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Pipeline Incident Report

Natural Gas Pipeline Rupture near

Fort St. John, British Columbia

15 May 2002


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Pipeline Incident Report

Natural Gas Pipeline Rupture near

Fort St. John, British Columbia

15 May 2002


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© Her Majesty the Queen in Right of Canada as represented by theNational Energy Board 2004

Cat. No. NE23-119/2004EISBN 0-662-37318-9

This report is published separately in both official languages.

Copies are available on request from:

The Publications OfficeNational Energy Board

444 Seventh Avenue S.W.Calgary, Alberta, T2P 0X8E-Mail: [email protected]: (403) 292-5576Phone: (403) 299-35621-800-899-1265Internet: www.neb-one.gc.ca

For pick-up at the NEB office:

LibraryGround Floor

Printed in Canada

© Sa Majesté la Reine du chef du Canada représentée parl’Office national de l’énergie 2004

Nº de cat. NE23-199/2004FISBN 0-662-77074-9

Ce rapport est publié séparément dans les deux langues officielles.

Demandes d’exemplaires :

Bureau des publicationsOffice national de l’énergie

444, Septième Avenue S.-O.Calgary (Alberta) T2P 0X8Courrier électronique : [email protected]élécopieur : (403) 292-5576Téléphone : (403) 299-35621-800-899-1265Internet : www.neb-one.gc.ca

Des exemplaires sont également disponibles à la

bibliothèque de l’Office :Rez-de-chaussée

Imprimé au Canada

Permission to Reproduce

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For permission to reproduce the information in this publication for commercial redistribution, please e-mail: [email protected]

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Pipeline Incident Report i

Table of Contents

Table of Contents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .i

List of Acronyms and Abbreviations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .ii

Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .iii

Factual Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1Incident Synopsis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1Incident Narrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1Emergency Response . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .218-inch Fort St. John Pipeline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4Laboratory Examination of the Ruptured Pipeline Segment . . . . . . . . . . . . . . . . . . . . . . . . .4

Table 1: Rupture Pipe Steel Properties, API 5LX (1975) andCSA Z245.4 M1979 Specifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5

CSA Design Code Toughness Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6Pipeline In-line Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6Liquids Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6Gas Quality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7

Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8Hydrate Formation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8Pipe Quality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9Operating History . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9Emergency Response . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10Record Keeping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10

Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10

Safety Action Section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11 Action Taken by Westcoast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11

Pipeline Reconstruction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11Pipeline Integrity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11

NEB Directives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11

Appendices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12 Appendix A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12

Figure A1: Map of Taylor - fort St. John Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .14Figure A2: Schematic of Sending Barrel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .15


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ii National Energy Board

List of Acronyms and Abbreviations

API American Petroleum Institute

CSA Canadian Standards Association

˚C degree Celsius, unit of measure

Duke Duke Energy Gas Transmission

DSAW double submerged arc welded

EPZ emergency planning zone

ERW electric resistance welded

H2S hydrogen sulphide

in inch, unit of measure

J Joule, unit of measure

kPa kilopascals, unit of measure

ksi one thousand pounds per square inch, unit of measure

m meter, unit of measure

mm millimeter, unit of measure

MMscf million standard cubic feet, unit of measure

M.P. mile post

psi pounds per square inch, unit of measure

RCMP Royal Canadian Mounted Police

Samson Samson Canada Ltd.

SSCC sulphide stress corrosion cracking

WGC Westcoast Gas Control, located at Charlie Lake at the north end of Fort St. John


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Executive Summary

At approximately 15:08 Mountain Standard Timeon 15 May 2002, an 18-inch diameter natural gastransmission pipeline owned by Westcoast Energy

Inc., carrying on business as Duke Energy GasTransmission, ruptured at a location adjacent tothe Alaska Highway near the city of Fort St. John,British Columbia. The rupture occurred on asending barrel at a valve station. A Westcoastemployee was working on the sending barrel whenit ruptured and was knocked to the ground, butwas otherwise unhurt. The rupture in the pipelineresulted in the release of approximately 3.73MMscf of sour (0.41per cent H2S) natural gas. The

released gas did not ignite and developed into aplume which was blown by the wind towardnearby residences and a trailer park until the gasdissipated. There were no injuries resulting fromthe rupture. According to Westcoast Energy Inc.,property and other damages or losses totaled$139,960.

The emergency response to the incident wascoordinated by Westcoast until the onsite arrival of the Taylor Fire Chief who assumed the role of the

Field Incident Commander. Westcoast immediatelyisolated the section of the pipeline from gassources by closing line break valves upstream anddownstream of the rupture. The emergencyresponse resulted in stoppages of traffic on the

Alaska Highway, as well as between the highwayand the airport and the Baldonnel ElementarySchool. Notification to the airport of the ruptureand gas plume resulted in the issuance of flightrestrictions for the affected area by the airport’sflight services. Rail traffic was also stopped on a

rail line in the path of the gas plume.

Westcoast began phoning residents in the affectedemergency planning zone with a “shelter in place”message, meaning that the residents should stay intheir homes until the situation had been resolved

or it had been determined it was safe to evacuate.Having heard the initial rupture and havingwitnessed the developing gas plume, manyresidents in the immediate vicinity of the incidenthad already begun to evacuate themselves. After

observing the direction of travel of the gas plume,the Taylor Fire Chief made the decision toevacuate any remaining people in the areadownwind from the incident site, as well as theEdgewood Trailer Park and surrounding housing.

Attempts to contact residents in the emergencyplanning zone by Westcoast were discontinuedwhen it became apparent that all residents werebeing evacuated. Since the school day was drawingto a close, the Baldonnel Elementary School wasloading children onto school buses when the

rupture occurred. A local resident notified theschool of the rupture and to avoid travel westwardtowards the rupture and the evolving gas plume.

After testing did not find any measurable levels of H2S at the Alaska Highway, the Edgewood Trailer

Park, and the Baldonnel School, the area wasdeclared safe. Traffic blocks on the highway wereremoved, flight restrictions for the area wereremoved, and the rail line was reopened. The timefrom the rupture of the pipeline to Field IncidentCommander declaring the situation safe and securewas approximately two hours and twenty minutes.

Westcoast sent the section of ruptured pipe to anindependent laboratory for detailed metallurgicalfailure analysis and physical examination. TheNational Energy Board investigation included areview of laboratory analysis, Westcoastdocumentation available for the ruptured pipe,

Westcoast procedures and records.

The National Energy Board investigation of therupture resulted in the following findings:

1. The pipeline rupture was likely caused by ashock wave or impact created after a hydrateor ice plug blockage was released by adifferential pressure.

Pipeline Incident Report iii


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2. At the time of the incident, the sending barrelpipe was in a weakened condition caused bythe large centerline laminations that hadaccumulated elemental hydrogen, creating aninward bulge.

3. The sending barrel was idle for two yearsallowing fluids to accumulate.

4. The ruptured pipe did not meet the toughnessrequirements of the applicable CSA designstandard in effect at the time of pipefabrication and construction.

5. Westcoast did not have the necessarydocumentation for the materials and design of the sending barrel.

6. There was a lack of communication betweenthe Westcoast Incident Commander and theTaylor Fire Departments Field IncidentCommander.

As a result of the investigation into the rupture of the 18-inch Fort St. John natural gas transmissionpipeline, the NEB directs Westcoast as follows:

Directive 1

Westcoast shall review its Operations Manualto ensure the safe operation of pipelines thattransport raw gas or residue gas, payingparticular attention to:

a) hydrate prevention program;

b) the prevention of liquids accumulation;

c) procedures for the safe handling andremoval of hydrates.

Directive 2

Westcoast shall ensure that its pipeline oraboveground facilities integrity managementprograms provide for regular inspection andassessment of above ground piping inconformance with paragraph 8.8.1 of the

Westcoast OPR’99 audit of T-Central in 2001.

Directive 3

Westcoast shall review its pipeline system

records for the specifications and materialproperties related to the reuse of materials orequipment for projects executed since 1999.

Westcoast shall determine the adequacy of such records. Westcoast shall assess thesignificance of any gaps or deficiencies,develop an appropriate action plan, andsubmit it to the Board for approval within60 days of the issuance of this directive.

Directive 4

Westcoast shall review with its first responders,in the Fort St. John area, Westcoast’semergency response plan including thehandover of incident command, to ensure acommon understanding of its requirementsand accountabilities.

iv National Energy Board


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Factual Information

Incident Synopsis

At approximately 15:08 Mountain Standard Time

on 15 May 2002, an 18-inch-diameter steelpipeline owned by Westcoast Energy Inc., carryingon business as Duke Energy Gas Transmission(Westcoast), ruptured and released about 3.73MMscf of sour natural gas. The pipeline rupturedat an S-bend section of pipe where the pipedescends underground between a sending barreland an isolation valve. A Westcoast employeeworking beside the sending barrel was knocked tothe ground, but was otherwise unharmed. Therewere no other injuries. As of December 2002,

Westcoast estimated the total cost of the incident,including repair, cleanup, and restoration, to be$139,960.

The rupture was located within a fenced site on Westcoast’s pipeline right-of-way adjacent to acompressor station operated by Samson CanadaLtd. (Samson). There was no ignition of theescaping gas and, as a result, a large sour(0.41per cent H2S) gas plume developed. The

prevailing wind was from the southwest at 19km/hr, and was blowing the gas plume towardsthe Edgewood Trailer Park and the AlaskaHighway. The trailer park was 300 meters from theincident site. Further downwind of the gas plumewere the Baldonnel Elementary School and theflight path of the Fort St. John Municipal Airport.

Incident Narrative

On the afternoon of 15 May 2002, a Westcoastemployee began servicing valves at a pigging sitelocated at M.P. 2.47 on the 18-inch Fort St. Johnpipeline. Valve servicing is a routine maintenanceoperation which involves lubrication and cyclingof the valves between the open and closedposition. Adjacent to the Westcoast pigging site is

a compressor station where a Samson employeewas on site.

After servicing several valves on the adjacent16-inch Oak pipeline, the servicing of the 18-inchgate valve, which isolates the pig sending barrelfrom the pipeline, was the next scheduled activity.

With the initiation of work on the 18-inch valve,the employee discovered that the pig sendingbarrel was filled with a condensate and watermixture, which had also filled the power supplyline and the gas motor connected to the valveoperator. In order to correct this situation, theemployee first attempted to drain the barrel bymanually opening the isolation valve to allow thebarrel contents to drain. When this approach

proved unsuccessful, the employee attempted tocreate a pressure differential to push the liquidcontents down the barrel. Despite these actions,the employee determined that there was no flow of fluids from the sending barrel.

Upon further analysis of the situation and aftertrying to confirm the position of the valve’sisolating gate by observing the height of the valvestem, the employee then concluded that the valvestem may have separated from the internal gate. To

determine if the gate of the valve was in either theup or down position, the employee first decided todepressurize the sending barrel from the rear flarevalve located upstream and adjacent to the gatevalve. Upon initiating this action, the employeediscovered that the rear flare valve was seized andcould not be used to depressurize. Turning hisattention to the front flare valve, which is locatedon the front side of the sending barrel adjacent tothe barrel door, the employee discovered that thefront flare would open. However, the result of

opening the front flare valve immediatelyextinguished the flame in the flare stack with thesudden surge of liquids being purged from thesending barrel. The employee immediately closedthe front flare valve, waited for the flare stack to

Pipeline Incident Report 1


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relight itself, and reopened the front valve at areduced rate, so as not to extinguish the flare again.

As the barrel was slowly depressurizing, theemployee collected his tools and then began toreconnect supply lines to the isolation valveoperator. At this point in time, the employeenoticed that the pressure gauge at the rear flarevalve read 600 psi. A review of gas control recordsafter the incident indicated that the pipelinepressure was actually 743 psi at this time.Checking the pressure gauge at the front flarevalve, the employee observed that this gauge read100 psi. Realizing that there was a problem, theemployee was about to head back to the isolationvalve when the pipeline ruptured at the point

where the sending barrel descended into theground. The escaping gas and liquids caused thetransformer on the overhead power lines tooverload resulting in a bright flash witnessed bynearby residents. At the time of rupture theemployee was just in front of, and slightly to theside of the barrel door. The rupture caused thesending barrel to shift on its supports and into theemployee, striking him at groin level and knockinghim to the ground. When the employee stood up,the release of gas and fluids from the pipeline blew

the employee into an adjacent fence. Theemployee noted that he could taste saltwater afterbeing sprayed with the liquids in the pipeline. Theemployee regained his feet, observed that thepipeline had ruptured at the point where thesending barrel descended into the ground andthen climbed over the fence to the Samsoncompressor site. A Samson employee called

Westcoast Gas Control and notified of the pipelinerupture and associated sour gas release.

Emergency Response

With the rupture of the pipeline at approximately15:08 MST and the escape of the Westcoastemployee to the Samson compressor stationupwind and adjacent to the pipeline, a Samson

employee called Westcoast Gas Control (WGC),located in Fort St. John, at 15:18. The Westcoastemployee provided vital information to WGC onthe nature of the rupture, the direction of the gasplume and reported that no other personnel were

involved. The two personnel then proceeded toevacuate the Samson compressor site to the AlaskaHighway at the North Peace Apiaries Ltd. honeyfarm where they were met by other Westcoast andSamson personnel. Upon arrival, the Westcoastemployee was taken to the hospital forexamination. Two Samson employees blockedsouthbound traffic at this location until relieved of these duties by the RCMP at approximately 15:28.

At 15:15, the Fort St. John Fire Dispatch received

a 911 notification of the incident. It could not beverified who notified the Fire Dispatch through the911 call. Notifications to the RCMP, the Taylor FireDepartment, and local ambulance were made bythe Fire Dispatch by 15:17. At 15:19, Fort St. JohnFire Dispatch contacted WGC to confirm thelocation and relay this information back to theTaylor Fire Department.

Upon notification of the incident at 15:18, theSupervisor from WGC at Charlie Lake temporarily

assumed the duties and responsibilities of theIncident Commander role and began to implement

Westcoast’s Emergency Response Plan. WGCpersonnel immediately isolated the section of pipeline containing the rupture by closing the16-inch Oak line break valve at mile post 17.27and the 18-inch Fort St. John line break valves atmile posts 6.31 and 7.04. By 15:20, all of thesevalves were considered closed. The rate of gas flowescaping from the ruptured pipeline quicklydecreased. By 15:40, on site confirmation was

received by WGC of valve closures. Westcoastpersonnel were also sent to manually shut in allproducers at their receipt points.

At 15:18, the control room operator at Westcoast’sMcMahon Complex in Taylor was notified by

2 National Energy Board


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WGC of the incident. An investigative team wasimmediately dispatched from the McMahonComplex, and arrived on the incident site at15:33, at the same time as the Taylor FireDepartment. At this point in time, the Fire Chief

from the Taylor Fire Department assumed the roleof Field Incident Commander. Northbound trafficwas blocked on the Alaska Highway at theEdgewood Trailer Park. Traffic to the airport andBaldonnel Elementary School was also blocked. Atthis time, the Taylor Fire Department noted astrong smell of gas and that the wind was movingthe gas plume in a north east direction toward theEdgewood Trailer Park.

At 15:28, the RCMP arrived at the road block at

the North Peace Apiaries Ltd. honey farm andrelieved the Samson personnel manning thesouthbound traffic road block. At 15:30, the TaylorFire Department instructed the RCMP tocompletely close the highway. The RCMP thenproceeded to the second road block established bythe Taylor Fire Department at the EdgewoodTrailer Park. This road block would be movedsouth to the top of North Taylor Hill at 15:40.

At 15:30 an Incident Command Post was

established in the Emergency Response Room at WGC. At the same time Westcoast’s Land Resource Agents were delegated to be the telephonenotification team and to start contacting residentsin the affected emergency planning zone (EPZ).The Westcoast Incident Commanderrecommended that residents in the affected areashould “shelter in place”, meaning that theresidents stay in their homes until the situation hasbeen resolved or it has been determined it is safeto evacuate. After determining the affected

residents from the appropriate site specificemergency response plan and area map, thetelephone notification team started phoningresidents at 15:40. By 15:45 only one contact hadbeen made, with all other calls having no answer.

Attempts to contact residents in the EPZ by Westcoast were discontinued when it becameapparent that all residents were being evacuated.

Having heard the initial rupture and havingwitnessed the developing gas plume, residents inthe immediate vicinity of the incident began toevacuate themselves. Since the school day wasdrawing to a close, the Baldonnel ElementarySchool was loading children onto school buseswhen the rupture occurred. A local residentnotified the school of the rupture and to avoidtravel westward towards the rupture and theevolving gas plume. By 15:25, the Taylor FireDepartment was notified that the school had beenevacuated. At 15:50, a gas check was performed at

the Baldonnel School and no level of H2S wasdetected. Also at 15:50, the Taylor Fire Chief madethe decision to evacuate people in the downwindarea from the incident site, as well as theEdgewood Trailer Park and surrounding housing.Residents in the affected areas were instructed togather at a site near the south roadblock on the

Alaska Highway. At the request of the Taylor FireChief, the airport was notified by Fire Dispatch. At15:40 a “notice to airmen” was issued by theairport’s flight services putting flight restrictions inplace for the affected area. At 15:50, a B.C. Railrepresentative confirmed to the Taylor Fire Chief that rail traffic had been stopped. There was norecord of how B.C. Rail was notified. The TaylorFire Chief informed Westcoast’s onsite supervisorwho relayed the message to WGC that theevacuation of residents was complete at 16:10.

At 16:07, Westcoast personnel performed the firstvisual inspection of the rupture site and confirmedthat there were no remaining personnel in the areaand also confirmed that there was no pressure atthe gate valve nearest the rupture site. At 16:45,

Westcoast personnel began extensive testing of the Alaska Highway and of the Edgewood Trailer Parkfor the presence H2S.



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Shortly after 17:00, the Edgewood Trailer Park wasdeclared safe and the Alaska Highway road blockswere removed. Flight Services at the airport wasalso notified at this time that flight restrictions inthe area of the rupture could be removed. The

B.C. Rail line was reopened. At 17:30, the TaylorFire Chief declared the situation secure andordered his team to return to the fire hall. Sitecontrol was then returned to Westcoast.

18-inch Fort St. John Pipeline

The 18-inch Fort St. John pipeline was built in1957 using electric resistance flash welded (ERW)pipe manufactured by A.O. Smith. Over time,sections of the pipeline have been upgraded oraltered, such as the sending barrel where thepipeline rupture occurred. According to Westcoastas-built drawings, the sending barrel was moved ormodified in 1979. These drawings contain a notewhich states “material list not as-built”. The fieldand laboratory analysis of the ruptured pipedetermined that the pipe was manufactured using adouble submerged arc welded (DSAW) process andwas therefore not part of the original installation.

Westcoast could find no records to identify theorigin, grade, or vintage of the ruptured pipe.

For design purposes, the18-inch Fort St. Johnpipeline crosses through two class locationassessment areas, that is, through a class 1 andclass 3 designations1. In class 1 locations, thepipeline has a wall thickness of 7.1 mm (0.280inch), a pipe grade of 359 MPa (X52), and a pipemanufacturing standard of API 5LX-52. In class 3locations, the pipeline has a wall thickness of 7.6 mm (0.300 inch), a pipe grade of 414 MPa,and a pipe manufacturing standard of the Canadian

Standards Association (CSA) Z245.1-M1979.

The ruptured S-bend section of pipe between thebarrel and the isolation valve had a measured wall

thickness of 8.74 mm (0.344 inch). For designpurposes, the sending barrel location has a class 1designation.

The 18-inch Fort St. John pipeline has a maximumoperating pressure of 6895 kPa (1000 psi). Thenormal operating pressure of the pipeline over theprevious twelve-month period was 4480 kPa(650 psi) with a maximum operating pressure of 6200 kPa (900 psi) and a minimum operatingpressure of 4070 kPa (590 psi).

Laboratory Examination of theRuptured Pipeline Segment

The ruptured pipe was sent to an independentlaboratory for detailed metallurgical failure analysisand physical examination. The pipe was firstvisually examined and nondestructively tested,after which the steel properties were determinedthrough physical and chemical laboratory analysis.Specifically, a chemical analysis, tensile tests,Charpy impact tests, and hardness testing wereperformed on samples of the failed pipe material.The results of tensile testing and chemicalcomposition indicated that the pipe steel matchesthe strength and chemical requirements of API

5LX (1975) Grade 46 steel pipe. When comparedto the CSA Z245.4 M1979 Grade 317 pipespecification, the comparable Canadian standard ineffect at the time, the carbon content would havebeen too high. One of the three test specimensexhibited less than the minimal allowedelongation. The strength and chemicalrequirements and test results are shown in Table 1.

Charpy impact tests of the ruptured pipe steelindicated poor fracture toughness properties with a

ductile-brittle transition in the +30˚C to +40˚Ctemperature range. Scanning electron microscopyindicated that the entire fracture was comprised of


1. Class location assessment areas that contain 10 or fewer dwelling units are designated class 1 locations. Class locationassessment areas that contain 46 or more dwelling units are designated class 3 locations. Class location assessment areas are 1.6 kmlong and extend 200 m on both sides of the centerline of the pipeline.


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brittle cleavage features away from the fractureinitiation zone. API 5LX (1975) pipe standard hasno requirement for specifying toughness propertiesof pipe steel unless requested by purchaser. Therequirements for specifying toughness propertiesin CSA Z245.4-M1979 are determined by thedesign operating conditions of the pipe. Themetallurgical analysis did not detect any hardness

areas along the submerged arc weld zone.

Visual examination of the ruptured pipe revealedthat the rupture initiated at a large lamination2 inthe pipe that was created during the original platemanufacturing process. It is well known that wethydrogen sulphide inside the pipe dissociates toform iron sulphide and then releases atomichydrogen. Over time, atomic hydrogen diffused

into the steel and accumulated as elementalhydrogen at the lamination in the centerline of thepipe wall. At the rupture origin, the accumulatedgases had formed a large hydrogen blister3 bulginginward from the lamination and separating theinner ply from the opposing layer of material.

Yielding of the inner layer of steel occurred,resulting in a permanent bulge and significant

residual stresses associated with the bulge.Sulphide stress corrosion cracking (SSCC) wasfound on the inner ply of the steel that penetratedto the inside surface of the outer ply of steel.Shallow SSCC was also found on the inside surfaceof the outer ply of steel. The SSCC occurred inand around the bend zone, due to continuinghydrogen sulphide dissociation and the highresidual stresses associated with the bulge.


Carbon Manganese Phosphorus Sulfur Yield Strength min. Tensile Strength min. Elongation

(%) (%) (%) (%) ksi MPa ksi MPa (% min.)

Rupturepipe1

0.27 0.692 0.008 0.021 47.1 - 50 324.8 - 344.8 68.3 - 70.6 470.9 - 486.5 15 - 31.5

API5LXGr 46

0.302

max.1.25max.

0.04max.

0.05max.

46 317 63 434 27

CSAZ245.4Gr 317

0.26max.

0.30min.

0.04max.

0.04max.

46 317 63 434 27

Table 1: Rupture Pipe Steel Properties, API 5LX (1975) andCSA Z245.4 M1979 Specifications

1. To determine the physical properties of the ruptured pipe steel three test specimens were taken from intact regions of the arrest zone(transverse and longitudinal) and rupture (transverse) zone. The table shows the range of the test results from the three specimens.

2. For non-expanded welded (non-seamless) grade X46 pipe only. For cold expanded welded grade X46 pipe the maximum carbon contentallowed is 0.28 per cent.

2. Laminations are internal metal separations creating layers generally parallel to the surface. Some laminations are caused by a shrinkagecavity in the upper part of an ingot. If oxides form on the surface of this cavity, the surfaces will not weld together during subsequentrolling operations. Since the shrinkage cavity starts at the center of an ingot, it will remain in the center of the resulting slab, plate, orpipe wall.

3. Hydrogen blistering is caused by the diffusion of atomic hydrogen into the steel. Normally the hydrogen tends to diffuse through thesteel. However, when reaching a void, lamination, etc. the atomic hydrogen changes to molecular hydrogen. The continuedpenetration of atomic hydrogen results in the formation of more and more molecular hydrogen thus causing a high internal pressureresulting in a blister.


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As a result of substantial SSCC, the interior surfaceof the lamination, at the blister, was eventuallyopened up allowing a through wall path for gas andliquids to the remaining outer wall. It is assumedthat at the time of the rupture the pressure inside

the blister matched the internal pressure in thesending barrel. With the inner ply of the blister notproviding support for pressure containment, therupture occurred when the applied stress intensityat the outer ply crack tips exceeded critical levels.Calculation of the failure pressure, utilizing fracturemechanics models and using measured pre-existingdefect sizes, indicates that the failure pressurewould have been about 1000 psi. This level of stressis 30 per cent above that generated by the reportedline pressure of 743 psi.

CSA Design Code ToughnessRequirements

The Gas Pipelines Systems design standard ineffect at the time of construction of the sendingbarrel would have been either CSA Z184-M1979or CSA Z184-M1975, depending on the date of design and construction. Construction orrelocation of the sending barrel is thought to haveoccurred in 1979 or 1980. No mill certificates

could be found in Westcoast’s records that wouldconfirm the origin, grade or vintage of the pipe.Therefore, the results obtained from themetallurgical analysis of the ruptured pipe jointwere utilized to assess the sending barrel design,and compliance with the applicable designstandard. A review of the design requirements forpipe toughness properties shows that the rupturedsection of pipe did not meet the requirements of either CSA Z184-M1979 or CSA Z184-M1975.These pipe toughness property requirements arelisted in appendix A.

The absorbed energy values determined by testingof the rupture pipe showed poor properties, with arange of 7 to 14 J over a temperature range of -5˚Cto +20˚C. The actual or measured absorbed energy

is significantly below the minimum absorbedenergy of 20 J at a temperature of -45˚C specifiedby CSA Z184-M1979 or the minimum absorbedenergy of 27 J at a temperature of -45˚C specifiedby CSA Z184-M1975. It should be noted that the

absorbed energy value specified is a minimumvalue, and individual pipeline designs may requirehigher levels of specified absorbed energy.

In the current design standard for pipeline design,CSA Oil and Gas Pipeline Systems Z662-99, forpipe runs of less than 50 m it is permissible tosubstitute pipe without proven notch toughnessproperties. Although this pipe steel had poornotch toughness properties, and therefore poorprotection from fracture initiation and

propagation, it would be acceptable for useaccording to the current design standard.

Pipeline In-line Inspections

A metal loss in-line inspection of the 18-inch FortSt. John pipeline was last performed in 1998 usinga magnetic flux leakage tool. Magnetic flux leakagetools are best suited for detecting metal loss, butcan offer limited detection of defects such aslaminations. After the rupture, Westcoast reviewed

the results of the inspection run and did not findany indications of an anomaly at the sendingbarrel.

Liquids Management

Purging of liquids from the sending barrel waspreviously only done by Westcoast when there wasevidence of liquids accumulation. According to

Westcoast operations personnel, accumulation of liquids in the sending barrel only occurred in early2000 for a short period of time, prior to servicingof the kicker line valve on the bypass and the twobarrel flare valves. At that time, a temporaryprocedure for purging the sending barrel wasimplemented because a smoke plume was emittedduring regular flaring associated with receiving acleaning pig on the adjacent 16-inch Oak pipeline.



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This type of smoke plume was attributed toaccumulated liquids from minor valve weeping.

After the valves were serviced, the accumulation of liquids in the sending barrel was considered tohave ceased since there were no further smoke

plumes observed with receiving pigs on the16-inch Oak pipeline. As a result, the temporaryprocedure for purging liquids from the sendingbarrel was discontinued. Westcoast indicated thatthe last time the 18-inch Fort St. John pipelinesending barrel had been purged of liquids prior tothe rupture was in April 2000. Westcoastoperations personnel reported that the 18-inchFort St. John pipeline is no longer pigged forliquid management purposes.

Westcoast reported that the 18-inch Fort St. Johnpipeline and associated facilities are designed andequipped to accommodate significant volumes of liquids. McMahon Gas Plant, the delivery point forthe pipeline, can accept slug sizes of 1600 barrelsduring normal operations. The 18-inch FortSt. John pipeline has been simulated formultiphase flow behavior.

The flare at the site of the sending barrel was notdesigned to accommodate fluids in the line.

Westcoast reported that the engineering andprocurement of materials to install liquid knockoutfacilities at the site was underway before theincident, with the work scheduled to be completedby the end of 2002.

Gas Quality

Westcoast enters into contractual agreementsproviding raw gas transmission, treatment, liquidproducts stabilization and fractionation services to

shippers in the Fort St. John resource area. Theterms and conditions of the agreement require thatshippers deliver gas that is within a productspecification, and that Westcoast shall not beobliged to take delivery of any raw gas, residue gasor hydrocarbon liquids which do not comply withthe applicable quality specifications. These quality

specifications include limits for water content in theraw gas in either liquid or vapour form. The specificrequirements for the 18-inch Fort St. John pipelineinclude, in addition to other quality requirements,the following clauses concerning water content:

Raw gas shall:

a) not contain water vapour in excess of 65 milligrams per cubic meter, asdetermined by dewpoint apparatusapproved by the Bureau of Mines of theUnited States, but in no case need the rawgas be dehydrated to a water vapourdewpoint of less than minus 12˚C at thedelivery pressure, and

b) be free of water in liquid form.

Westcoast takes custody of the raw gas andhydrocarbon liquids at a receipt point owned andoperated by a shipper. The receipt point operatoris obligated to deliver gas and hydrocarbon liquidsthat meet the quality specifications of the termsand conditions of the contract, as well as beingresponsible for the accuracy and maintenance of all gas or hydrocarbon test equipment required formaintaining these specifications. The receipt point

operators on the 18-inch Fort St. John pipelineschedule and perform manual dewpoint checks inaccordance with Westcoast’s measurement policy.

Westcoast performs its own manual dewpointcheck on all new receipt points upon theircommissioning. Additionally, Westcoast willoccasionally witness the receipt point operator’sroutine manual dewpoint testing.

A review of the dewpoint testing records for thepast two years on the 18-inch Fort St. Johnpipeline and upstream pipelines revealed somereceipt points exceeding the dewpoint specificationof 65 milligrams per cubic meter. The highestwater vapour measurements were observed at theSamson compressor station located adjacent to thesending barrel site. The18-inch Fort St. John



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pipeline receives gas from the Samson compressorstation at a connection point immediatelydownstream from the isolation valve for theruptured sending barrel. The Samson compressorstation also supplies gas during pigging or purging

operations directly to the sending barrel throughthe kicker line.

Westcoast’s policy for water vapour measurementson the 18-inch Fort St. John pipeline that areoutside the specified requirements involve workingwith the receipt point operator to resolve theproblem first prior to shutting in the receipt point.The operator will be given the opportunity toexplain any out of the ordinary circumstancescontributing to the high dew point, and a grace

period will be determined by Westcoast personnelto correct them. If the receipt point operator failsto meet the gas quality requirement after the graceperiod, then the receipt point will be shut in. Thereceipt point will be reopened after the operatorverifies, according to Westcoast’s procedures, thatthey are within the specified gas qualityrequirements.

Analysis

Hydrate Formation

Since the fracture mechanics analysis indicates thatthe pressure required for the rupture of the pipeexceeded the reported line pressure, an additionalevent or stressor would have been required to causethe rupture. This would most likely have come fromthe suspected hydrate plug being dislodged andcreating a pressure wave within the pipeline. Therewas no evidence within the ruptured pipeline

remains that would prove the presence of a hydrateplug. However, the pressure differential reported bythe operator prior to the pipeline rupture can onlybe explained by a plug between the rear flare linegauge and the barrel door gauge. The operator’sactions of attempting to purge and depressurize the

barrel would have been enough to cause the hydrateplug to dislodge. When the blockage becamedislodged, a “hammer” effect, sufficient to initiatefracture in the steel, was generated.

Hydrates are mixtures of water and gas moleculesthat crystallize to form a solid “ice plug” underappropriate conditions of temperature andpressure. Hydrates can form from free watercondensed in the gas stream at or below its waterdewpoint. Hydrates commonly occur within thepipeline and reservoir environments and can createblockages in pipelines. The primary considerationswhich promote hydrate formation are lowtemperature, high pressure, and the gas must be ator below its water dew point with free water

present. An unusual feature of hydrates is thattheir formation is not strictly temperaturedependent. They form at high pressure when thetemperature of the flowing gas is well above thefreezing point of water. Based on evidencecollected at the incident site, the conditions in thesending barrel would have been optimal for theformation of hydrates.

Hydrates, like any other obstruction in a pipeline,can be detected by the consequences they create.

Obstructions will reduce flow, increasebackpressure on a system, and increase thedifferential pressure across the obstruction.Differential pressure can quickly accelerate ahydrate plug to velocities approaching the speed of sound, creating excessive forces. Moving hydratescan cause serious mechanical damage atdownstream locations where restrictions,obstructions or sharp change of direction exist.The failure can be impact or overpressure (shockwave) failure. Impact failures occur due to the

mass and momentum of the hydrate hitting andfracturing the pipe or fittings.

Since the size and location of the blockage is notknown, it is impossible to estimate the amount of force that the dislodged plug generated within the



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sending barrel prior to failure. The sending barrelruptured at its weakest point, a flaw introduced inthe manufacturing process that further deterioratedduring operation of the pipeline. In the absence of the flaw, it is possible that the sending barrel still

would have ruptured either at its next weakest pointdue to overpressure or as a result of the impact of the ice plug on the door of the sending barrel.

Pipe Quality

The section of pipe which ruptured exhibitedexceptionally poor metallurgical, mechanical, andphysical properties. Pipe toughness propertieswere below those values required by the applicableCSA design standard in effect at the time of pipefabrication and construction of the Westcoastfacilities.

At the time of the incident, the sending barrel pipewas in a weakened condition caused by the largecenterline laminations that had accumulatedelemental hydrogen which created inward bulging.Fracture analysis determined that the sulphidestress corrosion cracking and the crackingassociated with the bulging effectively removedmore than 50 per cent of the load-bearing carrying

capacity of the pipe. Fracture stress analysisindicated that an additional stress beyond thatcreated by line operating pressure was required toinitiate the fracture.

Although the sending barrel did not rupture dueto the line operating pressure alone at the time of the incident, the deterioration of the pipe as aresult of the lamination and bulging would havecontinued to progress under normal operatingconditions. It is reasonable to conclude that the

sending barrel would eventually fail during normaloperations.

Operating History

From a detailed review of the events immediatelybefore and after the rupture, it is evident that a

significant amount of liquid was present in thesending barrel. The operator’s first attempt topurge the barrel of liquids extinguished the piloton the flare stack. When the barrel ruptured, thearea was sprayed by salt water with enough force

to trip the transformer on a nearby overheadpower line. The operator onsite during the rupturecould taste salt water in the spray. After therupture, when the six inch kicker line to the barrelwas disassembled, it was found to be half filledwith salt water. It can be assumed the sendingbarrel was also at least half filled with salt water.

The operating history suggests that water wouldhave had considerable time to accumulate as thesending barrel was last purged of liquids in April

2000. As the rupture occurred in May of 2002, it ispossible that the sending barrel would not haveseen any use for two years, with the only activity onthe barrel being the valve servicing which theoperator was performing at the time of the rupture.

Westcoast considered that the problem of liquidaccumulation in early 2000 was remedied by theservicing of the kicker line valve on the bypass andthe two flare valves on the 18-inch Fort St. Johnpipeline sending barrel. The temporary procedure

of purging liquids from the sending barrel wasdiscontinued after the valve servicing, based on asmoke plume no longer being generated afterregular flaring associated with receiving of a pig onthe 16-inch Oak pipeline. Nonetheless, asubstantial amount of liquids was present in thesending barrel at the time of the incident.

Westcoast’s gas quality records indicate that thereceipt point with the highest level of watercontent was the Samson compressor station which

ties in to the 18-inch Fort St. John pipeline justdownstream of the isolation valve, and to thesending barrel through the kicker line where oneof the valves was serviced in 2000. It is possiblethat the kicker line valve may have continued toweep after its servicing, and after Westcoast



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discontinued the temporary purging procedure forthe sending barrel. In the subsequent two yearsthat the sending barrel was idle, there were nochecks done to see if liquids were accumulating.

Although the pipeline and related facilities aredesigned to be capable of handling liquids, theoperation of the flare at the sending barrel sitewould have benefited from liquid knockoutcapabilities. The smoke plume observed afterregular flaring associated with receiving of a pig onthe 16-inch Oak pipeline may have been preventedby removal of liquids from the flare gas streambefore combustion. The operator’s first attempt topurge the barrel of liquids resulted in extinguishingthe pilot on the flare. Liquid knockout capability

may have prevented this from occurring. Westcoasthad initiated plans for the addition of liquidknockout capability prior to the incident.

Emergency Response

The following two concerns were noted:

First, there appears to have been a lack of communication between the Taylor FireDepartment’s Field Incident Commander andthe Westcoast Incident Commander. At the

time that Westcoast was notifying affectedresidents with a “shelter in place” message, theField Incident Commander had given orders tofire department personnel and the RCMP toevacuate the same residents.

Secondly, the events during the incident werepoorly documented and recorded. Westcoastdid not provide an accurate and completehistory of the response to the incident.

In other aspects, the emergency response to theincident by Westcoast can be considered prompt,efficient and appropriate for this type of incidentwith hydrogen sulphide involved.

Record Keeping

Documentation was not available for the section of pipe which ruptured. Westcoast could find norecords to identify the origin, grade, or vintage of the ruptured pipe. As built records of theconstruction were deficient.

Records related to construction of the sendingbarrel were thought to have been destroyed in firesat the Charlie Lake office in either 1987 or 1995.

Conclusions

Findings

1. The pipeline rupture was likely caused by ashock wave or impact created after a hydrateor ice plug blockage was released by adifferential pressure.

2. At the time of the incident, the sending barrelpipe was in a weakened condition caused bythe large centerline laminations that hadaccumulated elemental hydrogen, creating aninward bulge.

3. The sending barrel was idle for two yearsallowing fluids to accumulate.

4. The ruptured pipe did not meet the toughnessrequirements of the applicable CSA designstandard in effect at the time of pipefabrication and construction.

5. Westcoast did not have the necessarydocumentation for the materials and design of the sending barrel.

6. There was a lack of communication betweenthe Westcoast Incident Commander and theTaylor Fire Departments Field IncidentCommander.



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Safety Action Section

Action Taken by Westcoast

Pipeline Reconstruction

As a temporary repair, the barrel, S-bend, andisolation valve were removed and an end capinstalled in order to return the18-inch Fort St.

John pipeline to service. Westcoast returned thepipeline to service on 18-May 2002.

Shortly afterward, the end cap was removed and anew S-bend and isolation valve were installed. Anew barrel will be installed when it becomesavailable. The new design locates the isolation

valve, transition pipe, and sending barrel aboveground, with the intention of eliminating a lowspot where liquids could accumulate.

Procedures

Westcoast’s Safe Work Procedures Sub-Committeereviewed the practices and procedures that involvepigging barrels and isolation valves. The Sub-Committee approved a revision to the task relatedto opening the front and back blowdown valves.

The previous procedure for this task was to:

Open the front blowdown 3A slowly, and thenopen the valve 3B. Always open bothblowdowns.

The new procedure for this task is:

Open the front blowdown 3A slowly, and thenopen the valve 3B. Always open bothblowdowns. While opening valves 3A and 3B

both pressure gauges should be monitoredcarefully. This will require two technicians. If at any time there is more than 100psidifferential between the two gauges theblowdown should be discontinuedimmediately. The immediate supervisor shouldbe advised and a site specific procedure should

be developed before proceeding or problemrectified.

Pipeline Integrity

Westcoast has developed and implemented a

Pipeline Integrity Program for below ground pipe.Efforts are currently underway to expand thisprogram to include above ground facilities.

Westcoast has committed to a completion of anexpanded Pipeline Integrity Program document bythe end of 2004.

NEB Directives

As a result of the investigation into the rupture of the 18-inch Fort St. John natural gas transmission

pipeline the NEB directs Westcoast as follows:

Directive 1

Westcoast shall review its Operations Manualto ensure the safe operation of pipelines thattransport raw gas or residue gas, payingparticular attention to:

a) hydrate prevention program;

b) the prevention of liquids accumulation;

c) procedures for the safe handling andremoval of hydrates.

Directive 2

Westcoast shall ensure that its pipeline oraboveground facilities integrity managementprograms provide for regular inspection andassessment of above ground piping inconformance with paragraph 8.8.1 of the

Westcoast OPR’99 audit of T-Central in 2001.Directive 3

Westcoast shall review its pipeline systemrecords for the specifications and materialproperties related to the reuse of materials or



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equipment for projects executed since 1999. Westcoast shall determine the adequacy of such records. Westcoast shall assess thesignificance of any gaps or deficiencies,develop an appropriate action plan, and

submit it to the Board for approval within60 days of the issuance of this directive.

Directive 4

Westcoast shall review with its first responders,in the Fort St. John area, Westcoast’semergency response plan including thehandover of incident command, to ensure acommon understanding of its requirementsand accountabilities.

Appendices

Appendix A

For an installation according to theCSA Z184-M1979, the notch toughnessrequirements for steel pipe are determined by theminimum design temperature, design operatingstress, and nominal wall thickness. The minimum

design temperature is taken as the lowest expectedoperating pipe or metal temperature when thehoop stress exceeds 50 MPa, which can beassumed to be -45˚C for the present situation.

With the design operating stress of the pipelineexceeding 175 MPa and a nominal wall thicknessexceeding 3.00 mm, Category II toughness isspecified by the CSA standard. However the CSAstandard permits substitutions of Category III pipefor pipe runs where the length of pipe is 50 m orless, as in the sending barrel assembly.

For Category III pipe, the clause 10.3.1.1 of CSAZ245.4-M1979 Line Pipe Standard states;

The steel shall exhibit an absorbed energy of 20 J minimum, when subjected to full sizeCharpy V-notch impact test, at the testtemperature specified by the purchaser.

Since the actual dates of design and constructionare not known, installation of the pipe accordingto the earlier CSA Z184-M1975 Gas PipelineSystems design standard is was also considered.For the 1975 CSA standard, the notch toughness

property requirements for the ruptured pipe aredetermined by the operating conditions listed inclause 3.1.2.2, which reads as follows:

3.1.2.2 Particular attention shall be given tothe tensile properties and the notch toughnessproperties at the designated temperatures (seeClause 3.1.2.3) when the following designedoperating conditions are encountered:

c) Exposed pipelines of all sizes and strengthlevels when operating at a stress level of over 30 per cent of the specified minimumyield strength.

d) Sour gas pipelines of all sizes and strengthlevels when operating at a stress level of over 30 per cent of the specified minimumyield strength.

The operating temperature, at which toughnessproperties are to be specified, is determined byClause 3.1.2.3 and reads as follows:

3.1.2.3 The following temperatures aredesignated for the operating conditionsoutlined in Clause 3.1.2.2:

b) For exposed pipelines, the lowest expectedtemperature shall take into considerationthe lowest air temperature for the locality…

The toughness properties as required for theseconditions are then listed in clause 3.1.2.4, and

reads as follows:

3.1.2.4 For all pipelines operating under theconditions listed in Clause 3.1.2.2:

a) The pipe shall display a minimumspecified of shear as determined by animpact test.



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b) The minimum specified value forpercentage of shear shall be as required inthe CSA Z245 Series of Standards for SteelLine Pipe.

The applicable line pipe standard for the rupturedsection of pipe is CSA Z245.4-1974. The rupturedsection of pipe would be assigned a Category IIIdesignation, intended for exposed pipe linesrequiring specific fracture toughness properties.The CSA standard lists a requirement for bothabsorbed energy and a displayed minimum sheararea in the full size Charpy V Notch Impact Test.Referencing Clause 10.3.2 of the same standardprovides an exemption for shorter lengths of exposed pipe and reads as follows:

10.3.2 Where the pipe is exposed for 100 feet(30.4 m) or less, and this length includes avalve or flanged connection, only theminimum absorbed energy value may berequired.

Referencing Clause 10.3.1 specifies the amount of minimum energy absorption for exposed pipe andreads as follows:

10.3.1 In addition a full size Charpy V NotchImpact Test shall display minimum energyabsorption of 20 foot-pounds (27.0 J) at thetesting temperature.



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