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Home My WebLink AboutAIO 012AREA INJECTION ORDER NO. 12 South Portion of Trading Bay Field 1. September 3, 1986 Unocal’s request for an AIO Trading Bay Field 2. September 12, 1986 Notice of Public Hearing and Affidavit of Publication 3. September 16, 1986 Unocal’s letter re: UIC Corrections 4. September 24, 1986 Addendum to application 5. May 24, 1994 Unocal’s request to augment waterflood injection on the Grayling and Monopod platforms 6. June 7, 1994 AOGCC’s response to 5/24/94 request 7. September 27, 2004 Public Notice to Amend Underground Injection Orders to Incorporate Consistent Language Addressing the Mechanical Integrity of Wells 8. January 9, 2006 Chevron’s request for continuation of shut-in status 9. February 9, 2006 Email re: A-12D and A-26 MIT Guidance 10. October 3, 2006 Unocal’s request for administrative approval to continue injection of non-hazardous Class II fluids for Monopod platform (AIO 12.001) 11. February 25, 2009 Unocal’s request for administrative approval to continue water injection into A-29RD (AIO 12.002) 12. March 19, 2009 A-29 Temperature Survey 13. March 22, 2011 A-29 Temperature Survey 14. August 9, 2013 Administrative approval to reestablish EOR Class II non- hazardous fluid injection into Trading Bay ST A-12RD (AIO 12.003) 15. February 17, 2015 Hilcorp’s request for cancellation of AIO 12.003 (AIO 12.003 Cancellation) 16. December 30, 2015 Hilcorp’s request for cancellation of AIO 12.002 (AIO 12.002 Cancellation) 17. February 26, 2016 Hilcorp’s request for administrative approval to allow well TBU ST A-25RD to be online in water only injection service with a known tubing by inner annulus communication. (AIO 12.004) 18. November 23, 2020 Hilcorp’s request for administrative approval to allow well TBU ST A-25RD to be online in water only injection service with a known tubing by inner annulus communication. (AIO 12.005) 19. -------------------- Annual EOR surveillance report 20. March 22, 2021 Complete water analysis report (AIO 12.006) 21. June 23, 2021 Request for Admin Approval to AIO 12 to add filtered Gray Water to approved injection fluids. (AIO 12.006) 22. March 13, 2025 Hilcorp Request cancelation of AIO 12.005 (AIO 12.005 Cancelation) - . STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re: THE REQUEST OF UNION OIL ) COMPANY OF CALIFORNIA for ) an Area Injection Order ) for the portion of the ) Trading Bay Field developed ) by the Monopod Platform ) Area Injection Order No. 12 Southern Portion of Trading Bay Field November 20, 1986 IT APPEARING THAT: 1. Union Oil c10mpany of California (Union) requested the Alaska Oil bnd Gas Conservation Commission to issue an Area Injection Order permitting the underground injec- tion of fluids within a portion of the Trading Bay Field for purposes of enhanced hydrocarbon recovery. 2. Notice was published in the Anchorage Daily News on September 12, 1986 of an opportunity for a public hearing on October 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. FINDINGS: 1. An order permitting the underground injection of fluids on an area basis, rather than for each injection well individually, provides for efficiencies in the adminis- tration and surveillance of underground fluid injection operations. 20 AAC 25.460 provides the Commission with the authority to issue an order governing underground injection operations on an area basis. 2. The portion of the Trading Bay Field developed by Union's Monopod platform constitutes a compact "project area" which can readily be described by governmental subdivisions. Union is the sole operator of this Project Area. Area Injection Jlter Page 2 November 20, 1986 No. 12 . 3. The Project Area encompasses approximately the Southern half (1/2) of the Trading Bay Field, Middle Kenai and Hemlock Oil Pools. The Project Area includes all existing injection wells and injection well sites planned for enhanced recovery of oil from the Middle Kenai and Hemlock Oil Pools in this portion of the field. 4. The portion of aquifers beneath Cook Inlet described by a 1/4 mile area beyond and lying directly below the Trading Bay Field are exempted for Class II injection activities by 40 CFR 147.102(b)(2)(D) and 20 AAC 25.440(c). 5. Less stringent requirements for well construction, operation, monitoring, and reporting of injection operations may be more appropriate than would be required when injection occurs into, through or above portions of aquifers not exempted. 6. The vertical limits of injection strata and confining formations may be defined in the Union Oil Company of California Trading Bay State well No. A-17. 7. The strata into which fluids are to be injected will accept fluids at injection pressures which are less than the fracture pressure of the injection strata and their confining formations. 8. Statewide regulations and conservation orders govern field operations except as modified by this order. 9. To ensure that fluids injected are confined to injec- tion strata, the mechanical integrity of injection wells should be demonstrated periodically and monitored routinely for disclosure of possible abnormalities in operating conditions. 10. Injection wells existing on the date of this order were constructed and completed in accordance with regu- lations which conform to the requirements of 20 AAC 25.412. Area Injection oJltr Page 3 November 20, 1986 No. 12 e NOW, THEREFORE, IT IS ORDERED' THAT the rules hereinafter set forth govern Class II underground injection operations in the following described area referred to in this order as the affected area: SEWARD MERIDIAN T9N R13W Section 3 : All. Section 4 : All. Section 5 : E~. Section 8 : NE%, N~ SE%. Section 9 : N~, N~ SE%, N~ SW%. Section 10: N~, N~ SE%, N~ SW%. Section 33: S~ SE%. TI0N R13W Rule 1 Authorized Injection Strata for Enhanced Recovery Within the affected area, non-hazardous fluids may be injected for purposes of pressure maintenance and enhanced oil recovery into strata defined as those strata which correlate with the strata found in the Union Oil Company of California Trading Bay State well A-17 between the measured depths of 3220 feet and 8270 feet for the Trading Bay Middle Kenai "B", "C", "D", "E" and Hemlock Oil Pools. Rule 2 Fluid Injection Wells The underground injection of fluids must be: 1) through a new well that has been permitted for drilling as a service well for injection in conformance with 20 AAC 25.005; 2) through an existing well that has been approved for conversion to a service well for injection in conformance with 20 AAC 25.280; or 3) through a well that existed as a service well for injection purposes on the date of this order. Rule 3 Monitoring the Tubing/Casing Annulus Pressures The tubing/casing annulus pressure of each injection well must be checked weekly to ensure there is no leakage and that it does not exceed a pressure that will subject the casing to a hoop stress greater than 70% of the casing's minimum yield strength. Area Injection oJltr Page 4 November 20, 1986 No. 12 e Rule 4 Reporting the Tubing/Casing Annulus Pressure Variations Tubing/casing annulus pressure variations between consecutive observations need not be reported to the Commission. Rule 5 Demonstration of Tubing/Casing Annulus Mechanical Integrity A schedule must be developed and coordinated with the Commission which ensures that the tubing/casing annulus for each injection well is pressure tested prior to initiating injection and at least once every four years thereafter. A test surface pressure of 1500 psi, or, assuming a 0.465 psi/ft geo-pressure gradient, a surface pressure that imposes a differential pressure gradient across the casing of 0.25 psi/ft at the vertical depth of the packer, whichever is greater; but not to exceed a hoop stress greater than 70% of the casing's minimum yield strength, must be held for 30 minutes with no more than a 10 percent decline. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Rule 6 Well Integrity Failure Whenever operating pressure observations or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, the operator must notify the Commission on the first working day following the observation, obtain Commission approval of a plan for corrective action, and when an USDW is not endangered, obtain Commission approval to continue injection. Rule 7 Plugging and Abandonment of Fluid Injection Wells An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission in accord- ance with 20 AAC 25.105. Rule 8 Administrative Relief Upon request, the Commission may administratively amend any rule stated above as long as the operator demonstrates to the Com- mission's satisfaction that sound engineering practices are maintained and the amendment will not result in an increased risk of fluid movement into an underground source of drinking water. Area Injection oJltr Page 5 November 20, 1986 No. 12 . DONE at Anchorage, Alaska and dated November 20, 1986. Alaska n, C airman Gas Conservation Commission Lonnie C. Smit Alaska Oil & Gas Commission þ/. W. W. W. Barnwell, Commissioner Alaska Oil & Gas Conservation Commission . ~1r~1rŒ LID~ ~~~~[(~ . AItASIiA. OIL AND GAS CONSERVATION COMMISSION FRANK H. MURKOWSKI, GOVERNOR 333 W. 7'H AVENUE, SUITE 100 ANCHORAGE. ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL AIO 12.001 Mr. Steve Lambert Advising Reservoir Engineer Unocal Alaska P.O. Box 196247 Anchorage, AK 99519-6247 RE: TBF A-19RD (PTD 188-001) Request for Administrative Approval Dear Mr. Lambert: Per Rule 8 of Area Injection Order 12, the Alaska Oil and Gas Conservation Commission ("AOGCC") hereby grants Unocal Alaska ("Unocal")'s October 3, 2006 request for administrative approval to inject water in Trading Bay Field ("TBF") A-19RD. Unocal notified the Commission on July 19, 2006 that TBF A-19RD exhibits tubing- casing pressure communication and that the well had been shut-in. Approval to continue injection for the purpose of performing well integrity diagnostics was granted by sundry number 306-262 on August 15,2006. Unocal has elected to perform no corrective action at this time on TBF A-19RD. Temperature surveys performed as part of the diagnostic testing confirm the injected fluids are exiting the well at the perforations. While there is evidence of fluid movement to sands above the perforations, all injected fluids are contained within the injection interval authorized by AIO 12. Monitoring has shown that pressures are contained within the wellbore. An aquifer exemption is in effect lor all aquifers lying directly below Trading Bay Field [40 CFR 147.102(b)(2)(iv)]. Accordingly, the Commission believes that the well's condition does not compromise overall well integrity so as to threaten the environment or human safety. The Commission's administrative approval to inject in TBF A-19RD is conditioned upon the following: 1. Injection is limited to WATER ONLY; Mr. Steve Lambert November 2, 2006 Page 2 of2 . . 2. Unocal shall monitor and record tubing, Inner annulus, and outer annulus pressures and injection rate daily; 3. Unocal shall submit to the Commission a monthly report of well pressures and injection rates; 4. Unocal shall perform a temperature survey every 2 years in lieu of the mechanical integrity test as outlined in Rule 5 of Ala 12 to demonstrate continued production casing integrity. For purposes of this requirement, the next temperature survey is due no later than September 30, 2008; 5. Unocal shall immediately shut in the well and notify the Commission if there is any change in the well's mechanical condition; and 6. After well shut in due to a change in the well's mechanical condition, Commission approval shall be required to restart injection. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. D Riel T. Seamount, Jr. Commissioner Cathy P. oerster Commi sioner Various Orders . . Subject: Various Orders From: Jody Colombie <jody _ colombie@admin.state.ak.us> Date: Wed, 08 Nov 200608:35:35 -0900 To: undisclosed-recipients:; BCC: , Christine Hansen <c.hansen@iogcc.state.ok.us>, Terrie Hubble <hubblet1@bp.com>, Sondra Stewrnan <StewrnaSD@BP.com>, stanekj <stanekj@unoca1.com>, ecolaw <ecolaw@trustees.org>, trmjrl <trmjrl@aol.com>,jdarlington <jdarlington@forestoil.com>, nelson <knelson@petroleurnnews.com>, cboddy <cboddy@usibelli.com>, Mark Dalton <mark.dalton@hdrinc.com>, Shannon Donnelly <shannon.donnelly@conocophillips.com>, "Mark P. Worcester" <mark.p.worcester@conocophillips.com>, Bob <bob@inletkeeper.org>, wdv <wdv@dnr.state.ak.us>, tjr <tjr@dnr.state.ak.us>, bbritch <bbritch@alaska.net>, mjnelson <mjnelson@purvingertz.com>, Charles O'Donnell <charles.o'dorinell@veco.com>, "Randy L. Skillern" <SkilleRL@BP.com>, "Deborah J. Jones" <JonesD6@BP.co "Steven R. Ro g" <RossbeRS@BP.com>, Lois <lois@inletkeeper.org>, Dan Bross<kuacnews@ .org>, Gordon Pospisil <PospisG@BP.com>, "Francis S. Sommer" <SommerFS@BP.com>, Schultz <Mikel.Schultz@BP.com>, "Nick W. Glover" <GloverNW@BP.com>, "Daryl J. Kleppin" <KleppiDE@BP.com>, "Janet D. Platt" <PlattJD@BP.com>, "Rosanne M. Jacobsen" . <JacobsRM@BP.com>, ddonkel <ddonkel@cfl.rr.com>, mckay <mckay@gci.net>, Barbara F Fullmer <barbara.f.fullmer@conocophillips.com>, Charles Barker <barker@usgs.gov> , doug_schultze <doug_schultze@xtoenergy.com>, Hank Alford <hank.alford@exxonrnobil.com>, Mark Kovac <yesno l@gci.net>, gspfoff <gspfoff@aurorapower.com>, Gregg Nady <gregg.nady@shell.com>, Fred Steece <fred.steece@state.sd.us>, rcrotty <rcrotty@ch2m.com>,jejones <jejones@aurorapower.com>, dapa <dapa@alaska.net>,jroderick <jroderick@gci.net>, eyancy <eyancy@seal-tite.net>, "James M. Ruud" <james.m.ruud@conocophillips.com>, Brit Lively <mapalaska@ak.net>,jah <jah@dnr.state.ak.us>, buonoje <buonoje@bp.com>, Mark Hanley <mark_hanley@anadarko.com>, 10ren_Ieman <loren_Ieman@gov.state.ak.us>, Julie Houle <julie_houle@dnr.state.ak.us>, John W Katz <jwkatz@sso.org>, tablerk <tablerk@unocal.com>, Brady <brady@aoga.org>, Brian Havelock <beh@dnr.state.ak.us>, bpopp <bpopp@borough.kenai.ak.us>, Jim White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exxonrnobil.com>, marty <marty@rkindustrial.com>, ghammons <gharnrnons@aol.com>, rmclean <rmclean@pobox.alaska.net>, rnkm7200 <mkrn 7200@aol.com>, Brian Gillespie <ifbmg@uaa.alaska.edu>, David L Boelens <dboelens@aurorapower.com>, Todd Durkee <TDURKEE@KMG.com>, Gary Schultz <gary_schultz@dnr.state.ak.us>, Wayne Rancier <RANCIER@petro-canada.ca>, Brandon Gagnon <bgagnon@brenalaw.com>, Paul Winslow <pmwinslow@forestoi1.com>, Sharrnaine Copeland <copelasv@bp.com>,. Kristin Dirks <kristin_dirks@dnr.state.ak.us>, Kaynell Zeman <kjzeman@marathonoil.com>, John Tower <John.Tower@eia.doe.gov>, Bill Fowler <Bill_Fowler@anadarko.COM>, Scott Cranswick <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP.com>, Steve Lambe <lambes@unoca1.com>,jack newell <jack.newell@acsalaska.net>, James Scherr <james.scherr@rnrns.gov>, nI617@conocophillips.com, Tim Lawlor <Tim_Lawlor@ak.blm.gov>, Lynnda Kahn <Lynnda_Kahn@fWs.gov>, Jerry Dethlefs <Jerry.C.Dethlefs@conocophillips.com>, crockett@aoga.org, Tamera Sheffield <sheffield@aoga.org>, Jon Goltz <Jon.Goltz@conocophillips.com>, Roger Belman <roger.belman@conocophillips.com>, Mindy Lewis <mlewis@brenalaw.com>, Kari Moriarty <moriarty@aoga.org>, Patty Alfaro <palfaro@yahoo.com>, Jeff <smetankaj@unocal.com>, Todd Kratz <ToddKratz@chevron.com>, Gary Rogers <gary_rogers@revenue.state.ak.us>, Arthur Copoulos <Arthur_Copoulos@dnr.state.ak.us>, Ken <ken@secorp-inc.com>, Steve Lambert <salambert@unocal.com>, Joe Nicks <news@radiokenai.com>, Jerry McCutcheon <susitnahydronow@yahoo.com>, Bill Walker <bill-wwa@ak.net>, Iris Matthews <Iris_Matthews@legis.state.ak.us>, Paul Decker <paul_decker@dnr.state.ak.us>, , Aleutians East 10f2 11/8/2006 8:50 AM Various Orders . . Borough <admin@aleutianseast.org>, Marquerite kremer <marguerite_kremer@dnr.state.ak.us>, , Mike Mason < bbi. >, Garland Robinson <gbrobinson@marathonoi1.com>, Cammy Taylor <Camille_ @l tate.ak.us>, Winton GAubert <winton_aubert@admi .ak.us>, Thomas E Maunder < ma @admin.state.ak.us>, Stephen F Davies <steve_davies in.state.ak.us>, Keith Wiles iles@marathonoi1.com>, Deanna Gamble <dgamble@kakivik.com>, James B Regg <jim_regg@admin.state.ak.us>, Catherine P Foerster <cathy_foe admin.stat s>, Bob <Bob@fairweather.com>, gregory micallef <micallef@clearwire.n , Laura Sillip <laura _ silliphant@dnr.state.ak.us>, David Steingreaber <david.e. steingreaber@exxonrnobi1.com>, akpratts@acsalaska.net, Robert Campbell <Robert.Campbell@reuters.com>, Steve Moothart <steve _ moothart@dnr.state.ak.us>, Anna Raff <anna.raff@dow· ones.com>, Cliff Posey <cliff@posey.org>, Paul Bloom <paul_bloom@m1.com>, , Me Powell <Meghan.Powell@asrcenergy.com>, Temple Davidson <temple _ davidson@dnr.state.ak.us>, Walter Featherly <WFeatherly@PattonBoggs.com>, Cynthia B Mciver <bren _ mciver@admin.state.ak.us> Jody Colombie <iody colombie(cì¿admin.state.ak.us> Special Staff Assistant Alaska Oil and Gas Conservation Commission Department of Administration . Content-Type: application/pdf eno3.pdf . Content-Encodmg: base64 Content-Type: application/pdf aio12-1.pdf Content-Encoding: base64 . Content-Type: application/pdf . co478a-01.pdf . Content-Encodmg: base64 20f2 11/8/2006 8:50 AM Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 John Levorsen 200 North 3rd Street, #1202 Boise, ID 83702 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 North Slope Borough PO Box 69 Barrow, AK 99723 . David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 Ivan Gillian 9649 Musket Bell Cr.#5 Anchorage, AK 99507 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 . Mona Dickens Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 .\p;~ ÖU «\Q. \ \ \ \ i • a o d o o SARAH PALIN, GOVERNOR ALA58A OII, A1~TD GA5 333 W. 7th AVENUE, SUITE 100 CO1~T51RQA`l`IO1~T COMDIISSIOI~T ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL AIO 12.002 Mr. Steve Lambert Sr. Advising Reservoir Engineer Union Oil Company of California PO Box 196247 Anchorage, Alaska 99519-6247 RE: Trading Bay State A-29RD (PTD 202-004) Request for Administrative Approval Dear Mr. Lambert: Per Rule 8 of Area Injection Order 12, the Alaska Oil and Gas Conservation Commission (Commission) hereby grants Union Oil Company of California (Union)'s request for administrative approval to continue water injection in the subject well. Unocal notified the Commission on February 23, 2009 that Trading Bay State A-29RD exhibited a significant pressure increase in the well's tubing-casing annulus. Pressure was detected on February 21, 2009 and the well was immediately shut in pending diagnostic tests. Union submitted a request dated February 25, 2009 to perform a 30-day injection test followed by a static temperature survey to confirm casing integrity. At the Commission's request, Union proceeded with the temperature survey without the 30-day injection. The temperature survey performed on March 18, 2009 confirms the injected fluids are exiting the well at the perforations and all injected fluids are contained within the injection interval authorized by AIO 12. Union also performed a wellhead inspection and confirms that there are no integrity concerns and that pressures are contained within the wellbore. An aquifer exemption is in effect for all aquifers lying directly below Trading Bay Field [40 CFR 147.102(b)(2)(iv)]. Based on the diagnostic test results, Union has elected to perform no corrective action at this time on Trading Bay State A-29RD. The Commission believes that the well's condition does not compromise overall well integrity so as to threaten the environment or human safety. The Commission's administrative approval to inject in Trading Bay State A-29RD is conditioned upon the following: 1. Injection is limited to WATER ONLY; AIO 12.002 March 23, 2009 Page 2 of 2 7 • • 2. Union shall monitor and record tubing, inner annulus, and outer annulus pressures and injection rate daily; 3. Union shall submit to the Commission a monthly report of well pressures and injection rates; 4. Union shall perform a temperature survey at intervals not to exceed every 2 years in lieu of the mechanical integrity test as outlined in Rule 5 of AIO 12 to demonstrate continued production casing integrity; 5. Union must immediately shut in the well and notify the Commission if there is any change in the well's mechanical condition; and 6. After well shut in due to a change in the well's mechanical condition, Commission approval shall be required to restart injection. The anniversary date for temperature survey is March 18, 2009. DONE at Anchorage, Alaska and dated March 23, 2009. Daniel T. amount, Jr. Cathy P Foer ter Chair RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs unti15:00 p.m. on the next day that does not fall on a weekend or state holiday. Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, March 24, 2009 10:43 AM Subject: aio12-2.pdf -Adobe Acrobat Professional Attachments: aio12-2.pdf BCC:'Anna Raff ; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'Cande.Brandow'; 'carol smyth'; 'Cary Carrigan'; caunderwood@marathonoil.com; 'Charles O'Donnell'; 'Chris Gay'; 'Cliff Posey'; 'Cody Rice'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David Brown'; 'David Gorney'; 'David Hall'; David House; 'David L Boelens'; 'David Steingreaber'; 'ddonkel ;Deborah Jones; 'doug_schultze'; 'Eric Lidji '; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gregg Nady'; 'gspfoff; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James Scherr'; 'Janet D. Platt'; 'jejones'; 'Jerry McCutcheon'; 'Jim Arlington'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing ; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; johnny.aiken@north-slope.org; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; knelson@petroleumnews.com; 'Krissell Crandall'; 'Kristin Dirks'; 'Laura Silliphant'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=fours@mtaonline.net'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; 'Matt Rader'; Melanie Brown; 'Mike Bill'; 'Mike Jacobs'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro ; 'Paul Decker'; 'Paul Winslow'; Pierce, Sandra M (DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'rcrotty'; 'rmclean'; 'Rob McWhorter'; rob.g.dragnich@exxonmobil.com; 'Robert Campbell'; 'Robert Province'; 'Roger Belman'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; Thompson, Nan G (DNR); 'Tim Lawlor'; 'Todd Durkee'; Tony Hopfinger; 'trmjrl'; Von Gemmingen, Scott E (DOR); 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier'; 'Aaron Gluzman'; 'Dale Hoffman'; Fridiric Grenier; 'Gary Orr'; 'Joe Longo'; 'Lamont Frazer'; Marc Kuck; 'Mary Aschoff; Maurizio Grandi; P Bates; Richard Garrard; 'Sandra Lemke'; 'Scott Nash'; 'Steve Virant'; Tom Gennings; 'Willem Vollenbrock ; 'William Van Dyke'; Woolf, Wendy C (DNR); Birnbaum, Alan J (LAW); Crisp, John H (DOA); Davies, Stephen F (DOA); Fleckenstein, Robert J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Mahnken, Christine R (DOA); Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Seamount, Dan T (DOA); Smith, Chasity R (DOA); Williamson, Mary J (DOA) Attachments: aio 12-2.pdf; 3/24/2009 Mary Jones David McCaleb Cindi Walker XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 Mark Wedman Schlumberger Ciri Halliburton Drilling and Measurements Land Department 6900 Arctic Blvd. 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99502 Anchorage, AK 99503 Anchorage, AK 99503 Baker Oil Tools Ivan Gillian Jill Schneider 4730 Business Park Blvd., #44 9649 Musket Bell Cr.#5 US Geological Survey Anchorage, AK 99503 Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow. AK 99723 ~'a./rte/ ~ ~i'~~ THE STATE 'JALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 12.002 CANCELLATION Mr. Larry Greenstein Regulatory Compliance Manager Hilcorp Alaska, LLC. P.O. Box 244027 Anchorage, AK 99524-4027 Re: Docket Number: AIO- 15-054 Request to cancel Area Injection Order (AIO) 12.002 Trading Bay State A-29RD (PTD 2020040) Trading Bay Field Hemlock Oil Pool Dear Mr. Greenstein: By email dated December 30, 2015, Hilcorp Alaska, LLC. (Hilcorp) requested cancellation of administrative approval (AA) Area Injection Order (AIO) 12.002. In accordance with Rule 8 of AIO 12.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS Hilcorp's request to cancel the AA. TBU A-29RD developed a tubing by inner annulus pressure communication in February 2009, and on March 23, 2009 the AOGCC issued AIO 12.002 to the then operator Unocal. AOGCC determined that water injection could safely continue if Unocal complied with the restrictive conditions set out in AA AIO 12.002. Hilcorp has performed an unsuccessful workover and has run a kill string into the well. AA AIO 12.002 is no longer necessary to the operation of A-29RD and is hereby CANCELLED. Injection into A-29RD will be governed by provisions of AIO No. 12.000. AIO 12.002 Cancellation January 7, 2016 Page 2 of 2 DONE at Anchorage, Alaska and dated January 7, 2016. Cathy P Foerster Daniel T. eamount, Jr. Chair, Commissioner Commissioner TION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, January 07, 20161:16 PM To: aogcc.inspectors@alaska.gov; 'Bender, Makana K (DOA) (makana.bender@alaska.gov)'; 'Bettis, Patricia K (DOA) (patricia.bettis@alaska.gov)'; 'Brooks, Phoebe L (DOA) (phoebe.brooks@alaska.gov)'; Carlisle, Samantha J (DOA); 'Colombie, Jody J (DOA) Oody.colombie@alaska.gov)'; 'Davies, Stephen F (DOA) (steve.davies@alaska.gov)'; Eaton, Loraine E (DOA); 'Foerster, Catherine P (DOA) (cathy.foerster@alaska.gov)'; Trystacky, Michal (michal.frystacky@alaska.gov)'; 'Guhl, Meredith (DOA sponsored) (meredith.guhl@alaska.gov)'; Kair, Michael N (DOA); 'Link, Liz M (DOA)'; Loepp, Victoria T (DOA); 'Mumm, Joseph (DOA sponsored) Ooseph.mumm@alaska.gov)'; 'Pa lad ijczuk, Tracie L (DOA) (tracie.paladijczuk@alaska.gov)'; 'Pasqual, Maria (DOA) (maria.pasqual@alaska.gov)'; 'Regg, James B (DOA) Oim.regg@alaska.gov)'; 'Roby, David S (DOA) (dave.roby@alaska.gov)'; 'Schwartz, Guy L (DOA) (guy.schwartz@alaska.gov)'; 'Seamount, Dan T (DOA) (dan.seamount@alaska.gov)'; Singh, Angela K (DOA); 'Wallace, Chris D (DOA) (chris.wallace@alaska.gov)'; 'Aaron Gluzman'; 'Aaron Sorrell'; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Bajsarowicz, Caroline J; Brian Gross; 'Bruce Williams'; Bruno, Jeff J (DNR); Casey Sullivan; David Tetta; Don Shaw; 'Donna Vukich'; Eric Lidji; 'Gary Orr'; 'Graham Smith'; Hak Dickenson; Heusser, Heather A (DNR); Holly Pearen; James Hyun; 'Jason Bergerson'; 'Jim Magill'; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); 'Louisiana Cutler'; Marc Kuck, Marcia Hobson; 'Marie Steele'; Matt Armstrong; 'Mike Franger'; Morgan, Kirk A (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; 'Ryan Daniel'; 'Sandra Lemke'; Sarah Baker; 'Susan Pollard'; Talib Syed; Terence Dalton; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); 'Wayne Wooster'; 'William Van Dyke'; 'AKDCWellIntegrityCoordinator'; 'Alan Bailey'; 'Alex Demarban'; 'Alexander Bridge'; 'Allen Huckabay'; 'Andrew VanderJack'; 'Anna Raff'; 'Barbara F Fullmer'; 'bbritch'; 'Becky Bohrer'; 'Bob Shavelson'; 'Brian Havelock'; 'Bruce Webb'; Burdick, John D (DNR); 'Caleb Conrad'; 'Carrie Wong'; 'Cliff Posey'; 'Colleen Miller'; 'Crandall, Krissell'; 'D Lawrence'; 'Dave Harbour'; 'David Boelens'; 'David Duffy'; 'David House'; 'David McCaleb'; 'David Steingreaber'; 'Davide Simeone'; 'ddonkel@cfl.rr.com'; 'Dean Gallegos'; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); 'Donna Ambruz'; 'Ed Jones'; 'Elowe, Kristin'; 'Evans, John R (LDZX)'; 'Frank Molli'; 'Gary Oskolkosf'; 'George Pollock'; 'Gordon Pospisil'; 'Gregg Nady'; 'gspfoff'; Hyun, James 1 (DNR); 'Jacki Rose'; 'Jdarlington oarlington@gmail.com)'; 'Jeanne McPherren'; 'Jennifer Williams'; 'Jerry Hodgden'; 'Jerry McCutcheon'; 'Jessica Solnick'; 'Jim Watt'; 'Jim White'; 'Joe Lastufka'; 'Joe Nicks'; 'John Adams'; 'John Easton'; 'Jon Goltz'; 'Juanita Lovett'; 'Judy Stanek'; 'Julie Houle'; 'Julie Little'; 'Kari Moriarty'; 'Kazeem Adegbola'; 'Keith Wiles'; 'Kelly Sperback'; 'Laura Silliphant (laura.gregersen@alaska.gov)'; 'Leslie Smith'; 'Lisa Parker'; 'Luke Keller'; 'Marc Kovak'; 'Mark Dalton'; 'Mark Hanley (mark.hanley@anadarko.com)'; 'Mark Landt'; 'Mark Wedman'; 'Marguerite kremer (meg.kremer@alaska.gov)'; 'Mary Cocklan-Vendl'; 'Michael Calkins'; 'Michael Duncan'; 'Michael Moora'; 'Mike Bill'; 'Mike Mason'; 'Mike) Schultz'; 'MJ Loveland'; 'mkm7200'; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); 'nelson'; 'Nichole Saunders'; 'Nick W. Glover'; 'Nikki Martin'; 'NSK Problem Well Supv'; Patty Alfaro; 'Paul Craig'; Paul Decker (paul.decker@alaska.gov); 'Paul Mazzolini'; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; 'Renan Yanish'; 'Richard Cool'; 'Robert Brelsford'; 'Ryan Tunseth'; Sara Leverette; 'Scott Griffith'; Shannon Donnelly; Sharmaine Copeland; 'Sharon Yarawsky'; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; 'Stephan Hennigan'; 'Stephanie Klemmer'; Sternicki, To: Oliver R; Steve Moothart (steve.moothart@alaska.gov); 'Suzanne Gibson'; Tamera Sheffield; 'Tania Ramos'; 'Ted Kramer'; Temple Davidson; Teresa Imm; Thor Cutler, -'Tim Mayers'; Todd Durkee; trmjrl; 'Tyler Senden'; Vicki Irwin; Vinnie Catalano Subject: aio12-002 cancellation (Hilcorp) Attachments: aio12-002 cancellation.pdf James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Mr. Larry Greenstein Richard Wagner Darwin Waldsmith Regulatory Compliance Manager P.O. Box 60868 P.O. Box 39309 Hilcorp Alaska, LLC Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 244027 Anchorage, AK 99524-4027 N�2L@ Angela K. Singh STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: THE APPLICATION OF ) Area Injection Order No. 012.003 HILCORP ALASKA, LLC. for ) Administrative Approval to re- ) Trading Bay Field (Southern half) establish FOR Class II non -hazardous ) Monopod Platform fluid injection into well Trading Bay ) Middle Kenai B, C, D, E and Hemlock ST A-12RD (PTD 1710290). ) Oil Pools September 25, 2013 By email dated August 12, 2013, Hilcorp Alaska, LLC (Hilcorp) requested approval to re-establish Enhanced Oil Recovery (EOR) injection operations governed by provisions of the underlying AIO 012.000. The Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS the Hilcorp request for administrative approval to allow the use of Trading Bay ST A-12RD. An annual review of the performance of this injection project is required as outlined below and will be the basis for continuing approval of injection into the well as currently configured. Trading Bay ST A-12RD has been shut-in since April 1984 after a failed MIT indicating tubing by inner annulus communication. The well has been retained since then for future use as an injector, and Hilcorp has now decided that the well can be of benefit to the Trading Bay Field given the recent workover successes and opportunity for increased injection rates. The well has been reported to AOGCC as required, and temperature surveys were performed in 1998, 2002, and 2005 which confirmed that injected fluids were contained within the C sands and there were no indications of cross flow in the wellbore. Hilcorp has indicated that, based on injection performance and Trading Bay Field development plans, the well would be evaluated as a workover candidate within a two year period. Rule 8 of AIO 12.000 allows the AOGCC administratively to amend any rule stated as long as the operator demonstrates to the AOGCC's satisfaction that sound engineering practices are maintained and the amendment will not result in an increased risk of fluid movement into an underground source of drinking water. Finding 4 of AIO 12.000 states that the portion of aquifers beneath the Cook Inlet described by '/4 mile area beyond and lying directly below the Trading Bay Field are exempt, and Finding 5 finds that less stringent requirements for well construction, operation, monitoring, and reporting of injection operations may be more appropriate than would be required when injection occurs into, through, or above portions of aquifers not exempted. AOGCC's approval to continue water injection only is conditioned upon the following: AIO 012.003 September 25, 2013 Page 2 of Z 1. Hilcorp shall re-establish injection and perform a temperature survey after one month of monitoring; 2. Hilcorp shall monitor and record wellhead pressures and injection rate daily; 3. Hilcorp shall submit to AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 4. Hilcorp shall perform a temperature survey every 2 years; 5. Hilcorp shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; 7. Hilcorp shall submit to AOGCC an annual surveillance report evaluating the performance of the FOR injection by April 1st of each year covering injection operations during the previous calendar year. The report shall include data sufficient to characterize the injection operation, including among other information, the following: injection and annuli pressures (i.e. daily average, maximum, and minimum pressures); fluid volumes injected; injection rates; mechanical condition of the injection wells; and integrity of confining layers. An assessment of the applicability of the injection order findings, conclusions, and rules based on actual performance shall be included with the annual performance report; and 8. This administrative approval shall expire 24 months after the effective date shown below unless an extension is approved according to Rule 8 of AIO 12.000. D NE at Anchorage, Alaska dated Septe ber 25, 2013 ..yfi Cath} P. Foerster Daniel T. Seamount, Jr. J Orman, Chair, Commissioner Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the AOGCC by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Singh, Angela K (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, September 25, 2013 9:16 AM To: Singh, Angela K (DOA); Ballantine, Tab A (LAW); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Ferguson, Victoria L (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Hunt, Jennifer L (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Bender, Makana K (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Wallace, Chris D (DOA); (michael j.nelson@conocophillips.com); AKDCWeIIIntegrityCoordinator; Alexander Bridge; Andrew VanderJack; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Barron, William C (DNR); Bill Penrose; Bill Walker; Brian Havelock; Burdick, John D (DNR); caunderwood@marathonoil.com; Cliff Posey; Colleen Miller; Crandall, Krissell; D Lawrence; Daryl J. Kleppin; Dave Harbour; Dave Matthews; David Boelens; David Duffy; David Goade; David House; David Scott; David Steingreaber; Davide Simeone; ddonkel@cfl.rr.com; Donna Ambruz; Dowdy, Alicia G (DNR); Dudley Platt; Elowe, Kristin; Evans, John R (LDZX); Francis S. Sommer, Frank Molli; Gary Laughlin; schultz, gary (DNR sponsored); ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; Gregory Geddes; gspfoff; Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren; Jones, Jeffery B (DOA); Jerry McCutcheon; Jim White; Jim Winegarner; Joe Lastufka; news@radiokenai.com; Easton, John R (DNR); John Garing; Jon Goltz; Jones, Jeffrey L (GOV); Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Kaynell Zeman; Keith Wiles; Kelly Sperback; Kiorpes, Steve T; Klippmann; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker; Louisiana Cutler, Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark P. Worcester; Kremer, Marguerite C (DNR); Michael Jacobs (michael.w Jacobs@p66.com); Mike Bill; mike@kbbi.org; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; knelson@petroleumnews.com; Nick W. Glover; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Pioneer; Randall Kanady; Randy L. Skillern; Randy Redmond; Rena Delbridge; Renan Yanish; Robert Brelsford; Robert Campbell; Ryan Tunseth; Sandra Haggard; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Moothart, Steve R (DNR); Steven R. Rossberg; Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer; Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler; Tim Mayers; Tina Grovier (tmgrovier@stoel.com); Todd Durkee; Tony Hopfinger; trmjrl; Vicki Irwin; Walter Featherly; yjrosen@ak.net; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Anne Hillman; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; David Lenig; David Martin; Perrin, Don J (DNR); Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr; Smith, Graham O (PCO); Greg Mattson; Heusser, Heather A (DNR); Holly Pearen; James Rodgers; Jason Bergerson; Jennifer Starck; jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Marc Kuck; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, James M (DNR); Bettis, Patricia K (DOA); Peter Contreras; Pollet, Jolie; Richard Garrard; Ryan Daniel; Sandra Lemke; Pexton, Scott R (DNR); Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Wayne Wooster; Woolf, Wendy C (DNR); William Hutto; William Van Dyke Subject: AIO 12-003 (Hilcorp) (Trading Bay Field) Attachments: aio12 003.pdf • ff JodyJ. Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 W. 7h Avenue Anchorage, Alaska 99501 (907) 793-1221 (907) 276-7542 Easy Peel® Labels i ♦ ® Bend along line to i Use Avery® Template 51600 j �d Paper ® expose Pop-up EdgerM Q AVERY® 51600 ; Trudi Hallett Reservoir Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive Anchorage, AK 99503 1 11 ttiquettes faciles a peler ♦ Repliez a la hachure afin de Utilisez le aabarit AVERY® 51600 Sens Sens de p_ pTM �,o„+ reveler le rebord Po u www.avery.com 1-800-GO-AVERY Easy Peet® Labels i Bend along line to Use Avery® Template 51604D a •eed Paper expose Pop-up EdgeTM 1 ti 1 AAMNY0 596oT,n David McCaleb Penny Vadla IHS Energy Group 399 W. Riverview Ave. GEPS Soldotna, AK 99669-7714 5333 Westheimer, Ste. 100 Houston, TX 77056 Jerry Hodgden Richard Neahring Hodgden Oil Company NRG Associates President G081 h St. Post Office Box 1655 Golden, CO 80401-2433 Colorado Springs, CO 80901 Bernie Karl CIRI K&K Recycling Inc. Land Department Post Office Box 58055 Post Office Box 93330 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Planning Department Richard Wagner Post O Post Office Box 69 Office Box 60868 Barrow, AK 99723 Fairbanks, AK 99706 Jack Hakkila Darwin Waldsmith Post Office Box 190083 Post Office Box 39309 Anchorage, AK 99519 Ninilchik, AK 99639 George Vaught, Jr. Post Office Box 13557 Denver, CO 80201-3557 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Baker Oil Tools 795 E. 94th Ct. Anchorage, AK 99515-4295 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 James Gibbs Post Office Box 1597 Soldotna, AK 99669 Irtiquettes faciles a peter i I& ffepliez a to haehure a#in de o- -_tom_ :a A%1VnW0 eew:® -Sensde »e..gh.:e.•et,....d e..w_...SM wwwavery.com ; 9_4Ari_r!L_AIICDV THE STATE °fALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gcv ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 12.003 CANCELLATION Mr. Larry Greenstein Regulatory Manager Hilcorp Alaska, LLC. P.O. Box 244027 Anchorage, AK 99524-4027 Re: Docket Number: AIO-15-009 Request to cancel Area Injection Order 12.003 Trading Bay ST A-12RD (PTD 1710290) Trading Bay Field (TBF) (Southern half) Monopod Platform Middle Kenai B, C, D, E and Hemlock Oil Pools Dear Mr. Greenstein: By letter dated February 17, 2015, Hilcorp Alaska, LLC. (Hilcorp) requested cancellation of administrative approval Area Injection Order (AIO) 12.003. In accordance with Rule 8 of AIO 12, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS the Hilcorp request to cancel the AA. A-12RD developed a tubing by inner annulus communication in 1984 and the well was shut in. However, in 2013 the AOGCC determined that water injection could safely continue if Hilcorp complied with the restrictive conditions set out in AIO 12.003. Hilcorp has performed a rig workover of A-12RD completed in February 2015 which repaired the tubing by inner annulus communication. A passing AOGCC witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) was achieved on February 11, 2015. AIO 12.003 is no longer necessary to the operation of A-12RD and is hereby CANCELLED. Injection into A- 12RD will be governed by provisions of AIO 12. AIO 12.003 Cancellation February 20, 2015 Page 2 of 2 DONE at Anchorage, Alaska and dated February 20, 2015. 24 �2 Cathy P Foerster Chair, Commissioner � f Michael Gallagher Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Singh. Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Friday, February 20, 2015 11:33 AM To: AKDCWellIntegrityCoordinator, Alexander Bridge; Allen Huckabay; Andrew Vandedack, Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Bill Penrose; Bill Walker; Bob Shavelson; Brian Havelock; Burdick, John D (DNR); Carrie Wong; Cliff Posey; Colleen Miller, Corey Cruse; Crandall, Krissell; D Lawrence; Dave Harbour, David Boelens; David Duffy; David Goade; David House; David McCaleb; David Scott; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallego; Delbridge, Rena E (LAS); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Francis S. Sommer; Frank Molli; Gary Oskolkosf, George Pollock; ghammons; Gordon Pospisil; Greg Duggin; Gregg Nady; gspfoff, Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW); Jim Watt; Jim White; Joe Lastufka; news@radiokenai.com; John Adams; Easton, John R (DNR); Jon Goltz, Jones, Jeffrey L (GOV); Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty, Keith Wiles; Kelly Sperback; Klippmann; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker, Louisiana Cutler, Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Michael Duncan; Michael Jacobs; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; MJ Loveland; mjnelson; mkm7200; Morones, Mark P (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly, Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler; Tim Mayers; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Walter Featherly; yjrosen@ak.net; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater; Anne Hillman; Bruce Williams; Bruno, Jeff J (DNR); Caroline Bajsarowicz; Casey Sullivan; Diane Richmond; Dickenson, Hak K (DNR); Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr, Smith, Graham O (PCO); Greg Mattson; Hans Schlegel; Heusser, Heather A (DNR); Holly Pearen; lames Rodgers; Jason Bergerson; Jennifer Starck; jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Bettis, Patricia K (DOA); Peter Contreras; Richard Garrard; Robert Province; Ryan Daniel; Sandra Lemke; Pexton, Scott R (DNR); Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, William Hutto; William Van Dyke; Ballantine, Tab A (LAW); Bender, Makana K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Gallagher, Mike (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Hunt, Jennifer L (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA) Subject: AIO 12.003 Cancellation (Trading Bay Field) Attachments: aio12-003 cancellation.pdf Please see attached. Samantha Carlisle Executive Secretary II Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 (phone) (907) 276-7542 (fax) CONFIDENTMLITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Samantha Carlisle at (907) 793-1223 or Samantha.Carlisle@alaska.gov. James Gibbs Jack Hakkila Bernie Karl Post Office Box 1597 Post Office Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 Post Office Box 58055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. Post Office Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Mr. Larry Greenstein Richard Wagner Darwin Waldsmith Regulatory Manager Post Office Box 60868 Post Office Box 39309 Hilcorp Alaska, LLC. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 244027 Anchorage, AK 99524-4027 Noka c�-&- C%jZ'r c 2c—:i, 2�\ Angela K. Singh THE STATE fALASKA GOVERNOR BILL WALKER Mr. Larry Greenstein Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 12.004 Regulatory Compliance Manager Hilcorp Alaska, LLC. P.O. Box 244027 Anchorage, AK 99524-4027 Re: Docket Number: AIO-16-005 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Request for administrative approval to allow well Trading Bay ST A-25RD (PTD 1881370) to be online in water only injection service with known tubing by inner annulus communication. Trading Bay ST A-25RD (PTD 1881370) Trading Bay Field (Southern Half Monopod Platform) Middle Kenai C and D Oil Pools Dear Mr. Greenstein: By email dated February 9, 2016, Hilcorp Alaska, LLC. (Hilcorp) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 8 of Area Injection Order (AIO) 012.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS the Hilcorp request for administrative approval to continue water only injection in the subject well. Hilcorp reported a potential tubing by inner annulus pressure communication to AOGCC in November 2015 while performing an acid stimulation to increase injectivity in the well. Hilcorp shut in the well and performed diagnostics including a static and injecting temperature survey. The surveys demonstrated fluid entry is below the packer to the perforations. Reported results of Hilcorp diagnostic procedures and wellhead pressure trend plots indicate that injection is confined to the authorized zone. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. Hilcorp has indicated that, based on injection performance and Trading Bay Field development plans, the well would be evaluated as a workover candidate within a 12 month period. Rule 8 of AID 12.000 allows the AOGCC to administratively amend any rule stated as long as the operator demonstrates to the AOGCC's satisfaction that sound engineering practices are maintained and the amendment will not result in an increased risk of fluid movement into an underground source of drinking water. Finding 4 of AIO 12.000 states that the portion of aquifers beneath the Cook Inlet described by 1/4 mile area beyond and lying directly below the Trading Bay Field are exempt, and Finding 5 AIO 12.004 February 26, 2016 Page 2 of 2 finds that less stringent requirements for well construction, operation, monitoring, and reporting of injection operations may be more appropriate than would be required when injection occurs into, through, or above portions of aquifers not exempted. AOGCC's approval to continue water injection only in Trading Bay ST A-25RD is conditioned upon the following: 1. Hilcorp shall record wellhead pressures and injection rate daily; 2. Hilcorp shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. Hilcorp shall perform a temperature survey every 2 years; 4. Hilcorp shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 5. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; 6. Hilcorp shall submit to AOGCC an annual surveillance report evaluating the performance of the FOR injection by April 1st of each year covering injection operations during the previous calendar year. The report shall include data sufficient to characterize the injection operation, including among other information, the following: injection and annuli pressures (i.e. daily average, maximum, and minimum pressures); fluid volumes injected; injection rates; mechanical condition of the injection wells; and integrity of confining layers. An assessment of the applicability of the injection order findings, conclusions, and rules based on actual performance shall be included with the annual performance report; and 7. This administrative approval shall expire 12 months after the effective date shown below unless an extension is approved according to Rule 8 of AIO 12.000. DONE at Anchorage, Alaska and dated February 26, 2016. Cathy . Foerster Chair, Commissioner Daniel T. eamount, Jr. Commissioner RECONSIDERA NOTICE OIL q,\ As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Carlisle, Samantha J (DOA) From: Carlisle, Samantha J (DOA) Sent: Monday, February 29, 2016 8:09 AM To: AKDCWellIntegrityCoordinator, Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Amanda Tuttle; Andrew Vandedack; Anna Raff; Barbara F Fullmer, bbritch; Becky Bohrer; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Caleb Conrad; Carrie Wong; Cliff Posey; Colleen Miller; Crandall, Krissell; D Lawrence; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David Steingreaber; David Tetta; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; Gordon Pospisil; Gregg Nady; gspfoff, Hyun, James J (DNR); Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jerry McCutcheon; Jim Watt; Jim White; Joe Lastufka; Joe Nicks; John Easton; Jon Goltz; Juanita Lovett; Judy Stanek; Julie Houle; Julie Little; Karen Thomas; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Laura Silliphant (laura.gregersen@alaska.gov); Leslie Smith; Louisiana Cutler; Luke Keller, Marc Kovak; Mark Dalton; Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Marquerite kremer (meg.kremer@alaska.gov); Mary Cocklan-Vendl; Mealear Tauch; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); nelson; Nichole Saunders; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Paul Craig; Paul Decker (paul.decker@alaska.gov); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly, Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Stephen Hennigan; Steve Moothart (steve.moothart@alaska.gov); Suzanne Gibson; Tamera Sheffield; Tania Ramos; Ted Kramer; Temple Davidson; Terence Dalton; Teresa Imm; Thor Cutler; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Caroline Bajsarowicz; Casey Sullivan; Diane Richmond; Don Shaw; Donna Vukich; Eric Lidji; Graham Smith; Hak Dickenson; Heusser, Heather A (DNR); Holly Pearen; Jason Bergerson; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez•, Lois Epstein; Longan, Sara W (DNR); Marc Kuck, Marcia Hobson; Marie Steele; Matt Armstrong; Mike Franger; Morgan, Kirk A (DNR); Pat Galvin; Patricia Bettis; Pete Dickinson; Peter Contreras; Richard Garrard; Robert Province; Ryan Daniel; Sandra Lemke; Susan Pollard; Talib Syed; Terence Dalton; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, William Van Dyke; Ballantine, Tab A (LAW) (tab.ballantine@alaska.gov); Bender, Makana K (DOA) (makana.bender@alaska.gov); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA) (phoebe.brooks@alaska.gov); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA) Oody.colombie@alaska.gov); Cook, Guy D (DOA); Davies, Stephen F (DOA) (steve.davies@alaska.gov); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA) (cathy.foerster@alaska.gov); Frystacky, Michal (michal.frystacky@alaska.gov); Grimaldi, Louis R (DOA) (lou.grimaldi@alaska.gov); Guhl, Meredith (DOA sponsored) (meredith.guhl@alaska.gov); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA) (Jeff Jones@alaska.gov); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored) Ooseph.mumm@alaska.gov); Noble, Robert C (DOA) (bob.noble@alaska.gov); Paladijczuk, Tracie L (DOA) (tracie.palad ijczuk@alaska.gov); Pasqual, Maria (DOA) (maria.pasqual@alaska.gov); Quick, Michael J (DOA); Regg, James B (DOA) Oim.regg@alaska.gov); Roby, David S To: (DOA) (dave.roby@alaska.gov); Scheve, Charles M (DOA) (chuck.scheve@alaska.gov); Schwartz, Guy L (DOA) (guy.schwartz@alaska.gov); Seamount, Dan T (DOA) (dan.seamount@alaska.gov); Singh, Angela K (DOA) (angela.singh@alaska.gov); Wallace, Chris D (DOA) (chris.wallace@alaska.gov) Subject: Area Injection Order 12.004 (TBF, Hilcorp) Attachments: aio012-004.pdf Please see attached. Samantha Carlisle E'Ac;cutive Secretary IiI Alaska Oil and C;as ('onservation Cbminnission 333 West 7" , Avenue LAnC'1tc}Yc14ye A ' 99501. (907) 793-1223 CONEIDENTIALRY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGC.C), State of Alaska and is for the sole use: of the intended recipient(s). It may contain confidential and/or privileged .information. The unauthorized review, use or disclosure of such .information may violate state or federal law. If. you are an unintended recipient of this e-mail, please delete .it, without .first saving or forwarding it, and, so that the AOGCC is aware. of the mistake in sending it to you, contact Samantha Carlisle at (907) 793-1223 or Samantha.CxrrhsleCa)alaska.i*ov, James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar C'r. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Mr. Larry Greenstein Richard Wagner Darwin Waldsmith Regulatory Compliance Manager P.O. Box 60868 P.O. Box 39309 Hilcorp Alaska, LLC Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 244027 Anchorage, AK 99524-4027 �e L ehc�2cY 2�� 2ollQ Angela K. Singh THE STNFE °fALASKA GOVERNOR NIIKL DUNIA AV'Y Ms. Julie Wellman Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 12.005 Regulatory Tech Hilcorp Alaska, LLC. 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 Re: Docket Number: AIO-20-027 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alasko.gov Request for administrative approval to allow well Trading Bay ST A-12RD (PTD 1710290) to be online in water only injection service with a known tubing by inner annulus (TxIA) pressure communication. Trading Bay ST A-12RD (PTD 1710290) Trading Bay Field, Monopod Platform Middle Kenai C Oil Pool Dear Ms. Wellman: By email dated November 23, 2020, Hilcorp Alaska, LLC (Hilcorp) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 8 of Area Injection Order (AIO) 12.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS Hilcorp's request for administrative approval to continue water only injection in the subject well. On November 16, 2020, Hilcorp reported that the well had potential TxIA pressure communication while on water injection. Hilcorp was granted time to complete diagnostics and monitoring including a static shut in temperature survey performed on November 20, 2020. The temperature survey demonstrates that the injected fluids are exiting the casing below the packer at the perforations into the approved injection intervals. Reported results of Hilcorp diagnostic procedures and wellhead pressure trend plots indicate that injection is confined to the authorized zone. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. Rule 8 of AIO 12.000 allows administrative amendment of any rule stated as long as the operator demonstrates to the AOGCC's satisfaction that sound engineering practices are maintained and the amendment will not result in an increased risk of fluid movement into an underground source of drinking water. Finding 4 of AIO 12.000 states that the portion of aquifers beneath the Cook Inlet described by V4 mile area beyond and lying directly below the Trading Bay Field are exempt, and Finding 5 finds that less stringent A10 12.005 December 9, 2020 Page 2 of 2 requirements for well construction, operation, monitoring, and reporting of injection operations may be more appropriate than would be required when injection occurs into, through, or above portions of aquifers not exempted. AOGCC's approval to continue water injection only in A-12RD is conditioned upon the following: 1. Hilcorp shall record wellhead pressures and injection rate daily; 2. Hilcorp shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. Hilcorp shall perform a temperature survey every 2 years to confirm injection is confined to the authorized injection zone; 4. Hilcorp shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 5. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection. 6. Hilcorp shall submit to AOGCC an annual surveillance report evaluating the performance of the EOR injection by April 1" of each year covering injection operations during the previous calendar year. The report shall include data sufficient to characterize the injection operation, including among other information, the following: injection and annuli pressures (i.e. daily average, maximum, and minimum pressures); fluid volumes injected; injection rates; mechanical condition of the injection wells; and integrity of confining layers. An assessment of the applicability of the injection order findings, conclusions, and rules based on actual performance shall be included with the annual performance report; and 7. The anniversary date for the temperature survey is November 20, 2020. DONE at Anchorage, Alaska and dated December 9, 2020. Jerem Clammy Mgned by Y lergemym.h.e M. Price ..",000 Jeremy M. Price Chair, Commissioner Daniel T. ft.Ryn. pwn.l i.5eemouMl,. Seamount,Jr. .2.030.12°9&3tr56 Daniel T. Seamount, Jr. Commissioner Jessie L. Digitally signed by Jessie L ChnnielowsId Chmielowski Date:2020.12.10 W.." so on00' Jessie L. Chmielowski Commissioner As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which can the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 12.005 CANCELATION Mr. Daniel Marlowe CIO Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket Number: AIO-25-010 Request to cancel Area Injection Order (AIO) 12.005 Trading Bay ST A-12RD (PTD 1710290), Middle Kenai C Oil Pool Dear Mr. Marlowe: By letter dated March 13, 2025, Hilcorp Alaska, LLC (Hilcorp) requested cancelation of administrative approval (AA) AIO 12.005. In accordance with 20 AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS Hilcorp’s request to cancel the AA. Hilcorp reported a tubing by inner annulus (TxIA) pressure communication to AOGCC on November 16, 2020. On December 9, 2020, AOGCC issued AIO 12.005. AOGCC determined that water only injection could safely continue if Hilcorp complied with the restrictive conditions set out in the AA. Hilcorp has repaired the well under Sundry 325-049 and converted the well from injection to production. AA AIO 12.005 is hereby CANCELED. DONE at Anchorage, Alaska and dated April 10, 2025. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.10 14:08:49 -08'00' Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.04.10 15:04:08 -08'00' AIO 12.005 Cancellation April 10, 2025 Page 2 of 2 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order 12.005 Cancelation (Hilcorp) Date:Friday, April 11, 2025 6:33:10 AM Attachments:AIO12.005 Cancelation.pdf Docket Number: AIO-25-010 Request to cancel Area Injection Order (AIO) 12.005 Trading Bay ST A-12RD (PTD 1710290), Middle Kenai C Oil Pool Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.coldiron@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.coldiron%40alaska.go v Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER 12.006 Mr. Dan Marlowe Operations Manager, Cook Inlet Offshore Hilcorp Alaska, LLC 3800 Centerpoint Dr., Suite 1400 Anchorage, AK 99503 Re: Docket Number: AIO-21-016 Request to include filtered gray water as an approved non-hazardous fluid for EOR injection on the Monopod Platform, Trading Bay Field Trading Bay Field Trading Bay Unit Middle Kenai Oil Pool Hemlock Oil Pool Dear Mr. Marlowe: By email dated June 23, 2021, Hilcorp Alaska LLC (Hilcorp) requested the Alaska Oil and Gas Conservation Commission (AOGCC) grant administrative approval amending Area Injection Order 12 (AIO 12) to include filtered gray water as an allowed non-hazardous fluid for EOR injection. The email described how the platform was to have a new sewage treatment unit installed, an Omnipure membrane bioreactor, that will both treat effluent and filter it to less than one micron. The new unit requires both gray and black water to be combined upstream of the unit, precluding the injection of black water only. Hilcorp provided a water analysis report that included scale predictions based on a mixed fluid stream. Hilcorp also tested the discharge stream from the installed water filtration unit and found no tendencies toward scaling at the expected temperatures of injected fluids. Additionally, Hilcorp tested injection of the combined stream for 9 months into injection well TBF A-12RD, reporting no adverse effects of the combined stream on the injectivity of the injector. A plot of pressures and injection volumes of well TBF A-12RD were provided that support this claim. Adding filtered gray water to the EOR injection fluids is a common practice on the platforms in Cook Inlet and has previously been approved for multiple platforms. It is expected that fluids on the Monopod Platform will behave similarly to the fluids from other Cook Inlet platforms, since they develop the same reservoirs and should have substantially similar EOR fluid properties. AIO 12.006 March 19, 2025 Page 2 of 2 NOW THEREFORE IT IS ORDERED: 1. In accordance with 20 AAC 25.556(d), the AOGCC hereby grants Hilcorp’s request for administrative approval to add filtered gray water to the waterflood EOR injection stream from the Monopod Platform. AIO 12 is hereby amended with the addition of filtered gray water as an allowed non-hazardous fluid for pressure maintenance and EOR purposes into authorized injection strata (as defined in AIO 12, Rule 1) via Monopod’s injection wells. DONE at Anchorage, Alaska and dated March 19, 2025. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.03.19 12:38:10 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.03.19 14:15:09 -08'00' From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order 12.006 (Hilcorp) Date:Wednesday, March 19, 2025 3:11:44 PM Attachments:AIO12.006.pdf Docket Number: AIO-21-016 Request to include filtered gray water as an approved non-hazardous fluid for EOR injection on the Monopod Platform, Trading Bay Field Trading Bay Field Trading Bay Unit Middle Kenai Oil Pool Hemlock Oil Pool Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.coldiron@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.coldiron%40alaska.go v 22 Hilcorp Alaska, LLC Daniel Marlowe, CIO Operations Manager 3800 Centerpoint Dr, Suite 1400 Anchorage, Alaska 99503 March 13, 2025 Commissioners Jessie Chmielowski & Greg Wilson Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: TRADING BAY ST A-12RD (PTD#171029) Request for Cancellation of AIO No. 12.005 Dear Commissioners, Hilcorp Alaska, LLC requests cancelation of AIO No. 12.005 for well A-12RD (PTD #171029) dated December 9, 2020. This administrative approval was granted for continued water injection service with known tubing by inner annulus (TxIA) pressure communication. On March 5, 2025, work was completed under sundry #325-049 to isolate the lower C sands and begin production from the upper B sands. As part of this work the tubing was replaced and passed an MIT-IA to 2,200 psi for 30 min. Due to the TxIA pressure communication on A-12RD being resolved, and the well’s service being changed to production, the cancellation of AIO No. 12.005 is requested. If you have any questions, please call me at 907-283-1329 or Dan Taylor at 907-777-8319. Sincerely, Daniel Marlowe CIO Operations Manager Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2025.04.07 08:40:12 - 08'00' Dan Marlowe (1267) 21 From:Roby, David S (CED) To:Salazar, Grace (CED) Cc:Wallace, Chris D (CED) Subject:FW: Request for Administrative Approval to AIO 12 to add filtered Gray Water to approved injection fluids. Date:Wednesday, June 23, 2021 2:23:32 PM Attachments:AIO 5 001 Sanitary Waste Grayling & Monopod (Unocal).pdf Monopod EI_CWA.pdf TBF A-12RD TIO & Injection data.png Grace, Please docket this and assign it to me. Thanks, Dave Roby (907)793-1232 From: Julie Wellman - (C) <Julie.Wellman@hilcorp.com> Sent: Wednesday, June 23, 2021 2:02 PM To: Roby, David S (CED) <dave.roby@alaska.gov>; Wallace, Chris D (CED) <chris.wallace@alaska.gov> Cc: Erik Mundahl <Erik.Mundahl@hilcorp.com>; Jessica Fisher <jfisher@hilcorp.com> Subject: Request for Administrative Approval to AIO 12 to add filtered Gray Water to approved injection fluids. Hello Dave and Chris, Hilcorp would like to apply for an Administrative Approval to AIO 12 under rule 8 to add filtered gray water to the approved non-hazardous fluids for EOR injection on the Monopod platform. The platform is currently undergoing quarters reconstruction, which will include the installation of a new sewage treatment unit. This unit is a membrane bioreactor, which not only treats the effluent, but the membrane filter will filter the stream to less than one micron. The configuration will include mixing the gray and black water streams upstream of the treatment unit, making it impossible to inject only our treated black water without the gray water included. With the new system, the black water makeup water will consist of potable water instead of the traditional filtered inlet water that is required as the makeup water for the Omnipure unit. Monopod is currently injecting a mixture of treated black and gray water on a temporary basis as required by the temporary quarters’ sanitary waste stream setup. The current stream consists of potable water makeup for the black and gray water streams, which is then combined and mixed with filtered inlet water for operation of the Omnipure. The entire combined discharge stream from the Omnipure unit was tested at the beginning of 2021, and showed no tendencies toward scaling at the temperatures the fluids will see. The scale indices report is attached. There have been no indications of adverse effects of the current injection stream on the performance or injectivity of the TBF A- 12RD well, which is currently the well injecting the treated effluent. A plot of two years of pressures and injection volumes are attached. The temporary quarters were installed in ~Sept 2020, so there is approximately 9 months of injection data of the mixed stream so far. The new, permanent setup will have two changes from the current stream composition: 1) the filtered inlet water will no longer be added as there will no longer be an Omnipure unit and 2) the process stream will be filtered to below one micron before injection. Please let me know if you have any questions or need any more information to assist with your consideration of our request. Thank you, Julie Wellman Regulatory Tech – Hilcorp Alaska, LLC o: 777-8505 | c: 360-265-4397 Julie.Wellman@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 20 mg/L meq/L mg/L meq/L Initial Temperature (°F): 250 13315.7 375.6 7330.0 319.0 Final Temperature (°F): 80 Sulfate (SO42-):1821.3 37.9 Potassium (K+):241.0 6.2 Initial Pressure (psi): 100 Borate (H3BO3):ND Magnesium (Mg2+):735.0 60.5 Final Pressure (psi): 15 Fluoride (F-):ND Calcium (Ca2+):270.0 13.5 Bromide (Br-):ND Strontium (Sr2+):5.4 0.1 Nitrite (NO2-):ND Barium (Ba2+):0.0 0.0 pH at time of sampling:7.1 Nitrate (NO3-):ND 0.8 0.0 pH at time of analysis: NA Phosphate (PO43-):0.8 0.0 Manganese (Mn2+):0.1 0.0 pH used in Calcs: 7.1 Silica (SiO2):3.9 ND 0.4 0.0 mg/L meq/L Bicarbonate (HCO3-):146.0 2.4 Aluminum (Al3+):ND Carbonate (CO32-):ND Chromium (Cr3+):ND Hydroxide (OH-):ND Cobalt (Co2+):ND mg/L meq/L Copper (Cu2+):ND aqueous CO2 (ppm):20.0 ND Molybdenum (Mo2+):ND aqueous H2S (ppm):0.5 ND Nickel (Ni2+):ND aqueous O2 (ppb):ND ND Tin (Sn2+):ND ND Titanium (Ti2+):ND Calculated TDS (mg/L): 23870 ND Vanadium (V2+):ND Density/Specific Gravity (g/cm3):1.0144 Zirconium (Zr2+):ND Measured Specific Gravity ND Lithium (Li):ND Conductivity (mmhos): 35.3 Resistivity: ND Total Hardness:3709 N/A MCF/D:No Data BOPD:No Data BWPD: No Data Anion/Cation Ratio: 1.04 SCALE PREDICTIONS BASED ON FIELD PROVIDED DATA; FUTHER MODELING MAY BE REQUIRED FOR VALIDATION OF SCALE PREDICTION RESULTS. Temp Press. Index Amt (ptb) Index Amt (ptb) Index Amt (ptb) Index Amt (ptb) 80°F 15 psi -0.19 0.000 -0.30 0.000 -0.85 0.000 -1.12 0.000 99°F 24 psi -0.35 0.000 -0.23 0.000 -0.84 0.000 -1.03 0.000 118°F 34 psi -0.49 0.000 -0.13 0.000 -0.82 0.000 -0.93 0.000 137°F 43 psi -0.60 0.000 -0.02 0.000 -0.80 0.000 -0.83 0.000 156°F 53 psi -0.69 0.000 0.10 2.774 -0.78 0.000 -0.72 0.000 174°F 62 psi -0.76 0.000 0.23 6.108 -0.77 0.000 -0.61 0.000 193°F 72 psi -0.82 0.000 0.35 9.417 -0.76 0.000 -0.49 0.000 212°F 81 psi -0.87 0.000 0.49 12.856 -0.76 0.000 -0.38 0.000 231°F 91 psi -0.91 0.000 0.62 16.150 -0.76 0.000 -0.27 0.000 250°F 100 psi -0.95 0.000 0.76 19.218 -0.76 0.000 -0.15 0.000 Temp Press. Index Amt (ptb) Index Amt (ptb) Index Amt (ptb) Index Amt (ptb) 80°F 15 psi -0.89 0.000 -2.83 0.000 -0.65 0.000 -1.24 0.000 99°F 24 psi -0.88 0.000 -2.85 0.000 -0.72 0.000 -1.11 0.000 118°F 34 psi -0.86 0.000 -2.87 0.000 -0.73 0.000 -0.95 0.000 137°F 43 psi -0.82 0.000 -2.88 0.000 -0.70 0.000 -0.80 0.000 156°F 53 psi -0.78 0.000 -2.88 0.000 -0.67 0.000 -0.65 0.000 174°F 62 psi -0.74 0.000 -2.88 0.000 -0.61 0.000 -0.51 0.000 193°F 72 psi -0.68 0.000 -2.88 0.000 -0.56 0.000 -0.38 0.000 212°F 81 psi -0.63 0.000 -2.87 0.000 -0.48 0.000 -0.26 0.000 231°F 91 psi -0.57 0.000 -2.86 0.000 -0.40 0.000 -0.14 0.000 250°F 100 psi -0.51 0.000 -2.85 0.000 -0.33 0.000 -0.04 0.000 Note 1: When assessing the severity of the scale problem, both the saturation index (SI) and amount of scale must be considered Note 2: Precipitation of each scale is considered separately. Total scale will be less than the sum of the amounts of the eight (8) scales. Note 3: Saturation Index predictions on this sheet use pH and alkalinity; %CO2 is not included in the calculations. DISTRICT:ALASKA SAMPLE ID:202106002705 Pacific Coast Area Laboratory 3901 Fanucchi Way E, Shafter, California 93263 REPORT DATE: 3/22/2021 COMPLETE WATER ANALYSIS REPORT SSP v.2021 CUSTOMER:HILCORP ALASKA, LLC ACCOUNT REP:COLIN T RATTERREE AREA/LEASE:MONOPOD PLATFORM SAMPLE DATE:1/28/2021 SAMPLE POINT NAME M-CC-0402 ANALYSIS DATE:3/19/2021 Chloride (Cl-): Sodium (Na +): SITE TYPE: ANALYST:SR/IL SAMPLE POINT DESCRIPTION:DISCHARGE HILCORP ALASKA, LLC, MONOPOD PLATFORM, M-CC-0402 FIELD DATA ANALYSIS OF SAMPLE ANIONS: CATIONS: ND = Not Determined pH: Iron (Fe2+): Lead (Pb2+): Zinc (Zn2+): ALKALINITY BY TITRATION: ORGANIC ACIDS: Formic Acid: Acetic Acid: Propionic Acid: Butyric Acid: Valeric Acid: Comments: Conditions Barite (BaSO4) Calcite (CaCO3) Gypsum (CaSO4·2H2O) Anhydrite (CaSO4) Conditions Celestite (SrSO4)Halite (NaCl) Iron Sulfide (FeS)Iron Carbonate (FeCO3) SCALE PREDICTIONS BASED ON FIELD PROVIDED DATA; FUTHER MODELING MAY BE REQUIRED FOR VALIDATION OF SCALE PREDICTION RESULTS. SAMPLE ID: 202106002705 HILCORP ALASKA, LLC, MONOPOD PLATFORM, M-CC-0402 0 10 20 30 40 50 60 15 24 34 43 53 62 72 81 91 100 -0.4 -0.2 0.0 0.2 0.4 0.6 0.8 1.0 80 99 118 137 156 174 193 212 231 250 Predicted Precipitation (mg/L)Pressure (psi)Saturation IndexTemperature (F) Calcite (CaCO3) SI mg/L 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 15 24 34 43 53 62 72 81 91 100 -1.0 -0.9 -0.8 -0.7 -0.6 -0.5 -0.4 -0.3 -0.2 -0.1 0.0 80 99 118 137 156 174 193 212 231 250 Predicted Precipitation (mg/L)Pressure (psi)Saturation IndexTemperature (F) Barite (BaSO4) SI mg/L 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 15 24 34 43 53 62 72 81 91 100 -0.9 -0.8 -0.8 -0.8 -0.8 -0.8 -0.7 -0.7 -0.7 80 99 118 137 156 174 193 212 231 250 Predicted Precipitation (mg/L)Pressure (psi)Saturation IndexTemperature (F) Gypsum (CaSO4·2H2O) SI mg/L 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 15 24 34 43 53 62 72 81 91 100 -1.2 -1.0 -0.8 -0.6 -0.4 -0.2 0.0 80 99 118 137 156 174 193 212 231 250 Predicted Precipitation (mg/L)Pressure (psi)Saturation IndexTemperature (F) Anhydrite (CaSO4) SI mg/L 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 15 24 34 43 53 62 72 81 91 100 -1.0 -0.9 -0.8 -0.7 -0.6 -0.5 -0.4 -0.3 -0.2 -0.1 0.0 80 99 118 137 156 174 193 212 231 250 Predicted Precipitation (mg/L)Pressure (psi)Saturation IndexTemperature (F) Celestite (SrSO4) SI mg/L 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 15 24 34 43 53 62 72 81 91 100 -2.9 -2.9 -2.9 -2.9 -2.9 -2.8 -2.8 -2.8 -2.8 80 99 118 137 156 174 193 212 231 250 Predicted Precipitation (mg/L)Pressure (psi)Saturation IndexTemperature (F) Halite (NaCl) SI mg/L 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 15 24 34 43 53 62 72 81 91 100 -0.8 -0.7 -0.6 -0.5 -0.4 -0.3 -0.2 -0.1 0.0 80 99 118 137 156 174 193 212 231 250 Predicted Precipitation (mg/L)Pressure (psi)Saturation IndexTemperature (F) Iron Sulfide (FeS) SI mg/L 0 0 0 0 0 1 1 1 1 1 1 15 24 34 43 53 62 72 81 91 100 -1.4 -1.2 -1.0 -0.8 -0.6 -0.4 -0.2 0.0 80 99 118 137 156 174 193 212 231 250 Predicted Precipitation (mg/L)Pressure (psi)Saturation IndexTemperature (F) Iron Carbonate (FeCO3) SI mg/L 19 Hilcorp Alaska, LLC March 23, 2022 Ms. Jessie Chmielowski Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Trading Bay Field AIO #12 2021 A-12RD Annual EOR Surveillance Report Dear Ms. Chmielowski: Attached for your review is the 2021 Annual EOR Surveillance for the Trading Bay Field water injector according to AIO #12.005. Injection well A-12RD was returned to injection in December 2020 under administrative approval 12.005 to operate the well with a known tubing by inner annulus communication. Injection remains within confining layers based on the November 20, 2020 temperature survey and a relatively constant injectivity index. There has been no change in the well’s mechanical condition since the Administrative Approval and the next temperature survey will be completed by November, 2022 as established by administrative approval 12.005 of AIO 12. Regards, Christopher Kanyer Reservoir Engineer Hilcorp Alaska Exhibit #1 – Daily average injection rates, tubing and annuli pressure plot Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 100 Anchorage, AK 99503 Phone: 907/777-8300 Fax: 907/777-8310 Date Tubing IA OA OOA OOOA Water Injection 12/31/2021 1900 1850 80 108 9 181 12/30/2021 1900 1900 78 109 9 183 12/29/2021 1550 1500 77 109 9 183 12/28/2021 1300 1275 76 108 10 183 12/27/2021 1300 1280 75 108 10 181 12/26/2021 1300 1275 74 108 9 182 12/25/2021 1275 1300 72 108 9 179 12/24/2021 1310 1290 72 108 9 178 12/23/2021 1527 1590 72 108 9 178 12/22/2021 1222 1300 70 109 10 174 12/21/2021 1225 1300 70 110 9 178 12/20/2021 1370 1350 70 110 10 178 12/19/2021 1350 1300 66 109 8 181 12/18/2021 1900 1900 66 109 8 181 12/17/2021 1300 1275 65 108 8 181 12/16/2021 1800 1775 65 107 8 180 12/15/2021 1340 1300 65 107 8 181 12/14/2021 1350 1300 65 106 8 181 12/13/2021 1350 1300 65 105 8 183 12/12/2021 1605 1650 65 105 8 187 12/11/2021 1885 1300 66 105 8 188 12/10/2021 1227 1300 65 105 9 190 12/9/2021 1232 1300 65 105 8 185 12/8/2021 1234 1300 65 105 8 185 12/7/2021 1569 1620 66 104 8 190 12/6/2021 1350 1300 66 103 8 189 12/5/2021 1350 1300 66 103 8 189 12/4/2021 1600 1550 65 103 8 189 Date Range: 01/01/2021 - 12/31/2021 Well: A-12RD Desc: Injection Permit to drill: 1710290 Admin Approval: AIO 12.003 API: 50-733-20076-01-00 12/3/2021 1700 1650 66 101 8 189 12/2/2021 1350 1300 67 102 8 189 12/1/2021 1950 1900 68 100 8 183 11/30/2021 1350 1300 67 100 8 184 11/29/2021 1860 1850 68 100 8 183 11/28/2021 1570 1540 69 99 8 175 11/27/2021 1350 1300 69 99 8 181 11/26/2021 1860 1845 71 100 8 176 11/25/2021 1320 1300 70 98 8 170 11/24/2021 1340 1300 69 98 8 174 11/23/2021 1350 1300 68 99 8 179 11/22/2021 1560 1590 67 100 8 178 11/21/2021 1350 1300 66 100 8 181 11/20/2021 1350 1300 66 100 8 181 11/19/2021 1600 1550 67 98 8 181 11/18/2021 1950 1930 68 97 8 189 11/17/2021 1350 1300 68 98 8 191 11/16/2021 1350 1300 68 98 8 191 11/15/2021 2000 1950 69 98 8 191 11/14/2021 1350 1310 68 90 2 201 11/13/2021 1350 1380 68 97 8 199 11/12/2021 1900 1900 69 98 8 202 11/11/2021 1350 1300 68 97 8 206 11/10/2021 1250 1260 68 97 8 198 11/9/2021 1342 1300 69 97 8 186 11/8/2021 1262 1250 69 96 8 182 11/7/2021 1350 1300 70 96 8 190 11/6/2021 1350 1300 70 96 8 183 11/5/2021 1250 1200 70 96 8 183 11/4/2021 1250 1200 69 96 8 186 11/3/2021 1320 1300 69 96 8 203 11/2/2021 1250 1200 68 96 8 203 11/1/2021 1360 1300 66 96 8 193 10/31/2021 1266 1300 67 95 8 226 10/30/2021 1837 1850 67 95 9 225 10/29/2021 1263 1300 67 95 8 226 10/28/2021 1266 1300 67 95 8 222 10/27/2021 1765 1800 68 95 8 221 10/26/2021 1710 1750 68 95 9 219 10/25/2021 1972 2000 70 94 9 220 10/24/2021 1490 1450 68 93 8 202 10/23/2021 1950 1930 69 92 8 205 10/22/2021 1400 1310 69 92 8 205 10/21/2021 1400 1375 69 92 8 224 10/20/2021 1450 1400 70 93 8 198 10/19/2021 1450 1410 70 93 8 198 10/18/2021 1400 1350 69 91 8 198 10/17/2021 1273 1310 70 90 8 214 10/16/2021 1272 1300 70 90 8 215 10/15/2021 1270 1300 70 90 8 215 10/14/2021 1670 1700 70 90 9 214 10/13/2021 1270 1300 70 90 9 215 10/12/2021 1276 1350 70 90 8 218 10/11/2021 1905 1925 72 90 8 220 10/10/2021 1550 1500 73 90 10 221 10/9/2021 1350 1300 72 89 8 224 10/8/2021 1450 1400 74 89 8 250 10/7/2021 1850 1800 74 89 8 248 10/6/2021 1400 1350 75 88 8 255 10/5/2021 1550 1500 75 88 8 224 10/4/2021 1400 1350 75 86 8 224 10/3/2021 1804 1850 77 88 9 214 10/2/2021 1298 1310 77 88 9 208 10/1/2021 1278 1305 78 87 9 221 9/30/2021 1896 1900 79 87 9 238 9/29/2021 1440 1400 75 87 9 251 9/28/2021 1454 1470 80 87 9 258 9/27/2021 1930 1950 82 87 9 254 9/26/2021 1859 1900 80 90 8 247 9/25/2021 1560 1600 80 90 8 247 9/24/2021 1411 1450 80 90 8 250 9/23/2021 1297 1300 80 90 10 250 9/22/2021 1917 2000 80 85 8 247 9/21/2021 1984 2000 80 85 8 202 9/20/2021 1839 1800 80 85 10 195 9/19/2021 1905 1880 81 85 9 192 9/18/2021 1322 1300 79 84 9 206 9/17/2021 1760 1715 78 85 9 232 9/16/2021 1640 1630 78 85 9 244 9/15/2021 1298 1275 77 86 9 252 9/14/2021 1450 1420 77 87 9 254 9/13/2021 1915 1900 77 87 9 248 9/12/2021 2000 1950 76 89 8 244 9/11/2021 1400 1350 75 89 8 255 9/10/2021 2010 1990 80 90 8 258 9/9/2021 1450 1430 75 90 8 255 9/8/2021 1400 1350 73 91 8 248 9/7/2021 1950 1920 73 91 8 213 9/6/2021 1940 1900 71 92 8 213 9/5/2021 1820 1850 70 93 9 214 9/4/2021 1296 1350 68 95 10 212 9/3/2021 1895 1925 65 95 10 210 9/2/2021 1298 1350 65 95 9 205 9/1/2021 1299 1350 63 96 9 204 8/31/2021 1881 1900 60 95 10 202 8/30/2021 1299 1350 60 97 10 205 8/29/2021 1400 1350 69 96 8 202 8/28/2021 1400 1350 69 96 8 205 8/27/2021 1400 1350 70 97 8 240 8/26/2021 1400 1350 70 97 8 255 8/25/2021 1400 1350 58 97 9 270 8/24/2021 1400 1350 58 97 9 251 8/23/2021 1400 1350 58 97 9 239 8/22/2021 1451 1500 57 97 9 220 8/21/2021 1513 1550 57 97 10 220 8/20/2021 1296 1350 55 95 9 226 8/19/2021 1843 1880 58 95 9 228 8/18/2021 1295 1320 60 95 10 225 8/17/2021 1378 1425 58 95 10 220 8/16/2021 1298 1310 60 95 10 235 8/15/2021 1316 1350 60 95 10 240 8/14/2021 1299 1300 60 95 8 243 8/13/2021 1854 1900 60 95 9 242 8/12/2021 1820 1850 60 95 10 245 8/11/2021 1736 1750 60 95 10 245 8/10/2021 1900 1900 60 95 10 242 8/9/2021 1303 1350 60 90 8 245 8/8/2021 1380 1325 57 94 10 243 8/7/2021 1365 1350 57 94 9 228 8/6/2021 1312 1330 58 95 9 228 8/5/2021 1369 1340 60 94 0 232 8/4/2021 1312 1310 59 94 0 228 8/3/2021 1663 1620 60 93 9 237 8/2/2021 1785 1740 60 93 10 230 8/1/2021 1580 1600 60 90 10 234 7/31/2021 1603 1600 60 95 10 238 7/30/2021 1800 1750 60 93 10 236 7/29/2021 1416 1500 60 95 10 238 7/28/2021 1467 1500 60 95 10 238 7/27/2021 1842 1700 60 95 10 240 7/26/2021 1987 1900 60 95 10 236 7/25/2021 1319 1350 60 95 10 200 7/24/2021 1900 1850 60 95 10 198 7/23/2021 1880 1850 60 95 10 196 7/22/2021 1880 1850 60 95 10 195 7/21/2021 1450 1430 62 95 10 194 7/20/2021 1475 1450 62 95 10 210 7/19/2021 2000 2000 64 95 10 208 7/18/2021 1950 1950 60 95 10 237 7/17/2021 1750 1700 60 95 10 232 7/16/2021 1500 1490 60 95 10 242 7/15/2021 1600 1600 60 95 10 235 7/14/2021 1650 1600 64 95 11 240 7/13/2021 1850 1830 64 95 10 237 7/12/2021 1500 1500 60 100 10 236 7/11/2021 1840 1780 64 98 10 232 7/10/2021 1450 1410 63 99 11 223 7/9/2021 1400 1350 63 99 11 212 7/8/2021 1540 1500 64 100 11 208 7/7/2021 1875 1850 65 100 10 199 7/6/2021 1440 1390 71 100 10 194 7/5/2021 1700 1700 66 101 10 203 7/4/2021 1600 1530 65 100 10 202 7/3/2021 1860 1850 66 101 10 202 7/2/2021 1450 1400 67 105 8 202 7/1/2021 1700 1750 68 103 8 240 6/30/2021 1700 1650 69 103 10 240 6/29/2021 1850 1800 69 104 10 248 6/28/2021 1500 1450 69 104 10 244 6/27/2021 1920 1830 70 105 10 248 6/26/2021 1410 1370 69 106 10 255 6/25/2021 1950 1920 70 107 10 246 6/24/2021 1425 1400 68 108 10 242 6/23/2021 1625 1580 68 108 11 228 6/22/2021 1590 1550 68 109 11 214 6/21/2021 1510 1490 68 110 10 214 6/20/2021 1800 1700 68 110 10 210 6/19/2021 1950 1900 66 106 10 213 6/18/2021 1800 1725 69 107 10 202 6/17/2021 1800 1750 69 106 10 240 6/16/2021 1700 1650 70 105 10 247 6/15/2021 1700 1650 70 110 10 251 6/14/2021 1910 1900 70 107 10 239 6/13/2021 1850 1800 70 110 10 380 6/12/2021 1760 1720 70 110 10 240 6/11/2021 2050 2000 72 110 10 239 6/10/2021 1900 1850 70 110 10 238 6/9/2021 1600 1550 70 110 10 240 6/8/2021 1800 1800 72 110 10 206 6/7/2021 1700 1700 72 110 10 203 6/6/2021 1800 1800 70 110 10 206 6/5/2021 1750 1700 75 110 10 210 6/4/2021 1800 1800 70 110 10 204 6/3/2021 2000 2000 70 110 10 240 6/2/2021 1500 1450 70 110 10 235 6/1/2021 1500 1450 70 115 10 238 5/31/2021 2000 2000 70 115 11 244 5/30/2021 2000 1950 72 115 10 238 5/29/2021 1600 1580 72 115 10 240 5/28/2021 1500 1450 72 115 10 221 5/27/2021 1500 1450 72 115 10 223 5/26/2021 1700 1650 71 115 10 224 5/25/2021 1910 1900 72 115 10 203 5/24/2021 1500 1450 70 118 10 205 5/23/2021 1600 1550 70 118 10 204 5/22/2021 1500 1490 70 118 10 205 5/21/2021 1750 1750 70 118 10 203 5/20/2021 2000 1945 70 119 10 229 5/19/2021 1750 1700 70 119 10 224 5/18/2021 1800 1750 70 120 10 230 5/17/2021 1700 1700 70 120 10 232 5/16/2021 1950 1920 72 120 11 244 5/15/2021 1925 1900 72 120 11 238 5/14/2021 1900 1860 72 121 11 245 5/13/2021 1950 1950 72 121 11 252 5/12/2021 1575 1550 72 120 11 246 5/11/2021 1825 1800 72 120 11 231 5/10/2021 1500 1490 72 120 11 208 5/9/2021 1850 1800 71 120 10 212 5/8/2021 1500 1500 71 120 10 210 5/7/2021 1500 1500 70 120 10 210 5/6/2021 1900 1850 72 120 10 244 5/5/2021 1510 1500 71 120 10 247 5/4/2021 1600 1600 71 120 10 248 5/3/2021 1700 1700 71 120 10 244 5/2/2021 1650 1600 72 120 10 234 5/1/2021 1900 1870 72 120 10 245 4/30/2021 1650 1625 72 120 11 253 4/29/2021 1500 1480 73 120 11 254 4/28/2021 1800 1725 72 120 12 236 4/27/2021 2000 2000 73 120 12 242 4/26/2021 1950 1930 73 121 11 235 4/25/2021 2000 2000 74 120 10 240 4/24/2021 1500 1500 74 120 11 242 4/23/2021 1500 1500 74 120 10 240 4/22/2021 1750 1700 75 120 10 238 4/21/2021 1500 1500 75 120 10 236 4/20/2021 2000 1990 75 120 10 236 4/19/2021 1500 1500 75 122 10 232 4/18/2021 1850 1800 75 120 11 220 4/17/2021 2000 1950 76 120 11 218 4/16/2021 1550 1500 76 120 11 220 4/15/2021 1940 1920 77 120 11 225 4/14/2021 1700 1670 77 120 11 225 4/13/2021 1550 1500 77 120 11 240 4/12/2021 1810 1790 77 120 11 230 4/11/2021 1900 1950 80 120 10 236 4/10/2021 1500 1500 80 120 10 241 4/9/2021 1550 1500 80 120 10 236 4/8/2021 1650 1600 85 130 10 232 4/7/2021 1900 1900 80 120 10 214 4/6/2021 1740 1760 80 125 10 220 4/5/2021 1550 1500 80 125 10 216 4/4/2021 1900 1850 83 125 10 208 4/3/2021 1810 1750 82 125 10 210 4/2/2021 1545 1500 82 125 10 205 4/1/2021 1525 1500 82 128 10 200 3/31/2021 1900 1890 84 128 12 225 3/30/2021 1550 1500 83 128 10 220 3/29/2021 1690 1700 84 130 10 235 3/28/2021 1935 2000 85 130 10 232 3/27/2021 1997 2000 85 130 10 247 3/26/2021 1537 1500 85 130 11 247 3/25/2021 1878 1900 90 135 10 236 3/24/2021 1525 1550 90 135 10 240 3/23/2021 1786 1750 90 135 11 234 3/22/2021 1660 1720 90 135 11 241 3/21/2021 1726 1750 88 135 10 228 3/20/2021 1464 1500 88 135 10 233 3/19/2021 1520 1575 88 135 10 235 3/18/2021 1533 1550 90 135 10 230 3/17/2021 1460 1500 90 138 10 225 3/16/2021 1462 1500 90 138 10 247 3/15/2021 1679 1745 90 135 11 249 3/14/2021 1660 1700 90 135 10 248 3/13/2021 1600 1575 90 135 10 248 3/12/2021 2050 2000 92 134 10 250 3/11/2021 2000 1950 93 135 10 248 3/10/2021 1900 1900 94 135 10 251 3/9/2021 1650 1600 94 135 10 240 3/8/2021 1720 1710 94 132 10 240 3/7/2021 1920 1900 94 132 10 250 3/6/2021 1876 1810 95 130 11 244 3/5/2021 1749 1715 95 134 11 238 3/4/2021 1691 1685 96 135 11 228 3/3/2021 1849 1700 96 135 11 236 3/2/2021 1782 1740 96 135 11 242 3/1/2021 1924 1750 97 135 11 230 2/28/2021 1900 1900 96 135 10 244 2/27/2021 2050 2000 96 135 10 206 2/26/2021 1867 1900 96 135 10 202 2/25/2021 1790 1850 95 135 10 202 2/24/2021 2000 1950 98 136 10 205 2/23/2021 1475 1510 96 136 10 202 2/22/2021 2050 2050 99 139 10 202 2/21/2021 1874 1865 98 137 11 204 2/20/2021 1760 1745 99 138 11 208 2/19/2021 1512 1495 100 138 11 206 2/18/2021 1580 1550 99 137 11 198 2/17/2021 1500 1470 100 138 11 195 2/16/2021 1830 1800 100 138 11 202 2/15/2021 1749 1630 100 138 11 209 2/14/2021 1600 1550 100 137 10 205 2/13/2021 1980 1950 101 136 10 205 2/12/2021 1850 1800 100 138 10 228 2/11/2021 1900 1850 100 136 10 224 2/10/2021 1700 1750 100 135 10 230 2/9/2021 2050 2000 100 135 10 229 2/8/2021 1950 1910 101 165 10 229 2/7/2021 1979 2000 102 135 10 218 2/6/2021 1473 1500 100 134 10 216 2/5/2021 1857 1850 102 134 10 218 2/4/2021 1768 1750 101 134 10 220 2/3/2021 1477 1525 102 135 10 202 2/2/2021 1911 1530 101 137 10 205 2/1/2021 1481 1500 102 140 10 210 1/31/2021 1479 1500 100 140 10 209 1/30/2021 1912 1900 105 140 10 228 1/29/2021 1547 1550 105 140 11 224 1/28/2021 1858 2000 105 140 10 215 1/27/2021 1995 1900 105 140 10 228 1/26/2021 1951 1900 105 140 10 212 1/25/2021 1920 2000 105 145 10 224 1/24/2021 1950 1930 104 144 11 206 1/23/2021 1710 1660 104 145 10 197 1/22/2021 1560 1530 105 146 11 201 1/21/2021 1600 1550 104 148 10 197 1/20/2021 1900 1850 105 150 10 211 1/19/2021 1900 1840 105 152 11 208 1/18/2021 1900 1860 105 154 10 211 1/17/2021 1850 1800 105 155 10 211 1/16/2021 1550 1500 104 155 10 210 1/15/2021 1650 1600 104 155 10 217 1/14/2021 1550 1500 105 155 10 221 1/13/2021 1900 1850 105 155 10 205 1/12/2021 1900 1850 105 155 10 206 1/11/2021 2150 2100 103 149 10 205 1/10/2021 2100 2150 104 148 10 210 1/9/2021 2050 2000 103 147 10 209 1/8/2021 2000 1945 105 147 10 206 1/7/2021 2050 1990 106 150 11 206 1/6/2021 1525 1500 105 152 11 201 1/5/2021 1480 1460 103 153 11 204 1/4/2021 2090 2050 103 153 11 212 1/3/2021 1950 1950 104 155 10 207 1/2/2021 2050 2000 104 155 10 205 1/1/2021 2000 1950 104 155 10 205 Hilcorp Alaska, LLC March 25, 2021 Ms. Jessie Chmielowski Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 Re:Trading Bay Field AIO #12 2020 A-12RD Annual EOR Surveillance Report Dear Ms. Chmielowski: Attached for your review is the 2020 Annual EOR Surveillance for the Trading Bay Field water injector according to AIO #12.005. Injection well A-12RD was returned to injection in December 2020 under administrative approval 12.005 to operate the well with a known tubing by inner annulus communication. Injection remains within confining layers based on the November 20, 2020 temperature survey and a relatively constant injectivity index. There has been no change in the well’s mechanical condition since the Administrative Approval and the next temperature survey will be completed on or before November 20, 2022 as established by administrative approval 12.005 of AIO 12. Regards, Christopher Kanyer Reservoir Engineer Hilcorp Alaska Exhibit #1 – Daily average injection rates, tubing and annuli pressure plot Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 100 Anchorage, AK 99503 Phone: 907/777-8300 Fax: 907/777-8310 Date Tubing IA OA OOA OOOA Water Injection 12/31/2020 1950 1910 104 155 10 206 12/30/2020 2100 2050 104 155 10 205 12/29/2020 1987 1910 105 156 10 202 12/28/2020 1550 1500 101 155 10 202 12/27/2020 2048 2070 102 155 10 198 12/26/2020 2070 2100 101 155 10 200 12/25/2020 2016 2050 102 155 11 197 12/24/2020 2040 2055 102 155 10 202 12/23/2020 2053 2075 101 155 10 199 12/22/2020 1956 2000 103 155 10 198 12/21/2020 1911 2000 100 155 10 196 12/20/2020 1910 2050 100 155 10 198 12/19/2020 1907 2050 100 155 10 199 12/18/2020 1707 1750 100 155 10 220 12/17/2020 2010 2050 100 155 10 213 12/16/2020 1929 2050 100 155 10 215 12/15/2020 1977 2100 100 155 10 234 12/14/2020 2092 2100 100 150 10 232 12/13/2020 2026 2050 101 152 10 192 12/12/2020 1982 2000 101 152 9 191 12/11/2020 2010 2050 102 152 9 190 12/10/2020 2053 2070 102 152 9 192 12/9/2020 2052 2060 102 150 9 194 12/8/2020 2047 2050 102 148 8 192 12/7/2020 1826 1880 102 147 10 188 12/6/2020 1921 2000 100 95 10 197 12/5/2020 1945 2000 100 140 10 194 12/4/2020 1813 2000 100 140 9 191 Date Range: 01/01/2020 - 12/31/2020 Well: A-12RD Desc: Injection Permit to drill: 1710290 Admin Approval: AIO 12.005 API: 50-733-20076-01-00 12/3/2020 2019 1900 100 140 10 194 12/2/2020 1881 2000 105 140 10 205 12/1/2020 1937 1900 100 140 10 198 11/30/2020 1880 1920 100 140 10 198 11/29/2020 1810 2050 103 138 10 186 11/28/2020 1961 1875 103 140 10 192 11/27/2020 1927 1575 103 141 10 197 11/26/2020 1508 1760 103 143 10 199 11/25/2020 1818 1840 105 143 10 201 11/24/2020 1662 1750 102 145 10 203 11/23/2020 1508 1840 102 147 10 211 11/22/2020 1850 1825 102 146 9 213 11/21/2020 1900 1900 105 98 8 350 11/20/2020 1500 1550 102 150 10 395 11/19/2020 2137 2137 100 150 8 366 11/18/2020 2045 2000 100 151 8 202 11/17/2020 2060 2050 99 150 8 202 11/16/2020 2080 2040 97 152 8 198 11/15/2020 2049 2000 95 150 30 180 11/14/2020 1972 1950 96 149 8 186 11/13/2020 1644 1550 95 150 8 194 11/12/2020 1501 1550 94 150 8 184 11/11/2020 1535 1925 93 148 9 178 11/10/2020 2054 2025 92 148 9 186 11/9/2020 2052 2050 92 148 9 190 11/8/2020 1980 1950 90 145 8 202 11/7/2020 2000 1995 90 145 8 202 11/6/2020 2020 2050 90 142 8 202 11/5/2020 2020 2000 90 141 8 202 11/4/2020 2100 2070 89 140 8 198 11/3/2020 2055 2100 87 136 8 181 11/2/2020 2061 2080 87 135 8 181 11/1/2020 2088 2100 86 135 8 182 10/31/2020 2029 2040 86 133 8 183 10/30/2020 2059 2070 86 132 8 182 10/29/2020 2068 2100 86 133 8 193 10/28/2020 1985 2100 85 132 8 195 10/27/2020 2040 1950 85 132 8 194 10/26/2020 2052 1880 85 130 9 195 10/25/2020 2008 2000 85 130 9 199 10/24/2020 2026 2000 85 130 8 197 10/23/2020 1919 1980 84 127 9 200 10/22/2020 2025 1900 70 125 8 200 10/21/2020 2084 1900 80 125 8 199 10/20/2020 2065 1850 80 125 8 195 10/19/2020 1955 1800 80 125 8 197 10/18/2020 2091 1800 80 122 8 176 10/17/2020 2049 1800 79 120 9 180 10/16/2020 2086 1775 78 118 9 184 10/15/2020 1892 1750 78 117 10 0 10/14/2020 2034 1730 78 117 10 177 10/13/2020 2050 1700 78 115 9 180 10/12/2020 1810 1625 77 115 10 172 10/11/2020 1971 1550 80 110 10 197 10/10/2020 1977 1500 75 115 10 199 10/9/2020 1737 1550 75 115 10 197 10/8/2020 1473 1550 75 110 10 197 10/7/2020 2003 1550 75 110 10 184 10/6/2020 2044 1600 73 110 10 184 10/5/2020 1996 1600 70 110 10 191 10/4/2020 1767 1560 72 110 8 185 10/3/2020 1532 1525 70 110 9 186 10/2/2020 1688 1500 70 110 8 185 10/1/2020 2093 1800 68 110 9 186 9/30/2020 2022 1780 68 110 8 180 9/29/2020 2037 1760 67 109 8 182 9/28/2020 1900 1750 66 107 8 182 9/27/2020 2050 1750 66 106 8 186 9/26/2020 2100 1750 66 105 8 184 9/25/2020 2050 1750 67 105 8 185 9/24/2020 2080 1700 66 104 8 184 9/23/2020 2050 1650 69 102 8 183 9/22/2020 2050 1650 69 102 8 183 9/21/2020 1875 1550 69 100 9 187 9/20/2020 1632 1500 69 100 9 184 9/19/2020 1531 1550 69 99 9 180 9/18/2020 1533 1560 70 99 9 176 9/17/2020 1531 1560 71 99 9 180 9/16/2020 1530 1550 70 99 9 182 9/15/2020 1779 1600 70 99 9 178 9/14/2020 1895 1575 70 100 9 188 9/13/2020 1625 1575 70 100 8 184 9/12/2020 1950 1600 70 100 8 183 9/11/2020 1975 1550 70 100 9 190 9/10/2020 1750 1570 72 100 9 187 9/9/2020 1536 1550 72 100 9 187 9/8/2020 1537 1550 73 100 9 189 9/7/2020 1539 1560 73 99 10 190 9/6/2020 1777 1575 73 99 10 184 9/5/2020 1538 1575 73 99 9 180 9/4/2020 1788 1600 73 100 9 184 9/3/2020 1539 1575 74 100 11 176 9/2/2020 1800 1600 74 100 11 185 9/1/2020 1625 1570 73 100 10 181 8/31/2020 1538 1600 75 100 10 187 8/30/2020 2066 1650 75 100 10 187 8/29/2020 1935 1650 73 100 9 189 8/28/2020 1878 1650 75 100 10 187 8/27/2020 1978 1650 75 100 10 187 8/26/2020 1988 1600 75 100 10 190 8/25/2020 1687 1600 70 100 10 188 8/24/2020 1984 1600 70 100 10 190 8/23/2020 2060 1620 73 103 9 180 8/22/2020 1984 1600 72 103 9 182 8/21/2020 1921 1600 72 103 10 180 8/20/2020 1644 1580 72 102 9 180 8/19/2020 1708 1575 72 103 9 181 8/18/2020 1794 1550 71 103 9 180 8/17/2020 1621 1550 72 104 10 182 8/16/2020 1898 1700 70 105 10 184 8/15/2020 1846 1700 70 105 10 187 8/14/2020 1854 1650 70 105 10 186 8/13/2020 1932 1650 70 105 10 184 8/12/2020 2064 1700 70 105 10 183 8/11/2020 2064 1700 70 105 10 183 8/10/2020 1930 1700 70 100 10 186 8/9/2020 2030 1700 72 104 10 175 8/8/2020 1923 1700 73 103 10 181 8/7/2020 1830 1775 73 102 10 172 8/6/2020 2047 1750 74 102 9 177 8/5/2020 1831 1760 74 102 10 180 8/4/2020 2032 1750 75 102 10 182 8/3/2020 1957 1725 76 101 10 178 8/2/2020 2000 1750 76 100 10 185 8/1/2020 1975 1700 87 100 10 187 7/31/2020 1800 1650 85 100 10 187 7/30/2020 1680 1590 80 100 10 184 7/29/2020 1709 1590 80 100 10 183 7/28/2020 1750 1550 80 98 10 183 7/27/2020 1618 1580 82 97 10 183 7/26/2020 1600 1580 83 96 10 180 7/25/2020 1548 1580 83 97 10 180 7/24/2020 1549 1600 83 98 10 180 7/23/2020 1554 1580 82 100 10 181 7/22/2020 1553 1580 82 100 10 181 7/21/2020 1555 1590 82 102 10 180 7/20/2020 1603 1550 81 103 10 180 7/19/2020 1889 1550 82 103 10 181 7/18/2020 1677 1605 82 103 10 182 7/17/2020 1776 1600 81 104 10 181 7/16/2020 1860 1555 82 108 10 184 7/15/2020 1817 1600 81 105 10 182 7/14/2020 1798 1660 81 105 10 182 7/13/2020 1916 1660 81 106 10 184 7/12/2020 1916 1700 81 107 10 182 7/11/2020 1923 1720 82 107 10 184 7/10/2020 2035 1775 82 107 10 182 7/9/2020 1834 1775 83 107 10 190 7/8/2020 1901 1750 84 107 10 192 7/7/2020 1870 1750 85 107 10 190 7/6/2020 1958 1700 90 107 10 188 7/5/2020 1807 1650 86 106 10 180 7/4/2020 1901 1625 85 107 10 184 7/3/2020 1802 1600 90 105 10 180 7/2/2020 1562 1600 90 105 10 184 7/1/2020 1564 1600 90 105 10 182 6/30/2020 1562 1600 90 105 10 180 6/29/2020 1563 1600 90 110 10 188 6/28/2020 1562 1600 90 108 11 177 6/27/2020 1562 1600 91 108 10 181 6/26/2020 1961 1650 92 109 10 176 6/25/2020 1768 1640 92 109 11 185 6/24/2020 1758 1650 93 110 11 194 6/23/2020 1665 1610 95 109 10 188 6/22/2020 1945 1600 96 110 10 182 6/21/2020 1802 1600 100 110 10 190 6/20/2020 1570 1550 100 110 10 192 6/19/2020 1564 1550 100 110 10 190 6/18/2020 1568 1550 100 110 10 194 6/17/2020 1567 1550 100 110 10 192 6/16/2020 1566 1550 100 110 10 194 6/15/2020 1566 1550 100 110 10 190 6/14/2020 1567 1550 103 114 10 194 6/13/2020 1925 1550 104 115 10 194 6/12/2020 1565 1600 105 115 10 192 6/11/2020 1565 1615 105 118 10 188 6/10/2020 1566 1610 105 118 10 190 6/9/2020 1569 1600 105 120 10 192 6/8/2020 1568 1600 105 120 10 194 6/7/2020 1570 1600 105 120 10 192 6/6/2020 1574 1600 105 120 10 196 6/5/2020 1571 1600 105 125 10 197 6/4/2020 1888 1600 105 135 10 194 6/3/2020 1932 1600 105 125 10 194 6/2/2020 1572 1600 110 130 10 197 6/1/2020 1574 1625 108 130 10 196 5/31/2020 1650 1650 110 132 10 194 5/30/2020 1650 1648 110 132 10 196 5/29/2020 1680 1640 110 132 10 197 5/28/2020 1630 1600 110 132 10 190 5/27/2020 1600 1600 105 135 10 193 5/26/2020 1650 1600 108 135 10 195 5/25/2020 1595 1600 107 135 10 196 5/24/2020 1573 1600 105 137 10 198 5/23/2020 1575 1650 105 138 10 196 5/22/2020 1575 1630 105 138 10 194 5/21/2020 1673 1600 105 137 10 194 5/20/2020 1648 1550 105 135 9 192 5/19/2020 1901 1550 105 135 9 196 5/18/2020 1830 1550 105 135 10 0 5/17/2020 1500 1500 107 130 10 0 5/16/2020 2045 1600 110 130 10 0 5/15/2020 2044 1600 110 130 10 192 5/14/2020 1953 1600 108 130 10 180 5/13/2020 1580 1500 110 126 10 199 5/12/2020 1600 1500 110 126 10 198 5/11/2020 1535 1500 110 126 10 195 5/10/2020 1498 1550 110 130 10 197 5/9/2020 1585 1600 110 130 10 195 5/8/2020 1950 1550 110 130 10 195 5/7/2020 1587 1550 110 130 10 194 5/6/2020 1586 1550 115 130 10 178 5/5/2020 1583 1600 115 130 10 180 5/4/2020 1585 1550 115 130 10 177 5/3/2020 1586 1600 116 131 10 175 5/2/2020 1584 1600 117 132 10 169 5/1/2020 1934 1590 117 132 10 166 4/30/2020 1630 1600 117 133 10 170 4/29/2020 1959 1550 118 133 10 178 4/28/2020 1584 1550 118 133 10 168 4/27/2020 1586 1540 118 135 10 175 4/26/2020 1471 1550 120 135 10 180 4/25/2020 1493 1550 120 140 10 186 4/24/2020 1590 1570 119 138 10 182 4/23/2020 1729 1600 120 140 10 184 4/22/2020 1905 1600 120 140 11 184 4/21/2020 1812 1600 120 140 10 178 4/20/2020 1588 1590 120 140 10 172 4/19/2020 1909 1600 121 142 10 174 4/18/2020 1960 1675 120 140 10 169 4/17/2020 1962 1650 121 140 10 184 4/16/2020 1932 1650 122 138 10 170 4/15/2020 1794 1640 123 138 10 178 4/14/2020 1829 1610 124 140 10 173 4/13/2020 1986 1600 124 140 10 180 4/12/2020 1607 1600 125 138 9 185 4/11/2020 1957 1670 125 138 10 185 4/10/2020 1989 1700 125 140 10 184 4/9/2020 1819 1650 126 138 10 186 4/8/2020 1600 1650 127 137 9 182 4/7/2020 1600 1610 128 137 10 180 4/6/2020 1606 1650 130 135 9 186 4/5/2020 1620 1610 135 136 10 192 4/4/2020 1650 1610 135 135 10 181 4/3/2020 1620 1610 132 135 10 187 4/2/2020 1736 1600 135 135 10 190 4/1/2020 1606 1600 135 138 10 185 3/31/2020 1650 1600 135 140 12 188 3/30/2020 1670 1600 135 140 12 185 3/29/2020 1896 1600 136 140 10 180 3/28/2020 1571 1570 137 143 10 185 3/27/2020 1604 1590 137 145 10 191 3/26/2020 1583 1560 138 148 11 193 3/25/2020 1779 1580 137 148 10 190 3/24/2020 1628 1680 136 150 10 192 3/23/2020 1606 1660 137 150 10 190 3/22/2020 1605 1700 137 155 10 185 3/21/2020 1920 1800 138 155 10 185 3/20/2020 1917 1800 138 155 10 200 3/19/2020 1700 1700 140 155 10 194 3/18/2020 1650 1700 140 155 10 192 3/17/2020 1950 1700 140 155 10 190 3/16/2020 2050 1700 139 154 10 190 3/15/2020 1683 1700 145 155 10 187 3/14/2020 1698 1700 140 155 10 189 3/13/2020 1970 1700 140 155 10 187 3/12/2020 1611 1700 140 155 10 185 3/11/2020 1720 1700 140 160 10 184 3/10/2020 1617 1700 140 165 10 188 3/9/2020 1619 1700 145 160 10 187 3/8/2020 1619 1700 143 162 9 174 3/7/2020 1605 1710 142 162 10 162 3/6/2020 1967 1700 142 162 9 170 3/5/2020 1658 1700 141 161 9 0 3/4/2020 1691 1675 142 162 10 168 3/3/2020 2015 1650 142 162 10 182 3/2/2020 2100 1650 144 164 10 178 3/1/2020 2079 1650 140 165 10 187 2/29/2020 2032 1650 145 165 10 186 2/28/2020 1843 1700 145 165 10 187 2/27/2020 1609 1700 145 165 10 187 2/26/2020 1607 1750 145 165 10 185 2/25/2020 2081 1750 145 165 10 185 2/24/2020 2036 1750 145 165 10 184 2/23/2020 1900 1700 142 165 8 184 2/22/2020 1800 1700 144 165 8 180 2/21/2020 1950 1700 140 165 9 186 2/20/2020 1900 1700 140 165 9 180 2/19/2020 1995 1700 140 160 9 190 2/18/2020 2000 1700 140 165 9 198 2/17/2020 1620 1700 140 165 9 192 2/16/2020 1689 1700 145 165 9 190 2/15/2020 2029 1700 145 165 10 192 2/14/2020 1916 1700 142 165 10 196 2/13/2020 1998 1700 147 165 10 194 2/12/2020 1704 1700 147 165 9 180 2/11/2020 1938 1680 148 165 8 184 2/10/2020 1698 1650 149 165 8 180 2/9/2020 2100 1700 150 165 6 181 2/8/2020 1965 1700 150 165 6 190 2/7/2020 2100 1700 150 170 6 187 2/6/2020 1800 1710 150 170 6 182 2/5/2020 1798 1700 155 170 6 189 2/4/2020 1635 1700 150 170 6 185 2/3/2020 1639 1700 150 170 9 180 2/2/2020 1636 1710 150 170 9 184 2/1/2020 1795 1720 150 171 10 180 1/31/2020 1643 1700 150 176 10 176 1/30/2020 1641 1700 150 175 10 180 1/29/2020 1642 1700 150 170 9 182 1/28/2020 1643 1700 150 175 10 176 1/27/2020 1991 1700 150 170 8 180 1/26/2020 1915 1650 152 170 9 174 1/25/2020 1647 1650 152 170 9 158 1/24/2020 1646 1700 152 171 9 171 1/23/2020 2014 1650 152 172 9 180 1/22/2020 1813 1625 152 171 9 168 1/21/2020 1655 1690 153 172 9 182 1/20/2020 1949 1700 153 173 9 174 1/19/2020 1649 1700 150 175 9 186 1/18/2020 1650 1700 150 175 8 185 1/17/2020 1650 1700 150 175 8 186 1/16/2020 1654 1700 150 175 10 187 1/15/2020 1645 1700 150 175 8 184 1/14/2020 2019 1700 150 175 10 184 1/13/2020 2000 1750 146 176 8 181 1/12/2020 2042 1750 146 176 8 170 1/11/2020 2060 1775 146 174 8 182 1/10/2020 2058 1810 146 173 8 168 1/9/2020 1910 1800 146 169 8 187 1/8/2020 2058 1850 147 168 8 177 1/7/2020 2056 1800 146 157 8 186 1/6/2020 1755 1775 147 159 8 182 1/5/2020 2047 1700 145 165 7 187 1/4/2020 2036 1650 145 160 6 190 1/3/2020 1669 1600 145 155 8 190 1/2/2020 1768 1580 148 165 8 186 1/1/2020 2025 1600 145 162 8 196 18 Colombie, Jody J (CED) From: Wallace, Chris D (CED) Sent: Tuesday, December 1, 2020 10:04 AM To: Colombie, Jody 1 (CED) Subject: FW: Monopod A-12RD (PTD #171029) Request for Administrative Approval Attachments: A-12RD 2020 Temp Survey with 2016 overlay.xls Categories: Yellow Category Jody, Can I get a docket number for this Admin Approval application please. Thanks Chris From: Julie Wellman - (C) <Julie.Wellman@hilcorp.com> Sent: Monday, November 23, 2020 3:29 PM To: Wallace, Chris D (CED) <chris.wallace@alaska.gov> Cc: Dan Marlowe <dmarlowe@hilcorp.com>; Katherine O'connor<Katherine.Oconnor@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com> Subject: Monopod A-12RD (PTD #171029) Request for Administrative Approval Hello Chris, To summarize the integrity of the Trading Bay, Monopod A-12RD (PTD #171029) well: -The A-12 well is a FIW injector that was last worked over in February 2015. -The wellhead was tested and passed on 11/17/2020. -TIO plot demonstrates TBG x IA pressure communication (plot below). -A static shut in temp survey was run 11/21/2020 with an overlay of the 2016 baseline (Jan 2016) and the post injection, shut in temp survey (Feb 2016). 2020 Survey with overlay is attached. The overall slope and character of the temp survey overlay demonstrates that the injected water is exiting the casing at the perfs into the approved injection intervals, and is not going into the inner annulus. The character of the 2020 survey shadows the 2016 IPROF temp survey when the well had full integrity. Hilcorp would like to request an Administrative Approval to commence long term water injection in A-12RD with monthly reporting of daily injection volumes / pressures and biennial temperature surveys to confirm that injection is being contained in the authorized EOR strata. At current oil prices and climate, Hilcorp does not envision being able to economically repair the mechanical integrity in this well in the immediate future. Please let me know if anything else is needed to proceed with this request. 2000 1500 1000 500 Lel TBF A 012RD - [50., F — —f-- 08/2020 09/2020 -- Tubing — IA — OA OOA Thank you, Julie The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 2 Hilcorp Well: A-12RD Field: Monopod 11/20/2020 Temperature (Deg. F) e s —13 —95/8" —7" —41/2" x Packer —Press 2020 —Temperature 1-20-16 —Temp 2020 —Temp 2-4-16 Report date: 12/912020 17 Wallace, Chlris D (DOA) From: Wallace, Chris D (DOA) Sent: Wednesday, February 24, 2016 9:58 AM To: 'Trudi Hallett' Cc: Larry Greenstein Subject: RE: A-25RD (PTD No. 188-137) - Monopod Platform, Trading Bay Field Trudi, Thanks for the temp survey. Approved for continued injection while an AA is processed for this well. Thanks and Regards, Chris Wallace Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 71h Avenue Anchorage, AK 99501 (907) 793-1250 (phone) (907) 276-7542 (fax) chris.wallace@alaska.gov CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at 907-793-1250 or chris.wallace@alaska.clov. From: Trudi Hallett [mailto:thallett@hilcorp.com] Sent: Wednesday, February 24, 2016 8:48 AM To: Wallace, Chris D (DOA) Cc: Larry Greenstein Subject: RE: A-25RD (PTD No. 188-137) - Monopod Platform, Trading Bay Field Hello, Chris - Please find the. attached temp surveys performed on the Monopod A-25RD Waterflood Injector. The results are conclusive - in which we don't see a downhole fluid containment issue. Please review and advise if we are able to return the well to injection while the AA is being processed. We really appreciate all your efforts with this matter as it is critical for our waterllood operations. Thank you again! Tr"4 . Trudi Hallett I Operations Engineer Cook Inlet Offshore Asset Teain I Hilcorp Alaska, LLC Hilcorp A Company Built on Energy thal lettAhilcorh.com 0: 907. 777.8323 C: 907.301.665 7 From: Wallace,. Chris D (DOA) [mailto:chris.wallace@alaska.gov] Sent: Wednesday, February 10, 2016 7:54 AM To: Trudi Hallett Cc: Larry Greenstein Subject: RE: A-25RD (PTD No. 188-137) - Monopod Platform, Trading Bay Field Trudi, I approve your plan Steps I, 2, and 3 as described below. Assuming the step 1 and step 3 temperature survey is conclusive of no movement behind pipe / out of authorized injection zone, you are approved to continue water only injection while the administrative approval is processing as per Step 4 of your plan below. Thanks and Regards, Chris Wallace Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7ch AvE!nue Anchorage, AK 99501 (907) 793-1250 (phone) (907) 276-7542 (fax) chris.wallace@alaska.gov CONFIDENTIALITY NOTICE. This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. From: Trudi Hallett [mailto:thallett@hilcorp.corn Sent: Wednesday, February 10, 2016 7:21 AM To: Wallace, Chris D (DOA) Cc: Larry Greenstein Subject: RE: A-25RD (PTD No. 188-137) - Monopod Platform, Trading Bay Field Hi Chris, We would like to workover this well by Q4 of this year. A 12 month expiration should suffice. Thanks - Tr ti' From: Wallace, Chris D (DOA) [mailto:chris.wallace@alaska.gov] Sent: Wednesday, February 10, 2016 7:15 AM To: Trudi Hallett Cc: Larry Greenstein Subject: RE: A-25RD (PTD No. 188-137) - Monopod Platform, Trading Bay Field Trudi, To synchronize your workover schedule with the AA, what is your recommended expiry date for an AA? Thanks and Regards, Chris Wallace Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7ch Avenue Anchorage, AK 99501 (907) 793-1250 (phone) (907) 276-7542 (fax) chris.wallace@alaska.Rov CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at 907-793-1250 or chris.wallace@alaska.aov. From: Trudi Hallett [mailtoahallett@hilcorp.coml Sent: Tuesday, February 09, 2016 2:45 PM To: Wallace, Chris D (DOA) Cc: Larry Greenstein Subject: RE: A-25RD (PTD No. 188-137) - Monopod Platform, Trading Bay Field Understood, Chris. Actually, this well is part of the workover plans later this year. We have a sundry already approved for a full workover. Sundry No. 315-745• (attached) We just need to be able to inject to help keep our waterflood going to A- izRD. This could be a temporary fix to allow injection if you agree. Thanks- Trv4bi From: Wallace, Chris D (DOA)[mailto:chris.wallace@alaska.gov] Sent: Tuesday, February 09, 2016 2:38 PM To: Trudi Hallett Cc: Larry Greenstein Subject: RE: A-25RD (PTD No. 188-137) - Monopod Platform, Trading Bay Field Trudi, My preference is of course to have all wells capable of obtaining a passing MITIA rather than under any Administrative Approval. I would like to hear more explanation of what Hilcorp can do to fix the A-25RD communication rather than move down a temp survey / administrative approval path? My understanding is the platform is about to do some workovers so I am interested to hear why this well is not included or when can it be scheduled along with any alternate injectors? Thanks and Regards, Chris Wallace Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 71h Avenue Anchorage, AK 99501 (907) 793-1250 (phone) (907) 276-7542 (fax) chris.wallace@alaska.gov CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. From: Trudi Hallett [mailto:thallett@hilcorp.com] Sent: Tuesday,, February 09, 2016 1:00 PM To: Wallace, Chris D (DOA) Cc: Larry Greenstein Subject: A-25RD (PTD No. 188-137) - Monopod Platform, Trading Bay Field Hello Chris, Hilcorp would like to begin the Administrative Approval process to return well A-25RD (PTD 188-137) to injection. Well A-25RD, a water injector which was shut-in November 2015 due to possible Tbg — IA communication as seen while performing an acid stimulation job to increase injectivity. A-25 was originally drilled in 1972. The well was completed as a C/D-Zone dual string injector. In 1989, the A-25 was redrilled as a single string C/D injector. The well initially injected rates of over 6,000 bwpd and then stabilized around 2000 bwipd dropping to below i000 bwipd over the last few years. Currently Hilcorp has one active water injector on the Monopod platform (A-12RD, PTD No. 171 — 029) It is imperative with our successful workover program and future drill well plans that we establish reliable and maintainable injection/withdrawal ratios in the Trading Bay Field. Since the shut-in we have performed a few diagnostics: • We tested our wellhead and proved all good there (see attached email). • We also used a D&D finder to find the leak in the tbg — and narrowed the leak to at or below the `XA' sleeve @ 6,494'. • We attempted to run a patch to isolate a leak using the approved sundry no. 316-051. However a slow bleed off occurred after performing our in house MIT to test the patch. (attached) We would like to request your approval to begin the AA process (Administrative Approval). 1. Run a baseline temperature survey. (planned for 2/10/2016 — prior to Rig firing up 2/11/2016) 2. Obtain permission to inject for one month (starting on 3/1 due to rig logistics) until the well has stabilized. 3. Run a temperature survey to demonstrate mechanical integrity by overlay with the baseline survey 4. Obtain Administrative Approval. 5. Monitor well daily, report monthly to AOGCC and repeat temperature surveys every 2 years. Attached for your informational purposes is the current wellbore schematic, wellhead integrity email, pressure chart, Injection Plot, and some correspondence regarding the shut in. Thank you for your consideration and if you have any questions regarding this request, please do not hesitate to contact me at 777-8323 or Larry Greenstein at 777-8322 Thanks- TrvA i. Trudi Hallett I Operations Engineer Cook Inlet Offshore Asset Team I Hilcorp Alaska, LLC Hilcorp A Company Built on Energy thallettAhilcorp.com O: 907.777.8323 C: 907.301.6657 0 ID i 1000 2000 3000 44-1 d G 4000 s a m G 5000 6000 7000 Pressure (psia) 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 8000 50 60 70 80 90 100 110 Temperature (Deg. F) 2-22-16 Pressure - Perfs x Packer 13 3/8" 9 5/8" T' 3 1 /2" 2-22-16 Temp 2-10-16 Temp 120 16 Wallace, Chris D (DOA) From: Larry Greenstein <Ireenstein@hilcorp.com> Sent: Wednesday, December 30, 2015 1:42 PM To: Wallace, Chris D (DOA); Schwartz, Guy L (DOA) Subject: FW: Request to continue injection in A-29RD (PTD# 2020040) until 6-1-15 Attachments: Admin Approval aiol2-2.pdf; A-29RD Schematic 2015-05-15.doc; 10-404 - Monopod - A-29RD Submitted 2015-05-18.pdf Welcome back Chris As you are aware, Chris, the WO on the A-29RD well was ultimately unsuccessful and as such the well has remained shut-in since then. The attached schematic shows this well currently has a kill string installed and we have no plans to 'resurrect' injection into this well using AIO 12.002. As such, Hilcorp requests that the AA for this well be cancelled. The well's pressures will be monitored daily and reported quarterly with the rest of the LTSI (long term shut-in) wells to verify stability of the wellbore. In light of commodity prices, it's doubtful that a WO of this well could meet the economic hurdles in our 2016 budget. If for some reason a WO was approved and was successful, this would also call for the cancellation of AIO 12.002. Let's just make that happen now Thank you Larry From: Wallace, Chris D (DOA) [mailto:chris.wallace@alaska.gov] Sent: Monday, March 16, 2015 8:38 AM To: Larry Greenstein Cc: Schwartz, Guy L (DOA) Subject: FW: Request to continue injection in A-29RD (PTD# 2020040) until 6-1-15 Larry, Thank you for the email and phone conversation. With the critical nature and benefit of the continued injection of this well, AOGCC will permit continued injection for a period ending with the well workover or June 1, 2015 (whichever occurs first). With the workover options being discussed at present, please be advised that a passing MITIA will be required as per AIO 12 Rule 5 for continued injection. A10 12.002 (admin approval on A-29) will be cancelled upon receipt of the Hilcorp request or on AOGCC's own motion. Again, as discussed, AOGCC is looking forward to having all the Hilcorp AA temp survey wells repaired to MITIA compliance status. We look forward to working with Hilcorp on prioritizing well repairs and seeing all these AA's cancelled in an expedient time frame. Thanks and Regards, Chris Wallace Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 71h Avenue Anchorage, AK 99501 (907) 793-1250 (phone) (907) 276-7542 (fax) chris.waIlace Palaska.Rov CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. From: Larry Greenstein[mailto:lgreenstein@hilcorp.com] Sent: Thursday, March 12, 2015 3:50 PM To: Wallace, Chris D (DOA) Subject: Request to continue injection in A-29RD (PTD# 2020040) until 6-1-15 Chris, After failed attempts to obtain the required compliance temp survey by the due date of 3/18/15 (see attached WSR for inability to get downhole), Hilcorp is requesting a continuation of injection for A-29RD until 6-1-15 which would give Hilcorp time to get a WO sundry approved and the rig skidded onto the well to reestablish mechanical integrity. The A-29RD well has been operating on AIO 12.002 (see attached pdf) since 2009 after communication between the tubing and casing was discovered. The biennial compliance temp surveys done in 2011 and 2013 showed continued casing integrity and injected fluids containment. In addition, the monthly rate and pressure reporting on this well haven't shown any secondary loss of containment and/or casing integrity. The A-29RD well injects over half the waterflood fluids on the Monopod platform and without its injection, the waterflood pumps have to be shut down. The WO of this well will repair the last active waivered injection well on the Monopod platform. Although waterflood will have to shut down during the A-29RD WO, this request for continued injection will minimize the overall loss of FOR fluids, especially in the critical Northern Nose section of the McArthur River Field where this well injects its water. The new WO rig schedule is to finish up the current well (A-18), during the rig's move to A-13, do some additional pre -WO diagnostics on A-29RD, complete the A-13 WO, then skid to A-29RD and work it over to reestablish mechanical integrity. The exact timing will depend on getting sundry approval for the A-29RD WO and finishing up the two WOs we do have sundries for, A-18 and A-13. The sundry for the WO on A-29RD is being prepared and will be getting to the State (Guy Schwartz) soon and a heads up e-mail has already been sent to him. As we can't get on the well to beat the 3/18/15 due date for the temp survey and shutting the well in early ahead of the upcoming WO would impact the support of the A-15RD and K-13 producing wells in that Northern Nose section of MRF, Hilcorp requests this continuation of injection until the 6-1-15 date. Please let me know if we can proceed as requested above and feel free to call with any questions about our plans. Larry X8322 Hilearp Alaska, LIX RKB: MSL =33.29 PBTD=13,259' TD=13,300' 43 deg hole angle at TD I Max angle = 47 deg at 5600' MD SCHEMATIC Monopod Platform Well: A-29RD Last Completed: 04/18/15 PTD: 202-004 Casing Detail Size Wt Grade Conn Top Btm 16" 65 H-40 8rd Surf 1,012' 13-3/8" 61 K-55 BTC Surf 1,785' (Window) 9-5/8" 47 S-95 BTC Surf 1,785' (Window) 7" 29 P-110 KC 1,554' 8,691' Tubing (Cemented Monobore): 4-1/2" 12.6 L-80 BTC Surf 1,427' 4-1/2" 12.6 L-80 Butt Mod. SSC 4,820' 13,309' JEWELRY DETAIL No Depth ID Item 1 1,427' 3.958 Kill String w/Mule Shoe (collar) 2 12,782' 3.813 4-1/2" Baker X-Nipple (12,767' CBT) 3 13,274 - Float Collar (13,259' CBT— Extrapolated) PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btrn (TVD) FT Date Status HB-1 12,912' 12,954' 9,754' 9,786' 42' 8/10/2002 Open HB-2 12,974' 13,035' 9,801' 9,848' 61' 8/10/2002 Open HB-2 13,055' 13,090' 9,864' 9,891' 35' 8/10/2002 Open HB-2 13,100' 13,126' 9,898' 9,918' 26' 8/10/2002 Open Notes Top of cement in 7" unknown Updated By: JLL 05/18/15 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Ll Plug Perforations U Fracture Stimulate ❑ Pull Tubing RI Operations shutdown ❑ Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: Run Kill String_ R1 2.Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska, LLC Development ❑ Exploratory ❑ Stratigraphlc❑ Service ❑� 202-004 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, AK 99503 50-733-20245-01 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0018731 / ADL0017594 Trading Bay St / A-29RD 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A McArthur River Field / Hemlock Oil Pool 11. Present Well Condition Summary: Total Depth measured 13,300 feet Plugs measured N/A feel true vertical 10,053 feet Junk measured N/A feet Effective Depth measured 13,274 feet Packer measured N/A feet true vertical 10,033 feet true vertical N/A feel Casing Length Size MD TVD Burst Collapse Structural Conductor Surface 1,012' 16" 1,012' 986' 1,640 psi 630 psi Intermediate 1,785' 13-3/8" 1,785' 1,622' 3,090 psi 1,540 psi Production 1,785' 9-5/8" 1,785' 1,622' 8,150 psi 7,100 psi Liner 7,137' 7" 8,691' 6,679' 11,220 psi 8,530 psi Perforation depth Measured depth 12,912 - 13,126 feet True Vertical depth 9,754 - 9,916 feet Tubing (size, grade, measured and true vertical depth) 4-1/2" 12.6# / L-80 1,427' & 13,309' (MD) 1,342' & 10,060' (TVO) Packers and SSSV (type, measured and true vertical depth) N/A & N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 9764 2160 2160 Subse uent to operation; ((640fiff per r t - Daily Report of Well Operations (A Exploratory❑ Development[] Service 0 Stratigraphlc ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil ❑ Gas ❑ WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ IGSTOR ❑ WINJ 0 WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or NIA if C.O. Exempt: 1315-149 Contact Dan Marlowe Email dmarlowet.U7_hilcorp.com Printed Name Dan Marlowe Title Operations Engineer .,7 Signature / yyp ,,� — Phone (907) 283-1329 Date 5/18/2015 Form 10-404 Revised 512015 Submit Original Only llilcorp Alaska, LLC RKB: MSL =33.20' PBTD=13,259' TD=13,3W 49 dog hole angle at M1 Max woo -47 dog at 56W MD SCHEMATIC Casing Detail Monopod Platform Well: A-29RD Last Completed: 04/18/15 PTD: 202-004 Updated By:1LL 05/18/15 if Hilcorp Alaska, LLC flfl�ur,i,,Iri+ku,I.I.f: Well Operations Summary Well Name API Number TWO Permit Number Start Date End Date A-29RD 50-733-20245-01 202-004 4/6/2015 4/18/2015 Daily Operations: 04/06/15 - Monday Set BPV and nip/dn remove tree and wing valve to cellar. Land Drilling Riser. N/U BOPE and associated equipment. Clean, check & chase lift threads. Screw 4 Y:"8rd x 3 Y," IF xo into hanger with 11 turns. Remove XO. MU blanking plug assembly with 4 Y," 8rd pin x 3 Y, IF box, 3 Ya" IF pin x 3 % 8rd box, 3 % 8rd pin X left hand stub ACME pin. Torque IF connections to spec and tack weld the 3 %" 8rd connection. Install blanking sub assembly into tubing hanger. MU 4 %" test joint crossed over to 3 %". Lay down PU slings. Clean work areas. Grease choke manifold and mud cross. Tie fingers back in derrick. Build and land 41/2" test joint. R/u to test BOP. Witness of test waived by Jim Regg, AOGCC. Function test BOP. Flood stack and choke manifold. Close and attempt to test Lower Pipe rams against tubing hanger. Pressure dropped from 3000 psi to 2000 psi In under Smin and still dropping. Did this 3 times with no visual leaks on stack. Perform same with Upper Pipe rams with same results. Break Down and Lay down 4 1/2" test joint. Continue to test Choke Manifold to 250/3000 psi. 04/07/15 - Tuesday Continue test choke manifold 250-3000 psi w/ one failure CMV i71. Perform rolling BOP test of annular, TPR, LPR and choke and kill valves and blinds w/ test pump holding 200-250 & 3000 -3200 psi on chart at least 5 min or longer to confirm no external leaks and no flow out of well bore. Rebuild CMV 91. Back out blanking sub. L/dn test jt. Pull BPV fill well w/ 35 bbls FIW. Monitor loss rate @ 65 bph and test CMV ftl (ok). Service rig and p/up Bha Ill Bowen "C" Dimension Spear Dressed w/ 3.947" grapple = 5.38", RIH engage hanger @ 37' set grapple w/ 5k over set at neutral and bleed off annulus and BOLDS. Work Hanger/Pipe Up in 10k over stages and jump box @ 75k over w/ no extra weight. Circ 50 bbls. POOH, shuck grapple and 1/dn 1 jt and pup of DP. R/up tbg tongs. L/dn hanger + 3 pups and 5 full jts 4-1/2" BTC tbg w/ SCC. ETOF @ 208.64'. (box) ID had heavy scale, OD had oily scum with touch of carbon w/ heavy pitting rotted collars and many holes, Daily FIW lost to well = 737 bbls. Total FIW lost t/ well = 877 bbls. Daily sized salt to well = 0 bbls. Total SS to well = 0 bbls. Ditch magnet 0 lbs. String magnet 0 lbs. Boot baskets 0 lbs. 20" X 16" = 0 psi, 16" X 13-3/8" = 0 psi, 13-3/8" x 9-5/8" = 55 psi. Set test plug. Begin testing of ROPE. Choke HCR would not test. Mobilized HCR from Dolly Platform, Repair electrical issue with accumulator. Chase leak issue with BOP test. Found TWC in test plug to be leaking. Change out same. Attempt to shell test. Still leaking. Pull test plug and inspect. Reset test plug and dump 5 sacks of salt on plug. Still leaking. Shut down hole fill gravity feed and disconnect hose to be able to observe for leaks. Good test finally. Change out choke HCR valve. Test ROPE as per sundry at 250 L/3000 H. Witness of test waived by Jim Regg, AOGCC. 04/08/15 - Wednesday Continue and finish ROPE test at 250 L/3000 H as per sundry on 3-1/2" and 4-1/2" test jts w/ one failure. BOPE witness waived by Mr. Regg on 4-6-15 @ 09:48 lus. BOPE test report will reflect rolling BOPE test of tbg hanger and test of choke manifold and positive test w/ test plug. R/dn test equipment and set wear ring. P/up bha 42 8-1/8" Bowen O/shot w/ cut lip guide dressed w/ 4-7/8" grapple and MPC + XO = 5.14' and load door w/ 4 1/2" 12.61f 1-80 IBT tbg strap same. Rih w/ Bha N2 p/up rabbiting 4-1/2" tbg t/ ETOF @ 208'. Service rig. Clean floor and m/up tbg collars on pups. Loss rate @ 62 bph. Rih p/up 4-1/2" tbg pups looking for TOF tag @ 214'. Attempt work over TOF by hand and power tongs t/ 215'. P/up with no over pull. Pooh on single. Std back 4-1/2" tbg in derrick. Inspect O/shot and grapple. No sign of collar engagement in grapple. RR Bha H2 = BHA 03 Rih and p/up pups t/ 213' engage fish @ 215'. With a little more zest, turn w/ power tong & fell t/ 216'. P/up w/ +/-2k extra weight. Pooh stand back tbg in derrick. Shuck grapple. Brk I/dn 0/shot. L/dn fish. Recovered 7 hull jts + 28.55' partial jt, 243' fish ( 2.90' of tube looking up) ETOF @ 451.50' w/ same heavy ID scale. OD some oily scum w/ touch carbon w/ heavy pitting, rotted collars and many holes. Clean and clear floor/door. Load door w/ new 4.1/2" tbg w/ loss rate of 56 BPH. P/up Bha 84 = 8-1/8" Bowen C/shot w/ curt lip guide + ext loaded w/ 4-7/8" grapple & MCP. Rih w/ 4-1/2" tbg out derrick t/ 184'. Continue rih. P/up and rabbit new 4-1/2" tbg off walk t/ tag @ 457' and no go out @ 462' (6.5' swallow to no-go). P/up 5k over set grapple and set slips. Daily FIW lost to well = 1111 bbls. Total FIW lost t/ well =1988 bbls. Daily sized salt to well = 0 bbls. Total SS to well = 0 bbls. Ditch magnoL.OJbs. String magnet. 11ooL baskets_Wb'S_- _!-_ i�?S[line__ .OJbs_ 112= 2,50drive own a er to 2,000 after working t rogT15' -15_00 . Run 431: Run 1= 3.25 swege own— 1,25_a_ndno-t a-ble— t-o-.p.._ass,Run 3.59 GR down to 1,900' after scraping scale 1,125' to 1,900'. POOH and R/D slick line. Loss rate 53 BPH. Circulate STS x 2 at 8 8PM/440 psi. Had no trace of OBM. Rig down circulating lines. Loss rate 60 BPH while circulating. Rig up PEST and test lubricator at 1500 psi. Run 81: 3.50 Spectra Jet cutter to 1,894'. Correlate on depth and make cut at 1,815'. Good indication of cut. POOH and rig down PE51. Loss rate 52 BPH. Pick up on string with 15K extra weight. POOH to fish. Release from grapple. POOH laying down fish. Recovered 44 full jts + 2.95' and 16.12' partial jt, 1365.57' fish (15.21' of tube looking up) w/ some heavy ID scale. OD same oily scum w/ touch carbon w/ heavy pitting rotted collars. Still a lot of holes. ETOF @ 1,823'. Loss rate 1.5 BPH. Photos of fish in o-drive. Pick up BHA 45: 6" x 4 9/16" dress -off shoe, wash pipe ext, top sub, double pin sub, bit sub, BS/OJ, 9 ea 4 3/4" DC's = 308.43. Hilcorp Alaska, LLC tlilumpAhu+ka,l.LC Well Operations Summary Well Name JAPI Number JWell Permit Number Start Date JEnd Date A-29RD 50-733-20245.01 202-004 1 4/6/2015 4/18/2015 Daily Operations: 04/09/15 -Thursday Finish Pick up BHA fl5: 6" x 4 9/16" dress -off shoe, wash pipe ext, top sub, double pin sub, bit sub, BS/OJ, 9 ea 4 3/4" DC's = 308.43. loss rate @ 1.5 bph. Service rig. Work on derrick cameras & service TDS power pack. Loss rate static. Daily FIW lost to well = 183 bbis. Total FIW lost t/ well = 2171 bbls. Daily sized salt to well = 0 bbis. Total SS to well = 0 bbis. Ditch magnet 0 lbs. String magnet 0 lbs. Boot baskets 0 lbs. 20" X 16" = 0 psi, 16" X 13- 3/8" = 0 psi, 13-3/8" x 9-5/8" = 30 psi. Rih w/ bha 115 w/ 3-1/2" dp out of derrick t/ 1,735' ( did briefly see TOL @ 1,553' ). Kelly up, fill pipe, brk circ wash do t/ 1,790'. Circ Btm up @ 9 bpm @ 770 psi. Establish parameters. Wash do tag TOF @ 1,823' @ 5 bpm @ 230 psi. Dress top fish t/ 4-9/16" @ 1,823' slide over and no go out @3,830'. Well still static, no losses. Pooh t/ bha @ 308'. L/dn and chk bha 115. Good indication of dressed t/ 4- 9/16". P/up Bha N6 = 5-3/4" O/shot w/ spiral grapple. No top sub for 5-7/8" o/shot. Having weather/wind problerns with tbg load out at dock. Prep strap rest of new 4-1/2" tbg on board. RIH choosing jts to build stands p/up rabbiting same t/ 1,747'. Build elevated pipe rack (tbg too short to stand back In derrick). Pooh std back tbg. L/dn 5-3/4" O/shot w/ spiral grapple. P/up 5-7/8" 0/shot and ext dressed w/ w/ 4-1/2" basket grapple. RIH t/ 1,570'. Install safety valve. Monitor static well. Clean out production waste water tank w/ vacuum. Recovered +/-40 bbis solids out of waste water tank until cuttings tanks all full. Rig housekeeping. Loss rate static. Offload work boat. Bring tubing on board. P/U 8 joints and 6' pup. Engage fish at 1,823'. P/U 20K over string weight. Set slips. Loss rate static. Rig up slick line. Test lubricator at 1500 psi. Run 111: 2.50 bailer down to 4,100'. Run IQ: 3.59 gauge ring to 1,900' and work down to 2,000'. Run 03: 3" gauge ring. RIH at report time. Loss rate static. 04/10/15 - Friday Continue finish slick line work. Run #3: 3.0" gauge ring to 4,100' ( set do work tools @ 2,075' ). R/dn slick line. R/up E-line test lubricator 250L and 1500H (ok). Rih ttl w/ 2" X 6' tbg punch loaded 2' @ 4 spf @ 0 deg phased decentralized tie in Punch tbg f/4,051" t/4,053' w/ no indication of out balance. Pooh. All shots fired. Rih #2 w/ 2-15/16" RTC. Rih tie in, place cutter on depth sever tbg @ 4,055' (2' below tbg punch). Attempt Pooh (cutter hung up). Work tools free. Pooh chk tools (cutter fired, tools appeared to have been back blasted slag on tool ). R/dn E-line. Daily FIW lost to well = 0 bbis. Total FIW lost t/ well = 2171 bbis. Daily sized salt to well = 0 bbls. Total SS to well = 0 bbis. Ditch magnet C1 lbs. String magnet 0lbs. Boot baskets 0 lbs. 20" X 16" = 0 psi, 16" X 13-3/8" = 0 psi, 13-3/8" x 9-5/8" = 50 psi. Kelly up work cut f/ -15 do wit t/ 30k over fish weight and circ STS @ 9 BPM @ 200 psi w/ no Joy. Set slips w/ + 20k over fish weight. R/up E-line, test 250-1500 psi (ok). Rih w/ 2nd 2-937" RTC cutter w/ ext. Tie in attempt 2nd cut @ 4,056' wlm. Pooh chk tools (just little slag on cutter) R/dn E-line. P/up on fish traveling @ 80k +/- 30k heavy. Install head pin. Circ STS X2 @ 9 bpm @ 620 psi w/ heavy sheen @ btm up. Pulled other 15k heavy off slips and little swabbing (slowed do pulling speed, fluid fell away). Continued POOH standing back work string. Loss rate static. Lay down over shot and stub in one piece. POOH laying down tubing/fish. Goad, even cut. Recovered 2,238.43'. ETOF now at 4,061'.Tubing still has numerous holes and collar pitting. First attempted RTC was 16" above good cut. Loss rate static. Break down overshot. P/U BHA 47: 5 7/8" Bowen overshot & ext dressed with 4 1/2" basket grapple & MCP. RIH with BHA 117 with work string out of derrick to +/-1860'. RIH with BHA 47 picking up 4 1/2" 12.6P BTC tubing from 1,860' to 3,700'. Loss rate static. Pull mouse hole and clean out debris, Clean rig floor and pathway to camp. 04/11/15 - Saturday RIH with BHA #7 picking up 4 1/2" 12.6tt IBT tubing from 3,700' to 3,898'. Loss rate static. (quit flowing over tbg), Kelly up, brk circ wash do singles f/ 3,898' t/ 4,055' @ 8 bpm @ 760psi. Circ @ 9 bpm @ 440 psi and work pipe attempting circ clean. Up/Dn wit 75/60k. Screen do shakers f/200s t/140s. Daily FIW lost to well = 0 bbis. Total FIW lost t/ well = 2171 bbis. Daily sized salt to well = 0 bbls. Total SS to well = 0 bbls. Ditch magnet 0lbs. String magnet 0lbs. Boot baskets 0 lbs. 20" X 16" = 0 psi, 16" X 13-3/8" = 0 psi, 13-3/8" x 9-5/8" = 10 psi. Circ @ max rate of 18 bpm @ 1380 psi and work pipe in attempt circ clean. Pump 15 bbl high vis sweep. Wash do engage fish @ 4,056'. Pull pipe into tension 30k above string wt. Recovered Sn-],5p(1�fir+t�atrezt-rovrstp�rrscc�arr�-ctarrr-»1-tttFiwltir25_Ii11St�itoX,�3}31tQLi�- 7,500'. Not set down. H2: RIH with 3.25" GR 7,500' with no tag. 83: RIH with 3.60" GR. Work through 4,131' to 5,310'. Stuck at 5,310'. Freed by pressuring up on tubing to 500 psi and releasing pressure quickly. Cut line and rehead.114: RIH with 2.5" DD bailer to 7,500'. Tight spot at 5,600' and able to work through. Recovered 1 cup of solids/scale. 115: RIH with 3.60" GR to 7,587'. Work through tight spots at 4,034', 5,540', 5,880', 6,148', 6,578'. Unable to get past 7,571'. t16: 3.73" GR to 4,124' and work down to 4,748'. POOH, H7: 2.5" DD bailer to 7,590'. Tight spot at 5,096'. Recovered 12 lbs of scale. H8: RIH with 3.60" GR to 7,582'. Unable to work past. 119: 2.5" DD bailer to 7,577'. Recovered 10 lbs. Hilcorp Alaska, LLC IIilumpAlnnka,LIX Well Operations Summary Well Name JAPI Number lWell Permit Number IStart Date End Date A-29RD 50.733-20245-01 202-004 1 4/6/2015 4/18/2015 Daily Operations: 04/12/15 - Sunday Pollard slick line runs. Rehead wire. Run 410: 2.5" DD bailer f/ 7,557' t/ 7,574'. Pooh, recovered 10 lbs of scale. Rih 411 w/ 3.60" GR t/ 7,464'. Pooh, rig do slick line. R/up E-line, test 250-1500 (ok). Rih $11 w/ 2.937" RTC w/ ext and jars. Tie in and attempt sever tbg @ 6,324', Good Indication of fire and tbg went on vacuum briefly. Tools hung up. Trip jars and free tools. Pooh, chk cutter (extensive back blast and slag). R/dn E/line. Daily FIW lost to well = 0 bbls. Total FIW lost t/ well = 2171 bbls. Daily sized salt to well = 0 bbis, Total SS to well = 0 bbls. Ditch magnet 0 lbs. String magnet 0 lbs. Boot baskets 0 lbs. 20" X 16" = 0 psi, 16" X 13-3/8" = 0 psi,13-3/8" x 9.5/8" = 15 psi, Kelly up work cut IF/ -15k do t/ 30k over and circ @ 18 bpm @ 1840 psi w/ no joy. Pull pipe into tension w/ 28k set slips. R/up E-line and test 250/1500 psi (ok). Rih 111 w/ 3.50" Spectra jet cutter. RIH tie in unable to pass 4,100' wim (pump do lubricator staging rate t/ 2.5 bpm and work tools no joy). POOH chk tools (ok). Rih #2 w/ 3.5" GR spangs on E-line. RIH work thru TOF. Work thru tight spot @ 4,100' unable to pass 4,140'. POOH. Chk tools (GR shows Iron marks). Run 43 w/ 3.25" GR w/ centralizer. Unable to pass 4,150'. Loss rate static. Rig down Pollard a -line unit. Rig up unit. Slick line. Run 111: 3.11 GR. Set down at 4,152' and not able to work through. Run IQ: 3.0" DD bailer to 4,151'. POOH and recovered 1 cup of scale, Run #3: 2.50 DD bailer to 6,500'. Set downs at 4,151' and work through at 4,158'. Recovered 2 cups scale. Run 114: 3.11 GR to 5,028'. Could not work past. Run 95: 2.50" DD bailer to 6,500'. Worked through spots at 5,025' - 5,028' and 5,043'. Loss rate static. Run 116: 3.11 GR to 6,500'. No issues. Run #7: 3.60" GR to 6,500' x 2. ID is good for now. Rig down slick line unit, Rig up Pollard a -line unit. Run 111: 3.50" Spectra jet cutter. RIH to 5,388'. Stuck at 5,388' but able to free by pressuring up to 600 psi on tubing and releasing pressure quickly. Not able to work down past 5,404'. POOH with jet cutter. Rig down Pollard a -line unit. Rig up slick line unit. Loss rate static. Pollard slick line. Run 111: 2.5" DD bailer. Work through 5,404' to 5,431' and on to 6,500' without any issue. loss rate static. 04/13/15 - Monday Slick line runs. Run 111: 2.50" DD bailer to 6,500'. Worked through 5,404' to 5,431'. Run 112: 3.60" t/ 6,500' no problems. R/dn slick line r/up E-line. Rih 111 w/ 2.937" RTC w/ ext. Tie in place cutter on depth. Attempt 2nd cut @ 6,326' (2' Below #1 cut attempt). Tool sluing hung up. Attempt work free. No-go. Continue to work wire close to weak point and assist by staging pressure up on well t/ 600 t/ 800 psi and clumping psi rapidly on 9th pressure surge freed tools. POOH. Check tools (cutter had extensive signs of back blast and heavy slag). R/dn E-line, M/up pups and Kelly up. Check pipe for free (No joy). Work cuts f/ -15k do t/ stage up t/ 90k over and circ @ 18 bpnt @ 1760 psi w/ no movement also worked 1.1/2 round in to string and attempted work torque down hole w/ no joy. Continue pulling on fish. Stage up to 80K overpull varying pump rate from 18 BPM/1380 psi to 5 BPM/185 psi. No progress made. Set string in slips with 80K over pull. Loss rate static. R/U slick line. Test lubricator 250 L/1500 H. Daily FIW lost to well = 0 bbls. Total FIW lost t/ well = 2171 bbls. Daily sized salt to well = 0 bbls. Total SS to well = 0 bbls. Ditch magnet 18 lbs, String magnet 0 lbs. Boot baskets 0 lbs. 20" X 16" = 0 psi, 16" X 13-3/8" = 0 psi, 13-3/8" x 9.5/8" = 15 psi. Run 41: 2.50" DD bailer to 4,318'. Recovered 5 Ibs of scale. Run tt2: Same down to 4,319'. Recovered 5 lbs scale. Run #3: Same to 4,320'. Recovered 9 lbs scale. Run #4: 2.50" pump bailer to 4,321'. Recovered 9 lbs scale. Run t15: 2.5" pump bailer to 4,331'. Break through bridge. RIH to 6,500'. Recovered 10 lbs scale. Run #6: 3.60 GR. Bulldoze scale 4,517' to 4,610'. Run 07: 2.5" pump bailer. Work bailer 4,610' to 4,629'. Recovered 10 lbs scale. Run it& 2.5" pump bailer. Work bailer 4,629' to 4,731'. Recovered 10 lbs scale/slit. Run 49: 2.5" pump bailer 4,731' to 4,739'. Recover 11 lbs scale, Run #10: 2.5" DD bailer 4,739' to 4,740'. recover 11 lbs scale (quarter size pieces). Run 1111" 2.5" DD bailer with extension 4,740' to 4,791'. Recovered 17 lbs scale. Run #12: 2.:5" DD bailer with extension 4,791' to 4,800'. Recover 19 lbs scale. Rehead tools. Run H13: 2.5" DD bailer with 10' extension. Hilcorp Alaska, LLC Ililrurpaluekx,LLc Well Operations Summary Well Name JAPI Number 1well Permit Number Start Date IlEnd Date A-29RD 50-733-20245.01 202.004 4/6/2015 4/18/2015 Daily Operations: _ 04/14/15 - Tuesday Slick line Run #13: 2.5" DD bailer with 5' f/ 4,798 t/ 4,800'. Recovered 6#. Run #14: 2.5" DD bailer w/ 5' extension f/ 4,799' t/ 4,802'. Recovered 20P (recovery scale appeared to have chg from a mostly iron to more of scale. Test a sample w/ acid w/ +/- 98% dissolved). Run It15: 2.5" DD bailer w/ 5' extension F/ 4,803' t/ 4,804' recovered 181t. Run If 16: 2.5" DD bailer f/ 4,804' t/ 4,805' fell t/ 4,842' recovered 1211. Run 1117: Run 2.5" DD bailer and clean out f/ 4,841' t/ 4,844'. POOH and recovered 12 # scale. Change tool to 2.5" dump bailer. Fill bailer with 1/2 gal of WAW273 wetting agent and had them reaction that started foaming out of the tool. Decided to RIH and dump to clean out tool. Run #18: RIH and tag at 4,844'. Dump and POOH. Daily FIW lost to well = 0 bbis. Total FIW lost t/ well = 2171 bbls. Daily sized salt to well = 0 bbis. Total SS to well = 0 bbis. Ditch magnet 18 lbs. String magnet 0 lbs. Boot baskets 0 lbs. 20" X 16" = 0 psi, 16" X 13-3/8" = 0 psi, 13.3/8" x 9-5/8" = 15 psi. Refill 2.5" dump bailer w/ 1 gal WAW273 wetting agent. Run It 18: RIH and dump at 4,842'. Refill 2.5" dump bailer w/ 1 gal again. Run It 19: RIH and tag and dump at 4,842'. POOH. Change tool back to 2.5" DD bailer. Run #20: Tag at 4,842' and work do to 4,843'. POOH and dump bailer. Recovered 14h scale with dime sized chunks. Change tool to 3.60 GR. Run It 21: RIH. 4,842' without seeing anything, POOH and RD slickiine. MU 41/2 tbg pups and pull off slips at 200k. Slack back do and set do 20k, PU to 120k which is 25k over the up wt. R/U E-line. RIH w 3.5 jet cutter and tag at 4,836'. PU to center of tbg jt at 4,819' and cut tbg. Seen good indication of cut. POOH w/ no extra drag. Loss rate static. R/D a -line. Make up top drive on string. Work pipe staging up to 205K (120K over string weight) and setting down to 40K while circulating at 18 BPM/1500 psi. Fish finally came free after +/-25 cycles. Service elevators and build elevated pipe rack for short tubing stands. POOH standing back 41/2" OTC work string to fish. Stands extremely short and had to use pup joints on several stands to be able to rack back. Secure stands of work string in derrick due to high winds. POOH laying down fish. Still numerous holes, some as large as 3". Tubing is starting to look much better. Recovered 762.42' of tubing/fish. ETOF Is 4,819'. RIH with BHA 118 to 3,080'. Fill pipe and CBU. Clear rig floor. Pick up BHA p8:6" x 4 9/16" dress off shoe, wash pipe extension, top sub, double pin sub, 3 ea 4 3/4" boot baskets, 7" casing scraper, bit sub, BS/OJ, 9 ea 4 3/4" DC's = 323.88. 04/15/15 - Wednesday RIH with BHA #8 t/ 4,040' and wash t/ top of fish at 4,820' DPM. 9.5 BPM at 1950 psi. PU and work pipe above fish while circ at 12 BPM and 2800 psi. Rt wt 80k, Up vrt 90k, Dn wt 74k, Got back 3 bbis of scale and black sludge. Slow do pumps to 5.5 BPM and 600 psi. Dress top of fish off w/ 1 to 4k bit wt and 30 RPM f/ 4,820' t/ 4,827'. Pull off fish and slide back over it 3 times. Pump 20 bbl high vis sweep and PU to top of fish. Increase pump rate back to 12.5 BPM at 2950 psi, and circ hole clean, Recovered 1 more bbl of scale and black sludge. Blow do TD. POH standing back 3 1/2 DP. No extra drag In 7" csg. Work BHA. Stand back DCs, lay do down and clean rest of BHA. Mill shoe still looks good. Recovered 12 # of scale from boot baskets, RU and pull wear ring. Wash out stack. RU to test BOPS. Witness of BOP Test was waived by Jim Regg at 1130 his on 4.14-15. Lay down test Joint. Set wear bushing. Daily FIW lost to well = 0 bbis. Total FIW lost t/ well = 2171 bbis. Daily sized salt to well = 0 bbls, Total SS to well = 0 bbls. Ditch magnet 18 lbs. String magnet 0lbs. Boot baskets 12 lbs. 20" X 16" = 0 psi, 16" X 13-3/8" = 0 psi, 13-3/8" x 9-5/8" = 15 psi, Test BOPE on 31/2" and 4 1/2" as per sundry at 250 L/3000 H. Upper IBOP failed test. Make up 7" RTTS and 3 stands drill collars. RIH with 7" RTTS to 4,750'. Repair top drive hydraulic link tilt hose. Set RTTS at 4,750'. Shut annular preventer and circulate through choke manifold to purge air. Shut in choke. Attempt to test 7", 9 5/8" and liner lap at 2500 psi/30 minutes on chart. 04/16/15-Thursday Release RTTS and pull up hole to 4,723'. Attempt to test 7", 9 5/8" and liner lap at 2500 psi. Started pumping away at 2 13PM and 2000 psi. Shut down pump and monitor pressure. Bled down to 1100 psi in 30 min. Bleed off pressure and release RTTS. POH to 1,608'. Set RTTS at 1,608'. Test 9 5/8 csg, 7" liner lap, and top section of 7" to 2500 psi for 30 min on a chart. Good testl Bleed off pressure and release RTTS. POH standing back DP and DCs. Lay_ al"UIS._LhangeouLaduato"ndJBCa"etest-atZ%-L/3000M,Go©d-test.-Make-up muleshoe en fir4t4tan"f-tubing.- IH with 3O stands of tubing to 2,615'. Daily FIW lost to well = 0 bbis. Total FIW lost t/ well = 2171 bbis. Dally sized salt to well = 0 bbls. Total SS to well = 0 bbis. Ditch magnet 18 lbs. String magnet 0 lbs. Boot baskets 12 lbs. 20" X 16" = 0 psi, 16" X 13-3/8" = 0 psi, 13-3/8" x 9-5/8" = 15 psi. Service rig and equipment, Add oil to air system. Loss rate static. POOH laying down 4 1/2" 12.611 BTC tubing. Back load work boat with tubing, fishing tools, etc. Continue POOH laying down tubing. Hole is static. Change over to 3 1/2" handling equipment. RIH with 3 stands of drill collars and 24 stands of 3 1/2" drill pipe. Hole is static. Hilcorp Alaska, LLC {Iilear,r ilnakn,LLC Well Operations Summary Well Name JAPI Number JWell Permit Number IStart Date JEnd Date A-29RD 50-733-20245-01 202.004 1 4/6/2015 4/18/2015 Daily Operations: 04/17/15 - Friday POOH laying down 3 1/2" drill pipe. Layed do 72 jts. RIH with the rest of the DP out of the derrick to 4,815'. Circ well while rigging up lines and cleaning the trip tank. Fill trip tank in prep to POH. Hold PJSM with all personal involved w/ displacing and shipping to production. Test lines to 1000 psi. Start out pumping w/ 112 pump to production shipping pump suction at 1 BPM & stage up to 2 BPM. Pump pit vol down to 150 bbis and start displacing well w/ FIW & Ill pump at 2 BPM until DP was displaced then increase rate to 4 BPM. Clean fluid back at 250 bbs. Shut do Nl pump. Continue pumping to production with N2 pump. Flush kill line and choke manifold. Still pumping dirty fluid to production. Drain and blow down. Had to shut do pumping to production at 1620 hrs due to pipeline press. Resumed pumping to production. P0I1 laying 3 1/2 DP IF/ 4,815' t/ 3,900'. Got done pumping to production. 512 bbis shipped. Continue POOH and laying down 3 1/2 DP. Back load work boat with tubulars. Pull wear bushing. Prepare to run 4 1/2" 12.60 BTC kill string. RIH with 4 1/2" 12.6N BTC kill string. Make up tubing hanger and landing joint. Land kill string. (EOT at 1,427.34') RILDS. Lay down landing joint. Rig down Weatherford. Daily FIW lost to well = 0 bbis. Total FIW lost t/ well = 2171 bbis. Daily sized salt to well = 0 bbis. Total 55 to well = 0 bbls. Ditch magnet 18 lbs. String magnet 0 lbs. Boot baskets 12 lbs. 20" X 16" = 0 psi, 16" X 13-3/8" = 0 psi, 13-3/8" x 9-5/8" = 15 psi. Nipple down BOPS. 04/18/15 - Saturday Nipple down ROPE. Pull riser, and clean up tbg spool. Cleaning pits. Land out and MU dry hole tree. Test void to 5000 psi. Pull BPV and install TWC, Test tree to 5000 psi. Pull TWC. Cleaning pits during this operation. Change out annulus valve. Blow down accumulator lines. Clean mud pits. Rig do TD. Pull clamps off the balls, lay do the balls, break out the saver sub and the TO valves. Clean mud pit N3. Flush and blow down the accumulator lines and BOPS. Continue cleaning pits. Back flush accumulator bottles several times. Hang blocks/TDS. Slip on 210' of drill line. Disconnect and plug service loop and Kelly hose. Weld/repair ladder in mud pit 113. Continue cleaning mud pits. Housekeeping/organization on rig floor and cellar. Clean around accumulator and disconnect hoses and secure. SARAN PALIN, GOVERNOR AL"KA OIL AND GALS CONSERVATION COMUSSIO* 333 W Rh AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL A1012.002 Mr. Steve Lambert Sr. Advising Reservoir Engineer Union Oil Company of California PO Box 196247 Anchorage, Alaska 99519-6247 RE: Trading Bay State A-29RD (PTD 202-004) Request for Administrative Approval Dear Mr. Lambert: Per Rule 8 of Area Injection Order 12, the Alaska Oil and Gas Conservation Commission (Commission) hereby grants Union Oil Company of California (Union)'s request for administrative approval to continue water injection in the subject well. Unocal notified the Commission on February 23, 2009 that Trading Bay State A-29RD exhibited a significant pressure increase in the well's tubing -casing annulus. Pressure was detected on February 21, 2009 and the well was immediately shut in pending diagnostic tests. Union submitted a request dated February 25, 2009 to perform a 30-day injection test followed by a static temperature survey to confirm casing integrity. At the Commission's request, Union proceeded with the temperature survey without the 30-day injection. The temperature survey performed on March 18, 2009 confirms the injected fluids are exiting the well at the perforations and all injected fluids are contained within the injection interval authorized by AIO 12. Union also performed a wellhead inspection and confirms that there are no integrity concerns and that pressures are contained within the wellbore. An aquifer exemption is in effect for all aquifers lying directly below Trading Bay Field [40 CFR 147.102(b)(2)(iv)]. Based on the diagnostic test results, Union has elected to perform no corrective action at this time on Trading Bay State A-29RD. The Commission believes that the well's condition does not compromise overall well integrity so as to threaten the environment or human safety. The Commission's administrative approval to inject in Trading Bay State A-29RD is conditioned upon the following: 1. Injection is limited to WATER ONLY; A10 12.002 March 23, 2009 Page 2 of 2 2. Union shall monitor and record tubing, inner annulus, and outer annulus pressures and injection rate daily; 3. Union shall submit to the Commission a monthly report of well pressures and injection rates; 4. Union shall perform a temperature survey at intervals not to exceed every 2 years in lieu of the mechanical integrity test as outlined in Rule 5 of AIO 12 to demonstrate continued production casing integrity; 5. Union must immediately shut in the well and notify the Commission if there is any change in the well's mechanical condition; and 6. After well shut in due to a change in the well's mechanical condition, Commission approval shall be required to restart injection. 7. The anniversary date for temperature survey is A DONE at Anchorage, Alaska and dated March 23, 2009 Z4" Daniel T. amount, Jr. Cathy P Foer ter Chair Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[tlhe questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the criod runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. 15 Wallace, Chris D (DOA) RECEIVED From: Larry Greenstein <Ireenstein@hilcorp.com> FEB 17 2015 Sent: Tuesday, February 17, 2015 9:34 AM AOGCG To: Wallace, Chris D (DOA) Cc: Colombie, Jody J (DOA) Subject: Request for Cancellation of Administrative Approval (AA) AIO 12.003 for A-12RD (PTD # 1710290) Attachments: MIT Monopod A-12RD 2-11-15.xis Hi Chris, With the recent WO on the A-12RD well, mechanical integrity has been re-established and the AA is no longer needed to continue injection into this well. Attached please find the initial MIT confirming the current mechanical integrity status. Hilcorp requests that AA A10 12.003 be cancelled. Upon approval of the cancellation, this well will be deleted from the monthly waivered well reporting. Thank you. Larry STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: nm reog(iDalaska.gov, AOGCC.Inspectors(o2alaska.gov: phoebe.brooks(a)alaska gov chns wallaceCdalaska.aov OPERATOR: Hilcorp Alaska, LLC FIELD / UNIT 1 PAD- Trading Bay Field/ TBU / Monopod platform DATE: 02/11/15 OPERATOR REP: George Ivie AOGCC REP: John HIII Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well A-12RD Type In' W TVD 1 4,122' Tubing 800 800 800 800 Interval P.T D. 1710290 Type test P Test psil 1500 Casing 0 1670 1670 1670 P/F P Notes: OA 0 0 0 0 Well I Type In' I TVD Tubing Interval P T D. I Type test I Test psi Casing P/F Notes: OA Well Type In . TVD Tubing Interval P T.D. I Type test I Test psi Casing --4- P/F Notes: OA Well I Type In' I TVD Tubing Interval P T D I Type test Test psi Casin P/F Notes: OA Well Type In' TVD Tubinq Interval P.T D. I Type test Test psi Casing P/F Notes: OA TYPE INJ Codes TYPE TEST Codes D = Drilling Waste M = Annulus Monitoring G = Gas P = Standard Pressure Test I = Industrial Wastewater R = Internal Radioactive Tracer Survey N = Not Injecting A = Temperature Anomaly Survey W = Water D = Differential Temperature Test INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance O = Other (describe in notes) Form 10-426 (Revised 11/2012) MIT Monopod A-12RD 2-11-15 As #14 • 0 Wallace, Chris D (DOA) From: Trudi Hallett [thallett@hilcorp.com] Sent: Monday, August 12, 2013 9:13 AM To: Wallace, Chris D (DOA) Cc: Larry Greenstein Subject: FW: Monopod Platform: A-12RD (Permit No. 171-029) Attachments: A-12RDhistory.jpg; A-12RD Temp Survey 5-17-02 vs 6-28-05.xls; A-12RD Casing Pressure Analysis @70 percent 20060104.pdf; A-12rdSchl2-8-72 Comp.doc Follow Up Flag: Follow up Flag Status: Flagged Chris, I apologize for not attaching the schematic. I have included it with this email. I would also like to note with action item no. 3 below, we would like to change the request to "Obtain Administrative Approval to Inject" and strike the word "Variance". Thank you. Tru44., Trudi Hallett I Reservoir Engineer Cook Inlet Offshore Asset Team I Hilcorp Alaska.. LLC Hilcorp A Company Built on Energy thal lett(d).hilcormcom d . go,:. 7 778323 C: 907.750.0747 From: Trudi Hallett Sent: Friday, August 09, 2013 3:47 PM To: Chris Wallace (Chris.Wallace(a)alaska.gov) Cc: Larry Greenstein; John Waski; Ted Kramer; Dan Marlowe; Chet Starkel; Stan Golis Subject: Monopod Platform: A-12RD (Permit No. 171-029) Chris, Hilcorp would like to begin the Administrative Approval process to return well A-12RD (PTD 171-029) to injection. Well A-12RD, a water injector which was shut-in in April 1984 due to a failed MIT, has been retained for potential future utility as an injector and we feel the Trading Bay Field could benefit with increased injection rates given the Monopod's workover success over the past couple of months. A-12RD was originally completed in 1971. In August 1972, well A-25 drilled into well A-12RD — it was shut in and worked over in December 1972. During the workover, the 9-5/8" casing was found to be parted at 3,640'. The casing was repaired and a 7" tie -back liner was cemented to surface. The well was completed as a C-Zone single string injector. The well initially injected rates of over 6,000 bwpd. In 1984, the well was shut-in due to communication between the tubing and the casing annulus. Notes in the history indicate the well was not returned to injection because of the conversion of up structure wells to injection and A-12RD down dip location. Temperature surveys run 40 in 8 2002 and zoo have confirme• at injected fluids continue to be contained within the "C" sands and there 99 5 1 are no indications of cross flow in the wellbore. Currently Hilcorp has three active water injectors on the Monopod platform - two of which inject into the Trading Bay Field (A-25RD and A-o8RD2) and one of which injects into McArthur River's northern nose(A-29RD). A-25RD is a "C-D" Zone injector and A-o8RD2 is a Hemlock injector. It is imperative with our successful workover program and future drill well plans that we establish reliable and maintainable injection/withdrawal ratios in the Trading Bay Field. We would like to request your approval to begin the AA process (Administrative Approval). 1.) Obtain permission to inject for one month until the well has stabilized. 2.) Run a temperature survey to demonstrate mechanical integrity. 3.) Obtain Variance to inject. 4.) Monitor well daily and repeat temperature surveys every z years. Attached for your informational purposes are copies of the baseline temperature surveys completed 5/17/2002 and 6/28/2005, schematic, Maximum Allowable Operating Pressure (graph) and some historical notes as well. Since we have a baseline, we would run another temperature survey to demonstrate wellbore integrity. Thank you for your consideration and if you have any questions regarding this request, please do not hesitate to contact me at 777-8323 or Larry Greenstein at 777-8322. Regards, �J Trudi Hallett I Reservoir Engineer Cook Inlet Offshore Asset Team j Hilcorp Alaska. LLC Hilcorp A Company Built on Energy thallett@hilcgM.com O: 907.777.8323 C: 907.750.0747 Oading Bay Field (TBF) A-12RD PTD 171-029 302-298 Unocal has submitted a temperature survey to demonstrate mechanical integrity for this injection well and has requested to keep the well in service with known tubing x annulus (T x IA) communication. This note evaluates Unocal's request and recommends approval of It. According to the RBDMS database, this well has not been in service since early 1984. The file does not have much information since the original completion In 1971. The well was drilled as an injection well. There Is a record in the MIT binder that Blair examined the bond log on 6115/89 and concluded that MI was Indicated, It Is unclear why the well has not been in service for so long. In the mid 19809, Unocal applied to workover the well converting to a single completion from the dual originally run. There Is no subsequent report of such workover, although the drawing In the file would indicate that the workover was performed. I have contacted Unocal to provide what informatlon they might have to complete our files on this work. In 1998, Unocal attempted a "81 MIT' and provided pressure observations for a 1-week period. This Information was not conclusive in demonstrating wellbore integrity. Subsequently, a temperature survey was performed May 5, 1998, The Information gathered at that time was accepted and demonstrated that there were no temperatures anomalies present in the wellbore. Unocal performed a subsequent survey May 17, 2002 and essentially the same thermal profile was developed. There 1s a general warming in the wellbore that would be expected since no injection has occurred. Area Injection Order 12 allows injection into Southern Portion of Trading Bay Field, developed by the Monopod Platform. The BKL of well A-12RD is located in the covered area. The portion of aquifers beneath Cook Inlet described by a 1/4 mile area beyond and lying directly below the Trading Bay Field are exempted for Class II injection activities by 40 CFR 147.102(b)(2)(iv) and 20 AAC 25.440(c). Granting Unocal's request will not endanger any fresh water. I recommend acceptance of the submitted temperature information. Unocal should add this well to the monthly monitoring report and plan to perform another temperature survey in May 2004. Unocal should be reporting this well as required by 20 AAC 25.115 (a) (Shut -In Wells]. In addition to those requirements, Unocal should provide an assessment of the future utility of this well prior to the end of 3'ti quarter 2003. SCMNED, APR 2 3 2003 Tom Maunder, PE Sr. Petroleum Engineer April 9, 2003 0 0 -h 1,000 3,000 O N r 4,000 CL a� 0 5,000 6,OOC 7,00C 8.00( A-12RD Maximum Allowable Operating Pressure Graph Pressure (PSI) 1,000 2,000 3,000 4.000 5,000 6,000 7,000 8,000 9,000 10,000 Run date : /4/2006 8:24:23 AM Safe operatin ressures (surface gauge) Production = 5712 p i. @ 70 % nominal casing yield Intermediate = 14 Si. limited by fracture pressure at shoe Surface = 283 psi i ad by fracture pressure at shoe Current Press re eadings Surveillance Thresholds TBGPRESS = 0 Warning = Alert = CSGPRESS=85 Warning = Alert= CSGPRESS2=1 Warning Alert CSGPRESS5=0 Warning = Alert= Casing Detail Size Weight Grade Yield Top Bottom Liner Segment 7 29 N-80 8160.0 36.3 3982.2 Liner Stgcollar 29 N-80 8160.0 3982.2 3984.9 Liner Segment 29 N-80 8160.0 3984.9 7261.0 Liner Hanger 29 N-80 8160.0 7261.0 7279.1 Liner Segment 7 32 X-LINE 7279.1 8465.6 Liner Shoe 7 8465.6 8468.0 Production Casin 9.6 5 43.5 N-80 6327.0 39.0 2010.3 Production Stgcol r 9.6 43.5 N-80 6327.0 2010.3 2012.5 Production Casin. 9.62 43.5 N-80 6327.0 2012.5 7490.0 Casing Para ters / AsSI Production casing field @ 70 % of Intermediate casi yield @ 45%, Surface casing yic J @ 45% of no Fracture gradient 0.7#/ft API :50733200 01 Permit 1710290 ial with Fluid weight of 0.433 #/ft final with fluid weight of 0.433 #/ft with fluid weight of 0.433 #/ft Workbook: A-12 Casing Pressure Ana sis @70 percent 20060104.As Variable Definitions RP = Reservoir Pressure CYP = Casing Yield Pressure SF =Safety Factor(70% for working annulus; 45% for outer annuli) HP = Internal Fluid Hydraulic Pressure MASP = Maximum allowable surface working pressure Graphical calculation method Inside pressure potential == Outside pressure containment Therefore HP + MASP = RP + (CYP' SF) Rearranging MASP = RP + (CYP' SF) - HP Internal Fluid Hydraulic Pressure Formation facture pressure @ 0.7 #/ft -Production CYP @ 70% -Outside Containment for Production casing -MASP (production casing) Intermediate CYP @ 45% -Outside Containment for Intermediate casing -MASP (Intermediate casing) Surface CYP @ 45% Outside Containment for Surface casing -MASP (Surface casing) • Current Pressure Readings Disclaimers (fine print) Casing yield values taken print) published sources where specifications are known. If specifications are unknown then values are the lowest value of probable materials. TVD interpolated from Openworks directional surveys. Values should be +/- 25 ft @ 10,000 ft. Unocal I Well: A-12RD I Field: Monopod Pressure (psia) 0 250 500 750 1000 1250 1500 1750 2000 2250 0 - I NT 500 -- - -- -- - - i 1000 —. _-- - - I --- Pressure -Temperature Profile 1500 1. Going in hole 6780' RKB 2000 --- -- -- -- -- - --- - 2500 - -- - - - fi- 3000 - G� - 3500 Jj 4000 - -- - - I 0 -- - 4500 5000 5500 6000 6500 7000 55 65 75 85 95 105 115 Temperature (Deg. F) 6-28-05 Pressure - Perfs 13 3/8" 9 5/8'. 7" 3 1/2" 6-28-05 Temp 5-17-02 Temp Report date: 9/23/2013 Unc Well: A-12RD Field: Monopod 6-28-2005 Pressure (psia) 0 250 500 750 1000 1250 1500 1750 2000 2250 2500 0 Pressure -Temperature Profile I -A- 1. Going in hole TVD 500 1000 - - 1500 2000 2500 - 3000 3500 4000 4500 5000 5500 6000 6500 55 65 75 85 95 105 115 Temperature (Deg. F) 6-28-05 Pressure — Perfs 13 3/8" 9 5/8" 7" 3 1/2" 6-28-05 Temp Report date: 9/2312013 • Trading Bay Unit UNOCAL 76 Well # A-12RD Re -Completed 12/8/72 RKB to TBG Head = 34.7' Tree connection: ? CASING AND TUBING DETAIL WT GRADE CONN ID TOP BTM. 13-3/8" 61 K-55 Butt 12.515 Surf. 1066' 9-5/8" 43.5 N-80 & P-110 Butt 8.755 Surf 7490' 7" 32 P-110 X-line 6.094 7261' 8468' 'Collar Tie Back 3 9g2' 7" 29 N-80 Butt 6.184 Surf 7261' Tubing: o ? N-RO Butt. 2.992 0' 7057' 1 2 0 3 C-7 C-7 C-7 4 5 6 7 47-5 47-5 47-5 7261' 50-3 51-6 51-6 PBTD = 8468' TD = 8475' KB ELEV = 101' HOLE ANGLE thru Interval = 40.7° NO. Depth JEWELRY DETAIL ID Item 34.7 3-1/2" CIW 8rd X Butt Tubing Hanger 1 6730' ???? Locator Seal Assy. w/ 8.2' of seals. 2 6730' Baker Model "I'" Pkr. 3 6780' Otis Metering Sub 4 7028' Locator Seal Assy. w/ 20.02' of seals. 5 7037' Baker Model "D" Retainer Production Packer 6 7055' 2.760 Otis "N" Profile Nipple, 2.875 7 7056' Mule Shoe btm 7057' STIMULATIONS Acid Squeeze w/ Mutual Solvent 3/72 Acid Squeeze 12/72 PERFORATION DATA Zone Top Btm Amt Accum SPF Last Perf Date Present Condition 6,811' 6,851' 40' 2 12/5/72 Open for Injection 6,886' 6,926' 40' 2 12/5/72 Open for Injection 6,960' 6,980' 20' 2 12/4/72 Open for Injection 7,092' 7,122' 30' 2 12/4/72 Open for Injection 7,102' 7,122' 20' 2 3/27/72 Isolated w/ tie back liner ran on 12/1/72 7,160' 7,180' 20' 4 12/4/72 Open for Injection 7,514' 7,520' 6' 2 3/26/72 Open for Injection 7,521' 7,522' 1' 8 3/19/72 Cmt sgz'd f/ bond 7,700' 7,701' 1' 4 3/17/72 Cmt sgz'd f/ bond 7,715' 7,721' 6' 2 3/26/72 Open for Injection 7,732' 1 7,740' 8' 2 3/26/72 Open for Injection A-12rdSch12-8-72 Comp REVISED: 9/23/2013 DRAWN BY: SLT M r Page 1 of 1 • • Maunder, Thomas E (DOA) From: Hallett, Trudi R. [TrudiHallett ©chevron.com] Sent: Tuesday, March 22, 2011 8:48 AM To: Maunder, Thomas E (DOA) Cc: Cole, David A; Greenstein, Larry P; Lambert, Steve A; Brooks, Phoebe L (DOA) Subject: A -29RD (PTD #202 -004) F' p, \Q Attachments: A -29RD Temp Survey 3 -19 -11 vs 3- 18- 09.zip Gentlemen, Well A -29RD (PTD 168 -109) was granted Administrative Approval (AIO 12.002) for continued water injection on March 23, 2009. As required under the approval and to demonstrate continued production casing integrity, a temperature survey was run on March 19, 2011. The survey confirms that all injected fluid is exiting the wellbore at the perforations. If you have any questions regarding the attached survey please do not hesitate to contact me. Thank you, Trudi Trudi Hallett Petroleum Engineer MidContinent /Alaska SBU Chevron North America Exploration & Production 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Office: (907) 263 -7323 Cellular: (907) 750 -0747 trudihallettta chevron.com CONFIDENTIALITY NOTICE: This message may contain confidential information that is legally privileged, and is intended only for the use of the parties to whom it is addressed, If you are not an intended recipient, you are hereby notified that any disclosure, copying, distribution or use of any information in this message is strictly prohibited and you must delete this email immediately. 3/22/2011 (Chevron I •IA -29RD I FieId:IMonop• 103 -19 -2011 I Pressure (psia) 0 500 1000 1500 2000 2500 3000 3500 4000 4500 0 1000 Pressure- Temperature Profile 1. RIH Overlay RKB 2000 — — — — _ 3000 4000 5000 6000 CD 2 7000 a - G 8000 — 9000 - 10000 11000 — — — — — 12000 — 13000 . _ - 14000 I I I I I 40 50 60 70 80 90 100 110 120 130 140 150 Temperature (Deg. F) — 3 - 19 - 11 Pressure — Perfs 13 3/8" 9 518" 7" 4 1/2" —3-19-11 Temp — 3 - 18 - 09 Temp Chevron • A -29RD Field: Monop 03 -19 -2011 Pressure (psia) 0 500 1000 1500 2000 2500 3000 3500 4000 4500 0 1 P ressure- Temperature Prof 1000 - 1. RIH Overlay TVD — 2000 r, - 3000 - - - — 4000 - -- -- - -- - - --- G> • > 5000 - F_ - Q 4\._ _. _ D 6000 - 7000 8000 \ _ 9000 - 10000 1 I 1 1 1 1 1 40 50 60 70 80 90 100 110 120 130 140 150 Temperature (Deg. F) —3-19-11 Pressure Perfs 13 3/8" 9 5/8" 7" 4 1/2" 3 -19 -11 Temp —3-18-09 Temp 12 A-29 Temperature survey Regg, James B (DOA) From: Regg, James B (DOA) ~ _ ~.~ ~y. 3~•z~~o~ Sent: Monday, March 23, 2009 8:35 AM ~ c To: 'Lambert, Steve A' Cc: Maunder, Thomas E (DOA); 'Greenstein, Larry P' Subject: RE: A-29 Temperature survey Steve - • Page 1 of 1 Unless you would like to proceed otherwise, Tom and I suggest moving ahead by recommencing continuous injection in A-29RD. We have sufficient information to prepare an administrative approval based on your request dated Feb 25, 2009 and the diagnostics results provided with your email below. Will try to have admin approval out in next couple days. Please ensure you are monitoring and recording pressures (tubing and annuli) daily; and, immediately shut in the well and notify the Commission if there is any change in the well's mechanical condition. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 From: Lambert, Steve A [mailto:salambert@chevron.com] Sent: Thursday, March 19, 2009 2:25 PM To: Regg, James B (DOA); Maunder, Thomas E (DOA) Cc: Cole, David A; Greenstein, Larry P Subject: A-29 Temperature survey Jim as requested, attached is the static temperature survey for well A-29RD. The survey confirms that all fluid was being injected into the zone of interest. I apologize for the delay in submitting this survey, but we had some surface equipment problems that temporarily prevented us from running wireline surveys. During the time that we were waiting to get the equipment repaired we were able to perform an inspection of the A-29RD wellhead and confirmed that there are no integrity issues in the wellhead. I have attached a summary of the wellhead inspection. As you consider the status of A-29RD you may want to consider that while this well only has one string of tubulars across the completion interval, the well is not a true monobore due to the fact that there are multiple strings of casing isolating the shallow water and hydrocarbon bearing intervals. If you have any questions or would like to discuss this well in more detail please contact me at 263-7658. I look forward to your recommendations on how best to move forward with plans to utilize this wellbore. «A-29RD Mar 09 vs Jun 07 Temp Log Comparison.ZlP» «A-29 wellhead report.pdf» zi~zi~nn4 __ evron Chevron Wellhead :Report Platform ar Field: Monopod Well-Number: A-29 Date: 3/12/2009 Casin Pro ram: 20 X 16 X 13 3/8 X 8 518 X 4 1!2 Wellhead Description: Starting head, OCT, 2 step unihead, 21 1 /4 2M API FE X 20 SOW, has 16" and 13 3/8 casing hung off in head. All outlets on head are 2 1/16 2M. Total of 20 IP in ass on wellhead. Casing spool, OCT-C29L, 21 1/4 2M X 13 5/8 3M, has 13 3/8 00 bottom, should be C-22 or C-29 13 X 9 5/8 a casin han er. Total of 8 standard OCT lock in ass on wellhead. Tubing head, CIW DCB, 13 5/8 3M X 11 5M, X bushing seal 9 5/8, has Cameron DCB-FBB tubing hanger in head. Total of 10 CIW-DCB lock in ass on wellhead. void TestsV Stettin head X casin 113 3f8 Iasi :Test to 2501500 'for thi minutes each. Casi s I X tubi head 9 518 Iasi :Test to 250125001 for thi minutes eacm. ubin han (41/2 tubi j; Teat goad to,250/ ~ fiEx ttti minutes each. Tubing Hanger Description: Tubin han er, CIW-DCB-FBB, 11 X 4 1/2 tubin , w/ 4" e H BPV rofile, 7" extended neck twee Lion: 71 5M CIW FBB adapter X 41/16 5M double master, swab, and single wing valve. All valves operate okay on tree. Not sure abotat which ones hold pressure or nom, well is dead so no ga#e tests could be rformed. Casing Pressures: 20" X 16": 20 si on 3/12/2009 16" X 13 3/8": NA no au eon valve 13 3/8" X 9 5/8": 143 si on 3!12/2009 9 5/8" X 4 1/2": 0 si on 3/12/2009 4 1 /2": Opsi on 3/12/2009 Notes: Elevation from the wellhead room floor to the top of the tuia' head is 7.6' 1 void #ests on the wellhead were very easy to achieve, nothing needed recharging, no iockpin leaks, at~i no trapped pressure in the voids, all uoids stiN ~ hydraulic-oil contai in them, rro wellbore fluids. in hem. Last Wellhead work pn this we# was in 2002. Important Part Numbers: Tubin head ass :20446-20-10-10 Casin s ool ass : 13-190-495 Tree ada ter ass :164789-01-03-02 Chevron Well: A-29RD Field: Monopod 03-18-2009 Pressure (psia) '! 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 0 I, 500 '`~. ~ -- - ~ _ _ ..:7s _ - ~ - Pressure-Temperature Profile 1000 ` ', -- - 1 RIH overlay 09,07 ~- - _._ ... __. _. ~_ ; 1500 _ I , - _ -, _ __ I _... ~I - ~ ' 'I T 2000 _ _.... _ _ ~ _. _ _ _ _ _ } _ _. _. _. _.. 2500 -- _...- .. ---- i _ ~ 3000 - - I - - _.__ . _. _ - - -- _ I -- --- - --- ---- - -... - I 3500 __ _ ---- ,, _ ~ ~ _ _.. ~. ~ _. _ _ i _ - - __. 4000 i _ -- _ --- -- - -- ~ ~ _. _ I ; ~ _.. 4500 - ~ rt - - - -- - - ~ -- , _. ___ __ -! 5000 - _ _ .. _ _. - .. _ j _ _. _.. , _ _ _ - , _. ~ _ ~ _.. -_ - _.r __ ---~ - - ~ 5500 -- - -- ~ ~ } 4 _ _ ~. _ ... , G1 + _ _. - -- w 6000 -- _ ~ - ..... ` , ... -- - - " 6500 _ 4 __ - - + - ~., - L 7000 _ -~ ~ ~ - - -- .E I ~ 7500 - - - I a ~- - - ~I i0 - ~~° _ - - -- - _ _ _ 8000 __ _ -- - - - _ ~ _ _. , I - _ - _. _ --- -- 8500 - -- - . ~ __.::.: E ~- _ ~ ..._...._ i _. _ _ 9000 _ ._ _._ __ , ~ __. _ , -- _ ~ - ~, I i - _ I _. 9500 _ _ _ - ~; - __ ---_. - 10000 - -- - ~ I i 10500 _ __ _ _ -r-- _ _ _ i _.._ - 11000 --- - _._ ' ~ _ ---- I _ -_ 4 t } i I 11500 _ _....... ~ i ! ~ 12000 __ _ __ - - ~ - , }~ _._ I __ - - -- i 12500 __ i _ ~ ~, ---- - ~ ~;-- - ~- -, ~ 13000 ~--~-- -- - , ~ , I I I 13500 ~ ;I ~ ~ 50 60 70 80 90 100 110 120 130 140 150 ~ I Temperature (Deg. F) 09 Pressure - Perfs 13 3/8" 9 5/8" 7" 4 1/2" ' I "°° 07 Psia 09 Temperature 07 Temp ~ ' - - --- -- 4000 i 3500 -. - ___ - __ - - - -- - ___ _ _ i i ~ - - - 1 r- - - - i - - - - ---------- -- ~ ', 150 140 130 120 ^ I 110 100 ~ L 90 ~ d a E 80 ~ 70 60 50 ~ 40 3000 .~ 2500 c~ .N L 2000 N N m a 1500 1000 500 0 L 8.00 9.00 10.00 11.00 12.00 13.00 14.00 15.00 16.00 17.00 18.00 Time (hrs) i Pressure Temperature i- _--- ------------ --- --------- ------- --------.. .- ~ • I • Pressure (psia) ~ i 0 500 1000 1500 2000 2500 3000 3500 4000 1 2 3 4 "" E D a a~ 11 1 1 1 50 60 70 80 90 100 110 120 130 140 150 Temperature (Deg. F) - i - --- - _ - - ~- Pressure - Perfs --13 5/8 ~-9 5/8 --7 4 1/2 - ~- Temperature _ _ -- - J ~~~ Chevron Steve Lambert Sr. Advising Petroleum Engineer MidContinent/Alaska • Chevron North America Exploration and Production P.O. Box 196247 Anchorage, AK 99519-6247 Tel 907 263 7658 Fax 907 263 7847 Email salambert@chevron.com ><.eP February 25, 2009 Tom Maunder Alaska Oil and Gas Conservation Commission 333 W 7th Ave #100 Anchorage, AK 99501-3539 Dear Tom: ~~~ ~i ~-` ~~~~ Alaska Oil ~ Gas Dons. Colrunission Anchorage Chevron requests approval to perform a 30 day injection test on well A-29RD. Following the completion of the 30 day test, a static temperature survey will be run. The purpose of the test is to confirm casing integrity with the goal of returning the well to long term injection. Well A-29RD (API # 50-733-2024-501-00, PTD #202-004) was shut-in shortly after midnight on February 21, 2009, when casing pressure increased from zero to 1,800 psi. The well remains shut-in. This well typically injected 9,000 BWPD or 75% of the total Monopod injection of 12,000 BWPD. Without this well, it has been necessary to shut-in the entire Monopod waterflood. Well A-29RD was redrilled as an injector in 2002. The well has abottom-hole location on the northern nose of the McArthur River Field. The well provides pressure support to offset producers A-15RD2 and K-13RD2. A recent pulse test confirmed that A-29RD positively benefits both producers. The well is unique in that it is completed as a monobore completion across. the perforated interval. A copy of the schematic is attached to this request. Following is the proposed procedure for bringing the well back on injection. 1) Obtain permission to inject. 2) Inject into the well until the injection rate has stabilized. (Limit the length of the test to 30 days.) 3) Run afollow-up temperature survey. 4) Request Administrative Approval to continue injection depending on results of the survey. If Administrative Approval for continued injection is granted, the daily rates and pressures will be monitored and temperature surveys will be repeated every two years. Sincerely, ~ ~, Steve Lambert MidContinent/Alaska Chevron North America Exploration and Production vvww.chevron.com • UNOCAL ~Q' Monopod Platform Well # A-29RD Actual Completion 8/2/02 Actual perfs, 8/10/02 RKB to TBG Hanger = 33.20' CASING AND TUBING DETAIL SIZE WT GRADE CONN TOP BOTTOM 13-3/8" 61 K-55 BTC 0 1785' Window 9-5/8" 47 5-95 BTC 0 1785' Window 7" 29 L-801iner KC buttress 1554' 8691' Tubing (Cemented Monobore): ~ 4-1/2" 12.6 L-80 Butt Mod. 0 13309' JEWELRY DETAIL Depth 9-5/8" and 13-3/8" NO. (PM) Item Window @ 1785' " " " ' " Baker X nipple, 3.813 ID 4-1/2 MD/1622' TVD 1. 12782 (12767' CBT) 2 13274' Float collar (13259' CBT -- Extrapolated) TOC at 7350' MD /5711' TVD 7" liner at 8691' MD/6678' TVD PERFORATIONS Zone Depth Shots Blanks HB-1 12912'-12954' 42' 8/10/02 20' HB-2 12974'-13035' 61' 8/10/02 20' HB-2 13055'-13090' 35' 8/10/02 10' HB-2 13100'-13126' 26' 8/10/02 - 1 . 164' S0' 214' total gross ETD -- 13211' CBT (tag with CBT log, 8/5/02), 13248' elm tagged with Coi18/10/02, 13224' shn with 2.92" GR on 8/12/02 2- 13274' -- float collar = 13259' CBT (Extrapolated) 4-1/2" tbg at 13309' MD tbg tally TD =13300' MD/10053' TVD 43 deg hole angle at TD Max angle = 47 deg at 5600' MD A29RDActualSchem080202.doc REVISED: 02/25/09 DRAWN BY: TAB a-29rd Pressure Data 2009 02 ~xls Regg, James B (DOA) From: Lambert, Steve A [salambert@chevron.com] Sent: Thursday, February 26, 2009 4:50 PM To: Regg, James B (DOA) Cc: Greenstein, Larry P Subject: a-29rd Pressure Data 2009 02 25.x1s Attachments: a-29rd Pressure Data 2009 02 25.x1s Page 1 of 1 «a-29rd Pressure Data 2009 02 25.x1s» Jim this plot is not exactly the same format that Larry usually submits for the TIO plots, but he is out of town this week. The plot should be very similar to what you are used to seeing and the actual data is included on the follow up page. 3/2/2009 TBF A-29rd Pressure Observations 3500 _ _ _ _ _ .~ _. ,~ ~.,..~:~~ ~~~ 12000 3000 - - - 10000 2500 -- - - --- 8000 2000 - - - - --- - m m 6000 ` a 1500 - -- - Hours Tubing 4000 1000 ~9 5/8" I 13 3/8" X20" Rate 2000 500 - - -- - -_ - - - - -- ~~ ~__.~__~, ~_. ~~~ _ _ ~ .~. ,_._ _ ~..~. p 11 /08/08 11 /28/08 12/18/08 01 /07/09 01 /27/09 02/16/09 03/08/09 Time Printed on 3/2/2009 at 10:16 AM a-29rd Pressure Data 2009 02 25.x1s • •~ • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re: THE REQUEST OF UNION OIL COMPANY OF CALIFORNIA for an Area Injection Order for the portion of the Trading Bay Field developed by the Monopod Platform Area Injection Order No. 12 Southern Portion of Trading Bay Field November 20, 1986 IT APPEARING THAT: 1. Union OiI Company of California (Union) requested the Alaska Oil and Gas Conservation Commission to issue an Area Injection Order permitting the underground injec- tion of fluids within a portion of the Trading Bay Field for purposes of enhanced hydrocarbon recovery. 2. Notice was published in the Anchorage Daily News on September 12, 1986 of an opportunity for a public hearing on October 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. FINDINGS: 1. An order permitting the underground injection of fluids on an area basis, rather than for each injection well individually, provides for efficiencies in the adminis- tration and surveillance of underground fluid injection operations. 20 AAC 25.460 provides the Commission with the authority to issue an order governing underground injection operations on an area basis. 2. The portion of the Trading Bay Field Union's Monopod platform constitutes area" which can readily be described subdivisions. Union is the sole ope Project Area. developed by a compact "project by governmental rator of this Area Injection er~o . 12 Page 2 November 20, 1986 3. The Project Area encompasses approximately the Southern half (1/2) of the Trading Bay Field, Middle Kenai and Hemlock Oil Pools. The Project Area includes all existing injection wells and injection well sites planned for enhanced recovery of oil from the Middle Kenai and Hemlock Oil Pools in this portion of the field. 4. The portion of aquifers beneath Cook Inlet described by a 1/4 mile area beyond and lying directly below the Trading Bay Field are exempted for Class II injection activities by 40 CFR 147.I02(b)(2)(D} and 20 AAC 25.440(c). 5. Less stringent requirements for well construction, operation, monitoring, and reporting of injection operations may be more appropriate than would be required when injection occurs into, through or above portions of aquifers not exempted. b. The vertical limits of injection strata and confining formations may be defined in the Union Oil Company of California Trading Bay State well No. A-17. 7. The strata into which fluids are to be injected will accept fluids at injection pressures which are less than the fracture pressure of the injection strata and their confining formations. 8. Statewide regulations and conservation orders govern field operations except as modified by this order. 9. To ensure that fluids injected are confined to injec- tion strata, the mechanical integrity of injection wells should be demonstrated periodically and monitored routinely for disclosure of possible abnormalities in operating conditions. 10. Injection wells existing on the date of this order were constructed and completed in accordance with regu- lations which conform to the requirements of 20 AAC 25.412. Area Injection Or ~. 12 J Page 3 November 20, 1986 NOW, THEREFORE, IT forth govern Class following described affected area: SEWARD MERIDIAN IS ORDERED THAT II underground area referred T9N R13W Section Section Section Section Section Section T10N R13W Section the rules injection to in this 3: 4: 5: 8: 9: 10: 33: • hereinafter set operations in the order as the All . A11. E2. NE 4f N2 SE 4. N~, N Z SE 4, N 2 SW 4 N'~, N~ SE 4f N 2 SW 4 S~ SE 4. Rule 1 Authorized Injection Strata for Enhanced Recovery Within the affected area, non-hazardous fluids may be injected for purposes of pressure maintenance and enhanced oil recovery into strata defined as those strata which correlate with the strata found in the Union Oil Company of California Trading Bay State well A-17 between the measured depths of 3220 feet and 8270 feet for the Trading Bay Middle Kenai "B", "C", "D", "E" and Hemlock Oil Pools. Rule 2 Fluid-Injection Wells The underground injection of fluids must be: 1) through a new well that has been permitted for drilling as a service well for injection in conformance with 20 AAC 25.005; 2}.through an existing well that has been approved for conversion to a service well for injection in conformance with 20 AAC 25.280; or 3) through a well that existed as a service well for injection purposes on the date of this order. Rule 3 Monitorin the Tubin /Casin Annulus Pressures The tubing/casing annulus pressure of each injection well must be checked weekly to ensure there is no leakage and that it does not exceed a pressure that will subject the casing to a hoop stress greater than 70~ of the casing's minimum yield strength. Area Injection 0 r N~ I2 Page 4 November 20, 1986 Rule 4 Reporting the Tubing/Casing Annulus Pressure Variations Tubing/casing annulus pressure variations between consecutive observations need not be reported to the Commission. Rule 5 Demonstration of Tubing/Casing Annulus Mechanical Integrity A schedule must be developed and coordinated with the Commission which ensures that the tubing/casing annulus for each injection well is pressure tested prior to initiating injection and at least once every four years thereafter. A test surface pressure of 1500 psi, or, assuming a 0.465 psi/ft geo-pressure gradient, a surface pressure that imposes a differential pressure gradient across the casing of 0.25 psi/ft at the vertical depth of the packer, whichever is greater; but not to exceed a hoop stress greater than 70~ of the casing's minimum yield strength, must be held for 30 minutes with no more than a 10 percent decline. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Rule d Well Integrity Failure Whenever operating pressure observations or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, the operator must notify the Commission on the first working day following the observation, obtain Commission approval of a plan for corrective action, and when an USDW is not endangered, obtain Commission approval to continue injection. Ruie 7 Plugging and Abandonment of Fluid Injection Wells An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission in accord- ance with 20 AAC 25.105. Rule 8 Administrative Relief Upon request, the Commission may administratively amend any rule stated above as Long as the operator demonstrates to the Com- mission's satisfaction that sound engineering practices are maintained and the amendment will not result in an increased risk of fluid movement into an underground source of drinking water. r Area Injection 0 ~ r~o . 12 Page 5 November 20, 1986 ~~ -.i..J DONE at Anchorage, Alaska and dated November 20, 19$6. ~~A ®~~ ~ ~ d ~ ~ F Y~ ,~ ~- ~ ~; ~ ~~r ~ .~ ~~ - ... .>. ~s ~~O o~ ~o Lonnie C. Smith Commissioner Alaska Oil ~ Gas Conservation Commission ff" ~ W. W. Barnwell, Commissioner Alaska Oil & Gas Conservation Commission Alaska uil ~ Uas conservation uommission #10 . , '- . Chevron . Steve Lambert Unocal Alaska Advising Reservoir Engineer Union Oil Company of California Box 196247 Anchorage, Alaska 99519-6247 Tel 907-263-7658 Fax 907-263-7847 salambert@chevron.com October 3, 2006 RECEIVED OCT 0 6 2006 Commissioner Chair John Norman Alaska Oil and Gas Commission 333 W. 7th Ave., Suite #100 Anchorage. Alaska 99501-3509 .Alaska Oil & Gas Cons. Commission Anchorage Dear Chair Norman: Unocal requests administrative approval under Area Injection Order 12, Rule 8 for the continuation of injection of non-hazardous Class II fluids for the Monopod Platform Well No. A-19 RD, Injector (Permit # 188-0010) in Trading Bay Field. To support this request, Unocal submits the following information and documentation: 1. Schematic (attached). 2. Sundry notice of operations (Form 404). 3. Temperature survey (attached). 4. Brieflrelevant well history (below and attached). Well A-19 was drilled and completed as a down dip "0" zone producer in January 1970. The well initially produced at rates in excess of 3,000 BOPD, but declined rapidly as water production increased. The well was shut-in in 1974. In 1976, A-19 was recompleted as a "0" zone injector. The well historically injected at rates in excess of 6,000 BWPD. Injection was shut-in in 1985 due to collapsed casing in an offset producer. In 1988 A-19 was redrilled north and down dip as a "C" and "0" zone injector. Initial profiles showed all the water was entering the C-7 sand (5,755'-5,890'). The "0" zone and all the "C" zone sands except the C-7 were acidized prior to completing the well. Injection rates were maintained between 2,000-3,000 BWPD thru 2001. The well was shut-in for 12 months in 2002 while the waterflood was evaluated. Injection was restarted in early 2003. Since early 2006, injection has been limited to less than 1,000 BWPD to more closely balance withdrawals. If approval is received to resume injection, Unocal will continue to monitor and record daily injection rates and tubing and casing pressures. This data will be provided to the AOGCC as part of the monthly reporting process. A temperature survey will be run every 2 years to insure that the injected water is contained within the completion interval. Steve Lambert # . Chair John Norman AOGCC February 22,2006 Page 2 cc: MIT book Well File " . 2 1,07CWftKB : 95/8" 40# N·80/J·55 440().OftKB : 7" Liner, 29#, N·80, 7,010.0ftKB Casin : 5" Liner. 18# N·80 7498.3ftKB 31/2",9.3#, N·80 set at 5,306.2ftKB on 9/3/1988 Ti K in M ke Hanger 40.9 Cameron Nipple 41.8 2.992 Tubing 45.2 2.992 Sleeve 5,259.6 2.992 Tubing 5,263.1 2.992 Locator Joint 5,294.3 3.000 BAKER 13318",61#, J-55, Seal Assembly 5,295.1 3.000 1,070ftKB Muleshoe 5,305.6 3.000 5 70 260 Packer Strin set at 5 350.9ftKB on 9/3/1988 m 10 in M Packer 5,295.1 4.000 BAKER FB-1 Seal Bore Extension 5,298.4 4.000 Crossover 5,307.8 3.000 Tubing 5,308.5 2.992 Nipple 5,318.5 2.750 Tubing 5,319.2 2.992 Wireline Re-ent Guide 5 350.1 3.125 OTIS 5263 5294 9518", 40#, N-80IJ-55, 4,400ftKB Shot Dens KB B K 8/10/1988 5,724.0 5,726.0 8/25/1988 5,755.0 5,890.0 8/10/1988 5,885.0 5,887.0 WSO 8/25/1988 6,032.0 6,140.0 8/9/1988 6,130.0 6,130.0 WSO 8/25/1988 6,476.0 6,505.0 8/25/1988 6,670.0 6,730.0 8/24/1988 6,934.0 6,950.0 8/9/1988 6,962.0 6,964.0 WSO 8/24/1988 6,983.0 7,015.0 Packer, 5,298 8/24/1988 7,045.0 7,095.0 8/24/1988 7,125.0 7,147.0 8/24/1988 G1, Main Hole 7,154.0 7,240.0 8/24/1988 G1, Main Hole 7,281.0 7,367.0 5295 5299 5306 5306 5308 5308 5319 5319 5350 5351 6807 6815 6820 7010 7" Liner, 29#, N-80, 7,010ftKB 7415 7419 7456 7457 7489 7497 7498 5" Liner, 18#, N-80, 7,498ftKB 7500 PBTD (ftKB) 7,415.0 KB-TH(ft) 41.00 Verified By: ,Verified Date: Rpt Name: Single 1/1 ~ STATE OF ALASKA . AL:1! OIL AND GAS CONSERVATION COMM~N REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon U Repair Well U Performed: Alter Casing 0 Pull Tubing 0 Change Approved Program [] Opera!. Shutdown 0 2. Operator Union Oil Company of California Name: 3. Address: Box 196247 Anchorage, Alasaka 99519 Plug Perforations U Perforate New Pool 0 Perforate 0 4. Well Class Before Work: Development 0 Stratigraphic 0 Stimulate U Other U Waiver 0 Time Extension D Re-enter Suspended Well D 5. Permit to Drill Number: Exploratory 0 188-0010 Service [] 6. API Number: 50-733-2015101 9. Well Name and Number: A-19RD 10. Field/Pool(s): Trading Bayl Middle Kenai "C" & "D" oil sands. 7. KB Elevation (ft): 105' 8. Property Designation: Trading Bay State- ADL 18731 11. Present Well Condition Summary: Total Depth measured 7,493' feet true vertical 6,012' feet Effective Depth measured 7,498' feet true vertical 6,012' feet Casing Length Size MD Structural Conductor Surface 1,070' 13318" 1 ,070' Intermediate 4,400' 9 5/8" 4,400' Production 3,553' 7" 7,010' Li ner 69, 5" 7,496' Perforation depth: Measured depth: 5755-5890.6032-6140,6476- 6505. 6670-6730, 6934-6950, 6983-7015,7045-7095,7125- 7147,7154-7240,7281-7367. Plugs (measured) Junk (measured) TVD Burst Collapse 1,033' 3,090 1,540 3,497' 5,750 3,090 5.563' 8,160 7.020 6.012' 10.140 10,490 True Vertical depth 4514-4622,4735-4822,5097- 5121, 5265-5369, 5496-5512, 5539-5567, 5593-5638, 5664- 5683, 5690-5766, 5802-5881 Tubing: (size, grade, and measured depth) 3112" N-80 9.3# 5,306' Packers and SSSV (type and measured depth) 7" 29# FB-1 packer Packer 5,296' 12. Stimulation or cement squeeze summary Intervals treated (measured): Treatment descriptions including volumes used and final pressure' 13. Oil-Bbl Representative Daily Average Production or Injection Data Gas-Mcf Water-Bbl Casing Pressure 961 BWPD 1100 Tubing Pressure 1200 Prior to well operation: Subsequent to operation: 14. Attachments: Copies of Logs and Surveys Run Daily Report of Well Operations 15. Well Class after work: Exploratory 0 16. Well Status after work: OilO Gas 0 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Temperature Survey (9-23-06) Development 0 Service [] WAG 0 GINJ 0 WINJ [] WDSPL ¡Sundry Number or NIA if C.O. Exempt 1306-262 o Contact Steve Lambert Printed Name Ste.ue.. \"""C!"Y'\ \oe.'C-t:...- ~ r~ \, . J '\ '. ) J i . ì.....1. j '-.. )(Lc",,-,! C,J}ss:::... .., Title Advising Reservoir Engineer Signature Phone 2. G?rl G '5 D Date .10 I L\ ( ceo Form 10-404 Revised 0412006 Submit Original Only ~ ~ STATE OF ALASKA . A~ OIL AND GAS CONSERVATION COMM~N REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon U Repair Well U Plug Perforations U Stimulate U Other U Performed: Alter Casing D Pull Tubing D Perforate New Pool D Waiver D Time Extension 0 Change Approved Program [2] Opera!. Shutdown D Perforate 0 Re-enter Suspended Well 0 2. Operator Union Oil Company of California 4 Well Class Before Work: 5. Permit to Drill Number: Name: Development 0 Exploratory 0 188-0010 3. Address: Box 196247 Anchorage, Alasaka 99519 Stratigraphic 0 Service [2] 6. API Number' 50-733-2015101 7. KB Elevation (ft) 9. Well Name and Number: 105' A-19RD 8. Property Designation: 10. FieldIPool(s): Trading Bay State- ADL 18731 Trading Bay/ Middle Kenai "COO & "0" oil sands. 11 Present Well Condition Summary: Total Depth measured 7,493' feet Plugs (measured) true vertical 6,012' feet Junk (measured) Effective Depth measured 7,498' feet true vertical 6,012' feet Casing Length Size MD TVD Burst Collapse Structural Conductor Surface 1.070' 133/8" 1.070' 1 ,033' 3,090 1 ,540 Intermediate 4,400' 9 518" 4,400' 3,497' 5,750 3090 Production 3,553' 7" 7,010' 5.563' 8,160 7,020 Li ner 691' 5" 7,496' 6012' 10.140 10,490 Perforation depth: Measured depth: 5755-5890,6032-6140,6476- 6505,6670-6730,6934-6950, 6983-7015,7045-7095,7125- 7147,7154-7240,7281-7367. True Vertical depth: 4514-4622, 4735-4822, 5097- 5121,5265-5369,5496-5512, 5539-5567, 5593-5638, 5664- 5683,5690-5766, 5802-5881 Tubing (size, grade, and measured depth) 3112" N-80 93# 5,306' Packers and SSSV (type and measured depth) 7" 29# FB-1 packer Packer 5,296' 12. Stimulation or cement squeeze summary: Intervals treated (measured) Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Met Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 961 BWPD 1100 1200 Subsequent to operation: 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Temperature Survey (9-23-06) Exploratory 0 Development 0 Service [2] Daily Report of Well Operations 16. Well Status after work: OilO Gas D WAG 0 GINJ 0 WINJ [2] WDSPL D 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. I:undry Number or NIA if CO. Exempt 306-262 Contact Steve Lambert Printed Name S'c" . ,L 0, Y'i\ \,', e ,,-c... Title Advising Reservoir Engineer - E:;. \.J e__ Signature bt !\~ 'J~ Phone 203ì Co ,") ð Date J...O! 4/ C (0 ¡ . ; iv..- """'--- \ c..;,··! ~"', Form 10-404 Revised 04/2006 Submit Original Only ~ mperatl~ 6'·'.','" 0""'6/.'" " ". .' v,, . , i:IW " . ~o lJ (hevrcm ~ ~ b.J -- -------..---.- ....--.....-------..-.-.--....-- ...-....-......-...--....-- --"--"- .-..- .-.......-...--.....--- Pressure (psia) 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 500 1000 ø 1500 2000 _ 3000 ø GI ::. 3500 è :E 1::. 4000 Õ. GI o 4500 5000 6000 . 5500 6500 7000 7500 78 80 82 84 86 88 90 92 94 96 98 100 102 Temperature (Deg. F) ..- ---------- Perfs ....."......... 13·3/8" - - 5" Pressure July Temp 9·5/8" - 1l3G Sept. Temp -... ---..-.'-'."-- © Chevron 2005 DOC ID 3 '. -. . Ä-19RD Monopod Platform Trading Bay Field Well History Well A-19 was drilled and completed as a "0" zone producer in January 1970. The well initially produced at rates in excess of 3,000 BOPD, but declined rapidly as water production increased. The well was shut-in in 1974. In 1976, A-19 was recompleted as a "0" zone injector. The well historically injected at rates in excess of 6,000 BWPD. Injection was shut-in in 1985 due to collapsed casing in an offset producer. In 1988 A-19 was redrilled north and down dip as a "C" and "0" zone injector. Initial profiles showed all the water was entering the C-7 sand (5,755'-5,890'). The "0" zone and all the "C" zone sands except the C-7 were acidized prior to completing the well. Injection rates were maintained between 2,000-3,000 BWPD thru 2001. The well was shut-in for 12 months in 2002 while the waterflood was evaluated. Injection was restarted in early 2003. Since early 2006, injection has been limited to less than 1,000 BWPD to more closely balance withdrawals. CumIJIaIiveO~Prod: ZJ81.15BJWbl <. ~ - . w.u, s,,,,,,,,, (4) <Amb;guous>. -77:= =i.... ¿........... UW.·U."'.. )~..."-.'.'..!".... .<~.. j...u........... .... u.u......... ·...·.·....u.... ....u...........u.u.......u...uu.......... u ..··...·......·..·u. ...u........ ...u......1 40 ," .:.....~_... ...:....:....... . -..:_ -.:-~-., _.-:-..d.___...d__:_____..d_:___'..__:.._:_.._L__~---------~ __:'"_'_~''' -':_"~__',___ .,.--:.---..-----, 20 -,' . "C - __ . , "d . ..;. .. _ .': .' _ - .', ... .' .'.'..... - . - - .' . . . . _ .' ... . . . :. _ .' __ _, .. _ . _.' _ __ _ _ '_ __ .' _ __ _ _ -.: _ .'. .. .' _ _ _ . _ _ _.. . , 'n n' .' __ _ -:__ . __ :. _ .' __ .' . .. .: .' _ .'..: .'.. .. _. _ .. ~ .. .' .. _: _ . . .' .:. __ __ __ __ ,. __ . .: .' _ __ . :__. _ o !~ 7' .. 1'2 .. lJ .. 7. : 75 Ii 17; 7! ' 7!1' IJ ð,' ~ .' aJ ' /101: !15 .' 86;'1 511: Q , 'JO' 11 !)'¡I I 9J '9* ~'¡¡¡¡;' 97 ~ 99":10(0' 0' \12" 03 .. Of Q5' 00 ''''''' , . - .', ~ 99 ~ m \12 ~ ~ Q5 œ ;01031200!!16:53:41 *9 R~: p~nn~n~ fo, SRF and NNA 2006 MITS' , This email documents our conversation 2/2/2006 and provides guidance regarding the required mechanical integrity determinations for the wells listed below. NNA #1 In accordance with DIO 28A (Rule 5), we would like to see another temperature survey with wellbore conditions replicating to the extent feasible those ofthe post-injection start temp survey done 12-31-04. Also, the MIT due this year (December 2006) should be performed with the IA pressure dropped to 500 psi below the tubing pressure and monitored for 30 minutes. This test coupled with the imposed pressure for back-up purposes (no apparent communication from no pressure plots I reviewed) will confirm tubing integrity. SRF 213-10 CO 474 orders Unocal to demonstrate mechanical integrity annually. This does not specifically require the demonstration to be a conventional pressure test (MIT). One way this requirement can be satisfied is the monitored and reported annuli pressures as required in the Order ("Each annuli pressure must be monitored daily and reported to the Commission quarterly."). In addition, before restarting production in Well 213-10, Unocal will be required to perform a pressure test to demonst ellbore' '!Y. ~ .~ Long Term Shut In Injectors Based on our conversation, there are 6-8 injectors that fall into this category. You have suggested doing a low pressure MIT as a way to confirm integrity while the well is shut in. Commission's current thought is that no MIT is necesssary for a well that would be categorized "long term shut in" (no intent to inject in the well in foreseeable future). In lieu of an MIT, periodically sending a no plot would provide information to determine any developing problems with the well. Regulations at 20 AAC 25.115 require you to address these SI wells annually (due 3/31); the injection orders include provisions for monitoring and notification if leakage or pressure communication is identified. Before restarting injection in any ofthese wells, Unocal will be required to demonstrate mechanical integrity (could include temp survey, MIT, other type of demonstration). PCU #4 Strategy outlined in your message regarding PCU #4 is appropriate. You have satisfied the requirements of our regulations by performing the pre-injection MIT 10/25/2005. A Commission inspector should witness the MIT after restarting storage injection and the well's performance has stabilized; you can coordinate scheduling such a test with me. MIT Due Dates We did not talk about this subject but clarification is appropriate based on recent discussions with other operators and within the Commission regarding scheduling MITs. Mechanical integrity determinations are due on or before the anniversary date. The Commission must approve an extension to go beyond the due date. lof2 4/25/2006 4: 11 PM ~' PI:nn:ng fn' SRF and NNA 2006 MIT' , For Admininstrative Approvals (well integrity, alternate demonstration of mechanical integrity), we are using the admin approval date to establish when the next mechanical integrity demonstration is due. Jim Regg AOGCC Greenstein, Larry P wrote: Tom/Jim, When you get a chance, could you call me (263-7661) to talk about a couple of MITs that will be coming up this year. They may be a little out of the ordinary depending how you define the MIT. NNA#1 (PTD #201-215)- calls for an MIT this year (every two years). We are constantly doing an MIT based on the backpressure held in the annulus (see previous letters in file). The backpressure could be altered for an inspector to verify integrity, if so desired. With the 'high set packer' in this well, we need to come to some agreement as to how to perform this MIT. Temp logs with test injection periods were used for the initial MIT on this well. SRF 213-10 (PTD #202-118) - called for an MIT last year (every year). This 31/2" monobore gas production well is not in use. We were originally considering converting this well into a gas storage well (with modifications to create a monitorable annulus), but decided against this. The well has remained shut-in and water appears to have entered the well bore (based on a wellhead pressure increase). Nothing is planned for this well in 2006 also. If we were to do something (recomplete uphole??) we would be able to do a pressure test MIT at that time. There is nothing in the budget, so I don't know if leaving this shut-in gas well idled until such time as we decide what to do next is adequate to meet the annual MIT requirements for an 'active gas well'. There is an uphole profile that would allow at least a fairly deep pressure test to be performed while it is in its idled condition. As usual, I would still like some time to discuss low pressure MITs with you as we still have a backlog of 6-8 wells pending your decision. On a shut-in well, I believe the normal 'operating condition' (ie shut-in) would allow a low pressure MIT to have validity. Let's discuss whenever you can. Also, I would like to inform you that we were unable to obtain the follow-up MIT on PCU #4 (PTD #201-193) gas storage well. Just about the time we had achieved a consistent stabilized gas injection (Xmas time after the injection compressor started up), the weather started getting real cold and all injection was stopped in this well. Prior to this time, the well was injecting using only the varying line pressure off the Enstar 20" line and the injection rates were all over the place. The best guess is that we will not start injection back up in PCU #4 until March at the earliest. We do have the successful pre-injection MIT and will plan on doing the follow-up MIT after injection stabilizes upon restarting injection this spring. Hope this is meets with your approval. Thanks for you time. Larry 20f2 4/25/20064:11 PM ~8 " , , Chevron !tIIIt IìijíIII Steve Lambert Advising Petroleum Engineer Union Oil Company of California P.O. Box 196247 Anchorage, AK 99519-6247 Tel 907 263 7658 Fax 907 263 7847 Email salambert@chevron.com January 9, 2006 Tom Maunder Alaska Oil and Gas Conservation Commission 333 W. 7th Ave., Suite #100 Anchorage, AK 99501-3539 & Continuation of Shut-in Status Well No.A-12RD Injector Monopod Platform Trading Bay Field Dear Tom, This letter serves as a follow-up to the assessment of well utility for well A-12 submitted on September 6, 2005. Unocal requests approval under Area Injection Order 12, for the continuation of status as a shut-in injector of non-hazardous Class II fluids for the Monopod Platform Well No. A-12 RD, Injector (Permit # 171-029) in Trading Bay Field. To support this request, Unocal submits the following information and documentation: 1. Schematic (attached). 2. Temperature surveys (attached). 3. Maximum allowable injection pressure calculation in graphical form (attached). 4. Brieflrelevant well history (below and attached). Well A-12RD was drilled through the West Foreland in March 1968 and abandoned. In March of 1972, the well was redrilled through the "C" sands in the 2-A Fault Block and completed as a dual string injection well. In August of 1972, well A-25 drilled into well A-12RD. A-12RD was shut-in and worked over in December 1972. During the workover, the 9 5/8" casing was found to be parted at 3,640'. The casing was repaired and squeezed and the 7" liner was tied back to the surface and cemented to surface. The well was completed as a single string "C" zone injector. Following the repair, A- 12RD became the primary "C" zone water injector. The well initially injected at rates in excess of 6,000 BWPD. The well was shut-in in 1984 due to communication between the tubing and casing annulus. Due to concerns about the well's down-dip location and the conversion of up structure wells to injection, it was decided not to resume injection in the A-12RD location. Temperature surveys run in 1998, 2002 and 2005 have confirmed that injected fluids continue to be contained within the "C" sands and there are no indications of crossflow in the well bore. Union Oil Company of California I A Chevron Company http://www.chevron.com , , Tom Maunder Alaska Oil and Gas Conservation Commission January 9, 2006 Page 2 Depending on the results of field development, it may be desirable to return this well to injection in the future. Unocal will seek concurrence from the AOGCC before attempting to return this well to injection. Unocal will continue to monitor and record daily tubing and casing pressures on the well and provide a report to the AOGCC on a monthly basis. A temperature survey will be run every two years to insure the injected water is contained within the completion interval. Thank you for your consideration and if you have any questions regarding this request please contact me at 263-7658 or Larry Greenstein at 263-7661. Sincerely, ~~~~ Steve Lambert cc: MIT book Well File Union Oil Company of California I A Chevron Company http://www.chevron.com , , A-12RD Well History Last Update: 12/29/2005 Date 3/1/68 3/1/72 12/1/72 6/1/84 5/29/98 6/28/05 Description Drilled thru West Foreland and abandoned. Redrilled thru "C" sands and completed as dual injector. A-25 drilled into wellbore. Found parted casing at 3,640'. Squeezed bad casing and ran 7" liner tie-back to surface. Completed as single string injector. Communication between tbg and csg. Well shut-in. Temperature survey confirmed zone isolation. Ran 2.50" GR to 1250' and tagged up. Had to jar up to free. Ran 2.25" GR to 6780' (Otis metering sub) and tagged up. Unable to work deeper. Ran temp survey to 6780'. C:\Documents and Settings\salambert\Local Settings\TempIA 12RDWellHistoryJHM Page 1 of 1 , , Pressure (psia) 0 250 500 750 1000 1250 1500 1750 2000 2250 2500 - ...... CI) 3000 J!! - - C 3500 :E I .J: ...... Q. 4000 CI) C 4500 o I.. -- - .-. f· '" - - ..- ~ c '" ..... ........-.... ;;;;;iii" ---- .... -. ...-........ ...... --- " e- - '- ........... ..... ...... " ~... - ... ~-- .... ..... _... --. ...... ........ "'- .." .. ....... '" ~ Ii"'" -......... ...... \Z ~ ....... ........... .-.. -- --- ......... - - .-- . .-. r - -... .........- - . ..-.- ..... "- ..... .... -.- ......~ ~- - - .-... -- ...... ... - ~... ...... ..... -. --... "-, - - -- - ... -- ..- ..... .__n 1l ... - "- I- ... ...... ~\.... ...... - I .-. - .....-- ..... - ....... - . .- ...... i , '\. ..- \. - - .......... ... ..... ..+ .... ~.··K· - .-. ....... ... - -- .... - --- .- -- ---- '\.\1 \ ..... - --- .--- .. ..... ~ \. ....... ..... --- ......... -.. ~, '\. .-..-. ... - 1- --- -- ....... -... .... ..-- ....- .... I\.\. \. 1- ..... n 1----- ...... m .- '\.'\. '\. .- -- '\.'\. , - ..- . ----- \.\. " - '\.'\. " .n .-. " 1\ -- .......... "- ...... ....- .-... "- '\. - - . e- .- ...-.... ----- .... , '\. e- ..... - ..... , i::=I..... \. ..--- ... .....,.,." 1 " f· ........ -.. . ..... - ""- .-- c···· . ..-......... ..... ... .-.. . -- c- .-. ..- . ...... "..... f ....... ., ,,"- e- ...... \'-;. .-. -- ........ .. .- I ----- ...... ..... ~ .. .- ..... .. - ..... -- ... .... -.. ... - ..... \ " ...... ...." - .... .--.-. ..- ..- "- - -- -- "- ._~ ..... .... ...... .-... - . .-. -- " \.\. - '\. , . -- ..... ..-. .... .. - ... .-..... "- ,- ..-.- .... ..- .. .... ..--.. -- -- "- -- .- m .- .- - -.. . ...-. ... '\. .".-...... " .. - ... - . -. -.... .-. '\.. ~J " - ... ...-. ...... m .. .-. . -- --- I .--. . -... ... .. ---- -... 500 1000 1500 2000 5000 5500 6000 6500 7000 55 85 105 115 65 95 75 Temperature (Deg. F) - 6-28-05 Pressure Perfs 1-7" -31/2" I -133/8" -6-28-05 Temp -95/8" -5-17-02 Temp 1,500' 2,000' 2,500' 3,000' 3,500' 4,000' 4,500' 5,000' 5,500' 6,000' 6,500' 7,000' 7,500' 500' 1,000' 40 0' 1/9/2006 8:43 AM 50 ~ 113-3/8" I ~ D ,. , Monopod A-12RD Temp Survey Comparison 60 70 80 90 100 110 120 -RIH OS/29/1998 -RIH 05/17/2002 5,235' Wire slipped out of detent gear, repair unit Jeff Dolan A-12RD Temp Survey 1998 and 2002 Temp chart ~. , UNOCALe '- Trading Bay Unit Well # A-12RD Re-Completed 12/8/72 RKB to TBG Head = 34.7' Tree connection: ? o C-7 2 C-7 3 4 C-7 5 6 4 7 5 - 6 7 47-5 47-5 CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. 13-3/8" 61 K-55 Butt 12.515 Surf. 1066' 9- 5/8" 43.5 N-80 & P-IIO Butt 8.755 Surf 7490' 7" 32 P-110 X-line 6.094 7261 ' 8468' Tie Back 7" 29 N-80 Butt 6.184 Surf 7261' Tubing: 3-112" 9.2 N-80 Butt. 2.992 0' 7057' NO. Depth 34.7 JEWELRY DETAIL ID Item 3-112" CIW 8rd X Butt Tubing Hanger 6730' Locator Seal Assy. w/ 8.2' of seals. ???? 6730' Baker Model "F" Pkr. 6780' Otis Metering Sub 7028' Locator Seal Assy. w/20.02' of seals. 7037' Baker Model "D" Retainer Production Packer 7055' Otis "N" Profile Nipple, 2.875 2.760 7056' btm 7057' Mule Shoe STIMULATIONS Acid Squeeze w/ Mutual Solvent Acid Squeeze 3/72 12/72 'if 7 , , ,rJ·! i .j.' '..J .'.' :J' 4:=J J' -\ 'j uib FRANK H. MURKOWSKI, GOVERNOR A...A~1iA OIL AND GAS CONSERVATION COMMISSION 333 W. 7'" AVENUE. SUITE 100 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" Integrity" Confinement" Area Injection Orders AIO 1 - Duck Island Unit 6 7 9 AIO 2B - Kuparuk River Unit; Kuparuk River, 6 7 9 Tabasco, Ugnu, West Sak Fields AIO 3 - Prudhoe Bay Unit; 6 7 9 Western Operating Area AIO 4C - Prudhoe Bay Unit; 6 7 9 Eastern Operating Area AIO 5 - Trading Bay Unit; 6 6 9 McArthur River Field AIO 6 - Granite Point Field; 6 7 9 Northern Portion AIO 7 - Middle Ground 6 7 9 Shoal; Northern Portion AIO 8 - Middle Ground 6 7 9 Shoal; Southern Portion AID 9 - Middle Ground 6 7 9 Shoal; Central Portion AIO lOB - Milne Point Unit; Schrader Bluff, Sag River, 4 5 8 Kuparuk River Pools AIO 11 - Granite Point 5 6 8 Field; Southern Portion AIO 12 - Trading Bay Field; 5 6 8 Southern Portion AIO 13A - Swanson River 6 7 9 Unit AIO 14A - Prudhoe Bay 4 5 8 Unit; Niakuk Oil Pool AIO 15 - West McArthur 5 6 9 · I Affected Rules "Demonstration of "Well Integrity "Administrative Injection Order Mechanical Failure and Action" Integrity" Confinement" River Unit AIO 16 - Kuparuk River 6 7 10 Unit; Tam Oil Pool 6 8 AIO 17 Badami Unit 5 AIO 18A - Colville River 6 7 11 Unit; Alpine Oil Pool AIO 19 - Duck Island Unit; 5 6 9 Eider Oil Pool AIO 20 - Prudhoe Bay Unit; 5 6 9 Midnight Sun Oil Pool AIO 21 - Kuparuk River 4 No rule 6 Unit; Meltwater Oil Pool AIO 22C - Prudhoe Bay 5 No rule 8 Unit; Aurora Oil Pool 6 9 Ala 23 Northstar Unit 5 AIO 24 - Prudhoe Bay Unit; 5 No rule 9 Borealis Oil Pool AIO 25 - Prudhoe Bay Unit; 6 8 13 Polaris Oil Pool AIO 26 - Prudhoe Bay Unit; 6 No rule 13 Orion Oil Pool Disposal Iniection Orders DIO 1 - Kenai Unit; KU No rule No rule No rule WD-l DIO 2 - Kenai Unit; KU 14- No rule No rule No rule 4 DIO 3 - Beluga River Gas No rule No rule No rule Field; BR WD-l DIO 4 - Beaver Creek Unit; No rule No rule No rule BC-2 DIO 5 - Barrow Gas Field; No rule No rule No rule South Barrow #5 DIO 6 - Lewis River Gas No rule No rule 3 Field; WD-I DIO 7 - West McArthur 2 3 5 River Unit; WMRU D-I DIO 8 - Beaver Creek Unit; 2 3 5 BC-3 DIO 9 - Kenai Unit; KU 11- 2 3 4 17 DIO 10 - Granite Point 2 3 5 Field; GP 44-11 I . Affected Rules "Demonstration of "Well Integrity "Administrative Injection Order Mechanical Failure and Action" Integrity" Confinement" DIO 11 - Kenai Unit; KU 2 3 4 24-7 DIO 12 -Badami Unit; WD- 2 3 5 1, WD-2 DIO 13 - North Trading Bay 2 3 6 Unit; S-4 DIO 14 - Houston Gas 2 3 5 Field; Well #3 DIO 15 - North Trading Bay 2 3 Rule not numbered Unit; S-5 DIO 16 - West McArthur 2 3 5 River Unit; WMRU 4D DIO 17 - North Cook Inlet 2 3 6 Unit; NCru A-12 DIO 19 - Granite Point 4 6 Field; W. Granite Point State 3 17587 #3 DIO 20 - Pioneer Unit; Well 3 4 6 1702-15DA WDW DIO 21 - Flaxman Island; 3 4 7 Alaska State A - 2 DIO 22 - Redoubt Unit; RU 3 No rule 6 D1 DIO 23 - Ivan River Unit; No rule No rule 6 IRU 14-31 DIO 24 - Nicolai Creek Order expired Unit; NCU #5 DIO 25 - Sterling Unit; SU 3 4 7 43-9 DIO 26 - Kustatan Field; 3 4 7 KF1 Stora2e In.iection Orders SIO 1 - Prudhoe Bay Unit, No rule No rule No rule Point McIntyre Field #6 SIO 2A- Swanson River 2 No rule 6 Unit; KGSF #1 SIO 3 - Swanson River Unit; 2 No rule 7 KGSF #2 Enhanced Recovery Injection Orders EIO 1 - Prudhoe Bay Unit; No rule 8 Prudhoe Bay Field, Schrader No rule Bluff Fonnation Well V-10S I · , Affected Rules Injection Order "Demonstration of "Well Integrity "Administrative Mechanical Failure and Action" Integrity" Confinement" EIO 2 - Redoubt Unit; RU-6 5 8 9 , . I 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER ADVERTISING ORDER NO. INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO, CERTIFIED AO-02514016 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE F AGENCY CONTACT DATE OF A.O. AOGCC 333 West ih Avenue, Suite 100 o Anchorage,AJ( 99501 M 907-793-1221 R PC DATES ADVERTISEMENT REQUIRED: T o Journal of Commerce 301 Arctic Slope Ave #350 Anchorage, AJ( 99518 October 3, 2004 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: United states of America AFFIDAVIT OF PUBLICATION REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. A CERTIFIED COpy OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. ATTACH PROOF OF PUBLICATION HERE. division. Before me, the undersigned, a notary public this day personally appeared who, being first duly swom, 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 lof2 9/29/2004 1:10 PM Public Notices , , 20f2 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 Please publish the attached Notice on October 3, 2004. Thank you. Jody Colombie Content-Type: application/msword Mechanical Integrity of Wells Notice.doc Content-Encoding: base64 Content-Type: application/msword Ad Order form. doc Content-Encoding: base64 I of 1 9/29/2004 1: 10 PM Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Kelly Valadez Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 , . /fla¡kd 1¿7/jk~ David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 John Levorsen 200 North 3rd Street, #1202 Boise, 10 83702 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle,WA 98119-3960 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 David Cusato 200 West 34th PMB 411 Anchorage, AK 99503 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow, AK 99723 ,[F:d: Re: Consistent Wording for Injecti.ders - Well Integrity ... , Subject: [Fwd: Re:ConsistentWotcjm~~()t Ir1j~cti()~ Order~ "Wêll ~têgritY{'Revised)] From: John Norman.<john=norman@aClmin~state.ak.us>; Dâte:Fri,·OI Oct 2004 J 1:09:26..0800 more -------- 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~law.state.ak.us> To:jim regg~admin.state.ak.us CC:dan seamount~admin.state.ak.us, john norman~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 weIl 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 <iim regg@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 <iim regg@admin.state.ak.us> 8/17/20044:33:52 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 lof2 10/2/20044:07 PM [Fwd, Re' Con,istent W n.-ding fo, loj",tion cS - Well Integ"ty ... . _ 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@admin.state.us> Commissioner Alaska Oil & Gas Conservation Commission 20f2 10/2/2004 4:07 PM {FW~: Re: Consistent Wording for Injecti.ers - Well Integrity... , Subject: [Fwd: Re:ConsistentW ording for Injection Onfers ". Well Intègrity (Revised)] Frf)m: John Norman <john_nonnan@admin.state.ak.us> Date: Fri, 01 Oct 2004 11 :08:55 -0800 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 200415:46:31 -0800 From:Rob Mintz <robert mintz~law.state.ak.us> To:dan seamount~admin.state.ak.us, jim regg~admin.state.ak.us, john norman~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 <¡im regg@admin.state.ak.us> 8/17/20044:33:52 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 Well Integrity Failure (i.e., more fi-equent MITs when communication demonstrated) - establishes more frequent MIT schedule for sluny 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 lof2 10/2/20044:07 PM [Fwd: Re: Consistent Wording for Injection 01- Well Integrity ... . - adopts "Administrative Actions" title (earlier rules used "Administrative Relief'); - consistent language regardless of type of injection (disposal, EaR, 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", "USDW s"; "risk of fluid movement"; "fluid escape from disposal zone" Jim Regg John K. Norman <John Norman(ã)admin.state.us> Commissioner Alaska Oil & Gas Conservation Commission Content- Type: applicationlmsword Injection Order language - questions.doc Content-Encoding: base64 Content-Type: applicationlmsword Orders language edits.doc Content-Encoding: base64 20f2 10/2/2004 4:07 PM · , 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, 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 Fonn 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 every four years thereafter (except at least once everv two years in the case of a slurry injection well), and before returning a well to service following after a workover affecting mechanical integrity, tmd at least once every '1 ycar~; '.vhile octi';ely injecting. For slurry injection '.vells, the tubing/casing Œ.1lulus must be tested for mechanical integrity every 2 years. Unless an alternate means is approved bv the Commission. mechanical integrity must be demonstrated by a tubing pressure tcst using a +he MI+-surface pressure of must be 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, that ffH:lSf-shoWâ stabilizing pressure that doesand may not change more than 10i¥tt- percent during a 30 minute period. --A:aÿ 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 Except as otherwise provided in this rule, +!he tubing, casing and packer of an injection well must demonstrate maintain integrity during operation. 'Whenever any pressure communication, leakage or lack of iniection zone isolation is indicated by iniection rate. operating pressure observation, test, survev, log. or other evidence. t+he operator ffffiSt-shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval~ whenever an v pressure communication. leakage or lack of injection zone isolation is indicated bv 0/ _ , _ "" injection rate, operating pressure observation, test, survey. or log. The operator shall shut in the well if so directed bv the Commission. The operator shall shut in the well \vithout awaiting a response Ü'om the Commission if continued operation would be unsafe or would threaten contamination offreshwaterIfthere is no threat to freslrA'ater, injection may continue until the Commission requires the ',cr.-ell to be shut in or secured. Until corrective action is successfullv 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. O[F;d: Re: [Fwd: AOGCC Proposed WI L.ge for Injectors]] , ~µÞlect: [Fwd: Re: [Fwd: AOGCC Proposed WI Language for Injectors]] ~r()~:.Winton Aubert <winton_aubert@admin.state.akus> Date: Thu, 28 Oct 2004 .9:48:53 -08.00 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 Aubert <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 Aubert wrote: FYI. ..-------- Original Message -------- AOGCC Proposed WI Language for Tue, 19 Oct 2004 13:49:33 -0800 Engel, Harry R <EngelHR@BP.com> winton aubert@admin.state.ak.us Injectors Subject: Date: From: To: 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 Ai 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*_** 100 10/28/2004 11 :09 AM [Fwd: Re: [Fwd: AOGCC Proposed WI Langu.r Injectors]] . returnj_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 colombie@admin.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 00 10/28/2004 11 :09 AM #6 '.1.. !:~¥~¥Œ , m~~~~~ ALASKA OIL AND GAS CONSERVATION CO~I~IISSION June 7, 1994 t,yALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE. A~KA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 ife.- ¡vt- fl...p i r G'F Hal Martin Reservoir Engineer Unocal Corporation Post Office Box 190247 Anchorage, Alaska 99519-0247 # ~ Re: Class II fluids, Grayling and Monopod platforms, Cook Inlet, Alaska À \<:J ç þ'\C) \ ã. Dear Mr. Martin: The commission has reviewed your request to augment waterflood injection on the Grayling and Monopod platforms with treated sanitary wastewater and glycol. Based on the chemical analysis provided} the commission acknowledges that treated sanitary waste water on both platforms is similar to the current EO~ injection fluid. Accordingly, the commission concurs that the treated wastewater is appropriate to augment the current EOR fluid. On the other hand, no data was submitted to support the glycol/water mixture as an appropriate EOR injection fluid. Therefore, the commission cannot conclude one way or the other its suitability for recovering hydrocarbons. Should you have further questions regarding this matter please do not hesitate to contact us. £',t p,i"led on 'ccycl~d p...pro, lJ yen ~5 s Unocal North Amen"'" Oil & Gas Division ~ Unocal Corporation 909 West 9th Ave., P.O. Box 190247 Anchorage, Alaska 99519-0247 Telephone (907) 276-7600 \.c.ts d,'~,--,~ UNOCALe ~ . . VIV!I\:¡ ~ COMM 'V ~.. COMM f-- . . RES ENG ¡ SR .E~IG I SR ENG I ENG ASSm ENG ASST I SR GEOL I I GEOL ASST I ! GEOL ASSTI STÄT TECH' Si'AtTECHi- -=ILE J May 24, 1994 Alaska Region K£CE\VED MA- '{ 2 7 '994 . . 0 Gas Cons. Commission ;).\",5\(1 UII Ql Anchorage Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501-3192 Attention: Mr. David W. Johnston Commissioner ~ ~-~~ ¿,..7, <f'-l _ Y Subject Class II-E Fluids Grayling and Monopod Platforms McArthur River Field Cook Inlet, Alaska Gentlemen: Union Oil Company of California (Unocal) requests the concurrence of the Alaska Oil and Gas Conservation Commission (AOGCC) with regard to supplementing the Grayling and Monopod Platforms' waterflood injection fluid (Cook Inlet sea water) with treated sanitary wastewater and glycol. Unocal believes the supplemental injection of such fluids will be used primarily to enhance oil recovery operations and will beneficially minimize the discharge of these wastes through recycling. The Grayling Platform currently uses approximately 76,000 barrels per day (BPD) of filtered Cook Inlet sea water as injection fluid for waterflooding. The primary supplemental fluid, treated sanitary wastewater, accounts for volumes in the range of 207 BPD (normal activity) to 279 BPD (during rig activity). These daily volumes include 171 BPD of filtered inlet water used as " make up" water for the treatment system. Therefore, the sanitary wastewater constitutes only 0.27% of the total daily volume injected on the Grayling Platform under normal operating conditions, and 0.37% under worst case conditions. The glycol wastes are generated intermittently. Based on historical records, a total of 100 barrels per year of 60% glycol/40% water mixture would be injected over two (2) non-consecutive days during the year. The glycol/water mixture would add 0.066% to the total daily injection volume in each of the two days. · . ~ tI .' Mr. Johnston AOGCC May 24, 1994 ~ . ,. The Monopod Platform currently uses approximately 6,000 BPD of filtered Cook Inlet sea water as injection fluid for waterflooding. The primary supplemental fluid, sanitary wastewater, accounts for volumes in the range of 185 BPD (normal activity) to 240 BPD (during rig activity). These daily volumes include 171 BPD of filtered Inlet water used as "make up" water for the treatment system. Therefore, the sanitary wastewater constitutes 3.08% of the total daily volume injected on the Monopod Platform under normal operating conditions, and 4.00% under worst case conditions. The glycol wastes are generated intermittently. Based on historical records, a total of 100 barrels per year of 60% glycol/40% water mixture would be injected over two (2) non-consecutive days during the year. The glycol/water mixture would add 0.83% to the total daily injection volume in each of the two days. Enclosed for your review are the analyses of the sanitary wastewater and Cook . Inlet water used to support Unocal's request. If you have any questions or need additional information in order to make your determination, please call me at 263-7675. Sincerely, ¡JaiL ;1J~ Hal Martin Reservoir Engineer GRWASTE.DOC enclosures cc: P.W. Lokke C.B. Beauchamp Grayling Foremen Monopod Foreman RECEIVED MA Y 2 7 1994 Alaska Oil & Gas Cons Com ". An . mIssIon chorage MAY 18 .~ '94 14:01 RR . ... ...., èomm8rci~"esting&: Engineering Co. . Environmental Laboratory Services .....,"'11"",".....".......11I',........'1'.....'.......,;.· LABORATORY ANALYSIS REPORT 94.2015-1 ; ; BINGHAMDISCHAilŒIGRAYLINOPLATFORM WA'IER UNfJCAL.OIL.t GAB DIVISION RAND PRICE StHC'1 I ttOI . CTa:BW.' CUentSample1D Matrix ClieøtName ¡ OidcredBy ¡ PJOjtICt NIDIC .: Projectl . i , PWSJD UA ~, : . .' WORK. <>rIt« PrintedDate CoJlec:tedDBte ReceivedD8te 78018 0S/16194 @ 16:.33 bu. 04Il6I94 @ In. 05/03194. @13:OO )n. Technical Diœctor ., IUJIa¿f C. EDB . ~--C. ~. ReleuedBy: ..,...".--- =v. Simple lùIDå.: SAMPLE COLLBCTIIDBY: VA. Pmmeter QC . Results Qual 340 1000 0.50 U 2180 8900 6.3 o U' 0.1 U 1.0 U 112 3 CsIciam Mspesium Bmum Sulfate Sodium StnmIium CarbonIte " Ch1o.riDe (ØIÌåUI1) . Iron , B~AJka1ioity . Raidae,NOD-F'ùtaable " t!..r..:":"'~''''. .- AIIøWIble Ixt. ADa1 Units Method Limita Date DIœ Juit mg/L EPA200.7 ICP osn.f194 DFL mgIL EPA200.7ICP 05114J94 t>FL mgIL EPA200.7ICP OSI14J94 DFL mg/L EPA3ÐO.OION 0SI05I94 MCE mgIL EPA200.7ICP 0S/14194 . DFL mgIL BPA 200.7 ICP 0SI14194 DFL mgIL 8M OSlO4l94 IEK ppm TAYLOR9081/9083 05106194 OSlO6l94. GPP m.gIL BPA200.7ICP 051104194 DFL mg/L EPA310.1 051Ð4194 IEK mgIL EPA 160.2 . 05lO9Ð4 . 0SIl0l94 1MW 'RECE\VEO MAY 2 7 1994 . AlaSKa ulI & Gas Cons. l,OlllffilSsion Anchorage · See Speciallast:nlJtiona AbOTe UA = Ua.aYsilable .. SecSempJeItaaalb Above 1«. Not·AìWyZed ! U· Uldetectcd, Reported ya1ue i. Gte P.I'ICtic:a1 CjIIII1tification limit LT- Les.1hm ~ D-Secoøcllrycihåion. '. .': . .' '. Gf.Ch:It...... ~ '. .' 6633 B Street.Anc.. AK 996''';800 - Tel: (907)> 562-2343 Fax: (907) 561-6301 eNVIRÇ)~eNTAL FACIUTlES IN ALASKA, COLORAOO. FLORIDA. IWNOIS. MARYlAND. NEW JERSEY. OHIO. UTAH. WEST VIRGINIA .'.. .... ~ ,18 '94 14'"2 ""., ..¿:t~ -- Commercial Testing & Engineering Co. En~ronmental Laboratory Service, ....lI..ßI~_:iI"I'AIIU"..._..dwam-vJII~ Jlr:~"'r# SINCI '101 LABORATORY ANALYSIS REPORT C1'&E'kf.' Client SlIIDplc ID Mallix 94.201S-2 OMNIPUREDISCHARGFlGRAYUNGPLA'1110RM WA'ŒR Client Name Ordered By Project Name ProjectM PWSID UNOCAlA>n. & GAS DMSION RAND PRICB UA Sample RaDås: SAMPLE COIJ.BC11ID BY: UA. . Parameter QC Raulf8 Qual Calcium Magnesium Barium Sulfate Sodium Strontium CarbOlUlte Chlorine (residual) Iron Bicarbonate,AlbliDity Reaidue,Non-F1ltcnIblc 310- 950 0..50 . U 2100 8300 5.8 o U 8 1.0. U 131 8 WORK Order 78018 PriDtedDate 0.5116/94 @ 16:33 bra. CQllectedDllte 04126194 @ hø. 1bIceindDatc o.SI03I94 @ 13:00 In. TecJuùc:al DnIc:tot zmsr!œlf C.EDE RelaledBy: ~C. ~~ ... - _.~.-.. AUØWIIb1e Bxt. AIIII Units Mr:tbod . Limits Date Dille fait mgIL EPA200.7ICP o.SII4JM DFL mgIL EPA2oo.7ICP OSß4JM DFL mgIL EPA 200.7 ICP OSß4J94 DFL mgIL EPA 300.0. ION OS1œ194 MŒ mgIL BPA200.7ICP o.Sß4J94 DPL mgIL ErA 200.7 ter 05n4J94 DFL mgIL 8M OSJ1J4I94 Dq{ ppm TAYLOR908119083 0.5106194 OS~ GPP mgIL BPA200.7ICP 0.5/14/94 DFL mgIL EPA 310.ì 051U4194 IEK. mgIL EPA I$).2 0.5109/94 0.5110194 1MW RECEIVED' MAY 2 7 1994 . Alaska Oil. & Gas COrts ( , . ..,ommfSslOO Anchorage . .. See SpeciaI·!utm::tioal Above .. S.&allp1eIliimlltlAbove ! . U - UndCteetcd, Rq!oit«l..... II .. pøctica1 cpnti1iœtiOJt limit. . ~ Dc Secoadlry cihüoa. . ~ UA- Ulurt'aillble NA- NotADalyzld LT-1as 'IUa.' Gr- Øater'Dla .~ .' 5633 B Street. Anchorage. AK 99618-'800 ;.... Tel: (907) 582-2343 Fax: (907) 681-&301 ENVIRONMENTAL FACIUOeS IN ALASKA. COLORADO. FLORIDA. ILLINOIS. MARYlAND, NEW JERSEY. OHIO. UTAH. WESTVlRGIMA , OS/24/94 . , . ~t... ;Ik~~ 10ft" C"r&~ Rcf,1I Client Samp Ie ill Ma.trix Client NtlIUe Ordered By ¡'rojecl Nume Projccl# pwsm 09, 21 ~IR!J.tENrnL lAB SERVICES . 9I37~ Commercial Testing & Engineering Co. Environmental laboretory Services .......,.,...",..........",.....,..........,...."....."1"1"......11....'1"....... NO. 862 ~03 - LABORATORY ANALYSIS REPORT 94.2016-2 SEWAGE DISCHARGElMQNOPOD WA'ŒR UNOCAL-OIL & GAS DIVISION RI\ND PRICR WORK Order Printed Dllte CnJlectcd Dllte Receí v ed Da~e 78019 05fl8194 04127/94 05103/94 @ 10:28 Ius. @ hrs. @ 13:()( hr:s. UA Technictù Director ST~I'HEN C. EDE Released By; ~c__~__ Sample Ranorkl1: SAMPLE ëöï:ï:ËC'IDD UY: UA. Par.uncter --- -------- Calcium Magnesium Barium Sulfate Sodium Strontium CIabonate Clùorine (residtuù) Iron l1icarbonalc,Alkalinity Residue,Non-Fùtel'1lble ..._--~ .,,----.,..-------~ -- Rc~ulll1 QC Qual Allowable Rxt. AMI Ullit¡; Method Limits r.)atc Date WI _.-- mglL BFA :WO.71CP 05114/94 DFL mg/L EPA 200.7 fCP 05/14/1)4 DFL II18/1.. EPA 20U.7 ICP 05/14/94 DFL mgIL P,P A 300.0 ION 05/05194 MCH mg/L HT'A200.71CP 05/14194 lWI. mgIL EPA200,71CP ()S/14/94 1)1'1. I11gIL 8M 05/04/94 JEK ppm TAYLOR908 Jl90S3 05/06/94 05/06/94 01'1' mg/L EM 200,71CP OS/14/94 DF.t, mgIL EPA310.1 05/04/94 IRK mgIL EPA 160.2 OS/09{IJ4 051[0194 TMW 340 990 0,50 212(J 860() 6.2 () 5 1.0 114 18 u u RECEIVED MAY 2 7 i994 Alaska Oil & Gas Cons. Commission Anchorage ---- ---- ..- -- ~===- - - ~~ ======- ----==.:..:::.:== · 8~ Special InstJ:uction~ J\bove .. See Sample ReJ11arks Above tJ = Undt:tected, Reported value is the l'ractieal (\IUltitication limi L ~ I) = Secondary dilution. ë ~ ;'" Ii.. UA=lJnavai!tIl'le NA.. Not.AnulY7ed LT=Ids1han Gr = (ìreatcr Than 56338 Street. Anchorage. AK 99618·1600 - Tel: (907) 562-2343 Fax: (907) 561·5301 . '-.. --- ... .. --.. '--.. . -....--.. ENVIRONMENTAL FACILITIES IN ALASKA, COLORADO. FLORIDA, IllINOIS. MARYLAND, NEW JERSEY, OHIO. UTAH. WEST VIRGINIA , OS/24/94 ¡;g'21 "IROf'ENTfL LAB SERVICES. ~ Commercial Testing & Engineering Co. Environmental laboratory Services ...111-'1.11'I'111'..........11.1'1'1'1'1'1......,.........1'1"",...... NO. 862 002 1; '. , - . ~f~- :!:tNCe.1!1U¥ LABORATORY ANALYSIS REPORT ": . " CT&E Ref.lI Client Scmq¡le 11> . Matrix 9<1.2016-1 W A1"illU'LOOD INJECTrONIMONOPOD WATER ", Client N fltne Ordered By I'roject Name l'rojectl# I'WSID UNOCAL-OlL &. GAS DMSION RAND PRICE WORK Order Printed Date CollcclcdDote ReoeivcdD;ìte 78019 IIS1ISl94 ()4127/94 05103194 (~ 10:28 br". cJJ 11rS. @ 13:00 hrs. UA Technicttl Director STEPHEN c.l:mE Released By: ~c_~ _ ------ ------ ---- SlImP 1 e llemlU"k.3: SAMPLECOLLF.CTEDBY: UA. QC Allowable Hxt. Ann! Parameter Resulls Qual Unite¡ Method J..imits Date Date Inil ---- Calcium 330 m.¡¡IL EPA201).7TCP 05/14194 .>FI. Magnesiutn 1000 mgfL EPA200.7ICP 05/14/94 1)1<'1. Barium 0.50 u mgIL EPA 200.7 TCI' 05/14194 1)1"1. Sulli1te 2150 111 gII . EPA ]00.0 ION 05105/94 MCE Sudium 87(J() mglL EVA 200.7 ICP 05/14/94 DFL Sltòlltium 6.2 mg/L IWA 200.7 ICP 05/14194 DFL CtI1'blU1ate () U mglL SM 05/04/94 IEK Chlorine (residutù) 0.1 U ppm TA YLOR9081/9083 115/06/94 05/1)6194 GPP Iron 1.0 U mg/L EPA 200.7 TCP 05/14194 DFL llicarbonatc,A1kulÏI1 ity 11() mglL RPA 310.1 ()5104f94 ŒK Re.,jdue, Non-}o1lterahle 4 mgIL BPA 160.2 05/09/94 OS/10/94 Opp RECEIVED MAY 27 1994 Alaska Oil & Gas Cons Cornm' . . I ISSlon Anchorage =======-- .'" -====e_ -=-:= -:-:- ..~._--::==~.:..: ' ....... -- -=~---=====--~ · See Spt:çìll11nstl"OOlions Above .. See Sample Remarks Above .. U" Undetected, Reportl.-d value is the practical qœntification limit. ~ ~ D=Secondary <i1ution. E C'. l- lL UA = Unllv!Ùlllhle NA '" Not Analyted l;r=Les~ 'Ulan &1':: Gn:ater Than . 5633 a S~reet. Ä"chorage, .~K 9961~:1600 - Tel.: (907) 562·2343 F~)(: (907) 561·5301 ,..._.. .__ ENVI~ONMeNTAL FACILmeS IN ALASKA, COLORADO. FLORIDA. ILUNOIS. MARYLAND. NEW JERSEY. OHIO, UTAH, WEST VIRGINIA ~A- r- - Unocal Oil & Gas Divisicr Unocal Corporation "'- P.O. Box 190247 Anchorage, Alaska 99519-0247 Telephone (907) 276-7600 Environmental Group Alaska District September 24, 1986 ;!¿~.. L-- ~ ðJf I '-:D tB(l ;it( t E ~~) :::r UNOCALe Mr. Lonnie Smith, Commissioner Ak. Oil & Gas Conservation Comm. 3001 Porcupine Drive Anchorage, Ak. 99501 Dear Mr. Smith: " Addendum to Application for an Area Injection Order, Trading Bay Field Cook Inlet, Alaska In response to Mr. C.H. Case's recent conversation with Blair Wondzell, it was brought to our attention that we inadvertently omitted the "D&E" Commingled and "Hemlock" Zones in our Application for an Area Injection Order for the Trading Bay Field. Unocal herein requests that the "D&E" Commingled and "Hemlock" Zones be included in our application for an area injection order as defined by Conservation Order Nos. 93 and 101. For your information, we have included a copy of the water analysis reports for both the "D&E" Commingled and Hemlock Zones, and request that they be included in our application for injection. Should you have any questions, please feel free to contact Candy Lockwood at the above number. Very truly yours, Þ Ú; LJ ¡ r-l- rf'7!ì . TIMJÞUj Roy D. Roberts Environmental Engineer Attachments cc: C.H. Case RECEtVED SEP 2 9 1986 Alaska OU & Gas Cons. líommission Anchorage .. , CHEMICAL & ~EOLOGICAL lABORATO(S TELEPHONE (907) 279-4014 OF ALASi<A, INC. 2603 ARCTIC BLVD P. O. BOX' 4 - 1 276 ANCHORAGE, ALASKA 99509 WATER ANALYSIS REPORT OPERATOP Union Oil Company of Calif. DATR February 9, 1972 LAB NO 0138-11 WELL NO A-18 LOCATION Mono~od ~~:;;~~ FIELD Trading: Bav FORMATION ~ R COUNTY INTERVAI. STAT'll Alaska SAMPLE FROU Wellhead REMARKS a: CONCLUSIONS- Sample taken February 1, 1972. Cloudy water, oil present. c.. tiona ~ 9994 198 890 170 ~ 434.70 5.07 44.41 13.97 Sodium Potuaium Calcium - Magnesium 1roD . . . . ( 498.15 Total Cationa . . . . ~ Sulfate - - - - Chloride _. - - Carbonate Bicarbonate Hydroxide \ mrrl1 55 17000 o 1074 ~Jl 1.14 479.40 17.61 Total Aniooa 498615 " Total diuolved fIOlida, m(l/1 -. - . . NaCl oquivalCIDt, m&/l - - . . ObMtved pH - - - - · · · . 28836 28695 7.8 Specific rcaiatnnce @ MOF.: Obaerved -... 0.215 o11xrrmGta'l Ca1cu1D.t~d . RECE~ ~mw.n SEP 2 9 1986 WATER ANALYSIS PATTERN Seal Waska Oil & Gas Cons. ltoUHíìission ,MEQ ;r Unit Anchorage Sample above described Na Cl 100 Na ~- Cl t..... . HC03 10 Ca ~ HC03 Ca Mg 1 SO", 10 Mg H- SO", 'I t Fe C03 10 Fe COa C (Ha nbM In .bon craphl iDdudel Na. E:, &lul U) HOTE: HK/I=JlWírrama per Uter Jlevl= Kill1&Tam equinlenœ per lit« Iodhua cbJoricte equinJeat = b7 Dwû.ap. A HawtbOnM ca.lculaÓOft frea ~~ ,,-- r CHElV1ICAL &'-' GEOLOGICAL LABORATOhTêS TELEPHONE (907) 279 -4014 P. O. BOX 4-1 276 ANCHORAGE, ALASKA 99509 OF ALASKA, INC. 2603 ARCTIC BLVD WAT~R ANALYSIS REPORT OPERA TOP Union Oil Company of Calif. WELL NO A-14L FIELD Tract tng Bay COUNTY STAT~ Alaska DAT~ February 9, 197.2 LAB NO 0138-8 LOCATION Monopod Platform FORMATION ( Hemlock") INTERV AI~ SAHPLE FROU Wellhead REUARKS a: CONCLUSIONS' Sample taken February I. 1972 Cloudy brown water. oil present ~tionA ~/1 ~ ~ , !:!:.1L! !E!1iJ. Sodltun - - - . 12244 532.60 Sulfate .. .. .. .. 31 0.64 PotaGaium 375 9.60 Chloride .. . - 43000 1212.60 Calcium - 12800 638 . 72 Carbonate 0 Wagneøium - . .. .. - 420 34.52 Bicarbonate .. 134 2.20 IroA Hydroxide ( Total ~tiona 1215.44 Total AnioDa 12]5 .d4 ,I . Total cüuolved GOUda, m¡:/1 - - - .. - 68936 Specific rcaißtnnce @ 68°F.: HaC1 oqwvaleot, m¡/1 . - . - . 68671 01x¡~ed - . . . 0.128 ohm-~ ObMned pH . - . . . 6.8 C&1cuW~ . . . . 0.125 o.bm-~ WATER ANALYSIS PATTERN Scale Sample above described MEQ per Unit RECEIVED SEP 2 9 1986 Alaska on· & Gas Cons. Commission ora e Na Cl 200 Na Cl :.'1-'+1 . ,M-! . ' I . \ I C. :,' HC03 20 Ca HC03 Mg < 80.4 20 Mg 80.4 . { Fe CO! 20 Fe COa l (Ha nl1H In .bow cnphl ÎJ)e!ucúe Na. Xt and U) HOTE: Mr/l=Killirramt per Uter Jhq/l= J¡(i1Uçam equi....l.l1t1 per Ut'Ir Iodhua cbJ.ori4e ~w.ùeat= b7 D\UI.1ap.. HnnilOI"M cakuladoa frOla ~~ *3 e Unocal Oil & Gas DivisiA. Unocal Corporation . P.O. Box 190247 Anchorage. Alaska 99519-0247 Telephone (907) 276-7600 UNOCAL8 Environmental Group Alaska District September 16, 1986 Mr. Lonnie Smith, Commissioner Ak. Oil & Gas Conservation Comm. 3001 Porcupine Drive Anchorage, Ak. 99501 Dear Mr. Smith: UIC CORRECTIONS In response to our recent conversation, I have attached corrected pages for Unocal's recent Area Injection applications. -' The first attachment corrects 2.7 MMSTBD to read 2.7 MMSTBO and should be placed in the Trading Bay Field Injection application. The remaining 3 attachments should be placed in the applicable applications, ie, Granite Point Platform, Trading Bay Field and Trading Bay Unit. Please give me a call if you have any questions. Very truly yours, //- C£t;?~ð-'7I-- Candace tockwood Environmental Department Attachments itfCtlVED - F 1. ? 1986 ,JJaska Oil ,~ Gas Cons. CHEMICAL &.- bEOLOGICAL LABORATOIí.5 TELEPHONE (907) 279·4014 P. O. BOX' 4 ·1276 ANCHORAGE, ALASKA 99509 OF ALASKA, INC. 2603 ARCTIC BLVD WATER ANALYSIS REPORT OPERATOF WBLL NO FIELD COUNTY STAT1t Union Oil Company of Calif. A-18 Tradin~ Bav DAT'It February 9, 1972 LAB NO LOCATION Monopod Platfpr1Il FORMATION ~ & E Coml n~~ INTBRV AT. SAMPLE PROU Wellhead 0138-11 Alaska REMARKS A CONCLUSIONS' Sample taken February I, 1972. Cloudy water, oil present. c.tkma am/t ~ ~ . mrr/1 ~~Jt - SodiIUD . . . - 9994 434.70 SaUlte - . - - 55 1.14 Poœaium 198 5.07 Chlorid. . . - - 17000 479,40 Calcium - 890 44.41 Carbona te 0 lIagDCIÎ.um . . . . . 170 13.97 Bicarbonate 1074 17,61 Inm - - - - Hydroxide ( Total Catiooa . 498.15 Total Aniooa 498. , 5 ." Total diøolved oolida, 1DlÚ! 28836 Specific rWUlnce @ 68°P,: HaC! tlqWvalClOt, IDI/t . . . - 28695 Obaervod . . . . 0.215 obm-maten Oboervecl pH . . - - - - - ' ' - - . 7.8 Cakulzue;d 0.20 ~~ -'. WATER ANALYSIS PATTERN Sc:nlø Sample above described ,MEQ per Unit ~ Na Ct 100 Na Cl Ca ... HCOa 10 Ca HC03 Ug ~ S004 10 Mg S04 '1'! Fe COa 10 Fe COI ( (H. ...... III .1Ioft I"'aphl lad..... No. IC, 04 U) NOTE: KI/I=..01iI"'..... pot' Utot Ihq/I= J¡(~ oquinl'Dta '* U_ 104..... cbJon4. oqw.u..t=" D........" H""",.... calculadoa IcCIID ~III '- CHEMICAL & 'GEOLOGICAL LABORATO!S TELEPHONE (907) 279-4014 P. O. BOX 4 ·1276 ANCHORAGE, ALASKA 99509 OF ALASKA, INC. 2603 ARCTIC BLVD WATER ANALYSIS REPORT OPERATOP Union 011 Company of Calif. WELL NO A-14L FIELD Trading Bay COUNTY STATII! Alaska DAT~ February 9 I 1972 LAD HO 0138-8 LOCATION Monopod Platform FORMATION ( Hemloclt) INTERV AT. SAlIPLE PROU Wellhead REUARKS ct CONCLUSIONS' Sample taken February I. 1972 Cloudy brown water. oil present / Catfona mltll ~ ~ . .s:L! re:::a II - - SodIum - - - - 12244 532.60 Sulf¡te . . . - 31 0.c;4 Potaoøium 375 9.60 Chloride . . - 43000 1232.60 Calcium - - - - 12800 638.72 Carbonate 0 Wagu.eaåum 420 34.52 Blc:arbonate . . . - . 134 2.20 ÜOQ - - - - Hydrozide ( ToQl Cationa 1215.44 Total AnJona 12]5..14 ,1,'- Total clialOJved IOlida, m¡:/1 - - - 68936 Specific rcai4tnnco @ 68°F.: N.CI oquiva1eat, mall 68671 Obc¡avød . . . . 0.123 obmocm.n ObMned pH - - - . . . . . . . 6.8 ~'-C1 0.125 cJ¡m.QOUilI I WATER ANALYSIS PATTERN Swe Sample above described MEQ per Unit - . ....... . , - .. Cl HCO:s 804 I CO. Na Ct 200 Na .... Ca HCO:a 20 Ca Mg 804 20 Mg Fc COs 20 Fe l . . .... (NI ...... III llIoft I1'l9hl I.dud. Na, E. .... LI) NOTE: K./l=MßIiI1'- 1* Uter Weq/l= JiiJJlcnm equinloDta I*' Utw IodIuJa cb&oriclo o'Iuinloat=b1 DUDIap.. H....u._ cakuladoa 11_ ~. :#a - .~. $T~TE OF ALASKA . ÀDVERTISING ORDER e F R o M Anchorage Daily News P. O.Box 149001 Anchorage, Alaska. 99514-9001 T o p U B L I S H E R Alaska. Oil & Gas Conservation Cœmf..ssion 3001 Porcupine Drive Anchorage, Alaska. 99501 . AGENCY CONTACT Galyn Evans 279-1433 PHONE (907) DATES ADVERTISEMENT REQUIRED: þ',./.....", ,F"P;.:;;' AOVERTlSING06DJ:,R..NO. AO- 08-5571 DATE OF A.a. SeptEfd:>er 10, 1986 Septenber 12, 1986 SPECIAL INSTRUCTIONS: f. 1\ "p 1 9 1986 & Gas Cons. ('1 . . \·''-·¡·J~(\.f1e """""\.'-' AFFIDAVIT OF PUBLICATION UNITED STATES OF AMERICA STATE OF ~ ~ ss DIVISION; BEFORE ME, THE UNDERSIGNED, A NOTARY PUBLIC THIS DAY PERSONALLY APPEARED ~ WHO, BEING FIRST DULY SWORN, ACCORDING TO LAW, SAYS THAT H¡¡¡SHE IS THE ~4-' OF PUBLISHED AT~~~~ . IN AtO OIVIStON ~U____ AND STATE OF a.fl~ ~ AND THAT THE ADVERTISEMENT, OF WHICH THE ANNEXED IS A TRUE COPY, WAS PUBLISHED IN SAID PUBLICATION ON THE ~ DAY OF ~ 19~,ANO THEREAFTER FOR ~ CONSECUTIVE DAYS, THE LAST PUBLICATION APPEARING ON THE ~AYOF~~¿ 19,JZ., AND THAT THE RATE CHARGED THEREON IS NOT IN EXCESS OF THE RATE C~. NATE INDIVIDUAL$. ~ t SUBSCRIBED AND SWORN TO BEFORE ME THIS~\DAY OF 'c... <. "~",,,~~\Y.1.93:::i~· -"'\. < \..~" ... . \~.<::-' (;-,. "- ..........~ ""'-~ ,,~ '-'''''-', "--~ ~_ ."-...... '...(""--,;-;,,-__, (~,'';.'' .L' " \/'.-.... ," ." ~~T~;~ :~~~~CN F~~I~~~TE'i;(;ommi~ri~~July3, 1990 02-901 (Rev. 6-85) PUBLISHER REMINDER- INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. ATTACH PROOF OF PUBLICATION HERE. /1 Ù .Jt I~ o . . Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: The application of UNION OIL COMPANY OF CALIFORNIA (Unocal) to amend Rule 8 of Conservation Order No. 93 and for an Area Inj ection Order for the portion of the Trading Bay Field developed by the Monopod Platform. The Alaska Oil and Gas Conservation Commission has been requested, by letter dated September 3, 1986, to amend Rule 8 of Conservation Order No. 93 to allow water and/or gas inj ection into the Trading Bay Middle Kenai "B" Oil Pool for enhanced recovery and to issue an order for area inj ection to provide authorization for utilizing existing service wells permitted in accordance with 20 AAC 25.005 or 20 AAC 25.280 to inj ect fluids underground for purposes of enhancing oil recovery from the Trading Bay Middle Kenai "B", "C", "D" and "E" Oil Pools and the Trading Bay Hemlock Oil Pool, as defined by Conservation Order No. 93. Parties who wish to protest the granting of the referenced request are allowed 15 days from the date of this publication in which to file a written 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 October 13, 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 September 29, 1986. If no such rotest is timel filed, the Commission will consider the issu- ance 0 t e or er W1t out a ear1ng. /~ ~'d Lonnie C. Smith Commissioner Alaska Oil & Gas Conservation Commission Published September 12, 1986 ~1 e Unocal Oil & Gas Di. Unocal Corporation P.O. Box 190247 - Anchorage, Alaska 99519-0247 Telephone (907) 276-7600 . UNOCAL 7~ Environmental Group Alaska District September 3, 1986 Mr. C.V. Chatterton Ak. Oil & Gas Conservation Comm. 3001 Porcupine Drive Anchorage, Ak. 99501 Dear Mr. Chatterton: . AREA INJECTION APPLICATION TRADING BAY FIELD, TRADING BAY STATE LEASE ",'~# Enclosed is an application for an Area Injection Order to provide authorization for utilizing service wells permitted in accordance with 20 AAC 25.005 or 20 AAC 25.280 to inject fluids underground for purposes of enhancing oil recovery within the Trading Bay State Lease, Trading Bay Field, Cook Inlet, Alaska, as defined by Conservation Order # 93. As operator for the Trading Bay Field, Union Oil Company of California, (Unocal) requests: 1) a single description of wells be accepted based on their similar characteristics as provided in 20 AAC 25.460 (a)(l). 2) authorization to drill, operate, convert, plug and abandon injection wells within the boundaries of the Trading Bay Field as provided in 20 AAC 25.460 (c). All future injection wells within the boundaries of the Trading Bay Field will meet the criteria described within the Area Injection Orders. Injection activities within the Trading Bay Field are in compliance with Alaska Oil and Gas Conservation Commission Regulations, and will continue to operate in compliance with said regulations and orders. . Very truly yours, b~/,./ /!-6:~Þ-- G. A. Graham District Operations Manager e e ~ LETTER OF APPLICATION FOR AN AREA INJECTION ORDER TRADING BAY FIELD, TRADING BAY STATE LEASE COOK INLET, ALASKA UNION OIL COMPANY OF CALIFORNIA A SUBSIDIARY OF UNOCAL ~ ,~. . ~ ~ ~ e e APPLICATION FOR AREA INJECTION ORDER TRADING BAY FIELD COOK INLET, ALASKA 20 AAC 25.402 (c) (I) Attachment No.1 shows the location of all injection wells, production wells, abandoned wells, dry holes, and any other wells that penetrate the injection zone within one-quarter mile of each proposed injection well. 20 AAC 25.402 (c)(2) All wells within the boundaries of the Trading Bay Field are located on State of Alaska Oil & Gas Leases. Union Oil Company of California, a subsidiary of Unocal Corporation; and Marathon Oil Company, a subsidiary of USX Corporation, are co-owners in the Trading Bay Field with Unocal operating the platform. Texaco and Mobil Oil Corporation are co-owners in Wells A-6 and A-15 with 16 2/3% and 15% respectively. Attachment No.2 lists all operators and surface owners within one-quarter mile radius of each proposed injection well. 20 AAC 25.402 (c)(3) Attachment No. 3 is an affidavit showing that the operators and surface owners within one-quarter mile radius have been provided with a copy of the application for injection. 20 AAC 25.402 (c)(4) The Trading Bay Field C & D Zone reservoirs are under water injection to improve oil recovery and the B Zone is proposed for water injection at a later date. Filtered Cook Inlet water is being used for injection in the C & D Zones and will also be used for the B Zone. The flowrate into each well will be metered with the rate being controlled by a variable choke. The facilities are comprised of surge tanks for source water, charge pumps, water filters and high pressure injection pumps. Gas may also be injected where feasible in the Tyonek B, C and D Zones to further maintain reservoir pressure. Gas injection pressure and rate would be controlled by a variable choke at the wellhead. Prior to commencement of gas injection, Unocal will provide the Commission with more information on the gas injection package. The surface equipment required for waterflood operations on the Monopod Platform is shown in Attachment No.4. For further information regarding proposed injection of the 8 Zone, Addendum A has been attached for your reference. ~ ~ ~ e e 20 AAC 25.402(c)(5) Attachment No. 5 is Conservation Order No. 93 for the Trading Bay Field, Trading Bay state, Cook Inlet, Alaska showing the names, description and depth of the pools affected. 20 AAC 25.402(c)(6) Attachment No. 6 contains the required geological information for the Trading Bay Field, Trading Bay state. 20 AAC 25.402(c)(7) All well logs are on file with the Alaska Oil and Gas Conservation Commission. 20 AAC 25.402(c)(S) Attachment No. 7 is an example of a casing program for the Trading Bay Field. Union Oil Company as operator will continue to construct and convert all injection wells in accordance with the regulations of the Alaska Oil and Gas Conservation Commission and Conservation Order #93. Specific details are provided with individual permits. All wells, both producers and injectors, are drilled and cased in essentially the same manner. All casing is cemented to assure no migration of formation fluids is possible. There will be some differences between wells regarding the size of pipe used and the depth at which the pipe is set. The minor differences are due to structure depth and method of completion. I~' 20 AAC 25.402(c)(9) & (10) Attachment No. S is an analysis of filtered sea water from the Cook Inlet. This fluid is injected into the oil production zones for pressure maintenance, and enhancing oil recovery. From time to time injection for well stimulation will occur. These injected fluids are primarily acids and formation waterwash fluids which are used to increase well injectivity. These fluids may contain corrosion inhibitors, oxygen scavengers and other products used to minimize pipe damage during the stimulation treatments. Other fluids of this nature may be used in future well stimulation activities. Attachment No. 9 is a list of the injection wells within the Trading Bay Field boundary. The list shows injection pressure, rate, volume and annulus fluid information. 20 AAC 25.402(c)(ll) Estimated fracture gradients within the Trading Bay Field vary from .9 to 1.15 psi/ft at Tyonek, B, C and 0 zone depths. The current injection pressure of 3000 psi corresponds to an injection gradient of 1.11 psi/ft. At this injection pressure, fractures will not be propagated into the surrounding formations. e e ~ 20 AAC 25.402(c)(12) Attachment No. 10 is an analysis of the water within the formations into which fluid injection is proposed. 20 AAC 25.402(c)(13) All portions of aquifers lying within and below the Trading Bay Field, Trading Bay state, Cook Inlet, Alaska are exempt under section 20 AAC 25.440(c). Attachment No. 11 is a copy of 40 CFR 147.102 (b)(2)(D) referencing the Federal Exemption. 20 AAC 25.402(c)(14) Initiation of water injection into the "B" zone will result in an incremental recovery of 2.7 MMSTBO. This represents an additional recovery of approximately 19% over the primary recovery. C and 0 zone injection has increased recovery at least an additional 12% of the original oil in place. 20 AAC 25.402(d) . The Trading Bay Field operator will monitor all injection wells in accordance with the regulations of the Alaska Oil & Gas Conservation Commission. The monitoring program includes continued determination of injection rates with flow meters. Injection volumes along with tubing and casing pressures are recorded daily. ,~. Union Oil Company, as Unit Operator will submit reports as required under this section for the Trading Bay Field. 20 AAC 25.402(e) Union Oil Company request a waiver of both requirements under this section. Limitations of the injection equipment will not allow pressures to exceed 70% of the minimum yield strength of the casing-tubing and changes of 200 psi between readings occur on a frequent basis, thus making reporting impractical and a burden to both parties. As noted in section 20 AAC 25.402(c)(13) aquifers within and below the Trading Bay Field are exempt. 20 AAC 25.402(h) Attachment No. 12 is a listing of all wells within the Trading Bay Field. To the best of Union Oil Company of California's knowledge all listed wells were constructed, and where applicable, abandoned in compliance with the requirements of the Alaska Oil and Gas Conservation Commission Regulations. . ce ce <e e e ATTACHMENT NO.3 AFFIDAVIT STATE OF ALASKA ) )ss Third Judicial District ) Roy D. Roberts, being first duly sworn on oath, deposes and says: That I am an employee of Union Oil Company of California (Unocal). That on the day of September, 1986, I caused to be mailed a true and correct copy of this application to the following operators and surface owners: Mr. Doyle Jones Marathon Production Company P.O. Box 102380 Anchorage, Ak. 99510 Mr. W.E. Pritchard Mobil Oil Company P.O. Box 5444 Denver, Co. 80217 ...~, Mr. John Havard ARCO Alaska, Inc. P.O. Box 100360 Anchorage, Ak. 99510 Mr. B.D. Whitley Texaco Oil Company 550 W. 7th St., Suite 1320 Anchorage, Ak. 99502 by placing said copy in the United States Mail with postage prepaid and certified at Anchorage, Alaska. ~~o.~ Roy . Rober s SUBSCRIBED AND SWORN to before me this t5.~ day of September, 1986. " \ !: "" l . ',' " ) . ( Notary Pu' ic in and (for Alagka ','. " My commission Expires: OZ· ()?~ ' e e ATTACHMENT NO. Ce ------.. / ,...---- 1/\ / " \ I / \ / / \ I I \ -_/.: / I 'S-.J.· ,~.; /,' '0. T5-3 :.-': I J.JS-S, .S-I";) ~;i¡/ I "'Y:"..... I ;/ · \, ':; .....>... ¡. I I ... TEXACO 'i -oTS-¡ \S-I"~f; ,,' . , + ~" ~---- CA) .!,t~--~ \..:' /. ~l'~:¿ I I -'~" /-/ s-s...L:...:-· TI::f,.- , , . /. .. ' .f.·T:> I J I TS-5R:J2\q~':S-3TS-3;:;:; '~J~ ,,'- I TS-S:s~ì:.s-::-iU~::'~~:" S-2.' , : ,'/ / \' ", )(0 ¡ I ../';-: '\ :;.. TS-!] "S-~, /; I TS_7~i l I '\..u.. 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'í.." ; 1('.IRD...._X-ÁRC6 I( ';K-II,.." ~ "....\.\~ /'\1('7.;1.;< K-/~" 1(-/9 .....-..-' it'r"",,,ndU".J ....."" \-: \\~ ,,~,.\\,>,... ..# "....TO 9768' .".",," I \", .... "\ // \" '''' / ",.,"'" ~ ,/':'.\<'" ,../\ '. :< ,/ _..../,., ,/ ,~/, ,\,." ", \ ,." /'" ....._,," '.,./ ...... ',:0.,",. \/\ '.f'.~..~·.:.T..,·'., , ......,.. to" .. I ,. \ ....,,.'. '. ;...:....,., :~': / / / / / / / / ,/' \ ,/' I ,/'/ f ,/' 1 // I / I / \_/ 31 (' I' \ \ ,,- \ \J I I , 1 I / I I I I I / I I / I I / " ..... + + 6 ce, "~CO MJflt1l, R/~,'-2 TO 10,29" ce 7 S-4 "" '\ '\ , .,' J: lIJ IT11 n {zi' rTB ALAS"..\' OISTR:Cr u........ 0·. a c.., = . .. 0" ........... ¡:.~<''' TRADING BAY FIELD U,I.C. PERMIT !:..;.,~;:... '..[~.~ :..:~..!. ; , ,r ce fe ~ e e Attachment No. 2 20 AAC 25.402 (2) Listed below are the operators and surface owners within one-quarter mile radius of each proposed injection well: Mr. Doyle Jones Marathon Production Company P.O. Box 102380 Anchorage, Ak. 99510 Mr. W.E. Pritchard Mobil Oil Company P.O. Box 5444 Denver, Co. 80217 Mr. John Havard ARCO Alaska, Inc. P.O. Box 100360 Anchorage, Ak. 99510 Mr. B.D. Whitley Texaco Oil Company 550 W. 7th st., Suite 1320 Anchorage, Ak. 99502 " . . c BACKWASH&PS NORTH 0 VACUUM TOWEn OURCE WATER UMPS SAND FILTERS . N. ATTACHMENT SOCK FILTERS (I) 0.. ~ :J a. INJECTION ACCUM. TANK 400 BBL. SATURN 2000+ CAT e MONO POD WATER INJECTION FACiliTIES 2 Vertical Turbine Source Water Pumps 1 Filter Charge Pump 125 hp 1 400BBL Accumulator Tank 75hp each 1 Filter Charge Pump 90 hp 1 Injection Charge Pump 125 hp 2 Vertical Turbine Backwash Pumps 100 hp each 3 Operating Sand Filters 2 Sock Filters 1 Vacuum Tower Operating 2 Stored Sand Filters 2 Saturn-Bingham Pumps e 1 Vacuum Tower Stored 2 D.E. Filters 2 30hp Electric CAT Injection Pumps "t"; DA TE M.E.G.¡11/6/85_ B. A. W., 'J 17 I e~_ -.-.. fl...~~=.~ ,~_._.,-'. .-.-- .... .- - ----- MONOPOD PLATFORM O~AW~ _ CKO. ___. _ APP'O. _________.,. .' ~çAl.E _____ __.___._. DA11'. _. _ .... h._. WATERFlOOD SCHE~ATIC DIAGRAM ,.", ..--4 ¡- j "--.,.-. ~;HIF'!,) '~Hfrr UNION OIL COMPANY OF CALlFonNIA At ASKA DI~, rRICT ,.-. Ce ce le e aATTf\CHf'iun ìW. 5 .., Pr;-0T- ,... 1 . ~~" D .0.UG '. '- nJ/U _.LAND D~. -- -"; STATE OF ALASKA DEP ARTMENT OF NATURAL RESOURCES DIVISION OF OIL AND GAS Alaska Oil and Gas Conservation Committee 3001 Porcupine Drive Anchorage, Alaska 99504 Re: THE APPLICATION OF THE UNION OIL COMPANY OF CALIFORNIA for redefinition of the Trading Bay Middle Kenai Oil Pools, for revision of certain existing pool rules, for pressure maintenance projects in the Trading Bay Field and for revocation of Conservation Order No. 57 ) ) ) ) ) ) ) ) ) ) July 31, 1970 Conservation Order No. 93 Trading Bay Field Trading Bay Middle Kenai "B" Oil Pools Trading Bay Middle Kenai "c" Oil Pools Trading Bay Middle Kenai "D" Oil Pools Trading Bay Middle Kenai "E" Oil Pools Trading Bay Hemlock Oil Pool IT APPEARING THAT: 1. The Union Oil Company of California submitted an application dated June 12, 19ïO requesting the referenced order. ,.' 2. A notice of public hearing was published in the Anchorage Daily News on June 17, 1970 pursuant to Title 11, Alaska Administrative Code, Section 2009. 3. A public hearing was held in the Ben Crawford Memorial Building, .~chorage, Alaska on June 29, 1970. Testimony was presented by the applicant. AND IT FURTHER APPEARING THAT: 1. Testimony indicates that significant differences occur in the reservoir and fluid characteristics of the various hydrocarbon-bearing sandstones. 2. Testimony given at the hearing on Conservation File No. 57 indicated the gas production was from a non-associated gas pool, but testimony now indicates it is associated gas from a saturated oil pool. 3. There are numerous separate pools not in communication with each other, but the erratic and unpredictable occurrence of separate pools makes it administratively impractical to isolate the individual pools for conservation purposes. 4. Previous designations of oil and gas pools should be changed and new oil pools designated. 5. Insufficient evidence was presented to justify defining the top of the Middle Kenai "B" Oil Pools at the depth proposed by the applicant. e e ('t. .. ¡ , ¡. II J:í OI:l>i:J\ NO. 93 July 31. ;',;. (e ('. :'::my of the individual pools arc of insufficient are;cl extent to jli~rify in~t31' tion of a pressure maintenance project. 7. The installation of pressure maintenance projects nay result in maxi~l~ oil recovery fror,' the proposed Trading Hay !fiddle Kenai "c" and "D" Oil Pools anå the Tradinr.: hay HcmlocL Oil Pool. G. Correlative rights \-1ill not be adversely affected by designation of ne\.: oil pools or by pressure maintenance projects. 9. Flexibility in locating, converting. and testing wells may be necessary [Jecause of reservoir configuration and cilaracteristics. 10. The complicated reservoir configuration and characteristics necessitate careful observation of reservoir performance to achieve Maximum oil recovcD'. 11. Downhole comminr,ling of production from some pools will increase oil recovery. :'10\-1, TlJEPJ.::FORE, IT IS ORDERED ThAT the following rules apply: r.ùLE 1. Area \-There Field Rules Are Applicable ce The area described as follows will be affected by tnese rules: ;I,~ Section 34: S . ~1. E 1/2 S 1/2 S[ 1/4, ~;E 1/4 Si:: 1/4 S~·! 1/4, i~ 1/2/ J ·.i.'9~', 1:13\1, Section 3: Section 4: Section 5: Section 8: Section 9: t& 1/4, W 1/2 SW 1/4 E 1/2, SU 1/4, S 1/2 ¡m 1/4. NE 1/4 N1-! 1/4 E 1/2 SE 1/4, S"ì 1/4 SE 1/4 :'a: 1 / 4 i'l 1/2 TIO!;, R13\J, Section 27: Section 33: s. t'l. ............- l:ù1...E 2. Definition of Pools (a) The Trading Bay t-liddle Kenai liB" Oil Pools are defined as t::e accumulations of oil and gas occurring in the interval whicÌl corn~- late with the interval 3200' to 4585', drilled depth, in tile Union Oil Company of California Trading Bay State A-14 Well. /32>5 . (b) The Trading Bay Middle Kenai "c" Oil Pools are defined as the accumulations of oil and gas occurring in the intervals which correlate with the interval 4,585' to 6,225', drilled depth, in the Union Oil Company of California Trading Bay State A-14 ~ell. <, ce (c) The Trading Bay Middle Kenai "D" Oil Pools are defined as the accumulations of oil and gas occurring in the intervals .....hich correlate with the interval 6,225' to 7,025', drilled depth, in the Union Oil Company of California Trading Bay State A-14 \·le] 1. -2- Ce ce ce , . e e c{ .:.' !. I\,' ":" ; 0:·, nl~lJL¡~ !'J(). 9 J July 31. "';' l:ULE J. RULE 4. r..ULE 5. nULE (" (d) TI1I' Trading Bay Niddl e hcn.1.i "E" Oil Pool s are dcfinc·d é1S tÌle é1ccumul:1tinTls of oil and gas occurrinr in the interv;'!ls '·!hici¡ ('orre];.¡tc \.¡ítli the interval 7,0¿5' to 7,425', drilled dcplil, in tht: lInion Oil COMpany of California Trading Hay State ,\-1/; Hell. <f..Go (e) The TradiTl~ Bay hemlock Oil Pool is defined ;.¡s the accumulations of oi 1 and gas occuring in the interval which correlates with the interval 5,380' to 5,720' in the Union Oil Company of California Trading Bay ffl-A Well, but which are not common to the accumulation of oil and gas occurring in the interval 10,275' to 10,635' in the Texaco Superior TS no. 1 Well. -: Cornminglin? COT1lmingline in the \olell bore of production from the Tradinr. bay Hiddle Kenai "D" anò "1.:" Oil Pools is allowed, provided each well is e~uippeè to permit separate testing of the defined pools for allocation of pro- duction. ì' , _ Spacin", Acreage ¡¡ot more than four (4) completed oil wells shall be allO'v!eù in eacTl of the defined pools in any governmental quarter section. Spé!cing Footage ,',. ,;0 oil \iE:Jl shal I be completed in any defined pools closer than ()f,G feet, true me:J.'sureò distance, to any other oil well in the same defined pools. Casing anò Cer;¡enting Requirements (a) Surface casjn~ shall be landed at not less than 1,000 feet and ceI:'.cnt shall be circulated to the sea floor. Casin¡è and control equipment shall be hydrostatically tested to not less than 1,000 pounds per square inch pressure before drillin¡ the shoe. (b) Production casing shall be landed through the completion zone and cement shall cover and extend to at least 500 feet above each potcr.tially productive sand interval. The use of multi-stage ce~entinh procedures shall be permitted. Alternatively, a casing string shall he adequately cemented <It an intermediate point anå a liner landed through the completion zone. If a liner is run, the annular space behind the liner shall Le filled witll cemen~ ::0 at least IOn feet above the casing shoe, or the tor of t;¡e lir:er shall be s~ueezed with sufficient cement to provide at least 100 feet of cement betwcen the liner and casing annulus. Cemcnt ;,;,:ust cover all potentially productive intervals behind t]¡C liner. Casin~ anò well head equipment shall he hydrostatically testeò to not less than 2,000 pounds per square inch pressure. -J- Ce <tt ce e e {I"'.' ¡·...iTU: ¡Hi.JJL!' ;':0.93 nUL:~ 7. BULL h. l.L;LL 9. f-ULE 10. . J ul "" .~: i (.' ~ ,!)o t_~..o!~~l.e-E..r_~..~..::~.!lre S~veys 1\ key \Jcl J bot t01'!1 holl' pressure survey shall be conducted in each of the defined pool s upon Committee request; prC'vided, hmlcver, stich surv('ys s:J:!J 1 not be required T'loreoften tban t,,,ice in any calendar year. The' ti rr:e and lenf,til of survey, number and locatlon of wells, datur-Jand other d(~tajls Hill be detl'mined by the Committee upon consultation with the Operators. Pressure ~~aintenance Projects The injection of v.:ater for tlw purpose of pressure maintenance, s'!conJary recovery or of conducting injectivity tests is plrr.Jitted in the "rading liay :!icjdle Kenai "c" and "D" Oi 1 Pools ¡md tlle Tradinz t;ay !,(~¡dock úiJ Peol. A semi-annual pro~ress report det.:Lili;lZ project op02ratirms and results shalJ be submitted to the Cor:JT:JÍttee \o1i tì,i.n ttvO r'lon ths ¡¡fter cac11 ser!!Í-annual period, "dth t)1C first report to cover cperatÜ>ns lhrou8Ìl December 31, 1970. /',ctr11ÍLisLT:1ti.VC: ApprovaJ LrPíì request of the applicant and a shm-lÌng that all affected parties :l<1Ve been not i fied of such reflucs t, the Commi ttee may autl:orize the drilliof: of ar.y '.vell at any location, the ten:1Ínation or suspension of any pressure maintenance project, the testing or conversion of any \èell, or any ot;1er operation reasonably designed to further the purposê~ of a pressure maintenance program. . Other Conservation Orders Conservation Order No. 57 and Rule l(c) of Conservation Order ~o. 69 arc rescinded. ¡aiLE 11. Exceptions Allmled AJl wells previously compJeted in accordance "lÍth then existing conser- vation orders that may be in conflict with these rules are hereby allowed excepti ons to such portions of these rules \lith which any such ,,,ell may be in conflict. DONE at Anchorage, Alaska, and dated July 31, 1970. ~furshall, Jr., [ cutive Secretary and Gas Conservation Committee -4- e e ("",,1 ,.1(1, t)i:!Jil' ¡';(I. '1'\ illJv \:. j-: <e Concurrence: ~/6~ ¡,orner L. Burrell, Ci¡airman Alaska Oil and Gas Conservation Commi ttee Committee ce ,.' <e -5- · ~. ~ e 4IÞ ATTACHMENT NO. 6 TRADING BAY FIELD, COOK INLET, ALASKA Geologic Report for Injection Zones and Confining Zones Stratiaraohv and Reservoir Descriotion: The productive zones of Trading Bay Field are all nonmarine sediments of Tertiary age. They belong to the Kenai Group (Calderwood and Fackler, 1972) which is composed of five formations, the three oldest of which are present in Trading Bay Field. In order of decreasing age, they are the West Foreland Formation, the Hemlock Conglomerate, and the Tyonek Formation. Only the Hemlock and Tyonek are productive in Trading Bay Field, although log analysis indicates that the West Foreland contains oil-bearing sands in some wells. The West Foreland rests unconformably on the Lower-Middle Jurassic Talkeetna Formation, which is composed of interbedded volcanic and volcaniclastic rocks, and is considered economic basement. The Tyonek Formation is unconformably overlain by a thin veneer of Pleistocene (7) or Recent (?) sands which have high resistivity and may contain fresh water. The two youngest formations of the Kenai Group, the Beluga and Sterling, are not present by erosion or nondeposition. Hemlock Conalomerate: The stratigraphically lowest reservoir in Trading Bay Field is the Hemlock Conglomerate of Oligocene age, which unconformably overlies the West Foreland .~. Formation. The Hemlock is characterized by its clean texture and quartz-rich composition. It is dominated by coarse-grained sandstones and pebble conglomerates that are commonly interspersed with thin siltstone beds or tightly cemented impermeable layers, with rare thin coals. Thickness of the Hemlock varies from 300 to 450 feet in Trading Bay Field. A well-developed system of braided streams of moderate energy that flowed into the trough from the northwest and north along the basin axis appears to have been the major depositional mechanism during Hemlock time. The Hemlock is not currently under water-injection. Tyonek Formation: The thickest and youngest Tertiary rock unit present in Trading Bay Field is the Tyonek Formation of Oligocene-Miocene age. It consists of 4700 to 6000 feet of interbedded thick, blocky sandstones which alternate with thinner siltstones, mudstones, and relatively thick coals. The sandstones are generally coarse-grained and pebbly at the base, and fine upward into very fine to fine-grained silty sandstone at the top of each sand. The upper contact of each sand is generally gradational with the overlying siltstone or mudstone, while the lower contact is erosional, with the sands usually resting on an underlying coalbed. This relationship is shown on Figure 2, an idealized lithologic section. c. c. c. e e This cyclic depositional pattern, with a fining-upward sandstone bed (Figure 2, unit "A") overlain by a thin siltstone or mudstone bed (Figure 2, unit "B"), which is overlain by a coalbed (Figure 2, unit"C") on top of which the next sandstone (Figure 2, unit "A"') is deposited, formed as a result of low to moderate energy streams which meandered across a broad floodplain. The sandstones are point-bar deposits and bedload channel deposits, while the siltstones and mudstones typify interchannel, overbank, and sag pond deposits that provided a marshy substrate on which plant debris accumulated and gradually became coal. The coals in the Tyonek Formation tend to be relatively thick and laterally persistent, which makes them useful correlation markers and laterally continuous vertical permeability barriers. The tyonek Formation has been subdivided into five zones which have been named alphabetically from "A" through "E", "A" being the shallowest and "E" being the deepest Tyonek, which rests on top of the Hemlock Conglomerate. These alphabetically-named zones apply only to Trading Bay Field and have no relation to the Tyonek "A" through "G" zones in adjacent McArthur River Field. Within Trading Bay Field, only the "II-A" fault block is large enough to justify secondary recovery methods. Presently, only the "C" and "0" zones are being waterflooded, although a "B"-zone waterflood is scheduled for start-up in the near future. Cross-section A-A' shows the stratigraphich and structural relationships between the Tyonek Formation and surrounding rock units in Trading Bay Field (Figure 7), as well as the relationship of the "II-A" fault block to adjacent fault blocks. ,Þ,' Tyonek "0" Zone: The Tyonek "0" zone contains seven reservoir oil sands in the "ll-A" fault block. Some or all of these sands have been produced in TBS wells A-2, A-8, A-9RO, A-lO, A-II, A-13, A-14, A-22, A-23, A-25, A-30 and A-32. Slightly less than 26 million barrels of oil have been produced from the "0" zone sands in the "II-A" fault block to date. Fluid contact data for "0" zone sands are shown in Table 1. 4. ce ce ce e e TABLE 1: Fluid Contact Data for "0" Zone Sands in "II-A" Fault Bleck: Sand 0/1'1 , LKO t or HKlv* GIO, HKO, or LKG* 53-0 O/W -5209 (A-I0) G/O(?) -5076 (LKG -5051, A-32; LKO -5102, A-9RO) 53-8 Dipping: HKW -5541 (T83) to O/W G/O(?) -5177 (LKG -5149, A-2; HKO -5615 (A-5) -5205, A-8) 54-5 O/W -5602 (A-21) LKG -5188 (A-32) 54-9 O/W -5572 (A-12RO, A-22) G/O -5236 (A-32) 55-7 O/W -5617 (A-12RD, A-22) G/O(?) -5338 (LKG -5306, A-2; HKO -5370, A-8) 56-1 Dipping: O/W -5675 (A-12RD) to G/O(?) -5418 (LKG -5406, A-2; HKO O/W -5723 (A-19) -5430, A-8) 57-2 LKO -5862 (A-19) GIO -5499 (A-2) O/W = Oil-Water Contact; LKO = Lowest Known Oil; HKW = Hignest Known water; G/O - Gas-Oil Contact; HKO = Highest Known Oil; LKG = Lowest Known Gas Generally, each sand has a unique oil-water and gas-oil contact, although it is possible that the "53-8" and "54-5" sands are in communication. The Tyonek "0" zone sands range from 0 to 110 feet in thickness, and average 50 feet. The confining zones for these reservoirs are the siltstone, mudstone, and coal beds which overlie each sandstone (Figure 2). The coals are laterally persistant, average ten feet in thickness, and range frem three to twenty feet. Average depth to the Tyonek "0" zone reservoirs is approximately 5500 feet. ,I,..J· Figures 3 and 4 are structure contour maps on top of the "53-0" and "56-I" IIO"-zone sands. These maps show the relationship of the oil zone, gas cap, and water injectors for each sand. Wells TBS A-5 and A-19 inject water into some or all of the Tyonek "O"-zone oil sands in the "II-A" fault block. Tyonek "C" Zone: The Tyonek "C" zone contains twelve reservoir oil sands in the II-A fault block. Some or all of these sands have been produced in TBS wells A-7, A-lO, A-II, A-14, A-16, A-23, A-24, A-25, and A-32. Slightly less than 18 million barrels of oil have been produced from the "C" zone sands to date in the "II-A" fault block. Fluid contacts for the "C" zone sands are shown in Table 2. 5. Ce .... 'é:- Ce ce e e Table 2: Fluid Contact Data for "C" Zone Sands in "II-A" Fault Block: Sand O/W, LKO or HKW* G/O, HKO or LKG* C-l C-2 C-3 C-4 C-5 C-6 C-7 47-5 48-5 48-7 49-4 50-0 O/W -3925 (A-14) O/W -4022 (A-19, A-25, A-30) LKO -4185 (A-5) LKO -4264 (A-5) O/W -4288 (A-19) LKO -4432 (A-5) O/W -4693 (A-26) O/W? -4757 COTB -4757, A-22; HKW -4758, A-12RD) LKO -4844 (A-5) LKO -4890 (A-5) LKO -4774 (A-lO) Dipping: HKW -4966 (A-21); LKO -4983 (A-22) G/O -3830 (A-16) No known gas No knovln gas No known gas No known gas No known gas No known gas No known gas G/O -4574 (A-32) No known gas No known gas No known gas O/W = Oil-Water Contact; LKO = Lowest Known Oil; HKW'= Hignest Known Water; G/O = Gas-Oil Contact; HKO = Highest Known Oil; LKG = Lowest Known Gas Generally, each "C"-zone sand has a unique oil-water contact and a small or nonexistant gas cap, and each is a separate reservoir. ,,1,1'-' Figure 5 is a structure contour map contoured on top of the "47-5" "C"-zone sand, which shows the relationship between the water injection wells and the oil accumulation. Only TBS wells A-5RD#2 and A-12 RD inject water into selected "C"-zone oil sands. The "C-l", "C-2", "50-Oil, and "50-6" sands are not currently being waterflooded; all other "C"-zone reservoirs are being waterflooded by either A-5RD#2 and/or A-12RD. The confining beds for these reservoirs are the siltstone, mudstone, and coal beds which overlie each reservoir sand (Figure 2). ~ Tyonek "B" Zone: The Tyonek "B" zone contains nine reservoir oil sands in the "II-A" fault block. Some or all of these sands are being produced in wells TBS A-17RD, A-22, A-24RD, and A-30. Slightly over one-half million barrels of oil have been produced to date from the Tyonek "B" zone in the "II-A" fault block. Fluid contacts for the "B" zone sands are shown in Table 3. 8. ce ce le e It Table 3: Fluid Contact Data for "B" Zone Sands in "II-A" Fault Block: Sand 0/\'1, LKO or HK\'I* G/O. HKO or LKG* 24-6 LKO -2758 (A-23) No known gas 26-7 LKO -2953 (A-5) G/O -2862 (A-24) 28-6 LKO -3072 (A-5) G/O -2965 (A-30, A-24) 31-8 LKO -3431 (A-26) G/O -3219 (A-13) 33-6 LKO -3517 (A-26) No known gas 40-4 0/\'/ -3508 (A-12RD) No known gas 41-3 LKO -3632 (A-26) G/O(?) -3468 (LKG -3445, A-IO; HKO -3492, A-14) 41-8 O/W -3649 (A-22) G/O -3486 (A-D) 44-7 011'1 -3867 (A-23) G/O -3757 (A-lO) Generally, each "B" zone sand has a unioue oil-water and gas-oil contact, and each is a separate reservoir, although it is possible that the 33-6 and 40-4 sands are in communication. The confining beds for the "B" zone reservoirs are the siltstone, mudstone, and coal beds which overly each reservoir sand, as shown in Figure 2. The "B" zone oil reservoirs are not currently being waterflooded. However, it is proposed that a "S"-zone waterflood be initiated in the near future in the "31-8", "33-6", "40-4", and "41-8" sands using the TSS A-29 wellbore for ,','_ injection. Figure 6 is a structure contour'map contoured on top of the "41-8" sand, which shows the relationship between the proposed A-29 water injection well, the oil accumulation, and the gas cap in the "II-A" fault block. ~ ð ø/j'~ ß,,~ ./ ~~:?.P./ Norman 'l. Gilmont Area Development Geologist NLG/pg 10360 10. ~,\, " ¢' M~f:S";KIE ~ ~, () TyC'~. ì ~ NICOLAI KALC14 "?'- \.. C'jEEK /) ~ASI ~, ~~! NE'\~~~ZI:E ~ TRADING .... 10lLI 8A ~ NO ~ TR. AOING .. ~ T R A TRAD ~AY ----? ¡8AY fj." ~ McARTHUR {RIVER} ,.. MIOOLE , WEST \ 10IU;~j ~ .... GROUND FORELAND ~; n SHOAL (GASI ,I !A,' (OIL I L.···~I '......: REOaUB T -! :' SHOAL ¡ ~ 10lLl I) G .; $- ~ I ~ '"' !Ö $!í .:0 V I, ¡"''Í-'?'_~ .....: (./ , : : i ~ .to '. '\. .;.-.;..' ..:, ,'. , ..: ,.'" 1\ \\ i, ""-/; (j ,..' .\. " '..... { ,j (J , . '( ~ .:.....;:» ~ì ,.......' lO' /~ \'...:~ } ~} .\ ./ ~ l' ~ ("' (j OIL A/OR GAS FIELD . TOWN Â WELL DRILLING PLATfORM C.J 200 FT. DEPTH CONTOUR e \J\ e I~ ) it' ~CÞ) '\ (( )V /~ \"'- I. ~~!~t <õ~ . ) ~(' .- r;;'~ RIVer " '" .~ ~'ANCHORAGE ..~ '- ~ " IWlllo. UOIOIII/lk '.' \ ~ \~~~~ ,\~';"': \ ) / t ~ NO COOK 1. INLET ~ ¡GASI -¥ .~ ING BAY FIEL Blf/'CH . HILL 16ASI .'.. ....... ~':~ , .: ( ~~ ~ j , ~(., ~ 'ì . I / ) WEST FVRK ~?,) II J OtG:JSJ ~ ð ;,<~\~\ 0'i~'Is~LING ~!'/ ~_ _ ¿~_ (\. .¿;."~ I ~~ _." \', ': . - , .........---------. '. \, .'..~ Moo" . / KENAI ,..' \.' - , _., \ POst ...... '. I$AS) " ~ "-/' I 1:\', ~ ~ . .r",~- , ") .....~ -'-ì > i ~ ~,,\ \:) .~ ~".I \ ~ ~''\ \ \ J ~) ..... / ~......... .--...t. , \ ~ /' \ ~ f .' IJ, SW¡jNSO~ ,. . h, RIVER '-,,/- lOlL) ,4 'BEAVER ~ CREEK IGASI o -/-/; ~~ + ~ o -;' ;), " . \ '- .. ',,- \ ~'D ~ " COOK INLET ALASKA AREA c:::v o 5 10 I\._~-~ WILES 20 I lOCATION MAP Fig. 1 -- II Jnit Î' -Unit 8 ¡ I :=;.- Unit A'" I ! -Unit C~ ~ 'Un; RI)' Unit An - Unit C' 3- Unit B' FIGURE 2 . ~YONEK FORMA TIOl\J IDEALIZED DEPOSITIONAL SEQUENCE (TBS A-25) EXPLANA TION [~f:¿;}11 Conglomeratic Sandstone 1:·0"",',:':-:";:::·1 San d s ton e .. - ¿,. ..;:::;~ ~-.... "J , ,.f -=- ~ ~ ......-:::- -~- . erl'~fll ." t - 0._" ¡~~~~Îb~ .>.."......:x:..--) -~.. ----- - - --- ~ <~ .~ ~~ ~ Unit A' ~~ -'!s I<==;t ~. ~ ,;::~ Unit C -'~ Unit B Unit A ~ ... .. .. ~I ----- ""'I~ ':> c~ ) ..¿ ~ ~. é... Gamma Ray -~I ...Þ.I ~ ¡1!'lei . .. '" '. 'j elltl;ll! . ::·.11::....:0:.::&>:: ..p........~.;.: '.(:7 ......: . . - :.:.. : : I : , , I , , I i , ¡ I I , : I , I I ! I I I I , I I , : I I , I ; : : ! f-'-'~ .-.- /---1 -- ~ Siltstone Mudstone Coal - '-'"'- ~ , : ...~~..:'. ;.....;.....~1\0..:..;-: :':J.a...:-'- ·:-t~:F~:~(~·f·~:~i~t)~~ .;-~, ! , ~::~:.~?~~·~~.tÇjWf'l ~'- ~ ~ ' I : ":;<-$;-,:;~~f~7'é};t1 ~ « -~~-"""~~~~ff~~.·'-='t-+ ..::'"~-:~~ ~'~""''-\'---'''''I·;,lJi -~_ :<'""'~~~~.~.-"':t ~ ! ". .~- ._';"~~.r,~y ~!- ~ ..¿s;", - -..~-- i((" - ~ " -. .--. -........, ...~.. .:-"'t.'.." '''~ 1', '·'r. "~~ :.~::._.' ',.- "''-'', ~- . "'. .,'-' _ r .- .L.., t ,. ... ~ . r-~j ~}(¡·-i!.~~~~ l-·~·tJ ~;.- ~ .'~J:'·~.lf.1<,·,"i\~·l}¡ ~, ( ~ , , '.. -;. ,':,-(t···,. ~~ _~_ /f;':,~>:~:+.:q~U·I'~ - ····:...~···t'¡ .,.:.~ t¡· .'<,.... "- ..~ . :~..~·.~r~::..~.~r~~~~,.~~~.. . r~ ~ -~.. ., - . : .. }~~%~I:;¿ß~H J ~--~- ...~~t~.:{;~;;::J~~ fi:t'í·_<~ "- ";,~} ;~:;t~~:;:.çMJM:~:,,~-- ~ - q/.."..'f ·~~t?~5:;ßF~n ß<'" +:~ :'\·J'+t;;1.1¡t~. '. _.~ . ~.'" ~::-t~j:-';'_-t.:.;4-~~'~ ·f.. . -...... : ; .. i I : ¡ ¡ ¡.\ I I .---. .- - --= . ,~ ""'"<:"-h:-~""\;~-'t't.-!:"" 'ï ~ ·",.õ!:."t·~::'~:·-"'~'!H ~.F- '..t'" ,:,"·ì:·~'~I'¡":¡;'l¡.'r\. ~., ~...;¡f ·:::'.J~:f::'·_~:!· "~.~·~'--P:µ--J~·H "., J".'JT ':'.: A.!<~t"2:~!:=~~I.~~ .t íL'=·.I.. . '. ., . .\..,;: ~·.:.,.I·,:· :: -",. ~ ~ ..~_r>::: "d:,~;:'''''....h;..r:t.'~..; ":t...~_ ·",··:~;'-~··':;f-:'.~;'''·~~''·~. ..-(.'<.:. "I. ...~ ~. ," ~"~r",·n· '..-;r';./" Shallow InducÚ.On -+- :"-:0- .' .., ~_ t....,. .,.~.; ~. ~ .- <T-·t·. .'1" ~ I" < .('. {:"'i~,,:?J+.1: ~. ~...~.._' .~.:.¡ "'<"f'-.j.~ ::':::1-"~~~~ - ,~. ;....~ ~ ~... ..'-" '---Y-~ II i -" Deep Induction Medium Induction i I ,: , : , I ; II i : I i , I ~~~"':¡¡I ::¡~:~~, '....--~ ~ -rI' e e ~ ."'" )~ .~. RI3W TS-4? . ...,c~ "':¡eJCt A-9 ...:¡..... . ~,.o ..... / / " .,......... I~ TS.2." -,- ~.c..._ "'_ LIol' I I I I I ------ VOI·O" iI,:Ø ",. .hO..ø--. ,~~...:-- ~ ~ ~ I 32.33 ~~ ~, ~ M' J'ør '.¢.1 ...... ¡' ',' A·I 1 .'>C"~ I"'~'- " ',> , r " I ¡ J .....-., ! . í,' ,"t ./. <r I / " I , Y· : . . ,'1 i. / .. .~ I I I ,," .- ,,> " , \ .,. .'t - .".- A·I9 ,- ---: ;- -.) "" .,.) 'c.SoLJ 1"IC)W" ""0..... 413\ gi,D '\ \ " .l· A,"21 RD . ·...0.·· ¡ 'or. I' .~.,;. ..,i.... : "....~¡;j. 3 ~...... ....... . ".;-:...,., . A-21 .! ~-..-- o '0' lCN£ IN.l£CTCRS , /6Ø~ ø ~:)~~.'\ ! 1m .~@. .~.y Ò\ I ,'"' I.~- ,:'" ,,' ~". ...... :"\. r.,'-'~ :':\ ,.-., "-" .\:.:1 - ,,' . r." ~_ f;:" '::l : ~." I ~.?I 2 (j P P .:;) G G~"" -.:::- A· 26 ,," J' ::-ö:.:: I j I fiGURE :3 unl®n \(õ i'~\ ,. ...;.... D........ ~t\. """0 ".... ~1œ OJ·········~' . . I . -.. t . .......... .,".. ',- TRADING BAY FIELD STRUCTURE CONTOURS TOP 53-0 S:'ND TYONEK fORMATION ,{ A- 27.' . ·.·.·.1 '.ø '0·' ,..~ , ¡ ... I e e .. _IICO ,'Ot:Jc.C .~. 1 ~- RI3W T5-4 /y . ·oC-=-:.. ....;'JC1' ·C' - .w~ I -----1 I I I I I .' , "'t....:.: 1~ T5-2.' -,- -.,0:..1_ !.:'~I r I I I I 3233 I 33134 ~'~'~~~~~"""'5~~~~~'~"""""""""""'"""""~,"""""~"""'~'\.,"""""""""""""'":;!~~,~~~~~ I ¡4, '..,. I..? I I " I ; !':!} . I .~;-;. ~~g~~: t' I iA-28 , . - -- ""'0:-" ~'ß.'.ft1t'i ,.. Y"4"r 1;:..11 I. '..06!>4' ,0." T 9 N ~.. I .£;~r r..:J"'1I j' f'."r ... f>"'" .' i~ -100"\1' !"::I","=, ~. ,Ot ; J. ~,~ \" A-t ··OC"_'1I .6 t..··;O·... ..> ;/: I " ~. 1.'16 .J"''''. .~~ -. 4 ".> "'1' "i:I::.S~" ''') ':."'~ / /. "'~ / ..... / ... ~'1- " ~<> ",' ...+... I . ,> I \ , \. 4'3 " --1..- . 9 JJO \ \, o . D' ZONE INJECTORS ,. ¡::;ç:.¡ Ö (.~0" .~ (:-:) ,_) U , --' (:) ,. :.'~ ... ..~... ~ 1.-.) ,:~ .@~~~;'~à ~ó . r.\ 0 ~ ,,",',", ".:IP I::J "-=' G r."o GQ'" t N I FIGURE 4 unl@n LøY~. (,.'!.' ," ", ......... O"'I"C' '8"(11.. ......0 "'.... ! ,.., "Y'O ~ OJ···..·..· I..... .... . . , . _ t . .......... ..-. TRADING BAY FIELD A - 21_~ . ;;~ :~.: STRUCTURE CONTOURS TOP 56-' SAND TYONEK FORMATION II-A fAULT BLOCK ,'.t.JQ j I ..I , e e . ."'" )C. .~. T5-4 / . _c~ ~~'JC'" T 9 N - -- ""..-. -----1 I I I I I /~L.- 1;' .... TS-2 .,~ . "'IIec.:_ on _ ~- f'"2 .- """ ,~'"'" ,''"0_' ~... I ~1''''''-' iF starr TO"" I I I ~ ~ " :: ~ " .. .~ z 5 '" z ,.....;.".. . .., ,.... -.:. o ; ... ·C· ZO~E I~JECTCAS A-26 t.;.. 'yO ,.-, ~.~. ------..... ...¡ .. ~ FIGURE 5 unl®n " ...,..... 0........ r.-"rj... ....~ ...... '" TRADING BAY FIELD b_~OO . - +- ----.+ . STRUCTURE CONTOURS TOP 47-5 SAND TYONEK fORMATION WfLL '"II(~~.. ,"._ t -, ".~ I ... I -........ ...- e e . ...co ~1~1" .~. )y /' fO~!IO <:f RI3W TS-47 . ..c<:-:.... -.: ,,),;1' r , I I I 32.33 I ~'~'~~~~~~~~.' ~~'\.~,""",""',......,"""""""""""""'"~'''''",""....."""""""""",,,,,,'-: I ..::> ,"" , ¡ I ~. . I I , - -- ----- /,(' 0" ..p ""{u:..: ,.''- TS -2 -.--=;.: . -.:,... ".: "". .... ~.. 4 ::"2 '0(; .... J .,,~, ""c"." !.....O'J., 33 5..4 -,...."., ;;:"""'~~""-~."..,...,""',,......,.....,',',"" 4,.:;; A-9 . -..: ".::'.ll' A.IS . " " _:u.. '.:~' ~;;1-" ....,,~~G" .~~ P"·' .\.1 ..~",.. '.~.". A-I5 . 010(,:(0'0 '.~ too· 0' ....:..., -.:,--: A-28, . .A-I2 T '.., .,,~ . ...:...., ". \:. \' A-6 . -..:-. '''~ ...... ,.--= " . -I ì I I I ¡ ¡ , I ¡ I . A-I . -~..., ,.'.;".. " NW_? A-12RC: \ \ ~- '~./ I' " .~'-- . .,fe'· " .:.~ .-... ,....; . ,.. ...... 7 --; A·J2~ '\. ~:,;,', " . T 9 N \ \: \ \. \ " " .......... 10 -B- ze;'.E '~Æ:!:~S" tr, ~ .~c·...::,) GOGo ! ',." @ r.\. G I /:"" ø\:...' ~ .'~ '~';~:'50 ~~ ~I ik:~ 0 ,,~ :'\ ,:::.) @ ~ ~ ~=- ;jI @ 1'7\ /"':""'t \.=-.v- ~,~ -- A-26 " '110I0.'." '_0'.'.1 . ( "'.....",.. F1G:..RE 6 unl@n ." ~o:¿. .....*'!..~ " ~." ...... ~·....t. 1 """ ~ u···'...'·r....' '" '." - .., - , . ..... .... .. . TRADING BAY FI ELD -----.----- A-27 ........... '.0°') , STRUCTURE CC~TOJ~ TOP 41- 8 St.tID !I-A FAULT BLOCK TYONEK fCRMATION ~l"'''''I!:'':J'''...... ."", ---~- . A SW UNION Trading Bay St.-3 e FIGURE 7 e CROSS SECTIOi'J A-A' TRADING SA Y FIELD -- A' NE UNION Trading Bay St.-1 o . N 300E ~ o Glacial (7) Sediments -1000 -7 --\ Base Glacial & Top Tyonek Formation -2000 J]-A Fault Block 1- h .... \ ~ -<- ç;¡" 'l Tyonek ftA" Zone Tyonek "A" Zone k "B" Zone Sands Tyone IIì-A Fault Block -- -- _. -- --- -5000 Zones ~-- .... ,..- .. _.. ~--.- -~~- '- ~:~~i=~~~~t.:-~__ ~.' - _4·...·_·...,--=V,......,-..-· -" ~~ ";:'''-'::(dåš -lone's) -" :-:. - .:(011 za~e.s) _~~~:....~_~.:._-'-. --:- - ,.":-:,..,..-.-; ~------- --- -~;:~-·:-:~f~;c~¡~~~~- Tyonek ~> l ~ ~.=:~-:~:.~::~t¡¿;4Efr;1.;;:~.~.J.. ~ "B" "'i ~~'~ ==-. ........,s-:Y.~þ. "_·-.:.~-,_..."'·....::..-"'''.,·~ç''''''...,<.'-_.-"'--o..· I . Zone ~\ I ,c,~:-~~~Ì.f~~~~1~~]r~~z;oe', '. ~ I -.-ð ..,·~·~..:."".,_....c.-.""'? ""'-"(Olt--zones) =..-,..,._-, -'. - . .~.--~- ~~~~~~;:Ædf~~¡~?~~l~,. ~ ~~~ -~~'F;:T-c...:2Ç::~E~~~~?~~~~~>.~.:::.:~~·~~=·~~~~"'!~.~ ~::::- (Gas .--"'< -~. ':~"'.,¡. .yonè!<·:>-:D· Zõne'Sänds:':';:': ':.:.--::::::-~= --:::-- .~~~:-:~~_~.~.:;·:7!çT~f~~~·~~'~~r.;:.-.: ~::'~:::~6~;~~~~?~~~ Zones) (Wet zone) .--.---=..::: . \-.,..,.···:-.:..,;-.":~·.~'C«O. II Zones) ':¡"'L.' ..-.'--;,~-;.'_'-'._~ ~ . . --.- ~.- - . - ·nF_~'\.,,_.--. - - - (Gas ,,~: -- ~·:Zö.ñe -Sand's: ;:~~:_~.:= - Zones) Tyonek - -. ··--&~~Oil Zó'ne$)'-~'~- . :;..~.:,;:~. .., . , :~.,~...~ .~"r..,:~..~,.",,;.__ '.'&'.~'.: '. ".: . þ~",:_~"...;.>;=/_"~;;~~~~';:-:7.",:::::· ". ,'-,.~>,,:,-:< :-,:.:Òil .......:~:;.:. (--.Con91omerate--.·-:i.~;':."""'-· ~~~~-:':'" v ::~:.<::>':"~~~'~~?~~:.~~~~a~~.~~_>:~",--:-,_ ~"'-::~'~.~<.:~::'7--'~/ '~J v v Vv v" .:..'......<.:.::'.::.....:.....~ \""å Formation ..___--J'" v v .::...>.....;..-:-"..~~\ fore ~~..- --....--;- //:/ v v ~v v v v ~,~ -7000 __________ v tna Formation v v v «0-.,) " v _____ v v Talkee volcanicS) v v v" v v v (JuraSSIC" v v v ~/ TMD 7260 v ~ ~ . -3000 Proposeq for "Y_a.!~!.ncJOq -4000 -6000 Tyonek "C~ Cur re n t.!.'í.J!.e i n9- Wa tertI aoded v v v v 'J n.~D 6532 " v II v v v . soo.~ o 1000' . . ATTACHMENT NO. 7 . WELL TBS A-29 (PROPOSED COMPLETION) 0' 33.15/ 16", 65#, H-10 Casing at 1012' 13 3/8", 61# & 68# K-55 Casing at 4020' . ¿o"'. Packer at:!:5170' Tubing Tail at :t5200' "B" ZONE 5272' - 6500' at Intervals Cement Retainer at ::7000' 9 5/8", 47#, 500-95 Casing at 8709' . . . . CHEìvlICA' & (GEOLOGiCAL TELEPHONE (907) 279-4014 ~l'. ~ ATTACHMENT NO.8 ( ^ . Q r: C\. . ~ C ,.., ('; ( :¡ Li""'\80" I unl~u 01 AL-.v".--" P.O. BOX 4-1276 260J À~C';¡C I"'· . I\i i I . , ANCHORAGE, ALASKA 99509 WATER ANALYSIS REPORT OPERATOR W~LL NO PIELD COm1TY ST A T~ Union Oil Comoenv of Calif. Coole Inlet Water Tradin<; Bay DATr" Febru<1rv 9, 1072 LA:;) NO LOCATION l\!ono~oct P!QtiOr¡1 FORMATION Cook Inlet Water INT!:RV AI. ...- SAlIPLI:: FRaT..! Inj ec-¡;ion \'íater ',- ---- 0123-2 Alaska RE::.!ARKS &: CONCLUSIONS' Sample talten January 31, 1972. Clear water. C:: tkm~ ~ 9490 340 123 850 m~/l - AnJ01"'.~ r=-/l 210·') lr,000 n '.59 ~ 412.78 SodIum Potw-..iwn Calcium . - . . :J¡¡ ¡¡n=i 11m Ù'Qn ..... "'- -- ~ ~. 'J~ Stù1;; tc Cå1=1do -.. - - Cubo::1.2te 13 k=' bon.:I UI Hydroxic» - - - - - . . . . 8,70 h. J 4 139.37 ~~"'; .':0 " ~. Tot:tl C¡¡ti= 497.<:19 "...._"'. L:.~7. .~a Tc{:lj Azic~ . - . . Tott.ù diuQlved øolk1a, m;:jj NaCl oquínlent, ~/l OWened pH ..... 28981 28740 ß.9 " '---:::.õ<-_. Specific rç'~t"..ncc ~ wOF.: O~crvf.XÌ - - - . C:U=l.';.t r.d () ",,, I V.-"'-I o:':'::':'-~., n.29 , . . WATER ANALYSIS PAT'rERN S¿:¡mplc above described Sc.'Ú", MEQ per Unit ............... ,.-....~ j J ~~ ..-- c. Na '~t~; ; :.: ~~~. 1 - ..,.....,..,-H--+~ .'~§g! w~~ n~ -rr~~ê; --1.1.' <: : y: ' .- . 1R~~"~:sg""""'--' ......., ~~ __~~ ~.t-- tttt I i ~ . ~ ~---. ...... ¡, .¡:;cr----.~:::.::::t;::::-'Ç ~ titËè~:; i.:::~~.-··~...:......... ~;. M~_J__--... f "Ffili~ It··"·- "'-~>::~"';"'(~¡;:j!~::;¡:¡i:¡:: '''H' ¡.. ......~_~_~io--~ ..... I·~ H~--.\¡-1-4-'" I ... I-~ ~~t:::=.;-..;.. ~~~--f ,:S£~__L~~ ;::+~~~ .......--.................._--~- .::::·':~7-,::::=;:.-...- I ..E........::;:.:--=--'~ "_<f-.lrr Þ f ....-.---. ,..,. ....- f 1r;~~ ~- --~~-=- '..µ.~-~...... Cl 100 Na HC03 10 Ca SO. 10 Mg 10 Fe ---~' ~~--==: ~~ --- - .,j--- ~L~~~---===. --~ '__-:.....-::-::: ~~.~ 1_.......,- ::::'tr~\, t ~~~--:.;:= ...~_ __t_. _'___,...--~'..._ ____"""- I--~---~ ----... j ......--.----- ~~~--- .;..~-- : - . --- :;:;~:.::::......-=-~-;::::.::::::::..._~-.:::- -... . I r ... -.-+þ----- ----- HC03 ..:=. .....-1---.. ~~~_. ~~--- - -- -- ME; -~ SO. -:::::.--- Fe -- co, ~r-- t ----------- ~ (1''' nlu4 h. .bcnoo ..,..øh. IncJU<!.. No. X. ....d U) HOT!!:: W,/J=WWirram.o I"'"' UtI< IJoqjJ= W¡JJJcnm oqUIU!."", ~ li_ Jod_ dÛDn.w -'I"'" Û01Io' = ~ D UA1.o¡t . H a'WU 0"- a..Icula..... ,._ _.. ..",,",p .... . . ~ WELL NUMBER EST. AVE DAILY RATE (BWPO) MonoDod Platform A-5S A-5L -~--- .-------- 353 149 e e CLASS II. TYPE 'R' INJECTION WELLS EST. MAX DAILY RATE (BI'1'PJ) 1000 500 EST. DAILY INJ. VOL (BW) 353 149 EST. AVE INJ. PRESS (PSI) 2900 2099 ATTACHMENT NO.9 EST /~AX INJ PRESS (PSI) 3000 3000 NATURE CF ANNULUS FLU!DS \'/ate::- Water "..~# The above wells are permitted for underground injection pursuant to Federal Regulations, Subpart "C", "Authorization of Underground Injection by Rule", 40 CFR 144.22, "Existing Class II enhanced recovery and hydrocarbon storage wells ". e · . ATTACHMENT NO. 10 CHEMICAL & GEOLOGICAL LABORATORIES OF ALASKA, INC. P.O. BOX 4·1276 Anchorage, Alaska 99509 ANCHORAGE INDUSTRIAL CENTER 5633 B Street TELEPHONE (907) 562-2343 WATER ANALYSIS REPORT UNOCAL/Northern Test Labs OPERATOR.. WELL NO. FIELD COUNTY STATE Alaska INVOICE #38750 REMARKS & CONCLUSIONS: iJC-z..... LAB NO. 3495 DATE LOCATION FORMATION . INTERVAL SAMPLE FROM B-Zo!le Water Barium, m.¡,1 : Strontium, mg/l: Iron, rrg/l meg/1 523.33 3.33 3.49 13.97 Total Cations. .., . . .. . 544.12 3.2 4.0 0.39 Total dissolved solids, mg/1 . . . . . . . . . . NaC1 equivalent, mg/1 .............. Observed pH.. . . . . . . . . . . . . . . . . . . . . . . Sample above described 31,040 29.946 8.21 Anions Sulfate. . . . . . . . . . . . . . Chloride. . . . . . . . . . . . . Carbonate. . . . . . . . . . . Bicarbonate ......... Hydroxide . . . . . . . . . . . meg/1 0.15 423.00 17.9R 10:::>.<1<1 mg/1 7.4 15,000 540 6.2RO · Cations Sodium ..........:.. Potassium. . . . . . . . . . . Calcium. . . . . . . . . . . . . Magnesium. . . . . . . . . . Iron............... . mg/1 12,030 130 70 170 Total Anions. . . . . . . . . . 544. 12 Specific resistance @ 680 F.: Observed .......... Calculated ......... 0.25 0.24 ohm·meters ohm·meters WATER ANALYSIS PATTERN Scale MEa per Unit Na C1 SO Na C1 Ca HC0310 Ca HC03 Mg SO' 1 Mg SO' · Fe C03 1 Fe C03 (Na value In above graphs Includes Na, K, and L 1) NOTE: Mg/l " Milligrams per liter Meq/1 "Milligram equivalent per liter c:....,.,,,r'" """"'nriri,ø pnlliV:::Ipr1t '= hv Dunl~o Pot H,.wfht"lrnp ~~Ir.tl~'in" frf"lrn ...n....,n.·".,,."',... r , I' .~-\ .= -- C:"1-12A é, CMrtMICAL & GJ::OLOGICAL LABORATORIES AMERICAN STRATIGRAPHIC COMPANY ... O. BOX a, 27 . ANCHOftAO&. AU.1eA . WATER ANALYSIS REPORT OPERATon V'lIJ:LL NO FmLD COUNTY STAT'" Union Oil Company of A-24-C Tradin~ Bav State California DAT1l January LOCATION FORMATION INTERV AT. SAMPLE FRO v Alaska 6, 1971 LAB NO A-770 RE1:!ARXS A> CONCLUSIONS' Slightly cloudy water, clear filtrate. vBarium---------------- 102 m~/1 W rq IF ì'"_ ~tions c.. ?ô::; c,_ m'!/l 16225 110 1606 972 ~ 705.75 2.82 80.14 79.90 ~ Sullate - - - - CbJorid. -.. - Carbonate Bicarbonate - - - - . Hydroxide - - - - - m'l'/l ~ Trace 30660 864.61 0 ;. 244 4.00 ( Sodlum Po~um c¡¡]clum - l!a~um - - - - _ Iron Total Catioaa 868.61 Total ma.olved 8Olida, me/I HaC1 oquivaloot. mtl/l Ob««ved pH - _ . . . 49646 50483 7.0 Specific reåataDCe @ 61°1'.: Obeened . - - - CakuI.ued ...- 868.61 ,~",. , - J .-<./ 0.142 o~meter'I 0.15 0ÀID0~ ; i , ¡ ! f ¡ Cl J HC03 f I I I 804 I , CO. Total AnioDa WATER ANALYSIS PATTERN SulB Sample above described MEQ per Unit Na Ca Cl 100 Na HC03 10 Ca SO" 10 Mg C03 10 Fe Mg Fe U'- nlue In .boft cr."". lad.... No. X. ... U) NO..: ..1I/1=U¡u¡'r...... ..... U'K UoqJl= Willi,...... eq....o1aD~ ..... U_ Sodfuro dt)ond. O'I"¡.......t=b,r D"nlop " HOWÚIo...... calculot\oa lr_ _ta .- \. .~ .~ CL1.12A (REV. 19G~) " t· . , " Vr,,¡ , ¡::JO"'O v v CI-IEMlr.A T. 14c GF.OLœICAL LA nOR A TORillS: Ar.HHHCA~ aVaA'iIGaAPH IC COr.APAr4V ".0. BOX 2127 . ANCHOAAC)E. ALASKA . WATER ANALYSIS REPORT OP~RATORUnion Oil Company of California W~LL NO TRSÂ--'::-T7~ FIELD Tr;¡rJ;n~; Alaska COUNTY STAT~ A 1 aska DATJtJanuary 6. 1969 LAB NO A-142-Vl LOCATION SE NE Sec 8. T-9-N. R-13-H. s. ~.~. FORMATION liD" Zone I'fj,ddle Kana i INTRRVAT. 6704 SAMPLE FROY .[: ~'I/ .= REMARKS It CONCLUSIONS· Oil sarnnle t water extracted, slightly clonày light yellow. Known "D" Zone ( Middle Kenai) Z) ).)::;> c;..' L- ¡~~",//t-" .) ~.r. ';'_ /!ÍOrt '/</5" ~ OJ mecI/l - - - · · 270 r).6? . . · · 22100 621.2? 180 r).99 . . · · 671 H.DO Ction. Sodlum Pot.uaium C&lcium . . tIaanuium Iron E.::!!. meq/l -5ßb-ª5- 11.1.08 20.J.-'6 22.JIll ~ Sulfate Chloride ... Carbonate Bicarbonate . Hydroxide ..... l1q8 c;50 1110 ?73 . . Absp.nt - - - - Totlll Clition. 61,r) .81 611c;.83 ".,-- Total Aniona Total diuolvcd øolid., m¡!l NaCl oquivalœt, lII,i/l Obecrved pH .. - . . 176r), 37 (--f..f, A,7 .ohm-~ ohm-metcn Specific: reWtance @ 68°P.: Obaerved . - . . Cakulated .. - - 0.215 O.?O WATER ANALYSIS PATTERN Swe Sample above described MEQ per Unit Na ... Cl 50 Na Cl HC03 5 Ca HC03 S04 5 Mg 504 C03 5 Fe CO. :1 Ca Mg Fe .lli; ~ ~...~ (H. ..I"" I.. ._ eTOph. ¡..clud.. No. IC, ud Ll) HOTI:: ...'I:::WOUero.... I*' Olot' Uoq/l::: WillIeTO'" oqul..l_to per Utw 104_ <ÀIcInd. equJ.....I=..' D..alap " H....._ caIaolado. fr_ ~to ---- ~--... ._---- -------- -.- ----- - ---- -. . g · c .c .\ 132:0502 e FEDERAL REGULATIONS made a part of the applicable UIC pro- gram under the SDW A for the State of Alabama. This incorporation by reference was approved by the Director of the Fed- eral Register on June 25, 1984. (1) Code of Alabama 1975, §§ 9-17-1 through 9-17-110 (1980 and Supp. 1983); (2) State Oil and Gas Board of Ala- bama, Oil and Gas Report 1 (supple- mented) (1981), General Order Pre- scribing Rules and Regulations Governing the Conservation of Oil and Gas in Alabama (Order No. 76-100) as amended by Board Order No. 82-96 (May 14, 1982) amending Rule E-4). (b) The Memorandum of Agreement between EPA Region IV and the Alabama Oil and Gas Board, signed by the EPA Regional Administrator on June 15, 1982. (c) Statement of Legal Authority. "State Oil and Gas Board has Authority to Carry Out Underground Injection Con- trol Program Relating to Class II Wells as Described in Federal Safe Drinking Water Act - Opinion by Assistant Attorney General," May 28, 1982. (d) The Program Description and any other materials submitted as part of the application or as supplements thereto. §147.51 State-administered program - Class I, Ill, IV and V wells The VIC program for Class I, III, IV and V wells in the State of Alabama is the program administered by the Alabama Department of Environmental Manage- ment, approved by EPA pursuant to Sec- tion 1422 of the SDW A. Notice of this approval was published in the Federal Register on August 25, 1983 (48 FR 38640); the effective date of this program is August 25, 1983. This program consists of the following elements, as submitted to EPA in the State's program application: (a) Incorporation by reference. The re- quirements set forth in the State statutes and regulations cited in this paragraph are hereby incorporated by reference and made a part of the applicable UIC pro- gram under SDW A for the State of Ala- bama. This incorporation by reference was approved by the Director of the Federal Register on June 25, 1984. (I) Alabama Water Pollution Control Act, Code of Alabama 1975, §§22-22-l through 22-22-14 (1980 and Supp. 1983); (2) Regulations, Policies and Proce- dures of the Alabama Water Improve- ment Commission, Title I (Regulations) Rev. December 1980), as amended May 17, 1982, to add Chapter 9, Underground Injection Control Regulations (effective June 10, 1982), as amended April 6, 1983 (effective May II, 1983). (b) The Memorandum of Agreement between EPA Region IV and the Alabama Department of Environment Management signed by the EPA Regional Administra- tor on May 24, 1983. (c] Statement of Legal Authority. (1) "Water Pollution-Public Health-State has Authority to Carry Out Underground injection Control Program Described in Federal Safe Drinking Water Act- Opinion by Legal Counsel for the Water Improvement Commission," June 25, 1982; (2) Letter from Attorney, Alabtima Water Improvement Commission, to Regional Administrator, EPA Region IV, "Re: A WIC Response to Phíllip Tate's (U.S. EPA. Washington) Comments on A WIC's Final Application for Class I, Ill, IV, and V UIC Program," September 21, 1982; (3) Letter from Alabama Chief Assistant Attorney General to Regional Counsel, EPA Region IV, "Re: Status of Independent Legal Counsel in Alabama Water Improvement Commission's Underground Injection Control Program," September 14. 1982. (d) The Program Description and any other materials submitted as part of the application or as supplements thereto. Subpart C-Alaska § 147.100 State-administered program. [Reserved] §147.101 EPA-administered program. (a) Contents. The VIC program for the State of Alaska is administered by EPA. This program consists of the VIC program requirements of 40 CFR Parts 124, 144, and 146, and additional requirements set forth in the remainder of this subpart. Injection well owners and operators, and EPA, shall comply with these requirements. Environment Reporter e ATTACHMENT NO. 11 (b) Effective date. The effective date of the UIC program for Alaska is: June 25, 1984. ( §147.102 Aquifer exemptions. (a) This section identifies any aquifers or their portions exempted in accordance with §§144.7(b) and 146.4 of this chapter at the time of program promulgation. EPA may in tþe future exempt other aquifers or portions, according to applica- ble procedures, without codifying such ex- emptions in this section. An updated list of exemptions will be maintained in the Re- gional office. (b) The following aquifers are exempted in accordance with the provisions of §§144.7(b) and 146.4 of this chapter for Class II injection activities only: (I) The portions of aquifers in the Kenai Peninsula, greater than the indicat- ed depths below the ground surface, and described by a \4 mile area beyond and lying directly below the following oil and gas producing fields: (A) Swanson River Field-1700 feet. (B) Beaver Creek Field-1650 feet. (C) Kenai Gas Field-1300 feet. (2) The portion of aquifers beneath Cook Inlet described by a \4 mile area beyond and lying directly below the fol- lowing oil and gas producing fields: (A) Granite Point. (B) McArthur River Field. (C) :-'1iddle Ground Shoal Field. (D) Trading Bay Field. (3) The portions of aquifers on the North Slope described by a II. mile area beyond and lying directlv below the Ku- paruk River Unit oil and gas producing field. §147~103 Existing class I, II (except en- hanced recovery and hydrocarbon storage) and III wells authorized by rule Maximum injection pressure. The own- er or operator shall limit injection pressure to the lesser of: (a) A value which will not exceed the operating requirements of § 144.28(f)(3)(i) or (ii) as applicable: or (b) A value for well head pressure cal- culated by using the following formula: ,..,...( Pm=(O.733-0.433 Sg)d where ~ [Sec. 147.103(b)] 152 . . . MONOPOD WELL DATA 5-23-85 SPUD CO~1P. DEPTH WELL API '''JU~IBER DATE DATE SURFACE LOCATION BOTTm~HOLE LOCATION TVD STATUS TBS-A-l 50-733-10055 10102/66 07106167 1618'N, 567'1'1 f/SE/Cr.,See.4,T9N,R13W,5M. 34/17'N, 545'\'1 f/SE,Cr.,See.4,T9N,R13W,SM. 6,187 Prod. TBS-I-A 50-733-10052 05110/65 06/25/65 1598'1'1,2029'5 f/NE/Cr.,See.4,T9N,R13W/5M. 3/¡l¡7'N, 545'1'1 f/SE,Cr.,See.4,T9N,R13W,SM. 6,532 P'" A lBS-A-2 50-733-10056 10/18/66 12/06/66 1613'N, 570'1'1 f/SE/Cr.,See.4,T9N,R13W,5M. 2069'N,2033'W f/5E,Cr.,5ee.4,T9N,R13W,5M. 6,448 Prod. T05-A-3 50-733-10057 12/09/66 04/24167 556'W,1616'N f/SE/Cr.,Sce.4,T9N,R13W,5M. ]t¡27'N, 357'E f/SW,Cr. ,See.5, T9tJ,R13W,SI~. 10,544 51 18S-A-4 50-733-20001 03/24/67 04/26/67 1611'N, 558'1'1 f/SE/Cr.,See.4,19tJ,R13W,5M. 1768'N, 78'E f/SW,Cr.,See.5,19N,R13W,SM. 10,491 51 IBS-A-5 50-733-20011 04/27/67 06/04/67 1605'N, 568'1'1 f/5E/Cr.,5ee.4,T9N,R13W,SM. 487'5,2598'1'1 f/NE,Cr.,See.9,T9N,R13W,SM. 6,962 P'" A e 18S-A-5RO 50-733-20011 01/30/70 02/24/70 1605'N, 568'1'1 f/SE/Cr. ,Sec.4, T9N,R13W,SI~. 332'5,2668'1'1 f/NE,Cr.,Sec.9,T9N,R13W,SM. 6,815 P & A IBS-A-5RD2 50-733-20011-01 02/04/76 03106176 1605'N, 568'1'1 f/SE/Cr.,See.4,T9N,R13W,SM. 693'5,2673'1'1 f/NE,Cr.,See.9,19N,R13W,sM. 6,251 Inj. TBS-A-6 50-733-20020 06/06/67 06/28167 1600'N, 568'1'1 f/SE/Cr.,sec.4,T9N,R13W,SM. 3465'N,1997'W f/SE,Cr.,See.4,19N,R13W,SM. 6,007 Prod. 18S-A-7 50-733-20036 08/27/67 10/12/67 1615'N, 561'1'1 f/SE/Cr.,See.4,T9N,R13W,SM. 1826'N, 514'1'1 f/SE,Cr.,See.4,T9N,R13W,SM. 6,389 Prod. TBS-A-8 50-733-20043 10/11/67 11/11/67 1612'N, 577'1'1 f/SE/Cr.,see.4,19N,R13W,SM. 2105'N,3123'W f/SE,~r.,See.4,19N,R13W,SM. 6,518 51 TB5-A-9 50-733-20062 11/12/67 12105/67 1625'N, 566'1'1 f/SE/Cr.,Sec.4,T9N,R13W,SM. 549'S, 777'1'1 f/NE,Cr.,See.4,T9N,R13W,SM. 6,076 P & A TBS-A-9RO 50-733-20062-01 04/10/81 05/11181 1625~N, 566'1'1 f/5E/Cr.,sec.4,T9N,R13W,SM. 1530'N,2700'W f/SE,Cr.,See.4,19N,R13W,5M. 6,467 Prod. TBS-A-10 50-733-20064 12/05167 01/07168 1609'N, 571'1'1 f/SE/Cr.,5ee.4,T9N,R13W,SM. 1094'N,2639'W f/SE,Cr.,Sec.4,T9N,R13W,5M. 6,652 SI IBS-A-ll 50-733-20214 03/20170 OS/23170 1619'N, 559'1'1 f/SE/Cr.,Sec.4,T9N,RI3W,sM. 281'N, 514'1'1 f/SE,Cr. ,See,4, T9N,R13W, 511. 9,927 Prod. TBS-A-12 50-733-20076 02/13/68 03/17168 1617'N, 571'W f/SE/Cr. ,Sec.4, T9I1,R13W,SI~. 3343'N,3119'W f/SE,Cr.,Sec.4,T9N,R13W.SM. 6,450 P & A TBS-A-12RO 50-733-20076-01 02/22/72 03/31172 1617'N, 571'1'1 f ISElCr., see.4, T9N, R13W, SI~. 2694'N, 184'W f/sE,Cr.,see.5,T9N,R13W,511. 6,118 SI TB5-A-13 50-733-20077 01106/68 02/13/68 1604'N, 573'W f/SE/Cr.,See.4,T9N,R13W,5M. 993'N,3730'W f/SE,Cr. ,5ee.4, T9N,R13W,SM. 6,447 Prod. TB5-A-14 50-733-20099 04/04/68 06/01/68 1601'N, 579'1'1 f/SE/Cr.,5ee.4,T9N,R13W,5M. 286'N,4618'W f/SE,Cr.,See.4,T9N,R13W,SM. 6,630 Prod. TBS-A-15 50-733-20105 06/06/68 06/23168 1616'N, 577'1'1 f/SE/Cr.,Sec.4,T9N,R13W,SM. 4206'N,1911'W f/5E,Cr.,See.4,T9N,R13W,SM. 6,011 Prod. TB5-A-16 50-733-20111 06/25/68 07/24/68 1610'N, 566'1'1 f/SE/Cr.,See.4,T9N,R13W,SM. 1669'N,3960'W f/SE,Cr.,Sec.4,19N,R13W,SM. 6,515 SI TBS-A-17 50-733-20135 07/23/68 08/28/68 1608'N, 576'1'1 f/SE/Cr.,Sec.4,T9N,RI3W,sM. 823'S, 605'E f/NW,Cr.,See.9,T9I1,R13W,sM. 6,876 SI TB5-A-17RD 50-733-20135-01 06/11/81KO 07/03/81 1608'N, 576'W f/5E/Cr.,See.4,T9N,R13W,5M. 37'5,2609'1'1 F/NE,Cr.,5ec.9,T9N,RI3W,SM. 4,197 Prod. TB5-A-18 50-733-20143 08/29/68 11117/68 1624'N, 558'1'1 f/5E/Cr.,See.4,T9N,R13W,5M. 741'5, 443'E f/NW,Cr.,Sec.3,T9N,R13W,SM. 10,228 Prod. TB5-A-19 50-733-20151 11/23/69 01/29170 1625'11, 562'W. f/SE/Cr.,Sec.4,T9N,R13W,5M. 3480' S, 1050' 1'1 fiNE, Cr., See. 5, T9N, R13W, SI~. 6,886 51 TB5-A-20 50-733-20302 07/24/77 10/01/77 1601¡'N, 559'1'1 F/SE/Cr.,5ec.4,19N,R13W,5M. 2618'N,1857'£ f/5W,Cr.,See.10,T9N,R13W,5M. 10,661 S1 T8S-.I\-21 50-733-20223 09/21170 10/21170 1600'N, 561'1'1 f/5E/Cr.,See.4,19N,R13W,SM. 1901'5,1182'£ f/NW,Cr.,See.9,T9N,R13W,5M. 6,164 P & A TBS-A-21RD 50-733-20228 01/17/72 02/21172 1600'N, 561'1'1 f/SE/Cr.,Sec.4,T9N,R13W,5M. 1908'S, 993'£ f/NW,Cr.,See.9,T9N,R13w,SM. 6,197 Prod. e 18S-.I\-22 50-733-20218 05/27170 07/19/70 1600'N, 565'1'1 f/SE/Cr.,sec.4,T9N,RI3W,5M. 149'5, 248'W f/NE,Cr.,see.8,T9N,R13W,SM. 6,926 Prod. 185-A-23 50-733-20227 12/28170 Gl/1l¡171 1601'N, 557'W f/SE,Cr.,Sec.4,19N,RI3W,5M. 733' S, 38135' 1'1 f mE ,Cr. ,See. 9 ,19N, R13W, SM. 5,976 Prou. TB5-A-24 50-733-20226 10/21170 11123170 1620'N, 574'1'1 f/SE,Cr.,5ee.4,T9N,R13W,5M. 912'N,1546'W f/sW,Cr.,See.5,T9N,R13W,SM. 6,162 P & A IBS-A-24RD 50-733-20226-01 01/15/81 1620 'N, 574 '1'1 F /SE ,Cr. ,Sec .ll,19N ,IU 31'1,9·1. 357'N,3396'W f/SE,Cr.,See.4,T911,RI3W,SM. 4,265 Prod. lOS-A-25 50-733-20242 05178/72 07/21/72 1(,17'11,551'1'1 f'/SE,Cr.,Sec.ll,T911,HIIV/,']1. JOIII'II, 5:JI'E f/SW,Cr.,Sec,lI, T9I1,rH3W,5/~. 5,959 51 TlJS-I\- 26 50-733-2rJ2.30 011/01//2 05102172 1606'11, 563'1'1 t/~,r:,CI'. ,5r,c.ll, 1911,HI3W,~it~. J9:J9'S, ldJ'W f/SE,Cr. ,Sce.O, 1911,fn3W,5M. 5,672 SI TOS-I\-27 50-733-20246 02/23/73 011/11173 1605'N, 553'1'1 '/SE,er. ,Sec.lI,19tJ,H13il,SM. 2"11)11' S. 39llU '1'1 fiNE ,Cr. ,See. 9, 19N,R13W, SI~. 7,017 Prod. mS-A-28 50-733-20255 11/03/73 12/05/73 1621'11, 55l¡ 'W f/SE,Cr.,Sec.4,T~J,RI3W,SM. 10119'S, 2%'E f/NW,Cr.,Sec.3,T9N,RI3W,5M. 5,570 Prod. 105-1\-29 50-733-202/15 12/0?/72 021'22/73 16'll¡ 'N, 5l0'W fISE,Cr. ,Sec. II, r~Jt,'¡1 ~W,5I·1. ~1I!5' ~J, 1370' 1'1 f/SE,Cr. ,See.5, 19U,H13W,5tt. 5,619 S1 lBS-A-30 SO-733-2l1253 05/05/73 07/0ll/7 3 1612'11, 5~) 1 '1'1 f'I ~;F , C 1'. , ~;e c . l¡ , I 91 " n ~ IV , ~H . 1921'N,/¡JI¡2'W f/SE,Cr. ,Sec.4, r9t1,H13W, Sit. 5,933 Prod. TUS-A-32 50-733-20301 OS/20/77 08/Œi/77 1607'N, 556'1'1 f/SE,er.,Sce.4,r9N,HJ2W,SM. 2363'N, 8tH '1'1 f IsE ,Cr. ,Sec. II, r9N,HI jlV ,S,~. 6,304 Prod. ATTACIIMENT NO. 12 , . · · · , e APPLICA nON FOR ADDITIONAL RECOVERY 20 ACC 25.400 TRADING BAY FIELD 'B' POOL WATERFLOOD e ADDENDUM NO. A ,.' e e . APPLICATION FOR ADDITIONAL RECOVERY 20 AAC 25.400 TRADING BAY FIELD 'B' POOL WATERFLOOD Summary The 'B' Pool water flood is a pressure maintenance project currently proposed in the II-A fault block of the Trading Bay Field. The purpose is to supplement the 'B' Pool reservoir pressure to optimize oil recovery. As shown in Exhibit I, the 'B' Pool water flood will encompass the following area: T 9 N, R 13 W,S. M. Sections 4 and 9 The 'B' Pool water flood will include the four existing producers in the II-A fault block and one new water injector that will be recompleted from an existing Trading Bay Field well. The single water injector is planned to inject approximately 1350 BWPD. If this injection rate cannot be maintained in one well, additional wells· will be recompleted to supplement the injection. The injector will be located as a peripheral injector rather than a five-spot pattern. All of the 'B' Pool wells, along with all other Monopod wells, are shown on Exhibit I. . The operator of the 'B' Pool waterflood will be Union Oil Company, a ,,- subsidiary of Unocal Corporation. A 50% interest is held by the Operator in all sections included in the project. The other 50% interest owner is Marathon Oil Company. The addresses of Union, Marathon, and the names and addresses of the adjacent lease holders are included in Exhibit II. Reservoir Description The name of the reservoir to be water flooded is the Trading Bay Middle Kenai 'B' Oil Pools. According to Rule 2 of the Field Rules (Conservation Order No. 93), these pools are defined as the accumulations of oil and gas occurring in the interval which correlate with the interval 3200' to 4585', drilled depth, in the Union Oil Company of California Trading Bay State A-14 well. Exhibit III lists the pools in which all existing wells in the II-A fault block are currently completed along with the status of each well. . Injection Wells and Casing Program The location of A-29, the well to be converted to the 'B ' Pool water injector, is shown on Exhibit I. The log section of this well across the 'B' Pool is shown on Attachment IV along with the proposed perforations. The casing program for the well and any future well to be recompleted into the 'B' Pool will be in accordance with 20 AAC 25.410. The current idle completion of well A-29 in the 'C' and '0' Pools will be permanently e e . Application for Additional Recovery Trading Bay Field 'B' Pool Waterflood August 26, 1985 Page 2 abandoned with a cement retainer and then cement squeezed. The 'B' Pool completion will consist of the following casing and tubing: 16", 6511, H-40 cemented at 1012' M.D. 13 3/8", 6111 & 6811, K-55 cemented at 4020'M.D. 9 5/8", 4711, 500-95 cemented at 8709' M.D. Cement Retainer at approximately 7000' M.D. 2 7/8" or 3 1/2" tubing to approximately 5200' M.D. Production Packer at approximately 5170' M.D. The actual wellbore schematic of well A-29 has been included in Exhibit v. Source Water As is the case with the Trading Bay Field water floods in the 'C' and '0' Pools (described in Conservation Order No. 93), filtered Cook Inlet water will be used for injection water. Well Tests and Monitoring . The most recent production rates of the four existing 'B' Pool producers are listed in Exhibit VI. The average production rate is 121 BOPD with a'" total 'B' Pool water cut of only 2.4%. Following the recompletion of well A-29 and any future recompleted water injectors in the 'B' Pool, a water injector profile survey will be performed. The surveys will be used to insure that all injection water is confined to the intended completion interval. Additional profile surveys will be performed following any type of remedial work that changes the completion interval or if a drastic change occurs in the injectivity. A semi-annual progress report will be submitted similar to the reports of the 'C' and '0' Pools specified in Rule 8 of the Field Rules (Conservation Order No. 93). All injection volumes will be reported monthly per 20 AAC 25.430. Development Plan The 'B' Pool waterflood is planned to include four producers and one injector in the II-A fault block. However, the lack of injection volume in well A-29 would cause additional injectors to be completed in the 'B' Pool. . The facilities for the 'B' Pool water flood consist of those in current operation supplying water to the Trading Bay Field 'C' and '0' Pool Water floods . No additional equipment or modi fications are necessary as the current facilities are capable of more water than will be required. Current filtration and injection capacity on the Monopod is approximately 12,000 BWPD. The combined requirement for the IB', 'C' and '0' water floods will be 8,000 BWPD. A schematic of the water injection facilities are included in Exhibit VII. JCL/ejj:1204r . e e --------, I I ...... ,,".-_'"" 1 Y::~1 rd- I 32,33 33134 ~'~~~'~~~"""5""~À.·"~'\."""""'~'''''''''''''''''''"~""""",,,,,,,,,,,,,,,,,,,,,,,,~,,,,,,,,,,,,,,,,,,,,,,,,,,,"'~"""""~~~,'~~~~~ I....... I , ......,. ¡ ..:; I I' r I , A-IS I I \ I .A-9 i:-:~"';-~i.'· \ I \:::~ r . I' I: ~ ¡ : ! A-2S .' "-01 . : A-IŠ '1 ;. ;~~¡ · ;ï -¡ ,~.. : ~:..-.., \' r "... I \"v I I \', I " j. ¡. I \' '. .A-6. '~~ A-I / ' I ~A-J2 ~=.' \' :;:';~. i / r I ::':';:; \\ II ~;-;;; .I~ r I',' /(.. I \. J !! A-12 RDI ' I, (0' · , L I . . \ \ ! I' f'tIe...~.,-j -- - -....... - - ~~-. ,~., t'--.. ~"A...3,~ \, í I)~ .~ f-S I ~ ~-;¿;-'\'" ,/ A-30 -. =~ -- . ¡ A:.,,2_1It'-... A<Þ11 '\. ~'A.7 . '.. A ------- :r::=;:''fO'''~'~~fC'' í.....,-.¡, ~ . I:'r.::!l"\ -------:--.,. '.! ._. ,~.- ..ç;"-~-' X _A~1~ --__ .. ...¡ ..., " ..".~;+:··A-4 ~ ~:':;~, " .-- . . ..... ....... ~.i..:6.- --.__ _..~~..w . __ '" _ ----l- ¡ --;....- 97"- ,....._ , .... A-9~?:., . ~~ . . ':'-~. ~1~- ~/-<'ÿ~~?"Î ~\~ - A-I3 ~.-"---:--~p-;;/: .,,/. ' , ' --- . ~._;~~~ /,,~;..-;/, r:-;;::: ~:::f' -r ~~....-' @d;j/'/' ._;::-~. V; ~/'/ _______. ý/5 / /, , . A-2~~q//Ji,;/' . ¡,/ \ ~::: ~:l~I~O . / / 413 ~. .'/-:'.:~~~~,,:f,l gilD \ . /'" ""~:l"--- /" .1,/ . ~:~; ~~' A- 17 . .-/ A-5 RD-2 ... ... .~ ... 'A,.23 hO'''''''' " :-:~= r:i~~ // ."'" )r: -. . T 9 N A-29 A-24 ~ -..,.,., jí 2::.:...:::..·.. ;~:~ ~ . EXHIBIT I r I A-I9 ......... --. '''D._ A-2.5 . ~= ---....-:.-. 514 A-22 J¡ ~ 9 ;:\~.:; . A-I4 ::~'? / A-26 , ;:: ~:: A~!I..~D .-.....- -- ,.....,..~ --"/---~ ........... . 3 ..-~' ,..... t-iiY / . I / ,/ ,/ / / T$-4.// J ,i ~ïl' r..- ' ,. ........... , -.; T5-2 ,~- ~-;;:~ ,.' \\\\ I \\\ ,. I unl3fl TRADING BAY FIELD ... A-27 ..// -<-to ..--t -r-- ._._~---~-- ---~-..- ---~ ......- f.._' ~-~ .." .... , -.-.- ,.- , "' . e . ARCO Alaska Inc. A TO 1115B Anchorage, Alaska 99510 Marathon Oil Company P. O. Box 10-2380 Anchorage, Alaska 99510 Mobil Oil Company P. O. Box 5444 Denver, Colorado 80217 EXHIBIT I I. OPERATOR ADDRESSES Texaco Oil Company 3350 Wilshire Boulevard Los Angeles, California 90010 . .' Union Oil Company P. O. Box· 190247 Anchorage, Alaska 9951S-0247 JCL/ejj/1204r . e ,.' e e . EXHIBIT III TRADING BAY FIELD II-A Fault Block Well Completions Well No. Pool status A-2 S '0 '-Hemlock Shut-in Producer A-2 L Hemlock Active Producer A-5 ROII2 S 'c' Active Injector A-5 ROII2 L '0' Acti ve Injector A-a S 'O'-'E' Shut-in Producer A-a L Hemlock Shut-in Producer A-9 RO S 'c' Active Producer A-9 RD L 'D'-'E' Active Producer A-IO S 'C' Shut-in Producer A-IO L 'D'-'E' Shut-in Producer A-ll S 'C' Active Producer A-ll L '0' Active Producer A-12 RD 'c' Shut-in Injector A-13 'O'-'E'- Hemlock Active Producer A-14 'c' Active Producer A-16 S 'C' Shut-in Producer A-16 L Hemlock Shut-in Producer . A-I? RO 'B' Active Producer -p A-19 S '0' Shut-in Injector A-19 L '0' Shut-in Injector A-22 S 'B' Shut-in Producer A-22 L 'B' Active Producer A-23 S 'C' Shut-in Producer A-23 L '0' Active Producer A-24 RD 'B' Active Producer A-25 S 'C' Shut-in Producer A-25 L '0' Active Producer A-26 S 'c' Shut-in Injector A-26 L '0' Shut-in Injector A-29 S 'C' Shut-in Injector A-29 L '0' Shut-in Injector A-30 'B' Active Producer A-32 'c' Active Producer . . EXHIBIT.I[ . TRADING SA. FIELD;_, ~._=-.' 1_ WELL TBS A-29 1:; X.·n " CNL-FDC CASED HOLE I-=:~!. ':-:..1 TOP 31-8 SANDI ._, ~. : -: I oJ 5269' (-3337')--t.- .. -. g · . t.. I . . ! _I.~.-: .1· : : : >i! ~'-----i · .: . S .. '-1 I . J .. ! I·· ~ · .~ -_.f" . ..-. ..,. ----- ~--------O.___-< 0 I .. < . ¡ . . . · i c. BASE 31-8 SAND <.': . ':..1 :- : := ! -"'-' ,f'--'; . ...... ! :: :21 :: ¡ ,- ~ ~:-f:> :~: I , .: -: ,?¡ . . . -- TOP 33-6 SAND, ~~- · ~. . ~ . - . j 5557' (-3493 ') j-.-.- /' I _.-. _ -. "" . 'u... . -. . I I.. . ~. )-. .---. ~ 1. BASE 33-6 SAND!----' .. ¡ : : : : I ." i ~ç~_-~~-~~ TOP 40-4 SANDI : -- : :.,.~ ¡ I . . .- <" " 5676' (-3559') I~t-_L_-~--j I ' ..." ... I ¿ BASE 40-4 SANDi· :.: {. I :..:: ·1 , -/'1 I . ....... I' I .-. ~I .;."'-¿ ... !~~-~~> --:~~I g :::~:::! TOP 41,-8 SAND!---:-~-~~<~:--j , . , , 5" 5870' (-3667') ¡ . . -. .... J '~f :-r-~-'-:~ I ¡ : \ ! : : : : . I---~ ~)---~.~~~- "~ I··,· I (',"';'>0:. I i . : ' : , : : . : I ·1· , . . . .; " BASE 41-8 SANDI .~! ..! 0 6023' (-3753') I : : . ~ . : : : I 1--:-~(~-~-1 , :: :/" . : : I I . .. ~. . I ~ :-~-:'¿.:.'~-:' ___un! :; . . . (:) o o -l u.. a: w t- « ~ a: o u.. Z o - t- W -l a. ~ o o w a: w z o N It fI) ::; -' ~. ' ,- ,; -- --~-·~~-r-· ~:.~ :--~--- _.._~~-~ ~--. -~ -;--r: .. ~~~ _:..----, -----. --~. . ,.~. -"-~~iT- --- . ! :. -~ - -=? i ------- --=.:~~~~- I : ¡ .~<-~- . --. - j . -. . f i --. . . -~..--.. :~ : . :~."4 'I -=;;--' --- ---~~---~....:...~ ~_._-_.- -- ~-~- - - ----._- -- .--- ----- c - ,- : .: :S:-:=::.-. =::-. _2:.____________ · -I · ¡ , I · - f ~ - -_---:-:-~ ? . ...:z:.-'-' .. j-', -. - ~~-=--=-:~ ~--==---: ' ... ;..' . ¿ 4 ______ ~... : __________ ____u__ ~- ~-~ ~ ""'- . -- . ~ - ------ L ~~' . '.j .---==- I·~:~_~···.,r I _ .;~ ~~_ I' : : -;..: ',...." .. ~~ : : .: I ,_. ":? . .. I----c:~ ~~ --~-~ I_.u ____~_ I : : I .. .. .,. -__.. . I ! I ! ..-- ~... '", :;-~ ~~- 'p ~. ~==-' ------ . ..--:...-::j..'-'-~ - ---- ~ -..--~.. --- ~ .:.'~=",~. I . . : · I . ---. - --- --- ~:. ~ --.- I ~ I ¡ "--'S~' .---~~ I . ž~ ¡ 3' i ~~'- -.----~ ¡ , -..;:=-' · I ' --="" e EXHIBIT I e . WELL TBS A-29 (PROPOSED COMPLETION) 0' 33.15' 16", 65#, H-10 Casing at 1012' 13 3/8", 61# & 68# K-55 Casing at 4020' . ,.' Packer at:!:5170' Tubing Tail at :!:5200' "B" ZONE 5272' - 6500' at Intervals Cement Retainer at:!:. 7000' 9 5/8", 47#, 500-95 Casing at 8709' . · · · WEll # A-17RD A-22 . A-24RD A-30 TOTAL e EXHIBIT II e TRADING SA Y FIELD "B" POOL PRODUCERS CURRENT RATES RATE (BPDI GROSS NET WATER CUT . (%1 74 74 o 133 133 o 176 166 5.8 112 110 1.7 495 483 Oil GRAVITY (0 API! 20.3 19.4 ,. . 19.5 20.2 BACKWASHIMPS SAND FILTERS . . OURCE WATER 'JMPS ... NORTH 0 VACUUM TOWEr, INJECTION CHARGE PUMP SOCK FILTERS (I) 0.. ~ ::J 0.. ACCUM. TANK 400 BBL. SATURN INJECTION 2000+ CAT e' MONOPOD WATER INJECTION FACiliTIES 2 Vertical Turbine Source Water Pumps 1 Filter Charge Pump 125 hp 1 400BBL Accumulator Tank 75hp each 1 Filter Charge Pump 90 hp 1 Injection Charge Pump 125 hp 2 Vertical Turbine Backwash Pumps 100 hp each 3 Operating Sand Filters 2 Sock Filters 1 Vacuum Tower Operating 2 Stored Sand Filters 2 Saturn-Bingham Pumps e 1 Vacuum Tower Stored 2 D.E. Filters 2 30hp Electric CAT Inject Ion Pumps ¡¡t:o I D~H. DRAWN _ CKD. __. _ M.E.G.+J 116/85_ MONOPOD PLATFORM APP'D. ---. B.A.W...3lZleQ_ :;CAL( I DAT E --l~--- ". ,.. _.r_ . .~-~_. --_.- W A TERFlOOD SCHEMA TIC DIAGRAM --- .-. ----- , .-.---, UNION OIL COMPANY OF CALIFOR N IA --. ..t- ----.. A LA SK A DI5TRICT ~H!·f.T<; . 'èHFFT .-.