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Home My WebLink AboutAIO 028 AREA INJECTION ORDER 28 Colville River Field Colville River Unit Nanuq Oil Pool 1. September 15, 2005 Application for AIO 2. September 26, 2005 Advertising Order AO-02614014 3. November 7, 2005 Supplemental information 4. -------------------- Emails 5. March 28, 2007 CPAI’s request for AA (AIO 28.001) 6. March 29, 2007 Alpine Produced Water Compatibility Report 7. May 21, 2009 CPAI’s request for AA to authorize gas injection into pool without a miscibility requirement and to authorize injection of additional fluid types (AIO 28.002) 8. October 15, 2010 CPAI’s request for AA for CD4-209 to be online water injection only (AIO 28.003) 9. November 5, 2010 Backup information (AIO 28.004), corrected on 12/2/10 10. May 8, 2013 – August 16, 2013 Amendment of Alternative MIT schedule for UIC injection wells and background information 11. March 26, 2016 - February 23, 2017 CPAI’s request to perform an MIT-IA every two years to the maximum anticipated injection pressure (AIO 28.003 Amended) 12. September 3, 2017 Administrative approval to allow well CD4-291 (PTD 2131100) to be online in water only injection service with a known outer annulus x atmosphere pressure communication. (AIO 28.005) 13. September 19, 2017 Administrative approval to allow well CD4-214 (PTD 2061450) to be online in water only injection service with a known tubing by inner annulus communication. (AIO 28.006) 14. June 1, 2018 Administrative Approval to cancel AIO 28.005. 15. February 28, 2018 CPA Request for Administrative Amendment, CRU (AIO28.007) 16. December 1, 2021 CPA request to allow CRU CD4-291 (PTD 213-110) to remain in water only injection service (AIO 28.008) 17. May 26, 2021 CPAI request to reinstate AIO 18A with modifications (AIO 28.009) 18. February 21, 2023 CPAI request to amend AIO 28.006 (AIO 28.006 amend) 19. April 24, 2023 CPAI request to amend AIO 28.008 (AIO 28.008 amend) 20. January 15, 2025 AIO 7 Proposed language change (AIO 28.011) ORDERS . . STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: THE APPLICATION OF CONOCO-PHILLIPS ALASKA INC. for an order authorizing underground injection of fluids for enhanced oil recovery in the Nanuq Oil Pool, Colville River Unit, North Slope, Alaska IT APPEARING THAT: ) Area Injection Order No. 28 ) ) Colville River Field ) Colville River Unit ) Nanuq Oil Pool ) ) April 24, 2006 I. By letter and application filed September 15, 2005, ConocoPhillips Alaska, Inc. ("ConocoPhillips") in its capacity as Unit Operator of the Colville River Unit requested an order from the Alaska Oil and Gas Conservation Commission ("Commission") authorizing the injection of fluids for enhanced oil recovery in the Nanuq Oil Pool. 2. Notice of a public hearing was published in the Anchorage Daily News on September 27, 2005. 3. No protests, requests for hearing, or comments were submitted to the Commission during the 30-day public comment period. 4. The Commission vacated the public hearing on October 28,2005. 5. The Commission requested additional information from ConocoPhillips on October 28,2005, January 10, 2006 and January 11, 2006. Supplemental information was received from ConocoPhillips on November 2,2005, January 10,2006 and January 12,2006. FINDINGS: 1. Operator: ConocoPhillips is the operator of the property in the area proposed for development. ConocoPhillips uses the name Nanuq in reference to the development project. 2. Project Area Pool and Formations Authorized for Enhanced Recovery: Enhanced recovery injection for the Nanuq development is proposed within the Nanuq Oil Pool. The target injection zone is correlative to the Nanuk No.2 exploration well between 7,043 feet and 7,223 feet measured depth. 3. Proposed Injection Area: ConocoPhillips requested authorization to inject fluids for the purpose of enhanced recovery operations on lands in the Colville River Unit within TI0N-R4E, TI0N-R5E, Tl1N-R4E, and TIIN-R5E, Umiat Meridian. Area Injection Order 28 April 24, 2006 . . Page 2 4. Operators/Surface Owners Notification: ConocoPhillips provided operators and surface owners within one-quarter mile of the proposed area with a copy of the application for injection. The only affected operator is ConocoPhillips, operator of the Colville River Unit. The State of Alaska, Department of Natural Resources and Kuukpik Corporation are the only affected surface owners. 5. Description of Operation: The Nanuq Oil Pool will be developed with a total of 16 horizontal wells, nine producers and seven injectors. Water alternating with miscible gas injection ("MW AG") will be implemented as the enhanced recovery mechanism for the pool. Water injection is scheduled to begin in late 2006 followed by miscible gas injection ("MI") beginning in 2007. Prior to processing, production from the Nanuq Oil Pool and the deeper Nanuq-Kuparuk Oil Pool will be commingled on the surface at the Colville River Unit CD4 drill site and further commingled with production from the Alpine Pool and other Alpine satellite pools before separation at the Alpine Central Facility, located on the Colville River Unit CDl drill site. All production will be transported from the Alpine Central Facility using the existing pipeline to the Kuparuk River Field. Peak production rates are expected to be between 4,000 and 11,000 barrels of oil per day. Waterflood injection rates are estimated to peak between 3,500 and 9,600 barrels of water per day ("BWPD") and miscible gas injection rates are estimated to peak at 12 to 33 million standard cubic feet of gas per day ("MMSCFPD"). 6. Hydrocarbon Recovery: Estimates of original oil in place and recovery (in units of one million stock tank barrels or "Million STB") within the Nanuq development area are: Hydrocarbon Volume Original Oil in Place Primary Recovery (10%) Primary + Waterflood (20 to 25%) Primary + Waterflood + MW AG (29 to 39%) Low Estimate (Million STB) 84 8 17 24 High Estimate (Million STB) 169 17 42 66 7. Geologic Information: a. Stratigraphy and Structure: The Nanuq reservoir is a Cretaceous-aged basin floor submarine fan system dominated by lobe-sheet deposits. This fan system lies 1 to 2 miles east of the time-equivalent, northeast-southwest trending base of slope. The reservoir consists of fine-grained sandstone with interbedded shale layers of varying thickness. The best reservoir-quality rock is generally found in the upper part of the interval. Although there is a localized high within the proposed development area, the Nanuq reservoir sandstone generally dips to the south and east. To the north and west, the absence of sand creates a stratigraphic trap. Well log and core data place the oil-water contact at 6,207 feet true vertical depth subsea. A gas cap also is believed to be present, Area Injection Order 28 April 24, 2006 . . Page 3 with a gas-oil contact at about 6,100 feet true vertical depth subsea. There are no major faults mapped within the proposed development area. b. Confining Intervals: The Nanuq Oil Pool is overlain by approximately 2,000 feet of interbedded mudstone and siltstone assigned to the Torok Formation. The pool is underlain by about 400 feet of mudstone, siltstone and sandstone within the basal Torok. The basal Torok is, in turn, underlain by about 280 feet of mudstone and shale assigned to the HRZ interval, Kalubik Formation, and the Kuparuk D interval, in descending order. The overlying and underlying confining intervals are laterally continuous throughout the proposed development area. 8. Well Logs: Logs of injection wells will be filed with the Commission according to the requirements of 20 AAC 25. 9. Mechanical Integrity and Well Design of Injection Wells: The casing programs for all injection wells will comply with 20 AAC 25.030. ConocoPhillips requests packers be located more than 200 feet measured depth above the top of the injection zone to facilitate wireline access. Tubing or other equipment will be designed and installed in accordance with 20 AAC 25.412. Cement-bond logs will be run to demonstrate isolation of injected fluids to the Nanuq reservoir. Mechanical integrity tests will be performed on all injection wells in accordance with 20 AAC 25.412(c). Casing-tubing annulus pressures will be monitored during injection operations in accordance with 20 AAC 25.402(e). In the event that pressure observations or the tests indicate communication or leaking of any tubing, casing, or packer, ConocoPhillips will notify the Commission within 24 hours of the observation to obtain Commission approval of appropriate corrective actions. 10. Type of Fluid / Source: Fluids requested for injection are: a. source water from the Beaufort Sea; b. miscible gas obtained from the Alpine Central Facility; c. produced water from the Nanuq Oil Pool; d. produced water from the Alpine Oil Pool and other Alpine satellite pools; and e. all amounts of fluids collected from sumps, hydrotests, rinsate from washing mud hauling trucks, excess well-work fluids, and treated camp waste water. 11. Water and MI Composition and Compatibility with Formation: Seawater is planned as the initial waterflood source water for the proposed Nanuq Oil Pool, and it has been tested in core flood studies and found to be compatible with the injection zone. Later in the life of the field, waterflood source water is expected to change from seawater to Area Injection Order 28 April 24, 2006 . . Page 4 some combination of seawater, produced water from the Nanuq and Nanuq-Kuparuk Oil Pools, produced water from other oil pools within the Colville River Unit, small volumes of non-hazardous fluids collected from sumps, hydrotests, rinsate from washing mud hauling trucks, well work, and treated camp waste water. The operator reports there is no evidence that treated seawater or treated produced waters will be incompatible among any of the existing or proposed pools in the Colville River Field. Numerical simulation, laboratory experiments and PVT modeling demonstrate that MI obtained from the Alpine Central Facility will be miscible with Nanuq crude oil at initial reservoir conditions, and will significantly reduce residual oil saturation below that achievable by waterflooding alone. 12. Injection Rates and Pressures: Injection rates will be adjusted to manage voidage for the reservoir. Injection of water and MI will alternate in each injection well. Expected maximum and average injection rates are: Oil Pool Maximum MI Rate (MMSCFD) Average MI Rate (MMSCFD) Maximum Water Rate (BWPD) A verage Water Rate (BWPD) Nanuq 10 5 5,000 1,000 Seawater injection pressures from the Alpine Central Facility pump discharge are expected to average approximately 2,500 psi. Wellhead pressures during water injection cycles are expected to be about 2,400 psi. MI pressure available from the Alpine Central Facility is expected to be approximately 4,000 psi, and wellhead pressures during MI injection cycles are expected to be about 3,800 psi. Injection rates may be managed by choking injection wells. MI composition may vary and, as a result, minimum miscibility pressure may vary from 1,900 to 2,600 psia. The proposed project will be operated so that the average pressure in the Nanuq reservoir will be maintained at 3,000 psi, which is significantly above the minimum miscibility pressure. 13. Fracture Information: Although maximum water injection pressure will exceed the Nanuq reservoir rock parting pressure, computer modeling using injection rates 50% greater than planned indicates: a. fractures will propagate into but not through the mudstone and siltstone beds of the Torok Formation that bound the pool above and below, and b. injection fluids will remain within the Nanuq reservoir. 14. Absence of Underground Sources of Drinking Water: According to the findings and conclusions of Area Injection Orders 18, 18A, and 18B, there are no underground sources of drinking water beneath the permafrost in the Colville River Unit area. Examination of well log data from exploratory wells in and near the proposed Nanuq development confirms that there are no aquifers within the affected area that could serve as underground sources of drinking water. Area Injection Order 28 April 24, 2006 . . Page 5 15. Mechanical Condition of Adjacent Wells: The Nanuk No.1, Nanuk No.2, Nanuq No.3, and Nanuq No.5 exploration wells all penetrate the proposed Nanuq and Nanuq-Kuparuk injection intervals within the project area. Nanuk No.1 and Nanuk No.2 have been plugged and abandoned. Nanuq No.3 and Nanuq No.5 were drilled through the injection intervals, cased and suspended. All four of these wells have sufficient mechanical isolation to confine injected fluids to the target reservoirs and prevent cross flow into other intervals. CONCLUSIONS: 1. The application requirements of 20 AAC 25.402 have been met. 2. Injection of water and miscible gas will significantly improve recovery. 3. There are no underground sources of drinking water beneath the permafrost in the Colville River Unit or the proposed affected area. 4. Increasing the distance between the packer and top ofthe injection zone will not compromise well integrity, so long as the top of production casing cement is at least 300 feet measured depth above the packer. 5. The proposed injection operations will be conducted in permeable strata, which can reasonably be expected to accept injected fluids at pressures less than the fracture pressure of the confining strata. 6. Injected fluids will be confined within the appropriate receiving intervals by impermeable lithology, cement isolation of the wellbore and appropriate operating conditions. 7. Seawater waterflood source water will be compatible with the Nanuq reservoir. Compatibility has not been demonstrated for produced waters, mixtures of waters, non- hazardous liquids collected from sumps, hydrotests, well work, rinsate from washing mud- hauling trucks, and treated camp waste water. 8. Reservoir pressure will be maintained to ensure gas miscibility. 9. Reservoir and well surveillance, coupled with regularly scheduled mechanical integrity tests will demonstrate appropriate performance of the enhanced oil recovery project or disclose possible abnormalities. 10. Sufficient information has been provided to authorize injection of water and miscible gas into the Nanuq Oil Pool for the purposes of pressure maintenance and enhanced oil recovery. NOW, THEREFORE, IT IS ORDERED that: The underground injection of fluids for pressure maintenance and enhanced oil recovery is authorized in the following area, subject to the following rules and the statewide requirements under 20 AAC 25 (to the extent not superseded by these rules). Area Injection Order 28 April 24, 2006 . . Page 6 Umiat Meridian Township, Range, UM TI0N, R4E T10N, R5E T11N, R4E Sections TIIN, R5E 1,2 3,4,5,6 1, 2, 3, 4, 9, 10, II, 12, 13, 14, 15, 16, 21, 22, 23, 24,25,26,27,28,33,34,35,36 3,4,5,6,7,8,9,10,15,16,17,18,19,20,21,22, 27,28,29,30,31,32,33,34 Rule 1 Authorized Injection Strata for Enhanced Recovery Authorized fluids may be injected for purposes of pressure maintenance and enhanced recovery within the Nanuq development area into strata that are common to, and correlate with, the interval between the measured depths of 7,043 feet and 7,223 feet in the Nanuk No.2 well. Rule 2 Fluid Injection Wells The underground injection of fluids must be through a well that has been permitted for drilling as a service well for injection or through a well approved for conversion to a service well for injection in conformance with 20 AAC 25. Rule 3 Well Construction To facilitate wireline access, packers in injection wells may be located more than 200 feet measured depth above the top of the Nanuq pool; however, packers shall not be located above the confining zone. In cases where the packer distance is more than 200 feet above the injection zone, the production casing cement volume should be sufficient to place cement a minimum of 300 feet measured depth above the planned packer depth. Rule 4 Authorized Fluids for Enhanced Recovery Fluids authorized for injection are: a. source water from a sea water treatment plant; b. miscible gas obtained from the Alpine Central Facility with the condition that the reservoir pressure must be maintained to ensure the miscibility of the injectant. In addition, the following fluids may be authorized by future administrative approval for injection upon demonstration of compatibility with the Nanuq reservoir: a. produced water; b. tracer survey liquid to monitor reservoir performance; c. small amounts of other non-hazardous liquids: sump liquid, hydrotest liquid, rinsate from washing mud hauling trucks, excess well work liquids, and treated camp waste water. In the event any mixture of fluids is injected, the following additional requirements apply: The operator shall continue to collect and analyze representative samples of the mixed fluid Area Injection Order 28 April 24, 2006 . . Page 7 stream to demonstrate its non-hazardous characteristics and its continued suitability for EOR injection. Analysis results must be retained according to the provisions of 20 AAC 25.310. Volumes of injected mixed fluids must be reported in the monthly (Form 10-406) and annual (Form 10-413) injection reports. Rule 5 Monitoring Tubing-Casing Annulus Pressure The tubing and casing annuli pressures of each injection well must be monitored at least daily, except if prevented by extreme weather condition, emergency situations, or similar unavoidable circumstances. Monitoring results shall be documented and made available for Commission inspection. Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity A Commission-witnessed mechanical integrity test must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter, except at least once every two years in the case of a slurry injection well. The Commission must be notified at least 24 hours in advance to enable a representative to witness mechanical integrity tests. 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 1,500 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. Results of mechanical integrity tests must be readily available for Commission inspection. Rule 7 Well Integrity and Confinement Injection operations must ensure that injected fluids do not fracture adjacent confining intervals or migrate out of the approved injection zone. 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 notify the Commission by the next business day 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. Rule 8 Notification of Improper Class II Injection Injection of fluids other than those listed in Rule 4 without prior authorization is considered improper Class II injection. Upon discovery of such an event, the operator must immediately notify the Commission, provide details of the operation, and propose actions to prevent recurrence. Additionally, notification requirements of any other State or Federal agency remain the operator's responsibility. Area Injection Order 28 April 24, 2006 . . Page 8 Rule 9 Plu22in2 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 accordance with 20 AAC 25.112. Rule 10 Other conditions a. It is a condition of this authorization that the operator complies with all applicable Commission regulations. b. The Commission may suspend, revoke, or modify this authorization if injected fluids fail to be confined within the designated injection strata. Rule 11 Administrative Actions Unless notice and public hearing are otherwise required, the Commission may administratively waive or amend the requirements of 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 an increased risk of fluid movement into freshwater. : K. 1\ orm~Chairman Alaska Oi~ Gas Conservation Commission Daniel T. Seamount, Jr., Commissioner Alaska Oil and Gas Conservation Commission ~/~~ Cathy P. oerster, Commissioner Alaska il and Gas Conservation Commission AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23'd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10-day period. An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by non-action of the Commission, the 30-day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e., 10th day after the application for rehearing was filed). Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 .. David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 John Levorsen 200 North 3rd Street, #1202 Boise, ID 83702 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 James Gibbs PO Box 1597 Soldotna, AK 99669 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 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 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 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 \06/ Off f{\f\\ ;r1 0. AI028 Colville River Field Nanuq Oil Pool . . Subject: AI028 Colville River Field Nanuq Oil Pool From: Jody Colombie <jody_colombie@admin.state.ak.us> Date: Tue, 25 Apr 200608:54:53 -0800 To: undisclosed-recipients BCC: Cynthia B Mciver < ver@admin.state.ak.us>, Robert E Mintz <robert_mintz@law.state. , Chr' . e Hansen <c.hansen@iogcc.state.ok.us>, Terrie Hubble <hubbletl@bp.com>, Sondra St tewmaSD@BP.com>, stanekj <staneIq@unocal.com>, ecolaw <ecolaw@trustees.org>, trmjr 1 , shaneg <shaneg@evergreengas.com>, jdarlington <jdarlington restoil.com>, nelso roleumnews.com>, cboddy <c y >, Mark Dalton @ . c.co hannon Donnelly <sh on. phillips. com , W er" <markp.wor philli >, Bob <bob@m r.org>, wdv <wdv@dnr.state.ak.us>, tjr <tjr@dnr.state.ak.us>, bbritch ch@alaska.net>, mjne <mjnelson ingertz.com>, Charles O'Donnell <charles.o'do· veco.com>, "Randy L. lem" <Ski @BP.com>, "Deborah 1. Jones" <JonesD6@B m>, "Steven R. Rossberg" <RossbeRS@BP.com>, Lois <lois@inletkeeper.org>, Dan Bra kuacnews@kuac.org>, Gordon Pospisil <PospisG@BP.com>, "Francis S. Sommer" <SommerF P.com>, Mikel Schultz <Mikel.Schultz@BP.com>, "Nick W. Glover" BP.com>, "Daryl J. Kleppin" <KleppiDE@BP.com>, "Janet D. Platt" <PlattJ osann J obsen" <Jaco P.com>, ddonkel <ddonkel@cfl.rr.com>, mckay <mc ci.net>, Bar ara.f. er@conocophillips.com>, Charles Barker <b @ 0 schu ze xtoenergy., Hank Alford <hank.alfor . com> , Mark Kovac sno 1 i.ne foff <gspfoff@aurorapower.com>, Gr <gregg.nady om>, Fred Steece <fred.steece@state.sd.us>, rcrotty ch2m.com>, . <jejones@aurorapower.com>, dapa <dapa@alaska.net>,jroderick <jro @gci.net>, ey cy@seal-tite.net>, "J . Ruud" <james.m.ruud@conocophillips.co rit Lively <map ak.net>,jah <jah@dnr. .ak.us>, buonoje <buono·e@bp.com>, Mar ley <mark_hanley arko.com>,loren_leman <loren lem .state.ak.us>, Julie houle@ state.ak.us>, John W Katz <jwk s u J Hill <suzan ate.ak.u k <tablerk@unocal.com>, Brady <bra Br Haveloc b .ak.us>, <bpopp@borough.kenai.ak.us>, Jim Whit tx.rr.com>, "J S. Ha <john.s. rth@exxonmobil.com>, marty .com>, ghammons <ghamm aol.co clean <rmclean@pobox.alaska.net>, mkm7200 <mkm O@aol.com>, Brian Gillespi fbmg@uaa. aska.edu>, David L Boelens <dboelens@aurorapower.com>, Todd Durkee <TDURKEE@KMG.com>, Gary Schultz <gary_schultz@ tate.akus>, Wayne Rancier <RANCIER@petro-canada.ca>, B on Gagnon <bgagnori@bren >, Paul Winslow <pmwinslow@forestoil.com>, Sharmain opeland <cop stin Dirk istin_dirks@dnr.state.ak.us>, Kaynell Zeman <kjz noil.com>, Jo . wer <John.Tower@eia.doe.gov>, Bill Fowler <Bill wler@ darko.CO Cranswick <scott.cranswick@mms.gov McKim <mcklmbs@BP > ve lambes@unocal.com> ne <jack well@acsalaska.net>, James Scherr < .s err@mms.gov>, n1617@conoco .com Lawlor <Tim_Lawlo1'@ Im.gov>, Lynnda Kahn <Lynnda_K fw v>, Jerry Dethlefs <Jerry.C.Dethlefs@conocophillips.com>, crockett@aoga.org, T era Sheffiel effield@aoga.org>, Jon Goltz <Jon.Goltz@conocophillips.com>, elman <r r.belman@co cophillips.com>, Mindy Lewis <ml 's enalaw.com>, Kari <m @aoga.org>, Patty Alfaro <palfaro@yahoo > f <smetankaj@unocal.com>, T Kratz <ToddKratz@chevron.com>, Gary Rogers <gary_ro rs@revenue.state.ak.us>, Arthur Copou <Arthur_Copoulos@dnr.state.ak.us>, Ken <ken@secorp-inc.com>, Steve Lambert <salambert@unocal.com>, Joe Nicks <news@radiokenai.com>, 10f2 4/25/2006 1 :00 PM AI028 Colville River Field Nanuq Oil Pool . . Jerry McCutcheon <susitnahydronow@yahoo.com>, Paul Todd <paulto@acsalaska.net>, Bill Walker <bill- . Matthews < . ews@legis.state.ak.us>, Paul Decker <paul_ .ak.us>, Rob rob.g.dragnich@exxonmobi1.com>, Aleutians East Borough tianseas g>, 'te kremer <marguerite_kremer@dnr.state.ak.us>, Robert Brelsford <Robert. BreIs smediagroup.com>, ia Konsor <alicia_konsor@dnr.state.ak.us>, Mike Mason <m' k arland Robinson <g @mar oi1.com>, Cammy Taylor <Camille_Taylo aw >, Winton GAubert < aubert in.state.ak.us>, Thomas E Maunder <tom_maund .state.ak.us>, Stephen F les <ste _ avies@admin.state.ak.us> Content- T aio28.pdf C ontent-En application/pdf g: base64 20f2 4/25/2006 1 :00 PM . ~1f~1fŒ (ID~ ~~~~æ~ . AI.ASIiA. OIL AlQ) GAS CONSERVATION COMMISSION SARAH PALIN, GOVERNOR 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. AIO 28.001 Mr. Jack Walker ConocoPhillips Alaska Inc. P.O. Box 196860 Anchorage, AK 99519-0105 Re: The application from ConocoPhillips Alaska, Inc. to inject produced water from the Colville River Field, Alpine Oil Pool, into the Nanuq Oil Pool, North Slope, Alaska. Dear Mr. Walker: ConocoPhillips Alaska, Inc. ("CP AI") requested by letter dated March 28, 2007 authorization to inject produced water from the Alpine Oil Pool into the Nanuq Oil Pool. Injection of produced water will be an integral part of freeze protection that is necessary when the seawater injection system is not operating. CP AI has scheduled seawater injection system maintenance beginning March 31, 2007 . CPAI' s request is approved. Enhanced oil recovery by injecting seawater was authorized by Area Injection Order ("Ala") 28 dated April 24, 2006. The Commission's findings in Ala 28 concluded that CPAI had not demonstrated the compatibility of produced water from other Colville River Unit ("CRU") oil pools. Future approval of produced water from other CRU oil pools was however identified as an option upon demonstration of fluid compatibility with the Nanuq reservoir. CP AI provided fluid compatibility analysis for Alpine Oil Pool produced water by electronic mail dated March 29,2007. A common seawater injection system provides water for enhanced recovery in all CRU oil pools. According to CP AI, maintenance and repairs are periodically necessary for the proper operation of the seawater injection system. Freeze protection of the surface facilities and wells is necessary if seawater injection is shut down, involving the pumping of small volumes of produced water (roughly 200 barrels) into each seawater injection line daily during the shut down. The water placed into the injection line(s) would eventually be injected into the Nanuq Oil Pool. The Commission agrees with CPAI's analysis and assessment that injecting produced water from the Alpine Oil Pool will not be detrimental to the Nanuq Oil Pool. The Commission further finds that injecting produced water from the Alpine Oil Pool will not promote waste or jeopardize correlative rights, and will not contribute to the potential for fluid movement outside of the injection zone. . ADMINISTRATIVE APPROVAL NO. AlO 28-001 March 30,2007 Page 2 of2 . This approval applies to the small volume injection produced water from the Alpine Oil Pool only for the purpose of freeze protection when necessitated by maintenance or repairs to the seawater injection system. Larger scale injection of produced water from other CRU oil pools into the Nanuq Oil Pool will require additional review by the Commission prior to injection should CP AI plan such injection in the future. 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. DONE at rage, Alaska and dated March 30, 2007. ~ Daniel T. Seamount Commissioner . 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 Baker Oil Tools 4730 Business Park Blvd., #44 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 . 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 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 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 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 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 w AIO 27-001, 28-001,30-001 Colville River Field . . Subject: Ala 27-001, 28-001, 30-001 Colville River Field From: Jody Colombie <jody _ colombie@admin.state.ak.us> Date: Fri, 30 Mar 2007 15:28:26 -0800 To: undisclosed-recipients:; BCC: jack.a.walker@conocophillips.com, Christine Hansen <c.hansen@iogcc.state.ok.us>, Terrie Hubble <hubblet1@bp.com>, Sondra Stewman <StewmaSD@BP.com>, stanekj <stanekj@unocal.com>, trmjr 1 <trmjr l@ao1.com>, jdarlington <jdarlington@forestoil.com>, nelson <knelson@petroleumnews.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@in1etkeeper.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'donnell@veco.com>, "Randy L. Skillern" <SkilleRL@BP.com>, "Deborah J. Jones" <JonesD6@BP.com>, "Steven R. Rossberg" <RossbeRS@BP.com>, Lois <lois@in1etkeeper.org>, Dan Bross <kuacnews@kuac.org>, Gordon Pospisil <PospisG@BP.com>, "Francis S. Sommer" <SommerFS@BP.com>, Mikel Schultz <Mike1.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.fu1lmer@conocophillips.com>, doug_schultze <doug_schultze@xtoenergy.com>, Hank Alford <hank.alford@exxonmobi1.com>, Mark Kovac <yesnol@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>, Julie Houle <julie_houle@dnr.state.ak.us>, John W Katz <jwkatz@alaskadc.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@exxonmobil.com>, marty <marty@rkindustrial.com>, ghammons <ghammons@aol.com>, rmclean <rmclean@pobox.alaska.net>, mkm7200 <mkm7200@ao1.com>, Brian Gillespie <ifbmg@uaa.alaska.edu>, David L Boelens <dboelens@aurorapower.com>, Todd Durkee <TDURKEE@K.MG.com>, Gary Schultz <gary_schultz@dnr.state.ak.us>, Wayne Rancier <RANCIER@petro-canada.ca>, Brandon Gagnon <bgagnon@brenalaw.com>, Paul Winslow <pmwinslow@forestoil.com>, Sharmaine Copeland <copelasv@bp.com>, Kristin Dirks <kristin_dirks@dnr.state.ak.us>, Kaynell Zeman <kjzeman@marathonoi1.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>, jack newell <jack.newell@acsalaska.net>, James Scherr <james.scherr@mms.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 <m1ewis@brenalaw.com>, Kari Moriarty <moriarty@aoga.org>, Patty Alfaro <palfaro@yahoo.com>, Jeff <smetankaj@unocal.com>, Gary Rogers <gary _ rogers@revenue.state.ak.us>, Arthur Copoulos <Arthur _ Copoulos@dnr.state.ak.us>, Ken <klyons@otsint1.com>, Steve Lambert <salambert@unocal.com>, Joe Nicks <news@radiokenai.com>, Jerry McCutcheon <susitnahydronow@yahoo.com>, Bill Walker <bill-wwa@ak.net>" Paul Decker <paul_decker@dnr.state.ak.us>, Aleutians East Borough <admin@aleutianseast.org>, Marquerite kremer <marguerite_kremer@dnr.state.ak.us>, Mike Mason <mike@kbbi.org>, Garland Robinson lof2 3/30/20073:28 PM AIO 27-001, 28-001, 30-001 Colville River Field . . <gbrobinson@marathonoi1.com>, Cammy Taylor <cammy_taylor@dnr.state.ak.us>, Thomas E Maunder <tom_maunder@admin.state.ak.us>, Stephen F Davies <steve_davies@admin.state.ak.us>, Keith Wiles <kwiles@marathonoil.com>, Deanna Gamble <dgamble@kak:ivik.com>, James B Regg <jim _ regg@admin.state.ak.us>, Catherine P Foerster <cathy _ foerster@admin.state.ak.us>, Bob <Bob@fairweather.com>, gregory micallef <micallef@clearwire.net>, Laura Silliphant <laura _ silliphant@dnr.state.ak.us>, David Steingreaber <david.e.steingreaber@exxonmobi1.com>, akpratts@acsalaska.net, Robert Campbell <Robert.Campbell@reuters.com>, Steve Moothart <steve_moothart@dnr.state.ak.us>, Anna Raft' <anna.raff@dowjones.com>, Cliff Posey <cliff@posey.org>, Paul Bloom <paul_ bloom@m1.com>, Meghan Powell <Meghan.Powell@asrcenergy.com>, Temple Davidson <temple _ davidson@dnr.state.ak.us>, Walter Featherly <WFeatherly@PattonBoggs.com>, Tricia Waggoner <twaggoner@nrginc.com>, Mike Stockinger <Mike.Stockinger@anadarko.com>, John Spain <jps@stateside.com>, Cody Rice <Cody_Rice@legis.state.ak.us>, John Garing <garingJD@bp.com>, Harry Engel <engelhr@bp.com>, Jim Winegamer <jimwinegamer@brooksrangepetro.com>, Matt Rader <mattJader@dnr.state.ak.us>, carol smyth <caro1.smyth@shell.com>, Arthur C Saltmarsh <art_saltmarsh@admin.state.ak.us>, Chris Gay <cdgay@marathonoil.com>, foms@mtaonline.net, Rudy Brueggeman <rudy.brueggemann@international.gc.ca>, Cary Carrigan <cary@kfqd.com>, Sonja Frankllin <sfranklin6@bloomberg.net>, Mike Bill <Michae1.Bill@bp.com>, Walter Quay <WQuay@chevron.com>, Cynthia B Mciver <bren _ mciver@admin.state.ak.us> Jody Colombie <iody colombie(â!admin.state.ak.us> Special Staff Assistant Alaska Oil and Gas Conservation Commission Department of Administration Content-Type: application/pdf aio28-001.pdf Content-Encoding: base64 Content-Type: application/pdf aio30-001.pdf Content-Encoding: base64 Content.. Type: application/pdf aio27-001.pdf Content-Encoding: base64 20f2 3/30/20073:28 PM ~ ~J ;~ ~-"'" t " ."~ ~ _ ~-..-~ ~~ ~,~ _ ~.,~, ~ ~ ~ ~ ~ ~ ~ ~W ~ ~ ~' ~ ~ ~ ~~ ~ ~ ~ ~ €~~ ~ 6~+ ^ ~.- ~.. G1 p g ~ ~u. ~ { ~~ ~ ~ ~~~ ~ ~ G ~ ~ h ~ ~ ~ ~ ~~ ~ ' ~ ~ ~ ' ~ ~° ~ SEAN PARNELL, GOVERNOR ~ ~ ~ ~ ~ ~~, ~ ~ ~~. .,~ ~ ~y~ ~. ~~~ ~ ~n~~ .~ ~-7~ O.W ~~v-7 333 W. 7th AVENUE, SUITE 100 CO1~T5ERQATIOI~T COMDIISSIOI~T ~ ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 d FAX (907) 276-7542 ADMINISTRATIVE APPROVAL AIO 28.002 Nanuq Oil Pool ADMINISTRATIVE APPROVAL AIO 30.003 Fiord Oil Pool Chris Wilson Supervisor, Western North Slope Base ConocoPhillips Alaska, Inc. P. O. Box 100360 Anchorage, Alaska 99501 Dear Mr. Wilson: By letter dated May 21, 2009, and received by the Alaska Oil & Gas Conservation Commission (Commission) on May 26, 2009, ConocoPhillips Alaska, Inc. (CPAI), on behalf of the working interest owners in the Colville River Unit, requested the Commission remove the miscibility requirement for gas injection and authorize additional fluids for in injection in the Nanuq and Fiord Oil Pools (Application). CPAI's request related to gas injection is GRANTED, with the requirement that the gas injected must be enriched gas. CPAI's request to authorize other fluids is also GRANTED with the stipulations listed below. In the Application, CPAI states that it "expects recovery from the Colville River Field (CRF) will be greater if the miscibility requirement is removed because the total gas volumes available could then be used more efficiently in the field to recover oil." By eliminating the miscibility requirement in the subject Area Injection orders, CPAI will be able to blend a larger volume of enriched gas and thus would have a smaller volume of lean gas to handle. Currently, lean gas is injected into certain wells in the Alpine Oil Pool in order to allow for "black start" capability for the field. Lean gas is also injected into very mature injectionpatterns were no additional benefits to oil recovery would be obtained by continued injection of enriched gas. Reducing the amount of lean gas would reduce the amount of gas injected in patterns contributing little benefit to ultimate recovery and allow a greater volume of enriched gas to be injected in the areas of the field where it will provide additional benefits. Information presented by CPAI demonstrates that ultimate recovery in the CRF will not be harmed by injecting enriched gas in the Nanuq and Fiord Oil Pools that is not fully miscible, provided the total volume of enriching components remains the same. CPAI's application also requests approval of additional fluids for injection in the subject pools. CPAI requests authorization to allow the injection of commingled produced water from the other CRF oil pools in the Nanuq Oil Pool. The Application contains no evidence to demonstrate that the proposed fluids would be compatible with the rock and fluid properties in the pools. However, a water injectivity compatibility study on record with the Commission evaluated the effect of injecting 75 pore-volumes of synthetic Alpine produce water (brine) and synthetic ~ ~ Beaufort Sea brine into core samples from the Fiord, Nanuq, and Nanuq-Kuparuk reservoirs. CPAPs researcher concluded that "...either brine could be injected without injectivity issues."1 Laboratory analysis provided in support of the current application shows that the commingled CRF produced water has a greater chloride composition than Nanuq formation water. Laboratory analysis also shows that the barium concentration in the Nanuq formation water is significantly higher than for the commingled CRF produced water. Additionally, the sulfate concentration in the commingled CRF produced water is significantly higher than in the Nanuq formation water, which creates the possibility of barium sulfate scale deposition in the Nanuq reservoir when commingled produced water is injected. During a phone conversation on July 28, 2009, CPAI stated that the commingled CRF produced water would be treated with scale inhibitor to reduce the chances of scale deposition in the Nanuq reservoir. CPAI also requests authorization to inject sump fluid, hydrotest fluids, rinsate generated from washing mud hauling trucks, excess well work fluids, and treated camp effluent in both the Nanuq and Fiord Oil Pools. Likewise, CPAI has provided no information demonstrating that such fluids would be compatible with the subject pools. However, the volumes of these types of fluids are expected to be very small and the injection of small amounts of such fluids has been authorized by the Commission elsewhere in the CRF.Z Although CPAI will take steps to reduce the possibility of fluid incompatibility between the requested additional fluids and native formation water, it is prudent for the Commission to require additional monitoring of injection to ensure that the Nanuq and Fiord reservoirs will not be damaged. The Commission finds that injecting enriched gas in the Nanuq and Fiord Oil Pools instead of miscible gas, will not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. Additionally, the Commission finds further expansion of the list of authorized injection fluids to include commingled produced water for the Nanuq Oil Pool and sump fluid, hydrotest fluids (excluding fluids derived from tests of transportation pipelines), rinsate generated from washing mud hauling trucks, excess well work fluids, treated camp effluent and mixtures involving such fluids for both the Nanuq and Fiord Oil Pools will not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater, provided the following conditions are met. 1) Commingled produced water shall be treated with scale inhibitors to reduce the possibility of scale deposition in the formation. ~ Hedges, J.H., 2008, Colville [sic] River Field, Alaska: Water Injection Compatibility; ConocoPhillips, Inc., Bartlesville Technical Center, Hed-03-2007, p.l ; document provided in support of AIO 30.002 by ConocoPhillips, Inc. on January 3, 2008. z Alpine Oit Pool under AIO 18B.002; Nanuq-Kuparuk Oil Pool under AIO 27, Rule 4d; Qannik Oil Pool under AIO 35.001. September 23, 2009 Page 2 of 3 ~ ~ 2) CPAI shall monitor injection rates and pressures when injecting commingled produced water into the Nanuq Oil Pool or when injecting sump fluid, hydrotest fluid, rinsate generated from washing mud hauling trucks, excess well work fluids, and treated camp effluent and mixtures involving such fluids into either the Fiord or Nanuq Oil Pools. 3) If the monitoring done under Condition 2 indicates the possibility of loss of injectivity or formation damage, CPAI shall cease injection of such fluids immediately and notify the Commission. CPAI shall not recommence injection of these fluids until authorized by the Commission. The injection of lean gas into the Nanuq and Fiord Oil Poc from the Commission. DONE at Anchorage, Alaska, and dated September 23, 200 Dani~ . Seamount, Jr. 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 until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. September 23, 2009 Page 3 of 3 ~ ~ Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, September 23, 2009 1:03 PM To: 'Aaron Gluzman'; caunderwood@marathonoil.com; 'Dale Hoffman'; Frederic Grenier; 'Gary Orr'; Jerome Eggemeyer; 'Joe Longo'; 'Lamont Frazer'; Marc Kuck; 'Mary Aschoff ; Maurizio Grandi; P Bates; Richard Garrard; 'Sandra Lemke'; 'Scott Nash'; 'Steve Virant'; 'Wayne Wooster'; 'Willem Vollenbrock'; 'William Van Dyke'; Woolf, Wendy C(DNR); 'Anna Raff ;'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Blaine Campbell'; 'Bowen Roberts'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'Cande.Brandow'; 'carol smyth'; 'Charles O'Donnell'; Chris Gay; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David Brown'; 'David Gorney ; David House; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; Deborah Jones; Decker, Paul L(DNR); 'doug_schultze'; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gregg Nady'; 'gspfoff ; 'Hank Alford'; 'Harry Engel'; 'jah'; 'Janet D. Platt'; 'jejones'; 'Jerry Brady'; 'Jerry McCutcheon'; 'Jim Arlington'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; 'Jon Goltz'; Joseph Darrigo; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; knelson@petroleumnews.com; 'Krissell Crandall'; 'Kristin Elowe'; 'Laura SilliphanY; 'mail=akpratts@acsalaska.net'; 'mail=foms@mtaonline.net'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marquerite kremer'; Melanie Brown; 'Michaet Nelson'; 'Mike Bill'; 'Mike Jacobs'; 'Mike Mason'; 'Mikel Schuftz'; 'Mindy ~ewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro'; 'Paul Winslow'; 'peter Contreras'; Rader, Matthew W(DNR}; Raj Nanvaan; 'Randall Kanady'; 'Randy L. Skillern'; 'Rob McWhorter'; rob.g.dragnich@exxonmobil.com; 'Robert Campbel~'; 'Robert Province'; 'Rudy Brueggeman'; 'Sandra Pierce'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P(DNR); Slemons, Jonne; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Ted Rockwell'; 'Temple Davidson'; Teresa Imm; 'Terrie Hubble'; 'Thor Cutler'; 'Todd Durkee'; Tony Hopfinger; 'trmjr1'; 'Von Hutchins'; 'Walter Featherly'; Williamson, Mary J (DNR) Subject: Amendment 28 and 30 (Colville River Unit) Attachments: aio30-003.pdf Jody J. C;'olornbie Specicrl Assistant Alaska Oil cznd Gas Conservation Comrnissios7 333 W'es1 7th Aver~~ue, Suite 100 Anchoruxe, AK ~9501 (907)7~3-1221 (phone) (907)276-7542 (fc~~) 9/23/2009 • i Mary Jones David McCaleb Cindi Walker XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 Mark Wedman Schlumberger Ciri Halliburton Drilling and Measurements Land Department 6900 Arctic Blvd. 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99502 Anchorage, AK 99503 Anchorage, AK 99503 Baker Oil Tools Ivan Gillian Jill Schneider 4730 Business Park Blvd., #44 9649 Musket Bell Cr.#5 US Geological Survey Anchorage, AK 99503 Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Kari 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 ~ ~~~ ~ ~o ~. ~ • 0 O Q 6 SEAN PARNELL, GOVERNOR t�T t��KA OIL A" VrvS 333 W. 7th AVENUE, SUITE 100 CO N SE RVATION ►S IOls COMUSSIO ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 ADMINISTRATIVE APPROVAL AIO 28.003 Mr. Martin Walters Problem Wells Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 -0360 RE: CRU CD4 -209 (PTD 2060650) Request for Administrative Approval Dear Mr. Walters: An application to continue water injection in CRU well CD4 -209 with a known communication was received on October 19, 2010. The injection order and rule citation are incorrect. Injection into the Nanuq Oil Pool is governed by Area Injection Order (AIO) 28, rather than AIO 18 which applies to the Alpine Oil Pool. In accordance with Rule 11 of A10 28.000, the Alaska Oil and Gas Conservation Commission (AOGCC or Commission) hereby GRANTS ConocoPhillips Alaska Inc. (CPAI)'s request for administrative approval to continue water injection in the subject well. Colville River Unit (CRU) CD4 -209 exhibits pressure communication between the production and surface casings (outer annulus or OA). The Commission was notified of the communication in November 2009. Positive pressure tests performed on the well's inner annulus (IA), OA, have identified a leak at 36' below pad level. Although the flow rate through the leak is small, the IA and OA pressures tend to equalize over time. The Commission finds that CPAI does not intend to perform repairs at this time, deferring until a rig workover can be justified. Reported results of CPAI's diagnostic procedures and wellhead pressure trend plots indicate that CRU CD4 -209 exhibits at least two competent barriers to the release of well pressure. Accordingly, the Commission believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC's administrative approval to continue water injection only in CRU CD4 -209 is conditioned upon the following: I 1. CPAI shall record wellhead pressures and injection rate daily; AIO 28.003 • November 1, 2010 Page 2 of 2 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli; 3. CPAI shall perform an MIT -IA every 2 years to 1.2 times the maximum anticipated injection pressure; 4. CPAI shall perform an MIT -OA or IA x OA CMIT every 2 years to 1800 psi; 5. CPAI shall limit IA pressure to 2000 psi and OA pressure to 1000 psi; 6. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 7. After well shut in due to a change in the well's mechanical condition, s� approval shall be required to restart injection, and 8. The MIT anniversary date is November 28, 2009. v DONE at Anchorage, Alaska and dated November 1, 2010. P � `�AIPS!i1e 1 a a,tt Daniel T. Seamount, Jr. Cathy . Foerster Jo an Chair, Commissioner Co issioner ommissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, November 03, 2010 7:22 AM To: (foms2 @mtaon line. net); ( michael .j.nelson @conocophillips.com); (Von. L. Hutchins @conocophillips.com); Alan Dennis; alaska @petrocalc.com; Anna Raff; Barbara F Fullmer; bbritch; Becky Bohrer; Bill Penrose; Bill Walker; Bowen Roberts; Brad McKim; Brady, Jerry L; Brandon Gagnon; Brandow, Cande (ASRC Energy Services); Brian Gillespie; Brian Havelock; Bruce Webb; carol smyth; caunderwood; Chris Gay; Cliff Posey; Crandall, Krissell; dapa; Daryl J. Kleppin; Dave Matthews; David Boelens; David House; David Steingreaber; 'ddonkel @cfl.rr.com'; Deborah J. Jones; Delbridge, Rena E (LAA); 'Dennis Steffy'; Elowe, Kristin; eyancy; Francis S. Sommer; Fred Steece; Garland Robinson; Gary Laughlin; Gary Rogers; Gary Schultz; ghammons; Gordon Pospisil; Gorney, David L.; 'Greg Duggin'; Gregg Nady; gspfoff; Harry Engel; Jdarlington Qarlington @gmail.com); 'Jeanne McPherren'; Jeff Jones; Jeffery B. Jones Qeff.jones @alaska.gov); Jerry McCutcheon; Jill Womack; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John Katz'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'Jon Goltz'; 'Judy Stanek'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kim Cunningham'; 'Larry Ostrovsky'; 'Laura Silliphant'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley (mark.hanley @anadarko.com)'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; 'Michael Dammeyer'; 'Michael Jacobs'; 'Mike Bill'; 'Mike Mason'; 'Mike) Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'nelson'; 'Nick W. Glover'; 'NSK Problem Well Supv'; 'Patty Alfaro'; 'Paul Decker (paul.decker @alaska.gov)'; 'Paul Figel'; 'PORHOLA, STAN T'; 'Randall Kanady'; 'Randy L. Skillern'; ' rob.g. drag nich @exxon mobil. com'; 'Robert Brelsford'; 'Robert Campbell'; 'Rudy Brueggeman'; 'Ryan Tunseth'; 'Scott Cranswick'; 'Scott Griffith'; Scott, David (LAA); 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'tablerk'; Tamera Sheffield; Taylor, Cammy O (DNR); Temple Davidson; Teresa Imm; Terrie Hubble; Thor Cutler; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjr1; Vicki Irwin; Walter Featherly; Will Chinn; Williamson, Mary J (DNR); Yereth Rosen; 'Aaron Gluzman'; Bettis, Patricia K (DNR); 'Dale Hoffman'; David Lenig; 'Gary Orr'; 'Jason Bergerson'; 'Joe Longo'; Marc Kuck; 'Mary Aschoff; 'Matt Gill'; Maurizio Grandi; Ostrovsky, Larry Z (DNR); Richard Garrard; 'Sandra Lemke'; Talib Syed; 'Tiffany Stebbins'; 'Wayne Wooster'; 'William Van Dyke'; Woolf, Wendy C (DNR); Aubert, Winton G (DOA); Ballantine, Tab A (LAW); Brooks, Phoebe; Davies, Stephen F (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Johnson, Elaine M (DOA); Laasch, Linda K (DOA); Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Shartzer, Christine R (DOA) Subject: FW: AIO 213.058, AIO 28.003, AIO 28.038 amended, AIO 9.007 amended, AIO 9.008 amended, AIO 1.009 amended, AIO 1.007 amended Attachments: AIO 2B.058.pdf; AIO 28.003.pdf; AIO 2B.038 amended.pdf; AIO 9.007 amended.pdf; AIO 9.008 amended.pdf; AIO 1.009 amended.pdf; AIO 1.007 amended.pdf A10213-038 AND A10213-058 (KUPARUK RIVER UNIT) A1028 -003 (COLVILLE RIVER UNIT) A109 -007 AND A109 -008 (MIDDLE GROUND SHOAL) A101 -007 AND A101 -009 (DUCK ISLAND UNIT) 1 Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton 408 18 Street President 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Schlumberger CIRI Drilling and Measurements Land Department Baker Oil ho o fs 2525 Gambell St, #400 P.O. Box 93330 795 E. 94 Ct. Anchorage, AK 99515 -4295 Anchorage, AK 99503 Anchorage, AK 99503 North Slope Borough Jill Schneider Gordon Severson US Geological Survey P.O. Box 69 3201 Westmar Circle Barrow, AK 99723 4200 University Drive Anchorage, AK 99508 -4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Cliff Burglin Refuge Manager 399 West Riverview Avenue 319 Charles Street P.O. Box 2139 Soldotna, AK 99669 -7714 Fairbanks, AK 99701 Soldotna, AK 99669 -2139 Richard Wagner Bernie Karl P.O. Box 60868 K &K Recycling Inc. Fairbanks, AK 99706 P.O. Box 58055 Fairbanks, AK 99711 2 ME OF ALASKA SEAN PARNELL, GOVERNOR AI A.7KA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 M CONSERVATION COMMISSION /ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 ADMINISTRATIVE APPROVAL AIO 18C.001 ADMINISTRATIVE APPROVAL AIO 28.003 ADMINISTRATIVE APPROVAL AIO 30.004 ADMINISTRATIVE APPROVAL AIO 35.001 Mr. Jack Walker North Slope Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 RE: Application to Allow Injection of Kuparuk River Unit Produced Water into the Following Oil Pools No. 18C Alpine Oil Pool No. 28 Nanuq Oil Pool No. 30 Fiord Oil Pool No. 35 Qannik Oil Pool Colville River Field Dear Mr. Walker: In accordance with Rule 11 of Area Injection Orders (AIO) 18C, 28, and 30, respectively governing the Alpine Oil Pool, Nanuq Oil Pool, and Fiord Oil Pool, and Rule 10 of AIO 35 governing the Qannik Oil Pool, the Alaska Oil and Gas Conservation Commission (Commission) CONDITIONALLY GRANTS ConocoPhillips Alaska, Inc.'s (CPAI) request for administrative approval to inject produced water from the Kuparuk River Unit (KRU) into the aforementioned oil pools. Due to a fuel gas line failure, the CPAI- operated seawater treatment plant in the KRU is unable to move seawater to the Colville River Field (CRF). In order to prevent the seawater transport pipeline from freezing, CPAI has begun to displace the line with warmer produced water from the KRU. CPAI expects the displacing operation to require approximately 26,000 bbls of produced water obtained from the CPF -2 facility in the KRU. Once the seawater treatment plant is back in operation, CPAI will begin shipping seawater to the CRF again and thus displace the KRU produced water that will be occupying the seawater transport pipeline. Currently, the aforementioned AIOs, as amended, do not authorize injection of produced water from the KRU for enhanced recovery purposes, so the only option currently available to accommodate the AIO 18C.001 • AIO 28.003 AIO 30.004 AIO 35.001 November 5, 2010 Page 2 of 3 produced water from the KRU is to inject it into one or both of the Class I disposal wells in the CRF. These two wells don't have a high injection rate capability, so it would take several days to completely purge the seawater pipeline of KRU produced water. As such CPAI has requested authorization to inject the KRU produced water into the aforementioned oil pools for enhanced recovery purposes. CPAI has provided compositional analyses produced water from the KRU and CRF as l ses of the C p p Y p well as compositional analysis of the Beaufort seawater shipped to the CRF. The composition of the KRU produced water is very similar to the CRF produced water, so there should not be any formation compatibility issues with injection of this water. There are some differences between the KRU produced water and the Beaufort seawater that could lead to scale deposition, however the use of scale inhibitors and the small relative volume for the produced water to be injected, 26,000 bbls versus the normal monthly injection volume of 3 mmbbls, should result in negligible amount of scale deposition. The Commission has determined that the proposed action does not require notice and public hearing, will not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. Therefore, in accordance with Rule 11 of AIOs 18C, 28, and 30, and Rule 10 of AIO 35, the Commission administratively amends the orders to authorize the injection of up to 30,000 barrels of KRU produced water for enhanced oil recovery purposes. CPAI must use an appropriate scale inhibitor to minimize the possibility of formation damage due to scale deposition when mixing of KRU produced water and Beaufort seawater from the seawater treatment plant. This administrative approval does not exempt CPAI from obtaining additional permits or approvals required by law from other governmental agencies. t ENTERED at Anchorage, 4s ka, d vember 5, 2010. '�Y 4 an4iT. Sea ount, Jr. Cathy P. Foer ster � ' � ti � ,, ��Chair Commissioner 1. ` AIO 18C.001 • AIO 28.003 AIO 30.004 AIO 35.001 November 5, 2010 Page 3 of 3 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 period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Fisher, Samantha J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, November 05, 2010 4:04 PM To: Aaron Gluzman; Bettis, Patricia K (DNR); caunderwood @marathonoil.com; Dale Hoffman; David Lenig; Gary Orr; Jason Bergerson; Joe Longo; Lara Coates; Marc Kuck; Mary Aschoff; Matt Gill; Maurizio Grandi; Ostrovsky, Larry Z (DNR); Richard Garrard; Sandra Lemke; Talib Syed; Tiffany Stebbins; Wayne Wooster; William Van Dyke; Woolf, Wendy C (DNR); (foms2 @mtaon line. net); ( michael .j.nelson @conocophillips.com); (Von. L. Hutchins@conocophillips.com); AKDCWelllntegrityCoordinator; Dennis, Alan R (DNR); alaska @petrocalc.com; Anna Raff; Barbara F Fullmer; bbritch; Becky Bohrer; Bill Penrose; Bill Walker; Bowen Roberts; Brad McKim; Brady, Jerry L; Brandon Gagnon; Brandow, Cande (ASRC Energy Services); Brian Gillespie; Brian Havelock; Bruce Webb; carol smyth; Chris Gay; Cliff Posey; Crandall, Krissell; dapa; Daryl J. Kleppin; Dave Matthews; David Boelens; David House; David Steingreaber; ddonkel @cfl.rr.com; Deborah J. Jones; Delbridge, Rena E (LAA); Dennis Steffy; Elowe, Kristin; eyancy; Francis S. Sommer; Fred Steece; Garland Robinson; Gary Laughlin; Rogers, Gary A (DNR); Gary Schultz; ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; gspfoff; Harry Engel; Jdarlington Qarlington @g mail. com); Jeanne McPherren; jeff.jones @alaskajournal.com; Jones, Jeffery B (DOA); Jerry McCutcheon; Jill Womack; Jim White; Jim Winegarner; news @radiokenai.com; John Garing; Katz, John W (GOV); John S. Haworth; John Spain; John Tower; Jon Goltz; Judy Stanek; Julie Houle; Kari Moriarty; Kaynell Zeman; Keith Wiles; Kim Cunningham; Ostrovsky, Larry Z (DNR); Laura Silliphant; crockett @aoga.org; Mark Dalton; Mark Hanley (mark.hanley @anadarko.com); Mark Kovac; Mark P. Worcester; Marquerite kremer; Michael Dammeyer; Michael Jacobs; Mike Bill; mike @kbbi.org; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; knelson @petroleumnews.com; Nick W. Glover; NSK Problem Well Supv; Patty Alfaro; Decker, Paul L (DNR); Paul Figel; PORHOLA, STAN T; Randall Kanady; Randy L. Skillern; rob.g.dragnich @exxonmobil.com; Robert Brelsford; Robert Campbell; Rudy Brueggeman; Ryan Tunseth; Scott Cranswick; Scott Griffith; Scott, David (LAA); Shannon Donnelly; Sharmaine Copeland; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Sondra Stewman; Steve Lambert; Steve Moothart; Steven R. Rossberg; Suzanne Gibson; tablerk; sheffield @aoga.org; Taylor, Cammy O (DNR); Temple Davidson; Teresa Imm; Terrie Hubble; Thor Cutler; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjrl; Vicki Irwin; Walter Featherly; Will Chinn; Williamson, Mary J (DNR); yjrosen @ak.net; Aubert, Winton G (DOA); Ballantine, Tab A (LAW); Brooks, Phoebe L (DOA); Davies, Stephen F (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Johnson, Elaine M (DOA); Laasch, Linda K (DOA); Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Shartzer, Christine R (DOA) Subject: aio18 -001, aio 28 -003, aio 30 -004 and aio35 -001 (All within the Kuparuk River Unit) Attachments: aiol8c -001, aio 28 -003, aio30 -004 and aio 35 -001 KRU.pdf Jody J. Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 (907)793 -1221 (phone) (907)276 -7542 (fax) 1 Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton 408 18 Street President 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI K &K Recycling Inc. Land Department Baker Oil ho o ts P.O. Box 58055 P.O. Box 93330 795 E. 94 Ct. Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Jill Schneider US Geological Survey Gordon Severson P.O. Box 69 3201 Westmar Circle Barrow, AK 99723 4200 University Drive Anchorage, AK 99508 -4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Cliff Burglin Refuge Manager 399 W est Riverview Avenue 319 Charles Street P.O. Box 2139 Soldotna, AK 99669 -7714 Fairbanks, AK 99701 Soldotna, AK 99669 -2139 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 GOVERNOR BILL WALKER March 30, 2017 Ms. Kelly Lyons 44Z o 2-`6 Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-17-009 Alaska Oil and Gas r� l 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc,alaska.gov .� rvl 9 ✓lCi CL Request to amend the Mechanical Integrity Testing (MIT) anniversary date for 97 wells which operate under existing administrative approvals. Request to amend the required MIT pressure criteria for six wells which operate under existing administrative approvals. Area Injection Orders 213, 2C, 16, 18B, 18C, 28 and 30 Kuparuk River Unit and Colville River Unit Dear Ms. Lyons: By letter dated February 23, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to change the MIT anniversary date on 97 wells to align with the established CPAI Underground Injection Control MIT permanent test schedule for pad testing. CPAI also requested an amendment to the required MIT pressure criteria for six wells. In accordance with Rule 9 of Area Injection Order (AIO) 0213.000, Rule 10 of AIO 16, and Rule 11 of AIO 2C, 18B, 18C, 28, and 30, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for administrative approval to amend the MIT anniversary date for the 97 wells and amend the required MIT pressure criteria for the six wells as detailed in the accompanying tables. CPAI has been working with AOGCC since late 2015 and submitted a proposal to AOGCC on March 26, 2016 looking to consolidate well testing to the established pad testing schedule which has an emphasis on summer months May through August. CPAI has been looking for efficiencies by scheduling and completing the multiple well tests required in a pad by pad sequence averaged over a four-year workload. Over the last twelve months the CPAI well integrity team has coordinated with AOGCC inspectors to witness multiple well tests and both have identified efficiencies in utilizing this pad schedule. The administrative action rules contained within the Area Injection Orders allow the AOGCC to administratively waive or amend the requirements of any rule as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. DONE at Anchorage, Alaska and dated March 30, 2017. Cathy/ . Foerster 115aniel T. Seamount, Jr. Hollis French 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. 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. PTD # Well name AIO # New Anniversary Test Month 1981630 KUPARUK RIV U TARN 2N-325 AIO 16.001 August 2018 1982400 KUPARUK RIV U TARN 2L-305 AIO 16.002 August 2018 2071120 KUPARUK RIV U TARN 2L-319 AIO 16.003 August 2018 2100280 KUPARUK RIV U TARN 2L-310 AIO 16.004 August 2018 1982510 KUPARUK RIV U TARN 2L-323 AIO 16.005 August 2018 2032250 COLVILLE RIV UNIT CD1-07 AIO 18B.006 June 2017 2010060 COLVILLE RIV UNIT CD1-21 AIO 18B.007 June 2017 2061420 COLVILLE RIV NAWK CD4-321 AIO 18C.002 June 2017 2061180 COLVILLE RIV UNIT CD4-17 AIO 18C.003 June 2017 2040240 COLVILLE RIV UNIT CD1-46 AIO 18C.004 June 2017 2071010 COLVILLE RIV NAWK CD4-322 AIO 18C.005 June 2017 2010380 COLVILLE RIV UNIT CD1-14 AIO 18C.006 June 2017 2060650 COLVILLE RIV NAWN CD4-209 AIO 28.003 June 2017 1851090 KUPARUK RIV UNIT 2Z-16 AIO 213.002 August 2015 1960900 KUPARUK RIV UNIT 2M-09A AIO 26.004 June 2016 1951930 KUPARUK RIV UNIT 3Q-21 AIO 213.005 August 2018 1830960 KUPARUK RIV UNIT 2C-07 AIO 26.007 August 2015 2001940 KUPARUK RIV UNIT 1A-04A AIO 2B.011 July 2017 1951810 KUPARUK RIV UNIT 311-25 AIO 26.012 August 2018 2000260 KUPARUK RIV UNIT 3K-22A AIO 2B.013 May 2017 1881200 KUPARUK RIV UNIT 2K-03 AIO 26.016 June 2017 1890590 KUPARUK RIV UNIT 2K-10 AIO 26.017 June 2017 1861960 KUPARUK RIV UNIT 3Q-05 AIO 213.019 August 2018 1841060 KUPARUK RIV UNIT 2G-10 AIO 26.030 May 2018 1880590 KUPARUK RIV UNIT 30-10 AIO 213.033 June 2017 1821300 KUPARUK RIV UNIT 1G-01 AIO 26.035 July 2017 1841510 KUPARUK RIV UNIT 2D-04 AIO 26.037 August 2017 1831560 KUPARUK RIV UNIT 2F-13 AIO 26.039 July 2018 1861780 KUPARUK RIV UNIT 3Q-15 AIO 213.042 August 2018 1890740 KUPARUK RIV UNIT 2K-12 AIO 213.048 June 2017 1811780 KUPARUK RIV UNIT 1A-12 AIO 2B.049 July 2017 1830520 KUPARUK RIV UNIT 1Y-09 AIO 26.051 July 2017 1841520 KUPARUK RIV UNIT 2D-02 AIO 213.052 August 2017 1841230 KUPARUK RIV UNIT 1L-05 AIO 26.054 June 2018 1831760 KUPARUK RIV UNIT 2V-05 AIO 26.055 June 2018 1830620 KUPARUK RIV UNIT 1Y-08 AIO 213.056 July 2017 2100490 KUPARUK RIV UNIT 3N-16A AIO 213.057 August 2018 1811360 KUPARUK RIV UNIT 16-11 AIO 26.060 June 2017 1861640 KUPARUK RIV UNIT 3K-11 AIO 26.061 May 2017 1852280 KUPARUK RIV UNIT 3F-04 AIO 26.063 June 2017 1831070 KUPARUK RIV UNIT 2X-05 AIO 26.064 June 2017 2101810 KUPARUK RIV UNIT 1E-08A AIO 213.065 June 2018 1950920 KUPARUK RIV UNIT 2T-28 AIO 2B.066 June 2017 1851140 KUPARUK RIV UNIT 36-10 AIO 26.067 June 2017 1911250 KUPARUK RIV UNIT 3Q-01 AIO 213.068 August 2018 1841010 KUPARUK RIV UNIT 2D-10 AIO 2B.070 August 2017 1831610 KUPARUK RIV UNIT 2V-02 AIO 26.071 June 2017 2120950 IKUPARUK RIV UNIT 3N-11A AIO 26.072 August 2018 1840290 IKUPARUK RIV UNIT 213-10 AIO 26.073 May 2018 1831870 KUPARUK RIV UNIT 2F-04 AIO 26.074 July 2018 1820310 KUPARUK RIV UNIT IA-16RD AIO 2B.075 July 2017 1840960 KUPARUK RIV UNIT 21-1-13 AIO 26.076 May 2018 1822140 KUPARUK RIV UNIT 1E-22 AIO 26.078 June 2018 1821320 KUPARUK RIV UNIT 1F-05 AIO 26.080 June 2018 2100130 KUPARUK RIV UNIT 1E-15A AIO 26.081 June 2018 1861790 KUPARUK RIV UNIT 3Q-16 AIO 26.082 August 2018 1900350 KUPARUK RIV UNIT 1L-10 AIO 26.083 June 2018 1850180 KUPARUK RIV UNIT 2U-05 AIO 26.084 August 2018 1830890 KUPARUK RIV UNIT 2C-03 AIO 26.085 August 2017 1830950 KUPARUK RIV UNIT 2C-08 AIO 26.086 August 2017 1852460 KUPARUK RIV UNIT 3F-08 AIO 26.087 June 2017 1851520 KUPARUK RIV UNIT 111-15 AIO 26.088 May 2017 1852720 KUPARUK RIV UNIT 3F-11 AIO 26.089 June 2017 1850440 KUPARUK RIV UNIT 1Q-13 AIO 26.090 July 2017 1830940 KUPARUK RIV UNIT 2C-04 AIO 26.091 August 2015 1860960 KUPARUK RIV UNIT 2T-10 AIO 213.092 June 2017 1841920 KUPARUK RIV UNIT 1Q-09 AIO 213.093 July 2017 1861410 KUPARUK RIV UNIT 2T-02 AIO 2C.001 June 2017 1861890 KUPARUK RIV UNIT 3Q-12 AIO 2C.002 August 2018 1870780 KUPARUK RIV UNIT 31-1-06 AIO 2C.003 June 2017 1901320 KUPARUK RIV UNIT 3G-23 AIO 2C.004 August 2017 1850750 KUPARUK RIV UNIT 36-05 AIO 2C.005 June 2017 1821720 KUPARUK RIV UNIT 1F-04 AIO 2C.006 June 2018 2140470 KUPARUK RIV UNIT 2T-32A AIO 2C.007 June 2017 1841450 KUPARUK RIV UNIT 1L-07 AIO 2C.008 June 2018 1840700 KUPARUK RIV UNIT 21-1-03 AIO 2C.009 May 2018 2000770 KUPARUK RIV UNIT 1D-38 AIO 2C.010 July 2018 1901210 KUPARUK RIV UNIT 3G-15 AIO 2C.011 August 2017 1840220 KUPARUK RIV UNIT 26-06 AIO 2C.012 May 2018 1852160 KUPARUK RIV UNIT 3J-08 AIO 2C.013 July 2018 1830510 KUPARUK RIV UNIT 1Y-10 AIO 2C.014 July 2017 1840860 KUPARUK RIV UNIT 21-1-15 AIO 2C.015 May 2018 1870790 KUPARUK RIV UNIT 3H-07 AIO 2C.016 June 2017 1951210 KUPARUK RIV UNIT 1Q-24 AIO 2C.017 July 2017 2012090 KUPARUK RIV UNIT 1F-16A AIO 2C.018 June 2018 1841180 KUPARUK RIV UNIT 2G-01 AIO 2C.019 May 2018 1911320 KUPARUK RIV UNIT 2M-19 AIO 2C.020 June 2018 1920710 KUPARUK RIV UNIT 2M-27 AIO 2C.021 June 2018 1950170 KUPARUK RIV UNIT 2T-18 AIO 2C.023 June 2017 1840240 KUPARUK RIV UNIT 26-07 AIO 2C.024 May 2018 1851160 KUPARUK RIV UNIT 313-12 AIO 2C.025 June 2017 1880290 KUPARUK RIV UNIT 30-17 AIO 2C.026 June 2017 1971120 KUPARUK RIV UNIT 16-08A AIO 2C.027 June 2017 1850770 KUPARUK RIV UNIT 36-07 AIO 2C.028 June 2017 1840800 KUPARUK RIV UNIT 2G-05 AIO 2C.029 May 2016 2100310 COLVILLE RIV FIORD CD3-123 AIO 30.005 February 2018 2110240 COLVILLE RIV FIORD CD3-198 AIO 30.006 February 2018 PTD # Well name AIO # Amended MIT pressure criteria CPAI shall perform an MIT -IA every 2 years to the maximum 2060650 COLVILLE RIV NAN-N CD4-209 AIO 28.003 anticipated injection pressure. CPAI shall perform an MIT -IA every 2 years to the maximum 1881200 KUPARUK RIV UNIT 2K-03 AIO 26.016 anticipated injection pressure. CPAI shall perform an MIT -IA every 2 years to the maximum 1890590 KUPARUK RIV UNIT 2K-10 AIO 26.017 anticipated injection pressure. CPAI shall perform an MIT -IA every 2 years to the maximum 1861960 KUPARUK RIV UNIT 3Q-05 AIO 26.019 anticipated injection pressure. CPAI shall perform an MIT -IA every 2 years to the maximum 1811360 KUPARUK RIV UNIT 1B-11 AIO 26.060 anticipated injection pressure. CPAI shall perform an MIT -IA every 2 years to the maximum 1861640 KUPARUK RIV UNIT 3K-11 AIO 213.061 anticipated injection pressure. Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov March 30, 2017 Ms. Kelly Lyons -4�L 0 2� 3 Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-17-009 Request to amend the Mechanical Integrity Testing (MIT) anniversary date for 97 wells which operate under existing administrative approvals. Request to amend the required MIT pressure criteria for six wells which operate under existing administrative approvals. Area Injection Orders 2B, 2C, 16, 18B, 18C, 28 and 30 Kuparuk River Unit and Colville River Unit Dear Ms. Lyons: By letter dated February 23, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to change the MIT anniversary date on 97 wells to align with the established CPAI Underground Injection Control MIT permanent test schedule for pad testing. CPAI also requested an amendment to the required MIT pressure criteria for six wells. In accordance with Rule 9 of Area Injection Order (AIO) 02B.000, Rule 10 of AIO 16, and Rule 11 of AID 2C,18B,18C, 28, and 30, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for administrative approval to amend the MIT anniversary date for the 97 wells and amend the required MIT pressure criteria for the six wells as detailed in the accompanying tables. CPAI has been working with AOGCC since late 2015 and submitted a proposal to AOGCC on March 26, 2016 looking to consolidate well testing to the established pad testing schedule which has an emphasis on summer months May through August. CPAI has been looking for efficiencies by scheduling and completing the multiple well tests required in a pad by pad sequence averaged over a four-year workload. Over the last twelve months the CPAI well integrity team has coordinated with AOGCC inspectors to witness multiple well tests and both have identified efficiencies in utilizing this pad schedule. The administrative action rules contained within the Area Injection Orders allow the AOGCC to administratively waive or amend the requirements of any rule as long as the change does not promote waste of jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. DONE at Anchorage, Alaska and dated March 30, 2017. //signature on file// //signature on file// //signature on file// Cathy P. Foerster Daniel T. Seamount, Jr. Hollis French Chair, Commissioner Commissioner Commissioner AND APPEAL 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. PTD # Well name AIO # New Anniversary Test Month 1981630 KUPARUK RIV U TARN 2N-325 AIO 16.001 August 2018 1982400 KUPARUK RIV U TARN 2L-305 A1016.002 August 2018 2071120 KUPARUK RIV U TARN 2L-319 AIO 16.003 August 2018 2100280 KUPARUK RIV U TARN 2L-310 AIO 16.004 August 2018 1982510 KUPARUK RIV U TARN 2L-323 AIO 16.005 August 2018 2032250 COLVILLE RIV UNIT CD1-07 AIO 18B.006 June 2017 2010060 COLVILLE RIV UNIT CD1-21 AIO 18B.007 June 2017 2061420 ICOLVILLE RIV NAWK CD4-321 AIO 18C.002 June 2017 2061180 COLVILLE RIV UNIT CD4-17 AIO 18C.003 June 2017 2040240 COLVILLE RIV UNIT CD1-46 AIO 18C.004 June 2017 2071010 COLVILLE RIV NAWK CD4-322 AIO 18C.005 June 2017 2010380 COLVILLE RIV UNIT CD1-14 AIO 18C.006 June 2017 2060650 COLVILLE RIV NAWN CD4-209 AIO 28.003 June 2017 1851090 KUPARUK RIV UNIT 2Z-16 AIO 2B.002 August 2015 1960900 KUPARUK RIV UNIT 2M-09A AIO 26.004 June 2016 1951930 KUPARUK RIV UNIT 3Q 21 AIO 2B.005 August 2018 1830960 KUPARUK RIV UNIT 2C-07 AIO 2B.007 August 2015 2001940 KUPARUK RIV UNIT 1A-04A AIO 2B.0I I July 2017 1951810 KUPARUK RIV UNIT 311-25 AIO 213.012 August 2018 2000260 KUPARUK RIV UNIT 3K-22A AIO 213.013 May 2017 1881200 KUPARUK RIV UNIT 2K-03 AIO 2B.016 June 2017 1890590 KUPARUK RIV UNIT 2K-10 AIO 2B.017 June 2017 1861960 KUPARUK RIV UNIT 3Q-05 AIO 26.019 August 2018 1841060 KUPARUK RIV UNIT 2G-10 AIO 26.030 May 2018 1880590 KUPARUK RIV UNIT 30-10 AIO 213.033 June 2017 1821300 KUPARUK RIV UNIT 1G-01 AIO 213.035 July 2017 1841510 KUPARUK RIV UNIT 2D-04 AIO 26.037 August 2017 1831560 KUPARUK RIV UNIT 2F-13 AIO 26.039 July 2018 1861780 KUPARUK RIV UNIT 3Q-15 AIO 213.042 August 2018 1890740 KUPARUK RIV UNIT 2K-12 AIO 213.048 June 2017 1811780 KUPARUK RIV UNIT 1A-12 A10 2B.049 July 2017 1830520 KUPARUK RIV UNIT 1Y-09 AIO 26.051 July 2017 1841520 KUPARUK RIV UNIT 2D-02 AIO 2B.052 August 2017 1841230 KUPARUK RIV UNIT 1L-05 AIO 213.054 June 2018 1831760 KUPARUK RIV UNIT 2V-05 AIO 26.055 June 2018 1830620 KUPARUK RIV UNIT 1Y-08 AIO 213.056 July 2017 2100490 KUPARUK RIV UNIT 3N-16A AIO 213.057 August 2018 1811360 KUPARUK RIV UNIT 16-11 AIO 213.060 June 2017 1861640 KUPARUK RIV UNIT 3K-11 AIO 26.061 May 2017 1852280 KUPARUK RIV UNIT 3F-04 AIO 26.063 June 2017 1831070 KUPARUK RIV UNIT 2X-05 AIO 26.064 June 2017 2101810 KUPARUK RIV UNIT 1E-08A AIO 26.065 June 2018 1950920 KUPARUK RIV UNIT 2T-28 AIO 28.066 June 2017 1851140 KUPARUK RIV UNIT 36-10 AIO 26.067 June 2017 1911250 KUPARUK RIV UNIT 3Q 01 AIO 213.068 August 2018 1841010 KUPARUK RIV UNIT 2D-10 AIO 213.070 August 2017 1831610 KUPARUK RIV UNIT 2V-02 AIO 2B.071 June 2017 2120950 KUPARUK RIV UNIT 3N-11A AIO 2B.072 August 2018 1840290 KUPARUK RIV UNIT 213-10 AIO 2B.073 May 2018 1831870 KUPARUK RIV UNIT 2F-04 AIO 2B.074 July 2018 1820310 KUPARUK RIV UNIT 1A-16RD A10 2B.075 July 2017 1840960 KUPARUK RIV UNIT 21-1-13 AIO 213.076 May 2018 1822140 KUPARUK RIV UNIT 1E-22 AIO 213.078 June 2018 1821320 KUPARUK RIV UNIT 1F-05 AIO 213.080 June 2018 2100130 KUPARUK RIV UNIT 1E-15A AIO 26.081 June 2018 1861790 KUPARUK RIV UNIT 3Q-16 AIO 213.082 August 2018 1900350 KUPARUK RIV UNIT 1L-10 AIO 213.083 June 2018 1850180 KUPARUK RIV UNIT 2U-05 AIO 26.084 August 2018 1830890 KUPARUK RIV UNIT 2C-03 AIO 26.085 August 2017 1830950 KUPARUK RIV UNIT 2C-08 AIO 26.086 August 2017 1852460 KUPARUK RIV UNIT 3F-08 AIO 26.087 June 2017 1851520 KUPARUK RIV UNIT 111-15 AIO 26.088 May 2017 1852720 KUPARUK RIV UNIT 3F-11 AIO 213.089 June 2017 1850440 KUPARUK RIV UNIT 1Q-13 AIO 26.090 July 2017 1830940 KUPARUK RIV UNIT 2C-04 AIO 213.091 August 2015 1860960 KUPARUK RIV UNIT 2T-10 AIO 2B.092 June 2017 1841920 KUPARUK RIV UNIT 1Q-09 AIO 213.093 July 2017 1861410 KUPARUK RIV UNIT 2T-02 AIO 2C.001 June 2017 1861890 KUPARUK RIV UNIT 3Q 12 AIO 2C.002 August 2018 1870780 KUPARUK RIV UNIT 31-1-06 AIO 2C.003 June 2017 1901320 KUPARUK RIV UNIT 3G-23 AIO 2C.004 August 2017 1850750 KUPARUK RIV UNIT 313-05 AIO 2C.005 June 2017 1821720 KUPARUK RIV UNIT IF-04 AIO 2C.006 June 2018 2140470 KUPARUK RIV UNIT 2T-32A AIO 2C.007 June 2017 1841450 KUPARUK RIV UNIT 1L-07 AIO 2C.008 June 2018 1840700 KUPARUK RIV UNIT 21-1-03 AIO 2C.009 May 2018 2000770 KUPARUK RIV UNIT 1D-38 AIO 2C.010 July 2018 1901210 KUPARUK RIV UNIT 3G-15 AIO 2C.011 August 2017 1840220 KUPARUK RIV UNIT 213-06 AIO 2C.012 May 2018 1852160 KUPARUK RIV UNIT 3J-08 AIO 2C.013 July 2018 1830510 KUPARUK RIV UNIT 1y-10 AIO 2C.014 July 2017 1840860 KUPARUK RIV UNIT 2H-15 AIO 2C.015 May 2018 1870790 KUPARUK RIV UNIT 31-1-07 AIO 2C.016 June 2017 1951210 KUPARUK RIV UNIT 1Q 24 AIO 2C.017 July 2017 2012090 KUPARUK RIV UNIT IF-16A AIO 2C.018 June 2018 1841180 KUPARUK RIV UNIT 2G-01 AIO 2C.019 May 2018 1911320 KUPARUK RIV UNIT 2M-19 AIO 2C.020 June 2018 1920710 KUPARUK RIV UNIT 2M-27 AIO 2C.021 June 2018 1950170 KUPARUK RIV UNIT 2T-18 AIO 2C.023 June 2017 1840240 KUPARUK RIV UNIT 213-07 AIO 2C.024 May 2018 1851160 KUPARUK RIV UNIT 36-12 AIO 2C.025 June 2017 1880290 KUPARUK RIV UNIT 30-17 AIO 2C.026 June 2017 1971120 KUPARUK RIV UNIT 16-08A AIO 2C.027 June 2017 1850770 KUPARUK RIV UNIT 36-07 AIO 2C.028 June 2017 1840800 KUPARUK RIV UNIT 2G-05 AIO 2C.029 May 2016 2100310 COLVILLE RIV FIORD CD3-123 AIO 30.005 February 2018 2110240 ICOLVILLE RIV FIORD CD3-198 AIO 30.006 February 2018 PTD # Well name AlO # Amended MIT Pressure criteria CPAI shall perform an MIT -IA every 2 years to the maximum 2060650 COLVILLE RIV NAWN CD4-209 AIO 28.003 anticipated injection pressure. CPAI shall perform an MIT -IA every 2 years to the maximum 1881200 KUPARUK RIV UNIT 2K-03 AIO 26.016 anticipated injection pressure. CPAI shall perform an MIT -IA every 2 years to the maximum 1890590 KUPARUK RIV UNIT 2K-10 AIO 213.017 anticipated injection pressure. CPAI shall perform an MIT -IA every 2 years to the maximum 1861960 KUPARUK RIV UNIT 3Q-05 AIO 2B.019 anticipated injection pressure. CPAI shall perform an MIT -IA every 2 years to the maximum 1811360 KUPARUK RIV UNIT 16-11 AIO 213.060 anticipated injection pressure. CPAI shall perform an MIT -IA every 2 years to the maximum 1861640 KUPARUK RIV UNIT 3K-11 AIO 26.061 1 anticipated injection pressure. Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711-0055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639-0309 Fairbanks, AK 99706-0868 Singh, Angela K (DOA) From: Colombie, Jody 1(DOA) Sent: Thursday, March 30, 20171:37 PM To: DOA AOGCC Prudhoe Bay, Bender, Makana K (DOA); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Paladijczuk, Trade L (DOA); Pasqua[, Maria (DOA); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity, AKDCWel[IntegrityCoordinator, Alan Bailey, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew Vandedack; Ann Danielson; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Ben Boettger, Bill Bredar, Bob Shavelson; Brandon Viator, Brian Havelock; Bruce Webb; Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Colleen Miller, Connie Downing; Crandall, Krissell; D Lawrence; Dale Hoffman; Darci Horner, Dave Harbour, David Boelens; David Duffy, David House; David McCaleb; David McCraine, David Tetta; ddonkel@cfl.rr.com; DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Elwood Brehmer, Evan Osborne, Evans, John R (LDZX); George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff, Hunter Cox; Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose, Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Watt, Jim White; Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); John Stuart, Jon Goltz, Chmielowski, Josef (DNR); Juanita Lovett; Judy Stanek, Kari Moriarty, Kasper Kowalewski; Kazeem Adegbola; Keith Torrance, Keith Wiles; Kelly Sperback; Frank, Kevin J (DNR); Kruse, Rebecca D (DNR); Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; MJ Loveland; mkm7200; Motteram, Luke A, Mueller, Marta R (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shahla Farzan; Shannon Donnelly, Sharon Yarawsky, Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Stephanie Klemmer, Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Ted Kramer, Teresa Imm; Thor Cutler, Tim Jones, Tim Mayers; Todd Durkee, trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Well Integrity, Well Integrity, Weston Nash; Whitney Pettus, Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Assmann, Aaron A; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Catie Quinn; Corey Munk; Don Shaw, Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Holly Pearen; Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Laney Vazquez, Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, lames M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW); Wayne Wooster, William Van Dyke Subject: Various Administrative Approvals for ConocoPhillips and Hilcorp Alaska Attachments: co462.007.pdf, MIT schedule 2017 approval.pdf, Anniversary dates 2017 attachment.pdf Please see attached. Re: Docket Number: CO-17-001 Application to administratively amend Rule 3 of Conservation Order No. 462 Duck Island Unit Endicott Oil Pool Re: Docket Number: AIO-17-009 Request to amend the Mechanical Integrity Testing (MIT) anniversary date for 97 wells which operate under existing administrative approvals. Request to amend the required MIT pressure criteria for six wells which operate under existing administrative approvals. Area Injection Orders 2B, 2C, 16, 18B, 18C, 28 and 30 Kuparuk River Unit and Colville River Unit Jody -1. Cotornbie _AUCC'C` Specia('�ssistant Alaska oil and t7as Con7servati()n ('orrinlission 333 West 7" Avenue Am ho)-age, -Alaska c)9)5oi Office: (()07) 793-1221 .)-ax: (007) 276-7542 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 Jody Colombie at 907.793.1221 or iody.colombie@alaska.gov. A l li T E OT AIASKIA SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 CORRECTED ADMINISTRATIVE APPROVAL AIO 18C.001 ADMINISTRATIVE APPROVAL AIO 28.004 ADMINISTRATIVE APPROVAL AIO 30.004 ADMINISTRATIVE APPROVAL AIO 35.002 Mr. Jack Walker North Slope Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 RE: Application to Allow Injection of Kuparuk River Unit Produced Water into the Following Oil Pools No. 18C Alpine Oil Pool No. 28 Nanuq Oil Pool No. 30 Fiord Oil Pool No. 35 Qannik Oil Pool Colville River Field Dear Mr. Walker: The Commission has corrected the Administrative Approval to reflect the correct number in AIO 28 and AIO 35. In accordance with Rule 11 of Area Injection Orders (AIO) 18C, 28, and 30, respectively governing the Alpine Oil Pool, Nanuq Oil Pool, and Fiord Oil Pool, and Rule 10 of AIO 35 governing the Qannik Oil Pool, the Alaska Oil and Gas Conservation Commission (Commission) CONDITIONALLY GRANTS ConocoPhillips Alaska, Inc.'s (CPAI) request for administrative approval to inject produced water from the Kuparuk River Unit (KRU) into the aforementioned oil pools. Due to a fuel gas line failure, the CPAI- operated seawater treatment plant in the KRU is unable to move seawater to the Colville River Field (CRF). In order to prevent the seawater transport pipeline from freezing, CPAI has begun to displace the line with warmer produced water from the KRU. CPAI expects the displacing operation to require approximately 26,000 bbls of produced water obtained from the CPF -2 facility in the KRU. Once the seawater treatment plant is back in operation, CPAI will begin shipping seawater to the CRF again and thus displace the KRU produced water that will be occupying the seawater transport pipeline. Currently, the aforementioned AIOs, as amended, do not authorize injection of produced water from the KRU AIO 18C.001 • • AIO 28.004 A10 30.004 AIO 35.002 December 2, 2010 Page 2 of 3 for enhanced recovery purposes, so the only option currently available to accommodate the produced water from the KRU is to inject it into one or both of the Class I disposal wells in the CRF. These two wells don't have a high injection rate capability, so it would take several days to completely purge the seawater pipeline of KRU produced water. As such CPAI has requested authorization to inject the KRU produced water into the aforementioned oil pools for enhanced recovery purposes. CPAI has provided compositional analyses of the produced water from the KRU and CRF as well as compositional analysis of the Beaufort seawater shipped to the CRF. The composition of the KRU produced water is very similar to the CRF produced water, so there should not be any formation compatibility issues with injection of this water. There are some differences between the KRU produced water and the Beaufort seawater that could lead to scale deposition, however the use of scale inhibitors and the small relative volume for the produced water to be injected, 26,000 bbls versus the normal monthly injection volume of 3 mmbbls, should result in negligible amount of scale deposition. The Commission has determined that the proposed action does not require notice and public hearing, will not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. Therefore, in accordance with Rule 11 of AIOs 18C, 28, and 30, and Rule 10 of AIO 35, the Commission administratively amends the orders to authorize the injection of up to 30,000 barrels of KRU produced water for enhanced oil recovery purposes. CPAI must use an appropriate scale inhibitor to minimize the possibility of formation damage due to scale deposition when mixing of KRU produced water and Beaufort seawater from the seawater treatment plant. This administrative approval does not exempt CPAI from obtaining additional permits or approvals required by law from other governmental agencies. ENTERED at Anchorage, Alaska, and dated November 5, 2010. Corrected on December 2, 2010. Daniel T. Seamount, Jr. ( 4 an orm Commissioner, Chair oner o� i�o �T i AI0 18C.001 • • AIO 28.004 AIO 30.004 AIO 35.002 December 2, 2010 Page 3 of 3 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, December 02, 2010 1:22 PM To: (foms2 @mtaon line. net); ( michael .j.nelson @conocophillips.com); (Von. L. Hutchins@conocophillips.com); 'AKDCWelllntegrityCoordinator'; Alan Dennis; alaska @petrocalc.com; Anna Raff; Barbara F Fullmer; bbritch; Becky Bohrer; Bill Penrose; Bill Walker; Bowen Roberts; Brad McKim; Brady, Jerry L; Brandon Gagnon; Brandow, Cande (ASRC Energy Services); Brian Gillespie; Brian Havelock; Bruce Webb; carol smyth; caunderwood; Chris Gay; Cliff Posey; Crandall, Krissell; dapa; Daryl J. Kleppin; Dave Matthews; David Boelens; David House; David Steingreaber; 'ddonkel @cfl.rr.com'; Deborah J. Jones; Delbridge, Rena E (LAA); 'Dennis Steffy'; Elowe, Kristin; eyancy; Francis S. Sommer; Fred Steece; Garland Robinson; Gary Laughlin; Gary Rogers; Gary Schultz; ghammons; Gordon Pospisil; Gorney, David L.; 'Greg Duggin'; Gregg Nady; gspfoff; Harry Engel; Jdarlington (jarlington @g mail. com); 'Jeanne McPherren'; Jeff Jones; Jeffery B. Jones Qeff.jones @alaska.gov); Jerry McCutcheon; Jill Womack; 'Jim White'; 'Jim Winegarner; 'Joe Nicks'; 'John Garing'; 'John Katz'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'Jon Goltz'; 'Judy Stanek'; 'Julie Houle'; 'Karl Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kim Cunningham'; 'Larry Ostrovsky'; 'Laura Silliphant'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley (mark.hanley @anadarko.com)'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marquerite kremer'; 'Michael Dammeyer'; 'Michael Jacobs'; 'Mike Bill'; 'Mike Mason'; 'Mike) Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'nelson'; 'Nick W. Glover'; 'NSK Problem Well Supv'; 'Patty Alfaro'; 'Paul Decker (paul.decker @alaska.gov)'; 'Paul Figel'; 'PORHOLA, STAN T'; 'Randall Kanady'; 'Randy L. Skillern'; ' rob.g. drag nich @exxon mobil. com'; 'Robert Brelsford'; 'Robert Campbell'; 'Rudy Brueggeman'; 'Ryan Tunseth'; 'Scott Cranswick'; 'Scott Griffith'; Scott, David (LAA); 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'tablerk'; Tamera Sheffield; Taylor, Cammy 0 (DNR); Temple Davidson; Teresa Imm; Terrie Hubble; Thor Cutler; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjr1; 'Valenzuela, Mariam'; Vicki Irwin; Walter Featherly; Will Chinn; Williamson, Mary J (DNR); Yereth Rosen; 'Aaron Gluzman'; Bettis, Patricia K (DNR); 'Dale Hoffman'; David Lenig; 'Gary Orr'; 'Jason Bergerson'; 'Joe Longo'; 'Lars Coates'; Marc Kuck; 'Mary Aschoff; 'Matt Gill'; Maurizio Grandi; Ostrovsky, Larry Z (DNR); Richard Garrard; 'Sandra Lemke'; Talib Syed; 'Tiffany Stebbins'; 'Wayne Wooster'; 'William Van Dyke'; Woolf, Wendy C (DNR); Aubert, Winton G (DOA); Ballantine, Tab A (LAW); Brooks, Phoebe; Davies, Stephen F (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Johnson, Elaine M (DOA); Laasch, Linda K (DOA); Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Shartzer, Christine R (DOA) Subject: aio18c -001, aio28 -004, aio30 -004, aio 35- 002.pdf - KRU Attachments: aio18c -001, aio28 -004, aio30 -004, aio 35- 002.pdf Attached is a corrected Administrative Approval correcting the numbers. I apologize. Jody Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton 408 18 Street President 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI K &K Recycling Inc. Land Department Baker Oil ho P.O. Box 58055 P.O. Box 93330 795 E. 94 Ct. Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Jill Schneider Gordon Severson P.O. Box 69 US Geological Survey 3201 Westmar Circle Barrow, AK 99723 4200 University Drive Anchorage, AK 99508 -4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Cliff Burglin Refuge Manager 399 West Riverview Avenue 319 Charles Street P.O. Box 2139 Soldotna, AK 99669 -7714 Fairbanks, AK 99701 Soldotna, AK 99669 -2139 I Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 Q �,�° THE STATE °fALASKA GOVERNOR BILL WALKER Ms. Rachel Kautz Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 28.005 Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-17-028 333 west Seventh Avenue Anchorage. Alaska 99501-3572 Main: 907.279.1433 Fax 907.276.7542 www-aogcc.alaskagov Request for administrative approval to allow well CD4 -291 (PTD 2131100) to be online in water only injection service with a known outer annulus x atmosphere pressure communication. Colville River Unit (CRU) CD4 -291 (PTD 2131100) Colville River Field Nanuq Oil Pool Dear Ms. Kautz: By letter dated September 3, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 28.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for administrative approval to continue water only injection in the subject well. CPAI reported a potential outer annulus (OA) x atmosphere pressure communication to AOGCC on April 28, 2017. CPAI completed diagnostic evaluations including a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on May 1, 2017 which indicates that CD4 -291 exhibits at least two competent barriers to the release of well pressure. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 28.005 September 11, 2017 Page 2 of 2 AOGCC's approval to continue water injection only in CRU CD4 -291 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI 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. CPAI shall perform a mechanical integrity test of the inner annulus (MITIA) every 2 years to the maximum anticipated injection pressure; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to as low as reasonably possible not to exceed 400 psi; 5. CPAI 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; and 7. The next required MIT is to be before or during the month of June 2019. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated September 11, 2017. I V Hollis S. French Commissioner, Chair RECONSIDERATION AND APPEAL 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. THE STATE 01ALASKA (,()VERNOR BILL WALKER Ms. Rachel Kautz Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 28.005 Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-17-028 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.olaska.gov Request for administrative approval to allow well CD4 -291 (PTD 2131100) to be online in water only injection service with a known outer annulus x atmosphere pressure communication. Colville River Unit (CRU) CD4 -291 (PTD 2131100) Colville River Field Nanuq Oil Pool Dear Ms. Kautz: By letter dated September 3, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 28.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for administrative approval to continue water only injection in the subject well. CPAI reported a potential outer annulus (OA) x atmosphere pressure communication to AOGCC on Apri128, 2017. CPAI completed diagnostic evaluations including a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on May 1, 2017 which indicates that CD4 -291 exhibits at least two competent barriers to the release of well pressure. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. A10 28.005 September 11, 2017 Page 2 of 2 AOGCC's approval to continue water injection only in CRU CD4 -291 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI 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. CPAI shall perform a mechanical integrity test of the inner annulus (MITIA) every 2 years to the maximum anticipated injection pressure; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to as low as reasonably possible not to exceed 400 psi; 5. CPAI 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; and 7. The next required MIT is to be before or during the month of June 2019. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated September 11, 2017. //signature on file// Hollis S. French Commissioner, Chair //signature on file// Daniel T. Seamount, Jr. Commissioner AND APPEAL 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 he 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 ran 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 oras until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711-0055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639-0309 Fairbanks, AK 99706-0868 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, September 14, 2017 2:38 PM To: DOA AOGCC Prudhoe Bay; Bender, Makana K (DOA); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Davies, Stephen F (DOA); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity; AKDCWeIIIntegrityCoordinator; Alan Bailey; Alex Demarban; Alexander Bridge; Alicia Showalter; Allen Huckabay; Andrew Vanderlack, Ann Danielson; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Ben Boettger; Bill Bredar; Bob Shavelson; Brandon Viator; Brian Havelock; Bruce Webb; Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Cody Gauer; Colleen Miller, Connie Downing; Crandall, Krissell; D Lawrence; Dale Hoffman; Darci Horner, Dave Harbour; David Boelens; David Duffy, David House; David McCaleb; David McCraine; ddonkel@cfl.rr.com; Diemer, Kenneth J (DNR); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Elwood Brehmer; Evan Osborne; Evans, John R (LDZX); Brown, Garrett A (DNR); George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff, Hunter Cox; Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jason Brune; Jdarlington Qarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); John Stuart; Jon Goltz; Chmielowski, Josef (DNR); Juanita Lovett; Judy Stanek, Kari Moriarty; Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Frank, Kevin J (DNR); Kruse, Rebecca D (DNR); Kyla Choquette; Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Louisiana Cutler; Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; Mike Morgan; MJ Loveland; mkm7200; Motteram, Luke A; Mueller, Marta R (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick Ostrovsky, Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan Yanish; Richard Cool; Robert Brelsford; Robert Warthen; Sara Leverette; Scott Griffith; Shahla Farzan; Shannon Donnelly; Sharon Yarawsky; Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Ted Kramer; Teresa Imm; Tim Jones; Tim Mayers; Todd Durkee; Tom Maloney; trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Well Integrity; Well Integrity; Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andy Bond; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff 1 (DNR); Casey Sullivan; Corey Munk; Don Shaw, Eppie Hogan; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Shine, Jim M (DNR); Joe Longo; John Martineck; Josh Kindred; Keith Lopez; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Melonnie Amundson; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Rachel Davis; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); William Van Dyke Subject: AIO 28.005 Attachments: aio28.005.pdf Re: Docket Number: A10- 17-028 Request for administrative approval to allow well CD4 -291 (PTD 2131100) to be online in water only injection service with a known outer annulus x atmosphere pressure communication. Colville River Unit (CRU) CD4 -291 (PTD 2131100) Colville River Field Nanuq Oil Pool Jody J. CoCombie AOGCC speciaLAssistant .?Kaska OiCandGas Conservation Commission 333 West 7'fi Avenue .anchorage, Alaska 99501 Office: (907) 793-1221 Fax: (907) 276-7542 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 Jody Colombie at 907.793.1221 or iodv.colombie@olaska.aov. 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.olaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 28.005 CANCELLATION Ms. Rachel Kautz Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-18-029 Request to cancel Area Injection Order (AIO) 28.005 Colville River Unit (CRU) CD4 -291 (PTD 2131100) Colville River Field Nanuq Oil Pool Dear Ms. Kautz: By letter dated June 1, 2018, ConocoPhillips Alaska, Inc. (CPAI) requested cancellation of administrative approval (AA) Area Injection Order 28.005. In accordance with Rule 11 of Area Injection Order (AIO) 28.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request to cancel the AA. CD4 -291 developed an outer annulus (OA) x atmosphere pressure communication and on September 11, 2017 the AOGCC issued AIO 28.005. AOGCC determined that water injection could safely continue if CPAI complied with the restrictive conditions set out in AA AIO 28.005. CPAI has recently completed a successful surface casing repair via Sundry 317-213 and the well passed a mechanical integrity test of the outer annulus (MITOA) on May 24, 2018. AA AIO 28.005 is no longer necessary to the operation of C134-291 and is hereby CANCELLED. A1028.005 Cancellation June 18, 2018 Page 2 of 2 DONE at Anchorage, Alaska and dated June 18, 2018. Hollis S. French Chair, Commissioner As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. I'l 11-, 5-1:1 IT Alaska Oil and Gas Conservation Commission .........-.a_...._..m.._--..._...__-.._-._____............. __.. 333 west Seventh Avenue r Anchorage. Alaska 99501-3572 t�pt tV 1�32ti YAR i,f ._[. 1i ,91 i_Eia Main: 907.279.1433 Fax: 907.276.7542 aogcc.oloska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 28.005 CANCELLATION Ms. Rachel Kautz Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-18-029 Request to cancel Area Injection Order (AIO) 28.005 Colville River Unit (CRU) CD4 -291 (PTD 2131100) Colville River Field Nanuq Oil Pool Dear Ms. Kautz: By letter dated June 1, 2018, ConocoPhillips Alaska, Inc. (CPAI) requested cancellation of administrative approval (AA) Area Injection Order 28.005. In accordance with Rule 11 of Area Injection Order (AIO) 28.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request to cancel the AA. CD4 -291 developed an outer annulus (OA) x atmosphere pressure communication and on September 11, 2017 the AOGCC issued AID 28.005. AOGCC determined that water injection could safely continue if CPAI complied with the restrictive conditions set out in AA AID 28.005. CPAI has recently completed a successful surface casing repair via Sundry 317-213 and the well passed a mechanical integrity test of the outer annulus (MITOA) on May 24, 2018. AA AID 28.005 is no longer necessary to the operation of CD4 -291 and is hereby CANCELLED. ATO 28.005 Cancellation June 18, 2018 Page 2 of 2 DONE at Anchorage, Alaska and dated June 18, 2018. //signature on file// Hollis S. French Chair, Commissioner //signature on file// Cathy P. Foerster Commissioner AND APPEAL NOTICE //signature on file// Daniel T. Seamount, Jr. Commissioner As provided in AS 31.05.080(a), within 20 days atter 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 atter 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 1 (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, June 19, 2018 11:17 AM To: Bell, Abby E (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Davies, Stephen F (DOA); Earl, Adam G (DOA); Erickson, Tamara K (DOA); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Laubenstein, Lou (DOA); Loepp, Victoria T (DOA); Martin, Teddy J (DOA); McLeod, Austin (DOA); Mcphee, Megan S (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Rixse, Melvin G (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity; AKDCWellIntegrityCoordinator, Alan Bailey; Alex Demarban; Alicia Showalter; Allen Huckabay; Andrew VanderJack; Ann Danielson; Anna Lewallen; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Ben Boettger; Bill Bredar; Bob Shavelson; Bonnie Bailey, Brandon Viator; Brian Havelock; Bruce Webb; Caleb Conrad; Candi English; Cody Gauer; Cody Terrell; Colleen Miller, Connie Downing; Crandall, Krissell; D Lawrence; Dale Hoffman; Danielle Mercurio; Darci Horner; Dave Harbour; David Boelens; David Duffy, David House; David McCaleb; David Pascal; ddonkel@cfl.rr.com; Diemer, Kenneth J (DNR); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Elwood Brehmer; Evan Osborne; Evans, John R (LDZX); Brown, Garrett A (DNR); George Pollock, Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff, Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jason Brune; Jdarlington Qarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Shine; Jim Watt, Jim White 0im4thgn@gmail.com); Young, Jim P (DNR); Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); Jon Goltz; Josef Chmielowski; Joshua Stephen; Juanita Lovett; Judy Stanek, Kari Moriarty; Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Frank, Kevin J (DNR); Kruse, Rebecca D (DNR); Kyla Choquette; Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Michael Bill; Michael Calkins; Michael Moora; Michael Quick; Michael Schoetz; Mike Morgan; MJ Loveland; Motteram, Luke A; Mueller, Marta R (DNR); Nathaniel Herz; knelson@petroleumnews.com; Nichole Saunders; Nick Ostrovsky; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan Yanish; Richard Cool; Robert Brelsford; Robert Tirpack; Robert Warthen; Ryan Gross; Sara Leverette; Scott Griffith; Shahla Farzan; Shannon Donnelly; Sharon Yarawsky; Skutca, Joseph E (DNR); Smith, Kyle S (DNR); Spuhler, Jes 1 (DNR); Stephanie Klemmer; Stephen Hennigan; Stephen Ratcliff; Sternicki, Oliver R, Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Tanisha Gleason; Ted Kramer; Teresa Imm; Terry Caetano; Tim Mayers; Todd Durkee; Tom Maloney, Tyler Senden; Umekwe, Maduabuchi P (DNR); Vern Johnson; Vinnie Catalano; Well Integrity; Well Integrity; Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andy Bond; Bajsarowicz, Caroline J; Bruce Williams; Casey Sullivan; Corey Munk; Don Shaw; Eppie Hogan; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Keith Lopez; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Matt Armstrong; Melonnie Amundson; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Patricia Bettis, Pete Dickinson; Peter Contreras; Rachel Davis; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Scott Pins; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); William Van Dyke; Zachary Shulman Subject: Cancel AIO 28.005 (CPA) Attachments: aio28.005 cancel.pdf Please see attached. Docket Number: AIO-18-029 Request to cancel Area Injection Order (AIO) 28.005 Colville River Unit (CRU) CD4 -291 (PTD 2131100) Colville River Field Nanuq Oil Pool Jody J. Coiombie .AOGCC SpeciaC.Assistant .ACaska OilandGas Conservation Commission 333 'vest 711 Avenue .Anchorage, .Alaska 995o1 Office: (907) 793-1221 Fax (907) 275-7542 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 Jody Colombie at 907.793.1221 or iodv.colombie@alaska.aov. 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 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 THE STATE ALASKA GOVERNOR BILL WALKER Ms. Rachel Kautz Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 28.006 Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-17-030 333 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 CD4 -214 (PTD 2061450) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) CD4 -214 (PTD 2061450) Colville River Field Nanuq Oil Pool Dear Ms. Kautz: By letter dated September 19, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 28.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for administrative approval to continue water only injection in the subject well. CPAI reported a potential Tubing (T) x Inner Annulus (IA) pressure communication to AOGCC on July 9, 2017 while the well was on miscible gas injection. The well was WAG'ed to water for a 30 day monitoring period in which communication was not observed. CPAI had performed diagnostics including a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on July 24, 2017 which indicates that CD4 -214 exhibits at least two competent barriers to the release of well pressure. CPAI WAG'ed the well back to miscible gas injection but the monitoring was concluded when pressure communication was observed.. The well does not exhibit signs of pressure communication while on water injection. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 28.006 September 22, 2017 Page 2 of 2 AOGCC's approval to continue water injection only in CRU CD4 -214 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI 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. CPAI shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi; 5. CPAI 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; and 7. The next required MIT is to be before or during the month of June 2019. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated September 22, 2017. OILgt F v Hollis French Daniel T. Seamount, Jr. Cathy P. Foerster Chair, Commissioner Commissioner Commissioner N,. 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 aweekend or state holiday. THE SI'ATF "ALASKA (JOVERNO R BILI. WALKFR Ms. Rachel Kautz Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 28.006 Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-17-030 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 oogcc.alaska.gov Request for administrative approval to allow well CD4 -214 (PTD 2061450) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) C134-214 (PTD 2061450) Colville River Field Nanuq Oil Pool Dear Ms. Kautz: By letter dated September 19, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 28.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for administrative approval to continue water only injection in the subject well. CPAI reported a potential Tubing (T) x Inner Annulus (IA) pressure communication to AOGCC on July 9, 2017 while the well was on miscible gas injection. The well was WAG'ed to water for a 30 day monitoring period in which communication was not observed. CPAI had performed diagnostics including a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on July 24, 2017 which indicates that CD4 -214 exhibits at least two competent barriers to the release of well pressure. CPAI WAG'ed the well back to miscible gas injection but the monitoring was concluded when pressure communication was observed.. The well does not exhibit signs of pressure communication while on water injection. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. A10 28.006 September 22, 2017 Page 2 of 2 AOGCC's approval to continue water injection only in CRU CD4 -214 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI 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. CPAI shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi; 5. CPAI 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; and 7. The next required. MIT is to be before or during the month of June 2019. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated September 22, 2017. //signature on file// //signature on file// //signature on file// Hollis French Daniel T. Seamount, Jr. Cathy P. Foerster `a,r Chair, Commissioner Commissioner Commissioner ��Ajgauvrni° As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl M Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711-0055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639-0309 Fairbanks, AK 99706-0868 'il LQC�' `t- 25 - ZC, k -C Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, September 22, 2017 2:27 PM To: DOA AOGCC Prudhoe Bay; Bender, Makana K (DOA); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha 1 (DOA); Colombie, Jody J (DOA); Davies, Stephen F (DOA); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael 1 (DOA); Regg, James B (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity, AKDCWellIntegrityCoordinator; Alan Bailey; Alex Demarban; Alicia Showalter; Allen Huckabay; Andrew VanderJack, Ann Danielson; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Ben Boettger; Bill Bredar; Bob Shavelson; Brandon Viator; Brian Havelock, Bruce Webb; Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Cody Gauer; Colleen Miller; Connie Downing; Crandall, Krissell; D Lawrence; Dale Hoffman; Dard Horner, Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David McCraine; ddonkel@cfl.rr.com; Diemer, Kenneth J (DNR); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Elwood Brehmer; Evan Osborne; Evans, John R (LDZX); Brown, Garrett A (DNR); George Pollock, Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff; Hunter Cox; Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jason Brune; Jdarlington (arlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); John Stuart; Jon Goltz; Chmielowski, Josef (DNR); Juanita Lovett; Judy Stanek; Kari Moriarty; Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Frank, Kevin 1 (DNR); Kruse, Rebecca D (DNR); Kyla Choquette; Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt, Mark Wedman; Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; Mike Morgan; MJ Loveland; mkm7200; Motteram, Luke A; Mueller, Marta R (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick Ostrovsky; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan Yanish; Richard Cool; Robert Brelsford; Robert Warthen; Sara Leverette; Scott Griffith; Shahla Farzan; Shannon Donnelly; Sharon Yarawsky; Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Ted Kramer, Teresa Imm; Tim Jones; Tim Mayers; Todd Durkee; Tom Maloney; trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Well Integrity; Well Integrity; Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andy Bond; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Corey Munk; Don Shaw, Eppie Hogan; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Shine, Jim M (DNR); Joe Longo; John Martineck; Josh Kindred; Keith Lopez, Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Melonnie Amundson; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Rachel Davis; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); William Van Dyke Subject: AIO 28.006 (CPA) Attachments: aio28.006.pdf Sec Attached. Re: Docket Number: AIO-17-030 Request for administrative approval to allow well C134-214 (PTD 2061450) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) CD4 -214 (PTD 2061450) Colville River Field Nanuq Oil Pool Jody J. Co(ombie AOGCC Syecia(Assistant Alaska Oi(andgas Conservation Commission 333 West 7" .avenue Anchorage, A(aska 99501 Office: (907) 793-1221 Fax: (907) 276-7542 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 Jody Colombie at 907.793.1221 or iodv.colombie@alaska.aov. 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 28.006 AMENDED Ms. Kathleen Dodson Well Integrity Specialist ConocoPhillips Alaska, Inc. P.O. Box 1000360 Anchorage, AK 99510 Re: Docket Number: AIO-23-004 Request to Amend Area Injection Order 28.006; Water Alternating Gas Injection Colville River Unit (CRU) CD4-214 (PTD 2061450), Nanuq Oil Pool Dear Ms. Dodson: By emailed letter dated February 21, 2023, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to amend Area Injection Order (AIO) 28.006 to include water alternating gas (WAG) injection with a known tubing by inner annulus (TxIA) pressure communication. In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions,CPAI’s requestto amend the administrative approval to continue WAG injection in the subject well. CPAI reported a potential TxIA pressure communication to AOGCC on July 9, 2017, while the well was on miscible gas injection. CPAI performed diagnostics and confirmed the TxIA pressure communication was only present during gas injection. AOGCC issued AIO 28.006 on September 22, 2017, restricting the well to water only injection. CPAI has recently changed an internal policy to allow WAG injection in wells that have casing rated to support the higher pressures of gas injection should a barrier fail, and that can meet stringent testing criteria. CPAI has performed additional diagnostics including a passing non- state witnessed mechanical integrity test (MIT) of the inner annulus (to a test pressure greater than the anticipated gas injection pressure of 3,900 psi) on December 25, 2022. This indicates that CD4-214 exhibits at least two competent barriers to the release of well pressure. CPAI has installed an injection line choke and surface safety valve (SSV) on CD4-214. Both of these devices have remote shut down capability by the Board Operator. Combining this with live transmitters on the inner and outer annulus and the alarm functions in the Supervisory Control and Data Acquisition (SCADA) system create robust layers of protection from an over pressure event. These inner and outer annulus alarms and shut-in protocols combined with the planned inner and outer annulus operating pressure limits enable AOGCC to remove the original water only restriction and re-authorize gas injection. AOGCC believes CPAI can safely manage the TxIA communication with periodic pressure bleeds by maintaining the inner annulus AIO 28.006 Amended March 2, 2023 Page 2 of 3 to a pressure not to exceed 2,400 psi when on gas injection and 2,000 psi when injecting water. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC’s approval to continue WAG injection in CRU CD4-214 is conditioned upon the following: 1) CPAI shall record wellhead pressures and injection rate daily; 2) CPAI 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) CPAI shall perform a MIT of the inner annulus every two years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 4) CPAI shall limit the well’s inner annulus operating pressure to 2,400 psi during gas injection and 2,000 psi during water injection. Audible control room alarms shall be set at or below these limits; 5) CPAI shall limit the well’s outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 6) CPAI shall monitor the inner and outer annulus pressures in real time with its SCADA system; 7) CPAI shall maintain the injection line choke and surface safety valve (SSV) remote shut down capability. During gas injection, the IA protocols will include a drill site operator alarm set at 2,200 psi, and a high alarm set at 2,400 psi that will prompt the control room Board Operator to remotely shut in the choke or SSV; 8) CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 9) After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 10) The next required MIT is to be before or during the month of June 2023. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated March 2, 2023. Brett W. Huber, Sr Jessie L. Chmielowski Chair, Commissioner Commissioner Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.03.02 11:14:32 -09'00' Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.03.02 11:22:48 -09'00' AIO 28.006 Amended March 2, 2023 Page 3 of 3 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:Carlisle, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order 28.006 Amended (CRU) Date:Thursday, March 2, 2023 11:40:24 AM Attachments:aio28.006 amended.pdf Docket Number: AIO-23-004 Request to Amend Area Injection Order 28.006; Water Alternating Gas Injection Colville River Unit (CRU) CD4-214 (PTD 2061450), Nanuq Oil Pool Samantha Carlisle 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.carlisle@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.carlisle%40alaska.gov Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 mailed 3/6/23 THE STATE °fALASKA GOVERNOR BILL WALKER Mr. Stephen Thatcher Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVALS AREA INJECTION ORDER NO. 28.007 AREA INJECTION ORDER NO. 30.010 AREA INJECTION ORDER NO. 35.003 Manager, WMS Development North Slope Operations and Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.ciogcc.olaska.gov Re: Docket Number: AIOI8-014 Request for administrative approval to amend approved fluids for enhanced oil recovery injection for the Colville River Field. Colville River Field Colville River Unit Nanuq Oil Pool Fiord Oil Pool Qannik Oil Pool Dear Mr. Thatcher: By letter dated February 28, 2018, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to amend the list of fluids authorized for injection for enhanced oil recovery (EOR) purposes in the Colville River Field (CRF) to allow the injection of produced water from the Lookout Oil Pool (LOP) in the Greater Moose's Tooth Unit (GMTU).1 In accordance with Rule 11 of Area Injection Orders (AIO) No. 28, 30, and 35, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request to amend the list of fluids approved for EOR purposes in the CRF. ' The application only applies to AIOs for the Nanug, Fiord, and Qannik Oil Pools because the language currently in the AIO for the Alpine Oil Pool will allow the injection of the produced water from the LOP for enhanced recovery purposes. AID 28.007, 30.010, and 35.003 August 13, 2018 Page 2 of 4 CPAI plans to commence production from the LOP in late 2018 and will ship produced fluids from the LOP to the CRF where they will be commingled with production from the Alpine Oil Pool, Nanuq Oil Pool, Fiord Oil Pool, and Qannik Oil Pool before being processed at the Alpine Central Facility (ACF). Since production is commingled prior to processing, the produced water and gas streams to be used for EOR injection at both the CRF and the LOP will contain fluids from both fields. Only the AIO for the Alpine Oil Pool in the CRF allows injection of gas and water from the LOP for EOR purposes2. The AIO's for the Nanuq' and Fiord' Oil Pools allow the injection of miscible injectant from the ACF and produced water from the CRF5. The Qannik Oil Pool AIO does not allow gas injection but does allow the injection of produced water from the CRF. The LOP is an Alpine formation development, as is the Alpine Oil Pool, so no fluid compatibility issues are anticipated to arise from injecting the produced water from the LOP into the CRF oil pools, provided any required treatment is continued. The administrative action rules for the affected orders allow the AOGCC to amend an order administratively if the proposed action will not result in waste, will not jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in increased risk of fluid movement into freshwater. Waste is prevented by being able to use the produced water from the LOP for EOR purposes in the LOP and CRF. Correlative rights are protected because all of the affected pools are within the Colville River Unit. The injection of the commingled fluids is based on sound engineering and geoscience principles. Sharing of production facilities and infrastructure helps to lessen environmental impacts and increase ultimate recovery through the sharing of expenses. There will be no increased risk of fluids moving into freshwater because all injection operations will be conducted in accordance with the appropriate AIOs and regulations. Now therefore it is ordered that Rule 4 of AIO 28 is amended to read as follows Rule 4 Authorized Fluids for Enhanced Recovery Fluids authorized for injection are: a. source water from a sea water treatment plant; b. enriched gas obtained from the Alpine Central Facility c. produced water treated with scale inhibitors to reduce the possibility of scale deposition in the formation from the Alpine Central Facility. Z Rule 1 of AIO 18D specifies that produced water and miscible injectant from the ACF, as well as lean gas with no source restrictions, can be injected for EOR purposes. 3 Rule 4 of AIO 28 authorized the injection of MI from the ACF and AIO 28.002 changed the MI requirement to enriched gas, authorized the injection of treated commingled produced water from the CRF, and authorized the injection of other sources of water with conditions. ' Rule 4 of AlO 30 authorized the injection of MI from the ACF and AID 30.002 authorized the injection of commingled produced water from the CRF. ' Lean gas injection is not authorized for the Nanuq and Fiord Oil Pools. AIO 28.007, 30.010, and 35.003 August 13, 2018 Page 3 of 4 d. sump fluid, hydrotest fluid (excluding fluids derived from tests of transportation pipelines), rinsate generated from washing mud hauling trucks, excess well work fluids, and treated camp effluent and mixtures involving such fluids. CPAI shall monitor injection rated and pressures when injecting fluids from c. and d. above. If the monitoring indicates the possibility of loss of injectivity or formation damage, CPAI shall cease injection of such fluids immediately and notify the AOGCC. CPAI shall not recommence injection of these fluids until authorized by the AOGCC. In addition, the following fluids may be authorized by future administrative approval for injection upon demonstration of compatibility with the Nanuq reservoir: a. tracer survey liquid to monitor reservoir performance; In the event any mixture of fluids is injected, the following additional requirements apply: The operator shall continue to collect and analyze representative samples of the mixed fluid stream to demonstrate its non -hazardous characteristics and its continued suitability for EOR injection. Analysis results must be retained according to the provisions of 20 AAC 25.310. Volumes of injected mixed fluids must be reported in the monthly (Form 10-406) and annual (Form 10-413) injection reports. The injection of lean gas will require separate authorization from the AOGCC. That Rule 4 of AIO 30 is amended to read as follows: Rule 4 Authorized Fluids for Enhanced Recovery Fluids authorized for injection are: a. source water from a sea water treatment plant; b. Enriched gas obtained from the Alpine Central Facility. c. Produced water from the Alpine Central Facility. d. sump fluid, hydrotest fluid (excluding fluids derived from tests of transportation pipelines), rinsate generated from washing mud hauling trucks, excess well work fluids, and treated camp effluent and mixtures involving such fluids. In addition, the following fluids may be authorized by future administrative approval for injection upon demonstration of compatibility with the Fiord reservoir: a. tracer survey liquid to monitor reservoir performance; In the event any mixture of fluids is injected, the following additional requirements apply The operator shall continue to collect and analyze representative samples of the mixed fluid stream to demonstrate its non -hazardous characteristics and its continued suitability for EOR injection. Analysis results must be retained according to the provisions of 20 AAC 25.310. Volumes of injected mixed fluids must be reported in the monthly (Form 10-406) and annual (Form 10-413) injection reports. The injection of lean gas will require separate authorization from the AOGCC. AIO 28.007, 30.010, and 35.003 August 13, 2018 Page 4 of 4 And that Rule 3 of AIO 35 is amended to read as follows: Rule 3 Authorized Fluids for Enhanced Recovery Fluids authorized for injection are: a. source water from the Kuparuk sea water treatment plant; and b. produced water from the Alpine Central Facility. Any other fluids shall be approved by separate ad ^' ;�rrar;.,P not;nn DONE at Anchorage, Alaska and dated August 13,2C Hollis S. French Ca y . Foerster Chair, Commissioner Commissioner uommissroner 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 ofthe 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. 'I 111: SfAI'1i °ALAS KA (,0vl:RN()R lilt I WAI.K1-V Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVALS AREA INJECTION ORDER NO. 28.007 AREA INJECTION ORDER NO. 30.010 AREA INJECTION ORDER NO. 35.003 Mr. Stephen Thatcher Manager, WMS Development North Slope Operations and Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov Re: Docket Number: AIO18-014 Request for administrative approval to amend approved fluids for enhanced oil recovery injection for the Colville River Field. Colville River Field Colville River Unit Nanuq Oil Pool Fiord Oil Pool Qannik Oil Pool Dear Mr. Thatcher: By letter dated February 28, 2018, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to amend the list of fluids authorized for injection for enhanced oil recovery (EOR) purposes in the Colville River Field (CRF) to allow the injection of produced water from the Lookout Oil Pool (LOP) in the Greater Moose's Tooth Unit (GMTU). t In accordance with Rule I1 of Area Injection Orders (AIO) No. 28, 30, and 35, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request to amend the list of fluids approved for EOR purposes in the CRF. 1 The application only applies to AIOs for the Nanug, Fiord, and Qannik Oil Pools because the language currently in the AID for the Alpine Oil Pool will allow the injection of the produced water from the LOP for enhanced recovery purposes. AIO 28.007, 30.010, and 35.003 August 13, 2018 Page 2 of 4 CPAI plans to commence production from the LOP in late 2018 and will ship produced fluids from the LOP to the CRF where they will be commingled with production from the Alpine Oil Pool, Nanuq Oil Pool, Fiord Oil Pool, and Qannik Oil Pool before being processed at the Alpine Central Facility (ACF). Since production is commingled prior to processing, the produced water and gas streams to be used for EOR injection at both the CRF and the LOP will contain fluids from both fields. Only the AIO for the Alpine Oil Pool in the CRF allows injection of gas and water from the LOP for EOR purposes'. The AIO's for the Nanug3 and Fiord' Oil Pools allow the injection of miscible injectant from the ACF and produced water from the CRF'. The Qannik Oil Pool AIO does not allow gas injection but does allow the injection of produced water from the CRF. The LOP is an Alpine formation development, as is the Alpine Oil Pool, so no fluid compatibility issues are anticipated to arise from injecting the produced water from the LOP into the CRF oil pools, provided any required treatment is continued. The administrative action rules for the affected orders allow the AOGCC to amend an order administratively if the proposed action will not result in waste, will not jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in increased risk of fluid movement into freshwater. Waste is prevented by being able to use the produced water from the LOP for EOR purposes in the LOP and CRF. Correlative rights are protected because all of the affected pools are within the Colville River Unit. The injection of the commingled fluids is based on sound engineering and geoscience principles. Sharing of production facilities and infrastructure helps to lessen environmental impacts and increase ultimate recovery through the sharing of expenses. There will be no increased risk of fluids moving into freshwater because all injection operations will be conducted in accordance with the appropriate AIOs and regulations. Now therefore it is ordered that Rule 4 of AIO 28 is amended to read as follows Rule 4 Authorized Fluids for Enhanced Recovery Fluids authorized for injection are: a. source water from a sea water treatment plant; b. enriched gas obtained from the Alpine Central Facility c. produced water treated with scale inhibitors to reduce the possibility of scale deposition in the formation from the Alpine Central Facility. ' Rule 1 of AIO 18D specifies that produced water and miscible injectant from the ACF, as well as lean gas with no source restrictions, can be injected for EOR purposes. 3 Rule 4 of AID 28 authorized the injection of MI from the ACF and AIO 28.002 changed the MI requirement to enriched gas, authorized the injection of treated commingled produced water from the CRF, and authorized the injection of other sources of water with conditions. 4 Rule 4 of AID 30 authorized the injection of MI from the ACF and AIO 30.002 authorized the injection of commingled produced water from the CRF. 5 Lean gas injection is not authorized for the Nanuq and Fiord Oil Pools. AIO 28.007, 30.010, and 35.003 August 13, 2018 Page 3 of 4 d. sump fluid, hydrotest fluid (excluding fluids derived from tests of transportation pipelines), rinsate generated from washing mud hauling trucks, excess well work fluids, and treated camp effluent and mixtures involving such fluids. CPAI shall monitor injection rated and pressures when injecting fluids from c. and d. above. If the monitoring indicates the possibility of loss of injectivity or formation damage, CPAI shall cease injection of such fluids immediately and notify the AOGCC. CPAI shall not recommence injection of these fluids until authorized by the AOGCC. In addition, the following fluids may be authorized by future administrative approval for injection upon demonstration of compatibility with the Nanuq reservoir: a. tracer survey liquid to monitor reservoir performance; In the event any mixture of fluids is injected, the following additional requirements apply: The operator shall continue to collect and analyze representative samples of the mixed fluid stream to demonstrate its non -hazardous characteristics and its continued suitability for EOR injection. Analysis results must be retained according to the provisions of 20 AAC 25.310. Volumes of injected mixed fluids must be reported in the monthly (Form 10-406) and annual (Form 10-413) injection reports. The injection of lean gas will require separate authorization from the AOGCC That Rule 4 of AIO 30 is amended to read as follows: Rule 4 Authorized Fluids for Enhanced Recovery Fluids authorized for injection are: a. source water from a sea water treatment plant; b. Enriched gas obtained from the Alpine Central Facility. c. Produced water from the Alpine Central Facility. d. sump fluid, hydrotest fluid (excluding fluids derived from tests of transportation pipelines), rinsate generated from washing mud hauling trucks, excess well work fluids, and treated camp effluent and mixtures involving such fluids. In addition, the following fluids may be authorized by future administrative approval for injection upon demonstration of compatibility with the Fiord reservoir: a. tracer survey liquid to monitor reservoir performance; In the event any mixture of fluids is injected, the following additional requirements apply: The operator shall continue to collect and analyze representative samples of the mixed fluid stream to demonstrate its non -hazardous characteristics and its continued suitability for EOR injection. Analysis results must be retained according to the provisions of 20 AAC 25.310. Volumes of injected mixed fluids must be reported in the monthly (Form 10-406) and annual (Form 10-413) injection reports. The injection of lean gas will require separate authorization from the AOGCC. AIO 28.007, 30.010, and 35.003 August 13, 2018 Page 4 of 4 And that Rule 3 of AIO 35 is amended to read as follows: Rule 3 Authorized Fluids for Enhanced Recovery Fluids authorized for injection are: a. source water from the Kuparuk sea water treatment plant; and b. produced water from the Alpine Central Facility. Any other fluids shall be approved by separate administrative action. DONE at Anchorage, Alaska and dated August 13, 2018. //signature on file// //signature on file// //signature on file// Hollis S. French Cathy P. Foerster Daniel T. Seamount, Jr. Chair, Commissioner Commissioner Commissioner As provided in AS 31.05.080(a), within 20 days after written notice of the may of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 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 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 � 7 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. 28.008 December 13, 2021 Mr. Travis Smith Well Intervention & Integrity Engineer ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-21-031 Request for Administrative Approval to Area Injection Order 28: Water Injection Colville River Unit (CRU) CD4-291 (PTD 2131100), Nanuq Oil Pool Dear Mr. Smith: By letter dated November 30, 2021, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water injection with a known tubing by inner annulus (TxIA) pressure communication. In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, CPAI’s request for administrative approval to continue water only injection in the subject well. CPAI reported a potential TxIA pressure communication to AOGCC on June 29, 2021, while the well was on miscible gas injection. The well was swapped to water injection for a 30-day monitoring period in which communication was not observed. CPAI performed diagnostics including a passing non-state witnessed mechanical integrity test (MIT) of the inner annulus to 4,105 psi on July 20, 2021, which indicates that CD4-291 exhibits at least two competent barriers to the release of well pressure. The well does not exhibit signs of pressure communication while on water injection. AOGCC believes CPAI can safely manage the TxIA repressurization with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,000 psi and the outer annulus not to exceed 1,000 psi. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 28.008 December 13, 2021 Page 2 of 2 AOGCC’s approval to continue water injection only in CRU CD4-291 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI 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. CPAI shall perform a MIT of the inner annulus every two years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1500 psi; 4. CPAI 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; and 6. The next required MIT shall be completed before or during the month of June 2023. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated December 13, 2021. Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski 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. 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. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2021.12.13 09:27:30 -09'00' Dan Seamount Digitally signed by Dan Seamount Date: 2021.12.13 10:04:40 -09'00' Jeremy Price Digitally signed by Jeremy Price Date: 2021.12.13 10:10:37 -09'00' 1 Salazar, Grace (OGC) From:Salazar, Grace (OGC) Sent:Monday, December 13, 2021 10:32 AM To:Travis.T.Smith@conocophillips.com Cc:Wallace, Chris D (OGC) Subject:RE: CRU CD4-291 (PTD#213-110) Administrative Approval Request Attachments:AIO 28.008.pdf Dear Mr. Smith, The Alaska Oil and Gas Conservation Commission (AOGCC) has issued the attached Area Injection Order granting administrative approval for water injection operations in the Colville River Unit (CRU) CD4-291 (PTD 2131100). If you have any questions, please do not hesitate to contact Mr. Chris Wallace, Senior Petroleum Engineer, at (907) 793-1250 or via email at chris.wallace@alaska.gov. Grace ____________________________________ Respectfully, M. Grace Salazar, Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Direct: (907) 793-1221 Email: grace.salazar@alaska.gov https://www.commerce.alaska.gov/web/aogcc/ From: Carlisle, Samantha J (OGC) <samantha.carlisle@alaska.gov> Sent: Wednesday, December 1, 2021 11:15 AM To: Salazar, Grace (OGC) <grace.salazar@alaska.gov> Subject: FW: CRU CD4-291 (PTD#213-110) Administrative Approval Request From: Smith, Travis T <Travis.T.Smith@conocophillips.com> Sent: Wednesday, December 1, 2021 11:13 AM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: CRU CD4-291 (PTD#213-110) Administrative Approval Request See attached Administrative Approval request. Please let me know if you have any questions. Thanks, Travis Smith AOGCC 333 W 7th Avenue, Anchorage, AK 99501 TO: BERNIE KARL K&K RECLYCLING, INC. PO BOX 58055 FAIRBANKS, AK 99711 Mailed 12/14/21 gs 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 28.008 AMENDED Ms. Kathleen Dodson Well Integrity Specialist ConocoPhillips Alaska, Inc. P.O. Box 1000360 Anchorage, AK 99510 Re: Docket Number: AIO-23-008 Request to Amend Area Injection Order 28.008; Water Alternating Gas Injection Colville River Unit (CRU) CD4-291 (PTD 2131100), Nanuq Oil Pool Dear Ms. Dodson: By emailed letter dated April 24, 2023, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to amend Area Injection Order (AIO) 28.008 to include water alternating gas (WAG) injection with a known tubing by inner annulus (TxIA) pressure communication. In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, CPAI’s request to amend the administrative approval to continue WAG injection in the subject well. CPAI reported a potential TxIA pressure communication to AOGCC on June 29, 2021, while the well was on miscible gas injection. CPAI performed diagnostics and confirmed the TxIA pressure communication was only present during gas injection. AOGCC issued AIO 28.008 on December 13, 2021, restricting the well to water only injection. CPAI has recently changed an internal policy to allow WAG injection in wells that have casing rated to support the higher pressures of gas injection should a barrier fail, and that can meet stringent testing criteria. CPAI has performed additional diagnostics including a passing non-state witnessed mechanical integrity test (MIT) of the inner annulus (to a test pressure greater than the anticipated gas injection pressure of 3,900 psi) on March 29, 2023. This indicates that CD4-291 exhibits at least two competent barriers to the release of well pressure. CPAI has installed an injection line choke and surface safety valve (SSV) on CD4-291. Both of these devices have remote shut down capability by the Board Operator. Combining this with live transmitters on the inner and outer annulus and the alarm functions in the Supervisory Control and Data Acquisition (SCADA) system create robust layers of protection from an over pressure event. These inner and outer annulus alarms and shut-inprotocols combined with the planned inner and outer annulus operating pressure limits enable AOGCC to remove the original water only restriction and re-authorize gas injection. AOGCC believes CPAI can safely AIO 28.008 Amended May 17, 2023 Page 2 of 3 manage the TxIA communication with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,400 psi when on gas injection and 2,000 psi when injecting water. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC’s approval to continue WAG injection in CRU CD4-291 is conditioned upon the following: 1) CPAI shall record wellhead pressures and injection rate daily; 2) CPAI 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) CPAI shall perform a MIT of the inner annulus every two years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 4) CPAI shall limit the well’s inner annulus operating pressure to 2,400 psi during gas injection and 2,000 psi during water injection. Audible control room alarms shall be set at or below these limits; 5) CPAI shall limit the well’s outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 6) CPAI shall monitor the inner and outer annulus pressures in real time with its SCADA system; 7) CPAI shall maintain the injection line choke and surface safety valve (SSV) remote shut down capability. During gas injection, the IA protocols will include a drill site operator alarm set at 2,200 psi, and a high alarm set at 2,400 psi that will prompt the control room Board Operator to remotely shut in the choke or SSV; 8) CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 9) After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 10) The next required MIT is to be before or during the month of June 2023. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated May 17, 2023. Brett W. Huber, Sr Jessie L. Chmielowski Gregory C. Wilson Chair, Commissioner Commissioner Commissioner Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.05.17 14:05:58 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.05.17 14:39:06 -08'00' Gregory Wilson Digitally signed by Gregory Wilson Date: 2023.05.17 14:41:31 -08'00' AIO 28.008 Amended May 17, 2023 Page 3 of 3 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:Carlisle, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order 28.008 Amended (CRU) Date:Thursday, May 18, 2023 10:21:46 AM Attachments:aio28.008 Amended.pdf Docket Number: AIO-23-008 Request to Amend Area Injection Order 28.008; Water Alternating Gas Injection Colville River Unit (CRU) CD4-291 (PTD 2131100), Nanuq Oil Pool Samantha Carlisle 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.carlisle@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.carlisle%40alaska.gov Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 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. 18E.001 AREA INJECTION ORDER NO. 28.009 AREA INJECTION ORDER NO. 35.004 AREA INJECTION ORDER NO. 40.003 AREA INJECTION ORDER NO. 43.001 January 27, 2022 Mr. Stephen Thatcher, Manager North Slope Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-21-010 Request to Reinstate Area Injection Order No. 18.001with Modifications Colville River Unit, Alpine Oil Pool Dear Mr. Thatcher: By letter dated May 26, 2021, ConocoPhillips Alaska, Inc. (CPAI) requested reinstatement of Area Injection Order (AIO) No. 18A.001, which allowed for the mixing of treated effluent with Class II enhanced oil recovery (EOR) fluids for injection into the Alpine Oil Pool (AOP) when the Class I disposal well was unavailable. AIO 18A.001 was rescinded when AIO 18E was issued on March 4, 2021. The Alaska Oil and Gas Conservation Commission (AOGCC) does not reinstate rescinded orders. However, the substance of CPAI’s request is for administrative approval to authorize an additional fluid to be for injection, and AOGCC will treat it as such. Since AIO 18A.001 was issued, four additional pools have been tied into the EOR injection system that serves the AOP. These pools and the AIOs that govern their injection operations are: Pool Governing AIO Nanuq Oil Pool (NOP) AIO 28 Qannik Oil Pool (QOP) AIO 35 Lookout Oil Pool (LOP) AIO 40 Rendezvous Oil Pool (ROP) AIO 43 The NOP and QOP are in the Colville River Unit (CRU), and the LOP and ROP are in the Greater Moose’s Tooth Unit (GMTU). AIO 18E.001, AIO 28.009, AIO 35.004, AIO 40.003, & AIO 43.001 January 27, 2022 Page 2 of 2 There are currently two usable Class I disposal wells (a third Class I well was suspended in 2013) in the CRU, and there are none in the GMTU. Well CRU WD-02 (PTD 198-258) is used for disposal of treated effluent, and CRU CD1-01A (PTD 212-099) is the primary drilling waste disposal well. Having the ability to mix small amounts of treated effluent into the EOR injection stream when using a Class I well is not possible due to required mechanical integrity testing, well damage, well workover operations, or any other incident that may make a well temporarily unusable provides operational flexibility for the remote CRU and GMTU developments. Under the authorization of AIO 18A.001, CPAI has periodically mixed treated effluent with the EOR injection water with no indication of fluid incompatibilities or formation damage that reduces injectivity. In accordance with 20 AAC 25.556(d), the AOGCC hereby amends AIO numbers 18E, 28, 35, 40, and 43 to include the following in the list of authorized fluids in Rule 1 of AIO 18E, Rule 4 of AIO 28, and Rule 3 of AIO 35, 40, and 43: - Treated effluent, subject to the following conditions: o Treated effluent injection may occur when the Class I disposal well for effluent disposal is unavailable; o Treated effluent will be mixed with other EOR injection fluids (seawater or produced water); and o Injection of treated effluent may not exceed 1% by volume of the total annualized average water injection at the Colville River Unit and Greater Moose’s Tooth Unit. DONE at Anchorage, Alaska and dated January 27, 2022. Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski Commissioner, Chair Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Dan Seamount Digitally signed by Dan Seamount Date: 2022.01.27 08:48:32 -09'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.01.27 09:05:42 -09'00' Jeremy Price Digitally signed by Jeremy Price Date: 2022.01.27 13:57:28 -09'00' From:Salazar, Grace (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order Nos. 18E.001, 28.009, 35.004, 40.003 and 43.001 (ConocoPhillips, Alpine Pool) Date:Thursday, January 27, 2022 2:53:56 PM Attachments:AIO 18E.001_ AIO 28.009_ AIO 35.004_ AIO 40.003_AIO 43.001.pdf The Alaska Oil and Gas Conservation Commission has issued the attached administrative approval amending a number of Area Injection Orders for ConocoPhillips Alaska, Inc.’s Colville River Unit, Alpine Oil Pool. Grace ____________________________________ Respectfully, M. Grace Salazar, Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Direct: (907) 793-1221 Email: grace.salazar@alaska.gov https://www.commerce.alaska.gov/web/aogcc/ __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: grace.salazar@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/grace.salazar%40alaska.gov AOGCC 333 W 7th Avenue, Anchorage, AK 99501 TO: BERNIE KARL K&K RECLYCLING, INC. PO BOX 58055 FAIRBANKS, AK 99711 Mailed 1/28/22gs 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 APPROVALS AREA INJECTION ORDER 18E.007 AREA INJECTION ORDER 28.010 AREA INJECTION ORDER 35A.001 AREA INJECTION ORDER 40.004 AREA INJECTION ORDER 43.002 Mr. Michael Driscoll WNS Development Supervisor North Slope Development ConocoPhillips Alaska, Inc. P.O Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-25-013 Making mechanical integrity testing notification requirements consistent across Colville River Unit and Greater Moose’s Tooth Unit pools Colville River Unit, Alpine Oil Pool, Qannik Oil Pool, and Nanuq Oil Pool Greater Moose’s Tooth Unit Lookout Oil Pool and Rendezvous Oil Pool Dear Mr. Driscoll: By letter dated March 17, 2025, ConocoPhillips Alaska, Inc. (CPAI) asked the Alaska Oil and Gas Conservation Commission (AOGCC) to reconsider a portion of Rule 5 of Enhanced Recovery Injection Order No. 9 (ERIO 9) which stated that CPAI was required to provide a minimum of 72- hour notice prior to conducting a required mechanical integrity test. CPAI pointed out that other pools the in Colville River Unit (CRU) and Greater Moose’s Tooth Unit (GMTU) have different minimum notification requirements and that the pools should be consistent and proposed changing the requirement in Rule 5 of ERIO 9 from 72 to 24 hours. The AOGCC agrees the notification requirement should be consistent across all pools in these two units. However, the CRU and GMTU are remote locations in the context of Industry Guidance Bulletins (IGB) 10-01A (Test Witness Notification) and IGB 10-02B (Mechanical Integrity Testing) because the fields do not have a permanent road connection to Alaska’s road system and therefore 48 hours’ notice is appropriate for these fields. On its own motion and in accordance with 20 AAC 25.556(d), the AOGCC hereby amends the Demonstration of Tubing/Casing Annulus Mechanical Integrity rules in the injection orders for the CRU and GMTU fields. AIO 18E.007, 28.010, 35A.001, 40.004, and 43.002 April 24, 2025 Page 2 of 4 Now Therefore it is Ordered: Rule 6 of AIO 18E is amended to read as follows: Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity (Source: Revised This Order for Clarification) The mechanical integrity of each injection well must be demonstrated before injection begins and before returning a well to service following any workover affecting mechanical integrity. An AOGCC-witnessed MIT must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (e.g., temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. For slurry injection wells, the tubing/casing annulus must be tested for mechanical integrity every two years. The AOGCC must be notified at least 48 hours in advance to enable a representative to witness an MIT. Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 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. Results of MITs must be readily available for AOGCC inspection. Rule 6 of AIO 28 is amended to read as follows: Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity A Commission-witnessed mechanical integrity test must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter, except at least once every two years in the case of a slurry injection well. The Commission must be notified at least 48 hours in advance to enable a representative to witness mechanical integrity tests. 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 1,500 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. Results of mechanical integrity tests must be readily available for Commission inspection. Rule 6 of AIO 35A is amended to read as follows: Rule 6. Demonstration of Tubing/Casing Annulus Mechanical Integrity (Source: AIO 35) The mechanical integrity of an injection well must be demonstrated before injection begins, and before returning a well to service following a workover affecting mechanical integrity. An AOGCC-witnessed mechanical integrity test must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter (except at least once every two years in the case of a slurry injection well). The AOGCC must be notified at least 48 hours in advance to enable a representative to witness mechanical integrity tests. Unless an alternate means is AIO 18E.007, 28.010, 35A.001, 40.004, and 43.002 April 24, 2025 Page 3 of 4 approved by the AOGCC, 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. Results of mechanical integrity tests must be readily available for AOGCC inspection. Rule 6 of AIO 40 is amended to read as follows: Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of each injection well must be demonstrated before injection begins and before returning a well to service following any workover affecting mechanical integrity. An AOGCC-witnessed MIT must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. The AOGCC must be notified at least 48 hours in advance to enable a representative to witness an MIT. Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 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. Results of MITs must be readily available for AOGCC inspection. Rule 6 of AIO 43 is amended to read as follows: Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of each injection well must be demonstrated before injection begins and before returning a well to service following any workover affecting mechanical integrity. An AOGCC-witnessed mechanical integrity test (MIT) must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. The AOGCC must be notified at least 48 hours in advance to enable a representative to witness an MIT. Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 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. Results of MITs must be readily available for AOGCC inspection. DONE at Anchorage, Alaska and dated April 24, 2025. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.04.23 15:47:29 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.23 16:29:43 -08'00' AIO 18E.007, 28.010, 35A.001, 40.004, and 43.002 April 24, 2025 Page 4 of 4 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:Area Injection Orders 18E.007, 28.010, 35A.001, 40.004, 43.002 (CPAI) Date:Thursday, April 24, 2025 9:25:00 AM Attachments:AIO18E.007_AIO28.010_AIO35A.001_AIO40.004_AIO43.002.pdf Docket Number: AIO-25-013 Making mechanical integrity testing notification requirements consistent across Colville River Unit and Greater Moose’s Tooth Unit pools Colville River Unit, Alpine Oil Pool, Qannik Oil Pool, and Nanuq Oil Pool Greater Moose’s Tooth Unit Lookout Oil Pool and Rendezvous Oil Pool Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 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 APPROVALS AREA INJECTION ORDER NO. 2C.096 AREA INJECTION ORDER NO. 16.009 AREA INJECTION ORDER NO. 18E.008 AREA INJECTION ORDER NO. 28.011 AREA INJECTION ORDER NO. 35A.002 AREA INJECTION ORDER NO. 39A.001 AREA INJECTION ORDER NO. 40.005 AREA INJECTION ORDER NO. 43.003 Greg Hobbs, Regulatory Engineer ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-25-001 Request to change language of Area Injection Order Rule 7 Well Integrity and Confinement Dear Mr. Hobbs: By letter dated January 15, 2025, ConocoPhillips Alaska, Inc. (CPAI) requested the amendment to Rule 7 of the Area Injection Orders listed below: •AIO 18E: Colville River Field, Colville River Unit, Alpine Oil Pool • AIO 28: Colville River Field, Colville River Unit, Nanuq Oil Pool • AIO 35A: Colville River Field, Colville River Unit, Qannik Oil Pool • AIO 39A: Kuparuk River Field, Kuparuk River Unit, Torok Oil Pool • AIO 40: Greater Moose's Tooth Field, Greater Moose's Tooth Unit, Lookout Oil Pool • AIO 43: Greater Moose's Tooth Field, Greater Moose's Tooth and Bear Tooth Units, Rendezvous Oil Pool The purpose of the amendment is to clarify the appropriate process and current practice when pressure communication, leakage or lack of injection zone isolation is indicated by certain data observed by the operator. CPAIproposed adopting the Rule 7 language from the recently approved AIO 45 Coyote Oil Pool. AIO 2C.096, AIO 16.009, AIO 18E.008, AIO 28.011, AIO 35A.002, AIO 39A.001, AIO 40.005, and AIO 43.003 May 12, 2025 Page 2 of 3 In accordance with 20 AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI’s request to amend Rule 7 of the AIOs listed above. Additionally, on its own motion, and in accordance with 20 AAC 25.556(d), the AOGCC has determined that Rule 7 of the CPAI AIO’s listed below should also be amended for the same reasons. • AIO 2C: Kuparuk River Field, Kuparuk River Unit, Kuparuk River, West Sak, and Tabasco Oil Pools • AIO 16: Kuparuk River Field, Kuparuk River Unit, Tarn Oil Pool Now Therefore it is Ordered: Rule 7 of each of the AIO’s listed is amended to read as follows: Rule 7 Well Integrity and Confinement Whenever an indication of pressure communication, leakage, or lack of injection zone isolation occurs, the operator must notify the AOGCC by the next business day. Such indication may arise from information including but not limited to injection rate, operating pressure observation, test, survey, log, or outer anulus pressure monitoring in wells within one-quarter mile radius of where the applicable defined oil pool is not cemented. If the operator's investigation supports a conclusion of pressure communication, leaking, or lack of injection zone isolation, the operator must submit a corrective action plan to the AOGCC, following the applicable unit sundry matrix order. The operator must shut in any well for which: (a) continued operation would be unsafe, (b) continued operation would threaten contamination of freshwater; or (c) the AOGCC directs the operator to shut in the well. The operator must submit a monthly report of daily tubing and casing annuli pressures and injection rate for injection wells that (a) are subject to administrative approval (AA) to operate; or (b) lack injection zone isolation. DONE at Anchorage, Alaska and dated May 12, 2025. Jessie L. Chmielowski Gregory C. Wilson. Commissioner, Chair Commissioner Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.05.12 12:12:38 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.05.12 13:42:57 -08'00' AIO 2C.096, AIO 16.009, AIO 18E.008, AIO 28.011, AIO 35A.002, AIO 39A.001, AIO 40.005, and AIO 43.003 May 12, 2025 Page 3 of 3 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 Orders Admin Approvals (CPAI) Date:Monday, May 12, 2025 1:54:34 PM Attachments:AIO2C.096, AIO16.009, AIO18E.008, AIO28.011, AIO35A.002, AIO39A.001, AIO40.005, and AIO43.003.pdf Docket Number: AIO-25-001 Request to change language of Area Injection Order Rule 7 Well Integrity and Confinement 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 INDEXES 20 January 15, 2025 VIA E-MAIL DELIVERY Victoria Loepp Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: Area Injection Order Rule 7 Proposed Language Change Dear Ms. Loepp, ConocoPhillips Alaska Inc. (CPAI) makes this application to amend the Area Injection Orders listed below to clarify the appropriate process and current practice when pressure communication, leakage or lack of injection zone isolation is indicated by certain data observed by the operator. An example of the current area injection order language from the Alpine Area Injection Order (AIO 18E) is as follows: Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by an injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall, by the next business day, 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 AOGCC. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC for all injection wells indicating well integrity failure or lack of injection zone isolation. There are two concerns with the current language. First, the rule requires the filing of a form 10-403 report with the AOGCC on the next business day. This does not represent current practice. Instead, the rule should require the Operator to notify the AOGCC by the next business day and file a report following the applicable AOGCC Sundry matrix only if the Operator’s investigation supports a conclusion of pressure communication, leaking, or lack of injection zone isolation. Second, the current rule requires the submission of daily tubing and casing annuli pressure for all injection wells indicating well integrity failure or lack of injection zone isolation. The current practice is not to submit this information for wells that are shut in. The shut in wells are separately tracked in the annual long-term shut-in wells report to the AOGCC. Greg Hobbs Principal Regulatory Engineer 700 G Street, ATO 1562 Anchorage, AK 99510 (907) 263-4749 (office) Greg.S.Hobbs@conocophillips.com By Samantha Coldiron at 12:09 pm, Jan 15, 2025 2 CPAI proposes the following language from the recent Coyote Oil Pool area injection order to resolve both issues: Whenever an indication of pressure communication, leakage, or lack of injection zone isolation occurs, the operator must notify the AOGCC by the next business day. Such indication may arise from information including but not limited to injection rate, operating pressure observation, test, survey, log, or outer anulus pressure monitoring in wells within one-quarter mile radius of where the COP is not cemented. If the operator’s investigation supports a conclusion of pressure communication, leaking, or lack of injection zone isolation, the operator must submit a corrective action plan to the AOGCC, following the [KRU, CRU or GMTU sundry matrix order as applicable]. The operator must shut in any well for which: (a) continued operation would be unsafe, (b) continued operation would threaten contamination of freshwater; or (c) the AOGCC directs the operator to shut in the well. The operator must submit a monthly report of daily tubing and casing annuli pressures and injection rate for injection wells that (a) are subject to administrative approval (AA) to operate; or (b) lack injection zone isolation. If acceptable, CPAI requests that the rule be modified in the following orders with appropriate reference to the applicable sundry matrix order: x AIO 18E: Colville River Field, Colville River Unit, Alpine Oil Pool x AIO 28: Colville River Field, Colville River Unit, Nanuq Oil Pool x AIO 35A: Colville River Field, Colville River Unit, Qannik Oil Pool x AIO 39A: Kuparuk River Field, Kuparuk River Unit, Torok Oil Pool x AIO 40: Greater Moose’s Tooth Field, Greater Moose’s Tooth Unit, Lookout Oil Pool x AIO 43: Greater Moose’s Tooth Field, Greater Moose’s Tooth and Bear Tooth Units, Rendezvous Oil Pool CPAI appreciates your consideration of this request. Feel free to contact me at 907-263-4749 or greg.s.hobbs@conocophillips.com with any questions. Sincerely, Greg Hobbs Regulatory Engineer ConocoPhillips Alaska, Inc. Digitally signed by Greg Hobbs DN: OU=Regulatory Engineer, O= ConocoPhillips Alaska Wells, CN=Greg Hobbs, E=greg.s.hobbs@ conocophillips.com Reason: I am the author of this document Location: Date: 2025.01.15 10:49:29-09'00' Foxit PDF Editor Version: 13.0.0 Greg Hobbs 19 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 April 24, 2023 Commissioner Jessie Chmielowski Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Commissioner Chmielowski, ConocoPhillips Alaska, Inc. submits the attached application to amend administrative approval AIO28.008 to allow CRU injection well CD4-291 (PTD 213-110) to allow water alternating gas (WAG) injection. The well currently has known tubing by inner annulus communication only while on gas injection. Please contact me at 907-265-6181 if you have any questions. Sincerely, Kate Dodson Well Integrity Specialist ConocoPhillips Alaska, Inc. Kathleen Dodson Digitally signed by Kathleen Dodson Date: 2023.04.27 13:47:10 -08'00' P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Well Integrity Specialist 4/24/2023 1 Alpine Well CD4-291 (PTD 213-110) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. requests AOGCC amend Administrative Relief Area Injection Order 28.008, to allow water alternating gas (WAG) injection for Colville River Unit injection well CD4-291 (PTD 213-110). The well displays tubing by inner annulus (IA) communication only during gas injection (MI). Well History and Status Colville River Unit injector CD4-291 was reported to the Commission on June 29,2019, for a suspect IA pressure increase while on miscible gas injection. AOGCC approved diagnostic monitor periods for both MI and water injection services, which confirmed the tubing to IA communication only existed during MI injection. Early in 2023, CPAI discovered a significant benefit to maintaining gas injection in to CD4-291. CPAI conducted diagnostics including MITOA, packoff tests and MITIA, and confirmed the well’s integrity. Barrier and Hazard Evaluation Tubing: The 3-1/2”, 9.3lb/ft, L-80 grade tubing has integrity to the packer at 6704’ MD (6078' TVD) based on passing a MIT-IA to 4200 psi on 3/29/2023. Intermediate casing: The 7”, 26 lb/ft, L-80 grade intermediate casing has integrity to the packer at 6704’ MD (6078' TVD) based on the previously mentioned MIT-IA and TIO trends. Surface casing: The 10-3/4”, 45.5 lb/ft, L-80 grade surface casing has an internal yield pressure rating of 5210 psi. The surface casing has integrity based on TIO trends. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Secondary barrier: The intermediate casing is the secondary barrier should the tubing fail. Tertiary barrier: The surface casing will act as a third barrier in the unlikely case that the first two normal barriers have failures. Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the completion it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. TIO trends are compiled, reviewed, and submitted to the AOGCC for review monthly. Proposed Operating and Monitoring Plan P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Well Integrity Specialist 4/24/2023 2 1. Well will be used for water alternating gas injection. 2. Perform a passing MITIA every 2-years to maximum anticipated injection pressure. 3. Allow operating IA pressure up to 2,400 psi during gas injection service and 2,000 psi during water injection service. The operating OA pressure is allowed up to 1,000 psi. 4. Pressure transmitters will be maintained on the IA and OA allowing real time monitoring and alarm notifications. 5. Submit monthly reports of daily tubing, IA, and OA pressures, injection volumes and pressure bleeds for all annuli. 6. Shut-in the well if diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. 7. Maintain the injection line choke and SSV remote shut down capability. During gas injection, the inner annulus protocols will include a drill site operator alarm set at 2,200 psi, and a high alarm set at 2,400 psi that will prompt the control room Board Operator to remotely shut in the choke or SSV. 8. MIT Anniversary date will continue to be the month of June to maintain the 2-year AOGCC witnessed testing with the UIC MIT permanent 4-year scheduled pad testing. CD4-291 90-Day Bleed History WELL DATE STR-PRES END-PRES DIF-PRES CASING CD4-291 2023-04-08 1616 975 -641 IA CD4-291 2023-04-08 1616 975 -641 IA Last Tag Annotation Depth (ftKB)End Date Wellbore Last Mod By Last Tag:CD4-291 haggea Last Rev Reason Annotation End Date Wellbore Last Mod By Rev Reason: Reset Inj Valve 9/11/2019 CD4-291 boehmbh Casing Strings Casing Description CONDUCTOR Insulated 34" OD (in) 16 ID (in) 15.06 Top (ftKB) 35.0 Set Depth (ftKB) 114.0 Set Depth (TVD)… 114.0 Wt/Len (l… 62.50 Grade H-40 Top Thread Welded Casing Description SURFACE OD (in) 10 3/4 ID (in) 9.95 Top (ftKB) 36.9 Set Depth (ftKB) 2,436.4 Set Depth (TVD)… 2,378.5 Wt/Len (l… 45.50 Grade L-80 Top Thread BTCM Casing Description INTERMEDIATE OD (in) 7 ID (in) 6.28 Top (ftKB) 34.5 Set Depth (ftKB) 7,209.7 Set Depth (TVD)… 6,210.2 Wt/Len (l… 26.00 Grade L-80 Top Thread BTCM Casing Description LINER OD (in) 3 1/2 ID (in) 2.99 Top (ftKB) 6,703.9 Set Depth (ftKB) 12,585.0 Set Depth (TVD)… 6,244.2 Wt/Len (l… 9.30 Grade L-80 Top Thread SLHT Liner Details Top (ftKB)Top (TVD) (ftKB)Top Incl (°)Item Des Com Nominal ID (in) 6,703.96,077.7 65.47 PACKER BAKER HRD ZXP LINER TOP PACKER 4.320 6,723.9 6,085.9 66.27 NIPPLE BAKER 5'' RS NIPPLE 4.250 6,726.8 6,087.0 66.39 HANGER BAKER FLEX LOCK LINER HANGER 4.340 6,736.8 6,091.0 66.79 SBE BAKER 80-40 10' SEAL BORE EXTENSION 4.000 6,761.4 6,100.5 67.78 NIPPLE HES XN LANDING NOGO NIPPLE 2.813 Tubing Strings Tubing Description TUBING 4.5x3.5"@138' String Ma… 3 1/2 ID (in) 2.99 Top (ftKB) 31.4 Set Depth (ft… 6,745.4 Set Depth (TVD) (… 6,094.4 Wt (lb/ft) 9.30 Grade L-80 Top Connection EUE-M Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Item Des Com Nominal ID (in) 31.4 31.4 0.00 HANGER FMC TUBING HANGER 3.958 138.6 138.6 0.13 XO - Reducing XO - 4 1/2" IBT (B) x 3 1/2" EUE 8 RD (P)2.992 2,009.3 1,974.3 19.41 NIPPLE CAMCO BP-6i NIPPLE w/ 2.812" DS profile 2.812 6,675.7 6,065.7 64.34 NIPPLE HES X LANDING NIPPLE 2.813 6,714.5 6,082.065.89 LOCATOR BAKER LOCATOR (5.00" OD)2.990 6,715.7 6,082.5 65.94 SEAL ASSY BAKER 80-40 SEAL ASSY 2.990 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Des Com Run Date ID (in)SN 2,009.3 1,974.2 19.41 INJ VALVE 2.81" A-1 INJ VLV (S/N: HABS-0223/ 1.5" ORIFICE) ON B-7 LOCK 9/11/2019 1.500 6,671.0 6,063.7 64.16 FISH RHC PLUG BODY PUSHED DOWNHOLE TO NIPPLE AND HELD BY SLIPSTOP 10/12/20130.000 Perforations & Slots Top (ftKB)Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB)Linked Zone Date Shot Dens (shots/ft )Type Com 7,246.6 7,339.7 6,214.5 6,218.3 9/29/2013 16.0 SLOTS Slotted 2 1/4" x .125 slots/8 rows/16 slots/ft 7,559.68,895.7 6,217.36,214.4 9/29/2013 16.0SLOTSSlotted 2 1/4" x .125 slots/8 rows/16 slots/ft 8,990.09,230.26,215.26,219.09/29/2013 16.0SLOTSSlotted 2 1/4" x .125 slots/8 rows/16 slots/ft 9,387.010,481.96,219.16,223.89/29/2013 16.0SLOTSSlotted 2 1/4" x .125 slots/8 rows/16 slots/ft 10,889.611,505.26,234.06,240.7 9/29/2013 16.0SLOTSSlotted 2 1/4" x .125 slots/8 rows/16 slots/ft 11,693.312,270.26,240.5 6,243.99/29/2013 16.0SLOTSSlotted 2 1/4" x .125 slots/8 rows/16 slots/ft 12,364.1 12,454.5 6,245.1 6,246.4 9/29/2013 16.0 SLOTS Slotted 2 1/4" x .125 slots/8 rows/16 slots/ft Mandrel Inserts St ati on N o/Top (ftKB) Top (TVD) (ftKB)Make Model OD (in)Serv Valve Type Latch Type Port Size (in) TRO Run (psi)Run Date Com 1 6,658.5 6,058.2 CAMCO KBMG 1 GAS LIFT DMY BK 0.000 0.0 2/1/2018 Notes: General & Safety End Date Annotation 9/20/2017 Note: Waivered for Water-Only Injection due to surface casing leak 10/22/2013 NOTE: Mandrel Orientation #1) 9:30 HORIZONTAL, CD4-291, 5/29/2020 11:19:30 AM Vertical schematic (actual) LINER; 6,703.9-12,585.0 SLOTS; 12,364.1-12,454.5 SLOTS; 11,693.3-12,270.2 SLOTS; 10,889.5-11,505.2 SLOTS; 9,387.0-10,481.9 SLOTS; 8,990.0-9,230.1 SLOTS; 7,559.6-8,895.7 SLOTS; 7,246.6-7,339.7 INTERMEDIATE; 34.5-7,209.7 SEAL ASSY; 6,715.7 LOCATOR; 6,714.5 NIPPLE; 6,675.7 FISH; 6,671.0 GAS LIFT; 6,658.5 SURFACE; 36.9-2,436.4 INJ VALVE; 2,009.3 NIPPLE; 2,009.3 CONDUCTOR Insulated 34"; 35.0-114.0 HANGER; 31.4 WNS INJ KB-Grd (ft) 36.47 Rig Release Date 10/2/2013 CD4-291 ... TD Act Btm (ftKB) 12,595.0 Well Attributes Field Name NANUQ Wellbore API/UWI 501032067200 Wellbore Status INJ Max Angle & MD Incl (°) 92.11 MD (ftKB) 12,535.30 WELLNAME WELLBORE Annotation Last WO: End DateH2S (ppm)DateComment SSSV: WRDP Submit to: OOPERATOR: FFIELD / UNIT / PAD: DDATE: OOPERATOR REP: AAOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 213-110 Type Inj W Tubing 2087 2085 2085 2085 Type Test P Packer TVD 6078 BBL Pump 2.3 IA 1360 4200 4157 4144 Interval O Test psi 1520 BBL Return 2.3 OA 526 699 698 692 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: ConocoPhillips Alaska Inc, Alpine / CRU / CD4 Pad Brendan Weimer 03/29/23 Notes:Non-witnessed diagnostic MITIA Notes: Notes: Notes: CD4-291 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMechani cal Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: Form 10-426 (Revised 01/2017)CD4-291 MIT 3-29-2023.xlsx 18 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Commissioner Chmielowski, ConocoPhillips Alaska, Inc. submits the attached application to amend administrative approval AIO28.006 to allow CRU injection well CD4-214 (PTD 206-145) to allow water alternating gas (WAG) injection. The well currently has known tubing by inner annulus communication only while on gas injection. Please contact me at 907-265-6181 if you have any questions. Sincerely, Kate Dodson Well Integrity Specialist ConocoPhillips Alaska, Inc. February 21, 2023 Commissioner Jessie Chmielowski Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 By Samantha Carlisle at 1:41 pm, Feb 21, 2023 Kathleen Dodson Digitally signed by Kathleen Dodson Date: 2023.02.21 11:26:30 -09'00' Well Integrity Specialist 1 ConocoPhillips Alaska, Inc. Alpine Well CD4-214 (PTD 206-145) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. requests AOGCC amend Administrative Relief Area Injection Order 28.006, to allow water alternating gas (WAG) injection for Colville River Unit injection well CD4-214 (PTD 206-145). The well displays tubing by inner annulus (IA) communication only during gas injection. Well History and Status Colville River Unit well CD4-214 (PTD 206-145) was completed in November 2006. After a pre-production period and a shut-in time for pressure observation, the well was placed into injection service in October 2009. In July 2017, the well was reported to the Commission for slowly increasing IA pressure while on gas injection. During AOGCC approved injection monitor periods, pressure trends showed TxIA communication exists only when the well is on gas injection service. Diagnostics performed during the monitor period, including passing MITIA and packoff tests, also confirmed the well’s integrity to liquid. In July of 2021, the well was reported to AOGCC for a surface casing leak. The surface casing has been repaired. Diagnostics performed after the repair, including passing MITIA and packoff tests, confirmed the well’s integrity. Barrier and Hazard Evaluation Tubing:The 4-1/2”, 12.6 lb, L-80 tubing has integrity to the packer at 7,524’ RKB (5,967’ TVD) based on a passing MITIA to 4,200 psi on 12/25/2022. Production casing:The 7”, 26 lb, L-80 production casing has integrity down to the packer at 7,524’ RKB (5,967’ TVD) based on the previously mentioned passing MITIA to 3,300 psi. This production casing has an internal yield pressure rating of 7,240 psi. Surface casing:The well is completed with 9-5/8”, 40 lb,L-80 surface casing. This surface casing has an internal yield pressure rating of 5,750 psi. The surface casing was previously repaired externally to cover a shallow leak. Primary barrier:The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Secondary barrier:The production casing is the secondary barrier should the tubing fail. Monitoring:Each well is monitored daily for wellhead pressure changes. Should leaks develop in the tubing or casing it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. T/I/O plots are compiled, reviewed, and submitted to the AOGCC for review monthly. Proposed Operating and Monitoring Plan 1. Well will be used for water alternating gas injection. 2. Perform a passing MITIA every 2-years to maximum anticipated injection pressure. 2/21/2023 Well Integrity Specialist 2 3. Allow operating IA pressure up to 2,400 psi during gas injection service and 2,000 psi during water injection service. The operating OA pressure is allowed up to 1,000 psi. 4. Pressure transmitters will be maintained on the IA and OA allowing real time monitoring and alarm notifications. 5. Submit monthly reports of daily tubing, IA, and OA pressures, injection volumes and pressure bleeds for all annuli. 6. Shut-in the well if diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. 7. Maintain the injection line choke and SSV remote shut down capability. During gas injection, the inner annulus protocols will include a drill site operator alarm set at 2,200 psi, and a high alarm set at 2,400 psi that will prompt the control room Board Operator to remotely shut in the choke or SSV. 8. MIT Anniversary date will continue to be the month of June to maintain the 2-year AOGCC witnessed testing with the UIC MIT permanent 4-year scheduled pad testing. 2/21/2023 CD4-214 90-Day Bleed History WELL DATE STR-PRES END-PRES DIF-PRES CASING CD4-214 2022-12-25 643.0 498 -145.0 IA CD4-214 2023-02-11 225.0 965 740.0 OA CD4-214 2023-02-15 982.0 200 -782.0 OA CD4-214 2023-02-18 256.0 0 -256.0 OA Last Tag Annotation Depth (ftKB) End Date Wellbore Last Mod By Last Tag:CD4-214 claytg Last Rev Reason Annotation End Date Wellbore Last Mod By Rev Reason: Set Retrievable Plug 9/10/2021 CD4-214 boehmbh Casing Strings Casing Description CONDUCTOR OD (in) 16 ID (in) 15.25 Top (ftKB) 37.0 Set Depth (ftKB) 114.0 Set Depth (TVD) … 114.0 Wt/Len (l… 68.00 Grade H-40 Top Thread Casing Description SURFACE OD (in) 9 5/8 ID (in) 8.83 Top (ftKB) 36.4 Set Depth (ftKB) 2,677.0 Set Depth (TVD) … 2,365.4 Wt/Len (l… 40.00 Grade L-80 Top Thread BTC-M Casing Description INTERMEDIATE OD (in) 7 ID (in) 6.28 Top (ftKB) 34.2 Set Depth (ftKB) 8,696.0 Set Depth (TVD) … 6,210.4 Wt/Len (l… 26.00 Grade L-80 Top Thread Casing Description OPEN HOLE 258' OD (in) 6 1/8 ID (in) Top (ftKB) 14,814.3 Set Depth (ftKB) 15,072.0 Set Depth (TVD) … 6,279.7 Wt/Len (l…Grade Top Thread Casing Description LINER OD (in) 4 1/2 ID (in) 3.99 Top (ftKB) 8,493.9 Set Depth (ftKB) 14,814.3 Set Depth (TVD) … 6,263.8 Wt/Len (l… 12.60 Grade L-80 Top Thread SLHT Liner Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Com Nominal ID (in) 8,493.9 6,197.1 86.14 SLEEVE BAKER 'HR' LINER SETTING SLEEVE 4.420 8,506.9 6,198.0 86.17 NIPPLE BAKER 'RS' PACKOFF SEAL NIPPLE 4.250 8,510.7 6,198.2 86.18 HANGER BAKER 'DG' FLEX LOCK LINER HANGER 4.400 8,520.5 6,198.9 86.20 XO 5x4.5 CROSSOVER 5" x 4.5" 4.000 Tubing Strings Tubing Description TUBING String Ma… 4 1/2 ID (in) 3.96 Top (ftKB) 31.9 Set Depth (ft… 8,506.8 Set Depth (TVD) (… 6,198.0 Wt (lb/ft) 12.60 Grade L-80 Top Connection Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Com Nominal ID (in) 31.9 31.9 0.00 HANGER FMC TUBING HANGER 4.500 2,189.2 1,983.2 37.45 NIPPLE DB NIPPLE 3.812 7,523.5 5,967.5 62.04 PACKER BAKER PREMIER PACKER 3.875 7,580.8 5,993.5 63.89 NIPPLE XN NIPPLE. 3.725 XN Nipple Milled to 3.80" 3.800 8,494.6 6,197.2 86.15 WLEG BAKER FLUTED WLEG ASSEMBLY 3.958 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Des Com Run Date ID (in) SN 7,700.0 6,043.0 67.10 RBP 4.5" EVO-TRIEVE PLUG 9/10/2021 0.000 8,750.0 6,214.4 85.55 WHIPSTOCK - MONOBORE 4.5" monobore whipstock - BOT tray 180° ROHS 12/7/2019 1.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft )Type Com 8,688.0 14,773.0 6,209.8 6,260.9 11/10/2006 32.0 SLOTS Alternating solid/slotted pipe - 0.125"x2.5" @ 4 circumferential adjacent rows, 3" centers staggered 18 deg, 3' non-slotted ends Stimulation Intervals Interva l Numbe r Type Subtype Start Date Top (ftKB) Btm (ftKB) Proppant Designed (lb) Proppant Total (lb) Vol Clean Total (bbl) Vol Slurry Total (bbl) 1 ACID STIM 4/13/2007 12,230.0 14,820.0 0.0 0.00 0.00 Mandrel Inserts St ati on N o/Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Make Model OD (in) Serv Valve Type Latch Type Port Size (in) TRO Run (psi) Run Date Com 1 7,419.0 5,915.3 58.15 CAMCO KBG-2 1 Gas Lift DMY BK 0.000 6/25/2019 Notes: General & Safety End Date Annotation 9/25/2017 Note: Waivered for Water-Only Injection due to TxIA on gas 7/24/2009 NOTE: ZONES NOT LOADED TO WELLVIEW YET 11/7/2008 NOTE: VIEW SCHEMATIC w/Alaska Schematic9.0 11/13/2006 NOTE: TREE: FMC 4-1/16" 5000 psi - TREE CAP CONNECTION: 7" OTIS CD4-214, 9/29/2021 1:34:33 PM Vertical schematic (actual) OPEN HOLE 258'; 14,814.3- 15,072.0 LINER; 8,493.9-14,814.3 ACID STIM; 12,230.0 SLOTS; 8,688.0-14,773.0 WHIPSTOCK - MONOBORE; 8,750.0 L1 Slotted Liner; 8,725.1- 10,812.0 INTERMEDIATE; 34.2-8,696.0 WLEG; 8,494.6 RBP; 7,700.0 NIPPLE; 7,580.8 PACKER; 7,523.4 GAS LIFT; 7,419.0 SURFACE; 36.4-2,677.0 NIPPLE; 2,189.2 CONDUCTOR; 37.0-114.0 HANGER; 31.9 WNS INJ KB-Grd (ft) 43.34 Rig Release Date 11/14/2006 CD4-214 ... TD Act Btm (ftKB) 15,072.0 Well Attributes Field Name NANUQ Wellbore API/UWI 501032053700 Wellbore Status INJ Max Angle & MD Incl (°) 93.59 MD (ftKB) 9,890.12 WELLNAME WELLBORECD4-214 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: INJ VALVE Submit to: OOPERATOR: FFIELD / UNIT / PAD: DDATE: OOPERATOR REP: AAOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 206145 Type Inj G Tubing 2041 2041 2035 2035 Type Test P Packer TVD 5967 BBL Pump 2.5 IA 643 4200 4155 4150 Interval O Test psi 1500 BBL Return OA 178 185 184 184 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMechani cal Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: ConocoPhillips Alaska Inc, Alpine / CRU / CD4 Pad Arend 12/25/22 Notes:Non-witnessed diagnostic MITIA Notes: Notes: Notes: CD4-214 Form 10-426 (Revised 01/2017)CD4-214 10-426 25Dec22.xlsx 17 By Grace Salazar at 1:21 pm, May 26, 2021 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 November 30, 2021 Commissioner Chmielowski Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner, ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 28, Rule 11, to apply for administrative approval to allow injection well CRU CD4-291 (PTD 213-110) to remain in water-only injection service. The well was recently determined to show suspect IA pressurization only while on MI gas injection. If you need additional information, please contact me at 670-4014. Sincerely, Travis Smith Well Intervention & Integrity Engineer ConocoPhillips Alaska, Inc. By Grace Salazar at 2:19 pm, Dec 01, 2021 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 1 Colville River Unit Injector CRU CD4-291 (PTD 213-110) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. (CPAI) proposes that the AOGCC approve this administrative relief request as per Area Injection Order 28, Rule 11, to continue water only injection for Colville River Unit injection well CD4-291 (PTD 213-110). The well displays IA pressurization only during miscible injectant (MI) gas injection. Well History and Status Colville River Unit well CD4-291 (PTD 213-110) was completed in 2013 as a service well. CD4-291 was reported to the Commission in April 2017 for showing signs of a surface casing leak to atmosphere via the surface casing by conductor annulus. From 2017 until June 2018 the well operated under Administrative Approval as a water-only injector due to this surface casing leak. The AA was cancelled following an excavation repair of the surface casing in 2018. CD4-291 was reported to the Commission on July 2021 for inner annulus pressure increase while on MI injection. CPAI communicated a plan to the AOGCC that included intent to observe the well on water injection to confirm if the pressurization occurred during water injection. No suspect IA pressurization was observed during the water injection monitor period. Diagnostic testing in July 2021, including an MIT-IA to 4,200 psi, demonstrated the well has competent barriers for injection service. Further investigation of the IA pressurization seen only during gas/MI injection service may be pursued in future. However, as a diagnostic path forward will take time to develop, CPAI is currently requesting an Administrative Approval (AA) to allow continued water injection. Barrier and Hazard Evaluation Tubing: The 3-1/2”, 9.3 lb/ft, L-80 grade tubing has integrity to the seal assembly at 6716’ MD (6083' TVD), based on passing a MIT-IA to 4,200 psi on 7/20/21 and water injection TIO trends. Intermediate casing: The 7”, 26 lb/ft, L-80 grade casing has integrity to the packer at 6716’ MD (6083' TVD), based on the aforementioned MIT-IA and TIO trends. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation during water injection is the tubing and packer. Secondary barrier: The intermediate casing is the secondary barrier should the tubing fail. Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the completion it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication requires investigation, Commission notification, and corrective P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 2 action, up to and including a shut-in of the well. TIO trends are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. Proposed Operating and Monitoring Plan 1. WAG well to be used for water only injection (no MI or gas injection allowed); 2. Perform a passing MITIA every 2-years to maximum anticipated injection pressure; 3. Allow operating IA pressure up to 2000 psi and operating OA pressure up to 1000 psi; 4. Submit monthly reports of daily tubing & IA pressures, injection volumes and pressure bleeds for all annuli; 5. Shut-in the well should diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC; 6. Anniversary date for the AOGCC witnessed testing to be set for the month of June 2019 (last AOGCC witnessed test was June 20, 2019) to align with the UIC MIT permanent pad testing schedule. Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2131100 Type Inj W Tubing 3525 3525 3525 3525 Type Test P Packer TVD 6078 BBL Pump 3.1 IA 1475 4200 4120 4105 Interval O Test psi 3800 BBL Return 2.9 OA 0 2 2 2 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting ConocoPhillips Alaska Inc, ALPINE / CRU / CD4 PAD N/A Van Camp 07/20/21 Notes:Non-witnessed diagnostic MIT-IA Notes: CD4-291 Notes: Notes: Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Form 10-426 (Revised 01/2017)MIT CRU CD4-291 07-20-21.xlsx Annular Communication Surveillance 31 Well Name:CCD4-291 Start Date:31-Aug-2021 29 Days:90 End Date:29-Nov-2021 50 60 70 80 90 100 110 120 130 140 150 0 500 1000 1500 2000 2500 31-Aug-213-Sep-216-Sep-219-Sep-2112-Sep-2115-Sep-2118-Sep-2121-Sep-2124-Sep-2127-Sep-2130-Sep-213-Oct-216-Oct-219-Oct-2112-Oct-2115-Oct-2118-Oct-2121-Oct-2124-Oct-2127-Oct-2130-Oct-212-Nov-215-Nov-218-Nov-2111-Nov-2114-Nov-2117-Nov-2120-Nov-2123-Nov-2126-Nov-2129-Nov-21Temperature (degF)Pressure (PSI)Pressure Summary WHP IAP OAP WHT 0 200 400 600 800 1000 1200 1400 31-Aug-213-Sep-216-Sep-219-Sep-2112-Sep-2115-Sep-2118-Sep-2121-Sep-2124-Sep-2127-Sep-2130-Sep-213-Oct-216-Oct-219-Oct-2112-Oct-2115-Oct-2118-Oct-2121-Oct-2124-Oct-2127-Oct-2130-Oct-212-Nov-215-Nov-218-Nov-2111-Nov-2114-Nov-2117-Nov-2120-Nov-2123-Nov-2126-Nov-2129-Nov-21Injection Rate (BPD or MSCFD)Injection Rate Summary DGI MGI PWI SWI BLPD Last Tag Annotation Depth (ftKB)End Date Wellbore Last Mod By Last Tag:CD4-291 haggea Last Rev Reason Annotation End Date Wellbore Last Mod By Rev Reason: Reset Inj Valve 9/11/2019 CD4-291 boehmbh Casing Strings Casing Description CONDUCTOR Insulated 34" OD (in) 16 ID (in) 15.06 Top (ftKB) 35.0 Set Depth (ftKB) 114.0 Set Depth (TVD)… 114.0 Wt/Len (l… 62.50 Grade H-40 Top Thread Welded Casing Description SURFACE OD (in) 10 3/4 ID (in) 9.95 Top (ftKB) 36.9 Set Depth (ftKB) 2,436.4 Set Depth (TVD)… 2,378.5 Wt/Len (l… 45.50 Grade L-80 Top Thread BTCM Casing Description INTERMEDIATE OD (in) 7 ID (in) 6.28 Top (ftKB) 34.5 Set Depth (ftKB) 7,209.7 Set Depth (TVD)… 6,210.2 Wt/Len (l… 26.00 Grade L-80 Top Thread BTCM Casing Description LINER OD (in) 3 1/2 ID (in) 2.99 Top (ftKB) 6,703.9 Set Depth (ftKB) 12,585.0 Set Depth (TVD)… 6,244.2 Wt/Len (l… 9.30 Grade L-80 Top Thread SLHT Liner Details Top (ftKB)Top (TVD) (ftKB)Top Incl (°)Item Des Com Nominal ID (in) 6,703.96,077.7 65.47 PACKER BAKER HRD ZXP LINER TOP PACKER 4.320 6,723.9 6,085.9 66.27 NIPPLE BAKER 5'' RS NIPPLE 4.250 6,726.8 6,087.0 66.39 HANGER BAKER FLEX LOCK LINER HANGER 4.340 6,736.8 6,091.0 66.79 SBE BAKER 80-40 10' SEAL BORE EXTENSION 4.000 6,761.4 6,100.5 67.78 NIPPLE HES XN LANDING NOGO NIPPLE 2.813 Tubing Strings Tubing Description TUBING 4.5x3.5"@138' String Ma… 3 1/2 ID (in) 2.99 Top (ftKB) 31.4 Set Depth (ft… 6,745.4 Set Depth (TVD) (… 6,094.4 Wt (lb/ft) 9.30 Grade L-80 Top Connection EUE-M Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Item Des Com Nominal ID (in) 31.4 31.4 0.00 HANGER FMC TUBING HANGER 3.958 138.6 138.6 0.13 XO - Reducing XO - 4 1/2" IBT (B) x 3 1/2" EUE 8 RD (P)2.992 2,009.3 1,974.3 19.41 NIPPLE CAMCO BP-6i NIPPLE w/ 2.812" DS profile 2.812 6,675.7 6,065.7 64.34 NIPPLE HES X LANDING NIPPLE 2.813 6,714.5 6,082.065.89 LOCATOR BAKER LOCATOR (5.00" OD)2.990 6,715.7 6,082.5 65.94 SEAL ASSY BAKER 80-40 SEAL ASSY 2.990 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Des Com Run Date ID (in)SN 2,009.3 1,974.2 19.41 INJ VALVE 2.81" A-1 INJ VLV (S/N: HABS-0223/ 1.5" ORIFICE) ON B-7 LOCK 9/11/2019 1.500 6,671.0 6,063.7 64.16 FISH RHC PLUG BODY PUSHED DOWNHOLE TO NIPPLE AND HELD BY SLIPSTOP 10/12/20130.000 Perforations & Slots Top (ftKB)Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB)Linked Zone Date Shot Dens (shots/ft )Type Com 7,246.6 7,339.7 6,214.5 6,218.3 9/29/2013 16.0 SLOTS Slotted 2 1/4" x .125 slots/8 rows/16 slots/ft 7,559.68,895.7 6,217.36,214.4 9/29/2013 16.0SLOTSSlotted 2 1/4" x .125 slots/8 rows/16 slots/ft 8,990.09,230.26,215.26,219.09/29/2013 16.0SLOTSSlotted 2 1/4" x .125 slots/8 rows/16 slots/ft 9,387.010,481.96,219.16,223.89/29/2013 16.0SLOTSSlotted 2 1/4" x .125 slots/8 rows/16 slots/ft 10,889.611,505.26,234.06,240.7 9/29/2013 16.0SLOTSSlotted 2 1/4" x .125 slots/8 rows/16 slots/ft 11,693.312,270.26,240.5 6,243.99/29/2013 16.0SLOTSSlotted 2 1/4" x .125 slots/8 rows/16 slots/ft 12,364.1 12,454.5 6,245.1 6,246.4 9/29/2013 16.0 SLOTS Slotted 2 1/4" x .125 slots/8 rows/16 slots/ft Mandrel Inserts St ati on N o/Top (ftKB) Top (TVD) (ftKB)Make Model OD (in)Serv Valve Type Latch Ty pe Port Size (in) TRO Run (psi)Run Date Com 1 6,658.5 6,058.2 CAMCO KBMG 1 GAS LIFT DMY BK 0.000 0.0 2/1/2018 Notes: General & Safety End Date Annotation 9/20/2017 Note: Waivered for Water-Only Injection due to surface casing leak 10/22/2013 NOTE: Mandrel Orientation #1) 9:30 HORIZONTAL, CD4-291, 5/29/2020 11:19:30 AM Vertical schematic (actual) LINER; 6,703.9-12,585.0 SLOTS; 12,364.1-12,454.5 SLOTS; 11,693.3-12,270.2 SLOTS; 10,889.5-11,505.2 SLOTS; 9,387.0-10,481.9 SLOTS; 8,990.0-9,230.1 SLOTS; 7,559.6-8,895.7 SLOTS; 7,246.6-7,339.7 INTERMEDIATE; 34.5-7,209.7 SEAL ASSY; 6,715.7 LOCATOR; 6,714.5 NIPPLE; 6,675.7 FISH; 6,671.0 GAS LIFT; 6,658.5 SURFACE; 36.9-2,436.4 INJ VALVE; 2,009.3 NIPPLE; 2,009.3 CONDUCTOR Insulated 34"; 35.0-114.0 HANGER; 31.4 WNS INJ KB-Grd (ft) 36.47 Rig Release Date 10/2/2013 CD4-291 ... TD Act Btm (ftKB) 12,595.0 Well Attributes Field Name NANUQ Wellbore API/UWI 501032067200 Wellbore Status INJ Max Angle & MD Incl (°) 92.11 MD (ftKB) 12,535.30 WELLNAME WELLBORE Annotation Last WO: End DateH2S (ppm)DateComment SSSV: WRDP 15 ConocoPhillips February 28, 2018 Hollis French, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 Stephen Thatcher Manager, WNS Development North Slope Operations and Development ConocoPhillips Alaska, Inc. ATO -1770 700 G Street Anchorage, AK 99501 phone 907.263.4464 RECEIVED MAR 01 2018 AOGCC RE: Request for Administrative Amendments, Colville River Unit, North Slope, AK Dear Commissioner French, ConocoPhillips Alaska, Inc. ("CPAP') as operator of the Colville River Unit ("CRU") and Greater Mooses Tooth Unit ("GMTU"), requests that the Alaska Oil and Gas Conservation Commission administratively amend area injection orders for the Fiord, Nanuq, and Qannik oil pools to allow injection of GMTU Lookout Oil Pool ("LOP") produced water into any of the other CRU oil pools. CPAI also requests that the conservation orders for the Fiord and Qannik oil pools be amended to allow commingling of LOP production in surface facilities prior to custody transfer. This request is being made concurrently with applications for a LOP Conservation Order and Area Injection Order. Those applications provide further background for this request. The CO application explains that LOP production is expected to be compatible with production from the CRU oil pools. The Fiord, Nanuq and Qannik pools area injection orders have specific rules for "fluids authorized for injection." LOP produced water is not specifically listed as a fluid authorized for injection. The recent Commission order authorizing the expansion of the Alpine Pool Area Injection Order provides that "[p]roduced water from the Alpine Central Facility" is a fluid authorized for injection. See Area Injection Order No. 18D, Rule 1 b. CPAI requests that the Alpine pool language be used to amend the Fiord, Nanuq and Qannik area injection orders to allow for injection of any produced water from the Alpine Central Facility including LOP produced water injection. This amendment will provide for consistency in CRU oil pool area injection orders. CPAI also requests that the Fiord, Alpine and Qannik pool rules be amended to allow for the commingling of LOP production in CRU surface facilities prior to custody transfer. The Nanuq oil pool rules allow production to be "commingled with production from other pools in surface facilities prior to custody transfer." See Conservation Order 562, Rule 7a. CPAI requests that similar language be adopted for the Fiord, Alpine and Qannik pools to allow for the commingling of production from these oil pools with other production at the Alpine Central Facility. Request for Administrative Amendments February 28, 2018 Page 2 of 2 Please contact John Cookson (265-6547) if you have questions or require additional information. Regards, Stephen Thatcher Manager, WNS Development North Slope Operations and Development Cc: Land Manager - Alaska, Anadarko E&P Onshore LLC Bruce W. Hunt, Petro -Hunt LLC 14 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 June 1, 2018 Commissioner Hollis S. French Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RECEIVED jU :� 2018 t'eOGCC Re: Request to Cancel Area Injection Order (AIC) 28.005 for Colville River Unit (CRU) CD4 -291 (PTD 213-110) Dear Commissioner French: ConocoPhillips requests cancellation of Administrative Approval AIO 28.005. The approval was originally issued September 11, 2017 to allow continued water -only injection into CRU CD4 -291 (PTD 213-110) with a known surface casing leak to atmosphere. In May of 2018, a surface casing sleeve was welded over the leak to repair the communication, and subsequent diagnostics confirm surface casing integrity is restored. This request is to cancel the Administrative Approval and return the well back to normal injection operation. Please call Travis Smith or myself at 659-7126 if you have any questions. Sincerely, v v� Rachel Kautz Well Integrity Supervisor ConocoPhillips Alaska, Inc. 13 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 September 19, 2017 Commissioner Hollis S. French Alaska Oil & Gas Conservation Commission 333 West 7ch Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner French: RECEIVED SEP 21 2017 A®GCC ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 28, Rule 11, to apply for Administrative Approval allowing CRU well CD4 -214 (PTD 206-145) to be online in water -only injection service due to previously diagnosed TxIA communication on gas injection. If you need additional information, please contact myself or Rachel Kautz at 659-7126. Sincerely, Travis Smith Well Integrity Supervisor ConocoPhillips Alaska Inc. ConocoPhillips Alaska, Inc. Alpine Well CD4 -214 (PTD 206-145) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this Administrative Relief request as per Area Injection Order 28, Rule 11, to continue water -only injection for Alpine injection well CD4 -214. The well has known tubing by inner annulus (IA) communication when on gas injection. Well History and Status Colville River Unit well CD4 -214 (PTD 206-145) was completed in November 2006. After a pre -production period and a shut-in time for pressure observation, the well was placed into injection service in October 2009. In July 2017, the well was reported to the Commission for slowly increasing IA pressure while on gas injection. During AOGCC approved injection monitor periods, pressure trends showed TxlA communication exists only when the well is on gas injection service. Diagnostics performed during the monitor period, including passing MITIA and packoff tests, also confirmed the well's integrity to liquid. ConocoPhillips requests an Administrative Approval (AA) to allow the CD4 -214 to remain online in water -only injection service. Barrier and Hazard Evaluation Tubing. The 4-1/2", 12.6 lb, L-80 tubing has integrity to the packer at 7,254' RKB (5,994' TVD) based on a passing MfrIA to 3,300 psi on 7/24/2017. Production casing: The 7", 26 lb, L-80 production casing has integrity down to the packer at 7,254' RKB (5,994' TVD) based on the previously mentioned passing MITIA to 3,300 psi. This production casing has an internal yield pressure rating of 7,240 psi. Surface casing: The well is completed with 9-5/8", 40 lb, L-80 surface casing. This surface casing has an internal yield pressure rating of 5,750 psi. The surface casing was previously repaired externally to cover a shallow leak. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Secondary barrier: The production casing is the secondary barrier should the tubing fail. Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the tubing or casing it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. T/UO plots are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. Proposed Operating and Monitoring Plan 1. Well will be used for water -only injection service (no MI or gas injection allowed); Well Integrity supervisor 9/19/2017 t 2. Perform a passing MITIA every 2 years to maximum anticipated injection pressure; 3. Allow operating IA pressure up to 2000 psi, and operating OA pressure up to 1000 psi; 4. Submit monthly reports of daily tubing, IA, and OA pressures, injection volumes and pressure bleeds for all annuli; 5. Shut-in the well should MIT's or injection rates and pressures indicate further problems with appropriate notification to the AOGCC; 6. Anniversary month to be set as June 2019 (last AOGCC witnessed MITIA: June 12, 2015) to align with the ConocoPhillips Alaska, Inc. UIC MIT Permanent Test Schedule. Well Integrity Supervisor 9/19/2017 Conoco✓Phillip! Alaska, IIIc. WNS CD4 -214 S Well Attributes Max An )e & MD ITO r Wellborn 320no "W53)FielO Name W¢Il Slalua Incl t•1 MD (flNBI . Act son !RKB) 501000 NANUQ INJ 93.59 9,89012 15,072.0 Comment SSSV: WROP MLS!ppm) Data Annaletlan Lasl W0: Entl gate KBAr4.3 Rig Releaee Dal¢ 43.34 11/14/200fi Annotation Depth lhnel Lam Tag'. Ena Dale Annotation Last Moa._ Ena Rev Reason: WELL RF-VIFde os6orl 10252012 Date Casin Strin s CasingDescription atring 0._ String'ED ToplftKB) Sel gsinK set Depth HIM D).. shin WL.. aMng... string Top Thea CONDUCTOR 16 15.250 37.0 114.0 114.0 68.00 H40 Caaing0esmiPaim string 0... sbie,K)... Top lftNBf set DepiM1 h... e,eplh ll'VD)...iering Wl-string... String Top Thrd SURFACE 95R 8.835 36.4 2,677.0 2,365.4 40.00 LEO BTC -M Cam Ing Description String D.,, string lDTop(h ... K0) sells,".(L.. Set DepiM1 ITV01... string We.. srog... string ToPThrd INTERMEDIATE ] 6.276 34.2 8,696.0 6,210.4 26.00 L-80 Casing Desmlpdre siring D... sY1ng ID... Top (RKB) Set DepiM1 lr...se[DepM TND)... Sltlip WL. Shing... string Top TRrd OPEN HOLE 258' 6118 14,814.3 15,072.0 6.279) Caaing Descripllon Strang O.. String iD... Top(RKDI SetDepih(L. Set DepiM1liVD1... String WL. Siring... 5lriog Top Thrd LINER 4112 3.992 8,493.9 14.814.3 G.2G3] 1260 L-80 6LHT 4iner Details Ta Top OepwtudltR p Incl Noml... Item Description Comment IDI,11 4935(Rhal 8,493.9 '17 6 6,19).1 86.145LEEVE BAKER 'HIT LINER SETTING SLEEVE 4.g20 8,506.9 6c198.0 86.17 NIPPLE BAKER 'RS' PACKOFF SEAL NIPPLE 4.250 8,510.7 6,198.2 86.18 HANGER BAKER DG FLEX LOCK LINER HANGER 4,400 $520.5 6,198.9 86.20 XO 5x4.5 CROSSOVER 5"x4.5" 4.000 Tubin Strin s TubM9 DescriPllol $[r1n90... Slrin9lD... Top (RKS) Set DePih lt...ist Depth (ND)... Shing Wt. String - pre, TOP TM1M TUBING 412 3.958 31.9 8,5068 6,198.0 12.60 L-80 Com letion Details Top Depth (TVD) Toplacl Nomt- Top(,XB (RKB) 1•) Item Desert heCamment ID (in) 31.9 31.9 -0.07 HANGER FMC TUBING HANGER 4.500 2,189.2 1,9820 35.50 NIPPLE DB NIPPLE 3,812 7,523.5 5,957.4 62AI PACKER BAKER PREMIER PACKER 3.875 7,580.8 5.992.3 63.69 NIPPLE XN NIPPLE 3.725 8,494.6 6,197.2 86.14 WLEG BAKER FLUTED WLEG A63EMBLY 3.958 Other In Note )reline retrievable Plugs. valves, PMPSI fish etc. Top Depth ITVDI To ISled To (ttKB) (flKB) rl I Desetlpticn Commend Run Dale ID (in) 2,1892 "Na',135.50VALVE 3.81"DB LOCK ON A-1 INJECTION VALVE(HAAS445) 1923/2011 1250 Perforations & Slots To RKB Bim line Toplrvd) (RKa) Rod IhKB) Zone Date snot Dens Pb T" Comment 8,688.0 14,773.0 6,209.8 6,260.3 111102006 32.0 SLOTS AltemalingsoliNAoddedPipe- 0.125"x2.5' @ 4 circumferential adjacent rows, 3" centers staggered 18 deg, 3non slotted ends Stimulations & Treatments Min Top Depth (ftKBI Max Btm DepthIND) (NKS) Tcp Depth IRKS) eoftom Depth (1Y0) (RKaj Type Date 6ommem 12,230.6 14,8200 6,221.6 6,26g2AG1D3TIM 4/131200) Pumped 6% KClwawrialdng returns in surface. Layed in 198 B51s. 12% He across stated liner Notes: General & Safe End Dae Annotnwe 11/13/2006 NOTE: TREE: FMC 4-1116"5000 psi- TREE CAP CONNECTION: I OTIS 11!)/2008 NOTE VIEW BCHEMATIC wIAlaska SDhematle9.0 ZcSIM09 NOTE: ZONES NOT LOADED TO WELLVIEW VET Mandrel Details its Top flKB) Top Depth (NSI (RKB) Top Incl F) Ma. Madel OD (in) do, Value Type Latch Type Pure She (in) TRO Run (pd) Run Data Co.... 1 7,419.0 5,914.9 cre d CAMCO KBG2 I 1 Gas Lifl OMV BEKS Id.umal 0.0 72312009 Well Name: CD4 -214 Start Date: 21.Jun-2017 Days: 90 End Date: 19 -Sep -2017 7/14/17 Refresh Annular Communication Surveillance 4500 4000 170 3500 150 3000 H 2500 130 LL 2000 110 v 1500 a 1000 90 500 70 0 50 ti N m N —WHP —IAP —OAP —WHT Injection/Production 1800 1600 p 1400 a 1200 m 1000 O 800 h 60D 400 200 0 t 3 3 9 > > 6 W Q Q N VI N N •� f V N P � nS d � m •+ ry m r —DG] —MGI —PWI SWI —BLPD Data CD4 -214 7/25/17 1283 967 316 INNER SWI CD4 -234 7/14/17 1684 1200 484 INNER SWI C134-214 7/9/17 2236 1500 736 INNER MIS 12 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 September 3, 2017 Commissioner Hollis S. French Alaska Oil & Gas Conservation Commission 333 West 7t' Avenue, Suite 100 Anchorage, AK 99501 Commissioner French, RECEIVED SEP0 6 2017 ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 28, Rule 11, to apply for an Administrative Approval to allow injector CRU CD4 -291 (PTD 213-110) to be online in water -only injection service with a surface casing leak to atmosphere. If you need additional information, please contact myself or Travis Smith at 659-7126. Sincerely, Rachel Kautz Well Integrity Supervisor ConocoPhillips Alaska Inc. ConocoPhillips Alaska, Inc. Colville River Unit CD4 -291 (PTD 213-110) Technical. Justification for Request of Administrative Approval Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this request for Administrative Approval, as per Area Injection Order 28, Rule 11, to allow water -only injection into CRU CD4 - 291 due to a known surface casing leak to atmosphere. Well History and Status Colville River Unit well CD4 -291 (PTD 213-110) was completed in 2013 as a service well. CD4 -291 was reported to the Commission on April 28, 2017 for showing signs of a surface casing leak to atmosphere via the surface casing by conductor annulus. A diagnostic MITIA was performed and passed to 2500 psi. Outer annulus diagnostics were performed and confirmed a surface casing leak to atmosphere, however, further investigation showed the leak would require at least an excavation to repair. ConocoPhillips Alaska, Inc. now requests Administrative Approval (AA) to allow water -only injection into CD4 -291 with a known surface casing leak to atmosphere. Barrier and Hazard Evaluation Tubing: The 4-1/2", 12.6 ppf, L-80 tubing to 138' MD, and 3-1/2", 9.3 ppf, L-80 tubing from 138' MD to the packer at 6703' NO. The tubing string has integrity to the packer based on the passing MITIA to 2500 psi performed on May 1, 2017. Intermediate casing: The 7", 26 ppf, L-80 intermediate casing has an internal yield pressure rating of 7240 psi and has integrity to the packer at 6703' MD based on the passing MITIA mentioned above. Surface casing: The 10-3/4", 45.5 ppf, L-80 surface casing is set at 2436' MD (2379' TVD), but has a known leak to atmosphere. Diagnostics indicate the leak activates at an OA pressure above 400 psi. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing down to the packer set at 6703' MD. Second barrier: The secondary barrier to prevent a release from the well and provide zonal isolation is the intermediate casing should the tubing fail. Monitoring: Each well is monitored daily for wellhead pressure changes. Should a leak develop in the tubing or intermediate casing, it will be noted during the daily monitoring process. Pressure trends that indicate annular communication require investigation, Commission notifications, and corrective action, up to and including a shut-in of the well. T/I/O plots are compiled, reviewed, and submitted to the AOGCC for review monthly. Well Integrity Supervisor 9/22017 Proposed Operating and Monitoring Plan 1. Well will be used for water only injection. 2. Perform a passing MITIA to maximum anticipated injection pressure every 2 -years. 3. Allow operating IA pressure up to 2000 psi while injecting water; operating OA pressure to be held as low as reasonably possible, not to exceed 400 psi, and OA pressure management is to be maintained by bleeds due to an open shoe. 4. Submit monthly reports of daily tubing, IA, and OA pressures, injection volumes and pressure bleeds for all annuli. 5. Shut-in the well should MIT, injection rates, or pressures indicate further problems with appropriate notification to the AOGCC. 6. Anniversary date to be set for June 30, 2019 (last AOGCC witnessed MIT was June 12, 2015) to align the AOGCC witnessed testing with the UIC MIT permanent 4 -year scheduled pad testing. Well Integrity Supervisor 9/2/2017 WNS INJ CD4 -291 g onoeornimps Well Attributes Max Angle & MD TD Ala$fa, InC. WOIIM1oro gPllUWI FiOltl Nama W¢IIO ve SUl uc ndl°) 50103206] 200 NANUD INH 92.11 MG (kxBf PCI BIm ttKB) 12,535.30 12,595.0 Commonl H23 (ppm) Gale AndRpe- Ertl OaY SSBV'. WRDP G, WO: KBCsN(fll RiB R<Ieaae Gale 36.47 1022013 K0RR9NTAL-M4.2o,G31rz%15al M PIR cwoh Annolallap Oeplh (flKB) Entl Dale Lasl Tag: Annolelbn Rsv1MS,v PULL INJ VALVE,SET EVOTRIEVE PLUG ON TOP OF FISH Lsst Med By pprovan E,Itl MI SI3120b HPNGER: SIq� Cacing U-npllon 00en) 10 (in) Top (IIKB) SpI OepIM1 KR) Set Gap1111iVG)... WULen (I... G2de Top Threatl CONDUCTOR Insulated 16 15.062 35.0 114.0 114.0 62.50 H-90 Welded 34" asinq pesriplion OD(in) 10 (in) Top(We) 9e1 GOpU fXK6) Se1GepU lnO)... WOLen L. G.G. Tap Thpod SURFACE 10314 9.950 38.9 2,436.6 2,378.5 65.50 L�80 BTCM GG (In) 10 (In) Tup (flKBf Set DepU (KKB) Bet OepiM1 nVp)... WULm 9... Cnde Tap Thnad INTERMEDIATE INTERMEDIATE ] 6.216 36.5 ],209.] 6,210.2 26.00 L -BD BTCM Casin90eacripnen OG lin) ID 6n) Tpp IflK3) Set G¢pIM1 (%HB) Bet OapU (NG)... WULan 9... Grado Top Thread LINER 31/2 2.992 6,]03.9 1$585.0 6.244.2 9.30 L-80 SLHT CONDUCTOR InWNd 24: Liner Details ,,,AToD Top (ft.) Top(TVO)(fIKB) Tepind(°) Item No Co. Nominal lG nt 6,703.9 6,085.9 65.67 PACKER BAKER HRD ZXP LINER TOP PACKER 6.320 6,723.9 6,085.9 66.27 NIPPLE BAKERS"RS NIPPLE 4.250 8,826.0 6,08].0 66.39 HANGER BAKER FLEX LOCK LINER HANGER 4.340 NIPPLE;ya09.3 6,836,0 6,0910 66.79 SBE BAKER004010'SEAL BORE EXTENSION 4.000 6,861.4 6,100.5 67 78 NIPPLE HES XN LANDING NOLO NIPPLE 2913 Tubing Strings Tomng oescdpden so-lne M•... TUBING 31/2 4.5x3.5"@138' to lin) 2.992 roplBxB) 31 sal Depm lx.. 4 Q745.4 set Devro lTen) 1_. Wlphu4 6,096p 9.30 ado L-811 Topconnemon EUE-M SURFACE: 389.2.430.4 Completion Details Top (%KB) Top free) (%KB) Top Incl l•) item -He IOem Ges Com (in) 31.4 31.4 000 HANGER FMO TUBING HANGER 3.958 -Red 138.6 1386 0.13 70- UdC9 XO- 41 IT ST (8) x 31ITEVE B RD (P) 2.992 2,009.3 1,974.3 19.41 NIPPLE 5UC-0BPUS NIPPLE wl 2812 -DS pmtile 2.012 6,675.7 6,065.7 64.34 NIPPLE HES X LANDING NIPPLE 2.813 6,714.5 6,0820 65.89 LOCATOR BAKER LOCATOR (5.00'OD) 2.990 15) 8082.5 89 6596 SEALASSY BAKER 804D SEAL ASSY 2.990 GAs uPT;esses Other IT Hole (Wiregne rilavable plugs, valves, pumps. Fish, etc.) Tep (rvO) Top maI EVOTRIEVEpLUG', BATq.O FISK:6.A Tep (XKB) (MB) v B) U. Co. Run Dela IG(In) B,6>0.0 6,063.2 fi4.12 EVOTRIEVE 2.]T'EV0TRIEVE PLUG TOP PLUG OF FISH 5130201, 0.000 6,6]1.0 6063.7 64.16 PIBH RHC PWG BODY PUSHED DOWNHOLE TO 10112121113 0000 NIPPL668757 NIPPLE AND HELD BY SLIPSTOP Perforations & Slots snm Dea LOCAtt1R:8.>1i5 Top (flKB) BM (XKB) Tcp(rvG) (flKB)(flKB) BIm1rvD) 2vne O01 (shot4lf X Type Co. 8,246.6 ],339.7 8,214.5 6,218.3 91292013 18.0 SLOTS 21//1x.125 5 O W." slotted 7,558.8 8,695.7 6,217.3 8,214.4 812912013 16.0 SLOTS 2114"X.125X SEPLASSN 8.71E7 SICSItl oeGjx.125 slobl0 mwsll6 sIo1LX 0,990.0 9,230.2 6,215.2 6,219.0 92912013 16.0 SLOTS SIMtCd21/4"x.125 slo1s10 rowalle slov B 9,307.0 10,481.9 6.219.1 6,223.8 9292013 18.0 SLOTS Slotted 21)4"x.125 slots/8 rows/10 slobeft 10,889.6 11,505.2 6,234.0 6,240.7 9292013 16.0 SLOTS Slotletl 211Px.125 sICWS Rows l6Idbte/fl 11,fi93.3 12,2]0.2 8,240.5 8,243.9 929/2013 16.0 SLOTS Mued 11/4"x.125 Flo1SMR,, 116 Coopil 12,364.1 12,454.5 8,245.1 6,248.4 97292013 16.0 SLOTS Sblted2l/4"x.125 slow¢ rowsM6 sl01sl11 Mandrel Inserts st aB N Tap(%KB) Top1rvG) /XKB) MaW Model o0 (In) SIL Valve Type Laah Pon Type pn) she TRORan (ps1) Run Gab Cam 1 6,658 5 . 6,058.2 CAMCO KBMG 1 GAS LIFT DMY BK 0000 09 5-1252014 Notes: General & Safety Ead Data Apaphdpn 10/25/2013 NOTE: Mandrel Orientation#TgD0 PITERMEDNTE: 34.5-7,2091 SLOTS: 7.246fi-7,2]6.7� 9LOT5: 7,559.8B2SS.l� SUM:0,9¢0.0AIl3e1- SLOTS:B13gT.0.fOp51.9� SLOTS: 10,88".115052 SLOTS: 11.88].}12.2]03 SLOTS: 12284.1-12 <54.5 LINER:6,700.9-12,395-0- STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submitto: fim.regaillalaska.00y AOGCC.Insoectorsrmalaska GoVhpebg prooks9W.ske.Gov OPERATOR: ConoccPhillips Alaska Inc. FIELD/UNIT/PAD: Colville River FleldtCRU/CD4 DATE: 05/01/17 OPERATOR REP: Arend AOGCC REP: 0= Other(deecdbe In notes) chis wallacer�alaske oov Well CD4.291Pressures: P=Pressure Test Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. 0= Other(deecdbe In notes) PTD 213-110 Type Inj G Tubing $860 3860 3860 3860 Type Test P Packer TVD 6078 BBLPump 1.4 IA 1267 2500 2440 2430 Interval 0 Test psi 1520 BBI-Return OA 504 575 572 568 Result I P otes: Diagmstic MITIA Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBLPumpl Interval Test psi BBL Return OA Result Note.: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing TypeTest Packer TVD BEL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBLPump IA Interval Test psi BBL Return OR Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. aD Min. PTD Type Inj Tubing Type Test Packer TVD BBLPump IA Interval Test psi BBLRetum I OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type lnj Tubing Type Test Packer TVD BEL Pump IA Interval Test psi BBLRetum OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BEL Pump IA Interval Test psi BBL Return OA Result Notes: Pressures: Pretest Initial 1510m. 30 Min. 45 Min. 60 Min. Type lnj Tubin Type Test g BBLPump IA Interval Result TYPE [NJ Cotler W=Water G = Gas a=Slurry 1= Industrial wroo..kr N = Net Inledln0 TYPETESTCodes INTERVAL Codes P=Pressure Test I=Ideal Too 0= Other(4escribe In Notes) 4=FourYear Cycle V= Reguns! by Variance 0= Other(deecdbe In notes) FORM 10-426 (Revised 01/2017) CRU CD4.291 Diagnodlc MIT 5-1-2011 AU Result Codes P = Pass F=Far 1=1rs.r.lorl. Well Name Slant Date Days End Date CD4-291 61512017 90 91312077 Notes Bleed Hisaory Annular Communication Surveillance +6m 160 WELL-10 TINE STR-PFIES ENO-FRES DIF-PRES CASING SERVICE W00 _WNP IP —ppp 16D 3600 —_Yi1R 140 30LO 130 250D 20 1 2000 ImLL 1600 loom IDDD Ib �D So D 70 m Me l7 J.n17 JLL17 Aup1T S&P17 i 0.9 0. —WI O 0.7 —NC 5 o.e —� m 0.5 —a3 0.4- .1 0.3 0.3 0.2 D1 D Mey-17 JVHT JLL1] Aug17 Septi Date 11 Conoco`Phillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 March 26, 2016 Chris Wallace Alaska Oil and Gas Commission 333 West 7`h Avenue, Suite 100 Anchorage, AK 99501 Dear Mr. Wallace, CPAI requested a meeting with the AOGCC in December 2015 to discuss several topics. The intent of the meeting was to discuss ideas to improve efficiency and cost savings for both CPAI and the AOGCC, while maintaining regulatory compliance which ensures the safety of personnel and the environment. The purpose of the following proposal is to maintain a good working relationship with the AOGCC while streamlining reporting requirements, align Administrative Approval (AA) anniversary dates, and outline an acceptable diagnostic and operating path forward pertaining to injectors that have an IA pressure anomaly while on gas injection. The first topic for consideration is to align the anniversary dates on AA's with the current approved UIC testing schedule. This will optimize CPAI's time and resources as well as North Slope AOGCC Inspector time by aligning the testing with the rest of the pad instead of making multiple trips to Kuparuk for 1 or 2 wells at a time. This covers both future approvals and amending the dates on existing approvals. With the current testing requirements and the acceptance of this proposal, the wells will still be tested every 2 years. However, every other test will fall in line with the 4 year UIC pad testing. For future approvals, the AA applications will include a requested anniversary test month which will align the testing cycle of the specific well with the required UIC test month schedule. Initially this may require a test early in the cycle for alignment. However, it will be more efficient over the long term. For existing approvals already in place, a blanket amendment is requested to change the dates to align with the approved UIC test month schedule. An outline of each well, the existing anniversary date, the date of the last witnessed test, and the new proposed anniversary date is included for easy reference. The attached spreadsheet includes all of the above data and an explanation of how the new date will be achieved. However a number of these wells have not had a recent witnessed MITIA due to having been shut in long term. These wells will be evaluated for cancellation of their AA's. Some of the wells will require early testing and some of the wells include a request to delay the testing for a short period, no longer than 5 months, in order to get each well in cycle. Along with the information listed above, each well has a note included of how CPAI intends to test each well to keep the wells within compliance and to achieve the new anniversary testing month. In addition to aligning the MITIA anniversary test dates, the MITIA test pressure criteria should be brought into alignment with current requirements. There are 6 older AA's that require "1.2 times the maximum anticipated injection pressure" for the MITIA criteria. The wells in question are 1B-11, 2K-03, 2K-10, 3K-11, 3Q-05, CD4-209. CPAI requests that the AA MITIA test criteria for these wells be changed to "maximum anticipated injection pressure". The second topic for consideration is to clarify and improve the reporting process for injectors. CPAI proposes that a report to the AOGCC will not be initiated until annular communication and/or casing integrity failures have been confirmed. This will be accomplished via diagnostic testing and/or extended observation of a well. After observing an anomaly, a standard suite of diagnostics would begin. These typically include an MIT of the annulus in question, packoff testing either of the tubing and/or inner casing, and a drawdown test to establish a buildup rate if the MIT passes. Depending on the results of the drawdown test, a period of extended bleeds or an annular fluid replacement may be performed. If the extended bleeds or fluid replacement indicate that there are no signs of communication, a self -regulated monitor period while remaining on injection may be started to confirm the repeatability of the anomaly. Normally a monitor period of 30 days will be used. However, if the suspected communication is of a very slow or intermittent nature, longer observation may be necessary. The WellTracker system recently put into place at CPAI will help in tracking these wells. If the monitor period does not show any further anomalies, the well will not be reported at that time. If a well fails an MIT or if the anomaly repeats itself and there is confirmed communication, the well will be reported at that time. The initial report at that time will include all diagnostics that have been performed to date, including the dates and results of the testing, a TIO plot with a minimum of 90 days to cover the entire duration of the diagnostics (including the initial tests and any diagnostic periods that may have occurred), a rate plot of injection, and the plan forward for further diagnostics or intentions to waiver will be included. With this approach, ConocoPhillips will be reporting wells that have confirmed communication with the details of how it was confirmed and minimize the reporting of wells that do not have confirmed communication. The results of the diagnostics will dictate each new path forward. A failing MIT will result in the well being shut in as soon as reasonably possible and may include securing with a downhole plug as necessary. If communication is observed on gas injection, if possible, the well will remain on gas injection and attempts will be made to establish the bleed frequency and the approximate psi per day pressure build up rate. This will be done to determine whether the well can be operated maintaining the inner annulus below the "Do not exceed" (DNE) pressure with a maintenance bleed program. After the communication on gas injection has been confirmed and a buildup rate determined, the well will be WAG'ed to water injection and an additional 30 day monitoring period will be conducted to ensure that the communication is only present when on gas injection. The third topic for consideration concerns the wells which demonstrate TxIA communication only while on gas injection and for which there are no plans to continue gas injection. CPAI proposes that these wells should not need to have an AA to continue water -only injection. Instead, CPAI will submit a sundry request to convert these injectors from WAG to WINJ status. When on water injection, these injectors display all of the characteristics of a well with full integrity and behave no differently than the normal wells. After being placed in WINJ status, these wells would then be governed by their respective field's Area Injection Order. To ensure that these wells are not inadvertently returned to gas injection, the gas lines will be physically disconnected from the wellheads. The fourth topic for consideration concerns the injectors which demonstrate TxIA communication only when on gas injection and where CPAI would operate these wells under a "Maintenance Bleed" AA. For those wells, CPAI would like to remain consistent with our current Well Operating Guidelines (WOG) allowance of OA bleeds on a gas lifted producer. This would mean that the acceptable and manageable rate would be a buildup of pressure requiring no more than two bleeds per week to keep the IA under the standard DNE of 2400 psi for gas injectors in Kuparuk and Alpine. The bleed frequency would be established as part of the diagnostics and if an acceptable frequency was achieved, an AA request would be submitted to continue WAG injection allowing maintenance bleeds on the IA while on gas injection only. In addition to a normally required 2 year MITIA, a caliper survey of the tubing from the packer to the surface would be logged. With this criteria in place, the testing requirements would evaluate or test the integrity of the tubing every year. The caliper will evaluate the internal condition of the pipe and the MITIA would test the integrity of the tubing externally as well as the integrity of the production casing and packer. The proposed AA would request a 2 year witnessed MITIA to the standard AOGCC test pressure (.25 x Packer TVD or 1500 psi whichever is greater), alternating with a 2 year non -witnessed caliper survey. The caliper survey would be submitted to the AOGCC but would not require an inspector on site to witness the logging. The request for the lowered test pressure criteria; in lieu of the higher test pressure to maximum anticipated pressure, is based on the annual monitoring of the tubing condition and the well operating under normal gas injection well criteria, other than the maintenance bleeds, with the IA remaining under the 2400 psi DNE limits. The well would be shut in if the bleed frequency increased above two bleeds per week which could indicate a change in mechanical condition of the well. Any `slow' gas -only tubing leaks which are identified in the future will follow the protocol as outlined above. However, any of the existing AA's for wells with this type of communication will need to be addressed separately. For some of these wells, investigation will be needed to quantify their gas leak rates. Therefore, a diagnostic plan will be developed and a request submitted at a future date asking for permission from the AOGCC to allow these wells to have gas injection temporarily restored to perform the diagnostics. A judgment from that point can be made as to whether the leaks can be managed by bleed (criteria from above) or whether they will need to remain on water injection. For those wells which will need to remain on water injection, a request will be submitted to change their status from WAG to WINJ and have their AA's cancelled, as outlined under the third topic in this proposal. ConocoPhillips is continuously striving for improvement. This proposal includes some of the topics for consideration that have been identified as areas for improvement. The intent of this proposal is to better utilize resources for both CPAI and the AOGCC. We believe with the implementation of the topics above, it will enable more efficient use and time of CPAI resources while providing less burden on the AOGCC, both town personnel and the North Slope inspectors. It will also reduce the amount of redundant work and streamline communication to include more factual information and not just suspicions. Additionally these ideas will help maximize production by allowing continued gas injection while ensuring the well is still safe to operate and does not compromise the safety of the environment or personnel. This proposal will still maintain the wells within regulatory compliance while achieving a higher level of efficiency. Due to the nature of the upcoming summer MIT schedule, a prompt response would be appreciated. If necessary, we are available to set up a face to face meeting to finalize the details. Don't hesitate to call if you have any questions. For your consideration from ConocoPhillips Alaska's Problem Wells Supervisors: Brent Rogers Kelly Lyons Dusty Freeborn Jan Byrne Anniversary Date Amendement Proposal Well name AIO # Existing Anniversary Date Date Last Witnessed Test Proposed New Anniversary Date Notes 1A-04A AIO 213.011 5/30/2006 6/29/2014 7/31/2017 1A pad due next July of 2019. This well will be tested by 06/29/16 and then the following year by 07/31/17 to get on schedule. 1A-06 AIO 2C.031 July 2017 7/26/2011 7/31/2017 New approved AA calls for anniversary date to be before or during month of July 2017. CPAI requests to change this to last day of July for precise database maintenance. 1A-12 AIO 2B.049 3/16/2010 2/20/2016 7/31/2017 This well will be tested on or before 07/31/17 to get on schedule. 1A-16RD AIO 2B.075 3/22/2015 3/22/2015 7/31/2017 CPAI requests a delay of 4 months on the test to allow the test on or before 07/31/17 to get on schedule. 1B-08A AIO 2C.027 8/7/2015 7/12/2013 6/30/2017 1B pad due next June of 2017. Well to be tested early, on or before 6/30/17 to get on schedule. 16-11 AIO 26.060 7/6/2011 7/7/2015 6/30/2017 Well to be tested early, on or before 7/31/16 to get on schedule. 1D-38 AIO 2C.010 8/26/2014 8/26/2014 7/31/2016 1D pad due next July of 2018. Well to be tested early, on or before 7/31/16 to get on schedule. 1E-08A AIO 213.065 8/30/2011 8/27/2015 6/30/2016 1E pad due next June of 2018. Well to be tested early, on or before 6/30/16 to get on schedule. 1E-15A AIO 213.081 12/8/2013 11/20/2015 6/30/2016 Well to be tested early, on or before 6/30/16 to get on schedule. 1E-22 AIO 26.078 6/16/2013 11/20/2015 6/30/2016 Well to be tested early, on or before 6/30/16 to get on schedule. IF-04 AIO 2C.006 9/16/2014 2/14/2013 6/30/2016 1F pad due next June 2016. Well to be tested early, on or before 6/30/16 to get on schedule. 1F-05 A1O.213.080 7/12/2012 7/4/2014 6/30/2016 Well to be tested early, on or before 6/30/16 to get on schedule. 1F-16A AIO 2C.018 3/24/2015 12/2/2013 6/30/2016 Well to be tested early, on or before 6/30/16 to get on schedule. 1G-01 AIO 213.035 6/28/2008 6/15/2014 7/31/2017 1G pad due next July of 2019. This well will be tested by 6/28/16 and then on or before 7/31/17 to get on schedule. 1L-05 AIO 213.054 8/11/2010 7/27/2014 6/30/2016 1L pad due next June of 2016. Well to be tested early, on or before 6/30/16 to get on schedule. 1L-07 AIO 2C.008 10/28/2014 5/25/2012 6/30/2016 Well to be tested early, on or before 6/30/16 to get on schedule. 1L-10 AIO 26.083 2/22/2014 2/20/2016 6/30/2016 Well to be tested early, on or before 6/30/16 to get on schedule. 1Q-09 AIO 26.093 5/30/2014 7/9/2013 7/31/2017 1Q pad due next July of 2017. This well will be tested by 5/30/16 and then on or before 7/31/17 to get on schedule. 1Q-13 AIO 28.090 6/29/2014 6/29/2014 7/31/2017 This well will be tested by 6/29/16 and then on or before 7/31/17 to get on schedule. 1Q-24 AIO 2C.017 3/11/2015 7/9/2013 7/31/2017 CPAI requests a delay of 5 months to allow the test to be performed on or before 7/31/17 to get on schedule. 111-15 AIO 213.088 1/12/2014 1/2/2016 5/31/2017 1R pad due next May of 2019. Well to be tested early, on or before 5/31/17 to get on schedule. 1Y-05 AIO 28.015 7/23/2006 7/8/2013 7/31/2017 1Y pad due next July of 2017. This well has been offline since 2/6/12. If the well is BO1 it will be tested post stabilization and then again on the earliest date to align with the schedule. 1Y-08 AIO 26.056 6/15/2010 2/15/2015 7/31/2017 This well will be tested by 6/15/16 and then on or before 7/31/17 to get on schedule. 1Y-09 AIO 26.051 5/20/2010 2/15/2015 7/31/2017 This well will be tested by 5/20/16 and then on or before 7/31/17 to get on schedule. 1Y-10 AIO 2C.014 8/29/2014 9/12/2015 7/31/2017 This well will be tested by 8/29/16 and then on or before 7/31/17 to get on schedule. 213-06 AIO 2C.012 12/26/2014 12/26/2014 5/31/2016 2B pad due next May of 2016. Well to be tested early, on or before 5/31/16 to get on schedule. 26-07 AIO 2C.024 12/18/2014 5/10/2012 5/31/2016 Well to be tested early, on or before 5/31/16 to get on schedule. 26-10 AIO 213.073 2/14/2013 2/8/2015 5/31/2016 Well to be tested early, on or before 5/31/16 to get on schedule. 2C-03 AIO 213.085 2/5/2013 2/20/2016 8/31/2017 2C pad due next August 2017. Well to be tested early, on or before 8/31/17 to get on schedule. 2C-04 AIO 213.091 6/21/2014 6/21/2014 8/31/2017 This well will be tested by 6/21/16 and then on or before 8/31/17 to get on schedule. 2C-07 AIO 213.007 2/5/2006 2/5/2012 8/31/2017 This well has been offline since 9/12/12. If the well is BO1 it will be tested post stabilization and then again on the earliest date to align with the schedule. 2C-08 A1O26.086 3/4/2014 2/20/2016 8/31/2017 Well to be tested early, on or before 8/31/17 to get on schedule. 2D-02 AIO 213.052 3/22/2011 3/22/2015 8/31/2017 2D pad due next August of 2017. CPAI requests a delay of 5 months to allow the MIT to be performed on or before 8/31/17 to get on schedule. 2D-04 AIO 26.037 6/21/2008 6/21/2014 8/31/2017 This well will be tested by 6/21/16 and then on or before 8/31/17 to get on schedule. 2D-10 AIO 26.070 2/6/2012 1/19/2016 8/31/2017 Well to be tested early, on or before 8/31/17 to get on schedule. 2F-04 AIO 28.074 6/7/2012 6/7/2014 7/31/2016 2F pad due next July of 2016. CPAI requests a delay of 2 months to allow the MIT to be performed on or before 7/31/16 to get on schedule. 2F-13 AIO 213.039 7/5/2008 6/7/2014 7/31/2016 CPAI requests a delay of 1 month to allow the MIT to be performed on 7/31/16. 2G-01 AIO 2C.019 1/11/2015 5/1/2012 5/31/2016 2G pad due next May of 2016. Well to be tested early, on or before 5/31/16 to get on schedule. 2G-03 AIO 26.014 5/14/2006 5/28/2010 5/31/2016 This well has been offline since 9/28/11. If the well is BOI it will be tested post stabilization and then again on the earliest date to align with the schedule. 2G-05 AIO 2C.029 8/27/2015 5/1/2012 5/31/2016 Well to be tested early, on or before 5/31/16 to get on schedule. 2G-10 AIO 213.030 2/24/2008 5/1/2012 5/31/2016 This well has been offline since 9/28/12. If the well is BO1 it will be tested post stabilization and then again on the earliest date to align with the schedule. 21-1-03 AIO 2C.009 12/9/2014 5/6/2012 5/31/2016 2H pad due next May of 2016. Well to be tested early, on or before 5/31/16 to get on schedule. 21-1-13 AIO 2B.076 3/23/2013 8/15/2015 5/31/2016 Well to be tested early, on or before 5/31/16 to get on schedule. 21-1-15 AIO 2C.015 12/25/2014 5/6/2012 5/31/2016 Well to be tested early, on or before 5/31/16 to get on schedule. 2K-03 AIO 26.016 6/1/2007 5/30/2015 6/30/2017 2K pad due next June of 2019. CPAI requests a delay of 1 month to test on or before 6/30/17 to get on schedule. 2K-10 AIO 26.017 6/1/2007 5/29/2015 6/30/2017 CPAI requests a delay of 1 month to test on or before 6/30/17 to get on schedule. 2K-12 AIO 213.048 8/8/2009 8/4/2015 6/30/2017 Well to be tested early, on or before 6/30/16 to get on schedule. 2L-305 AIO 16.002 1/21/2012 1/19/2016 8/31/2016 2L pad due next August of 2018. Well to be tested early, on or before 8/31/16 to get on schedule. 2L-310 AIO 16.004 2/5/2014 2/4/2016 8/31/2016 Well to be tested early, on or before 8/31/16 to get on schedule. 2L-319 AIO 16.003 10/4/2012 9/8/2014 8/31/2016 Well to be tested early, on or before 8/31/16 to get on schedule. 2L-323 AIO 16.005 2/1/2015 9/8/2014 8/31/2016 Well to be tested early, on or before 8/31/16 to get on schedule. 2M-09A AIO 213.004 2/6/2008 9/25/2015 6/30/2016 2M pad due next June 2016. Well to be tested early, on or before 6/30/16 to get on schedule. 2M-19 AIO 2C.020 5/4/2015 9/2/2012 6/30/2016 Well to be tested early, on or before 6/30/16 to get on schedule. 2M-27 AIO 2C.021 5/5/2015 9/2/2012 6/30/2016 Well to be tested early, on or before 6/30/16 to get on schedule. 2N-325 AIO 16.001 12/30/2009 12/27/2015 6/30/2016 2N pad due next August of 2018. Well to be tested early, on or before 6/30/16 to get on schedule. 213-447 AIO 2113.001 8/31/2014 12/26/2014 8/31/2016 2P pad due next August of 2016. This well is on schedule. 2T-02 AIO 2C.001 11/9/2014 11/9/2014 6/30/2017 2T pad due next June of 2017. This well will be tested by 11/9/ 16 and then on or before 6/30/17 to get on schedule. 2T-10 AIO 26.092 10/2/2014 10/2/2014 6/30/2017 This well will be tested by 10/2/16 and then on or before 6/30/17 to get on schedule. 2T-18 AIO 2C.023 4/16/2015 6/1/2013 6/30/2017 CPAI requests a 3 month delay to allow the MIT to be performed on or before 6/30/17 to get on schedule. 2T-28 AIO 26.066 10/2/2011 9/25/2015 6/30/2017 Well to be tested early, on or before 6/30/17 to get on schedule. 2T-32A AIO 2C.007 11/9/2014 11/9/2014 6/30/2017 This well will be tested by 11/9/16 and then on or before 6/30/17 to get on schedule. 2U-05 AIO 2B.084 1/12/2014 12/27/2015 8/31/2016 2U pad due next August of 2018. Well to be tested early, on or before 8/31/16 to get on schedule. 2V-02 AIO 2B.071 5/29/2012 11/6/2015 6/30/2016 2V pad due next June of 2016. CPA[ requests a delay of 1 month to allow the test to be performed on or before 6/30/16 to get on schedule. 2V-05 AIO 26.055 6/26/2010 7/27/2014 6/30/2016 CPAI requests a delay of 1 month to allow the test to be performed on or before 6/30/16 to get on schedule. 2X-05 AIO 26.064 6/26/2011 6/10/2015 6/30/2017 2X pad due next June of 2019. CPAI requests a delay of 1 week to allow the MIT to be performed on or before 6/30/17 to get on schedule. 2Z-16 AIO 26.002 9/25/2007 8/31/2017 2Z pad due next August of 2019. This well has been off line since 3/6/06. If the well is BOI it will be tested post stabilization and then again on the earliest date to align with the schedule. AA did not stipulate anniversary date. 38 pad due next June of 2019. This well will be tested by 10/13/16, and then the 313-05 AIO 2C.005 10/13/2014 6/19/2011 6/30/2017 following year by 6/30/17 to get on schedule. CPAI requests a delay of 2 weeks to allow the MIT to be performed on or before 6/30/17 36-07 AIO 2C.028 6/18/2015 6/18/2015 6/30/2017 to get on schedule. CPAI requests a delay of 2 weeks to allow the MIT to be performed on or before 6/30/17 313-10 AIO 213.067 6/19/2011 6/18/2015 6/30/2017 to get on schedule. CPAI requests a delay of 1 week to allow the MIT to be performed on or before 6/30/17 36-12 AIO 2C.025 6/27/2015 6/18/2015 6/30/2017 to get on schedule. 3F pad due next June of 2019. CPAI requests a delay of 1 month to allow the MIT to be 3F-04 AIO 26.063 6/5/2011 6/5/2015 6/30/2017 performed on or before 6/30/17 to get on schedule. 3F-08 AIO 26.087 2/13/2014 2/4/2016 6/30/2017 Well to be tested early, on or before 6/30/17 to get on schedule. 3F-11 AIO 26.089 1/27/2014 1/17/2016 6/30/2017 Well to be tested early, on or before 6/30/17 to get on schedule. 3G pad due next August of 2019. This well will be tested by 6/11/16 and then the 3G-15 AIO 2C.011 6/11/2014 8/30/2011 8/31/2017 following year by 8/31/17 to get on schedule. This well will be tested by 10/10/16 and then the following year by 8/31/17 to get on 3G-23 AIO 2C.004 10/10/2014 9/6/2014 8/31/2017 schedule. 3H pad due next June 2017. This well will be tested by 7/12/16 and then the following 31-1-06 AIO 2C.003 7/12/2014 11/19/2013 6/30/2017 year by 6/30/17 to get on schedule. This well will be tested by 9/18/16 and then the following year by 6/30/17 to get on 31-1-07 AIO 2C.016 9/18/2014 9/18/2014 6/30/2017 schedule. 3J-08 AIO 2C.013 11/27/2014 7/5/2012 7/31/2016 3J pad due next July of 2016. This well will be tested by 7/31/16 to get on schedule. 3K pad due next May of 2017. This well has been off line since 5/25/15. If the well is BO1 it will be tested post stabilization and then again on the earliest date to align with 3K-11 AIO 26.061 7/29/2011 7/8/2013 5/31/2017 the schedule. CPAI requests a delay of 2 months to allow the MIT to be performed on or before 3K-22A AIO 213.013 4/5/2005 4/14/2015 5/31/2017 5/31/17to get on schedule. 3N pad due next August of 2016. Well to be tested early, on or before 8/31/16 to get 3N-11A AIO 26.072 12/7/2012 12/13/2014 8/31/2016 on schedule. Well to be tested early, on or before 8/31/16 to get on schedule. AA did not stipulate 3N-16A AIO 26.057 12/13/2014 8/31/2016 anniversary date. 30 pad due next June of 2017. CPAI requests a delay of 3 months to allow the MIT to be 30-06 AIO 2C.022 3/27/2015 3/27/2015 6/30/2017 performed on or before 6/30/17 to get on schedule. New approved AA calls for anniversary date to be before or during month of June 2017. 30-07 AIO 2C.032 June 2017 3/14/2016 6/30/2017 CPAI requests to change this to last day of June for precise database maintenance. 30-10 AIO 26.033 6/10/2008 6/15/2014 6/30/2017 This well will be tested by 6/10/16 and then on or before 6/30/17 to get on schedule. 30-17 AIO 2C.026 8/5/2015 8/5/2015 6/30/2017 Well to be tested early, on or before 6/30/17 to get on schedule. 3Q pad due next August of 2016. This well will be tested on or before 8/31/16 to get on 3Q-01 AIO 26.068 11/24/2011 11/13/2015 8/31/2016 schedule. 3Q-05 AIO 213.019 10/1/2007 9/25/2015 8/31/2016 Well to be tested early, on or before 8/31/16 to get on schedule. 3Q-12 AIO 2C.002 8/14/2014 8/8/2012 8/31/2016 CPAI requests a delay of 3 weeks to allow the MIT to be performed on or before 8/31/16. 3Q-15 AIO 26.042 9/25/2008 6/27/2015 8/31/2016 Well to be tested early, on or before 8/31/16 to get on schedule. 3Q-16 AIO 26.082 1/12/2014 1/2/2016 8/31/2016 Well to be tested early, on or before 8/31/16 to get on schedule. 3Q-21 AIO 213.005 4/25/2006 4/15/2014 8/31/2016 CPAI requests a delay of 4 months to allow the test to be performed on or before 08/31/16 to get on schedule. 311-25 AIO 26.012 4/27/2005 4/24/2015 8/31/2016 3R pad due next August of 2016. Well to be tested early, on or before 8/31/16 to get on schedule. 35-18 AIO 26.069 6/6/2012 6/6/2012 Alternating service and development well. Required to have witnessed MIT upon start of each injection cycle. Well currently on production. CD1-07 AIO 186.006 6/8/2008 6/11/2015 6/30/2017 CD1 pad due next June of 2017. CPAI requests a delay of 3 weeks to allow the test to be performed on or before 6/30/17. CD1-14 AIO 18C.006 9/1/2015 6/12/2013 6/30/2017 Well to be tested early, on or before 6/30/17 to get on schedule. CD1-21 A1O.1813.007 6/12/2013 6/11/2015 6/30/2017 CPAI requests a delay of 3 weeks to allow the test to be performed on or before 6/30/17 to get on schedule. CD1-46 AIO 18C.004 2/20/2015 6/12/2013 6/30/2017 CPAI requests a delay of 4 months to allow the test to be performed on or before 6/30/17 to get on schedule. CD3-123 AIO 30.005 2/23/2014 2/18/2016 2/28/2018 CD3 pad due next February 2018. CPAI requests a delay of 1 week to allow the test to be perfomed on or before 2/28/18 to get on schedule. CD3-198 AIO 30.006 7/30/2015 4/12/2015 2/28/2018 Well to be tested early, on or before 2/28/17 and then on or before 2/28/18 to get on schedule. CD4-17 AIO 18C.003 5/6/2015 6/30/2011 6/30/2017 CD4 pad due next June 2019. CPAI requests a delay of 2 months to allow the test to be performed on 6/30/17 to get on schedule. CD4-27 AIO 18C.008 June 2017 6/12/2015 6/30/2017 New approved AA calls for anniversary date to be before or during month of June 2017. CPAI requests to change this to last day of June for precise database maintenance. CD4-209 AIO 28.003 11/28/2009 11/11/2015 6/30/2017 Well to be tested early, on or before 6/30/17 to get on schedule. CD4-213B AIO 18C.007 June 2017 6/12/2015 6/30/2017 New approved AA calls for anniversary date to be before or during month of June 2017. CPAI requests to change this to last day of June for precise database maintenance. CD4-321 AIO 18C.002 5/10/2013 11/11/2015 6/30/2017 CPAI requests a delay of 2 months to allow the MIT to be performed on or before 6/30/17 to get on schedule. CD4-322 AIO 18C.005 6/12/2015 6/12/2015 6/30/2017 CPAI requests a delay of 3 weeks to allow the test to be performed on or before 6/30/17 to get on schedule. ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 February 23, 2017 Chris Wallace Alaska Oil and Gas Commission 333 West Ph Avenue, Suite 100 Anchorage, AK 99501 Dear Mr. Wallace, RECEIVED FEB A0GOC, Last year on March 26, 2016, CPAI submitted a proposal to the AOGCC for your consideration. After nearly a year of implementation of accelerated MIT testing, efficiencies in time and resources for both CPAI and AOGCC inspectors have been demonstrated. Therefore, CPAI would like to reiterate our request to have a blanket amendment be approved to change the MIT anniversary dates of all of the wells which operate under an Administrative Approval to align with the UIC test month schedule. Attached is an updated list with all of the AA'd wells, which include their existing and proposed new anniversary dates, the dates of their last witnessed tests and notes which detail how CPAI intends to test each well to keep the wells within compliance and achieve their new anniversary testing months. In addition to the changes in anniversary dates, we would also like to reiterate our request to align the MITIA test pressure criteria with current requirements. There are 6 older AA's that require "1.2 times the maximum anticipated injection pressure" for the MITIA criteria. The wells in question are 113-11, 2K-03, 2K-10, 3K-11, 3Q-05, CD4- 209. CPAI requests that the AA MITIA test criteria for these wells be changed to "maximum anticipated injection pressure". CPAI still would like the other topics which were included in the March 2016 letter to be considered by the AOGCC. But it is understood that they will be addressed at a future date. If you need additional information or have any questions, please contact myself or Brent Rogers at 659-7224. Sincerel , Kelly Lyo Well Integrity Supervisor ConocoPhillips Alaska, Inc. Anniversary Date Amendement Proposal Well name AIO # Existing Anniversary Date Date Last Witnessed Test Proposed New Notes Anniversary Test Month 1A-04A AIO 2B.011 5/30/2006 5/12/2016 July 2017 1A pad next due July of 2019. Well to be tested on or before 7/31/17 to get on schedule. 1A-06 AIO 2C.031 July 2017 2/4/2016 July 2017 No changes 1A-12 AIO 2B.049 3/16/2010 2/20/2016 July 2017 Well to be tested on or before 7/31/17 to get on schedule. IA-16RD AIO 2B.075 3/22/2015 3/22/2015 July 2017 CPAI requests a delay of 4 months to allow the test on or before 07/31/17 to get on schedule. 16-08A AIO 2C.027 8/7/2015 7/12/2013 June 2017 1B pad next due June of 2017. Well to be tested on or before 6/30/17 to get on schedule. 113-11 AIO 2B.060 7/6/2011 7/7/2015 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 1D-38 AIO 2C.010 8/26/2014 8/7/2016 July 2018 1D pad next due July of 2018. Well to be tested on or before 7/31/18 to get on schedule. 1E-08A AIO 2B.065 8/30/2011 8/27/2015 June 2018 1E pad next due June of 2018. Well to be tested on or before 8/30/17 and then tested on or before 06/30/18 to get on schedule. 1E-15A AIO 2B.081 12/8/2013 1/8/2017 June 2018 Well to be tested on or before 6/30/18 to get on schedule. 1E-22 AIO 213.078 6/16/2013 1/8/2017 June 2018 Well to be tested on or before 6/30/18 to get on schedule. 1F-04 AIO 2C.006 9/16/2014 6/15/2016 June 2018 1F pad next due June 2020. Well to be tested on or before 6/30/18 to get on schedule. 1F-05 A1O.26.080 7/12/2012 6/15/2016 June 2018 Well to be tested on or before 6/30/18 to get on schedule. 1F-16A AIO 2C.018 3/24/2015 6/15/2016 June 2018 Well to be tested on or before 6/30/18 to get on schedule. 1G-01 AIO 2B.035 6/28/2008 6/21/2016 July 2017 1G pad next due July of 2019. Well to be tested on or before 7/31/17 to get on schedule. 1L-05 AIO 26.054 8/11/2010 6/1/2016 June 2018 1L pad next due June of 2020. Well to be tested on or before 6/30/18 to get on schedule. 1L-07 AIO 2C.008 10/28/2014 6/1/2016 June 2018 Well to be tested on or before 6/30/18 to get on schedule. 1L-10 AIO 26.083 2/22/2014 6/1/2016 June 2018 Well to be tested on or before 6/30/18 to get on schedule. 1L-22 AIO 2C.042 June 2018 6/3/2016 June 2018 No changes 1Q-09 AIO 213.093 5/30/2014 5/26/2016 July 2017 1Q pad next due July of 2017. Well to be tested on or before 7/31/17 to get on schedule. 1Q-13 AIO 26:090 6/29/2014 6/21/2016 July 2017 Well to be tested on or before 7/31/17 to get on schedule. 1Q-14 AIO 2C.034 July 2017 7/9/2013 July 2017 No changes 1Q-24 AIO 2C.017 3/11/2015 2/20/2017 July 2017 Well to be tested on or before 7/31/17 to get on schedule. 1R-15 AIO 2B.088 1/12/2014 1/2/2016 May 2017 iR pad next due May of 2019. Well to be tested on or before 5/31/17 to get on schedule. 1Y-08 AIO 2B.056 6/15/2010 6/5/2016 July 2017 3Y pad next due July 2017. Well to be tested on or before 7/31/17 to get on schedule. 1Y-09 AIO 2B.051 5/20/2010 5/7/2016 July 2017 Well to be tested on or before 7/31/17 to get on schedule. 1Y-10 AIO 2C.014 8/29/2014 8/18/2016 July 2017 Well to be tested on or before 7/31/17 to get on schedule. 26-06 AIO 2C.012 12/26/2014 5/1/2016 May 2018 2B pad next due May of 2020. Well to be tested on or before 5/31/18 to get on schedule. 213-07 AIO 2C.024 12/18/2014 5/1/2016 May 2018 Well to be tested on or before 5/31/18 to get on schedule. 213-10 AIO 26.073 2/14/2013 7/31/2016 May 2018 Well to be tested on or before 5/31/18 to get on schedule. 2C-03 AIO 26.085 2/5/2013 2/20/2016 August 2017 2C pad next due August 2017. Well to be tested on or before 8/31/17 to get on schedule. 2C-04 AIO 2B.091 6/21/2014 6/21/2014 August 2015 This well has been offline since 3/31/16. If the well is BOI it will be tested post stabilization and then again on the earliest date to align with the schedule. 2C-07 AIO 213.007 2/5/2006 2/5/2012 August 2015 This well has been offline since 9/12/12. If the well is BO1 it will be tested post stabilization and then again on the earliest date to align with the schedule. 2C-08 AIO213.086 3/4/2014 2/20/2016 August 2017 Well to be tested on or before 8/31/17 to get on schedule. 2D-02 AIO 26.052 3/22/2011 3/22/2015 August 2017 2D pad next due August of 2017. CPAI requests a delay of up to 5 months to test on or before 8/31/17 to get on schedule. 2D-04 AIO 213.037 6/21/2008 6/21/2016 August 2017 Well to be tested on or before 8/31/17 to get on schedule. 2D-10 AIO 26.070 2/6/2012 1/19/2016 August 2017 Well to be tested on or before 8/31/17 to get on schedule. 2F-02 AIO 2C.035 July 2016 7/9/2016 July 2016 2F pad next due July of 2020. No changes. 2F-03 AIO 2C.039 July 2018 7/9/2016 July 2018 No changes 2F-04 AIO 213.074 6/7/2012 7/9/2016 July 2018 Well to be tested on or before 7/31/18 to get on schedule. 2F-13 AIO 26.039 7/5/2008 7/9/2016 July 2018 Well to be tested on or before 7/31/18 to get on schedule. 2G-01 AIO 2C.019 1/11/2015 5/10/2016 May 2018 2G pad next due May of 2020. Well to be tested on or before 5/31/18 to get on schedule. 2G-05 AIO 2C.029 8/27/2015 5/1/2012 May 2016 Well has been shut in since 2/22/16. If the well is BOI, it will be tested post stabilization and then again on or before 5/31/18 to get on schedule. 2G-07 AIO 2C.038 May 2018 5/10/2016 May 2018 No changes 2G-10 AIO 26.030 2/24/2008 6/21/2016 May 2018 Well to be tested early, on or before 5/31/18 to get on schedule. 21-1-01 AIO 2C.037 May 2018 7/31/2016 May 2018 2H pad next due May 2020. No changes. 21-1-03 AIO 2C.009 12/9/2014 5/26/2016 May 2018 Well to be tested on or before 5/31/18 to get on schedule. 21-1-13 AIO 213.076 3/23/2013 5/10/2016 May 2018 Well to be tested on or before 5/31/18 to get on schedule. 21-1-15 AIO 2C.015 12/25/2014 5/10/2016 May 2018 Well to be tested early, on or before 5/31/18 to get on schedule. 2K-03 AIO 26.016 6/1/2007 5/30/2015 June 2017 2K pad next due June of 2019. CPAI requests a delay of up to 1 month to test on or before 6/30/17 to get on schedule. 2K-10 AIO 213.017 6/1/2007 5/29/2015 June 2017 CPAI requests a delay of up to 1 month to test on or before 6/30/17 to get on schedule. 2K-12 AIO 213.048 8/8/2009 8/4/2015 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 2K-20 AIO 2C.041 June 2017 11/13/2015 June 2017 No changes 2L-305 AIO 16.002 1/21/2012 2/14/2017 August 2018 2L pad next due August of 2018. Well to be tested on or before 8/31/18 to get on schedule. 2L-310 AIO 16.004 2/5/2014 2/14/2017 August 2018 Well to be tested on or before 8/31/18 to get on schedule. 2L-319 7I0 16.003 10/4/2012 9/30/2016 1 August 2018 lWell to be tested on or before 8/31/18 to get on schedule. 2L-323 AIO 16.005 2/1/2015 1/17/2017 August 2018 Well to be tested on or before 8/31/18 to get on schedule. 2M-09A AIO 213.004 2/6/2008 9/25/2015 June 2016 2M pad next due June 2020. Well has been shut in since 10/6/15. If it is BOI, the well will be tested post stabilization and then again on the earliest date to align with the schedule. 2M-19 AIO 2C.020 5/4/2015 6/3/2016 June 2018 Well to be tested on or before 6/30/18 to get on schedule. 2M-27 AIO 2C.021 5/5/2015 10/15/2016 June 2018 Well to be tested on or before 6/30/18 to get on schedule. 2N-306 AIO 16.006 August 2016 8/20/2016 August 2016 2N pad next due August of 2018. No changes 2N-325 AIO 16.001 12/30/2009 2/14/2017 August 2018 Well to be tested on or before 8/31/18 to get on schedule. 2P-447 AIO 216.001 8/20/2016 2P pad next due August of 2018. This well is on schedule. No anniversary date on AA. Follows the pad schedule which occurs every 2 years. No changes. 2T-02 AIO 2C.001 11/9/2014 10/25/2016 June 2017 2T pad next due June of 2017. Well to be tested on or before 6/30/17 to get on schedule. 2T-10 AIO 26.092 10/2/2014 9/30/2016 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 2T-18 AIO 2C.023 4/16/2015 6/1/2013 June 2017 Well to be tested on or before 4/16/17 and then again on or before 6/30/17 to get on schedule. 2T-28 AIO 213.066 10/2/2011 9/25/2015 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 2T-32A AIO 2C.007 11/9/2014 10/25/2016 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 2U-05 AIO 28.084 1/12/2014 2/14/2017 August 2018 2U pad next due August of 2018. Well to be tested on or before 8/31/18 to get on schedule. 2V-02 AIO 213.071 5/29/2012 9/30/2016 June 2017 2V pad next due June of 2020. Well to be tested on or before 6/30/17 to get on schedule. AA requires a yearly test. 2V-05 AIO 26.055 6/26/2010 6/3/2016 June 2018 Well to be tested on or before 6/30/18 to get on schedule. 2X-05 AIO 213.064 6/26/2011 6/10/2015 June 2017 2X pad next due June of 2019. Well to be tested on or before 6/30/17 to get on schedule. 2Z-16 AIO 26.002 9/25/2007 August 2015 2Z pad next due August of 2019. This well has been offline since 3/6/06. If the well is BO1 it will be tested post stabilization and then again on the earliest date to align with the schedule. AA did not stipulate anniversary date. 313-01 AIO 2C.033 June 2017 6/18/2015 June 2017 3B pad next due June of 2019. No changes 3B-05 AIO 2C.005 10/13/2014 12/27/2016 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 3B-07 AIO 2C.028 6/18/2015 6/18/2015 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 3B-10 AIO 26.067 6/19/2011 6/18/2015 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 36-12 AIO 2C.025 6/27/2015 6/18/2015 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 3F-04 AIO 2B.063 6/5/2011 6/5/2015 June 2017 3F pad next due June of 2019. Well to be tested on or before 6/30/17 to get on schedule. 3F-08 AIO 26.087 2/13/2014 2/4/2016 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 3F-11 AIO 2B.089 1/27/2014 1/17/2016 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 3G-15 AIO 2C.011 6/11/2014 6/1/2016 August 2017 3G pad next due August of 2019. Well to be tested on or before 8/31/17 to get on schedule. 3G-23 AIO 2C.004 10/10/2014 9/26/2016 August 2017 Well to be tested on or before 8/31/17 to get on schedule. 3G-24 AIO 2C.040 August 2017 8/15/2015 August 2017 1 No changes 3H-06 AIO 2C.003 7/12/2014 7/10/2016 June 2017 3H pad next due June 2017. Well to be tested on or before 6/30/17 to get on schedule. 3H-07 AIO 2C.016 9/18/2014 9/26/2016 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 3J-08 AIO 2C.013 11/27/2014 7/5/2016 July 2018 3J pad next due July of 2020. Well to be tested on or before 7/31/18 to get on schedule. 3K-11 AIO 213.061 7/29/2011 4/30/2016 May 2017 3K pad next due May of 2017. Well to be tested on or before 5/31/17 to get on schedule. 3K-22A AIO 26.013 4/5/2005 4/14/2015 May 2017 CPAI requests a delay of up to 1 month to allow the MIT to be performed on or before 5/31/17 to get on schedule. 3N-11A AIO 213.072 12/7/2012 8/1/2016 August 2018 3N pad next due August of 2020. Well to be tested on or before 8/31/18 to get on schedule. 3N-16A AIO 2B.057 8/7/2016 August 2018 Well to be tested on or before 8/31/18 to get on schedule. AA did not stipulate anniversary date. 30-07 AIO 2C.032 June 2017 3/14/2016 June 2017 30 pad next due June of 2017. No changes 30-10 AIO 26.033 6/10/2008 6/1/2016 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 30-17 AIO 2C.026 8/5/2015 8/5/2015 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 3Q-01 AIO 2B.068 11/24/2011 8/2/2016 August 2018 3Q pad next due August of 2020. Well to be tested on or before 8/31/18 to get on schedule. 3Q-05 AIO 26.019 10/1/2007 8/2/2016 August 2018 Well to be tested on or before 8/31/18 to get on schedule. 3Q-12 AIO 2C.002 8/14/2014 9/15/2016 August 2018 Well to be tested on or before 8/31/18 to get on schedule. 3Q-15 AIO 213.042 9/25/2008 8/2/2016 August 2018 Well to be tested on or before 8/31/18 to get on schedule. 3Q-16 AIO 26.082 1/12/2014 8/2/2016 August 2018 Well to be tested on or before 8/31/18 to get on schedule. 3Q-21 AIO 26.005 4/25/2006 8/2/2016 August 2018 Well to be tested on or before 08/31/18 to get on schedule. 3R-25 AIO 213.012 4/27/2005 8/2/2016 August 2018 3111 pad next due August of 2020. Well to be tested on or before 8/31/18 to get on schedule. 35-18 AIO 213.069 6/6/2012 6/6/2012 Alternating service and development well. Required to have witnessed MIT upon start of each injection cycle. Well currently on production. No changes 35-26 AIO 2C.036 August 2016 8/18/2016 August 2016 3S pad next due August of 2018. No changes CD1-07 AIO 1813.006 6/8/2008 6/11/2015 June 2017 CD1 pad next due June of 2017. Well to be tested on or before 6/30/17 to get on schedule. CD1-14 AIO 18C.006 9/1/2015 6/12/2013 June 2017 Well to be tested on or before 6/30/17 to get on schedule. CD1-21 A1O.186.007 6/12/2013 6/11/2015 June 2017 Well to be tested on or before 6/30/17 to get on schedule. CD1-46 AIO 18C.004 2/20/2015 6/12/2013 June 2017 Well was recently BO1 on 2/21/17. The well will be tested when stable and then again on or before 6/30/17 to get on schedule. CD2-51 AIO 18C.010 June 2016 6/22/2016 June 2016 CD2 pad next due June of 2018. No changes CD3-112 AIO 30.007 February 2018 2/23/2014 February 2018 CD3 pad next due February of 2018. No changes CD3-123 AIO 30.005 2/23/2014 2/18/2016 February 2018 Well to be tested on or before 2/28/18 to get on schedule. CD3-128 AIO 18C.009 February 2018 2/23/2014 February 2018 No changes CD3-198 AIO 30.006 7/30/2015 1/28/2017 February 2018 Well to be tested on or before 2/28/18 to get on schedule. CD4-17 AIO 18C.003 5/6/2015 6/30/2011 June 2017 CD4 pad next due June of 2019. Well has been shut in since 5-3-15. If the well is BOI it will be tested on or before 5/6/17 and then again on or before 6/30/17 to get on schedule. CD4-27 AIO 18C.008 June 2017 6/12/2015 June 2017 No changes CD4-209 AIO 28.003 11/28/2009 11/11/2015 June 2017 Well to be tested on or before 6/30/17 to get on schedule. CD4-321 AIO 18C.002 5/10/2013 11/11/2015 June 2017 Well to be tested on or before 6/30/17 to get on schedule. CD4-322 AIO 18C.005 6/12/2015 6/12/2015 June 2017 Well to be tested on or before 6/30/17 to get on schedule. #10 TIDE STATE �Ipl LIN I GOVERNOR SEAN PARNELL Mr. Jerry Dethlefs Well Integrity Director ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 August 16, 2013 Conservation Commission CERTIFIED MAIL — RETURN RECEIPT REQUESTED 7009 2250 0004 3911 5884 Re: Amendment of Alternative MIT schedule for UIC. injection Wells Dear Mr. Dethlefs: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 By a letter received on May 9, 2013 ConocoPhillips Alaska, Inc (CPAI) requested approval to amend the permanent Mechanical Integrity Test (MIT) schedule for Class II injection wells in fields operated by CPAI on the North Slope of Alaska. The Alaska Oil and Gas Conservation Commission (AOGCC) hereby APPROVES the requested amendment establishing the MIT due date for Kuparuk River Unit 1J-pad injection wells as May, and Colville River Unit pads CD3 as February and CD4 as June. AOGCC also APPROVES CPAI's request to allow for a test month for MITs in lieu of an anniversary date. No further action is deemed necessary regarding MITs in Area Injection Orders 213, 16, 18C, 21A, 28, 30 and 35. Should you have any questions, please contact Chris Wallace at 907-793-1250. P Cathy P. toers er 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 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 he period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Postal Service• MAIL,CERTIFIED RECEIPT (Domestic/ No Insurance Coverage Provided) �3 47For deliverVilr1formation visit [7 • L U ur website at •S • rl \c� 1. l� L f 'Z 17- Postage $ m Certified Fee a Return Receipt Fee Postmark Here O (Endorsement Required) ID Restricted Dtalivary Fee d (Endorsement Required) r.r7 FU Total Postage t rt.J IT era o Q Mr. Jerry Dethlefs ED �veei, iipi No.; Well Integrity Director or POBoXNo. ConocoPhillips Alaska, Inc. City, State, ZlPr4 Post Office Box 100360 Anchors e AK 99510-0360 • CorYmpfete items r, 2, and S. Also complete item 4 if Restricted Delivery is desired. • Print your name and address on the reverse so that we can return the card to you. • Attach this card to the back of the mailpiece, or on the front if space permits. 1. Article Addressed to Mr. Jerry Dethlefs Well Integrity Director ConceoPhillips Alaska, Inc. Post Office Box 100360 AnchoraQe.AK 99510-0360 A. Sig. ure X ❑Agent ❑ Addressee . R rued by (Printed4me) C. Date of Delivery �F D. Is deliv ry address different from item 1? ❑ Yes If YES, enter delivery address below: ❑ No 3. Sgivice Type Certified Mail ❑ Express Mail ❑ Registered ❑ Return Receipt for Merchandise ❑ Insured Mail ❑ C.O.D. 4. Restricted Deiivery7 (Extra Pee) ❑ Yes 2. Article Number 7009 2250 0004 3911 5884 (transfer from service labeg PS Form 3811, February 2004 Domestic Return Receipt 102595-02-M-1540 THE STATE ,-,LASKA GOVERNOR SEAN PARNELL Alaska Oil and Gas Conservation Commission August 16, 2013 AOGCC Industry Guidance Bulletin No. 10-02A Mechanical Integrity Testing 333 West Seventh Avenue Anchorage, Alaska 99501-3572 1v'�atm 907.279.-1433 Fax:907.276.7542 Tlie Alaska Oil and Gas Conservation Commission (AOGCQ provides the following clarification of m Injection well mechanical integrity pressure test (MIT) requirements set forth in 20 AAC 25252 and 25.402. Injection orders supplement AOGCC regulations by providing additional operating and testing obligations. MIT Preparation - 'The AOGCC must be notified at least 24 hours in advance (48 hours for wells remote from the nearest AOGCC office) for an opportunity to witness the MIT; - Pumping into and bleeding pressures from annuli should be avoided for 24 hours prior to the MIT; if necessary, information should be available to document such activity; - The well's annulus must be fluid packed before the AOGCC Inspector arrives', - Calibrated pressure gauges with suitable range and accuracy must be installed on the tubing, inner (tubing by casing) annulus, and outer (casing by casing) annuli; current calibration should be evident with proper labels or other documentation; - Suitable flow measurement equipment should be available to determine the volume of fluids pumped into and returned from the tested space; - Other equipment (e.g., tanks, lines, bleed trailers, etc.) necessary for the safe pressure testing and suitable for the operating environment should be rigged up prior to AOGCC Inspector arrival at the location. The following information must be available at the location for AOGCC Inspector review: - Valid approved waivers, if any, relating to the integrity of the tested well; - Current well schematic; - Graph of tubing, inner annulus, and outer annulus pressures for the preceding 90 days. Equipment Pressure Rating Equipment subject to test pressure must have a rated working pressure that meets or exceeds the planned test pressure. API defines the rated working pressure of equipment to be the maximum internal pressure that the equipment is designed to contain or control. 0 Guidance Bulletin 10-02A Mechanical lnregrity Testing Pa'-,e 2 of 3 Test Cycle After the initial MIT, Class 11 disposal wells injecting solid slurries (used muds, cuttings; produced sand. etc.) require an MIT once every 2 years; otherwise, MITs must be conducted once every 4 years. Injection wells used for enhanced recovery operations must be tested once every 4 years. The AOGCC may, in its discretion, approve an alternate MIT schedule. A 2- or 4-year MIT means the test must be performed not later than the 2- or 4-year anniversary of the test month, unless a specific arimversary date for the MIT has been established by AOGCC approval (e.g., Area Injection Order administrative approval). For example, a test due August 14, 2014 would — under the new "test month" approach - be allowed to be tested not later than August 30, 2014. Operators are encouraged to take advantage of operating efficiencies in scheduling groups of MITs, and to initiate scheduling early in the month to increase inspector availability and allow time for retesting or unplanned events. The AOGCC must be provided the opportunity to witness the MIT for a test to establish a new test due date. The AOGCC may require a witnessed test to be rescheduled tc accommodate workload priorities. A pre -injection MIT performed prior to demobilizing a drilling rig from a well should be documented on the AOGCC's MIT Form 10-426 and emailed to the AOGCC addressees noted on the test report form. Test Pressure Unless otherwise required by the AOGCC, an MIT of the inner annulus is required to a minimum pressure of 1500 psi or a pressure determined by multiplying 0.25 psi per foot times the true vertical depth of the packer — whichever is greater. A minimum pressure differential of 500 psi should be maintained between the tested annulus and tubing or adjacent annulus. The operator has the discretion to test to a higher pressure. A passing MIT will have no more than a 10 percent decline in pressure (based on the actual test pressure), a stabilizing pressure trend, and a final pressure that is at or above the required test pressure. For example, the operator may choose to start a required 1500 psi test at or above 1650 psi (additional 150 psi to allow for the 10 percent pressure decline over test duration). Reporting Unless otherwise required by the AOGCC, MIT results must be verified by an operator's designated representative and submitted electronically using Form 10-426 to the AOGCC no later than the 5" calendar day of the month following the testing. i • Guidance Bulletin 10-02A Mechanic -al lntegrity Testing Pace 2 of Shut-in Wells The AOGCC's preference is to witness an MIT while a well is actively injecting and ��ellbore conditions (rate and temperature) are stable. if the well is in a short-term shut-in status when the MIT is due, the AOGCC should be notified and provided an alternate date for testing based on whe❑ injection will be recommenced. Injection wells that are shut in long-term (undetermined when injection will restart) need not be tested until they are ready to recommence injection. In lieu of an MIT for the long term shut-in well; the operator must provide to the AOGCC a quarterly graph of tubing, inner annulus and outer annulus pressures. Please share this Guidance Bulletin with all appropriate members of your organizations. Questions or discussion regardirig this guidance bulletin should be directed to Chris Wallace at (907) 793-1250. Sincerely, Cathy P. oerster Chair, Commissioner Ll ConocoPhillips May 8, 207.2 Mr. Chris Wallace Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 MAY092013 Subject: Amendment of alternative MIT schedule for UIC injection wells Dear Mr. Wallace: Jerry Dethlefs Well Integrity Director ConocoPhillips Alaska, Inc 700 G Street Anchorage, AK Phone 907-265-1464 ConocoPhillips Alaska, Inc. (CPAI) requests approval to amend the permanent Mechanical Integrity Test (MIT) schedule for Class II injection wells in fields operated by CPAI on the North Slope of Alaska. The amendment is to include new pads installed since the original approval and to clarify the affected Area Injection Orders (AIO). On February 13, 2006, CPAI requested approval to adopt an alternate MIT schedule for their North Slope Class II injection wells so as to allow the majority of the wells to be tested during the summer months (schedule attached). On March 23, 2006, administrative approval was granted for the alternate schedule by the AOGCC (attached). The approval letter states "The requested schedule modification will allow for greater operating efficiency and will reduce risks to personnel and the environment. The Commission hereby APPROVES the requested modification." The alternative test schedule also complies with the AOGCC Industry Guidance Bulletin No. 10-002 Mechanical Integrity Testing. The section titled "Test Cycle" reads: "Injection wells used for enhanced recovery operations must be tested once every 4 years. The Commission may, in its discretion, approve an alternate MIT schedule. A 2- or 4-year MIT means the test must be performed not later than the 2- or 4-year anniversary of the most recent test date, unless a specific anniversary date for the MIT has been established by a Commission approval (e.g., Area Injection Order administrative approval)." ....."Operators are encouraged to take advantage of operating efficiencies in scheduling groups of MITs within the 2- or 4-year window"...... A key component of the 4-year testing program is that each pad is assigned a specific month to be tested every four years (see attached schedule). The number of pads and wells are divided over the four year period so that roughly one-fourth of the required MITs are performed each year. The specified month is the due date, rather than the specific day of the prior test, to eliminate schedule creep over time. All injection wells on a pad will be tested during the visit. This method was adopted and put into practice with the March 23, 2006 approval and has proven to work well. Please note that CD3, due to lack of summer road access, is scheduled for February by prior AOGCC approval. • CPAI is requesting an amendment to incorporate new drillsites and clarify the affected AIOs. Drillsites 1J, CD3 and CD4 have been added to the list. The administrative approval regards Rule 6 in AIOs 2B, 16, 18C, 28, 30 and 35, and Rule 4 in 21A. The MIT schedule applies only to CPAI wells on the standard 4-year test frequency, with the exception of 2P (Meltwater) which is on a 2-year cycle due to recent changes in AIO 21A. Wells with specific approvals or variances on 2-year test cycles will continue to be tested on or before the exact 2-year anniversary date. Approval of this request at your earliest convenience is appreciated. Please call Brent Rogers or Kelly Lyons at 659-7224, or me at 265-1464 if you have any questions. Sincerely, Jerry Dethlefs Well Integrity Director cc: Jim Regg Cathy Forester Attachments ConocoPhillips Alaska, Inc. UIC MIT Permanent Test Schedule Revised May 7, 2013 Target 4-year Cycle: The following schedule repeats every 4 years Year 1 Kuparuk Alpine May 2A, 2B, 2G, 2H June 1 F, 1 L, 2M, 2V July 2E, 2F, 3J, 3M August 3N, 3Q, 3R, 2P* Year 2 May 3K June 1 B & WSW, 2T, 3H, 30 CD1 July 1Q, 1Y August 1 H, 2C, 2D, 3A, 3C Year 3 February CD3 May 1 C, 1 J June 1 E CD2 July 1 D August 2L, 2N, 2P*, 2U, 3S Year 4 May 1 R, 2W June 2K, 2X, 3B, 3F CD4 July 1A, 1G, 31 August 3G, 2Z Note: Year 1=2012 Revised 05-07-13 Contact: CPAI Problem Well Supervisor, 907-659-7224 • ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 February 13, 2006 Mr. Tom Maunder Alaska Oil & Gas Commission 333 West 7ch Avenue, Suite 100 Anchorage, AK 99501 Subject: Proposal for permanent MIT schedule on UIC injection wells Dear Mr. Maunder: On December 19, 2005, ConocoPhillips Alaska, Inc. (CPAI) requested approval to delay UIC 4-year Mechanical Integrity Tests (MIT) due in 2006 for a limited time beyond their due date so the tests could be performed during the summer months. The request was approved by the AOGCC on December 29, 2005, with the stipulation no further extensions would likely be granted for future years. CPAI is proposing an alternative test plan that should meet the objectives of both CPAI and AOGCC. The AOGCC position is that UIC MIT tests be performed no later than the exact due date of the previous 4-year test on each well, as specified in 20 AAC 25.412 and in Area Injection Orders 2B and 18B. The justification for this date enforcement is lack of precedent within the regulations for an Operator to alter the due date without specific approval from the AOGCC. Previously these tests had routinely been delayed to the summer months due to safety and spill potential issues and efficiency/cost savings associated with performing these tests during warm weather. CPAI is proposing a schedule for UIC MIT testing patterned after the AOGCC required program used for testing the Safety Valve System (SVS). In that program each pad is assigned to two specific months of the year for testing. To prevent schedule creep over time, there is some flexibility to perform the tests anytime during the assigned month. The pads are scheduled to roughly balance the workload from one month to the next. For 4-year UIC MIT testing, CPAI is proposing that each pad be assigned a specific month to be tested every four years. The number of pads and wells will be divided over the four year period so that roughly one-fourth of the required MITs will be performed each year. The specified month will be the due date, rather than the specific day of the prior test, to eliminate schedule creep over time. To implement this schedule • • Mr. Tom Maunder Page 2 of 2 02/13/06 CPAI will accelerate testing on a number of wells over the next few years. The proposed schedule and pad/month assignments are attached. There are a number of benefits to this proposal: • Each well will be tested close to the previous 4-year test if a small allowance is approved to prevent schedule creep. This should meet the "every 4-year" test frequency requirement in the UIC regulations. • All the injection wells on a given pad will be addressed during the same testing operation, regardless of when the last test was performed on a particular well. This will keep all the wells on the same schedule, results in efficiencies in time and reduces fluid handling risk. • Eliminates requests to "reset" the 4-year clock when tests are performed during the year, eliminating significant record keeping efforts. • The proposed months are in the May through August time period that meets the CPAI goal of testing during warmer weather. The AOGCC is specifically being requested in this proposal to approve the "due month" concept of this plan rather than the "exact due date" specified in the letter dated December 29, 2005. In addition, the proposal applies only to CPAI wells on the standard 4-year test frequency. Wells with specific approvals or variances on 2-year test cycles will continue to be tested on or before the exact 2-year anniversary date. Approval of this request at your earliest convenience is appreciated. Please call MJ Loveland, Marie McConnell, or me at 659-7224 if you have any questions. Sincerely, 0-4-W4 M Jerry Dethlefs Problem Well Supervisor Attachment ConocoPhillips Alaska, Inc. Proposed UIC MIT Permanent Test Schedule Initial 4-year Cycle: Requires accelerating tests for all wells on a pad to be on same cycle Year 1: 2006 Total Wells Kuparuk Pads Alpine Pads Total Wells May 22 1C June 56 1 B, 3H, 30, 1 E July 54 1 D, 1 Q, 1Y, 3F' August 48 1A-, 1 R', 2G', 2K', 2L, 2N, 2P, 2U, 2W', 2Z', 3G', 3S CD2 29 Total 160 Year 2: 2007 May 21 1 R, 2W June 53 2K, 2T, 2X, 36, 3F July 28 1 A, 1 G, 31 August f 25 1 F', 2D-, 2F', 2H', 2M', 3G, 3M-, 2Z Total 127 Year 3: 2008 May 23 2A, 213, 2G, 2H June 38 1 F, 1 L, 2M, 2V July 30 2E, 2F, 3J, 3M CD1' 2 August 24 3N, 3Q, 3R Total 115 Year 4: 2009 May 14 3K June 39 1 B, 2T, 3H, 30 July 19 1Q, tY August 35 1 H, 2C, 2D, 3A, 3C CD1 22 Total 107 Target 4- ear Cycle: The foAowln schedule re eats every 4 years Year 5 May 22 1 C June 31 1E July 34 1 D August 32 2L, 2N, 2P, 2Z, 3S CD2 29 Total 119 _ Year 6 May 21 1 R, 2W June 38 2K, 2X, 3B, 3F July 18 1 A, 1 G, 31 Aun-t 1 R 3G. 2Z Total 95 Year 7 May 23 2A, 2B, 2G, 2H June 38 1 F, 1 L, 2M, 2V July 30 2E, 2F, 3J, 3M 11 August I Z4 I aim, ou, art Total 115 s 1 Year 8 May 14 3K June 40 2T, 1 B, 3H, 30 July 27 1Q, 1Y August 35 1 H, 2C, 21), 3A, 3C CD1 24 Total 116 Notes: 1) ' Denotes pads to be accelerated prior to due -date for combining all wells on a pad to same test date 2) New pads will be added to the schedule as they are brought in service 2 ME 0 ALASKA FRANK H. MURKOWSKI, GOVERNOR �7KA OIL AND GAS333 W. 7m AVENUE, SUITE 100 CONSIBIR-A IOAT COMMISSIOAT ANCHORAGE, ALASKA 99501-3539 jj PHONE (907) 279-1433 FAX (907) 276-7542 Mr. Jerry Dethlefs Problem Well Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 RE: North Slope MIT Schedule Dear Mr. Dethlefs: On February 13, 2006 ConocoPhillips Alaska, Inc ("CPAI") requested approval to modify the schedule for demonstrating mechanical integrity on their North Slope injection wells so as to allow the majority of the wells to be tested on a rotating schedule during the summer months. The requested schedule modification will allow for greater operating efficiency and will reduce risks to personnel and the environment. The Commission hereby APPROVES the requested modification. In order to allow opportunity for AOGCC Inspectors to witness the testing, CPAI is requested to provide the planned schedule for Summer 2006 as soon as practical. If you have any questions, please contact Jim Regg at 793-1236. As provided in AS 31.05.080(a), 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 reconsideration. A request for reconsideration 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 reconsideration )r4 been requested. Alaska and dated March 0, 2006 Dan T. Seamount, Jr. Commissioner *Cathy. Foerster Commissioner 0- 0 ConocoPhillips April 8, 201� Mr. Dan Seamount Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Jerry Dethlefs Well Integrity Director ConocoPhillips Alaska, Inc 700 G Street Anchorage, AK Phone 907-265-1464 b oil(et-t-i- )-3 , o c0 Subject: Administrative Approval for alternative MIT schedule for UIC injection wells (revised) Dear Mr. Seamount: ConocoPhillips Alaska, Inc. (CPAI) requests approval for a modified Mechanical Integrity Test (MIT) schedule for Class II injection wells in fields operated by CPAI on the North Slope of Alaska. A provision in AOGCC Industry Guidance Bulletin No. 10-002 Mechanical Integrity Testing, under "Test Cycle" states: "Injection wells used for enhanced recovery operations must be tested once every 4 years. The Commission may, in its discretion, approve an alternate MIT schedule. A 2- or 4-year MIT means the test must be performed not later than the 2- or 4-year anniversary of the most recent test date, unless a specific anniversary date for the MIT has been established by a Commission approval (e.g., Area Injection Order administrative approval)." CPAI is requesting administrative approval from Rule 6, Area Injection Orders 2B, 16, 18B, 27, 28, 30 and 35, and Rule 4, AIO 21, in order to "take advantage of operating efficiencies in scheduling groups of MITs within the 2- or 4-year window" (reference Bulletin 10-002). On February 13, 2006, CPAI requested approval to modify the MIT schedule for their North Slope Class 11 injection wells so as to allow the majority of the wells to be tested during the summer months (attached). On March 23, 2006, approval was granted for the modified schedule by the AOGCC (attached). The approval letter states 'The requested schedule modification will allow for greater operating efficiency and will reduce risks to personnel and the environment. The Commission hereby APPROVES the requested modification." CPAI complied with the MIT schedule as approved until the AOGCC issued Industry Guidance Bulletin No. 10-002 Mechanical Integrity Testing. According to the AOGCC, as of the date of the Guidance Bulletin the administrative approval for the MIT test schedule was revoked. Although the Guidance Bulletin may meet the needs of other operators in the state, it also results in placing CPAI back to the point of the initial schedule modification request. Therefore, CPAI is again requesting approval to modify the MIT schedule by Area Injection Order administrative approval. The justification for the schedule change request has not altered since the original request in 2006. CPAI requests relief from the requirement in Bulletin 10-002: "A 2- or 4-year MIT means the test must be performed not later than the 2- or 4-year anniversary of the most recent test date, unless a specific anniversary date for the MIT has been established by a Commission approval (e.g., Area Injection Order administrative approval). " 0 CPAI proposes a schedule for UIC MIT testing patterned after the AOGCC required program used for testing the Safety Valve System (SVS). In that program each pad is assigned to two specific months of the year for testing. To prevent schedule creep over time, there is some flexibility to perform the tests anytime during the assigned month. The pads are scheduled to roughly balance the workload from one month to the next. For 4-year UIC MIT testing, CPAI is proposing the same schedule as that approved in 2006; that each pad be assigned a specific month to be tested every four years (see attached schedule). The number of pads and wells are divided over the four year period so that roughly one-fourth of the required MITs are performed each year. The specified month is the due date, rather than the specific day of the prior test, to eliminate schedule creep over time. This method was adopted and put into practice with the March 23, 2006 approval and has proven to work well. Please note that CD3, due to lack of summer road access, is scheduled for February by prior AOGCC approval. There are a number of benefits to this proposal: • Each well will be tested close to the previous 4-year test if a small allowance is approved to prevent schedule creep. This should meet the "every 4-year" test frequency requirement in the UIC regulations. • All the injection wells on a given pad will be addressed during the same testing operation, regardless of when the last test was performed on a particular well. This will keep all the wells on the same schedule, results in efficiencies in time and reduces fluid handling risk. • Eliminates requests to "reset" the 4-year clock when tests are performed during the year, eliminating significant record keeping efforts. • The proposed months are in the May through August time period that meets the CPAI goal of testing during warmer weather to minimize risks regarding personnel safety and releases to the environment. The AOGCC is being requested to approve the "due month" concept of this plan rather than the "exact, due date" specified in Bulletin 10-002. In addition, the proposal applies only to CPAI wells on the standard 4-year test frequency. Wells with specific approvals or variances on 2-year test cycles will continue to be tested on or before the exact 2-year anniversary date. Approval of this request at your earliest convenience is appreciated. Please call Brent Rogers or Kelly Lyons at 659-7224, or me at 265-1464 if you have any questions. Sincerely, Jerry Dethlefs Well Integrity Director cc: Cathy Forester Jim Regg Attachments • • ConocoPhillips Alaska, Inc. UIC MIT Permanent Test Schedule Target 4-year Cycle: The following schedule repeats every 4 years Year 1 Kuparuk Alpine p May 2A, 2B, 2G, 2H June 1 F, 1 L, 2M, 2V July 2E, 2F, 3J, 3M August 3N, 3Q, 3R Year 2 May 3K June 1B & WSW, 2T, 3H, 30 CD1 July 1Q, 1Y August 1 H, 2C, 2D, 3A, 3C Year 3 February CD3 May 1 C, 1 J June 1 E CD2 July 1 D August 2L, 2N, 2P, 2U, 3S Year 4 May 1 R, 2W June 2K, 2X, 3B, 3F CD4 July 1A, 1G, 31 August 3G, 2Z Note: Year 1=2012 Revised 04-05-12 Contact: CPAI Problem Well Supervisor, 907-659-7224 C7 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 February 13, 2006 Mr. Tom Maunder Alaska Oil & Gas Commission 333 West 7`h Avenue, Suite 100 Anchorage, AK 99501 Subject: Proposal for permanent MIT schedule on UIC injection wells Dear Mr. Maunder: On December 19, 2005, ConocoPhillips Alaska, Inc. (CPAI) requested approval to delay UIC 4-year Mechanical Integrity Tests (MIT) due in 2006 for a limited time beyond their due date so the tests could be performed during the summer months. The request was approved by the AOGCC on December 29, 2005, with the stipulation no further extensions would likely be granted for future years. CPAI is proposing an alternative test plan that should meet the objectives of both CPAI and AOGCC. The AOGCC position is that UIC MIT tests be performed no later than the exact due date of the previous 4-year test on each well, as specified in 20 AAC 25.412 and in Area Injection Orders 2B and 18B. The justification for this date enforcement is lack of precedent within the regulations for an Operator to alter the due date without specific approval from the AOGCC. Previously these tests had routinely been delayed to the summer months due to safety and spill potential issues and efficiency/cost savings associated with performing these tests during warm weather. CPAI is proposing a schedule for UIC MIT testing patterned after the AOGCC required program used for testing the Safety Valve System (SVS). In that program each pad is assigned to two specific months of the year for testing. To prevent schedule creep over time, there is some flexibility to perform the tests anytime during the assigned month. The pads are scheduled to roughly balance the workload from one month to the next. For 4-year UIC MIT testing, CPAI is proposing that each pad be assigned a specific month to be tested every four years. The number of pads and wells will be divided over the four year period so that roughly one-fourth of the required MITs will be performed each year. The specified month will be the due date, rather than the specific day of the prior test, to eliminate schedule creep over time. To implement this schedule Mr. Tom Maunder Page 2 of 2 02/13/06 CPAI will accelerate testing on a number of wells over the next few years. The proposed schedule and pad/month assignments are attached. There are a number of benefits to this proposal: • Each well will be tested close to the previous 4-year test if a small allowance is approved to prevent schedule creep. This should meet the "every 4-year" test frequency requirement in the UIC regulations. • All the injection wells on a given pad will be addressed during the same testing operation, regardless of when the last test was performed on a particular well. This will keep all the wells on the same schedule, results in efficiencies in time and reduces fluid handling risk. • Eliminates requests to "reset" the 4-year clock when tests are performed during the year, eliminating significant record keeping efforts. • The proposed months are in the May through August time period that meets the CPAI goal of testing during warmer weather. The AOGCC is specifically being requested in this proposal to approve the "due month" concept of this plan rather than the "exact due date" specified in the letter dated December 29, 2005. In addition, the proposal applies only to CPAI wells on the standard 4-year test frequency. Wells with specific approvals or variances on 2-year test cycles will continue to be tested on or before the exact 2-year anniversary date. Approval of this request at your earliest convenience is appreciated. Please call MJ Loveland, Marie McConnell, or me at 659-7224 if you have any questions. Sincerely, Jerry Dethlefs Problem Well Supervisor Attachment 0 AIASKA / FRANK H. MURKOWSKI, GOVERNOR gar S"a4i Rtt j/�►7s HA OIL A" GAS 333 W. 7"' AVENUE, SUITE 100 CONSERVATION COt•> USSION ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Mr. Jerry Dethlefs Problem Well Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 RE: North Slope MIT Schedule Dear Mr. Dethlefs: On February 13, 2006 ConocoPhillips Alaska, Inc ("CPAI") requested approval to modify the schedule for demonstrating mechanical. integrity on their North Slope injection wells so as to allow the majority of the wells to be tested on a rotating schedule during the summer months. The requested schedule modification will allow for greater operating efficiency and will reduce risks to personnel and the environment. The Commission hereby APPROVES the requested modification. In order to allow opportunity for AOGCC Inspectors to witness the testing, CPAI is requested to provide the planned schedule for Summer 2006 as soon as practical. If you have any questions, please contact Jim Regg at 793-1236. As provided in AS 31.05.080(a), 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 reconsideration. A request for reconsideration 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 reconsiderationA been requested. Alaska and dated March 2�, 2006 Dan T. Seamount, Jr. Commissioner Cathy Y. Foerster Commissioner ConocoPhillips Alaska, Inc. Permanent UIC MIT Test Schedule Initial 4-year Cycle: Requires accelerating tests for all wells on a pad to be on same cycle Year 1: 2006 Total Wells Kuparuk Pads Alpine Pads Total Wells May 22 1C June 56 1B & WSW, 1E, 3H, 30 July 54 1 D, 10, 1Y, 3F* August 48 1A*, 1 R*, 2K*, 2L, 2N, 2P, 2U, 2W*, 2Z*, 3G*, 3S CD2 29 Total 180 Year 2: 2007 May 21 1 R, 2W June 53 2K, 2T, 2X, 3B, 3F July 28 1A, 1G, 31 August 25 1 F*, 2D*, 2F*, 2G*, 2H*, 2M*, 3G, 3M*, 2Z Total 127 Year 3: 2008 May 23 2A, 2B, 2G, 2H June 38 1F, 1L, 2M, 2V CD1* 2 July 30 2E, 2F, 3J, 3M August 24 3N, 3Q, 3R Total 115 Year 4: 2009 May 14 1 J*, 3K June 39 1B & WSW, 2T, 3H, 30 CD1 22 July 19 1Q, 1Y CD4* 15 August 35 1 H, 2C, 2D, 3A, 3C Total 144 I I Tar et 4-year Cycle: The following schedule repeats every 4 years 8 Feb CD3 May 37 1C,1J { ---- - ---- ----29 June 31 1 E CD2 July, i. . ...---- 34 1D August i 32 _ 2L, 2N, 2P, 2U, 2Z, 3S .- Total ; 119 _ ___ __ -_ Year 6- 21 1R 2W -- ---- - - -- -- --- _ -_ June -- - - ---- - 38 -- - --- - - - - - 2K, 2X 3B, 3F CD4 - -- --- - .. 1 A, 1 G, 31 - - ------- -- - - -- - Au ust 18 3G 2Z Total 95 _Year 7 - - --- +- - -- -- -- - - -- -- Ma 23 2A,26 2G,2H June 38 1 F, 1 L, 2M, 2V July 1 2E, 2F, 3J, 3M _ - .30___--._.. August 24 3N 3Q, 3R Total 115 .._ Year 8 t . May I 14 ---- June - - -- 40---- 3K - --- --- - -- - ------ ------ ----- 16 &WSW, 2T, 3H, 30 --- --- CD1 --- _ __ 24 _... July 27 1Q, 1Y - August ' -- 36-`- -- 1H, 2C 2D, 3A 3C _._.. _._ . _ Total 116 Notes: 1) * Denotes pads to be accelerated prior to due -date for combining all wells on a pad to same test date 2) New pads will be added to the schedule as they are brought in service; load leveling may be required Revised 08-16-06 Roby, David S (DOA) From: Walker, Jack A [ Jack .A.Walker @conocophillips.com] Sent: Friday, November 05, 2010 10:20 AM To: Roby, David S (DOA) Subject: Colville River Field & Kuparuk River Field Water Comparison Attachments: ColvilleRiverWaterAnalyses.xis Dave, Enclosed is the comparison we discussed on the phone. The two charts show the range of dissolved solids for Colville produced water and seawater plotted with the average value for Kuparuk CPF -2 produced water which is basis for our belief that the CPF -2 water is compatible with the Colville River Field formations. I'll follow up with more background regarding the request for authorization to inject Kuparuk River Field produced water into the Colville River Field Oil Pools. Jack Colville River Field and CPF -2 Produced Water Comparison 100000 10000 Q 1000 a J 100 ■ ■ E ■ ■ 10 ■ • 4 a 1 0.1 a� E oCRU Produced Water (Range) 6 ■ c 0.01 D ■ CPF -2 PW Average - Last 10 Samples • Of U 0.001 ■ ■ - me �o ao �;o o Q , � 's` � 5 �` J`' �a �a o �. ��a ��` �J o� �� G�J N� 4 -:31 r�J o�J �o �� o� �oJ a�� Ga�o Grp 5 5J P��` �� C ;V Grp °�` 4 ' 0 �'� a Q, ��°'� 5 oy Q r 5� �, 0 �` Q l / 4r Colville River Field Seawater and CPF -2 Produced Water Comparison 100000 10000 „ v t. ■ 1000 J 100 • CFO ■ ■ E ■ ■ .� 10 ■ c E o k Q 1 ■ ■ ■ 0.1 MSeawater (Range) ■ 0.01 ■ CPF - 2 PW Average - Last 10 Samples . 0.001 - ■ _.. �- _ . ■ a � 0 - a� �,�2 `ate J `Op �J , J� � �J� �� `J� �J� J� a�o� � Gr�o� 5J`� �J� \J�� 6Vo �`�' G`� SAMPLE NUM Date Time Location ravity @ 60 pH 6298863 10/3/2010 22:33 Separator 1.0179 7.48 6298864 10/3/2010 22:27 Separator 1.0201 8.37 AB71202 7/4/2010 4:00 Drum 1.0204 7.81 AB71201 7/4/2010 4:00 Separator 1.0206 7.76 AB71200 7/4/2010 4:00 Separator 1.0188 8.59 AB68013 4/4/2010 2:50 Separator 1.0201 8.43 AB68012 4/4/2010 2:30 Separator 1.0208 7.63 AB64673 1/5/2010 3:00 Separator 1.0201 8.59 AB64672 1/5/2010 2:50 Separator 1.0198 7.58 AB61378 10/12/2009 15:00 Drum 1.0207 7.6 Seawater - AB42201 7/4/2008 Summer 1.0026 7.01 Seawater - AB36364 2/8/2008 Winter 1.0338 6.75 Specific G ravity @ 60 pH PW Minimum 1.0179 7.48 PW Maximum 1.0208 8.59 Difference 0.0029 1.11 SW Minimum 1.0026 6.75 SW Maximum 1.0338 7.01 Difference 0.0312 0.26 SAMPLE NUM Date Time MPLE POI ravity @ 60 j pH CPF -2 Prod. Water Tank AB65778 2/6/2010 14 :09 Outlet 1.0168 7.98 CPF -2 Prim. Sep. Water AB62075 11/4/2009 0:00 Outlet 1.0191 7.87 CPF -2 Prim. Sep. Water AB61846 10/29/2009 12:40 Outlet 1.0198 7.9 CPF -2 Prim. Sep. Water AB61525 10/21/2009 13:02 Outlet 1.0192 7.74 CPF -2 Prim. Sep. Water AB60990 10/5/2009 12:45 Outlet 1.0191 7.79 CPF -2 Prim. Sep. Water AB59666 9/5/2009 0:00 Outlet 1.0188 8.05 CPF -2 Prod. Water Tank AB59106 8/22/2009 13:40 Outlet 1.02 7.9 CPF -2 Prod. Water Tank AB50294 2/6/2009 0:00 Outlet 1.0188 7.98 CPF -2 Prod. Water Tank AB43457 8/10/2008 0:00 Outlet 1.0194 7.9 i CPF -2 Prim. Sep. Water AB42709 7/17/2008 0:00 Outlet 1.0188 7.73 Min 1.0168 7.73 Max 1.02 8.05 Average 1.01898 7.884 Previous 10 Samples Bicarbonate 1230 1140 1225 1223 1136 Carbonate 0 95 0 0 109 Chloride 15050 14620 15260 14960 14400 Sulfate 250 250 172 172 180 Sulfide Aluminum <0.1 <0.1 < 0.1 < 0.1 < 0.1 Boron 28.6 3.4 28 28 28 Barium 4.3 <1.0 8 3 13 Calcium 148.9 21.5 138 138 147 Chromium <0.2 <0.2 < 0.2 < 0.2 < 0.2 Iron 1.3 1.1 0.9 1.3 2.6 Potassium 67.6 7.9 55 58 56 Lithium 3.2 <0.5 2 2 2 Magnesium 62.1 7.7 57 57 58 Manganese 0.027 0.009 0.033 0.029 0.037 Sodium 11700 14600 10470 10330 10400 Phosphorus 0.9 0.1 0.6 1.1 0.3 Silicon 23.3 2.3 22 21 21 Strontium 15.3 1.9 16.4 15.9 16.2 Zinc 0.1 <0.1 < 0.1 < 0.1 < 0.1 Specific Gravity 60 degrees F 1.0179 1.0201 1.0204 1.0206 1.0188 H 7.48 8.37 7.81 7.76 8.59 on uctivity micro -m os /cm 40100 40100 40100 Notes: 1. Min / Max values taken from 10 most recent PW samples and typical summer / winter SW samples 2. Averages derived from 10 most recent CPF -2 PW samples. �I 0 0 Ftivity micro- Bicarbonate I Carbonate I Chloride I Sulfate I Sulfide Aluminum Boron 1230 0 15050 250 <0.1 28.6 1140 95 14620 250 <0.1 3.4 40100 1225 0 15260 172 < 0.1 28 40100 1223 0 14960 172 < 0.1 28 40100 1136 109 14400 180 < 0.1 28 34900 1108 97 14790 205 0.1 28.3 35700 1253 0 15180 228 < 0.1 30.4 28200 1178 185 15500 280 < 0.1 27.1 29800 1280 0 15600 290 < 0.1 28.4 30500 1403 0 15310 219 < 0.1 27 5960 100 0.001 1814 279 0.001 0 1 51900 140 0 24960 3580 0.001 0.1 4.9 tivit micro-n Carbonate Chloride Sulfate Sulfide I Aluminum Boron 28200 1108 0 14400 172 0 0.1 3.4 40100 1403 185 15600 290 0 0.1 30.4 11900 295 185 1200 118 0 0 27 5960 100 0 1814 279 0.001 0 1 51900 140 0.001 24960 3580 0.001 0.1 4.9 45940 40 0.001 23146 3301 0.0001 0.1 3.9 Ftivity micro- carbonate m arbonate m Chloride mg/l mg/l Sulfate m /I Sulfide m /I Fluminum mgl Boron mg/1 35200 1515 0 12050 42 9.4 < 0.1 16.2 I 30000 1541 0 13920 34 5.9 < 0.1 16.8 29800 1571 0 14550 65 16 <0.1 15 29400 1585 0 14400 69 8.7 < 0.1 16 29700 1589 0 13750 42 8.5 < 0.1 19.6 0'0965 0061.5 0965 Q090C oonz oozgz OOLg 8'9 9L'9 W1 91 891 65'8 £91 £17'8 0' L 8££0' L 9200' l LOZO' L 86 LO' L LOW' L 8020' L LOZOl 0'0 L 0 L'O > L'0 > L'0 > L'0 > V0 > 0'L Z'OL L £L 17'9 L 9'9L 8L 8'9L 0'0 L 0 6L LZ OZ £Z LZ 0'0 L'0 0 Z'0 £'0 £'0 9'0 9'0 0'605 096£L 605 00170E 9696 0956 OL9LL 08ZLL 0'0 LOO'0 17L0'0 £0'0 9£0'0 Z£0'O L50'0 L90'0 Ll 0£9L 17ZL 85 L5 Z5 £8 Z8 0'0 5'0 0 Z Z Z Z Z 61 609 1 717 89 99 179 £17L 170E 0'0 5'0 0 6'0 8'L 9'0 9'Z 17'Z TO Z'0 0'O Z'O > Z'0 > Z'0 > Z'0 > Z'0 > 9'LZ 9L9 179 EEL Z£L LZL M 98L 0'0 0' L 0'0 L9 17 9 Z L L 0' L 617 L LZ 17'8Z L'LZ 17'0£ £'8Z 0'0 L'0 0'0 L'0 > L'0 > L'0 > L'0 > L'0 0'0 0'0 0'0 O'ZLL 089E 6LZ 6LZ 06Z 08Z 8ZZ 90Z 0'148L 09617Z IML OL£9L 0099E 0099L OML 06D7 0'0 0'O 0'0 0 0 98L 0 L6 O'OOL Obl OOL £OK 08ZL 8LLL £9ZL 8OLL (, /6w) wnw,u, apinl®O 5£'9L 100'0 99999999'6 9'617 L68£ WTO ZL9L 08£L£ 9'6L 0 9L 69 OOL17L 0 L66L OOZE£ L'17L 0 6'9 17£ 090ZL 0 ML 00£6Z LA7L L'0 > L'9 L17 096£L 0 6Z6 008££ V9 L'0 > ZL 617 06917E 0 L66L 001717£ I 9'9L L'0> £9 OLL£l 0 099L 00£Z£ 9'9L L'0 > Z'L 69 OOL17L 0 L85L 00£6Z L L L'0 > 9' L L 9£ OZ6£ L 0 8£5 L 0066Z 0 0 Barium I Calcium I Chromium Iron Potassium I Lithium I Magnesium Man anese 4.3 148.9 <0.2 1.3 67.6 3.2 62.1 0.027 <1.0 21.5 <0.2 1.1 7.9 <0.5 7.7 0.009 8 138 < 0.2 0.9 55 2 57 0.033 3 138 < 0.2 1.3 58 2 57 0.029 13 147 < 0.2 2.6 56 2 58 0.037 11 185 < 0.2 2.4 104 2 82 0.051 2 192 < 0.2 2.5 143 2 83 0.051 5 121 < 0.2 0.6 54 2 52 0.032 4 132 < 0.2 1.8 65 2 57 0.036 67 133 < 0.2 0.9 68 2 58 0.03 0 54 0 0 44 0 124 0.014 1 515 0.2 0.5 609 0.5 1530 0.001 Barium Calcium I Chromium Iron Potassium Lithium Magnesium Man anese 2 21.5 0 0.6 7.9 2 7.7 0.009 67 192 0 2.6 143 3.2 83 0.051 65 170.5 0 2 135.1 1.2 75.3 0.042 0 54 0 0 44 0 124 0.001 1 515 0.2 0.5 609 0.5 1530 0.014 1 461 0.2 0.5 565 0.5 1406 0.013 Barium m /I Calcium m / hromium md Iron m /I otassium md Lithium m / a nesium m an anese m 29 135 < 0.2 < 0.5 87 2 98 0.018 43 105 < 0.2 < 0.5 66 2 101 0.015 36 93 0.2 0.3 56 1 95 0.03 28 97 < 0.2 1.3 62 2 104 0.025 34 112 < 0.2 < 0.5 96 2 107 0.011 43 91 <0.2 <0.5 61 2 100 <0.01 42 99.9 < 0.2 < 0.5 62.5 < 0.5 101 < 0.001 34 109 < 0.2 < 0.5 63 1 78 0.011 22 111 < 0.2 5.5 91 2 103 0.048 28 105 < 0.2 < 0.5 81 2 102 0.013 22 91 0.2 0.3 56 1 78 0.011 43 135 02 5.5 96 2 107 0.048 33.9 105.79 0.2 2.4 72.55 1.8 98.9 0.021375 River Field PW & SW aX1Ii um DifferenBe (m9/L) (mSIL) 1403.0 1303.0 1515.0 1541.0 1571.0 1585.0 1589.0 1538.0 185.0 185.0 0.0 0.0 0.0 0.0 0.0 0.0 24960.01 23146.0 12050.0 13920.0 14550.0 14400.0 13750.0 13920.0 3580.0 3408.0 42.0 34.0 65.0 69.0 42.0 36.0 0.0 0.0 9.4 5.9 16.0 8.7 8.5 11.6 0.1 0.1,< 0.1 < 0.1 <0.1 < 0.1 < 0.1 < 0.1 30.4 29.4 16.2 16.8 15.0 16.0 19.6 17.0 67.0 67.0 29.0 43.0 36.0 28.0 34.0 43.0 515.0 493.5 135.0 105.0 93.0 97.0 112.0 91.0 0.2 0.2 < 0.2 < 0.2 0.2 < 0.2 < 0.2 < 0.2 2.6 2.6 < 0.5 < 0.5 0.3 1.3 < 0.5 < 0.5 609.0 601.1 87.0 66.0 56.0 62.0 96.0 61.0 3.2 3.2 2.0 2.0 1.0 2.0 2.0 2.0 1530.0 1522.3 98.0 101.0 95.0 104.0 107.0 100.0 0.1 0.1 0.0 0.0 0.0 0.0 0.0 < 0.01 14600.0 14091.0 13700.0 9059.0 9780.0 9195.0 6625.0 9899.0 1.1 1.1 0.5 0.6 0.6 1.6 1.3 1.0 23.3 23.3 17.0 18.0 16.0 17.0 21.0 18.0 18.0 17.0 10.1 12.1 9.0 9.7 13.0 9.7 1.0 1.0 < 0.1 < 0.1 <0.1 < 0.1 < 0.1 0.4 1.0 0.0 1.0 1.0 1.0 1.0 1.0 1.0 8.6 1.8 8.0 7.9 7.9 7.7 7.8 8.1 5 4 0 4 0 9 Sodium I Phosphorus Silicon I Strontium Zinc nded Solids 0 45 u mg /I 11700 0.9 23.3 15.3 0.1 92 14600 0.1 2.3 1.9 <0.1 32 10470 0.6 22 16.4 < 0.1 10330 1.1 21 15.9 < 0.1 10400 0.3 21 16.2 < 0.1 11280 0.6 21 16.8 < 0.1 109 11670 0.6 23 18 < 0.1 153 9560 0.3 20 15.6 < 0.1 80 9696 0.3 21 15.4 < 0.1 10400 01 19 13 < 0.1 509 0 0 1 0 13960 0.1 1 10.2 1 Sodium I Phosphorus Phosphorusl Silicon I Strontium Zinc nded Solids 0 45 u mg /I 9560 0.1 2.3 1.9 0.1 32 14600 1.1 23.3 18 0.1 153 5040 1 21 16.1 0 121 509 0 0 1 0 0 13960 0.1 1 10.2 1 0 13451 0.1 1 9.2 1 0 Sodium m /I os horns ml Silicon m /I Otrontium mgj Zinc m / Tota Dissolved Solids 13700 0.5 17 10.1 <0.1 9059 0.6 18 12.1 < 0.1 30096 9780 0.6 16 9 <0.1 9195 1.6 17 9.7 < 0.1 6625 1.3 21 13 < 0.1 9899 1 18 9.7 0.4 33700 9890 1.7 17 < 1 < 0.1 8044 1 18 9 < 0.1 9264 1.1 18 11.1 < 0.1 9599 0.4 18 11.9 < 0.1 6625 0.4 16 9 0.4 30096 13700 1.7 21 13 0.4 33700 9505.5 0.98 17.8 10.6222222 0.4 CPF -2 PW verage (mg /L) 1581.0 1880.0 1991.0 1929.0 1515.0 1991.0 1672.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 14700.0 13110.0 14590.0 13980.0 12050.0 14700.0 13897.0 59.0 53.0 49.0 47.0 34.0 69.0 49.6 7.2 12.0 6.7 5.9 16.0 9.6 < 0.1 < 0.1 < 0.1 < 0.1 0.0 0.0 0.0 15.5 16.6 16.1 14.7 14.7 19.6 16.4 42.0 34.0 22.0 28.0 22.0 43.0 33.9 99.9 109.0 111.0 105.0 91.0 135.0 105.8 < 0.2 < 0.2 < 0.2 < 0.2 0.2 0.2 0.2 < 0.5 < 0.5 5.5 < 0.5 0.3 5.5 2.4 62.5 63.0 91.0 81.0 56.0 96.0 72.6 < 0.5 1.0 2.0 2.0 1.0 2.0 1.8 101.0 78.0 103.0 102.0 78.0 107.0 98.9 70.001 0.0 0.0 0.0 0.0 0.0 0.0 9890.0 8044.0 9264.0 9599.0 6625.0 13700.0 9505.5 1.7 1.0 1.1 0.4 0.4 1.7 1.0 17.0 18.0 18.0 18.0 16.0 21.0 17.8 < 1 9.0 11.1 11.9 9.0 13.0 10.6 < 0.1 < 0.1 < 0.1 < 0.1 0.4 0.4 0.4 1.0 1.0 1.0 1.0 1.0 1.0 1.0 7.9 8.0 7.9 7.7 7.7 8.1 7.9 29 300.01 2 34400.01 33800.01 29300.0 35200.0 31380.0 0 0 SAMPLE NUM 6298863 6298864 AB71202 AB71201 AB71200 Date 10/3/2010 10/3/2010 7/4/2010 7/4/2010 7/4/2010 Time 22:33 22:27 4:00 4:00 4:00 Inlet Separator Flash Inlet Separator Previous 10 Samples Separator Water Drum Separator Water Bicarbonate 1230 1140 1225 1223 1136 Carbonate 0 95 0 0 109 Chloride 15050 14620 15260 14960 14400 Sulfate 250 250 172 172 180 Sulfide Aluminum <0.1 <0.1 < 0.1 < 0.1 < 0.1 Boron 28.6 3.4 28 28 28 Barium 4.3 <1.0 8 3 13 Calcium 148.9 21.5 138 138 147 Chromium <0.2 <0.2 < 0.2 < 0.2 < 0.2 Iron 1.3 1.1 0.9 1.3 2.6 Potassium 67.6 7.91 55 58 56 Lithium 3.2 <0.5 2 2 2 Magnesium 62.1 7.7 57 57 58 Manganese 0.027 0.009 0.033 0.029 0.037 Sodium 11700 14600 10470 10330 10400 Phosphorus 0.9 0.1 0.6 1.1 0.3 Silicon 23.3 2.3 22 21 21 Strontium 15.3 1.9 16.4 15.9 16.2 Zinc 0.1 <0.1 < 0.1 < 0.1 < 0.1 S ecific Gravity (60 °F) 1.0179 1.0201 1.0204 1.0206 1.0188 H 7.48 8.37 7.81 7.76 8.59 Conductivity micro - mhos /cm 40100 40100 40100 • • AB68013 AB68012 AB64673 AB64672 AB61378 4/4/2010 4/4/2010 1/512010 1/5/2010 2:50 2:30 3:00 2:50 15:00 Colville River Field PW CPF -2 PW Separator Inlet Separator Inlet Flash Minimum Maximum Difference Average Water Separator Water Separator Drum (mg /L) (mg/L) (mg /L) (mg /L) 1108 1253 1178 1280 1403 1108 1403 295 1672 97 0 185 0 01 0.0 185.0 185.0 0.001 14790 15180 15500 15600 15310 14400 15600 1200 13897 205 228 280 290 219 172 290 118 49.6 9.56 0.1.< 0.1 <0.1 <0.1 <0.1 0.0 0.1 0.1 0.001 28.3 30.4 27.1 28.4 27 3.4 30.4 27.0 16.35 11 2 5 4 671 2.0 67.0 65.0 33.9 185 192 121 132 133 21.5 192 170.5 105.79 70.2 < 0.2 < 0.2 < 0.2 < 0.2 0 0 0.0 0.2 2.4 2.5 0.6 1.8 0.9 0.6 2.6 2.0 2.4 104 143 54 65 68 7.9 143 135.1 72.55 2 2 2 2 2 2.0 3.2 1.2 1.8 82 83 52 57 581 7.7 83 75.3 98.9 0.051 0.051 0.032 0.036 0.03 0.009 0.051 0.042 0.02 11280 11670 9560 9696 10400 9560 14600 5040 9505.5 0.6 0.6 0.3 0.3 0.2 0.1 1.1 1.0 0.98 21 23 20 21 19 2.3 23.3 21 17.8 16.8 18 15.6 15.4 13 1.9 18 16.1 10.62 <0.1 <0.1 <0.1 <0.1 <0.1 0.1 0.1 0.0 0.4 1.0201 1.0208 1.0201 1.0198 1.0207 1.0179 1.0208 0.0029 1.01898 8.43 7.63 8.59 7.58 7.6 7.48 8.59 1.11 7.884 34900 35700 282001 298 01 28200 40100 11900 31380 Roby, David S (DOA) From: Davies, Stephen F (DOA) Sent: Friday, November 05, 2010 11:00 AM To: Roby, David S (DOA); Maunder, Thomas E (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA) Subject: RE: Colville River Field & Kuparuk River Field Water Comparison I'm not an very familiar with scale formation, but the sulfate content differs (PW = 172 -290 vs seawater = 279- 3580), carbonate content differs (PW avg. = 0 -185 vs seawater = — 0- 0.001), and bicarbonate differs (PW =1108 -1403 vs seawater = 100 -140), as does the pH (pw = 7.5 — 8.6 vs seawater = 6.75 -7.0). However, the amount of water proposed to be injected is insignificant compared with the volume of fluid injected into the Alpine Pool alone on a regular basis (3,163,281 bbls in Sept 2010), so I think that any formation damage would be minimal. From: Roby, David S (DOA) Sent: Friday, November 05, 2010 10:32 AM To: Maunder, Thomas E (DOA); Davies, Stephen F (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA) Subject: FW: Colville River Field & Kuparuk River Field Water Comparison Guys, attached as a comparison of CRU and CPF -2 produced waters as well as seawater. After a quick glance they look pretty similar to me. What do you guys think? Dave Roby (907)793 -1232 From: Walker, Jack A [mailto: Jack .A.Walker @conocophillips.com] Sent: Friday, November 05, 2010 10:20 AM To: Roby, David S (DOA) Subject: Colville River Field & Kuparuk River Field Water Comparison Dave, Enclosed is the comparison we discussed on the phone. The two charts show the range of dissolved solids for Colville produced water and seawater plotted with the average value for Kuparuk CPF -2 produced water which is basis for our belief that the CPF -2 water is compatible with the Colville River Field formations. I'll follow up with more background regarding the request for authorization to inject Kuparuk River Field produced water into the Colville River Field Oil Pools. Jack 1 Roby, David S (D ®A) From: Roby, David S (DOA) Sent: Friday, November 05, 2010 11:04 AM To: Davies, Stephen F (DOA); Maunder, Thomas E (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA) Subject: RE: Colville River Field & Kuparuk River Field Water Comparison They are aware of the possibility for scale creation when seawater and produced water mix and were planning on adding scale inhibitors. Dave Roby (907)793 -1232 From: Davies, Stephen F (DOA) Sent: Friday, November 05, 2010 11:00 AM To: Roby, David S (DOA); Maunder, Thomas E (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA) Subject: RE: Colville River Field & Kuparuk River Field Water Comparison I'm not an very familiar with scale formation, but the sulfate content differs (PW =172 -290 vs seawater = 279 - 3580), carbonate content differs (PW avg. = 0 -185 vs seawater = - 0- 0.001), and bicarbonate differs (PW =1108 -1403 vs seawater = 100 -140), as does the pH (pw = 7.5 - 8.6 vs seawater = 6.75 -7.0). However, the amount of water proposed to be injected is insignificant compared with the volume of fluid injected into the Alpine Pool alone on a regular basis (3,163,281 bbls in Sept 2010), so I think that any formation damage would be minimal. From: Roby, David S (DOA) Sent: Friday, November 05, 2010 10:32 AM To: Maunder, Thomas E (DOA); Davies, Stephen F (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA) Subject: FW: Colville River Field & Kuparuk River Field Water Comparison Guys, attached as a comparison of CRU and CPF -2 produced waters as well as seawater. After a quick glance they look pretty similar to me. What do you guys think? Dave Roby (907)793 -1232 From: Walker, Jack A [mailto: Jack .A.Walker @conocophillips.com] Sent: Friday, November 05, 2010 10:20 AM To: Roby, David S (DOA) Subject: Colville River Field & Kuparuk River Field Water Comparison Dave, Enclosed is the comparison we discussed on the phone. The two charts show the range of dissolved solids for Colville produced water and seawater plotted with the average value for Kuparuk CPF -2 produced water which is basis for our belief that the CPF -2 water is compatible with the Colville River Field formations. I'll follow up with more background regarding the request for authorization to inject Kuparuk River Field produced water into the Colville River Field Oil Pools. Jack Roby, David S (DOA) From: Walker, Jack A [ Jack .A.Walker @conocophillips.com] Sent: Friday, November 05, 2010 12:28 PM To: Roby, David S (DOA) Subject: CRU Seawater P/L Follow Up Dave, To follow up the compositional analyses data for seawater, Colville River Field produced water, and Kuparuk produced water that I sent to you earlier for your consideration, this email describes our situation and reasons for requesting authorization to inject produced water from the Kuparuk River Field in the Alpine, Fiord, Nanuq and Qannik Oil Pools. Seawater from the Kuparuk River Unit Seawater Treatment Plant is normally supplied to the Colville River Field for enhanced oil recovery via a pipeline approximately 34.6 miles long. There was an unplanned shutdown of the seawater pipeline, and freeze protection was subsequently implemented by pumping warm Kuparuk River Field produced water into the pipeline to displace the cold seawater. This freeze protection will be good for a period, and within this period we expect resumption of normal seawater operations. When normal seawater operations are possible, the seawater will displace the Kuparuk produced water used for freeze protection toward the Alpine Central Facility. Two operational options exist for routing the freeze protection fluid at the Alpine Central Facility: (1) inject it into properly permitted Class I disposal wells, or (2) if AOGCC authorizes, inject it into WAG service wells in the Alpine, Fiord, Nanuq, and Qannik Oil Pools. Option (1) is feasible, but this operation will require significantly more time than Option (2) due to the disposal well system capacity. Option (1) has a minor risk of freezing the seawater pipeline due to the time required for the seawater to displace the freeze protect fluid. Option (2) is recommended because the Kuparuk produced water (freeze protect fluid) is compatible with the Colville River Field formations, because the freeze protect fluid can be beneficially used for enhance oil recovery, and because this displacement operation will require about one tenth of the time required for Option (1) resulting in less risk of freezing the seawater pipeline during the displacement of the freeze protect fluid. We expect normal seawater to be available as early as 6 p.m. tonight. Thank you for the time you have put into this. Jack Walker North Slope Development ConocoPhillips Alaska, Inc. 907 -265 -6268 office 907- 250 -1749 cell i #$ • 0 ConocoPhillips Aaska P.O. BOX 100360 CE ANCHORAGE, ALASKA 99510 -0360 E n r. r 7 g 2010 October 15, 2010 ftsk1100&Qas Cop$. Comr ��Sl�ll Mr. Dan Seamount Alaska Oil & Gas Commission 333 West 7' Avenue, Suite 100 Anchorage, AK 99501 Dear Mr. Seamount: ConocoPhillips Alaska Inc. resents the attached proposal per AID 18 Rule 9 to apply p P p p p � pp Y for Administrative Approval allowing well CD4 -209 (PTD 206 -065) to be online in water only injection service with IAxOA communication. If you need additional information, please contact myself or Brent Rogers at 659 -7224, or MJ Loveland / Perry Klein at 659 -7043. Sincerely, Martin Walters Problem Wells Supervisor ConocoPhillips Alaska Inc. Cc: Working Well File, Legal Well File • • ConocoPhillips Alaska, Inc. Colville River Unit CD4 -209 (PTD# 206 -065) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this Administrative Relief request as per Area Injection Order 18, Rule 9, to continue injection with known annular communication for Alpine injection well CD4 -209. I Well History and Status Colville River Unit well CD4 -209 (PTD 206 -065) was drilled and completed in 2006 as a service well. CD4 -209 was reported to the Commission on November 11, 2009 as showing signs of IAxOA communication. The following pertinent operations have been completed to date: Date gyration Result Comment 8/24/10 MITOA Passed 8/16/10 Cement NA Pumped OA cement shoe 4/13/10 LDL NA Identified production casing leak at 36' 11/28/09 MITIA Passed 11/15/09 IC POTS Passed 10/19/09 MITIA Inconclusive Witnessed by Bob Noble (passed AOGCC criteria) 9/28/09 T &IC POTs Passed 7/14/09 MITIA Passed Repair of the production casing leak would require a rig workover and cannot be justified at this time but will be considered should a workover be necessary in the future. ConocoPhillips requests Administrative Approval which will allow the OA to equalize with the IA in water only injection service at a pressure not to exceed 1000 psi. NSK Problem Well Supervisor 10/16/2010 1 • • Barrier and Hazard Evaluation Tubing: The 4 -1/2 ", 12.6 ppf, L -80 tubing has integrity to the packer @ 6446' MD, based on the passing MITIA as outlined above. Production casing: The 7 ", 26 ppf, L -80 production casing has an internal yield pressure rating of 7240 psi and but does not have integrity to the packer @ 6446' MD (6025' TVD) based upon the leak detect log results and pressure trend that illustrate IAxOA equalization in a relatively short period of time.. Surface casing: The 9 -5/8 ", 40 ppf, L -80 surface casing with an internal yield pressure rating of 5750 psi set at 2394' MD (2381' TVD) has integrity based upon the passing MITOA outlined above. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the production tubing. Second barrier: The secondary barrier to prevent a release from the well and provide zonal isolation is the surface casing should the production tubing fail. Monitoring Each well is monitored daily for wellhead pressure changes. Should leaks develop in the tubing or surface casing above the conductor shoe it will be noted during the daily monitoring process. Any deviations from approved MAOP annular pressures require investigation and corrective action, up to and including a shut -in of the well. T /I /O plots are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. SVS: Due to the surface casing yield pressure rating of 5750 psi and the maximum anticipated injection pressure of 2600 psi, ConocoPhillips does not intend to install automatic shut -in equipment on the well's outer annulus. Proposed Operating and Monitoring Plan 1. Well will be used for water injection only (no gas or MI allowed), OA pressure may equalize with IA pressure not to exceed 1000 psi; 2. Perform a passing MITIA or MITT with tubing plug below uppermost packer every 2 -years as per AOGCC criteria (0.25 x TVD @ packer, 1500 psi minimum). 3. Perform a passing MITOA or IAxOA CMIT to 1800 psi every 2 years; 4. IA pressure not to exceed 2000 psi & OA pressure not to exceed 1000 psi. 5. Submit monthly reports of daily tubing & IA pressures and injection volumes; 6. Shut -in the well should MIT's or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. NSK Problem Well Supervisor 10/16/2010 2 WNS CD4 -209 a pcmPh ips Well Attributes Max Angle & MD Iu BSka. Inc. Wellbore APl /UWI Field Well Status Incl ( °) MD(ftKB) (ftKB) 501032053200 NAN INJ 94.28 7,79136 ,215.0 r' Comment H2S (ppm) Date Annotation End Date KB A (ft) Rig Release Date "' SSSV: WRDP Last WO: 44.13 6/11/2006 Well Cony : Horizon al - coo gas alsnolo 4:zz: e Schematic - Actual Annotation Depth (ftKB) End Date Annotation Last Mod... End Date Last Tag: Rev Reason: RESET INJ VLV Imosbo' 4116/2010 HANGER, zs =- - - - -� Casina Strin s - -- Casing Description String 0... String ID ... Top (ftK8) Set Depth if Set Depth (TVD) ... String Wt... String ... String Top Thrd - - - - - - - - CONDUCTOR 16 15.250 41.5 118.8 118.8 65.00 H -40 Welded Casing Description String 0... String ID... Top (ftKB) Set Depth (f... Set Depth (TVD) ... String Wt.. String ... String Top Third - - - - - - - - - - - - - - - - C SURFACE 9518 8.835 41.4 2,393.8 2,380.9 40.00 L -80 BTC asing Description String 0... String ID ... Top (ftKB) Set Depth if Set Depth (TVD)... String WL.. String... String Top Third INTERMEDIATE 7 6.276 37.4 6,994.4 6,201.3 26.00 L -80 BTCM Casing Description String 0... String ID ... Top (ftK8) Set Depth If Set Depth (TVD) ... String Wt... String ... String Top Third CONDUCTOR, LINER Slotted 41/2 3.958 6,839.8 13,205.0 6,195.8 12.60 L -80 SLHT 41 -119 Liner Details Top Depth ITVD) Top Ind Nomi... Top (ftK8) (ftKB) (°) Item Description Comment ID (In) VALVE 2001 6,839.8 6,172.4 76.48 SLEEVE BAKER'HR' LINER SETTING SLEEVE 4.420 NIPPLE,2,001 6,852.8 6,175.2 77.03 NIPPLE BAKER "RS Packoff Seal Nipple 4.250 6,856.6 6,176.2 77.19 HANGER BAKER "DG" Flex Lock Hanger 4.400 - 6,866.5 6,178.6 77.60 XO CROSSOVER 5x4.5" 3.910 13,162.61 6,198.21 93.26 BUSHING BAKER Packoff Bushing 2.380 Tubing Strings Tubing Description String 0... String ... Top (ftK8) Set pth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd SURFACE, TUBING 41/2 3.958 ID 28.9 6,847.0 De 6,173.8 12.60 L - 80 IBTM 47 -2,394 Completion Details Top Depth (TVD) Top Incl Nom.... Top (ftKB) (ftKB) V) Item Description Comment ID (in) GAS LIFT, 28.9 28.9 -0.04 HANGER FMC Tubing Hanger w/ 2.28' pup 3.958 8,339 f 2,001.0 1,996.1 10.96 NIPPLE Camco DB nipple 3.812 6,445.9 6,025.2 59.53 PACKER BAKER PREMIER PACKER 3.875 6,503.4 6,053.7 61.28 NIPPLE HESXNNipple 3.725 PACKER, 8,448 6,827.2 6,169.6 75.95 WLEG Baker fluted WLEG w/ LOCATOR SUB 3.958 Tubing pup, Other In Hole Wireline retrievable pluqs, valves, pumps, fish, etc. 6,454 Top Depth (TVD) Top Inc, Top (ftKB) (RKB) 1 "1 Description Comment Run Date ID (In) NIPPLE, 6,503 2,001 1,996.1 10.96 VALVE A -1 INJECTION VALVE (HRS -45) w/1.25" ORIFICE 4/15/2010 1.250 Perforations & Slots WLEG, 6,827 Shot Top (TVD) a TVD) Dens Top (ftKB) Btm (ftKB) (ftKB) (ftKB) Zone Date (sh••• Type Comment 6,991 13,163 6,200.6 6,198.2 NANLB3, 6/9/2006 32.0 SLOTS Alternating slotted/blank pipe Ij NANLB2, NANLB3, CD4 -209 Notes: General & Safety End Date I Annotation 7/6/2006 NOTE: TREE: FMC 4 -1/16" 5,000 PSI - TREE CAP CONNECTION: 7" OTIS 6/712008 NOTE: SHUT -IN INJECTOR 9/3/2008 NOTE: VIEW SCHEMATIC w /Alaska Schematic9.0 NTERMEDIATE, • I ' 37 -6,1MM f f j SLOTS, f 6,991 - 13,163 • i l l Mandrel Details Top Depth Port (TVD) Ind OD Valve Latch Size TRO Run 1 ` Stn Top (ftKB) (ftKB) (*) M Model (in) Ser , Type Type (in) (psi) Run Date Co.] I 5,966.9 56.26 CAMCO KBG -2 1 1 JINJI OMY BK 10.0001 0.0 7/17/2009 LINER Slotted, 8,840.13,205 TD, 13,215 Well Name CD4 -209 Notes: Administrative Approval Application Start Date 5/112010 Days 180 End Date 10/28/2010 Annular Communication Surveillance 3000 W H P 160 IAP OAP WHT 140 2500 120 2000 - 100 LL .Q 1500 80 'a 60 1000 40 500 20 0 0 May -10 Jun -10 Jul -10 Aug -10 Sep -10 Oct -10 7000 �DGI 6000 �MGI 0 5000 �PWI m a000 SWI ° 6000 BLPD U f 2000 1000 0 May -10 Jun -10 Jul -10 Aug -10 Sep -10 Oct -10 Date ~7 ~ • FtEGEIVED MAY 2 6 10uJ ConocoPhillips May 21, 2009 Commissioner Dan Seamount, Chairman Alaska Oil & Gas Conservation Commission 333 West 7t" Avenue, Suite 100 Anchorage, AK 99501 Alaska Oii & Gas Cons. Commission Anchorage Chris Wilson Supervisor, WNS Base North Slope Operations and Development, ATO 1762 700 G. ST. ANCHORAGE, ALASKA 99501 Telephone 907- 265-6573 E-mail Christopher.j.wilson@conocophillips.com Subject: Area Injection Orders for Fiord and Nanuq Oil Pools Administrative Amendment Colville River Field North Slope, Alaska Dear Commissioner Seamount, ConocoPhillips Alaska, Inc., as the Operator on behalf of the working interest owners of the Colville River Unit ("CPAI"), respectfu!!y requests that the Alaska Oil & Gas Conservation Commission ("Commission") approve administrative amendments to Area Injection Order (AIO) Nos. 28 and 30 to authorize gas injection into the Nanuq Oil Pool and Fiord Oil Pool without a miscibility requirement and to authorize injection of additional fluid types into the Nanuq and Fiord Oil Pools. The bases for these requests are provided below. 1. Authorization for Gas Injection Without a Miscibility Requirement. AIO Nos. 28 and 30 authorize, for the Nanuq and Fiord Oil Pools, respectively, injection of miscible gas obtained from the Alpine Central Facility with the condition that reservoir pressure must be maintained at a level high enough to ensure the miscibility of the injectant. While significant volumes of miscible gas have already been injected into the Alpine (including the CD4 NanUq-Kuparuk zone) Oil Pool and Fiord Oil Pool, CPAI expects recovery from the Colville River Field will be greater if the miscibility requirement is removed because the gas volumes available could then be used more efficiently in the field to recover oil. Maintaining the pressure of the Fiord and Nanuq Oil Pools with water- alternating-gas (WAG) injection is planned, but maintaining a miscible gas composition limits the voiume of WAG gas available for enhanced recovery operations in these pools. Gas from the Colville River Field that is not used as fuel in the field or sold or transferred to others is conserved by re-injecting it as either lean gas or miscible injectant. Enriching May 21, 2009 • ~ p• 2 Subject: Area Injection Orders for Fiord and Nanuq Oil Pools Administrative Amendment components (i.e., ethane and higher weight gaseous hydrocarbons) are blended with lean gas to create miscible injectant. The limited volume of enriching components restricts the volume of miscible injectant that can be generated. Because there is a limited volume of miscible injectant and all gas in excess of fuel and sales must be reinjected, the miscibility requirement for Fiord and Nanuq Oil Pools results in greater lean gas injection in the Alpine Oil Pool than may be desired. This increased lean gas injection may potentially adversely impact recovery given the associated increase in gas cycling coupled with the Alpine Central Facility gas handling constraints. Pattern model simulation of the Alpine, CD4 Kuparuk, Fiord and Nanuq reservoirs indicate that recoveries are similar for a WAG process involving the use of (1) a miscible gas or (2) an enriched gas that does not meet a standard definition of miscibility~, provided the same amount of enriching fluid is injected in both scenarios. This is illustrated in the attached Figures 1, 2, 3 and 4, which show recoveries as a function of total (water plus gas) injection-volumes for an MWAG process and an enriched gas WAG process. The simulations were performed using 5% HCPV (hydrocarbon pore volume) slug sizes and a WAG ratio of 1.0. Cumulative gas injection totaled 30% HCPV and 34.4% HCPV for the MWAG and enriched gas WAG cases, respectively. These volumes resulted in all cases that provided for injection of the same amount of enriching fluid for both scenarios. CPAI proposes that the Alpine Central Facility continue to generate enriched and lean gas streams. Lean gas would be injected in specific service wells to provide a source of fuel for "black start" capability, and in some very mature areas as one of the latter steps in the recovery process. The enriched gas stream would be used as a WAG gas in enhanced recovery operations. Removing the miscibility requirement from the Fiord and Nanuq Oil Pools would increase the amount of WAG gas (and its associated enriching fluids) available for use across the Colville River Field. This proposed revision would maximize resource recovery by reducing lean gas injection (and associated gas cycling) in the Alpine Oil Pool and increase tertiary recovery in the Fiord and Nanuq Oil Pools by increasing the gas volume available for injection. The proposed revision would not create waste, jeopardize correlative rights, nor contribute to potential fluid movement outside approved injection zones. 2. Authorization for Injection of Additional Fluid Types. In addition to the changes in gas injection requirements for the Fiord and Nanuq Oil Pools, CPAI requests adminis~rative amendment of AIO No. 28 to authorize injection of commingled produced water in the Nanuq Oil Pool. CPAI also requests administrative amendment to AIO Nos. 28 and 30 to authorize injection of sump fluid, hydrotest fluid, rinsate generated from washing mud hauling trucks, and excess well work fluids, and treated camp effluent in the Nanuq and Fiord Oil Pools, respectively. Commingled produced water from the Colville River Field is slightly higher salinity than and has a composition sufficiently similar to the produced water from the Nanuq Oil Pool to conclude that the Colville River Field commingled produced water is compatible with the Nanuq Oil Pool injection zone. The attached Table 1 shows the produced water compositions. ' Stalkup, F. I., Miscible Displacement, Society of Petroleum Engineers, 1983; p. 27 May 21, 2009 ~ ~ p~ 3 Subject: Area Injection Orders for Fiord and Nanuq Oil Pools Administrative Amendment The Commission approved injection of small volumes of sump fluid, hydrotest fluid, rinsate generated from washing mud hauling trucks, and excess well work fluids, and treated camp effluent into the Alpine Oil Pool. Injecting small volumes of these fluids will have no detrimental impact on enhanced oil recovery from the Nanuq and Fiord Oil Pools. To implement both authorizations requested above, CPAI requests Rule 4 of Area Injection Order Nos. 28 and 30 be administratively amended to read as follows: Fluids authorized for injection are: a, commingled produced water from the Colville River Fieid; b, source water from a sea water treatment plant; c. gas; d, sump fluid, hydrotest fluid, rinsate generated from washing mud hauling trucks, and excess well work fluids, and treated camp effluent. Please do not hesitate to contact me at (907) 265-6822, or Jack Walker at 265-6268 should you have any questions about this request. Sincerely, ~s" ~~ ~ .~- ~ Chri Wilson Supervisor Western North Slope Base ConocoPhillips Alaska,lnc. Cc: Kevin Banks, Alaska Department of Natural Resources, Division of Oil and Gas Tim Flemming, Anadarko __ Teresa Imm, Arctic Slope Regional Corporation May 21, 2009 • • Subject: Area Injection Orders for Fiord and Nanuq Oil Pools Administrative Amendment Figure 1 Alpine WAG Recovery Pattern Model Results o eoo . a 0.7W p 0.600 c ° 0.500 m - - . . ~ 0.400 - Z ~ 0.300 _. .. 0 ~ 0200 ~ - - 30 % HCPV MI ~ 0.100 ~~ - 3q.4 % hICPJ Enriched Gas 00 0. 0 0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 Total InJection HCPV (fraction) Figure 31 CD4-Kuparuk WAG Recovery Pattern Model Results o.a a 0.7 p 0.6 - ° 0.5 u .., OA Z ~ 0.3 u ~ 0.2 .. . -30% HCPJ MI ~ 0.1 -34.4% HCW EnrichedGas 0 0.0 02 0.4 0.6 0.8 1.0 12 1.4 Total Injection HCPV (fraction) Figure 2 p. 4 Fiord WAG Recovery Pattern Model Results o.e a 0.7 p 0.6 -~° 0.5 ,` 0.4 Z ~' 0.3 ._ 0 ~ 02 - - - 30 % FICW MI ~ ~•~ -34.4% FICP/EnrlchedGas 0 0.0 02 0.4 0.6 0.8 1.0 12 1.4 Total InjecHon HCPV (fraetion) Figure 4 Nanuq WAG Recovery Pattern Model Results 8 0. a 0.7 - p 0.6 - ° 0 5 - r . ~ 0.4 ~ ~ 0.3 u ~ 0.2 - ~ -30% FICW MI ~ ~'~ -34.4% EnrichedGas 0 0.0 0.2 0.4 0.6 0.8 1.0 12 1.4 Total InJedion HCPV (fraction) May 21, 2009 ~ ~ p. 5 ,. Subject: Area Injection Orders for Fiord and Nanuq Oil Pools Administrative Amendment . ~ ! ~-'' . . ConocoPhillips January 3, 2008 Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West 7~' Avenue, Suite 100 Anchorage, AK 99501 Re: Produced Water Injection in the Fiord Oil Pool Colville River Field Dear Chairman Norman: • Jack Walker ConocoPhiAips Alaska 700 G Street Anchorage, AK 895D1 Phone: 907.265,6268 ~~~.~~~~~~~ 1.~N ~ ~ Z~~~ ~ils~ka i~R! ,z,, ~~~ ~ori~~ k;~t~'I±rti~si~n A~iehbr~~~ . ConocoPhillips Alaska, Inc. (CPAI) as operator of the Colville River Unit requests the Commission to administratively amend Area Injection Order No. 30 to authorize injection of commingled produced water from the Colville River Field into the Fiord Oil Pool. Testing of core samples from the Fiord #5 well demanstrates that water produced from the Colville River Field is compatible with the formation. Brine composition had no effect on permeability measured in core taken from the Fiord #5 well in the Fiord Oil Pool. There was no difference in the permeability to the brines with produced water and the seawater compositions. The core testing report is attached. I would be happy to answer any questions regarding this request. Very truly yours, ~ ~~~ ~~~.~ Jack Walker Staff Production Engineer North Slope Operations and Development ConocoPhillips Alaska, Inc. Attaclunent ~ ~ i i ~fJl"1~3C~P~'1 I ~ ~ 1 ~?S Interoffice Correspondence Bartlesville, OK 74004 Jack A. Walker E&P - Alaska (2) January 2, 2008 ~ Coleville River Field, Alaska Water Injection Compatibili#v Hed-03-2Q07 We have completed a water injection study on core samples from the Coleville River Field, Western North Siope, Alaska. We studied the injection of synthetic Alpine produced brine and synthetic Beaufort Sea water in core samples taken from the Fiord #5 {Piord Reservoir), Nanuk #2 (Nanuq Reservoir) and Nanuq #3 (Nanuq-Kuparuk Reservoir) cored wells. Table I lists the routine properties for these core plugs. Brine permeability results are given in Table II. Stable permeabilities to Alpine produced brine and Beaufort Sea water were obtained (seventy-five pore volumes of each brine were injected). Measured brine permeabilities were lower than the measured routine gas permeabilities as expected. As clay content increases in low permeability samples (see samples 17b and 17c), the water permeability is relatively much lower than the measured gas permeability (permeability to oil at connate water vvould also be much lower than the measured gas permeability). Both briues produced equivalent permeabilities which showed that either brine could be injected without injectivity issues. The testing protocol consisted of the following: + Plug samples drilled fronn whole core pieces using brine as a cutting fluid. • Sample cleaning was conducted using a submerged Soxhlet cleaner with chloroform-methanol azeotrope solvent. • The cleaned samples were dried at 60°C in a vacuum oven. • Routine properties were measured using standard techniques (see Table ~. • T'he plugs were vacuum and pressure saturated with Alpine formation brine. ~ Permeab~lity to Alpine formation brine followed by Beaufort Sea water was measured at reservoir temperature. Seventy-five pore volumes of each brine were injected to insure equilibrium and stability to flow. • The Beaufort Sea water contained 15ppm of scale inhibitor (SCW 3~01 WC by Baker Petrolite). If we can be of further service, please feel free to contact us. J. H. Hedges 130 GB, Bartlesville Technical Center Bartlesville, OK 74004 (Phone 918-661-9515) (Fax 918-662-5257) (Email ~im.h.hedges[)conocophillips.com) JHI3:dw Attachtnents ~ ~ ~ Coleville River Field, Alaska,Water Injection Compatibility Hed-p3-2007 Page 2 Table 1. fioutine Core Analysis Sample Well Depth Reservoir Parosi#y Grain N2 Perm No, Name Feet °!o Densi# rnc! LE-1 Fiord # 5 7054.4 Fiard 16.6 2.66 14.4 LE-8 Fiord # 5 7045.1 Fiord 17.~ 2.69 2.70 17b Nanuk # 2' 7096.55 Nanu 15.5 2.69 2.00 22c Nanuk # 2 7096.75 Nanu 16.3 2,68 4.66 18c Nanuk # 2 7096.65 Nanua 15.5 2.69 2.07 IKG-3 2.75 Table 11. Br~ine PermeabiNity Sampte Reservoir N2 Perrn Form Brine Beaufart Sea Reservoir Na md Perm md Perm md Temp °F LE-1 Fiord 14.4 6.35 6.29 165 LE-8 Fiord 2.~0 1.08 1.02 165 17b Nanu 2.00 0.04 0.04 135 22c Nanuq 4.66 1.50 1.50 135 18c Nanu 2.07 0.05 0.05 135 KG-3 Nanu -Kuparuk 28.1 14.0 11.'! 165 KG-4 Nanuq-Kuparuk 180 56.3 50.9 165 ~ ~ Coleville River Field, Alaska,Water Injection Compatibility Hed-03-~007 Page 3 Table Ul. Synthetic Alpine Pr~-duced Water Alpine Average Produced Water FURMATION BRINE RECIPE USING 1VIATERIAL WEIGHTS GRAMSIC{?MPONENT NA CL 20.28~ NA CL 162.25~ K C~ d303 K CL 2.427 CA CL2 2H2fl 0.466 CA CL2 2H2{~ 3.Z27 MG CL2 6H2O fl.812 MG CL2 6H2O 6.492 BA CL2' 2H2O 0.005 BA CL2 2H2O O.Q43 5R CL2 6H2~ 0.0z7 SR CL2 6H2~ 0.219 NH4 CL 0.400 NH4 CL 0.0~0 FE S04 7H2Q 0.000 FE S04 7H2O 0.000 NA HC03 1.020 NA HC03 8.1b3 NA BR 0,000 NA BR 0.0~{l fUA2 S04 0.642 NA2 S04 5.136 NA3 P~4 12H2O fl.000 NA3 PQ4 12H2O 0.000 NA I fl.fl00 NA I ~A00 H20 976.442 H20 7811.538 GMS SOLLTTION 1000A GM~ SQLUTION 8fl00.0 TDS (PP1Vn 22989 CALC CLs {FPM) i2958 INPUT VALUES INPUT'VALUES CATION (PPM) ANIOP+T (PP1V~ NA 8461 HC03 741 K 159 S04 with Na 434 CA 127 S04 with Fe 0 MG 97 BR 0 BA 3 Pfl4 0 SR 9 t 0 NH4 0 FE 0 SUMMATION 8856 SUMMATI(}N 1175 ~ ~ Coleville River Fie1d, Alaska,Watsr'Injection Compatibility Hed-03=2007 Page 4 Table IV. Synthetic Beaufort Sea Water Seaufort Sea Water FORMATION BRINE RECIPE USLNG MATERIAL WEIGHTS GRAMS/COMPONENT NA CL 24.533 NA CL I96.26b K CL 0.845 K C~ 6.762 CA CL2 2H2O I S92 CA CL2 2H2~ 1.~.736 MG CL2 6H2O 11.219 MG CL2 6H2O 89.753 BA CL2 2H2O 0.005 BA CL2 2H2O OA43 SR CL2 6H2O 0.030 SR CL2 6H2O 0.243 NH4 CL O.Oaa NH4 CL O.OOQ FE S04 7H2O 0.000 FE S04 7H2O 0.004 NA HC03 0.24~ NA HC03 1.439 NA BR 0.000 NA BR O.OOU NA2 S04 4.046 NA2 S04 32.3b4 NA3 P0412H2O 0.000 NA3 P04 12H2O 0.000 NA 1 0.000 NA 1 O.OOU H20 957.~487 H20 7b59.893 GMS SOLUTION 1000,0 GMS SOLUTION 8000,0 TDS (PPM) 3612$ ~CALC CLs {PPM) 19965 INPUT VALUES INPUT VALIIES CATION (PPM) ANIUN (PPM) NA 11~21 HC03 176 K 443 S04 with Na 2735 CA 434 Sfl4 with Fe p MG 1341 BR Q' BA 3 P04 0 SR 10 I 0 NH4 0 FE 0 SUMMATION 13252 SUMMATION 2911 ~Te - ~° ~°q° °^o 9 'aw~ - , w~'c jo- = °> ~3PaL ~ ( = I ip ~ m E°w b; I~EB' ~ =` gyE~E: Oa - s uV e„ ~ ze Re "€oN`-`, , y ~ m I$e: ~~`:~a ~;5 ~- ~~ ~' En" ~g m ^ ~~ ~d~` ~ _°wm ~ i" ` ~" ~~ , F A~LL"3E ia2 @ :s~`_S 5 ^` ° - s' 4 $~ eae b~aa~e~£° as~: ~o S~ E F 5 m "c• g~ E~ n€ S a°u w E ~, 2~ V`- ~ fC Y -° c I`€ o= n~ E~ S~e ¢~ .°e'E'c9ii'~~° ma`~ 5 ~=s~ `^y`oQY ~ ~ g" f i~ -'~ SE r~ 'n ~; ~~e-`~ o ~ $.~~ °a~~` :88~A .'eal ~ . 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'_s~ . S ~ ..v~ . ~ . __ ~ e»., ~ s I I ( $ • . u i . ~ ~ ~ _ a ~ ___a_...__.._.: ~ a -----...__..a.._..___. ~ a ........~._.__ __; ( i ~ A ~ ~ _._......._.~....-- i i c z° ---.._........ o ' ° { ~'~ g _ . .- g . .~ ( g I i n , 8 « 8 R 8 #6 Alpine Prod Wtr Compatibility Report . . Re: Request for Administrative Approval for AIO 27, 28, and 30 Jim, We performed and enclosed a compatibility analysis for the Nanuq, Nanuq-Kuparuk and Fiord Oil Pools, similar to the compatibility analysis for AIO 18.8.002. Please call with any questions. Thanks Jack 265-6268 «Alpine Satellite Compatibility Study.xls» «Alpine Produced and Sea Water Analysis.dot» Alpine Satellite Compatibility Study.xls Content-Type: Content-Encoding: C t D . t· Alpine Satellite Compatibility onten - escnp Ion: St d 1 u y.x s application!vnd.ms-excel base64 Alpine Produced and Sea Water Analysis.dot Content-Type: Content-Encoding: .. Alpine Produced and Sea Content-DescnptlOn: W t An I . d t a er a YSIS. 0 application! octet -stream base64 1 of 1 3/30/2007 10:06 AM PW/Satellite 1 2 3 4 100 00 00 100 100 PW '" Produced Water from LP SW= Sea Water Fiord Oil = CD3-109 Oil '" CD4-211 Oil = CD4-318 T. Vuk 3/29101 · . Kuparuk Laboratory Report of Analysis t'? 3);b\ 01 \,",,~f Report Date: 3/29/07 To: J. Walker Alpine Lead Operator Sample Description STP Seawater Plant Discharge Alpine LP Separator Water WellNum 0 0 Date 02/14/07 03/01/07 Time 13:30 00:25 LocDescriptor Analvsis Unit Result Result Chloride mg/l 20190 11940 Sulfate mg/l 2810 480 Aluminum mg/l <0.1 0.8 Barium mg/l <1 3 Boron mg/l 5 12.9 Calcium mg/l 410 126 Chromium mg/l <0.2 <0.2 Iron mg/l <0.1 0.5 Lithium mg/L <0.5 1 Magnesium mg/l 1207 119 Manganese mg/l 0.006 0.022 Phosphorus mg/l <0.1 0.4 Potassium mg/l 291 120 Silicon mg/l <1 12 Sodium mg/l 10130 7869 Strontium mg/l 10 8.4 Zinc mg/l <0.1 < 0.1 Bicarbonate mg/l 310 915 Carbonate mg/l 0 42 Conductivity micro-mhos/cm 39700 28000 Line Pressure PSIG --- 110 Line TemperatureF Degrees F --- ISO Oil In Water ppm --- 31 pH --- 7.33 8.41 Specific Gravity @ 60 degrees --- 1.0283 1.0157 F Sulfide mg/l Not Analyzed Not Analyzed Total Suspended Solids 0.45 u mg/l --- 20.0 Ifthere are any questions regarding this data, please call KLS at 659-7214. Completed By: Reviewed By:_ TJV_ #5 . . . , ConocóPhiUips Jack Walker North Slope Operations and Development ConocoPhillips Alaska 700 G Street Anchorage, AK 99501 Phone: 907.276.1215 RECEIVED MAR 2 8 Z007 Alaska Oil & Gas Cons. Commission Anchorage March 28, 2007 Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West th Avenue, Suite 100 Anchorage, AK 99501 Re: Administrative APproval for Fiord, Nanuq and Nanuq-Kuparuk Oil Pools Area Injection Orders 27, 28, and 30 Colville River Field Dear Chairman Norman: ConocoPhillips Alaska, Inc. as operator of the Colville River Unit requests administrative approval to freeze protect facilities and wells servicing the Fiord, Nanuq, and Nanuq- Kuparuk Oil Pools by injecting small amounts of produced water from the Alpine Oil Pool. This method of freeze protection is needed when the sea water injection system is shut down for maintenance. Planned sea water system maintenance is anticipated to require freeze protection on March 31,2007. Area Injection Orders 27, 28 and 30 for the Nanuq-Kuparuk, Nanuq, and Fiord Oil Pools respectively authorize the injection of seawater for enhanced recovery, and do not authorize injection of produced water from other poois. The Colville River Field seawater injection system is common to all pools, and is occasionally shut down for planned and unplanned maintenance. Freeze protection of surface facilities and wells is necessary if seawater injection is shut down. The proposed freeze protection of the Colville River Field seawater injection system involves injecting roughly 200 barrels of produced water into each cross-country seawater injection lines servicing the subject pools each day while the sea water system is shut down. The upcoming shutdown is planned for 4 days. ,. . . Administrative Approval for Fiord, Nanuq and Nanuq-Kuparuk Oil Pools Area Injection Orders 27,28, and 30 Colville River Field March 28, 2007 We estimate the freeze protection volume of Alpine Oil Pool produced water injected will amount to less than 0.02% of the total injection into the subject pools. Injection of this volume of produced water from the Alpine Oil Pool for freeze protection will not adversely affect recovery from the Nanuq, Nanuq-Kuparuk, and Fiord Oil Pools. Thank you for considering this request for an administrative approval to Area Injection Orders 27,28, and 30. Please call me at 265-6268 if you have questions. Very truly yours, ð~ UJ~ Jack Walker North Slope Operations and Development ConocoPhillips Alaska, Inc. cc: Mr. Jim Regg, AOGCC Mr. Chris Wilson, ConocoPhillips Alaska, Inc. #4 [rwd: KE: Nanuq Kecovenesj e e Subject: [Fwd: RE: Nanuq Recoveries] From: Jane Williamson <:jane_williamson@admin.state.ak.us> Date: Tue, 14 Feb 2006 10:02:32 -0900 To: Jody J Colombie <:jody _ colombie@admin.state.ak.us> cc: Stephen F Davies <steve~davies@admin.state.ak.us> Please put this in the Nanuq and Nanuq-Kuparuk files. -------- Original Message -------- RE: Nanuq Recoveries Tue, 10 Jan 2006 13:23:51 -0900 Walker, Jack A <Jack.A.Walker@conocophillips.c8m> Jane Williamson <jane williamson@admin.state.ak.us> Subject: Date: From: To: No downhole coœmingling planned on injection or production. Injection will have a common source on the surface and production will be coœmingled in the surface manifold. Jack -----Original Message----- *From:* Jane Williamson [mailto:jane williamson@admin.s~ate.ak.usJ *Sent:* Tuesday, January 10, 2006 12:57 PM *To:* Walker, Jack A *Subject:* Re: Nanuq Recoveries One other question. Is your plan to have separate injectors for Nanuq and Kuparuk reservoirs, or do you plan to co~~ingle injection? I may have missed it but I didn't see anything in your application on this. Walker, Jack A wrote: When I first heard the projected recoveries for Nanuq-Kuparuk, they seemed high to me, too. The reservoir is described as thin with high permeability and relatively homogeneous. The waterflood mobility and the response to miscible injectant are favorable. The reservoir description and fluid characterization lead to prediction of the recovery factors we cited. Would be nice to find more OOIP... Jack PS: The MWAG recovery is incremental to waterflood as you assumed. -----Original Message----- *From:* Jane Williamson [mailto:Jane w~lliamson@admin.state.ak.usJ *Sent:* Tuesday, January 10, 2006 9:39 AM *To:* Walker, Jack A *Subject:* Re: Nanuq Recoveries OK. I was just wondering about the Nanuq-Kuparuk recoveries . Assuming 10-15% primary, incremental waterflood recovery of 25-37% and incremental MWAG recovery of 17-25% (I assume incremental to waterflood), I calculate between 52% and 77% recovery. This seems really high to me. It's not that important for the order. I was just curious and wanted to make sure I didn't report incorrect values within the findings. Walker, Jack A wrote: Jane, I looked at the Nanuq & Nanuq-Kuparuk recoveries in the AIO application. The recovery factors on p. 18 were what we intended. The ranges reported was based on judgement of the reservoir engineer after running many, many sensitivities. T 1. of2 2/1 7/2006 1 :06 PM [Fwd: RE: Nanuq Recoveries] e e belleve they are consistent with the tes~imony offered in the public hearing of October 4 (p. 42 of the ppt file). I'll touch base tomorrow. Jack Jane Williamson, PE <jane williamson(â¿admin.state.ak.us> Reservoir Engineer Alaska Oil and Gas Conservation Commission : of2 2íl 7/2006 1:06 PM .....-L-J. ....................'1J......""'............J.........,....V.l... ..........1.\.4...,.1.. LJt.......\.4......V.l...L-I.l '<................,1.1Vl......... .I..Vl '-"t-'........I.4I.V.. e e Steve, Responses to Nanuq AIO questions: 1. The Nanuq sandstone is a very fine to fine-grained, lithic sandstone (litharenite). The average composition of the framework grains is 45% quartz,8% feldspar and 45% lithic rock fragments and detrital minerals. Detrital matrix within the sand ranges from 1-10%. The detrital matrix consists predominantly of clay minerals with local patches replaced by siderite cement. The clays present consist of illite/mica (11%), chlorite (7%), kaolinite (2%). Mixed layer lllite/smectite clays only account for 1-2% and are mostly illite with 20-30% smectite layers. Clay swelling is not expected to be significant based on experience with similar clays in other Brookian reservoirs and Nanuq core flood studies. Secondary sandstone cementation is generally localized and patchy based on control from core and existing wells. Various core and log analyses indicate the Nanuq-Kuparuk interval is a Kuparuk C Sand very similar to Kuparuk C Sand found in the Kuparuk River Unit (KRU). Based on extensive experience with Kuparuk C Sand injection operations at the KRU and the similarity of Nanuq-Kuparuk, clay or fines are not expected to influence reservoir performance of the Nanuq-Kuparuk pool. 2. There is DO £virlence that treated seawater or treated produced waters will be incompatible among any of existing and proposed pools in the Colville River Field. Please call or reply with any further questions. Jack Walker ConocoPhillips Alaska, Inc. North Slope Development -----Original Message----- From: Stephen Davies [mailto:steve davies@admin.state.ak.us Sent: Wednesday, January 11, 2005 9:01 AM To: Walker, Jack A Cc: Tom Maunder; Jane Williamson Subject: Re: Nanuq Area Injection Order: Additional Questions for Operator Jack, A couple of final questions concerning the Nanuq and Nanuq-Kuparuk AIO's: 1. Is there any evidence of clay or other fine materials that may swell or mobilize and influence reservoir performance in either the Nanuq or Nanuq-Kuparuk Oil Pool? If they are present, could you please provide descriptions and percentages? 2. Do you have any evidence that produced or blended, produced water from the Nanuq, Nanuq-Kuparuk, Alpine, or even Fiord would be incompatible with the Nanuq or Nanuq-Kuparuk reservoirs? Thanks for your help, .of2 l/19i2006 8:45 AM ....~. ... ......~J......'1. . u.....u. ...J.J.J....~l..l..vJ....L '--'..I. 1,..$.""1... ... 1ro.U\..!..ll..tV.liUt "<:u.\,,,.-JI..J..VU.J LVi """"'}'\""-1 ULVl e e Steve Davies Petroleum Geologist Alaska Oil & Gas Conservation Commission 907-793-1224 Walker, Jack A wrote: Steve, Enclosed is a draft response. to the Chairman. We'll follow up with a paper transmittal Jack -----Original Message----- From: Stephen Davies eve cia,vi.Es@admirl.s=ate.ak.tlS Sent: Friday, October 2:43 PM To: Walker, Jack A Cc: Tom Maunder; John Hartz Subject: Nanuq Area Injection Order: Addltional Questions for Operator Jack, Attached are a few more questions from AOGCC concerning the Nanuq Area Injection Order. I apologize for the delay in getting them to you. These are the last few questions we have prior to completing the order. The public hearing scheduled for Tuesday, Nov. 1 has bee2 vacated. Please call me at 793-1224 if you have any questions. Sincerely, Steve Davies Petroleum Geologist Alaska Oil & Gas Conservation Commission 20f2 lI19/2006 8:45 AM e e Subject: Re: Nanuq Area Injection Order: Additional Questions for Operator From: Stephen Davies <steve_davies@admin.state.ak:.us> Date: Wed, 11 Jan 2006 09:00:51 -0900 To: "Walker, Jack A" <Jack.A. Walker@conocophillips.com> CC: Tom Maunder <tom_maunder@admin.state.ak:.us>, Jane Williamson <Jane_ Williamson@admin.state.ak.us> Jack, A couple of final questions concerning the Nanuq and Nanuq-Kuparuk AIO's: 1. Is there any evidence of clay or other fine materials that may swell or mobilize and influence reservoir performance in either the Nanuq or Nanuq-Kuparuk Oil Pool? If they are present, could you please provide descriptions and percentages? 2. Do you have any evidence that produced or blended, produced water from the Nanuq, Nanuq-Kuparuk, Alpine, or even Fiord would be incompatible with the Nanuq or Nanuq-Kuparuk reservoirs? Thanks for your help, Steve Davies Petroleum Geologist Alaska Oil & Gas Conservation Commission 907-793-1224 Walker, Jack A wrote: Steve, Enclosed is a draft response. We'll follow up with a paper transmittal to the Chairman. Jack -----Original Message----- From: Stephen Davies [mailto:steve davies@admin.state.ak.us] Sent: Friday, October 28, 2005 2:43 PM To: Walker, Jack A Cc: Tom Maunder; John Hartz Subject: Nanuq Area Injection Order: Additional Questions for Operator Jack, Attached are a few more questions from AOGCC concerning the Nanuq Area Injection Order. I apologize for the delay in getting them to you. These are the last few questions we have prior to completing the order. The public hearing scheduled for Tuesday, Nov. 1 has been vacated. Please call me at 793-1224 if you have any questions. Sincerely, Steve Davies Petroleum Geologist Alaska Oil & Gas Conservation Commission : of I 1/11/2006 11 :27 AM L&- ~._. ....~. ~ '-...--.. ~--_........ _A&_.......J e e Subject: [Fwd: RE: Nanuq Recoveries] From: Jane Williamson <jane_ williamson@admin.state.ak.us> Date: Tue, 10 Jan 2006 13:32:05 -0900 To: Thomas E Maunder <tom_maunder@admin.state.ak.us>, Stephen F Davies <steve_davies@admin.state.ak.us> I think we should take out the rule on injection commingling. They can come to us later if they wish to do it, with justification. -------- Original Message -------- RE: Nanuq Recoveries Tue, 10 Jan 2006 13:23:51 -0900 Walker, Jack A <Jack.A.Walker@conocophilllps.com> Jane Williamson <jane williamson@admin.state.ak.us> Subject: Date: From: To: No downhole commingling planned on injection or production. Injection will have a common source on the surface and production will be commingled in the surface manifold. Jack -----Original Message----- *From:* Jane Williamson [mailto:jane williamson@a~~in.state.ak.us] *Sent:* Tuesday, January 10, 2006 12:57 PM *To:* Walker, Jack A *Subject:* Re: Nanuq Recoveries One other question. Is your plan to have separate injectors for Nanuq and Kuparuk reservoirs, or do you plan to commingle injection? I may have missed it but I didn't see anything in your application on this. Walker, Jack A wrote: When I first heard the projected recoveries for Nanuq-Kuparuk, they seemed high to me, too. The reservoir is described as thin with high permeability and relatively homogeneous. The waterflood mobility and the response to miscible injectant are favorable. The reservoir description and fluid characterization lead to prediction of the recovery factors we cited. Would be nice to find more OOIP... Jack PS: The MWAG recovery is incremental to waterflood as you assumed. -----Original Message----- *From:* Jane Williamson [mailto:jane williamson@admin.state.ak.us] *Sent:* Tuesday, January 10, 2006 9:39 AM *To:* Walker, Jack A *Subject:* Re: Nanuq Recoveries OK. I was just wondering about the Nanuq-Kuparuk recoveries . Assuming 10-15% primary, incremental waterflood recovery of 25-37% and incremental MWAG recovery of 17-25% (I assume incremental to waterflood), I calculate between 52% and 77% recovery. This seems really high to me. It's not that important for the order. I was just curious and wanted to make sure I didn't report incorrect values within the findings. Walker, Jack A wrote: Jane, I looked at the Nanuq & Nanuq-Kuparuk recoveries in the AIO application. The recovery factors on p. 18 were what we intended. The ranges reported was based on judgement of the reservoir engineer after running many, many sensitivities. I believe they are consistent with the testimony offered in the public hearing of October 4 (p. 42 of the ppt file). I'll touch base tomorrow. Jack of2 1/1112006 7:48 AM 1.'UJ..U,..&'1..1. VVJ. ..1.'-0...&1........,. ..I. IAVI.J.",", ............U.J.J.J.J.5 .L..i^!-""'"''''...U....J.vJ..1J UJ.J.U .c1r.uuJ....J.vJ.J.U.1 '<'U"'"''''.,. e e Jack, The Alaska Oil and Gas Conservation Commission's ("Commission") order process establishes rules and exceptions to statewide regulations in 20 AAC 25 to govern efficient, safe production practices for maximizing ultimate resource recovery. The Commission is required to perform its duties to the protect public interest in a public forum. A public hearing has been requested concerning the Nanuq pool rules. This hearing will be held on October 4, 2005 at 9 AM. The Commission will shortly publish on our web site a set of expectations for pool rules hearings. The following rough draft of those expectations will help ConocoPhillips prepare for the hearing. Public Hearing Expectations In order to ensure that adequate information is provided to the Commission and the public during a hearing, the applicant must prepare and present testimony of sufficient detail to allow the Commission to establish governing rules. This testimony must be prepared and presented by representatives capable of addressing detailed Commission questions and comments concerning the following topics: 1. Ownership and lease issues 2. Confidentiality issues: identify specific exhibits and testimony, justify each request 3. Geology and geophysics 4. Reservoir description, rock and fluid properties, reservoir modeling 5. Hydrocarbon-in-place, recovery factors, reserves 6. Production mechanisms 7. Production: historical and projected 8. Well construction 9. Development Plans 10. Facilities, including metering 11. Specialized waivers: request and justify In addition to displays used to illustrate technical discussions, the applicant must also supply a legible base map that will be used during the hearing to identify key geographic features and key elements of the proposed project. Additional Commission Questions and Comments Upon further review of ConocoPhillips' application and supplemental information, the Commission has identified several questions and comments that should be addressed, either in writing before the public hearing or within the oral testimony at the hearing. 1. Will the proposed development include wells that encroach within 500' of existing unit boundaries, PA boundaries, or property lines where ownership or landownership changes? If so, why is this? 2. Have all affected working interest ownership, landownership, surface ownership issues been successfully addressed and resolved? Have all issues with the Alaska DNR been successfully addressed and resolved? 3. In ConocoPhillips' application, Proposed Conservation Order Rule 3, well spacing, requests a 300' set back from external boundaries where working interest ownership changes. Every other order issued by the Commission specifies at least a 500' set back trom such boundaries. Please provide technical justification for this request. lof2 9/26/2005 11 :55 AM ... ...................... .... V'...,.... .................~. ... ......v............ ...........,~....J....I.....ó LJr\.p........,\.u\.J.vJ.J.o..J UJ.J.U J.·LUUJ.LJ.UJ..lU.l '<....(U......:J... e e 4. If the nature of the Nanuq is stratigraphic, wouldn't more pressure surveys be required to determine reservoir compartmentalization? The reservoirs appear to cover 6 to 10 sections (between 3800 and 6400 acres). The proposed reservoir pressure surveillance program calls for 2 surveys per year. In light of the apparent influence of stratigraphy over this pool, a minimum of 4 or 5 would seem more appropriate, especially during the early years of development. 5. CPAI is proposing to obtain initial pressures in only injection wells. Why are pressure surveys not planned in production wells? An initial static survey in wells drilled after production start up will document early pressure performance. 6. Why not develop the portion of the reservoir to the southwest at this time? 7. Proposed Conservation Order Rule 7 is a re-statement of existing regulations. 8. Proposed Conservation Order Rule lOb does not specifY monitoring frequency. Please contact me if you need additional information. Sincerely, Steve Davies Alaska Oil and Gas Conservation Commission (907) 793-1224 20f2 9/26/2005 11 :55 AM .I. "I"","LU~ 1. ..t'.t-'J.H....U...J.VJ.J.J e e Jack, After reviewing the pool rules draft application, we have the following questions: 1. Could you please describe, in language that can be made part of the public record, the overall structure and trap configuration of the Nanuq and Nanuq-Kuparuk reservoirs? 2. Could you please provide separate estimates of OOIP and an approximate recovery factor for each reservoir for the public record? 3. Is there a rough magnitude of difference in recovery factor between vertical development versus horizontal well development? (ref sec 1.3) 4. There should be a brief description of the allocation process and or basic equations that will be used for allocating total production back to the pool then the wells. This will help us understand any sensitivities with respect to correlative rights and tax or royalty issues prior to production start up. (ref sec 3.0) 5. Please provide compositional assays of the oil and gas from each pool as exhibits. 6. A shallow zone identified as the "K-2" is shown on the exploration well drawings. It is stated that this zone is hydrocarbon-bearing, but there is no mention of this zone in the draft document. Could you address this? The course of action from here is to update the draft pool rules application answering the questions above, then formally submit that application and the AIO application to the Commission as soon as you can. The order process should take about 6 weeks. AOGCC will publish the public notice (which takes about 2 to 3 days) and set a tentative hearing date at least 30 days from the date of publication. After the hearing, the order should be published in 5 or so business days (assuming there are no problems). In the meantime, if we have additional questions AOGCC will request supplemental information in writing from you. If you have questions, I will be out of the office on Monday, but Tom and Jack Hartz will be in. Thanks, Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793 -1224 1 of 1 9/26/2005 11 :55 AM j'\(1IlUl{ e - Steve, Tom, & Jack, I've been getting some questions from management/partners on the timing of the Nanuq & Nanuq-Kuparuk pool rules and area injection orders. Could you give me an estimate of the rough date or a timeframe when orders will be made? Thanks, Jack Walker ConocoPhillips Alaska, Inc. Western North Slope Development 907-265-6268 I of 1 9/26/2005 11 :56 AM Ke: Nanuq AIU & CU Uratts - CorrectIOns . e Thanks Jack. Call when you come over. I haven't looked at the documents yet, but based on what you relate in your message will the injectors have cemented liners or will they be slotted as well?? Tom Walker, Jack A wrote: Tom, I came across some errors in the drafts I dropped off Friday. The most glaring error was that the "production/injection holes will be cemented" - we're NOT planning to cement /iners/casing in the production holes. We are planning slotted liners. I'll drop off corrected versions of those sheets today (cementing error on p. 13 of the AID app & p. 4 of the non-Confidential C.O. app). Please accept my apology for any confusion this may have caused. Jack 265-6268 1 of 1 9/26/2005 11 :56 AM #3 . . ~ ConocoPhillips Chris Alonzo Development Supervisor. WNS ConocoPhillips Alaska 700 G Street Anchorage, AK 99501 Phone: 907.276.1215 November 7, 2005 Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission Alaska Department of Revenue 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Supplemental Information for Area Injection Order(s) for Proposed Nanuq and Nanuq-Kuparuk Oil Pools Colville River Field Dear Mr. Norman: On September 15, 2005, ConocoPhillips Alaska, Inc. (CP AI) as operator of the Colville River Unit and on behalf of the Working Interest Owners, requested an area injection order (AIO) authorizing enhanced recovery operations in the proposed Nanuq and Nanuq-Kuparuk oil pools. Mr. Steve Davies communicated some questions and comments regarding the Nanuq AIO on October 28,2005. Attached to this letter are responses to the questions and comments. I hope that this information meets your needs and I am available to discuss it with you and your staff if needed. Please call me at 265-6822 or Jack Walker at 265-6268 if you have questions. Very truly yours, Chris Alonzo Development Supervisor, Western North Slope ConocoPhillips Alaska, Inc. Attachment . . Applications for Area Injection Order(s) for Proposed Nanuq and Nanuq-Kuparuk Oil Pools Colville River Field November 7,2005 Page 2 cc: Alaska Department of Natural Resources Division of Oil and Gas Attention: Mike Kotowski 550 W. 7th Avenue, Suite 800 Anchorage, Alaska 99501 Arctic Slope Regional Corporation Attention: Teresa Imm 3900 C Street, Suite 801 Anchorage, Alaska 99503-5963 Kuukpik Corporation Attention: Isaak Nukapigak P.O. Box 187 Nuiqsut, Alaska 99789-0187 Kuukpik Corporation Attention: Lanston Chinn 825 W. 8th Avenue, Suite 206 Anchorage, Alaska 99501 Anadarko Petroleum Corporation Attention: Bill Shackelford 1201 Lake Robbins Drive P.O. Box 1330 Houston, Texas 77251-1330 ConocoPhillips Alaska, Inc. Attention: Matt Elmer ATO 1750 700 W. G Street P.O. Box 100360 Anchorage, Alaska 99510-0360 . . ~upplementallnformation for the Nanuq and Nanuq-Kuparuk AIO AOGCC questions (some cases statements with blanks filled in by CPA!) are shown in normal font. CP AI responses are shown in bold. italicized font. 1. Production and injection rate estimates are needed for each pool for public record: Annualized peak production rates for the Nanuq Oil Pool are expected to be between 4,000 and 11,000 barrels of oil per day ("SOPO"). Annualized waterflood injection rates are estimated to peak between 3,500 and 9,600 barrels of water per day ("SWPD") and miscible gas injection rates are expected to peak at 12 to 33 million standard cubic feet of gas per day ("MMSCFO"). Annualized peak production rates for the Nanuq-Kuparuk Oil Pool are expected to be between 3,700 and 8,500 barrels of oil per day ("SOPO"). Annualized waterflood injection rates are estimated to peak between 3,500 and 7,900 barrels of water per day ("SWPD") and miscible gas injection rates are expected to peak at 3.5 to 8 million standard cubic feet of gas per day ("MMSCFD"). 2. Recovery estimates are needed for public record. Are the following statements accurate? The Nanuq Oil Pool is estimated to contain 84 to 169 million stock tank barrels ("STS") of original oil in place ("OOIP") within the development area, based on exploratory drilling and seismic mapping. Computer simulation suggests primary recovery for the pool is expected to be approximately 10% of the OOIP. Waterflood is expected to increase recovery by 10 to 15%, and use of MWAG technology should produce an additional 9 to 14% of the OOIP. The Nanuq-Kuparuk Oil Pool OOIP is estimated to be 21 to 36 million STS within the development area. Primary recovery is estimated to be approximately 15% of OOIP. Incremental waterflood recovery is expected to recover an additional 25 to 37% above primary. Reservoir simulation supports an incremental increase of 17 to 25% for the MW AG process. Yes, these statements are acc;urate. 3. A general description of the Nanuq and Nanuq-Kuparuk structure is needed for the record. The Nanuq reservoir is a basin floor submarine fan system dominated by lobe-sheet deposits. The fan system lies 1 to 2 miles east of the time equivalent, northeast-southwest trending base of slope. The Nanuq reservoir occurs at a local high in the Drillsite CD4 area with structure dipping to the south and east, and absence of sand to the north and west. The trap is stratigraphically created. There are no major faults cutting the Nanuq reservoir. The Nanuk #1 and #2 and Nanuq #3 and #5 wells define the core of the development area for the Nanuq reservoir. Log and core data confirm an oil-water contact at 6,207 subsea true vertical depth (TVD). The CD1-229 test indicated a possible gas cap. Page 1 of 3 1117/2005 CPAI Responses to AOGCC Questions . . ~upplementallnformation for the Nanuq and Nanuq-Kuparuk AIO The Nanuq-Kuparuk reservoir is a shallow marine transgressive sandstone that lies below the Kalubik shales and just above the Lower Cretaceous Unconformity (LCU). The structure dips from east to west at approximately 0.7 degrees. Trap is stratigraphic in nature with sand encased above and below by shales. The northern edge of the reservoir has one mapped fault which not expected to affect recovery. 4. In the application, there is a statement that a single, small fault has been mapped in the northern portion of the development area, but is not expected to affect reservoir performance. Does this fault affect both intervals? That fault cuts only the Nanuq-Kuparuk reservoir, and is not apparent in the Nanuq reservoir. 5. Please provide a statement regarding compatibility of produced water with the reservoir. Will produced water be used for EOR purposes at CD4? Based on commingled processing of several pools (Alpine, Fiord and Nanuq initially and others later) at CD1 it appears possible that multiple produced waters could be injected at CD4. If so, please provide a statement addressing compatibility of that water with the Nanuq and Nanuq-Kuparuk Oil Pools. The water injection plan for the Nanuq and Nanuq-Kuparuk Oil Pools is based on a single water injection pipeline between the Alpine Central Facility (ACF) and Drill Site COol. Processing of all production from all pools in the Colville River Field is planned via the ACF. Drill Site CD4 is the surface location for all development wells planned for the two proposed pools. Seawater is planned as the initial waterflood source water for Drill Site COol and produced water or mixed water is planned for injection later in the field life. Production commingling on the surface is planned for all pools in the Colville River Field at the ACF. Compatibility of waters will be managed with the addition of scale inhibitors. Scale inhibitor is presently used for produced water and seawater mixing upstream of one of three water injection pumps at the Alpine Central Facility (ACF). By mixing produced water and seawater, pump utilization can be maximized in the interim when produced water volume is sufficient to only partially load a water injection pump. The other two ACF water injection pumps are presently dedicated to seawater service. The mixed water and seawater injection lines are segregated and each flow to a separate set of wells. The mixed produced water and seawater are presently directed to a certain subset of wells at Drill Site CD1. As produced water increases beyond the capacity of a single pump, the segregation of the mixed water may be ceased and all wells served by the ACF water injection system may receive mixed seawater and produced water. Page 2 of 3 11/7/2005 CPAI Responses to AOGCC Questions . . :ïupplementallnformation for the Nanuq and Nanuq-Kuparuk AIO 6. Is it possible that non- hazardous filtered water collected from the initial Alpine development area will be considered for injection at CD4? If so, appropriate statements of request and justification are needed. Yes, Commission-approved fluids used for injection in the Alpine Oil Pool will be considered for injection at CD4. Non-hazardous fluids from several sources in the Colville River Field are normally injected into the WD-02 Class I disposal well. But, the WD-02 well is occasionally unavailable due to compliance testing or diagnostics. The Commission approved blending of specific non-hazardous fluids with existing Class II fluids used for EOR in the Alpine Oil Pool (AIO 188.002). When WD-D2 is unavailable, current practice is to blend specific non- hazardous fluids (NHF) approved by the Commission with the mixed water stream discussed in section 5. Manifolding at the Alpine Central Facility allows the segregation of the blended NHF stream for injection into a subset of CD1 wells. As produced water increases and exceeds the capacity of a single water injection pump, all injection water for the Colville River Field may become mixed water, and the NHF will be blended into that stream. If NHF is blended in the entire stream of Colville River ReId EOR injection water, the concentration of NHF will decrease to 0.02% of the EOR injection water. This concentration is not expected to cause any change to the EOR effciency in any of the Colville River Field pools. Page 3 of 3 11/7/2005 CPAI Responses to AOGCC Questions . .---, . - -- -'J-----'. -.--.. . .--...---. x--.- .~- -1:'"-'---' . Subject: Nanuq Area Injection Order: Additional Questions for Operator From: Stephen Davies <steve_davies@admin.state.ak.us> Date: Fri, 28 Oct 2005 14:42:52 -0800 To: Jack.A. Walker@conocophillips.com CC: Tom Maunder <tom_maunder@admin.state.ak.us>, John Hartz <jack_hartz@admin.state.ak.us> Jack, Attached are a few more questions from AOGCC concerning the Nanuq Area Injection Order. I apologize for the delay in getting them to you. These are the last few questions we have prior to completing the order. The public hearing scheduled for Tuesday, Nov. 1 has been vacated. Please call me at 793-1224 if you have any questions. Sincerely, Steve Davies Petroleum Geologist Alaska Oil & Gas Conservation Commission Content-Type: application/msword 051027_ Questions_ for_Operator_Nanu~AIO _.doc Content-Encoding: base64 1 of 1 1/19/20068:52 AM . . Nanuq AIO Questions for Operator 1. Production and injection rate estimates are needed for each pool for public record: Peak production rates for the Nanuq Oil Pool are expected to be between and barrels of oil per day ("BOPO"). Waterflood injection rates are estimated to peak between and barrels of water per day ("BWPD") and miscible gas injection rates are expected to peak at million standard cubic feet of gas per day ("MMSCPD"). Peak production rates for the Nanuq-Kuparuk Oil Pool are expected to be between and barrels of oil per day ("BOPD"). Waterflood injection rates are estimated to peak between and barrels of water per day ("BWPD") and miscible gas injection rates are expected to peak at million standard cubic feet of gas per day ("MMSCPO"). 2. Recovery estimates are needed for public record. Are the following statements accurate? The Nanuq Oil Pool is estimated to contain million stock tank barrels ("STB") of original oil in place ("OOIP") within the development area, based on exploratory drilling and seismic mapping. Computer simulation suggests primary recovery for the pool is expected to be % of the OOIP. Waterflood is expected to increase recovery by 10 to 15%, and use of MWAG technology should produce an additional 9 to 14% of the OOIP. The Nanuq-Kuparuk Oil Pool OOIP is estimated to be million STB within the development area. Primary recovery is estimated to be %. Incremental waterflood recovery is expected to recover an additional 25 to 37% above primary. Reservoir simulation supports an incremental increase of 17 to 25% for the MWAG process. 3. A general description of the Nanuq and Nanuq-Kuparuk structure is needed for the record. 4. In the application, there is a statement that a single, small fault has been mapped in the northern portion of the development area, but is not expected to affect reservoir performance. Does this fault affect both intervals? 5. Please provide a statement regarding compatibility of produced water with the reservoir. Will produced water be used for EOR purposes at CD4? Based on commingled processing of several pools (Alpine, Fiord and Nanuq initially and others later) at CD1 it appears possible that multiple produced waters could be injected at C04. If so, please provide a statement addressing compatibility of that water with the Nanuq and Nanuq-Kuparuk Oil Pools. 6. Is it possible that non- hazardous filtered water collected from the initial Alpine development area will be considered for injection at C04? If so, appropriate statements of request and justification are needed. AOGCC Page 1 of 1 2/14/2006 051020_ Questions_for _Operator _ Nanu<L AlO. doc #2 STATE OF ALASKA . NOTICE TO PUBLISHER . ADVERTISING ORDER NO. ADVERTISING ORDER SEE BOTTOM FOR INVOICE ADDRESS INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE AO-02614014 F AOGCC AGENCY CONTACT DATE OF A.O. R 333 W 7th Ave, Ste 100 o Anchorage, AK 99501 M Jody Colombie PHONE September 26, 2005 PCN (907) 793 -1221 DATES ADVERTISEMENT REQUIRED: ~ Anchorage Daily News PO Box 149001 Anchorage, AK 99514 September 27,2005 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Type of Advertisement X Legal D Display Advertisement to be published was e-mailed D Classified DOther (Specify) SEE ATTACHED SEND INVOICE IN TRIPLlCATE AOGCC, 333 W. 7th Ave., Suite 100 TO A nchoral!e. A K 99:'i0 1 REF TYPE NUMBER AMOUNT DATE 1 VEN 2 ARD 02910 3 4 I TOTAL OF I PAGE 1 OF ALL PAGES$ 2 PAGES COMMENTS ~IN dMnllNT !::v r.r. Pr.M Ir. dr.r.T ~v NMR DIST UQ 05 02140100 73451 2 3 4 REQUISITIONED BY: ---=/ ¡DIVISION APPROVAL: . . Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Proposed Nanuq and Nanuq-Kuparuk Oil Pools, Colville River Field Request for an Area Injection Order ConocoPhillips Alaska, Inc., by letter and application dated September 15, 2005, has requested the Alaska Oil and Gas Conservation Commission ("Commission") issue an area injection order, in accordance with 20 AAC 25.460, authorizing enhanced oil recovery operations in the proposed Nanuq and Nanuq-Kuparuk Oil Pools within the Colville River Unit. These proposed pools, and the proposed development area, are located within portions of TION-R4E, TI0N-R5E, T11N-R4E, and TIIN-R5E, Umiat Meridian. The Commission has tentatively scheduled a public hearing on this application for November 1, 2005 at 9:00 am at the offices of the Alaska Oil and Gas Conservation Commission at 333 West ih Avenue, Suite 100, Anchorage, Alaska 99501. A person may request that the tentatively scheduled hearing be held by filing a written request with the Commission no later than 4:30 pm on October 14,2005. If a request for a hearing is not timely filed, the Commission may consider the issuance of an order without a hearing. To learn if the Commission will hold the public hearing¡please call 793-1221. In addition, a person may submit a written protest or written comments regardin~ this application to the Alaska Oil and Gas Conservation Commission at 333 West i Avenue, Suite 100, Anchorage, Alaska 99501. Written protest or comments must be received no later than 4:30 pm on October 28, 2005 except that if the Commission decides to hold a public hearing, written protest or comments must be received no later than the conclusion of the November 1,2005 hearing. who may need special accommodations in ing, please contact Jody Colombie at 793- Published Date: September 27,2005 ADN AO# 02614014 . Anchorage Daily News Affidavit of Publication . 1001 Northway Drive, Anchorage, AK 99508 PRICE OTHER OTHER OTHER OTHER OTHER GRAND AD# DATE PO ACCOUNT PER DAY CHARGES CHARGES #2 CHARGES #3 CHARGES #4 CHARGES #5 TOTAL 614495 œ/27/2005 02614014 STOF0330 $176.32 $176.32 $0.00 $0.00 $0.00 $0.00 $0.00 $176.32 Notice of Public Hearing \J Ii , /), r; !/]TJ; /'''fI i~ ,j'/L ...... '/- . . /' ..' .' /7);/ P\--,·",\ ~ _ STATE OF ALASKA Alaska oH and Gas Canservation Commission Re: Proposed No'"ÌJq and Nanuq-Kuparuk Oil Pools, Colville River Field Request for an Area Iniecfion Order ConocoPhillips Alaska, Inc., by letter and appli- cation dated September IS, 200S, has requested the Alaska Oil and Gas Conservation Commission ("Commission") issue an areainiection order, in accordance with 20 AAC 2S.460, authorizing en- hanced oil recovery operations in the proposed Nanua and Nanuq-Kuparuk Oil Pools within the Colville River Unit. These proposed pools, and the proposed development area, are located within portions of Tl0N-R4E, TlON-RSE,TllN-R4E,and Tll N-RSE, Umiat Meridian. The Commission has tentatively scheduled a pub- lic hearing on this application for November 1, 200S at 9:00 am at the offices of fhe Alaska Oil and Gas Co~servation Commission at 333 West 7th Avenue, SUI,te 100, Anchorage, Alaska 99S01,. A person may request that the tentatively scheduledhearing..b&-; h!,ld by filing a written request with the Commis- sIon no later than 4:30 pm an October 14, 2005. If a ~equest for ahearing is not timelY filed, the CommIssion may consider the issuance of an or- d~r without a hearing. To learn if the Commission will hold the public heoring, please call 793-1221. In addition, a person may submit a written pro- t!,st or written comments regarding this applica- tIon tothe Alaska Oil and Gas Conservation Com- mission at 333 west 7th Avenue, Suitè 100 Anchorage, Alask099S01. Written protest or com: ments must be received no later than 4:30 pm on October 28, 200S except that if the Commission de- cIdes to hold a public hearing, written protest or comments must be received no later ,than the con- clusion of the November 1, 200S hearing. If you a~e a person with 0 disability who may needspeclol accommodations in order. to com- ment or to ottend the public hearing, please con- ~~;t2~~~J'oiolombie at 793-1221 no later than Octo- STATE OF ALASKA THIRD JUDICIAL DISTRICT Teresita Peralta, being first duly sworn on oath deposes and says that she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchora¡:çe, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on the above dates and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Signed ~jaJ Subscribed and sworn to me before this date: John K, Norman Chairman Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska ADN AO# 02614014 Published Date: September 27, 200S MY qOMMISSION EXPIRES: I / .j 1/,1' / b< f/.J ;:1/ V~.¿ J/,/.' ... / ¡ Re: Public Notice . . Subject: Re: Public Notice From: "Ads, Legal" <legalads@adn.com> Date: MOll, 26 Sep 2005 14:40:02 -0800 To: Jody Colombie <jody _ colombie@admin.state.ak.us> Hello Jody: Following is the confirmation information on your legal notice. Please review and let me know if you have any questions or need additional information. Account Number: STOF 0330 Legal Ad Number: 614495 Publication Date(s): September 27, 2005 Your Reference or PO#: 02614014 Cost of Legal Notice: $176.32 Additional Charges: Web Link: E-Mail Link: Bolding: Total Cost To Place Legal Notice: $176.32 Your Legal Notice Will Appear On The Web: www.adn.com: XXXX Your Legal Notice Will Not Appear On The Web www.adn.com: Thank You, Kim Kirby Anchorage Daily News Legal Classified Representative E-Mail: legalads@adn.com Phone: (907) 257-4296 Fax: (907) 279 - 81 70 On 9/26/05 1:47 PM, "Jody Colombie" Sjody co1ombie@admin.state.ak.us> wrote: Please publish 9/27/05 1 of 1 9/26/2005 2:58 PM I 02-902 (Rev. 3/94) PUbIiShe.¡g¡nal Copies: Department Fiscal, Departm.ReceiVing AO.FRJ'v! STATE OF ALASKA ADVERTISING ORDER SEE BOTTOM FOR INVOICE ADDRESS NOTICE TO PUBLISHER ADVERTISING ORDER NO. INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COpy OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE AO-02614014 F AOGCC 333 West ih Avenue. Suite 100 A nr.nr'\nwf> A K qq.::;01 907-793-1221 AGENCY CONTACT DATE OF A.O. R o M .Todv Colombie Sentember 26. ::W05 PHONE PCN (907) 793 -12? 1 DATES ADVERTISEMENT REQUIRED: T o Anchorage Daily News PO Box 149001 Anchorage, AK 99514 September 27, 2005 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 sworn, according to law, says that helshe 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 2005, and thereafter for _ consecutive days, the last publication appearing on the _ day of , 2005, 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 2005, Notary public for state of My commission expires Public Notice Colville River Field and AlO 5.007 (Trading Bay Unit) . . Subject: Public Notice Colville River Field and AIO 5.007 (Trading Bay Unit) From: Jody Colombie <jody _colombie@admin.state.ak.us> Date: Mon, 26 Sep 2005 16:26: 19 -0800 To: undisclosed-recipients:; BCC: Cynthia B Mciver <bren_mciver@admin.state.ak.us>, Robert E Mintz <robert_mintz@law.state.ak.us>, Christine Hansen <c.hansen@iogcc.state.ok.us>, Terrie Hubble <hubblet1@bp.com>, Sondra Stewman <StewmaSD@BP.com>, Scott & Cammy Taylor <staylor@alaska.net>, stanekj <stanekj@unocal.com>, ecolaw <ecolaw@trustees.org>, roseragsdale <roseragsdale@gci.net>, tnnjr 1 <tnnjrl@aol.com>, jbriddle <jbriddle@marathonoil.com>, shaneg <shaneg@evergreengas.com>, j darlington <j darlington@forestoil.com>, nelson <knelson@petroleumnews.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@dm.state.ak.us>, tjr <tjr@dm.state.ak.us>, bbritch <bbritch@alaska.net>, mjnelson <mjnelson@purvingertz.com>, Charles O'Donnell <charles.o'donnell@veco.com>, "Randy L. Skillern" <SkilleRL@BP.com>, "Deborah J. Jones" <JonesD6@BP.com>, "Steven R. Rossberg" <RossbeRS@BP.com>, Lois <lois@inletkeeper.org>, Dan Bross <kuacnews@kuac.org>, Gordon Pospisil <PospisG@BP.com>, "Francis S. Sommer" <SommerFS@BP.com>, Mikel 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>, bocastwf <bocastwf@bp.com>, Charles Barker <barker@usgs.gov>, doug_schultze <doug_schultze@xtoenergy.com>, Hank Alford <hank.alford@exxonmobil.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@dm.state.ak.us>, Kurt E Olson <kurt_olson@legis.state.ak.us>, buonoje <buonoje@bp.com>, Mark Hanley <mark _ hanley@anadarko.com>, loren _leman <loren _leman@gov.state.ak.us>, Julie Houle <julie_houle@dm.state.ak.us>, John W Katz <jwkatz@sso.org>, Suzan J Hill <suzan _ hill@dec.state.ak.us>, tablerk <tablerk@unocal.com>, Brady <brady@aoga.org>, Brian Havelock <beh@dm.state.ak.us>, bpopp <bpopp@borough.kenai.ak.us>, Jim White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exxonmobil.com>, marty <marty@rkindustrial.com>, ghammons <ghammons@aol.com>, nnclean <rmclean@pobox.alaska.net>, mkm7200 <mkm7200@aol.com>, Brian Gillespie <ifbmg@uaa.alaska.edu>, David L Boelens <dboelens@aurorapower.com>, Todd Durkee <TDURKEE@KMG.com>, Gary Schultz <gary_schultz@dm.state.ak.us>, Wayne Rancier <RANCIER@petro-canada.ca>, Bill Miller <Bill_Miller@xtoalaska.com>, Brandon Gagnon <bgagnon@brenalaw.com>, Paul Winslow <pmwinslow@forestoil.com>, Garry Catron <catrongr@bp.com>, Sharmaine Copeland <copelasv@bp.com>, Kristin Dirks <kristin _ dirks@dm.state.ak.us>, Kaynell Zeman <kjzeman@marathonoil.com>, John Tower <John.Tower@eia.doe.gov>, Bill Fowler <Bill_Fowler@anadarko.COM>, Vaughn Swartz <vaughn.swartz@rbccm.com>, Scott Cranswick <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP.com>, Steve Lambe <lambes@unocal.com>,jack newell <jack.newell@acsalaska.net>, James Scherr lof2 9/26/2005 4:27 PM Public Notice Colville River Field and AIO 5..Trading Bay Unit) . <james_scherr@yahoo.com>, david roby <David.Roby@mms.gov>, Tim Lawlor <Tim_Lawlor@ak.blm.gov>, Lynnda Kahn <Lynnda_Kahn@fws.gov>, Jerry Dethlefs <Jerry.C.Dethlefs@conocophillips.com>, Jerry Dethlefs <n1617@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>, Harry Lampert <harry.lampert@honeywell.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>, Phillip Ayer <pmayers@unocal.com>, Ken <ken@secorp-inc.com>, Steve Lambert <salambert@unocal.com>, Joe Nicks <news@radiokenai.com> Content-Type: application/pdf AI05.007.pdf Content-Encoding: base64 Content-Type: application/pdf AIO Nanuq Public Notice.pdf b 64 - - - Content-Encoding: ase 20f2 9/26/2005 4:27 PM Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Mona Dickens 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 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 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 . 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 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 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 North Slope Borough PO Box 69 Barrow, AK 99723 David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 John Levorsen 200 North 3rd Street, #1202 Boise,ID 83702 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 #1 . Conoc;p.,illips . Chris Alonzo Development Supervisor, WNS ConocoPhillips Alaska 700 G Street Anchorage, AK 99501 Phone: 907.276.1215 September 15, 2005 Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission Alaska Department of Revenue 333 West ih Avenue, Suite 100 Anchorage,AJe 99501 Re: Applications for Area Injection Order(s) for Proposed Nanuq and Nanuq-Kuparuk Oil Pools Colville River Field Dear Mr. Norman: In accordance with 20 AAC 25.460, ConocoPhillips Alaska, Inc. (CP AI) as operator of the Colville River Unit and on behalf of the Working Interest Owners, is requesting an area injection order authorizing enhanced recovery operations in the proposed Nanuq and Nanuq-Kuparuk oil pools. An application for the area injection order(s) is attached. I hope that this information meets your needs and I am available to discuss it with you and your staff if needed. Please call me at 265-6822 or Jack Walker at 265-6268 if you have questions. Very truly yours, C?£, / ~:' ,é- '..'- .' _c' .f./'" "_'. n ",_- .' ~~/ Cf~é "-j9/ Chris Alonzo Development Supervisor, Western North Slope ConocoPhillips Alaska, Inc. Attachments . ~ ConocoPhillips . Chris Alonzo Development Supervisor, WNS ConocoPhillips Alaska 700 G Street Anchorage, AK 99501 Phone: 907.276.1215 September 15, 2005 Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission Alaska Department of Revenue 333 West th Avenue, Suite 100 Anchorage,AJC 99501 Re: Applications for Area Injection Order(s) for Proposed Nanuq and Nanuq-Kuparuk Oil Pools Colville River Field Dear Mr. Norman: In accordance with 20 AAC 25.460, ConocoPhillips Alaska, Inc. (CP AI) as operator of the Colville River Unit and on behalf of the Working Interest Owners, is requesting an area injection order authorizing enhanced recovery operations in the proposed Nanuq and Nanuq-Kuparuk oil pools. An application for the area injection order(s) is attached. I hope that this information meets your needs and I am available to discuss it with you and your staff if needed. Please call me at 265-6822 or Jack Walker at 265-6268 if you have questions. Very truly yours, C([ ., . \ . 1/ ?/h j5Vr' /.~- .~ ." L~-<-v f\... / Chris Alonzo Development Supervisor, Western North Slope ConocoPhillips Alaska, Inc. Attachments . . Applications for Area Injection Order(s) for Proposed Nanuq and Nanuq-Kuparuk Oil Pools Colville River Field September 15, 2005 Page 2 cc: Alaska Department of Natural Resources Division of Oil and Gas Attention: Mike Kotowski 550 W. ih Avenue, Suite 800 Anchorage, Alaska 9950 I Arctic Slope Regional Corporation Attention: Teresa lmm 3900 C Street, Suite 801 Anchorage, Alaska 99503-5963 Kuukpik Corporation Attention: Isaak Nukapigak P.O. Box 187 Nuiqsut, Alaska 99789-0187 Kuukpik Corporation Attention: Lanston Chinn 825 W. 8th Avenue, Suite 206 Anchorage, Alaska 99501 Anadarko Petroleum Corporation Attention: Bill Shackelford 1201 Lake Robbins Drive P.O. Box 1330 Houston, Texas 77251-1330 ConocoPhillips Alaska, Inc. Attention: Matt Elmer ATO 1750 700 W. G Street P.O. Box 100360 Anchorage, Alaska 99510-0360 . . Application to the Alaska Oil and Gas Conservation Commission for the Nanuq Area Injection Order Colville River Field ConocoPhillips Alaska, Inc Anadarko Petroleum Corporation Application to the AO. for the Nanuq Area Injection Order . Colville River Field September 13, 2005 Table of Contents Introduction ... ....... .... ..... ........... ..... ..... ..... ... .... .... ........... ...... .... .... .... ........... ...... ........... ........ .......... ...3 20 MC 25.402 (c)(1) Plat of Wells Penetrating Injection Zone....................................................... 4 20 MC 25.402 (c)(2) Operators and Surface Owners within One Quarter Mile of Injection Operations........................................................................................................................ ................ 5 20 MC 25.402 (c)(3) Affidavit of Jack A. Walker Regarding Notice to Surface Owners ................ 6 20 MC 25.402 (c)(4) Description of the Proposed Operation ........................................................ 7 20 MC 25.402 (c)(5) Description and Depth of Pool to be Affected............................................... 9 20 MC 25.402 (c)(6) Description of the Formation....................................................................... 10 20 MC 25.402 (c)(7) Logs of the Injection Wells.......................................................................... 11 20 MC 25.402 (c)(8) Casing Description and Proposed Method for Testing............................... 12 20 MC 25.402 (c)(9) Injection Fluid Analysis and Injection Rates ...............................................13 20 MC 25.402 (c)(10) Estimated Pressures.................................................................................14 20 MC 25.402 (c)(11) Fracture Information .................................................................................15 20 MC 25.402 (c)(12) Quality of Formation Water....................................................................... 16 20 MC 25.402 (c)(13) Aquifer Exemption Reference................................................................... 17 20 MC 25.402 (c)(14) Incremental Hydrocarbon Recovery......................................................... 18 20 MC 25.402 (c)(15) Mechanical Condition of Wells Within % Mile of Proposed Area.............. 19 List of Fiqures Figure 1 Proposed Area for Nanuq and Nanuq-Kuparuk Oil Pools and Area Injection Order(s) Figure 2 Planned Development Wells for Nanuq and Nanuq-Kuparuk Oil Pools Figure 3 Nanuq Type Log Figure 4 Nanuq-Kuparuk Type Log Figure 5 Nanuq Log Model Figure 6 Nanuq-Kuparuk Log Model Figure 7 Typical Injection Well Schematic Figure 8 Nanuq CD4 Project Simulated Slimtube Recovery Results Attachments Fracture Containment Modeling Nanuq Interval Fracture Contatinment Modeling Nanuq-Kuparuk Interval Nanuk #1 Well Completion Report Nanuk #1 Actual Plug and Abandon Diagram Nanuk #2 Well Completion Report Nanuk #2 P&A Schematic Nanuq #3 Well Completion Report Nanuq #3 Operations Shutdown Final Schematic Nanuq 5 Operational Shutdown Sundry Approval Nanuq 5 Well Schematic After Suspension Page 2 ConocoPhillips Alaska, Inc. Application to the AO. for the Nanuq Area Injection Order . Colville River Field September 13, 2005 Introduction This application seeks Alaska Oil and Gas Conservation Commission endorsement and authorization for the proposed Nanuq CD4 Miscible Water Alternating Gas Project in the Colville River Unit. This project involves the development of two reservoirs from Drill Site CD4: Nanuq and Nanuq-Kuparuk. This application has been prepared in accordance with 20 AAC 25.402 (Enhanced Recovery Operations) and 20 MC 25.460 (Area Injection Orders). The proposed Nanuq CD4 Miscible Water Alternating Gas Project is an enhanced oil recovery project, employing the cyclic injection of miscible gas and water, to be implemented for the development of the proposed Nanuq and Nanuq-Kuparuk Oil Pools, which are located within the Colville River Unit on the North Slope of Alaska. The proposed Nanuq Oil Pool includes the Nanuq reservoir within the Torok Formation. The proposed Nanuq-Kuparuk Oil Pool is the deeper reservoir in the Kuparuk River Formation. The proposed Nanuq Oil Pool directly overlies the proposed Nanuq-Kuparuk Oil Pool. Concurrent with this application for an Area Injection Order, ConocoPhillips Alaska, Inc., as operator of the Colville River Unit and on behalf of the working interest owners (WIO's), is seeking Conservation Order(s) by the Commission regarding the classification and rules to govern the development of the proposed Nanuq and Nanuq-Kuparuk Oil Pools. For each proposed oil pool, the working interest owners plan to form a corresponding separate participating area within the Colville River Unit. Preliminary boundaries for the future participating areas are shown on Figure 1 with the present Colville River Unit Boundary. ConocoPhillips Alaska, Inc. as operator and on behalf of the WIO's, plans to apply to the State of Alaska and Arctic Slope Regional Corporation, to form a Nanuq Participating Area and a Nanuq-Kuparuk Participating Area in early 2006. Development drilling is scheduled to commence in October, 2005 at Drill Site CD4, creating the need to establish pool rules and complementary area injection order(s) for the proposed oil pools. Page 3 ConocoPhillips Alaska, Inc. Application to the AO. for the Nanuq Area Injection Order . Colville River Field September 13, 2005 20 MC 25.402 (c)(1) Plat of Wells Penetratinq Injection Zone The attached map (Figure 2) show all existing wells penetrating the injection zones in the proposed injection area. The maps also show the areal extent of the injection zone relative to preliminary participating areas within the Colville River Unit, and the location of all proposed Nanuq Oil Pool and Nanuq-Kuparuk Oil Pool development wells (injection wells and development wells). Page 4 ConocoPhillips Alaska, Inc. Application to the AO. for the Nanuq Area Injection Order . Colville River Field September 13, 2005 20 MC 25.402 (c)(2) Operators and Surface Owners within One Quarter Mile of Injection Operations Operator: ConocoPhillips Alaska, Inc. Attention: Matt Elmer P. O. Box 100360 Anchorage, AK 99510-0360 Surface Owners: State of Alaska Department of Natural Resources Attention: Mike Kotowski P. O. Box 107034 Anchorage, AK 99510 Kuukpik Corporation Mr. Isaac Nukapigak PO Box 187 Nuiqsut, Alaska 99789-0187 Page 5 ConocoPhillips Alaska, Inc. Application to the AO.for the Nanuq Area Injection Order . Colville River Field September 13, 2005 20 AAC 25.402 (c)(3) Affidavit of Jack A. Walker Reqardinq Notice to Surface Owners Jack A. Walker, on oath, deposes and says: 1. I am the Nanuq Production Engineer for ConocoPhillips Alaska, Inc., the operator of the Colville River Unit. 2. On September 15, 2005, I caused copies of the application for the Nanuq Area Injection Order to be provided to the surface owner and operator of all land within a quarter mile of the proposed injection wells as listed below: a. State of Alaska Department of Natural Resources Attention: Mike Kotowski P. O. Box 107034 Anchorage, AK 99510 b. Kuukpik Corporation Mr. Isaac Nukapigak PO Box 187 Nuiqsut, Alaska 99789-0187 c. ConocoPhillips Alaska, Inc. Attention: Matt Elmer ATO-1750 P.O. Box 100360 Anchorage, Alaska 99510-0360 If Jack A. Walker STATE OF ALASKA ) ) ss. THIRD JUDICIAL DISTRICT) SUBSCRIBED AND SWORN to before me this fifteenth day of September, 2005. STATE OF ALASKA,~ NOTARY PUBLIC e Carol Kelly " ~ My Commisslon'~~!!~S Aug. 16,2008 ?o~ßCX:Lú; NOT AR'(PUBLI~ IN AN~ Io~ASKA My Commission Expires: Page 6 ConocoPhillips Alaska, Inc. Application to the AOa for the Nanuq Area Injection Order . Colville River Field September 13, 2005 20 MC 25.402 (c)( 4) Description of the Proposed Operation An Area Injection Order is needed to develop the Nanuq and Nanuq-Kuparuk reservoirs. The scope of the development project includes drilling 19 wells from a new Colville River Unit Drill Site CD4. Three wells are planned to develop the proposed Nanuq-Kuparuk Oil Pool and sixteen wells are planned to develop the proposed Nanuq Oil Pool. Development of the proposed Nanuq and the Nanuq- Kuparuk Oil Pools is planned with development wells solely dedicated to a single pool with no subsurface commingling. Unitized substances produced from the proposed Nanuq and the Nanuq-Kuparuk Oil Pools will be commingled on the surface with each other and with substances from the existing Alpine Oil Pool. Similar to the existing allocation of unitized substances for the Alpine Oil Pool, production allocation for the proposed pools will be based on periodic well tests and producing conditions, e.g. up time; and injection allocation for the proposed pools will be based on meters on each injection well. Water alternating with miscible gas injection is the proposed recovery mechanism for both reservoirs. The project scope includes injection of water and enriched hydrocarbon gas from the Alpine Central Facility ("ACF"), also located within the Colville River Unit. At the end of the Nanuq CD4 Project miscible gas injection phase, lean gas and/or water may be injected to recover the remaining mobilized oil and injected hydrocarbons. Injection of water is scheduled to begin in late 2006, followed by MI injection beginning in mid-2007. Seven injection wells for the Nanuq reservoir and one injection well for the Nanuq-Kuparuk reservoir are included in the scope of the Nanuq CD4 Project. Surface facilities will be installed at the CD4 drillsite to deliver and meter both M I and water to each injection well. Horizontal development wells will be drilled from Drill Site CD4. For both reservoirs, well layout is a direct line drive pattern configuration with rows of injectors and producers. Planned interwell spacing is 1500 feet for Nanuq and 6,000 feet for Nanuq-Kuparuk. Different well spacing may be implemented if justified after analysis of reservoir performance. Horizontal production holes are planned at 4,900 to 7,100 feet for Nanuq and 4,500 to 6,700 feet for Nanuq- Kuparuk. The Nanuq CD4 surface facilities scope includes a 3.8-mile gravel road to a 9.3- acre gravel pad located south of the ACF. The project includes produced oil, water injection, MI, and gas lift pipelines from the ACF to the Nanuq CD4 drillsite. Drillsite facilities include the following: Production, test, artificial lift, gas injection, and water injection headers; Tie-in slots for 24 wells (including spares) with wellhead shelters; Electrical and instrumentation module with transformers, switch gear, and telecommunications; Test separator; Page 7 ConocoPhillips Alaska, Inc. Application to the AoA for the Nanuq Area Injection Order . Colville River Field September 13, 2005 Emergency shut down (ESD) skid; Water injection line pig receiver; Chemical injection and storage; Wellhead hydraulic panels (in well house); and Lighting, surveillance, and communication equipment. Additionally, tie-ins at the ACF will include a manifold module and associated piping. Powerlines (13.8 kV) will be suspended by messenger cable below the pipelines. CPAI constructed the gravel road from the existing CD1 Airstrip / CD2 access road to the new Nanuq CD4 gravel pad drillsite during winter 2005. Four new pipelines from the ACF at CD1 to the new Nanuq CD4 drillsite will follow the same route as the existing Alpine Sales Line. The approximate length of pipelines from Nanuq CD4 to CD1 is 4.6 miles. The following pipelines from Nanuq CD4 are planned: 14-inch diameter production pipeline 8-inch diameter water injection pipeline 6-inch diameter MI pipeline 6-inch diameter gas-lift pipeline Page 8 ConocoPhillips Alaska, Inc. Application to the AO. for the Nanuq Area Injection Order . Colville River Field September 13, 2005 20 MC 25.402 (c)(5) Description and Depth of Pool to be Affected Location The proposed Nanuq and Nanuq-Kuparuk Oil Pools are located in the Colville River Unit approximately 4 miles south of the Alpine Central Facility. As shown on Figure 1, the affected area proposed for the Nanuq Area Injection Order is: Umiat Meridian T11N R4E Sections 1-4, 9-16, 21-28, 33-36 T11N R5E Sections 3-10,15-22,27-34 T10N R4E Sections 1, 2 T10N R5E Sections 3-6 Pool Definitions The proposed Nanuq Oil Pool is the hydrocarbon-bearing interval between 7,043 and 7,223 feet measured depth in the Nanuk #2 well (Figure 3) and its lateral equivalents. The proposed Nanuq-Kuparuk Oil Pool is the hydrocarbon-bearing interval between 7956 and 7,972 feet measured depth in the Nanuk #2 well (Figure 4) and its lateral equivalents. Pool Descriptions The Nanuq reservoir is a basin floor submarine fan system dominated by lobe- sheet deposits. This reservoir is a Cretaceous age interval within the Torok Formation. The gross Nanuq interval is located between 6138 feet and 6312 feet subsea total vertical depth ("SSTVD"), as shown on the Nanuk #2 Well Log (Figure 5). The northern (distal) edge of the fan is defined by 22 Alpine development and delineation wells. This fan sequence is sand-rich with the majority of the best reservoir quality rock found in the upper part of the interval. In the proposed Nanuq Oil Pool area, approximately 2000 feet of Albian Torok interval overlies the Nanuq sandstone. The Torok interval above the Nanuq sandstone is comprised of interbedded mudstones and siltstones. The Nanuq sandstone is underlain by approximately 400 feet of mudstones, siltstones, and sandstone in the basal Torok interval. Below the basal Torok are shales of the HRZ. The Nanuq-Kuparuk reservoir is a shallow marine transgressive sandstone that lies below the shales of the Kalubik and Kuparuk D interval, and just above the Lower Cretaceous Unconformity (LCU). The Nanuq-Kuparuk gross interval is located below the Nanuq reservoir between approximately 7062-7072 feet SSTVD as shown on the Nanuq #3 well log (Figure 6). Overlying the Kuparuk sand is approximately 280 feet of shale-rich lithology. The lower 120 feet is comprised of dark grey Barremian-aged mudstone of the Kalubik and Kuparuk D intervals. The upper 160 feet is comprised of brown, organic rich shale of the Albian-aged HRZ interval. The Kuparuk sand is underlain by approximately 250 feet of silty, black shale of the Valanginian Miluveach interval. Page 9 ConocoPhillips Alaska, Inc. Application to the AO. for the Nanuq Area Injection Order . Colville River Field September 13, 2005 20 MC 25.402 (c)(6) Description of the Formation The Nanuq reservoir matrix consists of fine-grain sandstone with interbedded shales of variable thickness. The target net interval is defined by a likely gas-oil contact at 6100 feet SSTVD, and a water-oil contact at 6207 feet SSTVD. Log and core data confirm the oil-water contact. A gas-oil contact, estimated at 6,100 subsea TVD, is based on the oil-up-to in the Nanuk #1 well (6,104 subsea TVD), the CD1-229 (nee NQ1) well test and production log. Porosity averages approximately 16% and permeability averages approximately 5 md. Average water saturation above the water-oil contact is approximately 32%. Analysis of well test fluid from the Nanuk #2 well indicated a reservoir fluid viscosity of approximately 0.47 centipoise, and separator tests yielded solution gas:oil ratio of 920 SCF/STB, and a formation volume factor of 1.46 RB/STB. The crude oil produced during the Nanuk #2 test had a gravity of 39° API. Original reservoir pressure is approximately 2740 psi. Reservoir temperature is 135°F. The Nanuq-Kuparuk reservoir is thin, with a maximum gross thickness of 12 feet observed to date. The Nanuq-Kuparuk reservoir matrix is fine- to medium- grained, quartz-rich sandstone that contains varying amounts of glauconite. The Nanuq-Kuparuk reservoir is similar to the Kuparuk C Sands developed from Drill Site 3S (Palm) in the Kuparuk River Field. The Nanuq-Kuparuk sandstone has these average properties: approximately 22% porosity, 200 md permeability, and 15% water saturation. No gas or water contacts have been identified in the Kuparuk reservoir. Based on combined reservoir fluid samples and subsequent flow tests performed on the Nanuk #2 exploratory well, the crude contained in the Kuparuk reservoir is very similar to that contained in the Nanuq reservoir, with only slight differences in API gravity, solution gas-oil ratio, and bubble point. For numerical simulation modeling purposes, the Kuparuk and Nanuq reservoir fluids were assumed to have the same pressure-volume-temperature (PVT) properties. No gas or water contacts have been identified to date for the Kuparuk reservoir. The original reservoir pressure is approximately 3240 psi. Reservoir temperature is 160°F. Page 10 ConocoPhillips Alaska, Inc. Application to the AO. for the Nanuq Area Injection Order . Colville River Field September 13, 2005 20 MC 25.402 (c)(7) Loqs of the Injection Wells Typical well logs for proposed injection wells are shown in Figures 3 and 4. Page 11 ConocoPhillips Alaska, Inc. Application to the AO.C for the Nanuq Area Injection Order . Colville River Field September 13, 2005 20 MC 25.402 (c)(8) Casinq Description and Proposed Method for Testinq All underground injection into the proposed Nanuq and Nanuq-Kuparuk Oil Pools will be through wells permitted as service wells for injection in conformance with 20 AAC 25.005, or approved for conversion to service wells in conformance with 20 AAC 25.280. A typical well schematic is included as Figure 7. The Nanuq Oil Pool and Nanuq-Kuparuk Oil Pool will be accessed from wells directionally drilled from a gravel pad utilizing drilling procedures, well designs, casing and cementing programs consistent with current practices in other North Slope fields. For proper anchorage and to divert an uncontrolled flow, 16-inch conductor casing will be drilled and cemented at least 75 feet below pad. Cement returns to surface will be verified by visual inspection. A diverter system compliant with the Commission requirements may be installed on the conductor. Primary, secondary, and general well control for drilling and completion operations will be performed in accordance with 20 AAC 25 Articles 01 and 06. Casing and cementing will be performed in accordance with 20 AAC 25.030. Surface casing, cemented to surface, is planned at approximately 2500 feet true vertical depth. Intermediate hole will be drilled to the target formation and production casing will be cemented with the shoe in the target formation. Formation integrity tests are planned after drilling 20 to 50 feet beyond the surface casing shoe and the production casing shoe. The production casing will be cemented with such a volume to protect any significant hydrocarbon zones. Production and injection holes will be horizontally drilled beyond the casing shoe in the target sand. Slotted liners are planned in the production and injection holes for both reservoirs. To prevent hole collapse, blank pipe liners are planned where the production/injection holes cross significant non-pay, shaley intervals. Tubing and packer or other equipment will be run to isolate pressure to the injection interval consistent with 20 AAC 25.412, but the maximum spacing of 200 feet measured depth between the pressure isolation equipment and the top of the injection zone should be waived to accommodate efficient logging of the horizontal injectors. Casing-tubing annulus pressures will be monitored during injection operations in accordance with 20 MC 25.402(e). Automated monitoring of injection rates, tubing and casing-tubing annulus pressures is planned. Significant deviations or aberrations in pressures or rates will be communicated to the Commission. Prior to commencement of injection, each injection well will be pressure tested in accordance with 20 MC 25.412(c). In the event pressure observations or tests indicate communication or leakage of any tubing, casing, or packer, ConocoPhillips will notify the Commission within 24 hours of the observation to obtain Commission approval of appropriate corrective actions. Commission approval will be received prior to commencement of corrective actions unless the situation represents a threat to life or property. Page 12 ConocoPhillips Alaska, Inc. Application to the AO.C for the Nanuq Area Injection Order . Colville River Field September 13, 2005 20 AAC 25.402 (c)(9) Injection Fluid Analysis and Injection Rates Initially, Beaufort Sea water and miscible injectant (MI) will be injected. Seawater has been tested in core flood studies and was found to be compatible with the proposed Nanuq Oil Pool injection zone. By analogy to the Kuparuk River Unit, seawater is compatible with the proposed Nanuq-Kuparuk Oil Pool injection zone. Later in the field life, produced water will also be re-injected. The anticipated MI composition available from the ACF is: Component Mol Fraction H2O 0.0001 CO2 0.0056 Nitrogen 0.0098 Methane 0.6276 Ethane 0.1106 Propane 0.1560 i-Butane 0.0271 n-Butane 0.0517 Pentanes 0.0095 C6+ 0.0020 Injection rates will be managed based on voidage for both reservoirs. Individual well injection rates will vary according the reservoir properties encountered. Injection of MI and water will alternate in each injection well. The maximum expected and average injection rates are: Maximum MI Rate Average MI Rate Maximum Water Rate Average Water Rate (MSCFD) (MSCFD) (BPD) (BPD) Nanuq 10,000 5,000 5,000 1,000 Nanuq-Kuparuk 16,000 5,000 15,000 5,000 Small amounts of Class II fluids will be blended with seawater and produced water for injection. These Class II fluids include: sump fluid, hydrotest fluid, rinsate generated from washing mud hauling trucks, excess well work fluids, and treated camp waste water. Page 13 ConocoPhillips Alaska, Inc. Application to the AOa for the Nanuq Area Injection Order . Colville River Field September 13, 2005 20 AAC 25.402 (c)(10) Estimated Pressures The MI pressure available from the ACF is expected to be approximately 4000 psi. Due to pressure losses in the distribution system, wellhead injection pressures are expected to be 3800 psi with MI. Injection wells may be choked to lower wellhead pressures to manage injection rate. The seawater injection pressures from the ACF pump discharge are expected to average approximately 2500 psi. Due to pressure losses in the distribution system, wellhead injection pressures are expected to be 2400 psi with water. Injection wells may be choked to lower wellhead pressures to manage injection rate. Page 14 ConocoPhillips Alaska, Inc. Application to the AoA for the Nanuq Area Injection Order . Colville River Field September 13, 2005 20 AAC 25.402 (c)(11) Fracture Information Modeling of the proposed Nanuq Oil Pool indicated injection fluids will remain within the target Nanuq sands. To help refine the Nanuq sand fracture model, a history match the Nanuk #2 well stimulation was performed. Several pre-frac injection tests were conducted prior to the main Nanuk #2 frac. Pressure-rate behavior was analyzed to determine in-situ stress and other reservoir properties. Digital log data from the Nanuk #2 well were processed to estimate elastic properties and in-situ stress. Actual bottomhole pressure and rate data were input to a fracture simulator and the derived rock properties and stresses were used to simulate frac performance of the Nanuk #2 well. The model of the Nanuq #2 stimulation indicated height growth occurred throughout the Nanuq sands. Maximum water injection pressure will exceed the parting pressure of the Nanuq reservoir rock. Under long term water injection conditions at maximum injection pressure, the fracture model indicated that the fractures will not propagate through the shales of the Torok formation above and below the Nanuq reservoir. The proposed Nanuq-Kuparuk Oil Pool Kuparuk C Sand, and the Kalubik and Miluveach shales above and below the Nanuq-Kuparuk are similar to those same intervals in the Kuparuk River Unit (KRU). Extensive analysis and experience with water and gas injection in the KRU at comparable rates and pressures provide evidence that proposed injection in the proposed Nanuq-Kuparuk Oil Pool will not propagate fractures through confining zones. Mechanical properties estimated from the Nanuk #1 and #2 well logs were used with a fracture simulator to model water injection of the proposed Nanuq-Kuparuk Oil Pool. Maximum water injection pressure will exceed the Nanuq-Kuparuk reservoir rock parting pressure. Fracture modeling of long term water injection indicated containment by the Kalubik/Kuparuk D and the Miluveach intervals. Fracture modeling reports are attached. Page 15 ConocoPhillips Alaska, Inc. Application to the AOa for the Nanuq Area Injection Order . Colville River Field September 13, 2005 20 MC 25.402 (c)(12) Quality of Formation Water The formation fluids within the proposed Nanuq Oil Pool includes water below a depth of 6207 ft SSTVD. Formation water was sampled from the Nanuk #2 well during its post frac production test in April, 2000. The Nanuk #2 produced water analysis indicated this composition: Sodium Potassium Calcium Magnesium Bicarbonate Sulfate Chloride 7,000 ppm 150 ppm 200 ppm o ppm 800 ppm o ppm 10,600 ppm An oil-water contact within the proposed Nanuq-Kuparuk Oil Pool has not been observed. Petrophysical evaluations were carried out using the KRU field assumption for water salinity (0.27 ohmm @ 75°F; TDS of 23,000 ppm NaCI) with results very comparable to core data. As an alternative, we also calculated apparent water salinity in the underlying Miluveach shale. Based on the Nanuk #1 well which has better hole and data quality in the Miluveach, standard modeling results in Rwa of 0.124 ohmm @ 160°F, for a salinity of 24,000 ppm NaCI equivalent. Page 16 ConocoPhillips Alaska, Inc. Application to the AO. for the Nanuq Area Injection Order . Colville River Field September 13, 2005 20 AAC 25.402 (c){13) Aquifer Exemption Reference No underground sources of drinking water (USOW's) exist beneath the permafrost in the Colville River Unit area. See Area Injection Order 188 (October 7, 2004) conclusion 3 for a portion of the area of interest for this application: Umiat Meridian T11N R4E Sections 1,2,3,4,5,7,8,9,10,11,12,13,14,15, 16,21,22,23,24,25,26,27; T11N R5E Sections 1,2,3,4,5,6,7,8,9,10,11,12,13,14, 15,16,17,18,19,20,21,22,23,24,29,30. Surface casing for all development wells for the proposed Nanuq and Nanuq- Kuparuk Oil Pools are planned within the affected area of Area Injection Order 188. Annular disposal of drilling waste is planned at Orill Site C04 after authorization under 20 AAC 25.080. Page 17 ConocoPhillips Alaska, Inc. Application to the AO. for the Nanuq Area Injection Order . Colville River Field September 13, 2005 20 MC 25.402 (c)(14) Incremental Hydrocarbon Recovery The Nanuq CD4 Project will employ a miscible water-alternating-gas ("MW AG") process to maximize ultimate oil recovery by miscible displacement of reservoir fluids. This process consists of a multiple-contact miscible displacement of reservoir oil. The MI contacts oil not swept by water injection, and mixes with that oil so that it becomes mobile. This mobilized oil is then pushed to production wells by subsequent alternating slugs of injected MI and water. Through this miscible displacement process, the residual oil saturation is reduced to very low levels in the swept pore volume, with the mobilized oil displaced to the producing wells. By alternating between the injection of MI and water, gas and water interaction in the pore space improves reservoir sweep efficiency by reducing the effective mobility of the MI. The injected water helps maintain reservoir pressure, retards gravity segregation of the MI, and controls gas channeling. By combining the mobilization of unswept oil by the miscible displacement process with the sweep efficiency enhancement of alternating gas and water injection, the MW AG displacement process results in more than an insignificant increase in ultimate crude oil recovery, compared with waterflood alone. For the Nanuq reservoir, incremental waterflood recovery is expected to be 10 to 15% of original oil in place (OOIP) above primary recovery, and numerical compositional simulation supports an incremental recovery factor over waterflood of 9 to 14% OOIP for the enriched hydrocarbon miscible gas alternating with water (MWAG) process. For the Nanuq-Kuparuk reservoir, incremental waterflood recovery is expected to be 25 to 37% OOIP above primary, and numerical compositional simulation supports an incremental recovery factor of 17 to 25% OOIP for the enriched hydrocarbon miscible gas alternating with water (MWAG) process. Numerical simulation, tuned to laboratory experiments and PVT modeling, demonstrated that the ACF MI composition is miscible with Nanuq and Nanuq- Kuparuk crude oil at initial reservoir conditions, and will significantly reduce residual oil saturations below waterflooding. An equation-of-state ("EOS") fluid model was created and validated against laboratory measurements of the Nanuq crude oil PVT properties. This EOS was tuned to predict the phase behavior of mixtures of crude oil with a variety of hydrocarbon gas compositions. Slimtube simulation results show that ACF MI composition is miscible with Nanuq and Nanuq-Kuparuk crudes, with a minimum miscibility pressure (MMP) of approximately 2400 psi (Figure 8). Based on historical performance, MI composition may vary, such that the MMP may vary from 1900 to 2600 psia. The Nanuq CD4 Project will be operated so that the average reservoir pressure will be maintained at 3000 psi, significantly above the MMP. Page 18 ConocoPhillips Alaska, Inc. Application to the AO'C for the Nanuq Area Injection Order . Colville River Field September 13, 2005 20 MC 25.402 (c)(15) Mechanical Condition of Wells Within %. Mile of Proposed Area Four wells as shown in Figure 2 penetrate the proposed injection intervals, both Nanuq and Nanuq-Kuparuk within %. mile of the the injection area: Nanuk #1, Nanuk #2, Nanuq #3, and Nanuq #5. Reports are attached for each of the four wells. Nanuk #1 and Nanuk #2 have been plugged and abandoned. Nanuq #3 and Nanuq #5 were drilled to total depths beyond the injection intervals, cased and suspended. CPAI plans to apply to the Commission to sidetrack the Nanuq #3 and Nanuq #5 well to use as Drill Site CD4 development wells. All four of the wells penetrating the proposed injection intervals have sufficient mechanical integrity to prevent any flow such as cross flow from an injection interval to other intervals. Several Alpine development wells have bottomhole locations penetrating the Alpine Oil Pool near the proposed Nanuq injection area. But, these Alpine wells penetrate the Nanuq and Nanuq-Kuparuk zones above the production casing shoe, more than %. mile from proposed injection wells. Page 19 ConocoPhillips Alaska, Inc. Application to the AOGCC for the Nanuq Area Injection Order September, 2005 Colville River Field Figure 1: Proposed Area for Nanuq and Nanuq-Kuparuk Oil Pools and Area Injection Order{s) Colville River Unit --1 '"I r t CD3 . q Alpine PA r---, J r' J CD1 r - II! CD2 , L I ~ . L- ., L .' I Proposed Affected Area For Nanuq Area Injection Order(s) . ... .. Preliminary Nanuq Participating Area .... - Application to the AOGCC for the Nanuq Area Injection Order Colville River Field September, 2005 Figure 2: Planned Development Wells for Nanuq Oil Pool and Nanuq-Kuparuk Oil Pool \ ~ ~~;p:: \ - CD1 pad-\\ . Typical Nanuq Penetration Typical Kuparuk Penetrati n Nanuq # CD4 Pad . ...... Future Nanuq-Kuparuk Injector Future Nanuq-Kuparuk Producer Future Nanuq Injector Future Nanuq Producer Existing Alpine Well Existing Nanuq Well ~ STRTUTE MILES ¡;¡ . . . 1". 0 S T R T UTE MIL E 5 . Application to the AOGCC for the Nanuq Area Injection Order Colville River Field .. c: o .- .. CO E .... o u. ~ o .... o I- " .. - CO ~ (1) .. c: - C'" ~ c: CO Z " September, 2005 Figure 3: Nanuq Type Log Nanuk #2 o GR GAPI L ,- , ~ ~,I -~ ..,j. :< '. ~?'I " " ,. I - ~ : ¡ :ë jÞo! j ....1 ~ ...1.. " ....1". N JJ I, ~ .. .. ~ ." ....... .. - ....P '" "] .( !~i- :~ - ;:æ!Þ ;f t -r I ..c ..!---J '" ... ì' oc -; ~ ... Depth 150 MD 1 Resistivity OHMM 100 7020 Top Nanuq . 7040 7060 7080 7100 7120 7140 7160 . 7180 7200 7220 Base Nanuq 7240 7260 Application to the AOGCC for the Nanuq Area Injection Order Colville River Field E u. ~ ~ L- eo Co ~ ~ Kuparuk D . Interval Kuparuk C Interval E u. J: U eo (I) > ~ - .- :E Figure 4: Nanuq-Kuparuk Type Log Nanuk #2 GR GAPI 150 Resistivity OHMM 100 7940 7960 7980 8000 8020 September. 2005 . Top Kuparuk C Base Kuparuk C, (LCU) . Application to the AOGCC for the Nanuq Area Injection Order September, 2005 Colville River Field Figure 5: Nanuq Log Model ~' ~ w u z CAlCS.VCl GR 4 II! o~--vÑ~--~ æt; CAlCS.NET f'A-¥!_i:2 6 0 )H.GR_AIT _5_1 20 GAP! 120 Nanuq #2 CORE _A~Al YS::J~.Rr OB_5D('U!JANlIQCCSYVT _ 1 1 MD 100 1.6G>/C3.65 1 VN 0 :AlCS.PIÐH.NF HIS_CN,T _SS:;Al CS.SVV1f_4 1 MD 10060Pu·S 0 1 0 C H.AF1 ~ORs-ð ~Al.YS~OR~_A C;RE,A'J¿l Y~I;;.SVVR_1 1 OHMM 100 40 PCT 0 lOOPeT 0 loopcr 0 OH.RD_1 þÄl.CSpHIT~4! CA~CSSW J_4 OHMM 100 0.4 0 1 VN 0 . . Application to the AOGCC for the Nanuq Area Injection Order Colville River Field Figure 6: OH.GR_MWD_S_1 20 GAPI 120 PALMq££~Y~_AG_1 6 0 t o >f- t-w cnw cnu- 7060 7070 September, 2005 Nanuq-Kuparuk Log Model Nanuk #3 .I:. - Q.f- Q)W o~ cœE ANAL YSISPERM HO" CORE ANAL YSISSWR - * MO *" 1000 100 *" PCT * :ORE ANAL YSIS,PHI OB1500 Ir,:. ~* p'; ~ * - 0...... PALMCC.VCl GR 1 - ----V;------"';' PALMCCPERM_1 MD PALMCC,SW_1 10001 VN PALMCC,VCGS_1 . OHRPS_MWD_S_1 OH I.JPHIS EDITED 1) VN" __ ";' " - _~__,,4.'" PALMCvC,,,.VCG ;=~,. 1000 ~_.._,,,.,,_,"..,,f~ _._.'""~ c':r- . ¡I""T'H'" OH,RHOB MW"~..:¡;2.¿~_,,_~ . . PALMCC:~HíT~~("'l~~'~ 10002 GIC3 :) 1 VN r QHMM OH.RPD_MWD_S_1 OHMM 8530 . 8540 8550 Application to the AOGCC for the Nanuq Area Injection Order Colville River Field Figure 7: Typical Injection Well Schematic .oil H1¡¡ I:::: ::;:'. ::::: ~ 16" Conductor to 114' II :1::; :;i,: ~~~~~ 3_~tI or 4-%" Cameo DB Nipple at 2000' TVD :;:!: "" with differential pressure-controlled SSSV :;::: ;i;i; ¡iii, ::ii: "iii. 9-5/8" 36 or 40 ppf L-80 BTC Surface Casing @2500' TVD cemented to surface 3-W' or 4-%" L-80 IBT M tubing Liner top packer and hanger wI PBR =-=--===-=- -=1 Top Reservoir Nanuq @ 6200'TVD Kuparuk @ 7100'TVD 4-1/2" L-80 BTC 7" 26 ppf L-80 BTC Mod slotted liner Production Casing @+I- 85° September, 2005 . . Application to the AOGCC for the Nanuq Area Injection Order Colville River Field September, 2005 Figure 8: Nanuq CD4 Project Simulated Slimtube Recovery Results 1 - .u 0.9 - u 0.8 - .- .= 0.7- > ~ 0.6 _. m ~ @ 0.5- ~ ~ 0.4- o ~ 0.3- 0.2 - 0.1 -. o o J I I I - I I I I I I I I I I o o IJ') o o IJ') ~ o o o C\I o o o ~ +- . ... . _ f- . U: . u m __".._'.__n___..___ Nanuq CD4 Project MI composition is désigned for 2400 psi minimum miscibility pressure. J I I ¡ ¡ I J I I I I I I I I I I I I I J I I o o IJ') C\I o o o ('V') o o o ""'" o o IJ') ('V') o o IJ') ""'" o o o IJ') o o IJ') IJ') Pressure, psia I I I I . . o o o (0 . . Fracture Containment Modeling Nanuq Interval Jack Walker July, 2005 . Nanuq Interval Fracture Containment Modeling . July 2005 Summary Fracturing the Nanuq interval with injection water and miscible injectant was modeled with Mfrac software 1. The Alpine injection system has the capability of exceeding the parting pressure of the Nanuq reservoir rock on both water and gas injection. However, insitu stress contrast is adequate to confine fractures initiated in the Nanuq sands. The modeling indicated that fractures caused by gas injection will not grow throughout the Nanuq interval due to intra-interval stress contrasts. Water injection could fracture the entire Nanuq interval. Upward fracture growth for both water and gas injection will be arrested in the siltstone above the Nanuq sands. On water injection the base of fracture growth will be within 20 feet of the base of the Nanuq interval. Analvsis Mechanical properties were calculated from open hole logs (Ramos 2002l and tuned to the actual fracture data collected in Nanuk #2. Nanuk #2 fracture G- function analysis indicated a closure pressure gradient of 0.515 psi/foot (Barree 2004f Instantaneous shut in pressure suggested the fracture extension pressure gradient is 0.555 psi/foot. Based on mechanical property trends, the Nanuk #2 Torok Formation was divided into 18 subintervals between 5830 and 6420 feet subsea, including the productive sands. Mechanical properties were averaged over these subintervals. Figure 1 shows the mechanical properties plotted with depth. At a depth of approximately 6177 feet (true vertical), the fracture closure pressure, or minimum horizontal stress, is 3181 psi and fracture extension pressure is 3428 psi. Maximum surface delivery pressures are expected to be 2400 psi for water and 3800 psi for miscible injectant. Ignoring friction pressure drop, these maximum surface pressures translate into bottomhole injection pressures of 5100 psi and 4700 psi for water and gas, respectively. The injection system is capable of delivering water and gas at pressures exceeding the parting pressure. However, the model indicates that maximum injection pressures will be lower than the maximum facility capacity because permeability of the formation allows leakoff of injection fluid at a high rate. Figure 1 shows the stress gradient, stress, modulus and Poisson's ratio input for the fracturing modeling. 2 . Nanuq Interval Fracture c..;ontainment Modeling ,,:: Stress Gradient .-. c:: -- ,-..., ~2=:) '""" ? . July 2005 _____'C"____ _,..,,__,______,__~____._,~._..._'_._ 2Ht-~ 4...C··:, ')2 ') j ). ï~.'))J ~;:,""-', 4~"~-:' .:' (psilft) (psi) Stress Young's 1\'fodulus Poisson's Ratio Figure 1 Mechanical Properties Nanuk #2 (psi) )3 ),4 Mfrac was run using 1 % KCI water as a substitute for seawater. Miscible injectant properties were created and named MGAS in the Mfrac fluid library. Leakoff was manually calculated based on reservoir and fluid properties4. Permeability, relative permeability and fluid viscosities were taken from Nanuk #2 core and fluid studies. High injection rate (7200 BPD for water, 15 MMCFD for M I) was chosen to model greater than planned injection pressure and greater stress on confining layers than that likely to be encountered during planned operations. The modeled rates are 150% of the maximum planned rate. The specific injection rate per foot of interval for the vertical well fracture model was approximately more than 50 times greater than the expected specific injection rate of less than 1 BPD per foot of interval open in the planned horizontal injectors. The much higher than expected rate was modeled as a conservative approach to ensure induced fractures will be confined. Perforations with large flow capacity were chosen to model low pressure drop. A vertical well frac was modeled with 1000 perforations (1 II diameter) over the entire Nanuq interval. Water and gas cycles were run at the same injection rate for a cumulative injection volume of 2.5 million barrels. The fracture geometries with vertical stress profiles are shown in Figures 2 and 3 for the water and gas cases, respectively. 3 . Nanuq Interval Fracture Containment Modeling Stress ð4~:'D ;,4:" ;~');-' ~:,:-, _1oL~!t1: 11,- i ~. I II ,;, ¡ .~; I ~-go-ç, B!1 "', III'" -~-I!!!I;; 11M -; . July 2005 \Vidth Profiles ~----~_._-_. 4':-'::) .... -' _ >:: Stress (psi) Figure 2 Water Injection Case Fracture Geometry Stress ~ > ~m Stress (psi) _~'~ L~~!b 110 11I120 1140 go-ç, J!!!!Sé' II!!!! .') "'0< ...... . -II" -¡ i ..'),-'.;; ).v·:· D. ¡') \Vídth (i.11.) \Vidth Profiles i mm+. ¡ ! --., - ------------+---------- ".'__n_..__·_·_·····_________ _.__.._-_._--_._-,---,-,-,~----,--_.- i I I ·_________·_1 ¡ I i f----- i 1 I 1 -------.---.----- __1____. -...------------.--------.-.---.-~-----.-------- I I i I I I I I ÞJ:-0 -~1J Figure 3 Miscible Injectant Case Fracture Geometry 4 ----.~-~.~--- ....j:-:::: J'~3 J1'J \Vidth (in.) . . July 2005 Nanuq Interval Fracture Containment Modeling Conclusions 1. Fracturing the Nanuq sands is possible with the delivery pressure and rate expected to be available at Drill Site CD4. Without choking injection, fracturing will likely occur on water and gas injection. 2. Fracture growth will be confined by the siltstone above the Nanuq sands. 3. The fracture model indicated that fracturing induced by miscible injectant will not grow through inter-lobe mudstones. 4. The fracture model indicated that water fracturing in a vertical well will grow throughout the Nanuq interval and will be arrested in the shaley interval immediately below the Nanuq interval. 1 Meyer & Associates, Version 5.2.1209, Natrona Heights, PA 2 Ramos, R., Nanuk2.mechpro.v2.xls 3 Barree, R. D., "ConocoPhillips Nanuq Fracture Treatment Designs", August 2,2004 4 Gidley, et. aI., Recent Advances in Hydraulic Fracturinq SPE Monograph Volume 12,1989, pp. 147-157 5 . . Fracture Containment Modeling Nanuq-Kuparuk Interval Jack Walker July, 2005 . Nanuq-Kuparuk Fracture Containment Modeling . July 2005 Summary Fracturing the Nanuq-Kuparuk interval with injection water and miscible injectant was modeled with Mfrac software 1. The Alpine injection system has the capability of exceeding the parting pressure of the Nanuq reservoir rock on both water and gas injection. However, insitu stress contrast is adequate to confine fractures initiated in the Nanuq-Kuparuk sands. Analvsis Mechanical properties were calculated from open hole logs (Ramos 2002)2. Based on mechanical property trends, the Nanuk #2 Kuparuk River Formation and surrounding shales were divided into 7 subintervals between 6350 and 7330 feet subsea, including the productive sands. Least principle stress and Poisson's ratio were averaged over these subintervals. The modulus was taken from the Nanuk #1 log3. Figure 1 shows the mechanical properties plotted with depth. At a depth of approximately 7092 feet (true vertical), the fracture closure pressure, or minimum horizontal stress, was estimated from logs to be 4111 psi. Maximum surface delivery pressures are expected to be 2400 psi for water and 3800 psi for miscible injectant. Ignoring friction pressure drop, these maximum surface pressures translate into bottomhole injection pressures of 5500 psi and 4800 psi for water and gas, respectively. The injection system is capable of delivering water and gas at pressures exceeding the parting pressure. However, the model indicates that maximum injection pressures will be lower than the maximum facility capacity because permeability of the formation allows leakoff of injection fluid at a high rate. Figure 1 shows the stress gradient, stress, modulus and Poisson's ratio input for the fracturing modeling. 2 . Nanuq-Kuparuk Fracture Containment Modeling Stress Gradient .:$J - _ .~_ ~ _ _:.. . l_ .; _ ~ _ _~. .. ..;..,..,..l.,. .'..'.. I , ) ' , , , I , : õ»¡ .~-r'-:j~-.:~~t1:-t:t:- ~ - ~ - ~- -:- ~ - ~ - ~- -~- .. ' . ~..:.. l, . ~.~. .:.. õZ)¡ .. .,' . ",:, M.. ,l. ~,: Hj~,~ : I .r'" õ")J ::: :::: :Ht:p r , " " , , , , 1 ; ; õ6)J::::I:::r::="~: ~ ¿¿,,¡ ::~:L;:lU.·~: : : ' ! " , --r--,- -;-"1 -,--,-- 1 ,¡ , - -.,. -..., - -,- - r ' - ., - -,- - - - .. -< - -,- ~ - .., - .o.j - -- ~ - 'œ() , ' _.'_..1__'__;,,_-,_"'!__,--_ 1 , , ; I , , t:J;;;;';;';~;;;';;~;;; , ! " - - + - -,: --:- - ~, - - -: - -:~ - 72:N '- , , , I , . , i ' r ' ---r---,--"--r -, ""--1-- , , ; , I , -~ - .., - .,- - i ~ - .., - - r' - - - ... - ~ - -1- _ ¡- '-i _ ., _ _,~ - "";0 ."\.1 '-6 (psi'ft) Stress '1;3~,)jQ "m (p si) Figure 1 Mechanical Properties Nanuk #2 . July 2005 .Young's ~,irodulus Poisson's Ratio " H~""'il;'_u, uu·u <-LiCu ... H~,' __"pk'~'H .:..... ... .X~. .i.....i--.... -- -;-.- ----;-------- - -- ---~-- --------~-~--- " ,. 1 .-----,----- , -,------ 0- - ..,---- I ,---- , " " ¡ ,- " , , ", - ~ ~ - - -.- - - - - - - - - - - - - - r - - T - - - - - T - - - 3 , , · - - - - - ,. - - - - -..- - - - - - T - - - - - , , , · - - - - - ~ - - - - - ,~ - - - - - ~ - - - - --...--"--..---..... - - --~~--;--- -7-----'7-- -.. , , , - - - - - - - - - - - - - - - - ~ - - - -- , , , , , ------¡"-- -r-----r----'- · ~ - - - - - - - - - ..- - - - - - T . - .. - - · - .. - - - .-.... - - ... - . - - + - ~ .....~ d ..--...;,1~ ~~::::~~::::f':"f¡':::; " )---- -T- -- 1 , - - - - - - r - - ~ - - -, - - . T - - - - - , , - - -' - ... ~ - - - '" - .. - - , , '''.:>5 ,¡ " J.' ,- . - ~ .. - ..'- - - - - - -r - - - - - - - --, - - - ."... - -. - - - - - - ..,- - - - --- -. ---\---- -_..-- -,-..---- ._----'- -- ---------- -- '----------------------- . , ----- --,---- . - - -..,.... ~ - - - - - - - - -,- - - '-- --:---------- -,------- --- Mfrac was run using 1 % KCI water as a substitute for seawater. Miscible injectant properties were created and named MGAS in the Mfrac fluid library. Leakoff was manually calculated based on reservoir and fluid properties4. Permeability, relative permeability and fluid viscosities were taken from Nanuk #2 core and fluid studies. - - - - - - '- - - - - - ~ - - -,- - - - - - t;;;;:;:; ;,;:;:;;:;;; =,............. _,r...t-U;;;;; , . - ~ - - - - - - - - - - - - - - - - - --- --,--- ----- --,---_... -~ - - - - - - - - - - -,- - - -- ~))J J (psí) High injection rate (7800 BPD for water, 17 MMCFD for MI) was chosen to model greater than planned injection pressure and greater stress on confining layers than that likely to be encountered during planned operations. The modeled rates are 150% of the maximum planned rate. The specific injection rate per foot of interval for the vertical well fracture model was approximately more than 50 times greater than the expected specific injection rate of less than 1 BPD per foot of interval open in the planned horizontal injectors. The much higher than expected rate was modeled as a conservative approach to ensure induced fractures will be confined. Perforations with large flow capacity were chosen to model low pressure drop. A vertical well frac was modeled with 1000 perforations (1" diameter) over the entire Nanuq-Kuparuk interval. Water and gas cycles were run at the same injection rate for a cumulative injection volume of 2.5 million barrels. The fracture geometries with vertical . Nanuq-Kuparuk Fracture Containment Modeling . July 2005 stress profiles are shown in Figures 2 and 3 for the water and gas cases, respectively. Stress ""' ,:::: > :- n:? 7";"::) 4::=,} \Vidth Profiles - :':$L:::æ:é: 11I;'- 11II-" I!I-v., ----~ iii ;C· Iii 3:' 11II ;C' -- u u _!!II ;j ~C. ;; - - - ~ - - - - - - - - - -------------- -- 44':C, Stress (psi) Figure 2 Water Injection Case Fracture Geometry Stress -= ?- 7,;,;) '::-::0) 4.:1':0 48·:D -::_ :-'j }-):< .-,'".; .-.- \Vidth (in.) Width Profiles _ %L~nh .C' - .1{! .'0 -Ii;.o iii SD t III ". t I :::::::=~ :::::::::~::::::::r::::::::::::- , ~_____u!... ~.__.__ I _ __1__ -------------j i I t I i i I I --- -·-·-----·---t--·"- .---.-.-..-------'- -.------..-""'-"'..-..-..-.-~.,--.-,--- -- T I ____...J____ i t i I 4~'::-) --,J. :>J .'..::; 0. ~:! ..:~.'~5 ,- Stress (psi) Figure 3 Miscible Injectant Case Fracture Geometry \Vidth (in.) 4 . Nanuq-Kuparuk Fracture Containment Modeling . July 2005 Conclusions 1. Fracturing the Nanuq-Kuparuk sands is possible with the delivery pressure and rate expected to be available at Drill Site CD4. Without choking injection, fracturing will likely occur on water and gas injection. 2. Model~ing indicates that fracture growth will be confined by the Kalubik / D shale above the Nanuq-Kuparuk sands for both water and gas injection 3. Modeling indicates that fracture growth will be confined by the Miluveach shale below the Nanuq-Kuparuk sands for both water and gas injection 1 Meyer & Associates, Version 5.2.1209. Natrona Heights, PA 2 Ramos, R., Nanuk2_Dipole_Stress_contrast.xls, 2005 3 Chin, L., Enderlin, M., Ramos, R., "Rock Mechanics Strength Tests and Analysis Kuparuk Interval, Fiord Alpine Satellite, WNS". May 26,2004 4 Gidley, et. aI., Recent Advances in Hvdraulic Fracturinq SPE Monograph Volume 12, 1989, pp. 147-157 5 . STATE OF ALASKA . . ALASKA Oil AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1 Status of Well Classification of SelVice Well Oil D GAS 0 2 Name of Operator ARCO Alaska, Inc 3 Address P.O. Box 100360, Anchorage, AK 99510-0360 4 location of well at surface SUSPENDED 0 ABANDONED IKJ SERVICE D 7 Permit Number 96-57 8 API Number 50-103-20238 9 Unit or lease Name 2627' FSL, 869' FWL, SEe 19, T 11 N, R SE, UM At Top Producing Interval N/A 10 Well Number SAME At Total Depth NANUK #1 11 Reid and Pool SAME 5 Elevation In feet (indicate KB, OF, etc.) RKB 38' ABOVE SL 12 Date Spudded 12-Mar-96 17 Total Depth (MD+ TVD) 7630' M D, 7630' TVD WILDCAT 16 lease Designation and Serial No. ADL 384211 14 Date Camp. , Susp. or Aband. 3-24-96 Abandoned 115 Water Depth, ¡foffshore 116 No. of Completions NA feetMSl NA 12.0 Depth where SSSV set /21 Thickness of permafrost . NA feet MD =800' NA 13 Date T.D. Reached 19-Mar-96 16 Plug Back Depth (MD+ TVD) 19 Directional SUlVey YES ŒJ NoD 22 Type Electric or Other logs Run lWD: GR, RES, NEUTRON. DENSITY W/l: DSI, CNT, lDT, GR, RFT, MSCT 23 CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD CASING SIZE 'NT GRADE TOP BTM HOlE Size CEMENTÆCORD 16" 62.58# B SURF 107' 20" 230sx AS I 9.625" 53.5# L-80 SURF 1792' 12.25" 325 SXAS III &610 SXAS I 24 Perforations open to Production (MD+ TVD of Top and Bottom and IntelVal, size and number) NA 25. SIZE TUBING RECORD DEPTH SET (MD) PACKER SET (MD) 26 ACID, FRACTURE, CEMENT SOUEEZE, ETC DEPTH INTERVAL (MD) I AMOUNT & KIND OF MATERIAL USED See attached operations summary 27 Date First Production Date atTest Hours Tested PRODUCTION TEST IMethod of Operation (Rowing, gas lift, etc.) PRODUCTION FOR Oll-BBl GAS-MCF TEST PERIOD Ë CALCULATED Oll-BBl GAS-MCF 24-HOUR RATEË NIA WATER-BBl CHOKE Size I GAS-Oll RATIO OIL GRAVITY-API (carr) Flow Tubing Press. Casing Pressure WATER-BBl 28 CORE DATA Brief description of lithology, porosity, fracturas, apparent dips and presence of all, gas or water. Submit core chips. TO BE SENT UNDER SEPARATE COVER BY EXPLORATION GEOLOGY Form 10-407 Submit In duplicate 29. . , 30. . GEOLOGIC MAR<ERS FORMATON TESTS NAME MEAS DEPTH TRUE VERT. DEPTH Include interval tested, pressure data. all fluids recovered and gravity, GOR, and time of each phase. TO BE SENT BY EXPlORATION GEOLOGY 31. LIST OF ATTACHMENTS AS-BUIL T SURVEYS. P&A DIAGRAM. AND DIRECTIONAL SURVEYS AND DAILY DRILLING REPORTS 32. I hereby certify that the foregoing is true and correct to the best of my knowlege. s._ µ ~~ nr. DATE r-" .> --(b'" rt INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (OF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cement- ing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- jection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Form 1 0-407 . . NANUK #1 ACTUAL PLUG AND ABANDON DIAGRAM CASING CUTOFF 3' BELOW GROUND LEVEL WELL IDENTIFICATION PLATE WELDED TO CASING STUB ~///~..'l / / / / / / / / ~.'l /~.~,~ ~(/.////////////% SURFACE CEMENT PLUG 30'-250' ~ ' - ~ BRIDGE PLUG AT 250' r?; ?d 12-1/4" HOLE %% ~.-j :.:.:.:.: 10.2 LBIGAL MUD :.:.fj ,:::'::{::: ,::g.):.j ESTIMATED TOP OF PLUG #4 @ 1615' ,.::.:~.::.::.:::::::::::::::::::::::::::::::::::::::::::::::::::::: .~:~'::':~'::j !1~;;;;~;~;;';:';,~';;;;'cl~¡~ CEMENT RETAINER AT 1715' ~·::¡;::};:::::¡;:::::¡;:::::!t::!t::¡;:::::¡;:::::!;:}(:!;:::::!r"'-:"-:'::::::':'J 9-5/8" SURFACE CSG AT 1792' RKB BASE OF PLUG #4 @ 1900' ):..::~.:..::~.::::~.::::~.::::~.::::~.::::~.:.:::~.::::~.::):::: NOTE: 10.2 PPG KILL WEIGHT MUD PLACED BETWEEN ALL PLUGS 16" CONDUCTOR AT 107' RKB TAGGED TOP OF PLUG #3 @ 3285' I : I I : h 0.2 LBIGAL MUD ~ : I 8-1/2" HOLE . ..... ..... ..... '.:. ',:. '.:. ..... ',:. "':. '.:. ~.:.' .:: :.:::: :.:::: :.:::: :.:::: :.:.-:: :.:::: :.:::: :.:::: :.:::: :.:::: :.:.-:: : ¡~:;~::~;~;~,;~j,{~¡ . i i : : I 11 0.2 LB/GAL MUD ¡ I : : I I 3800'-4100' HYDROCARBON RFARING 70NF - K? BASE OF PLUG #3 @ 4150' ESTIMA TED TOP OF PLUG #2 @ 5735' ':::'::':::'::':::'::':::'::':::'::':::'::':::'::':::'::':::'::':::'::':::'::':: ': ::.:: ::,:: ::.:: ::,:: ::.:: ::,:: ::.:: :::': ::.:: ::.:: ::.:: : 0: ::.:: ::.:: ::.:: ::.:: =:.:: =:.:: ::.:: =:.:: ::.:: ::.:: =:.:: . ':::.::::.::::.::::.:::,'.::::.::::.::::.::::.::::.::::.::: HYDROCARBON ::::.::::.::::.::::.::::.::::.::::.::::.::::.::::.::::.::: 61 4 S' - 6 3 0 0' BEARING ZONE - ALBIAN :~ ~:::::~ ~:::::~ ~:::::~ ~:::::~ ~:::::~ ~:::::~ ~:::::~ ~:::::~ ~:::::~ (::~ ~:::::~ ~ ': ::.:: ::.:: ::.:: ::.:: ::.:: ::.:: ::.:: ::.:: ::.:: ::.:: ::.:: : :: ::.:: ::.:: ::.:: ::.:: =:.:: ::.:: ;:.:: ::.:: ::.:: ::.:: ::.:: : '.:"':"':"':"':"';"':".:-":".:."=".: . ':. ':. ':. ':. ':. ':. ':. ':. .:. ..... .... B;:: ~: :~~: :,2 : ::::" 11111111111117200-7350' ~~E. J-4 BASE OF PLUG #1 @ TD ":"':"':"':"':"':"':"':"':".:.:.:.:.. t:.::,:,:.:.:::.:~~.,,:,:::,::~,::.:::.:J TD AT 7630' MD ~ ARCTIC-SET CEMENTS [:?Em CLASS G CEMENT WITH ADDITIVES . FJ 4/1 3/96 · t c-= STATE OF ALASKA . ALASKA OIL AND GAS CONSERVATION COMMfs$ION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of well Classification of Service Well ouO Gas 0 2. Name of Operator Phillips Alaska, Inc. 3. Address P. O. Box 100360, Anchorage, AK 99510-0360 4. location of well at surface Suspended 0 Abandoned ø Service 0 465' FNL, 864' FEL, Sec. 25, T11 N, R4E, UM (ASP: 377335, 5954678) At Top Producing Interval 1172' FNL, 3718' FEL, SEC 25, T11N, R4E. UM (ASP: 374470,5954017) AfT otal Depth 7. Permit Number 200-030 I 300-118 8. API Number 50-103-20332-00 9. Unit or lease Name Colville River Unit 10. Well Number Nanuk #2 11 . Field and Pool Exploration 1172' FNL, 3718' FEL, SEe 25, T11N, R4E, UM (ASP: 374470, 5954017) 5. Elevation in feet (indicate KB, DF, etc.) 16. lease Designation and Serial No. RKB 28 & Pad 11' ADL 354209 ALK 4700 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., Susp. Or Aband. March 24, 2000 April 1, 2000 5/7/2000 Abandoned 17. Total Depth (MD + TVD) 18. Plug Back Depth (MD + TVD) 19. Directional Survey 9112' MD /8241' TVD 9024' MD /8154' TVD YES 0 No 0 22. Type Electric or Other logs Run Neutron/Density/4_phase Resistivity/GR, PEXlCMR, DSI, FMI, RFT, USIT/GRlCCL, CBL 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD TOP BOTTOM Surface 108' Surface 2219' Surface 9105 115. Water Depth, if offshore N/A feet MSL 120. Depth where SSSV set N/ A feet MD 16. No. of Completions 1 21. Thickness of Permafrost 722' MD CASING SIZE 16" 9.625" 7" WT. PER Fr. 62.5# 53.5# 29# GRADE B L-80 L-80 HOLE SIZE 20" 12.25· 8.5" CEMENTING RECORD AMOUNT PUllED 200 cu ft. 397 sx AS IIIlW, 350 SX Class G 198 sx Class G lead, 245 sx Class G Tail 24. Perforations open to Production (MD + TVD of Top and Bottom and interval, size and number) 25. SIZE cement plug @ 6701' MD set bridge plug @ 334' RKB TUBING RECORD DEPTH SET (MD) 3.5" 6906' PACKER SET (MD) 6791' 7048'-7108' MD 6178'-6238' TVD 7948'-7962' MD 7077'-7091' TVD 5 spf 6 spf 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED 7048'-7108',7948'-7962' FRAC: 293550# of 16/20 behind pipe with 12 ppa on formation. left 2450# prop in wellbore bridge plug: 12.75 bbls AS I cement Plug #1: 113 bbls Class G 27. Date First Production April 19, 2000 Date of Test Hours Tested 4/19-24/2000 133 hrs Flow Tubing Casing Pressure press. 350 Psi 655 28. PRODUCTION TEST Method of Operation (Flowing, gas lift, etc.) Abandoned Oll-BBl GAS-MCF WATER-BBl 869 WATER-BBl 935 CHOKE SIZE GAS-Oll RATIO 48/64 575 SCF/STB Oil GRAVITY - API (corr) 39° Production for Test Period> Calculated 533 306 Oll-BBl GAS-MCF 740 N/A CORE DATA 24-Hour Rate> Brief description of lithology, porosity, fractures, apparent dips and pressence of oil, gas or water. Submit core chips. To be sent under separate cover Form 10-407 Rev. 7-1-80 CONTINUED ON REVERSE SIDE Submit in duplicate 29. . ~= GEOLOGIC MARKERS 30. -- FORMATION TESTS MEAS. DEPTH TRUE VERT. DEPTH Include interval tested, pressure data, all fluids recovered and gravity. GOR, and time of each phase. NAME RFT Tests: see attachment for details refer to attachment Wellbore P&A'd 31. LIST OF ATTACHMENTS Summary of Daily Operations, Directional Survey, Geologic Tops, Time and mud weight chart, memo of abnormal pressure, as-built 32. I hereby certify that the following is true and correct to the best of my knowledge. Signed Title ExPloration Drillinq Team Leader Date Paul Mazzolini Prepared by Sharon Allsup-Drake INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1: Classification of Service wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Form 10-407 I~~;ON~~~ k tr ¿ · ét7~~1~~:/,7~"~_'(ì) calcu~a~ns Chari '. Fite . I By T J ß, i . Date r-)¡!oO , . /" '~;\'\'~.\' 1~;~~.~,ø-~.·.,' "/,,-:,~:~ ,f¡¿..% J J:'i. "p/j.@O.OOO ~r't ~c./()5 \,'~~.'~: ' -d~hr') '~~'<"//-7')'2"" .. .OZC:.yt-; ~."'. . ....,'.... ./..{L~II)~ 'If ) " ~ / I '/', \. "@1/¡C>'·,'./'" 7 'I <, / ~. ¿ 0//1)1-0 I Jt-tdJ!:t:;;.,<",:: < ' . 1 14' 7' /~" ? JZ:r-}7Cj l¡Dje .oz.~¿ 'off 7':.21/"1- Þ !:lJe... 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'''. · STATE OF ALASKA .,; ALASKA Oil AND GAS CONSERVATION CO SSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of well Classification of Service Well Oil 0 Gas 0 Suspended 0 2. Name of Operator Phillips Alaska, Inc. 3. Address P. O. Sox 100360, Anchorage, AK 99510-0360 4. Location of well at surface Abandoned 0 Service 0 7. Permit Number 201-026/301-059 8. API Number 50-103-20365-00 9. Unit or Lease Name 2268' FSL, 574' FEL, Sec.24, T11N, R4E, UM At Top Producing Interval 2129' FSL, 703' FWL, Sec. 24, T11N, R4E, UM (ASP: 373664,5957333) At Total Depth 2151' FSL, 95' FWL, Sec. 24, T11N, R4E, UM (ASP: 373056,5957366) 5. Elevation in feet (indicate KB, DF, etc.) 16. Lease Designation and Serial No. RKS 28 & Pad 15' ADL 380077 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., Susp. Or Aband. 115. Water Depth, If offshore March 1,2001 March 14,2001 3/17/2001 suspended N/A feetMSL '17. Total Depth (MD + TVD) 18. Plug Back Depth (MD + TVD) 19. Directional Survey 120. Depth where SSSV set 9112'MD17646'TVD 5155'MD/4225'TVD YES 0 No 0 N/A feetMD 22. Type Electric or Other Logs Run GRlRes/NeutlDens/Sonic 23. (ASP: 377669, 5957405) Colville River Unit 10. Well Number Nanuq #3 11. Field and Pool Colville River Unit 16. No. of Completions o 21. Thickness of Permafrost 875' CASING SIZE wr. PER FT. GRADE 16' 62.58# H-40 9.625· 40# L-80 7· 26# L-80 CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD TOP BOTTOM Surface 117' Surface 1965' Surface 9092' HOLE SIZE CEMEmlNG RECORD AMoum PULLED 24' 320 sxAS I 360 sx AS Lite & 350 sx Class G 12.25· 8.5· 460 sx Class G & 200 sx Class G 24. Perforations open to Production (MD + TVD of Top and Bottom and interval, size and number) 3.5· TUBING RECORD DEPTH SET (MD)..' 2290' .. PACKER SET (MD) N/A 25. SIZE None 26. ACID, FRACTURE, CEMEm SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED None 27. Date First Production PRODUCTION TEST Method of Operation (Flowing, gas 11ft, etc.) Suspended OIL -BBL GAS-MCF WATER-BBL CHOKE SIZE IGAS-OIL RATIO OIL GRAVITY· API (corr) Date of Test Hours Tested Production for Test Period > Calculated OIL-BBL GAS-MCF WATER-BBL Row Tubing Casing Pressure press. psi 28. 24-Hour Rate> CORE DATA Brief description of lithology, porosity, fractures, apparent dips and pressence of oil, gas or water. Submit core chips. See Attachments Fonn 10-407 Rev. 7-1-80 CONTINUED ON REVERSE SIDE Submit In duplicate -29. .., GEOLOGIC MAR.' 30 .., FORMATION TESTS MEAS. DEPTH TRUE VERT. DEPTH Include interval tested, pressure data, all fluids recovered and gravity. GOR, and time of each phase. NAME K-3 HRZ K-1 4642' 8152' 8449' Annulus left open - freeze protected with diesel. 31. LIST OF ATTACHMENTS Summary of Daily Operations, Directional Survey, Memo of Abnormal Pressure, As-Built, Core description, Final Schematic 32. I hereby certify that the following Is true and correct to the best of my knowledge. Questions? CaD Scott Reynolds 265-6253 s,,,", k~ ~ Title Alpine DrillinQ Team Leader Date S((ø(or Prepared by Sharon Allsu/>,Orake INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1: Classification of Service wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Form 10-407 . . ( Colville River Field ( Nanuq #3 Operations Shutdown . RKB -Gl=43' &-&'8" x r annulus freeze protsc:tad wfth 65 bb( cfiese( ~ apprcx. 1950' MD Toe 0 +/- 4300 Me (500' Me above top K2) Top K2 sand at 4830' MD Bottom K2 sand at 5170' MD Stage Tool set @ 5286' MD . Toe C +/- 6500' MO (600' MD above 7' RMLS Assy) Top Nanuq Reservoir at 7530' MD Top Kuparuk Reservoir at 8543' MD Well TD at9112' MD/7645' TVD (+1-19 deg Inc.) . .. ::..:.::~.::....:::.'~~':~":':./::.~.'. : ;;:~:. ~ .J -. . :.~. ." ,- ~ ............ ...,. ~ -:!: .... ~ ;1 -- .... i~ - ;:::' ~~ ----...;..~ j;: ;~: ~-i :;" ';.~;~ ;'.-: ~:.~..~'.<~.;.~. Rnal Schematic 5/4/01 Wellhead 1 ~ 16- Conductor to 11 T i ,., I 9-518' 40 ppf L-eo BTC .. Surface Casing o 1965' MD /1781'1VD cemented to sutface Tubinq "SuDended wfth ~eseI to 2290' MD Coo1pIetion Tubing Hanger plus 3-1fl", 9.3Mt. Tubing to 2290' MD ·~I "-' ! ~- 'i: i: ',: ,. Top of cement plug @ ----f5155' MD 37.8 bbls of 15.8 PPG. Class G emt w/aclditives Assume 50% excess annular volume. ,. ...1 ~ '" ~ ~ ...:. ~ -~< ".:-::- 7" RMLS Latch Assoo1bt{ o 6985' MD 7' RMLS Latch Assembt{ 08011' MD . f~ 7" 26 ppf L·BO BTC Mod Produclion Casing @ 9092' MD 17626' TVD @ 19 deg . . STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS Description summary of proposal _X Detailed operations program _ BOP sketch _ I Refer to attached morning drilling report for LOT test, surface cement details and casing detail sheets, schematic _ 14. Estimated date for commencing operation 15. Status of well classification as: May 6, 2002 16. If i1:~osal was~erballY proved Oil ~7YVJ ' ~\ ~t~CO) Name ofappro\er Date approved Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 1. Type of request: Abandon Suspend _ Alter casing _ Repair well_ Change approved program _ Operational shutdow~ ~ :( ì Plugging _ \(i) Pull tubing _ 5. Type of Well: 2. Name of Operator Phillips Alaska, Inc. 3. Address P. O. Box 100360 Anchorage, AK 99510-0360 4. Location of well at surface 2342' FSL, 283' FEL, Sec. 24, T11 N, R4E, UM At top of productive interval Development _X Exploratory _ Stratigraphic _ Service (asp's: 377961, 5957475) At effective depth At total depth 671' FNL, 2451' FWL, Sec. 31, T11 N, R5E, UM 12. Present well condition summary Total depth: measured true vertical (ASP: 380560, 5949139) Effective depth: 11735 7128 11735 7128 feet Plugs (measured) feet feet Junk (measured) feet Cemented 11 cu yds Portland Type C 340 sx AS Lite & 240 sx Class G measured true vertical Length 82' 2877' 1 0970' Casing Conductor Surface Production Liner Size 16" 9.625" 7" 158 sx LiteCrete, 69 sx LiteCrete Perforation depth: measured No perforations true vertical No Perforations Tubing (size, grade, and measured depth 4.5" Kill string @ 3038' Packers & SSSV (type & measured depth) No packers, No SSSV 13. Attachments Signed Chip Alvord ~ ¿ CJ¿~ Title: Drilling Team Leader Re-enter suspended well _ Time extension Stimulate _ Variance Perforate_ 6. Datum elevation (DF or KB feet) 32' RKB feet 7. Unit or Property name Other Colville River Unit 8. Well number Nanuq 5 9. Permit number I approval number 202-042 10. API number 50-1 03-20414-00 11. Field I Pool N/A Measured Depth 114' 2909' 11002' True vertical Depth 114' 2393' 7708' RECEIVED MAY 1 4 2002 Alaska Oil & Gas Cons. Gamm¡sslO¡ Anchorage Gas Suspended _XX Questions? Call Vem Johnson 265-6081 Date 5(I2...fol- Prepared by Sharon Allsup-Drake FOR COMMISSION USE ONLY Conditions of approval: Notify Commission so representative may witness Plug integrity _ BOP Test _ Location clearance _ Mechanical Integrity Test _ Subsequent fonn required 10- 40 '-\ App",,'" by o",e, ot the Comm;,sJoo ~ ~ ~. "Lit C AT E Form 10-403 Rev 06/15/88 . ' (~=fOZ-"/ Date 'T/III{)~ Commissioner SUBMIT IN TRIPUCATE ~ .. . t-- STATE OF ALASKA ' ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS '1. Operations performed: Operation Shutdown _)0 Pull tubing _ P.O. Box 100360 Anchorage. AK 99510-0360 4. Location of well at surface: 2342' FSL, 283' FEL, Sec. 24, T11 N, R4E, UM At top of productive interval: (asp's: 377961, 5957475) Stimulate_ Plugging _ Perforate _ Alter casing _ Repair well_ Other _ 5. Type of Wel!: 6. Datum of elavation (DF or KB feet): Development X. 32' RKB Exploratory --'- 7. Unit or Property: Stratagrapic -'" Service . Colville River Unit 8. Well number: Nanuq 5 9. Permit number/approval number: 202-0421 10. API number: 50-103-20414-00 11. FieldIPool: NlAI 2. Name of Operator: Phillips Alaska, Inc. 3. Address: At effective depth: At total depth: 671' FNL, 2451' FWL, Sec. 31. T11N. R5E, UM 12. Present well condition summary (ASP: 380560.5949139) Total Depth: measured true vertical 11735' 7128' Plugs (measured) Effective Depth: measured true vertical 11735' 7128' Junk (measured) Casing Length Size Conductor 82' 16" Surface 2877' 9.625" Production 10970' 7" Liner Cemented 11 Cll yds Portland Type C 340 ax AS U!tl & 240 ox Class G Measured depth 114' 2909' True vertical depth 114' 2393' 158 ox LltaCrete, 69 sx LllaCrs'. 11002' 7708' Perforation Depth measured No perforations true vertical No Perforations Tubing (size, grade, and meesured depth) 4.5" Kill string @ 3038' Packers and SSSV (type and measured depth) No packer, No SSSV 13. Stimulation or cement squeeze summary Intervals treated (measured) N/A Intervals treated (measured) 14. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Met Water-Bbl Casing Pressure Tubing Pressure Prior to well operation NIA Subsequent to operation N/A 15. Attachments /16. Status of well classification as: Copies ot Logs and Surveys run _ Daily Report of Well Operations _ Oil_ Gas 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed .A ~.¿ 0tZ. Title: Alpine Drilling Team Leader ~ipAlvord Form 10-404 Rev 06115/88 Suspended _XX Service Questions? Call Vem Johnson 265-6081 Date "5( 12. , " L- Prepared by Sharon Allsup-Drake SUBMIT IN DUPLICATE Nanuq 5 !ell Schematic After sus'nsion I+-- FMC Gen. V Wellhead .. 16" Conductor to 114' Updated 7/13/05 9-518" 40 ppf L-80 BTC Surface Casing MD/2393' TVD cemented to surface ~ 4-Y, tubing circulation string to 3038' MD with diesel cap and brine from 3038'-6297' MD Toe @ 6550' MD (500' MD above top K2) Completion Tubing Hanger 4-Y,", 12.6 ppf IBTM tubing WEG (+1- 57.2°) MQ Dill 32' 32' 3038' 2464' Stage Tool set @ 6297' MD 81 bbls of 11 PPG LiteCrete cement w/additives Assume 75% excess annular volume. Top K2 sand at 6050' MD Bottom K2 sand at 6160' MD Top of Cement @ 8950' MD 7" RMLS Latch Coupling at 9665' and 9163' Note: 6.140" ID (Baker-Ioc connection) Nanuq @ 9950' MD Kuparak @ 11608' MD 7" 26 ppf L-80 BTC Mod Production Casing @11003'MDI7708'TVD @ 57.6° . . Jordan F. Wiess, on oath, deposes and says: 1. I am the Nanuq Development Coordinator for ConocoPhillips Alaska, Inc., the operator of the Colville River Unit. 2. On August 17, 2005, I caused copies of the request for the classification of the Nanuq and Nanuq-Kuparuk reservoirs and prescription of rules for development and operation to be provided to the royalty interest owners and other working interest owner: a. Anadarko Petroleum Corporation Bill Shackelford P.O. Box 1330 Houston, T x 772551-1330 b. Arctic Slope Regional Corporation Teresa Imm 3900 C Street, Suite 801 Anchorage, Alaska 99503-5963 c. Department of Natural Resources Division of Oil and Gas Mike Kotowski 550 West th Avenue, Suite 800 Anchorage, Alaska 99501 (j7¿ tJ0 Jordan F. Wiess STATE OF ALASKA ) ) ss. THIRD JUDICIAL DISTRICT) SUBSCRIBED AND SWORN to before me this fifteenth day of September, 2005. STATE OF ALASKA..~, NOTARY PUBLIC Ð Carol Kelly " ~ My Commission ~?ires Aug. 16, 2008 / ð/'ftCP c::¡(¿¡M N~BLIC ;j~[i1FpR ALASKA My Commission Expires: v2u¿¡¿¿Of /~) <?tJ08 "-~. . . Jack A. Walker, on oath, deposes and says: 1. I am the Nanuq Production Engineer for ConocoPhillips Alaska, Inc., the operator of the Colville River Unit. 2. On August 11, 2005, I caused copies of the request for the classification of the Nanuq and Nanuq-Kuparuk reservoirs and prescription of rules for development and operation to be provided to the surface owner of all land within the proposed development area: a. Kuukpik Corporation Mr. Isaac Nukapigak PO Box 187 Nuiqsut, Alaska 99789-0187 b. Kuukpik Corporation Mr. Lanston Chin 825 W. 8th Avenue Suite 206 Anchorage, Alaska 99501 \ ¿Lf!,~ Ó Jack A. Walker STATE OF ALASKA ) ) ss. THIRD JUDICIAL DISTRICT) SUBSCRIBED AND SWORN to before me this fifteenth day of September, 2005. STATE OF ALASKA """" / ~¿ ,) ~O~ARY PUBLIC U NOTAR'(PUB~ÂN: ~~ASKA I' Carol Kelly -, ~ My Commission Expires: ,LJ.a¿¡tI~f ¡(.pI c¥CJOg My Commission ~':':l?~;s Aug. 16,2008 ...... . ~ - {j