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Home My WebLink AboutCO 311 A i" Conservation Order Cover P~ge XHVZE This page is required for administrative purposes in managing the scanning process. It marks the extent of scanning and identifies certain actions that have been taken. Please insure that it retains it's current location in this file. ,~J~ //~ Conservation Order Category Identifier Organizing RESCAN Color items: [] Grayscale items: [] Poor Quality Originals: [] Other: NOTES: DIGITAL DATA [] Diskettes, No. [] Other, No/Type OVERSIZED (Scannable with large plotter/scanner) [] Maps: [] Other items OVERSIZED (Not suitable for plotter/scanner, may work with 'log' scanner) [] Logs of various kinds [] Other ' BY: ~ MARIA Scanning Preparation TOTAL PAGES Production Scanning Stage I PAGE COUNT FROM SCANNED DOCUMENT: '~/~:~ PAGE COUNT MATCHES NUMBER IN SCANNING PREPARATION: y YES NO BY: Stage 2 IF NO IN STAGE 1, PAGE(S) DISCREPANCIES WERE FOUND: ~ YES NO (SCANNING IS COMPLETE AT THIS POINT UNLESS SPECIAL ATTENTION IS REQUIRED ON AN INDIVIDUAL PAGE BASIS DUE TO QUALITY, GRAYSCALE OR COLOR IMAGES) General Notes or Comments about this Document: 5/21/03 ConservOrdCvrPg.wpd STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage Alaska 99501-3192 Re: THE APPLICATION OF ARCO ALASKA, ) INC. for an order eliminating the requirement ) for subsurface safety valves in wells drilled to ) the West Beach Oil Pool. ) Conservation Order No. 311A Prudhoe Bay Field West Beach Oil Pool December 20, 1996 IT APPEARING THAT: ARCO Alaska, Inc., operator of the West Beach Oil Pool in the Prudhoe Bay Oil Field, submitted an application dated October 28, 1996 requesting a revision to Rule 6 of Conservation Order No. 311. The revision would eliminate the requirement for subsurface safety valves in wells drilled to the West Beach Oil Pool. 2. Notice of opportunity for public hearing was published in the Anchorage Daily News on November 23, 1996 pursuant to 20 AAC 25.540. 3. No protests to the application were received. FINDINGS: Commission regulation, 20 AAC 25.265 requires surface (SSV) and subsurface safe.ty valves (SSSV) in offshore wells capable of unassisted flow of hydrocarbons to the surface. Discretion to require SSV's and SSSV's in other areas is also provided. 2. Wells capable of unassisted flow of hydrocarbons to the surface that are equipped with both a SSV and a SSSV are afforded redundant protection from an uncontrolled flow. 3. Conservation Order 31 !, Rule 6, requires all wells in the West Beach Oil Pool capable of unassisted flow of hydrocarbons to the surface to be equipped with a SSV and a SSSV. 4. Previous commission policy was to require multiple safety valves in onshore production wells (for permafrost areas) capable of unassisted flow of hydrocarbons to thc surface. The initial requirement for SSSV's was largely related to concern for the loss of well control from casing collapse due to freeze back of the permafrost. The magnitude and extent of freeze back forces and appropriate mitigating well construction techniques, had not been shown through experience to be correctly anticipated and was not well understood when the requirement for SSSV's was imposed. Wells drilled to the West Beach Oil Pool have been constructed using cement formulated for permafrost conditions, and casing grades and annular fluids capable of preventing appreciable deformation of casing due to permafrost freeze back. 7. The Commission has no record of an SSSV being used in Alaska to prevent uncontrolled flow from a North Slope onshOre production well. ARCO intends to use a risk based management system which will include producing rate, potential for environmental damage, corrosion concerns, proximity to facilities and populated areas, and economics as factors in evaluating wells for SSSV removal. 9. SSSV's contribute to higher operating costs, and increascd difficulty and risk for some downholc operations. 10. The Commission has eliminated the requirement for SSSV's in onshore wells in other North Slope oil pools. Conservation Order No. 311 December 20, 1996 Page 3 CONCLUSIONS: . o SSSV's may reduce ultimate recover)' by contributing to higher operating costs, and may increase the chance of an accidental release of hydrocarbons when conducting certain downhole operations. Extensive experience indicates the potential for casing failures through the permafrost due to freeze back has been greatly reduced by usc of appropriate construction techniques in North Slope production wells. SSSV's in West Beach Oil Pool production wells have provided limited benefit to public safety, environmental protection or resource recover),. 4. Eliminating the requirement for SSSV's in West Beach Oil Pool production wells is not likely to contribute to waste and may improve safety of certain well operations and greater ultimate recovery. NOW, THEREFORE, IT IS ORDERED Rule 6 of Conservation Order 311 is amended to: Rule 6. Automatic Shut-in Equipment (a) Each well shall bc equipped with a Commission approved fail-safe automatic surface safety valve system (SVS) capable of preventing uncontrolled flow by shutting off flow at the wellhead. (b) The sVs shall not be deactivated except during repairs, while engaged in active well work, or if the pad is manned. If the SVS cannot be returned to service within 24 hours, the well must be shut in at the wellhead and at the manifold building. 1) Wells with a deactivated SVS shall be identified by a sign on the wellhead stating that the SVS has been deactivated and the date it was deactivated. (c) 2) A list of wells with the SVS deactivated, the dates and reasons for deactivating, and the estimated activation dates must be maintained current and available for the Commission on request. A representative of the Commission will witness operation and performance tests at intervals and times as prescribed by the Commission to confirm that the SVS and all associated equipment are in proper working order. DONE at Anchorage, Alaska O a v i-'~-~._ ~b~C ,~ a i r~a n'' sor ion Commission · uckerman Babcock, Commissioner Alaska Oil and Gas Conse~ation Commission AS 31.05.080 provides that within 20 days atter receipt of written notice of the entry of an order, a person allbcted by it may file with the Cotmnission an application for rehearing. A request lbr rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day ifa holiday or weekend, to be timely filed. The Commission shall grant or reti~se the application in whole or in part within 10 days. The Commission can refi~se an application by not acting on it within the 10-day period. An affected person has 30 days from the date the Commission refi~ses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Conmfission, the 30-day period for appeal to Superior Court runs from the date on which the request is deemed denied · (i.e., l0th day after the application for rehearin~ was filed). Subject: [Fwd: West Beach Waterflood: Update] Date: Fri, 04 Aug 2000 09:35:21 -0800 From: Jack Hartz <jack_hartz@admin.state.ak.us> Organization: Alaska Oil and Gas Conservation Commission To: Lori Taylor <lori_taylor@admin.state.ak.us> Please print and file in CO 31 lA file Thx, Jack Subject: Re: West Beach Waterflood: Update Date: Tue, 25 Jul 2000 17:11:33 -0700 From: Jack Hartz <jack_hartz@admin.state.ak.us> Organization: Alaska Oil and Gas Conservation Commission To: Paul J Taylor <pjtaylor@ppco.com> CC: Camille Oechsli <cammy_oechsli@admin.state.ak.us>, Daniel T Seamount JR <dan_seamount@admin.state.ak.us> Paul, Thanks for the W Beach update. I am reviewing the data from the WB wells and note the GORs range upward to 15000+ SCF/STB and that reservoir pressure is around 3000 psi, down from about 4260 psi initial. Has there been any work done to verify whether long term ongoing primary production has the potential to do reservoir damage? That would be our greatest concern on continuation of production without injection. Of course it depends on how long it will be until WB-06 is ready for injection. You mentioned it could take up to a month or longer. Is that the downside time estimate? Let me know what you think. Jack Hartz Paul J Taylor wrote: Jack, As of today we are still experiencing problems with the conversion of WB-06 and would like to apply for the extension of AA 311.07. The plan forward is as follows: 1 ) Replace all live lift gas mandrels with dummies, establish packer integrity. 2) Attempt to break down perfs with high pressure injection. 3) Failing that, attempt to produce the well again using a coil siphon string. 4) Repeat clean-out, sample fill, stimulate (if necessary), restart conversion process. If steps 1 & 2 are successful, we could be near the 10 day mark now. If not, it could be upwards of a month or longer before the well is converted. We will contact you after step 2 to give you an update of our progress. If you have any questions, please reply or call (263-4822). > Paul Taylor > Jack Hartz <jack_hartz@admin.state.ak.us> on 07/21/2000 08:08:43 AM > To: Mike R Morgan/AAI/ARCO@Arco > cc: blair_wondzell@admin.state.ak.us, bob_crandall@admin.state.ak.us, > tom_maunder@admin.state.ak.us, steve_davies@admin.state.ak.us, Gordon Kidd/AAI/ARCO@Arco, Paul J Taylor/AAI/ARCO@Arco Subject: Re: West Beach Waterflood Mike, Paul, Gordon, Mike, thanks for the heads up on the start of injection and the possibility it will be delayed into August. I recommend that you wait until next week to apply for an extension of AA 311.07. You can apply for the extension by email. In the application, give a notification of when you expect to begin injection. The operator must notify the Commission at least ten days prior to start of injection according to 20 AAC 25.420. The 24 month clock you mention is in 20 AAC 25.402(i), not (f). Paragraph (i) means that the injection project must start within 24 months of the date of AIO 4C, April 19, 2000. If the project is not begun by April 18, 2002 the order will expire unless an extension is granted. I will be in the office all week 7~24-28 and out on 7/31. Have Paul or Gordon contact me if it is unlikely that injection will start by 7/31. Thanks, Jack Hartz Mike R Morgan wrote: Hello Jack, As a follow-up to my phone message, I just wanted to let you know the status of the West Beach Waterflood Project. We completed the source well, WB-07, on June 10, 2000 and have been finalizing the tie-in and conversion preparatory work on WB-06. Although our target is to have water injection started before the end of the month it may slip into August. Will you need a request to extend the July 7, 1999 GOR waiver allowing production from the West Beach Pool through July 31, 2000, or does the April 19, 2000 approval of the West Beach Enhanced Recovery Project cover it with the start of the 24 month clock under 20 AAC 25.402(f)? Please respond to Paul Taylor (263-4822, e-mail above) or Gordon Kidd (263-4103, e-mail above) as I will be out of town until August 1, 2000. Paul and Gordon both will be working for BPA, the new operator of the West Beach Pool. Best regards, Mike Morgan Phillips Alaska Inc. Exploration and Land > 907-263-4332 (See attached file: jack_hartz.vcf) Subject: [Fwd: West Beach Waterflood: Update] Date: Fri, 04 Aug 2000 10:01:59 -0800 From: Jack Hartz <jack_hartz@admin.state.ak.us> Organization: Alaska Oil and Gas Conservation Commission To: Lori Taylor <lori_taylor@admin.state.ak.us> file CO 311A (I think) Jack Subject: Re: West Beach Waterflood: Update Date: Wed, 26 Jul 2000 08:27:32 -0700 From: Jack Hartz <jack_hartz@admin.state.ak.us> Organization: Alaska Oil and Gas Conservation Commission To: Paul J Taylor <pjtaylor@ppco.com> CC: Camille Oechsli <cammy_oechsli@admin.state.ak.us>, Daniel T Seamount JR <dan_seamount@admin.state.ak.us> Paul, I will recommend a one month extension. One month will allow orderly planning, implementation and evaluation of the current work plan. When the results of the remedial work are in and a new prognosis is available, we can discuss whether the continue or shut the wells in. Keep us posted. Jack Paul J Taylor wrote: > Hi Jack. We did do some preproduction sensitivities that showed little > impact on reserves with timeframes that went up to two years. Admittedly, > though, the GORs are near marginal, reservoir pressures are Iow, and it's > summer on the slope, so shutting WB-04 in for a while is not a big deal. > > My hope was to defer making a decision until we get the results from the > high pressure breakdown. That should happen fairly soon. A one week > extension (past July 31 ) will probably cover us for this. We could then > discuss plans later if the breakdown is delayed or unsuccessful. Does that > sound reasonable? > Paul > > Jack Hartz <jack_hartz@admin.state.ak.us> on 07/25/2000 03:11:33 PM > To: Paul J TaylodAAI/ARCO@Arco > cc: Camille Oechsli <cammy_oechsli@admin.state.ak.us>, Daniel T Seamount > JR <dan_seamount@admin.state.ak.us> > Subject: Re: West Beach Waterflood: Update > > Paul, > > Thanks for the W Beach update. I am reviewing the data from the WB wells and > note the GORs range upward to 15000+ SCF/STB and that reservoir pressure is > around 3000 psi, down from about 4260 psi initial. Has there been any work done to verify whether long term ongoing primary production has the potential to do reservoir damage? That would be our greatest concern on continuation of production without injection. Of course it depends on how long it will be until WB-06 is ready for injection. You mentioned it could take up to a month or longer. Is that the downside time estimate? Let me know what you think. Jack Hartz Paul J Taylor wrote: Jack, As of today we are still experiencing problems with the conversion of WB-06 and would like to apply for the extension of AA 311.07. The plan forward is as follows: 1) Replace all live lift gas mandrels with dummies, establish packer integrity. 2) Attempt to break down perfs with high pressure injection. 3) Failing that, attempt to produce the well again using a coil siphon string. 4) Repeat clean-out, sample fill, stimulate (if necessary), restart conversion process. If steps 1 & 2 are successful, we could be near the 10 day mark now. If > not, it could be upwards of a month or longer before the well is converted. > We will contact you after step 2 to give you an update of our progress. If you have any questions, please reply or call (263-4822). Paul Taylor Jack Hartz <jack_hartz@admin.state.ak.us> on 07/21/2000 08:08:43 AM To: Mike R Morgan/AAI/ARCO@Arco cc: blair_wondzell@admin.state.ak.us, bob_crandall@admin.state.ak.us, tom_maunder@admin.state.ak.us, steve_davies@admin.state.ak.us, Gordon Kidd/AAI/ARCO@Arco, Paul J TaylodAAI/ARCO@Arco Subject: Re: West Beach Waterflood Mike, Paul, Gordon, Mike, thanks for the heads up on the start of injection and the possibility it will be delayed into August. I recommend that you wait until next week to apply for an extension of AA 311.07. You can apply for the extension by email. In the application, give a notification of when you expect to begin injection. The operator must notify the Commission at least ten days prior to start of injection according to 20 AAC 25.420. The 24 month clock you mention is in 20 AAC 25.402(i), not (f). Paragraph (i) means that the injection project must start within 24 months of the date of AIO 4C, April 19, 2000. If the project is not begun by April 18, 2002 the order will expire unless an extension is granted. I will be in the office all week 7/24-28 and out on 7/31. Have Paul or Gordon contact me if it is unlikely that injection will start by 7/31. Thanks, Jack Hartz Mike R Morgan wrote: Hello Jack, As a follow-up to my phone message, I just wanted to let you know the status of the West Beach Waterflood Project. We completed the source well, WB-07, on June 10, 2000 and have been finalizing the tie-in and conversion preparatory work on WB-06. Although our target is to have water injection started before the end of the month it may slip into August. Will you need a request to extend the July 7, 1999 GOR waiver allowing production from the West Beach Pool through July 31, 2000, or does the April 19, 2000 approval of the West Beach Enhanced Recovery Project cover it with the start of the 24 month clock under 20 AAC 25.402(f)? Please respond to Paul Taylor (263-4822, e-mail above) or Gordon Kidd (263-4103, e-mail above) as I will be out of town until August 1,2000. Paul and Gordon both will be working for BPA, the new operator of the West Beach Pool. Best regards, Mike Morgan Phillips Alaska Inc. Exploration and Land 907-263-4332 (See attached file: jack_hartz.vcf) Jack Hartz <Jack_Hartz@admin.state.ak.us> Sr. Reservoir Engineer Alaska Oil & Gas Conservation Commission Jack Hartz Sr. Reservoir Engineer <Jack_Hartz@admin.state.ak.us> Alaska Oil & Gas Conservation Commission 3001 Porcupine Dr. Fax: 907-276-7542 Anchorage Work: 907-793-1232 Alaska 99501 USA f~15S 1~ (' AFFIDAVIT AO-02714017 STATE OF ALASKA. ) THIRD JUDICIAL DISTRICT. ) .... Eua..~ .... ~au.f.m~nn ........... being first duly sworn on oath deposes and says that he/she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during ali said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on Nov. 23, 1996 OF PUBLICATION STATE OF ALASKA " · Ali~ka Oil and ~ . i C0nS~rv~i0n commission i ~' ~,he application of t i",/klaska, Inc. to ame~ Rul~ 7 of Con~rvation Order No. 207 and Rule 6 of Conser- and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. s i g ne d ?.~ (~. "~Y'-'~..~.~..~. Subscribed and s~t,~~~~e ,~ me thisc~.../day o~...c~../Z.~ Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY CO/VWIISSION EXPIRES ...... ......... ARCO Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 Joseph A. Leone October 28, 1996 Mr. David W. Johnston, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Re: Request to Revise Conservation Order 207, Rule 7 Prudhoe Bay Field, Lisburne Oil Pool Request to Revise Conservation Order 311, Rule 6 Prudhoe Bay Field, West Beach Oil Pool RECEIVED NOV 1 4 1996 Dear Mr. Johnston: Alaska Oil & Gas Cons. Commission Anchorage With reference to your letter, dated September 26, 1996, ARCO Alaska, Inc., BP Exploration (Alaska), Inc., and Exxon Company are amending our July 8, 1996 correspondence to request that the Commission only revise the requirements of Conservation Orders 207, Rule 7, for the Lisburne Oil Pool and Conservation Order 311, Rule 6, for the West Beach Oil Pool. At this time, we have elected not to include the Point McIntyre and Niakuk Oil Pools in this request. The proposed rule change modifies the safety valve system requirements for the Lisburne and West Beach Pools by eliminating subsurface safety valves and requiring only surface safety valves in wells in these Pools. The background, proposal, and justification for this request remains as stated in our July 8, 1996 correspondence. For clarity, a copy of the current rules and proposed new rules are attached (Attachments 1-4). On October 17, 1996, Mr. Kris Fuhr with ARCO Alaska, Inc. discussed our amended request with Mr. Bob Crandall of your office. Please contact us if you have any questions or need more information related to this matter. Our phone numbers are 263-4431, 564-5433, and 564-3689 for the ARCO, BPX, and Exxon contacts respectively. Sincerely, ^ f~ ~ I~' / ~,,,J~ A. Leone ~. N. Bo lea Manager GPMA Asset Manager GPMA ARCO Alaska, Inc. BP Exploration (Alaska), Inc. Attachments Production Manager-Alaska Exxon Company USA Attachment I Current Conservation Order 207, Rule 7. Rule 7. Automatic Shut-In Equipment a) Any well which is capable of unassisted flow of hydrocarbons must be equipped with 1) a fail-safe automatic surface safety valve (SSV) capable of preventing an uncontrolled flow; and 2) a fail-safe automatic surface controlled subsurface safety valve (SSSV). This valve must be in the tubing string and located below permafrost. The valve must be capable of preventing an uncontrolled flow. For operational necessity the Commission may administratively waive the surface controlled requirement. b) A representative of the Commission will witness performance tests at times prescribed by the Commission to confirm that the SSV, SSSV, and all associated equipment are in proper working condition. c) When requested by the operator, a representative of the Commission will witness "no-flow tests" to verify that a well is no longer capable of unassisted flow. Upon approval by the Commission, the operator will no longer be required to maintain the SSSV's in that well until any subsequent workover or stimulation of the well makes it again capable of unassisted flow. The Commission may require additional "no-flow tests" following subsequent well work. RECEIVED NOV 1 4 1995 Alas~ Oil & Gas Cons. Commission Anchorage Attachment 2 Proposed Revised Conservation Order 207, Rule 7. Rule 7. Automatic Shut-In Equipment (a) Each well shall be equipped with a Commission approved fail-safe automatic surface safety valve system (SVS) capable of preventing uncontrolled flow by shutting off flow at the wellhead. (b) The safety valve system (SVS) shall not be deactivated except during repairs, while engaged in active well work, or if the pad is manned. If the SVS cannot be returned to service within 24 hours, the well must be shut in at the wellhead and at the manifold building. ! Wells with a deactivated SVS shall be identified by a sign on the wellhead stating that the SVS has been deactivated and the date it was deactivated. . A liSt of wells with the SVS deactivated, the dates and reasons for deactivating, and the estimated re-activation dates must be maintained current and available for the Commission on request. (c) A representative of the Commission will witness operation and performance tests at intervals and times as prescribed by the Commission to confirm that the SVS and all associated equipment are in proper working condition. Attachment 3 Current Conservation Order 311, Rule 6. Rule 6. Automatic Shut-in Equipment (a) Upon completion, each well which is capable of unassisted flow of hydrocarbons shall be equipped with: a fail-safe automatic surface safety valve (SSV) capable of preventing an uncontrolled flow. a fail-safe automatic subsurface safety valve (SSSV), unless another type of subsurface valve is approved by the Commission, installed in the tubing string below the base of the permafrost capable of preventing an uncontrolled flow, (b) A well that is not capable of unassisted flow of hydrocarbons, as determined by a "no-flow" performance test witnessed by a Commission representative or by other means, is not required to have fail-safe automatic SSSVs. (c) For projects receiving Commission administrative approval, the requirements for fail-safe SSSV equipment may be waived. (d) SSSVs may be temporarily removed as part of routine wellwork operations without specific notice to, or authorization by, the Commission. RECEIVED NOV 1 4 1996 Alaska 0/I & ~s ~on~ Comm,nlon Attachment 4 Proposed Revised Conservation Order 311, Rule 6. Rule 6. Automatic Shut-In Equipment (a) Each well shall be equipped with a Commission approved fail-safe automatic surface safety valve system (SVS) capable of preventing uncontrolled flow by shutting off flow at the wellhead. (b) The safety valve system (SVS) shall not be deactivated except during repairs, while engaged in active well work, or if the pad is manned. If the SVS cannot be returned to service within 24 hours, the well must be shut in at the wellhead and at the manifold building. . Wells with a deactivated SVS shall be identified by a sign on the wellhead stating that the SVS has been deactivated and the date it was deactivated. . A list of wells with the SVS deactivated, the dates and reasons for deactivating, and the estimated re-activation dates must be maintained current and available for the Commission on request. (c) A representative of the Commission will witness operation and performance tests at intervals and times as prescribed by the Commission to confirm that the SVS and all associated equipment are in proper working condition. Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: The application of ARCO Alaska, Inc. to amend Rule 7 of Conservation Order No. 207 and Rule 6 of Conservation Order No. 311. ARCO Alaska, Inc. by letter dated October 28, 1996 has requested amendments to Rule 7 of Conservation Order No. 207 and Rule 6 of Conservation Order No. 311. The amendments would eliminate the subsurface safety valve requirements for all wells in the Lisburne and West Beach Oil Pools within the Prudhoe Bay Field and require surface safety valves only for those wells capable of unassisted flow of hydrocarbons to the surface. A person who may be harmed if the requested order is issued may file a written protest prior to 4:00 PM December 9, 1996 with the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501, and request a hearing on the matter. If the protest is timely filed and raises a substantial and material issue crucial to the Commission's determination, a hearing on the matter will be held at the above address at 9:00 am on December 27, 1996 in conformance with 20 AAC 25.540. If a hearing is to be held, interested parties may confirm this by calling the Commission's office, (907) 279-1433 after December 9, 1996. If no protest is filed, the Commission will consider the issuance of the order without a hearing. If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing, please contact Diana Fleck at 279-1433 no later than December 19, 1996. David W.~ohnston C o mmi s si o'ne,,....~..~ Published November 23, 1996 AO02714017 TONY KNOWLE$, GOVERNOR AL&SKA OIL AND GAS CONSERVATION COMMISSION 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3'192 PHONE: (907) 279-1433 FAX: (907) 276-7542 September 26, 1996 A.N. Bolea, Asset Manager GPMA BP Exploration (Alaska), Inc. P O Box 196612 Anchorage, AK 99519-6612 Dear Mr. Bolea: We are responding to your July 8, 1996 correspondence, which we received September 6, 1996, requesting a change to Conservation Order Nos. 207, 311, 317, and 329. The proposed change would modify the safety, valve system requirements by eliminating subsurface safety valves, and requiring surface safety, valves only in wells capable of unassisted flow to the sm'face. The Commission previously approved removal of subsurface safety valves for the Prudhoe and Kuparuk River oil pools. The modification to Prudhoe and Kuparuk orders was consistent with statewide safety valve requirements for onshore wells. The Niakuk and Pt. Mclntyre drill sites, however, are adjacent to the Beaufort Sea and the Commission wishes to see more information or your assessment of any potential risk of environmental damage because of the location of the wells. As for the remainder of your request, in our view the Lisburne and West Beach wells are properly operated under our statewide requirements for onshore wells. Accordingly, we are prepared to support your proposal to remove subsurface safety valves for .those pools. We invite you to meet with us to discuss this matter further. This will afford you the opportunity to either modify your request or to provide additional information supporting removal of the subsurface safety valve in the Pt. Mclntyre and Niakuk wells. Please contact Bob Crandall to arrange a meeting. ~l~id ~hnst°rman ~,, JTuckerman Babcock Commissioner ARCO Alaska, Inc.( Post Office B~... 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 July 8, 1996 Mr. David W. Johnston, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Re: Request to Revise Conservation Order 207, Rule 7 Prudhoe Bay Field, Lisburne Oil Pool Request to Revise Conservation Order 311, Rule 6 Prudhoe Bay Field, West Beach Oil Pool Request to Revise Conservation Order 317, Rule 8 Pt. Mclntyre Oil Field, Pt. Mclntyre & Stump Island Pools Request to Revise Conservation Order 329, Rule 5 Prudhoe Bay Field, Niakuk Oil Pool Dear Mr. Johnston: RECEIVED SEP 0 ~ 1996 Alasl<~ 0!1 & 62s Cons. Commission] .ARCO Alaska, Inc., Operator of the Lisburne, West Beach, Point Mclntyre and Stump Island Oil Pools, BP Exploration (Alaska), Inc., Operator of the Niakuk Oil Pool, and Exxon Company USA, Working Interest Owner in these Pools, request that the Commission revise the requirements of Conservation Orders 207, 311,317, and 329 to require only a surface safety valve for wells capable of unassisted flow. Similar to the previously approved requests from the Kuparuk, Milne Point, and Prudhoe Bay Units, the purpose of this request is to remove the subsurface safety valve requirement which will allow more efficient operation of the fields while maintaining a safe operation. Additionally, this will bring consistency to all Pools currently flowing into the Lisburne Production Center (LPC). Conservation Order 345 for the North Prudhoe Oil Pool, the other Pool currently flowing into the LPC, does not require subsurface safety valves. This letter, which should be considered our joint formal request, is divided into three main sections covering the background, proposal, and justification for this action. BACKGROUND The pool rules referenced above (Conservation Orders 207, 311,317, and 329) require each well be equipped with both surface and subsurface safety valves for all wells capable of unassisted flow of hydrocarbons. The subsurface safety valve requirements in North Slope fields were originally requested by us based on the Iow level of experience with arctic production operations. After many years of safe operations, these concerns no longer exist. We have gained substantial arctic operating experience and now possess an extensive infrastructure operated by a highly skilled work force. ARCO Alaska, Inc. is a Subsidiary of AtlanticRichfieldCompany AR3t3-6003-C Mr. David W. Johnston, Chairman Request to Revise Conservation Order 207, Rule 7 Request to Revise Conservation Order 311, Rule 6 Request to Revise Conservation Order 317, Rule 8 Request to Revise Conservation Order 329, Rule 5 Page 2 One of the main concerns during the early years of arctic operation was the potential freeze back of the permafrost. Subsurface valves were used to protect against the risk of loss of well control due to casing collapse during freeze back of the permafrost. The uncertainty relating to this risk, however, was eliminated with the improved design of casing strings and cement capable of withstanding the thaw- freeze back forces. Over nineteen years of production operations on the North Slope have clearly demonstrated that this is no longer an area for concern. In the Lower 48, as in Alaska, subsurface safety valves are used primarily in offshore applications where wells and platforms are at risk due to hurricanes, oceangoing ships, and subsea mud slides. The use of subsurface safety valves in onshore wells in the Lower 48 is very rare and generally restricted to wells with extremely high levels of hydrogen sulfide, located in heavily populated urban areas. Consistent with the industry's practice in the Lower 48, the use of subsurface safety valves is not required or in use in any of the other onshore fields in Alaska outside of the North Slope. PROPOSAL. We propose that Conservation Order 207, Rule 7, Conservation Order 311, Rule 6, Conservation Order 317, Rule 8, and Conservation Order 329, Rule 5 be revised to eliminate the subsurface safety valve requirement for all wells, and to require a surface safety valve only in wells capable of unassisted flow of hydrocarbons. The pilot actuated surface safety valve is capable of automatically closing to prevent an uncontrolled flow. Surface valves will continue to be tested as required by the AOGCC every six months. For clarity, a copy of the current rules and proposed new rules are attached (Attachments 1- 8). Removing the .requirement for subsurface valves in the Lisburne, West Beach, Pt. Mclntyre, Stump Island, and Niakuk Oil Pools is consistent with the Commission's statewide regulation, 20 AAC 25.265, which imposes a universal subsurface valve requirement only for offshore wells. JUSTIFICATION Subsurface safety valves provide only a redundant level of protection to the surface safety valve. The risks which were thought to justify the extra protection provided by subsurface safety valves have proven to be either absent or extremely unlikely in the Oil Pool wells flowing into the LPC. In fact, subsurface valves actually create a small element of risk, as numerous downhole well operations are performed each year just to service and maintain existing valves. In addition, the requirement for subsurface valves may preclude or hinder the development and application of various alternate completion techniques being studied to extend the life of these fields. Mr. David W. Johnston, Chairman Request to Revise Conservation Order 207, Rule 7 Request to Revise Conservation Order 311, Rule 6 Request to Revise Conservation Order 317, Rule 8 Request to Revise Conservation Order 329, Rule 5 Page 3 Please note that we are not asking for a waiver of a statewide rule as 20 AAC 25.265(b) does not require either a surface or subsurface safety valve for onshore wells. Our proposal is to continue to exceed the requirements of the statewide rules by continuing to install and maintain surface safety valves. These revisions will result in a significant improvement in the efficiency of operations for all the pools flowing into the LPC. It is not our intent to remove or disable operational subsurface valves in wells in these Pools. However, if the operation of a well's subsurface valve becomes problematic, the Operator will decide if the subsurface valve should be repaired, removed, or disabled based on criteria adopted by the Owners. These revisions conform with prudent oil field management and will not adversely affect ultimate recovery. Please contact us if you have any questions or need more information. Our phone numbers are 263-4431, 564-5433, and 564-3689 for the ARCO, BPX, and Exxon contacts respectively. l~~cerely,, ,~,,~t. A. Leone /lanager GPMA ARCO Alaska, Inc. A. N. Bolea / J.F. Branch Asset Manager GPMA /_ ~Production Manager-Alaska BP Exploration (Alaska), Inc.Exxon Company USA Attachments Attachment I Current Conservation Order 207, Rule 7. Rule 7. Automatic Shut-In Equipment a) Any well which is capable of unassisted flow of hydrocarbons must be equipped with 1) a fail-safe automatic surface safety valve (SSV) capable of preventing an uncontrolled flow; and 2) a fail-safe automatic surface controlled subsurface safety valve (SSSV). This valve must be in the tubing string and located below permafrost. The valve must be capable of preventing an uncontrolled flow. For operational necessity the Commission may administratively waive the surface controlled requirement. b) A representative of the Commission will witness performance tests at ' times prescribed by the Commission to confirm that the SSV, SSSV, and all associated equipment are in proper working condition. c) When requested by the operator, a representative of the Commission will witness "no-flow tests" to verify that a well is no longer capable of unassisted flow. Upon approval by the Commission, the operator will no longer be required to maintain the SSSV's in that well until any subsequent workover or stimulation of the well makes it again capable of unassisted flow. The Commission may require additional "no-flow tests" following subsequent well work. Attachment 2 Proposed Revised Conservation Order 207, Rule 7. Rule 7. Automatic Shut-In Equipment (a) Each well shall be equipped with a Commission approved fail-safe automatic surface safety valve system (SVS) capable of preventing uncontrolled flow by shutting off flow at the wellhead. (b) The safety valve system (SVS) shall not be deactivated except during repairs, while engaged in active well work, or if the pad is manned. If the SVS cannot be returned to service within 24 hours, the well must be shut in at the wellhead and at the manifold building. , Wells with a deactivated SVS shall be identified by a sign on the wellhead stating that the SVS has been deactivated and the date it was deactivated. , A list of wells with the SVS deactivated, the dates and reasons for deactivating, and the estimated re-activation dates must be maintained current and available for the Commission on request. (c) A representative of the Commission will witness operation and performance tests at intervals and times as prescribed by the Commission to confirm that the SVS and all associated equipment are in proper working condition. Attachment 3 Current Conservation Order 311, Rule 6. Rule 6. Automatic Shut-in Equipment (a) Upon completion, each well which is capable of unassisted flow of hydrocarbons shall be equipped with: a fail-safe automatic surface safety valve (SSV) capable of preventing an uncontrolled flow. a fail-safe automatic subsurface safety valve (SSSV), unless another type of subsurface valve is approved by the Commission, installed in the tubing string below the base of the permafrost capable of preventing an uncontrolled flow. (b) A well that is not capable of unassisted flow of hydrocarbons, as determined by a "no-flow" performance test witnessed by a Commission representative or by other means, is not required to have fail-safe automatic SSSVs. (c) For projects receiving Commission administrative approval, the requirements for fail-safe SSSV equipment may be waived. (d) SSSVs may be temporarily removed as part of routine wellwork operations without specific notice to, or authorization by, the Commission. RECEIVED ~EP O~ 1996 Alaska Oil & G~s Cons. Commission Attachment 4 Proposed Revised Conservation Order 311, Rule 6. Rule 6. Automatic Shut-In Equipment (a) Each well shall be equipped with a Commission approved fail-safe automatic surface safety valve system (SVS) capable of preventing uncontrolled flow by shutting off flow at the wellhead. (b) The safety valve system (SVS) shall not be deactivated except during repairs, while engaged in active well work, or if the pad is manned. If the SVS cannot be returned to service within 24 hours, the well must be shut in at the wellhead and at the manifold building. , Wells with a deactivated SVS shall be identified by a sign on the wellhead stating that the SVS has been deactivated and the date it was deactivated. . A list of wells with the SVS deactivated, the dates and reasons for deactivating, and the estimated re-activation dates must be maintained current and available for the Commission on request. (c) A representative of the Commission will witness operation and performance tests at intervals and times as prescribed by the Commission to confirm that the SVS and all associated equipment are in proper working condition. Attachment 5 Current Conservation Order 317, Rule 8. Rule 8. Automatic Shut In Equipment a. Upon completion, any well which is capable of unassisted flow of hydrocarbons to the surface shall be equipped with: a fail-safe automatic surface safety valve (SSV) capable of preventing uncontrolled flow. ii. a fail-safe automatic subsurface safety valve (SSSV), unless other type of subsurface valve are approved by the Commission, shall be installed in the tubing string below the base of the permafrost and be capable of preventing an uncontrolled flow. b, A well that is not capable of unassisted flow of hydrocarbons, as determined by a "no-flow" performance test witnessed by a Commission representative, is not required to have fail-safe automatic SSSV's. C, SSSVs may be temporarily removed as part of routine well operations without specific notice to, or authorization by the Commission. Attachment 6 Proposed Revised Conservation Order 317, Rule 8. Rule 8. Automatic Shut-In Equipment (a) Each well shall be equipped with a Commission approved fail-safe automatic surface safety valve system (SVS) capable of preventing uncontrolled flow by shutting off flow at the wellhead. (b) The safety valve system (SVS) shall not be deactivated except during repairs, while engaged in active well work, or if the pad is manned. If the SVS cannot be returned to service within 24 hours, the well must be shut in at the wellhead and at the manifold building. . Wells with a deactivated SVS shall be identified by a sign on the wellhead stating that the SVS has been deactivated and the date it was deactivated. . A list of wells with the SVS deactivated, the dates and reasons for deactivating, and the estimated re-activation dates must be maintained current and available for the Commission on request. (c) A representative of the Commission will witness operation and performance tests at intervals and times as prescribed by the Commission to confirm that the SVS and all associated equipment are in proper working condition. Attachment 7 Current Conservation Order 329, Rule 5. Rule 5. Automatic Shutln Equipment a. Upon completion, each well shall be equipped with: a fail-safe automatic surface safety valve (SSV) capable of preventing uncontrolled flow. ii. a fail-safe automatic subsurface safety valve (SSSV), unless other types of subsurface valve are approved by the Commission, shall be installed in the tubing string below the base of the permafrost and be capable of preventing uncontrolled flow. b. A well that is not capable of unassisted flow of hydrocarbons, as determined by a "no flow" performance test witnessed by a Commission representative, is not required to have fail-safe automatic SSSV's. C. Safety valves may be temporarily removed for not more than 15 days as part of routine well operations or repair without specific notice to, or authorization by the Commission. The SSV and SSSV may not be simultaneously out of service without specific authorization from the Commission. Wells with SSV's or SSSV's removed shall be identified by a sign on the wellhead stating that the valve has been removed and the date of removal. ii. A list of wells with SSV's and SSSV's removed, removal dates, reasons for removal, and estimated re-installation dates must be maintained current and available for Commission inspection on request. do The Low Pressure Sensor (LPS) systems shall not be deactivated except during repairs to the LPS, while engaged in active well work or if the Pad is manned. If the LPS cannot be returned to service within 24 hours, the well must be shut-in at the well head and at the manifold building. Wells with a deactivated LPS shall be identified by a sign on the wellhead stating that the LPS has been deactivated and the date it was deactivated. ii. A list of wells with the LPS deactivated, the dates and reasons for deactivating, and the estimated re-activation dates must be maintained current and available for Commission inspection on request. Attachment 8 Proposed Revised Conservation Order 329, Rule 5. Rule 5. Automatic Shut-In Equipment (a) Each well shall be equipped with a Commission approved fail-safe automatic surface safety valve system (SVS) capable of preventing uncontrolled flow by shutting off flow at the wellhead. (b) The safety valve system (SVS) shall not be deactivated except during repairs, while engaged in active well work, or if the pad is manned. If the SVS cannot be returned to service within 24 hours, the well must be shut in at the wellhead and at the manifold building. . Wells with a deactivated SVS shall be identified by a sign on the wellhead stating that the SVS has been deactivated and the date it was deactivated. , A list of wells with the SVS deactivated, the dates and reasons for deactivating, and the estimated re-activation dates must be maintained current and available for the Commission on request. (c) A representative of the Commission will witness operation and performance tests at intervals and times as prescribed by the Commission to confirm that the SVS and all associated equipment are in proper working condition. RECEIVED SER 0 (~ 1996 Alaska 0]] & G.as CoDs. Commission An0h0rc. ge FROM ~PMA AN~HORAOE ~ I. Pu rpos_~ FAX HO.: 26~4894 i~ GREATER POINT MclNTYRE AREA SSSV MANAGEMENT IMPLEMENTATION PLAN 8/8/96 08-09-96 The purpose of 1his implementation plan is to provide a means to consistently manage the usage and removal of subsurface safety valves (SSSV) from Greater Point Mclntyre Area (GPMA) wells. The procedures, and other information have been reviewed with and approved by ARCO, Exxon, and BP Exploration management. il. Background On ._ ,1996, the Alaska Oil and Gas Conservation Commission (AOGCC) approved Conservation Order No. , (see A!~pendix I) which modified: Field Rule No. 7 for the Lisburne Oil Pool, Field Rule No. 6 for the West Beach Oil Pool, Field Rule No. 8 for ti~e Point Mclntyre & Stump Island Oil Pools, and Field Rule No. 5 for the Niakuk Oil Pool. The Order eliminated the requirement for SSSVs in wells in these Pools (Conservation Order 345 for the North Prudhoe Bay Oil Pool, the other Pool currently flowlng in the Lisburne Production Center, does not require subsurface safety valves), A Safety Valve System (SVS) including a surface safety valve (SSV) is still required for each well. The requirement for SSSVs was included in the original field rules for these Pools because of a relatively Iow level of experience in Arctic production operations at that time. One of the primary concerns was the potential for freeze back of permafrost and the impact this may have on casing collapse and subsequent well control problems, The North Slope operators have demonstrated that the concern regarding casing collapse has been adequately addressed by the proper design of casing, annular fluids, and cementing systems for Arctic conditions. Additional justification for removing the AOGCC requirement for SSSVs was provided by m~my years of safely operating on the North Slope, a highly skilled workforce, and an extensive infrastructure. I!1..General.. I.nforma_tion 'Environmental Issue ,For consfstency, minor wording changes relating to SSSVs were made in both the EOA & J~_OA Oil Di$charg~___Preventi_on and Contin_c/_eney Plans ("C-Plan")and have been submitted to the Alaska Department of Environmental Conservation (ADEC) and other appropriate agencies as updates to the C-Plans. No changes to other environmental plans are necessary. General Removal Approach SSSV removals/deactivations will generally occur in the order listed below assuming that the criteria and approvals outlined in the Criteria and Procedure sections are addressed. It is the FROM: GPMA AHOHORAGE I" ~ FAX NO.: 26:54894 ~"" 08-09-96 1~;::S2 P,O:~ intention of ARCO and BPX to utilize many of the existing SSSVs for as long as reasonably possible. There are no target dates established for SSSV removal/deactivation. 1) Remove K-Valves. These SSSVs result in various operational problems and In most ce. see require back pressure to be held on the well to prevent nuisance shut-ins. The end result is reduced oil production rates and incremental wireline and operator costs. 2) Disable/remove safety valves with current chronic problems. An example of this is a well with a chronic hydraulic leak in the control Pine system which requires frequent operator attention (i.e,, repressuring the hydraulic fluid reservoir on the panel two or more times a day. 3) Pull wireline-retrievable (WRSSSV) or disable tubing-retrievable (TRSSSV) SSSVs at next wireline opportunity. SSSVs add incremental wireline costs and a small element of risk through additional wireline runs. It is not recommended to make wiretine unit rig-ups specifically to pull/disal:)le an SSSV, 4) Utilize remainder of SSSVs until an operational decision to remove/disable is made. It is recognized that there is a cost to disable or remove a subsurface valve. As a result, many cf the subsurface valves will remain in service and will be gradually phased out as they impair well operations and require costly m~tintenance to keep them functional. Operations Standard Operating Procedures The GPMA Drill Site SOPs have been revised to reflect the minor operational changes resulting from the SSSV removaVdeactivation, These changes have been communicated to the GPMA Drill Site Operators'via the Management of Change guidelines. IV. _Criteria It is expected that the removal/deactivation of SSSVs in the GPMA will not be accomplished immediately, but will be conducted in a phased approach over several years. The SSSVs will be removed/deactivated based on operational and economic considerations. However, some wells may continue to have functioning SSSVs based on their productive potential, proximity to facilities, potential for environmental Impact, special corrosion concerns, or well usage. Proclucers are segregated into tWO categories b~sed on total fluid and gas rates. Listed below are the criteria to be utilized when considering an SSSV for rem ova I/deactivatio n, Category I - Producers FROM~ GPMP ANCHORAGE '" FA~ NO.: 2634894 08-09-96 GREATER POINT MclNTYRE AREA SSSV MANAGEMENT IMPLEMENTATION PLAN 8/8/96 1~:52 P.04 The following wells will be designated as Category I wells and will be required to have a functional SSSV in the GPMA: · Every producing well until~t has been evaluated/and reclassified. * Covered 'jndcr ~J$ last bu!!ct arc.-a(A~l producing wells at Point Mclntyre, West Beach, North Prudhoe Bay, and Niakuk wh~ ,.,;,..,,, ~....... ~..~-~.~..,,.,4~..,,..,..~.,~.~ ~,..,..~^..,~.....~.., ~ I due to their close proximity to open water and regardless of their actual rates. o Producing wells that have unlifted rates greater than or equal to 5000 BLPD or greater titan or equal to 25 MMSCFPD. · Producing wells that have unlifted rates less than 5000 BLPD and less than 25 MMSCFPD but have special concerns such as proximity to facilities or populated areas, potential for environmental impact, special corrosion c(3ncerns, or well usage as determined by the GPMA Superintendent (ARCO)/PE Supervisor (BPX). Exception: A.n..v. p_r.~ducing well__may be exempted from this category by aka_jo!hr_ ag_ree~me~nt_of2' th~,,~e'ii ~"V~)~ki~'g I~l:~-r'&%t Ow'i~'ers-~z-r..... .... ~.., ! .......... ~..,, and reclas~l-[. Category !!- Producers Category II wells include all producing wells not included in Category I and are not required to have an SSSV. Any designation into this category requires a written recommendation by the GPMA Drill Site Supervisor (ARCO) and approval by the GPMA Superintendent (ARCO)/PE Supervisor (BPX). Wells included in this Category are: · Producing wells that have unlifted rates less than 5000 BLPD and less than 25 MMSCFPD, and have not been classified as Category I. Producing wells with unlifted rates greater than or equal to ,5000 BLPD or .¢z:i.u, al .1o ~.5..,.MM~SCFPD that have been reclassified as Category II by the~well's Working I nte rest ' O~/i~ 6;~.~it~leCJ.~-~ ~n a~cr, Injection Wells Gas injection wells, both natural gas and manufactured miscible gas, will continue to require SSSVs based on their potential deliverability and the risk of personnel safety, Water iniection wells will not require SSSVs, New Wells All new completions will be assigned to an SSSV Category by the GPMA Drill Site Supervisor based on projected usage and rate estimates provided by the Surveillance Engineer (see Appendix !1), All Category I wells will have an SSSV included in the completion design. Wells designated as Category tl will be approved as such by the GPMA Superintendent (ARCO)/PE Supervisor (BPX) and wili not be completed with an SSSV. All completions which do not have an SSSV will have a profile at 500-i-_ for setting a safety device if needed at a later date, FROM: GREATER POINT MclNTYRE AREA SSSV MANAGEMENT IMPLEMENTATION PLAN 8/8/96 When initial stabilized production rates are available from the new completions, the GPMA Field Engineer will verity that the well was assigned to the proper SSSV Category. No action is required for wells which produce at or below the maximum rate criteria for the pre- completion SSSV Category. If any well exceeds the maximum rate criteria for the pre- completion SSSV Category, the GPMA Drill Site Supervisor (ARCO) or Sr. Wireline Coordinator (BPX) is required to take the necessary action to get the well In compfiartce witl~ the Implementation Plan within 60 day~ (i.e., cither !nsta!!~.n ~SSV cr get Ficld Mc, nagcr V. Pro_ced ure. There are two procedures in this section. The first outlines the processes which will be used to a) Identify the_,jQLti_a,J_C.~_e,g, gr~of preducing,w_.eJ,l!s _a..12,q. b.,Lm~.ir].ta~ C_a. te.clory_ upda.t,c_es.,.q,n_,,_a` -- - -- I -- , _ / -..-. '~ -; -.~/~---'-...,¢------..4'-"7':"' "T.-- ~ .... . . ..~r ,, "'""--.~'--?'~''--'--~-,"',,4----*''t' . -'r. _ ..q..u,a, rzer.y uas,~LLS.k,~ ne secona proceaure aennes the steps 1o u.e To~lowea when ~ ~s desJrea To ,~" rem'o~ ad sss'v fro-n ,service..,--- ......... "' ' ............................. '---- ................ ~-- ...... '----"-"- proced_u_re #1 - Initial DEtermination of Cate__Eory of Producers The first step in the SSSV removal/deactivation process is the determination of which wells in the field are in each Category. This section describes the methodology for identifying the Category of those wells, based on liquid and gas rate cutoffs. A) Initial Procedure: 1) The GPMA Field Engineer will identify all GPMA producing wells which have estimated unlifted rates greater than 5000 BLPD or greater than 25 MM$CFPD, at any time during the previous 12 months, 2) Wells which fail into this group, and CURRENTLY have VALID estimated unlifted rates Iess than 5000 BLPD and less than 25 MM$CFPD, will be deleted from the list. Well test data is considered valid as a basis for estimate Only if the test was conducted within the previous SIX months, was deemed a "good" test for allocation purposes, and the choke was in the full open position. 3) Wells which do not have valid well test data will be re-tested. 4) The Category of each well will be Identified based on the gathered valid well test data and the CAtegory I & II criteria outlined in the previous section. NOTE: If it well qualifies for Category II, Procedure #2 must be followed to obtain proper authorization to remove/deactivate the well's SSSV. A listing of all GPMA wells grouped by Category will be distributed by the GPMA Field Engineer to the GPMA Drill Site Supervisor (ARCO) and the Sr. Wirellne Coordinator (RPX). RECFIVED ~'FP "' 4 3._, 0~:' i995 Gas C O,,"')s. uuiTI~,o?,IOB Atasks ' ' ,, ....... . FROH ~ BPI'lO ANCHORAGE (" Fi:I:.; NO.I 2634894 ~' 00-09-96 1:~::~5 P.06 GFIEATER POINT MclNTYRE AREA $SSV MANAGEMENT IMPLEMENTATION PLAN 818196 6) Functional testincj and maintenance for all Category I SSSV$ will be carried out according to the regulations and procedures in effect prior to ,1996. B) Periodic Update to Category Determinations: The list of Category I and Category !1 wells (by production rale) will be updated each quarter by the GPMA Field Engineer to reflect any changes in production characteristics of the wells. The updated list will be distributed to the GPMA Drill Site Supervisor (ARCO)/Sr. Wireline Coordinator (BPX). Wells that are currently Category II but have Category [ production characteristics wilt be forested within three days and a $$SV will be installed within sixty days if the test rate is equal to or greater than 5000 BLPD or 25 MMSCFPD. The GPMA Field Engineer will ensure that all of the Category I SSSVs have been tested within the preceding six months. Prqcedure ~2 - PrO_c__edure for.. SSSV ExemDtio_o/Re_rnov_8.t The purpose of this procedure is to ensure that a consistent approach is taken when considering the exemption of a subsurface safety valve , .... ~ .. ..... ~ GPMA well. Each decision 1o remove/deactivate an SSSV may impact the safety of the well operation and should be carefully weighed regardless of rate, It is important to consider the various impacts of well energy, potential corrosion damage, safety, potential environmental impact, economics, and future welt usage in the SSSV removal decision process. Procedure' i Note; This procedure does not currently apply to producing wells at Point Mclntyre, West ? Beach, North Prudhoe Bay, and Niakuk. SSSVs wilt continue to be maintained and tested in , those wells (as per the Category I criteria above)..--.,... -,'----- ..,"'"" '"" , · o~ .... .'~"~'~~--'"~'",..., .,, ",,, '~,,, , ,.,, , , .'-',..-,., .... ,.- ~ ....... 1) Obtain a valid welt test. 2) Use the following table to determine the appropriate level of approval necessary to remove/deactivate an SSSV' ' V~ell Tea{ "Rate .... Format[on Gas Req'd Appro'val CAT BLPD Rate Level M$CFD >_ 5000 '"or ''~. 2500'0 No Removal Deactivatio~ i ',~5000 b~t and ' <25000 but No Remov,~l p..r Special Consideration Special Consider. Deastivat~or[';,.~ (see CAT I Criteria) (see CAT I .......... Criteria) .. II...... <$000 ' ' and < 25000 '" GPMA Supt(ARCO}/ PE SuP_V(BPX) FROM: GPMA ANCHORAGE ' FAX NO.: 2634894 i~'' 08-09-96 13:54 P.87 GREATER POINT MolNTYRE AREA B$!BV MANAGEMENT8/81961MPLEMENTATION PLAN ¢~//~~ - ,, l_ ll ~ff~ ~l~ l~~ . ......... ~.--~~ ........ ~----~~, ........... ~ ............ ~~ .... ~ .......... . ...... ' SSSVs will be maimain~-and tested in wells wi~h rates in this range unless removal is '~ approved by th~ well's Working Interest Owners, ~ .... ~ ..~_...~ .... ~ 3) The GPMA Drill Site Supervisor will prepare the REQUEST FOR GPMA SSSV EXEMPTION FORM (see Appendix III) end submit ~ for approval, The GPMA Field Engineer will retain the original approved form in their files, and will distribute a copy of ~ to the appropriate personnel listed on the boEom of ~he form. 4) Following the removal/deactivation of the SSSV, the GPMA Field Engineer will ensure that the appropriate information is entered jn the EOA/WOA Subsurface Safety Valve Master Database for tracking SSSV removals/deactivations on a Operator-wide basis. 5) The GPMA Field Engineer is responsible for making and distributing the appropriate changes 1o the Weltbore Schematic. e) The GPMA Drill Site Supervisor is responsible for ensuring that a sign is placed on the outside of the wellhouse indicating "CAT II-NO S$,~V". In addition, a CAUTION tag will be utilized in the wellhouse (at the tree needle valve and on the hydraulic panel) to denote that the SSSV has been removed/disabled. Vi, S$SV/_S.$V TeS_ting/'Mair~_tenanc_e During the first 12 months following ~itial e.x_ecution of the Implementation Plan, all of the potential Category II wells will be~v~'~-~:t~'a'..'.~ by the Gl=MA Superintendent (AROO)/PE Supervisor (BPX) as to t e~rh'i~i'FT~$~ctive SSSV requirement. Those wells which are granted an exemption and are approved for operi~tion without SSSVs will require no further testing or maintenance of the SSSV. Conversely, the wells for which there is no exemption of the SSSV requirement wild continue to be tested and maintained in accordance to the procedures in effect prior to ..,,_.1~99.6. All wells will continue to be tested at the current six month frequency Ontil they ~re ~~t~Td~iecislcncd. Testing Testing will be conducted to meet requirements set prior to , 1996, and test frequency will continue to be once every six months. The SSSV testing be conducted in conjunction with the regularly scheduled State-witnessed testing of the well's Safety Valve System (SVS). Surface safety valves (SSV) and Iow pressure pilot valves/switches on all wells except water injectors will continue to be State-tested on current 6 month schedule as per current AOGCC regulations. It should be noted that when an SSV fails a State test, the valve must be repaired or replaced no later than the next calendar day. In addition, GPMA operating procedures dictate that a Iow pilot/swilch failure on a prodv.¢ir~...we[~ ce%uires one of the 0 i99 FROM~ FgX ~0.: 26J4894 i" 08-09-96 15:J5 P.08 Mc:INTYRE AREA GREATER POINT SSSV MANAGEMENT IMPLEMENTATION PLAN 8/8/96 following actions: 1) the pilot/switch be repaired immediately with a man-watch on the pad until repairs are completed or, 2) the well is shut-in at the wellhead and manifold building. The GPMA FieJd Engineer will continue to coordinate State-testing as well as maintain SVS test records 1or the field. Maintenance The emphasis of the well SVS maintenance program in the GPMA will be on the surface safety valves and pilot valves/switches. This equipment has been demonstrated to be more reliable in part because of its accessible location. The only SSSVs which will be maintained will be tho~e Category I wells identified in the Criteria section as required to have functional SSSVs in place and the Gas Injection Wells. VII. Trecki ng/Doc_u_ment@tion The GPMA Field Engineer is responsible for the tracking system to document the status of the SSSVs for each well in the field. 1) _R_~uest For GPMA S_S_SV Exemc~tion Forms - The GPMA Field Engineer will retain the original approved hard cc~py in their files and will dislribute a copy to the personnel listed on the bottom of the form. 2) EONW.0A Subsq. r. face Safety Valve Master Database - This will be the central tracking database for each area o~ the field The GPMA Field Engineer will ensure the database is updated when the approved removal/deactivation forms are received and the well work has been completed, it will not be necessary to enter an SSSV which has been removed from service on the Safety Defeated Log (SDL) since the removal is being tracked on a master database. VIII. ~omrn un i.c,_at ion The GPMA Drill Site Supervisor will ensure that the following items are completed: Wellsite 1) Sign on outside of wellhouse (red metal background with white letters) for wells without SSSVs: required verbiage - "CAT II-NO $$SV". 2) CAUTION tags on the tree needle valve and on the hydraulic panel indicating: ",..,e$$V Not in Service". Well Records FROM: GPMA ANCHORAGE FA~ NO.: 26~4B94' GREATER POINT MclNTYRE AREA MANAGEMENT IMPLEMENTATION 8/8/96 00-09-96 13:35 P .09 PLAN 1) Wellbore Schematics - The GPMA Field Engineer will make the proper notations on the wellbore schematics to indicate that an SSSV is not In service, or that an SSSV is not installed. IX. Pro_o_ram Review .P. roeess~ Initial Plan Assessment An Initial Plan Assessment will be conducted by the Operator's HSET Departments beginning six months after the Implementation Plan is instituted in the field. The purpose of the assessment will be to evaluate and report to management on Plan compliance, Plan deficiencies, and make a recommendation on whether future HSET assessments are required. Annual Review The annual review process is viewed as a very important component of managing SSSV utilization and removal in the GPMA. As experience is gained, it may become necessary to adjust the management of the process. The GPM~A Drill Site Supervisor wilt be responsible for initiating the annual review process. Exxon~cu!d be invited to participate in the annual review because of their contribution to the development of the criteria utilized in the Implementation Plan. It is suggested that the annual review should accomplish the following objectives: 1) Review the status of SSSV removal/deactivation in the field. Examples of information to be inCluded are number of valves removed/deactivated, types of wells impacted, any notable problem areas, assess risk of the current implementation ptan, identify wells which crossed Category lines following the removal/deactivation of the SSSVs. 2) Review the decision criteria and make recommendations to revise the criteria if necessary. 3) Report the status of the SSSV removal/0eactivation progress to management. STATE OF ALASKA' ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re: Request by ARCO ALASKA, INC.) et al to present testimony ) to revoke Conservation Order) No. 83-C and adopt new rules) for the Lisburne Oil Pool ) in the Prudhoe Bay Field. ) Conservation Order No. 207 Prudhoe Bay Field Lisburne Oil Pool January 10, 1985 IT APPEARING THAT: 1. ARCO Alaska, Inc., on behalf of itself and Exxon Corpo- ration, requested the Alaska Oil and Gas Conservation Commission to hold a public hearing in order to receive testimony for the revocation of Conservation Order No. 83-C and establishment of new pool rules for the development and depletion of the Lisburne Oil Pool in the Prudhoe Bay Field. 2. Notice of the public hearing was published in the Anchorage Times on October 26, 1984. 3. A public hearing was held at the Municipality of Anchorage Assembly Room, 3500 East Tudor Road, Anchorage, Alaska on November 29, 1984. 4. Members of the staff of ARCO Alaska, Inc. presented testimony on behalf of itself, Exxon Corporation and Sohio Alaska Petroleum Company. Exxon Corporation presented a statement in full support of the testimony. The hearing record remained open until 4:30 pm, December 10, 1984. Timely comments were submitted by Sohio Alaska Petroleum Company and Mr. Kelley Everett,. FINDINGS: 1. The Lisburne Group underlies the Sadlerochit Group and consists primarily of shallow marine limestone and dolomite with lesser amounts of shale, silt, sand, and chert. 2. Shaly or silty beds are fairly continuous over a broad area and are useful for correlation. 3. The Lisburne Group is characterized by abundant natural and predominately vertical fractures which allows for fluid movement through the carbonates as well as the thin silty and shaly beds. Conservation Or~ Page 2 January 10, 1985 No. 207 ii: 4. The Lisburne Group of carbonate sediments was penetrated in it entirety by ARCO Prudhoe Bay State Well #1. The top of the Lisburne Group was encountered at a measured depth of 8,790 feet and the base at 10,440 feet measured depth. 5. The Lisburne Group has been partially or fully pene- trated by numerous wells. Oil and gas has been encountered within the Lisburne Group as low as 10,050 feet subsea within the area described by Conservation Order No. 83-C. 6. Evidence indicates that an oil reservoir with an associated gas cap exists and that an oil pool should be defined. The hydrocarbon accumulation may appropriately be defined as the Lisburne Oil Pool. 7. The Lisburne Reservoir is an anticlinal structure that is bounded on the north by the Prudhoe Bay-Niakuk fault complex, by truncation and/or the Mikkelson Bay fault to the east and by dip of 135 feet per mile to the south and west. 8. Evidence is sufficient to establish a definitive gas-oil contact at 8,600 feet subsea. Data are anomalous and insufficient to definitively establish an area-wide planar oil-water contact for the Lisburne Oil Pool. 9. The affected area described in Conservation Order No. 83-C. appears to be adequate in the eastern portion of the Lisburne Oil Pool but should be expanded westward to reflect the current structural interpretation. 10. A spacing unit of one producing well per governmental quarter section appears adequate to drain the reservoir. 11. Conductor casing set and cemented a minimum of 75 feet below surface should provide adequate anchorage for a diverter system. 12. The effects of permafrost thaw-subsidence and freeze back loadings can be mitigated by setting and cementing surface casing of sufficient strength at least 500 feet below the base of the permafrost but no deeper than 5000 feet true vertical depth. 13. Several casing types and grades that are approved for use as surface casing in the Prudhoe Oil Pool and the Kuparuk River Oil Pool are appropriate for this pool. 14. Perforation of cemented casing or liners, slotted liners, screen wrapped liners, gravel packs and open hole completions appear to be equally effective completion techniques. Conservation Or~ {' No. 207 Page 3 January 10, 1985 15. Significant concentrations of hydrogen sulfide gas were encountered in a production test of the ARCO Pingut State Well No. 1 and smaller amounts of hydrogen sulfide gas have been reported from other wells. 16. Installation of automatic surface shut-in valves is appropriate to prevent an uncontrolled flow of oil or gas. 17. Installation of automatic down hole shut-in valves in the tubing below the premafrost is appropriate to prevent an uncontrolled flow of oil or gas. 18. The flaring of a limited amount of gas will be neces- sary for the safety purposes and for operational necessities. 19. To aid in the evaluation of the effectiveness of the reservoir depletion, the reservoir pressure and the gas-oil ratio of ~ells should be monitored on a regular and continuous basis. 20. Current studies indicate that a daily oil rate of 160,000 barrels will not be detrimental to ultimate hydrocarbon recovery. However, pool withdrawal rates in excess of 160,000 barrels of oil per day may affect ultimate recovery. 21. Conservation Order No. 83-C is out-of-date and should be rep laced. 22. Evidence is insufficient to determine the prudency of state of the art methods for enhancement of recovery from the Lisburne Oil Pool. Pilot field projects are necessary to develop data for determination of the applicability of methods for recovery enhancement. 23. Evidence indicates that the injection of produced gas into the gas cap will retard the rate of decline in reservoir pressure. 24. .The average initial reservoir pressure for the Lisburne Oil Pool is 4,490 pounds per square inch at an 8,900 foot subsea datum. Reservoir temperature approximates 183° Fahrenheit at the datum. 25. The Lisburne Oil Pool contains in excess of 3 billion barrels of Original Oil In Place (OOIP). Primary depletion may recover no more than 7 percent of the OOIP. 26. It appears that most if not all of the Lisburne Oil Pool lies within the current boundary of the Prudhoe Bay Unit. However, it is possible that the pool limits may extend beyond the Prudhoe Bay Unit boundary. · Conservation Orr ~ No. 207 Page 4 January 10, 1985 27. Terms of the Prudhoe Bay Unit Agreement provide for the expansion of the Prudhoe Bay Unit boundary and for the establishment and expansion of an initial participating area for the Lisburne Oil Pool. 28. Management of the Lisburne Oil Pool under terms of the Prudhoe Bay Unit Agreement will effectively protect correlative rights, prevent waste and insure the maximum hydrocarbon recovery. NOW, THEREFORE, IT IS ORDERED THAT the rules hereinafter set forth apply to the following described area and is referred to in the order as the affected area: IrMIAT MERIDIAN 'Ti ON, R13E T10N, R14E TI ON, R15E T10N, R16E T10N, R17E TllN, R13E TllN, R14E TI IN, R15E TllN, R16E TllN, R17E T12N, R13E T12N, R14E T12N, R15E T12N, R16E Sections 1, 2, 3, 10, 11, and 12. Sections 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 35, and 36. All. All. Sections 3, 4, 5, 6, 7, 8, 9, 10, 15, 16, 17, 18, 19, 20, 21, 22, 27, 28, 29, 30, 31, 32, 33, and 34. Sections 1, 2, 3, 4, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, and 36. All. Ail. All. Sections 3, 4, 5, 6, 7, 8, 9, 10, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30 ,31, 32, 33, 34, 35, and 36. Sections 35 and 36. Sections 13, 14, 15, 16, 21, 22, 23, 24, 25, 26, 27, 28, 31, 32, 33, 34, 35, and 36. Sections 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, and 36. Sections 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, and 36. -Conservation Ore ~' No. 207 Page 5 January 10, 1985 Rule 1. FIELD AND POOL NAME. The field is the Prudhoe Bay Field and the pool is the Lisburne Oil Pool. Rule 2. POOL DEFINITION. The Lisburne Oil Pool is defined as the accumulations of oil and gas which occur in stratigraphic sections which correlate with the stratigraphic section found in the Atlantic Richfield-Humble Prudhoe Bay State No. 1 well between the depths of 8,790 feet measured depth and 10,440 feet measured depth. Rule 3. WELL SPACING. The spacing unit shall be one producing well per governmental quarter section. No pay may be opened in a well closer than 1,000 feet to the pay opened in another well or opened in a well which is closer than 500 feet to the boundary of the affected area. Rule 4. CASING AND CEMENTING. a) A conductor casing shall be set at least 75 feet below the surface and sufficient cement shall be used to fill the annulus behind the pipe to the surface. Rigid high density polyurethane foam may be used as an alternate to cement, upon approval by the Commission. The Commission may also administratively approve other sealing materials which are supported by sound engi- neering principles and performance data. b) Surface casing to provide proper anchorage for equipment to prevent uncontrolled flow, to withstand anticipated internal pressure and to protect the well from the effects of permafrost thaw-subsidence or freeze back loadings shall be set at least 500 feet, measured depth, below the base of the permafrost but not below 5000 feet true vertical depth. Sufficient cement shall be used to fill the annulus behind the casing to the surface. c) Surface casing types and grades approved for use through the permafrost interval include: 1) 13-3/8 inch, 72 pounds/foot, 2) 13-3/8 inch, 72 pounds/foot, 3) 13-3/8 inch, 68 pounds/foot, L-80 Buttress; N-80 Buttress; MN-80 Buttress. Conservation Ore ~', No. 207 Page 6 January 10, 1985 d) e) The Commission may administratively approve additional types and grades of surface casing through the permafrost interval upon a showing that the proposed casing and connection can withstand the permafrost thaw-subsidence and freeze back loadings which may be experienced. Evidence submitted to the Commission shall include: 1) full scale tension and compression testing; or 2) finite element model studies; or, 3) other types of axial strain data acceptable to the Commission. Alternate casing programs may be administratively approved by the Commission upon application and presentation of data which show the alternatives are appropriate, based upon accepted engineering principles. Rule 5. COMPLETION PRACTICES. Wells completed for production may utilize casing strings or liners cemented through the productive intervals and perforated, slotted liners, screen-wrapped liners, gravel packs or open hole methods, or combinations thereof. The Commission may administra- tively approve alternate completion methods where appropriate. Rule 6. HYDROGEN SULFIDE. a) Drilling and production equipment and operations shall be in accordance with: 1) 20 AAC 25. 065(c)(1) detection monitoring, (2) contingency and control, and (3) training; 2) 20 AAC 25.065(b) prior to penetration of the top of the Lisburne Group for all step-out wells surrounding the Pingut St. No. 1 well, located 1142' FSL, 1298' FWL, Sec. 24, TilE, R15E, UM, or step-outs from any subsequent well with hydrogen sulfide concentrations greater than 25 ppm; 3) API RP 55, Conducting Oil and Gas Production Operations Involving Hydrogen Sulfide, First Edition, October, 1981; and 4) API RP 7G, Section 8, Drill Stem Corrosion and Sulfide Stress Cracking, Eighth Edition, April, 1978 when drill pipe utilized has a yield strength~ greater than 95,000 psi. Conservation Ore ~ do. 207 Page 7 January 10, 1985 Rule 7. AUTOMATIC SHUT-IN EQUIPMENT. a) Any well which is capable of unassisted flow of hydrocarbons must be equipped with 1) a fail-safe automatic surface safety valve (SSV) capable of preventing an uncontrolled flow; and 2) a fail-safe automatic surface controlled subsurface safety valve (SSSV).This valve must be in the tubing string and located below permafrost. The valve must be capable of preventing an uncontrolled flow. For operational necessity the Commission may administratively waive the surface controlled requirement. b) A representative of the Commission will witness performance tests at times prescribed by the Commission to confirm that the SSV, SSSV, and all associated equipment are in proper working condition. c) When requested by the operator, a representative of the Commission will witness "no-flow tests" to verify that a well is no longer capable of unassisted flow. Upon approval by the Commission, the operator will no longer be required to maintain the SSSV's in that well until any subsequent workover or stimulation of the well makes it again capable of unassisted flow. The Commission may require additional "no-flow tests" following subsequent well work. Rule 8. GAS VENTING OR FLARING. a) The venting or flaring of gas is prohibited except for operational necessities and for safety volumes set out in this rule; b) A daily average volume of 1,000 MCF per day is approved for the safety flare at the Lisburne Production Center; c) Volumes of gas to provide safety flares for additional facilities may be approved by administrative order upon proper application; d) The volumes of gas for safety flares may be decreased or increased by administrative order; and e) Gas flaring may be approved by administrative order during commissioning of new equipment, purging, and start-ups after major repairs or interruptions. Conservation Or~' t ~o. 207 Page 8 January 10, 1985 'Rule 9. GAS-OIL RATIO TESTS. a) Between 90 and 120 days after regular production commences and each six months thereafter a gas-oil ratio test will be taken on each well for as long as it produces oil; b) The gas-oil ratio tests will be for a minimum of four hours and shall be taken at the normal producing rate of the well; and c) The results of the gas-oil ratio tests will be reported on Form 10-409, Gas-Oil Ratio Test and will be submit- ted in January and July of each year. Rule 10. PRESSURE SURVEYS. a) A static bottomhole pressure survey shall be taken prior to production or injection on each well drilled to the pool and results reported on Form 10-412, Reservoir Pressure Report; b) The pressure datum for the Lisburne Oil Pool is 8,900 feet subsea. The Commission may administratively amend this datum or create an additional datum when more information on the reservoir is available. c) Prior to July 10, 1987 the operator shall submit to the Commission a program to adequately monitor the reser- voir pressure during depletion. Before the above date, any transient pressure surveys taken shall be timely submitted on Form 10-412 to the Commission. Rule 11. UNITIZATION. To ensure the protection of correlative rights and to prevent waste, the Lisburne Oil Pool shall be administered in accordance with the Prudhoe Bay Unit Agreement. Rule 12. PILOT PROJECTS. Upon application, the Commission may administratively approve field pilot projects, well production and injection tests and other field operations necessary for the purpose of developing a prudent enhanced recovery method and reservoir depletion program. .Conservation Or~ Page 9 January 10, 1985 Rule 13. POOL OFFTAKE RATE. No more than 160,000 barrels of oil per day may be produced from the Lisburne Oil Pool. However when evidence can be presented to the Commission showing that a higher offtake rate will not affect ultimate recovery, the Commission may increase the daily offtake rate by administrative order. Rule 14. CONSERVATION ORDER NO. 83-C. Conservation Order No. 83-C is hereby cancelled. DONE at Anchorage, Alaska and dated January 10, 1985. C%--~. ChaCt~fon,/ C~fairman Alaska Oil and Gas Conservation Co~nission harry W. D6gler, Com~issi'°ner Alaska Oil and Gas Conservation Commission Lonnie C. Smi~d~,k~ommissioner Alaska Oil and Gas Conservation Commission