Appendix E OM-2287

7/23/2019 Appendix E OM-2287

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A P P E N D I X E

Praxair’s Pipeline Operating and

Maintenance Manual

7/23/2019 Appendix E OM-2287


7/23/2019 Appendix E OM-2287


OM-2287

Operating and Maintenance Manual

Regulated

Hydrogen Gas

Pipelines

7/23/2019 Appendix E OM-2287


7/23/2019 Appendix E OM-2287


OM-2287 Issued: November 1995Revised: October 2007

Operating and Maintenance Manual

Regulated Hydrogen

Gas Pipelines

7/23/2019 Appendix E OM-2287


Copyright 1998, 2007 Praxair Technology, Inc. All rights reserved

Printed in the USA. 10/2007

Praxair, Inc. OM-2287Technical CommunicationsP.O. Box 44Tonawanda, NY 14151-0044USA

[email protected]

Phone: 800-PRAXAIR800-772-9247716-879-2472

Fax: 800-772-9985716-879-2146

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Regulated Hydrogen Gas Pipelines

OM-2287Issued: Nov 1995, Revised: Oct 2007 Page iii of xxii

NOTICES

Business Confidential: This document contains confidential and proprietary information ofPraxair, Inc. and is provided in confidence and solely for use in conjunction with theOperating and Maintenance Manual for Regulated Hydrogen Gas Pipelines. Thisdocumentation may not be reproduced or its contents disclosed to third parties withoutthe prior written consent of Praxair, Inc.

Disclaimers: All information referred to and/or included in this documentation is current as ofthe original issue date. Praxair, Inc., makes no warranty or representation with respectto the accuracy of the information or with respect to the suitability of the use of suchinformation outside Praxair, Inc., nor does Praxair, Inc., assume responsibility for anyinjury or damage which may result, directly or indirectly, from the use of suchinformation.

This documentation could include technical inaccuracies or typographical errors.Changes are made periodically to the information herein; these changes will beincorporated in subsequent revisions. Praxair, Inc., reserves the right to makeimprovements and/or changes to the product(s) and/or programs described in thisdocument at any time and without notice.

Trademarks: Praxair and the Flowing Airstream design are trademarks or registeredtrademarks of Praxair Technology, Inc., in the United States and/or other countries.Other trademarks used herein are trademarks or registered trademarks of theirrespective owners.

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OM-2287Page iv of xxii Issued: Nov 1995, Revised: Oct 2007

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OM-2287Issued: Nov 1995, Revised: Oct 2007 Page v of xxii

TABLE OF CONTENTS NOTICES .................................................................................................................................. iii

CHAPTER 1 – SCOPE AND PURPOSE ................................................................................. 1

CHAPTER 2 – REPORTING REQUIREMENTS ...................................................................... 2

2.1 Incident Reporting...................................................................................................... 2

2.2 Safety-Related Conditions Reporting ......................................................................... 22.2.1 Conditions That Must Be Reported ............................................................................ 22.2.2 Filing a Safety-Related Condition Report ................................................................... 3

2.3 Annual Report ............................................................................................................ 3

2.4 Other Reports ............................................................................................................ 3

2.5 DOT Reporting Addresses ......................................................................................... 3

CHAPTER 3 – CUSTOMER NOTIFICATIONS ........................................................................ 5

CHAPTER 4 – NORMAL OPERATIONS ................................................................................. 6

4.1 Operations and Maintenance Manual Review ............................................................ 6

4.2 Availability of Pipeline Records .................................................................................. 6

4.3 Pipeline Startup and Shutdown .................................................................................. 6

4.4 Procedure Review and Update .................................................................................. 7

4.5 Safety Precautions for Excavated Trenches .............................................................. 74.6 Pipe-type and Bottle-type Holders ............................................................................. 7

4.7 Report of a Gas Odor Inside a Building ...................................................................... 7

CHAPTER 5 – ABNORMAL OPERATING CONDITIONS ...................................................... 8

5.1 Task-specific AOCs ................................................................................................... 8

5.2 Generic AOCs ........................................................................................................... 8

5.3 AOC Follow-up .......................................................................................................... 9

5.4 Notifying Personnel of an AOC .................................................................................. 9

CHAPTER 6 –

CLASS LOCATIONS ..................................................................................... 10

6.1 Definitions ................................................................................................................ 106.1.1 Class Locations Units .............................................................................................. 106.1.2 Class 1 Location ...................................................................................................... 106.1.3 Class 2 Location ...................................................................................................... 106.1.4 Class 3 Location ...................................................................................................... 106.1.5 Class 4 Location ...................................................................................................... 10

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6.2 Class Location Studies ............................................................................................ 10

6.3 MAOP Change Due to Class Locator Change ......................................................... 11

CHAPTER 7 – CONTINUING SURVEILLANCE .................................................................... 13

CHAPTER 8 – DAMAGE PREVENTION PROGRAM ........................................................... 14

CHAPTER 9 – EMERGENCY MANUALS ............................................................................. 15

CHAPTER 10 – PUBLIC EDUCATION ................................................................................. 16

CHAPTER 11 – FAILURE INVESTIGATION ......................................................................... 17

CHAPTER 12 –

MAXIMUM ALLOWABLE OPERATING PRESSURES .............................. 18

CHAPTER 13 – PRESSURE TESTING ................................................................................ 19

CHAPTER 14 – UPRATING PIPELINE MAOP .................................................................. 20

CHAPTER 15 – ODORIZATION OF GAS ............................................................................. 21

CHAPTER 16 – TAPPING PIPELINES UNDER PRESSURE .............................................. 22

CHAPTER 17 – PIPELINE BLOWDOWN, PURGING, OR RE-PRESSURIZATION ........... 23

CHAPTER 18 – MAINTENANCE PROCEDURES ................................................................ 24

CHAPTER 19 – RIGHT-OF-WAY PATROLS AND LEAK SURVEYS ................................. 25

19.1 Right-of-Way Patrols ................................................................................................ 2519.1.1 ROW Patrol Schedule .............................................................................................. 2519.1.2 Pipeline Cover ......................................................................................................... 2519.1.3 Construction Activity along ROW ............................................................................. 2619.1.4 Casing Vent Stacks ................................................................................................. 26

19.2 Leak Surveys ........................................................................................................... 2619.2.1 Scheduled Leak Surveys ......................................................................................... 2619.2.2 Unscheduled Leak Surveys ..................................................................................... 2719.2.3 Visual Inspection for Underground Piping Leaks ...................................................... 2719.2.4 Aboveground Piping Leak Detection ........................................................................ 2719.2.5 Leaks Detected in non-Praxair Pipelines ................................................................. 2819.2.6 Detection Report Form ............................................................................................ 28

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OM-2287Issued: Nov 1995, Revised: Oct 2007 Page vii of xxii

CHAPTER 20 – PIPELINE MARKERS ................................................................................. 29

CHAPTER 21 – RECORDKEEPING ..................................................................................... 30

CHAPTER 22 – FIELD REPAIR PROCEDURES ................................................................. 31

22.1 Immediate Response to Pipeline Damage ............................................................... 31

22.2 Repair of Imperfections and Damage....................................................................... 31

22.3 Permanent Field Repair of Welds ............................................................................ 31

22.4 Permanent Field Repair of Leaks ............................................................................. 32

22.5 Testing of Repairs.................................................................................................... 32

CHAPTER 23 – PIPELINE ABANDONMENT /DEACTIVATION ........................................... 33

23.1 Discontinuance of Service ....................................................................................... 33

23.2 Deactivated Pipelines .............................................................................................. 33

23.3 Abandonment of a Pipeline ...................................................................................... 34

CHAPTER 24 – COMPRESSOR STATION PROCEDURES ................................................ 35

24.1 Compressor Operating Procedures ......................................................................... 35

24.2 Compressor Maintenance Procedures ..................................................................... 35

24.3 Compressor Building Requirements ........................................................................ 36

CHAPTER 25 – PRESSURE LIMITING AND REGULATOR STATION PROCEDURES ..... 37

25.1 Pressure Limiting Valve Inspections ........................................................................ 3725.2 Meter/Regulator Station Inspections ........................................................................ 37

25.3 Security and Safety Requirements ........................................................................... 38

CHAPTER 26 – VALVE INSPECTIONS ................................................................................ 39

26.1 Mainline Isolation Valves ......................................................................................... 39

26.2 Check Valves ........................................................................................................... 39

26.3 Vaults ...................................................................................................................... 39

CHAPTER 27 – PREVENTION OF ACCIDENTAL IGNITION ............................................... 40

CHAPTER 28 – WELDING AND WELD DEFECT REMOVAL ............................................ 41

28.1 Praxair Maintenance Welding Standards ................................................................. 41

28.2 Weld Procedures ..................................................................................................... 41

28.3 Welder Qualifications ............................................................................................... 41

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OM-2287Page viii of xxii Issued: Nov 1995, Revised: Oct 2007

28.4 Weld Preparation and Alignment ............................................................................. 42

28.5 Other Welding Requirements ................................................................................... 42

28.6 Inspection of Welds ................................................................................................. 42

28.7 Repair of Weld Defects ............................................................................................ 42

CHAPTER 29 – NONDESTRUCTIVE TESTING PROCEDURES......................................... 43

CHAPTER 30 – PLASTIC PIPE ............................................................................................ 44

CHAPTER 31 – CATHODIC PROTECTION S YSTEMS ....................................................... 45

31.1 Cathodic Protection System Design and Installation ................................................ 45

31.2 Electrical Isolation .................................................................................................... 45

31.3 Coating Specifications ............................................................................................. 46

31.4 Cathodic Protection Criteria ..................................................................................... 4731.4.1 -850 MV with Cathodic Protection Current Applied .................................................. 4731.4.2 Negative Polarized Potential of -850 MV .................................................................. 4831.4.3 100 MV Shift of Cathodic Polarization ...................................................................... 48

31.5 Cathodic Protection System Annual Inspection ........................................................ 48

31.6 Rectifier Inspections ................................................................................................ 49

31.7 Stray Current and Interference Bonds...................................................................... 49

31.8 Cathodic Protection System Repair ......................................................................... 49

31.9 Cathodic Protection Records ................................................................................... 50

CHAPTER 32 – CORROSION INSPECTIONS AND RESPONSE ........................................ 51

32.1 Aboveground Piping Inspections .............................................................................. 51

32.2 External Inspection of Exposed Pipe ....................................................................... 51

32.3 Inspection of Exposed Internal Pipe Surfaces .......................................................... 52

32.4 Investigation of Causes of Corrosion ....................................................................... 52

32.5 Prompt Repair of Corroded Pipe .............................................................................. 52

CHAPTER 33 – UNDERWATER PIPELINE INSPECTIONS ................................................. 54

CHAPTER 34 – LEAK INSPECTION AND RESPONSE....................................................... 55

34.1 Leak Classification and Action Criteria ..................................................................... 5534.1.1 Leak Investigation .................................................................................................... 5534.1.2 Leak Reporting ........................................................................................................ 56

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OM-2287Issued: Nov 1995, Revised: Oct 2007 Page ix of xxii

LIST OF TABLES

1 Right-of-Way Patrol Schedule .................................................................................. 25

2 Leakage Surveys ..................................................................................................... 27

3 Leak Classification ................................................................................................... 55

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Regulated Hydrogen Gas Pipelines]

OM-2287Issued: Nov 1995, Revised: Oct 2007 Page xi of xxii

Protocol Cross-Reference to Operating Manual

Name of Operator: Praxair, Inc.

OP ID No.: 20044 Unit ID No.: Contra-Costa PipelineHQ Address: System/Unit Name and Address:

Praxair, Inc.39 Old Ridgebury RoadDanbury, CT 06810

Praxair, Inc.841 Chevron Way,Richmond, CA, 94801-2006

Co. Official: James R. Ryan Activity Record ID No.:

Phone No.: (815) 467-5412 Phone No.:

Fax No.: (815) 467-5643 Fax No.:

Emergency Phone No.: (815) 342-1121 Emergency Phone No.:

Company System Maps (Copies for Region Files):

49 CFR PART 191 REPORTING PROCEDURES O&M Section 2.0

.605(b)(4)Procedures for gathering data for incident reporting:191.5 Telephonically reporting incidents to NRC (800) 424-8802. Local

emergencymanual

191.15(a) 30-day follow-up written report (Form 7100-2).

191.15(b) Supplemental report (to 30-day follow-up).

.605(a) 191.23 Reporting safety-related condition (SRCR). 2.2

191.25 Filing the SRCR within 5 days of determination, but not later than 10 daysafter discovery.

2.2.2

191.27 Offshore pipeline condition reports – filed within 60 days after theinspections.

N/A

.605(d)Instructions to enable operation and maintenance personnel to recognize potentialSafety Related Conditions.

2.2.1

49 CFR PART 192.13(c) CUSTOMER NOTIFICATION PROCEDURES O&M Section 3.0

.16 Procedures for notifying new customers, within 90 days, of their responsibility forthose selections of service lines not maintained by the operator.

3.0

.605(a) NORMAL OPERATING and MAINTENANCE PROCEDURES O&M Section 4.0

.605(a) O&M Plan review and update procedure (1 per year/15 months). 4.1

.605(b)(3) Making construction records, maps, and operating history available toappropriate operating personnel.

4.2

.605(b)(5) Start up and shut down of the pipeline to assure operation within MAOP plus allowable buildup.

4.3

.605(b)(8) Periodically reviewing the work done by operator’s personnel to determinethe effectiveness and adequacy of the procedures used in normaloperation and maintenance and modifying the procedures whendeficiencies are found.

4.4

.605(b)(9) Taking adequate precautions in excavated trenches to protect personnel

from the hazards of unsafe accumulations of vapors or gas, and makingavailable when needed at the excavation, emergency rescue equipment,including a breathing apparatus and a rescue harness and line.

4.5

.605(b)(10) Routine inspection and testing of pipe-type or bottle-type holders. 4.6

* .605(b)(11) Responding promptly to a report of a gas odor inside or near a building,unless the operator’s emergency procedure under §192.615(a)(3)specifically apply to these reports. Amdt 192-93 pub. 9/15/03, eff.10/15/03.

4.7

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OM-2287Page xii of xxii Issued: Nov 1995, Revised: Oct 2007

49 CFR PART 191 .605(a) ABNORMAL OPERATING PROCEDURES O&M Section 5.0

.605(c)(1) Procedures for responding to, investigating, and correcting the cause of:

(i) Unintended closure of valves or shut downs. 5.0, 5.1, 5.2

(ii) Increase or decrease in pressure or flow rate outside of normaloperating limits. 5.0, 5.1, 5.2

(iii) Loss of communications. 5.0, 5.1, 5.2

(iv) The operation of any safety device. 5.0, 5.1, 5.2

(v) Malfunction of a component, deviation from normal operations orpersonnel error.

5.0, 5.1, 5.2

.605(c)(2) Checking variations from normal operation after abnormal operationsended at sufficient critical locations.

5.3

.605(c)(3) Notifying the responsible operating personnel when notice of an abnormaloperation is received.

5.4

.605(c)(4) Periodically reviewing the response of operating personnel to determinethe effectiveness of the procedures and taking corrective action wheredeficiencies are found.

4.4

.605(a) CHANGE in CLASS LOCATION PROCEDURES O&M Section 6.0

.609 Class location study. 6.2

.611 Confirmation or revision of MAOP. 6.3

.613 CONTINUING SURVEILLANCE PROCEDURES O&M Section 7.0

.613(a) Procedures for surveillance and required actions relating to change inclass location, failures, leakage history, corrosion, substantial changes inCP requirements, and unusual operating and maintenance conditions.

7.0

.613(b) Procedures requiring MAOP to be reduced, or other actions to be taken, ifa segment of pipeline is in unsatisfactory condition.

7.0

.605(a) DAMAGE PREVENTION PROGRAM PROCEDURES O&M Section 8.0

.614 Participation in a qualified one-call program, or if available, a companyprogram that complies with the following:

(1) Identify persons who engage in excavating. 8.0

(2) Provide notification to the public in the One Call area. 8.0

(3) Provide means for receiving and recording notifications of pendingexcavations.

8.0

(4) Provide notification of pending excavations to the members. 8.0

(5) Provide means of temporary marking for the pipeline in the vicinity ofthe excavations.

8.0

(6) Provides for follow-up inspection of the pipeline where there is reasonto believe the pipeline could be damaged.

8.0

(i) Inspection must be done to verify integrity of the pipeline. 8.0

(ii) After blasting, a leak survey must be conducted as part of theinspection by the operator.

8.0

.615 EMERGENCY PROCEDURES O&M Section 9.0

.615(a)(1) Receiving, identifying, and classifying notices of events which requireimmediate response by the operator.

Local emergencymanual – all items

.615(a)(2) Establish and maintain communication with appropriate public officialsregarding possible emergency.

.615(a)(3) Prompt response to each of the following emergencies:

(i) Gas detected inside a building.

(ii) Fire located near a pipeline.

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OM-2287Issued: Nov 1995, Revised: Oct 2007 Page xiii of xxii

49 CFR PART 191

(iii) Explosion near a pipeline.

(iv) Natural disaster.

Local emergencymanual – all items

.615(a)(4) Availability of personnel, equipment, instruments, tools, and materialrequired at the scene of an Emergency.

.615(a)(5) Actions directed towards protecting people first, then property

.615(a)(6) Emergency shutdown or pressure reduction to minimize hazards to life orproperty.

.615(a)(7) Making safe any actual or potential hazard to life or property.

.615(a)(8) Notifying appropriate public officials required at the emergency scene andcoordinating planned and actual responses with these officials.

.615(a)(9) Instructions for restoring service outages after the emergency has beenrendered safe.

.615(a)(10) Investigating accidents and failures as soon as possible after theemergency.

.615(b)(1) Furnishing applicable portions of the emergency plan to supervisorypersonnel who are responsible for emergency action.

.615(b)(2) Training appropriate employees as to the requirements of the emergency

plan and verifying effectiveness of training..615(b)(3) Reviewing activities following emergencies to determine if the procedures

were effective..615(c) Establish and maintain liaison with appropriate public officials, such that

both the operator and public officials are aware of each other’s resourcesand capabilities in dealing with gas emergencies.

.605(a)

*

PUBLIC EDUCATION PROCEDURES O&M Section 10

.616 Public Awareness Program also in accordance with API RP 1162 (Amdt192-99 pub. 5/19/05, eff. 06/20/05). The Clearinghouse recently reviewedthe procedure applicable to API 1162.

PA Plansubmitted to

clearing house.616(d) The operator's program must specifically include provisions to educate the

public, appropriate government organizations, and persons engaged inexcavation related activities on:

PA Plan – AllItems

(1) Use of a one-call notification system prior to excavation and other

damage prevention activities;(2) Possible hazards associated with unintended releases from a gas

pipeline facility;

(3) Physical indications that such a release may have occurred;

(4) Steps that should be taken for public safety in the event of a gaspipeline release; and

(5) Procedures for reporting such an event.

.616(e) The program must include activities to advise affected municipalities,school districts, businesses, and residents of pipeline facility locations.

.616(f) The program and the media used must be as comprehensive asnecessary to reach all areas in which the operator transports gas.

.616(g) The program must be conducted in English and in other languagescommonly understood by a significant number and concentration of thenon-English speaking population in the operator's area.

.617 FAILURE INVESTIGATION PROCEDURES O&M Section 11

.617 Analyzing accidents and failures including laboratory analysis whereappropriate to determine cause and prevention of recurrence.

11.0

.605(a) MAOP PROCEDURES O&M Section 12

.619 Establishing MAOP so that it is commensurate with the class location. 12.0

MAOP cannot exceed the lowest of the following:

(a)(1) Design pressure of the weakest element. 12.0

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OM-2287Page xiv of xxii Issued: Nov 1995, Revised: Oct 2007

49 CFR PART 191 (a)(2) Test pressure divided by applicable factor.

* (a)(3) The highest actual operating pressure to which the segment ofline was subjected during the 5 years preceding the applicabledate in second column, unless the segment was tested according

to .619(a)(2) after the applicable date in the third column or thesegment was uprated according to subpart K. Amdt 192-102 pub.3/15/06, eff. 04/14/06. For gathering line related compliancedeadlines and additional gathering line requirements, referto Part 192 including this amendment.

Pipeline segment Pressure date Test date-- Onshore gathering line that first became

subject to this part (other than § 192.612) after April 13, 2006.

-- Onshore transmission line that was a gatheringline not subject to this part before March 15,2006.

March 15, 2006, ordate line becomessubject to this part,whichever is later.

5 years precedingapplicable date insecond column.

Offshore gathering lines. July 1, 1976. July 1, 1971. All other pipelines. July 1, 1970. July 1, 1965.

N/A – all lineshave been

pressure testedsince applicable

dates

(a)(4) Maximum safe pressure determined by operator.

12.0(b) Overpressure protective devices must be installed if .619(a)(4) isapplicable.

* (c) The requirements on pressure restrictions in this section do notapply in the following instance. An operator may operate asegment of pipeline found to be in satisfactory condition,considering its operating and maintenance history, at the highestactual operating pressure to which the segment was subjectedduring the 5 years preceding the applicable date in the secondcolumn of the table in paragraph (a)(3) of this section. Anoperator must still comply with § 192.611. Amdt 192-102 pub.3/15/06, eff. 04/14/06. For gathering line related compliancedeadlines and additional gathering line requirements, refer toPart 192 including this amendment.

N/A

.13(c) PRESSURE TEST PROCEDURES O&M Section 13

.503 Pressure testing. 13.0

.13(c) UPRATING PROCEDURES O&M Section 14

.553 Uprating. 14.0

.605(a) ODORIZATION of GAS PROCEDURES O&M Section 15

.625(b) Odorized gas in Class 3 or 4 locations (if applicable) – must be readilydetectable by person with normal sense of smell at 1/5 of the LEL.

15.0

* .625(f) Periodic gas sampling, using an instrument capable of determining thepercentage of gas in air at which the odor becomes readily detectable. Amdt 192-93 pub.9/15/03, eff. 10/15/03.

N/A – Noodorization

.605(a) TAPPING PIPELINES UNDER PRESSURE PROCEDURES O&M Section 16

.627 Hot taps must be made by a qualified crew. NDT testing is suggestedprior to tapping the pipe. Reference API RP 2201 for Best Practices.

16.0

.605(a) PIPELINE PURGING PROCEDURES O&M Section 17

.629 Purging of pipelines must be done to prevent entrapment of an explosivemixture in the pipeline:

(a) Lines containing air must be properly purged.17.0

(b) Lines containing gas must be properly purged.

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OM-2287Issued: Nov 1995, Revised: Oct 2007 Page xv of xxii

49 CFR PART 191 .605(a) MAINTENANCE PROCEDURES O&M Section 18

.703(b) Each segment of pipeline that becomes unsafe must be replaced,repaired, or removed from service. 18.0

(c) Hazardous leaks must be repaired promptly.

.605(b) TRANSMISSION LINES - PATROLLING & LEAKAGE SURVEY PROCEDURES O&M Section 19

.705(a) Patrolling ROW conditions. 19.1

(b) Maximum interval between patrols of lines:

Class LocationAt Highway and Railroad

CrossingsAt All Other

Places

1 and 2 2/yr (7½ months) 1/yr (15 months)

3 4/yr (4½ months) 2/yr (7½ months)

4 4/yr (4½ months) 4/yr (4½ months)

19.1.1

.706 Leakage surveys – 1 year/15 months. 19.2.1

Leak detector equipment survey requirements for lines transporting un-

odorized gas(a) Class 3 locations - 7½ months but at least twice each calendar

year .19.2.1

(b) Class 4 locations - 4½ months but at least 4 times each calendaryear .

.605(b) LINE MARKER PROCEDURES O&M Section 20

.707 Line markers installed and labeled as required. 20.0

.605(b) RECORDKEEPING PROCEDURES O&M Section 21

.709 Records must be maintained.

21.0

(a) Repairs to the pipe – life of system.

(b) Repairs to “other than pipe” – 5 years.

(c) Operation (Sub L) and Maintenance (Sub M) patrols, surveys, tests – 5 years or until next one.

.605(b) FIELD REPAIR PROCEDURES O&M Section 22

Imperfections and Damages

.713(a) Repairs of imperfections and damages on pipelines operating above 40%SMYS.

(1) Cut out a cylindrical piece of pipe and replace with pipe of designstrength.

22.2(2) Use of a reliable engineering method.

.713(b) Reduce operating pressure to a safe level during the repair.

Permanent Field Repair of Welds

.715 Welds found to be unacceptable under §192.241(c) must be repaired by:

(a) If feasible, taking the line out of service and repairing the weld inaccordance with the applicable requirements of §192.245. 22.3

(b) If the line remains in service, the weld may be repaired inaccordance with §192.245 if:

(1) The weld is not leaking.

22.3(2) The pressure is reduced to produce a stress that is 20% of

SMYS or less.

(3) Grinding is limited so that ⅛ inch of pipe weld remains.

(c) If the weld cannot be repaired in accordance with (a) or (b) above,a full encirclement welded split sleeve must be installed.

22.3

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OM-2287Page xvi of xxii Issued: Nov 1995, Revised: Oct 2007

49 CFR PART 191 Permanent Field Repairs of Leaks

.717 Field repairs of leaks must be made as follows:

(a) Replace by cutting out a cylinder and replace with pipe similar or ofgreater design.

22.4

(b)(1) Install a full encirclement welded split sleeve of an appropriatedesign unless the pipe is joined by mechanical couplings andoperates at less than 40% SMYS.

(b)(2) A leak due to a corrosion pit may be repaired by installing a bolt onleak clamp.

(b)(3) For a corrosion pit leak, if a pipe is not more than 40,000 psiSMYS, the pits may be repaired by fillet welding a steel plate.The plate must have rounded corners and the same thickness orgreater than the pipe, and not more than ½D of the pipe size.

(b)(4) Submerged offshore pipe or pipe in inland navigable waterwaysmay be repaired with a mechanically applied full encirclement splitsleeve of appropriate design.

(b)(5) Apply reliable engineering method.

Testing of Repairs

.719(a) Replacement pipe must be pressure tested to meet the requirements of anew pipeline.

22.5(b) For lines of 6-inch diameter or larger and that operate at 20% of more ofSMYS, the repair must be nondestructively tested in accordance with§192.241(c).

.605(b) ABANDONMENT or DEACTIVATION of FACILITIES PROCEDURES O&M Section 23

.727(b) Operator must disconnect both ends, purge, and seal each end beforeabandonment or a period of deactivation where the pipeline is not beingmaintained. Offshore abandoned pipelines must be filled with water or aninert material, with the ends sealed. 23.2

(c) Except for service lines, each inactive pipeline that is not being maintainedunder Part 192 must be disconnected from all gas sources/supplies,purged, and sealed at each end.

(d) Whenever service to a customer is discontinued, do the proceduresindicate one of the following:(1) The valve that is closed to prevent the flow of gas to the customer

must be provided with a locking device or other means designed toprevent the opening of the valve by persons other than thoseauthorized by the operator.

23.1(2) A mechanical device or fitting that will prevent the flow of gas must

be installed in the service line or in the meter assembly.(3) The customer’s piping must be physically disconnected from the

gas supply and the open pipe ends sealed.(e) If air is used for purging, the operator shall ensure that a combustible

mixture is not present after purging.23.2, 23.3

(g) Operator must file reports upon abandoning underwater facilities crossingnavigable waterways, including offshore facilities.

23.3

.605(b) COMPRESSOR STATION PROCEDURES O&M Section 24

.605(b)(6) Maintenance procedures, including provisions for isolating units orsections of pipe and for purging before returning to service.

24.2

.605(b)(7) Starting, operating, and shutdown procedures for gas compressor units. 24.1

.731 Inspection and testing procedures for remote control shutdowns andpressure relieving devices (1 per yr/15 months), prompt repair orreplacement.

24.2

.735 (a) Storage of excess flammable or combustible materials at a safedistance from the compressor buildings. N/A 24.3

(b) Tank must be protected according to NFPA #30.

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OM-2287Issued: Nov 1995, Revised: Oct 2007 Page xvii of xxii

49 CFR PART 191 .736 Compressor buildings in a compressor station must have fixed gas

detection and alarm systems (must be performance tested), unless: N/A 24.3$ 50% of the upright side areas are permanently open, or

$ It is an unattended field compressor station of 1000 hp or less. N/A 24.3

.605(b) PRESSURE LIMITING and REGULATING STATION PROCEDURES O&M Section 25

.739(a) Inspection and testing procedures for pressure limiting stations, reliefdevices, pressure regulating stations and equipment (1 per yr/15 months).

25.1, 25.2

(1) In good mechanical condition.

(2) Adequate from the standpoint of capacity and reliability of operationfor the service in which it is employed.

* (3) Set to control or relieve at correct pressures consistent with.201(a), except for .739(b). Amdt. 192-96 pub. 5/17/04, eff.10/8/04.

(4) Properly installed and protected from dirt, liquids, other conditionsthat may prevent proper oper.

* .739(b) For steel lines if MAOP is determined per .619(c) and the MAOP is 60 psi(414 kPa) gage or more . . . Amdt. 192-96 pub. 5/17/04, eff.10/8/04.

If MAOP produces hoop

stress that

Then the pressure limit is:

Is greater than 72 percent ofSMYS

MAOP plus 4 percent

Is unknown as a percent ofSMYS

A pressure that will prevent unsafe operationof the pipeline considering its operating

and maintenance history and MAOP

25.1

.743 Testing of Relief Devices

* .743 (a) Capacity must be consistent with .201(a) except for .739(b), and bedetermined 1 per yr/15 mo. Amdt. 192-96 pub. 5/17/04, eff.10/8/04.

25.1* .743 (b) If calculated, capacities must be compared; annual review and

documentation are required. Amdt. 192-93 pub. 9/15/03, eff.10/15/03.

* .743 (c) If insufficient capacity, new or additional devices must be installed

to provide required capacity. Amdt. 192-93 pub. 9/15/03, eff.10/15/03..605(b) VALVE AND VAULT MAINTENANCE PROCEDURES O&M Section 26

Valves

.745 (a) Inspect and partially operate each transmission valve that might berequired during an emergency (1 per yr/15 months).

26.1* .745 (b) Prompt remedial action required, or designate alternative valve.

Amdt. 192-93 pub. 9/15/03, eff. 10/15/03.

Vaults

.749 Inspection of vaults greater than 200 cubic feet (1 per yr/15 months). N/A 26.3

.605(b) PREVENTION of ACCIDENTAL IGNITION PROCEDURES O&M Section 27

.751 Reduce the hazard of fire or explosion by:

(a) Removal of ignition sources in presence of gas and providing for afire extinguisher.

27.0(b) Prevent welding or cutting on a pipeline containing a combustiblemixture.

(c) Post warning signs.

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OM-2287Page xviii of xxii Issued: Nov 1995, Revised: Oct 2007

49 CFR PART 191 .13(c) WELDING AND WELD DEFECT REPAIR/REMOVAL PROCEDURES O&M Section 28

* .225 (a) Welding procedures must be qualified under Section 5 of API1104 (19th ed. 1999, 10/31/01 errata) or Section IX of ASMEBoiler and Pressure Code (2001 ed.) by destructive test. Amdt.

192-94 pub. 6/14/04, eff. 7/14/04.

28.2

(b) Retention of welding procedure – details and test.

* .227 (a) Welders must be qualified by Section 6 of API 1104 (19thed.1999, 10/31/01 errata) or Section IX of ASME Boiler andPressure Code (2001 ed.) See exception in .227(b). Amdt.192-94pub. 6/14/04, eff. 7/14/04.

28.3(b) Welders may be qualified under section I of Appendix C to weld

on lines that operate at < 20% SMYS..229 (a) To weld on compressor station piping and components, a welder

must successfully complete a destructive test.(b) Welder must have used welding process within the preceding 6

months.28.3

(c) A welder qualified under .227(a) –

* . (1) May not weld on pipe that operates at > 20% SMYS unless

within the preceding 6 calendar months the welder has hadone weld tested and found acceptable under the sections 6or 9 of API Standard 1104; may maintain an ongoingqualification status by performing welds tested and foundacceptable at least twice per year , not exceeding 7½months; may not requalify under an earlier referencededition. Amdt. 192-94 pub. 6/14/04, eff. 7/14/04.

28.3

(2) May not weld on pipe that operates at < 20% SMYS unlessis tested in accordance with .229(c)(1) or requalifies under.229(d)(1) or (d)(2).

(d) Welders qualified under .227(b) may not weld unless:

(1) Requalified within 1 year/15 months, or28.3(2) Within 7½ months but at least twice per year had a

production weld pass a qualifying test.

.231 Welding operation must be protected from weather.28.5

.233 Miter joints (consider pipe alignment).

.235 Welding preparation and joint alignment. 28.4

* .241 (a) Visual inspection must be conducted by an individual qualified byappropriate training and experience to ensure: Amdt. 192-94 pub.6/14/04, eff. 7/14/04.

28.6

(1) Compliance with the welding procedure.

(2) Weld is acceptable in accordance with Section 9 of API1104.

(b) Welds on pipelines to be operated at 20% or more of SMYS mustbe nondestructively tested in accordance with 192.243 exceptwelds that are visually inspected and approved by a qualifiedwelding inspector if:

(1) The nominal pipe diameter is less than 6 inches, or

(2) The pipeline is to operate at a pressure that produces ahoop stress of less than 40% of SMYS and the welds are solimited in number that nondestructive testing is impractical.

* .241 (c) Acceptability based on visual inspection or NDT is determinedaccording to Section 9 of API 1104. If a girth weld is unacceptableunder Section 9 for a reason other than a crack, and if AppendixA to API 1104 applies to the weld, the acceptability of the weldmay be further determined under that appendix. Amdt. 192-94pub. 6/14/04, eff. 7/14/04.

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OM-2287Issued: Nov 1995, Revised: Oct 2007 Page xix of xxii

49 CFR PART 191 .13(c) .245 Repair and Removal of Weld Defects:

(a) Each weld that is unacceptable must be removed or repaired.Except for offshore pipelines, a weld must be removed if it has acrack that is more than 8% of the weld length.

22.3, 28.7

(b) Each weld that is repaired must have the defect removed down tosound metal, and the segment to be repaired must be preheated ifconditions exist which would adversely affect the quality of the weldrepair. After repair, the weld must be inspected and foundacceptable.

(c) Repair of a crack or any other defect in a previously repaired areamust be in accordance with a written weld repair procedure,qualified under §192.225.

$ Sleeve Repair – low hydrogen rod (Best Practices –ref. API 1104App. B, In Service Welding).

28,5

NONDESTRUCTIVE TESTING PROCEDURES O&M Section 29

.243 (a) Nondestructive testing of welds must be performed by any process,other than trepanning, that clearly indicates defects that may affectthe integrity of the weld.

29.0

(b) Nondestructive testing of welds must be performed:(1) In accordance with a written procedure, and

29.0

(2) By persons trained and qualified in the establishedprocedures and with the test equipment used.

(c) Procedures established for proper interpretation of eachnondestructive test of a weld to ensure acceptability of the weldunder 192.241(c).

(d) When nondestructive testing is required under §192.241(b), thefollowing percentage of each day’s field butt welds, selected atrandom by the operator, must be nondestructively tested over theentire circumference.(1) In Class 1 locations at least 10%.

29.0(2) In Class 2 locations at least 15%.

(3) In Class 3 and 4 locations, at crossings of a major navigableriver, offshore, and within railroad or public highway rights-of-way, including tunnels, bridges, and overhead roadcrossings, 100% unless impractical, then 90%.Nondestructive testing must be impractical for each girthweld not tested.

29.0

(4) At pipeline tie-ins, 100%.

(e) Except for a welder whose work is isolated from the principalwelding activity, a sample of each welder’s work for each day mustbe nondestructively tested, when nondestructive testing is requiredunder §192.241(b).

(f) Nondestructive testing – the operator must retain, for the life of thepipeline, a record showing by mile post, engineering station, or bygeographic feature, the number of welds nondestructively tested,the number of welds rejected, and the disposition of the rejectedwelds.

.273(b) JOINING of PIPELINE MATERIALS O&M Section 30

.281 Joining of plastic pipe:

$ Type of plastic used.

N/A 30.0 – Noplastic pipe

allowed

$ Proper markings in accordance with §192.63.

$ Manufacturer.

$ Type of joint used.

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OM-2287Page xx of xxii Issued: Nov 1995, Revised: Oct 2007

49 CFR PART 191 * .283 Qualified joining procedures for plastic pipe must be in place Amdt. 192-

94 pub. 6/14/04, eff. 7/14/04.* .285 Persons making joints with plastic pipe must be qualified Amdt. 192-94

pub. 6/14/04, eff. 7/14/04.* .287 Persons inspecting plastic joints must be qualified Amdt. 192-94 pub.

6/14/04, eff. 7/14/04..605(b) CORROSION CONTROL PROCEDURES O&M Sections

31 & 32

.453 Are corrosion procedures established for:

$ Design.

31.1$ Operations.

$ Installation.

$ Maintenance.

.455 (a) For pipelines installed after July 31, 1971, buried segments mustbe externally coated, and

31.1(b) cathodically protected within one year after construction (see

exceptions in code).

(c) Aluminum may not be installed in a buried or submerged pipeline ifexposed to an environment with a natural pH in excess of 8 (seeexceptions in code).

.457 (a) All effectively coated steel transmission pipelines installed prior toAugust 1, 1971, must be cathodically protected.

31.1(b) If installed before August 1, 1971, cathodic protection must be

provided in areas of active corrosion for: bare or ineffectivelycoated transmission lines, and bare or coated c/s, regulator sta,and meter sta. piping.

.459 Examination of buried pipeline when exposed: if corrosion is found, furtherinvestigation is required.

32.2

.461 Procedures must address the protective coating requirements of theregulations. External coating on the steel pipe must meet therequirements of this part.

31.3

.463 Cathodic protection level according to Appendix D criteria. 31.4

.465 (a) Pipe-to-soil monitoring (1 per yr/15 months). 31.5

(b) Rectifier monitoring (6 per yr/2½ months). 31.6

(c) Interference bond monitoring (as required). 31.7

(d) Prompt remedial action to correct any deficiencies indicated by themonitoring.

31.8

* .465 (e) Electrical surveys (closely spaced pipe to soil) on bare/unprotectedlines, cathodically protect active corrosion areas (1 per 3 years/39months) Amdt 192-93 pub.9/15/03, eff. 10/15/03.

31.1

.467 Electrical isolation (include casings). 31.2

.469 Sufficient test stations to determine CP adequacy. 31.5

.471 Test lead maintenance. 31.8

.473 Interference currents. 31.7

.475 (a) Proper procedures for transporting corrosive gas?

32.3, 32.5(b) Removed pipe must be inspected for internal corrosion. If found,

the adjacent pipe must be inspected to determine extent. Certainpipe must be replaced. Steps must be taken to minimize internalcorrosion.

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OM-2287Issued: Nov 1995, Revised: Oct 2007 Page xxi of xxii

49 CFR PART 191 .605(b) .476 Systems designed to reduce internal corrosion. Amdt 192-(no number)

Pub. 4/23/07, eff. 5/23/07.

(a) New construction.

(b) Exceptions – offshore pipeline and systems replaced before

5/23/07.(c) Evaluate impact of configuration changes to existing systems.

.477 Internal corrosion control coupon (or other suit. Means) monitoring (2 peryr/7½ months).

.479 (a) Each exposed pipe must be cleaned and coated (see exceptionsunder .479(c)).

31.3Offshore splash zones and soil-to-air interfaces must be coated.

(b) Coating material must be suitable.

Coating is not required where operator has proven that corrosionwill:

(c) (1) Only be a light surface oxide, orN/A – 31.3

(2) Not affect safe operation before next scheduled inspection.

.481 (a) Atmospheric corrosion control monitoring (1 per 3 yrs/39 months

onshore; 1 per yr/15 months offshore).

32.1* .481 (b) Special attention required at soil/air interfaces, thermal insulation,

under disbonded coating, pipe supports, splash zones, deckpenetrations, spans over water Amdt 192-93 pub.9/15/03, eff.10/15/03.

* .481 (c) Protection must be provided if atmospheric corrosion is found (per§192.479) Amdt 192-93 pub.9/15/03, eff. 10/15/03.

32.5

.483 Replacement and required pipe must be coated and cathodicallyprotected (see code for exceptions).

.485 (a) Procedures to replace pipe or reduce the MAOP if generalcorrosion has reduced the wall thickness?

(b) Procedures to replace/repair pipe or reduce MAOP if localizedcorrosion has reduced wall thickness (unless reliable engineeringrepair method exists)?

(c) Procedures to use Rstreng or B-31G to determine remaining wallstrength?.491 Corrosion control maps and record retention (pipeline service life or 5

yrs).31.9

.605(b) UNDERWATER INSPECTION PROCEDURES – GULF of MEXICO and INLETS O&M Section 33

* .612(a) Operator must have a procedure prepared by August 10, 2005 to identifypipelines in the Gulf of Mexico and its inlets in waters less than 15 feet(4.6 meters) deep that are at risk of being an exposed underwater pipelineor a hazard to navigation? Amdt. 192-98 pub. 8/10/04, eff. 9/9/04.

33.0

* .612(b) Operator must conduct appropriate periodic underwater inspections basedon the identified risk Amdt. 192-98 pub.8/10/04, eff. 9/9/04.

.612(c) Do procedures require the operator to take action when the operatordiscovers that a pipeline is exposed on the seabed, or constitutes ahazard to navigation:

(1) Promptly, within 24 hours, notify the National Response Center of the location of the pipeline?(2) Promptly, but not later than 7 days after discovery, mark the

location of the pipeline in accordance with 33 CFR Part 64 at theends of the pipeline segment and at intervals of not over 500 yardslong, except that a pipeline segment less than 200 yards long need only be marked at the center?

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OM-2287Page xxii of xxii Issued: Nov 1995, Revised: Oct 2007

49 CFR PART 191 (3) Place the pipeline so that the top of the pipe is 36 inches below

the seabed for normal excavation or 18 inches for rockexcavation within 6 months of discovery or not later thanNovember 1 of the following year if the 6 month period is laterthan November 1 of the year the discovery is made? See code re:

engineering alternatives, PHMSA notification.

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OM-2287Issued: Nov 1995, Revised: Oct 2007 Page 1 of 56

1 SCOPE AND PURPOSE

Protocol: .605 This Operating and Maintenance (OM) Manual is applicable to Praxair

pipelines transporting hydrogen gas that are regulated by 49 U.S.C.60101 et seq. (the pipeline safety laws) and 49 U.S.C. 5101 et seq. (thehazardous material transportation laws).

The numbers shown in parentheses identify the subparts of 49 CFR 191or 49 CFR 192 with which the paragraph or section of the manualcomplies.

Praxair pipelines may also be required to comply with additional and/ordifferent state regulations in the states in which the pipelines operate.These additional requirements are addressed in Addendum A for eachstate.

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OM-2287Page 2 of 56 Issued: Nov 1995, Revised: Oct 2007

2 REPORTING REQUIREMENTS

2.1 Incident ReportingProtocol: 191.5 Incident reporting is explained in the local Emergency Plan at each

location.

2.2 Safety-related Conditions Reporting

2.2.1 Conditions That Must Be Reported

Protocol: 191.23 As defined in the Department of Transportation (DOT) Code Part 191,paragraph 191.23, a report of a safety-related condition shall be filed inthe following cases:

A pipeline (that operates at 20 percent specified minimum yieldstrength [SMYS] or more) has general corrosion that has reduced thewall thickness to less than that required for the maximum allowableoperating pressure (MAOP) and/or has localized corrosion pitting to adegree where leakage might result.

A pipeline has experienced unintended movement or abnormalloading by an environmental condition (such as an earthquake,landslide, or flood) that impairs its serviceability.

A pipeline (that operates at 20 percent SMYS or more) has any

material defect or physical damage that impairs its serviceability.

A pipeline experiences any malfunction or operating error that causesthe pressure to exceed the MAOP of the pipeline.

A pipeline experiences a leak that constitutes an emergency.

A pipeline experiences any safety-related condition that would lead toan imminent hazard and cause a 20 percent or more reduction inoperating pressure or shutdown of pipeline operation.

Reports of safety-related conditions are not required under this

paragraph when:

An incident results from the condition before the deadline for filing thesafety-related condition report.

The condition exists on a pipeline that is more than 220 yards fromany building intended for human occupancy or outdoor place of

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assembly, except that reports are required for conditions within theright-of-way of an active railroad, paved road, street, or highway.

The condition is corrected by repair or replacement in accordancewith applicable safety standards before the deadline for filing the

safety-related condition report.

2.2.2 Filing a Safety-Related Condition Report

Protocol: 191.25 A report of any safety-related condition must be filed in writing within 5working days (not including Saturday, Sunday, or federal holidays) afterthe day a representative of the operator first determines that the conditionexists but no later than 10 working days after the day a representative ofthe operator discovers the condition. The Pipeline RegulatoryCompliance Manager shall file all Safety-Related Condition Reports withboth the DOT and the applicable state agency, as required. Safety-related conditions shall be filed using the Safety-Related Condition Report(Exhibit B).

2.3 Annual Report

Each year, the Pipeline Regulatory Compliance Manager shall submitPHMSA Form 7100.2-1 – Annual Report for Gas Transmission andGathering Systems to the Office of Pipeline Safety. The report shall besubmitted on or before March 15 of each year. Instructions for filling outand submitting the report are available from the web site of the Office ofPipeline Safety (OPS) (http://ops.dot.gov/). Copies of the report shall alsobe submitted to the respective state agencies.

2.4 Other Reports

Various other reports and submittals to government agencies may berequired, as specified in other compliance programs (IntegrityManagement Program, Operator Qualification Program, and Public

Awareness Program) or at the request of the regulating agency. All suchreports and submittals shall be made by or at the direction of the PipelineRegulatory Compliance Manager to the DOT and to the respective stateagencies at the addresses shown in the respective appendices of eachstate.

2.5 DOT Reporting Addresses

Incidents must be reported by telephone at the earliest practicablemoment following the incident, to the National Response Center (1-800-424-8802). Incident reporting is explained in more detail in the localEmergency Plan at each location.

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Annual reports (PHMSA Form 7100.2-1) may be filed electronically withthe Office of Pipeline Safety at the OPS web site (http://ops.dot.gov) through the On-line Data Entry System (ODES). The ODES alsocontains copies of all reports submitted since 2001. The PipelineRegulatory Compliance Manager submits these entries and maintains thepassword for access to Praxair’s entries in the ODES.

Completed forms may be submitted by mail to:

DOT/PHMSA Office of Pipeline SafetyInformation Resources Manager400 7th Street SW, Room 2103, PHP-10Washington, DC 20590

Completed forms may be faxed to the Information Resources Manager at:

202-366-4566.

http://ops.dot.gov/

http://ops.dot.gov/

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3 CUSTOMER NOTIFICATIONS Protocol: .16 Praxair pipelines supply industrial customers exclusively. The pipelines

connect directly into customer process piping and do not pass throughservice piping. The contracts with Praxair’s customers clearly identifywhere Praxair’s responsibilities end and the customer’s responsibilitiesbegin. No notifications are made to customers beyond those made in thesupply contracts.

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4 NORMAL OPERATIONS

4.1 Operations and Maintenance Manual ReviewProtocol: .605(a) This OM Manual shall be reviewed at least once each calendar year, not

to exceed 15 months, by the Pipeline Manager or Facility Manager. TheManager shall identify updates to reflect changes in operating andmaintenance practices, addition or removal of equipment with specialrequirements, etc. The Manager shall also consult with the PipelineRegulatory Compliance Manager to ensure that the OM Manual isupdated as required by possible regulatory changes. When changes arenecessary, the Pipeline Regulatory Compliance Manager shall initiate aManagement of Change (MOC) to ensure review and communicationsabout the updates, as necessary.

4.2 Availability of Pipeline Records

Protocol: .605(b)(3) Most pipeline records and documentation, including as-built drawings,project books, inspection records, and other records are maintained in thefile rooms and file cabinets at the local office of each pipeline. Each localoffice and these pipeline records and documentation are available andaccessible to all pipeline personnel 24 hours per day. In severallocations, pipeline personnel also have laptop computers with appropriatehardware to provide wireless access to the Praxair wide area network.The wide area network enables the pipeline personnel to connect to thePraxair Pipeline Asset Control System (PACS), the DigTrack web site for

One-Call management, and to the other systems and databases thatprovide relevant information or records.

4.3 Pipeline Startup and Shutdown

Protocol: .605(b)(5) Instructions for normal operation of all pipelines and compressors (whereinstalled) are contained in the Standard Operating Procedure (SOP) Booklocated in the local control room of each pipeline. The SOP Bookcontains procedures for startup, shutdown, and other normal operationalpipeline activities. The procedures are written so that when properlyexecuted they will not allow pipeline pressure to exceed the MAOP of anypipeline segment.

Instructions for the normal operations of remotely located pipelinecompressors, including startup and shutdown, are located at thecompressor facility.

Procedures for compressor isolation are documented using the PraxairHazardous Energy Control Procedure.

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4.4 Procedure Review and Update

Protocol: .605(b)(8), Praxair periodically reviews and updates its procedures for both normal.605(c)(4) and abnormal operating conditions to ensure that they are effective and

adequate. The Pipeline Management Team, which includesrepresentatives from various pipeline groups like Operations,Maintenance, Engineering, Corrosion Protection, Regulatory Compliance,and Safety, meet periodically to review pipeline operations and considerchanges to procedures or equipment, as warranted. This group alsolooks at new technologies to decide how those technologies will beapplied by Praxair.

Personnel are also periodically observed performing procedures toconfirm that the procedures, as written, achieve the desired results safelyand effectively.

The Praxair Safety Observation System (SOS) allows Praxair employeesat all levels, to report safety-related actions by themselves and others.The SOS Cards may be signed or anonymous, and all SOS cards are fedinto both local and safety management for action, as appropriate.

When procedure shortcomings are identified through any of thesereviews, the procedure is revised, as required, and personnel using theprocedure are trained on how to use the new or revised procedure.

4.5 Safety Precautions for Excavated TrenchesProtocol: .605(b)(9) When purging or working on flammable gas pipelines, measures shall be

taken to ensure positive ventilation in confined areas, and periodicatmospheric test taken according to the Hazardous Work Permit (HWP)procedures to detect any oxygen deficiency in the work area.

When needed at an excavation site, Praxair shall provide emergencyrescue equipment, including a breathing apparatus and a rescue harnessand line. These shall be provided by a rescue services contractor hiredfor the situation. Such an excavation shall be treated as a confined spaceand the Praxair Confined Space Entry procedures shall be applied.These are explained in the Worldwide S&ES Manual database in section2.04.

4.6 Pipe-type and Bottle-type HoldersProtocol: .605(b)(10) Praxair does not use pipe-type or bottle-type holders in its operations.

4.7 Report of a Gas Odor Inside a BuildingProtocol: .605(b)(11) This response is addressed in the local Emergency Plan at each location.

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5 ABNORMAL OPERATING CONDITIONS An abnormal operating condition (AOC) is defined as a condition that may

indicate a malfunction of a component or deviation from normaloperations that may:

Indicate a condition exceeding design limits

Result in a hazard(s) to persons, property, or the environment

AOCs include:

Unintended closure of valves or shutdown

Increase or decrease of pressure

Loss of communications

Operation of any safety device

Malfunction of a component, deviation from normal operations, orpersonnel error

5.1 Task-specific AOCsProtocol: .605(c)(1) For each of Praxair’s covered tasks, various possible AOCs could occur

during execution of the task, including or in addition to the AOCs listed

above. These AOCs are described in the procedures related to eachcovered task and in the task training modules in the Praxair OperatorQualifications Program, including how to recognize and react to the

AOCs. The tests and performance evaluations for each module are usedto verify that the individuals who perform covered tasks can recognizeand properly react to AOCs that they might encounter during theperformance of a covered task.

5.2 Generic AOCsProtocol: .605(c)(1) In addition to task-specific AOCs, generic AOCs may be encountered at

any time a person is working at pipeline facilities, without regard to the

covered task being performed. The Praxair Operator QualificationProgram includes a training and qualification verification module thatcovers generic AOCs that all Praxair personnel must complete to performpipeline tasks. Contractor qualifications to recognize and react to generic

AOCs must also be verified before they may perform work, through one ofthe equivalent verification methods described inP-15-496, Operator Qualification (OQ) Manual.

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5.3 AOC Follow-upProtocol: .605(c)(2) After an AOC appears to have been restored to the normal condition,

Praxair personnel will continue to observe pipeline parameters related toor providing indication of the abnormal condition. Close monitoring ofthese parameters will continue as long as necessary, until operatingpersonnel are satisfied that pipeline operations are completely stable andnormal.

5.4 Notifying Personnel of an AOCProtocol: .605(c)(3) When an AOC occurs, the personnel responding to the AOC are required

to notify others who may be affected by the AOC, except to the extentthat they could put themselves or others in harms way. Thus, controlroom personnel are made aware of field operations each day and areexpected to notify field personnel when an AOC occurs in the vicinitywhere they are working or that could affect them in some way.

Likewise, field personnel are expected to notify control room personnelabout AOCs occurring in the field so that they can begin appropriateresponse activities. Both field and operating personnel are expected tonotify management about the occurrence of AOCs as well.

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6 CLASS LOCATIONS

6.1 Definitions6.1.1 Class Location Units

A class location unit is an onshore area that extends 220 yards on eitherside of the centerline of any continuous 1-mile (1.6 kilometers) of pipeline.

6.1.2 Class 1 Location

A Class 1 location is defined as any class location unit that is an offshorearea or any class location unit that has 10 or fewer buildings intended forhuman occupancy.


A Class 2 location is defined as any class location unit that has more than10 but fewer than 46 buildings intended for human occupancy.


A Class 3 location is defined as any class location unit that has 46 ormore buildings intended for human occupancy, or an area where thepipeline lies within 100 yards of either a building or a small well-definedoutside area such as a playground, recreational area, outdoor theatre, or

other place of public assembly that is occupied by 20 or more persons onat least 5 days a week for 10 weeks in any 12-month period (days andweeks need not be consecutive).


A Class 4 location is defined as any class location unit where buildingswith four or more stories above ground are prevalent. A Class 4 locationends 220 yards from the nearest building with four or more stories aboveground.

6.2 Class Location StudiesProtocol: .609 Class locations for a pipeline segment shall be determined during the

engineering and construction processes. Additional Class LocationStudies shall be conducted periodically, as warranted by conditions alongthe pipeline right-of-way (ROW). ROW conditions, including evidence ofconstruction, are monitored as part of the regularly scheduled ROW

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inspections. New construction along the ROW is reported on the ROWInspection Report.

A Class Location Study shall be conducted when it appears from theROW inspection reports or other unscheduled observations, that

population densities or land uses along the ROW have changedsignificantly.

Class location studies shall determine:

The present class location for the segment involved.

The design, construction, and testing procedures followed in theoriginal construction and a comparison of these procedures with thoserequired for the present class location by the applicable provisions ofthis part.

The physical condition of the segment to the extent it can beascertained from available records.

The operating and maintenance history of the segment.

The maximum actual operating pressure and the correspondingoperating hoop stress, taking pressure gradient into account, for thesegment of pipeline involved.

The actual area affected by the population density increase andphysical barriers or other factors that may limit further expansion ofthe more densely populated area.

Class Location Studies are conducted by the Pipeline RegulatoryCompliance Manager or a designee, using the PACS RiskFrame-HCAapplication. Results of the study are integrated into the PACS GISdatabase.

6.3 MAOP Change Due to Class Location Change

Protocol: .611 The class of a pipeline segment is one of the factors considered whendetermining the MAOP of the segment. When the class of a locationchanges, the MAOP shall be reviewed to confirm that it is commensuratefor the new class location. If the current MAOP of a segment is notcommensurate for the new class location, one of the following steps mustbe taken.

Perform a pressure test of the segment to qualify it to operate at thenew MAOP.

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Reduce the MAOP of the segment to meet the new Class location.

Replace the pipe with piping that meets the new MAOP requirement.

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7 CONTINUING SURVEILLANCE Protocol: .613(a), Praxair has many regularly scheduled inspections of its pipeline

.613(b) facilities, including ROW patrols, leak surveys, equipment inspections,and cathodic protection system surveys. These inspections areperformed by both Praxair personnel and qualified contractors, all ofwhom may report observations about pipeline conditions, not only relatedto the specific inspection or survey being performed, but also related toany other condition that may warrant further investigation. Suchconditions, when observed, are reported on the appropriate inspectionforms and survey reports. A pipeline management representative reviewsevery inspection report to ensure that appropriate responses are beingmade to deficiencies that are reported and integrates information from thevarious inspections and surveys to identify trends, problem areas, orpotential deficiencies that may be likely to occur.

Personnel are also trained to observe and report unusual pipelineconditions they may observe during routine work they may be performingalong the pipeline. These observations are discussed during a morningmeeting of the pipeline personnel and the pipeline management.

Whenever anomalous conditions are discovered, the pipelinemanagement shall promptly review and assess them to ensure that theydo not jeopardize pipeline integrity. When necessary, they may conductadditional inspections to confirm conditions (wall thicknessmeasurements, RSTRENG® calculations, indirect inspections, etc.).When a pipe segment is discovered to be in unsatisfactory condition,

appropriate repairs shall be scheduled and made on a timely basis, or thesegment shall be phased out of service. If the segment cannot bereconditioned or taken out of service, the MAOP shall be lowered to anappropriate pressure according to §192.619.

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8 DAMAGE PREVENTION PROGRAM Protocol: .614 Every Praxair pipeline participates in the One-Call Systems in the states

in which the pipelines operate. Each location has, or is connected with, aresponse center that is manned 24 hours per day with staff qualified toreceive requests for pipeline identification and probing/locating. Thetelephone number of the respective response center is shown on ourpipeline markers.

Praxair technicians or Praxair’s qualified contractors locate and markPraxair pipelines with temporary markers, as required by the local One-Call regulations. Technicians do on-site inspections of locations that arein close proximity to a pipeline or about which insufficient information hasbeen provided to determine how close construction activities will be to apipeline. When a Praxair pipeline is adjacent to the activity or is exposed,a technician observes the activity to conclusion to ensure the integrity ofthe pipeline.

Praxair annually notifies, by mail, residents along our pipeline ROWs ofthe product our pipeline transports, how to identify a pipeline leak, what todo if one occurs, and where to call. Additional information about otherPraxair notifications to the public and various contractors is described inthe Praxair Public Awareness Program.

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9 EMERGENCY MANUALS Protocol: .615 The local emergency manuals describe how personnel should respond to

emergencies that might be encountered in the course of pipelineoperations and maintenance. In particular, the manuals explainnotification of other emergency responders, Praxair management, andgovernment authorities, and steps to follow to manage the scene of theemergency. Some AOCs may trigger emergency response activities, asexplained in the emergency manuals.

The emergency manuals also explain how personnel shall respond tovarious possible natural disasters or threats by third parties to pipelineintegrity.

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10 PUBLIC EDUCATION Protocol: .616 Praxair has an extensive public awareness and education program that

complies with API RP 1162. Refer to the Praxair Public AwarenessProgram.

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11 FAILURE INVESTIGATION Protocol: .617 All pipeline or pipeline component failures or leaks shall be investigated to

determine cause. The investigation shall follow the Praxair Root Cause Analysis (RCA) process to identify probable causes and contributoryconditions. The RCA shall also provide recommendations to preventreoccurrence.

The root cause analysis procedures and forms can be found in thePraxair NAIG Operations Procedures database as SOP-010, Root Cause

Analysis Program. Completed RCAs shall be entered in the RCAdatabase. The subject databases are located on all Praxair Lotus Notesservers. The RCA short form may be used to document an RCA,provided it allows for documentation of all of the relevant factors about theroot cause; however, additional documentation will have to be attached toensure that all of the documentation requirements have been covered.

If any section of leaking or corroded pipe has been replaced to repaircorrosion or a leak, the pipe section that was removed shall be analyzedby the Praxair Metallurgical Lab or by a suitably qualified outside lab toidentify conditions that may have caused or contributed to the corrosionor leak. These findings shall be considered as part of the RCA. Samplesof failed pipe or pipeline components may also be provided to state orfederal regulating agencies, on their request, for further investigation.

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12 MAXIMUM ALLOWABLE OPERATING

PRESSURES No segment of a steel pipeline shall be operated at a pressure thatexceeds the lower of the following:

Protocol: .619(a)(1) The design pressure (as defined in Subparts C & D of Part 192) of theweakest element of the pipeline. The term “elements” refers to pipe,valves, fittings, and other components that may be exposed to themaximum allowable operation pressure.

Protocol: .619 The formula for calculating the design pressure of pipe is explained in§192.105. For this calculation, the design factor “F” is applied to takeinto account the class location of the pipe. Details about the design

factor for class locations may be found in §192.111.

The design pressures for other components are specified by themanufacturer.

Protocol: .619(a)(2) The pressure obtained by dividing the pressure to which the pipelineis tested after construction by a factor of 1.5 (assuming Class 3 or 4locations). Exceptions to this factor are noted in §192.619.

Protocol: .619(a)(4), The maximum pressure considered safe by the Pipelines and.619(b) Metering Engineering Department or by the Region Operations

Department. Note that when MAOP is selected based on the

maximum pressure considered safe, pipeline safety devices must beinstalled and set to prevent exceeding the selected MAOP.

Changes to the class of a pipeline location or changes to the condition ofthe pipe or components of a pipe segment may require changes to theMAOP. These circumstances are explained in various places in thismanual.

If it is desired to increase the MAOP of a pipe segment, the increase mustbe conducted according to a written plan that follows the requirements of49 CFR 192 Subpart K. Refer to Chapter 14 of this manual.

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13 PRESSURE TESTING Protocol: .503 All pressure tests shall be performed according to Praxair procedure T-1,

Procedure for Field Pneumatic Testing, or Praxair procedure T-6,Hydrostatic Testing of Pipelines. The most current versions of theseprocedures may be found on the Praxair Standards – Technologydatabase.

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14 UPRATING PIPELINE MAOPProtocol: .553 Any increase in the MAOP of a pipeline segment shall be performed in

accordance with 49 CFR 192, Subpart K – Uprating. Subpart K includesthe following requirements:

Develop and follow a written plan that ensures that all Subpart Krequirements will be met.

Review the design, operating, and maintenance history and previoustesting of the segment of pipeline, and determine whether theproposed increase is safe and consistent with the requirements ofSubpart K.

Make any repairs, replacements, or alterations in the segment of

pipeline that are necessary for safe operation at the increasedpressure.

Increase pressure in pre-determined increments.

Hold the pressure constant after each pressure increase, and inspectthe pipeline for leaks.

Repair any potentially hazardous leaks before increasing pressurefurther, and monitor leaks that are not potentially hazardous.

Subpart K has additional requirements and specifications for MAOP

increases based on pipeline material of construction, internal stressesthat will be encountered, class location, and other factors. All of thesemust be considered when preparing the written plan for the pressureincrease.

All records of MAOP uprating shall be kept for the life of the pipeline.

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15 ODORIZATION OF GAS Protocol: .625(b), All Praxair regulated pipelines transport hydrogen gas is used as a

.625(f) feedstock for industrial manufacturing processes; therefore, odorization isnot required.

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16 TAPPING PIPELINES UNDER PRESSURE Protocol: .627 Praxair safety procedures do not permit hot-tapping pipelines that contain

hydrogen at any pressure. Any connection made to a Praxair hydrogenpipeline must be made under the control of a Praxair HWP, with theeffected line purged out of service and depressurized.

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17 PIPELINE BLOWDOWN, PURGING, OR

RE-PRESSURIZATION Any hydrogen pipeline blowdown, purging, or re-pressurization activitiesshall be performed according to Praxair SOP-214, Hazardous GasPipeline Job Plan Template and the Praxair Safety & Health ManualDatabase, section 2.2.1, Hazardous Work Permit procedures.

Protocol: .629(a) When purging a hydrogen pipeline out of service, the line shall be purgedusing nitrogen or other inert gas. The purge vent shall be sampled withappropriate analytical equipment to determine that all hydrogen has beenpurged.

Protocol: .629(b) When purging a hydrogen pipeline into service, the pipeline shall first be

purged using nitrogen or other inert gas to remove all air from it. Thepurge vent shall be sampled with appropriate analytical equipment todetermine that all of the air has been purged. After all of the air has beenpurged, the pipeline shall be purged with hydrogen gas. The purge ventshall be sampled with appropriate analytical equipment to determinewhen hydrogen purity has been restored, after which the pipeline may beraised to the normal operating pressure and put back into service.

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18 MAINTENANCE PROCEDURES Protocol: .703(b) Praxair inspects and monitors its hydrogen pipelines on a frequent and

on-going basis to ensure that they are in good condition for the intendedservice. Whenever anomalous conditions are discovered, the pipelinemanagement shall promptly review and assess them to ensure that theydo not jeopardize pipeline integrity. When necessary, they may conductadditional inspections to confirm conditions (wall thicknessmeasurements, RSTRENG® calculations, indirect inspections, etc.).When a pipe segment is discovered to be in unsatisfactory condition,appropriate repairs shall be scheduled and made on a timely basis, or thesegment shall be phased out of service. If the segment cannot bereconditioned or taken out of service, the MAOP shall be lowered to anappropriate pressure according to §192.619. Any segment found to beunsafe shall be repaired immediately or taken out of service.

Protocol: .703(c) When a hazardous Class 1 leak occurs, Praxair shall take immediateaction to take the affected pipeline segment out of service untilappropriate repairs can be made. Praxair personnel shall make the areaof the hazardous leak safe until the pipeline has been taken out of serviceand the leak area is no longer hazardous. Refer to Chapter 34, LeakInspections and Response, and the local Emergency Plan for moredetails about responses to hazardous leaks.

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19 RIGHT-OF-WAY PATROLS AND LEAK

SURVEYS

19.1 Right-of-Way Patrols

Protocol: .705(a) Each pipeline location shall maintain a pipeline patrol program to observesurface conditions on the pipeline right-of-way (ROW). During thesesurveys, the ROW shall be observed for leaks, construction activity,vandalism, missing or damaged markers or casing vents, and any otherfactors affecting the safe operation of the pipeline system.

Pipeline patrols and findings are recorded using the Pipeline Patrol Log(Exhibit F). Logs are maintained in the files of the local pipeline office.

When a pipeline patrol reveals the need for repairs or other remedialaction, such requirements shall be documented and managed with a D7iWork Order.

9.1.1 ROW Patrol Schedule

Protocol: .705(b) The schedule shown in Table 1 shall apply:

Table 1Right-of-Way Patrol Schedule

ClassLocation

At Highways and RailroadCrossings

At All Other Places

1 and 2 Twice per calendar year, not toexceed 7½ months

Once per calendar year, not toexceed 15 months

3 Four times per calendar year, not toexceed 4½ months

Twice per calendar year, notto exceed 7½ months

4 Four times per calendar year, not toexceed 4½ months

Four times per calendar year,not to exceed 4½ months

19.1.2 Pipeline Cover

Each pipeline location shall monitor all segments of the undergroundpipeline system for acceptable cover during normal pipeline patrolling.During the patrol, if personnel see any indication of major changes in thecover over the pipelines at road crossings, ditches, or cross-countryterrain, they shall take the following action:

Determine whether the cover has deteriorated to an unacceptablelevel.

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Inspect the line, where possible, for line movement.

If the cover has deteriorated to an unacceptable level or the pipeline isexposed, provide temporary protection such as markers, barriers, andsupports or shoring until the cover can be permanently restored.

19.1.3 Construction Activity along ROW

Any construction or other unusual activity noted around Praxair pipelinesduring patrols shall be reported on a Construction Activity Report (refer toExhibit G). Construction Activity Reports are maintained in the files of thelocal pipeline office. Copies are also submitted to the Pipeline RegulatoryCompliance Manager, who evaluates the need for a Class Location Studyof the pipeline segments near the construction site and the impact of theconstruction on risk and integrity assessments of the IntegrityManagement Program.

19.1.4 Casing Vent Stacks

Casing vent stacks are used at all locations where the pipeline is installedin a casing to relieve pressure in the casing in the event of a leak in thepipe within the casing. A pipeline marker shall be installed on the pipelinevent stack. Casing vents shall be inspected for damage during thepipeline ROW patrols. Findings shall be reported on the Patrol Log. Ifrepairs or other remedial action are required, such requirements shall bedocumented and managed with a D7i Work Order.

Casing vent atmospheres shall be sampled with leak detection equipment

during leak surveys to check for leaks of the piping inside the casing.Leak survey procedures and documentation are explained in section19.2, Leak Surveys.

19.2 Leak Surveys

19.2.1 Scheduled Leak Surveys

Protocol: .706 Each pipeline location shall conduct leakage surveys on its hydrogenpipelines at the minimum intervals shown in the Table 2. Leak surveys inClass 3 and 4 locations shall be performed using calibrated leak detectionequipment. Leak detection equipment is typically used in Class 1 and 2

locations as well.

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Table 2Leakage Surveys

ClassLocation

Frequency

1 and 2 Once per calendar year, not to exceed 15 months

3 Twice per calendar year, not to exceed 7½ months

4 Four times per calendar year, not to exceed 4½ months

Leak surveys may be conducted by qualified Praxair personnel or byqualified contractors, depending on local staffing. Leak surveys shall bedocumented using a suitable format. Leak surveys that are performed atthe same time as a ROW patrol may be documented on the Patrol Log.Leak surveys conducted by contractors shall be documented with awritten report submitted by the contractor. After the appropriateemergency response, any leak discovered shall be documented on the

Leak Detection Report.

19.2.2 Unscheduled Leak Surveys

Protocol: .614(6)(ii) Whenever blasting has occurred in close proximity to a Praxair pipeline orwhenever some other activity has occurred on or near the pipeline thatmight have jeopardized pipeline integrity, a leak detection survey, withleak detection instruments, will be performed on that section of thepipeline.

19.2.3 Visual Inspection for Underground Piping Leaks

A visual leak inspection is conducted by inspecting the pipeline ROW forany of the following conditions:

Vegetation changes (dead grass or plants)

Noise

Bare spots in ground

Gas bubbling in water

Observations of any of these conditions will warrant a subsequent

inspection of the area using leak detection equipment capable ofdetecting hydrogen. Visual leak inspections are conducted as part of theregularly scheduled ROW inspections.

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19.2.4 Aboveground Piping Leak Detection

In addition to the required leak surveys using calibrated leak detectionequipment, aboveground piping may also be checked for leaks using a

soapy water solution or other foam-forming solution. Pipeline casingsand areas where vegetation around the pipeline may not be adequate toindicate the presence of a leak shall be inspected by sampling theatmosphere at ground surface openings and casing vents.

19.2.5 Leaks Detected in non-Praxair Pipelines

If, during a survey, indications of leakage are found to originate from anearby pipeline not owned or operated by Praxair, prompt action shall betaken as necessary to protect life and property. The operator of theleaking pipeline shall be notified of the approximate location of the leak;and if an emergency condition exists, local emergency responders shall

be notified of the leak.

19.2.6 Detection Report Form

Any pipeline leak or failure shall be reported on the Leakage DetectionReport Form (Exhibit A).

Section 1 of the form shall be completed by operating location personnelat the time the leak is reported. The Pipeline Manager or a designeeshall be accountable to complete the report as more information isgathered about the leak. If the leak or failure was defined as a Grade 1leak, a copy of the report shall be attached to a Plant Incident Report and

forwarded to the appropriate personnel.

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20 PIPELINE MARKERS Protocol: .707 Signs and markers have been installed to identify the location of the

pipeline to reduce the possibility of damage or interference.

Generally, pipeline markers shall be located such that a person can standat one marker and see the next marker where possible. Markers shall beinstalled at all valve and meter stations; road, railroad, and watercrossings; and on all casing vent stacks.

All markers shall carry the word “Warning” followed by the words“Hydrogen Pipeline.” The marker shall include the name, Praxair, and thetelephone number at which Praxair personnel can be reached 24 hoursper day. Lettering shall be at least 1-inch tall with a stroke width of notless than ¼ inch.

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21 RECORDKEEPING Protocol: .709 All pipeline construction and maintenance records shall be kept for the life

of the pipeline. These include the date, location, and description ofrepairs to both pipe and pipeline components. All surveys, inspections,tests, and patrols shall also be kept for the life of the pipeline.

Records shall be kept in the files of the local pipeline office and/or in anyof Praxair’s computerized systems, including DataStream D7i CMMS,PACS GIS system, the DOT Regulated Pipelines Sharewaves site, or filefolders on either of these servers:

\\usatonas2\deptdata\SPET\Pipeline Management\Integrity Management Program

\\usadeets1\Compliance Documents\Integrity Management

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22 FIELD REPAIR PROCEDURES

22.1 Immediate Response to Pipeline Damage

Whenever a leak, imperfection, or other damage is discovered on apipeline that impairs the pipeline’s serviceability, Praxair shall takeimmediate, temporary steps, as necessary, to protect the public. Praxairshall make permanent repairs as soon as it is feasible to do so.Temporary steps may include cordoning off the area of the defect,temporarily taking the pipeline out of service, temporarily lowering theMAOP, or other steps as the situation warrants.

22.2 Repair of Imperfections and Damage

Protocol: .713(a)(1, 2) An imperfection or other damage may be repaired by cutting out acylindrical piece of pipe that includes the damaged area and replacing itwith pipe of equal or greater design strength or by installing a ClockSpring® or similar engineered repair system.

Imperfections or damage in submerged pipelines may also be repaired byinstalling a Clock Spring® or similar engineered repair system.

Protocol: .713(b) Before making any repair to an in-service pipeline segment, the situationshall be evaluated to determine a safe operating pressure at which therepair can be made, and the pipeline pressure shall be maintained at orbelow that pressure until the repairs have been completed. This provisionapplies only to engineered repair systems (wraps) or bolt-on split sleeves.

Praxair does not permit welding on lines under pressure or linescontaining hazardous or flammable gases.

For the proper protection of the repaired pipeline, the pipe shall beadequately coated according to Praxair Standard EN-49.

22.3 Permanent Field Repair of Welds

Protocol: .715(b) Defective welds in Praxair pipelines may only be repaired with thepipeline purged out of service.

Protocol: .245(b), A weld that is unacceptable according to section 9.0 of API Standard.715(a) 1104 can be repaired by removing the defect down to clean metal andwhere appropriate, preheating the segment before rewelding. Afterrewelding, the repaired weld must be inspected. Repaired welds that failinspection must be completely removed.

Protocol: .245(a) A cracked weld may only be repaired if the crack is shorter than 8 percentof the weld length.

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Protocol: .715(c) If the defective weld cannot be repaired as described, it may be repairedby installing a full encirclement welded split sleeve of appropriate designover the defective weld.

22.4 Permanent Field Repair of Leaks

Protocol: .717(a)(b) A leak may be repaired by cutting out a cylindrical piece of pipe that(1, 2, 5) includes the leak, and replacing it with pipe of equal or greater design

strength, or by installing a Clock Spring® or similar engineered repairsystem. Leaks may also be repaired by installing a full encirclementwelded split sleeve of appropriate design over the leak area. If the leak isdue to a corrosion pit, it may be repaired by installing a bolt-on leakclamp.

Protocol: .717(b)(4) Leaks in submerged pipelines may be repaired by installing amechanically applied full encirclement split sleeve of appropriate designover the leak.

Before making any repair to an in-service pipeline segment, the situationshall be evaluated to determine a safe operating pressure at which therepair can be made, and the pipeline pressure shall be maintained at orbelow that pressure until the repairs have been completed. This provisionapplies only to engineered repair systems (wraps) or bolt-on split sleeves.Praxair does not permit welding on lines under pressure or linescontaining hazardous or flammable gases.

Protocol: .717(b)(3) Praxair does not allow the use of fillet-welded patches, no matter what theMAOP stress levels to the pipe segment may be. For the properprotection of the repaired pipeline, the pipe shall be adequately coated

according to Praxair Standard EN-49.

22.5 Testing of Repairs

Protocol: .719(a) All replacement pipe must be pressure tested to the same pressure thatwould be required for a new pipeline installed in the same location. Thereplacement pipe may be tested before installation.

Pressure testing shall be done according to Praxair T-1 or T-6procedures.

Protocol: .719(b) All repairs made by welding shall be nondestructively tested. Theseinclude welds made to repair defective or cracked welds, welds made toinstall a full-encirclement split sleeve, and tie-in welds of new pipesegments that were pressure tested prior to installation. Nondestructivetesting shall be in compliance with API 1104, section 8 - Procedures forNondestructive Testing. Test acceptability shall be in accordance with

API 1104, section 9, or API 1104, Appendix A, for girth welds withrepaired weld defects other than cracks.

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23 PIPELINE ABANDONMENT /DEACTIVATION

23.1 Discontinuance of Service

Protocol: .727(d) When service is discontinued to a customer, one of the following actionsshall be taken:

A valve that fully isolates the customer’s piping from the Praxairpipeline shall be locked and tagged shut. Only specifically authorizedPraxair personnel may unlock or open the valve.

A flange blind or similar mechanical device or fitting that prevents theflow of gas to the customer shall be installed in the meter station orother location at or upstream of the customer’s piping.

The customer piping shall be physically disconnected from the Praxairpiping, and the open ends of the pipe shall be sealed.

23.2 Deactivated Pipelines

Deactivation refers to the cessation of use of a pipeline for some period oftime. Because a pipeline is a valuable piece of property, a deactivatedpipeline shall be maintained so that it may be restored to service.

The decision to deactivate a pipeline must consider ROW concerns,associated costs, safety, future use by Praxair, and possible sale for use

by others. The Pipeline Manager will secure Business Management andOperations Management agreement on all deactivation decisions. Uponreceipt of authorization to deactivate a pipeline facility or section thereof,it shall be the responsibility of the local pipeline location to executedeactivation procedures.

Protocol: .727(e) Pipeline segments that are to be deactivated shall be purged with aninert gas and tested as necessary to confirm that they do not containa flammable gas mixture.

Customer supply connections shall be closed and locked ordisconnected (refer to section 23.1).

Protocol: .727(c) Pipeline segments shall be physically disconnected from all sourcesand supplies of product, including connecting pipelines, crossoverpiping, meter station control piping, and other apparatus.

All disconnected piping ends or other openings shall be sealed withblind flanges, welded caps, or other sealing devices as appropriate forthe connection.

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Automatic mainline block valves shall be locked open and shall bemetal tagged open.

Pipeline markers and casing vents shall not be removed.

The deactivated segments shall remain included in the local One-CallSystem, and Praxair shall continue to respond to One-Call locaterequests on the segments as though they are still in service.

The deactivated segments shall be removed from compliance withPart 192.

Additional conditions that are found in a particular lease, license oreasement covering that section of line regarding deactivation shall beadhered to.

All records for executing the deactivation plan shall be maintained inthe files of the local pipeline office.

23.3 Abandonment of a Pipeline

If there is no further need for a pipeline and Praxair desires to cease allmaintenance of the pipeline, the following considerations apply:

Protocol: .727(e) Pipeline segments that are to be abandoned shall be purged with aninert gas and tested as necessary to confirm that they do not containa flammable gas mixture.

All connections to in-service piping shall be removed.

All aboveground elements and components shall be removed.

ROW owners shall be notified that the line will no longer be operated.

Corporate rules for abandonment shall be adhered to.

Additional abandonment actions shall be taken as stipulated byapplicable right-of-way agreements or by state or local laws orregulations.

Protocol: .727(g) For pipeline segments that cross navigable waterways, reports

documenting the location and abandonment shall be filed with theNational Pipeline Mapping System in accordance with the Standardfor Pipeline and Liquefied Natural Gas Operator Submissions and toapplicable state agencies.

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24 COMPRESSOR STATION PROCEDURES

24.1 Compressor Operating Procedures

Protocol: .605(b)(7) Procedures for compressor operations, including startup, shutdown,emergency shutdown, and other compressor-related actions that can beperformed remotely from a control center are maintained at each controlcenter.

Protocol: .605(b)(7) Procedures for local compressor operations, including startup, shutdown,emergency shutdown, and other compressor-related actions that can beperformed locally and procedures for compressor maintenance aremaintained at the local compressor control station or at the plant facilityfrom which compressor operators are dispatched.

24.2 Compressor Maintenance Procedures

Protocol: .605(b)(6) Compressor isolation shall be performed according to a procedure writtenspecifically for the compressor. Isolation procedures shall include stepsfor purging hydrogen from compressor components and adjoining pipingwith inert gas, before opening any part of the compressor. Isolationprocedures shall include steps to purge air from an isolated compressorwith inert gas before returning the unit to service.

Protocol: .731 Compressor remote shutdown devices shall be tested once per calendaryear, not to exceed 15 months. Local compressor emergency shutdown

devices shall also be tested once per calendar year, not to exceed 15months. Shutdown devices that do not function properly shall bereplaced promptly.

Compressor pressure relief valves shall be tested once per calendar year,not to exceed 15 months, as described in section 25.1, Pressure LimitingValve Inspections.

The capacity calculations for each compressor pressure relief valve arereviewed once each calendar year, not to exceed 15 months, to confirmthat the valve capacity is sufficient for the pressures and flows to which itis exposed. Any valve found to have insufficient capacity shall be

replaced immediately with a valve that has sufficient capacity for thelocation at which it is installed. Capacity calculations and reviews areperformed and documented by the Pipelines and Metering EngineeringDepartment.

The tests shall be documented in the D7i Computerized MaintenanceManagement System.

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24.3 Compressor Building Requirements

Protocol: .735(a, b), None of Praxair’s pipeline compressors are inside compressor buildings .736 or other structures. No flammable or combustible material is stored

around any compressor.

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25 PRESSURE LIMITING AND REGULATOR

STATION PROCEDURES

25.1 Pressure Limiting Valve Inspections

Protocol: .739(a)(3) All pipeline pressure limiting valves and safety relief valves shall be set toprevent pipeline pressure from exceeding the MAOP of the protectedsegment by more than 10 percent.

Protocol: .739(a)(1, 2, 4) All pressure limiting valves and safety relief valves shall be inspected,tested, and adjusted by a certified testing facility, once each calendaryear, not to exceed 15 months. Valves to be tested and their setpressures are listed in the Overpressure Protection List.

Protocol: .739(b) None of the MAOPs of Praxair pipeline segments produce stressesexceeding 72 percent of SMYS.

The testing facility shall submit a test report for each valve tested. Thereport lists the test date, repairs made, and the as-left set pressure.Copies of all test reports shall be kept in the files of the local pipelineoffice.

Protocol: .743(a, b, c) The capacity calculations for each pressure limiting device shall bereviewed once each calendar year, not to exceed 15 months, to confirmthat the valve capacity is sufficient for the pressures and flows to which itis exposed. Any valve found to have insufficient capacity shall be

replaced immediately with a valve that has sufficient capacity for thelocation at which it is installed. Capacity calculations and reviews areperformed and documented by the Pipelines and Metering EngineeringDepartment.

25.2 Meter/Regulator Station Inspections

Protocol: .739(a) Regulator valves have been installed at critical locations on all Praxair(1, 2, 3, 4) pipelines to maintain the proper operating pressure of the respective line

sections and to meet customer requirements. Meter/Regulator StationInspections shall be conducted at least once each calendar year, not to

exceed 15 months, but these inspections are typically conductedquarterly. Each inspection of a meter or regulating station shall bedocumented on the Meter/Regulator Station Inspection Report (ExhibitH). The completed reports shall be kept in the files of the local pipelineoffice.

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When an inspection reveals the need for repairs or other remedial action,such requirements shall be documented and managed with a D7i WorkOrder .

25.3 Security and Safety Requirements An exterior chain link fence shall enclose each meter/regulator stationwith gates locked when the site is unattended. Warning signs forpotential hazards, where appropriate, shall be posted; e.g., noise, no cellphones, no pagers, or other portable electrical devices, No Smoking, willbe conspicuously displayed at the station. Proper Personal ProtectiveEquipment Required signs will also be posted, i.e., Flame RetardantClothing, Hardhats, etc.

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26 VALVE INSPECTIONS

26.1 Mainline Isolation Valves

Any Praxair pipeline system equipped with mainline isolation valves shallhave these valves installed in locations readily accessible formaintenance and emergency operation.

Protocol: .745(a, b) Each isolation valve that might be required to operate in an emergencymust be partially operated at least once each calendar year (not toexceed 15 months) and promptly repaired if defective. The inspectionshall include visual and operational checks. Isolation valve inspectionsshall be documented on the Valve Exercising Log, which shall be kept inthe files of the local pipeline office.

When the inspection reveals the need for repairs or other remedial action,such requirements shall be documented and managed with a D7i WorkOrder.

26.2 Check Valves

Each Praxair pipeline contains check valves that are installed to preventbackflow of customer materials into the pipeline network.

Proper functioning of check valves shall be verified by an operational test,or the valves shall be removed for inspection and repair or replacement.

It is recognized that some of these check valves cannot be inspectedunless a customer outage occurs. An agreement between the customerand the sales department must take place. Check valve function testsare typically performed at five-year intervals, operations permitting.

Inspection results, including valve tag number and/or location, date ofinspection, method of inspection, results of inspection, remedial actiontaken, and remarks shall be documented on the Check Valve InspectionLog. A separate log shall be maintained for each check valve. All CheckValve Inspection Logs shall be kept in the files of the local pipeline office.

When the inspection reveals the need for repairs or other remedial action,such requirements shall be documented and managed with a D7i WorkOrder.

26.3 Vaults

Protocol: .749 The Praxair pipeline systems do not have any vaults.

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27 PREVENTION OF ACCIDENTAL IGNITION All construction, maintenance, and repair work to or near Praxair

pipelines shall be carried out in accordance with the rules of Praxair’sHWP procedures.

Where a hazardous amount of gas is being vented or the presence offlammable gas constitutes a hazard of fire or explosion:

Protocol: .751(a) All potential source of ignition shall be removed from the area.

Protocol: .751(a) A fire extinguisher shall be provided.

Protocol: .751(c) Warning signs shall be posted around the area.

The atmosphere shall be monitored with flammable gas detectionequipment.

Protocol: .751(b) No welding or cutting shall be permitted on any pipeline segment orcomponent containing a combustible mixture of flammable gas and air.

Activities that might otherwise present a risk of accidental ignition may berestricted to designated areas, as necessary, to ensure safe completionof the job.

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28 WELDING AND WELD DEFECT REMOVAL

28.1 Praxair Maintenance Welding Standards

All welding of Praxair pipelines shall be in accordance with PraxairStandard W-39, Field Welding of Cross Country Pipelines in compliancewith ANSI/ASME B31.8 Code, and the Praxair Gas Transmission DesignManual.

W-39 is based on ASME Gas Transmission and Distribution PipingSystems, ASME Boiler and Pressure Vessel Code Welding and BrazingQualifications, section IX, and API 1104 Welding of Pipelines and RelatedFacilities. In some cases, the applicable Praxair standards applyadditional and/or more restrictive requirements than the ASME or APIstandards and must be followed for all welding to be done on Praxairpipelines.

Welding shall only be performed on a pipeline that has beendepressurized and purged under an HWP.

28.2 Weld Procedures

Protocol: .225(a, b) All pipeline welding must be performed by a qualified welder according toa welding procedure qualified under API 1104, section 5 or ASME Boilerand Pressure Vessel Code, section IX, as specified in W-39, section 4.1.Test welds produced for weld procedure qualification shall be

destructively tested, as specified in these standards. The procedurespecification and the procedure test records shall be kept for the life ofthe pipelines on which it was used.

28.3 Welder Qualifications

Protocol: .227(a), Welders shall be qualified to perform the welding procedure specified for.229(a, b) the work being performed (refer to section 28.2). Welder qualification

shall be according to either API 1104, section 6, or ASME Boiler andPressure Vessel Code, section IX, as specified in W-39, section 4.2,including destructive testing of weld samples produced by the welderusing the procedure for which qualification is sought. For the qualification

to remain valid, the welder must have performed the specified procedurein the last six months. Welders performing welds on compressor pipingor components shall also be qualified according to these requirements.

Protocol: .227(b), Welder qualifications achieved according to Part 192, Appendix C, shall.229(c, d) not be accepted, even when welding pipe that will operate at stresses

less than 20 percent SMYS.

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Welders shall also have met the requirements of the Praxair OperatorQualification Program.

The welder shall present copies of his certifying paperwork. If thatpaperwork is more than six months old, records of having performed the

weld procedure in the last six months must also be presented. Therequired records shall be presented before starting work.

28.4 Weld Preparation and Alignment

Protocol: .235 Weld preparation and alignment shall be as specified in W-39, sections6.1 and 6.2.

28.5 Other Welding Requirements

Protocol: .231 All welding operations must be protected from the weather.

Protocol: .233 Miter joints are not permitted on underground piping (See GasTransmission Design Manual (GTE-9) section 9.9.6.7 – Fabrication andFit-up Procedures).

Additional welding requirements are specified in the Gas TransmissionDesign Manual (GTE-9) and in W-39, section 6.

Protocol: .245(*) All of the welding rods specified for pipeline welding are low hydrogenrods.

28.6 Inspection of WeldsProtocol: .241 Weld inspection procedures shall be as specified in W-39, section 7.0.

28.7 Repair of Weld Defects

Defective welds may only be repaired with the pipeline purged out ofservice.

Protocol: .245(c) Repairs shall be made in accordance with API 1104, section 10.0, at thecontractor’s expense. If a repair is unacceptable, the weld shall beremoved. Any weld with a crack that exceeds 8 percent of the weld

length shall be removed.

Additional information about repairs of weld defects may be found insection 22.3.

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29 NONDESTRUCTIVE TESTING

PROCEDURES Protocol: .243(a), (b)(1), Nondestructive tests of welds shall be performed according to a written

(c) test procedure that complies with the testing standards of the AmericanSociety for Nondestructive Testing (ASNT). The test applied shall be onethat clearly indicates defects that may affect the integrity of the weld. Thewritten procedure shall describe how to perform the test and how tointerpret the results of the test.

Protocol: .243(b)(2) Nondestructive testing shall be performed by a technician holding ASNTTC1A Level 2 certification to perform the procedure who is also trained inthe use of the tools and equipment required to perform the nondestructivetest procedure.

Weld acceptability shall be in accordance with API 1104, section 9.

Protocol: .243(d) When nondestructive testing is required, the following percentages of buttwelds shall be randomly selected for inspection:

10 percent of welds in Class 1 locations

15 percent of welds in Class 2 locations

100 percent of the welds in Class 3 and 4 locations, at major ornavigable river crossings, offshore, and within railroad or public

highway ROW, including tunnels, bridges, and overhead roadcrossings 100 percent unless impractical, then 90 percent.Nondestructive testing must be impractical for each girth weld nottested.

All tie-in welds not subjected to a pressure proof test shall be examined.

Protocol: .243(e) When nondestructive testing is required, a sample of each welder’s workshall be tested each day.

Protocol: .243(f) A record of nondestructive testing shall show by mile post, engineeringstation, or geographic feature the number of welds nondestructively

tested, the number of welds found to be defective, and the disposition ofthe defective welds.

These nondestructive test records shall be kept for the life of the pipeline.They will be stored in the local facility file room.

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30 PLASTIC PIPE Protocol: .281, .283, Praxair does not currently permit the use of plastic pipe for hazardous gas

.285, .287 service.

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31 CATHODIC PROTECTION S YSTEMS

31.1 Cathodic Protection System Design andInstallation

Protocol: .453 Cathodic protection systems for Praxair pipelines shall be designed andinstalled according to the Praxair Gas Transmission Design Manual,section GTE-14. The Cathodic Protection System shall include sufficienttest stations to measure its condition and capability to protect the pipeline.

The system may be designed and installed by Praxair or by a reputableCathodic Protection contractor. In either case, the design and installationshall comply with NACE RP-0169 and RP-0177.

Protocol: .455(a, b), All buried pipelines shall be externally coated, and a cathodic protection.457, .465(e) system shall be installed and in operation within one year of completion of

construction.

Protocol: .455(c) Materials suitable for pipeline construction are listed in Gas TransmissionEngineering Guideline, GTE-7. Aluminum, copper, or plastic may not beused as a pipeline material.

31.2 Electrical Isolation

Protocol: .467 Each buried or submerged pipeline shall be electrically isolated fromother foreign underground structures and casings except where systemdesign allows mutual cathodic protection. All aboveground piping shall beproperly grounded.

Insulating devices shall be installed where electrical isolation of a portionof a pipeline is necessary to facilitate the application of corrosion control.Insulating devices may not be installed in any area where a combustibleatmosphere is anticipated.

Pipelines shall be electrically isolated from metallic casings. Whereisolation is impractical, the existing cathodic protection current shall beadjusted, as necessary, to ensure cathodic protection of the carrier pipedespite the shorted casing.

Underground piping shall be electrically isolated by means of insulatedflanges, physical separation of at least 12 inches from other piping or bydielectric shielding. The proper installation of insulating flanges is shownin Praxair Engineering Standards EN-39 and EN-49.

Pipeline segments near electrical transmission line tower footings shall beprotected against fault currents.

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Lightning arrestors shall be installed to provide alternate electrical pathsaround insulating flanges, where necessary, to protect against possiblelightning strikes or to protect against possible AC power surges.

31.3 Coating SpecificationsProtocol: .461, .479 Coatings shall meet the following criteria:

Be applied on a properly prepared surface

Have sufficient adhesion to the metal surface to effectively resistunderfilm migration of moisture

Be sufficiently ductile to resist cracking

Have sufficient strength to resist damage from handling and soil stress

Have properties compatible with any supplemental cathodic protection

Coatings that are inherently electrically insulating must also have lowmoisture absorption and high electrical resistance.

Coatings shall be inspected just before lowering the pipe into the ditchand backfilling, and any coating damage that could affect the corrosioncontrol capability of the coating shall be repaired.

Coatings shall be protected from any trench conditions (rocks, debris,etc.) or damage from supporting blocks that could cause damage to thecoating.

Installation techniques such as boring, driving, pulling, etc., shall beperformed in a manner that minimizes coating damage.

Protocol: .479(a) All aboveground pipelines shall be cleaned and either coated or jacketedwith a material suitable for the prevention of atmospheric corrosion,including soil-to-air interfaces.

Information about external coating types and capabilities for buriedpipelines are explained in detail in the Gas Transmission Design ManualGTE-13 – Coatings for Underground Pipelines. Information aboutcoatings for aboveground piping may be found in Praxair Standard

EN-34, Painting of Industrial Gas Plants.

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31.4 Cathodic Protection Criteria

Protocol: .463 Corrosion control can be achieved at various levels of cathodicpolarization, depending on the environmental conditions. However, in the

absence of specific data that demonstrates achievement of adequatecathodic protection, one or more of the following shall apply:

-850 MV with cathodic protection current applied

Negative polarized potential of 850 MV

100 MV shift of cathodic polarization

On rectified systems, IR drop will be measured by cycling the rectifier orby use of coupons. For magnesium anode systems or rectified systems,IR drop may be measured by using dual-coupon test stations. One

coupon is connected to the pipeline and used to measure the level ofcathodic protection current applied. The second coupon is leftunconnected to the pipeline to measure the native soil potential.Momentary interruption of the protected coupon will indicate the level ofpolarization, either by having a reading higher than -850 MV or by havinga greater than 100 MV shift to the native potential measured at theunconnected coupon.

31.4.1 -850 MV with Cathodic Protection Current Applied

This refers to a negative cathodic potential of at least 850 MV (relative toa saturated copper-copper sulfate reference electrode) with the cathodic

protection applied and consideration given to electrolytic voltage droperrors.

This potential is measured with the reference electrode contacting theelectrolyte. Voltage drops, other than those across the structure toelectrolyte boundary, must be considered for valid interpretation of thisvoltage measurement.

Consideration of electrolytic voltage drop errors is understood to meanthe application of sound engineering practice in determining thesignificance of voltage drops by methods such as:

Measuring or calculating the voltage drops

Reviewing the historical performance of the cathodic protectionsystem

Evaluating the physical and electrical characteristics of the pipe andits environment

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When appropriate, other standard reference electrodes may besubstituted for the saturated copper/copper sulfate reference electrodewith proper voltage conversion to copper/copper sulfate referenceequivalent.

31.4.2 Negative Polarized Potential of –

850 MV

This refers to a negative polarized potential of at least -850 MV relative toa saturated copper-copper sulfate reference electrode.

This potential is to be measured with the cathodic protection currentinterrupted. Care must be taken to record this Instant Off potential beforesignificant depolarization occurs. It is very important that all currentsources affecting the survey area be interrupted for this measurement.

When appropriate, other standard reference electrodes may besubstituted for the saturated copper/copper sulfate reference electrodewith proper voltage conversion to copper/copper sulfate referenceequivalent.

31.4.3 100 MV Shift of Cathodic Polarization

This refers to a minimum of 100 MV of cathodic polarization between thestructure surface and a stable reference electrode contacting theelectrolyte.

This criterion requires two voltage measurements. One measurement isthe polarized potential described above. The other measurement is thedepolarized potentials taken after the cathodic protection current sourceshave been de-energized (or disconnected) and the structure allowedsufficient time to depolarize.

The difference between both measurements is the cathodic polarization.This difference must be at least 100 MV.

The formation or decay of polarization can be measured to satisfy thiscriterion, that is, the voltage measurements may be performed in eitherorder.

31.5 Cathodic Protection System Annual Inspection

Protocol: .465(a), .469 Each cathodic protection system shall be tested at least once eachcalendar year, not to exceed 15 months. The inspection shall includemeasurement of pipe to soil potentials and tests for shorted casings. Testleads shall also be inspected as part of the survey to ensure properfunctioning and to ensure that there are a sufficient number of test leadsto determine the adequacy of the Cathodic Protection System beinginspected.

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Test meters and half-cells shall be calibrated, as required, to ensure thattests and measurements are accurate and repeatable. These calibrationresults shall be recorded as part of the report for which they wereperformed.

When the survey indicates a shorted casing, the report will also indicatewhether the short is metallic or non-metallic. If a metallic short isindicated, it shall be repaired. If a non-metallic short is identified, thecasing shall be inspected with leak-detection equipment at least twiceeach calendar year, not to exceed 7½ months.

Cathodic Protection Survey results shall be reported on a CathodicProtection Survey Report that includes readings taken at each teststation, repairs, or other remediation required, and any other notableconditions observed.

31.6 Rectifier InspectionsProtocol: .465(b) Rectifier stations shall be inspected six times each calendar year (not to

exceed 2½ months) as part of the normal pipeline patrol to ensure thatthey are operating properly and have not been damaged. Inspectionresults shall be reported on the appropriate Exhibit C Report Form.

31.7 Stray Currents and Interference Bonds

Protocol: .465(c) Critical interference bonds shall be inspected at least six times percalendar year, not to exceed 2½ months. All other bonds shall bemonitored, as required, to ensure proper operation of the bond. Bond

inspections are typically performed in conjunction with rectifierinspections.

Protocol: .473 In addition to the regularly scheduled inspections, which include tests tocheck for potential stray currents, Praxair corrosion specialists shallparticipate in corrosion control committees, where they exist, to resolvepotential interference problems with operators of other pipelines or otherunderground structures

31.8 Cathodic Protection System Repair

Protocol: .465(d), .471 When the inspection reveals the need for repairs or other remedial action,such repairs shall be made promptly, and repair requirements and resultsshall be documented and managed with a D7i Work Order. Repairs mayinclude the following, as appropriate for the problems found:

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The application or repair of a protective coating

The installation of anodes

The application of impressed current (via rectifier)

Electrical isolation from adjacent pipelines or structures

The control of stray currents from other systems

31.9 Cathodic Protection Records

Protocol: .491 Each pipeline location shall maintain Cathodic Protection maps to showcathodically protected piping, cathodic protected facilities, andneighboring structures bonded to the Cathodic Protection System.Records of each test, survey, and inspection required by this section shall

also be maintained in the files of the local pipeline office. The recordsshall identify the pipeline system, site location, date of test, and results,findings, or remarks. All records shall be kept for as long as the pipelineis in service.

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32 CORROSION INSPECTIONS AND

RESPONSE

32.1 Aboveground Piping Inspections

Protocol: .481 Each aboveground pipeline and soil/air interface shall be visuallyinspected for corrosion at least once every 3 calendar years, not toexceed 39 months. The inspection shall cover the following items:

Painting/coating condition on external pipe surfaces

Soil-to-air interfaces

Thermal insulation

Under disbonded coating

Pipe supports

Splash zones

Deck penetrations

Spans over water

Soil/air interfaces shall be given special attention for corrosion prevention.

Inspections reports shall be maintained in the files of the local pipelineoffice.

32.2 External Inspection of Exposed Pipe

Protocol: .459 Whenever a portion of an underground pipeline is exposed, the exposedportion shall be examined for evidence of external corrosion anddeteriorating coating. Inspection results shall be reported using theExposed Pipe Inspection Report. Exposed pipe shall be photographed,as required, to document all corrosion or defects found.

If evidence of external corrosion is found, the area must be cleaned, andthe actual wall thickness shall be determined using an ultrasonicthickness gauge. The RSTRENG® or B31G calculation method shall beapplied to determine the strength of the remaining wall.

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32.3 Inspection of Exposed Internal Pipe Surfaces

Protocol: .475, .477 Praxair hydrogen pipelines transport very high-purity dry hydrogen gas,which does not contain significant amounts of corrosive compounds.

Internal corrosion is not anticipated, nor has evidence of internalcorrosion ever been found. As a result, Praxair pipelines do not requirecoupons for monitoring internal corrosion.

Protocol: .475(b) If during the process of pipeline maintenance or capital project work theinternal surfaces of a pipeline segment are exposed or a pipelinesegment is removed, the internal walls of the section of pipeline that wasremoved and the ends of the pipeline still in the ground shall be inspectedfor internal corrosion. Inspection results shall be reported on the ExposedPipe Inspection Report.

Protocol: .475(b) If there is any evidence of internal corrosion, the pipeline sections still in

the ground shall be inspected as necessary to determine the extent of thecorrosion. The RSTRENG® or B31G calculation method must be appliedto determine the strength of the remaining wall.

32.4 Investigation of Causes of Corrosion

Whenever any form of corrosion of a pipeline segment is discovered, anRCA must be performed to determine the causes of the corrosion and toidentify corrective measures to prevent further corrosion from theidentified causes (refer to Chapter 11, Failure Investigation).

32.5 Prompt Repair of Corroded PipeProtocol: .475(b), .485 When a corrosion inspection reveals the need for repairs or other

remedial action, such repairs shall be made promptly. If RSTRENG® orB31G calculations reveal that the strength of the remaining pipe wall isinsufficient for the current MAOP of the segment and the segment will notor cannot be repaired promptly, the MAOP of the segment shall bereduced to a pressure suitable for the strength of the remaining wall.

Protocol: .483 Repairs to corroded underground and aboveground pipe shall be madeby cutting out and replacing the corroded pipe segment with pipe thatmeets the requirements for new pipe installed in the same location, or the

pipe shall be repaired by installation of an engineered repair system thatcan permanently restore the serviceability of the pipe. Repaired orreplacement pipe shall also be appropriately coated and cathodicallyprotected. Refer to section 22, Field Repair Procedures, for moreinformation about repairs.

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Protocol: .481(c) Aboveground or buried pipe that is not severely corroded enough torequire replacement or repair shall be cleaned and recoated with acoating material suitable for the installation location and conditions.

Repair requirements and results shall be documented and managed with

a D7i Work Order .

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33 UNDERWATER PIPELINE INSPECTIONS Protocol: .612(a, b) Periodically, underwater pipeline surveys are conducted to ensure that

pipelines in navigable waters have adequate cover and do not leak.

Protocol: .612(c) If it is discovered that a pipeline is exposed or constitutes a hazard tonavigation, the National Response Center (NRC) will be notified within 24hours. Reporting to the NRC is explained in the local Emergency Plan.

Also, within 7 days, the exposed segments of the pipeline shall bemarked in accordance with 33 CFR 64 (mark the ends of the exposedsegments and at intervals not more than 500 yards along the exposedsegments). Corrective action to rebury the exposed segments or to applyan engineered solution to provide the same level of protection as burialshall be completed within 6 months.

An accredited underwater pipeline contractor shall be hired to perform thesurvey and submit a findings report that will be kept in the files of the localpipeline office.

Operation of the cathodic protection equipment, which is installed toprotect the integrity of the underwater pipeline, will be tested.

The contractor performing the inspection shall provide a report of findings,including depth of cover.

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34 LEAK INSPECTION AND RESPONSE

34.1 Leak Classification and Action Criteria

Pipeline leaks are classified into three grades, as shown in Table 3.

Table 3Leak Classification

Grade Definition

Grade 1 A leak that represents an existing hazard to persons or property and requiresimmediate repair or continuous action until conditions are no longer hazardous.

Grade 2 A leak that is recognized as being non-hazardous at the time of detection but justifies scheduled repair based on probable future hazards.

Grade 3 A leak that is non-hazardous at the time of detection and can reasonably beexpected to remain non-hazardous.

If a leak or failure is classified as a Grade 1 leak, the local pipelinepersonnel shall immediately initiate the emergency plan specified in theEmergency Plan. A Leakage Detection Report shall be completed assoon as practical.

In certain circum stances, a leak may also be classif ied as an

inc ident, as defined in 49 CFR 191. Incid ents must be

reported as soon as practicable. Report ing requirements are

explained in the loc al Emergency Plan.

If the leak is not considered to be an emergency, it should be classified asa Grade 2 or 3. A Leak Detection Report shall be completed, and a workorder shall be entered into the D7i Maintenance Management System fora scheduled repair. The priority of the work request and scheduled repairshall be based on the severity of the leak and probable future hazard, asdescribed under the definition of a Grade 2 leak. Leaks that are classifiedas a Grade 2 or 3 will be monitored until the leak has been repaired.

34.1.1 Leak Investigation

All leaks shall be investigated to determine cause. The leak investigationshall follow the Praxair RCA process to identify probable causes andcontributory conditions. The RCA shall also provide recommendations toprevent reoccurrence.

If any section of leaking or corroded pipe has been replaced to repair theleak, the pipe section that was removed shall be analyzed by the Praxair

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Metallurgical Lab or by a suitably qualified outside lab to identifyconditions that may have caused or contributed to the leak.

34.1.2 Leak Reporting

All pipeline leaks will be reported to Pipeline and Metering Engineering.The Leak Detection Report, which includes the preliminary findings of thefailure investigation, shall be included.

A copy of the Leak Detection Report, including details of the incident andthe final failure investigation, will be kept in the files of the local pipelineoffice. A copy of the report shall also be submitted to the PipelineRegulatory Compliance Manager, who will submit reports as required tofederal and state government agencies.

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OM-2287Issued: Nov 1995, Revised: Oct 2007 Page I-1 of 3

INDEX

100 MV Shift of Cathodic Polarization 48

-850 MV with Cathodic Protection Current Applied 47

A

Abandonment of a Pipeline 34 Abnormal Operating Conditions 8

AOC Follow-up 9Generic AOCs 8Notifying Personnel of an AOC 9Task-specific AOCs 8

Aboveground Piping Inspections 51 Aboveground Piping Leak Detection 27 Annual Report 3

AOC Follow-up 9 Availability of Pipeline Records 6

C

Casing Vent Stacks 26Cathodic Protection Criteria 47

100 MV Shift of Cathodic Polarization 48-850 MV with Cathodic Protection Current

Applied 47Negative Polarized Potential of -850 MV 48

Cathodic Protection Records 50Cathodic Protection System Annual Inspection

48Cathodic Protection System Design and

Installation 45Cathodic Protection System Repair 49Cathodic Protection Systems 45

Cathodic Protection Criteria 47Cathodic Protection Records 50Cathodic Protection System Annual Inspection

48Cathodic Protection System Design and

Installation 45Cathodic Protection System Repair 49Coating Specifications 46Electrical Isolation 45

Rectifier Inspections 49Stray Current and Interference Bonds 49

Check Valves 39Class 1 Location 10Class 2 Location 10Class 3 Location 10Class 4 Location 10Class Location Studies 10

Class Locations 10

Class Location Studies 10Definitions 10MAOP Change Due to Class Locator Change

11Class Locations Units 10Coating Specifications 46Compressor Building Requirements 36Compressor Maintenance Procedures 35Compressor Operating Procedures 35Compressor Station Procedures 35

Compressor Building Requirements 36Compressor Maintenance Procedures 35Compressor Operating Procedures 35

Conditions That Must Be Reported 2Construction Activity along ROW 26Continuing Surveillance 13Corrosion Inspections and Response 51

Aboveground Piping Inspections 51External Inspection of Exposed Pipe 51Inspection of Exposed Internal Pipe Surfaces

52Investigation of Causes of Corrosion 52Prompt Repair of Corroded Pipe 52

Customer Notifications 5

D

Damage Prevention Program 14Deactivated Pipelines 33Definitions 10

Class 1 Location 10Class 2 Location 10Class 3 Location 10Class 4 Location 10Class Locations Units 10

Detection Report Form 28Discontinuance of Service 33DOT Reporting Addresses 3

E

Electrical Isolation 45Emergency Manuals 15External Inspection of Exposed Pipe 51Failure Investigation 17Field Repair Procedures 31

Immediate Response to Pipeline Damage 31Permanent Field Repair of Leaks 32Permanent Field Repair of Welds 31

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Index

OM-2287Page I-2 of 3 Issued: Nov 1995, Revised: Oct 2007

Repair of Imperfections and Damage 31Testing of Repairs 32

F

Filing a Safety-Related Condition Report 3

G

Generic AOCs 8

I

Immediate Response to Pipeline Damage 31Incident Reporting 2Inspection of Exposed Internal Pipe Surfaces 52Inspection of Welds 42Investigation of Causes of Corrosion 52

L

Leak Classification and Action Criteria 55Leak Investigation 55Leak Reporting 56

Leak Inspection and Response 55Leak Classification and Action Criteria 55

Leak Investigation 55Leak Reporting 56Leak Surveys 26

Aboveground Piping Leak Detection 27Detection Report Form 28Leaks Detected in non-Praxair Pipelines 28Scheduled Leak Surveys 26Unscheduled Leak Surveys 27

Visual Inspection for Underground PipingLeaks 27

Leaks Detected in non-Praxair Pipelines 28

M

Mainline Isolation Valves 39Maintenance Procedures 24MAOP Change Due to Class Locator Change 11Maximum Allowable Operating Pressures 18Meter/Regulator Station Inspections 37

N

Negative Polarized Potential of -850 MV 48Nondestructive Testing Procedures 43Normal Operations 6

Availability of Pipeline Records 6Operations and Maintenance Manual

Review 6Pipeline Startup and Shutdown 6Pipe-type and Bottle-type Holders 7Procedure Review and Update 7

Report of a Gas Odor Inside a Building 7Safety Precautions for Excavated Trenches 7

Notices iiiNotifying Personnel of an AOC 9

oOdorization of Gas 21Operations and Maintenance Manual Review 6Other Reports 3Other Welding Requirements 42

P

Permanent Field Repair of Leaks 32Permanent Field Repair of Welds 31Pipeline Abandonment/Deactivation 33

Abandonment of a Pipeline 34Deactivated Pipelines 33Discontinuance of Service 33

Pipeline Blowdown, Purging, or Re-Pressurization 23

Pipeline Cover 25Pipeline Markers 29Pipeline Startup and Shutdown 6Pipe-type and Bottle-type Holders 7Plastic Pipe 44Praxair Maintenance Welding Standards 41Pressure Limiting and Regulator Station

Procedures 37Meter/Regulator Station Inspections 37Pressure Limiting Valve Inspections 37Security and Safety Requirements 38

Pressure Limiting Valve Inspections 37Pressure Testing 19Prevention of Accidental Ignition 40Procedure Review and Update 7Prompt Repair of Corroded Pipe 52Public Education 16

R

Recordkeeping 30Rectifier Inspections 49Repair of Imperfections and Damage 31Repair of Weld Defects 42Report of a Gas Odor Inside a Building 7

Reporting Requirements 2 Annual Report 3DOT Reporting Addresses 3Incident Reporting 2Other Reports 3Safety-Related Conditions Reporting 2

Right-of-Way Patrols 25Casing Vent Stacks 26

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Construction Activity along ROW 26Pipeline Cover 25ROW Patrol Schedule 25

Right-of-Way Patrols and Leak Surveys 25Leak Surveys 26

Right-of-Way Patrols 25ROW Patrol Schedule 25

S

Safety Precautions for Excavated Trenches 7Safety-Related Conditions Reporting 2

Conditions That Must Be Reported 2Filing a Safety-Related Condition Report 3

Scheduled Leak Surveys 26Scope and Purpose 1Security and Safety Requirements 38Stray Current and Interference Bonds 49

TTapping Pipelines Under Pressure 22Task-specific AOCs 8Testing of Repairs 32

U

Underwater Pipeline Inspections 54Unscheduled Leak Surveys 27Uprating Pipeline MAOP 20

V

Valve Inspections 39

Check Valves 39Mainline Isolation Valves 39Vaults 39

Vaults 39Visual Inspection for Underground Piping Leaks

27

W

Weld Preparation and Alignment 42Weld Procedures 41Welder Qualifications 41W ldi d W ld D f t R l 41