# ALYESKA PIPELINE SERVICE CO — Notice of Probable Violation

- **operation:** document
- **citation:** CPF 520135008
- **title:** ALYESKA PIPELINE SERVICE CO — Notice of Probable Violation
- **source type:** enforcement
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2013-08-01
- **effective on:** Not available
- **summary:** CLOSED notice of probable violation citing 195.579(a).
- **machine formats:** - **json:** https://regulus.evalyn.ai/document/phmsa-enforcement-520135008.json
- **markdown:** https://regulus.evalyn.ai/document/phmsa-enforcement-520135008.md
- **app url:** https://regulus.evalyn.ai/document/phmsa-enforcement-520135008
- **source url:** https://primis.phmsa.dot.gov/enforcement-data/case/520135008
**body:**

Notice of Probable Violation involving ALYESKA PIPELINE SERVICE CO. PHMSA's enforcement data identifies the cited regulation as 195.579(a). The case was opened on 2013-08-01 and is reported as closed as of 2017-07-13. Proposed civil penalty: $145,000. Assessed civil penalty: $145,000. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

520135008_Closure Letter_07132017.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520135008/520135008_Closure%20Letter_07132017.pdf

520135008_Closure Letter_07132017_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520135008/520135008_Closure%20Letter_07132017_text.pdf

520135008_Final Order_10082015.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520135008/520135008_Final%20Order_10082015.pdf

520135008_Final Order_10082015_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520135008/520135008_Final%20Order_10082015_text.pdf

520135008_NOPV PCO PCP_08012013.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520135008/520135008_NOPV%20PCO%20PCP_08012013.pdf

520135008_NOPV PCO PCP_08012013_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520135008/520135008_NOPV%20PCO%20PCP_08012013_text.pdf

520135008_Operator Response_11042013.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520135008/520135008_Operator%20Response_11042013.pdf

520135008_Closure Letter_07132017_text.pdf

CERTIFIED MAIL - RETURN RECEIPT REQUESTED
July 13, 2017
Mr. Rod Hanson
Senior Vice President, Operations and Maintenance
Alyeska Pipeline Service Company
3700 Centerpoint Drive
Anchorage, Alaska 99503
CPF 5-2013-5008
Closure Letter
Dear Mr. Hanson:
On October 8, 2015, the Pipeline and Hazardous Materials Safety Administration (PHMSA)
issued to the Alyeska Pipeline Service Company a Final Order in the above-referenced case.
This Order included a Compliance Order and Civil Penalty assessment. Based on our review
of the documentation you provided and confirmation of payment of the civil penalty, it has
been determined that you have complied with the terms of this Order.
Accordingly, this case is now closed and no further action is contemplated with respect to the
matters involved in this case. Thank you for your cooperation in this matter.
Sincerely,
Dustin B. Hubbard
Acting Director, Western Region
Pipeline and Hazardous Materials Safety Administration
cc: PHP-60 Compliance Registry
PHP-500 H. Marlowe (#132739)

520135008_Final Order_10082015_text.pdf

October 8, 2015
Mr. Tom Barrett, President
Alyeska Pipeline Service Company
3700 Centerpoint Drive
P.O. Box 196660
Anchorage, AK 99503
Re: CPF No. 5-2013-5008
Dear Mr. Barrett:
Enclosed please find the Final Order issued in the above-referenced case. It makes one finding
of violation, assesses a civil penalty of $145,000, and specifies actions that need to be taken by
Alyeska Pipeline Service Company to comply with the pipeline safety regulations. The penalty
payment terms are set forth in the Final Order. When the civil penalty has been paid and the
terms of the compliance order completed, as determined by the Director, Western Region, this
enforcement action will be closed. Service of the Final Order by certified mail is deemed
effective upon the date of mailing, or as otherwise provided under 49 C.F.R. § 190.5.
Thank you for your cooperation in this matter.
Sincerely,
Jeffrey D. Wiese
Associate Administrator
for Pipeline Safety
Enclosure
cc: Mr. Chris Hoidal, Director, Western Region, OPS
Mr. Michael W. Joynor, Senior Vice President, Operations, Alyeska Pipeline Service
Company
CERTIFIED MAIL - RETURN RECEIPT REQUESTED



U.S. DEPARTMENT OF TRANSPORTATION
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION
OFFICE OF PIPELINE SAFETY
WASHINGTON, D.C. 20590
____________________________________
)
In the Matter of )
)
Alyeska Pipeline Service Company, ) CPF No. 5-2013-5008
)
Respondent. )
____________________________________)
FINAL ORDER
On January 8, 2011, pursuant to 49 U.S.C. § 60117, a representative of the Pipeline and
Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS),
responded to and began an investigation of a crude-oil release at Pump Station 1 (PS-01) of the
Trans-Alaska Pipeline System (TAPS) operated by Alyeska Pipeline Service Company
(Alyeska). TAPS transports crude oil from Alaska’s North Slope across 800 miles of varied
Alaskan terrain to Valdez, Alaska, North America’s northernmost ice-free port.1
On that same date, Alyeska had discovered crude oil flowing into the PS-01 booster pump
basement under insulation at the 4th Unit Booster Pump discharge line basement wall penetration
(2011 Failure). As a result of PHMSA’s subsequent investigation, the Director, Western Region,
OPS (Director), issued to Respondent, by letter dated August 1, 2013, a Notice of Probable
Violation, Proposed Compliance Order, and Proposed Civil Penalty (Notice or NOPV). In
accordance with 49 C.F.R. § 190.207, the Notice proposed finding that Alyeska had violated
49 C.F.R. § 195.579 and proposed assessing a civil penalty of $145,000 for the alleged violation.
The Notice also proposed ordering Respondent to take certain measures to correct the alleged
violation.
Alyeska responded to the Notice by letter dated November 4, 2013 (Response). The company
contested the allegation for Item 1, offered additional information in response to the Notice, and
requested that the proposed civil penalty be reduced and the Proposed Compliance Order be
withdrawn. It also submitted supplemental information in a subsequent letter dated August 26,
2014 (Supplemental Response). Respondent did not request a hearing and therefore has waived
its right to one.
1 http://www.alyeska-pipe.com/TAPS/PipelineOperations (last accessed on June 4, 2015).



CPF No. 5-2013-5008
Page 2
FINDING OF VIOLATION
The Notice alleged that Respondent violated 49 C.F.R. Part 195, as follows:
Item 1: The Notice alleged that Respondent violated 49 C.F.R. § 195.579(a), which states:
§ 195.579 What must I do to mitigate internal corrosion?
(a) General. If you transport any hazardous liquid or carbon dioxide
that would corrode the pipeline, you must investigate the corrosive effect
of the hazardous liquid or carbon dioxide on the pipeline and take
adequate steps to mitigate internal corrosion.
The Notice alleged that Respondent violated 49 C.F.R. § 195.579(a) by failing to take adequate
steps to mitigate internal corrosion in “deadlegs” (i.e., process piping sections that have been
isolated and no longer maintain a flow of liquid or gas) and areas of low flow on TAPS, which
transports a hazardous liquid that would corrode the pipeline. Specifically, the Notice alleged
that Alyeska had been aware since at least 2008 that TAPS faced the risk of internal corrosion
but failed to take adequate steps to control it. It alleged that the 2011 Failure was directly
caused by internal corrosion.
According to PHMSA, Alyeska hired a contractor, Det Norske Veritas (DNV), in 2011 to
conduct a root cause analysis of the 2011 Failure. DNV’s final report determined that the direct
cause of the leak was microbiologically influenced corrosion (MIC) and noted five causal
factors, all related to inhibit internal corrosion.2 Finally, PHMSA alleged that Alyeska had
installed a sleeve on piping at Pump Station 9 in 2013 to remediate internal corrosion that had
been causing significant (approximately 40%) pipe wall loss and that such repair showed that the
company’s internal corrosion program continued to be inadequate.
Alyeska responded to the Notice in writing on November 4, 2013 (Response). Alyeska disputed
PHMSA’s allegation that the company had been aware of internal corrosion problems on TAPS
as early as 2008 but failed to take adequate steps to mitigate it.3 The company stated that “the
[Notice] does not fully acknowledge the work that Alyeska has performed to improve its
Integrity Management program beginning in 2008 until the present”4 and outlined five principal
measures it had taken to address the problem.
First, Alyeska contended that since 2008, it had optimized its procedures for microbiological
monitoring, that it had used and assessed the effectiveness of appropriate biocide and corrosion
2 The Notice alleged that DNV specifically found five causal factors for the 2011 Failure: “a. [Pump Station 1]
Booster #4 not added, b. No bio testing/ biocide injection, c. Non-biocide inhibitor began in mid-90s, d. Risk
mitigation less than adequate on urgency to replace piping, and e. Lack of accessibility to inspect below ground
deadleg/low flow pipe segments.”
3 Alyeska also challenged the Proposed Compliance Order and proposed civil penalty amount. I will address those
arguments in the appropriate sections below.
4 Response, Attachment, at 2.



CPF No. 5-2013-5008
Page 3
inhibitors, and that it had assessed chloride sources. The company further asserted that in 2008,
it had contracted with Baker Petrolite, a nationally-recognized expert in the field, to perform a
corrosivity study for the crude oil flowing into TAPS. Alyeska claimed that it had used the
results of that study “to optimize the corrosion inhibition and biocide treatment programs and
tested recommended inhibitors and biocides using actual TAPS crude-oil and water samples.”5
Alyeska further stated that it had subsequently hired Baker Hughes to assess the company’s
internal corrosion inhibitor program and to assist Alyeska in improving its effectiveness.
Alyeska received an independent evaluation of the crude oil and water for corrosive elements
from Baker Hughes, which provided recommendations for a more effective internal corrosion
inhibitor program. Alyeska claimed that it had re-evaluated and revised its inhibitor-injection
program based on this report, had revised its procedures for biocide and inhibitor treatments in
Fall 2010, and had begun biocide treatments at Pump Station Three and Pump Station Four in
November 2010 and in pump station facility piping in February 2011. It also claimed that it had
treated PS-01 crude tanks with biocide in May 2011 and begun system biocide-treatment
monitoring of bacteria levels in April 2011, which showed locations where bacteria counts were
decreasing, an indicator of biocide effectiveness.6
Alyeska also engaged DNV to perform a root cause analysis of the booster pump leak at PS-01,
which was completed on December 7, 2011. Alyeska created a Management Action Plan to
address the identified causes of the leak. This included a 2012 Baker Hughes “assessment of
chlorides and their potential impact on corrosion acceleration.”7
Second, Alyeska argued that it had taken steps to replace or modify certain pipeline
infrastructure that the company believed to be susceptible to internal corrosion. This included
the removal of deadlegs and bringing certain facility piping above ground as part of the crude-oil
piping assessment and replacement required under a 2011 Consent Agreement with PHMSA.8
Third, the company argued that it had been expanding its Pipeline Integrity Testing (PIT)
program for internal inspections and assessments and researching new technologies that
potentially allowed the inspection of previously-inaccessible piping. These included guided
wave, electro-magnetic acoustic transducers, and robotic crawler “pigs.”9
Fourth, contrary to PHMSA’s allegation that the installation of a sleeve over corroded pipe at
Pump Station 9 in April 2013 demonstrated the inadequacy of the company’s internal corrosion
program, Alyeska asserted that this repair “does not demonstrate that the internal corrosion
5 Id, at 3.
6 Id.
7 Id. at 4.
8 In the Matter of Alyeska Pipeline Service Company, CPF 5-2011-5001S (August 17, 2011). Available at:
http://primis.phmsa.dot.gov/comm/reports/enforce/CONOEvent opid 0.html?nocache=3154# TP 1 tab 5.
9 Response, at 4-5.



CPF No. 5-2013-5008
Page 4
inhibitor program is inadequate. The purpose of the program is to provide monitoring,
prevention, and repair to maintain pipeline integrity…Installing any sleeve enhances the
effectiveness of the overall, system integrity management program and is not a measure of the
effectiveness of the corrosion inhibitor.”10
Fifth, in its Supplemental Response, Alyeska provided further information regarding the
adequacy of its internal-corrosion mitigation efforts. Alyeska stated that it was currently
performing flow studies, which indicated that “[l]aminar flow conditions are not reached until
TAPS flow rates are in the 200,000 barrels per day (BPD) range.” This rate is not expected to be
reached for several more years.11 Alyeska stated that although bacteria levels and corrosion rates
were shown to be increasing at some corrosion-coupon locations in its previously-submitted
Bacteria Testing Analysis PowerPoint presentation, TAPS was primarily experiencing corrosion
rates under 0.1 mils per year or less, which are considered low by NACE criteria. Additionally,
Alyeska described its process for ensuring the integrity of TAPS valve bypasses, including visual
inspections for evidence of external corrosion as well as non-destructive testing for evidence of
internal corrosion.12
After careful consideration of all these arguments and all of the evidence in the record, I am
unpersuaded that Alyeska took adequate steps from 2008 to 2011 to mitigate internal corrosion
on TAPS deadlegs and in low-flow areas. While it is clear that the company did take a number
of steps, particularly after the 2011 Failure, to deal with the company’s complex and
longstanding problems with MIC, the fact remains that the 2011 Failure itself constitutes strong
evidence that the efforts Alyeska had been making prior to that time were inadequate to mitigate
internal corrosion in low-flow piping. As stated in the Notice, DNV’s root cause analysis of the
2011 Failure concluded that the direct cause of the oil leak was MIC and five other generic
causes, including “[l]ess than adequate process for corrosion inhibitor selection.”
Alyeska was aware of these inadequacies several years before the 2011 release. In 2008,
Alyeska released a risk assessment report, titled “Removing Concrete from PS-01 Buried Piping
for Internal Corrosion Investigation.” Alyeska’s evaluation concluded that in order to deal with
the active corrosion problems affecting the PS01 below-ground piping, it was necessary to obtain
corrosion data for the welds on this buried piping. The report stated that if no data were
available,
[A]lyeska assumes a high probability of significant, active corrosion
associated with the belowground welds. . . Due to the high risks of
interrupting crude oil supply, every scenario the team evaluated
recommends replacing the buried pipe (i.e., the booster pump suction
line, over and short line, suction and discharge relief lines) and
10 Id. at 5.
11 Laminar, as opposed to turbulent, flow could allow a corrosive environment to accumulate near the walls of the
pipeline and possibly contribute to internal corrosion or enhance existing internal corrosion.
12 Supplemental Response, at 3.



CPF No. 5-2013-5008
Page 5
possible replacement or modification of the related facilities.
13
Despite such warnings from its own study, the company chose to continue using the existing
piping without taking appropriate steps to mitigate the internal corrosion that eventually resulted
in a release . In essence, Alyeska addressed the corrosion problem on the below-ground piping
symptomatically, contracting a corrosivity study with Baker Petrolite and an evaluation of the
internal corrosion inhibitor program with Baker Hughes but not taking action that would
properly correct the corrosion that led to the 2011 Failure.
Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R.
§ 195.579(a) by failing to take adequate steps to mitigate internal corrosion in deadlegs and areas
of low flow in TAPS.
This finding of violation will be considered a prior offense in any subsequent enforcement action
taken against Respondent.
Under 49 U.S.C. § 60122, Respondent is subject to an administrative civil penalty not to exceed
$100,000 per violation for each day of the violation, up to a maximum of $1,000,000 for any
related series of violations. In determining the amount of a civil penalty under 49 U.S.C.
§ 60122 and 49 C.F.R. § 190.225, I must consider the following criteria: the nature,
circumstances, and gravity of the violation, including adverse impact on the environment; the
degree of Respondent’s culpability; the history of Respondent’s prior offenses; the Respondent’s
ability to pay the penalty and any effect that the penalty may have on its ability to continue doing
business; and the good faith of Respondent in attempting to comply with the pipeline safety
regulations. In addition, I may consider the economic benefit gained from the violation without
any reduction because of subsequent damages, and such other matters as justice may require.
The Notice proposed a total civil penalty of $145,000 for the violation cited above.
Item 1: The Notice proposed a civil penalty of $145,000 for Respondent’s violation of
49 C.F.R. § 195.579(a), for failing to take adequate steps to mitigate internal corrosion in
deadlegs and areas of low flow in TAPS.
Alyeska objected to the proposed civil penalty on several grounds. First, it argued that a
comparison with other NOPVs issued by PHMSA to other operators in 2013 “demonstrates that
similar violations related to corrosion control, integrity assessment programs, cathodic protection
programs, and inline inspection requirements, all regulatory requirements under Pipeline
Integrity Management or Subpart H, Corrosion Control resulted in lower penalty amounts.”14
Specifically, it argued that Buckeye Partners received three NOPVs in 2013 alleging violations
of corrosion-related regulations. Each had proposed penalties of less than $100,000; two of the
ASSESSMENT OF PENALTY
13 Pipeline Safety Violation Report (August 1, 2013) (on file with PHMSA), at Exhibit 7, at 4.
14 Response, at 5-6.



CPF No. 5-2013-5008
Page 6
three were multiple-violation notices. Similarly, Texas Eastern Transmission was issued an
NOPV with three probable violations, only one of which was corrosion-related, with a proposed
penalty of $33,700. Centerpoint Energy Gas Transmission had an NOPV with 10 alleged
violations, five of which were integrity- or corrosion-related. Although the total proposed
penalty in that case was $137,200, the proposed penalties for the integrity-related
alleged violations totaled only $87,900. PHMSA issued an NOPV to Jayhawk Pipeline
for four alleged violations of regulations involving high consequence areas (HCAs), yet the
proposed penalty was only $82,400. BP Pipeline (North America) received an NOPV in 2013
with alleged violations of integrity management programs, including HCA regulations.
Although there were six probable violations, the proposed penalty was $100,000. According to
Alyeska, each of these cases had similar probable violations, yet all had proposed penalties that
were less, some significantly less, than the $145,000 proposed in this case.15
Alyeska further argued that because 49 C.F.R. § 190.225 is “silent on the consideration of
potential harm,….PHMSA should be considering only actual harm, such as personal injury or
adverse impact on the environment when assessing the gravity of an alleged violation.” The
company cited another 2013 case in which Kinder Morgan Liquids Terminals, LLC, received an
NOPV in 2013 for an accident in which an employee had been injured and yet the proposed
penalty was only $100,000. In contrast, Alyeska argued that in the current case, no harm
occurred. Therefore, Alyeska argued, the proposed penalty is unsupported by the nature,
circumstances and gravity of the violation when compared to other cases involving personal
injury or damage to the environment.16
Second, the company argued, with regard to culpability, that it had acted diligently, not
recklessly or negligently, in taking remedial action to mitigate internal corrosion. Alyeska
contended that its internal corrosion inhibitor program was designed to create an awareness of,
and to address, the consequences of moving hazardous liquid in TAPS.
Third, Alyeska argued, with regard to its history of prior offenses, that it had four prior
enforcement actions alleging violations of § 195.579, but three did not have any proposed
penalties. The remaining NOPV had a proposed penalty of only $11,000 for each of the
applicable probable violations.
Fourth, Alyeska argued, with respect to the lack of a penalty reduction for good faith, that it had
indeed demonstrated good-faith efforts to achieve compliance with § 195.579, through the
various measures discussed above. According to the company, these various efforts should serve
as “a mitigating factor” that would support a reduction of the proposed civil penalty.17
Fifth, Alyeska argued that while the proposed penalty would not affect the company’s ability to
continue in business, the proposed penalty could be more effectively spent on the company’s
continuing program to mitigate internal corrosion.
15 Id, at 5.
16 Id, at 6.
17 Id, at 7.



CPF No. 5-2013-5008
Page 7
I have carefully reviewed the record, considered Alyeska’s five arguments for a penalty
reduction, and evaluated the proposed penalty in this case relative to other recent enforcement
cases cited by Respondent. I find the company’s arguments unpersuasive. Specifically, I find
the proposed penalty to be reasonable and consistent with PHMSA’s civil penalty assessment
criteria.
Alyeska has put great store in comparing the proposed penalty in the present case with those
proposed against other operators in 2013. While PHMSA strives for consistency in its analysis
and calculation of proposed civil penalties, the wide range in penalty amounts among the cases
cited by Respondent is directly attributable to material differences in the facts that serve as the
underlying basis for considering each penalty factor.
The greatest shortcoming in Respondent’s analysis is that none of the other 2013 NOPVs cited
by Alyeska involved an accident.
18 In the present case, there was an actual release of crude oil
from TAPS that was a reportable incident causally related to the alleged violation. Additionally,
Alyeska cited one of its own cases where it was cited $11,000 for the same violation. Again, that
particular case did not involve an accident.
Further, it is misleading to compare a penalty assessed against one operator with one assessed
against another operator for the same regulatory violation, since PHMSA’s assessment criteria
do not depend upon the substantive content or subject matter of a regulation (e.g., internal
corrosion, welding, or valve inspections) to determine a proposed penalty, but, rather, rely upon
the nature, circumstances, gravity of the violation and other factors. These penalty factors and
the factual basis for each one are set forth in detail in PHMSA’s standardized Violation Report
and serve as the actual framework for proposing penalties. These factors are applied consistently
to all operators across all regions of the country. In summary, I find nothing in the assessment of
the proposed penalty in this case that is inconsistent or out of line with those assessed in the other
recent cases cited by Respondent.
Accordingly, having reviewed the record and considered the assessment criteria, I assess the
Respondent a total civil penalty of $145,000 for violation of 49 C.F.R. § 195.579(a).
Payment of the civil penalty must be made within 20 days of service. Federal regulations
(49 C.F.R. § 89.21(b)(3)) require such payment to be made by wire transfer through the Federal
Reserve Communications System (Fedwire), to the account of the U.S. Treasury. Detailed
instructions are contained in the enclosure. Questions concerning wire transfers should be
directed to: Financial Operations Division (AMK-325), Federal Aviation Administration, Mike
Monroney Aeronautical Center, P.O. Box 269039, Oklahoma City, Oklahoma 73125. The
Financial Operations Division telephone number is (405) 954-8845.
18 As noted earlier, Alyeska cited a case involving Kinder Morgan Liquids Terminals, LLC [CPF 1-2013-5004], “in
which an employee was injured and yet the proposed penalty was only $100,000.” This is incorrect. The Kinder
Morgan case actually involved five probable violations arising out of an accident, but the total proposed (and
uncontested) penalty in the case was $500,000, not $100,000, as stated by Alyeska. The Kinder Morgan case
actually reinforces the large difference that exists between penalties for violations that constitute causal factors in
accidents and those that do not.



CPF No. 5-2013-5008
Page 8
Failure to pay the $145,000 civil penalty will result in accrual of interest at the current annual
rate in accordance with 31 U.S.C. § 3717, 31 C.F.R. § 901.9 and 49 C.F.R. § 89.23. Pursuant to
those same authorities, a late penalty charge of six percent (6%) per annum will be charged if
payment is not made within 110 days of service. Furthermore, failure to pay the civil penalty
may result in referral of the matter to the Attorney General for appropriate action in a district
court of the United States.
COMPLIANCE ORDER
The Notice proposed a compliance order with respect to Item1 in the Notice, for a violation of
49 C.F.R. § 195.579(a). Under 49 U.S.C. § 60118(a), each person who engages in the
transportation of hazardous liquids or who owns or operates a pipeline facility is required to
comply with the applicable safety standards established under chapter 601. Alyeska stated that
the Proposed Compliance Order should be withdrawn because the work that was proposed has
already been completed.
The Director has reviewed the Response and acknowledges that Respondent has completed most
of the Proposed Compliance Order items. However, Alyeska has not demonstrated that it has
completed Item (1)(a) of the Proposed Compliance Order by optimizing its procedures for
microbiological monitoring or biocide-dosing protocols for current and anticipated future flow
rates.
Therefore, pursuant to the authority of 49 U.S.C. § 60118(b) and 49 C.F.R. § 190.217,
Respondent is ordered to take the following action to ensure compliance with the pipeline safety
regulations applicable to its operations:
1. With respect to the violation of § 195.579(a) (Item 1), Respondent must optimize
procedures for microbiological monitoring, especially effectiveness in deadlegs and
low-flow areas, as well as biocide-dosing protocols to mitigate MIC for current and
anticipated future flow rates. Such work must be completed no later than 180 days
following receipt of this Order.
The Director may grant an extension of time to comply with any of the required items upon a
written request timely submitted by the Respondent and demonstrating good cause for an
extension.
Failure to comply with this Order may result in administrative assessment of civil penalties not
to exceed $200,000 for each violation for each day the violation continues or in referral to the
Attorney General for appropriate relief in a district court of the United States.
Under 49 C.F.R. § 190.243, Respondent has a right to submit a Petition for Reconsideration of
this Final Order. The petition must be sent to: Associate Administrator, Office of Pipeline
Safety, PHMSA, 1200 New Jersey Avenue, SE, East Building, 2nd Floor, Washington, DC
20590, with a copy sent to the Office of Chief Counsel, PHMSA, at the same address. PHMSA
will accept petitions received no later than 20 days after receipt of service of this Final Order by



CPF No. 5-2013-5008
Page 9
the Respondent, provided they contain a brief statement of the issue(s) and meet all other
requirements of 49 C.F.R. § 190.243. The filing of a petition automatically stays the payment of
any civil penalty assessed. Unless the Associate Administrator, upon request, grants a stay, all
other terms and conditions of this Final Order are effective upon service in accordance with
49 C.F.R. § 190.5.
___________________________________ __________________________
Jeffrey D. Wiese Date Issued
Associate Administrator
for Pipeline Safety

520135008_NOPV PCO PCP_08012013_text.pdf

NOTICE OF PROBABLE VIOLATION
PROPOSED COMPLIANCE ORDER
and
PROPOSED CIVIL PENALTY
CERTIFIED MAIL – RETURN RECEIPT REQUESTED
August 1, 2013
Mr. Tom Barrett
President
Alyeska Pipeline Service Company
3700 Centerpoint Drive
P.O. Box 196660
Anchorage, AK 99503
CPF 5-2013-5008
Dear Mr. Barrett:
On January 8, 2011, a representative of the Pipeline and Hazardous Materials Safety
Administration (PHMSA), pursuant to Chapter 601 of 49 United States Code, responded to and
began an investigation of a crude oil release at Pump Station 1 (PS-01) of the Trans-Alaska
Pipeline System (TAPS) operated by Alyeska Pipeline Service Company (Alyeska).
Background
TAPS is an 800 mile, 48-inch diameter pipeline. Alyeska has operated TAPS since 1977,
transporting crude oil from Prudhoe Bay to the Valdez Marine Terminal in Alaska. The unique
environment and circumstances under which TAPS operates pose many challenges for the
pipeline. The challenges Alyeska faces include seismic instability, permafrost, cold
temperatures, the vast distance of land the pipeline travels, mountainous and rugged terrain,
remote locations along the pipeline, and internal and external corrosion.
In 1988, Alyeska discovered internal corrosion in sections of pipe known as deadlegs which
experienced only occasional or low flow movement of oil. Alyeska reported that the cause of
this internal corrosion was water that was deposited by the crude oil and settled in the bottom of
the pipe.1
1 GAO Report to the Chairman, Subcommittee on Water, Power, and Offshore Energy Resources, Committee on
Interior and Insular Affairs, House of Representatives, RCED91-89, Trans-Alaska Pipeline, July 1991, page 24.



In 2007, Alyeska discovered internal corrosion in the heat-affected zone of girth welds in
sections of pipe that were being removed from PS-01. An Alyeska summary of the corrosion
noted that this section of the piping system at PS-01 has low oil flow compared to the mainline
pipe, that low flow rates can increase the potential for water and sediment to settle at the bottom
of the pipe and provide a corrosive environment, and that the facility piping systems are not
piggable by either cleaning pigs or in-line inspection pigs.2
On April 1, 2008, PHMSA issued a Notice of Probable Violation alleging that Alyeska had
failed to provide any records to demonstrate that it had investigated the corrosive effects of the
hazardous liquids transported and that it had not taken adequate steps to mitigate internal
corrosion in the TAPS mainline.3 In Alyeska’s written response, the company stated “Alyeska
has not analyzed the crude oil transported in TAPS.”4 Alyeska asserted that it mitigated internal
corrosion through the use of an aggressive maintenance pigging program, chemical inhibitors,
and corrosion coupons. Nonetheless, Alyeska agreed in a Compromise Agreement dated
November 16, 2011, that the company had committed these violations. The Compromise
Agreement also stated that the company had developed and implemented an internal corrosion
mitigation program.
In September 2008, Alyeska discovered internal corrosion adjacent to girth welds in tank lines at
PS-01 and filed a Safety-Related Condition Report with the Office of Pipeline Safety. The flow
rate in these tank lines is significantly less than the flow rate on the mainline pipe. Alyeska
installed five sleeves over areas with significant pipe wall loss, including two areas with over
80% wall loss.5 In February 2010, PHMSA inspectors noted in the Safety-Related Condition
Report that “Alyeska has completed a conceptual engineering study of the active below ground
DOT covered piping. This study identified piping that was… difficult to inspect due to structural
interference. Alyeska is currently conducting a preliminary engineering study to determine
project details for the subset of this work at PS01.”
Alyeska’s 2008 Annual Report for Pipeline and Valdez Marine Terminal Facilities Corrosion
Monitoring was sent to the Joint Pipeline Office (JPO) on April 17, 2009. This report shows that
the company questioned the effectiveness of a corrosion inhibitor that it was using on TAPS:
“The use of RU248, which is formulated for corrosion caused by dissolved acid gases, may no
longer be effective in APSC system due to changing crude oil characteristic. This is because
corrosion induced bacteria has been identified in several locations at the facilities…. IME
[Alyeska’s Integrity Management Engineering department] recommends and will be conducting
an evaluation of current corrosion inhibitor effectiveness by conducting a study on all segments
of the facilities; a recommendation and implementation of the most effective chemical that
inhibits corrosion will be completed.”6
In 2009, the JPO requested information on the internal corrosion at PS-01. Alyeska responded
2 GL 17088, Exhibit 5, page 1.
3 Notice of Probable Violation, CPF No. 5-2008-5008.
4 See GL 16053, May 22, 2008, Finding 5, pages 2-3.
5 PHMSA OPS Safety Related Condition Report 20080077.
6 Trans Alaska Pipeline System 2008 Annual Report for Pipeline and Valdez Marine Terminal Facilities Corrosion
Monitoring, page 20, Appendix A, Table 5.
2



that they had performed a risk assessment on October 6, 2008, and decided not to excavate the
concrete boxes at PS-01 to inspect for corrosion on the below ground piping.7 In addition, Baker
Petrolite, a contractor Alyeska selected to evaluate the corrosivity of TAPS crude oil, reported
“significant levels of bacteria in the Alyeska system which have the potential to cause
corrosion.”8 Specifically, Baker Petrolite noted that “[b]ased on the current test results, it
appears that facility piping which is not in turbulent flow and able to be pigged has the potential
for bacteria corrosion problems.”9
In December of 2009, Baker Petrolite reported to Alyeska the results of a bacteria enumeration
survey that it conducted in fall of 2009 on the pipeline deadlegs. The report stated: “The basic
conclusion from this survey is that Pipeline and the Valdez Marine Terminal have bacteria in
numbers that can and will degrade the integrity of the measured systems.”10
On June 24, 2010, Alyeska met with PHMSA and made a presentation regarding its internal
corrosion program. The materials Alyeska provided during that presentation indicated that it had
been analyzing the corrosivity of the crude oil and water in TAPS since 2007, that the internal
corrosion inhibitor that it had been using was ineffective for the type of bacteria found in TAPS,
and that the company planned to begin using a new corrosion inhibitor treatment program by
September 15, 2010.11 The company also planned to treat all deadlegs in the system according
to the new inhibitor program in September and October of 2010.12
On January 8, 2011, crude oil was discovered flowing into the PS-01 booster pump basement
under the insulation at the 4th Unit Booster Pump discharge line basement wall penetration.
Alyeska contracted with Det Norske Veritas (DNV) to perform the metallurgical analysis of the
removed pipe segment. DNV produced a report, “PS01 Booster Pump Manifold Failure
Investigation: Laboratory Analysis September 12, 2011,” which concluded: “High levels of
bacteria were found in solids and swabs taken from the area of pitting associated with the leak
location…. The presence of microorganisms on the pipe surfaces combined with the
undercutting pit morphology observed in the metallographic cross-sections indicates that
microbiologically influenced corrosion (MIC) is likely the primary corrosion mechanism.”13
In 2011, Alyeska contracted with DNV to perform a Root Cause Analysis of the PS-01 crude oil
release. The final Root Cause Analysis report, dated December 7, 2011, concludes that the direct
cause of the oil leak was Microbiologically Influenced Corrosion (MIC), and that five causal
factors were: “a. PS01 Booster #4 not added, b. No bio testing/ biocide injection, c. Non-biocide
inhibitor began in mid-90s, d. Risk mitigation less than adequate on urgency to replace piping,
and e. Lack of accessibility to inspect below ground deadleg/low flow pipe segments.” The
report states, “Some of the causal factors have a very long historical influence on the potential
7 GL 18303, Exhibit 7, Removing Concrete from PS01 Buried Piping for Internal Corrosion Investigation, page 16.
8 GL 18303, Exhibit 5, Baker Petrolite letter to Alyeska dated February 9, 2009, page 1.
9 GL 18303, Exhibit 5, Baker Petrolite letter to Alyeska dated February 9, 2009, page 5
10 Baker Petrolite Letter to Alyeska dated December 10, 2009, pages 1-2.
11 Alyeska Internal Corrosion Program, Integrity Management Engineering, presentation dated June 24, 2010, slide
14.
12 Id. at slide 23
13 DNV, PS01 Booster Pump Manifold Failure Investigation: Laboratory Analysis, September 12, 2011, page 19.
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for MIC to develop (e.g., a. and b. above).”14
DNV’s Root Cause Analysis noted six generic causes of the accident, including “Less than
adequate process for corrosion inhibitor selection.”15
In response to the January 2011 release at PS-01, PHMSA issued a Notice of Proposed Safety
Order (CPF 5-2011-5001S) on February 1, 2011, which proposed requiring Alyeska to
implement certain safety actions to address factors involved in the release of crude oil and
difficulties associated with safely restarting the pipeline. That proposed safety order resulted in a
Consent Order on August 17, 2011. Once PHMSA believed the primary causal factors of the
January 2011 release had been addressed, PHMSA began to focus on whether any regulatory
violations had contributed to the release by reviewing the DNV metallurgical analysis and root
cause analysis and the PHMSA Accident Investigation Report.
In 2013, Alyeska installed a sleeve over a pipe with approximately 40% wall loss caused by
internal corrosion in the 36” high-pressure (discharge) relief header at PS-9.16 This pipe has a
low flow rate compared to the mainline pipe, similar to the low flow conditions in the PS-01
deadleg prior to the January 2011 release.
It appears that you have committed a probable violation of the Pipeline Safety Regulations, Title
49, Code of Federal Regulations. The probable violation is:
1. §195.579 What must I do to mitigate internal corrosion?
(a) General. If you transport any hazardous liquid or carbon dioxide that would
corrode the pipeline, you must investigate the corrosive effect of the hazardous
liquid or carbon dioxide on the pipeline and take adequate steps to mitigate
internal corrosion.
Alyeska did not take adequate steps to mitigate internal corrosion in deadlegs and areas of low
flow in TAPS. Alyeska was aware of this problem by 2008, but failed to adequately mitigate
internal corrosion. PHMSA, the Joint Pipeline Office, and Alyeska’s contractors voiced
numerous concerns regarding Alyeska’s internal corrosion mitigation efforts, including those
being taken at PS-01, between 2008 and 2010.
The leak that began at PS-01 on January 8, 2011, was caused by internal corrosion; DNV’s final
Root Cause Analysis report concluded that the direct cause of the oil leak was Microbiologically
Influenced Corrosion (MIC), and noted six generic causes of the accident, including “Less than
adequate process for corrosion inhibitor selection.” In 2013, Alyeska installed a sleeve at PS-9
to remediate internal corrosion that was causing significant pipe wall loss, which shows that the
internal corrosion program continued to be inadequate.
14 DNV, Alyeska Root Cause Analysis – PS01 Booster Pump, December 7, 2011, pages 24-25.
15 Id. at 25.
PHMSA).
16 Email from Joseph P. Robertson, Alyeska, to Bill Flanders, PHMSA 
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