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Home My WebLink AboutCO 329 AIndex Conservation Order 329A Niakuk Oil Pool 1. January 23, 1996 BP Exploration's request for revision to CO 329 2. January 27, 1996 Notice of Hearing, Affidavit of publication and a letter to interested parties re: stating wrong Rule on Notice 3. February 12, 1996 Exxon's letter to AOGCC re: BP request 4. February 12, 1996 Arco Alaska's Ltr to AOGCC re: BP request 5. February 12, 1996 DNR's Ltr to AOGCC re: BP request 6. April 24, 1996 BP Exploration request to permanently waive the requirements of Rule 10, Figure 6, 8, 13 held confidential 7. December 30, 1997 BP Exploration's request to amend CO 329 to include additional lands located to the west and north of the current rules area 8. January 12, 1998 DNR letter of clarification of statements 9. February 28, 2006 BPXA request for a Spacing Exception 10. March 2, 2006 Notice of Hearing, Affidavit of publication, mailing lists 11. March 13, 2006 E-mail from Geologist. Exception not needed 12. August 31, 2006 Prudhoe Bay Filed — Annual Surveillance Reporting requirements to AOGCC 13. February 24, 2020 BPXA Request to amend CO 492 rule 3(a) and 6(a) (co329A.002) 14. May 21, 2020 Notice of Hearing and mailing 15. ----------------- Emails Conservation Order 329A • STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501 -3192 Re: The Application of BP Exploration ) Conservation Order No. 329A (Alaska) Inc. requesting a change to Rule ) 10, Conservation Order 329 governing ) Prudhoe Bay Field maximum production rate. ) Niakuk Oil Pool ) June 4, 1996 IT APPEARING THAT: 1. By letter received January 23, 1996, BP Exploration (Alaska) Inc. (BPXA) requested a change to Rule 10, Conservation Order 329. 2. Notice of opportunity for public hearing to be held February 26, 1996, was published in the Anchorage Daily News on January 27, 1996. 3. Comments on the application were received from ARCO Alaska, Inc., Exxon Company, USA and Department of Natural Resources, Division of Oil and Gas. 4. There were no protests or requests for public hearing. 5. The Commission issued Administrative Approval No. 329.04 on February 22, 1996, which allowed temporary waiver of Rule 10 for 120 days or until Rule 10 is changed, to allow BPXA time to prepare data and evaluate studies supporting their request to change the production limit. 6. On April 26, 1996 BPXA submitted additional data and information supporting its application. FINDINGS: 1. BPXA anticipated that facility constraints, gas -oil ratio (GOR) and other performance measures would limit pool production rates to no more than 23,000 BPD when it submitted its original development plans for the Niakuk Pool. 2. Since the Niakuk Pool rules were adopted, the Lisburne Production Center facility capacity has increased from 135,000 BPD to over 210,000 BPD on peak production days. 3. Reservoir performance has been better than originally anticipated and the pool is larger than anticipated at the time pool rules were adopted. 4. Waterflood operations started in April 1995 with reservoir response evident in oil rate increase, water production increase and GOR decrease. 5. Pressure measurements show reservoir pressure above bubble point and generally trending upward since waterflood started. Conservation Order 329 1 Page 2 Niakuk Oil Pool June 3, 1996 6. Results of operator model studies in the various reservoir segments indicate that ultimate recovery will not be diminished by increasing offiake rate beyond 23,000 BDP for the pool. 7. The operator expects to drill additional infill wells to capture reserves more efficiently. CONCLUSIONS 1. Results of model studies indicate ultimate recovery will not be diminished by increasing pool ofltake rate. 2. Pressure and GOR trends indicate that pool response to waterflood is beneficial. 3. There are no technical reasons for restricting ofake rate from the pool. 4. The owners and operators of pools producing to the Lisburne Production Center have agreed to use well performance characteristics such as GOR and water production to maximize oil production rate while managing facility gas and water handling constraints. 5. Eliminating the rate restriction in Rule 10 will not cause waste, jeopardize correlative rights and will not compromise maximum recovery. NOW, THEREFORE, IT IS ORDERED THAT the plan of development submitted by BP Exploration (Alaska) Inc. is approved, subject to rules hereinafter set forth and state -wide requirements under 20 AAC 25, for the following affected area. Umiat Meridian T12N R15E Section 23 S/2 Section 24 SW /4 Section 25 All Section 26 All Section 36 NE /4 T12N R16E Section 28 All Section 29 All Section 30 All Section 31 N/2 Section 32 N/2 Conservation Order 329 • Page 3 Niakuk Oil Pool June 3, 1996 Rule 1 Field and Pool Name The field is the Prudhoe Bay Field. Hydrocarbons underlying the affected area and contained within the Kuparuk River Formation constitute a single associated gas and oil reservoir called the Niakuk oil pool. Rule 2 Pool Definition The Niakuk oil pool is defined as the accumulation of oil and gas that correlates with the interval between 12,318 feet and 12,942 feet measured depth in the Niakuk 6 well. Rule 3 Well Spacing Upon application of the operator, the Commission may administratively approve the drilling of any well to a bottom hole location greater than 500 lineal feet from the external boundary of the affected area. No well bore may be open to the Niakuk oil pool within 500 feet of the external boundary of the affected area nor within 1000 feet of another well capable of producing from the same pool. Rule 4 Casing and Cementing a. A conductor casing shall be set at least 75 feet below the surface. If cemented, cement to surface shall be verified by visual inspection. b. Surface casing shall be set at least 500 feet MD below the base of the permafrost but not below 5000 feet TVD subsea. c. Surface casing must have minimum axial strain properties of .5% in tension and .7% in compression to withstand forces generated by thaw subsidence and freeze back in permafrost. Rule 5 Automatic Shut In Equipment a. Upon completion, each well shall be equipped with: i. 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. Conservation Order 329 Page 4 Niakuk Oil Pool June 3, 1996 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. i. 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 or SSSVs removed, removal dates, reasons for removal, and estimated re- installation dates must be maintained current and available for Commission inspection on request. d. 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. i. 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. Rule 6 Surface Commingling and Common Facilities a. Production from the Niakuk oil pool may be commingled on the surface with production from other pools for processing at the LPC prior to custody transfer. b. Production from each well will be determined by the following well test allocation methodology. Allocation data and well test data will be supplied to the Commission monthly in both computer file and report formats. i. Conduct well tests to determine production rates for each well. ii. Calculate each well's theoretical monthly production (TMP) based on well test rate(s) and actual time on production. iii. Sum the TMP volume for all wells in all pools. iv. Determine an allocation factor as the ratio of the metered volume to the TMP for all wells in all pools (i.e., metered/TMP) v. Calculate each well's actual monthly production (AMP) volume as: Conservation Order 3290 • Page 5 Niakuk Oil Pool June 3, 1996 AMP = TMP x Allocation Factor c. NGL's will be allocated to each pool based on actual gas production volumes and NGL process simulations. Process simulations will be updated at least once per year based on NGL samples and results reported to the Commission. d. Each producing well will be tested at least twice each month. Wells that have been shut in and cannot meet the twice monthly test frequency must be tested within five days of startup. All available test separator capacity within the constraints imposed by operating conditions must be utilized for well testing. e. Optimum test duration and stabilization time will be determined on a well by well basis by the operator. f. Water volumes will be determined by API/MPMS approved methods, or the use of industry proven, on -line water cut measurement devices approved by the Commission. g. API gravity will be determined for each producing well annually by an API/MPMS approved method. h. Gas samples will be taken and analyzed for composition from each non gas lifted producing well yearly. i. Quarterly allocation process reviews will be held with the Commission. j. This rule may be revised or rewritten after an evaluation period of at least one year. Rule 7 Production Anomalies In the event of oil production capacity proration at or from the LPC, all commingled pools produced at the LPC will be prorated by an equivalent percentage of oil production recognizing mechanical limitations and operational constraints. Rule 8 Reservoir Pressure Monitoring a. Prior to regular production, a pressure survey shall be taken on each well to determine the reservoir pressure. b. A minimum of one bottom hole pressure survey per producing governmental section shall be obtained annually. The surveys in part 'a' of this rule may be used to fulfill the minimum requirements. c. The datum for all surveys is 9200' TVDss. d. Pressure surveys will be either a pressure buildup, pressure falloff, RFT, or static bottom hole pressure after the well has been shut in for an extended period. Conservation Order 329r`T'"' Page 6 Niakuk Oil Pool June 4, 1996 e. The pressure surveys will be reported to the Commission quarterly on form 10 -412, Reservoir Pressure Report. All data necessary for complete analysis of each survey need not be submitted with the form 10 -412 but must be submitted upon request. f. Results and data from any additional reservoir pressure tests, surveys or special monitoring techniques shall be submitted in accordance with part 'e' of this rule. Rule 9 Niakuk Oil Pool Annual Reservoir Report. A surveillance report will be required within one year of regular production and annually thereafter. The report shall include but is not limited to the following: a. Progress of enhanced recovery project(s) implementation and reservoir management summary including engineering and geotechnical parameters. b. Voidage balance by month of produced fluids and injected fluids. c. Analysis of reservoir pressure surveys within the pool. d. Results and where appropriate, analysis of production logging surveys, tracer surveys and observation well surveys. e. Results of any special monitoring. f. Future development plans. Rule 10 Ofltake rate. Repealed June 4, 1996. Rule 11 Additional Recovery Project Within one year of regular production, a waterflood or other Commission approved secondary recovery project must commence. Rule 12 Administrative Action Upon proper application or its own motion, the Commission may administratively waive the requirements of any rule stated above or administratively amend this order as long as the change does not promote waste, jeopardize correlative rights or compromise ultimate recovery, and is based on sound engineering principles. 11 1) Conservation Order 329 Page 7 Niakuk Oil Pool June 4, 1996 DONE at Anchorage, Alaska and dated June 4, 1996. Afr 1K% oit 1. David W. • ston, C : irman r Alaska Oil . d Gas Co . ervation Commission 1440- • , 0 M V � '4 LION CO uckerman Babcock, Commissioner Alaska Oil and Gas Conservation Commission AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10 -day period. An affected person has 30 days from the date the Commission refuses 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 Commission, the 30 day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e., 10th day after the application for rehearing was filed). • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7 Avenue, Suite 100 Anchorage, Alaska 99501 Re: AN ORDER rescinding those rules within ) Docket Number: CO -10 -21 existing Conservation Orders relating to ) Other Order No. 66 well safety valve systems. ) ) Statewide, Alaska ) January 11, 2011 IT APPEARING THAT: 1. On October 13, 2010 the Alaska Oil and Gas Conservation Commission (AOGCC or Commission) formally adopted new regulations relating to well safety valve systems, at 20 AAC 25.265. 2. The newly adopted well safety valve system regulations underwent final review by the Regulations Section of the Alaska Attorney General's Office and were forwarded to the Alaska Lieutenant Governor's Office on October 28, 2010. 3. The new regulations were signed by the Lieutenant Governor and took legal effect on December 3, 2010. 4. To ensure consistency with the new regulations, the AOGCC, on its own motion, proposed to rescind part or all of the outdated rules within existing Commission Orders relating to well safety valve systems. 5. On November 4, 2010, pursuant to 20 AAC 25.540, the Commission published in the Alaska Daily News notice of opportunity for public hearing on December 6, 2010. 6. The Commission received written comments in response to its public notice, and held a public hearing on December 7, 2010. 7. Oral testimony and written comments were provided at the December 7, 2010 hearing. FINDINGS: 1. Well safety valve systems are regulated under newly- adopted 20 AAC 25.265, which consolidates the requirements previously established in legacy documents, g Y policies, and statewide guidelines relating to safety valve systems. 2. Thirty -four existing Commission Orders contain rules governing well safety valve systems. Twenty of those Orders contain broad regulatory requirements for safety valve systems that are now covered by the newly- adopted regulations. The remaining fourteen Orders include field- or pool - specific safety valve system requirements. Other Order 66 • • Page 2 Statewide, AK January 11, 2011 3. Within existing Commission Orders are rules unrelated to well safety valve systems; these rules will continue in effect, unmodified. 4. Existing Commission Orders containing individual rules relating to well safety valve systems are enumerated in the attached Table. CONCLUSIONS: 1. Eliminating redundant requirements and standardizing wording for those field - and pool - specific safety valve system requirements deemed appropriate to retain will improve regulatory clarity. 2. Twenty existing Commission Orders that include rules relating to well safety valve systems are rendered unnecessary, and can be replaced by newly- adopted 20 AAC 25.265. As more fully set forth in the attached Table, those Orders are Conservation Orders 98A, 207A, 300, 311B, 317B, 329A, 341E, 345, 402B, 432D, 452, 457B, 471, 477, 484A, 505B, 553, 559, 570, and a Commission unnumbered Order signed March 30, 1994 (policy dictating SVS performance testing requirements). 3. Fourteen existing Commission Orders include field- or pool - specific safety valve system requirements that the Commission considers appropriate for retention. Wording for the same safety valve system requirements existing in different Commission Orders has been standardized. As more fully set forth in the attached Table, those Orders are Conservation Orders 406B, 423, 430A, 435A, 443B, 449, 456A, 458A, 562, 563, 569, 596, 597, and 605. NOW, THEREFORE, IT IS ORDERED THAT individual rules in thirty-four existing Commission Orders that relate to well safety valve systems are hereby rescinded or revised as enumerated in the Table. Remaining rules unrelated to safety valve systems within affected Commission Orders remain in effect, unmodified. Aido ..- DONE a t Anchorage, Alaska, and dated . - ary 11, 2011 Daniel T. Se. r. ou , r., Commissioner, Chair p , i • ell . • :. s Conservation Commission t � M.k AID 444 l� 7 orrman, Coer cP i ; ' ; a Oi , , . a Conserva ion Commission 0. ' r C at y e� P. oerst r, Commissioner r � �"`'" 40- Alaska it and Gas Conservation Commission Other Order 66 • • Page 3 Statewide, AK January 11, 2011 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[tMhe questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. • • • Fisher, Samantha J (DOA) From: Fisher, Samantha J (DOA) Sent: Tuesday, January 11, 2011 4:08 PM To: Ballantine, Tab A (LAW); '(foms2 @mtaonline.net)'; '( michael .j.nelson @conocophillips.com)'; '(Von.L .Hutchins @conocophillips.com)'; 'AKDCWelllntegrityCoordinator; 'Alan Dennis'; 'alaska @petrocalc.com'; 'Anna Raff; 'Barbara F Fullmer; 'bbritch'; 'Becky Bohrer; 'Bill Penrose'; 'Bill Walker; 'Bowen Roberts'; 'Brad McKim'; 'Brady, Jerry L'; 'Brandon Gagnon'; 'Brandow, Cande (ASRC Energy Services)'; 'Brian Havelock'; 'Bruce Webb'; 'carol smyth'; 'caunderwood'; 'Chris Gay; 'Cliff Posey'; 'Crandall, Krissell'; 'D Lawrence'; 'dapa'; 'Daryl J. Kleppin'; 'Dave Matthews'; 'David Boelens'; 'David House'; 'David Steingreaber; 'ddonkel @cfl.rr.com'; 'Deborah J. Jones'; Delbridge, Rena E (LAA); 'Dennis Steffy'; 'Elowe, Kristin'; 'Erika Denman'; 'eyancy'; 'Francis S. Sommer; 'Fred Steece'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gorney, David L.'; 'Greg Duggin'; 'Gregg Nady'; 'gspfoff; 'Harry Engel'; 'Jdarlington (jarlington @gmail.com)'; 'Jeanne McPherren'; 'Jeff Jones'; 'Jerry McCutcheon'; 'Jill Womack'; 'Jim White'; 'Jim Winegarner; 'Joe Nicks'; 'John Garing'; 'John Katz'; 'John S. Haworth'; 'John Spain'; 'John Tower; 'Jon Goltz'; 'Judy Stanek'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kelly Sperback'; 'Kim Cunningham'; 'Larry Ostrovsky'; 'Laura Silliphant'; 'Marilyn Crockett; 'Mark Dalton'; 'Mark Hanley (mark.hanley @anadarko.com)'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer; 'Michael Dammeyer; 'Michael Jacobs'; 'Mike Bill'; 'Mike Mason'; 'Mike) Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'nelson'; 'Nick W. Glover'; 'NSK Problem Well Supv'; 'Patty Alfaro'; 'Paul Decker (paul.decker @alaska.gov)'; 'Paul Figel'; 'PORHOLA, STAN T'; 'Randall Kanady'; 'Randy L. Skillern'; ' rob.g.dragnich @exxonmobil.com'; 'Robert Brelsford'; 'Robert Campbell'; 'Ryan Tunseth'; 'Scott Cranswick'; 'Scott Griffith'; Scott, David (LAA); 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Steve Lambet; 'Steve Moothart'; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'tablerk'; 'Tamera Sheffield'; Taylor, Cammy 0 (DNR); 'Temple Davidson'; 'Teresa Imm'; 'Terrie Hubble'; 'Thor Cutler; 'Tina Grovier'; 'Todd Durkee'; 'Tony Hopfinger; 'trmjrl'; 'Valenzuela, Mariam '; 'Vicki Irwin'; 'Walter Featherly'; 'Will Chinn'; Williamson, Mary J (DNR); 'Yereth Rosen'; 'Aaron Gluzman'; Bettis, Patricia K (DNR); caunderwood @marathonoil.com; 'Dale Hoffman'; 'David Lenig'; 'Gary Orr; 'Jason Bergerson'; 'Joe Longo'; 'Lara Coates'; 'Marc Kuck'; 'Mary Aschoff; 'Matt Gill'; 'Maurizio Grandi'; Ostrovsky, Larry Z (DNR); 'Richard Garrard'; 'Sandra Lemke'; 'Talib Syed'; 'Tiffany Stebbins'; 'Wayne Wooster'; 'William Van Dyke'; Woolf, Wendy C (DNR); Aubert, Winton G (DOA) (winton.aubert@alaska.gov); Brooks, Phoebe L (DOA) (phoebe.brooks @alaska.gov); Colombie, Jody J (DOA) (jody.colombie @alaska.gov); Crisp, John H (DOA) (john.crisp @alaska.gov); Davies, Stephen F (DOA) (steve.davies @alaska.gov); Foerster, Catherine P (DOA) (cathy.foerster @ alaska.gov); Grimaldi, Louis R (DOA) (lou.grimaldi @alaska.gov); Johnson, Elaine M (DOA) (elaine.johnson @ alaska.gov); Jones, Jeffery B (DOA) (jeff.jones @alaska.gov); Laasch, Linda K (DOA) (linda.laasch @alaska.gov); Maunder, Thomas E (DOA) (tom.maunder @alaska.gov); McIver, Bren (DOA) (bren.mciver @alaska.gov); McMains, Stephen E (DOA) (steve.mcmains @alaska.gov); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA) (bob.noble @alaska.gov); Norman, John K (DOA) (john.norman @alaska.gov); Okland, Howard D (DOA) (howard.okland @alaska.gov); Paladijczuk, Tracie L (DOA) ( tracie.paladijczuk @alaska.gov); Pasqua!, Maria (DOA) (maria.pasqual @alaska.gov); Regg, James B (DOA) (jim.regg @alaska.gov); Roby, David S (DOA) (dave.roby @alaska.gov); Saltmarsh, Arthur C (DOA) (art.saltmarsh @alaska.gov); Scheve, Charles M (DOA) (chuck.scheve @alaska.gov); Schwartz, Guy L (DOA) (guy.schwartz @alaska.gov); Seamount, Dan T (DOA) (dan.seamount @alaska.gov); Shartzer, Christine R (DOA) Subject: Other 66 Safety Valve Systems Attachments: other66.pdf Sa4'flO4 haW Ft4he -r ALa4k.a. a vu Gam C o-► -varLo i Co mi/ksio' (907)793 -1223 (907)276 -7542 (fay.) 1 • • Mary )ones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton President 408 18 Street 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI K &K Recycling Inc. Land Department Baker Oil Tools P.O. Box 58055 P.O. Box 93330 795 E. 94 Ct. Fairbanks, AK 99711 Anchorage, AK 99503 Anchorage, AK 99515 -4295 North Slope Borough Jill Schneider Gordon Severson P.O. Box 69 US Geological Survey 3201 Westmar Circle Barrow, AK 99723 4200 University Drive Anchorage, AK 99508 -4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Cliff Burglin Refuge Manager 399 West Riverview Avenue 319 Charles Street P.O. Box 2139 Soldotna, AK 99669 -7714 Fairbanks, AK 99701 Soldotna, AK 99669 -2139 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 Orders Establishing Requirements for Well Safety Valve Systems 1/7/2011 Unit/Field Pool Conservation Rule Rescind Rule? Existing Order Requirement New Regulation Provisions Order (1) Addressing Reqts from Order Revised Rule - "Well safety valve systems" (2) Comment fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(a); 25.265(b); 25.265(d)(2)(H); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Colville River Unit Qannik 605 5 no (1) double check valve, or (ii) single check valve and SSV; injection arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or Check valve requirements for injectors are not covered by valve satisfies single check valve requirement; test every 6 months 25.265(h)(5 SCSSV satisfies the requirements of a single check valve." readopted regulation fail -safe auto SSV and SCSSV; injection wells (except disposal) require "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve 25.265(a); 25.2659(b); 25.265(d)(1); Oooguruk Oooguruk - Nuiqsut 597 6 no (i) double check valve, or (ii) single check valve and SSV; injection arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or Check valve requirements for injectors are not covered by valve satisfies single check valve requirement; test every 6 months 25.265(h)(5 SCSSV satisfies the requirements of a single check valve" readopted regulation fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(a); 25.265(b); 25.265(d)(1); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Oooguruk Oooguruk - Kuparuk 596 6 no (i) double check valve, or (ii) single check valve and SSV; injection arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or Check valve requirements for injectors are not covered by valve satisfies single check valve requirement; test every 6 months 25.265(h)(5 SCSSV satisfies the requirements of a single check valve." readopted regulation Prudhoe Bay Unit Raven 570 5 yes fail -safe auto SSV and SCSSV; maintain list of wells w/ removed or 25.265(a); 25.265(b); 25.265(d)(2)(F); Requirement to maintain a wellhead sign and list of wells with deactivated SVS; sign on wellhead 25.265(m) N/A deactivated SVS was replaced with requirement to maintain a tag on well when not manned fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25,265(a); 25.265(b); 25.265(d)(2)(H); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Colville River Unit Fiord 569 5 no (i) double check valve, or (ii) single check valve and SSV; injection arrangement or (ii) a single check valve and a SSV. A subsurface - controlled in jection valve or Check valve requirements for injectors are not covered by valve satisfies single check valve requirement; test every 6 months 25.265(h)(5 SCSSV satisfies the requirements of a single check valve." readopted regulation fail-safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(a); 25.265(b); 25.265(d)(2)(H); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Colville River Unit Nanuq - Kuparuk 563 6 no (i) double check valve, or (ii) single check valve and SSV; injection arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or Check valve requirements for injectors are not covered by valve satisfies single check valve requirement; test every 6 months 25.265(h)(5 SCSSV satisfies the requirements of a single check valve." readopted regulation fail -safe auto SSV and SCSSV; injection wells (except disposal) require "I wells (excluding disposal injectors) must be equipped with(i) a double check valve 562 6 n 25.265(a); 25.265(b); 25.265(d)(2)(H); Check valve requirements for injectors are not covered by Colville River Unit Nanuq (i) double check valve, or (ii) single check valve and SSV; injection 25.265(h)(5) arrangement or (ii) a single check valve and a SSV. Asubsurface- controlle injection valve or valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve." readopted regulation Prudhoe Bay Unit Put River 559 3 yes fait -safe auto SSV SSSV landin nippl below permafrost; test as 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Deep Creek Unit Happy Valley 553 3 yes SSV or SSsvCommission 25.265(h)(5) replaces SSSV nipple requirement for all wets Y 25.265(a) N/A Prudhoe Bay Unit Orion 505B 3 yes fail -safe auto SSV; SSSV landing nipple below permafrost; test as 25.265(a); 25.265(b); 25.265(d); Readopted 25.265(d) dictates which wells require SSSV; y prescribed by Commission 25.265(h)(5) N/A replaces SSSV nipple requirement for all wells Prudhoe Bay Unit Polaris 484A 3 yes fail -safe auto SSV; SSSV landing nipple below permafrost; test as 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; prescribed by Commission 25.265(h)(5) replaces SSSV nipple requirement for all wells Milne Point - fail -safe auto SSV; SSSV landing nipple below permafrost; gas /MI 25.265(x); 25.265(b); 25.265(d); Milne Point Unit 477 5 yes i njection well require SSSV or injection valve below N/A Schrader Bluff Readopted 25.265(d) dictates which wells require SSSV; y I q injection permafros test 25.265(h)(5) replaces SSSV nipple requirement for all wells every 6 months Prudhoe Bay Unit Borealis 471 3 yes fail -safe auto SSV; SSSV landing nipple below permafrost; gas / MI 25.265(a); 25.265(b); 25.265(d); y N/A injection well require SSSV below permafrost; test every 6 months 25.265(h)(5) Readopted 25.265(d) dictates which wells require SSSV; replaces SSSV nipple requirement for all wells Northstar Northstar 458A 4 no fail -safe auto SSV and SCSSV; test as prescribed by Commission; 500 ft minimum setting depth for SSSV 25.265(a); 25.265(b); 25.265(d)(1) "The minimum setting depth for a tubing conveyed subsurface safety valve is 500 feet." Existing pool rule established a minimum setting depth for the SSSV Prudhoe Bay Unit Aurora 457B 3 yes fail -safe auto SSV; SSSV landing nipple below permafrost: test every 6 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(4) dictates which wells require SSSV; months 25.265(h)(5) replaces SSSV nipple requirement for all wells fail -safe auto SSV; gas /MI injectors require SSV and single check 25.265(a); 25.265(b); 25.265(d); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Kuparuk River Unit Meltwater 456A 5 no valve and SSSV landing nipple; water injection wells require (1) double arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation; readopted 25.265(dX5) does not include check valve, or (ii) single check valve and SSV; test every 6 months 25.265(h)(5 SCSSV satisfies the requirements of a single check valve." q n9 SSSV requirement for MI injectors Prudhoe Bay Unit Midnight Sun 452 6 yes fail -safe auto SSV (all injector an d producers capable of unassisted 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; flow to surface); test every 6 months 25.265(h)(5) replaces SSSV nipple requirement for all wells fail -safe auto SSV and SCSSV; SSSV may be installed above or below 25.265(a); 25.265(b); 25.265(d)(1); "The setting depth of a required subsurface safety valve must be located in the tubing either Existing pool rule established alternate SSSV setting depth; Duck Island Unit Eider 449 7 no permafrost; injection wells require double check valve; LPS trip above or below permafrost. Injection wells must be equipped with a double check valve check valve requirements for injectors are not covered by pressure; test every 6 months 25.265(h)(5 arrangement." readopted regulation fail -safe auto SSV and SCSSV (producers and gas injectors); water "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Colville River Unit Alpine 443B 5 no injection wells require (i) double check valve, or (ii) single check valve 25.265(a); 25.265(b); 25.265(d)(2)(H) arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or Check valve requirements for injectors are not covered by and SSV SCSSV satisfies the requirements of a single check valve." readopted regulation fail -safe auto SSV; gas/MI injectors require SSV and single check 25.265(a); 25.265(b); 25.265(d); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Kuparuk River Unit Tabasco 435A 6 no valve and SSSV landing nipple; water injection wells require (i) double arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation; readopted 25.265(d)(5) does not include check valve, or (ii) single check valve and SSV; test every 6 months 25•265(h)(5 SCSSV satisfies the requirements of a single check valve." q 9 SSSV requirement for M! injectors fail -safe auto SSV (S /D well and artificial lift); sign on well if SVS Requirement to maintain a wellhead sign and list of wells with Kuparuk River Unit; deactivated; maintain list of wells w/deactivated SVS; test a 25.265(a); 25.265(b); 25.265(h)(5); deactivated SVS was replaced with requirement to maintain a Milne Point Unit Kuparuk 432D 5 yes prescribed by Commission; CO 432D.009 modifies Rule 5(b) - LPP N/A tag on well when not manned; administrative approval CO may be defeated on W. Sak injectors w /surface pressure <500psi w/ 25.265(m) 432D.009 remains effective ire:defeating the LPS when surface notice when defeated and placed back in service injection pressure for West Sak water injector is <500psi] Page 1 of 2 Orders Establishing Requirements for Well Safety Valve Systems 1/7/2011 UnitlField Pool Conservation Rule Rescind Rule? Existing Order Requirement New Regulation Provisions Order (1) Addressing Reqts from Order Revised Rule - "Well safety valve systems" (2) Comment fail -safe auto SSV; gas /MI injectors require SSV and single check 25.265(a); 25.265(b); 25.265(d); "Injection wets (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Kuparuk River Unit Tarn 430A 6 no valve and SSSV landing nipple; water injection wells require (i) double arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation; readopted 25.265(d)(5) does not include check valve, or (ii) single check valve and SSV; test every 6 months 25.265(h }(5 SCSSV satisfies the requirements of a single check valve." q 9 SSSV requirement for MI injectors Milne Point - Sag fail -safe auto SSV; injection wells require double check valve; test Milne Point Unit 423 7 no 25.265(a); ll 25.265 b arrangement." Check valve requirements for injectors are not covered by River every 6 months ( ); 25.265(h)(5) "Injection wells must be equipped with a double check valve readopted regulation fail -safe auto SSV; gas /MI injectors require SSV and single check valve and SSSV landing nipple; water injection wells require double / (excluding I ) () a double check valve check valve, or (ii) single check valve and SSV; test every 6 months; 25.265(a); 25.265(b); 25.265(d); arrangement or (ii) Check valve requirements for injectors are not covered by 9 pp i 1 q (i) " Injection wells i) a si ngle disposal injectors) must beequipped with i readopted regulation; readopted 25.265(d)(5) does not include Kuparuk River Unit Kuparuk - West Sak 406B 6 no i) a single check valve and a SSV. A subsurface- controlled injection valve or CO 4068.001 modifies Rule 6(e) - LPP may be defeated on W. Sak 25.265(h)(5) SCSSV satisfies the requirements of a single check valve. The Low Pressure Pilot may be SSSV requirement for MI injectors; administrative approval CO injectors w /surface pressure <500psi w/ notice when defeated and defeated on West Sak water injectors with surface injection pressure less than 500psi." 4066.001 remains effective [re:defeating the LPS when surface placed back in service injection pressure for West Sak water injector is <500psi] fail -safe auto SSV and SCSSV; LPS trip pressure; readily accessible Badami Badami 402E 6 yes control unit; SSSV below permafrost; NTE 210days between tests; 25.265(a); 25.265(b); 25.265(h); N/A submit test results electronically within 14days; SVS defeated /removed 25.265(m) only if well SI or pad continuously manned fail -safe auto SSV (S /D well and artificial lift); sign on well if SVS 25.265(a); 25.265(b); 25.265(h)(5); Requirement to maintain a wellhead sign and list of wells with Prudhoe Bay Unit North Prudhoe 345 4 yes deactivated; maintain list of wets w /deactivated SVS; test as 25.265 m N/A deactivated SVS was replaced with requirement to maintain a prescribed by Commission ( ) tag on wet when not manned fail -safe auto SSV (S /D well and artificial lift); if SSSV installed it must be Prudhoe Bay Unit Prudhoe 341E 5 yes maintained and tested as part of SVS; sign on well if SV 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; deactivated; maintain list of wells w /deactivated SVS; test as 25.265(h)(5) replaces SSSV nipple requirement for all welts prescribed by Commission fail -safe auto SSV and SCSSV; maintain list of wells w/ removed or 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Niakuk 329A 5 yes deactivated SVS; sign on wellhead 25.265(h)(5); 25.265(m) replaces SSSV nipple requirement for all wells Prudhoe Bay Unit Pt. McIntyre 317B 8 yes fail -safe auto SSV and SCSSV; SSSV may be rermoved as part of 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; routine well ops w/o notice 25.265(j); 25.265(m) replaces SSSV nipple requirement for all wets Prudhoe Bay Unit West Beach 311 B 6 yes fail -safe auto SSV; sign on well if SVS deactivated; maintain list of wells 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; w /deactivated SVS; test as prescribed by Commission 25.265(h)(5); 25.265(m) replaces SSSV nipple requirement for all wells West Fork West Fork (Sterling 300 5 yes fail -safe auto SVS on each production tubing 25.265(a); 25.265(b) N/A Prudhoe Bay Unit Lisburne 207A 7 yes fail -safe auto SSV; sign on well if SVS deactivated; maintain list of wells 25.265(a); 25.265(b); 25.265(h)(5); Requirement to maintain a wellhead sign and list of wells with w /deactivated SVS; test as prescribed by Commission 25.265(m) N/A deactivated SVS was replaced with requirement to maintain a suitable automatic safety valve installed below base of tag on well when not manned Prudhoe Bay Unit Prudhoe - Kuparuk 98A 5 y permafrost to Readopted 25.265(d) require prevent uncontrolled flow 25.265(d) N/A p 25.265 d dictates which wells re uire SSSV; yes replaces SSSV nipple requirement for all wets Statewide N/A N/A N/A yes Commission policy dictating SVS performance testing AOGCC Policy - SVS Failures; issued by order of the y requirements 25.265(h); 25.265(n); 25.265(0) N/A Commission 3/30/1994 (signed by Commission Chairman Dave Johnson) Footnotes (1) No SVS rules found in Injection Orders (2) New title for Revised Rule; "N /A" means entire pool rule to be rescinded Page 2 of 2 • • Public Hearing Record And d Backup Information available in Other 66 4 5- rY \ 11 ( 111‘ # FRANK H. MURKOWSKI, GOVERNOR ALASKA OIL AND GAS 333 W. 7TM AVENUE, SUITE 100 CONSERVATION COMMISSION AN CHORA (90 7) 2ASKA 99501-3539 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. 207.17 ADMINISTRATIVE APPROVAL NO. 311B.01 ADMINISTRATIVE APPROVAL NO. 329A.01`° ADMINISTRATIVE APPROVAL NO. 341D .01 ADMINISTRATIVE APPROVAL NO.345.01 ADMINISTRATIVE APPROVAL NO. 452.01 ADMINISTRATIVE APPROVAL NO. 457A.01 ADMINISTRATIVE APPROVAL NO. 471.01 ADMINISTRATIVE APPROVAL NO. 484.01 George Blankenship GPB Field Manager BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, Alaska 99519 Dear Mr. Blankenship: Conservation Order No. 492, dated June 26, 2003, amended the conservation orders adopting pool rules for all pools within the Prudhoe Bay field to add rules addressing sustained annulus pressures in devel- opment wells. Upon further review, the Commission has determined that paragraph 6 of these annulus pressure rules should be clarified. Paragraph 6 provides that before a shut -in well is placed in service, any annulus pressure must be relieved to a suffi- cient degree that specified annulus pressures at operating temperature will not be reached or exceeded. However, paragraph 3 of the annulus pressure rules contemplates that there may be wells that can be safely operated with an annu- lus pressure in excess of a maximum specified in paragraph 6, and in such cases it would not be practicable or meaning- ful to relieve annulus pressure to the degree required under paragraph 3 when placing a shut -in well in service. In addi- tion, the Commission may approve different pressure limits for well start -up on a case -by -case basis under paragraphs 4 and 5. ' `C NNEi' AUG 2003 • • July 29, 2003 4 Page 2 of 2 Accordingly, Conservation Orders No. 207, 311B, 329A, 341D, 345, 452, 457A, 471, and 484 are amended to replace paragraph 6 of the annulus pressure rules adopted in Conservation Order No. 492 with the following revised paragraph 6: 6. Except as otherwise approved by the AOGCC under para- graph 4 or 5 of these rules, before a shut -in well is placed in service, any annulus pressure must be relieved to a suffi- cient degree (a) that the inner annulus pressure at operating temperature will be below 2500 psig for wells processed through the Lisburne Production Center and below 2000 psig for all other development wells, and (b) that the outer annulus pressure at operating temperature will be below 1000 psig. However, a well that is subject to paragraph 3, but not paragraph 5, of these rules may reach an annulus pressure at operating temperature that is described in the operator's notification to the AOGCC under paragraph 3, unless the AOGCC prescribes a different limit. DATED at Anchorage, Alaska and dated July 29, 2003. �--- ---- 9 r fi - ��'�, ■ .1 in D. D. - e T. Seamount, Jr. - ancY Ruedric -. Chair Commissioner Commissioner BY ORDER OF THE COMMISSION OIL \ \ / 0 i , ,$ a 1 `, � , '; � �CE)499- 1 o I co THE STNYE °fALASKA GOVERNOR MIKE DUNLEAVY Mr. Oliver Stemicki Alaska Oil and. Gas Conservation Commission ADMINISTRATIVE APPROVALS CONSERVATION ORDER NO. 83A.001 CONSERVATION ORDER NO. 207D.002 CONSERVATION ORDER NO. 311B.004 CONSERVATION ORDER NO. 317B.004 CONSERVATION ORDER NO. 329A.002 CONSERVATION ORDER NO. 3411.002 CONSERVATION ORDER NO. 345.003 CONSERVATION ORDER NO. 452.005 CONSERVATION ORDER NO. 457B.007 CONSERVATION ORDER NO. 471.010 CONSERVATION ORDER NO. 484A.005 CONSERVATION ORDER NO. 50513.003 CONSERVATION ORDER NO. 559A.002 CONSERVATION ORDER NO. 570.011 Well Integrity Engineer Hilcorp North Slope LLC P. O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Numbers: CO -20-004 and CO -20-008 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olasko.gov Request to amend normal operating limit for inner annulus pressure for non Lisburne development area wells from 2,000 psig to 2,100 psig and to add an administrative approval clause to Conservation Order No. 492 Prudhoe Bay Unit All Oil Pools Dear Mr. Stemicki: By application dated February 24, 2020, Hilcorp North Slope, LLC' (FINS) applied to modify Conservation Order No. 492 (CO 492) to raise the inner annulus (IA) normal operating limit (NOL) reporting threshold from 2,000 psig to 2,100 psig for all wells not processed through the Lisburne Processing Center (LPC)2. CO 492 was issued on June 26, 2003 and applied to all pools in the ' The February 24, 2020, application was submitted by BP Exploration (Alaska) Inc. (BPXA) as operator of the Prudhoe Bay Unit (PBU) but effective on July 1, 2020, BPXA came under new ownership and was renamed HNS. HNS is currently the operator of the PBU. = The IA NOL for wells processed through the LPC is currently set at 2,500 psig. HNS is not seeking to modify this at this time. COs 83A.001, 207D.002, 311B.,..,4, 317B.003, 329A.002, 3411.002, 345.003, 452.x... , 457B.006, 471.009, 484A.005,505B.003,559A.002, & 570.011 October 1, 2020 Page 2 of 4 Prudhoe Bay Unit (PBU). The order established rules for dealing with sustained casing pressure for all producers in the PBU. Some, but not all, of the pools in the PBU area have incorporated the rules found in CO 492 directly into its pool rules. CO 492 itself did not contain provisions to allow it the be administratively amended, so providing public notice and opportunity to comment was required in order to amend the order. As such CO 492 will be amended separately and this letter will amend the individual pool rules for the PBU area oil pools. Due to operational changes over time in the PBU, namely increases in the gas lift header pressures, the 2,000 psig NOL for the IA that requires notification to the Alaska Oil and Gas Conservation Commission (AOGCC) when it is exceeded is triggering numerous notifications. These notifications do not on their own require any corrective action to be taken, but simply are a reporting burden on the operator and the AOGCC. Increasing the NOL from 2,000 to 2,100 would decrease the frequency of these notifications. Currently, the NOL for the IA for wells processed through the LPC is 2,500 psig. Exceeding the 2,500 psig NOL triggers a reporting requirement, but does not, standing alone, require corrective action. Another limit that is currently in place, and is not being changed by this action, is a pressure limitation of 45% of the casing's burst pressure rating. Exceeding the 45% pressure limitation requires that corrective action to be taken. Increasing the reporting threshold from 2,000 psig to 2,100 psig for the wells that are not processed at the LPC will eliminate many unnecessary notifications for wells where notification was triggered by the gas lift system pressure instead of an actual problem with the well that might indicate loss of containment. Increasing the IA NOL from 2,000 psig to 2,100 psig for production wells that are not processed at the LPC is based on sound engineering and geoscience principles. Now therefore it is ordered that the text below shall replace the text in the specified rules in the following orders: Conservation Order Oil Pool 207D Lisburne 457B Aurora 484A Polaris 505B Schrader Bluff 559A Put River 570 Raven Rules being replaced 15 11 and 123 11 11 10 12 7 In the current CO 457B, the pool rules for the Aurora Oil Pool, Rule I I contains paragraphs a. through f. of the annular pressure rules and Rule 12 contains the definitions in paragraph g. of the annular pressure rules. Paragraph g. is a part of the revised Annular Pressure of Production Wells shown here and thus Rule 12 in CO 457B is being eliminated. i COs 83A.001, 207D.002,31 I D.v04, -it /mu03, 329A.002, 3411.002, 345.003, 452.w5, 457B.006, 471.009, 484A.005, 505B.003, 559A.002, & 570.011 October 1, 2020 Page 3 of 4 And be added as the new rule indicated in the following orders: Conservation Order Oil Pool Added rule 83A Kuparuk River 9 311B West Beach 14 317B Pt McIntyre and Stump Island 17 329A Niakuk 13 341I Prudhoe Oil Pool 22 345 North Prudhoe Bay 12 452 Midnight Sun 15 471 Borealis 11 Annular Pressure of Production Wells a. At the time of installation or replacement, the operator shall conduct and document a pressure test of tubulars and completion equipment in each production well that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. b. The operator shall monitor each production well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for Commission inspection. c. The operator shall notify the Commission within three working days after the operator identifies a well as having (1) sustained inner annulus pressure that exceeds 2500 psig for wells processed through the Lisburne Processing Center and 2100 psig for all other production wells, or (2) sustained outer annulus pressure that exceeds 1000 psig. d. The Commission may require the operator to submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action or increased surveillance for any production well having sustained pressure that exceeds a limit set out in paragraph (c) of this rule. The operator shall give the Commission notice consistent with the requirements of Industry Guidance Bulleting 10-01 A of the testing schedule to allow the Commission to witness the tests. e. If the operator identifies sustained pressure in the inner annulus of a production well that exceeds 45% of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45% of the burst pressure rating of the well's surface casing for outer annulus pressure, the operator shall notify the Commission within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before Commission approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10- 403) a proposal for corrective action. The operator shall give the Commission sufficient notice of the testing schedule to allow the Commission to witness the tests. COs 83A.001, 20713.002, 31 Ib.,..J4, 317B.003, 329A.002, 3411.002, 345.003, 452.w.J, 457B.006, 471.009, 484A.005, 505B.003, 559A.002, & 570.011 October 1, 2020 Page 4 of 4 f Except as otherwise approved by the Commission under (d) or (e) of this rule, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree (1) that the inner annulus pressure at operating temperature will be below 2000 prig, and (2) that the outer annulus pressure at operating temperature will be below 1000 psig. However, a well that is subject to (c) but not (e) of this rule may reach an annulus pressure at operating temperature that is described in the operator's notification to the Commission under (c) of this rule, unless the Commission prescribes a different limit. g. For purposes of this rule, I. "inner annulus" means the space in a well between tubing and production casing; 2. `outer annulus" means the space in a well between production casing and surface casing; 3. "sustained pressure" means pressure that (A) is measurable at the casing head of an annulus, (B) is not caused solely by temperature fluctuations, and (C) is not pressure that has been applied intentionally. DONE at Anchorage, Alaska and dated October 1, 2020, Jeremy DID ltmya Vnce by JereDate 202010DI M. Price 135919-04oy Jeremy M. Price Chair, Commissioner Daniel T. Digitally cgned by Daniel T. stammer, Jr. $edtrlOUnt, Jr. Date 2020.10.01 1,dJ,,d900' Daniel T. Seamount, Jr Commissioner Digitally sig ned by Jessie L. Jessie t. Chmielowski Chmielowski 11e:1020A0,01 12:22:07 08 -00 - Jessie L. Chmielowski Commissioner As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration an FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distribuns, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 From: Rixse, Melvin G (CED) Sent: Wednesday, June 10, 2020 2:27 PM To: Sternicki, Oliver R Cc: Colombie, Jody J (CED) Subject: FW: June 25 hearing to amend 4 CO's Attachments: CO -20-008 Public Hearing Notice.pdf,, RE: CO -20-008 This is a clarification email to BPXA, Oliver Sternicki, that the AOGCC interpretation of any development well going through Lisburne Production Center, whetheron gas lift or natural flow, will be allowed 2500 psig sustained inner annulus pressure before reporting is required. CO -20-008 as written should be fine. We will then administratively amend the COs per the notice. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231) or (Mel v I n-Rtxse(atalaska govt. cc. Jody Colombie From: Colombie, Jody J (CED) Sent: Wednesday, June 10, 2020 8:59 AM To: Chmielowski, Jessie L C (CED) <jessie.chmielowski@alaska.gov> Cc: Rixse, Melvin G (CED) <melvin.rixse(dalaska gov> Subject: RE: June 25 hearing to amend 4 CO's No one has requested a hearing. Mel: Do you vote to vacate? Jody From: Chmielowski, Jessie L C (CED) <jessie.chmielowski0alaska gov> Sent: Wednesday, June 10, 2020 8:57 AM To: Colombie, JodyJ (CED) <jody.colombie@alaska eov> Cc: Rixse, Melvin G (CED) <melvin.rixse(@alaska eov> Subject: June 25 hearing to amend 4 CO's Hi Jody, Were there any requests to hold the hearing that's scheduled for June 25? Wondering if we can vacate and administratively amend the CO's? Co onnbie, Jody J (CED) From: Sternicki, Oliver R <Oliver.Stern icki@bp.com> Sent: Tuesday, June 2, 2020 3:43 PM To: Rixse, Melvin G (CED) Cc: Lau, Jack Subject: RE: CO -20-008 Mel, I was doing some work on the NOL increase and noticed something that might need slightly more clarification. The operator shall notify the AOGCC within three working days after the operator identifies a development well as having (a) sustained inner annulus pressure that exceeds 2500 psig for wells with supplied gas lift pressure from the Lisburne Processing Center and 2100 psig for all other development wells, or (b) sustained outer annulus pressure that exceeds 1000 psig- The issue is that this wording could be interpreted as just applying to the gas lifted produces at LPC and excludes the natural flow producers at that facility and in the GPMA area. There are currently 69 wells this applies to. This part should read: ...for wells with supplied gas lift pressure from the Lisburne Processing Center or wells processed through the Lisburne Processing Center... Let me know what you think, Oliver Sternicki Y'Yo yoeai Mm, a.wmrm, Sr. Well Integrity Engineer BP Exploration Alaska Cell: 1 (907) 350 0759 of iver. stern icki(a)bp. com From: Rixse, Melvin G (CED) <melvin.rixse@alaska.gov> Sent: Friday, May 15, 20204:31 PM To: Sternicki, Oliver R <Oliver.Sternicki@bp.com> Subject: FW: CO -20-008 From: Colombie, Jody 1 (CED) <iody.colombiet7a alaska.eov> Sent: Friday, May 15, 2020 3:16 PM To: AOGCC_Public_Notices <AOGCC Public Notices(a list state ak us> Subject: [AOGCC—Pu blic_Notices] CO -20-008 14 STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMITINVOICE SHOWING ADVERTISING ORDER NO, CERTIFIED AFFIDAVITOF PUBLICATIONWITHATTACHED COPY OF ADVERTISMENT. ADVER11SING ORDER NUMBER O A AO-08-20-024 H O YO 00-20-02Y FROM: AGENCY CONTACT: Jody Colombie/Samantha Carlisle Alaska Oil and Gas Conservation Commission DATE OF A.O. AGENCY PHONE: 333 West 7th Avenue 5/15/2020 907 279-1433 Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: ASAP FAX NUMBER: 907 276-7542 TO PUBLISHER: SPECIAL INSTRUCTIONS: Anchorage Daily News, LLC PO Box 140147 Anchorage, Alaska 99514-0174 TYPEOE ADVERTfSfEN'I',{`fir LEGAL 1� DISPLAY ;`'-r CLASSIFIEDj" OTHER (Specify below) % .. DESCRIPTION PRICE CO-20-008 Initials ofwho re ared AO: Alaska Non -Taxable 92-600185 SUBMIT INVOICE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION WITHATTACHED COPY OF ADVERTISMENTTO: AOGCC 333 west 7th Avenue AnchDra e, Alaska 99501 Page I of I Total of All Pa es $ _ REF Tye Number Amount Dale Commenm I PVN VCO21795 2 AO AO-08-20-024 3 4 FEN AMOUNT SY Act Tem late PGM T LIQ1 20 AOGCC 20 2 3 =0riV1y'x 4 5Purch n ri Title: PurchasingAuthSignature Telephone Number .O. # and receiving agency name must appear on all invoices and documents relating to this purchase. 2 e state is registered for tax free transactions under Chapter 32, IRS code. Registration number 92-73-0006 K. Items are for the exclusive use of the state and of for resale. DISTRIBUTION: Division Fiscal/Original AO Copies: Publisher (faxed), Division Fiscal, Receiving Form: 02-901 Revised: 5/21/2020 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION Re: Docket Number: CO -20-008 Prudhoe Bay Field, All Pools BP Exploration Alaska, Inc., by application received February 24, 2020, requests the Alaska Oil and Gas Conservation Commission (AOGCC) revise Rule 3 of Conservation Orders 317, 505, 559 and 570 to include the following language: The operator shall notify the AOGCC within three working days after the operator identifies a development well as having (a) sustained inner annulus pressure that exceeds 2500 psig for wells with supplied gas lift pressure from the Lisburne Processing Center and 2100 psig for all other development wells, or (b) sustained outer annulus pressure that exceeds 1000 psig. In addition, on its own motion AOGCC proposes to add the language that "unless notice and public hearing are otherwise required, upon proper application the AOGCC may administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater." The AOGCC has tentatively scheduled a public hearing on this application for June 25, 2020, at 10:00 a.m. at 333 West 7`s Avenue, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the AOGCC no later than 4:30 p.m. on June 5, 2020. Due to health mandates issued as a result of the covid-19 virus, if a hearing is requested, the hearing will be held telephonically. Those desiring to participate or be present at the hearing should call 1-800-315-6338 and, when instructed to do so, enter the code 14331. Because the hearing will start at 10:00 a.m., the phone lines will be available starting at 9:45 a.m. Depending on call volume, those calling in may need to make repeated attempts before getting through. If a request for a hearing is not timely filed, the AOGCC may consider the issuance of an order without a hearing. To learn if the AOGCC will hold the hearing, call (907) 793-1221 after June 7, 2020. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 West 71' Avenue, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on June 22, 2020, except that, if a hearing is held, comments must be received no later than the conclusion of the June 25, 2020 hearing. If, because of disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Jody Colombie, at (907) 793-1221, no later than June 20, 2020. Jerbmy M. Price Chair, Commissioner Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 by BP Exploration (Alaska) Inc. Alin: Well Integrity Coordinator, PRB-20 Post Office Box 196612 Anchorage, Alaska 99519-6612 February 24, 2020 Mr. Jeremy Price Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Request to amend Conservation Order No. 492 rule 3(a) and 6(a). Dear Mr. Price, BP Exploration (Alaska) Inc. requests an amendment to Conservation Order No. 492 rule 3(a) and 6(a) such that current notification and pressure limits are changed from 2000psi to 2100 psi for wells not processed through the Lisburne Processing Center. Current maximum gas lift header pressure in the Prudhoe Bay field for wells not processed through the Lisburne Processing Center regularly exceeds 2000psi. The field - wide IA (Inner Annulus) NOL (Normal Operating Limit) is set at 2000 psi for non -Lisburne development wells, excluding jet pump wells. Beginning in 2015 BPXA began installation of wireless digital annulus pressure gauges on all wells, this was completed in late 2019. Due to the increased accuracy of the annulus pressure readings and realtime monitoring/alerting capability, board operators are now very frequently responding to false alerts of IA NOL excursions on gas lifted wells due to gas lift header pressure exceeding 2000 psi, not sustained casing pressure as intended. BPXA requests that rule 3(a) and 6(a) be changed from 2000psi to 2100 psi (excluding jet pumps) for wells not processed through the Lisburne Processing Center to help minimize bo and well pad operators responding to false alerts. If you have any questions, please call me at 564-5430. Sincerely, Ryan Daniel BPXA Well Integrity Team Lead Attachments: Technical Justification Technical Justification for Conservation Order No. 492 Amendment February 24, 2020 History and Status: Gas lift header pressure at many of the drill sites and pads in the Prudhoe Bay field (excluding wells processed through the Lisburne Process Center) regularly exceeds the 2000 psi IA NOL set for development wells. Gas lift compressor outlet pressures are commonly set at 2100 psi. Historical gas lift pressures can be seen in Figure 1 & 2 for reference. The legacy IA NOL value of 2000 psi was set to remain compliant with Conservation Order No. 492 rule 3(a) and 6(a). Prior to the installation and monitoring of wireless annulus pressure gauges this was not as large of a problem due to one IA pressure read being recorded via mechanical gauge daily per well. If a pressure read exceeded the 2000 psi NOL it was reported to Well Integrity and evaluated to determine if the excursion was SCP or not. Currently all wells in the Prudhoe Bay field have the inner annulus pressures monitored in real-time by either the EOA or WOA production center board operators. The board operators are notified with an alert when the IA pressure of a well exceeds the set NOL value of 2000 psi. This ensures a timely notification and response to any potential excursion event. With the utilization of the wireless annulus pressure gauge alerting it has become an ongoing problem where wells supplied with gas lift pressure are regularly setting off alerts due to the gas lift supply pressure exceeding the 2000 psi NOL and not due to SCP as intended. This excessive alerting has the potential to desensitize workers to possible hazardous occurrences. Increasing IA NOL from 2000 psi to 2100 psi for development wells would eliminate the majority of these false NOL excursion alerts and allow resources to be more focused on response and evaluation of probable SCP events. This increase of 100 psi to the IA NOL is well within the design parameters of development wells across the Prudhoe Bay field. All development wells are included in this request in an effort to reduce the complexity of the IA NOL change. While non gas lifted wells are not subject to the same false alerts there is an increased risk of operating the field with IA NOLs varying for different types of wells. The use of gas lift on development wells, including natural flow producers, is continually changing, some require gas lift for kick off purposes only while others need constant gas lift. Gas lift usage may also change as a well ages depending on depletion or may change due to well work such as add pert/ reperf interventions. The tracking of these dynamic changes would be very difficult and the continual changing of NOL between 2000 psi and 2100 psi for individual wells in multiple data and control systems would greatly increase the complexity and management of NOLs across the field. This inconsistency in IA NOLs would be difficult for field personnel to continually keep track of and would reduce their effectiveness in identification of potential SCP events and would potentially result in misreporting of excursions. The IA NOL increase would not reduce the ability to identify SCP excursions in non -gas lifted wells. BPXA currently monitors development wells for minimum tubing by IA differential pressure thresholds as an indicator of communication. In addition to this SITP of non - gas lifted wells is in excess of 2100 psi, which if seen on the IA would indicate a loss of I tubing integrity and would flag as SCP. Based on this it is requested to increase the IA NOL for all development wells (excluding jet pump wells and those processed through the Lisburn Processing Center) to 2100 psi. Figure 1- EOA DS Gas Lift Header Pressure EOA Gas Lift Pressure IRmm 5/1VP15 —DS 03 I —OS M —0505 � —mCx —m0y —os u I —mlx --m13 —OS 10 —DS:6 05I) I 5/U305 6/YQ'NH$ V5/3mS 63RV}O1s 11/17/xO15 1/6/:016 3/3Y4:6 Me � Figure 2- WOA Pad Gas Lift Header Pressure WOA Gas Lift Pressure SVgm VWM35 5/U3015 6/3V3015 6/9//1015 9/}V3m5 l])D/im5 I/b/30}6 3/3YA16 Date —4Pda —6P.d —.Pad --MPad —/Pad —L Pr —m Pan —x Pad PPO R Pad —sP» ,"d a Pad .Pad xPad .Pad } Pad X12 Prudhoe Bay Field - Annual Surveillance Reporting Requirements to AOGCC Group 1 IPA Group 2 GPMA Group 3 Satellites Annual Surveillance Report 15-Mar 15-Jun 15-Sep Annual Overview Presentation 22-Mar 22-Jun 22-Sep Production Period to be Covered Jan 1-Dec 31 Apr 1-Mar 31 Jul 1-Jun 30 • Amends Order/Rule Order Date Comment Group 1 - IPA Oil Pools Note CO341E (modified Pool Definition to Prudhoe Oil Pool CO341 D Rule 11 11/30/2001 include a portion of Put River Sandstone) Put River Oil Pool CO559 11/22/2005 Corrected 2/14/2006 Group 2 - GPMA Oil Pools Lisbume CO207, 207A No rule on Surveillance reports Niakuk CO329A Rule 9 6/4/1996 North Prudhoe Bay CO345 Rule 8 12/16/1994 Pt. McIntyre CO317B Rule 15 4/19/2000 Raven Oil Pool CO570 Rule 10 8/9/2006 West Beach Oil Pool CO311B Rule 13 8/1/2000 • Group 3 - Prudhoe Satellite Oil Pools Aurora C0457B Rule 8 6/25/2004 (corrected 8/9/2004) Boreallis C0471 Rule 4 5/29/2002 Midnight Sun C0452 Rule 11 11/15/2000 Orion CO505A Rule 9 4/28/2006 Polaris C0484A Rule 9 11/3/2005 Subject: [Fwd: [Fwd: Re: surveillance report dates]] From: Jane Williamson < jane _williamson@admin.state.ak.us> Date: Fri, 20 Apr 2007 13:03:59 -0800 To: Jody J Colombie < jody _colombie@admin.state.ak.us >, Dave Roby <dave_roby @admin.state.ak.us>, Cathy P Foerster < cathy _foerster @admin.state.ak.us>, Alan J Birnbaum <alan birnbaum @law.state.ak.us> CC: Stephen E Mcmains < Steve _mcmains @admin.state.ak.us>, art Saltmarsh <art saltmarsh @admin.state.ak.us>, Thomas E Maunder <tom maunder @admin.state.ak.us> There is something I didn't get around to before I left and that was to administratively amend the COs for PBU to include reporting dates agreed to verbally with BP (and DNR). Really, only Pt. McIntyre and Borealis have the wrong dates in the CO's. The others are either ok, or not explicit. Attached are the COs affected. I'm not sure how you want to handle. Jody. Please put this in the following CO files along with the attachment. Group 1 - IPA Oil Pools Prudhoe Oil Pool CO341D Put River Oil Pool CO559 Group 2 - GPMA Oil Pools Lisburne CO207, 207A Niakuk CO329A Rule 9 North Prudhoe Bay CO345 Pt. McIntyre CO317B Raven Oil Pool CO570 West Beach Oil Pool CO311 B Group 3 - Prudhoe Satellite Oil Pools Aurora C0457B Boreallis C0471 Midnight Sun C0452 Orion CO505A Polaris C0484A Original Message Subject:Re: surveillance report dates Date:Thu, 31 Aug 2006 17:27:45 -0800 From:Jane Williamson <jane wiliamson(r�,admin.state.ak.us> Organization: State of Alaska To:Lenig, David C <David.Lenig(,bp.com> References : <CBF4D8E92B5A70479F644165821 6A? 7CB8 i AEO(bp1ancex005.bp1.ad.bp.com> Oops Lenig, David C wrote: Hi Jane, 1 of 3 4/23/2007 9:50 AM • 411 d [[ _ get the attachment David From: Jane Williamson [_ ] Sent: Thursday, August 31, 2006 5:14 PM To: Lenig, David C Subject: Re: surveillance report dates E -mail is fine. Attached is a list of the pools and orders /rules that will be amended with the Admin approval. Take a look and see if this looks right to you. (Note, I'm only listing the rules that are affected by the new dates - there may be • additional amendments unrelated to the surveillance requirements that I've not listed.) I'm flexible on the date for the Overview presentation. I'd be fine with specifying it to be within one or two months of the report date rather than the POD overview that you've noted. What would you prefer? 0 Lenig, David C wrote: Jane, Here is a table showing the dates for the various Reports and Presentations. I've added the production period as well. The IPA review date remains problematic due to the proximity to spring break but we seem to work around it each year. Would you prefer that I put this in a letter requesting the changes? I know we talked about this a little while ago I just haven't found the time. Thanks, David IPA GPMA Satellites Annual Surveillance Report March 15 June 15 September 15 Annual Overview Presentation March 22 June 22 September 22 Plan of Development March 30 June 30 September 30 Production Period Janl -Dec31 Aprl -Mar31 Jull -Jun30 Original Message From: Jane Williamson [mailto:jane tai'- liamson @admin.state.ak.us] Sent: Thursday, August 31, 2006 2:30 PM To: Lenig, David C Subject: surveillance report dates Hi David. When you get a second, could you please send back an e -mail that lists all the surveillance report dates that we've agreed to for all PBU pools (including GPMA)? Also, do you have dates for surveillance reviews? I'll go through the list and make sure the Conservation orders are correctly worded, then put out administrative amendments as necessary. I checked with Cammy and she said an e -mail is fine for starting the 2 of 3 4/23/2007 9:50 AM • • administrative action process. Thanks. Jan., Williamson PE <jgrie , vvill1Pmsonfx,Pdroirl. ,, t9te.acus> Senior Reservoir Engineer (907) 793-1226 Alaska Oil and Gas Conservation Commission Content application/vnd.ms-excel surveillance report.xls Content-Encoding: base64 3 of 3 4/23/2007 9:50 AM 411 Cancell niakuk 14A Spacing Exception • Subject: Cancell niakuk 14A Spacing Exception From: Robert Crandall <bob crandall@admin.state.ak.us> Date: Mon, 13 Mar 2006 15:56:22 -0900 To: Jody Colombie < jody _colombie @admin.state.ak.us> Jody; The subject spacing exception is not necessary. The pool rules area foir the Niakuk pool was modified by a Administrative Approval and was never incoprorated into a order, causing some confusion. BP will be apply to change the pool rules area again, and this time it will be done with a hearing and a redrafting of the Conservation Order. thanks Bob C 1 of 1 3/13/2006 4:05 PM 410 STATE OF ALASKA • NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING O N TE SHESO., CERTIFIED A O_02614030 AFFINVIDAVIT ICE MUST OF PUB I LICATION TRIPLICA (PART 2 OF THIS OWING ADV FORM WITH ING ORDER ATTAC COPY OF /`1 ORDER ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE 1,4 n'BOT OMiFC ";i3V1VOI�Ii��i Aa,,,,(i III "RI' F AOGCC AGENCY CONTACT DATE OF A.O. R 333 W 7th Ave, Ste 100 Jody Colombie March 1, 2006 ° Anchorage, AK 99501 PHONE PCN M - (9071 793 —1221 DATES ADVERTISEMENT REQUIRED: o Anchorage Daily News March 2, 2006 PO box 149001 Anchorage, AK 99514 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS g ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Advertisement to be published was e- mailed Type of Advertisement Legal® ❑ Display Classified ❑Other (Specify) SEE ATTACHED SEND INVOICI 'I IH ATEt AOGCC, 333 W. 7th Ave., Suite 100 PAGE 1 OF TOTAL OF Ta Vi Anchorage_ AK 99501 2 PAGES ALL PAGES$ REF TYPE NUMBER AMOUNT DATE COMMENTS 1 VEN 2 ARD 02910 _ 3 4 FIN AMAI INT CV rr. P(:1111 I r err.T FV NMR DIST LIQ 1 05 02140100 _ _ 73451 2 3 4 REQUISITIONED BY: DIVISION APPROVAL: • IC I Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission BP Exploration (Alaska), Inc., by letter received by the Alaska Oil and Gas Conservation Commission on February 28, 2006, has applied for an exception tion to the well p spacing requirements of Niakuk Oil Pool Rule 3 in Conservation Order No. 329A for the drilling, completion and production of the Niakuk 14A development oil well. The subject well is proposed as a deviated hole with a surface location 1358 feet from the South Line (FSL) and 944 feet from the East Line (FEL) of Section 36 T12N, R15E, Umiat Merdian (U.M.) and a bottom hole location 2137 FSL and 2418 FEL of Section 23, T12N, R15E UM. The Commission has tentatively scheduled a public hearing on this application for April 11, 2006 at 9:00 am at the Commission's offices at 333 West 7 Avenue, Suite 100, Anchorage, Alaska 99501. A person may request that the tentatively scheduled hearing be held by filing a written request with the Commission no later than 4:30 pm on March 21, 2006. If a request for a hearing is not timely filed, the Commission will consider the issuance of an order without a hearing. To learn if the Commission will hold the public hearing, please call 793 -1221 after March 29, 2006. In addition, a person may submit a written protest or written comments regardin this application to the Alaska Oil and Gas Conservation Commission at 333 West 7 Avenue, Suite 100, Anchorage, Alaska 99501. Written protest or comments must be received no later than 4:30 pm on April 3, 2006, except that if the Commission decides to hold a public hearing, written protest or comments must be received no later than the conclusion of the April 11, 2006 hearing. If you are a person with a disabilit ho may need special modifications in order to protest or comment or to attend the b c hearing, please contact the Commission's Special Assistant Jody Colo = t 79 , -1 -1 before April 4, 2006. IF • . Nor :( ai an Published Date: March 2, 2006 AO# 02614030 • • 02 - 902 (Rev. 3/94) Publisher /Original Copies: Department Fiscal, Department, Receiving AO.FRM STATE OF ALASKA NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHG SG RDER O., RI /� 0-02614030 AFFIDAVIT OF PUBLICATION (PART 2 OF OWIN THIS FORM) ADVERTI WITH IN ATTACHED NO COPY CE OF TFIED /`1 ORDER ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SSE BOTTOM F AR {1 11 ADDR its IaI iII VI�I�I! F AOGCC AGENCY CONTACT DATE OF A.O. R 333 West 7 Avenue. Suite 100 Jodv Colombie March 1. 2006 O Anchnracre AK QQ5f 1 PHONE PCN M 907 - 793 -1221 (9071 793 -1221 DATES ADVERTISEMENT REQUIRED: o Anchorage Daily News March 2, 2006 PO box 149001 Anchorage, AK 99514 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS g ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Account # STOF0330 AFFIDAVIT OF PUBLICATION United states of America REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. division. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE Before me, the undersigned, a notary public this day personally appeared ATTACH PROOF OF PUBLICATION HERE. who, being first duly sworn, according to law, says that he /she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2005, and thereafter for consecutive days, the last publication appearing on the day of , 2005, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This day of 2005, Notary public for state of My commission expires Re: Public Notice Subject: Re: Public Notice From: "Ads, Legal" <legalads @adn.com> Date: Wed, 01 Mar 2006 16:16:03 -0900 To: Jody Colombie < jody _colombie @admin.state.ak.us> Hello Jody: Following is the confirmation information on your legal notice. Please review and let me know if you have any questions or need additional information. Account Number: STOF 0330 Legal Ad Number: 735871 Publication Date(s): March 2, 2006 Your Reference or PO #: 02614030 Cost of Legal Notice: March 2, 2006 Thank You, Kim Kirby Anchorage Daily News Legal Classified Representative E -Mail: legalads @adn.com Phone: (907) 257 -4296 Fax: (907) 279 -8170 On 3/1/06 3:23 PM, "Jody Colombie" <jody colombie @admin.state.ak.us> wrote: Please publish tomorrow if possible. Jody 1 of 1 3/1/2006 4:17 PM Public Notice • Subject: Public Notice From: Jody Colombie < jody _colombie @admin.state.ak.us> Date: Wed, 01 Mar 2006 15:23:02 -0900 To: Legal Ads Anchorage Daily News <legalads @adn.com> Please publish tomorrow if possible. Jody Content - Type: application/msword Ad Order form.doc Content- Encoding: base64 Content - Type: application/msword 'NK14APH.doc Content- Encoding: base64 1 of 1 3/1/2006 3:31 PM Public Notice Niakuk . • Subject: Public Notice Niakuk From: Jody Colombie < jody_colombe @admin.state.ak.us> Date: W ed, 01 Mar 2006 15:30:04 -0900 To: un disclosed- recipients•; BCC: Cynthia B Mcver <bren mciver @adrnn.state.ak.us, Robert E Mintz <robert mintz@law.state.ak.us >, Christine Hansen • <c. @ s >, Terri Hubble <hubbletl @bp.com >, Sondra Stewman <StewmaSD @BP.corn>, Scott & Cammy Taylor <staylor @alaska,net>, stanekj <stanekj @unocal,com >, ecolaw <ecolaw@trustees,org >, trrnjr1 <trmjrl @aol.com >, jbriddle • <jbriddle @marathonoil.com> shaneg <shaneg@evergreengas,com> jdarlington <jdarlington @forestoil.com>, nelson <knelson @petroleumnews.com >, cboddy <cboddy @usibelli.com >, Mark Dalton <markdalton @hdrinc,com >, Shannon Donnelly Shannon. orc ly @conocophill ps.com >, "Mark P. Worcester" mark. p .worcester @conocophillips.corn >, Bob <bob @inletkeeper.org >, wdv <wdv @dnr.state.ak.us >, tjr <tjr @dnr.state.ak us >, bbritch <bbritch @alaska.net>, • mjnelson <rn jnelson @pure ngertz;.com> Charles O'Donnell <charles.o'donnell @veco.cam >, "Randy L. Skllern" <Ski11eRL @BF.com >, "Deborah J. Jones" <JonesD6 @BP.com >, "Steven R. Rossberg" < RossbeRSBP .com >, Lois <lois @nletkeeper.org >, Dan Bross <kuacnews @kuac.org >, Gordon Pospisil <FospisG @BP.corn>, "Francis S. Sommer" <SommerFS @BP. > , Mi Schultz <Mikel.Schultz @BP.com >, "Nick W Glover <GloverNW @BP.com >, " Daryl J. Kleppin" <KleppiDE @BP.com >, " Janet D. Platt" <PlattJD @BP.com >, "Rosanne M. Jacobsen" <JacobsRM @BP.com >, ddonkel <ddonkel @cfl.rr.com >, mckay <mck @g ci.net>, B F Fullmer <Barbara.f.fullmer @conocophill ps.com >, bocastwf <b ocastwf ul >, Charles Barker <barker @usgs.gov >, doug_schultze • <doug_sehultze @xtoenergy.com > Hank Alford <hank.alfo @exxonmobil.eam >, Mark Kovac <yesno 1 @gci.net>, gspfo <gspfoff @ aurorapower.com >, Gregg Nady <gregg.nady @shell.corn> Fred Steece <fr ed.steece @state.sd.us >, rcrotty <rcrotty@ch2m.com >, jejones <jejones @a >,` dapa <dapa @ a l aska . n e t> , jroderick <jroderck @gci.net • eyancy < eyancy @seal- tite.net>, "James M. Ruud" < r.stat • m.ruud @con ocoph i ll i ps.com >, Brit Lively <mapalaska @ak.net>, jah <jah @d nr.state.ak.us >, buonoje <buonoje @bp.com >, Mark Hanley <mark hanley@anadarko.com>, Loren Leman • <loren eman @gov.state.ak.us >, Julie Houle <' 1' houle @dnr.state.ak.us >, John W Katz <jwkatz @sso.org >, Suzan • J Hill <suzan_hill @dec.state.ak :us >, tablerk • <tablerk @unocal.com >, Brady <brady @aogaorg >, Brian Havelock <beh @ dnr .state.ak.us >, bpop <b popp @borough.kenai.ak.us >, Jim White jim @ satx,rr .co m >, "John S. Haworth" • <john s.haworth @exxonmobil.corn>, marry <martyrkindustrial,com >, ghammons <ghammons @aal.com >, rmclean <rmclean@pobox.alaska.net>, mkm7200 <mkm7200 @aol.com >, Brian Gillespie <ifbmg @uaa.alaska.edu >, David L Boelens <dboele orapower.com >, Todd Durkee <TDURKEE @KMG.com >, Ga ry Schultz <gary_schultz @dnr.state.ak.us >, Wayne Ranvier <RANCT @petro- canada.ca >, Brandon Gagnon <bgagnon @brenalaw.corn >, Paul Winslow <pmwinslow @forestoil.corn >, Garry Catron <catrongr @bp.com >, Shar Copeland <copelasv @bp.corn >, Kristin Dirks < kri stin dirks @dnr.state.ak.us > K aynell Zeman <kjzeman @marathon ©il.com >, John Tower <Jahn,Tower @e >, Bill Fowler <Bill @anadarko.COM >, Scott Granswick <scott ,cransw ck s.gou >, Brad McKim <mckim @ BP.com >, Steve Lamb e <lambcs @ unocal.com >, • jack newell <ja ck,newell @acsalaska.net>, James Scherr < james.sc ahn < L ms,gov> n1617 @conocophillips.com, Tim Lawlor <Tim_Lawlor @ak.blm. >, Lynnda KahnLynnda_Kahn @fws.gov >, Jerry Dethlefs < Jerry. C.Dethlefs @conocophillips.com >, Crockett@aoga.org, Tamera Sheffield <sheffield @aoga.org >, Jon Goltz <Jon.Goltz @conocophillips.com >, Roger Belman <roger.belman@conocoph llips.com >, Mindy Lewis <mlewis @brenalaw.com >, Kari Moriarty <moriarty @aoga.org >, Patt y Alfaro' <palfaro @yahoo.com >, Jeff <smetankaj @unocal :com > T odd Kr atz <T @chevron.com >, Gary Rogers 1 of 2 3/1/2006 3:31 PM Public Notice Niakuk • < Arthur < gary _rogers @revenue.state. >, Arthur Copoulos _Copoulos @dnr.state.ak.us>, Ken <ken @secorp- inc,com >, Steve Lambert <salambert@unocal,com >o, Joe Nicks <new ll Walker s @radiokenai.com >, Jerry McCutcheon <susitnahydronow @ > Paul Todd <paulto @acsalaska.net>, Bi <bill- wwa @ak,net>, Iris Matthews < Iris_ Matthews @legis.state.ak.us >, Paul Decker < aul decker dnr.state.ak.us> Rob Dra nick <rob .dra ch exxonmob co Aleutians East p _ @ g g Borough <admin @aleutianseast.org >, marque kremer < marguerite _kremer @dnr.state,ak.us >, Robert Brelsford < Robert. Brelsford @argusmediagroup,com >, Alicia Konsor <alicia konsor @dnr.state.ak.us >, Mike Mason <mike @kbbi.org> Content -Type: application/pdf NK14APH.pdf Content- Encoding: b 2 oft 3/1/2006 3:31 PM • . Mary Jones David McCaleb Mona Dickens XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102 -6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201 -3557 408 18th Street President Golden, CO 80401 -2433 PO Box 1655 Colorado Springs, CO 80901 John Levorsen Kay Munger Samuel Van Vactor 200 North 3rd Street, #1202 Munger Oil Information Service, Inc Economic Insight Inc. Boise, ID 83702 PO Box 45738 3004 SW First Ave. Los Angeles, CA 90045 -0738 Portland, OR 97201 Michael Parks Mark Wedman Schlumberger Marple's Business Newsletter Halliburton Drilling and Measurements 117 West Mercer St, Ste 200 6900 Arctic Blvd. 2525 Gambell Street #400 Seattle, WA 98119 -3960 Anchorage, AK 99502 Anchorage, AK 99503 Ciri Baker Oil Tools Ivan Gillian Land Department 4730 Business Park Blvd., #44 9649 Musket Bell Cr. #5 PO Box 93330 Anchorage, AK 99503 Anchorage, AK 99507 Anchorage, AK 99503 Jill Schneider Gordon Severson Jack Hakkila US Geological Survey 3201 Westmar Cr. PO Box 190083 4200 University Dr. Anchorage, AK 99508 -4336 Anchorage, AK 99519 Anchorage, AK 99508 Darwin Waldsmith James Gibbs Kenai National Wildlife Refuge PO Box 39309 PO Box 1597 Refuge Manager Ninilchick, AK 99639 Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669 -2139 Penny Vadla Richard Wagner Cliff Burglin 399 West Riverview Avenue PO Box 60868 PO Box 70131 Soldotna, AK 99669 -7714 Fairbanks, AK 99706 Fairbanks, AK 99707 Bernie Karl North Slope Borough Williams Thomas K &K Recycling Inc. PO Box 69 Arctic Slope Regional Corporation PO Box 58055 Barrow, AK 99723 Land Department Fairbanks, AK 99711 PO Box 129 Barrow, AK 99723 bp • p BP Exploration (Alaska) Inc. 900 East Benson Boulevard February 28, 2006 DELIVERED BY HAND Anchorage, Alaska 99519 -6612 (907) 561 -5111 Commissioners Alaska Oil and Gas Conservation Commission ,�� 333 West 7 Avenue, Suite 100 Anchorage, AK 99501 FEB 2 8 2006 RE: Application for Spacing Exception - NK -14A Well Alaska Oil & Gas Cons. Commission CO No. 329 - Niakuk Oil Pool Anchorage Prudhoe Bay Unit Dear Commissioners: BP Exploration (Alaska) Inc. (BPXA), the Prudhoe Bay Unit Operator, submits this application for an exception to 20 AAC 25.055(a) and Rule 3 of Conservation Order No. 329, as amended (CO 329 — Niakuk Oil Pool) to allow drilling the NK- 14A Well to a producing location closer than 500 feet from the external boundary of the pool and drilling unit. The NK -14A Well will be sidetracked from the existing NK -14 wellbore within Section 23, T12N, R15E, U.M. (Exhibit A). The NK -14A Well is located entirely within ADL 034625 and is anticipated to enhance oil recovery in the northwest portion of the Niakuk Oil Pool. The departure location will occur at 9,094 ft. TVDss at (X = 714,529 and Y = 5,991,031) and the well will remain in the Kuparuk Formation while reaching a bottomhole location within in the Niakuk Oil Pool at 9,230 ft. TVDss (X = 715,295 and Y = 5,992,768), also within Section 23, T12N R15E U.M. Also attached is an affidavit (Exhibit B) attesting that all facts in the application are true and that the attached plat correctly portrays pertinent and required data. The affidavit also affirms that notice via registered mail of this application has been sent all owners and operators of governmental quarter sections directly and diagonally offsetting the quarter section where the well is to be located. Please contact myself (564 -5351) or Gary Gustafson at 564 -5304 if you have any questions or need additional information. Sincerely, nAiL I L() Mark Weggeland GPMA Manager • • Attachments Exhibit A - Location of NK -14A Well Exhibit B - Affidavit of Mark Weggeland Cc: Sonny Rix, ExxonMobil Dan Kruse, CPAI G.P. Forsthoff, Chevron Paul Winslow, Forest Oil Gary Gustafson, BPXA Dave Strait, BPXA Bob Crandall, AOGCC Art Copoulos, BPXA _ ________---.....••■•■■■Imm. Exhibit A - Location of NK -14A Well N1'16 N K -14A � S° M il e I (} [PH -11 f .;1 MC N6- L NH - 14 P7PB2 • CrIT1�0 -20 x`_13° i ahL 2' 19 .7. . 2 . L45-114 x -oe - ` -1 � A II L034 :25 ill \ 1074 _ tnc -9a� u�t-4e �. 11X lkoitaL Niakuk Oil Pool � D 034630 MC-06• UK 4 is -074 27 Ili \ : I i, 21 44'3NKII lik V N ) ' Pe . \\ .11 m , - pi ‘ 4 ‘ 414 --, 1 1P 1 - 7" / / 0 --1 .,‘.. 1 " ‘ I/ 4.411 . t *N ,,, 34 DSNK '• • • Exhibit B Affidavit STATE OF ALASKA THIRD JUDICAL DISTRICT I, Mark Weggeland, declare and affirm as follows: 1. I am the Greater Pt. McIntyre Area (GPMA) Resource Manager for BP Exploration (Alaska) Inc. (BPXA), the designated operator of the Prudhoe Bay Unit and the Niakuk Participating Area, and as such have responsibility for unit operations within the Niakuk area, including the NK -14A Well. 2. I attest that to the best of my knowledge, all facts presented in the February 28, 2006 BPXA Application for a Spacing Exception are true and the plat included in Exhibit A thereto correctly portrays all pertinent and required data. 3. On February 28, 2006 I caused copies of the February 28, 2006 BPXA Application for a Spacing Exception for the NK -14A Well pursuant to 20 AAC 25.055(a) and Rule 3 of Conservation Order No. 329 (CO 329 — Niakuk Oil Pool) to be provided to the below referenced owners and operators of all governmental quarter sections directly and diagonally offsetting the quarter section where the NK -14A well is located. Operators: Prudhoe Bay Unit Operator: State of Alaska Operator: Maureen Johnson, GPB PUL Bill Van Dyke, Acting- Director BP Exploration (Alaska) Inc. Division of Oil & Gas PO Box 196612 Department of Natural Resources Anchorage, AK 99519 -6612 550 West 7 Avenue, Suite 800 Anchorage, AK 99519 -6612 Surface Owners: Attention: Dick Mylius, Acting- Director Heirs of Andrew Oenga Division of Mining, Land and Water c/o Inupiat Community of the Arctic Slope Department of Natural Resources P.O. Box 934 550 West 7 Avenue, Suite 1000 Barrow, AK 99723 Anchorage, AK 99501 -3510 1 • • Subsurface Owners: BP Exploration (Alaska) Inc. Chevron U.S.A. Attn: Maureen Johnson Attn: Gary Forsthoff PO Box 196612 PO Box 36366 Anchorage, AK 99519 -6612 Houston, TX 77236 ConocoPhillips Alaska, Inc. ExxonMobil Alaska Production Inc. Attn: Darren Jones Attn: Richard Owen PO Box 100360 PO Box 196601 Anchorage, AK 99510 -0360 Anchorage, AK 99519 -6601 Forest Oil Corporation Attn: Leonard Gurule 310 K Street, Suite 700 Anchorage, AK 9501 Mark Weggeland Date STATE OF ALASKA ) ss. THIRD JUDICIAL DISTRICT ) SUBSCRIBED AND SWORN to before me this day of ; O , 200 6. e titta _ _ N • T RY PUBLIC IN AND FOR ALASKA My Commission Expires: 10 j 2 I 9� TONY KNOWLES. GOVERNOR DEPARTMENT OF NATURAL RESOURCES 3601 "C" STREET, SUITE 1380 ANCHORAGE, ALASKA 99503 -5948 DIVISION OF OIL AND GAS PHONE: (907) 269 - 8800 COMM � j- Q cow /7# r January 12, 1998 „ ig 8 G 'Iy �? ENC All Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 -3192 Attn: Chairman David Johnston Subject: Amendment of C.O. 329, Niakuk Oil Pol Subject: �111 Dear Mr. Johnston: ow Reference is made to BP Exploration (Alaska) Inc.'s request to amend Cons - er 329, Niakuk Oil Pool, dated December 30, 1997. The Department of Natural Resources (DNR) would like to clarify statements contained in the amendment request. The DNR approved an application for the interim expansion of the Prudhoe Bay Unit, interim expansion of the Niakuk Participating Area, and interim formation of the West Niakuk Participating Area. DNR's decision on the interim application governs operations in the Greater Niakuk Area (GNA) while the GNA Owners obtain additional drilling and production data that will enable them to resolve the equity issues among themselves prior to a final application on the GNA. The Commissioner's Decision and Finding regarding this matter is enclosed for your review. Sincerely, 6 52)•) () Ck Kenneth A. Boyd Y Director Attachment JAN 1 1998 IPask Oil & Gas Cons. Commission ichofage cc: Robert Janes - BP w/o Attachment PBU.Niakuk.AOGCC.Txt "Develop, Conserve and Enhance Natural Resources for Present and Future Alaskans" PRUDHOE BAY UNIT APPLICATION FOR THE FOURTH EXPANSION OF THE UNIT AREA, FIRST EXPANSION OF THE NIAKUK PARTICIPATING AREA AND FORMATION OF THE WEST NIAKUK PARTICIPATING AREA DECISION AND FINDINGS OF THE COMMISSIONER ALASKA DEPARTMENT OF NATURAL RESOURCES JAN 13 1998 NOVEMBER 17, 1997 Alaska Oil & Gas Cans, COMMISSIM AnchoFaa J R IGINAL sq• PRUDHOE BAY UNIT FOURTH EXPANSION OF THE UNIT AREA, FIRST EXPANSION OF THE NIAKUK PARTICIPATING AREA AND FORMATION OF THE WEST NIAKUK PARTICIPATING AREA I. INTRODUCTION AND BACKGROUND ARCO Alaska, Inc. (ARCO), the Exxon Corporation (Exxon), and BP Exploration (Alaska), Inc. (BPX) (collectively known as the GNA Owners) filed an interim application to expand the Prudhoe Bay Unit (PBU) and Niakuk Participating Area (NPA) and to form a new participating within the PBU, the West Niakuk Participating Area (WNPA). This interim application proposes a temporary solution to the problem of having wells producing from a known reservoir that are not in a participating area or unit. Production data indicates that the acreage proposed for inclusion in the expanded NPA and WNPA overlies Kuparuk River Formation that is capable of production or contributing to production of hydrocarbons in paying quantities. DNR's decision on this Interim Application will govern operations in the Greater Niakuk Area (GNA) while the GNA Owners obtain additional drilling data that will enable them to resolve the equity issues among themselves. A "final" application is due no later than March 31, 1998. An oil and gas "unit" is comprised of a group of leases which cover all or part of one or more potential or known reservoirs and which are subject to a "unit agreement." The "unit agreement" is the instrument which is typically executed by those with an interest in the leases, including the royalty owner, and which specifies how unit operations will be conducted, and how costs and benefits will be allocated among the various leases. A second agreement called a "unit operating agreement" controls the relationship between parties which share the costs of unit development. Unitization generally allows a potential or known reservoir to be more efficiently explored, developed, or produced than on a lease by lease basis. A "participating area" (PA) is usually limited to that part of the unit area which has been shown to be productive of oil or gas in "paying quantities." A PA may consist of less, but not more, area than the unit area. If the unit area encompasses more than one reservoir, a separate PA must generally be established for each delineated reservoir. If the same reservoir contains both oil and gas, separate PAs may be established to distinguish between the oil rim and the gas cap. For example, the PBU now consists of five PAs overlying several reservoirs all located within the PBU area: the oil rim and gas gap PAs (collectively the initial participating areas or IPAs) for the Prudhoe Bay or Permo- Triassic Reservoir; the Lisburne PA for the Lisburne Reservoir; the West Beach PA for the West Beach Reservoir; and the Pt. McIntyre PA for the Pt. McIntyre and Stump Island Reservoirs. CLI P JAN 1 3 1998 `masks I & Gas Cons.Comirfn ArtchtrapP 411, 00 The boundaries of PAs can be continually revised as more wells are drilled and more data is obtained. PAs must be expanded to include all acreage that overlays a common reservoir. 11 AAC 83.356. The Division approves the Interim Application as a temporary solution. A final decision defining the appropriate PA(s), and unit(s) boundaries will be made after the "final" application is submitted with supporting geologic information. That application is due no later than December 31, 1997. Approval of the Interim Application is not intended to create any precedent or bind the Department ■ of Natural Resources (DNR) in its evaluation of further applications regarding the lands within the GNA. II. APPLICATION FOR THE FOURTH EXPANSION OF THE UNIT AREA, FIRST EXPANSION OF THE NIAKUK PARTICIPATING AREA AND FORMATION OF THE WEST NIAKUK PARTICIPATING AREA On July 31, 1997, ARCO, Exxon, and BPX (collectively, the GNA Owners) applied to expand the PBU and the existing NPA and to form the WNPA. The proposed interim expansion of the PBU would add portions of two state oil and gas leases, ADL 34625 and ADL 34626, totaling approximately 4480 acres, to the PBU for a total expanded PBU of approximately 247,595 acres. The two leases were issued as a result of state Lease Sale No.18 (Prudhoe), held on January 24, 1967. These leases were issued on state lease form DL -1 (Revised Oct. 1963) providing for a 12.5 percent royalty to the state. Simultaneously with the application to expand the PBU, the GNA Owners applied to approve the expansion of the existing NPA and formation of the WNPA within the expanded and existing PBU. The unit expansion acreage and the acreage proposed for the WNPA and expanded NPA encompass reservoirs of the Kuparuk River Formation, which are capable of producing or contributing to the production of hydrocarbons in paying quantities and included in an approved Plan of Development. The proposed WNPA would contain parts of two individual oil and gas leases, ADLs 34626 and 34629, and would total approximately 3,040 acres. The proposed expansion of the NPA would contain parts of two individual oil and gas leases, ADLs 34625 and 34630, and would total approximately 2,240 acres. The Interim Application also included interim WNPA and NPA Tract Participation Factors, a copy of the Western Niakuk Special Provisions to the PBU Operating Agreement, and incorporated by reference the 1997 Plan of Development for the NPA as the plan of development and operations for the WNPA and expansion area of the NPA. The Interim Application is a result of lengthy discussions between the GNA Owners and the DNR, Division of Oil and Gas ( "the Division "). The GNA Owners and the Division discussed the numerous tract and lease operations being conducted from the NPA Heald Point facilities. The geologic evidence exists to expand the NPA beyond its current boundaries to develop the Kuparuk River Formation reservoirs within the GNA under a unified plan of development. Tract Operations to evaluate the further extent of the Kuparuk River Formation adjacent to the NPA began with the NK -19 Well in December 1994. Next came the NK -29 (WNK -1) Well Tract Operation to the west of the NPA in March 1995. The NK -29 Well was certified capable of production in paying quantities in June 1995. Following the NK -19 and NK -27 Tract Operations, NK -13, NK -14, NK -15, and NK -17 were drilled to the north of the NPA on BPX lease ADL 34625. To the northwest of the NPA, NK -28 (WNK -2) and NK -29 (WNK -3) were drilled on ARCO/Exxon lease ADL 34626. Since the formation of the initial NPA, a total of eight wells have been drilled to evaluate the extent of the Kuparuk River Formation reservoirs surrounding the current NPA. The West Niakuk wells, NK -27 and NK -28, are producing on average between 2,900 and 3,800 BOPD, while NK -14 is producing on average 2,900 BOPD. NK -15 and NK -17 are designated water injection wells. Additional wells are scheduled in 1997 to evaluate the Kuparuk River Formation to the northwest on ADL 34626 and to the northeast on ADL 312827. Pursuant to Article 4.4 of the PBU Agreement, the director' approved the PBU Tract Operations for a limited period of time. In its response to an ARCO request to further extend the Niakuk Well NK -27 Tract Operation, and a BP request to extend the Niakuk Well NK -19 Tract Operation and approve the Niakuk Well NK -13 Lease Operation, the Division notified the GNA Owners on December 31, 1996, that: Given the number of tract operations and lease production wells, not to mention the proposed waterflood operations planned for Segment 3/5 of the Niakuk Reservoir with the NK -17 well, the Division believes that the lands to the west and northwest of the Niakuk Reservoir are reasonably known to be underlain by hydrocarbons and known or reasonably estimated through the use of geological, geophysical, or engineering data to be capable of producing or contributing to the production of hydrocarbons in paying quantities. 11 AAC 83.351. Additionally, these areas of the Niakuk Reservoir have been proven to be capable of sustained commercial production. Article 5.3 of the PBU Agreement. The owners must establish a participating area for all or that portion of the Niakuk Reservoir as has been reasonably defined by the recent Niakuk drilling results. Although the Division does not require a final NPA expansion boundary nor a final participation interest, it does require an interim expansion and participation formula that brings the reasonably defined portions of the reservoir into the NPA and under the NPA Plan of Development (POD). The Division believes that this action will protect the interests that would normally be protected through a participating area to insure the maximum ultimate recovery from all leases overlying the Niakuk Reservoir. After several meetings between the GNA Owners and the Division to address the issues raised in the December 31, 1996 letter, and exchanges of draft interim applications, the Interim Application was submitted on July 31, 1997. With receipt of the filing fee required under 11 AAC 05.010(a)(10)(E), the DO &G determined that the Interim Application was complete under 11 AAC 83.306. On August 17, 1997, public notice 'When the PBU Agreement was executed, the state director of the Division of Minerals and Energy Management, the predecessor agency of the Division, was responsible for plan of testing, evaluation and pilot production decisions. 041 was published in the Anchorage Daily News and in the Fairbanks Daily News Miner, as required by 11 AAC 83.311. Copies of the public notice were provided to interested parties in compliance with 11 AAC 83.311, and to the City of Barrow, the North Slope Borough, the Arctic Slope Regional Corporation, the Alaska Department of Environmental Conservation, the Alaska Department of Fish and Game, the Alaska Department of Natural Resources, Division of Land and Water Management, and the Alaska Oil and Gas Conservation Commission (AOGCC). During the 30 -day public notice period allowed under 11 AAC 83.311, no comments were received from the public, interested parties, or state or local agencies. III. DISCUSSION OF DECISION CRITERIA The commissioner or the commissioner's designee may approve expansion of a unit area if it is determined that expansion is "necessary or advisable to protect the public interest." AS 38.05.180(p) and 11 AAC 83.303(c). Approval of the Interim Application and the anticipated "final" application for the PA, PAs, "final" PBU expansion, or formation of a new unit and "final tract allocation schedule(s) must be based on the criteria in 11 AAC 83.303(a) and the factors enumerated in 11 AAC 83.303(b). Article 9.1 of the PBU Agreement (PBUA), which permits expansion of the PBU if approved by the director, restates the commissioner's discretionary power under AS 38.05.180(p) and 11 AAC 83.303. Article 5.3 of the PBUA reflects the commissioner's discretionary power under AS 38.05.180(p) and 11 AAC 83.351 to approve or disapprove formation of a participating area. Article 5.3 requires the lessees to apply for expansion of participating areas using specified criteria and procedures but does not change the commissioner's discretion to approve establishment, enlargement, or contraction of lands reasonably proven to be within the reservoir limits. In meetings with the Division and in the Interim Application, the GNA Owners have represented that the GNA contains multiple Kuparuk River Formation reservoirs that are hydraulically isolated from one another. The GNA Owners have not agreed among themselves whether to expand the NPA or form a new PA or PAs. The GNA Owners have advised DNR that their "final" proposal for the GNA, after appraisal drilling and their equity negotiation process are complete, may be multiple participating areas and tract allocation schedules for the various reservoir segments within an expanded PBU. 11 AAC 83.356(a) states that a "unit must encompass the minimum area required to include all or part of one or more oil or gas reservoirs, or all or part of one or more potential hydrocarbon accumulations." That regulation does not mandate that two adjacent reservoirs or two adjacent separate fault bounded reservoir segments/accumulations must be in the same unit. The regulation requires that a unit must encompass, at a minimum, only part of a reservoir. A unit area may 2 In the case of an exploratory unit, the minimum area is "part of one...potential hydrocarbon accumulation...." The West McArthur River Unit is an exploratory unit that includes only a part of a potential hydrocarbon accumulation. The Kuparuk River Unit and the Milne Point Unit are producing units that initially included only a part of the oil or gas accumulation from which the two produce. include part of one reservoir, one complete reservoir, one complete reservoir and part of another reservoir, or any one of a number of combinations. It must include, at least part of a reservoir. A unit cannot be formed without at least a portion of a reservoir, but it can be formed with only that minimum area. As more geologic data become available the unit area must be contracted to exclude areas that do not contain any reservoir. 11 AAC 83.356(b). The commissioner has discretion to approve or disapprove a unit consisting of "all or a part of an oil or gas pool, field, or like area" when it is "necessary or advisable in the public interest." 11 AAC 83.356(a), AS 38.05.180(p). Even if the separate Kuparuk Formation reservoirs segments are included within the PBU now, the commissioner may form a separate unit that includes the various reservoir segments if that result better met the statutory and legal criteria for approval of unit and PA expansions. Article 9.1 provides: The Unit Area may be enlarged from time to time so as to include any additional lands reasonably determined to be within any Reservoir any portion of which is within the Unit Area. The lands to be included shall be based on such subdivisions of the public land survey as may be approved by the Director, but not less than the area approved by the well- spacing order affecting such lands for such Reservoir. After due consideration of all pertinent information, the Director shall render his decision, separate as to each lease or lands therein submitted for commitment. Under the statutes, the unitization regulations, and the terms of the PBU Agreement, the commissioner retains the discretion, after consideration of the criteria in 11 AAC 83.303, to approve or deny the expansion of the PBU to include the expanded NPA and WNPA based on the "final" application . The commissioner will approve a proposed expansion of a unit area, a proposed PA, or a proposed production or cost allocation formula if the commissioner finds that each requested approval is necessary or advisable to protect the public interest. AS 38.05.180(p). To fmd that any or all of the requested approvals are necessary or advisable to protect the public interest, the commissioner must fmd that the requested approval will: (1) promote the conservation of all natural resources; (2) promote the prevention of economic and physical waste; and (3) provide for the protection of all parties of interest, including the state. 11 AAC 83.303(a). In evaluating the above criteria, the commissioner must consider: (1) the environmental costs and benefits; (2) the geological and engineering characteristics of the potential hydrocarbon accumulation or reservoir(s) proposed for inclusion in the participating area (3) prior exploration activities in the proposed participating area (4) the applicant's plans for exploration or development of the proposed participating area; (5) the economic costs and benefits to the state; and (6) any other relevant factors (including mitigation measures) the commissioner determines necessary or advisable to protect the public interest. 11 AAC 83.303(b). J 1 3 1998 Alaska O' ( AN Gas Cons. r nl k MAW 11/40 I A PA may include only land reasonably known to be underlain by hydrocarbons and known or reasonably estimated through use of geological, geophysical, or engineering data to be capable of producing or contributing to the production of hydrocarbons in paying quantities. 11 AAC 83.351(a). "Paying quantities" is defined by 11 AAC 83.395(4) to mean: quantities sufficient to yield a return in excess of operating costs, even if drilling and equipment costs may never be repaid and the undertaking as a whole may ultimately result in a loss; quantities are insufficient to yield a return in excess of operating costs unless those quantities, not considering the costs of transportation and marketing, will produce sufficient revenue to induce a prudent operator to produce those quantities. The following evaluates the Interim Application under all these criteria and considerations. (A) Promote the Conservation of All Natural Resources. The unitization of oil and gas reservoirs and the formation of PAs within unit areas to develop hydrocarbon- bearing reservoirs is a well accepted means of hydrocarbon conservation. Without unitization, the unregulated development of reservoirs tends to be a race for possession by competitive operators. The results can be: (1) overly dense drilling, especially along property lines; (2) rapid dissipation of reservoir pressure; and (3) irregular advance of displacing fluids. These all contribute to the loss of ultimate recovery or economic waste. The proliferation of surface activity; duplication of production, gathering, and processing facilities; and haste to get oil to the surface also increase the likelihood of environmental damage (such as spills and other surface impacts). Requiring lessees to comply with conservation orders and field rules issued by the AOGCC would mitigate some of these impacts without an agreement to unitize operations. Unitization, however, provides a practical and efficient method for maximizing oil and gas recovery, and minimizes negative impacts on other resources. The interim expansion of the PBU, the interim expansion of the NPA, and the interim formation of the WNPA to encompass additional lands overlying the Kuparuk River Formation reservoirs in the GNA will allow this area to be comprehensively and efficiently explored and developed. Adoption of a operating agreement and plan of development governing that production will help avoid unnecessary duplication of development efforts on and beneath the surface. Although the extent of the Kuparuk River Formation reservoirs in the GNA has not been finally determined, including the lands in the PBU and a PA now will accelerate exploration and maximize recovery from the area. When the extent of the separate Kuparuk Formation reservoir segments are better known, the commissioner may decide to create a separate unit to combine the various segments. Producing hydrocarbon liquids from the expanded NPA and the new WNPA through the existing production and processing facilities, at Heald Point and the LPC, generally reduces the incremental environmental impact of the additional production. Using the existing facilities, gravel pads, and infrastructure eliminates the need for new ones. The interim expansion of the PBU, the interim expansion of the NPA, and the interim formation of the WNPA to encompass additional lands overlying the Kuparuk River Formation reservoirs in the GNA will promote resource conservation and protect the public interest during the current appraisal drilling and production phase. Depending on the results from the additional delineation wells drilled in 1997 and the GNA Owners' equity negotiations, the creation of a separate unit over the various individual reservoir segments would also accomplish the same resource conservation goals under terms and conditions potentially more favorable to the public interest. (B) The Prevention of Economic and Physical Waste. Traditionally, under unitized operations, the assignment of undivided equity interests in the oil and gas reservoirs to each lease largely resolves the tension between lessees to compete for their share of production. Economic and physical waste, however, could still occur without an equitable cost sharing formula, and a well- designed and coordinated development plan. Consequently, unitization must equitably divide costs and production, and plan to maximize physical and economic recovery from any reservoir. It must also treat the royalty owner fairly. An equitable allocation of hydrocarbon shares among the WIOs discourages hasty or unnecessary surface development. Similarly, an equitable cost - sharing agreement promotes efficient development of reservoirs and common surface facilities and encompasses rational operating strategies. Such an agreement further allows the WIOs to decide well spacing requirements; scheduling, reinjection and reservoir management strategies; and the proper common, joint -use surface facilities. Unitization prevents economic and physical waste by eliminating redundant expenditures for a given level of production, and avoiding loss of ultimate recovery by adopting a unified reservoir management plan. Unitized operations greatly improve development of reservoirs beneath leases which may have variable productivity. Marginally economic reserves, which otherwise would not be produced on a lease by lease basis, often can be produced through unitized operations in combination with more productive leases. Facility consolidation saves capital and promotes better reservoir management by all WIOs. Pressure maintenance and secondary recovery procedures are much more predictable and attainable through joint, unitized efforts than would otherwise be possible. In combination, these factors allow less profitable areas of a reservoir to be developed and produced in the interest of all parties, including the state. The GNA Owners have negotiated agreements among themselves to share the existing production capacity of the Lisburne facilities, the Heald Point facilities, and the PBU infrastructure. Using this infrastructure and facilities eliminates the need to construct stand -alone facilities to process the volume of recoverable hydrocarbons from the GNA. Further, these agreements address reservoir management and operational decisions for the Kuparuk River Formation reservoirs within the GNA. The state has i ate in attempts reduce the need for additional p d i tte p to uc tional major rocessin P g facilities and thus to minimize any additional surface impacts and costs. The state has agreed to allow commingled production through the existing Lisburne Production Center (LPC) and has worked to provide for a well test -based production allocation methodology for current and future reservoirs sharing the LPC. The adoption of that methodology is subject to periodic review and reconsideration to assure that the state's royalty and tax interests are protected. Further, facility consolidation will save capital and promote better reservoir management through pressure maintenance and enhanced recovery procedures. In combination, these factors allow the Kuparuk River Formation reservoirs within the GNA to be developed and produced in the interest of all parties. Nevertheless, the formation of multiple interim PAs could possibly make proper reservoir management in the western Niakuk area difficult. A potential for economic waste and physical waste exists because: (1) The boundaries of interim PAs do not conform to the known compartmentalization of the Kuparuk reservoirs in the western Niakuk area; (2) The GNA Owners do not have an integrated full field model for this very complex field and at least parts of the field will be in decline before the development of such a model; (3) Although the GNA Owners have made progress in sharing raw and interpretative geological, geophysical and engineering data, the Division has been told the sharing is not complete, thereby complicating reservoir management and delaying any consensus technical mapping in the western Niakuk area; and (4) Because the GNA Owners have not yet developed a methodology for equity determination, a new development well may not be optimally placed for production of the reservoir but for its value in future equity negotiations. Although the Division has not seen evidence that economic or physical waste has or will occur in the Niakuk field, it remains concerned and will continue to monitor closely the GNA reservoir management and to encourage the GNA Owners to complete their equity negotiations as soon as possible. Although expanding the PBU to unitize the leases encompassing the various Kuparuk Formation reservoirs within the expanded NPA and WNPA could prevent economic and physical waste in the interim, creating a separate unit for some of the reservoir segments, under terms and conditions potentially more favorable to the public interest, could accomplish these same goals. (c) Protection of All Parties The Interim Application seeks to protect the economic interests of all working interest owners of the reservoirs in the GNA, as well as the royalty owner. By combining interests and operating under the terms of a unit agreement and unit operating agreement, such as the PBU Agreement and PBU Operating Agreement, as amended to account for any special PA provisions, as well as the GNA Agreement, the GNA Owners may fairly allocate costs and revenues among themselves. Because hydrocarbon recovery will be maximized and additional production -based revenue will be derived from the additional GNA production, the state's economic interest is promoted. Additional recovery of hydrocarbons alone may not always be determinative of the state's best interest. Production must occur under suitable terms and conditions to assure that the economic interests of both the working interest owners and the state, as the royalty owner, are protected. The Interim Application is a reasonable temporary resolution of the current undesirable situation. There are now numerous, individual, tract and lease operations for each well drilled and produced within the GNA. The current NPA needs to be expanded or a new PA, PAs, or new unit formed to provide for the integrated development of the lands that have been proven by the tract and lease operations to be capable of sustained commercial production of Unitized Substances. 110 1111 In the Interim Application, the GNA Owners agreed that the effective date for the "final" expansion of the PBU, "fmal" new, expanded or contracted PA(s), and "final" tract allocation schedule for the PA(s) would be November 1, 1996. DNR agreed to provide the opportunity for the GNA Owners to complete their equity determination process and submit the application for "fmal" PBU expansion, "fmal" PA(s), and "final" tract allocation schedule by December 31, 1997. Given the information presented by the GNA Owners on November 10, 1997, the Division will extend that time to March 31, 1997. Failure to timely submit the "final" application may cause the DNR to prescribe the "final" expansion boundaries of the PBU, "final" new, expanded or contracted PA(s), and "final" tract allocation schedule for the PA(s). As proposed, the Interim Application, protects all parties' interests, including the State's and allows the GNA Owners more time to propose a fmal solution. The GNA Owners and the DNR recognize that the Interim Application is not the "final" answer as to the ultimate size and shape of the PA or PAs for the Kuparuk River Formation reservoirs in the GNA, the extent of any PBU expansion or unit formation, and the ultimate tract allocation schedule for the PA or PAs. The determination of the boundaries of a "final" PA, PAs, or new unit, and the "final" expansion of the PBU or formation of a new unit will be based on the applicable provisions of the PBU Agreement, the state statutes and regulations, and the information determined from additional drilling and development operations in the GNA. The "final" PBU expansion will not be approved unless all parties of interest, including the state, can be protected. 11 AAC 83.303(a)(3). The GNA Owners must show why the state's interests, particularly its economic interests, are better protected by expansion of the PBU, than by forming a new unit area. In reviewing the above criteria, the following factors were considered: (1) The Environmental Costs and Benefits As discussed above, the sharing of the existing facilities eliminates duplication and reduces the surface area altered by development. The GNA Owners negotiated agreements that provide for increased access to existing Heald Point and LPC facilities for exploration, production, and development in the GNA. Additional GNA wells will be drilled from surface locations at the Niakuk drillsite to, delineate and test potential Kuparuk River Formation accumulations in the northern portions of the proposed expanded NPA and proposed WNPA. These activities will not significantly alter the existing gravel pads, roads or surface facilities. There will be no significant additional impacts to nearshore habitat or biological resources because of the additional Niakuk production, or production from other accumulations near Heald Point. (2) The Geological and Engineering Characteristics of the Reservoir Geological, geophysical, or engineering information was not submitted with the Interim Application. However, geological, geophysical, and production data available from the Niakuk field indicates that the Kuparuk River Formation reservoir is stratigraphically and structurally complex and contains multiple compartments. Any given compartment may or may not be in full or partial pressure or fluid communication with adjacent compartments. Compartmentalization N - N appears to be a function of multiple depositional point sources, syn- depositional and post - depositional faulting, and variations in depositional environmental relating to the local and regional tectonics and basin morphology. The proposed PA boundaries do not conform with the known compartmentalization of the reservoir. For example, production, test, and geophysical data indicate that the Kuparuk reservoir is in communication between the proposed WNPA and the current NPA. The boundaries for the WNPA and the expanded NPA in the Interim Application are based on geography and lessee interests rather than the known geology of the reservoir. (3) Prior Exploration and Development Activities Numerous delineation wells have been drilled since the NPA was formed and drilling continues from Heald Point to determine the extent of the Kuparuk River Formation reservoirs in the GNA. Within the proposed expanded NPA, at least four wells have been drilled: NK -13, NK -14, NK -15, and NK -17. Three wells have recently been drilled within the proposed WNPA: NK -27, NK -28, and NK -29. Production data available to the Division indicate that NK -14, NK -27, and NK -28 produce at an average rate of 2,962 BOPD, 3,806 BOPD, and 2,900 BOPD, respectively. NK -27 was certified as capable of production in paying quantities in June 1995. In addition to the well data, 2 -D and proprietary 3 -D seismic surveys, acquired over the GNA, have assisted the evaluation of the lands appropriate for inclusion within the expanded PBU, expanded NPA, and proposed WNPA. The GNA Owners are expected to provide the results from their 1997 drilling efforts with the "final" application. (4) The Applicant's Plan for Exploration or Development of the Participating Area The Interim Application incorporated by reference the 1997 Plan of Development for the NPA as the plan of development and operations for the WNPA and expansion area of the NPA. The Division approved this plan of development for the period March 2, 1997 through March 2, 1998. (5) The Economic Costs and Benefits to the State As discussed in Article III(c) above, increased production and revenues alone may not always be in the state's best interest. Here, however, the gain in economic benefits outweigh any costs to the state. In the Interim Application, the GNA Owners have agreed to make November 1, 1996, the effective date for the "final" expansion of the PBU, "final" new, expanded or contracted PA(s), and "final" tract allocation schedule for the PA(s). This retroactive effective date will assure that the state receives the timely, adjusted benefits of the earliest production from Kuparuk River Formation reservoirs in the GNA in exchange for providing the GNA Owners the time to complete their reservoir delineation plans and equity determination process. The state's royalty share will be adjusted using the effective date for the "final" PA or PAs. M - N The GNA Owners submitted an allocation of production for the leases in the proposed WNPA and the extended NPA (Exhibit 4 and Exhibit 5, respectively, to the Interim Application) to comply with 11 AAC 83.371. Because the tract allocation schedules are only for the interim period before the "final" PA or PAs application are submitted and are subject to the retroactive adjustment date mentioned above, the tract allocation schedules are acceptable. (6) Any other relevant factors (including mitigation measures) the commissioner determines necessary or advisable to protect the public interest The factors are discussed in Article IV below. IV. OTHER ISSUES PERTINENT TO THE INTERIM APPLICATION As part of the Interim Application, the GNA Owners and the Division have agreed that ARCO's, BP's, and Exxon's ANS Gas Royalty Settlement Agreements and ANS Royalty Litigation Settlements Agreements will apply to all production from the WNPA and the NPA, as expanded. The parties have further agreed that the 1980 Prudhoe Bay Royalty Settlement Agreement (RSA) will apply to (1) all GNA leases currently in the PBU; (2) the production attributable to the southern halves of ADL 34625 and ADL 34626 as these lands were included in the PBU on the effective date of the RSA; and (3) the production attributable to the northern halves of ADL 34625 and ADL 34626. Any changes for field cost allowances on the northern halves of ADL 34625 and ADL 34626 which may result from a final resolution of the field cost allowance issue for the "final" PA or PAS would be effective retroactive to November 1, 1996. The parties have agreed that this proposal in no way prejudices or limits any GNA Owners' right to claim or the DNR's right to object to field cost allowances for the production attributable to the northern halves of ADL 34625 and ADL 34626. V. FINDINGS AND DECISION Considering the facts discussed in this document and the administrative record, I hereby make findings and impose conditions as follows: 1. DNR had the discretion to expand the PBU under the conditions proposed by the GNA Owners. 2. In evaluating whether to exercise my discretion to approve the proposed expansion, I must determine that it is in the state's best interest to do so considering the specific facts and circumstances surrounding the application. 3. In making a determination that the proposed expansion is in the state's best interest, it is necessary to evaluate the proposal in light of the statutes, the regulations and the contractual obligations to which the state is party. 13 1998 Alaska Oil & SAN Gas Cons. rr;aanr Anchapapp IMO 4. The interim expansion of the PBU and the NPA, and the interim formation of the WNPA are necessary and advisable to protect the public interest. AS 38.05.180(p) and 11 AAC 83.303. 5. The available well data and exploration plans justify the inclusion of the proposed lands within the PBU. Under the regulations governing formation and operation of oil and gas units (11 AAC 83.301 - 11 AAC 83.395) and the terms and conditions under which these lands were leased from the State of Alaska, the following lands are to be included in the expanded PBU area: T.12.N., R.15.E., U.M., Secs. 13, 14, Sec. 23: N /2, Sec. 24: N /2, SE /4 (ADL 34625 (Tract 4)); T.12.N., R.15.E., U.M., Secs. 15, 16, 22, Sec. 21: N /2, SE /4 (ADL 34626 (Tract 5)). 6. The available well data demonstrate that a paying quantities certification is appropriate for the well(s) in the Kuparuk River Formation reservoirs within the GNA. The data also suggest that the acreage is underlain by hydrocarbons and known and reasonably estimated to be capable of production or contributing to production in sufficient quantities to justify the interim expansion of the NPA and the interim formation of the WNPA within the PBU. The available well and geological data as well as exploration plans justify the interim inclusion of the proposed tracts within the NPA and WNPA. Under the regulations governing formation and operation of oil and gas units (11 AAC 83.301 - 11 AAC 83.395) and the terms and conditions under which these lands were leased from the State of Alaska, the following lands are to be included in the expanded NPA Area and WNPA: (A) Expanded NPA: T.12.N., R.15.E., U.M., Secs. 13, 14, Sec. 23: N /2, Sec. 24: N /2, SE /4 (ADL 34625 (Tract 4)); T.12.N., R.15.E., U.M., Sec. 36: NE /4 (ADL 34630 (Tract 31)); (B) WNPA: T.12.N., R.15.E., U.M., Secs. 15, 16, Sec. 21: N /2, SE/4, Sec. 22 (ADL 34626 (Tract 5)); T.12.N., R.15.E., U.M., Sec. 27 (ADL 34629 (Tract 30)). 7. The approved interim expansion of the NPA and the interim formation of the WNPA encompass the reasonably known hydrocarbon bearing portion of the Kuparuk River SS Formation reservoirs within the GNA that are capable of production or contributing to production in paying quantities. The NPA expansion and WNPA formation provide for the equitable division of costs and an equitable allocation of produced hydrocarbons, and set forth a development plan designed to maximize physical and economic recovery from the reservoirs within the expanded and approved participating areas. 8. Pursuant to 11 AAC 83.371(a), the allocation of production and costs for the tracts within expanded NPA and the WNPA, Exhibit 5 and Exhibit 4 of the Interim Application, are approved. 9. The production of GNA hydrocarbon liquids through the existing production and processing facilities within the PBU reduces the environmental impact of the additional production. Utilization of existing facilities will avoid unnecessary duplication of development efforts on and beneath the surface. 10. The currently approved well test allocation methodology continues to be acceptable for royalty allocation purposes and for allocating the commingled gas and hydrocarbon liquids production amongst all the PAS that are processed through the LPC. The LPC Operator, ARCO, shall provide the Division with the monthly production allocation reports and well test data for the wells producing through the LPC by the 20th day of the following month. The Division reserves the right to request any information it deems pertinent to the review of those reports. The allocation report shall include a monthly oil, gas, and water allocation factor to be applied uniformly to the commingled production, a summary of monthly allocation by well, a summary of the allocated volumes of oil, hydrocarbon liquids, gas, and water by participating area, oil gravity for each participating area and the oil gravity of the combined streams, and specific well test data for all tests which have been conducted. 11. The Division reserves the right to review the well test allocations to insure compliance with the methodology prescribed in this decision. Such review may include, but is not limited to, inspection of facilities, equipment, well test data, and separator back - pressure adjustments. 12. To account for the gas produced from each participating area, the gas volume disposition and gas reserves debited from or credited to each PA using the shared LPC, the LPC Operator shall continue to submit a monthly gas disposition and reserves debit report. The gas disposition report, now to include the WNPA, shall be submitted with the monthly production allocation reports. 13. The field cost allowance for the state's royalty share of oil produced from all GNA leases currently in the PBU and the production attributable to the southern halves of ADL 34625 and ADL 34626, as these lands were included in the PBU on the effective date of the RSA, is governed by the RSA. During the period of the Interim Application, the field cost allowance for the production attributable to the northern halves of ADL 34625 and ADL 34626 will also be governed by the RSA. Any changes for field cost allowances on the 40. northern halves of ADL 34625 and ADL 34626 which may result from a final resolution of the field cost allowance issue for the "final" PA or PAs would be effective retroactive to November 1, 1996. The parties have agreed that this proposal in no way prejudices or limits any GNA Owner's right to claim or the DNR's right to object to field cost allowances for the production attributable to the northern halves of ADL 34625 and ADL 34626. 14. Diligent exploration and delineation of the reservoir underlying the GNA is planned by the GNA Owners under the PBU plans of development and operation approved by the state. 15. The plan of development for the WNPA and the expansion area of the NPA was included with the 1997 plan of development for the NPA. That plan met the requirements of 11 AAC 83.303 and 11 AAC 83.343 and was approved by the Division on April 21, 1997. Further plans of development which describe the status of projects undertaken and the work completed, any changes or expected changes to the plan must be submitted in accordance with 11 AAC 83.343. 16. Approval of the interim expansion of the Prudhoe Bay Unit, interim expansion of the NPA, and the interim formation of the WNPA are effective this date. 17. A final application must be submitted by March 31, 1998. %u >1 J 2 9 7 Kenneth A. Bo d, Ditictor Date Division of Oil and Gas Attachments: Expanded NPA Tracts and Tract Allocation Schedule WNPA Tracts and Tract Allocation Schedule PBU.4exp.Appv.doc * 7 t • ! B j� BP EXPLORATION BP Exploration (Alaska) Inc. 1 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519 -6612 (907) 561 -5111 December 30, 1997 r e Chairman David Johnston Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage AK 99501 -3192 Re: Amendment of Conservation Order 329, Niakuk Oil Pool Dear Chairman Johnston: BP Exploration (Alaska) Inc. (BPXA), on behalf of itself, ARCO Alaska, Inc. (ARCO), and Exxon Corporation (Exxon) hereby request that the Commission amend Conservation Order 329 to include additional lands located to the west and north of the current rules area. BPXA was the original applicant for C.O. 329, and ARCO and Exxon are the lessees of additional lands to be included. Exhibit A contains a map of the proposed amended area and sets forth the legal description of the lands to be covered by the amended rules. With respect to these lands, the Alaska Department of Natural Resources has also recently approved expansion of the Prudhoe Bay Unit and the Niakuk Participating Area and establishment of a participating area to the west called the Western Niakuk Participating Area. The inclusion of this acreage under C.O. 329 will aid in the protection of correlative rights, ensure greater ultimate recovery of oil and gas, and prevent waste by ensuring that a common set of rules governs development area wide. No exception or change to current rules, other than the affected area, is requested. All affected parties support this request; therefore, we do not believe a public hearing is necessary for the Commission to act on this request. Please do not hesitate to contact the undersigned at 564 -4623 if you have any questions about this request or require additional information. se Sincerely, _ ,„ rt '-' to & � , . Robert Janes Manager, GPMA cc: Jim Branch, Exxon , • , ; 4 Joe Leone, ARCO Alaska : _ r _ r „ Ken Boyd, ADNR Patrick Coughlin, ADNR BP BOUNDARIES OF THE NIAKUK OIL POOL EXHIBIT A �� 1 0.5 0 1 MILE STEFANSSON 12 10 11 12 • Niakuk Pool � . DL BPx,00.00 ii 2 LEGEND ADL 385549 3 Mile �mft Proposed Expansion NK / IIL,I Greater Niakuk Area I r 15 18 17 16 13 14 NIC P — 9 _....._ _. ........_.__ • K h. -14 NK- O • O 1► BPX 95.50 22 GU UI O • C IRI 2.50 1 ' O K - 28 - ' 2 � , ti § . r §C1Y AL I '� 2{} 21 2 3 N ANA1 ; 50 ARC x.00 ` uV lh ARCO50.00 DOYON0.50 I J ADLN5 I v y k ' a �' e' l ' N i lk II� ADL 3,12827 O,A a ADL 312828 W d DUCK ISLAND I. GULL -„w NK -a 411 V�rw mow. •da l� l � I ',II I I kC I ' l §u _ . . Il limp vwlhll 111 RlWlH4 r !L IIII � rr § r L I _ RESOLUTION S. O 1® d I �1 s h , , i. „Ci i p 1100 § 10 Nu w � � W N II '�' W Nq -IT � � is I I s , pr a ;alllgmlllI Yy , c r y1 r g11 , Il � - t y I I0111II �I '�:�mdl S' a 11 1 CN.s 0 J ,. � u w � Iy � I h 3 � + � k luollq � f I � � I I r uC�l r �I 7 R ,, �, " 4it r. r I IIIIII 1 � w x a r W i uV lk til li B 44 �� ., a W illy ' w�I �lu w h1 � I ��1 1 l 27 2E 25 I iy ��VI I I I Iii�iiI�rv, , fifl w 1 II ,a �1 f � r y l GULL °nifl.a � ' i 141 ail �I m �f ' r � Ih � „,4,5,6r,„:01,1 l � I� = a I� IV ly y � � � '�4 V u I I rI r � — � IH IIf 1 1 � 11111II��Pu I r s �s ' �IIJ P� -_ �u y u I� � � d4l�ss §s II I9 4 . .. r �I r� . �I1 ? plp fwa Idti r -.. r u IW 1 �I " y. C 1 VI� ^.! 2.50/U08 ' _ _ w � fy BSI �� I��,I� I I VF V .w Su§ _ -__ ......_......._ _ ' ._ 4 .,.a � � I P �� 1 4 6 p ...... _..___........ f LS-29 _ . ' II r 4 VU@ , II 11: �V Wi' O O f 9 lal d� ,. §{ zt If1 s � , J MPI �. L538 w1n "b � V y� h l n sr � 16 s p L5_33 1 s^. II c; i 1, 4 � h V Il l L5 -25 . <a'lI1 1 91 .:w + I � �. ^I I a,....'� I V 33 NK-25 33 34 Os O O � �. K -26 GULL-02 ARCO * LS 28 BPX 100.00 O BPX 100.00 BPX 100.00 Exl(ON50.00 BPX 100;00 HEgLDpr, ADL34635 SAGD01 ADL 4634 ADL 34833 T12N ADL 34629 ADL _ :, . T11 N O L5-24 . L5.09 O O 3 L617 LS 1 $AGDEL - i� 13 /i LS-,8 W P O ARC 34831 BPX � _ T12N E XX ON 50.00 BPX 100.00 Q W W BPX 1 OD.00 �' BPX 100.00 PR UDHOE BAY ADL 34631 ADL 1518 ADL {< c ADL 28397 ADL 34838 12/15/97 w113623.dgn W6 I D ' BP EXPLORATION BP Exploration (Alaska) Inc. P O . East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519 -6612 (907) 561 -5111 April 24, 1996 Mr. David Johnston Chairman, Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 -3192 Subject: Request for Revision to Conservation Order 329, Niakuk Oil Pool Dear Mr. Johnston, BP Exploration (Alaska), Inc. ('BP'), Operator of the Niakuk Oil Pool, hereby requests that the Alaska Oil and Gas Conservation Commission permanently waive the requirements of Rule 10, Conservation Order No. 329. Rule 10 states: "The offtake rate for the Niakuk oil pool shall not exceed 23 mb /d of oil averaged monthly." BP has reviewed the testimony and transcript of the Niakuk Pool Rules Hearing and confirmed that while the studies presented at the hearing did reference a peak rate of 23 mb /d, a limit for the pool was not requested or discussed as a concern during the proceedings. BP can only assume this rate cap was included in the Pool Rules as a means of controlling offtake prior to waterflood startup to avoid excessive reduction of reservoir pressure during the first year of primary production. A temporary waiver (No. 329.04) of the offtake rate limitation was received from the Commission on February 22, 1996. This waiver is effective until June 21, 1996, and has allowed time for BP to prepare data and evaluate studies that support eliminating the production rate limitation. The technical justification for granting a permanent waiver is included in the attached report. This request includes full field model run outputs containing reserves information which BP requests be kept confidential pursuant to 20 AAC 25.537(b), since it is information "not required by this chapter, but voluntarily filed with the Commission." The confidential information is found on Figures 6, 8 and 13. BP therefore requests that those figures be kept separate and confidential from the remainder of this request. Mr. David Johnso. • April 23, 1996 Page 2 Please call Bob Janes at 564 -463 or me at 564-5433 if you have any questions, comments, or require additional information. We appreciate your prompt attention to this matter. Sincerely, 2Agaz-aeL-- - - A. N. Bolea Asset Manager - Greater Point McIntyre Area Attachment cc: J. Dickey G. Lyle File: 23.00 R. W. Janes J. Leone (ARCO Alaska, Inc.) w/o confidential attachments J. F. Branch (Exxon, USA) w/o confidential attachments CORRESPONDENCE \ANB\4 /18 JOHNSTON -AOGCC - /ds • Prudhoe Bay Unit Niakuk Oil Pool Conservation Order 329 Technical Justification for Waiver of Rule 10 This Report has been prepared for submission to the Alaska Oil and Gas Conservation Commission to provide a technical justification for a change in Rule 10 of Conservation Order No. 329 for the formation of the Niakuk Oil Pool dated January 11, 1994. The report concludes that removing the limit will not cause waste or loss of recovery. On the contrary, continuation of the Rule 10 rate limitation may have the opposite effect by reducing the amount of oil recovered, and discouraging further development within the pool. BP Exploration (Alaska), Inc. ('BP') requests a revision to Rule 10 that governs the maximum average oil offtake rate allowed in the Niakuk Oil Pool. This rate is currently set at 23 mb /d of oil averaged monthly and BP requests that the rate cap be permanently waived. The Niakuk Oil Pool has been producing for nearly two years. During this time, information has been gathered about well and field performance. Waterflood was initiated one year ago in conjunction with permanent production modules. The field data has shown that the current offtake rate limitation is restrictive relative to better than expected field performance, increased field size and operational considerations. Reservoir modeling has shown that higher offtake rates do not jeopardize ultimate oil recovery from the Niakuk Oil Pool provided that reservoir pressure is maintained. In addition, there are no mechanistic reasons for loss of recovery to occur at higher throughput/offtake rates as long as voidage is replaced and pressure is maintained in the areas of the field where waterflood is feasible. The current Niakuk Oil Pool consists of at least four separate oil accumulations, which are managed separately. They are named Segments 1, 2, 2A, and 3 and are identified on the map in Figure 1. An additional accumulation exists to the northeast of Segment 2 around Sag Delta #8. Other accumulations may exist to the north of Segment 2 in the Tract 75 acreage, to the north of Segment 3, or in oil- bearing horizons deeper than the current vertical limits of the Niakuk Pool. These additional accumulations are all outside the current Pool and will not be discussed in this report. Because the bulk of the evidence indicates the Segments are hydraulically separate from each other, and because BP manages them independently, this technical discussion treats each Segment individually. Other factors related to the offtake rate and general conclusions are provided at the end of this report. The current geologic interpretation and reservoir performance for Niakuk have been incorporated into reservoir simulation models. The reservoir simulation model used for the original Pool Rules Testimony has been updated to account for this latest information. Two models have been constructed to simulate the Niakuk oil pool. One model ('Model A') encompasses only Segments 1 and 3 and a second simulation model ('Model B') includes Segments 2, 2A and Tract 75 acreage. The areal extent of Models A and B is shown on Figure 2. a. Segment 1 The location of Segment 1 is shown in Figure 1. This segment has currently been developed by wells NK- 7,8,10 and 12a within the boundaries of the Niakuk Pool. NK -27 is producing from the Segment 1 accumulation, but resides outside of the current pool boundaries. NK -27's performance has been accounted for in this analysis. Reservoir simulator runs indicate that increasing the offtake rate in Segment 1 will not cause loss of reserves from the area. Figure 2 shows the location of Model A which encompasses the Segment 1 area. Basic model parameters are given in Figure 3 and a 3 -D view of Model A is shown in Figure 4. Waterflood was initiated in May 1995 in this Segment. Water injection is provided by NK -10 and this well is currently injecting water at about 19 mb /d. Static pressures surveys are graphed in Figure 5. There had been a relatively consistent pressure drop over time prior to waterflood startup which is due to the continuous and connected nature of the productive intervals in this segment. Prior to waterflood startup, the maximum pressure drop measured in the segment was approximately 420 psi, measured in Niakuk 8 on 4/20/95. For the period of time between waterflood startup and January 1996, water injection volumes have exceeded total reservoir voidage (including voidage from ARCO /Exxon's NK -27, which is in Segment 1, but outside of the current pool boundaries) and reservoir pressure has increased approximately 100 -200 psi. Water injection is provided by NK -10 and this well is currently injecting water at about 19 mb /d. Since January the voidage replacement ratio has been maintained at approximately 1. Plans are to maintain voidage replacement at approximately 1, and keep reservoir pressure constant at the current level. As shown in Figure 5, the Model A pressure trend provides a reasonable match of field data. The offtake rate study using Model A is based on two different production scenarios. The first scenario ('restricted rate') limits the offtake rate to 8 mb /d for all wells in Segment 1. This rate is proportional to what Segment 1 might contribute if the current rate cap was not removed. The second scenario ('increased rate') allows the wells to produce up to their hydraulic limit as long as water injection capacity is sufficient to sustain reservoir pressure. It should be noted that the second offtake scenario most closely compares to current offtake rates, and the first scenario would represent a significant reduction in offtake and injection in Segment 1. In both scenarios, reservoir pressure is maintained within the Segment. Figure 6 shows the oil rate and cumulative recovery profiles associated with a 'restricted rate' and an 'increased rate' scenario. Total Segment 1 production reaches 12 mb /d when increased production rates are allowed versus 8 mb /d in the 'restricted rate' scenario. The cumulative recoveries are the same within model accuracy. The model demonstrates that there is no loss of recovery with the different offtake rates. In conclusion, the waterflood process is not rate sensitive. Note: The cumulative oil recovery for each case has been normalized and is shown as a percentage of the ultimate oil recovery. Since both rate scenarios achieve approximately the same ultimate recovery (i.e., both barrels ultimately produced and recovery factor), both cases converge to the same 100% end point. b. Segment 3 The analytical process performed on Segment 3 is identical to that used on Segment 1. Figure 1 shows the location of Segment 3. Figures 2 to 4 describe location, parameters and a 3D view of Model A. The reservoir description in the Segment 3 area of the model is based on current knowledge. Although Segment 1 and 3 are both included in the model, they are hydraulically disconnected along the east -west fault dividing the two Segments which is consistent with actual field pressure data. The pressure trend for Segment 3 is graphed in Figure 7. This plot shows the NK -9 pressure data for both the field data and Model A. A reasonable history match of NK -9's performance -to -date has been achieved. Although the ultimate development scope of Segment 3 has not yet been defined, initial results from NK -9 are encouraging. Additional drilling is required in this Segment to determine ultimate well counts. Therefore for the purpose of this offtake rate analysis, Model A was run with only one additional well in this Segment which formed one producer /injector pair with NK -9. This well was assumed to be drilled and available July 1996 at which time injection was initiated. After water injection startup, reservoir pressure was maintained in both cases. i • Figure 8 provides the rate and recovery plots from the Model A analysis. It is estimated that a producer in this area will have a capacity of up to 8 mb /d under waterflood. This 'increased rate' case was compared to a 'restricted rate case of 4 mb /d. The model demonstrates that there is no loss of recovery with an increased offtake rate. Although there is upside to the rate potential for the Segment 3 area, this study was limited to the oil recovery for one producer- injector pair around the NK -9 area. It is expected that the waterflood process will be rate insensitive, if reservoir pressure is maintained, even when this process is applied to a development scope of the Segment 3 area that may include more wells. c. Segment 2 In Segment 2, NK -18, 20, 21, 22 and 42 have all benefited from the water injection in wells NK -16, 23 and 38. Gas -oil ratios, well -head pressures and reservoir pressure measurements obtained since waterflood startup have confirmed waterflood response. Reservoir connectivity, although more complex than Segment 1, is apparent. Current plans are to maintain reservoir pressure by adjusting production and injection volumes as required. Additional wells are being planned in this Segment within the current Pool boundaries to help delineate the reservoir. Figure 1 shows the location of Segment 2 and the current producing and injecting wells. As previously stated, an updated reservoir simulation model (Model B) has been constructed covering Segments 2 and 2A as well as much of the undeveloped Tract 75 area to the north of Segment 2. The areal extent of Model B is shown in Figure 2. Model B indicates that increasing the offtake rate in Segment 2 will not cause loss of reserves from that segment. Figure 9 describes the model and provides a description of the reservoir properties by zone in the region. A 3 -D view of Model B is provided in Figure 10. Consistent with field pressure data, the Segment 2A area is hydraulically isolated from Segment 2 in the model, and Segment 2 and the Tract 75 area are partially connected. The field pressure results for Segment 2 have been divided into two overall 'zone' classifications. These sub - segment classifications are named Upper -Zone F and the Lower -Zones D /E. The pressure plots have been divided between the upper and lower zones in Segment 2 for reasons of clarity rather than any distinction that they are hydraulically isolated. In fact, pressure response seen to date indicates that all zones in Segment 2 are in some degree of communication. Positive response to the waterflood is apparent in each zone and between zones. a . k 1 ✓� Figures 11 and 12 show the field pressure data for each sub - segment. Although there is the same overall pressure trend between the two sub - segments, there are several wells in the lower zones of Segment 2 that are difficult to match with the model. NK -21, for instance, has had wide pressure swings prior to and subsequent to water injection. The well is being supported by the injector NK -16, and appears to reside in a small pool closely linked to NK -16. Although the model has difficulty matching some elements of field performance in Segment 2, the model is adequate for assessing the effects of offtake rate on recovery. Model B indicates that increasing the offtake rate does not impact ultimate recovery. As shown in Figure 13, two cases were studied. The 'restricted rate' case kept the Segment 2 rates capped at 13 mb /d of oil; which would be a reasonable proration for Segment 2's production under the current rate cap. The 'increased rate' case allowed the wells to flow up to their hydraulic capacity of about 19.5 mb /d while maintaining reservoir pressure. Both cases maintained reservoir pressure at 4200 psi after waterflood startup. Cumulative oil recovery for Segment 2 is also shown in Figure 13. The 'increased rate' case achieves the same recoverable oil volume as for the 'restricted rate' case provided reservoir pressure is maintained. It is concluded that the waterflood process is not rate sensitive in Segment 2. d. Segment 2A NK -19 is the only well in the Segment 2A area. Figure 1 shows the location of this Segment. Segment 2A is a small pressure isolated pool between Segments 1 and 2. The field pressure data is shown in Figure 14. The initial pressure survey confirmed the pool containing NK -19 was isolated. Subsequent production was high GOR (-10000) and pressure declined rapidly. Material balance studies to date have indicated a small oil pool with a gas cap. Because of the poor performance results of NK -19, the model was not used to evaluate any sensitivities on rate in this area. The option for pressure support in this region is remote and the plan is to produce the well under natural depletion. e. Operational Considerations There are several operational issues that are influenced by any production rate cap at Niakuk: 1) Offtake would be restricted to the point where wells would have to alternately produce between various segments or within segments. Alternating wells in this fashion is sub - optimal and could jeopardize ultimate recovery. 2) Higher offtake rates early in field life assure maximum recovery is achieved prior to shut -in and abandonment (e.g. due to corrosion) when facility replacement costs become prohibitive. 3) There are times when, due to facility, well intervention or field downtime issues, it may be advantageous to produce Niakuk at higher rates to maximize LPC throughput. 4) Since the rate cap is on a monthly basis, additional time would be required to monitor field production rates for the current month and additional time and oversight would be required to ensure that the field produces up to, but not in excess of the monthly limit. f. Conclusions Reservoir modeling has shown that producing the Niakuk Pool at higher offtake rates than established in Rule 10 of Conservation Order No. 329 does not affect ultimate recovery provided that reservoir pressure is maintained in those areas with a viable waterflood. The scope of development for the Niakuk Oil Pool has increased since the submission of the Pool Rules testimony. Segments 2A and 3 were not included in the studies performed in support of the original pool rules application, and eastern Segment 2 appears more prospective than thought at that time. The performance of the Niakuk Oil Pool has been better than expected. Well capacity and reservoir connectivity in conjunction with waterflood has allowed for higher offtake rates than previously anticipated. Additional wells are planned within the current pool boundaries to efficiently develop the Niakuk reservoir. With the rate cap in place, these wells can not be economically justified because any additional capacity they may develop can not be produced. Therefore, rate restrictions may defer or cancel drilling options and put reserves at risk. Additional upside to current Niakuk Pool exists in the Tract 75 area, northern Segment 3, and western Segment 1. Rate restrictions may impair waterflood performance. Wells within a waterflood area may be shut -in prematurely or alternately produced due to a rate restriction, thereby reducing ultimate recovery. BPX (Alaska): Niakuk Oil Pool Figure 1 Location Map ____ . 1 S BP 100% Tract 75 - Segment 3 BP/Arco •••■•■••■••• 50%/50% I . 6 #."1.6.1111M22110 #P :17111.1.1111111111.111117"...... j # 38 4, 1"...-4.#-1.--- 4 1 #27 • Se ng_Ni—it 1 I • I Se rt_g_At—Tt 2 4023 . Niakuk Fault 1 • vil • • , • Exxon/Arco Niakuk Oil Poo 50%150% amLiAlt l 111 1 1 .sse_ jg Heald . N I , Point Drillsite BP 100% N L • Production well • Injection well R E r E APR 2 Alaska Oil & Gas (013. Cctiraission Ancliorc.ga BPX (Alaska): Niakuk Oil Pool Reservoir Simulation Model Locations Figure 2 4 2 «w..n�. . x..:., - M o defi . �.��.,��, i B � A 0 pproximate Boundary of i Approximate Boundary of Segment 1/3 Reser1946Mps11 Segment 212, /Tract 75 Reservoir Model • g Tract 75 • • j # 2 7 • Segment 1s 0 • • , -........._-- • °u1n • I Segment 2 Niakuk Fault • • • • i Niakuk Oil Pool t Segment 2A i I I Heald Al Point Drils�te N f • Production well Injection well ' ' Alaska Oil CK " ?s r, COMMISS On • BPX (Alaska): Niakuk Oil Pool Model A Parameters: Segments 1 and 3 Figure 3 • 3- Dimensional, 3- Phase, Black Oil Simulator • 40x26 Blocks Areally (2.5 acres each), 14 Layers (10600 active blocks) • History Matched through February 1996 • Range of Model Parameters: Model H NTG Por Perm Swi Layer Zone feet % and 1 -2 4 20 -120 .2 -.9 16 7 50 3 -8 3b 30 -120 .7 -.9 22 -26 300 -1000 33 9 3a 10 -30 .3 -.9 14 -22 30 -150 47 10 -11 2c 20 -60 .7 -.9 20 -24 300 -700 33 12 2b 100 .2 -.7 17 -21 50 -200 47 13 2a 50 -150 .2 -.5 10 -14 2 -10 47 14 1 20 -200 .4 -.8 17 -20 100 -200 53 BPX (Alaska): Niakuk Oil Pool Model A Grid: Segments 1 and 3 Figure 4 - . 2a #9 1, egrnent ;3 y North #8 egt1 • ECHVE APR 2 e' 199G Alaska Qi1 & Gas Cars. Cc;rmissi0n BPX (Alaska): Niakuk Oil Pool Segment 1 Pressure: Model A vs Field Data Figure 5 Pressure (psia) 4600 Original Pressure 4500 4400 7 4300 10 ■ ■ 8 Field Data 12a 10 4200 12a 12aa 12a 4100 N. Model A Trend 4000 3900 Well N located next to Field Data Point 3800 Apr 94 Oct 94 Apr 95 Oct 95 Feb 96 BPX (Alaska): Niakuk Oil Pool Segment 3 Pressure: Model A vs Field Data Figure 7 4600 Pressure (psia) Original Pressure • 4500 9 9 Field Data 4400 4300 4200 9 • Model A Trend 4100 - APR 2 r, 1396 4000 3900 Well # located next to Field Data Point 3800 - Apr 94 Oct 94 Apr 95 Oct 95 Feb 96 BPX (Alaska): Niakuk Oil Pool Model B Parameters: Segments 2 and 2A Figure 9 • 3- Dimensional, 3- Phase, Black Oil Simulator • 80x40 Blocks Areally (2.1 acres each), 14 Layers (11400 active blocks) • History Matched through February 1996 • Range of Model Parameters: Model H NTG Por Perm Swi Layer Zone feet % and 1 -2 not present in Segment 2 3 -5 f 30 -200 .5 -1 16 -28 20 -1500 27 -50 6 -8 e 30 -250 .4 -1 10 -24 10 -1000 50 -60 MIFF 9 -10 d 50 -200 .5 -1 12 -23 10 -700 45 -70 11 -13 c 100 -300 .2 -.8 13 -24 10 -800 45 -70 13 b 100 -200 .2 -.7 16 -18 30 -100 60 -70 BPX (Alaska): Niakuk Oil Pool Model B Gr Segments 2 and 2A Figure 10 0 North - .... 4 , .. ,_ , ._ , ... \ , ._._,.........,...,......,..,..,.,........................ ......,, ..„,' , ..... ...,,_ ,,, . " _.... Tract 75 ; h . • .d _ v ,. 4 � �S . . . . „ Sc r y1Ii 2 _ >. i t' \\V: 2 • ' �► f ' ma ". fl. A ..-rt 41 1::„,- 0 -°' * ''' ''' V -*to- '- '' t 9 , .w A 1 t . -- - -- F - r k - v _ fi BPX (Alaska): Niakuk Oil Pool • Segment 2 (Upper -Zone F) Pressure: Model B vs Field Data Figure 11 Pressure (psia) 4600 Original Pressure 22 • 4400 . Field Data 4200 .22 22 18 1111 N 23 3 • 4000 ■ ■ ■ 18 Model B Trend 18 18 3800 ■ 23 • 3600 RECEIVED 3400 2 f 1996 Well # located next to Field Data Point 3200 Apr 94 Oct 94 Apr 95 Oct 95 Feb 96 BPX (Alaska): Niakuk Oil Pool Segment 2 (Lower-Zones DIE) Pressure: Model B vs Field Data Figure 12 Pressure (psia) 5000 21 • Original Pressure 4700 20 Field Data 4400 21 4r it2 4100 21 21 20 Average Range 20 3800 20 of FFM Trends 20 3500 20 • 3200 2900 Well # located next to Field Data Point X 2600 Apr 94 Oct 94 Apr 95 Oct 95 Feb 96 BPX (Alaska): Niakuk Oil Pool Segme Segment ') A Pressure: Field Plata Fi gure 14 nt LrI I 14�7�7b11 V■ Field IN V N<bl Pressure (psia) 5000 - Original Pressure • 4700 19 4400 Field Data Trend 4100 3800 3500 APR 2 G 1996 • 19 19 3200 Alaska Qil 2900 Well # located next to Field Data Point 2600 Apr 94 Oct 94 Apr 95 Oct 95 Feb 96 45 @Tr irE ia • TONY KNOWLES GOVERNOR nsiAn DEPARTMENT OF NATURAL RESOURCES 3601 "C" STREET, SUITE 1380 ANCHORAGE, ALASKA 99503 -5948 DIVISION OF OIL AND GAS PHONE: (907) 269 -8784 J v IrD February 12, 1996 FEB 1 3 1996 Alaska € s & Gas Cons. Ccii n ssS Of3 Anchorage Alaska Oil and Gas Conservation Commission Via Fax (276 - 7542) and Mail 3001 Porcupine Drive Anchorage, Alaska 99501 -3192 Attn: David W. Johnston, Chairman Dear Mr. Johnston: Reference is made to the Alaska Oil and Gas Conservation Commission's public notice regarding the application of BP Exploration (Alaska), Inc. to waive the requirement of Rule 10, Conservation Order 329 for the Niakuk Field, Niakuk Oil Pool. The Division of Oil and Gas does not protest the application, but requests that the engineering and geological data and studies justifying the waiver be available in the Commission's record before the AOGCC rules in the application. For instance, what will be the new rate and what justification is there to support that new rate? And, how will the new areas be added to the pool and participating area and will the plan of development be amended to include the new areas and new wells? The engineering and geological studies could either be provided in writing to the Commission or through a public meeting or hearing before the Commission. Sincerely, 1 , 4/./ William Van Dyke Petroleum Manager PBU.AOGCC.NiakukRule l0.req r4 printed on rec , led oaper s, y t:,, 1. # 4 i • ARCO Alaska, Inc. " Post Office Box 100360 Anchorage, Alaska 99510 -0360 Telephone 907 2761215 Joseph A. Leone Manager Greater Pt. McIntyre Area FEB 14 1996 Alaska DJ & Gas Cons. Ccrnrnissioll February 12, 1995 Anchorage (via fax) Mr. David W. Johnston, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 -3192 RE: BPX Request to Remove the Niakuk Offtake Restriction Dear Mr. Johnston: This letter conveys comments of ARCO Alaska, Inc. regarding the request by BP Exploration (Alaska), Inc., the Operator of the Niakuk Participating Area, for an administrative waiver of the requirements of Rule 10, Conservation Order 329. This rule restricts offtake from the Niakuk Pool Rules area to a monthly average of 23 MBOPD. BPX provided ARCO an opportunity to review the draft proposal prior to submitting the request for the Commission's consideration and ARCO generally supports the request. ARCO appreciates the opportunity to comment and supports the BPX proposal. However, any consideration of reservoir management in the Niakuk field must address the fact it is comprised of more than one pool. ARCO has no ownership in the East Niakuk pool and is in no position to speak to the impact of a change in the offtake restriction on the management of East Niakuk. ARCO has few concerns with removing the rate restriction on the West Niakuk pools, which offset the ARCO /Exxon leases. With adequate voidage replacement, increased field offtake is not expected to impact ultimate recovery. ARCO, Exxon, and BPX have been holding regular meetings to discuss performance and reservoir management of the West Niakuk pools. In this forum, the companies have agreed to maintain a voidage replacement ratio of 1.0 or greater in Segment 1. Waterflood has not been initiated in Segment 3, and restraint on production in this area is appropriate pending a second well and initiation of waterflood. ARCO and Exxon anticipate this well to be spud this spring. Currently there is no protection against production below the bubble point in Segment 3. However, the companies have discussed the need to suspend production if elevated GOR's are experienced. ARCO Alaska, Inc. is a Subsidiary of AtlanticRichfieldCompany • ARCO expects that the cooperation demonstrated by these meetings will ultimately lead to a consensus development and waterflood plan for the West Niakuk pools. With positive and continuing technical dialog with BPX and Exxon, ARCO is comfortable that correlative rights and the interests of conservation in the West Niakuk pools are being protected and will not be impacted by removing the Rule 10 offtake restriction. In summary, we support the BPX request that an increase in offtake is justified. ARCO anticipates that continued cooperation between the three owners of West Niakuk will result in optimal development. ARCO has no ownership in the East Niakuk pool and therefore defers to the Commission's insight regarding this pool. Sincerely, . A. Leone cc: A. N. Bolea, BPX J. F. Branch, Exxon ARCO Alaska, Inc. Is a Subsidiary of AtlanticRichfieldCompany 43 1 • E)5(ON COMPANY, U.S.A. POST OFFICE BOX 196601 • ANCHORAGE, ALASKA 99519 -6601 • TELEPHONE (907) 561 -5331 PRODUCTION DEPARTMENT ALASKA INTEREST JAMES F. BRANCH February 12, 1996 PRODUCTION MANAGER - ALASKA David W. Johnston, Chairman Alaska Oil & Gas Conservation Commission V ED 3001 Porcupine Drive Fla 12 1996 Anchorage, Alaska 99501 -3192 Dear Chairman Johnston: Alaska Oil & Gas Cons, Commission Anchorage Exxon received the Notice of Public Hearing dated January 27, 1996, regarding the Waiver of Rule 12, Conservation Order 329 for the Niakuk Field, Niakuk Oil Pool. We assume you are seeking comments regarding BP's request to waive Rule 10. Exxon agrees with your decision to solicit public comment on the need for a hearing, rather than rely on the administrative procedure of Niakuk Pool Rule 12. While we do not believe that a hearing will be necessary, Exxon would like to comment on this proposed action as an interested party. ARCO, BPX and Exxon have been meeting regularly to address the reservoir management of Segments 1 and 3. Exxon is pleased with the cooperation to date, and expects that continued cooperation will result in the efficient development of the western Niakuk area. BP had discussed their plans to seek an increase in offtake with us and this has allowed us to assess the impact of such an action. Within this framework of cooperation, it does not appear that conservation and correlative rights will be adversely impacted by increasing the offtake in the western Niakuk area. Exxon has no ownership or detailed understanding of the eastern Niakuk area and we are not in a position to offer an opinion on what impact higher offtakes might have in that area. At this stage of field development and with our current limited understanding of the eastern Niakuk area, we are unable to comment on a technically appropriate rate limit or the advisability of entirely waiving Rule 10. However, at this time, in order to provide BPX the necessary near -term operating flexibility, Exxon will support amending Rule 10 to an offtake rate mutually agreeable to BPX and the AOGCC. Exxon also supports the setting of this rate administratively and as such do not believe a hearing is necessary. With continued field development and evaluation of the entire Niakuk area, Exxon should be in a better position to comment on future changes to Rule 10 that are deemed appropriate. Sincerely, --� JFB:jpc /998b -� � �_� c: Mr. A. N. Bolea - BPX Mr. J. A. Leone - ARCO A DIVISION OF EXXON CORPORATION � RECYCLED FEB 12 ' 96 01 46P P 1 ltr ARCO ALASKA, INC. 700 "G' ST. ANCHORAGE. AK 99501 GREATER POINT McINTYRE AREA FACSIMILE TRANSMISSION Fax Nuu►ber (907) 263 -4894 Verify (907) 263 -4948 (Ashley) DATE: c- `' NUMBER OF PAGES: C + --. TO COMPANY: , LOCATION: FROM: .■ PHONE 0: i.-(13—(-114-31 F - _ 4 5 irt'‘ • t'N � r PP S , x i a � 3 o a' 1 TONY KNOWLES, GOVERNOR ALASKA OIL AND GAS 3001 PORCUPINE DRIVE b CONSERVATION COMMISSION : ANCHORAGE, ALASKA 99501 -3192 r PHONE: (907) 279 -1433 FAX: (907) 276 -7542 February 7, 1996 To: Public hearing notice Recipients: Re: Notice published January 27, 1996 (Attached) The attached notice for public hearing incorrectly stated the applicant requested a waiver to Rule 12 of Conservation Order No. 329. The notice should have stated Rule 10 of Conservation Order No. 329. The subject, dates, times and terms of the notice remains the same. We hope this has not caused any inconvenience to recipients. Sincerely, 11111 _ David W. •hnston Chairman • NOTICE OF PUBLIC HEARING STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Re: The application of BP Exploration (Alaska), Inc., to waive the requirement of Rule 12, Conservation Order 329 for the Niakuk Field, Niakuk Oil Pool. BP Exploration (BPX) by letter dated January 23. 1996, has requested a waiver of the requirement of Rule 12, Conservation Order 329, which limits the Niakuk Oil Pool offtake rate to 23 MB /D of oil averaged monthly. Waiver of Rule 12 would allow BPX to produce the Niakuk Oil Pool at monthly average offtake rates greater than 23 MB /D based on waterflood response, better than expected productivity and potential for expanded pool development. A person who may be harmed if the requested order is issued may file a written protest prior to 4:00 PM February 12, 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 February 26, 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 February 12, 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 February 20, 1996. David W. J: nston, ••mmissioner Alaska Oil an. , -s C9nservation Commission Published January 27, 1996 A0- 02614029 #7724 STOF 0330 AO- 02614029 AFFIDAVIT F PUBLICATION $68.25 STATE OF ALASKA, ) Notice of Public Hearing [� THIRD JUDICIAL DISTRICT. ) STATE OF ALASKA �y 0 a *� I I I Oil and Gas ! //- Tamara R. McIntosh Conservation Commission i The application n bf- B.P. being first duly sworn on oath waive the te of to requirement of Rule deposes and says that he /she is t Conservation Order 329 for the Niakuk Field, Niakuk Oil an advertising representative of P ° ° '' B.P. Exploration (BPX) by the Anchorage Daily News, a letter dated January 23, 1996 has requested a waiver of the daily newspaper. That said requirement of Rule 12, Conser- vation Order 329, which limits newspaper has been approved , the Niakuk Oil Pool offtoke rate the Third to 23 MB /D of oil averaged by Judicial Court, monthly. Anchorage, Alaska, and it now Waiver of Rule 12 would allow BPX to produce the Niakuk Oil Pool at monthly average offtoke and has been published in the rates greater than 23 MB /D English language continually as a based on waterflood response, better than expected productivi- daily newspaper in Anchorage, ty and potential for expanded Alaska, and it is now and during pool development. A person who may be harmed all said time was printed In an if the requested order is issued may file a written protest prior Office maintained at the aforesaid to 4:00 PM February 12, 1996 with the Alaska Oil and Gas place of publication of said Conservation Commission, 3001 Porcupine Drive; Anchorage, newspaper. That the annexed is Alaska 99501, and request a hearing on the matter. If the a copy of an advertisement as it protest is timely filed and was published in regular issues raises a substantial and materi- al issue crucial to the Commis (and not in supplemental form) of sion's determination, a hearing on the matter will be held at the said newspaper on above address at 9:00 am on. February 26, 1996 in confor- mance with 20 AAC 25.540. If a 1/27, 1996 hearing is to be held, interested parties may confirm this by calling the Commission's office, 19071 279 -1433 after February 12, 1996. If not protest is filed, the Commission will consider thei issuance of the order without a hearing. If you are a person with a disability who may need a spe- cial modification in order to comment or - attend the public hearing, please contact Diana Fleck at 279 -1433 no. later than February 20, 1996. and that such newspaper was /s /David W. Johnson, Commissioner Alaska Oil and regularly distributed to its Gas Conservation commission subscribers during all of said Pub: January 27, 1996 period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged • iv °t: individual / n ,. . „ si . - jilt, gh IMP Subscribe• and sworn to before me this C day o 1 ; 1 ` .. „ Notary Public in and for _ . PU u`°O" .. -- the State of Alaska. : Third Division. °a ' 1 Anchorage, Alaska � ,i1 � � OF I' 0 6 ■ ' MY C. ISSION EXPIRES JJ J) 0 7 Expire. J ii1 1111J3j 1 � ,f 19.9 . *1 i ! COMM B p BP EXPLORATION BP Exploration (Alaska) Inc. COMM 'Of f [" 900 East Benson Boulevard COMM P.O. Box 196612 �■ Anchorage, Alaska 99519 -6612 RES ENG >5I (907) 561 -5111 SR ENG ria b! ., wr 4 NRO ti 2 SR GEOL „ . GEOL ASST January 23, 1996 STATT H Mr. David Johnston Chairman, Alaska Oil and Gas Conservation Commission u. 3001 Porcupine Drive 111111111111111 Anchorage, Alaska, 99501 -3192 Flt, Subject: Request for Revision to Conservation Order 329, Niakuk Oil Pool Dear Mr. Johnston, BP Exploration (Alaska), Inc.( "BPX "), Operator of the Niakuk Oil Pool, hereby requests that the Alaska Oil and Gas Conservation Commission administratively waive the requirements of Rule 10, Conservation Order No. 329 pursuant to Rule 12 of the Order. Rule 10 states: "The offtake rate for the Niakuk oil pool shall not exceed 23 MB /D of oil averaged monthly ". Rule 12 provides that the Commission may waive the requirements of any rule within or amend the Order " ... as long as the change does not promote waste, jeopardize correlative rights or compromise ultimate recovery". BPX's reasons for requesting a waiver to this rule are summarized below: 1) Waterflood Response Waterflood was initiated on April 14, 1995 and approximately 50 MB /D of water is currently being injected into the Niakuk Pool. This amounts to an overall voidage replacement ratio of 1.4. Positive response has been seen in all Segments where waterflood has been initiated: Segment 1 producers have responded to water injection from Niakuk 10, as shown by favorable GOR response and reservoir pressure measurements. Reservoir management plans are to maintain the injection at a voidage replacement ratio of 1 or greater to maximize recovery from this Segment. Injection rates into Niakuk 10 are sufficient to maintain reservoir pressure with an oil offtake of 14 MB /D from Niakuk 7, 8, 12a and ARCO /Exxon well Niakuk 27 (note that Niakuk 27 is not within the current pool boundaries; offtake from Segment 1 within the Pool as currently defined is approximately 11 MB /D). r • • In Segment 2, Niakuk 20, 21, 22 and 42 have all responded to water injection in Niakuk 16, 23 and 38. Gas oil ratios, flowing wellhead pressure and reservoir pressure measurements obtained since waterflood startup have been favorable. Niakuk 18 also appears to be benefiting from this injection. Based on reservoir performance to date, it is currently expected that oil offtake can be maintained at rates up to 20 M /BD (note that at these rates two wells are limited by test separator capacity - future debottlenecking may permit higher offtake rates from this segment). Future offtake in this segment will be adjusted as field performance and well results dictate. Initial production results from Niakuk 9 have been encouraging. This is the only well in Segment 3 to date and pressure support has not been initiated. An offset well is planned in Segment 3 later this year when a rig capable of drilling high departure wells becomes available, at which time pressure maintenance will be initiated. Niakuk 9 is capable of production in excess of 6 MB /D, current plans are to produce the well at 3 MB /D. To the best of our knowledge, Niakuk 19 is in pressure isolation from Segments 1 and 2. Reservoir pressure declined rapidly in this area indicating little or no potential for an offset well or a pressure maintenance program. Near term plans are to cycle the well and gather further production /pressure data to increase our understanding of the area. 2) Expanded Development Area Due to positive initial drilling results, the development area within the Pool is presently estimated to be larger than that anticipated at the time of application for Pool Rules. In particular, three wells which were not within the scope originally envisioned at the time of pool rule application (Niakuk 9, 19 and 38) have been drilled in peripheral areas of the Pool. Results to date indicate there may be further potential for several additional wells within the current Pool boundary. 3) Operational Flexibility With the existing well capacity, the monthly limit set forth in Rule 10 may cause unnecessary operational practices, such as shutting wells in at the end of the month or modifying reservoir management strategy to stay within the monthly average limit for the Pool. ♦, • • • BPX believes that it is prudent to produce wells within the Niakuk Oil Pool at rates which exceed the 23 MB /D monthly average for the pool. BPX further believes that waiving the requirements of Rule 10 will not promote waste, jeopardize correlative rights or compromise ultimate recovery and is based on sound engineering principles. Current production rates are approximately 26 MBD within the Pool with plans to increase to approximately 29 MB /D in the near future. While we do not anticipate that this will result in January's average production exceeding the maximum monthly oil rate set out in Rule 10, it is anticipated that we will exceed this monthly average in February. Please call Bob Janes at 564 -4623 or myself at 564 -5433 if you have any questions or comments regarding the above. We w uId also be willing to meet informally with the Commission to discuss this request in more detail if you desire. We appreciate your prompt attention to this matter. Sincerely, cy j A. N. Bolea Asset Manager Greater Point McIntyre Area cc: M. R. Davis J. H. Dickey File: 23.00 R. W. Janes Joe Leone (ARCO Alaska, Inc.) Jim Branch (Exxon, USA) I I k r, ..,V F .3'..� .au S AN 116