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DIO 002
~ i Image Project Order File Cover Page xHVZ~ This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. ~,~ d ~~~ Order File Identifier Organizing (done) RESGAN ^ Color Items: ^ Greyscale Items: ^ Poor Quality Originals: ^ Other: <o.aea uuimmiiiuii DIGITAL DATA ^ Diskettes, No. ^ Other, No/Type: ^ Logs of various kinds: NOTES: BY: C Maria Date: Project Proofing BY: _ Maria Date iuiumimiiiu ~~ Scanning Preparation BY: Maria Production Scanning Re.~,,,~eea~ iiiuiiiiAiiuuii OV SIZED (Scannable) M/tips: • Other Items Scannable by V a Large Scanner ~b~ OVERSIZED (Non-Scannable) ^ Other:: /s/ P Date: f/ , ~(/ T x 30 = + =TOTAL PAGES (~.~,~ q f/n (Count does not include cover sheet) Stage 1 Page Count from Scanned File: ~ v tCount does include cover sh t) Page Count Matches Number in Scanning Pr partition: YES BY: Maria Date: I L ~~ /D Stage 1 If NO in stage 1, page(s) discrepancies were found: YES BY: Maria Date: Scanning is complete at this point unless rescanning is required. -wIP "iui~umuHiui ReScanned III II~III I) (~I I I II~ BY: Maria Date: /s/ Comments about this file: Quality Checked III (I'IIIIII III II 10/6/2005 Orders File Cover Page.doc INDEX DISPOSAL INJECTION ORDER NO 2 Kenai Gas Field December 31, 1986 Union's Ltr re: WD-1 Step Rate Test and 2. January 20, 1987 3. January 30, 1987 4. November 7, 1994 5. February 18, 1987 6. September 27, 2004 temperature Survey Unocal's Injection Application Kenai Gas Field Notice of Hearing and affidavit of publication Unocal ltr re:: Data for KU 14-4 Disposal Project Request by UNOCAL to dispose Proposal to amend underground injection order Disposal Injection Order 2 ~~ • iii ; ~ ~ ~ { .~ ~ ~ ~ ``., ~ ~ ~ j ' ~ ~, ' _ i ~~ l '%,~+ J as, ~~`,; ~ ~ °'=, ~ ~, '', ~% FRANK H. MURKOWSK/, GOVERNOR :..-...a .~ ~ .,~..~ .... .~ :~ r' ~~~~ ~~a~~+ ~t ~~r > ~a~ca-71~A OIIt A1~TD GAS ~' 333 W. 7"' AVENUE, SUITE 100 CO1~T-rlFiRQA'1`IO1Q CO1rII~IISSIOR - ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 27&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 In'ection Orders AIO 1 -Duck Island Unit 6 7 9 AIO 2B - Kuparuk River Unit; Kuparuk River, Tabasco, Ugnu, West Sak 6 ~ 9 Fields AIO 3 -Prudhoe Bay Unit; Western Operating Area 6 ~ 9 AIO 4C -Prudhoe Bay Unit; Eastern Operatin Area 6 ~ 9 AIO 5 -Trading Bay Unit; McArthur River Field 6 6 9 AIO 6 -Granite Point Field; Northern Portion 6 ~ 9 AIO 7 -Middle Ground Shoal; Northern Portion 6 ~ 9 AIO 8 -Middle Ground Shoal; Southern Portion 6 ~ 9 AIO 9 -Middle Ground Shoal; Central Portion 6 ~ 9 AIO l OB -Milne Point Unit; Schrader Bluff, Sag River, 4 5 8 Kuparuk River Pools AIO 11 -Granite Point Field; Southern Portion 5 6 $ AIO 12 -Trading Bay Field; Southern Portion 5 6 8 AIO 13A -Swanson River Unit 6 ~ 9 AIO 14A -Prudhoe Bay Unit; Niakuk Oil Pool 4 5 8 AIO 15 -West McArthur 5 6 9 u Affected Rules Injection Order "Demonstration of "Well Integrity "Administrative Mechanical Failure and Action" Inte rity" Confinement" River Unit AIO 16 - Kuparuk River Unit; Tarn Oil Pool 6 7 10 AIO 17 - Badami Unit 5 6 8 AIO 18A -Colville River Unit; Alpine Oil Pool 6 7 11 AIO 19 -Duck Island Unit; Eider Oil Pool 5 6 9 AIO 20 -Prudhoe Bay Unit; Midnight Sun Oil Pool 5 6 9 AIO 21 - Kuparuk River Unit; Meltwater Oil Pool 4 No rule 6 AIO 22C -Prudhoe Bay Unit; Aurora Oil Pool 5 No rule 8 AIO 23 - Northstar Unit 5 6 9 AIO 24 -Prudhoe Bay Unit; Borealis Oil Pool 5 No rule 9 AIO 25 -Prudhoe Bay Unit; Polaris Oil Pool 6 g 13 AIO 26 -Prudhoe Bay Unit; Orion Oil Pool 6 No rule 13 Dis osal Injection Orders DIO 1 -Kenai Unit; KU WD-1 No rule No rule No rule DIO 2 -Kenai Unit; KU 14- 4 No rule No rule No rule DIO 3 -Beluga River Gas Field; BR WD-1 No rule No rule No rule DIO 4 -Beaver Creek Unit; BC-2 No rule No rule No rule DIO 5 -Barrow Gas Field; South Barrow #5 No rule No rule No rule DIO 6 -Lewis River Gas Field; WD-1 No rule No rule 3 DIO 7 -West McArthur River Unit; WMRU D-1 2 3 5 DIO 8 -Beaver Creek Unit; BC-3 2 3 5 DIO 9 -Kenai Unit; KU 11- 17 2 3 4 DIO 10 -Granite Point Field; GP 44-11 2 3 5 • • Affected Rules Injection Order "Demonstration of "Well Integrity "Administrative Mechanical Failure and Action" Integrity" Confinement" DIO 11 -Kenai Unit; KU 24-7 2 3 4 DIO 12 - Badami Unit; WD- 1, WD-2 2 3 5 DIO 13 -North Trading Bay Unit; S-4 2 3 6 DIO 14 -Houston Gas Field; Well #3 2 3 5 DIO 15 -North Trading Bay Unit; S-5 2 3 Rule not numbered DIO 16 -West McArthur River Unit; WMRU 4D 2 3 5 DIO 17 -North Cook Inlet Unit; NCIU A-12 2 3 6 DIO 19 -Granite Point Field; W. Granite Point State 3 4 6 17587 #3 DIO 20 -Pioneer Unit; Well 1702-15DA WDW 3 4 6 DIO 21 - Flaxman Island; Alaska State A-2 3 4 7 DIO 22 -Redoubt Unit; RU D1 3 No rule 6 DIO 23 -Ivan River Unit; IRU 14-31 No rule No rule 6 DIO 24 - Nicolai Creek Unit; NCU #5 Order expired DIO 25 -Sterling Unit; SU 43-9 3 4 7 DIO 26 - Kustatan Field; KF 1 3 4 7 Stora a Injection Orders SIO 1 -Prudhoe Bay Unit, Point McIntyre Field #6 No rule No rule No rule SIO 2A- Swanson River Unit; KGSF # 1 2 No rule 6 SIO 3 -Swanson River Unit; KGSF #2 2 No rule 7 Enhanced Recove In'ection Orders EIO 1 -Prudhoe Bay Unit; Prudhoe Bay Field, Schrader No rule No rule 8 Bluff Formation Well V-105 • • Affected Rules Injection Order "Demonstration of "Well Integrity "Administrative Mechanical Failure and Action" Inte 'ty" Confinement" EIO 2 -Redoubt Unit; RU-6 5 g 9 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM STATE of ALASKA NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED w O_0251 ~16 ORDER AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF /'1 ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE ~ SEE' BOTTOM: FOR tt+IVOICE ADDRESS F AOGCC AGENCY CONTACT DATE OF A.O. R 333 West 7th Avenue, Suite 100 ° Anchorage, AK 99501 PHONE Pc "' 907-793-1221 DATES ADVERTISEMENT REQUIRED: o Journal of Commerce October 3, 2004 301 Arctic Slope Ave #350 Anchorage, AK 99518 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: AFFIDAVIT OF PUBLICATION United states of America REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. division. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED W ITH THE INVOICE. Before me, the undersigned, a notary public this day personally appeared ATTACH PROOF OF PUBLICATION HERE. who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2004, and thereafter for consecutive days, the last publication appearing on the day of .2004, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This -day of 2004, Notary public for state of My commission expires Public Notices • Subject: Public Notices From: Jody Colombie <jody colombie@admin.state:ak.us> Date: Wed, 29 Sep 2004 13:01:04 -0800 To: undisclosed=recipients:; BCC: Cynthia B Mciver <bren mciver@dmin.state.ak.us>, Angela Webb' <angie_webb@.drnin.state.ak.us>, Robert E Mintz <robert_mintz@!law.state.ak.us>; Christine Hansen <e.hansen@-iogcc.state.ak.us>, Terrie Nubble <hubbieal(«~bp.com=, Sondra Ste~wman <StewmaSD@BP.com>, Scott & Cammy Taylor<staylor@laska.net>, stanekj <stanekj@ueocal.com>, ecolaw <ecolaw@trustees.org>, roseragsdale <roseragsdaie@ei.net>, trrrrjrl <trmjrl@ol.cam>, jbriddle <jbriddle@marathonail.com>, rockhll <rockhill@aga.org>, shaneg <shaneg@evergreengas.ccnn>, jdarlington <jdarington@forestoil.com>, nelson <knelson@etraleurnnews.com>, cboddy <cboddy@sibelli.com>, Mark Dalton <mark.daltan@drinc.com>, Shannon Donnelly <shannon.donnellti ~a.'conocophllip$.cam ~- "Mark F. Worcester" <mark.p.wureester@conocaphillips.com>, "Jerry C. Detlrlefs" jerry.c.dethlefs@onocophillips_com>, Bob <bob~a inletkeeper.orgj, ~~d~ ~ -wd~,r~'dnr.state.ak.us>, tjr <tjr@dnr.state.ak.us>, bbriteh <bbritch@alaska.net>, mjnelsan <mjnelsan@ur~~ingertz.com>, Charles Q'Donnell <charles.a'donneli@vecocom>, "Randy L. Skillern" <SkiI1eRL@BP.com>, "Deborah J. Janes" <JonesD6@BP:com>, "PauLG. Hyatt" <hyattpg@BP.cc~m>, "Steven R. Rossherg"` <RossbeRS@BP.cam>, Lois Alois@nletkeeper.org>, Dan Bross <kuacne«~s@kuac.org>, Gordan Pospisil <PospisG@BP.cam>, "Francis S. Sarnmer" <SommerFS~BP.com=>. Mikel Sehuitz <Mikel.Schultz@BP.cam>, "Nick W.<Glaver" <GloverNW@BP.com=~, "Daryl J. Kleppie" <KleppiDE@BP.corn>, "Janet D. Platt" <PlattJD@BP.~,om>, "Rosanne M..Tacobsen" <JacobsRM@BP.corn>, ddonkel <ddonkel@fl.rr.cam>,"Collins Mount <collies_mount@revenue.state.ak.us>, mckay <mckay@gci.net>, )=3arbara F Fullmer <barbara.f.fullmer@canocaphillips.cam>, bocastwf <bocastwf@bp.com-~, Charles Barker- . <barker@usgs.gov>, doug_sirhuitzc <da@~schultze@xta~nergy.com>, Hank Alford <hankalford@xxonmabil.corn=>, Mark Ka~ac @esnal@gci.net>~ gspfoff <gspfoff@aurorapower.com>, Gregg,Nady <gregg.nady@sheilc~~m>, Fred Steece <fred.steece@state.sd.us>, rerotty <rcratty@ch2m.com>, jejones . jejorres~aaurorapowzr'cam>, dapa <dapa@aIaska.net>; jroderick ~jroderick@gci.net>, eyancy <eyancy(ciseal-tite.net=>, "James M. Ruud" <jatnes.m.ruud@~onacophillips.com>, Brit Lively <mapala.~ka(cLak.net= , jah <jah@dnr.state.ak.us>, Ktrrt E Qlsan <kurt alson@egis.state.ak.us= , buonojc ~'buonojt;@bp.com>, Nlark Hanley <rnark hanley@anadarka.com>, bren lemon <loren lemantcl~ov.state.ak.us>, Julie Houle <julie haul@dnr.state.ak.us>,`Jahn W Katz <jwkatz@ssa.org>, Suzan J Hill <suzan hill@dec.state.ak.us=~, tablerk <tablerk@ueocal.eam>, Brady <brady@aoga.org>, Brian Havelock <~h@dnr.state.ak.us>, bpopp <bpopp@orough.kenai.ak.us>. Jim White <jirnw~ite(a;~satx.rr.com~, "John S.' Haworth" <jai.s.ha«~orth~uexxonmobiLcom=~, many <rnarty@kindustrial.com>, ~hammans <« arnons(uaoLcom=~, rmclean <rmclean(~cpobox.alaska.net =, mkm7?00 ~'mkm7200(%aol.com>, Brian Gillespie <ifbmg@uaa~.ala.5ka.edu>, Day. id L Bo~lens <dboelen.~ _@aurorapotiver.com=>, Todd Durkee <TDURKEE@KMG.com>, Gary Schultz <gary schultz%~i;dnr.state.ak.us>, W`a~ne Rancier <RANCIER@petro-canada.ca= , BiII Miller <Bill_1Vliller~uxtoalaska.com ~. Brandon Ga~nan <bgagnon@brenalaw.com>, Paul ~~'inslaw <pmwinslow ciforestoiLcom>, Garry Catron <catrongr@bp.cam>, Shanrraine Copeland <copelas@~bp.com>, Suzanne Allexan <salleXan a;;helmener~-.com=, Kristin'Dirks<kristin_dirks@;dnr.state.ak.us>. Kay~nell Zeman <kjzeman«i;marathonoil.com>, John Tower <John.Tol~-er@eia.doe.gov>, Bill Fowler <Bill_Fo«~ler@anadarko.C01~1=~, Vaughn S~~~artz =va~glrn.s~G~artz cnc~cm.com>, Scott Crans~vick 1 of 2 9/29/2004 1:10 PM Public Notices • <scott.cranswick@mms.gov>, Brad McKim <mckimbs cx SP.com> ', I Please find the attached Notice and Attachment for the proposed amendment of underground injection orders and the Public Notice Happy Valley #10. Jody Colombie ' Content-Type: appiication;'msword Mechanical Integrity proposa.doe Content-Encoding: base64 1 Content-Type: appiication/msword MechanicalIntegrity of Weiss Notice.doc Content-Encoding: base64 Content-Type: application/rns~vord HappyV alleyl0_HearingNotice.doc Content-Encoding: base64 2 of 2 9; 29,%2004 1:10 PM I Public Notice • Subject: Public Notice From: Jody Colombie <jody colombie@admin.state:ak.us> Date: Wed, 29 Sep 2.004 12:55:26 -0800 To: legal @alaskaj ournaI. com 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 1 of 1 9/29/2004 1:10 PM Citgo Petroleum Corporation Mary Jones David McCaleb PO Box 3758 XTO Energy, Inc. IHS Energy Group Tulsa, OK 74136 Cartography GEPS 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 Ft. Worth, TX 76102-6298 Houston, TX 77056 Kelly Valadez Robert Gravely George Vaught, Jr. Tesoro Refining and Marketing Co. 7681 South Kit Carson Drive PO Box 13557 Supply & Distribution Littleton, CO 80122 Denver, CO 80201-3557 300 Concord Plaza Drive San Antonio, TX 78216 Jerry Hodgden Richard Neahring John Levorsen I~'~, Hodgden Oil Company NRG Associates 200 North 3rd Street, #1202 ~ 408 18th Street President Boise, ID 83702 Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 Kay Munger Samuel Van Vactor Michael Parks Munger Oil Information Service, Inc Economic Insight Inc. Marple's Business Newsletter PO Box 45738 3004 SW First Ave. 117 West Mercer St, Ste 200 Los Angeles, CA 90045-0738 Portland, OR 97201 Seattle, WA 98119-3960 Mark Wedman 5chlumberger David Cusato Halliburton Drilling and Measurements 200 West 34th PMB 411 6900 Arctic Blvd. 2525 Gambell Street #400 Anchorage, AK 99503 Anchorage, AK 99502 Anchorage, AK 99503 Baker Oil Tools Ciri Jill Schneider 4730 Business Park Blvd., #44 Land Department US Geological Survey Anchorage, AK 99503 PO Box 93330 4200 University Dr. Anchorage, AK 99503 Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 Williams Thomas North Slope Borough Arctic Slope Regional Corporation PO Box 69 Land Department Barrow, AK 99723 PO Box 129 Barrow, AK 99723 [Fwd: Re: Consistent Wording for Injection ~rs -Well Integrity ... Subject: [Fwd: Re: Consistent Wording for Injection Orders - From: John Norman <john_norman@admin.state.ak.us> Date: Fri, 0'1 Oct 2004 11:09:26 -0800 To: Jody) Colambe <jody colombe@admin.state.ak:us> more Well Integrity (Revised)}- ------- Original Message -------- Su6ject:Re: Consistent Wording for Injection Orders -Well Integrity (Revised) Date:Wed, 25 Aug 2004 16:49:40 -0800 From:Rob Mintz <robert mintz(u~law.state.ak.us> To:jim regg(c~admin.state.ak.us CC:dan seamount cnr,admin.state.ak.us, john norman(c~,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 ean only require the well to be shut in by going through an enforcement action, issuing an order after notice and opportunity for hearing, or meeting the strict requirements for an emergency order under the regulations. The proposed language makes clear that it is a condition of the authorization to inject, that the operator must shut in the well if directed by the Commission after a notification of loss of integrity, etc. »> James Regg <jim regg(tiadmin.state.ak.us> 8/25/2004 3:15:06 PM »> Rob -Thanks for the review; here's a redraft after considering your comments. I have accepted most of the suggested edits; also attached is response to questions you pose (responses are embedded in the comments, using brackets [JBR - ...] to set apart from your questions). Jim Regg Rob Mintz wrote: Jim, I have some questions about the draft language, which are shown as comments on the first document attached. Based on my current guesses about what the answers will be to my questions, I also have some suggested edits, which are shown as redlines on the second document attached. »> James Regg <jim regg(cadmin.state.ak.us> 8/17/2004 4:33:52 PM »> Please delete previous version (email sent 8/9/04); I found another inconsistency in the injection orders regarding well integrity that I have integrated into the proposed fix. Attached is a proposal for consistent language in our injection orders addressing 3 rules related to well integrity: - "Demonstration of Tubing/Casing Annulus Mechanical Integrity" - "Well Integrity Failure" - "Administrative Actions". This proposal includes input from all Sr. staff (except Jack). If you agree with the approach, I'll work with Jody to prepare the public notice. Main points - Demonstration of Tubing/Casing Annulus Mechanical Integrity - standardizes the wording used for mechanical integrity demonstrations, and establishes abililty to grant alternate methods (e.g., temp survey, logging, pressure monitoring in lieu of pressure testing 1 of 2 10/2/2004 4:07 PM [Fwd: Re: Consistent Wording for Injection ~rs -Well Integrity ... - specific to AIO 2C for Kuparuk, there is wording that is more appropriately included in Well Integrity Failure (i.e:, more frequent MITs when communication demonstrated) - establishes more frequent MIT schedule for slurry injection wells (every 2 yrs) which is consistent with our current practice (but not addressed in regulations) Well Integrity Failure - retitles to "Well Integrity Failure and Confinement"; inserted language regarding injection zone integrity (see DIO 25 and 26) - consistent language regardless of type of injection (disposal, EOR, storage); - eliminates requirement for immediate shut in and secure; allows continued injection until Commission requires shut in if there is no threat to freshwater; - eliminates delay in notifying Commission after detect leakage or communication ("i.e., "immediately notify"); - removes language about notifying "other state and federal" agencies; - requires submittal of corrective action plan via 10-403; - requires monthly report of daily injection rate and pressures (tubing and all casing annuli); this is a requirement we currently impose when notified of leak or pressure communication; - notice and action not restricted to leaks above casing shoe as stated in several DIOs Administrative Actions - adopts "Administrative Actions" title (earlier rules used "Administrative Relief'); - consistent language regardless of type of injection (disposal, EOR, storage); - uses "administratively waive or amend" in lieu of terms like "revise", "reissue", etc.; - adds geoscience to "sound engineering principles"; - language is more generic regarding fluid movement out of zone; existing versions mention varying combinations of protecting "freshwater", "aquifers", "USDWs"; "risk of fluid movement"; "fluid escape from disposal zone" Jim Regg John K. Norman <John Norman(ctadmin.state.us> Commissioner Alaska Oil & Gas Conservation Commission 2 of 2 10/2/2004 4:07 PM [Fwd: Re: Consistent Wording for Injection ~rs -Well Integrity ... r~ Subject: [Fwd: Re: Consistent Wording for Injection Orders -Well Integrity (Revised}) From: John. Norman <john norrnan@adminatate.ak.us> Date: Fri, Ol Oct 2004 11:08:55 -0800 To: Jody J Calombe <jody_colombie ~;admin.state.ak.us> please print all and put in file for me to review just prior to hearing on these amendments. thanx ------- Original Message -------- Subject:Re: Consistent Wording for Injection Orders -Well Integrity (Revised) Date:Thu, 19 Aug 2004 15:46:31 -0800 From:Rob Mintz <robert mintz~law.state.ak.us> To:dan seamount(a,admin.state.ak.us, dim regg(a~admin.state.ak.us, john norman(a~admin.state.ak.us Jim, I have some questions about the draft language, which are shown as comments on the first document attached. Based on my current guesses about what the answers will be to my questions, I also have some suggested edits, which are shown as redlines on the second document attached. »> James Regg <jim regg~~admin.state.ak.us> 8/17/2004 4:33:52 Pi/I »> 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 iviechanical 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 frequent MITs when communication demonstrated) - establishes more frequent MIT schedule for slurry injection wells (every 2 yrs) which is consistent with our current practice (but not addressed in regulations) Well Integrity Failure - retitles to "Well Integrity Failure and Confinement"; inserted language regarding injection zone integrity (see DIO 25 and 26) - consistent language regardless of type of injection (disposal, EOR, storage); - eliminates requirement for immediate shut in and secure; allows continued injection until Commission requires shut in if there is no threat to freshwater; - eliminates delay in notifying Commission after detect leakage or communication ("i.e., "immediately notify"); - removes language about notifying "other state and federal" agencies; - requires submittal of corrective action plan via 10-403; - requires monthly report of daily injection rate and pressures (tubing and all casing annuli); this is a requirement we currently impose when notified of leak or pressure communication; - notice and action not restricted to leaks above casing shoe as stated in several DIOs Administrative Actions 1 of 2 10/2!2004 4:07 PM [Fwd: Re: Consistent Wording for Injection ~rs -Well Integrity ... , - adopts "Administrative Actions" title (earlier rules used "Administrative Relief'); - consistent language regardless of type of injection (disposal, EOR, storage); - uses "administratively waive or amend" in lieu of terms like "revise", "reissue", etc.; - adds geoscience to "sound engineering principles"; - language is more generic regarding fluid movement out of zone; existing versions mention varying combinations of protecting "freshwater", "aquifers", "USDWs"; "risk of fluid movement"; "fluid escape from disposal zone" Jim Regg John K. Norman <John Norman(a~admin.state.us> Commissioner Alaska Oil & Gas Conservation Commission __ ... Content-Type: application/msword ;Injection Order language - questions.doc Content-Encoding: base64 _ .._ Content-Type: application/msword Injection Orders language edits.doc Content-Encoding: base64 2 of 2 10/2/2004 4:07 PM r • i Standardized Language for Injection Orders Date: August 17, 2004 Author: Jim Regg Demonstration of Tubin /Casing Annulus Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, after a workover affecting mechanical integrity, and at least once every 4 years while actively injecting. For slurry injection wells, the tubing/casing annulus must be tested for mechanical integrity every 2 years. The MIT surface pressure must be 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, must show stabilizing pressure and may not change more than 10% during a 30 minute period. Any alternate means of demonstrating mechanical integrity must be approved by the Commission. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Well Inte rity Failure and Confinement The tubing, casing and packer of an injection well must demonstrate integrity during operation. The operator must immediately notify the Commission and submit a plan of corrective action on Form 10-403 for Commission approval whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, or log. If there is no threat to freshwater, injection may continue until the Commission requires the well to be shut in or secured. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating pressure communication or leakage. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. w • a Standardized Language for Injection Orders Date: August 17, 2004 Author: Jim Regg Demonstration of Tubin /Casing Annulus Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (eYCept at least once every two years in the case of a slurry i_n~ection ~vel.l}, and. before returning a ~~~ell to sen~ice. folio~vin~ ~ a workover affecting mechanical integrity ,•..,a ~•* ~ * r =~ ~~ ~~ ~, ~•+ - t ~•+~ ~ ~: CLLtU LLL /l.. •~VL T J'~V CEI ~) TS ti ~ b' ~ ~ ' Unless an alternate means is approved by the Commission mechanical inte,~;rity must be demonstrated by a tubing pressure test using a ~ ?v1:-I-surface pressure ofn~~ 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, that ~-shows stabilizing pressure that doesa-x not change more than 10°=$- erp cent during a 30 minute period. -4n-y .. - . The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Well Inte city Failure and Confinement Except as otherwise provided in this rule Tthe tubing, casing and packer of an injection well must d~ ~~~~rt~-maintain integrity during operation. ~~Thenever any pressure communication, leakage or lack of infection zone isolation is indicated by infection rate. operation pressure obset-~~ation test survey, loa or other evidence, tThe operator its-shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval. ~~ ,,,,~~,+; .~+° ,.~~ >,,. ,~, „+;, +1,.~ . ,._ The o 'Y° ~ r1V° ~, Aerator shall shut in the well i.f so directed by the Commission. The operator shall shut in the well without aEVaitin~ a response from the Commission if continued operation would be unsafe or would threaten contamination of freshwater >.. ~"~*?~ Y,~~ .,L. Le:~uLL.,t, tl r~ + ~ ° ~• + _ •-'. Until,corrective action is successfully completed. Aa monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating pressure communication or leakage. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. [Fwd: Re: [Fwd: AOGCC Proposed WI Lan for Injectors]] • Subiect: [Fwd: Re: [FWd: AQGCC Proposed WI Language for Injectors]] From: Winton Aubert <winton aubert~a admin.state.ak:us> Date: Thu; 28 Oct 2004 09:48:53 -0800- To: lady J Cola~nhie <jady_colornbie@admin.state.ak:us> ; This is part of the record for the Nov. 4 hearing. WGA -------- Original Message -------- Subject: Re: [Fwd: AOGCC Proposed WI Language for Injectors] Date: Thu, 28 Oct 2004 09:41:55 -0800 From: James Regg <jim regg@admin.state.ak.us> Organization: State of Alaska To: Winton 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 -------- Subject: AOGCC Proposed WI Language for Injectors i Date: Tue, 19 Oct 2004 13:49:33 -0800 From: Engel, Harry R <Enge1HR@BP.com> To: winton aubert@admin.state.ak.us Winton... Here are the comments we discussed. Harry *From: * NSU, ADW Well Integrity Engineer *Sent: * Friday, October 15, 2004 10:43 PM *To: * Rossberg, R Steven; Engel, Harry R; Cismoski, Doug A; NSU, ADW Well Operations Supervisor *Cc: * Mielke, Robert L.; Reeves, Donald F; Dube, Anna T; NSU, ADW Well Integrity Engineer *Subject: * AOGCC Proposed WI Language for Injectors Hi Guys. John McMullen sent this to us, it's an order proposed by the AOGCC to replace the well integrity related language in the current Area Injection Orders. Listed below are comments, not sure who is coordinating getting these in front of Winton/Jim. Overall, looks okay from an Operations perspective. We do have a few comments, but could live with the current proposed language. Note the proposed public hearing date is November 4. The following language does not reflect what the slope AOGCC inspectors are currently requiring us to do: "The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (except at least once every two years in the case of a slurry injection well), and_* before*_** 1 of 3 10/28/2004 11:09 AM [Fwd: Re: [Fwd: AOGCC Proposed ~VI Lane for Injectors]] • return'.ng a well to service following a workover affecting mechanical integrity." After a workover, the slope AOGCC inspectors want the well warmed up and on stable injection, then we conduct the AOGCC witnessed MITIA. This language requires the AOGCC witnessed MITIA before starting injection, which we are doing on the rig after the tubing is run. Just trying to keep language consistent with the field practice. If "after" was substituted for "before", it would reflect current AOGCC practices. It would be helpful if the following language required reporting by the "next working day" rather than "immediately", due to weekends, holidays, etc. We like to confer with the APE and get a plan finalized, this may prevent us from doing all the investigating we like to do before talking with the AOGCC. "Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall_* immediately*_** notify the Commission" This section could use some help/wordsmithing: "A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation." Report content requirements are clear, but it's a little unclear what triggers a well to be included on this monthly report. Is it wells that have been reported to the AOGCC, are currently on-line and are going through the Administrative Action process? A proposed re-write would be: "All active injection wells with well integrity failure or lack of injection zone isolation shall have the following information reported monthly to the Commission: daily tubing and casing annuli pressures, daily injection rates." Requirements for the period between when a well failure is reported and when an administrative action is approved are unclear. This document states "the operator shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403". If we don't plan to do any corrective action, but to pursue an AA, does a 10-403 need to be submitted? The AOGCC has stated they don't consider an AA as "corrective action". Let me know if you have any questions. Joe -----Original Message----- From: Kleppin, Daryl J Sent: Wednesday, September 29, 2004 1:37 PM To: Townsend, Monte A; Digert, Scott A; Denis, John R (ANC); Miller, Mike E; McMullen, John C Subject: FW: Public Notices FYI -----Original Message----- From: Jody Colombie [ mailto:jody 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 of 3 10/28/2004 11:09 AM ~5 w ~. ST:~T,=. Or ALASi~~ AL.~S:~A OIL AND GAS CONSERVATION COi~?~ISSIO~+ 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re: REQUEST BY UNOCAL COMPANY j Disposal Injection Order No. 2 to dispose of non- hazardous oil field wastes) Kenai Unit by underground injection ) Kenai Gas Field in well KU 14-4, Kenai Gasj Field February 18, 1987 IT APPEARING THAT: 1. Unocal Company (Unocal) requested on January 20, 1987 the Alaska Oil and Gas Conservation Commission to authorize the use of well KU I4-4 as a disposal well in the Kenai Unit, Kenai Gas Field. Unocal will inject non-hazardous waste fluids generated by normal drilling and production operations. 2. Notice of an opportunity for a public hearing on March 11, 1987 w3 s0 p1987shed in the Anchorage Daily News on January , 3, No protest or request for a public hearing was timely filed. Accordingly, the Commission will, in its discretion, issue an order without a public hearing. FINDINGS: 1, All aquifers below 1300 feet within the Kenai Gas Field Boundary, and one-quarter (4) mile beyond, are exempted under 40 CFR 147.102(b)(1)(C) for Class II injection activities. 2. Permeable stWa2900tfeetwin1we11eKU 14~~cted fluids, are present belo 3. A series of confining strata are present above 2900 feet in well KU 14-4 that will prevent upward movement of the injected waste fluids into non-exempt aquifers. 4. The strata into which fluids are to be injected will accept fluids at injection pressures ectionastratasand than the fracture pressure or the inj their confining formations. r ~ D isoosal I::j ect Orde_ No . ;ebruary _8, 1987 image ~ 5. To ensure that waste fluids are confined to injection strata, the mechanical integrity of KU 14-4 will be demonstrated periodically and monitored routinely for disclosure of possible abnormalities in operating conditions. 6. KU 14-4 is constructed in conformance with the requirements of 20 AAC 25.412. CONCLUSIONS: The geologic sequence present at the well site and maintenance of the mechanical integrity of KU 14-4 will prevent movement of injected fluids into non-exempt aquifers. NOW, THEREFORE, IT IS ORDERED THAT: Non-hazardous oil field waste fluids may be injected in conformance with Alaska Administrative Code Title 20, Chap~tion5below the measuredodepthpofa2900tfeeteintwellnKU form I4-4. DONE at Anchorage, Alaska, and dated February 18, 1987. ~` ~ i L -~ 5~ '~o ~ ~ ~- ~ o ~!~ T~aN C~r~~, C. V. C attertonl, C~ai~man Alaska Oil and Gas Conservation Commission ~' ~ l j j ..~` / Lonnie C. Smith, Commissioner Alaska Oil and Gas Conservation Commission ~. W. W. 3arnwell, Commissioner Alaska Oil and Gas Conservation Commission ~ 4 • Unocal Energy Resou~ivision Unocal Corporation 909 West 9th Avenue, P.O. Box 196247 Anchorage, Alaska 99519-6247 Telephone (907) 276-7600 Health, Environmental, Safety Alaska Business Unit Mr. Bob Crandall Alaska Oil & Gas Conservation Comm. 3001 Porcupine Lane Anchorage, AK 99501 sate for i4U 'i4-4 Disposai Project Dear Bob: As you requested, I have enclosed information regarding the Class II disposal well at KU 14-4, at the Kenai Gas Field. One plot shows volumes of slurry and solids injected over time and the second.... plot shows injection rate and surface pressure over time. These plots include data through September, 1993. If you have any questions please call the project engineer, Chuck Partridge, at 263-7670 or myself at 263-7615. Very truly yours, '~_ ~` . /`~ Rr~!~e St. Pierre Environmental Scientist BWS:ccm Attachments cc: Chuck Partridge John Beitia/BWS Reading KU 14-4 File RECEIVE NOV _ 9 1994 ztiaska Uil & Gas Cons. Commission Anchors ~ou~u~` ~~s~ ~uo~ s~ J'8 !?~'~ ~o~ss~ua~o~ ~66t ~ ~ ~pN ~n~~~~,~ O CJl O n C ~ ~ O O ~ ~~ ~~ ~~ -~~ -~ ~~ o -~ ~~ a a pp Cum. Barrels Slurry Injected (Thousands} ~ -- N N W W -P -~ CTt ~ n pn ~ O O O O O -~- N w +~ O O O O (Millions} Curn. Pounds Solid injected O O C 1 Y ~• 0 T~+ V 0 ~• rf 0 ~F ~~ KU 14-4 INJ 2-33 All Recorded Shut-in Data (1170 Pts) 50 45 40 .-. ~ 35 m _' 30 ~' 25 0 m 20 a~ ~ 15 1 ~~ ~.. ~~ 0 ~t,~~~~~nh k ~~ - ~ , ,. , ~~ ~ m 0 ~- N 0 0 ~, ~, ,~ ~ ~ 50 100 150 Cum. Time, rnin (Thousands) ZUU 2500 ?000 • .-. a. 1500 ~ a a 1000 ~ ', cn 500 --~-0 250 • • • • STATE OF ALASKA ALASKA OI.L AND GAS CONSERVATION COMMISSION• 3001 Porcupine Drive Anchorage, Alaska 99501=3192 Re: THE REQUEST OF UNOCAL ) COMPANY to dispose of ) non-hazardous oil field) wastes by undeY•ground ) injection in well ) KU WD-1, Kenai Gas ) Field ) Disposal Injection Order No. 1 Kenai Unit Kenai Gas Field February 18, 1987 IT APPEARING THAT: 1. Unocal Company (Unocal) requested on January 20, 1987 the Alaska Oil and Gas Conservation Commission to authorize the continued use of KU WD-1 as a disposal well in the Kenai Unit, Kenai Gas Field. Unocal will inject nori-hazardous waste fluids generated by normal drilling and production operations. 2. Notice of an opportunity for a public hearing on March 11, 1987 was published in the Anchorage Daily News on January 30,1987. 3. No protest: or request for a public hearing was timely filed. Accordingly, the Commission will, in its discretion, issue an order without a public hearing. FINDINGS: 1. Unocal, a;> operator of the Kenai Gas Field, currently is authorized by EPA permit AK-2DO217-E issued in conformance with the Safe Drinking Water Act as amended 42 USC 300f et s~eg to inject non-hazardous liquid wastes intro welt KU WD-1, Kenai Gas Field. • In'ection Orde~No. 1 Disposal ~ February 18, 1987 Page 2 • 2. All aquifers below 1300 feet within the Kenai Gas Field Boundary, and one-quarter (4) mile beyond, are exempted .under 40 CFR 147.102(b)(1)(C) for Class II injection activities. 3. Permeable strata, that will accept injected fluids, are present below 2700 feet in well KU WD-1. 4. A series of confining strata are present above 2700 feet in well KU WD-1 that will prevent upward movement of the injected waste fluids into non-exempt aquifers. 5. 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. 6. To ensure that waste fluids are confined to injection strata, the mechanical integrity of KU WD-1 will be demonstrated periodically and monitored routinely for disclosure of possible abnormalities in operating conditions. 7. KU WD-1 is constructed and and has been tested in conformance with the requirements of 20 AAC 25.412. CONCLUSIONS: The geologic sequence present at the well site and maintenance of the mechanical integrity of well KU WD-1 will prevent movement of injected waste fluids into non-exempt aquifers. NOW, THEREFORE, IT IS ORDERED THAT: Non-hazardous oil field waste fluids may be injected in conformance with Alaska Administrative Code Title 20, Chapter 25, for the purpose of disposal into the Sterling formation below the measured depth of 2700 feet in well KU WD-1. • Ai~sposal Injectio..~der No. 1 ~~ February 18, 1987 Page 3 • DONE at Anchorage, Alaska and dated February 18, 1987. ~~A ott ~~ y ~ ~ O ,~ ~:f;~,b ! a O N ^ -- -• ~~ L 5... ,~ . [ ``~ ~roN ~o~ ~~ U l Lonnie C. Smith, ommissioner Alaska Oil and Gas Conservation Commission ~~• {~/. W. W. Barnwe Commissioner Alaska Oil and Gas Conservation Commission • Alaska Oil and Gas Conservation Commission ~3 .~~ ~. ~ • Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: The application of UNION OIL COMPANY OF CALIFORNIA (Unocal) for an order authorizing the underground disposal by in- jection of non-hazardous oil field waste fluids at the Kenai Gas Field. The Alaska Oil and Gas Conservation Commission has been requested by letter from Unocal dated January 20, 1987 to issue an order in conformance with 20 AAC 25.252. The order would authorize the disposal of non-hazardous liquid waste by injection into well KU-W.D. No. 1 and well KU-14A. These wells would be used for disposal of non-hazardous oil field waste fluids by injection into the Sterling Formation at the Kenai Gas Field, Kenai Peninsula, Alaska. A person who may be harmed if the requested order is issued, may file a written protest, prior to February 16, 1987, with the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501 and request a hearing on this matter. If the rotest is filed timel and raises a substantial and material issue crucia to t o ommission s etermination, a earin on t o matter wi e e at t e a ove a ress at on Marc , in con ormance wit C 5. I ~a Baring is to e e intereste parties may con irm this by calling the Com- mission's office, (907) 279-1433, after February 16, 1987. If no such rotest is timel filed, the Commission will considers-tTe issuance o t e or er wit out a Baring. w w ~-~- W. W. Barnwell Commissioner Alaska Oil & Gas Conservation Commission Published January 30, 1987 �F Unocal Oil & Gas Divi~ Unocal Corporation P.O. Box 190247 Anchorage, Alaska 99519-0247 Telephone (907) 276-7600 CAL. 76 G. A. Graham District Operations Manager Alaska District ~~t ~. t ~~ ~ ~ 1g~1 ,~`~~5~00 S ~~~,~ 0~~ P~~ A~as~~ Dear ~~ir. Chatterton: January 2U, 1987 hfr. C. V. Chatterton, Chairman Alaska Oil and Gas l.onservation Comm. 3001 Porcupine Drive Anchorage, Ak. 99501 INJECTION APPLICATION KENAI GAS FIELD, KENAI PENINSULA, ALASKA Attached is the Kerlai Gas Field Injection Application. Union Oil Company of t;aliforrlia, DBA UNOCAL, as operator of the Kenai Gas Field, requests that an injection order be issued to authorize the continued use of WD #1 as a disposal well ar~d to utilize KU 14-4 as a new disposal well, to inject clan-hazardous waste fluids generated during normal drilling, workover, and production operations. This application is submitted in accordance with the regulations set forth in 20 AAC 25.252. _ The Sterling formation is currently taking fluids injected into WD 4~1 through perfi'orations frcm 3030'-3160', 3178'-3193', and 3235'-3250'. Injection into KU 14-4 will be accomplished in two pi~ases. In Phase I, it is proposed to inject into the existing perforations open in the Sterling B-1 and B-2 gas sands from 4194'-4250'. The B-1 and B-2 sands watered out in late. 1980. Phase II would be initiated after injection in Phase I is no longer possible. Iri Phase II, it is proposed to abandon tree perforation from Phase I and inject into the Sterling formation through perforations from 3156'-318U', 3198'-3244', 3296'-3318', 3333'-3354', acid 3370'-3437'. Attachment 5 contains the casing diagram for WD ~~l ar~d for KU 14-4, Phase I and II. C.V. ~hatterton A1asl:a Oii & Gas Conservation Commission Dispasai activities within the Kenai Gas Field are Oil and Gas Conservation Commission Regulations ar Environmental Conservation Regulations and will compliance -vith said regulations any orders. Very truly y C- ~~c ~~ . G. A. Graham District Ope in compliance with Alaska i the Alaska Department of continue to operate in ~s, <«.~~-- P.1anager ~~ '' • ~~ gids~a ~/,~~ ~ r'' f'~,,~ ~,, ~ ~ '~ Gyp. '~u~(S''J J `'mss ~w, LETTER GF APPLICATION FOR AN INJECTION CRDER KE:NAI GAS Fl"ELD, KENAI PENINSULA, ALASKA UNION UIL C;Ur~iPANY OF CALiFURNIA A SUBSIDIARY OF UNOCAL i KENAI GAS FIELD 1trJECTION APPLICATION KEtJAI PENINSULA, ALASKA 20 AAC 25.252 (c)(1) i Attachment No. 1 shows the location of all wells in the Kenai Gas Field, including well No. 6vD ~~1, the. existing disposal well and KU 14-4, the proposed disposal well. For this application, Unocal will use an area extending 1/4 mile (1320') radially from the bottemhole location of VJD iii, whose center paint is located 600' N and 2297' W of the SE corner, Section 31, TSN, R1iW, St~i and an area 1/4 mile (1320' ) radially from the bottom hole location of KU 14-4, whose center point is located 1i77.03'N and 4489.35'W of the SE corner, Section 4, T4td, R11W, S~9. 2U AAC 25.252 (c)(~) Unien Oil Cornpar~y of California, a subsidiary of Unocal Corporation, Marathon Gii Company, a subsidiary of USX Corporation, and Chevron USA are co-owners in the Kerrai Gas Field, with Unocal operating tF~e field. Attachment No. 2 lists all operators avid surface owners within one-quarter mile radius of each proposed disposal well. ~0 AAC 25.252 (c)(~) Attachment No. 3 is an affidavit showing tf-rat the operators and surface owners within one-quarter mile radius of each proposed disposal well have been provi~ed with a copy of this application. 20 AAC 25.252 (c)(4) Attachment No. 4 contains tt~e geological information for tt~e Kenai Gas Field, Kenai Peninsula, Alaska. 20 AAC 25.252(c)(5) Logs far ir7dividual wells arE on file with the Alaska Oil and Gas Conservation Commission. Attachment No. 4 includes dull inouction logs for ~VD #1 and KU 14-4. 2U AAC 25.252(c)(6) Attachment tJo. 5 is the casing diagram for well WD ~~1 and the proposed aisposal well KU 14-4, Phase I and II, in the Kenai Gas Fielci. i 20 AAC 25.252(c)(7) ~ i8) Attachment Nu. 6 is a water analysis of fluid injected into WD ~~l during April, 1y86. Unocal is currently permitted under ADEC permit ~~8423-DB015 for the in,~ection into WD ~~1 of a maximum of 5,000 barrels/day and 150,000 barrels/yea of non-hazardous waste fluids associated with the drilling, production anu workover operations of oil and natural gas wells. The injection of any f-razardous waste, as defined under 40 L'FR 261, is prohibited. Sased on tl~e geological rata presented, and the step-rate test dated December i8, 1936, Unocal requests a maximum surface injection pressure of 1500 psig fcr Weil NU ~r'-i. V~D ~~l will likely operate with an average surface injection pressure betweer~ 800-900 psig, but highrr pressures will be needed to dispose of fluids prior to periodic wEll bore cieanout operations. M;U i4-4 will operate with arr average surface injection pressure between 500 to i2UG psig. The maximum disposal pressure will be adjusted based on step-rate tests tc be performed after the well is put in service. 20 AAC 25.252(c)~9) The infection pressure for fluid disposal will be maintained at a pressure which will prevent infection or formation water from enterir7g freshwater strata. A step rate test was performed on tiJD ~~1 Cecember 18, 1986. Attachment No. 7 is a summary of that test showing that a fracture was induced irr t~~e formation at an estimated surface pressure of 1090 psig. Estimated fracture gradients within the KU 14-4 area vary from 0.67 to 0.78 psi/ft at the f3-1 sand depth. The maxium operating surface pressure will be determined by a step-rate fast conducted after the well is placed on injection. 20 AAC 25.252(c)(10) Attact~nient No. 4 contains information as to formation water and salinity for wells WD ~~1 and KU 14-4. 20 AAC v .252 (c) (11 In,,ection in 6•~D ~~l and KU 14-4 will occur below 3000'. All aquifers below 1300' witi-~in the Kenai Gas Field Boundary, and 1/4 mile beyond, are exempted for Class iI activity. (P,efer to Attachment No. 4 for geologic confining zones above 3000' and below 1300'.) Attachment No. 8 is a copy of 40 CFR 147.102 (b)(1)(C) referencing the Federal Exemption. ~ • 20 hAC 25.252(d) The t:enai Gas Field operator will monitor- all disposal wells in accordance with the regulations of the Alaska Oil & Gas Conservation [.ommission. Trre monitoring program includes continued determination cf disposal rates wit~~ flow meters. Injection volumes along witty tubing any casing pressures are recorded uaily. Unocal, as Operator ~vill subrrrit reports as required under this section for the Kenai Gas Fief c0 AAC 25.~52(e) Urrccal request a waiver of both requirements under this section. Limitations ofi' the Disposal equipment will not allow pressures to exceed 70% of the min~rnum yield strength of the easing-tubing and ct~ranges of 200 ti psi between thus makin readings occur on a frequent oasis due to injection ces, prac g 1`portrrrg impractical anu a turden Lo ooth parties. As noted in section 20 AAC ~5.4U2(c)~li) aquifers below 1300' within the Kenai Gas Field are exempt. ~'0 AAC 25 . X52 (t ~ ) The w~11s ~~~ithin the E<enai Gas Field are shown on Attachment Na. 1. To the nest of Urrocal's knowledge, all listed wells were constructed, acrd where applicable, af/andoned in compliance -vith the requirements of the Alaska Oil and Gas Conservation Commission t7eguiations. ~~~'~ ~~ ~~~~~ Kaska ou ~~`~, ~~G ~ CbS r, /)JT~/` i ,Attachment No. 2 20 AAC 25.402 (2) Listed ~elcw are tl~e operators and surface owners within one-quarter mile radius of each proposed disposal weii: Cook Inlet Region lnc. P . 0 . Drawer 4-fJ Anch~raye, Ak. 99509 Leonard ck Eveiyn Keener P.O. (3ox 2521 Kenai, Ak. 99611 Kenai Peninsula Borough BUX iSJO Soidotna, Ak. 99669 State of Alaska Department of FJaturai Resources P.U. Box 70:4 AncharayE, Ak. 99510-0734 Fir . Doyle Jones Marathon Oil Production Co. P.O. Box 102380 Anchorage, Ak. 995iU Tirnothy Bruce Keener 106 tiaillov~ Street Kenai, Ak. 99611 Fair. Joe Dygas Bureau of Land F4anagement 4700 E. 72nd Avenue Anchorage, Ak. 99507 h1r. hi.J. Vasilauskas l;hevron USA P.O. Box 5043 San Ramon, Ca. 94583-0943 R12W ~ 1 R IIW ~' Attachment No. 1 20 ~ ~ KDU-7 (KU 42-30) 3p 29 T rj ,,,,,,,~,_ ~ KU 33-30 N I S/TE 33 -30 - I ~ca° Aatp 31 KU SITE .34-3/ ' KU 1435 WD-I I4 KU 3435 ~-- -1- ~ - 1 ' ~ ~ 4KU 11-6 '~ K -' KU 21-6 1 Y 1 1 28 33 ~" ~ .. ( KU 13-6 K KBU 23X-66 KiU 43-6X U 43-6 5 4 1 Z S/TE 33-/ KU 43-6A _\\ _ j ~ ° KTU 13-5 \ 1 KU 33-I , ~ ~~ KU 24.5 S?E /4-4 ; Q.. KDU- ®KU14-4 , Z C W - KDU-8 /TE/4 _ i E ][ + ~ + KUI4-6, KU 21-7 KBU I ~'`'-` _ /~ 1 S/TE4/-y ~~KDU-2(21-8) - 1 ° KUII-8 KBU 31•? ® KDU-4 ° I KBU 13-8 9 ~ KU 43-12 KDU-4RD (13-7) KBU 33-7 8 KU43-~ T 4 N I KU 24-7 KUH-I(14X-B) > KU I I-17 SITE 4/'/B 4h18(KUH-I) _I3 I 18 IT KU 44-18 _ 1 i ..~. '{~ KU 41-19 S/TE 4/-/9 0~ 20FA FEET - R12W RIIW -}" 16 um~n KENAI GAS FIELD L • Attachment No. 2 c0 AAC ~5.40~ (1) Listen bela~+ are the operators and surface owners within one-quarter mile radius of each proposed disposal Weil: Cock Inlet Region Inc. P . U . Dra-~er 4-N Anchorage, Ak. 99509 Leonard & Evelyn Keener P.O. box 25~~ Kenai, A~:. u9611 1<enai Peninsula Borough Box 850 Soidc;tna, Ak. 99669 State oi' Alaska Department ofi~fvatural kesources P .0 . tsox 7034 Anchorage, Ak. 995iU-0734 Mr . Doyle: Uones Marathon Oil Production Co. P.O. Box 102380 Anchorage, Ak. 59510 Timothy brace Keer~e:r i06 k+illoty Street Kenai, Ak. 99G1i h1r . :,'ce Uygas Bureau of Land htanagernent 4-700 E. 72nd Avenue Anctrerage, Ak. 99507 hir. J.J. Vasilauslcas Chevron USA P.C. Box 5043 San Ramon, Ga. 94583-0943 n • Attachment No. 3 STATE OF ALASKA ) )ss Third Judicial District ) AFFIDAVIT Candace Lockwood, being first duly sworn on oath, deposes and says: That I am an employee of Union Oil Company of California Unocal). "that on tP~e ,~~:~'~~ ` ~ day of January, 1987, I caused to be mailed a true and correct copy of this application to the following operators and surface owners: Cook Inlet Region Inc. P.O. Drawer 4-N Anchorage, Ak. 99509 Leonard & Evelyn Keener P.O. Box 2521 Kenai, Ak. 99611 Kenai Peninsula Borough Box 850 Soldotna, Ak. 99669 State of Alaska Department of Natural Resources P.O. Box 7034 Anchorage, Ak. 99510-0734 her . Doyle Jones Marathon Oil Production Co. P.O. Box 102380 Anchorage, Ak. 99510 Timothy Bruce Keener 106 Willow Street Kenai, Ak. 99611 h9r. Joe Dygas Burea,~ of Land Management 4700 E. 72nd Avenue Anchorage, Ak. 99507 Mr. Yd.J. Vasilauskas Chevron USA P.O. Box 5043 San Ramon, Ca. 94583-0943 by placing said copy in the United States t~iail with postage prepaid and certified at Anchorage, Alaska. t;anoace Lockwood SUBSCRIBED AND SYJORN to before me this <:1;~r.c day of January, 1987. i;' '~ Notar~r Public in and for Alaska.., My commission Expires: ~ i4{~ ~~ • ~ Attachment No. 4 GEOLOGIC SU~1MARY AND SHALL0~~1 FORh1ATI0N WATER SALIPJITY STUCY KENAI UNIT WD ~~1, SECTION 31, TSN, R116~1, S~•1 KENAI GAS FIELD, ALASKA A shallow formation water salinity study was conducted in Union's, KU '~vD ~~1 well, located in the Kenai Gas Field, Alaska. The purpose of this study was to determine the formation water salinities in the relatively shallow sand interval which underlies the Pleistocene glacial deposits and overlies the Pliocene Lower Sterling Formation gas reservoirs. In addition, a subsurface evaluation was conducted to determine the stratigraphic relationship of the freshwater aquifers and the disposal well sands in the Kenai Gas Field. Results and Conclusions: The sandy interval in KU WD ~~1, between 460' to 3273' (TVD) contains calculated equivalent salinities ranging from 1100 to 2600 ppm PJaCl. (Plate 1.) It is believed these calculated salinities represent a minimum ba__reline in equivalent ppm NaCl. In addition, the cement bond log (CBL) indicates ooed cement between the seven-inch (7") liner and the formation, indicating that "channeling of injected fluids behind pipe" into other intervals is not occurring. Annual temperature logs in KU ~~JD ~~l show the fluids are being injected only into the perforated intervals in KU WO ,~1. Plates 2 and 3 (north-south and east-tivest geologic cross-sections) show the lateral continuity of the impermeable shale intervals. These shale intervals act as upper and lower confining impermeable units in the sand-rich Sterling Formation. The shales vary in thickness from three to 40 feet. The data " available is therefore conclusive that the shales are areally widespread and prevent vertical fluid communication between sandstones.. Plate 4 shows the stratigraphic relationship of the fresh;pater aquifers and impermeable claystone intervals in the Pleistocene strata overlying the Sterling Formation. The freshwater aquifers are generally fluvial channel sands bounded by lacustrine claystdnes. A major unconformity lies at the base of the Pleistocene strata (Top Pliocene Sterling Formation). This unconformity also acts as a barrier between the freshwater zone and the more highly saline Sterling Formation sands. _ Procedures and Methods: Only a Dresser Atlas Dual Induction Focused Log and Acoustic Cement Bond Log were run in KU WD ~~1. The sediments below the base of the glacial depositsv (at 417' MD, Annotated Log, Plate 1) are in the upper and middle part of the Sterling Formation. These sediments are sands, siltstones, shales and occasional thin-bedded coals. The sands are highly unconsolidated and generally uncemented. Shaded intervals on the Type Log indicate impermeable shale zones. Waste water is currently being injected in these Sterling Formation sands at the base of the wellbore from 3030'-3160', 317x'-3193', and 3235'-3250'. =:a: ~;. • • Log analysis of the DIFL in KU tiVD ~~1 indicates the shallow focused resistivity reading is consistently higher than the deep induction curve.. This suggests the shallow focused curve is reading closer to the true Rxo value, the flushed zone resistivity of the formation. No hydrocarbons are present in this interval. Usino Schlumberger's Chart S~V-1 (Exhibit A), and assuming the average porosity of those sands to be 35% (based on detail log analysis of the Sterlino Formation Gas Reservoirs), Rw values in these sands were determined. Maximum bottom hole temperature in the well was 100°F. Using a 35°F mean surface temperature, the thermal gradient in this well was calculated to 1.96°F/100'. By platting both the Rw and formation temperature values on Schlumberger's Temperature and Resistivity Chart Gen. 9 (Exhibit B), an estimate of the formation waters' salinity was derived and is shown on the accompanying Type Log, KU WD ~~1. (Plate l.) Also included is a detailed well completion schematic for the Union, KU-'r10 ~~1 well (Exhibit C). Geologic Summary: The Sterling Formation of Pliocene Age is currently the disoosal interval for the injected fluids in KU-V~D ~~1 in the Kenai Gas Field. This formation is over 3500 feet thick in the area with the lower +1100 feet containing commercial gas producing reservoirs. The Sterling Formation is made up of a thick sequence of massive sandstones and conglomeratic sandstones with impermeable interbeds of mudstone, siltstones and thin coals. This seouence was deposited by moderately large, meandering streams which were part of the ,,. main drainage system of the Cook Inlet Basin. These moderately large stream courses deposited point bar sands and flood plain silts and muds. The paint bar sands are typically fining upward sequences of significant thickness and lateral continuity as are the interbeds of mudstone and siltstones. A low angle unconformity occurs at the base of the Pleistocene strata (Quaternary glacial deposits), thus separating these deposits from the top of the Pliocene Sterling Formation. The glacial deposits consist of poorly to moderately consolidated fluvial channel sands and gravels with interbeds of glacio-lacustine claystones. KDK/pg ', _ 766D '~ .. -•- - June 20, 1985 Attachments: Plate 1: Annotated Type Log, KU N10 ~~1 Plate 2: North-South Structural Cross Section, the Glacial and Sterling Formation Intervals Plate 3: East-West Structural Cross-Section, the Glacial and Sterling Formation Intervals Plate 4: North-South Structural Cross Section, Pleistocene Freshwater. Aquifers and Impermeable Claystone Intervals in the Pleistocene Strata Exhibit A: Schlumberger Chart Sti~l-1 Exhibit B: Schlumberger Chart Gen. 9 Exhibit C: Well Completion Schematic for KU-V!D ~~1 Well CONC R: R. Warthen District Development Geologist C a 1 C i • .'~•~. ..... ..~ .._..:~t.Z...v... ._. ~ .. _.. ... ~... Saturation Determination (Clean Formations) C - ~ ~ R° R, _ ' 2 m : S2: m II • m s . i . 30 t 0.000 .008 % Fq 8.000 6.000 8 .Ot 2.5 2000 20 4.000 7 • - - 3 3.000 • - t000 800 2.^00 8 .02 • 4 EGO t 0 1 000 5 400 . ECO 10 8 300 8 Epp •~ 7 200 6 4C0 12 .04 . 8 •- y 5 300 14 .os ~o e0° a 2C0 .O6 60 t 6 15 40 3 tC0 EO 18 .08 30 EO 20 .t 20 20 2 ap 25 30 25 30 10 6 20 2 35 40 5 5 t t0 30 4 g 8 E , ,a __ 0.62 Fq 4 Q2.t5 6 a0 .4 5 3 2 .5 A 50 .s 3 t . .8 -.. ,~ - 9 .fi EO 1.0 .. .. : 2 q . ~ 70 - - _ ~_ 80 - 2 • -• ~ .'2.0 ~ t - __ 1 _ 100 • • ~ - 08 ~: •. S a.o .~- . • Ro=EBBW "'- R ( - ~ ~ - • ~ -• ~ ~ ©SchlumCerger ~ ~ .. - ~ - This nomograph solves the`Archie watcr•saturation e ration ~ - Kt - FR . It should be used in'clean (nonshaly) formations only. 1C Ro (resistivity when 1,, .1°/o tvatcr saturated) is known, a straight Gne from the known Ru •. value through the measured R, value gives water saturation, S,,. If R„ is not knou-n, it may be determined by connecting •. .. • the fotTrtatio^ water resistivity, Rw, with the formation resistivity factor, FR, or porosity, d. E~;.1~1P LE: RW = O.OS ^•in ~: `~:m~:ioa c..:: ,.eratu:= ~ ... • ~ = 20°'0 (FR = 20) . '. ~ l0 i1•m ... .. Thus, 5,,, = 31.G°.'(, ~ . Sw-1 _ -.. 75 EXfiIBIT A • 'ie«: ..~~. ~-- C Resistivity Nomo~rapn for NaCI Solutions This nomo_raph may be used to estimate the resistivity of a water sample at a eiven temperature \\•hen the salin ity (NaCI concent ration) is known, or to estimate the salinity when resistivity and temperature are known. !t may al so be used to com •ert resistivit}~ From one temperature to another temperature. E.~111P LE: Resistivity of a water sample is 0.3 ~•m at 25°C; what is its resisti\•it}• at 8~'C? Draw a line connecting the 25'C point \vith the 0.3 ~•m R point. This indicares a sal init}• of 20,000 ppm. Pivotin_^_ about this salinit}• poin[ }Melds a water sample resistivit}~ of 0.13 ~•m at ~ 85 ° C. R Conversion appro~mated by: - ~•m .C1 Rz=R4 ~ TI+6.77 ~ r:\«.,;°F Temperature T, + 6.77 of oC ~ 1 so to or Concentration T,+21 ° ~ ' .~2 ; C . R_=R ) glka gnaal 4 ~ ++ ± T:+21.3 • = or « 24°C - .~3 so ppmlxtOCC) or 75°F 300 - 7700 cs 70 20 200 -'- 1'000 ~ .CS 10000 _ .C6 100 r. + eo eo -~- =_coo y' ..8 30 60 -~ -000 + 0.1 90 "?~00 1 40 ' 100 30 -+' 2000 _ 40 20 + .2 CCO 50 -~ .3 10 g ~ 500 .4 60 6 -~ 400 5 150 - ~ 4 ` 300 .6 4 3 200 ~ 8 80 ) _. • 1.0 2 . 200 _ 100 100 1 8 50 2.- 250 120 40 .6 30 3 140 .4 20 .. - . 300 .3 `) ~ 4 160 ~ ~ 2 ~ 5 • 6 t80 _~ a 4~ 200 t0 220 240 500 260 • ~ ~ •Stn~umparger 20 Gen-9 S • _• EXHIBIT B L Unocal Oil & Gas Din Unocal Corporation P.O. Box 190247 Anchorage, Alaska 99519-0247 Telephone (907) 276-7600 Alaska District October 3, 1986 T0: R. D. Roberts FROM: K. D. Kiloh ~(~ SHALLOW FORMATION WATER SALINITY STUDY KENAI UNIT 14-4, SECTION 4, T4N, R11W, SM KENAI GAS FIELD, ALASKA Attachment No. 4 As per your request, a shallow formation water salinity study was conducted in Union's KU 14-4 well, located in the Kenai Gas Field, Alaska. The purpose of this study was to determine the formation water salinities in the relatively shallow,~sandy interval from 1069' (the 11-3/4" casing shoe) to 4262', the base of the water productive B-2 sand in the Lower Sterling Formation gas sand interval. In addition, an east-west geologic cross section was constructed to show the lateral continuity of the impermeable shale/siltstone intervals which prevent vertical migration of the injected Fluids. Results and Conclusions: Formation evaluation in the interval from 1069' to 3942' in KU 14-4,~indicates the sand zones contain formation waters having equivalent salinities ranging from 1100 to 2700 ppm NaCl. These salinity values are supported by water analyses from the B-1 and B-2 gas sands that contain 1100 ppm NaCl from a January 1983 test. During a November 1960 production test in the B-3 gas sand, formation water was produced, and analyzed. The results from this test were 1100 ppm NaCl (63 grains/gallon). The calculated salinities resulting from this study represent at best, a baseline minimum in equivalent ppm NaCl. Factors such. as mud cake thickness and the flushed zone fluids in the borehole environment affect the Rxo measuring device (16-inch normal on the Induction-Electrical log), resulting in a lower recorded resistivity than the true Rxo value. Also, the presence of bivalent ions such as magnesium, calcium and potassium, etc., in the formation waters will affect salinity calculations giving a lower equivalent ppm NaCl value than is actually present. r T0: R. D. Roberts i FROM: K. D. Kiloh October 3, 1986 Page Two Procedures and Methods: A Schlumberger Induction-Electrical log and Sonic log were run in KU 14-4. Sonic porosities were not used in this study because field-wide studies indicate they are too high (37 to 42%). Log analysis indicates the sediments from 1069' to 5039' (Plate 1) are sandstones, siltstone/shale, and occasional thin-bedded coals. The sands are unconsolidated and generally uncemented. The B-1 and B-2 sands are recommended for Phase 1 injection since open perforations are present and these sands are not gas productive. Sands ~~1 through ~~5 are recommended for Phase 2 injection. Bath proposed injection zones are colored light green on the annotated log and cross section. Subsequent injection phases will involve uncolored sands ~~6 through ~~16. The orange-colored intervals on the log and cross section (Plate 2) indicate impermeable shale/siltstone units which will prevent vertical communication of the injected fluids. Plate 2 shows the lateral continuity of the impermeable shale/siltstone intervals which vary in thickness from 5 to 29 feet. This section runs from Union, WD4~1 to Union, KU 14-4. In evaluating the Induction-Electrical log, it was noted that the 16-inch normal curve was consistently reading higher resistivity measurements than the induction curve. This suggests that the 16-inch normal curve is reading closer to a true Rxo measurement, and did not require a borehole correction. ~. Using Schlumberger's Chart Sw-1 (Exhibit A), and assuming the average porosity ~ of those sands to be 35% (based on detail log analysis of the Sterling Formation gas reservoirs), Rw values in these sands were determined and are indicated on Plate 1. Maximum bottom hole temperature in this well is 124°F. Using a 35°F mean surface temperature, thermal gradient in this well was calculated to be 1.74°F/100 feet. By plotting both the derived Rw and formation temperature values at specific depths in the wellbore on Schlumberger's Temperature and Resistivity Chart Gen. 9 (Exhibit B), an estimate of the formation waters' equivalent salinity was derived and is shown on the annotated log for KU 14-4. KDK/pg 1965D Attachments: Plate 1: Annotated Type Log KU 14-4 Plate 2: East-West Structural Cross Section, The Glacial and Sterling Formation Intervals Exhibit A: Schlumberger Chart Sw-1 Exhibit B: Schlumberger Chart Gen. 9 CONCUR: Ir ~.:~n:R s,~TUR,~i u>~ ((r l is I Saturation Determination (Clean Formations) RW Sl•m Ro ~'m R, Sl•m 5 30 10,000 .ooe ~ FR 6,00o s s,ooo .o, 2.5 2000 20 4,000 7 3 3,000 1000 800 2,000 8 .02 a 600 , 10 400 5 ~ 1,000 800 10 8 6 300 600 .03 7 200 6 400 12 ,Oq 9 5 300 05 10 80 4 200 14 .06 60 16 3 15 40 100 BO 18 .08 30 60 20 •1 20 20 2 40 25 10 30 20 25 30 g .2 35 6 a0 5 1 10 30 4 8 .3 .8 0.62 FR= 6 ~z.is s a ao 4 .5 3 .5 4 2 50 .6 3 1 .8 8 .6 60 1.0 2 .4 70 2 80 90 2.0 .1 .1 100 3.0 .os E B R ~,_ ~= B W i ~: Schlumberger This nomograph solves the Archie water saturation equation SW = Ro F R,,. ~= R, . It should be used in clean (nonshaly) formations only. If ~ (resistivity when 100% water sat urated) is known, a straight line from the known Ro value through the measured R, value gives water saturation, S„ . [f R„ is not known, it may be deter mined by connecting the formation wa ter resistivity, RW, with the formation resistivit}• factor, FR, or porosity, ~. EXAhIPLE : Rµ. = 0.05 i1•m at formation temperature ~ = 20010 (FR = 20) R, = 10 S2•m Thus, SW = 31.601a , SW EXNI~IT ~ . 75 C Resisti~~•ity Nomograph for NaCI Solutions This nomograph may be used to estimate the resistivity of a water sample at a given temperature when the sali nity (NaCI concent ration) is known, or to estimate the salinity when resistivity and temperature are kno\\~n. It may also be used to con vert resistivity from one temperature to another temperature. EXAMP LE: Resistivity of a water sample is 0.3 il•m at 25°C; \vhat is its resistivity at 85°C? Draw a line connecting the 25°C point with the 0.3 S2•m R point . This indicates a salinit y of 20,000 ppm. Pivoting about this salinity point yields a water sample resistivity of 0.13 4• m at 8~°C. R Com•ersion approximated by: S?•m .01 ~T,+6.77) ° Rz=R1 t:v~,l; F T o Fpera Cre Tz + 6.77 ° so 1o or R,=R T,+21.5 .°C Concent I ( ) ration .02 ~ 9/kg T~ + 21.5 gr/gal or @ 24°C .03 so ppm(x1000) or75°F 300 17500 .04 70 20 200 13000 .05 10000 .06 80 100 80 5000 .OS 30 60 4000 0 1 90 3000 40 100 30 2000 40 20 .2 . 1000 50 .3 10 60 8 - 500 4 6 400 5 150 300 . 6 4 80 3 200 .8 1.0 200 2 100 100 1 . 8 50 2 250 120 6 40 30 3 140 '4 20 300 ,3 4 160 .2 5 6 180 8 400 200 10 220 240 500 '260 Schlumberge~ 20 Gen-9 EXHIBIT ~ 5 PHASE I KU 14-4 W.O. 11-3/4", 42~, H-80 CASING AT 1,069 PHASE II PROPOSED • PRESENT Baker Sleeve at 4, t 1 1' f Baker `'G-22' Locator at 4, 147' Baker P,fodel "D" Packer at 4, 148' i ~~ ~. lBaker Mule Shoe at 4, 158' 4,19.4' - 4,250' STERLING B-1 "XA" Sleeve at +2,480 Perm. Paker at ±2,500 3156'-3180', 3198'-324 3296'-3318', 3333'-335 33 70'-343 T.O.C. at ±4,00( Retainer at ±4, 16( 8~ B-2 SANDS -- 4825'-27' RETAINER AT 4,500' ~ 4885'-4926' ----- RETAINER AT 5,043' - ~- 7", 23~ 8~ 26T, S-95, J-55 8~ N-80 CASING AT 5,102' 4- lf2" Tubing -7/8", 6.4~, PJ-80 Tubing r+ a ~+ o', cr~'~ ttachment No. 5 9-5/8", 47~, N-80 Driven to 180' /2", 12.6, N-80 Buttress Tubing )1'-1,503' Squeezed A" Sleeve at 2,115' WC Perm. Packer at 2,147' "X" Nipple at 2,162' W/L ReEntry Guide at ?,174' 30'' 3,160' Open 7$'-3,193' Open 35'-3,250' Open D. at 3,252' (Top of Cement) ~ 29~, N-80 Casing at 3,278' *See Packer Schematic For Further Dimensions KENAI GAS FIELD WASTE DISPOSAL INJECTION. WELL ~ 1 W.O. attachment No. 6 ~ ~q~Q 4 ~ ~` or •:• ~. ~:. , usowwrowi~s APR 2 z 19s~ CHEMICAL & GEOLOGICAL LABORATORI~ ~'F~.~NC. P.O. BOX 4-1276 TELEPHONE ANC '~~~~~~rr'~eU Anchorage, Alaska 99509 (907) 562-2343 APR 181986 WATER ANALYSIS REPORT Ak Em~fronm OPER/~TOR Ur~or Oil Ccnr~a~y WELL NO. Disposal Well FIELD Kenai Gas Field COUNTY ---- STATE -~1 aGka WATER ANALYSIS PATTERN Scale MEt] per Unit. REMARKS & ONCLUSIONS: - ~OC~ - Cations mgli meg11 Anions mgll megll Sodium ............. 1~ 44.04 Sulfate .............. --- --- Potassium ........... 7F 1 _95 Chloride ............. 1500 4~ „30 Calcium ............. 92 4.5A Carbonate ........... ---- --- Magnesium.......... ~~- 1_R1 Bicarbonate ......... X15 10-0A Iron ................ 0.42 --- Hydroxide ........... ---- --- ' Total Cations ......... rig 3A Total Anions .......... 5~ 3g Total dissolved solids, mgli .......... 3005 Specific resistance @ 68° F.: NaC1 equivalent, mg/i .............. 2885 Observed .......... 2:6 ohmmeters Observed pH ....................... 7.7 Calculated ......... 2.4 ohm-meters - Sample above described Na Ca Mg Fe • ental Group DATE d.,/2/f36 LAS NO. 2474 LOCATION ----- FORMATION -- - INTERVAL --- SAMPLE FROM PrrxltTC~Pr3 itiTat-Pr 1'n;Pr'tai int-n WD #l, Kenai Gas Field C1 10 Na HCOa 5 Ca SO' 1 Mg CO' 0 Fe C1 HCOa SO' C O' (Na value in above graphs Includes Na, K, and Lt) A ~ ',L NOTE: Mglt =Milligrams per Iiler Meg11=Milligram equivalent per liter r ~I ~~ ~~ l ~ Sodium Chloride equivalent=by Dunlap & Hawthorne calculation Irom components i Union Oil Comp~f California 11-0-0 % Q4 TG: C. H. CASE FF;OM : S . L . TREt~1 December 31, 1986 RE: WD-1 STEP RATE TEST AND TEP1PERATURE SURVEY ~ ,~, ~, 5 1987 C, ~,~ . LUCKWO On December 18, 1986, a step rate test was -run on well WD-1. The following volumes and pressures were recorded: RATE CU~~IULATIVE VOLUME 0.413 BPt'~1 37 bbls 1.106 BPM 87 bbls 2.07$ BPh1 193 bbls 3.290 BPhI 249 bbls 4.900 BPP~I 347 bbls 6.950 BPP%i 500 bbls FINAL PRESSURE 9i0 psi 990 psi 1050 psi 1100 psi 1150 psi 1180 psi Dynamic temperature surveys were run before and after the test. The first dynamic survey was run while the well was injecting at 1.25 BPM, prior to the step rate test; the second dynamic survey was run while the well was in a fractureu state, at a rate of 3 BPM. A total of 2500 barrels of cold (35°F) water was injected prior to the second dynamic survey. The well was then shut in for six hours and a static temperature survey was rur~ . This survey ( Run ~~4 ) clearly showed the zor~~es which took water: 3030' to 3100', 3145' to 316U', 3180' tc 3195', and 3230' to 3250'. Ttie confining shale zones were not broken down by the fracture.; there is no evidence tf~at the injected water broke into any fresh water zones. SLT/ejj/0308r Attachment i KENA1 GAS FIELD WO-~ Step Rate Test Calculation of Fracture Gradient Fracture Pressure = 1090 prig (wellhead) Fluid Gradient (fresh water} = 0.433 psi/ft Top Perf. Depth: 30>0' i Fracture Gradient = (10>U + 14.7} + (0.43~)(303u) 303G' = 0.797 psi/f t SLT/e,,ji030£3i~/2 i2-31-~~ KEN Ai GAS FIELD WELL WD-1 STEP RATE TEST December 18th - 19th, 1986 X200 • ~ ~ 00 _~ N tooo a ... W W 900 a. i• Boa 70C 0 ESTIMATED FRACTURE PRESSURE = 1,090psi r 1.0 2.0 3.0 4.0 5.0 6.0 7.0 WATER INJECTIGN RATE (BPM) C C 132:0502 made a part of the applicable UIC pro- gram under the SDWA for the State of Alabama. This incorporation by reference was approved by the Director of the Fed- eral Register on June 25, 1984. (I) Code of Alabama 1975, §§ 9-17-1 through 9-17-110 (1980 and Supp. 1983 ); (2) State Oil and Gas Hoard 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 (IVfay 14, 1982) amending Rule E-4). (b) The itilemorandum of Agreement bettiveen 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, III, 1V and V wells The UIC 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 SDWA. 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 SDWA for the State of Ala- bama. This incorporation by reference was approved by the Director oC the Federal Register on June 25, 1984. Attachment No. 8 FEDERAL REGULATIONS (1) Alabama Water Pollution Control Act, Code of Alabama 1975, §§22-22-1 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 ti, 1983 (effective May I1, 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 LesalAuthority. (1) "Water Pollution-Public Health-State has Authority to Carry Out Underground injection Control Frogram Described in Federal Safe Drinking Water Act- Opinion by Legal Cowtsel for the Water Improvement Commission," June 25, 1982; (2) Letter from Attorney, Alabama Water Improvement Commission, to Regional Administrator, EPA Region IV, "Re: AWIC Response to Phillip Tale's (U.S. EPA, Washington) Comments on AV'JIC's Final Application for Class I, II1, IV, and V UiC Program," September 21, 1982; (3j Letter from Alabama Chief Assistant Attorney General to Regional Counsel, EPA Region IV, "Re: Status of Independent Legal Counsel in P.labama 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. IFieservedl §147.101 EPA-administered program. (a) Contents. The U[C program for the State of Alaska is administered by EPA. This program consists of the UIC 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. ' ~~~~,1~~ Jr`~N ~ 2 1S87 (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 the 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: (1) The portions of aquifers in the Kenai Peninsula, greater than the indicat- ed depths below the ground surface, and described by a '/a 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 ~/a mile area beyond and lying directly below the fol- lowing oil and gas producing fields: (A) Granite Point. .•-~~ (B) McArthur River Field. (C) Middle Ground Shoal Fieid. (D) Trading Bay Field. (3) The portions of aquifers on the North Slope described by a 45 mile area beyond and lying directly below the Ku- paruk River Unit oil and gas producing field. §147.103 Existing class I, t[ (except en- hanced recovery and hydrocarbon storages 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=(0.733-0.433 Sg)d where Alaska oii ~ ~:~.; ,. - ,,.-.~+s~tission Anch~ra~e Environment Roporter (Sec. 147.103(b)1 t 52 Attachment No. 7 Union Oil Compan~ California uno~n December 31, 198c~ TG: C. H. CASE FROM: S. L. TREM RE: WD-1 STEP RATE TEST AND TEMPERATURE SURVEY ,~ A N 5 1981 ~. ~~ . LocxWO~. On December 18, 1986, a step rate test was run do well WD-1. The following volumes and pressures were recorded: RATE CUMULATIVE VOLUME FINAL PRESSURE U.4i3 BPM 37 bbls 9i0 psi 1.106 6PM 87 bbis 990 psi 2.078 BPM 193 bbls 1050 psi 3.290 BPM 249 bbls 1100 psi 4.900 BPP~1 347 bbls 1150 psi 6.950 BPM 500 bbls 1180 psi Dynamic temperature surveys were run before and after the test. The first dynamic survey was run while the well was injecting at 1.25 BPM, prior to the step rate test; the second dynamic survey was run while the well was in a fractured state, at a rate of 3 BPM. A total of 2500 barrels of cold (35°F) water was injected prior to the second dynamic survey. The well was then shut in for six hours and a static temperature survey was run. This survey (Run ~f4) clearly showed the zones which took water: 3030' to 3100', 3145' to 3160', 3180' to 3195', and 3230' to 3250'. Tt~e confining shale zones were not broken down by the fracture; there is no evidence that the injected water broke into any fresh water zones. SLT/ejj/0308r Attachment • • KENA1 GAS FIELG WD-i Step R«te Test Calculation of Fracture Gradient Fracture Pressure = 1090 psig (wellhead) Fluid Gradient (fresh Water) = U.4~3 psi/ft Top Perf. Depth: 3030' Fracture Gradient = (1090 + 14.7) + (0.433)(3036) 3036` = 0.797 psi/f t SLT/e, j i 0308i~/2 12-~1-80 KENAI GAS FIELD WELL WD-1 STEP RATE TEST December 18th - 19th, 1986 12 1 100 ~ ~ ESTIMATED FRACTURE PRESSURE = 1,090psi v~ N i0oo a v W Qr W 900 a 800 700 1.0 2.0 3.0 4.0 5.0 6.0 7.0 WATER INJECTION RATE (BPM) J Attachment No. 8 C 132:0502 made a part of the applicable UIC pro- gram under the SDWA for the State of Alabama. This incorporation by reference was approved by the Director of the Fed- eral Register on June 25, 1984. (I) 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. (1) Alabama Water Pollution Control Act, Code of Alabama 1975, §§22-22-I through 22-22-14 (]980 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 11, 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, ]983. (cj Statement of Legol 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, Alabama Water Improvement Commission, to Regional Administrator, EPA Region IV, "Re: AWIC Response to Phillip Tote's (U.S. EPA. Washington) Comments on AV'/IC's Fir,al Application for Class I, III, IV, and V UIC Program," September 21, 1982; (3) Letter from Alabama Chief Assistant Attorney General to Regional Counsel, EPA Region IV, "Re: Stat:IS of Independent Legal Counsel in P.labama 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] (b) Effective date. The effective date of the UIC program for Alaska is: June 25, 1984. §147.102 Aquifer exemptions. (a) This section identities 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 the 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: (1) The portions of aquifers in the Kenai Peninsula, greater than the indicat- ed depths below the ground surface, and described by a ~/a mile area beyond and lying directly below the following oil and gas producing fields: (A) Swanson River Field-1 700 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) Middle Ground Shoal Field. (D) Trading Bay Field. (3) The portions of aquifers on the North Slope described by a ~~: mite area beyond and lying directly below the Ku- paruk River Unit oil and gas producing field. § 147.103 Existing class ], 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: §147.51 State-administered program - Class I. III, IV and V wells The UIC 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 SDWA. 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 SDWA for the State of Ala- bama. This incorporation by reference was approved by the Director of the Federal Register on June 25, 1984. C §147.101 EPA-administered program. (a) Contents. The U[C program for the State of Alaska is administered by EPA. This program consists of the UIC 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. FEDERAL REGULATIONS Pm=(0.733-0.433 Sg)d where .~ ~~ ~ ~ t p ,.- ,~ .. - j ;;'~~'- ~ .'1 ,~ tL,~{ n .,, °' „ _. ~ i~;;.~ '' ~1` t,~",rj~ i Environment Reporter [SeC. 147.103(b)J t52 C
