# ANADARKO E & P COMPANY LP — Notice of Amendment

- **operation:** document
- **citation:** CPF 520095006M
- **title:** ANADARKO E & P COMPANY LP — Notice of Amendment
- **source type:** enforcement
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2009-02-19
- **effective on:** Not available
- **summary:** CLOSED notice of amendment citing 195.452(e)(1), 195.452(f)(5), 195.452(f)(6), 195.452(f)(7), 195.452(f)(8), 195.452(i)(2).
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- **source url:** https://primis.phmsa.dot.gov/enforcement-data/case/520095006M
**body:**

Notice of Amendment involving ANADARKO E & P COMPANY LP. PHMSA's enforcement data identifies the cited regulations as 195.452(e)(1),  195.452(f)(5),  195.452(f)(6),  195.452(f)(7),  195.452(f)(8),  195.452(i)(2). The case was opened on 2009-02-19 and is reported as closed as of 2009-04-14. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

520095006M_notice of amendment_02192009.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520095006M/520095006M_notice%20of%20amendment_02192009.pdf

520095006M_notice of amendment_02192009_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520095006M/520095006M_notice%20of%20amendment_02192009_text.pdf

520095006M_operator response_03162009.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520095006M/520095006M_operator%20response_03162009.pdf

520095006M_notice of amendment_02192009_text.pdf

NOTICE OF AMENDMENT
CERTIFIED MAIL - RETURN RECEIPT REQUESTED
February 19, 2009
Mr. Dan Rea
Sr. Vice President of Midstream
Anadarko Petroleum Corporation
1201 Lake Robbins Drive
Woodlands, TX 77380
CPF 5-2009-5006M
Dear Mr. Rea:
On September 24, 2008, a representative of the Pipeline and Hazardous Materials Safety
Administration (PHMSA), pursuant to Chapter 601 of 49 United States Code, inspected the
Anadarko Petroleum Corporation’s (APC) procedures for their Integrity Management Program
(IMP) in Green River, Wyoming.
On the basis of the inspection, PHMSA has identified the apparent inadequacies found within
APC’s plans or procedures, as described below:
1. §195.452 Pipeline integrity management in high consequence areas.
(f) What are the elements of an integrity management program? An integrity
management program begins with the initial framework. An operator must
continually change the program to reflect operating experience, conclusions
drawn from results of the integrity assessments, and other maintenance and
surveillance data, and evaluation of consequences of a failure on the high



consequence area. An operator must include, at minimum, each of the following
elements in its written integrity management program:
(8) A process for review of integrity assessment results and information analysis
by a person qualified to evaluate the results and information (see paragraph (h)
(2) of this section).
The APC procedures are inadequate for ensuring the qualification of their integrity
management (IM) reviewer and/or evaluator. The procedures do not specify the level
of qualifications the IM reviewer and/or evaluator must have to adequately review and
analyze the assessment results, e.g. in-house IM team and hydrotest engineer.
2. §195.452 Pipeline integrity management in high consequence areas.
(e) What are the risk factors for establishing an assessment schedule (for both the
baseline and continual integrity assessments)?
(1) An operator must establish an integrity assessment schedule that prioritizes
pipeline segments for assessment (see paragraphs (d) (1) and (j) (3) of this
section). An operator must base the assessment schedule on all risk factors that
reflect the risk conditions on the pipeline segment. The factors an operator must
consider include, but are not limited to:
(i) Results of the previous integrity assessment, defect type and size that the
assessment method can detect, and defect growth rate;
(ii) Pipe size, material, manufacturing information, coating type and condition,
and seam type;
(iii) Leak history, repair history and cathodic protection history;
(iv) Product transported;
(v) Operating stress level;
(vi) Existing or projected activities in the area;
(vii) Local environmental factors that could affect the pipeline (e.g., corrosivity of
soil, subsidence, climatic);
(viii) geo-technical hazards; and
(ix) Physical support of the segment such as by a cable suspension bridge.
(2) Appendix C of this part provides further guidance on risk factors.
The APC has a risk based analysis process from an original framework of their IM
program that was used in a Subject Matter Expert (SME) setting. The APC procedures
are inadequate to ensure a more comprehensive and robust risk model that consider all
required risk factors on their pipeline, e.g. data driven risk model.
3. §195.452 Pipeline integrity management in high consequence areas.
(f) What are the elements of an integrity management program? An integrity
management program begins with the initial framework. An operator must
continually change the program to reflect operating experience, conclusions
drawn from results of the integrity assessments, and other maintenance and
surveillance data, and evaluation of consequences of a failure on the high
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consequence area. An operator must include, at minimum, each of the following
elements in its written integrity management program:
(6) Identification of preventive and mitigative measures to protect the high
consequence area (see paragraph (i) of this section);
(i) What preventive and mitigative measures must an operator take to protect the
high consequence area?
(1) An operator must take prompt action to address all anomalous conditions the
operator discovers through the integrity assessment or information analysis. In
addressing all conditions, an operator must evaluate all anomalous conditions and
remediate those that could reduce a pipeline's integrity. An operator must be able
to demonstrate that the remediation of the condition will ensure the condition is
unlikely to pose a threat to the long-term integrity of the pipeline. An operator
must comply with § 195.422 when making a repair.
(i) Temporary pressure reduction. An operator must notify PHMSA, in
accordance with paragraph (m) of this section, if the operator cannot meet the
schedule for evaluation and remediation required under paragraph (h)(3) of this
section and cannot provide safety through a temporary reduction in operating
pressure.
(ii) Long-term pressure reduction. When a pressure reduction exceeds 365 days,
the operator must notify PHMSA in accordance with paragraph (m) of this
section and explain the reasons for the delay. An operator must also take further
remedial action to ensure the safety of the pipeline.
(2) Risk analysis criteria. In identifying the need for additional preventive and
mitigative measures, an operator must evaluate the likelihood of a pipeline release
occurring and how a release could affect the high consequence area. This
determination must consider all relevant risk factors, including, but not limited
to:
(i) Terrain surrounding the pipeline segment, including drainage systems such as
small streams and other smaller waterways that could act as a conduit to the high
consequence area;
(ii) Elevation profile;
(iii) Characteristics of the product transported;
(iv) Amount of product that could be released;
(v) Possibility of a spillage in a farm field following the drain tile into a waterway;
(vi) Ditches along side a roadway the pipeline crosses;
(vii) Physical support of the pipeline segment such as by a cable suspension
bridge;
(viii) Exposure of the pipeline to operating pressure exceeding established
maximum operating pressure.
(3) Leak detection. An operator must have a means to detect leaks on its pipeline
system. An operator must evaluate the capability of its leak detection means and
modify, as necessary, to protect the high consequence area. An operator's
evaluation must, at least, consider, the following factors–length and size of the
pipeline, type of product carried, the pipeline's proximity to the high consequence
area, the swiftness of leak detection, location of nearest response personnel, leak
history, and risk assessment results.
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(4) Emergency Flow Restricting Devices (EFRD). If an operator determines that
an EFRD is needed on a pipeline segment to protect a high consequence area in
the event of a hazardous liquid pipeline release, an operator must install the
EFRD. In making this determination, an operator must, at least, consider the
following factors–the swiftness of leak detection and pipeline shutdown
capabilities, the type of commodity carried, the rate of potential leakage, the
volume that can be released, topography or pipeline profile, the potential for
ignition, proximity to power sources, location of nearest response personnel,
specific terrain between the pipeline segment and the high consequence area, and
benefits expected by reducing the spill size.
• Item 3: §195.452 (f)(6)
• Item 3A: §195.452 (i)(2)
The process description to identify additional preventive and mitigative actions did not
show how the IM projects are integrated into the risk model process. The APC
procedures are inadequate to ensure a more comprehensive and robust process to
identify additional preventive and mitigative measures (P&MM).
• Item 3B: §195.452 (i)(2)
The APC procedures are inadequate for defining and ranking P&MM for their pipeline
in the IM program. This is important to ensure future preventive and mitigative
decisions are made in a consistent and risk-based manner.
4. §195.452 Pipeline integrity management in high consequence areas.
(f) What are the elements of an integrity management program? An integrity
management program begins with the initial framework. An operator must
continually change the program to reflect operating experience, conclusions
drawn from results of the integrity assessments, and other maintenance and
surveillance data, and evaluation of consequences of a failure on the high
consequence area. An operator must include, at minimum, each of the following
elements in its written integrity management program:
(5) A continual process of assessment and evaluation to maintain a pipeline's
integrity (see paragraph (j) of this section);
(j) What is a continual process of evaluation and assessment to maintain a
pipeline's integrity?
(1) General. After completing the baseline integrity assessment, an operator must
continue to assess the line pipe at specified intervals and periodically evaluate the
integrity of each pipeline segment that could affect a high consequence area.
(2) Evaluation. An operator must conduct a periodic evaluation as frequently as
needed to assure pipeline integrity. An operator must base the frequency of
evaluation on risk factors specific to its pipeline, including the factors specified in
paragraph (e) of this section. The evaluation must consider the results of the
baseline and periodic integrity assessments, information analysis (paragraph (g)
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of this section), and decisions about remediation, and preventive and mitigative
actions (paragraphs (h) and (i) of this section).
(3) Assessment intervals. An operator must establish five-year intervals, not to
exceed 68 months, for continually assessing the line pipe's integrity. An operator
must base the assessment intervals on the risk the line pipe poses to the high
consequence area to determine the priority for assessing the pipeline segments. An
operator must establish the assessment intervals based on the factors specified in
paragraph (e) of this section, the analysis of the results from the last integrity
assessment, and the information analysis required by paragraph (g) of this
section.
(4) Variance from the 5-year intervals in limited situations-
(i) Engineering basis. An operator may be able to justify an engineering basis for
a longer assessment interval on a segment of line pipe. The justification must be
supported by a reliable engineering evaluation combined with the use of other
technology, such as external monitoring technology, that provides an
understanding of the condition of the line pipe equivalent to that which can be
obtained from the assessment methods allowed in paragraph (j)(5) of this section.
An operator must notify OPS 270 days before the end of the five-year (or less)
interval of the justification for a longer interval, and propose an alternative
interval. An operator must send the notice to the address specified in paragraph
(m) of this section.
(ii) Unavailable technology. An operator may require a longer assessment period
for a segment of line pipe (for example, because sophisticated internal inspection
technology is not available). An operator must justify the reasons why it cannot
comply with the required assessment period and must also demonstrate the
actions it is taking to evaluate the integrity of the pipeline segment in the interim.
An operator must notify OPS 180 days before the end of the five-year (or less)
interval that the operator may require a longer assessment interval, and provide
an estimate of when the assessment can be completed. An operator must send a
notice to the address specified in paragraph (m) of this section.
(5) Assessment methods. An operator must assess the integrity of the line pipe by
any of the following methods. The methods an operator selects to assess low
frequency electric resistance welded pipe or lap welded pipe susceptible to
longitudinal seam failure must be capable of assessing seam integrity and of
detecting corrosion and deformation anomalies.
(i) Internal inspection tool or tools capable of detecting corrosion and
deformation anomalies including dents, gouges and grooves;
(ii) Pressure test conducted in accordance with subpart E of this part;
(iii) External corrosion direct assessment in accordance with § 195.588; or
(iv) Other technology that the operator demonstrates can provide an equivalent
understanding of the condition of the line pipe. An operator choosing this option
must notify OPS 90 days before conducting the assessment, by sending a notice to
the address or facsimile number specified in paragraph (m) of this section.
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The APC procedures are inadequate for addressing the pipe condition and location-
specific integrity threats. The procedures do not specify what additional safety
measures and/or evaluation methods will be used to ensure the safety condition of their
pipeline.
5. §195.452 Pipeline integrity management in high consequence areas.
(f) What are the elements of an integrity management program? An integrity
management program begins with the initial framework. An operator must
continually change the program to reflect operating experience, conclusions
drawn from results of the integrity assessments, and other maintenance and
surveillance data, and evaluation of consequences of a failure on the high
consequence area. An operator must include, at minimum, each of the following
elements in its written integrity management program:
(7) Methods to measure the program's effectiveness (see paragraph (k) of this
section);
(k) What methods to measure program effectiveness must be used? An operator's
program must include methods to measure whether the program is effective in
assessing and evaluating the integrity of each pipeline segment and in protecting
the high consequence areas. See Appendix C of this part for guidance on methods
that can be used to evaluate a program's effectiveness.
The APC procedures do not specify the IM program evaluations as required by Part
195.452(f) (7) and the method to perform an effective evaluation of the IM program.
In addition, the procedures do not specify the collection of performance metric data at a
frequency that will provide timely evaluations of the IM program.
Response to this Notice
This Notice is provided pursuant to 49 U.S.C. § 60108(a) and 49 C.F.R. § 190.237. 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. Be
advised that all material you submit in response to this enforcement action is subject to being
made publicly available. If you believe that any portion of your responsive material qualifies
for confidential treatment under 5 U.S.C. 552(b), along with the complete original document
you must provide a second copy of the document with the portions you believe qualify for
confidential treatment redacted and an explanation of why you believe the redacted
information qualifies for confidential treatment under 5 U.S.C. 552(b). 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.
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If, after opportunity for a hearing, your plans or procedures are found inadequate as alleged in
this Notice, you may be ordered to amend your plans or procedures to correct the inadequacies
(49 C.F.R. § 190.237). If you are not contesting this Notice, we propose that you submit your
amended procedures to my office within 30 days of receipt of this Notice. This period may be
extended by written request for good cause. Once the inadequacies identified herein have been
addressed in your amended procedures, this enforcement action will be closed.
In correspondence concerning this matter, please refer to CPF 5-2009-5006M and, for each
document you submit, please provide a copy in electronic format whenever possible.
Sincerely,
Chris Hoidal
Director, Western Region
Pipeline and Hazardous Materials Safety Administration
cc: PHP-60 Compliance Registry
PHP-500 H. Nguyen (#122216)
Enclosure: Response Options for Pipeline Operators in Compliance Proceedings
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