Vol. 1

Fig. 8: Incomplete saturation

CASE STUDIES Overheated Tap Changer Leads In this case study, the winding resistance measurements produces significantly higher readings on LTC positions 14R and 4L for Phase B, see Figure 8. Normal measurements were expected to be in the 25-30

mΩ range. The 14R and 4L measurements clearly exceeded the recommended limit of 2%. At first glance, it appears unusual that separate LTC positions produce questionable results. After reviewing the LTC nameplate information, see Table 1 below, it shows that LTC positions 14R and 4L share a common tap lead (#7).

Fig. 9: Winding resistance measurements on LTC

29

Transformers Vol. 1 POS

Volts

LTC

16R 15R 14R 13R 12R 11R 10R 9R 8R 7R 6R 5R 4R 3R 2R 1R

X1-X2-X3 15180 15095 15010 14920 14835 14750 14660 14575 14490 14405 14320 14230 14145 14060 13940 13885

A 8 7 7 6 6 5 5 4 4 3 3 2 2 1 1 0

B 8 8 7 7 6 6 5 5 4 4 3 3 2 1 1 1

N IL 2L 3L 4L 5L 6L 7L 8L 9L 10L 11L 12L 13L 14L 15L 16L

13800 13715 13360 13540 13455 13370 13280 13195 13110 13025 12940 12850 12765 12680 12590 12505 12420

0 8 8 7 7 6 6 5 5 4 4 3 3 2 2 1 1

0 0 8 8 7 7 6 6 5 5 4 4 3 3 2 2 1

9

M

Upon further investigation, clear over-heating of connection #7 was observed. This overheating is shown below in Figure 10.

K

Fig. 10: Overheating of connection #7

Poor LTC Contact Winding resistance measurements were performed on a load-tap changing transformer with a resistor-type LTC. All odd positions failed. Phase X3-X0 had higher than expected measurements The resistance measurements were consistently higher. This is shown in Figure 11.

Table 1: LTC nameplate

Fig. 11: Winding resistance measurement (poor odd positions on Phase C)

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Transformers Vol. 1

When measurements fail consistently in a pattern, as shown above, “in common” components should be investigated. This pattern indicates the problem is mostly associated with the diverter switch main contacts or associated leads. See Figure 12 below shows one side of the diverter switch.

Fig. 12: Diverter Switch

CONCLUSION This paper shares insight associated with performing DC Winding Resistance tests, saturation techniques, safety considerations, and demagnetization, and provides two case studies. The salient points of this paper are summarized as follows: ●● The Winding Resistance measurement circuit includes 3 components - a DC source (V or I), a Voltmeter, and a Current meter, and by simultaneously measuring voltage and current determines resistance by Ohm’s Law. ●● The DC Winding Resistance test provides a diagnostic tool that focuses on thermal and mechanical failure modes. The winding resistance test identifies problems such as loose lead connections, broken winding strands, or poor contact integrity in tap changers. ●● DC Winding Resistance results are interpreted based on comparison, and are corrected for temperature. ●● Transformer core saturation is a prerequisite for obtaining valid winding resistance measurements. Understanding the influence of the transformer core on the DC Winding Resistance measurement is challenging. Experience best equips a user in successfully identifying complete saturation of the transformer’s magnetic circuit.

REFERENCES 1

I EEE Std 62-1995, “Guide for Diagnostic Field Testing of Electrical Apparatus – Part 1: Oil Filled Power Transformers, Regulators, and Reactors”.

2

 . Gill: “Electrical Power Equipment Maintenance and Testing” P Second Edition, CRC Press, 2009

3

 . L. Sweetser, “The Importance of Advanced Diagnostic MethC ods for Higher Availability of Power Transformers and Ancillary Components in the Era of Smart Grid”, IEEE Power Engineering Society Summer Meetings, Detroit, MI, USA, July 22-26, 2011

Charles Sweetser received a B.S. Electrical Engineering in 1992 and a M.S. Electrical Engineering in 1996 from the University of Maine. He joined OMICRON electronics Corp USA, in 2009, where he presently holds the position of Technical Services Manager for North America. Prior to joining OMICRON, he worked 13 years in the electrical apparatus diagnostic and consulting business. He has published several technical papers for IEEE and other industry forums. As a member of IEEE Power & Energy Society (PES) for 14 years, he actively participates in the IEEE Transformers Committee, and presently holds the position of Chair of the FRA Working Group PC57.149. He is also a member of several other working groups and subcommittees. Additional interests include condition assessment of power apparatus and partial discharge.

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Transformers Vol. 1

PARTIAL DISCHARGE TESTING USING THE UHF DRAINVALVE SENSOR + PD SMART OR USING A SIMPLE SURVEY TOOL PDS 100 WITH THE SAME UHF DRAINVALVE PowerTest 2013 Karl Haubner, Doble Engineering

Partial Discharge Detection is considered one of the most powerful tools to determine the condition of insulation systems. There are various options to monitor for PD activity based on the release of the energy due to PD. Conventional electrical PD measurements according to IEC60270 require the installation of a sensor to the HV circuit. To monitor PD on transformers in the factory the PD detector is typically connected to the bushing taps. Once the transformer is placed in service this method is not always practicable and in most cases will be subject to external interference hence other called non conventional methods of PD detection are desirable. Rightfully, the most popular method to detect PD activity in transformer is by detecting the chemical decomposition of both cellulose and oil using Dissolved Gas Analysis. But there are sometimes situations that call for complementary techniques. Hydrogen, which is the key indicator of PD activity can have other origins and DGA is not 100% conclusive. DGA is an integrated measure and slower to identify a rapidly changing situation. Also direct on-line measurements can provide additional information on the type location of PD. Another methods relies on detecting the acoustic pressure wave generated by the internal PD event using piezoelectric sensors mounted on the outside of the tank wall but this technique has poor sensitivity for PD activity from within the transformer winding and should be seen more as an location rather than a detection technique. The demand for a more sensitive field technique has lead to the development of alternative methods. A PD event results in a transient current pulse and an electromagnetic field in very high (VHF) and ultrahigh (UHF) frequency range. These electromagnetic waves can be detected using special sensors or antennas. For transformer these electromagnetic waves emitted by PD resonate within the transformers enclosure and can be measured everywhere in the transformer with moderate attenuation of the signal but are not easily detected from the outside. The transformer tank acts like a Faraday cage effectively shielding external PD signals that may corrupt the measurement permitting much sensitive detection of PD activity on energized transformer then other methods based on acoustics or detection of PD activity via High Frequency CT’s in-

stalled on the neutral of the transformer but an internal PD sensor is required. There are two possibilities of installing these sensors. Either permanently fitted UHF hatch type sensor that can be incorporated in the transformer design or later installed by replacing an inspection cover typically installed during an outage in a UHF sensors that can be inserted through an oil drain wave are used.

Fig. 1: UHF Hatch Sensor

Fig. 2: PDS 100 RFI Survey

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Transformers Vol. 1

Fig. 5: Healthy transformer with no PD activity detected Fig. 3: UHF drain valve

Fig. 4: PDS 100 RFI Survey PD measurent using the UHF Drainvalve sensor + PDsmart or for a simple survey the UHF Drainvalve + PDS100 PD measurements via the oil drain sensor can be conducted whilst the transformer remains energized. The output signal of the sensors can be processed in time or frequency domain. The output cannot be described in term of apparent charge as in conventional measurements, but simultaneous measurements using both conventional IEC60270 test circuit and UHF couplers have shown sensitivities in the low pC range for the UHF couplers. Because the transformer shields the measurement from external interference, interpretation also is less complex.. In the absence of any active PD source in most cases only background is detected.

Fig. 6: Transformer with critical PD activity Since the PD pulse characteristics are preserved using a UHF PD detector, it is sometimes possible to determine the nature of the PD using the phase resolved patterns. The main aim of the above tests is to detect if the transformer has PD activity or not. Once the presence of PD has been confirmed and some estimate about the severity of the activity is known PD location should be attempted. The output of the UHF probe can now be used as the trigger signal enhancing the accuracy of the triangulation techniques. In summary for the first time PD measurements comparable in terms of sensitivity to laboratory tests are possible in the field even under adverse condition and without an outage to conduct these tests. This compliments the well known Dissolved Gas Analysis and overcomes shortcomings of the acoustic technique which is more suitable for location rather than conclusive detection. The main disadvantage of the UHF method is that it is not possible to calibrate the PD in terms of apparent charge in pC.

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Transformers Vol. 1

I HAVE A LOT OF NUMBERS, WHAT DO THEY MEAN – BASIC INTERPRETATION OF TWO WINDING TRANSFORMER DATA PowerTest 2013 Keith Hill, Doble Engineering Company

INTRODUCTION: The intent of this paper is to educate an inexperienced tester on the steps to be taken to be assured that the proper test procedures were performed. It is recommended that these guidelines be understood and followed to prevent testing errors in the field. In this paper, you will see some terminology that may be new to you. An attempt will be made to identify these components with a brief description. More detailed information can be located in the operator’s manual provided by the manufacturer of your equipment. For this paper it will be assumed that the tester knows how to operate the test set. This presentation is an attempt to demonstrate to the tester what each item means. It is important that the tester fully understand the test form and software being used.

The CH’ and CL’ may be new terminology to both inexperienced and experienced testers who may normally use test equipment manufactured by various manufacturers. CH’ is the CH insulation minus the sum of the C1 results for the primary bushings. CL’ is the CL insulation minus the sum of the C1 results for the secondary bushings. C1 is the test performed on the bushings (Figure 2), with a capacitance tap, by energizing the main conductor and measuring to the tap in the Ungrounded Specimen Test (UST) mode.

The following terminology will be used in this paper: CH, CL, CHL, CH, CL, and C1. CH is used to describe all of the high voltage components to ground. This will include the high side insulation, high side bushings, structural insulating members, insulating fluid, and de-energized tap changed, if present. CL is used to describe all of the low voltage components to ground. This will include the low side insulation, low side bushings, structural insulating members, insulating fluid and load tap changer, if present. CHL is used to describe the insulation between the windings, winding barriers, and the insulating fluid.

Fig. 2: Main-insulation/C1 test standard method One of the most important parts of analyzing test data is to make sure that the tests were performed correctly. This can be accomplished by using simple math as demonstrated in the following examples. A review of the DTAF layout (Figure 3) is provided for personnel who are not familiar with this test form. Column 1: Test number Column 2: Note indication box Column 3: Winding energized Column 4: Test mode of low voltage lead - Ground

Fig. 1: Dielectric circuit of a two-winding transformer

Column 5: Test mode of low voltage lead - Guard Column 6: Test mode of low voltage lead - Measured

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Transformers Vol. 1

Column 7: Test voltage in kV Column 8:

mA

Column 9: Watts Column 10: Measured power factor Column 11: Power factor corrected to 20 degree C Column: 12: Correction factor

sured that the test procedures used were correct. If the currents and watts add correctly then the high voltage cable and the low voltage lead can be reversed and testing of the low voltage winding can take place. Once testing has been performed on the low voltage windings, the same procedure is used to verify the low voltage test results (Figure 4).

Column 13: Measured capacitance Column 14: Insulation measured Column 15: Rating provided by DTAF expert system Column 16: rating provided by tester

Fig. 4: Low voltage test results For test number 5 (column 1), note that the insulation measured (column 14) is the CL and CHL. Fig. 3: DTAF layout For test number 1 (column 1), note that the insulation measured (column 14) is the CH and CHL. For test number 2 (column 1), note that the insulation measured (column 14) is the CH. For test number 3 (column 1), note that the insulation measured (column 14) is the CHL. Using simple math we see that the following statement should be true: Line 2 mA + Line 3 mA = Line 1 mA (CH) + (CHL) = (CH + CHL) 11 mA + 19.97 mA = 30.97 mA Line 1 is actually 30.98 mA Line 2 watts + Line 3 watts = Line 1 watts (CH) + (CHL) = (CH + CHL) .248 watts + .578 watts = .826 W Line 1 is actually .829 watts Test 4 is the calculated CHL which allows the tester to “doublecheck” the test result. Test 1 (Current and Watts) - Test 2 (Current and Watts) = Calculated UST (Line 4) (CH + CHL) - (CH) = (CHL) Test 3 and Test 4 should be “equal” If these currents and watts add up the tester can usually be as-

For test number 6 (column 1), note that the insulation measured (column 14) is the CL. For test number 7 (column 1), note that the insulation measured (column 14) is the CHL. Using simple math, we see that the following statement should be true: Line 6 mA + Line 7 mA = Line 5 mA (CL) + (CHL) = (CL + CHL) 45.43 mA + 19.97 mA = 65.40 mA Line 5 is actually 65.41 mA Line 6 Watts + Line 7 Watts = Line 5 Watts (CL) + (CHL) = (CL + CHL) 1.328 W + .576 W = 1.904 W Line 1 is actually 1.907 W Test 8 is the calculated CHL which allows the tester to “doublecheck” the test results. Test 5 (Current and Watts) - Test 6 (Current and Watts) = Calculated UST (Line 8) (CL + CHL) - (CL) = (CHL) Test 7 and Test 8 should be “equal” Tests 3, 4, 7, and 8 should be “equal” As stated for the high voltage winding tests, if the low side currents and watts add up the tester can usually be assured that the test procedures used were correct. If the bushing have capacitance taps the C1 and C2 tests can be performed, which will allow for the calculations of the CH’ and CL’.

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Transformers Vol. 1 In Figure 5 the CH’ Calculation is on Line 9 of the test form.

Fig. 8: Fig. 5:

Using the current and watts in Figures 7 and 8, we can calculate the CL’. Sum of the Secondary Bushings C1 tests currents (Figure 8) 2.114 (X1) + 2.138 (X2) + 2.189 (X3) + 2.146 (X0) = 8.587 mA Line 6 mA – Sum of C1 mA = Line 10 mA (Figure 7) 45.430mA – 8.587 mA = 36.843 Ma

Fig. 6:

Sum of the Secondary Bushings C1 tests Watts (Figure 8)

Using the current and watts in Figures 5 and 6, we can calculate the CH’.

.054 (X1) + .053 (X2) + .054 (X3) + .056 (X0) = .217W

Sum of the H bushings C1 tests currents (Figure 6)

Line 6 Watts – Sum of C1 Watts = Line 10 Watts (Figure 7)

1.333 (H1) + 1.333 (H2) + 1.323 (H3) + 1.334 (H0) = 5.323 mA

1.328 W – .217 W = 1.111 W

Line 2 mA – Sum of C1 mA = Line 9 mA (Figure 5) 11mA –

5.323 mA

= 5.677 Ma

Sum of the H bushings C1 tests Watts (Figure 6) .030 (H1) + .030 (H2) + 1.323 (H3) + .030 (H0) = 1.20 Watts Line 2 Watts – Sum of C1 Watts = Line 9 Watts (Figure 5) .128 W – .120 W = .128 W Line 9 (Figure 5) is the primary insulation without the bushings included in the tests. We should remember that power factor is actually ‘average’ power factor” as an average of the insulation system is measured. The power factor for line 9 may remain the same if both the bushings and windings were acceptable. If the bushings were acceptable and the windings were contaminated the power could increase. If the bushings had higher than normal power factors the power factor for line 9 could decrease.

Line 10 is the CL insulation without the secondary bushings included in the tests. The same holds to be true for the secondary tests as for the primary tests. The power factor for line 10 may remain the same if the bushings and windings were acceptable. If the bushings were acceptable and the windings were contaminated the power could increase. If the bushings had higher than normal power factors the power factor for line 10 could decrease. Please remember that after the bushing tests are performed the tester must return to the overall test sheet and perform a recalculation for the bushings to be subtracted from the CH and CL.

This same procedure is used when calculating the CL’. Fig. 9:

Fig. 7:

In Figure 9, you will note an increase in the power factor for tests 9 (CH), when compared to test 2 (CH) and test 10 (CL) when compared to test 6 (CL). The power factor increased 1.5% for test 9, without the bushings, compared to test 2, with the bushings. This is an indication of good bushings (Figure 10) “masking” the contaminated windings. The same applies for test 10 compared to test 6, but the increase in power factor is not as great.

36

Transformers Vol. 1 When questions arise always go back to the basics: A change is current or capacitance is a physical change. A change in watts is due to contamination or deterioration.

Fig. 10:

HANDY FORMULAS AND THINGS TO KEEP IN MIND Power Factor = watts x 10 mA Capacitance = 265 x mA (60 Hz) (Rule of thumb is good up to about 15% power factor)  apacitance = 318 x mA (50 Hz) (Rule of thumb is good up C to about 15% power factor) It must be remembered that a change in current or capacitance from prior tests is a physical change, while a change in watts is usually from contamination or deterioration. From the above power factor formula, one can see that if the capacitance and current are the same that the change in power factor would have to be from a change in the watts.

CONCLUSION: This is a quick review/introduction on the steps used to verify that the test procedures used were correct. One should always analyze the power factor but that will not be covered in this paper as the power factor can vary for different transformers. These quick steps should always be performed once a test is complete and before the leads are changed. Please remember that a “G” rating does not mean that the tests were performed correctly as this may be the first test performed and the software may be comparing the corrected power factor to know limits. Often, emphasis is placed only on the power factor of the apparatus being tested. To correctly analyze the data, the currents, watts, capacitances, and power factor should all be reviewed and analyzed. Prior test data can be used as a reference as the currents should basically be the same each time. Power factor is only one tool in your tool box and acceptance of this apparatus should not be based only on power factor results. Excitation current, transformer turns ratio, winding resistance, and oil analysis are all recommended to be performed in an attempt to establish the condition of the transformer. Sweep Frequency Response Analysis (SFRA) along with Leakage Reactance (LR) tests may also assist in identifying a problem.

Keith Hill has been employed at Doble Engineering since 2001, and currently works as a Principal Engineer in the Client Service Department. Keith has over 38 years of experience in substation maintenance, electrical testing, and project management. Mr. Hill is a member of IEEE, a former NETA certified technician, and is a level I and II certified thermographer. Prior to Doble, Mr. Hill was the Electrical Supervisor of Engineering Services for a major refinery. Mr. Hill has published several papers relating to equipment testing and maintenance for various conferences and publications. At the present time, Keith serves as the secretary of the Doble Arresters, Capacitors, Cables, and Accessories committee. Keith received his BS from the University of Houston with a major in Electric Power.

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Transformers Vol. 1

ARE YOU REALLY TESTING YOUR INSTRUMENT TRANSFORMERS? PowerTest 2013 Michael Hancock, P.E.

INTRODUCTION Instrument transformers are a forgotten entity within any electrical system. Sometimes, they are tested upon commissioning and sometimes they are not. With the ever increasing focus on cost reductions, instrument transformer testing is usually one of the first items to be removed from the preventative maintenance test listing. There are many basic tests that can be completed on instrument transformers. However, are these tests satisfactory and sufficient to determine if they are acceptable for use and/or will they function as designed? There are many hidden secrets within these tests and this paper will focus on the basics of testing instrument transformers and the hidden practice to determine if they will truly work correctly. For example, are you simply hooking up an automated test set and looking at the results and assuming that all is well? What about the burden, i.e. connected load? We will dive into the art of instrument transformer testing to determine if you are indeed actually testing your instrument transformers.

WHAT TESTS SHOULD BE CONDUCTED ON INSTRUMENT TRANSFORMERS: ●● Perform insulation resistance through bolted connections. ●● Perform insulation resistance between windings ●● Perform Polarity Test ●● Perform ratio test on all taps ●● Perform excitation test to determine knee voltage or saturation point on current transformers ●● Measure burden at transformer terminals ●● Perform dielectric withstand voltage on primary windings

“Through” the connection. The results should be very low, i.e. in the micro-ohms. Compare the results for similar connections for they should be very close. If anomalies are found, investigate further by checking the torque on the bolts and if necessary, break the connection, clean, reassemble and then retest. See Figure 1 below for an example of where to apply the test leads to measure the resistance of the bolted connection.

Fig. 1: Test Resistance of Bolted Connection

Perform insulation resistance between windings The intention of this test is to ensure that there are no shorted windings to one another and to ensure that the internal windings are properly insulated from ground. This test is important to ensure that the windings are properly insulated. There are many types of instrument tranformers, for example, some are encased in plastic, and some have metal mounting brackets molded into them, just to name a few. See Figure 2 below for an example of where to apply the test leads in order to test between the various windings.

●● Measure power factor ●● Verify proper grounding ●● Verify fuse ratings and test fuses

Perform insulation resistance through bolted connections. All current and potential transformers are connected to bus bars, cables or some other type of connection. The intention of this test is to ensure that the connections are tight and torqued properly. To perform this test, you apply a Digital Low Resistance Ohmmeter (“DLRO”) across the connection and measure the resistance

Fig. 2: Perform Insulation Resistance Between Windings

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Transformers Vol. 1

Perform Polarity Test The polarity test is extremely important, especially in today’s times with the advanced protective relays and metering devices. The polarity determines the power flow of the current or voltage applied. If the power flow into the protective relay or meter is not correct, the meter may not read correctly and the protective relay may miss operate or not operate at all depending upon how it is wired. All current and potential transformers have markings that show the high and low side connections. These are normally labeled as H1, H2, X1, and X2. If the current transformers have multiple windings, i.e. taps, they may have additional markings, such as X1, X2, X3, X4, X5, etc. Please review Figure 3 below which shows an elementary diagram of a current transformer, a potential transformer and a typical test utilized to measure the polarity.

ments are exceeded, i.e. connected load is too large, the instrument transformer will become saturated and not produce linear results. Therefore, it is important to perform the excitation test to determine the point at which the instrument transformer will saturate and not produce linear results. The knee point is determined at the point on the curve where the voltage plot begins to be non-linear, which is typically at a point of 45 degrees tangent to the curve; see the example in Figure 4 below. To determine this point, apply voltage to the instrument transformer, raise the voltage and plot the results. The resulting graph should be similar to the one in Figure 4.

Fig. 4: Current Transformer Excitation Plot

Measure burden at transformer terminals Fig. 3: Polarity Test

Perform ratio test on all taps All instrument transformers have a set ratio. For example, a common potential ratio for a 4200 volt system is 4200/120. If exactly 4200 volts were applied onto the primary, the secondary would read 120 volts. Current transformers typically have ratios similar to 4000/5, 3000/5, 1200/5, etc. Therefore, utilizing the 4000/5 ratio as an example, if 4000 amps were applied to the primary, the secondary flow would be 5 amps. The intention of the ratio test is to verify that the ratio is per the name plate and that the proper tap is connected per the engineering design if the instrument transformer has multiple taps.

What is the proper way to measure burden? Do you simply apply 5 amps in 1 amp increments and measure the voltage? Technically no. What happens when a severe fault occurs and instantaneous settings are utilized? Not only that but each device should be tested to ensure that it is properly wired into the instrument transformer loop and the proper polarity has been applied. In order to properly test the burden, you should ask what the instantaneous setting is if utilized because this is the maximum current that must be sensed by the protective relay. The instrument transformer should be able to push this current and voltage through the connected secondary loops linearly.

Perform excitation test to determine knee voltage or saturation point on current transformers

To determine the maximum burden voltage level, apply current, preferably at the instrument transformer, so that all of the resistance of the connected instrument transformer load is connected and evaluated. The measured voltage required to drive the instantaneous setting should be less than 50% of the knee voltage. If the voltage required to drive the connected load is above 50% as compared to the knee voltage of the instrument transformer, it is highly advised to consult the engineering group that designed the circuit and to further recommend high current injection testing of the instrument transformer loop to ensure proper operation.

The excitation test is utilized to determine the knee voltage or saturation point. All instrument transformers have a power rating, just like a large power transformer. If the power require-

When testing the burden, it is recommended to apply low amperage, around 1 amp or so, then verify that all of the connected loads are wired correctly. Every element should be verified to

Most modern instrument transformer test units have auto functions and will measure and provide the ratio. A simple method to verify a ratio is to apply voltage onto the primary and measure the secondary voltage, then compare this against the name plate rating, which should be the same.

Transformers Vol. 1 have the proper polarity as connected. Most relays utilized today are of microprocessor type and can determine phase faults, phase calculations, watts, vars, etc. and if any of the elements are corrected incorrectly the relay may trip incorrectly or read incorrectly. Figure 5 below shows an elementary diagram on the left showing where to ensure proper polarity, which should be done for all connected devices. The diagram on the right is a more advanced system and all elements in this example should be verified.

Fig. 5: Current Transformer Burden Testing

Perform dielectric withstand voltage on primary windings The intention of this test is to verify that the device can withstand the applied voltage and ensure proper insulation. This test should be applied when appropriate and the appropriate AC and or DC test voltage should be utilized.

Measure power factor This test is typically applied to higher class instrument transformers such as 138kV rated or higher. This test can be applied to lower classes but is most typically completed on higher class instrument transformers. The power factor should be referenced to similar like devices and to historical tables. This is an extremely useful test to determine the overall condition of the apparatus.

Verify proper grounding Proper ground should be verified on the secondary side of the instrument transformers. Most current and potential transformer loops are grounded on the secondary sides and should only have one ground. The ground should be verified for reference and for safety purposes.

Verify fuse ratings and test fuses All potential transformer loops should be protected by fuses. The fuse ratings should be verified and it is further recommended to test the fuses. Care must be utilized when testing low ratings to not utilize a test instrument that will blow the fuses. The fuse ohm readings should be compared to similar fuse types.

39 Mike Hancock is a P.E. who has worked within the Electrical Power industry since 1992. Within Shermco, Mike is tasked with leading the 8010 divisional sales team and developing the electrical power utility markets. Mike has held numerous positions with various companies with increasing responsibility such as Senior Field Engineer, Area Supervisor, Executive Project Manager, PDS Global & National Accounts Manager and currently holds the title District Sales Manager/ Business Development with Shermco’s (ESD) Electrical Services Division. Mike has extensive experience with power systems engineering and solutions, field startup and commissioning and has advanced into the management realm. Mike has experience working with telecom, industrials, electric utilities, large retail, commercial, government, institutions and in many other market segments.

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Transformers Vol. 1

PARTIAL DISCHARGE TESTING OF ROTATING MACHINES – IS IT SCIENCE OF BLACK MAGIC? PowerTest 2013 Vicki Warren, Iris Power LP, Qualitrol Company

ABSTRACT In the past few years, reports based on a few case studies have shown that modern air-cooled stator windings are suffering from premature deterioration of the insulation. However, since these reports have no statistical basis, the total population is unknown and some machine manufacturers claim the ‘situation is normal.’ To obtain a more objective insight into whether modern air cooled stators are seeing an increase in deterioration; analysis was made of a large partial discharge database collected from such machines. The paper will present the data and explain the PD measurement process. The deduction is that this more objective analysis indicates that higher design stresses used in the past decade are in fact resulting in more rapid deterioration of insulation systems.

INTRODUCTION Partial discharges (PD) are small electrical sparks that occur when voids exist within or on the surface of high voltage insulation of stator windings in motors and generators. These PD pulses can occur because of the thermal deterioration [Figure 1], manufacturing/installation processes [Figure 2], winding contamination or stator bar movement during operation. As the insulation degrades, the number and magnitude of PD pulses will increase. Although the magnitude of the PD pulses cannot be directly related to the remaining life of the winding, the doubling of PD pulse magnitudes approximately every 6 months indicates rapid deterioration is occurring. If the rate of PD pulse activity increases rapidly, or the PD levels are high compared to other similar machines, this is an indicator that visual inspections and/or other testing methods are needed to confirm the insulation condition [IEEE 1434-2000]. Furthermore, if the PD magnitudes by the same test method from several identical windings are compared, the windings exhibiting higher PD activity are generally closer to failure.

Fig. 1: PD due to Thermal Deterioration

Fig. 2: PD at the Voltage Stress Coatings

THEORY Once a void is created within the bulk or on the surface of insulation, a potential difference will build across it. The magnitude of this voltage will depend upon the applied voltage, the capacitance of the insulation and the gas in the void. The voltage that develops across the void is shown in Figure 3. A discharge can only occur when the electric stress (V/mm) exceeds the electrical breakdown point for the gas based on Paschen’s law. Other issues besides gap length that can affect the electric stress in a void are: diameter, internal gas and pressure, and the nature of the surface in the void. In general, the product of the gap separation and the gas pressure establishes the voltage necessary to lead to a discharge, i.e., breakdown voltage [IEEE 1434-2000].

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Transformers Vol. 1 PD CHARACTERISTICS

Fig. 3: Electrical Stress in a Void between Coil and the Core When the applied 50/60Hz increases sinusoidally, the apparent electric stress across the void increases until it reaches 3kV/mm or the equivalent breakdown voltage in the void. Over voltage is the state at which the voltage across a void exceeds the breakdown voltage required for the void size and gas. The larger the over voltage the more intense the space charge effects in the void. Although a void may be in an over voltage state, breakdown will not occur until a free electron (due to cosmic or natural radiation) appears within the gap and starts an avalanche of the electrons. This avalanche is a flow of electrons across the gap which gives rise to a very fast rise-time (a few nanoseconds) current pulse, called a partial discharge (PD). The dependence on the free electron for a partial discharge makes the occurrence of PD a statistical event and therefore not predictable. Once the breakdown occurs, the voltage across the gap collapses to a voltage level sufficient to sustain the discharge. Most instruments only detect the initial breakdown pulse [IEC 60034-27]. No further detectable discharges will occur until the gap voltage has reversed in polarity and another over voltage condition established. Thus, for each pulse position there will be a detectable PD occurring twice in an AC cycle. However, the occurrence, magnitude, and pattern in a void are a complex phenomenon depending on the size, shape, internal gas pressure, and nature of the void surface and will deviate from cycle to cycle due to past space charge trapping (as shown in Figure 4).

Fig. 4: Partial Discharge Occurence

Machines that have not been properly impregnated or that have been operating for several years at high temperatures tend to develop voids within the groundwall insulation. If both sides of the void have similar insulation materials then the charge distribution will be equal during the positive and negative cycles. In theory, there will be two observable PD pulses in each AC cycle of equal magnitude and opposite polarity per void within the bulk of the insulation [Figure 5]. These pulses clump at the classic positions for phase-to-ground dependent pulses, that is, negative pulses at 45° and the positive pulses at 225° with reference to the 50/60Hz phase-to-ground voltage [Figure 6]. A machine that is frequently load cycled or severely overheated develops voids near the copper conductors. A void bounded by the copper conductor and insulation, exhibits a different phenomenon than those within the bulk of the insulation. Though the basic breakdown mechanisms are the same, because the electrodes are of dissimilar materials, polarity predominance occurs. The mobility of the positive ions on the insulation surface is much lower than the negative ions on the conductor surface. The result is a predominance of negative ions migrating through the gap to the positive insulation surface. In this case, there will usually be an observable predominance of negative PD pulses clumped at 45° during the positive AC cycle [Figure 5]. Loose coils, poor semi-conductive coatings, and problems with the grading/semicon interface can all lead to surface discharge between the stator bar and the grounded core iron, called slot discharges. As with those near the copper conductors, these discharges occur between electrodes made of different materials. Here, the immobile positive charges on the insulation and mobile negative charges on the grounded metallic electrode lead to pulses occurring during the negative AC cycle. Because the metallic electrode is grounded, the observable PD pulses will be predominantly positive clumped at 225° [Figure 5].

Fig. 5: Polarity Predominance

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Transformers Vol. 1 where near the source of the PD. Two types of sensors referenced in IEEE 1434-2000 and IEC/TS 60034-27-2 are: ●● Capacitive couplers, Epoxy Mica Capacitors (EMC) - for motors, hydros, and small turbos. [Fig. 8, Fig. 9] ●● Stator slot couplers (SSC) - for large turbos (>100MW). [Fig. 10]

Fig. 6: Phase-to-ground Discharges Contamination and/or Phase to Phase Discharges in the end arm area, on ring busses, or motor leads can lead to partial discharge activity in these areas. Unlike the previously described pulses that are phase-to-ground voltage dependent, these pulses are based on phase-to-phase voltages. Though these pulses tend to be very erratic, it is sometimes possible to distinguish these pulses from others by observing their location with reference to the phase-to-ground voltage. Typically, because of the phase-to-phase voltage dependency there is a 30° phase shift from the classic phase positions associated with pulses that are phase-to-ground voltage dependence as shown in Figure 7. Phase-to-phase pulses tend to clump at 15°, 75°, 195°, and 255°, based on the location of the pulses and the phase rotation of the machine. Sometimes, it is possible to determine which two phases are involved, but often it is difficult to extract that information accurately from the quantity of pulses detected.

Fig. 8: EMC at Terminals

Fig. 9: EMCs on Bus Bar

Fig. 10: SSCs in Turbo

PD DETECTION Fig. 7: Phase-to-phase Discharges

PARTIAL DISCHARGE SENSORS Permanently mounted PD sensors block the AC power signal (50/60Hz), but pass the high frequency PD pulses (50-250MHz). The type of sensor installation and test instrument depends on the machine or equipment being monitored. The first step of PD detection is the placement of a sensor some-

During normal operation, a continuous PD monitoring or portable PD instrument connected to the sensors separates noise and properly classifies the PD. Until recently such an “on-line” PD test had been difficult to implement due to the presence of electrical disturbances that have PD-like characteristics. This can lead to healthy windings being misdiagnosed as deteriorated, which lowers confidence in the test results. “Noise is defined to be non-stator winding signals that clearly are not pulses.” [IEC/TS 60034-27-2] Electrical noise from power tool operation, corona

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Transformers Vol. 1 from the switchgear and RF sources, etc., is easily confused with PD from the machine windings.

Separation based on pulse characteristics [Figure 14].

“Disturbances are electrical pulses of relatively short duration that may have many of the characteristics of stator winding PD pulses – but in fact are not stator winding PD.” [IEC/TS 6003427-2] Some of these disturbances are synchronized to the AC cycle, and some are not. Sometimes synchronized disturbance pulses can be suppressed based on their position with respect to the AC phase angle. A good on-line PD test reduces the influence of noise and disturbances, leading to a more reliable indication of machine insulation condition. Three methods of noise and disturbance separation include: Fig. 14: PD coming from System

Band-pass filtering of PD between 50-300MHz, whereas noise is less than 35MHz [Figure 11]

ANALYSIS

Fig. 11: Band-pass Filter 40-350MHz Separation based on direction-of-arrival to two sensors connected to a single phase [Figure 12, Figure 13]

Although the magnitude of the PD pulses cannot be directly related to the remaining life of the winding, if the rate of PD pulse activity increases rapidly or the PD levels are high compared to other similar machines, this is an indicator that visual inspections and/or other testing methods are needed to confirm the insulation condition [IEEE 1434-2000].

TREND If the unit operating parameters – voltage, load, winding temperature and gas pressure – are similar to those of the previous test, then a direct comparison can be made between the two test results. Environmental conditions such as humidity may have a very noticeable impact, especially if the surface contamination becomes to some extent conductive when damp, so it should be recorded from one test to the next. When a trend line is established for PD tests taken over a period, it will be obvious that most show small up and down variation between successive tests [Figure 15]; however, a sustained upward trend indicates developing problems.

Fig. 12: PD coming from Machine

Fig. 15: Typical PD Trend

COMPARE TO SIMILAR MACHINES

Fig. 13: PD coming from System

If the PD magnitudes by the same test method from several similar windings are compared, the windings exhibiting higher PD activity are generally closer to failure. Due to the influence of the test arrangement on the results, the test setup (sensors and test instrument) must be the same for all comparisons5 .

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One example is the statistical summaries of the peak magnitude, Qm, values based on the most recent Iris Power database that contains several thousands of test results. Each table shows the average, maximum, and the 25th, 50th, 75th, 90th, and 95th percentile ranks [Table 1]. The 25th percentile is the Qm magnitude for which 25% of the test results are below, similarly for the other percentiles. Normally, there is concern for a winding if the Qm in a machine is higher than the 75th percentile and increasing. 25

6-9

10-12

13-15

16-18

25%

29

34

50

41

Chart 1: Motors 6-8kV by OEM

50%

70

77

113

77

75%

149

172

239

151

90%

288

376

469

292

Chart 2 below depicts the 25th, 50th, 75th, 90th and 95th percentiles for all manufacturers based on date of winding installation (500 kVA) cast-coil transformers (stand-alone or unit substation types) are generally applied (in lieu of open-wound or encapsulated types) where additional strength and protection is required. These units are intended for harsh environments and/or outdoor applications and are applied for their superior short-circuit strength and short-duration overloads as are typically experienced in industrial process applications. One noted disadvantage when applying or using a cast-coil transformer is that the coefficient of expansion of the epoxy insulation is less than that of the copper (or aluminum) windings. If the transformer is exposed to environmental or operating conditions that create cyclical expansion and contraction by heating and cooling the coils, this can lead to cracking of the cast-coil epoxy-resin insulation over time. General Electric published a service bulletin titled Test Application Data for Secondary Substation Transformers. In this test application guide, the insulation power-factor test is listed as an optional test; however, it is noted that this test is useful for checking the condition of the insulation. This service guide identifies that

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Transformers Vol. 2 comparative measurements made at periodic (i.e., maintenance) intervals are useful in identifying potential problems rather than the absolute test value. Thus, GE is one manufacturer that readily acknowledges the value of using the insulation power-factor test trend data as a maintenance test. The American National Standards Institute (ANSI) publishes the ANSI/NETA MTS, Standard for Maintenance Testing Specifications for Electrical Power Equipment and Systems, 2015 edition. The ANSI/NETA MTS-2015 test specifications identify the insulation power-factor test as a standard (routine) test. Additionally, the specifications identify an insulation power-factor tip-up test as an option. Industry practice has established the value of performing this additional test when the standard insulation-power-factor test results are suspect. The industry body of knowledge referenced herein provides guidance on transformer testing by considering the type of insulation system: dry-type or liquid-filled. There is some distinction with respect to size. Transformers larger than 500 kVA (threephase) are generally considered significantly more critical to business operations. The standards make no distinction with respect to the test specifications based on the various types of dry-type insulation system designs such as cast coil, resibloc, vacuum-pressure impregnated (VPI), or vacuum-pressure encapsulated (VPE). Industry standards further guide the user toward good engineering judgment and apply reasonable economic justification based on additional factors such as reliability, criticality, environment, and service-aged conditions. Having data on the frequency and magnitude of through-faults experienced by a transformer are criteria that warrant consideration with respect to specifying more or less testing. In facilities and plant sites that have high available fault currents, and in situations where a transformer has been subjected to a through-fault, it is prudent to perform insulation power-factor testing to verify the insulation quality. Doble Engineering Company suggests the following as acceptable, stand-alone insulation-power-factor test values: Ventilated Dry-Type ●● CHL (high-to-low) 2 percent ●● CL (low-to-ground) 4 percent ●● CH (high-to-ground) 3 percent Epoxy Encapsulated Dry-Type ●● CHL 1 percent ●● CL 2 percent ●● CH 3 percent It is important to note that CL power factors as high as 8 percent have been noted in some manufacturers’ transformers, and these

levels may be considered acceptable. Thus, having trend data is very helpful in monitoring/identifying normal and degraded conditions. Literature published by electrical test instrument manufacturer Megger Group Ltd. provides the following insight: “Higher overall power-factor results may be expected on dry-type transformers; however, the majority of test results for PF are found to be below 2.0 percent, but can range up to 10 percent.” The test community universally recognizes applying the insulation power-factor test periodically for maintenance and using the trend-test data to validate the quality of dry-type transformer insulation as an established industry best practice. This practice is also recommended by ANSI/NETA as a routine maintenance test. The insulation power-factor tip-up test is an additional test recognized in the ANSI/NETA MTS-2015 industry standard. This test is performed to further clarify what the insulation power-factor test results may be indicating. When performed, this optional test is useful in evaluating and discriminating whether moisture or corona are present in the insulation system. To perform the tip-up test, the applied test voltage starts at about 1 kV and increases in intervals up to 10 kV or the line-to-ground rating of the winding insulation. If the insulation power-factor does not change as the test voltage is increased, moisture is suspected as a probable cause. If the insulation power-factor increases as the voltage is increased, carbonization of the insulation or ionization in voids is a probable cause.

CONCLUSION It is reasonable to perform the insulation power-factor test on dry-type transformers, including cast-coil designed units. The insulation power-factor test may add two to four hours to the testing scope; thus, it can be significant in the price of the work. It is important to understand how to prioritize the value of this test with customer economic expectations. In some aspects, this is akin to the mindset that transformers only need to be tested on the applied tap setting. However, turnto-turn winding shorts are found often enough to justify testing a transformer on all of its available tap positions, and time added for this testing is minimal. Understanding the value of the test, the added scope/cost, and when it may provide the best value to the customer are all things to consider when specifying testing for drytype cast coil transformers. Bruce Rockwell, P.E. has been Director of American Electrical Testing’s Engineering Division for the last nine years. He has over thirty years of business development, management, construction and engineering experience; specializing in the T&D utility sector. Bruce holds an MBA from Monmouth University and received his BSEE from New Jersey Institute of Technology. Bruce is a Certified Co-Generation Professional with the Association of Energy Engineers and a Continuing Education Instructor for the State of New Jersey.

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QA ELECTRICAL TESTING OF MEDIUMVOLTAGE GLOBAL VPI STATOR WINDINGS PowerTest 2015 Vicki Warren, Iris Power, Toronto, Ontario This research was initially done for presentation at the 2014 Electrical Apparatus Service Association (EASA) Conference in Boston, MA.1

INTRODUCTION If manufactured properly, large squirrel cage medium voltage global VPI stator windings in induction motors (greater than a few hundred horsepower) and synchronous motors typically enjoy 20 years or more of operation. However, if during the motor manufacturing process, the resin did not properly penetrate the tapes, failure may occur in just a few years due to premature aging. Premature failure can also occur as a result of installation errors, such as insufficient spacing or misapplication of surface coatings. [See Table 1] Failure Mechanism

Symptoms

Inadequate bonding

Partial discharge

Electrical slot discharge

Partial discharges, slot discharge, ozone

Semi-con/stress interface

Partial discharge, white powder, ozone

Detection Tests

This paper describes research done by EASA service shops on the effectiveness and practicality of using offline partial discharge combined with a dielectrics characteristic test to evaluate the consolidation of stator windings in medium voltage machines manufactured by GVPI. Advantages and disadvantages of each test and industrial standards will be described as appropriate. Please see the Reference section at the end of this paper for industry standards and recommendations regarding the use of the tests mentioned in this paper.

STATOR WINDING OFF-LINE TESTS For the best test results, the motor should be isolated from the power supply cables. If possible, the winding phases should be tested individually. There are four tests that are recommended by various standards for GVPI insulation systems: capacitance, dissipation factor, power factor, and offline partial discharge.

CAPACITANCE TESTING (EPRI LEMUG) Capacitance, tan ∆ , power factor, tip-up, partial discharge

Table 1: Stator Winding Failure Mechanisms 2 Traditional tests of insulation resistance, polarization index (IEEE 43) and the controlled DC high voltage test (IEEE 95) have been effective in evaluating certain aspects of global vacuum pressure impregnation (GVPI) stator windings; however, they have not proven adequate for determining whether or not the insulation system is well-consolidated. Recently there has been the development of an IEC standard (IEC 60034-27) that defines the test procedures for performing off-line partial discharge testing as part of quality assurance (QA) testing. In addition, globally there has been a move towards using a dielectrics characteristic test, either power factor or dissipation factor, as part of the QA testing for GVPI systems. Partial discharge tests have proven to be effective in locating isolated problems that could lead to failure; whereas, the dielectrics characteristic tests provide a more general condition assessment. Based on experience to date, both are needed to fully evaluate how well the winding is consolidated.

If some of the organic resin is displaced with a void that fills with air this changes the dielectric constant of the insulation system. Caution - the variability in capacitance of newer insulation systems is usually so subtle that unless the winding is severely deteriorated it is difficult to observe any changes. The capacitance can be measured at a low voltage and best done with a bridge that will eliminate the effect of the stray capacitance of the test supply. As the winding cures, there will likely be a notable decrease in the capacitance as the polarizing and conductive currents decrease. This decrease will be observable independent of changes in voltage, that is, across all voltage steps the capacitance should be lower.11 A variation on the capacitance test is the capacitance tip-up test, which is performed on complete windings or preferably individual winding phases, and measures the void content in the groundwall of the stator coils. Measurements shall be taken at 20% of the motor rated line-to-ground voltage (0.2E) and at the motor rated line-to ground voltage (1E).8 The tip-up is based on the fact that line-to-ground voltage, if there are voids in the groundwall insulation, the gas in the void ionizes to produce sufficiently high conductivity to short the void out. This reduces the effective thickness of the insulation producing an increase in capacitance between low and high line-to-ground

23

Transformers Vol. 2 voltage. One void would have no impact, but if there are excessive voids due to the inadequate resin impregnation or problems with the tape or bonding material in the insulation system, the change in capacitance would be noticeable.11 Normally this test is performed on each phase of a winding, when practical, with an accurate capacitance bridge. The capacitance Clv is measured at 0.2E where E is the rated line-to-ground voltage and Chv is measured at line to ground voltage which is 1E. The capacitance at low voltage is the capacitance of the insulation with the gaps of the voids; whereas, as at the higher voltage the voids have been shorted, so it is the capacitance of the insulation alone without gaps, which mean a smaller effective distance between the plates. Therefore, an increase in capacitance with voltage is an indication of internal voids. In the absence of voids, the capacitance will not change as the test voltage is increased. The capacitance tip-up is defined as:

DISSIPATION FACTOR (TAN ∆ )

(NEMA MG-1, IEEE 286, EPRI LEMUG, IEEE 56) Like the capacitance test, the dissipation factor (tan Δ) test also looks for any changes in the insulation system of the winding. When a 60-hertz voltage is impressed across the stator insulation, the total current that flows is similar to that of any capacitor. The total current has two components: a relatively large capacitive current (ic), which leads the voltage by 90°, and a smaller resistive current (ir) which is in phase with the voltage. In a perfect insulation system, there would be no resistive current (ir), as all of the current would be capacitive (ic). However, as with the capacitance test, if there are voids, then the dielectric characteristics of the insulation system will change. The dielectric of this simulated capacitor is the insulation system which is embedded between two electrodes: the high-voltage copper conductors and the stator iron core. The dissipation factor is the tangent of δ, the angle between the ir and ic, or the angle between the capacitive current and the total current (Figure 2).3

Δ

Fig. 1: Change of ∆C as a function of the relative volume of voids within the epoxy resin specimen 11 ΔC = (Chv – Clv)/Clv Uncured/moisture contamination ⇒Clv is high Delamination ⇒ ΔC increases with voltage The higher ΔC is, the more voids there are in the winding groundwall. Note that as shown in Figure 1, as the void volume increases, so does the ΔC percentage. For well bonded modern epoxy mica groundwall insulation, typically the ΔC is less than about 1%.8 It should be noted that if the coils have semi-conducting and grading voltage stress control layers, these influence the results of this test. At the higher voltage, the grading layers of silicon carbide material conduct to increase the effective surface area and thus the capacitance of the sections of winding being tested, and so may give a false indication of high void content. However, if the results are trended against time, an increase in ΔC may give a true indication of increased void content in the groundwall insulation.11

Fig. 2: Dielectric of a winding This test is normally done at voltage steps that increase from 0.2E (DFlow) to normal line-to-ground voltage, 1E (DFhigh), preferably on individual phases. The intention of the test is to observe the increase in real power loss due to the presence of voids in a delaminated insulation (Δ tan δ = DFhigh – DFlow). As with the capacitance test, increases as a function of voltage are due to partial discharge and the ionization of the gas in the voids of the insulation system.11 As the applied test voltage increases so will the partial discharge activity in the voids and thus an increase in resistive current (ir) or real power loss. The absolute value of the dissipation factor is also useful in determining the extent of curing in a new insulation system since uncured components have different dielectric characteristics from cured components. DF = tan δ = IR / IC Uncured/moisture ⇒ DFlow is high Delamination ⇒ Δ tan δ increases with voltage

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Transformers Vol. 2

Typically, the DFlow for epoxy mica windings is about 1 - 2% and the Δ tan δ is less than 1%. Trending the results against time makes the best use of this test. As with the Δ capacitance test, voltage stress coatings can lead to ambiguous results obtained at high voltage.8

POWER FACTOR (COS θ)

(NEMA MG-1, IEEE 56, EPRI LEMUG) Similar to the dissipation factor (tan δ) the power factor test is looking for any changes in the insulation system of the winding. The power factor is the cosine of θ, the angle between the applied voltage and the total current (Figure 2). The test is normally done at a specific applied voltage that makes it possible for comparing the results to other machines, 0.2E. This is a valuable test for determining the extent of curing in new coils or winding. Because the presence of the voltage stress control in a complete winding greatly affects the results, tests on complete windings can be ambiguous.3 The tip-up test (Δ cos θ) is done at two voltages, one below the inception of partial discharge activity (PDIV), 20% of lineto-ground voltage, 0.2E (PFlow), and one at 100% line-to-ground voltage, 1E (PFhigh), preferably on individual phases. As with the Δ tan δ test, the difference in the power factors at these two voltages can be attributed to the energy loss due to partial discharges. PF = cos θ = mW / mVA Uncured/moisture ⇒ PFlow is high Delamination ⇒ Δ cos θ increases with voltage Typically, the PFlow for epoxy mica windings is less than about 0.5% and the Δ cos θ is 0.5%, though many suggest the acceptance levels should be the same as for dissipation factor, that is, 1-2% for 0.2E values and 1% for tip-up. As with the capacitance tip-up test, the results of this test are influenced by the presence of voltage stress coatings on the coils, since at high line-to-ground voltage currents flow through it to produce additional power losses. Because this test method measures total energy it is only sensitive to how widespread the PD is and not how close the winding is to failure (worst spot).

OFF-LINE PARTIAL DISCHARGE TEST (IEEE 1434-2000, IEEE 56-2012, IEC 60034-27-2 and EPRI LEMUG)

Partial discharges (PD) are small electrical sparks which occur in stator windings rated 3.3 kV or higher. PD is non-existent or negligible in well-made stator windings that are in good condition. However, if the stator winding insulation system was poorly made, then PD will occur. A PD test directly measures the pulse currents resulting from PD within a winding. Each PD produces a current pulse that has high frequency components to the hundreds of megahertz. Any device sensitive to high frequencies can detect the PD pulse currents. In a PD test on complete windings, the most common means of detecting the PD

currents is to use a high voltage capacitor connected to the stator terminal. Typical capacitances are 80 to 1000 pF. The capacitor is high impedance to the high AC current in the stator, while being very low impedance to the high frequency PD pulse currents. The output of the high voltage capacitor drives a resistive load. The PD pulse current that passes through the capacitor will create a voltage pulse across the resistor, which can be displayed on an oscilloscope, frequency spectrum analyzer, or other display device. The key measurement in a PD test is the peak PD magnitude Qm, i.e. the magnitude of the highest PD pulse, since this is proportional to the largest defect in the stator insulation. Tests are usually taken at increasing voltage steps starting at 0.2E to line-to-ground voltage (1E), preferably on individual phases. Measurements include:7, 10 ●● the voltage at which partial discharge starts, or the inception voltage (PDIV), ●● the voltage at which partial discharge stops, or the extinction voltage (PDEV), and ●● the largest repeatedly occurring PD magnitude at rated voltage Both the PDIV and the PDEV should be above 50% of line-toground voltage, or higher than 0.5E.8, 9

CASE STUDIES Using these tests and acceptance values, several motors were tested at various stages. Tests were done using two different sets of test instruments: ●● Using a PDTech DeltaMaxx™ to measure capacitance, dissipation factor and partial discharge ●● Using a Biddle® power factor/capacitance test instrument along with an Iris Power HF/LF partial discharge test Please be advised that when testing partial discharge, the measuring bandwidth of the test configuration influences results, so standard acceptance values for PD magnitudes are not possible. However, comparison among results using a similar test configuration is possible.

Case Study 1: Coil Resin Impregnation 4kV A single coil 4kV was tested at various stages of the resin impregnation process from before (green) to partial to full impregnation.

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Transformers Vol. 2

●● PDIV: the PDIV was higher than standard recommendation of 0.5E ●● PD max: there is no standard; however, the patterns were typical of internal voids and elevated when compared to the PD instrument manufacturers database.

Case Study 3: Rewound Winding 4kV A 4kV winding tested “as-is” state before a rewind and then after the rewind. Fully penetrated

In the table above, the pink refers to values that would be of great concern, while the yellow values are marginally acceptable and the green values are within expected limits. ●● Dissipation Factor (DF): decreases to between 0.01 and 0.02 as the quantity of resin is increased. The slightly elevated tip-up may be an issue. ●● Capacitance Tip-Up: since this is primarily testing for curing, then it makes sense that the partial (wet) state would have the highest activity along with the elevated DF values. Note that after full impregnation and curing, the values were significantly less than 1%. The increase in capacitance at 0.2E is unusual (see PD Max below). ●● PDIV: in all cases the PDIV was higher than standard recommendation of 0.5E ●● PD max: this was puzzling in that the magnitude of the measurable PD increased with impregnation. It is hypothesized that before resin impregnation the voids were too large to have detectable PD, so the effective thickness of the groundwall was minimal. Void shape and pattern as shown below are typical for small internal voids with the clusters within the first and third quadrants of the AC cycle as shown.

●● Dissipation Factor (DF): decreases after rewinding to levels almost between 0.01 and 0.02; while the tip-up decreases as well it is still slightly higher than the standard recommendation of less than 1%. ●● Capacitance: Behaved as expected with the lower capacitance in the rewound motor and a tip-up less than 1%. ●● PDIV: in all cases the PDIV was higher than standard recommendation of 0.5E ●● PD max: the decrease in PD activity is expected in a new winding with minimal PD activity.

Before

After

Case Study 4: Reconditioned Winding 12kv A 12.5kV winding was tested before and after reconditioning.

Case Study 2: Reconditioned Winding 4kV A reconditioned 4kV motor was tested.

●● Power Factor (PF): was within range ●● Power Factor Tip-up: was outside of standard recommendation of 0.5% which suggests moderate internal voids ●● Capacitance tip-up: was within range

●● Dissipation Factor (DF): decreases after reconditioning to levels between 0.01 and 0.02. ●● DF Tip-up: both before and after the DF tip-up were above the standard recommendation which suggests noticeable internal voids supported by the low PDEV.

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●● Capacitance: Behaved as expected with minimal change in the values, but still elevated tip-up values suggesting internal voids. ●● PDIV/PDEV: after reconditioning the PDIV was higher than the standard recommendation of 0.5E; however, the PDEV though better was still lower that acceptable by standard ●● PD max: the decrease in PD activity is likely due to the cleaning and re-varnishing that reduced surface PD activity. The PD patterns are classic and considered very high from the PD instrument manufacturer.

Before

REFERENCES 1

“ Condition Assessment of Stator Windings in Medium Voltage GVPI Machines”, Electrical Apparatus Service Association (EASA) Conference, Boston, MA, 2014.

2

 .C. Stone et al, “Electrical Insulation for Rotating Machines: G design, evaluation, aging, testing and repair”, IEEE Press-Wiley, 2004

3

 uarte, E. “Power Factor Testing of Stator Winding InsulaD tion” http://www.scribd.com/doc/83509152/Power-FactorTesting-of-Stator-Winding-Insulation (cited 9 April 2014)

4

 EMA Standard Publication No. MG 1-2006 Motors and GenN erators

5

ANSI Std. C50 41-1982, American National Standard for Polyphase Induction Motors for Power Generating Stations

6

IEEE 286-2000 Recommended Practice for Measurement of Power-Factor Tip-Up of Rotating Machinery Stator Coil Insulation

7

IEEE P1434-2010, Guide to the Measurement of Partial Discharges in Rotating Machinery

8

 PRI LEMUG Report 1000897 (Dec. 2000) Repair and ReE conditioning Specification for AC Squirrel-Cage Motors with Voltage Ratings of 2.3 - 13.2 kV.

9

IEEE 56-2012 (Draft) Guide for Insulation Maintenance of Large Alternating-Current Rotating Machinery (10,000 kVA and Larger)

After

PD tests using the same test configuration were taken while the machine was off-line and on-line. The results show activity originating around the zero crossings of the line-to-ground cycle with a “rabbit ears” pattern. PD of this magnitude and pattern are indicative of deterioration of the voltage stress coatings, and as such would not be “fixed” with cleaning and re-varnishing.

Off-Line

On-Line

SUMMARY Though it is premature to establish acceptance criteria for the capacitance results at 0.2E or the PD Max values at 1E, it is obvious based on these case studies that these five (5) tests in combination provide valuable information about the quality of a GVPI insulation system before and after refurbishment or rewind. Each test evaluates a different aspect of the insulation, so it requires all five for a full evaluation: ●● DF or PF at 0.2E – curing state (