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Chevron Thailand Exploration and Production Co., Ltd

Asset Integrity Team / Reliability Group

Facilities Engineering Department

AIT-P-I-001: Inspection of Process Piping

Prepared by: Opass Vanitchagornsawat (Asset Integrity Engineer) Reviewed by: Anuchai Sompakdee (Asset Integrity Engineer) Approved by: Songpan Svasdikara (Asset Integrity Team Lead)

Revision No.: 0

Copy No.00

Date: 2-May-12

Chevron Thailand Exploration & Production, Ltd.

AIT-P-I-001: Inspection of Process Piping

Amendment List Revision

Date

Page/ Section

Reason

By

0

2 May 12

All

Initial release for comment

OPNV

1

3 July 12

All

Revised per Anuchai’s comments

ATOH

2

5 July 12

All

Revised per Abie’s comments

APZH

TABLE OF CONTENTS 1.

PURPOSE

1

2.

SCOPE

2

3.

REFERENCE

3

4.

DEFINITIONS

4

5.

RESPONSIBILITIES

6

6.

INSPECTION PERSONNEL

8

7.

PROCEDURES 7.1 Safety 7.2 Piping identification 7.3 Piping inspection 7.4 Repair criteria and rejection limit 7.5 Inspection interval 7.6 Hydrostatic Testing

9 9 9 10 13 14 15

8.

RECORDS AND DOCUMENTATION

16

APPENDIX A CORROSION RATE AND REMAINING LIFE CALCULATION

18

APPENDIX B MINIMUM RETIRED THICKNESS

20

APPENDIX C PROCESS PIPING CLASSIFICATION

23

APPENDIX D CORROSION CIRCUITS

25

APPENDIX E EROSION AND CORROSION/EROSION

26

APPENDIX F DETERMINATION OF THE NUMBER OF CMLs

28

APPENDIX G CHECKLIST FOR EXTERNAL INSPECTION OF PIPING

29

APPENDIX H THE PRACTICE OF CMLs

30

Chevron Thailand Exploration & Production, Ltd.

1.

AIT-P-I-001: Inspection of Process Piping

PURPOSE

This Work Instruction shall be used by Inspectors as a guide for inspecting the existing process piping based on recommendations found in the relevant Corrosion Control Manuals or derived from corrosion/criticality reviews. The objective of such inspection is to confirm the mechanical integrity of the piping. Scheduled inspection of piping is required to ensure safe and reliable operation. It also assists in forecasting maintenance and replacement based on the measured or estimated rate of deterioration of piping’s components.

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Chevron Thailand Exploration & Production, Ltd.

2.

AIT-P-I-001: Inspection of Process Piping

SCOPE

This document defines inspection requirements and specific responsibilities for both out-ofservice and in-service inspection of piping systems. It applies to all piping subjected to pressure or vacuum conditions at Chevron Thailand Exploration and Production Co., Ltd (CTEP) area of operations, including valves, fittings, supports, etc. It does not apply to submarine piping, non-metallic piping and pipe line under seawater or to instrumentation piping beyond the first isolation valve and shall not be used for the new construction (Green Field). The document is not a detailed inspection manual, specific location selective may change on case-by-case basis.

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Chevron Thailand Exploration & Production, Ltd.

3.

AIT-P-I-001: Inspection of Process Piping

REFERENCES 1) API STD 570 Piping Inspection Code 2) API RP 574 Inspection of Piping, Tubing, Valve, and Fitting 3) API Public. 2201 Procedures for welding or Hot Tapping on Equipment Containing Flammables 4) ASME B31.3 Chemical Plant and Petroleum Refinery Piping 5) ASME B31G Manual for Determining the Remaining Strength of Corroded Pipeline 6) ASME BPV Section V Nondestructive Testing 7) ASME Section IX Welding and Brazing Qualifications

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Chevron Thailand Exploration & Production, Ltd.

4.

AIT-P-I-001: Inspection of Process Piping

DEFINITIONS A piping system includes all pipes and piping components e.g. flanges, elbows, reducers, nozzles, supports, instrument connections up to first block valve, bellows, threaded nipples if any, instrument thermowell nozzles, vents, drains etc. CMMS: Computerized Maintenance Management System. Process Piping: A metallic piping system which contains process fluids under pressure. Fluids may include but are not limited to gas, condensate, produced water, hazardous fluids used in the processing of products and hazardous waste streams. Hydrocarbon or chemical piping located at, or associated with, a company production facility. External Thickness Monitoring: External thickness measurements normally performed with, but not limited to, the NDE ultrasonic gauging instrument which may be performed while the piping either is in-service or out-of-service. This definition coincides with the term "On-Stream Inspection". External Inspection: An assessment of the conditions of the piping external surfaces, such as: insulation, coating & painting, and structures associated with the pipe such as supports and pipe-rack. Internal Inspection: This normally refers to, but is not limited to, an assessment of the condition of the piping internal surfaces. CMLs: Designated areas on piping systems where periodic examinations are conducted. Previously, they were normally referred to as “thickness monitoring locations (TMLs).” Corrosion Circuit: A term used to describe a section of piping of the same design and with approximately similar corrosive conditions, taking into account the corrosive environment (internally and externally), temperature, pressure, and the shell material. Risk: A combination of the probability of occurrence of process piping system failure and magnitude of the consequence of the failure. Flammable Materials: As used in this document, includes liquids, vapors and gases, which will support combustion. All fluids with a flammability hazard rating of four in NFPA 704 "Identification of the Fire Hazards of Materials" should be considered either Class 1 or 2, as defined in this document. Fluids with NFPA flammability ratings of two or three should be considered either Class 2 or 3. Only process fluids with a NFPA flammability rating of zero or selected fluids rated one should be considered Class 4. Inspector: Piping inspectors shall be API 570 certified or authorized by company.

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AIT-P-I-001: Inspection of Process Piping

NDT Technician: NDE Technicians who are performing and interpreting non-destructive examinations must be certified in the method(s) used by one of the following: - ANST Level I, II or III -

ISO 9712 level I, II or III

-

NDT techs pass a CVX test from Practice of NDT Personnel Qualification

Scanning: Inspection technique used to find the thinnest thickness measurement at a CMLs. Scanning is normally accomplished with ultrasonic measurements, but may also be accomplished with radiography and eddy current. When accomplished with ultrasonic measurements, scanning consists of taking several thickness measurements in the vicinity of the CMLs, searching for localized thinning. Suggested Corrosion Rate: The minimum corrosion rate that should be used for a circuit when projecting minimum retired dates. Risk Based Inspection (RBI) program will use company computerized inspection records system to select the greater of the calculated corrosion rate or the suggested corrosion rate. This is mainly useful when corrosion rates increase as a result of changed operation, upsets, or new service when little or no thickness data is available. If no value is entered, a default corrosion rate is used with a value of 10 mpy (0.25 mm/y) for significant corrosion and 5 mpy (0.13 mm/y) for non-significant corrosion. Restricted interval (RI): A factor in company computerized inspection records system used to shorten the length of the thickness measurement inspection interval when there is a potential for uneven corrosion rates in the circuit/loops.

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Chevron Thailand Exploration & Production, Ltd.

AIT-P-I-001: Inspection of Process Piping

5.

RESPONSIBILITIES

5.1

Asset integrity program owner shall be responsible for:

5.2

5.1.1

Responsible to implement of the Owner User Program and ensure that resources are adequate.

5.1.2

Provide necessary qualified people and tools to execute inspection work to follow the RBI programs.

5.1.3

Responsible for assuring the Authorized Inspector maintains the required qualifications/certifications. Inspection and nondestructive examination personnel who perform inspection tasks do not have to be company personnel.

Asset integrity SME team shall be responsible for: 5.2.1

Providing technical support and fit for purpose solutions to the corrosion, inspection, repair method and integrity challenges.

5.2.2 Evaluating inspection findings, and providing evaluation of potential repairs and replacement. 5.2.3

5.3

5.4

Preparing required inspection, replacement, and repair scopes.

Asset integrity offshore execution team shall be responsible for: 5.3.1

Performing external and internal inspection of the piping and components in accordance with this procedure.

5.3.2

Determining if cleaning is needed to achieve a satisfactory thorough inspection.

5.3.3

Establishing circuits and CMLs on-site.

5.3.4

Obtaining ultrasonic thickness readings of piping, valves, and fittings.

5.3.5

Physically identifying CMLs and providing a sketch of the piping marked to indicate inspection findings and the location of findings.

5.3.6

Identifying the locations of repairs and replacements.

5.3.7

Providing an inspection report and anomaly report to meeting all requirements in this procedure.

Asset integrity program shall be responsible for: 5.4.1

Maintain static data, historical data and repair records in Visions4.

5.4.2

Run Visions4 for planning and scheduling of piping system. This will include generate work order of both inspection and repair scope in CMMS. Page | 6

Chevron Thailand Exploration & Production, Ltd.

5.4.3 5.5

AIT-P-I-001: Inspection of Process Piping

Focal point to conduct Risk Assessment with the RBI group and ETC.

The FE Construction Team shall be responsible for: 5.5.1. Replacing or repairing the deteriorated piping or components. 5.5.2

5.6

Radiographic Examination.

The field operation and maintenance (O&M), and Asset team shall be responsible for: 5.6.1. Permit to work and isolate for any repairs. 5.6.2. Removal of insulation for inspection and repairs. Re-installation of insulation after inspection and repairs are completed. 5.6.3. Facilitate and Coordinate with all related parties to achieve repair work efficiently.

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Chevron Thailand Exploration & Production, Ltd.

6.

AIT-P-I-001: Inspection of Process Piping

INSPECTION PERSONNEL

Personnel performing inspection of piping system and piping components shall be certified in accordance with Chevron’s written Practice of NDT Personnel Qualification in the SERIP Document. They should also have at least 3 years of experience in design, construction, repair, operation or inspection of piping systems and qualified at least level I or higher for UT and level II or higher for other NDT techniques. API 570 Certified inspectors shall hold valid certificates and recognized by the Company.

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Chevron Thailand Exploration & Production, Ltd.

7.

PROCEDURES

7.1

Safety

7.2

AIT-P-I-001: Inspection of Process Piping

7.1.1

All necessary permits/clearances in accordance with CTEP Safety Regulations shall be obtained before commencement of inspection activities.

7.1.2

Appropriate Personal Protection Equipment shall be worn in accordance with guidelines in the CTEP Safety Regulations or according to Permit to work requirements.

7.1.3

Proper safe access should be provided for inspection to be conducted.

7.1.4

Hammer testing shall not be carried out on live piping and tight adherent scales shall not be removed from the pipe surface because of potential leaks.

Piping identification 7.2.1

All process piping requiring inspection shall be included in Visions4. Inspector shall provide adequate information to precisely locate and identify the piping. 1) To assist inspection personnel in locating and identifying piping, process piping can be shown on isometric sketches or drawings. 2) The piping shall be identified as to process unit, service, design temperature, design pressure, and piping design classification. a. Where the design pressure or design temperature is unknown, the design pressure and temperature of upstream equipment shall be used. b. Where the piping classification for existing piping is unavailable, the Engineering Team shall be notified so one may be developed. 3) All pertinent piping inspection information shall be indicated in inspection documentation, such information shall include: a. Component type (pipe, elbow, tee, valve, etc.) b. Piping connection type (flanged, welded, screwed, etc.) c. Piping component sizes, etc.

7.2.2

Each service shall be further subdivided into corrosion a circuit which identifies a common corrosive environment. Each circuit shall be uniquely identified for record keeping purposes. Factors to consider in defining a corrosion circuit are: 1) Main fluid flow from one piece of process equipment to another piece of process equipment. 2) For mixed phase flow and certain corrosive services, where velocity effects can cause erosion/corrosion, each different piping size can be considered as a separate circuit.

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AIT-P-I-001: Inspection of Process Piping

3) Each circuit shall contain the same piping materials except for valve internals, orifices, etc. 7.2.3

Within each corrosion circuit CMLs shall be identified. The number and strategic placement of these locations depends on a number of factors: 1) The higher the potential for corrosion, hazard, or risk, the more CMLs may be selected. 2) Less complex circuits normally require fewer locations than more complex circuits in similar service. 3) CMLs should be selected where they are easily accessible to the inspector. Care should be taken to minimize locations where scaffolding is required, except where it is necessary to meet other inspection location requirements. 4) Where possible CMLs shall be selected at the following locations: a. Dead legs (a location that water is trapped or no flow) shall contain at least one CMLs. b. Any location where a change in fluid temperature could causes water condensation. - Where turbulence, changes in flow direction, or changes in velocity may occur. - Where two streams join within a piping circuit. - Dissimilar material joints subject to having high galvanic corrosion. 5) As piping corrodes in a corrosion circuit and nears the retirement thickness, additional CMLs may be added to increase the accuracy of the corrosion size and depth measurement for maximum allowable operating pressure calculation and corrosion rate estimation.

7.3

Piping inspection The following provides general guidelines for the inspection of piping systems that are an integral part of a plant or facility and are subject to internal and external pressures. Asset Integrity Program should generate work order for PPI in CMMS approximately 3 months in advance. The Inspector shall determine the suitable NDT technique to be applied. When NDT personnel are employed to conduct the work, Asset integrity Supervisor should assist the NDT personnel to co-ordinate with the maintenance planning where scaffolds, insulation removal, power supply, etc. are required. The inspector shall specify the specific number of thickness monitoring locations CMLs that require measurement in each circuit before start inspection in advance and identify those CMLs that must be measured, e.g., the CMLs associated with injection points or the CMLs that resulted in setting the required inspection interval as a result of the previous inspection. 7.3.1

External inspection

External inspection of piping systems for either in-service or out-of-service conditions should include visual checks on the condition of the lines and its components. A checklist is given in Appendix F. Note: this checklist is intended as a guide for external inspection, covering items that should be considered during inspection of piping. Inspector shall apply knowledge and experience in the interpretation and application of the inspection findings. Page | 10

Chevron Thailand Exploration & Production, Ltd.

7.3.2

AIT-P-I-001: Inspection of Process Piping

External corrosion

External corrosion can be a significant problem particularly in industrial and coastal areas where sulphur oxides and chlorides are substantial. Corrosion can be serious where moisture can gather and any protective coating or painting has broken down. Coating/painting breakdown on paintwork, bitumen wrapping, fiberglass wrapping, etc. can be localized and is often difficult to detect. External corrosion on insulated piping can give rise to unexpected failures. Hence piping surveys should be over full length. Likely places to corrode include pipe clamps, dummy supports, pipe rest locations, near seawater front, pipes beneath leaking seawater and industrial water piping/equipment, uninsulated low temperature pipes (sweating pipes), broken insulation locations and etc. 7.3.3

Corrosion under insulation (CUI)

Certain areas and types of piping systems are potentially more susceptible to CUI, including the following: 1) Areas exposed to process spills, ingress of moisture, or acid vapors. 2) Carbon steel piping systems, including those insulated for personnel protection, operating between 10o F and 350o F. CUI is particularly aggressive where operating temperatures cause frequent or continuous condensation and reevaporation of atmospheric moisture. 3) Carbon steel piping systems that normally operate in-service above 350o F but are in intermittent service. 4) Austenitic stainless steel piping systems operating between 120oF and 400oF. (These systems are susceptible to chloride stress corrosion cracking.) 7.3.4

Carbon Steel Piping

Premature failures have been experienced due to corrosion, erosion or a combination of both. Corrosion frequently occurs at stagnant or low flow locations where deposits have settled e.g. dead ends and bends. Locations where a change of direction occurs, e.g. bends, tees, reducers can suffer local erosion by impurities or abrasives carried in the process stream. Pipe thickness and internal condition can be determined by commonly used NDT techniques such as ultrasonic thickness gauging and radiography. 7.3.5

Stainless Steel Piping

Corrosion rates of these pipes are generally very low. However failures can occur due to thermal fatigue, where significant temperature differences exist, or due to aqueous chloride or polythionic acid stress corrosion cracking. The problem areas are mostly at highly stressed locations e.g. welds, bends, nozzles etc. Additionally Amine and Cl- stress corrosion cracking generally threaten to this piping as well especially in stagnant locations (e.g. drains, vents); locations where insulation is poor or broken and internal parts exposed to atmosphere without an alkaline wash are particularly conducive to pitting corrosion. If internally accessible, these locations should be visually inspected and or dye-penetrant tested. If internally inaccessible, radiographic or ultrasonic inspection should be conducted at selected locations. Page | 11

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AIT-P-I-001: Inspection of Process Piping

Locations under clamp-supports should be checked for crevice corrosion. If the clamped section had not been previously painted or coating is damaged, it should be exposed visually inspected. While dye penetrant testing shall be performed on where area is susceptible to Chloride stress corrosion cracking.

7.3.6 Inspection at Injection Points Potentially corrosive injection points are those that could experience highly localized deterioration (corrosion/erosion) and led to piping failure during operation especially the injection system fails to perform as designed. It is recommended to carry out focused inspection on areas most susceptibility to failure. The following is guideline to monitor thickness using UT and RT at selected locations in the potential corrosion zone. -

Defined inspection scopes for pipe & inline mixer are the same scope. From upstream 3D or12” whichever is greater /Downstream to10D or 25ft is the inspection area. Carry out UTM WI every D RT one shot for checking quill. Inspection interval could coincide with PPI based on actual CR via RBI process. 360 deg around the injection point. Impingement point opposite the nozzle shall be inspected.

Sketch for inspection monitoring Injectant stream

D Main process stream D

10D

3D Inspection area

Note: D = Outside diameter of main process stream.

Inspection should include examination of the injection quill or spray nozzle when possible and confirmation that removed injection quills are reinstalled in the correct orientation. A process to confirm and record this is done should be in place. When the NDT technician and inspector confirms that corrosion rates have changed significantly in injection point circuits, that fact shall be immediately reported to asset integrity team, assets engineer and operations for appropriate corrective action.

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Chevron Thailand Exploration & Production, Ltd.

AIT-P-I-001: Inspection of Process Piping

7.3.8 Inspection of Dead-legs Inspections should include profile radiography on small diameter dead-legs, such as vents and drains, and ultrasonic or radiography on larger diameter dead-legs. 7.3.9 Localized Erosion-Corrosion Areas of localized erosion-corrosion should be inspected using visual inspection internally if possible or by using profile radiography. Scanning of the areas with ultrasonic is also a good technique and should be used if the line is larger than 8" NPS. 7.3.10 Small bore piping Small bore piping should be inspected down to the block valve that is normally used in operations. Inspections should include profile radiography on small diameter where UT is not practical. While either ultrasonic or radiography should be applied on larger diameter. When vibration is observed, MT and PT should be applied on the suspected weld joint. 7.4

Repair criteria and rejection limit Generally, the acceptable condition of an existing piping system should be such that the remaining corrosion allowance can last till the next planned shutdown based on the calculated rate of corrosion. If the wall of piping has thinned below the minimum required thickness (The minimum required thickness is the greater value of the pressure design thickness or the structural minimum thickness, See Appendix B), the affected area may be reviewed for fitness-forpurpose for the maximum allowable operating pressure using applicable codes or standards. In such cases, AI engineer shall approve recommendations for continued operation. A list of repair or replacement recommendations which impact pressure equipment integrity is required and shall be kept current. The recommendation tracking system shall include: -

Recommended corrective action, repaired location and repair date shall be specified in Visons4 and CMMS.

-

Actual work done and completed date shall updated in Visons4 and CMMS immediately after repair work is completed.

7.4.1

When in the judgment of the Inspection Authority, conditions in the piping exist which would render it unfit or unsafe for continued service, the identified piping shall be either repaired or replaced. Such conditions include, but are not limited to, the following: 1) Consumption of the corrosion allowance as determined by engineering calculations or applicable code requirements and identified by the thickness monitoring program.

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AIT-P-I-001: Inspection of Process Piping

2) Excessive pitting which may lead to penetration of the piping wall and result in leakage of its contents. 3) Sufficient deterioration of the piping material properties as to render it unfit which may be caused by one or more of the following: graphitization, embitterment, creep, hydrogen attack, etc. 4) Mechanical factors in the piping system which may result in excessive cyclic or steady state stresses beyond code allowances in piping components. Such conditions may arise from excessive piping movement, insufficient pipe support, improper design, etc. 5) Environmental cracking caused by such substances as caustics, hydrogen sulfide, amines, chlorides, etc. 7.4.2

The piping service life may be extended beyond its allowable limit only if an engineering analysis of the piping verifies that its life can safely be extended. The extension shall be acceptable to and approved by the authorized inspector and AI Engineer. The analysis shall recommend a maximum life extension interval or new minimum wall thickness limit. This analysis shall be documented and included in Visons4 and CMMS.

7.4.3

Whenever possible, piping repair or replacement should be identified with sufficient lead time to allow for a scheduled maintenance outage to perform the work.

7.4.4

Temporary and permanent repairs shall be performed and inspected in accordance with the requirements of API 570 and the approved welding procedure specifications. No welding should be carried out on any piping unless approval of CTEP QA/QC team and AI Engineer. MOC is always required for temporary repair and permanent repair may be required as per MOC procedure.

7.4.5 Each CMLs in Visions4 shall have a minimum required thickness. 7.5

Inspection interval For inspection of piping, the thickness data obtained shall be entered into RBI system. Comparison should be made against those obtained at previous two consecutive shutdowns/OSI where available. Where thicknesses are found to be reduced, more measurements should be taken both up and downstream of the monitored points. From a review of these inspection results, the Inspector should then add new or delete inspection points/sketches, as appropriate. API 570 sets the recommended maximum inspection intervals for thickness measurements and visual external inspections for piping systems. Shorter or longer intervals may be dictated by corrosion rates, jurisdictional requirements, and risk based inspection (RBI). The inspection interval shall be established using the lesser value of the following criteria: 1. 2. 3.

Corrosion rate and remaining life calculation (See Appendix A) Risk Based Inspection assessment (See Vision 4) Piping service classification as in API_570 (See Appendix A)

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AIT-P-I-001: Inspection of Process Piping

Thickness measurements should be scheduled based on the calculation of not more than half the remaining life determined from corrosion rates and the maximum interval suggested in Appendix A. 7.6

Hydrostatic Testing Replacement and repaired piping should normally be tested at 1.5 times the design pressure based on corrosion condition. Where the design pressure is not known, the piping class design limit at ambient temperature should be used (e.g. class 150#, 300#, 600# etc.). When testing a piping system or when testing with other equipment as a system, the test pressure shall be not greater than 1.5 times the design pressure of the weakest component in the system. In circumstances when a hydrostatic test is not practical, an alternative test is permitted such as Pneumatic test (see PIM-PU-5284), subject to the approval of the Authorized Inspector and AI Engineer. Golden weld procedure shall be applied. Test medium shall be water for general carbon steel pipe. While piping fabricated of or having components of 300 series stainless steel should be hydrotested with a solution made up of potable water, de-ionized/de-mineralized water or steam condensate having a total chloride concentration of less than 50 ppm. Holding time shall not less than 30 minutes or per codes.

Prior to final acceptance of the piping, inspection and test results shall be reviewed and approved by the inspector to assure appropriate quality has been maintained and all the inspection requirements of the applicable codes and standards have been met.

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Chevron Thailand Exploration & Production, Ltd.

8.

AIT-P-I-001: Inspection of Process Piping

RECORDS AND DOCUMENTATION

Piping inspection findings (all sketches, photographs, results and reports of NDT), recommendations and actions taken shall be recorded in Visions4. While any recommendation for repair or replace shall be recorded into CMMS. For piping, which is replaced, a set of thickness data should be obtained on the new piping as base measurements for future calculation of corrosion rates. All records on the piping systems shall be kept until the piping is permanently removed from service. 8.1

Piping Circuit Information The following information should be recorded for each piping circuit on which CMLs are located: a) b) c) d) e) f) g) h) i) j)

Pipe material or piping class operating and design pressures and temperatures ANSI flange rating process fluids whether the circuit is a dead-leg, injection point, intermittent service, or other special circuit the corrosion rate and remaining service life maximum interval for external inspection maximum interval for thickness measurement inspection any unusual or localized corrosion mode that would require specialized inspection techniques Particular circuit features that might subject it to rapid corrosion increases in the event of a process upset or loss of injection fluid flow.

In most cases, much of the above information will be the same for all circuits in a system and may be recorded at the system level rather than requiring duplication for each circuit. To prevent discrepancies, CMLs information shall be recorded in RBI Visions4 Program. 8.2

Inspection Isometric Drawings (ISOs) The primary purpose of inspection ISOs is to identify the location of CMLs and to identify the location of any recommended maintenance. Inspection ISOs should contain the following: a) all significant components of the piping system (e.g., all valves, elbows, tees, branches, etc.) b) all CMLs c) adequate orientation information d) piping system and circuit numbers and changes e) Continuation drawing numbers.

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AIT-P-I-001: Inspection of Process Piping

Inspection ISOs do not need to be drawn to scale or show dimensions unless necessary to locate CMLs. 8.3

Piping Failure and Leak Reports Leaks and failures (including recommendations and action taken if any) in piping that occur as a result of corrosion, cracking and etc. must be reported and recorded as part of the leak recording requirement in Visions4. As with other pressure equipment failures, leaks and failures in piping systems must be investigated to identify and correct the cause of failure. Temporary repairs to piping systems shall also follow the requirement of CTEP MOC process. All thickness data should be entered into the records, analyzed for corrosion rates and inspection interval adjustments, and validated, as necessary, within 30 working days of being measured by the data taker unless high priority issues.

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AIT-P-I-001: Inspection of Process Piping

APPENDIX A

CORROSION RATE AND REMAINING LIFE CALCULATION 1.

The long-term (LT) corrosion rate shall be calculated from LT corrosion rate

2.

tinitial −tlast

time (year)between tlast and tinitial

The short-term (ST) corrosion rate shall be calculated from: ST Corrosion rate

3.

=

=

tprevious −tlast

time (year)between tlast and tprevious

The remaining life of piping shall be calculated from: Remaining life

=

tlast −trequire

Selected corrosion rate

The selected corrosion rate shall be determined from the maximum value whether LT or ST, that best reflects the current process. Where: t initial

=

The piping original wall thickness before service.

t last

=

The piping wall thickness at time of last inspection.

t previous =

The piping wall thickness at time of previous inspection.

t required =

the greater value of the pressure design thickness (MAWP) or the structural minimum thickness.

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AIT-P-I-001: Inspection of Process Piping

Recommended Maximum Inspection Intervals (API570) Pipe Class Class 1 Class 2 Class 3 Class 4

Thickness Measurement 5 Years 10 Years 10 Years > 10 Years (Arbitrary)

External Visual Inspection 5 Years 5 Years 10 Years > 10 Years (Arbitrary)

Class 1:

Services with highest potential of resulting in an immediate emergency if a leak were to occur. 1. Flammable services that may rapidly auto-refrigerate and lead to brittle fracture. 2. Pressure services that may rapidly vaporize during release, creating vapors that may collect and form an explosive mixture, such as C 2 , C 3, and C 4 streams.

Class 2:

Services include the majority of unit process piping and selected offsite piping. 1. On-site hydrocarbon that will slowly vaporize during release. 2. Hydrogen, fuel gas, and natural gas.

Class 3:

Services that are flammable but do not significantly vaporize when they leak and are not located in high-activity areas, such as on-site hydrocarbons that will not significantly vaporize during release.

Class 4:

Process and utility services which are essentially non-flammable or non-toxic e.g. air, nitrogen, steam, lube oil.

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AIT-P-I-001: Inspection of Process Piping

APPENDIX B

MINIMUM RETIRED THICKNESS Pressure design thickness for piping The pressure design thickness shall be calculated using Barlow formula: t

=

Where: t P D S E

= = = = =

Y

=

PD

2(SE+PY)

the pressure design thickness for internal pressure, in inches the internal design gauge pressure of the pipe, in pounds per square inch the OD of the pipe, in inches the allowable unit stress at the design temperature, in pounds per square inch Quality Factors for Longitudinal Weld Joints in Pipes from table A-1B of B31.3 coefficient from Table 304.1.1 of B31.3, valid for t < D/6 and for materials shown. The value of Y may be interpolated for intermediate temperatures.

Structural minimum thickness for piping

Practical Wall Limits for Carbon and Low Alloy Steel Piping Nominal Pipe Size (NPS)

0.5 0.75 1 1.5 2 3 4 6 8 10-18 20-24

Alert Thickness T-min

Required Thickness

Inches (mm)

Inches (mm)

0.08 (2.0) 0.08 (2.0) 0.08 (2.0) 0.09 (2.3) 0.10 (2.5) 0.11 (2.8) 0.12 (3.1) 0.13 (3.3) 0.13 (3.3) 0.13 (3.3) 0.14 (3.6)

0.07 (1.8) 0.07 (1.8) 0.07 (1.8) 0.08 (2.0) 0.08 (2.0) 0.08 (2.0) 0.09 (2.3) 0.11 (2.8) 0.11 (2.8) 0.11 (2.8) 0.12 (3.1)

Table 1 Retired Thickness of piping from Structure Force

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AIT-P-I-001: Inspection of Process Piping

Table 1 generally applies to piping systems fabricated from carbon steel, low alloy steels, and chromium molybdenum alloy steels. Any piping systems which operate beyond the pressure/temperature ratings for these flange classes or above 650°F require that the retired thickness be calculated in accordance with the applicable code. This table does not typically apply to valves, cast pipe, cast fittings, austenitic stainless steel, high alloy components, or non-standard fittings. Minimum retired thickness requirements for threaded connections under 1" NPS should be evaluated by engineering if significant corrosion is detected. Circumstances may be such that these components will need to be upgraded to schedule 160 or to welded components. As a general rule, the minimum retired thicknesses in Table 1 also apply to the unthreaded portion of threaded pipe. For areas of external corrosion of considerable size, in which the circumferential stresses govern, or for widely scattered external pits, the principles of API-570, API579 or ASME B31G regarding area averaging, may be applied. Pressure design thickness for valve The formula to be used for calculation of the minimum allowable thickness of carbon steel and alloy steel valves and fitting shall be a modification of Barlow’s formula (API570) t Where: t P S

= = =

=

PDx1.5 2S

Minimum Allowable Thickness (MAT) Design Pressure or Maximum Allowable Working Pressure Allowable Stress based on temperature as show in ASME Code

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AIT-P-I-001: Inspection of Process Piping

Structural minimum thickness for Valves

Minimum Wall Thickness of Valves and Fittings to be used where calculation results in a smaller values of Carbon and Low Alloy Steel materials Outside Minimum Allowable Minimum Allowable Diameter Thickness Thickness (Inches) t-min t-min

2.99” and below 3.00” to 3.99” 4.00” to 4.99” 5.00” to 5.99” 6.00” to 7.99” 8.00” to 9.99” 10.00” to 11.99” 12.00” and over

Operating Temperature Below 450F 0.10” (2.54 mm) 0.11”(2.79 mm) 0.12”(3.05mm) 0.13” (3.30mm) 0.15” (3.81mm) 0.17” (4.32mm) 0.19” (4.83mm) 0.21” (5.34mm)

Operating Temperature Above 450F 0.13” (3.30mm) 0.14” (3.56mm) 0.15” (3.81mm) 0.16” (4.06mm) 0.18” (4.57mm) 0.20” (5.08mm) 0.22” (5.59mm) 0.24” (6.10mm)

Table 2 Retired Thickness of Valves and Fittings from Structure Force

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AIT-P-I-001: Inspection of Process Piping

APPENDIX C

PROCESS PIPING CLASSIFICATION Process piping systems are classified into four classes for the purposes of establishing maximum visual external inspection and thickness monitoring frequencies. This classification system shall take into account the hazards associated with the fluid contained in the Piping system, and any other factors that Asset Integrity Team may deem relevant. Process piping systems shall be classified in accordance with the piping service classes described in API 570 Para 6.2. There are three classes: Class 1, Class 2, and Class 3. Proper classification of piping systems may require input from specialists, AI Engineer in the fields of Safety, Environmental Conservation, Process and/or Engineering Materials. If increased inspection of a particular piping system is desired for operating or reliability reasons, the extent of inspection and inspection interval may be altered, but the classification shall not be changed. A fourth piping service class designated Class 4 is added to the three classes described in API 570 Para 6.2. Class 4 is intended to provide a means to classify utility services piping. Class 4 piping shall be designated as follows: Class 4 - Process and utility services which are essentially non-flammable or non-toxic. Typical examples of Class 4 services include: 1) 2) 3) 4) 5) 6) 7)

steam and steam condensate air nitrogen water, including boiler feed water, stripped sour water lube oil, seal oil, heat transfer oil ANSI B 31.3 category D services plumbing and sewers

Certain process piping systems may be exempted from the thickness monitoring requirements of this Practice, at the discretion of the Asset Integrity Team, Operations and Process Engineer provided that the piping system is not considered critical and has the following characteristics: 1) Extremely low potential for creating a safety or environmental emergency in the event of a leak. 2) Non corrosive system, as demonstrated by history or similar service, and the system is not subject to changes that could cause future corrosion.

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AIT-P-I-001: Inspection of Process Piping

PIPING CLASSIFICATION LOGIC DIAGRAM

Utility Service

Yes

Class 4

Yes

Class 4

Yes

Class 1

Yes

Class 1

Yes

Class 1

Yes

Class 3

Yes

Class 2

No Process leaks normally considered Non-hazardous (Process fluid 150 F and flash Point 400 F) No Service has a high likelihood Of causing an environmental or health Related emergency if a small leak occurs No Vapors from a leak may collect And result in an explosive mixture No Small leak may auto-refrigerate And leave piping system vulnerable To a brittle fracture No Off-site line which operates Below the boiling point, but May Still be flammable No Process unit line which will Significantly vaporize after leakage No Class 3

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AIT-P-I-001: Inspection of Process Piping

APPENDIX D

CORROSION CIRCUITS 1

2

The prime objective of the Corrosion Circuits is to provide information on the deterioration rate, corrosion mechanism of the selected locations and also to reduce shutdown inspection activities wherever feasible. The Corrosion Engineer in consultation with the Inspector determines selection of piping registration and monitoring points. In the selection process, the following factors should be considered: a)

Process Stream This should include Pressure, Temperature, Flow Velocity, Corrosivity, Erosivity, Phase separation, Phase change, Toxicity and any other factor deemed relevant.

b)

Piping System Material of construction and its reaction with the process medium/media.

c)

Consequence Consequence of failure.

d)

Service Life Minimum service life available.

A process pipe run may be of significant length and involve several changes of direction, branch connections, fittings, etc. The following forms of degradation should be considered to select monitoring points. a)

Straight horizontal pipe: i) general corrosion ii) groove corrosion due to stratified flow, phase separation or stagnant conditions

b)

Vertical pipe: i) general corrosion ii) stagnant conditions leading to local attack at liquid/vapour or liquid/liquid interface

c)

Bends, Tees, Reducers - points of change of direction can suffer local erosion or corrosion. These are normally the first components of a piping system to fail.

d)

Thermowell Nozzles - points of local turbulence.

Operating conditions e.g. stratified flow, phase separation turbulence or stagnation at different locations of each piping system may differ significantly, as does the rate of corrosion. The selection of the locations where wall thickness measurements are to be conducted, should take account of which of the circumferential portions of the pipe, elbow or fittings would be most sensitive to internal corrosion or erosion e.g. bottom, side or top, inner or outer radius of an elbow and vent/drain etc. Page | 25

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AIT-P-I-001: Inspection of Process Piping

Where possible, during construction stage, the provision of inspection windows or insulation covers should be arranged to facilitate future inspection. This should be indicated on marked up isometric sketches.

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AIT-P-I-001: Inspection of Process Piping

APPENDIX E

EROSION AND CORROSION/EROSION

Erosion can be defined as the removal of surface material by action of numerous individual impacts of solid or liquid particles. It can be characterized by grooves, rounded holes, waves, and valleys in a directional pattern. Erosion usually occurs in areas of turbulent flow, such as changes of direction in piping system or downstream of control valves where vaporization may take place. Erosion damage is usually increased in streams with large quantities of solid or liquid particles flowing at high velocities. A combination of corrosion and erosion results in significantly greater metal loss than can be expected from corrosion or erosion alone. This type of corrosion occurs at high-velocity and high-turbulence areas. Examples of places to inspect include the following: 1) 2) 3) 4)

Downstream of control valves, especially when flashing is occurring. Downstream of orifices. Downstream of pump discharges. At any point of flow direction change, such as the inside and out side radius of elbows and tees. 5) Downstream of piping configurations (such as welds, thermo-wells, flanges, and couplings) that produce turbulence, particularly in velocity sensitive systems such as low pH (acid) fluid system. Areas suspected of having localized corrosion/erosion should be inspected using appropriate NDE methods that will yield thickness data over a wide area, such as ultrasonic scanning, or radiographic profile.

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AIT-P-I-001: Inspection of Process Piping

APPENDIX F

DETERMINATION OF THE NUMBER OF CMLs This appendix is a guide for establishing the minimum number of CMLs for each circuit in a Class 1, 2 or 3 process unit piping system. The method takes into account the classification of the piping system as well as the length of the line, number of fittings, and circuit average corrosion rate. The general formula is: Number of CMLs = (L+F) x (C) The factors for this equation are defined in the following table.

FACTOR

CLASSIFICATION

L = LENGTH FACTOR 0-30 ft 31-100 ft 101-200 ft 201-500 ft 501-1000 ft >1000 ft

CLASS I 0.5 1.0 1.5 2.0 2.5 3.0

CLASS II 0.5 1.0 1.5 2.0 2.5 3.0

CLASS III 0.25 0.50 0.75 1.00 1.25 1.50

F = FITTING FACTOR

0.75(X)

0.35(X)

0.25(X)

C = CORROSION RATE FACTOR (CR < 2 MPY) (CR = 2-10 MPY) (CR > 10 MPY)

0.5 1.0 2.0

0.25 1.0 2.0

0.10 0.25 0.50

X CR

= =

Number of fittings Circuit Average Corrosion Rate

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AIT-P-I-001: Inspection of Process Piping

APPENDIX G

CHECKLIST FOR EXTERNAL INSPECTION OF PIPING 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22.

External corrosion Paint/coating condition/breakdown Insulation condition Damaged insulation/cladding Potential for under-lagging corrosion Cladding applied for personnel protection Corrosion at penetrations Small bore fittings – fatigue, cracking especially for any socket weld, corrosion Screwed fittings Pipe supports/sleepers - condition Freedom for expansion Fretting/local damage to pipe under supports Pipe hanger function (Hot/Cold set –check) Vibrations Leaks at flanges Clamps – registered? Buried sections/soil build-up Steam tracing leaks and functioning properly Steam traps functioning House-keeping/weeds/etc Dead-legs/seldom used lines/low points Sleeves/wrapping intact/damaged

Note: this checklist is intended as a guide for external inspection, covering items that should be considered during inspection of piping. The list is not exhaustive, and the inspector should apply knowledge and experience in the interpretation and application of the inspection findings.

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AIT-P-I-001: Inspection of Process Piping

APPENDIX H

THE PRACTICE OF CMLs Thickness measurements shall be taken at designated CMLs to monitor the rate of corrosion using inspection methods as practical. 1.

An inspection plan must be developed to define the best method of obtaining thickness data for each inspection location to be monitored.

2.

When possible, initial readings shall be taken when the piping is new to establish the un-corroded thickness of the piping. It is recommended to do UTM in 1,000 hrs after service to establish a base line if that system is excluded in Visions4. When initial readings are taken, the area of the CMLs shall be scanned to determine a typical thickness. When it is not possible to take initial readings, the value of the nominal thickness of new, un-corroded piping shall be used.

3.

Subsequent thickness readings should include scanning the entire CMLs where possible to identify a minimum reading (if profile radiography is used, two films taken at 90 degrees to each other should be taken)

4.

The minimum thickness reading, CMLs ID number, inspector’s name, measurement method, and date shall be recorded. Any unusual visual observations shall also be noted and recorded.

5.

Where practical, profile radiography may be used to assess the general internal and external condition of insulated piping at the CMLs without insulation removal. a. The film shall be of adequate size to provide as much information on the CMLs as practical. b. Thickness measurements may be taken directly from the radiograph utilizing appropriate sizing factors if there is sufficient confident I the accurate of the reading. c. If the information from the radiograph indicates unusual conditions, further inspection adjacent to or nearby the CMLs may be warranted. d. Radiography shall be the preferred thickness measurement method for small diameter piping (1 NPS and less). e. Radiography should not be done on a pipe filled with liquid.

6.

The minimum required pipe wall thickness or retirement thickness shall be based on piping class flange rating and structure force considerations using the design formula in AMSE Code, API570 and table 1. Locally thinned areas shall be evaluated using guideline in API579 and ASME B31G.

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AIT-P-I-001: Inspection of Process Piping

When utilizing ultrasonic testing to measure thickness: 1.

Where experience/service indicates a greater erosion/corrosion concern, accessible pipe elbows shall have ultrasonic thickness scanning performed at the outside bend radius at several CMLs.

2.

Accessible tees and branch connections shall have ultrasonic thickness scanning performed along the backside of the connections (directly opposite the neck of the branch inlet and at adjacent locations) when fluid flow is from the branch into the main piping.

3.

Accessible reducers shall have ultrasonic thickness scanning taken at the transition.

4.

Where appropriate, thickness measurements should include measurements at each of the four quadrants on a pipe and fitting.

5.

When Ultrasonic testing is used to monitor thickness of insulated piping, inspection hole (insulation plug) designed to prevent the ingress of moisture under the insulation shall be installed. They shall be placed at the CMLs point where the highest rate of corrosion is anticipated. Profile radiography may be utilized where possible to assist to initially locate this point.

6.

When scanning a CMLs with ultrasonic testing, the minimum reading shall be recorded for thickness monitoring purposes.

7.

When subsequent readings at a CMLs indicate a thickness, outside the precision error of the inspection method, additional readings shall be taken to verify the reading value. The number of gauging point shall be followed Piping Component Sketch for UT Measurement.

8.

Piping_Component_Sketch_for_UT_Measurement.pdf

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