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Home My WebLink AboutO 029 ) 1. 2. 3. December 12, 2003 November 14,2004 January 10, 2005 4. August 19,2005 ') INDEX OTHER NO. 29 A-22 Enforcement Action Notice of Proposed Enforcement Decision and Order BPXA's Submission in response to Commission Decision and Order dated 11/14/04 Ltr to BPXA re: Credit for Pilot Program Costs Other Order #29 and further penalty documentation Investigative filed located in the Confidential Room #4 @ìI/ð\ ìíre @¡~i ~lJU: ) /.~ \ n [ÆrA \@ n[i" l~ 1\_ LF; ~./ L \\ !. l / jj \ ~.~\\ U1 \ ¡ LI. \ !JJ 'J~/i ~ ¡ \ lJ ) AItASHA OIL Alfl) GAS CONSERVATION COMMISSION 333 W. pH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 August 19, 2005 Ms. Maureen Johnson Vice President, Greater Prudhoe Bay BP Exploration (Alaska) Inc. 900 East Benson Blvd. P.O. Box 196612 Anchorage, AK 99519-6612 RE: PBUA-22 Enforcement Action Credit for Pilot Program Costs Dear Ms. Johnson: The Alaska Oil and Gas Conservation Commission issued a final Decision and Order regarding the Prudhoe Bay Unit ("PBU") A-22 enforcement action on November 15,20041. As part of the decision, BP Exploration (Alaska) Inc. ("BPXA") was ordered to pay a civil penalty in the amount of $1,265,000. The Commission further recognized that BPXA had voluntarily initiated actions, including a pilot project begun in the winter of 2003-2004 to determine the feasibility of remote, real time monitoring of outer annulus pressures. The Commission's Decision and Order allowed BPXA to credit its actual expenditures on the Pilot Program, up to the amount of $549,000 against the imposed civil penalties. As required by the Decision and Order, BPXA provided the Commission with documentation of its actual expenditures on the Pilot Program. A two-volume cost accounting titled "A-22 Annulus Pressure Monitoring Pilot Project" was submitted by BPXA to the Commission on January 10,2005 as evidence of the actual expenditures. We have completed our review of the information provided by BPXA and agree that the $549,000 credit is warranted. Therefore, BPXA has satisfied all financial obligations as directed by the Commission's Decision and Order. 1 Other Order 29 ) ) The Commission believes the results of the subject pilot project may hold benefits for the entire oil industry in Alaska regarding the effective management of annulus pressure in wells. We would appreciate an update of the project status and results to date. Also of interest would be any efforts BPXA is considering or has instituted to expand on the study, and in particular, installations identified as a result of the study that would benefit from remote, real-time monitoring of annulus pressures. The Commission is also interested in BPXA's intentions for sharing the pilot project results with the industry. With this letter we are officially closing our file an this #3 ) ) RE: BP EXPLORATION (ALASKA), INC., AS OPERATOR OF THE ) PRUDHOE BAY UNIT; PRUDHOE BAY FIELD; ) WELL A-22 ENFORCEMENT ACTION ) ) STATE OF ALASKA ECEIVED ALASKA OIL AND GAS CONSERVATION COMMISSION JAN 1 0 2005 i Id O' 0 G"q¡¡> Cmv1' Comm¡~~3¡ml A¡ïaSlAia h cl <¡¡¡o¡)J' .,;p. ArJch[Dwage BPXA'S SUBMISSION IN RESPONSE TO COMMISSION DECISION AND ORDER DA TED NOVEMBER 15,2004 In its November 15, 2004 Decision and Order in this matter, the Alaska Oil and Gas Conservation Commission ("AOGCC or Commission") ordered BP Exploration (Alaska), Inc. ("BPXA"), as Operator of the Prudhoe Bay Unit, to pay the Commission a civil penalty of $1,265,000 (Ordering Paragraph No.1) and to pay $1,112 for the unauthorized, venting of 1,053 thousand cubic feet of gas (Ordering Paragraph No.3). The Commission also stated that the penalty would be reduced by the amount that has been expended on the pilot program described in BPXA's May 28, 2004 letter to the Commission (a copy of which is attached as Appendix B to the Commission's November 15, 2004, Decision and Order) ("Pilot Program"), subject to a maximum reduction of $549,000 and provided BPXA provide documentation of its actual expenditures on the Pilot Program (Ordering Paragraph No.2). This filing is timely made to comply with the Commission's Decision and Order. Concurrent with this pleading, BPXA submits two checks: the first for $716,000 and the second for $1,112. BPXA also submits two volumes of documentation of its actual expenditures on the Pilot Program in support of the $549,000 reduction. A summary of the expenditures is contained at the front of Volume I of the submission. The Commission will observe that through November 30, 2004, BPXA spent a total of $626,129.30 in connection with the Pilot Program. . BPXA's Submission in Response to Commission Decision and Order Dated November 15,2004 Page 1 ) ') The total amount expended, which includes expenditures subsequent to November 30, 2004, now exceeds $700,000. Documentation for the expenditures in connection with the Pilot Program is segregated into three sections in the binders. The first section is entitled Warehouse Issues and includes documentation of the costs incurred for materials and equipment used in connection with the Pilot Program. These expenditures total $218,141.76. The second section is entitled Labor Allocations and includes the costs expended by BPXA for labor associated with the Pilot Program. In 2003, those expenditures comprised $44,903.96. For 2004, the amount was $36,936.51. The total for both years is $81,840.47. The third and final section is comprised of Vendor Invoices for services and materials provided by vendors in connection with the Pilot Program. Because some of the invoices also include expenditures that are unrelated to the Pilot Program, BPXA has identified with yellow highlighter the expenditures on each invoice that are directly attributable to the Pilot Program. The total of sums expended by BPXA on Vendor Invoices for the Pilot Program is $326,139.07. The total of all three sections is, as noted above, $626,121.30. Therefore, as allowed by Ordering Paragraph No.2, the penalty has been reduced by the maximum reduction of $549,000. If the Commission has any questions or is in need of additional documentation for these expenditures, BPXA would be pleased to provide whatever assistance is needed. .'!} _,j .1\ Dated this kL'day of January, 2005. Randal G. Buckendorf Attorney for BP Exploration (Alaska) Inc. /¡,./) ,~;; .¡ /'/ /~~ / ,r" J // ~(~:;:~/~.f' );'Â~/::~~/é;~~~(~~",' ( 'l·--j./;~~~---;, "---~-~ . 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" .", "', .. ,'" "", , ,~" ~!t~~~~~ ~f 'I;) ~~~~!:I ~ ******$1,112.00****** ALASKA OIL AND GAS CONSERVATION COMMISSION 333 WEST 7TH AVENUE, SUITE 100 ANCHORAGE, AK 99501-3539 · . .' 1 #2 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue, Suite 100 Anchorage Alaska 99501-3539 Re: BP Exploration (Alaska), Inc., as Operator of the ) Prudhoe Bay Unit; Prudhoe Bay Field; ) Well A-22 Enforcement Action ) ) AOGCC Order No. 029 November 15,2004 DECISION AND ORDER On December 11, 2003, the Alaska Oil and Gas Conservation Commission ("Commission" or "AOGCC") issued a Notice of Proposed Enforcement Action under 20 AAC 25.535(b), stating that it considered that BP Exploration (Alaska) Inc. ("BPXA") had violated 20 AAC 25.526 in connection with its practices in managing wells with sustained annular pressures, by failing to carry out operations and maintain the property in a safe and skillful manner in accordance with good oil field engineering practices. The Commission proposed civil penalties under AS 31.05.150(a) in the total amount of $2,530,000, plus a penalty for wasted gas under AS 31.05.150(e) in the amount of$I,112. BPXA requested informal review under 20 AAC 535(d). As part of the informal review, BPXA provided written submissions to the Commission and made an oral presentation to the Commission on April 15, 2004. Having now completed its review, the Commission issues this proposed Decision and Order. A. Background Early on the morning of August 16, 2002, previously shut-in Prudhoe Bay Well A-22 ("Well A-22"), operated by BPXA, failed catastrophically while being brought back into AOGCC Order #29 Page 2 of 10 November 15,2004 production. A rapid release of gas from below the pad surface led to an explosion and fire that seriously injured the pad operator employed by BPXA. The blast blew open doors of the well house, and the resulting fire continued for approximately six hours before it was brought under control. A subsequent investigation by the Commission examined information gathered through field inspections, meetings, BPXA's responses to AOGCC requests, public hearings, Commission review of well records, Commission review of BPXA operating policies and training programs, and interviews with operating personnel. This investigation disclosed the following: ] 1. Well A~22 exhibited historical pressure in the casing annuli prior to August 2002. Approximately 1,300 pounds of pressure per square inch (psi") was imposed in the inner casing annulus for artificial lift. Annulus pressure records indicated the historical outer casing annulus pressure to have been approximately 600 psi. 2. Pressure increased in the outer casing annulus from approximately 600 psi to approximately 1,900 psi sometime between July 24 and August 1, 2002. There was no available pressure information between these two dates and no information describing the cause of increased pressure in BPXA' s records, nor were any diagnostics performed to determine the source of the sudden outer casing annulus pressure increase or to evaluate the well for continued operation. 1 A copy of the Commission's investigative report dated November 17,2003 is attached hereto as Appendix "A". AOGCC Order #29 Page 3 of 10 November 15,2004 3. Well A-22's surface casing failed because the internal gas pressure exceeded the outer casing's burst capacity, and well A-22's surface casing burst approximately 17 feet below the well pad surface. 4. The excessive internal gas pressure was a direct result of heating during well startup, acting on relatively high initial outer casing annulus gas pressure. No evidence was found to suggest that any attempts were made to relieve annulus pressures from the well at the time the well was restarted, and outer annulus pressures at the time of restart were reported by separate sources as ranging from approximately 1,700 psi to approximately 1,950 psi. 5. At the time, a BPXA internal waiver process was used to allow wells to continue in operation with annulus pressure communication. A temporary waiver had been orally issued by BPXA on August 15, 2002, clearing Well A-22 to return to production. The justification for the waiver was high fluid level in the outer casing annulus and a high imposed inner annulus pressure, which BPXA incorrectly interpreted to represent well integrity. Diagnostic testing to support a permanent waiver for Well A-22 was scheduled but never occurred. 6. When Well A-22 was restarted, the pressurized gas that ruptured the surface casing vented up the space between the conductor and surface casing, blowing well house wood flooring and gravel upward. Sparks from flying debris or damaged electrical equipment ignited the escaping gas and started the fire. 7. A single operator per 12-hour work shift was responsible for three production pads, containing more than 100 wells and associated facilities. 8. No high-pressure hose was available at the site of Well A-22 or elsewhere on A- Pad with which to relieve casing annulus pressures. Therefore, prior to the explosion, the pad operator found it necessary to leave the well, and the production pad, unattended while he went AOGCC Order #29 Page 4 of 10 November 15,2004 to obtain a hose, from another pad, approximately 2 miles away, to relieve the pressure in the well's outer annulus. 9. The pad operator returned to the well, attempted to enter the well house, was caught in the blast and received severe injuries. 10. No engineering analysis or other technical framework was found in BPXA's annular pressure management policies or operator training actions prior to the Well A-22 failure that addressed the importance of controlling thermally induced well pressures prior to initiating well startup. 11. Pressure was not bled from the well prior to start-up. If the pressure in the outer casing annulus of Well A-22 had been appropriately bled, the final outer casing annulus pressure would not have approached the burst rating of the surface casing (5,380 psi) and this event would not have occurred. 12. Corrective actions to prevent future incidents similar to what occurred at Well A- 22 have been initiated by BPXA and the Commission, and are now in place. In its written submission and oral presentation, BPXA raised various issues relative to the existence of a violation and objected to the size of the Commission's proposed penalty, assuming the existence of a violation. These points are addressed below. B. The Violation of 20 AAC 25.526. Some time prior to August 16, 2002, pressure in the outer casing annulus of Well A-22 increased from its historic level of approximately 600 psi to approximately 1,900 psi, a pressure that equalized with and tracked the imposed gas lift pressure in the well's inner annulus. This indicates that the pressure being introduced into the inner casing annulus leaked into and became trapped in the outer casing annulus. There was no attempt to relieve this trapped pressure, and as AOGCC Order #29 Page 5 of 10 November 15,2004 the well was being restarted, heat resulting from restart of the well caused the fluids trapped in the outer casing annulus to expand and exceed the burst capacity of the surface casing. The central issue is whether this incident was an unforeseeable anomaly or whether it resulted from a negligent failure to observe good oil field engineering practices. BPXA contends that its then-existing policies and procedures were adequate and based upon sound engineering analysis. BPXA further contends that its policies in effect in August of 2002 set rigid minimum requirements for allowing a well with sustained casing pressure to remain in production, and that primary responsibility for monitoring well pressures rested with the individual pad operator. It is the Commission's opinion, however, that the policies cited by BPXA in defense of its practices in managing wells with sustained annulus pressures were used more as guidelines than as rigid standards, and were not consistently implemented or enforced by BPXA field supervisors. Moreover, BPXA's policies for bleeding down and monitoring annular pressures failed to address key issues. Nowhere in the record is there a credible explanation for why Well A-22 was allowed to be restarted with such high pressure in the outer casing annulus, or why this pressure was not relieved before restarting the well. BPXA states that a detennination was made that well A-22 could be returned to production safely "if outer annulus pressure was kept below 2,000 "psi." Yet Well A-22 was restarted at approximately 1,950 psi without proper equipment (a high pressure hose) readily available to pennit the predictable heat induced pressure increase to be relieved. Indeed, Well A-22, already at the threshold of BPXA's maximum pressure limit in the outer casing annulus, was allowed to continue to operate unattended for at least 5 hours. Nothing in the record indicates that the lone pad operator, who had simultaneous responsibility for more than 100 wells, was aware of the potentially disastrous consequences of restarting a well with pressure AOGCC Order #29 Page 6 of 10 November 15,2004 trapped in the outer casing annulus and the resulting effect that thermally induced high pressure could have on a well left unattended after restart. Nor does anything in the record suggest any latent defect in material - in fact, the well's casing actually withstood substantially greater pressure than it was rated for. There is no evidence of any unforeseeable external event, such as a lightning strike, that might be viewed as having caused this event. Rather, the casing failure and the resulting explosion and fire are, in the opinion of the Commission, the completely predictable and foreseeable outcome of managing this well in the way it was managed, given the pressure conditions of the well preceding restart. It is therefore difficult to accept BPXA' s argument that such management was consistent with good oil field engineering practices. BPXA has also argued that in August of 2002, its policies for managing wells with high outer annulus pressures were in strict compliance with the Commission's statutes, regulations and orders then in effect, because none of the Commission's requirements expressly addressed annular pressure issues. However, in August of 2002, the practice of the Commission was to rely upon each operator to manage annular pressures in accordance with good oil field engineering practices. Following this incident the Commission concluded it could no longer rely upon individual operators to self-employ good oil field engineering practices in annular pressure management, and the Commission enacted specific Conservation Orders establishing explicit annular pressure management requirements for Prudhoe Bay and other fields in Alaska. The fact that these specific orders were not in place at the time of this incident in no way relieves BPXA from its responsibility to carry out operations in a safe and skillful manner in accordance with good oil field engineering practices, as required by 20 AAC 25.526. AOGCC Order #29 Page 7 of 10 November 15,2004 C. The Penalty Amount. The Commission's proposed civil penalty totaling $2,530,000 was calculated by multiplying the maximum daily penalty allowed under AS 31.05.150 ($5,000) by the number of days from the most recent revision ofBPXA's annular pressure management policies (March 21, 2001) to the date of the Well A-22 explosion and fire (August 16, 2002). BPXA has argued the proposed penalty amount is excessive, for several reasons. First, BPXA argues that the Commission's maximum penalty should be reserved only for the most egregious violations, and that this case does not fall into that category. In past enforcement matters the Commission has identified five factors as among those that should be considered in determining the appropriate amount of a civil penalty. These are: (1) the good or bad faith of the operator in violating the law; (2) the injury to the public resulting from the violation; (3) the benefits derived by the operator from its violation; (4) the operator's ability to pay the penalty; and (5) the need to deter similar behavior by the operator and others in the future. After careful consideration of all relevant facts and the arguments presented by BPXA in its written submission, and at the April 15, 2004 informal review conference, the Commission is persuaded that although the potential - and in this case the actual - consequences of this type of violation are extremely serious, BPXA's acts and omissions here were not the result of bad faith. In addition, the Commission believes it is appropriate to take into account the extensive self- investigation conducted by BPXA to help determine the precise cause of this incident and also to consider BPXA's voluntary actions since the Well A-22 incident to develop new and better methods to monitor and manage well conditions. This incident was a costly and traumatic event AOGCC Order #29 Page 8 of 10 November 15,2004 for BPXA and its involved employees, and BPXA has responded to the experience by putting into place more stringent and specific operating requirements designed to avoid a recurrence of such an event. The Commission concludes therefore that imposition of the maximum daily penalty is not warranted in this case and has reduced the proposed penalty amount by one half. The Commission also notes that in the aftermath of the Well A-22 incident, BPXA voluntarily took a number of positive steps. Among these, one that may hold benefits for the entire oil industry in Alaska, is a Pilot Program begun in the winter of 2003-2004 to determine the feasibility of remote monitoring of outer annulus pressures, in real time. Although it is too soon to make any conclusions, this study could lead to utilization of new and safer technology in Alaska's oil fields. The record shows that BPXA has budgeted $549,000 for this program. Therefore, the Commission will allow BPXA to credit its actual expenditures on the Pilot Program, up to the amount of $549,000, against the civil penalties that are otherwise imposed by this Decision and Order. BPXA has argued that the penalty period is not reasonably related to this incident. However, the company policies that allowed this event to occur, arguably had been in place for far longer than the penalty period. The Commission chose however to look back only to the last clear opportunity BPXA had to enact and implement better annular pressure management policies, in March 2001, and the penalty was calculated using this date. Finally, BPXA argues that the proposed penalty is inconsistent with constitutional principles of due process and equal protection. In support of this argument BPXA cites testimony of other operators who at the time of this incident were following policies similar to those of BPXA, and it is implied that BPXA may have been unfairly singled out. The Commission disagrees. The Commission has approached this enforcement action even- AOGCC Order #29 Page 9 of 10 November 15, 2004 handedly. To the Commission's knowledge, no other operator's well has been allowed to develop avoidable annular pressures sufficient to rupture a casing. It is the incident, not the Commission's desire to penalize BPXA, which brought about this enforcement action. NOW THEREFORE IT IS ORDERED THAT: 1. BPXA shall pay to the Commission a civil penalty of $1,265,000 within 30 days from the date this Decision and Order becomes final; 2. The penalty amount specified in the preceding paragraph may be reduced by the amount that has been expended on the Pilot Program described in BPXA' s letter to the Commission dated May 28, 2004 (a copy of which is attached as Appendix "B), subject to a maximum reduction of $549,000, if within 30 days from the date this Decision and Order becomes final, BPXA provides to the Commission documentation of its actual expenditures on the Pilot Program; 3. Within 30 days from the date this Decision and Order becomes final, BPXA shall pay to the Commission $1,112 for the unauthorized venting (waste) of 1,053 thousand cubic feet of gas that occurred as a direct result of the Well A-22 incident; and 4. This Decision and Order shall, pursuant to 20 AAC 25.535(d), become final on the 30th day of November, 2004, unless on or before the 29th day of November, 2004, BPXA files with the Commission a written request for a hearing.2 If BPXA timely files a written request for a The normal time period has been extended because of the Thanksgiving holiday. AOGCC Order #29 Page 10 of 10 November 15,2004 hearing, this Decision and Order shall be of no effect, and the Commission will proceed to schedule this enforcement action for a formal hearing in accordance with 20 AAC 25.540. Done at Anchorage, Alaska this 15th day of ove I certify that c: // /5· (F/ ¡¡¡ copy '·...f ~'-o ""<~.~-,·"'ê:"'",:;,,;·~·¿, ... /(.,/'yf¡......... aaÑiI v ~n.... QW".··j", .,.··,,/tZ·,Oe:Ttl'l fW~ 01 t~Q ,;~~,?""":",, .. -. '["'";\r"';~¡' r:;i1~~ œ r=,;'(=ro:ns 07:t:..;¿ k: ~¿ ..._g~_Ci_~ / if' ------- Daniel T. Seamount, Jr., Commissioner Alaska Oil and Gas Conservation Commission Appendix "A" to AOGCC Order 29 dated November 15., 2004 Appended hereto is a copy of the Alaska Oil and Gas Conservation Staff Report regarding investigation of the explosion and fire that occurred at Prudhoe Bay Well A-22, on August 16, 2002. IuvestigatiouQfExplosion and Fire at Prudhoe Bay Well A-22 North Slope, Alaska August 16, 2002 Alaska on & Gas Conservation Commission Staff Report November 17,2003 ) Contents Section Acronyms Summary Incident Overview Background Information AOGCC Investigative Strategy Discussion Timeline Well A - 22 Restart Decompletion and Subsequent Study of Damaged Pipe Why Did A-22 Overpressure? Annulus Pressure Policy Reporting Potential Contributing Factors Regulatory Response to the PBU A-22 Incident Enforcement Appendix Chronology of Meetings, Information Requests, and Responses ) Page 2 3 5 5 5 8 8 11 12 14 15 16 17 19 19 1 BPXA AOGCC AAC PBU OA IA EOR SSV TAPS WIE TIO Psi SI DHD GC-3 F CO POP TIFL MITOA PPPOT-IC MSCF AS EWI ) ) Acronyms BP Exploration(Alaska) Inc Alaska Oil and Gas. Conservation Commission Alaska Administrative Code Prudhoe Bay Unit Outer Annulus Inner Annulus Enhanced Oil Recovery Surface Safety Valve Trans Alaska Pipeline System Well Integrity Engineer Tubing, Inner Annulus, Outer Annulus Pounds per square inch Shut in Downhole Diagnostics Gathering Center 3 Fahrenheit Conservation Order Put on Production Tubing Integrity Fluid Level Mechanical Integrity Test - Outer Annulus Positive Pressure Packoff Test - Inner Casing Thousand Standard Cubic Feet Alaska Statute Edison Welding Institute 2 ') ) Summary Early in the morning of August 16, 2002 previously shut-in Prudhoe Bay Well A-22 failed catas- trophically while being brought on production. A rapid release of gas from below the pad sur- face led to an explosion and fire that seriously injured a pad operator employed by the Prudhoe Bay Field operator, BP Exploration (Alaska), Inc. (BPXA). A subsequent incident investigation by the Alaska Oil and Gas Conservation Commission (AOGCC or Commission) examined information gathered through field inspections, meetings, BPXA responses to AOGCC requests, public hearings, Commission review of well records, Commission review of BPXA operating policies and training programs, and interviews with op- erating personnel. The investigation disclosed the following: · A-22 exhibited historical pressure in the casing annuli prior to August 2002. Ap- proximately 1,300 psi was imposed in the inner casing annulus for artificial lift. An- nulus pressure records indicated the historical outer casing annulus pressure to be ap- proximately 600 psi. · Pressure increased in the outer casing annulus from 600 psi to 1,900 psi sometime be- tween July 24 and August 1, 2002; there is no pressure information between the two dates, and no information describing the cause of increased pressure in BPXA re- cords. · A-22 surface casing failed because internal gas pressure exceeded the casing's burst capacity. A-22 surface casing burst approximately 17 feet below the well pad sur- face. Excessive internal gas pressure was a direct result of well heating during start- up, acting on relatively high initial outer annulus gas pressure. No evidence suggests attempts were made to relieve initial annulus pressures from the well, reported by separate sources as ranging from 1,700 to 1,950 psi. · High pressure gas from the A-22 outer annulus vented up the well's conductor by sur- face casing annulus, blowing well house wood flooring and gravel upward. Sparks from flying debris or damaged electrical equipment ignited escaping gas. · A pad operator who had been restarting A-22 attempted to enter the well house, was caught in the blast, and received severe injuries. · A single operator per 12-hour work shift was responsible for three production pads, containing more than 100 wells and associated facilities. Prior to the explosion, the operator found it necessary to leave the well, and the production pad, unattended. · A BPXA internal waiver process is used to allow wells to continue in operation with annulus pressure communication. A temporary waiver was verbally issued on August 15, 2002, clearing A-22 to return to production. The waiver basis was a high fluid level in the outer casing annulus and a high imposed inner annulus pressure, which 3 ) ) BPXA interpreted to represent well integrity. Diagnostic testing in support of a per- manent waiver was scheduled. . No engineering analysis or other technical framework was found in BPXA's annular pressure management policies, operator training literature, or field actions leading to the A-22 restart that addresses the importance of controlling thermally induced well pressures prior to initiating well startup. . Corrective actions to prevent future incidents similar to A-22 were initiated by BPXA and by the Commission. 4 ) ) PBU A-22 Accident Investigation August 16, 2002 Incident Overview At about 9:37 PM on 8/15/2002, Prudhoe Bay Well A-22 (A-22) was restarted following repairs to surface production equipment. About five hours later, reported as 2:12 AM, 8/16/2002, A-22 failed catastrophically. High-pressure gas in the well's outer annulus (OA)l was released through a surface casing burst 1 7 feet below the well pad's surface, upward through the 20" con- ductor by 13-3/8" surface casing annulus2. The rapid release of annulus pressure caused loose materials in the wellhouse (gravel, foundation boards) to impact and damage the production tree, controls, and lights, resulting in an explosion and fire. The explosion seriously injured the Field Production Operator (Pad Operator) who was responsible for the well's operation. Lift gas from A-22's inner annulus (IA)3 continued to jet through a damaged casing valve for several hours, until the annulus gas was depleted and response personnel regained well control. Background Information Prudhoe Bay Well A-22 is located in the Western Operating Area (WOA), and operated by BP Exploration (Alaska) Inc. (BPXA). Sohio Alaska Petroleum Company4 (Sohio) drilled A-22 in 1982 as a producing well. The well has produced nearly continuously since August 19845. Well design includes 20" conductor casing, 13-3/8" surface casing, 9-5/8':' production casing, 7" pro- duction liner, and 3-112" production tubing. Surface and production casing strings were success- fully tested to 3,000 psi at installation. The well is configured for artificial lift, provided by in- jecting gas down the IA under controlled conditions. A-22 gas lift began during December 1986. The Prudhoe Bay field is now undergoing enhanced oil recovery (EOR). Alternating volumes of water and enriched gas are injected via selected wells into the reservoir to raise pressure and sweep the producing zone of residual oil, increasing ultimate recovery. EOR began at A Pad in September 1985. Gas lift of A-22 was suspended in July 2002 since reservoir pressure had in- creased due to pressure support from the ongoing EOR, allowing the well to produce withQut gas lift. AOGCC Investigative Strategy The A-22 incident led the Alaska Oil and Gas Conservation Commission (AOGCC or Commis- sion) to investigate, seeking to determine (1) the incident's actual cause, (2) whether there is po- tential for another incident similar to A-22, and, if so, how it can be prevented, and (3) whether annular pressure regulations are needed. 1 OA - outer annulus; annular space between 13-38" and 9-5/8" casings in the well 2 The 20" by 13-3/8" annular space is open at the casing hanger in the wellhead and is not designed to be a pressure containing barrier 3 IA- inner annulus; annular space between the 9-5/8" production casing and the 3-1/2" production tubing 4 Sohio later became Standard Alaska Production Company, and finally BP Exploration (Alaska) Inc. S "Summary by Month: Individual Well Production"; PBU A-22; AOGCC database 5 ) ) AOGCC Petroleum Inspectors visited the site, documented the damage to A-22, and provided early insight into events. Periodic meetings with BPXA allowed AOGCC to gather infonnation about A-22 and monitor BPXA's internal. investigation. BPXA also provided information about other wells within Greater Prudhoe· Bay exhibiting annular pressures, including wells that were deemed to be most similar to A-22. These early meetings helped the Commission prioritize ef- fort into three principal focus areas: (1) Other wells - Numerous wells with ànnular pressures exist in the Prudhoe Bay Field. After the incident BPXA shut in numerous wells and others were targeted for integrity testing, diagnostics, or monitoring to assess risks related to annular pressures. Assess- ing the potential for another incident similar to A - 22 and detennining how to prevent such were AOGCC's highest priorities. (2) Regulation and inspection - Domestic and international regulatory strategies were re- viewed. Policies of Alaska well operators were assessed, culminating in a public hear- ing to detennine if annular pressure regulations were appropriate. The appropriate in- spection response to wells affected by annular pressures was also assessed. Pool rules were amended to address annulus pressure. (3) Enforcement - Investigation sought to establish if there are grounds for enforcement proceedings according to 20 AAC 25.535. An understanding of the precise A-22 failure mechanism was critical to each of the focus areas. To detennine the cause of failure, the Commission approved BPXA's request to decomplete A- 22. BPXA hired Edison Welding Institute, a reputable third party' with pipe failure expertise, to evaluate A-22's damaged pipe. The Commission reviewed the following infonnation during its A-22 investigation: (1) Well design - Permit to Drill and Subsequent Reports; casing and cementing records; pressure tests. (2) Drilling history - AOGCC records and BPXA infonnation. (3) Workover history - AOGCC records and BPXA infonnation. (4) Pressure history - BPXA data beginning August 2001; IA pressures imposed due to gas lift. (5) Safety devices - Surface safety valve (SSVs) test data. (6) Inspection reports - Inspections of the critical operations (equipment recovery, witness- ing pressure tests) during the Well A-22 decompletion. (7) Casing failure analysis6. 6 Edison Welding Institute, Project #46381 CSP-04 - "Analysis of A-22 Casing Failure" 6 (8) BPXA annular pressure policies. (9) BPXA training programs. In AOGCC several to assess the witnesses' then in effect. Gas lift Supply line ~ ~ Damaged valve- ~ Source of gas to fire Metal RectangUI~1 Cellar Box Packer at 10.821ft I I Rupture Point 17 ft Fluid Level 85 ft. Conductor Casing 20 in. Set at 80 Ft. Inner Annulus Outer Annulus Smface Casing 13 3/8 in. Set at 2,705 Ft. Packer set at 2605 ft 3-1/2" Tubing End ofTubing 10.909 ft Production casing 9-5/8 inset at ....... 11,389 ft ..... Trapp¡:d Gas Lift Gas Produced Fluids 7" Liner from 10,886 ft-12.316 it ~ ~ ~'W .... ~~ 111I - .. - Arctic Pack Cement Figure 1: Well Schematic 7 7 "Prudhoe Bay Well A-22 Incident Review", BP, September 17,2002 7 ) ') Discussion· Timeline. AOQCC met with BPXA periodically following the A-22 explosion, coincident with an ongoing~'BPXA investigation. Numerous information requests by AOGCC and responses by BPXA oC'Gurred during the early phase of this investigation. A chronology of these including a brief summary-is irtcluded in the Appendix. Figure 1 is a schematic of A-22 at the time of the incident, artriotatedwithinformation about the casing failure and fluids released. A timeline be- ginning July 24, 2:002 (Table 1) for A-22 was constructed. Dates, activities, and pressures used to construct the timeline did not always agree. After initial efforts to resolve the differences, it was deemedunnecessary to devote significant additional time since the differences do not impact overall findings. Recorded Prudhoe Bay well pressures are maintained in separate databases by BPXA engineers and by pad operators. BPXA's annular pressure database indicates no communication between A-22's casing annuli prior to July 24, 2002. The IA pressure (1300 psi) noted on July 24, 2002 was gas lift>pressure, which was maintained in the IA despite gas lift not being required. OA pressure reported in the BPXA database from August 2001 to August 2002 was approximately 600 psi. BPXA interpreted the pressure differential as demonstrating well integrity. Pressure monitoring, was apparently conducted each day, although data were not recorded between July 24 and August!, 2002. IA and OA pressures in the pad operator database between August 5 and August 15, 2002 were inconsistent with information in other data sources provided by BPXA. It remains unclear if pad operator pressures are actual readings or interpolations from previous readings. 8 The Trans-Alaska Pipeline System (TAPS) shut down on July 26, 2002 resulted in the shut in of A-22. Efforts to freeze protect A-22 for a short duration shut in included pressuring up the tub- ing with lift gas. High OA pressure was identified on August 1, 2002 with notification to the BPXA Well Integrity Engineer on August 4, 2002. It is possible that high OA pressure existed before August 1 but no information exists to confirm this. Completion of TAPS work and the re- start of processing facilities allowed A-22 to be restarted on August 5, 2002 with annular pres- sures bled frequently during the restart. No diagnostics were performed to determine the source of the sudden OA pressure increase or evaluate the well for continued operation. It is not possi- ble to determine, based on the information presented, if freeze protection had anything to do with the high OA pressure. There was also no explanation as to why three days elapsed between iden- tifying high OA pressure (exceeding the 1,000-psi OA pressure threshold established in BPXA policy9) and reporting to the Well Integrity Engineer (WIE) for an engineering analysis of the change in well conditions. A subsequent shut in of A-22 occurred on August 9, 2002 due to a compressor shut down at Gathering Center 3 (GC-3); that shut down lasted approximately two days. Subsequent well re- 8 "A-22 Casing Failure" - compilation of information provided by BPXA on August 23,2002; table titled "A-Pad Well Readings" 9 "Alaska Drilling and Wells, Standard Operating Procedure: Tubing/Annulus Communication and Annulus Moni- toring Policy" - Sections 5.1 and 5.2. Document is part of the BPXA "Standard Operating Procedure: Annulus Communication and Monitoring Policy"; revised 3/21/01 8 ) ) start was interrupted after 1.7 hours because of a leaking check valve in the A-22 flow line.lO No prolonged production occurred from A-22 until the well was again put on production on August 15, 2002. High OA pressure was noted on August 14, 2002 and the pad operator bled it. Notice was provided to the BPXA Well Integrity Engineer on August 15, 2002 after the OA repressured to 1,950 psi. Date 7/24/02 7/26/02 8/1/02 8/4/02 8/5/02 8/9/02 8/10/02 8/11/02 8/12/02 8/13/02 8/14/02 8/15/02 8/16/02 Activity/Event Producing A-22 shut in A-22 remains shut in A-Pad Operator notifies WIE of high OA pressure DHD crew bleeds OA pres- sure A-22 put on production A-22 shut in A - 22 remains shut in A-22 put on production A - 22 shut in after 1.7 hrs production A - 22 remains shut in A-22 remains shut in A-Pad Operator bled OA pressure (0030 - 0050 hrs) A-22 flow line "safed out" A-22 remains shut in Check valve replaced WIE contacted by A-Pad Op- erator about OA OA fluid level by DHD crew TIO Pressures (psi) 238/1300/600 Remarks No gas lift (since 7/02?); last docu- mented pressures prior to 8/1/02 TAPS shut down First documented evidence of OA track- ing IA pressure Pre-bleed pressures No data S1/2000/1900 SI/2000/2000 S1/2000/350 Post-bleed pressures 300/1500/500 GC-3 restart (TAPS work completed); pressure bled frequently during restart GC-3 compressor K-5500 shut down 300/1350/600 300/1350/600 300/1350/600 Compressor K-5500 back on line Flow line check valve leaking (source: production records) No data 300/1350/600 SI/?? /2000 SI/?? /200 Pre-bleed pressures Post-bleed pressures Prepare for check valve replacement S1/2000/1800 Flow line "safed in" @ 1600 hrs @1630 hrs; possible IA x OA commu- nication OA fluid level @ 85 ft TIO = 1840/2000/1950 psi WIE returns call to A-Pad 1735 hrs; ok to put on production; moni- Operator; "temporary waiver" tor OA; 2000 psi pressure limit A-Pad Operators change-out Debrief regarding A-22 condition A-22 put on production @ No data No gas lift (production records); well 2135 hrs temp 40F A-14 put on test No data 0150 hrs per Pad Operator notes A-22 explosion and fire No data 0210 hrs; Pad Operator injured Table 1: Well A-22 Timeline The WIE issued a temporary waiver (verbal) from the well operating in BPXA's annulus pres- sure policy on August 15, 2002 allowing A-22 to return to production with annular pressure up 10 "A-22 Casing Failure" - compilation of information provided by BPXA on August 23,2002; Production tab - "A- 22 Production Rates and SI Status" 9 to 2,000 pSi.ll BPXA's annular pressure management program aIIowed issuance of a temporary waiver, leading to a fuII waiver allowing wells to operate with annulus pressure communication. A temporary waiver could be issued for such conditions as a high OA fluid level; a penl1anent waiver required further diagnostics (tubing integrity fluid level, and mechanical integrity test of the OA).12 Statements made during interviews of the Pad Operator and the WIE indicate the ba- sis for A-22's temporary waiver was a high OA fluid level. BPXA policy for managing annular pressures required well evaluation if the OA pressure tracks IA pressure or requires more than 2 bleeds per week to keep the OA pressure under 1,000 psi. The policy further stated: "Best effort will be made to quickly eliminate the leak" and the "well will be shut in ifrepairs or diagnostic work have not been initiated within 72 hours." 13 Pressure was bled from A-22's OA on August 4, again on August 11 (during startup of production) and on August 14. Rapid OA repressurization noted on August 15 was not addressed by bleeding pres- sure prior to restart, but clearly placed the well into the category of requiring weII evaluation. Additional diagnostic tests for A-22 were ordered according to a written statement from the WIE to the BPXA Well A-22 Investigation Team dated August 22, 2002. 1 . HHHHH! miles Figure 2: General area of Prudhoe Bay Pads A, B and X 11 Caution tag - Control #041249; undated 12 Interview with BPXA Well Integrity Engineer, June 10,2003 13 "Alaska Drilling and Wens, Standard Operating Procedure: Tubing/Annulus Communication and Annulus Moni- toring Policy" - Sections 5.1 and 5.2. Document is part of the BPXA "Standard Operating Procedure: Annulus Communication and Monitoring Policy"; revised 3/21101 10 ') ) WëllA-22 Restart. There was no AOGCC notification or involvement in the A-22 restart. Two P'~â.f>perators working 12-hour shifts were responsible for wells and facilities at A, B and X p'~d.~.14 An estimated four miles separate A and X Pads, with Pad B lying between A and X Pads (F~$ry 2). The on-duty Pad Operator (at the time of A-22 explosion) testified as to his location iì?mit~e time A-22 was restarted to when he was injured. He had just begun a two-week tour of dUt~;'b~ginning with a 12-hour work shift at 6:00 PM August 15,2002. A turnover meeting was held between hÎmself and the Pad Operator rotating off duty. The on-duty Pad Operator was ad- vised that the WIE had verbally issued a temporary waiver clearing A-22 for restart. A-22 was placed on production at approximately 9:30 PM August 15, 2002. The on;.. duty Pad Operator believed that a high-pressure hose would be necessary to bleed pres- sure fromA-22 during restart. No high-pressure hose was then available on A-Pad, which the off-duty Pad Operator later confirmed. Operator discretion allowed the on-duty Pad Operator to leave A-22 unattended for several hours during restart. The on-duty Pad Operator then traveled to X-Pad to get a bleed hose. He bled high annulus pressures from several X-Pad wells and completed a "walkthrough". BPXA records indicate that four X-Pad wells had BPXA internal waivers as of August 15, 2002: X-04, X-08, X-18 and X-25. The on-duty Pad Operator also completed a "walkthrough" at B-pad and noted six wells with high annular pressures, and then returned to A-pad. There were no BPXA waivers on any B-pad well according to information available to AOGCC. Pad Operator notes15 identify recent annulus pressure activities on other A, B, and X pads: 8/8/02 B-26; X-27; X-36 pressure bled from casing annuli; 8/11/02 X-17 hydrocarbons bubbling in well cellar; A-56 internal leak; 8/13/02 B-30 tubing hanger lockdown screws leaking. The existence of several wells with internal waivers and other wells with high annular pressures appears to be consistent with statements made by the on-duty Pad Operator regarding the need to attend to X- and B-Pad wells. Five hours after production restart, at about 2:10 AM, 8/16/02, A-22's 13-3/8" surface casing failed about 17 feet below surface.16 The onO-duty Pad Operator testified he was opening the wellhouse door at approximately when the casing burst and was caught in the blast. He received severe injuries and was removed from location by BPXA's incident response team. Information gathered during interviews with Pad Operators and a Field Operations Team Lead, and from BPXA's pad operator training program, confirms there was broad operator discretion provided in well restart procedures. No specific engineering analysis or guidance addresses startup procedures or when pressures should be bled. A historical understanding of a well's "character" was one operating criterion mentioned by all those interviewed. For example, the on-duty Pad Operator stated that previous restarts of Wells X-18 and X-25 indicated that thermal effects, causing elevated pressures, were not significant for several hours. Well A-22 was con- sidered analogous to X-18 and X-25. Both X-pad wells were operating under BPXA internal 14 A-pad: 42 wells; B-pad: 36 wells; X-pad: 36 wells; facilities vary at each pad (control, manifold/valves, etc.) 15 "Handover Report on B-A-X Pads", August 8-15, 2002 16 "Well Pad A-22, Final Incident Summary, Investigation Closeout Meeting 12/20/02" 11 Subsequent Study of Damaged Pipe. AOGCC and repair QfA-22 on September 11, well integrity, and return the well to and components in A-22 to term decisions abou.t operating wells desired to identify any failure 600 psi to 1,900 psi) while A-22 was not explained the source of gas in the OA. to recover encouraged abou.t this can be im- increase of TAPS shut down. Figure 3: tubing split Commission inspectors witnessed critical ery of the tubing and damaged casing, tubing was recovered from the well, the A-22 decompletion, including recov- tests of the tubing, casing and packer. Split to detennine if it was a contributing factor in 17 September 11, 2002, letter forwarding approved #302-289 12 the incident. BPXA stated the tubing split was tl1e result·øf a stringshøt used tø remøve excess build up inside the pipe priør cutting øf.tubing før rerrwvalY Photograpl1s taken of.the split tub- ing 3) and the fact that nø liquid hydmcarbons were released fmm A-22 appear tø cøn- firm assessment. recørds før tubing and IA pmvide nø useful inførmatiøn øccurred due a leak. pressure was bled ftøm 15,2002. There nø recørd gests that gas was bled. øf a leak in the 9-5/8" the cømmunicatiøn remained by BPXA during the decøm- pletiøn and repair øf There is nø BPXA evaluated this pøssible cømmunica- tiøn as suggested in the Cømmissiøn's September 11, 2002, letter approving A-22 decømmis- siøning and repair. Figure 4: Damaged surface casing recøvered ftøm Well A-22 Visual examinatiøn øf recovered 13-3/8" surface casing (Figure 4) revealed nø apparent cørrø- siøn ør wear; bøth were identified as pøssible reasøns før pipe failure early in the investigatiøn (beføre the pipe was recøvered). The pipe was bulged øver a distance øf 15 feet, with a ragged split, cønsistent with a high pressure burst. A 32-føøt sectiøn øfpipe was sent tø Edisøn Weld- ing Institute før detailed mechanical testing and measurement, metalløgraphy, and chemical analysis. Full scale burst testing øf a døwnstream sectiøn øf the recøvered pipe was perførmed. The burst testing replicated the actual failure (ductile rupture) and demønstrated a measured 18 Email from WIE (BPXA) dated June 14,2003 13 ) ) burst for the A-22 surface casing of approximately 7,700 pSi.19 The fact that the actual burst pressure is significantly higher than the published burst is expected, given the safety factors in- volved. Why did A-22 overpressure? AOGCC evaluated the effect of temperature on annulus pressure in A-22. BPXA presented information about the thermal effects of well startup during a hearing in response to Conservation Order 48320, held to determine if regulations governing annulus pres- sures in Prudhoe Bay wells were appropriate. AOGCC used an in-house mathematical simulator to approximate OA pressure in A-22 as a function of temperature. AOGCC developed the simu- lator, which utilizes Boyle's and Charles's Laws to calculate gas pressure changes as a result of temperature and volume changes, and a coefficient of thermal expansion to calculate liquid vol- ume changes resulting from temperature changes. The following assumptions were made: (1) rigid well casing; (2) ideal gas behavior; (3) non-varying liquid coefficient of expansion with changing pressure. AOGCC calibrated the simulator based upon observed A-22 end point pres- sures and temperatures. Wellbore dimensions and specifications were gathered from AOGCC well records and verified with information provided by BPXA after the explosion. A-22 OA flu- ids consisted of arctic pack21 on top of a column of cement. The OA fluid level was measured at 85 feet below the wellhead. 8000 7000 6000 '¡¡¡ 5000 Co a; ~ 4000 en CI) ... a. « 3000 o ~ ~ 2000 1000 o o 10 20 30 40 50 60 70 80 90 Delta T, deg. F Figure 5: A-22 OA Pressure as a Function of Temperature Change; 1,900 psi initial pressure 19 Edison Welding Institute, Project #46381CSP-04, "Analysis of A-22 Casing Failure" 20 Hearing record for CO 483 21 Arctic pack - fluid mixture consisting of diesel and bentonite used to freeze protect a well through the pennafrost 14 -) ) Figure 5 represents calculated A-22 OA pressure and temperature as the well was being started. Initial OA pressure was 1,900 psi and initial temperature was about 40° F. No pressure was bled from the well prior to startup. As warm produced fluids flowed, A-22 heated from its initial temperature to its eventual in-service temperature of about 116° F (historical information). The resulting temperature change, or delta T, was 76° F. Figure 5 reveals that as A-22 heated, the published burst pressure rating of the well's surface casing22 (5,380 psi) was exceeded at a delta T of about 68° F. In other words, the burst rating was exceeded before the well had reached its historic operating temperature. Figure 6 illustrates the effect of a lower initial pressure on the final OA pressure at in-service temperature. The initial OA pressure of 600 psi corresponds to a final OA pressure of less than 2,500 psi at maximum delta T. 2500 2000 ëñ Q. 1500 ti ~ :3 II) II) () ~ D.. « 1 000 o ~ 500 o o 10 20 30 40 50 60 70 80 90 Delta T, deg. F Figure 6: A-22 OA Pressure as a Function of Temperature Change; 600-psi initial pressure If the OA pressure in A-22 had been bled to the historic value (600 psi), the final OA pressure would not approach the published burst rating of the surface casing (5,380 psi), and would have been about one-third the actual failure pressure (7,700 psi). In fact, OA pressure probably would not have exceeded the casing pressure test (3,000 psi) performed before A-22 was placed in ser- vice on August 15,2002. Annulus Pressure Policy. A copy of BPXA's annulus pressure management program (policies and procedures) was provided to the Commission on August 23, 2003. The program was appli- 22 API Bulletin 5C2, "Bulletin on Performance Properties of Casing and Tubing"; API grade L-80; 13-3/8", 72 lb/ft 15 ") ) cable to wells in Greater Prudhoe Bay, Greater Point McIntyre, and Niakuk fields. The stated purpose of the BPXA policy was to "ensure wells with mechanical problems are identified, evaluated, and monitored in a timely and consistent manner." BPXA's policy includes responsi- bilities of key personnel, and requirements that must be demonstrated for continued well opera- tion. The policy further establishes an internal (to BPXA) waiver process for wells that do not meet operating criteria. The Commission reviewed BPXA's annulus pressure policy as it relates to the events leading to A-22 failure. The engineering basis for decision criteria and pressure triggers was also assessed. Hearing testimony preliminary to CO 483 provided additional opportunity to gather infonnation about the policy and practices used at Prudhoe Bay. Responding to questions about the policy evolution, specifically the imposed annulus pressure triggers, BPXA noted that the basis for the current pressure triggers is a combination of operating experience, BPXA and Arco well integrity practice, and the "range of operability that we were seeing on those annuluses." Well A-22 raised questions about the decision process used to detennine when a well is no longer safe to operate. Responding to questions posed by the Commissioners in the November 14, 2002 hear- ing, BPXA stated that their decision procedures have been developed over time with reliance on case-by-case reviews and comparison to actual experience. They further stated no fonnal engi- neering or risk assessment has been perfonned by BPXA as part of the policy evolution that al- lows leaks across multiple casing barriers and the maintenance of high annulus pressures.23 AOGCC's review of BPXA's policy and the statements about operating limits, coupled with the actions implemented at A-22 prior to explosion, suggests that BPXA emphasizes continued op- eration of wells exhibiting annular communication, by issuance of an internal waiver, in prefer- ence to repair of the wells. Further evidence of this is the diagnostic testing protocol (including types and sequence of tests, and acceptance criteria) practiced by BPXA in detennining a well's competence for continued operation.2 Reporting25 On August 16, 2002 BPXA provided the Commission with verbal notice of an explosion and fire at Prudhoe Bay A-22. A written "Notification of Uncontrolled Natural Gas Release" followed later that day, summarizing the event and reporting the release of 1.035 million cubic feet of natural gas. BPXA provided Spill Reports on August 18, 2002 (initial) and September 16, 2002 (final), noting that there were no liquid hydrocarbons released during the event. By letter dated August 27, 2002 the Commission reminded BPXA of the obligation to file a final written report within 30 days, detailing the incident. BPXA submitted a final "Notification of Uncontrolled Natural Gas Release" on September 16, 2002. An incident review report was pro- vided on September 17, 2002, in a slide presentation fonnat. On December 23, 2002 the BPXA Law Department faxed to AOGCC a document titled "Key Findings of a Final A-22 Incident Investigation" with a cover letter from BPXA's principle 23 Transcript of Proceedings, Public Hearing, November 14,2002 24 Transcript of Proceedings, Public Hearing, May 27, 2003 2520 AAC 25.205 16 ) ) Commission contact regarding A-22. The letter notes that BPXA "now considers its investiga- tion to be closed." The "key findings" document was a paper copy of a slide presentation sum- marizing the incident, the response, BPXA' s investigation, contributing factors to the incident, system causes, and recommendations and action plans. Potential Contributing Factors The immediate cause of A-22 failure and explosion was thermal expansion acting on a high an- nular pressure that had not been bled down before well restart. Pressure communication in A-22 resulted in an OA pressure increase from a historical value of 600 psi to 1,900 psi, a pressure that equalized with and tracked the imposed gas lift pressure in the IA. Several attempts to relieve pressures between August 4 and August 14 (while the well was static) demonstrated OA repres- surization, evidence of significant pressure communication or leak (failed pressure barrier). As the well was brought into production on August 15, 2002 warm reservoir fluids created thermal expansion of the fluid in the closed annular space, increasing pressure. The thermal effects of producing the well without pressure relief resulted in an OA pressure exceeding the burst capac- iti6 of A-22's surface casing. Analysis shows that pipe failure was induced by overpressure. The following potential contributing factors are noted: 1. Tubing and Casing Material Quality. Wells are designed to fail inward ( collapse) such that pressures remain contained and controlled within the wellbore. Tubing integrity in A-22 was demonstrated by the lack of continued feed of gas after the explosion and the ability to withstand increasing pressures in the IA and OA during production restart. Tubing integrity does not ap- pear to have been a contributing factor to the failure of A-22, based on the available evidence. Initial concerns about 13-3/8" casing wear (from drill pipe movement while drilling the well) and corrosion or stress cracking (induced by chemicals in drilling fluid and formation) were also eliminated as possible factors in A-22 failure based on engineering studies of the recovered pipe by Edison Welding. 2. BPXA Annular Pressure Policy and Procedures (a) Emphasis on Allowing Continued Operation. BPXA statements during an annular pres- sure rule hearing indicate well leaks leading to elevated annular pressures are routine. Re- sponding to Commission questions during the Conservation Order 483 hearing regarding op- erating a well with annular pressure communication, BPXA experts stated: "by necessity it has been a good oilfield practice simply because so many wells do have annular pressure of some type. It is just a common occurrence, and so monitoring that and then operating, hav- ing a prudent method of operation is very definitely good oilfield practice.,,27 The delay in notice to the Well Integrity Engineer, and apparent lack of diagnostic and engineering work in support of issuing a waiver may reflect a relatively low priority placed by BPXA on re- solving annular pressure issues at the time A-22 experienced the failure. (b) Lack of Clarity and Understanding Related to Problem Well Restart. Those interviewed during the investigation expressed their belief that policies were clear for wells with high OA 26 As compared to the published minimum internal yield pressure of 5,380 psi used in designing the well 27 "Transcript of Proceedings", Public Hearing in response to CO 483, November 14,2002 17 ) ) pressure. However, that does not appear to be the case, particularly with regard to the role of bleeding pressures. While there were references in BPXA training program documents and policies then in place that mention bleeding pressures as a diagnostic tool, for managing pressures during well start, and for avoiding failures that would result in costly repairs, what is missing is a clear expression of the importance of bleeding pressures prior to start-up to offset the effects of well heating. It also appears that the WIE and the two Pad Operators had different understandings of the basis for allowing A-22 to be restarted with an internal BPXA waiver. For example, the off- duty Pad Operator (at the time of A-22 restart) stated an operator should remain at the loca- tion until the well is stable, meaning temperature and pressures remain constant for a period oftime,zs The on-duty Pad Operator referenced Wells X-18 and X-25 as providing historical experience thought to be relevant to the restart of A-22 (i.e., A-22 would behave similarly to X-I8 and X-25 during restart).29,30 He left A-22 after placing it on production to get a high- pressure bleed hose and attend to other duties based on his understanding and historical ex- perience. The potential implication to the startup procedure due to the fact that the pressure characteristics had changed was not clearly addressed in the information provided to the Pad Operators. Information provided to the Pad Operators may have been interpreted as suggesting that the annular pressures might decrease, rather than increase, as the well warmed up. There was no instruction provided regarding A-22 IA pressure (monitoring, bleed off, etc.) despite the pre- start pressure in the IA at the pressure limit (2000 psi) as established in BPXA's policy. Nothing regarding the IA pressure was noted in the temporary waiver or the caution tag pre- pared by the WIE. The engineering basis for statements about pressures decreasing was un- substantiated in information provided to the Commission, and may have provided the Pad Operator additional justification for leaving A-22 unattended during startup. (c) Degree of Flexibility and Discretion in Implementation. According to testimony, proce- dures in handling the same well conditions varied among the Pad Operators. BPXA' s pres- sure management policies were apparently used as guidelines rather than engineering stan- dards. BPXA's "key findings" from an internal investigation state: "Procedures for bleeding down and monitoring annular pressures did not fully address key issues and were not consis- tently implemented in the field.,,3l Examples of the apparent discretion in how annulus pres- sure management was approached included: Pressure thresholds (1,000 psi OA; 2,000 psi IA) that trigger actions treated as guides rather than rigid standards; No diagnostics for OA pressure that increased on or before August 1; Attempt to restart production in A-22 on August 4 without a waiver or diagnostics; Pressure bleed procedures as implemented by BPXA not a diagnostic tool as under- stood by the Commission; Delayed reporting of pressures exceeding pressure thresholds; 28 Interview dated July 25, 2003 29 Interview dated May 27, 2003 30 Wells X-I8 and X-25 had internal waivers due to IA by OA communication and high pressures 31 "Well Pad A-22, Final Incident Summary, Investigation Closeout Meeting 12/20102" 18 ) ) Daily pressure checks and/or reporting"not conducted from July 25 through July 31 and questionable and inconsistent pressures from August I through August 15 (in multiple data sources reviewed by the Commission); No evidence of engineering analysis to predict the expected consequences from physical actions taken in the restart of A-22 (as it existed on August 15). This level of discretion in managing well pressures, and specifically how to restart a well with high OA pressure appears to have been a contributing factor to the A-22 failure. 3. Operator Training. BPXA's training program lacked clear engineering-based guidance re- garding trouble wells. Information reviewed by the Commission shows general discussions about the importance of maintaining pressures in wells, but requirements for bleeding pressures prior to well start and continuous operator presence during restart, etc., are absent from training programs. 4. Workload/Personnel Resources/Work Prioritization. The Pad Operator had simultaneous re- sponsibility for three well pads (more than 100 wells and associated facilities - valves, controls, etc.). BPXA did not establish priorities regarding activities associated with well startup. Regulatory Response to the PBU A-22 Incident Shortly after A-22 failed, the Commission sought and was provided information regarding other wells with annular pressures in the Prudhoe Bay Field. Because of the early emphasis on deter- mining the cause of A-22 failure, and the priority of minimizing risk of similar occurrences, the Commission determined to impose rules at Prudhoe Bay regarding annular pressure manage- ment. The Commission deemed it inappropriate to continue self-regulated annular pressure management as was previously practiced by BPXA. Conservation Order 492, published on June 26, 2003, establishes annular pressure management requirements for the Prudhoe Bay field. Rules for other producing fields throughout the state have also been developed or are in the proc- ess of being developed. Included in CO 492 are rules requiring daily monitoring for sustained annuli pressures, notification of the Commission and corrective action when annuli pressures ex- ceed specific triggers, and pressure relief prior to placing the well in service. Inspection activities have also been enhanced to gather information about wells affected by an- nular pressures. Commission staff now has oversight, and the opportunity to validate, an opera- tor's procedures rather than relying solely on the operator for well integrity assurance. Commis- sion Inspectors continue to perform random inspections of well starts and the equipment used to bleed pressures from casing annuli to make sure it is maintained. Increased surveillance and AOGCC involvement in well operation through annular pressure management rules imposed by Conservation Order should provide early warning of potential problem wells. Annulus pressure management practices that are consistent with these rules should prevent the recurrence of a failure similar to Prudhoe Bay Well A-22. Enforcement The Commission should assess enforcement options based on the results of this investigation. 19 APPENDIX ) ) Chronology of Meetings, Information Requests, and Responses A series of meetings between AOGCC engineering staff and BPXA were held beginning August 16, 2002. Frequent contact was maintained with BPXA personnel during the first 2 months to address questions as they were identified in the AOGCC investigative review. August 16, 2002 - Notice of Event AOGCC Inspector visits BPXA Incident Command Center; visits A-pad once safe to access area; photos of Well A-22 wellhouse AOGCC engineering staff review well file (casing and cement records); discussions with BPXA Well Integrity Engineer to gather information about incident Teleconference briefing by BPXA about incident; BPXA initiated investigation o AOGCC invited to participate in BPXA investigation; decision made by Commis- sion to perform independent investigation August 18, 2002 - Spill report Initial report; no hydrocarbons spilled August 19,2002 - Teleconference Status Update AOGCC schedules technical meeting with BPXA AOGCC develops outline for technical meeting; focus on history of A-22, incident as it occurred, diagnostic procedures, policies for wells with annular pressures, other wells with similar conditions August 22, 2002 - Meeting Agenda Forward email agenda to BPXA; technical meeting August 23, 2002 - BPXA Investigation Team AOGCC engineering staff met with key personnel ofBPXA investigation team; pri- mary BPXA point of contact for Commission inquiries established Immediate cause of event identified as failure of 13-3/8" casing o Baroscope confirmed split in 13-3/8" casingaf""'-'17 ft below surface Draft incident report prepared by investigation team; tinder review by BPXA man- agement and legal personnel AOGCC provided data book labeled "A-22 Casing Failure"; compilation of technical background data gathered by the Well Integrity Group (pressure history, well work history, photos of the well site, supporting information about the well and production tree, BPXA policies for wells with annular pressure communication) BPXA addressed points per AOGCC request o 123 wells identified as having annular communication requiring BPXA inter- nal waiver; 7 shut in to date due to rapid communication o Additional shut-ins not discussed; assessing mechanical integrity of 123 wells o Further technical discussions necessary as BPXA proceeds APPENDIX ) ') August 24.2002 - BPXA Notification of Well Shut-ins BPXA notifies Commissioner Taylor of intent to shut in wells based on recommenda- tions of their internal investigation team o 9 wells shut in to date - have rapid tubing by IA communication o 125-130 wells with OA pressures will be shut in; · Wells are currently on BPXA internal waivers August 27.2002 - AOGCC letter to BPXA requesting infonnation Additional infonnation necessary to accomplish the objectives of AOGCC investiga- tion into Well A - 22 incident o Cause of this incident AND how future incidents of this type can be prevented Requested infonnation regarding the wells shut in by BPXA in response to Well A-22 explosion, fire, injury of pad operator; also the decision criteria for selecting wells and restarting production; diagnostics to confinn well integrity August 29.2002 - BPXA Response Provided list of wells shut in by BPXA Developing decision criteria - which wells restart production; procedures for startup o Will be communicated to AOGCC before production initiated September 3.2002 - Status update meeting with BPXA Engineering staff only from AOGCC and BPXA o No additional documentation provided Overview ofBPXA investigative efforts to date o Root cause analysis summarized including primary and contributing factors o Still unanswered questions as to why the 13-3/8" casing failed Verbal summary of recommendations from BPXA investigation team Tentative plans by BPXA to restart production of shut-in wells September 4. 2002 - Infonnation exchange by electronic mail BPXA advised that written procedures for diagnostic testing, startup and monitoring are required before production is restarted Waiver well classification used to detennine which wells are shut in Copy of BPXA Safety Bulletin provided September 6. 2002 - Well diagnostics and restart procedures AOGCC receives and initiates review of procedures: o Production well nonnal startup o Monitoring annulus pressure o Wells with annular pressure communication September 6.2002 - Sundry application - AOGCC receives and initiates review of work over for Well A-22 o Sundry Application Fonn 10-403 11 APPENDIX ) ) September 7.2002 - Meeting to discuss procedures Engineering staff only from AOGCC and BPXA Clarification about diagnostics, integrity testîng, and startup and operating procedures o Establish mechanical integrity bounds by pressure testing · Test to 120% of the maximum allowable operating annular pressure . Max allowable pressure equivalent to gas lift pressure o Pressure bleed-offs; manning requirements for restarts AOGCC approval for subset of wells to restart production o 33 wells require additional analysis before restart Advised that Finàl Incident Report per 20 AAC 25.205 is due 9/16/02 September 9. 2002 - Written Authorization Engineering review completed on Well A-22 Sundry application for workover Written approval documenting verbal approval granted 9/7/2002 to bring subset of shut in wells and conditionally approved workover sundry application from AOGCC September 11. 2002 - Rig workover Sundry application approved; forwarding letter to BPXA W orkover operations commence September 13. 2002 - Status update; more wells identified with annular pressures Training offield personnel (Pad Operators) completed 20 wells to date completed restart process o Only 9 producing due to other production facility shut-ins (Gathering Center 2 and Flow Station 1) o AOGCC Inspectors witnessing restarts to validate procedures implemented as described Well 13-34 restart did not meet criteria (IA and OA pressures tracking); well shut in Pad Operators report 126 additional wells with annular pressure exceeding 1,000 psi o Pad Operators directed by BPXA to diagnose pressures September 16.2002 - Status update Only 40 of 126 new wells with annular pressures have OA pressures; remaining have IA pressures only o 8 wells on previous list (shut in) Continuing diagnostic testing Re-waiver all wells o Tubing integrity and casing pressure tests September 19. 2002 - Inj ection wells shut in Confinn 137 wells shut in after A - 22 incident Identified 8 inj ectors shut in as part of original 137 wells # wells that have completed restart sequence o 47 reviewed; 25 producing - impacting 27,000 bpd Discuss timing for analysis of damaged casing 111 APPENDIX ) ') September 20. 2002 - Public Hearing notice Consider rules governing annular pressure management at Prudhoe Bay October 1.2002 - Status update W orkover results to date o Ultrasonic, camera, caliper surveys o Cut and recovered 45- foot section of casing; prep part of recovered pipe for transport to Edison Welding Institute for detailed study Have not yet interviewed on-duty Pad Operator injured in explosion at family request; released to long tenn care facility; expected to be home in 3 wks Startup procedures are now policy compared to interpretive guideline prior to A-22 Tubing split? BPXA has no plans to evaluate October 3.2002 - Status update Status of original 137 wells shut in Additional 125 wells identified with annular pressure; not shut in W orkover update October 8.2002 - Workover completed October 22. 2002 - W orkover report Report of Sundry Well Operations (Fonnl0-404) received; summary of work over November 14.2002 - Annular Pressure Rule Hearing Testimony by BPXA, AOGA December 19.2002 - Status update BPXA investigation closed EWI testing revealed casing failed at 7700 psi Will check to see if EWI report can be released to AOGCC BPXA interviewed injured Pad Operator; could not remember much about accident December 20. 2002 - Letter to BPXA; pre-explosion events Questions regarding BPXA actions leading up to A-22 explosion December 20. 2002 - Letter to on-duty Pad Operator Commission would like to discuss A-22 events December 20. 2002 - Letter to PACE Union Commission available to discuss A-22 infonnation PACE believes is relevant January 16. 2003 - Annular Pressure Rule for Prudhoe Bay CO 483 published; a rule for Greater Prudhoe Bay addressing annular pressure man- agement practice is appropriate tv APPENDIX ) ) February 14.2003 - Response to December 20,2002 letter Copy of EWI report provided, Pad Operator notes provided Responses to questions posed by AOGCC May 20. 2003 - Interview letters Letters to on- and off-duty Pad Operators, and WIE requesting interviews May 27. 2003 - Interview with on-duty Pad Operator June 10. 2003 - Interview with WIE June 26. 2003 - Interview letter Letter to Field Operations Team Lead requesting interview June 26. 2003 ~ Subpoena served to off-duty Pad Operator June 26. 2003 - Annular Pressure Rule CO 492 published; annular pressure rule for Greater Prudhoe Bay Regulatory oversight Monitoring Pressure thresholds for notification and corrective action July 24. 2003 - Interview with Field Operations Team Lead July 25.2003 - Interview with off-duty Pad Operator August 21. 2003 - Policies, procedures and training BPXA provides policies, procedures and training documents in place at time of A-22 incident Included is information provided to State of Alaska Department of Labor and Work- force Development, Occupational Safety and Health v A - 22 Report ) ) Subject: A-22 Report From: lody Colombie <jody_ eolombie@admìn.state.ak.us> Date: Fri, 12 Dee 2003 13:50:08 -0900 . 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Content-Type: applieationlmsword· enforcement notice a-22.doc C E d· b 64 - - ontent- nco lng: ase ..................................................................,.........,.......... ...... ........................................ ...,...........................................................,........,............,........... ........................................,....... ..,......................................... Content-Type: applieationlmsword release cover note.doc C E d· b 64 ontent- nco lng: ase ._---~._-_._._._._-_.._._._--_._~_.__..._........_-_._.- 1 of 1 12/12/2003 1 :55 PM ) ) Appendix "B" to AOGCC Order 29 dated November 15, 2004 Appended hereto is a copy of a letter from BPXA dated May 28, 2004 describing the Pilot Program. bp ) ) '"t , :t " BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 May 28, 2004 Hand-delivered RECEIVED MAY 2.8 2004 John K. Norman, Chair Daniel T. Seamount, Jr., Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Ste. 100 Anchorage, AK 99501-3539 Alaska Oil & Gas Cons. Commission Anchorage Re: Response to AOGCC's 5/11/04 letter re Remote Monitoring of Annulus Pressures Dear Commissioners: This letter responds to your letter of May 11, 2004 requesting additional information on the options BPXA has studied for mechanically monitoring and relieving annulus ,pressure, and the remote monitoring pilot project at Prudhoe Bay's X pad. The detailed answers to your questions are contained in Attachment 1, and we would be happy to meet with you or members of your staff to provide more information as requested. Before responding to the specific questions, I would like to provide some background information. Our goal is to determine whether mechanical options are viable for monitoring and/or relieving annular pressure in Prudhoe Bay development wells. Several prerequisites exist that must be met for any option to be considered viable. For example, it must be viable over the long-term; provide accurate data; be capable of determining that the systems are fully functional; withstand the effects of arctic conditions; comply with existing statutes, regulations and orders; provide increased protection or other benefits over the systems currently in place; be reasonably cost effective; and most importantly, it must not introduce new risks. Further, any option must augment the protection offered through the enhanced administrative controls (well start-up, operating and monitoring procedures) that were strengthened following the A22 investigation. In early 2003, we performed an engineering evaluation that resulted in a number of options for remote monitoring and relief of outer annular (OA) pressure. These options included automated pressure relief, automated production shutdown, and automated monitoring and alarms. A list of the options reviewed, as well as other options considered to reduce the risk of annular pressure problems is provided in an attached spreadsheet entitled, GPB Outer Annular Pressure Options. Our engineering group and pad operators evaluated each of these options, and five on- site meetings with the Western Operating Area pad operators were held to incorporate feedback ) .~ J '-i 'May 28, 2004 Page 2 from a broad base of operations staff. BP's global engineering network assisted in the evaluation based on their experience outside Alaska. Based on this evaluation and the feedback from operations, a remote monitoring option was determined to have the best potential for improving detection (and thus control) of annular pressure, while having the least likelihood for generating additional risks. The reviewers determined that remote pressure relief options introduced additional reliability risk. For example, many components would require heat tracing to prevent freezing or hydrate problems. This is of particular concern on stagnant lines such as relief lines that are more susceptible to freeze problems. Another concern is that annular relief systems would bypass the well's existing surface safety valve system and introduce risks associated with emergency well control. A pilot program was authorized at a cost of $549,000.00 to assess two designs for remote monitoring of outer annular pressure in real time. While the purpose of each design is the same (to monitor annular pressure), each of these designs utilizes a different method for potentially mitigating the anticipated problems associated with freeze-up or hydrate plugging: The two different methods involve: 1) a conventionally threaded pressure transmitter that utilizes electrical heat trace; and 2) a flanged diaphragm seal connected pressure transmitter that relies upon heat transfer from the wellhead, and eliminates short sections of small diameter piping (nipples) that are often freeze prone. The goal of this pilot is to test the reliability of the system over the long term; the potential for freeze-up or hydrate plugging; and, methods for potential mitigation of any such problem. The two designs minimize the amount of equipment exposed to freezing and hydrate potential compared to the other alternatives considered, while offering the potential for early detection of annular pressure problems. Our experience on the North Slope has shown that the severe arctic conditions materially impact the reliability of mechanical, hydraulic. and electronic devices. Therefore, any engineered solution must decrease risk beyond that of the enhanced administrative controls that were put into place by BPXA following the implementation of Conservation Order 492. When BPXA authorized the pilot project, we did so with the knowledge that the technical success of the pilot would not necessarily reflect larger scale viability. However, as we continue to modify and incorporate automation solutions for the field, technical success of this pilot might enable us to integrate this kind of monitoring into other automation and construction projects. The evaluation and selection of the remote monitoring option and the implementation of the pilot project have been important steps in this evaluation. Our understanding of the risks and benefits of engineered control of annular pressures has matured. However, a detailed evaluation of the pilot results and risk analysis is necessary to outline the basis for further steps. The pilot program began in the middle of the 2003-04 winter. Because we anticipate problems associated with arctic conditions, it will be important to gather data over a full winter ) ) '"1 .May 28, 2004 Page 3 season (2004-05). The results of the pilot, and potential next steps will be analyzed and discussed with our field personnel and with the Commission. If you have additional questions, please do not hesitate to contact me at 564-5671 or Bruce Williams, OPB' s Operations Integrity Manager at 564-4632. BJW/MLJ/pj Enclosures: BPXA's Responses to AOOCC's 5/11/04 Letter GPB's Potential Annular Pressure Options ) ) "¡vlay 28, 2004 Page 1 Attachment 1 BPXA's Responses to Questions Contained in 5/11/04 AOGCC Letter 1. The basis for selection of the X-pad wells. X pad was chosen because several wells have outer annulus pressure waivers, and because X pad has the necessary electrical power and control wiring for the monitoring devices. 2. Installation date and test period. Four wells were fitted with conventionally threaded transmitters with electrical heat trace and standard fittings (X-08, X-09, X-IS, and X-19) by January 17, 2004. Four wells were fitted with silicone filled, diaphragm seal connected transmitters [X-OS, X-09, X-18, & X-25] by February 10, 2004~ The test period began upon installation and is currently in progress. 3. Specific well parameters being measured. The outer annulus pressure. 4. Accuracy of measuring and transmitting devices. The calculated error (for the both transmitters is reported to be no more than 8 - 10 psi with a temperature swing from -50 to + 150 deg F, for a transmitter span of 3000 psi. 5. Field personnel access to information and how the information will· be used by Pad Operators, Well Integrity personnel, others. All control room operators, well integrity engineers and well pad operators have access to the infonnation. If the information is found to be reliable, it is likely that these personnel will use it more widely. Currently, the infonnation is being used by the pilot project personnel to evaluate the pilot. 6. What in BPXA's opinion will constitute a successful pilot project? A successful pilot program will be signaled by a better understanding of technical and administrative issues associated with the engineering controls. This is expected to take more than a single winter season test cycle. The results of the pilot will be factored into the risk analyses to determine what next steps might be appropriate and provide the basis for evaluating the costs, risks and feasibility of the installation of remote annular pressure monitoring devices in specific Prudhoe Bay wells. As discussed earlier, we must ensure that any engineered solution materially decreases risks beyond the administrative controls enhancements that were put into place last year. 7. The basis for operational installation at PBU and other facilities including the following: a) Mechanical condition of a well that would trigger installation of the remote monitoring system, b) Projected date for the identification of candidate wells, c) Anticipated timeline for installation of the remote monitoring capability on candidate wells if the pilot project is implemented. We can't answer these questions at this time as it is premature to speculate on the results of the pilot. Ultimately the basis for further installations will depend not only on the pilot results ) ·.May 28, 2004 Page 2 ) but also subsequent engineering, risk and cost analysis before an informed decision can be made on any operational installation. Of utmost importance is the fundamental issue of whether, and in what circumstances, the installation of such devices would result in a net reduction of risk. We would be happy to discuss the current progress of the pilot program if you would like, as well as the final results when our analyses are complete. 8. Specific examples of where BPXA has shared or plans to share the pilot project results with other Alaskan operators. Prudhoe Bay co-owners will review the results of the pilot and risk analysis when they are completed. ********** In addition to the information requested above, the Commission requested the following supplemental details. a. Results of the mechanical pressure relief options study, including any reports generated by the study team relevant to the milestones. The results are outlined above; no reports were generated. b. Participants in the study and their work responsibilities. David Neill, Project Lead Veronica Reem John· Dengler Harry Engel Joe Anders Dave Ingalls Bill Johnson Craig Wiggs Bill Blosser BPXA Senior Instrument Controls Engineer Veco Process Engineer BPXA Process Engineer BPXA Wells Staff Engineer BPXA Wells Integrity Engineer BPXA Field Operator/P ACE HSE Committee BPXA ElectricianIP ACE HSE Committee GPB Field Operations Manager BPXA Operations Integrity and Assurance c. List of all relief system options considered in the study. Please see above. d. Specific criteria that were used to accept/reject techniques and technologies for further evaluation. Criteria used included: a. long-term device and system reliability in arctic conditions, b. device/system ability to provide accurate data, c. ability to determine that the systems are fully functional, d. whether the technique would provide increased protection or other benefits over the systems currently in place, e. reasonably cost effective, f. confidence that the system wouldn't introduce new risks. e. Relative importance of each criterion used to advance the technology. Each of the criteria listed above is critical. We would be happy to discuss this in detail with you if you would like. ) ) '.May 28, 2004 Page 1 Attachment 2 GPB Outer Annular Pressure Options [as outlined in September, 2003] Options Scope Definition Technical Issues Notes · Pressure cycling may impact the integrity of the casings. Remove liquids Pressurize annulus with gas Depressuring into a trailer or tank also has safety and from the surface of the casing down to and blow down to remove environmental risks. liquids. · Ensuring a 200-foot level is extremely difficult due to the the 200-foot level communication. Pump down liquid level · Previous attempts to pump the liquid using a hose have 2 through hose or tubing proved unsuccessful due to the sharp bend from the Pump out liquid inserted through casing head connection to the annulus. val ve · Ensuring the liquid level remains minimal is extremely difficult due to the communication. Add a tapped spacer · PSV s must be maintained according to state guidelines (PMs 3 connection upstream of the required). Impact to existing PM schedule. root valve on the OA Provide automatic · Requires electrical power to individual wells to provide freeze pressure relief for connection to the wellhead. protection for PSV installation. the annulus of each Install a pilot modulating PSV · Heat trace or heater less reliable than actual relief device. well with an upstream and · Requires the well to be shut in and no pressure on the OA downstream isolation valve to allow for preventive such that the root valve can be removed. maintenance. · Rupture Disc may fail due to thermal cycling of the system. · Requires new p-pilot installation on wellhead. 4 Monitor OA pressure with a P- · Potential for sensing line freeze up, loss of indication. Pilot. To minimize freeze· up Difficult to identify. problems, add a tapped spacer · Uses existing hydraulic safety system to isolate well. Automatic Pressure Shutdown on High upstream of the root valve on · Difficult to know when twinned wells have shut-in without Annulus Pressure the OA connection to the separate remote pressure indication. wellhead. This instrument · Requires the well to be shut in and no pressure on the OA would activate the existing such that the root valve can be removed. hydraulic safety system. · Impact to existing PM schedule. · Bypasses Surface Shutdown System. · May require electrical power and signal wires to individual 5 Provide local alarms Monitor OA pressure with a wells. pressure transmitter. To · Requires new transmitter installation on wellhead. for well houses to alert personnel of minimize freeze up problems, · Potential for sensing line freeze up, loss of indication. add a tapped spacer upstream Difficult to identify. over pressure or gas of the root valve on the OA · Requires the well to be shut in and no pressure on the OA release. connection to the wellhead. such that the root valve can be removed. · Impact to existing PM schedule. 1 . '..May 28, 2004 Page 2 Options Periodically vent annulus pressure to verify process connection is not frozen Provide hard-piped relief lines from IA and OA to "8" risers. ') Scope Definition Add a solenoid valve between process connection and pressure transmitter. The pressure signal should change each time the solenoid vents. If no change detected, safety system could be activated. Add a hard-line connection from the Casing valve to the S riser. Include a check valve and tie-in isolation valve to prevent production back flow into annulus. ) Technical Issues Notes 6 · Continual small releases of hydrocarbons into module and may not be allowed by state regulations. · Difficult to detect when well has been shut in. · Bypasses Surface Shutdown System. · Potential for small fluid flow from Annulus to production line. · Potential hydrate formation may cause line to freeze-up even while well is on production. · Potential for loss of annulus freeze protect fluids to production line. · Possible increase in flow from IA to OA on wells producing into the low pressure system due to increased differential pressure. This may result in further damage to the IA to OA piping. · In some cases, pressure in the "S" riser is too high. 7 Explanatory notes added 5/28/04: The scope definition for these options was not finalized, but rather an initial basis was chosen to allow for review and discussion with operations personnel. The pilot project scope was loosely based on the third option in the list above. Enhancements were made to try to optimize the design. 1. This option provides a gas buffer for any thermally induced liquid expansion. The 200 ft level is just a rough estimate of what may be necessary. A minimum level would be identified for the worst-case scenano. 2. This option does not maintain a gas cap on the outer annulus. It simply maintains the outer annulus fl uid level at a certain depth. 3. A typical pressure relief installation is the basis for this option. Once the set pressure is reached, the val ve will open. 4. This option would allow a pressure switch to automatically activate the shutdown valve. This indication is local only without remote indication. 5. All remote measurement options for outer annulus pressure monitoring are included in this option. Initial ideas included a local alarm (e.g. flashing strobe on well house) to alert operations. Sensing line blockages were not addressed. 6. A method to help determine if the sensing line was blocked in this option. 7. This option would allow for a permanent connection from the inner and outer annulus connections directly to the well production line. This option does not actively control the pressure/flow from the IA or OA to the flow line. #1 (Cù. cvr~ fÄí' l~r íP .. \. ¡, \ I ~ '- ':, I· !! @ULruUL6 ') rrJì~líE ®~ ®~!ZÆ\ lW if W ~ LnJ @t Jü U\.j ) A'~ASKA. OIL AND GAS CONSERVATION COMMISSION ¡ l / / / j I FRANK H. MURKOWSKI, GOVERNOR 333 W. 7fH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 December 12,2003 Ms. Maureen Johnson Prudhoe Bay Business Unit Manager BP Exploration (Alaska), Inc. PO Box 196612 Anchorage AK 99519 Dear Ms. Johnson: This to confinn that the first Notice of Proposed Enforcement Action that you received yesterday was an incompletely signed version that was delivered by mistake. The second version that was delivered soon afterwards is the correct version. I apologize for any confusion this may have caused. I have enclosed once again a copy of the correct verSIon. Sincerely, \~ì. .,.~ ~. C'J~~ J( C '. o m Special Staff Assistant cc: Ms. Jeanne Dickey, BPXA ~ ) ') ~r~1Œ [} !Æl!Æ~~«~ I ¡ .1 ;' FRANK H. MURKOWSK/, GOVERNOR ~ t,A~KA OIL AND GAS CONSERVATION COMMISSION / / .I J 333 W. 7fH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 December 11, 2003 Ms. Maureen Johnson Prudhoe Bay Business Unit Manager BP Exploration (Alaska), Inc. PO Box 196612 Anchorage AK 99519 Re: Notice of Proposed Enforcement Action Dear Ms. Johnson: The Alaska Oil and Gas Conservation Commission ("Commission") has. investigated the explosion and fITe that occurred on August 16, 2002, at Prudhoe Bay well A-22. Based on this investigation, the Commission considers that BP Exploration (Alaska) Inc. ("BPXA") may have violated 20 AAC 25.526, by failing to carry on operations and maintain the property in a safe and skillful manner in accordance with good oil field engineering practices. Pursuant to 20 AAC 25.535, the Commission proposes to take enforcement action as described below. More specifically, the nature of the apparent violation is inadequate practices to manage wells with sustained annular pressures. It appears that BPXA failed to ensure sufficient engineering analysis as to the causes of high annular pressure occurring in wells, allowing such wells to be operated or restarted without an adequate understanding of the problem or without repair; that BPXA failed to ensure sufficient monitoring of annular pressure; and that BPXA failed to ensure that shut-in wells characterized by high annular pressure were bled down to safe pressure levels before startup. In the case of A-22, it appears that these failures led to the well's being brought into production on August 15 and 16, 2002, with an outer annulus pressure buildup that exceeded the burst capacity of the surface casing, causing a catastrophic failure of the well with the release and explosion of high-pressure gas. One BPXA worker was seriously injured in the explosion. The reasons the Commission considers a violation to have occurred are summarized in the enclosed A-22 investigation staff report. The Commission proposes to impose civil penalties on BPXA under AS 31.05.150(a). The proposed penalties are $5,000 per day for each day from March 21,2001, to August 16, 2002, for a total of $2,530,000. March 21, 2001, is the date of the last revision of BPXA's annulus pressure policy prior to the A-22 explosion. In addition, the Commission proposes to impose a penalty under AS 31.05.150(e) for the venting of 1,053 Mcf of gas in the A-22 incident. The proposed penalty is $1,112. t ' . .. ) Ms. Maureen Johnson I " December 11, 2003 Page 2 of2 ) As provided under 20 AAC 25.535(c), within 15 days after receipt of this notification BPXA may file with the Commission a written response that concurs in whole or in part with the proposed action described here, requests informal review, or requests a hearing under 20 AAC 25.540. If informal review is requested and BPXA disagrees with the Commission's proposed decision or order after that review, BPXA may tþen req1;lest a hearing witþ.in 10 days after the proposed decision or order is issued. If BPXA does not file a timely written response to this notification, the Commission will consider BPXA to have accepted by default the proposed penalties described above. However, if BPXA needs more than 15 days to respond, it may for good cause shown request an extension of the I5-day response period. é Enclosure cc: Ms. Jeanne Dickey, BPXA Daniel T. Seamount Commissioner Decision and Order Well A-22 ') ) Subject: Decisionand OrderWeU A-22 From: J ody Colombie <jody -'- colombie@admin.state.alcus> Date: Man, J5Nov200416:25:10 -0900 T~:~i#~!B*~~"r~~~~~;¡;::i;:;C",;i:',:", ';.·,"¡·.'..i/··...",.¡"'{::'I..:..·..'c¡,,.",·,',.,.... ~S·~.·:··~r~729·~~~i~;~g~;··.A~ip~.~.~~i~~·~.~.sj~gAW.~.·~~?~~~~.~8~~.~..~R~;....· ~~e18~i18l<:@Ç~;¢Ptn.~·.·y~§~Ç>1@g2i;J;1~~#.d9'-1git}~~µ~~q[1~~9~~J~qgm,:pª~..... '. ........."". :.... ...:..:...... .... : '". ":. ..:,":;".:" :"-: :'.' :.:.... :::.:' ."::..:..-: :......' .:.... :.:"".:: .:......:....:.. .......:.......: .....:..::..: ":'::.':':' ":"":", . . ...... .". "." ". .. .""..,.. ... .' . ....... '. ., '.' .. . . . . ". ..... . . '. :.' .. '. . ..... '. . . . .. ..' '. .' '.' '. ".". ". ". 0"" ..... :.' . .",. ... . ....... ", .' . . '. . ... . ., .' .'. . . '.' '. . ," ":-.::... .:..:.:..::..:::'.:.....,.: ":':. ',>,:.::..-:' ':::'::>. :,....:: :':':. ).:"":: >,.,:,....... .:..........:........ ....... ......... ...... ..........::....: ........::.:..... ".:' :.. :....: :.:.....:.... ....:.........:..........:.. . l;.:t····,··· ....,....,....,........,......... .....,;.; .... ~.J;1U~ç~~~{. ..,:.:,¡/:....'... .·.P~~~9¥,···..··,········· .... The attached document is the Decision and Order for Well A-22. I have not attached the appendices due to the fact your e-mail server may not accommodate a 7 megabyte document. If you wish to have the appendices please e-mail me your request, include your name and address I will mail you a CD with the file. Jody Colombie Special Staff Assistant AOGCC Content- T\'pe: applicatiol1'pdf ' 'Order 29.pdf, . - Content-Encoding: base64 1 of 1 11/15/2004 4:32 PM Decision and Order Well A-22 ) ) ~lÎ~ject:·. Decision anâ C)râët Vjèl1'A-22 IfITom: ...Jody Colombie<jody_colombie@adrnin.statë.åk.i1s> :Oate:Mon, '15Nov200416:25:10,-09QO :. ........:....... ..... .........:... .:...................... ...:............. . .... . . ... .... .' :.. ....>gqy'i,·..···,·· . The attached document is the Decision and Order for Well A-22. I have not attached the appendices due to the fact your e-mail server may not accommodate a 7 megabyte document. If you wish to have the appendices please e-mail me your request, include your name and address I will mail you a CD with the file. Jody Colombie Special Staff Assistant AOGCC Content- T\/pe: applicatiou,/pdf ' Order 29.pdf . Content-Encoding: base64 1 of 1 11/16/20049:52 AM Final Decision ) ) Subject: Final Decision FroDl: J ody. Colol11bìe <j odY__c61ol11bie@adrnin.statø.ak.us> Date: Tue, 16Nov200411:06:35-0900 1;9·:.·.Yj(q$~~@~~l1et· As requested. Jody . .... ....... ,".... .................. ,-... ¡ Content- Tvpe: applicationlpdf Order 29.pdc' " - , Content-Encoding: base64 1 of 1 11/16/2004 11:08 AM Re: Decision and Order Well A-22 ) ) I will send it this week. J ody Marc Kovac wrote: Jody, Yes, I would like a CD copy of the appendices. Please send to: Marc Kovac PACE PO Box 2973 Seward, Alaska 99664 L¡n~cI /IJ/~IoL/ X~ Thank you, Marc Kovac Original Message ----- From: Jody Colombie <jody colombie@admin.state.ak.us> Date: Monday, November 15, 2004 3:25 pm Subject: Decision and Order Well A-22 The attached document is the Decision and Order for Well A-22. I have not attached the appendices due to the fact your e-mail server may not accommodate a 7 megabyte document. If you wish to have the appendices please e-mail me your request, include your name and address I will mail you a CD with the file. Jody Colombie Special Staff Assistant AOGCC 1 of 1 11/16120049:25 AM THANKS FOR THE EMAILED DECISION ) ') Jody, Thanks for the emailed decsion. Please mail to me the CD at ChuckHamel 101 Quay Street Alexandria, VA 22314 7r7~ 1/)~/oC¡ ~~ Incidentally did you catch the Court TV program November 4th? Chuck 1 of 1 11/16/20049:33 AM Re: FT request ) ) Subject: Re:FT request From:. Jody Colombie <jody_colombie@admin.state.ak.us> pat~: . r~e, .l?· ~ 0\T~?04.·1?:.~.1:3.~....-9?90 to: dougwcamerön@ftp.etworj(;çoJIi ... It is not on the website. The attached is the order itself. If you want the appendices as well I will have to send you a CD because I believe the file is too big for your server (7 megabytes) . Jody dougwcameron@ftnetwork.com wrote: Hi, I was looking for the latest BP ruling on the website, but couldn't find it. Could u possibly point me in the right direction. Second, what does this do to the whole issue of the probabtion which BP has been on since 2000? Doug Cameron Houston Correspondent Financial Times 713 520 9087 (W) 713 885 2680 (M) Visit the web site of the Financial Times at http://www.ft.com , Content- T, pe: application pdf ¡fOrder 29.pdf I ~ I Content-Encoding: base64 ::...::..::1:::::..... ..............................::::::::::::::::::::::::::::::::::::::::::: ...........::::::::::::::::::::::::::1 1 of 1 11/16/2004 10:51 AM Re: Copy of Prudhoe Bay order ) ') Subject:· Re:· Copy?f Prudhoe Bay order From:· J odyColQmbie. <jody_colombie@admin.state.ak.us> Date:1'ue,. 16 Nov 200410:46:47-0900 :.....: .: ........ ". ..... ....: . ..... ..... . ........ .". ...................:.....", ..:....:...... ........: .....:..:...:....:.... ...:-.... ," ".. .. j;'~;. ~i$t~p,·..t\T ¢lsQriW1}þølšQn.@þ~ttQl¢µriW~wšJþpm?-·. .. . .... ... ....".. ,"..... .. ..... . ." .. .... . .. .. you can come anytime. it is at the front desk for you. Kristen Nelson wrote: Jody, yeah, darn, I do need the appendices... How soon could I pick up a CD? Kristen -----Original Message----- From: Jody Colombie [mailto:jody colombie@admin.state.ak.us] Sent: Tuesday, November 16, 2004 9:24 AM To: Kristen Nelson Subject: Re: Copy of Prudhoe Bay order Kristen, I can't send you the appendices because your e-mail server is not big enough. I have attached the order though and you can either come by the office or I can send you a CD. Jody Kristen Nelson wrote: Hi, Jody, could you send me a copy of the commission's order on the Prudhoe Bay well fine? Thanks, Kristen Kristen Nelson, Editor-in-Chief Petroleum News -- North America's weekly oil & gas newspaper ph : ( 9 0 7) 24 5 - 5553, fax: ( 90 7) 24 8 - 343 7 www.PetroleumNews.com 1 of 1 11/16/2004 10:46 AM ! ! ) ! I !?Ch /ffftler ¡ii Ifa/f' 2b/~Ø7 I· 11: ) 1/22 {)/ckr A-22 Decision ) .) S~bje~t:.··..A-22...Ðeqision Fro In:. Jol1nN 0nnan. .<john_~öl1l1an@adßlin.state.ak.Ûs> Date: Mon, ..15Nov 200414-:01 :01 -0900 F...I?~~e~·.··f·~~r~ti~yi~~~a.~i~~~t~~~;~~H~f,·.·~ql1~.·~...f1~9~.~l1:· . .~·.~~?~§~ec¡¿~ª~t~~~.~·~~j~:~~~~,~.,.~~..?".~·...1ø ~i~[-~~c~~~~~!ti'~~~~?:!j~"~ .. ·tei~mfÎI; ~št~Y~?-~9m~~~~:~~~#~~~........... ......... ... .....:~~...~........:.................. :.~ <jjp!.¡teg~~~~~~,~~~t~;~~~~ffl~1~~~9~?1:.~"'tl . ..' :J0t~JJ~t!~!Jtn~J~nt!!tttJJJnttJt: ç(f; Ð~W~~a,t}1gupt'4d(:lþis~a1AP~~@atiri1i):h~ta,~~'~;1Js?,·Jo4YJÇq~<)tnÞ~~'5j()C!Y¿Cdl~m1,jie@a,~il1;~tf!tê,~;µ~('· Everyone-this afternoon we are issuing the Commission's long-awaited final Decision and Order in the BP Well A-22 matter. You may read about this in the newspaper in the next few days. This Decision represents excellent work by the AOGCC staff. In keeping with our role as a professional, quasi-judicial agency of the state of Alaska, we will let the written Decision and Order speak for itself and none of us will be making any statements to the press to elaborate upon it. BP will have until November 29 to decide whether to request a formal hearing. If they do not request a formal hearing, then this Decision and Order will become final on November 30, 2004. Dan and I want to thank all of you who worked on this. In particular we want to express appreciation to Jim Regg and Winton Aubert for their outstanding work; and, as always to Rob Mintz for his good advice and careful review and to Jody for her usual superb job in pulling it all together. If there are calls from the press, they should be referred to Jody. If she needs to, she will consult with Rob and/or David Fremming before returning such calls. No useful purpose will be served by the rest of us making any public pronouncements on this matter beyond what is stated in the decision. John John K. Nonnan <John Norman(iqadmin.state.us> Commissioner Alaska Oil & Gas Conservation Commission 1 of 1 11/16/2004 10:59 AM