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Solidaris LLC 1700 Rockville Pike, #535 Rockville, MD. US

LM6000 Gas Turbine Generator Set

Maintenance Course Presented by: S&W Energy Solutions, Inc.

September, 2012 Rev. 0

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Disclaimer: This document is intended for training use only. It is not intended to cover all possible variations in equipment or to provide for specific problems that may arise. Technical drawings and descriptions herein are intended to illustrate conceptual examples and do not necessarily represent as-supplied system details. System users are advised to refer to drawings of current release when conducting troubleshooting, maintenance procedures, or other activities requiring system information. Solidaris LLC advises that plant personnel read this training manual and the Operation & Maintenance Manual to become familiar with the generator package, its auxiliary equipment and its operation. This manual is not a replacement for experience and judgment. The final responsibility for proper, safe operation and maintenance of the generator package lies with the Owners and Operators.

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TABLE OF CONTENTS Section 6

Sections 1 - 5 for REVIEW purposes only. Covered under LM6000 FAM/BOC Course

06A - Maintenance Administration 06B - Maintenance Checks Periodicity 06C - Equipment Testing 06D - Engine Checks 06E - Generator Checks - Brush Section 7 – Borescope Section 8 08A - Level 1 and Level 2 Work Packages 08B – ICM Interim Letter

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SECTION 6A MAINTENANCE ADMINISTRATION

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MAINTENANCE MANAGEMENT SYSTEMS The primary objective of the Maintenance Systems is to manage maintenance and maintenance support in a way that will ensure maximum equipment operational readiness. There are basically two sub-systems that make up standard maintenance systems. They are:  Planned Maintenance System  Maintenance Data System

Planned Maintenance System (PMS) The planned maintenance system is an overall management tool that provides a simple and efficient way in which basic maintenance on all equipment can be planned, scheduled, controlled, and performed. 1. Define the minimum planned maintenance required to schedule and control maintenance work packages. 2. Provide for the detection and prevention of impending casualties. 3. Forecast and plan manpower and material requirements. 4. Plan and schedule maintenance task. 5. Estimate and evaluate material readiness. 6. Detect areas requiring additional or improved personnel training and improved maintenance techniques or attention. 7. Provide increased readiness of the plant. Benefits Planned Maintenance System As mentioned before, the Planned Maintenance System is a management tool. By using a well-established program, the Maintenance Department and Plant Managers can readily determine the status of the plant and overall reliability is intensified. In addition: 1. Preventive maintenance reduces the need for major corrective maintenance, increases economy, and saves the cost of repairs. 2. Better records since it provides additional useful data to the maintenance manager. 3. System assists in the prevention of unexpected changes in employee schedules. This reduces frustrating breakdowns and irregular hours of work.

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MAINTENANCE INFORMATION SYSTEMS Overview A maintenance information system is a necessary part of a good maintenance program. Such a system makes the maintenance program more effective and reduces its cost in the long run. A suitable system allows the maintenance manager to gather data to support maintenance decisions. It includes equipment failure data that may be fed back to designers or manufacturers, used for process hazard evaluation, or sent to the purchasing department to support changes to specifications or to support the selection or avoidance of particular vendors or equipment types. The maintenance information system is also a valuable resource for the planning department to use when preparing job packages for future maintenance work. The maintenance information system provides: 1. An easily retrievable historical record for each major piece of equipment or group of similar equipment. This record should include the original specification information, manufacturer, a history of operation time and conditions, and a record of inspection results and of all maintenance performed. 2. Equipment inspection and service schedules that specify the inspection and service scope and standards. The schedule should indicate which safety precautions apply and which permits are required during each activity. When fire protection equipment or systems are involved, proper backup procedures should be required. 3. A persistent follow-up or tracking system to ensure that proper inspection and maintenance service are being performed according to schedule. 4. An equipment repair and maintenance task priority assignment system that automatically increases the priority of deferred jobs. 5. Specifications for special replacement parts and materials for individual pieces of equipment so that proper parts and materials are used during maintenance procedures. A list of qualified suppliers for these items should be maintained. Management of change procedures should be followed before any substitutions are authorized. 6. An inventory of spare parts and an inventory control system. The control system should include written procedures for proper storage of large, complex or sensitive parts such as turbine rotors, electric motors or coils, or electronic modules. 7. Programs to analyze the effectiveness and cost of inspection and maintenance procedures. 8. Written notification to management and other affected departments so they will be promptly alerted when critical or safety-related components and systems are out of service for maintenance or any other reason.

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In most organizations, the maintenance information system uses computers to assist in program management. With the present state of the technology, there is no reason that even small organizations cannot benefit from the relatively low-cost computer equipment and maintenance management software available.

Maintenance Data System (MDS) The Maintenance Data System is exactly what it implies. The system works to collect maintenance data and to store it for future use. The data system may be either computer based or hard copy paper. From the MDS come the current plant maintenance tasks and scheduled future maintenance periods. The key forms (Data) listed below are the minimum required for a functional system. 1. Maintenance Action Form (MAF) is used by maintenance personnel to report deferred maintenance actions and completed maintenance actions (including those previously deferred). This form also allows the entry of screening and planning information for management and control of intermediate maintenance activity workloads. a. Reporting of completed maintenance/repair tasks b. Reporting of maintenance or repair tasks that are unable to be completed due to operational restrictions, insufficient training, depot level requirements, or shortage of required material. c. Reports spare part usage. d. Reports man-hours utilized 2. Deferred Maintenance Report (DMR) lists deferred maintenance and alterations which have been identified through Maintenance Action Form (MAF) reporting. The purpose of the DMR is to provide plant maintenance managers with a consolidated listing of deferred corrective maintenance/repairs so they can manage and schedule its accomplishment. a. Provides managers with critical information to assist in scheduling future maintenance periods. b. Provides managers a listing to assist in funding and scheduling of outside depot level assistance required to complete tasking. c. Allows for critical maintenance/repair parts ordering and tracking. d. Allows for scheduling maintenance department employees to meet maintenance-tasking requirements. 3. Parts Report is a listing of parts utilized for repair and maintenance. a. Provides a list for re-ordering expended items b. Provides managers with a method to ensure high failure or commonly used parts are on hand. c. Assists managers in projecting maintenance budget.

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The screen prints on the following pages are from an off-the-shelf maintenance program that is available in numerous formats and range from simplified too extensive tracking program. These programs can be arranged to meet the requirements of the customers utilizing them.

Work Request Form, Operators to Maintenance Department

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Maintenance Work Order Produced By The Program

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Parts Tracking

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OPERATOR EVENT LOGS Operating Records and Reports Operations records contain a narrative of the plant status, and of all events required to reconstruct a history of operations. In this context, logs are defined as a narrative sequence of events or functions performed by the operations staff. Operation logs are established to record the data necessary to provide a history of plant operations. The scope, type, and amount of data required by management is entered into the logs, including documentation of actions taken, activities completed, and data necessary to reconstruct events. Logs are reviewed to insure they are adequately maintained and that operations personnel are aware of the information in the logs. Operating records are not intended to replace frequent inspections of operating machinery by supervisory personnel and are not to be trusted implicitly to provide warning of impending casualties. Personnel who maintain operating records must be properly indoctrinated. They must be trained to correctly obtain, interpret, and record data, and to report any abnormal conditions noted. The plant manager’s directives specify which operating records will be maintained and prescribe the forms to be used. The Operations Manager may require additional operating records when (all factors considered—including the burden of added paperwork) it is deems necessary when no standard record forms are provided. Completed records must be stowed where they will be properly preserved, and in such a manner as to ensure that any one of the records can be easily located. The Plant Supervisor should establish the time period that logs will be retained on-site.

General Log Construction Information to be recorded All information pertaining to the safe and efficient operation of the plant is recorded in the operations logbooks. To aid in reconstructing events, as much information as possible is logged during emergencies and abnormal or unexpected events. Timeliness of Recordings 1. Information is entered promptly or as soon as reasonably possible to prevent inaccuracies. 2. Log keeping does not take precedence over controlling and monitoring the plant.

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Minimum information required: 1. Machine modes (e.g. operations, shutdown, maintenance, system contents, etc.) 2. Changes in plant operating mode or condition 3. Record of critical data 4. Abnormal facility configurations 5. Status changes in safety-related or important equipment 6. Occurrences of reportable events 7. Initiation and completion of tests or studies 8. Security, Medical and Fire incidents 9. Shift relief’s and call-ins 10. Out-of-parameter readings from equipment logs should circled in red to draw attention and annotated in event log. 11. Equipment that is out-of-commission. (Tagged out) 12. Outside telecommunication discussions (Dispatch)

Legibility 1. All log entries must be legible, understandable, and made in pen of a color that can be photocopied. Corrections 1. Incorrect entries are scored with a single line and initialed. References to incorrect entries are made in the shift summary. Log Review 1. The designated supervisor reviews the operations logbook. 2. The supervisor has the responsibility for filing and storing the logs for the expected life of the facility. Back-logs are available for review by Operators or staff returning after an absence. 3. On-coming shift supervisors to get overall picture of plant operation.

It should be noted that many of the equipment operating software programs would print out equipment parameters when commanded to do so. This is a practical solution for complete data dumps, but will not suffice as a stand-alone operator event log.

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INDIVIDUAL EQUIPMENT OPERATING LOG Equipment Logs Equipment logs may help to spot trouble in the equipment. They also aid in ensuring proper periodic maintenance and inspection are performed on the equipment. Logs may provide a means of self-protection when trouble occurs and the cause can be placed on an individual. A typical operating log may contain entries such as the following: 1. 2. 3. 4. 5. 6. 7. 8. 9.

Date and time of readings Ambient temperature Pressure and temperature readings Flow readings Differential pressure readings Visual Inspection Oil levels Operating hours Remarks column

These types of readings give a complete picture of the current and past operating conditions of the equipment or plant and can assist the maintenance department in keeping the equipment or plant at its maximum efficiency.

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Good judgment must always be used in analysis of service troubles and specific corrections should be followed whenever possible. One of the methods for determining when and what corrective measures are necessary on equipment or a plant which is not operating properly is to compare the pressures and temperatures of various parts of the system with corresponding readings taken in the past when the equipment or plant was operating properly under similar heat load and circulating water temperature conditions.

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EQUIPMENT HISTORY LOGS History logs contain entries of when, what, and who performed periodic maintenance and inspections on major pieces of equipment. It also allows for annotation for implementation of technical directives. Such logs help ensure that the equipment or plant is well maintained and that the life expectancy of the equipment or plant is fully used. Equipment history log entries may include the following: 1. Date/type of maintenance. 2. Date/type of inspection. 3. History of major component change out. 4. What was done to equipment? 5. Who did the work? 6. Technical directive incorporated. It is important to compare operating log readings of the equipment before and after the maintenance was completed to ensure maintenance was accomplished properly, and that it had no ill effects on the equipment or plant. Conduct Initial Performance Test (Keep logs & records)

Conduct employee On the Job Training (OJT)

Continually assess systems operational parameters

Maintain equipment/repair IAW vendor documentation

Analyze data, review equipment material condition, submit recommendations to vendors for improvements and request tech assist as required

Document discrepancies corrected and deferred maintenance

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Package Maintenance Levels Normally overall package maintenance is divided into three basic levels according to shop capability. Normally, some combination of these defined maintenance levels will satisfy the requirements of each customer. On-Site (External) - Level I On-site external maintenance encompasses the following two categories of maintenance tasks: (1) Preventive (tasks that are scheduled on the basis of equipment run hours or calendar time), and (2) Corrective (tasks that are unscheduled and accomplished as a result of a problem). The work scopes for these tasks cover all work on the exterior of installed equipment plus scheduled inspections, turbine compressor cleaning (water wash), turbine engine changeout, and changeout of components of driven equipment. Off-Site (Medium Shop Repair) - Level II This maintenance level includes complete teardown and rebuilding of the turbine engine by subassemblies. Replacement of major subassemblies is within the capability of this maintenance level. Off-Site (Extensive Shop Repair) - Level III Level III off-site repair includes all levels of maintenance, plus complete repair of a turbine engine or drive equipment parts. A test cell is required for a Level III facility.

Maintenance Schedule Normal maintenance of each GTG set during the initial 3 years of operation will require only a weekly visual inspection of turbine and turbine-driven equipment exteriors. None of these inspections or tasks requires equipment removal or disassembly. The weekly inspection will require approximately 1 hour by one man and can be performed with the unit operating. The scheduled maintenance tasks are recommended at 6-month and 12-month intervals and can be performed in one 8-hour shift, requiring approximately 16 man-hours for the set of tasks on the turbine engine.

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MAINTENANCE WORK PACKAGE DEVELOPMENT Develop a plant concurrent Maintenance Work Package that includes all major maintenance actions such as Planned Maintenance System (PMS), gas turbine maintenance work packages, electronic calibrations, repairs, alterations, and testing to be conducted by plant’s maintenance department during the maintenance periods, as applicable. Establish a strategy for calibration of gages, instruments, and tools based on maintenance requirements. Identify all industrial activity, providing production and testing support equipment needed to accomplish work, or to re-certify systems following work. Identify this equipment to the industrial activity prior to the start of the maintenance period. This support equipment includes the following, as applicable: 1. System certification to proper authorities. (i.e. Fire marshal, insurance agents) 2. System hydrostatic test equipment. 3. Calibration equipment. 4. Special tools. (i.e. Borescope, turbine tools) 5. Welding certifications. PMS development will take a considerable amount of time, attention to detail and devotion to assemble a complete listing of maintenance work packages. All turbine support systems, balance of plant equipment vendor documentation needs to be reviewed and appropriate work packages added to the program. There are various sources listing maintenance checks that require to be performed. They are as listed: 1. Engine Maintenance/Repair Work Packages a. LM6000PC GEK 105059 b. LM6000PD GEK 105061 c. LM2500+ Marine GEK 105163 d. LM2500+ SAC GEK 105054 e. LM2500+ DLE GEK 105048 f. LM2500 GEK 97310 2. Vendor Documentation 3. Experience 4. GE LM Series Maintenance Videotapes

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MAINTENANCE AND REPAIR RESPONSIBILITIES As discussed previously, in order to fulfill maintenance and repair responsibilities along with administrative and supervisory responsibilities planning must be done ahead of time. Determine all the work that must be done and prepare a schedule to ensure that it is done. The schedule must be flexible enough to allow unexpected maintenance and repair work to be done whenever the need for such work arises. Review the Maintenance Data System (MDS); it will make your planning and scheduling considerably easier.

Materials and Repair Parts The responsibility for maintaining adequate stocks of repair parts and repair materials belongs at least as much to you as it does to the supply department. The duties of the supply department are to procure, receive, stow, issue, and account for the support of the plant. However, the supply department is not the prime user of repair parts and repair materials; the initiative for maintaining adequate stocks of repair materials, parts, and equipment must come from the personnel who are going to use such items. Namely the maintenance department Identification of Repair Parts and Materials 1. Identification of parts and materials is not usually a great problem when you are dealing with equipment you work on daily; but it may present problems when you are conducting repair work on equipment not normally tended. 2. The materials and repair parts to be used are specified for many repair jobs but not for all. Most equipment will have an Illustrated Parts Breakdown The fact that materials and repair parts are not specified in the instructions accompanying a job does not mean that you are free to use your own judgment in selecting parts and materials to accomplish a job. Instead, it usually means that you must know where to look for information on the type of material or repair parts needed, then locate and requisition them in order to complete the assigned job. When you must make the decision yourself, select materials on the basis of the service conditions they must withstand. Operating pressure and operating temperature are primary considerations in selecting materials and parts for most equipment repair work.

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There are several sources of information that will be useful to you in identifying the equipment and/or the repair parts needed. They include: 1. Operation & Maintenance Manual a. Package O&M b. Engine GEK Manual c. Engine Illustrated Parts Breakdown (IPB) d. Manufacturer’s technical manuals e. Plans, blueprints, and other drawings. 2. Nameplates on the equipment 3. Vendor Information a. Web based internet sites b. Vendor Customer Representatives 4. Gas Turbine Serial Number a. This will identify what upgrades are installed.

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REFERENCE MATERIAL

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PACKAGE OPERATION & MAINTENANCE MANUAL

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Purpose of O&M Manual This manual set provides operation and maintenance information for the GE Aero Energy Products gas turbine-generator (GTG) set. The GTG set uses a General Electric (GE) LM Series turbine engine set to drive an air-cooled, alternating-current (AC) electrical generator. The set produces 11 kV, 3ø, 50-Hz power and contains the necessary control and auxiliary systems required for manual or automatic operation.

Scope of Manual This manual describes the GTG set. The manual supplies functional descriptions of mechanical and electrical systems. This information, when used with the site-specific engineering drawings and the vendor-supplied support documentation, will enable a reader to understand the function, operation, and maintenance of the GTG set. Familiarity with appropriate illustrations will be helpful in understanding the various systems and equipment. The operation data sheets, found in the Factory Test Procedure located in the Appendix of this manual, provide a convenient reference to alarm and shutdown set points. Information contained in this manual is presented in a logical progression by order of complexity. Following introductory material, the mechanical and structural aspects of the system are covered. The mechanical subsystems are then described, followed by a description of the electronic control system, generator electronic-excitation control, electro-mechanical monitoring and safety, and power control subsystems.

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TABLE OF CONTENTS Description

Chapter-Section

Title Page

Front Matter

I

Record of Ownership Record of Revisions List of Effective Pages Table of Contents Notice of Liability Introduction Warning and Caution Summary Site-specific Warnings and Cautions Product Bulletins Metric and SI Conversions

Front Matter Front Matter Front Matter Front Matter Front Matter Front Matter Front Matter Front Matter Front Matter Front Matter

I

General Information and Operating Instructions Introduction and Description of System Specifications Controls and Indicators Operation Operating Instructions: LM6000 Water Wash System (Pump System)

1 1-1 1-2 1-3 1-4

I

Maintenance General Information Servicing Troubleshooting Engine Alignment, Repairs, and Adjustments

2 2-1 2-2 2-3 2-4

I

Parts Spare Parts Recommended Spare Parts

3 3-1 3-2

I

Drawings Drawings Drawing Lists

4 4-1 4-2

I thru IV

Vendor Publications Vendor Information List of Vendor Publications

5 5-1 5-2

V thru XVI

Lubricant Specifications Fuel-Water Specifications Abbreviations and Acronyms Factory Test Procedures

Appendix A Appendix B Appendix C Appendix D

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Manual Arrangement This manual is divided into nine sections. Each section is specific in its purpose. Each section is listed and described below. Take time to familiarize yourself with the layout of the manual before continuing. Front Matter

This section contains information about the owner of the manual, revision history, a list of effective pages, the general table of contents, the introduction to the manual, how to use this manual, and a warnings and cautions summary.

General Information and Operating Instructions

This section is divided into four subsections, providing an introduction and a detailed description of each system that comprises the gas turbine-generator set, technical specifications for major components, illustrations and descriptions of the operating equipment and panel-mounted controls and indicators, and a general operations summary.

Maintenance

This section is divided into four subsections, providing general information on maintenance; maintenance definitions and concepts; maintenance schedules; servicing information; troubleshooting of the prime mover, generator, and ancillary equipment; and repairs and adjustments to the equipment.

Parts

This section contains recommendations on spare parts, lists of required and recommended spare parts, and points-of-contact to order or find information on parts for the gas turbine-generator set.

Drawings

This section contains a listing of mechanical and electrical drawings sent with the manual. The list contains the GE Aero Energy Products engineering document number, the revision level of the drawing, and the title of the drawing.

Vendor Publications

This section contains vendor publications that provide operation, maintenance, and parts information for the equipment and related components in the gas turbine-generator set. The publications include vendor material ranging from catalog data sheets to complete sets of operation and maintenance manuals and parts manuals.

Lubricant Specifications

The appendix contains the lubricant requirements necessary to operate and maintain the GTG set.

Fuel – Water Specifications

This section contains information and specifications of particular importance to the operator, such as fuel and water requirements for the engine.

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Abbreviations and Acronyms

This is a listing of abbreviations and acronyms commonly used in the power-generation field.

Factory Test Procedure

This section contains the published Factory Test Report as issued by GE Aero Energy Products. This report contains an equipment identification record, general information on the factory operational load test, test conditions, test instrumentation, data documenting the safety alarm and shutdown test, and a list of recorded data.

GE AEP F&ID Drawings, The O&M Volumes contains the drawings required to maintain and troubleshoot the system, equipment, and related components in the turbine-generator system. Drawings prepared by equipment manufacturers or vendors are provided in these manuals, and companion GE AEP drawings may be provided in this chapter.

Drawing Types and Their Uses Two types of drawings have been identified in the following pages. These drawings, mechanical and electrical, are the documents that define the configuration of your unit. Mechanical and electrical drawings provided have been carefully detailed to include all the engineering and design data required to fully understand and operate your LM Series GTG set. The mechanical drawings illustrate subsystem flows, both off-skid and on-skid. The electrical drawings illustrate interconnection of the devices identified on the mechanical drawings and should be used in conjunction with the mechanical drawings. A letter has identified the revision level of each drawing produced by GE AEP. This letter will be found in the title block. NOTE

Questions regarding applicable revision levels should be referred to GE Aero Energy Products, Jacintoport Engineering, Document Control, or your project contact.

Mechanical Drawings The mechanical drawings included in this manual provide engineering-design and device set point data on the turbine-generator set and its subsystems. Refer to the expanded explanation of applicable drawing types that follows in this section. General Arrangement drawings, Flow and Instrument Diagrams, and Instrument Diagrams are defined in the expanded listing that follows.

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Mechanical Drawing Types General Arrangement Drawings

These drawings provide isometric, plan-and-elevation, and physical configuration data about major pieces of equipment, including skid interconnection-interface information and installation and footprint data. Data regarding the actual size and dimensions of major equipment may be found on these drawings. Related drawings have been identified on sheet 1 of each General Arrangement drawing.

Flow and Instrument Diagrams

These drawings define the flow characteristics, start permissives, and device set point and control-logic data. Flow (in gpm or scfm), filtration requirements, pressurelimiting, and shutdown responses are identified on these drawings. Together with the wiring and system wiring diagrams, these drawings define each system and its related components. Related drawings have been identified, as they were on the other drawings, on sheet 1 of each Flow and Instrument Diagram drawing.

Instrument Diagrams

These drawings identify protective devices which have been interlocked to the control system software and which respond to out-of-tolerance conditions by activating alarms and initiating system wide shutdowns as applicable. Related drawings have been identified, as they were on the other drawings, on sheet 1 of each Instrument Diagram drawing.

Electrical Drawings The electrical drawings included in this manual illustrate device interconnection and controlloop specifications used in the turbine-generator set and its subsystems. Refer to the expanded explanation of applicable drawing types that follows in this section. Interconnect Wiring Diagrams, One- and Three-Line Diagrams, Wiring Diagrams, and System Wiring Diagrams are defined in the expanded listing that follows. Electrical Drawing Types Interconnect Wiring Diagrams

These are a series of three drawings (typically the first drawings found in the section covering electrical drawings). The first of these drawings provides an overview to the interconnection of major equipment to the main skid and the turbine-control system. The two remaining drawings provide the detailed information required to interconnect subsystem devices to the control system and other ancillary items. Related drawings have been identified, as they were on the other drawings, on sheet 1 of each Interconnect Wiring Diagram drawing.

One- and Three-Line Diagrams

These two drawings define the operation of the GTG set as it has been configured for installation at your site. Your one-line drawing establishes the overall configuration of your unit and its interconnection to the utility or plant grid. Your three-line drawing further defines the interaction of the systems identified on the one-line drawing and establishes the manner in which devices—meters, switches, lamps, and the control system— interact and receive and transmit data. Also shown on these drawings are the system circuit breaker and the current and potential transformers. Related drawings have been identified, as they were on the other drawings, on sheet 1 of the One- and Three-Line Diagram drawings. These drawings show simplified wiring for terminal block–to–terminal block installation and interconnection of control devices. These are the first level of wiring diagrams and do not provide point-to-point wiring data. Point-to-point wiring data are presented on the System Wiring Diagrams. Related drawings have been identified, as

Wiring Diagrams

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they were on the other drawings, on sheet 1 of each Wiring Diagram drawing. System Wiring Diagrams

These drawings provide precise, detailed information regarding device interconnection to the terminal blocks and, from the terminal blocks, to the control system and the ancillary equipment that assists the control system in maintaining steady-state operation of the turbine generator. These drawings detail wiring connections by wire color, termination number, wire number, terminal block number, and associated device and applicable end termination in the control system. Related drawings have been identified, as they were on the other drawings, on sheet 1 of each System Wiring Diagram drawing.

Other Drawing Types Logic Flow Diagrams

These drawings define the machine logic that controls system devices. Each step in the logic of the specific system (e.g., fire suppression and gas detection or turbinecontrol system) is enumerated using standard logic-flow symbology.

Vendor Drawings

Some vendors of specialized control system and mechanical components have jobspecific drawings associated with each piece purchased for your unit. Other data from the applicable vendor may also be found in these sections.

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ENGINE GEK MANUALS  105059 Engine O&M  105060 Illustrated Parts Breakdown

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GEK 105059 – ENGINE OPERATION AND MAINTENANCE MANUAL

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ENGINE MAINTENANCE Engine GEK manuals have a series of work packages that are designed for maintenance, repair and inspection of the package prime mover. There is no package support included in this manual. Chapter 12 of the GEK manual defines the requirements and frequency for performing preventive maintenance checks, inspections, and servicing. Dry motoring procedures, generally associated with maintenance, are also provided, as are definitions of terms used to evaluate equipment condition and damage during inspections.

GEK Levels of Maintenance Level 1 - Corrective maintenance allows replacement of external parts, adjustments, and other work (preventive and corrective) up to and including removal and replacement of the entire engine. Level 2 - Corrective maintenance permits the replacement of major engine sections (modules) and the replacement or repair of certain internal parts. Level 2 maintenance is performed on-site on a non-installed engine or on an installed engine in the enclosure, as permitted by the enclosure design. Maintenance is performed with the engine horizontal. Level 3 - Preservation, Handling, Storage, and Balance of the gas turbine. Level 4 – Various inspections on the gas turbine

GEK General Checks and Inspections This section provides general guidelines, conditions, and definitions for conducting engine checks and inspections. Preventive maintenance and servicing inspections and checks are performed to reduce unscheduled shutdown time. If the frequency of inspection/service requires change, coordinate with the packager. Table 12-1 illustrates a sample of checks and service intervals.

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Preventative Maintenance and Servicing Checks

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Preventative Maintenance and Servicing Checks

Additional Preventative Maintenance and Servicing Checks from Svc Letter 6000-05-03 Sprint nozzle clean, flow and Every 25,000 hours of WP 1916 00 inspection at authorized repair source SPRINT operation High pressure compressor variable compressor vane bushing replacement

Every 12,500 hours

WP 1412 00

Additional Recommended Checks from Service Letter 6000-05-03 Starter carbon seal cleaning Annually WP 2813 D/E Sump drain interface cleaning Annually N/A (disconnect package drain to clean engine and package drain as required) Fuel nozzle (PA or PC). Clean, flow At hot section interval (PA & PC) WP1510, and inspect at authorized repair source WP1511, WP1512, WP1513, WP1514 Pg 6A-38

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Level 1 Maintenance Examples WP 0001 00 Numerical List of Support Equipment, Consumables, and Expendables WP 1110 00

Axial Inlet Centerbody Assembly Replacement

WP 1111 00

Low Pressure Compressor Inlet Temperature/Pressure (T2/P2) Sensor Replacement

WP 1112 00

Variable Inlet Guide Vane (VIGV) Actuator Replacement

WP 1112 01

Variable Inlet Guide Vane (VIGV) Actuator Replacement with Fixed Link

WP 3010 00

Gas Turbine in Enclosure Replacement

WP 3011 00

Preservation/Depreservation

WP 3012 00

Gas Turbine Maintenance Dolly Removal and Installation

WP 4010 00

Gas Turbine Inlet Inspection

WP 4011 00

External Engine Cleaning

WP 4012 00

Gas Turbine External Inspection (Visual)

WP 4013 00

Gas Turbine Exhaust System Inspection

WP 4014 00

Gas Turbine Water-Wash

Level 2 Maintenance Examples WP 2110 00 Variable Inlet Guide Vane (VIGV) Assembly Replacement SWP 2110 01

Inlet Frame Replacement

WP 2210 00

Low Pressure Compressor (LPC) Module Replacement

WP 2211 00

Low Pressure Compressor (LPC) Stage 0 Rotor Blades Replacement

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TROUBLESHOOTING Troubleshooting is part of the technician's job. Troubleshooting is fault isolation using logical, known troubleshooting techniques. The nature of troubleshooting is going to be first locating the faulty unit and from there, locating the faulty assembly, and the faulty component. The key to troubleshooting is following a logical sequence making measurements with test equipment using a vendor technical manual that has known parameters in it and isolating the fault. There are numerous technical documentations available to assist with the troubleshooting of the equipment. The following is examples of troubleshooting documentation for 1. LM Series Engines 2. Generator 3. Support Equipment

Troubleshooting For the LM Series Engines General troubleshooting procedures for the GTG set are contained in Volume I, Chapter 10 of the General Electric LM6000 Series On-Site Operation and Maintenance Manual, GEK 105059, located in Chapter 5 of this manual. This chapter includes two major segments: 1. Troubleshooting Reference Table 2. Troubleshooting Procedures.

Troubleshooting Reference Table The Troubleshooting Reference Table shows various problem events and system conditions, alarms, control actions, and the setpoints that trigger these alarms or control actions. These are grouped by major engine/facility systems. Each event also lists a numbered Troubleshooting Procedure (TS-) or a SPAM (See Packager’s Appropriate Manual) reference. At the end of the Troubleshooting Reference Table, items in the Miscellaneous category either (1) do not trigger an alarm or control action or (2) are a combination of conditions, some of which may or may not trigger an alarm or control action on their own, that must also be looked at in combination with others. Except where otherwise indicated, each event shown in this table is accompanied by an alarm, regardless of whether it is accompanied by a control action. Limits are shown in the alarm column for events resulting in an alarm only. Events that have both an alarm and an accompanying control action will show the limits in the appropriate action column and an X in the alarm column. In cases where one limit triggers an alarm only and a higher limit triggers both an alarm and control action, the limits for each will be shown in the appropriate Rev 0 06/26/2012

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columns. In any case that has no particular limits and is simply an either/or condition, the alarm and/or control action will be indicated by “X” in the appropriate columns.

Numbered Troubleshooting Procedures The numbered Troubleshooting Procedures (TS-1 through TS-32) are referred to in the Troubleshooting Reference column of the Troubleshooting Reference Table. These procedures show symptoms for each engine or facility condition, possible causes for each, the troubleshooting procedure to isolate the cause of the problem, and the recommended corrective action. Events or conditions in the Troubleshooting Reference Table that have only a SPAM reference are not discussed in the numbered troubleshooting procedures.

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Troubleshooting Reference Table

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Troubleshooting Reference Table Notes

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Numbered Troubleshooting Procedures

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GEK 105060 - ILLUSTRATED PARTS BREAKDOWN Introduction The Illustrated Parts Breakdown is an illustrated listing of the parts of the LM Series Gas Turbine Models designed, developed, and manufactured by the GE AeroDerivative Gas Turbines, Cincinnati, Ohio 45215. The Illustrated Parts Breakdown is intended to be used for requisitioning, storing, issuing, and identifying parts. Major sections, assemblies, subassemblies, and attaching parts are presented in an orderly sequence to provide both the detailed parts information and relationship of parts to assemblies. The listing shows Part Numbers, Description, Quantity. Items in the listings are keyed to those in the illustrations by common Index Numbers. Additional descriptive identifying data, references to higher and lower assemblies, specialized part and marking information, references to other publications, and GE Control Drawing Numbers are furnished within the nomenclature of the specified item.

Explanation of Parts Breakdown Figure and Index column: This column contains the Figure Number in which the part or assembly is shown, and the Index Number common to the illustration and to the listing. The Figure Number is separated from the Index Number by a hyphen. Both Figure Numbers and Index Numbers are in numerical sequence. When an illustration is changed, additional indexes are added between existing indexes by adding the preceding Index Number plus a letter of the alphabet such as –22A, -22B, etc.

Part Numbers Column and Description The Part Numbers column contains the part number assigned to each part in accordance with the Contract drawing Specification.

The Part Numbers Column Contains: 1. COM’L ITEMS: Commercial Items use the word COM’L in the Part Numbers column. Identifying information such as dimensions, size, material type, special features and commercial catalog numbers is listed in the description column. 2. NO NUMBER: Articles without part numbers are listed as “No Number” parts in the Part Numbers column. The Model Number (if any) and other descriptive data are given in the Description. 3. GENERAL ELECTRIC PART NUMBERS: Parts designed by the General Electric Company. Required explanations related to the General Electric Company parts are noted in the Description. Pg 6A-52

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FIG 21

VSV ACTUATOR REPLACEMENT

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NAMEPLATES DATA Nameplates on equipment supply information regarding the characteristics of the equipment. Nameplate data seldom, if ever, include the exact materials required for repairs; however, the information given on the characteristics of the equipment and on pressure and temperature limitations may provide useful clues for the selection of materials.

Typical Name Data Plate

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PRODUCT BULLETINS Product Bulletins are issued by GE Energy to inform customers of changes to and improvements in the gas turbine product. All Product Bulletins issued by GE Energy and cross-references to Product Bulletins are available from GE Energy. Bulletins will be mailed to the customer and are also available on the LM6000 Operator and Maintenance Manual (GEK 105059) CD-Rom.

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Excerpt of Service bulletin

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Interim – Interim Change Notice Interim Change Notices are changes to the manual that have yet to be incorporated but are still required actions.

Typical Interim Change Notice

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Letter – GE Letters (Product & Service) GE issues letters to make their customers aware of certain concerns, product specific or service specific, experienced by users that may be of interest to other users. Typically customer issues of minor importance.

Typical Product Letter

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Papers - Position Papers (LM Series, LM6000, IEC NEC TCP 50/60 Hz) A position paper is an essay that presents an opinion about an issue, typically that of the author or another specified entity. Position papers are used by GE to make public the official beliefs and recommendations of the group.

Typical White Paper

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New GEK Web Based Updated System

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VENDOR DOCUMENTATION

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Alternating-Current (Ac) Generator

Troubleshooting procedures for the generator are provided in the operation and maintenance manual located in the O&M manual.

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Ancillary Equipment Troubleshooting information for external systems of the GTG set is provided in vendor literature contained in the O&M manual. Information for repair for many of the subsystems and components of the GTG set are in the original equipment manufacturers’ literature located in the O&M. The following adjustments should be made as needed to maintain equipment in proper working order. 1.

Instruments and Indicators—Instruments and indicators may need to be calibrated more frequently than listed in the maintenance table, Ancillary Equipment Schedule, in Section 2 of the O&M manual.

2.

Transducers and Probes—Positioning and calibration of probes may need to occur if indications appear to fluctuate or vary from normal. Refer to GE AEP flow and instrument diagrams and the Factory Test Report for set points of mechanical and electrical sensing instruments.

3.

Pressure and Temperature Controllers—Adjustments may need to be made on pressure and temperature controllers. Refer to GE AEP flow and instrument diagrams contained in Chapter 4 for set points. Refer to O&M for vendor-supplied details of the various controllers.

4.

Equipment Alignment—Realignment of equipment may need to be performed to compensate for normal wear. Excessive vibration or noise will generally indicate when this should take place. Settling of the unit or foundation can adversely affect machinery alignment. Refer to vendor documentation in Chapter O&M manual for alignment tolerances of various equipment.

5.

Air Filtration System—The air filtration system is designed to operate for extended periods between maintenance intervals. The system is equipped with a differential pressure switch that will trip an alarm when the air filtration system restriction reaches the point that maintenance is required. Maintenance of the air filtration system shall be carried out in accordance with the instructions provided by the air filter manufacturer.

6.

Control System—The areas in the control system that require regular maintenance to ensure proper operation are the battery banks, with their attendant battery chargers; switches; transducers; senders; thermocouples; and other sensing devices that are employed to monitor the operation of the unit.

7.

Battery Banks—The batteries require periodic testing and replenishment of electrolytes, and inspection and cleaning of battery terminal connections and battery cases. The float-and-equalize voltage settings of battery chargers must also be checked and adjusted. Maintenance procedures and recommendations for direct current power systems are found in the battery and battery charger instruction manuals provided with the equipment.

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SECTION 6B MAINTENANCE CHECKS PERIODICITY

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INDEX OF MAINTENANCE CHECKS

Weekly Checks Monthly Checks Bimonthly Checks Quarterly Checks Semiannual Checks Annual Checks As Required Checks

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GEK GENERAL CHECKS AND INSPECTIONS This section provides general guidelines, conditions, and definitions for conducting engine checks and inspections. Preventive maintenance and servicing inspections and checks are performed to reduce unscheduled shutdown time. If the frequency of inspection/service requires change, coordinate with the packager.

WEEKLY GAS TURBINE ENGINE Component

Vendor & Part Number

Maintenance Frequency

Remarks

GT Assy

Inspect external engine components for security of installation

SYNTHETIC LUBE OIL Reservoir Level GEPPLP, 724977A

Weekly

Check oil reservoir level and check system for leaks

HYDRAULIC START SYSTEM Hydraulic Start NA Reservoir

Weekly

Check oil level and check system for leaks

Hydraulic Start System

Weekly (Recommended)

Inspect system piping, hoses and components for leakage and indication of damage.

(During Operation)

GENERATOR LUBE OIL Donaldson, Weekly HPK0300B0802NX (Recommended)



(During Operation)



Reservoir Level

Weekly

Check oil level and check system for leaks

Lubricating Oil

Weekly (Recommended)

Sample and visually inspect oil for water entrainment/emulsification.

AC Lube Oil Pump

Weekly (Recommended)

Check pump packing for leakage

Jacking Oil Discharge Oil Filter

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Inspect differential visual indicator during operation. Visually inspect gage pressure

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LIQUID FUEL SYSTEM & NOX WATER INJECTION Low Pressure Gear Box

Kobe/Milwaukee, 0657603

Weekly

☺Check oil level weekly when unit is at rest, and add oil required.

VENTILATION AND COMBUSTION SYSTEM Component Filter House

Vendor & Part Number

Maintenance Frequency

Remarks

Weekly (Recommended)

Record the filter resistance. Check that each filter is straight and square to its frame.

FIRE PROTECTION SYSTEM Optical Flame Detector

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Det-Tronics, Weekly X9800EQP (Recommended) (382A4669P0001)

Visually verify proper operation via LED

Maintenance Check Periodicity

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MONTHLY SYNTHETIC LUBE OIL Component Vendor & Part Number

Maintenance Frequency

Remarks

Oil System Plumbing

Monthly or 500 operating hours

Check oil plumbing line to and on engine for security, chafing and leaks. (Applicable sections of GEK WP4012 00)

Turbine Lube GEPPLP, Oil Air/Oil (701209) Separator

Monthly

Visually inspect fin/fan cooler for indication of external fin blockage. Clean as necessary.

Lubricating Oil

Monthly or 700 operating hours

☺Analyze sample of oil IAW GEK WP4016 00.

GEPPLP, Various

NA

GENERATOR LUBE OIL SYSTEM Lubricating Oil

Monthly or 700 operating hours (Recommended)

Sample and conduct lab spectroanalysis (In conjunction with GT lube oil sample)

VENTILATION AND COMBUSTION SYSTEM Filter House

Monthly (Recommended)

Inspect the filter media for signs of damage. Ensure that all conduits runs and junction boxes are drained of condensate and corrosion free.

FIRE PROTECTION SYSTEM Flexible Hose Kidde, 251821 (377A2245P0002)

Monthly

Check for loose fittings, damaged threads, rust, dirt, and frayed wire braid.

(Dry Line) Discharge Pressure Switch

Wilson Fire, WFPS/108 (382A6241P0001)

Monthly

Check for deformation, cracks, dirt, or other damage. Replace switch if damaged.

Electronic Discharge Kiddie Heads

Kidde, 872450 (377A2233P0001)

Monthly

Check for physical damage, deterioration, corrosion, and dirt.

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FIRE PROTECTION SYSTEM (Cont) Component

Vendor & Part Number

Maintenance Remarks Frequency

System Components

Various

Monthly

Inspect hazard area components

Cylinder

Kidde, 870269 (377A1188P0002)

Monthly

Check for leakage and physical damage.

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BI-MONTHLY GENERATOR LUBE OIL Component Vendor & Part Number

Maintenance Frequency

Generator Lube Oil AC Pump

2 Months or 500 ☺Ensure motor is lubricated. When hours lubricants are operated at elevated temperatures, the lubrication frequency should be increased. Over greasing can cause excessive bearing temperatures, lubricant and bearing failure.

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Maintenance Check Periodicity

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QUARTERLY SYNTHETIC LUBE OIL Component Vendor & Part Number

Maintenance Frequency

Turbine Lube GEPPLP, Oil Air/Oil (701209) Separator

3 Months or 2000 Stop the mist eliminator and drain Hours any accumulated oil. Replace the demister elements when a differential pressure of 1.7 psid is obtained or every year, whichever occurs first.

Turbine Lube GEPPLP, Oil Air/Oil (701210) Pre-Separator

3 Months or 2000 Stop the mist eliminator and drain Hours any accumulated oil. Replace the demister elements when a differential pressure of 1.7 psid is obtained or every year, whichever occurs first.

Air/Oil Seperator Fin/Fan Cooler

3 Months or 2000 Inspect heat exchanger for build Hours up of dirt and debris.

American Technology, 780-1812

Turbine Lube API Basco Oil Heat Exchanger

3 months (Recommended)

Remarks

Vent coolers to remove air or vapor accumulated in the system. (As apllicable)

HYDRAULIC START SYSTEM Hydraulic Starter Motor

GE Motors, 5KE445SFC121 (377A1012P0001)

Hydraulic Pump SOV Actuated

Sauer-Sundstrand, 3 Months or 2000 Check hoses for damage or aging. 90R130KC1NN80L Hours Replace if defective. 4F1F03 GBA36421024 (382A9258P0001)

Oil Tank Fill Cap

Magnaloy, FB-A008X

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3 Months or 2000 Monitor oil temperature. Hours Relubricate bearing (see placard with precise instructions at the pressure-feed lubrication nipples). Renew grease in the bearings.

3 Months or 2000 Replace or clean filler/ breather Hours filter routinely.

Maintenance Check Periodicity

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HYDRAULIC START SYSTEM Component

Vendor & Part Number

Maintenance Frequency

Remarks

Low Pressure Return Filter, Case Drain Filters, Charge Pump Filter

Donaldson, HMK 25-04

3 Months or 2000 Check visual indicators on both Hours sides of filters. If indicator is activated, replace filter element. Replace filter on a regular basis and replace filter once a year regardless of visual indicator indication.

Hydraulic Pump Suction Strainer

Marvel, 450M200

3 Months or 2000 Check and clean when suction Hours PDT alarm activates. Remove and clean during the tank and heater inspection.

Hose Assemblies

GEPLPP, Various

3 Months or 2000 Check hoses for damage or aging. Hours Replace if defective.

GENERATOR LUBE OIL Generator Reservoir Filler Strainer

Vickers, 3E8501-01

3 Months or 2000 Check for clogging. Remove access Hours cover and clean strainer.

Hose Assemblies

GEPPLP, Various

3 Months or 2000 Check hoses for damage or aging. Hours Replace if defective.

Generator Lube Oil Heat Exchanger

API Basco

3 months (Recommended)

Vent coolers to remove air or vapor accumulated in the system. (As Applicable)

LIQUID FUEL SYSTEM & NOX WATER INJECTION Fuel Gas Strainer

Mueller Steam, 377A7957P0001

3 Months or 2000 Hours

Remove access cover and clean strainer. Replace o-ring if necessary and re-install strainer and access cover.

Hose Assemblies

GEPLPP, Various

3 Months or 2000 Hours

Check hoses for damage or aging. Replace if defective.

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LIQUID FUEL SYSTEM & NOX WATER INJECTION (CONT) Component

Vendor & Part Number

Maintenance Frequency

FCV-2005 Exhaust Collector Drain Flow Control Valve

Fisher, 3 Months or FSEZ2000 hours 405/STEM15,FS65 5-9/*3&8T (382A6218P0001)

GE Motors, MOT-2186/ 5KE444SFC121 2194 Electric Motor (377A1010P0001) - Water Inject Pump

3 Months or 2000 Hours

Remarks Verify proper operation. Check valve stem for leakage. If valve stem is damaged or fails, replace valve.

☺Monitor oil temperature. Relubricate bearing (see placard with precise instructions at the pressure-feed lubrication nipples). Renew grease in the bearings.

VENTILATION AND COMBUSTION SYSTEM Hose Assemblies

GEPPLP, Various

3 Months or 2000 Hours

Check hoses for damage or aging. Replace if defective.

Turbine AWV INC., Enclosure Fire 33389 Protection (382A5531P0001) Damper 50 1/2" X 53"

3 Months or 2000 Hours

Check for cleanliness and freedom from foreign matter that would impede normal movement, and seating of blades and seals on a scheduled basis.

Turbine Enclosure Ventilation Fan - 66" Diameter Centaxial Fan Assembly and Motor

Fan: TCF Aerovent, C-31403 (66” dia) GE Motor:

3 Months or 2000 Hours

☺Check for cleanliness and freedom from foreign matter. Verify belt status. Check tightness of all screws and bolts and tighten if necessary.

Generator Enclosure Ventilation Fan (63 3/4" dia.) Vaneaxial Fan Assembly and Motor

Fan: TCF Aerovent, C-31399-00 GE Motor:

3 Months or 2000 Hours

☺Check for cleanliness and freedom from foreign matter. Verify belt status. Check tightness of all screws and bolts and tighten if necessary.

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Motor Dual Rating 125/104 hp, 60/50 hz, 460/380 vac 3 Phase, 1780/1475 rpm 444T Frame, explosion proof

Motor Dual Rating 100/83 hp, 60/50 hz, 460/380 vac 3 Phase, 1800/1500 rpm 405T Frame, explosion proof

Maintenance Check Periodicity

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VENTILATION AND COMBUSTION SYSTEM (CONT) Component Vendor & Part Number

Maintenance Frequency

Remarks

Generator Ventilation Back Draft Damper

AWV INC.,

3 Months or 2000 Hours

Check for cleanliness and freedom from foreign matter that would impede normal movement, and seating of blades and seals on a scheduled basis.

Air Filter Combustion and Ventilation

GEPPLP, (Legged Air Filter) (733200)

3 Months or 2000 Hours

Check to ensure that the operational and structural members are maintaining their function. Look at the internal surfaces of the clean air sections and its ductwork while the turbine is shutdown and no air flows through the system. Check for leakage. Dust streaks indicate a leak at one of the seams. Locate the leak and caulk as necessary to reseal any openings. Check pneumatic system thoroughly.

Generator Exhaust Damper

AWV, 24475

3 Months or 2000 Hours

Check for cleanliness and freedom from foreign matter that would impede normal movement, and seating of blades and seals on a scheduled basis.

VBV Drain GEPPLP, Strainer - 40 (J05017) Mesh 1"-150# Flat

3 Months or 2000 Hours

Check and clean when necessary.

Inlet Volute GEPPLP, Drain Strainer (J05021) - 40 Mesh 1"150# Flat

3 Months or 2000 Hours

Check and clean when necessary.

WATER WASH SYSTEM Hose Assemblies

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GEPPLP, Various

3 Months or 2000 Hours

Maintenance Check Periodicity

Check hoses for damage or aging. Replace if defective.

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SPRINT SYSTEM Component

Vendor & Part Number

Maintenance Frequency

Remarks

Hose Assemblies

GEPPLP, Various

3 Months or 2000 Check hoses for damage or aging. Hours Replace if defective.

Skid Mounted Y-Strainer 2"-150#RF

Mueller Steam, 761-SS(2")

3 Months or 2000 Check for pressure loss across Hours strainer. If pressure loss or clogging is observed, remove access cover and clean strainer. Replace o-ring if necessary and re-install strainer and access cover.

FIRE PROTECTION SYSTEM Combustible Gas Detector

Wilson Fire, WFDCUEX-1 (382A6223P0001)

3 months

☺Calibrate sensor and DCU.

MEDENSHIA GENERATOR Shaft Earthing Brush

3 Months or 2000  Hours 

Rotor Earth Fault Detector

3 Months or 2000 Refer to vendor documentation Hours

Rev 1 06/26/2012

Maintenance Check Periodicity

Check that brush is free in holder. Change when it becomes to 15mm length. Original length is 30 mm.

Pg 6B-13

LM6000 GENERATOR PACKAGE

MAINTENANCE COURSE

SEMI-ANNUAL GAS TURBINE ASSEMBLY Component

Vendor & Part Number

Maintenance Frequency

Remarks

GT Assy

Borescope inspection Variable Stator Vane Rig Check VBV Door Rig Check Vibration Monitoring System Check T4.8 Thermocouple Inspection P4.8 Inlet probe inspection

6 Months or 4000 Hours 6 Months or 4000 Hours 6 Months or 4000 Hours 6 Months or 4000 Hours

WP 4015 00

6 Months or 4000 Hours

WP 1711 00

6 Months or 4000 Hours

WP 1712 00

Combustion Air Inlet Inspection

GEPPLP

6 Months or 4000 Hours

Conduct Inlet Inspection IAW IAD Service Letter No. 6000-02-05

Borescope

GEPPLP

6 Months or 4000 Hours

Conduct borescope IAW IAD Service Letter No. 6000-02-05

6 Months or 4000 Hours or indication of blockage

Schedule replacement of filter element every six months or sooner, and have ample supply of spare elements. If external leakage is noted, replace Oring or bonded seal at leak. For bowl seal leaks, replace O-ring seal. If leakage persists, check sealing surfaces for scratches or cracks; replace any defective parts. Differential pressure devices actuate when the element needs changing or because of high fluid viscosity in “cold start” conditions.

GT Assy GT Assy GT Assy GT Assy GT Assy

WP 1411 00 WP 1312 00 WP 4024 00

SYNTHETIC LUBE OIL Turbine Lube Oil Filters (Supply and Scavenge)

Pg 6B-14

Pall, HZ8640A20KNTW PT-Y302 (J00463)

Maintenance Check Periodicity

Rev 1 06/26/2012

LM6000 GENERATOR PACKAGE

MAINTENANCE COURSE

SYNTHETIC LUBE OIL (Cont) Component

Vendor & Part Number

Maintenance Frequency

Remarks

VGV Pump Filter Element 40 Micron

Aircraft Porous Media, AC-B244F244OY1

6 Months or 4000 Hours or indication of blockage

Schedule replacement of filter element every six months or sooner, and have ample supply of spare elements. If external leakage is noted, replace O-ring or bonded seal at leak. For bowl seal leaks, replace O-ring seal. If leakage persists, check sealing surfaces for scratches or cracks; replace any defective parts. Differential pressure devices actuate when the element needs changing or because of high fluid viscosity in “cold start” conditions. Conduct IAW GEK WP4021 00.

Lube oil pump inlet screen inspection

GE

6 months or indication of blockage

Check engine attached lube oil supply and sacavage pump inlet screens (finger filter) for particulate buildup IAW GEK WP4020 00

Magnetic Chip Detector

GE

6 months or high Check magnetic chip detector for alarm activates particulate buildup IAW GEK WP4017 00

Turbine Lube Chromalox, 6 Months or Oil Tank Heater 155-500710-849 4000 Hours and Thermostat (382A5610P0001)

Rev 1 06/26/2012

Check heaters for coatings and corrosion. Clean if necessary. Check tank for sediment around the heater and remove as necessary. Check heater and tank for accumulated sludge deposits and remove if necessary. Inspect for loose or corroded terminal connections/ends and tighten and clean as necessary. If corrosion is found, check box gasket and replace as necessary. Check conduit layout to correct conditions that allow corrosion to enter terminal housing.

Maintenance Check Periodicity

Pg 6B-15

LM6000 GENERATOR PACKAGE

MAINTENANCE COURSE

HYDRAULIC START SYSTEM Component

Vendor & Part Number

Maintenance Remarks Frequency

Hydraulic Starter Motor Assembly

Sauer-Sundstrand, 5115005

6 Months or 4000 Hours

Keep both interior and exterior of the motor free from dirt, water, oil, and grease. Motors operating in dirty places should be periodically disassembled and thoroughly cleaned. Check to see that the bearings are in good condition and operating properly. Check to see that there is no mechanical obstruction to prevent rotation in the motor or in the driven load. Check to see that the air gas is uniform. Check to see that all bolts and nuts are tightened securely. Check to see that there is a proper connection to the drive machine or that the load has been made.

Reservoir Heater and Thermostat

Chromalox, 156-500541-585 (382A5596P0001)

6 Months or 4000 Hours

Check for coating and corrosion and clean if necessary.

Pg 6B-16

Maintenance Check Periodicity

Rev 1 06/26/2012

LM6000 GENERATOR PACKAGE

MAINTENANCE COURSE

GENERATOR LUBE OIL Component

Vendor & Part Number

Maintenance Frequency

Remarks

Generator Lube Inudfil, 6 Months or 4000 Oil Filter IDGL-2-320-2"Hours CODE 61-06-VCSV (382A5649P0001)

☺Schedule replacement of filter element every six months or sooner, and have ample supply of spare elements. Replace any defective parts. Differential pressure devices actuate when the element needs changing or because of high fluid viscosity in "cold start" conditions.

Generator Chromalox, 6 Months or 4000 Lube Oil Tank 155-500710-850 Hours Heater (382A5597P0001) Thermostaticall y Controlled Heater

☺Check heaters for coatings and corrosion. Clean if necessary. Check tank for sediment around the heater and remove as necessary. Check heater and tank for accumulated sludge deposits and remove if necessary. Inspect for loose or corroded terminal connections/ends and tighten and clean as necessary. If corrosion is found, check box gasket and replace as necessary.

Generator Lube Supplied w/ Oil Pump Generator (Att. Pump)

6 Months or 4000 A small amount of SHELL Hours ALVANIA EP grease should be replenished through the oil plug hole of the coupling case. Over greasing can cause excessive bearing temperatures, lubricant and bearing failure.

AC Lube Oil Pump and Motor

6 Months or 4000  Hours (Recommended) 

Rev 1 06/26/2012

Maintenance Check Periodicity

Check Foundation bolts for tightness Verify pump to motor alignment

Pg 6B-17

LM6000 GENERATOR PACKAGE

MAINTENANCE COURSE

LIQUID FUEL SYSTEM & NOX WATER INJECTION Component

Vendor & Part Number

Maintenance Frequency

FCV-2001 Fuel Metering Valve

Woodward 6 months, or upon Requirement from GEK 8915-1029 indication of problems 105059 Preventative Maint., (382A5322P0001) Table 12-1

FSV-2004/ 2006 Fuel Shutoff Valve

Woodward 6 months, or upon Requirement from GEK 8918-082 indication of problems 105059 Preventative Maint., (382A5524P0001) Table 12-1

CO-AX, 6 months, or upon SOV-2008 Fuel Vent VFK502O664TTA indication of problems Solonoid Valve 256YVXG1P1A (382A6357P0001) Ignition System Functional Check

GE LM6000 Component

Remarks

Requirement from GEK 105059 Preventative Maint., Table 12-1 (24 VDC NO 2" 600#RF)

6 months, or upon Requirement from GEK indication of problems 105059 Preventative Maint., Table 12-1

Woodward, 6 Months or 4320 OP FCV-2019 Water Injection 8915-1024 Hours (See vendor Flow Control (382A4821P0001) documentation) Valve

Index Cavitation-resistant sleeve

Low Pressure Gear Box

6 Months or 3000 Hours

☺Change lube oil every 6 months or 3000 hours thereafter.

Low Pressure Rotojet, Water Injection ROA S-375 Pump (J04699)

6 Months or 4000 Hours, whichever occurs first

☺Change Bearing Oil

Water Injection Falk Coupling, Drive Coupling G20-1020G (Low Pressure) (365TS)(J00417)

6 Months (Use of General Purpose Grease)

Lubriacte Coupling (Use of general purpose grease)

Pg 6B-18

Kobe/Milwaukee, 0657603

Maintenance Check Periodicity

Rev 1 06/26/2012

LM6000 GENERATOR PACKAGE

MAINTENANCE COURSE

VENTILATION AND COMBUSTION SYSTEM Component

Vendor & Part Number

Filter House

Maintenance Remarks Frequency Check the clean plenum for 6 Months (Recommend degradation and moisture build-up. Check all joints for evidence of air ed) or dust leakage.

Turbine AWV INC., Enclosure Fire 33389 Protection (382A5531P0001) Damper 50 1/2" X 53"

Sleeve bearing, S.S. pins w/ OIB 6 months (Recommende bushings in linkage and kiddie trip pin arm to be coated with “neverd) seez” regular grade lubricant. Cycle Damper

Turbine Enclosure Ventilation Fan - 66" Diameter Centaxial Fan Assembly and Motor

Fan: TCF Aerovent, C-31403 (66” dia) GE Motor:

Generator Enclosure Ventilation Fan (63 3/4" dia.) Vaneaxial Fan Assembly and Motor

Fan: TCF Aerovent, C-31399-00 GE Motor:

Generator Ventilation Back Draft Damper

AWV INC.,

Sleeve bearing, S.S. pins w/ OIB 6 months (Recommende bushings in linkage to be coated with “never-seez” regular grade d) lubricant. Cycle damper assy.

Generator Exhaust Damper

AWV, 24475

Sleeve bearing, S.S. pins w/ OIB 6 months (Recommende bushings in linkage and kiddie trip pin arm to be coated with “neverd) seez” regular grade lubricant. Cycle Damper

Rev 1 06/26/2012

   

   

6 months or 4500 Hours

☺Lubricate fan and motor assembly

6 months or 4500 Hours

☺Lubricate fan and motor assembly

Motor Dual Rating 125/104 hp, 60/50 hz, 460/380 vac 3 Phase, 1780/1475 rpm 444T Frame, explosion proof

Motor Dual Rating 100/83 hp, 60/50 hz, 460/380 vac 3 Phase, 1800/1500 rpm 405T Frame, explosion proof

Maintenance Check Periodicity

Pg 6B-19

LM6000 GENERATOR PACKAGE

MAINTENANCE COURSE

VENTILATION AND COMBUSTION SYSTEM (Cont) Component

Vendor & Part Number

Maintenance Remarks Frequency

Expansion Joint Various VBV Duct

6 Months

Visual Inspection

Expansion Joint Various Inlet Volute

6 Months

Visual Inspection

Combustion Air GEPPLP Inlet Inspection

6 Months or 4000 Hours

Conduct Inlet Inspection IAW IAD Service Letter No. 6000-02-05

6 Months or 4000 Hours

☺Check heaters for coatings and corrosion. Clean if necessary. Check tank for sediment around the heater and remove as necessary. Check heater and tank for accumulated sludge deposits and remove if necessary. Inspect for loose or corroded terminal connections/ends and tighten and clean as necessary. If corrosion is found, check box gasket and replace as necessary. Check conduit layout to correct conditions that allow corrosion to enter terminal housing.

WATER WASH SYSEM Water Wash Tank Heater 2 1/2" NPT 480V 9KW

Chromalox, 156-500509-025 (382A5598P0001)

FIRE PROTECTION SYSTEM Electronic Kiddie Heads

Kidde, 872450

6 months

Test electronic control heads

Cylinder

Kidde, 870269 (377A1188P0002)

6 months

Check CO2 cylinder weight

Optical Flame Detector

Det-Tronics, X9800EQP (382A4669P0001)

6 Months

Calibrate sensor.

Pg 6B-20

Maintenance Check Periodicity

Rev 1 06/26/2012

LM6000 GENERATOR PACKAGE

MAINTENANCE COURSE

FIRE PROTECTION SYSTEM (Cont) Component

Vendor & Part Number

Maintenance Remarks Frequency

Fire/Gas Alarm Wilson Fire, Horn and FSASHH24SMRW/ Strobe TCWL (J00169)

6 Months

Inspect for loose fittings, damaged threads, rust, dirt, and frayed wire braid. Check for deformation, cracks, dirt, or other damage. Replace component if damaged.

6 Months or 4000 Hours

Check that no oil leakage exist.

Air Inlet Screen

6 Months or 4000 Hours

Check that screens are free from obstruction and cleanliness.

Generator Lube Supplied w/ Oil Pump Generator (Att. Pump)

6 Months or 4000 Hours

A small amount of SHELL ALVANIA EP grease should be replenished through the oil plug hole of the coupling case. Over greasing can cause excessive bearing temperatures, lubricant and bearing failure.

MEDENSHIA GENERATOR Labyrinth Seal

MANUAL VALVE PREVENTATIVE MAINTENANCE Preventative maintenance operations essentially consist of periodic inspections to ensure that the valve is working correctly. 

The valves must be opened and closed at least once every 6 months and, should such be required on the basis of the fluid or the application of the valve and its importance, opening and closing check plans will have to be established for shorter periods.



The user will be responsible for establishing opening and closing plans that are adequate for the work conditions and the fluids used!



WARNING! Never leave the valves open or closed for a long period of time.



A very high torque increase could be due to the inclusion of foreign bodies in the seats. It is important not to force the valve! Proceed with an inspection of the seats in order to avoid damaging the ball.



We advise replacement of the seals and the seats whenever an in-depth revision of the installation is made.

Rev 1 06/26/2012

Maintenance Check Periodicity

Pg 6B-21

LM6000 GENERATOR PACKAGE

MAINTENANCE COURSE

YEARLY SYNTHETIC LUBE OIL Component Vendor & Part Number

Maintenance Frequency

Remarks

Lube Oil Reservoir

Yearly

Clean and inspect interior of lube oil reservoir. (Based on oil analysis sample IAW GEK WP4016 00)

Turbine Lube Tedeco, Oil Tank Fill MF9639LKPSS Cap

Annually (more often if repeated problems occur)

Inspect filler cap for missing parts which would prevent cap from sealing and allow water or contaminates to enter tank. Replace missing parts as necessary. Inspect flange seal area for leakage. If leaking replace Oring.

Turbine Lube Tedeco, Oil Tank 3E8501-101 Basket (377A2452P0001) Strainer

Annually (more often if repeated problems occur)

Replace missing parts as necessary. Inspect flange seal area for leakage. If leaking replace Oring.

Turbine Lube Protecto Seal, Oil Tank FF6672 Flame Arrestor

Annually (more often if repeated problems occur)

Replace component if damaged or fails.

Turbine Lube GEPPLP, Oil Air/Oil (701209) Separator

Annually

Replace the demister elements when a differential pressure of 1.7 psid is obtained or every year, whichever occurs first.

Turbine Lube GEPPLP, Oil Air/Oil (701210) Pre-Separator

3 Months or 2000 Hours

Replace the demister elements when a differential pressure of 1.7 psid is obtained or every year, whichever occurs first.

Turbine Lube API Basco Oil Heat Exchanger

Annually (Recommended)

Check internal components for fouling.

Pg 6B-22

GEPPLP, 724977A

Maintenance Check Periodicity

Rev 1 06/26/2012

LM6000 GENERATOR PACKAGE

MAINTENANCE COURSE

SYNTHETIC LUBE OIL Component Vendor & Part Number

Maintenance Frequency

Remarks

Turbine Lube Oil Tank Demister 2”

Dollinger AE-229-110

Annually

Under normal conditions, the 'Profilter Element requires changeout every second change of the Final Stage Elements. Maintain optimum performance of the Profilter Element and inspect the element for dirt build-up. This would be evidenced by heavy build up of oil, dirt, etc. on the inlet side of the element. Also inspect for damage in the form of holes or tears. Changeout of the Final Stage Elements is required when regularly scheduled system maintenance is conducted. The Vent Breather Element should also be replaced every second change of the Final Stage Elements.

Lube Oil Reservoir

GE

Annually

Inspect interior of lube oil reservoir. Clean and replace oil if necessary (Based on results of spectroanalysis of lube oil IAW GEK 105059, WP4016 00

HYDRAULIC START SYSTEM Charge Pump Donaldson, Filter Element P16-5332

Annually (more Replace filter on a regular basis and often if repeated replace filter once a year regardless problems occur) of visual indicator indication.

Clutch Drain Streamflo Strainers, Annually (more Replace missing parts as necessary. Return Strainer 377A7898P0001 often if repeated Inspect flange seal area for leakage. problems occur) If leaking replace O-ring. Case Drain Return Filter

Donaldson, HMK 05-04

Annually (more Replace filter on a regular basis and often if repeated replace filter once a year regardless problems occur) of visual indicator indication.

Hydraulic Starter Oil Cooler

Hayden, 377A6812P0001

Annually (more Check fan blades, check V-bolt often if repeated drives, lubricate fan motor bearings, problems occur) consult troubleshooting guide for excess vibration or noise, tighten all bolts and set screws.

Rev 1 06/26/2012

Maintenance Check Periodicity

Pg 6B-23

LM6000 GENERATOR PACKAGE

MAINTENANCE COURSE

GENERATOR LUBE OIL Component Vendor & Part Number

Maintenance Frequency

Remarks

Generator Reservoir Air/Oil Separator

Dollinger, AE-129-660

Annually (more often if repeated problems occur) (Recommended)

Replace filter elements

Jacking Oil Discharge Oil Filter

Donaldson, Annually (more HPK0300B0802NX often if repeated problems occur)

Replace filter on a regular basis and replace filter once a year regardless of visual indicator indication.

Generator Amot, Lube Oil 2"BCSJ-140-02-D Thermostatic (J00176) 3-Way Control Valve

Annually (more often if repeated problems occur)

Replace thermostatic element and seals whenever some variation in the controlled temperature is noticed.

Generator Jacking Oil Pump

Voith/Eckerle, IPV-3/3/3/35/5/3.5/3.5/-102 (RCN1970A)

Annually (more often if repeated problems occur)

Protect pump from freezing temperatures. Ensure motor is lubricated. When lubricants are operated at elevated temperatures, the lubrication frequency should be increased. Over greasing can cause excessive bearing temperatures, lubricant and bearing failure.

Generator Tedeco, Lube Oil Tank MF9639LKPSS Fill Cap

Annually (more often if repeated problems occur)

Inspect filler cap for missing parts which would prevent cap from sealing and allow water or contaminates to enter tank. Replace missing parts as needed.

Generator Watts, Lube Oil 1/2"-S8000-LL Pressure Sensing Valve

Annually (more often if repeated problems occur)

Check valve stem for leakage. If valve is damaged or fails, replace valve.

Generator Lube Oil Auxiliary Pump Coupling

Annually (more often if repeated problems occur)

Inspect coupling. If coupling is defective or fails, replace coupling.

Pg 6B-24

Magnaloy, 200

Maintenance Check Periodicity

Rev 1 06/26/2012

LM6000 GENERATOR PACKAGE

MAINTENANCE COURSE

LIQUID FUEL SYSTEM & NOX WATER INJECTION Water Injection Indufil B.V., 12 Months Duplex Filter - IDGH-2-320-2" CODE 61-25-V-SS (382A5653P0001)

☺If alarm is activated, replace filter element. Replace filter once a year regardless of visual indicator indication.

Low Pressure Rotojet, Water Injection ROA S-375 Pump (J04699)

☺Disassemble, clean and inspect pump. Replace parts as necessary.

12 Months

VENTILATION AND COMBUSTION SYSTEM Filter House

12 months (Recommended)

Prefilters to be replaced.

Annually (more often if repeated problems occur)

Open, Inspect and clean reservoir. Check reservoir for leakage.

WATER WASH SYSEM Water Wash Tank

GEPPLP, 724981A

Open and inspect in conjunction with heater maintenance.

In-Line Filter

Parker, 12A-F16L-50-BNSS (377A6552P0001)

Annually (more often if repeated problems occur)

☺Replace filter on a regular basis and replace filter once a year.

Pump/Motor Assembly 3600 RPM 22GPM

Goulds, 1SVDK7-GE (382A5578P0001)

Annually (more often if repeated problems occur)

Protect pump from freezing temperatures. Ensure motor is lubricated.

Annually (more often if repeated problems occur)

☺Replace filter on a regular basis and replace filter once a year regardless of visual indicator indication.. Replace moisture drain

Instrument Air Hankison, Filter HF9-24-8-G

Rev 1 06/26/2012

Maintenance Check Periodicity

Pg 6B-25

LM6000 GENERATOR PACKAGE

MAINTENANCE COURSE

WATER WASH SYSTEM (CONT) Component

Vendor & Part Number

Maintenance Frequency

Remarks

Motor

GE Motors, Supplied With Pump

Annually (more often if repeated problems occur)

☺Lubricate Motor. Keep both interior and exterior of the motor free from dirt, water, oil, and grease. Motors operating in dirty places should be periodically disassembled and thoroughly cleaned. Check to see that the bearings are in good condition and operating properly. Check to see that there is no mechanical obstruction to prevent rotation in the motor or in the driven load. Check to see that all bolts and nuts are tightened securely. Check to see that there is a proper connection to the drive machine or that the load has been made.

Pg 6B-26

Maintenance Check Periodicity

Rev 1 06/26/2012

LM6000 GENERATOR PACKAGE

MAINTENANCE COURSE

SPRINT SYSTEM Component

Vendor & Part Number

Maintenance Frequency

Remarks

Electric Motor GE Motors, Supplied by Pump Manufacturer

Annually (more often if repeated problems occur)

☺Lubricate Motor. Keep both interior and exterior of the motor free from dirt, water, oil, and grease. Motors operating in dirty places should be periodically disassembled and thoroughly cleaned. Check to see that the bearings are in good condition and operating properly. Check to see that there is no mechanical obstruction to prevent rotation in the motor or in the driven load. Check to see that all bolts and nuts are tightened securely. Check to see that there is a proper connection to the drive machine or that the load has been made.

Pump

Goulds, 3SVD-10STG-GE (382A5652P0001)

Annually (more often if repeated problems occur)

Protect pump from freezing temperatures. Ensure motor is lubricated.

Filter

Indufil, Annually (more TSGH-2-200-1 1/2" often if repeated ANSI-150# problems occur) (382A1201P0001)

Replace filter on a regular basis and replace filter one a year regardless of visual indicator indication.

FCV-2104 Flow Control Valve - 1"

AWC, Annually (more 1CPT4466TSEA.12 often if repeated 5/10DFP17424D/20 problems occur) B754Z24DV53 (382A5526P0001)

Check valve stem for leakage. If valve stem is damaged or fails, replace valve.

Rev 1 06/26/2012

Maintenance Check Periodicity

Pg 6B-27

LM6000 GENERATOR PACKAGE MEDENSHIA GENERATOR Component Vendor & Part Number

MAINTENANCE COURSE

Maintenance Frequency

Remarks

Bearing Insulation

12 Months or 8000 Check for shaft voltage or Hours resistance.

Insturmentation and Protective Devices

12 Months or 8000 Check that the function and Hours settings are correct.

Attached Lube Oil Pump Bearing

12 Months or 8000 Change out the bearing Hours

Pg 6B-28

Maintenance Check Periodicity

Rev 1 06/26/2012

LM6000 GENERATOR PACKAGE

MAINTENANCE COURSE

AS REQUIRED Component Vendor & Part Number

Maintenance Frequency

Remarks

GT Assy

Inlet & coupling inspection

As Required

WP4010 00

GT Assy

External Engine Inspection

As Required

WP4012 00

GT Assy

Compressor water wash

As Required

WP 4014 00

GT Assy

Vibration Monitoring System Check

As Required

WP 4020 00

GT Assy

Exhaust coupling check

As Required

WP 4013 00

GT Assy

Stage 1 HPC blade replacement

16,000 hrs of HP WP 2413 00 SPRINT operation or 25,000 hrs of total SPRINT operation, whichever comes first

GT Assy

Stage 2,3 and 4 HPC blade cord length check (sys with E-SPRINT)

At same time as stage 1 HPC blade replacement

WP 2413 00

GT Assy

Stage 1 LPC blade inspection

Every 25,000 hours of LP SPRINT operation

TBD

Note 1: “As required” is defined as anytime maintenance is performed in the area or when the area is accessible.

Rev 1 06/26/2012

Maintenance Check Periodicity

Pg 6B-29

LM6000 GENERATOR PACKAGE

MAINTENANCE COURSE

MEDENSHIA GENERATOR Component Vendor & Maintenanc Remarks Part Number e Frequency Painting Labyrinth seals Stator Windings Rotor Windings Rotating Rectifiers, fuses for diodes and CR absorbers AC Exciter PMG Bearing Metal

Air Gap Whole Generator

Pg 6B-30

5 years or 40,000 hours 5 years or 40,000 hours

5 years or 40,000 hours

5 years or 40,000 hours

5 years or 40,000 hours 10 Years or 80000 hours

Check that it has no damage Check the deterioration of pressurized pipes.  Remove contaminates by means of brushes, a vacuum cleaner, waste cloth and detergents  Check the cracks, distortion and deterioration of coil surface.  Check the looseness of wedges, bolts, nuts, balance weights etc.  Check the conductivity diodes and fuses  

Check the radial and thrust surfaces. Check the corrosion due to shaft current.  Check the top clearance of bearing by means of lead stripes.  Check the side clearance of driven end bearing with thickness gauge. Check the air gap for generator, AC exciter, PMG and rotor earth fault detector  Withdraw the rotor from the generator frame and perform cleaning of all items.  Remove contaminates by means of brushes, a vacuum cleaner, waste cloth and detergents  Check all items from 5 year periodic maintenance.  Check for cracks of retaining rings.  After reassembly, check the alignment such as the radial differences and parallelism of the coupling by means of dial gauges and thickness gauges.

Maintenance Check Periodicity

Rev 1 06/26/2012

LM6000 GENERATOR PACKAGE

MAINTENANCE COURSE

LIQUID FUEL SYSTEM & NOX WATER INJECTION Component Vendor & Part Number

Maintenance Frequency

Remarks

Low Pressure Rotojet, Water Injection ROA S-375 Pump (J04699)

As required

Replace Seals. Max allowable leakage is 1 pint/hr

Water Injection Falk Coupling, Drive Coupling G20-1020G (Low Pressure) (365TS)(J00417)

3 years (Use of special grease required)

Lubricate Coupling. (Use of Kalk long term grease (NLGI #1/2 grade))

VENTILATION AND COMBUSTION SYSTEM Filter House

24 months (Recommended)

High efficiency filters to be replaced. Check all surfaces for corrosion.

Auxiliary Skid GEPPLP, Enclosure (382A7074P0001) Damper/Motor /Fan Assembly

No Vendor docs

Space Heater GEPPLP, Generator (FX412480360-5T) Enclosure (For Winterization)

No Vendor docs

Auxiliary Skid GEPPLP, Enclosure (382A7074P0001) Acoustical Louver

No Vendor docs

FIRE PROTECTION SYSTEM Distribution Piping

Various

2 years

Blow out distribution piping

Combustible Gas Detector

Wilson Fire, WFDCUEX-1 (382A6223P0001)

2 Years

Replace clock batteries.

Rev 1 06/26/2012

Maintenance Check Periodicity

Pg 6B-31

LM6000 GENERATOR PACKAGE

MAINTENANCE COURSE

FIRE PROTECTION SYSTEM (Cont) Component

Vendor & Part Number

Maintenance Frequency

Remarks

Cylinder

Kidde, 870269 (377A1188P0002)

5 Years

Inspect and/or hydrostatically test CO2 cylinders and flexible discharge and actuation hoses

Optical Flame Detector

Det-Tronics, X9800EQP (382A4669P0001)

7 Years

Replace Clock Battery

2 Years

Check for blockage and clean

WATER WASH SYSTEM Water Wash Nozzles

NA

GENERATOR LUBE OIL Generator Lube GE Motors, 7.5 HP 4 Years Oil AC Pump 5KS213RSP226 Motor (377A1000P0001)

☺Lubricate Motor

Jacking Oil Pump Electric Motor

☺Lubricate Motor

Pg 6B-32

GE Motors, 1.5 Years 5KS254RSP221 (377A1001P0001)

Maintenance Check Periodicity

Rev 1 06/26/2012

LM6000 GENERATOR PACKAGE

MAINTENANCE COURSE

SECTION 6C EQUIPMENT TESTING

Rev 1 06/26/2012

Equipment Testing

Pg 6C-1

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MAINTENANCE COURSE

THIS PAGE INTENTIONALLY LEFT BLANK

Pg 6C-2

Equipment Testing

Rev 1 06/26/2012

LM6000 GENERATOR PACKAGE

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CLEANLINESS Cleaning Cleaning as a maintenance man or maintenance manager is one of your most important aids in the prevention and control of corrosion. To take full advantage of the benefits, an adequate cleaning program must be in place and adhered too. The term clean means to do the best job possible using the time, materials, and personnel available. A daily wipe down of all machinery is better than no cleaning at all. The importance of frequent cleaning cannot be overemphasized. Any cleaning procedures, however, should be in the mildest form possible to produce the desired results. For example, spraying water around multi-pin connectors can cause electrical shorts or grounds, with a possible loss of control functions or equipment damage. In general, gas turbine engines and enclosures should be cleaned as often as necessary to keep surfaces free of salt, dirt, oil, and other corrosive deposits. A thorough inspection and cleaning of gas turbine intakes and enclosures should always be done in conformance with Planned Maintenance requirements. Since gas turbines are more subject to internal corrosion than engines used in other types of applications, internal cleaning is of particular importance. This is accomplished by means of water washing. A mixture of cleaning solvent water-wash compound and distilled water is injected into the engine air inlet while it is being motored and then rinsed with distilled water in the same manner. It is then operated for about 5 minutes to remove all liquid. For more detailed information on this procedure, consult the applicable maintenance work package.

Characteristics of Metals As a member of the maintenance organization, you should have a thorough knowledge of the characteristics of the various metals used throughout the engineering plant, as well as the engines themselves. To some extent, all metals are subject to corrosion. To keep corrosion to a minimum, corrosion-resistant metals are used to the fullest extent possible consistent with weight, strength, and cost considerations. On exposed surfaces, the major preventive for providing relative freedom from corrosion is a coating of protective surface film. This film can be in the form of electroplate, paint, or chemical treatment, whichever is most practical. Most of the metals used in the engineering plants require special preventive measures to guard against corrosion. In the case of aluminum alloys, the metal is usually anodized or chemically treated and painted. Steel and other metals such as brass or bronze (with the exception of stainless steels) use cadmium or zinc plating, protective paint, or both. Rev 1 06/26/2012

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In all cases, the protective finish must be maintained to keep active corrosion to an absolute minimum.

PRESERVATION AND DEPRESERVATION OF GAS TURBINE ENGINES The main purpose of engine preservation is to prevent corrosion of the various types of materials that make up the engine and its accessories. Preservation also ensures against gumming, sticking, and corrosion of the internal passages. Engine preservation and depreservation is vital because the corrosion of engine structures can and does have a great effect on the operational and structural integrity of the unit. Therefore, it is important that you know about methods of preservation, materials used, and depreservation procedures.

Preservation for Extended Shutdown or Storage If you know that an engine is to be secured for an extended period or stored, you must make plans to preserve it prior to the extended shutdown. When an LM Series engine is to be layed-up or inoperable for an extended period of time, precautions must be taken to preserve the gas turbine in order to minimize exposure to atmospheric corrosion. Details of preservation depend on the duration of non-operation and whether the gas turbine is being stored in an engine enclosure or in a shipping container. GEK manual 105059, table 6-1 provides a summary of these details. Refer to WP 3011 00 for details of precautions and preservation procedures.

Depreservation An engine that has been in storage (or inoperable) for an extended period of time must be depreserved before it can be placed in service. Refer to WP 3011 00 for details of precautions and preservation procedures.

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SPECIAL TOOLS Special tools are required to provide Level I and Level II maintenance activities. These tools are listed in General Electric LM6000 Series On-Site Operation and Maintenance Manual, GEK 105059, Volume II (WP 0001 00), and are recommended for customer-performed maintenance. The basic tooling to remove the turbine from, and install it in, the engine compartment, and an alignment fixture are provided by GE AEP in the basic scope of supply. WP 0001 00 has the following information: 1. Table 1 lists recommended mechanics’ hand tools. 2. Table 2 lists special tools for Level I and Level II maintenance and for periodic inspections/maintenance on support equipment. 3. Table 3 lists consumable materials. 4. Table 4 lists on-site expendables. Note: Equipment listed in WP 0001 00, Tables 1, 2, 3, and 4 may not be provided in the basic scope of supply. Some equipment listed is not essential, but is recommended for ease of service. Additional items may be purchased from GE Aero Energy Products. Refer to Test and Calibration Equipment Required for Calibration of the Control System Sensing Devices, in this section for a list of special tools and equipment required for calibration of the control system sensing devices.

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Test and Calibration Equipment Required for Calibration of the Control System Sensing Devices Nomenclature

Model/Part No.

Source/ Manufacturer

Deadweight Tester (for testing pressure switches)

23-1, or equivalent

Chandler, or equivalent

Hot Oil Bath, electrically heated with adjustable thermostatic temperature control, oil agitator, and calibrated thermometer (for testing temperature switches)

Various

Various

Digital Multimeter (Qty 2) 177

8021B

Fluke Keithley

AC/DC Power Supply (Qty 2) 6234A

Hewlett-Packard

Volt-Ohmmeter, 20 kOhm per volt

260

Simpson

Oscilloscope, Dual-Channel, 15 MHz 2213A/2215A

1222A

Hewlett-Packard Tektronix

Jumpers, with Insulated Alligator Clips

Various

Various

Discriminating Optical Flame Detector Field Test Unit (steam-injected units)

7100

Systron Donner

Ionization Detector Sensitivity Checker SCU-9 Larm

Pyrotronics Pyr-A-

Adapter Kit Larm

Pyrotronics Pyr-A-

SAU-2

Gas Detector Remote Calibration Meter 361-155

Delphian

Gas Detector Calibration Kit

360-642

Delphian

Gas Detector Calibration Adapter Fitting 360-643

Delphian

Megohm Meter, 500 V–5 kV

Biddle, or equivalent

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WP 0001 00 Cover Page

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WP 0001 00 Special Tools

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WP 0001 00 Consumable Material

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WP 0001-00 Consumable Material

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EQUIPMENT TESTS Maintenance departments have the responsibility for scheduling and performing various tests on your equipment. The purpose of those tests is to determine how your equipment is performing and if there are any equipment malfunctions. These tests are performed at various times, such as 1. 2. 3. 4.

Before extended maintenance periods Prior to seasonal shutdowns Loss of efficiency Required by Planned Maintenance (PM)

The equipment tests may be performed by plant personnel, outside repair agents, or by inspection teams (such as insurance and fire certifications).

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ENGINE TREND ANALYSIS Preventive maintenance receives a great deal of attention from everyone in the field of turbine engine operation, since letting an engine run as long as it will run and fixing it only after a breakdown occurs is not only unwise, but extremely costly. On the other hand, it would be just as unwise to constantly tear down an engine just to inspect it. You should know that vital parts of an engine last longer and operate better if they are not tampered with unnecessarily. Therefore, an attempt must be made to find a happy medium between these two forms of maintenance. One way to determine the condition of an engine is by monitoring its operation. This is done by regularly obtaining certain engine operating data and by studying, analyzing, and comparing it with previous data. The results of this information can be utilized by plant personnel for interpretation of engine performance, and decide whether the engine needs to be shut down for maintenance. Trends analysis may be performed from the Turbine Control Panel HMI. The trend screen allows for trending of separate values each. When setting up the trend screen, both live and historical data can be trended on the HMI. The screen may be printed if a printer is available.

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Fuel Trending Screen

Lube Oil Trending Screen

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PERFORMANCE DATA RECORDING For a more in-depth trending a Performance Data Recording should be conducted. For diagnosing performance or emissions issues, best results are obtained when all the parameters in the Performance Data Sheet are recorded and the data is recorded to the indicated level of precision. Also for best accuracy in the analysis, the engine should be stabilized for at least 5 minutes prior to data recording and several (3-5) readings should be taken at a given power level. The Performance Data Sheet shows typical parameters and precision levels which would normally be required for a performance evaluation by GE. Other considerations for best accuracy: 

Instrumentation should be recently calibrated



VG systems should be rig checked and calibrated



Crank soak washing should be performed prior to test



Fuel sample should be collected and analyzed for lower heating value (LHV) and specific gravity (SG) to assist in expedited analysis of performance data. Liquid fuel is to be analyzed for contaminants and compliance with fuel specification



High power data readings should be taken with VBV closed



The same data should be used for periodic trending of engine performance.

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LM6000 GAS TURBINE PERFORMANCE DATA SHEET ENGINE SERIAL N0.

SITE

OTHER INFORMATION ABOUT SITE AND REASON FOR DATA READING REASON FOR CURRENT DATA READING

[ ] ROUTINE

[ ] OTHER

[ ] DIAGNOSTIC SIMPLE OR COMBINED CYCLE

[ ] SIMPLE CYCLE [ ] COMBINED CYCLE (i.e. has boiler) [ ] SIMPLE/COMBINED (has boiler and bypass capability)

DOES INLET SYSTEM HAVE A CHILLER?

[ ] EVAPORATOR COOLER EVAPORATOR COOLER? [ ] CHILLER

INLET LOSS (INCHES WATER), IF KNOWN ______________________________ EXIT LOSS (INCHES WATER), IF KNOWN ______________________________ INLET FILTER PRESSURE DROP, IF AVAILABLE ______________________________ LAST CRANK SOAK DATE ______________________________

HOW OFTEN DOES CUSTOMER CRANK SOAK ENGINE?

[ ] MORE THAN ONCE A MONTH [ ] ABOUT ONCE PER MONTH [ ] ONCE EVERY FEW MONTHS [ ] NEVER

DRIVEN EQUIPMENT AND MANUFACTURER Hz (i.e. GENERATOR, GE) Hz

[ ] GENERATOR 50 [ ] GENERATOR 60 [ ] COMPRESSOR

HOW IS ENGINE DISPATCHED?

[ ] FULL POWER ALL THE TIME [ ] FULL POWER DURING DAILY PEAK ONLY [ ] MW AS REQUIRED [ ] OTHER

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LM6000 GAS TURBINE PERFORMANCE DATA SHEET ENGINE SERIAL N0. ______________

UNIT

PRECISION

RDG NO

SITE ______

RDG NO

RDG NO

TIME DATE COUNTERS TOTAL T3 BASE T48/T3 BASE FIRED STARTS GENERAL OUTPUT REGULATOR

HRS HRS HRS COUNTS

MW Ib/hr OR GPM

FUEL FLOW (FOR GT) SPRINT WATER

XX.XX

T3, T48, SPEED?

GPM Ib/hr OR GPM

NOx WATER (FOR GT)

XXXXX. OR

xx.x XX.X XXXXX. OR XX.X

NOx STEAM (FOR GT)

Ib/hr

XXXXX

WATER:FUEL RATIO

N/D

X.XX

XN25

RPM

XXXXX.

XN2

RPM

XXXX.

LHV

BTU/LB OR BTU/SCF

XXXXX. OR XXX.X

SPECIFIC GRAVITY CYCLE TEMPERATURES TO - DRY BULB TO - WET BULB T2SEL

N/D

.XXX

°F °F °F

XXX.X XXX.X XXX.X

T25SEL

°F

XXX.X

T3A

ºF

XXXX.

T313

ºF

XXXX.

T3SEL

ºF

XXXX.

T48SEL

ºF

XXXX.

T8

ºF

XXX.

LM6000 Performance Data Sheet (Sheet 2 of 4)

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LM6000 GAS TURBINE PERFORMANCE DATA SHEET ENGINE SERIAL N0. ______________

UNIT

PRECISION

RDG NO

SITE ______

RDG NO

RDG NO

TIME DATE CYCLE PRESSURES PO

PSIA

XX.XX

P25SEL

PSIA

XX.X

PS3SEL P48SEL

PSIA PSIA

XXX. XXX.X

PTB PS3A

PSIA PSIA

XXX. XXX.

PS3B

PSIA

XXX.

%

XX.

VBVSEL

%

XX.

VIGVSEL

%

XX.X

VG SYSTEMS VSVSEL

EMISSIONS NOx

PPM

XX.X

NOx (15% 02)

PPM

XX.X

02

%

XX.X

CO

PPM

XX

T48 INDIVIDUALS T48A

°F

XXXX.

T48B T48C T48D

°F °F °F

XXXX. XXXX. XXXX.

T48E

°F

XXXX.

T48F

°F

XXXX.

T48G

°F

XXXX.

T48H

°F

XXXX.

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LM6000 GAS TURBINE PERFORMANCE DATA SHEET ENGINE SERIAL N0. ______________ UNIT

PRECISION

RDG NO

SITE ______ RDG NO

RDG NO

TIME DATE LUBE SYSTEM GT LUBE SUPPLY PRESS

psia

XXX.

LUBE SCAV PRESS LUBE FILTER dP HYDRAULIC FILTER dP

psia psi psi

XXX. XX. XX.

LUBE SUPPLY TEMP

°F

XXX.

AGB SCAV TEMP TGB/A SCAV B SCAV TEMP C SCAV TEMP D SCAV TEMP E SCAV TEMP A/TGB CHIP DET B-SUMP CHIP DET

°F °F °F °F °F °F Ω Ω

XXX. XXX. XXX. XXX. XXX. XXX. XXX. XXX.

C-SUMP CHIP DET

Ω

XXX.

GT VIBES LP-CRF HP-CRF LP-TRF

ips/mils ips/mils ips/mils

X.X X.X X.X

HP-TRF

ips/mils

X.X

LM6000 Performance Data Sheet (Sheet 4 of 4)

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VIBRATION ANALYSIS

The Most Basic Form of Vibration Analysis The most basic form of vibration analysis is called an overall vibration measurement. This reading provides a single number that describes the total amount of vibration energy being emitted by a machine. The idea is that more vibration indicates a problem. A number of tables and guides have been developed to explain what levels are acceptable for various machine types. This technology is inexpensive but it can also be inaccurate and inconclusive. As an example, a pump experiencing turbulence or flow noise will have a very high overall level, although there are no mechanical faults. On the other side of the coin, the pump may have a bearing problem that is serious but emits little vibration energy in comparison to the energy emitted by the shaft and the flow noise. Thus the bearing problem may not be evident in the overall reading. Finally, because the overall level provides only one number, it cannot differentiate between faults. In other words, one will not know if there is imbalance, misalignment, a bearing problem, a foundation problem etc. Overall readings were and are used today simply because the devices needed to collect this information are inexpensive and once were the only thing available. Unfortunately, many people today have incorrect concepts of what vibration analysis is and how it works because this simplistic approach is the only experience they have had with the technology.

Narrow Band Vibration Analysis When computers became widely available, so did the capacity to collect narrow band vibration data, or vibration spectra. A vibration spectrum separates measured vibration into small frequency bands. Different machine components and different faults will produce vibration and vibration patterns at specific frequencies. Thus, using a vibration spectrum, one can relate individual peaks and patterns in the spectrum to individual machine components and specific machine faults. In order to do this, one must have some information about the machine, such as the number of fan blades, impeller vanes and gear teeth, as well as shaft speeds and type of bearings (rolling contact or sleeve). Vibration data is most useful when taken in all three axes (axial, vertical and horizontal) as different faults may appear in different axis. This is the most common type of vibration measured today. Refer to the figure below for a comparison between an overall vibration measurement discussed in the previous section and narrow band vibration analysis.

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Predictive Maintenance Vs. Trouble Shooting In short, using vibration analysis in the context of Predictive Maintenance is easy, accurate, efficient and inexpensive. Using vibration analysis for troubleshooting is more difficult, often less accurate depending on the consultant, and more expensive. Here is the difference: In predictive maintenance, one routinely monitors the machine under repeatable test conditions and looks for changes. If the machine is not failing, the vibration patterns won’t change. If it is failing, the patterns will change, and it will be easy to determine what has changed and what fault the machine has. How much and how quickly the pattern is changing tells one how severe the problem is and indicates when action should be taken. Vibration analysis is sensitive enough to find some faults a year or more before they progress enough to require attention. It will take an experienced analyst no more than 5 to 10 minutes to compare a new set of data to an older or reference set of data and point out what has changed and what the problem is. Refer to Figure below for a trend plot that shows the change in machine condition and specific faults over a 1-1/2 year period; this type of trend is the basis of predictive maintenance.

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Troubleshooting is the process of taking measurements on a machine 1 time and trying to determine if it has a fault or not. In order to troubleshoot a machine correctly, one must take quite a lot of data including phase measurements and possibly structural measurements in addition to spectral data. These can be quite time consuming and expensive. The results a consultant provides will depend a lot on their experience and the types of tests they take. It can take a whole day or more to accurately troubleshoot a machine. Additionally, even though one may find some faults in a machine, without knowing the machine’s history it can be quite difficult to decide what to do with the information. If you knew the machine has had the same problem it has now for the past five years and has continued to operate fine, would you spend money to fix it now?

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ULTRASOUND AND INFRARED THERMAL IMAGING Thermal Imaging

The theory of thermal imaging is simple. All objects above absolute zero (0 Kelvin) emit infrared radiation. While infrared energy is invisible to the human eye, infrared imagers detect and convert these invisible wavelengths into visible light images that are displayed on a screen. Images can be either monochrome or multicolored where the shades of gray or color represent temperature patterns across the surface of the object. These thermal images can be viewed in real time or stored on videotape, computer disk, or PC card. Thermal images then can be recorded onto photographic film or paper; the images are called thermographs or thermograms. Thermal imaging is both non-contact and nondestructive. Since it is non-contact, it is useful for inspecting energized electrical systems as well as mechanical systems and rotating equipment. Since the infrared energy emitted from a surface is proportional to its temperature, imaging radiometers are capable of providing surface temperatures as well as images.

Ultrasonic Detector An ultrasonic detector senses subtle changes in the ultrasonic signature of a component and pinpoints potential sources of failure before they can cause damage. Longer wavelengths of lower-pitched sounds are gross waves that can be difficult to locate. But higher frequency sounds are short wave signals localized to the source of emission. For this reason, it is possible to use ultrasonic sensors in relatively noisy environments.

Ultrasound and Infrared Working Together Why do infrared and ultrasound work so well together? One answer is to look at our own senses. The more senses we use, the better we are able to navigate through our world. To expand on this concept, infrared inspection and ultrasonic inspection are expansions of the senses of sight and hearing. Infrared "sees" what we cannot see; ultrasound "hears" what we cannot hear. By combining them we advance our ability to detect problems. In essence, infrared will detect changes in emissions related to heat characteristics of equipment it "looks" at, while ultrasound senses changes in sound patterns. Without getting into the basics of each technology, let's examine some of the common areas of application for these two inspection methods.

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Steam Systems There are many opportunities to use both ultrasound and infrared in steam system inspections. A simple way to determine when to use a specific instrument is to look at the system from an objective perspective. Which components have more of a tendency to produce a change that is heat related and which are more sound related? As an example, the loss of or weakening of insulation is measured best by determining heatrelated changes. Pressure is calculated by checking temperature changes upstream and downstream of a valve or steam trap. Sound-related processes are best tested by using ultrasound. Valve leakage, steam trap inspection, and conditions such as cavitation in pumps are examples of sound-related inspection. Heat or infrared alone cannot be used to validate steam trap operation. There are many subtle and not-so-subtle pressure changes that occur in and around the steam trap that can effect changes in temperature which can in turn lead to a false diagnosis. Since a trap produces a distinct sonic signature, listening to the sound of the trap as it cycles can accurately determine the trap condition. Many steam trap manufacturers refer to this as a "positive" test. Infrared is useful in determining blockage conditions and whether a trap is on-line because the former will indicate a lower temperature than a working trap in the same area and the latter will be observed as producing heat. Using both infrared and ultrasound together will help make certain that the most common conditions of trap operations can be thoroughly inspected. Using the two technologies in valve condition inspection also can provide useful information. In some cases, heat can be used to determine valve condition, while in other situations, the fact that a valve leak can be isolated and heard will help improve the accuracy of the diagnosis. By using an ultrasonic sensor's contact probe to touch a valve upstream and downstream, valve leakage or valve blockage can be identified. A leaking valve will be heard through the headphones as a gurgling or rushing sound while blockage will produce no sound. Valve blow-by in steam systems will produce a higher temperature reading downstream. Ultrasound will tend to find smaller leaks, especially when the fluid does not have a higher temperature.

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Loose connections and damaged conductors, electrical problems that produce increased resistance resulting in higher temperature of affected elements, are easily detected by inspection with infrared hermography. (Photo courtesy FLIR Systems, Inc.) Heat Exchangers The two technologies can be utilized quite effectively in the inspection of heat exchangers. An infrared scan of a heat exchanger can indicate heat-related changes that can be diagnosed as anything from flow blockage of the cooling element to tube leakage. Once the condition is spotted with the scan, an ultrasonic detector can be incorporated to confirm a diagnosis and, in some instances, locate a leaking tube. The ultrasonic inspection is performed while the exchanger is either on partial load or off line. By pressurizing, or by keeping a vacuum on the shell side, the headers of the exchanger can be removed and the tube sheet scanned to identify the leaking tube. A leaking tube produces a turbulent, rushing sound as air flows from the high-pressure to the low-pressure side of the tube leak. The sound will be isolated to the leaking tube and will be heard as the scanning module passes over it. Combining infrared and ultrasound provides a fast, accurate way to keep on top of heat exchanger problems. Underground Leaks Underground water leaks of any type are a very difficult proposition. Unless the leak is so gross as to produce an obvious wet pool or bubbling around the site, many days can be spent trying to locate the source. There are often situations in which inspectors have been called to locate a leak after most other methods have failed. This experience indicates that not one method works all the time. However, utilizing ultrasound and infrared together can produce effective results. In an actual event, a condensate return line in a major airport was reported to be leaking. The area of investigation covered about 3 miles of piping located approximately 6 ft below the asphalt surface. Standard methods using listening devices that detected only the audible range were not successful. To find the leak quickly, a method incorporating ultrasound and infrared was devised. Rev 1 06/26/2012

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Recognizing that condensate was heated water, it was determined that a late-night scan would be effective because the heated water would be easier to locate with the cooler ground around it. A scan of the piping system as determined by piping diagrams was performed. Every hot spot that could be suspected as a leak site was marked. Metal wave-guides were then positioned in the ground over the marked hot spots. A contact probe from the ultrasonic detector was placed directly on the wave-guide and an operator listened for a flow. The IR/UL inspection began shortly after midnight and continued until 4 a.m. Identified leaks were repaired before the end of that same day. Motors and Pumps Here we have a combination of electrical, mechanical, and fluid flows that produce heat and sound. While the condition of most bearings can be diagnosed through changes in sound as determined by ultrasound, as well as by vibration analysis, there are also IR scans that detect heat-related problems. According to NASA research, the earliest indicator of incipient bearing failure is a change in the amplitude of a monitored ultrasonic frequency. Ultrasonic inspection also can reveal lack of lubrication and prevent over-lubrication. Bad motor coils, windings, stators, or rotors can cause an increase in resistance and will produce heat that is readily detected with an infrared scan. In addition, over-lubrication, misaligned belts, and bearings in advanced failure states can be quickly spotted due to the heat generated by friction and metal fatigue. Pumps running dry, plugged feeds, and distorted vanes are all candidates for infrared detection. Cavitation, which is caused by air bubbles being trapped in fluid and then bursting under pressure, can destroy a pump or valve over time. Because these bursting bubbles produce a distinct sound, ultrasound inspection can trend the cavitation from onset. As it continues toward destructive levels, there is a combination of sound and heat. Hydraulic Valves and Actuators Heat is a good indicator of a leaking hydraulic valve. The forces of fluid moving through a leak can produce heat as a by-product. This has been a useful effect in aircraft inspection. However, not every leaking hydraulic valve will produce heat, and the proximity of valves in certain configurations can lead to a potentially inaccurate diagnosis due to heat (and in some instances sound) transference. This inspection process can be aided by incorporating ultrasound with infrared. A valve, when leaking, will produce a louder sound downstream. By comparing infrared results and ultrasonic readings taken upstream with those from downstream, an operator can quickly make a positive diagnosis. Electrical Equipment This is the most common area of application. While infrared detects problems related to resistance and heat, the ultrasound detector can be used to locate sonic-related problems.

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Corona and tracking in its early stages do not produce readably detectable infrared emissions but they do produce ultrasound. In addition, with enclosed switchgear and transformers where surface heat cannot be relied upon for diagnosis, scans can be aided by using ultrasound to listen. This can be accomplished by scanning switchgear door seals and air vents while listening to the sonic pattern. Corona produces a steady buzzing sound while tracking has a gradual build-up followed by a sudden drop off of signal. Arcing is heard as sudden starts and stops. Inspection time can be greatly sped up by utilizing IR and UL scanning. Since switchgear can be inspected by scanning doors and air vents, there is no need to open each compartment. In all types of mechanical function, changes in heat and sound are the most reliable indicators of potential problems. Fluid flow patterns, line blockage, and leaking valves and steam traps are best-diagnosed through IR/UL inspection. Hydraulic systems produce sound and heat that can be observed through an integrated approach, as does high voltage equipment. Using IR/UL inspection will allow users to accurately determine the condition of operating equipment as well as identify the location of problems. These two technologies complement each other and advance the goals of condition monitoring programs.

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SPECTROGRAPHIC ANALYSIS Using Oil Analysis for Machine Condition Monitoring Oil analysis can go far beyond simply revealing the condition of the lubricant. Advanced oil analysis techniques are being used to monitor equipment condition. Through the use of these advanced techniques, equipment reliability increases and unexpected failures and down time can be minimized. Many types of abnormal wear can exist inside a piece of machinery. However, there are only a few primary sources of the wear. Problems related to the oil itself may contribute to wear when the lubricant has degraded or become contaminated. Machine condition also can contribute to the generation of wear if a component is misaligned or improperly balanced. Improper use of the equipment, such as overload or accelerated heating conditions, also can generate wear. Here are some examples of types of wear. • Abrasive wear is the result of hard particles coming in contact with internal components. Such particles include dirt and a variety of wear metals. Using a filtration process can reduce abrasive wear that will, in turn, ensure that vents, breathers, and seals are working properly. • Adhesive wear occurs when two metal surfaces come in contact, allowing particles to break away from the components. Insufficient lubrication or lubricant contamination normally causes this condition. Ensuring that the proper viscosity-grade lubricant is used can reduce adhesive wear. Reducing contamination in the oil also helps eliminate adhesive wear. • Cavitation occurs when entrained air or gas bubbles collapse. When the collapse occurs against the surface of internal components, cracks and pits can be formed. Controlling foaming characteristics of oil with an antifoam additive can help reduce cavitation. • Corrosive wear is caused by a chemical reaction that actually removes material from a component surface. Corrosion can be a direct result of acidic oxidation. A random electrical current also can cause corrosion. Electrical current corrosion results in welding and pitting of the wear surface. The presence of water or combustion products can promote corrosive wear. • Cutting wear can be caused when an abrasive particle has embedded itself in a soft surface. Equipment imbalance or misalignment can contribute to cutting wear. Proper filtration and equipment maintenance are imperative to reducing cutting wear. •Fatigue wear results when cracks develop in the component surface, allowing the generation and removal of particles. Leading causes of fatigue wear include insufficient lubrication, lubricant contamination, and component fatigue. • Sliding wear is caused by equipment stress. Subjecting equipment to excessive speeds or loads can result in sliding wear. The excess heat in an overload situation weakens the lubricant and can result in metal-to-metal contact. When a moving part comes in contact Pg 6C-28

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with a stationary part, sliding wear becomes an issue. Providing proper lubrication, filtration, and equipment maintenance can reduce much of the wear that occurs inside of equipment. Potential problems can be identified with predictive maintenance techniques such as vibration, infrared thermography, and oil analysis. By monitoring the equipment's condition with oil analysis, a plant can identify various types of wear and take corrective action before failure occurs. In many cases, oil analysis can identify problems with rotating equipment even before vibration analysis detects it. When an oil analysis condition monitoring program is implemented, it is important to select tests that will identify abnormal wear particles in the oil. When components inside the equipment wear, debris is generated. Identifying the wear debris can establish the source of the problem. Here are some examples of laboratory tests that can help identify wear. • Spectrometric analysis is the most commonly used technology for trending concentrations of wear metals. The main focus of this technology is to trend the accumulation of small wear metals and elemental constituents of additives, and identify possible contaminants. The results are typically reported in parts per million. This technology monitors only the smaller particles present in the oil. Any large wear-metal particles will not be detected or reported. • Particle counting tracks all ranges of particles found in the sample. However, particle counting does not differentiate the composition of materials present. Its main focus is to identify the number of particles in the sample. The results are typically reported in certain size ranges per milliliter or per 100 milliliters of sample. •Direct-reading ferrography monitors and trends the relative concentration of ferrous wear particles and determines a ratio of large to small ferrous particles to provide insight into the wear rate of the lubricated component. This method can be used as a tracking and trending tool, especially in systems that generate a high rate of particles. •Analytical ferrography uses microscopic analysis to identify the composition of the material present. This technology differentiates the type of material contained within the sample and determines the wearing component from which it was generated. It is used to determine characteristics of a machine by evaluating particle type, size, concentration, distribution, and morphology. This information assists in determining the source and resolution of the problem. Each laboratory test has limitations. A well-balanced test package will correctly identify potential problems in equipment. Many of the laboratory tests actually complement each other. The purpose of an oil analysis program should not be to merely check the lubricant's condition. The real maintenance savings from utilizing oil analysis occur when equipment problems are detected. Break-in wear, normal wear, and abnormal wear are the three phases of wear that exist in equipment. Break-in wear occurs during the startup of a new component. It typically generates significant wear-metal debris that will be removed during the first couple of oil changes. Normal wear occurs after the break-in stage. During this stage the component becomes more stabilized. The proportion of wear metals increases with

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equipment usage and decreases when makeup oil is added or oil is changed. Abnormal wear occurs as a result of some form of lubricant, machinery, or maintenance problem. During this stage the wear metals increase significantly. When oil analysis is used routinely, a baseline for each piece of equipment can be established. As the oil analysis data deviate from the established baseline, abnormal wear modes can be identified. Once abnormal wear modes have been identified, corrective action can be planned. Implementation of an oil analysis program with analyses consistent with the goals of the program significantly reduces maintenance costs and improves plant reliability and safety. Lubricant analysis for the purpose of machinery conditioning monitoring is at its best with a significant amount of historical data. It is important to establish a baseline for each piece of equipment. Certain analytical results may change with lubricant oxidation and degradation from normal use; the major changes occur because of contamination from environmental factors and machinery wear debris. The analytical costs of a properly implemented program should be covered by the extension of the lubricant change interval. Increased reliability and availability, and the prevention of unanticipated failures and downtime are added benefits.

Oil Analysis in Machine Condition Monitoring

The role of oil analysis has a varied and inconsistent history. In the petrochemical and power generation industries, oil analysis has been conducted primarily to determine when and/or if an oil change is required. In hydraulic applications, it has been used to control the contamination that jams servo-valves and abrades components, leading to premature component failure. In fleet applications, oil analysis has been applied to determine when additives have depleted, soot is building up in the oil, fuel and/or coolant is contaminating the oil, or abnormal component wear is occurring. Each application is valid and each application provides information to support important, but varied, decisions. In sum, there are three distinct categories, or dimensions, of oil analysis: 1. Fluid health analysis—Oil analysis reveals the general health of oil. The oil’s physical, chemical, and additive properties can be measured and trended to guide decisions about if and when an oil should be changed or regenerated with an additive package. Oil analysis also identifies when the incorrect oil has been added to a system. When oil is degrading abnormally, oil analysis often can determine if the degradation is oxidative, hydrolytic, or from another root cause. In addition to simple oil change decisions, oil analysis supports decisions to change oil base-stock or additive formulation or control the environment in which the oil operates. Machines cannot run healthfully without healthy lubrication, making these decisions imperative to the reliability effort. 2. Contamination monitoring—Contamination is a leading cause of machine degradation and failure. Abrasive particles and moisture combined lead to the generation of the majority of wear in various industrial applications. Also, particles Pg 6C-30

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and moisture contamination strip the oil of its additives and exacerbate lubricant degradation. Contamination monitoring enables the reliability organization to make effective decisions to control this important cause of machine failure. 3. Wear debris detection and analysis—When a machine is ailing, it generates particles. The detection and analysis of wear debris assists in scheduling maintenance actions and in determining the root cause of a problem. An effective program of oil analysis should include a focus on each of the three distinct dimensions of oil analysis. Relying upon oil analysis information simply to guide oil change decisions leaves a tremendous amount of information value on the table about the machine’s health and the interface between the machine and its environment.

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Typical Oil Analysis Report

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PARTICLE ANALYSIS Particle analysis is the second phase of oil analysis. This test evaluates the particulate from 5100 plus microns. A particle count is a totally separate test from the spectroanalysis. In many cases there is no correlation’s between a particle count and the spectroanalysis. Particle Analysis is one of the most misunderstood procedures in oil analysis. It is the purpose of this section to give a clear understanding of what type of particle tests are available, different formats of information and how to interpret the data.

Partic

le Analysis

Two of the most common methods of particle counting are:  Automated Mechanical Method  Manual Optical Method Automated Mechanical Method The most common method is an automated mechanical method. This method employs a particle-counting machine that uses some form of a laser beam or light source to count the particulate. Advantages 1. Easy to perform 2. Requires limited technician training time 3. Provides automatic graphing capabilities 4. Fast Disadvantages 1. Cannot count samples with high water content 2. Some use high dilution factors that decrease accuracy

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3. No identification of particulate composition (What type of particle is it?) 4. Photograph of contamination is not possible Manual Optical Method This method follows Aerospace Recommended practice ARP 598. In this method 50-100 mls of fluid is filtered through a .8 micron guided milipore patch. The particulate are then counted and identified using a high power microscope. Advantages 1. Can count samples with high water content 2. Uses little or no dilution factor to increase accuracy 3. Identifies the type of particulate 4. Photographs of contamination are possible Disadvantages 1. Requires a highly trained staff 2. No automated graphing system 3. Time consuming

Data Reporting Formats The three most common forms for data formats are:   

ISO- International Standard Organization NAS- National Aerospace Standards SAE- Society of Automated Engineers

Once a trend is developed using one type of test method, it is important not to cross methods, using one method one time and the other the next. It is important that the method of testing, optical or laser is known when comparing test results. If there is a big discrepancy between the test results, call the laboratory and see if they can help you find out why.

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FILTER ANALYSIS A filter analysis is used to gain even more insight into the system. The filter collects data with every gallon of oil filtered. By evaluating the residue the filter collects we can:   

Determine system cleanliness Predict failure of components Determine source of contamination from inside or outside the system

The filter analysis is used in the following situations: 1. System is experiencing short filter life. 2. Vibration monitoring system is picking up abnormal vibrations. 3. high pressure differential across the filter 4. Large metal particulate present in the system. 5. Highly contaminated particle count. 6. Failure analysis investigation. The filter analysis picks up where the particle count leaves off. When some components fail they fail in large chunks. These particles are not circulating in the oil, but are picked up by the filter or strainers. Take a roller bearing for example. When it fails the particulate that are generated are too large to be picked up in a spectroanalysis and are usually from 25 to 100 microns in size. These are picked up in the filter and can be evaluated using filter analysis.

The Process The residue is washed from the filter, dried and weighed. It is then evaluated for metal content, organic matter, and foreign contamination. The percent of each contamination is evaluated and reported. MAJOR-40% or more MINOR-20 to 30% TRACE-10% or less The residue is then photographed at 25X, 40X, and 100x magnification. This allows the customer to see exactly what is in the filter. The method of filter analysis was first used on aircraft applications. OAL found it so effective that that started to perform the same procedures to industrial filters.

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Particulate Magnification

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REQUIRED LUBRICANTS The turbine requires a synthetic oil supply, which has been approved by GE for use in the gas turbine engine and which conforms to MIL-L-23699 lubricating oil specifications. Some approved oils that meet this specification are listed in the Table below, Required Lubricants and Consumables, under “Turbine Lube Oil.” Refer to the generator manual (located in the O&M manual) for approved generator lubricating oils. Contact the GE regarding possible use of other oils. The hydraulic system requires hydraulic fluid conforming to MIL-H-17672 and ISO-VG46 specifications. Hydraulic fluids conforming to this specification are listed below. Note: Oil companies reserve the right to revise their specifications periodically. It is essential and a customer responsibility to verify the suitability of oils selected to meet specifications. Required Lubricants and Consumables

System Turbine Lube Oil

Hydraulic Fluid

Hydraulic Fluid (Cont)

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Mobil Jet Oil II

Mobil Sales and Supply Corp. New York, NY

Exxon Turbo Oil 2380

Exxon Company, USA Marketing and Technical Services Houston, TX

Required Quantity 220 gal (832.7 L)

220 gal (832.7 L)

Castrol 5000

Castrol Specialty Products Div. Irvine, CA

220 gal (832.7 L)

Mobil DTE 25 Type 2075 TH

Mobil Sales & Supply Corp. New York, NY

40 gal (151.4 L)

Texaco Rando HDAZ-46

Texaco, USA Houston, TX

40 gal (151.4 L)

Arco Duro AW-46

Lyondell PetroChemical Co. Houston, TX

40 gal (151.4 L)

Exxon Nuto H

Exxon Company, USA Marketing and Technical Services Houston, TX

40 gal (151.4 L)

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SAMPLING & ANALYSIS PERIODS Lube oils and hydraulic fluid being supplied to the gas turbine package must meet the quality standards set by the document in Appendix of the Operation & Manual (O&M) and the LM Series GEK Maintenance Scheduled Maintenance and Troubleshooting Manual. Sampling Point Gas Turbine Sump Gas Turbine Sump Generator Sump Generator Sump Hydraulic Start System, Sump Tanks

When to sample… Weekly Monthly or 700 hrs Weekly 6 months or 4000 hrs

How to test… Check Oil Level Lab Analysis Check Level Lab Analysis

Weekly Check

Level

In addition to the required oil analysis requirements, maintenance personnel may conduct onsite qualitative testing. Note There are no requirements for performing on-site Qualitative Testing by the GE AEP Operation and Maintenance Manual. Should the maintenance department choose to implement a qualitative lube oil sampling/testing program, the following section is excerpts from Naval Ship’s Technical Manual, No. S9086-H7-STM-010/CH-262R5. Qualitative testing may includes the following set of sampling and testing procedures. It is recommended to perform qualitative tests weekly on operating equipment. The following equipment should be on-hand to accomplish testing: 1. 2. 3. 4. 5. 6. 7. 8. 9.

Centrifuge, BS & W Centrifuge Tube, 100 ml Solvent, PD-680 Type II Test Tube Rack Goggles, Safety Bottle, Wash, 500 ml Apron, Laboratory Bottle, 8 oz. Sq. Glass Thermometer, Dial

1 EA 10 EA As Required 1 EA 2 EA 2 EA 2 EA 20 EA 2 EA

NOTE: BIOTEK HISOLV may be substituted for PD-680 Type II solvent.

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Free Water?

Obtain Sample

No

Sample Hazy?

Yes

Sample 120degF?

Yes

Wait 30min

No Sample Hazy?

Heat to 120degF

Yes BRIGHT Yes

Pass LO through Purifier 3 Times

Continue to Purify and Find the Contamination Source

No

Identify Contamination Source?

Log Results

Unsat Sample

Yes

Visible Sediment?

Yes

Passed 3 Times?

No

Log Results

Sample Satisfactory

CLEAR

Yes

Perform BS&W Testing

Log Results

Unsat Sample

Flow Chart for Systems With Online Purification Capabilities

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Flow Chart For Systems Without Online Purification Capabilities

Lube Oil Clear & Bright Test Procedure This test procedure is taken directly from the Naval Ship’s Technical Manual, No. S9086-H7STM-010/CH-262R5. The degree of water and particulate contamination in lube oil samples may be quickly assessed by the Clear and Bright test. Clear refers to the absence of visible particulate matter. Bright refers to the absence of free water, moisture or other factors that affect the color and clarity of the lube oil sample. For example, oil that is free of water contamination appears bright, with no discernable haziness or cloudiness. As the amount of water contamination increases, the sample gradually assumes a hazy or cloudy appearance due to the suspension of tiny water droplets throughout the oil. When the level of water contamination reaches a point where the oil cannot dissolve any additional droplets, the excess water falls to the bottom of the sample and becomes visible as droplets or a layer of free water.

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When performing the Clear and Bright test, the following procedure shall be followed: 1. Obtain a clean, dry 8 oz. square glass bottle and draw a representative sample for inspection. The sampling connection shall be flushed free of any stagnant oil by allowing an amount of oil equivalent to the sample connection volume to drain into a clean container before filing the sample bottle. All condensate in the sump shall be drained off prior to obtaining the sample. Waste oil shall be placed in the settling tank for renovation or properly disposed. 2. Assess the appearance of the sample by holding it in front of a strong light source. Inspect the sample for the bright criterion by observing for any free water, haziness, or cloudiness in the oil. If free water is present, it will be readily apparent as bubbles or a layer on the bottom of the sample bottle. If the oil appears hazy or cloudy, the temperature of the sample shall be checked with a thermometer. If the sample is at operating temperature 1205F (534C) and the sample appears hazy, dissolved air or water may be present; allow the sample to settle at room temperature for 30 minutes. If dissolved air is present, the sample will clear from the bottom to the top. If dissolved water is present, the sample will remain cloudy, or will begin to clear from the top to the bottom. If the sample continues to appears hazy or cloudy after the 30 minute settle time, the oil fails the bright criterion. If the sample came from equipment without online purification capability, conduct the transparency test. If the lubricating oil does not pass the Clear & Bright tests, the transparency test, visible sediment test, and BS&W (Bottom Sediment & Water) tests should be performed.

Transparency Test This test procedure is taken directly from the Naval Ship’s Technical Manual, No. S9086-H7STM-010/CH-262R5. To perform the transparency test, hold a piece of paper with standard size print behind the sample. If the printed words can be read through the sample, the oil passes the Transparency Test and must be checked for the clear criteria. If the card cannot be read through the sample, the oil fails the Transparency Test.

Visible Sediment Test This test procedure is taken directly from the Naval Ship’s Technical Manual, No. S9086-H7STM-010/CH-262R5. This test allows a qualitative assessment of the level of particulate contamination present in a sample, and provides a means of screening lube oil samples prior to conducting further testing. To perform the test, the following procedure shall be used:

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1. If visible sediment is noted, let the sample bottle stand for 10 minutes or until all of the sediment has settled to be bottom. Gently lay the sample bottle on its side for 10 minutes or until all visible sediment has accumulated along the intersection of the side (on which the bottle is laying) and the normal bottom of the bottle. 2. If a solid, unbroken line of sediment is observed along this intersection, or if individual particles greater than 1/8 inch along the largest axis are observed, more testing is required. If a broken line of individual particles is observed, none of which is greater than 1/8 inch along the largest axis, the sample passes the visible sediment test and is satisfactory for us in equipment without online purification capability.

Bottom Sediment & Water Test 1. Obtain two clean, dry centrifuge tubes and fill each with 50 ml of well-shaken sample. 2. Set the tubes in the test tube rack and fill each tube to the 100 ml mark with solvent. Tightly cork each tube and shake for 30 seconds to ensure adequate mixing of the oil and solvent. The cork shall be covered with a thin plastic film (such as cellophane) so that it can be reused. 3. Place the centrifuge tubes securely on opposite sides in the centrifuge and whirl at 1500 rpm for 30 minutes. 4. Remove the tubes and obtain the percent BS&W by adding the readings of the two tubes. 5. At the end of the test, dispose of oily waste and clean the centrifuge tubes with solvent.

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Oil Loss Troubleshooting Chart

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Oil Pressure, Temperature and Flow Chart

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BEARING MAINTENANCE Maintenance technicians at a plant recently witnessed first hand how high temperatures can affect and potentially damage rolling bearings. Bearings in a fan used to evacuate superheated air during a process began to overheat. Bearing temperatures, which normally hovered around 170°F (77°C), climbed to 195°F (91°C). While the fan continued to run, plant technicians consulted with a bearing engineer to devise a solution. But their efforts came too late: by the time the meeting ended, the grease inside the bearing had dried up and smoke had begun to emanate from the bearing, causing shutdown. Failure analysis quickly pinpointed a cause: process temperatures of 1000°F (538°C) or more produced in the process resulted in an ambient temperature of 220°F (104°C). The plant immediately took steps to shield fan bearings mechanically from the worst of this heat. In addition, the "floating" bearing in the fan arrangement was offset in the housing, providing it with more room to travel axially to accommodate shaft expansion. Higher-than-normal operating temperatures, whether caused by ambient conditions or generated within the bearing itself, have the potential to harm rolling bearings. Normal operating temperatures differ, depending on the application. Maintenance technicians should be aware of this and know the common causes of, and remedies for, bearing overheating. Electric Motors The ball bearings used in most electric motors are pre-greased, shielded ball bearings. Normal motor bearing operating temperatures range from 140°F (60°C) to 160°F (71°C). Overheating in electric motor bearings is generally lubricant-related. For example, when re-lubricating open bearings, users may inadvertently employ a low-temperature grease which does not provide adequate viscosity at the normal operating temperature. Or the user may over-grease the bearing, forcing bearing balls to push through excess grease as they rotate, leading to a sharp temperature rise. Another cause of overheating is mixing incompatible greases, which can reduce the consistency of the grease and possibly the overall viscosity. Fans Commercial fans generally utilize ball and roller bearings mounted in cast iron or pressed steel housings. Fans are exposed to a wide variety of ambient conditions, ranging from below-zero temperatures for rooftop fans to extremely high temperatures for fans used in industrial processes. Normal bearing operating temperatures varies, depending on the environment and application. The standard grease in most fan bearings remains effective to an operating temperature of 180°F (82°C). If steady-state operating temperatures are higher than 180°F (82°C), consider using a grease with a synthetic base oil. Viscosity in synthetic oil does not vary as much with temperature as in a standard mineral oil, and the rate of oxidation is much slower. For operating temperatures above 200°F (93°C), a circulating oil system may be needed. These systems pump clean, cool oil Pg 6C-46

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through a bearing arrangement. In hot-gas fans, special measures must be taken to protect bearings from high temperatures. In virtually all cases, an aluminum disk or flinger placed on the shaft between the bearing and the fan casing can act as a heat shield. Often, a blower wheel or compressed air can be used to direct cooling air across the bearing housing or the shaft. Pumps Depending on the application, normal bearing operating temperatures in pumps range from 100°F (38°C) to 180°F (82°C), with most running between 140°F (60°C) and 160°F (71°C). Although grease is used in some vertical pumps, oil is the preferred lubricant in the majority of pump applications. Standard bearing oils in pumps remain effective to approximately 180°F (82°C). If normal operating temperatures are higher than 180°F (82°C), synthetic oil should be used; if temperatures exceed 200°F (93°C), a circulating oil system will probably be required. As in other bearing applications, higher-than-normal operating temperatures in pumps can be caused by bearing over-lubrication. Overheating can also be caused by bearing misalignment or ball skidding within the bearing. Specially designed bearings are available to eliminate ball skidding. Ideally, bearing temperatures in pumps, especially those in critical applications, should be regularly monitored. Gear Drives Bearings in gear drives normally operate at 160° (71°C)-180°F (82°C) and are lubricated with static oil systems. As improved technology permits reductions in the size of gear drives, there is a growing trend to transmit more power through a given size drive than ever before. This practice can cause bearings in gear drives to run hotter and may necessitate the use of alternative cooling methods. Summary In summary, proper bearing lubrication is the primary concern in all high-temperature applications. That concern is heightened by the trend of running industrial equipment at higher speeds than originally intended, further increasing bearing temperatures. The general rule is to provide the minimum viscosity required at the expected operating temperature: 100 SUS (20cst) for roller bearings and 70 SUS (13cst) for ball bearings. In addition, the increased thermal expansion of the shaft must be accounted for both axially (to ensure that high thrust loads are not induced) and radially (to ensure that radial internal clearance is adequate to avoid preload). The solution may also entail using a grease with a synthetic base oil or converting to a different lubricant delivery system, such as circulating oil.

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Single-Point Lubricators In the petrochemical industry, bearing faults drive the majority of repair events for motors, pumps and compressors. In a study performed at 12 petrochemical plants, the data showed that approximately 60 percent of all motor repair events originated with bearing troubles. This number differs significantly for pumps and compressors because of the impact on equipment life due to the performance of mechanical seals. Historical data gathered at these 12 facilities showed that bearing problems represent approximately 70 percent of all repair events for motors and 30 to 35 percent for pumps and compressors. This climbs to 80 percent in equipment that is selected and supplied with lifetime lubrication. When a bearing defect is allowed to progress to a catastrophic failure, the failure will be far more costly. This is because damage tends to grow exponentially with time. As equipment damage grows, so does the potential for extended downtime. Under these circumstances where repeated bearing failures are present due to bearing distress caused by lubrication deficiencies, it should be simple to justify the use of innovative techniques to reduce the number of failures. The single-point lubricator is one method of extending bearing life. This technology was introduced into the petrochemical industry about 30 years ago with mixed results. In recent years, manufacturers have introduced significant technological advances that have increased the life of bearings and the reliability of single-point lubricators. Lubrication by Automatic Single-Point Lubricators Single-point automatic grease lubricators are refinements of the old compression grease cup (Figure 1). Grease cups are small containers filled with grease that are fitted to the bearing.

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The principle of operation is to force the grease into the bearing by turning down the cap or piston covering the grease charge. The next development in this line of products is the springloaded grease cup. The spring-loaded lubricator, a simple refinement of the compression cup, is accomplished by replacing the screw-down cap or piston with a spring-activated, leatherpacked plunger. This plunger, when engaged by the spring pressure, slowly forces grease into the bearing. Neither of the two types of grease cups is recommended for use under conditions of wide temperature variation, where the consistency of the grease may be affected. Single-point lubricators differ from the traditional grease cup by employing either a spring or an expanding gas pressure to exert a force on the cap, piston or diaphragm in contact with the grease volume. These continuous forced grease injection devices are screwed into the threaded grease port. They range in size from 2 to 18 oz. (60 to 250 cc) of grease capacity and can develop pressures as high as 65 psi (4 bar). The original device, as shown in Figure 1, is spring-loaded. The flow of grease is adjusted by the use of a metering control principle. A piston O-ring seal, which creates a changing level of friction as it moves along the tapered wall of the reservoir dome, adjusts the flow. The changing resistance is designed to counterbalance the changing force of the compression spring as it gradually expands. Because the lubricators operate with a single universal spring (other sizes are available) at the lowest reliable pressure (under two psi), no grease is moved into the bearing until it is needed. Variations in discharge flow rate are achieved by inserting different size orifices into the discharge nipple of this field-refillable lubricator. In application, the design is highly affected by the ambient temperature and the age of the grease in the canister. Tests performed by the author on the spring-loaded lubricator showed that in some applications the bearings would be overgreased, while in others, no grease would flow at all.

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The device shown in Figure 2 is a significant improvement on the original concept of the grease cup. Further details in the operation of lubricators of the same design as Figure 2 show a cylinder containing a pressure generator and a piston, which pushes the prepacked lubricant into the bearing in response to the pressure generator. The pressure generator is a rubber bladder containing an electrolytic solution and a sealed plastic tube containing a galvanic strip of specially treated metal. After the injector is installed, the activating screw is used to break the plastic tube. This exposes the galvanic strip to the electrolytic solution, resulting in an electrochemical reaction within the bladder which produces a gas. As the bladder pushes against the piston, the piston pushes the lubricant out of the injector and into the bearing. When all of the lubricant has been expelled into the bearing, the unit expires and is thrown away, and a similar unit is installed. The rate of lubricant ejection is a function of the gas production, which in turn depends on time and rate of reaction. Consequently, the rate of lubricant discharge can be predesigned into this device to accommodate the user’s discharge rate specifications. Should the lubricant discharge flow be restricted due to viscosity increase, hardening of the grease or mechanical restriction in the supply line, the flow will be reduced or stopped. Under these conditions, the gas pressure will increase to a maximum of 136 psi until normal flow is restored. If resistance to lubricant flow is reduced, the lubricant flow will temporarily increase. This will continue until equilibrium between the amount of gas generated and the amount of lubricant discharged is reached. Similarly, as with the older devices, the discharge rates are affected by ambient temperature variations because of the increase or decrease in the speed of the electrolytic action resulting from temperature changes within the bladder. As the temperature rises, the discharge rate increases and as the temperature drops, the rate decreases. A sudden large increase in temperature also causes the lubricant to expand within the unit, which will cause a temporary increase in discharge rate. Conversely, a sudden drop in temperature will cause the lubricant within the unit to contract. This results in a temporary decrease in discharge rate, until the gas production within the bladder compensates for the reduced volume within the unit, resulting from the sudden temperature drop. For lubrication of electric motor bearings ranging from 25 to 400 horsepower, injector manufacturers recommend a unit, which at an ambient temperature of 77ºF (25ºC) would discharge approximately 0.166 cc per day and would be in service for 24 months. Elevation of the ambient temperature to 113ºF (45ºC) would increase the grease discharge rate by a factor of 4 to 0.66 cc per day, resulting in six months of service life for the device.

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Newer electromechanical devices are more sophisticated and capable of delivering lubricant to multiple machine points. A typical cross-section of one such device is shown in Figure 3. These devices consist of a reusable drive motor (battery or direct-wire powered), a refillable/replaceable lubrication canister and a small pumping device. These units can be set for different discharge periods and be turned on and off with a switch. They are also temperature independent and have precise discharge periods. Additionally, some of these units can be connected to a PLC to monitor operating conditions. Newer units are available in capacities ranging from 60 to 500 cc (2 to 36 oz.). The choice of selector switch fixes the rate of gas generated in the electrochemical cell. The dispenser is adjusted to deliver lubricant at the specified rate against atmospheric pressures (14.7 psi absolute). Added backpressure will reduce the discharge rate. Depending on the manufacturer, selected units are capable of developing discharge pressure that exceeds 350 psi (23 bar). Regardless of the type of device selected, questions remain on the appropriate method or technique that should be employed to lubricate bearings. Various user organizations employ different approaches of how to properly apply grease to different bearing configurations. A study of 12 petrochemical facilities showed that lubrication practices for grease bearings of general-purpose equipment varied, from one extreme of having no program for relubrication to the other extreme of employing continuous lubrication via oil mist. Four plants stated they had no lubrication program and ran equipment to failure. Correct grease application is essential to assure that neither excessive nor insufficient grease conditions create component failure. Match the manufacturer’s recommendations for grease volume requirement with unit output when using single-point lubricators. Also consider these conditions:

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Area Classification Make sure that the lubricator you are considering is designed to meet the electrical area classification of the area of the plant where you plan to install it. Overlubrication of Bearings Too much grease in a bearing or its housing causes churning, resulting in a sharp increase in temperature and often, premature lubricant and/or bearing failure. On start-up, greaselubricated bearings expel grease into vacant spaces around the housing. To prevent churning, there must be sufficient empty space in the housing to accommodate this grease. Relubrication volume is application-dependent, but a common rule for grease application is to pack the bearing completely, but fill only one-third of the bearing housing. Underlubrication of Bearings Even with the correct grease in your single-point lubricators, underlubrication can occur. The consequences are excessive heat and eventually metal-to-metal contact between bearing components. Always take into account the changes in ambient temperature at your site. For example, a common practice at a plant using electrochemical devices was to purchase 24month lubricators to be replaced yearly. This was done to compensate for high temperatures during the summer. Failure to Prevent Lubricant Contamination Lubricant contamination is a leading cause of bearing failure. Dirt particles, other contaminants and the application of incompatible grease are all factors that increase equipment failures. The use of two incompatible lubricants will lead to deterioration in lubricating capability. Using the Wrong Seals The use of the correct bearing design (seal and shields) supplemented with a bearing isolator can be the difference between long-term reliable service and a “bad actor.” Review all your applications with the bearing manufacturer to assure an optimum fit. Failure to Relubricate Bearings Even without exposure to contaminants, lubricant quality can deteriorate over time. Although single-point lubricators will continue to operate, failure to keep track of lubricant condition and age can lead to premature equipment failures. Contact the bearing manufacturer for recommendations on optimum lubricant replacement intervals. Failure to Provide Relubrication Training Maintenance technicians commonly receive training on bearing selection and installation, but not lubrication. Ensure that technicians are thoroughly trained in lubrication fundamentals as well.

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Recommendations Lubrication should not be left to chance. Optimized grease lubrication requires knowledge of bearing configuration, lubricant and operating conditions. Single-point lubricators should be selected and applied judiciously to obtain the desired extended equipment life. These lubricators have their place, but cannot be applied indiscriminately. They are quite useful in keeping bearing housing grease cavities full, keeping in mind the importance of bearing design and shield application. It is important to remember that this advantage can become a disadvantage if an overgreasing situation is created. Single-point lubricators are attractive in inaccessible locations. However, inaccessible should not mean forgotten. Climatic conditions and age can lead to changes in grease quality, and eventually to separation problems, which are frequently observed in many plants. It is the responsibility of maintenance professionals to consider the cost of using single-point lubricators for every lubrication point in the plant. One must be cautious of grease compatibility issues when applying single-point lubricators with the refillable feature. The wrong grease or the mixture of incompatible greases can create as much trouble as improper lubrication does. Depending on the application, single-point lubricators can extend the life of rotating equipment and increase reliability while significantly reducing the cost of applying the lubricant. In these days of reduced budgets and staffs, these devices can provide increased long-term service for the general-purpose equipment of the plant.

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GAUGE CALIBRATION Purpose: As an operator, you observe and detect malfunction in operating equipment and take necessary action to prevent damage to the equipment. For accuracy, the best method of observing and detect malfunctions in the operating equipment is through use of indicating instruments, such as temperature and pressure gauges. These gauges range from direct acting, such as ordinary thermometers, to electrically activated resistance detectors. The main function of all indicating instruments is to give information on the operating equipment. When you are operating equipment, these instruments give you the ability to compare normal operating conditions. This comparison permits you to detect damage in equipment. It is important that readings be taken at set intervals. By reviewing operating logs the operator or shift supervisor can determine equipment condition and make corrective actions prior to a component failure. There are many types of measuring equipment found in power generation, auxiliary, and control stations. Calibration: Calibration is a compression of a system or instrument of unverified measurement accuracy to a measurement instrument of known or greater accuracy, to detect and correct any variation from established or required performance specifications. Power plants should have a method for calibration of portable (Torque wrenches, micrometers) and permanently installed mechanical and electromechanical measuring equipment/instrumentation found within your power plant. Example of Instrumentation require calibration:  Pressure Calibrators  Temperature Calibrators  Viscometers  Flash point testers  Standards  Micrometers  Torque Wrenches  Hydrometers  Test Equipment Standard: A standard is a device used to maintain continuity of value in the units of measurement by periodic comparison with higher echelon or national standards. Personnel Requirements Personnel qualified to perform these task do the repair, adjustments, and calibration of portable measuring instrumentation. If you have not established a calibration program, instrumentation should be sent out for calibration. Each plant should have calibrated gauges standing by as spares as gauges fail or used as replacement as gauges are sent for calibration. Pg 6C-54

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Pressure Measurement Pressure Measurement Pressure is one of the broadest and most complex areas in the field of physical measurements. Its large scopes results from numerous and diversified types of instruments, which are used for pressure measurements, while its complexity stems from the many-sided nature of pressure itself. Total pressure is composed of atmospheric and non-atmospheric components. Atmospheric pressure: Produced by the weight of the atmospheric blanket, atmospheric pressure has a pronounced influence on a great variety of phenomena. It directly influences boiling points, density, and deformation. Correction for atmospheric pressure is required in the physical measurement. Non-atmospheric Pressure: The second type of pressure, which is artificially produced to transfer or amplify force to produce work. This is the type of pressure used in a service station to lift a car, in a machine shop to operate a hydraulic press, or in a turbine to power a propeller or generator. We will deal mainly with liquid or gas pressure and it’s measurement. Pressure might be described as force acting over an area. Mathematically the most common equation for pressure is: Where

P=F (1) A F = The force in units of lbs., newtons, dynes

And

A = The area in units of inch2, meter2, centimeter2 P = The pressure in units of lbs/in2, newtons/m2, dynes/cm2

Sometimes difficulty arises regarding the distinction between force and pressure. This generally can be avoided if the reader remembers that pressure describes force acting over a particular area. If we restate equation (1) in terms of force we obtain. F=PA (2) The study of fluids at rest is called hydrostatics. Given a fluid in a state of equilibrium under static conditions, the pressure of the fluid against a point on the surface in contact with the fluid is numerically equal to the normal force exerted by the fluid against a point on the surface. At any given point within a fluid in hydrostatic equilibrium, the pressure is equal to the sum of the external pressure exerted at the top of the fluid and weight of the fluid in a vertical column of cross-sectional until area existing over the point. Under static equilibrium conditions of a fluid without flow, the pressures on every point of a horizontal plane of fluid are equal, and the pressures in any direction about any point are equal. Straight, duplex, differential, compound and vacuum gages are designed for measurement of either a pneumatic or hydraulic pressure medium.

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Red arm Settings:

Some pressure gages and thermometers are provided with an adjustable pointer, which is painted red, in addition to the indicating pointer. The red pointer (Red Hand) is supplied as an aid to the operator. Either the maximum or minimum setting, whichever is most applicable may be selected. Where specified, if the maximum or minimum operating pressures are not available to operators, the Red Hand should be set at maximum or minimum operating pressure (normal conditions) to provide the operator with information

Conversion Factors:

To relate absolute pressure, gage pressure and vacuum, it is necessary to specify the atmospheric pressure that exists at the time and the place of the measurement. Standard atmospheric pressure or barometric pressures (bars) is taken as 14.696 psia, or 760 mm of mercury column at sea level and 0 C (32F). The most commonly used approximations are 14.7 psig and 29.92 inches of mercury column. During the time and at the place of measurements, the atmospheric pressure may vary considerably from the standard pressure. Pressure gages indicate the pressure above atmospheric pressure and usually read in ponds per square inch gage (psig). Low-pressure gages may read in inches of mercury (in Hg) or inches of water (in H2O). When converting gage pressure in pounds per square inch (psi) to absolute pressure in the same units of measurement, add 14.7 to the gage reading. As an example would be a reading of 50-psig equals 64.7 psia. To convert vacuum in inches of mercury to absolute pressure in inches of mercury, subtract the vacuum gage reading from the barometric pressure reading. When converting from absolute pressure in inches of mercury to absolute pressure in pounds per square inch, multiply by the conversion factor 0.4912, as an example, for a vacuum of 14 inches of mercury, with barometric pressure of 16.92 in. HG., MULTIPLYING 16.92 BY THE COVERSION FACTOR 0.4912 EQUALS 8.3-PSIA PRESSURE. Commonly used conversion factors are given. Multiply 1 Atmosphere 1 Atmosphere 1 Atmosphere 1 Atmosphere 1 Atmosphere Feet of Water Feet of Water Feet of Water Feet of Water Inches of Mercury Inches of Mercury

By 29.9231 33.959 14.69595 232.136 1.01325 0.02984 0.88109 0.43275 6.924 0.033864 1.135

To Obtain Inches of Mercury Feet of Water (fresh) Lb/in2 Oz/in2 Bars Bars Inches of Mercury Lp/in2 Oz/in2 Bars Feet of Water (fresh)

Note 1. Inches of Mercury (Hg) shall indicate inches of mercury referred to 0C (32F) one inch of mercury is equal to 0.49115 lb/in2.

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2. Inches of Water (in. H2O) shall indicate inches of water referred to 20C (68F) one inch of water is equal to 0.036063 lb/in2.

Pressure Snubbers: A pressure snubber is a pressure-transmitting device that restricts the rate of the fluid flow to a pressure-sensing instrument and, as a result, the rate of pressure change. Pressure snubber should be used when a gage, transducer, or other pressure sensing instrument is subject to constant and rapid pressure fluctuations or hydraulic shocks which have the potential to damage the pressure sensing element and result in premature failure. In the case of pressure gages, such pressure fluctuations may result in excessive wear to the drive mechanism and rapid pointer oscillation, making reading difficult. A pressure snubber greatly reduces the magnitude of the pressure oscillation and thus prolongs the life of the pressure-sensing instrument.

Snubbers

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Safety:

As with any pressurized system safety is of primary concern. In addition to potential hazards associated with working with a pressurized fluid, there are other cautions that must be observed. These include contamination and reuse. Contamination can occur when a fluid from a calibration system (or reuse from a different application) comes in contact with the internal portions of a snubber, which is intended for use in an incompatible fluid system, e.g oil in gas or water system. The consequences of incompatibility can range from simple contamination resulting in improper snubber action to explosive failure when oil is introduced into an oxygen system. Reuse- It is strongly recommended that the Snubbers not be transferred from one application to another. If a snubber transfer is necessary, then transfer from one application to another should only be done after concerns about chemical and material, viscosity, and pressure compatibility are addressed. In general, the same criteria used to select a snubber for a particular application should be govern its reapplication. There are several indicators of pressure snubber malfunction. These are minimal or no snubbing action, excessive delay in response of the pressure sensing instrument, and lack of response from the pressure sensing instrument. Lack of snubbing action may indicate deterioration of either the porous metal element or the piston. Excessive delay or lack of response is symptomatic of the accumulation of particulates either within the porous metal element or around the piston assembly. If improper operation traceable to the pressure snubber is indicated, then it should be removed and inspected. If the snubber is of the porous metal design, then it should be replaced-it is not practical to clean or repair it. If the snubber is of piston design, then it can be disassembled and cleaned. If required, the piston can be replaced. Even if improper snubber operation is not evident, Snubbers should be inspected annually for proper operation.

Pressure Gage Calibration:

Pressure gages are most often calibrated by adjusting their mechanisms so the pointer gives accurate readings over the range of the gage. The accuracy is determined by testing the range against a standard pressure at several points up to full scale, then rechecking as the pressure is returned to zero. Some recommended practices are:  Cycle the gage twice to full scale prior to testing.  Test gage at 25% increments to full scale, and 25% increments downscale, including normal operating pressure.  The applied pressure should not exceed the test point when using upscale or down. If it does, return to the previously checked point and continue from there.  Test readings should be taken after the gage is lightly tapped near the center of the dial in order to minimize fraction errors.

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C-Type Pressure Gages: The C-type Bourdon tube named for its shape is constructed of a Bourdon tube connected by mechanical linkages and gearing to a pointer. The movement of the pointer with respect to a fixed dial indicates pressure changes with graduated markings representing magnitudes of pressure.

Bourdon Tube Gage

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As an example Military Gage accuracy are as follows: 2 inch dials 2 ½ inch dials 3 ½, 4 ½, 8 ½ inch dials

+/- 3% of span =/- 2% of span +/- 1% of span

Pressure Transmitters: Pressure transducers are sensors that convert a measured pressure into an electrical output signal that is proportionate to the input pressure. Some typical use of pressure transducers are used in industrial environments where a remote reading of a pressure indicator is required, or when an electrical signal representing a pressure is required for input into a control system, or data acquisition system, or a data recording devices. Capacitive Element- a diaphragm positioned between two fixed plates is deflected, causing capacitance change in two circuits. If the dielectric of the capacitor is maintained constant or compensated for, a highly stable very repeatable transducer is achieved. Small displacement of the capacitor-diaphragm is a major inherent advantage. Variable Reluctance/Inductive Sensors- a pair of coils excited by a carrier frequency is influenced by changes in magnetic coupling of a pressure driven armature, which displaces or rotates between two coils. The following two basic designs have developed around the variable reluctance design. BI-metallic Thermometers- Consist of two dissimilar metal strips fused together in a spiral or helix configuration. The spiral-sensing element is enclosed in a protective metal tube with one end of the element affixed to the close-end of the tube and a pointer stem and pointer attached to the other end of the element. The helical element and likewise the indicating pointer will rotate as the dissimilar metal strips thermally expand or contract at different rates. The pointer and temperature scale dial are housed in a circular metal case, which is affixed atop a sensing.

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BI-metallic Thermometers

Filled System Thermometers Bi-Metallic Thermometers Calibration: The calibration method for bimetallic thermometers is dependent on the stem size; most thermometers are calibrated with a dry well temperature calibrator. The gage is calibrated at 1/3 increments of the total free scale. Based on manufactures tolerances most gauges are calibrated at +/- 1 % of total free scale. Resistance Temperature Detectors: The RTD’s operate on the principle that electrical resistance changes in a predictable manner with temperature changes. The elements of RTD’s are made of nickel, cooper, or platinum. Nickle and cooper are used for temperatures of 600 F or lower. Platinum elements are used for temperatures of 600 F or greater. Thermo wells protect sensors from physical damage by

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keeping them isolated from the medium being measured. This also lets you replace the element with the system running. Which makes life a lot easier and less messy. As temperature increases around an RTD, the corresponding resistance will also increase at a proportional value. You can find the resistance values within the manufactures technical manual. The most common method of heating an RTD is use of heated water bath and calibrated thermometer. The most common fault you will find with an RTD will be either a short circuit or an open circuit. You can quickly diagnose these faults by using digital display readings or data log printouts. By observing the reading or the printout, you may find that the indication is either zero or a very low valve. A malfunction of this type means a short circuit exists in either the RTD or its associated wiring. A very high reading, such as 300F on a 0F to 300F RTD could indicate an open circuit. Transducers: Transducers are devices that receive energy from one system and retransmitted it to another system. The energy retransmitted is often in a different form then that received. A pressure transducer receives energy in the form of pressure and retransmits energy in the form of electrical current. Transducer allows monitoring at remote locations on the gas turbine propulsion plants. Mechanical gages provide pressure readings at the machinery locations or on gage panels in the immediate area. Pressure transducers are generally designed to sense absolute, gauge, or differential pressure. The typical unit receives pressure through the pressure ports. It transmits an electrical signal, proportional to the pressure input, through the electrical connector. Regardless of pressure range of a specific unit, the electrical output is always the same. The electrical signal conditioners before being displayed on an analog meter or a digital readout located on control panel. Pressure transducers should be calibrated on a bench before installation.

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GEK 105059 Maintenance Considerations

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SECTION 6D LM6000 ENGINE CHECKS

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GEK GENERAL CHECKS AND INSPECTIONS This section provides general guidelines, conditions, and definitions for conducting engine checks and inspections. Preventive maintenance and servicing inspections and checks are performed to reduce unscheduled shutdown time. If the frequency of inspection/service requires change, coordinate with the packager. The table below illustrates a sample of checks and service intervals. Maintenance work packages (WP) are found in the GEK 105059. Preventative Maintenance and Servicing Checks

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Preventative Maintenance and Servicing Checks

Additional Preventative Maintenance and Servicing Checks from Svc Letter 6000-05-03 Sprint nozzle clean, flow and Every 25,000 hours of WP 1916 00 inspection at authorized repair source SPRINT operation High pressure compressor variable compressor vane bushing replacement

Every 12,500 hours

WP 1412 00

Additional Recommended Checks from Service Letter 6000-05-03 Starter carbon seal cleaning Annually WP 2813 D/E Sump drain interface cleaning Annually N/A (disconnect package drain to clean engine and package drain as required) Fuel nozzle (PA or PC). Clean, flow At hot section interval (PA & PC) WP1510, and inspect at authorized repair source WP1511, WP1512, WP1513, WP1514 Pg 6D-4

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SECTION 6E GENERATOR CHECKS

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SECTION 07 BORESCOPE

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GAS TURBINE BORESCOPE This chapter will cover object damage and borescope inspection of the LM series engine. The majority of this chapter deals with the LM series engine damage evaluation. The last part of this chapter is on proper preservation and corrosion control methods for maintaining turbines in peak operating status.

Object Damage There are two basic types of object damage maintenance personnel will see. One of the most damaging gas turbine casualties, and one of the easiest to prevent, is foreign object damage (FOD). In this section we will discuss the hazards of FOD and some of the ways to prevent it. The other type of object damage that can cause failure of a turbine is domestic object damage (DOD).

Hazards The effects of object damage and the hazards involved vary greatly with the size and location of the object ingested. Small dents and abrasions may cause little or no damage. However, if the engine ingests a large enough object, severe internal damage will result. Large, soft items (such as paper) can clog the FOD screen, causing a loss of power and elevated turbine inlet temperatures. The other type of damage that was mentioned is domestic object damage (DOD). DOD occurs when an internal object from the engine breaks loose and causes impact damage to the engine.

Prevention To prevent FOD to engines while working in and around intake and plenum areas, you and your personnel must observe the following safety precautions: 1. When performing maintenance inside the intake areas, always-follow all written guidelines found in the plant SOP’s. 2. Remember to remove all loose objects from your person. You must also account for all tools and equipment used in the intake. 3. After completing your work, inspect the intake for cleanliness, and re-inventory the tools and equipment before securing the accesses. 4. Periodically inspect all intakes for cleanliness, the state of preservation, and the condition of the FOD screens. 5. Correct any abnormal conditions.

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The frequency of inspection will depend on the operating conditions, Planned Maintenance (PM) requirements, and Standard Operating Procedures (SOP’s). Remember, the PM’s only provides minimum standards. PM’s can always be exceeded if you or your supervisors deem it necessary. To prevent DOD damage, maintenance personnel need to follow a strict regiment of cleaning and inspections (internal and external). This attention to detail, as described in the next four paragraphs, is absolutely necessary to avoid DOD damage. 1. Make sure the engine is properly cleaned inside and out. Always following the standards in the work package PM’s and the manufacturer’s technical manual. Cleanliness is an important factor in the fight against corrosion. Corrosion control (discussed later in this chapter) also can reduce the chances of component failures that can lead to DOD. 2. Perform frequent external and internal GTE inspections to reduce the possibilities of DOD occurrences. GTE external inspections are very important. Locating loose, missing, or broken external components (VSV retaining nuts) during these inspections is a significant factor in preventing damage. 3. Using borescope inspections aids in determining the extent and prevention of DOD. The most frequent damage is identified as potential component failures (blade stress cracks). 4. Ensure all LM Series Engine GEK Interim Change Notices are implemented. This document is sent out by GE AEP to update the GEK operation and maintenance manuals. These changes are implemented for a variety of reasons, all to upgrade dependability. a. The maintenance department will need to ensure that pen updates are made to the appropriate documentation or replaced as necessary. b. The interim change notices will be sent out hard copy and/or on updated GEK CD Rom.

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Sample Of Interim Change Notice Rev 1 06/26/2012

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Sample Of Interim Change Notice

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BORESCOPE INSPECTIONS Borescope inspection requirements and procedures are found on the Maintenance Work Package (WP 4015 00) found in the GEK manual. These instructions contain all the basic information necessary to conduct an inspection. Included in the Work Package are the serviceability limits and a list of conditions that require an inspection. Borescope inspections are usually performed semiannually or when the engine has been operated beyond the allowable limits listed on the Work Package.

General Inspection Procedures It is a good practice to review the machinery history of an engine before you conduct an inspection. Various component improvement programs will eventually effect all engines in service. A rebuilt or modified engine may contain improved parts that differ from the original. An example of this is the combustion chamber upgrade. If you review the machinery history, you will discover the status of those parts that have been changed or modified. Assuming that the engine history is normal and FOD is not suspected, you should be aware of the following factors when conducting a borescope inspection: 1. 2. 3. 4. 5. 6. 7. 8.

Know your equipment. Locate all inspection areas and ports. Review previous borescope report Establish internal reference points. Scan the inspection area thoroughly in an orderly manner. Note any inconsistencies. Evaluate the inconsistencies. Report your conclusions.

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GEOMETRIC ORIENTATION OF THE ENGINE To communicate information about an engine inspection, you must establish a geometric frame of reference for the engine assembly. A language for describing the physical damage is also necessary. An example of this information is provided in geometric orientation of the LM6000 below.

Engine Orientation – Aft Looking Forward

Geometric orientation of the borescope Pg 7-8

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Circumferential

R a d i a l

Axial

12 11

1

3 2

4

1

2

3 10 AFT 4 9 8 5 7 6

Clockwise

Fwd to Aft

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The figure to the left shows an example of radial and axial cracking on a compressor blade. The figure below shows an example of circumferential and axial cracking in the combustion section. A listing at the end of this chapter provides a list of condition codes and definitions of terms that you need to know when inspecting an LM series engine.

Radial & Axial Cracking On Compressor Blade

Circumferential And Axial Cracking In The Combustion Section Pg 7-10

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INDEXING AND ROTATING THE ENGINE There are two ways to rotate the high-pressure rotor assembly of the engine during borescope. Either by hand with a ½” drive wrench or a motorized electronic turning tool with adapter. The borescope drive pad to rotate the high-pressure rotor is found on the backside of the accessory gearbox (AGB). This drive pad may be utilized as an accessory drive. If so, the accessory must be removed for access to the pad.

Accessory Gearbox Borescope Drive Pad

To rotate the low-pressure rotor assembly an individual, other than the one conducting the borescope, will be required to utilize a strap wrench to turn the drive shaft between the turbine and generator. Due to the location, it is recommended that two-way electronic communication (radios) be established.

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Future Drive Turning Tool Kit

ELECTRONIC TURNING TOOL A fully programmed electronic tool is available that automates the process of engine rotor shaft positioning during borescope inspections for various types of turbines. Benefits: 1. One-person operation. 2. Inspection time is reduced. 3. Inspection accuracy (& thoroughness) is increased. 4. Damaged blades can be flagged and quickly relocated for re-inspection. System consists of three components: 1. Main power unit. a. Provides power to the controller and drive unit. 2. Drive unit. a. Attaches to the engine Accessory Gearbox drive pad to rotate the engine rotor assembly. 3. Controller a. Hand held controller used to jog/rotate the engine rotor assembly.

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CONTROLLER LCD Status Display Consists of 4 Lines ENGINE: displays the engine type selected STAGE: displays the stage selected and at the end of the line the # of blades in that stage. MODE: displays the mode being used. STATUS: displays status messages on operations and at the end of line display an F if the current blade is flagged. Mode Select Knob Engine- Used to select the Engine that is being Borescope inspected. Stage- Used to select the stage of the engine to be inspected. Future Drive Controller

Jog- Used to jog the engine back and forth and used to set the zero point. Blade Move- Used to move from blade to blade.

Drive Unit

Blade flag- Used to flag particular blades for re-inspection during the inspection of a particular stage. Interval- Used to perform an automated blade move with a particular interval between blade moves. Go To Blade- Used to select and move to a particular blade. Speed- Used to select a speed between 1 and 99

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Engine Turning Pad Locations For HP Rotor Borescope Inspections Detailed procedures are provided for indexing and reference point for distress reporting for each stage in the GEK maintenance work package 4015 00. During rotation of the engine, you should not concentrate on counting the blades. Instead, concentrate on the specific condition of each airfoil. Accessory drive gear ratios are listed below. All reference RPM’s in the figure below are based on an HP compressor speed of 10,000 RPM’s. When rotating the wrench by hand, calculate the drive pad ratio to establish how many full arcs of the ratchet wrench are required to move the main rotor one full revolution. For example, when you are using the aft drive pad, a 240-degree revolution of the input drive pad equals 360 degrees on the main rotor.

Accessory Gearbox Layout

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Indexing The HP Compressor Rotor To The Zero Reference You may find the compressor rotor zero reference by use of the locking lugs on the compressor blades. It is important to use a standardized reference to be able to map/record findings. 1. Gain access through the borescope port through the 11th stage bleed air manifold. 2. Rotate rotor clockwise (forward looking aft) and use the borescope probe to view stage 12-rotor blade platform. Locate the first blade to the left of the locking lugs. See figure below. 3. Position this blade in line with leading edge of stage 12 stator vane (as viewed through the borescope) Identify this blade as blade No.1. 4. The HPC rotor is now zero-referenced for all stages of compressor and HPT rotor blades. Inspection of each applicable stage must start with HPC rotor position back to Zero reference point at stage 12.

Hp Compressor Zero Reference

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BORESCOPE EQUIPMENT A borescope is used to inspect internal parts on an engine without having to disassemble the engine. This instrument helps a great deal during inspections and estimating the amount of repair work needed and the time required for the repair Borescopes are the ideal choice when straight-line access to the area of interest is available. These rigid instruments use an optical lens system to transmit an image from the inspection area back to the eye and a non-coherent fiber bundle to illuminate the object. Their ease of use ensures a straightforward inspection solution with minimum set-up. Most borescopes have the following basic components: 1. Eyepiece (zoom or wide angle) 2. Scan control ring 3. Probe 4. Scan mirror 5. Lamp 6. Focus control ring 7. Other electrical accessories As with any optical instrument, you should handle the borescope with care to avoid damaging its lenses and mirrors. The borescope is powered by alternating current. So, before you first use it, be sure to read and follow the manufacturer’s operating instructions. There are numerous types of borescope equipment, depending on manufacturer and cost considerations. Illustrated below are two different types of borescope equipment.

Typical Borescope

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Video Probe XLPro Borescope

Borescope

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Flex Borescope

Flex Borescope

Borescope Light Source

Fiber Optic Cable

Borescope Equipment: Viewing Probes: Probe # I (Yellow) Used for all inspections requiring GREATER MAGNIFICATION Magnification Factor: 1:1 @ 7” Field of Vision: 35 Focus Adjustment: ADJUSTABLE using the knob Rev 1 06/26/2012

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Borescope Equipment: Viewing Probes: Probe # II (Red) Used for All INITIAL Inspections Magnification Factor: 1:1 @ 2” Field of Vision: 62 to 64 Focus Adjustment: FIXED

Borescope Equipment: Viewing Probes: Probe # III (Green) Used for Combustion Outer Liner and Blade Tip Inspections Magnification Factor: 1:1 @ 2” Field of Vision: 62 to 64 Focus Adjustment: FIXED

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Probe # I

Probe # II

Probe # III

YELLOW 90o Viewing Angle

RED 100 Viewing Angle

GREEN 70o Viewing Angle

o

Bending Section

Focus Adjustment

Eye Piece Flexible Insertion Sheath

Angle Knob (Right-Left)

Angle Knob (Up-Down)

Light Source Cable

Typical Flex Borescope Probe Rev 1 06/26/2012

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Bending Section

Forward Viewing Adapter

Side Viewing Adapter

Positioning Slot

Light Guide Window

Objective Lens

Flex Probe Tip with Changeable Viewing Adapters

Magnification Adapter

Angle Attachment Video Camera

Borescope Attachments

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VIDEO PROBE BORESCOPE EQUIPMENT

Video Probe XLPro Borescope

System Features Temperature Warning System and Interchangeable Probes

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Borescope PC Connectivity Capabilities

XLPro Borescope Insertion Tube

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Video Probe XLPro Borescope Insertion Tube Probes

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LM6000 BORESCOPE PORTS Low Pressure Compressor (Right Side) S4-1

VIGV- Variable Inlet Guide Vanes

S4-2

Low Pressure Compressor

S4-3

Low Pressure Compressor

S4-5

Low Pressure Compressor

Low Pressure Compressor (Left Side) S4-4

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VIGV- Variable Inlet Guide Vanes

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High Pressure Compressor (Right Side) S5-0

0 Stage Rotor Blades

S5-6

6th Stage Rotor Blades

S5-8

S5-12

8th Stage Rotor Blades (8th Stage Bleed Manifold) 9th Stage Rotor Blades (8th Stage Bleed Manifold) 12th Stage Rotor Blades

S5-13

13th stage Rotor Blades

S5-9

High Pressure Compressor (Left Side) S5-1

1st stage Rotor Blades

S5-2

2nd Stage Rotor Blades

S5-3

3rd Stage Rotor Blades

S5-4

4th Stage Rotor Blades

S5-5

5th Stage Rotor Blades

S5-7

7th Stage Rotor Blades (7th Stage Bleed Manifold) 10th Stage Rotor Blades

S5-10 S5-11

12th Stage Rotor Blades (11th Stage Bleed Manifold)

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High Pressure Turbine & Combustor (Right Side) S6-1

Combustion Chamber (UV Sensor)

S6-2

Combustion Chamber (Upper Igniter)

S6-3

Combustion Chamber (Lower Igniter)

S7-1

High Pressure Turbine

S7-2

High Pressure Turbine

High Pressure Turbine & Combustor (Left Side) S6-4

Combustion Chamber

S6-5

Combustion Chamber

S6-6

Combustion Chamber (UV Sensor)

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Low Pressure Turbine S8-1

(P-48 Probe) Low Pressure Turbine

S8-2

Turbine Rear Frame

S8-3

Low Pressure Turbine

S8-4

Low Pressure Turbine

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SERVICE LIMITS This section discusses the types of damage that you might find when conducting a routine inspection. This material will be limited to a discussion of the major engine areas. Service limits are listed in WP 4014 00 and define the extent of damage that is acceptable for continued operations, on-site maximum repairable limits and on-site corrective action.

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Impact Damage

Blade Dent

Gouge

Impact Damage (Torn)

Blade Loss

Impact Damage (DOD)

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COMPRESSOR Compressor Section You should inspect the compressor section for nicks and dents, cracks, spacer rubs, casing rubs, blade tip rubs, bent edges, missing pieces, and trailing edge erosion. Inspect the firststage compressor mid-span damper for leading edge dents and other types of defects.

Airfoil Surface Defects Surface defects are the result of object damage or adjacent blade interference (tip clang). Impacts in the center section of the airfoil are not common. Tip clang damage is the result of a blade leading edge tip contacting the adjacent blade tip at approximately one-third of the chord length forward of the trailing edge on the low-pressure (convex) side of the blade. This is the result of compressor stall.. You should report any observed defect on the airfoil surfaces in the inspection record. Your report should contain information relative to the stage, location on the blade (estimate the percent of chord and span), and the condition of the surrounding airfoil. You do not have to record the appearance of the defect (sharpness and contour). Compressor stall is one of the worst things that can happen to an engine. Tip clang damage is difficult to spot and gives the appearance of minor damage. The V-shaped notch on the top of a blade caused by tip clang is only an indicator; it in itself is not the damage. The damage is at the blade root and normally cannot be seen. If a blade has been overstressed, it must be replaced.

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Compressor Rotor Blade Tip Clang Damage.

Platform Shingling (Overlapping)

Platform Fretting (Bowed)

Platform Distortion. Compressor blade platform fretting or shingling can be observed on some after stage blades. These distortions are the overlapping of one blade platform mating edge with the adjacent platform edge. When shingling is found, the platforms will be distorted and bowed. When the platforms are shingled, only the locking lug blades will exhibit this defect. Monitor this condition to see if a platform crack develops. Also look for missing pieces around the locking lugs. You must report and record any cracks in the platform. Be sure you have included the following information: 1. The stage 2. The number of blades

Midspan Shroud Wear Some stage 1 HP compressor blades show wear at the mating surfaces of the midspan damper shrouds. Wearing of the tungsten-carbide wear coat causes the mating face contour to change from a straight line to a stepped line. This occurs at the after edge of the clockwise blade midspan (trailing edge) and the forward edge of the counterclockwise blade midspan shroud (leading edge). In the step area, some metal maybe turned or protruding from the midspan

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shroud mating line (mushrooming). This protrusion is indicative of wear-through. A missing pad on one face would initiate an accelerated failure of the mating surfaces.

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Compressor Blade Midspan Damper Carboloy Pad.

Blade Deposits Compressor blades and stator vanes exhibit varying degrees of cleanliness. Variables such as air-inlet configuration, ambient atmospheric conditions, and air contaminants (chemicals, salt, dirt, water, and so forth) all tend to affect the surface condition of the compressor rotor and stator blades.

Airfoil And Tip Cracks Cracks in the compressor hardware are difficult to detect because they are tight and shallow in depth. You can miss these subtle effects because of deteriorated borescope optics or if you rotate the rotor too fast. You should record all crack information relative to the stage, area, magnitude, direction, and adjacent blade condition.

Cracked Dovetail A cracked dovetail of a blade may lead to blade loss. The location of the blade will determine the extent of engine damage. Before the actual catastrophic failure of the blade, the separated crack in the dovetail will be evident by a leaning blade platform. You can find this fault by using the borescope to inspect each blade platform. The leaning blade platform will be higher than the adjacent nonleaning blades. e A "leaner" is a blade that has a crack on the aft ide of the dovetail and is leaning in the forward direction (fig. 2-12). If a leaner is detected, it must be verified and the engine should be removed from service. Airfoil and Tip Tears.- The most critical area of a torn blade is the area around the end of the tear and its location on the airfoil. You should inspect this area for cracks that lead from the tear and are susceptible to propagation. This condition could lead to the loss of the airfoil section that would create downstream impact damage. You should record all information such as stage, blade locations, area of the blade in which the defect was found, and the condition of the rest of the airfoil and adjacent airfoils. Section A of figure 2-11 shows the nomenclature of a blade.

Leading And Trailing Edge Damage FOD and DOD can cause random impact damage throughout the compressor rotor stages. The leading and trailing edge of an airfoil is the area of the compressor blade extending from the edge into the airfoil. You must assess both sides (or faces) of the airfoil when determining the extent of a given defect. If you observe a defect, estimate the percentage of damaged chord length. Observe the defect and the condition of the airfoil area around the defect. If the observed damage is assessed to be "object damage," the most difficult determination is the differentiation between cracks, scratches, and marks made by the passing objects. Cracks are usually tight in the airfoils, but the apex of the damage usually allows viewing into the airfoil

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thickness. This provides a direct inspection of the area around the crack You may have to use all the probes at varying light levels to determine the extent of the damage.

Tip Curl Compressor rotor blade tip curl is a random and infrequent observation. Tip curl is usually the result of blade rub on the compressor case. Tip curl also can be the result of objects being thrown to the outer circumferential area of the flow path and then being impacted by the rotating blade tip (either leading or trailing edge). These curled tips are usually smooth in the bend area of the airfoil distortion. However, you should inspect the area at the change in normal airfoil for tears or cracks. When you report tip curl, estimate he percent of the chord length, the number of blades with curl, and the condition of the adjacent airfoil area. Record any evidence of impact and inspect for the origin of the impact. Always look at the adjacent blades for evidence of tip clang.

Missing Metal Missing metal from compressor rotor blade airfoils is a result of the progression of cracked or tom airfoils that release part of the airfoil into the flow path. Crack propagation in the root fillet area can result in the separation of the entire blade. Severe FOD or DOD may result in several random rotor and stator airfoils with missing metal. The inspection report hould include the stage, the number of blades with missing metal, the amount, and the location on the airfoil. Estimate the percent of chord, the span of the airfoil that is missing metal, and the condition of the remaining airfoil.

Airfoil Powdering Compressor rotor blades may have aluminum particles visible on the airfoils in varying degrees (from stage to stage). This powder is indicative of a possible compressor stall or a hard blade tip rub.

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COMBUSTION SECTION Inspect the combustor for eroded or burned areas, cracks, nicks, dents, hot streaks, flatness of liners caused by hot spots, blocked air passages, and carbon buildup. If damage is found in the combustion section, it usually consists of a burn-through in the dome area adjacent to a fuel nozzle. The problem can usually be traced to a loss of film-cooling air caused by upstream debris or to a faulty fuel nozzle. Cracking is not normally a problem, but you should photograph and report any suspected or confirmed cracks. Carbon deposits around the fuel nozzles occur on all engines and are not considered serious. These deposits build up only on the venturi and swirl cup rather than on the shroud or discharge orifice. They do not usually interfere with the fuel spray pattern. If you find cracking, evaluate it to ensure that no pieces will detach and cause any secondary damage to the HP turbine.

Combustion Section Damage In the following paragraphs, we describe some of the damage that you might find during a borescope inspection of the combustion section. Because the dark surfaces in the combustion section absorb light, you will need a 1,000-watt light source for a proper inspection.

Discoloration Normal aging of the combustor components will show a wide range of color changes. This is not a cause for concern. As operating time is accrued on the combustor assembly, an axial streaking pattern running aft of every other circumferential fuel nozzle will occur. On lowtime assemblies, the coloration is random and has little or no information to aid you during the inspection. As operating time increases on the assembly, you will observe significant deterioration at the edges of the streaking patterns. Cracking will begin in the forward inner liner panels and will propagate aft. The axial cracks tend to follow the light streaks. Panel overhang cracking and liberation usually occur at the edge of the streaks.

Riveted Joints(LM2500 Series Engines) The dome band and the inner and outer liner assemblies are joined by rivets as shown in figure below. The presence and condition of the rivet heads and rivet holes are easily assessed because of their position in relationship to the borescope ports. Record any missing rivets and torn or cracked hole edges.

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Combustion Liner Dome Rivet Joint.

Dome Assembly Distortion of the trumpets and/ or swirl cups is random and occurs on high-time assemblies. Record the distortion (in percent) of the edge and/ or span of the trumpet and the percent of circumference versus diameter of the swirl cups.

Combustion Liner Dome Band And Plate Cracks.

Cracking in the dome band area occurs at relatively low operating time. Record the number of cracks and their relationship to one another. Indicate if these cracks are parallel, T-shaped, circumferential or angled to connect and separate part of the band, and so forth.

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All the missing metal areas or burn-through must be recorded. For the dome bands, estimate the magnitude by the number or partial/ circumferential span of the dimples and axially by percent of span of the band overhang to the trumpet. Record the trumpet areas of burn-away and burn-through of the dome plate around the swirl cups. Burn-through in the combustor dome will reduce cooling flow to the HP turbine vanes. Monitor the HP turbine vane condition as burn-through progresses.

Igniter Tubes And Ferrules Inspect the two-igniter locations for the condition of the weld at the cutaway of the trumpet and the dome band. The ferrules are visible from these ports. Record the condition for evidence of cracking, loss of ferrule metal, or both. Cracking from the igniter tube aft to the panel overhang is common.

Combustion Liner Dome Igniter Tube.

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Inner And Outer Liner Assemblies You can inspect all areas of the inner and outer liner assemblies aft of the fuel nozzles by rotating and tilting the probe, and by varying the immersion depth. Some of the damage that you may find is described in the following paragraphs.

Circumferential Cracks The figure below shows an example of circumferential cracking on a high-time combustion liner. This type of cracking occurs over the area of the inner liner stiffening bands. The bands are viewed through the borescope inside the combustor assembly. Before actual cracking, the thermal working of the liner shows stress lines. These lines will be visible in all panels. Take care to inspect for the presence of cracks, not merely lines. A crack will be open and the separation will show an edge. The distortion occurs so that the inner liner lifts up into the flow path and the outer liner bends down into the flow path. These irregularities are usually obvious when the liners are viewed through wide angle probe No. 2. When circumferential cracking is observed, record the band number and the span of the cracking relative to the number of cooling/ dilution holes. Use the diameter of the cooling holes as a comparative measurement gauge.

Inner/ Outer Liner Cracks

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Axial Cracks Axial cracking usually starts at band No. 3 on the inner liners and propagates aft and forward. As operating time is accrued, these axial panel cracks grow into three-legged cracks as seen in figure above. The edges of these cracks will separate and the corners will lift into the flow path. Inspect the areas aft and forward of these cracks, recording the axially separated cracks that show a tendency to grow together. DOD is the primary cause of damage to the HP nozzle and turbine rotor elements. It is caused by pieces from the combustor liners cracking out of the panel overhangs and impacting with the rotating turbine elements. The most serious problem is the separation of a large section of liner that could cause significant damage. This usually occurs as a result of axial and circumferential cracks growing together as shown in the figure above. It is important to record the damage to adjacent areas of about 5 inches to either side of the damaged area. These areas can grow together and liberate large pieces of material. These circumferentially spaced, cracked areas are usually separated at every other fuel nozzle spacing along with axial color streaking.

Inner/ Outer Liner Burns and Missing Metal

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Missing Metal And Burn-Through Inspect for the loss of metal at the panel overhang and the area between dimples. Bumthrough of the liners is not common. What is common are the bluish-black slag areas that show roughness and appear to be oxidized. Inspect these areas carefully for T cracks because they will propagate and open up.

Distortion Distortion or bowing of the liner assemblies is extremely difficult to assess when viewed through the borescope. If an axial streak (gutter) is observed to be out of contour, estimate the relative distortion in terms of dimples spanned or in relation to the diameter of the dilution holes. If the distortion is present at the No. 1 band, estimate the contour change at the dome band relative to the panel.

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Borescope

Pg 7-41

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HP TURBINE Inspect the HP turbine for eroded or burned areas, cracks or tears, nicks or dents, and missing blades. Knifing (erosion resulting in sharp edges) can occur on first-stage blades. The severity will vary according to the cleanliness of the turbine inlet air. Check for pitting on the leading edge near the root of the second-stage blading. Cracking of the first-stage nozzle guide vanes is not very common, but photograph and report any suspected cracks. First-stage vane surfaces at the juncture of the inner and outer platforms have a tendency to corrode or erode. It would not be unusual for you to find several small penetrations in a vane platform during its service life. Most of these penetrations remain small and are not usually severe enough to warrant engine replacement. Record any such penetrations and regularly inspect them for any changes in size or quantity. Vane HP (concave) surfaces will show gradual erosion with time, and the trailing edge slots will become elongated. When this degradation reaches maximum service limits, as noted on the PMS card or in the manufacturer's technical manual, the engine must be replaced. HP turbine second-stage blades have a service life that is dependent upon operating conditions. Cracks are the major inspection criteria listed. You should document and report any confirmed cracks. The most common form of degradation is deposit buildup and erosion; this is not usually as severe as on the first-stage blades. The most serious form of damage that you may find in this area is pitting in the root area, which you must document and report.

Hp Turbine Nozzle Damage The first-stage turbine nozzle vanes are inspected simultaneously with the combustor and fuel nozzles. The following paragraphs describe the common damage you may find during the borescope inspections.

Discoloration Normal aging of the HP turbine nozzle stage 1 vanes will result in coloration changes as operating time is accrued. There is no limit relative to discoloration of HP turbine nozzle vanes. Oxidation and/ or burning of the vane areas is accompanied by dark areas silhouetting the initial distress. Cracks are shrouded in dark patches adjacent to the defect. Usually the distress starts as a crack, followed by oxidation of the shroud adjacent to the crack. Impact damage usually shows as a dark spot on the leading edge.

Leading Edge Damage This type of damage can be found between the forward gill holes on the concave and convex side of the leading edge.

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Axial cracks form around the leading edge. Estimate the percent of span of the leading edge or span relative to the nose cooling hole rows to determine the crack length. Burns and spalling on the leading edge should not be construed as coloration only, but must have actual metal oxidized (surface metal loss), but no holes through the leading edge. Estimate the area boundaries by the nose cooling holes spanned both radially (up and down the leading edge) and axially (around or across the leading edge). Record the number of vanes affected. Blocked cooling air passages on the leading edge is another type of damage. If multiple hole blockage is observed, record the separation of the open cooling holes and the number of adjacent plugged holes.

Airfoil Concave Surface Radial cracks run spanwise in the vane airfoil surface (up and down the vane). Record the relative chord position of the cracks. Record the relation of axial cracking versus radial cracking, such as axial and radial cracks that intersect or join at the second row of gill holes. The intent of the service limits are to preclude the liberation (break-out) of pressure face pieces.

Other Airfoil Area Defects The following paragraphs describe other airfoil area defects that you may find during the inspections. Burns and cracks on concave and convex sides (charred). Record the area and length, estimate the length relative to the leading edge area (gill hole to gill hole and spanwise by span of cooling or gill holes). Estimate the surface damage relative to separation of gill hole rows and radially by gill or cooling holes. Craze cracking. These cracks are superficial surface cracks, caused by high temperature. They are random lines that are very thin in appearance with tight lines (no depth or width to the cracks). There is no limit against this condition. Nicks, scores, scratches, or dents. These defects are allowed by the service limit and may "be present on any area of the nozzle vanes. Cracks in the airfoil fillet at the platform - there is no limit restricting these cracks, except at the leading edge area. Metal splatter. Aluminum and combustor liner metal, when liberated by the compressor or combustor, frequently splatter the surface areas of the stage 1 HP turbine nozzle vanes. There is no limit for these deposits; however, abnormal amounts of this splatter is reason to inspect the compressor.

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Pg 7-43

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Platforms Cracking in the HP turbine nozzle stage 1 platforms is difficult to see from the combustor borescope ports. When this area is viewed through the port, extreme magnification is afforded even with probe No. 2. This is due to the closeness of the surface to the distal end of the probe. Record the origin and end of the cracking and assess the magnitude using trailing edge slots and gill hole rows for radial and axial dimensions. Nicks, scores, scratches, and dents on platform surfaces are again masked from the combustor ports, except for the forward areas. Viewed via borescope, the area is magnified. Record the magnitude of the defect using the geometry of the trailing edge, gill hole rows, and gill hole separation for comparative dimensions. You must record burns on vane platform areas and use probe No. 1 to assess the conditions. If a burn-through occurs, the inner and outer surface edge of the platform should be seen. This difficult assessment can be done with the aid of a fiberscope. Any incomplete or doubtful evaluation should be the subject of a followup check after a specified amount of operating time.

HP TURBINE BLADE DAMAGE

When inspecting the HP turbine blades, you should use probe No. 2 with the 150-watt light source. The following paragraphs describe some of the damage you may find.

Cracks In The Leading Edge The leading edge of the stage 1 turbine rotor blades is the area forward of the gill holes. Cracks in the leading edge can be caused by DOD impact (combustion liner pieces) or thermal stress. An indication on the leading edge open enough to show depth is defined as a crack. Some conditions may mislead you in the determination of the presence of cracks. Dirt and debris buildup in layers on the leading edge, as shown in figure below, are not cracks. As this buildup begins to flake off, the edge of the area where the flake came off causes visible lines. These lines are irregular and appear to be cracks. The other common point of confusion on leading edge cracks is on the convex side of the leading edge tip area. This area is subject to "scratching" by the small pieces of combustor metal that pass through the HP turbine.

Cracks in the Trailing Edge The trailing edge is the flat surface with cooling holes that forms the after edge of the blade airfoil. Trailing edge cracks are difficult to see, but if a crack is suspected, use probe No. 1 for increased magnification. Record the location relative to a cooling hole and the magnitude of the crack. Record any plugged trailing edge cooling holes.

Pg 7-44

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Cracks in Concave and Convex Surfaces The airfoil surfaces are the areas aft of the gill holes back to the trailing edge. The tip area is further restricted to that area above the tip cap. When you evaluate the airfoil serviceability, do not consider the tip as a part of that area. Cracks in the airfoil surfaces are very tight, but can readily be seen with probe No. 2. Airfoil surface cracks are irregular in edge appearance and are not usually confined with streaks, which are usually straight in appearance. Record the area by the percent of span or gill hole spacing equivalent for location and magnitude of the cracking. For axial position, use an estimate of percent chord and the position relative to the tip cooling film cooling holes.

Cooling Hole Blockage The HP turbine rotor stage 1 blades are film cooled by air that flows out of the cooling holes. Report plugged holes relative to the number of blades affected and the position and number of plugged holes. Ensure the correct callout of the holes (such as the nose cooling, convex gill, tip film cooling holes, and so forth.)

Distortion Heavy impact damage to the leading edge of the blade usually results in distortion. When the impact is severe enough, cracking and/ or tearing of the leading edge, adjacent to the impact area, occurs. Record the magnitude and span location relative to the number of gill holes spanned. Estimate the out of contour as percent of the leading edge frontal area width or relative to the lateral spanning of the leading edge cooling hole rows.

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Borescope

Pg 7-45

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HP Turbine Blade Flaking And Buildup.

Blade Tip Nibbling The HP turbine rotor stage 1 blade tip nibbling is associated with hot running engines. Momentary overtemperature operation (such as experienced during compressor stalls) has exhibited this type of deterioration. This area of the blade is above the tip cap and located about two-thirds of the chord aft from the leading edge. The Figure below shows a typical "nibbled tip" as a result of a severe stall.

Blade Leading Edge Impact Damage The two figures below show an impacted and distorted leading edge of a stage 1 HP turbine rotor blade. (Note the cracking condition leading from the impact area into the airfoil surface.) The critical part of this type of damage is the axial or chord wire cracking. If this cracking progresses from the impacted damaged area into the convex or concave airfoil surface, the damage can be severe.

Pg 7-46

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HP Turbine Blade Tip Nibbling

HP Turbine Blade Impact Damage

Hp Turbine Blade Coating Failure The HP turbine protective coating is the key factor in the service life of an LM Series engine. The combined effect of film cooling and protective coating will extend the service life. Coatings are thinly and uniformly applied by a vacuum film deposition process. Coatings do not usually cause problems by chipping, peeling, or flaking. The normal failure mode is usually by pitting, rub-off, or nicks and scratches. Occasionally a bubble will occur in the surface coating during the coating process. If a bubble occurs, it will be tested at the coating facility to ensure that it cannot be rubbed off the surface. These bubble imperfections pose no problem to the engine. If the bubble area of the coating fails, you should monitor that area to determine any further deterioration.

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Pg 7-47

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HP Turbine Rotor Stage 1 Blade Areas Of Severe Corrosion After Extensive Operating Time.

Hp Turbine Blade Failure Modes Failures that you may observe during a borescope inspection include the following types: 1. Corrosion of the coating. This appears as pitting of the coating primarily in the 80percent span mid-chord region of the concave airfoil (thumbprint) side and the 20percent span mid-chord region (root print). This corrosion/erosion has not been found on blades coated with BC23.

HP Turbine Leading Edge Impact Damage.

2. Cracks in all areas of the blade, including radial cracks in the tips. Cracks generally start at the cooling holes. 3. FOD/ DOD, including nicks and dents. Aluminum spattering that appears as metallic deposits on the blade. This results from compressor tip rubs. 4. HP turbine blade tip rubs. This results in coating removal and tip damage. Pg 7-48

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CORROSION Characteristics The appearance of corrosion will vary with the metal involved. The following discussion includes brief descriptions of typical corrosion product characteristics. These descriptions are only for the most common materials used in gas turbine propulsion and support equipment.

Iron and Steel Possibly the best known and most easily recognized of all forms of metal corrosion is the familiar reddish-colored iron rust. When iron and its alloys corrode, dark iron oxide coatings usually form first. These coatings, such as heat scale on steel sheet stock and the magnetite layer that forms on the inside of boiler tubes, protect iron surfaces rather efficiently. However, if sufficient oxygen and moisture are present, the iron oxide is soon converted to hydrated ferric oxide, which is conventional red rust. Hydrated ferric oxide, red rust, does not protect surfaces. It destroys surfaces.

Aluminum Aluminum and its alloys exhibit a wide range of corrosive attacks, varying from general etching of surfaces to penetrating attacks along the internal grain boundaries of the metal. The corrosion products of aluminum are seen as white-gray powdery deposits.

Copper And Copper Alloys Copper and its alloys are generally corrosion resistant, although the products of corrosive attack on copper are commonly known. Sometimes copper or copper alloy surfaces will tarnish to a gray-green color, while the surface will remain relatively smooth. This discoloration is the result of the formation of a fine-grained, airtight copper oxide crust, called a patina. Patina offers good protection for the underlying metal in ordinary situations. However, exposure of copper alloys to moisture or salt spray will cause the formation of blue or green salts called verdigris. The presence of verdigris indicates active corrosion.

Cadmium and Zinc Cadmium is used as a coating to protect the area to which it is applied and to provide a compatible surface when the part is in contact with other metals. The cadmium plate supplies sacrificial protection to the underlying metal because of its great activity. During the time it is protecting the base metal, the cadmium is intentionally being consumed. Zinc coatings are used for the same purpose, although to a lesser extent. Attack is evident by white-to-brownto-black mottling of the surfaces. These indications do NOT indicate deterioration of the base Rev 1 06/26/2012

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metal. Until the characteristic colors peculiar to corrosion of the base metal appear, the coating is still performing its protective function.

Nickel and Chromium Alloys Nickel and chromium alloys are also used as protective agents. They are used as electroplated coatings and as alloying constituents with iron in stainless steels and with other metals such as copper. Nickel and chromium plate provide protection by the formation of an actual physical non-corrosive barrier over the steel. Electroplated coatings, particularly chromium on steel, are somewhat porous. Eventually, corrosion starts at these pores unless a supplementary coating is applied and maintained.

TYPES OF CORROSION

As stated previously, corrosion may occur in several forms, depending upon the metal involved, its size and shape, its specific function, the atmospheric conditions, and the corrosion-producing agents present. Those corrosion types described in this section are the most common forms found on gas turbine engines and machinery structures.

Direct Surface Attack The surface effect produced by reaction of the metal surface to oxygen in the air is a uniform etching of the metal. The rusting of steel, tarnishing of copper alloys, and the general dulling of aluminum surfaces are common examples of direct surface attacks. If such corrosion is allowed to continue unabated, the surface becomes rough, and in the case of aluminum, frosty in appearance. Direct surface attack is sometimes referred to as uniform etch corrosion.

Galvanic Corrosion Galvanic corrosion is the term applied to the accelerated corrosion of metal caused by dissimilar metals being in contact in a corrosive medium. Dissimilar metal corrosion is usually a result of faulty design or improper maintenance practices which result in dissimilar metals coming in contact with each other. This is usually seen as a buildup of corrosion at the joint between the metals. For example, when aluminum pieces are attached with steel bolts and moisture or contaminations are present, galvanic corrosion occurs around the fasteners.

Pitting The most common effect of corrosion on aluminum alloys is pitting. It is caused primarily by variations in the grain structure between adjacent areas on the metal surfaces that are in contact with a corrosive environment. Pitting is first noticeable as a white or gray powdery deposit, similar to dust, that blotches the surface. When the superficial deposit is cleaned away, tiny pits or holes can be seen in the surface. These pits may appear either as relatively

Pg 7-50

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shallow indentations or as deeper cavities of small diameters. Pitting may occur in any metal, but it is particularly characteristic of aluminum and aluminum alloys.

Inter-granular Corrosion Inter-granular corrosion is an attack on the grain boundaries of some alloys under specific renditions. During heat treatment, these alloys are heated to a temperature that dissolves the alloying elements. As the metal cools, these elements combine to form other compounds. If the cooling rate is slow, they form predominantly at the grain boundaries. These compounds differ electrochemically from the metal adjacent to the grain boundaries. These altered compounds can be either anodic or cathodic to the adjoining areas, depending on their composition. The presence of an electrolyte will result in an attack on the anodic area. This attack will generally be quite rapid and can exist without visible evidence. As the corrosion advances, it reveals itself by lifting up the surface grain of the metal by the force of expanding corrosion products occurring at the grain boundaries just below the surface. This advanced attack is referred to as EXFOLIATION. Recognition and necessary corrective action to immediately correct such serious instances of corrosion are vital. This type of attack can seriously weaken structural members before the volume of corrosion products accumulate on the surface and the damage becomes apparent.

Fretting Fretting is a limited but highly damaging type of corrosion caused by a slight vibration, friction, or slippage between two contacting surfaces that are under stress and heavily loaded. Fretting is usually associated with machined parts such as the contact area of bearing surfaces, two mating surfaces, and bolted assemblies. At least one of the surfaces must be metal. In fretting, the slipping movement at the interface of the contacting surface destroys the continuity of the protective films that may be present on the surfaces. This action removes fine particles of the basic metal. The particles oxidize and form abrasive materials that further accumulate and agitate within a confined area to produce deep pits. Such pits are usually located where they can increase the fatigue potential of the metal. Fretting is evidenced at an early stage by surface discoloration and by the presence of corrosion products in any lubrication. Lubricating and securing the parts so that they are rigid are the most effective measures for the prevention of this type of corrosion.

Stress Stress, evidenced by cracking, is caused by the simultaneous effects of tensile stress and corrosion. Stress may be internal or applied. Internal stresses are produced by non-uniform deformation during cold working conditions, by unequal cooling from high temperatures during heat treatment, and by internal-structural rearrangement involving volume changes. Stresses set up when a piece is deformed. Examples of internal stresses include those induced by press-and-shrink fits and those in rivets and bolts.

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Pg 7-51

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Concealed stress is a more dangerous condition than design stress. Concealed stress corrosion is difficult to recognize before it has overcome the design safety factor. The magnitude of the stress varies from point-to-point within the metal. Stresses in the neighborhood of the yield strength are generally necessary to promote stress corrosion cracking, but failures may occur at lower stresses.

Fatigue Fatigue is a special type of stress corrosion. It is caused by the combined effects of corrosion and stresses applied in cycles. An example of cyclic stress fatigue is the alternating loads to which the connecting rod of a double-acting piston in an air compressor is subjected. During the extension (up) stroke a compression load is applied, and during the retraction (down) stroke a tensile or stretching load is applied. Fatigue damage is greater than the combined damage of corrosion and stresses. Fracture of a metal part due to fatigue corrosion generally occurs at a stress far below the fatigue limit in a laboratory environment, even though the amount of corrosion is very small. For this reason, protection of all parts subject to alternating stress is particularly important wherever practical, even in environments that are only mildly corrosive.

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Borescope Definitions Condition of Part Code Definition Related Acceptable 01 Satisfactory for use

Terms OK, Checked OK

Battered

02

Damaged by repeated blows or impacts

Bent

03

Sharp deviation from original line or plane, usually caused by lateral force Example: Creased or folded sheet metal

Creased, Folded, Kinked

Binding

04

Restricted movement such as tightening or sticking condition, resulting from high or low temperatures, foreign object jammed in mechanism, etc.

Sticking, Tight

Bowed

05

Curved or gradual deviation from original line or plane usually caused by lateral force and/or heat

Broken

06

Separated by force into two or more pieces (Complete destruction of cohesion)

Fractured

Bulged

07

Localized outward or inward swelling, usually caused by excessive local heating and/or differential pressures

Ballooned, Swelling

Burned

08

Destructive oxidation, usually caused by higher temperature than parent material can withstand

Burred

09

A rough edge or sharp projection on the edge of the surface of the parent metal

Carboned

10

Accumulation of carbon deposits

Carbon Covered, Coked

Chafing

11

A rubbed action between parts having limited relative motion (as in vibration)

Abrasion, Fretting

Chipped

13

A breaking away of the edge, corner, or surface of the parent material, usually caused by heavy impact (not flaking)

Corroded

14

Gradual destruction of the parent material by chemical action. Often evidenced by oxide buildup on the surface of the parent material

Cracked

15

Visible partial separation of material which may progress to a complete break

Curled 16

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Rusted, Oxidation

A condition where the tip(s) of compressor blades or turbine blades have been curled over due to rubbing against engine casing

Borescope

Pg 7-53

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Condition of Part Code Definition

Related Terms

Dented

17

A surface indentation with rounded bottom, usually caused by impact of a foreign object. Parent material is displaced, seldom separated

Deposits

18

A buildup of material on a part either from foreign material or from another part not in direct contact.

Distorted 19

Extensive deformation of the original contour of a part, usually due to impact of a foreign object, structural stresses, excessive localized heating, or any combination of these.

Eroded 20

Carry away of material by flow of a fluid or gasses, accelerated by applied pressure

Peened

Buckled, Deformed, Depressed, Twisted, Warped

Flake

21

A thin chip-like or scale layer of metal

Fretting

22

Wear in a ripple pattern, caused by friction

Frosted

23

A dull, roughened surface finish

Fused

24

Joined together by two materials, usually caused by heat or friction

Gall

25

A defect caused by movement of two surfaces in contact with each other. In most cases an accumulation of foreign material is deposited on the parent material.

See Pickup

Gouged

26

A scooping out of material, usually caused by foreign material

Furrowed

Grooved

27

Smooth, rounded furrow or furrows of wear, usually wider than scouring with rounded corners and smooth on the groove bottom. (Example: A ball bearing wearing into a ring could cause a grooved condition)

Indications 28

Cracked, inclusion, fracture, etc. Not visible without fluorescent or magnetic penetrates.

Knifing

29

Erosion resulting in sharp edge.

Loose

30

Separation of a part from another part to which it is normally affixed.

Melted

31

Deformation from original configuration due to heat, friction, or pressure as with melted bearings or insulation

Pg 7-54

Chafing, Abrasion

Borescope

Separated, Disengaged

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Condition of Part Code Definition

Mismatched

32

Mispositioned 33

Related Terms

Improper association of two or more parts Improper installation of a part, resulting in damage to the installed part or to associated part.

Misaligned, Reversed

Nicked

34

A sharp surface indentation caused by impact of a foreign object. Parent material displaced, seldom separated

Obstructed

35

Prevention of free flow of a fluid (air, oil, fuel, water) because of foreign material in the flow path or malfunction in the flow member.

Clogged, contaminated, Plugged, Restricted

OverTemperature

36

Subjected to excessive temperature, usually evidence by change in color and appearance of the part.

Heat discolored

Oxidation

37

A surface deterioration by the chemical reaction between oxygen in the air and the metal surface. Attack is manifested as red rust in iron and low-alloy steels when formed at ambient temperature. The oxidation which forms on super alloys are complex and can be green or black, depending on material composition and temperature at which it is formed.

Part Missing

38

The absence of a required part.

Loss

Peeled

39

A breaking away of surface finish such as coating, plating, etc. Peeling would be flaking of large pieces. A blistering condition usually proceeds or accompanies flaking.

Blistered, Flaked

Pickup

40

Transfer of one material into or upon the surface of another, caused by contact between moving parts or deposits of molten material on a cooler material.

Burr, Gall, High spot, Imbedment, Inclusion, protrusion, Metalization

Pinched

41

Distortion of one or more surfaces of the parent material, caused by pressure

Bound, Tight, Compressed, Flattened, Seized, Smashed, Squashed,

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Condition of Part Code Definition

Related Terms

Pitted

42

Small irregular shaped cavities in the surface of the parent material, usually caused by corrosion, chipping, or heavy electrical discharge

Rolled-over

43

Lipping or rounded of metal edge

Rubbed

44

To move with pressure or friction against another part, such as compressor rub.

Scuff

45

A surface roughened by wear

Scrap, Scratch

Seizure

46

A welding or binding of two surfaces which prevent further movement.

Bound up, tight, Frozen, Wedged, welded

Scored

47

Deep Scratch or scratches made on the part surface by sharp edges of foreign particulates

Scratched

48

Light, narrow, shallow mark(s) caused by movement of a sharp object or particulate across a surface. Material is displaced, not removed

Sheared

49

Dividing a body by cutting action i.e., division of a body so as to cause its parts to slide relative to each other in a direction parallel to their plane of contact

Shingling

50

The effect of two adjacent surfaces overlapping, usually caused by wear to one edge of the lapping planes.

Spall

51

Broken or crushed material due to heat, or structural causes. Chipping off of small fragments under the action of abrasion

Stall

52

A disruption of the normally smooth airflow through the gas turbine. The compressor blades stall in much the same manner as the wings of an aircraft. A high-speed stall is indicated by a rise of t4.8, with corresponding reduction in XN2.5 and P3. A sub-idle stall is indicated by a rapid rise in T4.8 and hang-up of XN2.5. Personnel in the immediate area of the base enclosure may hear a chugging or a rumble during a stall.

Pg 7-56

Borescope

Lipped, Turned metal

Chip

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Condition of Part Code Definition

Related Terms

Sulfidation

53

A form of hot corrosion in heat-resistant alloys by the reaction at the metal surface of sodium chloride (sea air) and sulfur (from fuel). Attack usually over a broad front and can be identified as gray or black blisters (early stages) or surface delamination (advanced stages).

Tip Clang

54

The banging together of the leading edge of one blade and the trailing edge of the adjacent blade during stall. Tip clang results in trailing edge fretting.

Torn

55

Separation by pulling apart

Varnish Film

56

A hard surface film on metal, straw color to very dark brown, buildup by exposure to dry chemicals or fluids (commonly oil) while the part is heated above the breakdown point of the chemical or fluid.

Banded, Discolored, Oxidation, Stained

Warped

57

Not true in plane or in line; out of true shape.

Distorted, Bent, Twisted, Buckled, Contorted

Worn Excessively

58

Material of part consumed as a result of exposure to operation or usage.

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Borescope

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Borescope

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Pg 7-82

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Borescope

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Borescope

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Pg 7-84

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Borescope

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Borescope

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Pg 7-86

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Borescope

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Borescope

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Pg 7-88

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Borescope

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Borescope

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Pg 7-90

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Borescope

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Borescope

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Pg 7-92

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Borescope

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Borescope

Pg 7-93

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Pg 7-94

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Borescope

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Borescope

Pg 7-95

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Pg 7-96

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Borescope

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Borescope

Pg 7-97

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Pg 7-98

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Borescope

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Borescope

Pg 7-99

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Pg 7-100

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Borescope

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Borescope

Pg 7-101

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Pg 7-102

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Borescope

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Borescope

Pg 7-103

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Pg 7-104

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Borescope

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Borescope

Pg 7-105

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Borescope

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Borescope

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Borescope

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Borescope

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Borescope

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Borescope

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Borescope

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Borescope

Pg 7-113

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Borescope

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Borescope

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Borescope

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Borescope

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Borescope

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Borescope

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Borescope

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Borescope

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Borescope

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Borescope

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Pg 7-130

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Borescope

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Borescope

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Pg 7-134

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Borescope

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Drive Motor, 2C14764G05/G06, and Adapter, 1C8208, installation. NOTE  The gas turbine inspection drive motor permits one operator to control the rotation of the gas turbine high pressure rotors for purpose of inspection. No other personnel are required. The inspection drive motor will allow the gas turbine high pressure rotors to be rotated in either direction at a very slow, variable speed. The drive motor will not rotate the low pressure rotors  The drive motor may be installed at alternate locations as required. Spline adapter, 1C8208, is required for all drive motors. Spline adapter, 1C8208, can be used at various accessory locations.  The gas turbine can be rotated by hand using a 1/2-inch-drive wrench in the borescope drive pad.

Remove nuts and washers that secure drive pad cover onto transfer gearbox (figure 1). Remove cover from gearbox and discard preformed packing. Retain hardware for reinstallation. 1 NOTE

This drive pad may be utilized as an accessory drive. If so, the accessory must be removed for access to the pad. Refer to the packager's manual for removal/installation instructions.

Install adapter plate onto gearbox drive pad (figure 1). Secure with nuts provided with adapter plate. Tighten nuts to 55-70 lb in. (6.2-7.9 N·m) of torque. Install drive shaft onto drive motor and tighten setscrew. Insert drive shaft through hole in center of adapter plate and into spur gear. Ensure drive shaft splines mesh with spur gear splines. Secure drive motor to adapter plate with bolts and washers supplied with drive motor. Tighten bolts to 420-510 lb in. (47.5-57.6 N·m) of torque. Connect drive motor cord to control unit J3 motor connector. Connect remote control cord to control unit J2 remote connector. WARNING Electrical power shall be off before connecting or disconnecting electrical connectors. Electricity causes shock, burns, and death.

Connect three-prong power cord to control unit J1 power connector. Plug three-prong Rev 1 06/26/2012

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connector into power source. Operate drive motor during borescope as follows: a. Move control unit power switch to ON position. b. Select direction of rotor rotation for particular borescope inspection. c. Move switch on remote control to forward or reverse as required. Adjust motor speed on control unit to achieve desired rotor rotation speed. Operator may perform borescope inspection as planned, and may vary speed and direction of rotation as required. CAUTION Before reversing direction of rotation, bring rotor to a complete stop. Failure to stop the rotor before reversing rotation may result in severe damage to the drive motor mechanism.

d. To reverse direction of rotation, move directional selector to neutral position which allows gas turbine to free wheel. Wait until rotor completely stops; then move directional selector to opposite direction.

Drive Motor, 2C14764G05/G06, and Adapter, 1C8208, Removal. WARNING Electrical power shall be off before connecting or disconnecting electrical connectors. Electricity causes shock, burns, and death.

Switch control unit off and disconnect power cord from power source and control unit. Disconnect remote control and drive motor from control unit. Remove drive motor from adapter plate by removing drive motor bolts and washers. Loosen setscrew on drive shaft and remove drive shaft from drive motor. Remove nuts that secure adapter plate onto transfer gearbox. Remove adapter plate from gearbox. NOTE If drive pad is used for driving an accessory, install the accessory per the packager's manual.

Install preformed packing, J221P134, and drive pad cover (figure 1) onto transfer gearbox and secure with nuts and washers removed during drive motor installation. Tighten nuts to 5570 lb in. (6.2-7.9 N·m) of torque. Pg 7-140

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SECTION 8A LEVEL 1 MAINTENANCE WORK PACKAGES

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Level 1 Gas Turbine Maintenance

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Level 1 Maintenance Work Package

Description

WP 0001 00

Numerical List of Support Equipment, Consumables, and Expendables Axial Inlet Centerbody Assembly Replacement Low Pressure Compressor Inlet Temperature Pressure (T2P2) Sensor Replacement Variable Inlet Guide Vane (VIGV) Actuator Replacement Variable Inlet Guide Vane (VIGV) Actuator Replacement with Fixed Link Variable Inlet Guide Vane (VIGV) System Check Forward Seal Cover Plate Replacement Low Pressure Compressor Speed (XN2) Sensor Replacement High Pressure Compressor Inlet Temperature-Pressure T25-P25) Sensor Replacement Variable Bypass Valve (VBV) Actuator Replacement Variable Bypass Valve (VBV) System Check Bypass Valve, Bellcrank, and Actuating Ring Replacement Variable Stator Vane (VSV) Actuator Components Replacement Variable Stator Vane (VSV) Rigging Variable Stator Vane 8VSV) Stages 3 to 5 Bushing Replacement (High Boss HPC Stator Case) Fuel System Replacement Dual Fuel System Replacement Gas/Water Fuel System Components Replacement Liquid Fuel/Water Fuel System Components Replacement Gas Fuel System Components Replacement Ultraviolet Flame Sensor, L28490, Flame Sensor Sight Glass, and Flame Sensor Bracket Replacement Ultraviolet Flame Sensor, L44819, Flame Sensor Sight Glass, and Flame Sensor Bracket Replacement Igniter Plug Replacement High Pressure Compressor Discharge Temperature (T3) Sensor Replacement Compressor Discharge Pressure (CDP) Bleed Air Manifold And Flange Cover Replacement Low Pressure Rotor Speed (XNSD) Sensor Replacement Low Pressure Turbine Inlet Temperature (T48) Thermocouple Replacement-Inspection Low Pressure Turbine Inlet Pressure (P48) Probe Replacement Thrust Balance Valve (TBV) Assembly Replacement Liquid Fuel Pump Assembly, Fuel Pump Adapter, and Quick Disconnect Adapter Replacement

WP 1110 00 WP 1111 00 WP 1112 00 SWP 1112 01 WP 1113 00 WP 1114 00 WP 1210 00 WP 1310 00 WP 1311 00 WP 1312 00 WP 1313 00 WP 1410 00 WP 1411 00 WP 1412 00 WP 1510 00 WP 1511 00 WP 1512 00 WP 1513 00 WP 1514 00 WP 1515 00 SWP 1515 01 WP 1516 00 WP 1517 00 WP 1518 00 WP 1710 00 WP 1711 00 WP 1712 00 WP 1713 00 WP 1810 00

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Maint. Level 1&2 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1

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Work Package

Description

WP 1811 00

Hydraulic Control Unit (Hcu) and Hydraulic Filter Assembly Replacement Variable Geometry Hydraulic Pump Replacement Lube and Scavenge Pump Replacement Pneumatic Starter Replacement Hydraulic Starter and Distributor Assembly Replacement High Pressure Compressor Speed (XN25) Sensor Replacement Lube Resistance Temperature Detector (RTD) Replacement Magnetic Chip Detector Replacement Accelerometer Replacement Liquid Fuel Manifold Temperature Sensor Replacement External Piping, Hoses, and Electrical Harness Replacement Front Frame Module External Tubing, Harnesses, and Clamping Core Module External Tubing, Electrical Leads, and Clamping Low Pressure Turbine (LPT) Module External Tubing, Harnesses, and Clamping Engine Assembly External Tubing, Harnesses, and Clamping Fuel Pressurization Valve Replacement High Pressure Compressor Water Injection (Sprint®) Kit Removal and Installation Gas Turbine In Enclosure Replacement Preservation-Depreservation Gas Turbine Maintenance Dolly Removal and Installation Gas Turbine-Support Pedestal Removal and Installation Gas and Dual Fuel Manifold Support Fixture Replacement Gas Turbine Inlet Inspection External Engine Cleaning Gas Turbine External Inspection (Visual) Gas Turbine Exhaust System Inspection Gas Turbine Water-Wash Borescope Inspection Lube Oil Sampling Lube and Scavenge Pump Chip Detector Inspection Main Fuel Filter replacement Fuel Pump Filter Check Lube and Scavenge Pump Screen Check Variable Geometry Pump-Hydraulic Control Unit Filter Check Pneumatic Starter Servicing Ignition System Functional Check Vibration Monitoring System Functional Check Overspeed Inspection Over-temperature Inspection Bearing Sump Flow Tests Variable Stator Vane Off-Schedule Inspection

WP 1812 00 WP 1813 00 WP 1814 00 WP 1815 00 WP 1816 00 WP 1817 00 WP 1910 00 WP 1911 00 WP 1912 00 WP 1913 00 SWP 1913 01 SWP 1913 02 SWP 1913 03 SWP 1913 04 WP 1914 00 WP 1916 00 WP 3010 00 WP 3011 00 WP 3012 00 WP 3013 00 WP 3015 00 WP 4010 00 WP 4011 00 WP 4012 00 WP 4013 00 WP 4014 00 WP 4015 00 WP 4016 00 WP 4017 00 WP 4018 00 WP 4019 00 WP 4020 00 WP 4021 00 WP 4022 00 WP 4023 00 WP 4024 00 WP 4025 00 WP 4026 00 WP 4027 00 WP 4028 00

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Maint. Level 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1

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Level 2 Maintenance Work Package

Description

WP 0001 00

Numerical List of Support Equipment, Consumables, and Expendables Description

Work Package WP 2110 00 SWP 2110 01 WP 2210 00 WP 2211 00 WP 2212 00 WP 2213 00 WP 2214 00 WP 2215 00 WP 2216 00 WP 2217 00 WP 2310 00 WP 2411 00 SWP 2411 01 WP 2412 00 WP 2413 00 WP 241400 WP 2510 00 WP 2511 00 WP 2610 00 WP 2611 00 WP 2612 00 WP 2613 00 WP 2614 00 WP 2710 00 WP 2711 00 WP 2810 00 WP 2811 00 WP 2812 00 WP 2813 00 WP 3014 00 WP 3017 00

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Variable Inlet Guide Vane (VIGV) Assembly Replacement Inlet Frame Replacement Low Pressure Compressor (LPC) Module Replacement Low Pressure Compressor (LPC) Stage 0 Rotor Blades Replacement Low Pressure Compressor (LPC) Stages 0-3 Upper and Lower Stator Case Replacement Low Pressure Compressor (LPC) Stages 0-3 Stator Vanes Replacement Low Pressure Compressor (LPC) Stages 1-3 Rotor Blades Replacement Low Pressure Compressor (LPC) AFT Fan Case Replacement Low Pressure Compressor (LPC) Stage 4 Stator Vanes Replacement Low Pressure Compressor (LPC) Stage 4 Rotor Blades Replacement Front Frame Air Collector Replacement High Pressure Compressor (HPC) Upper and Lower Stator Case Replacement High Pressure Compressor Upper-Lower Stator Case OpeningClosing High Pressure Compressor (HPC) Stator Vanes Replacement High Pressure Compressor (HPC) Rotor Blades Replacement High Pressure compressor (HPC) Stator Outlel Guide Vanes Replacement Combustion Chamber Replacement Stage 1 High Pressure Turbine (HPT) Nozzle Replacement High Pressure Turbine (HPT) Module Replacement Stage 2 High Pressure Turbine (HPT) Nozzle (On Engine) Replacement Stage 2 High Pressure Turbine (HPT) Nozzle (Off Engine) Replacement Stage 1 High Pressure Turbine (HPT) Rotor Blades Replacement Stage 2 High Pressure Turbine (HPT) Rotor Blades Replacement Low Pressure Turbine (LPT) Module Replacement Rear Drive adapter or Aft Seal Spacer Replacement Radial Drive Shaft Replacement Transfer Gearbox Assembly Replacement Spur Gearshaft Assemblies Replacement Accessory Gearbox Carbon Seals Replacement Gas Turbine In Shipping Container Replacement Low Pressure Turbine (LPT) Module In Shipping Container Replacement

Level 1 Gas Turbine Maintenance

Maint. Level 1&2 Maint. Level 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2

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ICM, Interim, Letter, Paper

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ICM – Installation and Commissioning Manual This manual consists of all the requirements and procedures for installing and commissioning the LM6000.

Interim – Interim Change Notice Interim Change Notices are changes to the manual that have yet to be incorporated but are still required actions.

Figure 1, Typical Interim Change Notice Rev 1 06/26/2012

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Letter – GE Letters (Product & Service) GE issues letters to make their customers aware of certain concerns, product specific or service specific, experienced by users that may be of interest to other users. Typically customer issues of minor importance.

Figure 2, Typical Product Letter

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Papers - Position Papers (LM Series, LM6000, IEC NEC TCP 50/60 Hz) A position paper is an essay that presents an opinion about an issue, typically that of the author or another specified entity. Position papers are used by GE to make public the official beliefs and recommendations of the group.

Figure 3, Typical White Paper

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