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Home My WebLink AboutAIO 018 BINDEX AREA INJECTION ORDER 18B Colville River Field Colville River Unit Alpine Oil Pool 1. July 22, 2004 CPAI's application for Expansion of CO 443 and AIO 18A 2. July 30, 2004 Notice of Hearing, affidavit of publication, bulk mailing, email distribution 3.----------------- Various emails 4. May 15, 2005 CPAI's request for AA to inject additional fluids for FOR (AIO 1813.001) 5. April 21, 2005 CPAI's request for AA to inject additional fluids for FOR (AIO 1813.002) 6. May 30, 2005 Email: follow-up questions 7. June 1, 2005 Email from AOGCC to CPAI re: June 1, 2005 AA 8. November 11, 2005 CPAI's request for clarification of AIO 1813.001 9. November 30, 2005 AOGCC's response to CPAI's 11/11/05 letter 10. February 13, 2006 CPAI's request to delay UIC 4 year MIT schedule on UIC injection wells 11. March 23, 2006 Approval of CPAI's 2/13/06 request and decision backup 12. January 20, 2007 CPAI's request for administrative relief (AIO 1813.003) 13. May 10, 2007 CPAI's email request for AA to adjust surveillance logging and plug depth tags (AIO 1813.004) 14. August 3, 2007 Memo to file 15.October 1, 2007 CPAI's Class I Well DEC Application 16. May 9, 2009 CPAI's request for AA (AIO 1813.005) 17. May 23, 2009 CPAI's request for AA (AIO 18B.006) 18. May 28, 2009 AIO 1813.006 background information 19. January 21, 2010 CPAI's request to cancel AA (AIO 18B.003 Cancellation) 20. January 30, 2010 CPAI's request to cancel AA (AIO 1813.005 Cancellation) 21. December 1, 2013 CPAI's request for AA (AIO 1813.007) 22. March 26, 2016 — February 23, 2017 CPAI's request to align the anniversary dates on AA's with the current approved UIC testing schedule (AID 1813.006 Amended and AIO 1813.007 Amended) ORDERS ) ) STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: The APPLICATION OF CONO- COPHILLIPS ALASKA Inc. ("CP AI") for an amendment of Area Injection Order No. 18A to expand the enhanced oil recovery project in the Alpine Oil Pool, Colville River Field, North Slope, Alaska. ) Area Injection Order No. 18B ) Colville River Field ) Colville River Unit ) Alpine Oil Pool ) ) October 7, 2004 ) IT APPEARING THAT: 1. By application dated July 22, 2004, ConocoPhillips Alaska, Inc. ("CP AI") requested authoriza- tion from the Alaska Oil and Gas Conservation Commission ("Commission") to expand the af- fected area to inject fluids for the purposes of enhanced oil recovery from the Alpine Oil Pool. 2. Notice of opportunity for public hearing was published in the Anchorage Daily News on July 30, 2004. 3. The Commission did not receive a protest or a request for a public hearing. FINDINGS: 1. Commission regulation 20 AAC 25.460 provides authority to issue an order governing under- ground injection of fluids on an area basis for all wells within the same field, íàcility site, reser- voir, project, or similar area. 2. The Commission issued Disposal Injection Order No. 18 ("DIO 18") on April 19, 1999 and Area Injection Order No. 18 ("AlO 18") on January 24, 2000. 3. Area Injection Order No. 18A ("AIO 18A") dated April 18, 2000, amended AIO 18 and incorpo- rated DIO 18 into AIO 18A to provide disposal on an area wide basis. The findings, conclusions and administrative records for AIO 18 and DIO 18 were adopted by reference and incorporated into AIO 18A. 4. The Alpine Oil Pool ("AOP") is located in the Colville River Delta area on Alaska's North Slope. 5. CP AI is the only operator of all wells within one-quarter mile of the area proposed for disposal. The State of Alaska and Kuukpik Corporation are the surface owners. 6. CPAI has applied to expand the affected area of the AOP as defined in AIO 18. The ex- pansion area includes Sections 25 and 36 of Township 12N Range 3E, Umiat Meridian Area Injection Order No. 18B October 7, 2004 Page 2 ) ) ("UM") and Sections 20,21,22,23,27,28,29,30,31, and 32 of Township 12N Range 4E, UM. 7. CPAI anticipates drilling up to six development wells (producers and injectors) to develop an ad- ditional 31 to 55 million barrels of original oil in place ("OOIP") in the expansion area of the Al- pine Oil Pool. OOIP for the AOP was estimated at 650 to 750 million barrels of oil. 8. Minimum values of formation water salinity in the Colville Delta Area, determined using stan- dard openhole wellbore geophysical methods calibrated to water samples collected from drill stem and production testing, range from 15,000 to 24,000 milligrams per liter ("mg/l") total dis- solved solids ("TDS"). 9. The Alpine Oil Pool is contained within the Alpine Sandstone, an Upper Jurassic-aged, informal member of the Kingak Formation. It is the stratigraphically highest sandstone within the Kingak Formation in the Colville Delta area. The interval is approximately 7,000 feet below sea level and net sand thickness ranges from 0 to 120 feet. Sand thickness in the expansion area is ex- pected to range from 0 to 30 feet. 10. The Alpine Sandstone consists of very fine to fine-grained, moderate to well sorted, burrowed, quartzose sandstone with variable glauconite and clay content. Core porosity and permeability ranges are 15% to 23% and 1 to 160 millidarcies, respectively (CO 443 finding 8). 11. Approximately 70 to 120 vertical feet of ductile shale in the Miluveach Formation overlie the Alpine Sandstone. The vertical thickness of this shale is controlled by the Lower Cretaceous Unconformity. Core and log analyses indicate the parting pressure of the Miluveach shale is 600 to 700 pounds per square inch ("psi") greater than the Alpine Sandstone. 12. The Alpine Sandstone is underlain by a thick shale interval assigned to the Upper Kingak Forma- tion. Petrophysical analysis indicates the parting pressure of these shales is 700 to 800 psi greater than the Alpine sandstone. 13. Bottom-hole injection pressures are expected to exceed the Alpine formation parting pressure during normal operations. Rock mechanics and fracture analysis indicate that competent confin- ing strata above and below the Alpine Sandstone will confine injected fluids within the Alpine formation (AIO 18, Finding 10). 14. Alpine Pool crude oil gravity is 40 degree API, solution gas-oil ratio is 850 scf/stb, bubble point is 2,454 psi, and viscosity is 0.46 centipoise. Initial reservoir pressure was 3,215 psi at 7,000 feet true vertical depth subsea ("TVDss"), and average reservoir temperature is 160 degrees F. 15. Alpine crude oil properties create favorable reservoir water-oil mobility ratio that enhances areal and vertical waterflood sweep efficiency. Core flood studies showed residual oil saturation may be expected to range from 35 to 40% of the OOIP after a waterflood. 16. Estimated high residual oil saturation after waterflood provided incentive to study the feasibility of a tertiary enhanced recovery process. 17. A miscible water-alternating-gas ("MW AG") project began concurrently with initial pool pro- duction to maximize recovery and to avoid relative permeability-related reduction of productivity and injectivity that is expected after water breakthrough. Area Injection Order No. 18B October 7,2004 Page 3 ) ') 18. Fine-grid compositional reservoir simulations of the MW AG process indicate incremental recov- ery of 10 to 12% OOIP or approximately 100 million barrels over primary (AIO 18, Finding 15). Surveillance combined with numerical simulation suggests incremental EOR recovery of 10 to 15 % ofOOIP. Ultimate recovery could approach 65% with EOR. 19. Current average reservoir pressure is about 3,020 psia at 7,000' TVDss, which is significantly above the reservoir bubble point pressure of 2,454 psi. 20. Miscible injectant ("MI") is manufactured from Alpine Pool associated gas and enriching liquids recovered from fuel gas to ensure a minimum miscibility pressure of 2900 psi. To date, MI slug volume injected is approximately 21 % of hydrocarbon pore volume at Pad CDl and 6% at Pad CD2. Total MI slug volume injected is expected to be 25 to 30% of pattern hydrocarbon pore volume. 21. Maximum MI injection pressures attainable at the plant discharge are 4,500 psi. Maximum well- head pressures vary from 3,600 to 4,300 psi (AIO 18, Finding 25). Maximum water injection pump discharge pressure is 3,500 psi (AIO 18, Finding 26). Wellhead Injection pressure varies considerably from well to well based on local reservoir pressure, faults and fracturing within the Alpine Sandstone. Wellhead pressures for MI injection currently vary from 2,200 to 3,500 psi. Wellhead pressures for water injection currently vary from 600 to 1,800 psi. 22. Injection water sources are Beaufort Sea water and produced water from the Alpine Oil Pool. 23. Produced fluids that are not compatible with the Alpine Sandstone are disposed in Colville River Unit Well WD-2, as described in Disposal Injection Order No. 18 (AIO 18, Finding 23). Pro- duced fluids are also disposed in CDI-I9A. 24. Injection well mechanical integrity conforms to 20 AAC 25.412, and tubing-casing annulus pres- sures of injection wells are monitored in conformance with the requirements of 20 AAC 25.402 (d) & (e) to ensure there is no leakage and that casing pressure remains less than 70% of mini- mum yield strength of the casing. 25. The Commission issued Disposal Injection Order No. 18 for well WD-02. The well is currently operating as a Class I well under EPA UIC Area Permit AK-1I003-A (AIO 18A, Finding 6). 26. EPA UIC Area Permit AK-1I003-A Part II.A.3 prohibits the drilling of offsetting wells into or below the arresting zone (lower Kingak) within the Y4 mile radius area of review unless directed by EP A (AIO 18A, Finding 7). 27. The only wellbores penetrating the disposal interval will be those wellbores intended for disposal purposes. Since these wellbores will be fully cemented across both the injection and confming intervals, there are no past, present or planned penetrations of this interval that could provide communication channels to shallower intervals (AIO 18A, Finding 10). 28. As of July 31,2004,231,301 barrels of oil field waste fluids have been disposed through the CDI-19A well into the Sadlerochit Formation, and 447,950 barrels of produced water have been injected into the Alpine Sandstone at Pad CD 1. 29. Current practice suggests an ongoing disposal volume of approximately 30,000 bbl/year into the Sadlerochit Formation over an anticipated thirty-year field life, depending on development drill- ing activity and well work. Area Injection Order No. 18B October 7,2004 Page 4 ) 30. CP AI disposes of oil field waste fluids that include drill cuttings and fluids, completion, workover and stimulation fluids, frac sand, produced water, crude oil, production vessel sludge/sand, natural gas liquids, rig wash and well cellar fluids, diesel/methanol used as freeze protectant, plant upset fluids, snowmelt, and any fresh or seawater necessary to enable disposal. 31. Daily disposal injection volumes into the CDI-19A well do not exceed 2,500 barrels. Currently, maximum injection pressures range from 3,450 and 3,500 psig at rates ranging from 1.2 to 3.5 barrels per minute. Perforation plugging and fill accumulation affects injection pressure. Periodic clean out and re-perforation is necessary. 32. CPAI demonstrates the mechanical integrity of injection wells as specified in 20 AAC 25.412 prior to initiating injection operations. 33. The operator has complied with the requirements of 20 AAC 25.402 (d) & (e) to monitor tubing- casing annulus pressures of injection wells periodically during injection operations to ensure there is no leakage and that casing pressure remains less than 70% of minimum yield strength of the casing. 34. All existing wells drilled within the proposed project area have been constructed in accordance with 20 AAC 25.030. All wells abandoned in the proposed project area have been abandoned in accordance with 20 AAC 25.105 and 20 AAC 25.112 or an equivalent precursor regulation. CONCLUSIONS: 1. The application requirements of 20 AAC 25.402 have been met. 2. An amended Area Injection Order is appropriate for the expanded Alpine Oil Pool area in Sec- tions 20, 21, 22, 23, 28, 29, 30, 31, and 32 of Township 12N, Range 4E, UM and Sections 25 and 36 of Township 12N, Range 3E, UM in accordance with 20 AAC 25.460. Section 27 of Township 12N, Range 4E, UM was included in the original affected area of AIO 18. 3. No underground sources of drinking water ("USDW's") exist beneath the permafrost in the Col- ville River Unit area. 4. Enhanced recovery and disposal injection operations are conducted in permeable strata, which reasonably can be expected to accept injected fluids at pressures less than the fracture pressure of the confining strata. 5. The proposed Alpine tertiary enhanced oil recovery project is expected to recover significantly more oil than a waterflood project. 6. Ample confining shale exists above and below the Alpine Oil Pool to assure containment of the injected fluids within the Alpine Sandstone. 7. Enhanced recovery injection fluids consist of water and miscible gas. MWAG was implemented at startup to maximize ultimate recovery. 8. Class II disposal injection is, and will continue to be, limited to produced water and oil field wastes that the Commission determines are suitable for disposal in a Class II well. Area Injection Order No. 18B October 7, 2004 Page 5 ) ) 9. Class I industrial waste disposal inj ection is, and will continue to be, in accord with EP A UIC Area Permit AK-lI003-A. 10. No wells may be drilled into or below the arresting zone (lower Kingak) within the Y4 mile radius area of review of well WD-02 under EPA permit AK-1I003-A. 11. Well mechanical integrity is demonstrated in accordance with 20 AAC 25.412 prior to initiation of injection or disposal operations. 12. The mechanical integrity of each injection well will be tested at least every four years after an ini- tial test. Wells used for grind and inject purposes must be tested every two years. 13. Tubing-casing annulus pressure and injection rates are monitored at least weekly for surveillance of operational conditions. 14. An amendment to Area Injection Order 18A to expand the project area will not cause waste nor jeopardize correlative rights. NOW, THEREFORE, IT IS ORDERED that: This Area Injection Order supersedes AIO 18A dated April 18, 2000, and AIO 18 dated January 24,2000. The findings, conclusions and administrative record for AIO's 18 and 18A are adopted by reference and incorporated in this decision so far as they do not conflict with the findings of this order. The following rules, in addition to statewide requirements under 20 AAC 25, to the extent not superseded by these rules, apply to the Alpine Oil Pool within the following affected area: UMIAT MERIDIAN TlIN R4E Section 1,2, 3,4,5,7, 8, 9, 10, 11, 12, 13, 14, 15, 16,21,22,23,24,25,26,27. TllN 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, and 30. Tl2N R3E Sections 25,36. T12N R4E Sections 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35 and 36. T12N R5E Sections 13, 14, 15, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35 and 36. Rule 1 Authorized Iniection Strata for Enhanced Recovery (Restated from AIO 1SA) Within the affected area, fluids may be injected for purposes of pressure maintenance and enhanced re- covery into strata that are common to and correlate with the interval between the measured depths of 6,876 and 6,976 feet in the Bergschrund No.1 well. Area Injection Order No. 18B October 7,2004 Page 6 ) ) Rule 2 Authorized Injection Strata for Disposal (Restated from AIO 18A) Within the affected area, Class II fluids may be injected for purposes of disposal into strata that are com- mon to and correlate with the interval between the measured depths of 8,432 and 9,540 feet in the Sohio Alaska Petroleum Company Nechelik No.1 well. Rule 3 Fluid In.jection Wells (Restated from AIO 18A) The underground injection of fluids must be through a well permitted for drilling as a service well for in- jection in conformance with 20 AAC 25.005 or through a well approved for conversion to a service well for injection in conformance with 20 AAC 25.280. Rule 4 Monitoring the Tubing-Casing Annulus Pressure Variations (Restated from AIO 18A) The tubing-casing annulus pressure and injection rate of each injection well must be checked at least weekly to ensure there is no leakage and that it does not exceed a pressure that will subject the casing to a hoop stress greater than 70% of the casing's minimum yield strength. Rule 5 Reporting the Tubing-Casing Annulus Pressure Variations (Restated from AIO 18A) Tubing-casing annulus pressure variations between consecutive observations need not be reported to the Commission unless well integrity fàilure is indicated as in Rule 7 below. Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, after a work- over affecting mechanical integrity, and at least once every 4 years while actively injecting. For slurry injection wells, the tubing/casing annulus must be tested for mechanical integrity every 2 years. The MIT surface pressure must be 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, must show stabilizing pressure and may not change more than 10% during a 30 minute period. Any al- ternate means of demonstrating mechanical integrity must be approved by the Commission. The Com- mission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Rule 7 Well Inte2rity Failure and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injec- tion rate, operating pressure observation, test, survey, log, or other evidence, the operator shall immedi- ately notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval. The operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the Commission. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation. Rule 8 Pluge;Îng and Abandonment of Injection Wells (Restated from AIO 18A) An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission in accordance with 20 AAC 25.105. Area Injection Order No. 18B October 7, 2004 Page 7 ) ) Rule 9 Surveillance (Modified from AIO 18A) For grind and inject slurry injection wells, a baseline temperature survey from surface to total depth, ini- tial step rate test to pressure equal or exceeding maximum injection pressure and pressure falloff are re- quired prior to sustained disposal injection. Regular fill depth tags are required at least once annually or as warranted following consultation with the Commission. Operating parameters including disposal rate, pressure, annuli pressures and volume of slurry pumped must be monitored and reported according to the requirements of 20 AAC 25.432. For slurry injection wells, an annual performance report will be required including rate and pressure per- formance, surveillance logging, fill depth, survey results, and volumetric analysis of the disposal storage volume, estimate of fracture growth, if any, and updates of operational plans. Report submission must be on or before April 1, in conjunction with the Alpine Pool Annual Reservoir Report. Rule 10 Notification (Restated from AIO 18A) The operator must notify the Commission if it learns of any improper Class II injection. Additionally, notification requirements of any other State or Federal agency remain the operators' responsibility. Rule 11 Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. DO....N.. E a~. .. ()ÍÌ, :g..,..~,. ...,.A. I. as.ka. and oc?/:obe , 04. , ~~Ø~7\~_;~,,~t1~ " .~~I""\~.c \ :: '~p ~ t/ I~'.',\ i I J ~2\~~\ l ~,j ~ I: ,"'....... ~/ ""~~~,\µ'~" Jo K.~an, Chai:..~:;¡n f.'.',.'. . '," .;-::..,1, i\J-~J' _-~~~;:~\"..~."'.\.I\ as a ~1 an as onservation Commission tl .. --.:-·.rtl~I.t.·"~'I~I"II~,.IJ.,.:¡""'~.: f.l ;:P'~ t, ...."f" . r.~~ r.~ "\).:.'J,i:~~.:;;' ~.\'" ¡II ~. t'\ '. f. /~ ~j .0:'.(".' .... . t(" ¡ 1/"'/ I " \. .(~t...'. I ','. i ': ':~~":" t.1~ -..,," . ' ~(~ ,J \ I ... ,....~ t·' ~,...":... .... /,' .",.... " .- '\ ''1, .~' ß~ tl,~r¡,;;.:\Ifi:(. '. . l é0 Dan ~amo% Commissioner \....¡,J} "~:,(l-y':~I~t;¡"";¡'~'~'")'I~""-' ,.,~~) 1 k . d . . . '\~{ I. ~~. '~"';~tt:'.,:~iJ~;:f~j.,_~·i. .¡'," (,(?" A as a 011 an Gas ConservatIon CommIssIon . ":;~~;r:zi.i~I:~('? AS 31.05.080 provides thàt within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commis- sion an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next work- ing 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 deci- sion to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30-day period for appeal to Superior Court runs from the datc on which the rcquest is decmed denied (i.e., 10th day after the application for rehearing was filed). Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Kelly Valadez Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 ) 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 Ciri Land Department PO Box 93330 Anchorage, AK 99503 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 David Cusato 200 West 34th PMB 411 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. 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"Deborah 1 Jones" ..<JonesD(j@BP.com>,.."~~ulCi.If~att" <hyattpgqyBr .CQµ1>,"Steyen<~.Rossberg" <~?s.sbeRS..@).~P...com>~ .·Lois.·.:loi.s{qjinletkeeper;prg2., ·P8f1·..·~ross·.·.·5~uacµe\Vs.~k~a.c;.org>,..·(Jo~don . P·o·~pis·il...·<;Pospj.s(}@B~.q()l1l(,. ·.'·~·rr.atlc.~.s.·...S...·...S.qij111'l~~"...~~o~e~J1.~@,ªp·ócQrrl~~·...iji~~·l..·~~þ~~t~.·.·.... <¥ikel.Schultz@BP.com:>,.· "~ick.· W~·..·Glove~"-<<f:19yerN"\\T@]3~;c9m~; .."J?~~...~... ~lel':pi~~'······ <KleppiI?E@13P .com?; "Janet}).. P l~tt" <PlatQIJ@BP.com::> ,<"lR.psa.nl1~M.Jacoþsÿn" .. <JacobsRM@BP .com>,. ddonkel.<ddonl(el@cflrr.com>, Collins. Mount <collills_mount@revenue.state.ak.us~,mckay.<mckay@gci~net>,..~arbara P··Pullmer . -<:lJarb(;tra.f. fuHP1er@conocophillips..com>, bocélStwf<bocastw~@bp.com> ; Charles. Barker <barker@usgs.gov>, doug.c-schultze <~oug_schu1tze@xtoenergtco~~, Hank. Alford <hank.alford@e~xonmobil.com>.,...Mark..Kov.ac..<yest10.1.@gci.net>,...·gSpfoff ~gspf9~f@aµrorapower.c()m>,GreggNady«~egg.l1ad)'@shen.col11?'~~reci~tee~~ ... .. ..... . .... ... ..... .... .. ...... <fred.steece@state.sd.us>, rcrotty<rcrotty@ch2m~com>,jejones ·..~ejones<@a~rorapo}Ner.c9l11;>,·..dapa <dapa@alaska.net>,jroderick <jroderick@gcLnet>,. eyancy <~yrancy@seal-tite'l1et> ~"Jal1le~M~ . Ruud" <james.m.ruud@col1ocophillips.com>, Brit Lìvely <mapalaska.@aknet>, jab <jah@dnr.state.ak~ us>, Kurt E· Olson . <kurt _ olson@legis.state.alcus>, buonoje <buonoje@bp.com>, Mark Hanley <mark_ hanley@anadarko.com>, ·loren_leman <loren_Ieman@gov.state.ak.us>, Julie Houle <julie_houle@dnr.state.ak.us>,John W Katz <jwkatz@sso.org>, Suzan J Hill <suzan _hill@dec.state.ak.us>, tablerk <tablerk@unoca1.com>, Brady <brady@aoga.org>, Brian Havelock <beh@dnr.state.ak.us>, bpopp <bpopp@borough.kenai.ak.us>, Jim White <jìmwhite@satx.rr.com>, "John S.Haworth" <john.s.haworth@exxorunobi1.com>,marty <marty@rkindustria1.com>, ghammons <ghammons@ao1.com>,· nncIean <rmclean@pobox.alaska.net>, mkm7200 <mkm7200@ao1.com>, Brian Gillespie <ifbmg@uaa.alaska.edu>, David L Boelens <dboelens@aurorapower.com>, Todd Durkee <TDURKEE@KMG.com>, Gary Schultz <gary_schultz@dnr.state.ak.us>, Wayne Rancier <RANCIER@petro-canada.ca>, Bill Miller <Bill_Miller@xtoalaska.com>, Brandon Gagnon <bgagnon@brenalaw.com>, Paul Winslow <pmwinslow@forestoi1.com>, Garry Catron <catrongr@bp.com>, Sharmaine Copeland <copelasv@bp.com>, Suzanne Allexan <sallexan@helmenergy.com>, Kristin Dirks <kristin_dirks@dnr.state.ak.us>, Kaynell Zeman <kjzeman@marathonoil.com>, John Tower <John.Tower@eia.doe.gov>, Bill Fowler <Bill_Fowler@anadarko.COM>, Vaughn Swartz <vaughn.swartz@rbccm.com>, Scott Cranswick lof2 10110/20042:52 PM 10/10/20042:52 PM 20f2 ) ) Various Orders e ~1r~1rŒ (ID~ ~~~~æ~ e AI.ASIiA. OIL AND GAS CONSERVATION COMMISSION FRANK H. MURKOWSKI. GOVERNOR 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. AIO 18B.001 Ms. M. J. Loveland Problem Well Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 RE: CRU CD2-51 (PTD 202-249) Request for Administrative Approval AIO 18B.00 1 Dear Ms. Loveland: Per Rule 11 of Area Injection Order ("AIO") 018.B, 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. AOGCC finds that CPAI has performed diagnostic testing on CD2-51 attempting to locate and quantify the reason for an intermittent pressure communication from the tubing to inner annulus. The diagnostic testing has not been able to definitively determine a cause for the communication. Based on the intermittent appearance of the pressure communication and the relationship to fluid temperatures, CPAI believes that a slight leak in the sealing elements at the packer may be the cause. At this time, CPAI does not propose to perform a repair to eliminate the pressure communication. The Commission further finds that, based upon reported results of CPAI's diagnostic procedures, CD2-51 exhibits two competent barriers to release of well pressure. Accordingly, the Commission believes that the well's condition does not compromise overall well integrity so as to threaten the environment or human safety. AOGCC's administrative approval to continue water injection in CRU CD2-51 is conditioned upon the following: 1. Injection is limited to WATER ONLY; 2. CPAI shall monitor and record wellhead pressures (T/I/O) and injection rate daily; 3. CPAI shall submit to the AOGCC a monthly report of well pressures and injection rates; Administrative APproval. 18B.001 May 23, 2005 Page 2 of 2 . 4. CPAI shall demonstrate continued tubular integrity by performing an MIT-T and MIT-IA every two years to 3000 psi; 5. CPAI shall determine the fluid level in the OA every 2 years; 6. CPAI shall immediately shut in the well and notify the AOGCC upon any measurable change in well outer annulus pressure; and 7. After well shut in, AOGCC approval shall be required to restart injection. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission cision to Superior Court unless rehearing has been requested. ,2005. aniel T. Seamount. Jr. Commissioner f:6¿~ Commissioner Admin Approval AIO l8B.00l Colville River Unit e . lof2 5/23/2005 11 :51 AM Admin Approval AIO 18B.00l Colville River Unit e e <Tim Lawl <Jerry.C.Det conoc crockett@aoga.org, Tam <Jon. Goltz@conocophilli <mlewis@brenalaw.com>, arry Lampert <harry.! < >, Patty Alf: .state.ak.us 20f2 5/23/2005 11 :51 AM 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 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 -- -- - -- -. _._~~_._----_._------ --.-- P-enny VäaIS----------- 399 West Riverview Avenue Soldotna, AK 99669-7714 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 r t 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 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 James Gibbs PO Box 1597 Soldotna, AK 99669 'RI'eñard Wagner' PO Box 60868 Fairbanks, AK 99706 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 f 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 David Cusato 200 West 34th PMB 411 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 ---~-'----'----- ..,-----------.-- ._-_.._--~--- -'- --ChffBurg¡in~'-- PO Box 70131 Fairbanks, AK 99707 North Slope Borough PO Box 69 Barrow, AK 99723 (~~\\1 jLf<D1 FRANK H. MURKOWSKI, GOVERNOR ALASKA OIL AND GAS CONSERVATION COMMISSION 333 W. yrH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. AIO 18B.002 Mr. Matt Elmer Alpine Operations Superintendent ConocoPhillips Alaska Inc. ALP 15 P.O. Box 196860 Anchorage, AK 99519-0105 Re: The application from ConocoPhillips Alaska, Inc. to inject non- hazardous fluids for Class II enhanced oil recovery in the Colville River Field, Alpine Oil Pool, North Slope, Alaska. Dear Mr. Elmer: ConocoPhillips Alaska, Inc. ("CPAI") has requested by letter dated April 21, 2005 authorization to inject non-hazardous fluids from several sources into Class II enhanced oil recovery ("EOR") wells in the Alpine Oil Pool. These fluids would normally be injected into the Class I disposal well (WD-02), however, there is no option for fluid disposal when the well is unavailable due to compliance testing or diagnostics when there are indications of possible mechanical integrity concerns. The Commission may authorize the injection of non-hazardous fluids for EOR purposes if it is appropriate for enhanced recovery. The non-hazardous fluid sources are: sump fluid, hydrotest fluid, rinsate, and excess well work fluids (brine, freshwater, etc.). Additional clarification about the characteristics and sources of rinsate was provided by CPAI on May 20, 2005. Area Injection Order ("Ala") 18A authorized the injection of water and miscible gas for EaR into the Alpine Oil Pool and wastes generated from exploration and production-related activities for disposal purposes into the Ivishak and Sag River formations. On August 1, 2002 the Commission administratively approved CPAI's request to blend treated camp wastewater effluent with seawater for EaR when WD-02 is unavailable. On October 7, 2004 the Commission issued amended Ala 18B, expanding the area authorized for injection and clarifying well integrity requirements. According to CPAI, the fluid streams would be blended with Alpine manifold CD IB water injection and would account for 0.02 percent of the weekly total EaR fluid injection volume based on current water injection rates. The ) ADMINISTRATIVE APPROVAL !~O. AIO 18B.002 June 1, 2005 Page 2 of 2 ) maximum volume of the non-hazardous fluids injected per week would be 10,000 gallons. In addition to documentation confirming the non-hazardous status of these fluid streams under Resource Conservation and Recovery Act provisions, CPAI provided the results of fluid compatibility studies that demonstrate the proposed fluid/ seawater mix would not be detrimental to the Alpine reservoir. The Commission agrees with CPAI's analysis and assessment that blending seawater, treated camp wastewater and the small volume of these additional fluid streams prior to injection is unlikely to impact the EOR efficiency negatively. The Commission further finds that the blended EOR fluid will not promote waste or jeopardize correlative rights, and will not contribute to the potential for fluid movement outside of the injection zone. Therefore, in accordance with the provisions of Area Injection Order 18B, Rule 11 the Commission approves the injection of the following non-hazardous fluids by blending with existing Class II fluids used for EOR: sump fluid, hydrotest fluid, rinsate generated from washing mud hauling trucks, and excess well work fluids. The Commission further incorporates the previously approved blending of treated camp effluent with the seawater for EOR purposes as described in AIO 18A.0 1. As a condition of this approval CPAI must continue to collect and analyze representative samples of the mixed fluid stream at Alpine manifold CD IB to demonstrate its non-hazardous characteristics and its continued suitability for EOR injection. Analysis results shall be retained according to the provisions of 20 AAC 25.310. Volumes shall be incorporated into the monthly (Form 10-406) and annual (Form 10-413) injection reports. orage, Alaska and dated June 1, 2005. ~ Daniel T. Seamount Commissioner ~p~fe~ Commissioner ~~~ OJL hS ~ ..¿"..~,. I ~k . ~i\ 11l?J;~ ~ f .,' '" .:: ,/"",,-<~~\þ ~ ~ ....... ..... . "-, { r"'- '..;' <. .'\:"·'n-.. l, Ç}, \'; ~ I'; ";":',:~':":;~:; \ ¡J-'" ..~.¡7,:... '. , : ,.', I /,?:- ' '~i',¿-";,{:.~'~~~~' -1 Ì'}¡O" -. 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P()~plSll~tO~'pl~p@J?r:?Om~,'~~ran9~~' ~·~,2Wp1~r~', ~~omWr~fS@~:e~g~~N,·.+'4!~~1§911~~tz··· «~~~¡'~.c?~l~@~P,(Jø~~~ ·."~iCk'j{:'··~16Ye~!:t<p19Y~t~\¥~~~jC~~~'.!'I?~lJ;"~~~Bi~!' )f1<]~ppiQ~~~~·g~m>', ·..~':if1Q~tR·" ~~,~tt~' ~~:~~tt)!P:~~~11P~ro~ ,:';;¡~"~~;:~~~,ty1;¡:!'11~8,~Þ'§~~¡;'''',:.::¡,:.,, ".':"..........". ......,..... .... <S~~9~~¡f;f~11o/~r@c8~~copþllhB,~.CQ!11r,'lþRç~SI}'¥~',f&Rf~s~~f~b~:c?111>'; C~arl~,~ ..~~¡¿~r . ->barl{~~@q~~s:;~o¥:>,. dpu!5+-~çl1;ultz~.lfq9Jtg~s911Bltz~.@~tQ¡eqe~g~~:çR91~,~:tI~,1~~f~rq':II.' ..... ../ .'!," .... <~ai1k.~lford@~xx9hmobq~pom~, ¥~~ :~oyac~yes~ol ~:~ci.~et~.,g~þf~,ff... ..",,1.':' ':" <g~pfoff@auror~po\Ver.com>, Q~~ggN'ady<~r~gg.~~dy@sh~n.?om>, Freçl~fee'cel" ......... i.... ..' <fred..steece@state.sg.us>, rcrotty<rcrottY@CÄ2~.'9om0~ j ej9{les:.'<jej()p.es@~uror~pqwer.col11>, dapa <dapa@alaska.net>,.jroderic~<jrodericl<@gcLne~.,'~Y~9Y~~Y~cy@~~~lTtït~.~et>,:;:"Jkn1és M.Ruud " <j ames.m.rq.ud(Ðconocophillips.com>,'Brit.tively ·<l11apalask~@ak.net>, j ål1. <jåh@dnr.state.ak.us>, Kurt E. Olson <kurt _olson@legis.state.ak.us>,buQnaje <buonoje@bp.com> ,:MarkH~ley , <mark ~ hanley@anadarko.com>, loren _leman <loren_Iemffi1@gov.state.ak.us>,.Julie Houle <julie_houle@dnr.state.ak.us>, John.W Katz<jwkatz@sso.org>, SuzanJ Hill <suzan_hill@dec.state.ak.us>, tablerk <tablerk@unoca1.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@exxonmobi1.com>, marty <marty@rkindustria1.com>, ghammons <ghammons@ao1.com>, rmclean <rmclean@pobox.alaska.net>, mk.m7200 <mkm7200@ao1.com>, Brian Gillespie <ifbmg@uaa.a1aska.edu>, David L Boelens <dboelens@aurorapower.com>, Todd Durkee <TDURKEE@KMG.com>, Gary Schultz <gary_schultz@dnr.state.ak.us>, Wayne Rancier <RANCIER@petro-canada.ca>, 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@dnr.state.ak.us>, Kaynell Zeman <kjzeman@marathonoi1.com>, John Tower <John.Tower@eia.doe.gov>, Bill Fowler <Bill_Fowler@anadarko.COM>, Vaughn Swartz <vaughn.swartz@rbccm.com>, Scott Cranswick <scott.cranswick@rnms.gov>, Brad McKim <mckimbs@BP.com>, Steve Lambe <lambes@unoca1.com>, jack newell <j ack.newell@acsalaska.net> , James Scherr 10f2 6/1/2005 3 :09 PM 1\10 18B.002 (Colville Riverm Alpine) ') ') <jal1les.SÞ~~ÍT@mms:.g()v>"daviq r()p)'<Da~i4:'~9b~($,Wl}1~~~QV; ,)'ifu,La)ylor',i.....,:" " <Tirn~LaW!PI@a¥~ blQ}.g()v).,', Lyµnda"Fahri <~yrl~4a.~~flhp~fW~~g9v>~JeUy,Detµl~fs ' <Jerry ;Ç.R~tlilÿfs@col1'Oc9Ph.i1li ps:.com:;>; ,J errYiPe~nl~fs, 'f~T61 'Z~c()nQcqphilli ps,cpm>, croc~ett~apg~.org~ !aWera~h~ft1dd <;sheffie1d@apga¡orgf>,JonGdltz',ii"":"" ,', ". <Jon,"',.Go,,',lt,z, @,'" C,:0P,',q~p, iP, P, :,H, lip, s;Þb,'~,:, ,>;, Roge", r ,B, ,el"m, an,,'" <""r"o",g,er" .,b, ,elm, an, ',@"c: ,,0,, nO~0, "phillip" s.po, m, ',>, ',;.'" !'1, ,indy Lewis I ' " ", I: ',' : ' " ,'", ' , I , " " 'I, I " I I " . , " I , I I 'I, ' , ' , I ~ ' , " " , " ' , ~ I' I ' I, I I ,,' I I 1'1 ' , II 'I " , : ,I " , ' ',', , , ' , , ' , ' : I : ' :', ,'" ", " ' , " I <mlewis@bre11.al~w;c()IIl>," Harry~ampert ~ha¡ry::låip.pef1:@hºn~ywelr:c011l>, ~c:µ-iMotiarty: <m91"iarty@~og~~org>,:'~'~ttY Alfar():.-<palfarW@Y~~Qå.·q()wrr,;¡:, '".,',:,:: I :::,:,,;1<'::;;:: 'I:, I, :":':;::::':' '" " '"~' ': : ,:"'~,,,:'::,' , ¡i,,:::::,. :;:1 ",,>, ,!(', :;: ': :':I~':!"'"" ::: '!'\I ,;1 20f2 6/1/2005 3:09 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 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 ) Mary Jones XTO Energy, Inc. Cartograp~y 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 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 ) 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 David Cusato 200 West 34th PMB 411 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 11)¿:t/~ Á V/þp:J . ~V~VŒ (ffi~ ~~~~[{~ . AI1ASIiA 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. AlO 18B.003 Mr. Perry Klein Problem Well Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 RE: CRU CD2-48 (PTD 202-108) Request for Administrative Approval AIO 18B.003 Dear Mr. Klein: Per Rule 11 of Area Injection Order ("AIO") 018.B, 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. AOGCC fmds that CPAI has performed diagnostic testing on CD2-48 and confirmed pressure communication from the tubing to inner annulus. CPAI has determined that a workover is necessary to eliminate the pressure communication. At this time, the workover has not been scheduled. The Commission further fmds that, based upon reported results of CPAI's diagnostic procedures, CD2-48 exhibits two competent barriers to release of well pressure. Accordingly, the Commission believes that the well's condition does not compromise overall well integrity so as to threaten the environment or human safety. AOGCC's administrative approval to continue water injection in CRU CD2-48 is conditioned upon the following: 1. Injection is limited to WATER ONLY; 2. CPAI shall monitor and record wellhead pressures (TjljO) and injection rate daily; 3. CPAI shall submit to the AOGCC a monthly report of well pressures and injection rates; 4. CPAI shall demonstrate continued tubular integrity by performing an MIT - T and MIT - IA every two years to 3000 psi; . Administrative Approval AID 18B.003 February 12, 2007 Page 2 of 2 . 5. CPAI shall immediately shut in the well and notify the AOGCC upon any measurable change in well outer annulus pressure; and 6. After well shut in, AOGCC approval shall be required to restart injection. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission d . ion to Superior Court unless rehearing has been requested. r ge, Alaska and dated February 12, 2007. ~ Daniel T. Seamount. Jr. Commissioner ()jL, ~^- cath;%. Foerster Commissioner ~, aio18b-003 CRU CD2-48 . . Subject: aio 18b-003 CRU CD2-48 From: Jody Colombie <jody _ colombie@admin.state.ak.us> Date: Tue, 13 Feb 2007 13:48:36 -0900 To: undisclosed-recipients:; BCC: Cynthia B Mciver <bren_mciver@admin.state.ak.us>, Christine Hansen <c.hansen@iogcc.state.ok.us>, Terrie Hubble <hubbletl@bp.com>, Sondra Stewman <StewmaSD@BP.com>, stanekj <stanekj@unocal.com>, ecolaw <ecolaw@trustees.org>, trmjrl <trmjr 1 @ao1.com>, jdarlington <jdarlington@forestoi1.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@inletkeeper.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" <K1eppiDE@BP.com>, "Janet D. Platt" <PlattJD@BP.com>, "Rosanne M. Jacobsen" <JacobsRM@BP.com>, ddonkel <ddonke1@cfl.rr.com>, mckay <mckay@gci.net>, Barbara F Fullmer <barbara.f.fu1lmer@conocophillips.com>, Charles Barker <barker@usgs.gov>, doug_schultze <doug_schultze@xtoenergy.com>, Hank Alford <hank.alford@exxonmobi1.com>, Mark Kovac <yesno I@gci.net>, gspfoff <gspfoff@aurorapower.com>, Gregg Nady <gregg.nady@shel1.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.kenaLak.us>, Jim White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exxonmobi1.com>, marty <marty@rkindustrial.com>, ghammons <ghammons@ao1.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@KMG.com>, Gary Schultz <gary_schultz@dnr.state.ak.us>, Wayne Rancier <RANCIER@petro-canada.ca>, Brandon Gagnon <bgagnon@brenalaw.com>, Paul Winslow <pmwinslow@forestoi1.com>, 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>, n1617@conocophillips.com, Tim Lawlor <Tim_Lawlor@ak.blm.gov>, Lynnda Kahn <Lynnda_Kahn@fws.gov>, Jerry Dethlefs <Jerry .C.Dethlefs@conocophillips.com>, crockett@aoga.org, Tamera Sheffield <sheffield@aoga.org>, Jon Goltz <Jon.Goltz@conocophillips.com>, Roger Belman <roger.belman@conocophillips.com>, Mindy Lewis <mlewis@brenalaw.com>, Kari Moriarty <moriarty@aoga.org>, Patty Alfaro <palfaro@yahoo.com>, Jeff <smetankaj@unocal.com>, Gary Rogers <garyJogers@revenue.state.ak.us>, Arthur Copoulos <Arthur_Copoulos@dnr.state.ak.us>, Ken <k1yons@otsint1.com>, Steve Lambert <salambert@unocal.com>, Joe Nicks <news@radiokenai.com>, Jerry McCutcheon <susitnahydronow@yahoo.com>, Bill Walker <bill-wwa@ak.net>, Iris Matthews <lris_Matthews@legis.state.ak.us>, Paul Decker <paul_decker@dnr.state.ak.us>, Aleutians East Borough lof2 2/13/2007 1 :48 PM aio 18b-003 CRU CD2-48 . . <admin@aleutianseast.org>, Marquerite kremer <marguerite_kremer@dnr.state.ak.us>, Mike Mason <mike@kbbi.org>, Garland Robinson <gbrobinson@marathonoi1.com>, Cammy Taylor <Camille_Taylor@law.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@kakivik.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 Raff <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 <enge1hr@bp.com>, Jim Winegarner <jimwinegarner@brooksrangepetro.com>, Matt Rader <matt_rader@dnr.state.ak.us>, carol smyth <caro1.smyth@shell.com>, Arthur C Saltmarsh <art _saltmarsh@admin.state.ak.us>, Chris Gay <cdgay@marathonoi1.com>, foms@mtaonline.net, Rudy Brueggeman <rudy.brueggemann@international.gc.ca> Jody Colombie <jody colombie(a?admin.state.ak.us> Special Staff Assistant Alaska Oil and Gas Conservation Commission Department of Administration Content-Type: applicationlpdf aio18b-003.pdf . Content-Encodmg: base64 20f2 2/13/2007 1 :48 PM Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 John Levorsen 200 North 3rd Street, #1202 Boise, ID 83702 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 North Slope Borough PO Box 69 Barrow, AK 99723 . David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 Ivan Gillian 9649 Musket Bell Cr.#5 Anchorage, AK 99507 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 . Mona Dickens Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 y . \V l' 0 ~\ (' ~- • • O ~ ~ ~ SEAN PARNELL, GOVERNOR L~i/t'1~7~ OiL ~ ~ 333 W. 7th AVENUE, SUITE 100 CO1~SI~iRQA~`IO1~T COMnII5SIOI~T ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 CANCELLATION ADMINISTRATIVE APPROVAL NO. AIO 18B.003 Mr. Martin Walters Problem Well Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 RE: Cancellation of Administrative Approval AIO 18B.003 CRU CD2-48 (PTD 202-108) Alpine Oil Pool Dear Mr. Walters: Pursuant to ConocoPhillips Alaska, Inc. (CPAI)'s request dated January 12, 2010 Alaska Oil and Gas Conservation Commission (AOGCC) hereby cancels Administrative Approval AIO 18B.003, which allows continued water injection in Colville River Unit (CRU) well CD2-48. This well exhibited tubing by inner annulus communication and CPAI did not at the time propose repairing the well to eliminate the problem. The Commission determined that water injection could safely continue in the well, but subject to a number of restrictive conditions set out in the administrative approval. CPAI has since performed a workover and replaced the tubing in CRU CD2-48. A standard MITTIA was successfully accomplished after setting the new packer. Consequently, Administrative Approval AIO 18B.003 no longer applies to operation of this well. Instead, injection into CRU CD2-48 will be governed by provisions of the underlying AIO No. 18B. DONE at Anchorage, Alaska and dated January 22, 2010. The Alaska Oil and Gas Conservation Com~nison "~~:~, Daniel eamount, Jr. Jo K. Norman ; f;`;ti;, Chair i ioner ~ ~~ `~ ~~ ,~, Y ~~~ °'~ ' K~ , • • Mary Jones David McCaleb Cindi Walker XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 Mark Wedman Schlumberger Ciri Halliburton Drilling and Measurements Land Department 6900 Arctic Blvd. 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99502 Anchorage, AK 99503 Anchorage, AK 99503 Baker Oil Tools Ivan Gillian Jill Schneider 4730 Business Park Blvd., #44 9649 Musket Bell Cr.#5 US Geological Survey Anchorage, AK 99503 Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow. AK 99723 -, '~1 / f, 1 • Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, January 22, 2010 2:50 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'; 'Tiffany Stebbins'; 'Wayne Wooster'; 'Willem Vollenbrock'; 'William Van Dyke'; Woolf, Wendy C (DNR); (foms2 @mtaonline.net); (michael.j.nelson@conocophillips.com); (Von.L.Hutchins@conocophillips.com); alaska@petrocalc.com; Anna Raff; Barbara F Fullmer; bbritch; Becky Bohrer; Bill Walker; Bowen Roberts; Brad McKim; Brady, Jerry L; Brandon Gagnon; Brandow, Cande (ASRC Energy Services); Brian Gillespie; Brian Havelock; Bruce Webb; carol smyth; Charles O'Donnell; Chris Gay; Cliff Posey; Crandall, Krissell; Dan Bross; dapa; Daryl J. Kleppin; David Boelens; David House; David Steingreaber; 'ddonkel@cfl.rr.com'; Deborah J. Jones; doug_schultze; Elowe, Kristin; Evan Harness; eyancy; Francis S. Sommer; Fred Steece; Garland Robinson; Gary Laughlin; Gary Rogers; Gary Schultz; ghammons; Gordon Pospisil; Gorney, David L.; Gregg Nady; gspfoff; Hank Alford; Harry Engel; Jdarlington Qarlington@gmail.com); Jeff Jones; Jeffery B. Jones Qeff.jones@alaska.gov); Jerry McCutcheon; 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; Laura Silliphant; Marilyn Crockett; Mark Dalton; Mark Hanley (mark.hanley@anadarko.com); Mark Kovac; Mark P. Worcester; Marguerite kremer; Michael Jacobs; Mike Bill; Mike Mason; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; nelson; Nick W. Glover; NSK Problem Well Supv; Patty Alfaro; Paul Decker (paul.decker@alaska.gov); PORHOLA, STAN T; Rader, Matthew W (DNR); Raj Nanvaan; Randall Kanady; Randy L. Skillern; Rob McWhorter; rob.g.dragnich@exxonmobil.com; Robert A. Province (raprovince@marathonoil.com); Robert Campbell; Roberts, Susan M.; Rudy Brueggeman; Scott Cranswick; 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); Ted Rockwell; Temple Davidson; Teresa Imm; Terrie Hubble; Thor Cutler; Todd Durkee; Tony Hopfinger; trmjr1; Walter Featherly; Williamson, Mary J (DNR); Winslow, Paul M; Aubert, Winton G (DOA); Ballantine, Tab A (LAW); Brooks, Phoebe; Crisp, John H (DOA); Darlene Ramirez; Davies, Stephen F (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Mahnken, Christine R (DOA); Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA) Subject: aio18b-003 cancellation.pdf -Adobe Acrobat Professional Attachments: aio18b-003 cancellation.pdf . ~V~VŒ illJ~ ~~~~æ~ . AI,ASIiA. OILAlQ) GAS CONSERVATION COMMISSION SARAH PALIN, GOVERNOR 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRA TIVE APPROVAL AIO 18B.004 Ms. MJ Loveland Well Integrity Project Supervisor ConocoPhillips Alaska Inc. P.O. Box 100360 Anchorage, AK 99510-0360 RE: Surveillance Frequency - Request for Administrative Approval Dear Ms. Loveland: Pursuantto Rule 11 of Area Injection Order ("AIO") 18B.000, the Alaska Oil and Gas Conservation Commission ("AOGCC" or "Commission") hereby grants ConocoPhillips Alaska Inc. ("CP AI")' s request for administrative approval to reduce the frequency of surveillance logging and fill depth tag requirements to not less than once every two years. By electronic mail dated May 10, 2007 CP AI requested the Commission reduce the re- quired frequency of fill depth tags to a biennial cycle for Colville River Unit disposal wells. AIO 18, Rule 9 currently requires fill depth tags "at least once annually or as war- ranted following consultation with the Commission." The Commission findings based on a review of this request and Commission well files include the following: 1. CP AI operates two Class II disposal injection wells in support of the Alpine field development within the Colville River Unit: Wells WD-02 and CD 1-19 A. Well WD-02 is the subject of a recent Commission administrative approval as outlined below; 2. Sound well integrity and confinement of injected wastes has consistently been demonstrated in all Class II disposal wells operated under DIO 18 using daily well performance monitoring, well integrity testing, and surveillance logging; 3. The Environmental Protection Agency modified its UIC Class I permit (No. AK- 11003-A) for Colville River Unit Well WD-02 based on historical mechanical in- tegrity demonstrations, reducing the frequency of surveillance logging and fill depth tag requirements from an annual cycle to a biennial cycle; . . Ms. MJ Loveland August 3, 2007 Page 2 of3 4. The Commission issued Administrative Approval DIO 18.001 (August 3, 2007) for Well WD-02, reducing the frequency of surveillance logging and fill depth tag requirements from an annual cycle to a biennial cycle; 5. The risk of damage to the wellbore and resulting operational problems may be re- duced with less frequent well interventions; 6. Consistency among all disposal wells will minimize both confusion and duplica- tion of effort regarding surveillance requirements; and 7. There are no underground sources of drinking water underlying the Colville River Unit. Performance monitoring of injection operations associated with Colville River Unit Class II disposal wells provides an accurate and timely assessment of any potential well integ- rity problems. Reducing the frequency of surveillance logging and fill depth tags will not compromise overall well integrity so as to threaten the environment or human safety. Accordingly, AIO 18B, Rule 9 is hereby amended to provide as follows: Rule 9, Surveillance (Modified from AIO 18A) For grind and inject slurry injection wells, a baseline temperature survey from surface to total depth, initial step rate test to pressures equal or exceeding maximum injection pressure and pressure falloff are required prior to sustained disposal injection. Regu- lar fill depth tags are required at least once every two years or as warranted following consultation with the Commission. Operating parameters including disposal rate, dis- posal pressure, annuli pressures and volume of slurry pumped must be monitored and reported according to requirements of20 AAC 25.432. For slurry injection wells, submittal of an annual performance report will be required on or about April 1 of each year in conjunction with the Alpine Pool Annual Reser- voir Report. The report shall include rate and pressure performance, a volumetric analysis of the disposal storage interval, an estimate of fracture growth, if any, and updates of operational plans. If completed, results of logging, fill depth, or other sur- veillance surveys designed to document disposal injection performance and confine- ment of injected fluids shall also be included in the annual report. . . Ms. MJ Loveland August 3, 2007 Page 3 of3 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 consid- ered 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. chm ge, Alaska and dated August 3, 2007. Chairman ~ 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 Ii . . Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Monday, August 06,20073:31 PM To: Mciver, C (DOA); 'Alan Birnbaum <""Alan J Birnbaum "> (alan.birnbaum@alaska.gov)'; 'Aleutians East Borough'; 'Anna Raft'; 'Arthur C Saltmarsh'; 'Arthur Copoulos'; 'Barbara F Fullmer'; 'bbritch'; 'Bill Fowler'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'buonoje'; 'Cammy Taylor'; 'carol smyth'; 'Cary Carrigan'; 'Catherine P Foerster'; 'Charles O'Donnell'; 'Chris Gay'; 'Christian Gou-Leonhardt'; 'Christine Hansen'; 'Cliff Posey'; 'Cody Rice'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deanna Gamble'; 'Deborah J. Jones'; 'doug_schultze'; 'Evan Harness'; 'eyancy'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gregg Nady'; 'gregory micallef; 'gspfoft'; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James B Regg'; 'James M. Ruud'; 'James Scherr'; 'Janet D. Platt'; 'jdarlington'; 'jejones'; 'Jerry McCutcheon'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kristin Dirks'; 'Laura Silliphant'; 'Lois'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=crockett@aoga.org'; 'mail=foms@mtaonline.net'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marquerite kremer'; 'marty'; 'Matt Rader'; 'mckay'; 'Meghan Powell'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; 'Patty Alfaro'; 'Paul Decker'; 'Paul Winslow'; 'Randall Kanady'; 'Randy L. Skillern'; 'rcrotty'; 'rmclean'; 'Robert Campbell'; 'Roger Belman'; 'Rosanne M. Jacobsen'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'stanekj'; 'Stephen F Davies'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; 'Thomas E Maunder'; 'Tim Lawlor'; 'Todd Durkee'; 'Tricia Waggoner'; 'trmjr1'; 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier' Subject: Public Notice Redoubt Unit; Admin Approvals Colville River Unit A1018B-004 and DIO 18-001 Attachments: AI018B-004.pdf; DI018-001.pdf; Public Notice Redoubt Unit.pdf 8/6/2007 • 0 SARAH PALIN, GOVERNOR 0 Ai/A-7I1A O~ ~ ~ 333 W. 7th AVENUE, SUITE 100 CO1~T5ERQATIOI~T COI~IAII5SIOIQ ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL AIO 18B.005 Mr. Brent Rogers Problem Wells Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 RE: CRU CD2-56 (PTD 2041500) Request for Administrative Approval Alpine River Oil Pool Dear Mr. Rogers: In accordance with Rule 11 of Area Injection Order (AIO) 18B.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) CD2-56 has a history of high inner annulus pressures while injecting miscible injectant. The well is completed with an open production casing shoe. CPAI indicates the well was swapped to sea water injection in February 2009 and despite maintaining a significant differential between the injection pressure and inner annulus (IA) pressure, the well has exhibited signs of elevated IA pressure. A one-way production packer leak is suspected, which CPAI intends to repair by a rig workover in the future. Reported results of CPAI's diagnostic procedures and wellhead pressure trend plots indicate that CRU CD2-56 exhibits competent tubing and production casing as 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 CD2-56 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; 3. CPAI shall limit the inner annulus pressure to 2000 psi and the outer annulus pressure to 1000 psi; 4. CPAI shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure; AIO 18B.005 May 26, 2009 Page 2 of 2 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 MIT anniversary date is April 12, 2009. DONE at Anchorage, Alaska and dated May 26, 2009. J ,/~ .~/~.- Daniel T. Seamount, Jr. Cathy . Foerster Chair Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal aze 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. (;ommiss>oner Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, May 27, 2009 10:46 AM Subject: aio18b-5 CRU Attachments: aio18b-5.pdf BCC:'Anna Raff ; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'Cande.Brandow'; 'carol Smyth'; 'Cary Carrigan'; caunderwood@marathonoil.com; 'Charles O'Donnell'; Chris Gay; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David Brown'; 'David Gorney'; 'David Hall'; David House; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; Deborah Jones; Decker, Paul L (DNR); 'doug_schultze'; 'Eric Lidji '; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gregg Nady ; 'gspfoff; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James Scherr'; 'Janet D. Platt'; 'jejones'; 'Jerry Brady'; 'Jerry McCutcheon'; 'Jim Arlington'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; johnny.aiken@north-slope.org; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; knelson@petroleumnews.com; 'Krissell Crandall'; 'Kristin Dirks'; 'Kristin Elowe'; 'Laura Silliphant'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=fours@mtaonline.net'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; Melanie Brown; 'Mike Bill'; 'Mike Jacobs'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200 ; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro'; 'Paul Winslow'; Pierce, Sandra M (JPO); Rader, Matthew W (DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'rmclean'; 'Rob McWhorter'; rob.g.dragnich@exxonmobil.com; 'Robert Campbell'; 'Robert Province'; 'Roger Belman'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; Teresa Imm; 'Terrie Hubble'; Thompson, Nan G (DNR); 'Tim Lawlor'; 'Todd Durkee'; Tony Hopfinger; 'trmjrl'; Von Gemmingen, Scott E (DOR); 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier'; 'Aaron Gluzman'; 'Dale Hoffman'; Fridiric Grenier; 'Gary Orr'; Jerome Eggemeyer; 'Joe Longo'; 'Lamont Frazer'; Marc Kuck; 'Mary Aschoff; Maurizio Grandi; P Bates; Richard Garrard; 'Sandra Lemke'; 'Scott Nash'; 'Steve Virant'; Tom Gennings; 'Willem Vollenbrock'; 'William Van Dyke'; Woolf, Wendy C (DNR); Aubert, Winton G (DOA); Birnbaum, Alan J (LAW); Crisp, John H (DOA); Davies, Stephen F (DOA); Fleckenstein, Robert J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Mahnken, Christine R (DOA); Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Seamount, Dan T (DOA) Attachments:aio 18b-S.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) 5/27/2009 • Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group Cartography GEPS 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 Ft. Worth, TX 76102-6298 Houston, TX 77056 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 North Slope Borough PO Box 69 Barrow, AK 99723 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 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 Cindi Walker 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 Ciri Land Department PO Box 93330 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 • • o ~ O ~ SEAN PARNELL, GOVERNOR 7~T ~r~1 nitC>•-7~ ~~ ~cV[0-7 333 W. 7th AVENUE, SUITE 100 C~is-7~RQ~~Ol` C~~IIS'~7'I~~ ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 CANCELLATION ADMINISTRATIVE APPROVAL NO. AIO 18B.005 Mr. Martin Walters Problem Well Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 RE: Cancellation of Administrative Approval AIO 18B.005 CRU CD2-56 (PTD 204-150) Alpine Oil Pool Dear Mr. Walters: Pursuant to ConocoPhillips Alaska, Inc. (CPAI)'s request dated January 30, 2010 Alaska Oil and Gas Conservation Commission (AOGCC) hereby cancels Administrative Approval AIO 18B.005, which allows continued water injection in Colville River Unit (CRU) well CD2-56. This well exhibited tubing by inner annulus communication and CPAI did not at the time propose repairing the well to eliminate the problem. The Commission determined that water injection could safely continue in the well, but subject to a number of restrictive conditions set out in the administrative approval. CPAI has since performed a workover and replaced the tubing in CRU CD2-56. A standard MITTIA was successfully accomplished after setting the new packer. Consequently, Administrative Approval AIO 18B.005 no longer applies to operation of this well. Instead, injection into CRU CD2-56 will be governed by provisions of the underlying AIO No. 18C which superseded AIO 18B effective March 26, 2009. DONE at Anchorage, Alaska and dated March 22, 2010. The Alaska Oil and Gas Conservation Commission Daniel T. eamount, Jr. Chair ' ~ ~~ a '~ . , ~ ~ ~ 7 :~ ,,, -~ ~~~ ~ r _ -_ ~;: ~ 4' ~ ~ V J ~r i } a ` ~. ! ..~ ~`. ~ .ar" t~ Cathy . Fo ster Com issioner Mary Jones David McCaleb George Vaught, Jr. XTO Energy, Inc. IHS Energy Group PO Box 13557 Cartography GEPS Denver, CO 80201-3557 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 Ft. Worth, TX 76102-6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton 408 18th Street President 6900 Arctic Blvd. Golden, CO 80401-2433 PO Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Schlumberger Ciri Baker Oil Tools Drilling and Measurements Land Department 4730 Business Park Blvd., #44 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99503 Anchorage, AK 99503 Anchorage, AK 99503 Ivan Gillian Jill Schneider Gordon Severson 9649 Musket Bell Cr.#5 US Geological Survey 3201 Westmar Cr. Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508-4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs PO Box 190083 PO Box 39309 PO 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 PO Box 2139 Soldotna, AK 99669-7714 Fairbanks, AK 99701 Soldotna, AK 99669-2139 Richard Wagner Bernie Karl North Slope Borough PO Box 60868 K&K Recycling Inc. PO Box 69 Fairbanks, AK 99706 PO Box 58055 Barrow, AK 99723 Fairbanks, AK 99711 ~~~> /~~ ~e~~,~ • Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Monday, March 22, 2010 3:52 PM To: 'Aaron Gluzman'; Bettis, Patricia K (DNR); caunderwood@marathonoil.com; 'Dale Hoffman'; Frederic Grenier; 'Gary Orr'; Jerome Eggemeyer; 'Joe Longo'; 'Lamont Frazer'; Marc Kuck; 'Mary Aschoff'; Maurizio Grandi; Ostrovsky, Larry Z (DNR); P Bates; Randy Hicks; Richard Garrard; 'Sandra Lemke'; 'Scott Nash'; Talib Syed; 'Tiffany Stebbins'; 'Wayne Wooster'; 'Willem Vollenbrock'; 'William Van Dyke'; Woolf, Wendy C (DNR); (foms2@mtaonline.net); (michael.j.nelson@conocophillips.com); (Von.L.Hutchins@conocophillips.com); alaska@petrocalc.com; Anna Raff; Barbara F Fullmer; bbritch; Becky Bohrer; Bill Walker; Bowen Roberts; Brad McKim; Brady, Jerry L; Brandon Gagnon; Brandow, Cande (ASRC Energy Services); Brian Gillespie; Brian Havelock; Bruce Webb; carol Smyth; Charles O'Donnell; Chris Gay; Cliff Posey; Crandall, Krissell; Dan Bross; daps; Daryl J. Kleppin; David Boelens; David House; David Steingreaber; 'ddonkel@cfl.rr.com'; Deborah J. Jones; doug_schultze; Elowe, Kristin; Evan Harness; eyancy; Francis S. Sommer; Fred Steece; Garland Robinson; Gary Laughlin; Gary Rogers; Gary Schultz; ghammons; Gordon Pospisil; Gorney, David L.; Gregg Nady; gspfoff; Hank Alford; Harry Engel; Jdarlington Qarlington@gmail.com); Jeff Jones; Jeffery B. Jones (jeff.jones@alaska.gov); Jerry McCutcheon; 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; Larry Ostrovsky; Laura Silliphant; Marilyn Crockett; Mark Dalton; Mark Hanley (mark.hanley@anadarko.com); Mark Kovac; Mark P. Worcester; Marguerite kremer; 'Michael Dammeyer'; Michael Jacobs; Mike Bill; Mike Mason; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; nelson; Nick W. Glover; NSK Problem Well Supv; Patty Alfaro; Paul Decker (paul.decker@alaska.gov); PORHOLA, STAN T; Rader, Matthew W (DNR); Raj Nanvaan; Randall Kanady; Randy L. Skillern; Rob McWhorter; rob.g.dragnich@exxonmobil.com; Robert A. Province (raprovince@marathonoil.com); Robert Campbell; Roberts, Susan M.; Rudy Brueggeman; Scott Cranswick; 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); Ted Rockwell; Temple Davidson; Teresa Imm; Terrie Hubble; Thor Cutler; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjr1; Walter Featherly; Williamson, Mary J (DNR); Winslow, Paul M; Aubert, Winton G (DOA); Ballantine, Tab A (LAW); Brooks, Phoebe; Crisp, John H (DOA); Darlene Ramirez; Davies, Stephen F (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Mahnken, Christine R (DOA); Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA) Subject: aio18b-005 (CD2-56) and aio2b-047 (KRU 2K-18) administrative approvals Attachments: aio18B-005 Cancellation.pdf; aio2b-047.pdf Jody J. Colombie Special Assistant Alaska Oil and Gas Coru~ervation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 (907)793-1221 (phone) (907)276-7542 (fax) d 0 ~ ~ ~ SARAH PALIN, GOVERNOR ~-7I~-1! OII, A1~TD GA5 333 W. 7th AVENUE, SUITE 100 CO1~T5ERQA'1`IO1~T COMi-II55101~ ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL AIO 18B.006 Mr. Martin Walters Problem Wells Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 RE: CRU CD 1-07 (PTD 2032250) Request for Administrative Approval Alpine River Oil Pool Dear Mr. Rogers: In accordance with Rule 11 of Area Injection Order (AIO) 18B.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) CD1-07 has a history of high inner annulus pressures while injecting miscible injectant. Reported results of CPAI's diagnostic procedures and wellhead pressure trend plots indicate that CRU CD 1-07 exhibits competent tubing and production casing as barriers to the release of well pressure. Diagnostic testing further indicated that the tubing packoffs may be the source of pressure communication while injecting gas. After converting CD1-07 to water injection, the packoffs appear to be a competent barrier based on the pressure differential exhibited between tubing (injection) pressure and inner annulus 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 CD1-07 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; 3. CPAI shall limit the inner annulus pressure to 2000 psi and the outer annulus pressure to 1000 psi; AIO 18B.006 • May 29, 2009 Page 2 of 2 6 4. CPAI shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure; 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be requ 7. The MIT anniversary DONE at Anchorage, Alaska Daniel T. Seamount, Jr. Chair TION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the 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 aze 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), "[tJhe questions reviewed on appeal aze 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. Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, May 29, 2009 11:20 AM Subject: aio2b-042 (KRU 3Q-15), aio2b-043 (KRU 2E-12), aio18b-006 (CRU) Attachments: aio18b-006.pdf; aio2b-042.pdf; aio2b-043.pdf BCC:'Anna Raff ; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'Cande.Brandow'; 'carol Smyth'; 'Cary Carrigan'; caunderwood@marathonoil.com; 'Charles O'Donnell'; Chris Gay; 'Cliff Posey'; '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'; 'Eric Lidji '; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gregg Nady'; 'gspfoff; 'Hank Alford'; 'Harry Engel'; 'jah'; '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'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; knelson@petroleumnews.com; 'Krissell Crandall ; 'Kristin Dirks'; 'Kristin Elowe'; 'Laura Silliphant'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=fours@mtaonline.net'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marquerite kremer'; Melanie Brown; 'Mike Bill'; 'Mike Jacobs'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro'; 'Paul Winslow'; Pierce, Sandra M (JPO); Rader, Matthew W (DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'rmclean'; 'Rob McWhorter '; rob.g.dragnich@exxonmobil.com; 'Robert Campbell'; 'Robert Province'; 'Roger Belman'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; Teresa Imm; 'Terrie Hubble'; Thompson, Nan G (DNR); 'Tim Lawlor'; 'Todd Durkee'; Tony Hopfinger; 'trmjrl'; Von Gemmingen, Scott E (DOR); 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier'; 'Aaron Gluzman'; 'Dale Hoffman'; Fridiric Grenier; 'Gary Orr'; Jerome Eggemeyer; 'Joe Longo'; 'Lamont Frazer; Marc Kuck; 'Mary Aschoff; Maurizio Grandi; P Bates; Richard Garrard; 'Sandra Lemke'; 'Scott Nash'; 'Steve Virant'; Tom Gennings; 'Willem Vollenbrock'; 'William Van Dyke'; Woolf, Wendy C (DNR); Aubert, Winton G (DOA); Birnbaum, Alan J (LAW); Crisp, John H (DOA); Davies, Stephen F (DOA); Fleckenstein, Robert J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Mahnken, Christine R (DOA); Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Seamount, Dan T (DOA) Attachm ents: aio 18b-006.pdf;aio2b-042.pdf;aio2b-043 .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) 5/29/2009 Mary Jones David McCaleb Cindi Walker XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Wertheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 Mark Wedman Schlumberger Ciri Halliburton Drilling and Measurements Land Department 6900 Arctic Blvd. 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99502 Anchorage, AK 99503 Anchorage, AK 99503 Baker Oil Tools Ivan Gillian Jill Schneider 4730 Business Park Blvd., #44 9649 Musket Bell Cr.#5 US Geological Survey Anchorage, AK 99503 Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow, AK 99723 ~~~1~~~ 5~~~~6 • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 71h Avenue, Suite 100 Anchorage, Alaska 99501 Re: THE APPLICATION OF ) Area Injection Order No. 1813.007 CONOCOPHILLIPS ALASKA, ) INC. for Administrative Approval ) Colville River Unit allowing well CD 1-21 (PTD 2010060) ) Colville River Field to be online in water only injection ) Alpine Oil Pool service with tubing x inner annulus ) pressure communication. ) December 4, 2013 By letter dated December 1, 2013, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule l l of Area Injection Order (AIO) 018B.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 x Inner Annulus pressure communication to AOGCC on November 2, 2013 while on miscible injectant (MI) injection service for approximately one month. Diagnostics were performed while on MI, and CPAI WAG'ed the well to water on November 8, 2013 after receiving permission from AOGCC for 14 days of water only diagnostic monitoring. The well does not exhibit signs of pressure communication while on water injection. The passing non state witnessed mechanical integrity test of the Inner Annulus (MITIA) on November 5, 2013 indicates that CD 1-21 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. AOGCC's approval to continue water injection only in CRU CD1-21 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 as low as reasonably possible not to exceed 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 MIT anniversary date is June 12, 2013. AIO 18B.007 December 4, 2013 Page 2 of 2 0 DONE at Anchorage, Alaska and dated December 4, 2013 Cathy . Foerster Chair, Commissioner Daniel T. Seamount, Jr. 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. Rasher, 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 ite AOGCC mails, OR 30 days if the AOGCC 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 AOGCC by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. • 9 Singh, Angela K (DOA) From: Colombie, Jody J (DOA) Sent: Friday, December 06, 2013 11:01 AM To: Singh, Angela K (DOA); Ballantine, Tab A (LAW); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Ferguson, Victoria L (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Hunt, Jennifer L (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Eaton, Loraine E (DOA); Bender, Makana K (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Norman, John K (DOA); Paladijczuk, Tracie L (DOA); Pasqua[, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Turkington, Jeff A (DOA); Wallace, Chris D (DOA); (michael j.nelson@conocophillips.com); AKDCWellIntegrityCoordinator; Alexander Bridge; Andrew VanderJack; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Barron, William C (DNR); Bill Penrose; Bill Walker; Brian Havelock; Burdick, John D (DNR); Cliff Posey; Colleen Miller; Crandall, Krissell; D Lawrence; Daryl J. Kleppin; Dave Harbour; Dave Matthews; David Boelens; David Duffy; David Goade; David House; David Scott; David Steingreaber; Davide Simeone; ddonkel@cfl.rr.com; Donna Ambruz; Dowdy, Alicia G (DNR); Dudley Platt; Elowe, Kristin; Evans, John R (LDZX); Francis S. Sommer; Frank Molli; Schultz, gary (DNR sponsored); ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; gspfoff, Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren; Jones, Jeffery B (DOA); Jerry McCutcheon; Jim White; Jim Winegarner; Joe Lastufka; news@radiokenai.com; Easton, John R (DNR); John Garing; Jon Goltz; Jones, Jeffrey L (GOV); Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Keith Wiles; Kelly Sperback; Kiorpes, Steve T; Klippmann; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker; Louisiana Cutler; Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark P. Worcester; Kremer, Marguerite C (DNR); Michael Jacobs; Mike Bill; mike@kbbi.org; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; knelson@petroleumnews.com; Nick W. Glover; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Randy Redmond; Rena Delbridge; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sandra Haggard; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Moothart, Steve R (DNR); Steven R. Rossberg; Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer; Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler; Tim Mayers; Tina Grovier (tmgrovier@stoel.com); Todd Durkee; Tony Hopfinger; trmjrl; Vicki Irwin; Vinnie Catalano; Walter Featherly; yjrosen@ak.net; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater; Anne Hillman; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; David Lenig; Perrin, Don J (DNR); Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr; Smith, Graham O (PCO); Greg Mattson; Hans Schlegel (hans.schlegel@ge.com); Heusser, Heather A (DNR); Holly Pearen; James Rodgers; Jason Bergerson; Jennifer Starck; jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; Josh Kindred; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Bettis, Patricia K (DOA); Peter Contreras; Pollet, Jolie; Richard Garrard; Ryan Daniel; Sandra Lemke; Pexton, Scott R (DNR); Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster; Woolf, Wendy C (DNR); William Hutto; William Van Dyke s � Subject: aio 2b-080 (KRU Admin Approval) and aio 18b-007 (CRU Admin Approval) Attachments: aiol8b 007.pdf; aio2b 080.pdf Jody J. Colombie AOGCC Special Staff Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 iodu. colombieaalaska. aov Office: (907) 793-1221 Fax: (907) 276-7542 Kelly Lyons Problem Wells Supervisor ConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage, AK 99510-0360 C� 0 0 David McCaleb Penny Vadla IHS Energy Group George Vaught, Jr. 399 W. Riverview Ave. GEPS Post Office Box 13557 Soldotna, AK 99669-7714 5333 Westheimer, Ste. 100 Denver, CO 80201-3557 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton cn President 408 18 St. 6900 Arctic Blvd. Golden, CO 80401-2433 Post Office Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI Baker O11 K&K Recycling Inc. Land Department 'COIS Post Office Box 58055 Post Office Box 93330 795 E. 94 Ct. Fairbanks, AK 99711 Anchorage, AK 99503 Anchorage, AK 99515-4295 North Slope Borough Planning Department Richard Wagner Gordon Severson Post Office Box 69 Post Office Box 60868 3201 Westmar Cir. Barrow, AK 9ox23 Fairbanks, AK 99706 Anchorage, AK 99508-4336 Jack Hakkila Darwin Waldsmith James Gibbs Post Office Box 190083 Post Office Box 39309 Post Office Box 1597 Anchorage, AK 99519 Ninilchik, AK 99639 Soldotna, AK 99669 THE STATE GOVERNOR BILL WALKER March 30, 2017 Ms. Kelly Lyons Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-17-009 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 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. �4 Cathy/P. Foerster 6aniel 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 CDI-07 AIO 186.006 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 2B.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 213.012 August 2018 2000260 KUPARUK RIV UNIT 3K-22A I AIO 26.013 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 26.019 August 2018 1841060 KUPARUK RIV UNIT 2G-10 AIO 26.030 May 2018 1880590 KUPARUK RIV UNIT 30-10 AIO 26.033 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 IKUPARUK RIV UNIT 2F-13 AIO 26.039 July 2018 1861780 KUPARUK RIV UNIT 3Q-15 AIO 26.042 August 2018 1890740 KUPARUK RIV UNIT 2K-12 AIO 26.048 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 26.057 August 2018 1811360 KUPARUK RIV UNIT 113-11 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 213.064 June 2017 2101810 KUPARUK RIV UNIT 1E-08A AIO 26.065 June 2018 1950920 KUPARUK RIV UNIT 2T-28 AIO 26.066 June 2017 1851140 KUPARUK RIV UNIT 36-10 AIO 213.067 June 2017 1911250 KUPARUK RIV UNIT 3Q-01 AIO 26.068 August 2018 1841010 KUPARUK RIV UNIT 2D-10 AIO 26.070 August 2017 1831610 KUPARUK RIV UNIT 2V-02 AIO 26.071 June 2017 2120950 KUPARUK RIV UNIT 3N-11A AIO 26.072 August 2018 1840290 1 KUPARUK RIV UNIT 2B-10 AIO 213.073 May 2018 1831870 KUPARUK RIV UNIT 2F-04 AIO 26.074 July 2018 1820310 KUPARUK RIV UNIT 1A-16RD AIO 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 IKUPARUK RIV UNIT 1F-05 AIO 2B.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 213.085 August 2017 1830950 KUPARUK RIV UNIT 2C-08 AIO 2B.086 August 2017 1852460 KUPARUK RIV UNIT 3F-08 AIO 213.087 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 26.092 June 2017 1841920 KUPARUK RIV UNIT 1Q-09 AIO 26.093 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 ID-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 21-1-15 AIO 2C.015 May 2018 1870790 KUPARUK RIV UNIT 3H-07 AIO 2C.016 June 2017 1951210 KUPARUK RIV UNIT IQ-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 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 2B.017 anticipated injection pressure. CPAI shall perform an MIT -IA every 2 years to the maximum 1861960 KUPARUK RIV UNIT 3Q-05 AIO 213.019 anticipated injection pressure. CPAI shall perform an MIT -IA every 2 years to the maximum 1811360 KUPARUK RIV UNIT 1B-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 2B.061 anticipated injection pressure. III , !:II. March 30, 2017 Ms. Kelly Lyons Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-17-009 Alaska Oil and Gas Conservation Commission. 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov 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 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 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// Cathy P. Foerster Chair, Commissioner //signature on file// Daniel T. Seamount, Jr. Commissioner //signature on file// Hollis French Commissioner 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 186.006 June 2017 2010060 COLVILLE RIV UNIT CD1-21 AIO 1813.007 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 213.004 June 2016 1951930 KUPARUK RIV UNIT 3Q-21 AIO 213.005 August 2018 1830960 KUPARUK RIV UNIT 2C-07 AIO 2B.007 August 2015 2001940 KUPARUK RIV UNIT 1A-04A A1O 2B.011 July 2017 1951810 KUPARUK RIV UNIT 311-25 AIO 28.012 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 28.017 June 2017 1861960 KUPARUK RIV UNIT 3Q-05 AIO 2B.019 August 2018 1841060 KUPARUK RIV UNIT 2G-10 AIO 213.030 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 2B.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 26.048 June 2017 1811780 KUPARUK RIV UNIT 1A-12 A1O 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 213.054 June 2018 1831760 KUPARUK RIV UNIT 2V-05 AIO 213.055 June 2018 1830620 KUPARUK RIV UNIT 1Y-08 AIO 213.056 July 2017 2100490 KUPARUK RIV UNIT 3N-16A AIO 26.057 August 2018 1811360 KUPARUK RIV UNIT 16-11 AIO 28.060 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 28.065 June 2018 1950920 KUPARUK RIV UNIT 2T-28 AIO 2B.066 June 2017 1851140 KUPARUK RIV UNIT 36-10 AIO 2B.067 June 2017 1911250 KUPARUK RIV UNIT 3Q-01 AIO 2B.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 213.072 August 2018 1840290 KUPARUK RIV UNIT 213-10 T AIO 213.073 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 213.084 August 2018 1830890 KUPARUK RIV UNIT 2C-03 AIO 28.085 August 2017 1830950 KUPARUK RIV UNIT 2C-08 AIO 2B.086 August 2017 1852460 KUPARUK RIV UNIT 3F-08 AIO 2B.087 June 2017 1851520 KUPARUK RIV UNIT 111-15 AIO 213.088 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 IKUPARUK RIV UNIT 2T-10 AIO 26.092 June 2017 1841920 KUPARUK RIV UNIT IQ-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 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 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 1B-08A AIO 2C.027 June 2017 1850770 KUPARUK RIV UNIT 313-07 AIO 2C.028 June 2017 1840800 KUPARUK RIV UNIT 2G-05 AIO 2C.029 May 2016 2100310 ICOLVILLE RIV FIORD CD3-123 AIO 30.005 February 2018 2110240 ICOLVILLE 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 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 2B.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 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 2B.061 I 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 J (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, 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, AKDCWellIntegrityCoordinator, Alan Bailey, Alex Demarban; Alexander Bridge; 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; 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, lames 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, James 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, 1813, 18C, 28 and 30 Kuparuk River Unit and Colville River Unit JodVI.J. C'olombie _40 O U ' Specie! .:Ilssista-nt 'ftiaska Oii aiid (3as ctmservat ion (:ommissioll 333 West 71" _Avetme llchorage, .;ltaska c)�)5oi Office: (Q07) 793-1221 %'ax: (q07) 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 ColornUe at 907.793.1221 or iody.colombie@alaska.gov. INDEXES 22 1 ConocoPh i I I i ps Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 March 26, 2016 Chris Wallace Alaska Oil and Gas Commission 333 West 7t` 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 A10 2B.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 A10 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 A10 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. 16-08A 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. 1B-11 AIO 213.060 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 11) pad due next July of 2018. Well to be tested early, on or before 7/31/16 to get on schedule. 1E-08A AIO 26.065 8/30/2011 8/27/2015 6/30/2016 3E pad due next June of 2018. Well to be tested early, on or before 6/30/16 to get on schedule. 1E-15A AIO 26.081 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. 1F-04 AIO 2C.006 9/16/2014 2/14/2013 6/30/2016 IF pad due next June 2016. Well to be tested early, on or before 6/30/16 to get on schedule. 1F-05 A10.26.080 7/12/2012 7/4/2014 6/30/2016 Well to be tested early, on or before 6/30/16 to get on schedule. IF-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 26.035 6/28/2008 6/15/2014 7/31/2017 iG 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 IL 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 213.093 5/30/2014 7/9/2013 7/31/2017 IQ 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 213.090 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 26.088 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 NO 26.015 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 213.056 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 213.051 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 NO 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 2026. Well to be tested early, on or before 5/31/16 to get on schedule. 213-07 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 26.073 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 NO 26.085 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 26.007 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. 213-02 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 213.037 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 NO 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 26.074 6/7/2012 6/7/2014 7/31/2016 2F pad due next July of 2026. 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 213.014 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 26.030 2/24/2008 5/1/2012 5/31/2016 This well has been offline since 9/28/12. If the well is 13O1 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 26.076 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 213.017 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 26.048 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. 21--310 A]O 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. 2P-447 AIO 216.001 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. 21-1-05 AIO 26.084 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 NO 213.071 5/29/2012 11/6/2015 6/30/2016 2V pad due next June of 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. 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 2029. 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 offline 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. 3B 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 6/30/17 313-07 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 26.067 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 213.063 6/5/2011 6/5/2015 6/30/2017 performed on or before 6/30/17 to get on schedule. 3F-08 AIO 213.087 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 213.089 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 5/31/17 to 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 213.072 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 213.057 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 28.033 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 213.068 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 26.005 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 08/31/16to 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 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. CD1-07 AIO 186.006 6/8/2008 6/11/2015 6/30/2017 CDi 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 AlO 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 AI0.1813.007 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. CD4-21313 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 Ito 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 Vh Avenue, Suite 100 Anchorage, AK 99501 Dear Mr. Wallace, FEB 2 7 2017 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. 1A-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. 113-08A 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 26.060 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 213.065 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 26.081 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 IF 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 26.035 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 213.054 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 213.088 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 213.056 6/15/2010 6/5/2016 July 2017 1Y pad next due July 2017. Well to be tested on or before 7/31/17 to get on schedule. 1Y-09 AIO 26.051 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. 213-06 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 2B.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 213.085 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 213.091 6/21/2014 6/21/2014 August 2015 This well has been offline since 3/31/16. If the well is BO1 it will be tested post stabilization and then again on the earliest date to align with the schedule. 2C-07 A10 26.007 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 A1O26.086 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 213.052 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 213.070 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 213.039 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 BO1, 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 213.030 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. 2H-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 A10 2B.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 26.017 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 A10 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 AIO 16.003 10/4/2012 9/30/2016 August 2018 Well 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 28.004 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 BO1, 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. 213-447 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 2B.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 26.084 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 26.071 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 26.064 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 213.002 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 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. 36-01 AIO 2C.033 June 2017 6/18/2015 June 2017 3B pad next due June of 2019. No changes 313-05 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. 36-07 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. 36-10 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 213.087 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 213.089 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 No changes 31-1-06 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. 31-1-07 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 3.11 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 213.013 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 26.072 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 26.057 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 213.068 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 213.005 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 311 pad next due August of 2020. Well to be tested on or before 8/31/18 to get on schedule. 3S-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 3S-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 6/11/201S 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.18B.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 13O1 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 BO1 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 All 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. #21 0 • ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 December 1, 2013 Commissioner Dan Seamount Alaska Oil and Gas Conservation Commission 333 West 7t' Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner Seamount: (mac 13 IG13. ConocoPhillips Alaska, Inc. presents the attached proposal as per AIO 18B, Rule 11, to apply for Administrative Approval to allow injection well CD 1-21 (PTD 201-006) to remain in water only injection service with tubing by inner annulus communication only when injecting MI. If you need additional information, please contact myself or Brent Rogers at 659-7224. Sincerely, ?Kelly Lyon Problem Wells Supervisor ConocoPhillips Alaska Inc. Attachments 0 ConocoPhillips Alaska, Inc. Alpine Well CD1-21 (PTD# 201-006) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this Administrative Relief request as per Area Injection Order 1813, Rule 11, to continue water only injection for Alpine injection well CD1-21. The well displays annular communication only when the well is on MI injection. Well History and Status Colville River Unit well CD 1-21 (PTD 201-006) was drilled and completed as a WAG injection well in February 2001. CDl-21 was initially reported to the Commission on November 2, 2013, as showing signs of TxIA communication after being on MI injection since September 5, 2013. Diagnostics were performed while the well remained on MI injection. Inner casing packoff tests and a MITIA to 3000 psi passed. The negative drawdown tubing packoff test of the metal to metal seals failed. Therefore, this may or may not be the point of communication. When the well continued to display TxIA communication following a failed extended IA drawdown test, the well was WAG'ed to water injection on November 8, 2013. Approval was granted for 14 days of water injection. After several bleeds were performed shortly after being WAG'ed, the IA pressure did not show any evidence of repressurization. A follow-up IA drawdown test passed on November 20, 2013. The well was shut in on November 22, 2013. Since then, the IA has continued to not build pressure. See attached 90 day TIO graph. The well does not show any sign of TxIA communication while on water injection, indicating that the communication is possibly a small thread leak downhole or a pack off leak in the well head. ConocoPhillips intends to pursue repairs if the leak worsens enough to be detectable and located on water injection. However, until the leak is detectable both on gas and water injection, ConocoPhillips requests an administrative approval (AA) which will allow the well to remain online in water only injection service. The IA pressure will be maintained below 2000 psi. Barrier and Hazard Evaluation With only water injection, this well has all the barriers of a normal injection well Tubing: The 4-1/2" 12.6# L-80 tubing has integrity to the packer @ 8676' MD, based on passing differential operating pressure between the tubing and casing when on water injection and a passing MITIA to 3000 psi completed on 11/05/13. Production casing: The 7" 26# L-80 production casing with an internal yield pressure rating of 7240 psi has integrity to the packer @ 8676' MD, based on the passing MITIA test outlined above, as well as the differential operating pressure between the tubing and casing when on water injection. Surface casing: The well is completed with 9-5/8" 36# J-55 surface casing with an internal yield pressure rating of 3520 psi. The surface casing is set at 2718' MD (2379' TVD) and the cement shoe was left open after being drilled out. Problem Wells Supervisor 12/1/2013 • • Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Second barrier: The production casing is the secondary barrier should the tubing fail. Third barrier: The surface casing and cement shoe 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 tubing or production casing above the surface casing shoe 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/IO 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 (no MI or gas injection allowed); 2. Perform a passing MITIA every 2-years to the maximum anticipated pressure; 3. Allow operating IA pressure up to 2000 psi, 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 MIT's or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. Problem Wells Supervisor 12/1/2013 2 dWOJL1OAOLIC 0 LO CD ` ' �' CN YI r • r 0 0 ULJ V 0 a- H 0 I c z c� z- z CV fJ r U 0 i I co coo r i i L �J coo r 0} co CA ISd 0 10 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submitto: AOGCC.Inspectorsaalaska.gov phoebe. brooks(a)alaska.gov chris.wallace(Walaska.gov OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: ConocoPhillips Alaska, Inc Kuparuk / CRU / CD1 Pad 11/05/13 Jensen / Beck non -witnessed Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well CD1-21 Type Inj. I G TVD 6,928' Tubing 3,850 3,850 3,850 3,850 Interval p P.T.D. 2010060 I Type test I P Test psi 1732 Casing 325 3,000 2,950 2,950 1 P/F I P Notes: Diagnostic MITIA OA 550 560 560 560 Well I Type Inj. I TVD Tubing Interval P.T.D. I Type test I Test psi I Casing P/F Notes: OA Well Type Inj. I TVD Tubing Interval P.T.D. I Type test I Test psi Casing P/F Notes: OA Well I Type Inj. TVD Tubing Interval P.T.D. I Type test I Test psi I Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. I Type test I Test psi Casing P/F Notes: OA Well I Type Inj. I TVD Tubing Interval P.T.D. I Type test I Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. I Typetest I Test psi Casing P/F Notes: OA Well I Type Inj. I TVD I Tubing Interval P.T.D. I I Type test I Test psi I Casing P/F Notes: OA Well I Type Inj. I TVD I Tubing Interval P.T.D. I Type test I Test psi Casing I P/F Notes: OA TYPE INJ Codes TYPE TEST Codes D = Drilling Waste M = Annulus Monitoring G = Gas P = Standard Pressure Test I = Industrial Wastewater R = Internal Radioactive Tracer Survey N = Not Injecting A = Temperature Anomaly Survey W = Water D = Differential Temperature Test INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance 0 = Other (describe in notes) Form 10-426 (Revised 11/2012) MIT CRU CD1-21 Diagnostic MITIA 11-05-13.xis Cwocahillips Alaska, IIIC. ... I o HANGER, VALVE, NIPPLE, SURFACE, 37-2.718 NIPPLE, 8,734 WLEG, 8.744 WINDOW PRODUCTION, 349,049 WNS Attributes Last Tag: SLM Casing Str Casing Descript CONDUCTOR Casing Descript SURFACE WINDOW L1 Casing Desch OPEN HOLE Tubing S1 TubingDescri TUBING :Id Name Well Status in (°( MD IRK PINE INJ 93.40 10,: H2S (ppm) jDate Annotrtlon End Date KB-Grd CD1-21 TD Act Btm (ftKB) 11.087.0 Last WO: 44.39 1 2/25/2001 KB) 3.0 End Date Annotation 11/27/2012 Rev Reason: SET INJ VLV I Last Mod ... osborl End Dete 6/102013 ing 0... 16 ... Top (ftKB) 37.0 Set Depth if... 114.0 Set Depth ( VD) ... 114.0 String Wt... 62.58 String ... H-40 String Top Thrd WELDED Ing 0... 9 5/8 ... Top (ftKB) 36.8 Set Depth (f... 2,717.8 Set Depth (ND) ... 2,378.9 String Wt... 36.00 String ... J-55 String Top Third BTC ing 0... 7 ...Top rString! (ftKB) 34.5 Set Depth If... 9,049.5 Set Depth (ND) ... 7,040.7 String Wt... 26.00 String ... L-80 String Top Thrd BTCM Ing 0... 61/88,987.0 ... Top (ftKB) Set Depth ifSet 8,997.0 Depth (ND) ... 7,036.7 String Wt... String ... String Top Thrd ing 0... 61/8 ... 6.125 Top (ftKB) 9,049.0 Set Depth if... 11,087.0 Set Depth (ND) ... 6,999.9 String Wt String ... String Top Thrd ing 0... 41/2 String ID ... 3.958 Top (ftKB) 32.3 Set Depth (f... 8,745.8 Set Depth (ND) ... 6'962.8 String Wt... 12.60 String ... L-80 String Top Thrd IBTM S Incl .I hem Descriotlon Comment No - ID (in In Hole Wireline Top Depth (ND) Top Incl Comment OPEN HOLE, 9,049-11,087 TD (CD1-21). 11,087 X20 • Conocot~illips a P.O. Bt?X 100360 APICHOR~E, ALASKA 94510-0360 January 30, 2010, _ Mr. Daniel Seamount, Chairman Alaska Oil & Gas Commission 333 West 7~' Avenue, Suite 100 Anchorage, AK 99501 • Subject: CD2-56 (PTD# 204-150) Request for Cancellation of AIO 18B.005 Dear Mr. Norman: ConocoPhillips Alaska, Inc. requests cancellation of Administrative Approval 18B.005. The approval, originally issued on May 26, 2009, was for continued water injection with TxIA communication. The tubing was replaced and an additional packer was set during a recent rig work over. The well passed a MITIA on O1/24!10 which was witnessed by a State inspector Chuck Scheve. If you require any additional information please contact myself or Brent Rogers at 907- 659-7224. Sincerely, Martin Walters Problem Wells Supervisor Cc: Central Files, Working Well Fiie, Legal Well File, PE, DSLT ll - _ I f~P py'~ /j'IQ' ~ C~OGvrr~Ps~ ~G~/e~1 ~n ~~~ ~ ~D G G C ®~i~ ~ /~~/Gr1 Page 1 of 1 Maunder, Thomas E (DOA) From: NSK Problem Well Supv [n1617@conocophillips.com] Sent: Thursday, March 18, 2010 1:38 PM To: Maunder, Thomas E (DOA) Cc: NSK Problem Well Supv Subject: Copy of Cancellation request for CD2-56 Attachments: CD2-56 AA Cancellation AIO 18B 005 01-30-10 Resubmission.pdf Tom, Here is a copy of the request that Martin resubmitted. Please let me know if you have any questions. Brent Rogers/Martin Walters Problem Wells Supervisor ConocoPhillips Alaska, Inc. Desk Phone (907) 659-7224 Pager (907) 659-7000 pgr. 909 3/18/2010 x#19 • Page 1 of 3 Maunder, Thomas E (DOA) From: NSK Problem Well Supv [n1617@conocophillips.com] Sent: Thursday, January 21, 2010 3:16 PM To: Maunder, Thomas E (DOA) Subject: RE: ConocoPhillips Cancellation of A1018B.003 Tom, That test has not been completed yet. We will submit the results as soon as it is complete. Brent RogerslMartin Walters Problem Wells Supervisor ConocoPhillips Alaska, Inc. Desk Phone (907) 659-7224 Pager (907) 659-7000 pgr. 909 From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Thursday, January 21, 2010 3:11 PM To: NSK Problem Well Supv Cc: NSK Well Integrity Proj; Schneider, Tim S.; Regg, James B (DOA); Schwartz, Guy L (DOA) Subject: RE: ConocoPhillips Cancellation of AI018B.003 Martin, I have the MIT for CD2-48 and have prepared the cancellation document. I do not find the MIT for CD2-56. Has that been accomplished? Thanks in advance. Tom Maunder, PE AOGCC From: NSK Problem Well Supv [mailto:n1617@conocophillips.com] Sent: Tuesday, January 12, 2010 2:43 PM To: Schwartz, Guy L (DOA); Maunder, Thomas E (DOA); Regg, James B (DOA) Cc: NSK Well Integrity Proj; ALP DS Lead and Simops Coord; Reed, Scott; Schneider, Tim S.; Barreda, Brian B; Tonello, John V; Pysz, Nick P; NSK Problem Well Supv Subject: ConocoPhillips Cancellation of AI018B.003 Guy/Tom/Jim, Alpine injector CD2-48 (PTD#202-108) passed its post workover MITIA as witnessed by Lou Grimaldi on 01/08/10. CPAI hereby requests that Administrative Approval A1018B.003 be cancelled and allow the well to be returned to WAG injection service. The well will also be removed from the monthly report. Please contact me at your convenience if you have questions or comments. Martin Martin Walters / Brent Rogers Problem Wells Supervisor ConocoPhillips Alaska Inc. 1 /22/2010 • . Page 2 of 3 Office 907-659-7224 Cell 907-943-1720 / 1999 Pager 907-659-7000 #909 From: Schwartz, Guy L (DOA) [mailto:guy.schwartz@alaska.gov] Sent: Tuesday, October 20, 2009 1:37 PM To: Schneider, Tim S.; Maunder, Thomas E (DOA) Cc: NSK Well Integrity Proj; ALP DS Lead and Simops Coord; Regg, James B (DOA); NSK Problem Well Supv; Reed, Scott; Packer, Brett B; ALP DS Lead and Simops Coord Subject: RE: Cancellation of AI018B.003 And AI018B.005 Tim/Martin, I haven't seen the 10-404 for CD2-56 but assume it will be in hand shortly. I have just received the 404 for CD2- 48late last week. Don't remember all the issues with these two wells but hopefully the stacker packer and new tubing will solve issues with elevated IA pressures associated with the MI injection. Keep me in the loop on the witnessed MIT testing and I will try to expedite the cancellations. Are you planning on going to MI as soon as possible?? Guy Schwartz Petroleum Engineer AOGCC 793-1226 (office) 444-3433 (cell) From: Schneider, Tim S. [mailto:Tim.S.Schneider@conocophillips.com] Sent: Tuesday, October 20, 2009 12:48 PM To: Maunder, Thomas E (DOA) Cc: NSK Well Integrity Proj; ALP DS Lead and Simops Coord; Regg, James B (DOA); NSK Problem Well Supv; Schwartz, Guy L (DOA); Reed, Scott; Packer, Brett B; ALP DS Lead and Simops Coord Subject: RE: Cancellation of AI018B.003 And AI018B.005 Tom, We have not yet brought the wells online due to rig interference while sidetracking CD2-60A (completed on 10- 18). We will be performing the post rig slickline work this week and should get the two wells on water injection by early next week. Our operations personnel will then be communicating with the AOGCC to perform a witnessed MITIA once the wells stabilize. Let me know if any additional information is required for these two wells. Thanks Tim S. Schneider Subsurface Development Staff Production Engineer WNS-Alpine ~ Phone: 907-265-6859 S Fax: 907-265-1515 <~? Mobile: 907-632-8136 Email: timsschneider@conocophillip_s_.com From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Tuesday, October 20, 2009 10:50 AM To: NSK Problem Well Supv Cc: NSK Well Integrity Proj; ALP DS Lead and Simops Coord; Schneider, Tim S.; Regg, James B (DOA); Schwartz, Guy L (DOA) 1 /22/2010 f ~ ~ . Page 3 of 3 Subject: RE: Cancellation of AI018B.003 And AI018B.005 Martin, et al, Has the witnessed MIT been accomplished for either of these wells? The most recent information in our files is the sundries which were only issued - 4 weeks ago. I understand that Guy has just reviewed one of the 404s. While the work has been accomplished and the pressure tests performed while running the new completions likely demonstrated that primary integrity has been restored, your request to cancel the approvals seems premature. If the pressure tests accomplished by the rig indicate integrity, it is acceptable to resume water injection. As soon as we have all the documentation, it will time to move on the cancellations. Tom Maunder, PE AOGCC From: NSK Problem Well Supv [mailto:n1617@conocophillips.com] Sent: Monday, October 19, 2009 1:57 PM To: Regg, James B (DOA); Maunder, Thomas E (DOA); Schwartz, Guy L (DOA) Cc: NSK Well Integrity Proj; NSK Problem Well Supv; ALP DS Lead and Simops Coord; Schneider, Tim S. Subject: Cancellation of AI018B.003 And AI018B.005 Jim/Tom/Guy, Alpine injectors CD2-48 (PTD#202-108) and CD2-56 (PTD#204-150) recently underwent workovers to repair TxIA communication. Administrative Approvals A1018B.003 and A1018B.005 are hereby cancelled. Both wells will also be removed from the monthly report. Please contact me at your convenience if you have questions or comments. Martin Martin Walters / Brent Rogers Problem Wells Supervisor ConocoPhillips Alaska Inc. Office 907-659-7224 Cell 907-943-1720 / 1999 Pager 907-659-7000 #909 1 /22/2010 ~~~ • Page 1 ~~~~ Regg, James B (DOA) From: NSK Problem Well Supv [n1617@conocophillips.com] Sent: Thursday, May 28, 2009 3:17 PM ~e~ ~I "~IZ~`~~~ To: Regg, James B (DOA) Subject: RE: CRU CD1-07 Admin Approval Request Attachments: CD1-07 TIO Plot.ppt '~ As per your request. Martin From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Thursday, May 28, 2009 2:49 PM To: NSK Problem Well Supv Subject: RE: CRU CD1-07 Admin Approval Request apologize for the repeat messages. I reviewed the TIO plot; legend was truncated so I cannot tell which line goes with T, IA and OA pressures. Please resend TIO plot with lines labeled. Thank you. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 From: Regg, James B (DOA) Sent: Thursday, May 28, 2009 2:10 PM To: 'NSK Problem Well Supv' Subject: RE: CRU CD1-07 Admin Approval Request Disregard my message; I found email dated 5/23/09 with TIO plot and well schematic. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 From: Regg, James B (DOA) - Sent: Thursday, May 28, 2009 11:35 AM To: 'NSK Problem Well Supv' Subject: CRU CD1-07 Admin Approval Request Received request for admin approval on May 27 from Lead DHD Tech Ron Bates. Application is incomplete - missing current TIO plot, well schematic, diagnostic IA DD test results. Jim Regg 5/28/2009 ~~z~~2~ 5 5ZZ ` X02 ~ Ln-~ CjJ r~~ ConoenPt~illips 1~I~si~~x ~~, TUBING (0-12471, , OD:4.500, ' ID:3.958) SURFACE (0-3041, OD:9.625, Wt:36.00) PRODUCTION (0-13477, OD:7.000, wt:zs.oo) Gas Lift nndrel/Dummy Valve 1 ;12292-12293, # ;° OD:5.984) PACKER ;12407-12408, OD:5.970) NIP ;12459-12460, OD:5.000) WLEG ;12470-12471, OD:5.000) OPEN HOLE , ;1 34 7 7-1 7 5 90, OD:6.125) 1 , 1 -'' ALPINE CD1-07 CD1-07 API: 501032047800 Well T e: INJ An le TS: de SSSV Type: NIPPLE Orig Completion: 2/13/2004 Angle @ TD: 93 deg @ 17590 Annular Fluid: Last W/O: Rev Reason: Reset CSG to s Reference Lo 36' RKB Ref Lo Date: Last U date: 12/4/2004 Last Ta TD: 17590 ftK6 Last Ta Date: Max Hole An le: 93 de 17590 Casin _Strin - ALt'STRING S Descri lion Slze To _ Bottom -, TVD Wt Grade Thread CONDUCTOR 16.000 0 114 114 62.50 H-40 WELDED PRODUCTION 7.000 0 13477 6900 26.00 L-80 BTCM SURFACE 9.625 0 3041 2364 36.00 J-55 BTC OPEN HOLE 6.125 13477 17590 17590 0.00 Tubin Strin -TUBING -- - Size To Bottom TVD Wt Grade Thread 4.500 0 12471 6638 12.60 L-80 IBTM Gas Lift Mandrels/Valves St MD TVD Man Mfr Man Type V Mfr V Type V OD Latch Port TRO Date Run Vlv Cmnt 1 12292 6558 CAMCO KBG-2 DMY 1.0 BK 0.000 0 3/30/2004 Other lu s, u .etc. -JEWELRY De th TVD T e Descri lion ID 33 33 HANGER FMC 2.5" TBG HANGER 4.500 2291 2021 NIP CAMCO 'DB' LANDING NIPPLE 3.812 2291 2021 VALVE 3.812" A-1 INJECTION VALVE W/1.25" ORI 3/31 /2004 FICE (ser #HWS-38) Set 1.250 12407 6610 PACKER BAKER S-3 W/MILLOUT EXTENSION 3.875 12459 6633 NIP HES NO GO'XN' NIPPLE 3.725 12470 6638 WLEG BAKER WIRELINE GUIDE 3.875 General N otes Date Note 2/14/2004 TREE: FMC 4-1/16 5K TREE CAP CONNECTION: 7" OTIS ~~ • ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 May 23, 2009 Mr. James B Regg Alaska Oil & Gas Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 ("Its A~~Ska ~!~ ~ GAS l+C,,'° ~~s~S1~JP? AftG~'3~?:', . M+ Dear Mr. Regg: Enclosed, please find a request for Administrative Relief to continue water injection operations for well CD1-07 (PTD 203-225) Please call Brent Rogers or Martin Walters @ 659-7224 if you have any questions. 1, Ron Bates Lead DHD Technician Attachments ~ a ConocoPhillips Alaska, Inc. Alpine Well CD1-07(PTD 203-225) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc., proposes that the AOGCC approve this Administrative Relief request as per Area Injection Order 18B, Rule 11, to continue water only injection with known annular communication for Alpine injection well CD 1-07. Well History and Status Colville River Unit well CD1-07 (PTD 203-225) was drilled and completed in February 2004 as a WAG injection well. On 06/12/08, the well passed an AOGCC witnessed MITIA. CD1-07 was originally reported with suspected TxIA communication on 06/19/08 and diagnostics indicated the tubing packoffs appeared to be leaking. After reported, the well was put on water injection for further diagnostics. On 06/26/08, the well passed another MITIA and an IA DD test while on water injection. The tubing packoffs were energized and permission was granted to return the well to gas injection for diagnostics. An ultrasonic LDL was unable to detect a leak in the tubing leading us to believe the packoffs are the leak source. The well remained in gas service and the TIO plots showed no signs of communication until Jan. 2009. At which time, the well was reported again and diagnostics indicate the tubing packoffs are leaking on MI. The well was swapped to water injection 4/22/09, since then, the packoffs have shown to be a competent barrier. The well will require a workover to repair the tubing packoffs. Barrier and Hazard Evaluation Tubing: The 4-1/2" 12.6# L-80 tubing has integrity to the packer at 12,407' MD based on the passing MITIA's performed on 06/12/08 and 06/26/08. Production casing: The 7" 26# L-80 production casing with an internal yield pressure rating of 7240 psi has integrity to the packer @ 12,407' MD based on the MITIA's described above. Surface casing: The well is completed with 9-5/8" 36# J-55 surface casing with an internal yield pressure rating of 3520 psi. The surface casing is set at 3041' MD (2364' TVD). The well has an open shoe and will hold pressure up to 850 psi. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the production casing and packer. Second barrier: The surface casing with an open shoe are the second barrier. Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the tubing, production casing, or surface casing 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 ashut-in of the well. T/UO plots are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. Approved Operating and Monitoring Plan NSK Problem Well Supervisor 5/25/2009 1. Well will be used for water injection only (no gas or MI allowed); 2. Perform a passing MITIA every 2-years as per AOGCC criteria (0.25 x tvd @ packer, 1500 psi minimum); 3. Submit monthly reports of daily tubing & IA pressures and injection volumes; 4. Shut-in the well should MIT's or injection rates and pressures indicate further problems; 5. Workover and/or repair the well prior to gas injection consideration with appropriate AOGCC notification. NSK Problem Well Supervisor 5/25/2009 2 SC 3000 2700 ,v 2'400 2100 1800 1500 1200 900 600 y )00 0 WELL NAME WLALPCDI-07 PLOT -ART TIME MINOR TIME PLOT DURATION PLOT EN-1IME 24-FEB-09 11:57 MAJOR TIME WEEK ++ 16 :" :-Do - 25-MAY-09 7 ~~~ WNS ~ CD1-07 COflOCO~ 'II~~IPS Well Attributes Wellbore API/l1Wl Field Nenw Well Statue Maxim um Inclination (°) T otal Depth (ftKB) '~''~'"'' ~~' 501032047800 ALPINE INJ 92.74 17,590.0 Comment H2S (ppm) Dato Annotation Entl Date KB-Grtl (/t) Rip Release Deto w Con : -COt-07 Og1200 8 3 03 39 PM Last WO: 36.95 2/13/2004 emouc-Acted Annotation DepN (ftKB) End Dato Annotellon E nd Date Last Tag: Rev Reason: PULL PLUG, set INJ VLV 8/7/2008 Casin Strin s Casing Deacriptlon OD Iln) ID (ln) Top (ftKB) Set Depth (ftNB) Set Depth (ND) (ftKB) Wt (lbe/(t) Dreda Top Thread ~ ~ ~ CONDUCTOR 16 15.062 0.0 114.0 114.0 62.50 H-00 WELDED I , I SURFACE 95/8 8.921 0.0 3,041.0 2,363.7 36.00 J-55 BTC PRODUCTION 7 6.151 0.0 13,477.0 6,904.6 26.00 L-80 BTCM e~ -~ OPEN HOLE 6 118 13,477.0 17,590.0 HANOER. 33 ~ Tubin Stfln s Tubing Deacdption OD (In) ID (In) Top (ftKB) Set Depth (ftKB) Sat Depth (N D) (ftKB) Wt (Iba/k) Grade Top ThraeO TUBING 4 1/2 3.958 0.0 12,471.0 6,638.4 12.60 L-80 I BTM Other In Hole Al l Jewel :Tubin Ru n 8 Retrievable, Fis h, etc. Top (ftKB) Deecrlption Comment Run Dab ID (In) coNOUCTOR, 33.0 HANGER FMC 4.5" TBG HANGE R 21742004 4.500 111 2,291.0 NIPPLE CAMCO'DB' LANDIN G NIPPLE 21142004 3.812 2,291.0 VALVE 3.812" A-1 INJECTION VALVE W/1.25" ORIFICE ( 7tFIWS-3 80) 8/72008 1.250 12,292.0 GAS LIFE CAMCO/KBG-Z/1/DMY /BK/// Comment STA 1 3x302004 3.938 NIPPLE, 2,291 ~ 12,407.0 PACKER BAKER S-3 W/MILLO UT EXTENSION 2/142004 3.875 VALVE, 2,291 - 12,459.0 NIPPLE HES NO GO'XN' NIPP LE 2/142004 3.725 12,470.0 WLEG BAKER WIRELINE GU IDE 2/142004 3.875 SURFACE, 3,011 OAS LIFT, 12,292 PACKER, 12,107 I{I {~ f NIPPLE, 12,159 WLEO, 12,170 PRODUCTION, 13,177 O O OPEN HOLE, O , 17,590 TD (CDt-07), 17,590 X16 ConocoPhillips ~s~ P.0. BOX 100360 ANCHORAGE, ALASKA 99510-0360 May 9, 2009 Mr. Jim Regg Alaska Oil & Gas Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Dear Mr. Regg: • ~;~=~ ~~8s ~,~r .~~ ~a ~'tf~~v.. f q~ ~ ~~,,- ~' o ~~~~ ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 18B, Rule 11, to apply for Administrative Approval allowing well CD2-56 (PTD 204-150) to be online in water only injection service with suspected production casing by formation communication via a one way packer leak. ConocoPhillips intends to pursue a rig workover to repair the well in the future, the appropriate paperwork will be submitted at that time. If you need additional information, please contact myself or Martin Walters at 659-7224, or MJ Loveland / Perry Klein at 659-7043. Sincerely, i Brent Rogers Problem Wells Supervisor ConocoPhillips Alaska Inc. Attachments • ConocoPhillips Alaska, Inc. Alpine Well CD2-56 (PTD 204-150) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc., proposes that the AOGCC approve this Administrative Relief request as per Area Injection Order 18B, Rule 11, to continue water only injection with known annular communication for Alpine injection well CD2-56. Well History and Status Colville River Unit well CD2-56 (PTD 204-150) was drilled and completed in October 2004 as a WAG injection well. CD2-56 was converted from MI injection to Sea water on 02/13/09. On 06/29/08 the well was reported to the AOGCC with suspected TxIA communication. On 07/11/08, with the well on water injection, an MITIA passed @ 3000 psi but the tubing packoffs failed and the IA failed a DD test. On 08/04/08, the tubing packoffs were energized and a passing test was completed. While on injection, the tubing and inner annulus did not equalize, continually maintaining 500 psi or greater differential pressure. The well continued to maintain a significant differential pressure, however showed signs of an elevated IA pressure. On 04/12/09, the well passed an MITT to 3000 psi and an MITIA to 3050 psi. On 04/20/09, the IA failed a DD test with a very small linear pressure increase (~20 psi) while on water injection. The well is currently on injection and is maintaining a 1500 psi differential pressure from the tubing to the IA. See TIO plot. ConocoPhillips intends to repair the well with a workover and would like to continue injection until the well is repaired. Barrier and Hazard Evaluation Tubing: The 4-1/2" 12.6# L-80 tubing has integrity based on the passing MITT on 04/12/09 with a plug set @ 13,193'. Production casing: The 7" 26# L-80 production casing has integrity to the packer @ 13,128' MD based on the MITIA on 04/12/09. Surface casing: The well is completed with 9-5/8" 36# J-55 surface casing with an internal yield pressure rating of 3520 psi. The surface casing is set at 3523' MD (2365' TVD). The well has an open shoe. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Second barrier: The production casing is the secondary barrier should the tubing fail. Third barrier: The surface casing will act as a third barrier should the first two barriers have failures. Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the tubing, production casing, or surface casing it will be noted during the daily monitoring process. Any deviations from approved MAOP annular pressures require investigation and NSK Problem Well Supervisor 5/9/2009 corrective action, up to and including ashut-in of the well. T/I plots are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. Approved Operating and Monitoring Plan 1. Well will be used for water injection only (no gas or MI allowed); 2. Perform a passing MITIA every 2-years as per AOGCC criteria (0.25 x tvd @ packer, 1500 psi minimum); 3. Submit monthly reports of daily tubing & IA pressures and injection volumes; 4. Shut-in the well should MIT's or injection rates and pressures indicate further problems; 5. Workover and/or repair the well prior to gas injection consideration with appropriate AOGCC notification. NSK Problem Well Supervisor 5/9/2009 2 'w.,TLLS 'w/LHD CURRENT VALUE CURRENT VALUE CURRENT VALUE CURRENT VALUE OPERATOR NOTES SET CHOKE CHOKE 104. INJ RATE 4510- WH PRESS 2364. ORIF DP 14.73 INJ TEMP 73. INJ VOL 3159. IGV/OGV OPEN FL PRESS 2364_ WELLSTATUS 105-00 3000 ON 3000. ERT OPEN/SI 3000. 2700 EVENT AT 3000. PICK TIME 6000. 2400 72.43 GENERAL PURPOSE 2100 EVENT AT 3000. PICK TIME CREATE WELL AUTOSCALE 1800 NOTE AT 10101313 PICK TIME 09 = 1500 ORIFICE a .1200 L7 FREEZE PROTECTION W--mwx SAVE F.�. " 900 CREATE 600 SAFETY DEFEAT U. VIEW 0. SAFETY DEFEAT 50. 300 0. 0.00 0 PREV WELL 0.00 Pff NEXT WELL 0.00 --------------------------------------------------------------------------------------------------- ------------------------------------------------ ---------------------------------------------------------------------------------------------- ------------- ----------------------------- ER SCALE DESC PICK VALUE LATEST CHOKE 15. 104. 2196. 0 09-MAY-09 16:45 WH PRESS 2378. 2364. INJ TEMP 74. 73. F- 7- F- F- F- 7 FL PRESS 2378- 2364. INJ RATE 5192. 4510. MINOR TIM: PW ORIF-bP 19.53 14.73 M T Mk-'- --.- WEEK 1A PRES 750. 750. 1 0A. PRES 100. 100. DAILY eicK TIME 07-14AY-09 01:30:37 N ANNCOM PROBLEMS DAY Flags: TBG: IA: Suspect TxIA Communication OA: DAY --------ICI- --------------------- ---------- - -------- - --------- -- --------- --- ------------------- ---------------------- ----------- ---------- v ---------- --------- - - ------ - --------------------- --------- --------- * ----- -------- -------------- ---- ---------- ------------------ I., - ----------- --------- --------- ---- ---- ---------- -- ------------ - - ---------- ---- ---------- - ------ ----------- ----------- ---- ---- --------- ------- ---------------- ------ ------- ------- ---------------------- ---- --- I ------------ 1- - - I-- ----------------------------------- -------- --------- I ------- - --------- ------- -------------------- - -- ----------- ---- ----------- ---- ----------------- --------------- ---------- ----------- -- - -------- *,� ---------------------- ---- ---- --------------------- ---------- - -------- - --------- -- --------- --- ------------------- ---------------------- ----------- ---------- v ---------- --------- - - ------ - --------------------- --------- --------- * ----- -------- -------------- ---- ---------- ------------------ I., - ----------- --------- --------- ---- ---- ---------- -- ------------ - - ---------- ---- ---------- - ------ ----------- ----------- ---- ---- --------- ------- ---------------- ------ ------- ------- ---------------------- ---- --- I ------------ 1- - - I-- ----------------------------------- -------- --------- I ------- - --------- ------- -------------------- - -- ----------- ---- ----------- ---- ----------------- --------------- ---------- ----------- -- - -------- *,� ---------------------- ---- ---- STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Email to:jim.regg@alaska.gov; tom.maunder@alaska.gov;bob.fleckenstein@alaska.gov;doa.aogcc.prudhoe.bay@alaska.gov OPERATOR: FIELD /UNIT /PAD: DATE: OPERATOR REP: AOGCC REP: ConocoPhillips Alaska Inc. Alpine /CRU /CD2-56 04/12/09 HES Packer Depth Pretest Initial 15 Min. 30 Min. Well CD2-56 Type Inj. N TVD 6,998' Tubing 2,350 3,000 2,925 2,925 Interval O P.T.D. 2041500 Type test P Test psi 1750 Casing 1,350 1,350 1,350 1,350 P/F P Notes: Diagnostic MITT OA 100 100 100 100 Plug is set @ 13,193' in HES XN nipple Well CD2-56 Type Inj. W TVD 6,998' Tubing 2,325 2,322 2,324 2,324 Interval O P.T.D. 2041500 Type test P Test psi 1750 Casing 1,100 3,050 2,975 2,950 P/F P Notes: Diagnostic MITIA OA 200 350 350 350 Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubin Interval P.T.D. Type test Test psi Casing P/F Notes: OA TYPE INJ Codes D =Drilling Waste G =Gas I =Industrial Wastewater N =Not Injecting W =Water TYPE TEST Codes M =Annulus Monitoring P =Standard Pressure Test R =Internal Radioactive Tracer Survey A =Temperature Anomaly Survey D =Differential Temperature Test INTERVAL Codes I =Initial Test 4 =Four Year Cycle V =Required by Variance T =Test during Workover O =Other (describe in notes) MIT Report Form BFL 11/27/07 MIT CRU CD2-56 04-12-09.x1s ~, ~y WNS • CD2-56 W1 KrilJrl ll~~lpS ~ tNell Attributes Max A n le 8 MD TD AI~1~,i.A I~1~ Wallbora API/U WI Fla ltl Nama Wall Sbtus Prod/InJ Type Inc! (°) MD (ftK6) Act 8[m (RKB) , 501032049800 AL PINE INJ 92.21 14,934.84 19,544.0 Comment H23 (ppm) Date Annotatlon Entl Data KB-Grtl (fl) Rlg Release Dab ""° SSSV: WRDP 0 7/1/2008 Last WO: 43.63 10/32004 Well on 11/19 12:18:15 AM SCMmatk-Actual Annotatlon DepN (RKB) End Data A nnotatlon Entl Oate Last Tag: 14,165.0 10232004 R ev Reason: SET INJ VLV 11/18!2008 Casin Strin s String OD 3tring ID Sat Depth Sat Daplh (TVD) Stri ng Wt String Casing Descrlp[lan (In) (Inl Top (RKB) (RKB) (RKB) (IbsRt) Oratle String ToD Thrtl CONDUCTOR 16 15.062 0.0 114.0 114.0 62.50 H-40 WELDED SURFACE 9518 8.921 0.0 3,523.0 2,365.3 38.00 J-55 BTC PRODUCTION 7 6.151 0.0 14,391.0 7,366.0 26.00 L-80 BTCM OPEN HOLE 6 1/8 6.125 14,391.0 18,027.0 7,359.1 Tubin Strin s HANGER. 30 String 00 String ID Sa[ Depth Se[ Depth (TVD) String WI String Tubing Descrlptlon (In) (In) Top (RKB) (RKB) (RKB) (IbsIR) Grade String Top Thrtl TUBING 4 1/2 3.958 0.0 13,207.0 7,033.8 12.60 L-80 EUE Other In Hole A ll Jevr el :Tubin Run 8c Retrievable Pish etc. Top Depth (TVD) Top Inc! Top (RKB) (RKB) (°) Deacrlptlon Comment Run Data ID (In) 34 0 34 0 -0 28 HANGER FMC 4 5" TUBING HANGER 1022004 3.958 CONDUCTOR. . . . . tte 2,339.0 1,811.3 62.10 SAFETY VLV 3.812" A-1 INJECTION VALVE (HWS-05) 111752008 1.250 2,339.0 1,811.3 62.10 NIPPLE CAMCO'DB'NIPPLE 1022004 3.812 13,015.0 6,943.6 61.00 GAS LIFT CAMCO/KBG-2/1/DMY/BK/ll Comment: STA 1 1022004 3.938 13,128.0 6,997.6 62.27 PACKER BAKER S-3 PACKER 1022004 3.875 NIPPLE. 2 339 13,193.0 7,027.4 62.98 NIPPLE HES'XN'NIPPLE 1022004 3.725 . SAFETY VLV. ~ 13 205.0 7 032.9 63.11 WLEG BAKER WIRELINE ENTRY GUIDE 7022004 3.875 2,339 ~ , , Notes: Gener al & Safe '~ Entl oat. Annotation 10/22004 NO TE: TREE: FMC 4-1116 SK-TREE CAP CONNECTION: 7" OTIS 10/22004 NO TE: MULTI-LATERAL WELL CD2-56, CD2-5611 SURFACE, 3,523 GAS LIFT. 13 015 PACNEH, 13,125 NIPPLE. 13,193 WLEG. 13 ZOS PRODUCTION. 10.391 OPEN HOLE. Q 15,021 rD (coz-551. 19 sa4 ~ OPEN MOLE ~ 0 Lt, 19.55< e ~k15 • Conoc Phillips Alaska, Inc October 1, 2007 Mr. Shawn Stokes Manager, Wastewater Discharge Program Alaska Department of Environmental Conservation 555 Cordova St. Anchorage, AK 99501 RE: Class 1 Well Application Well CD1-19A Dear Mr. Stokes: • Jason Charton Senior Environmental Coordinator 700 G Street, ATO 1756 P.O. Box 100360 Anchorage, Alaska 98510-0360 Phone 907.263-4978 Fax 907.265.1515 Certified Mail 7001 2510 0002 9588 7649 Return Receipt Requested ConocoPhillips Alaska, Inc. hereby submits a Notice of Disposal for an existing disposal well at the Alpine Oilfield. The well is known as CD1-19A. It is currently permitted by the State of Alaska Oil and Gas Conservation Commission as a dedicated Class II disposal well. CPAI is permitting the well for Class I disposal. The Environmental Protection Agency ("EPA") Underground Injection Con#rol ("UIC") permit wil! be forwarded upon receipt. Please find the enclosed $275 application fee, EPA UIC permit application binder and form 2005DB0001. Should you have any questions or need additional information, please feel free to contact me at the numbers or address listed above. Sincerely, ason Charton Senior Environmental Coordinator Enclosures Cc: Thor Cutler -EPA (electronic w/o binder) Talib Syed - TSA, Inc. (electronic wlo binder) Tom Maunder - AOGCC (electronic w/o binder) Isaac Nukapigak - Kuukpik (electronic w/o binder) • STATE OF ALASKA DEPARTMENT OF ENVIRONMENTAL CONSERVATION DIVIION OF WATER NOTICE OF DISPOSAL FOR CLASS I INJECTION WELL 2005D60001 See General Permitfor details on eltgtbility, requested application information and perrntt requirements. RESPONSIBLE PARTY fowner_ onerator_ or nersnn reannncihle for overall manaoPmrnt of the nrn;P~rl• First Name: Jason Last Name: Charton Phone Number: 907.263.4978 Com an Name: ConocoPhilli sAlaska,Inc. Fax Number: 907.26S.1S1S Mailin Address: PO Box 100360, ATO-1756 Ci Anchor a State: AK Zi 99S 10 Email Address: jason.t.charton Conoco hilli s.com ON SITE CONTACT: First Name: Wendy/Jodi Last Name: Mahan/Smith Phone Number: 907.670.4423 FACILITY: NAICS Code former l the Standard Industrial Code (SIC)):221111 Facili Name: Al ine Oil Field Phone Number: 907.670.4423 Mailin Address: PO Box 100360, ALP 14 Fax Number: 907.670.4205 City: Ancho a State: AK Zi 99S 10 Physical Address:. North Slo e CONSi Tf .TANT• First Name: N/A Last Name: N/A Phone Number: N/A Company Name: N/A Fax Number: N/A EPA CLASS I INJECTION WELL PERMIT NUMBER: Pending Beginning Date: TBD Ending Date: TBD INJECTION FLOW RATES ANn V~T.T 1MF• Avera e: SOM Gallons Per Da Maximum: 200M Gallons Per Da Estimated Total Injection Volume: 874 MM Gallons over 20 years LOCATION OF INJECTION POINT(S): Area(s): Colville River Unit Name of formation and depth(s): Ivishak Formation 9200 ft Latitude /Longitude of Injection Point(s) in decimal degrees: Well: CDl-19A Latitude: 70.3S331S30001 Longitude: 150.93035103966 Well: Latitude: Longitude: Well: Latitude: Longitude: Well: Latitude: Longitude: Lat/Long Coordinate Source: ^ Internet ^ MAP ®GPS/Survey Datum: NAD 27 • 9/26/2007 Page 2 ADEC 2005DB0041 NOD MAPS OF INJECTION POINT(S): Submit to ADEC two maps: a map that shows the general location of the facility and a detailed map that shows the facility layout monitoring wells, injection wells, drinking water wells, abandoned wells, water bodies and other pertinent information within the area of interest (0.5 mile radius of the facility}. Maps may be drawings, USGS maps, or aerial photographs and must include a scale. ®Maps attached GENERAL DESCRIPTION OF THE PROJECT: Describe where the wastewater to be injected comes from; the chemical, physical, and biological characteristics of the wastewater; and what if an wastewater treatment will be erfonned. See attached UIC application for re uested detail. OTHER PERTINENT INFORMATION: Describe unusual circumstances that ma aid in ermit rocessin . None RENEWAL REQUEST: U Current ADEC permit Number: ~ N/A ~ If any operation or procedures have changed since the issuance of the last general permit authorization or individual ermit lease describe below. N/A WASTEWATER PERMIT APPLICATION SIGNATURE: The information~gi~vicen~.o~n this application is complete and accurate to the best of my knowledge. gnature Date Jason Charton Senior Environmental Coordinator Printed Name Title If it is not possible to submit this Notice of Disposal electronically, please mail or fax the Notice to the address below. Alaska Department of Environmental Conservation Division of Water 555 Cordova Street Anchorage, Alaska 99501 Telephone (907) 269-7500 Fax (907) 269-7652 Email: wa permit a,dec.state.ak.us t._..~ --- -'-- ---a- i ~ Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Monday, October 01, 2007 9:28 AM To: Jim Regg Subject: FW: ADEC Notice of Disposal CD1-19A (200-040) Attachments: ADEC App.PDF Jim, ~°-~P ~a1'~ ~'~ i„ '~~ FYI. I will place a copy of the document in the file for CD1-19A and the order file. Tom From: Charton, Jason T. [mailto:Jason.T.Charton@conocophillips.com] Sen#: Monday, October O1, 2007 9:09 AM To: cutler.thor@epa.gov; talib syed; Inukapigak@kuukpik.com; Maunder, Thomas E (DOA) Subject: ADEC Notice of Disposal CD1-19A «ADEC App.PDF» Jason Charton PO Box 100360, ATO 1756 Anchorage, AK 99510-0360 Phone: 907.263.4978 Fax: 907.265.1515 10/1/2007 ~+ UNIT~_,.~TATESENVIRONMENTALPROTECTIOh.. ENCY ~~ ~~ REGION 10 a ~ 1200 Sixth Avenue ~ ~ Seattle, WA 98101 ~~'+C PRO'~G~ Reply To ~ ~ AP~ Zl]O5 Attu Of OCE-082 Mr. Bruce St. Pierre Senior Permit Coordinator Conoco Phillips Alaska., Inc. (CPA>) Alpine Development Project 700 G Street Anchorage, Alaska 99510-0360 Re: Permit Modification of EPA Class I Injection Well Permit No. AK-11003-A Modification of Class I Well Testing and Reporting Requirements Colville River Unit Class I Well WD-02 Well Dear Mr. St. Pierre: ~ : ALT/ ~ (e' ..~ (~,~ o.~-~-e~ This letter is in response to your letter of September 28, 2004, to U.S. Environmental Protection Agency (EPA) requesting a modification of testing requirements for the Colville River Unit (CRU) Class I We11 WD-02. Based on information provided in your letter of February 4, 2005, and the history of the well performance of mechanical integrity, modifications to the permit have been incorporated to maintain annual mechanical integrity testing and to perform other tests conditionally based on the results of well performance, metal loss, and other well conditions. 'The EPA will, however, retain its discretion and flexibility to either increase or decrease the frequency of testing based on the test results. No written comments were received during the public comment period of March 7, 2005, through April 10, 2005. A public hearing was offered. However, it was canceIled due to the lack of requests for the hearing. Enclosed are the modified EPA Class I UIC program permit for the Class I non- hazardous industrial waste injection well at the CRU, the Fact Sheet, and Public Notice. We appreciate the cooperation of your staff during the processing of the permit modification process. If you have any questions, please call Thor Cutler at (206) 553-1673. ' cere Michael A. Bussell, Director Office of Compliance and Enforcement •.,. Enclosures cc: Pete McGee, ADEC, Fairbanks . John Norman, AOGCC . Theodore Rockwell, EPA Anchorage Marcia Corrtbes, EPA Anchorage ~Prlnted on Recycled Paper • Page 1 of 18 ISSUANCE DATE AND SIGNATURE PAGE U.S. ENVIRONMENTAL PROTECTION AGENCY UNDERGROUND INJECTION CONTROL PERMIT: CLASS I Permit Number AK-11003-A In compliance with provisions of the Safe Drinking Water Act (SDWA), as amended, (42 U.S.C. 300f-300j-9), and attendant regulations incorporated.bythe U.S. Environmental Protection Agency (EPA) under Title 40 of the Code of Federal Regulations, ARCO Alaska, Inc. (permittee} is authorized to inject non-hazardous industrial waste Through up to three Class I injection wells at the Alpine Field of the Colville River Unit of the North Slope of Alaska, into the Ivishak and Sag River Formations, in accordance with conditions set forth herein. Injection of hazardous waste as defined under the Resource Conservation and Recovery Act (RCRA), as amended, (42 USC 6901) or radioactive wastes are not authorized under this permit. Injection shall not commence until the operator has received written authorization from the EPA Director, Region 10 Office of Water, to inject. All references to Title 40 of the Code of Federal Regulations are to all regulations that are in effect on the date that this permit is issued. Appendices are referenced to the Alpine Development Project Underground Injection Control Permit application dated September 1997. This permit shall become effective on February 3, 1999, in accordance with 40 CFR 124.15. This permit and the authorization to inject shall expire at midnight, February 3, 2009, unless terminated. Signed this 3rd day of February, 1999 /s/ Randall F. Smith Randall F. Smith, Director Office of Water U.S. Environmental Protection Agency Region 10 First Modification: effective February 14th, 2000 /s/ Randall F. Smith Randall F. Smith, Director Office of Water U.S. Environmentaf Protection Agency Region 10 Second Modification: effective April ~ 'Michael A. Russell, Director Office of Compliance and Enforcemen U.S. Environmental Protection Agency Region 10 • Page 2 of 18 TABLE OF CONTENTS ISSUANCE DATE AND SIGNATURE PAGE .............................................. 1 GENERAL PERMIT GONDITIONS ..................................................... 4 EFFECT OF PERMIT ........................................................... 4 PERMIT ACTIONS ............................................................ 4 SEVERABILITY ................................................................. 4 CONFIDENTIALITY ............................. --........................... 5 GENERAL DUTIES AND REQUIREMENTS .......................................... 5 Duty to Comply ......... ................................................ 5 Penalties for Violations of Permit Conditions .................................... 5 Duty to Reapply............~ ............................................... 5 Need to Halt or Reduce Activity Not a Defense ................. ~.................. 5 Duty to Mitigate .............................................................. 5 Proper Operation and Maintenance ........................................... 6 Duty to Provide Information ................................................. 6 Inspection and Entry .............. ....................................... 6 Records ................................................................. 6 Reporting Requirements ..................................................... 7 Anticipated Noncompliance ................................................. B Twenty-Four Hour Reporting ................................................ 8 Other Noncompliance.......... .......................................... 8 Reporting Corrections ....................................... ~................ 8 Signatory Requirements ....................................:................ 8 PLUGGING AND ABANDONMENT ................................................ 9 Notice of Plugging and Abandonment ......................................... 9 Plugging and Abandonment Report ............................................ 9 Cessation Limitation ........................................................ 9 Cost Estimafe for Plugging and Abandonment ..................................... 9 FINANCIAL RESPONSIBILfTY .................................. ............... 10 WELL SPECIFIC CONDITIONS ........................................................ 11 CONSTRUCTION ................................ . ............................ 11 Casing and Cementing ..................................................... 11 Tubing and Packer Specifications ............................................ 11 • Page 3 of 18 New Wells in the Area of Review ................................ ......... . CORRECTIVE ACTION ......................................................... WELL OPERATION ............................................................. Prior to Commencing Injection .............................................. . Mechanicallntegrity ....................................................... Injection Intervals ................................:....................... . injection Pressure and Rate Limitations ........................... ......... . Annulus Pressure ......................................................... Injection Fluid Limitation ................................................... . MONITORING ................................................................. Monitoring Requirements .................................................. . Continuous Monitoring Devices :........... ............................ . Alarms and Operational Modifications ........................................ . REPORTING REQUIREMENTS .................................................. . .Semiannual Reports .... ............................................... Report Certification ........................................................ 11 11 11 12 12 13 13 14 14 14 14 14 14 14 14 15 REPORTING FORMS ............................................................... 16 ENHANCED SURVEILLANCE PLAN ................................................. 17 • • Page 4 of 18 PART I GENERAL PERMIT CONDITIONS A. EFFECT OF PERMIT The permittee is allowed to engage in underground injection in accordance with the conditions of this permit. The underground injection activity, otherwise authorized by this permit, shall not allow the movement of fluid containing any contaminant into underground sources of drinking water, if the presence of that contaminant may cause a violation of any primary drinking wafer regulation under 40 CFR Part 141 or may otherwise adversely affect the health of persons or the environment. Compliance with this permit during its term constitutes compliance for purposes of enforcement with Part C of the Safe Drinking Water Act (SDWA). Such compliance does not constitute a defense to any action brought under Section 1431 of the SDWA, or any other law governing protection of public health~or the environment from imminent and substantial endangerment to human health or the environment. This permit may be modified, revoked and reissued, or terminated during its term for cause. Issuance of this permit does not convey property rights or mineral rights of any sort or any exclusive privilege; nor does it authorize any injury to persons or property, any invasion of other private rights, or any infringement of State or local law or regulations. This permit does not authorize any above ground generating, handling, storage, or treatment facilities. This permit is based on the permit application submitted in September 1997. B. PERMIT ACTIONS 1. Modification Reissuance or Termination This permit may be modified, revoked and reissued, or terminated for cause as specified in 40 CFR 144.39 and 144.40. Also, the permit can undergo minor modifications for cause as specified in 40 CFR 144.41. The filing of a request for a permit modification, .revocation and reissuance, or termination, or the notification of planned changes, or anticipated noncompliance on the part of the permittee does not stay the applicability or enforceability of any permit condition. Transfer of Permits This permit is not transferable to any person except after notice to the Director on APPLICATION TO TRANSFER PERMIT (EPA Form 7520-7) and in accordance with 40 CFR 144.38. The Director may require modification or revocation and reissuance of the permit to change the name of the permittee and incorporate such other requirements as maybe necessary under the SDWA. C. SEVERABILITY The provisions of this permit are severable, and if any provision of this permit or the application of any provision of.this permit to any circumstance is held invalid, the application of such provision to other circumstances, and the remainder of this permit, shall not be affected thereby. • Page 5 of 18 D. CONFIDENTIALITY In accordance with 40 CFR Part 2, any information submitted to EPA pursuant to this permit may be claimed.as confidential by the submitter. Any such claim must be asserted at the time of submission in the manner prescribed in 40 CFR 2.203 and on the application form or instructions, or, in the case of other submissions, by stamping the words "confidential" or "confidential business information" on each page containing such information. If no claim is made at the time of submission, EPA may make the information available to the public without further notice. If a claim is asserted, the information will be treated in accordance with the procedures in 40 CFR Part 2 (Public Information). Claims of confidentiality for the following information will be denied: 1. The name and address of the permittee. 2. Information which deals with the existence, absence, or level of contaminants in drinking water. E. GENERAL DUTIES AND REQUIREMENTS 1. Duty to CompY The permittee shall comply with all conditions of this permit. Any permit noncompliance constitutes a violation of the~SDWA and is grounds for enforcement action, permit termination, revocation and reissuance, modification, or for denial of a permit renewal application; except that the permittee need not comply with. the provisions of this permit to the extent and for the duration such noncompliance is authorized in an emergency permit under 40 CFR 144.34. 2. Penalties for Violations of Permit Conditions Any person who violates a permit condition is subject to a civil penalty not to exceed $27,500 per day of such violation. Any person who willfully or negligently violates permit conditions is subject to a fine of not more than $27,500 per day of violation and/or being imprisoned for not more than three (3) years. 3. Du to Reapply If the permittee wishes to continue an activity regulated by this permit after fhe expiration date of this permit, the permittee must apply for and obtain a new permit. To be timely, a complete application for a new permit must be received at least 180 days before this permit expires. 4. Need to Halt or Reduce Activity Not a Defense It shall not be a defense for a permittee in an enforcement action that it would have been necessary to halt or reduce the permitted activity in order to maintain compliance with the conditions of this permit. 5. Duty to Mitigate The permittee shall take all reasonable steps to minimize or correct any adverse impact on the environment resulting from noncompliance with this permit. • Page 6 of 18 6. Proper Operation and Maintenance The permittee shall, at all times, properly operate and maintain all facilities and systems of treatment and control (and related appurtenances) which are installed or used by the permittee to achieve compliance with the conditions of this permit. Proper operation and maintenance includes effect'nre performance, adequate funding, adequate operator staffing and training, and adequate laboratory and process controls, including appropriate quality assurance procedures. This provision requires the operation of back-up or auxiliary facilities or similar systems only when necessary to achieve compliance with the conditions of this permit. 7. Duty to Provide Information The permittee shall provide to the Director, within a reasonable time, any information which the Director may request to determine whether cause exists for modifying, revoking and reissuing, or terminating this permit, or to determine compliance with this permit. The permittee shall also provide to the Director, upon request, copies of records required to be kept by this permit. 8. Inspection and Enter The permittee shall allow the Director, or an authorized representative, upon the presentation of credentia{s and other documerits as maybe required bylaw to: a. Enter upon the permittee's premises where a regulated facility or activity is located or • conducted, or where records are kept under the conditions of this permit; b. Have access to and copy, at reasonable times, any records that are kept under the conditions of this permit; • c. Inspect at reasonable times any facilities, equipment (including monitoring and control equipment), practices, or operations regulated or required under this permit; and d. Sample or monitor at reasonable times, for the purposes of assuring permit compliance or as otherwise authorized by SDWA, any contaminants or parameters at any location. 9. Records a. The permittee shall retain records and all monitoring information, including all calibration and maintenance records and ail original strip chart recordings for continuous monitoring instrumentation, copies of all reports required by this permit and records of all data used to complete this permit application for a period of at least three years from the date of the sample, measurement, report or application. 'These periods maybe extended 6y request of the Director at any time. b. The permittee shall retain records concerning the nature and composition of all injected fluids until three years after the completion of plugging and abandonment. At the conclusion of the retention period, if the Director so requests, the permittee shall deliver the records to the Director.. The permittee shall continue to retain the records after the three year retention period unless he delivers the records to the Director or obtains written approval from the Director to discard the records. c. Records of monitoring information shall include: (1) The date, exact place, and time of sampling or measurements; • Page 7 of 18 (2} The name(s) of the individual(s) who performed the sampling or measurements; (3) The date(s) analyses, were performed; (4) The name(s) of the individual(s) who pertormed the analyses; (5) The analytical techniques or methods used; and (6) The results of such analyses. d. Monitoring of the nature of injected fluids shall comply with applicable analytical methods cited and described in Table I of 40 CFR 136.3 or in appendix III of 40 CFR Part 261 or in certain circumstances by other methods that have been approved by the Administrator. e. All environmental measurements required by the permit, including, but not limited to measurements of pressure, temperature, mechanical integrity, and chemical analyses shall be done in accordance with EPA's Quality Assurance Program Plan. As part of the COMPLETION REPORT, the operator must submit a PLAN that describes the procedures to be carried out to obtain detailed chemical and physical analysis of representative samples of the waste including the quality assurance procedures used including the following: (1) The parameters for which the waste will be analyzed and the rationale for the selection of these parameters; (2) The test methods that will be used to test~for these parameters; and (3) The sampling method that will be used to obtain a representative samp{e of the waste to be analyzed. Where applicable, the Waste Analysis Plan (WAP) from the permit application may be incorporated by reference. g. The permittee shall complete a written manifest for each load of waste received. The manifest shall contain a description of the nature and composition of all injected fluids, date of receipt, source of material received for disposal, name and address of the waste generator, a description of the monitoring performed and the results, a statement stating if the waste is exempt from regulation as hazardous waste as defined by 40 CFR 261.4, and any information on extraordinary occurrences. For waste streams piped more or less continuously from the source(s) to the wellhead, the permittee shall provide for continuous, recorded measurement of the discharge volume and shall provide such sampling and testing as maybe necessary to provide a description of the nature and composition of all injected fluids, and to support any statements that the waste is exempt from regulation as hazardous waste as defined by 40 CFR 261.4 h. Dates of most recent calibration or maintenance of gauges~and meters used for monitoring required by this permit shall be noted on the gauge or meter. 10. Reporting Requirements The permittee shall give notice to the Director, as soon as possible, of any planned physical alterations or additions to the permitted facility or changes in type of injected fluid. • Page 8 of 18 11. Anticipated Noncompliance The permittee shall give advance notice to the Director of any planned changes in the permitted facility or activity which may result in noncompliance with permit requirements. 12. Twenty-Four Hour Reporting a. The permittee shall report to the Director any noncompliance which may endanger health or the environment. Any information shall be provided orally within 24 hours from the time the permittee becomes aware of the circumstances. The following shall be included as information which must be reported orally within 24 hours: (1) Any monitoring or other information which indicates that any contaminant may cause an endangerment to an underground source of drinking water. (2) Any noncompliance with a permit condition or malfunction of the injection system. b. A written submission shall also be provided within five (5) days of the time the permittee becomes aware of the circumstances. The written submission shall contain a description of the noncompliance and its cause, the period of noncompliance, including exact date and times, and, if the noncompliance has not been corrected, the anticipated time it is expected to continue, and steps taken or planried to reduce, eliminate, and prevent recurrence of the noncompliance. 13. Other Noncompliance The permittee shall report all other instances of noncompliance not otherwise reported at the time monitoring reports are submitted. The reports shall contain the information listed in Permit Condition E-12.b. 14. Renorting Corrections When the permittee becomes aware that he failed to submit any relevant facts in the permit application or submitted incorrect information in a permit. application or in any report to the Director, the permittee shall promptly submit such facts or information. 15. Signatory Requirements a. A(I permit applications, reports required by this permit and other information requested by the Director shall be signed by a principal executive officer of at least the level ofvice-president, or by a duly authorized representative of that persona A person is a duly authorized representative only if: (1) The authorization is made in writing by a principal executive of at least the level of vice-president. . (2) The authorization specifies either an individual or a position having responsibility for the overall operation of the regulated facility or activity, such as the position of plant manager, operator of a well or a well field, superintendent, or position of equivalent responsibility. A duly authorized representative may thus be either a named individual or any individual occupying a named position. (3) The written authorization is submitted to the Director. • Page 9 of 18 b. If an authorization under paragraph a. of this section is no longer accurate because a different individual or position has responsibility for the overall operation of the facility, a new authorization satisfying the requirements of paragraph a. of this section must be submitted to the Director prior to or together with any reports, information or applications to be signed by an authorized representative. c. Any person signing a document under paragraph a. of this section shall make the following certification: "I certify under the penalty of law that I have personally examined and am familiar with the information submitted in this document and all attachments and that, based on my inquiry of those individuals immediately responsible for obtaining the information, I believe that the information is true, accurate, and complete. 1 am aware that there are significant penalties for submitting false information, including the possibility of fine and imprisonment." F. PLUGGING AND ABANDONMENT 1. Notice of Plugging and Abandonment The permittee shall notify the Director no later than 45 days before conversion or abandonment of the well. 2. Plugginq and Abandonment Report The permittee shall plug and abandon the well as provided iri the PLUGGING AND ABANDONMENT PLAN (Appendix F.), which is hereby incorporated as a part of this permit. Within 60 days after plugging any well the permittee shall submit a report to the Director in accordance with 40. CFR 144.51(p). EPA reserves the right to change the manner in which the well will be plugged if the well is not proven to be consistent with EPA requirements for construction and mechanical integrity. The Director may ask the permittee to update the estimated plugging cost periodically. 3. Cessation Limitation After a cessation of operations of two years, the permittee shall plug and abandon the well in accordance with the plan unless he: a. Provides notice to the Director; Demonstrates that the well will be used in the future; or c. Describes actions or procedures, satisfactory to the Director, that the permittee will take to ensure that the well will not endanger underground sources of drinking water during the period of temporary abandonment. These actions and procedures shall include compliance with the techriicai requirements applicable to active injection wells unless waived by the Director. 4. Cost Estimate for Plugging and Abandonment a. The permittee estimates the 1997 cost of plugging and abandonment of the permitted wells to be $1,000,000 each b. The permittee must submit financial assurance and a revised estimate in April of each year. The estimate shall be made in accord with 40 CFR 144.62. • :~ Page 10 of 18 c. The permittee must keep at the facility during the operating life of the facility the latest plugging and abandonment cost estimate. d. When the cost estimate changes, the documentation submitted under 40 CFR 144.63(f) shall be amended as well to ensure that appropriate financial assurance for plugging and abandonment is maintained continuously. e. The permittee must notify the Director by registered mail of the commencement of a voluntary or involuntary proceeding under Title 11 (Bankruptcy), U.S. Code, naming the owner or operator as debtor, within 10 business days after the commencement of the proceeding. G. FINANCIAL RESPONSIBILITY The permittee shall maintain continuous compliance with the requirement to maintain financial responsibility and resources to close, plug, and abandon the underground injection weN. If the financial test and corporate guarantee provided under 40 CFR 144.63(f) should change, the permittee shall immediately notify the Director. The permittee shall not substitute an alternative demonstration of financial responsibility for that which the Director has approved, unless it has previously submitted evidence of that alternative demonstration to the Director and the Director notifies him that the alternative demonstration of financial responsibility is acceptable. • Page 11 of 18 PART II WELL SPECIFIC CONDITIONS A. CONSTRUCTION Casing, Cementing and Logging The permittee shall case and cement the well(s) to prevent the movement of fluids into strata other than the authorized injection interval (see II.C.3, below). Casing and cement shall be installed in~accordance with application Appendix F. The permittee shall, at a minimum, run the open- and cased-hole logs as described in application Appendix F. The permittee shall provide not less than ten days advance notice to the Director of all cementing operations. 2. Tubing and Packer Specifications The well shall inject fluids through tubing with a packer. Tubing and packer shall be installed in accordance with Appendix F of the permit application. Except as may otherwise be authorized. herein, the packer shall be located not more than 150 feet uphole ftom the top of the authorized injection zone. With respect to WD-2 completed in April 1999 with.the packer as installed at approximately 7865 feet TVD, operation with the packer located at this depth is authorized provided enhanced surveillance continues to demonstrate integrity of the pipe below the packer. See Part I I.C.3.(b)(3) 3. New Wells in the Area of Review New welts within the area of review shall be constructed in accordance with the Alaska Oil and Gas Conservation Commission Regulations Title 20 -Chapter 25. Further, no offsetting wells within the Area of Review (1/4 mile radius) may be drilled into or below the arresting zone (lower Kingak Formation) as depicted in Exhibit C-2 of the application) unless directed by EPA.. B_ CORRECTIVE ACTION The applicant has identified no wells in the Area of Review (AOR) which require corrective action in order to prevent fluids.resulting from injection from moving above the confining zone. If the applicant later discovers that a.well or wells within the AOR require(s) Corrective action to prevent this fluid movement, as described in 40 CFR 144.55, then the applicant shalt inform the EPA upon such discovery and provide a corrective action plan for EPA review and approval. If the EPA or the applicant discovers that fluids resulting from injection have moved above the confining zone along the wellbore of a well within the Area of Review, then injection shall cease until the fluid movement problem can be diagnosed ahd corrected. C. WELL OPERATION 1. Prior to Commencing Infection Injection operations pursuant to this permit may riot commence until: a. Construction is complete and the permittee has submitted two copies of COMPLETION FORM FOR iN:tECTION WELLS (EPA Form 7520-9), see APPENDIX; and • • Page 12 of 18 (1) The Director has inspected or otherwise reviewed the new injection welt and finds it is in compliance with the conditions of the permit; or (2) The permittee has not received notice from the Director of intent to inspect or otherwise review the new injection well within thirteen (13) days of receiving the COMPLETION REPORT in which case prior inspection or review is waived and the permittee may commence injection. b. The operator demonstrates that the well has mechanical integrity as described herein and in Part II.C.3 below and the permittee has received notice from the Director that such a demonstration is satisfactory. The permittee shall notify EPA two weeks prior to conducting this initial test so that an EPA representative maybe present. In order to demonstrate there is no significant leak in the casing, tubing or packer, the tubing/casing annulus must be pressure tested to at least 3,500 pounds per square inch gauge (psig) for not less than thirty minutes. Pressure shall show a stabiizing tendency. That is, the pressure may not decline more than 10 percent during the test period and shall experience less than one-third of its total foss in the last half of the test period. If the total loss exceeds 5% or if the {oss during the second 15 minute period is equal to or greater than one half the loss during the first 15 minutes, the permttee may extend the test period for an additional 30 minutes to demonstrate stabilization.. c. The operator has conducted astep-rate test and submitted a preliminary report to EPA which summarizes the results. During Injection The injection facility shall be manned 24 hours per day by trained and qualified operators during injection. 3. Mechanicallnteority a. Standards The injection wells} must have and maintain mechanical integrity pursuant to 40 CFR 146.8. b. Prohibition Without Demonstration of Mechanical Integrity Injection operations are prohibited after the effective date of this permit unless the permittee has conducted the following tests and submitted the results to the Director: (1) To detect leaks in the casing, tubing, or packer, the casing-tubing annulus must be pressure tested to at least 3,500 psig for thirty minutes. Pressure shall show a stabilzing tendency as described in II.C.1.b, above. This pressure test is required at a time interval of no more than 12 months between tests. (2} to defect movement of fluids behind the casing, approved fluid movement tests shall be conducted not less often than biennially. Approvable fluid movement tests include, but are not limited to tracer surveys, temperature, noise or other logs. The specific suite of fluid movement tests proposed to satisfy this requirement are subject to prior approval by the Director. Tracer surveys shall be run at injection pressures at least equal to the maximum continuous injection pressure observed in the well in the previous 6 months and the tracer concentration shall be sufficient to • Page 13 of 18 ensure detection behind the casing..Copies of all logs shall be accompanied by a descriptive and interpretative report. The initial operational fluid movement tests shall be completed not less than three nor more than nine months after initiation of operation. In the event these initial tests are held after less than six months of operation, tracer surveys shall be run at injection pressures at least equal to the maximum continuous injection pressure observed in the well since the beginning of operation. . (3) Continued operation of Alpine WD-02 as originally constructed is dependent uponimplementation by the permittee of the Enhanced Surveillance Plan (ESP) attached to this permit as Appendix 6 and incorporated herein by reference. In the event the EPA approves relocation of the packer and the permittee completes the packer relocation, the permittee may cease implementation of the ESP. c. Terms and Reporting (1) Two (2) copies of the log(s) and two (2) copies of a descriptive and interpretive report of the mechanical integrity tests identified in 3.b shall be submitted within 45 days of completion of the logging. (2) Mechanical integrity shall also be demonstrated by the pressure test in 3.b.(1) any time the tubing is removed from the well or if a loss of mechanical integrity becomes evident during operation. The permittee shall report the results of such tests within 45 days of completion of the tests. (3} After the initial mechanical integrity demonstration, the permittee shall nofify the Director of intent to demonstrate mechanical integrity at least 30 days prior to subsequent demonstrations. Such notice must include an indication of the suite of fluid movement tests the permittee proposes to use. In the event that any of the proposed tests has not been previously approved by the Director, this notice shall include: (a} a complete description of such proposed tests, (b) available evidence supporting the applicability of the proposed test, and (c) a description of such back- up procedures as the permittee deems necessary to adequately demonstrate mechanical integrity in the event that the proposed tests fail to do so. (4) The Director will notify the permittee of the acceptability of the mechanical integrity demonstration within 13 days of receipt of the results of the mechanical integrity tests. injection operations may continue during this 13 day review period. If the Director does not respond within 13 days, injection may continue. (5) In the event that the well fails to demonstrate mechanical integrity during a test or a loss of mechanical integrity occurs during operation, the permittee shall halt operation immediately and shall not resume operation until the Director gives approval to resume injection. (6} The Director may, by written notice, require the permittee to demonstrate mechanical integrity at any time. 4. Injection Intervals Injection shall be limited to the Ivishak and Sag River Formations, as depicted in Exhibits C-1 and G-2 of the application. •5. Injection Pressure and Rate Limitations • Page 14 of 18 The maximum injection pressure, •measured at the wellhead, shall not exceed 3200 pounds per square inch (psig). Further, injection pressures and rates shall be limited as needed to prevent the initiation of new fractures or propagation of existing fractures in the upper confining zone (above the J3 marker which separates the upper and lower Kingak Formations) depicted in Exhibit C-2 of the permit application. The permittee shall continuously monitor both the injection rate and pressure. 7. Annulus Pressure The annulus between the tubing and the long string casing shall be failed with a corrosion inhibited non-freezing solution. A positive surface pressure up to 1500 psig is authorized. 8. Infection Fluid Limitation No substance other than those non-hazardous wastes noted in the permit application shalt be injected. Neither hazardous waste as defined in 40 CFR 261 nor radioactive waste other than naturally occurring radioactive material (NORM) from pipe scale and sludge shall be injected for disposal. D. MONITORING 1. Monitoring Requirements Samples and measurements collected for the purpose of monitoring shall be representative of the monitored activity. Continuous Monitoring Devices Continuous monitoring devices shall be installed, maintained, and used to monitor injection pressure and rate, and to monitor the pressure of the non-freezing fluid in the annulus between the tubing and the long string casing. Calculated flow rates and calculated volumes are not acceptable. 3. Alarms and Operational Modifications a. The permittee shall install, continuously operate, and maintain alarms to detect excess injection pressures and rates and significant changes in annular fluid pressure. These alarms must be of sufficient placement and urgency to alert operators in all operating spaces. b. The permittee shall install and maintain ari emergency shutdown system to respond to losses of internal mechanical integrity as evidenced bjr deviations in the annular fluid pressure. c. Plans and specifications for the alarms and pressure relief valve shall be submitted to the Director prior to the initiation of injection. E. REPORTING REQUIREMENTS Semiannual Reports The permittee shall submit serrmiannuat reports to the Director containing the following information: Monthly average, maximum and minimum values for injection pressure, rate, and volume • • i Page 15 of 18 shall be reported on INJECTION WELL MONITORING REPORT (EPA Form 7520-8). b. Graphical plots of continuous injection pressure and rate monitoring. c. Raw monitoring data in an electronic format. ' d. Physical, chemical, and other relevant characteristics,of the injected fluid. e. Any well work over or other significant maintenance of downhole or injection-related surface components. f. Results of all mechanical integrity tests performed since the previous report including any maintenance-related tests and any "practice" tests. g. Any other tests required by the Director. 2. Report Certification All reporting and notification required by this permit shall be signed and certified in accordance with Part I.E.15., and submitted to the following address: Manager, Ground Water Pratection Unit U.S. Environmental Protection Agency (OCE-082) 1200 Sixth Avenue Seattle, Washington 98101 • Page 16 of 18 APPENDIX A REPORTING FORMS Enclosed are EPA Forms: 7520-7 APPLICATION TO TRANSFER PERMIT 7520-8 INJECTION WELL MONITORING REPORT 7520-9 COMPLETION FORM FOR INJECTION WELLS • Page 17 of 18 APPENDIX B Enhanced Surveillance Plan 1. This Enhanced Surveillance Plan (Plan) is required pursuant to Part II.C.3.b.3 of the Permit Number AK-1I003-A. This Enhanced Surveillance Plan was developed to address EPA's concerns about continued casing integrity with respect to the current packer placement in this well. 2. All demonstrations of mechanical integrity described in Permit AK-1I003-A, Part lI.C.3.b remain in full force and effect. To summarize, this includes the following; • Standard casing-annulus pressure tests (SAPT) to detect loss of mechanical integrity above the packer. • Fluid movement tests to detect fluid movements behind the casing and loss of mechanical integrity below the packer. Approved tests include, but are not limited to tracer surveys, temperature surveys, noise or other logs as approved by the EPA. 3. To non-destructively evaluate casing condition below the packer, caliper surveys shall be conducted not less often than biennially over all exposed 7" casing between the tubing tail and the inj ection interval. 4. To confirm the results of the annual caliper and tracer surveys, pressure testing of all exposed 7" casing between the packer and the top of the permitted injection interval will be performed conditionally based on the results of the biennial caliper, temperature and oxygen activation (OA) water flow logs instead of every four years. This pressure test will be performed if (a) the~caliper log shows exposed casing wall losses exceed SO% of the casing wall thickness between the bottom of the packer and the top of the permitted injection interval, or (b) the temperature and/or the WFA/OA logs show fluid movement outside the permitted injection interval. Isolation plugs will be set in the 7" casing within 100 feet of the permitted injection interval and tested through the tubing to a surface pressure of 3500 prig for 30 minutes. Testing specifications will duplicate those specified in Permit 1I003-A Part II.C.l.b. S. In the event that (1) surveillance determines casing wall losses exceed SO% of the casing wall thickness in any'area of exposed casing between the bottom of the packer tailpipe and the approved injection interval or (2)' for other reasons, EPA or permittee believe the casing integrity maybe compromised, surveillance logs and other information shall be reviewed by EPA and permittee to determine if additional surveillance or remedial activities are necessary. 6. Modification to this Enhanced Surveillance Plan must be approved by EPA. • Page 18 of 18 7. This Enhanced Surveillance Plan remains in effect until such time as the Plan is modified, or the permit condition requiring said Plan is eliminated. 8. The EPA will, however, retain its discretion and flexibility to either increase or decrease the frequency of testing based on the results of testing. • FACT SHEET Proposed Modifications of Underground Injection Control (ITIC~Permit AK-1I003-A for the Construction -and Operation of Class INon-Hazardous Industrial Waste In'el ction Wells at the Alpine/Colville River Unit on the North Slope of Alaska. U.S. Environmental Protection Agency, Region 10 Crround Water Protection Unit, OCE-082 1200 Sixth Avenue Seattle, Washington 98101 March 4, 2005 Introduction ConocoPhillips Alaska, Inc. (CPAT) has requested a modification of the EPA issued Underground Injection Control (TJIC) permit for the construction and operation of a Class I non- hazardous industrial waste injection well at the Alpine/Colville River Unit (CRU). The EPA UIC permit for a Class I well was issued on February 3, 1999 and is effective through February 3, 2009. To date, one (1) Class I well - WD-02 has been drilled and completed and was first placed on injection on May 15, 1999. Overview of .Alpine/CRU and Class IWell - WD-02 The CRU field, operated by CPAI is located approximately 250 miles north of the Arctic Circle and 40 miles west of the Kuparuk base camp on Alaska's North Slope and is astand-alone, self- contained, completely independent operation. The Alpine field does not have ayear-round road connecting to the existing North Slope infrastructure. Ice roads are therefore built in the winter to bring in supplies. During the 8-9 months per year when ice roads cannot be utilized, Alpine depends uniquely on air support for all supplies. Alpine started oil production in November 2000, with~gas injection start-up in December 2000 and seawater injection start-up in January 2001. Curreixtly the field is producing approximately 120 - 130,000 barrels of oil per day (BOPD). The waste disposal system~is. designed to provide an integrated approach to managing wastes generated from oil production, maintenance operations, the camp sewage system, and some minor liquids from the drilling rig. As stated earlier, a single Class I well, WD-02, is used for disposal for non-hazardous waste fluids generated at the Colville River Field. Well WD-02 was drilled and completed to the Ivishak and Sag River Formations. The perforated injection intervals are from 9459'-10;047' measured depth (NID) (9085'-9651' sub sea) selectively opposite the 7" casing. The well has primarily been used to dispose of these fluids (including camp grey water) to reduce the need to transport waste from this isolated field to off-site disposal. The well has consistently demonstrated sound mechanical integrity (both internal and external) on an annual basis in compliance with EPA permit requirements since injection was initiated in May 1999. Representatives from EPA were on-site to witness each annual inspection and testing. -1- • EPA has previously determined that there are no underground sources of drinking water (USDWs) beneath the permafrost of the CRU area. The base of the permafrost at the WD-02 site is at 900 feet below ground. Summary of Proposed Action and Permit Conditions CPAI has requested modifications to the frequency of testing and/or the types of testing, and the monitoring requirements, as required under the current permit. The proposed permit modifications include the following: (1) Retain the current requirement to demonstrate that the well has internal mechanical integrity based on a standard annulus pressure test (SAPPED) on an annual basis, (2) Modify the time interval from "not less often than annuall}~' to "not less often than biannually" between approved fluid movement tests (both the temperature and the. Water Flow/Oxygen Activation logs are commonly used to confirm external mechanical integrity) that are used to verify external mechanical integrity and to confirm there is no flow behind the pipe, (3) Modify the current requirement of submitting monitoring reports from a quarterly basis to a semiannual basis, (4) Modify the time interval between caliper surveys over the exposed 7" casing from "not less often than annually" to "not less often than biannually", and (5) Modify the pressure testing of all exposed 7" casing between the packer and the. top of the permitted injection interval to be performed conditionally based on the results of the biannual caliper, temperature and oxygen activation (OA) water flow logs instead of every four years. This pressure test will be performed if (a) the caliper log shows exposed casing wall losses exceed 50% of the casing wall thickness between the bottom of the packer and the top of the permitted injectian interval, or (b) the temperature and/or the WF'L/OA logs show fluid movement outside the permitted injection interval. As Alpine/Colville River Field is a roadless operation, WD-02 is the primary disposal option for non-hazardous waste fluids. Therefore, by reducing the number of well bore entries, the well work risks will be reduced and the potential for losing the tools down hole with resultant down- timewill be greatly reduced. The permit modifications requested by CPAI will not lessen the environmental protection or lower the operating or testing standards. EPA will however, retain its discretion and flexibility to either increase or decrease the frequency of testing based on the results of testing. Public Comment The EPA is now requesting public review of the proposed permit modifications. Persons wishing to comment on the ~royoseci permit modification may do~so in writing by April 10, 2005. Comments should be accompanied with a basis for the comments and substantiating facts. Please also include the name address and telephone number of the person making comment. All written comments and requests should be submitted to EPA to the attention of: Thor Cutler, Crround Water Protection Unit, EPA ~(1VIS: OCE-082) 1200 Sixth Avenue, Seattle, WA. 98101 or via electronic mail to cutler.thor(cr~,epa.~ov. After April 10, 2005, the EPA may choose to finalize the modification as drafted if no substantive comments are received during the public comment period. For further information, please contact Thor Cutler at (206) 553-1673 or via e-mail: cutler.thor(a,epa.gov -2- • United States Environmental Protection Agency, Region 10 Ground Water Protection Unit, OCE-082 1200 Sixth Avenue Seattle, Washington 98101 NOTICE OF PROPOSED MODIFICATION OF A CLASS I UNDERGROUND INJECTION CONTROL, (UIC) PERMIT FOR THE DISPOSAL OF NON-HAZARDOUS Il~IDUSTRIAL WASTE FLUID AT THE COLVJI,LE RIVER UNIT ON THE NORTH SLOPE OF ALASKA Public Notice Issuance Date: March 7, 2005 Closure Date: April 10, 2005 Applicant ConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 EPA Permit Number: AK1I003-A EPA Region 10 has direct implementation responsibility in Alaska for. the regulation of Class I injection wells through the Underground Injection Control (CTIC) program, which is authorized by Part C of the Safe Drinking Water Act. Class I injection wells are used for the.. deep disposal of industrial waste into naturally saline ground water, beneath any aquifers which could serve as underground sources of drinking water (LTSDWs). EPA is proposing to modify a permit issued on February 3, 1999, to ConocoPlullips Alaska, Inc. (CPAI - formerly Arco Alaska, Inc) for up to three (3) Class Inon-hazardous waste injection wells at the Colville River Unit (CRU). To date, one (1) Class I well, WD-02 has been drilled and completed and was first placed on injection on May 15, 1999. The CRU field, operated by CPAI is Located approximately 250 miles north of the Arctic Circle and 40 miles west of the Kuparuk base camp on Alaska's North Slope and is astand-alone, self-contained; completely independent operation. The waste disposal system is designed to provide an integrated approach to managing wastes generated from oil production, maintenance operations, the camp sewage system, and some minor liquids from the drilling rig. A single Class I well, WD-02, is used for disposal ofnon-hazardous waste fluids generated at the Colville River Field. Well WD-02 was drilled and completed to the Ivishalc and Sag River Formations. The well has primarily been used to dispose of these fluids (primarily camp grey water) to reduce the need to transport waste from this isolated field to off-site disposal. The well has consistently demonstrated sound mechanical integrity (both internal and external) on an annual basis in compliance with EPA permit requirements since injection was initiated in May 1999. Representatives from EPA were on-site to witness each annual inspection and testing. -1- • EPA has previously determined that there are no USDWs beneath the permafrost of the CRU area (base of the permafrost is at 900 feet below the surface). CPAI has requested modifications to the frequency of testing and/or the types of testing, and the monitoring requirements as required under the current permit requirements. The proposed modifications will: (1) Retain the current requirement to demonstrate that the well has internal mechanical integrity using a standard annulus pressure test (SAPT) on an annual basis, (2) Modify the time interval between approved fluid movement tests (to demonstrate external mechanical integrity and no flow behind pipe) from "not less than annually" to "not less often than biennially". (3) Modify the current requirement to submit quarterly monitoring reports to submit semiannually monitoring reports, (4) Modify the time interval between caliper surveys over the exposed 7" casing from "not less often than annually" to "not less often than biennially", and (5) Modify the pressure testing of all exposed 7" casing between the packer and the top of the permitted injection zone interval to be performed conditionally based on the results of the biennial caliper, temperature and water flow log (WFL) oxygen activation (OA) Logs instead of every four years. This pressure test will be performed if (a) the caliper log shows exposed casing wall losses exceed 50% of the casing wall thickness between the bottom of the packer and the top of the permitted inj ection interval, or (b) the temperature and/or the WFL/OA logs show fluid movement outside the permitted injection interval. As Alpine/Colville River Field is a roadless operation, WD-02 is the primary disposal option for non-hazardous waste fluids. Therefore, by reducing the number of well bore entries, the well work risks will be reduced and the potential for losing the tools down hole (and resultant down-time) will be reduced. The permit modifications requested by CPAI will not lessen the environmental protection. or lower the operating or testing standards. EPA will however, retain its discretion and flexibility to either increase or decrease the frequency of testing based on the results of testing. A Fact Sheet which describes the proposed modification and the proposed modified EPA permit are available upon request and can be viewed at www.epa.gov/regionl0/uic.htm 2. Tentative Determinations The Region 10 Office of the EPA has tentatively determined to modify the UIC permit issued to the above listed applicant. 3. Public Comments Persons wishing to comment on the proposed permit may do so in writing by the close of the Public Comment period, April 10, 2005, at 5:00 PM Pacific Daylight Time. All comments should include the name, address, and telephone number of the person commenting, a statement of the basis of any comment, and the facts upon which it is based. All written comments and requests should be submitted to EPA at the above -2- • L' address to the attention of Thor Cutler, EPA Region 10, Ground Water Protection Unit (OCE-082) 1200 Sixth Avenue, Seattle, WA 98101. 4. Public Hearings The Environmental Protection Agency has tentatively scheduled a public hearing to be held on Tuesday, Apri15, 2005 at 7 p.m. in the Meeting Room of the Hampton Linn, located at 4301 Credit Union Drive (at C Street and Tudor Street) in Anchorage, Alaska. However, this hearing may be canceled in the absence of any specific written requests for such a hearing. Written requests for a hearing on the proposed permit must be received by Thor Cutler at EPA Region 10, Ground Water Protection Unit (OCE-082) 1200 Sixth Avenue, Seattle, WA 98101 or via a-mail at cutler.thor@epa.gov not later than March 30, 2005 at 5 P.M. PDT. Administrative Record The proposed UIC permit and other related documents are on file and maybe inspected at the above address any time between 8:30 a.m. and 4:00 p.m., Monday through Friday. Copies and other information may be requested by writing to the EPA at the above address to the attention of the Manager, Ground Water Protection Unit (OCE-082) or by calling (206) 553-6697. The draft permit and fact sheet are also available from the EPA Alaska Operations Office, Room 537, Federal Building, 222 West 7th Avenue, # 19, Anchorage, Alaska 99513 and EPA Alaska Operations Office, 410. Willoughby Drive, Suite 100, Juneau, Alaska 99801. Moreover, copies of the draft permit and fact sheet may be viewed at www.epa.gov/regionl0/uid.htm. For those with impaired hearing or speech, please contact EPA's telecommunications device for the deaf (TDD) at (206) 553-1698. For further information, please contact Thor Cutler at (206) 553-1673 (cutler.thor@epa.gov). -3- ~ ~ ~ ~ ~ DEPT. OF ENVIRONMENTAL CONSERVATION DIVISION OF WATER WASTEWATER DISCHARGE PERMITS PROGRAM Bruce St. Pierre, ATO 1708 ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, Alaska 99510-0360 March 9, 2004 Re: Wastewater Disposal Permit No. 48053 Renewal of Permit No. 9821-DB003 Dear Mr. St. Pierre, tr(piraz wG-vZ:~~'clLr~~trr'S Frank Murkowski, Governor 43335 Kalifornsky Beach Road Suite No. 11 Soldotna, Alaska 99669 PHONE: (907) 262-5210 FAX: (907) 262-2294 Certified Mai1 7002 2410 0003 5676 9198 Return Receipt Requested The Department of Environmental Conservation has completed its review of your request for the renewal of the above referenced wastewater disposal permit and is issuing ADEC Wastewater Disposal Permit 48053. This pernnit replaces Permit 9821-DB003 and becomes effective on March 9, 2004. This permit expires at midnight, February 3, 2009. This State of Alaska Wastewater Discharge Permit is being issued in accordance with AS 46 and 18 AAC 15. Department regulations provide that if you disagree with this decision you may request an adjudicatory hearing in accordance with 18 AAC 15.200-910. The request should be mailed to the Commissioner, Alaska Department of Environmental Conservation, 410 Willoughby Avenue, Suite#105, Juneau, Alaska 99801-1795, by certified mail, return receipt requested. A copy of the request shall also be sent to the undersigned. Failure to submit a request within thirty days of service of this letter shall constitute a waiver of your right to administrative review of the decision. In addition, any other person who disagrees with this decision may request an adjudicatory hearing within thirty days of service of the enclosed permit. Any hearing granted will be limited to issues related to the issuance of this permit. If an adjudicatory hearing is thereafter granted, all permit conditions remain in full force and effect. Sincere , Oran Woolley Wastewater Disposal Permits • STATE OF ALAS DEPARTMENT OF ENVIRONMENTAL CONSERVATION DIVISION OF WATER WASTEWATER DISCHARGE PERMITS PROGRAM WASTEWATER DISPOSAL PERMIT Permit 48053 Date: March 9, 2004 This wastewater discharge permit is issued to ConocoPhillips Alaska, Inc. for the disposal of wastewater resulting from oil and gas production and associated support facilities. The waste will be disposed of by subsurface injection into the Ivishak and Sag River Formations through any of three (3) Class I injection wells, identified as the Alpine Field main facility pad (CD-1) in the Colville River Unit, located at latitude 70° 20' 38", longitude 150° 55' 08", Prudhoe Bay, Alaska. This permit is subject to the conditions contained in Underground Injection Control Permit Number AK-1I003-A effective Febn~ary 3, 1999, which is incorporated herein by reference, and to the conditions in the following paragraphs. The permittee must supply the Department with copies of the certified reports required in Underground Injection Control Permit Number AK-II001-A, Section E, and "Reporting Requirements." Copies of the reports submitted to the U.S. Environmental Protection Agency must be sent to the following address: Alaska Department of Environmental Conservation 43335 Kalifornsky Beach Road, Suite 11 Soldotna, Alaska 99669 This permit is issued under provisions of Alaska Statutes 46.03, the Alaska Administrative Code as amended or revised, and other applicable State laws and regulations. Any rights or privileges inuring to the benefit of the Environmental Protection Agency in the Underground Injection Control permit, including any right to enter, inspect, sample, and have access to records, also inure to the benefit of the Department. Any records or other information filed with the Environmental Protection Agency pursuant to the Underground Injection Control permit must be contemporaneously filed with the Department. This permit is effective on March 9, 2004 and expires at midnight, February 3, 2009. It may be terminated or modified in accordance with AS 46.03.120. Department regulations require that a wastewater disposal permit renewal request be received at least 30 days prior to the expiration of the current permit. Requests not received prior to this date cannot be renewed and must be reissued as a new permit. This process takes a minimum of 60 days, during which the facility may be prohibited from operating. ~ Oran Woolley Wastewater Disposal Permits • ^ ~~ p STATE ~!F ALASKA ~ DOMESTIC WASTEWATER PLA,. REVIEW/WAIVER/PERMIT FEE t~a.^ t r-' y n 5 3 Department of Environmental Conservation -~n-I~iew # t3 Invoice #223373 PAYlVIE1VT IS EXPECTED AT TIME OF SUBMITTAL (please reference invoice # on your check) Make check payable to: STATE OF ALASKA ADEC Contact: 43335 Kalifornsky Beach Rd., Suite 11, Soldotna, AK 99669 DUNS: 809386587 EIN 92-6600185 A licants name: QuCF 5 E A plicants phone number: 0 ) ZG `j " (o'er t~ A licants address: ~- c o~S t-rc t L.4lP S Engineer contact: Engineer contact hone number: ( ) Facility/ProjectNarne: L Ptw~E" C t, Z ~ - ~ ee eg - or a p an review wazver or an rant or oan a project, o not temtze Invoice ount Reference make payment now. Please contact your area ADEC office for information. Fee Amount code Due 72.440 ONSITE CERTIFIED INSTALLER Certified installer/homeowner training $65 DW2C Certification fee - (2 years) $625 DW2C Certification fee- (2 annual Installments) $34 0 DW2C ~~ , 72.945 INSPECTIONS a--. $43/hr 72.955 DOMESTIC WASTEWATER PLAN REVIEW (From Table D S°e. l) (A) Based on peak design flow of: 0 = 500 gpd $270 DW2R (B) Based on peak design flow of: 501 - 1500 gpd $340 DWZR (C) Based on peak design flow of: 1,501-2,SOOgpd $360 DWZR (D) Based on peak design flow of: 2,501-15,000gpd $730 DWZR (E) Based on peak design flow of: 15,001-SO,000gpd $1,200 DW2R (F) Based on peak design flow of: 50,001-100,000 $2,370 DW2R (G) Based on peak design flow of: 100,001-250,000 $2,960 DW2R (H) Based on peak design flow of: 250,000 and over $3,510 DW2R 72.955 DOMESTIC WASTEWATER MODIFICATIONS TO AN EXISTING OR APPROVED DOMESTIC WASTEWATER SYSTEM THAT INCREASE DAILY PEAK CAPACITY BY: Modification <20%; 20% of fee in A-H above DWZR Modification 20% to 50% change; fee is equivalent to percentage of that in A-H above DW2R Modification >50% change; fee is 100% of fee in A-H above DW2R 72.955 WAIVER/MODIFICATION OF PROVISIONS under 18 AAC 72.060 Individual on-site system (single-family or duplex) waiver(s) $300 DW2R First Five waivers submitted for a project, other than single-family or duplex $250/waiver DW2R - ~~: ~... ~ , x ~ . - 72.955 NON-DOMESTIC WASTEWATER DISCHARGE PLAN REVIEW Does not include stormwater -Passive Treatment(2 or fewer treatment methods) $440 DW2R Each additional treatment method after 2 $90 DW2R Does not include stormwater-Complex Treatment (2 or fewer treatment devices) $940 DW2R Each additional treatment device after 2 $190 ~~3tty'~'-_..vyr ~=s~°rrK Tom,-~~.; ~-~ . ,^R~~~~,~ r,,~~~it~W ~1 ~,t--,~ ~,~;c-:r- h r,~.r=;~: ;,mar=.-~:~.^~^r°°ar,,-:;;o=•; 72.955 DOMESTIC AND NON-DOMESTIC(Iincluding Storm Drain collection) For sewer replacement, or extension of Up to 1,000 ft $310 DWZR per each addttronal 1 000 ft or fraction thereof $160 DWZR 72.956 GENERAL PERMIT-FIXED FEE TABLE E.1-11 use EH worksheet Fee determined by Section # DW2GP 72.959 GENERAL PERMIT-HOURLY AND NEGOTIATED FEES -use EH worksheet Fee determined by Section # DW2GP 72.957 INDIVIDUAL PERMIT -FIXED FEE TABLE F.1-10 use EH worksheet Fee determined by Section # DW2GP 72.969 INDIVIDUAL PERMIT -HOURLY AND NEGOTIATED FEES-use EH worksheet Fee determined by Section # l[~ ~ Q- G 'j 2 . ~9 DW2GP '~ Check # - r ~~ ~-~~ P "d: Cash TOTAL: ` ~ (~ C ~ ~o~ / ( / 1 Sienatur of DE ontact Title Date **2nd and 3rd digit =region code, 4th, 5th, 6th digit =sequence number revised Sept. 2003 4Þ14 . . AOGCC Memorandum Date: August 3, 2007 To: DIO 18 / AIO 18BV' \Z"1Q ~~iJÎ From: Jim Regg, Petroleum Engineer Subject: Administrative Approvals DIO 18.001; AIO 18B.004 CP AI requested administrative approval to adjust the frequency of surveillance logging and plug depth tags ("surveillance") to be consistent with recent EP A action on the Class I disposal well WD-02 at Alpine. EP A recently relaxed the surveillance frequency to once every 2 years. I called MJ Loveland (CP AI, Well Integrity Project Supervisor; 907-659-7043) this date to clarify the frequency - their administrative approval request read "biannual". She stated the request should have read "biennial" (i.e., once every 2 years) instead of "biannual". Approval letters reflect the required surveillance frequency is "biennial". :#-13 AIO 18 B .c ßðo i£G ß.. 004 > Jim, ConocoPhillips requests a modification to Ala 18 BRule 9 to be consistent with other disposal well permits (010 18) at Alpine. Currently Rule 9 requires fill depth tags on an at least annual cycle or as warranted following consultation with the Commission for slurry injection wells. Ala 18B Rule 9 currently allows for a different fill depth tag schedule with consultation and approval from the Commission. At this time ConocoPhillips request the fill depth tag or any other annual required surveillance logging be reduce to bi-annual to be consistent with the other permits currently in place for the Alpine disposal wells. Please let me know if this change is acceptable. Thank you for consideration. MJ Loveland Well Integrity Project Supervisor ConocoPhillips Alaska, Inc. Desk Phone (907) 659-7043 Cell Phone (907) 448-3114 1 of 1 5/16/200710:06 AM #12 . . Conoc;p.,illips Alaska RECEIVED P.O, BOX 100360 ANCHORAGE, ALASKA 99510-0360 JAN 2 3 2007 A~sk~ Oil & Gas Cons. Commission Anchorage January 20,2007 Mr. Tom Maunder Alaska Oil & Gas Commission 333 West ih Avenue, Suite 100 Anchorage, AK 99501 Dear Mr. Maunder: Enclosed please find the Administrative Relief Request for ConocoPhillips Alaska, Inc. well CD2-48 (PTD 202-108). Please call Marie McConnell or myself at 659-7224 or MJ Loveland / Jerry Dethlefs at 659-7043 if you have any questions. ~û Perry Klein Problem Well Supervisor Attachments . . ConocoPhillips Alaska, Inc. Alpine Well CD2-48 (PTD 202108) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc., proposes that the AOGCC approve this Administrative Relief request as per Area Injection Order 2B, Rule 9, to continue water only injection with known annular communication for Alpine injection well CD2-48, Well History and Status Colville River Unit well CD2-48 (PTD 202108) was drilled and completed in June 2002 as a WAG injection well. CD2-48 was converted ftom MI injection to Sea water on 10/29/06. On 11/26/2006 the well was shut in and T x IA communication was reported to the AOGCC, On 11/28/2006, with the well shut in, an MITIA passed @ 2500 psi. While shut in, the tubing and inner annulus did not equalize, continually maintaining 500 psi or greater differential pressure. The passing MITIA was submitted to AOGCC on 17/7/2006 along with a verbal request to restart injection to further monitor and test the well. AOGCC approval to restart injection was received on 12/11/2006 and the well was placed on water injection 12/12/2006, While on injection the well began to show signs of T X IA communication. On 1/15/2007 an MITIA to 3500 psi passed. CP AI notified the AOGCC of the wells status on 01/18/2007 and submitted the passing MITIA. The well is currently on injection and is maintaining a 260 psi differential pressure from the tubing to the IA. The well will require a workover to repair. Barrier and Hazard Evaluation Tubing: The 4-1/2" 12.6# L-80 tubing has integrity to the packer at 9477' MD based on a passing MITIA performed on 1/15/2007. Production casing: The 7" 26# L-80 production casing has integrity to the packer @ 9477' MD based on the MITIA described above. The well passed a witnessed, 4 year MITIA on 8/26/2006. Surface casing: The well is completed with 9-5/8" 36# J-55 surface casing with an internal yield pressure rating of3520 psi. The surface casing is set at 2550' MD (2379' TVD). The well has an open shoe and maintains pressure integrity to 1100 psi. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Second barrier: The production casing is the secondary barrier should the tubing fail. Third barrier: The surface casing and cement shoe will act as a third barrier should the first two barriers have failures. Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the tubing, production casing, or surface casing 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 plots are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. NSK Problem Well Supervisor 1/20/2007 1 . . Approved Operating and Monitoring Plan 1. Well will be used for water injection only (no gas or MI allowed); 2. Perform a passing MITIA every 2-years as per AOGCC criteria (0.25 x tvd @ packer, 1500 psi minimum); 3. Submit monthly reports of daily tubing & IA pressures and injection volumes; 4. Shut-in the well should MIT's or injection rates and pressures indicate further problems; 5. Workover and/or repair the well prior to gas injection consideration with appropriate AOGCC notification, NSK Problem Well Supervisor 1/20/2007 2 #11 e e FRANK H. MURKOWSKI, GOVERNOR AlfASIiA OIL AlWD GAS CONSERVATION COMMISSION 333 W. 7'" AVENUE. SUITE 100 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, CP AI 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 been requested. , Alaska and dated March 1$, 2006 C\~~. ~~ Dan T. Seamount, Jr. Commissioner ~ [Fwd:"CP AI MIT's] e e -------- Original Message -------- Subject: CPAI MIT's Date: Mon, 20 Mar 2006 16:35:22 -0500 From: traP2er@mtaonline.net <traP2er@mtaonline.net> Rep 1 y - To: ------- t-rãpper@lTIt:a-õnTirïe . net ---------------------- To : j.:!:!!l_~_~9:.g_~~_ª.r!li!.!:_:?_t:.~ t e..:..~~:_~~ Jim, This appears to be an effort to better utilize everyones summer time. I believe the months could quite easily be extended 1 month each way with no adverse reaction from the weather. However when BP hears of this they will quite possibly request the same thing, which mayor may not place the burden on the AOGCC inspection group. All in all I feel that tis idea has medrit and should proceed. jhs ------------------------------------------- ------------------------- mai12web - Check your email from the web at t"-t:_!=:E:j¿!!l_?:~~_?~!~1.?_~9.!1:l¿ c..~ W~ c;.oh2..\~ <=-OM~-'--\;, ~c___+~ î:~~~,~ ~..\~ LO~C.(!:\\I'.-> ~<è\-(;,:::,. es~e.v,\~-<Å.\"Y ""~'ê' ~o.J...<..crr ~Q ~J ~ ",.\\\\W>.,-,eo ç\<i:;\\6\"'\~1 ì:~~A-kR:, :lv--s {>ec\ìl:)o-- SCk~0 \f: ~(èA") ~ \ \. ""\' \ \' D (' (. ,.L... ~ 2Þ..KCt. ...\-- .\- ,<, 0. ,<; D ( ~ \ '" CS \ lIv'D. '{ \l--LÙ '0Q: ~(), \ Il,,,, '-'"""~ ";,. ~ íG: (:OSe: ~~ '-5", ~ 0-'> (p \~c- ~ 'o.~ ~ t- S'\ ",-u:: l-"'-~ ,>~J",:~~ \<? \'> i"D ~ ~. V íC)SU\ \'~ ~ \ \éh. T'ì~ <~ '-.;1" ...,. ~ I.r-.-t.-";,. \'C::> '0 eo L. \.-\ 'i &\;, )f~ 1 of 1 3/23/2006 9:50 AM Re: Cp' AI MIT schedule e e John - We always have the right and ability to change their schedule if there is a conflict, and if we decide to approve CPAI's request, I expect that will become necessary on occasion. We do not work for the operator and are not bound by their schedules. Jim John Crisp wrote: In this case, I think c/p is trying hard to find a way to stay completely in compliance. I think this schedule will work unless all Operators attempt to schedule the same way. Possibly our goals for witnessing the number of four year MIT's could be adjusted if we have conflicting work. It is my understanding that Alpine is now using annular pressure maximums of 1000 psi. OA & 3000psi IA for their gas injectors. This is the case in Kuparuk & has been documented many times. I think it is understood by all the Operators that a new injector must have a State witnessed MIT in a timely manner after the well has been on injection. Probably would not hurt to remind Operators of this policy, or have it written in any new policy. Thanks JC 1 of 1 3/23/2006 9:54 AM Re: CJ>AI_Summer_MITs.pdf e e Lou Grimaldi wrote: Hi Tom, Not a bad idea, would make it more convenient for them and us if we could ensure that they do the tests on a day when there are two inspectors on the slope. It should be approved only if they understand we may have to put them off a day or two if circumstances get hairy up here. Lou Thomas Maunder wrote: Jim asked me to send to everyone. Attached is a letter from Jerry Dethlefs proposing to schedule all CPAI MITs during the summer months (May - August). He and I think the idea has merit and is workable. We would like to hear your comments. Thanks, Tom Hi Tom, I agree with Lou that we could end up losing flexibility in witnessing MIT's or other inspections. When we went to 14 day BOPE inspections we lost 50% of the opportunities to meet our inspection goals for the rigs. We should also remember that whatever is approved for CPAI is immediately subject to the "me too" effect by all the other operators. The others will cry foul if we don't let everyone do the same. Winters are long and summers are short in Alaska and staffing (2 inspectors) on the slope has been flexible in the past for this reason. If JS retires soon there could be ramifications this summer. I suggest we don't lock ourselves in right away and if we decide to make a major change like this to the way we do our inspections, we should consider doing it for a trial period and then assess the program and see if it really works for us and adjust as needed. Thanks, Jeff 1 of 1 3/23/2006 9:53 AM #10 e e Conoc~illips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 RE(CE~\/E'D ceo f ~ ?. ¡ t.:.U .1 ¡(]I ,-006 February 13, 2006 J\¡I~(1:I&', t;'\~J J) !f"" .- i . ¡...""idJ !.,;I;a ;:t t:lJ3 ¡;{J1'I~ r;>'''''''1''1''Í'''.'''fij!. ' V""¡,,,.,j&"~ß!] ,4m.:hol'1}ge Mr. Tom Maunder Alaska Oil & Gas Commission 333 West ih Avenue, Suite 100 Anchorage, AK 99501 S ubj ect: 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. Thll request was approved by the AOGCC on December 29,2005, with the stipulation no further extensions would likely be granted for future years. CP AI 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 ofthe 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. CP AI 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, CP AI 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 " e e Mr. Tom Maunder Page 2 of2 02/13/06 CP AI 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 CP AI goal of testing during warmer weath~r. 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 CP AI 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, ~c~ Jerry Dethlefs Problem Well Supervisor Attachment "-"¡" e e ConocoPhillips Alaska, Inc. Proposed UIC MIT Permanent Test Schedule Ilnitial 4-year Cycle: Requires accelerating tests for all wells on a pad to be on same cycle I Year 1: 2006 i Total Wells Kuparuk Pads i Alpine Pads , Total Wells May 22 i 1C June 56 i 1B, 3H, 30, 1E i I i July 54 10, 1Q, 1Y, 3F* I i August 48 1A', 1 R', 2G', 2K', 2L, 2N, 2P, 2U, 2W, 2Z', 3G', 35 ! CO2 I 29 I Total i 180 I I Year 2: 2007 ! I I May 21 1R,2W i June I 53 2K, 2T, 2X, 3B, 3F i July ! 28 1A, 1G, 31 I ! August i 25 1 F', 20', 2F', 2H*, 2M', 3G, 3M', 2Z i Total ! 127 i , , Year 3: 2008 i I i May 23 I 2A, 2B, 2G, 2H I I i June , 38 1 F, 1 L, 2M, 2V I July ! 30 i 2E, 2F, 3J, 3M I C01' 2 August 24 ¡ 3N, 3Q, 3R Total i 115 ! , i I I Year 4: 2009 ! 1 i May 14 3K June 39 I 1 B, 2T, 3H, 30 July I 19 1Q,1Y August i 35 i 1 H, 2C, 20, 3A, 3C C01 22 Total 107 ! Year 5 I i May ! 22 1C ¡ June I 31 i 1E i ! ! July i 34 i 10 ! August i 32 2L,2N,2P,2Z,35 CO2 29 Total I 119 i I ! Year 6 : May 21 I 1R,2W i June 38 2K, 2X, 38, 3F ! I July I 18 i 1A,1G,31 i ! I August 18 ! 3G,2Z i Total 95 i I I I Year 7 I I I May i 23 I 2A, 2B, 2G, 2H i ] June i 38 1F,1L, 2M, 2V i July i 30 2E, 2F, 3J, 3M August 24 3N, 3Q, 3R I Total : 115 : Year 8 i ! i May 14 3K June 40 2T,1B,3H,30 I i July , 27 1Q,1Y i August i 35 ! 1 H, 2C, 20, 3A, 3C I C01 ! 24 Total I 116 i i Notes: 1) , Oenotes 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 #9 l.I~)).Ù iJ. 1¡/"'51.F:/ 1\ [>71 F rc \\ I, ~·t\\~ II i:;::;J , I I ,:' \ ¡ : 'I @J¡!Li\1,l1Lb ') (~ IE ! r [t lrr;¡ : '! I !~ i ) / / J FRANK H. MURKOWSKI, GOVERNOR AIIA.~HA ORAND GAS CONSERVATION COMMISSION 333 W. pH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 November 30, 2005 Ms. M. J. Loveland Problem Well Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 RE: Administrative Approval AI018B.00l Dear Ms. Loveland: In response to your recent inquiry, this is to clarify the applicability of Administrative Approval AID 18B.00 1. That administrative approval addressed a situation in which intermittent pressure communication from the tubing to inner annulus had been discovered in well CD2-51 (202-249). When the approval request was submitted, ConocoPhillips Alaska, Inc. ("CPAI") did not propose repairing the well to eliminate the pressure communication. The Commission determined that water injection would be allowed to continue in the well, but subject to a number of restrictive conditions set out in the administrative approval. Subsequent to obtaining the approval, CPAI has repaired the well, eliminating the pressure communication. The well has successfully passed the standard Mechanical Integrity Test ("MIT"). Consequently, Administrative Approval Ala 18B.00 1 no longer applies to operation of this well. Instead, the provisions of the under ~ng Area Injection Order No. 18 will again govern injection in well CD2- 1 __ ~~ Commissioner ---~ #8 ) ) > >-------- Original Message -------- >Subject: CD2-51 AA cancellation (AIO 18B.001) >Date: Fri, 11 Nov 2005 11:31:52 -0900 >From: NSK Problem Well Supv <n1617@conocophillips.com> >To: tom_maunder@admin.state.ak.us, James Regg ><jim_regg@admin.state.ak.us> >cc: NSK Problem Well Supv <n1617@conocophillips.com> > > > >Tom & Jim, > >CD2-51 had a RWO in the last month that repaired the TxIA >communication. CD2-51 had been injecting under AIO 18B.001 approval. > >This well will be removed from the Monthly Failed MITIA report, changed > >back to a 4 yr MITIA cycle, and MI injection will be allowable. > >Are the AA's just like sundry approvals in that they cancel >automatically when the drilling sundry report of repair is submitted, >or >is there extra paperwork needed to cancel the AIO for CD2-51? > >Thanks, >Marie McConnell >problem Well Supervisor >659-7224 > > > > > > > > 1 of 1 11/30/2005 11: 13 AM #7 Re: EOR Approval Clarification - June 1, 2005 Administrative Approval Subject: Re: EOR Approval Clarification - June 1,2005 Administrative Approval From: James Regg <jim_regg@admin.state.ak.us> Date: Tue, 21 Jun 2005 15:20:25 -0800 To: ALP Env Coord <n1508@conocophillips.com> Jason - Thank you for the clarification regarding the Administrative Approval. The clarifications outlined below (use an existing sample point downstream of the pump; follow the EPA-approved Waste Analysis Plan and existing policies to demonstrate the nonhazardous characteristics of the injected fluid) are consistent with the intent of the Commission's June 1, 2005 Administrative Approval (AIO 18B.002). Jim Regg UIC Program Manager AOGCC ALP Env Coord wrote: Jim, Per our conversation, CPAI has two points, pertaining to the June 1, 2005 Administrative Approval, for which we would like to provide additional information and request clarification from the Commission. They are outlined below. . Sample Point Location - The Commission has requested that CPAI sample the combined fluid stream in the 1 B manifold for characterization and enhanced oil recovery compatibility purposes. CPAI requests approval to use an existing sample point downstream of the pump, which sends the combined fluid stream to the 1 B manifold. There will be no change in the fluid composition between the existing sample point and the 1 B manifold. . Characterization of the Combined Waste Stream - The commission has requested CPAI perform characterization sampling at the 1 B manifold. CPAI requests that characterization sampling be performed according to the EPA approved Waste Analysis Plan (WAP) and existing CPAI policies and procedures. By following the WAP and existing procedures, applicable sampled fluids will be properly segregated and controlled until lab results are received demonstrating the fluid's non-hazardous characteristics. Thank you for your consideration of these clarification requests. Please contact us if you have any additional questions. Shellie Colegrove/Jason Charton Alpine Environmental Coordinators Phone: 907-670-4200 Fax: 907-670-4507 I of] 6/21/20053:20 PM #6 ") Versacoat Use and Rinse Sample Origins ) Jim, Per our phone conversations, this email is being written in follow-up to your questions pertaining to ConocoPhillips Alaska, Inc.'s (CPAI's) enhanced oil recovery (EOR) request dated April 21, 2005. The questions related to the mud additive Versacoat and the type of rinse loads sampled by CPAI for the EaR request. Versacoat is a mud additive that has a low flashpoint in its pure form. Versacoat is used in CPAI's oil based mud systems. It is added at an approximate ratio of 180 gallons per 12,000 gallons mixed. The resultant mud mixture will not exhibit a low flash point. Alpine's mud hauling trucks are routinely washed and, if approved, the resultant non-hazardous mud rinse fluids may be used for EOR when the Class I well is unavailable and, if exempt, the Class II well is unavailable. CPAI provided AOGCC with two types of analyses for rinse loads at Alpine; RCRA characterization and EOR compatibility. The July 10, 2004 annual rinse fluid sample was analyzed to determine RCRA regulatory status as required by Alpine's Class I Well Waste Analysis Plan (WAP). The rinse sample was taken at Alpine's truck wash facility, which is used to wash the exterior of vehicles. The January 29, 2005 EaR compatibility rinse sample was taken from a 325 bbl vac truck that had last held drilling mud. Two sample log book entries and an email have been attached as supporting documentation on the origin of the samples. Additionally, please find an attached mud rinse RCRA characterization sample taken previously as required by Alpine's W AP. If you have any additional questions, please feel free to contact us at 670-4200. Thanks, Jason Shellie Colegrove/Jason Charton Alpine Environmental Coordinators Phone: 907-670-4200 Fax: 907-670-4507 «July 2004 Rinse Sample Log Entry.pdf» «EaR Capatibility Sample Log Book Entry.pdf» «EOR Compatibility Sample Source Email.pdf» «Mud Rinse RCRA Charaterization Report.pdf» C t t D . t· July 2004 Rinse Sample Log on en - escnp Ion: Entry.pdf July 2004 Rinse Sample Log Entry.pdf C t t T 1· t· n/ t t tr on en - ype: app lca 10 oc e -s eam Content-Encoding: base64 C t t D . t· EOR Capatibility Sample on en - escnp Ion: EOR Capatibility Sample Log Book Entry.pdf Log Book Entry.pdf Content-Type: application/octet-stream 1 nf ") )/11/')00) 1"'19 PM Versacoat Use and Rinse Sample Origins :) ') Content-Encoding: base64 , . . . EOR Compatibility i Content-Description. 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'·/..::~'~.QÞ ,', I'· ' , ,- _\- i1 (\.: I '.. r';,:;: ~__s; '-'-~f~' "~" 'U::~?::~(ll. - <'~:~'~,'" '. ._"__.__:-~. ~ \1~m .... I: '~~.~.- { .~L.__.." '" ;";~~~~~~'~:¡-~~." ' . ~ ._ ..,. . ,"~·......,"___..w..___..~......_. (,,;;( . ,. .::1. i ¡;,f;":L~ @ { ?;'ÙÓ -- ..··-ïT~¿-;;l:;:-- ...... f; G.-. ) ) ALP Env Coord . :'11I.\ From: Sent: To: Subject: ALP Drlg Support Sunday, May 29,20059:26 AM ALP Env Coord RE: Container Rinse Sample for EOR Compatibility Analysis Jason, Just got some clarification on the well and the fluid from the MI mud plant. We were on CD1-20 which is a Injector, and we were hauling Drilling mud on Truck # 8016. Thanks Dave. -----Original Message----- From: ALP Env Coord Sent: Sunday, May 29, 20059:06 AM To: ALP Drlg Support Subject: RE: Container Rinse Sample for EOR Compatibility Analysis Thanks, Dave. One final piece. You're sure through personnel interviews that it was drilling mud? The oil/water piece is secondary to determining that it was drilling mud of some type. Jason -----Ori 9 i naJ Message----- From: ALP Drlg Support Sent: Sunday, May 29, 200S 9:04 AM To: ALP Env Coord Subject: RE: Container Rinse Sample for EOR Compatibility Analysis Jason, The truck # was 8016 which is a 325 BBL vac truck, and according to the drilling schedule, we should have been on CD2-21, which was a producer, and around 1-29-05 we should have been in the production part of the hole, and been using Oil Base Mud. Since we don't have the log book from that date for fluid transfers this is at best guess, but should be right. Thanks Dave. --d·Orlginal Message----- From: ALP Env Coord Sent: Sunday, May 29,20058:41 AM To: ALP Drlg Support Subject: Container Rinse Sample for EOR Compatibility Analysis Dave, Our sample log indicates that on or about 1/29/05 y'all pulled a truck rinse sample for our EOR compatibility study. If possible, can you provide more details about the sample. Specifically, we're interested in the following. . Truck number and type . Fluid last carried in truck prior to rinse Thanks, Jason Shellie Colegrove/Jason Charton Alpine Environmental Coordinators Phone: 907 -670-4200 Fax: 907-670-4507 1 11-01 11: 57A K'Y'; st )PYOiCe f 907 )59-2146 P.02 " NORTHERN TESTING LABORATORIES, INC. 3330 JN~US·tRlAJ AVENur .-OO!, SCIIOON ~mr.1 I POlJOI .I.,00,t3 I AJ~B^~KS. ALASKA Y~701 ANCUOHAGE, AI ASKA 99!J18 PtnJDHOE BAY, AI. ASKA 99734 1~)OII156· 31 Iii . J: AX .,5G :) \2'-' 190/1::149 lOon·fAX3A9 lOHi H)()}I 659 :lIJ!; . FAX 659 :>146 Report Date: 10 January 01 Report No.: 01010024 Report of Analysis Phillips Alpine Envíronmental P.O. Box 196860 Anchorage, AK 99519·6860 Purchase Order Number: 998609 Field ID Number Sample Description Oo.~ I~~ sQtY\þ',~d DatelTime Receìved NTL Lab Number 010701-MI-01 Alpine Mud Plant (/7 fo t @09:30 VJo 10 J @09:00 NT07169 by JG by JEP Analyte "", '''' "esult : ; -)r ,h Point Resu'lt Res ult 8.71 >·140 Units Std. Units degrees F MDL Method EP A 9040 EPA 1020 : 'I' , P¡'~p',i1ratlon ~ate : 01/10/01 01/10/01 Analysis Da'e. Analyst Q1/10/01 KHP 01/10/01 KHP . ~ . .'1 ':>. :' , '.' I, , ',: I"j :.'. I ,~': "t . . ~..:., :.' Jì; \ .' ...;. ',: '....... I ~ I.:' ~ . ;.~; : .:.::; ~".~ ~ ~ ,. ),- '-0041 ..._............ "'_~ . ..',' \ i·i." ;;t~ t;, \ , '1 i ..~ 'I . '\ I. .,1 , ',' ,,;'1,;:: " Approved by: v< fl';;¿' ..., rJu¡. 0- Je1rry tOfl~Sty Price lab Supervisor J Chemist /;'¡él-Ol 11:57A Kris-'\Price I' JAN-19-01 H<l U1: 1;¿ ~M "JKIHI:.KN Jt~J INlz LHfj. / . ~¡ D . .,...._.~...."'......._...'......_~...IIII..............__".·,~........_·,.·...It. ""...-11I".' ___._IiI.......·\ ,.... .." .. . -..., ..., .. ~ 'to ,,' 'i~.j!:}~>t .~ NOHTHERN TESTING lABORATORIES, JNC. ¡t' . ~.~ ~';\ l\ ~ 3::',~r,) mUll s 1tr..~1.. A.vw..,l,.;¡- r A!mM,i':o.:' ~~. AI t.!:R~'\~!I ib'1 (90"/) 45~·:1"G" rAX .\S:·312!i '¡1.( ," , i".,.~.~ ~ f,.;,\q.;(:lInC,N "i1~.t' I ., ..\N(:I~()·~.I\.li!=, ^L~",^ !I€I!'i1S 19Q,) 34!J.10u0· FAX 3-\O·101ii . \ rt.:¡ .< :~t ~i ~~:~~ ~: ..~:I ~_:. :~:'.~..).. ..._._ " ____..~. ~·'ÍÌ¡r~~~.~~: ~. ALASKA 9'73-1 ¡90'1J Ð!i9·214!i · F' AX G!i9 2'4'; 90', );59-2146 rti^ NU..u1UttH:>C"1£::O P.03 r. U,J -."1 - ~--._.. Ph:1Iì1~ Ah,jl\:: t!.tlVin~nm,mttll r\ LP- 1·1 FtO Br.x I C;ÓS60 :\;H·h(Iril:~\·. 1\ to:. 995 J9··6H6ù ¡\nn: Ch:lI-ll1P/Gnai'ka .Rb1',,"VL nah~,: CUle ArJ'i"t'd: Dat&:- S.:.mpled· Tjm,t. Si1m~"lc-d: S~I]1}pl~11 ßy: 1119/01 1/1210] lfilOt 9:30:00AM Jìm Gill~rl Phl"iH.·~ F:\x: «(107) (j70~47~1 ("07) û~JO-·1n~ 2107·1 1'2.0177) l..i\luiú A1p¡~,~ M~~ PI:Wll Q J0701·MI·OI MRL = Mt.lhod Rëp~)"Lín~ UmH Bi~g, Q~JjliililJtJ5 n:; l)ç)ow R~gHI;,tl)ry Minil'L'lnm H ~ Al)ov~ Re.c;u!::ItOi·Y Maxirl1u1r) M = M;I~rix. TQh.rft.'r",lt.'t :fa = t.&.:s~ '.0\3.11 R~porlh}~ Lim.i~ : ('OC I.:: r,,~ n. Laj,!f: S~\"II"'lt: I"klln~: r ~lnlth11~¡Pr\~¡':'-'I,; ,; "''';(~~\i~r¡,". S~;Jj)''I!~ \() C\.'HH~w~n\:;: ... . .. ..-... - .....-.. ..... _...... . ... .~~:).~~ - ~~~. '~_,!2'il~ _._~~~~'~-;,. :~1.t!,--'A~~~·r~~is I)!'I~ < MRl.. moiL If< O.~ijQ 1/18101 ~I)" .. .......... . -..- ---. .. " . , : ,M~t1'(fl ',h,i;Ä'¡ÓOOA J.n¡'(I m(,,·h.·.. Algonk: hy TCL? GF'A :'7.10 So!coÎtJrn by TCLP < MJ{I. mgll. ... 0.200 1/10/01 " ! .. ~. ~ :\t::t JA 701~'O M¡)'CUIY <. MRt. maIL '" 0.0020 1/18100 \ I ,',E:PA '/7~fJ silver t:y TCLP < 1\·m.L mg/L * 0.10 1/17/00 " t, · . · . .. . ep r\ 60 toD ! ! C=1dmitJrn by TCLP < :\1RL .nglL s!. '025 1/17/0t · . ,. . ,..:";:1 , EPA Ei010B ClirotrlJúl' by TCLP C:,MRr. mg1\. .. o.;i~ , i,¡ 1/17101 Eþ^ 6DfO[.I l.c:\d by 1 CLP < l\'JRI. mg/l ~ 2.5 1117/01 ~ .... .~ !j¡J K") ~((MlJJ'~:!rif1~" '.rl.!."'cßëC/ 1~~ ¡.. .}.t~·¡m1'¡ed üy .hmy N¡~oll Ï'.ül'}R1r,k.¡ <:¡k·nt'~ry Surwni..,ÞT "- .:', . ; ;,' ·1 :. ~. . I · .....:. . '. '\ 'v ) 907-659-2146 t'H~ NU. I~UrqOO~L~~ J ) 121-01 11:58A Kris~ Price If JAN-19-Ul FlU U1: 1:) PM NUt<lH!:MN It:tiJ INti LHtl. !; !j j; h ~~~ .:'4 ')... . .... 'j""" f .', ~. ".(, ~ r t~. \ . ~/. ., .. "t·.. '''l: ~ ~"·"''''1. .~~~ ! .'. , I' ~ ~>' .¡,.. ..-:':',A.(,....:...'l) , ~ W' "'" I ,~ ~ 11 II ¡.,j .j ::..". "... . 'OO' ,:t..:"'.~. I~'-':-W' -:~-:~ -. .-...-..,,, .""".........._.-~..__"..----. ...........,. .~"'---""-'.. ...... P.04 r. U'I ~ --..: --~ ~.. ·V· - NORTHERN TESTING LABORATORIES, INC. ;!.; 10 INOU~TRI.'\l JWI f\~u~: t;'.t:,·... !\":I t!'):')r~ :. rr:r, , r..l..), Jt'u 3-',0(101 ~ F,~·n~A~..:;. f>J A~'(,^ t'-J"lO, ANC' IO",<$',t:, hL ^SIC^ !)!Ð,a .'HU L~II\'jr (~A '". AL ^-S teA O!inl'l ,t¡þ ..-..... ..---~.."_ ...,.._w.... - .., _........ _"'41 ............ "".-.-......... "''''10 ~_ Plu)ip~ .I'\lf1jn~ Ilnvi((.1J1ml;·I~I~'l .i\Lr~·14 PO r~tiX 19G5GO A!ld\(\f~\gt·. A K 99519·-63GO AIl:l: Ch;\r;$I/QI ;.\iku NJt\J\l-:: f':'x: (')()"¡) 67()··:Hc. J (<}U7) ()70~47-)i{ 21074 F20 J77l Lhr..'h \ A1p~T\c Mud Pbn.t OI070J-MI·Ol c(le 0: N U.. tab/: $iI1nJ'l~C' M¡,lri·.\. '.ix:¡U i ;)ulPn.1k<.·': , "J' lÒH"uc San;pk ID (""lnl Ut::J.l~ ; .' ':. J ~ i<-th.... . ,'. ". .... .... f 't"' , E;PA 6010ß .... --.--....-..-... .. l·;¡'("~\UI'=l(lJ,· nt'~n't' Jrlili .. --.... .....-.__. If! ......... I .. . . ... __.. a~·ium by TCLP , MRt. maIL ~ SW (M67.3 Hyt1r~oo" CY:ShJcle <MR1. "'9'1C9 .'; ¡s, ; " $W 04a7.3 HytJrtI!~on 5..Jlrktß 10 mglk~ :" ¡ I':,: ¡:. , , . 'I' ~..¡ .: .. ,. '. -/ ,I,. .;gJ~' L', .~ t"'~f.l."'" J ·SfJ1ß/ð-~~. .,!¿I.'l"u..I.C.-d ,.)":lfrlmy Ni,·..tl1 "~¡'~ir(;o~J~s t 'hc-mÞ'1I")' Sup\'ni:;ur . . lh;port Di.l.lè: D~Lc: Arrived: D;o.te SJrnpltd: Titœ S~mplc,l: Si.1J1)pl~ Dy: (~O') 4$5 :n rG.. FAX 41 !di....., 25 1901) 349·'1000· fA)(. 3"~.\C'~ (90 tì (;!þg 21'45· FAX liS!) ~~JfG ... .__._-.1'_..----.......................... 1/19101 )/12.10] 1nlOl 9:30:00 AM Jim Gi\hcrl MRL = M~I.huù R~1>Orli1\.'r Limit FI¡I!._Q~I'iQi.MJti ß = nelow Re~dMQry Minimu1~ H = ^\'>O\'t;. R~~ult~l,(}fy Ma.~\l\\'.1~n M = M:llrix IntftCerence , * :: Lt_~ ·f.bnn ReP<'r1jl1~ L;'1~it ~ FI". "-. 'M'I~I¡'" '·~:~~}'SiS I~~ 110 s~o: 1/17/01 oj¡ . I " .~ . ,;( .- ,. , . \ t.' . , ,I. H Ji, 1116101 11\6101 I:' I" . ':. . \~ ;r-' '. J' ; " : . '- /' ~ ' '21-01 11:SSA Kr;~} Price ,/ JAN 16 ' 01 02: 48PM NIL ANCHORAGE / ~.. ) 90,-659-2146 P.05 t" . C:/ c:: NORTHERN TESTING LABORATORIES, INC. FAlRBAN.cs. ALASKA 't701 ANCttOAAGE. A\,ASKA .', PRUOHOE BAY. ALASKA "'J& 3330 IND~STRIAL AVENue 800S .tCHOON STREE" POUCH 340043 ... Phillips Al1)1.ne Environmental; ALP 14 P.O. Box 196860 J\nchoragc.~ 99519~S60 Ann: Charton/Graik'a Client ID: 01 070 VMI-ot Client Pr~iec:t #~ Source: NIL L1.b#: Al70446 Sample Matrix: Liquid Comments; ....--- --. --. .--. --... - ~~.;. ~~- EPA 1311/8270 ," ,·-··::;~~"~e"Qt-,\)oroeth..e .. . "..' ~itrobez1z.e :-..... . " ' Haœchlorobutadienc .; ,·~..~:<-Zr4..Dinitrotolu=e , .. ··'··"·~"·"H~acblOtObenzefte ., ' " .2.4,6- Trichlorophcnol ,:', ,,,' .', 2,4,5.. Trichlorophemol :.",1;;: J¡~"'" ,~Pcntacbloropbenol ~,.::,. ~\ !Pyridine . ~'''. o-Creso1 . '. II. :. . .... ?':.,.m.ø-Creso! I.j,;" ~:,: , Total Cresols r J I ." ,. , ~ ""'' ~\ ." Pbenol.d6 (Surr) , .' : t·· ..",,"1' t·'.,'. NittObeuztne-d5 (Sun) 2...'luoJO-phenol (8urr) 2~FluorobipheoYl (SUI!') , ..,2,4.6-Tn"bromophmoJ (5UJr) " . ¡J-TeI1)hcayl.d14 (Suri') . .' 'I : ~ ~ ,,' " :. . , ,i· ...J, ::.1, . ,.' i;, " 11,' ì . '"1 ,·:h. .. . - f & --rt'""(4: ,~;""f"Y' ...,; h.. t ~ ~ Rcponcd..B)r. Wendy M. Miwhell AJtchora.~ Chemistry SUpervisor .:, I " .~ ' Units mzIL mgIL 1ÞIIL mYIL mg/L mgIL maIL mWL mWL mpJL mgIL mWL 0/. R.cçovtrY "- Recovery % Recoveay % Recovery % R«ovay % R.eœvery ¿" ilm1lt <M:RL <MaL <MRL <MaL <MlU. <MaL <MIU. <MBL <MRL <MRL <MIlL <MaL 90 107 84 117 86 91 (901) "56~ne · FAX 4S6-3125 (907134·1000" FAX 349,,1016 (90'7) 659-214' · f:'AX GS9-214G -- Aepon Daœ: 1/16/01 Date Arrived: 1/11101 Sample Date:; In 101 Sampl~ Time: 9:30 CoUec;;ted By: JG ** Le¡end .. lo-DU. ,- MEàcSRIport~ MCL .. Max. Conta~€ÞI1¡f' LéYcI ø · ~t In Mdbod Btri B ,. ~v_ M - MMzix 1f11tdàt1llc.f; H = Abo<ve MCL 'D · Lø To DiluDon Date - Da~ .~ 1'rt'paIe6 AnAlY~} MlU.. 0.050 1/12101 0.050 ~ ~... 0.005. : II ,/,1 ' 0.005 ',;~.~: 0.005 . '...' 0.050 ,~. .'. 0.050 :~~. , 0.050':'':' ~::'. o.O$ci~.ái~, t L ¡.. B'\' 0.050 ~'... 0.050 1. O.c>SO .. . : :, .. \, . " '. " , I . ... . !:!I, \,:.J . . : :.i ~ 1/13/01 ~~I' .: . .. ~ '. . ;~ :t:.'~.. ..0 ,I ~. . 'i" .: '.b ~ ~ #5 ¡ ¡¡ ~ , . '. ) ConocJPhillips Alaska, Inc ) Matt Elmer Alpine Operations Superintendent Alpine Operations ALP 15 P.O. Box 196860 Anchorage, Alaska 99519-6105 Phone 907.670.4200 ~I2CE:-- April 21, 2005 API? clVI2D Mr. John Norman Alaska Oil 2 7 Z005 Chair & Gas COlis Certified Mail Alaska Oil & Gas Conservation Commission Anchorage· COl11tr,is8io 7000 167Q 00070391 8946 333 West ih Avenue 11 Return Receipt Suite 100 Anchorage, AK 99501 RE: Request for Administrative Approval of AIO 188 to Allow Injection of Additional Fluids for EOR Dear Commissioner Norman: ConocoPhillips Alaska, Inc. respectfully submits a request for administrative approval to allow the injection of non-hazardous sump fluid, hydrotest fluid, rinsate, and excess wellwork fluids when the primary disposal well is unavailable. Area Injection Order 188 states Class II Enhanced Oil Recovery (EOR) fluids may be injected for purposes of pressure maintenance and enhanced recovery. AOGCC has previously authorized various fluids for EOR at Alpine in specified situations. For example, in an August 1, 2002 Administrative Approval (AIO 18A.01), Alpine may use treated wastewater effluent, mixed with seawater, for EOR when the Class I well is unavailable. The fluids under proposal would be blended with manifold CD18 water injection. A maximum total of 10,000 gallons of the proposed fluids are expected per week. Alpine is currently injecting 25,000 bbls of seawater per day for EOR at the CD1 8 manifold. Assuming the current injection rate is maintained, the proposed fluids will comprise a maximum of 0.10,10 of the weekly CD18 total EOR water injection volume. The proposed fluids would comprise 0.020/0 of the Alpine weekly total EOR water injection volume (140,000 bwpd). Camp waste water volumes were not included in the above referenced values. CPAI reservoir personnel have considered the proposed fluids, and do not anticipate that the proposed fluid/seawater mixture will be detrimental to the Alpine reservoir, based on both the estimated volumes and a recent laboratory fluid compatibility study, which is enclosed. Finally, the proposed fluids are commonly used for EOR in other fields on the North Slope, and in general, are found checked as pre-approved for EOR in the Alaska Waste Disposal and Reuse Guide (Redbook). Per the Redbook, fluids that are pre-approved for EOR are subject RCRA status verification. CPAI uses analytical results, generator knowledge and/or manufacturer supplied information to make RCRA status determinations on all material that is disposed, reused or recycled. We have enclosed documentation confirming the RCRA non- hazardous status of the proposed fluids. I. 1:"-'" ..¡,.,.. ~ I' ~ Request for Administrative APp,2al of AIO 188 to Allow Injection of Addition~ Fluids for EOR April 21, 2005 Page 2 Please do not hesitate to contact me at (907) 670-4024 should you have any questions about this submittal. Sincerely, . ~ /. /1itf~ Matt Elmer Alpine Operations Superintendent Enclosures Cc: Tom Maunder, AOGCC Compatibility Analyses ) ') Alpine EfflUe_~tIEOR study ~ - - - -- -~- :;:on~ - '. . " - -,:¡. 1 Sump/SW 2 3 4 W,./I vJ.-1J( 5 Raw/SW 6 7 8 vJt;JI""¡C,lll 9 Brine/SW 10 11 12 v1A.¡Jw¡,Jk. 13 Slick/SW 14 15 16 17 Sump Water 18 Raw Water Wtl/r./t1]< 19 Brine Wtß Wt.A~. 20 Slick Water 21 Seawater 22 Hydrotest Water 23 Seawater 24 Truck Tank Rinse/SW 25 26 27 28 29 HydrotestlSW 30 31 32 D. Newman 1-31-5 M. AshlT. Vuk 02-09-05 D. Newman 2-26-5 ;11 ~--~ 10/90 30/70 50/50 90/10 10/90 30/70 50/50 90/10 10/90 30/70 50/50 90/10 10/90 30/70 50/50 90/10 100/0 100/0 100/0 100/0 100/0 100/0 100/0 10/90 30/70 50/50 90/10 100/0 10/90 30/70 50/50 90/10 Volume 100 100 100 50 100 100 100 100 100 100 100 100 100 50 30 20 50 100 100 20 100 100 100 100 50 30 25 20 100 100 60 50 Filter Wt 0.0498 0.0507 0.0505 0.0508 0.0418 0.0417 0.0419 0.041 0.0424 0.042 0.0418 0.0416 0.0415 0.0406 0.041 0.0406 0.0409 0.0413 0.0416 0.0411 0.0422 0.0467 0.0457 0.0487 0.0462 0.0483 0.0471 0.0436 0.0479 0.0465 0.0447 0.0424 Final Wt TSS 0.45u 0.0599 ~§?;¡Jif~ 0.0807 ~ --.. .-30.0 0.1056~. . 551· 0.0941: ~.".::.' '.I;J66~ 0.0435 i '" . :' t7 0.0426 ( g' 0.0426 ~7 0.0424. :. :1~ 0.0449; . .: . 2~: 0.0472: . . ':52 0.0492 : _ .: '74' 0.0614; .:.':".: .; . _1"S~ 0.0486 : _"~;:'- "']1 0.0428 ~ .~':~ . .,' ':44 0.0432 i ..}, ".' :73. 0.0433 ~,·.'i_' .t~5 0.0962 ~ : ':"=?, .,~ lPß g~~~m~t;:,; 0.0424 ¡:!Ù~?:·"~j-2 0.0472 ¡ . c ~~ :.~> >:-;,'':5-: o~mr-;~l~¡ 0.0948 ¡~: '£~i; -\t!i5D g:;~~~¡t-= ~: ~:~~ ¡'~·:-;ð:·:i;~~':~'-:~- 0.0448 t;:::~1f-~~·-:'~{~' 0.0426 ,~.---;' .', '4: Sump/Oil 10/90 50/50 90/10 Raw/Oil 10/90 50/50 90/10 Brine/Oil 10/90 50/50 90/10 Slick/Oil 10/90 50/50 90/10 Truck Rinse/Oil 10/90 50/50 90/10 HydrotestlOil 10/90 50/50 90/10 Precipitate Emulsion ~- ~ -6..-:--;=::=: 75 F, 12 Hours Sump Raw Brine Slick Truck Rinse Hydrotest .~ Report Date: 01/31/05 To: Alpine Env ') Kuparuk Laboratory Report of Analysis Sample Description: Sample ID Sample point Well Num Loc Descriptor Collection Date Collection Time Analysis pH Specific Gravity @ 60 degrees F Conductivity Bicarbonate Carbonate Chloride Sulfate Sulfide Aluminum Boron Barium Calcium Chromium Iron Potassium Lithium Magnesium Manganese Sodium Phosphorus Silicon Strontium Zinc ') .Alpine EOR 'Vater Compatibility S....rr--f Wt:;11 w..¡)c.. VIlt/' Y~uì( AA97597 AA97598 AA97599 APMIS- W APMIS- W APMIS- W 000 Sump Water Raw Water (Lake) Brine Water 01/22/05 01/23/05 01/22/05 00:00 00:00 00:00 Result Result Result 6.46 6.36 7.15 1.003 1.0001 1.1364 Unit micro-mhos/ cm mg/l mg/l mg/l mg/l mg/l mg/l mg/l mg/l mg/l mg/l mg/l mg/l mg/L mg/l mg/l mg/l mg/l mg/l mg/l mg/l 524 135 o 40 <10 Not Available 0.5 0.5 o 34 o 1 20 o 5 0.360 39 0.7 2 o 0.2 116 65 o 10 <10 Not Available o o o 10 o 0.2 o o 4 0.003 3 o o o o Ifthere are any questions regarding this data, please call KLS at 659-7214. 96600 88 o 108875 Not detected Not Available o o 2 4302 o 2 117800 o 9 0.206 768 o o 4 o Completed By:_DN_ Reviewed By:_DV 1A/tll N..J}t. AA97600 APMIS-W o Slick Water 01/22/05 00:00 Result 7.27 1.1208 84500 140 o 96250 <10 Not Available o o 2 3126 o 3 104100 o 8 0.221 664 o o 3 o ) ') Kuparuk Laboratory Report of Analysis port Date: 2/9/05 1I11ple Description: .Alpine l\'Iisc. 'Vater Lab ill Sample Description WellNum Date Time LocDescriptor Analysis Chloride Sulfate Aluminum Barium Boron Calcium Chromium Iron Lithium Magnesium Manganese Phosphorus Potassium Silicon Sodium Strontium Zinc Bicarbonate Carbonate Conductivity pH Specific Gravity @ 60 degrees F Sulfide Unit mg/l mg/l mg/l mg/l mg/l mg/l mg/l mg/l mg/L mg/l mg/l mg/l mg/l mg/l mg/l mg/l mg/l mg/l mg/l micro-mhos/ cm mg/l AA97978 Alpine Misc. Water o 02/01/05 00:00 Truck tank rinse water Result 630 12 < 1 < 1 < 1 326 < 0.1 < 0.1 < 0.1 4.6 < 0.1 < 1 50 2 60 < 1 < 1 173 o 1900 7.1 1. 00 1 0 Not Analyzed there are any questions regarding this data, please call KLS at 659-7214. Completed By: T JV Reviewed By: DN ') ) Kuparuk Laboratory Report of Analysis ort Date: 02/28/05 Alpine Cnst Env. ~-\Ipine l\'isc. \Vater mple Description: Sample ID Smnple point Well Num Loc Descriptor Collection Date Collection Time Analysis pH Specific Gravity @ 60 degrees F Conductivity Bicarbonate Carbonate Chloride Sulfate Sulfide Aluminum Boron Barium Calcium Chromium Iron Potassium Lithium Magnesium Manganese Sodium Phosphorus Silicon Strontium Zinc Unit micro-mhos/em mg/l mg/l mg/l mg/l mg/l mg/l mg/l mg/l mg/l mg/l mg/l mg/l mg/L mg/l mg/l mg/l mg/l mg/l mg/l mg/l AA98551 APMIS-W o Hydrotest Fluid 02/22/05 00:00 Result 5.99 1.0000 188 71 o 35 5 Not Available o 00.3 0.1 8 o 28 1.3 o 2.9 0.686 12 0.6 0.5 o 0.1 here are any questions regarding this data, please call KLS at 659-7214. Completed By: _ DN Reviewed By:_DV ) ) Waste Characterization Analyses and MSDSs j~~J JA" O,q. to'~',·l~~ fk;,t:, }~)::f.ri~~ ;Cr~"i¡~Ä0!r1~~à~,(:d '1. " ~~Ö1 'm" "" " '.;.' '. ,'. 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" , , U$AGE:f~1.~È~A.Utldf4$: · ?Ú'ôd ~~p~HMf.~){::~:.~~~~f~~~~j ~y\~<:'.;j~)t~~( . : $rÜt~AÖ}i.:.PHE{~Ât)tWÜ~si }Ü~~~~þ W\x~*iWH(~~>ät,!ht~c K?èþ. ¡¡¡,::\);:~;{ ~~~y~ \:~:1~~¡~::;.-~6¡ %~ri~ä~ .;~ h\t :d~~:;::~~,~. \~<j~!¡:Ô.tk(:~.. , . "'" ' '..,...,.,.,.,.....,...,.,...,.....,.,...,...,.....,.,...,.,...,.,.,.,.,.....,.,.....,.,.....,.,.,.,.,.,.;..,.",.,;,;,.."".",.",;",.,;"""",.;.;...;.;.;.;.,'.;.;.;.;.;.;.;.;.,...;.....;.;.;.;.,'0:.;.;.,.;.;...;.;.;-:.;.,.'.;.;.;.;.;.;.;.;.;.;.;0:-.....;0:.....;-:.'....'....'.'....'.............'...................'..,........,...',........,..............................'.'..,........................'....'....'....'....'.'..................'....'..........'..."...'....'"''''''".."...'''"""..""..."......... , . " . <l~ 'E;¥J~qS:IJ f~tE,: G(JN~rRú,L.$,:·A.~4.tl þ~R:-E~Ø:~~f~:L Pf{ÞrÞ(~:!1Ø:t4: .......'.'.....'.'.'.....'.'...'...........'.........'.....'.'...'.'.'.............'.................................'.'.'.'.............'.'.'.'.'.'...............'.........'.................'.....'...'...'.'...'.'.'.........'.'.......'...'.....................'...'.....'.'.'...................'.....'...'...'......,'..,....'.'.'.'..,'.'...'........,....',....'....,'.'.'.'..,'..,'...'.'...','.......',..'..,......',..',...,..'...'..,'.','.'.'.'......,',..'......,..'...'...'... , ""'" , , . , , , . F<ROT€(;'T}VE t~:QmÞMENT:· e·,,,· ft' . ,,' .. .·f·~ "",: '. '. ." . . ',<-!<,,' Vff.:NJ~t/f'n9N:: >¡:::~:~~:~Ù~: ~8j~<~<pi~h~ :#!.~':~'A:~~::~tk~,Ü. >,~:K ì)~~M;t >,~jÜ*:;'~: ¡ÚÚ,: . " . Rf~S?lRA 1'O(~$; ·;;~~:~.:~~~~·:~~;~~::·~:::~~~:~~:;i:~1~':;~:~~~~:~;;;:!~:~;~:~;~:~:.::;::~~¡:~~~:J¿~;:~:~~~:~·i{~~·Ø¡~t i::,:¡.~. X~~~? . :~i, I: ì ~~.:~: :'..>~~ ~j i·~:·,~d· ';$'i¡~k( . ~~,~:(;:~}>\i~:,~::::~ ¡ PRürËZ1TtVË>$LOVËS·~ ." " "..., . '" -,... . . ,. " f~~;r¡:~Ii~~~1~~\:~~~:;~~¡H N,y,,% N~~i~¡~r~~tt ~;:~r prö¡j>,~WiÔ M f~~},~~~:;~t(:<.1 K:·:.I:¡~~:(:~~~<~,·¡~;:~:r~~'¡;-M':::~¡\;:<:: .{~1(','\\~,:; .¡tj;~xJ:~:::~t~ }\j!yni'wl .. , . E'$<E.PHOTËC'T}OU; :W~M·,\~~~~~;):.;·>¡j?·;i, {h~::ïj¡.ç;~·¡.~<¡Úty~Wgj~~~j~ '<Òn~z jj>'~j<~h!{::w:r\;. ¡';< H::,\~,){!~jf;'::Y l\~·{~h;~hk. ('!THEH PROlE¢:TK}N: l~i'''~'<':~k~,<ew;':,:,:h :)¡*\Ú>.e:: V·ir:-~i: ~::~"~'j/('\pt;.~Ü~ r: ìf;{b~s:;~: j<:i j~:t:/\:·tjJ. ~~:¡>:;:;;; h~~~ .(It ·~iN:ì~.x:;~,{:d .(~ ;Ü:~ ~Jm,:::;,: ~ 0-. ~.... 0-.....0-.0-....0-.... 0-. 0-" e.............................. .... ............................................. 0.0... .,................... .,............0 .......... ...... . . .. ..,....,.....".,........,.................................................................................. 9. PHYSICAL AND CHEMfCAL PHOPERTUSS:. '.........................................,'.......____................,...........,.,.....,..........,..........,...,...........,...,.,.,...............,.,.....,.,......,...,.......,.........,...,.,...,.,.,...,.....,..........0,.,................,..............,.......................,..,....,.............'.......,.........,.........,'.......,......................,...................... APp¡~ARANÇE:.. ÇOìl.H.JR:: OPO\J.Rf'fA$'f:6:: $¡jliJtm",ffV t~ t.t;ì·GRW'!'roN: û<)1t.JNG ~O¡NT{'~C, }nt~p'{:é;¡j}: bËJ,lS¡1'yl$P~ÇWfÇ~rþ\yrry {9l~nQ~ pH,Vl\U)ú:', ~~()Nt.;..$OL.U'nnN; ~'~~~~~;'~'~~}:.;:~;;:: ~:: ~~;:;~.:::~, t-<l¡h~ {<¡~. !'~Ú:.<;. )~«~i~'t' .:..:.:;;:d~~~>}~: ~>:c. ·,"':~)t{:{. .'~ l<Xi fiRF~$URF~ .:, ! ,(1 'rEM P r.-;n. /~ 'fUR}£ «''(::}~ .10 ~~~H e' ~,{~; ./:':::"~ ;@]W .~~~:*~~~~~~!\ .;1=W ) ) . 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(";~J~:~?:'~~¿ ~:~:~;~·di~:~~7J~~· ~~;~~~:~1t~.~· '$;"~f$>f~~~:~l:~~i(:~;,: ~;t:t~;-~~:~~;~: ~f~k~~t~~~~.: . . H<\~ARt~6!J<':Öl;:¡"þl;(¡i;p' PRflDt)G':r8~ . . .. . '.) . ':"" ... :<. .... .'~.' . ¥·Y:Ü:~~·;ï'hi.áJI>h·ihj~~.;ù·;;~L:·:¢~;~~:~<w:(;~:. !rÚI:,<ií¡¡.Ü: t.;~t~~:~:\:nx~w·:~Ú\!~n~(;~~~>f,Ò~.(t;·~){t ~ú:~d~~(~~~:üM~:j:::~~~J~0H' n~~:iii~:'?~::~:~~ . {C:Ú'¡. . . . ..,...,.,.,.,.,.,..',.,.,.,.,........ ..,.'"..'.'.....................'.....'.....'...'...'.','.'.','," ... ",.".,......................................, ....'.'.....',.....,.,.,.,.,...,...,...,.....,...,.,.,.,...,.....,.......,.,.,.....,.... ..,'......,'......,..'..,.,.,.,.....,...,.,'..,...,.,.,.,...,.....,...,.....,...,'..,'......,.,.....,..',...,......".','..,..'...'.....' '11, T'ú.x~ÖÖLCHj¡ÜAL· ~NfØt{Ml\TH)N; "~'~.""""". ..... ........,., .....,. ,',',',',', ...' .: .'.' .' .'.'.'.'.'.' .~.' .................................... .'.... ............ .'.'.'.' ,.,............. . . . . . 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"",.' ..... . . . . . . . . ...'.......'.. ...... ........,.,., "":"" ......":.: .,'.:.:.:... 1~t ECOt;ootëÄ:l tNF·OR.MA'fiÖN: . .. ., . . ...............~..........,.,...,.,.,...,...,...,.,.,...,......................................,....~....,.,.,.......'.. .'.......'........................:......................""^"oY...............................,...,...,...,...,.....:.:.:':.:.:.:.:.~.:.~.:.:.:.:...:.~.;.:.:.:.~~.:.:.~..'.:...:.............-..._...___".,....."..........'.'.........'......,.........,.....,., ...,.... ..... . .'.'.'.'.'.'................."'....'.'... ....... .. .. ...'....... . t~¢OtQ{~:~ÇA:t .~Nr~~~:~;t~;}~.~ft:~·.~~~.;.6:~ü¡:¡;.Ù.~:::\r:'~¡.:~~~~ M..l':~..r:!~~~:b.w~~~ÙÜ.i. AÚÒt¿ .Üér!ònr<w(;~t· f(*~ .;>~ùbi~~::t1· b¡'Lbi:¡;:¡Ùl:f:~.. :¡.'>+J~~' t)K.Q¡:~q~~ ~,qt~.)\¡i:: q ,~...'...'.......................~.;........,...,~..,.,.....:...,...:.:.;.:.:O;O:........--:-.~...'.......'.........'.........'..'............'....'...'..... ~ ~'...'.......'..............,...,...,...,.,.,.,.,.,.,.,...............................................,":.::...>:.:.:.:.:~.:.:.....:.:.;.:.:.;.:.:.:.:.:.:.~~»:.~~,~:~.:.~~.,.:.:....:...~~................................----...........................,..~.........'...... 1:t Pi$P(}$Al,.ÇON$IDE:gA119Nß: ,',".','.',',','.','," . . . . .'.'.'.'.'.'........"'.................."''''.'...'. . .'. .'. .......... ...J.......~................,.................,~,:.......','.','. 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'fRAN$?()RT ~NFQRM.AT!ÖN; .-....................................,....,..................................'... ,. ,............................................................................'.......'................................ .,.................................................................... ....,...................,...........................,...........,...,................ ROAD TRANSÞötrr: ROtH> TRAN~PÖR.T N(Yrf.:~(~ r;(>~. ,(I :¡~i :.:i ;:t ;~~ &\tL t R.~\N~WORT ~ (~AIL H{AN$POR,"Y NOTE.S: N<>:i. Cb~:;<i~:\.'d, ~~Cþ. n~.ANSPÖRJ: $'6A TRAN$PQ~l N(:ræ$: ~<~t çt;~:,;~~¡m,:d. A~RTRANS?OOT: A¡~ r&~N.$PORT Ntrn:m: Nr~; c~<;.$~:~ifi·~Ü. ....................'....................................-...-........................................... -,---- -",. ,....y.o_..___........-^"""'""'^""""^'-_,...____..__...._~.........._........_·..~~....-.........~-.·Ñ........,.N",¡;^O:.:.»:<O"~.~..-"...."..'^-..--"JOo....,...-.._-"..~^..y^.........,........,,-..........................--.....,.............................-;...,._....-..........-,',',' {f ) ) .:ft.. t! ¡ , ,I ~. .. 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".'. ,,":.;_.......... .'....................... .'... .'.'.'....................................................................................................................... .~. .,.'.......'.'.........'.........'...;.;........,...... . ,. . , . , '" , ",,' , , '''' BW~f:{ ~r¡~A$~·$: "'..,","" ',,'" '~~~~; t:.T~~>;:~:::í:~.;~~rt $AFGTY 8H{~A$:f.$:: : ~'k!: ~::¡)~;;~m(~d, · iH~' 8t:.~U'~.ATQ:RY R~Jl:::Nl2NçES: (~~~~~1~~J:~~~:::~:~~'~::~}:..t\~~·:;~~~::t)( ..~' 'tï:'l'~" .~:>. :'"1 ~'::;'; ¡'¡' ,x~ .:" -'~'.: J .') ,':- :' .;'~ ": :~~ ~'~~:4~' :·f~h~ 't~:i>t~~t~\'~J: (~f' ·$:,~{itt't~Ù:~ H~j~~'43'·d!:~·¡:ii.· : '.: ! ',' I',,, ;'1, : ~', I ... GWt~ANGftNö:TES~ <)<::~~.I*~~;~;~~)~:d f:~~~:.~!:~~tu~· L~~dl:~. m.%Þ::f:n ;:p :·n~<j··,h·~j~i:.~'¡<~~: i$f:t( ¡.¥~:~; , " " " " ' . 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INFORMA:r~(~~l $Çîi.JRGl6:S.: . :~,~t;~;~;:;~~(;:;~~.;J~~:~¡~~;~, ll,~~~:~t;§~~~< 1. 9.~Wi :MM~¡-bì:~N~:iì:/ V~,~:à:~~h~~:'1,~.;¡¡~:<:: '. . , . . .~, .,,:: ~;<';,¡t;~,A::.~';,);:K~r~~;~;~:)~~~~~;:1i;~!~~~~~~j:~:Ü¡··(~·t~ÙÙiW!~~·) .9;h!,;~;,t:: l>~~~"~Ü~.}?· j.: '~;k ¡ .{~,~Ù;\ {\'(:~Wì,:::~:¡H~::Ù}çc:;~dhr' þ..:}\;i:;ki h~i ¡b{:ç<~tÙn·@·d;~¡ ,<·~m«({~·Ú;)..· · H,~~~)it~~~~qf·t Gøt~~rÚ~Nr~~~ , , .. " '" , ." ., . , , ,. ~,~::~~~t~i.~~~.~1 :l~~~· ;~~i\~~i.~J~,:<~h~;\~~i~f~ ¡:$~<Uf.'bw(~ fk ~Ú;·~:!¡yW:Jh:t: · ~~ÚVt~W:)t-{ nArE~' 12·,:lG,·~m R}.'::V~··N{))R~PL,. $P~9,E:N%BATËrt l . " " .'... , ... " " ,,'.. .."" .., , " ... .. tlJ(:~ }¡t.>H· tS' ø~:Ö,ÖUt'~Ú) ",Vl:nA ~USjtr(:HttHÜ:,~' \V}>¡Öi:)\~l0: ... 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TI;1:\~~;~~<~~~~~~;i;~~i~~~~~~~~~~~::!" t'.;.\,:~ :~~ ":',:;:.,1/: ~"·.I:,,:";":,~ '·:~:i'~~;'~'. ,I'.'~;':"':, ~,' '" ',-" "·;L;'.,',~' ::::...' i ..' ,:,"¡!~~;:' ~ ~d''','''' .. ~'....',' J':~'~.' . . I·.~ I'.':'. ':, ,. .~J.... : ,11" :. ) : 'oJ. '" ~ "'.:' Þ", I' ~ ~ ~~ 'I ~'t:~~ " ) ~ I , I I," ·.1. :., '. I~' ). {t.~;:~Ú;<$·~·~~~j~::~~::~::)'f;:~ I JI,( . P '. ,. ) :~ '. '.: ~ ,',. . '.F" .,..' . f'~. ~ I. ~ I,. .,.J.;' (~(~~~:~y ::pü:r::::)i~,¡~ r(:~pc;.:j ~«. ~~:Ú$ V;,~(h1~~;;~ ::¡¿.~<>'.;~~~>j~~<~~~~:,:~::~(:::~.:~::,~<k.' ¡::r::Ù~:<::~~~~~ ~:f:~~:.>r~::J~~I:· ) ) C,h7()!ß2Ii? 10072 - POTASSIUM CHLORIDE MATERIAL SAFETY DATA SHEET POTASSIUM CHLORIDE 1. CHEMICAL PRODUCT AND COMPANY IDENTIFICATION TRADE NAME: POTASSIUM CHLORIDE SYNONYMS: Muriate of potash. CHEMICAL CLASS: Inorganic salts, APPLICATIONS: EMERGENCY TELEPHONE: Oil well drilling fluid additive. Shale inhibition 281-561-1600 TELEPHONE: FAX: Supplied by a Business Unit of M-I L.L.c. P.O. Box 42842, Houston, Texas 77242-2842 See cover sheet tòr local supplier. 281-561-1509 281-561-7240 SUPPLIER: CONTACT PERSON: Sam Hoskin - Manager, Occupational Health 2. COMPOSITION, INFORMATION ON INGREDIENTS INGREDIENT NAME: Potassium chloride CAS No.: 7447-40-7 CONTENTS: 60-97 % EPA RQ: TPQ: COMPOSITION COMMENTS: Commercial grade potassium chloride (not food grade). 3. HAZARDS IDENTIFICATION EMERGENCY OVERVrEW: CAUTION! MAY CAUSE EYE, SKIN AND RESPIRATORY TRACT IRRJTATION. Avoid contact with eyes, skin and clothing. Avoid breathing airborne product. Keep container closed. Use with adequate ventilation. Wash thoroughly after handling. This product is a white powder. Slippery when wet. A nuisance dust. ACUTE EFFECTS: HEALTH HAZARDS, GENERAL: Particulates may cause mechanical irritation to the eyes, nose, throat and lungs. Particulate inhalation may lead to pulmonary fibrosis, chronic bronchitis, emphysema and bronchial asthma. Dermatitis and asthma may result from short contact periods. INHALATION: May be irritating to the respiratory tract if inhaled. INGESTION: May cause gastric distress, nausea and vomiting if ingested. SKIN: EYES: May be iITitating to the skin. May be irritating to the eyes. 1/6 ) ') 10072 - POTASSIUM CHLORIDE CHRONIC EFFECTS: CARCINOGENICITY: lARC: Not listed. OSHA: Not regulated. NTP: Not listed. ROUTE OF ENTRY: Inhalation. Skin and/or eye contact. TARGET ORGANS: Respiratory system, lungs. Skin. Eyes. 4. FIRST AID MEASURES GENERAL: INHALATION: Persons seeking medical attention should carry a copy ofthis MSDS with them. Move the exposed person to fresh air at once. Perform artificial respiration ifbreathing hag stopped. Get medical attention. INGESTION: Drink a couple of glasses water or milk. Do not give victim anything to drink of he is unconscious. Get medica] attention. SKIN: Wash skin thoroughly with soap and water. Remove contaminated clothing. Get medical attention if any discomfort continues. EYES: Promptly wash eyes with lots of water while lifting the eye lids. Continue to rinse for at least 15 minutes. Get medical attention if any discomfort continues. 5. FIRE FIGHTING MEASURES AUTO IGNITION TEMP. (OF): N/A FLAMMABILITY LIMIT - LOWER(%): N/A FLAMMABILITY LIMIT - UPPER(%): N/A EXTINGUISHING MEDIA: Carbon dioxide (C02). Dry chemicals. Foam. Water spray, fog or mist. SPECIAL FIRE FIGHTING PROCEDURES: No specific fire fighting procedure given. UNUSUAL FIRE & EXPLOSION HAZARDS: No unusual fire or explosion hazards noted. HAZARDOUS COMBUSTION PRODUCTS: This material is not combustible. Fire or high temperatures create: Irritating gases/vapors/fumes. Hydrogen chloride (HCI). 6. ACCIDENTAL RELEASE MEASURES PERSONAL PRECAUTIONS: Wear proper personal protective equipment (see MSDS Section 8). SPILL CLEAN-UP PROCEDURES: Avoid generating and spreading of dust. Shovel into dry containers. Cover and move the containers. Flush the area with water. Do not contaminate drainage or waterways. Repackage or recycle ifpossible. 2/6 ) ) 10072 . POTASSIUM CHLORIDE 7. HANDLING AND STORAGE HANDLING PRECAUTIONS: Avoid handling causing generation of dust. Wear full protective clothing for prolonged exposure and/or high concentrations. Eye wash and emergency shower must be available at the work place. Wash hands often and change clothing when needed. Provide good ventilation. Mechanical ventilation or local exhaust ventilation is required. STORAGE PRECAUTIONS: Store at moderate temperatures in dry, well ventilated area. Keep in originaJ container. 8. EXPOSURE CONTROLS, PERSONAL PROTECTION INGREDIENT NAME: Potassium chloride CAS No.: 7447-40-7 OSHA PEL: ACGIH TLV: OTHER: TWA: STEL: TWA: STEL: TWA: STEL: UNITS: No std. INGREDIENT COMMENTS: *Exposure limits are for Particulates Not Otherwise Classified (PNOC). PROTECTIVE EQUIPMENT: eð ø ENGINEERING CONTROLS: Use appropriate engineering controls such as, exhaust ventilation and process endosure, to reduce air contamination and keep worker exposure below the applicable limits. VENTILATION: Supply natural or mechanical ventilation adequate to exhaust airborne product and keep exposures below the applicable limits. RESPIRATORS: Use at least a. NIOSH-approved N95 half-mask disposable or reuseable particulate respirator. In work environments containing oil mist/aerosol use at least a NIOSH-approved P95 half-mask disposable or reuseable particulate respirator. PROTECTIVE GLOVES: Use suitable protective gloves if risk of skin contact. EYE PROTECTION: Wear dust resistant safety goggles where there is danger of eye contact. PROTECTIVE CLOTHING: Wear appropriate clothing to prevent repeated or prolonged skin contact. HYGIENIC WORK PRACTICES: Wash promptly with soap and water if skin becomes contaminated. Change work clothing daily if there is any possibility of contamination. 9. PHYSICAL AND CHEMICAL PROPERTIES APPEARANCE/PHYSICAL STATE: COLOR: ODOR: SOLUBILITY DESCRIPTION: MEL T./FREEZ. POINT (OF, interval): DENSITY/SPECIFIC GRAVITY (gfml): BULK DENSITY: Powder, dust. White. Odorless or no characteristic odor. Soluble in water. 1351 1.98 TEMPERATURE (OF): 68 1980 kg/m3 3/6 ') ) 10072 - POTASSIUM CHLORIDE VAPOR DENSITY (air=1): VAPOR PRESSURE: pH.VALUE, DILUTED SOLUTION: N/A NJA -7 TEMPERATURE (OF): CONCENTRATION (%,M): 1% 1 o. STABILITY AND REACTIVITY STABILITY: Nom1ally stable. CONDITIONS TO AVOID: NJA. HAZARDOUS POLYMERIZATION: Will not polymerize. POLYMERIZATION DESCRIPTION: Not relevant. MATERIALS TO AVOID: No incompatible materials noted. HAZARDOUS DECOMPOSITION PRODUCTS: No specific hazardous decomposition products noted. 11. TOXICOLOGICAL INFORMATION TOXIC DOSE· LD 50: Component: 2600 Potassium chloride TOXICOLOGICAL DATA: Corrosive effects. Eye irritation test. 24 hours. Rabbit. 500 mg - Mild IlTitation TOXIC DOSE - LD 50: 2600 mg/kg (oral rat) 12. ECOLOGICAL INFORMATION ECOLOGICAL INFORMATION: No ecological information is available tor this product. 13. DISPOSAL CONSIDERATIONS WASTE MANAGEMENT: This product does not meet the criteria of a hazardous waste if discarded in its purchased fonn. Under RCRA, it is the responsibility of the user of the product to detenT1ine at the time of disposal, whether the product meets RCRA criteria for hazardous waste. This is because product uses) transformations, mixtures, processes, etc, may render the resulting materials hazardous. Empty containers retain residues. All labeled precautions must be observed. DISPOSAL METHODS: Recover and reclaim or recycle, if practiC<1l. Should this product become a waste, dispose of in a pennitted industrial landfill. Ensure that containers are empty by RCRA criteria prior to disposal in a permitted industriallandfùl. 14. TRANSPORT INFORMATION 4/6 ') 10072 - POTASSIUM CHLORIDE GENERAL: U.S. DOT: U.S. DOT CLASS: CANADIAN TRANSPORT: TDGR CLASS: SEA TRANSPORT; IMDG CLASS: AIR TRANSPORT~ ICAO CLASS: 15. REGULATORY INFORMATION ) RQ = N/A Not regulated. Not regulated. Not regulated. Not regulated. REGULATORY STATUS OF INGREDIENTS: NAME: CAS No: Potassium chlOlide 7447-40·7 US FEDERAL REGULATIONS: WASTE CLASSIFICATION: REGULATORY STATUS: STATE REGULATIONS: STATE REGULATORY STATUS: CANADIAN REGULATIONS: REGULATORY STATUS: 16. OTHER INFORMA TJON NPCA HMIS HAZARD INDEX: FLAMMABILITY: REACTIVITY; NPCA HMIS PERS. PROTECT. INDEX: USER NOTES: TSCA: CERCLA: SARA 302: SARA 313: DSL(CAN): Yes No No No Yes Not a hazardous waste by U.S. RCRA criteria. See Section 13. This Product or its components, if a mixture~ is subject to following regulations (Not meant to be all inclusive - selected regulations represented): SECTION 313: This product does not contain toxic chemical subject to the reporting requirements of Section 313 of Title III of the Superfund Amendment and Reauthorization Act of 1986 and 40 CFR Part 372. SARA 311 Categories: 1: Immediate (Acute) Health Effects. The components ofthis product are listed on or arc exempt from the following international chemical registries: TSCA (U.S.) This product or its components, if a mixture, is subject to following regulations (Not meant to be all inclusive - selected regulations represented):. None. This Material Safety Data Sheet has been prepared in compilance with the Controled Product Regulations. Canadian WHMIS Classification: Not a Controlled Product. 1 Slight Hazard o Minimal Hazard o Minimal Hazard E . Safety Glasses, Gloves, Dust Respirator NI A::;:: Not applicable N/D :;: Not determined 5/6 ') ) 10072 - POTASSIUM CHLORIDE INFORMATION SOURCES: OSHA Pcnnissible Exposure Limits, 29 CFR 1910, Subpart Z, Section 1910.1000, Ajr Contaminants. ACGIH Threshold Limit Valu.es and Biological Exposure Indices for Chemica.l Substances and Physical Agents (latest edition). Sax's Dangerous Properties oflndustrial Materials, 9th ed., Lewis, R.J. Sr.) (ed.), VNR, New York, New York, (1997). Product infonnation provided by the commercial vendor(s). PREPARED BY: Sam Hoskin REVISION No.JRepl. MSDS of: 2/July 10, 1998 MSDS STATUS: Approved. DATE: June 6, 2001 DISCLAIMER: MSDS furnished independent of product sale. \Vhile every effort has been made to accurately describe this product, same of the data are obtained from sources beyond our direct supervision. We cannot make any assertions as to its reliability or completeness; therefore, user may rely on it only at user's risk. We have made no effort to censor or conceal deleterious aspects of this product. Since we cannot anticipate or control the conditiions under which this information and product may be used) we make 110 guarantee that the precautions we have suggested wiH be adequate for a11 individuals and/or situations. It is the obligation of each user of this product to comply with the requirements of all applicable laws regarding use and disposal of this. product. Additional information will be furnished upon request to assist the user; however, no warranty, either expressed or implied, nor liability of any nature willi respect to this product or to the data herein is made or incurred hereunder. 6/6 #4 ) ConocJP'hillips Alaska ) P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 RECEIVED MAY 1 8 2005 May 15, 2005 Alaska Oil & Gas Cons. Commission Anchorage Mr. John Nonnan, Chainnan Alaska Oil & Gas Commission 333 West ih Avenue, Suite 100 Anchorage, AK. 99501 Subject: Alpine Well CD2-51 (PTD 202-249) Request for Administrative Relief to Continue Water Injection Operations Dear Mr. Nonnan: ConocoPhillips Alaska, Inc., requests approval to continue water injection operations into Alpine well CD2-51. This request is pursuant to Area Injection Order No. 18B, Rule 11 Administrative Actions. CD2-51 has tubing by inner annulus communication via a very slow linear leak in an undetennined location - possibly at the packer. A combination of mechanical integrity pressure tests of tubing and casing strings indicates the well has competent mechanical integrity and can be safely operated. Barriers have been defined (see attached) that will prevent an inadvertent release and confine fluids to the approved zones. The attached Technical Justification includes a proposed operating and monitoring plan. Daily monitoring of the wellhead and casing/tubing mechanical integrity tests are proposed to verify the well continues to be safe to operate. Should observations or tests indicate a compromise of well integrity, the well will be shut-in and the AGOCC notified. There is no source of underground drinking water in this area that could be endangered by this proposal. If you need additional infonnation, please contact me or Marie McConnell at 659-7224. ;¡µ~ MJ Loveland Problem Well Supervisor Attachments ORIGINAL ) ) ConocoPhillips Alaska, Inc. Alpine Well CD2-51 (PTD 202-249) Technical Justification for Administrative Relief Request Well History and Status Colville River Unit well CD2-51 (PTD 202-249) was originally completed in May 2003, as a MW AG Service well. In January 2004, inner annulus (IA) and tubing (T) pressures in this well started tracking, indicating TxlA communication. At that time, the 1" dummy valve in the tubing was pulled and replaced, after which, the tubing and IA stopped tracking and the well passed a mechanical integrity test of the IA (MITIA). March 23,2005, TxlA communication indications were again observed and reported to the AOGCC. The well failed a diagnostic MITIA on 3/25/05, with a very slow linear pressure leak and was SI. On 4/7/05 that failure could not be repeated - after conducting several passing MIT's of the tubing and inner annulus the well was brought back online. However, the well failed an additional MITIA on 4/15/05, with another slow linear leak. We concluded that the well would pass an MIT while it was Sl; however, would fail an MIT while online injecting cold seawater. On 4/27/05, the dummy valve in the tubing was replaced; this time with an extended packing dummy for water service in hopes it would seal the leak. It passed an MITIA that day while it was Sl; however, also failed another MITIA with a slow linear leak on 4/30/05 after it was brought on line. The pressure leak off in every failed MIT was slow enough that a liquid leak rate could not be achieved for a conventional leak detection log. Currently the well will pass a mechanical integrity pressure test when the well is Sl and warm. It will fail a MIT while it is online injecting cooler seawater. This phenomenon suggests some sort of seal leak, possibly the packer. Well events: 3/25/05: MITIA to 2500 psi - failed with well online. 4/07/05: MITT to 2400 psi with plug in TT - passed, MITIA to 2500 psi - passed, Combo TxIA MIT tubing to 1750 and IA to 3000 psi - passed, all tests were completed with the well SI. 4/15/05: MITIA -2500 psi - failed while well was online, tubing and inner casing packoff pressure tests passed. 4/27/05: Replaced DV with high seal ability packing, MITIA to 2500 psi - passed while well was SI. 4/30/05: MITIA to 2500 psi - failed while well was online injecting cool SW. 5/10/05: MITOA failed - well has an open shoe, can pump 1 BPM at 1600 psi, holds static column of fluid at 800 psi. NSK Problem Well Supervisor 5/1512005 1 ) ) Barrier and Hazard Evaluation Tubing: The tubing has integrity to the casing and sand interval below the packer based on a passing MITT @ 3000 psi. Production casing: The production casing has integrity down to the packer based on a passing MITIA to 3000 psi while the well is SI. However, may still have a very slow linear leak possibility at the packer when injecting cold seawater. The 7" L-80 production casing has an internal yield pressure rating of 7240 psi. Surface casing: The surface casing has no cement shoe; however, will hold a static column of fluid at 800 psi. The 9-5/8" 36# J-55 surface casing has an internal yield pressure rating of 3520 pSI. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing. The tubing appears to have solid integrity based on the MITT. Secondary barrier: The production casing is the second barrier. It holds a solid MIT when SI and only has a slow linear leak to pressure when online. The surface casing also provides a partial secondary barrier up to ,...., 800 psi. Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the production casing above the surface casing shoe, it will be noted during the daily monitoring process. Any deviations from approved Maximum allowable operating pressures (MAOP) annular pressures require investigation and corrective action, up to and including a shut-in of the well. T /IlO plots are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. Proposed Operating and Monitoring Plan 1. Approve for water-only injection (no gas or MI allowed); 2. Perform 2-year MIT -T or MITIA to verify the tubing has not developed a leak and the MITIA failure has not worsened. 3. Perform 2-year OA fluid levels to ensure no injection out the bottom of the surface casing shoe; 4. Monitor T, lA, and OA pressures daily, particularly noting any sudden change from one day to the next. 5. Submit monthly reports of daily wellhead 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. Future Options The Engineering staff is proposing further options to identify the source of the leak using leak detection technology that is currently not available on the slope. There is a significant volume of reserves at risk if the well can not be returned to MI service. Therefore, every effort will be made to restore the casing integrity by locating and patching the leak or working over the well in the next couple of years. NSK Problem Well Supervisor 5/15/2005 2 #3 [Fwd: Re: [Fwd: FW: CD2-09 tlowback re I . Subject: [Fwd: Re:·· [Fwd:FW:€b2-0Ø tlÖ~båckt~Cl~êst]] From: John Hartz <jack __hartz@adrr1in.state;ak.u$:> I?a.t.e: .~~~,.~2.ê~p2?P41.?:~7.:.~.~...-?8P?..... ..........<...................................... ..............:...... ....... 1'q:Jo9YGþl()rµbj~~Qqyjç~~pm1.)i~@~~ip,:~t~~~;~~:ci~~ .... .....,... ;", ....,;.., I'; Please put a copy in the CPAI - CRU application to amend CO 443 and AIO 18. Thanks, Jack -------- Original Message -------- Subject: Re: [Fwd: FW: CD2-09 flowback request] Date: Wed, 22 Sep 2004 16:25:47 -0800 From: John Hartz <jack hartz@admin.state.ak.us> Organization: State of Alaska To: Dora.I.Soria@conocophillips.com, Kelli.L.Hanson@conocophillips.com cc: Stephen F Davies <steve davies@admin.state.ak.us>, Thomas E Maunder <tom maunder@admin.state.ak.us> References: <4151F7BF.50609@admin.state.ak.us> Dora & Kelli, The operation you describe is a completion operation and for which approval is part of the permit to drill. Cleaning the wells to tanks is a pretty common feature of completion operations to prevent formation damage by foreign fluids. We expect to have the amended orders ready in the next week or so, prior to your beginning "regular production" (that means ...production of oil or gas from a well into production facilities and transportation to market, but does not include short term testing, evaluation, ...") Jack Hartz, PE Stephen Davies wrote: Jack, The Alpine flowback request I mentioned earlier. Steve -------- Original Message -------- Subject: FW: CD2-09 flowback request Date: Wed, 22 Sep 2004 13:38:41 -0800 From: Soria, Dora I <Dora.I.Soria@conocophillips.com> To: steve davies@admin.state.ak.us CC: Hanson, Kelli L <Kelli.L.Hanson@conocophillips.com>, Alonzo, Chris <Chris.Alonzo@conocophillips.com> Steve: You have informed me we should expect a favorable ruling early next week to request for an expanded area for Alpine pool rules and an injection order. respectfully requests AOGCC's permission to perform the operation described in advance of a final approvable. Thank you for your prompt consideration. our CPAI below Best regards, -dora lof2 9/23/20047:42 AM [Fwd: Re: [Fwd: FW: CD2-09 tlowback rf -. . -----Original Message----- From: Hanson, Kelli L Sent: Wednesday, September 22, 2004 1:27 PM To: Soria, Dora I Cc: Alonzo, Chris Subject: CD2-09 flowback request Dora, As I mentioned on the phone earlier, the CD2-09 post-rig slickline work has been completed and the well is ready for flowback. We flow back new wells to unload and clean up the well prior to sending the produced oil to the plant. We perform these flowbacks as soon as possible following the completion of the drilling program in order to minimize the amount of time the drilling fluid (in this case, mineral oil-based mud) sits on the formation and thus prevents/minimizes formation damage. In this case, we are requesting approval to flow CD2-09 back to tanks. CD2-09 is the first and only well to be completed in the Alpine Northwest Periphery (outside the existing PA). CD2-09 will be flowed back until the oil is clean (no solids) and low water cut. The well will then be shut-in until the approval is obtained to bring the well online. Please let me know if you have any further questions. Thanks, Kelli Kelli L. Hanson Production Engineer Alpine Engineering WNS Subsurface Development 907.265.6945 Jack Hartz, P .E. <jack hartz@admin.state.ak.us> Alaska Oil & gas Conservation Commission 20f2 9/23/2004 7:42 AM [Fwd: Re: Questions Regarding Expansion ·Jine Order Area] .. "',,.. » /' ·§q~jé~~·.:..·....[~~3:...~ë:...·..~1.1estioIls.....Regat"dìl1g.·..gxp.ansion of Alpine ·Order. Area] .lf~()~;·...·.·.~'~T~~e.~·...B.~~.i7~...·..~s~ev~__4~yie.s.@admin;state.ak.us> I>at~:··Tlrµf02§.ep···..2()04. ·.1.··~.:17:54-0800 To:' Jo.dY Colombie <jody_ colombie@admin.state.ak.us> Please put this message into the order file. Thanks, Steve D. -------- Original Message -------- Subject: Re: Questions Regarding Expansion of Alpine Order Area Date: Wed, 01 Sep 2004 11:33:23 -0800 From: Thomas Maunder <tom maunder@admin.state.ak.us> Organization: State of Alaska - To: Alonzo, Chris <Chris.Alonzo@conocophillips.com> CC: Rodgers, Dan <Dan.Rodgers@conocophillips.com>, Soria, Dora I <Dora.I.Soria@conocophillips.com>, Ireland, Mark M <Mark.M.Ireland@conocophillips.com>, Crabtree, C L <C.L.Crabtree@conocophillips.com> References: <127E49C8DD4E4A4591702B4B7941AA1A48FEFF@ancexmb1.conoco.net> Chris, et al: Please be advised that we have received your information and the questions we posed have been satisfactorily answered. There has been no request for a hearing and Commissioner Norman has asked me to advise you that the Commission will NOT be holding a hearing on this matter. Please contact myself or Jody Colombie with any questions. Tom Maunder, PE AOGCC Alonzo, Chris wrote: Tom, Per request, please find enclosed the CPAI responses to the AOGCC questions regarding the CPAI application to expand the applicable areas of C0443 and AIO 18B for the northwest Alpine peripheral area. Please review the data and let me know if CPAI needs to provide any additional data to the AOGCC. Thanks, Chris Alonzo Alpine Engineering Supervisor ConocoPhillips, Alaska (907) 265-6822 chris.alonzo@conocophillips.com -----Original Message----- From: Thomas Maunder [mailto:tom maunder@admin.state.ak.us] Sent: Wednesday, August 04, 2004 1:28 PM To: Crabtree, C L; Alonzo, Chris Cc: Steve Davies; John D Hartz Subject: Questions Regarding Expansion of Alpine Order Area Cliff and Chris, Attached are two documents containing the questions/clarifications we have developed with regard to CPAI's applications to expand the applicable areas of CO 443 and Ala 18A. You should refer to the existing orders to how the subject of our questions was addressed ; When the orders were originally written. Please feel free to contact me or Steve Davies with any questions. Tom Maunder, PE AOGCC 10f2 9/8/2004 10:38 AM [Fwd: Re: Questions Regarding Expansior ,.. line Order Area] . 20f2 9/8/2004 10:38 AM Re: Questions Regarding Expansion of AI' ,Ider Area . SJlbJ~¿t:Re:QllestionsRegarding Expansion of Alpine Order Area FJ:om:Thomas Maunder <tom _ maunder@admin.state.ak.us> Da:'-~e:Wed,.OI. Sep 2004 11 :33:23 -0800 Tó: "AIo~o, Chris" <Chris.Alonzo@conocophillips.com> çç:: ·.~'Rpdgers" Dan" <Dan.Rodgers@conocophillips.com>, "Soria, Dora I" ~p()~~:Soria@conocophillips.com>, "Ireland, Mark M" <Mark.M.Ireland@conocophillips.com>, "ç~Þti.ee~C ·L" <C.L.Crabtree@conocophillips.com> Chris, et al: Please be advised that we have received your information and the questions we posed have been satisfactorily answered. There has been no request for a hearing and Commissioner Norman has asked me to advise you that the Commission will NOT be holding a hearing on this matter. Please contact myself or Jody Colombie with any questions. Tom Maunder, PE AOGCC Alonzo, Chris wrote: Tom, Per request, please find enclosed the CPAI responses to the AOGCC questions regarding the CPAI application to expand the applicable areas of C0443 and AIO l8B for the northwest Alpine peripheral area. Please review the data and let me know if CPAI needs to provide any additional data to the AOGCC. Thanks, Chris Alonzo Alpine Engineering Supervisor ConocoPhillips, Alaska (907) 265-6822 chris.alonzo@conocophillips.com -----Original Message----- From: Thomas Maunder [mailto:tom maunder@admin.state.ak.us] Sent: Wednesday, August 04, 2004 1:28 PM To: Crabtree, C L; Alonzo, Chris Cc: Steve Davies; John D Hartz Subject: Questions Regarding Expansion of Alpine Order Area Cliff and Chris, Attached are two documents containing the questions/clarifications we have developed with regard to CPAI's applications to expand the applicable areas of CO 443 and AIO l8A. You should refer to the existing orders to how the subject of our questions was addressed When the orders were originally written. Please feel free to contact me or Steve Davies with any questions. Tom Maunder, PE AOGCC 1 of 1 9/1/2004 12:54 PM con~o~hilliPS applies for expansion of AI":¡Oil pool- 08/0412004 t ~ . -w'" <, ~ r i~ I, , ' , , ",'1/",' I ,~:",:" ,'rc"...., ,',;",;,:-;, '", ",.." ',I ""''''~.¡;L 1~,,~\;':::'(;"'/ ",:'?r":':.;¡::;::;: ":,"<"'"."'....;¡¡;¡;..-!ot".,~;;;;¡¡¡,i ,"~~~~~~~~~~~~,':"~...'''''.'''..,~~......'''_,.-'.,...,,..'_~.........., ,"~, ,",',' ','"":,,,' ","',," ",' ,'", " ",,','" :~Fì.,-· . 'Wlt.I'~"~:r[ï f_!¡~~jl'~Ii&;~I;l\AAt.r~;;~~~,~Hi!.I~ N=WS BU__=- N August 04,2004 - Vol. 10, No. 68 August 2004 ConocoPhillips applies for expansion of Alpine oil pool ConocoPhillips Alaska has applied to the Alaska Oil and Gas Conservation Commission to expand the area of the Alpine oil pool covered by the corrnnission's production and injection orders. proposed expansion area is within the Colville River UIÙt, and drilling would be from Colville River unit drill site CD2. ConocoPhillips said information for the requested expansion comes from results of its development drilling, which "has greatly increased our knowledge of the distribution of the sands" in the Alpine participating area and has allowed it to better coITelate seismic data with reservoir sands. Original oil in place in the expansion area is estimated at 31 million to 55 million barrels, and the company said that range "will undoubtedly change as new drilling information becomes available." ARCO Alaska Inc., ConocoPhillips Alaska's predecessor, told the commission in 1999 that Alpine contained an estimated 960 million barrels of oil in place, and that with horizontal wells and a miscible water-alternating-gas oil recovery process implemented at startup, recovery was expected to be 45 percent, or some 429 million barrels. At a midpoint in the 31 million to 55 million barrel range the proposed. expansion area would add less than 5 percent to oil in place at the field. ANS production down on Alpine, pipeline shutdowns Alaska North Slope crude oil production averaged 825,733 barrels per day in July, down 11.63 percent from June, due primarily to the beginning of a scheduled shutdown at Alpine for facility expansion and maintenance work. A 30-hoW' scheduled shutdown of the trans-Alaska pipeline July 10-11 for maintenance combined with summer temperatures, which make compressors used. for gas re-injection less efficient, contributed to an average production drop at all North Slope fields from June to July. The ConocoPhillips Alaska-operated Alpine field, which ramped down to marginal production July 19 and had no production from July 21 through the end of the month, averaged 54,173 bpd for the month, compared to 102,864 bpd in June. The BP-operated Endicott field averaged 21,502 bpd in July, down 12.9 percent from a June average of 24,678 bpd. The BP-operated Lisbwne field averaged 47,318 bpd in July, down 9.26 percent from a June average of 52,146 bpd. The BP-operated Prudhoe Bay field averaged 397,464 bpd in July, down 7.9 percent from a June average of 431,444 bpd. BP's Milne Point field averaged 49,490 bpd in July, down 6.91 percent from a June average of53,161 bpd. The ConocoPhillips-operated Kuparuk River field averaged 185,921 bpd, down 5.76 percent from a June average of 197,275 bpd. BP's Northstar field averaged 69,865 bpd in July, down 4.13 percent from a June average of 72,875 bpd. The July North Slope temperature averaged 49.8 degrees Fahrenheit at Pump Station No.1, compared to a three-year average of 10f2 --::~ ",.--,....~. 8/5/2004 10:54 AN --'-"-->"ì'\ ""' ~- I " - ~ 4- ConocoPhillips applies for expansion of AIP;"'~)oil pool - 08/04/2004 · " , '1 20f2 J 46.9 degrees F. Production in Cook Inlet averaged 23,694 bpd, down 2.94 percent from a June average of24,411 bpd. See complete stories in Aug. 8 issue of Petroleum News. Print this sto.·y Petroleum News - Phone: 1-907522-9469 - Fax: 1-907522-9583 circulationrã'i,PetrolcumNcws.com - http://wwVI..pctro1cumncws.com -- SUB S C RIB E Translate this story to your language: from I English to Spanish ~"" T~an~late .1 CLICK BELOW FOR A MESSAGE FROM OUR ADVERTISERS. Æiffu . TRANSPORTATION SYSTEMS C3111(907)245-8008 8/5/2004 1 0:54 A~ #2 AO.FRM Publisher/Original Copies: Department Fiscal, Department, Receiving 02-902 (Rev. 3/94) Ddc;:.P7ftfßJ 3 R:QUISITIONEDB~ ~ _ 2 ARD 02910 3 4 FIN AMOUNT SY CC PGM LC ACCT FY NMR DIST LIQ 1 05 02140100 73451 2 PAGE 1 OF TOTAL OF 2 PAGES ALL PAGES$ COMMENTS ~!_~~JI~~~~~J,pr~"~~~t~:: AOGCC, 333 W. 7th Ave., Suite 100 ::~~·,:~~yg{;¿.ti;1:fI~~~:;::·:\r::rø:;':~U~::\;:!:f:':';:~ : t;+".:'::"'~'" ';, Anchorage, AK 99501 REF TYPE NUMBER AMOUNT DATE VEN SEE ATTACHED STOF0330 Advertisement to be published was e-mailed D Classified DOther (Specify) o Display Type of Advertisement X Legal THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: July 30, 2004 ~ Anchorage Daily News POBox 149001 Anchorage, AK 99514 (907) 793 -1 ??, 1 DATES ADVERTISEMENT REQUIRED: DATE OF A.O. AGENCY CONTACT Jody Colombie PHONE STATE OF ALASKA ADVERTISING ORDER :~:}(~:;;:~~~_:~~~~:~~~~,>'.;:'?: F AOGCC R 333 W 7th Ave, Ste 100 o Anchorage, AK 99501 M July 29, 2004 PCN AO-0251400S ~ NOTICE TO PUBLISHER ~ IN\"'MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER . CERTIFIED AFFIIJAVIT OF PUBLICATION (PART2 OF THIS FORM) WITH ATIAC E:D COPY OF ADVERTISEMENT MUST BE SUBMITIED WITH INVOICE ADVERTISING ORDER NO. J J Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Alpine Oil Pool, Prudhoe Bay Field Request for expansion of area subject to pool rules and area injection order ConocoPhillips Alaska, Inc. by application dated July 22, 2004, has applied for expansion of the affected area for the Alpine Oil Pool as defined in Conservation· Order No. 443 and for Area Injection Order No. 18A according to 20 AAC 25.402 and 20 AAC 25.520. The Commission has tentatively scheduled a public hearing on this application for September 2,2004 9:00 am at the Alaska Oil and Gas Conservation Commission at 333 West 7th 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 August 16, 2004. If a request for a hearing is not timely filed, the Commission will 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 7t Avenue, Suite 100, Anchorage, Alaska 99501. Written protest or comments must be received no later than August 31, 2004 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 September 2, 2004 hearing. If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing, please contact Jody Colombie at 793-1221 before August 23,2004. ft~::5 /' Chair Published Date: July 30, 2004 AO# 02514005 .fnchOrage Daily News Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 ) 71?tJ/2~ PRICE OTHER OTHER OTHER OTHER OTHER GRANO Ao# DATE PO ACCOUNT PER DAY CHARGES CHARGES #2 CHARGES #3 CHARGES #4 CHARGES #5 TOTAL 244613 07/30/2004 02514005 STOF0330 $154.76 $154.76 $0.00 $0.00 $0.00 $0.00 $0.00 $154.76 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 Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on the above dates and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Signed >fJ~JcU Subscribed and sworn to me before this date: /cJ} Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY;Z0 M.ISSIO. N... EXPIRES.: C.'.)(;./11,1) !1,(if'JW{(ff . í .'-, / ~\\ i-RlY -4 ((I'"...... . / Ii 1)/ I¡ / ~,~~... :.:..:...,II.;:{'"'- . - U1YÝJc,Uo/ /: "A'Ùi4Þ~~~"~O~~~~~'f~ J I -~' PuS" \c ' ~ . ::..:.:z- '. cP "". : ~ ~ ~~"~~ ~-.. F'~'~ -:... ..'" . OF A~ ." "'-~ ........ , . . . . .~. ," /.//, t ,Explr-3':", ~ ì \'\'\ ·j/i}J}}))), I'/( 0 :<O(í L! -./ I N ~tic:e' Of .... pu bllcHeari ng' ~TÄTE OF'ALASKA ..IO~I.O ÜII·)r,a (,00;. (,)."o;r.o..,)n CI)rT\m.,;~.rA ,<",'Alp.no; 0" ¡:'Oul ¡:'rual'lo", Bo',' Fi",lo RO:-Qu.;-;I ,.:,r '" ~ Clor.., ".r, (,I or,;-o '>IJb I 0:-( I II) p(,OI '.;!'Úlesandarea injection '()rder t'ónoCoP~i;lrpO¡;'Alo'::kd 'I~C: bycib~l¡cdtl(\h 0.) 1",(1 J u'" J.j il'OJ hO~ OIJPIo,;-(I lor 0:- ~ Clun ;ion Crl 111.,. 01""(1"''] orfù lur In.. /.olp,r,,;- 0;1 PCl(o! O~ a..linf.:l ,n (c,n;er.OlirJn (r.::l..r tl,]. JJ3 ond lor ....reo Inl~C"Or, Or.:lO:-~ 1'1'. I¡¡A O"Oralr,';1 1020 AAC ~5 J')2 on.:l 20 AACt5..5.tú. I The ComlT1i55ion ho,> tentOthiF.':IV'.iCh";ÓLiled CI :IuDI,( 110:-0r.r'9 or. Ir"" OPPI',al;,Jrr lor 5epl",mD"r ~ :Oll(IJ'1 ÚO Onllll Ir.... ~1.\J;,l\ù I),¡ o~e! Vf.l'.i~"ÿ";:r .(~' , "on Cumrn,o¡,;,lorr 01 J3, lIIIe~1 7m "Y1!A~'~II,:" IOU ':'n, roc,rog" ':'lo.~,O 4Q50 I A p~rson¡mQ'\I reqlJe,>1 IhOI Ino:- l",nIOI,."I·. ';cno:-dulea heori1~ b¿ nfle! D. 1,I,r.q 0 ~,rll'..n I"'O'JE-;.I JIIIIr. Ih,¡. Col'11i'r,,~,>,l)n no , laH~r rhon 4:jú pm on AU9U~116,2?Úf'</:' If ° request for a hea.riml is not timèlY filed. the Commissionwillcon~idèr the Is~uol1ce ot on , order without ° hearing, To.leorn if the Commìs- sionwìllholdthep\Jblic. hearing, pleasecaU 793-1221. ' I n addition, a person may sµbmiJ,a w.ritten pro- test .01' written comments regotØJr¡9thlS applica- tion to the AlaskaOìlandGas¡~p~ri,¡¡êI'Ylatl~m Com- mission ot 333 West 7th Avenu,e.¡-$ulte 100, Anchorage, Alaska .99501. . Wr.ftt~n ,:r,otestor com- ments mustbe,:received no làte:r'-;.fb.á'n August 31, 2004 except thatJf t·he CommissíÒò'decides to hold a public heoring, written protest· or. comments must be received no later than the conclusion of I the September 2, 2004 hearing. If you are ° person with a disability who may need a special modification in order to comment or to'attend the public hearing, please contoct Jody Colombie at 793-1221 before August 23,2004. John Normat'\' Chair' AO# 02514005 . ' Publish': J'ù!v 30. 2004 ~ J~ RE: Notice ) '-' J Sllbject:ltE:.}Jotice ~~~·ltl:·.···..l~fala~s.·..<lega~ads@)adn·com> Q~*~:Weâ,28..·.Ju12Q()4.()9:08:27~0800 To:fJody.Colomhie <jody _ colombie@admin.state.ak.us> Good Morning Jody: Following is the confirmation information on your legal notice. Please let me know if you have any questions or need additional information. Account Number: STOF 0330 Legal Ad Number: 244613 Publication Date(s): July 30,2004 Your Reference or PO#: 02514005 Cost of Legal Notice: $154.76 Additional Charges Web Unk: E-Mail Link: Bolding: Total Cost to Place Legal Notice: $154.76 Ad Win Appear on the web, www.adn.com: :xxxx Ad Win 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) 279-8170 ---------- From: Jody Colombie Sent: Wednesday, July 28, 2004 8:14 AM To: legalads Subject: Notice «File: Alpine C0443 AI0188 Notice.doc»«File: Ad Order form.doc» Please publish the attached on July 30, 2004. Thank you. 1 of 1 7/28/20049:34 AM STATE OF ALASKA ADVERTISING ORDER ~::.:"..~:~~,,,~::~~~~~,,~~~~~~~.:\".':.,,:'. j NOTICE TO PUBLISHER J ADVERTISING ORDER NO. INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AO 02514005 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF - ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE F AGENCY CONTACT DATE OF A.O. AOGCC R 333 West 7th Avenue,Suite 100 o Anchorage, AK 99501 M 907-793-1221 Joòy Colombie July ?9, ?004 PHONE PCÑ (907) 793 -1 ??1 DATES ADVERTISEMENT REQUIRED: ~ Anchorage Daily News POBox 149001 Anchorage, AK 99514 July 30, 2004 THE MATERIAL BETWEEN mE 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 he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2004, and thereafter for _ consecutive days, the last publication appearing on the _ day of , 2004, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This _ day of 2004, Notary public for state of My commission expires 02-901 (Rev. 3/94) Page 2 AO.FRM PUBLISHER 7/28/20048:15 AM 1 nf" S~bje~t:Notice F~()IJl:J()qyColombie<jody_colombie@adrnin.state.ak. US> Date: Wed, 28 Jul200408:15:44~0800 'Tof undiscl(>sed~¡'ecipients:; BCC:RobertE· ~ntz· <roberL. mintz@law.state:ak.us>, Christine Hansen <c.:hansen@iogcc.state.ok.us>, TeiTieHubble <hubblet1@bp.com>, Sondra Stewman <StewmaSD@BP .com>, Scott & Cammy Taylor <staylor@alaska.net>, stanekj <stanekj@unocatcom>, ecolaw <ecolaw@trustees.org>, roseragsdale <roseragsdale@gcLnet>, tnnjr 1 <tnnjrl@aol.com>, jbriddle <jbriddle@marathonoi1.com>, rockhill <rockhil1@aoga.org>, shaneg <Shaneg@evergreengas.com>, jdarlington <jdarlington@forestoil.com>, nelson <nelson@gcLnet>, cbqddy ·<CboddY@uSibel~ì.com>, MarkDaltoD<emark.daltòn@hdrinc.com>, . Shannon Donnelly ~b.ftt1noµ'~donneny@conocophinips.com>, "Mark P.. Worcester" . <. ·m. ..... ark. .:p. .~worc..e. st. ðr@.·çonocoP.·billips.com.>'."Jerry... .. C.D..· ethIe.. fs" . <j;~riy.~~dethlef.s@.cono:cophinipS...c<;)m> ,Bob <bob@inletkeep~r.org>, wdv <wdv@dnr.state~alcus>, tjt: <tjr@cinr~~tate~ak.us> ,bbriteh<bbritch@alaska.net> ,mjnelson <mjnelson@purvingertz.com>, Charle$O'D<?I111~U <charles,o'donnell@Veco.com>, "RandyL. Skillern" <SkilleR,L@BP .com>, "Jeann.,· .·e H~pickey" <DickeyJH@BP.com>,~~Deborah J. JoneS" <JonesD6@BP.Co111>,tlPauLG.. Hy~~t'; <hyat~pg@BP.Com>, !'Steyen R.R.ossþerg"<RòssbeRS@BP.com>,L01s . . .., <lºìs@inletk~epei.org>, tlJosephF.Kirchner" <l(irc~@ap·.cOß1>, Gordol1.Pospisil <:~òsp~sG~P..t0111~; . "Fr~ci~:S~ SOmmer" <Somme~FS@BP~com::>, Mikel SCl1ultz" ~Mik:yl.S¢Þu11:z@B})~ç()th>~nNick W . Glover" <GIQveJ;NW(@BP .com>, "Daryl J ~ Kleppin~' , <Iq.eppiDE@Bp ~com>~ ~lanetD . Platt" <PlattJD@BP .com>~ "RosanIle M~J acobsen i' <JacobsRM@BP..com>, dd6ÏÙ<:el <ddohkel@cfl.rr.com>,CollinsMount <cpl~~_!11~unt@revenue.sta!e.ak.us>, mckay<mckaY@jgcLnet>, BarbaraP Ft1l1mer <:barbara.£fu1lmer@cono~ophinips.com>, bocastwf <bocastwf@bp.com>, Charles Barker <barker@usgs.gov>,doug_ schultze <doug_schultze@Xtoenergy.com>, Hank Alford "%~~~a!f9rd@~~~onmobiLco111> , Mark Kovac <yesnÇ)l@gci.net>, gspfoff . . ~~spf.()ff@àuro~âpower.c()m>, Gregg· Nady. <::gregg.nady@s~ell.com>, Fred·Steece 5fr.'ed.s~e~c~®state.sd..us>, rcrotty <rcrotty@ch2m.com>, jejones <jejones@aurorapower.com>, dapa ~a@alaska.net>,jroderick. <jroderick@gcLriet>, eyáncy.<ey~cy@seal-tite,net>, "James M. ~~ud~'. <james.m.ruud@conocophillips.com>, Brit Lively<mapalaska@ak.net>, jab <jah@drir.state.ak:.us>,Kurt .E Olson <kurt _ olson@legis.state.ak.us>, bQonoje <buonoje@bp.com>, Mark ~anley <mark _ hanley@anadarko.com>, loren_lernan. <loren_leman@gov.state.ak.us>, Julie Houle <julie_houle@dDr.state.ak.us>, John W Katz <jwkatz@sso.org>, Suzan J Hill ~~8l1..,.:.hill@dec.state..al{.\ls>,tablerk <tablerk@unocal.com>, Brady <brady@aoga.org>, Brian Itãvelock' <beh@dnr.state.ak.us>, bpopp <bpopp@borough.kenai.alcus>, Jim White <.iimwhit~@SatX~rr.cottl>, "John S~ Haworth·· <john.s.haworth@exxonmobil.com>, rnarty ~riu\rty@rkfudµstriatcó~> ~ ghanunòns <ghamrnons@~1.com>,nnclean <nn~le~@p9box.a1aska.net>, James Scherr <james.scherr@mrD.s.gov>, mkm7200 <Inkm7200@aol.com>, Brian Gillespie <ifbmg@uaa.a1aska.edu>, David L Boelens. <dboelens@aurorapower.com>, Todd Durkee <IDURKEE@KMG.com>, Gary Schultz <g~_schultz@dnr.state.ak:.us>, Wayne Rancler <RANCIER@petro-canada.ca>, Bill Miller <:silt... Mi11er@xtoalaska.com~, Br~don Gagnon <bgagnon@brenalaw.com>, Paul Winslow <p~Winslow@forestoil.com>, Garry C&tron <catrongr@bp.com>~. Sharmaine Çopeland . <s~opelasv@bp.~com~, Suzanne :Allexan <sa1lt~xan@helmenergy.com>, ~stÌÌ1:pjr1cs: 4Z~s!mß(iit'~@~~~r4t~~~~ít.S,?·' . ..... J J Notice Notice ~ J Alpine _ C0443 _ AI018B _ Notice.doc Content-Type: application/msword ............................................. .......................................... ...: ...Content-Encoding: base64 ........................,......... ..., ",............".....".,.",.".."",............ ......,,,......,....,..........,...........,.. 2 of2 7/28/20048:15 AM Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Kelly Valadez Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 w) ~ David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 John Levorsen 200 North 3rd Street, #1202 Boise,lD 83702 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Schlumberger Drilling and Measurements 3940 Arctic Blvd., Ste 300 Anchorage, AK 99503 David Cusato 200 West 34th PMB 411 Anchorage, AK 99503 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Penny Vadla 399 West Riverview Avenue SOldotna, AK 99669-7714 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow, AK 99723 /{/I/æd ~¡þc¡ Notice ,-,' \ '-" Please p~blish on line. """"""g~"9:Y"""""""",, " i Alpine _ C0443 _ AI018B Notice.doc: Content-Type: applie ation/msword l_,,::::::::::::::::::::::::::,,::::::::::::::::::.:::::::::.::":::::::::::::.:":::.::::::::::::::::::::::"::::::::::::::::.::::::::::::::::::::::::::,,:::::::.:::.:::::::::::,,:::...::::~:~,,~~:~~~=~:~~~:~:~~,,~:~:,,:.:,,~:~~.~:~:;:.:,,::::::::::::::::::::::::::::::.:,,:::::::::::::.::.:"::::::::::::::::,,- 1 of 1 7/28/20048:15 AM \Totice , " \ ~ Stl~j··e~t:.·...~()tice E."", ',...."r.,....., C)....',. ,i,.~"..,.,...,:.".......JO..'.....,.....d.",.........r.p. i~l,O. P,..,..b".·,..,~~...<.,'.ð.·()..'··..'..~..'.y,.'. _,.,'..~, O.I..Ö.'.,m....,..·.,'..".h~e..,. @.·"......adm..."'ID.·.....,..,...8,.".t. .ate,··.....',..,.,ak"."..·..,.....'.....,..,.,.....,...,..u...,.,.,'..'...,.,.s"",·.'>....,',..,..'". Date.:,.Wed,28Jul.200408:14:2ó'··,..0800 ". .:. 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" '" , . , , ..~ .................................................................................................................................-...................................-....-........-.............................................-................................................................................................ 1 of 1 7/28/20048:15 AM #1 ") y W'. ConocoPhillips ...,) Chris Alonzo Alpine Engineering Supervisor Post Office Box 100360 700 G Street Anchorage, Alaska 99510 Telephone 907 265-6806 July 22, 2004 l~ J/ }¡,f '.' l ~,/~I~D"" "', ""í. 9 C:. -. ~o{ l? .,' or. ,..004 Mr. John Norman, Chairman Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Re: Expansion of Conservation Order No. 443 and Area Injection Order No.18A Dear Commissioner Norman: By this letter and supporting documents, ConocoPhillips Alaska, Inc. (CPAI) requests expansion of the Alpine Oil Pool described in Conservation Order No. 443 and Area Injection Order 18A to include additional acreage to the North and West of the currently defined Alpine Participating Area (Expansion Area) as shown on Exhibit 1. Attachment A provides information supporting the expansion with respect to Conservation Order #443. Attachment B provides input supporting the expansion with respect to Area I njection Order No. 18A. The Expansion Area will be drilled from CRU Drill Site CD2. A request for authorization to conduct tract operations has been submitted to Alaska Department of Natural Resources (UADNR") and the Arctic Slope Corporation (ASRC) for the drilling of the CD2-03, CD2-04, CD2-09, CD2-11 and CD2-21 Wells (the "Wells"). CPAI anticipates ADNR, ASRC and Colville River Unit owners will agree to the proposed tract operations. Should all or a part of the Expansion Area be confirmed as productive per the CRU Agreement, CPAI would submit an application to ADNR and ASRC to expand the Alpine Participating Area to include such productive Expansion Area acreage. Detailed geophysical, geologic and engineering information describing the Expansion Area is provided in Attachments A and B, which CPAI considers confidential. CPAI requests that Conservation Order No. 443 and Area Injection Order No.18A be amended to include the following areas outlined in orange on Exhibit 1. All of the subject tracts are contained within the current Colville River Unit boundary. This expansion may be specifically described to include the following areas: Township 12N Range 4E - (Umiat Meridian) all of sections 20, 21, 22, 23, 27, 28, 29, 30,31 and 32 Township 12N Range 3E - (Umiat Meridian) all of sections 25 and 36. ') w J Other than the described request to include the Expansion Area acreage, no changes to Conservation Order No. 443 or Area Injection Order No.18A are requested. We appreciate your review of this request and would be happy to address any questions. I can be reached at 265-6822 or chris.alonzo@conocophillips.com via emaH. Sincerely, ~çs- Attachments Page 2/3 11 14 13 APC;CPAI 23 24 19 l, Colville River Unit . ~ O~6-09 25 . 30 APC, C~AI 2 Proposed Alpine f t Pool and Injection Area '\,.~~~!. \( , ~ ~.' : 4 6-7-04 03071001F02 ~ .~' ~ ..-' J J CC: Mr. Mark Meyer, Director Alaska Department of Natural Resources Division of Oil & Gas 550 W. 7th Avenue, Suite 8000 Anchorage, Alaska 99501-3560 Mr. Mike Kotowski Division of Oil and Gas P. O. Box 107034 Anchorage, AK 99510 Ms. Teresa Imm, Resource Development Manager Arctic Slope Regional Corporation 301 Arctic Slope Avenue, Suite 300 Anchorage, Alaska 99518-3035 Mr. Isaac Nukapigak, President Kuukpik Corporation PO Box 187 Nuiqsut, Alaska 99789-0187 Mr. Lanston Chin Kuukpik Corporation 825 W 8th Ave., Suite 206 Anchorage, AK Mr. Bill Esco Anadarko Petroleum Corporation PO Box 1330 Houston, Texas 77251-1330 Mr. John Bridges Anadarko Petroleum Corporation 1201 Lake Robbins Dr. The Woodlands, TX 77380 J .....,} Attachment A Supporting Information for Expansion of Conservation Order No. 443 I. Explanation of Request The information presented in this Attachment A supports the application before the Alaska Oil and Gas Conservation Commission (AOGCC) for expansion of the geographic area specified in Conservation Order No. 443. The scope of this attachment includes a discussion of geological and reservoir properties, CPAI's plans for reservoir development, surveillance, well planning and are considered confidential. CPAI is providing this information on behalf of the Alpine Participating Area Working Interest Owners (Alpine WIOs). This information is provided so that the AOGCC is properly informed to render a decision and issue findings concerning this application. Existing Alpine facilities will be employed to process production and supply injectant to the expanded area. The intent of all parties is that the Alpine Participating Area will be expanded to include the subject acreage and operated in accordance with the Colville River Unit (CRU) Agreement and the CRU Operating Agreement. The expansion area is under lease by the Alpine WIOs from the State of Alaska and Arctic Slope Regional Corporation. CPAI has filed an application with the Commissioner of the Department of Natural Resources and Arctic Slope Regional Corporation to conduct tract operations in the subject areas. The intent of all parties is that the subject areas will be included within the Alpine Participating Area (PA) boundary once proven by production as required under the applicable CRU agreements. It is proposed that Conservation Order No. 443 be expanded to include: Township 12N Range 4E - (Umiat Meridian) all portions of sections 20, 21, 22, 23,27,28,29,30,31 and 32 Township 12N Range 3E - (Umiat Meridian) all portions of sections 25 and 36. ~2 L 11 14 1.3 L APC.CPAI 23 24 19 Colville River Unit ~ 0Eh3fr09 ir 0 ~ 52 M081817 25 30 APC, CPAI 2 Proposed Alpine Pool and Injection Area CONFIDENTIAL 03071 001 F02 Page 6 ) . A~ment A - Expansion of Conservation orde~ 443 II. Geology Introduction In this section, the geologic data supporting the proposed expansion is discussed. Geoloaic Interpretation of the Expansion Area Reservoir penetrations gathered through the course of development drilling has greatly increased our knowledge of the distribution of the sands within the existing Alpine P A and allowed for continual improvement in the correlation between the seismic response and presence of reservoir sands. The result of this is the WID's ability to better project reservoir limits. The latest zero net pay contour is shown in Exhibit 2. Volumetric estimates of original oil in place within the expansion area range from 31 MMSTB to 55 MMSTB. This range will undoubtedly change as new drilling information becomes available. Several tests of vertical pay thickness have been obtained through tagging the top and bottom of the Alpine reservoir while drilling in the existing northern row in the northwest portion of the current PA (CD2-06, CD2-20, CD2-12 and CD2-15). Based on these intersections, we estimate there is nineteen to forty feet of reservoir quality Alpine sand present at the toe of the current northern row of development wells at CD2. Injector CD2-18 encountered approximately 20' of Alpine A sand at it's northern extent. Alpine Well CD2-06 tested the concept that accommodation space for the Alpine sands exists to the north, between the area developed by existing wells and the ultimate truncation of the interval by the regional Lower Cretaceous Unconformity. The current Alpine net pay map outlining the expansion area is shown in Exhibit 3. These results were previously reported in the Colville River Unit Agreement Section 3.9.8 meeting held in December of 2003. III. Reservoir Description This section summarizes the reservoir properties assumed to be present in the expansion area. Formation Description The mapped gross reservoir interval in the expansion area is estimated thickness between 0 to 30 feet Log model net pay is calculated using a 150/0 porosity cutoff on log derived porosity data. Average porosity ranges from 17% AJhment A - Expansion of Conservation orde.J 443 to 21 %. Calculated log model water saturations range from are 10% to 220/0. Permeability ranges from less than 1 0 md to almost 60 md. Given the extensive pressure continuity observed across the developed portions of the Alpine field, we anticipate the expansion area is in pressure communication with the Alpine reservoir within the current Alpine PA boundary. Reservoir Fluid Properties The oil and formation water properties are expected to be the same as those found in the developed portions of the Alpine reservoir. Please refer to the supporting information provided in the application for Conservation Order No. 443 and Area Injection Order No. 18A. IV. Reservoir Development This portion of the application includes a discussion of the recovery process, development and management strategies. Recoverv Process The recovery processes previously described in the application for Conservation Order No. 443 in and updated via subsequent annual surveillance reports will be extended into the proposed development area. Development Approach We anticipate the current horizontal well line drive pattern configuration will be extended into the proposed expansion area Well Spacina Spacing between longitudinal rows will be adjusted as needed for efficient drilling and recovery. Wells will not be drilled closer than 500' as specified by Rule 3 of Conservation Order No. 443. Stimulation Plans There is a possibility that lower quality reservoir rock will be encountered in the proposed expansion area. Propped hydraulic fracture stimulation may be evaluated in these instances. Artificial Lift As has been the practice in Alpine producers drilled to date, gas lift will remain the preferred artificial lift mechanism. ') '-hment A - Expansion of Conservation Orde~ 443 V. Facilities Introduction Other than new well tie in, no substantive changes to surface facilities are anticipated General Overview The proposed area will be developed from CRU Drill Site C02 (C02). With slight modification, the existing facilities will accommodate the additional wells anticipated from this expansion. Pads and Roads C02 is designed to accommodate a total of 60 wells on 1 Q-foot centers. At this time, no additional gravel construction is anticipated due to the proposed expansion. Pipelines Pipeline facilities are sufficient to accommodate the proposed expansion. Power Line Existing power facilities will accommodate the incremental wells drilled as a result of this expansion Drill Site Facilities C02 facilities are designed to require minimal operator presence. Data gathering and most routine operations are to be accomplished remotely from the production facility control room. VI. Drilling & Well Design Introduction The information below details drilling and completion practices for the proposed expansion area. AJhment A - Expansion of Conservation ordeJ 443 Casina & Cementina As has been the case throughout Alpine development, casing and cementing plans for will be consistent with AOGCC Regulation 20 ACC 25.030. All casing and cementing requirements will adhere to Rule 4 of Conservation Order No. 443. Automatic Shut-in Eauipment All automatic shut-in equipment requirements will adhere to Rule 5 of Conservation Order No. 443. VII. Reservoir Surveillance Introduction This section provides a description of proposed reservoir surveillance. Well Testina Well test operations will comply with Rule 9 of Conservation Order No. 443. Reservoir Pressure Measurements Pressure measurement will comply with Rule 6 of Conservation Order No. 443. Reservoir Surveillance Report The proposed expansion area will be integrated into the Rule 8 Alpine reservoir surveillance report. VIII. Summary The Alpine WIOs are committed to a safe and environmentally friendly operation. Alpine operations meet or exceed all requirements specified in the Commission's rules and regulations. Well and facility designs meet or exceed the standards specified in state and national codes, the recommended practices of the relevant advisory organizations, and the time-proven practices of prudent operation. We respectfully request that AOGCC approve expansion of the area covered by Conservation Order No. 443 to enable continued development of the Alpine Reservoir. I ¡ I ! I ~----- ---,------------- ----- '- ----'-------------- i , ! AIPin1 PO?I +--andJl1JectlOl1-------- j Expar sian Ar a i ! 18 23 21 I~ 35 -- ---.- "--1" [ i I ~~. __________ I J1 ---T----------------------- ________h___;,_ ----- , I ¡? -~----------~---- ----- -. -- . - ---- l"N, R4E CO,,-- 17 ~ I ----- --~~ ,29 _ ~=~~,~,~ 'Lmi !_u j , 1-J i oooo~ ¡ \, 1··~><III'BÌ\'8 coiCD1~ ~\. 9 §CD1-IÞ'';'' ", I "CQ1.:Jt. ::.. I I .,,D :CD~ i " ei~CH .. ~ ~~::ne'~+A~:m~:~~ ';' 5', .'TUTE " IFl'E'ST.~ , ,I ,',' ~. - ., '. ,.., .8 I.@ STlH~H: MilES I ~ PlanÆd Injeftor (921 well ~veloPment ~iri) \ ; ! ! ¡ _____.:----\- ___ ¡Planned Producer (92 well!developme~ Program) ~ Drilled Well (~ of 06/27/OL) ~ Potential Per'pheratCandidate 27 Attachment A - Expansion of Conservation Order No. 443 Exhibit 3 II / 12 I "WI"~7 16 1 5 I~ 13 18 17 TEJ.PTA~ ,/ 20 21 ne C02-(J1~ 2-ç '\ .AlPflE¡"\ "\ <¡O>-'''', '25 30 \: "\ , \, ~1" -~:\-.~\-\..~-L-J-L ... .. ¡~7\~~\CD""'\ \ \ . \ , - CON> Î crrno, I ' ¡ \ \, 33 '-~--~t ~ I 13 u_ ------ -r---~I-- I ! [ -"to: ~-:~ _. ~~~(,~ SO!i!:e fEET ¡ ,< ; 8 ------._----- ---- .----.-....--------.-- - ___A __A __ ._~__ --------- 23 7.f, 1 9 --~-~_._--- _n____._._________.___ ----- ~-- --~ --~- L 0 :?s "0 -+------_~_____u_~ i , ! ! 17 22 29 16 iLf~, ; ~, h, HAHIJO:I, .1---1"'--- ¡ i I I I I ¡ I 21 2'; H.I··- ----~ rAHUK..---- Contour IntelVal = 10 ft 27 26 28 25 NAHUQs.. 10 11 IS 1 ~ ~~f\ i \.... 22 23 27 26 34 35 -1:1 112N,IR5E 111N~ R5E '1 rC__~m " I ~ 26 Page 7 "'\ 13 18 21 19 L- 25 3ß 36 31 -----C- " 18 2'; ¡ 9 25 32 J J Attachment B Supporting Information for Expansion of Area Injection Order No. 18A Introduction The information presented in this Attachment B supports the application before the Alaska Oil and Gas Conservation Commission (AOGCC) for expansion of the land area specified in Order No. 18A. Expansion of the effective area is necessary to efficiently recover Alpine Reservoir hydrocarbon resources within the Colville River Unit. 20 AAC 25.402 (c)(1) Plat of Wells PenetratinQ Iniection Zone Exhibit 3 shows all existing wells penetrating the injection zone in the proposed injection area. The map also shows the areal extent of the injection zone relative to the Colville River Unit boundary, and the location of all proposed Alpine Oil Pool development wells. 20 AAC 25.402 (c)(2) Operators and Surface Owners within One Quarter Mile of Iniection Operations Operator: ConocoPhillips Alaska Inc. Attention: Mark Ireland 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 1 J o 20 AAC 25.402 (c )(3) Affidavit of Chris J. Alonzo STATE OF ALASKA THIRD JUDICIAL DISTRICT I, Chris J. Alonzo, declare and affirm as follows: 1. I am the Alpine Engineering Supervisor for ConocoPhillips Alaska, Inc., the designated operator of the Colville River Unit (which includes the Alpine Pool). 2. On July 22,2004, I caused copies of the Application for Expansion of Area Injection Order No. 18A with confidential attachments to be provided to the following surface owners and operators of all land within a quarter-mile radius of the proposed injection area: Operator: ConocoPhillips Alaska, Inc. Attention: Mr. Mark Ireland P.O. Box 100360 Anchorage, AK 99510-0360 Surface Owners: State of Alaska Department of Natural Resources Attention: Mr. Mike Kotowski Anchorage, AK 99510 Kuukpik Corporation Attention: Mr. Isaac Nukapigak P.O. Box 187 Nuiqsut, AK 99789-0187 Dated: 2-) ,2004. 8 .\\\\ \\\ \ì j ì/ lif/IIIA #'\\\'-<... }~!~~~ ~ r..)'-.·o~tf\iSSion &_oo'f<. ~ ~ ':' o· cp'· -~ ". tP ~ ~ ...,¡l~ ~"" ~ :"'-.;; "-00: 0 ~ :::: i NOTARY ~ - ~ 'tL \. PUBLIC/ .~ ~"T" e. ~ . ~ ~ ~<P/>.~<in 4. 2~e.·Ä,~ ~ ~/!:i·öF"·~\'~~ . . ""ij.t:tI\ \\,\\\\~ n · 2004. ~( .... r ¿,...(j. 1'- ;~ ~a' ublic in and for Alaska My commission Expires: ~. '-I ) ;}aD", Declared and affirmed before me this ;;¿ I day of Page 2 J J 20 AAC 25.402 (c)(4) Description of the Proposed Operation The Alpine recovery process and operations have been described in previous applications which were the basis for Conservation Order No. 443 and Area Injection Order No 18A. The information is also updated yearly in the Annual Alpine Surveillance Report required by Rule 8 of CO No. 443. No changes to the process or operations are anticipated from expansion of the subject area. 20 AAC 25.402 (c)(5) Description and Depth of Pool to be Affected Location It is proposed that Area Injection Order 18A be expanded to include: Township 12N Range 4E - (Umiat Meridian) all portions of sections 20, 21, 22, 23,27,28,29,30,31 and 32 Township 12N Range 3E - (Umiat Meridian) all portions of sections 25 and 36. Trap and Structure The Alpine trap and structure was described in previous applications which were the basis for Conservation Order No. 443 and Area I njection Order No 18A. No variation is expected in the proposed expansion area. Exhibit 4 is a top Alpine depth structure map based on 3D seismic data. Structural dip is to the southwest at 1 to 2 degrees. The major faults in the Alpine Oil Pool area are normal north-northwest trending, and down thrown to the west. At the Alpine level, most of the faults have small throws, generally less than 25 feet. 20 AAC 25.402 (c)(6) Description of the Formation The Alpine formation was described in the application that was the basis for Area Injection Order No. 18A. No variation is expected in the proposed expansion area. Page 3 J J 20 AAC 25.402 (c){8) Casina Description and Proposed Method for Testina Casinq Casing designs and methods for testing have been described in previous applications which were the basis for Conservation Order No. 443 and Area Injection Order No 18A. No variance is expected in the proposed expansion area. 20 AAC 25.402 (c){9) Iniected Fluid Analvsis Fluid properties and composition were described in the application that was the basis for Area Injection Order No. 18A. No variation is expected in the proposed expansion area. 20 AAC 25.402.{c){10) Estimated Pressures In practice, injection pressures within the Alpine area presently developed have been lower than estimates contained in the application which was the basis for Area Injection Order No 18A. As the recovery process matures, we anticipate that injection pressures will increase but still be below the highest pressures quoted in the original AIO application. 20 AAC 25.402 (c){11) Fracture Information No later information contradicts analyses provided in the application that was the basis for Area Injection Order No. 18A. The Alpine formation fracture gradient appears to range between 0.56 to 0.6 psi 1ft. No significant variation is expected within the proposed expansion area. 20 AAC 25.402 (c){12) Formation Fluid No later fluid information contradicts analyses provided in the application that was the basis for Area Injection Order No. 18A. Page 4 J J 20 AAC 25.402 (c)(13) Aquifer Exemption No underground sources of drinking water (USDW) have been identified within the Colville River Unit area. Since there are no USDW's at Alpine, an aquifer exemption per 20 AAC 25.440 is not applicable. It is proposed the previously recognized area be expanded to include: Township 12N Range 4E - (Umiat Meridian) all portions of sections 20, 21, 22, 23, 27, 28, 29, 30, 31 and 32 Township 12N Range 3E - (Umiat Meridian) all portions of sections 25 and 36. 20 AAC 25.402 (c)(14) Incremental Hydrocarbon Recovery Later information supports the analyses provided in the application that was the basis for Area Injection Order No. 18A. The Alpine reservoir is responding favorably to the ongoing enhanced oil recovery process. Within pattern limits, recovery is expected to exceed 50% of original oil in place. Summary The Alpine WIOs are committed to a safe and environmentally friendly operation. Alpine operations meet or exceed all requirements specified in· the Commission's rules and regulations. Well and facility designs meet or exceed the standards specified in state and national codes, the recommended practices of the relevant advisory organizations, and the time-proven practices of prudent operation. We respectfully request that AOGCC approve expansion of Area Injection Order No. 18A to enable continued development of the Alpine Reservoir. Page 5 Attachment B - Expansion of Area Injection Order No. 18A Exhibit 3 " ¡ 2 / 15 10 ¡ nr----·-·------------nn--------- _____n_______ ! I ¡ ¡ 1 13 i Alpiner Pool l---andJnjection I Expar sian Ar I 23 ¡ I ¡--------------- ; i ~ f--------------.--..- --.-.--....--......... ¡ 8 I~.....·~:::-· 17 I // Tl!!WTAdt/'- lõ I 17 i8 15 I ~ ! 3 ]5 2 ; 22 22 21 ~~\ ,,--~ C01~. cmif C01~\ ....\..:/ ! 27 C[)1{I1,. i \'. CD24O\.. \\ IdPM;'''''' ~. \ dD2-<". '2.5 30 "\ -\ 'I. ~ 33"" cor.. 34 -n 1N. R4E 56 \- I j .- ¡ I I I ~a;l1T. i ..___n......__._..____ ___I ~\\ " þJ~ine'~::et;::¿ "'JUTE ':l'::'· ." ::u:. .S """'UTE '!l" I ; .. . __n__ ~-.~.-..-t ~ _, L j/¡~ \,: \, \- \. ~ C"...' \. C01.,þ. --...-..--......-.- :J l' .~~ r, twUJJ------~---."\ k\ \ 10 t & .... 16 ~~ \- p- ---_._--~- ------ 10~ ____.______ ___~__h__ u_._ 0' n 22 I 9 22 21 21 _.--------~,--_._------~-~---- ;JW«JK ,...-----~ 26 29 28 ContoI.I' Interval = 10 ft 27 , 26 25 25 3Ø ------------- --------~- ..-JQ~ 1\ 11 FCRO ~ ¡ "\1 1\ ~\\. 23 26 --~--- L 3S ._..fl -n2NJR5E -n1N~ R5E "~ 13 ! 6 H i9 --- L """"""' 25 32 RQRD ""i 36 31 12 ~ ----1··--··---·----~ 1 ~ 26 13 . - I ~ Plannëd Injeftor' (~l well ~veloPment r~M) -I Planned Producer (92 weill development Program) --i Drilled Well (k of 06127/(4) ~ Potential Per 'pheratCandidate 27 21 19 25 32 Page 6 Page 7 SHITUTf IoIILE5 i .2 .'1 .6 .8 1.1i 5T!HuTt:: tILES ~ Exhibit 4 1 .