# WILLIAMS GAS CO — Corrective Action Order

- **operation:** document
- **citation:** CPF 520031003H
- **title:** WILLIAMS GAS CO — Corrective Action Order
- **source type:** enforcement
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2003-05-02
- **effective on:** Not available
- **summary:** CLOSED corrective action order.
- **machine formats:** - **json:** https://regulus.evalyn.ai/document/phmsa-enforcement-520031003h.json
- **markdown:** https://regulus.evalyn.ai/document/phmsa-enforcement-520031003h.md
- **app url:** https://regulus.evalyn.ai/document/phmsa-enforcement-520031003h
- **source url:** https://primis.phmsa.dot.gov/enforcement-data/case/520031003H
**body:**

Corrective Action Order involving WILLIAMS GAS CO. The dataset does not identify a cited regulation for this case. The case was opened on 2003-05-02 and is reported as closed as of 2010-03-17. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

520031003H.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520031003H/520031003H.pdf

520031003HA.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520031003H/520031003HA.pdf

520031003H_Amendment to CAO_12182003.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520031003H/520031003H_Amendment%20to%20CAO_12182003.pdf

520031003h_amendment to cao_12182003_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520031003H/520031003h_amendment%20to%20cao_12182003_text.pdf

520031003H_CAO_05022003.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520031003H/520031003H_CAO_05022003.pdf

520031003h_cao_05022003_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520031003H/520031003h_cao_05022003_text.pdf

520031003H_post-hearing decision on CAO amendment_04092004.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520031003H/520031003H_post-hearing%20decision%20on%20CAO%20amendment_04092004.pdf

520031003H_post-hearing decision on CAO amendment_04092004.pdf

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U.SDeoortment
of Tronsoortolion
Reseorch ond
Spe€iol Prognoms Admanistrolion
40o Seventh St S.W
Washrngton. O C 20590
Ai,1
," '.^,.\ A
.. .' ],+
Mr. Randy Bamard
Vice President of Operations
Williams Gas Pipeline - Northwest
2800 Post Oak Boulevard
MD-21
Houston, TX 77056
Re: CPFNo. 5-2003-1003-H
Dear Mr. Bamard:
Enclosed is the Post Hearing Decision to the Amendment to the Corrective Action Order in
this case. The Post Hearing Decision includes a Second Amendment to the Corrective Action Order
and proposes an additional amendment, The Second Amendment clarifies and modifies some of the
provisionsoftheDecemberl8,2003AmendmenttotheCorrectiveActionOrder. ThisPostHearing
Decision also notifies you of a proposed amendment that would require you to take additional
corrective action involving your communication and liaison procedures with public officials and
provide progress reports on the work done under the order.
Service is being made by certified mail and facsimile. Your receipt constitutes service under
49 C.F.R. $ 190.5. The terms and conditions of this Second Amendment to the Corrective Action
Order are effective upon receipt. You have the right to a hearing with respect to the proposed
additional amendment.
Sincerely,
nf\ v \ 4(A^S^
/\a u
H", Revnolds
6tl Pipeline iompliance Registry
\ Office of Pipeline Safety
Enclosure
VIA CERTIF'IED MAIL RETURN RECEIPT REOIJ]ESTED) AND TELECOPY



DEPARTMENT OF TRANSPORTATION
RESEARCH AND SPECIAL PROGRAMS ADMINISTRATION
WASHINGTON. DC 20590
In the Matter of
Williams Gas Pipeline. Northwest,
Respondent.
CPF No.5-2003-1003-H
POST.HEARING DECISION --
SECOND AMENDMENT TO TI{E CORRECTIVE ACTION ORDER
AND PROPOSED FURTHER AMENDMENT
Purpose and Background
On May 2, 2003, the Associate Administrator for Pipeline Safety issued a Corrective Action Order
(May 2 Order) in this case, under authority of 49 U.S.C. $ 60112, finding that continued operation
by Williams Gas Pipeline - Northwest (Respondent) of its 26-inch natural gas pipeline in westem
Washington State would be hazardous to the public, property, and the environment without
corrective measures. The May 2 Order was issued as a result of the May |,2OO3 rupture of the line
at mile post 1352.7 near Lake Tapps in Pierce County, Washington.
On December 13,2003, the line ruptured again. This time the failure occurred near Toledo, kwis
County, Washington. On December 18, 2003, the Associate Administrator issued an Amendment
to the Corrective Action Order (Amendment) to require additional corrective measures. By letter
ofDecember29,2003,Respondentrequesteda"hearingandclarification"andenumeratedsix items
of the Amendment it intended to address.
A hearing was conducted on lanuary 26, 2004 in the OPS offices in Lakewood, Colorado.
Representatives of the Washington Utilities and Transportation Commission (WUTC), which
participated in the investigation ofthe accidents as an interstate agent, participated in the hearing.
In addition to the six items enumerated in the response, Respondent raised issues and sought
clarification with respect to other items of the Amendment. On February 9, Respondent filed its
post-hearing submission.
Discussion of Items Raised by Respondent
Pressure restriction on Sumas to Mt Venton segrnent. Respondent noted that it had been unable to
comply with Item 1 of the Amendment on the Sumas to Snohomish portion of the line. Item 1
required reduction of the line pressure to 100 psi by mid-January. By letter of January 12,2004,
Respondent had requested additional time to achieve that pressure. Respondent contends that



achieving the reduced pressure can only be done by venting a considerable amount of gas to the
atmosphere in the more populated area of the line. Respondent has been unable to reduce the
pressure on this segment below 100 psi and still operate the line. Respondent confirmed that this
pressure is less than 207o of the specified minimum yield strength of the pipe, a pressure at which
it is highly unlikely to rupture. The line was subsequently depressurized for integrity testing.
However, if retum to full service is delayed, there is a need to prescribe an acceptable interim
pressure. The Regional Director concurs that operation of this segment at pressures up to 200 psi
would not likely result in failure. Accordingly, paragraph a. below modifies Item 1 to grant relief.
Metallurgical Analysis. Item 2 of the Amendment required Respondent to submit the original of the
metallurgical report to the Regional Director within one week of receipt. The Regional Director
noted that the goal was to ensure that OPS saw the original version of the metallurgical analysis and
that having thd laboratory mail the copy simultaneously with forwarding the report to Respondent
would achieve this. Respondent has now submitted a copy of the original report to the Regional
Director.
IntegriQ management program. Respondent requested clarification with respect to Item 3 of the
Amendment:
3. Integrity management. Finalize an integrity management program that conforms to the
requirements for integrity management programs published on December 15, 2003 (new
subpart O to 49 C.F.R. Part 192) on an expedited basis. The program must address the
factors involved in the failures on the line that have occurred since 1990, including stress
corrosion cracking and land movement, as risks. Submit this program within 90 days of
issuance of this Amendment for approval by the Director, Westem Region.
Specifically, Respondent noted the difficulty of developing a plan that will satisfy all of the detailed
requirements of the December 15 final rule prior to the development of the protocols and guidance
that OPS has indicated will be forthcoming. The Regional Director agreed that some of the details
may need to be filled in later, but noted that, based on a December 10,2003 meeting, Respondent
had already done a considerable amount of work in analyzing the risks on the lines subject to this
order. It is not unreasonable to require Respondent to produce a first version of an integrity
management plan for the lines covered by this order on an expedited basis. At the hearing, the
Regional Director agreed to review an eady draft and provide feedback on the adequacy of the plan
to meet the requirements of the Amendment and the areas which Respondent may need to address
in the future as it implements the integrity management program for its entire system. Respondent
informally submitted its draft on February 2,2004 andhas engaged in discussions with regional staff
about the scope. To allow these discussions to continue, the Regional Director extended time for
submitting the program until April 18, 2004. Accordingly, paragraph b. below modifies item 3 of
the Amendment to again allow for a slight extension of time and to allow for future development
of a complete integrity management program.



Pipe replacement. Item 4 of the Amendment requires Respondent to develop a prioritized plan to
remove pipe that is subject to stress corrosion cracking from the 26-inch line if it intends to request
removal of the current pressure restrictions. The plan may allow for implementation to extend over
aten-year period. Although the term "replacement" is used, nothing in the Amendment requires
Respondent to continue operating or to replace the line pipe with pipe of equivalent size.
Respondent would satisfy the replacement requirement by constructing a new pipeline that meets
future capacity needs and abandoning (in accordance with 49 C.F.R. $ 192.605) all or sections of the
cuffent 26-inch line requiring replacement.
As an initial argument, Respondent challenges the need to replace pipe in the 26-inch line.
Respondent argues that OPS lacks authority to order replacement with the information available to
it. Respondent urges OPS to consider an approach that allows the line to continue in service
indefinitely so long as it is managed through an integrity management program. Section 60112 of
Title 49, United States Code, expressly allows OPS to order "suspended or restricted use of the
facility, . . ., replacement, or other appropriate action" ifthe agency determines that the pipeline
facility at issue is or would be hazardous but for the corrective actions. As already noted,
replacement in this context does not require Respondent to replace with equivalent pipe, but does
require that the hazardous pipe be removed from service. In this case, OPS has presented evidence
of numerous SCC failures that have occurred on the line. There is evidence that the pipe is subject
to several of the factors in SCC - nature of the coating, environmental conditions, and metallurgical
toughness of the pipe. The same toughness factors make the pipe prone to failure during land
movement, which is also a well-recognized risk in the area. Respondent has not challenged this
evidence or the conclusion of OPS that corrective action is needed. The question comes down to the
reasonableness of a requirement to remove pipe rather than to manage the risk of SCC and earth
movement through some other means,
Evidence of pipeline failure due to land movement was detailed in the May 2 Order in this case. The
followine indicates that SCC is a serious and pervasive problem on this line:
The metallurgical report on the 1992 SCC failure south of Snohomish indicated that there
was a family of deep cracks on the pipe examined. The report recommended periodic
hydrostatic testing to identify and remove the SCC in the line.
Hydrostatic testing of a 4.8 mile segment of a l6-inch lateral in 1994 resulted in 22 SCC
failures.
The report on the 1999 Mt. Pleasant failure noted 21 othercracks in addition to the crackthat
caused the failure.
The report on the May L, 2003 SCC failure noted numerous other cracks due to SCC in the
pipe examined.
The report on the December 73,2003 SCC failure that underlies the Amendment also
indicates that there are several other cracks due to SCC that had not failed in the pipe tested.



The Ulffascan crack detection done in 2003 revealed 38 SCC colonies in the three miles from
Sumner to White River. There have been 8 digs in this three-mile segment in which over a
hundred anomalies have been noted. At least one of these was a crack with 100Vo
penetration of the pipe and at least 10 had a depth of more than25Eo.
At the hearing, Respondent claimed that the transverse field inspection tool (TFI) can accurately
detect, and thus be used to manage, SCC in the26-inch line. Noel Duckworth, an expert in internal
inspection technology, discussed the limitations of the TFI in locating SCC. In his opinion, the tool
does not at this time reliably detect SCC sufficiently in advance of failure for it to be used for long-
term management. The limitations stem from the manner in which the tool measures anomalies,
rather than from the quality of the analysis done of the inspection data. Although Respondent
pointed out that Mr. Duckworth's assessment was opinion, not fact, Respondent did not present
evidence that supported a contrary view. OPS is left with the information before it. There is a
history of SCC with two failures in the past year, the existence of several known parameters for
SCC, an expert opinion that TFI will not detect SCC in time to prevent failure, and no countervailing
evidence,
Respondent indicates that a complete understanding of the SCC parameters at issue could allow an
integrity management program to eliminate the threat of SCC failures and that it should not be
ordered to replace the line until it can gain that complete understanding. It is not clear, however,
when Respondent will have enough information to present such a case or whether technology will
indeed provide sufficient certainty to manage the SCC on this line for an indefinite time.
Respondent indicates that hydrotesting being done may provide data that would be helpful and that
I-Jltrascan crack detection has been accurate. However, discussions at the hearing indicate that
Ultrascan cannot be used on the entire system because of the hilly terrain. In the meantime, OPS is
faced with the real risk of a future failure.
The Amendment does not require Respondent to replace line pipe if replacement is not necessary
for safety and is otherwise reasonable with respect to the replacement program. The terms of the
Amendment expressly provide Respondent with the opportunity to present the case that a particular
segment is not subject to SCC and that replacement is not necessary (Items 4.v. and 6). As
examples, this showing could be evidence that, because of different construction, manufacturing
techniques, or pipe materials, a particular segment is not subject to SCC.
To the extent that extenuating circumstances mean that, despite all efforts, Respondent cannot make
a decision about replacement of the capacity within the 120 days cunently required for a replacement
plan, the order allows for extensions of time for good cause. In addition, if the hydrotesting and
trials of the Ultrascan crack detection provide new unexpected and convincing data indicating that
SCC can be managed on this line, Respondent may request OPS to amend the order with respect to
the replacement program. Accordingly, this Second Amendment does not change the requirements
of Item 4 of the Amendment which addresses the current risks accordins to the current realitv.



to seek removal from pressure restrictions for pipe in the replacement program. The basis is an
oManaging SCC until replacement. Item 5 of the Amendment provides a provision for Respondent
adequate demonstration that SCC can be managed as a temporary measure through periodic
hydrostatic testing or intemal inspection. Respondent has requested some modification of these
procedures.
First, Respondent has asked that it be allowed to retum a segment to service after successful
completion of a hydrostatic test but prior to the establishment of the interval for retesting.
Respondent asks that it be allowed 90-120 days to establish this interval. This additional time will
allow for better analysis of the test data, including analysis of any failures that occur. There is
literature available that provides guidance on appropriate retest intervals and it is appropriate that
Respondent use this guidance to establish an interim interval prior to requesting permission to return
to service. If this is done, allowing Respondent to adjust the retest interval within 90 days after
complete analysis is reasonable. This provides assurance that there will always be an interval in
place for retesting. Paragraph c. below provides for this modification.
Second, Respondent has asked that the "spike test" be conducted for no more than 30 minutes rather
than for the t hour provided in Item 5. iii. and thatthe pressure of ll0%o of the specified minimum
yield strength (SMYS) not be required for the entire segment. The Regional Director has agreed that
this is acceptable provided the entire segment be tested to a minimum of lOUVo SMYS with the
weakest pipe, typically 0.28l-inch pipe, testing to LLOVo SMYS at some point in the test section.
Respondent's post-hearingcomments assert that the Regional Directorhas indicated that only0.281-
inch pipe need be tested. That assertion is incorrect and all pre-1970 pipe must be tested. Paragraph
c. below provides for modification with respect to the terms of the "spike test".
Third, Respondent has asked that, if intemal inspection using a combination of TFI and magnetic
flux tools is used, it be allowed up to one year to address the anomalies after a retum to service.
Some anomalies may require expedited repair, but a repair schedule that addresses the most critical
first (prior to return to service) and allows additional time for noncritical repairs is acceptable.
Paragraph d. below provides for this modification.
Finally, discussion at the hearing indicated public concern about safety when work is done on a
pipeline and Respondent's willingness to include provisions for a public safety procedure in the
protocol for hydrostatic testing. Based on continuing concern from local officials, OPS proposes,
below, to further amend this corrective action order to provide for a public safety procedure for all
activities conducted under the order that could create the need for public safety decision-making by
federal, state, or local officials.
Evaluation of other lines. Item 8 requires Respondent to evaluate certain other lines for
susceptibility to SCC and to report the findings and response to the Regional Director. Respondent
has sought clarification as to the requirement. Item 8 does not require Respondent to evaluate the
other lines using hydrostatic testing or internal inspection, or indeed to select either in selecting the
o



response to the evaluation. If, at some time in the future, OPS determines that either is needed, it
may further amend the order. No change to the Amendment is needed.
Modifications of the Required Corrective Action of the Amendment
Pursuant to 49 U.S.C. $ 60112, I hereby amend the corrective action of the December 18, 2003
Amendment to the Corrective Action Order (Amendment) as follows:
Item I of the Amendment (addressing pressure restrictions on the 26-inch line) is amended by
adding the following language:
ff a reduced pressure of 100 psi cannot be maintained on the Sumas to Snohomish segment,
Respondent may reduce the pressure and operate the line at a maximum pressure of 200 psi
as needed to maintain a minimal line pack on the segment.
b. Item 3 of the Amendment is modified to read as follows:
3. Integrity management. Develop an integrity management program covering the lines
subject to this orderthat substantiallyconforms to the requirements forintegritymanagement
programs published on December 15,2003 (new subpart O to 49 C.F.R. Pafi 192) on an
expedited basis. The program must address the factors involved in the failures on the line
that have occurred since 1990, including stress corrosion cracking and land movement, as
risks. The program must include at least the following elements of an integrity management
program: 49 C.F.R. $$ 192.911(a), (b), (c), (e), (f), (h), (i), 0), (l) and (m). Submit this
program to the Director, Western Region by April 30,2004 for his approval.
c. Item 5 iii. of the Amendment is modified to read:
iii. Successful completion of hydrostatic testing must include a "spike test"; that is, a test
with someportionofthesegmentexperiencingll0percentofthespecifiedminimumleld
strength of the weakest pipe in the test section for a period of 30 minutes and no segment
experiencing less than 100 percent, The spike test must be followed by a test at a minimum
of 90 percent of the specified minimum yield strength for eight hours. Each failure must
be metallurgically tested to identify cause and failed pipe must be replaced with pretested
pipe.
In supporting the request for removal of the pressure restriction, Respondent may submit for
approval an interim interval for reassessment of a pipe section based upon general guidance.
Respondent must then provide a final interval for reassessment based upon additional analysis
within 90 days of removal of the pressure restriction.



d. The last bullet of Item 5. iv. of the Amendment is modified to read as follows:
. Following written procedures approved by the Director, Western Region, that include
fitness for service criteria for identifying, pri oitizing, and correcting defects within one year
after removal of the pressure restriction.
The terms and conditions of this Amendment are effective upon receipt. Failure to comply with this
Order may result in the administrative assessment of civil penalties of not more than $i00,000 per
day and in referral to the Attomey General for appropriate relief in United States District Court.
Pronosed Further Amendment - Public Safety Procedures: Progress Reports
Since I issued the Amendment to the Corrective Action Order, public safety officials have expressed
concern that an ineffective and uncoordinated flow of information from the Respondent about the
pipelines is hindering their ability to execute their public safety responsibilities and to protect
persons in the vicinity of the pipeline. This proposed additional amendment proposes additional
corrective measures based on the following:
. In meetings with the Associate Administrator for Pipeline Safety, public officials from Skagit,
Puyallup and Bellevue, WA, and representatives of the WUTC expressed concern that more
information from Respondent about the condition and ongoing operations ofthe subject pipeline
was necessary to avoid confusion, enhance coordination and better protect the citizens for whom
the officials are resoonsible.
In a meeting with the Associate Administrator for Pipeline Safety, the Fire Chief of Puyallup,
WA expressed concern that more information from Respondent concerning its planned
operating activities was necessary for the Fire Chief to effectively carry out his responsibilities.
In addition, corrective action orders with extensive measures require significant monitoring effort
on the part of OPS. Based on the experience thus far, OPS believes that periodic progress reports
are necessary for effective monitoring.
Accordingly, I propose to further amend this coffective action order by adding the following items:
10. Identify actions or series of actions taken under this order that may require rapid decision-
making by responsible authorities at the community level to protect the public safety such as
through evacuations, road closings, or notifications of police, fire, or other emergency
responders (such actions would include, but are not limited to, line restarts, pressure testing,
purging, and other significant excavation activities). Develop procedures for communicating
timely notice of such actions to federal, state, and local officials and for maintaining liaison to
coordinate pre-planned and actual response activities with the appropriate officials that provide
for appropriate notice to the public officials. Provide a copy of these procedures to the Director,
Westem Region, within 30 days (of issuance of an amendment including this term).



1L Provide Progress Reports on actions taken under this order on a monthly basis to the Director,
Western Region, that include at least the following information:
Number of miles of pipe hydrostatically tested, number of failures, and suspected causes
with updates based on results of the metallurgical testing.
ll.
(For each type of nondestructive test performed) The number of miles tested, the number
and nature of anomalies found, and the number and nature of repairs made.
Within 10 days of receipt of this proposed amendment, Respondent may request a hearing, to be held
as soon as practicable, by notitlng the Associate Administrator for Pipeline Safety in writing,
delivered personally, by mail or by telecopy at (202) 366-4566. The hearing will be held in
Lakewood, Colorado or Washington, DC on a date that is mutually convenient to OPS and
Respondent. Failwe to respond authorizes the Associate Administrator to issue an amendment
consistent with this notice.
APR - g 2m4
Date Issued
for Pioeline Safetv

520031003h_amendment to cao_12182003_text.pdf

U5 Department
or Tronsporiarion
taeaearch and
SpeckN Aogrwna
AglmlirlattcNon
c0o ~enih si s w
waahegl0n D C 20590
DEC 18 21lc3
Mr Randy Barnard
Vice President of Operations
Williams Gas Pipeline - Northwest
2800 Post Oak Boulevard
MD-21
Houston, TX 77056
Re CPF No. 5-2003-1003-H
Dear Mr. Barnard
Enclosed is an Amendment to the Corrective Action Order issued by the Associate
Admmistrator for Pipeline Safety m the above-referenced case. It requires you to take additional
corrective actions with respect to your 26-inch line in Western Washington and to evaluate your 30-
inch parallel line, the 26-inch line from the Washougal Compressor Station east to the Goldendale
Compressor station, and all transmission lines from the Washougal Compressor Station south to
Grants Pass, Oregon, for similar safety concerns. Service is being made by certified mail and
facsimile. Your receipt of this Amendment constitutes service of that document under 49 C F R
g 190 5. The terms and conditions of this Amendment to the Corrective Action Order are effective
upon receipt
Smcerely,
James Reynolds
Pipehne Compliance Registry
Once of Pipeline Safety
Enclosure
Vl. a C ED MAIL RETURN El RE STE ND ECOPY,



DEPARTMENT OF TRANSPORTATION
RESEARCH AND SPECIAL PROGRAMS ADMINISTRATION
WASHINGTON, DC 20590
In the Matter of
Williams Gas Pipeline - Northwest, Respondent.
)
CPF No. 5-2003-1003-H
A ENDM TT CO ACTION ORDER
Pur ose and Back round
On May 2, 2003, the Associate Administrator for Pipeline Safety issued a Corrective Action Order
(May 2 Order) in this case, under authority of 49 U S. C g 60112, finding that continued operation
by Williams Gas Pipeline - Northwest (Respondent) of its 26-inch natural gas pipeline in v estern
Washington State would be hazardous to the public, property, and the environment v ithout
corrective measures
The May 2 Order was issued as a result of the May 1, 2003 rupture of the linc at mile post 1352. 7
near Lake Tapps in Pierce County, Washington. The May 2 Order restricted operating pressure on
the linc and required Respondent to conduct a metallurgical analysis of the May 1, 2003 failure, to
re-evaluate in-lme inspection surveys, to do a geotechnical evaluation of the area, and to take
appropriate remedial action
On December 13, 2003, the hne ruptured again This time the failure occurred near Toledo, Lee is
County, Washington
Pursuant to 49 U. S. C. ) 60117, thc Western Region, Office of Pipeline Safety (OPS) initiated an
investigation of the incident, The Washington Utilities and Transportation Commission (WUTC),
which, as an interstate agent, inspects the line for compliance with pipeline safety regulations, is
participating in the investigation.
Additi nal Prelimina 'nd s
~ On the morning of December 13, 2003, a rupture occurred on Respondent's 26-inch gas
transmission pipeline at Mile Post 128LS, approximately 7 miles south of the Chchalis
compressor station in Lewis County, Washington. AAer confirming that the pressure drop that
had been detected was indeed a failure, Respondent reported the failure to th«National
Response Center at approximately 11. 15 A. M. 1, "ST.



The failure resulted in the release of gas for at least three hours. There was no ignition and no
fatalities or tnJunes. The residents of 4 of the 12 homes in the vicinity evacuated voluntarily
The linc is located in primarily rural locations. Howcvcr, thc line is in close proximity to
population where the line passes through the Seattle area, Whatcom County, as well as other
communities. There were houses within 250 yards of the failure site as well as a road crossing
approximately 30 feet away.
The maximum allowable operating pressure (MAOP) had been reduced by 20 percent by the
May 2 Order.
Visual examination of the failed section revealed a dark stain at the edge of the rupture area
which is indicative of corrosion. Field examination revealed signs of moisture beta een the
1957 vintage tar coating and the pipe wall and indications of surface corrosion and pitting
Visual examination also revealed significant longitudinal cracking of the pipe body that appears
to be stress corrosion cracking (SCC)
The May 2 Order required a metallurgical analysis of the May I, 2003 failure The analysis,
performed by an independent laboratory, found that the cause was stress corrosion «racking
(SCC). The May 2 Order also required a geotechnical evaluation This evaluation, performed
by an independent consultant, indicated that land movement. originally thought to be a factor,
was not the cause.
According to a November 1992 metallurgical report by an independent third party, the failure
that occurred on the line approximately 7 miles south of Snohomish during hydrotesting was
causedl by stress ~convsion . :. «. . ' in,
An Apnl 23, 1999 metallurgical report by an independent third party consultant indicated that
stress corrosion cracking was involved in a leak that occurred near M. P. 1255 5 in March 1999
In addition to the failures on the line within the State of Washington, there were 22 fail wes duc
to SCC expenenced dunng hydrostatic testing of a 16-inch lateral between June and August
1994 between Mile Posts 21 and 26 near Oregon City, Oregon.
On October I, 2003, OPS issued an advisory bulletin to owners and operators of gas and
hazardous liquid pipelines advising them to assess their pipelines for susceptibility to SCC Th«
bulletin contains detailed instructions on identifying and addressing the SCC threat The
0
play a role in SCC include the operating pressures, imposed loads placed on pipeline due to
stress, the acidity of the soil, and coal tarcoating. These are factors found on this 26-inch line



~ Respondent operates a 30-inch pipeline parallel to the 26-inch line that is the subject of the May
2 Order This line is of newer construction and does not have the failure history of the 26-inch
line However, it is subject to the same land movements and soil conditions, and has coal tar
coating
Determination of Necessity for Corrective Action Order and Right to Hearing
Section 60112 of Title 49, United States Code, provides for the issuance of a Corrective Action
Order, aAer reasonable notice and the opportunity for a hearing, requiring corrective action, which
may include the suspended or restricted use of a pipeline facihty, physical inspection, testing, repair,
replacement, or other action as appropnate The basis for making the determmation that a pipeline
facility is hazardous, requinng correct& ve action, is set forth both in the above referenced statute and
49 C. F. R. )190. 233, a copy of which is enclosed.
Section 60112, and the regulations promulgated thereunder, provide for the issuance of a Corrective
Action Order without prior opportunity for notice and hearing upon a finding that failure to issue the
Order expeditiously will result in likely senous harm to life, property or the environment. In such
cases, an opportunity for a hearing will be provided as soon as practicable aAer the issuance of the
Order
AAcr evaluating the preliminary findings of fact, I continue to find that the operation of
Respondent's 26-inch line between the Sumas station near the Canadian border and the Washougal
station near the Columbia River (Sumas-Washougal 26-inch line), without corrective measures
would be hazardous to life, property and the environment and that additional measures arc required
Additionally, aAer considering the age of the pipe, the population near the pipeline in western
Washington state, the excessive land movements in the area, the prior history of the pipeline, the
May 1, 2003 accident attributed to stress corrosion cracking, the possibility that the December 13,
2003 accident was also caused by stress corrosion cracking, and the fact that a second accident
occurred under the reduced operating pressure, I find that a failure to expeditiously issue this
Amendment, requiring immediate corrective action, would likely result in serious harm to life,
property, and the environment.
Accordingly, this Amendment mandating needed immediate correcti ve action is issued without prior
notice and opportunity for a heanng. The terms and conditions of this Amendment are efYectivc
upon receipt.
Within 10 days of receipt of this Amendment, Respondent may request a hearing, to be held as soon
as practicable, by notifying the Associate Administrator for Pipeline Safety in wnting, delivcrcd
personally, by mail or by telecopy at (202) 366-4566. The hearing will be held in Lakcwood,
Colorado or Washington, DC on a date that is mutually convenient to OPS and Respondent



After receiving and analyzing additional data in the course of tlus investigation, OPS may identify
other corrective measures that need to be taken. In that event, Respondent will be notifie of any
additional measures required and further amendment of the May 2 Order will be considered. To the,
extent consistent with safety, Respondent will be afforded notice and an opportunity for a hearing
prior to the imposition of any additional corrective measures.
R ird
Pursuant to 49 U. S. C. $ 60112, I hereby order Respondent to immedtately take thc following
additional corrective actions
With respect to the Sumas-Washougal 26-iach Iiae:
Arlrhttonal pressure restnctton, Immediately reduce operating pressure on the line and alloi~
depletion of the product to achieve a reduced pressure of 100 psi withia 30 days of issuance
of this Amendment. Once the reduced pressure of 100 psi has been achieved, the line may be
operated at a maximum pressure of 110 psi as needed to maintain a minimal line pack on thc
system.
2. Metallurgical analysts. Conduct a detailed metallurgical analysis of the pipeline that failed nn
December 13, 2003 to determine the cause of failure and contributing factors Submit an
origmal copy of the report of this analysis to the Director, Western Region, OPS, within one
week of your receipt of the report,
3. Integnti management. Finalize an integrity management program that conforms to the
requirements for integrity management programs published on December 15, 2003 (new subpart
0 to 49 C. F. R. Part 192) on an expedited basis The program must address the factors involved
in the failures on the line that have occurred since 1990, including stress corrosion cracking and
land movement, as risks. Submit this program withia 90 days of issuance of this Amendment
for approval by the Director, Western Region
4. Replacement program. Withia 120 days of issuance of tlus Amendment, develop a plan for
replacement of pipe in those segments for which Respondent intends io seek removal of
pressure restrictions as provided for in item 5 below, The plan must provide that
A segment in a high consequence area, as defined in the natural gas integrity management
rule published on December 15, 2003, which is to be replaced, must be replaced on a
priority basis within three years of issuance of this Amendment.
A segment in a class 2 area must be replaced within five years of the issuance of this
Amendment.



iii. All other segments to be replaced must be replaced within ten years of issuance of this
Amendment.
iv. To the extent that pressure restrictions have been liAed on a segment in accordance v ith
item 5, retesting prescribed in item 5 must contmue until replacement.
v, Provided that there are no mdicationsof SCC, segments that contam pipe with well-bonded
coating and matenal toughness that meet standards for pipelines constructed aAer 1970 need
not be replaced.
5 Removal of pressure restrictions. The Director, Western Region, may authonze removal of the
pressure restnctions m this corrective action order, as amended, upon request by Respondent
Support a request for removal of the pressure restrictions on a segment by demonstrating the
fol lowmg.
The successful completion of either hydrostatic test or fraternal inspection of the segment
in accordance with requirements provided below and the establishment of an approved
retest interval for the segment that does not exceed 3 years; or
n. There is evidence that the pipe in the segment is not prone to SCC, This mcludes evidence,
that the pipe has been replaced smce original construction with pipe meeting standards for
toughness and coating acceptable for pipeline constructed since 1970 and has not shown
indications of SCC
iii. Successful completion of hydrostatic testing must include a "spike test", that is, a test
conducted at 110 percent of the specified minimum yield strength of the weakest pipe in the
test section fora penod of 1 hour The spike test must be followed by a test at a minimum
of 90 percent of the specified mimmum yield strength for eight hours. Each failure must
be metallurgically tested to identify cause and failed pipe must be replaced wi th pretested
pipe
iv. Successful completion of internal inspection must include:
~ Use of a tool that is at least capable of reliably detecting SCC. Tool capability must
be validated. Validation is done through hydrostatic testmg of one statistically
representative section without failure during the test. This hydrostatic test is done aAcr
the tool has been run and all identified SCC anomalies in the section have been
addressed.
~ Direct evaluation and repair or replacement of any identified SCC that could fail before
the middle of the next test cycle.
~ Follov mg wntten procedures approved by the Director, Western Region, that include
fitness for service critena for identifying, pnontizing, and correcting defects



6. Other exceptions from replacement. At any time, Respondent may present evidence that a
segment of pipe that this Amendment requires to be replaced is not susceptible to SCC and
request that the Deputy Associate Administrator, OPS, grant an exception to replacement For
example, Respondent may present evidence that a segment has been both hydrostatically tested
without failure due to SCC and internally inspected without identification of SCC' The decision
of the Deputy Associate Administrator granting or denying the request must be in writing
7, Advance no(ifica(ion of activities. Provide the Regional Director, Western Region, at least 5
working days advance notice of the schedules for any testing, inspection, excavation. repair, or
replacement done under the corrective action order, as amended. The purpose of this is to allov,
the Regional Director the opportumty to arrange for a Federal or State representative to witness
thc activity.
With respect to the parallel 30-inch line within the State of Washington, the 26-inch line from
the Washougal Compressor Station east to the Goldendale Compressor Station, and all the
transmission lines from the Washongal Compressor Station south to Grants Pass, Oregon:
8 Evaluate the lines for susceptibility to SCC based on data available and risk factors. Provide
a report to the Director, Western Region, within 180 days of issuance of this Amendment on
the findings and any programs Respondent is undertaking to address the findings
9, Monthly Progress Reports on the status of the evaluations required in Item 8 must be submitted
to the Director, Western Region.
Except for a request for a replacement exception (Item 6), the Director, Western Region, may extend
the time for the conduct of any item in this order, as amended Respondent may appeal any decision
of the Director, Western Region, OPS, or of the Deputy Associate Administrator, OPS, to the
Associate Admimstrator for Pipelin
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