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Home My WebLink AboutCO 452CONSERVATION ORDER 452 1. February 17, 2000 Letter from Groth (Arco) to Christensen Midnight Sun Pool Rules hearing request 2. February 25, 2000 Notice of Public Hearing, affidavits 3. March 21, 2000 Sign in sheet 4. March 27, 2000 Arco request to reschedule hearing 5. April 1, 2000 Notice of Cancellation of Public Hearing 6. May 3, 2000 Phillips Midnight Sun Oil Pool, Pool Rules and AIO application 7. June 13, 2000 Sign in sheet for hearing 8. June 21, 2000 Sign in sheet for hearing 9. June 21, 2000 Transcript of Hearing 10. ---------------- Misc e-mails 11. August 31, 2006 Prudhoe Bay Filed – Annual Surveillance Reporting requirements to AOGCC 12. November 2, 2015 Request for admin approval for waiver of monthly reporting of daily production allocation data (CO 452.003) 13. October 23, 2018 Request for admin approval for conforming PBU Satellite Pool Rules for Consistency (CO 452.004) 14. February 24, 2020 BPXA Request to amend CO 492 rule 3(a) and 6(a) (co452.005) 15. May 21, 2020 Notice of Hearing and mailing 16. ----------------- Emails 17. December 17, 2021 Request for admin approval to amend CO 452 by repealing Rule 3 (CO 452.006) ORDERS THE STATE - °1ALAS-KA GOVERNOR NIM DUNLEAVY Mr. Oliver Sternicki 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 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 Mor: 907.279.1433 Fax: 907.276.7542 www.00gcc.oiaska.gov Request to amend normal operating limit for inner annulus pressure for non Lisburne development area wells from 2,000 psig to 2,100 psig and to add an administrative approval clause to Conservation Order No. 492 Prudhoe Bay Unit All Oil Pools Dear Mr. Stemicki: By application dated February 24, 2020, Hilcorp North Slope, LLC' (HNS) 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. ' 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.002,311 B.004,317B.003,329A.002,341I.002,345.003, 452.005,457B.006,471.009, 484A.005,50513.003,559A.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 prig 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 I In the current CO 457B, 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.002,311B.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 31111 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 10-01A 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.002,311B.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 f. Except as otherwise approved by the Commission under (d) or (e) of this rule, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree (1) that the inner annulus pressure at operating temperature will be below 2000 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 Digitally Mignied ed by Pr Dale: 2020.10 01 M. Price 133926-0600' Jeremy M. Price Chair, Commissioner Daniel T. Digitally signed by Daniel T. Seamount Jr. Seamount, Jr. Date 2020,1001 1210B 46 Lentl Daniel T. Seamount, Jr Commissioner Digitally signed by Je55tE L. Jessie L. Chmielawskl Chmlelowski Date: 3030.10.01 1]53:0)-08'00' Jessie L. Chmielowski Commissioner As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration 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 maybe appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO. 452.006 December 21, 2021 Ms. Kyndall Carey Land Representative Hilcorp North Slope, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket Number: CO-21-025 Request for Administrative Approval to Amend Well Spacing for the Midnight Sun Oil Pool Prudhoe Bay Unit Dear Ms. Carey: By letter dated and received December 17, 2021, Hilcorp North Slope, LLC (Hilcorp) requested administrative approval to amend Rule 3 of Conservation Order No. 452 (CO 452) to remove the 80-acre well spacing requirement and allow for unrestricted interwell spacing for the Midnight Sun Oil Pool (MSOP). In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS Hilcorp’s request. CO 452 was issued on November 15, 2000. Since that time, drilling and completion practices have significantly advanced. Strict adherence to a rigid well spacing requirement can prevent smaller targets from being targeted and does not provide for wells to be placed for optimal development of the MSOP. Numerous pools in Alaska originally had rigid well spacing requirements, but over the years the spacing has been revised to eliminate the interwell spacing requirements while retaining the standoff restrictions from property lines to allow for optimal development of the pool while protecting the correlative rights of nearby landowners. Amending Rule 3 of CO 452 to eliminate the interwell spacing requirements while prohibiting wells from being completed within 500 feet of property lines where the owner or operator changes will allow for MSOP development to be optimized and correlative rights to be protected. CO 452.006 December 21, 2021 Page 2 of 2 Now therefore it is ordered that Rule 3 of CO 452 is repealed and replaced by the following: Rule 3 Well Spacing There shall be no well spacing restrictions within the Midnight Sun Oil Pool, except that no well shall be opened to production within 500 feet of a property line where ownership and landownership are not the same on both sides of the property line. DONE at Anchorage, Alaska and dated December 21, 2021. 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. Jeremy Price Digitally signed by Jeremy Price Date: 2021.12.21 13:50:29 -09'00' Dan Seamount Digitally signed by Dan Seamount Date: 2021.12.21 14:28:16 -09'00' From:Salazar, Grace (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] AOGCC Conservation Order Nos. 457B.008, 452.006 and 484A.006 Date:Tuesday, December 21, 2021 3:00:39 PM Attachments:CO 457B.008.pdf CO 452.006.pdf CO 484A.006.pdf The Alaska Oil and Gas Conservation Commission has issued the attached Conservation Orders granting Hilcorp North Slope, LLC’s request for amendments to well spacing requirements in the Aurora Oil Pool (CO 457, Rule 1), Midnight Sun Oil Pool (CO 452, Rule 3), and the Polaris Oil Pool (CO 484, Rule 1). Grace ____________________________________ 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@list.state.ak.us You subscribed as: grace.salazar@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/grace.salazar%40alaska.gov AOGCC 333 W 7th Avenue, Anchorage, AK 99501 TO: BERNIE KARL K&K RECLYCLING, INC. PO BOX 58055 FAIRBANKS, AK 99711 Mailed 12/21/21 gs INDEXES North Slope, LLC Kyndall Carey Land Representative 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone: 907/777-8386 Fax: 907/777-8301 kyndall.carey@hilcorp.com December 17, 2021 Jeremy Price, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 RE: Proposed Amendment to Conservation Order No. 452 (Prudhoe Bay Field Midnight Sun 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 approve1 an amendment to Conservation Order (“CO”) No. 452 (November 15, 2000) by repealing Rule 3 in its entirety and replacing it with the following language. Rule 3: Well Spacing There shall be no well spacing restrictions within the Midnight Sun 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. 452 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 Jeff Nelson at 907/777-8300. Sincerely, Kyndall Carey Land Representative Hilcorp North Slope, LLC cc: ConocoPhillips Alaska, Inc. ExxonMobil Alaska Production, Inc. Chevron U.S.A., Inc. Administrative Action is being requested pursuant to CO No. 452, Rule 13. By Samantha Carlisle at 9:34 am, Dec 17, 2021 'LJLWDOO\VLJQHGE\.\QGDOO&DUH\ '1FQ .\QGDOO&DUH\ RX 8VHUV 'DWH .\QGDOO&DUH\ From: Rixse, Melvin G (CED) Sent: Wednesday, June 10, 2020 2:27 PM To: Sternicki, Oliver R Cc: Colombie, Jody J (CED) Subject: FW: June 25 hearing to amend 4 CO's Attachments: CO -20-008 Public Hearing Notice.pdf, RE: CO -20-008 This is a clarification email to BPXA, Oliver Sternicki, that the AOGCC interpretation of any development well going through Lisburne Production Center, whetheron gas lift or natural flow, will be allowed 2500 psig sustained inner annulus pressure before reporting is required. CO -20-008 as written should be fine. We will then administratively amend the COs per the notice. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231) or (Melvi n. Rixse(a alaska eoJ. cc. Jody Colombie From: Colombie, JodyJ (CED) Sent: Wednesday, June 10, 20208:59 AM To: Chmielowski, Jessie LC (CED)<jessie.chmielowski(@alaska.aov> Cc: Rixse, Melvin G (CED) <melvin.rixse(@alaska.¢ov> Subject: RE: June 25 hearing to amend 4 CO's No one has requested a hearing Mel: Do you vote to vacate? Jody From: Chmielowski, Jessie L C (CED) <jessie.chmielowski@alaska eov> Sent: Wednesday, June 10, 2020 8:57 AM To: Colombie, Jody J (CED) <jody.colombie@alaska aov> Cc: Rixse, Melvin G (CED) <melvin.rixse(@alaska aov> 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 omnia, 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 sball 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 o - q bal wA0 a......"W. Sr. Well Integrity Engineer BP Exploration Alaska Cell: 1 (907) 350 0759 oliver.sternicki(a)bo com From: Rixse, Melvin G (CED) <melvin.rixse@alaska.gov> Sent: Friday, May 15, 20204:31 PM To: Sternicki, Oliver R <Oliver.Sternicki@bp.com> Subject: FW: CO -20-008 From: Colombie, Jody J (CED) <jodv.colombie(caalasl<a.eov> Sent: Friday, May 15, 2020 3:16 PM To: AOGCC Public—Notices <AOGCC Public Notices @list state ak us> Subject: [AOGCC_Public_Notices] CO -20-008 Docket Number: CO -20-008 Prudhoe Bay Field, All Pools .lodv J. Colomhie .Special Assistant Alaska Oil and Gets Conservation Commission 333 best 7)' Avenue Anchorage, AK 99501 (907) 793-1231 Direct (9(17) 276-7542 Fax List Name: AOGCC Public Notices@list state ak us You subscribed as: ryan.daniel(o)bp.com Unsubscribe at: http://list.state.ak.us/mailman/options/aogcc public notices/roan daniel%40bp com STATE OF ALASKA ADVERTISINGNOTICE ORDER TO PUBLISHER SUBMIT INVOICE SHOWING ADYERTISINGORDER NO., CERTIFIED AFFIDAVITOFPUBLICATION WITHATTACHEDCOPY OF ADVERSMENT. TI 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: W LEGAL DISPLAY F_ CLASSIFIED F OTHER (Specify below) DESCRIPTION PRICE CO -20-008 Initials of who prepared AO: Alaska Non -Taxable 92-600185 SUBMIT INVOICE SHOWING ADVERTISING ORDERNO., CERTTFIED AFFIDAVIT OF PUBLICATTON WITH ATTACHED COPY OF ADVERTTSMENTTO: AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Pae I of 1 Total of All Pages $ REF Type I Number Amount Date Cum,nents 1 PvN IVCO21795 2 AG AO -08-20-024 3 4 FW AMOUNT SY Act. Template PGM LGR Object FY DIST LIQ I 20 AOGCC 3046 20 2 3 4 5 Purch n u ri Title. Purchasing Authority's Signature Telephone Number .O.#and raoilving agency name must appear on all Invoices and documents relating to this purchase. 72 e state is registered for tax free transactions under Chapter 32, IRS code. Registration number 92-73-0006 K. Items are for the exclusive use of the state and of for resale. DISTRIBUTION: Division Fiscal/Original AO Copies: Publisher (faxed), Division Fiscal, Receiving Form: 02-901 Revised: 5/21/2020 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION Re: Docket Number: CO -20-008 Prudhoe Bay Field, All Pools BP Exploration Alaska, Inc., by application received February 24, 2020, requests the Alaska Oil and Gas Conservation Commission (AOGCC) revise Rule 3 of Conservation Orders 317, 505, 559 and 570 to include the following language: The operator shall notify the AOGCC within three working days after the operator identifies a development well as having (a) sustained inner annulus pressure that exceeds 2500 psig for wells with supplied gas lift pressure from the Lisburne Processing Center and 2100 prig for all other development wells, or (b) sustained outer annulus pressure that exceeds 1000 prig. 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 7s' Avenue, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on June 22, 2020, except that, if a hearing is held, comments must be received no later than the conclusion of the June 25, 2020 hearing. If, because of disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Jody Colombie, at (907) 793-1221, no later than June 20, 2020. Jeebmy M. Price Chair, Commissioner Bernie Karl K&K,Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 14 no, BP Exploration (Alaska) Inc.'` Attn: Well Integrity Coordinator, PRB-20 Post Office Box 196612, Anchorage, Alaska 99519-6612 February 24, 2020 Mr. Jeremy Price Alaska Oil and Gas Conservation Commission 333 West 7t' 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 b`o_�rd 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 lemm J/1]1X115 5/M., VW.0 5 9/IM, WIV.15 11/11/3015 1/6/:016 J/3'�XI:6 Me Figure 2- WOA Pad Gas Lift Header Pressure WOA Gas Lift Pressure L,aovm 3(1LID15 5/U3015 6/3p X110 9/9/3m5 9/]w." 1J/11/301, t(6/4016 E/ti'Nt6 pale —Dsps --Dsm —Dsm —D519 ql3 Ds n —Luna —ns voo x sad v vae aPw —sane -Duna v na W Ped XPW . sad . . STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501-3 192 Re: The APPLICATION OF ) Conservation Order No. 452 PHILLIPS Alaska, Inc. ("PHILLIPS") ) Prudhoe Bay Field for an order to establish pool rules for ) Midnight Sun Participating Area development of the Midnight Sun Oil Pool ) Midnight Sun Oil Pool in the Midnight Sun Participating Area, ) Prudhoe Bay Field, North Slope Alaska. ) November 15, 2000 IT APPEARING THAT: I. By letter dated February 17, 2000 and application dated May 3, 2000, Phillips Alaska, Inc. ("PHILLIPS") requested authorization from the Alaska Oil and Gas Conservation Commission ("Commission") to establish pool rules for continued production of the Midnight Sun Oil Pool. PHILLIPS provided supplemental information on June 12, 2000. 2. Notice of Public Hearing was published in the Anchorage Daily News on February 25, 2000, and a hearing was scheduled for April 4, 2000. On March 27,2000, PHILLIPS requested the hearing be rescheduled. On Aprill, 2000, a Notice of Cancellation of Public Hearing was published in the Anchorage Daily News. A second Notice of Public Hearing was published in the Anchorage Daily News on May 10,2000, and the hearing was rescheduled to June 13,2000. 3. A hearing concerning the applicant's request was convened in conformance with 20 AAC 25.540 at the Commission's offices, 3001 Porcupine Drive, Anchorage, Alaska 99501 on June 13,2000. Concurrently, the Commission heard testimony concerning proposed injection of fluids for enhanced recovery in the Midnight Sun Oil Pool. FINDINGS: 1. PHILLIPS presented testimony in support of an application for pool rules and area injection order for the proposed Midnight Sun Oil Pool ("MSOP") on June 13,2000. 2. The Midnight Sun Participating Area ("MSP A") is located within and adjacent to the Prudhoe Bay Unit ("PBV") on Alaska's North Slope. 3. Working interest owners are PHILLIPS, ExxonMobil Corporation and BP Exploration (Alaska) Inc. ("BPXA"). The State of Alaska is the surface owner. 4. The Commission approved the designation of BP Exploration (Alaska) Inc. ("BPXA") as sole operator of the PBU effective July 1,2000. 5. BPXA is the designated operator of all wells within one-quarter mile of the proposed area. 6. The MSOP is a name proposed to describe an accumulation of hydrocarbons trapped within the Kupamk Formation. This accumulation is located outside of the previously defined Kuparuk Oil Pool area within the PBV. The current, estimated limits of the MSOP lie within, and adjacent to, the PBD. 7. The MSOP was discovered in 1997 during the drilling of the Sambuca #1 well, later renamed the PBU E-100. This well encountered 100 feet of gross hydrocarbon volume, with 36 feet of gas above the oil column. Conservation Order No. 452 November 15, 2000 Page 2 . - 8. One delineation well, the Midnight Sun #1 (later renamed the PBU E-lOl) was drilled from E-pad in October 1998. 9. Well and seismic data have been used to characterize the accumulation within the MSOP. 10. The MSOP is defined as the accumulation of hydrocarbons that are common to, and which correlate with, the Kuparuk Formation accumulation in the PBU E-I00 well between 11,662 and 11,805 feet measured depth (MD). 11. Petrophysical log, conventional core, RFT, and production data have been used to determine the MSOP reservoir properties. 12. A trap of combined structural and stratigraphic elements delineates the MSOP. It is bounded to the north by the Sambuca fault, to the west by the Prudhoe Mid-Field fault, to the South by the Prudhoe- bounding fault system with an apparent stratigraphic pinch out to the east. 13. The MSOP is contained within the Kuparuk Formation of Lower Cretaceous age (153-115 million years before present). Within the participating area, the Kuparuk Fom1ation is stratigraphically complex, and is characterized by rapid changes in thickness, sedimentary facies and local diagenetic cementation. 14. The interval lies approximately 8,000 feet below sea level with a typical gross sand thickness of about 110 feet. 15. Within the MSOP, the Kuparuk Formation can be informally divided into lower and upper units. 16. The lmver Kuparuk unit is about 40 feet thick, and is subdivided into two lithologic intervals. The basal non-productive sandstone is approximately five feet thick, with a discontinuous distribution that contains abundant glauconite and minor detrital shale. The overlying unit is continuous, very fine to fine grained and quartz-rich reservoir-quality sandstone. 17. The upper unit ranges from 0 to 70 feet in thickness, and consists of poor to well sorted sandstone interbedded with minor amounts of muddy siltstone. The sandstones contain varying amounts of glauconite and siderite and are prone to reductions in porosity and permeability due to intergranular siderite cementation and compaction. 18. Mean porosity and permeability in the reservoir interval of the lower Kuparuk unit are 27.3% and 760 millidarcies, respectively. Average water saturation is 12.6% in the reservoir interval of the lower Kuparuk unit. 19. Mean porosity in the upper Kuparuk unit is 20.7% and mean permeability is 200 millidarcies. Average water saturation is 26.4% in the upper Kuparuk Fom1ation. 20. The estimated original oil in place ("OOIP") in the MSOP ranges from 40 to 60 MMBO. Total gas in place is estimated to be 100 to 130 bscf. Free gas volume associated with the gas cap is estimated to range between 60 and 80 bscf. 21. The MSOP gas-oil contact lies at a true vertical subsea depth of 8,010 feet, based on Repeat Formation Test data. No oil-water contact has been observed. 22. Heavy oil was encountered below a true vertical depth of 8, 107 feet in the PBU E-I 0 1 well. The areal extent of this heavy oil accumulation is uncertain. 23. MSOP crude oil properties were obtained from a recombined sample from the PBU E-101 well. API gravity of the oil is approximately 25.5 degrees, solution gas-oil ratio is 717 scf/stb, formation volume factor is 1.33 reservoir barrels per stock tank barrel and viscosity measures 1.68 cp at the reservoir bubble point pressure, 4045 psia. 24. Initial reservoir pressure is 4058 psia and temperature is 160 degrees at the reservoir datum of 8050 true vertical depth sub sea. Conservation Order No. 452 November 15, 2000 Page 3 e -- 25. The MSOP has low structural dip, good vertical permeability and contains a relatively large gas cap. 26. MSOP production started from the PBU E-IOO in October of 1998. Production from the well was restricted to mitigate gas coning and was shut-in to limit depletion. 27. The PBU E-1O 1 production was affected by gas under-running and has been restricted to 5000 BOPD. 28. Based on reservoir data evaluation and simulation studies, PHILLIPS has planned a three-well field with a midfield waterflood. The plan includes drilling one additional up structure producing well and converting one well to injection. 29. Recovery estimated from reservoir simulation of primary depletion is approximately 14% of the OOlP, about 6 to 8 MMBO. Estimates of incremental waterflood recovery ranges from 15 to 25% of the OOlP, or 10 to 15 MMBO, with 0.7 pore volumes of water injected. 30. Initial watertlood will begin third quarter 2000 with source water injection at E-Pad. Produced water from Gathering Center One (GCl) may supplement the flood at some point in the future. 31. PHILLIPS has requested minimum well spacing of 80 acres to allow flexibility in planning infill and/or peripheral wells. 32. PHILLIPS will measure initial reservoir pressure in producers and injectors. Periodic reservoir pressure measurements will be done to monitor reservoir performance. Other surveillance such as profile logs may be applied where multiple intervals are open for production or injection. 33. Casing and cement plans will adhere to 20 AAC 25.030 with designs based on performance factors to withstand permafrost and downhole conditions. 34. PHILLIPS proposes to commingle MSOP fluids with Ivishak Participating Area (IP A) fluids on the surface at E-Pad. Commingled fluids will be transferred to the GC 1 production facilities for processing and shipment to Pump Station One. 35. Initial production will be allocated to the MSOP on the basis of monthly well tests in IP A facilities as previously approved by the Commission. A new metering skid, to be installed, will continuously meter Midnight Sun production prior to commingling with IPA fluids. 36. A 15 kV power line from GCI to the Midnight Sun facilities at E-pad will provide power for the new Midnight Sun drill site equipment. CONCLUSIONS: 1. Pool rules for the development and delineation of the Midnight Sun Oil Pool are appropriate at this time. 2. Initial development will be conducted on leases within the Prudhoe Bay Unit. 3. Minimum well spacing of 80 acres will not cause waste, compromise ultimate recovery or jeopardize correlative rights. 4. Implementation of water injection will preserve reservoir energy and increase ultimate recovery from the pool by a significant amount. 5. Monitoring of reservoir performance by measurement of production and reservoir pressure on a regular basis will help to ensure proper management of the pool. 6. Commingling MSOP and IP A fluid at the surface is appropriate provided there are adequate well tests to assure accurate production allocation. Conservation Order No. 452 November 15, 2000 Page 4 e e NOW, THEREFORE, IT IS ORDERED THAT the following rules apply to the following affected area: Umiat Meridian T12N Tl2N R13E Rl4E Sec 25, S Yz; Sec 36, N Yz, SE 14, E Yz of SW 14 Sec 29, all; Sec 30, S Yz, S Yz ofNE 14, S Yz ofNW 14; Sec 31, N Yz, SW 14, N Yz of SE 14; Sec 32, NW 14 Sec 28, W Yz, W Yz ofNE 14, W Yz of SE 1;4 Tl2N Rl4E Rule 1 Field and Pool Name The field is known as thc Prudhoe Bay Field. Hydrocarbons underlying the affected area and within the referenced intervals of the Kuparuk Formation constitute a single oil and gas reservoir called the Midnight Sun Oil Pool. Rule 2 Pool Definition The Midnight Sun Oil Pool is defined as the accumulation of hydrocarbons common to and correlating with the intervals between the measured depths of 11,662 feet and 11,805 feet in the PBU E-IOO well. Rule 3 Spacing Units Nominal spacing units within the pool will be 80 acres. The pool shall not be opened in any well closer than 500 feet to an external boundary where ownership changes. Rule 4 Casing and Cementing Practices a.) In addition to the requirements of20 AAC 25.030, the conductor casing must be set at least 75 feet below' the surface. b.) In addition to the requirements of20 AAC 25.030, the surface casing must be set at least 500 feet, MD, below the base of the permafrost but not below 5000 feet true vertical depth (TVD). c.) In addition to variances under 20 AAC 25.030(g), alternate casing programs may be administratively approved by the Commission upon application and presentation of data, which show the alternatives are consistent with good oil field engineering practices. Rule 5 Injection Well Completion Injection wells may be completed with tubingless completions, (monobores or tapered casing) provided a sealbore assembly, packer, or other isolation device is positioned not more than 200 feet above the top of the injection or perforated interval. Rule 6 Automatic Shut-in Equipment a.) All wells capable of unassisted flow of hydrocarbons must be equipped with a fail-safe automatic surface safety valve. b.) Injection wells must be equipped with a fail-safe automatic surface safety valve. c.) Surface safety valves must be tested at six-month intervals. Conservation Order No. 452 November 15, 2000 Page 5 e e Rule 7 Common Production Facilities and Surface Commingling a.) Prior to installing a continuous metering skid, production from the Midnight Sun Oil Pool may be commingled with Initial Participating Area production in surface facilities prior to custody transfer. Producing Midnight Sun wells must be tested a minimum of two times per month and production must be allocated by interpolating between well test results. b.) After installation of a continuous metering skid, the requirements of20 AAC 25.230 will be satisfied by measuring production from the Midnight Sun Oil Pool as a whole and allocating the production to each well daily. c.) The allocation factor for the Midnight Sun Oil Pool will be 1.00. d.) Thc operator shall submit a monthly file(s) containing daily production metering, allocation data and daily test data for agency surveillance and evaluation. Rule 8 Reservoir Pressure Monitoring a.) A minimum of onc 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.) Pressure surveys may consist of stabilized static pressure measurements at bottom-holc or extrapolated from surface, pressure fall-off, pressure buildup, multi-rate tests, drill stem tests, and opcn-hole formation tests. 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 submitted with the Form 10-412 but must be available to the Commission upon request. e.) Results and data tram special reservoir pressure monitoring tcsts or surveys shall also be submitted in accordance with part (d.) ofthis rule. Rule 9 Gas-Oil Ratio Exemption Wells producing from the Midnight Sun Oil Pool are exempt from the gas-oil-ratio limit set forth in 20 AAC 25.240(b) so long as the provisions of20 AAC 25.240(c) apply. Rule 10 Pressure Maintenance Project Water injection for pressure maintenance must commence before reservoir pressure drops below 3300 psi at the datum or within two years of initial production. Rule 11 Reservoir Surveillance Report A surveillance report is required after one year of regular production and annually thereafter. The report shall include but is not limited to the following: a.) Progress of enhanced recovery project(s) implementation and reservoir management summary including engineering and geotechnical parameters. b.) Voidage balance, by month, ofprodueed fluids and injected fluids. e.) Analysis of reservoir pressure surveys within the pool. Conservation Order No. 452 November 15, 2000 Page 6 . e d.) Results and where appropriate, analysis of production and injection logs, tracer surveys and observation well surveys. e.) Results of well allocation and test evaluation for Rule 7(d.) and any other special monitoring. f.) Future development plans. g.) Review of Annual Plan of Operations and Development. Rule 12 Production Anomalies In the event of oil production capacity restrictions at or from the Gathering Center One facilities, all commingled reservoirs produced through the IP A facilities must be prorated by an equivalent percentage of oil production, unless it will result in surface or subsurface equipment damage. Rule 13 Administrative Action Upon proper application, the Commission may administratively waive the requirements of any rule stated above or administratively amend this order as long as the change does not promote waste, jeopardize correlative rights, and is based on sound engineering principles. Rule 14 Statewide Requirements Except where a rule stated above substitutes for a statewide requirement, statewide requirements under 20 AAC 25 apply in addition to the above rules. DONE at Anchorage, Alaska and dated November 15,2000. ~ (J rQu1vJ.: ~AA{I$Z- Camillé Oechsli Taylor, Co;~~ioner Alaska Oil and Gas Conservation Commission Daniel T. Seamount Jr., Commissioner Alaska Oil and Gas Conservation Commission AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can reJùse an application by not acting on it within the lO-day period An aftècted person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission. to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30-day period for appeal to Superior Court runs from the date on which the request is deemed denied (ie.. ¡ Oth day after the applicatIOn for rehearing was filed). • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7 Avenue, Suite 100 Anchorage, Alaska 99501 Re: AN ORDER rescinding those rules within ) Docket Number: CO -10 -21 existing Conservation Orders relating to ) Other Order No. 66 well safety valve systems. ) ) Statewide, Alaska January 11, 2011 IT APPEARING THAT: 1. On October 13, 2010 the Alaska Oil and Gas Conservation Commission (AOGCC or Commission) formally adopted new regulations relating to well safety valve systems, at 20 AAC 25.265. 2. The newly adopted well safety valve system regulations underwent final review by the Regulations Section of the Alaska Attorney General's Office and were forwarded to the Alaska Lieutenant Governor's Office on October 28, 2010. 3. The new regulations were signed by the Lieutenant Governor and took legal effect on December 3, 2010. 4. To ensure consistency with the new regulations, the AOGCC, on its own motion, proposed to rescind part or all of the outdated rules within existing Commission Orders relating to well safety valve systems. 5. On November 4, 2010, pursuant to 20 AAC 25.540, the Commission published in the Alaska Daily News notice of opportunity for public hearing on December 6, 2010. 6. The Commission received written comments in response to its public notice, and held a public hearing on December 7, 2010. 7. Oral testimony and written comments were provided at the December 7, 2010 hearing. FINDINGS: 1. Well safety valve systems are regulated under newly- adopted 20 AAC 25.265, which consolidates the requirements previously established in legacy documents, 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 . - ary 11, 2011 Alpee ...- Daniel T. Se. r ou , r., Commissioner, Chair • j it . • s Conservation Commission „ lc rman, Coer et,,, 4 4- '' - ' 1 .••• • r a Oi • • % a Conserva ion Commission 4:6411 ,. - 71 ,...._ I. i. • t Y Cat P.. oerst- r Commissioner "'iv cow �' Alaska • il 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(6), "[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)'; 'AKDCWelllntegrityCoordinator; 'Alan Dennis'; 'alaska @petrocalc.com'; 'Anna Raff; 'Barbara F Fullmer'; 'bbritch'; 'Becky Bohrer'; 'Bill Penrose'; 'Bill Walker'; 'Bowen Roberts'; 'Brad McKim'; 'Brady, Jerry L'; 'Brandon Gagnon'; 'Brandow, Cande (ASRC Energy Services)'; 'Brian Havelock'; 'Bruce Webb'; 'carol smyth'; 'caunderwood'; 'Chris Gay; 'Cliff Posey'; 'Crandall, Krissell'; 'D Lawrence'; 'daps'; 'Daryl J. Kleppin'; 'Dave Matthews'; 'David Boelens'; 'David House'; 'David Steingreaber'; 'ddonkel @cfl.rr.com'; 'Deborah J. Jones'; Delbridge, Rena E (LAA); 'Dennis Steffy'; 'Elowe, Kristin'; 'Erika Denman'; 'eyancy; 'Francis S. Sommer'; 'Fred Steece'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gorney, David L.'; 'Greg Duggin'; 'Gregg Nady'; 'gspfoff; 'Harry Engel'; 'Jdarlington (jarlington @gmail.com)'; 'Jeanne McPherren'; 'Jeff Jones'; 'Jerry McCutcheon'; 'Jill Womack'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John Katz'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'Jon Goltz'; 'Judy Stanek'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kelly Sperback'; 'Kim Cunningham'; 'Larry Ostrovsky'; 'Laura Silliphant'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley (mark.hanley @anadarko.com)'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; 'Michael Dammeyer'; 'Michael Jacobs'; 'Mike Bill'; 'Mike Mason'; '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 @exxonmobii.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 Moothat; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'tablerk'; 'Tamera Sheffield'; Taylor, Cammy 0 (DNR); 'Temple Davidson'; 'Teresa Imm'; 'Terrie Hubble'; 'Thor Cutler', 'Tina Grovier'; 'Todd Durkee'; 'Tony Hopfinger'; 'trmjrl'; 'Valenzuela, Mariam '; 'Vicki Irwin'; 'Walter Featherly'; 'Will Chinn'; Williamson, Mary J (DNR); 'Yereth Rosen'; 'Aaron Gluzman'; Bettis, Patricia K (DNR); caunderwood@marathonoil.com; 'Dale Hoffman'; 'David Lenig'; 'Gary Orr'; 'Jason Bergerson'; 'Joe Longo'; 'Lara Coates'; 'Marc Kuck'; 'Mary Aschoff; 'Matt Gill'; 'Maurizio Grandi'; Ostrovsky, Larry Z (DNR); 'Richard Garrard'; 'Sandra Lemke'; 'Talib Syed'; 'Tiffany Stebbins'; 'Wayne Wooster'; 'William Van Dyke'; Woolf, Wendy C (DNR); Aubert, Winton G (DOA) (winton.aubert@alaska.gov); Brooks, Phoebe L (DOA) (phoebe. brooks @alaska.gov); Colombie, Jody J (DOA) (jody.colombie @alaska.gov); Crisp, John H (DOA) (john.crisp @alaska.gov); Davies, Stephen F (DOA) (steve.davies @alaska.gov); Foerster, Catherine P (DOA) (cathy.foerster @alaska.gov); Grimaldi, Louis R (DOA) (lou.grimaldi @alaska.gov); Johnson, Elaine M (DOA) (elaine.johnson @alaska.gov); Jones, Jeffery B (DOA) (jeff.jones @alaska.gov); Laasch, Linda K (DOA) (linda.laasch @alaska.gov); Maunder, Thomas E (DOA) (tom.maunder @alaska.gov); McIver, Bren (DOA) (bren.mciver @alaska.gov); McMains, Stephen E (DOA) (steve.mcmains @alaska.gov); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA) (bob.noble @alaska.gov); Norman, John K (DOA) (john.norman @alaska.gov); Okland, Howard D (DOA) (howard.okland @alaska.gov); Paladijczuk, Tracie L (DOA) ( tracie.paladijczuk @alaska.gov); Pasqua!, Maria (DOA) (maria.pasqual @alaska.gov); Regg, James B (DOA) (jim.regg @alaska.gov); Roby, David S (DOA) (dave.roby @alaska.gov); Saltmarsh, Arthur C (DOA) (art.saltmarsh @alaska.gov); Scheve, Charles M (DOA) (chuck.scheve @alaska.gov); Schwartz, Guy L (DOA) (guy.schwartz @alaska.gov); Seamount, Dan T (DOA) (dan.seamount @alaska.gov); Shartzer, Christine R (DOA) Subject: Other 66 Safety Valve Systems Attachments: other66. pdf Somla.vithov Fo Al u%kat Oa/ a ;(4 Coime,rvoctloiv C (907)793 -1223 907 276 -7542 ( ) (few) • 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 408 18 Street President 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI Baker Oil Tools K &K Recycling Inc. Land Department 795 E. 94 Ct. P.O. Box 58055 P.O. Box 93330 Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Jill Schneider Gordon Severson P.O. Box 69 US Geological Survey 3201 Westmar Circle Barrow, AK 99723 4200 University Drive Anchorage, AK 99508 -4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Cliff Burglin Refuge Manager 399 West Riverview Avenue 319 Charles Street P.O. Box 2139 Soldotna, AK 99669 -7714 Fairbanks, AK 99701 Soldotna, AK 99669 -2139 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 9 1/4V4s‘ Orders Establishing Requirements for Well Safety Valve Systems 1/7/2011 Unit/Field Pool Conservation Rule Rescind Rule? Existing Order Requirement New Regulation Provisions Revised Rule - "Well safety valve systems" (2) Comment Order (1) Addressing Reqts from Order fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(a); 25.265(b); 25.265(d)(2)(H); "In 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 Qannik 605 5 no (i) double check valve, or (ii) single check valve and SSV; injection 25 h 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 25.265(h)(5) ) SCSSV satisfies the requirements of a single check valve" fail -safe auto SSV and SCSSV; injection wells (except disposal) require wells (excluding disposal injectors) must be equipped with(i) a double check valve 25.265(a); 25.2659(b); 25.265(d)( 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 . arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or 25.265(h)(5) readopted regulation valve satisfies single check valve requirement; test every 6 months ( )( 5 ) 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)(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 - Kuparuk 596 6 no (i) double check valve, or (ii) single check valve and SSV; injection and . arrangement or (ii) a single check valve a a SSV. A subsurface - controlled injection valve or 25.265(h)(5) readopted regulation valve satisfies single check valve requirement; test every 6 months ( )( 5 ) 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 r "I wells (excluding disposal injectors) must be equipped with(i) a double check valve i (.) 9 injection 25.265(b); 25.265(d)( ng (ii) single 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 si le check valve and a SSV. A subsurface- controlled injection valve or 25265 h valve satisfies single check valve requirement; test every 6 months SCSSV satisfies )( 5 ) readopted regulation fies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require "In wells (excluding disposal injectors) must be equipped with(i) a double check valve (.) single 25.265(a); 25.265(b); 25.265(d)(2)(H); ng (ii) 9 injection valve requirements for injectors are not covered by Colville River Unit Nanuq - Kuparuk 563 6 no (i) double check valve, or ii si le 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 valve satisfies single check valve requirement; test every 6 months ( )( 5 ) 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); "Injection 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 562 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 25.265(h)(5) readopted regulation valve satisfies single check valve requirement; test every 6 months ( )( 5 ) SCSSV satisfies the requirements of a single check valve." Prudhoe Ba Unit Put River 559 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 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 wets require SSSV; Y prescribed by Commission 25.265(h)(5) replaces SSSV nipple requirement for at 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 O 25.265 d 25.26!5 a ; 25.265 b ; 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 yes 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 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 25.265(b); 25.265(d)(1) "The minimum setting depth for a tubing conveyed subsurface safety valve is 500 feet." SSSV Prudhoe Ba Unit Aurora 457B 3 yes fail -safe auto SSV; SSSV landing nipple below permafrost; test every 6 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; 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(a); 25.265(b); 25.265(d); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Kuparuk River Unit Meltwater 456A 5 no valve and SSSV landing nipple; water injection wells require (1) double arrangement or (ii) a single check valve and a SSV. A subsurface controlled injection valve or readopted regulation; readopted 25.265(d)(5) does not include check valve, or (ii) single check valve and SSV; test every 6 months 25.265(h)(5) SCSSV satisfies the requirements of a single check valve." SSSV requirement for MI injectors Prudhoe Bay 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; flow to surface); test every 6 months 25.265(h)(5) replaces SSSV nipple requirement for all wells _ fail -safe auto SSV and SCSSV; SSSV may be installed above or below "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 25.265(a); 25.265(b); 25.265(d)(1); 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 wets (excluding disposal injectors) must be equipped with(i) a double check valve Colville River Unit Alpine 443B 5 no injection wells require (i) double check valve, or (ii) single check valve 25.265(a); 25.265(b); 25.265(d)(2)(H) arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or Check valve requirements for injectors are not covered by and SSV SCSSV satisfies the requirements of a single check valve." readopted regulation fail -safe auto SSV; gas /MI injectors require SSV and single check 25.265(a); 25.265(b); 25.265(d); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Kuparuk River Unit Tabasco 435A 6 no valve and SSSV landing nipple; water injection wells require (i) double arrangement or (ii) a single check valve and a SSV. A subsurface-controlled injection valve or readopted regulation; readopted 25.265(d)(5) does not include check valve, or (ii) single check valve and SSV; test every 6 months 25.265(h)(5) SCSSV satisfies the requirements of a single check valve." 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 265 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/ ( ) 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 Unit/Field Pool Conservation Rule Rescind Rule? Existing Order Requirement New Regulation Provisions Revised Rule - "Well safety valve systems" (2) Comment Order (1) Addressing Reqts from Order fail -safe auto SSV; gas /Ml injectors require SSV and single check 25.265(a); 25.265(b); 25.265(d); 'Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Kuparuk River Unit Tarn 430A 6 no valve and SSSV landing nipple; water injection wells require (i) double arrangement or (ii) a single check valve and a SSV. A subsurface-controlled injection valve or readopted regulation; readopted 25.265(d)(5) does not include check valve, or (ii) single check valve and SSV; test every 6 months 25 SCSSV satisfies the requirements of a single check valve." SSSV requirement for MI injectors Milne Point - Sag fail -safe auto SSV; injection wells require double check valve; test Check valve requirements for injectors are not covered by Milne Point Unit River 423 7 no every 6 months 25.265(a); 25.265(b); 25.265(h)(5 'Injection wells must be equipped with a double check valve arrangement" readopted regulation 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(i) 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 25.265(b); 25.265(d); a rrangement or (ii) a single check valve and a SSV. A subsurface - controlled inj ection val ve or readopted regulation; readopted 25.265(d)(5) does not include Kuparuk River Unit Kuparuk - West Sak 406B 6 no CO 4066.001 modifies Rule 6 e - LPP ma b d efeated o W. S ak SSSV requirement for MI injectors; administrative approval CO () y 25.265(h)(5) SCSSV satisfies the requirements of a single check valve. The Low Pressure Pilot may be 4066.001 remains effective [re:defeating the LPS when surface injectors w /surface pressure <500psi w/ notice when defeated and defeated on West Sak water injectors with surface injection pressure less than 500psi." placed back in service injection pressure for West Sak water injector is <500psi] fail -safe auto SSV and SCSSV; LPS trip pressure; readily accessible Badami Badami 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 wet 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 N/A deactivated SVS was replaced with requirement to maintain a prescribed by Commission 25.265(m tag on well when not manned fail -safe auto SSV (SID well and artificial lift); if SSSV installed it must Prudhoe Bay Unit Prudhoe 341E 5 yes be maintained and tested as part of SVS; sign on w if SVS 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; deactivated; maintain list of wells w /deactivated SVS; test as 25.265(h)(5) replaces SSSV nipple requirement for all wells prescribed by Commission Prudhoe Bay Unit Niakuk 329A 5 yes fail -safe auto SSV and SCSSV; maintain list of wells w/ removed o 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; deactivated SVS; sign on wellhead 25.265(h)(5); 25.265(m) replaces SSSV nipple requirement for all wells Prudhoe Bay Unit Pt. McIntyre 3176 8 yes fail -safe auto SSV and SCSSV; SSSV may be rermoved as part o 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; routine wet ops w/o notice 25.265(j); 25.265(m) replaces SSSV nipple requirement for all wells Prudhoe Bay Unit West Beach 311B 6 yes fail -safe auto SSV; sign on well if SVS deactivated; maintain list of well 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; w /deactivated SVS; test as prescribed by Commission 25.265(h)(5); 25.265(m) replaces SSSV nipple requirement for all wells West Fork West ) B) Fork (Sterling 300 5 yes fail -safe auto SVS on each production tubing 25.265(a); 25.265(b) N/A Prudhoe Bay Unit Lisburne 207A 7 yes fail -safe auto SSV; sign on well if SVS deactivated; maintain list of well 25.265(a); 25.265(b); 25.265(h)(5); N/A Requirement to maintain a wellhead sign and list of wells with w /deactivated SVS; test as prescribed by Commission 25.265(m) deactivated SVS was replaced with requirement to maintain a tag on well when not manned suitable automatic safety valve installed below base of permafrost to Readopted Bay Unit Prudhoe - Kuparuk 98A 5 yes 25.265(d) N/A .() pted 25.2 dictates which wells require SSSV; prevent uncontrolled flow replaces SSSV nipple requirement for all wells Statewide N/A N/A N/A yes Commission policy dictating SVS performance testing 25.2Ei5 h ; 25.265 n ; 25.265 o NIA AOGCC Policy - SVS Failures; issued by order of the requirements ( ) ( ) ( ) Commission 3/30/1994 (signed by Commission Chairman Dave Johnson) Footnotes (1) No SVS rules found in Injection Orders (2) New title for Revised Rule; "N /A" means entire pool rule to be rescinded Page 2 of 2 • • Public Hearing Record And Backup Information available in Other 66 . fl" il1\ LJ~.. . fß FRANK H. MURKOWSKI, GOVERNOR AI1ASIiA OIL AND GAS CONSERVATION COMMISSION 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRA TIVE ACTION NO. 457 A.02 ADMINISTRA TIVE ACTION NO. 471.02 ADMINISTRA TIVE ACTION NO. 484.02 ADMINISTRA TIVE ACTION N<ØØA2 Mr. Oil Beuhler PBU Satellite Engineering Manager BP Exploration (Alaska) Inc. P. O. Box 196612 Anchorage, AK 99519-6612 Re: PBU Western Satellite Production Metering Plan Amendment of Conservation Orders 457A, 471, 484, and 452 Dear Mr. Beuhler: By letter dated April 23, 2002, BPXA requested approval of the Prudhoe Bay Unit Western Operating Metering Plan for allocation of production from satellite oil pools in the Western region of the Prudhoe Bay Unit. The Commission conditionally approved this plan for one year beginning August 1, 2002. Rule 4 of Conservation Order No. 471 for the Borealis Oil Pool, Conservation Order No. 457 A for the Aurora Oil Pool, and Conservation Order No. 484 for the Polaris Oil Pool addresses the metering and allocation of production under this plan. Continued authorization of metering and allocation procedures was to be determined at a hearing to be scheduled no later than July 31, 2003. BPXA provided the Commission with a detailed metering and allocation procedures document on August 1, 2002. BPXA provided the Commission with a thorough review of the allocation performance of the Prudhoe Bay Unit Western Operating Metering Plan at technical meetings held on May 22 and June 5, 2003. In addition, well test and allocation information of all production fluids within the OC 1 and OC2 areas were provided as required. The Commission finds that continued use of the Prudhoe Bay Unit Western Operating Metering Plan is appropriate and that a further hearing is unnecessary. In addition, the Commission finds that technical process review meetings, required by the Commission to take place quarterly, need only take place annually. Accordingly, the Conservation Orders 471, 457, 484, and 452 are amended as follows. Borealis Oil Pool (CO 471). Aurora Oil Pool (CO 457A) and Polaris Oil Pool (CO 484) IHU·¡"" C1J ... 'j 1i '"'l '3' t\· 0 t.t 1 LU J, . . Mr. Gil Buehler August 11, 2003 Page 2 of2 Rule 4 of Conservation Orders Nos. 471, 457A, and 484 is amended to provide that approval of the Prudhoe Bay Unit Western Operating Metering Plan is permanent. Rule 4 of Conservation Orders Nos. 471, 457A, and 484 is amended to require technical process review meetings to be held at least annually. Midni2ht Sun Oil Pool (CO 452) Rule 7 of Conservation Order No 452 ("CO 452"), approved November 15, 2000, requires revision to conform to the allocation procedures of the approved Prudhoe Bay Unit Western Operating Metering Plan, and is amended as follows: CO 452 - Rule 7 Common Production Facilities and Surface Commin2lin2 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. 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. 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. DATED at Anchorage, Alaska, nunc pro tunc August 11,2003. ~,-, /) ~ ----" Æ í / (/ , <§iii~~~\f ~ Chair . . . n I ¡ LS FRANK H. MURKOWSKI, GOVERNOR .AI,ASIiA. ORAND GAS CONSERVATION COMMISSION 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAJ< (907)276-7542 ADMINISTRATIVE ACTION NO. 457 A.01 ADMINISTRA TIVE ACTION NO. 471.01 ADMINISTRATIVE ACTION NO. 484.01 ADMINISTRA TIVE ACTION NO 451.01 Mr. Gil Buehler PBU Satellite Engineering Manager BP Exploration (Alaska) Inc. P. O. Box 196612 Anchorage, AK 99519-6612 Re: PBU Western Satellite Production Metering Plan Amendment of Conservation Orders 457A, 471, 484, and 452 Dear Mr. Beuhler: By letter dated April 23, 2002, BPXA requested approval of the Prudhoe Bay Unit Western Operating Metering Plan for allocation of production from satellite oil pools in the Western region of the Prudhoe Bay Unit. The Commission conditionally approved this plan for one year beginning August 1, 2002. Rule 4 of Conservation Order No. 471 for the Borealis Oil Pool, Conservation Order No. 457 A for the Aurora Oil Pool, and Conservation Order No. 484 for the Polaris Oil Pool addresses the metering and allocation of production under this plan. Continued authorization of metering and allocation procedures was to be determined at a hearing to be scheduled no later than July 31, 2003. BPXA provided the Commission with a detailed metering and allocation procedures document on August 1, 2002. BPXA provided the Commission with a thorough review of the allocation performance of the Prudhoe Bay Unit Western Operating Metering Plan at technical meetings held on May 22 and June 5, 2003. In addition, well test and allocation information of all production fluids within the GC 1 and GC2 areas were provided as required. The Commission finds that continued use of the Prudhoe Bay Unit Western Operating Metering Plan is appropriate and that a further hearing is unnecessary. In addition, the Commission finds that technical process review meetings, required by the Commission to take place quarterly, need only take place annually. Accordingly, the Conservation Orders 471, 457, 484, and 452 are amended as follows. Borealis Oil Pool (CO 471). Aurora Oil Pool (CO 457A) and Polaris Oil Pool (CO 484) '~'Ii"'¡\~i::"'C\i''\! fI'U' G C}¡;\ 1 2003 "'::)""MS''C~'\IIIooL/ d :J.~_. . . Mr. Gil Buehler August 11, 2003 Page 2 of2 Rule 4 of Conservation Orders Nos. 471, 457A, and 484 is amended to provide that approval of the Prudhoe Bay Unit Western Operating Metering Plan is permanent. Rule 4 of Conservation Orders Nos. 471, 457A, and 484 is amended to require technical process review meetings to be held at least annually. Midni2ht Sun Oil Pool (CO 452) Rule 7 of Conservation Order No 452 ("CO 452"), approved November 15, 2000, requires revision to conform to the allocation procedures of the approved Prudhoe Bay Unit Western Operating Metering Plan, and is amended as follows: CO 452 - Rule 7 Common Production Facilities and Surface Commin2lin2 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. 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. 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. DATED at Anchorage, Alaska and dated August 11, 2003. ~^td~Ç!$ Q~ 'Sarâh palin \ \ Daniel T. Seamount, Jr. Chair/ \J Commissioner BY ORDER OF THE COMMISSION THE STATE o1ALASKA GOVERNOR BILL WALKER Alaska On and Cas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO. 50513.001 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 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Docket Number: CO-15-013 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, 041F.001, CO 471.008, CO 452.003, CO 48A, CO 559.011, CO 570.009, CO 329B.004 January 7, 2016 Page 2 of 3 - Rule 4(d) of CO 484A'; - 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 505B, Rule 10 of CO 457B, 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 329B.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 32913.003, 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 505B, 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, 4 1F.001, CO 471.008, CO 452.003, CO 484A. , 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. 5,1,A OIL&1,4 A,�o �J► Cathy . Foerster Daniel T. Sea ount, Jr. Chair, Commissioner Commissioner °�b 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. Bernie Karl James Gibbs Jack Hakkila P.O. Box 1597 P.O. Box 190083 K&K P.O. Box Recycling Inc. 58 Box Soldotna, AK 99669 Anchorage, AK 99519 055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Ms. Diane Richmond Performance and Data Management Lead, Richard Wagner Darwin Waldsmith Alaska Reservoir Development P.O. Box 60868 P.O. Box 39309 BP Exploration (Alaska), Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 196612 Anchorage, AK 99519-6612 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 J (DOA); Colombie, Jody J (DOA) oody.colombie@alaska.gov); Cook, Guy D (DOA); Crisp, John H (DOA) 0ohn.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) (Jeff Jones@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.pa lad ijczu k@a laska.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.wallace@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 1 (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 To: Pear' , Jason Bergerson; Jim Magill; Joe Longo; * 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 Subject: 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) Attachments: 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 Please see attached. Conservation Order 505B.001 Conservation Order 457B.005 Conservation Order 341F.001 Conservation Order 471.008 Conservation Order 452.003 Conservation Order 484A.003 Conservation Order 559.011 Conservation Order 570.009 Conservation Order 329B.004 Thank you, Samantha Carlisle `\ u—_ ! iVe'3IIK' CONFIDENTIAL[TY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Conunission (AOGCC), State of Alaska and is for the sole: use of the intended lecipient(s). It may contain confidential and/or privileged information. The unauthorized. reviexv, use or disclosure of such information may violate state or federallaw. 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 vou, contact Samantha Carlisle at (907) 793-1223 or Samantha Carlisle(O,'alaskagov. THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Ms. Katrina Garner 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 www.aogcc.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 AIO 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 AIO 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 Commingling (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 Monitoring 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 Comminalin¢ 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, & 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, 1A, 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. ` } Daniel T. Seamount, Jr. J ie L. Chmielowski = " Commissioner mmissioner 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. TILE STATE "'ALASKA GOVERNORMICHAEL I NTNLEVVY Ms. Katrina Garner Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO. 452.004 CONSERVATION ORDER NO. 45713.006 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 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 wvr v.aogcc.olaska.gov Re: Docket Number: CO -18-035 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 AIO 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 AIO 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 Comminaline (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 A10 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, 9/7/011 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 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 AIO 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¢linz 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. ��`OILgyQ //signature on file// //signature on file// £ Daniel T. Seamount, Jr. Jessie L. Chmielowski�+nn�� 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. Bernie Karl K&K 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 13 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 960 East Benson Bou,evarc P.O Box X96612 Anchorage, Alaska 99519-6612 (907)561-5111 1 Ld' ,. (i i,. L ue 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 axle 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 A/13, 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. E Application for Administrative Approval Amendment of COs 457 AB, 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 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 [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 S 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 iniection well pressure fall-off test, a multi -rate test[s], an interference test re drill stem tests, and open -hole formation tests aacceptable. 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 conjunction 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 fA] 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 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 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, 50513, 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 wellsbe run annually. The surveys in part (a) of this rule may be used to fulfill the minimum requirements.] 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 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 Resort 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 LA] 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 A/B, 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 un 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 infection. 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.] Midnieht 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.l Transient pressure surveys obtained b y 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 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. A Application for Administrative Approval Amendment of COs 457 A/13, 471, 50513, 484A, 452 October 23, 2018 If the commission has any questions please contact Bill Bredar at William.bredar&bp.com (907) 564-5348. Sincerely, J(�/ J�� iC/if✓t'ri.vt 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 N Q POW (O Ru4 / t0 Clrtlraf cw.n. rmWxrr,m/W RUN I10 (TYr(I 1f.4fmm11+M IF.1 u..Hn MkRrmrm.W eWaom M.N PrepoMRipmmn/a J mOr14n hggrU mM4nwn / qWf f 1p O+fryf pylf I.O (a+/ryf h04p0 1.Y (W LO.IW1.xW VrOpYrO R1Y I41QYr(O RW .b(IW1j. Cu YrOd. (P.r POfr) Ol ifr4 Mdrp1Wa �Mml.n 41 Cdadm.ovtm .- - " gmerm.wr+lal x[Iwm wll Ixr reprermxrw«ea pd:nil lakuNlron 06pv Se make gU.rfwly purw,• til ryx __.___... n x+mne w � 1 j«.xe a mmff«nJe W. INl dwa.n «ke Uum wn«e Maxdn ane Vmwre wrwry ... -...__ eMmuule yp I Ilwr reprafmn:K xea pfrmrl takmYw+a 6pr Lx.o.. an 4 «mewN Ni ' � u ru nr+aln INt.amann xlive Irdn wrt«e bpa mmr+nV Mn4+ Ur tm 1 ' .req Sp a v menUUw xfaa wCI NUJIraW YI![WYI_ SJ (wJdm IU COP. ' I 1 pn regeaenlJlM arla PWnUI faKU4lien W BMP rx.rxWSx as axnmxe au i l lyn gdlucxy Ba+vrmrwll.N INlronlalmxlrT n�+axe M.pdn Hry I ,x.mxf •: wl � welgj well on wxer xRftlxm NMrn Y/M RnpnprcUnlpYlnvnr' +U CMIWmIa I'Or. ], unlJ lewnrpNdrM gdNMlrcn. Mnw Ilxnl WPa4iiNm WW1( 1l pr lfpewmlNin xf]4an f.[d.d+W uplxe a It., Yry P 4MA an4ae <a flnnnvle aU 'eanw/ m+Iparlmnrt.: l;Ll �n .NI 1.., xliw• xwu rr+waln m/(IWn 'AUrwa RLle Sf uarler flwrew I rvaY S, riurnwif SU er'I+r Ony.Rmenl 560,000 570000 580000 590.000 600000 610000 620000 630000 Represenative Areas by o BPXA requests this map be kept confidential under AS 38.05.035(a)(8), 11 AAC 82.810 and other applicable law. NJll -- _ _ o Aurora Borealis ` Kuparuk 1 LEGEND t Kuparuk Representative Areas (Approximate) --------^-'r Aurora (West of Crest, North of Crest, South ED • --_---_—_—_---_____—_--. of Crest, Crest Area, South of Crest) 5119 �. ' — • [D Borealis (NL -Pad, SWL-Pad, EV -Pad, NV -Pad, I / �� } 2L I • \y • 0 -1 rth S_ of Crest S-� • o "' SV -Pad, Z -Pad) Pools — ., � West of Crest •S-121 • q $-1 3 -104 Q Aurora � Borealis 1100 • 3• i J-123 L_ 4 \ I; _ Al � -105 ��a. Participating \ �J 118 North L -Pad •L- 19 Sd • S-10 5.42 - i • • -1108 AURORA S ��-N�1 \ P L I LA 1 •L 120 1 -� • S\ 1 S- 210 1 • SS -115 11JL S-109 3BL1� 01• Crest Area • • S-112jS-123 0 o BOREALIS 1--� Prudhoe m °i •1 4A 11 L-11 5 ` L-103 i -1 • • 1_ Bay Unit L-1 2 • 7 -11 '• m N • Pert Midpoint P "` —` ` • • V-103 • f / t L-1 1 X120 �1♦100 South _ South of.Crest• • East of Pools • I L-1 L-1 V- East V -Pad S-125 6A Crest SW L -P d • `- -_-- L '�07 v.7 •V V �' O6,C1-1 1 128 • I _ •S-129 Q Aurora Q Borealis -102}i S-135 L-110 N`orth V -Pad • TKUD Faults �''I" Vi10 •1y-108 • --. • V -105•V-1 1 ` V-122 TKUD Depth (feet TVDss) o • 1 •V' •V-100 • l _ o High: -6200 m �—V-10 V- 12 •V -115L • • —�,� m Low .-7700 `I South -Pad • V' • -1151` I _1 i• PPP V -1 7 _101 i 4 - -V • 11 •Z-1�3 Vi I 3 • - ��`l Z.1 2 j IZ-Pad \, •Z-100 o Z 2 Z-103 `• • 8 coordinate system: o e c o NAD 1927 StatePlane Alaska 4 FIPS 5004 m i lam. - "' a o Projection: Transverse Mercator vNmi Datum: North American 1927 jData Sources: Well, Units, Coastline maintained by BPXA Cadography. Miles ITs M 010 aP EZPloration Alaska monuounusxa 900 E. Benson Blvd Anchorage, AK MAP 1 Rry 0 560000 570000 580000 590000 600000 670000 620000 630000 cls x. sommm on is Bare REI REVIEW V Oii15, 109 560,000 570.000 580.000 590.000 600000 610000 620,000 630000 Represenative Areas bp N I Aurora Borealis 0 Kuparuk { 1 1 LEGEND ! -- ----- � I ! 1---- ---- KuParuk RePresenative Areas � ) (Approximate) � --- - - - � I —----- ----------------------------- Aurora (West of Crest, North of Crest, South East of Crest, Crest Area, South of Crest) S-119 o O Borealis (NL -Pad, SWL-Pad, EV -Pad, NV -Pad, S-1 5-102L m SV-Pad,Z-Pad) I • •5-107 9-102 North - 2 Pools S-1 2jof Crest IL----_— )-------------------- West of Crest •S-121 0 Aurora --? f-'• S•114A 5-103 • 5-100 S 01• S-104 0 Borealis a -123 _124 (_. - • -31 A s -105 Participating Areas s L-118 S. A S-108 ! North L -Pad •L-119 S42 - A • •5-1108 • AURORA o ' L-122 • L-117 e 5-113 S- 20 • • S-115 5-112L1 5-109 5 01• BOREALIS L_ L-101 •L-120 �1 36L1• • Ar. S —_- • -1140L-115• t .rest 112 Prudhoe Bay Unit L -114A •L- • •L-103 ----- L-1 2 �•� i S 1 5-123 • 17 S-118 • - _ 1 -`-' • • L_ • V-103 1 South South • Part Midpoint 1 •L-1 1 • �f_120 of Crest S 5-13 • East of Pools X100 L-10 _. •- L-108 V-12 East V -Pad 125 C S• 6A rest S•128• • Q Aurora .�._... ---_----_- SW L_ • { 107 1 • V OOV-106A V-1 1 •V-102 •5-129 Q Borealis j L-110 • S-135 • North V -Pad • L -121A 0101•V-104 • n • V -105•V-111 V-122 •V 11• - V• S 108 •V-100 S n V-112-109 •V -115L • ^ t V- N South V -Pad • V- • Z-115 -1 • 1 - - ---•--w : -117 -101 Z-114 • • V-11 • Z-113 Y-! -112 Z -Pad - 1' •-,. -_r' '-'--� )'`----------------.. • Z-100 o h - ic Z-102 Z-103 n iic I Z-108 j p —L so } Coordinate System: so 1 o NAD 1927 StatePlane Alaska 4 FPS 5004 in o Projection: Transverse Mercator "x on Datum'. North American 1927 1 Data Sources: 1 Well, Units, Coastline maintained by BPXA Cartography. r t Miles I , BP Exploration Alaska �Acho0 E ason eAKS 9 MAP 1620000 LE 560000 570000 580000 600000 616000 600000 a590000 125,201] 560000 570000 580.000 590000 600,000 610000 620000 630000 Represenative Areas by N BPXA requests this map be kept confidential under AS 38.05.035(a)(8), 11 AAC 82.810 and other applicable law. Orion / Polaris 0 0 0 0 0 Schrader Bluff 0 0 LEGEND -------------------f Schrader Bluff Represenative Areas (Approximate) I I -- I Orion (1, 1A, 2, 2A, 2AS. 3A, 3S, 3N, 4, 5N, L --- �--^ 5S, 6N, 65, 8, 9) L- j ----------------------------------- o Q Polaris (SPadN, SPadS, WPadN, WPadS) on —� i ox m Pool . on Polaris --- Ll -- �\ X203 • L-223 - t------------------' �' Orion -200 212 41 L- 1 L- ;4L.216 L.216 • L-215 S' 01 • Participating Areas i L-218 L-2Sb ORION •L-202 •L-219 o �-- — --� • '--S Pad N POLARIS COTO \� i \� No � \ � L �L— • 210 �� I Prudhoe Bay Unit to —! + Perf Midpoint j -213 L- 4 • • • 21 1 \ '1, S-2\ _. OA Faults L -221 -214• V-20• • 0 S-217 OA Depth (ft TVDss) ! • 0 V-�29 V-216 213 24 • I •S-218 �, S PadS_ High :-3100 o i L .. .. V-P*040 • 21 222 I -5800 o V V-217 • ' 1 _ - ,....,.... , a •W-221 \ o .22..2 • • V-223 191 —� •V-215 •W-220chin W-218--r'=--- • W-202 ,4 1 V1�22 l i W + / • ; W Pad N W-217 I { -2164 W-201 IL, W-21 4 t • • o 17_ 13 19+W-205Ac Nm i-------------------i • -212 W-20 c m Lpp• � • 211® -210 03 W_2e 7 1 0 1 • Miles W Pad S y Coordinate System: I NAD 1927 SlalePlane Alaska 4 FIPS 5004 ? Projection: Transverse Mercator t Datum'. North American 1927 SR, Data Sources: Well, Units, Coastline maintained by BPXA Cartography. to l-- — _— -, —_--� ,n O I t I 4 BP Exploration Alask 560000 BIWIFY 900 E BensoAnchorage Anchorage, AK MAP 2 M98REDAR 570000 580000 590000 600000 610000 620000 630000 120.20v 25,p09 560000 570000 580000 590000 600,000 610000 620000 630000 bp Represenative Areas N i Orion / Polaris 0 0 0 o co Schrader Bluff 0 LEGEND ----------------- ? ----_ ___—_--__—_—___---_- ----------- Schrader Bluff Represenative Areas (Approximate) Orion (1, 1A, 2, 2A, 2AS; 3A, 3S, 3N, 4, 5N, 5S, 6N, 6S, 8, 9) p1 "' ----------------------------------------- o ti pp Polaris (SPadN, SPadS, WPadN, WPadS) ---------- p Co 2 Pool _< Q Polaris L---------t: - L♦203•L-223--�-----------------' Orion L-200 L-212 ' {Participating i -�11 L_�1=t1L-216 5-201 P 9 Areas I _. ._... L-215 .--.:...,A.,...,. • L-218 L-25% • ORION j • L-202 •L-219 -- L_____-----, •SPadN POLARIS o' N 1 •L-201 L-222L s co 2 r-'- j ; Prudhoe Bay Unit 214A L-210 on-- — 1 • t L-213 L-204 • V-221 s Perf Midpoint t `_________._. • • V-203 • V-2Z V-210 • S-213A • • • V-220 L-2059-221 • • 1 V-202 • •V-207, V-2140V S-217 • �9 • L-220 • V-216111i • -224 •5-218 • SPad S -21- Z �. •V-212 2 -� .V-2W-221V-217 • V.21 • S t '225• • V-223 V-219 -220 IFL 1 V-205• • i • V-215 ,... ! W X18 W-202 r- '----^ 1Z 1 V1r223 - �--------- ; 1 `,W 4 • W Pad N • •W-217 J , t { - ...�. 216• W-201 L ' L-r I • W-214 j - • W 219 o j 13 • W-205 , m L-------------------- -1 00• • W-212 0 —L------' W-20 1 • un j 211• 210 i 7 1 W-203 0 1 g R f • Mlles d 1 WPadS Coordinate System: 1 NAD 1927 StatePlane Alaska 4 FIPS 5004 ProjectionTransverse Mercator 1 Datum North American 1927 SData Sources: c Well, Units, Coastline maintained by BPXA Cartography. Y a 1 Bou BP Exploration Alaska tOCAocnnox.AusxA 560000 2 . Anchorage, AK c900 E Benson Blur PE9ls KSOMMER OrN 2017MAP 2 570000 580000 590000 600000 616000 620000 630000 WEVILWI B BBEDAfl IW25.20171 12 Es November 2, 2015 GENE NOV 0 4 2015 BP Exploration (Alaska) Inc. 900 AO `^ C '°` P.O. Box t 96612n Boulevard Anchorage, Alaska 99519-6612 (907) 561-5111 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 River 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 AdStrative 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, -, 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.roby@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 C03296. 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.roby(�)alaska.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 edmin approval for this request and I hajauestion 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 329E 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 C032913.003 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)793-1232 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.roby@alaska.gov. From: Richmond, Diane M [mailto:Diane. Richmond@bp.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) [mailto:dave.roby(d)alaska.gov] Sent: Thursday, December 03, 2015 10:15 AM To: Richmond, Diane M Cc: Sorrell, Aaron L; Bajsarowicz, Caroline J 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 131h, 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-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 [ma iIto: DO. Richmond @bp.com] • Sent: Thursday, December 03, 2015 8:55 AM To: Roby, David S (DOA) Cc: Sorrell, Aaron L; Bajsarowicz, Caroline 3 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) #11 Prudhoe Bay Field - Annual Surveillance Reporting Requirements to AOGCC Annual Surveillance Report Annual Overview Presentation e Production Period to be Covered Group 1 -I~~_ºil~f:)~~~__~__ .-----_.- Prudhoe Oil Pool ----- -----_.._.__...._----~-~-_.__.__..._-- Put River Oil Pool Group_ 2 - GPMA OiL~~()~~__ --_._"'_.....,,-_...__._~ e Lisburne -- ~.,_.._--_.,_._--_.------------_._-_.,-~- Niakuk -- ------_._..._,----~.- ___~__ _~~!!~~!lJdh0E!_~ _ ____ Pt. Mel ntyre Raven Oil Pool ._-.---_...._-----~,_... ..---- West Beach Oil Pool Group 1 IPA 15-Mar Group 2 GPMA 15-Jun .---_._,-,..._..,._..._~-_....._._--,~-~---,------_.~. 22-Jun 22-Mar _.'n"______"·____ ---~---- Jan 1-Dec 31 Amends Order/Rule --_._~~_..,. C0341D Rule 11 --'--'-~- C0559 ..~----~ -._.__._~ ____ C0207, 207 A C0329A Rule 9 C0345 Rule 8 ---_.._--_._._-,--~ C0317B Rule 15 ---~- C0570 Rule 10 C0311B Rule 13 G~()up 3 -~r~~~()~§~!elli!_~_9i1 Pools _________ Aurora C0457B Rule 8 -_._------_.~--~,._.~.~ Boreallis C0471 Rule 4 __,___..._._____..._____.__..__.__.__..._.____~_____."_m_..___,_".___ J'.4i~~iS!h_~ª!JÐ__~_º0452 _~ule 11 Orion C0505A Rule 9 ---~_..-..__._,-~._..__.._._..__. ..- .._----~---~-._-_._-,---~-~_..._-".__._------~_._.."-~ Polaris I C0484A Rule 9 Apr 1-Mar 31 Order Date 11/30/2001 11/22/2005 Group 3 Satellites 15-Sep 22-Sep Jul1-Jun 30 Comment I I t Note C0341 E (modified Pool Definition to include a portion of Put River Sandstone) Corrected 2/14/2006 "~----- ~.._~--------~ 6/4/1996 12/16/1994 4/19/2000 8/9/2006 8/1/2000 No rule on Surveillance reports ---_...__._----~-_..~.,_..._,-._---" -....-------.--. -----~ -~._"--_._--~-- 6/25/2004 5/29/2002 11/15/2000 4/28/2006 ~-~..._.- 11/3/2005 ~-~"_._----,.. (corr~cted 8/9!~Qº4) ..._·_______~__·__·..__MO_·_________·__._.·.______..__~. -----_.~--_.._-- _...._~--_._---_..,----,...,_._-- p+-.-- ---_.._._~._._-_._..._-- ----~-_..- ----~ l-"" .. _. l~ '...... ~"'_. ............ -.................-- ..-t""".... --..-....JJ e . Subject: [Fwd: [Fwd: Re: surveillance report dates]] From: Jane Williamson <jane_williamson@admin.state.ak.us> Date: Fri, 20 Apr 2007 13:03:59 -0800 To: Jody J Colombie <jody_colombie@admin.state.ak.us>, Dave Roby <daveJoby@admin.state.ak.us>, Cathy P Foerster <cathy _foerster@admin.state.ak.us>, Alan J Birnbaum <alan _ birnbaum@law.state.ak.us> cc: Stephen E Mcmains <steve_mcmains@admin.state.ak.us>, art Saltmarsh <art _ saltmarsh@admin.state.ak.us>, Thomas E Maunder <tom _ maunder@admin.state.ak.us> There is something I didn't get around to before left and that was to administratively amend the COs for PBU to include reporting dates agreed to verbally with BP (and DNR). Really, only Pt. McIntyre and Borealis have the wrong dates in the eo's. The others are either ok, or not explicit. Attached are the COs affected. I'm not sure how you want to handle. Jody. Please put this in the following CO files along with the attachment. Group 1 - IP A Oil Pools Prudhoe Oil Pool C0341 D Put River Oil Pool C0559 Group 2 - GPMA Oil Pools Lisburne C0207, 207 A Niakuk C0329A Rule 9 North Prudhoe Bay C0345 Pt. McIntyre C0317B Raven Oil Pool C0570 West Beach Oil Pool C0311B Group 3 - Prudhoe Satellite Oil Pools Aurora C0457B Boreallis C0471 Midnight Sun C0452 Orion C0505A Polaris C0484A -------- Original Message -------- Subject:Re: surveillance report dates Date:Thu, 31 Aug 2006 17:27:45 -0800 From:Jane Williamson <jane williamson~admin.state.ak.us> Organization:State of Alaska To:Lenig, David C <David.Lenig(ã?bp.com> References:<CBF4D8E92B5A 704 79F64416582F6A17CB81AEO@bplancex005.bpl.ad.bp.com> Oops Lenig, David C wrote: Hi Jane, 100 4/23/2007 9:50 AM L" ..-. l'" ....... ......................... ........"..-.:..-- ~....t'.......~ ~..._.....JJ t djdr(t get the attachrnent . . David From: Jane Williamson Sent: Thursday, August 31,20065:14 PM To: Lenig, David C Subject: Re: surveillance report dates E-mail is fine. Attached is a list of the pools and orders/rules that will be amended with the Admin approval. Take a look and see if this looks right to you. (Note, I'm only listing the rules that are affected by the new dates - there may be additional amendments unrelated to the surveillance requirements that I've not listed.) I'm flexible on the date for the Overview presentation. I'd be fine with specifying it to be within one or two months of the report date rather than the POD overview that you've noted. What would you prefer? Lenig, David C wrote: Jane, Here is a table showing the dates for the various Reports and Presentations. I've added the production period as well. The IPA review date remains problematic due to the proximity to spring break but we seem to work around it each year. Would you prefer that I put this in a letter requesting the changes? I know we talked about this a little while ago I just haven't found the time. Thanks, David Plan of Development Production Period Jul1-Jun30 IPA GPMA March 15 June 15 September 15 March 22 June 22 September 22 March 30 June 30 September 30 Jan1-Dec31 Apr1-Mar31 Satellites Annual Surveillance Report Annual Overview Presentation -----Original Message----- From: Jane Williamson [mailto:jane williamson@aQmin.state.ak.us] Sent: Thursday, August 31, 2006 2:30 PM To: Lenig, David C Subject: surveillance report dates Hi David. When you get a second, could you please send back an e-mail that lists all the surveillance report dates that we've agreed to for all PBU pools (including GPMA)? Also, do you have dates for surveillance reviews? I'll go through the list and make sure the Conservation orders are correctly worded, then put out administrative amendments as necessary. I checked with Cammy and she said an e-mail is fine for starting the 20f3 4/23/2007 9:50 AM l"'- ..-. l" ........ ,,---....-... ._....~...----...._- ~-.t'--,.... --...-....JJ administrative action .cess. . Thanks. Jane tlS> ~1 :1l1e Senior Reservoir Engineer (907) 793-1226 Alaska Oil and Gas Conservation Commission Content-Type: application/vnd.ms-excel surveillance report.xls Content-Encoding: base64 30f3 4/23/2007 9:50 AM ~10 Midnight Sun Allocation Factor . 1_ <"' ~ P'(( (d~ ~ -' W'~l cho.t.J_ ql\ ï ~ fccc...l, tr Subject: Midnight Sun Allocation Factor Date: rue, 26 Sep 2000 11 :58:58 -0900 From: "Daniel J Eck" <DJECK@ppco.com> To: blair _ wondzell@admin.state.ak.us CC: "Weiler, Bruce E" <WeilerB@BP.com>, "Ethan Fode" <EFODE@ppco.com>, "Carl Kinney" <CKINNEY@ppco.com> Blair, In response to your phone call asking why we were requesting an allocation factor of 1.0 for Midnight Sun. We requested the use of an allocation factor of 1.0 for the Midnight Sun field since all MS production will be continuously metered before it is commingled with any IPA production. By comparison, the Greater Point Mac Area uses multiple well tests each month is able to allocate production to +/- 1%. The MS production will flow into a separator where the gas is separated from the liquids. The gas will be metered with an orifice meter and the liquids will be metered with a micromotion coriolis mass meter. This liquid meter is identical to the meters used in the GPMA for well tests. The liquid meter for MS will be calibrated once a year using the GPMA calibration skid located at the LPC. The LPC facility engineers can provide you with details regarding the calibration equipment and procedures. They are Ethan Fode / Carl Kinney at 659-8645. Hope this helps. Dan ps, ARCO/Phillips is no longer the operator for Midnight Sun, and questions should be addressed to Bruce Weiler with BP at 564-4350. 10fl 9/26/002:18 PM [Fwd:..\;gency ct!stions Regarding the Midnight SUWI Rules and AIOApplication] e Subject: [Fwd: Agency Questions Regarding the Midnight Sun Pool Rules and AIOApplication) Date: Mon, 19 Jun 2000 13:37:33 -0800 From: Robert Crandall <Bob _ Crandall@admin.state.ak.us> Organization: DOA-AOGCC To: "Davies, Steve" <steve_davies@admin.state.akus>, "Mahan, Wendy" <wendy_mahan@admin.state.ak.us>, "Maunder, Thomas" <torn _ maunder@admin.state.akus>, "Oechsli, Camille" <cammy _ oechsli@admin.state.akus>, "Seamount, Dan" <dan_searnount@admin.state.akus>, lOW ondzell, Blair" <blair _ wondzell@admin.state.ak.us> These are the responses to the questions we drafted after reviewing the midnight sun testimony. These answers are complete and I feel address our concerns. Combined with the testimony already submitted I do not foresee any outstanding issues related to wednesday's hearing, let me know if you feel different. I'll be out of the office on thursday 6/22 cheers RPC '~~'''n Subject: Agency Questions Regarding the Midnight Sun Pool Rules and AIO Application Date: Mon, 12 Jun 2000 15:39:41 -0900 From: "Carl E Lundgren" <CLUNDGR@ppco.com> To: bob _ crandall@admin.state.akus Bob, Attached are the Q&A's. Carl ---------------------- Forwarded by Carl E Lundgren/AAI/ARCO on 06/12/2000 03:38 PM --------------------------- ERIC W REINBOLD 06/12/2000 02:40 PM To: Jack Hartz@admin.state.ak.us cc: (bce: Carl E Lundgren/AAI/ARCO) Subject: Agency Questions Regarding the Midnight Sun Pool Rules and AIO Application Jack- The enclosed document contains answers to the question identified by the AOGCC in your review of the application. We will be prepared to answer these, or related questions, at the hearing next week. If you need any clarification, please don't hesitate to call me at 263-4465. (See attached file: AOGCC MS Q&As.doc)] Thanks! Eric Reinbold PHILLIPS Alaska, Inc. 10f2 7/18/0010:00 AM [Fwd:,,~gency Quêstions Regarding the Midnight SU.l Rules and AIOApplication] e Name: AOGCC MS Q&As.doc ~AOGCC MS Q&As.doc T~pe: Microsoft Word Document (application/msword) .. I Encodmg: base64 iDesc..~iption: Mac Word 3.0 20f2 7/18/0010:00 AM Milght Sun Pool Rules and AIO APPlicln AOGCC Q&As Has there been any more work done to quantify the volume of heavy oil relative the the lighter oil volume? No. An additional downstructure well would be required to define the distribution of the heavy oil. At this point, no additional downstructure development is anticipated. What is the magnitude of a better history match? shift of the HOC? the shift in heavy oil contact made to achieve How did the volume of light oil change with the The heavy oil contact was shifted from 8107' TVD-SS to 8111' TVD-SS to increase down structure pore volume. The deeper contact increased the light oil OOIP 3 MMstb. A gas sample analysis should be analysis is available, provide or analogs. included if one is available. If no the properties derived from correlation Compositional analysis of the E-101 separator gas was performed in conjunction with the routine PVT study. The PVT report has be provide to the agency. What surveillance methods are being considered to monitor or estimate oil flux into or toward the gas cap? You may want to state how reservoir management will be used to prevent oil flux into the gas cap. Oil flux west of the upstructure producer will be limited by managing voidage replacement. After achieving a target reservoir pressure of 3800 to 4000 psi, the Voidage Replacement Ratio (VRR) will be maintained at 1.0, to fully replace voidage, while limiting any out of pattern flux. The voidage replacement balance will be monitored monthly. Additionally, annual reservoir pressure measurements will be used to insure that a balanced voidage replacement is being achieved. Is there any evidence of communication through the reservoir, i.e., interference the between production well and the shut in well? Yes. A pulse test was conducted in January of 1999 that confirmed continuity between Wells E-100 and E-101. Subsequent to this determination, Well E-100 has been utilized as the observation well to monitor reservoir pressure decline associated with downstructure production. During fillup, do you expect gas to resaturate the oil as the average pressure increases? Yes, to a degree. As pressure declines, evolved gas remains immobile until the critical gas saturation is achieved. At this point, gas will migrate upstructure, accumulating under barriers or coalescing with the overlying gas cap When waterflood is implemented and reservoir pressure begins to increase, any gas that remains in close association with oil will resaturate the oil. In contrast, gas that moves upstructure will be effectively removed from the oil and not be available for resaturation. 07/18/00 Page 1 of 1 [Fwd: Agency Questions Regarding the Midnight WOOl Rules and AIOApplication] e Subject: [Fwd: Agency Questions Regarding the Midnight Sun Pool Rules and AIOApplication] Date: Tue, 13 Jun 200009:24:41 -0800 From: Robert Crandall <Bob _ Crandall@admin.state.ak.us> Organization: DOA-AOGCC To: "Davies, Steve" <steve_davies@admin.state.ak.us>, "Maunder, Thomas" <tom_maunder@admin.state.ak.us>, "Oechsli, Camille" <cammy _ oechsli@admin.state.ak.us>, "Seamount, Dan" <dan_seamount@admin.state.ak.us>, "W ondzell, Blair" <blair _ wondzell@admin.state.ak.us> Please review Subject: Agency Questions Regarding the Midnight Sun Pool Rules and AIO Application Date: Mon, 12 Jun 2000 15:39:41 -0900 From: "Carl E Lundgren" <CLUNDGR@ppco.com> To: bob _ crandall@admin.state.ak.us Bob, Attached are the Q&A's. Carl ---------------------- Forwarded by Carl E Lundgren/AAI/ARCO on 06/12/2000 03:38 PM --------------------------- ERIC W REINBOLD 06/12/2000 02:40 PM To: Jack Hartz@admin.state.ak.us cc: (bce: Carl E Lundgren/AAI/ARCO) Subject: Agency Questions Regarding the Midnight Sun Pool Rules and AIO Application Jack- The enclosed document contains answers to the question identified by the AOGCC in your review of the application. We will be prepared to answer these, or related questions, at the hearing next week. If you need any clarification, please don't hesitate to call me at 263-4465. (See attached file: AOGCC MS Q&As.doc)] Thanks! Eric Reinbold PHILLIPS Alaska, Inc. Name: AOGCC MS Q&As.doc ~ AOGCC MS Q&As.doc T~pe: Microsoft Word Document (application/msword) EJ Encodmg: base64 Description: Mac Word 3.0 =.'_'w_,_¥_'''_'_'''_'_'.''~',''''='='¥O''¥''''''''~''',v'~'ymm~o" "..,.v"'.,...~-"-., 1 of 1 6/20/00 1: 19 PM Ml.ght Sun Pool Rules and AIO APPlicton AOGCC Q&As Has there been any more work done to quantify the volume of heavy oil relative the the lighter oil volume? No. An additional downstructure well would be required to define the distribution of the heavy oil. At this point, no additional downstructure development is anticipated. What is the magnitude of a better history match? shift of the HOC? the shift in heavy oil contact made to achieve How did the volume of light oil change with the The heavy oil contact was shifted from 8107' TVD-SS to 8111' TVD-SS to increase downstructure pore volume. The deeper contact increased the light oil OOIP 3 MMstb. A gas sample analysis should be analysis is available, provide or analogs. included if one is available. If no the properties derived from correlation Compositional analysis of the E-101 separator gas was performed in conjunction with the routine PVT study. The PVT report has be provide to the agency. What surveillance methods are being considered to monitor or estimate oil flux into or toward the gas cap? You may want to state how reservoir management will be used to prevent oil flux into the gas cap. Oil flux west of the up structure producer will be limited by managing voidage replacement. After achieving a target reservoir pressure of 3800 to 4000 psi, the Voidage Replacement Ratio (VRR) will be maintained at 1.0, to fully replace voidage, while limiting any out of pattern flux. The voidage replacement balance will be monitored monthly. Additionally, annual reservoir pressure measurements will be used to insure that a balanced voidage replacement is being achieved. Is there any evidence of communication through the reservoir, i.e., interference the between production well and the shut in well? Yes. A pulse test was conducted in January of 1999 that confirmed continuity between Wells E-100 and E-101. Subsequent to this determination, Well E-100 has been utilized as the observation well to monitor reservoir pressure decline associated with downstructure production. During fillup, do you expect gas to resaturate the oil as the average pressure increases? Yes, to a degree. As pressure declines, evolved gas remains immobile until the critical gas saturation is achieved. At this point, gas will migrate upstructure, accumulating under barriers or coalescing with the overlying gas cap When waterflood is implemented and reservoir pressure begins to increase, any gas that remains in close association with oil will resaturate the oil. In contrast, gas that moves upstructure will be effectively removed from the oil and not be available for resaturation. 06/20100 Page 1 of 1 Midnight Sun Prepared Testimony Feedback e e Subject: Midnight Sun Prepared Testimony Feedback Date: Thu, 25 May 200008:42:47 -0700 From: Jack Hartz <jack_hartz@admin.state.ak.us> Internal Organization: Alaska Oil and Gas Conservation Commission To: John W Groth <JGROTH@ppco.com> CC: Daniel T Seamount JR <dan_seamount@admin.state.ak.us>, Camille Oechsli <cammy _ oechsli@admin.state.ak.us> John Groth Development Supervisor.. Eastern North Slope Phillips Alaska, Inc. John, Staff at the AOGCC reviewed the subject testimony and have only a few comments or questions. Your staff may wish to add to the testimony or be prepared to answer possible questions along these lines during the hearing. Has there been any more work done to quantify the volume of heavy oil relative the the lighter oil volume? What is the magnitude of the shift in heavy oil contact made to achieve a better history match? How did the volume of light oil change with the shift of the HOC? A gas sample analysis should be included if one is available. If no analysis is available, provide the properties derived from correlation or analogs. What surveillance methods are being considered to monitor or estimate oil flux into or toward the gas cap? You may want to state how reservoir management will be used to prevent oil flux into the gas cap. Is there any evidence of communication through the reservoir, i.e., interference the between production well and the shut in well? During fillup, do you expect gas to resaturate the oil as the average pressure increases? The overall application package was quite informative and well laid out We look forward the the hearing. Any questions, call myself, Bob Crandall, Steve Davies or Tom Maunder on operations issues. Jack Hartz Jack Hartz <Jack Hartz(cl¿admin.state.ak.us> Sf. Reservoir Engineer Alaska Oil & Gas Conservation Commission 10f2 6/20/00 1 :22 PM ~9 e e · 1 ALASKA OIL AND GAS CONSERVATION COMMISSION 2 PUBLIC HEARING 3 In Re: 4 MIDNIGHT SUN OIL POOL RULES and 5 AREA INJECTION APPLICATION. 6 7 8 9 10 APPEARANCES: 11 Commissioners: 12 13 · 14 15 16 17 18 19 20 21 22 23 24 25 TRANSCRIPT OF PROCEEDINGS Anchorage, Alaska June 21, 2000 9:23 o'clock a.m. MS. CAMILLE OECHSLI TAYLOR MR. DAN SEAMOUNT * * * * * * R r":. '."'t r""" ',,\\ ø r- D · r-I"·.... '\ t: v"...", V ~,_ JUL 0 6 2CCi 550 West Seventh Avenue, Suùe 1650 Anchorage, Alaska 99501 (907) 276-3876 AI~a Oil & Gas Cons. Commission Anchorage A ~. {X '/1 ,~ ¿'t- V · MET ROC 0 U R T R E P 0 R TIN G, INC. A ^ ^ ORIGINAL v .., y · · · e e 2 1 PRO C E E DIN G S 2 3 (On record - 9:23 a.m.) 4 COMMISSIONER SEAMOUNT: I would like to call 5 this hearing to order. The date is June 21, 2000. The time is 6 approximately 9:23 a.m. We're located 3001 Porcupine Drive, 7 Anchorage, Alaska. These are the offices of the AOGCC. Start 8 by introducing the head table. My name is Dan Seamount, one of 9 the commissioners. Our other commissioner is -- to my left is 10 Cammy Oechsli Taylor. Laura Ferro of Metro Court Reporting is 11 making a transcript of the proceedings. You can get a copy of 12 transcript from Metro Court Reporting. 13 The purpose of today's hearing is to consider an 14 application from Phillips Alaska, Incorporated, to establish 15 pool rules for the Midnight Sun Oil POOli and also to approve 16 an area injection order authorizing enhanced oil recovery 17 operations in the pool. Notice of the hearing was published on 18 May 10, 2000. It was previously scheduled for June 13, 2000, 19 and it's been continued to today. 20 Start with some ground rules. These proceedings are 21 held in accordance with 20 MC 25.540, regulations governing 22 public hearings. The hearing will be recorded. There should 23 be no off the record conversation except among the applicants 24 themselves or I guess any of the parties themselves. You can 25 do that during the recess or if we have an in camera that's a MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 3 1 confidential session. We provide that we can consider sworn 2 testimony or unsworn statements. Greater weight is given to 3 the sworn testimony. If you wish to be considered an expert, 4 you should state your qualifications, and then the Commission 5 will rule on whether to consider you as an expert or not. 6 We'll hear from the applicant first, and then we'll allow 7 opportunity for other interested parties to ask questions. 8 Generally the way to do that is to write your questions, 9 forward it to the head table. The Commission will ask the 10 question. But there is also good possibility that we could 11 allow you to -- allow other testimony, protest, or cross 12 examination. Those wishing to cross examine the applicants 13 will be considered by the commissioners. 14 I didn't see -- the sign up sheet wasn't real full at 15 the time. Is there anyone here that's going to be giving any 16 other testimony besides the applicants? Okay. If you have 17 questions, go ahead and send them up to me and often we'll just 18 let the person giving -- asking the question do their own 19 questioning. 20 So, I would like to introduce the -- I would like to 21 invite the applicant to introduce themselves and approach the 22 Commission. One other thing, if you have questions, and always 23 when you're testifying, please use the microphone that's up 24 there. So, anyone that wants to ask questions, you can come up 25 here and we'll pull a chair in for them if there's too many MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · 1 2 3 4 5 6 7 8 9 10 11 · · e e 4 people up front, if there's a lot of people. Are you going to be giving sworn testimony? MR. GROTH: Yes, I will be. COMMISSIONER SEAMOUNT: Raise your right hand. (Oath administered) MR. GROTH: Yes, I do. COMMISSIONER SEAMOUNT: What is your name? MR. GROTH: My name is John Groth. COMMISSIONER SEAMOUNT: And who do you represent, Mr. Groth? MR. GROTH: I'm a supervisor with Phillips, 12 Alaska. I hold a Bachelor of Science degree in chemical 13 engineering from Rice University. I've been employed by 14 Phillips Alaska and its predecessor since 1977 in a variety of 15 positions. I have supervised the Midnight Sun development 16 effort since 1998. I'd like to be recognized as an expert 17 witness. 18 COMMISSIONER SEAMOUNT: Do you have any 19 questions, Commissioner? 20 COMMISSIONER OECHSLI TAYLOR: I don't and I 21 don't have any objections. 22 COMMISSIONER SEAMOUNT: We will accept you as 23 an expert witness. Please continue. 24 Phillips Alaska is presenting MR. GROTH: 25 testimony in support of the application to establish pool rules MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · 17 18 19 20 21 22 23 24 25 · e e 5 1 for the Midnight Sun Field, and to amend or establish the area 2 injection order for the pool as appropriate. And I'll come 3 back to that shortly. Phillips Alaska presents this testimony 4 on behalf of the Midnight Sun working interest owners: 5 Phillips Alaska, BP Amoco, and Exxon Mobil. The testimony is 6 divided into several parts. Paul Daggett will describe the 7 geologic aspects. Eric Reinbold will describe the reservoir 8 and operations aspects. Dan Eck will describe the facility and 9 allocation aspects. Each witness is prepared to respond to 10 questions concerning his testimony and related exhibits. For 11 the convenience of the Commission, we have available the text 12 of the testimony and copies of the exhibits. 13 In today's testimony, we will elaborate on an alternate 14 source of injection water, which was mentioned in our 15 application of May 3rd. Under consideration by the owners is 16 the option to distribute produced water from the GC1 to Midnight Sun for water flow operations. We will discuss this alternative in more detail in the facilities, well operations, and area injection operations portion of the testimony. Phillips Alaska submitted the application for the area injection order and is providing testimony today in support of that application. The Commission however may wish to issue the area injection order with due consideration of the imminent approval of a single operator for the Prudhoe Bay Unit. Unless there are any questions at this time, I'll turn MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 6 1 to Paul Daggett to get us started. 2 COMMISSIONER OECHSLI TAYLOR: I don't have any 3 questions. 4 COMMISSIONER SEAMOUNT: No questions. Do you 5 wish to give sworn testimony? 6 MR. DAGGETT: Yes, I do. 7 COMMISSIONER SEAMOUNT: Please raise your right 8 hand. 9 (Oath administered) 10 MR. DAGGETT: I do. 11 COMMISSIONER SEAMOUNT: Thank you. What is 12 your name? 13 MR. DAGGETT: My name is Paul Daggett. 14 COMMISSIONER SEAMOUNT: And who do you 15 represent? 16 MR. DAGGETT: I'm a staff geophysicist with 17 Phillips Alaska, Incorporated. I received a Bachelor of Scient 18 degree in physics from Georgia Institute of Technology and a 19 doctor of philosophy degree in geophysics from New Mexico State 20 University. I worked for Phillips Alaska, Incorporated, and 21 its predecessor since 1981 in a variety of geoscience 22 positions. I've been working on the Midnight Sun development 23 team since October 1998. I'd like to be recognized today as an 24 expert witness. 25 COMMISSIONER SEAMOUNT: What is the subject? MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 7 1 MR. DAGGETT: Geology. 2 COMMISSIONER SEAMOUNT: Do you have any 3 questions, Commissioner? 4 COMMISSIONER OECHSLI TAYLOR: I don't. 5 COMMISSIONER SEAMOUNT: WeIll accept you as 6 expert witness. 7 MR. DAGGETT: Thank you. My testimony today 8 will be on the geology section of the Midnight Sun Pool rules 9 application. The Midnight Sun Pool is located on Alaska's 10 North Slope, as illustrated on Exhibit 1-1. The Midnight Sun 11 Pool was discovered in 1997 during the drilling of Sambuca 12 Number 1, later renamed E-100 well. Midnight Sun Pool is 13 located north of the Prudhoe bounding fault system and 14 southwest of the Point McIntyre Pool. 15 COMMISSIONER SEAMOUNT: Mr. Daggett, excuse me. 16 Do we need to close the shades here? Can everybody see that 17 okay? Is that okay? Okay. Sorry. 18 MR. DAGGETT: The reservoir interval is the 19 Kuparuk River Formation. The E-100 well is the first well to 20 encounter the Kuparuk River Formation in this area. The Fawn 21 Lake Number 1, Abel State Number 1, Term Well A, North Prudhoe 22 Bay State Number 1 and Number 2, and North Prudhoe Bay Number 3 23 wells, and wells drilled from nearby pads in the Prudhoe Bay 24 Field did not encounter the Kuparuk River Formation. 25 Exhibit 1-2 shows the location of the Midnight Sun MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . 9 10 11 12 13 . 14 . e e 8 1 Participating Area. Development drilling will utilize the 2 existing gravel E-pad from which the E-100 discovery well was 3 drilled. One delineation well, the Midnight Sun Number 1 well, 4 later renamed E-101, was drilled from the E-pad in October 1998 5 to confirm the extent of the Midnight Sun discovery. 6 The Midnight Sun Pool is composed of the Kuparuk River 7 Formation, also informally referred to as the Kuparuk 8 Formation. This formation was deposited during the Lower Cretaceous geologic time period between 153 and 115 million years before present. Exhibit 1-3 shows a portion of the open hole electric logs from the E-100 well. This type log illustrates the stratigraphic definition of the Midnight Sun Pool. The log is scaled in true vertical depth subsea, and also has a measured 15 depth track. In the E-100 well, the top of the Kuparuk 16 Formation occurs at 7,974 feet subsea, or 11,622 feet measured 17 depth, and the base occurs at 8,074 feet subsea or 11,805 feet 18 measured depth. This is also the productive interval of the 19 Midnight Sun Pool. 20 The Kuparuk Formation base is defined by its contact 21 with the Jurassic-age Kingak Formation as seen with a change in 22 lithology and conventional electric log character. The Kingak 23 Formation is a shale with low resistivity of one to three ohm- 24 meters. The Kuparuk Formation is composed of medium to fine 25 grained quartz-rich to glauconitic sandstone with higher MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 9 1 resistivity of three to 50 ohm-meters. The Kuparuk Formation 2 top is defined by its contact with the Lower Cretaceous age 3 High Radioactive Zone Formation as seen by a change in 4 lithology and conventional electric log character. The HRZ is 5 a black organic-rich shale recognized by the gamma ray log 6 typically greater than 150 gamma API units. 7 The Kuparuk Formation in the Midnight Sun Pool is 8 stratigraphically complex, characterized by rapid change in 9 thickness, sedimentary facies, and local digenetic cementation. 10 Lithology is dominantly sandstone with lesser amounts of 11 siltstone sandy mudstone. As shown on the type log in Exhibit 12 1-3, the Kuparuk Formation can be divided into upper and lower 13 units. The basal portion of the lower unit in E-I0l is a non- 14 productive, tight, glauconitic sandstone with minor amounts of 15 shale rip-up clasts. This unit was not encountered in E-I00 16 and is assumed to be restricted to the area near E-I0l. Moving 17 up in the lower reservoir unit, which is typically about 40 18 feet thick, the lithology changes abruptly to porous, quart- 19 rich sandstone. Grain size is typically very fine to fine- 20 grained and is well sorted. 21 The lithology of the upper unit is variable, including 22 interbedded sandstone with minor amounts of muddy siltstone. 23 The thickness of this interval is variable and ranges from zero 24 to 70 feet. This interval contains glauconite and siderite and 25 is more prone to reductions in porosity and permeability due to MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 10 1 cementation and compaction. The sands in the upper unit are 2 poorly to well sorted. Intergranular siderite cement is common 3 in the upper unit and plays an important role in determining 4 reservoir quality. Cementation is especially abundant in the 5 lower portion of the upper unit where it degrades reservoir 6 quality. 7 The upper and lower units have distinctly different 8 thickness trends. The lower unit maintains a nearly uniform 9 thickness through the Midnight Sun area suggesting that its 10 deposition predates significant fault movement. In contrast, 11 the thickness and lithology and of the upper unit are variable 12 and have been influenced by syn-depositional faulting. 13 Exhibit 1-4 is a structure map on the top of the 14 Kuparuk Formation with a contour interval of 20 feet. Top 15 Kuparuk structure in the Midnight Sun area is characterized by 16 a bowl~shaped depression gently dipping to the northeast. The 17 Midnight Sun depression is bounded to the west by the Prudhoe 18 Mid-Field fault, to the south by the Prudhoe bounding fault 19 system, to the north by the Sambuca fault, and to the east by 20 the North Prudhoe structural high. The top of the Kuparuk 21 horizon reaches a structural high to the southwest at 22 approximately 7,789 feet subsea against the Prudhoe bounding 23 fault. The Kuparuk Formation dips eastward to a zero edge 24 against the North Prudhoe high at approximately 8,100 feet 25 subsea. The structural high surrounding the Midnight Sun MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 11 1 accumulation are devoid of Kuparuk Formation rock. Along the 2 axis of the depression, the structural dip is less than two 3 degrees down to the northeast. 4 Exhibit 1-5 is an isochore map of the Kuparuk Formation 5 with a contour interval of 10 feet. The Midnight Sun 6 accumulation is a combination structural/stratigraphic trap 7 with isolation assisted by neighboring structural highs that 8 are fault controlled. The controls on Kuparuk Formation 9 thickness are fault movement and erosional truncation. Kuparuk 10 Formation deposition occurred in marine shoreface and deltaic 11 depositional environments. 12 Exhibit 1-6 is a structural cross section along the 13 axis of the Midnight Sun structural depression. This cross 14 section illustrates the western and eastern limits of the 15 Midnight Sun Pool. The western limit of the pool is fault 16 controlled by the Prudhoe Mid-Field fault, and the eastern 17 boundary is a stratigraphic truncation of the Kuparuk Formation 18 onto the North Prudhoe structural high. 19 Exhibit 1-7 is a north-south structural cross section 20 through the Midnight Sun Pool. This exhibit illustrates the 21 fault-bounded isolation of the Kuparuk Formation on the north 22 by the Sambuca fault, and on the south by the Prudhoe bounding 23 fault system. 24 The Midnight Sun Pool gas-oil contact is determined to 25 be at a depth of 8,010 feet subsea based on Repeat Formation MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 12 1 Tester data. No oil-water contact was identified in either of 2 the Midnight Sun wells. Based on core water saturation data 3 and mercury injection capillary pressure data, the reservoir is 4 interpreted to be significantly above the effective oil-water 5 contact. Heavy oil was encountered at 8,107 feet subsea in the 6 E-101 well. A heavy oil sample measuring 10 degrees API 7 gravity was recovered by the RFT at 8,107 feet subsea. 8 Conventional core from the E-101 well contain heavy oil in the 9 lower Kuparuk section below 8,107 feet subsea. The aerial 10 extent of the heavy oil is uncertain. 11 The trap for the oil and gas in the Midnight Sun Pool 12 is created by a combination of structural and stratigraphic 13 features. To the south, west, and north, the pool limit is 14 defined by the juxtaposition of the reservoir against the 15 impermeable Kingak shale across the Prudhoe bounding fault 16 system, Prudhoe Mid-Field fault and Sambuca fault, 17 respectively. Stratigraphic truncation of the Kuparuk 18 Formation forms the trapping mechanism to the east. 19 The boundaries of the Midnight Sun PA encompass the 20 proposed boundaries of the Midnight Sun Pool. 21 Exhibit 1-8 is a net sandstone map of the Midnight Sun 22 Pool with a contour interval of 10 feet. 23 And Exhibit 1-9 is a gross hydrocarbon distribution map 24 of the Midnight Sun Poo¡. 25 That concludes my prepared testimony. MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · 19 20 21 22 23 24 25 · e e 13 1 COMMISSIONER SEAMOUNT: Thank you, Mr. Daggett. 2 Will you be giving sworn testimony? 3 MR. REINBOLD: Yes, I will. 4 5 please. 6 7 8 COMMISSIONER SEAMOUNT: Raise your right hand, (Oath administered) MR. REINBOLD: I do. COMMISSIONER SEAMOUNT: Thank you. Please 9 state your name. 10 MR. REINBOLD: My name is Eric Reinbold. 11 COMMISSIONER SEAMOUNT: And who do you 12 represent, Mr. Reinbold? 13 MR. REINBOLD: I represent Phillips Alaska, a 14 staff engineer for Phillips. I've been working as a reservoir 15 engineer on the Midnight Sun development project. I received a 16 Bachelor of Science degree in petroleum engineer from the 17 University of Alaska Fairbanks. I was employed and have been 18 employed by Phillips and its predecessor, ARCO Alaska in since 1985, and have worked on a variety of engineering projects in Alaska and at ARCO's research facility in Texas. I've worked on Kuparuk Formation satellite and development projects in the Greater Point McIntyre area since April of 1995. I would like to be acknowledge as an expert witness today. COMMISSIONER SEAMOUNT: Do you have any MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . . . e e 14 1 questions? 2 COMMISSIONER OECHSLI TAYLOR: I don't have any 3 questions and I have no objection. 4 COMMISSIONER SEAMOUNT: You are accepted as an 5 expert witness. 6 MR. REINBOLD: My testimony this morning will 7 be in three parts. I'll first start with the reservoir 8 description development planning section of our application. 9 Rock and Fluid Properties. The reservoir description 10 for Midnight Sun Pool is based on core data from the E-I00 11 (sic) well and log data from the E-I00 or Sambuca Number 1 12 well, and E-I0l, or the Midnight Sun Number 1 well. Well E-I0l 13 was cored through the entire Kuparuk section with water based 14 mud and low invasion coring techniques. The core data were 15 used to calibrate the petrophysical log model, which was used 16 to construct the Midnight Sun geologic model. 17 Porosity and Permeability. Core porosity and 18 permeability measurements were conducted at overburden 19 pressure, and permeability was corrected for gas slippage or 20 the Klinkenberg effect. Mean porosity for the upper Kuparuk 21 Formation is 20.7 percent based on the E-I01 core data. In the 22 lower Kuparuk Formation excluding the non-reservoir basal 23 interval, the mean porosity is 27.3 percent. Mean permeability 24 for the upper Kuparuk Formation is 200 millidarcies, based 25 again on the E-I00 core data -- E-I0l, excuse me. In the lower MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 15 1 Kuparuk Formation, excluding the non-reservoir basal interval, 2 the mean permeability is 760 millidarcies. The ratio of 3 vertical to horizontal permeability ranges from 0.2 to 1.0 in 4 the upper Kuparuk Formation, and from 0.6 to 1.0 in the lower 5 Kuparuk Formation. 6 Net Pay. Net pay was determined based on visual 7 inspection of the E-101 core in conjunction with review of thin 8 section and routine core analysis data. The Kuparuk Formation 9 in the Midnight Sun Pool has very low clay content, generally 10 less than two percent by volume, and no defined shale sections. 11 In the upper Kuparuk Formation, reservoir volume is reduced by 12 the presence of discontinuous, nodular and banded siderite and 13 glauconite. These mineral inclusions were identified visually, 14 and the net to gross ratio was determined based on the ratio of 15 reservoir quality sand to gross rock area exposed on the 16 slabbed core. The net to gross ratio for the upper Kuparuk 17 Formation ranged from 0.25 to 0.72. The lower Kuparuk 18 Formation has negligible glauconite and siderite content, and 19 exhibits a net to gross ratio of approximately 1.0. The non- 20 reservoir basal interval in the lower Kuparuk section is heavily cemented, with a net to gross ratio of zero. Water Saturation. Water saturation data were measured 21 22 23 throughout the Kuparuk Formation interval in the E-101 low 24 invasion core. A chemical tracer confirmed that the core 25 experienced minimal invasion. Water saturation data were METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 16 · 1 corrected for mud filtrate invasion based on the tracer 2 results. Water saturation measurements from the core were then 3 used to calibrate the petrophysical log model. Mean water 4 saturation for the Kuparuk Formation is 26.4 percent based on 5 E-I0l core data. In the lower Kuparuk Formation excluding non- 6 reservoir basal interval, the mean water saturation is 12.6 7 percent. 8 Water saturation data derived from the core and log 9 data were used to develop Leverett J-functions, which were 10 subsequently translated to drainage capillary pressure curves 11 for the upper and lower Kuparuk Formation intervals. The 12 capillary pressure data were then used to initialize water · 13 saturation in the reservoir model based on capillary pressure 14 equilibrium. 15 Relative permeability. A steady state water-oil 16 relative permeability experiment was conducted on a composite 17 core from the upper Kuparuk Formation interval. The residual 18 oil saturation from this displacement experiment was 22.7 19 percent. Centrifuge water-oil and gas-oil experiments were 20 also conducted. Results from these experiments indicate that 21 22 23 24 25 · water-oil relative permeability measurements for the Midnight Sun Pool are similar to those measured for other North Slope fields exhibiting favorable waterflood performance. In the absence of having an extensive data set for all relative permeability functions, analog data sets were used for MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . . . e e 17 1 performance projections. 2 Initial Pressure and Temperature. Based on RFT data, 3 the initial reservoir pressure is estimated at 4,058 psia at 4 the reservoir datum of 8,050 feet tvd subsea. The reservoir 5 temperature is approximately 160 degrees Fahrenheit at the 6 datum. 7 Fluid PVT Data. Reservoir fluid PVT studies were 8 conducted on a recombined surface sample obtained from E-101 9 well. The sample was recombined to the bubble point pressure 10 of 4,045 psi corresponding to the pressure at the gas-oil 11 contact at initial conditions. The API gravity of the PVT 12 sample was 25.5 degrees, with a solution GOR of 717 standard 13 cubic feet per stock tank barrel, a formation volume factor of 14 1.33 reservoir barrels per stock tank barrel, and an oil 15 viscosity of 1.68 centipoise at the bubble point pressure. 16 Exhibit 11-1 shows a summary of the fluid property 17 information for the Midnight Sun Pool. 18 Exhibit 11-2 contains a listing of the various 19 pressure-volume-temperature or PVT properties as a function of 20 pressure. 21 Hydrocarbons in Place. The estimates of hydrocarbons 22 in place for the Midnight Sun Pool reflect current well 23 control, stratigraphic and structural interpretation, and rock 24 and fluid properties. These data were integrated in the 25 construction of a fine scale geologic model, which provides the METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · . . 18 1 basis for estimation of original oil in place. The results 2 indicate an original oil in place range of 40 to 60 million 3 stock tank barrels, and total gas in place of 100 to 130 4 billion cubic feet. The free gas volume associated with the 5 gas cap is 60 to 80 billion cubic feet. 6 Reservoir Performance. Two wells, E-100 and E-101, 7 have been drilled and completed in the Kuparuk Formation. Both 8 wells are tied into the Prudhoe Bay E-pad facilities. 9 Production commenced in October of 1998. 10 Well E-100, the discovery well, encountered 100 feet of 11 gross hydrocarbon column, with 36 feet of gas above oil. The 12 well was perforated over a 20 foot interval at the base of the 13 reservoir. The initial production rate 2,000 to 3,000 barrels 14 of oil per day with a GOR of approximately 950 standard cubic 15 feet per stock tank barrel. The rate was restricted to mitigate coning, although the GOR increased steadily to 6,000 standard cubic feet per stock tank barrel during the first 16 17 18 three months of production. The well is currently shut in to 19 limit reservoir voidage. 20 Well E-101 was drilled as a downstructure delineation 21 well to the Midnight Sun Pool. The well encountered 84 feet of 22 gross hydrocarbon column, all above the gas-oil contact 23 identified in the E-100 well. No oil-water contact was 24 identified by open-hole logs. The initial production rate in 25 November of 1998 was seven to 8,000 barrels of oil per day with MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 19 1 a GOR of approximately 800 standard cubic feet per stock tank 2 barrel. In January of 1999, the well was restricted to 5,000 3 barrels of oil per day to conserve reservoir energy while 4 completing reservoir surveillance and field development 5 studies. 6 Gas Coning. Production from E-100 well is affected by 7 gas coning. E-100 is a deviated well with an inclination of 46 8 degrees across the Kuparuk. The well is completed with a 9 standoff of 42 tvd from the gas-oil contact. During the first 10 10 days of production, the GOR in E-100 well increased to 2,000 11 standard cubic feet per stock tank barrel. The production rate 12 was restricted to mitigate coning. The cement bond log in this 13 well is interpreted to show good cement quality, and the coning 14 interpretation was confirmed by production logging. Subsequent 15 inspection of the E-100 core E-101 core confirmed that 16 intra-formation cementation in the upper Kuparuk would act as a 17 baffle but not a barrier to vertical flow. With slightly more 18 than 50 percent of the oil column overlain by the gas cap, 19 coning can be a significant reservoir mechanism in the Midnight 20 Sun Pool. 21 Gas Under-Running. The Midnight Sun reservoir is a 22 thin reservoir with a structural dip of less than two degrees. 23 The low structural relief results in a gas cap that overlays 24 more than 50 percent of the areal extent of the oil column. 25 Reservoir model results calibrated to field performance MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 20 1 suggest that gas under-running, which is movement of gas below 2 a barrier, will impact early field performance, and is a 3 mechanism to address in depletion planning. The GOR at the 4 well E-101 is currently over 5,000 standard cubic feet per 5 stock tank barrel and increasing consistent with predictions. 6 The low structural relief at the Midnight Sun reservoir limits 7 the effectiveness of gas cap expansion or gas injection as a 8 recovery mechanism. 9 Development Plans. The reservoir model of the Midnight 10 Sun Pool was constructed to evaluate development options, 11 investigate reservoir management practices, and generate rate 12 profiles for facility design. This section of the application 13 describes the reservoir model, model results, and development 14 plans. 15 Reservoir Model Construction. A fine scale three- 16 dimensional geologic model of the Midnight Sun Pool was 17 constructed based on detailed stratigraphic and structural 18 interpretation. This model provided the bulk reservoir volume 19 and distribution of porosity and permeability used in the 20 construction of the Midnight Sun reservoir model. The 21 reservoir model is a three-dimensional three-phase black oil 22 finite different flow simulation model. The model area 23 encompasses the graben fault block defining the Midnight Sun 24 Pool. Areal gridding is 250 feet by 250 feet or 1.43 acre 25 cells. The vertical gridding is defined by 15 model layers MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . e 21 · 1 with nominal thickness of four to eight feet. 2 Exhibit 11-3 shows the average physical properties for 3 each model layer. Faults and juxtaposition are honored through 4 corner point geometry and non-local grid connections. 5 Water saturation in the reservoir model was established 6 by capillary pressure equilibrium. There is no aquifer in the 7 reservoir model. Capillary pressure measurements suggest that 8 the effective oil-water contact is below the structural limit 9 of the reservoir. The 10 at the gas-oil contact 11 RFT data. reservoir pressure was set to 4,045 psi of 8,010 feet tvd subsea based on the 12 Exhibit 11-4 shows the comparison of model predictions 13 and field performance. For the history match, oil rate is · 14 specified and the reservoir pressure and well GORs are 15 predicted. The history match of reservoir pressure was 16 achieved with no modification to the gas cap volume in the 17 reservoir model. The GOR history match reflects accurate 18 modeling of both the coning at well E-100 and under-running at 19 well E-101, reservoir mechanisms. The downstructure pore 20 volume was increased to reflect under-run timing at well E-101. 21 Model Results. Three development options were 22 evaluated for the Midnight Sun Pool: primary depletion, 23 upstructure gas injection, and waterflood. 24 Primary Recovery. Primary recovery was evaluated with 25 E-101 well as the single downstructure producer. The primary · METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · . e 22 1 recovery mechanism was a combination of gas cap expansion and 2 solution gas drive. The gas cap at Midnight Sun contains 3 approximately 40 percent of the total reservoir hydrocarbon 4 pore volume. 5 Model results indicate that primary depletion would 6 achieve an estimated 14 percent recovery of the original oil in 7 place or OOIP. 8 Exhibit II-5 shows production and recovery profiles for 9 primary depletion. The performance is attributed to depletion 10 of the gas cap and associated reduction in reservoir energy. 11 The model shows gas under-running and high GaR production at 12 well E-101. Reservoir pressure was depleted at the end of the 13 model run, and the majority of the gas cap volume had been 14 produced. 15 Upstructure Gas Injection. Upstructure gas injection 16 was evaluated with a horizontal injection well installed in the 17 Midnight Sun gas cap. Reservoir management for this case 18 assumed that injection would be sufficient to increase 19 reservoir pressure back to the original condition and then 20 maintain a voidage replacement ratio of 1.0. The peak 21 injection requirement for this case was 40 million standard 22 cubic feet per day. 23 Model results indicate that upstructure gas injection 24 would achieve an estimated 20 percent recovery of the OOIP 25 after 1.0 hydrocarbon pore volume injection or HCPVI. Recovery METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · . e 23 1 of 27 percent was obtained with 2.0 HCPVI. 2 Exhibit 11-6 shows production and recovery profiles for 3 upstructure gas injection. Upstructure gas injection results 4 in gas under-running the top Kuparuk Formation and then coning 5 into the perforations at the downstructure producer. As a 6 result of these mechanisms, the vertical sweep efficiency for 7 upstructure gas injection is poor with correspondingly low 8 recovery in the lower Kuparuk Formation. 9 Waterflood. Several waterflood development options 10 were studies using the Midnight Sun reservoir model, including 11 upstructure, downstructure, and midfield water injection. Both 12 upstructure and midfield options involve water injection at or 13 near the original gas cap. All waterflood options result in · 14 some degree of re-saturation of the gas cap by oil in the 15 midfield area. Case studies of successful applications of this · 16 type of waterflood process are documented in the literature. 17 The midfield configuration shows the best overall 18 waterflood performance with greater ultimate recovery and an 19 earlier production profile associated with improved pressure 20 response relative to the other cases. Midfield configuration 21 involves conversion of the E-I00 well to injection service. 22 Initial production was from the E-I0l well. An upstructure 23 horizontal production well is completed two to 4,000 feet east 24 of the western limit of the light oil column. This well was 25 managed in the reservoir model to limit gas coning. MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 24 1 The midfield waterflood shows improved waterflood 2 response over the upstructure and downstructure injection 3 options as evidenced by lower peak GOR and faster pressure 4 response. Waterflood fill-up is achieved within two years of 5 waterflood start up. The improved response is attributed to 6 closer injector/producer spacing and greater distance of the 7 key production well from the gas cap. The midfield water 8 injection case achieves an estimated 39 percent recovery at 0.7 9 HCPV1. Cumulative gas production is lower relative to the 10 upstructure gas injection case. 11 Exhibit 11-8 shows production and recovery profiles for 12 midfield water injection. 13 The upstructure configuration included a new horizontal 14 injection well towards the western limit of the light oil 15 column. The configuration was envisioned as a means of 16 isolating the gas cap while waterflooding the midfield and 17 downstructure areas. The primary downstructure producer would 18 be well E-I0l,although the E-IOO well was also produced for a 19 limited time. Model results for upstructure water injection 20 indicate that the western limit of the gas cap can be isolated, 21 and the classic waterflood fill up and response are achieved 22 within three years of waterflood start up. The upstructure 23 water injection case achieves an estimated 39 percent recovery 24 at 0.7 HCPV1, although production response to waterflood is 25 slower and gas production is greater relative to the midfield METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . 10 11 12 13 . 14 15 16 . e e 25 1 case. 2 The downstructure configuration involves conversion of 3 well E-101 to injection service. production from well E-100 4 would be resumed and rate would be initially restricted to 5 mitigate coning. The downstructure waterflood configuration or 6 in the downstructure waterflood configuration an upstructure 7 horizontal production well is drilled to recover the 8 upstructure reserves. Waterflood performance for downstructure 9 injection is less attractive than the waterflood configurations. In this configuration, gas coning and under- running at well E-100 require restricted field rate and continue to be a production issue for both production wells. The downstructure water injection case achieves an estimated 31 percent recovery at 0.56 HCPVI with a delayed production profile relative to the upstructure and midfield alternatives. Enhanced Oil Recovery or EaR. Preliminary analysis 17 indicates there may be potential for enriched gas injection at 18 Midnight Sun. However, no EaR project evaluations have been 19 initiated. Due to the technical complexities, reservoir 20 uncertainty, and cost involved, improved reservoir description 21 and additional field performance data are necessary before 22 these options may be fully evaluated. . . 23 Development Plans. Based on reservoir model studies, 24 the recommended development plan is implementation of a 25 midfield waterflood for the Midnight Sun Pool. This plan MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 26 1 provides the most favorable production profile while minimizing 2 cumulative gas production and maximizing ultimate recovery. 3 Water injection is expected to commence in the third quarter of 4 2000, with design injection rates of 20 to 25,000 barrels of 5 water per day. A peak production rate of eight to 10,000 6 barrels oil per day is expected prior to waterflood 7 breakthrough. 8 Waterflood Sensitivity Studies. Reservoir model 9 sensitivity studies were conducted in support of development 10 planning. Model runs were conducted to optimize well placement 11 and completion design. Sensitivities to key model assumptions 12 including relative permeability, vertical permeability, and oil 13 viscosity were evaluated. None of these assumptions were found 14 to significantly alter development plans. 15 Other sensitivity studies included the effect of 16 continued production to waterflood startup. Earlier waterflood 17 startup mitigates reservoir pressure decline and reduces peak 18 GaR response prior to waterflood fill up. However, no recovery 19 impact was identified with a waterflood startup during the 20 third quarter of 2000, assuming continued production of 5,000 21 barrels oil per day until start up. In the reservoir model, 22 reservoir pressure declined to 3,300 psi, and GaR peaked at 23 8,000 standard cubic feet per stock tank barrel. 24 Well Spacing. The planned development well program 25 includes the addition of one upstructure horizontal production MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · 20 21 22 23 24 25 · e e 27 1 well to complete a three well development of the Midnight Sun 2 Pool. The development will form an irregular pattern due to 3 the constraints of development within a small fault block. 4 This well spacing is nominally 280 acres. Closer well spacing 5 does not appear to be justified due to the thin oil column. 6 However, infill drilling and/or peripheral drilling along the 7 eastern margin field may be evaluated as field development 8 continues. To allow for flexibility to respond to these 9 conditions, a minimum well spacing of 80 acres is requested. 10 Reservoir Management Strategy. Gas cap expansion will 11 provide initial pressure support prior to waterflood start up. 12 Following waterflood start up, the VRR or voidage replacement 13 ratio target will exceed 1.0 to suppress gas production and 14 restore reservoir pressure. A balanced VRR will be maintained 15 restored once reservoir pressure is restored to a target range 16 of 3,800 to 4,000 psi. 17 In the planned waterflood configuration, oil flux into 18 the gas cap is anticipated in the midfield area due to low 19 structural relief. Reservoir surveillance and voidage management, however, should minimize oil flux to the west of the upstructure horizontal producer. The objective of the Midnight Sun reservoir management strategy is to manage reservoir development and depletion to achieve the maximum ultimate recovery consistent with good oil field engineering practices. To accomplish this objective, MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 28 1 reservoir management is approached as a dynamic process. The 2 initial strategy is derived from model studies and limited 3 historical performance. New well results and additional 4 reservoir performance data will increase knowledge and improve 5 predictive capabilities resulting in adjustments to the initial 6 strategy. The reservoir management strategy for the Midnight 7 Sun Pool will continue to be evaluated throughout field life. 8 Reservoir Performance Conclusions. Reservoir model 9 results support implementation of waterflood in the Midnight 10 Sun Pool. An initial three well development program is 11 contemplated with midfield water injection at well E-100, and 12 the addition of one upstructure horizontal producer. Water 13 injection is expected to commence in the third quarter of 2000, 14 with design injection rates of 20 to 25,000 barrels of water 15 per day. Following initiation of waterflood a peak production 16 rate of eight to 10,000 barrels of oil per day is expected. We 17 request that the operator be allowed to determine the field 18 off-take rate based upon sound reservoir management practices. 19 This concludes my testimony on reservoir description 20 and development planning. 21 COMMISSIONER SEAMOUNT: Thank you, Mr. 22 Reinbold. I have a few questions. When -- what date was the 23 E-100 drilled and completed? 24 MR. REINBOLD: I believe it was November of 25 '97. METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . . . e e 29 1 COMMISSIONER SEAMOUNT: 197. What was the 2 deepest penetration of that well? 3 MR. REINBOLD: It went through the Sag and 4 Ivishak. It TD'd below the Ivishak or in the Ivishak. We 5 didnlt penetrate the base Ivishak. 6 COMMISSIONER SEAMOUNT: Did you test the 7 Ivishak? 8 MR. REINBOLD: The Ivishak was tested. 9 COMMISSIONER SEAMOUNT: Is the information 10 confidential? 11 MR. REINBOLD: I would expect not. It's more 12 than two years old so no. 13 COMMISSIONER SEAMOUNT: What was the -- what 14 were the results of the test? 15 MR. REINBOLD: I donlt know the exact numbers 16 but it was on the order of 3,000 barrels oil per day. Water 17 cut came in initially very low but in order of a few days moved 18 up beyond 30 or 40 percent. 19 COMMISSIONER SEAMOUNT: Do you have any 20 development plans for the Ivishak? 21 MR. REINBOLD: At this point, it appears that 22 the Ivishak is marginal and there are currently no development 23 plans. 24 COMMISSIONER SEAMOUNT: Now, with gas injection 25 you will produce no water ever, correct? METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 30 1 MR. REINBOLD: Other than just minimal..... 2 COMMISSIONER SEAMOUNT: If you were to go with 3 gas injection. 4 MR. REINBOLD: Yeah, connate water, yeah. 5 COMMISSIONER SEAMOUNT: Do you believe there's 6 water in the system? 7 MR. REINBOLD: In the Kuparuk? 8 9 Kuparuk? 10 11 Kuparuk. COMMISSIONER SEAMOUNT: No. Yeah, in the MR. REINBOLD: There's no water leg in the There's connate water only in the reservoir to the 12 best of our knowledge. 13 COMMISSIONER SEAMOUNT: What prevents water 14 from entering? Is it the heavy oil column or is there no water 15 at all? 16 MR. REINBOLD: I would expect that as the 17 system filled up, it displaced all the water out of the system. 18 COMMISSIONER SEAMOUNT: So..... 19 MR. REINBOLD: Fully saturated the tank. COMMISSIONER SEAMOUNT: No water in the system. 20 21 What is the gravity of the heavy oil? 22 MR. REINBOLD: We took one sample with RFT and 23 recovered 10 api oil at near the top of the section, near the 24 top of the heavy oil section. 25 COMMISSIONER SEAMOUNT: Do you believe that METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 31 · 1 it -- I may not have heard -- you may have answered this 2 already in your testimony but is there heavy oil moveable? Are 3 you going to produce some heavy oil? Or did you just consider 4 the light oil in the model? 5 MR. REINBOLD: The development plan calls for 6 development of only the light oil. We don't expect that the 7 heavy oil is commercially recoverable. 8 COMMISSIONER SEAMOUNT: I'm speaking out of 9 ignorance, not having much experience on North Slope but is the 10 heavy oil moveable anywhere other than if you apply special 11 engineering to it? 12 MR. REINBOLD: I'm not really here to address · 14 15 16 17 18 19 20 21 22 13 other fields. COMMISSIONER SEAMOUNT: But you don't believe it's moveable at Midnight Sun? MR. REINBOLD: No. COMMISSIONER SEAMOUNT: Would there be possible in the future any plans to try to recover any of the heavy oil? MR. REINBOLD: That would be speculative. I guess I can't answer that question. COMMISSIONER SEAMOUNT: Speculative. Let's see. You mentioned the future -- are we going to cover the 23 more of the future drilling plans or did you cover all of it 24 for your team? 25 MR. REINBOLD: We'll speak briefly to that in · METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 12 13 . 14 15 16 17 . . e e 32 1 the well operation section but at this point we plan one 2 upstructure producer. We also will make some reference to the 3 potential of drilling a couple of source wells if we pursue the 4 source water plan. There's also some potential for additional 5 drilling in the pool for development purposes, again, depending 6 on reservoir performance and continuing evaluation. 7 COMMISSIONER SEAMOUNT: So, you mentioned three 8 wells at this time? 9 MR. REINBOLD: In the base plan, yes. 10 COMMISSIONER SEAMOUNT: Are you going to show a 11 map with the well locations on it? MR. REINBOLD: I don't have one with me. We can show the overhead. I can show you where they're at on the geologic map. COMMISSIONER SEAMOUNT: Uh-hum. Our new office space is going to contain a much friendlier hearing room than this, guaranteed. 18 MR. REINBOLD: This is the E-101 well. That's 19 the downstructure production well and our midfield development 20 case. The E-100 well which has been shut in since about 21 January 1999 will become our water injection well, and then we 22 would add an upstructure horizontal producer up in this area. 23 The western limit of the gas cap is just slightly to the west 24 of that up in here. 25 COMMISSIONER SEAMOUNT: So, the horizontal MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 33 1 would be in the northwest corner of section -- I don't see 2 sections on there. Do you know what section that is? 3 MR. REINBOLD: No. 4 COMMISSIONER SEAMOUNT: Looks like the 5 northwest corner of the southern section of the field. 6 MR. REINBOLD: Section 36. 7 COMMISSIONER SEAMOUNT: Section 36. Okay. And 8 minimum spacing of 80 acres. Do you have any questions, 9 Commissioner? 10 COMMISSIONER OECHSLI TAYLOR: No, I don't have 11 any questions. Thank you. 12 COMMISSIONER SEAMOUNT: I guess if there's any 13 other questions, we'll wait toward the end. Thank you, Mr. 14 Reinbold. 15 MR. REINBOLD: Thank you. 16 COMMISSIONER SEAMOUNT: Very good work. 17 MR. REINBOLD: Thank you. I'll turn it over 18 now to Dan Eck who will describe the Midnight Sun facilities. 19 COMMISSIONER SEAMOUNT: Are you giving sworn 20 testimony? 21 MR. ECK: Yes, I am. 22 COMMISSIONER SEAMOUNT: Please raise your right 23 hand. 24 (Oath administered) 25 MR. ECK: Yes, I do. MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 34 1 COMMISSIONER SEAMOUNT: Thank you. Please 2 state your name. 3 MR. ECK: My name is Dan Eck. 4 COMMISSIONER SEAMOUNT: And who do you 5 represent, Mr. Eck? 6 MR. ECK: Phillips Alaska. COMMISSIONER SEAMOUNT: And do you wish to be 7 8 considered as an expert witness? 9 MR. ECK: Yes, I do. 10 COMMISSIONER SEAMOUNT: What is the subject? 11 MR. ECK: Facilities for Midnight Sun. I am 12 the Midnight Sun facility engineer responsible to Phillips 13 Alaska for the integrity and the viability of the Midnight Sun 14 production facilities. I graduated from the University of 15 Missouri Rolla with a bachelor degree in mechanical 16 engineering. Following graduation, I went to work for ARCO, 17 subsequently Phillips Alaska, and have been involved in the 18 design, construction, and operation of hydrocarbon processing 19 facilities for the past 15 years. I am a registered mechanical 20 engineer with the State of Alaska. I would like to be 21 acknowledged as an expert witness today. 22 Do you have any COMMISSIONER SEAMOUNT: 23 questions, Commissioner Oechsli? 24 COMMISSIONER OECHSLI TAYLOR: I don't. 25 MR. ECK: Midnight S- --..... MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · e e 35 1 COMMISSIONER SEAMOUNT: We will consider you as 2 an expert witness. Accepted. 3 MR. ECK: Midnight Sun Facilities General 4 Overview. Midnight Sun wells will be drilled from the E-pad 5 drill site. Surface facilities include an existing IPA drill 6 site, pipelines and processing facilities to produce Midnight 7 reservoir fluids. Midnight Sun fluids will be commingled with 8 Initial Participating Area, IPA, fluids for the surface -- on 9 the surface at E-pad and then transported to Gathering Center 1 10 for treatment and shipment to Pump Station 1. Midnight Sun 11 will make use of existing IPA infrastructure. This minimizes 12 environmental impacts and reduces cost to help maximize 13 recovery. · 14 Use of 15 and processing · the GC1 production facility includes separating equipment, inlet manifold and related piping, 16 flare system, and water injection facilities. IPA facilities 17 that will be used include 24 inch low pressure common line from 18 E-pad to GC1, 16 inch and 6 inch high pressure common lines 19 from E-pad to GC1, oil sales line from GC1 to pump station I, 20 and the power distribution and generation facilities. Plans to 21 deliver GC1 produced water to E-pad using an existing six inch 22 IPA flowline are also being considered. Exhibit III-1 is an 23 area map showing locations of the facilities that will be used 24 for Midnight Sun development. 25 Drill Sites, Pads, and Roads. Use of the E-pad drill MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 36 1 site for the Midnight Sun wells has been selected to eliminate 2 new gravel placement, minimize well stepout to within current 3 available drilling technology while reaching the extent of the 4 reservoir, and maximizing the use of existing facilities. 5 Wells will be drilled between existing IPA wells, eliminating 6 the need to expand the E-pad. A schematic of the drill site 7 layout is shown in Exhibit 111-2. This schematic shows 8 facilities for local source water injection system. As an 9 alternative, the Midnight Sun owners are working towards 10 approval to use GC1 produced water as a water source for the 11 Midnight Sun project. 12 No new pipelines will be required for development of 13 the Midnight Sun reservoir. Midnight Sun production will be 14 routed to GC1 via existing E-pad high pressure and low pressure 15 commonlines. No new roads or roadwork will be required. 16 Drill Site Facilities and Operations. Two existing E- 17 pad production manifold slots and well lines will be used for 18 the Midnight Sun wells. Water for the waterflood operations 19 will be obtained from either source water wells drilled at E- 20 pad or produced water delivered by pipeline from GC1. If the 21 source water system is installed, the source wells would be 22 equipped with electrical submersible pumps to deliver water to 23 the project. The source water injection system option is 24 illustrated in Exhibit 111-3. 25 Future gas lift gas will be obtained from an IPA E-pad METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · 5 6 7 8 9 10 11 12 13 · 14 · . e 37 1 well. Gas removed from this well for raw gas lift will be 2 metered prior to the gas being introduced into the Midnight Sun 3 well. This IPA gas will be returned to the IPA. 4 If initial power is needed beyond currently available capacity at E-pad, it will be provided by installing a new 15 kv power line from GC1 to the Midnight Sun facilities at E-pad. All well control at the drill sites will be performed manually by a drill site operator, with the exception of well safety shut in system, which are automatic, and the drill site emergency shutdown system, which can be triggered manually or automatically. Initially, production will be allocated based upon well tests as previously approved by the Commission. After a new metering skid is installed in the third or fourth quarter 2000, 15 Midnight Sun production will be continuously metered prior to 16 combing with IPA production. The skid will consist of a two 17 phase separator, with liquids measured by a mass meter and gas 18 production measured by conventional orifice plate methods. The 19 Midnight Sun oil gravity will be used to calculate the oil and 20 water volumes based on liquid mass measurement. After 21 metering, the gas and liquid streams will be re-combined and 22 commingled with IPA fluids at E-pad for transport to GC1. The 23 data obtained from the metering skid will provide the basis for 24 allocating production between Midnight Sun and the IPA. 25 Production allocation is addressed later in Section V. MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . e 38 · 1 Data gathering at the drill site will be both 2 manual and automatic. The data gathering system, SCADA, will 3 be expanded to accommodate the Midnight Sun wells and drill 4 site equipment. The SCADA will continuously monitor the 5 flowing status, pressures, and temperature of the producing 6 wells at the drill sites. These data will be under the drill 7 site operator's supervision through his monitoring station. 8 Midnight Sun production metering will continuously monitor the 9 pressures, temperatures, and flow of the liquid and gas 10 streams. 11 The rate of production from each well will be regulated 12 by manually adjusted chokes. The flow from the wells would be 13 routed to the production metering skid and then to GC1 for · 14 processing. 15 Production Center. No modifications to the GC1 16 production center will be required to process the Midnight Sun 17 production. GC1 was built to process a nominal oil rate of 18 400,000 barrels of oil per day, gas rate of 320 million 19 standard cubic feet per day. Modifications have increased this 20 to 2,600 million standard cubic feet per day and a produced 21 water rate of 4,000 -- 40,000 barrels of water per day. 22 Modifications have increased this to 85,000 barrels of water 23 per day. Production, including that from the Midnight Sun 24 reservoir, is not expected to exceed GC1 capacity. This 25 concludes my testimony on facilities for the Midnight Sun Oil · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e -- 39 · 1 Pool. 2 COMMISSIONER SEAMOUNT: Thank you. What/s the 3 4 5 6 7 8 9 10 11 12 13 · 14 15 16 17 18 19 · area covered by pad EI do you know? MR. ECK: I don/t know off the top of my head how much gravel is there. It is one of the original drill sites so it/s quite large. COMMISSIONER SEAMOUNT: One of the larger ones? MR. ECK: Yes. COMMISSIONER SEAMOUNT: Do you have any questions I Commissioner Oechsli? COMMISSIONER OECHSLI TAYLOR: I don/t. COMMISSIONER SEAMOUNT: Thank youl Mr. Eck. MR. ECK: The next sectionl Well Operations I will be presented by Eric Reinbold. COMMISSIONER SEAMOUNT: We/ve already considered Mr. Reinbold as an expert witness. I don/t believe that we need to go through that againl do we? COMMISSIONER OECHSLI TAYLOR: I don/t think so. COMMISSIONER SEAMOUNT: Okay. Thank you. 20 MR. REINBOLD: Well Operations. Drilling and 21 Well Design. Two wells have been drilled in the Midnight Sun 22 Pool I E-I00 and E-I0l. E-I0l is currently producing with plans 23 to convert E-I00 to injection service. Exhibit IV-l shows the 24 schematic of the E-I00 well. The Midnight Sun depletion plan 25 calls for drilling one additional upstructure well to complete METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 40 1 the initial development plan. If the source water injection 2 system is installed, two shallow source wells would also be 3 drilled. 4 Midnight Sun wells would be directionally drilled from 5 E-pad utilizing drilling procedures, well designs, and casing 6 and cementing programs similar to those currently used in other 7 North Slope fields. A 20 inch conductor casing will be set 80 8 feet below pad level and cemented to surface. Consideration 9 will be given to driving or jetting the 20 inch conductor as an 10 alternative setting method. A diverter system meeting 11 Commission requirements will be installed on the conductor. 12 Surface hole would be drilled no deeper than 5,000 feet 13 tvd subsea. This setting depth provides sufficient kick 14 tolerance to drill the wells safely and allows the angle-build 15 portions of high departure wells to be cased. No hydrocarbons 16 have been encountered to this depth in previous Midnight Sun 17 wells. Cementing and casing requirements similar to other 18 North Slope fields will be adopted for Midnight Sun. 19 The casing head in a 5,000 psi blowout-preventer stack 20 will be installed onto the surface casing and tested consistent 21 with Commission requirements. Production hole will be drilled 22 below the surface casing to the Kuparuk Formation allowing 23 sufficient rathole to facilitate logging. Production casing 24 will be set and cemented. Intermediate casings and production 25 liners will be used to achieve specific completion objectives MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · 9 10 11 12 13 · 14 15 16 18 19 20 21 22 23 24 25 · e It 41 1 or to provide sufficient contingency in mechanically 2 challenging wills such as high departure wells. 3 To date, H2S has not been detected in any Midnight Sun 4 wells. However, with planned waterflood operations, there is 5 some potential of generating small amounts of H2S over the life 6 of the field. 7 Safe drilling practices to account for the effects of 8 the H2S gas on both people and equipment will be followed, including continuous monitoring for the presence of H2S. A readily available supply of H2S scavenger, such as zinc carbonate, will be maintained to treat the entire mud system. Emergency operating and remedial protective equipment will be kept at the wellsite. All personnel on the rig will be informed of the dangers of H2S, and all rig site supervisors will be trained for operations in an H2S environment. The nature of the wells to be drilled requires the use 17 of E-75, 8-105, or S-135 grade drill pipe. These materials are susceptible to sulfide stress cracking but can be used safely under controlled conditions recommended in Section 8, Drill Stem Corrosion and Sulfide Stress Cracking, of API RP 78, Drill Stem Design and Operating Limits, which will be used as applicable. Well Design and Completions. Contingent water supply wells would be drilled into the Tertiary interval and completed with a single casing string and downhole electric submersible MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . . . . e 42 1 pumps. Open hole gravel packs would be used in the water 2 supply wells to maximize productivity and present -- prevent 3 sand production. 4 The upstructure horizontal producer is planned with a 5 measured depth of over 14,000 feet, and would be completed in 6 the Kuparuk Formation. This departure would necessitate top- 7 setting the Kuparuk. In general, the production casing will be 8 sized to accommodate the desired tubing size in the Midnight 9 Sun wells. The following table indicates the casing and tubing 10 sizes utilized in the proposed well designs for the Midnight 11 Sun wells. Tubing sizes vary from 3-1/2 to 4-1/2 inches in the 12 Midnight Sun wells. And the table is shown in the text. It's 13 not an exhibit. 14 Plans are to run L-80 tubing and casing in these wells. 15 All tubing jewelry will be completed with 9-Chrome/lMoly, which 16 is compatible with both L-80 and 13-Chrome. 17 All proposed wells call for completion in a single zone 18 with a single string and a single packer. As shown in the 19 schematic, the wells have gas lift mandrels with dummy valves 20 to provide flexibility for artificial lift if needed to enhance 21 production rates. Sufficient mandrels will be run to provide 22 flexibility for changing well production volumes, gas lift 23 supply pressure, and changes in water-oil ratio. 24 Surface Safety Valves. Or excuse me, Subsurface Safety 25 Valves first. Subsurface safety valves do not appear to be METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · . . 43 1 necessary to Midnight Sun wells according to statewide 2 regulations 20 AAC 25.265. Existing completions are equipped 3 with subsurface safety valve nipples. The upstructure producer 4 would be completed in a similar manner. 5 Surface Safety Valves. Surface safety valves are 6 included in the wellhead equipment. These devices can be 7 actuated by high and low pressure sensing equipment, and are 8 designed to isolate produced fluids upstream of the surface 9 safety valve if pressure limits are exceeded. Testing of 10 surface safety valves will be in accordance with the standard 11 Prudhoe Bay Unit operator practices. 12 Drilling Fluids. In order to minimize skin damage from 13 drilling and to maintain shale stability, water-based KCl mud 14 will be used to drill through the Midnight Sun Pool and nearby 15 shales will be low solids, non-dispersed fluids excuse me, 16 while non-dispersed fluids will be used in the upper sections 17 of the well. 18 Stimulation Methods. Stimulation to enhance 19 productivity or injectivity capability is not currently planned 20 for Midnight Sun wells. Formation damage associated with 21 drilling and completion activity appears to be minor or 22 insignificant. The use of stimulation in the medium to high 23 permeability rock may be evaluated at a later date. 24 Reservoir Surveillance Program. The Midnight Sun data 25 will continue to be collected to monitor reservoir performance METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suiie 1650 Anchorage, Alaska 99501 (907) 276-3876 . 10 11 12 13 . 14 15 16 17 18 19 . . e 44 1 and define fluid properties. 2 Reservoir Pressure Measurements. An initial static 3 reservoir pressure will be measured in each well prior to 4 production. Additionally, a minimum of one pressure survey 5 will be taken annual for the Midnight Sun Pool. This will 6 consist of stabilized static pressure measurements at bottom 7 hole or may be extrapolated from the surface, pressure fall- 8 off, pressure build-up, multi-rate tests, drill stem tests, and 9 open-hole formation tests. The reservoir pressure will be reported at the common datum elevation of 8,050 tvd subsea. Surveillance Logs. Surveillance logs, which may include flow meters, temperature logs, or other industry proven downhole diagnostic tools, will be periodically run to help determine reservoir performance, for example, gas-oil contact monitoring and injection profile evaluation. That concludes my testimony on well operations for the Midnight Sun Pool. And if there are any questions, I can address those. COMMISSIONER SEAMOUNT: You stated that 20 subsurface safety valves are not necessarily indicated by 21 regulations. Does that mean that you don't plan to use the 22 subsurface safety valve? 23 MR. DAGGETT: Yeah. Currently we do not have 24 safety valves installed. There are nipples, profiles where we 25 could install them if necessary but currently they're not. METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e . 45 1 COMMISSIONER SEAMOUNT: What is the percentage 2 KCl you're going to be using for drilling? Have you worked 3 that out yet? 4 MR. REINBOLD: It's two to four. 5 UNIDENTIFIED SPEAKER: It's less than 6 (indiscernible) 7 MR. REINBOLD: Somewhere -- it's in two and 8 four percent. 9 COMMISSIONER SEAMOUNT: I'm not sure if you're 10 the one that would want to answer this next question, Mr. 11 Reinbold, but would you put the -- one of those maps back up. 12 I would like to learn something about the ownership of the 13 area. Can anyone address that? 14 MR. REINBOLD: Okay. 15 What is the ownership COMMISSIONER SEAMOUNT: 16 of the PA? Actually, what I'd like to know is there a 17 difference in ownership as you come out of the PA? 18 MR. REINBOLD: Within the Kuparuk River 19 Formation, the ownership would be the lease ownerships outside 20 of the participating area. Inside the participating area, it's 21 2.75 percent owned by BP, or the tract participations are such, 22 and Exxon Mobile and Phillips share the remainder. 23 MR. GROTH: However, with the Prudhoe Bay Unit 24 (indiscernible) agreement that's recently been signed, the 25 ownerships within the PA, and with eventual approval by the MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 46 · 1 State of a cross assignment of the leases, and I believe all of 2 these leases in this area are held by the three parties, 3 Phillips Alaska, BP Amoco, and Exxon Mobile. And so ownership 4 in all of these leases that are associated with this PA would 5 be at the (indiscernible). 6 COMMISSIONER SEAMOUNT: Okay. Thank you. 7 Where's the sign in sheet? Did anyone else say they wanted to 8 present testimony? I haven't seen any questions. Are the 9 applicants finished? 10 11 12 13 · 14 15 actually. 16 MR. GROTH: No. COMMISSIONER SEAMOUNT: I'm sorry. MR. GROTH: We have.. . . . COMMISSIONER SEAMOUNT: I'm sorry. MR. GROTH: We have several more sections MR. REINBOLD: The next section is on 17 production allocation. Dan Eck will be presenting that. 18 COMMISSIONER SEAMOUNT: Mr. Eck has already 19 been recognized as an expert witness. Please proceed. 20 MR. ECK: In this portion of the testimony, I 21 will discuss the incentives for commingled production, the 22 concept of continuous metering allocations, and the details of 23 production allocation activities for Midnight Sun. 24 Section V. Production Allocation. Initially, a 25 combination of well tests and wellhead pressure trends will · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 47 1 continue to be used to allocate production. Under this 2 methodology, the production from an individual well is first 3 calculated from the average daily wellhead pressure using the 4 deliverability equation. During periods of rising GOR and 5 changing tubing hydraulics, the deliverability equation may not 6 accurately reflect the production as measured by well tests. 7 During such periods, the daily well production is determined by 8 linear interpolation between well test points. A minimum of 9 two well tests per month, as well as lab-measured water cuts 10 and zero-rate tests, are performed on Midnight Sun wells to 11 ensure allocation accuracy. Summing the calculated data 12 calculated daily production volume for all producing wells 13 provides an estimate of the Midnight Sun daily field 14 production. A fixed allocation factor of 1.0 is used for the 15 Midnight Sun. 16 The long-term metering plan for Midnight Sun is to use 17 continuous production metering. The metering skid described in 18 the facility section of this application will be used to 19 continuously meter the entire Midnight Sun production stream 20 through a compact two-phase separator before it is commingled 21 with the IPA production at E-pad. Each wellhead will have a 22 continuous two phase meter to monitor fluid and gas production 23 with monthly shakeouts to ascertain water cut. We request 24 Commission approval under 20 MC 25.215 (a) that the Midnight 25 Sun metering is an acceptable method. An allocation factor of MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, SuiJe 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 48 1 1.0 would continue to be used with the continuous meter. The 2 Midnight Sun Pool will have a set allocation factor of 1.0 with 3 production allocated back to individual wells using the 4 continuous two-phase metering data to calculate wellhead 5 allocation factors. Consistent with existing reporting, no 6 NGLs will be allocated to Midnight Sun. 7 This concludes the testimony on production allocation 8 for the Midnight Sun Oil Pool. 9 COMMISSIONER SEAMOUNT: Questions? 10 COMMISSIONER OECHSLI TAYLOR: No, I don't have 11 any questions. Thanks. 12 COMMISSIONER SEAMOUNT: Thank you, Mr. Eck. 13 MR. ECK: The next section, area injection 14 operations, will be presented by Eric Reinbold. 15 Please proceed, Mr. COMMISSIONER SEAMOUNT: 16 Reinbold. 17 MR. REINBOLD: Thank you. Section VI is the 18 area injection operations. This application, prepared in 19 accordance with 20 AAC 25.402, Enhanced Recovery Operations, 20 and 20 AAC 25.460, Area Injection Orders, requests 21 authorization for water injection to enhance recovery for the 22 Midnight Sun Oil Pool. This section addresses the specific 23 requirements of 20 AAC 25.402(c). 24 Plat of the Project Area. Exhibit 1-2, which has 25 previously been shown, shows the location all existing MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . . . e e 49 1 injection wells, production wells, abandoned wells, dry holes, 2 and any other wells within the Midnight Sun Pool as of April 1, 3 2000. Specific approvals for any new injection wells or 4 existing wells to be converted to injection service will be 5 obtained pursuant to 20 AAC 25.005, 25.280, and 25.507, or any 6 applicable successor regulation. 7 Operator and Surface Owners. Phillips Alaska, Inc., is 8 the designated operator of the Midnight Sun Participating Area. 9 Surface owners within a one-quarter mile radius and inclusive 10 of the Midnight Sun Participating Area are as follows: and 11 listed here is only the State of Alaska Department of Natural 12 Resources, Ken Boyd P.O. Box 107034, Anchorage, Alaska 99510. 13 Pursuant to 20 AAC 25.402(c) (3), Exhibit VI-1 shown here is an 14 affidavit showing that the operators and surface owners within 15 a one-quarter mile radius of the area and inclusive -- and 16 including -- included within the Midnight Sun Participating 17 Area have been provided a copy of this application for 18 injection. 19 Description of Operation. Development plans for the 20 Midnight Sun Pool are described in Section II of this 21 application. Drill site facilities and operations are 22 described in Section III. If the source water injection system 23 is installed, source water wells will be permitted and 24 construction -- and constructed in accordance with 20 AAC 25 25.005. METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 50 1 Geological Information. The geology of the Midnight 2 Sun Pool has been described in Section I of this application. 3 Injection Well Casing Information. The E-100 well will 4 be converted to injection service for the Midnight Sun Oil Pool 5 Enhanced Recovery Project. The casing program for this well 6 was permitted and completed in accordance with 20 MC 25.030. 7 Exhibit IV-1 already shown details the completion for the E-100 8 well. A cement bond log was recorded and indicated good cement 9 bond across and above the Kuparuk River Formation. Conversion 10 of the E-100 well will be conducted in accordance with 11 20 MC 25.412. 12 The actual casing program is included with the 13 application to drill for each well. It is documented with the 14 AOGCC in the completion record. API injection casing 15 specifications are included on each drilling permit 16 application. All injection casing is cemented and tested in 17 accordance with 20 MC 25.412 for both newly drilled and 18 converted injection wells. All drilling and production 19 operations will follow approved operating practices regarding 20 the presence of H2S in accordance with 20 MC 25.065. 21 Injection Fluids. Type and - - Type of Fluid and 22 Source. The Midnight Sun Enhanced Recovery Project will 23 utilize either GC1 produced water or water produced from the 24 Tertiary Sagavanirktok Formation, as shown in Exhibit VI-2, as 25 an initial and primary source. So this is Exhibit VI-2 and it MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · 1 2 3 4 5 6 7 8 9 10 · · e e 51 just shows the interval that we would acquire water from if we installed the source well system. COMMISSIONER SEAMOUNT: What kind of rates do you anticipate? MR. REINBOLD: What kind of rates? COMMISSIONER SEAMOUNT: Uh-hum. MR. REINBOLD: The design rate is 10,000 barrels a day for each source well. COMMISSIONER SEAMOUNT: Okay. MR. REINBOLD: Composition. First, Tertiary 11 Water. The water sample from the Tertiary -- or a water sample 12 from the Tertiary water source interval has not been obtained. 13 However, it's anticipated the water will be of similar 14 composition as water produced from the drill site 15-6 well in 15 the Cretaceous interval. The drill site 15-6 water composition 16 is shown in Exhibit VI-3. 17 GC1 Produced Water. The composition of produced water 18 from GC1 is shown in the next exhibit, Exhibit VI-4. The 19 composition of Midnight Sun produced water will be a mixture of 20 connate water and source injection water. No water-oil contact 21 has been identified in the Midnight Sun Pool, and no 22 significant connate water production has occurred or is 23 anticipated. In order to conduct geochemical modeling, the 24 Midnight Sun Oil Pool connate water composition is assumed to 25 be similar from samples from the offset Point McIntyre Oil MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 52 1 Pool. Refer to Exhibit J-3 in the application for modification 2 to area injection order number 4, dated April 5, 1993. 3 Maximum Injection Rate. Maximum water injection rates 4 required at the Midnight Sun Pool are estimated at 25,000 5 barrels of water a day. 6 Compatibility with Formation and Confining Zones. Core 7 analyses and geochemical modeling indicate no significant 8 problem with clay swelling or compatibility with in-situ 9 fluids. Analysis of the E-I0l core indicates a low clay 10 content, less than five percent by volume, primarily in the 11 form of kaolinite and illite. No fines migration problems are 12 anticipated. 13 Geochemical modeling results indicate that a 14 combination of Tertiary water and connate water is likely to 15 form calcium carbonate and barium sulfate scale in the 16 production wells and downstream production equipment. Similar 17 scaling problems are anticipated for GCl produced water and 18 connate water. Scale precipitation will be controlled using 19 standard oil field scale inhibition methods. 20 Injection Pressures. The expected average surface 21 water injection pressure for the project is 2,250 psig. The 22 estimated maximum surface injection pressure for the Midnight 23 Sun Pool Enhanced Oil Recovery Project is 2,750 psig. The 24 resulting bottom hole pressure will be limited by hydraulic 25 pressure losses in the well tubing, with a maximum expected METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 53 1 bottom hole pressure of 6,000 psig. 2 Fracture Information. The expected maximum injection 3 pressure for the Midnight Sun Oil Pool Enhanced Recovery 4 Project wells will not initiate or propagate fractures through 5 the confining strata, and therefore will not allow injection or 6 formation fluid to enter any freshwater strata. There is no 7 evidence of injection out of zone for similar Kuparuk River 8 Formation waterflood operations in the North Slope. 9 Freshwater Strata. There are no freshwater strata in 10 the area of issue. See Section N of the application for 11 Modification to the area injection order number 4, dated April 12 5, 1993. Additionally, calculations of water salinity for open 13 hole resistivity logs acquired in the Prudhoe Bay well E-16 14 indicate a salinity range of 40 to 45,000 parts per million for 15 the Cretaceous and Tertiary sands above the Kuparuk River 16 Formation. Therefore, even if a fracture were propagated 17 through all confining strata, injection or formation fluid 18 would not come in contact with freshwater strata. 19 Enhanced Recovery. Water injection operations at the 20 Midnight Sun Oil Pool are expected to be above the formation -- 21 Kuparuk River Formation parting pressure to enhance injectivity 22 and improve recovery of oil. Fracture propagation models 23 confirm that injection above the parting pressure will not 24 exceed the integrity of the confining zone. 25 The Kuparuk River Formation at the Midnight Sun Oil MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 13 · 14 15 16 17 18 · · e e 54 1 Pool is overlain by the Kalubik and HRZ shales, which have a 2 combined thickness of approximately 110 feet. The HRZ is a 3 thick shale sequence which tends to behave as a plastic medium, 4 and can be expected to contain significantly higher pressures 5 than sandstones of the Kuparuk River Formation. Mechanical 6 properties determined from log data for the HRZ and Kalubik 7 intervals indicate a fracture gradient from approximately 0.8 8 to 0.9 psi per foot. 9 No tests have been conducted to determine the formation 10 breakdown pressure at the Midnight Sun Oil pool. However, data 11 from offset fields suggest that a fracture gradient of between 12 0.6 and 0.7 psi per foot can be expected in the Kuparuk River Formation at initial reservoir conditions. The Kuparuk River Formation is underlain by the Miluveach and Kingak shale sequence. A leakoff test in the Kingak shale formation demonstrates leakoff at a gradient of approximately 0.85 psi per foot. In addition, rock mechanics calculations and data from 19 the Prudhoe Bay Oil Pool indicate that sandstone fracture 20 gradients are reduced during waterflooding operations due to 21 reduced in-situ rock stress associated with the injection of 22 water that's colder than the reservoir. A tertiary water 23 source system would have an expected surface water injection 24 temperature of 60 to 80 degrees Fahrenheit, resulting in a 25 fracture gradient reduction of 0.3 to O. -- I'm sorry, excuse MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · 7 8 9 10 11 12 13 · 14 16 17 18 19 20 21 22 23 24 25 · e e 55 1 me, 0.03 to 0.05 psi per foot. The produced water from GC1 2 would have limited impact on the fracture gradient because the 3 water temperature would be close to the reservoir temperature. 4 Hydrocarbon Recovery. The Midnight Sun Oil Pool is 5 estimated to have an original oil in place of 40 to 60 million 6 stock tank barrels. Reservoir stimulation studies indicate incremental recovery from waterflood to be between 15 to 25 percent of the original oil in place relative to primary depletion. This concludes the testimony on the area injection operations for the Midnight Sun Pool. It also concludes our testimony for the combined application. So, if there are any questions, we can address those now. COMMISSIONER SEAMOUNT: Well, I haven't seen 15 any written questions. Mr. Groth. MR. GROTH: If I may, we appreciate the opportunity to elaborate on one question that was asked earlier regarding plans for the deeper horizons and the E-100 well. COMMISSIONER SEAMOUNT: Okay. MR. GROTH: We spoke with future plans on the Ivishak. With regard to the Sag River though, we just submitted a request of the Commission to approve a testing operation in the Sag River Formation in that well prior to the conversion of that well to injection. So, if you haven't seen that, it should be arriving shortly. MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 56 1 COMMISSIONER SEAMOUNT: Great. Sounds 2 interesting. 3 MR. GROTH: Thank you. 4 Thank you. Well, do COMMISSIONER SEAMOUNT: 5 you have any questions, Commissioner Oechsli? 6 COMMISSIONER OECHSLI TAYLOR: I don't. That 7 was an excellent presentation. 8 Yes. If there are no COMMISSIONER SEAMOUNT: 9 questions, we would like to thank the applicant for corning in. 10 You've given a very complete presentation. Looks like a very 11 good project. We wish you all the best of luck. And I guess 12 it's appropriate to go ahead and close the meeting. Thank you. 13 (Off record 10:52 a.m.) 14 END OF PROCEEDINGS 15 16 17 18 19 20 21 22 23 24 25 METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · 4 5 6 7 8 9 10 11 12 13 · 14 15 16 17 18 19 20 21 22 23 24 25 · e e 1 C E R T I FIe ATE 2 UNITED STATES OF AMERICA) ) ss. 3 STATE OF ALASKA ) I, Laura Ferro, Notary Public in and for the State of Alaska, and Reporter for Metro Court Reporting, Inc., do hereby certify: That the foregoing Alaska Oil & Gas Conservation Commission Public Hearing, was taken before myself on the 21st day of June 2000, commencing at the hour of 9:23 o'clock a.m., at the offices of Alaska Oil & Gas Conservation Commission, 3001 Porcupine Street, Anchorage, Alaska; That the hearing was transcribed by myself to the best of my knowledge and ability. IN WITNESS WHEREOF, I have hereto set my hand and affixed my seal this 3rd day of July 2000. ~?~ Notary Public in and for Alaska My commission expires: 05/03/01 MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 ~8 · e ALASKA OIL AND GAS CONSERVATION COMMISSION PUBLIC HEARING JUNE 21, 2000 9:15 AM MIDNIGHT SUN NAME - AFFILIATION TELEPHONE Do you plan to testify? Yes No (pLEASE PRINT) K Y-L~ }Jcl~/f>^( A- ---4~.wG..:,~ ~~A< '-¡J&lk \ l~~Qtt tJ~l~$P; . ~V\, re k .' ~\~:~;:> rr-Lt KhÁbJ//) ~J?t~ Mavle.- {jJ:JVC¿~ ~ r Æ ( c.. Af2. L- L v....J1 ~e',.¡ :::P Â:l. t\~ ~S boc~ \\cj¡)\ \ r:Â¡ V,(~ ~ ~~( 1-1 ( 0 P X fhttR.G¡,1('<.&í s . WO~(7 - e~'ff"Mt'bi I \ S ~ H t.'tif<- CJ' ~ ~'(O'" ~~r! ;11 ICHJ\.f:L- ;S;;~ rJ~O,J - &"xo,.J 110 BI L- yg ikj/QS ,1/,hÎs~ f!!;¿ ~,,( PDskýð+-\ fÆ/- EI</c PLETCHE¡¿ f'xY..ol1f'1ob;¡ ,6J C/~).,)/ /ló(!,~ J;M 'iOU^I(~ fA ! ",.5/L tr<:.- ~C'- t/ /~~ 40(;C~é Älf8-3b~ ~ 2£,~c. s ~ ¿" a;s ~ ¡ 504- ~~S-- ~/OPJ ?6~-t/K/5 2-~ ...,.... -6.;-'-< <( YÞJ' 'æS y~ '- ,,:::,-. <.ø L.. 0 ." ~lf· ~110 ~ j.(LI_· S;lb 6lt;+, 11 ~ $~~-]? ;);). ç~ ~- 3 Î / I S b y.-- Si5i? Z~5- 1'1':/(, 56'1 - J6ò '7 ?t.~-/?3Õ 2C ~ / '-I 5() <-I 713 -/22...<1 IVO l/?ú rJo No N;; NO V<:-. No rJo fljo ND M\ /'JO /\/0 ~7 . . ALASKA OIL AND GAS CONSERVATION COMMISSION NAME - AFFILIATION (pLEASE PRINT) ---l J/G-ot..o~ 4,u-;¡ðS ¡vk v(<:-<-tJ~ç. ~ ('- .:::J (IV..... ~. ~ t....J 1À~ r~L-.- ( ~~J June 13, 2000 9:00 AM PUBLIC HEARING - MIDNIGHT SUN TELEPHONE 2(;. S--:'::-¿: 9 4" Z & ~'";. G,'j''f'f LQq- ß"f~~ a...v... . J" ~ ~ ,~ Do you plan to testify? Yes No )&~ VlQ tJo ~6 ".. . . . .... .. Midnight Sun Oil Pool Pool Rules And Area Injection Application Revised June 21, 2000 '" Midnight Sun Pool Rules and Atlnjection Application . June 20, 2000 .J Table of Contents I. Geology p. 1 II. Reservoir Description and Development Planning 5 rn. Facilities 15 IV. Well Operations 18 V. Production Allocation 22 VI. Area Injection Operations 23 VII. Pool Rules- Proposed Findings, Conclusions, and Rules 29 vrn. Area Injection Application - Proposed Findings, Conclusions, and Rules 37 IX. Exhibits 41 ... Midnight Sun Pool Rules and .Injection Application . June 20, 2000 I. Geology Introduction The Midnight Sun Pool is located on Alaska's North Slope, as illustrated in Exhibit 1-1. The Midnight Sun Pool was discovered in 1997 during the drilling of the Sambuca #1 (E-100) well. The Midnight Sun Pool is located north of the Prudhoe bounding fault system and southwest of the Pt. McIntyre Pool. The reservoir interval is the Kuparuk River Formation. The E-100 well is the first well to encounter the Kuparuk River Formation in this area. The Fawn Lake #1, Abel State #1, North Prudhoe Bay State #1 and #2, North Prudhoe #3, Term Well A wells, and wells drilled from nearby pads in the Prudhoe Bay Field did not encounter the Kuparuk River Formation. Exhibit 1-2 shows the location of the Midnight Sun Participating Area (MSPA). Development drilling will utilize the existing gravel E-pad, from which the E-100 discovery well was drilled. One delineation well, the Midnight Sun #1 (E-101), was drilled from E-pad in October 1998 to confirm the extent of the Midnight Sun discovery. Stratigraphy The Midnight Sun Pool is composed of the Kuparuk River Formation, also informally referred to as the "Kuparuk Formation". This formation was deposited during the lower Cretaceous geologic time period, between 153 and 115 million years before present. Exhibit 1-3 shows a portion of the open hole electric logs from the E-100 well. This "type log" illustrates the stratigraphic definition of the Midnight Sun Pool. The log is scaled in true vertical depth subsea (tvdss) and also has a measured depth (md) track. In the E-lOO well, the top of Kuparuk Formation occurs at 7,974 ft. tvdss (11,662 ft. md) and the base occurs at 8,074 ft. tvdss (11,805 ft. md). This is also the productive interval of the Midnight Sun Pool. The Kuparuk Formation base is defined by its contact with the Jurassic-age Kingak Formation as Page 1 of 41 Midnight Sun Pool Rules and A!Injection Application e June 20, 2000 seen with a change in lithology and conventional electric log character. The Kingak Formation is a shale with low resistivity (1 to 3 ohm-meters). The Kuparuk Formation is composed of medium- to fine-grained quartz-rich to glauconitic sandstone with higher resistivity (3-50 ohm- meters). The Kuparuk Formation top is defined by its contact with the lower Cretaceous-age High Radioactive Zone (HRZ) Formation as seen by a change in lithology and conventional electric log character. The HRZ is a black, organic-rich shale recognized by the gamma ray log, typically greater than 150 gamma API units. The Kuparuk Formation in the Midnight Sun Pool is stratigraphically complex, characterized by rapid change in thickness, sedimentary facies and local diagenetic cementation. Lithology is dominantly sandstone with lesser amounts of siltstone and sandy mudstone. As shown on the type log in Exhibit 1-3, the Kuparuk Formation can be divided into upper and lower units. The basal portion of the lower unit in E-101 is a non-productive, tight, glauconitic sandstone with minor amounts of shale rip-up clasts. This unit was not encountered in E-I00 and is assumed to be restricted to the area near E-lOl. Moving up in the lower reservoir unit, which is typically about 40 feet thick, the lithology changes abruptly to porous, quartz-rich sandstone. Grain size is typically very fine to fine-grained and is well sorted. The lithology of the upper unit is variable including interbedded sandstone with minor amounts of muddy siltstone. The thickness of this interval is variable and ranges from 0 to 70 feet. This interval contains glauconite and siderite and is more prone to reductions in porosity and permeability due to cementation and compaction. The sands in the upper unit are poorly to well- sorted. Intergranular siderite cement is common in the upper unit and plays an important role in determining reservoir quality. Cementation is especially abundant in the lower portion of the upper unit where it degrades reservoir quality. The upper and lower units have distinctly different thickness trends. The lower unit maintains a nearly uniform thickness throughout the Midnight Sun area, suggesting that its deposition predates significant fault movement. In contrast, the thickness and lithology of the upper unit are variable and have been influenced by syn-depositional faulting. Page 2 of 41 Midnight Sun Pool Rules and A_Injection Application . June 20, 2000 Structure Exhibit 1-4 is a structure map on the top of the Kuparuk Formation with a contour interval of 20 feet. Top Kuparuk structure in the Midnight Sun area is characterized by a bowl-shaped depression gently dipping to the northeast. The Midnight Sun depression is bounded to the west by the Prudhoe Mid-Field fault, to the south by the Prudhoe bounding fault system, to the north by the Sambuca fault, and to the east by the North Prudhoe structural high. The top of the -.--....--.... Kuparuk horizon reaches a structural high to the southwest at 7,780 ft. tvdss against the Prudhoe bounding fault. The Kuparuk Formation dips eastward to a zero edge against the North Prudhoe high at approximately 8,100 ft. tvdss. The structural highs surrounding the Midnight Sun accumulation are devoid of Kuparuk Formation rock. Along the axis of the depression, the structural dip is less than 2 degrees, down to the northeast. Exhibit 1-5 is an isochore map of the Kuparuk Formation with a contour interval of 10 feet. The Midnight Sun accumulation is a combination structural/stratigraphic trap, with isolation assisted by neighboring structural highs that are fault controlled. The controls on Kuparuk Formation thickness are fault movement and erosional truncation. Kuparuk Formation deposition occurred in marine shoreface and deltaic depositional environments. Exhibit 1-6 is a structural cross-section along the axis of the Midnight Sun structural depression (see Exhibit 1-1 for location). This cross-section illustrates the western and eastern limits of the Midnight Sun Pool. The western limit of the pool is fault-controlled by the Prudhoe Mid-Field fault and the eastern boundary is a stratigraphic truncation of the Kuparuk Formation onto the North Prudhoe structural high. Exhibit 1-7 is a north-south structural cross-section through the Midnight Sun Pool (see Exhibit 1-1 for location). This exhibit illustrates the fault-bounded isolation of the Kuparuk Formation on the north by the Sambuca fault and on the south by the Prudhoe bounding fault system. Fluid Contacts The Midnight Sun Pool gas-oil contact (GOC) is interpreted to be at a depth of 8,010 ft. tvdss, Page 3 of 41 e Midnight Sun Pool Rules and Area Injection Application e June 20, 2000 based on Repeat Formation Tester (RFT) data. No oil-water contact (OWC) was identified in either of the Midnight Sun wells. Based on core water saturation data and Mercury Injection Capillary Pressure data, the reservoir is interpreted to be significantly above the effective OWC. Heavy oil was encountered at 8,107 ft. tvdss in the E-101 well. A heavy oil sample, measuring 10 degrees API gravity, was recovered by the RFT at 8,107 ft. tvdss. Conventional core from the E-101 well contained heavy oil in the lower Kuparuk section below 8,107 ft. tvdss. The areal extent of the heavy oil is uncertain. Pool Limits The trap for oil and gas in the Midnight Sun Pool is created by a combination of structural and stratigraphic features. To the south, west, and north, the pool limit is defined by the juxtaposition of the reservoir against the impermeable Kingak shale across the Prudhoe bounding fault system, Prudhoe Mid-Field fault, and Sambuca fault, respectively. Stratigraphic truncation of the Kuparuk Formation forms the trapping mechanism to the east. The boundaries of the Midnight Sun P A encompass the proposed boundaries of the Midnight Sun Pool. Exhibit 1-8 is a net sandstone map of the Midnight Sun Pool with a contour interval of 2-feet. Exhibit 1-9 is a gross hydrocarbon distribution map of the Midnight Sun Pool. Page 4 of 41 .. Midnight Sun Pool Rules and Aenjection Application e June 20, 2000 II. Reservoir Description and Development Planning ROCK AND FLUID PROPERTIES The reservoir description for the Midnight Sun Pool is based on core data from the E-101 well and log data ftom @sambuca # 1) aeYMidu¡ght Sun #1) wells. Well E-I 0 1 was cored through the~reKuparuk section with water based mud and low invasion coring techniques. The core data were used to calibrate the petrophysical log model, which was used to construct the Midnight Sun geologic model. Porosity and Permeability Core porosity and permeability measurements were conducted at overburden pressure and permeability was corrected for gas slippage (Klinkenberg correction). Mean porosity for the upper Kuparuk Formation is 20.7%, based on E-lOl core data. In the lower Kuparuk Formation, excluding the non-reservoir basal interval, the mean porosity is 27.3%. Mean permeability for the upper Kuparuk Formation is 200 md, based on E-1 0 1 core data. In the lower Kuparuk Formation, excluding the non-reservoir basal interval, the mean permeability is 760 md. The ratio of vertical to horizontal permeability ranges from 0.2 to 1.0 in the upper Kuparuk Formation and from 0.6 to 1.0 in the lower Kuparuk Formation. Net Pay Net pay was determined based on visual inspection of the E-101 core in conjunction with review of thin section and routine core analysis data. The Kuparuk Formation in the Midnight Sun Pool has very low clay content, generally less than 2% by volume, and no defined shale sections. In the upper Kuparuk Formation, reservoir volume is reduced by the presence of discontinuous, nodular and banded siderite and glauconite. These mineral inclusions were identified visually, and the net-to-gross-ratio was determined based on the ratio of reservoir quality sand to gross rock area exposed on the slabbed core. The net-to-gross ratio for the upper Kuparuk Formation ranges from 0.25 - 0.72. The lower Kuparuk Formation has negligible glauconite and siderite content and exhibits a net-to-gross ratio of approximately 1.0. The non-reservoir basal interval in Page 5 of 41 e Midnight Sun Pool Rules and Area Injection Application e June 20, 2000 the lower Kuparuk Formation section is heavily cemented, with a net-to-gross ratio of 0.0. Water Saturation Water saturation data were measured throughout the Kuparuk Formation interval in the E-10 1 low invasion core. A chemical tracer confirmed that the core experienced minimal invasion. Water saturation data were corrected for mud filtrate invasion based on the tracer results. Water saturation measurements from the core were then used to calibrate the petrophysical log model. Mean water saturation for the upper Kuparuk Formation is 26.4%, based on E-101 core data. In the lower Kuparuk Formation, excluding the non-reservoir basal interval, the mean water saturation is 12.6%. Water saturation data derived from the core and log data were used to develop Leverett J- functions, which were subsequently translated to drainage capillary pressure curves for the upper and lower Kuparuk Formation intervals. The capillary pressure data were then used to initialize water saturation in the reservoir model based on capillary pressure equilibrium. Relative Permeability A steady state water-oil relative permeability experiment was conducted on a composite core from the upper Kuparuk Formation interval. The residual oil saturation from this displacement experiment was 22.7%. Centrifuge water-oil and gas-oil experiments were also conducted. Results from these experiments indicate that water-oil relative permeability measurements for the Midnight Sun Pool are similar to those measured for other North Slope fields exhibiting favorable waterflood performance. In the absence of having an extensive data set for all relative permeability functions, analog data sets were used for performance predictions. Initial Pressure & Temperature Based on RFf data, the initial reservoir pressure is estimated at 4058 psia at the reservoir datum .".,.,~_u__~__~..,.",·,...~,______ of 8050 ft. tvdss. The reservoir temperature is approximately 160 degrees Fahrenheit at the .~._.- datum. Page 6 of 41 ... Midnight Sun Pool Rules and Aenjection Application e June 20, 2000 Fluid PVT Data Reservoir fluid PVT studies were conducted on a recombined surface sample obtained from the E-101 well. The sample was recombined to the bubble point pressure of 4045 psia, corresponding to the pressure at the GOC at initial conditions. The API gravity of the PVT sample was 25.5 degrees with a solution gas-oil-ratio (GOR) of 717 scf/stb, a formation volume factor of 1.33 RVB/STB, and an oil viscosity of 1.68 centipoise at the bubble point pressure. Exhibit II-I shows a summary of the fluid property information for the Midnight Sun Pool. Exhibit II-2 contains a listing of the various pressure-volume-temperature (PVT) properties as a function of pressure. Hydrocarbons in Place Estimates of hydrocarbons in place for the Midnight Sun Pool reflect current well control, stratigraphic and structural interpretation, and rock and fluid properties. These data were integrated in the construction of a fine scale geologic model, which provides the basis for estimation of original fluids in place. The results indicate an Original Oil In Place (OOIP) ra.~ge of~O to 60 MMSTB,a.!l(:LtQ.t~s in place of 100 to 130 BSCF. The free gas volume associated //'" "'" '-........................... ..........._.......................-..._.................._........._._....~ with the gas ca~~_~..~~~~~~:J RESERVOIR PERFORMANCE Well Performance Two wells (E-I00, and E-l 0 1) have been drilled and completed in the Kuparuk formation. Both wells are tied into the Prudhoe Bay E-Pad facilities. Production commenced in October of 1998. We¡ÚE-lO~ (Sambuca #1), the discovery well, encountered 100 feet of gross hydrocarbon col~. ·wi'h 36feet of gas above the oil column. The well was perforated over a 20 feet interval at the base of the reservoir. The initial production rate was 2,000 to 3,000 BOPD with a GOR of approximately 950 scf/stb. The rate was restricted to mitigate coning, although the GOR increased steadily to 6000 scf/stb during the first three months of production. The well is currently shut in to limit reservoir voidage. Page 7 of 41 .. Midnight Sun Pool Rules and A!njection Application e June 20, 2000 Well E-101 (Midnight Sun #1) was drilled as a do.:vnstructure delineation well in the Midnight Sun Pool. The well encountered 84 feet of gross hydrocarbon column all below the GOC identified in the E-lOO well. No oil-water contact was identified by open-hole logs. The initial production rate in November of 1998 was 7000 to 8000 BOPD with a GOR of approximately 800 scf/stb. In January of 1999, the well was restricted to 5000 BOPD to conserve reservoir energy while completing reservoir surveillance and field development studies. Gas Coning Production from the E-100 well is affected by gas coning. E-100 is a deviated well with an inclination of 46 degrees across the Kuparuk. The well is completed with a standoff of 42 feet tvd from the GOc. During the first 10 days of production, the GOR in the E-100 well increased to 2000 scf/stb. The production rate was restricted to mitigate coning. The cement bond log in this well is interpreted to show good cement quality; and the coning interpretation was confirmed by production logging. Subsequent inspection of the E-101 core confirmed that intra-formation cementation in the upper Kuparuk would act as a baffle but not a barrier to vertical flow. With slightly more than 50% of the oil column overlain by the gas cap, coning can be a significant reservoir mechanism in the Midnight Sun Pool. Gas Under-Running The Midnight Sun reservoir is a thin reservoir with a structural dip of less than 2 degrees. The low structural relief results in a gas cap that overlays more than 50% of the areal extent of the oil column. Reservoir model results, calibrated to field performance, suggest that gas under-running, which is movement of gas below a barrier, will impact early field performance and is a mechanism to address in depletion planning. The GOR at well E-101 is currently 5000 scf/stb and increasing consistent with predictions. The lo~ structural relief at the Midnigh~ Sun reservoir@ the effectiveness of gas cap expansion or gas injection as a recovery mechanism. Page 8 of 41 Midnight Sun Pool Rules and A.njection Application e June 20, 2000 DEVELOPMENT PLANS A reservoir model of the Midnight Sun Pool was constructed to evaluate development options, investigate reservoir management practices, and generate rate profiles for facility design. This section of the application describes the reservoir model, modeling results and the development plans. Reservoir Model Construction A fine scale three-dimensional geologic model of the Midnight Sun Pool was constructed based on detailed stratigraphic and structural interpretation. This model provided the bulk reservoir volume and distribution of porosity and penneability used in the construction of the Midnight Sun reservoir model. The reservoir model is a three-dimensional, three-phase, black oil finite difference flow simulation model. The model area encompasses the graben fault block defining the Midnight Sun Pool. Areal gridding is 250 feet by 250 feet (1.43 acre cells). The vertical gridding is defined by 15 model layers with nominal thicknesses of 4 to 8 feet. Exhibit ll-3 shows average physical properties for each model layer. Faults and juxtaposition are honored through comer point geometry and non-local grid connections. Water saturation in the reservoir model was established by capillary pressure equilibrium. There is no aquifer in the reservoir model. Capillary pressure measurements suggest that the effective OWC is below the structural limit of the reservoir. The reservoir pressure was set to 4045 psia at the GOC of 8010 ft. tvdss, based on the RFf data. Exhibit ll-4 shows the comparison of model predictions and field perfonnance. For the history match, oil rate is specified and reservoir pressure and well GOR are predicted. A history match of reservoir pressure was achieved with no modification to the gas cap volume in the reservoir model. The GOR history match reflects accurate modeling of both the coning (E-IOO) and under-running (E-101) reservoir mechanisms. The down structure pore volume was increased to reflect under-run timing at well E-I01. Page 9 of 41 Midnight Sun Pool Rules and A.njection Application e June 20, 2000 Model Results Three development options were evaluated for the Midnight Sun Pool: 1) primary depletion, 2) up structure gas injection, and 3) waterflood. Primary Recovery Primary recovery was evaluated with E-101 well as the single down structure producer. The primary recovery mechanism was a combination of gas cap expansion and solution gas drive. The gas cap at Midnight Sun contains approximately 40 percent of the total reservoir hydrocarbon pore volume. Model results indicate that prig¡ary depletion would achieve an estimated 14% recovery of th~ OOIP. Exhibit II-5 shows production and recovery profiles for primary depletion. The "~------ performance is attributed to depletion of the gas cap and associated reduction in reservoir energy. The model shows gas under-running and high GOR production at Well E-101. The reservoir pressure was depleted at the end of the model run and the majority of the original gas cap volume had been produced. Upstructure Gas Injection Upstructure gas injection was evaluated with a horizontal injection well installed in the Midnight Sun gas cap. Reservoir management for this case assumed that injection would be sufficient to increase reservoir pressure back to the original condition and then maintain a voidage replacement ratio (VRR) of 1.0. The peak injection requirement for this case was 40 MMscfd. Model results indicate that upstructure gas injection would achieve an estimated 20% recov~ the OOIP after 1.0 hydrocarbon pore volume injection (HCPVI). Recovery of 27% was observed ~- with 2.0 HCPVI. Exhibit II-6 shows production and recovery profiles for up structure gas injection. Up structure gas injection results in gas under-running the top Kuparuk Formation and then coning into the perforations at the downstructure producer. As a result of these mechanisms, the vertical sweep efficiency for up structure gas injection is poor with correspondingly low recovery in the lower Kuparuk Formation. Waterflood Several waterflood development options were studied using the Midnight Sun reservoir model including upstructure, downstructure, and midfield water injection. Both the Page 10 of 41 Midnight Sun Pool Rules and A.njection Application e June 20, 2000 upstructure and midfield options involve water injection at or near the original gas cap. All waterflood options result in some degree of resaturation of the gas cap by oil in the midfield area. Case studies of successful application of this type of waterflood process are documented in the literature. The midfield configuration showed the best overall waterflood performance with greater ultimate recovery and an earlier production profile associated with improved pressure response relative to the other cases. The midfield configuration involves conversion of the E-I00 well to injection service. Initial production was from the E-101 well. An up structure horizontal production well is completed 2,000 to 4,000 feet east of the western limit of the light oil column. This well was managed in the reservoir model to limit gas coning. Th~dfield waterflood sho~ improved waterflood response over the up structure and down structure injection options, as evidenced by lower peak: GOR and faster pressure response. Waterflood fill-up is achieved within two years of waterflood start-up. The improved response is attributed to closer injector / producer spacing and greater distance of the key production well from the gas cap. Th~ld wa~njection case achieved an estimateçl39% recovery <It 0.7 !ICPVI. Cumulative gas production is lower relative to the upstructur:finjection case. Exhibit II-8 shows production and recovery profiles for midfield water injection. The ~figuration included a new horizontal injection well towards the western limit of the light oil column. The configuration was envisioned as a means of isolating the gas cap while waterflooding the midfield and down structure areas. The primary down structure producer would be well E-101, although the E-lOO well was also produced for a limited time. Model results for up structure water injection indicate that the western limit of the gas cap can be isolated, and ~la~sic ~_ªt.~[f.I2ººfI!1':llP~~_!~~P~~~~_~e ~hieve~Lwithin three years of waterflood start-up. The upstruc_ture water injection case achieves an estimated 39% recovery at 0.7 HCPVT, J although production response to waterflood is slower and gas production is greater relative to the --- ' '--::::.. ~ The ~onfiguratiOn involves conversIOn of Wen E-101 to injection sefV1CC. Production from Well E-100 would be resumed and rate would initially be restricted to mitigate Page 11 of 41 Midnight Sun Pool Rules and Alnjection Application It June 20, 2000 conmg. In the down structure waterflood configuration, an up structure horizontal production well is drilled to recover upstructure reserves. Waterflood performance for down structure injection is less attractive than the other waterflood configurations. In this configuration, gas coning and - , under-running at Well E-100 require restricted field rate and continue to be a production issue for both production wells. The down structure water injection case achieves an estimated 31 % recovery at 0.56 HCPVI with a delayed production profile relative to the upstructure and midfield alternatives. Enhanced Oil Recoverv (EOR) Preliminary analysis indicates there may be potential for enriched gas injection at Midnight Sun; however, no EaR project evaluations have been initiated. Due to the technical complexities, reservoir uncertainty, and costs involved, improved -".,.-....-.-,---;> reservoir description and additional field performance data are necessary bef0r.e these options may be fully evaluated. Development Plans Based on reservoir model studies, the recommended development plan is implementation of a - --....:> mi~!ield waterflood for the Midnight Sun Pool. This plan provides the most favorable production profile, while minimizing cumulative gas production and maximizing ultimate recovery. Water injection is expected to commence in the third quarter of 2000, with design injection rates of 20-25,000 BWPD. A peak production rate of 8-10,000 BOPD is expected prior to waterflood breakthrough. Waterflood Sensitivity Studies Reservoir model sensitivity studies were conducted in support of development planning. Model runs were conducted to optimize well placement and completion design. Sensitivities to key model assumptions, including relative permeability, vertical permeability, and oil viscosity were evaluated. None of these assumptions were found to significantly alter development plans. Other sensitivity studies included the effect of continued production prior to waterflood startup. Earlier waterflood startup mitigates reservoir pressure decline and reduces peak GOR response prior to waterflood fill-up. However, no recovery impact was identified with a waterflood start- up during third quarter 2000, assuming continued production of 5,000 BOPD until start up. In Page 12 of 41 Midnight Sun Pool Rules and Altnjection Application -- June 20, 2000 the reservoir model, reservoir pressure declined to 3300 psi, and GOR peaked at 8000 SCF/STB. Well Spacing The planned development well prog:<:1:!!l- ~.cl.dition of one upstructure horizonta~ production well to complete a €e well of the Midnight Sun Pool. The »..-,.;- development will form an irregular pattern due to the constraints of development within a small fault block. This well spacing is nominally 280 acres. Closer well spacing does not appear to be justified due to the thin oil column; however, infill drilling and/or peripheral drilling along the eastern margin of the field will be evaluated as field development continues. To allow for flexibility to respond to these conditions, a minimum well spacing of 80 acres is requested. RESERVOIR MANAGEMENT STRATEGY Gas cap expansion will provide initi pressure support prior to waterflood start-up. Following If' ~ waterflood start-up, the VRR target will exceed 1.0 to suppress gas production and restore reservoir pressure. A balanced VRR will be maintained once reservoir pressure is restored to a target range of 3800 - 4000 psi. In the planned waterflood configuration, oil flux into the gas cap is anticipated in the midfield area due to low structural relief. Reservoir surveillance and voidage management, however, should minimize oil flux to the west of the up structure horizontal producer. The objective of the Midnight Sun reservoir management strategy is to manage reservOIr development and depletion to achieve the maximum ultimate recovery consistent with good oil field engineering practices. To accomplish this objective, reservoir management is approached as a dynamic process. The initial strategy is derived from model studies and limited historical performance. New well results and additional reservoir performance data will increase knowledge and improve predictive capabilities resulting in adjustments to the initial strategy. The reservoir management strategy for the Midnight Sun Pool will continue to be evaluated throughout field life. Page 13 of 41 Midnight Sun Pool Rules and A.njection Application - June 20, 2000 Reservoir Performance Conclusions Reservoir model results support implementation of a waterflood in the Midnight Sun Pool. An initial three well development program is contemplated, with midfield water injection at Well E- 100, and the addition of one up structure horizontal producer. Water injection is expected to -- commence in the third quarter of 2000, with design injection rates of 20-25,000 BWPD. Following initiation of waterflood, a peak production rate of 8-10,000 BOPD is expected. We request that the Operator be allowed to determine the field off-take rate based upon sound ? .¿ reservoir management practices. Page 14 of 41 Midnight Sun Pool Rules anAa Injection Application e June 20,2000 III. Facilities GENERAL OVERVIEW Midnight Sun wells will be drilled from the E-Pad drill site. Surface facilities include an existing IP A drill site, pipelines and processing facilities to produce Midnight Sun Reservoir fluids. Midnight Sun fluids will be commingled with Initial Participating Area (IP A) fluids on the surface at E-Pad and then transported to Gathering Center 1 (GCl) for treatment and shipment to Pump Station No. 1 (PS-l). Midnight Sun will make use of existing IP A infrastructure. This minimizes environmental impacts and reduces costs to help maximize recovery. Use of the GCl production facility includes separating and processing equipment, inlet manifold and related piping, flare system, and water injection facilities. IP A field facilities that will be used include 24" low-pressure common line from E-pad to GCl, 16" and 6" high-pressure common lines from E-pad to GCl, oil sales line from GCl to PS-l and the power distribution and generation facilities. Plans to deliver GCl produced water to E-pad using an existing 6" IPA flowline are also being considered. Exhibit III-I is an area map showing locations of the facilities that will be used for Midnight Sun development. Drill Sites, Pads, and Roads Use of the E-Pad drill site for the Midnight Sun wells has been selected to (1) eliminate new gravel placement, (2) minimize well stepout to within currently available drilling technology while reaching the extent of the reservoir, and (3) maximize the use of existing facilities. Wells will be drilled between existing IPA wells, eliminating the need to expand the E-Pad. A schematic of the drill site layout is shown in Exhibit III-2. This schematic shows facilities for a local source water injection system. As an alternative, the Midnight Sun owners are working towards approval to use GC 1 produced water as a water source for the Midnight Sun project. No new pipelines will be required for development of the Midnight Sun reservoir. Midnight Sun production will be routed to GCl via existing E-Pad high pressure and low-pressure Page 15 of 41 Midnight Sun Pool Rules and.a Injection Application e June 20, 2000 commonlines. No new roads or roadwork will be required. Drill Site Facilities and Operations Two existing E-Pad production manifold slots and well lines will be used for the Midnight Sun wells. Water for waterflood operations will be obtained from either source water wells drilled at E-pad or produced water delivered by pipeline from GC 1. If the source water system is installed, the source wells would be equipped with electrical submersible pumps (ESPs) to deliver water to the project. The source water injection system option is illustrated in Exhibit III-3. Future gas lift gas will be obtained from an IP A E-pad well. Gas removed from this well for raw gas lift will be metered prior to the gas being introduced into any Midnight Sun well. This IP A gas will be returned to the IP A. If initial power is needed beyond currently available capacity at E-pad, it will be provided by installing a new 15 kv power line from GCl to the Midnight Sun facilities at E-Pad. All well "~._.,..,,"-~ control at the drill sites will be performed manually by a drill site operator with the exception of ...------"""'..-----.-- the well safety shut in systems (which are automatic) and the drill site emergency shutdown system (which can be triggered manually or automatically). Initially, production will be allocated based upon well tests as previously approved by the Commission. After a new metering skid is installed in the third or fourth quarter 2000, Midnight Sun production will be continuously metered prior to combining with IP A production. The skid will consist of a two-phase separator, with liquids measured by a mass meter and gas production measured by conventional orifice plate methods. The Midnight Sun oil gravity will be used to calculate the oil and water volumes based on the liquid mass measurement. After metering, the gas and liquid streams will be re-combined and commingled with IP A fluids at E-Pad for transport to GC 1. The data obtained from the metering skid will provide the basis for allocating production between Midnight Sun and the IPA. Production allocation is addressed in Section V. Data gathering at the drill site will be both a manual and automatic function. The data gathering system (SCADA) will be expanded to accommodate the Midnight Sun wells and drill site equipment. The SCADA will continuously monitor the flowing status, pressures, and Page 16 of 41 Midnight Sun Pool Rules an~a Injection Application e June 20, 2000 temperature of the producing wells at the drill sites. These data will be under the drill site operator's supervision through his monitoring station. Midnight Sun production metering will continuously monitor the pressures, temperatures, and flow of the liquid and gas streams. The rate of production from each well will be regulated by manually adjusted chokes. The flow from the wells would be routed to the production metering skid and then to GC 1 for processing. Production Center No modifications to the GC1 production center will be required to process the Midnight Sun production. GC1 was built to process a nominal oil rate of 400 MBOPD, gas rate of 320 MMSCFPD (modifications have increased this to 2,600 MMSCFPD) and a produced water rate of 40 MBWPD (modifications have increased this to 85 MBWPD). Production, including that from the Midnight Sun Reservoir, is not expected to exceed existing GC1 capacity. Page 17 of 41 Midnight Sun Pool Rules and.a Injection Application e June 20, 2000 IV. Well Operations DRILLING AND WELL DESIGN Two wells have been drilled in the Midnight Sun Pool, E-100 and E-lOl. E-101 is currently producing with plans to convert E-l 00 to an injector. Exhibit IV-I shows the schematic of the E- 100 well. The Midnight Sun depletion plan calls for drilling one additional up structure production well to complete the initial development. If the source water injection system is installed, two shallow source water wells would also be drilled. Midnight Sun wells would be directionally drilled from E-Pad utilizing drilling procedures, well designs, and casing and cementing programs similar to those currently used in other North Slope fields. A 20-inch conductor casing will be set 80 feet below pad level and cemented to surface. Consideration will be given to driving or jetting the 20-inch conductor as an alternative setting method. A diverter system meeting Commission requirements will be installed on the conductor. Surface hole would be drilled no deeper than 5,000 ft. tvdss. This setting depth provides sufficient kick tolerance to drill the wells safely and allows the angle-build portions of high departure wells to be cased. No hydrocarbons have been encountered to this depth in previous Midnight Sun wells. Cementing and casing requirements similar to other North Slope fields will be adopted for Midnight Sun. The casing head and a 5,000-psi blowout-preventer stack will be installed onto the surface casing and tested consistent with Commission requirements. Production hole will be drilled below surface casing to the Kuparuk Formation, allowing sufficient rathole to facilitate logging. Production casing will be set and cemented. Intermediate casings and production liners will be used to achieve specific completion objectives or to provide sufficient contingency in mechanically challenging wells such as high departure wells. To date, H2S has not been detected in any Midnight Sun wells. However, with planned waterflood operations, there is some potential of generating small amounts of H2S over the life of the field. Page 18 of 41 Midnight Sun Pool Rules and.a Injection Application e June 20, 2000 Safe drilling practices, to account for the effects of H2S gas on both people and equipment will be followed, including continuous monitoring for the presence of H2S. A readily available supply of H2S scavenger, such as zinc carbonate, will be maintained to treat the entire mud system. Emergency operating and remedial protective equipment will be kept at the wellsite. All personnel on the rig will be informed of the dangers of H2S, and all rig site supervisors will be trained for operations in an H2S environment. The nature of the wells to be drilled requires the use of E-75, G-105, or S-135 grade drillpipe. These materials are susceptible to sulfide stress cracking but can be used safely under the controlled conditions recommended in Section 8, "Drill Stem Corrosion and Sulfide Stress Cracking," of API RP 7G, "Drill Stem Design and Operating Limits" which will be used as applicable. WELL DESIGN AND COMPLETIONS Contingent water supply wells would be drilled into the Tertiary interval and completed with a single casing string and downhole electric submersible pumps (ESPs). Open hole gravel packs would be used in the water supply wells to maximize productivity and prevent sand production. The upstructure horizontal producer is planned with a measured depth of over 14,000 ft. and would be completed in the Kuparuk Formation. This departure would necessitate top-setting the Kuparuk. In general, the production casing will be sized to accommodate the desired tubing size in the Midnight Sun wells. The following table indicates the casing and tubing sizes utilized in the proposed well designs for the Midnight Sun wells. Tubing sizes will vary from 3-1/2 to 4-112 inches in Midnight Sun wells. Surface Casing Inter 1 Prod Casing Production Liner Production Tubing Water Supply 9-5/8" N/A N/A 4-112" Horizontal 10-314" or 9-5/8" 7-5/8" or 7" 4-112" or 3-112" 4-112" or 3-112" Page 19 of 41 Midnight Sun Pool Rules and.a Injection Application . June 20, 2000 Plans are to run L-80 tubing and casing in these wells. All tubing jewelry will be completed with 9-CrIlMoly, which is compatible with both L-80 and 13-Cr. All proposed wells call for completion in a single zone, with a single string and a single packer. As shown in the schematic, the wells have gas lift mandrels with dummy valves to provide flexibility for artificial lift if needed to enhance production rates. Sufficient mandrels will be run to provide flexibility for changing well production volumes, gas lift supply pressure, and changes in WOR.. 1.\'_. l0~wf~ SUBSURFACE SAFETY VALVES Subsurface safety valves do not appear to be necessary in the Midnight Sun wells according to statewide regulations (20 AAC 25.265). Existing completions are equipped with SSSV nipples. The up structure producer would be completed in a similar manner. SURFACE SAFETY VALVES Surface safety valves are included in the wellhead equipment. These devices can be activated by high and low pressure sensing equipment and are designed to isolate produced fluids upstream of the SSV if pressure limits are exceeded. Testing of SSVs will be in accordance with the standard PBU Operator practices. DRILLING FLUIDS In order to minimize skin damage from drilling and to maintain shale stability, water-based KCl o,;'f: mud will be used to drill through the Midnight Sun Pool and nearby shales while low solids, non- dispersed fluids will be used for the upper sections of the well. STIMULA TION METHODS Stimulation to enhance productivity or injection capability is not currently planned for Midnight ----, Sun wells. Fonnation damage associated with drilling and completion activity appears to be Page 20 of 41 Midnight Sun Pool Rules and I Injection Application .' June 20, 2000 minor or insignificant. The use of stimulation in the medium to high permeability rock may be evaluated at a later date. RESERVOIR SURVEILLANCE PROGRAM Midnight Sun data will continue to be collected to monitor reservoir performance and, define reservoir properties. Reservoir Pressure Measurements An initial static reservoir pressure will be measured in each new well prior to production. /", Additionally, a minimum of one pressure survey will be tak.en(~rlnu~ for the MidnigbtSun - __________ c:s::: Pool. This will consist of stabilized static pressure measurements at bottom-hole or may be extrapolated from surface, pressure fall-off, pressure build-up, multi-rate tests, drill stem tests, and open-hole formation tests. The reservoir pressures will be reported at the common datum elevation of 8,050 ft. tvdss. Surveillance Logs Surveillance logs, which may include flowmeters, temperature logs, or other industry proven downhole diagnostic tools, will be periodically run to help determine reservoir performance (e.g., aoe monitoring and injection profile evaluation). ~~; Page 21 of 41 Midnight Sun Pool Rules anc6a Injection Application .' June 20, 2000 V. Production Allocation Initially, a combination of well tests and wellhead pressure trends will continue to be used to allocate production. Under this methodology, the production from an individual well is first calculated from the average daily wellhead pressure using the deliverability equation. During periods of rising GOR and changing tubing hydraulics, the deliverability equation may not accurately reflect the production as measured by well tests. During such periods, the daily well production is determined by linear interpolation between well test points. A minimum of two well tests per month, as well as lab-measured water cuts and zero-rate tests, are performed on Midnight Sun wells to ensure allocation accuracy. Summing the calculated daily production volume for all producing wells provides an estimate of the Midnight Sun daily field production. A fixed allocation factor of 1.0 is used for Midnight Sun. The long-term metering plan for Midnight Sun is to use continuous production metering. The metering skid described in the Facilities section of this application will be used to continuously meter the entire Midnight Sun production stream through a compact two-phase separator before it is commingled with IPA production at E-Pad. Each wellhead will have a continuous two- phase meter to monitor fluid and gas production, with monthly shakeouts to ascertain water cut. We request Commission approval under 20 AAC 25.215(a) that the Midnight Sun metering is an acceptable method. An allocation factor of 1.0 would continue to be used with the continuous meter. The Midnight Sun Pool will have a set allocation factor of 1.0, with production allocated back to individual wells using the continuous two-phase metering data to calculate wellhead allocation factors. Consistent with existing reporting, no NGLs will be allocated to Midnight 4__,^_ ~ Sun. Page 22 of 41 Midnight Sun Pool Rules anAa Injection Application e June 20, 2000 VI. Area Injection Operations This application, prepared in accordance with 20 AAC 25.402 (Enhanced Recovery Operations) and 20 AAC 25.460 (Area Injection Orders), requests authorization for water injection to ~~."..------~"'~ --. enhance recovery from the Midnight Sun Oil Pool. This section addresses the specific requirements of 20 AAC 25.402(c). PLAT OF PROJECT AREA 20 AAC 25.402(c)(1) Exhibit 1-2 shows the location of all existing injection wells, production wells, abandoned wells, dry holes, and any other wells within the Midnight Sun Oil Pool as of April 1, 2000. Specific approvals for any new injection wells or existing wells to be converted to injection service will be obtained pursuant to 20 AAC 25.005, 25.280 and 25.507, or any applicable successor regulation. OPERA TORS/SURFACE OWNERS 20 AAC 25.402(c)(2) and 20 AAC 25.402(c)(3) PHilLIPS Alaska, Inc. is the designated operator of the Midnight Sun Participating Area. Surface Owners within a one-quarter mile radius and inclusive of the Midnight Sun Participating Area are as followings: State of Alaska Department of Natural Resources Attn: Ken Boyd P.O. Box 107034 Anchorage, AK 99510 Pursuant to 20 AAC 25.402(c)(3), Exhibit VI-l is an affidavit showing that the Operators and Page 23 of 41 Midnight Sun Pool Rules anAa Injection Application e June 20, 2000 Surface Owners within a one-quarter mile radius of the area of and included within the Midnight Sun Participated Area have been provided a copy of this application for injection. DESCRIPTION OF OPERATION 20 AAC 25.402(c)(4) Development plans for the Midnight Sun Oil Pool are described in Section IT of this application. Drillsite facilities and operations are described in Section ill. If the source water injection system is installed, source water wells will be permitted and constructed in accordance with 20 AAC 25.005. GEOLOGIC INFORMATION 20 AAC 25.402(c)(6) The Geology of the Midnight Sun Oil Pool are described in Section I of this application. INJECTION WELL CASING INFORMATION 20 AAC 25.402(c)(8) The E-1 00 Well will be converted to injection service for the Midnight Sun Oil Pool Enhanced Recovery Project. The casing program for this well was permitted and completed in accordance with 20 AAC 25.030. Exhibit N-1 details the completion for the E-lOO Well. A cement bond log was recorded and indicates good cement bond across and above the Kuparuk River Formation. Conversion of the E-1 00 Well will be conducted in accordance with 20 AAC 25.412. The actual casing program is included with the "Application to Drill" for each well and is documented with the AOGCC in the completion record. API injection casing specifications are included on each drilling permit application. All injection casing is cemented and tested in accordance with 20 AAC 25.412 for both newly drilled and converted injection wells. All drilling and production operations will follow approved operating practices regarding the Page 24 of 41 Midnight Sun Pool Rules anAa Injection Application e June 20, 2000 presence of HzS in accordance with 20 AAC 25.065. INJECTION FLUIDS 20 AAC 25.402(c)(9) Type of Fluid/Source The Midnight Sun Enhanced Recovery Project will utilize either GC 1 produced water or water produced from the Tertiary Sagavanirktok formation, as shown in Exhibit VI-2, as an initial and primary water source. Composition Tertiary Water - A water sample from the Tertiary water source interval has not been obtained. However, it is anticipated the water will be of similar composition as water produced from the DS 15-6 Well in the Cretaceous interval. The DS 15-6 Well water composition is shown in Exhibits VI-3. GC 1 Produced Water - The composition of produced water from GC 1 is shown in Exhibits VI-4. The composition of Midnight Sun produced water will be a mixture of connate water and source injection water. No oil-water contact has been identified in the Midnight Sun Oil Pool and no significant connate water production has occurred or is anticipated. In order to conduct geochemical modeling, the Midnight Sun Oil Pool connate water composition is assumed to be similar to samples from the offset Pt. McIntyre Oil Pool (refer to Exhibit J-3 in the "Application for Modification to Area Injection Order No.4", dated April 5, 1993). Maximum Injected Rate Maximum water injection requirements at Midnight Sun Oil Pool are estimated at 25,000 BWPD. Compatibility with Formation and Confining Zones Core analyses and geochemical modeling indicate no significant problems with clay swelling or compatibility with in-situ fluids. Analysis of the E-1 0 1 core indicates low clay content (less than 5% by volume), primarily in the form of kaolinite and illite. No fines migration problems are Page 25 of 41 Midnight Sun Pool Rules andea Injection Application e June 20, 2000 anticipated. Geochemical modeling results indicate that a combination of Tertiary water and connate water is likely to form calcium carbonate and barium sulfate scale in the production wells and downstream production equipment. Similar scaling problems are anticipated for GC1 produced water and connate water. Scale precipitation will be controlled using standard oil field scale inhibition methods. INJECTION PRESSURES 20 AAC 25.402(c)(10) The expected average surface water injection pressure for the project is 2250 psig. The estimated maximum surface injection pressure for the Midnight Sun Oil Pool Enhanced Recovery Projects is 2750 psig. The resulting bottom hole pressure will be limited by hydraulic pressure losses in the well tubing, with a maximum expected bottom hole pressure of 6000 psig. FRACTURE INFORMATION 20 AAC 25.402(c)(11) The expected maximum injection pressure for the Midnight Sun Oil Pool Enhanced Recovery Project well(s) will not initiate or propagate fractures through the confining strata, and, therefore, will not allow injection or formation fluid to enter any freshwater strata. There is no evidence of injection out of zone for similar Kuparuk River Formation waterflood operations on the North Slope. Freshwater Strata There are no freshwater strata in the area of issue (see Section N of the Application for Modification to Area Injection Order No.4, dated April 5, 1993). Additionally, calculations of water salinity from open hole resistivity logs acquired in the Prudhoe Bay E-16 indicate a salinity range of 40,000 to 45,000 ppm for Cretaceous and Tertiary sands above the Kuparuk River Page 26 of 41 Midnight Sun Pool Rules anaa Injection Application e June 20, 2000 Formation. Therefore, even if a fracture were propagated through all confining strata, injection or formation fluid would not come in contact with freshwater strata. Enhanced Recovery Water injection operations at the Midnight Sun Oil Pool are expected to be above the Kuparuk River Formation parting pressure to enhance injectivity and improve recovery of oil. Fracture propagation models confirm that injection above the parting pressure will not exceed the integrity of the confining zone. The Kuparuk River Formation at the Midnight Sun Oil Pool is overlain by the Kalubik and HRZ shales, which have a combined thickness of approximately 110 feet. The HRZ is a thick shale sequence which tends to behave ~~"-a pl~ti~-~edium and ~àn be expected to contain significantly higher pressures than sandstones of the Kuparuk River Formation. Mechanical properties determined from log data for the HRZ and Kalubik intervals indicate a fracture gradient from approximately 0.8 to 0.9 psi/ft. No tests have been conducted to determine the formation breakdown pressure at the Midnight Sun Oil Pool; however, data from offset fields suggest that a fracture gradient of between 0.6 and \ 0.7 psi/ft can be expected in the Kuparuk River Formation at initial reservoir conditions. \ The Kuparuk River Formation is underlain by the Miluveach/Kingak shale sequence. A leakoff test in the Kingak shale formation demonstrated leakoff at a gradient of approximately 0.85 psi/ft. In addition, rock mechanics calculations and data from the Prudhoe Bay Oil Pool indicate that sandstone fracture gradients are reduced during waterflooding operations due to reduced in-situ rock stress associated with the injection of water that is colder than the reservoir. A tertiary source water system would have an expected surface water injection temperature is 60 - 80°F, resulting in a fracture gradient reduction of .03 to .05 psi/ft. Produced water from GCl would have limited impact on the fracture gradient because the water temperature would be close to the Page 27 of 41 Midnight Sun Pool Rules an.a Injection Application It June 20, 2000 reservoir temperature. HYDROCARBON RECOVERY 20 AAC 25.402(c)(14) The Midnight Sun Oil Pool is estimated to have an original oil in place of 40 to 60 MMSTB. Reservoir simulation studies indicate incremental recovery from waterflooding to be between 15% to 25% of the original oil in plac~,~~on. Page 28 of 41 Midnight Sun Pool Rules and.a Injection Application e June 20, 2000 VII. Pool Rules Proposed Findings, Conclusions, and Rules PROPOSED FINDINGS PHilLIPS Alaska, Inc., in its capacity as Midnight Sun Operator, respectfully requests that the Commission consider adopting the following findings in establishing an Pool Rules for the Midnight Sun Oil Pool. Geology 1. The Midnight Sun Pool is located north of the Prudhoe bounding fault system and southwest of the Pt. McIntyre Pool. The reservoir interval is the Kuparuk River Formation. 2. The Midnight Sun Pool was discovered in 1997 during the drilling of the Sambuca #1 (E- 100) well. The well encountered 100 feet of gross hydrocarbon column, with 36 feet of gas above the oil column. 3. In the E-100 well, the top of Kuparuk Formation occurs at 7,974 ft. tvdss (11,662 ft. md) and the base occurs at 8,074 ft. tvdss (11,805 ft. md). 4. Well E-101 (Midnight Sun #1) was drilled as a downstructure delineation well in the Midnight Sun Pool. The well encountered 84 feet of gross hydrocarbon column all below the GOC identified in the E-1 00 well. 5. Lithology is dominantly sandstone with lesser amounts of siltstone and sandy mudstone. The Kuparuk Formation can be divided into upper and lower units. In the lower reservoir unit, which is typically about 40 feet thick, the lithology changes abruptly to porous, quartz-rich sandstone. Grain size is typically very fine to fine-grained and is well sorted. The lithology of the upper unit is variable including interbedded sandstone with minor amounts of muddy siltstone. The thickness of this interval is variable and ranges from 0 to 70 feet. This interval contains glauconite and siderite and is more prone to reductions in porosity and permeability due to cementation and compaction. 6. The Midnight Sun Pool is bounded to the west by the Prudhoe Mid-Field fault, to the south by the Prudhoe bounding fault system, to the north by the Sambuca fault, and to the east by the North Prudhoe structural high. 7. The top of the Kuparuk horizon reaches a structural high to the southwest at 7,780 ft. tvdss against the Prudhoe bounding fault. The Kuparuk Formation dips eastward to a zero edge against the North Prudhoe high at approximately 8,100 ft. tvdss. The structural dip is less than 2 degrees. 8. The Midnight Sun accumulation is a combination structural/stratigraphic trap, with isolation assisted by neighboring structural highs that are fault controlled. The controls on Kuparuk Page 29 of 41 Midnight Sun Pool Rules and.a Injection Application e June 20, 2000 Formation thickness are fault movement and erosional truncation. 9. The Midnight Sun Pool gas-oil contact (GOC) is interpreted to be at a depth of 8,010 ft. tvdss, based on Repeat Formation Tester (RFT) data. 10. No oil-water contact (OWC) was identified in either of the Midnight Sun wells. 11. Heavy oil was encountered at 8,107 ft. tvdss in the E-101 well. Conventional core from the E-101 well contained heavy oil in the lower Kuparuk section below 8,107 ft. tvdss. The areal extent of the heavy oil is uncertain. Reservoir Description and Development Planning 1. Mean porosity for the upper Kuparuk Formation is 20.7%, based on E-101 core data. In the lower Kuparuk Formation, excluding the non-reservoir basal interval, the mean porosity is 27.3%. 2. Mean permeability for the upper Kuparuk Formation is 200 md, based on E-1 0 1 core data. In the lower Kuparuk Formation, excluding the non-reservoir basal interval, the mean permeability is 760 md. 3. The net-to-gross ratio for the upper Kuparuk Formation ranges from 0.25 - 0.72. The lower Kuparuk Formation has negligible glauconite and siderite content and exhibits a net-to-gross ratio of approximately 1.0. The non-reservoir basal interval in the lower Kuparuk Formation section is heavily cemented, with a net-to-gross ratio of 0.0. 4. Mean water saturation for the upper Kuparuk Formation is 26.4%, based on E-101 core data. In the lower Kuparuk Formation, excluding the non-reservoir basal interval, the mean water saturation is 12.6%. 5. Based on RFf data, the initial reservoir pressure is estimated at 4058 psia at the reservoir datum of 8050 ft. tvdss. The reservoir temperature is approximately 160 degrees Fahrenheit. 6. Reservoir fluid PVT studies were conducted on a recombined surface sample obtained from the E-101 well. The API gravity of the PVT sample was 25.5 degrees with a solution gas-oil- ratio (GOR) of 717 scf/stb, a formation volume factor of 1.33 RVB/STB, and an oil viscosity of 1.68 centipoise at the bubble point pressure. 7. The Midnight Sun Pool contains an estimated Original Oil In Place (OOIF) of 40 to 60 MMSTB, and total gas in place of 100 to 130 BSCF. The free gas volume associated with the gas cap is 60 to 80 BSCF. 8. Production of the Midnight Sun Pool commenced in October of 1998. Early production from the E-100 Well was restricted to mitigate gas coning, and is currently shut in to limit reservoir voidage. Page 30 of 41 Midnight Sun Pool Rules and.a Injection Application e June 20, 2000 9. Production from well E-I01 demonstrates gas under-running. In January of 1999, the E-101 well was restricted to 5000 BOPD to conserve reservoir energy while completing reservoir surveillance and field development studies. 10. A reservoir model of the Midnight Sun Pool was constructed and history matched to evaluate development options, and reservoir management practices. II. Three development options were evaluated for the Midnight Sun Pool: 1) primary depletion, 2) upstructure gas injection, and 3) waterflood. 12. Model results indicate that primary depletion would achieve an estimated 14% recovery of the OOIP 13. Model results indicate that up structure gas injection would achieve an estimated 20% recovery of the OOIP after 1.0 hydrocarbon pore volume injection (HCPVI) and 27% after 2.0 HCPVI. The vertical sweep efficiency for upstructure gas injection is poor, showing low recovery in the lower Kuparuk unit. 14. Several waterftood development options were studied using the Midnight Sun reservoir model including upstructure, downstructure, and midfield water injection. The midfield configuration showed the best overall waterflood performance with greater ultimate recovery and an earlier production profile associated with improved pressure response relative to the other cases. The midfield configuration involves conversion of the E-100 well to injection service. The midfield water injection case achieved an estimated 39% recovery at 0.7 HCPVI. 15. Based on reservoir model studies, the recommended development plan involves implementation of a midfield waterflood for the Midnight Sun Pool. The planned development well program includes the addition of one up structure horizontal production well to complete a three well development of the Midnight Sun Pool. 16. The development plan results in a nominal spacing of 280 acres for the three well development, however the operator has requested a minimum well spacing of 80 acres. 17. Gas cap expansion will provide initial pressure support prior to waterflood start-up. 18. Water injection is expected to commence in the third quarter of 2000, with design injection rates of 20-25,000 BWPD. A peak production rate of 8-10,000 BOPD is expected prior to waterflood breakthrough. 19. Following waterflood start-up, the VRR target will exceed 1.0 to suppress gas production and restore reservoir pressure. A balanced VRR will be maintained once reservoir pressure is restored to a target range of 3800 - 4000 psi. Page 31 of 41 Midnight Sun Pool Rules and.a Injection Application . June 20, 2000 20. Model results indicate that oil flux into the gas cap will occur as a result of the low structural relief. Reservoir surveillance and voidage management will mitigate oil flux to the west of the up structure horizontal producer. 21. Preliminary analysis indicates there may be potential for enriched gas injection at Midnight Sun; however, no EOR project evaluations have been initiated Facilities 1. Midnight Sun wells will be drilled from the E-Pad drill site and make use of existing IP A infrastructure. 2. Midnight Sun fluids will be commingled with Initial Participating Area (IP A) fluids on the surface at E-Pad and then transported to Gathering Center 1 (GCl) for treatment and shipmentto Pump Station No.1 (PS-1). 3. Water for waterflood operations will be obtained from two source water wells equipped with electrical submersible pumps or via pipeline from GC 1. 4. Future gas lift gas will be obtained from an IP A E-pad well. Gas removed from this well for raw gas lift will be metered prior to the gas being introduced into any Midnight Sun well. This IP A gas will be returned to the IP A. 5. Initially, production will be allocated based upon well tests as previously approved by the Commission. After a new metering skid is installed in the third or fourth quarter 2000, Midnight Sun production will be continuously metered prior to combining with IP A production. 6. The continuous metering skid will consist of a two-phase separator, with liquids measured by a mass meter and gas production measured by conventional orifice plate methods. The Midnight Sun oil gravity will be used to calculate the oil and water volumes based on the liquid mass measurement. After metering, the gas and liquid streams will be re-combined and commingled with IPA fluids at E-Pad for transport to GCl. The data obtained from the metering skid will provide the basis for allocating production between Midnight Sun and the IPA. Well Operations 1. Additional Midnight Sun Pool development wells will use drilling procedures, well design, and casing and cementing programs consistent with those currently used in other North Slope fields. 2. All proposed wells call for completion in a single zone, with a single tubing string and a single packer Page 32 of 41 Midnight Sun Pool Rules anAa Injection Application e June 20, 2000 3. Sub-Surface Safety Valves (SSSV) are not installed in existing Midnight Sun, and are not planned for additional wells, however, nipples are installed to allow flexibility to install wireline retrievable SSSVs. 4. Surface safety valves are included in the wellhead equipment of existing Midnight Sun Pool wells. Testing of SSVs will be in accordance with the standard PBU Operator practices. 5. Stimulation to enhance productivity or injection capability IS not currently planned for Midnight Sun wells. 6. An initial static reservoir pressure will be measured in each new well prior to production. Additionally, a minimum of one pressure survey will be taken annually for the Midnight Sun Pool. A pressure datum elevation of 8,050 ft. tvdss is recommended. Production Allocation 1. Initially, a combination of well tests using the E-Pad facilities and wellhead pressure trends will continue to be used to allocate production. The daily well production is determined by linear interpolation between well test points. 2. A continuous production metering skid will be installed to continuously meter the entire Midnight Sun production stream through a compact two-phase separator before it is commingled with IPA production at E-Pad. 3. Each wellhead will have a continuous two-phase meter to monitor fluid and gas production, with monthly shakeouts to ascertain water cut. An allocation factor of 1.0 would continue to be used with the continuous meter. 4. The Midnight Sun Pool will have a set allocation factor of 1.0, with production allocated back to individual wells using the continuous two-phase metering data to calculate wellhead allocation factors. PROPOSED CONCLUSIONS PHILLIPS Alaska, Inc., in its capacity as Midnight Sun Operator, respectfully requests that the Commission consider adopting the following as its conclusions: 1. Commercially exploitable hydrocarbons are present in the Midnight Sun Pool, contained within Kuparuk River Formation. 2. Pool rules for the development of the Midnight Sun reservoir are appropriate at this time. Page 33 of 41 Midnight Sun Pool Rules and.a Injection Application e June 20, 2000 3. An integration of interests for the area contemplated for development by the operator exists between the working interest owners and royalty owners. 4. The vertical limits of the Midnight Sun reservoir may be defined in the E-lOO well which appears to be a typical and representative well. 5. The low structural relief at the Midnight Sun reservoir limits the effectiveness of gas cap expansion or gas injection as a recovery mechanism. 6. Waterflood operations are planned and appear to achieve the greatest ultimate recovery of oil. 7. Other than establishing setting depths, the operator is not requesting variance from statewide casing and cementing requirements. 8. The E-Pad drill site is an onshore location. 9. Subsurface safety valves are not required by statewide regulations. 10. Surface commingling of Midnight Sun production with IP A and other Prudhoe satellite production will increase ultimate recovery, will not cause waste nor jeopardize correlative rights. 11. The Midnight Sun continuous metering plan is an acceptable method of allocating produced fluids back to the Midnight Sun Pool for revenue and reservoir management purposes. 12. Appropriate reservoir surveillance data will be obtained to complete development and conduct appropriate reservoir management. 13. The operator has demonstrated that primary depletion, supported by gas cap expansion, does not adversely impact ultimate recovery as long as waterflood operations commence before the reservoir pressure drops below 3300 psi at the reservoir datum. 14. Exception to the gas-oil-ratio limit of 20 AAC 25.240(b), is appropriate at this time. PROPOSED RULES PHJLLIPS Alaska, Inc., in its capacity as Midnight Sun Operator, respectfully requests that the Commission consider adopting the following Pool Rules for the Midnight Sun Oil Pool: Subject to the rules below and statewide requirements, production from the Midnight Sun reservoir may occur in a manner that will protect freshwater, prevent waste, protect correlative rights, and provide for the maximum ultimate recovery of oil and gas that is prudent. Page 34 of 41 Midnight Sun Pool Rules and.a Injection Application e June 20, 2000 In addition to statewide requirements, the following pool rules are proposed to govern the proposed development and operation of the Midnight Sun Pool. Rule 1: Field and Pool Name and Classification The field is the Prudhoe Bay Field and the pool is the Midnight Sun Pool. The Midnight Sun Pool is classified as an Oil Pool. Rule 2: Pool Definition TI2N-R13E: Sec 25, S 112; Sec 36, N1I2, SE1/4, El/2 of SW1I4 TI2N-R14E: Sec 29, ALL; Sec 30, S1I2, Sl/2 ofNE1I4, S1I2 of NW1I4; Sec 31, N1I2, SW1/4, N1I2 ofSE1I4; Sec 32, NWl/ 4 T12N-R14E: Sec 28, W1I2, W1I2 ofNE1I4, Wl/2 of SE1I4 The Midnight Sun Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between measured depths 11,662 and 11,805 feet in the E-1 00 well. Rule 3: Spacing Minimum spacing within the pool will be 80 acres. The pool shall not be opened in any well closer than 300 feet to an external boundary where ownership changes. Rule 4: Automatic Shut-In Equipment (a) All wells capable of unassisted flow of hydrocarbons will be equipped with a fail-safe automatic surface safety valve. (b) Injection wells will be equipped with a fail-safe automatic surface safety valve. (c) Surface safety valves will be tested at six-month intervals. Rule 5: Common Production Facilities and Surface Commingling (a) Prior to installation of a continuous metering skid, producing Midnight Sun wells will be tested a minimum of 2 times per month and production will be allocated by interpolating between well test results. (b) After installation of the continuous metering skid, the requirements of 20 AAC 25.230 will be satisfied by measuring production from the Midnight Sun Pool as a whole, and then allocating that production to each well daily. (c) The allocated production for the Midnight Sun Pool will not be adjusted in conjunction with the IP A allocation factors (i.e. the Midnight Sun allocation factor will be 1.0). (d) The operator shall submit monthly reports containing daily production metering and daily well allocations. Page 35 of 41 Midnight Sun Pool Rules and~a Injection Application e June 20, 2000 Rule 6: Reservoir Pressure Monitoring (a) A minimum of one bottom-hole pressure survey will be taken annually for the Midnight Sun Pool. (b) The reservoir pressure datum will be 8,050 feet true vertical depth subsea. (c) Pressure surveys may consist of stabilized static pressure measurements at bottom-hole or may be extrapolated from surface, pressure fall-off, pressure build-up, multi-rate tests, drill stem tests, and open-hole formation tests. (d) Data and results from pressure surveys shall be reported annually. (e) Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (d) of this rule. Rule 7: Gas-Oil Ratio Exemption Wells producing from the Midnight Sun Oil Pool are exempt from the gas-oil ratio limit set forth in 20 AAC 25.240(b). Rule 8: Pressure Maintenance Project Water injection for pressure maintenance will commence before reservoir pressure drops below 3300 psi at the datum or within 2 years of initial production. Rule 9: Reservoir Surveillance Report A surveillance report will be required after one year of regular production and annually thereafter. The report shall include but is not limited to the following: 1. Summary of produced and injected fluids. 2. Summary of reservoir pressure analyses within the pool. 3. Results of any other special monitoring. 4. Future development plan. The report will be submitted to the Commission by the end of first quarter of each year. Rule 10: Administrative Action Upon proper application, the Commission may administratively waive the requirements of any rule stated above or administratively amend the order as long as the change does not promote waste, jeopardize correlative rights, and is based on sound engineering principles. Page 36 of 41 Midnight Sun Pool Rules and.a Injection Application e June 20, 2000 VIII. Area Injection Application Proposed Findings, Conclusions, and Rules PROPOSED FINDINGS PHll.LIPS Alaska, Inc., in its capacity as Midnight Sun Operator, respectfully requests that the Commission consider adopting the following findings in establishing an Area Injection Order for the Midnight Sun Oil Pool. 1. The reservoir interval containing the Midnight Sun Oil Pool is the Kuparuk River Formation. 2. Production from the Midnight Sun Oil Pool commenced in October of 1998. There are currently two wells in the Midnight Sun Oil Pool. The location and mechanical configuration of these wells are identified in the application. There are currently no injection wells in the Midnight Sun Oil Pool. 3. Initial enhanced recovery plans for the Midnight Sun Oil Pool call for conversion of one well, E-lOO, to water injection. Water injection is expected to commence in the third quarter of 2000, with a nominal design injection rate of 20-25,000 BWPD. 4. Operators and Surface Owners within a one-quarter mile radius of the area included in the Midnight Sun Participated Area have been provided a copy of this application for injection. 5. Injection water for the enhanced recovery project will be obtained from either source water wells or will utilize produced water from GC 1. If a source water system is installed, source wells would be drilled and equipped with electrical submersible pumps (ESPs) to deliver water to the project. 6. An initial three well development program is contemplated, with midfield water injection at the E-I00 Well, and the addition of one up structure horizontal producer. Additional injection and production wells may be considered depending on reservoir performance and ongoing technical evaluation. 7. Reservoir simulation studies indicate incremental recovery from waterflooding to be between 15 to 25% of the estimated 40-60 MMSTB original oil in place, relative to primary depletion driven by gas cap expansion. 8. The casing program for the E-lOO Well was permitted and completed in accordance with 20 Page 37 of 41 Midnight Sun Pool Rules and.a Injection Application e June 20, 2000 AAC 25.030. A cement bond log was recorded and indicates good cement bond across and above the Kuparuk River Formation. All injection casing is cemented and tested III accordance with 20 AAC 25.412 for both newly drilled and converted injection wells. 9. Estimated maximum and average injection pressures (psi g) for the Midnight Sun Oil Pool are 2250 psig and 2750 psig, respectively. 10. Following waterflood start-up, the void age replacement by water injection will exceed offtake to suppress gas production and restore reservoir pressure. A balanced voidage replacement will be maintained once reservoir pressure is restored to a target range of 3800 - 4000 psi. 11. Core analyses and geochemical modeling indicate no significant problems with clay swelling or compatibility with in-situ fluids. 12. Water injection operations at the Midnight Sun Oil Pool are expected to be above the Kuparuk River Formation parting pressure to enhance injectivity and improve recovery of oil. 13. The expected maximum injection pressure for the Midnight Sun Oil Pool Enhanced Recovery Project welles) will not initiate or propagate fractures through the confining strata (Kalubik and HRZ shales), and, therefore, will not allow injection or formation fluid to enter any freshwater strata. 14. There are no freshwater strata overlying the proposed area for this enhanced recovery project. PROPOSED CONCLUSIONS PHILLIPS Alaska, Inc., in its capacity as Midnight Sun Operator, respectfully requests that the Commission consider adopting the following as its conclusions: 1. The requirements of 20 AAC 25.402, and 20 AAC 25.460 have been met for the injection of water for the proposed Midnight Sun Oil Pool enhanced recovery operations. 2. Establishment of a new Area Injection Order for the Midnight Sun Oil Pool area will not cause waste nor jeopardize correlative rights, and is based on sound engineering principles. 3. No underground sources of drinking water (USDW) are known to exist in the Western Operating Area of the Prudhoe Bay Unit, including the proposed Midnight Sun Oil Pool. 4. Authorizing injection of water for enhanced recovery operations in Midnight Sun Oil Pool is Page 38 of 41 Midnight Sun Pool Rules and" Injection Application e June 20, 2000 appropriate and in accordance with sound engineering principles. 5. Injection operations in the Western Operating Area of the Prudhoe Bay Unit, and the Midnight Sun Oil Pool will be conducted in penneable strata which can reasonably be expected to accept fluids at pressures less than the fracture pressure of the confining strata. 6. Specific approvals to convert or drill injection wells will be required. PROPOSED RULES PHILLIPS Alaska, Inc., in its capacity as Midnight Sun Operator, respectfully requests that the Commission issue an order authorizing the underground injection of Class II fluids for enhanced oil recovery in the Midnight Sun Pool and consider the following rules to govern such activity: Affected Area: TI2N-R13E: Sec 25, S 1/2; Sec 36, N1/2, SE1/4, E1/2 of SW1/4 TI2N-RI4E: Sec 29, ALL; Sec 30, S1/2, SI/2 ofNE1/4, S1/2 ofNW1/4; Sec 31, Nl/2, SW1/4, N1/2 of SE1/4; Sec 32, NW1/ 4 TI2N-RI4E: Sec 28, W1/2, Wl/2 ofNE1/4, W1/2 of SE1/4 Rule 1: Authorized Injection Strata for Enhanced Recovery Within the affected area, Class II fluids may be injected for purposes of pressure maintenance and enhanced recovery into strata defined as those which correlate with and are common to the fonnation found in the E-l 00 Well between the measured depths of 11,662-11,805 feet. Rule 2: Fluid Injection Wells The injection of fluids must by conducted: 1) through a new well that has been permitted for drilling as a service well for injection in confonnance with 20 AAC 25.005; or 2) through an existing well that has been approved for conversion to a service well for injection in confonnance with 20 AAC 25.280. Rule 3: Monitoring the Tubing-Casing Annulus Pressure Variations The tubing-casing annulus pressure of each injection well must be checked at least weekly to ensure there is no leakage and that it does not exceed a pressure that will subject the casing to a hoop stress greater than 70% of the casing's minimum yield strength. Rule 4: Reporting the Tubing-Casing Annulus Pressure Variations Tubing-casing annulus pressure variations between consecutive observations need not be reported to the Commission. Page 39 of 41 Midnight Sun Pool Rules and la Injection Application e June 20, 2000 Rule 5: Demonstration of Tubing/Casing Annulus Mechanical Integrity A schedule must be developed and coordinated with the Commission that ensures that the tubing-casing annulus for each injection well is pressure tested prior to initiating injection, following well workovers affecting mechanical integrity, and at least once every four years thereafter. A test surface pressure of 1500 psi or 0.25 psi/ft. multiplied by the vertical depth of the packer, whichever is greater, but not to exceed a hoop stress greater than 70% of the casing's minimum yield strength must be held for at least a 30 minute period with decline no more than or equal to 10% of test pressure. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Rule 6: Well Integrity Failure Whenever disposal rates and/or operating pressure observations or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, the operator must notify the Commission on the first working day following the observation, obtain Commission approval to continue injection and submit a plan of corrective action on Fonn 10-403 for Commission approval. Rule 7: Plugging and Abandonment of Injection Wells An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission in accordance with 20 AAC 25.105. Rule 8: Administrative Action Upon proper application, the Commission may administratively waive the requirements of any rule stated above or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering principles, and will not result an increased risk of fluid movement into an USDW. Page 40 of 41 Midnight Sun Pool Rules and.a Injection Application . June 20, 2000 IX. Exhibits Exhibit 1-1 Location Map of Midnight Sun Pool Exhibit 1-2 Midnight Sun Participating Area Exhibit 1-3 Type Log (E-100) - Kuparuk Interval Exhibit 1-4 Top Kuparuk Structure Map for Midnight Sun Pool Exhibit 1-5 Kuparuk Isochore Map for Midnight Sun Pool Exhibit 1-6 East-west well structural cross-section along axis of Midnight Sun Pool Exhibit 1-7 North-south well structural cross-section across Midnight Sun Pool Exhibit 1-8 Net sandstone map for Midnight Sun Pool Exhibit 1-9 Gross hydrocarbon distribution map for Midnight Sun Pool Exhibit 11-1 Fluid Property Summary for the Midnight Sun Pool Exhibit II -2 Pressure- V olume- Temperature (PVT) Properties as a Function of Pressure Exhibit 11-3 Reservoir Model Layering and Average Physical Properties Exhibit 11-4 Comparison of Model Predictions and Field Performance Exhibit 11-5 Production and Recovery Profiles for Primary Depletion Exhibit 11-6 Production and Recovery Profiles for Upstructure Gas Injection Exhibit 11-7 Production and Recovery Profiles for Waterflood Exhibit 111-1 Facility Location Map Exhibit 111-2 Drill Site Schematic Exhibit 111-3 Source Water Injection System Exhibit IV -1 E-loo Wellbore Schematic Exhibit VI-l Affidavit of Notification Exhibit VI-2 Shallow Section Type Log E-16 - Source Water Intervals Exhibit VI-3 DS 15-6 Produced Water Sample Analysis Exhibit VI-4 GC #1 Produced Water Sample Analysis Page 41 of 41 . . Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Midnight Sun Pool, Prudhoe Bay Field - Pool Rules and Area Injection Order PHILLIPS Alaska, Inc. by letter dated May 3, 2000, has petitioned the Alaska Oil and Gas Conservation Commission under 20 AAC 25.520 and 20 AAC 25.460 to hold a public hearing to present testimony to establish pool rules and an area injection order for the Midnight Sun Pool, Prudhoe Bay Field, on the North Slope of Alaska. A hearing will be held at the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501, at 9:00 AM on June 13, 2000, in conformance with 20 AAC 25.540. All interested persons and parties are invited to present testimony. If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing, please contact Diana Fleck at 793-1221 before June 6,2000. Ca~({h,~ ~ Camillé Oechsli Taylor Commissioner Published May 10, 2000 ADN A002014036 e . PHilLIPS Alaska, Inc. A Subsidiary of PHilLIPS PETROLEUM COMPANY P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 May 3, 2000 Robert N. Christenson, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99502-3192 Re: Request for Hearing: Midnight Sun Oil Pool, Pool Rules and Area Injection Application Dear Mr. Christenson: PHILLIPS Alaska, Inc. ("PHILLIPS"), in its capacity as Midnight Sun Operator for itself and on behalf of Exxon Mobil Corporation ("Exxon Mobil") and BP Exploration (Alaska), Inc. ("BPX"), requests that the Commission schedule a public hearing to consider the Midnight Sun application for pool rules and area injection order. We request that you schedule the hearing for a day that is convenient for the Commission in June. Enclosed is the complete application. Please contact E. W. Reinbold (263-4465) if you have any questions or require additional information. Sincerely, --=~...--- ~J1, G:v""-O !~. J. W. Groth cc: D. W. Bose (PHILLIPS) M. P. Evans (ExxonMobil) J. Hurliman (BPX) , n , 2· 000 ..~ () l1... . f~ja$ka & e ~ I I I I I I I I I I I I I I I I I I Midnight Sun Oil Pool Pool Rules And Area Injection Application May 3,2000 ,··('f"".\\'ED REJb';{' .. , ., 0 4 2.00() " . ,', f' !"'\m:"~ìon ·V' 'fl. "'a" C"n~ liJ)\' ,¡,;W Alas'Ka Oil \:I. \:j ~ . " ':' AnCl'¡oí~{e I I I I I I I I I I I I I I I I I I I e . Midnight Sun Pool Rules and Area Injection Application May 3, 2000 Table of Contents I. Geology p. 1 II. Reservoir Description and Development Planning 5 III. Facilities 15 IV. Well Operations 18 V. Production Allocation 22 VI. Area Injection Operations 23 VII. Pool Rules- Proposed Findings, Conclusions, and Rules 29 VIII. Area Injection Application - Proposed Findings, Conclusions, and Rules 37 IX. Exhibits 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and A.n;ectiOn Application -- May 3, 2000 I. Geology Introduction The Midnight Sun Pool is located on Alaska's North Slope, as illustrated in Exhibit 1-1. The Midnight Sun Pool was discovered in 1997 during the drilling of the Sambuca #1 (E-lOO) well. The Midnight Sun Pool is located north of the Prudhoe bounding fault system and southwest of the Pt. McIntyre Pool. The reservoir interval is the Kuparuk River Formation. The E-l00 well is the first well to encounter the Kuparuk River Formation in this area. The Fawn Lake #1, Abel State #1, North Prudhoe Bay State #1 and #2, North Prudhoe #3, Term Well A wells, and wells drilled from nearby pads in the Prudhoe Bay Field did not encounter the Kuparuk River Formation. Exhibit 1-2 shows the location of the Midnight Sun Participating Area (MSPA). Development drilling will utilize the existing gravel E-pad, from which the E-lOO discovery well was drilled. One delineation well, the Midnight Sun #1 (E-lOl), was drilled from E-pad in October 1998 to confirm the extent of the Midnight Sun discovery. Stratigraphy The Midnight Sun Pool is composed of the Kuparuk River Formation, also informally referred to as the "Kuparuk Formation". This formation was deposited during the lower Cretaceous geologic time period, between 153 and 115 million years before present. Exhibit 1-3 shows a portion of the open hole electric logs from the E-l00 well. This "type log" illustrates the stratigraphic definition of the Midnight Sun Pool. The log is scaled in true vertical depth subsea (tvdss) and also has a measured depth (md) track. In the E-l00 well, the top of Kuparuk Formation occurs at 7,974 ft. tvdss (11,662 ft. md) and the base occurs at 8,074 ft. tvdss (11,805 ft. md). This is also the productive interval of the Midnight Sun Pool. The Kuparuk Formation base is defined by its contact with the Jurassic-age Kingak Formation as Page 1 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and A. Injection Application e May 3, 2000 seen with a change in lithology and conventional electric log character. The Kingak Formation is a shale with low resistivity (1 to 3 ohm-meters). The Kuparuk Formation is composed of medium- to fine-grained quartz-rich to glauconitic sandstone with higher resistivity (3-50 ohm- meters). The Kuparuk Formation top is defined by its contact with the lower Cretaceous-age High Radioactive Zone (HRZ) Formation as seen by a change in lithology and conventional electric log character. The HRZ is a black, organic-rich shale recognized by the gamma ray log, typically greater than 150 gamma API units. The Kuparuk Formation in the Midnight Sun Pool is stratigraphically complex, characterized by rapid change in thickness, sedimentary facies and local diagenetic cementation. Lithology is dominantly sandstone with lesser amounts of siltstone and sandy mudstone. As shown on the type log in Exhibit 1-3, the Kuparuk Formation can be divided into upper and lower units. The basal portion of the lower unit in E-101 is a non-productive, tight, glauconitic sandstone with minor amounts of shale rip-up clasts. This unit was not encountered in E-lOO and is assumed to be restricted to the area near E-lOl. Moving up in the lower reservoir unit, which is typically about 40 feet thick, the lithology changes abruptly to porous, quartz-rich sandstone. Grain size is typically very fme to fine-grained and is well sorted. The lithology of the upper unit is variable including interbedded sandstone with minor amounts of muddy siltstone. The thickness of this interval is variable and ranges from 0 to 70 feet. This interval contains glauconite and siderite and is more prone to reductions in porosity and permeability due to cementation and compaction. The sands in the upper unit are poorly to well- sorted. Intergranular siderite cement is common in the upper unit and plays an important role in determining reservoir quality. Cementation is especially abundant in the lower portion of the upper unit where it degrades reservoir quality. The upper and lower units have distinctly different thickness trends. The lower unit maintains a nearly uniform thickness throughout the Midnight Sun area, suggesting that its deposition predates significant fault movement. In contrast, the thickness and lithology of the upper unit are variable and have been influenced by syn-depositional faulting. Page 2 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and" Injection Application e May 3, 2000 Structure Exhibit 1-4 is a structure map on the top of the Kuparuk Formation with a contour interval of 20 feet. Top Kuparuk structure in the Midnight Sun area is characterized by a bowl-shaped depression gently dipping to the northeast. The Midnight Sun depression is bounded to the west by the Prudhoe Mid-Field fault, to the south by the Prudhoe bounding fault system, to the north by the Sambuca fault, and to the east by the North Prudhoe structural high. The top of the Kuparuk horizon reaches a structural high to the southwest at 7,780 ft. tvdss against the Prudhoe bounding fault. The Kuparuk Formation dips eastward to a zero edge against the North Prudhoe high at approximately 8,100 ft. tvdss. The structural highs surrounding the Midnight Sun accumulation are devoid of Kuparuk Formation rock. Along the axis of the depression, the structural dip is less than 2 degrees, down to the northeast. Exhibit 1-5 is an isochore map of the Kuparuk Formation with a contour interval of 10 feet. The Midnight Sun accumulation is a combination structura1/stratigraphic trap, with isolation assisted by neighboring structural highs that are fault controlled. The controls on Kuparuk Formation thickness are fault movement and erosional truncation. Kuparuk Formation deposition occurred in marine shoreface and deltaic depositional environments. Exhibit 1-6 is a structural cross-section along the axis of the Midnight Sun structural depression (see Exhibit 1-1 for location). This cross-section illustrates the western and eastern limits of the Midnight Sun Pool. The western limit of the pool is fault-controlled by the Prudhoe Mid-Field fault and the eastern boundary is a stratigraphic truncation of the Kuparuk Formation onto the North Prudhoe structural high. Exhibit 1-7 is a north-south structural cross-section through the Midnight Sun Pool (see Exhibit 1-1 for location). This exhibit illustrates the fault-bounded isolation of the Kuparuk Formation on the north by the Sambuca fault and on the south by the Prudhoe bounding fault system. Fluid Contacts The Midnight Sun Pool gas-oil contact (GOC) is interpreted to be at a depth of 8,010 ft. tvdss, Page 3 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and AI Injection Application e May 3, 2000 based on Repeat Formation Tester (RFT) data. No oil-water contact (OWC) was identified in either of the Midnight Sun wells. Based on core water saturation data and Mercury Injection Capillary Pressure data, the reservoir is interpreted to be significantly above the effective owe. ' Heavy oil was encountered at 8,107 ft. tvdss in the E-101 well. A heavy oil sample, measuring 10 degrees API gravity, was recovered by the RFT at 8,107 ft. tvdss. Conventional core from the E- 101 well contained heavy oil in the lower Kuparuk section below 8,107 ft. tvdss. The areal extent of the heavy oil is uncertain. Pool Limits The trap for oil and gas in the Midnight Sun Pool is created by a combination of structural and stratigraphic features. To the south, west, and north, the pool limit is defined by the juxtaposition of the reservoir against the impermeable Kingak. shale across the Prudhoe bounding fault system, Prudhoe Mid-Field fault, and Sambuca fault, respectively. Stratigraphic truncation of the Kuparuk Formation forms the trapping mechanism to the east. The boundaries of the Midnight Sun P A encompass the proposed boundaries of the Midnight Sun Pool. Exhibit 1-8 is a net sandstone map of the Midnight Sun Pool with a contour interval of 2- feet. Exhibit 1-9 is a gross hydrocarbon distribution map of the Midnight Sun Pool. Page 4 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and. Injection Application e May 3, 2000 II. Reservoir Description and Development Planning ROCK AND FLUID PROPERTIES The reservoir description for the Midnight Sun Pool is based on core data from the E-101 well and log data from the E-l00 (Sambuca #1) and E-lOl (Midnight Sun #1) wells. Well E-101 was cored through the entire Kuparuk section with water based mud and low invasion coring techniques. The core data were used to calibrate the petrophysical log model, which was used to construct the Midnight Sun geologic model. Porosity and Permeability Core porosity and permeability measurements were conducted at overburden pressure and permeability was corrected for gas slippage (Klinkenberg correction). Mean porosity for the upper Kuparuk Formation is 20.7%, based on E-lOl core data. In the lower Kuparuk Formation, excluding the non-reservoir basal interval, the mean porosity is 27.3%. Mean permeability for the upper Kuparuk Formation is 200 md, based on E-I0l core data. In the lower Kuparuk Formation, excluding the non-reservoir basal interval, the mean permeability is 760 md. The ratio of vertical to horizontal permeability ranges from 0.2 to 1.0 in the upper Kuparuk Formation and from 0.6 to 1.0 in the lower Kuparuk Formation. Net Pay Net pay was determined based on visual inspection of the E-I01 core in conjunction with review of thin section and routine core analysis data. The Kuparuk Formation in the Midnight Sun Pool has very low clay content, generally less than 2% by volume, and no defined shale sections. In the upper Kuparuk Formation, reservoir volume is reduced by the presence of discontinuous, nodular and banded siderite and glauconite. These mineral inclusions were identified visually, and the net- to-gross-ratio was determined based on the ratio of reservoir quality sand to gross rock area exposed on the slabbed core. The net-to-gross ratio for the upper Kuparuk Formation ranges from 0.25 - 0.72. The lower Kuparuk Formation has negligible glauconite and siderite content and exhibits a net-to-gross ratio of approximately 1.0. The non-reservoir basal interval in the Page 5 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and Al:njectiOn Application e May 3, 2000 lower Kuparuk. Formation section is heavily cemented, with a net-to-gross ratio of 0.0. Water Saturation Water saturation data were measured throughout the Kuparuk Formation interval in the E-101 low invasion core. A chemical tracer confirmed that the core experienced minimal invasion. Water saturation data were corrected for mud filtrate invasion based on the tracer results. Water saturation measurements from the core were then used to calibrate the petrophysical log model. Mean water saturation for the upper Kuparuk Formation is 26.4%, based on E-101 core data. In the lower Kuparuk Formation, excluding the non-reservoir basal interval, the mean water saturation is 12.6%. Water saturation data derived from the core and log data were used to develop Leverett J- functions, which were subsequently translated to drainage capillary pressure curves for the upper and lower Kuparuk Formation intervals. The capillary pressure data were then used to initialize water saturation in the reservoir model based on capillary pressure equilibrium. Relative Permeability A steady state water-oil relative permeability experiment was conducted on a composite core from the upper Kuparuk Formation interval. The residual oil saturation from this displacement experiment was 22.7%. Centrifuge water-oil and gas-oil experiments were also conducted. Results from these experiments indicate that water-oil relative permeability measurements for the Midnight Sun Pool are similar to those measured for other North Slope fields exhibiting favorable waterflood performance. In the absence of having an extensive data set for all relative permeability functions, analog data sets were used for performance predictions. Initial Pressure & Temperature Based on RFf data, the initial reservoir pressure is estimated at 4058 psia at the reservoir datum of 8050 ft. tvdss. The reservoir temperature is approximately 160 degrees Fahrenheit at the datum. Page 6 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules anMa Injection Application . May 3, 2000 Fluid PVT Data Reservoir fluid PVT studies were conducted on a recombined surface sample obtained from the E-101 well. The sample was recombined to the bubble point pressure of 4045 psia, corresponding to the pressure at the GOC at initial conditions. The API gravity of the PVT sample was 25.5 degrees with a solution gas-oil-ratio (GOR) of 717 scf/stb, a formation volume factor of 1.33 RVB/STB, and an oil viscosity of 1.68 centipoise at the bubble point pressure. Exhibit II-I shows a summary of the fluid property information for the Midnight Sun Pool. Exhibit 11-2 contains a listing of the various pressure-volume-temperature (PVT) properties as a function of pressure. Hydrocarbons in Place Estimates of hydrocarbons in place for the Midnight Sun Pool reflect current well control, stratigraphic and structural interpretation, and rock and fluid properties. These data were integrated in the construction of a fine scale geologic model, which provides the basis for estimation of original fluids in place. The results indicate an Original Oil In Place (OOIP) range of 40 to 60 MMSTB, and total gas in place of 100 to 130 BSCF. The free gas volume associated with the gas cap is 60 to 80 BSCF. RESERVOIR PERFORMANCE Well Perlormance Two wells (E-lOO, and E-lOl) have been drilled and completed in the Kuparuk formation. Both wells are tied into the Prudhoe Bay E-Pad facilities. Production commenced in October of 1998. ,V ell E-l00 (Sambuca #1), the discovery well, encountered 100 feet of gross hydrocarbon column, with 36 feet of gas above the oil column. The well was perforated over a 20 feet interval at the base of the reservoir. The initial production rate was 2,000 to 3,000 BOPD with a GOR of approximately 950 scf/stb. The rate was restricted to mitigate coning, although the GOR increased steadily to 6000 scf/stb during the first three months of production. The well is currently shut in to limit reservoir voidage. Page 7 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and. Injection Application e May 3, 2000 Well E-lOl (Midnight Sun #1) was drilled as a downstructure delineation well in the Midnight Sun Pool. The well encountered 84 feet of gross hydrocarbon column all below the GOC identified in the E-loo well. No oil-water contact was identified by open-hole logs. The initial production rate in November of 1998 was 7000 to 8000 BOPD with a GOR of approximately 800 scf/stb. In January of 1999, the well was restricted to 5000 BOPD to conserve reservoir energy while completing reservoir surveillance and field development studies. Gas Coning Production from the E-IOO well is affected by gas coning. E-loo is a deviated well with an inclination of 46 degrees across the Kuparuk.. The well is completed with a standoff of 42 feet tvd from the GOC. During the first 10 days of production, the GOR in the E-loo well increased to 2000 scf/stb. The production rate was restricted to mitigate coning. The cement bond log in this well is interpreted to show good cement quality; and the coning interpretation was confirmed by production logging. Subsequent inspection of the E-lOl core confirmed that intra-formation cementation in the upper Kuparuk would act as a baffle but not a barrier to vertical flow. With slightly more than 50% of the oil column overlain by the gas cap, coning can be a reservoir mechanism in the Midnight Sun Pool. Gas Under-Running The Midnight Sun reservoir is a thin reservoir with a structural dip of less than 2 degrees. The low structural relief results in a gas cap that overlays more than 50% of the areal extent of the oil column. Reservoir model results, calibrated to field performance, suggest that gas under-running, which is movement of gas below a barrier, will impact early field performance and is a mechanism to address in depletion planning. The GOR at well E-1O 1 is currently 5000 sef/stb and increasing consistent with predictions. The low structural relief at the Midnight Sun reservoir limits the effectiveness of gas cap expansion or gas injection as a recovery mechanism. Page 8 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and" Injection Application e May 3, 2000 DEVELOPMENT PLANS A reservoir model of the Midnight Sun Pool was constructed to evaluate development options, investigate reservoir management practices, and generate rate profiles for facility design. This section of the application describes the reservoir model, modeling results and the development plans. Reservoir Model Construction A fine scale three-dimensional geologic model of the Midnight Sun Pool was constructed based on detailed stratigraphic and structural interpretation. This model provided the bulk reservoir volume and distribution of porosity and permeability used in the construction of the Midnight Sun reservoir model. The reservoir model is a three-dimensional, three-phase, black oil finite difference flow simulation model. The model area encompasses the graben fault block defining the Midnight Sun Pool. Areal gridding is 250 feet by 250 feet (1.43 acre cells). The vertical gridding is defined by 15 model layers with nominal thicknesses of 4 to 8 feet. Exhibit 11-3 shows average physical properties for each model layer. Faults and juxtaposition are honored through corner point geometry and non-local grid connections. Water saturation in the reservoir model was established by capillary pressure equilibrium. There is no aquifer in the reservoir model. Capillary pressure measurements suggest that the effective OWC is below the structural limit of the reservoir. The reservoir pressure was set to 4045 psia at the GOC of 8010 ft. tvdss, based on the RFT data. Exhibit II -4 shows the comparison of model predictions and field performance. For the history match, oil rate is specified and reservoir pressure and well GOR are predicted. A history match of reservoir pressure was achieved with no modification to the gas cap volume in the reservoir model. The GOR history match reflects accurate modeling of both the coning (E-lOO) and under- running (E-lOl) reservoir mechanisms. The downstructure pore volume was increased to reflect under-run timing at well E-lO 1. Page 9 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and" Injection Application e May 3, 2000 Model Results Three development options were evaluated for the Midnight Sun Pool: 1) primary depletion, 2) up structure gas injection, and 3) waterflood. Primary Recoverv Primary recovery was evaluated with E-I01 well as the single downstructure producer. The primary recovery mechanism was a combination of gas cap expansion and solution gas drive. The gas cap at Midnight Sun contains approximately 40 percent of the total reservoir hydrocarbon pore volume. Model results indicate that primary depletion would achieve an estimated 14% recovery of the OOIP. Exhibit 11-5 shows production and recovery profiles for primary depletion. The performance is attributed to depletion of the gas cap and associated reduction in reservoir energy. The model shows gas under-running and high GOR production at Well E-I01. The reservoir pressure was depleted at the end of the model run and the majority of the original gas cap volume had been produced. Upstructure Gas In.iection Up structure gas injection was evaluated with a horizontal injection well installed in the Midnight Sun gas cap. Reservoir management for this case assumed that injection would be sufficient to increase reservoir pressure back to the original condition and then maintain a voidage replacement ratio (VRR) of 1.0. The peak injection requirement for this case was 40 MMscfd. Model results indicate that up structure gas injection would achieve an estimated 20% recovery of the OOIP after 1.0 hydrocarbon pore volume injection (HCPVI). Recovery of 27% was observed with 2.0 HCPVI. Exhibit 11-6 shows production and recovery profiles for up structure gas injection. Up structure gas injection results in gas under-running the top Kuparuk Formation and then coning into the perforations at the downstructure producer. As a result of these mechanisms, the vertical sweep efficiency for up structure gas injection is poor with correspondingly low recovery in the lower Kuparuk Formation. Waterflood Several waterflood development options were studied using the Midnight Sun reservoir model including up structure, downstructure, and midfield water injection. Both the Page 10 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and" Injection Application e May 3, 2000 up structure and midfield options involve water injection at or near the original gas cap. All watertlood options result in some degree of resaturation of the gas cap by oil in the midfield area. Case studies of successful application of this type of watertlood process are documented in the literature. The midfield configuration showed the best overall watertlood performance with greater ultimate recovery and an earlier production profile associated with improved pressure response relative to the other cases. The midfield configuration involves conversion of the E-I00 well to injection service. Initial production was from the E-I0l well. An up structure horizontal production well is completed 2,000 to 4,000 feet east of the western limit of the light oil column. This well was managed in the reservoir model to limit gas coning. The midfield watertlood shows improved watertlood response over the up structure and downstructure injection options, as evidenced by lower peak GOR and faster pressure response. Watertlood fill-up is achieved within two years of watertlood start-up. The improved response is attributed to closer injector / producer spacing and greater distance of the key production well from the gas cap. The midfield water injection case achieved an estimated 39% recovery at 0.7 HCPVI. Cumulative gas production is lower relative to the up structure injection case. Exhibit 11- 8 shows production and recovery profiles for midfield water injection. The up structure configuration included a new horizontal injection well towards the western limit of the light oil column. The configuration was envisioned as a means of isolating the gas cap while watertlooding the midfield and downstructure areas. The primary downstructure producer would be well E-lOl, although the E-100 well was also produced for a limited time. Model results for up structure water injection indicate that the western limit of the gas cap can be isolated, and classic watertlood fill-up and response are achieved within three years of watertlood start-up. The up structure water injection case achieves an estimated 39% recovery at 0.7 HCPVI, although production response to watertlood is slower and gas production is greater relative to the midfield case. The downstructure configuration involves conversion of Well E-lO 1 to injection service. Production from Well E-lOO would be resumed and rate would initially be restricted to mitigate Page 11 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and A.InjectiOn Application e May 3, 2000 coning. In the downstructure watertlood configuration, an up structure horizontal production well is drilled to recover up structure reserves. Watertlood performance for downstructure injection is less attractive than the other watertlood configurations. In this configuration, gas coning and under-running at Well E-100 require restricted field rate and continue to be a production issue for both production wells. The downstructure water injection case achieves an estimated 31 % recovery at 0.56 HCPVI with a delayed production profile relative to the up structure and midfield alternatives. Enhanced Oil Recoverv (EOR) Preliminary analysis indicates there may be potential for enriched gas injection at Midnight Sun; however, no EOR project evaluations have been initiated. Due to the technical complexities, reservoir uncertainty, and costs involved, improved reservoir description and additional field performance data are necessary before these options may be fully evaluated. Development Plans Based on reservoir model studies, the recommended development plan is implementation of a midfield watertlood for the Midnight Sun Pool. This plan provides the most favorable production profile, while minimizing cumulative gas production and maximizing ultimate recovery. Water injection is expected to commence in the third quarter of 2000, with design injection rates of 20- 25,000 BWPD. A peak production rate of 8-10,000 BOPD is expected prior to watertlood breakthrough. Waterftood Sensitivity Studies Reservoir model sensitivity studies were conducted in support of development planning. Model runs were conducted to optimize well placement and completion design. Sensitivities to key model assumptions, including relative permeability, vertical permeability, and oil viscosity were evaluated. None of these assumptions were found to significantly alter development plans. Other sensitivity studies included the effect of continued production prior to watertlood startup. Earlier watertlood startup mitigates reservoir pressure decline and reduces peak GOR response prior to watertlood fill-up. However, no recovery impact was identified with a waterflood start- up during third quarter 2000, assuming continued production of 5,000 BOPD until start up. In Page 12 of 41 I I I I I I I I I I I I ,I I I I I I I Midnight Sun Pool Rules and. Injection Application e May 3, 2000 the reservoir model, reservoir pressure declined to 3300 psi, and GOR peaked at 8000 SCF/STB. Well Spacing The planned development well program includes the addition of one up structure horizontal production well to complete a three well development of the Midnight Sun Pool. The development will form an irregular pattern due to the constraints of development within a small fault block. This well spacing is nominally 280 acres. Closer well spacing does not appear to be justified due to the thin oil column; however, infill drilling and/or peripheral drilling along the eastern margin of the field will be evaluated as field development continues. To allow for flexibility to respond to these conditions, a minimum well spacing of 80 acres is requested. RESERVOIR MANAGEMENT STRATEGY Gas cap expansion will provide initial pressure support prior to watertlood start-up. Following watertlood start-up, the VRR target will exceed 1.0 to suppress gas production and restore reservoir pressure. A balanced VRR will be maintained once reservoir pressure is restored to a target range of 3800 - 4000 psi. In the planned watertlood configuration, oil flux into the gas cap is anticipated in the midfield area due to low structural relief. Reservoir surveillance and voidage management, however, should minimize oil flux to the west of the up structure horizontal producer. The objective of the Midnight Sun reservoir management strategy is to manage reservoir development and depletion to achieve the maximum ultimate recovery consistent with good oil field engineering practices. To accomplish this objective, reservoir management is approached as a dynamic process. The initial strategy is derived from model studies and limited historical performance. New well results and additional reservoir performance data will increase knowledge and improve predictive capabilities resulting in adjustments to the initial strategy. The reservoir management strategy for the Midnight Sun Pool will continue to be evaluated throughout field life. Page 13 of 41 I I I I I Î I I I I I I I I I I I' I I Midnight Sun Pool Rules and" Injection Application e May 3, 2000 Reservoir Perlormance Conclusions Reservoir model results support implementation of a waterflood in the Midnight Sun Pool. An initial three well development program is contemplated, with midfield water injection at Well E- 100, and the addition of one up structure horizontal producer. Water injection is expected to commence in the third quarter of 2000, with design injection rates of 20-25,000 BWPD. Following initiation of waterflood, a peak production rate of 8-10,000 BOPD is expected. We request that the Operator be allowed to determine the field off-take rate based upon sound reservoir management practices. Page 14 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and AajectiOn Application e May 3, 2000 III. Facilities GENERAL OVERVIEW Midnight Sun wells will be drilled from the E-Pad drill site. Surface facilities include existing IPA drill sites, pipelines and processing facilities to produce Midnight Sun Reservoir fluids. Midnight Sun fluids will be commingled with Initial Participating Area (IP A) fluids on the surface at E- Pad and then transported to Gathering Center 1 (GCl) for treatment and shipment to Pump Station No. 1 (PS-l). Midnight Sun will make use of existing IPA infrastructure. This minimizes environmental impacts and reduces costs to help maximize recovery. Use of the GCl production facility includes separating and processing equipment, inlet manifold and related piping, flare system, and on-site water disposal. IP A field facilities that will be used include 24" low-pressure common line from E-pad to GCl, 16" and 6" high-pressure common lines from E-pad to GCl, oil sales line from GC1 to PS-l and the power distribution and generation facilities. Exhibit III -1 is an area map showing locations of the facilities that will be used for Midnight Sun development. Drill Sites, Pads, and Roads Use of the E- Pad drill site for the Midnight Sun wells has been selected to (1) eliminate new gravel placement, (2) minimize well stepout to within currently available drilling technology while reaching the extent of the reservoir, and (3) maximize the use of existing facilities. Wells will be drilled between existing IP A wells, eliminating the need to expand the E- Pad. A schematic of the drill site layout is shown in Exhibit 111-2. No new pipelines will be required for development of the Midnight Sun reservoir. Midnight Sun production will be routed to GCl via existing E-Pad high pressure and low-pressure commonlines. No new roads or roadwork will be required. Page 15 of 41 I I I il I I I I I I I I I I I I I I I Midnight Sun Pool Rules and A.Injection Application e May 3, 2000 Drill Site Facilities and Operations Two existing E-Pad production manifold slots and well lines will be used for the Midnight Sun wells. Water for watertlood operations will be obtained from source water wells equipped with electrical submersible pumps (ESPs) to deliver water to the injection well at a rate of 10,000 bpd from each source water well at minimum pressure of 2100 psig. The source water injection system is illustrated in Exhibit III - 3. Future gas lift gas will be obtained from an IP A E-pad well. Gas removed from this well for raw gas lift will be metered prior to the gas being introduced into any Midnight Sun well. This IP A gas will be returned to the IP A. Power for new Midnight Sun drill site equipment will be provided by installing a new 15 kv power line from GCl to the Midnight Sun facilities at E-Pad. All well control at the drill sites will be performed manually by a drill site operator with the exception of the well safety shut in systems (which are automatic) and the drill site emergency shutdown system (which can be triggered manually or automatically). Initially, production will be allocated based upon well tests as previously approved by the Commission. After a new metering skid is installed in the third or fourth quarter 2000, Midnight Sun production will be continuously metered prior to combining with IP A production. The skid will consist of a two-phase separator, with liquids measured by a mass meter and gas production measured by conventional orifice plate methods. The Midnight Sun oil gravity will be used to calculate the oil and water volumes based on the liquid mass measurement. After metering, the gas and liquid streams will be re-combined and commingled with IPA fluids at E-Pad for transport to Gel. The data obtained from the metering skid will provide the basis for allocating production between Midnight Sun and the IPA. Production allocation is addressed in Section V. Data gathering at the drill site will be both a manual and automatic function. The data gathering system (SCADA) will be expanded to accommodate the Midnight Sun wells and drill site equipment. The SCADA will continuously monitor the flowing status, pressures, and temperature of the producing wells at the drill sites. These data will be under the drill site operator's supervision through his monitoring station. Midnight Sun production metering will continuously Page 16 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and. Injection Application e May 3, 2000 monitor the pressures, temperatures, and flow of the liquid and gas streams. The rate of production from each well will be regulated by manually adjusted chokes. The flow from the wells would be routed to the production metering skid and then to GC 1 for processing. Production Center No modifications to the GCl production center will be required to process the Midnight Sun production. GCl was built to process a nominal oil rate of 400 MBOPD, gas rate of 320 MMSCFPD (modifications have increased this to 2,600 MMSCFPD) and a produced water rate of 40 MBWPD (modifications have increased this to 85 MBWPD). Production, including that from the Midnight Sun Reservoir, is not expected to exceed existing GCl capacity. RECEIVED , 04 2000 Alaska Oil 8: Gas Cons. Commission Anchorage Page 17 of 41 I I I I I I I I I I· I I, I I I I I I I Midnight Sun Pool Rules and A.njeCtion Application e May 3, 2000 IV. Well Operations DRILLING AND WELL DESIGN Two wells have been drilled in the Midnight Sun Pool, E-loo and E-lOl. E-101 is currently producing with plans to convert E-I00 to an injector. Exhibit IV -1 shows the schematic of the E- 100 well. The Midnight Sun depletion plan calls for drilling three additional wells: two shallow source water wells and one horizontal up structure producer, each drilled from E-Pad. Midnight Sun wells would be directionally drilled from E- Pad utilizing drilling procedures, well designs, and casing and cementing programs similar to those currently used in other North Slope fields. A 20- inch conductor casing will be set 80 feet below pad level and cemented to surface. Consideration will be given to driving or jetting the 20- inch conductor as an alternative setting method. A diverter system meeting Commission requirements will be installed on the conductor. Surface hole would be drilled no deeper than 5,000 ft. tvdss. This setting depth provides sufficient kick tolerance to drill the wells safely and allows the angle-build portions of high departure wells to be cased. No hydrocarbons have been encountered to this depth in previous Midnight Sun wells. Cementing and casing requirements similar to other North Slope fields will be adopted for Midnight Sun. The casing head and a 5,000-psi blowout-preventer stack will be installed onto the surface casing and tested consistent with Commission requirements. Production hole will be drilled below surface casing to the Kuparuk Formation, allowing sufficient rathole to facilitate logging. Production casing will be set and cemented. Intermediate casings and production liners will be used to achieve specific completion objectives or to provide sufficient contingency in mechanically challenging wells such as high departure wells. To date, H2S has not been detected in any Midnight Sun wells. However, with planned watert100d operations, there is some potential of generating small amounts of H2S over the life of the field. Page 18 of 41 I I I I I I I I I I I Ii I I I I I I I Midnight Sun Pool Rules and. Injection Application e May 3, 2000 Safe drilling practices, to account for the effects of H2S gas on both people and equipment will be followed, including continuous monitoring for the presence of H2S. A readily available supply of H2S scavenger, such as zinc carbonate, will be maintained to treat the entire mud system. Emergency operating and remedial protective equipment will be kept at the wellsite. All personnel on the rig will be informed of the dangers of H2S, and all rig site supervisors will be trained for operations in an H2S environment. The nature of the wells to be drilled requires the use of E-75, G-I05, or S-135 grade drillpipe. These materials are susceptible to sulfide stress cracking but can be used safely under the controlled conditions recommended in Section 8, "Drill Stem Corrosion and Sulfide Stress Cracking," of API RP 7G, "Drill Stem Design and Operating Limits" which will be used as applicable. WELL DESIGN AND COMPLETIONS Three additional wells are planned for Midnight Sun, two water supply wells and one horizontal producer. The water supply wells would be drilled into the Tertiary interval and completed with a single casing string and downhole electric submersible pumps (ESPs). Open hole gravel packs would be used in the water supply wells to maximize productivity and prevent sand production. Tubing sizes will vary from 3-1/2 to 5-1/2 inches in Midnight Sun wells. The up structure horizontal producer is planned with a measured depth of over 14,000 ft. and would be completed in the Kuparuk Formation. This departure would necessitate top-setting the Kuparuk. In general, the production casing will be sized to accommodate the desired tubing size in the Midnight Sun wells. The following table indicates the casing and tubing sizes utilized in the proposed well designs for the Midnight Sun wells. Surface Casing Inter I Prod Casing Production Liner Production Tubing Water Supply 9-5/8" N/A N/A 4-1/2" Horizontal 10-314" or 9-5/8" 7 -518" or 7" 4-112" or 3-1/2" 4-112" or 3-112" Page 19 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and. Injection Application e May 3, 2000 Plans are to run L-80 tubing and casing in these wells. All tubing jewelry will be completed with 9-Cr/lMoly, which is compatible with both L-80 and 13-Cr. All proposed wells call for completion in a single zone, with a single string and a single packer. As shown in the schematic, the wells have gas lift mandrels with dummy valves to provide flexibility for artificial lift if needed to enhance production rates. Sufficient mandrels will be run to provide flexibility for changing well production volumes, gas lift supply pressure, and changes in WOR. SUBSURFACE SAFETY VALVES Subsurface safety valves do not appear to be necessary in the Midnight Sun wells according to statewide regulations (20 AAC 25.265). Existing completions are equipped with SSSV nipples. The up structure producer would be completed in a similar manner. SURFACE SAFETY VALVES Surface safety valves are included in the wellhead equipment. These devices can be activated by high and low pressure sensing equipment and are designed to isolate produced fluids upstream of the SSV if pressure 1irrùts are exceeded. Testing of SSVs will be in accordance with the standard PBU Operator practices. DRILLING FLUIDS In order to minimize skin damage from drilling and to maintain shale stability, water-based KCl mud will be used to drill through the Midnight Sun Pool and nearby shales while low solids, non- dispersed fluids will be used for the upper sections of the well. STIMULA TION METHODS Stimulation to enhance productivity or injection capability is not currently planned for Midnight Sun wells. Formation damage associated with drilling and completion activity appears to be Page 20 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and A.Injection Application - May 3, 2000 minor or insignificant. The use of stimulation in the medium to high permeability rock may be evaluated at a later date. RESERVOIR SURVEILLANCE PROGRAM Midnight Sun data will continue to be collected to monitor reservoir performance and, define reservoir properties. Reservoir Pressure Measurements An initial static reservoir pressure will be measured in each new well prior to production. Additionally, a minimum of one pressure survey will be taken annually for the Midnight Sun Pool. This will consist of stabilized static pressure measurements at bottom-hole or may be extrapolated from surface, pressure fall-off, pressure build-up, multi-rate tests, drill stem tests, and open-hole formation tests. The reservoir pressures will be reported at the common datum elevation of 8,050 ft. tvdss. Surveillance Logs Surveillance logs, which may include flowmeters, temperature logs, or other industry proven downhole diagnostic tools, will be periodically run to help determine reservoir performance (e.g., GOC monitoring and injection profile evaluation). Page 21 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and" Injection Application . May 3, 2000 V. Production Allocation Initially, a combination of well tests and wellhead pressure trends will continue to be used to allocate production. Under this methodology, the production from an individual well is first calculated from the average daily wellhead pressure using the deliverability equation. During periods of rising GOR and changing tubing hydraulics, the deliverability equation may not accurately reflect the production as measured by well tests. During such periods, the daily well production is determined by linear interpolation between well test points. A minimum of two well tests per month, as well as lab-measured water cuts and zero-rate tests, are performed on Midnight Sun wells to ensure allocation accuracy. Summing the calculated daily production volume for all producing wells provides an estimate of the Midnight Sun daily field production. A fixed allocation factor of 1.0 is used for Midnight Sun. The long-term metering plan for Midnight Sun is to use continuous production metering. The metering skid described in the Facilities section of this application will be used to continuously meter the entire Midnight Sun production stream through a compact two-phase separator before it is commingled with IPA production at E-Pad. Each wellhead will have a continuous two-phase meter to monitor fluid and gas production, with monthly shakeouts to ascertain water cut. We request Commission approval under 20 AAC 25.215(a) that the Midnight Sun metering is an acceptable method. An allocation factor of 1.0 would continue to be used with the continuous meter. The Midnight Sun Pool will have a set allocation factor of 1.0, with production allocated back to individual wells using the continuous two-phase metering data to calculate wellhead allocation factors. Consistent with existing reporting, no NGLs will be allocated to Midnight Sun. Page 22 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and. Injection Application . May 3, 2000 VI. Area Injection Operations This application, prepared in accordance with 20 AAC 25.402 (Enhanced Recovery Operations) and 20 AAC 25.460 (Area Injection Orders), requests authorization for water injection to enhance recovery from the Midnight Sun Oil Pool. This section addresses the specific requirements of 20 AAC 25.402(c). PLA T OF PROJECT AREA 20 AAC 25.402(c)(1) Exhibit 1-2 shows the location of all existing injection wells, production wells, abandoned wells, dry holes, and any other wells within the Midnight Sun Oil Pool as of April 1, 2000. Specific approvals for any new injection wells or existing wells to be converted to injection service will be obtained pursuant to 20 AAC 25.005, 25.280 and 25.507, or any applicable successor regulation. OPERA TORS/SURFACE OWNERS 20 AAC 25.402(c)(2) and 20 AAC 25.402(c)(3) PHILLIPS Alaska, Inc. is the designated operator of the Midnight Sun Participating Area. Surface Owners within a one-quarter mile radius and inclusive of the Midnight Sun Participating Area are as followings: State of Alaska Department of Natural Resources Attn: Ken Boyd P.O. Box 107034 Anchorage, AK 99510 Pursuant to 20 AAC 25.402(c)(3), Exhibit VI-l is an affidavit showing that the Operators and Surface Owners within a one-quarter mile radius of the area of and included within the Midnight Page 23 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and fa Injection Application tp May 3, 2000 Sun Participated Area have been provided a copy of this application for injection. DESCRIPTION OF OPERATION 20 AAC 25.402(c)(4) Development plans for the Midnight Sun Oil Pool are described in Section II of this application. Drillsite facilities and operations are described in Section III. The source water wells will be permitted and constructed in accordance with 20 AAC 25.005. GEOLOGIC INFORMATION 20 AAC 25.402(c)(6) The Geology of the Midnight Sun Oil Pool are described in Section I of this application. INJECTION WELL CASING INFORMATION 20 AAC 25.402(c)(8) The E-lOO Well will be converted to injection service for the Midnight Sun Oil Pool Enhanced Recovery Project. The casing program for this well was permitted and completed in accordance with 20 AAC 25.030. Exhibit IV-I details the completion for the E-l00 Well. A cement bond log was recorded and indicates good cement bond across and above the Kuparuk River Formation. Conversion ofthe E-lOO Well will be conducted in accordance with 20 AAC 25.412. The actual casing program is included with the "Application to Drill" for each well and is documented with the AOGCC in the completion record. API injection casing specifications are included on each drilling permit application. All injection casing is cemented and tested in accordance with 20 AAC 25.412 for both newly drilled and converted injection wells. All drilling and production operations will follow approved operating practices regarding the presence of HzS in accordance with 20 AAC 25.065. Page 24 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and. Injection Application tp May 3, 2000 INJECTION FLUIDS 20 AAC 25.402(c)(9) Type of Fluid/Source Primary Source - The Midnight Sun Enhanced Recovery Project will utilize water produced from the Tertiary Sagavanirktok formation, as shown in Exhibit VI-2, as an initial and primary water source. Alternate Source - Produced water from GC 1 or produced water separated directly from Midnight Sun production at E-Pad have been identified as potential alternate water source options. Composition Primary Source - A water sample from the Tertiary water source interval has not been obtained. However, it is anticipated the water will be of similar composition as water produced from the OS 15-6 Well in the Cretaceous interval. The OS 15-6 Well water composition is shown in Exhibits VI-3. Alternate Source - The composition of produced water from GC1 is shown in Exhibits VI-4. The composition of Midnight Sun produced water will be a mixture of connate water and source injection water. No oil-water contact has been identified in the Midnight Sun Oil Pool and no significant connate water production has occurred or is anticipated. In order to conduct geochemical modeling, the Midnight Sun Oil Pool connate water composition is assumed to be similar to samples from the offset Pt. McIntyre Oil Pool (refer to Exhibit J-3 in the "Application for Modification to Area Injection Order No.4", dated April 5, 1993). Maximum Injected Rate Maximum water injection requirements at Midnight Sun Oil Pool are estimated at 25,000 BWPO. Compatibility with Formation and Confining Zones Core analyses and geochemical modeling indicate no significant problems with clay swelling or compatibility with in-situ fluids. Analysis of the E-I0l core indicates low clay content (less than Page 25 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and" Injection Application . May 3, 2000 5% by volume), primarily in the form of kaolinite and illite. No fines migration problems are anticipated. Geochemical modeling results indicate that a combination of Tertiary water and connate water is likely form calcium carbonate and barium sulfate scale in the production wells and downstream production equipment. Similar scaling problems are anticipated for the alternate source water options. Scale precipitation will be controlled using standard oil field scale inhibition methods. INJECTION PRESSURES 20 AAC 25.402(c)(1O) The expected average surface water injection pressure for the project is 2250 psig. The estimated maximum surface injection pressure for the Midnight Sun Oil Pool Enhanced Recovery Projects is 2750 psig. The resulting bottom hole pressure will be limited by hydraulic pressure losses in the well tubing, with a maximum expected bottom hole pressure of 6000 psig. FRACTURE INFORMATION 20 AAC 25.402(c)(11) The expected maximum injection pressure for the Midnight Sun Oil Pool Enhanced Recovery Project well(s) will not initiate or propagate fractures through the confIning strata, and, therefore, will not allow injection or formation fluid to enter any freshwater strata. There is no evidence of injection out of zone for similar Kuparuk River Formation watert100d operations on the North Slope. Freshwater Strata There are no freshwater strata in the area of issue (see Section N of the Application for Modification to Area Injection Order No.4, dated April 5, 1993). Additionally, calculations of water salinity from open hole resistivity logs acquired in the Prudhoe Bay E-16 indicate a salinity range of 40,000 to 45,000 ppm for Cretaceous and Tertiary sands above the Kuparuk. River Page 26 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and!. Injection Application , May 3, 2000 Formation. Therefore, even if a fracture were propagated through all confIning strata, injection or formation fluid would not come in contact with freshwater strata. Enhanced Recovery Water injection operations at the Midnight Sun Oil Pool are expected to be above the Kuparuk River Formation parting pressure to enhance injectivity and improve recovery of oil. Fracture propagation models confirm that injection above the parting pressure will not exceed the integrity of the confining zone. The Kuparuk River Formation at the Midnight Sun Oil Pool is overlain by the Kalubik and HRZ shales, which have a combined thickness of approximately 110 feet. The HRZ is a thick shale sequence which tends to behave as a plastic medium and can be expected to contain significantly higher pressures than sandstones of the Kuparuk. River Formation. Mechanical properties determined from log data for the HRZ and Kalubik intervals indicate a fracture gradient from approximately 0.8 to 0.9 psi/ft. No tests have been conducted to determine the formation breakdown pressure at the Midnight Sun Oil Pool; however, data from offset fIelds suggest that a fracture gradient of between 0.6 and 0.7 psi/ft can be expected in the Kuparuk River Formation at initial reservoir conditions. The Kuparuk River Formation is underlain by the Miluveach/Kingak shale sequence. A leakoff test in the Kingak shale formation demonstrated leakoff at a gradient of approximately 0.85 psi/ft. In addition, rock mechanics calculations and data from the Prudhoe Bay Oil Pool indicate that sandstone fracture gradients are reduced during waterflooding operations due to reduced in-situ rock stress associated with the injection of water that is colder than the reservoir. The reservoir temperature for the Midnight Sun Oil Pool is approximately 160o¡., and the expected surface water injection temperature is 60 - 80o¡.. The cold water injection is expected to reduce the fracture gradient by .03 to .05 psi/ft. Page 27 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and" Injection Application e ~ May 3, 2000 HYDROCARBON RECOVERY 20 AAC 25.402(c)(14) The Midnight Sun Oil Pool is estimated to have an original oil in place of 40 to 60 MMSTB. Reservoir simulation studies indicate incremental recovery from waterflooding to be between 15% to 25% of the original oil in place, relative to primary depletion. Page 28 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and. Injection Application . May 3, 2000 VII. Pool Rules Proposed Findings, Conclusions, and Rules PROPOSED FINDINGS PHILLIPS Alaska, Inc., in its capacity as Midnight Sun Operator, respectfully requests that the Commission consider adopting the following findings in establishing an Pool Rules for the Midnight Sun Oil Pool. Geology 1. The Midnight Sun Pool is located north of the Prudhoe bounding fault system and southwest of the Pt. McIntyre Pool. The reservoir interval is the Kuparuk River Formation. 2. The Midnight Sun Pool was discovered in 1997 during the drilling of the Sambuca #1 (E-lOO) well. The well encountered 100 feet of gross hydrocarbon column, with 36 feet of gas above the oil column. 3. In the E-loo well, the top of Kuparuk Formation occurs at 7,974 ft. tvdss (11,662 ft. md) and the base occurs at 8,074 ft. tvdss (11,805 ft. md). 4. Well E-lOl (Midnight Sun #1) was drilled as a downstructure delineation well in the Midnight Sun Pool. The well encountered 84 feet of gross hydrocarbon column all below the GOC identified in the E-lOO well. 5. Lithology is dominantly sandstone with lesser amounts of siltstone and sandy mudstone. The Kuparuk Formation can be divided into upper and lower units. In the lower reservoir unit, which is typically about 40 feet thick, the lithology changes abruptly to porous, quartz-rich sandstone. Grain size is typically very fine to fine-grained and is well sorted. The lithology of the upper unit is variable including interbedded sandstone with minor amounts of muddy siltstone. The thickness of this interval is variable and ranges from 0 to 70 feet. This interval contains glauconite and siderite and is more prone to reductions in porosity and permeability due to cementation and compaction. 6. The Midnight Sun Pool is bounded to the west by the Prudhoe Mid-Field fault, to the south by the Prudhoe bounding fault system, to the north by the Sambuca fault, and to the east by the North Prudhoe structural high. 7. The top of the Kuparuk horizon reaches a structural high to the southwest at 7,780 ft. tvdss against the Prudhoe bounding fault. The Kuparuk Formation dips eastward to a zero edge against the North Prudhoe high at approximately 8,100 ft. tvdss. The structural dip is less than 2 degrees. 8. The Midnight Sun accumulation is a combination structural/stratigraphic trap, with isolation assisted by neighboring structural highs that are fault controlled. The controls on Kuparuk Page 29 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and AlInjeCtiOn Application It May 3, 2000 Formation thickness are fault movement and erosional truncation. 9. The Midnight Sun Pool gas-oil contact (GOC) is interpreted to be at a depth of 8,010 ft. tvdss, based on Repeat Formation Tester (RFT) data. 10. No oil-water contact (OWC) was identified in either of the Midnight Sun wells. 11. Heavy oil was encountered at 8,107 ft. tvdss in the E-1O 1 well. Conventional core from the E-I0l well contained heavy oil in the lower Kuparuk section below 8,107 ft. tvdss. The areal extent of the heavy oil is uncertain. Reservoir Description and Development Planning 1. Mean porosity for the upper Kuparuk Formation is 20.7%, based on E-101 core data. In the lower Kuparuk Formation, excluding the non-reservoir basal interval, the mean porosity is 27.3%. 2. Mean permeability for the upper Kuparuk Formation is 200 md, based on E-l 0 1 core data. In the lower Kuparuk Formation, excluding the non-reservoir basal interval, the mean permeability is 760 md. 3. The net-to-gross ratio for the upper Kuparuk Formation ranges from 0.25 - 0.72. The lower Kuparuk Formation has negligible glauconite and siderite content and exhibits a net-to-gross ratio of approximately 1.0. The non-reservoir basal interval in the lower Kuparuk Formation section is heavily cemented, with a net-to-gross ratio of 0.0. 4. Mean water saturation for the upper Kuparuk Formation is 26.4%, based on E-101 core data. In the lower Kuparuk Formation, excluding the non-reservoir basal interval, the mean water saturation is 12.6%. 5. Based on RFT data, the initial reservoir pressure is estimated at 4058 psia at the reservoir datum of 8050 ft. tvdss. The reservoir temperature is approximately 160 degrees Fahrenheit. 6. Reservoir fluid PVT studies were conducted on a recombined surface sample obtained from the E-101 well. The API gravity of the PVT sample was 25.5 degrees with a solution gas-oil- ratio (GOR) of717 scf/stb, a formation volume factor of 1.33 RVB/STB, and an oil viscosity of 1.68 centipoise at the bubble point pressure. 7. The Midnight Sun Pool contains an estimated Original Oil In Place (OOIP) of 40 to 60 MMSTB, and total gas in place of 100 to 130 BSCF. The free gas volume associated with the gas cap is 60 to 80 BSCF. 8. Production of the Midnight Sun Pool commenced in October of 1998. Early production from the E-100 Well was restricted to mitigate gas coning, and is currently shut in to limit reservoir voidage. Page 30 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and" Injection Application e May 3, 2000 9. Production from well E-IOl demonstrates gas under-running. In January of 1999, the E-101 well was restricted to 5000 BOPD to conserve reservoir energy while completing reservoir surveillance and field development studies. 10. A reservoir model of the Midnight Sun Pool was constructed and history matched to evaluate development options, and reservoir management practices. 11. Three development options were evaluated for the Midnight Sun Pool: 1) primary depletion, 2) upstructure gas injection, and 3) waterflood. 12. Model results indicate that primary depletion would achieve an estimated 14% recovery of the OOIP 13. Model results indicate that up structure gas injection would achieve an estimated 20% recovery of the OOIP after 1.0 hydrocarbon pore volume injection (HCPVI) and 27% after 2.0 HCPVI. The vertical sweep efficiency for up structure gas injection is poor, showing low recovery in the lower Kuparuk unit. 14. Several waterflood development options were studied using the Midnight Sun reservoir model including up structure, downstructure, and midfield water injection. The midfield configuration showed the best overall waterflood performance with greater ultimate recovery and an earlier production profile associated with improved pressure response relative to the other cases. The midfield configuration involves conversion of the E-100 well to injection service. The midfield water injection case achieved an estimated 39% recovery at 0.7 HCPVI. 15. Based on reservoir model studies, the recommended development plan involves implementation of a midfield waterflood for the Midnight Sun Pool. The planned development well program includes the addition of one up structure horizontal production well to complete a three well development of the Midnight Sun Pool. 16. The development plan results in a nominal spacing of 280 acres for the three well development, however the operator has requested a minimum well spacing of 80 acres. 17. Gas cap expansion will provide initial pressure support prior to waterflood start-up. 18. Water injection is expected to commence in the third quarter of 2000, with design injection rates of 20-25,000 BWPD. A peak production rate of 8-10,000 BOPD is expected prior to waterflood breakthrough. 19. Following waterflood start-up, the VRR target will exceed 1.0 to suppress gas production and restore reservoir pressure. A balanced VRR will be maintained once reservoir pressure is restored to a target range of 3800 - 4000 psi. Page 31 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and. Injection Application e May 3, 2000 20. Model results indicate that oil flux into the gas cap will occur as a result of the low structural relief. Reservoir surveillance and voidage management will mitigate oil flux to the west of the up structure horizontal producer. 21. Preliminary analysis indicates there may be potential for enriched gas injection at Midnight Sun; however, no EOR project evaluations have been initiated Facilities I. Midnight Sun wells will be drilled from the E- Pad drill site and make use of existing IP A infrastructure. 2. Midnight Sun fluids will be commingled with Initial Participating Area (IP A) fluids on the surface at E-Pad and then transported to Gathering Center 1 (GCl) for treatment and shipment to Pump Station No.1 (PS-l). 3. Water for watertlood operations will be obtained from two source water wells equipped with electrical submersible pumps 4. Future gas lift gas will be obtained from an IPA E-pad well. Gas removed from this well for raw gas lift will be metered prior to the gas being introduced into any Midnight Sun well. This IP A gas will be returned to the IP A. 5. Initially, production will be allocated based upon well tests as previously approved by the Commission. After a new metering skid is installed in the third or fourth quarter 2000, Midnight Sun production will be continuously metered prior to combining with IP A production. 6. The continuous metering skid will consist of a two-phase separator, with liquids measured by a mass meter and gas production measured by conventional orifice plate methods. The Midnight Sun oil gravity will be used to calculate the oil and water volumes based on the liquid mass measurement. After metering, the gas and liquid streams will be re-combined and commingled with IPA fluids at E-Pad for transport to GCI. The data obtained from the metering skid will provide the basis for allocating production between Midnight Sun and the IPA. Well Operations 1. Additional Midnight Sun Pool development wells will use drilling procedures, well design, and casing and cementing programs consistent with those currently used in other North Slope fields. 2. All proposed wells call for completion in a single zone, with a single tubing string and a single packer Page 32 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and" Injection Application e May 3, 2000 3. Sub-Surface Safety Valves (SSSV) are not installed in existing Midnight Sun, and are not planned for additional wells, however, nipples are installed to allow flexibility to install wireline retrievable SSSVs. 4. Surface safety valves are included in the wellhead equipment of existing Midnight Sun Pool wells. Testing of SSVs will be in accordance with the standard PBU Operator practices. 5. Stimulation to enhance productivity or injection capability is not currently planned for Midnight Sun wells. 6. An initial static reservoir pressure will be measured in each new well prior to production. Additionally, a minimum of one pressure survey will be taken annually for the Midnight Sun Pool. A pressure datum elevation of 8,050 ft. tvdss is recommended. Production Allocation 1. Initially, a combination of well tests using the E-Pad facilities and wellhead pressure trends will continue to be used to allocate production. The daily well production is determined by linear interpolation between well test points. 2. A continuous production metering will be installed to continuously meter the entire Midnight Sun production stream through a compact two-phase separator before it is commingled with IP A production at E- Pad. 3. Each wellhead will have a continuous two-phase meter to monitor fluid and gas production, with monthly shakeouts to ascertain water cut. An allocation factor of 1.0 would continue to be used with the continuous meter. 4. The Midnight Sun Pool will have a set allocation factor of 1.0, with production allocated back to individual wells using the continuous two-phase metering data to calculate wellhead allocation factors. PROPOSED CONCLUSIONS PHILLIPS Alaska, Inc., in its capacity as Midnight Sun Operator, respectfully requests that the Commission consider adopting the following as its conclusions: 1. Commercially exploitable hydrocarbons are present in the Midnight Sun Pool, contained within Kuparuk: River Formation. 2. Pool rules for the development of the Midnight Sun reservoir are appropriate at this time. Page 33 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and" Injection Application e May 3, 2000 3. An integration of interests for the area contemplated for development by the operator exists between the working interest owners and royalty owners. 4. The vertical limits of the Midnight Sun reservoir may be defined in the E-loo well which appears to be a typical and representative well. 5. The low structural relief at the Midnight Sun reservoir limits the effectiveness of gas cap expansion or gas injection as a recovery mechanism. 6. Waterflood operations are planned and appear to achieve the greatest ultimate recovery of oil 7. Other than establishing setting depths, the operator is not requesting variance from statewide casing and cementing requirements. 8. The E-Pad drillsite is an onshore location 9. Subsurface safety valves are not required by statewide regulations 10. Surface commingling of Midnight Sun production with IP A and other Prudhoe satellite production will increase ultimate recovery, will not cause waste nor jeopardize correlative rights. 11. The Midnight Sun continuous metering plan is an acceptable method of allocating produced fluids back to the Midnight Sun Pool for revenue and reservoir management purposes. 12. Appropriate reservoir surveillance data will be obtained to complete development and conduct appropriate reservoir management. 13. The operator has demonstrated that primary depletion, supported by gas cap expansion, does not adversely impact ultimate recovery as long as waterflood operations commence before the reservoir pressure drops below 3300 psi at the reservoir datum. 14. Exception to the gas-oil-ratio limit of20 AAC 25.240(b), is appropriate at this time. PROPOSED RULES PHILLIPS Alaska, Inc., in its capacity as Midnight Sun Operator, respectfully requests that the Commission consider adopting the following Pool Rules for the Midnight Sun Oil Pool: Subject to the rules below and statewide requirements, production from the Midnight Sun reservoir may occur in a manner that will protect freshwater, prevent waste, protect correlative rights, and provide for the maximum ultimate recovery of oil and gas that is prudent. Page 34 of 41 I I I I I I I I I I ,I I I I I I I I I Midnight Sun Pool Rules and" Injection Application e May 3, 2000 In addition to statewide requirements, the following pool rules are proposed to govern the proposed development and operation of the Midnight Sun Pool. Rule 1: Field and Pool Name and Classification The field is the Prudhoe Bay Field and the pool is the Midnight Sun Pool. The Midnight Sun Pool is classified as an Oil Pool. Rule 2: Pool Definition TI2N-R13E: See 25, S1I2; Sec 36, Nl/2, SE1I4, E1I2 of SWl/4 TI2N-RI4E: See 29, ALL; See 30, S1I2, S1I2 ofNE1I4, S1I2 ofNW1I4; Sec 31, N1I2, SW1I4, N1I2 ofSE1I4; Sec 32, NW1I4 TI2N-RI4E: Sec 28, W1I2, W1I2 ofNE1I4, W1I2 of SE1I4 The Midnight Sun Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between measured depths 11,662 and 11,805 feet in the E-IOO well. Rule 3: Spacing Minimum spacing within the pool will be 80 acres. The pool shall not be opened in any well closer than 300 feet to an external boundary where ownership changes. Rule 4: Automatic Shut-In Equipment (a) All wells capable of unassisted flow of hydrocarbons will be equipped with a fail-safe automatic surface safety valve. (b) Injection wells will be equipped with a fail-safe automatic surface safety valve. (c) Surface safety valves will be tested at six-month intervals. Rule 5: Common Production Facilities and Suñace Commingling (a) Prior to installation of a continuous metering skid, producing Midnight Sun wells will be tested a minimum of 2 times per month and production will be allocated by interpolating between well test results. (b) After installation of the continuous metering skid, the requirements of 20 AAC 25.230 will be satisfied by measuring production from the Midnight Sun Pool as a whole, and then allocating that production to each well daily. (c) The allocated production for the Midnight Sun Pool will not be adjusted in conjunction with the IPA allocation factors (i.e. the Midnight Sun allocation factor will be 1.0). (d) The operator shall submit monthly reports containing daily production metering and daily well allocations. Page 35 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and" Injection Application . May 3, 2000 Rule 6: Reservoir Pressure Monitoring (a) A minimum of one bottom-hole pressure survey will be taken annually for the Midnight Sun Pool. (b) The reservoir pressure datum will be 8,050 feet true vertical depth subsea. (c) Pressure surveys may consist of stabilized static pressure measurements at bottom-hole or may be extrapolated from surface, pressure fall-off, pressure build-up, multi-rate tests, drill stem tests, and open-hole formation tests. (d) Data and results from pressure surveys shall be reported annually. (e) Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (d) of this rule. Rule 7: Gas-Oil Ratio Exemption Wells producing from the Midnight Sun Oil Pool are exempt from the gas-oil ratio limit set forth in 20 AAC 25.240(b). Rule 8: Pressure Maintenance Project Water injection for pressure maÙltenance will commence before reservoir pressure drops below 3300 psi at the datum or within 2 years of initial production. Rule 9: Reservoir Surveillance Report A surveillance report will be required after one year of regular production and annually thereafter. The report shall include but is not limited to the following: 1. Summary of produced and injected fluids. 2. Summary of reservoir pressure analyses within the pool. 3. Results of any other special monitoring. 4. Future development plan. The report will be submitted to the Commission by the end of first quarter of each year. Rule 10: Administrative Action Upon proper application, the Commission may administratively waive the requirements of any rule stated above or administratively amend the order as long as the change does not promote waste, jeopardize correlative rights, and is based on sound engineering principles. Page 36 of 41 I I I I I I I I I I I I I I I I I I I Midnìght Sun Pool Rules and .I Injection Application e May 3, 2000 VIII. Area Injection Application Proposed Findings, Conclusions, and Rules PROPOSED FINDINGS PHILLIPS Alaska, Inc., in its capacity as Midnight Sun Operator, respectfully requests that the Commission consider adopting the following findings in establishing an Area Injection Order for the Midnight Sun Oil Pool. 1. The reServoir interval containing the Midnight Sun Oil Pool is the Kuparuk River Formation. 2. Production from the Midnight Sun Oil Pool commenced in October of 1998. There are currently two wells in the Midnight Sun Oil Pool. The location and mechanical configuration of these wells are identified in the application. There are currently no injection wells in the Midnight Sun Oil Pool. 3. Initial enhanced recovery plans for the Midnight Sun Oil Pool call for conversion of one well, E-lOO,¡ to water injection. Water injection is expected to commence in the third quarter of 2000, with a nominal design injection rate of 20-25,000 BWPD. 4. Operators and Surface Owners within a one-quarter mile radius of the area included in the Midnight Sun Participated Area have been provided a copy of this application for injection. 5. Injection water for the enhanced recovery project will be provided by two local source water wells drilled at E-Pad and completed with Electrical Submersible Pumps (ESPs) in the Tertiary Sagavanirktok Formation. Produced water from GCl or produced water separated directly from Midnight Sun production at E-Pad have been identified as potential alternate water source options. 6. An initial three well development program is contemplated, with midfield water injection at the E-l 00 Well, and the addition of one up structure horizontal producer. Additional injection and production wells may be considered depending on reservoir performance and ongoing technical evaluation. 7. Reservoir simulation studies indicate incremental recovery from waterflooding to be between 15 to 25% of the estimated 40-60 MMSTB original oil in place, relative to primary depletion driven by gas cap expansion. Page 37 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and" Injection Application e May 3, 2000 8. The caSing program for the E-l00 Well was permitted and completed in accordance with 20 AAC 25.030. A cement bond log was recorded and indicates good cement bond across and above the Kuparuk River Formation. All injection casing is cemented and tested in accordance with 20 AAC 25.412 for both newly drilled and converted injection wells. 9. Estimated maximum and average injection pressures (psig) for the Midnight Sun Oil Pool are 2250 pSig and 2750 psig, respectively. 10. Followjng watert100d start-up, the voidage replacement by water injection will exceed offtake to suppress gas production and restore reservoir pressure. A balanced voidage replacement will be maintained once reservoir pressure is restored to a target range of 3800 - 4000 psi. 11. Core analyses and geochemical modeling indicate no significant problems with clay swelling or compatibility with in-situ fluids. 12. Water injection operations at the Midnight Sun Oil Pool are expected to be above the Kuparuk River Formation parting pressure to enhance injectivity and improve recovery of oil. 13. The expected maximum injection pressure for the Midnight Sun Oil Pool Enhanced Recovery Projec~ well(s) will not initiate or propagate fractures through the confining strata (Kalubik and HRZ shales), and, therefore, will not allow injection or formation fluid to enter any freshwater strata. 14. There are no freshwater strata overlying the proposed area for this enhanced recovery project. PROPOSED CONCLUSIONS PHILLIPS Alaska, Inc., in its capacity as Midnight Sun Operator, respectfully requests that the Commission consider adopting the following as its conclusions: 1. The requirements of 20 AAC 25.402, and 20 AAC 25.460 have been met for the injection of water for the proposed Midnight Sun Oil Pool enhanced recovery operations. 2. Establishment of a new Area Injection Order for the Midnight Sun Oil Pool area will not cause waste nor jeopardize correlative rights, and is based on sound engineering principles. 3. No underground sources of drinking water (USDW) are known to exist in the Western Operating Area of the Prudhoe Bay Unit, including the proposed Midnight Sun Oil Pool. 4. Authorizing injection of water for enhanced recovery operations in Midnight Sun Oil Pool is Page 38 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sum. Pool Rules and" Injection Application e May 3, 2000 appropriate and in accordance with sound engineering principles. 5. Injection operations in the Western Operating Area of the Prudhoe Bay Unit, and the Midnight Sun Oil Pool will be conducted in permeable strata which can reasonably be expected to accept fluids at pressures less than the fracture pressure of the confining strata. 6. Specific approvals to convert or drill injection wells will be required. PROPOSED RULES PHILLIPS, Alaska, Inc., in its capacity as Midnight Sun Operator, respectfully requests that the Commission issue an order authorizing the underground injection of Class II fluids for enhanced oil recovery in the Midnight Sun Pool and consider the following rules to govern such activity: Affected Area: Tl2N-Rl3E: See 25, Sl/2; Sec 36, Nl/2, SEl/4, El/2 of SWl/4 TI2N-RI4E: See 29, ALL; Sec 30, Sl/2, Sl/2 ofNEl/4, Sl/2 ofNWl/4; Sec 31, Nl/2, SWl/4, Nl/2 of SEl/4; See 32, NWl/ 4 TI2N-RI4!E: Sec 28, Wl/2, Wl/2 ofNEl/4, Wl/2 of SEl/4 Rule 1: Alilthorized Injection Strata for Enhanced Recovery Within the affected area, Class II fluids may be injected for purposes of pressure maintenance and enhanced recovery into strata defined as those which correlate with and are common to the formation found in the E-l 00 Well between the measured depths of 11,662-11,805 feet. Rule 2: Fluid Injection Wells The injectjon of fluids must by conducted: 1) through a new well that has been permitted for drilling asa service well for injection in conformance with 20 AAC 25.005; or 2) through an existing well that has been approved for conversion to a service well for injection in conformance with 20 AAC 25.280. Rule 3: Monitoring the Tubing-Casing Annulus Pressure Variations The tubing-casing annulus pressure of each injection well must be checked at least weekly to ensure there is no leakage and that it does not exceed a pressure that will subject the casing to a hoop stress greater than 70% of the casing's minimum yield strength. Rule 4: Reporting the Tubing-Casing Annulus Pressure Variations Tubing-casing annulus pressure variations between consecutive observations need not be reported to the Commission. Page 39 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and t Injection Application . May 3, 2000 Rule 5: D~monstration of Tubing/Casing Annulus Mechanical Integrity A schedule must be developed and coordinated with the Commission that ensures that the tubing- casing annulus for each injection well is pressure tested prior to initiating injection, following well workovers affecting mechanical integrity, and at least once every four years thereafter. A test surface pressure of 1500 psi or 0.25 psi/ft. multiplied by the vertical depth of the packer, whichever is greater, but not to exceed a hoop stress greater than 70% of the casing's minimum yield strength must be held for at least a 30 minute period with decline no more than or equal to 10% of test pressure. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Rule 6: Well Integrity Failure Whenever disposal rates and/or operating pressure observations or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, the operator must notify the Commission on the first working day following the observation, obtain Commission approval to continue ilijection and submit a plan of corrective action on Form 10-403 for Commission approval. Rule 7: Plpgging and Abandonment of Injection Wells I An injecti<!>n well located within the affected area must not be plugged or abandoned unless approved by the Commission in accordance with 20 AAC 25.105. Rule 8: Administrative Action Upon proper application, the Commission may administratively waive the requirements of any rule stated above or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering principles, and will not result an increased risk of fluid movement into an USDW. Page 40 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and. Injection Application . May 3, 2000 IX. Exhibits Exhibit 1-1 Location Map of Midnight Sun Pool Exhibit 1-2 Midnight Sun Participating Area Exhibit 1-3 Type Log (E-lOO) - Kuparuk Interval Exhibit 1-4 Top Kuparuk Structure Map for Midnight Sun Pool Exhibit 1-5 Kuparuk Isochore Map for Midnight Sun Pool Exhibit 1-6 East-west well structural cross-section along axis of Midnight Sun Pool Exhibit 1-7 North-south well structural cross-section across Midnight Sun Pool Exhibit 1-8 Net sandstone map for Midnight Sun Pool Exhibit 1-9 Gross hydrocarbon distribution map for Midnight Sun Pool Exhibit II~ 1 Fluid Property Summary for the Midnight Sun Pool Exhibit IIf2 Pressure-Volume-Temperature (PVT) Properties as a Function of Pressure Exhibit IIr3 Reservoir Model Layering and Average Physical Properties Exhibit 11-4 Comparison of Model Predictions and Field Performance Exhibit 11.·5 Production and Recovery Profiles for Primary Depletion Exhibit 11.·6 Production and Recovery Profiles for Up structure Gas Injection Exhibit 11-7 Production and Recovery Profiles for Watertlood Exhibit III-I Facility Location Map Exhibit IU-2 Drill Site Schematic Exhibit IU-3 Source Water Injection System Exhibit IV -1 E-loo Wellbore Schematic Exhibit VI-l Affidavit of Notification Exhibit VI-2 Shallow Section Type Log E-16 - Source Water Intervals Exhibit VI-3 DS 15-6 Produced Water Sample Analysis Exhibit V~-4 GC #1 Produced Water Sample Analysis Page 41 of 41 ........-............................ ... /I> .......................... .......... 1 mile Exhibit rea I I I I I SSrvD Depth FEET FEET I I - 11650 - ' I I - 8000 _ 11700 _ I I - 11750 - I - 8050 - I - 11800 - I I I I I I I: 1 k API#: 500292281900 DATE: 21-Feb-1999 SCALE: 1 :240 TVD LOG Exhibit 1-3.. Type Log for Midnight Sun Pool ..---..-.. ..--......-..- .. 1 mi <~;'\ Exhibit .. - -.............................. 1 mile ~'" Exhibit 1...5. uparuk I I I I ARGO Alaska, Inc. Well: F-18 I APt#: 500292063600 DATE: 25-0ctN1999 SCALE: 1:1200 TVO LOG I I I I I I I I I I I I I I I I CT NI R HT C UN S s CTI N R ARGO Aiaska, Inc. Well: E-100 AP¡#: 500292281900 DATE: 25-0ct-1999 SCALE: 1:1200 TVO LOG ARCO Alaska, Inc. Well: E-101 AP¡#: 500292290900 DATE: 2S..oct-1999 SCALE: 1:1200 TVD LOG 1 ARGO Well: NPB_ST_1 AP!#: 500292004900 DATE: SCALE' lOG Inc. I I UN NI HT C CTI N I UCTU I outh I ARGO Alaska, Inc. Well: E-100 AP¡#-: 500292281900 DA TE: 25~Oc¡-1 ggg $CALE: 1:1200 TVD lOG ARGO Alaska, Inc. Well: FAWN_LAKE_1 AP¡#: 500292200700 DATE: 26~Oct*1999 SCALE: 1 :1200 TVD lOG ARGO Alaska, Inc. Well: E-16 AP¡#: 500292048100 DATE: 26-0ct-1999 SCALE: 1:1200 TVO LOG I I I I I I I I I I I I I I I " N rth --..-..---- --------- 1 mile Fawn #1 bit Kuparuk ------------------- 1 mile Exhibit 1...94& Gross Distribution I -MIDNIGHT SUN RESERVO. I FLUID PROPERTIES I INITIAL RESERVOIR PRESSURE AT 8010' TVD-SS 4045 PSIA I BUBBLE POINT PRESSURE 4045 PSIA RESERVOIR TEMPERATURE 160 DEGF I OIL GRA VITY 25 - 29 API I RESERVOIR OIL VISCOSITY 1. 68 CP RESERVOIR WATER VISCOSITY 0.39 CP I RESERVOIR GAS VISCOSITY .027 CP I SOLUTION GAS-OIL-RATIO (Rs) 717 SCF/STB I OIL FORMATION VOLUME V ACTOR (Bo) 1.331 RBL/STB WATER FORMATION VOLUME FACTOR (Bw) 1.045 RBL/STB I GAS FORMATION VOLUME FACTOR (Bg) 0.699 RBL/STB I I I I I I I I I Exhibit II-I I ~IDNIGHT SUN RESERVO:t!Þ I PVT PROPERTIES AS A FUNCTION OF PRESSURE I Pressure Bo Bg Oil Viscosity Gas Viscosit) Solution PSIA RBL/STB RBLIMSCF Cp Cp GOR I MSCF/STB 14.7 1.0541 19.4137 9.2900 0.0100 0.0000 I 154.7 1.0769 19.4137 5.7800 0.0114 0.0490 414.7 1.0992 7.0333 4.5100 0.0124 0.1020 814.7 1.1265 3.4663 3.7200 0.0134 0.1730 I 1214.7 1.1511 2.2654 3.1900 0.0145 0.2390 1614.7 1.1751 1.6681 2.7900 0.0157 0.3040 2014.7 1.1990 1.3149 2.4700 0.0171 0.3690 I 2414.7 1.2234 1.0858 2.2100 0.0188 0.4350 2814.7 1.2485 0.9296 2.0000 0.0208 0.5020 I 3214.7 1.2744 0.8213 1. 8400 0.0228 0.5700 3614.7 1. 30 11 0.7474 1. 7400 0.0249 0.6390 4045.0 1.3311 0.6988 1.6800 0.0271 0.7170 I 4114.7 1.3348 0.6911 1.6674 0.0275 0.7313 4214.7 1.3418 0.6808 1.6561 0.0280 0.7490 I 4314.7 1.3487 0.6712 1.6462 0.0285 0.7666 4414.7 1.3557 0.6624 1.6376 0.0290 0.7843 4514.7 1.3626 0.6544 1.6300 0.0294 0.8020 I 5014.7 1.3974 0.6226 1.6042 0.0315 0.8905 5514.7 1.4321 0.5995 1.5854 0.0333 0.9790 I 6014.7 1.4668 0.5777 1.5563 0.0350 1. 067 5 I I I I I I I Exhibit II - 2 I I I I I I I I I I I I I I I I I I I .IDNIGHT SUN RESERVO. RESERVOIR MODEL LAYERING AND PROPERTIES 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 22.7 23.5 293 420 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.5 0.5 0.5 0.3 0.3 0.3 1.0 0.72 0.72 0.25 0.25 0.25 0.55 0.55 0.55 1.00 1.00 1.00 1.00 1.00 1.00 0.00 22.9 26.1 23.6 26.0 29.3 30.2 29.2 28.5 27.8 23.0 164 405 258 692 1291 1558 741 639 680 3 Exhibit II-3 I I I I I I I I I I I I nj ::J VI VI (j) ..... Q... Midnight Sun 1 c -I *Static BliP @ 8010' TVD-SS 1 Time (Year) D Bl 8- 6- I 4-- 2- I 0 I 1 I I I ES:MI DN IGHT _SUN: 1 Data>: 100:Static BHP n)Oi r Model Hi rruning R j E-100 Coning E-101 Under-Running ÜÜÜÜü.:¿, ¿, ÁÜ..Ii. A 1.1 .1 ..Ii...Ii. Time r) >: ---------- ------ PRODUCTION AND RECOVERY Oil Production vs. Water vs. Time 10000 25 16000 ¡_Oil Rate l 14000 - 8000 - GaR . 20 "1:1 "1:1 :èi 12000 - :èi 1ií 10000 - 6000 15 Ii) oJ 1i 8000 - 4000 ~ 10 a:: ... 6000 œ Õ - «I 4000 - 2000 5 ;: 2000 - 0 0 0 1998 2003 2008 2013 2018 1998 2003 2008 2013 201 Year Year VS. Time Recovery vs. 30000 50 25000 - 40 - ~ <l- t) 20000 ~ 30 Ii) :æ ~ 15000 - !,) œ 20 10000 - a:: Õ 10 5000 0 0 1998 2003 1 2003 2013 2018 Year Year - - -- ----- - - Oil VS. Time 10000 70 1 _OilRate GOR 60 14000 - 8000 ., ., ~ 50 .Q ñ 12000 ñ ~ ø 10000 - ø 6000 œ 8000 - ~ 30 ::¡¡¡ 4000 - ... 6000 - !Ii Õ ~ 20 'ai 4000 2000 := 10 2000 0 0 0 1998 2003 2008 2013 2018 1998 Year Water Production VS. Time - -- 2003 2008 2013 Year Production vs. Time Oil VS. Time 60000 50 50000 40 - :E ';J!. Õ i) œ 40000 >. ::¡¡¡ ... 30 - !Ii 30000 ~ ~ 20 - 20000 - a:: œ N Õ ~ 10000 0 1998 2003 2008 2013 2018 2003 2008 2013 Year Year 201 - -- ----- ------ PRODUCTION AND RECOVERY Oil Production vs. Time 10000 4000 8000 - ~ ¡¡; 6000- õ 2000 o 1998 2003 2008 Year Gas Production VS. Time 30000 25000 :J2 13 20000 Ii) ::'!5 Ii) m CI 5000 0 1998 7 I_Oil Rate ¡__ GOR . 6 ~5.o :!! 4¡ 3~ a:: -2g 1 o 2013 2018 2013 FOR MIDFIELD WATER INJECTION Water Production vs. Time 16000 14000 - :g 12000- 1i$ 10000 c 8000 c 6000 - 4000 - 2000 - o 1998 2003 2008 Year Oil Recovery vs. Time 50 ~ 40 <) > ~ o Q Æ 20 Õ o 1 2003 Year 2013 2018 2018 I I I I I I I I I I I I I I I I I I I . ...-..... ' 1 " . ¡ í t "" ' , , ¡ i " i' Jr'z""'~' " ' f ;' ',. l " }'. . ~ . . / ", J, : ,; \, . ~ ¡, .""",,,,.l J~' (, ' . '. '. ,.' , , , . . ,', .... ~ . , ." . .: ' . ~",~ :.,,', .. .,' ,. ',~, -, . ,,' . " , . <:""' ' .. , ·c ~71t1 . , ' .- , " . ,: , : , I ,J" j' " : rl: ' '," ..,... ''','. ." Exhibit HI-l Facility I I I I I I I I I I I I I I ~ 10 F-PAD WELL PAD E Midnight Sun Development as of January 1, 2000 II Flow1lne- Midnight Sun Equipment IPA Flowline' Skld- Midnight Sun Equipment * Midnight Sun/IPA Ti,,-In Point . CI"ss!Jloo æ MIOOI\Jhl Sun E;;¡ulµrf'oot for \9!t'!1 of FSA per S$(:tw 4-2 ReliEF PfT 21 29 36 200 28 õ--Jr 21.0- -u..... 19Aa I 31 D---' - PIT --a 1 ---a 5 ---a 6 --a 26 1::6 1030 .......:.......25 '-a 11 " ......-.Q 24.4 ' --0234 018'1' ~: I I" I I .,) ... I ~ '" "" " .. 1II!IIIIII!IIi!llllll!lli!llllll!lli!llllll!lli!llllll!lli!llllll!lli G ear .. ...... .. 1IIIIIIIII!IIIIII!IIi!llllll!lli!llllll!lli!llllll!lli!llllll!lli!llllll!lli_ 1IIIIIIIII!IIIIII!IIi' I L!IIIIII!IIi!llllll!lli!llllll!lli!llllll!lli & Cntrl Skid System .. - (Yê~"> .-------------------------- ----------. , I I I I Pwr & Cntr! Skid ,...... - 10 11 - .. .. 00 Well Meters ) ~ I I ftKB I 2245- I I 3405 3410- _.M6.º-- I _lQjjlíL= I 11609 11610 11620 I I 11635 11636 I 11645 11646 11647 11648 I I 11775 11780 11785 11790- -_._~---~ I 11855 I 11870 11871 - l____~ I 12900 12901- 12902 12903 - 12904 12905 12906 - I I -~- SSSV NIPPLE NIP PKR NIP WlEG Perf PKR NIP NIP 13024 - NIP I 13275 I __.,_.__.__.___m~.._ .i/ .i/ Ih. ... Exhibit IV-1 B-100 Wellbore Schematic API: 500292281900 PROD 12/15/97 SSSV Annular Reference log: last Tag: 13023' ELM last Tag Date: 3/15/00 Ref log Date: TD: 13361 ftKB Max Hole 57 deg @ 3950 A Date Note 11/20/98 Minimum ID 3.813" SSSVlN@2242', 'X' NIPPlE@ 11609', 'X' NIPPLE@11635' 12/24/98 'XN' @ 13024' HAS XXN PLUG NIPPLE 11609 8007 NIP 116208015 PKR 11635 8025 NIP 11645 8032 WLEG 11852 8176 PKR 118708189 NIP 12900 9066 NIP 130249181 NIP Ca$ing Strings - All Size Weight Grade 9.625 47.00 L-80 7.000 29.00 L-80 - All Size Weight Grade 4.500 12.60 L-80 4.500 12.60 L-80 Lift Mandrels/Valves Stn MD TVD Man Man Mfr 1 3401 3072 CAMCO 4.5" HES 'X' NIPPLE 7" x 4-1/2", BAKER S8-3 PKR 4.5" HES 'X' NIPPLE Wireline Guide BAKER 4.5" HES 'X' NIPPLE 4.5" HES 'X' NIPPLE 4.5" HES 'XN' NIPPLE, w/ XXN Plug 1/11/98) Top o o Btm 4441 12906 Feet 4441 12906 PRODUCTION Top o 11852 Btm 11646 13277 Feet 116464.5" 1425 4.5" LINER ID 3.810 3.810 3,880 3.810 3.960 4.380 3.810 3.810 1.0 TEGR!O.OOO V Type V OD latch Port TRO Date VI" Run Comment o 11/30/98 VMfr CA RA SHEAR DK DK DK DK DK 1.0 TEGR!O.OOQ 1.0 TEGRiO.OOO 1.0 TEGRiO.OOO 1.0 TEGR!O.OOO 1.0 TEGR!O.OOO 2 5101 3 6751 4 8441 5 10094 6 11543 4079 CAMeO KBG-2-LS 5009 CAMCO KBG-2-LS 6009 CAMCO KBG-2-LS 7067 CAMCO KBG-2-LS 7964 CAMCO KBG-2-LS CA CA CA CA CA Interval 11775 - 11795 13150 - 13155 13155 - 13165 TVD Zone Status Feet SPF Date Type Comment 8122 - 8136 20 41/19/98 9298 - 9303 5 612/26/9 34J HMX 9303 - 9312 10 412/20/9 o 11130/98 o 1 1/30f98 o 11/30/98 o 1 1/30/98 o 11130/98 I e e e e I EXHIBIT VI-l I AFFIDA VIT I STATE OF ALASKA THIRD JUDICIAL DISTRICT I, J. W. Groth, declare and affirm as follows: I 1. I am the Supervisor of Eastern Satellite Development for PHILLIPS Alaska, Inc., the designated operator of the Midnight Sun Participating Area, and as such have responsibility for Midnight Sun operations. I I 2. On ¡vf /ty ~ , 2000, I caused copies of the Midnight Sun Oil Pool, Pool Rules and Area Injection Application to be provided to the following surface owners and operators of all land within a quarter-mile radius of the proposed injection areas: I I Operators: I PHILLIPS Alaska, Inc. Attention: Mr. J. W. Groth P.O. Box 100360 Anchorage, AK 99510-0360 BP Exploration (Alaska) Inc. Attention: M. Cole P.O. Box 196612 Anchorage, AK 99519-6612 I Surface Owners: I State of Alaska Department of Natural Resources Attention: Mr. Ken Boyd P.O. Box 107034 Anchorage, AK 99510 I Dated: rVl ~ ::r ,2000. I ~~.~~~- 1. W. Groth I I " Decl""d and affnmod befn" me this 3~~ day nf M "-'ð- J ,2000. I \ \ \ ¡ [( ({( r (r f¡: . \.\ 0\,.\..5 Te-It\' 1"1",r- \.\.\~""~"" ~ ~h...·, ~ '.-::::. "-v,.... ._ -... : , J...." , (.,) . - '-..<:. 0 ' '" . cr.:::. '->-. , N .~_ :::: et:. ~w, .(¿,?; . CI) - -"".¿ ð'V' :"f~ ~...... ~, ,..¡'" -:::.Y'.>'. .~ ~ ~ -::.,..;. . . . . . 'I;.)~....-\' ./ *....:<'<.\' ./j. ~1'~': \ \ ./ . ~p-., ì I /JJ}lJ))] ì\)' ~.~~/¿.~ ~;~~u~¡ic~ and for Alaska My commission Expires: Z h ~ Izcc I I I I I I i it VI-2 Shallow Section Type Log E...16 Source ater Intervals I ssrvD fEEl Water Source Intervals I 2600 Non Marine I 2700 2600 I 2900 T..8 t: 0 I .- 3000 ........ CO E I T..8 Marker I... 3200 0 u... I 3300 ~ 0 3400 ........ ~ I 3500 I... .- t: CO I T..5 > 3700 C) CO I 3800 UJ 3900 I 4000 4100 I 4200 T-3 I 4300 4400 I I I I I I I I I I I I I I I I I I I I I e . EXHIBIT VI - 3 e . DS-15 PRODUCED WATER SAMPLE ANALYSIS DS #15-6 Cretaceous Water Analysis, February 15, 1990, Sample No. 17241 DETERMINATION PH Total Dissolved Solids Resistivity @ 68 degF Sodium Calcium Magnesium Iron Barium Strontium Chloride Hydroxyl Carbonate Bicarbonate Sulfate Fluoride Silicon Aluminum VALUE 6.4 47005. 0.178 15850. 1260. 890. 12. 137. 60. 28439. o. o. 348. <1. <1. 9. <1. Mg/L OHM-M MgIL Mg/L Mg/L Mg/L MgIL MgIL MgIL MgIL MgIL MglL MglL MgIL MgIL MgIL UNITS I I I I I I I I I I I I I I I I I I I e . EXHIBIT VI-4 e . GC #1 PRODUCED WATER SAMPLE ANALYSIS GC 1 Produced Water Analysis, December 17, 1998 DETERMINATION PH Total Dissolved Solids Resistivity @ 68 degF Sodium Calcium Magnesium Iron Barium Strontium Chloride Hydroxyl Carbonate Bicarbonate Sulfate Fluoride Silicon Aluminum VALUE 7.0 19985. 7420. 190. 78. 5. 3. 21. 11946. 1630 293. <10. 29. <1. Mg/L OHM-M MgIL MgIL Mg/L MgIL MgIL MgIL MgIL MgIL MgIL MgIL MgIL MgIL Mg/L MgIL UNITS :=\1õ . . Notice of Cancellation of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Midnight Sun Pool, Prudhoe Bay Field - Pool Rules ARCO Alaska, Inc. by letter dated February 17, 2000, petitioned the Alaska Oil and Gas Conservation Commission under 20 AAC 25.520 to hold a public hearing to present testimony to establish pool rules for the Midnight Sun Pool, Prudhoe Bay Field, on the North Slope of Alaska. The hearing previously scheduled for April 4, 2000, has been cancelled. A new Public Hearing Notice will be published when the future hearing date is determined. ~~~ Camillé Oechsli Taylor Commissioner Published April 1, 2000 ADN A0-02014030 ORIGINAL . Anchorage Daily News Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 AD# DATE PURCHASE ORDER EDITION ACCOUNT 331557 4/1/2000 02014030 STOF0330 DN STATE OF ALASKA THIRD JUDICIAL DISTRICT Eva Alexie, being first duly sworn on oath deposes and says that she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during 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 pUDlished in regular issues (and not in supplemental form) of said newspaper on the above dates 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. Legal Clerk S-c~~ ~~Q. Subscribed and sworn to me before this date: 4~ II tÄ¡- __J! ~ ~ Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIRES: Ph ~ j.¿lJtj -I~ \\llr(rrf(rr,r \\\\~~~ . ~Ul..(,,-,/- -0q,«/..' --.:.·.or;:... t .··~OTAí?··.~ ......." _..._ J-... _ ~ : ÞÚ8LIC ::: - .~ g :::: ':::'.- "A. --- ,ft': , ~ . ; ~'OF ALÞ-~ . . $' -:/ ...... \' /./.J * \\\ :/J)}JJJ})\)' . PRICE PER DAY $47.73 $47.73 "Ìfettfj,~_ ' øf'~....... . .putllieHeòri be p)6Ii$hiMt . . lure, heørtnti 1Iote-1,s'dIè'ller¡ 'iTli~: c'.<-,\ "'.":,"-.:"::";!'-:--::" /sICtlml#éOêchsLT~: . C:omml$5iorie'r .~.. - ' AQ..,o1OJ~ ,........ . Pvb.: Ä!II'nl, "\!IN RECEIVED .,:;~'I 1 0 2000 i., .\ Alaska Oil & Gas Cons. Commission Anchorage #4 FRO!": .~ ,_~BCO" ~RU1SKR FRX NO.: 9072634894 e .. AReo Alas. Inc. . Post Office Box 100360 Ançhorage, Als8ka 99510-0360 Telephol19 9012761215 03-27-00 04:22P P.02 . ~~ ~,.. Greater Pt. Mcintyre Area March 27, 2000 Robert N. Christensen, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99502-3192 Re: Request to Reschedule the Midnight Sun Hearing Dear Mr. Christensen; ARCO Alaska, Inc. ("ARGO"), in its capacity as Midnight Sun Operator for itself and on behalf of Exxon Mobil CorporatIon ("ExxonMobj") and BP Exploration (Alaska), Inc. ("BPX"), requests that the Commission reschedule the planned April 4, 2000 public hearing on the application for Midníght Sun Oil Pool Rules. As we discussed with you last week, we believe it ÎS desirable to hold one hearing to consider the pool rules and area injection applications at the same time. Accordingly, we request that you reschedule the hearing for a day that is convenient for the Commission in the first or second week in May. Additionally, as discussed at the meeting, the waiver of the GOR limit of 20 AAC 25.240 for Midnight Sun is set to expire on April 1, 2000. Thus, if the Commission postpones the pool rules hearing, we request that the Commission also extend the GOR waiver to August 1, 2000. This action will allow production to continue pending consideration of our proposal that the GOR waiver be included in the pool rules. Please contact J. W. Groth (265-6846) or E. W. Reinbold (263-4465) if you have any questions or require additional information. Sincerely, ~¿~ J. W. Groth ~\.I~n ~ '%I' ~;r~ftJ' · 'd'''' () 1ì'! ~.t ~ ?~. f~ t' ,~; f\ ". \. I 0 uNU :j ~ co: D. W. Bose (ARGO) M. P. Evans (Exxon Mobil) J. Hurliman (BPXA) AnGtQr1æf'1¡f. ~1 *3 e . e . ALASKA OIL AND GAS CONSERVATION COMMISSION /Þf,ð,../;6H"~- ~/ Meeting Subject /ifAe-Cl~ 21" LbOÒ Dateffime NAME - AFFILIATION (pLEASE PRINT) ~ð7fi - ff¡eCo Z~.!Æ~kÏ\ -~~ ~.l \- '-"""'de" ,,~ An·(' C) ) ~I iP y_vAp-\/~ - Ar~'('J '::':t\Ltl '~[JH: - ARC(J Mo.V'5a(~t W{)V\~ .. ~((oh Mobil . {<Lv ~ Vl J..-/ú 0-¿òr n .. r:,Yxdì I1!lJJ I ( ~~++Gi-k~r;[~!J ~£XX~...~~'./ 13;// £fYll1!Ç.f/d - f?fèc() \þtJ\2l)'lI'l\A.a;.lAN - Aor..u.- (f~ ~f-=b- ;.W, C0 ~ ~ ~ ßo¿r'~ ¡) ti-I? S' e~ ~'IO c.. r frO (Ç r-: {" , TELEPHONE 2tr- c afro 2"S-~· &106 2b?-Yftš 2(Pç:,· (p 2.0'] 1Jø ~ -Ir!,q í?" lit; -1504- '5fo4' 3770 st.-if-- -3Ic:¿. .r'-J/ - 372;). cJ63~ t.¡¡/9 ?-:¡, . l-t~ ~ '7q~ -12-~2/ ~.s -...J/¿3'O ?<73-/2¿7 4Þ2 . . Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Midnight Sun Pool, Prudhoe Bay Field - Pool Rules ARCO Alaska, Inc. by letter dated February 17,2000, has petitioned the Alaska Oil and Gas Conservation Commission under 20 AAC 25.520 to hold a public hearing to present testimony to establish pool rules for the Midnight Sun Pool, Prudhoe Bay Field, on the North Slope of Alaska. A hearing will be held at the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501, at 9:00 AM on April 4, 2000, in conformance with 20 AAC 25.540. All interested persons and parties are invited to present testimony. If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing, please contact Diana Fleck at 793-1221 before March 29,2000. Robert N. Christenson, P .E. Chair Published February 25,2000 ADN A002014027 ~ChOrage Daily News. Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 Ad # Date Puchase Order Edition Account Price Per Day 294245 02/25/2000 02014027 ON STATE OF ALASKA THIRD JUDICIAL DISTRICT Eva Alexie, being first duly sworn on oath deposes and says that she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during 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 the above dates 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. Legal Cierk_t~S~~~~____ Subscribed and sworn to me before this date: ----lêjLf{fl(!j--~4-PÆ2---- Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIRES: €b t :ZtJð y. -----'£-4 B ~0- -------- \.\.\¥-~'<... f!l.l.. /'~ ,\. /.' .' ___'.01"'\ ~q,V. . .... ,.... ~ ..' ~e:r~~:k:,1- ~ ....... ./):::., _ _ _ ~o~,. g . ~ Þ~~\G i: ::: ::::. . ,,~ ;,;:,_. .&": '" -::::. \\1>'" ~'<:" ¡ ~ -" ':~-OF þ..\...~.",,, :\' ~ ....... \' /././ * \,,\ /})}jjJ)))))\ STOF0330 $60.63 $60.63 Notice of PUblic Hearin,' i I STATeQf AL,jISK'A f AIOska Oil and Gas : Conservation,'Commission I , .... .'." I Re: MIdnight sunpOOI/' ·RPrUdht>e. Bay Field .. pooí ules ...... . '1 ARCQ Alaska,lnc. by let· 1 ter date~ ,February 17,2000 I h~s petItIOned.. theAlask~ j ..0" an.d G<;Is Conservation i ÇommlSSlpn '{nder 20 AAC ¡ ?5.520 to hold Qpublic hear.! mg_ to present, testirn¿mvtoi es!ab,l ish .pool rules. lor the I M,dnlghl ;Sun Pool, PrO/d· I hoe Bay Field, on the l!Ib.rth Slope 01 Alaska. I A.hea.r ·;ng..'W..i.'I..b e·.'. he Ida t... the Alaska Oil arid Go Conservotion ' CommisSionS 3001 . PorcuPine Drive' AnChor.ag. e, AI.aska 950) aí I 9:OQ AM on April 4, 200Ó, in conlormonce with. 20 . AAC i 25.54Q. All interested' per· I so. ns. ,..and parties a.re i. nVitedl topresenttestimQnv. '. '.1 y~u.·ore a Person wilh 0 I dlS(1b, I :ty",ho. O1ay need" J S.P....C....Ia............'........O...d....,...I.,...C....O.t.i.o.n. ..;n..I..... ordertocømme"t. or. to attend the P.ublic hearing, please contacl Diana Fleék 01193. 1 221 belore March 29 2000. '_' IS/Robert N. Christenson P.E., Choir. ' ."1.°...'°...2..°.).4027... ......1 Pub. :2125, 20p0 . 4f1 . ARCO Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 2761215 . ~~ ~". Greater Pt. Mcintyre Area February 17, 2000 Robert N. Christensen, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99502-3192 Re: Midnight Sun Pool Rules Hearing Request Dear Mr. Christensen: ARCO Alaska, Inc. ("ARCO"), in its capacity as Midnight Sun Operator for itself and on behalf of Exxon Corporation ("Exxon") and BP Exploration (Alaska), Inc. ("BPX"), requests that the Commission hold a public hearing pursuant to 20 AAC 25.540 and issue an order classifying the Midnight Sun Pool as an oil pool and prescribing rules to govern the proposed development and operation of the pool pursuant to 20 AAC 25.520. We request that you schedule the hearing during the week of March 20, 2000, but we also would be available any time in April. Enclosed are the rules that are proposed for the Midnight Sun Pool. In addition, we are prepared to meet informally with the Commission prior to the hearing to review the scope and content of the testimony to be presented at the hearing and to respond to any questions or concerns. Our preference would be to meet at the earliest convenience of the Commission, preferably within the next two weeks. Please contact J. W. Groth (265-6846) or E. W. Reinbold (263-4465) if you have any questions or require additional information. ~~ £--0"11(; J. W. Groth ORIGINAL "'.i; '~ B·... ,,~ !".'r ;J..,,, ;.; ,:~""' cc: D. W. Bose (ARCO) M. P. Evans (Exxon) J. Hurliman (BPXA) .r. \.): pr!sed Midnight SUD Oil Æl Rules In addition to statewide requirements, the following pool rules are proposed to govern the proposed development and operation of the Midnight Sun Pool. Rule 1: Field and Pool Name and Classification The field is the Prudhoe Bay Field and the pool is the Midnight Sun Pool. The Midnight Sun Pool is classified as an Oil Pool. Rule 2: Pool Definition T12N-R13E: Sec 25, S1/2; Sec 36, N1/2, SE1/4, E1/2 of SW1/4 T12N-R14E: Sec 29, ALL; Sec 30, S1/2, S1/2 of NE1/4, S1/2 of NW1/4; Sec 31, N1/2, SW1/4, N1/2 of SE1/4; Sec 32, NW1/4 T12N-R14E: Sec 28, W1/2, W1/2 of NE1/4, W1/2 of SE1/4 The Midnight Sun Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between measured depths 11,662 and 11,805 feet in the E-100 well. Rule 3: Spacing Minimum spacing within the pool will be 80 acres. The pool shall not be opened in any well closer to 300 feet to an external boundary where ownership changes. Rule 4: Automatic Shut-In Equipment (a) All wells capable of unassisted flow of hydrocarbons will be equipped with a fail-safe automatic surface safety valve. (b) Injection wells will be equipped with a fail-safe automatic surface safety valve. (c) Surface safety valves will be tested at six-month intervals. Rule 5: Common Production Facilities and Surface Commingling (a) Prior to installation of a continuous metering skid, producing Midnight Sun wells will be tested a minimum of 2 times per month and production will be allocated by interpolating between well test results. (b) After installation of the continuous metering skid, the requirements of 20 MC 25.230 will be satisfied by measuring production from the Midnight Sun Pool as a whole, and then allocating that production to each well daily. (c) The allocated production for the Midnight Sun Pool will not be adjusted in conjunction with the IPA allocation factors (Le. the Midnight Sun allocation factor will be 1.0). Page 1 of 2 .. pr!sed Midnight SUD Oil J!I Rules (d) The operator shall submit monthly reports containing daily production metering and daily well allocations. Rule 6: Reservoir Pressure Monitoring (a) A minimum of one bottom-hole pressure survey will be taken annually for the Midnight Sun Pool. (b) The reservoir pressure datum will be 8,050 feet true vertical depth subsea. (c) Pressure surveys may consist of stabilized static pressure measurements at bottom-hole or may be extrapolated from surface, pressure fall-off, pressure build-up, multi-rate tests, drill stem tests, and open-hole formation tests. (d) Data and results from pressure surveys shall be reported annually. (e) Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (d) of this rule. Rule 7: Gas-Oil Ratio Exemption Wells producing from the Midnight Sun Oil Pool are exempt from the gas-oil ratio limit set forth in 20 AAC 25.240(b). Rule 8: Pressure Maintenance Project Water injection for pressure maintenance will commence before reservoir pressure drops below 3300 psi at the datum or within 2 years of initial production. Rule 9: Reservoir Surveillance Report A surveillance report will be required after one year of regular production and annually thereafter. The report shall include but is not limited to the following: 1. Summary of produced and injected fluids. 2. Summary of reservoir pressure analyses within the pool. 3. Results of any other special monitoring. 4. Future development plan. The report will be submitted to the Commission by the end of first quarter of each year. Rule 10: Administrative Action Upon proper application, the Commission may administratively waive the requirements of any rule stated above or administratively amend the order as long as the change does not promote waste, jeopardize correlative rights, and is based on sound engineering principles. Page 2 of 2