{"operation":"document","citation":"CPF 420145011","title":"PHILLIPS 66 PIPELINE LLC — Notice of Probable Violation","source_type":"enforcement","agency":"Pipeline and Hazardous Materials Safety Administration","status":"historical","official":true,"published_on":"2014-05-13","effective_on":null,"summary":"CLOSED notice of probable violation citing 195.402(a), 195.432(b), 195.452(b), 195.452(b)(5), 195.452(f)(1), 195.452(h)(2), 195.505(a), 195.505(b).","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-enforcement-420145011.json","markdown":"https://regulus.evalyn.ai/document/phmsa-enforcement-420145011.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-enforcement-420145011","source_url":"https://primis.phmsa.dot.gov/enforcement-data/case/420145011","body":"Notice of Probable Violation involving PHILLIPS 66 PIPELINE LLC. PHMSA's enforcement data identifies the cited regulations as 195.402(a),  195.432(b),  195.452(b),  195.452(b)(5),  195.452(f)(1),  195.452(h)(2),  195.505(a),  195.505(b). The case was opened on 2014-05-13 and is reported as closed as of 2018-05-14. Proposed civil penalty: $175,300. Assessed civil penalty: $175,300. Open the official case record for notices, responses, orders, and the latest status.\n\nOfficial case documents:\n\n420145011_Closure Letter_05102018_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420145011/420145011_Closure%20Letter_05102018_text.pdf\n\n420145011_Closure Letter_05142018.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420145011/420145011_Closure%20Letter_05142018.pdf\n\n420145011_Final Order_09112015.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420145011/420145011_Final%20Order_09112015.pdf\n\n420145011_Final Order_09112015_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420145011/420145011_Final%20Order_09112015_text.pdf\n\n420145011_NOPV PCP PCO_05132014.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420145011/420145011_NOPV%20PCP%20PCO_05132014.pdf\n\n420145011_NOPV PCP PCO_05132014_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420145011/420145011_NOPV%20PCP%20PCO_05132014_text.pdf\n\n420145011_Operator Response to Notice_06132014.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420145011/420145011_Operator%20Response%20to%20Notice_06132014.pdf\n\n420145011_Closure Letter_05142018.pdf\n\nU.S. Department\n8701 S. Gessner, Suite 630\nof Transportation\nHouston, TX 77074\nPipeline and\nHazardous Materials Safety\nAdministration\nCERTIFIED MAIL - RETURN RECEIPT REQUESTED\nMay 14, 2018\nMr. Todd Denton\nPresident\nPhillips 66 Pipeline LLC\n1075 W Sam Houston Pkwy\nN. Suite 200 N812-03\nHouston, TX 77043\nCPF 4-2014-5011\nDear Mr. Denton:\nOn September 11, 2015, the Pipeline and Hazardous Materials Safety Administration (PHMSA)\nissued to Phillips 66 Pipeline LLC a Final Order in the above-referenced case. This Order included\na Compliance Order and Civil Penalty assessment. Based on our review of the documentation you\nprovided and confirmation of payment of the civil penalty, it has been determined that you have\ncomplied with the terms of this Order.\nmatters involved in this case. Thank you for your cooperation in this matter.\nAccordingly, this case is now closed and no further action is contemplated with respect to the\nSincerely,\nMary L. McDaniel, P.E\nDirector, Southwest Region\nOffice of Pipeline Satety\nPipeline and Hazardous Materials Safety Administration\n\n420145011_NOPV PCP PCO_05132014_text.pdf\n\nNOTICE OF PROBABLE VIOLATION\nPROPOSED CIVIL PENALTY\nand\nPROPOSED COMPLIANCE ORDER\nCERTIFIED MAIL - RETURN RECEIPT REQUESTED\nMay 13, 2014\nMr. Todd Denton\nPresident\nPhillips 66 Pipeline, LLC\n3010 Briarpark Drive\nHouston, TX 77042\nCPF 4-2014-5011\nDear Mr. Denton:\nOn multiple occasions between April and November 22, 2013, representatives of the Pipeline and\nHazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), pursuant to\nChapter 601 of 49 United States Code were onsite and inspected portions of Phillips 66 Pipeline LLC\n(Phillips) pipeline system located in Texas and Oklahoma.\nAs a result of the inspections, it appears that you have committed probable violations of the Pipeline\nSafety Regulations, Title 49, Code of Federal Regulations. The items inspected and the probable\nviolation(s) are:\n1. §195.402 Procedural manual for operations, maintenance, and emergencies.\n(a) General. Each operator shall prepare and follow for each pipeline system a manual of\nwritten procedures for conducting normal operations and maintenance activities and\nhandling abnormal operations and emergencies. This manual shall be reviewed at\nintervals not exceeding 15 months, but at least once each calendar year, and appropriate\nchanges made as necessary to insure that the manual is effective. This manual shall be\nprepared before initial operations of a pipeline system commence, and appropriate parts\nshall be kept at locations where operations and maintenance activities are conducted.\n\n\n\nPhillips did not follow their written atmospheric storage tank level alarm policy. P66PL-TPO-4001:\nAtmospheric Storage Tank Level Alarm Policy (Rev. 7 – Effective Date: 2012-07-09), Section 7 -\nInspection and Testing (Quarterly) states:\n“New systems are designed fail safe and alarm upon electrical failure. Steps should be taken\nto ensure existing systems perform in the same manner where possible. Level alarming\nsystems shall be visually inspected, have an electronic integrity test performed and be\nfunctionally tested each quarter. These functions shall include the following: Point-to-point\nverification will be completed for safety-related points by the field technician in contact\nwith the Controller for that pipeline as part of the repair or calibration using established\nmaintenance procedures. Document the name of the Controller on the form associated with\nthis procedure. The results of these point-to-point verifications will be retained in\naccordance with current practice for these calibrations.”\nWhile reviewing records associated with the overfill protection on Tanks 1201, 1202, 1501, 2101,\n2301, 2302, 2303, 2304 and 2305, PHMSA noted the tanks were last inspected on 7/25/2012 and\nagain on 1/29/2013. Phillips failed to provide documentation showing these devices were inspected\nduring the 4th quarter of 2012.\nPhillips, during their 1/29/2013 inspection, failed to document that the company conducted an alarm\ntest for tank 1202. Also, during the third and fourth quarters of 2012 and the first and second quarter of\n2013, P66PL failed to document the name of the controller on the level alarm inspection and testing\nreport required by their own procedure.\n2. §195.402 Procedural manual for operations, maintenance, and emergencies.\n(a) General. Each operator shall prepare and follow for each pipeline system a manual of\nwritten procedures for conducting normal operations and maintenance activities and\nhandling abnormal operations and emergencies. This manual shall be reviewed at\nintervals not exceeding 15 months, but at least once each calendar year, and appropriate\nchanges made as necessary to insure that the manual is effective. This manual shall be\nprepared before initial operations of a pipeline system commence, and appropriate parts\nshall be kept at locations where operations and maintenance activities are conducted.\nPhillips did not follow their written cathodic protection testing procedure. P66PL, MPR\n6018:Cathodic Protection Testing, Rev. 9 (Effective Date: 2012-03-27), section 7.3.4.1 states:\n“For the annual structure to soil survey, conduct a minimum of four (4) SSP readings at\nevenly spaced locations around the perimeter of each aboveground storage tank. The\nstructure-to-soil measurements shall be taken adjacent to the tank ringwall and the hook-up\nto the tank floor shall be on the chime weld extension, on a lug on the tank shell\nspecifically for SSP readings or on another readily accessible location on the tank.”\n2\n\n\n\nWhile reviewing Phillips’ 2011, 2012, and 2013 annual cathodic protection survey records associated\nwith the PHMSA jurisdictional breakout tanks # 201 and 202, PHMSA noted that the company\nconducted only one structure to soil potential reading, instead of the required four readings at evenly\nspaced locations around the perimeter of tanks. When PHMSA raised the concern, the Phillips\ncorrosion technician stated that Phillips had never taken four readings because these tanks are smaller\ndiameter tanks and thus, it was not required. Upon further review, PHMSA found the aforementioned\nprocedure and brought it to the company’s attention. The technician agreed and updated the Phillips\nrecords accordingly on June 25, 2013. During the PHMSA field inspection, adequate CP levels were\nnoted.\n3. §195.505 Qualification program.\nEach operator shall have and follow a written qualification program. The program shall\ninclude provisions to:\n(a) Identify covered tasks;\n(b) Ensure through evaluation that individuals performing covered tasks are qualified;\nPhillips failed to ensure through evaluation that employees were qualified to perform covered tasks on\n29 separate occasions. During the inspection, the following was identified:\nWhile reviewing records associated with the Overfill Protection equipment on the 17 DOT regulated\ntanks in Pasadena, TX, PHMSA noted that Phillips failed to ensure through evaluation that an\nemployee was qualified to perform a covered task. Specifically, task BT6023.1: Field Inspection and\nTesting of Overfill Protection Devices on Aboveground Breakout Tanks/Vessels. A Phillips employee\nperformed the task on April 26, 2013. PHMSA reviewed the qualification records for this individual,\nand the records indicated his qualification was not current for this covered task. According to Phillips,\nthe individual was a new hire and he was not qualified on covered task BT6023.1 until April 30, 2013.\nWhile reviewing records associated with the Annual Tank Inspections for 11 tanks located in\nPasadena, TX, PHMSA noted that Phillips failed to ensure, through evaluation, that an employee was\nqualified to perform a covered task. Specifically task BT2810 - Annual Visual Inspection of\nAboveground Storage Tanks Greater than 10,000 gallons. Phillips employee conducted annual tank\ninspections on 11 separate days for the aforementioned tanks. PHMSA reviewed the qualification\nrecords for this individual, and the records indicated that his qualification records were not current for\nthis covered task. The individual was last qualified on this covered task on January 14, 2010. The\nPhillips Operator Qualification Covered Task Reevaluation Frequency, BT2810, requires subsequent\nqualification at intervals of three years. Therefore, this qualification expired on or about January 14,\n2013. At the time of the inspection, Phillips failed to provide documentation indicating that an\nemployee was qualified prior to performing a covered task during the period of January 17-28, 2013.\nThis individual was re-qualified on 3/4/2013.\nWhile reviewing records associated with PI Form - Span and Exposed Piping Inspection Reports,\nPHMSA noted that Phillips failed to ensure through evaluation that two employees were qualified to\nperform a covered task. Specifically task CC6020 - Inspect Span and Exposed Pipe. Two Phillips\nemployees conducted a Span and Exposed pipe inspection on 2/16/2010. PHMSA reviewed the3\n\n\n\nqualification records for these individuals, and the records indicated their qualification records were\nnot current for this covered task. One individual was not qualified for this task and the other individual\nwas qualified on 4/13/2010.\nIf the aforementioned covered tasks; BT6023.1, BT2810 and CC6020 are performed by a non-\nqualified individual, Phillips' Operator Qualification, Active Covered Task List & Span of Control,\neffective Date: 03/18/2013, Version Number: 12.0, requires a span of control of a one to\none. According to the inspection documentation provided by Phillips, a qualified employee was not\npresent to observe or direct these individuals at the work site.\n4. §195.432 Inspection of in-service breakout tanks.\n(b) Each operator must inspect the physical integrity of in-service atmospheric and low-\npressure steel aboveground breakout tanks according to API Standard 653 (incorporated\nby reference, see § 195.3). However, if structural conditions prevent access to the tank\nbottom, the bottom integrity may be assessed according to a plan included in the\noperations and maintenance manual under § 195.402(c)(3).\nPhillips failed to consider the bottom side corrosion rate when determining the internal inspection\ninterval in accordance with API Standard 653 (incorporated by reference, see § 195.3).\nTank #1301 was constructed in 1972. It had previously been inspected and API 653 was applied in\n1994 for this tank, but documentation was not available that established an internal corrosion rate for\nthe tank bottom. Based upon the lack of information, API 653 processes would consider the corrosion\nrate as unknown, and the maximum internal inspection interval to be 10 years. This set the first\ninternal inspection for Tank #1301 to occur in 2004.\nOn January 16, 2004, Phillips performed an internal inspection on Tank # 1301. The inspection report\nfor Tank #1301, dated January 16, 2004, indicated reporting criteria was set by Phillips at 0.180 inch\nor less remaining thickness for the tank bottom plates. Three topside corrosion pits (Plat No. 63A, 48A\nand 48B) and one bottom-side corrosion pit (Plat No.56A) were identified during this inspection\n(Reference Table A-Bottom Reduction, section 6 of this report). Upon reviewing this table, PHMSA\nnoted, the minimum thickness remaining of 0.180, 0.180, 0.165 and 0.170 inch for plat 63A, 48a, 48B\nand 56A, respectively. Of these four corrosion pits, Phillips repair documentation showed only two\nanomalies were repaired and Minimum thickness for tank floor plate, API 653 Section 2.4.7\ncalculation sheet shows 3 topside and one soil side pitting repaired). Thus two reports are\ncontradicting each other.\nAPI 653 Section 6.4.2 describes the method for establishing the maximum initial and subsequent\ninspection intervals for internal inspections. Section 6.4.2 requires the calculation of the internal\ninspection intervals in accordance with Section 4.4.5 providing the owner and operator of breakout\ntanks obtained data on the thickness and condition of the tank bottom during an internal inspection.\nAn assumption of effective cathodic protection for the tank bottom side is allowed by API 653, which\nthen sets the soil side corrosion rate of the tank bottom plate to zero (0). However, if historic corrosion\nhas taken place, this is not a sufficiently conservative assumption, and the remaining unrepaired pits\n4\n\n\n\nshould be used to calculate the bottom side corrosion rate as specified in API 653. If bottom side\ncorrosion has occurred, it is not appropriate to assume a zero corrosion rate for the tank plate soil side\nin the calculation of the future inspection interval. The assumption of a zero (0) corrosion rate is\ninconsistent with the application of API 653.\nPhillips uses a program to determine the next internal inspection date using the formula from API 653,\nand inputs from the inspection report. There are no accompanying procedures that are used by the\nPhillips to establish when it is appropriate to assume that cathodic protection (CP) is effective, and the\ncorrosion rate can be effectively ignored in the re-inspection interval calculation. PHMSA noted that\nPhillips used a corrosion rate of zero for UPr in the inspection interval calculation. This value allowed\nthe re-inspection interval to be set at the maximum interval of 20 years. With UPr set equal to zero (0),\nPhillips set the next internal inspection date for January 16, 2024. API 653 defines UPr as the\nmaximum rate of corrosion on the bottom side of the tank bottom plate. Instructions state to calculate\nthe corrosion rate, use the minimum remaining thickness after repairs. For effective CP, UPr may be\nset to zero (0).\nSince corrosion had occurred on the tank bottom side, it was not appropriate to assume effective CP, or\nuse a corrosion rate of zero (0). Using the data obtained from the inspection report, and assuming a\nlinear corrosion rate based upon the age of the tank, PHMSA requested Phillips to input “No” into the\nprogram for effective CP and use a value for UPr set equal to actual corrosion growth rate in inches per\nyear. These calculations yielded the next internal inspection date of May 4, 2016, significantly less\nthan 20 years.\nBased upon these observations, PHMSA determined that Phillips failed to correctly demonstrate that it\nhad established a valid rate of corrosion on the bottom side of tank 1301, and did not have sufficient\ninformation to assume a corrosion growth rate of zero in calculating its inspection interval.\n5. §195.452 Pipeline integrity management in high consequence areas\n(h) What actions must an operator take to address integrity issues?\n(2) Discovery of condition. Discovery of a condition occurs when an operator has\nadequate information about the condition to determine that the condition presents a\npotential threat to the integrity of the pipeline. An operator must promptly, but no later\nthan 180 days after an integrity assessment, obtain sufficient information about a\ncondition to make that determination, unless the operator can demonstrate that the 180-\nday period is impracticable\nPhillips failed to declare discovery of a condition within 180 days despite the availability of the vendor\nreports to make such determinations.\nOn October 11, 2009, Phillips ran an NDT UT tool for the WT-80 pipeline between Slaughter and MP\n137. Subsequently, Phillips received a preliminary report for this run, which reported four “Company\nPriority Criteria” features that met the criterion of > 160 mils in depth. Phillips received the final\nreport on April 7, 2010, which was 2 days before the IMP discovery deadline (180 days). Phillips\nclaimed that the vendor’s final report submitted on April 7, 2010, did not contain adequate information5\n\n\n\nabout the condition of this pipeline to determine if a potential threat to the integrity of the pipeline\nexists. Phillips took until April 16, 2010, which is 7 days past the IMP discovery deadline to load the\nfinal report data for analysis.\nWhile Phillips was reviewing the tool run data in CPL-AID, they noted one anomaly was in an HCA\nat Station 383050 and was determined to be an IE 3 Priority (Anomaly that is in the judgment of the\nperson designated by the operator to evaluate the assessment result required immediate action. Cracks,\nSCC, or HIC indications called by an ILI vendor with criteria as follows: (E3) Cracks with a calculated\npredicted Burst Pressure (Burst) < MAOP at the anomaly location). Phillips did not limit the pressure\nat this anomaly site to 625 psi or less until 4/28/2010.\nPhillips Integrity Management Program, Section 5.4.1: Process for Assessment Results Review states:\n“When results are received in the form of Final Report, the INGRITY ENGINEER evaluates\nthe data and charts according to IEP 2.03 ILI Assessment Procedure within 30 business days\nfrom the receipt of report.”\nA review of IEP 1.03 – Reporting Requirements for Pipeline In-Line Inspection Procedure revealed\nthat Phillips allows 180 days for the Final Report to NDT Global vendor who runs the UT-UC tool.\nThus, Phillips procedure provides 180 days plus 30 business days to evaluate the data. The operator’s\nanomalous condition discovery process is inconsistent with the regulatory requirement.\nIt was Phillips, while analyzing the vendor’s data in final report noted a threat to the integrity of the\npipeline, but not until 4/28/2010, which was beyond 180 days. A vendor's failure to highlight an\nimmediate repair condition in the Executive Summary or \"feature summary listings\" does not excuse\nPhillips’ failure to discover the immediate condition within the 180-day timeframe.\n6. § 195.452 (b) What program and practices must operators use to manage pipeline integrity?\nEach operator of a pipeline covered by this section must:\n(1) Develop a written integrity management program that addresses the risks on each\nsegment of pipeline in the first column of the following table not later than the date in the\nsecond column:\n(5) Implement and follow the program.\nPhillips failed to make the appropriate changes to and follow their Integrity Management Plan to insure\nthat the manual is effective. Phillips Integrity Management Program, Section 5 Inspection and Repair,\nPipeline Maintenance and Leak Report, Section 5.6.3 states:\n“P66PL uses the Pipeline Maintenance and Leak Report (PMLR) located in e-Forms, in\nconjunction with the ILI Integrity Work List, to track the completion of repairs. O&M\nPersonnel complete and submit the PMLR, Form 3933, Pipeline Maintenance & Leak Report\n(PMLR) and companion Form 3933B, Field Anomaly Evaluation for any of the following\ntasks, and distribute them as detailed in MPR-2809, Instructions for Completing Form 3933 –6\n\n\n\nPipeline Maintenance & Leak Report (PMLR), and MPR-2839, Instructions for Completing\nForm 3933B Field Anomaly Evaluation:\n• Evaluating ILI features\nMapping receives the submitted PMLR, and then follows the workflow described in IEP 3.04\nPipeline Maintenance & Leak Report (PMLR) – Process Work Flow. This workflow describes\nhow the new data received is used to update the PODS database and where the hardcopy\nrecords are stored.”\nPHMSA learned that both MPR 2809 and MPR 2839 were discontinued in 2009. According to\nPhillips, the eForm is a smart form and self-explanatory. Phillips last revised their IM plan (Revision\n9) on July 21, 2011.\nIn addition, while reviewing the 2010 UT Crack Tool Okarche to Clinton data, dated 9/22/10, it was\nnoted that Phillips identified a total of 5 “Company Priority Criteria” conditions, based upon the\ncompany criteria HCA & Non-HCA - Anomalous Condition Definition. Of those five, two of the\npriority conditions (Station 1006239.13 and 1006232.05) were anomalies defined as IE Priority 2005C\n(Cracks, SCC or HIC indications called by an ILI Vendor with criteria as follows: C) Cracks with a\ncalculated Predicted Burst Pressure (Burst) < MOP at the anomaly location). For these two anomalies,\nPhillips made a repair with a 12' full encirclement sleeve and completed the Pipeline Maintenance and\nLeak Report (PMLR)(eForm # LO-01-11-0504). Upon further review of this eForm, PHMSA learned\nthat the “Field Anomaly Evaluation” documentation (eForm 3933B), dated 1/20/2011, reported that the\nfirst anomaly was 32.250 feet offset from weld # 96260, and 79.2 inches long, and, the second\nanomaly was 25.17 feet offset from weld # 96260, and 43.7 inches long. Based on this information,\nthe anomaly should have been repaired with more than twelve (12) feet.\nIn the same eForm, the “Inline Inspection Tool Correlation NDE Report” dated 1/20/2011 reported that\na total axial length of these two anomalous conditions from start to end (start of indication 24.31 and\n35.60 end of indication) is 11.29 feet and, as a result, a 13.10 feet length of pipe was examined. But\nbased on this report, 12 feet of type “B” sleeve was installed between upstream station # 10062+63.13\nand downstream station # 10062+75.13.\nTwo separate forms for the same location contradict each other. PHMSA verified Phillips’ PODS\nDatabase on 11/22/2013. The PODS Database showed 12 feet of full wrap was utilized at this location.\nIt appears that Phillips O&M personnel failed to accurately complete the companion form 3933 B of\nPMLR during their field anomaly evaluation on 1/20/2011. In addition, the Supervisor, the Integrity\nGroup and Mapping, failed to review the “Anomaly Evaluation”- for thoroughness on 2/14/2011,\n2/21/2011 and 4/15/2011, respectively. Phillips failed to correct this issue until PHMSA brought it to\nthe company’s attention.\nDuring the inspection, PHMSA noted several maintenance and construction related eForms throughout\nthe SW Region were found incomplete. Phillips completed these forms only after PHMSA brought to\nthe attention of the company.\n7\n\n\n\n7. §195.452 Pipeline integrity management in high consequence areas.\n(f) What are the elements of an integrity management program? An integrity\nmanagement program begins with the initial framework. An operator must continually\nchange the program to reflect operating experience, conclusions drawn from results of the\nintegrity assessments, and other maintenance and surveillance data, and evaluation of\nconsequences of a failure on the high consequence area. An operator must include, at\nminimum, each of the following elements in its written integrity management program:\n(1) A process for identifying which pipeline segments could affect a high consequence\narea;\nPhillips did not properly identify all segments that could affect an HCA. While reviewing Phillips'\nTranMap10, which manages and communicates information regarding HCA boundaries, PHMSA\nnoted that Line EZ at Hwy 183 crossing in Austin (East side is Creedmoor Street, Area Pilot Knob)\nappeared to be in an HCA. When PHMSA inquired further, Phillips responded that an older revision of\nthe NPMS (based on 2000 census data) did not identify this area as an HCA. Phillips conducted the\nfirst HCA analysis for this area during the 3rd Quarter of 2006 and determined that it was not an HCA\narea, because it was not identified as an HCA in NPMS. Phillips updated this area as an HCA on\nAugust 28, 2013, only after the new version of NPMS (based on 2010 census data) was released in\n2012. According to Phillips, since 1995, nothing has changed and the population has not grown.\nBased on the aforementioned, Phillips relied solely on NPMS data and failed to look for new HCAs on\ntheir own. The regulation does not except an operator from meeting the segment identification\nrequirement because data is incomplete and/or is not available on the NPMS. The operator has a\nresponsibility to seek and use alternative data to ensure that it has accurately identified pipeline\nsegments that could affect an HCA.\n8. §195.402 Procedural manual for operations, maintenance, and emergencies.\n(a) General. Each operator shall prepare and follow for each pipeline system a manual of\nwritten procedures for conducting normal operations and maintenance activities and\nhandling abnormal operations and emergencies. This manual shall be reviewed at\nintervals not exceeding 15 months, but at least once each calendar year, and appropriate\nchanges made as necessary to insure that the manual is effective. This manual shall be\nprepared before initial operations of a pipeline system commence, and appropriate parts\nshall be kept at locations where operations and maintenance activities are conducted.\nPhillips failed to follow their welding procedures and welder qualification requirements. On\nSeptember 23, 2009, P66PL ran a NDT UT crack tool on the WT-80 pipeline from Weems to\nSlaughter, Texas. As a result, one of the anomalies (Station 221227.83) was repaired with a welded\nsleeve on April 16, 2010. PHMSA reviewed the records associated with this repair (eForm WT-80-10-\n0517) and identified that one of the two welders used for this project was qualified with ASME Section\nIX on April 13, 2010. Upon further review of welder qualification record (Form GPL-106) revealed\nthat the actual test value for weld progression (Up/Down) was marked as Downhill. However, the\nwelder was qualified with an Uphill progression.\n8\n\n\n\nPhillips’ MPR 4401- Welding Procedures and Welder Qualification, Section 11.1.1 states”\n“When a qualification weld for THE COMPANY is completed, the inspector or the\nsupervisor shall complete the Welder Qualification Record for that welder and that weld.\nRefer to MPR-2811 for instructions for completing the Welder Qualification Record, P66\nForm GPL-106.”\nPHMSA reviewed MPR-2811 - Company Forms – Welder Qualification Record (Rev. 1 – Effective\nDate: 2008-07-08) and learned that the qualified range value for both API 1104 and ASMX IX test,\nmust be the same as the actual test value.\nBased on this review, the Phillips Certified Welding Inspector (CWI) failed to follow Phillips’\nprocedures to qualify the welder properly. When PHMSA raised this concern, Phillips stated, “After\nreviewing Tommy’s WQR with our welding SME, he deemed that the paperwork was incorrectly\nfilled out. We’ve located the CWI (Darryl Ezzell) and reviewed with him the errors found with his\npaperwork.” Phillips CWI updated the same document and resubmitted it (November 15, 2013) with a\nwelding progression actual value as “Uphill.”\n9. § 195.452 (b) What program and practices must operators use to manage pipeline integrity?\nEach operator of a pipeline covered by this section must:\n(1) Develop a written integrity management program that addresses the risks on each\nsegment of pipeline in the first column of the following table not later than the date in the\nsecond column:\n(5) Implement and follow the program.\nPhillips failed to follow their Integrity Management Program. P66PL-TSD-3008, Evaluation/Repair of\nExternal/Internal Pipeline Defects and Anomalies, Rev. 1 – Effective date 2012-10-15, Section 5.1.2:\nDefect Repair Requirements states:\n“The company will use the repair conditions criteria listed in section 195.452(h) of DOT 195,\nDOT 192.933, and Appendix A to address anomalies discovered in a High Consequence Area\n(HCA) and non-High Consequence Area (non-HCA)”.\nPHMSA reviewed records associated with the WT-80 pipeline TDW Magpie Combo tool run between\nSlaughter and MP 137 (tool run date 5/12/2010). Philips received the final report on 7/20/10 and\ndiscovered two anomalies on 9/27/2010 (repaired in May 2012) and three anomalies on 7/23/2010\n(repaired in December 2012) due to the company criteria for non-HCA - anomalous conditions defined\nper P66PL-TSD-3008. All five anomalies were reported as an IE Priority Code 1030 - Corrosion of or\nalong the Long Seam Weld.\nSimilarly, PHMSA reviewed records associated with the LO-01 pipeline TDW Magpie MFL tool run\nbetween Buxton and Clinton (tool run date 7/6/2009). Phillips received the final report on 10/05/20099\n\n\n\nand noted 142 anomalies (discovery date of 10/13/09). Of the 142 anomalies, nine met the company\ncriteria for Non-HCA anomalous condition definitions (1005C: Metal loss where SOP Pressure< MOP\nat the anomaly location). All nine anomalies were repaired between February – March of 2011.\nAccording to P66PL-TSD-3008, Revision 4 - Effective Date: 2012-10-15, repairs are required to be\nmade within 12 months. When PHMSA questioned why the aforementioned anomalies had not been\nrepaired within 12 months, Phillips advised that they combined MPR-4103 General Line and\nEquipment Maintenance Evaluation/Repair of External/Internal Pipeline Defect and Anomalies (Rev.\n13 – Effective Date: 2010-050-13) and GPL 513 into TSD-3008 in 2011. The previous policy (MPR-\n4103) had an 18-month requirement.\nFurthermore, Phillips’ Integrity Management Plan, Section 1.3.8: Management of Change states:\n“Over time, changes may occur in the P66PL-operated pipeline systems, the operations of\nthose systems, and/or the environment surrounding those systems, that may influence how an\nasset could affect an HCA. In an effort to ensure the program remains current, the IMP MOC\nprocess ensures proper documentation, communication, and response to changes affecting the\nprogram.\nThe IMP MOC effort focuses on, but is not limited to, the following key areas:\n• Newly identified HCAs\n• Changes to assessment plans\n• Modifications to the IMP based on new information\n• Changes in regulatory requirements\n• Changes in operations\n• Newly acquired integrity inspection data”.\nWhile updating the aforementioned policies, Phillips did not follow their IMP MOC procedure by\nfailing to document changes made to assessment plans as described above. Phillips was unable to\nprovide the date this change went into effect.\nProposed Civil Penalty\nUnder 49 United States Code, § 60122, you are subject to a civil penalty not to exceed $200,000 per\nviolation per day the violation persists up to a maximum of $2,000,000 for a related series of\nviolations. For violations occurring prior to January 4, 2012, the maximum penalty may not exceed\n$100,000 per violation per day, with a maximum penalty not to exceed $1,000,000 for a related series\nof violations. The Compliance Officer has reviewed the circumstances and supporting documentation\ninvolved in the above probable violation(s) and has recommended that you be preliminarily assessed a\ncivil penalty of $175,300 as follows:\n10\n\n\n\nItem number PENALTY\n2 $45,700\n3 $86,400\n5 $43,200\nWarning Items\nWith respect to items 1, 8 and 9 we have reviewed the circumstances and supporting documents\ninvolved in this case and have decided not to conduct additional enforcement action or penalty\nassessment proceedings at this time. We advise you to promptly correct these item(s). Failure to do so\nmay result in additional enforcement action.\nProposed Compliance Order\nWith respect to items 4, 5, 6, and 7 pursuant to 49 United States Code § 60118, the Pipeline and\nHazardous Materials Safety Administration proposes to issue a Compliance Order to Phillips 66\nPipeline LLC. Please refer to the Proposed Compliance Order, which is enclosed and made a part of\nthis Notice.\nResponse to this Notice\nEnclosed as part of this Notice is a document entitled Response Options for Pipeline Operators in\nCompliance Proceedings. Please refer to this document and note the response options. All material\nyou submit in response to this enforcement action may be made publicly available. If you believe that\nany portion of your responsive material qualifies for confidential treatment under 5 U.S.C. 552(b),\nalong with the complete original document you must provide a second copy of the document with the\nportions you believe qualify for confidential treatment redacted and an explanation of why you believe\nthe redacted information qualifies for confidential treatment under 5 U.S.C. 552(b). If you do not\nrespond within 30 days of receipt of this Notice, this constitutes a waiver of your right to contest the\nallegations in this Notice and authorizes the Associate Administrator for Pipeline Safety to find facts as\nalleged in this Notice without further notice to you and to issue a Final Order.\nIn your correspondence on this matter, please refer to CPF 4-2014-5011 and for each document you\nsubmit, please provide a copy in electronic format whenever possible.\nSincerely,\nR. M. Seeley\nDirector, Southwest\nPipeline and Hazardous Materials Safety Administration\nEnclosures: Proposed Compliance Order\nResponse Options for Pipeline Operators in Compliance Proceedings\n11\n\n\n\nPROPOSED COMPLIANCE ORDER\nPursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety\nAdministration (PHMSA) proposes to issue to Phillips 66 Pipeline LLC a Compliance Order\nincorporating the following remedial requirements to ensure the compliance of Phillips 66 Pipeline\nLLC with the pipeline safety regulations:\n1. 2. 3. 4. 5. 6. In regard to Item Number 4 of the Notice pertaining to Phillips failing to consider the\nbottom side corrosion rate when determining the internal inspection interval in\naccordance with API Standard 653, Phillips must develop procedures that clearly\nidentify when a corrosion rate of zero can be assumed. Phillips must also develop a\nprocedure that clearly identifies if an historic corrosion has occurred, and establish an\nappropriate corrosion rate from the measured data in accordance with API 653. After\ndeveloping procedures, Phillips must re-evaluate their tank inspection intervals against\nthe revised procedure to ensure that the internal inspection intervals are calculated in\naccordance with API 653 and to ensure that inspection occur prior to reaching the\nminimum plate thickness necessary to ensure tank plate integrity.\nIn regard to Item Number 5 of the Notice pertaining to failure to declare discovery of\ncondition within 180 days, Phillips must amend IEP 1.03 – Reporting Requirements for\nPipeline In-Line Inspection Procedure to be consistent with the regulatory requirement\nof §195.452 (h)(2).\nIn regard to Item Number 6 of the Notice pertaining to Phillips failing to make\nappropriate changes and follow the Integrity Management Plan, Phillips must amend the\nIntegrity Management Plan, Section 5.6.3 and remove deleted procedures reference.\nIn regard to Item Number 7 of the Notice pertaining to Phillips failing to properly\nidentify an HCA, Phillips must amend the Integrity Management Plan to broaden the\nHCA identification beyond the sole reliance on the NPMS.\nProvide PHMSA with documentation that verifies completion of numbers 1 - 4 above\nwithin 45 days following the receipt of the Final Order.\nIt is requested (not mandated) that Phillips 66 Pipeline LLC maintain documentation of\nthe safety improvement costs associated with fulfilling this Compliance Order and\nsubmit the total to R. M. Seeley, Director, Southwest Region, Pipeline and Hazardous\nMaterials Safety Administration. It is requested that these costs be reported in two\ncategories: 1) total cost associated with preparation/revision of plans, procedures,\nstudies and analyses, and 2) total cost associated with replacements, additions and other\nchanges to pipeline infrastructure.\n12\n\n420145011_Final Order_09112015_text.pdf\n\nSeptember 11, 2015\nMr. C. Todd Denton\nPresident\nPhillips 66 Pipeline LLC\nPinnacle Westchase PWC 078-7150-09\n3010 Briarpark Drive\nHouston, Texas 77042\nRe: CPF No. 4-2014-5011\nDear Mr. Denton:\nEnclosed please find the Final Order issued in the above-referenced case. It makes findings of\nviolation, assesses a civil penalty of $175,300, and specifies actions that need to be taken by\nPhillips 66 Pipeline LLC, to comply with the pipeline safety regulations. The penalty payment\nterms are set forth in the Final Order. When the civil penalty has been paid and the terms of the\ncompliance order completed, as determined by the Director, Southwest Region, this enforcement\naction will be closed. Service of the Final Order by certified mail is deemed effective upon the\ndate of mailing, or as otherwise provided under 49 C.F.R. § 190.5.\nThank you for your cooperation in this matter.\nSincerely,\nJeffrey D. Wiese\nAssociate Administrator\nfor Pipeline Safety\nEnclosure\ncc: Mr. Rodrick M. Seeley, Director, Southwest Region, OPS\nMr. Todd Tullio, Manager, Regulatory Compliance, Phillips 66 Pipeline LLC\nMr. Dave Barney, Manager, Engineering & Projects Downstream, Phillips 66 Pipeline LLC\nMr. Van Williams, General Counsel, Phillips 66 Pipeline LLC\nCERTIFIED MAIL - RETURN RECEIPT REQUESTED\n\n\n\nU.S. DEPARTMENT OF TRANSPORTATION\nPIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION\nOFFICE OF PIPELINE SAFETY\nWASHINGTON, D.C. 20590\n____________________________________\n)\nIn the Matter of )\n)\nPhillips 66 Pipeline LLC, ) CPF No. 4-2014-5011\na subsidiary of Phillips 66, )\n)\nRespondent. )\n____________________________________)\nFINAL ORDER\nBetween April 1 and November 22, 2013, pursuant to 49 U.S.C. § 60117, a representative of the\nPipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety\n(OPS), conducted an on-site pipeline safety inspection of Phillips 66 Pipeline LLC’s (Phillips or\nRespondent) facilities and records located in Texas and Oklahoma. Phillips, a wholly-owned\nsubsidiary of Phillips 66, operates approximately 12,000 miles of pipelines in the United States,\nthrough which it transports raw and finished petroleum products.1\nAs a result of the inspection, the Director, Southwest Region, OPS (Director), issued to\nRespondent, by letter dated May 13, 2014, a Notice of Probable Violation, Proposed Civil\nPenalty and Proposed Compliance Order (Notice), which also included warnings pursuant to 49\nC.F.R. § 190.205. In accordance with 49 C.F.R. § 190.207, the NOPV proposed finding that\nPhillips had violated 49 C.F.R. §§ 195.402, 195.505, 195.432, and 195.452, and proposed\nordering Respondent to take certain measures to correct the alleged violations. The Notice also\nproposed assessing Respondent a civil penalty of $175,300 for these alleged violations. The\nwarning items require no further action, but the operator is warned to correct the probable\nviolations or face possible enforcement action.\nPhillips responded to the Notice by letter dated June 13, 2014 (Response). In its Response,\nPhillips stated it “elects not to contest the violations stated in the Notice,”2 but raised objections\nto several of the proposed findings of violation and certain portions of the Proposed Compliance\nOrder, and further requested that the proposed civil penalty be reduced or eliminated.\nRespondent did not request a hearin","truncated":true,"body_characters":74106}