ALYESKA PIPELINE SERVICE CO — Notice of Probable Violation

520025003_Final Order_04282004.pdf, page 1Official PDFU.SDeporhent ot Tronsportolbn Reseorch dnd Speciol Progroms Admanislraiion 400 Sevenlh SI . S W Washinglon D C 20590 APR 2 8 2004 Mr. Robert Shoaf Vice President Regulatory Affairs 900 East Benson Boulevard Alyeska Pipeline Service Anchorage, AK 99508 Company Re: CPFNo.5-2002-5003 Dear Mr. Shoat Enclosed is the Final Order issued by the Associate Administrator for Pipe line Safety in the above-referenced case. The Final Order - mnkes findings of violation with respect to Items 7, 4, and 5 (Item # as alleged in the Notice of Probable Violation dated February 7,2002); withdraws the allegations of violation with respect to Items 2a andT1' makes a finding of inadequate procedures for Items 3a, 3b, 8a and 8b and requires amendment of those procgdures withdraws the allegation of inadequate procedures for Item 3c and 8c; finds that you have completed the actions specified in Items land 4 required to comply with the pipeline safety regulations; and assesses a civil penalty of $45,000. Your receipt ofthe Final Orderconstitutes service ofthat document under 49 C.F.R. $ 190.5. Sincerely, fi fAn fr-^ r t/ t*=-' Xmes Reynolds Pipeline Compliance Registry Office of Pipeline Safety Enclosure cc: Sheila Doody Bishop Attomey P.O. Box 60469 Fairbanks, Alaska 99706 CERTIFIED MAIL - RETURN RECEIPT REOUESTED#

520025003_Final Order_04282004.pdf, page 2DEPARTMENT OF TRANSPORTATION RESEARCH AND SPECIAL PROGRAMS ADMINISTRATION WASHINGTON. DC 20590 In the Matter of Alyeska Pipeline Service Company, Respondent. CPF No. 5-2002-5003 ) FINAL ORDER On July 17-28, September 13-17, October 7-17 and October 30-31, 2000, representatives of the Office of Pipeline Safety (OPS), pursuant to 49 U.S.C. $ 60117, conducted on-site pipeline safety inspections of Respondent's facilities and records from Pump Station #l to Valdez on the Trans Alaska Pipeline System (TAPS). As a result of the inspections, the Director, Westem Region, OPS, issued to Respondent, by letter dated February 7, 2002, a Notice of Probable Violation, Proposed Civil Penalty, Proposed Compliance Order and Notice of Amendment (Notice). ln accordance with 49 C.F'R. $ 190'207, the Notice proposed finding that Respondent had violated 49 C.F.R. $$ 195.401(a), 195'402(a), 1 95.418(a), 195.422and 1 95.428(a), proposed assessing a civil penalty of$80,000 for several ofthe alleged violations, and proposed that Respondent take certain measures to correct the alleged violations. The Notice also proposed, in accordance with 49 C.F.R. $ 190.237, that Respondent amend its procedures for Operations, Maintenance and Emergencies. Respondent responded to the Notice by letter dated M arch8,2002 (Response). Respondent did not contest one of the allegations (Item 5, $ 195.422) and submitted payment for the proposed civil penalty via wire transfer. Respondent requested an extension to respond to the other allegations in the Notice. The Westem Region granted an extension on March 15,2002. On April 16,2002' Respondent notified OPS that it was voiding the $25,000 check for the civil penalty amount and would include a response to Item 5 when it responded to the other allegations. On May 13' 2002, Respondent submitted its response to the Notice. Respondent contested the allegations, submitted information to address the aliegations and reserved the right to a hearing if OPS did not withdraw the allegations based on the submitted information. An informal hearing was held in the Western Region, OlS, on April 8, 2003. After the hearing, Respondent submitted a Closing Response dated June 6, 2003.#

520025003_Final Order_04282004.pdf, page 3FINDINGS OF VIOLATION Item I in the Notice alleged that Respondent had violated 49 C.F.R. g 195.401(a), which provides that an operator may not operate or maintain its pipeline system at a level of safety lower than that required by subpart F (Operation and Maintenance) and by the procedures the operator is required to establish under $ 195.a02@). The Notice alleged that Respondent had operated the pipeline unsafely from August 1999 to April 2000. According to the Notice, on August 22, 1 999, Respondent had modified the opening logic of Remote Gate Valve (RGV) #31 at Milepost 1 70 to open at 1 00% during pipeline startup, and on November 13, 1999 and February 10, 2000, Respondent had experienced large magnitude, abnormal hydraulic pulses at RGV 3l during pipeline startup. The Notice firther alleged that during start up on April 17,2000, the rapid opening of the valve caused unstable flow conditions to occw, creating a vapor pocket collapse immediately south of RGV 3 l. This collapse caused the resuhant pressure pulse to exert excessive hydraulic forces and movernent of the pipeline, tripping pipeline anchors near Mile post I 70, shearing off support bracket bolts on aboveground anchors and raising the pipeline pressure to 793 psi. Respondent maintained that the pipeline was operated safely from August I 999 until April 2000 and that the aboveground pipe and support and anchoring system performed as designed. Respondent disagreed with the allegations that it had not experienced the large-magnitude pressure variations beforemodif ingtheopeninglogicofRGV3l,thattheeventonApril lT,2}}lgeneratedexcessive hydraulic forces and that the modified opening logic resulted in excessive pressure pulses. Respondent acknowledged that a pressure pulse occurred and that the modified opening logic of RGV 3l was responsible for an increase in the magnitude of the hydraulic surges in that area. However, Respondent explained that the aboveground pipe is designed to respond to seismic and hydraulic events by absorbing energy through movement of the support and anchoring system. Respondent maintained that the aboveground pipe has experienced movement due to hydraulic surges but none of the pressure surges, including the one on April 17, exceeded I l0% of MOP or resultedinanydamagetothepipeline. Respondentacknowledgedthattheabovegroundpipemoved on its support and damaged the support system but argued that the pipeline remained supported and was undamaged. Respondent explained that the anchors were designed to prevent the pipeline from being subjected to forces above 105 kips. The incident on April 17,2000 was a bubble collapse that occurred at a slack line interface at MP 170. The PAULA program, which assessed the raised pressure at 109.8% of maximum operating pressure, assesses pressure pulses. However, this was not a high pressure pulse that can be analyzed by the PAULA surge model but a fast transient pressure bubble collapse. When a transient pressure spike occurs at stafiup, the pipeline and its components receive a significant shock. The shock cannot be measured by conventional hydraulic programs. Moreover, those pressure spikes were due to Respondent's own actions in modifying the opening logic of RGV 31. Respondent made the modification without analyzing the potential for surge. When a transient pressure spike occurs at startup, the pipeline and components receive a significant shock and are stressed beyond their metal ductility. The changing of the opening logic for RGV 31 caused the pipeline to be subject unnecessarily to high surge pressure events.#

520025003_Final Order_04282004.pdf, page 4oJ Although this was a fast transient pressure spike, the suppofi system supported the aboveground pipeline as it had been designed to do for seismic and thermal events. The smashing of the honeycornb barriers rn'as within the design as were the sliding bolts. But normal design was exceeded when the support bracket bolts on aboveground anchors were sheared offdue to the force ofbetween 120 and 130 kips. Accordingly, I find that Respondent violated $ 195.401(a), because the pipeline was operated unsafely between August 1999, rvhen Respondent changed the opening logic fbr RGV 31 and April 17, 2000, when the incident involving the vapor pocket collapse occurred. Item 2A alleged that Respondent violated 49 C.F.R. 0 195.402(a) because it did not follow its proceduiesin excavatingthepipeline atmilepost 710.77 r,-hen awall loss of 62o/ohadbeen identified ty a magnetic flux leakage (MFL) in-line inspection in 1992. Respondent's procedures require excavation of the anomaly if the penetration threshold exceeds 507o of nominal wall thickness, but Respondent did not excavate the pipeline until May 2000. The regulation requires an operator to pr"p-" and follow for its pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. Respondent disagreed that it had knowledge of wall loss at this location in 1992 and that it had not foiiowed its procedures in inspecting the anomaly. Respondent explained that the analysis of the 1992 MFL pig data identified a nonspecific indicator or pipeline feature at MP 710.7, but did not identify any wal1 loss with that feature. It was not until the smart pig inspection in 1998 and the 1999 data analysis from that run that a43o/owall loss was identified at that location. Respondent maintained that it took prompt action to excavate the location in May 2000 although the 43o/" corrosion wall loss did not match the criterion for required excavation. Respondent explained that when it excavated at the location, it found an actual wall loss of 600/o' Although the records, if the data had been analyzed correctly' may have showed the 60Vo wall loss before Respondent excavated the location in 2000, those charged with interpreting the data failed to identify ihe location as one requiring excavation under Respondent's procedures' Rather than a failure to follow procedures, the failure was in interpreting the data corectly and responding accordingly. Accordingly, I am withdrawing the allegation of violation' Item 4 alleged that Respondent violated 49 C.F.R. $ 195.418(a), which provides that an operator must not transport any hazardous liquid that would corrode the pipe or other components of its pipeline system unless the operator his invcstigatecl the corrosive effect ofthc hazardous liquid on ihl system and taken adequaie steps to mitigate corrosion. The Notice alleged that Respondent had not investigated the internal conosive effects ofthe hazardous liquids on its six-inch bypass piping oncheckvalves6, 1,g,13,18,29,29A,30,68Aand71 althoughRespondenthadnotedsubstantial internalwalllossinundergroundcheckvalves4, 10, 12, 16, 17,75,83 and34andinthebypasses of abovesround check valves 1 9,A., 32 and 3l .#

520025003_Final Order_04282004.pdf, page 5Respondent agreed that at the July 2000 inspection Respondent had not inspected utt oftn" .n"cj vaive bypasses. Respondent noted that in 1997 it had proposed a five-year schedule to excavate all the non-inspected buried check valves, and that it kept government agencies apprised ofthe status of its activities. Respondent stated that all check valves have now been inspected and there are procedures in place to ensure an adequate checking schedule. Respondent did not have a 49 U.S.C. $ 60118 (c) waiver from the requirement to investigate the internal corrosive effects ofthe hazardous liquids it was transporting on its check valve bypasses. Accordingly, I find that Respondent violated $ 195 .a 1 8(a) with respect to the cited check valves. Item 5 alleged that Respondent had not insured repairs it made to its pipeline were made in a safe manner,inviolationof49C.F.R. $195.a22@). TheNoticeallegedthatinexcavatingandexamining severe mechanical damage atMP 710.76 on May 15, 2000, Respondent had blpassed pump station L2, whichincreased thepressure atthe defect location from approximately 330psig to approximately 670 psig. The Notice further alleged that because Respondent could not determine accurately the remaining wall strength at the location of the defect, Respondent should have lowered the pressure at the location, or at least not mised the pressure. Respondent did not contest this allegation but explained that it had taken steps to ensure that in the future pressure is not raised on a known defect. Accordingly, I find that Respondent violated $ 195.a22@) when it made this repair on May 15,2000. Item 7 alleged that Respondent violated 49 C.F.R. $ 195.a28(a) because Respondent could not provide records demonstrating the standard maintenance procedures for all pressure safety valves at Pump station 3 had been completed for calendar year 1999. Respondent's maintenance records showed that pressure safety valves 304 A, B and C and 305 A, B and C were scheduled for maintenance on October 30, 1999 but that Respondent did not inspect valves 304 A, B and C until Novembcr2,2000, valve 305Auntil October24,2000 and valves 305 B and C untii September 16, 2000. The regulation requires an operator to inspect and test each pressure limiting device, relief valve, pressure regulator or other item of pressure control equipment to determine that it is functioning properly at intervals not exceeding 15 months, but at least once each calendar year. Respondent contested this allegation and maintained that it had tested the Pump station 3 suction and discharge valves at the required interval in 1999. At the hearing Respondent provided documents (Modei Work Orders and Prevenlive Maintenance Work Orders) demonstrating that it had inspected and tested the cited valves at the required intervals. The records showed that pump station valvcs 3054, B and C were tested on September 28,1999 and that Pump station valves 304 A, B and C were teste d on December 31,, 1999, all within the requirecl interval from the previous inspection and test. Accordingly, I am withdrawing this allegation of violation.#

520025003_Final Order_04282004.pdf, page 65 PENALTY ASSESSMENT Under 49 U.S.C. § 60122, Respondent is subject to a civil penalty not to exceed $100,000 per violation for each day of the violation up to a maximum of $1,000,000 for any related series of violations. The Notice proposed a total civil penalty of $80,000 for violation of §§ 195.401(a), 195.422 and 195. 428(a). (Items 1, 5 and 7.) 49 U.S.C. § 60122 and 49 C.F.R. § 190.225 require that, in determining the amount of the civil penalty, I consider the following criteria: nature, circumstances, and gravity of the violation, degree of Respondent's culpability, history of Respondent's prior offenses, Respondent's ability to pay the penalty, good faith by Respondent in attempting to achieve compliance, the effect on Respondent's ability to continue in business, and such other matters as justice may require. The Notice proposed a civil penalty of $25,000 for violation of 49 C.F.R. § 195.401(a) - operating the pipeline unsafely because of the modification of RGV 31's opening logic. Respondent acknowledged that the incident on April 17, 2000, was due to its having changed the valve's opening logic. The incident generated sufficient force to move the pipeline on its supports and to shear the anchors. Although it was fortunate the pipeline was not damaged, the pipeline, nonetheless, was stressed unnecessarily. As mitigating factors, Respondent noted that it had voluntarily notified OPS about the event and, on its own initiative, taken steps to identify the cause and reduce the magnitude of future surge events. I assess a civil penalty of $20,000 for this violation. The Notice proposed a civil penalty of S25,000 for Respondent's violation of 49 C.F.R. § 195.422(a) for not ensuring that repairs made to the pipeline were done in a safe manner. Respondent said that it had implemented new procedures to avoid unsafe repairs in the future. I assess a civil penalty of $25,000 for this violation. The Notice proposed a civil penalty of $30,000 for not testing the Pump station 3 valves at the required intervals. I withdrew this allegation of violation. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a total civil penalty of $45,000. Payment of the civil penalty must be made within 20 days of service. Federal regulations (49 C.F.R. § 89.21(b)(3)) require this payment be made by wire transfer, through the Federal Reserve Communications System (Fedwire), to the account of the U.S. Treasury. Detailed instructions are contained in the enclosure. Questions concerning wire transfers should be directed to: Financial Operations Division (AMZ-120), Federal Aviation Administration, Mike Monroney Aeronautical Center, P.O. Box 25082, Oklahoma City, OK: 73125; (405) 954-8893. Failure to pay the $45,000 civil penalty will result in accrual of interest at the current annual rate in accordance with 31 U.S.C. § 3717, 31 C.F.R. § 901.9 and 49 C.F.R. § 89.23. Pursuant to those same authorities, a late penalty charge of six percent (6%) per annum will be charged if payment is not made within 110 days of scrvice. Furthermore, failure to pay the civil penalty may result in referral of the matter to the Attorney General for appropriate action in a United States District Court.#

520025003_Final Order_04282004.pdf, page 7WARNING ITEM The Notice issued a waming for Item 2B - not following normal operating procedures in removing the RGV-35A control card for maintenance without requesting the Operation Control Center to inhibit the RGV controi logic. Respondent said that its operator qualification program is structured to prevent a recurrence. Respondent is again wamed that enforcement action will be taken if a subsequent inspection reveals a violation. The Notice also issued a waming for Item 6 for exceeding the maximum pressure when moving an aboveground section on the pipeline. Respondent contended that the regulation did not apply because it was written ior belowground pipe and Respondent's pipeiine at Squirrel Creek is aboveground. Respondent stated that it is preparing a request for a waiver {iom the regulation. Respondent must ensure that, while the waiver is pending, it complies with $ I 95.424(a) by reducing pressure when moving any line pipe. COMPLIANCE ORDER TheNoticeproposedacomplianceorderwithrespecttoltems l,2Aand4. Under49U'S.C. I 601 1 8(a), each person who engages in the transportation of hazardous liquids or who owns or operates a pipeline facility is required to comply with the applicable safety standards established under chapter 601. With respect to the violation of $ 195.401(a) (Item 1), the Notice proposed that Respondent provide an engineering/surge analysis ancl modify its start-up procedures. Respondent reported that it reviewed its records to determine what caused the largest pressure surge. It analyzed the April 17, 2000 event, recommended corrective action, and implemented a revised opening sequence for RGV With respect to the violation of $195.418(a) (Item 4), the Notice proposed that Respondent investigate the 6-inch bypass piping on the cited check valves for internal corrosion. Respondent reported that it had inspected all of its check valve bypass lines. Accordingly, since compliance has been achieved with respect to these violations, the compliance terms are not included in this Order. For Item 2A, the Notice proposed that Respondent integrate all of its pigging information to provide an engineering analysis on the condition of the Trans Alaska Pipeline System - Because I withdrew this allegation of violation. corrective action is not rcquired. AMENDMENT OF PROCEDLIITES The Notice (Items 3 and 8) allege<l inadequacies in Respondent's Procedural Manual for Operations, Maintenance and Emergencies and proposeal to require amendment of Respondent's procedures to comply with the requirements of 49 C.F.R. $$ 195.4160),195'424,195.428(d) and 195'432'#

520025003_Final Order_04282004.pdf, page 8Item 3 of the Notice alleged that Respondent's procedures - did not ensure that the cathodic protection system for abovegrowrd breakout tanks, where corrosion of the tank bottom is controlled by a cathodic protection system, is operated and maintained in accordance with API recommended practice 651. (Item 3a); did not address reducing pressure to a least 50% of maximum operating pressure before moving or leveling any aboveground crude oil piping (Item 3b); did not address overfill alarm testing and inspection ofthe grounding system during the five-year external inspection interval (Item 3c). With respect to the first allegation about the ina<iequacy of its procedures, Respondent maintained ihai there is no requirement that API RP 651 be site specific or that Respondent provide detailed site specific procedures in its O&M manual. Respondent argued that it was adequate for its OM-l ard MP- 166-3.20 (System Integrity Monitoring Program Procedures for Tarrk Monitoring) to reference API RP 651 in its entirety. The Notice cited inadequacy of the tank monitoring procedures to comply with $195.416(i), which was moved into new $ 195.573(d) as of October 2002. The requirement remained the same. The referenceinRespondent'sproceduresistoobroadtoprovideadequateinstructiontoemployees. The procedure should give more specific instructions or, at least, reference the applicable sections and paragraphs in API 651 . As for the second allegation, Respondent argued that the requirement did not apply to aboveground pipe and that its procedures are adequate to ensure aboveground pipe movement safety. Respondent maintained that it is preparing a request for a waiver from this requirement. Until Respondent is granted the waiver, therequirement applies andRespondent's procedure must reflect the requirement for a pressure reduction before moving any of the piping, including that aboveground. With respect to the third allegation, Respondent pointed out that the inspection occurred before the regulation became effective in October 2000. Accordingly, this allegation conceming Respondent's procedures is withdrawn. Item 8 ofthe Notice alleged that Respondent's procedures for breakout tanks- did not specify an inspection interval of the lesser ofhve years or 1/4 corrosion rate life ofthe shell, as specified in API Standard 653 (Item 8a); did not require the Authorized Inspector's interaction and oversight ofthe inspection activities (8b); and did not address the requirements of subsection I I .3 ofAPi RP 651 in its entirety (8c). In response to the first allegation, Respondent maintained that it had inspected its breakout tanks in#

520025003_Final Order_04282004.pdf, page 9d accordance with section 4 of API Standard 653 although the tank monitoring procedures listed the inspection frequency as five years. Respondent said that the standard had been incorporated by reference into its Tank Manual procedure TM -188. Nothing in the record disputes Respondent's assertion that its inspection schedule considered the 1 i4 shell corrosion rate. However, the allegation concemed whether that corrosion rate was specified in the procedure. The procedure Respondent submitted (TM-188, section 2.5) references API standard 653 when referring to a five-year inspection cycle. Althoughthe l/4 shell corrosion rate is in the standard, it should also be listed in the procedure to be absolutely clear about the length of the inspection cycle. With respect to the second allegation in Item 8, Respondent submitted its procedures that specify a ceilified API 653 tank inspector is to perform the visual inspections. Fut'"her amendment of these procedures is not required. The third allegation in Item 8 incorrectly referenced 9195.432. The Notice should have cited the cathodic protection monitoring requirements forbreakout tanks in $195.4160) (now $ 195.573(d)). Thus, this allegation was covered bythe allegation in Item 3A and need not be repeated. Accordingly, I find that Respondent's procedures as described in Items 3a, 3b, 8a and 8b are inadequate to assure safe operation of its pipeline system. Respondent has satisfactorily amended its procedures to address the inadequacy cited in Item 8b. Pursuant to 49 U.S.C. $ 60108(a) and 49 C.F.R. 5190.237, Respondent is ordered to make the following changes to its procedures. Resoondent must - 1. Amend its procedures for breakout tanks (Operations, Maintenance and Emergencies (OM-1) and SystemlntegrityMonitoringProgramProc€dures, TankMonitoring (MP166- 3.20)) to provide adequate instruction to carry out $195.573(d)). The procedures must provide more specific information about the requirements ofAPI Recommended Practice 651 that must be followed or must cite the specific sections nnd paragraphs of API Recommended Practice 651 that must be followed. z . Amend the procedures in its Operations, Maintenance and Emergencies manual (OM-l) to specify that pressufe must be reduced to at least 50% of ma,ximum operating pressure before moving or leveling the aboveground pipeline. 3. Amend its procedures for breakout tanks (Tank Monitoring (TM-188) and System IntegrityMonitoring Program Procedures, TankMonitoring (MP166-3.20)) to specifythat the inspection interval for breakout tanks is the lesser offive years or the ll4 corrosion rate life of the shell. 4. Submit the amended procedures to the Westem Regional Director, OPS within 30 days flom issuance of this Order.#

520025003_Final Order_04282004.pdf, page 10v 5. The Regiolal Director may extencl the period for complying with the required items if the Respondent requests an extension and adequatelyjustihes the reasons for the extcnsion. Under 49 C.F-.R. $ 190.215, Respondent has a right to petition for reconsideration of this Final Order. The petition must be received within 20 days ofRespondent's receipt ofthis Final Order and must contain a brief statement of the issue(s). The filing of thc petition automatically stays the payment of any civil penalty assessed. All other terms of the order, including any required corrective action and amendment ofprocedures, remain in full effect unless the Associate Administrator, upon request, grants a stay. The terms and conditions of this Final Order are effective upon receipt. APR 2 8 2004 Date Issued Stacev Gerard 4"oiiut"Admini for Pipeline Safety#