# BP PIPELINE (NORTH AMERICA) INC. — Notice of Probable Violation

- **operation:** document
- **citation:** CPF 420075003
- **title:** BP PIPELINE (NORTH AMERICA) INC. — Notice of Probable Violation
- **source type:** enforcement
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2007-02-13
- **effective on:** Not available
- **summary:** CLOSED notice of probable violation citing 195.410(a)(1), 195.420(c), 195.432(a), 195.436, 195.573(a), 195.579(a), 195.581(a).
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- **markdown:** https://regulus.evalyn.ai/document/phmsa-enforcement-420075003.md
- **app url:** https://regulus.evalyn.ai/document/phmsa-enforcement-420075003
- **source url:** https://primis.phmsa.dot.gov/enforcement-data/case/420075003
**body:**

Notice of Probable Violation involving BP PIPELINE (NORTH AMERICA) INC.. PHMSA's enforcement data identifies the cited regulations as 195.410(a)(1),  195.420(c),  195.432(a),  195.436,  195.573(a),  195.579(a),  195.581(a). The case was opened on 2007-02-13 and is reported as closed as of 2012-04-17. Proposed civil penalty: $168,000. Assessed civil penalty: $142,000. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

420075003_Amended Decision on the Petition for Reconsideration_02172011.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420075003/420075003_Amended%20Decision%20on%20the%20Petition%20for%20Reconsideration_02172011.pdf

420075003_Amended Decision on the Petition for Reconsideration_02172011_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420075003/420075003_Amended%20Decision%20on%20the%20Petition%20for%20Reconsideration_02172011_text.pdf

420075003_Closure_04172012.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420075003/420075003_Closure_04172012.pdf

420075003_Closure_04172012_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420075003/420075003_Closure_04172012_text.pdf

420075003_Decision on the Petition for Reconsideration_02042011 .pdf: https://primis.phmsa.dot.gov/enforcement-documents/420075003/420075003_Decision%20on%20the%20Petition%20for%20Reconsideration_02042011%20.pdf

420075003_Decision on the Petition for Reconsideration_02042011_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420075003/420075003_Decision%20on%20the%20Petition%20for%20Reconsideration_02042011_text.pdf

420075003_FinalOrder_07192010.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420075003/420075003_FinalOrder_07192010.pdf

420075003_FinalOrder_07192010_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420075003/420075003_FinalOrder_07192010_text.pdf

420075003_Petition for Reconsideration_08122010.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420075003/420075003_Petition%20for%20Reconsideration_08122010.pdf

CPF 4-2007-5003 BP Pipeline North America - Response Letter.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420075003/CPF%204-2007-5003%20BP%20Pipeline%20North%20America%20-%20Response%20Letter.pdf

CPF 4-2007-5003 BP Pipeline North America NOPV.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420075003/CPF%204-2007-5003%20BP%20Pipeline%20North%20America%20NOPV.pdf

CPF 4-2007-5003 BP Pipeline North America NOPV.pdf

U.S. Department
of Transportation
Pipeline and
Hazardous Materials Safety
Administration
8701 South Gessner, Suite 11 10
Houston, TX 77074
NOTICE OF PROBABLE VIOLATION
PROPOSED CIVIL PENALTY
and
PROPOSED COMPI-IANCE ORDER
CERTIFIED MAIL - RETURN RECEIPT REQUESTED
February 13, 2007
Mr. Jim La Manna
V. P. Operations
BP Pipeline North America, Inc.
Mail Code 7018
281 00 Torch Parkway
Warrenville, IL 60555
- CPF 4-2007-5003
Dear Mr. La Manna:
4
During the months of August, 2004, July, August, September, October, November and
December, 2005 a representative of the Pipeline and Hazardous Materials Safety
Administration (PHMSA), pursuant to Chapter 601 of 49 United States Code, conducted
pipeline safety inspections of BP Pipeline North America, Inc. (BP) facilities and records
pertaining to the Seaway Products System, in Texas and Oklahoma; West System, New
MexicoTTexas; and Texas/Oklahoma; East System, Oklahoma; and the Cushing Tank
Farm.
As a result of the inspection, it appears that you have committed probable violations of
the Pipeline Safety Regulations, Title 49, Code of Federal Regulations. The items
inspected and the probable violations are:
1. 9195.410 Line markers
(a) Except as provided in paragraph (b) of this section, each operator shall
place and maintain line markers over each buried pipeline in accordance with
the following:
(1) Markers must be located at each public road crossing, at each railroad



crossing, and in sufficient number along the remainder of each buried line so
that its location is accurately known.
(c) Each operator shall provide line marking at locations where the line is
above ground in areas that are accessible to the public.
BP does not have sufficient markers to accurately show where their pipelines are
located. When crossing cultivated agricultural fields, often the markers on the far side of
the field could not be seen. From valve sites, looking in both directions, the next marker
for the pipeline could not be seen. The lack of pipeline marking is a common problem
with several of the BP pipelines that were inspected. The pipelines were marked at road
crossings.
2. 9195.436 Security of facilities.
Each operator shall provide protection for each pumping station and breakout
tank area and other exposed facility (such as scraper traps) from vandalism
and unauthorized entry.
BP has a number of pump station, junction and scraper trap facilities that do not have
adequate protection against unauthorized entry or vandalism. Barbed wire fences are
not adequate. The Monroe pump station and break out tanks had cyclone fencing with
barbed wire around the top around the pump station, and 3 strands of barbed wire
around the break out tank area. Vandals got into the tank area, climbed up a tank and
walked around the wind girders on one of the tanks spraying graffiti. The vandals then
climbed down onto the floating roof, painted graffiti, and smoked on the floating roof.
The Artesia pump station has a 4 foot high hog and barbed wire fence facing the county
road, and barbed wire around the remainder of the facility. The Fullerton pump station1
break out tank area have no fencing at all. The gravel county road actually cuts through
the pump station. Remote location is also not adequate to meet the requirements of this
regulation.
9195.573 What must I do to monitor external corrosion control?
(a) Protected pipelines. You must do the following to determine whether
cathodic protection required by this subpart complies with Sec. 195.571:
1. Conduct tests on the protected pipeline at least once each calendar year,
but with intervals not exceeding 15 months. However, if tests at those intervals
are impractical for separately protected short sections of bare or ineffectively
coated pipelines, testing may be done at least once every 3 calendar years, but
with intervals not exceeding 39 months.
(d) Breakout tanks. You must inspect each cathodic protection system used to
control corrosion on the bottom of an aboveground breakout tank to ensure
that operation and maintenance of the system are in accordance with API
Recommended Practice 651. However, this inspection is not required if you
note in the corrosion control procedures established under Sec. 195.402(~)(3)
why compliance with all or certain operation and maintenance provisions of
API Recommended Practice 651 is not necessary for the safety of the tank.
BP is just beginning to implement surveys that consider IR drop. This requirement has
been in place since regulations were changed in 2001. A number of locations had
instant off potentials, measured during the PHMSA inspections that were less negative



than the -850 mV criteria. Operator records indicate that the tank bottoms are also not
being surveyed to account for IR drop during annual CP surveys.
4. 9195.579 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.
BP has not done adequate investigations to determine whether there is internal
corrosion or the potential for internal corrosion. BP has performed little monitoring, and
has not done inspections to investigate whether there could be internal corrosion in
facilities and non-piggable piping. The investigation of internal corrosion appears to be
based upon a few internal coupons, which are improperly located on pipelines, and no
other evidence could be produced.
5. 91 95.420 Valve maintenance
(c) Each operator shall provide protection for each valve from unauthorized
operation and from vandalism.
A number of the BP Pipeline valves do not have protection from vandalism at the
sites. The valves were chained and locked to prevent unauthorized use, but
these locations did not provide any deterrence against vandalism. Local
personnel did provide additional information regarding this issue.
During the inspections it was noted that BP' preferred method of complying with
195.420~ is to install locked chain link fencing around the valves. This was
evident in the six BP units that were inspected, where most of above ground
valves were located in locked fences.
Some of the remaining valves in those units were located above ground with no
fences. Some of the valves were inside a pipe post and beam enclosure, which
may be sufficient to keep cattle from rubbing on the valves, but do not address
prevention of vandalism. The number of above ground valves that were
observed without fences by the inspector on the six Texas and New Mexico units
exceeded seven, and the lack of fencing was pointed out to BP personnel at the
time of the inspections.
It should be pointed out that all of the unfenced valves were chain locked and
some had steel barricade posts installed. A review of your procedures by our
inspectors did not reveal any alternative method of security for valve sites
acceptable to you. BP should review their program, procedures, and facilities to
ensure they are compliant with this regulation.
6. 9195.432 Breakout tanks.
(a) Except for breakout tanks inspected under paragraphs (b) and (c) of this
section, each operator shall, at intervals not exceeding 15 months, but at least
once each calendar year, inspect each in-service breakout tank.



(b) Each operator shall inspect the physical integrity of in-service atmospheric
and low-pressure steel aboveground breakout tanks according to section 4 of
API Standard 653. However, if structural conditions prevent access to the tank
bottom, the bottom integrity may be assessed according to a plan included in
the operations and maintenance manual under §195.402(~)(3).
(c) Each operator shall inspect the physical integrity of in-service steel
aboveground breakout tanks built to API Standard 2510 according to section 6
of API 510.
(d) The intervals of inspection specified by documents referenced in
paragraphs (b) and (c) of this section begin on May 3, 1999, or on the
operator's last recorded date of the inspection, whichever is earlier.
During the PHMSA inspections of BP breakout tanks at pump stations and the Cushing
tank farm, a number of breakout tanks were noted for items not in compliance with the
requirements of API 653.
The records indicate that the tanks have been inspected, and the items not in
compliance with API 653 should have been noted and corrected after the inspections.
The records for the internal inspections and in some cases external inspections make it
impossible to determine whether issues documented during the inspections have been
addressed. Record keeping must include the records for the items identified during the
inspections, and their resolution, or reasons for not being resolved.
7. S195.581 Which pipelines must I protect against atmospheric corrosion and
what coating material may I use?
(a) You must clean and coat each pipeline or portion of pipeline that is
exposed to the atmosphere, except pipelines under paragraph (c) of this
section.
Several of the breakout tank roofs, above ground valves, piping in opened vaults and
exposed pipeline areas had coating that was failing or had failed, and was leaving the
pipe or tank top susceptible to external corrosion. If left as is, corrosion could continue
to the extent that the integrity of the pipeline or tanks would be compromised. Coating
should be replaced before serious corrosion occurs.
Under 49 United States Code, 5 60122, you are subject to a civil penalty not to exceed
$1 00,000 for each violation for each day the violations persists up to a maximum of
$1,000,000 for any related series of violations. The Compliance Officer has reviewed
the circumstances and supporting documentation involved in the above probable
violation(s) and has recommended that you be preliminarily assessed a civil penalty of
$168,000 as follows:
Item number
1
2
3
PENALTY
$26,000



With respect to items 5, and 7, we have reviewed the circumstances and supporting
documents involved in this case and have decided not to conduct additional enforcement
action or penalty assessment proceedings at this time. We advise you to promptly
correct these item(s). Be advised that failure to do so may result in BP being subject to
additional enforcement action.
With respect to items 1 through 4, and 6, pursuant to 49 United States Code § 601 18,
the Pipeline and Hazardous Materials Safety Administration proposes to issue a
Compliance Order to BP Products Operating, L.P. Please refer to the Proposed
Compliance Order which is enclosed and made a part of this Notice.
Enclosed as part of this Notice is a document entitled Response Options for Pipeline
Operators in Compliance Proceedings. Please refer to this document and note the
response options. If you do not respond within 30 days of receipt of this Notice, this
constitutes a waiver of your right to contest the allegations in this Notice and authorizes
the Associate Administrator for Pipeline Safety to find facts as alleged in this Notice
without further notice to you and to issue a Final Order.
In your correspondence on this matter, please refer to CPF 4-2007-5003 and for each
document you submit, please provide a copy in electronic format whenever possible.
Sincerely,
R. M. Seeley
Director, Southwest Region
Pipeline and Hazardous
Materials Safety Administration
Enclosures: Proposed Compliance Order
Response Options for Pipeline Operators in Compliance Proceedings



PROPOSED COMPLIANCE ORDER
Pursuant to 49 United States Code $ 60118, the Pipeline and Hazardous Materials
Safety Administration (PHMSA) proposes to issue to BP Pipeline North America, Inc. a
Compliance Order incorporating the following remedial requirements to ensure the
compliance of BP with the pipeline safety regulations:
1. In regard to ltem #1 of the Notice, BP must perform an inspection of pipeline ROW'S
throughout BP's pipeline system. The inspection is to evaluate the line markers
currently posted along the rights-of-way, as well as identify those areas where
additional markers are needed. If there are areas, such as cultivated fields, where it
is impractical to place markers, or because the markers are removed or plowed
under by the farmer, an alternative method of ensuring the safety of the public and
the pipeline should be developed. In areas where there are insufficient markers,
develop a plan and time table to place markers to ensure BP is in compliance with
$1 95.41 O(a)(l).
2. ltem #2 of the Notice indicates a lack of security at some BP facilities. BP shall
perform a survey of their pipeline facilities, identifying any facilities that do not meet
the requirements of $195.436. For BP facilities that do not meet the regulatory
requirements of being protected from unauthorized entry, and vandalism, BP shall
develop a plan and time table to secure the facilities, and ensure that they are in
compliance with $1 95.436.
3. In regard to ltem #3 of the Notice pertaining to BP's pipeline systems, review BP's
CP data collection and evaluation to ensure that data meets the regulatory
requirements, and that the pipelines are protected. In areas where the pipelines are
not adequately protected, develop a plan and time table to improve the CP systems
to bring BP into compliance.
4. In regard to ltem #4 of the Notice pertaining to BP's pipeline systems, perform an
assessment of pipelines and all facilities to determine if there are areas that would be
susceptible to internal corrosion. Perform inspections, install monitoring, and if
active corrosion is determined, implement mitigation methods.
5. Regarding ltem #6 of the Notice, BP must perform a review to ensure that all of BP's
breakout tanks are in compliance with $195.432. Items found not in compliance with
s195.432 and API-653 requirements shall be corrected, and a program to follow
through on future inspection issues implemented.
The data and results generated during API-653 internal and external inspections
shall be presented, along with a report showing resolution of any issues discovered
during the inspection, and explanation of any issues that were not resolved.
6. BP shall maintain documentation of the safety improvement costs associated with
fulfilling this Compliance Order and submit the total to R. M. Seeley, Director,
Southwest Region, Pipeline and Hazardous Materials Safety Administration. Costs



shall be reported in two categories: I) total cost associated with preparationlrevision
of plans, procedures, studies and analyses, and 2) total cost associated with
replacements, additions and other changes to pipeline infrastructure.
7. Submit to the Director, Southwest Region, Pipeline and Hazardous Materials Safety
Administration, 8701 South Gessner, Suite 11 10, Houston, Texas 77074.
1. Results of surveys and plans, with time tables, must be submitted within 30 days
following the receipt of the Final Order.
2. All items shall be completed within 365 days following the receipt of the Final
Order.

420075003_FinalOrder_07192010_text.pdf

JUL 19 2010
Mr. Steve Pankhurst
President
BP Pipelines (North America), Inc.
28100 Torch Parkway
Warrenville, IL 60555
Re: CPF No. 4-2007-5003
Dear Mr. Pankhurst:
Enclosed please find the Final Order issued in the above-referenced case. It makes findings of
violation, assesses a reduced civil penalty of $142,000, and specifies certain actions that need to
be taken by BP Pipelines (North America), Inc., 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, Southwest
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. Rod M. Seeley, Director, Southwest Region, PHMSA
Mr. Rob Knanishu, BP Pipelines (North America), Inc.
Mr. Bill Von Drehle, Director of Safety and Compliance, Centurion Pipeline
5 Greenway Plaza, Suite 110, Houston, TX 77046
Mr. Todd Tullio, Manager, Regulatory Compliance, ConocoPhillips Pipeline Company
600 North Dairy Ashford, Houston, Texas 77079
CERTIFIED MAIL – RETURN RECEIPT REQUESTED[7009 1410 0000 2472 2575]



U.S. DEPARTMENT OF TRANSPORTATION
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION
OFFICE OF PIPELINE SAFETY
WASHINGTON, DC 20590
____________________________________
In the Matter of )
BP Pipelines (North America), Inc., ) CPF No. 4-2007-5003
)
)
)
Respondent. )
____________________________________)
FINAL ORDER
During August 2004 and on various dates between July and December 2005, pursuant to 49
U.S.C. § 60117, representatives of the Pipeline and Hazardous Materials Safety Administration
(PHMSA), Office of Pipeline Safety (OPS), conducted an on-site pipeline safety inspection of
the facilities and records of BP Pipelines (North America), Inc. (BP Pipelines or Respondent), at
the company’s New Mexico, Texas, and Oklahoma locations. The inspection included the
following systems: Seaway Products Texas System, a 400-mile system transporting
hydrocarbons across Texas; the Seaway Oklahoma Unit, a 155-mile system transporting
hydrocarbons; the East System Oklahoma Unit, a 246-mile system transporting crude oil; the
West System, a 520-mile system transporting crude oil across Texas and New Mexico; the
Northwest System, a 672-mile system transporting crude oil across Texas and Oklahoma; and the
Cushing Tank Farm, an 80-tank facility in Oklahoma.1 BP Pipelines transports over 450 million
barrel miles of oil, refined products, natural gas liquids, carbon dioxide and chemicals daily
throughout the United States.
2
As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to
Respondent, by letter dated February 13, 2007, a Notice of Probable Violation, Proposed Civil
Penalty, and Proposed Compliance Order (Notice). In accordance with 49 C.F.R. § 190.207, the
Notice proposed finding that BP Pipelines had committed certain violations of 49 C.F.R. Part
195 and proposed assessing a civil penalty of $168,000 for the alleged violations. The Notice
1 After the inspection, on February 17, 2006, BP Pipelines submitted a letter to PHMSA indicating that
ConocoPhillips had acquired BP Pipelines’ interest in the Seaway Products Pipeline JV, effective December 1,
2005. The Seaway Products Pipeline carries refined petroleum products from Pasadena, Texas, to Cushing,
Oklahoma. On June 19, 2007, BP Pipelines submitted a second letter to OPS, confirming that it had transferred the
West Texas/New Mexico/Cushing Pipeline system to Centurion Pipeline, L.P., a subsidiary of Occidental Petroleum
Corp. BP Pipelines retained ownership of the Cushing Terminal and Shinn Pence tank farm in Oklahoma. Mr. Bill
Von Drehle represented Centurion Pipeline at the July 23, 2007 hearing. Since the OPS inspection occurred prior to
these ownership changes, the findings of violation set forth below are directed to BP Pipelines, the operator of all the
facilities at the time of the inspection.
2 http://www.bppipelines.com/aboutus.html (last accessed December 2, 2009).



2
also proposed ordering Respondent to take certain measures to correct the alleged violations and
warned Respondent to address other probable violations or be subject to future enforcement
action.
BP Pipelines responded to the Notice by letter dated March 23, 2007 (Response). Respondent
contested the allegations, penalties, and proposed compliance order, and requested a hearing. A
hearing was subsequently held on July 23, 2007, in Houston, Texas, with an attorney from the
Office of Chief Counsel, PHMSA, presiding. BP Pipelines was represented by counsel at the
hearing. Respondent subsequently provided a post-hearing submission dated August 20, 2007
(Brief).
FINDINGS OF VIOLATION
The Notice alleged that Respondent violated 49 C.F.R. Part 195, as follows:
Item 2: The Notice alleged that Respondent violated 49 C.F.R. § 195.436, which states:
§ 195.436 Security of facilities.
Each operator shall provide protection for each pumping station
and breakout tank area and other exposed facility (such as scraper traps)
from vandalism and unauthorized entry.
OPS alleged in the Notice that Respondent violated 49 C.F.R. § 195.436 by failing to provide
protection for a number of pump stations, junctions, and scraper trap facilities from vandalism
and unauthorized entry. Specifically, the Notice alleged that Respondent failed to protect the
Monroe, Artesia, and Fullerton facilities, as follows:
Monroe - The Monroe pump station and breakout tank area allegedly were secured only
by cyclone fencing and with barbed wire around the top of the pump station. BP Pipelines used
three strands of barbed wire around the breakout tank area. As a result, vandals entered the tank
area, sprayed the tank and floating roof with graffiti, and smoked on top of the structure, leaving
cigarette butts on the roof. OPS attached pictures of the damage with the Violation Report.3
Artesia – BP Pipelines allegedly used only a four-foot-high hog fence and barbed wire to
secure the facility. The pump station faces a county road and was therefore readily accessible to
the public.
Fullerton–The Fullerton pump station and breakout tank area allegedly did not have any
fencing. A county road cuts through the facility, providing easy public access to the pump
station.
In its Response, BP Pipelines contended that its procedures and practices were consistent with
Part 195. However, at the hearing and in its submissions, the company agreed to survey its
facilities and provide additional security to prevent vandalism and unauthorized entry. OPS
3 Pipeline Safety Violation Report (Violation Report), (February 15, 2007) (on file with PHMSA).



3
confirms that BP Pipelines has now completed the survey and secured the stations identified in
the Notice. Such corrective action, however, does not negate the fact that Respondent failed to
secure these facilities from unauthorized entry as of the date of the inspection. Accordingly,
having reviewed the evidence in the record, I find that Respondent violated § 195.436 by failing
to provide protection for each pumping station and breakout tank from vandalism and
unauthorized entry.
Item 3: The Notice alleged that Respondent violated 49 C.F.R. § 195.573, which states:
§ 195.573 What must I do to monitor external corrosion control?
(a) Protected pipelines. You must do the following to determine
whether cathodic protection required by this subpart complies with
§ 195.571:
(1) Conduct tests on the protected pipeline at least once each
calendar year, but with intervals not exceeding 15 months. However, if
tests at those intervals are impractical for separately protected short
sections of bare or ineffectively coated pipelines, testing may be done at
least once every 3 calendar years, but with intervals not exceeding 39
months….
(d) Breakout tanks. You must inspect each cathodic protection
system used to control corrosion on the bottom of an aboveground
breakout tank to ensure that operation and maintenance of the system are
in accordance with API Recommended Practice 651. However, this
inspection is not required if you note in the corrosion control procedures
established under § 195.402(c)(3) why compliance with all or certain
operation and maintenance provisions of API Recommended Practice 651
is not necessary for the safety of the tank....
The Notice alleged that Respondent violated 49 C.F.R. § 195.573 by failing to conduct surveys
to determine whether BP Pipelines’ cathodic protection (CP) system complied with § 195.571.
Specifically, the Notice alleged that Respondent failed to account for voltage or “IR drop” in its
annual cathodic protection surveys and therefore the company could not determine if its cathodic
protection system complied with § 195.571.
4 Under § 195.571, operators are required to utilize
CP that meets “one or more of the applicable criteria and other considerations for cathodic
protection contained in paragraphs 6.2 and 6.3 of NACE Standard RP 0169…”. Operators may
use the -850 mV criterion for determining whether adequate levels of CP have been achieved.5
However, when using this factor, voltage drops other than across the structure-to-electrolyte
boundary must be considered.6
4 “IR drop” is the difference between the voltage at the top of the pipe and the voltage at the surface of the earth. An
operator must consider this drop for a valid interpretation of the standards set forth by NACE RPO169, paragraph
6.2.
5 NACE International, RP0169, Paragraph 6.2 (2002).
6 Id. at 6.2.2.1.1.



4
After reviewing and considering BP Pipelines’ annual CP surveys for calendar years 2003, 2004,
and 2005, and discussing them with company personnel, OPS alleged in the Notice that several
locations had “instant-off” potentials that did not meet the -850 mV criterion. The requirement
to conduct tests to determine whether the cathodic protection on the pipeline complies with
§ 195.571 was promulgated by final rule on December 27, 2001, effective January 28, 2002.7
However, according to OPS, BP Pipelines had still not incorporated IR drop into its surveys at
the time of the 2004 OPS inspection. As documented in the Violation Report, BP Pipelines’
corrosion engineer initially argued that the -850 mV criterion already factored in the IR drop.8
In addition to the surveys, OPS also alleged that BP Pipelines failed to demonstrate that the
breakout tanks at pumps stations and at the Cushing Tank Farm met the protection criteria of API
RP 651.9
In its submissions and at the hearing, Respondent argued that its prior external corrosion control
procedures and practices were in compliance with § 195.571 since the company used a
methodology of -850 mV in conjunction with sound engineering practices.
10 BP Pipelines
explained that the sound engineering practices it relied on included the historical performance of
the CP system. The company stated that there had been no DOT-reportable spills caused by
external corrosion on this line. Respondent also stated that interrupted surveys were not the only
acceptable method of considering IR drop. The company contended that it had modified its
procedures in 2004 to include consideration of IR drop in response to a Notice of Amendment
(NOA) issued by OPS.
argued that the allegation of violation should be withdrawn. Finally, Respondent stated that
pursuant to its revised procedures, the company ran a Close Interval Survey (CIS) within a year
of every in-line inspection. Since segments from this inspection were assessed by in-line
inspection in 2006, a CIS would be conducted during the 2007 calendar year. On the basis of
these procedures and actions, BP Pipelines argued that the probable violation, proposed civil
penalty, and compliance order all should be withdrawn.
11 Since these procedures had been approved by OPS, the company
7 Controlling Corrosion on Hazardous Liquid and Carbon Dioxide Pipelines, 66 Fed. Reg. 66999 (Dec. 27, 2001).
8 Pipeline Safety Violation Report (Violation Report), (February 15, 2007) (on file with PHMSA).
9 Notice, at 2-3. Violation Report, at 8.
10 Operators using the -850 mV criterion must consider voltage drop. “Consideration” is further defined as “the
application of sound engineering practice…such as measuring or calculating the voltage drop; reviewing the
historical performance of the cathodic protection system; evaluating the physical and electrical characteristics of the
pipe and its environment; and determining whether or not there is physical evidence of corrosion. NACE Standard
RP0169, Paragraph 6.2.2.1.1.1 (2002).
11 In the Matter of BP Pipeline Company, Final Order, CPF No. 3-2004-5021M)(available at
www.phmsa.dot.gov/pipeline/enforcement). In response to this Notice of Amendment, BP Pipelines submitted
revised procedures on December 16, 2004, June 10, 2005, January 31, 2006, and March 10, 2006. The NOA alleged
that Respondent’s procedures included several “inadequacies”, including §§ 195.571 and 195.573. Upon review of
the company’s revised procedures, the Director stated that the inadequacies had been resolved and closed the case.



5
At the hearing, OPS clarified that the NOA issued to BP Pipelines on August 12, 2004, served as
a notification that OPS considered the company’s procedures inadequate. In fact, OPS stated in
the NOA that “BP Pipelines’ procedures fail[ed] to address identifying circumstances in which a
close-interval survey would apply” and that “BP Pipelines’ procedures fail[ed] to consider IR
drop when utilizing the -850 mVcriteria, as required by NACE RP 0169-96.”12 According to
OPS, BP Pipelines corrected its procedures after receipt of the NOA but did not put the new
procedures into practice. The OPS inspector stated in the Violation Report that it was evident at
the time of the inspection that BP Pipelines was just beginning to conduct interrupted surveys
no indication that Respondent considered voltage drop during its annual CP surveys prior to the
inspection, thereby prompting issuance of the Notice.
and close-interval surveys in conjunction with its Integrity Management Program.13 OPS found
I have reviewed the evidence and the arguments set forth by OPS and BP Pipelines. I find OPS’
argument persuasive in that the 2004 NOA pertained to the operator’s procedures, whereas the
Notice involved the operator’s practices. In 2004, BP Pipelines updated its procedures in
response to the NOA but failed to demonstrate that it had actually incorporated voltage drop in
its CP surveys as of the date of the inspection. Further, I do not find merit in Respondent’s
argument that leak history and a proposed CIS constitute compliance with § 195.571. I note that
the NACE Standard RP 0619, Paragraph 6.1.5, specifically states that corrosion leak history is
not sufficient by itself to determine whether adequate CP levels have been achieved.14 In
addition, BP Pipelines was in violation of this regulation prior to the submission of its revised
procedures in 2004 since consideration of IR drop became a requirement of the code as of
violated 49 C.F.R. § 195.573(a)(1) and (d) by failing to conduct CP surveys to ensure its
January 2002. 15 Therefore, based upon all of the evidence in the record, I find that Respondent
cathodic protection system complied with 49 C.F.R. § 195.571.
Item 4: 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….
OPS alleged in the Notice that Respondent violated 49 C.F.R. § 195.579 by failing to investigate
the corrosive effect of its products being transported. Specifically, the Notice and Violation
Report alleged that Respondent failed to perform inspections on dead legs, low points, facility
and non-piggable pipe, and in areas downstream of supplier taps. OPS alleged that these areas
had the potential to collect water that would corrode the pipeline but that Respondent failed to
monitor them for internal corrosion. OPS further alleged that Respondent had been unable to
12 Id. at 3.
13 Violation Report, at 9.
14 NACE International, RP0169, paragraph 6.1.5 (2002).
15 66 Fed. Reg. at 66999.



6
present evidence that it was meeting the requirements of the regulation, other than pointing to a
few internal coupons that had been inappropriately located on the pipeline.
In its Response and at the hearing, BP Pipelines contended that it had examined the facilities
included in the OPS inspection for internal corrosion. As evidence of its investigation
techniques, the company stated that its In-Line Inspection (ILI) results demonstrated the non-
corrosive nature of its crude oil and that the company had not experienced internal corrosion on
these lines. In addition, the company indicated that it had instituted a Facility Integrity
Management Program (FIMP) in 2005 that focused on internal corrosion. Prior to commencing
the program, BP Pipelines had replaced sections of pipe, eliminating dead legs and low-flow
piping. Finally, after the OPS inspection, Respondent performed a sample analysis of the crude
oil transported in its systems, which confirmed its non-corrosive nature.
I have reviewed the record and find that BP Pipelines violated § 195.579. Crude oil can be
corrosive if it contains water or other electrolytes. BP Pipelines was using internal coupons on
this line, demonstrating that the company itself recognized the potential corrosivity of the
products being transported. Under the regulation, BP Pipelines had an obligation to investigate
the corrosive effect of the product being transported and to take “adequate steps” to mitigate
internal corrosion. At the time of the inspection, Respondent failed to meet these affirmative
obligations.
The fact that this line had not had a history of internal corrosion spills is not persuasive.
Although BP Pipelines had not experienced a spill caused by internal corrosion, this fact alone
did not eliminate the possibility of a future incident, nor did it eliminate BP Pipelines’
responsibility to investigate the corrosive nature of its products. Although ILI results are
excellent corrosion indicators for piggable lines, additional preventive and mitigating measures
were necessary. Respondent should have identified the factors that could influence the formation
of internal corrosion, focusing on alignment changes such as dead legs and low points where
water could settle and lead to internal corrosion. Respondent also should have engaged in more
sampling activities. A periodic sampling of product only tests for corrosivity at specific times
and does not reflect a continuous sample of the product.
Finally, in its Response, BP Pipelines pointed to its FIMP program. However, this program was
instituted in 2005, after the OPS inspection had raised the alleged violation. Although the FIMP
program should benefit Respondent’s facilities by removing internal corrosion that has occurred,
Respondent was required to take other steps to effectively investigate and monitor the corrosive
nature of its product. Accordingly, having reviewed the evidence in the record, I find that BP
Pipelines violated § 195.579 by failing to investigate the corrosive effect of its product on the
pipeline and take adequate steps to mitigate internal corrosion.
Item 6: The Notice alleged that Respondent violated 49 C.F.R. § 195.432(b) and (d), which
states:



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§ 195.432 Inspection of in-service breakout tanks.
(a) Except for breakout tanks inspected under paragraphs (b) and
(c) of this section, each operator shall, at intervals not exceeding 15
months, but at least once each calendar year, inspect each in-service
breakout tank.
(b) Each operator shall inspect the physical integrity of in-service
atmospheric and low-pressure steel aboveground breakout tanks according
to section 4 of API Standard 653. However, if structural conditions
prevent access to the tank bottom, the bottom integrity may be assessed
according to a plan included in the operations and maintenance manual
under § 195.402(c)(3).
(c) Each operator shall inspect the physical integrity of in-service
steel aboveground breakout tanks built to API Standard 2510 according to
section 6 of API 510.
(d) The intervals of inspection specified by documents referenced
in paragraphs (b) and (c) of this section begin on May 3, 1999, or on the
operator’s last recorded date of the inspection, whichever is earlier.
The Notice alleged that BP Pipelines violated § 195.432(b) and (d) by failing to inspect its in-
service breakout tanks at pump stations and at the Cushing Tank Farm in compliance with
Section 4 of API 653, as incorporated by reference in the pipeline safety regulations. Pursuant to
API 653, operators must perform routine visual inspections of in-service breakout tanks, at
intervals not exceeding one month, and document certain areas of non-compliance for follow-up
action.16 Both OPS and the Respondent agree that BP Pipelines conducted the required
inspections. However, OPS alleged in the Notice and Violation Report that the company failed
to document and correct certain areas of non-compliance, as prescribed by API 653.
Specifically, the inspector noted broken and spalling concrete ring walls, cavities under tanks
made by animals and washouts, settlement around tank perimeters, exterior paint failure and
corrosion, lack of sealant between tank bottom and concrete ringwall, rivet/seam leakage, flange
that it was impossible to determine from Respondent’s records whether these issues were
leaks and leaks around flange bolts, and signs of leakage at mixers.17 In the Notice, OPS alleged
documented and resolved. OPS maintained that these items should have been documented
during monthly inspections and corrected before the next inspection.
In response, BP Pipelines asserted that it had inspected its breakout tanks as required by API
653. As part of its Response, BP Pipelines submitted follow-
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