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Home My WebLink AboutAEO 001• • AQUIFER EXEMPTION ORDER # 1 PRUDHOE BAY UNIT 1. 2. 3. 4. 5. 6 7 May 16 1986 Standard Alaska Production request for AEO May 19, 1986 Area Injection Order Application Prudhoe Bay May 21, 1986 Ltr to US EPA re: Application June 13, 1986 Notice of Hearing and Affidavit of Publication July 1, 1986 Ltr from US EPA to AOGCC re: receipt of Application July 10, 1986 Ltr from US EPA to AOGCC re: phone call to LonnieSmith September 27, 2004 AOGCC's proposal to amend underground injection orders to incorporate consistent language addressing the mechanical integrity of wells AQUIFER EXEMPTION ORDER # 1 ') STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re: THE REQUEST OF STANDARD ALASKA PRODUCTION COMPANY for an Aquifer Exemption Order for that portion of the Prudhoe Bay Unit commonly Known as the Western Operating Area including the contiguous K Pad Area ) ) ) ) " ) ) ) ) ) Aquifer Exemption Order No.1 Western Operating Area including the K Pad Area Prudhoe Bay Unit Prudhoe Bay Field July 11, 1986 IT APPEARING THAT: FINDINGS: 1. Standard Alaska Production Company, by letter of May 16, 1986, requested that the Alaska Oil and Gas Conservation Commission issue an order exempting those portions of all aquifers lying directly below the Western Operating Area and K Pad Area of the Prudhoe Bay Unit for Class II injection activities. 2. Notice of an opportunity for a public hearing on July 21, 1986, was published in the Anchorage Times on June 13, 1986. 3. Neither a protest nor a request for a public hearing was timely filed. Accordingly, the Commission will, in its discretion, issue an order without a public hearing. 4. A copy of Standard Alaska Production Company's request was forwarded to the U.S. Environmental Protection Agency (EPA) - Region 10, on May 21, 1986, in conformance with Section 13 of the Memorandum of Agreement, between the Alaska Oil and Gas Conservation Commission and EPA, effective June 19, 1986. 1. Those portions of freshwater aquifers occurring beneath the Western Operating and K Pad Areas of the Prudhoe Bay Unit do not currently serve as a source of drinking water. 2. Those portions of freshwater aquifers occurring beneath the Western Operating and K Pad Areas of the Prudhoe Bay Unit are situated at a depth and location that makes recovery of water for drinking water purposes economically impracticable. ) Aquifer Exemption Order No.1 Page 2 July 11, 1986 3. Those portions of freshwater aquifers occurring beneath the Western Operating and K Pad Areas of the Prudhoe Bay Unit are reported to have a total dissolved solids content of 7000 mg/l or more. By letter of July 1, 1986, EPA-Region 10 advises that the aquifers occurring beneath the Western Operating and K Pad Areas of the Prudhoe Bay Unit qualify for exemption. It is considered to be a minor exemption and a nonsub- stantial program revision not requiring notice in the Federal Register. 4. 5. The Western Operating Area and the contiguous K Pad Area constitute a compact land parcel which can readily be described by governmental subdivisions. CONCLUSION: Those portions of freshwater aquifers lying directly below the Western Operating and K Pad Areas of the Prudhoe Bay Unit qualify as exempt freshwater aquifers under 20 AAC 25.440. NOW, THEREFORE, IT IS ORDERED THAT the portions of aquifers on the North Slope described by the 1/4 mile area beyond and lying directly below the following tracts of land are exempted for Class II injection activities only. UMIAT MERIDIAN T12N RI0E Sections 13 and 24. T12N RIlE Sections 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 32, 33, 34, 35 and 36. T12N R12E Sections 7, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35 and 36. T12N R13E T12N R14E TIIN RIlE T11N R12E Sections 19, 20, 21, 22, 23, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35 and 36. Sections 27, 28, 29, 31, 32, 33 and 34. Sections 1, 2, 3, 4, 9, 10, 11, 12, 13, 14, 15, 24 and 25. Entire Township. ') Aquifer Exemption urder No.1 Page 3 July 11, 1986 TIIN R13E TIIN R14E TI0N R12E TI0N R13E TI0N R14E DONE at Anchorage, Entire Township. Sections 3, 4, 5, 6, 7, 8, 17, 18, 19, 20, 29, 30, 31 and 32. Sections 1, 2, 3, 4, 10, 11 and 12. Sections 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, and 24. Sections 5, 6, 7, 8, 17, 18, 19 and 20. Alaska and dated July 11, 1986. (7f! (7{?1' C. V. Chatterto .~~_. Alaska Oil and as Conservation ~. ~iSSioner Alaska Oil and Gas Conservation Commission Commission ~M William W. Barnwe I, Commissioner Alaska Oil and Gas Conservation Commission ~? j° FRANK H. MURKOWSKI, GOVERNOR Li r' ALA N OIL AND GALS 333 W. 7" AVENUE, SUITE 100 CONSERVATION COMUSSION ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 September 27, 2004 Proposals to Amend Underground Injection Orders to Incorporate Consistent Language Addressing the Mechanical Integrity of Wells The Alaska Oil and Gas Conservation Commission ("Commission"), on its own motion, proposes to amend the rules addressing mechanical integrity of wells in all existing area injection orders, storage injection orders, enhanced recovery injection orders, and disposal injection orders. There are numerous different versions of wording used for each of the rules that create confusion and inconsistent implementation of well integrity requirements for injection wells when pressure communication or leakage is indicated. In several injection orders, there are no rules addressing requirements for notification and well disposition when a well integrity failure is identified. Wording used for the administrative approval rule in injection orders is similarly inconsistent. The Commission proposes these three rules as replacements in all injection orders: Demonstration of Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (except at least once every two years in the case of a slurry injection well), and before returning a well to service following a workover affecting mechanical integrity. Unless an alternate means is approved by the Commission, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30 minute period. The Commission must be notified at least 24 hours in advance to enable a representative to witness mechanical integrity tests. Well Integrity Failure and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval. The operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the Commission. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation. • Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above 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 fluid movement outside of the authorized injection zone. The following table identifies the specific rules affected by the rewrite. Affected Rules Injection Order "Demonstration of "Well Integrity "Administrative Mechanical Failure and Action" Inte 'ty" Confinement" Area Injection Orders AIO 1 -Duck Island Unit 6 7 9 AIO 2B - Kuparuk River Unit; Kuparuk River, Tabasco, Ugnu, West Sak 6 ~ 9 Fields AIO 3 -Prudhoe Bay Unit; Western Operating Area 6 ~ 9 AIO 4C -Prudhoe Bay Unit; Eastern Operating Area 6 ~ 9 AIO 5 -Trading Bay Unit; McArthur River Field 6 6 9 AIO 6 -Granite Point Field; Northern Portion 6 ~ 9 AIO 7 -Middle Ground Shoal; Northern Portion 6 ~ 9 AIO 8 -Middle Ground Shoal; Southern Portion 6 7 9 AIO 9 -Middle Ground Shoal; Central Portion 6 ~ 9 AIO l OB -Milne Point Unit; Schrader Bluff, Sag River, 4 5 g Kuparuk River Pools AIO 11 -Granite Point Field; Southern Portion 5 6 8 AIO 12 -Trading Bay Field; Southern Portion 5 6 8 AIO 13A -Swanson River Unit 6 ~ 9 AIO 14A -Prudhoe Bay Unit; Niakuk Oil Pool 4 5 8 AIO 15 -West McArthur 5 6 9 • Affected Rules Injection Order "Demonstration of "Well Integrity "Administrative Mechanical Failure and Action" Integrity" Confinement" River Unit AIO 16 - Kuparuk River Unit; Tarn Oil Pool 6 7 10 AIO 17 - Badami Unit 5 6 8 AIO 18A -Colville River Unit; Alpine Oil Pool 6 7 11 AIO 19 -Duck Island Unit; Eider Oil Pool 5 6 9 AIO 20 -Prudhoe Bay Unit; Midnight Sun Oil Pool 5 6 9 AIO 21 - Kuparuk River Unit; Meltwater Oil Pool 4 No rule 6 AIO 22C -Prudhoe Bay Unit; Aurora Oil Pool 5 No rule 8 AIO 23 - Northstar Unit 5 6 9 AIO 24 -Prudhoe Bay Unit; Borealis Oil Pool 5 No rule 9 AIO 25 -Prudhoe Bay Unit; Polaris Oil Pool 6 g 13 AIO 26 -Prudhoe Bay Unit; Orion Oil Pool 6 No rule 13 Dis osal In'ection Orders DIO 1 -Kenai Unit; KU WD-1 No rule No rule No rule DIO 2 -Kenai Unit; KU 14- 4 No rule No rule No rule DIO 3 -Beluga River Gas Field; BR WD-1 No rule No rule No rule DIO 4 -Beaver Creek Unit; BC-2 No rule No rule No rule DIO 5 -Barrow Gas Field; South Barrow #5 No rule No rule No rule DIO 6 -Lewis River Gas Field; WD-1 No rule No rule 3 DIO 7 -West McArthur River Unit; WMRU D-1 2 3 5 DIO 8 -Beaver Creek Unit; BC-3 2 3 5 DIO 9 -Kenai Unit; KU 11- 17 2 3 4 DIO 10 -Granite Point Field; GP 44-11 2 3 5 ~~ Affected Rules Injection Order "Demonstration of "Well Integrity "Administrative Mechanical Failure and Action" Integrity" Confinement" DIO 11-Kenai Unit; KU 24-7 2 3 4 DIO 12 - Badami Unit; WD- 1, WD-2 2 3 5 DIO 13 -North Trading Bay Unit; S-4 2 3 6 DIO 14 -Houston Gas Field; Well #3 2 3 5 DIO 15 -North Trading Bay Unit; S-5 2 3 Rule not numbered DIO 16 -West McArthur River Unit; WMRU 4D 2 3 5 DIO 17 -North Cook Inlet Unit; NCIU A-12 2 3 6 DIO 19 -Granite Point Field; W. Granite Point State 3 4 6 17587 #3 DIO 20 -Pioneer Unit; Well 1702-15DA WDW 3 4 6 DIO 21 - Flaxman Island; Alaska State A-2 3 4 7 DIO 22 -Redoubt Unit; RU D 1 3 No rule 6 DIO 23 -Ivan River Unit; IRU 14-31 No rule No rule 6 DIO 24 - Nicolai Creek Unit; NCU #5 Order expired DIO 25 -Sterling Unit; SU 43-9 3 4 7 DIO 26 - Kustatan Field; KFl 3 4 7 Storage Injection Orders SIO 1 -Prudhoe Bay Unit, Point McIntyre Field #6 No rule No rule No rule SIO 2A- Swanson River Unit; KGSF # 1 2 No rule 6 SIO 3 -Swanson River Unit; KGSF #2 2 No rule 7 Enhanced Recove In'ection Orders EIO 1 -Prudhoe Bay Unit; Prudhoe Bay Field, Schrader No rule No rule 8 Bluff Formation Well V-105 • Affected Rules Injection Order "Demonstration of "Well Integrity "Administrative Mechanical Failure and Action" Integrity" Confinement" EIO 2 -Redoubt Unit; RU-6 5 g g 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM STATE OF ALASKA NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED A 0.02 514016 ORDER AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF A ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTO[uI FOR INVOICE ADDRESS F AOGCC AGENCY CONTACT DATE OF A.O. R 333 West 7th Avenue, Suite 100 ° Anchorage, AK 99501 PHONE pC M 907-793-1221 DATES ADVERTISEMEYT REQUIRED: o Journal of Commerce October 3, 2004 301 Arctic Slope Ave #350 Anchorage, AK 99S 1 S THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED [N ITS ENTIRETY ON THE DATES SHOWY. SPECIAL INSTRUCTIONS: AFFIDAVIT OF PUBLICATION United states of America REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. division. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. Before me, the undersigned, a notary public this day personally appeared ATTACH PROOF OF PUBLICATION HERE. .who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2004, and thereafter for consecutive days, the last publication appearing on the day of .2004, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This _ day of 2004, Notary public for state of My commission expires Public Notices • Subject: Public Notices From: Jody Colombie <jody_colombie@admin.state.ak.us> Date: Wed, 29 Sep 2004 13:01:04 -0800 To: undisclosed-recipients:; BCC: Cynthia B Mciver <bren mcver@admin.state.ak.us> Angela Webb <ange_webb@adinin.state.ak.us>, Robert E ~ntz <robert_mntz(ci?Ia~~.state.ak.us>, Christine Hansen <e.hansen@iogcc.state.ok.us>, Terrie Hubble<hubbletl@bp.cam=, Sondra Stewman <StewmaSD@BP.eom>,, Scott & Carnrny,Taylor <staylor@alaska.net~, stanekj <stanek@unocai.com> ecolaw <ecolaw@rustees.org>, roseragsdale <roseragsdale@gci.net>, trm}rl <trmjri@aol.com>, jbriddle <jbriddle@m~rathonoil.com>, rockhill <rc~ckhll(u;aoga.crrg>, shaneg <shaneg@evergreengas.cam>, jdarlington <jdaringtan@forestoil.cortl%, nelson <knelson@petroleumnews.com>, cboddy <cboddy@usibelli.com>, M<n-k Dalton , <mark.dalton@hdrinc.com>, Shannan Donnelly <shannan.dc~nnellylu,;conocophillips.com>, "Mark P. Worcester" <mark.p.worcester@eonocophillips.com>, "Jerry C: Detl~lefs" <jerry.c.dethlefs@conocaphillips.com>, Bob <bob@nletkeeper.org> ~~~dv ~ ~vd~~@dnr.state.ak.us>, tjr <tj~@dnr:state.ak.u5?, Bbritch <bbriteh@alaska.net>, mjnelson <mjnelson@purvingertz.eom>, Charles ODonnell <charles.o'donnell@veco.cam>, "Randy L, Skillern" <SkilleRI:@BP.com>, "Deborah J. Jones" <JonesD6@BP.com>, "Paul G. Hyatt" <hyattpg@BP.corn>, "Steven R. Rossberg" <RossbeRS~a BP_corn>, Lois dais@nletkeeper.org>, Dan Bross <kuacne«•s(a;kuac.org>, Gordon Pospisil <PospisG@BP.com>, "Francis S. Sommer" <SommerFS~;BP.com=-, Mikel Schultz. <Mikel.Schultz@BP.cam>, "Nick W Glover" <GloverNW@BP.corn>, "Daryl J. Kleppin" <KleppiDE@BP.corn>, "Janet D. Platt" <PlattJD@BP.com>, "Raszinne !~~t. Jacobsen" <JacobsR.M@BP.eom> ddonkel <ddonkel@efl.rr.com>,`Colln~ 'Mount <collns mount@revenue.state.ak.us>, mckay <mckay@,gci.net>, Barbara F Fullmer <Barbara.f.fullmer@conocophllips.eom> bocastwf <bocastwt@bp.cum===. Charles Barker . <barker@usgs.gov>, doug_s~hultze <doug schultze@xtaenergy.com>, Harilc Alford ' <hank.alford@exxanmobil.com>, Mark Kovac <yesnol@gci.net>, gspfoff <gspfoff@aurorapower.corn>, Gregg Nady <gregg.nady@shell.eom>, Fred Steece <fred.steeee@state.sd.us>, rcrotty <rerotty@eh2mcom>, jejones ~ jejon~s;a%aurorapower.eortt>, dapa <dapa@alaska.net> jroderick <jroderick@gci.net>, eyanc~ <~eyanc,y('a,seal-tite.net~, ".-ames M. Ruud" ~james.m.ruud<<~conocophil~ips.corn>, Brit f.ivcly ~mapalaska(cLak.net>, jah <jah@dnr.state.ak.us>, Kurt E Olson <kurt alson@egis.state.ak.us>, buonoje ~~buonoje ubp.com>, Mark Hanley<mark hanley@anadarko.com>, loren_lernan <loren leman(~~gov.state.ak.us>, Julie Houle <julie_houle@dnrstate.ak.us> John W Katz <jwkatz@ssa.or~=, Surar~ J Hill <suzan hill@dec.state.ak.us>, taBlerk <taBlerk@unocal.com>, Brady ~brady(a;ao~a.org>, Brian Havelock <beh@dnr.state,ak.us>, bpopp <bpopp@borough.kenai.ak.us==, Jim ~~'hite <jhnwhite@satx.rr.eom>, "John. S. Ha~vorth" <~ol~a.haworthrcr,:exxonmobil.com>, marts <marty@rkindustra}.c~m=>, ghammans <gharnmons@aol.com>, rmclean <rmclean@pc~Box.alaska.net>, rnkrn7200 <mkm72D0@aal.corn=-, Brian Gillespie <ifbmg@uaa.alaska.edu>,'David L Boelens ~dboelens@,aurorapo~ver.com,=r, Todd Durkea <TDIJRKEE@KMG.com>, Gary Schultz <gars_schultz~a%dnr.state.ak.us>, «~a~ne Rancier <RANCIER@petro-canada.ca=>, Bill Miller <Bill_Miller(c%~toalaska.com~. Brandon. Gagnon <bgagnon@Brenalaw.co~n>, Paul Winslow <pmwirtslow~~torestoiLcom= ,Garry Catron <catrongr@bp.eam>, Sharmaine Copeland <copelasv@bp.com>, Suzanne Allexan <sallexan@helm~nergy.com?, Kristin Dirks <krstin dirks(u!dnr.state.ak.us~, Etaynell Zeman <kjzeman~~i~marathonoiLcom >, Jc>lm Tc~~~~et-~ohn.Tower~cieia.doe.go~->, Bill Fowler <Eill_Fowler@anadarko.COM>, Vaughn Swartz <vaughn.s~~ artz~i rbccm.com>, Scott Cranswek i of 2 9/29/2004 1:10 PM Public Notices ~ . <scott.cranswick@mrn .gov>, Brad McKim <mcl~imbs@BP.com> Please find the attached Notice and Attachment for the proposed amendment of underground injection orders and the Public Notice Happy Valley #10. Jody Colombie Content-Type: app~icaton,~msward IVlechanieal Integrity proposal.doc Content-Encoding:-base64 - _ _ __ iComent-Type:.. applcation,!msword Mechanical Integrity of Wells Notice.doc i Coment-Encoding: base64 i, Content-Type: applicationlmsword IlappyValleyl0_HearingNotice.doc Content-Encoding: base64 2 of 2 9/29/2004 1:10 PM Public Notice ~ . Subject: Public Notice From: Jody Colombie <jody Colombie@admin.state.ak.us> Date: Wed, 29 Sep 2004 12:55:26 -0800 To: legal@alaskajournal.com Please publish the attached Notice on October 3, 2004. Thank you. Jody Colombie _ _ .._ Content-Type: application/msword 'Mechanical Integrity of Wells Notice.doc Gontent-Encoding: base64 .... _ _ .................. _ __ _ Content-Type: application/msword '! !Ad Order form.doc Content-Encoding: base64 1 of 1 9/29/2004 1:10 PM Citgo Petroleum Corporation Mary Jones David McCaleb PO Box 3758 XTO Energy, Inc. IHS Energy Group Tulsa, OK 74136 Cartography GEPS 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 Ft. Worth, TX 76102-6298 Houston, TX 77056 Kelly Valadez Robert Gravely George Vaught, Jr. Tesoro Refining and Marketing Co. 7681 South Kit Carson Drive PO Box 13557 Supply & Distribution Littleton, CO 80122 Denver, CO 80201-3557 300 Concord Plaza Drive San Antonio, TX 78216 Jerry Hodgden Richard Neahring John Levorsen Hodgden Oil Company NRG Associates 200 North 3rd Street, #1202 408 18th Street President Boise, ID 83702 Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 Kay Munger Samuel Van Vactor Michael Parks Munger Oil Information Service, Inc Economic Insight Inc. Marple's Business Newsletter PO Box 45738 3004 SW First Ave. 117 West Mercer St, Ste 200 Los Angeles, CA 90045-0738 Portland, OR 97201 Seattle, WA 98119-3960 Mark Wedman Schlumberger David Cusato Halliburton Drilling and Measurements 200 West 34th PMB 411 6900 Arctic Blvd. 2525 Gambell Street #400 Anchorage, AK 99503 Anchorage, AK 99502 Anchorage, AK 99503 Baker Oil Tools Ciri Jill Schneider 4730 Business Park Blvd., #44 Land Department US Geo{ogical Survey Anchorage, AK 99503 PO Box 93330 4200 University Dr. Anchorage, AK 99503 Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 Williams Thomas North Slope Borough Arctic Slope Regional Corporation PO Box 69 Land Department Barrow, AK 99723 PO Box 129 Barrow, AK 99723 [Fwd: Re: Consistent Wording for Injection ~s -Well Integrity ... Subject: [Fwd: Re: Consistent Wording for Injection Orders - From John Norman <john_norman@adrnin.state.ak.us> Date: Fri, 01'.Oct 2004 11:09:26 -0800 To; Jody) Colombie <Jody colombie@admin.state.ak.us> more s Well Integrity (Revised)] ------- Original Message -------- Subject:Re: Consistent Wording for Injection Orders -Well Integrity (Revised) Date:Wed, 25 Aug 2004 16:49:40 -0800 From:Rob Mintz <robert mintz(cLlaw.state.ak.us> To:jim regg(c~adrnin.state.ak.us CC:dan seamount(~admin.state.ak.us, john norman(cr),admin.state.ak.us Jim, looks good, but I still think maybe it would be good to include the following sentence or something like it in the well integrity and confinement rule: "The operator shall shut in the well if so directed by the Commission." My thinking is that otherwise, an operator might argue that the Commission can only require the well to be shut in by going through an enforcement action, issuing an order after notice and opportunity for hearing, or meeting the strict requirements for an emergency order under the regulations. The proposed language makes clear that it is a condition of the authorization to inject, that the operator must shut in the well if directed by the Commission after a notification of loss of integrity, etc. »> James Regg <jim reg~~;admin.state.ak.us> 8/25/2004 3:15:06 PM »> Rob -Thanks for the review; here's a redraft after considering your comments. I have accepted most of the suggested edits; also attached is response to questions you pose (responses are embedded in the comments, using brackets [JBR - ...) to set apart from your questions). Jim Regg Rob Mintz wrote: Jim, I have some questions about the draft language, which are shown as comments on the first document attached. Based on my current guesses about what the answers will be to my questions, I also have some suggested edits, which are shown as redlines on the second document attached. »> James Regg <jim reQti~admin.state.ak.us> 8/17/2004 4:33:52 PM »> Please delete previous version (email sent 8/9/04); I found another inconsistency in the injection orders regarding well integrity that I have integrated into the proposed fix. Attached is a proposal for consistent language in our injection orders addressing 3 rules related to well integrity: - "Demonstration of Tubing/Casing Annulus Mechanical Integrity" - "Well Integrity Failure" - "Administrative Actions". This proposal includes input from all Sr. staff (except Jack). If you agree with the approach, I'll work with Jody to prepare the public notice. Main points - Demonstration of Tubing/Casing Annulus Mechanical Integrity - standardizes the wording used for mechanical integrity demonstrations, and establishes abililty to grant alternate methods (e.g., temp survey, logging, pressure monitoring in lieu of pressure testing 1 of 2 10/2/2004 4:07 PM [Fwd: Re: Consistent Wording for Injectior~ers -Well Integrity ... - specific to AIO 2C for Kuparuk, there is wording that is more appropriately included in Well Integrity Failure (i.e., more frequent MITs when communication demonstrated) - establishes more frequent MIT schedule for slurry injection wells (every 2 yrs) which is consistent with our current practice (but not addressed in regulations) Well Integrity Failure - retitles to "Well Integrity Failure and Confinement"; inserted language regarding injection zone integrity (see DIO 25 and 26) - consistent language regardless of type of injection (disposal, EOR, storage); - eliminates requirement for immediate shut in and secure; allows continued injection until Commission requires shut in if there is no threat to freshwater; - eliminates delay in notifying Commission after detect leakage or communication ("i.e., "immediately notify"); - removes language about notifying "other state and federal" agencies; - requires submittal of corrective action plan via 10-403; - requires monthly report of daily injection rate and pressures (tubing and all casing annuli); this is a requirement we currently impose when notified of leak or pressure communication; - notice and action not restricted to leaks above casing shoe as stated in several DIOs Administrative Actions - adopts "Administrative Actions" title (earlier rules used "Administrative Relief'); - consistent language regardless of type of injection (disposal, EOR, storage); - uses "administratively waive or amend" in lieu of terms like "revise", "reissue", etc.; - adds geoscience to "sound engineering principles"; - language is more generic regarding fluid movement out of zone; existing versions mention varying combinations of protecting "freshwater", "aquifers", "USDWs"; "risk of fluid movement"; "fluid escape from disposal zone" Jim Regg _.. _ _ John K. Norman <John Norman(a~admin.state.us> Commissioner Alaska Oil & Gas Conservation Commission 2 of 2 10/2/2004 4:07 PM ,[Fwd: Re: Consistent Wording for Injection ~s -Well Integrity ... • Subject: [Fwd: Re Consistent, Wording for Injection Orders - We1I Integrity (Revised)]: From: John Norman <john_norman@admin.state.ak.us> Date: Fri, O1 Oct 2004 11:08:55 -0800 To: Jody J Coiornbie <jody_colombie@admnstate.ak.us> please print all and put in file for me to review just prior to hearing on these amendments. thanx ------- Original Message -------- Subject:Re: Consistent Wording for Injection Orders -Well Integrity (Revised) Date:Thu, 19 Aug 2004 1:46:31 -0800 From:Rob Mintz <robert mintz(dlaw.state.ak.us> To:dan seamount(a~admin.state.ak.us, jim regg(aadmin.state.ak.us, john norman(a,admin.state.ak.us Jim, I have some questions about the draft language, which are shown as comments on the first document attached. Based on my current guesses about what the answers will be to my questions, I also have some suggested edits, which are shown as redlines on the second document attached. »> James Regg <jim regg(w,admin.state.ak.us> 8/17/2004 4:33:52 PM »> Please delete previous version (email sent 8/9/04); I found another inconsistency in the injection orders regarding well integrity that I have integrated into the proposed fix. Attached is a proposal for consistent language in our injection orders addressing 3 rules related to well integrity: - "Demonstration of Tubing/Casing Annulus Mechanical Integrity" - "Well Integrity Failure" - "Administrative Actions". This proposal includes input from all Sr. staff (except Jack). If you agree with the approach, I'll work with Jody to prepare the public notice. Main points - Demonstration of Tubing/Casing Annulus Mechanical Integrity - standardizes the wording used for mechanical integrity demonstrations, and establishes abililty to grant alternate methods (e.g., temp survey, logging, pressure monitoring in lieu of pressure testing - specific to AIO 2C for Kuparuk, there is wording that is more appropriately included in Wetl Integrity Failure (i.e., more frequent MITs when communication demonstrated) - establishes more frequent MIT schedule for slurry injection wells (every 2 yrs) which is consistent with our current practice (but not addressed in regulations) Well Integrity Failure - retitles to "Well Integrity Failure and Confinement"; inserted language regarding injection zone integrity (see DIO 25 and 26) - consistent language regardless of type of injection (disposal, EOR, storage); - eliminates requirement for immediate shut in and secure; allows continued injection until Commission requires shut in if there is no threat to freshwater; - eliminates delay in notifying Commission after detect leakage or communication ("i.e., "immediately notify"); - removes language about notifying "other state and federal" agencies; - requires submittal of corrective action plan via 10-403; - requires monthly report of daily injection rate and pressures (tubing and all casing annuli); this is a requirement we currently impose when notified of leak or pressure communication; - notice and action not restricted to leaks above casing shoe as stated in several DIOs Administrative Actions 1 of 2 10/2/2004 4:07 PM [Fwd: Re: Consistent Wording for Injectior~ers -Well Integrity ... - adopts "Administrative Actions" title (earlier rules used "Administrative Relief'); - consistent language regardless of type of injection (disposal, EOR, storage); - uses "administratively waive or amend" in lieu of terms like "revise", "reissue", etc.; - adds geoscience to "sound engineering principles"; - language is more generic regarding fluid movement out of zone; existing versions mention varying combinations of protecting "freshwater", "aquifers", "USDWs"; "risk of fluid movement"; "fluid escape from disposal zone" Jim Regg John K. Norman <John Norman cr,admin.state.us> Commissioner !', Alaska Oil & Gas Conservation Commission ' Content-Type: application/msword jInjection Order language - questions.doc Content-Encoding: base64 __ _. _ _ Content-Type: application/msword !Injection Orders language edits.doc Content-Encoding: base64 __ 2 of 2 10/2/2004 4:07 PM • Standardized Language for Injection Orders Date: August 17, 2004 Author: Jim Regg Demonstration of Tubin /Casing Annulus Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, after a workover affecting mechanical integrity, and at least once every 4 years while actively injecting. For slurry injection wells, the tubing/casing annulus must be tested for mechanical integrity every 2 years. The MIT surface pressure must be 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, must show stabilizing pressure and may not change more than 10% during a 30 minute period. Any alternate means of demonstrating mechanical integrity must be approved by the Commission. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Well Integrity Failure and Confinement The tubing, casing and packer of an injection well must demonstrate integrity during operation. The operator must immediately notify the Commission and submit a plan of corrective action on Form 10-403 for Commission approval whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, or log. If there is no threat to freshwater, injection may continue until the Commission requires the well to be shut in or secured. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating pressure communication or leakage. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above 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 fluid movement outside of the authorized injection zone. • Standardized Language for Injection Orders Date: August 17, 2004 Author: Jim Regg Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, at least once even' four years thereafter fe~ccept at least once event two years in the case of a slurrtir infection ti~•ell), and. before returning a «•ell to se-n•ice follo~vin~ a workover affecting 1V~~ `<ie is mechanical integrity -' ~~* r, ~~* ~ ;~ ~~~~ ~ ~*~ ~ ~ *~ V Unless acs alternate means is approved by the Commission mechanical integrity must be demonstrated by a ti.~bin~ pressure test using a T~ ?vI-1-surface pressure ~f~~ 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, t11at t~~t-shows stabilizing pressure that does"„ not change more than 10°x-percent during a 30 minute period. ~iy .. - . The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Well Integrity Failure and Confinement EYCept as «thenvise provided in this rule Tthe tubing, casing and packer ofan injection well must dans~ate-maintain integrity during operation. «%henever any pressure communication, leakage or lack of infection zone isolation is indicated by infection rate operating pressure obscrvatio€z, test, survey log, or other evidence tThe operator nshall immediately notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval, i~j~''t'~~'-''•'r" - '~ ' ~ T• ~' ~ •' The operator shall shut in the r ,~, N ~%4 CLCl~ S 7 T well if so directed by the Commission. The operator steall shut in the; well without awaiting a ~•esponse Ii-om the Commission if continued c~eration would be unsafe or would threaten contamination of freshwater z < < .~-~. ~"'~"'~ *' " ~ ' '' t ' °~ Until~corrective action is successfully completed, Aa monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating pressure communication or leakage. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above 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 fluid movement outside of the authorized injection zone. <[Fwd: Re: [Fwd: AOGCC Proposed WI Lang for Injectors]] LJ Subiect: [Fwd: Re: [Fwd: AOGCC Proposed WI Language for Injectors]] From: Winton Hubert <winton aubert@admin.state.ak.us> Date: Thu, Z8 Oct 2004 09:48:53 -0800 Ta Jody J Colombie <jody calombe@admin.state.ak:us> This is part of the record for the Nov. 4 hearing. WGA -------- Original Message -------- Subject: Re: [Fwd: AOGCC Proposed WI Language for Injectors] Date: Thu, 28 Oct 2004 09:41:55 -0800 From: James Regg <jim regg@admin.state.ak.us> Organization: State of Alaska To: Winton Hubert <winton aubert@admin.state.ak.us> References: <41812422.8080604@admin.state.ak.us> These should be provided to Jody as part of public review record Jim Winton Hubert wrote: FYI. -------- Original Message -------- Subject: AOGCC Proposed WI Language for Injectors ', Date: Tue, 19 Oct 2004 13:49:33 -0800 From: Engel, Harry R <Enge1HR@BP.com> To: winton aubert@admin.state.ak.us Winton... Here are the comments we discussed. Harry *From: * NSU, ADW Well Integrity Engineer *Sent: * Friday, October 15, 2004 10:43 PM *To: * Rossberg, R Steven; Engel, Harry R; Cismoski, Doug A; NSU, ADW Well Operations Supervisor *Cc: * Mielke, Robert L.; Reeves, Donald F; Dube, Anna T; NSU, ADW Well Integrity Engineer *Subject: * AOGCC Proposed WI Language for Injectors Hi Guys. John McMullen sent this to us, it's an order proposed by the AOGCC to replace the well integrity related language in the current Area Injection Orders. Listed below are comments, not sure who is coordinating getting these in front of Winton/Jim. Overall, looks okay from an Operations perspective. We do have a few comments, but could live with the current proposed language. Note the proposed public hearing date is November 4. The following language does not reflect what the slope AOGCC inspectors are currently requiring us to do: "The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (except at least once every two years in the case of a slurry injection well), and * before* ** I 1 of 3 10/ /2 4 28 00 11.09 AM [Fwd: Re: [Fwd: AOGCC Proposed WI Lane for Injectors]] return'•_ng a well to service following a workover affecting mechanical integrity." After a workover, the slope AOGCC inspectors want the well warmed up and on stable injection, then we conduct the AOGCC witnessed MITIA. This language requires the AOGCC witnessed MITIA before starting injection, which we are doing on the rig after the tubing is run. Just trying to keep language consistent with the field practice. If "after" was substituted for "before", it would reflect current AOGCC practices. It would be helpful if the following language required reporting by the "next working day" rather than "immediately", due to weekends, holidays, etc. We like to confer with the APE and get a plan finalized, this may prevent us from doing all the investigating we like to do before talking with the AOGCC. "Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall_* immediately*_** notify the Commission" This section could use some help/wordsmithing: "A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation." Report content requirements are clear, but it's a little unclear what triggers a well to be included on this monthly report. Is it wells that have been reported to the AOGCC, are currently on-line and are going through the Administrative ', Action process? A proposed re-write would be: "All active injection wells with well integrity failure or lack of injection zone isolation shall have the following information reported monthly to the Commission: daily tubing and casing annuli pressures, daily injection rates." Requirements for the period between when a well failure is reported and when an administrative action is approved are unclear. This document states "the operator shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403". If we don't plan to do any corrective action, but to pursue an AA, does a 10-403 need to be submitted? The AOGCC has stated they don't consider an AA as "corrective action". Let me know if you have any questions. Joe -----Original Message----- From: Kleppin, Daryl J Sent: Wednesday, September 29, 2004 1:37 PM To: Townsend, Monte A; Digert, Scott A; Denis, John R (ANC); Miller, Mike E; McMullen, John C Subject: FW: Public Notices FYI -----Original Message----- From: Jody Colombie [ mailto:jody colombieQadmin.state.ak.us Sent: Wednesday, September 29, 2004 1:01 PM Subject: Public Notices Please find the attached Notice and Attachment for the proposed amendment of underground injection orders and the Public Notice Happy Valley #10. Jody Colombie «Mechanical Integrity proposal.ZIP» «Mechanical Integrity of Wells Notice.doc » 2 of 3 10/28/2004 11:09 AM :t:t: 0\ u.s, )VIRONMENTAL PROTECTION AC '}tv REGION 10 1200 SIXTH AVENUE SEATTLE, WASHINGTON 98101 1 0 1986 _\\"'iEO sr4l; ..:>" ~úI i ft ~ "' ~ z. -œuJ ]) " ~ "t" ~ o~ 1-): '\~ Aft. PR01~v REPLY TO MIS 409 A TTN OF: c. V. Chatterton, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 RE: Standard Alaska Production Company Aquifer Exemption Request May 16, 1986. ' Dear Mr. Chatterton: "'.;:"."i"'.'.C'.'''j'''-'';'''-'~....'.... ! C~ 0 'i,f ï\!& ¡ \' ¡ \\t( j TD \ -16fJ1 \ WJ LHn It-I ::;i Ø// ~ \ "'",~;';j;"~\ \-" :ò :';;j+~ &á \ :'..'...~......"'...'.'.;.".'...',..'i'",....'.''' ".,.'.' t~,. ".'." .. !.. \ ~'.. . ~>~) ~.. ,(.\. .~ . . ~. ~':-: \",.,) (1 ù--) -'...'.:""'.,." .". T":',.,f,'ilAA/. ---¡ / \~i\:~\ i ,:vj J L""... .-:,<I'\'f''''' Based on a July 7, 1986, telephone conversation between Lonnie Smith and Harold Scott, I understand there were no comments during the public comment period regarding the proposed exemption. Therefore, we concur with your decision to exempt the aquifers beneath the Western Operating Area of the Prudhoe Bay Unit for Class II injection activities only. This is a "non-substantial program revision" in accordance with Section 13 of our Memorandpm of Agreement. Si ncerely, q¿M~¡jJ Robert S. Burd Director, Water Division RtCt\\JtD JUL14 \986 . commlsS\on . & Gas Cons. l\\as\<a. 0\\ AncnoTage :::J:t:: U'8 \~ £0 sr"l: 0~ ~<5' ~. n ~ ~ ~~ZZ. ~ ;; ~"':''T'~ " \ ~" I ,.,' ~« «'-} ,\.p l'-il. PR01~V U ¡ENVIRONMENTAL PROTECTION, 'JNCY ?~ REGION 10 1200 SIXTH AVENUE SEATTLE, WASHINGTON 98101 JUL 0 1 1986 {'OFÌvf--I~ Cf)?"~¡\1~, (" ,"', '. .." -----..c .'" ';1 ,--- li/;,~;/c~¡- -'..:~' 'I.!. '.', , f:". -,;...~ .: . . . '- ..1..(.." '..... ,-- ~:~~~.t': .::;"~~.' ,,:,- ,,,-., ' l.... . .. T ,- l¡j-~;j-;L;;; ;,C FILE:~ .------ REPL Y TO ATTN OF: M/S 409 C. V. Chatterton, Chairman ALaska Oil and Gas Conservation Conmission 3001 Porcupine Drive Anchorage, Alaska 99501 RE: Standard Alaska Production Company Aquifer Exemption Request . ~1ay 16, 1986 Dear Mr. Chatterton: As you know, the UIC permit application submitted by the Standard Alaska Production Company (formerly Sohio Alaska Petroleum Company) to EPA on June 6, 1984, indicated there were no underground sources of drinking water (USDW's) at the Prudhoe Bay Oil Field (Western Operating Area). However, in their May 16, 1986, aquifer exemption request to AOGCC, it appears there are USDW's in the area. We will be contacting the operator for clarification as to ~hen they became aware of the existence of USDW's. We will keep you informed of our findings and any subsequent actions. In accordance with our Memorandum of Agreement, EPA has conducted a preliminary review of the aquifer exemption request. We believe that the subject aquifers qualify for an exemption. Our final concurrence/ non-concurrence with your decision will be based on the results of your detailed evaluation of the exemption request and any additional information developed through your public comment process. This action is considered to be a minor exemption and a IInonsubstantial program revision II and will not require notice in the Federal Register. Si ncerely, //~ /' -r /11f'J ~) /Z~{:Cc'¡// ¡;J--~L'~cr Robert S. Burd . Director, Water Division " c::Lv 'S ? he) /1; & f~ E eEl V E D JUt 071986 Afaska Oil & Gae; GGns. {;cIH!JIÌ:Jsi ^nc!:~rage on =+:t:: ~ J '\ Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: The application of STANDARD ALASKA PRODUCTION COMPANY for FRESHWATER AQUIFER EXEMPTION ORDER for the Western Operating Area of the Prudhoe Bay Unit. The Alaska Oil and Gas Conservation Commission has been requested, by letter of application dated May 16, 1986, to issue a freshwater aquifer exemption order for those potential fresh- water aquifer existing within the Western Operation Area of the Prudhoe Bay Unit. The data submitted with this application meets the criteria required in 20 AAC 25.440(a)(2). Parties who may be aggrieved if the referenced order is issued granting the referenced request are allowed 15 days from the date of this publication in which to file a written protest stating in detail the nature of their aggrievement and their request for a hearing. The place of filing is the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501. If such a protest and request for hearing is timely filed, a hearing on the matter will be held at the above address at 9:00 AM on July 21, 1986, in conformance with 20 AAC 25.540. If a hearing is to be held, interested parties may confirm this by calling the Commission's office, (907) 279-1433, after June 26, 1986. If no such protest is timely filed, the Commission will consider the issuance of the order without a hearing. ,'j ~ .-Þ/ ~, '-d Lonnie C. "Smith Commissioner Alaska Oil & Gas Conservation Commission Published June 13, 1986 THE ANCHORAGE TIMES p.o. BOX 40 °ROOf Of PUBLICATION ANCHORAGE, ALASKA 99510-0040 'K Oil & Gas Conservation Comm 3001 Porcupine Drive ~NCHORAGE, AK 99501 :AROLINE BRIGHT, BEING DULY SWORN, ACCORDING TO LAW DECLARES: rHAT SHE IS THE LEGAL CLERK OF THE ~NCHORAGf TIMES, A DAILY NEWSPAPER 'UBLISHED IN THE TOWN OF ANCHORAGE IN THE THIRD JUDICIAL DIVISION, STATf OF ALASKA, AND THAT THE ~OTICE Of.......................... ~ COpy OF WHICH IS HERETO ATTACHEO, ~AS PUBLISHED IN................... JF THE ANCHORAGE TIMES. ~EGINNING ON....................... ~NDING ON.......................... THE SIZE OF THIS AD WAS............ SIGNED.......... THE PRICE OF THIS AD IS............. $ AO-08"':"5564 1 ISSUES 06/13/86 06/13/86 67 LINES ~~~ 21.44 THE AD NUM8ER IS.................... 2369141 SUBSCRIBED AND SWORN TO BEFORE ME THIS................... 13 DAY OF Jun,1986 NOTARY PUBLIC OF THE STATE OF ALASKA MY COMMISSION EXPIRES..........~.... _~~1Zl~ ~cA_!.t_!_(/o t4otltê.~'~'ûbTìç)ti~~l~~ STATeOF,=A~ASKA . ' AIÇlska OllancfGo/ò'" . ...' 'ConservatIOI1<::Ô\1tml#IC)P' !. ". ":., , . , . ..:.:,~' " ",,:,.-, -' ,.,c"",, ~ :: ';1"' ',' ,.!: Re:.. The QØPllcCltloii'Qf ~SlfN'P1' ~gßtk~~~~,:~g~~'Fi~fAt W:ÁTE R AQU)' ~Ê'R'E>'<~.NI'P.~':' . '1',10/11 ORDE R,qrt~""est~rfi;' ~::{fJ~6~r~i:'9f the:pr~~' - ":,¡', -,' '.,",',"",". :':";,1'1 T . AI.aska ()iI and,.Gas <:0",,;: ser '. Cornmlsjl)n'tlasb,een I t . ,bYletf,ér"of'oppllC¡P~ . t .. MëJY16'1'1986, tol.ssqe' ter (JQI:/¡;ér.xemPfl~n:, ' -~"fho,e PO'fe"tlal'frésh~' . oqûlfer ..exlstIOSl. wIthin';.' thé W~tern °p'ratlonAreo . of th,<Pi1Icihoe' SaY'Orílt; 'Thectoto, submfftW with- tþl$, ØI?~II~.Øtl~.:..~ meets the. crlterlq.. r:'equfred~1n:A;U AAC25:4!O,(a)(;2},,;:.., ...:'.- PQrties .w'omclY bJ, a~~ grieved If. the.. refer.tÌ\c¡øø,;ord'r Is Issued grdntlrJg.thê: retet~, enced r.~uØ$:t .ar:e,.QUøw.i;1~': days.. fr.om. '...,.the.dOt.e. "O.f..i:-.f. ,;th... ).$P..U..b..(..."'...'.' cation ,In. which te; .fl,..,o':Wr.",t,., protest stotlng .1" ,~t(1U th~"na." tureOf fhelr'm,,1ev.Ment' ami. ~~:I.r .' 'f~~,~~~~:~." and ~rvattOJ1COIII'\rnls;.. , sløo,. . rcupJø'Dd~/A".", chorós;,. .. oska .'9501..1' ...,c:;h:ø protetNrnd,request for h~lrln,: Is timelY ,II", CI h.arln,onthe,t~ matter wmbehelø'Clt,tJutaÞø~": address at '. 9:00AM' '.~.' J'ullj:, 21;1" ~'1t 2~S:»~r'~~:f.~g 'r~tro~' held, Interested .POrtles.. may confirm this bY coiling the Com- mission's office, (907) 279.;1433, after June ~,1.~;lfnO such protest,'1i;ffftl."r;:t"~ tbe.-~'ii-¡ mission wlll.nsldf.r:,the Is-. $uance of the 'order::w""oqta IIearlng., ' ;.,' I , . :.: .' ' " :- . r , . . /st Lonnie C. Smith Commissioner '. Alo,koQIla,Gas ' " :i ; - ÇøriservotloR com~IS$~" I PO: AO.oa-5564 ' . , Pub:.rlun!'~, 1986 . ~ , ~".~ RECEIVED JUN 1 7 1986 Alaska OU & Gas Cons. Commission Anchorage ::t:t: w TELECOPY No. (907) 276-7542 May 21, 1986 Mr. Harold Scott, Environmentål Engineer United States Environmental Protection Agency 1200 Sixth Avenue Mail Stop #409 Seattle, WA 98101 Re: Fresh Water Aquifer Exemption Prudhoe Bay - Western Operating Area Dear Mr. Scott: Atta.ched please find Standard Alaska Production's May 16, 1986 applica.tion requesting exemption of that portion of aquifers lying directly beneath the Western Operating Area. of the Prudhoe Bay Unit for Cla.ss II injection activities only. Theapplica.tion is forwarded to you in conformance with Section 13 of our Memorandum of Agreement for your review and action. In view of your earlier action in exempting aquifers lying beneath the nearby Kuparuk River Unit, we consider the exemption request to be a non-substantial program revision. You'will recall that our regulation 20 MC 25.440{b) requires us to provide a 15 day legal notice and the opportunity for a public hearing. We do not plan to publish notice of the application until we first receive your comments. Advise should you need further information. - ----....--"'- Enclosure dlf:l.C.l1 ::ft tV t6Fr¡' r ( (" AREA INJECTION ORDER APPLICATION For Prudhoe Bay Unit Western Operating Area Enhanced Recovery Wells and Fluid Disposal Wells MAY 1986 Prepared for Alaska Oil and Gas Conservation Commission Prepared by STANDARD Alaska Production Company 01, -- ., ",-' GENERAL INFORMATION Subject: Area tnjection Order Application Prudhoe Bay Unit Western Operating Area (WOA) Submitted To: Alaska Oil and Gas Conservation Commission Facility Name and Location: ~ ~ ( I I I Standard Alaska Production company Prudhoe Bay Unit Western Operating Area (WOA) North Slope Borough, Alaska Operator Name and Mailing Address: Standard Alaska Production Company P.O. Box 196612 Anchorage, Alaska 99519-6612 ~ Technical Contact: Raymond Hanson (907) 564-5411 f r { I 1 ( RAH/hrf/5955V -1- . . May 1986 AREA INJECTION ORDER APPLICATION PRUDHOE BAY UNIT WOA Table of Contents Section Requ1atorv Cite Paqe A. Area Injection Order 20 AAC 25.460 4 Plat 20 AAC 25.402(c)(1) 20 AAC 25.252(c)(1) B. Operator/Surface owners 20 AAC 25.402(c)(2) 6 20 AAC 25.252(c)(2) C. Affidavit 20 AAC 25.402(c)(3) 7 20 AAC 25.252(c)(3) D. Description of Operation 20 AAC 25.402(c)(4) 10 E. Pool Information 20 AAC 25.402(c)(5) 12 F. Geologic Information 20 AAC 25.402(c)(6) 13 20 AAC 25.252(c)(4) G. Well Logs 20 AAC 25.402(c)(7) 21 I 20 AAC 25.252(c)(5) H. Casing Information 20 MC 25.402(c)(8) 22 . I 20 AAC 25.252(c)(6) I. Injection Fluid Composition 20 AAC 25.402(c)(9) & (10) 27 Injection Rate and Pressures 20 AAC 25.252(c)(7) & (8) ( J. Fracture Information 20 AAC 25.402(c)(11) 33 20 AAC 25.252(c)(9) I K. Formation Fluid 20 AAC 25.402(c)(12) 35 20 AAC 25.252(c)(10) ,< L. Aquifer Exemption 20 AAC 25.402(c)(13) 37 20 AAC 25.252(c)(11) M. Hydrocarbon Recovery 20 MC 25.402(c)(14) 39 N. Mechanical Integrity 20 MC 25.402(d) & (e) 40 20 MC 25.252(d) & (e) I I I ¡ -2- I [ I I I I I [ I I ( I [- ( '--.' I I 1 Section Requlatory Cite Paqe 20 MC 25.402(h) 20 MC 25.252(h) o. Wells Within Area P. Variances 42 20 MC 25.450(a) 43 Q. Addendum to Application Exhibit 1 Exhibit 2 Exhibit 3 44 Conservation Order No. 145 Prudhoe Bay Field, Prudhoe oil Pool June 1, 1977 Legal Description Prudhoe Bay Unit Effective February 22, 1986 Existing Injection Permits -3- SECTION A AREA INJECTION ORDER 20 MC 25.460 20 AAC 25.402(c)(1) 20 MC 25.252(c)(1) f [ I I I I r [ [ I Standard Alaska Production Company (SAPC), as operator of the Prudhoe Bay Unit Western Operation Area (WOA), requests issuance of an Area Injection Order to provide authorization for utilizing service wells permitted in accordance with 20 MC 25.005 or 20 MC 25.280 to inject fluids underground for purposes of enhancing oil recovery from the Prudhoe oil Pool as defined by Conservation Order i145 and disposal of non-hazardous oil field fluids into Cretaceous and Tertiary strata. Conservation Order t145 is attached as Exhibit 1 in Section Q. Area of Review: The Area of Review will encompass all lands with facilities operated by SAPC within the boundary of the Prudhoe Bay Unit which includes the WOA and the area around K Pad. The Unit boundary and the area operated by . SAPC are shown in Figure A-I. The Prudhoe Bay unit legal description is attached as Exhibit 2 in Section Q. The injection operations meet the requirements of 20 MC 25.460(a), Area Injection Orders, as addressed here. 1. Table A-I identifies the well types and number of wells for the WOA as of March 31 , 1986. A map showing" we 11 loca t ions is given in Section 0, Figure 0-1. The injectors are part of the same field, the WOA and K Pad Area. The WOA and K Pad will be operated by a single operator, SAPC. No hazardous waste as defined by 40 CFR 261 will be injected under 2. 3. 4. this area injection order. -4- ~ --- .- ............. --, ~ ~. .~ ~ , MILNE POtN1) ... - ... " ) BF -62/ UN IT I 39-2/355002 39-1/355001 BF 51/ 36-61343106 312814 ~ - \36-1/343101 25518 28231 414 312809 36-8/343108 66" . .. 28232 28233 28234 _43 47442 41465 41464 4146~ ... I ~ , , f . ~ / - J \ - I -. t 606 "8F-68/312829 BF-69 <f v - 606 312821 ' ~ ~. - GWYDYR BAY UNIT 8F-34/V-188 BF-35/Y-189 or. <1 F - 34623 -~ 601 \ I' r'~ ?f1:"f. 4144ð ZI!!',: e ð.4,. 2>32f13 ~7444 47468 47'4e,;> 47466 2 8'A 49 ' BF 36/V 190 , , U ",: , - .. uSS 3462 .:¡ðA - 4 4:> - ... 608 -- I r ~ .. 363~~,1) 36 34~1 4044 \, 65e 609 \ \ I, - - - .'L ' - - ~ 66~ 25':' 3~7:ITL"8 , 47447 ,18U7- I~~,n. 2816,,8 ,4,7448 4,78U, 2011S ,"1 28298 28~'¡'~,. 34624 '4621 '4626 '4625L-.:F-7;V3l,28~27" ~ 49: r ;'-;:>::',~<;., DUCK 2$2r9 I ":/"':~;:;:~ 34630 34635 3 . /",.", BF-7 .2~6~8 8239.2,'23' ,2~t~9 ,282~8 ~~2,t!i7 '.. .. ..282?B 2827'1 !829,9 '~~~~::~~:, 28301 34628 34629 - ð4633 312828 , I ' " 28282 28281 "'>:><',:,» 28302 KUP ARUK I - 28280 -:..-:' :>~,~' 256'9 28'.,1 ~~41, 18140, 47480 2UII 'U180 . UNIT -.L., I 28182 2St.. .:,.m PR U 0 HOE 25¿:.u .i:>32~3 28244 282jð ~~ 28263,1 47'4&1 282.83 28284 2828~ r , lB287 28286 '8'4. 2~ ~,,' ..~ 2.'09 ...6. 1./( ~2.248 14745. 41U.. .~.84 28288 . n 5 2!H.62 ~1~t.1~'2~ 1282~() 282" ;: 28 2 4 9 66 4 ~.4r1. 4 w£P 2 f5 6 ~ e 289 "I 74 71 4 T 4 12 28 S f3 . 1 - - -\ . , UNIT 34632 34631 28320 28338 7502 UNIT 28308 28343 I 28:340 ~I ~I I 28341 141506 147~07 318601 28307 28321 28322 28323 28339 28326 2B32~ '=«3324 I HEMI SPRIN GS "'--, 2&268 318608 .'118609 28290 474.7$ 41476 ~ - - ..- ,,>' fb "> 28330 q, 28332 28345J44 318615 318618,.- 28341 28347 318616 318620 . 28311 28329 28328 2B327 25e.~3 ~11j6(J~ -:3'8604282!)1 28267 .,. 0 I'- r<') CD C\J ::J .. 318.05 "8606 f8607 28211 28210 28269 318610 318611 318612 318613 "8.'4~ 28'~R ?"';""¡""'4 28330 28;49 365525 318611 "862. I 318646 25685 3186281 366003 13IPVAaJ~~9.28273 28212 28292 318642 28291 318645 28334A 28311 L , ~ K PAD AREA PRUDHOE SA Y UNIT AREA ~ Figure A-1 Effective: 2/22/1986 .:':'-:<'.:' '-', WOA I [ I I I Existing Permits - Separate authorization for ongoing and future WOA injection activities have been issued by the u.S. Environmental Protection Agency (Underground Injection Control Program) and the AlasKa Department of Environmental Conservation (Wastewater Disposal Permit Program). SAFC operates under permits listed in Exhibit 3 of Section Q. TABLE A-I EXISTING WELL SUMMARY* I I ( Type of Well Number of We lIs Reservoir Production 344 Permo-Triassic Waterflood 45 Permo-Triassic Injection Wells Suspended 4 Permo-Triassic Wells Abandoned 8 Permo-Triassic Observation Wells 2 Permo-Triassic West End Test Well 1 Permo-Triassic Produced Water/. 7 Cretaceous or Tertiary Sands Waste Disposal I I I I [- I 1 'I * Effective March 31, 1986 1 -5- [' . I I ¡ [ I I ( I ( t r- 1 I I 1 SECTION B OPRRATORS/sURFACE OWNERS 20 AAC 25.402(c)(2) 20 AAC 25.252(c)(2) The surface owners and Unit Operators within the Prudhoe Bay Unit WOA covered by this area inject ion order and extending 114 mile beyond the boundary (excluding Standard Alaska Production company) are listed here: 0 State of Alaska, Department of Natural Resources 0 Andrew Oenga 0 ARCO Alaska, Inc.: Unit Operator for Prudhoe Bay Unit Eastern Operating Area, Kuparuk Unit, and Hemi springs Unit 0 Conoco, Inc.: Unit Operator for the Gwydyr Bay Unit -6- See attached affidavit. [ [ I I I [ I I I, I SECTION C 20 AAC 25.402(c)(3} 20 AAC 25.252(c)(3) AFFIDAVIT -7- ( ( ¡ I I f I I I ( I I I I [- 1 1 1 I AFFIDAVIT ) ) SSe Third Judicial District) STATE OF ALASKA Raymond A. Hanson, being first duly sworn on oath, deposes and says: That I am an employee of Standard Alaska Production Company. That on the / C;; day of May, 1986, I caused to be mailed a true and correct copy of this application to the following operators and surface owners listed in Section B: Ms. Kay Brown, Director Division of Oil and Gas State of Alaska Depårtment of Natural Resources P.O. Box 7034 Ancho!age, Alaska 99510-0734 Mr. Andrew Oenga P.O.. Box 201 Barrow, Alaska 99723 Mr. Tom Fink, Manager Environmental Conservation ARCO Alaska, Inc. P.O. Box 100360 Anchorage, Alaska 99510-0360 Mr. John Kemp, Division Manager Conoco, Inc. 3201 C Street, Suite 200 Anchorage, Alaska 99503 -8- by placing said copy in the United States Mail with postage prepaid and I ! I I certified at Anchorage, Alaska. ~-ß/~ Raymond A. Hanson SUBSCRIBED AND SWORN to before me this / /:; day of May, 1986. ~ ~ " ~j{q~7h '~r~ Notary Public in and for Älaska My commission Expires: o/tji7 I 1 I I I [ I [- I 1 t 1 -9- ( SECTION D DESCRIPTION OF OPERATION 20 AAC 25.402(c)(4) CUrrent and proposed injection operations in the Western operating Area (WOA) are divided into two broad categories: enhanced recovery and fluid disposal. I ( 1 I [ Ie Enhanced recovery injection wells are used for the introduction of displacing fluids into the oil reservoir to increase the ultimate recovery of oil. Currently, water injection is the only method of enhanced recovery in use in the WOA. Waterflood operations for enhanced oil recovery utilize two water"' injection systems. The primary system is injection of Beaufort Sea water called source water through a network of filters, piping, injection pumps, and manifolding. The secondary water injection system consists of the réinjection of produced formation water. Future types of enhanced recovery injection will include miscible gas (water-alternating-gas) injection and produced gas injection. Existing water injection wells and future injection wells will continue to be designed, constructed, operated, and monitored to ensure the injection fluid is entering the oil pool. Enhanced oil recovery methods are/will be confined to the Permo-Triassic age formations. [~ Fluid disposal wells are used for the disposal of produced water and other fluids generated during WOA operations. Produced water is formation and/or waterflood water which is produced with the oil and gas and is subsequent ly separated from the oil and gas at the Gathering Centers. The remaining injection fluids are non-hazardous fluids generated by WOA operations. Fluid disposal is into the Tertiary and Cretaceous strata. Gathering Centers 1, 2, and 3 have fluid disposal wells. Existing and future fluid disposal wells will continue to be designed, constructed, operated, and monitored to ensure the injected fluid is entering/confined to the injection zone. l ¡, 1 -10- Miscible gas and water-alternating-gas injection are summarized in the Prudhoe Bay Miscible Gas Project certification document submit ted to the Alaska oil and Gas Conservation commission in December, 1983. Produced gas injection is currently planned for the West End, with operations similar to gas injecti.on in the Main Area. I [ [ I [- ! { 1 I -11- ( SECTION E POOL INFORMATION 20 AAC 25.402(c)(5) I I ¡ I I I ( [ I [- [ I I I The strata affected by injection for enhanced recovery from the Prudhoe oil Pool are defined by Rule 1 of Conservation Order No. 145 as the strata that are common to and correlate with the accumulation found in the Atlantic Richfield-Humble Prudhoe Bay State No. I Well between the depths of 8,110 and 8,680 feet, M.D. The strata affected by injection for waste disposal via the fluid disposal wells are defined as the Tertiary and Cretaceous sands that are common to and correlate with the sand zones found in the Sohio Well C-ll between depths of 3,924 and 5,969 feet subsea (see Figure F-2). -12- ( SECTION F GEOLOGIC INFORMATION 20 MC 25.402(c)(6) 20 MC 25.252(c)(4) ¡ [ I ( I I I I [- I 1 I This section describes the PBU WOA geology of injection zones and confining zones for the Prudhoe oil Pool and then for the Cretaceous and Tertiary Formations. A. Prudhoe Oil Pool Injection Interval - Permo-Triassic 1. Stratigraphy The Prudhoe Bay oil Pool is contained within several Permo-Triassic age formations. The Permo-Triassic formations from oldest to youngest are the Sadlerochit Group (made up of the Echooka Formation, the Kayik Shale and the Ivishak Formation), the Eileen Formation, the Shublik Formation, and the Sag River Formation. This stratigraphic sequence is shown in figure F-1. The major reservoir of the Prudhoe Bay Oil Pool is the Ivishak Formation with minor reservoirs in the Eileen Formation, Shublik Fonnation and the Sag River Formation. Present and proposed injection for Enhanced Recovery of the Prudhoe Bay Oil Pool occurs in the 'Ivishak Formation. Confining zones for the injection are the Kavik Shale at the base and the Jurassic age Kingak Shale at the top. 2. Major Reservoir The Permo-Triassic Ivishak Formation is 550 to 600 feet thick; the formation top is located 8300 to 9300 feet subsèa across the WOA. The Ivishak reservoir is divided into four zones (1-4) based on petrophysical parameters derived from lithologic and log data (see Figure F-1). .Zones 4, 3, and 2 are the primary injection zones within the WOA. Zone 4, the uppermost interval within the Ivishak Formation is characterized as a gradually fining upward sequence of fine to medium grained sandstone f~ \ -13- GENERALIZED STRATIGRAPHIC BECTlaN AND REF.RENCE LOG PERMD TRIASSIC RESERVDIRS - PRUDHDE BA V FIELD THK. AGe NAME < imtOl.óoY' . ¡:~:¡:~:~:¡:::¡:¡~:¡:¡::~:::::::::t( a GUB IK F M. .~:..::=.. ~. . : .' <: : '" ,,~..~ . ..". 0 - . ~ ... -e'- -.8-:~. ~--:-- .. -:--"". ,~,;--o' SAGAVANIRKTOK ':;=....-:...~-' '" FM .o-:-:-~'. '°. .. . ",. t~':~:.~" "' ""-00;.-'" ......' , UGNU FM. ,.....:.;::-..:~- " ;.(...,.:..i:.::~== COL VILLE WEST s~ GP. . . : T 'If . : 8300' < , ." ...... : "- .~":.:.~~-~ " ------ - -- - -- ------ ------ ------ ------ ------ --- - -- :=:~======= uK ------ ------ I .... '''''~ liT: ... ... : HIGHl Y RADIOACTIVE ZONE z 7751 I K KUPARUK RIVER ,.~. 0 ,......... u .'1 LOWER CAeTACeOU$ $HALE UNIT N: : J KINGAK FM. u -M-300-~~ f SAG RIV. FM." '.. . .., '. ". '. ~ ==;:==:==~, R SHUBLIK FM'I£üENA8!.~-'~'- ~- ';' c::( - - - - - - " - .-. 0" .- - - - . .. . ... ... .. i¥ ~~¡ä;~~ ~ SADlEROCHIT IVISHAK ~~. r:8I8.::,:..:. ,.e,,:.:',: ~ ;::::::::~::::~::::::?:~:::::::::::;:;: p" GP. K A V~~ H~t;Í ~:-:-:- < . 0 1"',,1.111\11.1 ~ . I."...J "II} ~ 1;1 . ac:: fP ";1 t J \ \.: ~ LtSBURNE GP. '~~i",(. ':: :;: '" ... . . . -. ... . . " :.;:! t. ~'\~ *na.1ñI .. 3000' + " M " ENDICOTT GP. 0 OLDER ITKK. Y ARIAK FM. KAYAK FM KEKIKTUK FW. BASEMENT CONFINI~G ZONE I NJ EC TlON ZONE !~~~~i~~~I~@~~~~I~I~~~~~~~I~Ii;~~¡I¡I~f~~l - - -- --. - - . ------- ------. ------- w z 0 N Z 0 - - - G- °- c- - - - - - - - - t- o W .., Z 0 - 0 0 c - a: t¡- o ~ a: w A. GR '" y " . L- ~ AReo - HUMBLE 0'9-11-13 SSD ~T .LD ~g -~ oJ 0 , - -0 0 -It) _ex:> -0 _0 co -ex:> -0 ~ -ex:> -0 0 -0) -co I ~ C> -0 - _o_~r¿__~_- AVERAGE ZONAL PROPERTIES ZONE. H = 175' (=150-300MD, - - ø= 22-25 ZONE 3 H=60' 1<=800- 1500+ P=10-12 ZONE 2 ~D H=230' 1<=200-500+ ø= 22-25 ZONE 1 H=120' - - - - K= 50-150MD ø= 15-?0 ~I~I Inr:: r:: - .. interbedded with thin, tight 5il tstone and shale. Bedding is typically massive, although occasional cross _and ripple laminatt~ns are present as are minor pebble-lag conglomerates. composition is dominated by quartz, I ¡ I I I ( ( I [ I ( ( I I I - dense chert and microporous chert. Cements in decreasing order of abundance include silica, siderite, ferroan-calcite, and pyrite. Zone 4 thickness varies from 150 to 200 feet within the WOA. Average porosity is about 23\ and average permeability is about 225 mill idarcies (md). The .depositional environment is interpreted to be fluvial. Zone 3 is made up of conglomerates and conglomeratic sandstones which are composed of dense chert, quartz and quartzite rock fragments. The zone is poorly sorted with clasts comprising a framework that is ~nfilled by sand. Pyrite occurs as a major cement, commonly occluding porosity. Zone 3 averages about 60 feet thick with an average porosity of 16\ and an average permeability of 800 md. This zone is interpreted to be deposited by a series of braided, fluvial channel systems. Zone 2 is composed of sandstones and conglomeratic sandstones and lesser amounts of conglomerates. Interbedded mudstones and siltstones occur locally. Quartz and chert make up the bulk of the sand-sized grain composition. Cements in decreasing order of abundance are silica~ siderite, pyrite, and ferroan-calcite. Zone 2 thickness 'averages about 230 feet. Zone 2. sandstones coounonly average about 23% porosity and have permeabilities in the 300 to 500 md range. The depositional environment is interpreted as being dominated by braided fluvial systems alternating with abandoned channel/flood plain and lacustrine deposits. Zone 1, the lowermost zone within the Ivishak Formation, is comprised of interbedded, often carbonaceous, shales, siltstones and well sorted very fine to fine grained sandstones. Zone 1 coarsens upward and represents, the transition from prodelta to delta front/delta plain depositional environments. Quartz, dense chert, and microporous chert are the major mineral components. Cements include silica and siderite. Porosities can average as high as 20 to 22% with permeabilities as high as 200 md. Zone 1 average thickness is 120 feet. -14- ( 3. Minor Reservoirs [ [ I [ I [ [ [ (, [ I I I I The Eileen Formation (present only west of a NW line through Mobil/Phillips/Chevron Kuparuk Well 24-11-12) overlies the Ivishak Formation and is composed of very fine to fine grained sandstones, siltstones and shale. Eileen sands are well sorted, with porosities ranging from 5 to 20\ and with permeabilities generally averaging less than 1.0 md. The formation reaches a maximum thic~ness of 40 feet along the western boundary of the PBU and gradually thins eastwards to 0 feet within the WOA. The Shublik Formation unconformably overlies the Ivishak Sandstone (in the absence of the Eileen Formation). The Shublik is characterized by variable lithology and has been divided into five members. In general, it consists of interbedded bioclastic sandy limestones, "tight" limestones with interbedded calcareous mudstones, and calcareous siltstones. The formation thickness averages 80 feet in the WOA. porosities typically average less than 5\ with permeabilities averaging less than 1.0 md. The Sag River Formation is a sandstone lying between the younger Jurassic Kingak Shale and the shales and limestone of the Triassic Shublik . Formation below. The sands are well sorted, fine grained, composed predominantly of quartz with variable amounts of glauconite - and chert. Both siderite and calcite cements are present. Typically the Sag River is approximately 35 feet thick with average porosity and permeability of 20\ and less than 100 md respectively. 4. Confining Zones The confining zone at the base of the Permo-Triassic reservoir is the Kavik Shale. The Kavik is greater than 100 feet in thickness over the area and gradually thickens to the south. It is Late Permian in age and consists of fairly uniform, medium to dark gray, silty shales which are pyritic, non-calcareous, and micaceous. There is virtually no porosity and permeability associated with this formation. -15- The upper confining zone is the Jurassic Kingak Shale. Thickness of the Kingak Shale is 1400 feet in the westernmost portion of the WOA. and decreases in thickness to the east as the sediments are progressively truncated by the Prudhoe Bay Unconformity. The Kingak Shale is best described as an interbedded sequence of marine argillaceous siltstones and shales. This interval has very low porosity and permeability. I [ [ [ [ ( [ I Leak-off tests in the Kingak Shale (Wells E-l, E-2, and D-6) confirm the confining nature of the shale. Gradients determined from these leak-off tests were .14, .80, and .19 psi/ft respectively. Leak-off test data is significant in that the fracture gradient would be somewhat higher than the gradient necessary to achieve leàk off. . From this data it appears that the fracture gradient necessary to create and extend a fracture in the Kingak Shale would be significantly higher than the matri.x fracture gradient in the Sadlerochit injection interval. 5. Formation Water Salinities Laboratory analyses of formation water salinities produced from the Ivishak sandstones indicate an average salinity of 18,500 ppm. NaCl equivalent and a total dissolved solids (TDS) content slightly in excess of 20,000 ppm (Jones and Speers, 1916).. 6. References Additional geologic information can be found in Standard' s Underground Injection Control Permit Application, Form 4, Attachment G, submitted to the U. S. Environmental Protection Agency June 6, 1984. i' I I Jones, H.P. and Speers, R.G. (1916) Permo-Triassic Reservoirs of Prudhoe Bay Field, North Slope, Alaska, in North American Oil and Gas Fields, AAPG Mem. .24, p.23-50. [ ( ( I -16- ( B. Cretaceous and Tertiary Injection Intervals [ I I I I I 1. Stratigraphy In the PBU area, the Cretaceous and Tertiary sequence refers to a clastic sequence that lies at depths from 2000 to 1000 feet subsea. The Cretaceous sequence is divided into 3 formations within the Colville Oroup. From oldest to younges,t they are the Seabee, West Sak and Ugnu formations. The Tertiary section, which conformably overlies the Ugnu Formation, is called the Sagavanirktok Formation. A generalized type log is illustrated in Figure F-2. Cross-sections depicting regional trends in sand body distribution and variability are provided in Figures F-3and F-4 inserted at the back of this document. 2. Injection Zones ~ I The top injection interval is the basal sand sequence in the Sagavanirktok Formation (see Figures F-2, F-3, and F-4). This basal sand interval is typically 10 to 100 feet thick and the upper contact varies between 2800 and 4300 feet subsea. Lithologically this sequence is composed of medium grained sandstone deposited between thick shale sequences. The vertical permeability is minimal due to these surrounding thick shales. Log analysis indicates that the average porosity of the basal sand is 30% and permeability is 250 md. ( [ , F The Upper Cretaceous Ugnu Formation underlies the Sagavanirktok Formation (see Figure F-2). The top of the Ugnu formation' occurs at 3000 to 4100 feet subsea across the WOA. The UgnuFormation is probably equivalent to the Prince Creek Formation of the U.S.O.S. and has an average thickness of about 1100 feet. This unit forms a transgressive sequence from marginal marine to meandering stream deposition overlain by aminör regressive ( ( ( ( ( sequence. Lithologically the Ugnu is composed of poorly sorted friable quartz-rich sandstone, pebbly sandstone to conglomerate and coal with tight interbeds of siltstone and shale. Non-porous sandstone units are cemented with silica, siderite and pyrite. Core analysis indicates that -17- Age "I' w z 0 N C) Z ~ Z "- U. CCS z .- 0 ...- U "- (]) I- U) ::J 0 Q) () CCS ...- (]) "- 0 SOHIO PBU C-11 19-T11N-R14E . Formation SUB-SEA ~tLl!-Q..~; .. ar~'" .., ~". , GR Sagavanirktok UJ Z 0 N Z Q ... 0 UJ , Z ~ _.~ ..=.r 'it= ~ -- :w , .:-..r ~ t t Ugnu - sooo - 5200 . - 5«00 West Sak ,- '----'- :-- 'l' ===--- . - 5600 =- såoo ,V ,~: . "",,,,,.....IIIIIIUUIUUUUIIIIII UI IIUUIIUIIUUlliih""."4 ""'.~"'W' 'lé1h. 111111111" , - 6200 :-- . .. . f""< UJ ~ - #'-. Z . -. :. 6«00 I 2 '.- \.: ) C) ~ 6600 ' . z S b. . ~ - ea ee - - : ~ ~ ~:~ :':: . ~ n .. ..-' -~ u -~ . .. ~-- ,=~~ ~ --~~ , ~.. ---"'Il1IIIIo.: v Pebble Shale TYPE LOG FOR. '. 'CRE,. ACEOUS/TERTI.ARY INTERVALS 'WELL PBU C-1 f . . - :FIGÙRE F~2 t the porosity varies from 28 to 40% and the permeability from 700 to 1200 md. r [ [ ( [ ( ( ( [ [ The top of the Ugnu Formation is picked petrophysically at a continuous coal bed above the uppermost major (greater than 50 feet) sand sequence with a blocky .Spontaneous Potential (Sp) and Garmna Ray (GR) curve shape. The net sand for the Ugnu in the Prudhoe Bay area is approximately 500 feet. Individual sand bodies are "shoestring" shaped, long and thin fluvial deposits separated by non-permeable shales. Core plug analysis indicates that the vertical permeability is 60\ less than the horizontal permeability. The water salinity derived by SP method is 17,000 to 45,000 ppm NaCl equivalent. In the M, N, and S drillpad regions minor water washed and bacterially degraded oil is present. Individual oil accumulations in the M, N, and S drillpad regions have variable oit-water contacts, indicating that the shales between sand bodies form good confining zones. Below the Ugnu Formation lies the Cretaceous West Sak Formation shown between 5500 and 5950 feet. subsea in Sohio Well C-ll (see Figure F-2). The West Sak is age equivalent to the Schrader Bluff Formation (U.S.G.S. nomenclature). This formation is a 350 to 600 feet thick, fine to medium grained sandstone. Most of the sand is very friable due to the lack of intergranular cement, -though carbonate cemented low permeable streaks are [ I ( I present. Core analysis indicates that the sand bodies have 22 to 30% porosity and less than 400 md permeability. The water salinity derived by SP method is 33,000 to 44,100 ppín NaCl equivalent. The West Sak was deposited in a deltaic environment resulting in 3 to 5 sand packets defined petrophysically by funnel shaped SP and GR curves. The funnel shape is indicative of coarsening upward sequences. The upper boundary between the West Sak and Ugnu is defined as the change from fining upward sequences of the Ugnu to coarsening upward sequences of the West Sake The lower contact of the West Sak Formation is defined petrophysically as the base of the oldest/deepest funnel shaped SP and GR curves (see Figures F-3 and F-4). Individual sand bodies, which are often shaley, are confined by shale beds above and below. , -18- 3. Confining Zones I I ¡ I ¡ ( ( ( ( [ [ [ I I The confining zones isolating Tertiary and Cretaceous injection intervals are the sagavanirktok and Seabee formations. The Sagavanirktok Formation above its basal sand sequence forms the upper confining zone to Tertiary injection. This upper confining zone is approximately 2000 feet thick and typically occurs between 2000 to 4300 feet subsea in the WOA (see Figures F-2, F-3 and F-4). The Sagavanirktok. sediments reflect several transgressive and regressive cycles. Depositional environments of sagavanirktok sediment vary from marine to deltaic. The rocks are composed of shale, siltstone and medium grained sandstone. Thin bentonite beds. are sometimes present. Individual sand bodies defined using SP curves are correlatable between wells. Vertical permeability is limited/non-existent due to the thick shale sequences between sand bodies. The top of the sagavanirktok Formation is defined by the unconformable contact with overlying conglomerates. The basal contact of the confining zone is the base of the next to the last clean sand sequence with a blocky to funnel shaped SP curve that overlies the coal bearing, fluvial dominated Ugnu Formation. The lower confining interval to Cretaceous injectioñ horizons is the thick . Seabee Formation shale (see Figure F-2). The Seabee is 1100 to 2800 feet thick and buried to depths of 5,000 to 6,000 feet subsea across the WOA. Lithologically this formation consists of marine shales and siltstones with minor very fine sandstone beds of probable turbidite origin. These deposits represent a deep marine basin filling period.. The rare, thin sand bodies are clay-rich indicating low porosity and permeability, measured core porosities range from 6 to 26\. Each sand body is encased by surrounding silts and shales. Petrophysically the Seabee top is defined as the base of the West Sak Formation, or the lowest/deepe~t Upper Cretaceous coarsening upward sand. The formation base is the top of the "~ebble Shale" of Lower Cretaceous age. The "Pebble Shale" (also known as high radioactivity zone - HRZ) has a two fold increase in GR response over the GR values of the Seabee silts and shales. This rise in GR marks the contact at the base of the Seabee Formation. -19- ( 4. Formation Water Salinities For the PBU WOA, Cretaceous and Tertiary formation water salinitie~ have been calculated using well log data and also analyzed using water samples. OVer the entire Cretaceous interval, petrophysically. derived sal inities (NaCl equivalents) range from 17,000 to 45,000 ppm NaCl using the SP method. Cretaceous water analysis,. for zones sampled, range from 36,800 to 44,100 ppm total dissolved solids (TDS). See Note 1 below. In the Tertiary interval, petrophysically derived salinities (NaCl equivalents) range from 7,000 to 24,000 ppm NaCl using the SP method. Cretaceous water analysis, for zones sampled, range from 9,900 to 11,100 ppm TDS. I I ( [ 1 ( I ! Tertiary water salinities less than 10,000 ppm NaCl (ranging from 1,000 to 10,000) are generally located west of GC-2 in the western half of the PBU WOA. Areas east of GC-2 have formation water salinities greater than 10,000 ppm TDS. A fresh water aquifer exemptions is requested in Section L. 5. References More information pertaining to salinity data and measurement techniques is provided in Standard's ure application, Form 4, Attachment E. NOTE 1: At the concentrations found, mg/l and ppm may be used interchangeably. r \ -20- ( SECTION G WELL LOGS 20 AAC 25.402(c)(7) 20 AAC 25.252(c)(5) All open hole logs from WOA wells are sent to the Commission as the logs are completed. r [ I [ [ ( [ [ I , I I -21- ( t, SECTION H CASING INFORMATION [ ¡ I I I I I ( [ I I I I I I I 20 AAC 25.402(c)(8) 20 AAC 25.252(c)(6) Standard Alaska Production Company Prudhoe Bay unit injection wells are cased as shown in Figure H-I- Those few wells whose casing programs vary slightly from the Figure H-l design comply with 20 MC 25.252, 25.402, and 25.412. Those casing designs are on file with the AOGCC in the form of Completion Reports and Sundry Notices. A complete list of wells varying from the Figure I design and their API numbers, "Completion Report filing dates, and Sundry Notice filing dates are also included. All newly completed injection wells will be cased, cemented, and tested in accordance with 20 AAC 25.252. In addition, the casing design is submitted for approval as required under 20 AAC 25.005 (Form 10-401) on the drilling permit application. -22- ----------t---,--- ÇJ -"-.--..-.-- ,__._- .----- - :0: GROUND LEVEL I [ [ [ I [ ( ( ( I [ I I ' [ CONDUCTOR L (i) 110' ~ SURFACE CASING L. @ Z'80' ~ I TESTE.D INTE~NALLY ; TO ~OOO P.s i i PRODUCTION TUBN~ : AND PACI::EIt., T£S TED !TO .3500 P6i I> // // / INréRHéDIATE ' J CASING /0 I MD --17- L ABove TOP OF . ~SAG RIVER FORMATION j rEsTED INTEP.NALJ.t Tf) .3000~¡- ,PRODUCTION LINêR (š) . /50 FT. BELOW ORIGINAL ~ L OIL.-WATSR CONTACT IN SADLEROCHIT J:"ORMATloAl. LAP AND INTSRNAL.. TEsrED ¡ TO 3000' p.sj I .- ( vi £1. LHEAD :0: // / / / ~ ~. --_...._. .... ~_._--- ~ ~ Figure H-l I --¡ { INJECTION WELLS WITH CASING DESIGNS VARYING FROM FIGURE I SCHEMATIC I I I I I ( ( ( ( ( ( I I I INJECTION TYPE: Produced/Source Water WELL NAME & NUMBER H-10 M-1 M-3 M-2 5-9 API NUMBER 50-029-20487 50-029-20042 50-029-20102 50-029-20101 50-029-20771 COMPLETION REPORT DATE 9-22-80 9-29-69 6-1-71 8-16-71 -2-7-84 SUNDRY NOTICE DATES 9-22-81 3-13-70 8-25-71 4-4-79 6-25-84 4-2-82 4-14-70 10-6-7.1 10-26-79 7-23-83 6-24-81 4-21-70 7-1-75 1-4-80 8-2-84 12-5-85 5-26-70 8-5-75 3-23-80 9-10-84 1-8-86 6-5-70 10-14-75 3-26-80 10-11-84 1-14-86 7-17-70 8-11-76 3-22-84 9-6-85 1-9-86 7-27-71 10-18-76 6-8-84 11-12-85 2-27-86 6-30-72 5-24-77 7-20-84 3-25-86 8-4-72 11-16-77 7-26-84 4-4-79 6-25-84 10-11-84 5-17-84 7-31-84 8-13-85 6-21-84 1-7-86 1-7-86 7-25-84 8-2-84 9-13-84 10-4-84 -23- INJECTION TYPE: WELL NAME & NUMBER API NUMBER COMPLETION REPORT DATE SUNDRY NOTICE DATES I I I [ [ [ [ I. I I I I Produced/Source Water T-7 N-8 A-3 A-8 50-029-20733 50-029-20143 50-029-20113 50-029-20132 8-13-82 8-20-74 2-28-72 5-29-74 11-8-83 8-23-76 10-14-77 8-16-77 12-23-85 5-05-77 12-29-77 9-8-77 7-1-77 7-13-78 9-27-77 7-25-77 3-8-78 2-3-78 6-13-78 3-15-78 3-8-78 6-25-84 3-27-85 4-27-81 7-31-84 4-27-85 5-11-81 2-6-85 6-19-85 5-7-81 11-15-85 9-18-85 4-27-85 12-10-85 7-3-85 2-21-86 7-3-85 8-21-85 9-8-85 -24- ¡( WELL NAME & NUMBER INJECTION TYPE: Waste Water GC-1A GC-1C GC-2B API NUMBER I I I I I I I: I I I I I I I I 1 COMPLETION REPORT DATE SUNDRY NOTICE DATES GC-2A 50-029-20185 50-029-20790 50-029-20167 50-029-20168 2-6-76 9-17-82 11-26-75 1-8-76 8-25"-82 12-11-84 2-18-76 2-18-76 2-12-85 1-16-78 2-21-78 3-1-78 2-18-78 7-12-78 3-8-78 8-17-78 10-23-78 10-3-78 7-26-79 10-5-79 -25- ( WELL NAME & NUMBER INJECTION TYPE: Waste Water GC-3A API NUMBER COMPLETION REPORT DATE SUNDRY NOTICE DATES I [ I I I I I I I I I I I 50-029-20302 6-1-78 10-17-78 7-25-79 9-6-79 9-13-79 7-29-80 GC-3C 50-029-20308 7-20-78 3-28-79 6-12-79 6-21-79 7-25-79 9-6-79 9-20-79 3-26-80 4-23-80 4-29-80 -26- ( GC-3D 50-029-20309 7-24-78 6-12-79 6-12-79 7-25-79 9-6-79 9-20-79 7-29-80 8-27-80 8-30-80 SECTION I INJECTION FLUID COMPOSITION INJECTION RATE AND PRESSURE I I I I I [ [ [ [ l [ I I I I 20 AAC 25.402(c)(9)&(10) 20 AAC 25.252(c)(7)&(8) This section provides injection fluid' properties and injection rate and pressure information. Table 1-1 contains the proposed operating parameters for each type of injection well including injection rate and pressure. The injection fluid properties are discussed first for enhanced recovery fluid (water, miscible gas, and produced gas) and then for fluid disposal (produced water and other production waste fluids). Enhanced Recovery Fluids 1. Type of Fluid - Water A. Analysis of Composition of Fluid The composition of Beaufort Sea water (source water) and produced Sadlerochit water is summarized in Table 1-2. B. Source of Fluid The primary source of injection fluid is filtered Beaufort Sea water handled through the Seawater Treatment Plant. In addition to this, water that is and will continue to be produced from Sadlerochit producing wells will be reinjected into the oil reservoir. -27- ( ¡ ! I ¡ I I I ( ( ( I I I I I TABLE I-I Operating Data Waterflood Injection Miscible Gas* Iniection Produced Gas* Injection Fluid Disposal Injection Rate (per well) Range 0-40 MBWPD 0-50 MMSCFD 0-80 MMSCFD 0-40 MBPD Maximum Injection Rate 675 MBWPD 190 MMSCFD 130 MMSCFD 240 MBPD (WOA total) Injection Pressure Average 1100 psig 2700 psig 4500 psig 1800 psig Max 2700 psig 4500 psig 4600 psig 2300 psig Units M = Thousand MM = Million BPD = Barrels per day SCFD = Standard cubic feet per day * Future Projects -28- TABLE 1-2 Water flood Water Quality The waterflood process will utilize source water (seawater) and produced water. Typical composition of both water types is presented here. 0 Source Water Analysis Sodium 10800 - 11100 MOIL Iron 0 Barium 0 Calcium 341 - 373 MOIL Magnesium 1160 - 1260 MGIL Chloride 18800 - 19400 MOIL Hydrocarbonate 142 - 149 MOIL Carbonate 0 Sulfate 2580 - 2640 MOIL Dissolved Solids 3.5 WT Percent Suspended Solids 1.0 PPM W (Max.) Nitrogen 17.0 PPM W Carbon Dioxide 156 PPM W (Max.) Dissolved Oxygen .02 PPM W I ¡ [ [ [, [ [ [ I 1 I 0 Produced Water Analysis Sodium Iron Barium Calcium Magnesium Chloride Sulfate Sulfide Dissolved Solids Suspended Solids Carbon Dioxide Dissolved Oxygen Total Alkalinity pH Crude Oil In Water Total Oil & Grease 0 Water Treatment Additives 7400 6 .1 162 38 11000 61 2.2 22600 5.7 871 .26 1600 6.7 178 87 PPM PPM PPM PPM PPM PPM PPM MOIL PPM MOIL PPM PPM MOIL PPM MOIL Water treatment additives include biocide, corrosion inhibitors, scale inhibitors, oxygen scavengers, and antifoam agents. A coagulant is also added upstream of the seawater filtration equipment. -29- ( C. Compatibility with Formation and Confining Zones Water sensitivity tests on core samples showed no significant problems with formation plugging or clay swelling over the anticipated operating range of salinities fQr produced and Beaufort Sea water. 2. Type of Fluid - Miscible Gas ! I I I I [ ( I I- I I I I I A. Analysis of Composition of Fluid The composition of the injectant is expected to be similar to that described in Table 1-3. B. Source of Fluid The Central Gas Facility (CGF) will be operational in early 1987 and will be responsible for the supply and composition of miscible gas for the miscible project. C. Compatibility with Formation and Confining Zones Full compatibility- reinjected into producing zone. 3. Type of Fluid - Produced Gas A. Analysis of COmposition of Fluid Composition of the injected gas will be similar to that described in Table 1-4. B. Source of Flu.id Sadlerochit and Sag River reservoirs. -30- I I I I [ I [ [ ( [ ( ( I I (' ( C. Compatibility with Formation and Confining Zones Full compatibility - reinjected into producing zone. TABLE I-3 Prudhoe Bay Miscible Gas Project Expected Injectant Composition Component Mole \ Nitrogen Carbon Dioxide Methane Ethane Propane I-Butane N-Butane I-Pentane N-pentane Hexane Heptane OCtane Nonane 0.01 21.60 23.50 24.03 28.43 1.22 1.19 0.01 0.01 Trace Trace 100.00 -31- .. . TABLE 1-4 ( Gas Composition West End Gas Injection Component Nitrogen Water Carbon Dioxide Hydrogen Sulfide Methane Ethane Propane I-Butane N-Butane I-Pentane N-Pentane Hexane Heptane Octane Nonane Flui.d Di.sposal 1. Type and Source Mole ,. 0.47 2 ppmw 12.66 0.02 74.58 6.25 3.34 0.49 1.08 0.20 0.54 0.19 0.14 0.03 0.01 100.00 The injection fluid for disposal is predominately produced water with some development and production related waste flutds. The injection stream could include drilling mud, reserve pit water, contaminated crude, diesel gel, glycol, domestic waste water and workover fluids. Only WOA generated non-hazardous fluids are injected. ! ! [ [ I I -32- I I ( I ( [ [ ( I I, I SECTION J FRACTURE INFORMATION 20 AAC 25.402(c)(ll) 20 AAC 25.252(c)(9) The proposed maximum injection pressure for the enhanced recovery and fluid disposal wells will not initiate fractures in the confining s~rata which might enable the injection or formation fluid to enter adjacent zones. Enhanced Recovery The Ivishak Sandstone has a fracture gradient of 0.52 to 0.65 psi/ft depending on . fluid temperature or reservoir pressure. A fracture gradient of 0.54 psi/ft corresponds to a bottom hole injection fracture pressure of 4750 psig. Surface injection pressure into the Ivishak has been at 1100 psig on the average with a maximum projected pressure of 2700 psig. Since start-up of waterflooding in the WOA, a substantial quantity of surveillance data has been collected and reported regularly to the AOGCC. Such data has included, but not been limited to injection profiles, temperature surveys, and injectivity index monitoring. In addition, step rate tests have been conducted on select wells to further investigate induced fracturing. All of the information gathered to date has verified that fractures initiated as a result of water injection have not extended outside of the injection zone. Therefore, the present and proposed water injection has been demonstrated to not cause fracturing in the Kavik and Kingak confining zones which have higher fracture gradients. Fluid Disposal Injection zones for waste fluid disposal may exhibit some hydraulic fracturing around the wellbore because of the nature of the waste fluids and the potential for high solids content. Two step-rate pressure tests have been -33- .. . (' conducted on the Cretaceous and Tertiary injection intervals. At Well GC-28, the step-rate pressure test of the basal sand in the Tertiary Sagavanirktok Formation was unsuccessful due to the high permeability of the sand. At Well GC-2A, the step-rate pressure test of a Cretaceous Ugnu Formation sand was found to have. a fracture gradient of 0.67 psi/ft. giving a fracturing presstlre of 3470 psi. Fluid disposal pressures average 1800 psig with a maximum of 2300 psig. Therefore, the liquid should not fracture the injection zones away from the borehole and will not fracture the confining zones which have a higher fracture gradient than the sands. I I I ( I [ I I I I ~ I -34- . SECTION K FORMATION FLUID 20 AAC 25.402(c)(12) 20 AAC 25.252(c)(10) A water analysis for the Sadlerochit formation can be referenced in Section I, Table 1-2 of this application. [ ( [ [ A water analysis for the Colville Group and the Sagavanirktok Formation is presented in Table K-l. r ~ (f -, ( ( I ( I I -35- ( ( I I TABl.E K-l Cretaceous and Tertiary [ Formation Water Analysis Summary Log (SP) Derived ( Zone Depth Lab Analysis NaCl NaCl Well Tested* TVDss (ft) TDS (PPM) Equivalent (PPM) Equivalent (PPM) I H-2 C 5059 37,394 37,874 36,000 C 5027 37,236 37,698 GC-2B T 3514-75 11,119 11,204 13,500 I T 3514-75 10,957 T 3514-75 9,904 C 5094-5265 36,808 37,351 I C 5094-5265 38,566 37,000 GC-3A T 3775-3805 9,952 9,645 10,000 I T 3775-3805 10,369 10,039 GC-3C C 5109-39 41,078 40,396 38,000 C 5109-39 41,073 40,406 ( C 5109-39 41,078 40,383 C 5109-39 43,262 C 5109-39 43,095 I C 5109-39 43,530 C 5109-39 44,066 C . 5109-39 42,878 C 5109-39 44,199 44,741 I C 5109-39 42,846 C 5109-39 42,538 C 5109-39 43,200 ( C 5109-39 43,226 GC-3D C 5120-5205 40,400 Log Invalid ( C 5120-5205 37,964 38,495 C 5120-5205 39,583 40,146 C 5120-5205 39,001 39,485 C 5120-5205 42,215 42,744 ( C 5120-5205 40,697 C 5120-5205 39,148 C 5120-5205 40,811 ( C 5120-5205 41,022 C 5120-5205 41,741 I * T - Tertiary Sagavani.rktok Formation (basal sand) C - Cretaceous Ugnu and West Sak Formations I I -36- SECTION ~ AQUIFER EXEMPTION 20 AAC 25.402(c)(13) 20 AAC 25.252(c)(11) f I [ ( ( I [ ( ( I ( I [ [ An exemption under 20 MC 25.440 is requested for all aquifers which could potentially contain freshwater within the area of review. The regulations define freshwater as "water having a TDS concentration of less than 10,000 mg/l ... I'. As described in Section F, available information suggests that some zones of the Tertiary sands may contain aquifers with salinity between 7000 and 10,000 mg/l total dissolved solids (TDS). The aquifers contain relatively high TDS and they are situated at a depth and remote location that makes recovery of water for drinking water purposes economically impractical. These aquifers within the area of review do not currently serve as a source of drinking water and cannot reasonably be expected to supply a publ ic water system. These criteria meet the requirements for exemption under 20 MC 25.440(a)(2). Geologic Data Based on an evaluation of well log data, certain sand sequences within the WOA potentially contain freshwater aquifers with less than 10,000 mg/l TDS. variations and uncertainties in measured and derived aquifer salinities preclude definitive classification of these aquifers. The strata ex~ected to contain less than 10,000 mg/l TOS correlate with the sand zones found in the Sohio Well C-ll between measured depth of 2,000 and 4,650 feet subsea (see Figure F-2). Formation water salinities, as calculated by the spontaneous potential (sp) method, yield 7,000 to 24,000 mg/l NaCl equivalents in several of the Tertiary sands. -37- Drj.nking Water in Area Drinking water for the W01\. is obtained from surface sources, primarily Big Lake, Lake Africa, and the Kuparuk reservoirs. These readily available sources are suf.ficient to meet the fresh water needs, and there are no plans to obtain drinking water frOm underground sources for WOA operations. I I I I Ie I Due to the water quality, depth, and remot~ location of the aquifers below permafrost, recovery of water from these sands for drinking water purposes would be both economically and technologically impractical. With these limitations and the abundance of fresh water from surface sources, the underground aquifers cannot be reasonably expected to supply a public water system. [ [ 1 [ I I I I ( -38- l I I I I I I I I I I I I I 1 (' SECTION M HYDROCARBON RECOVERY 20 AAC 25.402(c)(l4) Incremental hydrocarbon recovery of 450-550 MMSTB is expected to result from WOA waterflood, miscible gas, and West End produced gas projects. -39- ( SECTION N MECHANICAL INTEGRITY [ ¡ I ¡ I I I I I ( ( I ( I, I I 20 AAC 25.402(d) & (e) 20 ,AAC 25.252(d) & (e) In newly drilled Prudhoe Bay Unit WOA injection wells, the casing is pressure tested in accordance with 20 AAC 25.030(g). If a producing well is converted to injection, the casing pressure test will be repeated in accordance with 20 AAC 25.412(c), prior to injection. Thereafter, casing-tubing annulus pressures will be monitored on a regular basis and recorded by the Production Field Crew in accordance with 20 AAC 25.402(d). All Standard Alaska Production Company injection wells in the Prudhoe Bay Unit WÇ>A will be constructed in compliance with mechanical integrity criteria as set forth in 20 AAC 25.252(d) and 25 AAC 25.402(d). 20 AAC 25.402(e) requires immediate notice to the Commission and corrective action if the casing-tubing annulus pressure subjects the casing to a hoop stress that exceeds 70 percent of the minimum yield strength of the casing, or if there is more than 200 psi change in the pressure between consecut ive pressure readings. Standard Alaska Production Company will use the 70 percent limit as the trigger for immediate notice and corrective ac.tion. By using the 70 percent yield pressure limit, the injection wells can be monitored to detect leaks and operated safely. Tubing pressure changes and temperature effects during various workover, logging, or testing operations often yield casing-tubing annulus pressure changes greatly exceeding 200 psi. These operations are necessary and occur often during prudent operations. In addition, the annular pressure is sensitive to injection pressures and fluid temperature. Thermal effects and injection rate variation will be a significant controlling factor for casing -40- ( pressure on water and gas injection wells in the WOA. The requirement to provide immediate Commission notification and initiate commission approved corrective action per 20 AAC 25.402(e) when there is 200 psi change in annulus pressure is reasonable only under steady-state injection operations, i.e. constant injection rate, temperature, and pressure. The 'regulation as written would not enable sufficient allowances for day to day operational variations. Variance from this reporting requirement is requested in Section P. i ¡ I The waste fluid disposal wells at the Gathering Centers are equipped with heated glycol circulation strings which operate on a continuous basis to prevent well bore freezing. The 200 psi change is not a viable mechanical integrity test because the casing pressure is controlled by the glycol circulating pump. The glycol circulation string fluid and fluid level are ~nitored to detect communication between the annulus and tubing. [ ( [ I I I I I I -41- ¡ ¡ ¡ I [ I I I 1 I I I I 1 1 SRCTION 0 WELLS WITHIN AREA 20 AAC 25.402(h) 20 AAC 25.252(h) ( The wells within the Prudhoe Bay Unit WOA are shown on Figure 0-1. To the best of standard Alaska production company's knowledge, the wells within the area of review were constructed, and where applicable, abandoned to prevent the movement of fluids into freshwater sources. -42- SECTION P VARIANCES ¡ I I 20 MC 25.450(a) Standard Alaska Production Company, as operator of the Prudhoe Bay Unit Western Operating Area, requests a variance from the Oil and Gas Conservation commission rules. I I ( I I I ( I ( ( I I Variances may be given, at the commission's discretion if: 0 injection is not into, through or abòve' a freshwater (less than 10,000 mg/l TDS) or nonexempt freshwater aquifer, and 0 injection does not result in an increased risk of movement of fluids into a freshwater source. An aquifer exemption for the Prudhoe Bay Unit WOA was requested in Section L. Variance to 200 psi notification and corrective action requirement: 20 MC 25.252(e) and 20 MC 25.402(e) states the following: "If the casi.ng- tubing annulus pressure subjects the casing to a hoop stress that exceeds 70 percent of the minimum yield strength of the casing, or if there is more than a 200 psi change in pressure between consecutive pressure readings, the commission must be immediately notified and commission- approved corrective action taken." Variance is requested from the portion of the requirement that applies to immediate notification and commission-approved corrective action if there is a 200 psi change between consecutive annular pressure readings. Regular monitoring of annulus pressure and pressure trends will be implemented to ensure mechanical integrity of injection wells. In addition, fluid level wi.ll be monitored in the glycol circulation system of the water disposal wells and used as an indicator of mechanical integrity. The annular pressure readings will be reported monthly on Form 10-406. The 200 psi change in annular pressures will be a regular occurrence under prudent operation pract ices. Further justification for this request is presented in section N. I -43- ( « SECTION 0 ADDENDUM TO APPLICATION I 1 I I I I I I I I ( I [ [ I I The following exhibits are provided in support of the injection order application. Exhibit 1 Conservation Order No. 145 Prudhoe Bay Field, Prudhoe Oil Pool June 1, 1911 Exhibit 2 Legal Description Prudhoe Bay Unit Effective February 22, 1986 Exhibit 3 Existing Injection Permits -44- I I I 1 I ( ( ( ( I ( ( [ I I ( EXHIBIT 1 STATE œ AL1\SKA Department of Natural Resources Division of Oil and Gas conservatíon Alaska Oil and Gas Conservation Committee 3001 porcupine Drive Anchorage, Alaska 99501 Re: The request of Atlantic Richfield Conpany and BP Alaska Inc. to present testirrony to detennine nevl p<:xJl rules and amend existing rules for the Prudhoe Oil Pool. Conservation Order No. 145 Prudhoe Bay Field Prudhoe Oil Pool June 1, 1977 IT APPEARING THAT: 1. The referenced canpanies applied by letter received March 30, 1977, for a hearing to adopt new or amend existing pool rules. 2. Notice of public hearing was published in the Anchorage Daily News on April 2, 1977. 3., A public hearing was held in the Rarcada Irm, Anchorage, Alaska on May 5 and 6, 1977. 4. The hearing record was continued until the close of business on May 16, 1977. Additional data was received. FINDINGS: 1. Rules pertaining to the. Prudhoe Oil Pool have been included in Conservation Order Nos. 98-B, 130, and 137. 2. Administrative approvals 98-B.3, 98-B.6, 98-B.7, and 98-B.8 written pursuant to Conservation Order No. 98-B, Rule 8 are currently in effect. . 3. W:aivers pertaining to blowout prevention practices written pursuant to Conservation Order No. 137, Rule 2 are currently in effect. 4. The applicants propose to raise and lower the vertical pool limits of the Prudhoe Oil Pool to include the "Put River Sandstone" and Ivishak Shale respectively. 5. No drill stenl tests or production tests have been conducted in the "Put River Sandstone" or the Ivishak Shale. 6. No analysis of fluid fran the "Put River Sandstone" or the Ivishak. Shale are presently available to the Committee. ( COOSERVATION ORDER NO. 145 Page 2 June 1, 1977 7. The areal extent of the Prudhoe Oil Pool as defined on M3.rch 12, 1971, in Conservation Order No. 98-B, is considerably larger than the area nCÑl proven to be prcrluctive by the drilling of additional wells since that tiIœ. 8. Most producing wells in the Prudhoe Oil Pool are deviated holes to minimize the number of drilling pads. 9. The awlicants propose to eliminate reference to acreage spacing re- quirerænts but request that at least 2000 feet be naintained between the pay opened in the well bore in all wells in the Prudhoe Oil Pool. 10. The applicants propose that a distance of 1000 feet be maintained between the pay opened in any well and the boundary of the Prudhoe Oil Pool.' 11. Data fran the early prcx:1uction performance is needed for the proper regulation and operation of 1;.he reservoir. 12. Performance must be accurately obse:rved and quickly analyzed for a ti:Iœly assessment of reservoir behavior. I [ I [ [ [ [ [ [ [ 13. Performance during the first two years will be used to design the water flocrling projects and will be vital in formulating and imple- menting future operating plans. 14. A reservoir surveillance program can provide for rronitoring both reservoir and production data. 15. Monthly prcrluction tests will monitor changes in well productivity, gas-oil and oil-water ratios, and provide basic data for reservoir performance studies. 16. The reservoir is canplex with many discontinuous interbedded shales. 17. 'The reservoir is underlain by a heavy oil or tar zone of varying thickness. 18. Sare areas of the reservoir contain many faults. 19. The reservoir pressure data will provide infoImation on well flow efficiency, rese:rvoir perrreabili ty, reservoir discontinuities, and the need for a pressure maintenance program. 20. The use of specialized transient pressure testing techniques such as pulse testing, vertical penneabili ty tests, and interference tests mayprave useful. 21. Specific wells may be selected which æ::e located outside the main area of the Sadlerochit oil column to monitor the pressure in the gas cap, the aquifer, the Eileen area, and the Sag River gas cap. 22. The applicants have agreed to a carmon datum plane of 8800 feet subsea for all pressure surveys. ¡ ¡ ¡ I I I I I I I ( I I I I COOSERVATION ORDER N\.. ~ 45 Page 3 . June 1, 1977 ( 23. Changes in the gas-oil fluid contact rroverrent in the reservoir with response to production would provide information on shale continuity, effective vertical permeability, displacement efficiency of oil by gas and define areas of rxx>r natural recovery. . 24. Preliminary studies indicate that early run open hole or cased hole neutron logs may provide a suitable basE: log for m:mitoring the movement of the gas-oil contact by canparison with a later cased hole neutron log run in the same well. 25. Open hole neutron logs have already been run on the majority of wells. 26. Cased hole neutron logs have already been run in a number of wells and will continue to be run in selected wells until this technique is conf irIœd. . 27. Monitoring the movement of the oil-water contact should help to dete:rrn.ine.. the extent of water influx fran the aquifer, identify areas of peripheral water influx and allow determination of the water displacement efficiency. 28. MJnitoring the oil-water contact should provide infomation to help define locations where water injection would be beneficial. 29. A program is now in progress to evaluate the capability of IrOni toring the oil-water contact with one of three different rnethoos, such as the Thermal Lecay Tools (T. D. T .) or the Neutron Lifetime LcxJ (N. L. L. ) , the Carbon-Qxygen LcxJ and the Garrma Ray Lcxj. 30. The capability of these rnethcx:ls to monitor the changing oil-water c°I1:tact has not been demonstrated as yet. 31.. The contriliution of each of the various perforated intervals in each prcducing well may be determined through downhole spinner flo.v meter surveys. 32. A reliable assessment of the rate of the production fran the various lithologic subdivision$ within the reservoir will assist in the deter- mination of the effectiveness of the well canpletions to drain the reservoir. 33. Numerous canputer reservoir simulation mcx1el studies of the Sadlerochit Formation have been made by the State and the working interest o.vners. In these studies the offtake rates of oil and gas and the injection rates of gas and water have been varied. 34. The Trans-Alaska Pipeline will have an ;initial capacity of 1.2 million barrels per day and should be ready to accept oil near mid 1977. 35. The applicants have submitted a Plan of Operations which includes proposed average annual offtake rates of 1.5 million barrels per day for oil plus condensate production and 2.7 billion cubic feet per day for gas. ,( COOSERVATlœ ORDER NO. 145 Page 4 June 1, 1977 I I I I I I I I I' I ( . ( ( I I ( I Production facilities to support an average oil offtake of 1.2 million barrels per day will be installed by the last quarter of 1977. Addi- tions are planned during 1978 and 1979 to support an average oil .offtake rate of 1.5 million barrels per day plus condensate prcduction, ~hen pi¡;eline capacity is available. 37. Gas sales in large volures £ran the Prudhoe Bay Field will not be pössible until a gas oonditioning plant and a large gas sales pipeline are constructed. 36. 38. The ccrnpletion of a large gas sales pipeline and plant to. condition gas is estimatE¥! at approxiIrately five years fran start of oil prcxluction. 39. Until a large gas sales pipeline is available, all prcxiuced gas, except that used as fuel in the field and small local gas sales, will be reinjected into the gas cap. '40.. Gas will be used to supply the operating requirements of the Prudhoe Bay Field, the first four punp stations of the Trans-Alaska Pipeline and other minor local fuel needs. 41. To ræet pipeline sale quality it will be necessary to re:nove carbon dioxide fran the gas. 42. Water prcxluction will be minimal initially and will be disposed of "by injection into sands of Cretaceous age. 43. When water production becares significant, the applicants plan to file 'a secondary recovery application for the injection of this water into the Prudhoe Oil Pool. 44. Injection of prcduced water into the Prudhoe Oil Pool could begin within two years after start of oil production. 45. The applicants will proceed with design and implanentation studies concurrently with injectivity tests and reservoir data gathering to shorten the inplanentation tiIœ for a source water injection system. ' '46. The Sadlerochit Formation aquifer exhibits the best reservoir qualities near the Prudhoe Bay Field area and prCXJressively deteriorates away fran the field. CŒCI1JSIONS: 1. To avoid confusion it would be desirable to consolidate the outstanding Pool rules effectïng the Prudhoe Oil Pool into one order. Conservation Orders Nos. 98-B, 130, and Rule 2 of Conservation Order No. 137 should be canceled and the relevant portions included in Conservation Order No. 145. 1 I I .. ( ~ fi. [ [ I I I ( I COOSERVATlOO OHDEH Nl Page 5 June 1, 1977 (I A5 2. Administrative Approvals 98-B.3, 98-8.6, 98-B.7, and 98-B.8 should remain in effect and v!ill be applicable ill1til stable prcduction fran the field is attained or until the time period stipulated expires. 3. waivers pertaining to blo.vout preventers written pursuant to Conservation O".cder No. 137, Rule 2 should remain in effect. 4. There are insufficient data to justify raising or lo.vering the vertical limits of the Prudhoe Oil Pool, as proposed by the applicants, to correspond with the vertical limits of the Prudhoe Bay (perrro- Triassic) Reservoir as described in the Prudhoe Bay unit Agreerent. . 5. The areal extent of the Prudhoe Oil Pool should be identical to the initial participating area of the Prudhoe Bay Unit which is described as the Prudhoe Bay (Perrro-Triassic) Reservoir in the Unit Agreerrent. 6. A rule eliminating acreage spacing in the Prudhoe Oil Pool should facilitate present and future additional recovery operations and enable the uni t operators to. develop the prcx:1ucti ve capacity to rœet the planned throughput of the Trans-Alaska Pipeline. 7. A distance of 2000 feet between the pay opened in the well bore in all wells in the Prudhoe Oil Pool should maintain an adequate drainage area, not unnecessarily restrict bottaTÙ1ole target locations and protect correlative rights and prevent waste. 8. A distance of 1000 feet between the pay opened in any well and the boundary of the Prudhoe Oil Pool will protect correlative rights. 9. To gather the data necessary for proper regulation and operation of the reservoir, a rigorous surveillance prCXj.ram of reservoir performance should be accurately observed and assessed especially during the first two years of operation. The surveillance program should also provide guidelines for a long tenn key well surveillance prCXJram. 10. A surveillance prCXJram should include monitoring the reservoir pressures, gas-oil and oil-water contact movements, production tests, gas-oil and water-oil ratios, and prcx1uctivity profiles of individual wells. 11. A gas-oil contact movement monitoring prCXJram, based on a canparison of open hole neutron base lCXJs to be later COTIpared with neutron logs run in the sarœ wells should be attanpted. 12. The data obtained during the first two years could lead to a key well program of pericdic surveys that may adequately rronitor the gas-oil contact movements. 13. Monitoring the rrovenent of the oil-water contact is desirable to evaluate the water influx in the reservoir and the applicability of water injection systems. Three methcds are potentially applicable as means of mnitoring the ITOVE:ID2nt of the oil-water contact. These rrethods are the Thennal Decay Tools or the Neutron Lifet.iJne lDg, the Carbon-()),.ygen Log and the Gamna Ray Log. The prCXjTam to evaluate the relative capability of these I I ( ( ( 21. ( [ 22. [ 23. ( ( ( , (' CONSERVATION ORDER NO. 145 Page 6 June 1, 1977 legs should be continued and should any rrethod be derronstrated capable of adequately ITOni toring the changing water saturations in the reservoir, a key well program should be set up. 14. Downhole spinner flCM treter sUIVeys to determine well productivity profiles should help detennine the effectiveness of canpletions and provide infonnation on reservoir drainage. To provide the necessary productivity profile data a base line survey should be run on each well with later, folIa..¡ up surveys on each well. 15. The injection of prcxìuced water into the sands of Cretaceous age will not contaminate fresh water sources or endanger other natural resources. 16. Studies of the aquifer have iridicated that it probably will not offer mu~h pressure sup¡:xJrt. 17. Reservoir studies have shown that both prcxìuced water injection and source water injection into the Prudhoe Oil Pool should increase oil recovery . 18. Reservoir studies have shOÆ1 that large scale source water injection , will pròbab1y be necessary to maxinù.ze oil recovery. 19. The plarmed reinjection of gas into the Sadlerochit gas cap prior to large gas sales will help to maintain reservoir pressure and will not adversely affect ultimate recovery. 20. The Plan of Operations proposed by the applicants which include average annual offtake rates of 1.5 million barrels per day for oil plus condensate production and ,2.7 billion cubic feet per day for gas are consistent with sound conservation practices based on currently available data. After field and local fuel requi.ranents and the ranoval of carbon dioxide and'liquids fran the prcxìuced gas, it is estimated that a gas production rate of 2.7 billion standard cubic feet per day will yield 2.0 billion standard cubic feet per day of pipeline quality g~. - Production history will be needed to locate water injection wells and to refine reservoir m:Xiel studies. The offtake rates approved by the Corrmittee at this time must be established without the benefit of prcxìuction history. Therefore, these offtake rates may be changed as prcxìuction data and additional reservoir data are obtained and analyzed. \,.- .. ' ( CONSERVATIOO ORDER NO. 145 Page 7 June 1, 1977 NCX^J, THE REFDRE, IT IS ORDERED THAT the rules hereinafter set forth apply to the follcwing described area referred to in this order as the affected area: UMIAT MERIDIAN T. ION. , R. 12E. , T. ION. , R. 13E. , T. ION. , R. 14E. , Sections 1, 2, 3, 4, 10, II, 12 1, 2, 3 , 4, 5, 6 , 7, 8 , 9, 10, 11 , 12, 13, 14, 15, 16, 24 I, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 36 T. ION. , R. 15E. , I T. ION. , R. 16E. , T. llN. , R. 1lE., [ T. llN . , R. 12E. , I To llN. , R. 13E. , T.. llN . , R. 14E. , ( T. llN. , R. 15E. , [ T. llN. , R. 16E. , T. 12N. , R. 1lE. , (- T. 12N.., R.. 12E. , [ T.. 12N. , R. 13E. , [ T. 12N. , R. 14E. , T. 12N. , R. 15E.. , ( ( I I all 5, 6, 7, 8, 17, 18, 19, 20, 29, 30, 31 1, 2, 3, 4, 9, 10, 11, 12, 13, 14, 15, 24, 25 all all all all 30, 31, 32 15, 16, 17, 18, 19, 20, 21, 22, 25, 26, 27, 28, 29, 30, 32, 33, 34, 35, 36 23, 24, 25, 26, 27, 28, 33, 34, 35, 36 19, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36 25, 26, 27, 28, 2~, 31, 32, 33, 34, 351 36 27, 28, 29, 30, 31, 32, 33, 34 CONSERVATION ORDER NO. 145 Page 8 June 1, 1977 Rule 1 Pool Def ini tion The Prudhoe Oil Pool is defined as the accunulations of oil that are carmon to and which correlate with the aCClInulations found in the Atlantic Richf ield - Humble Prudhoe Bay State No. 1 well between the depths of 8,110 and 8,680 feet. Rule 2 Well Spacing In the affected area, ho pay shall be opened in a well closer than 2000 . feet to any pay opened in another well in the Prudhoe Oil Pool or be nearer than 1000 feet to the boundary of the affected area. [ [ [ [ ( I I ( ( ( I I ( ( Rule 3 Casing and Cementing RequireIœnts (a) Casing and cementing prcgrams shaLL provide adequate protection of all fresh waters and prcductive formations and protection fran any pressure that may be encountered, including external freezeback within the pe:rmafrost. (b) For proper anchorage and to prevent an uncontrolled flow, a conductor casing shall be set at least 75 feet belCM the surface and sufficient cement shall be used to fill the annulus behind the pipe to the surfaçe. ' (c) For proper anchorage, to prevent uncontrolled flow and to protect the well fran the effects of permafrost thaw, a string of surface casing shall be set at least 500 feet below the base of the perma- frost section but not belo.v 2, 700 feet unless a greater depth is approved by the Carrnittee upon showing that no potentially productive pay exists above the proposed casing setting depth, and sufficient cerrent shall be used to fill the annulus behind the pipe to the surface. The surface casing shall have minimum };X)st-yield strain properties of 0.9% in tension and 1.26% in compression. (d) If the surface casing does not meet the strain requirements in (c) above, the integrity of the well shall be protected from the effects of permafrost thaw by running an inner string of casing also set at least 500 feet belo.v the base of the permafrost section and properly canented except that the two casing strings shall not be bonded together wi thin the permafrost section. This inner string of casing shall not be utilized as production casing. (e) ,Other means for maintaining the integrity of the well fran the effects of permafrost thaw may be approved by the Camrittee upon application. (f) Prcx1uction casing shall be landed through the cœpletion zone and CeITeI1t shall cover and extend to at least 500 feet above each hydro- carbon-bearing formation which is potentially prcxlucti ve. In the alternative, the casing string may be set and adequately cemented at . . I I ¡ I I ( ( I ( ( ( I. I I I ( crnSERVATICN ORDER NO. 145 Page 9 June 1, 1977 ( at an intenrediate PJint and a liner landed through the canpletion zone. If such a liner is nm, the casing and liner shall over lap by at least 100 feet and the annular space behind the liner shall be filled with canent to at least 100 feet a1:ove the casing shoe, or the top of the liner shall be squeezed with sufficient ceIœnt to provide at least 100 feet of cerænt between the liner and casing. Cerrent must cover and extend at least 500 feet above each hydrocarbon- bearing formation which is lX'tentially productive. (g) Casing and liner, after being canented, shall be satisfactorily tested to not less than 50% of minimum internal yield pressure or 1,500 pounds per square inch, whichever is less. (h) No well shall be produced through the annulus between the tubing and the casing unless a canent sheath extends fran the top of the pay to the shoe of the next shall~ casing string. Rule 4 Blo.vout Prevention Equip¡œnt and Practice (a) The use of blowout prevention equipnent shall be in accordance with good established practice and all equipment shall be in good operating condition at all tiIres. All blowout prevention equipnent shall be adequately protected to ensure. reliab~e operation under the existing weather conditions. All blCMout prevention equipnent shall be checked for satisfactory operation during each trip. (b) Before drilling belo,.¡ the conductor string, each well shall have installed at least one remotely controlled annular type blCMout preventer and fla.v diverter system. The annular preventer installed on the conductor casing shall be utilized to permit the diversion of hydrocaroons and other fluids. This lCM pressure, high capacity diverter system shall be installed to provide at least the equivalent of a 6-inch line with at least two lines venting in different directions to insure downwind diversion and shall be designed to avoid freeze-up. These lines shall be equipped with full-opening butterfly type valves or other valves approved by the Conmittee. A schanatic diagram, list of equiprent, and operàtional procedure for the diverter system shall be su1:rnitted with the application Pennit to Drill or Deepen (Form 10-401) for approval. The above requirements may be waived for subsequent. wells drilled fran a multiple drill site. . (c) Before drilling belCM the surface casing all wells shall have three remotely controlled blcwout preventers, including one equipped with pipe rams, one with blind rams and one annular t~. The blOM)ut preventers and associated equipment shall have 3000 psi working pressure and 6000 psi test pressure. (d) Before drilling into the Prudhoe Oil Pool, the blcwout preventers and associated equipment required in (c) above shall have 5000 psi working pressure rating and 10,000 psi test pressure rating. . (f) I r I I ( ( ( ( ( I I I I (' COOSERVATIœ ORDER NO. 145 Page 10 June 1, 1977 (e) The associated equipment shall include a drilling spool with min~ three-inch side outlets (if not on the blowout preventer body), a minimum three-inch choke manifold, or equivalent, and a fill-up line. The drilling string will contain full-opening valves above and i.rrrœdiately helCM the kelly during all circulating operations with the kelly. 'IWo emergency valves with rotary subs for all connections in use will be conveniently located on the drilling floor. One valve will be an inside blowout preventer of the spring-lœded type. The second valve will be of' the manually-operated ball type, or any other type which will perform the saræ function. All ram-type blowout preventers, kelly valves, emergency valves and choke manifolds shall be tested to required working pressure when installed or changed and at least once each week theràfter. Annular preventers shall be tested to 50% recCI1Tænded working pressure when installed and once each week thereafter. Test results shall be recorded on w:çitten daily records kept at the wel).. .Rule 5 Automatic Shut-in Equi¡:ment Upon canpletion, each well shall be equipped with a sui table safety valve installed belo.v the base of the permafrost which will autanatically shut in the well if an uncontrolled flow occurs. . Rule 6 Pressure Surveys (a) Prior to initial sustained well prcrluction, a static bottanhole pressure survey shall be taken on each well. ( (b) Between 90 and 100 days after cœmencaœnt of sustained pcol pra:1uction, the applicants shall perform an initial key well botta1Ù101e transient pressure survey on one specific well on each pra:1ucing pad or drill site. Another survey of the same type shall be conducted each 90 days thereafter . (c) Within the first six months following the initial sustained well production, the applicants shali conduct a transient pressure survey on each well. (d) A semi-armual transient pressure survey shall be conducted on one well in each governmental section fran which oil is being prcx:1uced. This is in addition to the pressure surveys conducted in (b) and (c) above. (e) A long-tenn key well pressure survey will be fonnulated and inplerrented in approximately t\.;O years fran the start of prcxìuction based upon evaluation of data sul::mi.tted under (a), (b), (c), and (d) above. (f) Data fran the above rrentioned surVeys shall be filed with the Ccmnittee by the fifteenth day of the month following the Jronth in which each survey is taken. Fonn No. 10-412, Reservoir Pressure Report, shall be utilized for all surveys with attachments for complete additional data. Data suhnitted shall include but is not limited to rate, pressure, ti1œ, depths, temperature, and other well conditions necessary for \,. ., , . . CONSERVATIŒJ ORDER NO. 145 Page 11 June 1, 1977 complete analysis for each survey being conducted. The pool pressvre datum plane shall be 8800 feet subsea. Bottanhole transient pressures obtained by a 24 hour buildup or multiple flow rate test will be acceptable. (g) Results and data fran any special reservoir pressure monitoring techniques, tests or surveys shall also be sul:mi tted as prescribed in (f) above. (h) By administrative order the Committee shall specify additional pressure surveys if the survey prCXjrarn designated in this rule is found to be inadequate. Rule 7 G3.s-oil Ratio Tests Between 90 and 120 days after substantial prcx1uction starts and each six months thereafter a gas-oil ratio test shall be taken on each prcx1ucing well. The test shall be of at least 12 hours duration and shall l:::e made at the prcx1ucing rate at which the operator ordinarily prcx1uces the well. The test results shall be reported on gas-oil ratio test form P-9 wi thin fifteen days after canpletion of the survey. The Conmittee shall J:e notified at least five days prior to each test. Rule 8 Gas Venting or Flaring ¡ [ ¡ I. [ [ I I 1 I The venting or flaring of gas is prohibited except as may l:::e authorized by the Committee in cases of emergency or operational necessity. Rule 9 Gas-oil Contact Monitoring Open hole and cased hole neutron legs shall be run in selected wells to confirm gas-oil contact IroVem=nt unless this technique is proved tIDworkable or an al temati ve approoch is recœrnended and accepted by the Ccmni ttee. The wells selected for this neutron log survey together with a surrmary of the survey analyses shall be submitted to the Carmittee by January 1, 1978, and each six months thereafter. The Ccmnittee may also specify additional wells to be surveyed should. they decide the survey program being followed is inadequate. The cased hole neutron logs run shall be filed with the ccmni ttee by the fifteenth day of the month following the month in which the lCXjs~re run. Other methods of moni taring the gas-oil contact movement may be approved if they show to be more effective. A long term key well gas-oil contact movement monitoring prCXJram may be formulated and implerænted in approximately two years fran start of pro- duction if a workable technique is found. ( CONSERVATIOO ORDER NO. 145 Page 12 June 1, 1977 Rule 10 Oil-Water Contact I-bnitoring (a) A report on the evaluation program to determine the oil-water contact monitoring capability of the Thennal ~cay Tools or the Neutron Lifetime Log, the Carbon-Qxygen Log and the Garnna Ray Log shall be subTIi tted to the Cœmittee by January 1, 1978. (b) If the capability of rronitoring the change in oil-water contaét move- ment can be demonstrated by one or more of these rnethcrls, a key well program shall be set up by the applicants subject to the approval of the Cœmi ttee. Rule 11 Productivity Profiles (a) A spinner flo.-¡ meter survey shall be run in each well during the . first six months the well is on production. I ! I I I I I I ( I I (b) A follav up survey shall be perfonned on a rotating basis so that a new production profile is obtained on each well periodically. Nonscheduled surveys shall be run in wells which experience an abrupt change in water cut, gas-oil ratio, or proouctivity. (c) The ccrnplete spinner survey data and results shallte recorded and filed with the ccrrmi ttee 'by the 15th day of the rronth fOllo.-¡ing the month in which each survey is taken. ( Cd) By administrative order the Ccmnittee shall specify additional surveys should they determine the surveys suhnitted under (a), (b) and (c) above are inadequate. Rule 12 Changing the Affected Area By administrative approval the Camrittee may adjust the description of the affected area to conform to future changes in the ini tial participating area. Rule 13 Orders Cancelled Conservation Orders Nos. 98-B, 130,' and Rule 2 of Conservation Order No. 137 are hereby cancelled. Portions of Conservation Orders Nos. 98-B and 137 are made part of this order and the hearing records of these orders are also made part of the hearing record of this order. Rule 14 Approvals Redesignated Administrative Approvals made pursuant to CO 98-B, Rule 8 and the waiv~rs made pursuant to Conservation Order No. 137, Rule 2 remain in effect and will now be authorized by this order. \. . . r I [ ¡ ¡ [ ( ( ( I I I I COOSERVATIŒJ ORDER NC ( 15 Page 13 June 1, 1977 (, Rule 15 Pool Off-Take Rates The ~ximum annual average oil offtake rate is 1.5 million barrels per day plus condensate prcduction. The maxirrn..:rn annual average gas offtake rate is 2.7 billion standard cubic feet per day, which contemplates an annual average gas pipeline delivery sales rate of 2.0 billion standard cubic feet per day of pipeline quality gas when treating and transportation facilities are available. Daily offtake rates in excess of these amounts are permitted only as required to sustain these annual average rates. Th~ annua¡ average offtake rates as specified shall not be exceeded without the prior written approval of the Cœmi ttee. . . Annual average offtake rates mean the daily average rate calculated by dividing the total volume produced in a calendar year by the n~r of days in the year. However, in the first calendar year that large gas offtake rates are initiated, following the completion of a large gas sales pipeline, the annual average offtake rate for gas shall be determined by dividing the total volume of gas produced in that calendar year by the number of days rEmaining in the year follCMing ini tial delivery to the large gas sales pipeline. IX)NE at Anchorage, Alaska, and dated June l, 1977. h. ..¡.f>o. OJ t .<~. f,. 'ßç. ". ~.-v<> "( ß~~; C' 'If ~ r ~ ¡:":j~' ~ ¥ . ~:--~i:UI ~~-Þ..'.. :Q~""''<i.~."'' I' ~e. z ~ ~ /~ (") -:.. - 0'- -f~ \"~ t:.!, . 0 ----.;¿;;- _.. ;¡:/.\\ 1 ',' ¡''' "-:Jt - ...£-~~.. - d,.;:;, ;¡,. -..3 .h:'1 "':!~' .~ 0 . ~~:ulJ~~, ~~~ON co;lß/ ¿b. 1ial~~~=etary Alaska Oil and Gas Conservation Cæmittee Concurrence: 4~ #~~ HOfC ~~amilto( ~airman Alaska il and Gas Conservation Canmi ttee 10 ie C. Smith, r Alaska Oil and Ga Conservation Cæmittee (" b -<. '-~. .....-..---. ---I ~rn r~1 :.: - . t .;' f\ S ~ t._.""\ r 1.-.- . r:~.~:; !~): \ r.'~'. ""'C':-----'¡ \ \ \ ~ NOTICE OF PUBLIC HEARING STATE OF ALASKA DEPARTMENT OF NATURAL RESOURCES DIVISION OF OIL AND GAS CONSERVATION Alaska Oil and Gas Conservation Committee ';j t - \ \ -1) Qe~ ~ e ( {£',;:.:1: 't. ('.<;.0 .-.~:.~.: - . Conservati9n File No. 145 Re: The request of BP Alaska Inc. and Atlantic Richfield Company to hold a public hearing to hear testimony to determine the proper pool rules including amendment of existing rules and establishment of new rules for the Prudhoe Oil Pool, Prudhoe Bay Field Notice is hereby given that the Alaska Oil and Gas Conservation Committee will hold a public hearing to hear testimony to determine the proper pool rules including amendment of existing rules and establish- ment of new rules for the Prudhoe Oil Pool, Prudhoe Bay Field, pursuant to Title 11, AAC 22.520 on May 5, 1977 at 9:00 AM in the Ramada Inn, 598 W. Northern Lights Blvd., Anchorage, Alaska, at which time affected' and interested persons will be heard. On March 29, 1977, a Unit Agreement for the Prudhoe Bay Field was submitted by applicants and others for approval by the Director, Division of Minerals and Energy Management, the Commissioner and the Dßpartment of Natural Resources. In' connection with the establishment of the Prudhoe Bay Unit and the commencement of field production, adoption or amendment of pool rules will be requested to ensure proper conservation, the prevention of waste and the protection of correlative rights. l I- I [ ( ( [ ( [ I 1 The Committee will seek testimony on any matter relevant to the determination of proper pool rules including, but not limited to the following: 1 . 2. 3. 4. 5. 6. 7 . 8. 9. Vertical definition of pool. Drilling and facility plans and operation. Oil and gas off-take rates. Well spacing. Gas injection. Produced water disposal. Preliminary water injection plans. Reservoir data gathering plans. Studies of reservoir performance. Notice is also given that, based upon the record of the hearing, the Alaska Oil and Gas Conservation Committee may adopt, alter or amend pool rules for the Prudhoe Oil Pool, Prudhoe Bay Field. (, .I 2- ;' [ [ ¡ ! I ( ( ( I I ( I ( ( I In addition, the Committee will make a finding under AS 31.05.110(1) as to whether the plan for the development and operation of the field under the unit will conserve oil and gas. ' Copies of the unit application submitted and the unit agreement which accompanies the application and which incorporates the Plan of Development and Operation for the Prudhoe Bay Unit designat~d as Exhibit E are available for public inspection at the offices of the Division of Minerals and Energy Management, 323 E. 4th Avenue, Anchorage, Alaska 99501. A limited number of copies of these documents may be obtained. in person or by mail at the above address. VL. )ç J!¿¡ ~ i Thos. R. Marshall, Jr. Executive Secretary Alaska Oil and Gas Conservation 3001 Porcupine Drive Anchorage, Alaska 99501 Committee Pub 1 ish: ,Apri 1 2, 1977 /- '( ',~ ~-r" ( í) ", I" "~Jï1CE OF PUBLIC H£;.\~U!~G S T ,; T E C F A L ".5 r..A DEPAR~EHï OF !{F.TURAL ~ES(lURCES DrnS1C~ OF OIL ;JW ~S CC:iSERVh1¡C~\ Alaska Oil and Gas Conservation C~18ittee Conservation Fi1e 1ío. 145 [ I I I I ' I I I I [ I [ I I I p~: The request of BP AlðS~ð Inc. and Atlantic Richfie1d Ct~~3ny to hold a pub1ic hearing t~ Þear t€5ti~ony to è~te~ine the proper pt~l ru1~s incl~ding ~~errë7ent of existing r~1es and e5tzbl;st~eot of nê~ rules for the Prudhoe Oil PODl, Prudhoe BèY Fie1d - .. Hotice is hereby gi'i~n that the Alast~ Oil and f"as ~nservðtion CO:T.1itte~ ~il1 hold a public hfõring to r.~ar testi~~ny t~ ë~te~ine the proper poo1 rules includiog çTenL~nt of existing rules and est~b1ish- Pent of O~. ru1es for the Prudho~ Oil Pc~l, Prudhc~ Bay Field, pur~uant to Title ll~ Þ],C 22.520 on. )~1 5,1917 (It 9:~O p~ in the ~r'ada lnn, 598 W.. :iorthern liQhts Blvd.. Anchorar.é, A1as~a. at ~hich ti~e aff~ctJ.:d and inter-;aste-d ¡;€r'šcns will be r~~rd.- On ?arch 29, i971. è Unit Agreç~nt for the Frudhoe Bay Field wa~ sut~itted by è~pl;cants and ethers for approvè1 by the Dir~tort Division of ~inerals and Energy ~nag~ent, the Co~issioner and the ~pa'~~nt of fCatural ResouN:c$. 10 conn~~tÜm 'ttith the establis~efìt of th~ Pn;dhce BèY Unit and t"~ C(C1¡.ence.:~(!nt of field product ion, adtiflticn or ð~endrent of r.~Dl ruìes ~il1 t~ requested tó ensure proper ccn~ervation, the prevention of waste and the protection of correlôtive rights. 1he C~nnittee ~i11 SefK testi~~j' en any rattfr relevant to the dete~ir.alion,of prc~~r p~~1 rules incìuding, t~t r~t linit€d to the fo 11crlt-1°9: . .. 1. Vertical drfinition of ÿcol. 2. Dril1in9 a~ô fðCi1ity plans ar.d c~~ratic~. 3. Oil and ~s off-~i:e rat~5. 4. ~11 spacing. 5. Gas injection. 6. Pr<x1uced ~a ter äi sp-osa 1. ï. Prelinin3fY wat~r injt~ticn plans. 8. ReSQrïOir data ~~therinQ plans. 9" Studies of reservot r perfOf7'èfice. r ' ! lfot ice is ò 1 so gi ven tt'~t, b.aS0d UreD th~ re-cor'Ó of the h~òr1nrh the Aìôska Oi 1 and G.as Conserv~tion ço:'-Tri ttee n~j' adopt, ð ì ter or a:7~nd pt~l ru1es for th~ Prudhc~ Oil Pool, rrvdh~~ Bðy field. ~ , . . ø-,' "'-- ....... ". -(' 2- I ..I..J°t-\(", .t-þ C,.- :..... - .'11 -~.. &{ d' ~ . ''''0 .C:; ':"1 ~'- ~'t~{L' r. 3¡,;vl Qo'0, _I... ,.l.r! ~~e~"1 ¡ .",."e a :,f'! ¡r.:-, !,.;r:I-:...r 1'- ...; I. ).;. ; :\"'.. ¡ as to Kh~tr.~r :t; r1ðn for t~~ cf¥€lcp7ènt ðfid Q~~r~:ion úf the fie¡d unc~r the unit ~ill CC~~fr¥e oil and ~ðS. . Cepie~ of th~ unit appliCðtion sut:,itted and the un1t agf~~~ent ~hich øccv~~ðr.ies th~ applicðticn ðnd ~ñich incorp'oretes the Plðn of ~:(e1Q~~Ent and Cperaticn for, ~he Prurlhc~ Bay Unit è~si9natcrl as r~hibit Earc ~vði1ab1e for public in~ì~ction at the offices of the Divisiun of 1~ir.frèls and Ener9Y P~nac~~er.t, 323 E. 4th A~enue, Anchor~c~, ~l~ska 9950ì. A li~i!~d n~rti~~ of copiés of tr.~$e dç~~7ents ~ay be cbtair.2~ in ~~rsor: or by ~ail at tñ~ atù,e ðd~ress. I I I I I ( ( ( [ I I I I I 7hos. R. }~rshal1~ Jr. Executive S~cret~ry . Alê$~a Oi1 õr.õ 5a$ Ccnser~õt1cn 3Gùl PQrcupine Drive Þ~c~~ra~~, Alaska ~g501 ~ . . . , ~Iittce ( EXHIBIT 2 Legal Description Prudhoe Bay Unit Effective February 22, 1986 ADL Tract No. of serial [ No. Description Acres No. (umiat Meridian, Alaska) 1 T12N-R11E, Sees.. 9, 10 1,280 47445 [ 2 T12N-R11E, Sees. 11,12 1,280 28235 [ 3 T12N-R12E, Sec. 7 580 28254 T12N-R15E, 23,24 1,280 4 Sees. 34625 ¡ 5 T12N-R15E, Sees. 21,22 1,280 34626 6 T12N-R15E, Sees. 19,20 1,225 34627 I 7 T12N-R14E, Sees. 23,24 1,280 34624 [ 8 T12N-R14E, Sec. 22 640 28297 9. T12N-R13E, Sees. 19,20 1,225 47469 [ 10 T12N-R12E, Sees. 23,24 1,280 47448 11 T12N-RI2E, Sees. 21,22 1,280 28256 ( 12 T12N-R12E, Sees. 17,18,19,20 2,448 28255 I, 13 T12N~R11E, Sees. 13,14,23,24 2,560 28237 14 T12N-RI1E, Sees. 15,16,21,22 2,560 47447 I 15 TI2N-RIIE, Sees. 17,18,19,20 2,448 47446 16 TI2N-RI0E, Sees. 13,24 1,280 25637 I 17 TI2N-RIIE, Sees. 29,30,32 1,868 47449 I 18 T12N-RI1E, Sees. 27,28,33,34 2,560 28239 19 TI2N-RIIE, Sees. 25,26,35,36 2,560 28238 I I ADL Tract No. of Serial No. Description Acres No. (Umiat Meridian, Alaska) 20 T12N-R12E, Sees. 29,30,31,32 2,459 28259 r 21 T12N-R12E, Sees. 21,28,33,34 2,560 28258 I 22 T12N-R12E, Secs. 25,26,35,36 2,560 28251 23 T12N-R13E, Sees. 29,30,31,32 2,459 28219 r 24 T12N-R13E, Secs. 21,28,33,34 2,560 28218 25 T12N-R13E, Secs. 26,35,36 1,920 28211 I 26 T12N-R14E, Secs. 29,31,32 1,811 28299 [ 21 T12N-R14E, Secs. 21,28,33,34 2,560 28300 28 T12N-R14E, Secs. 25,26,35,36 2,560 28301 I 29 T12N-R15E, Secs. 29,30,31,32 2,459 34628 30 T12N-R15E, Secs. 21,28,33,34 2,560 34629 I 31 T12N-R15E, Secs. 25,26,35,36 2,560 34630 ( 32 T12N-R16E, Secs. 29,30,31,32 2,459 34635 33 T12N-R16E, Secs. 28, 33, SW/4, 1,560 34634 W/2NW/4, SW/4SE/4 Sec. 34 I 35 T11N-R16E, Sec. II, S/2NE/4, 1,480 34636 NW/4, S/2 Sec. 12, SW/4NW/4, ¡IF. SW/4, S/2SE/4 Sec. 2 , 36 T11N-R16E, Sees. 3,4,9,10 2,560 28331 I 31 TI1N-R16E, Secs. 5,6,1,8 2,469 28338 38 TIIN-R15E, Secs. 1,2,11,12 2,560 28320 I 39 T11N-R15E, Secs. 3,4,9,10 2,560 34631 I 40 T11N-R15E, Secs. 5,6,1,8 2,469 34632 41 T11N-R14E, Secs. 1,2,11,12 2,560 28302 I 42 TIIN-R14E, Sees. 3,4,9,10 2,560 28303 43 TIIN-R14E, Sees. 5,6,1,8 2,469 28304 I I ( ADL Tract No. of Serial No. Description Acres No. (Umiat Meridian, Alaska) 44 TIIN-R13E, Sees. 1,2,11,12 2,560 28280 45 TIIN-RI3E, Sees. 3,4,9,10 2,560 28281 46 TI1N-RI3E, Sees. 5,6,1,8 2,469 28282 41 TI1N-RI2E, Sees. 1,2,11,12 2,560 28260 48 TI1N-RI2E, Sees. 3,4,9,10 2,560 28261 49 TIIN-R12E, Sees. 5,6,1,8 2,469 41450 50 T11N-R11E, Sees. 1,2,11,12 2,560 28240 51 T11N-RIIE, Sees. 3,4,9,10 2,560 28241 52 TI1N-R11E, See. 15 640 28244 ¡ 53 T11N-RI1E, Sees. 13,14,24 1,920 28245 54 TI1N-R12E, Sees. 11,18,19 1,840 28262 I 54A T11N-R12E, See. 20 640 28262 I 55 T11N-RI2E, Sees. 15,16 1,280 28263 5521. T11N-RI2E, Sees. 21,22 1,280 28263 56 T11N-RI2E, Sees. 13,14,23,24 2,560 41451 51 T11N-R13E, Sees. 11,18,19,20 2,480 28283 58 T11N-R13E, Sees. 15,16,21,22 2,560 28284 ( 59 T11N-R13E, Sees. 13,14,23,24 2,560 28285 60 TI1N-R14E, Sees. 11,18,19,20 2,480 28305 ( 61 T11N-R14E, Sees. 15,16,21,22 2,560 28306 62 T11N-R14E, Sees. 13,14,23,24 2,560 28301 ( 63 TI1N-R15E, Sees. 11,18,19,20 2,480 28321 I 64 T11N-R15E, Sees. 15,16,21,22 2,560 28322 65 T11N-R15E, Sees. 13,14,23,24 2,560 28323 ( ( ( ADL Tract No. of Serial No. Description Acres No. (Umiat Meridian, Alaska) 66 TIIN-R16E, Secs. 11,18,19 1,840 28339 661'. T11N-R16E, Sec. 20 640 28339 61 T11N-R16E, Secs. 15,16 1,280 28340 671'. T11N-R16E, Sec. 21 640 28340 68 T11N-R16E, Secs. 13,14 1,280 28341 69 T11N-R16E, Secs. 30,31,32 1,851 28343 I 69A T11N-R16E, Sec. 29 640 28343 I 10 T11N-R15E, Secs. 25,26,35,36 2,560 28324 11 T11N-R15E, Secs. 21,28,33,34 2,560 28325 ( 12 T11N-R15E, Secs. 29,30,31,32 2,491 28326 13 T11N-R14E, Secs. 25,26,35,36 2,560 28308 I 14 T11N--R14E, Secs. 21,28,33,34 2,560 28309 [ 15 T11N-R14E, Secs. 29,30,31,32 2,491 28310 16 T11N-R13E, Secs. 25,26,35,36 2,560 28286 11 T11N-R13E, Secs. 21,28,33,34 2,560 28281 ... 18 T11N-R13E, Secs. 29,30,31,32 2,491 28288 [ 19 T11N-R12E, Secs. 25,26,35,36 2,560 28264 [ 80 T11N-R12E, Secs. 21,28,33,34 2,560 47452 81 T11N-R12E, Secs. 29,30,31,32 2,491 41453 ( 82 T11N-R11E, Sec. 25 640 28246 83 T10N-R12E, Secs. 3,4,10 1,920 41454 ( 84 T10N-R12E, Secs. 1,2,11,12 2,560 28265 85 T10N-R13E, Secs. 5,6,1,8 2,501 28289 I 86 T10N-R13E, Secs. 3,4,9,10 2,560 41471 I 87 T10N-R13E, Secs. 1,2,11,12 2,560 47472 I (, ADL Tract No- of Serial No- Descripti.on Acres No- (Umiat Meridian, Alaska) 88 T10N-R14E, Secs- 5,6,7,8 2,501 28313 89 TI0N-R14E, Sees- 3,4,9,10 2,560 28312 I 90 TI0N-R14E, Sees- 1,2,11,12 2,560 28311 91 T10N-R15E, Sees- 5,6,7,8 2,501 28329 I 92 T10N-R15E, Sees- 3,4,9,10 2,560 28328 93 T10N-R15E, Sees- 1,2,11,12 2,560 28327 [ 94 T10N-R16E, Sees. 5,6,7,8 2,501 28345 I 95 TI0N-R16E, Sees. 4,9 1,280 28344 96 T10N-R16E, Sec. 16 64Q 28347 I- 97 T10N-R16E, Sees. 17,18,19,20 2,512 28346 98 TI0N-R15E, Sees- 13,14,23,24 2,560 28332 ( 99 TI0N-R15E, Sees. 15,16,21,22 2,560 28331 [ 100 TI0N-R15E, Sees. 17,18,19,20 2,512 28330 101 TI0N-R14E, Sees. 13,14,23,24 2,560 28315 102 TI0N-R14E, Sees. 15,16,21,22 2,560 28314 103 T10N-R14E, Sees. 17,18,19,20 2,512 47475 ( 104 T10N-R13E, Sees. 13,14,24 1,920 47476 ( 105 TI0N-R13E, Sees. 15,16 1,280 28290 106 TI0N-R14E, Sees. 27,28 1,280 80595 .r 107 TI0N-R14E, Sees. 26,36 1,280 28316 =:. 107A T10N-R14E, Sec. 25 640 28316 ( 108 T10N-R15E, Sees. 29,30,31,32 2,523 28335 ( 109 TI0N-R15E, Sees. 33,34 1,280 28334 1091\ T10N-R15E, Sees. 27,28 1,280 28334 [ I I [ I [ I ( I I I ( I I I I I ADL Tract No. of Serial No. DescriPtion Acres No. (Umiat Meridian, Alaska) 110 T10N-R15E, Sees. 25,26,35,36 2,560 28333 111 T10N-R16E, S~cs. 29,30,31 1,883 28349 112 T12N-R13E, Sees. 21,22 1,280 28275 113 T12N-R13E, Sec. 23 640 28276 114 TIIN-R16E, Sees. 28,33 1,280 28342 ( [ [ I I I I I I I ( ( ( ( ( ( ( I I Exhibit 3 EXISTING INJECTION PERMITS Prior to implementation of the Environmental Protection Agency (EPA) Underground Injection Control (UlC) regulations, SAPC was operating nine injection wells within the WOA. The EPA UIC regulations authorized these nine wells to operate "by rule" and are listed below. In addition, EPA has issued Emergency UlC Permits on June 25, 1984 and February 26, 1986 which are also listed here. Wells Authorized by EPA Rule Well Number ADEC Permits Well R-3 Well R-6 Well GCl-A Well GCl-C Well GC2-A Well GC2-B Well GC3-A Well GC3-C We 11 GC3-D 8436-DBOO8 8436-DBOO8. 8436-DBOO9 8436-DBO'o9 8436-DBOlO 8436-DBOlO 8436-DBOIO //1 The two R Pad wells are operated under AOGCC secondary recovery authorizations. Produced water is injected through these wells into the Ivishak formation. The seven injection wells at the gathering centers are operated under Wastewater Disposal permits from the Alaska Department of Environmental Conservation (ADEC). These wells are used to inject produced water and production waste fluids into the Cretaceous and Tertiary sands. ( Wells Permitted by Emerqency UlC Permits Prudhoe Bay Unit Western Operating Area underground Injection Control Permits as Authorized by EPA June 25, 1984 Permit Number Well Number AI{-2ROOO1-E A-3 I AK-2ROOO2-E A-8 AK-2ROOO3-E A-11 AI{-2ROOO4-E A-16 I AI{-2ROOO5-E A-17 AK-:2ROOO6-E A-27 AI{-2ROOOï-E B-9 AK-2ROOO8-E B-13 ( AK-2ROOO9-E F-18 AI(-2ROOI0-E F-19 AK-2ROOII-E H-9 ( AK-2ROOI2-E H-IO AI(-2ROOI3-E M-1 AK-2ROOI4-E M-2 AK-2ROOI5-E M-3 ( AK-2ROOI6-E M-12 AK-2ROOlï-E M-13 AK-2ROOI8-E M-14 ( AK-2ROO19-E N-5 AK-2ROO20-E N-8 AK-2R0021-E R-2 I AK-2ROO22-E R-5 AK-2ROO23-E R-ï AK-2ROO24-E R-20 'AK-2ROO25-E 8-6 ( AK-2ROO26-E 8-9 AK,-2ROO2ï-E 8-11 AK-2ROO28-E 8-14 ( AK-2ROO29-E T-B AK-2ROO30-E T-7 AK-2ROO31-E U-A (U-4) ( AI(-2ROO32-E U-C (U-5) AK-2ROO33-E U-F (U-3) AK-2ROO34-E U-H (U-9) AK-2ROO35-E U-1 (U-I0) ( AK-2ROO36-E X-6 AK-2ROO3ï-E X-11 AK-2ROO38-E X-23 ( AK-2ROO39-E X-24 AK-2ROO40-E X-26 AK-2ROO41-E Y-3 AK-2ROO42-E Y-5 ( Al{-2ROO43-E Y-6 AK-2ROO44-E Y-ll AK-2ROO45-E Y-18 ( ( Wells Permitted by Rmerqency UIC Permits Prudhoe Bay Unit Western operating Area Underground Injection Control Permits as Authorized by EPA February 26, 1986 Permi t Number Well Number ! I I AI(-2R0243-E AI(-2R0244-E AK-2R0245-E H-l Y-7 M-MD (M-28) " I I , I I I I I I I ::J:t ~ ~'1 .~ Standard Alaska Production Company 900 East Benson Boulevd P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 564-5111 ') ¡-,;~¡ï,'~K.A."~. .. .. . '. . j-." t, 'f,.. ~:',~ . ~~ ,.:, w ! , .' " '. !' (I" ; -~ '" '-'''\1 t"" ~ "'\).' ;..... ,. ',: ,: \J --.J! . .. '. ' ';/ R' , ¡ I I I ~ STANDARD \ .. ~ ALASKA PRODU~TJON . )17- b~~ 'VkSJ}:: Ie;TAj"i"EC* LFI!:_E: Hay 16, 1986 Mr. C. V. Chatterton, Commissioner Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Re: Prudhoe Bay Unit WOA Freshwater Aquifer Exemption Dear Mr. Chatterton: By letter of application Standard Alaska Production Company, as operator of the Prudhoe Bay Unit Western Operating Area (WOA), hereby requests a freshwater aquifer exemption be granted for potential freshwater aquifers existing within the WOA. These aquifers meet the requirements for exemption found in 20 AAC 25.440 pertaining to freshwater aquifer exemptions. Attached is the WOA Injection Order Application which includes the aquifer exemption request as Section L (see page 37). Supporting information is included in the appropriate sections of the document. Per your request, the aquifer exemption is submitted under seperate cover letter to facilitate your review. Note that the Injection Order Application and Aquifer Exemption use the identical application package. Enclosed are five (5) copies of the Application for your use. Please contact Ivlr. Bob Allan 564-5007 or Nr. Raymond Hanson at 564-5411 if you have questions or require additional information. Sincerely, ~# ".' .. ...< . /' Ie t! .' .. ?//?:...e./,(¿,.ct.~~_.- ~~ ~ R.C. Herrera Manager Exploration Planning/Environment/Lands RCH:RAH/hrf/5900V Attachment cc: Ms. Kay Brown, Director, DOG, DNR (with copies to DGGS and DLWN) Mr. Andrew Oenga Mr. Tom Fink, Manager Environmental Conservation, ARCO Alaska, Inc. Mr. John Kemp, Division Manager, Conoco, Inc. A unit of the original Standard Oil Company Founded in Cleveland, Ohio, in 1870. , Attachment cc: Ms. Kay Brown, Director, DOG, DNR (with copies to DGGS and DLWM) Mr. Andrew Oenga Mr. Tom Fink, Manager Environmental Conservation, ARCO Alaska, Inc. Mr. John Kemp, Division Manager, Conoco, Inc.