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Home My WebLink AboutCO 505 BCONSERVATION ORDER 505B Prudhoe Bay Field Schrader Bluff Oil Pool 1. June 30, 2009 BPXA’s Application for Amendments (pages 21-49, 51-63 held in secure storage) 2. October 20, 2009 Notice of Public Hearing, Affidavit of Publication, email distribution, mailing list 3. October 21, 2009 Email regarding questions about Orion Application 4. November 2, 2015 Request for admin approval for waiver of monthly reporting of daily production allocation data (CO 505B.001) 5. October 23, 2018 Request for admin approval for conforming PBU Satellite Pool Rules for Consistency (CO 505B.002) 6. February 24, 2020 BPXA Request to amend CO 492 rule 3(a) and 6(a) (co505B.003) 7. May 21, 2020 Notice of Hearing and mailing 8. ----------------- Emails 9. June 24, 2021 Request for administrative approval to amend CO 505B and repeal Rule 1 according to well spacing restrictions (CO 505B.004) • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF BPXA ) Docket Number: CO-09-23 EXPLORATION (ALASKA) INC. ) Conservation Order No. SOSB for an order to expand the affected ) area of the Orion Oil Pool, Prudhoe ) Prudhoe Bay Field Bay Field, North Slope, Alaska. ) Schrader Bluff Oil Pool May 4, 2010 NOTICE CLOSING DOCKET BY THE COMMISSION: The Commission has the closed the Docket in the above captioned matter. ENTERED AND EFFECTIVE at Anchorage, Alaska and this 4th day of May, 2010. BY DIRECTION OF THE COMMISSION V Jody J. Co ombie Spe i Assistant to the Commission • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF BPXA ) EXPLORATION (ALASKA) INC. ) for an order to expand the affected ) area of the Orion Oil Pool, Prudhoe ) Bay Field, North Slope, Alaska. ) Docket Number: CO-09-23 Conservation Order No. SOSB Prudhoe Bay Field Schrader Bluff Oil Pool May 4, 2010 IT APPEARING THAT: 1. On June 30, 2009, BP Exploration (Alaska), Inc. (BPXA) requested the Alaska Oil and Gas Conservation (Commission) grant an expansion of the Prudhoe Bay Field, Schrader Bluff Oil Pool as currently defined in Conservation Order SOSA. 2. Pursuant to 20 AAC 25.540, on October 22, 2009 the Commission published in the Anchorage Daily News notice of the opportunity for a public hearing on December 1, 2009. 3. No protest to the application or request for hearing was received. 4. Because BPXA provided sufficient information upon which to make an informed decision, the request can be resolved without a hearing. 5. The hearing was vacated on November 18, 2009. FINDINGS 1. CO 505 issued January 5, 2004 defined the Schrader Bluff Oil Pool and set out rules governing development and operations within a specified area. 2 CO SOSA issued April 28, 2006 superseded CO 505 and authorized underground injection of enriched hydrocarbon gas in the OOP. 3 This amendment action should properly apply to CO SOSA. 4 BPXA proposes to expand the operation and development of the pool beyond the area specified in CO SOSA. 5 Subsurface wireline log data, pressure measurements, and newly reprocessed seismic data all indicate that the Schrader Bluff Oil Pool extends beyond the area specified in CO SOSA. 6 No testimony was presented that warrants a change in the governing rules set out in CO SOSA. Conservation Order SOSB• May 4, 2010 CONCLUSIONS: Page 2 1. Conservation Order No. SOSB supersedes and replaces CO 505 dated January 5, 2004, and CO SOSA, dated April 28, 2006 only insofar as CO SOSB concerns the Schrader Bluff Oil Pool. Conservation Order No. SOSB has no effect on CO 505 and CO SOSA as to any other pools. 2. The area subject to pool rules governing the development and operation of the Schrader Bluff Oil Pool should be expanded to encompass the additional area proposed for development. 3. All prior rules and approvals issued by the Commission for Schrader Bluff Oil Pool operation and development should be consolidated into this conservation order. NOW, THEREFORE, IT IS ORDERED: This Conservation Order supersedes and replaces CO SOSA dated April 28, 2006. The findings, conclusions and administrative record for Conservation Order SOSA are adopted by reference and incorporated in this decision. The following rules, in addition to the statewide requirements under 20 AAC 25 as set forth below, apply to the Schrader Bluff Oil Pool within the following affected area: Umiat Meridian Township Range, UM Lease Sections T12N-R10E ADL 025637 13 and 24 N/2 T12N-R11E ADL390067 14: S/2 S/2, 23: ALL, 24: SW/4, SW/4, NW/4 (expansion area this order) ADL 047446 17, 18, 19, and 20 ADL 047447 16 S/2 and NW/4 and S/2 NE/4, 21, and 22 ADL 028238 25 SW/4, 26, 35, and 36 ADL 028239 27, 28, 33 E/2 and N/2 NW/4, and 34 ADL 047449 29 N/2 and SE/4, and 30 N/2 NE/4 T11N-R11E ADL 028240 1, 2, 11 E/2 and E/2 NW/4, and 12 ADL 028241 3 N/2 and N/2 S/2, and 4 NE/4 N/2 SE/4 ADL 028245 13 N/2 and SE/4, 14 E/2 NE/4, and 24 E/2 Conservation Order 505 May 4, 2010 Page 3 NE/4 T11N-R12E ADL 047450 7, and 8 S/2 and NW/4 Rule 1: Well Spacing (Source CO 505) Spacing units shall be a minimum of 10 acres. The Schrader Bluff Oil Pool shall not be opened in any well closer than 500' to an external boundary where ownership changes. Rule 2: Casing and Cementing Practices (Source CO 505) a. In addition to the requirements of 20 AAC 25.030, conductor casing must be set at least 75' below surface. b. In addition to the requirements of 20 AAC 25.030, surface casing must be set at least 500' TVD below the base of permafrost. Rule 3: Automatic Shut-in Equipment (Source CO 505) a. All wells must be equipped with afail-safe automatic surface safety valve system capable of preventing an uncontrolled flow. b. All wells must be equipped with landing nipple at a depth below permafrost, which is suitable for the future installation of a downhole flow control device. The Commission may require such installation by administrative action. c. Operation and performance tests must be conducted at intervals and times as prescribed by the Commission to confirm that the safety valve systems are in proper working condition. Rule 4: Common Production Facilities and Surface Commingling (Source CO 505) a. Production from the Schrader Bluff Oil Pool may be commingled with production from Prudhoe Bay Oil Pool, and other oil pools located in the Prudhoe Bay Unit in surface facilities prior to custody transfer. b. The Prudhoe Bay Unit Western Operating Metering Plan, described by letter from BPXA dated April 23, 2002 and detailed within the PBU Western Satellite Production Metering Plan -Policies and Procedures Document" dated August 1, 2002 is approved for allocation of production from Schrader Bluff Oil Pool wells . c. All Schrader Bluff Oil Pool wells must use the Gathering Center 2 well allocation factor for oil, gas, and water. d. All wells must be tested a minimum of once per month. All new wells must be tested a minimum of two times per month during the first three months of production. The Commission may require more frequent or longer tests if the allocation quality deteriorates. e. Technical process review meetings shall be held at least annually. f. The operator shall submit a monthly report and file(s) containing daily allocation data and daily test data for agency surveillance and evaluation. Conservation Order 505 May 4, 2010 Page 4 Rule 5: Reservoir Pressure Monitoring (Source CO 505) a. Prior to regular production or injection, an initial pressure survey must be taken in each well. b. A minimum of one bottom-hole pressure survey per producing governmental section shall be run annually. The surveys in part (a) of this rule may be used to fulfill the minimum requirements. c. The reservoir pressure datum will be 4400' TVDss. d. Pressure surveys may be stabilized static pressure measurements at bottom-hole or extrapolated from surface (single phase fluid conditions), pressure fall-off, pressure buildup, multi-rate tests, drill stem tests, and open-hole formation tests. e. Data and results from pressure surveys shall be submitted with the annual reservoir surveillance report. All data necessary for analysis of each survey need not be submitted with the report but must be available to the Commission upon request. £ Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (e) of this rule. Rule 6: Gas-Oil Ratio Exemption (Source CO 505) Wells producing from the Schrader Bluff Oil Pool are exempt from the gas-oil-ratio limits of 20 AAC 25.240 (a) so long as requirements of 20 AAC 25.240 (b) are met. Rule 7: Enhanced Oil Recovery or Reservoir Pressure Maintenance Operations (Source CO SOSA) Waterflood is required and enriched gas injection is approved for purposes of pressure maintenance and enhanced oil recovery in the Schrader Bluff Oil Pool,. Production and injection operations must ensure the average reservoir pressure is maintained above the bubble point. Rule 8: Multiple Completion of Infection Wells (Source CO 505.001) a. Injectors may be completed to allow for simultaneous injection in multiple pools within the same wellbore so long as mechanical isolation between pools is demonstrated and approved by the Commission. b. Prior to initiation of co-mingled injection, the Commission must approve methods for allocation of injection to separate pools. c. Results of logs or surveys used for determining the allocation of water injection between pools, if applicable, must be supplied in the annual reservoir surveillance report. d. An approved injection order is required prior to commencement of injection in each pool. Conservation Order 505 May 4, 2010 Page 5 Rule 9: Annual Reservoir Review (Source CO SOSA) An annual report must be filed by September 15 of each year. The report must include future development plans, reservoir depletion plans, and surveillance information for the period July 1 of the prior calendar year through June 30 of the current calendar year (except the report due on September 15, 2006 must cover the period from January 2005 through June 30, 2006), and must include: a. voidage balance by month of produced and injected fluids, and cumulative status; b. reservoir pressure map at datum, summary and analysis of reservoir pressure surveys within the pool; c. results and, where appropriate, analysis of production and injection surveys, tracer surveys, observation well surveys, and any other special monitoring; d. review of pool production allocation factors and issues over the prior year; e. progress of enhanced recovery project implementation and reservoir management summary including results of reservoir simulation studies; f. progress of plans and tests to expand the productive limits of the pool, including any work within the Prince Creek formation; and g. results of monitoring to determine enriched gas injectant breakthrough to offset producers. The Operator shall schedule and conduct a yearly technical review meeting, on or about November 1, with the Commission to discuss the report contents and to review items that may require Commission action during the coming year. The Commission may conduct audits of technical data and analyses used in support of surveillance conclusions and reservoir depletion plans. Rule 10: Waiver of "Application for Sundry Approvals" Requirement for Workover Operations (Source CO 556) a. Except as provided in (d) and (e) of this rule, the requirement to submit an Application for Sundry Approvals (Form 10-403) and supporting documentation for workover activities described in 20 AAC 25.280 (a) (1), (2), (3) and (5) is waived or modified for development wells as provided in the Commission document entitled "Well Work Operations and Sundry Notice/Reporting Requirements for Pools Subject to Sundry Waiver Rules," dated July 15, 2005 (referred to below as "Sundry Matrix"). This waiver and modification does not affect the Operator's responsibility to submit a Report of Sundry Well Operations (Form 10-404) within 30 days following the completion of a workover operation. b. Except as provided in (d) and (e) of this rule, the requirement to submit an Application for Sundry Approvals (Form 10-403) and supporting documentation for workover activities described in 20 AAC 25.280 (a) (1) and (5) is modified for service wells as provided in the Sundry Matrix. This modification does not affect the Operator's responsibility to submit a Report of Sundry Well Operations (Form 10-404) within 30 days following the completion of a workover operation. c. The Sundry Matrix summarizes the sundry approval and reporting requirements that apply to various categories of operations in the specific well types under Conservation Order 505 May 4, 2010 Page 6 Commission regulations as modified by these rules. d. The waivers provided under (a) of this rule do not apply to wells that are required to be reported to the Commission under the provisions of Rule 11. e. The Commission reserves the discretion to require an operator to submit an Application for Sundry Approvals for a particular well or for a particular operation on any well. f. Each week the Operator shall provide the Commission with a report of workover operations performed the previous week that did not require submission of a Form 10-403. (These operations are listed in Column 2 of the Sundry Matrix.) The report must include the date, well, permit to drill number, nominal operation completed, and a brief description of that operation including depths of perforations, reperforations, and stimulated zones. g. Nothing in this rule precludes an Operator from filing an Application for Sundry Approvals (Form 10-403) in advance of any well work or from including Sundry authorized operations (listed in column 3 of the Sundry Matrix) in the weekly report required by (f) of this rule. h. Unless notice and public hearing are otherwise required, the Commission may administratively waive the requirements of any provision of this. rule or administratively amend any provision including the Sundry Matrix, 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. Rule 11: Annular Pressures (Sources CO 505, CO 492) a. At the time of installation or replacement the Operator shall conduct and document a pressure test of tubulars and completion equipment in each development 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 development 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 (a) sustained inner annulus pressure that exceeds 2500 psig for wells processed through the Lisburne Processing Center and 2000 psig for all other development wells, or (b) 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 development well having sustained pressure that exceeds a limit set out in paragraph 3 of this rule. The Commission may approve the Operator's proposal or may require other corrective action or surveillance. The Commission may require that corrective action be verified by mechanical integrity testing or other Commission approved diagnostic tests. The Operator Conservation Order 505 May 4, 2010 Page 7 shall give the Commission sufficient notice 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 development 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 Commission may approve the Operator's proposal or may require other corrective action. The Commission may also require that corrective action be verified by mechanical integrity testing or other Commission approved diagnostic tests. The Operator shall give the Commission sufficient notice of the testing schedule to allow Commission to witness the tests. £ Except as otherwise approved by the Commission under (d) or (e) of this rule, before ashut-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 psig, 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, "inner annulus" means the space in a well between tubing and production casing; "outer annulus" means the space in a well between production casing and surface casing; and "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. Rule 12: Use of Multiphase Flowmeters in Well Testing (Sources CO 547.004 and 547.005 For purposes of satisfying well test measurement requirements of 20 AAC 25.230, the use of the Weatherford Generation 2.0 Multiphase Metering System and FMC Technologies multiphase Flow Meter System (EMS MPM) is approved in accordance with the respective administrative approvals. Conservation Order 505 May 4, 2010 Page 8 Rule 13: Administrative Action Unless notice and public hearing are otherwise required, the Commission may administratively waive the requirements of any rule stated above or administratively amend any rule 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. DONE at Anchorage, Alaska and dates May 4, 2010. Daniel T. ~amoµnt, Jr. Cola`1'missioner, Chair ®rhtska 1 and s Conservation Commission ~f issioner Oil and Gas ration Commission ,~. s.i Cathy P Foerster, Commissioner Alaska Oil and Gas Conservation Commission 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 aze 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), "[t]he 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. • Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, May 04, 2010 2:27 PM To: Aubert, Winton G (DOA); Ballantine, Tab A (LAW); Brooks, Phoebe; Davies, Stephen F (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Johnson, Elaine M (DOA); Laasch, Linda K (DOA); Mahnken, Christine R (DOA); Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Aaron Gluzman; Bettis, Patricia K (DNR); caunderwood@marathonoil.com; Dale Hoffman; Frederic Grenier; Gary Orr; Jerome Eggemeyer; Joe Longo; Lamont Frazer; Marc Kuck; Mary Aschoff; Maurizio Grandi; Ostrovsky, Larry Z (DNR); Richard Garrard; Sandra Lemke; Scott Nash; Talib Syed; Tiffany Stebbins; Wayne Wooster; Willem Vollenbrock; William Van Dyke; Woolf, Wendy C (DNR); (foms2@mtaonline.net); (michael.j.nelson@conocophillips.com); (Von.L.Hutchins@conocophillips.com); Alan Dennis; alaska@petrocalc.com; Anna Raff; Barbara F Fullmer; bbritch; Becky Bohrer; Bill Walker; Bowen Roberts; Brad McKim; Brady, Jerry L; Brandon Gagnon; Brandow, Cande (ASRC Energy Services); Brian Gillespie; Brian Havelock; Bruce Webb; carol smyth; Charles O'Donnell; Chris Gay; Cliff Posey; Crandall, Krissell; Dan Bross; dapa; Daryl J. Kleppin; David Boelens; David House; David Steingreaber; ddonkel@cfl.rr.com; Deborah J. Jones; doug_schultze; Elowe, Kristin; Evan Harness; eyancy; Francis S. Sommer; Fred Steece; Garland Robinson; Gary Laughlin; Gary Rogers; Gary Schultz; ghammons; Gordon Pospisil; Gorney, David L.; Gregg Nady; gspfoff; Harry Engel; Jdarlington (jarlington@gmail.com); Jeff Jones; Jeffery B. Jones (jeff.jones@alaska.gov); Jerry McCutcheon; Jim White; Jim Winegarner; Joe Nicks; John Garing; John S. Haworth; John Spain; John Tower; John W Katz; Jon Goltz; Joseph Darrigo; Judy Stanek; Julie Houle; Kari Moriarty; Kaynell Zeman; Keith Wiles; 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; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; nelson; Nick W. Glover; NSK Problem Well Supv; Patty Alfaro; Paul Decker (paul.decker@alaska.gov); PORHOLA, STAN T; Rader, Matthew W (DNR); Raj Nanvaan; Randall Kanady; Randy L. Skillern; rob.g.dragnich@exxonmobil.com; Robert A. Province (raprovince@marathonoil.com); Robert Campbell; Roberts, Susan M.; Rudy Brueggeman; Scott Cranswick; Scott, David (LAA); Shannon Donnelly; Sharmaine Copeland; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Sondra Stewman; Steve Lambert; Steve Moothart; Steven R. Rossberg; Suzanne Gibson; tablerk; Tamera Sheffield; Taylor, Cammy O (DNR); Temple Davidson; Teresa Imm; Terrie Hubble; Thor Cutler; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjr1; Walter Featherly; Williamson, Mary J (DNR); Winslow, Paul M Subject: co505b PBU, Schrader Bluff Oil Pool Attachments: co505b.pdf; ~~ Jody J. Colombie Special ~~Issistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 (907)793-1221 (phone) (907)276-7542 (fax) Mary Jones David McCaleb George Vaught, Jr. XTO Energy, Inc. IHS Energy Group PO Box 13557 Cartography GEPS Denver, CO 80201-3557 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 Ft. Worth, TX 76102-6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton 408 18th Street President 6900 Arctic Blvd. Golden, CO 80401-2433 PO Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Schlumberger Ciri Baker Oil Tools Drilling and Measurements Land Department 4730 Business Park Blvd., #44 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99503 Anchorage, AK 99503 Anchorage, AK 99503 Ivan Gillian Jill Schneider Gordon Severson 9649 Musket Bell Cr.#5 US Geological Survey 3201 Westmar Cr. Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508-4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs PO Box 190083 PO Box 39309 PO 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 PO Box 2139 Soldotna, AK 99669-7714 Fairbanks, AK 99701 Soldotna. AK 99669-2139 Richard Wagner Bernie Karl North Slope Borough PO Box 60868 K&K Recycling Inc. PO Box 69 Fairbanks, AK 99706 PO Box 58055 Barrow, AK 99723 Fairbanks, AK 99711 • • 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, 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. DONE at Anchorage, Alaska, and dated aii ..- ary 11, 2011 Adioi Daniel T. Se. .. ou , r., Commissioner, Chair • • v. • it . • :. s Conservation Commission .� {� s .� r man, Co der et iti4,. a0i 4. a Conserva ion Commission r :4e. ,y•" Cat y P. oerst r, Commissioner ri " `''' 1 Alaska 11 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), "[t]he 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)'; 'AKDCWellIntegrityCoordinator'; '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'; 'ddonkei @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'; 'Mikel 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 Lambert'; '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'; 'trmjrt; '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) (Iinda.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); g ), Norman , John K (DOA) (john.norman @alaska.gov); Okland, Howard D (DOA) (howard.okland @alaska.gov); Paladijczuk, Tracie L (DOA) ( tracie.paladijczuk @ alaska.gov); Pasqual, 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 Sawwwthav FOrhor Ala4-kw cwtd.Ga'Co e,- vatwivC (907)793 -1223 (907)276 -7542 (fa/0 1 • Mary Jones 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. 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. Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 Jill Schneider North Slope Borough 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 Conservation New Regulation Provisions Unit/Field Pool Order (1) Rule Rescind Rule? Existing Order Requirement Addressing Regts from Order Revised Rule - "Well safety valve systems" (2) Comment 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); 25.265(b); 25.265(d)(2)(H); Check valve requirements for injectors are not covered by Colville River Unit Qannik 605 5 no (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. A subsurface- controlled injection valve or readopted regulation valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(a); 25.2659(b); 25.265(d)(1); "Injection wells (excludin disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Oooguruk Oooguruk - Nuiqsut 597 6 no (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. A subsurface - controlled injection valve or readopted regulation valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(a); a ) ; 25.265(b); b ) ; 25.265 ( d )( ) 1 ; "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements / uirements for injectors are not covered b y 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 g g p 25.265(h)(5) readopted regulation valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve." 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 Prudhoe Bay Unit Raven 570 5 yes N/ deactivated SVS was replaced with requirement to maintain a deactivated SVS; sign on wellhead 25.265(m) tag on well when not manned fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(a); "I njection we ll s (exc l u ding disposal injectors) must be equipped with(i) a double check valve a(a); 25 25 Check valve requirements for injectors are not covered by 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 injection valve or 25.265(h)(5) readopted regulation v alve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(a); 25.265(b); 25.265(d)(2)(H); "I wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by 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 readopted regulation 25.265(h)(5) valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check v alve. 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 25.265(a); 25.265(b); 25.265(d)(2)(H); Check valve requirements for injectors are not covered by Colville River Unit Nanuq 562 6 no (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. A subsurface - controlled injection valve or readopted regulation valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve." Prudhoe Ba Unit Put River 559 3 es 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; Y y prescribed by Commission 25.265(h)(5) replaces SSSV nipple requirement for all wells Deep Creek Unit Happy Valley 553 3 yes SSV or SSSV 25.265(a) N/A Prudhoe Ba 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); N/A Readopted 25.265(d) dictates which wells require SSSV; Y Y prescribed by Commission 25.265(h)(5) replaces SSSV nipple requirement for all wells Prudhoe Ba 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; Y prescribed by Commission 25.265(h)(5) replaces SSSV nipple requirement for all wells fail -safe auto SSV; SSSV landing nipple below permafrost; gas /MI Milne Point - 25.265(a); 25.265(b); 25.265(d); Readopted 25.265(d) dictates which wells require SSSV; Milne Point Unit Schrader Bluff 477 5 yes injection well require SSSV or injection valve below permafrost; test 25.265(h)(5) N/A replaces SSSV nipple requirement for all wells every 6 months Prudhoe Ba Unit Borealis 471 3 es fail -safe auto SSV; SSSV landing nipple below permafrost; gas /MI 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Y Y injection well require SSSV below permafrost; test every 6 months 25.265(h)(5) replaces SSSV nipple requirement for all wells fail -safe auto SSV and SCSSV; test as prescribed by Commission; 500• Existing pool rule established a minimum setting depth for the Northstar Northstar 458A 4 no ft minimum setting depth for SSSV 25.265(a); 25.265(b); 25 The minimum setting depth for a tubing conveyed subsurface safety valve is 500 feet." SSSV Prudhoe Ba Unit Aurora 457B 3 es 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(d) dictates which wells require SSSV; Y Y 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(x); 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(d)(5) does not include check valve, or (ii) single check valve and SSV; test every 6 months 25 SCSSV satisfies the requirements of a single check valve" SSSV requirement for MI injectors Prudhoe Ba Unit Midnight Sun 452 6 yes fail -safe auto SSV (all injectors and producers capable of unassisted 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Y 9 Y flow to surface); test every 6 months 25.265(h)(5) replaces SSSV nipple requirement for all wells fait -safe auto SSV and SCSSV; SSSV may be installed above or below 25.26.� ,- (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 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 q single ( Check valve requirements for injectors are not covered by Colville River Unit Alpine 443B 5 no injection wells require i O { double check valve, or (ii) sin le check valve 25.265 a ) ; 25.265(b); b ) ; 25.265 ( d )( 2 )( H ) arrangement (ii) ement or ii a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation and SSV SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV; gas /MI injectors require SSV and single check 25.265(x); 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 SCSSV satisfies the requirements of a single check valve." SSSV requirement for MI 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 deactivated; maintain list of wells w /deactivated SVS; test as deactivated SVS was replaced with requirement to maintain a Kuparuk River Unit; 25.265(a); 25.265(b); 25.265(h)(5); 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 25 m Milne Point Unit may be defeated on W. Sak injectors w /surface pressure <500psi w/ 25.265(m) 432D.009 remains effective [re: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 Conservation New Regulation Provisions Revised Rule - "Well safety valves stems" (2) Comment Unit/Field Pool Order (1) Rule Rescind Rule? Existing Order Requirement Addressing Reqts from Order y systems" ) fail -safe auto SSV; gas /MI injectors require SSV and single check "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by 25.265(a); 25.265(b); 25.265(d); arrangement or (ii) le check valve and a SSV. A subsurface - controlled injection readopted regulation; d ection valve or reado ulation; readopted ted 25.265 Kuparuk River Unit Tarn 430A 6 no valve and SSSV landing nipple; water injection wells require (i) double 25.265(h)(5) arran 9 () a single p 9 p 25.265(d)(5) ) does not include check valve, or (ii) single check valve and SSV; test every 6 months SCSSV satisfies the requirements of a single check valve" SSSV requirement for MI injectors Milne Point - Sag 423 7 no fad-safe auto SSV; injection wells require double check valve; test j equipped pp 9 Check valve requirements for injectors are not covered by Milne Point Unit every 6 months 25.265(a); a ) ; 25.265 ( b ) 25.265(h)(5) h )( 5 ) "Injection wells must bee ui ed with a double check valve arran ement." readopted regulation River fail -safe auto SSV; gas /MI injectors require SSV and single check valve and SSSV landing nipple; water injection wells require (i) double "Injection wells (excluding disposal injectors) must be equipped with() a double check valve Check valve requirements for injectors are not covered by 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) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation; readopted 25.265(d)(5) does not include Kuparuk River Unit Kuparuk - West Sak 406B 6 no SSSV requirement for MI injectors; administrative approval CO CO 406B.001 modifies Rule 6(e) - LPP may be defeated on W. Sak 25.265 h 5 S CSSV satisfies the requirements of a single check valve. The Low Pressure Pilot may be injectors w /surface pressure <500psi w/ notice when defeated and 25.265(h)(5) )( ) defeated on West Sak water injectors with surface injection pressure less than 500psi." 4068.001 remains effective [re:defeating the LPS when surface j p p injection pressure for West Sak water injector is <500psi] placed back in service fail -safe auto SSV and SCSSV; LPS trip pressure; readily accessible Badami Badami 402B 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 wells w /deactivated SVS; test as 25.265(m) N/A deactivated SVS was replaced with requirement to maintain a prescribed by Commission tag on well when not manned fail -safe auto SSV (S /D well and artificial lift); if SSSV installed it must be maintained and tested as part of SVS; sign on wet if SVS 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wets require SSSV; Prudhoe Bay Unit Prudhoe 341E 5 yes deactivated; maintain list of wells w /deactivated SVS; test as 25.265(h)(5) replaces SSSV nipple requirement for all wells 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 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; Prudhoe Bay Unit Pt. McIntyre 317B 8 yes routine well ops w/o notice 25.265(j); 25.265(m) _ replaces SSSV nipple requirement for all wells 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; Prudhoe Bay Unit West Beach 311B 6 yes 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 A &B) fail -safe auto SSV; sign on well ff 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 N/A deactivated SVS was replaced with requirement to maintain a Prudhoe Bay Unit Lisburne 207A 7 yes w /deactivated SVS; test as prescribed by Commission 25.265(m) tag on well when not manned suitable automatic safety valve installed below base of permafrost to d N/A Readopted 25.265(d) dictates which wells require SSSV; 25.2fi5 Prudhoe Bay Unit Prudhoe - Kuparuk 98A 5 yes prevent uncontrolled flow 25.265(d) ) replaces SSSV nipple requirement for all wells AOGCC Policy - SVS Failures; issued by order of the Commission policy dictating SVS performance testing 25.265(h); h ) ; 25.265(n); n ) ; 25.265 ( 0 ) N/A Commission 3/30/1994 (signed by Commission Chairman Statewide N/A N/A N/A yes requirements 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 Page2of2 • • Public Hearing Record And Backup Information available in Other 66 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 W. 71h Avenue, Suite 100 Anchorage Alaska 99501-3192 Re: THE APPLICATION OF BPXA ) Conservation Order No. 505B EXPLORATION (ALASKA) INC. ) for an order to expand the affected ) Prudhoe Bay Field area of the Orion Oil Pool, Prudhoe ) Schrader Bluff Oil Pool Bay Field, North Slope, Alaska. ) April 15, 2014 ERRATA NOTICE The Alaska Oil and Gas Conservation Commission (AOGCC) notes that Conservation Order No. 505B erroneously contracted a portion of the Schrader Bluff Oil Pool affected area. This correction will be reflected in a corrected Conservation Order No. 505B to be issued by the AC)CTCC DONE at Anchorage, Alaska and dated April 15, 2014. Cathy Y. Foerster Daniel T. Seamount, Jr. Chair, Commissioner Commissioner Singh, Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Tuesday, April 15, 2014 2:42 PM To: (michael j.nelson@conocophillips.com); AKDCWellIntegrityCoordinator, Alexander Bridge; Andrew Vanderlack; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Barron, William C (DNR); Bill Penrose; Bill Walker, Bob Shavelson; Brian Havelock; Burdick, John D (DNR); Cliff Posey; Colleen Miller, Crandall, Krissell; D Lawrence; Daryl J. Kleppin; Dave Harbour, Dave Matthews; David Boelens; David Duffy, David Goade; David House; David McCaleb; David Scott; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Donna Ambruz; Dowdy, Alicia G (DNR); Dudley Platt; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Francis S. Sommer; Frank Molli; schultz, gary (DNR sponsored); George Pollock; ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; gspfoff, Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren; Jones, Jeffery B (DOA); Jerry McCutcheon; Jim White; Joe Lastufka; news@radiokenai.com; Easton, John R (DNR); John Garing; Jon Goltz, Jones, Jeffrey L (GOV); Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Keith Wiles; Kelly Sperback; Klippmann; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker; Louisiana Cutler; Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark P. Worcester, Mark Wedman; Kremer, Marguerite C (DNR); Michael Jacobs; Mike Bill; mike@kbbi.org; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; Morones, Mark P (DNR); knelson@petroleumnews.com; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Randy Redmond; Rena Delbridge; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sandra Haggard; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Steve Kiorpes; Moothart, Steve R (DNR); Steven R. Rossberg; Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler, Tim Mayers; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Walter Featherly; yjrosen@ak.net; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater; Anne Hillman; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; David Lenig; Perrin, Don J (DNR); Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr; Smith, Graham 0 (PCO); Greg Mattson; Hans Schlegel; Heusser, Heather A (DNR); Holly Pearen; James Rodgers; Jason Bergerson; Jennifer Starck; jilt.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Bettis, Patricia K (DOA); Peter Contreras; Pollet, Jolie; Richard Garrard; Richard Nehring; Robert Province; Ryan Daniel; Sandra Lemke; Pexton, Scott R (DNR); Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster; Woolf, Wendy C (DNR); William Hutto; William Van Dyke; Ballantine, Tab A (LAW); Bender, Makana K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody 1 (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Ferguson, Victoria L (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Hill, Johnnie W (DOA); Hunt, Jennifer L (DOA); Johnson, Elaine M (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Turkington, Jeff A (DOA); To: Wallace, Chris D (DOA) Subject CO 5058 Errata Notice and CO 505E Corrected Attachments: co505b errata notice.pdf, co505b corrected.pdf Samantha Carlisle Executive Secretary II .Alaska Oil and i�as Conservation Commission 3.33'Vest 7" -Avenue, Suite loo .Anchorage, -AX 99501 6907) 793-1223 (yhone) (907) 276-7542 (fax) CONFIDENTTAM Y 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 Samantha Carlisle at (907) 793- 1223 or Samantha.Carlisle@Alaska.Gov. Janet D. Platt Director Regulatory Compliance and Environment BP Exploration (Alaska), Inc. Post Office Box 196612 Anchorage, AK 99519-6612 f4�� -e 'Ls�6, - kS � Penny Vadla George Vaught, Jr. Jerry Hodgden 399 W. Riverview Ave. Post Office Box 13557 Hodgden Oil Company Soldotna, AK 99669-7714 Denver, CO 80201-3557 40818 St. Golden, CO 80401-2433 Bernie Karl Cl RI North Slope Borough K&K Recycling Inc. Land Department Planning Department Post Office Box 58055 Post Office Box 93330 Post Office Box 69 Fairbanks, AK 99711 Anchorage, AK 99503 Barrow, AK 99723 Richard Wagner Gordon Severson Jack Hakkila Post Office Box 60868 3201 Westmar Cir. Post Office Box 190083 Fairbanks, AK 99706 Anchorage, AK 99508-4336 Anchorage, AK 99519 Darwin Waldsmith James Gibbs��`e� Post Office Box 39309 Post Office Box 1597 Ninilchik, AK 99639 Soldotna, AK 99669 8/STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF BPXA ) Docket Number: CO-09-23 EXPLORATION (ALASKA) INC. ) Conservation Order No. 505B Corrected for an order to expand the affected ) area of the Orion Oil Pool, Prudhoe ) Prudhoe Bay Field Bay Field, North Slope, Alaska. ) Schrader Bluff Oil Pool April 15, 20 t 4 IT APPEARING THAT: 1. On June 30, 2009, BP Exploration (Alaska), Inc. (BPXA) requested the Alaska Oil and Gas Conservation (AOGCC) grant an expansion of the Prudhoe Bay Field, Schrader Bluff Oil Pool as currently defined in Conservation Order 505A. 2. Pursuant to 20 AAC 25.540, on October 22, 2009 the AOGCC published in the Anchorage Daily News notice of the opportunity for a public hearing on December 1, 2009. 3. No protest to the application or request for hearing was received. 4. Because BPXA provided sufficient information upon which to make an informed decision, the request can be resolved without a hearing. 5. The hearing was vacated on November 18, 2009. FINDINGS 1. CO 505 issued January 5, 2004 defined the Schrader Bluff Oil Pool and set out rules governing development and operations within a specified area. 2 CO 505A issued April 28, 2006 superseded CO 505 and authorized underground injection of enriched hydrocarbon gas in the OOP. 3 This amendment action should properly apply to CO 505A. 4 BPXA proposes to expand the operation and development of the pool beyond the area specified in CO 505A. 5 Subsurface wireline log data, pressure measurements, and newly reprocessed seismic data all indicate that the Schrader Bluff Oil Pool extends beyond the area specified in CO 505A. 6 No testimony was presented that warrants a change in the governing rules set out in CO 505A. Conservation Order 505B Corrected April 15, 2014 Page 2 of 9 CONCLUSIONS: Conservation Order No. 505B supersedes and replaces CO 505 dated January 5, 2004, and CO 505A, dated April 28, 2006 only insofar as CO 505B concerns the Schrader Bluff Oil Pool. Conservation Order No. 505B has no effect on CO 505 and CO 505A as to any other pools. 2. The area subject to pool rules governing the development and operation of the Schrader Bluff Oil Pool should be expanded to encompass the additional area proposed for development. 3. All prior rules and approvals issued by the AOGCC for Schrader Bluff Oil Pool operation and development should be consolidated into this conservation order. NOW, THEREFORE, IT IS ORDERED: This Conservation Order supersedes and replaces CO 505A dated April 28, 2006. The findings, conclusions and administrative record for Conservation Order 505A are adopted by reference and incorporated in this decision. The following rules, in addition to the statewide requirements under 20 AAC 25 as set forth below, apply to the Schrader Bluff Oil Pool within the following affected area: Conservation Order 505B Corrected April 15, 2014 Page 3 of 9 Umiat Meridian Township Range, UM Lease Sections T12N-R10E ADL 025637 13 and 24 N/2 T12N-R11E ADL390067 14: S/2 S/2, 23: ALL, 24: SW/4 and SW/4 NW/4 (expansion area this order) ADL 047446 17, 18, 19, and 20 ADL 047447 16 S/2 and NW/4 and S/2 NEA, 21, and 22 ADL 028238 25 SW/4, 26, 35, and 36 ADL 028239 27, 28, 33 E/2 and N/2 NW/4, and 34 ADL 047449 29 N/2 and SEA, and 30 N/2 NE/4 T1IN-RI 1E ADL 028240 1, 2, 11 E/2 and E/2 NW/4, and 12 ADL 028241 3 N/2 and N/2 S/2, and 4 NE/4 and N/2 SE/4 ADL 028245 13 N/2 and SE/4, 14 E/2 NE/4, and 24 E/2 NE/4 Tl IN-R12E ADL 047450 7, and 8 S/2 and NW/4 ADL 028263 16 SWA and S/2 NW/4, and 21 SW/4 and S/2 NW/4 and NW/4 NW/4 and W/2 SE/4 ADL 028262 17, 18, 19 N/2 and SE/4 and N/2 SW/4, and 20 ADL 047452 28 W/2 and W/2 E/2 ADL 047453 29 N/2 and N/2 SE/4 Rule 1: Well Spacing (Source CO 505) Spacing units shall be a minimum of 10 acres. The Schrader Bluff Oil Pool shall not be opened in any well closer than 500' to an external boundary where ownership changes. Conservation Order 505B Corrected April 15, 2014 Page 4 of 9 Rule 2: Casing and Cementing Practices (Source CO 505) a. In addition to the requirements of 20 AAC 25.030, conductor casing must be set at least 75' below surface. b. In addition to the requirements of 20 AAC 25.030, surface casing must be set at least 500' TVD below the base of permafrost. Rule 3: Automatic Shut-in Equipment (Source CO 505) a. All wells must be equipped with a fail-safe automatic surface safety valve system capable of preventing an uncontrolled flow. b. All wells must be equipped with landing nipple at a depth below permafrost, which is suitable for the future installation of a downhole flow control device. The AOGCC may require such installation by administrative action. c. Operation and performance tests must be conducted at intervals and times as prescribed by the AOGCC to confirm that the safety valve systems are in proper working condition. Rule 4• Common Production Facilities and Surface Commingling (Source CO 505) a. Production from the Schrader Bluff Oil Pool may be commingled with production from Prudhoe Bay Oil Pool, and other oil pools located in the Prudhoe Bay Unit in surface facilities prior to custody transfer. b. The Prudhoe Bay Unit Western Operating Metering Plan, described by letter from BPXA dated April 23, 2002 and detailed within the PBU Western Satellite Production Metering Plan — Policies and Procedures Document" dated August 1, 2002 is approved for allocation of production from Schrader Bluff Oil Pool wells . c. All Schrader Bluff Oil Pool wells must use the Gathering Center 2 well allocation factor for oil, gas, and water. d. All wells must be tested a minimum of once per month. All new wells must be tested a minimum of two times per month during the first three months of production. The AOGCC may require more frequent or longer tests if the allocation quality deteriorates. e. Technical process review meetings shall be held at least annually. f. The operator shall submit a monthly report and file(s) containing daily allocation data and daily test data for agency surveillance and evaluation. Rule 5: Reservoir Pressure Monitoring (Source CO 505) a. Prior to regular production or injection, an initial pressure survey must be taken in each well. b. A minimum of one bottom -hole pressure survey per producing governmental section shall be run annually. The surveys in part (a) of this rule may be used to fulfill the minimum requirements. c. The reservoir pressure datum will be 4400' TVDss. Conservation Order 505B Corrected April 15, 2014 Page 5 of 9 d. Pressure surveys may be stabilized static pressure measurements at bottom -hole or extrapolated from surface (single phase fluid conditions), pressure fall -off, pressure buildup, multi -rate tests, drill stem tests, and open -hole formation tests. e. Data and results from pressure surveys shall be submitted with the annual reservoir surveillance report. All data necessary for analysis of each survey need not be submitted with the report but must be available to the AOGCC upon request. f. Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (e) of this rule. Rule 6• Gas -Oil Ratio Exemption (Source CO 505) Wells producing from the Schrader Bluff Oil Pool are exempt from the gas -oil -ratio limits of 20 AAC 25.240 (a) so long as requirements of 20 AAC 25.240 (b) are met. Rule 7• Enhanced Oil Recovery or Reservoir Pressure Maintenance Operations (Source CO 505A Waterflood is required and enriched gas injection is approved for purposes of pressure maintenance and enhanced oil recovery in the Schrader Bluff Oil Pool,. Production and injection operations must ensure the average reservoir pressure is maintained above the bubble point. Rule 8• Multiple Completion of Injection Wells (Source CO 505.0011 a. Injectors may be completed to allow for simultaneous injection in multiple pools within the same wellbore so long as mechanical isolation between pools is demonstrated and approved by the AOGCC. b. Prior to initiation of co -mingled injection, the AOGCC must approve methods for allocation of injection to separate pools. c. Results of logs or surveys used for determining the allocation of water injection between pools, if applicable, must be supplied in the annual reservoir surveillance report. d. An approved injection order is required prior to commencement of injection in each pool. Rule 9• Annual Reservoir Review (Source CO 505A) An annual report must be filed by September 15 of each year. The report must include future development plans, reservoir depletion plans, and surveillance information for the period July 1 of the prior calendar year through June 30 of the current calendar year (except the report due on September 15, 2006 must cover the period from January 2005 through June 30, 2006), and must include: a. voidage balance by month of produced and injected fluids, and cumulative status; b. reservoir pressure map at datum, summary and analysis of reservoir pressure surveys within the pool; c. results and, where appropriate, analysis of production and injection surveys, tracer surveys, observation well surveys, and any other special monitoring; d. review of pool production allocation factors and issues over the prior year; Conservation Order 505B Corrected April 15, 2014 Page 6 of 9 e. progress of enhanced recovery project implementation and reservoir management summary including results of reservoir simulation studies; f. progress of plans and tests to expand the productive limits of the pool, including any work within the Prince Creek formation; and g. results of monitoring to determine enriched gas injectant breakthrough to offset producers. The Operator shall schedule and conduct a yearly technical review meeting, on or about November 1, with the AOGCC to discuss the report contents and to review items that may require AOGCC action during the coming year. The AOGCC may conduct audits of technical data and analyses used in support of surveillance conclusions and reservoir depletion plans. Rule 10• Waiver of "Application for Sundry Approvals" Requirement for Workover Operations (Source CO 556) a. Except as provided in (d) and (e) of this rule, the requirement to submit an Application for Sundry Approvals (Form 10-403) and supporting documentation for workover activities described in 20 AAC 25.280 (a) (1), (2), (3) and (5) is waived or modified for development wells as provided in the AOGCC document entitled "Well Work Operations and Sundry Notice/Reporting Requirements for Pools Subject to Sundry Waiver Rules," dated July 15, 2005 (referred to below as "Sundry Matrix"). This waiver and modification does not affect the Operator's responsibility to submit a Report of Sundry Well Operations (Form 10-404) within 30 days following the completion of a workover operation. b. Except as provided in (d) and (e) of this rule, the requirement to submit an Application for Sundry Approvals (Form 10-403) and supporting documentation for workover activities described in 20 AAC 25.280 (a) (1) and (5) is modified for service wells as provided in the Sundry Matrix. This modification does not affect the Operator's responsibility to submit a Report of Sundry Well Operations (Form 10-404) within 30 days following the completion of a workover operation. c. The Sundry Matrix summarizes the sundry approval and reporting requirements that apply to various categories of operations in the specific well types under AOGCC regulations as modified by these rules. d. The waivers provided under (a) of this rule do not apply to wells that are required to be reported to the AOGCC under the provisions of Rule 11. e. The AOGCC reserves the discretion to require an operator to submit an Application for Sundry Approvals for a particular well or for a particular operation on any well. f. Each week the Operator shall provide the AOGCC with a report of workover operations performed the previous week that did not require submission of a Form 10-403. (These operations are listed in Column 2 of the Sundry Matrix.) The report must include the date, well, permit to drill number, nominal operation completed, and a brief description of that operation including depths of perforations, reperforations, and stimulated zones. Conservation Order 505B Corrected April 15, 2014 Page 7 of 9 g. Nothing in this rule precludes an Operator from filing an Application for Sundry Approvals (Form 10-403) in advance of any well work or from including Sundry authorized operations (listed in column 3 of the Sundry Matrix) in the weekly report required by (f) of this rule. h. Unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any provision of this rule or administratively amend any provision including the Sundry Matrix, 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. Rule 11: Annular Pressures (Sources CO 505, CO 492) a. At the time of installation or replacement the Operator shall conduct and document a pressure test of tubulars and completion equipment in each development 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 development 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 AOGCC inspection. c. The Operator shall notify the AOGCC within three working days after the Operator identifies a well as having (a) sustained inner annulus pressure that exceeds 2500 prig for wells processed through the Lisburne Processing Center and 2000 psig for all other development wells, or (b) sustained outer annulus pressure that exceeds 1000 psig. d. The AOGCC 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 development well having sustained pressure that exceeds a limit set out in paragraph 3 of this rule. The AOGCC may approve the Operator's proposal or may require other corrective action or surveillance. The AOGCC may require that corrective action be verified by mechanical integrity testing or other AOGCC approved diagnostic tests. The Operator shall give the AOGCC sufficient notice of the testing schedule to allow the AOGCC to witness the tests. e. If the Operator identifies sustained pressure in the inner annulus of a development 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 AOGCC within three working days and take corrective action. Unless well conditions require the Operator to take emergency corrective action before AOGCC approval can be obtained, the Operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The AOGCC may approve the Operator's proposal or may require other corrective action. The AOGCC may also require that corrective action be verified by mechanical integrity testing or other AOGCC approved diagnostic tests. The Operator shall give the AOGCC sufficient notice of the testing schedule to allow AOGCC to witness the tests. Conservation Order 505B Corrected April 15, 2014 Page 8 of 9 £ Except as otherwise approved by the AOGCC 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 psig, 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 AOGCC under (c) of this rule, unless the AOGCC prescribes a different limit. g. For purposes of this rule, "inner annulus" means the space in a well between tubing and production casing; "outer annulus" means the space in a well between production casing and surface casing; and "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. Rule 12• Use of Multiphase Flowmeters in Well Testing (Sources CO 547.004 and 547.005) For purposes of satisfying well test measurement requirements of 20 AAC 25.230, the use of the Weatherford Generation 2.0 Multiphase Metering System and FMC Technologies multiphase Flow Meter System (EMS MPM) is approved in accordance with the respective administrative approvals. Rule 13: Administrative Action Unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated above or administratively amend any rule 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. Conservation Order 505B Corrected April 15, 2014 Page 9 of 9 DONE at Anchorage, Alaska and dated April 15, 2014. Cathy P Foerst r Chair, Commissioner Daniel T. Seamount, Jr. Commissioner TION 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 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 are 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 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 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. Singh, Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Tuesday, April 15, 2014 2:42 PM To: (michael j.nelson@conocophillips.com); AKDCWeIIIntegrityCoordinator, Alexander Bridge; Andrew Vanderlack, Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Barron, William C (DNR); Bill Penrose; Bill Walker, Bob Shavelson; Brian Havelock; Burdick, John D (DNR); Cliff Posey; Colleen Miller; Crandall, Krissell; D Lawrence; Daryl J. Kleppin; Dave Harbour, Dave Matthews; David Boelens; David Duffy; David Goade; David House; David McCaleb; David Scott; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Donna Ambruz; Dowdy, Alicia G (DNR); Dudley Platt, Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Francis S. Sommer; Frank Molli; Schultz, gary (DNR sponsored); George Pollock; ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; gspfoff, Jacki Rose; ldarlington oarlington@gmail.com); Jeanne McPherren; Jones, Jeffery B (DOA); Jerry McCutcheon; Jim White; Joe Lastufka; news@radiokenai.com; Easton, John R (DNR); John Garing; Jon Goltz; Jones, Jeffrey L (GOV); Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty, Keith Wiles; Kelly Sperback; Klippmann; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker, Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark P. Worcester; Mark Wedman; Kremer, Marguerite C (DNR); Michael Jacobs; Mike Bill; mike@kbbi.org; Mikel Schultz; Mindy Lewis; M1 Loveland; mjnelson; mkm7200; Morones, Mark P (DNR); knelson@petroleumnews.com; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Randy Redmond; Rena Delbridge; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sandra Haggard; Sara Leverette; Scott Griffith; Shannon Donnelly, Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Steve Kiorpes; Moothart, Steve R (DNR); Steven R. Rossberg; Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler, Tim Mayers; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Walter Featherly; yjrosen@ak.net; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater; Anne Hillman; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; David Lenig; Perrin, Don J (DNR); Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr, Smith, Graham 0 (PCO); Greg Mattson; Hans Schlegel; Heusser, Heather A (DNR); Holly Pearen; James Rodgers; Jason Bergerson; Jennifer Starck; jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez, Lois Epstein; Longan, Sara W (DNR); Marc Kuck, Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, lames M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Bettis, Patricia K (DOA); Peter Contreras; Pollet, Jolie; Richard Garrard; Richard Nehring; Robert Province; Ryan Daniel; Sandra Lemke; Pexton, Scott R (DNR); Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, Woolf, Wendy C (DNR); William Hutto; William Van Dyke; Ballantine, Tab A (LAW); Bender, Makana K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha 1 (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Ferguson, Victoria L (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Hill, Johnnie W (DOA); Hunt, Jennifer L (DOA); Johnson, Elaine M (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Turkington, Jeff A (DOA); To: Wallace, Chris D (DOA) Subject: CO 505E Errata Notice and CO 505B Corrected Attachments: co505b errata notice.pdf, co505b corrected.pdf Samantha Carlisle Executive Secretary II .A.Cas(a OiCand iCas Conservation Commission 333'Nest 7t' .Avenue, Suite wo -Anchorage, -A�K 99501 (907) 793-1223 (yhone) (907) 276-7542 (fax) CONFIDENT LUM 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 Samantha Carlisle at (907) 793- 1223 or Samantha.Carlisle@Alaska.Gov. Janet D. Platt Director Regulatory Compliance and Environment BP Exploration (Alaska), Inc. Post Office Box 196612 Anchorage, AK 99519-6612 Penny Vadla George Vaught, Jr. Jerry Hodgden Hodgden Oil Company 399 W. Riverview Ave. Post Office Box 13557 40818' St. Soldotna, AK 99669-7714 Denver, CO 80201-3557 Golden, CO 80401-2433 Bernie Karl CIRI North Slope Borough K&K Recycling Inc. Land Department Planning Department Post Office Box 58055 Post Office Box 93330 Post Office Box 69 Fairbanks, AK 99711 Anchorage, AK 99503 Barrow, AK 99723 Richard Wagner Gordon Severson Jack Hakkila Post Office Box 60868 3201 Westmar Cir. Post Office Box 190083 Fairbanks, AK 99706 Anchorage, AK 99508-4336 Anchorage, AK 99519 Darwin Waldsmith James Gibbs t �J Post Office Box 39309 Post Office Box 1597 Ninilchik, AK 99639 Soldotna, AK 99669`: THE STATE "ALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO.505B.001 CONSERVATION ORDER NO.457B.005 CONSERVATION ORDER NO.341F.001 CONSERVATION ORDER NO.471.008 CONSERVATION ORDER NO.452.003 CONSERVATION ORDER NO.484A.003 CONSERVATION ORDER NO.559.011 CONSERVATION ORDER NO.570.009 CONSERVATION ORDER NO.329B.004 Ms. Diane Richmond Performance and Data Management Lead, Alaska Reservoir Development BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: CO-15-013 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Request for administrative approval to waive the monthly production allocation reporting requirement for the Schrader Bluff Oil Pool, Aurora Oil Pool, Prudhoe Oil Pool, Borealis Oil Pool, Midnight Sun Oil Pool, Polaris Oil Pool, Put River Oil Pool, Raven Oil Pool, and PBU Well NK-43 which is completed in the Niakuk and Raven Oil Pools in the Prudhoe Bay Unit. Dear Ms. Richmond: By letter dated November 2, 2015, and email date December 16, 2015, BP Exploration (Alaska) Inc. (BPXA) requested administrative approval to waive the requirement for monthly reporting of daily allocation and test data contained in the following rules: - Rule 4(f) of Conservation Order No. (CO) 50513; - Rule 4(e) of CO 45713; - Rule 18(d) of CO 341F; - Rule 4(g) of CO 471; - Rule 7(d) of CO 452; CO 505B.001, CO 457B.005, CO 341F.001, CO 471.008, CO 452.003, CO 484A.003, CO 559.011, CO 570.009, CO 329B.004 January 7, 2016 Page 2 of 3 - Rule 4(d) of CO 484A1; - Rule 4(f) of CO 559; - Rule 6(d) of CO 570; and - The first sentence of Rule 4 of CO 32913.003 In accordance with Rule 13 of CO 50513, Rule 10 of CO 45713, Rule 21 of CO 341F, Rule 10 of CO 471, Rule 13 of CO 452, Rule 13 of CO 484A, Rule 11 of CO 559, Rule 14 of CO 570, and Rule 5 of CO 32913.003, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to waive the requirement to submit monthly reports of daily allocation and test data. BPXA requested to waive only the first sentence of Rule 4 CO 329B.003, which states: The operator shall submit a monthly report and file(s) containing daily allocation data, daily test data, results of geochemical analysis and results of production logs used for purposes of allocation. BPXA requested to waive the following rules in their entirety. Rule 4(d) of CO 484A states: The Operator must submit a monthly report (in printed and electronic form) including well tests, daily -allocated production and allocation factors for the Pool. Rule 18(d) of CO 341F states: In addition to the other requirements of Rule 4 of CO 45713, the monthly reports required by Rule 4(e) of CO 457B must identify the Well S-26 production allocated to the Aurora Oil Pool and Prudhoe Oil Pool. Rule 4(f) of CO 50513, Rule 4(e) of CO 45713, Rule 4(g) of CO 471, Rule 7(d) of CO 452, Rule 4(f) of CO 559, and Rule 6(d) of CO 570 states: The operator shall submit a monthly report and electronic file(s) containing daily allocation data and daily test data for agency surveillance and evaluation. Each of the affected pools is required to submit an annual reservoir surveillance report, providing a summary report on the production allocation and well test data in this annual report and retaining the ability to review the daily data if necessary allows the AOGCC to verify the performance of the well testing and allocation system without the need for monthly reports on the same data. BPXA's application requested to amend CO 484, however CO 484 was replaced by CO 484A on November 30, 2005. Therefore, the AOGCC is treating BPXA's application as an application to amend CO 484A. CO 505B.001, CO 457B.005, CO 341F.001, CO 471.008, CO 452.003, CO 484A.003, CO 559.011, CO 570.009, CO 329B.004 January 7, 2016 Page 3 of 3 Now therefore it is ordered that: Part (d) of Rule 18 of CO 341F, part(d) of Rule 7 of CO 452, part (e) of Rule 4 of CO 457B, part (g) of Rule 4 of CO 471, part (d) of Rule 4 of CO 484A, Part (f) of Rule 4 of CO 505B, part (f) of Rule 4 of CO 559, and part (d) of Rule 6 of CO 570are revised as follows: The operator shall submit a review of pool production allocation factors and issues over the prior year with the annual reservoir surveillance report and retain electronic file(s) containing daily allocation data and daily test data for a minimum of five years. Rule 4 of CO 329B.003 is revised as follows: The operator shall submit a review of pool production allocation factors and issues over the prior year with the annual reservoir surveillance report and retain electronic file(s) containing daily allocation data and daily test data for a minimum of five years. Volumes reported on Form 10-405 in accordance with 20 AAC 25.230 (b) must break out Sag River Undefined Oil Pool and Niakuk Oil Pool allocated production within NK-43. DONE at Anchorage, Alaska and dated January 7, 2016. 0ILA,�,o Cathy . Foerster Daniel T. Se ount, Jr. Chair, Commissioner Commissioner 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 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 are 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 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 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. James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Ms. Diane Richmond Richard Wagner Darwin Waldsmith Performance and Data Management Lead, P.O. Box 60868 P.O. Box 39309 Alaska Reservoir Development Fairbanks, AK 99706 Ninilchik, AK 99639 BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 2�v2cN' 4i` Angela K. Singh Carlisle, Samantha J (DOA) From: Carlisle, Samantha J (DOA) Sent: Friday, January 08, 2016 12:51 PM To: Ballantine, Tab A (LAW) (tab.ballantine@alaska.gov); Bender, Makana K (DOA) (makana.bender@alaska.gov); Bettis, Patricia K (DOA) (patricia.bettis@alaska.gov); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA) (phoebe.brooks@alaska.gov); Carlisle, Samantha 1 (DOA); Colombie, Jody J (DOA) Oody.colombie@alaska.gov); Cook, Guy D (DOA); Crisp, John H (DOA) Oohn.crisp@alaska.gov); Davies, Stephen F (DOA) (steve.davies@alaska.gov); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA) (cathy.foerster@alaska.gov); Frystacky, Michal (michal.frystacky@alaska.gov); Grimaldi, Louis R (DOA) (lou.grimaldi@alaska.gov); Guhl, Meredith (DOA sponsored) (meredith.guhl@alaska.gov); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA) Oeffjones@alaska.gov); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored) Ooseph.mumm@alaska.gov); Noble, Robert C (DOA) (bob.noble@alaska.gov); Paladijczuk, Tracie L (DOA) (tracie.paladijczuk@alaska.gov); Pasqual, Maria (DOA) (maria.pasqual@alaska.gov); Regg, James B (DOA) Oim.regg@alaska.gov); Roby, David S (DOA) (dave.roby@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); Singh, Angela K (DOA) (angela.singh@alaska.gov); Wallace, Chris D (DOA) (chris.waIlace@alaska.gov); AKDCWellIntegrityCoordinator; Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack; Anna Raff; Barbara F Fullmer; bbritch; Becky Bohrer; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Caleb Conrad; Carrie Wong; Cliff Posey; Colleen Miller; Crandall, Krissell; D Lawrence; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; Gordon Pospisil; Gregg Nady; gspfoff; Hyun, James J (DNR); Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren; Jennifer Williams; Jerry Hodgden; Jerry McCutcheon; Jim Watt; Jim White; Joe Lastufka; Joe Nicks; John Adams; John Easton; Jon Goltz; Juanita Lovett; Judy Stanek; Julie Houle; Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Laney Vazquez•, Laura Silliphant (laura.gregersen@alaska.gov); Leslie Smith; Lisa Parker; Louisiana Cutler; Luke Keller; Marc Kovak; Mark Dalton; Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Marquerite kremer (meg.kremer@alaska.gov); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; Mike Mason; Mikel Schultz; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); nelson; Nichole Saunders; Nick W. Glover; Nikki Martin; NSK Problem Well Supv, Oliver Sternicki; Patty Alfaro; Paul Craig; Paul Decker (paul.decker@alaska.gov); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Stephen Hennigan; Steve Moothart (steve.moothart@alaska.gov); Suzanne Gibson; Tamera Sheffield; Tania Ramos; Ted Kramer; Temple Davidson; Terence Dalton; Teresa Imm; Thor Cutler, Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Caroline Bajsarowicz; Casey Sullivan; Diane Richmond; Don Shaw; Donna Vukich; Eric Lidji; Gary Orr; Graham Smith; Greg Mattson; Hak Dickenson; Heusser, Heather A (DNR); Holly Pearen; Jason Bergerson; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Marie Steele; Matt Armstrong; Mike Franger; Morgan, Kirk A (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Robert Province; Ryan Daniel; Sandra Lemke; Sarah Baker; Susan Pollard; Talib Syed; Terence Dalton; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster; William Van Dyke CO 505B.001, CO 457B.005, CO 341F.001, CO 471.008, CO 452.003, CO 484A.003, CO 559.011, CO 570.009, CO 329B.004 (PBU) co505b-001.pdf, co457b-005.pdf, co341f-001.pdf; co471-008.pdf; co452-003.pdf; co484a-003.pdf; co559-011.pdf; co570-009.pdf, co329b-004.pdf Exectr.tive Secxetary 1.11. Alaska Oil and (,as Conservation C:'c:7 anissi.c>n 333 West 7fl, Avenue Ancho.rage=, AK 99501 (907) 793-1223 CONFIDENTIALITY NOTICE. This e-mail message, in ludi:ng any attachments, contains information .from the .Alaska Oil and Gas Conservation Coranussion (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/ or privileged indonnation. 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 AOGC:C is aware of the .mistake .in sending it to you, contact Samantha Carlisle at (907) 793-1223 or Samantha.C.arlisk��alaska.g v. THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Ms. Katrina Garner Alaska Oil and Cas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO. 452.004 CONSERVATION ORDER NO. 45711.006 CONSERVATION ORDER NO. 471.009 CONSERVATION ORDER NO. 484A.004 CONSERVATION ORDER NO. 505B.002 West Area Manager Alaska Reservoir Development BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: CO -18-035 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 vvv✓w.a og cc. alaska.gov Request for Administrative Approval for Conforming Prudhoe Bay Unit (PBU) Satellite Pool Rules for Consistency Prudhoe Bay Unit Midnight Sun Oil Pool — Conservation Order (CO) No. 452 Aurora Oil Pool — CO 457B Borealis Oil Pool — CO 471 Polaris Oil Pool — CO 484A Schrader Bluff Oil Pool — CO 505B Dear Ms. Garner: By letter dated October 23, 2018, BP Exploration (Alaska) Inc. (BPXA) requested administrative approval to amend the pool rules in the above referenced orders in order to bring conformity and consistency to the well testing requirements and pressure survey requirements of these satellite pools in the PBU to improve efficiency of field management for the operator and compliance oversight for the Alaska Oil and Gas Conservation Commission (AOGCC). Initial Well Testing Requirement: BPXA requests that the requirement to conduct at least two well tests per month during the first three months of production from a new well be eliminated to make the testing requirements for these satellites consistent with those in place for the Prudhoe Oil Pool. All of these satellite pools are well established developments and the need for increased well testing in the early stages of a well's production no longer exists. Additionally, making well testing requirements consistent for these satellite pools and the POP will promote operation efficiencies on the numerous drill sites in the PBU that produce from more than one pool. COs 452.004, 457B.006, 471.009, 484A.004, & 505B.002 A10 2C.067 May 29, 2019 Page 2 of 7 Pressure Survey Requirements: Existing pool rules for the Aurora, Borealis, Orion, and Polaris Oil Pools require an initial pressure survey to be taken in each new wellbore before regular production commences from the well. Reliable estimates of the reservoir pressure can be obtained from the pore pressure survey fluid gradient study conducted prior to drilling a new wellbore and from reservoir response during actual drilling operations. Additionally, after so many years of development the pools in the PBU are well understood and have sophisticated reservoir models that make the arbitrary collection of pressure survey data on new wellbores unnecessary for proper development of the pools. A uniform approach to reservoir pressure monitoring provides more useful information than the arbitrary collection of pressure data in new wellbores that may be in portions of the pool where additional pressure data is not necessary for proper reservoir management. The pool rules for the Aurora and Orion Oil Pools relate the number of required pressure surveys to the number of governmental sections in the pool. Pool rules for the other satellite pools, which are completed in the same formations as the Aurora and Orion Oil Pools do not have this requirement. The age and geologic characteristics of the Aurora and Orion Pools makes reservoir pressure survey requirements based on governmental sections unnecessary to properly manage these pools. Developing a pressure survey program based on the representative areas (areas defined by major faulting) would provide uniform pressure survey data requirements that ensure that pressure survey data more accurately represent the actual reservoir pressure across the pool. Extrapolation of bottomhole pressure from the surface pressure of a well on water injection provides accurate results for the reservoir pressure. Requiring BPXA to submit a proposed reservoir pressure survey program for each pool each year as part of its annual surveillance report will provide AOGCC sufficient information to review and request changes if AOGCC determines they are necessary. At the minimum, AOGCC will collect at least one pressure survey per active representative area sufficient to ensure that an adequate reservoir pressure survey program is conducted in these pools. Changing the requirement to report reservoir pressure survey results for the Aurora Oil Pool from quarterly to yearly will bring Aurora's reporting requirements in conformance with the rest of the field. The pool rules for all the affected pools have an administrative approval clause that allows the AOGCC to administratively amend the rules 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 finds that these conditions are met and that the orders may be administratively amended. Now therefore it is ordered That the subject conservation orders are amended as shown below. Midnight Sun Oil Pool — Conservation Order No. 452 COs 452.004,457B.006, 471.009,484A.004, & 505B.002 A10 2C.067 May 29, 2019 Page 3 of 7 Rule 7 Common Production Facilities and Surface Commingling a. Production from the Midnight Sun Oil Pool may be commingled with production from Prudhoe Bay, and other oil pools located in the Prudhoe Bay Unit in surface facilities prior to custody transfer. b. The Prudhoe Bay Unit Western Operating Metering Plan, described in the letter dated April 23, 2002 and detailed within the "Prudhoe Bay Unit (PBU) Western Satellite Production Metering Plan — Policies and Procedures Document" dated August 1, 2002 is approved for allocation of production from Midnight Sun Wells. C. All Midnight Sun wells must use the Gathering Center 1 well allocation factor for oil, gas, and water. d. All wells must be tested a minimum of once per month. The Commission may require more frequent or longer tests if the allocation quality deteriorates. e. The operator shall submit a review of pool production allocation factors and issues over the prior year with the annual reservoir surveillance report and retain electronic file(s) containing daily allocation data and daily test data for a minimum of five years. Rule 8 Reservoir Pressure Monitoring a. A minimum of one bottom -hole pressure survey shall be measured annually for the Midnight Sun Oil Pool. b. The reservoir pressure datum must be 8,050 feet true vertical depth subsea. C. Transient pressure surveys obtained by a shut-in build up test, an injection well pressure fall-off test, a multi -rate test, or an interference test are acceptable. Calculation of bottom -hole pressure from surface data will be permitted for any well on water injection. Other quantitative methods may be administratively approved by the AOGCC. d. Data and results from pressure surveys shall be reported annually on Form 10- 412, Reservoir Pressure Report. All data necessary for analysis of each survey need not be submitter with the Form 10-412 but must be available to the AOGCC upon request. e. Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with part (d.) of this rule. Aurora Oil Pool — Conservation Order No. 457B Rule 4.Common Production Facilities and Surface Comminalina (AA 457.02, 9/11/03) a. The PBU Western Satellite Production Metering Plan, approved by the Commission in CO 471 effective August 1, 2002 governs satellite production within the Western Operating Area of the Prudhoe Bay Unit, including the Aurora Oil Pool. b. The Prudhoe Bay Unit Gathering Center 2 well allocation factor for oil, gas, and water COs 452.004, 457B.006, 471.009,484A.004, & 505B.002 AIO 2C.067 May 29, 2019 Page 4 of 7 shall be applied to adjust total Aurora Oil Pool production. c. All wells must be tested a minimum of once per month. The Commission may require more frequent or longer tests if the allocation quality deteriorates. d. Technical process review meetings with the Commission shall be held at least annually. Rule 5. Reservoir Pressure Monitorine (C0457, 9/7/01) a. An annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Aurora Oil Pool Reservoir Surveillance Report by September 15 of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next plan year, and it will be subject to approval by the AOGCC by October 15 of that year. These surveys are needed to effectively monitor reservoir pressure within the Aurora Oil Pool. The minimum number of bottom -hole pressure surveys performed each year shall equal the number of Representative Areas (West of Crest, North of Crest, South East of Crest, Crest Area, and South of Crest as depicted on Map 1 of the October 23, 2018, application) within the AOP that contain active wells. b. The reservoir pressure datum will be 6,700 feet tvdss. c. Transient pressure surveys obtained by a shut in buildup test, an injection well pressure fall-off test, a multi -rate test, an interference test, drill stem tests, and open -hole formation tests are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for any well on water injection. Other quantitative methods may be administratively approved by the AOGCC. d. Data and results from all relevant reservoir pressure surveys must be reported to the AOGCC annually on Form 10-412, Reservoir Pressure Report. All data necessary for analysis of each survey need not be submitted with the Form 10-412, but shall be available for inspection by the AOGCC upon request. e. Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with paragraph d of this Rule. Borealis Oil Pool — Conservation Order No. 471 Rule 4 Common Production Facilities and Surface Commineline a. Production from the Borealis Pool may be commingled with production from Prudhoe Bay, and other oil pools located in the Prudhoe Bay Unit in surface facilities prior to custody transfer. b. The Prudhoe Bay Unit Western Operating Metering Plan, described in the letter dated April 23, 2002 is conditionally approved for one year beginning August 1, 2002. c. As of August 1, 2002, all Borealis wells must use the Gathering Center 2 well allocation factor for oil, gas, and water. Until August 1, 2002, the Borealis Oil Pool allocation factor shall be 1.0. COs 452.004, 457B.006, 471.009, 484A.004, & 505B.002 A10 2C.067 May 29, 2019 Page 5 of 7 d. All wells must be tested a minimum of once per month. The AOGCC may require more frequent or longer tests if the allocation quality deteriorates. e. A metering and allocation procedures document shall be submitted to the AOGCC by August 1, 2002. A draft copy of the procedures shall be provided to AOGCC staff for technical review by July 8, 2002. f. Technical process review meetings shall be held quarterly to review progress of the implementation of the plan. g. Commission approval of the Prudhoe Bay Unit Western Operating Metering Plan will expire on August 31, 2003. Continued authorization of metering and allocation procedures will be determined at a hearing to be scheduled no later than July 31, 2003. Rule 5 Reservoir Pressure Monitorin¢ a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Borealis Oil Pool Reservoir Surveillance Report by September 15 each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next plan year, and it will be subject to approval by the AOGCC by October 15 of that year. These surveys are needed to effectively monitor reservoir pressure within the BOP. The minimum number of bottom -hole pressure surveys performed each year shall equal the number of Representative Areas (North L -Pad, SW L -Pad, East V -Pad, North V -Pad, South V -Pad, and Z -Pad as depicted on Map 1 of the October 23, 2018, application) within the BOP that contain active wells. b. The reservoir pressure datum will be 6600' TVD sub -sea. c. Transient pressure surveys obtained by a shut-in build-up test, an injection well pressure fall-off test, a multi -rate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for any well on water injection. Other quantitative methods may be administratively approved by the AOGCC. d. Data and results from pressure surveys shall be submitted with the annual reservoir surveillance report. All data necessary for analysis of each survey need not be submitted with the report but must be available to the AOGCC upon request. e. Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (d) of this rule. Polaris Oil Pool — Conservation Order No. 484A Rule 4 Common Production Facilities and Surface Commin¢line Production from the Polaris Oil Pool may be commingled with production from other Prudhoe Bay Field oil pools and tract operations in surface facilities prior to custody transfer. a. All Polaris wells must use the GC -2 well allocation factor for oil, gas, and water. b. All wells must be tested a minimum of once per month. The AOGCC may require more frequent or longer tests if the allocation quality deteriorates. c. Technical meetings with the AOGCC must be held at least yearly to review progress of the implementation of the Western Satellite Production Metering Plan. COs 452.004, 457B.006, 471.009, 484A.004, & 505B.002 AIO 2C.067 May 29, 2019 Page 6 of 7 d. The Operator must submit a monthly report (in printed and electronic form) including well tests, daily -allocated production and allocation factors for the Pool. Rule 5 Reservoir Pressure Monitoring (ref. CO 484) a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Polaris Oil Pool Reservoir Surveillance Report by September 15 of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next plan year, and it will be subject to approval by the AOGCC by October 15, of that year. These surveys are needed to effectively monitor reservoir pressure within the Polaris Oil Pool. The minimum number of pressure surveys performed each year shall equal the number of Representative Areas (S Pad N, S Pad S, W Pad N, and W Pad S as depicted on Map 2 of the October 23, 2018, application) that contain active wells. b. The reservoir pressure datum will be 5000' TVDss. c. Transient pressure surveys obtained by a shut-in build-up test, an injection well pressure fall- off test, a multi -rate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for any well on water injection. Other quantitative methods may be administratively approved by the AOGCC. d. Data and results from pressure surveys shall be submitted with the annual reservoir surveillance report. All data necessary for analysis of each survey need not be submitted with the report but must be available to the AOGCC upon request. e. Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (d) of this rule. Schrader Bluff Oil Pool — Conservation Order No. 505B Rule 4: Common Production Facilities and Surface Commingling a. Production from the Schrader Bluff Oil Pool may be commingled with production from Prudhoe Bay Oil Pool, and other oil pools located in the Prudhoe Bay Unit in surface facilities prior to custody transfer. b. The Prudhoe Bay Unit Western Operating Metering Plan, described by letter from BPXA dated April 23, 2002 and detailed within the PBU Western Satellite Production Metering Plan — Policies and Procedures Document' dated August 1, 2002 is approved for allocation of production from Schrader Bluff Oil Pool wells. c. All Schrader Bluff Oil Pool wells must use the Gathering Center 2 well allocation factor for oil, gas, and water. d. All wells must be tested a minimum of once per month. The AOGCC may require more frequent or longer tests if the allocation quality deteriorates. e. Technical process review meetings shall be held at least annually. Rule 5: Reservoir Pressure Monitoring a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Schrader Bluff Oil Pool Reservoir Surveillance Report by September 15 of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next plan year, and it will be subject to approval by the AOGCC COs 452.004, 457B.006, 471.009, 484A.004, & 50513.002 AIO 2C.067 May 29, 2019 Page 7 of 7 by October 15, of that year. These surveys are needed to effectively monitor reservoir pressure within the SBOP. The minimum number of pressure surveys performed each year shall equal the number of Representative Areas (currently active — 1, 1A, 2, 2A, and 5S, currently inactive — 6N, 6S, 9, 8, 4, 5N, 3A, 3N, and 3 S as depicted on Map 2 of the October 23, 2018, application) within the SBOP that contain active wells. The reservoir pressure datum will be 4400' TVDss. b. Transient pressure surveys obtained by a shut-in build-up test, an injection well pressure fall-off test, a multi -rate test, or an interference test are acceptable. Calculation of bottom - hole pressures from surface data will be permitted for any well on water injection. Other quantitative methods may be administratively approved by the AOGCC. c. Data and results from pressure surveys shall be submitted with the annual reservoir surveillance report. All data necessary for analysis of each survey need not be submitted with the report but must be available to the Commission upon request. d. Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (c) of this rule. DONE at Anchorage, Alaska and dated May 29, 2019. Daniel T. Seamount, Jr. J 'ie L. Chmielowski Commissioner mmissioner 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 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 are FINAL and maybe 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 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 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. TI 111 STATI "ALASKA GOVERNORMICK&EL. 1 DUNLEA Y Ms. Katrina Gamer Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO. 452.004 CONSERVATION ORDER NO. 457B.006 CONSERVATION ORDER NO. 471.009 CONSERVATION ORDER NO. 484A.004 CONSERVATION ORDER NO. 505B.002 West Area Manager Alaska Reservoir Development BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: CO -18-035 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 wvv v.00gcc.alaska.gov Request for Administrative Approval for Conforming Prudhoe Bay Unit (PBU) Satellite Pool Rules for Consistency Prudhoe Bay Unit Midnight Sun Oil Pool — Conservation Order (CO) No. 452 Aurora Oil Pool — CO 457B Borealis Oil Pool — CO 471 Polaris Oil Pool — CO 484A Schrader Bluff Oil Pool — CO 505B Dear Ms. Gamer: By letter dated October 23, 2018, BP Exploration (Alaska) Inc. (BPXA) requested administrative approval to amend the pool rules in the above referenced orders in order to bring conformity and consistency to the well testing requirements and pressure survey requirements of these satellite pools in the PBU to improve efficiency of field management for the operator and compliance oversight for the Alaska Oil and Gas Conservation Commission (AOGCC). Initial Well Testing Requirement: BPXA requests that the requirement to conduct at least two well tests per month during the first three months of production from a new well be eliminated to make the testing requirements for these satellites consistent with those in place for the Prudhoe Oil Pool. All of these satellite pools are well established developments and the need for increased well testing in the early stages of a well's production no longer exists. Additionally, making well testing requirements consistent for these satellite pools and the POP will promote operation efficiencies on the numerous drill sites in the PBU that produce from more than one pool. COs 452.004,457B.006, 471.009, 484A.004, & 50513.002 A10 2C.067 May 29, 2019 Page 2 of 7 Pressure Survey Requirements: Existing pool rules for the Aurora, Borealis, Orion, and Polaris Oil Pools require an initial pressure survey to be taken in each new wellbore before regular production commences from the well. Reliable estimates of the reservoir pressure can be obtained from the pore pressure survey fluid gradient study conducted prior to drilling a new wellbore and from reservoir response during actual drilling operations. Additionally, after so many years of development the pools in the PBU are well understood and have sophisticated reservoir models that make the arbitrary collection of pressure survey data on new wellbores unnecessary for proper development of the pools. A uniform approach to reservoir pressure monitoring provides more useful information than the arbitrary collection of pressure data in new wellbores that may be in portions of the pool where additional pressure data is not necessary for proper reservoir management. The pool rales for the Aurora and Orion Oil Pools relate the number of required pressure surveys to the number of governmental sections in the pool. Pool rules for the other satellite pools, which are completed in the same formations as the Aurora and Orion Oil Pools do not have this requirement. The age and geologic characteristics of the Aurora and Orion Pools makes reservoir pressure survey requirements based on governmental sections unnecessary to properly manage these pools. Developing a pressure survey program based on the representative areas (areas defined by major faulting) would provide uniform pressure survey data requirements that ensure that pressure survey data more accurately represent the actual reservoir pressure across the pool. Extrapolation of bottomhole pressure from the surface pressure of a well on water injection provides accurate results for the reservoir pressure. Requiring BPXA to submit a proposed reservoir pressure survey program for each pool each year as part of its annual surveillance report will provide AOGCC sufficient information to review and request changes if AOGCC determines they are necessary. At the minimum, AOGCC will collect at least one pressure survey per active representative area sufficient to ensure that an adequate reservoir pressure survey program is conducted in these pools. Changing the requirement to report reservoir pressure survey results for the Aurora Oil Pool from quarterly to yearly will bring Aurora's reporting requirements in conformance with the rest of the field. The pool rules for all the affected pools have an administrative approval clause that allows the AOGCC to administratively amend the rules 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 finds that these conditions are met and that the orders may be administratively amended. Now therefore it is ordered That the subject conservation orders are amended as shown below. Midnight Sun Oil Pool — Conservation Order No. 452 COs 452.004, 457B.006, 471.009, 484A.004, & 505B.002 A10 2C.067 May 29, 2019 Page 3 of 7 Rule 7 Common Production Facilities and Surface Commingling a. Production from the Midnight Sun Oil Pool may be commingled with production from Prudhoe Bay, and other oil pools located in the Prudhoe Bay Unit in surface facilities prior to custody transfer. b. The Prudhoe Bay Unit Western Operating Metering Plan, described in the letter dated April 23, 2002 and detailed within the "Prudhoe Bay Unit (PBU) Western Satellite Production Metering Plan — Policies and Procedures Document" dated August 1, 2002 is approved for allocation of production from Midnight Sun Wells. C. All Midnight Sun wells must use the Gathering Center I well allocation factor for oil, gas, and water. d. All wells must be tested a minimum of once per month. The Commission may require more frequent or longer tests if the allocation quality deteriorates. e. The operator shall submit a review of pool production allocation factors and issues over the prior year with the annual reservoir surveillance report and retain electronic file(s) containing daily allocation data and daily test data for a minimum of five years. Rule 8 Reservoir Pressure Monitoring a. A minimum of one bottom -hole pressure survey shall be measured annually for the Midnight Sun Oil Pool. b. The reservoir pressure datum must be 8,050 feet true vertical depth subsea. C. Transient pressure surveys obtained by a shut-in build up test, an injection well pressure fall-off test, a multi -rate test, or an interference test are acceptable. Calculation of bottom -hole pressure from surface data will be permitted for any well on water injection. Other quantitative methods may be administratively approved by the AOGCC. d. Data and results from pressure surveys shall be reported annually on Form 10- 412, Reservoir Pressure Report. All data necessary for analysis of each survey need not be submitter with the Form 10-412 but must be available to the AOGCC upon request. e. Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with part (d.) of this rule. Aurora Oil Pool — Conservation Order No. 457B Rule 4.Common Production Facilities and Surface Commin¢lina (AA 457.02, 9/11/03) a. The PBU Western Satellite Production Metering Plan, approved by the Commission in CO 471 effective August 1, 2002 governs satellite production within the Western Operating Area of the Prudhoe Bay Unit, including the Aurora Oil Pool. b. The Prudhoe Bay Unit Gathering Center 2 well allocation factor for oil, gas, and water COs 452.004,457B.006, 471.009, 484A.004, & 505B.002 AIO 2C.067 May 29, 2019 Page 4 of 7 shall be applied to adjust total Aurora Oil Pool production. c. All wells must be tested a minimum of once per month. The Commission may require more frequent or longer tests if the allocation quality deteriorates. d. Technical process review meetings with the Commission shall be held at least annually. Rule 5. Reservoir Pressure Monitoring (C0457,9/7/01) a. An annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Aurora Oil Pool Reservoir Surveillance Report by September 15 of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next plan year, and it will be subject to approval by the AOGCC by October 15 of that year. These surveys are needed to effectively monitor reservoir pressure within the Aurora Oil Pool. The minimum number of bottom -hole pressure surveys performed each year shall equal the number of Representative Areas (West of Crest, North of Crest, South East of Crest, Crest Area, and South of Crest as depicted on Map I of the October 23, 2018, application) within the AOP that contain active wells. b. The reservoir pressure datum will be 6,700 feet tvdss. c. Transient pressure surveys obtained by a shut in buildup test, an injection well pressure fall-off test, a multi -rate test, an interference test, drill stem tests, and open -hole formation tests are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for any well on water injection. Other quantitative methods may be administratively approved by the AOGCC. d. Data and results from all relevant reservoir pressure surveys must be reported to the AOGCC annually on Foran 10-412, Reservoir Pressure Report. All data necessary for analysis of each survey need not be submitted with the Form 10-412, but shall be available for inspection by the AOGCC upon request. e. Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with paragraph d of this Rule. Borealis Oil Pool — Conservation Order No. 471 Rule 4 Common Production Facilities and Surface Commingling a. Production from the Borealis Pool may be commingled with production from Prudhoe Bay, and other oil pools located in the Prudhoe Bay Unit in surface facilities prior to custody transfer. b. The Prudhoe Bay Unit Western Operating Metering Plan, described in the letter dated April 23, 2002 is conditionally approved for one year beginning August 1, 2002. c. As of August 1, 2002, all Borealis wells must use the Gathering Center 2 well allocation factor for oil, gas, and water. Until August 1, 2002, the Borealis Oil Pool allocation factor shall be 1.0. COs 452.004, 457B.006,471.009, 484A.004, & 505B.002 A10 2C.067 May 29, 2019 Page 5 of 7 d. All wells must be tested a minimum of once per month. The AOGCC may require more frequent or longer tests if the allocation quality deteriorates. e. A metering and allocation procedures document shall be submitted to the AOGCC by August 1, 2002. A draft copy of the procedures shall be provided to AOGCC staff for technical review by July 8, 2002. f. Technical process review meetings shall be held quarterly to review progress of the implementation of the plan. g. Commission approval of the Prudhoe Bay Unit Western Operating Metering Plan will expire on August 31, 2003. Continued authorization of metering and allocation procedures will be determined at a hearing to be scheduled no later than July 31, 2003. Rule 5 Reservoir Pressure Monitorina a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Borealis Oil Pool Reservoir Surveillance Report by September 15 each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next plan year, and it will be subject to approval by the AOGCC by October 15 of that year. These surveys are needed to effectively monitor reservoir pressure within the BOP. The minimum number of bottom -hole pressure surveys performed each year shall equal the number of Representative Areas (North L -Pad, SW L -Pad, East V -Pad, North V -Pad, South V -Pad, and Z -Pad as depicted on Map 1 of the October 23, 2018, application) within the BOP that contain active wells. b. The reservoir pressure datum will be 6600' TVD sub -sea. c. Transient pressure surveys obtained by a shut-in build-up test, an injection well pressure fall-off test, a multi -rate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for any well on water injection. Other quantitative methods may be administratively approved by the AOGCC. d. Data and results from pressure surveys shall be submitted with the annual reservoir surveillance report. All data necessary for analysis of each survey need not be submitted with the report but must be available to the AOGCC upon request. e. Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (d) of this rule. Polaris Oil Pool — Conservation Order No. 484A Rule 4 Common Production Facilities and Surface Commineline Production from the Polaris Oil Pool may be commingled with production from other Prudhoe Bay Field oil pools and tract operations in surface facilities prior to custody transfer. a. All Polaris wells must use the GC -2 well allocation factor for oil, gas, and water. b. All wells must be tested a minimum of once per month. The AOGCC may require more frequent or longer tests if the allocation quality deteriorates. c. Technical meetings with the AOGCC must be held at least yearly to review progress of the implementation of the Western Satellite Production Metering Plan. COs 452.004, 457B.006, 471.009, 484A.004, & 505B.002 A10 2C.067 May 29, 2019 Page 6 of 7 d. The Operator must submit a monthly report (in printed and electronic form) including well tests, daily -allocated production and allocation factors for the Pool. Rule 5 Reservoir Pressure Monitoring (ref. CO 484) a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Polaris Oil Pool Reservoir Surveillance Report by September 15 of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next plan year, and it will be subject to approval by the AOGCC by October 15, of that year. These surveys are needed to effectively monitor reservoir pressure within the Polaris Oil Pool. The minimum number of pressure surveys performed each year shall equal the number of Representative Areas (S Pad N, S Pad S, W Pad N, and W Pad S as depicted on Map 2 of the October 23, 2018, application) that contain active wells. b. The reservoir pressure datum will be 5000' TVDss. c. Transient pressure surveys obtained by a shut-in build-up test, an injection well pressure fall- off test, a multi -rate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for any well on water injection. Other quantitative methods may be administratively approved by the AOGCC. d. Data and results from pressure surveys shall be submitted with the annual reservoir surveillance report. All data necessary for analysis of each survey need not be submitted with the report but must be available to the AOGCC upon request. e. Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (d) of this rule. Schrader Bluff Oil Pool — Conservation Order No. 505B Rule 4: Common Production Facilities and Surface Commingling a. Production from the Schrader Bluff Oil Pool may be commingled with production from Prudhoe Bay Oil Pool, and other oil pools located in the Prudhoe Bay Unit in surface facilities prior to custody transfer. b. The Prudhoe Bay Unit Western Operating Metering Plan, described by letter from BPXA dated April 23, 2002 and detailed within the PBU Western Satellite Production Metering Plan — Policies and Procedures Document" dated August 1, 2002 is approved for allocation of production from Schrader Bluff Oil Pool wells. c. All Schrader Bluff Oil Pool wells must use the Gathering Center 2 well allocation factor for oil, gas, and water. d. All wells must be tested a minimum of once per month. The AOGCC may require more frequent or longer tests if the allocation quality deteriorates. e. Technical process review meetings shall be held at least annually. Rule 5: Reservoir Pressure Monitoring a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Schrader Bluff Oil Pool Reservoir Surveillance Report by September 15 of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next plan year, and it will be subject to approval by the AOGCC COs 452.004, 457B.006, 471.009,484A.004, & 505B.002 AIO 2C.067 May 29, 2019 Page 7 of 7 by October 15, of that year. These surveys are needed to effectively monitor reservoir pressure within the SBOP. The minimum number of pressure surveys performed each year shall equal the number of Representative Areas (currently active — 1, IA, 2, 2A, and 5S, currently inactive — 6N, 6S, 9, 8, 4, 5N, 3A, 3N, and 3S as depicted on Map 2 of the October 23, 2018, application) within the SBOP that contain active wells. The reservoir pressure datum will be 4400' TVDss. b. Transient pressure surveys obtained by a shut-in build-up test, an injection well pressure fall-off test, a multi -rate test, or an interference test are acceptable. Calculation of bottom - hole pressures from surface data will be permitted for any well on water injection. Other quantitative methods may be administratively approved by the AOGCC. c. Data and results from pressure surveys shall be submitted with the annual reservoir surveillance report. All data necessary for analysis of each survey need not be submitted with the report but must be available to the Commission upon request. d. Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (c) of this rule. DONE at Anchorage, Alaska and dated May 29, 2019. �OIL.�Yp //signature on file// //signature on file// € Daniel T. Seamount, Jr. Jessie L. ChmielowskifRa o wsS Commissioner 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 are 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 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 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 M Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639 Fairbanks, AK 99706 THE SPATE °1ALASKA GOVERNOR MIKE DLNLEAVy 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. 505B.003 CONSERVATION ORDER NO. 559A.002 CONSERVATION ORDER NO. 570.011 Mr. Oliver Stemicki 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. a ogc c.olasko.g ov 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, LLC1 (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)'. 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. 2 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.004,317B.003,329A.002,3411.002,345.003, 452.005, 45713.006,471.009, 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 9 In the current CO 45713, the pool rules for the Aurora Oil Pool, Rule 11 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. COs 83A.001, 207D.002,31 IB.004, 317B.003, 329A.002, 3411.002, 345.003, 452.005,457B.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 31113 West Beach 14 317B Pt McIntyre and Stump Island 17 329A Niakuk 13 3411 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-OIA 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, 207D.002, 31 1B.004, 317B.003, 329A.002, 3411.002, 345.003, 452.005, 457B.006, 471.009, 484A.005, 505B.003, 559A.002, & 570.011 October 1, 2020 Page 4 of 4 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 psig, 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, 1. "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 Dig tally signed by Jeremy M. Price Date: 20201001 M. Price 133918U900 Jeremy M. Price Chair, Commissioner Daniel T. Digitally signed by Danieli Seamount. J1 Seamount, Jr. Date 2020.10.01 lybB 4648'0V Daniel T. Seamount, Jr Commissioner Jessie L. Digitally signed by Jessie L. Chmielowski Chmielowski Date: 2020.1001 12:22:07-08.0P Jessie L. Chmielowski Commissioner 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 father 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 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 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 AiDi 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 THE STATE 'ALASKA September 9, 2021 GOVERNOR MIKE DUVLEAVY Ms. Kyndall Carey Land Representative Hilcorp North Slope, LLC 3800 Centerpoint Drive Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO. 50513.004 Re: Docket Number: CO -21-010 Request to amend well spacing for the Schrader Bluff Oil Pool Prudhoe Bay Unit Dear Ms. Carey: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov By application dated and received June 24, 2021, Hilcorp North Slope, LLC (Hilcorp) applied to the Alaska Oil and Gas Conservation Commission (AOGCC) to eliminate the 10 -acre spacing requirement for the Schrader Bluff Oil Pool (SBOP) in the Prudhoe Bay Unit (PBU). Conservation Order No. 505 (CO 505) was initially issued on January 5, 2004, and established 10 -acre well spacing for the SBOP. Since the time this order was issued, horizontal wells and multi -lateral wells have become a much more common development method for the Schrader Bluff formation developments across the North Slope. Old acre -based spacing schemes do not work well for horizontal wells since they do not pass through the target formation on vertical or near vertical trajectories but instead travel for thousands of feet horizontally or near horizontally through the target formation. The use of horizontal wells and multi -lateral wells is not exclusive to the Schrader Bluff formation but has been used extensively throughout the state; and as such, the AOGCC has eliminated acre -based and interwell spacing requirements for many pools across the state to allow for more efficient development of the oil and gas resources. Whenever the AOGCC has adopted spacing requirements for an oil or gas pool to eliminate acre -based or interwell spacing requirements, it has always imposed property line offset requirements in order to protect correlative rights along property lines where ownership is not the same on both sides of the property line. Hilcorp's request will allow for more efficient development of the SBOP and will protect correlative rights by requiring a minimum standoff from property lines where the ownership and or landownership changes. Ms. Kyndall Carey September 9, 2021 Page 2 of 2 Now therefore it is ordered: Rule 1 of CO 505B is revised to read as follows: Rule 1: Well Spacing There shall be no restrictions as to well spacing except that no pay shall be opened to a well within 500 feet of an external property line where the owners and landowners are not the same on both sides of the line. DONE at Anchorage, Alaska and dated September 9, 2021. JeremyDigitally signed by Dan Digitally signed by Jeremy Price Dan Seamount Price Date: 2021.09.09 Seamount Date: 2021.09.09 12:20:06 -08'00' 11:53:35 -08'00' Jeremy M. Price Daniel T. Seamount, Jr. Chair, Commissioner Commissioner 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 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 are 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 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 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. Salazar, Grace (CED) From: Salazar, Grace (CED) <grace.salazar@alaska.gov> Sent: Thursday, September 9, 2021 12:47 PM To: AOGCC Public Notices Subject: [AOGCC_Public_Notices] AOGCC Conservation Order No. 50513.004 Attachments: C0505B.004.pdf The Alaska Oil & Gas Conservation Commission has issued the attached Administrative Approval for Conservation Order No. 505. Re: Docket Numbers: CO -21-010 Request to amend well spacing for the Schrader Bluff Oil Pool Prudhoe Bay Unit Respectfully, M. Grace Salazar, Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Direct: (907) 793-1221 Email: grace.salazar@alaska.gov https://www.commerce.alaska.gov/web/aogcc/ List Name: AOGCC_Public_Notices@Iist.state.ak.us You subscribed as: grace.salazar@alaska.gov Unsubscribe at: https:Hlist.state.ak.us/mailman/options/aogcc_public_notices/grace.salazar%40alaska.gov Bernie Karl Recycling Inc. Gordon Severson Richard Wagner K&K P.O. Box 3201 Westmar Cir. P.O. Box 60868 Fairbanks, AK 99711 Anchorage, AK 99508-4336 Fairbanks, AK 99706 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 It Oti �JQ-� t Hilcorp North Slope, LLC June 24, 2021 Kyndall Carey Land Representative 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone: 907/777-8386 Fax: 907/777-8301 kyndall.carey@hilcorp.com Jeremy Price, Chair RECEIVED Alaska Oil and Gas Conservation Commission 333 West 7th Avenue By Grace Salazar at 10:35 am, Jun 24, 2021 Anchorage, AK 99501 RE: Proposed Amendment to Conservation Order No. 5058 (Prudhoe Bay Unit Schrader Bluff Oil Pool) Dear Chair Price: Hilcorp North Slope, LLC ("Hilcorp North Slope"), as the operator of the Prudhoe Bay Unit, respectfully requests that the Alaska Oil and Gas Conservation Commission administratively approve' an amendment to Conservation Order ("CO") No. 505B (May 4, 2010) by repealing Rule 1 in its entirety and replacing it with the following language. Rule 1: Well Sgacina There shall be no well spacing restrictions within the Schrader Bluff Oil Pool, except that no well shall be opened closer than 500 feet to an external boundary where ownership changes. In addition to reducing administrative burdens, the proposed change is designed to prevent economic and physical waste and improve the ultimate recovery of remaining hydrocarbons. This proposed change does not modify the affected area provided in CO No. 505B and it does not jeopardize correlative rights. By eliminating intra -pool well spacing requirements, Hilcorp North Slope will be able to target smaller, undrained portions of the reservoir that cannot be reached by wells conforming to current spacing restrictions. If you need additional information, please contact Michael Mayfield at 907/564-5097. Sincerely, signed byKyndall Carey (DN36'YKyndallC Ky�darey 39 Carey (3936) Date 202,.06.2409:5836-08'00' Kyndall Carey Land Representative Hilcorp North Slope, LLC cc: ConocoPhillips Alaska, Inc. ExxonMobil Alaska Production, Inc. Chevron U.S.A., Inc. I Administrative Action is being requested pursuant to CO No. 505B, Rule 13. Salazar, Grace (CED) From: Salazar, Grace (CED) Sent: Thursday, June 24, 2021 10:39 AM To: Kyndall Carey; Roby, David S (CED) Cc: Erickson, Stephanie N; Cross, Lisa M; Gary Selisker; Jill Fisk; Kevin Eastham; Michael Mayfield; Alicia Showalter; Kevin Tabler; Jim Shine Subject: RE: Application to Amend CO 505B Rule 1 Attachments: Application to Amend CO 505B Rule 1_06242021.pdf Thank you. This has been marked received and assigned Docket CO -21-010. Respectfully, M. Grace Salazar, Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Direct: (907) 793-1221 Email: grace.salazar@alaska.gov https://www.commerce.alaska.gov/web/aogcc/ From: Kyndall Carey <Kyndall.Carey@hilcorp.com> Sent: Thursday, June 24, 202110:06 AM To: Roby, David S (CED) <dave.roby@alaska.gov>; Salazar, Grace (CED) <grace.salazar@alaska.gov> Cc: Erickson, Stephanie N <Stephanie.N.Erickson @conocophillips.com>; Cross, Lisa M <Lisa.m.cross@exxonmobil.com>; Gary Selisker <gselisker@chevron.com>; Jill Fisk <jfisk@hilcorp.com>; Kevin Eastham <keastham@hilcorp.com>; Michael Mayfield <mmayfield@hilcorp.com>; Alicia Showalter <ashowalter@hilcorp.com>; Kevin Tabler <ktabler@hilcorp.com>; Jim Shine <jshine@hilcorp.com> Subject: Application to Amend CO 5058 Rule 1 Mr. Roby and Ms. Salazar, Please find attached an application to amend the well spacing requirement within the Prudhoe Bay Unit Schrader Bluff Oil Pool (CO 505B). Please confirm via email that you have received this submittal. Thank you in advance. Thank you, Kyndall Carey Land Representative Hilcorp Alaska, LLC Cell: 907-830-1409 Aombie,_Jody J (CED) 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, whether on 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 area n unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that he AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at(907-793-1231)or (Melvin . Rixsep aIaska. ay. cc. Jody Colombie From: Colombie, Jody J (CED) Sent: Wednesday, lune 10, 2020 8:59 AM To: Chmielowski, Jessie L C (CED) <iessie.chmielowskina alaska.aov> Cc: Rixse, Melvin G (CED) <melvin.rixse(@alaska.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)<Lessie.chmielowskit@alaska.eov> Sent: Wednesday, June 10, 2020 8:57 AM To: Colombie, Jody J (CED) <jody.colombiePalaska.eov> Cc: Rixse, Melvin G (CED) <melvin.rixse(@alaska.zov> 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.Sternicki@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 Wo moo., Wa,uw,„mA Sr. Well Integrity Engineer BP Exploration Alaska Cell: 1 (907) 350 0759 oliver.sternicki(o)bp com From: Rixse, Melvin G (CED) <melvin.rixse@alaska.gov> Sent: Friday, May 15, 2020 4:31 PM To: Sternicki, Oliver R <Oliver.Sternicki@bp.com> Subject: FW: CO -20-008 From: Colombie, Jody J (CED) <jody.colombiePalaska.gov> Sent: Friday, May 15, 2020 3:16 PM To: AOGCC_Public_Notices <AOGCC Public Notices(@Iist state ak us> Subject: [AOGCC_Public_Notices] CO -20-008 Docket Number: CO -20-008 Prudhoe Bay Field, All Pools Jodv J. Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7h Avenue Anchorage, AK 99501 ('907) 793-1221 Direct (907) 176-7512 Fay List Name: AOGCC Public Noticesna list state ak us You subscribed as: rvan.daniellaibp.com Unsubscribe at: http://Iist.state ak.us/mailman/options/ao¢cc public notices/roan daniel%40bp com STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMITINVOICE SHOWING ADVERTISINGORDER NO., CERTIFIED AFFIDAVITOF PUBLICATION WITH ATTACHED COPY OF ADVERTISMENT. ADVERTISING ORDER NUMBER AO-08-20-024 FROM: AGENCY CONTACT: Jody Colombie/Samantha Carlisle Alaska Oil and Gas Conservation Commission DATE OF A.O.AGENCY PHONE: 333 West 7th Avenue 5/152020 907 279-1433 Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: ASAP FAX NUMBER: 907 276-7542 TO PUBLISHER: Anchorage Daily News LLC SPECIAL INSTRUCTIONS: PO Box 140147 Anchorage Alaska 99514-0174 TYPE OF ADVERTISEMENT: I✓ LEGAL _ r DISPLAY '(— CLASSIFIED r OTHER (Specify below) DESCRIPTION PRICE CO-20-008 Initials of who prepared AO: Alaska Non -Taxable 92-600185 SUBMIT INVOICE SHOWING ADVERTISING ORDERNO,CERTIFIEDAFFIDAVITOF PUBLICATION WITH ATTACBED COPY OF ADVER715MENT iO: AOGCC 333 West 7th AvenueTotal ARchora a Alaska 99501 Pae I of I of All Pages $ REF Type I Number Amount Date Comments I PvN I VCO21795 2 AD AO-08-20-024 3 4 FIN AMOUNT I SY Act Te late PGM LGR Object FY DIST LIQ I 1 20 AOGCC 3046 20 2 3 4 5 Punch n u ri Tide: Purchasing Authority's Signature Telephone Number .O. # and receiving agency name must appear on all involces and documents relating to this purchase. 2 e state is registeredfortax 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 FiscaVOriginal AO Copies: Publisher (faxed), Division Fiscal, Receiving Form: 02-901 Revised: 5/21/2020 Bernie Karl Gordon Severson Richard Wagner P.O. Bo 58055ycling Inc. 3201 Westmar Cir. P.O. Box 60868 P.O. Box , AK Anchorage, AK 99508-4336 Fairbanks, AK 99706 Fairbanks, AK 99711 George Vaught, Jr. Darwin Waldsmith P.O. Box 13557 P.O. Box 39309 Denver, CO 80201-3557 Ninilchik, AK 99639 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 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 prig 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" 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 am. 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 7` 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 a 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. Jemmy M. Price Chair, Commissioner BP Exploration (Alaska) Inc. Attn: Well Integrity Coordinator, PRB-20,; Post Office Box 196612, Anchorage, Alaska 99519-6612 to . 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�ird 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 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 ;8060 •-__. _ _ -�a_� �—a—u.. _.... . � _ ir.�. _-_._.—. _ _ _ _ - - i� 5/1}/X)15 5/]/30i5 6/$Lr2T5 8A/3065 9/}VM15 1l/}]R015 }/fi/:016 }/};'X1,6 Figure 2- WOA Pad Gas Lift Header Pressure WOA Gas Lift Pressure umm IA W WV=5 5/I/Em5 6AW." B/9Am5 9/IVID15 3]/MMS 1/8/206 DN! 3/3$/X116 —mw I —OSM I I -mm —OS I3 —061] -013 —OS IC I —avw —BP.a —op. x Pae —LPA —.P. --NPA PPa a Pee —sP.e vre w P.e •Pm vwe 3P.e 0 SE October 23, 2018 Via USPS and Electronic Delivery Hollis French Commission Chair Alaska Oil and Gas Conservation Commission 333 West 7' Avenue, Suite 100 Anchorage, AK 99501 BP Exploration (Alaska) Inc 900 cast Benson Bowevare P O. Box 595612 Anchorage. Alaska 99519-6612 (907)561-5111 1-wh 2 6 21oiCr" C4ki 2f-' F -M Re: Application for Administrative Approval Conforming PBU Satellite Pool Rules for Consistency Amendments to Conservation Orders: 457 A/B, Rules 4b, 5b, 5e Aurora Oil Pool; 471, Rules 4d and 5b, Borealis Oil Pool; 505B, Rules 4d and 5b, Orion Oil Pool; 484A Rules 4b and 5b, Polaris Oil Pool, 452 Rule 7d, Midnight Sun Oil Pool, governing initial well testing requirements and pressure surveys Dear Chair French, BP Exploration (Alaska) Inc. (BPXA), as the operator of the Prudhoe Bay Unit (PBU), respectfully requests that the commission administratively approve amendments described in this application to the referenced Conservation Orders. Each of these pools is one of the Satellites in the PBU. This administrative relief is sought under Rule 10 of CO 457 and its equivalent in the other referenced Conservation Orders. The amendments are proposed with the goal of bringing more efficiency to the management of these reservoirs through achieving as much rule consistency as possible, while still honoring the unique aspects of each pool. More consistent rules will also result in easier monitoring of compliance for the commission. The proposed changes to pressure survey requirements are in line with recent commission -approved changes to CO 341 F for the Prudhoe Oil Pool. Initial Well Testing Requirements The current pool rules for the five satellites require two well tests per month during the first three months of production. BPXA requests that the commission eliminate this requirement, as the five satellites are now well established fields and we see no continuing purpose served by requiring two well tests per month during the first three months of production. This change to initial well testing requirements will align pool Application for Administrative Approval Amendment of COs 457 AB, 471, 50513, 484A, 452 October 23, 2018 rules for the five satellites with how new wells are tested in the Prudhoe Oil Pool. Operating efficiency will also be improved with a consistent testing requirement at L and V Pads where Orion and Borealis production occurs at the same location as Prudhoe Oil Pool production, at Z Pad where Borealis and Prudhoe Oil Pool production both occur, at S Pad where Polaris, Aurora, and Prudhoe Oil Pool production occurs, and at W Pad where Polaris and Prudhoe Oil Pool both occur. Pressure Survey Requirements Rule 5a for the Aurora, Borealis, Orion, and Polaris Oil Pools requires that prior to regular production or injection, an initial pressure survey must be taken in each well. BPXA requests elimination of that rule for these pools as exists for the Prudhoe Oil Pool. In order to safely drill any new well, BPXA conducts a pore pressure fluid gradient study at the well's location to determine drilling mud weight; furthermore, during the course of drilling, an estimate of reservoir pressure is provided by responses from the reservoir itself. Additionally, greater ultimate recovery is encouraged by not requiring the operator to shut a well back in after initial clean-up to obtain an initial pressure that will not provide materially useful information before placing a new well on production. Such pressures may be acquired as part of obtaining the minimum requirement for a Representative Area (see below). The pool rules for the Aurora and Orion Oil Pools currently relate the required number of annual pressure surveys to the number of governmental sections in the pool, yet the pool rules for the other satellite pools, in the same reservoirs, do not contain this requirement. BPXA requests that all 5 satellite pools address pressure surveys on the same basis, by using the Representative Area for the purpose of determining the number of required pressure surveys. Representative Areas are bounded by significant faults. BPXA manages all Satellite Pools by Representative Area. The revised rule would ensure areal spread of pressure surveys across the Pools, where the existing Aurora regulations allow the same location to be surveyed many times over. The revised rule would also be consistent with the Prudhoe Oil Pool pressure survey Rule 6 which defines seven development areas; these are broadly equivalent to Satellite Representative Areas. Regarding what constitutes an acceptable pressure for reporting requirements, we request to modify the language in the Aurora, Borealis, Orion and Polaris rules by closely aligning with what is in CO 341F (Prudhoe Oil Pool), and permitting calculation of bottom -hole pressures from surface data for any wells on water injection. In terms of frequency of pressure surveys, BPXA proposes to move to a minimum of one per annum per Representative Area, provided the Representative Area contains active well(s). As for the Prudhoe Oil Pool, each year's ASR report will propose the minimum number of pressures that will be acquired per active Representative Area for the next plan year. BPXA proposes AOGCC have the ability to object to the proposed number within the first month after ASR submittal. 2 Application for Administrative Approval Amendment of COs 457 A/13, 471, 50513, 484A, 452 October 23, 2018 We also request revision of reporting of all pressure surveys in Aurora's rule 5e to remove the quarterly requirement and make it annual, thereby bringing conformity with the other satellite pools. These proposed amendments are shown in the following section and summarized in the table on page 8. Proposed Amendments to Rules Note: Use of [ ]'s means delete existing order word(s). Use of underline denotes proposed new text. Aurora Oil Pool (AOP Rule 4b. All wells must be tested a minimum of once per month. [All new Aurora wells must be tested a minimum of two times per month during the first three months of production.] The Commission may require more frequent or longer tests if the allocation quality deteriorates. Rule 5a. [Prior to regular production or injection, an initial pressure survey must be taken in each well.] Rule 5b. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in coniunction with the Annual Aurora Oil Pool Reservoir Surveillance Report by September 15 of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next plan year, and it will be subject to approval by the AOGCC by October 15 of that Year. These surveys are needed to effectively monitor reservoir pressure within the Aurora Oil Pool The minimum number of bottom - hole pressure surveys performed each year shall equal the number of [governmental sections] Representative Areas within the AOP that contain active wells. [A minimum of four such surveys shall be conducted each year in representative area of the AOP. Bottom -hole surveys conducted pursuant to paragraph "a" of this Rule may be used to fulfill the minimum requirement.] With reference to the attached map (Mapl), the AOP currently contains 5 Representative Areas: West of Crest, North of Crest, South East of Crest, Crest Area, South of Crest). Rule 5d. Transient p[P]ressure surveys obtained by a shut in buildup test [may be stabilized static pressure measurements at bottom -hole or extrapolated from surface (single phase fluid conditions),] an injection well pressure fall-off test, a multi -rate test[s], an interference test, drill stem tests, and open -hole formation tests are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for any well on water iniection. Other quantitative methods may be administratively approved by the AOGCC. Application for Administrative Approval Amendment of COs 457 A/B, 471, 505B, 484A, 452 October 23, 2018 Rule 5e. 'Data and results from all reservoir pressure monitoring tests on surveys must be reported to the Commission annually [quarterly] on Form 10-412, Reservoir Pressure Report. All data necessary for analysis of each survey need not be submitted with the Form 10-412, but shall be available for inspection by the Commission upon request." Borealis Oil Pool (BOP) Rule 4d. All wells must be tested a minimum of once per month. [All new Borealis wells must be tested a minimum of two times per month during the first three months of production.] The Commission may require more frequent or longer tests if the allocation quality deteriorates. Rule 5a. [Prior to regular production or injection, an initial pressure survey must be takin in each well.] Rule 5b. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in coniunction with the Annual Borealis Oil Pool Reservoir Surveillance Report by September 15 of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next plan year, and it will be subject to approval by the AOGCC by October 15 of that year. These surveys are needed to effectively monitor reservoir pressure within the Borealis Oil Pool The [Al minimum number of bottom -hole pressure [of four] surveys performed [shall be required] each year shall equal the number of [in] Representative Areas [of the Borealis Pool] within the BOP that contain active wells. JBottom-hole surveys in paragraph (d) may fulfill the minimum requirement.] Rule 5d. "Transient [P]pressure surveys obtained by a shut-in build up test, an injection well pressure fall-off test, a multi -rate test or an interference test are acceptable Calculation of bottom -hole pressures from surface data will be permitted for any well on water iniection. Other quantitative methods may be administratively approved by the AOGCC. [may be stabilized static pressure measurements at bottom -hole or extrapolated from surface (single phase service fluid conditions]), pressure fall-off, pressure buildup, multi -rate tests, drill stem tests, and open -hole formation tests.] With reference to the attached map (Map 1), the BOP currently contains 6 Representative Areas: North L -Pad, SW L -Pad, East V -Pad, North V -Pad, South V -Pad, Z -Pad. Orion Oil Pool (OOP) Rule 4d. All wells must be tested a minimum of once per month. [All new wells must be tested a minimum of two times per month during the first three months of production.] The Commission may require more frequent or longer tests if the allocation quality deteriorates. 4 Application for Administrative Approval Amendment of COs 457 A/B, 471, 505B, 484A, 452 October 23, 2018 Rule 5a. [Prior to regular production or injection, an initial pressure survey must be takin in each well.] Rule 5b. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in coniunction with the Annual Orion Oil Pool Reservoir Surveillance Report by September 15 of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next plan year, and it will be subject to approval by the AOGCC by October 15 of that year. These surveys are needed to effectively monitor reservoir pressure within the Orion Oil Pool The [A] minimum number [of one bottom - hole] pressure surveys performed [per producing governmental section] each year shall equal the number of Representative Areas within the OOP that contain active wells [be run annually. The surveys in part (a) of this rule may be used to fulfill the minimum requirements.] Rule 5d. Transient 1PIpressure surveys obtained by a shut-in build up test an injection well pressure fall-off test a multi -rate test or an interference test are acceptable Calculation of bottom -hole pressures from surface data will be permitted for any well on water iniection. Other quantitative methods may be administratively approved by the AOGCC. [may consist of be stabilized static pressure measurements at bottom -hole or extrapolated from surface (single phase service fluid conditions), pressure fall-off, pressure buildup, multi -rate tests, drill stem tests, and open -hole formation tests.] With reference to the attached map (Map 2) the OOP developed portion contains Representative Areas with active well(s) labeled 1, M, 2, 2A, 5S.. Orion representative Areas without at least one active production well are 6N, 6S, 9, 8, 4, 5N, 3A, 3N, 3S. Polaris Oil Pool (Sat -POP) Rule 4b. All wells must be tested a minimum of once per month. [All new Polaris wells must be tested a minimum of two times per month during the first three months of production.] The Commission may require more frequent or longer tests if the allocation quality deteriorates. Rule 5a. [Prior to regular production or injection, an initial pressure survey must be takin in each well.] Rule 5b. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in coniunction with the Annual Polaris Oil Pool Reservoir Surveillance Report by September 15 of each Year. This plan will contain the number and approximate location of pressure surveys anticipated for the next plan year, and it will be subject to approval by the AOGCC by October 15 of that Year. These surveys are needed to effectively monitor reservoir pressure within the Polaris Oil Pool The IA] minimum number of [two] pressure surveys performed [shall be taken] each year shall equal the number of Representative Areas within the Sat -POP that contain active wells [in the main area S/MPad North and the W -Pad \ Term Well -C reservoir compartments, and one reservoir 5 Application for Administrative Approval Amendment of COs 457 AIB, 471, 505B, 484A, 452 October 23, 2018 pressure each year in the remaining compartments when at least one Polaris production well has been completed in the respective compartments]. With reference to the attached map (Map 2), the POP -Sat currently contains four Representative Areas labeled S Pad N, S Pad S, W Pad N, W Pad S. Rule 5d. Transient [P]pressure surveys obtained by a shut-in build up test an iniection well pressure fall-off test, a multi -rate test or an interference test are acceptable Calculation of bottom -hole pressures from surface data will be permitted for any well on water iri ection. Other quantitative methods may be administratively approved by the AOGCC. [may be stabilized static pressure measurements at bottom -hole or extrapolated from surface (single phase fluid conditions), pressure fall-off, pressure buildup, multi -rate tests, drill stem tests, or open -hole formation tests.] Midnight Sun Oil Pool Rule 7d. All wells must be tested a minimum of once per month. [All new Midnight Sun wells must be tested a minimum of two times per month during the first three months of production.] The Commission may require more frequent or longer tests if the allocation quality deteriorates. Rule 8c. [Pressure surveys may consist of stabilized static pressure measurements at bottom -hole or extrapolated from surface, pressure fall-off, pressure buildup, multi -rate tests, drill stem tests, and open -hole formation tests.) Transient pressure survey obtained by a shut-in build up test, an infection well pressure fall-off test a multi -rate test or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for any well on water iniection Other quantitative methods may be administratively approved by the AOGCC. BPXA respectfully requests the commission rule on this request before by first quarter 2019, as July 1 is the beginning of a new plan year. It will be more efficient if these rules were in effect for the entirety of the next plan year. This submission was initiated after consulting with commission staff beginning in the summer of 2017. Implementation of these changes to the satellite pool rules will promote BPXA's ability to manage the reservoirs in support of a greater ultimate recovery of oil and gas. C. Application for Administrative Approval Amendment of COs 457 A/B, 471, 505B, 484A, 452 October 23, 2018 If the commission has any questions please contact Bill Bredar at William. bredarkbp. com (907) 564-5348. Sincerely, Katrina Garner West Area Manager Alaska Reservoir Development Attachments: Maps 1 and 2 (Public and Confidential versions) Cc: D. Sturgis, ExxonMobil Alaska, Production Inc. J. Farr, ExxonMobil Alaska, Production Inc. E. Reinbold, CPAI D. White, Chevron USA D. Roby, AOGCC 7 N d Q Q Q cun.m mMtmwn.a 'cP..m ooW CO Ru4110 C1wy. grylleCNrM.I iti4/mmINM11NIlmoplM MepalM mYlmwn111W..b � MewrWm.a l.NPnNW lh.pn.p gYrowrm+.r 11u4.le CA :Iles wMr� aI.W MMW W., hmprr. q.r Y..r 10.r Owbm NOb h.4ur1 MW .p QYw 11W .bputl(. 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WNl( 1pr rpp.l{m1ylrY Yea nom wrx<OXA nwn Any VltlArf\' AI4q AA MmIn41. an � evM1lM l,frrrgYlrmlrll l:8lm IMIIMIYMYIrM VYYw WYN Ny(141r1 •w,Pa w,mx n vYl.r v 1 mY Sl dMrmale M exnrNmrn <wrryyrinrenl Wa1{a 2 • LL -123 L-124 __ai • -118 L-1 12 North L -Pad •L-119 • L-117 L -L-101 0L-120 • -114L-115• L -114A 1- • •L-103 L-1 -100 L-101 SW L -Pad \ ® -110 ,_�L-1.1A V-103 t= \f 120 108 V-12 East V -Pad 0 -107•V-102 V OOV-106A \ • North V -Pad 101 V1-104 V 105•V-171 0-1 3• •V• •V-100 V-112 0-109 •V -115L V - South V -Pad • V. • 01 -112 Z -Pad •Z-100 Z-102 Z-103 Z-108 N j J Represenative Areas by Aurora Borealis Kuparuk LEGEND a — — --- Kuparuk Represenative Areas (Approximate) S-111 Aurora (West of Crest, North of Crest, South • ----------------------------------- East of Crest, Crest Area, South of Crest) 5-119 • o Q Borealis (NL -Pad, SWL-Pad, EV -Pad, NV -Pad, 9-1 5-102L S SV -Pad, Z -Pad) •S-107 9.102 North • - 2 Pools West S-1 2•0f Crest West of Crest •5-121 M Aurora S -114A •5-103 • 5-100 S 03• S-104 0 Borealis • • -31A S -105 Participating Areas S� A 5-108 S-02 A0 •5-1108 5-113 S- 20 AURORA L1 • S 01• • S-115 S -1112S-11121-1 S-109 • Ar� • o -...- BOREALIS .rest S-112 S-123 i 1 5-118 g I j Prudhoe Bay Unit 7 • South Sout 5.13 • Pert Midpoint oTCrest• • Eastof S-125 Pools S- 6A 5.1280 • Crest 129 A —m: -135 0 Aurora Q Borealis _•S 1 0 Miles Coordinate System: NAD 1927 StatePlane Alaska 4 SIPS 5D04 Projection: Transverse Mercalor Datum: North American 1927 Data Sources: Well, Units, Coastline maintained by 3PXA Cartography. Be Exploration Alasl 90D E. Benson BIW Anchorage, AK MAP 1 Represenative Areas by Orion / Polaris Schrader Bluff LEGEND Schrader Bluff Represenative Areas (Approximate) Orion (1, 1A, 2,2A, 2AS; 3A, 3S, 3N, 4, 5N, 5S, 6N, 6S, 8, 9) O Polaris (SPadN, SPadS, WPadN, WPadS) Pool Q Polaris Q Orion Participating Areas ORION POLARIS Prudhoe Bay Unit • Pert Midpoint OA Faults OA Depth (ft TVDss) High :-3100 Miles Coordinate System: I NAD 1927 StatePlane Alaska 4 FIPS 5004 Projection. Transverse Mercator Datum: North American 1927 Data Sources: Well, Units, Coastline maintained by BPXA Cartography. P Exploration Alaska 900 E. Benson BW Anchorage, AK MAP 2 Represenative Areas by Orion / Polaris Schrader Bluff LEGEND Schrader Bluff Represenative Areas (Approximate) Orion (1, 1A, 2, 2A, 2AS, 3A, 3S, 3N, 4, 5N, 5S, 6N, 6S, 8, 9) O Polaris (SPadN, SPadS, WPadN, WPadS) Pool Q Polaris Q Orion Participating Areas ORION POLARIS Prudhoe Bay Unit s Perf Midpoint o Miles Coordinate System: NAD 1927 Slate Plane Alaska 4 FPS 5004 Projection: Transverse Mercator Datum: Norm American 1927 Data Sources: Well, Units, Coastline maintained by BPXA Cartography. Exploration Alaska 93e E. Benson BIW Anchorage, AK MAP 2 by RECEIVED NOV O 4 2015 A000 BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 November 2, 2015 Cathy Foerster Commission Chair Alaska Oil & Gas Conservation Commission 333 West 71h Avenue, Suite 100 Anchorage, AK 99501 Re: Request for Administrative Waiver of Monthly Reporting of Daily Production Allocation Data Dear Chair Foerster, BP Exploration (Alaska) Inc., as the Operator of the Prudhoe Bay Unit, respectfully requests that the Commission administratively waive the requirement in the following Conservation Orders (CO) Pool Rules, for monthly reports and files containing daily production allocation data: Schrader Bluff Oil Pool - CO 505B Rule 4f Aurora Oil Pool - CO 457B Rule 4e Prudhoe Oil Pool — CO 341 F Rule 18d Borealis Oil Pool - CO 471 Rule 4g Midnight Sun Oil Pool - CO 452 Rule 7d Polaris Oil Pool - CO 484 Rule 4d Put Fiver Oil Pool - CO 559 Rule 4f Raven Oil Pool - CO 570 Rule 6d Niakuk Oil Pool -43 — CO 32913.003 Rule 4b BP will continue to collect the daily production allocation data and will provide the data to the Commission at any time upon request. BP will also continue to submit required monthly production data to the Commission through the 10-405 forms. We simply seek relief from the cost and burden of preparing the reports on a monthly basis. We have attempted to include in this request all Prudhoe Bay Unit oil pool Conservation Orders that contain a requirement for monthly reporting of daily Request for AOGCC Administrative Waiver November 2, 2015 Page 2 allocation data. If the Commission is aware of additional Conservation Orders containing this requirement, BP respectfully requests the opportunity to add them to this request. Please direct any questions you may have to the undersigned or to Caroline Bajsarowicz at 907-564-4314, Caroline.Bajsarowicz@bp.com. Sincerely, 40 r , A L ," Diane Richmond Performance and Data Management Lead Alaska Reservoir Development, BPXA 564-4136 Carlisle, Samantha J (DOA) From: Roby, David S (DOA) Sent: Wednesday, December 30, 2015 2:53 PM To: Carlisle, Samantha J (DOA) Subject: FW: Monthly Reporting of Daily Production Allocation Data Sorry I forgot to forward this sooner. Dave Roby (907) 793-1232 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 Dave Roby at (907)793-1232 or dave.robv@alaska.gov. From: Richmond, Diane M [mailto:Diane. Richmond@bp.com] Sent: Wednesday, December 16, 2015 2:05 PM To: Roby, David S (DOA) Cc: Sorrell, Aaron L; Bajsarowicz, Caroline J Subject: RE: Monthly Reporting of Daily Production Allocation Data Dave, Thanks for your note. Actually you are correct in that we want to waive the first part of Rule 4 which was Rule 6 in C0329B. BP as operator is asking for a waiver of the monthly report and file(s) containing daily allocation data, daily test data, results of geochemical analysis and results of production logs used for purposes of allocation. However, we will continue to report volumes on Form 10-405. 6. The operator shall submit a monthly report and file(s) containing daily allocation data, daily test data, results of geochemical analysis and results of production logs used for purposes of allocation. Volumes reported on Form 10-405 in accordance with 20 AAC 25.230 (b) must break out Sag River Undefined Oil Pool and Niakuk Oil Pool allocated production within NK-43. Let me know if you need additional information. Thanks Diane From: Roby, David S (DOA) [mailto:dave.robyalaska.gov] Sent: Tuesday, December 15, 2015 6:11 PM To: Richmond, Diane M Cc: Sorrell, Aaron L; Bajsarowicz, Caroline J Subject: RE: Monthly Reporting of Daily Production Allocation Data Diane and/or Caroline, I'm putting the finishing touches on the admin approval for this request and 1 have a question for you. In the request you asking us to waive Rule 4b in CO 329B.003. However the way I read this order there is no 4b. CO 32913.003 states that Rule 6 (which dealt with reporting results during the pilot test) of CO 329b is to be renumbered as Rule 4, but Rule 6 in CO 329B does not contain a part b. I just want to clarify what you actually want waived in this order. I presume it is the entirety of C0329B.003 Rule 4. Please confirm this or let me know if it is just a portion of that rule that you want waive and if so which portion. Below are links to the orders. http://doa.alaska.gov/ogc/orders/co/co300 399/co329b-3.pdf http://doa.alaska.gov/ogc/orders/co/co300 399/co329b.pdf Regards, Dave Roby (907) 793-1.232 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 offhe 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 Dave Roby at (907)793-1232 or dave.robv@olaska.aov. From: Richmond, Diane M [ma iIto: Diane. Richmond (-0bp.com] Sent: Thursday, December 03, 2015 10:20 AM To: Roby, David S (DOA) Cc: Sorrell, Aaron L; Bajsarowicz, Caroline J Subject: RE: Monthly Reporting of Daily Production Allocation Data Thanks Dave. We will go ahead and complete the report. From: Roby, David S (DOA) [ma iIto: dave.roby@alaska.gov] Sent: Thursday, December 03, 2015 10:15 AM To: Richmond, Diane M Cc: Sorrell, Aaron L; Bajsarowicz, Caroline ] Subject: RE: Monthly Reporting of Daily Production Allocation Data Diane, Working on your request was actually on my to do list for today. That said, we won't have a quorum of commissioners until the week of the 13`h, so it's unlikely an official action will be taken until that time. While I don't expect there to be any issues with approving your request I cannot guarantee what the commissioners might say/decide, so to be safe you should probably go ahead and complete the report. Regards, Dave Roby (907) 793-1232 CONFIDENTIALITY NOTICE: This e-rnail 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 Dave Roby at (907)793-1232 or dave.roby@alaska.aov. From: Richmond, Diane M[ma iIto: Diane. Richmond Cabbp.com] Sent: Thursday, December 03, 2015 8:55 AM To: Roby, David S (DOA) Cc: Sorrell, Aaron L; Bajsarowicz, Caroline J Subject: Monthly Reporting of Daily Production Allocation Data Dave, We are getting ready to prepare the Monthly State Satellites production report. Before completing this report, I wanted to understand the status of our Request for Administrative Waiver of Monthly Reporting of Daily Production Allocation Data sent to the AOGCC on Nov 2, 2015. Should we complete this report for the month of November to stay in compliance? Thanks for all of your help as we look to streamline, but also stay compliant with AOGCC orders. Diane Diane M. Richmond BP AK Reservoir Development Compliance SPA 907-564-4136 907-440-0835 (Cell) ~3 Yage 1 of 2 Colombie, Jody J (DOA) From: Roby, David S (DOA) Sent: Wednesday, October 21, 2009 9:47 AM To: knelson@petroleumnews.com Cc: Colombie, Jody J (DOA) Subject: RE: question on Orion application Kristen According to the records we publish on our website the L-233 injection was permitted on September 23 and the L-203 hexalateral producer was permitted on September 30th. Neither well has been completed as of yet. Dave Roby (907)793-1232 From: Kristen Nelson [mailto:knelson@petroleumnews.com] Sent: Wednesday, October 21, 2009 9:33 AM To: Roby, David S (DOA) Subject: RE: question on Orion application Dave-thank you; I have looked at the DOG decision ... I was hoping for an update on drilling plans, as in looking through drilling permits I can't find that the injection well they talked about drilling into the expansion acreage (ADL 390067) was ever drilled, but they just got permits for the hexalateral they talked about earlier with bottomholes to the south and west of 390067 ... Kristen From: Roby, David S (DOA) [mailto:dave.roby@alaska.gov] Sent: Wednesday, October 21, 2009 9:20 AM To: knelson@petroleumnews.com Cc: Colombie, Jody J (DOA) Subject: RE: question on Orion application Kristen I have a call into BPXA regarding Attachment 4 but haven't heard back from them yet. I will let you know what I find out as soon as I hear back from BPXA and will scan and send any non-confidential portions of Attachment 4 to you after I get clarification from BPXA. In the meantime, Attachment 4 is a copy of something BPXA submitted to the DNR Division of Oil and Gas so you may try asking them for a copy. Incase you don't have it yet, here is a link to the DOG's decision to expand the Prudhoe Bay Unit and defer expansion of the Orion Participating Area until more well data is available. h_ttp 1/www dog.dnr.state.ak.us/oil/p.rograms/units/.2009/pbu-orion_expa.n..sion_decisio. n_021809p...d...f Regards, Dave Roby (907)793-1232 From: Kristen Nelson [mailto:knelson@petroleumnews.com] Sent: Wednesday, October 21, 2009 9:02 AM To: Roby, David S (DOA) Subject: question on Orion application 10/27/2009 . ~ Page 2 of "Z Dave Jody referred me to you with question on the Orion pool rules amendment application. Attachment 4 was not noted as confidential on the attachment list, but Jody said the pages were marked confidential-she said the commission had to check back with BP on that attachment. Do you know yet if it is really confidential? It's the amended Orion plan of development and operations; I'd really like to see that if it's a public document. Jody e-mailed me the rest of the non-confidential application yesterday; if the plan is a public document I could really use it today, thanks, Kristen Kristen Nelson Petroleum News (907) 245-5553 knelson@petroleumnews.com 10/27/2009 Page 1 of 1 Colombie, Jody J (DOA) __ From: Roby, David S (DOA) Sent: Wednesday, October 21, 2009 9:20 AM To: knelson@petroleumnews.com Cc: Colombie, Jody J (DOA) Subject: RE: question on Orion application Kristen I have a call into BPXA regarding Attachment 4 but haven't heard back from them yet. I will let you know what I find out as soon as I hear back from BPXA and will scan and send any non-confidential portions of Attachment 4 to you after I get clarification from BPXA. In the meantime, Attachment 4 is a copy of something BPXA submitted to the DNR Division of Oil and Gas so you may try asking them for a copy. In case you don't have it yet, here is a link to the DOG's decision to expand the Prudhoe Bay Unit and defer expansion of the Orion Participating Area until more well data is available. http://www dog.dnr.state ak u..s..../oil/pro..grams/units/2009/pbu-orion_expansion_d. ecision_02180...9.p.d.f Regards, Dave Roby (907)793-1232 From: Kristen Nelson [mailto:knelson@petroleumnews.com] Sent: Wednesday, October 21, 2009 9:02 AM To: Roby, David S (DOA) Subject: question on Orion application Dave Jody referred me to you with question on the Orion pool rules amendment application. Attachment 4 was not noted as confidential on the attachment list, but Jody said the pages were marked confidential-she said the commission had to check back with BP on that attachment. Do you know yet if it is really confidential? It's the amended Orion plan of development and operations; I'd really like to see that if it's a public document. Jody e-mailed me the rest of the non-confidential application yesterday; if the plan is a public document I could really use it today, thanks, Kristen Kristen Nelson Petroleum News (907) 245-5553 knelson@petroleumnews.com 10/27/2009 "ft'L r STATE OF ALASKA NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING ORDER INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE A O_03014012 /`1 SEE BOTTOM FOR INVOICE ADDRESS F R AOGCC Ste 100 333 W 7th Ave AGENCY CONTACT Jod Colombie DATE OF A.O. October 20, 2009 ° M , Anchorage, AK 99501 907-793-1238 PHONE - PcN DATES ADVERTISEMENT REQUIRED: o Anchorage Daily News PO Box 149001 Anchora e AK 99514 g ~ October 22, 2009 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Advertisement to be published was e-mailed Type of Advertisement Legal® ^ Display Classif ied ^Other (Specify) SEE ATTACHED SEND INVOICE IN TRIPLICATE TO AOGCC, 333 W. 7th Ave., Suite 100 Anchora e AK 99501 PAGE 1 OF 2 PAGES TOTAL OF ALL PAGES$ REF TYPE NUMBER AMOUNT DATE COMMENTS 1 VEN z A>to 0291 0 FIN AMOUNT SY CC PGM LC ACCT FY NMR 01ST LIQ ~ 10 02140100 73451 2 REQUISITIONE BY: DIVISION APPROVAL: 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM • • Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Docket #s CO-09-23 and AIO-09-17; The June 30, 2009, application of BP Exploration (Alaska) Inc. to expand the Schrader Bluff Oil Pool, Orion Development Area, as currently defined in Conservation Order SOSA and Area Injection Order 26A, by adding the following lands: T12N, R11E, Umiat Meridian (UM), Sec. 14: S/2 S/2 T12N, R11E, UM, Sec. 23: All T12N, R11E, UM, Sec. 24: SW/4, SW/4NW/4 all within the North Slope Borough, Second Judicial District, State of Alaska. The Commission has tentatively scheduled a public hearing on this matter for December 1, 2009 at 9:00 a.m. at the Commission. To request that the hearing be held, a written request must be filed by 4:30 p.m. on November 9, 2009. If a request is not timely filed, the Commission may consider the issuance of an order without a hearing. To learn if the Commission will hold a hearing, call 907-793-1221 after November 16, 2009. Written comments regarding the application may be submitted to the Commission, at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on November 23, 2009, except that, if a hearing is held, comments must be received no later than the conclusion of the hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, ca11907-793-1221 by November 25, 2009. Daniel T. Seamount, Jr. Chair STOF0330 #703940 $156.04 AFFIDAVIT OF PUBLICATION STATE OF ALASKA THIRD JUDICIAL DISTRICT Shane Drew being first duly sworn on oath deposes and says that he/she is a representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on October 22, 2009 and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. S ignec}~ ~/ `{JLI~ C'7Y~f.~T' Subscribed and sworn to before me this ~ day of ~) ~ 20 '~` `~j' ' ~., Nota ~~n~n~ 'F~tr ~Vis~ ®® ~, s~tc ora~ ias`kk~ ~", ~: DIY QOM ISS~~N EXPtRE~ ~; 9 ®1 Notlce of Public Heaiing STATE OB ALASKA Alaska Oil and Gas Conservatlon Commission Re: `' Docket #s CO-09-23 and A10-09r1Z; The June 30, 2009, application of BP Exploration (Alaska) Inc. to exppand the Schrader Bluff Oil Pool, Orion Development Area, as currently defined in Conservation Order 505A and'Area~ln~ection Order 26A'; by adding the following-lands- T12N; R11E, Umiat Meridran NM), Sec. 14: S/2 Sl2 T12N, R11E, UM, Sec. 23: All T12N, R11E, UM, Sec. 24:SW/4, SW/4NW14 all within the North Slope Borough, Second Judicia6 District, State of Alaska. The Commission has tentatively scheduled a public fiea~ing on this matter for December 1, 2009 at 9:00 a.m. at the Commission. To request that the hearing be held, a written request must be filed by 4:30 p.m. do November 9, 2009. If a request is not timely filed, the Commission may consider the issuance of an order without a hearing. ToJearn if the Commission will hold a hearing, call. 407-793-1221 after November 16, 2009. Written comments regarding the application may be submitted to the Commission, at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Comments must be received no Later than 4:30 p.m. bn November 23, 2009, except that, if a hearing is held, comments must be received no later than. the conclusion of the hearing. lf, because of a disability, special accommodations may be needed to commeht or attend the hearing, call 407-793-1221 by Novernber25, 2009. Daniel T. 5eamount, Jr. chair A0-03014012 Published: October 22, 209 Yage 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, October 20, 2009 2:29 PM To: Legal Ads Anchorage Daily News Subject: Public Notice Orion Expansion Attachments: Ad Order ADN.doc; Orion expansion.doc Thank you Jody J. Colombie Special Assiru~nt Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 (907)793-1221 (phone] (907j2?6-?542 fc~v) 10/20/2009 • • STATE OF ALASKA ( NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED /f, O_03014012 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF !1 ORDER ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM FOR INVOICE ADDRESS F AOGCC AGENCY CONTACT DATE OF A.O. R 333 West 7th Avenue. Suite 100 ° Anchnrage. AK 9951 PHONE PCN M 907-793-1238 - DATES ADVERTISEMENT REQUIRED: o Anchorage Daily News PO Box 149001 Anchorage, AK 99514 October 22, 2009 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Account # STOF0330 United states of America State of AFFIDAVIT OF PUBLICATION REMINDER 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 2009, and thereafter for consecutive days, the last publication appearing on the day of , 2009, 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 2009, Notary public for state of My commission expires _ . Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, October 20, 2009 2:30 PM To: Ballantine, Tab A (LAW); 'Aaron Gluzman'; caunderwood@marathonoil.com; 'Dale Hoffman'; Frederic Grenier; 'Gary Orr'; Jerome Eggemeyer; 'Joe Longo'; 'Lamont Frazer'; Marc Kuck; 'Mary Aschoff; Maurizio Grandi; P Bates; Richard Garrard; 'Sandra Lemke'; 'Scott Nash'; 'Steve Virant'; 'Wayne Wooster'; 'Willem Vollenbrock'; 'William Van Dyke'; Woolf, Wendy C (DNR); 'Anna Raff; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Bowen Roberts'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'Cande.Brandow'; 'carol smyth'; 'Charles O'Donnell'; Chris Gay; 'Cliff Posey'; 'Dan Bross'; 'daps ; 'Daryl J. Kleppin'; 'David Brown'; 'David Gorney'; David House; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; Deborah Jones; Decker, Paul L (DNR); 'doug_schultre'; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil ; 'Gregg Nady'; 'gspfoff; 'Hank Alford'; 'Harry Engel'; 'jah'; 'Janet D. Platt'; 'jejones'; 'Jerry Brady'; 'Jerry McCutcheon" 'Jim Arlington'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katr'; 'Jon Goltz'; Joseph Darrigo; 'Julie Houle'; 'Karl Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; knelson@petroleumnews.com; 'Krissell Crandall'; 'Kristin Elowe'; 'Laura Silliphant'; 'mail=akpratts@acsalaska.net'; 'mail=fours@mtaonline.net'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marquerite kremer'; Melanie Brown; 'Michael Nelson'; 'Mike Bill'; 'Mike Jacobs'; 'Mike Mason'; 'Mike) Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro'; 'Paul Winslow'; 'peter Contreras'; Rader, Matthew W (DNR); Raj Nanvaan; 'Randall Kanady'; 'Randy L. Skillern'; 'Rob McWhorter'; rob.g.dragnich@exxonmobil.com; 'Robert Campbell'; 'Robert Province'; 'Rudy Brueggeman'; 'Sandra Pierce'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'Susan Roberts° 'tablerk'; 'Tamers Sheffield'; 'Ted Rockwell'; 'Temple Davidson'; Teresa Imm; 'Terrie Hubble'; 'Thor Cutler'; 'Todd Durkee'; Tony Hopfinger; 'trmjr1'; 'Von Hutchins'; 'Walter Featherly'; Williamson, Mary J (DNR); Aubert, Winton G (DOA); Brooks, Phoebe; Crisp, John H (DOA); Darlene Ramirez; Davies, Stephen F (DOA); Fleckenstein, Robert J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Mahnken, Christine R (DOA); Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA) Subject: Public Notice -Orion Expansion Attachments: Public Notice Schrader Bluff-Orion dev.pdf Jody J. Colombie S/~ecia! iLssistant :1 /asks Oil and Gas Conservation Contntission 333 I~'est 7th Avenue, Barite 100 Anchorage, AK 99501 (907)793-1221 (phone) ~90~~?~6-~5a2 (fazj 10/20/2009 ! i Mary Jones David McCaleb Cindi Walker 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 Mark Wedman Schlumberger Ciri Halliburton Drilling and Measurements Land Department 6900 Arctic Blvd. 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99502 Anchorage, AK 99503 Anchorage, AK 99503 Baker Oil Tools Ivan Gillian Jill Schneider 4730 Business Park Blvd., #44 9649 Musket Bell Cr.#5 US Geological Survey Anchorage, AK 99503 Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow, AK 99723 a,iQ y, ~o~ -ol ~~ • ~ by June 30, 2009 Commissioners Alaska Oil and Gas Conservation Commission 333 West 7~' Avenue, Suite 100 Anchorage, AK 99501 BP Exploration (Alaska) Inc. 900 E. Benson Boulevard Anchorage, Alaska 99508 DELIVERED BY HAND RE: Amendments to Orion Pool Rules and Area Injection Order -Dear Commissioners: Enclosed for your review and action is the Prudhoe Bay Unit Working Interest Owners' application for amendments to Conservation Order 505 and Area Injection Order 26, the Orion Pool Rules and the Area Injection Order for the Orion reservoir. These amendments are necessary because BP Exploration (Alaska), Inc. (BPXA), as Orion Operator and Unit Operator, has applied to the Department of Natural Resources to expand the Prudhoe Bay Unit. Accordingly, BPXA hereby petitions the Commission to amend the above referenced rules as necessary to accommodate this expansion. BPXA requests that Section #1 of Conservation Order 505 and Section #2 of Area Injection Order 26 be amended as follows to reflect the revised legal description describing the expanded area affected by these orders. Umiat Meridian Township Range, UM Lease Sections T12N-R11E ADL 390067 Sec.14: S/2S/2 Sec.23: All Sec.24: SW/4, SW/4NW/4 Information in support of these amendments is attached. Please maintain as confidential those certain attachments attached and labeled "CONFIDENTIAL" in accord with 20 AAC 25.537(b). 1 • • Should you have any questions or require additional information, please do not hesitate to contact me at (907) 564-5749. Sincerely, 1 /~ Diane Richmond Prudhoe Bay Western Region Resource Manager Attachments: Attachment 1 Location Map of the OPA/PBU Expansion Area Attachment 2 Lease Map of Expanded OPA/PBU Attachment 3 Amended Orion Participations and Tract Allocations Attachment 4 Amended Orion Plan of Development and Operations Attachment 5 Orion Typelog Well L-216 -Confidential Attachment 6 OBd Structure Map -Confidential Attachment 7a Dip Cross-Section -Confidential Attachment 7b Strike Cross-Section -Confidential Attachment 8a Orion Seismic Dip Cross-Section A-A'-Confidential Attachment 8b Orion Seismic Strike Cross-Section B-B'- Confidential Attachment 8c Seismic Line Index Map -Confidential Attachment 9a Net Oil Pore Foot Thickness (NB Interval) -Confidential Attachment 9b Net Oil Pore Foot Thickness (OA Interval) -Confidential Attachment 9c Net Oil Pore Foot Thickness (OBa Interval) -Confidential Attachment 9d Net Oil Pore Foot Thickness (OBb Interval) -Confidential Attachment 9e Net Oil Pore Foot Thickness (OBc Interval) -Confidential Attachment 9f Net Oil Pore Foot Thickness (OBd Interval) -Confidential Attachment 10 Composite Net Pay Thickness Map -Confidential Attachment I 1 Reservoir Compartment Map -Confidential Attachment 12a Orion Oil-Water Contact Data (OA Sand) -Confidential Attachment 12b Orion Oil-Water Contact Data (Upper OBa) -Confidential Attachment 12c Orion Oil-Water Contact Data (Lower OBa Sand) -Confidential Attachment 12d Orion Oil-Water Contact Data (OBb Sand) -Confidential Attachment 12e Orion Oil-Water Contact Data (OBc Sand) -Confidential Attachment 12f Orion Oil-Water Contact Data (OBd Sand) -Confidential Attachment 12g Orion Oil-Water Contact Data (Nb Sand) -Confidential Attachment 13 Orion Tops and Rock Properties -Confidential Attachment 14 Orion Polygon lA Production History -Confidential Attachment 15 Index to Digital Data Attachment 16 Orion Well L-203 and Unit Expansion Acreage Context -Confidential Attachment 17 Notice of Intent to Enlarge OPA/PBU 2 • cc: Mike Utsler, BPXA Sherri Gould, BPXA Claire Sullivan, BPXA John Cyr, BPXA Jeff Spatz, BPXA Gary Benson, BPXA Gabriela Boersner, ExxonMobil Craig Haymes, ExxonMobil Mark Pohler, ExxonMobil Joe Falcone, ConocoPhillips Erec Isaacson, ConocoPhillips Jon Goltz, ConocoPhillips Glenn Frederick, Chevron Dave Roby, AOGCC Cammy Taylor, DO&G Judy Buono, BPXA Don Ince, ConocoPhillips Dan Kruse, ConocoPhillips Mark Menghini, ConocoPhillips Hank Bensmiller, ExxonMobil Steve Krohn, ExxonMobil Greg Peters, ExxonMobil Cheryl Wiewiorowsky, BPXA Alan Mitchell, BPXA • 3 • Attachment 1- Location Map of the OPA/PBU Expansion Area i c~ ~~~ - , a~ r.. ~;~. u~ ~ a ~,a --- _, ~ ~ ~ _~ . '~ I r - Q ~ a o ,~ OD W ~'' a ~~ t_"~~ O -- :,~. ~ m 1- ~ ~ ~ -~_( ~ -~ .. r; ---- -. ~ ~ ~ ~, I ~ ~ a m _' ___.. ~ I - f. '~ 1 •, ,_a.. a i ~, i -- -~-- i __ ~ . E ~' " ~ ~~ ~ x w i _ m a 4i O E'' n f' - _._ __.. -- ' ~J I~ .. 411lC1N~ s/ Attachment 1 -Location Map of the OPA/PBU Expansion Area Amendment to Orion Pool Rules and Area Injection Order 4 • • Attachment 2 -Lease Map of Expanded OPA/PBU i - { ` ~; _ i I __ _ __r ~_ ~_-_ ~ -=- - - I i \ ti it _ ~ ~- I ~ - 'r I ~,1 i ~_ i ----';--I-- ~ ~ i--~- - ~ .' ~ ~_~--' i .~ I -- --- - ----- - i~ ~ '~ I' _____.. AUL~4744fi ADL047447 ADL390067 ~I ~ I ~ - -- -1 • .~ _ _. ~-- ~. L naD ADLO 1'449 AULG28239~ ADL028238 _ _ -, ~~V PAD - -- _~_ . -_- j `~`_ _ _ -- -- ~~- t I `'~...',__J . ADL0~8241 --~D~Q28~`-•~~LC~i7450 r „.' _ \t ~ ``- -- -/ .//~ ' ~~, ~ _ 1~'F ~ ~ Z ?AU~ +r i II ~ , _._ -- ~ ---- ~~-- ADLO 8245 ~ ~~ ~~1DLGZ8262 I ~ _, ;" ~ ; I _ ~ '~ ~ I ----?I I ~ -.. ._ __ - ~ m i I I ~ P9„ON^_ 55\' VNT 3D.R/R~AY ~. --- oruea !=L HUN9EP. u ax ~ LKk.n :al r -- S i ~~ t ~ ti r/ ~l tiV PAf~ .,,~" AD~.C282fi3 - ---- _ - ADLC~7453 ADL017452 --I--- -, i -- -- ---- -- - --I- r ~ 1 _ yC 1 ~ :~'.•.... Attachment 2 -Lease Map of Expanded OPA/PBU 5 Amendment to Orion Pool Rules and Area Injection Order • • Attachment 3 -Amended Orion Participations and Tract Allocations Tract Lease T & R Section: Description Acres Royalty - - - - - - - -Tract Ownership %- - - - - - - - - - Tract Participation BPXA CPAI ExxonMobi Chevron % 13 39006 12N-11E Sec 14: S/2S/2 1,000 16.66667 26.360567% 36.076746% 36.402687% 1.160000% 0.117% Sec 23: All Sec 24: SW/4, SW/4NW/4 14 04744 12N-1IE Sec 16: S/2,NW4, 1,840 12.5 26.360567% 36.076746% 36.402687% 1.160000% 7.234% S/2NE4 Sec 21: All Sec 22: All 15 04744 12N-11E Sec 17: All 2,448 12.5 26.360567% 36.076746% 36.402687% 1.160000% 22.438% Sec 18: All Sec 19: All Sec 20: All 16 02563 12N-10E Sec 13: All. 960 12.5 26.360567% 36.076746% 36.402687% 1.160000% 10.012% Sec 24: N/2 17 04744 12N-11E Sec 29: N/2, SE/4 553.5 12.5 26.360567% 36.076746% 36.402687% 1.160000% 1.404% Sec 30: N/2NE/4 18 02823 12N-11E Sec 27: All 2,320 12.5 26.360567% 36.076746% 36.402687% 1.160000% 12.504% Sec 28: All Sec 33: E/2, N/2NW/4 Sec 34: All 19 028238 12N-11E Sec 25: SW/4 2,080 , 12.5 26.360567% 36.076746% 36.402687% 1.160000% 10.991% Sec 26: All Sec 35: All Sec 36: All 49 47450 11N-12E Sec 7: All 1,076 12.5 26.360567% 36.076746% 36.402687% 1.160000% 1.798% Sec 8: NW/4, S/2 50 28240 11N-11E Sec l: All 2,320 12.5 26.360567% 36.076746% 36.402687% 1.160000% 16.067% Sec 2: All Sec 11: E/2, E/2NW/4 Sec 12: All 51 28241 11N-11E Sec 3: N/2, N/2S/2 720 12.5 26.360567% 36.076746% 36.402687% 1.160000% 1.927% Sec 4: NE/4, N/2SE/4 53 28245 11N-11E Sec 13: N/2, SE/4 640 12.5 26.360567% 36.076746% 36.402687% 1.160000% 1.002% Sec 14: E/2NE/4 Sec 24: E/2NE/4 54 28262 11N-12E Sec 17: All 1,764.875 12.5 26.360567% 36.076746% 36.402687% 1.160000% 7.737% Sec 18: All Sec 19: N/2, SE/4, N/2SW/4 54A 28262 11N-12E Sec 20: All 640 12.5 26.360567% 36.076746% 36.402687% 1.160000% 4.388% 55 28263 11N-12E Sec 16: SW/4, 240 12.5 26.360567% 36.076746% 36.402687% 1.160000% 0.008% S/2NW/4 SSA 28263 11N-12E Sec 21: SW/4, 360 12.5 26.360567% 36.076746% 36.402687% 1.160000% 0.602% S/2NW4, NW/4NW/4, W/2SE/4 80 47452 11N-12E Sec 28: W/2, W/2E/2 480 12.5 26.360567% 36.076746% 36.402687% 1.160000% 0.379% 81 47453 11N-12E Sec 29: N/2, N/2SE/4 400 12.5 26.360567% 36.076746% 36.402687% 1.160000% 1.392% Attachment 3 -Amended Orion Participations and Tract Allocations Amendment to Orion Pool Rules and Area Injection Order • • Total = 19,842.375 acres BPXA = BP Exploration (Alaska), Inc. CPAI = ConocoPhillips Alaska, Inc. ExxonMobil = ExxonMobil Alaska Production Inc. Chevron =Chevron U.S.A. Inc. Attachment 3 -Amended Orion Participations and Tract Allocations 7 Amendment to Orion Pool Rules and Area Injection Order ~ • Attachment 4 -Amended Orion Plan of Development and Operations 2009 PLAN OF DEVELOPMENT (5TH) ORION PARTICIPATING AREA PRUDHOE BAY UNIT JANUARY 1, 2009 -DECEMBER 31, 2009 Attachment 4 -Amended Orion Plan of Development and Operations Amendment to Orion Pool Rules and Area Injection Order n u TABLE OF CONTENTS 1.0 INTRODUCTION 2.0 FIELD STATUS 3.0 SUMMARY OF ACTIVITIES 4.0 PLAN OF DEVELOPMENT 4.1 RESERVOIR MANAGEMENT 4.2 DEVELOPMENT DRILLING 4.3 PRODUCTION ALLOCATION 4.4 PROJECTS LIST OF ATTACHMENTS ATTACHMENT 1 : ORION WELL LOCATION MAP • ATTACHMENT 2: TABLE OF ORION WELLS, BY SPUD DATE ATTACHMENT 3: TABLE OF ORION / BOREALIS COMMINGLED INJECTION WELLS, BY SPUD DATE ATTACHMENT 4: CHART OF ORION PRODUCTION AND INJECTION HISTORY ATTACHMENT 5: ORION SCHRADER BLUFF TOP OBA DEPTH STRUCTURE MAP (CONFIDENTIAL ATTACHMENT 6: L-219 WELL PROFILE (CONFIDENTIAL ATTACHMENT 7: PRESSURE AND FLUID DATA FROM L-219 MDT (CONFIDENTIAL Attachment 4 -Amended Orion Plan of Development and Operations 9 Amendment to Orion Pool Rules and Area Injection Order • • 1.0 INTRODUCTION As provided for in the Findings and Decision for formation of the Orion Participating Area, BP Exploration Alaska, Inc. (BPXA) as operator of the Prudhoe Bay Unit is providing this annual update to the Orion Plan of Development. This document provides an overview of the projects and operations that comprise the development program for the Orion Participating Area (OPA). The OPA development plan is consistent with the current business climate and understanding of the Orion reservoir. Changes in business conditions, new insights into the reservoir or other new information could alter the timing, scope, or feasibility of one or more of the plan components. 2.0 FIELD STATUS Development of the Orion Reservoir has entailed phased drilling of 36 producers and injectors from L-, V- and Z-Pads. Initial drilling commenced in December, 2001 with production startup in April, 2002. Orion production is commingled with IPA and Borealis production and flows to GC-2 for processing. Water injection started in December 2003. The pattern waterflood is designed to increase recovery and provide pressure support in the Orion reservoir. Tertiary recovery, utilizing miscible gas for WAG (Water-Alternating-Gas injection) was initiated in October 2006. Central and southern areas of Orion will be developed using existing and expanded infrastructure at L-Pad, V-Pad, W-Pad, and Z-Pad. Northern Orion may be developed in the future from a proposed I-Pad. Additional surface facilities and pipelines maybe added to support future Orion production, injection and artificial lift requirements. Listed below is additional information regarding the Orion field as of May, 2008: • 17 wells drilled at L-Pad - 5 oil producers: 4 on-line - 12 water injectors: 9 on-line - (1 commingled Orion/Borealis water injector utilized) • 18 wells drilled at V-Pad - 4 oil producers: all on-line - 14 water injectors: 11 on-line. • 1 well drilled at Z-Pad - 1 water injector: SI until offset producer is drilled The average rates since the previous report are: • Oil Production Rate: 10,100 BOPD Attachment 4 -Amended Orion Plan of Development and Operations 10 Amendment to Orion Pool Rules and Area Injection Order ~ ~ • Gas Oil Ratio • Water Production Rate • Water Injection Rate: • Gas Injection Rate: 1404 SCF/BO 1500 BWPD 6300 BWPD 5.4 MMSCFD As of April 30, 2008 the cumulative totals are: • Cumulative Oil Production: 12.7 MMSTBO • Cumulative Gas Production: 13.1 BSCF • Cumulative Water Production: 1.1 MMSTB • Cumulative Water Injection: 10.2 MMSTB • Cumulative Gas Injection 2.6 BCF 3.0 SUMMARY OF ACTIVITIES Summarized below are significant activities at Orion since the previous report (July 31, 2007 through Apri130, 2008): • Spudded the L-205 hexa-lateral with coring operations underway at report time. • Drilled 4 vertical injection wells; V-220, V-223, L-221, L-220, to provide pressure support to existing and future Orion production wells. • Drilled the first high angle injection well, L-219. The tail of this well was drilled across the OWC in the OBd sand to enable data collection across the OWC. • Approval for an enhanced oil recovery project using Prudhoe Bay miscible injectant in Orion was granted by the Alaska Oil and Gas Conservation Commission on April 28, 2006 in Conservation Order SOSA. The first water-alternating-gas injection flood began in October, 2006. Currently, MI is being injected into 6 Orion wells, V-210, V-211, V- 212, V-214, V-215 and. V-218. • MI injection profiles have been run L-213, V-210, V-211, V-214 and V-216. This data will be used to calibrate models of the MI flood and adjust future injection strategy. Attachment 4 -Amended Orion Plan of Development and Operations 11 Amendment to Orion Pool Rules and Area Injection Order ~ • • Multi-zone injector V-2231 became the initial completion of an Orion well in the OBe sand. This injection interval will be sampled for future geochemical allocation of offset production. It will then be then be left SI until offset production is established in V-207. • Afield trial of multi-phase metering technology was performed on V-pad in 1Q 2008. Data from this trial is used to complete select phase engineering analysis for improvements in well testing on L and V pads. • Production heater installed at Z-pad with start-up in June, 2008. • GC2 D-bank modifications began in May 2008 for improved separation. • Two matrix bypass events (MBE) were identified during this reporting period: o An MBE was identified in V-222 in the OA sand on February 26, 2008 using the sandface gauge. Continued monitoring indicated that V-222 was in direct communication with V-202. Initial OA pressure in V-222 was 1285 psi. This may have indicated proximity to the original V-201 MBE or to another wormhole. o An MBE between V-216 and V-204 was suspected due to rapid MI breakthrough and confirmed with an interference test on March 22, 2008. Location of the MBE is in the OBa sand. Timing of the actual MBE is uncertain, but should be subsequent to installation of waterflood regulators in September of 2006. • Average producer uptime during the reporting period was 71 %. L-200 has been problematic, and is currently SI until the GC2 D-bank cleanout is complete. On-time for the other producers ranged from 74% to 87%. 4.0 PLAN OF DEVELOPMENT 4.1 RESERVOIR MANAGEMENT Orion is being developed with primary depletion and enhanced recovery. A MI flood is underway in Polygon 2. Water injection began in December 2003. Water rate is down since the last report reflecting injector swaps to MI. Individual well injection rates range from 300 to 1200 bwpd, or 1 to 3 MMSCFPD MI. MI injection commenced in October 2006 in the updip portion of Polygon 2. During the reporting period, several downdip injectors have been swapped to MI to test MI response in the lower quality oil near the OWC. The Orion Field is being developed with the emerging technology of multilateral production wells, typically supported by two to three vertical injectors per producer. Attachment 4 -Amended Orion Plan of Development and Operations 12 Amendment to Orion Pool Rules and Area Injection Order • • Some producers are choked back initially to manage reservoir pressure during early high- rate flush production. Currently, the Orion reservoir is being produced from six Schrader Bluff sands (Nb, 0A, OBa, OBb, OBc, & OBd). A lateral in V-207 is planned to establish offtake from a seventh zone, the OBe. Because of the variability in sand and oil quality between zones, reservoir surveillance work has been undertaken to develop a better understanding of the reservoir performance by zone and design a development program to maximize recovery. For producers, production allocation efforts focus on using geochemical fingerprinting analysis on produced oil. This technique is in use world-wide and has proven useful in the Schrader Bluff fields, KRU West Sak and Milne Point. The complex nature of multilateral designs makes conventional production logging for zonal contribution difficult, so this fingerprinting technique is very useful. For injectors, efforts include injection logging and zonal control using flow regulators. Work is ongoing to balance waterflood pattern voidage and provide pressure support. Field pressure measurements are collected per AOGCC CO 585.5 and submitted with the annual surveillance report. 4.2 DEVELOPMENT DRILLING Five development wells (one high angle injector and 4 vertical injectors) were drilled during the reporting period and are listed in Attachment 2. An updated Orion structure map incorporating recent drilling is included in confidential Attachment 5. Downhole MDT fluid sampling was performed on L-219. A well profile depicting the MDT sample points is shown in confidential Attachment 6 and the MDT pressure and APT gravity data results are shown in confidential Attachment 7. N and O sand coring is in progress on multilateral producer L-205. Up to seven additional development wells (2 producers and 5 injectors) from L-Pad and V-Pad are being evaluated and maybe drilled through 2009. Drilling of additional high angle injectors V-224, and V-227 will depend on successful coiled tubing deployment of waterflood regulators in L-219. Approximate coordinates for the 2008-2009 drilling program under evaluation are listed below, and shown in Attachment 1. Also included are wells listed in the previous 2008 POD. Wellname X Y Z(tvdss)ft Comments Drilling Date L-219i 589,370 5,982,360 -4475 Top OBa Spud 12/2007 V-220i 593,390 5,974,715 -4480 Spud 2/2008 V-223i 593,960 5,968,915 -4430 Spud 3/2008 Attachment 4 -Amended Orion Plan of Development and Operations 13 Amendment to Orion Pool Rules and Area Injection Order • • L-2211 583,485 5,975,650 -4200 Spud 3/2008 L-220i 582,870 5,977,435 -4200 Spud 4/2008 L-205. 580,925 5,978,010 -4130 Heel Target (OA leg) Spud 5/2008 581,950 5,973,640 -4170 Toe Target (OA leg) V-207 595,120 5,973,080 -4610 Heel Target (OBa leg) July 2008 594,450 5,975,940 -4625 Toe Target (OBa leg) V-219i 597,584 5,969,888 -4825 Top OBd V-224i 596,274 5,974,494 -4933 TD L-203 588,610 5,984,235 -4650 Heel Target (OBd leg) 584,373 5,987,016 -4588 Toe Target (OBd leg) V-227i 595,813 5,976,447 -4875 TD V-225i 590,374 5,969,155 -4771 TD 4.3 PRODUCTION ALLOCATION Orion production allocation is being performed according to the PBU Western Satellite Production Metering Plan. Allocation relies on performance curves to determine the daily theoretical production from each well. The GC-2 allocation factor is applied to adjust the total Orion production. At least one well test per month is used to check the performance curves and to verify system performance. No NGLs are allocated to Orion. 4.4 PROJECTS Schrader Bluff viscous oil production has affected GC-2 operation by a decrease in the inlet separation temperature, an increase in composite oil viscosity, an increase in the amount of solids entering the plant, and the introduction of overly stable emulsion layers formed by the mixture of formation fluids, solids, and oil-based drilling mud. Changes to GC-2 operations to deal with these challenges have been made in three areas: heat, chemicals, and hygiene. Added heat reduces viscosities, improves oil /water separation, and reduces required in- vessel residence times. Heat is added in the form of hotter, light-oil-related oil and water production with additional process heat. Plant testing has resulted in a new regimen of chemicals to break emulsions. Improving plant hygiene involves keeping vessels free of solids to maximize in-vessel residence times which allow fluids to separate properly. To help accomplish this, upgrades to the B-Train slug catcher and oil dehydrator were completed during the September, 2005 GC-2 shutdown. Upgrades to the D-Train slug catcher and oil dehydrator are in progress. Emulsion handling upgrades are also in progress. Attachment 4 -Amended Orion Plan of Development and Operations 14 Amendment to Orion Pool Rules and Area Injection Order • • A production heater has been installed on Z-Pad, which will handle the oil from L- and V- Pads and raise the temperature of the colder viscous oil to improve separation performance. The heater was put in service on 6/4/2008. Minor gravel pad expansion may be needed to support the drilling program discussed in Section 4.2. Define Engineering has been completed for the potential installation of a gas partial processing plant (GPP) at Z-Pad. Gravel installation for GPP has been completed at Z- Pad. The GPP would increase oil production by expansion of existing gas handling capacity and of pipeline infrastructure in the western region. The long-lead materials order for the GPP turbine compressor unit was placed in July 2007. The GPP sea-lift is currently estimated for 2011, with a startup in 2012. I-Pad Define Engineering has been completed based on a new surface location. This resolves the geotechnical concerns raised by the discovery of the ice lens last year. Development of I-pad is currently under evaluation. Attachment 4 -Amended Orion Plan of Development and Operations 15 Amendment to Orion Pool Rules and Area Injection Order • ATTACHMENT 1- ORION WELL LOCATION MAP / ~~ 4` nSn • Orion Poolllnjection 16 Area Well Base Map I~l Prudhoe Bay nl oun ary 7 Red outline -orlon Poolllnjection Area Orion Production Well Jr ~c203 Completed Pre-S/tAD7 ! Orion Production Well Completed between ~,~"` '~=208 811 N7 and 511 N8 Orion Production Well Planned for Completion f 4207 between 5/1108 and 12!31108 Orion Injection Well . 4203 Completed Pre-8!1107 Orion Injection Well Completed between -~~~ `•'=211 811 N7 and 511 ~D8 Orion Injection Well Planned for 5l1AD8to ~ 4223 12!31108 Orion ParticipatingRrea "''" Boundary PnlAhna Rau iln it Rnllnriaru ~ .` -its ~ to +ra a s z ~~ .uonmso ur4' !-Imwna MAIrl IILlO! ® II ~If1 M~111 1 to l 77 7 alow+a+ _nw ..~ Attachment 4 -Amended Orion Plan of Development and Operations 16 Amendment to Orion Pool Rules and Area Injection Order • • ATTACHMENT 2 - ORION PARTICIPATING AREA WELLS, BY SPUD DATE Orion Participating Area Wells, by Spud Date Well Name API No. Spud Date Well Type V-201 500292305400 1.2/25/2001 Suspended V-202 500292315300 5/4/2003 Horizontal Oil Producer V-202L1 500292315360 11/26/2003 Horizontal Oil Producer V-202L2 500292315361 12/3/2003 Horizontal Oil Producer L-210 500292318700 12/31/2003 Vertical Water Injector L-200 500292319100 1/18/2004 Horizontal Oil Producer L-200L1 500292319160 2/6/2004 Horizontal Oil Producer L-200L2 500292319161 2/14/2004 Horizontal Oil Producer L-211 500292319700 2/24/2004 Vertical Water Injector L-201 500292320200 3/17/2004 Horizontal Oil Producer L-201L1 500292320260 4/6/2004 Horizontal Oil Producer L-201L2 500292320261 4/14/2004 Horizontal Oil Producer L-201L3 500292320262 4/23/2004 Horizontal Oil Producer L-216 500292320600 5/2/2004 Vertical Water Injector V-213 500292321300 7/12/2004 Vertical Water Injector V-204 500292321700 7/29/2004 Horizontal Oil Producer V-204L1 500292321760 8/13/2004 Horizontal Oil Producer V-204L2 500292321761 8/19/2004 Horizontal Oil Producer V-204L3 500292321762 8/27/2004 Horizontal Oil Producer V-216 500292321600 9/2/2004 Vertical Water Injector Z-210 500292322600 10/10/2004 Vertical Water Injector V-210 500292323100 10/31/2004 Vertical Wag Injector V-211 500292323200 11/12/2004 Vertical Wag Injector V-221 500292324600 2/22/2005 Vertical Water Injector L-212 500292325200 3/23/2005 Vertical Water Injector L-202 500292322900 6/5/2005 Horizontal Oil Producer L-202L1 500292322960 6/20/2005 Horizontal Oil Producer L-202L2 500292322961 6/27/2005 Horizontal Oil Producer L-202L3 500292322962 7/3/2005 Horizontal Oil Producer L-218 500292327200 8/24/05 Vertical Water Injector L-215 50029232744 09/08/05 Vertical Water Injector L-250 500292328100 10/24/05 Horizontal Oil Producer L-250L1 500292328160 11/12/05 Horizontal Oil Producer L-250L2 500292628161 11/21/05 Horizontal Oil Producer V-214 500292327500 10/29/05 Vertical Wag Injector V-212 500292327900 12/02/05 Vertical Wag Injector V-203 500292328500 01/08/06 Horizontal Oil Producer V-203L1 500292328560 01/08/06 Horizontal Oil Producer V-203L2 500292328561 01/08/06 Horizontal Oil Producer V-203L3 500292328562 01/08/06 Horizontal Oil Producer V-203L4 500292328563 01/08/06 Horizontal Oil Producer L-214A 500292325801 03/13/06 Vertical Water Injector Attachment 4 -Amended Orion Plan of Development and Operations 17 Amendment to Orion Pool Rules and Area Injection Order r~ LJ • I-100PB1 500292324570 03/20/06 Appraisal plug-back L-213 500292330800 04/19/06 Vertical Wag Injector L-217 500292331200 07/03/06 Vertical Water Injector L-204 500292331400 07/16/06 Horizontal Oil Producer L-204L1 500292331460 8/3/06 Horizontal Oil Producer L-204L2 500292331461 8/9/06 Horizontal Oil Producer L-204L3 500292331462 8/16/06 Horizontal Oil Producer L-204L4 500292331463 8/25/06 Horizontal Oil Producer V-217 500292333400 1/8/07 Vertical Water Injector V-205 500292333800 1/19/07 Horizontal Oil Producer V-205L1 500292333860 2/1/07 Horizontal Oil Producer V-205L2 500292333861 2/10/07 Horizontal Oil Producer V-218 500292335000 4/1/07 Vertical Wag Injector V-215 500292335100 4/16/07 Vertical Wag Injector V-222 500292335700 6/4/07 Vertical Water Injector L-219 500292337600 12/12/07 Vertical Water Injector V-220 500292338300 2/24/08 Vertical Water Injector V-223 500292338400 2/24/08 Vertical Water Injector L-221 500292338500 3/28/08 Vertical Water Injector L-220 500292338700 4/10/08 Vertical Water Injector L-205 500292338800 4/15/08 Drilling Attachment 4 -Amended Orion Plan of Development and Operations 18 Amendment to Orion Pool Rules and Area Injection Order • • ATTACHMENT 3 - ORION/BOREALIS COMMINGLED INJECTION WELLS, BY SPUD DATE Orion Participating Area Commingled Orion /Borealis Injection Wells, by Spud Date Well Name API No. Spud Date Well Type L-117 500292303900 9/13/2001 Vertical Water Injector L-103 500292310100 7/26/2002 Vertical Water Injector V-105 500292309700 8/27/2002 Vertical Water Injector Attachment 4 -Amended Orion Plan of Development and Operations 19 Amendment to Orion Pool Rules and Area Injection Order • • ATTACHMENT 4 - ORION PRODUCTION AND INJECTION HISTORY 16000 O ~ 14000 ii v N 12000 m r ~ _ 10000 _ m ~ ~ .~ y 8000 m ~ m V 6000 .. a O 4000 aIS ~`~, 2000 3 0 00' 00' 00' 00 00 00 O~' Off` Off` Off` Off` O~ O~ ~~ J~ Q~ J~ G~ ac J~ Q~ ~~ Q~ Q~ ate c ) O ) ) P O P P )a O ) P ) 100% 90% 80% 70% 60% 50% 3 40% 30% 20 10% 0% 00 O~ OHO OHO OHO OHO 01 01 01 01 00 00 °~ te Q~ J~ °~. ac Q~ J~ °~. ate Q~ ~~ O )a Q ) O ) P ) O ) P ) Attachment 4 -Amended Orion Plan of Development and Operations 20 Amendment to Orion Pool Rules and Area Injection Order • ~ Attachment 15 -Index to Digital Data 1 zmap grid for Nb Structure 2 zmap grid for OBc Structure 3 zmap grid for OBd Structure 4 fault centerline file Attachment 15 -Index to Digital Data 50 Amendment to Orion Pool Rules and Area Injection Order • Attachment 17- Notice of Intent by • BP Exploration (Alaska) Inc. 900 E. Benson Boulevard Anchorage, Alaska 99508 VIA CERTIFIED MAIL- RETURN RECEIPT REQUESTED June 18, 2008 Kevin Banks Division of Oil and Gas Department of Natural Resources 550 West 7~' Avenue, Suite 800 Anchorage, AK 99501 RE: Notice of Intent to Enlarge the Prudhoe Bay Unit to Encompass Expansion to the Orion Participating Area Dear Mr. Banks: Pursuant to Section 9.1 of the Prudhoe Bay Unit Agreement and Section 1.003 of the Prudhoe Bay Unit Operating Agreement, BP Exploration (Alaska), Inc., acting in its capacity as Operator of the Prudhoe Bay Unit, hereby gives notice of the proposed enlargement of the Prudhoe Bay Unit Area to encompass proposed expansion to the Orion Participating Area. The proposed effective date for the enlargements is the first day of the calendar month following the date of the final approval of the enlargements by the Alaska Department of Natural Resources. The leases or portion of leases contemplated for inclusion in the Prudhoe Bay Unit Area ("Enlargement Areas") are listed on Exhibit A and depicted on Exhibit B, both of which are attached hereto and incorporated herein. As provided by Section 9.1 of the Prudhoe Bay Unit Agreement, the tracts included in the Enlargement Areas have been reasonably determined to be within the Orion Reservoir, a portion of which is within the Prudhoe Bay Unit Area. The inclusion of the Enlargement Areas in the Prudhoe Bay Unit Area will enable the timely development of the Orion Reservoir by facilitating the sharing of existing Prudhoe Bay Unit facilities. The expansion of the Prudhoe Bay Unit Area to include the Enlargement Areas will promote conservation of natural resources, promote the prevention of economic and physical waste, and will protect all parties, including the State of Alaska. The expansion also provides for the protection of Attachment 17 -Notice of Intent 64 Amendment to Orion Pool Rules and Area Injection Order. • • the environment through planned development that optimizes the use of existing facilities and prevents unnecessary duplication of facilities. Pursuant to Section 9.1(b) of the Prudhoe Bay Unit Agreement, any interested party may file with the Unit Operator written objections, and reasons therefore, to the proposed enlargements within thirty (30) days of the date this Notice was mailed. If you have any comments or questions, please contact Sherri Gould at (907) 564-5492. Sincerely, Mike Utsler Greater Prudhoe Bay Business Unit Leader Attachments: Exhibit A- PBU Enlargement Area to Encompass the Orion Participating Area Expansion Exhibit B- Map of Proposed PBU Enlargement Area CC: Sherri Gould, BPXA Claire Sullivan, BPXA John Cyr, BPXA Lewis Westwick, BPXA Gary Benson, BPXA Gwendolyn Dawson, ExxonMobil Craig Haymes, ExxonMobil via certified mail Mark Pohler, ExxonMobil Joe Falcone, ConocoPhillips Erec Isaacson, ConocoPhillips via certified mail Jon Goltz, ConocoPhillips Glenn Frederick, Chevron via certified mail Jane Williamson, AOGCC Cammy Taylor, DO&G Judy Buono, BPXA Don Ince, ConocoPhillips Mark Menghini, ConocoPhillips Hank Bensmiller, ExxonMobil Scott Cooley, ExxonMobil Sonny Rix, ExxonMobil Dan Kruse, ConocoPhillips Frank Paskvan, BPXA Michael Wortham, BPXA Attachment 17 -Notice of Intent 65 Amendment to Orion Pool Rules and Area Injection Order • • EXHIBIT A PBU ENLARGEMENT AREA TO ENCOMPASS THE ORION PARTICIPATING AREA EXPANSION I. Orion Participating Area/PBU Expa Tract Desc~tion Acreage 13 T12N-R11E 1000 Section 23 (all) Section 14: S/2S/2 Section 24: SW/4, SW/4NW/4 nsion -1000 Acres ADL Royalty WIO%~ 390067 16.66667% EM 36.402687% CPAI 36.076746% BPXA 26.360567% Chevron 1.160000% Legend EM - ExxonMobil Production Alaska, Inc. CPAI - ConocoPhillips Alaska, Inc. BPXA - BP Exploration (Alaska), Inc. Chevron- Chevron U.S.A. Inc. ' BPXA, CPAI, EM, and Chevron now own the above referenced Orion PA/PBU expansion acreage in ADL 390067 in aligned PBU ownership decimals indicated above. Attachment 17 -Notice of Intent 66 Amendment to Orion Pool Rules and Area Injection Order ~ ~' ~ ~ a~ ~ ~ ~~-Y r-. O J 0 I O O ~ ~. b ~ O O ~ ~ a 0 R. ., J ,, _ 1 9 Z9011L1 375133 3751 ^ .',9:15118 I .~d ..,. a4, h _J r /-I- i .I\II ~;i:r,N~ l~~"'. ~'~JC1~5C- - r ____.,._ .. .- __- { i° ri- _ i~ ~ ~ 160 nc. 2625G-2 1 I - __ _;:1')2:5_ _. 04744b-2 G474-' .590477 ]. -- JJJ ___ _ ~ ac ~.. ! J2~r,?7 i 39'209 ~ ~ 'J s7dU .ac. ..^.i744h/ 244K Ac. 047447 760 ~c. -1~oot-7 ~ 02B2~6 ~~20 Ac 047444 S?tail ac C474ri9 1225 A-. X28275 17nU A.. ,, ~- I I _. 04744 II 1 -- --=~ -_ - I 1-1 I ; Ly. ~_ i 1 g ~ ,47443-2 ~ gG8 Rr, gltl .59 :SoG ~Ac 02B2_'d 25fi0 dr..::7t17S9 ! 1459 .4.: 02t3278 i!+6'J :v:~ 028257 I y.~s0 :.c. 029279 dc.07627tf i 25G~ b(. C. _._. ____ __ I Il i / , ~_~. i ~ f ~- -. ---- - - ;~ _y1 I t Y ~ yam'/ -- _ - - ~ 1 ~. C~7H?42 i-.~29241 25G•0 :u:.'S2A~40\ 7yliEYAc~r5~7p^~,: 24F,9 Ac. ~2~G' , 2`vF0 %c. 2a60 A°. ~ 69 ,ac:. ~- t 25~i0 Ac :: __ I I ~ i~ yt82A4 29245 , ~1 0~9~.„~G~1~_128Cr A- a - - - - za2as-2 '42fl2s2-1~2926z-~. I ~„ 1u:. 'd4C Ar, s1.". ar_. 07B28J-2 1`230 Aa 047451 ;7ycd• Ac. 02&143 .490 ac, 02$284 25f,1: Ac. 1 ~A2i3'24.5 ~ ~G28244-~~ ~..._.o.>. s7~^ , I~ 4a2 ti I ~ c. 6 u' I 1 2 ~n~lc:: 1 I I ~ _.~:%.~ Ear -rr an_n_.~• ,02824E-2 ,e~.~,zaa , InrnsE.: r•EU r>.,uausm a u.:J.w e'~Il11aAi.1 •.'JYI'Ir I i I 01m2[! ALL NI7.13E~ - .E.lf EL`V\EKiY 1:1~I:lh I :. Ofi~;P1 Pi II 1 I i -!P'di9:91 i ~~ C28~49 j -~ i 5s 249' Ac. ^4 /<Eit 256U 047454 I 47454-2 6920 BP EXPLORATION (ALASKA) INC. ~ A~ Exhibit B Prudhoe Bay Unit Proposed PBU Expansion Areas DATE: SCALE: E7cF1~#t ~, t 41:,rch 2408 1:110,00') 9 b "~ b O d~ ~~ ~x C ,.., C'' ~ ~~ CrJ r • Pages 21 through 49 Pages 51 through 63 of applicants application are held confidential