BP WEST COAST PRODUCTS L.L.C. — Notice of Probable Violation

party submissionOfficial PDF220085007_operator response to notice_07222008.pdf#

220085007_Final Order_10062010_text.pdf, page 1Official PDFOCT 6 2010 Mr. Steve Pankhurst President BP Pipelines (North America), Inc. 28100 Torch Parkway Warrenville, IL 60555 Re: CPF No. 2-2008-5007 Dear Mr. Pankhurst: Enclosed please find the Final Order issued in the above-referenced case. It makes findings of violation and specifies actions that need to be taken by BP Pipelines (North America), Inc., to comply with the pipeline safety regulations. When the terms of the compliance order have been completed, as determined by the Director, Southern 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. Wayne Lemoi, Director, Southern Region, PHMSA Mr. David O. Barnes, Manager DOT & Integrity, BP Pipelines (North America), Inc. CERTIFIED MAIL – RETURN RECEIPT REQUESTED [7005 1160 0001 0039 0812]#

220085007_Final Order_10062010_text.pdf, page 2U.S. DEPARTMENT OF TRANSPORTATION PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION OFFICE OF PIPELINE SAFETY WASHINGTON, D.C. 20590 ____________________________________ In the Matter of ) BP Pipelines (North America), Inc., ) CPF No. 2-2008-5007 ) ) ) Respondent. ) ____________________________________) FINAL ORDER On October 9-12 and 22-24, 2007, pursuant to 49 U.S.C. § 60117, a representative 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. (BPNA or Respondent), in Warrenville, Illinois. BPNA operates approximately 654 miles of natural gas transmission pipelines in the United States, along with other gas and hazardous liquid pipelines. As a result of the inspection, the Director, Southern Region, OPS (Director), issued to Respondent, by letter dated June 19, 2008, a Notice of Probable Violation and Proposed Compliance Order (Notice). In accordance with 49 C.F.R. § 190.207, the Notice proposed finding that BPNA had committed various violations of 49 C.F.R. Part 192 and proposed ordering Respondent to take certain measures to correct the alleged violations. Respondent responded to the Notice by letter dated July 22, 2008 (Response). BPNA contested several of the allegations and requested a hearing. An informal hearing was subsequently held via teleconference on February 4, 2009, with Larry White, Attorney, PHMSA Office of Chief Counsel, presiding. At the hearing, Respondent was represented by counsel. After the hearing, Respondent provided additional written material for the record, by letter dated March 5, 2009. FINDING OF VIOLATION The Notice alleged that Respondent violated 49 C.F.R. Part 192, as follows: Item 7: The Notice alleged that Respondent violated 49 C.F.R. § 192.917(c), which states in relevant part:#

220085007_Final Order_10062010_text.pdf, page 32 § 192.917 – How does an operator identify potential threats to pipeline integrity and use the threat identification in its integrity program? (a) …. (c) Risk assessment. An operator must conduct a risk assessment that follows ASME/ANSI B31.8S, section 5, and considers the identified threats for each covered segment. An operator must use the risk assessment to prioritize the covered segments for the baseline and continual reassessments (§§192.919, 192.921, 192.937), and to determine what additional preventive and mitigative measures are needed (§192.935) for the covered segment. The Notice alleged that Respondent violated 49 C.F.R. § 192.917(c) by failing to have a risk model for conducting its risk assessments that enabled Respondent to determine the need for additional preventive and mitigative measures to minimize failure consequences for covered segments. More specifically, Respondent’s risk model and assessment process failed to describe how the risk assessment addressed the following: • Assessment of the benefits derived from mitigating actions. • Determination of the most effective mitigation measures for identified threats. • Assessment of the integrity impact from modified inspection intervals. • Assessment of the use of or need for alternative inspection methodologies. • More effective resource allocation. • Facilitation of decisions to address risks along a pipeline or within a facility. In its Response and during the hearing, BPNA stated that it used a relativistic risk model and that its subject matter experts considered conditional threats and non-conditional threats in performing its segment risk ranking. Respondent also noted that PHMSA did not conclude that its risk ranking results reflected an improper ranking of its covered segments. In its March 5, 2009 correspondence, Respondent offered further description of the threats it had identified and stated that the nature of these threats and the condition of its pipelines gave it reason to believe that further consideration of consequences was unnecessary. We acknowledge that Respondent’s risk model included threat identification. A determination of the need for additional preventive and mitigative measures for covered segments, however, is an express requirement of the cited regulation. Respondent did not produce any documentation showing that the risk modeling process it had in place during the relevant period included a means of determining the need for additional preventive and mitigative measures to minimize failure consequences and accomplish the purpose of the regulation. Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R. § 192.917(c) by failing to have a risk model for conducting its risk assessments that enabled the company to determine the need for additional preventive and mitigative measures to minimize failure consequences for covered segments. This finding of violation will be considered a prior offense in any subsequent enforcement action taken against Respondent.#

220085007_Final Order_10062010_text.pdf, page 43 COMPLIANCE ORDER The Notice proposed a compliance order with respect to Item 7 in the Notice for violation of 49 C.F.R. § 192.917(c). Under 49 U.S.C. § 60118(a), each person who engages in the transportation of gas or who owns or operates a pipeline facility is required to comply with the applicable safety standards established under chapter 601. 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 actions to ensure compliance with the pipeline safety regulations applicable to its operations: With respect to the violation of § 192.917(c) (Item 7), within 30 days following receipt of this order: a. Provide the Director with complete written procedures for conducting a risk assessment (likelihood and consequences) for all covered gas pipeline segments that follows ASME/ANSI B31.8S, section 5, considers the identified threats for each covered segment, and uses all available risk information; b. Provide the Director with a timeline for application of these procedures and completion of the risk assessment on all covered gas pipeline segments included in BPNA’s integrity management program. c. Maintain documentation of the safety improvement costs associated with fulfilling this Compliance Order and submit the total to the Director. Costs shall be reported in two categories: (1) total cost associated with preparation/revision of plans, procedures, studies and analyses; and (2) total cost associated with replacements, additions, and other changes to pipeline infrastructure. 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 the administrative assessment of civil penalties not to exceed $100,000 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. WARNING ITEMS With respect to Items 1, 2, 3, 4, 5, 6, 8, and 9, the Notice alleged probable violations of Part 192 but did not propose a civil penalty or compliance order for these items. Therefore, these are considered to be warning items. The warnings were for: 49 C.F.R. § 192.905(a) (Item 1) ─ Respondent’s alleged failure to identify all high consequence areas (HCAs) using appropriate methods; 49 C.F.R. § 192.905(c) (Item 2) ─ Respondent’s alleged failure to have a documented process for annual or more frequent identification of newly identified High Consequence Areas;#

220085007_Final Order_10062010_text.pdf, page 54 49 C.F.R. § 192.907(a) (Item 3) ─ Respondent’s alleged failure to follow its segment identification process for two offshore risers; 49 C.F.R. § 192.921(a) (Item 4) ─ Respondent’s alleged failure to incorporate all assessment specifications and methods best suited to address the identified threats; 49 C.F.R. § 192.917(e) (Item 5) ─ Respondent’s alleged failure to use threat identification information to monitor and address seam integrity risks on low frequency electric-resistance welded pipe; 49 C.F.R. § 192.917(b) (Item 6) ─ Respondent’s alleged failure to have a documented process for gathering and integrating available pipeline data to support threat analysis and risk determination; 49 C.F.R. § 192.933(d) (Item 8) ─ Respondent’s alleged failure to omit pressure reduction from the allowable actions to be taken when an immediate repair condition is identified on a gas pipeline operating at or below 30% SMYS; 49 C.F.R. § 192.945(a) (Item 9) ─ Respondent’s alleged failure to use specified metrics to evaluate the effectiveness of its integrity management program on a semi-annual basis. BPNA presented information in its Response showing that it had taken certain actions to address the cited items. Accordingly, having considered such information, I find, pursuant to 49 C.F.R. § 190.205, that probable violations of 49 C.F.R. §§ 192.905(a), 192.905(c), 192.907(a), 192.921(a), 192.917(e), 192.917(b), 192.933(d), and 192.945(a) have occurred as described above and Respondent is hereby advised to correct such conditions. In the event that OPS finds a violation of any of these items in a subsequent inspection, Respondent may be subject to future enforcement action. Under 49 C.F.R. § 190.215, Respondent has a right to submit a petition for reconsideration of this Final Order. Should Respondent elect to do so, 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 the Respondent, provided they contain a brief statement of the issue(s) and meet all other requirements of 49 C.F.R. § 190.215. Unless the Associate Administrator, upon request, grants a stay, the 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#

220085007_closure letter_11262010_text.pdf, page 1Official PDFNovember 26, 2010 Mr. Steve Pankhurst President BP Pipelines (North America), Inc. 28100 Torch Parkway Warrenville, IL 60555 CPF 2-2008-5007 Dear Mr. Pankhurst: On October 9-12, and October 22-24, 2007, a team of representatives from the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety conducted an inspection of the BP Pipelines (North America), Inc. (BPNA) gas integrity management program (IMP) in Warrenville, Illinois, pursuant to Chapter 601 of 49 United States Code. As a result of the inspections, PHMSA issued a Final Order on October 6, 2010. The Final Order included a Compliance Order (CO), which required BPNA to take certain actions to protect the public and the environment. The PHMSA Southern Region has reviewed your November 12, 2010, written response to the CO. We find that you have met the requirements specified in the CO. No further action is necessary with regards to the Final Order and this case is now closed. Please be advised that nothing herein states or implies that the above described gas integrity management program meets the requirements of the federal pipeline safety regulations or that the program is approved. The pipeline system and IMP remain subject to inspection by PHMSA. Sincerely, Wayne T. Lemoi Director, Office of Pipeline Safety PHMSA Southern Region#

220085007_nopv pco letter_06192008_text.pdf, page 1Official PDFU. S. Department of Transportation Pipeline and Hazardous Materials Safety Administration 233 Peacntree Street Ste. 600 Atlanta, GA 30303 NOTICE OF PROBABLE VIOLATION and PROPOSED COMPLIANCE ORDER CERTIFIED MAIL - RETURN RECEIPT RE UESTED June 19, 2008 Mr. Jim Lamanna President BP Pipelines P1orth America), Inc. 28100 Torch Parkway Warrenville, IL 60555 CPF 2-2008-5007 Dear Mr. Lamanna: On October 9-12 and 22-24, 2007, representatives of the Pipeline and Hazardous Materials Safety Administration (PHMSA) pursuant to Chapter 601 of 49 United States Code inspected your BP Pipelines (North America), Inc. procedures for Integrity Management in Warrenville, Illinois. 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 violation(s) are: tt192. 905 How does an operator identify a high consequence area? (a) General. To determine which segments of an operator's transmission pipeline system are covered by Subpart 0, an operator must identify the high consequence areas. An operator must use method (1) or (2) from the definition in tt192. 903 to identify a high consequence area. 1) The BP IMP does not account for inaccuracies in the HCA mapping process when identifying HCAs and HCA segment length. No buffer is applied to the Potential Impact Radius (PIR) and inaccuracies were stated to be as high as +/-50 to 100 It. in measurements obtained from aerial photography. Onshore pipelines, excluding LA Basin (Line 211) and HCL (Line 893) (both 100% HCA) will need to be reanalyzed to incorporate the stated accuracy.#

220085007_nopv pco letter_06192008_text.pdf, page 22) The initial effort to identify HCAs by 12/I'7/04 did not accurately account for identified sites in the HCA segment identification process. Identified sites were designated by points on structures and HCA segment were established based on point location rather than a PIC sliding along the pipeline for the length of the structure at its closest points of impact. The current practice requires ail identified sites to be digitized as polygons. 2. t)192. 905 How does an operator identify a high consequence area? (c) Newly identified areas. When an operator has information that the area around a pipeline segment not previously identified as a high consequence area could satisfy any of the definitions in t)192. 903, the operator must complete the evaluation using method (1) or (2). The BP IMP does not provide a documented process for how new information is identified and integrated with the integrity management program. Further, the IMP states that HCA updates are to occur on a 3-year basis rather than on an annual or more frequent basis. Changes were made to the BP IMP between weeks 1 and 2 of the inspection to address this issue. 3. II192. 907 What must an operator do to implement this subpart? (a) General. No later than December 17, 2004, an operator of a covered pipeline segment must and follow a written integrity management program that contains all the elements described in II192. 911 and that addresses the risks on each covered transmission pipeline segment. The initial HCA segment identification process did not include the risers offshore that could affect the platforms, Okeanos (Nakika) and Cleopatra (Mad Dog), which are identified sites in the Mardi Gras System not identified by 12/17/04. Records indicated that one segment operated on 11/30/03 and the other segment on 02/25/05. 5192. 921 How is the baseline assessment to be conducted? (a) Assessment methods. An operator must assess the integrity of the line pipe in each covered segment by applying one or more of the following methods depending on the threats to which the covered segment is susceptible. An operator must select the method or methods best suited to address the threats identified to the covered segment (See 11192. 917). The BP IMP does not make appropriate use of references to other documents which implement IMP activities. Examples include:#

220085007_nopv pco letter_06192008_text.pdf, page 3~ Specification BPPL-STP 32-210 provides requirements for ensuring the reliability of ILI assessments, but this specification is not clearly referenced in context by the IMP. ~ The procedure that controls hydro-testing to ensure Subpart I requirements are met is not referenced by the IMP. Changes were made to the BP IMP between weeks 1 and 2 of the inspection to address these issues. I'1192. 917 How does an operator identify potential threats to pipeline integrity and use the threat identification in its integrity program? (e) Actions io address particular threats. If an operator identifies any of the following threats, the operator must take the following actions to address the threat. (4) ER W pipe. If a covered pipeline segment contains low frequency electric resistance welded pipe (ERW), lap welded pipe or other pipe that satisfies the conditions specified in ASME/ANSI B31. S, Appendices A4. 3 and A4. 4, and any covered or noncovered segment in the pipeline system with such pipe has experienced seam failure, or operating pressure on the covered segment has increased over the maximum operating pressure experienced during the preceding five years, an operator must select an assessment technology or technologies with a proven application capable of assessing seam integrity and seam corrosion anomalies. The BP IMP contains no provisions to monitor operating pressures experienced over the preceding 5-year period to ensure that seam conditions on LF ERW piping do not become unstable. 11192. 917 How does an operator identify potential threats to pipeline integrity and use the threat identification in its integrity program? (b) Data gathering and integration. To identify and evaluate the potential threats to a covered pipeline segment, an operator must gather and integrate existing data and information on the entire pipeline that could be relevant to the covered segment. In performing this data gathering and integration, an operator must follow the requirements in ASME/ANSI B31. 8S, section 4. The BP IMP includes no documented plan or process for the gathering and integration of data to support threat analysis and risk determination. Data sources aud data elements in accordance with B31. 8S Tables 1 aud 2 are not identified. No provisions exist for treatment of missing or suspect data. No procedures are provided which ensure timely treatment of new data. No procedures exist to define the process for spatial integration of data or to demonstrate integration of ILI results with encroachments or foreign line crosslligs.#

220085007_nopv pco letter_06192008_text.pdf, page 47. $192. 917 How does an operator identify potential threats to pipeline integrity and use the threat identification in its integrity program? (c) Risk assessment. An operator must conduct a risk assessment that follows ASME/ANSI B31. 8S, section 5, and considers the identified threats for each covered segment. An operator must use the risk assessment to prioritize the covered segments for the baseline and continual reassessments (@192. 919, 192. 921, 192. 937), and to determine what additional preventive and mitigative measures are needed (t)192. 935) for the covered segment. There has been no development of a risk model as part of the BP IMP. Threats have been analyzed using a relativistic model and the model developed for liquid lines is stated to be similar to that which will be developed for gas lines over the next two years, but there has been no determination of risk (likelihood and consequences) for gas lines. Accordingly, there are no program procedures that describe the use of risk information as part of the Gas IMP. The BP IMP does not address pipeline risk in a manner that enables: ~ Assessment of the benefits derived from mitigating actions: ~ Determination of the most effective mitigation measures for identified threats; ~ Assessment of the integrity impact from modified inspection intervals; ~ Assessment of the use of or need for alternative inspection methodologies; ~ More effective resource allocation; ~ Facilitation of decisions to address risks along a pipeline or within a facility. No program documentation exists to describe how these objectives are met using risk determination. Further, no risk information exists to ensure appropriate ranking for conducting the BAP. (j192. 933 What actions must be taken to address integrity issues? (d) Special requirements for scheduling remediation. -(1) Immediate repair conditions. An operator's evaluation and remediation schedule must follow ASME/ANSI B31. 8S, section 7 in providing for immediate repair conditions. To maintain safety, an operator must temporarily reduce operating pressure in accordance with paragraph (a) of this section or shut down the pipeline until the operator completes the repair of these conditions.#

220085007_nopv pco letter_06192008_text.pdf, page 5The BP IMP states reduce pressure, shut down the line, or notify PHMSA if it discovers an immediate condition. If BP has a line operating at or below 30% SMYS they may simply notify PHMSA of the condition, rather than reduce pressure. There is no direction to immediately take a pressure reduction. BP stated that this is done at the 40% level on the liquid side, but changed to 30% to coincide with the gas Rule. This approach will be discussed internally with PHMSA management to determine if it meets the Rule intent. BP has not discovered any immediate condition in a HCA segment of its gas pipelines at this time. tj192. 945 What methods must an operator use to measure program effectiveness? (a) General. An operator must include in its integrity management program methods to measure, on a semi-annual basis, whether the program is effective in assessing and evaluating the integrity of each covered pipeline segment and in protecting the high consequence areas. Section I of the BP IMP addresses the need to track threat specific metrics on a semi- annual basis. There is no documentation to demonstrate that these metrics are taken. Changes were made to the IMP between weeks I and 2 of the inspection to correct this issue. Pro osed Com liance Order Pursuant to 49 United States Code $ 60118, the Pipeline and Hazardous Materials Safety Administration proposes to issue a Compliance Order to BP Pipelines (North America), Inc. Please refer to the Proposed Compliance Order that is enclosed and made a part of this Notice. ~Wlt With respect to item(s): I, 2, 3, 4, 5, 6, 8 and 9, 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 Pipelines (North America), Inc. being subject to additional enforcement action. Res onse to 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. 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#

220085007_nopv pco letter_06192008_text.pdf, page 6of 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 2-2008-5007 and for each document you submit, please provide a copy in electronic format whenever possible. Sincerely, Linda Daugherty Director, Southern Pipeline and Hazardous Materials Safety Administration Enclosures: Proposed Compliance Order Response Options for Pipeline Operators in Compliance Proceedings#

220085007_nopv pco letter_06192008_text.pdf, page 7PROPOSED COMPLIANCE ORDER Pursuant to 49 United States Code ) 60118, the Pipeline and Hazardous Materials Safety Administration (PHMSA) proposes to issue to BP Pipelines (North America), Inc. a Compliance Order incorporating the following remedial requirements to ensure the compliance of BP Pipelines (North America), Inc. with the pipeline safety regulations: In regard to Item Number 7 of the Notice pertaining to Risk Assessment, BP NA must conduct a risk assessment that follows ASME/ANSI B31. 8S, section 5, and considers the identified threats for each covered segment. Threats have been analyzed using a relativistic model and the model developed for liquid lines is stated to be similar to that which will be developed for gas lines over the next two years. BP NA must determine the risk (likelihood and consequences) for the gas lines and provide program procedures that describe the use of risk information as part of the Gas IMP. 2. BP NA must provide a timeline to PHMSA detailing the application of the Risk Assessment process to those pipeline segments included in BP NA's IMP. This is to be accomplished within 30 days following receipt of the Final Order. BP NA shall maintain documentation of the safety improvement costs associated with fulfilling this Compliance Order and submit the total to Linda Daugherty, Director, Southern Region, Pipeline and Hazardous Materials Safety Administration. Costs shall be reported in two categories: I) total cost associated with preparation/revision of plans, procedures, studies and analyses, and 2) total cost associated with replacements, additions and other changes to pipeline infrastructure.#