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Home My WebLink AboutAIO 018 C AREA INJECTION ORDER 18C Colville River Field Colville River Unit Alpine Oil Pool Nanuq-Kuparuk Oil Pool 1. December 10, 2008 CPAI’s request to include KRU formation in the Alpine Pool and to expand the Alpine Pool 2. November 5, 2010 Backup information (AIO 18C.001) corrected on 12/2/2010 3. April 13, 2013 CPAI’s request to allow well CD4-321 to be online in water only injection service with OAxOOA communication (AIO 18C.002) 4. May 8, 2014 – August 16, 2013 Amendment of Alternative MIT schedule for UIC injection Wells and background information 5. March 30, 2015 CPAI’s 2014 Annual Disposal Well Performance Reports for wells WD-02, CD1-19A, and CD1-01A 6. June 1, 2015 CPAI’s request for AA to allow well CD4-17 to be online in water injection service only (AIO 18C.003) 7. August 23, 2015 CPAI’s request for AA to allow well CD1-46 to be online in water injection service only (AIO 18C.004) 8. September 11, 2015 CPAI’s request for AA to allow well CD4-322 to be online in water only injection service (AIO 18C.005) 9. November 19, 2015 CPAI’s request for AA to allow well CD1-14 to be online in WAGIN service with a known tubing by inner annulus communication (AIO 18C.006) 10. January 12, 2016 CPAI’s request for AA to allow well CD4-213B to be online water only injection service with a known tubing by inner annulus communication (AIO 18C.007) 11. March 19, 2016 CPAI’s request for AA to allow well CD4-27 to be online in water only injection service with a known tubing by inner annular communication (AIO 18C.008) 12. March 30, 2016 CPAI’s request to cancel AIO 18C.007 (AIO 18C.007 Cancellation) 13. April 17, 2016 CPAI’s request for AA to allow well CD3-128 to be online in water only injection service with a known tubing by inner annular communication (AIO 18C.009) 14. May 14, 2016 CPAI’s request for AA to allow well CD2-51 to be online in water only injection service with a known tubing by inner annular communication (AIO 18C.010) 15. March 26, 2016 – February 23, 2017 CPAI’s request to align the anniversary dates on AA’s with the current approved UIC testing schedule (AIO 18C.002 Amended through AIO 18C.006 Amended) 16. May 7, 2017 CPAI’s request for AA to allow well CD4-321 to be online in water and gas injection service after a rig workover installed gas-tight tubing in the well (AIO 18C.002 (Amended and Corrected)) 17. May 12, 2017 CPAI’s request for AA to allow well CD2-78 to be online in water only injection service with a known tubing by inner annular communication (AIO 18C.011) 18. June 11, 2017 CPAI’s request for AA to allow well CD2-18 to be online in water only injection service with a known tubing by inner annulus communication (AIO 18C.012) 19. June 13, 2017 CPAI’s request for AA to allow well CD4-26 to online in water only injection service with a known tubing by inner annulus communication (AIO 18C.013) 20. February 17, 2018 CPAI request for amendment to existing AA for well CD4- 17 (AIO 18C.003 Amended) 21. December 24, 2018 CPAI’s request to cancel AIO 18C.011 (AIO 18C.011 Cancellation) 22. February 22, 2019 CPAI’s request to cancel AIO 18C.013 (AIO 18C.013 Cancellation) 23. April 2, 2019 CPAI’s request to cancel AIO 18C.006 (AIO 18C.006 Cancellation) 24. April 24, 2023 CPAI’s request to amend AIO 18C.008 (AIO 18C.008 amended) 25. June 5, 2023 CPAI’s request to cancel AIO 18C.009 (AIO 18C.009 canceled) ORDERS • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue, Suite 100 Anchorage, Alaska 99501 Re: THE APPLICATION OF ConocoPhillips Alaska, Inc. for an amendment of Area Injection Order No. 18B to expand the enhanced oil recovery project in the Alpine Oil Pool, and for termination of Area Injection Order No. 27 for the Nanuq-Kuparuk Oil Pool, Colville River Unit, Arctic Slope, Alaska IT APPEARING THAT: Area Injection Order No. 1$C Docket Number: AIO-08-58 Colville River Field Colville River Unit Alpine Oil Pool Nanuq-Kuparuk Oil Pool March 26, 2009 ConocoPhillips Alaska, Inc. (CPAI), in its capacity as unit operator, by application dated October 10, 2008 and received December 17, 2008 by the Alaska Oil and Gas Conservation Commission (Commission), requests an order expanding the affected acreage and strata covered by Area Injection Order (AIO) No. 18B, which regulates enhanced recovery operations in the Alpine Oil Pool, and terminating AIO No. 27, which regulates enhanced recovery operations in the Nanuq-Kuparuk Oil Pool. CPAI also requests expansion of the affected acreage and strata of the Alpine Oil Pool and termination of the Nanuq-Kuparuk Oil Pool; these requests are addressed in Conservation Order No. 443B. FINDINGS: 1. CPAI is the operator of the Colville River Unit and all non-unitized lands that are affected by this order. 2. CPAI and Anadarko Petroleum Corporation are the owners of the leases affected by this order. 'The State of Alaska and Arctic Slope Regional Corporation are the landowners of the affected lands. 3. Two wells recently completed in the Colville Delta No. 1 Drilling Pad (CD1) area encountered elevated pressures of 4,500 to 4,600 psi in the Kuparuk Formation (Kuparuk), which is stratigraphically above the Alpine sandstone (Alpine); the Alpine is an informal part of the Kingak Formation. Normal pressure for the Kuparuk in this area is about 3,200 psi. 4. The Char No, 1 exploratory welt, which was drilled approximately 7 miles to the northwest of CD1 (see Figure 1, below) during the winter 2007/2008 drilling season, also encountered elevated pressures in the Kuparuk. 5. Subtle pressure changes in the CD4 Drilling Pad area, which lies about 4 miles south-southwest of CD1, have occurred over the past two years; these pressure changes occurred following commencement of production from the Nanuq-Kuparuk Oil Pool. These changes suggest pressure communication between the Alpine and Kuparuk in this portion of the Colville River Unit. 6. Significant lost circulation events occurred while drilling the CD1-06 and CD1-14 wells, which are east of CD1. These events are attributed to subseismic-scale fractures or faults (i.e., fractures or faults that are too small to be visible on seismic lines) associated with a major fault that lies east of these wells. Water and gas injection into the Alpine reservoir open to CD1-06 and CD1-14 apparently pressurized the overlying Kuparuk through these fractures or faults. 7. Well CD2-02, located about 5-1/2 miles west of CD1, encountered sand-on-sand contact between the Kuparuk and the underlying Alpine. This contact is considered the mechanism responsible for the pressure communication between the Kuparuk and Alpine observed in the Char No. 1 exploratory • • well. The Iapetus No. 2 exploratory well, drilled in 2005 about 1-1/4 miles northwest of Char No. 1, encountered normal pressures in the Kuparuk, but these normal pressures were encountered before injection began in the CD2-02 well. ~ ~ ~ ~.,J B ai ort e c ~ -- -- ,_ ~, ~ ~ ~Colv4 le 1~2iv r nit ~~ ~~~~ ~~~ ~~ - ~ ~' ~.~ ~ _ [ap s o. 2 ~ D3~ Pa _ _ _ ~ C No. 1 ~ _~ - i ~ - C 2_p~ 1-~_ CDI-Pads-. CDl- 6 r F~_~ ~~~ ~I~ ~ +_ ~~+~ ~ iEld2-Pad ~~ -~~- I • Ipinq N - ~~-, - ~ - --r- - -- - -- ~ _ ~ I ~ . i Figure 1. Index Map (proposed affected area is highlighted with yellow) Area Injection Order No. 18C Effective March 26, 2009 Page 2 of 8 8. Pressure monitoring in wells open to the stratigraphically shallower Nanuq and Qannik Oil Pools shows no indication of pressure communication with the underlying Kuparuk and Alpine reservoirs. 9. Given the properties and thickness of the rocks underlying and overlying the proposed expanded pool, injected fluids will likely not move out of the expanded pool. 10. The Alpine Oil Pool's affected acreage overlies much, but not all, of the Nanuq-Kuparuk Oil Pool, and therefore, the affected acreage of the Alpine Oil Pool must be expanded to include all of the acreage of the Nanuq-Kuparuk Oil Pool. 11. CPAI plans to drill additional development wells into the proposed expanded Alpine Oil Pool; those wells would be outside the affected acreage of the current Alpine Oil Pool. 12. AIO 18B, which governs the Alpine Oil Pool injection operations, does not include a list of approved injection fluids; Rule 1 of AIO 18B states only that "fluids may be injected for purposes of pressure maintenance and enhanced recovery." 13. AIO 27, which governs the Nanuq-Kuparuk Oil Pool, includes a list of approved injection fluids. Compared to AIO 27, AIO 30 (including administrative approvals), which governs injection operations within the Kuparuk and Kingak Formations in the nearby Fiord Oil Pool, authorizes a greater variety of injection fluids. The Kuparuk in the area affected by this order and the Fiord Oil Pool are similar mineralogically. The injection of fluids authorized by AIO 30 have not damaged the Kuparuk. 14. Rule 11 of AIO 18B allows the Commission to administratively amend the order as long as the change does not promote waste, jeopardize correlative rights, or compromise ultimate recovery, is based on sound engineering and geoscience principles, and will not result in fluid movement outside the authorized injection zone. CONCLUSIONS: 1. Pressure communication between the Alpine and Kuparuk in the CD1, CD2, and CD4 Pad development areas is demonstrated by drilling, production, and pressure measurement results. Fluid communication in these areas is also highly likely. Therefore, under AS 31.05.170(12), these two reservoirs must be considered part of the same pool to ensure proper resource development and should be treated as a single unit for enhanced recovery injection operations. 2. Drilling, production, and pressure measurement results also demonstrate that the productive area of the pool likely extends beyond currently defined boundaries, and therefore expansion of the affected acreage of the Alpine Oil Pool and AIO 18B is appropriate to include likely future development areas and ensure proper resource development. 3. Cancellation of AIO 27 is appropriate as the affected area of this AIO will be expanded to include the strata currently covered by AIO 27. 4. Based on injection operations conducted at the Fiord Oil Poll under AIO 30, the Kuparuk will not be damaged by the injection of any fluids the operator may decide to use for purposes of pressure maintenance in and enhanced recovery from the Alpine Oil Pool. Area Injection Order No. 18C Effective March 26, 2009 Page 3 of 8 • • 5. Amending AIO 18B to incorporate the reservoirs now assigned to the Nanuq-Kuparuk Oil Pool within the Alpine Oil Pool and to expand the affected area of this AIO will promote more effective resource development by allowing the resource to developed as a single accumulation instead of as two separate ones, will not promote waste, jeopardize correlative rights, or compromise ultimate recovery, is based on sound engineering and geoscience principles, and will not result in fluid movement outside the authorized injection zone. NOW, THEREFORE, IT IS ORDERED: This Area Injection Order supersedes AIO 18B, issued October 7, 2004, and AIO 27, issued February 16, 2006. The findings, conclusions, and administrative records for AIO 18B and AIO 27 are adopted by reference and incorporated in this decision, except where inconsistent with this order. The following rules, in addition to any other requirements (including the statewide requirements of 20 AAC 25) that are not superseded by these rules, apply to the Alpine Oil Pool within the following affected area: Umiat Meridian Townshi Ran a Sections T10N R3E 1 T10N R4E 1, 2, 3, 4, 5, 6 T10N RSE 3, 4, 5, 6 T11N R3E 1, 2, 11, 12, 13, 14, 23, 24, 25, 26, 36 T11N R4E All T11N RSE 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 27, 28, 29, 30, 31, 32, 33, 34 T12N R3E 25, 26, 35, 36 T12N R4E 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36 T12N RSE 13, 14, 15, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36 Area Injection Order No. 18C Effective March 26, 2009 Page 4 of 8 • • Rule 1 Authorized Infection Strata for Enhanced Recovery (Revised this Order) Within the affected area, fluids may be injected for purposes of pressure maintenance and enhanced recovery into strata that are common to and correlate with the interval between the measured depths of 6,980 feet and 7,276 feet in the Alpine No. 1 well. Correlation Depth Resis Porosity SP <MD AT90 RFIDB 150 MV 200 OHMM 200. .65 G/C3 26. GR TVOSS> r~POR ""-- API 250 0 PLLS r,a - sn - sna T~`~ DrcP(Dn so use <MD Authorized Injection Strata for Enhanced Recovery Figure 1. Alpine No. 1, Type Log for the Expanded Alpine Oil Pool Area Injection Order No. 18C Effective March 26, 2009 Page 5 of 8 • Rule 2 Authorized Infection Strata for Disposal (Restated from AIO 18B) Within the affected area, Class II fluids may be injected for purposes of disposal into strata that are common 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. CArrBletlon DBpth Res is Poros dy SP( N/A) <M O RT RHOB t50 0 200 OHMM 2000 165 G/C3 26 GR TVDSS> NPOR iAFi _ 0 % 150 USFf 5 <MD Authorized Injection Strata for Disposal Figure 2. Nechelik No. 1, Authorized Injection Strata for Disposal Area Injection Order No. 18C Effective March 26, 2009 Page 6 of 8 • • Rule 3 Fluid Iniection Wells (Restated from AIO 18B) The underground injection of fluids must be through a well permitted for drilling as a service well for injection 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 18B) 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 18B) Tubing-casing annulus pressure variations between consecutive observations need not be reported to the Commission unless well integrity failure is indicated as in Rule 7 below. Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity (Restated from AIO 18B) The mechanical integrity of an injection well must be demonstrated before injection begins, after a workover affecting mechanical integrity, and at least once every 4 years while actively injecting. For slurry injection wells, the tubing/casing annulus must be tested for mechanical integrity every 2 years. The MIT surface pressure must be 1,500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, must show stabilizing pressure and may not change more than 10% during a 30 minute period. Any alternate means of demonstrating mechanical integrity must be approved by the Commission. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Rule 7 Well Integrity Failure and Confinement (Restated from AIO 18B) Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval. The operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the Commission. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation. Rule 8 Plugging and Abandonment of Iniection Wells (Restated from AIO 18B) 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. Rule 9 Surveillance (Restated from AIO 18B) For grind and inject slurry injection wells, a baseline temperature survey from surface to total depth, initial step rate test to pressure equal or exceeding maximum injection pressure and pressure falloff are required 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 performance, surveillance logging, fill depth, survey results, and volumetric analysis of the disposal Area Injection Order No. 18C Effective March 26, 2009 Page 7 of 8 • • 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 18B) 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 (Restated from AIO 18B) 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. ENTERED at Anchorage, Alaska and dated March 26, 2009. Daniel T. SAX"mount, Jr., Chair Alaska Oil and G~s Conservation Commission Gas Conserb~ion Commission Cathy P. oerster, Commissioner Alaska it and Gas Conservation Commission 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 a8er the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default a8er which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs unti15:00 p.m. on the next day that does not fall on a weekend or state holiday. Area Injection Order No. 18C Effective March 26, 2009 Page 8 of 8 Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, March 26, 2009 3:14 PM Subject: Various Conservation Orders and Area Injection Orders Attachments: aio18c.pdf; aio22d-2.pdf; co456a-4.pdf; co435a-4.pdf; co430a-5.pdf; co406b-5.pdf; co432d-4.pdf; co597-4.pdf; co596-4.pdf; co443b.pdf BCC:'Anna Raff ; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'Cande.Brandow ; 'carol Smyth ; 'Cary Carrigan'; caunderwood@marathonoil.com; 'Charles O'Donnell'; 'Chris Gay'; 'Cliff Posey'; 'Cody Rice'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David Brown'; 'David Gorney'; 'David Hall'; David House; 'David L Boelens'; 'David Steingreaber ; 'ddonkel'; Deborah Jones; 'doug_schultze'; 'Eric Lidji '; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gregg Nady'; 'gspfoff; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James Scherr'; 'Janet D. Platt'; 'jejones'; 'Jerry McCutcheon'; 'Jim Arlington'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing ; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; johnny.aiken@north-slope.org; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles ; knelson@petroleumnews.com; 'Krissell Crandall'; 'Kristin Dirks'; 'Laura Silliphant'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=fours@mtaonline.net'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; 'Matt Rader'; Melanie Brown; 'Mike Bill'; 'Mike Jacobs'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkin7200'; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro'; 'Paul Decker'; 'Paul Winslow'; Pierce, Sandra M (DNR); 'Randall Kanady ; 'Randy L. Skillern'; 'rcrotty'; 'rmclean'; 'Rob McWhorter '; rob.g.dragnich@exxonmobil.com; 'Robert Campbell'; 'Robert Province'; 'Roger Belman'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmair~ Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; Thompson, Nan G (DNR); 'Tim Lawlor'; 'Todd Durkee'; Tony Hopfinger; 'trmjrl ;Von Gemmingen, Scott E (DOR); 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier'; 'Aaron Gluzman'; 'Dale Hoffman'; Fridiric Grenier; 'Gary Orr'; 'Joe Longo'; 'Lamont Frazer'; Marc Kuck; 'Mary Aschoff; Maurizio Grandi; P Bates; Richard Garrard; 'Sandra Lemke'; 'Scott Nash'; 'Steve Virant'; Tom Gennings;'Willem Vollenbrock';'William Van Dyke'; Woolf, Wendy C (DNR); Birnbaum, Alan J (LAW); Crisp, John H (DOA); Davies, Stephen F (DOA); Fleckenstein, Robert J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Mahnken, Christine R (DOA); Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Seamount, Dan T (DOA); Smith, Chasity R (DOA); Williamson, Mary J (DOA) Attachments:aio 18c.pdf;aio22d-2.pdf;co456a-4.pdf;co435a-4.pdf;co430a-S.pdf;co406b-S.pdf;co432d-4.pdf;co597- 4.pdf;co596-4.pdf;co443b.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) 3/26/2009 Mary Jones David McCaleb Cindi Walker XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 Mark Wedman Schlumberger Ciri Halliburton Drilling and Measurements Land Department 6900 Arctic Blvd. 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99502 Anchorage, AK 99503 Anchorage, AK 99503 Baker Oil Tools Ivan Gillian Jill Schneider 4730 Business Park Blvd., #44 9649 Musket Bell Cr.#5 US Geological Survey Anchorage, AK 99503 Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow, AK 99723 ~~ f L ~ ~ a ME 0 ALASKA SEAN PARNELL, GOVERNOR ALASKA OIL A" GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMSSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 ADMINISTRATIVE APPROVAL AIO 18C.001 ADMINISTRATIVE APPROVAL AIO 28.003 ADMINISTRATIVE APPROVAL AIO 30.004 ADMINISTRATIVE APPROVAL AIO 35.001 Mr. Jack Walker North Slope Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 RE: Application to Allow Injection of Kuparuk River Unit Produced Water into the Following Oil Pools No. 18C Alpine Oil Pool No. 28 Nanuq Oil Pool No. 30 Fiord Oil Pool No. 35 Qannik Oil Pool Colville River Field Dear Mr. Walker: In accordance with Rule 11 of Area Injection Orders (AIO) 18C, 28, and 30, respectively governing the Alpine Oil Pool, Nanuq Oil Pool, and Fiord Oil Pool, and Rule 10 of AIO 35 governing the Qannik Oil Pool, the Alaska Oil and Gas Conservation Commission (Commission) CONDITIONALLY GRANTS ConocoPhillips Alaska, Inc.'s (CPAI) request for administrative approval to inject produced water from the Kuparuk River Unit (KRU) into the aforementioned oil pools. Due to a fuel gas line failure, the CPAI- operated seawater treatment plant in the KRU is unable to move seawater to the Colville River Field (CRF). In order to prevent the seawater transport pipeline from freezing, CPAI has begun to displace the line with warmer produced water from the KRU. CPAI expects the displacing operation to require approximately 26,000 bbls of produced water obtained from the CPF -2 facility in the KRU. Once the seawater treatment plant is back in operation, CPAI will begin shipping seawater to the CRF again and thus displace the KRU produced water that will be occupying the seawater transport pipeline. Currently, the aforementioned AIOs, as amended, do not authorize injection of produced water from the KRU for enhanced recovery purposes, so the only option currently available to accommodate the AIO 18C.001 AIO 28.003 AIO 30.004 AIO 35.001 November 5, 2010 Page 2 of 3 produced water from the KRU is to inject it into one or both of the Class I disposal wells in the CRF. These two wells don't have a high injection rate capability, so it would take several days to completely purge the seawater pipeline of KRU produced water. As such CPAI has requested authorization to inject the KRU produced water into the aforementioned oil pools for enhanced recovery purposes. CPAI has provided compositional analyses of the produced water from the KRU and CRF as well as compositional analysis of the Beaufort seawater shipped to the CRF. The composition of the KRU produced water is very similar to the CRF produced water, so there should not be any formation compatibility issues with injection of this water. There are some differences between the KRU produced water and the Beaufort seawater that could lead to scale deposition, however the use of scale inhibitors and the small relative volume for the produced water to be injected, 26,000 bbls versus the normal monthly injection volume of 3 mmbbls, should result in negligible amount of scale deposition. The Commission has determined that the proposed action does not require notice and public hearing, will not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. Therefore, in accordance with Rule 11 of AIOs 18C, 28, and 30, and Rule 10 of AIO 35, the Commission administratively amends the orders to authorize the injection of up to 30,000 barrels of KRU produced water for enhanced oil recovery purposes. CPAI must use an appropriate scale inhibitor to minimize the possibility of formation damage due to scale deposition when mixing of KRU produced water and Beaufort seawater from the seawater treatment plant. This administrative approval does not exempt CPAI from obtaining additional permits or approvals required by law from other governmental agencies. t► 11`sr�+ o t ENTERED at Anchorage, Alaska, d d vember 5, 2010. 'L!G 4 aniiT � S � eaffi - o ' — unt, Jr. J N Cathy P. Foerster�'�� •'()NMlg Chair om ' 10 er Comm'ssioner AIO 18C.001 • AIO 28.003 AIO 30.004 AIO 35.001 November 5, 2010 Page 3 of 3 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[tlhe questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Fisher, Samantha J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, November 05, 2010 4:04 PM marathonoil.com• Dale Hoffman; n• Bettis, Patricia K DNR • caunderwood , To: Aaron Gluzma (DNR); @ David Lenig; Gary Orr; Jason Bergerson; Joe Longo; Lara Coates; Marc Kuck; Mary Aschoff; Matt Gill; Maurizio Grandi• Ostrovsk Larry Z (DNR); Richard Garrard; Sandra Lemke; Talib , Y, rY ( ) Syed; Tiffany Stebbins; Wayne Wooster; William Van Dyke; Woolf, Wendy C (DNR); (foms2 @mtaon line. net); (michael.j.nelson @conocophillips.com); (Von. L. Hutchins @conocophillips.com); AKDCWelllntegrityCoordinator; Dennis, Alan R (DNR); alaska @petrocalc.com; Anna Raff; Barbara F Fullmer; bbritch; Becky Bohrer; Bill Penrose; Bill Walker; Bowen Roberts; Brad McKim; Brady, Jerry L; Brandon Gagnon; Brandow, Cande (ASRC Energy Services); Brian Gillespie; Brian Havelock; Bruce Webb; carol smyth; Chris Gay; Cliff Posey; Crandall, Krissell; dapa; Daryl J. Kleppin; Dave Matthews; David Boelens; David House; David Steingreaber; ddonkel @cfl.rr.com; Deborah J. Jones; Delbridge, Rena E (LAA); Dennis Steffy; Elowe, Kristin; eyancy; Francis S. Sommer; Fred Steece; Garland Robinson; Gary Laughlin; Rogers, Gary A (DNR); Gary Schultz; ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; gspfoff; Harry Engel; Jdarlington Qarlington @g mail. com); Jeanne McPherren; jeff.jones @alaskajournal.com; Jones, Jeffery B (DOA); Jerry McCutcheon; Jill Womack; Jim White; Jim Winegarner; news @radiokenai.com; John Garing; Katz, John W (GOV); John S. Haworth; John Spain; John Tower; Jon Goltz; Judy Stanek; Julie Houle; Kari Moriarty; Kaynell Zeman; Keith Wiles; Kim Cunningham; Ostrovsky, Larry Z (DNR); Laura Silliphant; crockett @aoga.org; Mark Dalton; Mark Hanley (mark.hanley @anadarko.com); Mark Kovac; Mark P. Worcester; Marquerite kremer; Michael Dammeyer; Michael Jacobs; Mike Bill; mike @kbbi.org; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; knelson @petroleumnews.com; Nick W. Glover; NSK Problem Well Supv; Patty Alfaro; Decker, Paul L (DNR); Paul Figel; PORHOLA, STAN T; Randall Kanady; Randy L. Skillern; rob.g.dragnich @exxonmobil.com; Robert Brelsford; Robert Campbell; Rudy Brueggeman; Ryan Tunseth; Scott Cranswick; Scott Griffith; Scott, David (LAA); Shannon Donnelly; Sharmaine Copeland; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Sondra Stewman; Steve Lambert; Steve Moothart; Steven R. Rossberg; Suzanne Gibson; tablerk; sheffield @aoga.org; Taylor, Cammy O (DNR); Temple Davidson; Teresa Imm; Terrie Hubble; Thor Cutler; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjrl; Vicki Irwin; Walter Featherly; Will Chinn; Williamson, Mary J (DNR); yjrosen @ak.net; Aubert, Winton G (DOA); Ballantine, Tab A (LAW); Brooks, Phoebe L (DOA); Davies, Stephen F (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Johnson, Elaine M (DOA); Laasch, Linda K (DOA); Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Shartzer, Christine R (DOA) Subject: aiol8 -001, aio 28 -003, aio 30 -004 and aio35 -001 (All within the Kuparuk River Unit) Attachments: aiol8c -001, aio 28 -003, aio30 -004 and aio 35 -001 KRU.pdf Jody J. Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 (907)793 -1221 (phone) (907)276 -7542 (fax) 1 Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton 408 18 Street President 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI K &K Recycling Inc. Land Department Baker Oil ho P.O. Box 58055 P.O. Box 93330 795 E. 94 Ct. Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Jill Schneider US Geological Survey Gordon Severson P.O. Box 69 3201 Westmar Circle Barrow, AK 99723 4200 University Drive Anchorage, AK 99508 -4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Cliff Burglin Refuge Manager 399 West Riverview Avenue 319 Charles Street P.O. Box 2139 Soldotna, AK 99669 -7714 Fairbanks, AK 99701 Soldotna, AK 99669 -2139 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 ,N'R� \\O � <� SEAN PARNELL, GOVERNOR ALA OIL AI%TD GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 CORRECTED ADMINISTRATIVE APPROVAL AIO 18C.001 ADMINISTRATIVE APPROVAL AIO 28.004 ADMINISTRATIVE APPROVAL AIO 30.004 ADMINISTRATIVE APPROVAL AIO 35.002 Mr. Jack Walker North Slope Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 RE: Application to Allow Injection of Kuparuk River Unit Produced Water into the Following Oil Pools No. 18C Alpine Oil Pool No. 28 Nanuq Oil Pool No. 30 Fiord Oil Pool No. 35 Qannik Oil Pool Colville River Field Dear Mr. Walker: The Commission has corrected the Administrative Approval to reflect the correct number in AIO 28 and AIO 35. In accordance with Rule 11 of Area Injection Orders (AIO) 18C, 28, and 30, respectively governing the Alpine Oil Pool, Nanuq Oil Pool, and Fiord Oil Pool, and Rule 10 of AIO 35 governing the Qannik Oil Pool, the Alaska Oil and Gas Conservation Commission (Commission) CONDITIONALLY GRANTS ConocoPhillips Alaska, Inc.'s (CPAI) request for administrative approval to inject produced water from the Kuparuk River Unit (KRU) into the aforementioned oil pools. Due to a fuel gas line failure, the CPAI- operated seawater treatment plant in the KRU is unable to move seawater to the Colville River Field (CRF). In order to prevent the seawater transport pipeline from freezing, CPAI has begun to displace the line with warmer produced water from the KRU. CPAI expects the displacing operation to require approximately 26,000 bbls of produced water obtained from the CPF -2 facility in the KRU. Once the seawater treatment plant is back in operation, CPAI will begin shipping seawater to the CRF again and thus displace the KRU produced water that will be occupying the seawater transport pipeline. Currently, the aforementioned AIOs, as amended, do not authorize injection of produced water from the KRU AIO 18C.001 AIO 28.004 AIO 30.004 AIO 35.002 December 2, 2010 Page 2 of 3 for enhanced recovery purposes, so the only option currently available to accommodate the produced water from the KRU is to inject it into one or both of the Class I disposal wells in the CRF. These two wells don't have a high injection rate capability, so it would take several days to completely purge the seawater pipeline of KRU produced water. As such CPAI has requested authorization to inject the KRU produced water into the aforementioned oil pools for enhanced recovery purposes. CPAI has provided compositional analyses of the produced water from the KRU and CRF as well as compositional analysis of the Beaufort seawater shipped to the CRF. The composition of the KRU produced water is very similar to the CRF produced water, so there should not be any formation compatibility issues with injection of this water. There are some differences between the KRU produced water and the Beaufort seawater that could lead to scale deposition, however the use of scale inhibitors and the small relative volume for the produced water to be injected, 26,000 bbls versus the normal monthly injection volume of 3 mmbbls, should result in negligible amount of scale deposition. The Commission has determined that the proposed action does not require notice and public hearing, will not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. Therefore, in accordance with Rule 11 of AIOs 18C, 28, and 30, and Rule 10 of AIO 35, the Commission administratively amends the orders to authorize the injection of up to 30,000 barrels of KRU produced water for enhanced oil recovery purposes. CPAI must use an appropriate scale inhibitor to minimize the possibility of formation damage due to scale deposition when mixing of KRU produced water and Beaufort seawater from the seawater treatment plant. This administrative approval does not exempt CPAI from obtaining additional permits or approvals required by law from other governmental agencies. ENTERED at Anchorage, Alaska, and dated November 5, 2010. Corrected on December 2, 2010. Daniel T. Seamount, Jr. o orman Commissioner, Chair Corn sioner o� D yr" s y v AI0 18C.001 . AIO 28.004 AIO 30.004 AIO 35.002 December 2, 2010 Page 3 of 3 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. I Colombie, Jody J (DOA) From: Colombie Jody J DOA Sent: Thursday, December 02, 2010 1:22 PM To: (foms2 @mtaonline.net); ( michael .j.nelson @conocophillips.com); Von. L. Hutchins conoco hilli s.com ; 'AKDCWeIIlntegrityCoordinator'; Alan Dennis; alaska @petrocalc.com; Anna Raff; Barbara F Fullmer; bbritch; Becky Bohrer; Bill Penrose; Bill Brad McKim; Brady, L; Brandon Gagnon; Brandow, Cande ASRC Walker Bowen Roberts, B ad c y, Jerry g Energy Services); Brian Gillespie; Brian Havelock; Bruce Webb; carol smyth; caunderwood; Chris Gay; Cliff Posey; Crandall, Krissell; dapa; Daryl J. Kleppin; Dave Matthews; David Boelens; David House; David Steingreaber; 'ddonkel @cfl.rr.com'; Deborah J. Jones; Delbridge, Rena E (LAA); 'Dennis Steffy'; Elowe, Kristin; eyancy; Francis S. Sommer; Fred Steece; Garland Robinson; Gary Laughlin; Gary Rogers; Gary Schultz; ghammons; Gordon Pospisil; Gorney, David L.; 'Greg Duggin'; Gregg Nady; gspfoff; Harry Engel; Jdarlington Qarlington @gmail.com); 'Jeanne McPherren'; Jeff Jones; Jeffery B. Jones Qeff.jones @alaska.gov); Jerry McCutcheon; Jill Womack; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John Katz'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'Jon Goltz'; 'Judy Stanek'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kim Cunningham'; 'Larry Ostrovsky'; 'Laura Silliphant'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley (mark.hanley @anadarko.com)'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; 'Michael Dammeyer'; 'Michael Jacobs'; 'Mike Bill'; 'Mike Mason'; 'Mike) Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'nelson'; 'Nick W. Glover'; 'NSK Problem Well Supv'; 'Patty Alfaro'; 'Paul Decker (paul.decker @alaska.gov)'; 'Paul Figel'; 'PORHOLA, STAN T'; 'Randall Kanady'; 'Randy L. Skillern'; ' rob.g. drag nich @exxon mobil. com'; 'Robert Brelsford'; 'Robert Campbell'; 'Rudy Brueggeman'; 'Ryan Tunseth'; 'Scott Cranswick'; 'Scott Griffith'; Scott, David (LAA); 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'tablerk'; Tamera Sheffield; Taylor, Cammy O (DNR); Temple Davidson; Teresa Imm; Terrie Hubble; Thor Cutler; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjr1; 'Valenzuela, Mariam'; Vicki Irwin; Walter Featherly; Will Chinn; Williamson, Mary J (DNR); Yereth Rosen; 'Aaron Gluzman'; Bettis, Patricia K (DNR); 'Dale Hoffman'; David Lenig; 'Gary Orr'; 'Jason Bergerson'; 'Joe Longo'; 'Lars Coates'; Marc Kuck; 'Mary Aschoff'; 'Matt Gill'; Maurizio Grandi; Ostrovsky, Larry Z (DNR); Richard Garrard; 'Sandra Lemke'; Talib Syed; 'Tiffany Stebbins'; 'Wayne Wooster'; 'William Van Dyke'; Woolf, Wendy C (DNR); Aubert, Winton G (DOA); Ballantine, Tab A (LAW); Brooks, Phoebe; Davies, Stephen F (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Johnson, Elaine M (DOA); Laasch, Linda K (DOA); Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Shartzer, Christine R (DOA) Subject: aio18c -001, aio28 -004, aio30 -004, aio 35- 002.pdf - KRU Attachments: aio18c -001, aio28 -004, aio30 -004, aio 35- 002.pdf Attached is a corrected Administrative Approval correcting the numbers. I apologize. Jody 1 Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton 408 18 Street President 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI K &K Recycling Inc. Land Department Baker Oil ho P.O. Box 58055 P.O. Box 93330 795 E. 94 Ct. Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Jill Schneider Gordon Severson P.O. Box 69 US Geological Survey 3201 Westmar Circle Barrow, AK 99723 4200 University Drive Anchorage, AK 99508 -4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Cliff Burglin Refuge Manager 399 West Riverview Avenue 319 Charles Street P.O. Box 2139 Soldotna, AK 99669 -7714 Fairbanks, AK 99701 Soldotna, AK 99669 -2139 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 . N \�� STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7 Avenue, Suite 100 Anchorage, Alaska 99501 Re: THE APPLICATION OF Area InjJ ection Order No. 18C.002 CONOCOPHILLIPS ALASKA, ) INC. for Administrative Approval ) Colville River Unit allowing well CD4 -321 (PTD ) Colville River Field 2061420) to be online in water only ) Nanuq Oil Pool injection service with outer annulus x ) outer outer annulus pressure ) April 25, 2013 communication. ) By letter dated April 13, 2013, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18C.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS ConocoPhillips Alaska Inc. (CPAI)'s request for administrative approval to continue water only injection in the subject well. CPAI reported to AOGCC on March 18, 2013 that well CD4 -321 showed signs of a surface casing leak to atmosphere via the surface casing by conductor annulus. A surface casing leak detect log (SCLD) was performed on March 17, 2013 indicating a suspected leak at 54 ft. The AOGCC finds that CPAI does not intend to perform repairs at this time. A passing non - witnessed mechanical integrity test of the Inner Annulus (MITIA) on March 17, 2013 indicates that CRU CD4 -321 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 CD4 -321 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a mechanical integrity test of the inner annulus (MITIA) every 2 years to the maximum anticipated injection pressure; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to as low as reasonably possible not to exceed 100 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 AIO 18C.002 • April 25, 2013 Page 2 of 2 7. The MIT anniversary date will be set as the date of the AOGCC witnessed MITIA that is to be completed once the well is returned to injection and stabilization is achieved. The Commission must be provided the opportunity to witness the MIT for the test that will establish the new MIT Anniversary date. DONE at Anchorage, Alaska and dated April 25, 2013. (? )rt, • o a r o thy P,, g9 Daniel T. eamount, Jr. hair, Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the AOGCC by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. C OIL AAr 4 /ION COF4 Singh, Angela K (DOA) From: Colombie, Jody J (DOA) Sent: Friday, April 26, 2013 9:53 AM To: Singh, Angela K (DOA); Ballantine, Tab A (LAW); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Ferguson, Victoria L (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Bender, Makana K (DOA); Mdver, Bren (DOA); McMains, Stephen E (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Wallace, Chris D (DOA); ( michael j .nelson @conocophillips.com); AKDCWelllntegrityCoordinator; alaska @petrocalc.com; Alexander Bridge; Andrew VanderJack; Anna Raft Barbara F Fullmer; bbritch; bbohrer @ap.org; Bill Penrose; Bill Walker, Bowen Roberts; Brian Havelock; Burdick, John D (DNR); caunderwood @marathonoil.com; Cliff Posey; Crandall, Krissell; D Lawrence; Daryl J. Kleppin; Dave Harbour, Dave Matthews; David Boelens; David Duffy; 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; Gary Laughlin; schultz, gary (DNR sponsored); ghammons; Gordon Pospisil; Gorney, David L; Greg Duggin; Gregg Nady; Gregory Geddes; gspfoff; Jdarlington (jarlington @gmail.com); Jeanne McPherren; Jones, Jeffery B (DOA); Jerry McCutcheon; Jim White; Jim Winegarner Joe Lastufka; news @radiokenai.com; Easton, John R (DNR); John Garing; Jon Goltz; Jones, Jeffrey L (GOV); Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Kaynell Zeman; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Louisiana Cutler; Luke Keller Marc Kovak; Mark Dalton; Mark Hanley (mark.hanley @anadarko.com); Mark P. Worcester; Kremer, Marguerite C (DNR); Michael Jacobs; Mike Bill; mike @kbbi.org; Mike Morgan; 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 Vanish; Robert Brelsford; Robert Campbell; Ryan Tunseth; Sandra Haggard; Sara Leverette; Scott Cranswick; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Moothart, Steve R (DNR); Steven R. Rossberg; Suzanne Gibson; sheffield @aoga.org; Tania Ramos; Ted Kramer; Davidson, Temple (DNR); Teresa Imm; Thor Cutler; Tim Mayers; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjrl; Vicki Irwin; Walter Featherly; Williams, Theresa; yjrosen @ak.net; Aaron Gluzman; Aaron Sorrell; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Dale Hoffman; David Lenig; David Martin; Donna Vukich; Eric Lidji; Erik Opstad; Franger, James M (DNR); Gary Orr Smith, Graham 0 (PCO); Greg Mattson; Heusser, Heather A (DNR); Holly Pearen; James Rodgers; Jason Bergerson; Jennifer Starck; jil l.a.mcleod @conocophillips.com; Jim Magill; Joe Longo; King, Kathleen J (DNR); Laney Vazquez; Lara Coates; Lois Epstein; Marc Kuck; Steele, Marie C (DNR); Matt Gill; Ostrovsky, Larry (DNR sponsored); Bettis, Patricia K (DOA); Perrin, Don.) (DNR); Peter Contreras; Pexton, Scott R (DNR); Pollard, Susan R (LAW); Poliet, Jolie; Richard Garrard; Ryan Daniel; Sandra Lemke; Talib Syed; Wayne Wooster Woolf, Wendy C (DNR); William Hutto; William Van Dyke Subject: AIO No. 2B.077(KRU) and AIO No. 18C.002 (CRU) Attachments: AIO No. 2B.077.pdf; AIO No. 18C.002.pdf 1 Easy Peet® Labels ♦ Bend along line to I CA AVERY® 5960r4 Use Avery® Template 5160® ed Paper 11 "'"'" expose Pop -up EdgeTM 1 1 Brent Rogers Problem Wells Alaska, uperviso ConocoPhillips A Inc. Post Office Box 100360 Anchorage, AK 99510 -0360 ).(/ n n _ `e% Etiquettes faciles a peter ; Repliez a la hachure afin de ; www.avery.cOm .. _ -_ �- --�_. _� ,..,r.,..tr� r,egoo i Sens de _rac 1- Ann -cm -AVERY L. 1 -_ _ ._ -_ 1 !.® EC Thy 1 Easy Evecr® m pEa 1 Bend along Eiite to i ''�' _, ;0 1 (Isel Avery® - :e:npiate 516:0 1 .d Paper ' -- -- expol Pop-up i =dge -114 ) --' 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 NRG Associates Halliburton Hodgden Oil Company President 40818` St. President 1655 6900 Arctic Blvd. P.O. Golden, CO 80401 -2433 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI ' Baker Oil Tools K &K Recycling Inc. Land Department 795 E. 94 Ct. Post Office Box 58055 Post Office Box 93330 Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Richard Wagner Gordon Severson Planning Department Post Office Box 60868 3201 Westmar Cir. Post Office Box 69 Fairbanks, AK 99706 Anchorage, AK 99508 -4336 Barrow, AK 99723 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 9._.c 2—° 5N I E+G.snattae fariipc 'a Haler ! _ Repliez a la hachure afro de 1 www.avery.com 1 THE STATE °fALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.002 AMENDED Ms. Rachel Kautz Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Docket Number: AIO-17-014 Request for administrative approval to allow well CD4-321 (PTD 2061420) to be online in water alternating gas injection service with a known outer annulus x outer outer annulus communication. Colville River Unit (CRU) CD4-321 (PTD 2061420) Colville River Field Nanuq Oil Pool Dear Ms. Kautz: By letter dated May 7, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to amend Area Injection Order (AIO) 18C.002 and restart water alternating gas (WAG) injection in the subject well. In accordance with Rule 11 of AIO 18C.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for the AIO administrative approval to amend AIO 18C.002 and to restart WAG injection in the subject well. CPAI reported to AOGCC on March 18, 2013 as showing signs of a surface casing leak to atmosphere via the surface casing by conductor annulus. A surface casing leak detect log (SCLD) was performed on March 17, 2013 indicating a suspected leak at 54 ft. CPAI performed a workover excavation under Sundry 317-010 in March 2017 attempting to repair the OA communication at approximately 58 ft below the OA valve. After repairing the suspected leak, testing determined that a deeper leak below the excavated portion was also present. CPAI then pursued a different workover strategy to replace the existing production tubing with gas tight tubing. This was successfully completed in April 2017 under Sundry 317- 111. CPAI performed diagnostics including a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on April 22, 2017 which indicates that CD4-321 exhibits at least two competent barriers to the release of well pressure. Accordingly, the AOGCC believes AIO 18C.002 Amended May 17, 2017 Page 2 of 2 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 WAG injection in CRU CD4-321 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 100 psi; 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The next required MIT is to be before or during the month of June 2017. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated May 17, 2017. �/14 /11, �� 7�— tkl�� - Cathy k. Foerster Ho is French Chair, Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. THE STATE oALASKA GOVERNOR BILL N'VALKER Ms. Rachel Kautz Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.002 AMENDED Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-17-014 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov Request for administrative approval to allow well CD4-321 (PTD 2061420) to be online in water alternating gas injection service with a known outer annulus x outer outer annulus communication. Colville River Unit (CRU) CD4-321 (PTD 2061420) Colville River Field Nanuq Oil Pool Dear Ms. Kautz: By letter dated May 7, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to amend Area Injection Order (AIO) 18C.002 and restart water alternating gas (WAG) injection in the subject well. In accordance with Rule 11 of AIO 18C.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for the AIO administrative approval to amend AIO 18C.002 and to restart WAG injection in the subject well. CPAI reported to AOGCC on March 18, 2013 as showing signs of a surface casing leak to atmosphere via the surface casing by conductor annulus. A surface casing leak detect log (SOLD) was performed on March 17, 2013 indicating a suspected leak at 54 ft. CPAI performed a workover excavation under Sundry 317-010 in March 2017 attempting to repair the OA communication at approximately 58 ft below the OA valve. After repairing the suspected leak, testing determined that a deeper leak below the excavated portion was also present. CPAI then pursued a different workover strategy to replace the existing production tubing with gas tight tubing. This was successfully completed in April 2017 under Sundry 317-111. CPAI performed diagnostics including a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on April 22, 2017 which indicates that CD4-321 exhibits at least two competent barriers AIO 18C.002 Amended May 17, 2017 Page 2 of 2 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 WAG injection in CRU CD4-321 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 100 psi; 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The next required MIT is to be before or during the month of June 2017. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated May 17, 2017. //signature on file// Cathy P. Foerster Chair, Commissioner //signature on file// Hollis French 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. Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711-0055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639-0309 Fairbanks, AK 99706-0868 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, May 17, 2017 2:58 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; ddonkel@cfl.rr.com; DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Elwood Brehmer; Evan Osborne; Evans, John R (LDZX); George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff, Hunter Cox; Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jason Brune; 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; Mike Morgan; 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; 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; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Catie Quinn; Corey Munk; David Tetta; Don Shaw; Eppie Hogan; Eric Lidji; Garrett Haag; Smith, Graham 0 (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); 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; Melonnie Amundson; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Rachel Davis; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW); Wayne Wooster; William Van Dyke Subject: Other Order 120 and AI018C.002 Amended Attachments: aio18C.002 amended.pdf, other120.pdf Please see attached. Re: Docket Number: AIO-17-014 Request for administrative approval to allow well CD4-321 (PTD 2061420) to be online in water alternating gas injection service with a known outer annulus x outer outer annulus communication. Colville River Unit (CRU) CD4-321 (PTD 2061420) Colville River Field Nanuq Oil Pool Re: Failure to Test Safety Valve Systems Safety Valve System Test Performance Kuparuk River Unit 2B-pad Jody J. CoCombie AOGCC SpeciaC,assistant A(aska OiCandGas Conservation Commission 333 West 71" .avenue .anchorage, ACaska 99501 Office: (907) 793-1221 Fax. (907) 276-7542 Other Order 120 Docket Number: OTH-11-030 May 17, 2017 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iodv.colombie@alaska.aov. THE STATE 'ALASKA GOVERNOR BILL WALKER Ms. Rachel Kautz Alaska Oil and Gas Conservation Commission CORRECTED ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.002 AMENDED Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-17-014 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.claska.gov Request for administrative approval to allow well CD4-321 (PTD 2061420) to be online in water alternating gas injection service with a known outer annulus x outer outer annulus communication. Colville River Unit (CRU) CD4-321 (PTD 2061420) Colville River Field Nanuq Oil Pool Dear Ms. Kautz: By letter dated May 7, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to amend Area Injection Order (AIO) 18C.002 and restart water alternating gas (WAG) injection in the subject well. In accordance with Rule 11 of AIO 18C.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for the AIO administrative approval to amend AIO 18C.002 and to restart WAG injection in the subject well. CPAI reported to AOGCC on March 18, 2013 as showing signs of a surface casing leak to atmosphere via the surface casing by conductor annulus. A surface casing leak detect log (SCLD) was performed on March 17, 2013 indicating a suspected leak at 54 ft. CPAI subsequently determined the leak was shallow and performed a workover excavation under Sundry 317-010 in March 2017 attempting to repair the OA communication at approximately 58 inches below the OA valve. After repairing the suspected leak, testing determined that a deeper leak below the excavated portion was also present. CPAI then pursued a different workover strategy to replace the existing production tubing with gas tight tubing. This was successfully completed in April 2017 under Sundry 317-111. CPAI performed diagnostics including a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on April 22, 2017 which indicates that CD4-321 exhibits at least two competent barriers to the release of well AIO 18C.002 Amended May 18, 2017 Page 2 of 2 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 WAG injection in CRU CD4-321 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 100 psi; 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The next required MIT is to be before or during the month of June 2017. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated May 18, 2017. Cathy . F erster Hollis French Chair, Commissioner Commissioner RECONSIDERATION AND APPEAL As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. 'ALASKA GOVI RNt)R BILL N%%TALKER Ms. Rachel Kautz Alaska Oil and Gas Conservation Commission CORRECTED ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.002 AMENDED Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-17-014 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov Request for administrative approval to allow well CD4-321 (PTD 2061420) to be online in water alternating gas injection service with a known outer annulus x outer outer annulus communication. Colville River Unit (CRU) CD4-321 (PTD 2061420) Colville River Field Nanuq Oil Pool Dear Ms. Kautz: By letter dated May 7, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to amend Area Injection Order (AIO) 18C.002 and restart water alternating gas (WAG) injection in the subject well. In accordance with Rule 11 of AIO 18C.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for the AIO administrative approval to amend AIO 18C.002 and to restart WAG injection in the subject well. CPAI reported to AOGCC on March 18, 2013 as showing signs of a surface casing leak to atmosphere via the surface casing by conductor annulus. A surface casing leak detect log (SCLD) was performed on March 17, 2013 indicating a suspected leak at 54 ft. CPAI subsequently determined the leak was shallow and performed a workover excavation under Sundry 317-010 in March 2017 attempting to repair the OA communication at approximately 58 inches below the OA valve. After repairing the suspected leak, testing determined that a deeper leak below the excavated portion was also present. CPAI then pursued a different workover strategy to replace the existing production tubing with gas tight tubing. This was successfully completed in April 2017 under Sundry 317-111. CPAI performed diagnostics including a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on April 22, 2017 which indicates that CD4-321 exhibits at least two competent barriers to the release of well AIO 18C.002 Amended May 18, 2017 Page 2 of 2 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 WAG injection in CRU CD4-321 is conditioned upon the following: l . 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 100 psi; 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The next required MIT is to be before or during the month of June 2017. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated May 18, 2017. //signature on file// Cathy P. Foerster Chair, Commissioner //signature on file// Hollis French 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 nun is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711-0055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639-0309 Fairbanks, AK 99706-0868 Colombie. Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, May 18, 2017 11:08 AM 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; ddonkel@cfl.rr.com; DNROG Units (DNR sponsored); Donna Ambruz, Ed Jones; Elizabeth Harball; Elowe, Kristin; Elwood Brehmer; Evan Osborne; Evans, John R (LDZX); George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff, Hunter Cox; Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jason Brune; 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; Mike Morgan; 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; 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; Andy Bond; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Catie Quinn; Corey Munk; David Tetta; Don Shaw; Eppie Hogan; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Keith Lopez; Laney Vazquez•, Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Melonnie Amundson; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Rachel Davis; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW); Wayne Wooster; William Van Dyke Subject: Administrative Approval Corrected AIO 18C.002 Amended Attachments: corrected aiol8C.002 amended.pdf Please see attached: Re: Docket Number: AIO-17-014 Request for administrative approval to allow well CD4-321 (PTD 2061420) to be online in water alternating gas injection service with a known outer annulus x outer outer annulus communication. Colville River Unit (CRU) CD4-321 (PTD 2061420) Colville River Field Nanuq Oil Pool Jody J. Colombie .AOGCC Special Assistant .Alaska Oil and Gas Conservation Commission 333'Nest 711 .Avenue .Anchorage, .Alaska 99501 Office: (907) 793-1221 Fax: (907) 276-7542 CONFIDENTIALITY NOTICE. This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iody.colombie@alaska.gov. THE STATE OfALAS_KA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.003 Mr. Dusty Freeborn Problem Wells Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.claska.gov Re: Docket Number: AIO-15-023 Request for administrative approval to allow well CD4-17 (PTD 2061180) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) CD4-17 (PTD 2061180) Colville River Field Alpine Oil Pool Dear Mr. Freeborn: By letter dated June 1, 2015, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18C.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 May 3, 2015 while the well was on miscible gas injection. CPAI performed diagnostics and WAG'ed the well to water after receiving permission from AOGCC. CPAI completed a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on May 6, 2015 which indicates that CD4-17 exhibits at least two competent barriers to the release of well pressure. The well does not exhibit signs of pressure communication while on water injection. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 18C.003 June 4, 2015 Page 2 of 2 AOGCC's approval to continue water injection only in CRU CD4-17 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi; 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The MIT anniversary date is May 6, 2015. DONE at Anchorage, Alaska and dated June 4, 2015. i Cathy P. toerster Daniel T. Seamount, Jr. Chair, Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. "That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Singh, Angela K (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, June 04, 2015 2:06 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); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Hunt, Jennifer L (DOA); Jackson, Jasper C (DOA); Kair, Michael N (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Paladijczuk, Tracie L (DOA); Pasqual, Maria (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); AKDCWellIntegrityCoordinator, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack, Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Bob Shavelson; Brian Havelock, Bruce Webb; Burdick, John D (DNR); Carrie Wong; Cliff Posey; Colleen Miller, Crandall, Krissell; D Lawrence; Dave Harbour; David Boelens; David Duffy, David House; David McCaleb; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; ghammons; Gordon Pospisil; Greg Duggin; Gregg Nady; gspfoff, Hulme, Rebecca E (DNR); Jacki Rose; Jdarlington Qarlington@gmail.com); Jeanne McPherren; Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW); Jim Watt; Jim White; Joe Lastufka; news@radiokenai.com; John Adams; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek, Houle, Julie (DNR); Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker, Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly, Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Sternicki, Oliver R; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Terry Templeman; Thor Cutler, Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw, Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr, Smith, Graham O (PCO); Greg Mattson; Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Hyun, James J (DNR); Jason Bergerson; jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck, Josh Kindred; Kenneth Luckey, King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck, Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, William Hutto; William Van Dyke Subject: AIO 14A.004 and AIO 18C.003 Attachments: aiol8c-003.pdf, aiol4a-004.pdf Aio 14A-004 (BP) PBU NK-10 Administrative Approval Aio 18C-003 (CPA) CD4-17 Administrative Approval James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Mr. Dusty Freeborn Richard Wagner Darwin Waldsmith Problem Wells Supervisor P.O. Box 60868 P.O. Box 39309 ConocoPhillips Alaska, Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 100360 Anchorage, AK 99510-0360 Angela K. Singh • THE STATE o ALASKA GOVERNOR BILL WALKER 0 Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.004 Mr. Jan Byrne Problem Wells Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.olaska.gov Re: Docket Number: AIO-15-039 Request for administrative approval to allow well CD1-46 (PTD 2040240) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) CD 1-46 (PTD 2040240) Colville River Field Alpine Oil Pool Dear Mr. Byrne: By letter dated August 23, 2015, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18C.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 February 19, 2015 while the well was on miscible gas injection. CPAI performed diagnostics and WAG'ed the well to water after receiving permission from AOGCC. CPAI completed a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on February 20, 2015 which indicates that CD 1-46 exhibits at least two competent barriers to the release of well pressure. The well does not exhibit signs of pressure communication while on water injection. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 18C.004 • August 28, 2015 Page 2 of 2 AOGCC's approval to continue water injection only in CRU CD 1-46 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi; 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The MIT anniversary date is February 20, 2015. DONE at Anchorage, Alaska and dated August 28, 2015. *4.,, ? Cathy V. Foerster Chair, Commissioner Daniel T. Seamount, Jr. Commissioner TION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Ralrer, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, August 28, 2015 11:36 AM To: Ballantine, Tab A (LAW) (tab.ballantine@alaska.gov); Bender, Makana K (DOA) (makana.bender@alaska.gov); Bettis, Patricia K (DOA) (patricia.bettis@alaska.gov); Brooks, Phoebe L (DOA) (phoebe.brooks@alaska.gov); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA) Oody.colombie@alaska.gov); Crisp, John H (DOA) Qohn.crisp@alaska.gov); Davies, Stephen F (DOA) (steve.davies@alaska.gov); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA) (cathy.foerster@alaska.gov); Frystacky, Michal (michal.frystacky@alaska.gov); Grimaldi, Louis R (DOA) (lou.grimaldi@alaska.gov); Guhl, Meredith (DOA sponsored) (meredith.guhl@alaska.gov); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jackson, Jasper C (DOA); Jones, Jeffery B (DOA) (Jeff Jones@alaska.gov); Kair, Michael N (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored) Ooseph.mumm@alaska.gov); Noble, Robert C (DOA) (bob.noble@alaska.gov); Paladijczuk, Tracie L (DOA) (tracie.palad ijczuk@alaska.gov); Pasqual, Maria (DOA) (maria.pasqual@alaska.gov); Regg, James B (DOA) Oim.regg@alaska.gov); Roby, David S (DOA) (dave.roby@alaska.gov); Scheve, Charles M (DOA) (chuck.scheve@alaska.gov); Schwartz, Guy L (DOA) (guy.schwartz@alaska.gov); Seamount, Dan T (DOA) (dan.seamount@alaska.gov); Singh, Angela K (DOA) (angela.singh@alaska.gov); Wallace, Chris D (DOA) (chris.wallace@alaska.gov); AKDCWellIntegrityCoordinator; Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew Vanderlack; Anna Raff; Barbara F Fullmer; bbritch; Becca Hulme; Becky Bohrer; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Carrie Wong; Cliff Posey; Colleen Miller; Crandall, Krissell; D Lawrence; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; ghammons; Gordon Pospisil; Greg Duggin; Gregg Nady; gspfoff; Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren; Jennifer Williams; Jerry Hodgden; Jerry McCutcheon; Jessica Solnick; Jim Watt; Jim White; Joe Lastufka; Joe Nicks; John Adams; John Easton; Jon Goltz; Juanita Lovett; Judy Stanek; Julie Houle; Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Laura Silliphant (laura.gregersen@alaska.gov); Leslie Smith; Lisa Parker; Louisiana Cutler; Luke Keller; Marc Kovak; Mark Dalton; Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Marquerite kremer (meg.kremer@alaska.gov); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; Mike Mason; Mikel Schultz; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); nelson; Nichole Saunders; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Paul Decker (paul.decker@alaska.gov); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Sternicki, Oliver R; Steve Moothart (steve.moothart@alaska.gov); Suzanne Gibson; Tamera Sheffield; Tania Ramos; Ted Kramer, Temple Davidson; Terence Dalton; Teresa Imm; Terry Templeman; Thor Cutler; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater; Anne Hillman; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw; Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr, Graham Smith; Greg Mattson; Hak Dickenson; Heusser, Heather A (DNR); Holly Pearen; James Hyun; Jason Bergerson; To: Jill*eod; Jim Magill; Joe Longo; John Martin*osh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Marie Steele; Matt Armstrong; Matt Gill; Mike Franger; Morgan, Kirk A (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Sarah Baker; Shaun Peterson; Susan Pollard; Talib Syed; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster; William Hutto; William Van Dyke Subject: aiol8c-004 (CPA) Attachments: aiol8c-004.pdf 0 James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Mr. Jan Byrne Richard Wagner Darwin Waldsmith Problem Wells Supervisor P.O. Box 60868 P.O. Box 39309 ConocoPhillips Alaska, Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 100360 Anchorage, AK 99510-0360 Angela K. Singh THE STATES °'ALASKA GOVERNOR BILL WALKER • Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.005 Mr. Jan Byrne Problem Wells Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-15-043 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Request for administrative approval to allow well CD4-322 (PTD 2071010) to be online in water only injection service with a known outer annulus x atmosphere pressure communication. Colville River Unit (CRU) CD4-322 (PTD 2071010) Colville River Field Alpine Oil Pool Dear Mr. Byrne: By letter dated September 11, 2015, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18C.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for administrative approval to continue water only injection in the subject well. CPAI reported a potential outer annulus (OA) x atmosphere pressure communication to AOGCC on June 25, 2015. A surface casing leak detect log (SCLD) was performed indicating a suspected leak at 12 feet below the OA valve. CPAI completed a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on June 12, 2015 which indicates that CD4-322 exhibits at least two competent barriers to the release of well pressure. Accordingly, the AOGCC believes that the wells condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 18C.005 • September 17, 2015 Page 2 of 2 AOGCC's approval to continue water injection only in CRU CD4-322 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a mechanical integrity test of the inner annulus (MITIA) every 2 years to the maximum anticipated injection pressure; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to as low as reasonably possible not to exceed 100 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, 2015.�.-.� DONE at Anchorage, Alaska and dated September 17, 2015. aloqo�41 z:: 7-, � — Cathy . Foerster Daniel T. Seamount, Jr. Chair, Commissioner Commissioner RECONSIDERATION AND APPEAL As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Singh, Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Wednesday, September 16, 2015 3:40 PM To: AKDCWellIntegrityCoordinator; Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew Vandedack; Anna Raff; Barbara F Fullmer, bbritch; Becca Hume; bbohrer@ap.org; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Carrie Wong; Cliff Posey; Colleen Miller; Crandall, Krissell; D Lawrence; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; ghammons; Gordon Pospisil; Greg Duggin; Gregg Nady; gspfoff, Jacki Rose; Jdarlington Oarlington@gmaii.com); Jeanne McPherren; Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW); Jim Watt; Jim White; Joe Lastufka; Joe Nicks; John Adams; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker, Louisiana Cutler; Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; M1 Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover; Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Terry Templeman; Thor Cutler; Tim Mayers; Todd Durkee; Tony Hopfinger; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Walter Featherly; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Caroline Bajsarowicz; Casey Sullivan; Diane Richmond; Don Shaw; Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr; Smith, Graham O (PCO); Greg Mattson; Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Hyun, James J (DNR); Jason Bergerson; jilt.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, lames M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Bettis, Patricia K (DOA); Pete Dickinson; Peter Contreras; Richard Garrard; Robert Province; Ryan Daniel; Sandra Lemke; Sarah Baker; Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster; William Hutto; William Van Dyke; Ballantine, Tab A (LAW); Bender, Makana K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha 1 (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA) Subject: A018C.005 (Colville River Unit) • Attachments: aiol8c-005.pdf Please see attached. Samantha Carlisle Executive Secretary II Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 (phone) (907) 276-7542 (fax) 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 Samantha Carlisle at (907) 793-1223 or Samantha.Carlisle@alaska.gov. 0 0 James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Mr. Jan Byrne Richard Wagner Darwin Waldsmith Problem Wells Supervisor P.O. Box 60868 P.O. Box 39309 ConocoPhillips Alaska, Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 100360 Anchorage, AK 99510-0360 r z,. ,n L Ser.��sr k-c t 2at5 Angela K. Singh THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.006 CANCELLATION Ms. Sara Carlisle Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-19-013 Request to cancel Area Injection Order (AIO) 18C.006 Colville River Unit (CRU) CD1-14 (PTD 20103 80) Colville River Field Alpine Oil Pool Dear Ms. Carlisle: By letter dated April 2, 2019, ConocoPhillips Alaska, Inc. (CPAI) requested cancellation of administrative annroval (AA) Area Iniection Order 18C.006. In accordance with Rule 11 of Area Injection Order (AIO) 18D.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request to cancel the AA. CD1-14 developed a tubing x inner annulus pressure communication in August 2015 and on November 30, 2015 the AOGCC issued AIO 18C.006. AOGCC determined that dry gas injection could safely continue if CPAI complied with the restrictive conditions set out in AA AID 18C.006. CPAI has repaired the well in March 2019 with new gas tight tubing and a production packer installed under Sundry 318-553. A passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on March 27, 2019 indicates that CD1-14 exhibits at least two competent barriers to the release of well pressure. AA AIO 18C.006 is no longer necessary to the operation of CD1-14 and is hereby CANCELLED. A10 18C.006 Cancellation April 5, 2019 Page 2 of 2 DONE at Anchorage, Alaska and dated April 5, 2019. -i Uwl-j Daniel T. Seamount, Jr. J ssie L. Chmielowski Commissioner Commissioner As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration we 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 tiled 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 ran is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. TI I F STATE °'ALASKA Alaska Oil and Gas Conservation Commission GOVERNORMICILUL I. DUNLLAXY 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.aloska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.006 CANCELLATION Ms. Sara Carlisle Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-19-013 Request to cancel Area Injection Order (AIO) 18C.006 Colville River Unit (CRU) CD1-14 (PTD 2010380) Colville River Field Alpine Oil Pool Dear Ms. Carlisle: By letter dated April 2, 2019, ConocoPhillips Alaska, Inc. (CPAI) requested cancellation of administrative approval (AA) Area Injection Order 18C.006. In accordance with Rule 11 of Area Injection Order (AIO) 18D.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request to cancel the AA. CD1-14 developed a tubing x inner annulus pressure communication in August 2015 and on November 30, 2015 the AOGCC issued AIO 18C.006. AOGCC determined that dry gas injection could safely continue if CPAI complied with the restrictive conditions set out in AA AIO 18C.006. CPAI has repaired the well in March 2019 with new gas tight tubing and a production packer installed under Sundry 318-553. A passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on March 27, 2019 indicates that CD1-14 exhibits at least two competent barriers to the release of well pressure. AA AIO 18C.006 is no longer necessary to the operation of CDI-14 and is hereby CANCELLED. AIO 18C.006 Cancellation April 5, 2019 Page 2 of 2 DONE at Anchorage, Alaska and dated April 5, 2019. //signature on file// Daniel T. Seamount, Jr. Commissioner //signature on file// Jessie L. Chmielowski Commissioner AND 0L 71ON c0 ' As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 THE STATE 0'ALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.006 Mr. Jan Byrne Problem Wells Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-15-051 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.gov Request for administrative approval to allow well CD1-14 (PTD 2010380) to be online in water alternating gas injection (WAGIN) service with a known tubing by inner annulus communication. Colville River Unit (CRU) CD1-14 (PTD 2010380) Colville River Field Alpine Oil Pool Dear Mr. Byrne: By letter dated November 19, 2015, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue dry gas injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18C.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for administrative approval to continue dry gas injection in the subject well. CD1-14 is a critical well for Alpine operations. As an Alpine Blackstart well, gas is injected into the well and later produced to provide fuel gas for the continued operation of the Alpine electrical generation system whenever fuel gas is unavailable from the production train due to a plant outage etc. Blackstart gas also allows for continued operations of the Nuiqsut gas skid which provides fuel gas to the village of Nuiqsit. Blackstart gas is used annually during the Alpine turnaround (4-30 days) and during unplanned plant outages and upsets. CPAI reported a potential Tubing x Inner Annulus pressure communication to AOGCC on August 14, 2015. CPAI performed diagnostics including a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on September 1, 2015 which indicates that CD1-14 exhibits at least two competent barriers to the release of well pressure. Accordingly, the AOGCC believes that the wells condition does not compromise overall well integrity so as to threaten human safety or the environment. B� AIO 18C.006 November 30, 2015 Page 2 of 2 AOGCC's approval to continue dry gas injection only in CRU CD1-14 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a mechanical integrity test of the inner annulus (MITIA) every 2 years to 3000 psi pressure; 4. CPAI shall limit the well's injection pressure to 4,025 psi, the IA operating pressure to 2400 psi, and the OA operating pressure to 1000 psi; 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. CPAI shall install transmitters on the IA and OA to provide real time monitoring; 7. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 8. The MIT anniversary date is September 1, 2015. DONE at Anchorage, Alaska and dated November 23, 2015. G!�,l �-- th erster Daniel T. Seamount, Jr. air, Commissioner Commissioner AND APPEAL As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on aweekend or state holiday. Singh, Angela K (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, December 01, 2015 10:53 AM To: 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); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Kair, Michael N (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Paladijczuk, Tracie L (DOA); Pasqual, Maria (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); Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; David Tetta; Don Shaw; Donna Vukich; Eric Lidji; Gary Orr; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Hyun, James J (DNR); Jason Bergerson; Jim Magill; Joe Longo; John Martineck, Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Louisiana Cutler, Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Sarah Baker; Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Tina Grovier (tmgrovier@stoel.com); Todd, Richard 1 (LAW); Tostevin, Breck C (LAW); Wayne Wooster, William Van Dyke; AKDCWellIntegrityCoordinator, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew Vanderlack; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Caleb Conrad; Carrie Wong; Cliff Posey; Cocklan-Vendl, Mary E; Colleen Miller; Crandall, Krissell; D Lawrence; Dave Harbour, David Boelens; David Duffy; David House; David McCaleb; David Steingreaber; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; Gordon Pospisil; Gregg Nady; gspfoff, Hyun, lames J (DNR); Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW); Jim Watt; Jim White; Joe Lastufka; Joe Nicks; John Adams; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek, Houle, Julie (DNR); Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker, Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover; Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephan Hennigan; Stephanie Klemmer; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Teresa Imm; Thor Cutler, Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano Subject: aiol8c-006 (CPA) Attachments: aiol8c-006.pdf James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. P.O. Box 58055 Soldotna, AK 99669 Anchorage, AK 99519 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Mr. Jan Byrne Richard Wagner Darwin Waldsmith Problem Wells Supervisor P.O. Box 60868 P.O. Box 39309 ConocoPhillips Alaska, Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 100360 Anchorage, AK 99510-0360 Angela K. Singh Colombie, Jody J (DOA) From: Foerster, Catherine P (DOA) Sent: Monday, November 30, 2015 4:35 PM To: Colombie, Jody J (DOA) Subject: Re: please review and approve Approve Sent from my Whone On Nov 30, 2015, at 3:49 PM, Colombie, Jody J (DOA) <jody.colombie@alaska.gov> wrote: ,Jody J. Colombie .AOGCC Special.Assistant Alaska Oil and Gas Conservation Commission 333 'Vest 141 ..Avenue .Anchorage, .Alaska 99501 Office: (907) 793-1221 Fax: (907) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iody.colombie@alaska.gov. <SKM_C454e15113012510.pdf> THE STATE 01ALAJKL'] GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.007 Mr. Dusty Freeborn Problem Wells Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alciska.gov Re: Docket Number: AIO-16-001 Request for administrative approval to allow well CD4-213B (PTD 2120050) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) CD4-213B (PTD 2120050) Colville River Field Alpine Oil Pool Dear Mr. Freeborn: By letter dated January 12, 2016, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18C.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 performed a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on June 12, 2015. CPAI reported a potential Tubing (T) x Inner Annulus (IA) pressure communication to AOGCC on October 18, 2015 while the well was on miscible injectant (MI). CPAI performed diagnostics including a passing non -state witnessed MITIA on December 8, 2015 which indicates that CD4-213B exhibits at least two competent barriers to the release of well pressure. The well was shut in and was WAG'ed to water for a 30 day period in which communication was not observed. The well was then WAG'ed to MI for a 30 day monitor period in which TxIA communication was evident. The well does not exhibit signs of pressure communication while on water injection. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 18C.007 January 28, 2016 Page 2 of 2 AOGCC's approval to continue water injection only in CRU CD4-21313 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 W W 7. pressure to 1000 psi; 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 required to restart injection; and The next required MIT is to be before or during the month of June 2017. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated January 28, 2016. Cathy P. Foerster Chair, Commissioner 045-1-0-- - Daniel T. Seamount, Jr. 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. Singh, Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Thursday, January 28, 2016 2:57 PM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AKDCWeIIIntegrityCoordinator, Alan Bailey, Alex Demarban; Alexander Bridge; Allen Huckabay; Amanda Tuttle; Andrew Vanderlack; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Caleb Conrad; Carrie Wong; Cliff Posey, Colleen Miller; Crandall, Krissell; D Lawrence; Dave Harbour, David Boelens; David Duffy; David House; David McCaleb; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; Gordon Pospisil; Gregg Nady; gspfoff, Hyun, James J (DNR); Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jerry McCutcheon; Jim Watt; Jim White; Joe Lastufka; Joe Nicks; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek, Houle, Julie (DNR); Julie Little; Kari Moriarty, Kazeem Adegbola; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker; Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Mealear Tauch; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky, Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Stephen Hennigan; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler, Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Caroline Bajsarowicz; Casey Sullivan; Diane Richmond; Don Shaw; Donna Vukich; Eric Lidji; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Jason Bergerson; Jim Magill; Joe Longo; John Martineck, Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, lames M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, William Van Dyke Subject: Area Injection Order 18C.007 (CRU) Attachments: aiol8c-007.pdf Please see attached. Samantha Carlisle Executive Secretary III Alaska Oil and Gas Conservation Commission 333 West 7h Avenue Anchorage, AK 99501 (907)793-1223 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 Samantha Carlisle at (907) 793-1223 or Samantha.Carlisle@alaska.ggy. James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Mr. Dusty Freeborn Richard Wagner Darwin Waldsmith Problem Wells Supervisor P.O. Box 60868 P.O. Box 39309 ConocoPhillips Alaska, Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 100360 Anchorage, AK 99510-0360 Angela K. Singh THE STATE "ALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission CANCELLATION ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.007 Mr. Dusty Freeborn Problem Wells Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-16-012 Request to cancel Area Injection Order (AIO) 18C.OM Colville River Unit (CRU) CD4-213B (PTD 2120050) Colville River Field Alpine Oil Pool Dear Mr. Freeborn: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov By letter dated March 30, 2016, ConocoPhillips Alaska, Inc. (CPAI) requested cancellation of administrative approval (AA) Area Injection Order (AIO) 18C.007. In accordance with Rule 11 of Area Injection Order (AIO) 18C.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request to cancel the AA. CRU CD4-213B developed a tubing by inner annulus pressure communication while on miscible injectant, and on January 28, 2016 the AOGCC issued AIO 18C.007. AOGCC determined that water injection could safely continue if CPAI complied with the restrictive conditions set out in AA AIO 18C.007. CPAI has performed a rig workover of CD4-213B in March 2016 which repaired the tubing by inner annulus communication. AA AIO 18C.007 is no longer necessary to the operation of CD4- 213B and is hereby CANCELLED. Injection into CRU CD4-213B will be governed by provisions of AIO No. 18C.000. DONE at Anchorage, Alaska and dated April 5, 2016. A, lc\� t 243 OLIFoerster iair, Commissioner I-V Daniel T. Seamot6t, Jr. Commissioner AIO 18C.007 Cancellation April 5, 2016 Page 2 of 2 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. THE STAY FOSAWIS l GOVERNOR BILL WALY i 1' Alaska Oil and Gas Conservation Commission CANCELLATION ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.007 Mr. Dusty Freeborn Problem Wells Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-16-012 Request to cancel Area Injection Order (AIO) 18C.007 Colville River Unit (CRU) CD4-21313 (PTD 2120050) Colville River Field Alpine Oil Pool Dear Mr. Freeborn: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov By letter dated March 30, 2016, ConocoPhillips Alaska, Inc. (CPAI) requested cancellation of administrative approval (AA) Area Injection Order (AIO) 18C.007. In accordance with Rule 11 of Area Injection Order (AIO) 18C.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request to cancel the AA. CRU CD4-213B developed a tubing by inner annulus pressure communication while on miscible injectant, and on January 28, 2016 the AOGCC issued AID 18C.007. AOGCC determined that water injection could safely continue if CPAI complied with the restrictive conditions set out in AA AIO 18C.007. CPAI has performed a rig workover of CD4-213B in March 2016 which repaired the tubing by inner annulus communication. AA AIO 18C.007 is no longer necessary to the operation of CD4- 213B and is hereby CANCELLED. Injection into CRU CD4-21313 will be governed by provisions of AID, No. 18C.000. DONE at Anchorage, Alaska and dated April 5, 2016. //signature on file// //signature on file// Cathy P. Foerster Daniel T. Seamount, Jr. Chair, Commissioner Commissioner AIO 18C.007 Cancellation April 5, 2016 Page 2 of 2 TION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Mather, 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 he filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Singh, Angela K (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, April 06, 20161:58 PM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael 1 (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AKDCWeIIIntegrityCoordinator, Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Amanda Tuttle; Andrew VanderJack; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Caleb Conrad; Cliff Posey, Colleen Miller; Crandall, Krissell; D Lawrence; Dave Harbour; David Boelens; David Duffy, David House; David McCaleb; David Steingreaber; David Tetta; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock, Gordon Pospisil; Gregg Nady; gspfoff, Hyun, James J (DNR); Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jerry McCutcheon; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Karen Thomas; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Louisiana Cutler, Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Mealear Tauch; Michael Calkins; Michael Moora; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer, Stephen Hennigan; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer; Davidson, Temple (DNR); Teresa Imm; Thor Cutler; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Ann Danielson; Anne Hillman; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw, Eric Lidji; Garrett Haag; Smith, Graham 0 (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Jason Bergerson; Jim Magill; Joe Longo; John Martineck, Josh Kindred; Kasper Kowalewski; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, lames M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW}; Talib Syed; Terence Dalton; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Vicky Sterling; Wayne Wooster, William Van Dyke Subject: aiol8c-007 cancellation - CPA Attachments: aiol8c-007 cancel lation.pdf James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. P.O. Box 58055 Soldotna, AK 99669 Anchorage, AK 99519 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Mr. Dusty Freeborn Richard Wagner Darwin Waldsmith Problem Wells Supervisor P.O. Box 60868 P.O. Box 39309 ConocoPhillips Alaska, Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 100360 Anchorage, AK 99510-0360 Angela K. Singh THE STATE 'ALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.008 Mr. Jan Byrne Problem Wells Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-16-010 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Request for administrative approval to allow well CD4-27 (PTD 2111460) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) CD4-27 (PTD 2111460) Colville River Field Alpine Oil Pool Dear Mr. Byrne: By letter dated March 19, 2016, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule I of Area Injection Order (AIO) 18C.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for administrative approval to continue water only injection in the subject well. CPAI reported a potential Tubing (T) x Inner Annulus (IA) pressure communication to AOGCC on December 25, 2015 while the well was on miscible injectant (MI). CPAI performed diagnostics including a passing non -state witnessed MITIA on December 30, 2015 which indicates that CD4-27 exhibits at least two competent barriers to the release of well pressure. CPAI began injecting MI for an AOGCC approved monitoring period in which communication was observed. CPAI WAG'ed the well to water for a monitoring period in which communication was not evident. The well does not exhibit signs of pressure communication while on water injection. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 18C.008 March 25, 2016 Page 2 of 2 AOGCC's approval to continue water injection only in CRU CD4-27 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi; 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The next required MIT is to be before or during the month of June 2017. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated March 25, 2016. //signature on file// Cathy Y. Foerster Chair, Commissioner //signature on file// D(#1 T. S6am"nt, Jr. Commissioner TION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Colombie, Jody J (DOA) From: Colombie, Jody 1 (DOA) Sent: Friday, March 25, 2016 9:52 AM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AKDCWellIntegrityCoordinator, Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Amanda Tuttle; Andrew VanderJack; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Caleb Conrad; Cliff Posey; Colleen Miller; Crandall, Krissell; D Lawrence; Dave Harbour, David Boelens; David Duffy; David House; David McCaleb; David Steingreaber; David Tetta; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; Gordon Pospisil; Gregg Nady; gspfoff; Hyun, James J (DNR); Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jerry McCutcheon; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Karen Thomas; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Louisiana Cutler; Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Mealear Tauch; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover; Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Stephen Hennigan; Moothart, Steve R (DNR); Suzanne Gibson; Sheffield@aoga.org; Tania Ramos; Ted Kramer; Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Ann Danielson; Anne Hillman; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw; Donna Vukich; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Jason Bergerson; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kasper Kowalewski; Kenneth Luckey; King, Kathleen J (DNR); 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); 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); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Vicky Sterling; Wayne Wooster; William Van Dyke Subject: aiol8c-008 - CPA (CD4-27) Attachments: aiol8c-008.pdf James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Mr. Jan Byrne Richard Wagner Darwin Waldsmith Problem Wells Supervisor P.O. Box 60868 P.O. Box 39309 ConocoPhillips Alaska, Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 100360 Anchorage, AK 99510-0360 t 20\ l0— Angela K. Singh Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER 18C.008 AMENDED Ms. Kathleen Dodson Well Integrity Specialist ConocoPhillips Alaska, Inc. P.O. Box 1000360 Anchorage, AK 99510 Re: Docket Number: AIO-23-009 Request to Amend Area Injection Order 18C.008; Water Alternating Gas Injection Colville River Unit (CRU) CD4-27 (PTD 2111460), Alpine Oil Pool Dear Ms. Dodson: By emailed letter dated April 24, 2023, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to amend Area Injection Order (AIO) 18C.008 to include water alternating gas (WAG) injection with a known tubing by inner annulus (TxIA) pressure communication. In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, CPAI’s request to amend the administrative approval to continue WAG injection in the subject well. CPAI reported a potential TxIA pressure communication to AOGCC on December 25, 2015, while the well was on miscible gas injection. CPAI performed diagnostics and confirmed the TxIA pressure communication was only present during gas injection. AOGCC issued AIO 18C.008 on March 25,2016, restricting the well to water only injection. CPAI has recently changed an internal policy to allow WAG injection in wells that have casing rated to support the higher pressures of gas injection should a barrier fail, and that can meet stringent testing criteria. CPAI has performed additional diagnostics including a passing non-state witnessed mechanical integrity test (MIT) of the inner annulus (to a test pressure greater than the anticipated gas injection pressure of 3,900 psi) on March 25, 2023. This indicates that CD4-27 exhibits at least two competent barriers to the release of well pressure. CPAI has installed an injection line choke and surface safety valve (SSV) on CD4-27. Both of these devices have remote shut down capability by the Board Operator. Combining this with live transmitters on the inner and outer annulus and the alarm functions in the Supervisory Control and Data Acquisition (SCADA) system create robust layers of protection from an over pressure event. These inner and outer annulus alarms and shut-inprotocols combined with the planned inner and outer annulus operating pressure limits enable AOGCC to remove the AIO 18C.008 Amended May 17, 2023 Page 2 of 3 original water only restriction and re-authorize gas injection. AOGCC believes CPAI can safely manage the TxIA communication with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,400 psi when on gas injection and 2,000 psi when injecting water. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC’s approval to continue WAG injection in CRU CD4-27 is conditioned upon the following: 1) CPAI shall record wellhead pressures and injection rate daily; 2) CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3) CPAI shall perform a MIT of the inner annulus every two years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 4) CPAI shall limit the well’s inner annulus operating pressure to 2,400 psi during gas injection and 2,000 psi during water injection. Audible control room alarms shall be set at or below these limits; 5) CPAI shall limit the well’s outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 6) CPAI shall monitor the inner and outer annulus pressures in real time with its SCADA system; 7) CPAI shall maintain the injection line choke and surface safety valve (SSV) remote shut down capability. During gas injection, the IA protocols will include a drill site operator alarm set at 2,200 psi, and a high alarm set at 2,400 psi that will prompt the control room Board Operator to remotely shut in the choke or SSV; 8) CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 9) After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 10) The next required MIT is to be before or during the month of June 2023. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated May 17, 2023. Brett W. Huber, Sr Jessie L. Chmielowski Gregory C. Wilson Chair, Commissioner Commissioner Commissioner Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.05.17 14:06:31 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.05.17 14:35:32 -08'00' Gregory Wilson Digitally signed by Gregory Wilson Date: 2023.05.17 14:39:35 -08'00' AIO 18C.008 Amended May 17, 2023 Page 3 of 3 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. From:Carlisle, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order 18C.008 Amended (CRU) Date:Thursday, May 18, 2023 10:20:15 AM Attachments:aio18C.008 Amended.pdf Docket Number: AIO-23-009 Request to Amend Area Injection Order 18C.008; Water Alternating Gas Injection Colville River Unit (CRU) CD4-27 (PTD 2111460), Alpine Oil Pool Samantha Carlisle Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.carlisle@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.carlisle%40alaska.gov Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 mailed 5/18/23 THE STATE °fALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.009 Mr. Jan Byrne Problem Wells Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Docket Number: AIO-16-016 Request for administrative approval to allow well CD3-128 (PTD 2110370) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) CD3-128 (PTD 2110370) Colville River Field Alpine Oil Pool Dear Mr. Byrne: By letter dated April 17, 2016, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18C.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 performed a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on February 23, 2014. CPAI reported a potential Tubing (T) x Inner Annulus (IA) pressure communication to AOGCC on May 13, 2015 while the well was on miscible injectant (MI). CPAI performed diagnostics including a passing non -state witnessed MITIA on May 17, 2015 which indicates that CD3-128 exhibits at least two competent barriers to the release of well pressure. The well was shut in until ice road season when CPAI performed additional diagnostics and monitoring including a passing non -state witnessed MITIA on January 25, 2016 before completing several monitoring periods on water and then gas injection. The TxIA communication was evident while on gas but the well does not exhibit signs of pressure communication while on water injection. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 18C.009 April 26, 2016 Page 2 of 2 AOGCC's approval to continue water injection only in CRU CD3-128 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 0 7. pressure to 1000 psi; 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 required to restart injection; and The next required MIT is to be before or during the month of February 2018. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. �1 DONE at Anchorage, Alaska and dated April 26, 2016. & /,09� C�athj P. Foerster Daniel T. Seamount, Jr. Chair, Commissioner Commissioner RECONSIDERATION AND APPEAL As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. THF, STATE "'ALASKA 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 ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.009 Mr. Jan Byrne Problem Wells Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-16-016 Request for administrative approval to allow well CD3-128 (PTD 2110370) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) CD3-128 (PTD 2110370) Colville River Field Alpine Oil Pool Dear Mr. Byrne: By letter dated April 17, 2016, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18C.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 performed a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on February 23, 2014. CPAI reported a potential Tubing (T) x Inner Annulus (IA) pressure communication to AOGCC on May 13, 2015 while the well was on miscible injectant (MI). CPAI performed diagnostics including a passing non -state witnessed MITIA on May 17, 2015 which indicates that CD3-128 exhibits at least two competent barriers to the release of well pressure. The well was shut in until ice road season when CPAI performed additional diagnostics and monitoring including a passing non -state witnessed MITIA on January 25, 2016 before completing several monitoring periods on water and then gas injection. The TxIA communication was evident while on gas but the well does not exhibit signs of pressure communication while on water injection. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. A10 18C.009 April 26, 2016 Page 2 of 2 AOGCC's approval to continue water injection only in CRU CD3-128 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi; 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The next required MIT is to be before or during the month of February 2018. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated April 26, 2016. //signature on file// //signature on file// Cathy P. Foerster Daniel T. Seamount, Jr. Chair, Commissioner Commissioner As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Carlisle, Samantha J (DOA) From: Carlisle, Samantha J (DOA) Sent: Tuesday, April 26, 2016 2:20 PM To: AKDCWellIntegrityCoordinator; Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Amanda Tuttle; Andrew VanderJack; Anna Raff; Barbara F Fullmer; bbritch; Becky Bohrer; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Caleb Conrad; Cliff Posey; Colleen Miller; Crandall, Krissell; D Lawrence; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David Steingreaber; David Tetta; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz, Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; Gordon Pospisil; Gregg Nady; gspfoff, Hyun, James J (DNR); Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jerry McCutcheon; Jim Watt; Jim White; Joe Lastufka; Joe Nicks; John Easton; Jon Goltz, Juanita Lovett; Judy Stanek; Julie Houle; Julie Little; Karen Thomas; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Laura Silliphant (laura.gregersen@alaska.gov); Leslie Smith; Louisiana Cutler; Luke Keller; Marc Kovak; Mark Dalton; Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Marquerite kremer (meg.kremer@alaska.gov); Mary Cocklan-Vendl; Mealear Tauch; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); nelson; Nichole Saunders; Nick W. Glover; Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Paul Craig; Paul Decker (paul.decker@alaska.gov); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Stephen Hennigan; Steve Moothart (steve.moothart@alaska.gov); Suzanne Gibson; Tamera Sheffield; Tania Ramos; Ted Kramer; Temple Davidson; Teresa Imm; Thor Cutler; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Caroline Bajsarowicz; Casey Sullivan; Diane Richmond; Don Shaw; Eric Lidji; Garrett Haag; Graham Smith; Hak Dickenson; Heusser, Heather A (DNR); Holly Pearen; Jason Bergerson; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Marie Steele; Matt Armstrong; Mike Franger; Morgan, Kirk A (DNR); Pat Galvin; Patricia Bettis; Pete Dickinson; Peter Contreras; Richard Garrard; Robert Province; Ryan Daniel; Sandra Lemke; Susan Pollard; Talib Syed; Terence Dalton; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster; William Van Dyke; Ballantine, Tab A (LAW) (tab.ballantine@alaska.gov); Bender, Makana K (DOA) (makana.bender@alaska.gov); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA) (phoebe.brooks@alaska.gov); Carlisle, Samantha 1 (DOA); Colombie, Jody J (DOA) oody.colombie@alaska.gov); Cook, Guy D (DOA); Davies, Stephen F (DOA) (steve.davies@alaska.gov); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA) (cathy.foerster@alaska.gov); Frystacky, Michal (michal.frystacky@alaska.gov); Grimaldi, Louis R (DOA) (lou.grimaldi@alaska.gov); Guhl, Meredith (DOA sponsored) (meredith.guhl@alaska.gov); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA) (Jeff Jones@alaska.gov); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored) ooseph.mumm@alaska.gov); Noble, Robert C (DOA) (bob.noble@alaska.gov); Paladijczuk, Tracie L (DOA) (tracie.paladijczuk@alaska.gov); Pasqual, Maria (DOA) (maria.pasqual@alaska.gov); Quick, Michael J (DOA); Regg, James B (DOA) oim.regg@alaska.gov); Roby, David S To: (DOA) (dave.roby@alaska.gov); Scheve, Charles M (DOA) (chuck.scheve@alaska.gov); Schwartz, Guy L (DOA) (guy.schwartz@alaska.gov); Seamount, Dan T (DOA) (dan.seamount@alaska.gov); Singh, Angela K (DOA) (angela.singh@alaska.gov); Wallace, Chris D (DOA) (chris.wallace@alaska.gov) Subject: Area Injection Order 18C.009 (Colville River Unit, CPAI) Attachments: aiol8c-009.pdf Please see attached. Samantha Carlisle S xecutive Secretary 111 ja-; a Oil ei.ind (sits Conservation n G onal"issio n Anchorage, AK 99501 CONFIDENT"IALFFY N07IC E: This e-mail inessage, 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 i.n.terided recipien.t(s)..It may contain cexrfide ntial and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal laNv. if you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the: AOGCC is aware of the. mistake in sending it to you, contact Samantha Carlisle at (9077) 793-1223 or Sarnantlra Carlisle>C aktska.Rov. Bernie Karl James Gibbs Jack Hakkila K&K Recycling Inc. P.O. Box 1597 P.O. Box 190083 P.O. Box 58055 Soldotna, AK 99669 Anchorage, AK 99519 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Mr. Jan Byrne Richard Wagner Darwin Waldsmith Problem Wells Supervisor P.O. Box 60868 P.O. Box 39309 ConocoPhillips Alaska, Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 100360 Anchorage, AK 99510-0360 e :L 2�e, 2- Angela K. Singh Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.009 CANCELLATION Ms. Kate Dodson Senior Well Intervention Engineer ConocoPhillips Alaska, Inc. P.O. Box 1000360 Anchorage, AK 99510 Re: Docket Number: AIO-23-014 Request to cancel Area Injection Order (AIO) 18C.009 Colville River Unit (CRU) CD3-128 (PTD 2110370), Alpine Oil Pool Dear Ms. Dodson: By letter dated June 5, 2023, ConocoPhillips Alaska, Inc. (CPAI) requested cancellation of administrative approval (AA) AIO 18C.009. In accordance with 20 AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI’s request to cancel the AA. CPAI first reported a potential tubing by inner annulus (TxIA) pressure communication to AOGCC on May 13, 2015, and on April 26, 2016, AOGCC issued AIO 18C.009. AOGCC determined that water only injection could safely continue if CPAI complied with the restrictive conditions set out in AA AIO 18C.009. CPAI has repaired the well with new tubing under Sundry 323-041 and completed a passing state witnessed mechanical integrity test (MIT) of the inner annulus on April 12, 2023, which indicates that CD3-128 exhibits at least two competent barriers to the release of well pressure. AA AIO 18C.009 is no longer necessary to the operation of CD3-128 and is hereby CANCELLED. DONE at Anchorage, Alaska and dated June 14, 2023. Brett W. Huber, Sr Jessie L. Chmielowski Gregory C. Wilson Chair, Commissioner Commissioner Commissioner Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.06.14 14:11:29 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.06.14 14:14:30 -08'00' Gregory Wilson Digitally signed by Gregory Wilson Date: 2023.06.14 14:21:45 -08'00' AIO 18C.009 Cancellation June 14, 2023 Page 2 of 2 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. From:Carlisle, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order 18C.009 cancellation Date:Wednesday, June 14, 2023 2:28:47 PM Attachments:aio18C.009 cancellation.pdf Docket Number: AIO-23-014 Request to cancel Area Injection Order (AIO) 18C.009 Colville River Unit (CRU) CD3-128 (PTD 2110370), Alpine Oil Pool Samantha Carlisle Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.carlisle@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.carlisle%40alaska.gov Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 THE STATE Alaska Oil and Gas °fALASKA Conservation Commission GOVERNOR BILL WALKER ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.010 Ms. Rachel Kautz Well Integrity Engineer ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov Re: Docket Number: AIO-16-021 Request for administrative approval to allow well CD2-51 (PTD 2022490) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) CD2-51 (PTD 2022490) Colville River Field Alpine Oil Pool Dear Ms. Kautz: By letter dated May 14, 2016, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18C.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 performed a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on June 13, 2014. CPAI reported a potential Tubing (T) x Inner Annulus (IA) pressure communication to AOGCC on March 13, 2016 while the well was on miscible injectant (MI). CPAI performed diagnostics including a passing non -state witnessed MITIA on March 14, 2016 which indicates that CD2-51 exhibits at least two competent barriers to the release of well pressure. CPAI completed several monitoring periods on MI and then water injection. The TxIA communication was evident while on gas but the well does not exhibit signs of pressure communication while on water injection. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC's approval to continue water injection only in CRU CD2-51 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; AIO 18C.010 May 23, 2016 Page 2 of 2 2. 3. 4. 5. 6. 7. 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; CPAI shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure; CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi; 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 required to restart injection; and The next required MIT is to be before or during the month of June 2016. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated May 23, 2016. Y Cathy . Foerster Daniel T. Seamount, Jr. Chair, Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, May 24, 2016 9:06 AM To: 'Ballantine, Tab A (LAW) (tab.ballantine@alaska.gov)'; 'Bender, Makana K (DOA) (makana.bender@alaska.gov)'; 'Bettis, Patricia K (DOA) (patricia.bettis@alaska.gov)'; 'Bixby, Brian D (DOA)'; 'Brooks, Phoebe L (DOA) (phoebe.brooks@alaska.gov)'; Carlisle, Samantha J (DOA); 'Colombie, Jody J (DOA) Oody.colombie@alaska.gov)'; 'Cook, Guy D (DOA)'; 'Davies, Stephen F (DOA) (steve.davies@alaska.gov)'; Eaton, Loraine E (DOA); 'Foerster, Catherine P (DOA) (cathy.foerster@alaska.gov)'; 'Frystacky, Michal (michal.frystacky@alaska.gov)'; 'Grimaldi, Louis R (DOA) (lou.grimaldi@alaska.gov)'; 'Guhl, Meredith (DOA sponsored) (meredith.guhl@alaska.gov)'; Herrera, Matthew F (DOA); 'Hill, Johnnie W (DOA)'; 'Jones, Jeffery B (DOA) (Jeff Jones@alaska.gov)'; Kair, Michael N (DOA); 'Link, Liz M (DOA)'; Loepp, Victoria T (DOA); 'Mumm, Joseph (DOA sponsored) Ooseph.mumm@alaska.gov)'; 'Noble, Robert C (DOA) (bob.noble@alaska.gov)'; 'Paladijczuk, Tracie L (DOA)(tracie. pa lad ijczu k@a laska.gov)'; 'Pasqual, Maria (DOA) (maria.pasqual@alaska.gov)'; 'Quick, Michael (DOA sponsored)'; 'Regg, James B (DOA) Oim.regg@alaska.gov)'; 'Roby, David S (DOA) (dave.roby@alaska.gov)'; 'Scheve, Charles M (DOA) (chuck.scheve@alaska.gov)'; 'Schwartz, Guy L (DOA) (guy.schwartz@alaska.gov)'; 'Seamount, Dan T (DOA) (dan.seamount@alaska.gov)'; 'Singh, Angela K (DOA) (angela.singh@alaska.gov)'; 'Wallace, Chris D (DOA) (chris.wallace@alaska.gov)'; 'AKDCWeIIIntegrityCoordinator'; 'Alan Bailey'; 'Alex Demarban'; 'Alexander Bridge'; 'Allen Huckabay'; 'Amanda Tuttle'; 'Andrew VanderJack'; 'Anna Raff'; 'Barbara F Fullmer'; 'bbritch'; 'Becky Bohrer'; 'Bill Bredar'; 'Bob Shavelson'; 'Brian Havelock'; 'Bruce Webb'; Burdick, John D (DNR); 'Caleb Conrad'; 'Candi English'; 'Cliff Posey'; 'Colleen Miller'; 'Crandall, Krissell'; 'D Lawrence'; 'Dave Harbour'; 'David Boelens'; 'David Duffy'; 'David House'; 'David McCaleb'; 'David Tetta'; 'ddonkel@cfl.rr.com'; 'Dean Gallegos'; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); 'Donna Ambruz'; 'Ed Jones'; 'Elowe, Kristin'; 'Evans, John R (LDZX)'; 'Frank Molli'; 'Gary Oskolkosf'; 'George Pollock'; 'Gordon Pospisil'; 'Gregg Nady'; 'gspfoff'; Hyun, lames 1 (DNR); 'Jacki Rose'; 'Jdarlington Oarlington@gmail.com)'; 'Jeanne McPherren'; 'Jerry Hodgden'; 'Jerry McCutcheon'; 'Jim Watt'; 'Jim White'; 'Joe Lastufka'; 'Joe Nicks'; 'John Easton'; 'Jon Goltz'; 'Juanita Lovett'; 'Judy Stanek'; 'Julie Houle'; 'Julie Little'; 'Karen Thomas'; 'Karl Moriarty'; 'Kazeem Adegbola'; 'Keith Torrance'; 'Keith Wiles'; 'Kelly Sperback'; 'Laura Silliphant (laura.gregersen@alaska.gov)'; 'Leslie Smith'; 'Louisiana Cutler'; 'Luke Keller'; 'Marc Kovak'; 'Mark Dalton'; 'Mark Hanley (mark.hanley@anadarko.com)'; 'Mark Landt'; 'Mark Wedman'; 'Marquerite kremer (meg.kremer@alaska.gov)'; 'Mary Cocklan-Vendl'; 'Mealear Tauch'; 'Michael Calkins'; 'Michael Moora'; 'MJ Loveland'; 'mkm7200'; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); 'nelson'; 'Nichole Saunders'; 'Nick W. Glover'; 'Nikki Martin'; 'NSK Problem Well Supv'; 'Oliver Sternicki'; 'Patty Alfaro'; 'Paul Craig'; 'Paul Decker (paul.decker@alaska.gov)'; 'Paul Mazzolini'; Pike, Kevin W (DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'Renan Yanish'; 'Richard Cool'; 'Robert Brelsford'; 'Ryan Tunseth'; 'Sara Leverette'; 'Scott Griffith'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sharon Yarawsky'; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); 'Smart Energy Universe'; Smith, Kyle S (DNR); 'Sondra Stewman'; 'Stephanie Klemmer'; 'Stephen Hennigan'; 'Steve Moothart (steve.moothart@alaska.gov)'; 'Suzanne Gibson'; Tamera Sheffield; 'Tania Ramos'; 'Ted Kramer'; Temple Davidson; Teresa Imm; Thor Cutler, 'Tim Mayers'; Todd Durkee; trmjrl; 'Tyler Senden'; Vicki Irwin; Vinnie Catalano; 'Aaron Gluzman'; 'Aaron Sorrell'; Ajibola Adeyeye; Alan Dennis; Ann Danielson; Bajsarowicz, Caroline J; Brian Gross; 'Bruce Williams'; Bruno, Jeff 1 (DNR); Casey Sullivan; D. McCraine; 'Don Shaw'; Eric Lidji; Furie Drilling; Garrett Haag; 'Graham Smith'; Hak Dickenson; Heusser, Heather A To: (DNR); Holly Pearen; J. Stuart; 'Jason Bergerson'; 'Jim Magill'; Joe Longo; John Martineck; Josh Kindred; Kasper Kowalewski; 'King, Kathleen J (DNR)'; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; 'Marie Steele'; Matt Armstrong; 'Mike Franger'; Morgan, Kirk A (DNR); Pat Galvin; 'Pete Dickinson'; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; 'Ryan Daniel'; 'Sandra Lemke'; 'Susan Pollard'; T. Hord; Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW); Vicky Sterling; 'Wayne Wooster'; Whitney Pettus; 'William Van Dyke' Subject: Various Orders Attachments: other110.pdf, aio18C.010.pdf, aio5.025.pdf, aio4F.008.pdf Please see Attached: Other Order 110 (Docket OTH-16-002) NO 18C-010 (Docket AI0-16-021) AIO 5-025 (Docket AI0-16-020) AIO 4F-008 (Docket A10-16-019) Jody J. CoCombie AOGCC SpeciaC.Assistant At4ska OiCandGas Conservation Commission 333 -West 7' Avenue .Anchorage, ACaska 99501 Office: (907) 793-1221 _Fax: (907) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iodv.colombie@alaska.gov. Jack Hakkila Bernie Karl P.O. Box 190083 K&K Recycling Inc. Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Penny Vadla George Vaught, Jr. 399 W. Riverview Ave. P.O. Box 13557 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Ms. Rachel Kautz Richard Wagner Well Integrity Engineer P.O. Box 60868 ConocoPhillips Alaska, Inc. Fairbanks, AK 99706 P.O. Box 100360 Anchorage, AK 99510-0360 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 0*k2\�( 2A4,, 2oUe Ss-� Angela K. Singh THE STATE GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov March 30, 2017 Ms. Kelly Lyons Amo iSrc. 00 2 4rY14,1c1,s C — 41c, IBC, ooc, Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-17-009 Request to amend the Mechanical Integrity Testing (MIT) anniversary date for 97 wells which operate under existing administrative approvals. Request to amend the required MIT pressure criteria for six wells which operate under existing administrative approvals. Area Injection Orders 2B, 2C, 16, 18B, 18C, 28 and 30 Kuparuk River Unit and Colville River Unit Dear Ms. Lyons: By letter dated February 23, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to change the MIT anniversary date on 97 wells to align with the established CPAI Underground Injection Control MIT permanent test schedule for pad testing. CPAI also requested an amendment to the required MIT pressure criteria for six wells. In accordance with Rule 9 of Area Injection Order (AIO) 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. �4/1 Cathy . Foerster Chair, Commissioner aniel T. Seamount, Jr. Commissioner Hollis French 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 fled 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 fled 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 1813.006 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 NAN-N CD4-209 AIO 28.003 June 2017 1851090 KUPARUK RIV UNIT 2Z-16 AIO 26.002 August 2015 1960900 KUPARUK RIV UNIT 21VI-09A AIO 213.004 June 2016 1951930 KUPARUK RIV UNIT 3Q-21 AIO 213.005 August 2018 1830960 KUPARUK RIV UNIT 2C-07 AIO 26.007 August 2015 2001940 KUPARUK RIV UNIT 1A-04A AIO 2B.011 July 2017 1951810 KUPARUK RIV UNIT 311-25 AIO 213.012 August 2018 2000260 KUPARUK RIV UNIT 3K-22A 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 213.030 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 KUPARUK RIV UNIT 2F-13 AIO 213.039 July 2018 1861780 KUPARUK RIV UNIT 3Q-15 AIO 26.042 August 2018 1890740 KUPARUK RIV UNIT 2K-12 AIO 213.048 June 2017 1811780 KUPARUK RIV UNIT 1A-12 AIO 2B.049 July 2017 1830520 KUPARUK RIV UNIT 1Y-09 AIO 26.051 July 2017 1841520 KUPARUK RIV UNIT 2D-02 AIO 26.052 August 2017 1841230 KUPARUK RIV UNIT 1L-05 AIO 213.054 June 2018 1831760 KUPARUK RIV UNIT 2V-05 AIO 26.055 June 2018 1830620 KUPARUK RIV UNIT 1Y-08 AIO 213.056 July 2017 2100490 KUPARUK RIV UNIT 3N-16A AIO 26.057 August 2018 1811360 KUPARUK RIV UNIT 1B-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 213.066 June 2017 1851140 KUPARUK RIV UNIT 36-10 AIO 26.067 June 2017 1911250 KUPARUK RIV UNIT 3Q-01 AIO 26.068 August 2018 1841010 KUPARUK RIV UNIT 2D-10 AIO 213.070 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 KUPARUK RIV UNIT 26-10 AIO 26.073 May 2018 1831870 KUPARUK RIV UNIT 2F-04 AIO 213.074 July 2018 1820310 KUPARUK RIV UNIT 1A-16RD AIO 2B.075 July 2017 1840960 KUPARUK RIV UNIT 2H-13 AIO 26.076 May 2018 1822140 KUPARUK RIV UNIT 1E-22 AIO 26.078 June 2018 1821320 IKUPARUK RIV UNIT 1F-05 AIO 26.080 June 2018 2100130 KUPARUK RIV UNIT 1E-15A AIO 213.081 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 213.085 August 2017 1830950 KUPARUK RIV UNIT 2C-08 AIO 213.086 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 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 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 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 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 26.060 anticipated injection pressure. CPAI shall perform an MIT -IA every 2 years to the maximum 1861640 KUPARUK RIV UNIT 3K-11 AIO 26.061 anticipated injection pressure. r Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov March 30, 2017 Ms. Kelly Lyons 1A=0 \-Cc, c)02 Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-17-009 Request to amend the Mechanical Integrity Testing (MIT) anniversary date for 97 wells which operate under existing administrative approvals. Request to amend the required MIT pressure criteria for six wells which operate under existing administrative approvals. Area Injection Orders 2B, 2C, 16, 18B, 18C, 28 and 30 Kuparuk River Unit and Colville River Unit Dear Ms. Lyons: By letter dated February 23, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to change the MIT anniversary date on 97 wells to align with the established CPAI Underground Injection Control MIT permanent test schedule for pad testing. CPAI also requested an amendment to the required MIT pressure criteria for six wells. In accordance with Rule 9 of Area Injection Order (AIO) 02B.000, Rule 10 of AIO 16, and Rule 11 of AID 2C,18B,18C, 28, and 30, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for administrative approval to amend the MIT anniversary date for the 97 wells and amend the required MIT pressure criteria for the six wells as detailed in the accompanying tables. CPAI has been working with AOGCC since late 2015 and submitted a proposal to AOGCC on March 26, 2016 looking to consolidate well testing to the established pad testing schedule which has an emphasis on summer months May through August. CPAI has been looking for efficiencies by scheduling and completing the multiple well tests required in a pad by pad sequence averaged over a four-year workload. Over the last twelve months the CPAI well integrity team has coordinated with AOGCC inspectors to witness multiple well tests and both have identified efficiencies in utilizing this pad schedule. The administrative action rules contained within the Area Injection Orders allow the AOGCC to administratively waive or amend the requirements of any rule as long as the change does not promote waste of jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. DONE at Anchorage, Alaska and dated March 30, 2017. //signature on file// //signature on file// //signature on file// Cathy P. Foerster Daniel T. Seamount, Jr. Hollis French Chair, Commissioner Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. PTD # Well name AIO # New Anniversary Test Month 1981630 KUPARUK RIV U TARN 2N-325 AIO 16.001 August 2018 1982400 KUPARUK RIV U TARN 2L-305 AIO 16.002 August 2018 2071120 KUPARUK RIV U TARN 2L-319 AIO 16.003 August 2018 2100280 KUPARUK RIV U TARN 2L-310 AIO 16.004 August 2018 1982510 KUPARUK RIV U TARN 2L-323 AIO 16.005 August 2018 2032250 COLVILLE RIV UNIT CD1-07 AIO 18B.006 June 2017 2010060 COLVILLE RIV UNIT CD1-21 AIO 1813.007 June 2017 2061420 COLVILLE RIV NAWK C134-321 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 26.005 August 2018 1830960 KUPARUK RIV UNIT 2C-07 AIO 213.007 August 2015 2001940 KUPARUK RIV UNIT 1A-04A AIO 2B.011 July 2017 1951810 KUPARUK RIV UNIT 311-25 AIO 26.012 August 2018 2000260 KUPARUK RIV UNIT 3K-22A AIO 213.013 May 2017 1881200 KUPARUK RIV UNIT 2K-03 AIO 28.016 June 2017 1890590 KUPARUK RIV UNIT 2K-10 AIO 213.017 June 2017 1861960 KUPARUK RIV UNIT 3Q-05 AIO 2B.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 KUPARUK RIV UNIT 2F-13 AIO 28.039 July 2018 1861780 KUPARUK RIV UNIT 3Q-15 AIO 213.042 August 2018 1890740 KUPARUK RIV UNIT 2K-12 AIO 213.048 June 2017 1811780 KUPARUK RIV UNIT 1A-12 A10 2B.049 July 2017 1830520 KUPARUK RIV UNIT 1Y-09 AIO 213.051 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 16-11 AIO 26.060 June 2017 1861640 KUPARUK RIV UNIT 3K-11 AIO 26.061 May 2017 1852280 KUPARUK RIV UNIT 3F-04 AIO 26.063 June 2017 1831070 KUPARUK RIV UNIT 2X-05 AIO 26.064 June 2017 2101810 KUPARUK RIV UNIT 1E-08A AIO 213.065 June 2018 1950920 KUPARUK RIV UNIT 2T-28 AIO 2B.066 June 2017 1851140 KUPARUK RIV UNIT 36-10 AIO 2B.067 June 2017 1911250 KUPARUK RIV UNIT 3Q-01 AIO 2B.068 August 2018 1841010 KUPARUK RIV UNIT 2D-10 AIO 2B.070 August 2017 1831610 KUPARUK RIV UNIT 2V-02 AIO 2B.071 June 2017 2120950 KUPARUK RIV UNIT 3N-11A AIO 2B.072 August 2018 1840290 KUPARUK RIV UNIT 26-10 AIO 2B.073 May 2018 1831870 KUPARUK RIV UNIT 2F-04 AIO 26.074 July 2018 1820310 KUPARUK RIV UNIT 1A-16RD A1O 2B.075 July 2017 1840960 KUPARUK RIV UNIT 21-1-13 AIO 2B.076 May 2018 1822140 KUPARUK RIV UNIT 1E-22 AIO 2B.078 June 2018 1821320 KUPARUK RIV UNIT lF-05 AIO 28.080 June 2018 2100130 KUPARUK RIV UNIT 1E-15A AIO 213.081 June 2018 1861790 KUPARUK RIV UNIT 3Q-16 AIO 213.082 August 2018 1900350 KUPARUK RIV UNIT 1L-10 AIO 2B.083 June 2018 1850180 KUPARUK RIV UNIT 21.1-05 AIO 213.084 August 2018 1830890 KUPARUK RIV UNIT 2C-03 AIO 213.085 August 2017 1830950 KUPARUK RIV UNIT 2C-08 AIO 26.086 August 2017 1852460 KUPARUK RIV UNIT 3F-08 AIO 26.087 June 2017 1851520 KUPARUK RIV UNIT 111-15 AIO 213.088 May 2017 1852720 KUPARUK RIV UNIT 3F-11 AIO 26.089 June 2017 1850440 KUPARUK RIV UNIT 1Q-13 AIO 2B.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 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 26-06 AIO 2C.012 May 2018 1852160 KUPARUK RIV UNIT 3J-08 AIO 2C.013 July 2018 1830510 KUPARUK RIV UNIT 1Y-10 AIO 2C.014 July 2017 1840860 KUPARUK RIV UNIT 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 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 213-07 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 113-08A 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 C133-123 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 26.017 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 16-11 AIO 213.060 anticipated injection pressure. CPAI shall perform an MIT -IA every 2 years to the maximum 1861640 KUPARUK RIV UNIT 3K-11 AIO 26.061 1 anticipated injection pressure. Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711-0055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639-0309 Fairbanks, AK 99706-0868 Singh. Angela K (DOA) From: Colombie, Jody 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, AKDCWeIIIntegrityCoordinator, 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@dl.rr.com; DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Elwood Brehmer, Evan Osborne; Evans, John R (LDZ)); George Pollock, Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff, Hunter Cox, Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jdarlington Qarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Watt; Jim White, Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); John Stuart, Jon Goltz, Chmielowski, Josef (DNR); Juanita Lovett, Judy Stanek, Kari Moriarty, Kasper Kowalewski; Kazeem Adegbola; Keith Torrance, Keith Wiles; Kelly Sperback; Frank, Kevin 1 (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 213, 2C, 16, 18B, 18C, 28 and 30 Kuparuk River Unit and Colville River Unit Tocttt.1, Co(ombic A0(7'C'(' Special _'Assistant _'Alaska oil anct yas Conservation Commission 3 3 )Vest Allen ue Am liovage, _`,Alaska 99501 ()nice: (907) 793-1221 .Tax: (907) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody ColornUe at 907.793.1221 or iody.colombie@alaska gov. THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.a ogcc.a laska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.011 CANCELLATION Ms. Rachel Kautz Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-18-049 Request to cancel Area Injection Order (AIO) 18C.011 Colville River Unit (CRU) CD2 -78 (PTD 2090660) Colville River Field Alpine Oil Pool Dear Ms. Kautz: By letter dated December 24, 2018, ConocoPhillips Alaska, Inc. (CPAI) requested cancellation of administrative approval (AA) Area Injection Order 18C.011. In accordance with Rule 11 of Area Injection Order (AIO) 18D.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request to cancel the AA. CD2 -78 developed a tubing by inner annulus communication and on May 22, 2017 the AOGCC issued AIO 18C.011. AOGCC determined that water injection could safely continue if CPAI complied with the restrictive conditions set out in AA AIO 18C.011. CPAI has recently repaired the well in November 2018 with new gas tight tubing installed under Sundry 318-325. A passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on December 12, 2018 indicates that CD2 -78 exhibits at least two competent barriers to the release of well pressure. AA AIO 18C.011 is no longer necessary to the operation of CD2 -78 and is hereby CANCELLED. A10 18C.0I I Cancellation December 27, 2018 Page 2 of 2 DONE at Anchorage, Alaska and dated December 27, 2018. Hollis S. French Chair, Commissioner Cathy V. Foerster 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. THE STATE °fALASKA Alaska Oil and Gas Conservation Commission GOVERNOR MIKE DUNLEAVY 333 West Seventh Avenue Anchorage, Alaska 9950 1 -3572 Main: 907.279.1433 Fax: 907.276.7542 www.cogcc.ciaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.011 CANCELLATION Ms. Rachel Kautz Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-18-049 Request to cancel Area Injection Order (AIO) 18C.0I I Colville River Unit (CRU) CD2 -78 (PTD 2090660) Colville River Field Alpine Oil Pool Dear Ms. Kautz: By letter dated December 24, 2018, ConocoPhillips Alaska, Inc. (CPAI) requested cancellation of administrative approval (AA) Area Injection Order 18C.011. In accordance with Rule 11 of Area Injection Order (AIO) 18D.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request to cancel the AA. CD2 -78 developed a tubing by inner annulus communication and on May 22, 2017 the AOGCC issued AIO 18C.011. AOGCC determined that water injection could safely continue if CPAI complied with the restrictive conditions set out in AA AID 18C.011. CPAI has recently repaired the well in November 2018 with new gas tight tubing installed under Sundry 318-325. A passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on December 12, 2018 indicates that CD2 -78 exhibits at least two competent barriers to the release of well pressure. AA AIO 18C.0I I is no longer necessary to the operation of CD2 -78 and is hereby CANCELLED. AIO 18C.011 Cancellation December 27, 2018 Page 2 of 2 DONE at Anchorage, Alaska and dated December 27, 2018. oft Mn '4r 9 Hsignature on fileH //signature on fileH Hollis S. French Cathy P. Foerster ` Chair, Commissioner Commissioner As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date ofthe event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl Gordon Severson Penny Vadla K&K Recycling Inc. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 58055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 6\ "r-\�\v e, xi� Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 THE STATE °fALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.011 Ms. Rachel Kautz Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Docket Number: AIO-17-015 Request for administrative approval to allow well CD2-78 (PTD 2090660) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) CD2-78 (PTD 2090660) Colville River Field Alpine Oil Pool Dear Ms. Kautz: By letter dated May 12, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18C.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 April 3, 2017 while the well was on miscible gas injection. CPAI performed diagnostics including a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on April 12, 2017 which indicates that CD2-78 exhibits at least two competent barriers to the release of well pressure. CPAI WAG'ed the well to water after receiving permission from AOGCC and monitored the well for an approved 30 day period. The well does not exhibit signs of pressure communication while on water injection. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 18C.0I I May 22, 2017 Page 2 of 2 AOGCC's approval to continue water injection only in CRU CD2-78 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 C pressure to 1000 psi; 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 required to restart injection; and The next required MIT is to be before or during the month of June 2018. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated May 22, 2017. Cath P. Foerster Daniel T. Seamount, Jr. Chair, Commissioner Commissioner Hollis S. French 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. "rHE STATE ,,ALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.011 Ms. Rachel Kautz Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov Re: Docket Number: AIO-17-015 Request for administrative approval to allow well CD2-78 (PTD 2090660) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) CD2-78 (PTD 2090660) Colville River Field Alpine Oil Pool Dear Ms. Kautz: By letter dated May 12, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18C.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 April 3, 2017 while the well was on miscible gas injection. CPAI performed diagnostics including a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on April 12, 2017 which indicates that CD2-78 exhibits at least two competent barriers to the release of well pressure. CPAI WAG'ed the well to water after receiving permission from AOGCC and monitored the well for an approved 30 day period. The well does not exhibit signs of pressure communication while on water injection. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. A10 18C.011 May 22, 2017 Page 2 of 2 AOGCC's approval to continue water injection only in CRU CD2-78 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi; 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The next required MIT is to be before or during the month of June 2018. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated May 22, 2017. //signature on file// Cathy P. Foerster Chair, Commissioner //signature on file// Daniel T. Seamount, Jr Commissioner //signature on file// Hollis S. French 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. 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. P.O. Box 13557 Denver, CO 80201-3557 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639-0309 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706-0868 S-Z3- kZ IN Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, May 23, 2017 9:19 AM 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; ddonkel@cfl.rr.com; DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Elwood Brehmer; Evan Osborne; Evans, John R (LDZX); George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff; Hunter Cox; Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jason Brune; 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; Mike Morgan; 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; 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; Andy Bond; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Catie Quinn; Corey Munk; David Tetta; Don Shaw; Eppie Hogan ; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Keith Lopez; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Melonnie Amundson; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Rachel Davis; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW); Wayne Wooster; William Van Dyke Subject: AIO 18C.001 Attachments: aiol8C.011.pdf Please see attached. Re: Docket Number: AIO-17-015 Request for administrative approval to allow well CD2-78 (PTD 2090660) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) CD2-78 (PTD 2090660) Colville River Field Alpine Oil Pool Jody J. Colombie .AOGCC Special.Assistant .Alaska Oil and Gas Conservation Commission 333 West /-' .Avenue -Anchorage, .Alaska 99501 Office: (907) 793-1221 Fax: (907) 276-7542 CONFIDENTIALITY NOTICE. This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iodv.colombie@alaska.aov. THE STATE °fALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.012 Ms. Rachel Kautz Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Docket Number: AIO-17-016 Request for administrative approval to allow well CD2-18 (PTD 2031510) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) CD2-18 (PTD 2031510) Colville River Field Alpine Oil Pool Dear Ms. Kautz: By letter dated June 11, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18C.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 March 11, 2017 while the well was on miscible gas injection. CPAI performed diagnostics including a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on March 14, 2017 which indicates that CD2-18 exhibits at least two competent barriers to the release of well pressure. CPAI WAG'ed the well to water after receiving permission from AOGCC and monitored the well for an approved 30 day period. The well does not exhibit signs of pressure communication while on water injection. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 18C.012 June 14, 2017 Page 2 of 2 AOGCC's approval to continue water injection only in CRU C132-18 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi; 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The next required MIT is to be before or during the month of June 2018. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated June 14, 2017. T Cathy . Foerster Daniel 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. 'i'I-II: s,i*Nr °1ALASKA t_rt()\'LRNOR BILL NV`ALKLR Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.012 Ms. Rachel Kautz Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov Re: Docket Number: AIO-17-016 Request for administrative approval to allow well CD2-18 (PTD 2031510) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) CD2-18 (PTD 2031510) Colville River Field Alpine Oil Pool Dear Ms. Kautz: By letter dated June 11, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18C.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 March 11, 2017 while the well was on miscible gas injection. CPAI performed diagnostics including a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on March 14, 2017 which indicates that CD2-18 exhibits at least two competent barriers to the release of well pressure. CPAI WAG'ed the well to water after receiving permission from AOGCC and monitored the well for an approved 30 day period. The well does not exhibit signs of pressure communication while on water injection. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 18C.012 June 14, 2017 Page 2 of 2 AOGCC's approval to continue water injection only in CRU CD2-18 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi; 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The next required MIT is to be before or during the month of June 2018. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated June 14, 2017. //signature on file// Cathy P. Foerster Chair, Commissioner //signature on file// Daniel T. Seamount, Jr Commissioner //signature on file// Hollis French Commissioner RECONSIDERATION AND APPEAL NOTICE OILgyO YAIrON CO' As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711-0055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639-0309 Fairbanks, AK 99706-0868 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, June 14, 2017 3:58 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; ddonkel@cfl.rr.com; DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Elwood Brehmer; Evan Osborne; Evans, John R (LDZX); George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff, Hunter Cox; Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jason Brune; 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; Mike Morgan; MJ Loveland; mkm7200; Motteram, Luke A; Mueller, Marta R (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick Ostrovsky; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan Yanish; Richard Cool; Robert Brelsford; 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; Tom Maloney; trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Well Integrity; Well Integrity; Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andy Bond; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Corey Munk; David Tetta; Don Shaw; Eppie Hogan; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Shine, Jim M (DNR); Joe Longo; John Martineck, Josh Kindred; Keith Lopez; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Melonnie Amundson; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Rachel Davis; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW); William Van Dyke Subject: AIO 18C.012 Attachments: aiol8C.012.pdf Re: Docket Number: AI0-17-016 Request for administrative approval to allow well CD2-18 (PTD 2031510) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) CD2-18 (PTD 2031510) Colville River Field Alpine Oil Pool Jody J. Colombie .AOGCC SpeciaCAssistant .Alaska Oil and Gas Conservation Commission 333 West 71ti .Avenue .Anchorage, .Alaska 99501 Office: (907) 793-1221 Fax: (.907) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iody.colombie@alaska.aov. THE STATE °fALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.013 Ms. Rachel Kautz Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Docket Number: AIO-17-017 Request for administrative approval to allow well CD4-26 (PTD 2090490) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) CD4-26 (PTD 2090490) Colville River Field Alpine Oil Pool Dear Ms. Kautz: By letter dated June 13, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18C.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 February 18, 2017 while the well was on miscible gas injection. CPAI performed diagnostics including a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on February 20, 2017 which indicates that CD4-26 exhibits at least two competent barriers to the release of well pressure. CPAI WAG'ed the well to water after receiving permission from AOGCC and monitored the well for an approved 30 day period. CPAI performed a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on June 9, 2017. The well does not exhibit signs of pressure communication while on water injection. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 18C.013 June 15, 2017 Page 2 of 2 AOGCC's approval to continue water injection only in CRU CD4-26 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi; 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The next required MIT is to be before or during the month of June 2019. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated June 15, 2017. a,, trz - Cathy t. Foerster Daniel eamount, Jr. Chair, Commissioner Commissioner Hollis S. French 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. THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.013 CANCELLATION Ms. Sara Carlisle Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-19-005 Request to cancel Area Injection Order (AIO) 18C.013 Colville River Unit (CRU) CD4 -26 (PTD 2090490) Colville River Field Alpine Oil Pool Dear Ms. Carlisle: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 v .aogcc.alaska.gov By letter dated February 22, 2019, ConocoPhillips Alaska, Inc. (CPAI) requested cancellation of administrative approval (AA) Area Injection Order 18C.013. In accordance with Rule 11 of Area Injection Order (AIO) 18D.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request to cancel the AA. CD4 -26 developed a tubing x Inner Annulus pressure communication in February 2017 and on June 15, 2017 the AOGCC issued AIO 18C.013. AOGCC determined that water injection could safely continue if CPAI complied with the restrictive conditions set out in AA AIO 18C.013. CPAI has repaired the well in February 2019 with new gas tight tubing and a production packer installed under Sundry 318-531. A passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on February 20, 2019 indicates that CD4 -26 exhibits at least two competent barriers to the release of well pressure. AA AIO 18C.013 is no longer necessary to the operation of CD4 -26 and is hereby CANCELLED. AIO 18C.013 Cancellation February 26, 2019 Page 2 of 2 DONE at Anchorage, Alaska and dated February 26, 2019. Cathy 1. Foerster Commissioner &0 -- Daniel T. Seamount, Jr. Commissioner RECONSIDERATION AND APPEAL As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. TI IE STATE ,,ALASKA GOVERNOR MICHAEL 1. DUNLEAVY ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.013 CANCELLATION Ms. Sara Carlisle Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO- 19-005 Request to cancel Area Injection Order (AIO) 18C.013 Colville River Unit (CRU) C134-26 (PTD 2090490) Colville River Field Alpine Oil Pool Dear Ms. Carlisle: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 W W W.00gcc.alaska.gov By letter dated February 22, 2019, ConocoPhillips Alaska, Inc. (CPAI) requested cancellation of administrative approval (AA) Area Injection Order 18C.013. In accordance with Rule 11 of Area Injection Order (AIO) 18D.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request to cancel the AA. CD4 -26 developed a tubing x Inner Annulus pressure communication in February 2017 and on June 15, 2017 the AOGCC issued AID 18C.013. AOGCC determined that water injection could safely continue if CPAI complied with the restrictive conditions set out in AA AIO 18C.013. CPAI has repaired the well in February 2019 with new gas tight tubing and a production packer installed under Sundry 318-531. A passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on February 20, 2019 indicates that CD4 -26 exhibits at least two competent barriers to the release of well pressure. AA AIO 18C.013 is no longer necessary to the operation of CD4 -26 and is hereby CANCELLED. AIO I&C.013 Cancellation February 26, 2019 Page 2 of 2 DONE at Anchorage, Alaska and dated February 26, 2019. //signature on file// Cathy P. Foerster Commissioner //signature on file// 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. 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 he filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 V THE ST'A`ITE , ALASKA (.,()VERNOR BILL NVALKFR Ms. Rachel Kautz Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.013 Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-17-017 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov Request for administrative approval to allow well CD4-26 (PTD 2090490) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) CD4-26 (PTD 2090490) Colville River Field Alpine Oil Pool Dear Ms. Kautz: By letter dated June 13, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18C.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 February 18, 2017 while the well was on miscible gas injection. CPAI performed diagnostics including a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on February 20, 2017 which indicates that CD4-26 exhibits at least two competent barriers to the release of well pressure. CPAI WAG'ed the well to water after receiving permission from AOGCC and monitored the well for an approved 30 day period. CPAI performed a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on June 9, 2017. The well does not exhibit signs of pressure communication while on water injection. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 18C.013 June 15, 2017 Page 2 of 2 AOGCC's approval to continue water injection only in CRU CD4-26 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi; 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The next required MIT is to be before or during the month of June 2019. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated June 15, 2017. //signature on file// //signature on file// //signature on file// 9roN Cathy P. Foerster Daniel T. Seamount, Jr. Hollis S. 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. 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 N/ ��'e CL Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, June 15, 2017 3:02 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; AKDCWeIIIntegrityCoordinator; 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; ddonkel@cfl.rr.com; DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Elwood Brehmer; Evan Osborne; Evans, John R (LDZX); George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff, Hunter Cox; Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jason Brune; 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; Mike Morgan; MJ Loveland; mkm7200; Motteram, Luke A; Mueller, Marta R (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick Ostrovsky; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan Yanish; Richard Cool; Robert Brelsford; 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; Tom Maloney; trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Well Integrity; Well Integrity; Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andy Bond; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff 1 (DNR); Casey Sullivan; Corey Munk; David Tetta; Don Shaw; Eppie Hogan ; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Shine, Jim M (DNR); Joe Longo; John Martineck, Josh Kindred; Keith Lopez; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Melonnie Amundson; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Rachel Davis; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW); William Van Dyke Subject: AIO 18C.013 (CPA) Attachments: aiol8C.013.pdf Please see attached. Re: Docket Number: AIO-17-017 Request for administrative approval to allow well CD4-26 (PTD 2090490) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) CD4-26 (PTD 2090490) Colville River Field Alpine Oil Pool Jody J. Cotombie AOGCC SpeciatAssistant A(aska Oit and Gas Conservation Commission 333 West 711 .Avenue .anchorage, Alaska 99501 Office: (907) 793-1221 Fax: (907) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iodv.colombie@alaska.gov. THE STATE ALASKA GOVERNOR BILL WALKER Ms. Rachel Kautz Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18C.003 Amended Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: A10-1 8-009 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.gov Request for administrative approval to allow well CD4 -17 (PTD 2061180) to be online in water only injection service with a known tubing by inner annulus communication and a known surface casing leak to atmosphere. Colville River Unit (CRU) C134-17 (PTD 2061180) Colville River Field Alpine Oil Pool Dear Ms. Kautz: By letter dated February 17, 2018, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to amend conditions of AID 18C.003 and continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18C.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 completed a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on February 3, 2018 which indicates that CD4 -17 exhibits at least two competent barriers to the release of well pressure. The well does not exhibit signs of tubing by inner annulus pressure communication while on water injection. The well does not exhibit signs of a surface casing leak to atmosphere if the OA is managed below approximately 200 psi. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 18C.003 Amended February 28, 2018 Page 2 of 2 AOGCC's approval to continue water injection only in CRU CD4 -17 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 Possible and not to exceed 150 psi• 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The next required MIT is to be before or durine the month of June 2019 This is to align with the agreed upon CPAI Underground Iniection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated February 28, 2018. Hollis S. French Chair, Commissioner 4 LP� Cathy/P. Foerster Daniel T. Seamount, Jr. r; Commissioner Commissioner RLUUNSIDEKATION AND APPEAL NOTICE I 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 me 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 ran is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711 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 Fairbanks, AK 99706 INDEXES 25 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 June 5, 2023 Commissioner Jessie Chmielowski Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Commissioner Chmielowski: ConocoPhillips Alaska, Inc. (CPAI) presents the attached cancellation request for Administrative Approval AIO 18C.009. CRU CD3-128 (PTD 211-037-0) was granted AIO 18C.009 on April 26, 2016, due to known TxIA communication. A RWO was completed in March of 2023. After the RWO, the well completed a monitor period on gas injection and no TxIA communication was observed, proving the RWO repaired the annular communication. AIO 18C.009 is no longer needed. CPAI requests that AIO 18C.009 be canceled and that CD3-128 be returned to normal WAG operation. If you need additional information, please contact us at your convenience. Sincerely, Kate Dodson Senior Well Integrity Engineer ConocoPhillips Alaska, Inc. Office phone: 907-265-6181 Email: kate.dodson@conocophillips.com Kate Dodson Digitally signed by Kate Dodson Date: 2023.06.05 16:45:01 -08'00' CD3-128 90-Day Bleed History WELL DATE STR-PRES END-PRES DIF-PRES CASING CD3-128 2023-04-02 750.0 172 -578.0 IA CD3-128 2023-04-12 1061.0 700 -361.0 OA CD3-128 2023-04-12 1380.0 1600 220.0 IA CD3-128 2023-04-30 1977.0 1375 -602.0 IA Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: SLM 12,822.0 CD3-128 8/14/2012 osborl Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Post Rig, SOV/DMY, Pull RBP, Pull XX plug, SBHP, Set Inj Valve CD3-128 3/30/2023 oberr Notes: General & Safety Annotation End Date Last Mod By NOTE: Well suspended after original drill/completion 2011; re-entered and drilled deeper, WO, 2012 2/21/2012 osborl General Notes: Last 3 entries Com Date Last Mod By Slickline was unable to pass throught the seal bore assembly with a 2.77 od drift. Ran a 2.77 od comression block and didnt see anything to determine the issue. Ran 2.74 od drift successfully. Ran 2.725 max od rbp and set without issue. 3/18/2023 d142cm Casing Strings Csg Des OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread CONDUCTOR INS. 42" 16 15.25 36.8 114.0 114.0 62.50 H-40 WELDED SURFACE 9 5/8 8.92 36.4 2,989.0 2,451.1 36.00 J-55 BTC-M PRODUCTION 7 6.28 32.8 13,009.0 6,980.4 26.00 L-80 BTC-M OPEN HOLE 6 1/8 18,685.0 20,387.0 7,082.6 LINER 4 1/2 3.96 12,694.7 18,685.0 7,061.9 12.60 L-80 IBTM Tubing Strings: string max indicates LONGEST segment of string Top (ftKB) 32.4 Set Depth … 12,324.0 Set Depth … 6,751.6 String Ma… 3 1/2 Tubing Description Tubing – Gas Injection Wt (lb/ft) 9.20 Grade L-80 Top Connection Hyd563 ID (in) 2.99 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 2,188.8 2,020.5 48.37 Nipple - Landing 3.500 3.5" MCX / 2.81" X-Lock set 3/30/23 HES X Nipple 2.813 12,241.2 6,710.8 60.68 Mandrel – GAS LIFT 3.500 Camco KBG-2 GLM 2.992 12,305.0 6,742.2 60.45 Seal assembly 3.500 H453-01-0065 - Part No. GBH-22 (Baker) Bonded locating seal assembl y 2.992 Top (ftKB) 12,287.8 Set Depth … 12,738.5 Set Depth … 6,926.0 String Ma… 3 1/2 Tubing Description Tubing - Production Wt (lb/ft) 9.30 Grade L-80 Top Connection EUE Mod ID (in) 2.99 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 12,287.8 6,733.7 60.29 PBR 5.020 BAKER 20' 80-40 PBR Baker 80-40 4.000 12,310.9 6,745.2 60.51 PACKER 5.960 BAKER PREMIER PACKER Baker Premier 2.970 12,353.5 6,766.0 60.89 NIPPLE 4.500 HES X NIPPLE Halliburt on X 2.813 12,396.2 6,786.6 61.33 GAS LIFT 5.390 CAMCO, KBMG GLM CAMCO KBMG 2.920 12,447.7 6,811.1 61.94 BLAST RING 4.000 SCC TUBING w/ BLAST RING INSTALLED, TOP 2.992 12,476.7 6,824.7 62.36 BLAST RING 4.000 SCC TUBING w/ BLAST RING INSTALLED, BOTTOM 2.992 12,545.9 6,855.5 64.66 SLEEVE-C 4.500 BAKER CMD SLIDING SLEEVE w/ 2.812" X PROFILE (CLOSED 5/25/2013) - ATTEMPTED TO OPEN SLEEVE, 4280 KEYS DID NOT ENGAGE; UNCERTAIN IF SLEEVE OPENED OR CLOSED (8/13/2013) 2.810 12,596.0 6,876.3 66.29 PACKER 5.970 BAKER PREMIER PACKER Baker Premier 2.870 12,665.4 6,902.5 69.60 NIPPLE 4.500 HES XN NO GO NIPPLE Halliburt on XN 2.750 12,704.2 6,915.5 71.33 LOCATOR 5.010 GBH-22 LOCATOR SPACED OUT 2' ABOVE FULLY LOCATED Baker GBH-22 2.960 12,727.1 6,922.6 72.41 SEAL ASSY 3.990 SPACER TUBE SEAL SUB Baker 3.000 12,736.5 6,925.4 72.87 SEAL ASSY 3.980 LOWER SEAL SUBS Baker 3.000 12,738.0 6,925.9 72.94 SHOE 3.980 MULE SHOE Baker 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 2,188.8 2,020.5 48.37 INJ VALVE 3.5" MCX on 2.81" X-lock Halliburt on MCX 43016 35-1 3/30/2023 1.100 Mandrel Inserts : excludes pulled inserts Top (ftKB) Top (TVD) (ftKB) Top Incl (°) St ati on No /S Serv Valve Type Latch Type OD (in) TRO Run (psi) Run Date Com Make Model Port Size (in) 12,241.2 6,710.8 60.68 1 DMY BK 1 0.0 3/25/2023 CAMCO KBMG 0.000 12,396.2 6,786.6 61.33 4 GAS LIFT DMY BK 1 0.0 5/7/2013 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 12,694.7 6,912.4 70.90 SLEEVE 5.790 HRD LINER SETTING SLEEVE 5.250 HORIZONTAL, CD3-128, 3/31/2023 8:23:46 AM Vertical schematic (actual) OPEN HOLE; 18,685.0-20,387.0 OPEN HOLE; 18,685.0-20,387.0 LINER; 12,694.7-18,685.0 Shoe; 18,678.0-18,685.0 Perf Pups; 18,633.4-18,637.8 PERFP; 18,633.0-18,637.0 Perf Pups; 18,266.2-18,270.6 PERFP; 18,266.0-18,270.0 Perf Pups; 17,903.8-17,908.2 PERFP; 17,904.0-17,908.0 PERFP; 17,541.0-17,546.0 Perf Pups; 17,541.1-17,545.8 Perf Pups; 17,172.6-17,177.3 PERFP; 17,172.0-17,177.0 Perf Pups; 16,803.9-16,808.7 PERFP; 16,804.0-16,808.0 FRAC; 13,217.0 Perf Pups; 16,440.5-16,445.3 PERFP; 16,440.0-16,445.0 Perf Pups; 16,070.7-16,075.4 PERFP; 16,070.0-16,075.0 Perf Pups; 15,705.9-15,710.7 PERFP; 15,705.0-15,710.0 Perf Pups; 15,342.3-15,347.1 PERFP; 15,342.0-15,347.0 Perf Pups; 14,975.7-14,980.5 PERFP; 14,975.0-14,980.0 Perf Pups; 14,611.7-14,616.5 PERFP; 14,611.0-14,616.0 Perf Pups; 14,236.4-14,241.2 PERFP; 14,236.0-14,240.0 Perf Pups; 13,875.9-13,880.7 PERFP; 13,875.0-13,880.0 Perf Pups; 13,508.1-13,512.9 PERFP; 13,508.0-13,512.0 Perf Pups; 13,217.9-13,222.7 PERFP; 13,217.0-13,222.0 Swell Packer; 13,123.3-13,128.9 Swell Packer; 13,068.8-13,074.4 PRODUCTION; 32.8-13,009.0 Float Shoe; 13,006.9-13,009.0 Float Collar; 12,922.0-12,923.0 Landing Collar; 12,880.0- 12,881.0 SHOE; 12,738.0 SEAL ASSY; 12,736.5 SBE; 12,718.8-12,742.9 SEAL ASSY; 12,727.1 HANGER; 12,709.5-12,718.8 NIPPLE; 12,706.9-12,709.5 LOCATOR; 12,704.2 SLEEVE; 12,694.7-12,707.0 NIPPLE; 12,665.4 PACKER; 12,596.0 SLEEVE-C; 12,545.9 RPERF; 12,476.0-12,496.0 GAS LIFT; 12,396.2 NIPPLE; 12,353.5 PACKER; 12,310.9 Seal assembly; 12,305.0 PBR; 12,287.8 Mandrel – GAS LIFT; 12,241.2 CEMENTER; 7,229.5-7,232.0 SURFACE; 36.4-2,989.0 Float Shoe; 2,986.7-2,989.0 Float Collar; 2,910.9-2,912.1 INJ VALVE; 2,188.8 Nipple - Landing; 2,188.8 CONDUCTOR INS. 42"; 36.8- 114.0 Casing Hanger; 36.4-38.6 HANGER; 32.8-35.4 WNS INJ KB-Grd (ft) 36.80 RR Date 4/30/2011 Other Elev… CD3-128 ... TD Act Btm (ftKB) 20,387.0 Well Attributes Field Name FIORD NECHELIK Wellbore API/UWI 501032063800 Wellbore Status INJ Max Angle & MD Incl (°) 91.79 MD (ftKB) 19,230.70 WELLNAME WELLBORECD3-128 Annotation Last WO: End Date 3/11/2023 H2S (ppm) DateComment SSSV: TRDP Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 12,706.9 6,916.4 71.45 NIPPLE 5.000 RS PACK-OFF SEAL NIPPLE Baker RS 4.250 13,068.8 6,986.3 85.44 Swell Packer 4.500 TAM FREECAP SWELL PACKER FSC-11 w/ 5.875" OD CEMENTRALIZER TAM 3.920 13,123.3 6,989.7 87.36 Swell Packer 4.500 TAM FREECAP SWELL PACKER FSC-11 w/ 5.875" OD CEMENTRALIZER TAM 3.920 13,174.1 6,991.3 88.90 XO THREAD 4.500 Crossover 4-1/2" 12.6 ppf L-80 SLHT x 4-1/2" 12.6 ppf L-80 IBTM 3.958 18,685.0 7,061.9 89.51 OPEN HOLE 6.125 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 12,476.0 12,496.0 6,824.3 6,833.5 Kuparuk, CD3- 128 5/5/2011 12.0 RPERF 4 5/8" 39 gm, 60 deg phase 13,217.0 13,222.0 6,991.7 6,991.7 Nechelik, CD3- 128 2/22/2012 1.0 PERFP 4.78' PERF PUPS 13,508.0 13,512.0 6,991.7 6,991.7 Nechelik, CD3- 128 2/22/2012 1.0 PERFP 4.78' PERF PUPS 13,875.0 13,880.0 7,000.4 7,000.6 Nechelik, CD3- 128 2/22/2012 1.0 PERFP 4.78' PERF PUPS 14,236.0 14,240.0 7,007.4 7,007.5 Nechelik, CD3- 128 2/22/2012 1.0 PERFP 4.78' PERF PUPS 14,611.0 14,616.0 7,014.2 7,014.2 Nechelik, CD3- 128 2/22/2012 1.0 PERFP 4.78' PERF PUPS 14,975.0 14,980.0 7,015.6 7,015.6 Nechelik, CD3- 128 2/22/2012 1.0 PERFP 4.78' PERF PUPS 15,342.0 15,347.0 7,017.5 7,017.6 Nechelik, CD3- 128 2/22/2012 1.0 PERFP 4.78' PERF PUPS 15,705.0 15,710.0 7,023.3 7,023.4 Nechelik, CD3- 128 2/22/2012 1.0 PERFP 4.78' PERF PUPS 16,070.0 16,075.0 7,023.8 7,023.9 Nechelik, CD3- 128 2/22/2012 1.0 PERFP 4.78' PERF PUPS 16,440.0 16,445.0 7,034.3 7,034.4 Nechelik, CD3- 128 2/22/2012 1.0 PERFP 4.78' PERF PUPS 16,804.0 16,808.0 7,042.3 7,042.3 Nechelik, CD3- 128 2/22/2012 1.0 PERFP 4.78' PERF PUPS 17,172.0 17,177.0 7,044.3 7,044.3 Nechelik, CD3- 128 2/22/2012 1.0 PERFP 4.78' PERF PUPS 17,541.0 17,546.0 7,046.4 7,046.5 Nechelik, CD3- 128 2/22/2012 1.0 PERFP 4.78' PERF PUPS 17,904.0 17,908.0 7,049.1 7,049.2 Nechelik, CD3- 128 2/22/2012 1.0 PERFP 4.78' PERF PUPS 18,266.0 18,270.0 7,052.6 7,052.7 Nechelik, CD3- 128 2/22/2012 1.0 PERFP 4.78' PERF PUPS 18,633.0 18,637.0 7,061.5 7,061.6 Nechelik, CD3- 128 2/22/2012 1.0 PERFP 4.78' PERF PUPS Stimulation Intervals Top (ftKB) Btm (ftKB) Inter val Num ber Type Subtype Start Date Proppant Designed (lb) Proppant Total (lb) Vol Clean Total (bbl) Vol Slurry Total (bbl) 13,217.0 20,387.0 1 FRAC 3/9/2012 0.0 0.00 0.00 HORIZONTAL, CD3-128, 3/31/2023 8:23:47 AM Vertical schematic (actual) OPEN HOLE; 18,685.0-20,387.0 OPEN HOLE; 18,685.0-20,387.0 LINER; 12,694.7-18,685.0 Shoe; 18,678.0-18,685.0 Perf Pups; 18,633.4-18,637.8 PERFP; 18,633.0-18,637.0 Perf Pups; 18,266.2-18,270.6 PERFP; 18,266.0-18,270.0 Perf Pups; 17,903.8-17,908.2 PERFP; 17,904.0-17,908.0 PERFP; 17,541.0-17,546.0 Perf Pups; 17,541.1-17,545.8 Perf Pups; 17,172.6-17,177.3 PERFP; 17,172.0-17,177.0 Perf Pups; 16,803.9-16,808.7 PERFP; 16,804.0-16,808.0 FRAC; 13,217.0 Perf Pups; 16,440.5-16,445.3 PERFP; 16,440.0-16,445.0 Perf Pups; 16,070.7-16,075.4 PERFP; 16,070.0-16,075.0 Perf Pups; 15,705.9-15,710.7 PERFP; 15,705.0-15,710.0 Perf Pups; 15,342.3-15,347.1 PERFP; 15,342.0-15,347.0 Perf Pups; 14,975.7-14,980.5 PERFP; 14,975.0-14,980.0 Perf Pups; 14,611.7-14,616.5 PERFP; 14,611.0-14,616.0 Perf Pups; 14,236.4-14,241.2 PERFP; 14,236.0-14,240.0 Perf Pups; 13,875.9-13,880.7 PERFP; 13,875.0-13,880.0 Perf Pups; 13,508.1-13,512.9 PERFP; 13,508.0-13,512.0 Perf Pups; 13,217.9-13,222.7 PERFP; 13,217.0-13,222.0 Swell Packer; 13,123.3-13,128.9 Swell Packer; 13,068.8-13,074.4 PRODUCTION; 32.8-13,009.0 Float Shoe; 13,006.9-13,009.0 Float Collar; 12,922.0-12,923.0 Landing Collar; 12,880.0- 12,881.0 SHOE; 12,738.0 SEAL ASSY; 12,736.5 SBE; 12,718.8-12,742.9 SEAL ASSY; 12,727.1 HANGER; 12,709.5-12,718.8 NIPPLE; 12,706.9-12,709.5 LOCATOR; 12,704.2 SLEEVE; 12,694.7-12,707.0 NIPPLE; 12,665.4 PACKER; 12,596.0 SLEEVE-C; 12,545.9 RPERF; 12,476.0-12,496.0 GAS LIFT; 12,396.2 NIPPLE; 12,353.5 PACKER; 12,310.9 Seal assembly; 12,305.0 PBR; 12,287.8 Mandrel – GAS LIFT; 12,241.2 CEMENTER; 7,229.5-7,232.0 SURFACE; 36.4-2,989.0 Float Shoe; 2,986.7-2,989.0 Float Collar; 2,910.9-2,912.1 INJ VALVE; 2,188.8 Nipple - Landing; 2,188.8 CONDUCTOR INS. 42"; 36.8- 114.0 Casing Hanger; 36.4-38.6 HANGER; 32.8-35.4 WNS INJ CD3-128 ... WELLNAME WELLBORECD3-128 Submit to: OOPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2110370 Type Inj G Tubing 3744 3745 3745 3745 Type Test P Packer TVD 6745 BBL Pump 2.0 IA 1180 2500 2460 2450 Interval I Test psi 1686 BBL Return 2.2 OA 854 960 959 960 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD 5448 BBL Pump IA Interval Test psi 1500 BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting ConocoPhillips Alaska Inc, Alpine / CRU / CD3 PAD Austin McLeod Hills / Hembree 04/12/23 Notes:Initial MITIA post RWO, currently operating under AIO 18C.009. Submitall for AA cancellation to follow passing MITIA and 30 day monitor on gas injection. Notes: Notes: Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMechanic al Integri ty Tes t jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: CD3-128 Form 10-426 (Revised 01/2017)MIT CRU CD3-114 and 128 04-12-23.xlsx 24 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 April 24, 2023 Commissioner Jessie Chmielowski Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Commissioner Chmielowski, ConocoPhillips Alaska, Inc. submits the attached application to amend administrative approval AIO18C.008 to allow CRU injection well CD4-27 (PTD 211-146) to allow water alternating gas (WAG) injection. The well currently has known tubing by inner annulus communication only while on gas injection. Please contact me at 907-265-6181 if you have any questions. Sincerely, Kate Dodson Well Integrity Specialist ConocoPhillips Alaska, Inc. Kathleen Dodson Digitally signed by Kathleen Dodson Date: 2023.04.27 13:30:52 -08'00' P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Well Integrity Specialist 4/24/2023 1 Alpine Well CD4-27 (PTD 211-146) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. requests AOGCC amend Administrative Relief Area Injection Order 18C.008, to allow water alternating gas (WAG) injection for Colville River Unit injection well CD4-27 (PTD 211-146). The well displays tubing by inner annulus (IA) communication only during gas injection (MI). Well History and Status Colville River Unit injector CD4-27 was reported to the Commission on December 24, 2015, for a suspect IA pressure increase while on miscible gas injection. AOGCC approved diagnostic monitor periods for both MI and water injection services, which confirmed the tubing to IA communication only existed during MI injection. Early in 2023, CPAI discovered a significant benefit to maintaining gas injection in to CD4-27. CPAI conducted diagnostics including SCLD, packoff tests and MITIA, and confirmed the well’s integrity. Barrier and Hazard Evaluation Tubing:The 4-1/2”, 12.6 lb/ft, L-80 grade tubing has integrity to the packer at 12,796’MD (7412' TVD) based on passing a MIT-IA to 4200 psi on 3/25/2023. Intermediate 2 casing:The 7”, 26 lb/ft, L-80 grade intermediate casing has integrity to the packer at 12,796’MD (7412' TVD) based on the previously mentioned MIT-IA and TIO trends. Intermediate 1 casing:The 9-5/8”, 40 lb/ft, L-80 grade intermediate casing has an internal yield pressure rating of 5750 psi.intermediate casing has integrity to the packer at 12,796’ MD (7412' TVD) based on the previously mentioned MIT-IA and TIO trends. Surface casing:The 11-3/4”, 60 lb/ft, L-80 grade surface casing has an internal yield pressure rating of 5830 psi. The surface casing has integrity based on TIO trends. Primary barrier:The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Secondary barrier:The intermediate 2 casing is the secondary barrier should the tubing fail. Tertiary barrier:The surface casing and intermediate 1 will act as a third barrier in the unlikely case that the first two normal barriers have failures. Monitoring:Each well is monitored daily for wellhead pressure changes. Should leaks develop in the completion it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. TIO trends are compiled, reviewed, and submitted to the AOGCC for review monthly. P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Well Integrity Specialist 4/24/2023 2 Proposed Operating and Monitoring Plan 1. Well will be used for water alternating gas injection. 2. Perform a passing MITIA every 2-years to maximum anticipated injection pressure. 3. Allow operating IA pressure up to 2,400 psi during gas injection service and 2,000 psi during water injection service. The operating OA pressure is allowed up to 1,000 psi. 4. Pressure transmitters will be maintained on the IA and OA allowing real time monitoring and alarm notifications. 5. Submit monthly reports of daily tubing, IA, and OA pressures, injection volumes and pressure bleeds for all annuli. 6. Shut-in the well if diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. 7. Maintain the injection line choke and SSV remote shut down capability. During gas injection, the inner annulus protocols will include a drill site operator alarm set at 2,200 psi, and a high alarm set at 2,400 psi that will prompt the control room Board Operator to remotely shut in the choke or SSV. 8. MIT Anniversary date will continue to be the month of June to maintain the 2-year AOGCC witnessed testing with the UIC MIT permanent 4-year scheduled pad testing. CD4-27 90-Day Bleed History WELL DATE STR-PRES END-PRES DIF-PRES CASING CD4-27 2023-03-04 14 300 286 OA Last Tag Annotation Depth (ftKB)End Date Wellbore Last Mod By Last Tag:CD4-27 osborl Last Rev Reason Annotation End Date Wellbore Last Mod By Rev Reason: Normal Up 3/25/2019 CD4-27 boehmbh Casing Strings Casing Description CONDUCTOR 30" Insulated OD (in) 16 ID (in) 15.06 Top (ftKB) 36.0 Set Depth (ftKB) 114.0 Set Depth (TVD)… 114.0 Wt/Len (l… 62.50 Grade J-55 Top Thread WELDED Casing Description SURFACE OD (in) 11 3/4 ID (in) 10.77 Top (ftKB) 36.7 Set Depth (ftKB) 3,227.8 Set Depth (TVD)… 2,377.5 Wt/Len (l… 60.00 Grade L-80 Top Thread BTCM Casing Description INTERMEDIATE 1 OD (in) 9 5/8 ID (in) 8.83 Top (ftKB) 3,067.0 Set Depth (ftKB) 10,905.0 Set Depth (TVD)… 6,448.7 Wt/Len (l… 40.00 Grade L-80 Top Thread Hyd.521 Casing Description INTERMEDIATE 2 OD (in) 7 ID (in) 6.28 Top (ftKB) 33.8 Set Depth (ftKB) 13,064.0 Set Depth (TVD)… 7,529.0 Wt/Len (l… 26.00 Grade L-80 Top Thread BTCM Casing Description OPEN HOLE OD (in) 6.151 ID (in)Top (ftKB) 15,179.0 Set Depth (ftKB) 16,878.0 Set Depth (TVD)…Wt/Len (l…Grade Top Thread Casing Description LINER OD (in) 4 1/2 ID (in) 3.96 Top (ftKB) 12,795.5 Set Depth (ftKB) 15,179.0 Set Depth (TVD)… 7,516.6 Wt/Len (l… 12.60 Grade L-80 Top Thread SLHT Liner Details Top (ftKB)Top (TVD) (ftKB)Top Incl (°)Item Des Com Nominal ID (in) 12,795.5 7,412.260.21 PACKER BAKER HRD ZXP LINER TOP PACKER 5.500 12,821.3 7,425.060.25HANGER BAKER FLEX LOCK HANGER 5.510 12,886.4 7,457.1 60.84 NIPPLE HES 'XN' NO GO NIPPLE 3.725 13,038.4 7,522.5 73.15 Swell Packer TAM SWELL PACKER FREECAP-1 FSC-14 3.960 13,596.9 7,519.7 92.72 Swell Packer TAM SWELL PACKER FREECAP-1 FSC-14 3.960 Tubing Strings Tubing Description TUBING String Ma… 4 1/2 ID (in) 3.96 Top (ftKB) 22.1 Set Depth (ft… 12,814.5 Set Depth (TVD) (… 7,421.6 Wt (lb/ft) 12.60 Grade L-80 Top Connection HYD.563 Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Item Des Com Nominal ID (in) 22.122.10.00 HANGER FMC TUBING HANGER 3.958 2,381.5 1,944.0 59.48 NIPPLE BAL-0 LANDING NIPPLE 3.812 12,799.3 7,414.1 60.22 LOCATOR MECHANICAL COLLAR LOCATOR 3.850 12,800.1 7,414.5 60.22 SEAL ASSY BAKER BULLET TIEBACK SEAL ASSEMBLY with 1/2 MULE SHOE 3.850 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Des Com Run Date ID (in)SN 2,381.5 1,944.1 59.48 INJ VALVE MODIFIED 4.5'' A-1 INJ VLV ON 3.81'' DB LOCK ( SN: HRS-48 / FREUDENBURG PACKING & CHEVRON BOTTOM / 73'' OAL ) 3/25/2019 1.250 13,150. 0 7,539.8 87.55 FISH LOST 7' X .875" PRONG BELOW 13147' SLM 11/2/2012 0.000 Perforations & Slots Top (ftKB)Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB)Linked Zone Date Shot Dens (shots/ft )Type Com 13,742.0 14,865.0 7,511.6 7,507.0 4/24/2012 32.0 SLOTS SLOTTED LINER 15,149.015,179.0 7,515.4 7,516.6 4/24/2012 32.0SLOTSSLOTTED LINER Mandrel Inserts St ati on N o/Top (ftKB) Top (TVD) (ftKB)Make Model OD (in)Serv Valve Type Latch Type Port Size (in) TRO Run (psi)Run Date Com 1 5,167.3 3,395.0 CAMCO KBG-2 1 GAS LIFT DMY BK 0.000 0.0 7/15/2012 2 9,313.5 5,609.2 CAMCO KBG-2 1 GAS LIFT DMY BK 0.000 0.09/9/2017 3 12,730.6 7,379.9 CAMCO KBG-2 1 GAS LIFT DMY BK 0.000 0.03/13/2019 Notes: General & Safety End Date Annotation 4/26/2012 NOTE: WELL SIDETRACKED, WINDOW @ 12938' w/ORIGINAL API#, PULLED KILL STRING HORIZONTAL, CD4-27, 5/29/2020 11:18:27 AM Vertical schematic (actual) OPEN HOLE; 15,179.0-16,878.0 LINER; 12,795.5-15,179.0 SLOTS; 15,149.0-15,179.0 SLOTS; 13,742.0-14,865.0 FISH; 13,150.0 INTERMEDIATE 2; 33.8- 13,064.0 SEAL ASSY; 12,800.1 LOCATOR; 12,799.3 GAS LIFT; 12,730.6 INTERMEDIATE 1; 3,067.0- 10,905.0 GAS LIFT; 9,313.5 GAS LIFT; 5,167.3 SURFACE; 36.7-3,227.8 INJ VALVE; 2,381.5 NIPPLE; 2,381.5 CONDUCTOR 30" Insulated; 36.0-114.0 HANGER; 22.1 WNS INJ KB-Grd (ft)Rig Release Date 4/28/2012 CD4-27 ... TD Act Btm (ftKB) 16,878.0 Well Attributes Field Name ALPINE Wellbore API/UWI 501032064400 Wellbore Status INJ Max Angle & MD Incl (°) 94.63 MD (ftKB) 13,290.94 WELLNAME WELLBORE Annotation Last WO: End DateH2S (ppm)DateComment SSSV: WRDP Submit to: OOPERATOR: FFIELD / UNIT / PAD: DDATE: OOPERATOR REP: AAOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2111460 Type Inj W Tubing 1525 1525 1525 1525 Type Test P Packer TVD 7412 BBL Pump 5.0 IA 62 4200 4170 4160 Interval O Test psi 1853 BBL Return 5.0 OA 285 373 373 373 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: ConocoPhillips Alaska Inc. ALPINE / CRU / CD4 PAD Brendan Weimer 03/25/23 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMec h an ic al Integ rit y Tes t jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov CD4-27 Notes:Non-witnessed diagnostic MITIA 23 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 April 2, 2019 Commissioner Hollis S. French Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RECEIVED APR 0 4 2019 AOGCC Re: Request to Cancel Area Injection Order (AIC) 18C.006 for Colville River Unit (CRU) C131-14 (PTD 201-038) Dear Commissioner French, ConocoPhillips requests cancellation of Administrative Approval AIO 18C.006. The approval was originally issued November 23, 2015 to allow dry gas injection into CRU CD1-14 (PTD 201-038) with known tubing to inner annulus (IA) communication. In March of 2019, a new gas-tight tubing and production packer completion was installed during a rig workover to restore integrity to Alpine's Blackstart well. A passing MITIA to 3,000 psi post -rig confirmed integrity. This request is to cancel the Administrative Approval and return the well to normal water alternating gas injection and blackstart operations. Please call Rachel Kautz or myself at 659-7126 if you have any questions. Sincerely, Sara Carlisle Well Integrity Supervisor ConocoPhillips Alaska, Inc. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: iim.reon0alaska.aov: AOGCC.Insoectors(d)alaska.aov: Dhoetle.brooks(rDalaskaociv OPERATOR: ConocoPhillips Alaska Inc, FIELD f UNIT / PAD: Alpine / CRU / CD1 Pad DATE: 03/27/19 OPERATOR REP: Greg Clayton AOGCC REP: O = Other (describe in Notes) chris.wallaceidialaska.nov Well CD1-14 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. O = Other (describe in Notes) 4 = Four Year Cycle PTD 2010380 Type Inj G Tubing 728 884 889 882 0= Other (describe in notes) Type Test P Packer ND 6666 BBL Pump 4.5 IA 137 3010 2920 2902 Interval O Test psi 1667 BBL Return OA 626 835 835 836 Result P Notes: Post ng workover MIT -IA. Not witnessed. Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer ND BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer ND BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 3D Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer ND BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer ND BBL Pump IA Interval Test psi BBL Return OA Result Notes: TYPE INJ Cotles TYPE TEST Codes INTERVAL Cases Result Cotles W=Water P=Pressure Test I=Initial Test P=Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S=Stu, V= Requires by Variance 1=Inconclusive I = Industrial Wastewater 0= Other (describe in notes) N = Not Inleotin9 Form 10-426 (Revised 01/2017) MITCRU ODI -14 OS-27-19.xsx WNS INJ WELLNAME CD1-14 WELLBORE CD1-14 Cono( Phillips Alaska. IRS. Well Attributes Max Angle & MD TD Fie WNIOo11-me ncl l') mO XKH) pct S. ISIS) Gieltl Name 'H ALPINE 501032037100 INJ 5.01 14,18199 18,939.0 Comment m5 hom) Date Mndatlon Entl Dale NeGra lX) Rlg Release Dem SSSV: WRDP Last WO: 4/16120, 21.65 5/1112001 CDt-1 p.INd 19 v:39'.25AM Last Tag VenkN eclumefio leafuetl Annod[bn Depm(IIKe) End Data WintersLeetMM By Last Tag ULM 13.420.0 2'1412018 1D1-14 boebmbb Last Rev Reason Wnper:3a.3 AnnolalNn End Data Wall.. De Motl By Rev Reason Post Rig Wart olk CD1-14 Car, Casing Strings Casing De==riplion o011n) ID(in) Top InKH) semeVm XlxHl sal 0epinlrvDl... wuLen 11 Grade iop Tnreaa CONDUCTOR 16 15.06 37.0 115.0 115.0 62.58 H40 WELDED Set Deo p... Grade TM1reatl CURT Descnplion OD (in)10(1n) Top IKKa) sH De5In IXKe) 2,366.0 rvDl... 95/in) 8.92 36.8 3566.5 40.00 L-80 BTC -MOD SURFACE 4DEO0 B CONWCTOR:3]6f1S0 Casing Description OD lin) ID lint Top IXKBI Set O.WUNIKB) set Depth l�Dl... Wtlten(I... Grade Top TMeM INTERMEDIATE ] 6.28 34.4 14,073.1 6.855.1 2600 L-80 BTCM Casing Description OD Bn IOlin) Top(11KH) set Depin IXK01 set Depth I TVDI.. WPLmr IF. G,ade Top Threat Oa Nipple 2]185 OPEN HOLE 6118 140>30 18939.0 68137 Tubing Strings Persupplaaa2l o o e Tuning De:cdPtmn sirma lvs..mPn) rop lnkH) sei Depth ln_ sr D, Pin I TV,) L.. Wt lhml Grace Top ConnikEp" 4.5"Completion 41/2 3.96 34.3 13,350.5 6.659.5 12.60 L-80 Hytl 563 TheremF 2,324.1 Production Completion Details T pPpml Nominal Too(1IKH11.1 Rem Des Com ID ImI 34.30.12 Hanger FMCHorixonlalGen111"x4-1/2-tuhln9hingelddfied3.885' 3.958 $319.565.63 DB Nipple Camro4-i/2" x 3.8]5" 0&6 landing nipple 3.815 . 1. 65.4 Ported Nipple CamcD4-117-II Chemical Injection nipple 3.883 susmCE: 3e",r I- 2,324.165.6] TRSSSV Cameo TRM4E SSSV w/3.813- integral X nipple Vam Top box x 3,813 16,�8.163.03 Vam Top pin 13,325.463.03 XNipple Cameo4-1,2' x 3.813" X landing nipple 3.813 13.343.4 63.22 Baker Perorb, Baker] -x4.5" non waling tubing stub Ovempoi (619Swa11ow) 4.670 Overshot iudrq Desnigron Sbinp Ma... 10 (in) Top IXKB) Set OepIM1 IX.. Set Cepin PND)(... WtIId10 Grade Top Connmtion TUBING ORIGINAL 41/2 3.96 13.339.0 13421.3 66908 12.60 1.80 IBTM Completion Details rop mot ToPlnd Dnmmal Tap IXKBI IXKe) PI Item Des Com lO lint 13,3661 6.666.0 63.49 PACKER BANEH 1-3 PACKER 3.875 13.409.1 6,685.4 64.04 NIPPLE HES XN NIPPLE 3.725 13,4200 6,690.2 64.1] WLEG WIRELINE GUIDE 3.875 Graph Manan; 13Da 8 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top(WO) TOPInd Top(XKB) (XKIp l-1 Des Com Run OaM form) IJ,JbU.0 6,6 .3 63.41 EVU TBG PWG 4.5" EVO I HUIV`LUG(OAL=16') &812019 U..D PCFnr Pipes), 13.Ei9 Mandrel Inserts 51 MI N Top BeO) Veale Lakn Pod Slxe TRORUn TopIXKB IXKB) Make Mo]el OD lin) $ery TYR Type lin) psi Run Oale Co. 1326].8 66219 Cameo NBG-2 1 GAS LIFT DMY BK 3'2('2019 x Midi 1p.A Notes: General & Safety End Dale gnngNpn 61222010 NOI E: View SCIMmNIC wl Alaska SchemalicGO 12/1112015 iNuTE: Waiver TxlA Communication 115120, NOTE: GLM C/0-2 STACKS HIGH SEALABILITY FREUDENBURG PACKING FOR GAS PER PACKING MANDREL soar Framer ,gannet: 139434 PACKER 13.3p5.0 NIPPLE: 13.4nd.1 NtEG', 13.4.40 INIEflMEOIATE 34.tr1a,0]?f tsse OPEN HOLE 14.0]]0.18M,O0 - 22 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 February 22, 2019 Commissioner Hollis S. French Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 � ZfC' I� V E FEB 2 5 2019 A0GCC Re: Request to Cancel Area Injection Order (AIO) 18C.013 for Colville River Unit (CRU) CD4 -26 (PTD 209-049) Dear Commissioner French, ConocoPhillips requests cancellation of Administrative Approval NO 18C.013. The approval was originally issued June 15, 2017 to allow continued water -only injection into CRU CD4 -26 (PTD 209-049) with known tubing to inner annulus (IA) communication during gas injection. In February of 2019, a new tubing and production packer completion was installed during a rig workover to restore integrity to the injector. A passing MITIA to 3,400 psi on -rig confirmed integrity. This request is to cancel the Administrative Approval and return the well to normal injection operation. Please call Rachel Kautz or myself at 659-7126 if you have any questions. Sincerely, Sara Carlisle Well Integrity Supervisor ConocoPhillips Alaska, Inc. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: iim.reatatilalaska.aov AOGCC Inspectors alaska.gov; phoebe.brooks0alaska.tiov, OPERATOR: Conow Phillips FIELD / UNIT / PAD: CRU CD4 DATE: 02/20/19 OPERATOR REP: Kevin Barr AOGCC REP: Not Witnessed chris.wallaceaalaska oov Well CD4 -26 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min, P = Pass G=Gas PTD 209049 Type Inj W Tubing I - I - I - I - I I 1=Inconclusive I Type Test P Packer ND 7317 BBL Pump - IA 3430 3400 1 3400 Interval I Test psi 1829 BBL Return - OA - - - - Result P Notes: Post rig vrorkover MIT -IA. Test pressures originally recorded on -ng on Manin-Decker chart, so only one annulus reading per test. Well CD4 -26 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. 049 Type Inj W Tubing 4270 4160 4150 Type Test P 17 BBL Pump - IA - - - - - - Interval29 BBL Retum - OA - - - - - - Result P =TVDBBL g vorkover MIT -T. Test pressures originally recorded on -rig on Martin -Decker chart, sc only one annulus reading per test. Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Type InjTubing TypeTest BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTDType Inj Tubing Type Test Packer ND BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTDType Inj Tubing Type Test Packer ND BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G=Gas 0= 01M1er(desvibe in Notes) 4=Four Year Cycle F=Fail S=Slurry V= Required by Variance 1=Inconclusive I = Industrial Wastewater O = 00er (describe in notes) N = Not Injecting Form 10-426 (Revised 01/2017) MIT CRUCD426 02-261ealsx 21 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 December 24, 2018 Commissioner Hollis S. French Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Request to Cancel Area Injection Order (AIO) 18C.011 for Colville River Unit (CRU) CD2-78(PTD 209-066) Dear Commissioner French, ConocoPhillips requests cancellation of Administrative Approval AID 18C.011. The approval was originally issued May 22, 2017 to allow continued water -only injection into CRU CD2-78 (PTD 209-066) due to known tubing by inner annulus communication during gas injection. In November 2018, a rig workover replaced the tubing. The subsequent MITIA and gas injection monitor period have confirmed tubing integrity is restored for WAG service. This request is to cancel the Administrative Approval and return the well back to normal WAG injection operation. Please call me or Sara Carlisle at 659-7126 if you have any questions. Sincerely, Rachel Kautz Well Integrity Supervisor ConocoPhillips Alaska, Inc. ORIGINAL zo ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 February 17, 2018 Commissioner French Alaska Oil & Gas Conservation Commission 333 West 7a' Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner French: RECEIVED FEB 2 0 2018 A®GCC ConocoPhillips Alaska, Inc.. presents the attached proposal per AIO 18C, Rule 11, to apply for an amendment to the existing Administrative Approval for well CRU CD4 -17 (PTD 206-118, AIO 18C.003). AIO 18C.003 allows water -only injection into injector CD4 -17 due to tubing by inner annulus communication identified during miscible gas injection. The amendment would allow CD4 -17 to continue water -only injection service with the aforementioned tubing by inner annulus communication and a known surface casing leak to atmosphere. If you need additional information, please contact Travis Smith or myself at 659-7126. Sincerely, Rachel Kautz Well Integrity Supervisor ConocoPhillips Alaska, Inc. ConocoPhillips Alaska, Inc. Colville River Unit CD4 -17 (PTD 206-118, AIO 18C.003) Technical Justification for Request of Administrative Approval Amendment Purpose Per Area Injection Order 18C, Rule 11, ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this amendment to the Administrative Approval AIO 18C.003 which will allow continued water only injection into CRU CD4 -17. The well displays tubing by inner annulus (IA) communication only while the well is on miscible gas injection, as detailed in the existing Administrative Approval, and now has a known surface casing leak to atmosphere. Well History and Status Colville River Unit well CD4 -17 was completed in October 2006 as a service well. CD4 -17 was previously reported to AOGCC and found to have tubing by IA communication on miscible gas injection in 2015. Subsequently, ConocoPhillips Alaska, Inc. (CPAI) requested Approval for Administrative Relief to continue water only injection. Approval was granted on June 4, 2015 with AIO 18C.003. The injector was later reported to the Commission on June 21, 2015 and shut in for a surface casing leak to atmosphere. Diagnostics suggest the surface casing leak to be at —42" below the outer annulus (OA) valve and that the leak activates when the OA pressure is near 200 psi. CPAI contacted AOGCC again and received permission on November 27, 2017 to restart water injection for a 30 -day monitor period to confirm the integrity of the well. The AOGCC approved monitor period was commenced on January 18, 2018. During the monitor on water injection, a passing state -witnessed MITIA to 3300 psi was performed (see attached 10-426). No TxIA communication was observed and the surface casing leak did not appear active during the monitor period. ConocoPhillips Alaska, Inc. now requests an amendment to AIO 18C.003, which will allow water only injection into CD4 -17 with known tubing by IA communication on miscible gas injection and a known surface casing leak to atmosphere. 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 lb/ft, L-80 tubing has integrity to the packer at 11,753' MD (7130' TVD), based on passing a MIT -IA to 3300 psi on February 3, 2018 and TIO trends. Production casing: The 7", 26 lb/ft, L-80 production casing has integrity to the packer at 11,753' MD (7130' TVD) based on the aforementioned passing MIT -IA and TIO trends. Surface casing: The 9-5/8", 40 lb/ft, L-80 surface casing has a leak to atmosphere found to be at —42" below the OA valve. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Secondary barrier: The production casing is the secondary barrier should the tubing fail. Well Integrity Supervisor 2/17/2018 1 Monitoring. Each well is monitored daily for wellhead pressure changes. Should a leak develop in the tubing or production casing, or should the surface casing leak appear active, it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. TIO trends are compiled, reviewed, and submitted to the AOGCC for review 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 maximum anticipated injection pressure; 3. Allow operating IA pressure up to 2000 psi; operating OA pressure will be held as low as possible and not to exceed 150 psi; 4. Submit monthly reports of daily tubing & IA pressures, injection volumes and pressure bleeds for all annuli; 5. Shut-in the well should diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC; 6. Anniversary date to be set on the 30th of June 2019 (last AOGCC witnessed test; February 3, 2018) to align the AOGCC witnessed testing with the UIC MIT permanent 4 -year scheduled pad testing. Well Integrity supervisor 2/17/2018 WNS INJ CD4 -17 wnva yr nnar.JD even dKnnouEes Max Angle&MD ITO ((� NG, WOIIYareAPIIIIWI Fleln Neme Wellhnn BlMus ncl (°) MOIkKB1 MBM 111Kid 501032053d00 ALPINE INJ 94.27 15,04403 1],9]5.0 Comment N381ppm) pale SSSV. WEEP Anndalien End Date Leat WO: d.-Cn ) qlg A.'—.Gale 37.17 10142006 D.c17 W29TN11124x 30 PM An...on DoodI —, —Dale Anne.— Lad Last Tag: Rev Reason: PULL PLUG &GUAGES, SET XXN ppmven Med By End dab 5121 1] _. _..........._. _..... PLUG -asing ngs ,—,En. -pilo ON To' IDpnl Too(M1HB) Het DenheKB) sal OUPlh(TVD)._ wI-en B... Gaae Top Tnreed CONDUCTOR 36" 16 15.250 36.0 114.0 1160 65.00 H-40 InModeE XµGER:31.] ...in. We. W(In) ID (in) Top (MB) den vepin(ME) Sal..M27D)... IRLan 11... Gretla Tap Th,pd SURFACE 9518 BASE 338 3,009.3 2.386.8 4000 L-80 Lealnp Desniplion F. (in) Ip 6n) Top (HKB) y(paplh (flKB) BN DapN (TVD)... WVIJn Q... Gfede Top TRZo INTERMEDIgTE ] 6276 33.5 13,3362 ],490.6 26.00 L-00 Lasing 0escr1p11on pp (in) ID(in) Top (M1KB) $el0epp (ryKB) 9N Depm (rvp)... wuUnB._G,.de Top Thrtxd OPEN HOLE 6116 13.334.0 1],975.0 Tubing Strings TUOinp Dascriptinn s"n. Ma... ID (in) ToP(DKSR SSI Dap(h(nSe10ap11, 1TVD)(... W[(IERn Gnde iop Lannatllon Tubing - Water IMP 41/2 3.958 317 .. 11825.6 ],163.4 12.60 L -6o Completion Details Too (ft.) TOP TVD)RIKIU Top In=I P) done Des Com Nomin¢n0 On) Ed I seed 31.7 31.] 0.00 HANGER FMCOTUBING HANGER 3.958 2.2619 1,901.5 55.49 NIPPLE CAMCO on'NIPPLE 3.812 CONDUCTOR 36� i1e.Mad; 40.1140 11,7530 ],130.2 51.93 PACKER BAKER PREMIE PACKER 3.8]5 11,813.3 ],15].9 63.32 NIPPLE HES'XN'NIPPLE 3,]25 NIPne, zzal a 11,824.3 ],1628 63.50 WLEG WIRELINE ENTRY GUIDE 3.8]5 Other In Hole (Wireline retrievable plugs, Valves, pumps, fish, etc.) T.plrvDl Top ln=I Tap nKa) 11,613.0 (NNB ],15].0 (°) Oes Cam 6331 XXNPWG 3.61"XXN(25") Ren Do. Io(in) 5/2412017 0.000 Mandrel Inserts So .B on TRIP (TVD) N Top (6KB) (%KB) Naka Model Dp (In) Ed Valn Lalcll Typ Type p.rt81a lint TRO Run IWO Run ptla Com 1 9,119.2 5,]13] CAMCO KBG-2 1 GMS LIFT DMY BK -5 0.000 0.0 11/16200] SDRFACE; a3ea.Baai 2 11,646] ],0]85 CAMCO KBG-2 1 GAS LIFT OMY BEK-2 0.000 0.01Vi6120W Notes: General & Safety end annelMlon 101W200E NOTE:TREE: FMC 4411fi'/5,000 psi-TREECPP CONNECTION ]"OTIS 12Ifi200B NOTE: View Schematic wl glaska Schema(ic90 &9/2015 NOTE: WAIVEREDWELLTxIACOMMUNICAT(ON. WATER INJECTION ONLY. GARURT;9.1.1 GAS LIFr', 11..61 PACKER', 11,753.0 de MN PLUG: 11.813A NIPPLE: 11.8133 WLEG:1f,B1e3 a„ INTERMEDIATE', 33.513,3N.3— s OPEN HOLE:13.]34.D.1;B75.p— STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: iim.regoiSalaska aov AOGCC.InsoectorstZDalaska aovho�ebe.brooks(a)alaska.aov OPERATOR: ConomPhillips Alaska Inc FIELD/UNIT/PAD: Alpine/CRU/CD4 Pad DATE: 02/03/18 OPERATOR REP: Green / VanCamp AOGCC REP: Brian Bixbv chris wallace(ftlaska aov Well CD4 -17 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. 0= Other (describe in Notes) PTD 2061180 Type Inj W Tubing 2275 2275 2275 2275 O = Other (describe in notes) Type Test P Packer ND 7130 BBI -Pump 3.5 IA 300 3300 3260 3250 Interval V Test psi 3000 BBL Return 3.4 OA 66 345 247 203 Result P Notes: MIT -IA per AIO 18C.0O3 to maximum anticipated injection pressure Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer ND BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test BBI-Pump IA Interval turn OA Result MrVOBBL Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Inj Tubing Type Test mp IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer ND BEL IA Interval Test psi BBL Return OA Result Notes: TYPE [NJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P= Pass G=Gas 0= Other (describe in Notes) 4=Four Year Cycle F=Fal S = Sluny V= Required by Variance I = Inconclusive I = Industnal Wastewater O = Other (describe in notes) N = Not Injecting Form 10-026 (Revised 01/2017) MIT CRU CD4 -17 02-03-18.xlsx Ma 2000 1500 Fa a 1000 500 IAP I TWO Plot - C134-17 .............. ......... 1 ...................... ..... I... ... ..... ..... ...I....� 0 18 -Nov -17 01 -Dec -17 14 -Dec -17 27 -Dec -17 09 -Jan -18 22 -Jan -18 04 -Feb -18 Date 200 150 K 11 n LA 19 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 June 13, 2017 Commissioner Foerster Alaska Oil & Gas Conservation Commission 333 West 7"' Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner Foerster: RECEIVED JUN 14 2017 AAGCC ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 18C, Rule 11, to apply for administrative approval to allow CRU injection well CD4-26 (PTD 209-049) to remain in water only injection service. Currently the well has known tubing by inner annulus communication only while on miscible gas injection. Please contact Travis Smith or myself at 659-7126 if you have any questions. Sincerely, Rachel Kautz Well Integrity Supervisor ConocoPhillips Alaska, Inc. ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Alpine Well CD4-26 (PTD 209-049) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this administrative relief request as per Area Injection Order 18C, Rule 11, to continue water only injection for Colville River Unit injection well CD4-26 (PTD 209-049). The well displays tubing by inner annulus communication only while the well is on miscible gas injection. Well History and Status Colville River Unit well CD4-26 was completed in May of 2009. The well was on production initially and then converted to injection in July of 2009. CD4-26 was reported to the Commission on February 18, 2017 for a suspect inner annulus (IA) pressure increase while on miscible gas injection. Passing diagnostic wellhead pack off tests and a MITIA were performed February 20, 2017. AOGCC approved diagnostic monitor periods took place, during which the well was placed on miscible gas injection service and then water injection service. During the miscible gas injection monitor, the well continued to exhibit IA pressure increase. The well was subsequently WAG'd to water injection to confirm integrity remains on water injection. No TxIA communication was observed during the water injection period. A passing state -witnessed MITIA was performed on June 9, 2017 at the end of the monitor period to honor the scheduled MIT pad testing anniversary date. ConocoPhillips intends to pursue repairs if tubing by inner annulus communication develops while on water injection. However, at this point the well exhibits no indications of tubing by inner annulus communication while on water injection. Therefore, ConocoPhillips requests an administrative approval (AA) which will allow for continued injection of water only. 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 lb, L-80 tubing has integrity to the packer at 15,146 MD (7347' TVD), based on passing a MIT -IA to 3300 psi on June 9, 2017 and TIO trends. Production casing: The 7-5/8", 29.7 lb, L-80 production casing has integrity to the packer at 15,146 MD (7347' TVD), based on the aforementioned passing MIT -IA and TIO trends. Surface casing: The 10-3/4" 45.5 lb L-80 surface casing has an internal yield pressure rating of 5210 psi. The surface casing has integrity based on TIO trends. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Secondary barrier: The production casing is the secondary barrier should the tubing or packer fail. Well Integrity Supervisor 6/13/2017 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, AIASKA 99510-0360 Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the completion it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. TIO trends are compiled, reviewed, and submitted to the AOGCC for review 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 maximum anticipated injection pressure; 3. Allow operating IA pressure up to 2000 psi, and operating OA pressure up to 1000 psi; 4. Submit monthly reports of daily tubing & IA pressures, injection volumes and pressure bleeds for all annuli; 5. Shut-in the well should diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC; 6. Anniversary date to be set on the 30th of June 2019 (last AOGCC witnessed test: June 9, 2017) to align the AOGCC witnessed testing with the UIC MIT permanent 4-year scheduled pad testing. Well Integrity Supervisor 6/13/2017 2 A--\�\ WNS [NJ CD4-26 ConocoPhillips Well Attributes MaxAngle & MD ITD Alaska, Inc, 2'IbloreAPUUVA Field Neme Wellbore Statue 1032060000 ALPINEINJ nel(") MD(ftKB) 93.05 24,276.67 Ac e1.(IRKS) 24,749.0 mmerrt 1-125 (ppml I Date SSSV: WRDP Annolatlon Eno Date Last WO: KB-Grtl (tt) Rig Relsme Date 35.801 6/29/2009 HORIZONTAL-CD4-26, 5/17201G 15'26:46AM Vertical schema8c (ectuap Annotallon Depth (ttKB) End Data Annotation Leer Mod By End Date Last Tag: Rev Reason: Open Hole OD correction lehallf 5f17/2016 ................. HANGER; 71./ ..................................................., asm Strings 9 9 Ceaing Descrlptlon OD (In) CONDUCTOR 16 ID (In) 15.250 Top (ttKB) 37.0 Set Depth (ftK8) 114.0 Sat Depth (TVD)... 114.0 WtfLen (I... 62.60 Grade Top H-40 Thread Welded Casing Deuription OD (In) ID (In) Top (ttKB) eel Depth (ftK8) Set Depth IWO)- Wtflen (1... Grade Top Threes SURFACE 103/4 9.950 36.9 2,802.0 2,384.6 45.50 L-80 BTC-M Casing Descrlptlon 00 thl ID (In) Top (ttKB) bet Depth (ttKB) Set Depth (TVD)... Wtd.en (1... Grade Top Thread INTERMEDIATE 7518 6.875 35.6 16,559.0 7,619.6 29.70 L-80 BTCM Casing Description OD (In) ID (In) Top (ttKB) Set Depth (ftKB) Set Depth (TVD)... WtlLen (I... Grade Top Thread OPEN HOLE 6314 16.559.0 24,749.0 7,515.3 Tubing Strings Tubing Descrlptlon Sf ring Ma... ID (In) lop (RKB) bet Depth (ft. Sal Depth (TVD) (... Wt (Iblh)Grade Top Connection CONDUCTOR; 37.0-114 D TUBING 41Y2 3.958 31.4 15,279.4 7,378.1 12.60 L-80 IBT-M Completion Details Top (MR) Top (TVD) (ftK8) Top Intl (") Item Des Com Nomnal ID (in) NIPPLE; 2,169.3 WRDP, 2169.3 31.4 31.4 0.00 HANGER FMC4 1/2" TUBING HANGER 4.600 2,169.3 2,001.4 45.57 NIPPLE CAMCO DB NIPPLE 3.812 15,146.0 7,347.2 63.86 PACKER BAKER PREMIER PACKER 3.875 15,207.1 7,373.2 65.86 NIPPLE HES XN NIPPLE 3.725 15,218.0 7,377.6 66.23 1 WLEG VJIRELINE ENTRY GUIDE 3.875 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top(TVDI Top (HKB) IRKS) Top Intl 11 Des Co. Run Date ID (In) SURFACE;369-2802.0 2.169.3 2,001.4 45.57 WRDP A-1 INJECTION VALVE (SIN: H68-169) 1.25" 10/4/2014 ORIFICE 16,206.1 7,372.7 65.82 FISH BAIT SUB SET 0" GUTTED JDx4.5' G-BAIT SUB 10/11/2012 0.000 GAS LIFT; 5.400.7 15.207.1 7,373.2 65.86 FISH PERF GUNS &TRACTOR 11/11/2011 0.000 Perforations & Slots Shot Dens Top (TVD) St. (TVD) (ahotsff Top (Mil) St. (tt)(B) (HKB) (fiK81 Zone Date 1) Type Com 15,666.0 15,687.0 7,514.2 7,517.2 1/11/2011 6.0 IPERF 33/8"GUN, MILLENIUM FEEP PENETRATING CHARGES, 60 deg PHASE 16,687.0 15,708.0 7,517.2 7,519.7 1/10=11 6.0 IPERF 33/8" GUN, MILLENIUM GAS LIFT; 10.976.4 FEEP PENETRATING CHARGES, 60 deg PHASE 15,708.0 16,729.0 7,519.7 7,521.7 1/10/2011 6.0 IPERF 33/8" GUN, MILLENIUM FEEP PENETRATING CHARGES, 60 deg PHASE GAS LIFT: 15,039.0 16.729.0 15.750.0 7,521.7 7,523.3 1/9/2011 6.0 IPERF 33/8" GUN, MILLENIUM FEEP PENETRATING CHARGES, 60 deg PHASE Mandrel Inserts s PACKER; 15,148.0 ad o^ N Top (ttKB) Top (TVD) (ttKB) Make Sery Valve Type Leleh Pori Type blu TRO (in) Run (psi) Run Date Com 5,400.7 3,395.7 Camco K-GAS jG-21 LIFT DMY BK 0.000 0.0 7/5/2009 2 10,976.4 5,597.E CamcD KB GAS LIFT DMY BK 0.000 0.0 7/6/2009 3 15,039.0 7,296.3 Camco KB GAS LIFT DMY SK 0.000 0.0 7/6/2009 FISH: 15.206., Notes: General & Safety End Date Annotation FISH' 15,207.1 NIPPLE: 15,207.1 7-1 6/12/2009 NOTE: View Schematic w/Alaska Schematic9.0 WLEG; 15.218.0 IPERF; 15,666.0615,687 0 IPERF; 15,6a7.o-15,706.0 IPERF; 15,708.0-15.729.0 IPERF; 16.729.0115, 750.0 I INTERMEDIATE; 35.6-18.559.0 OPEN HOLE; 16,558A-24.749.0 ",� STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: iim.reao(rDalaska.00v: AOGCC.Inspeclors(Malaska0ow phoebe.brooks0alaska.aov OPERATOR: ConocoPhillips Alaska Inc, FIELD I UNIT I PAD: Alpine / CRU / CD4 Pad DATE: 06/09/17 OPERATOR REP: Miller/Riley AOGCC REP: Bob Noble ch ds.wallace(rDa la ska. g ov Well CD4-17 pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2061180 Type Inj N Tubing 1475 1940 1940 1940 Type Test P Packer TVD 7130 BBLPump 3.7 IA 130 3300 3260 3250 Interval V Test psi 3000 BBL Return 3.7 OA 1 0 6 1 3 2 Result P Notes: MITIA per AIO 18C.003 to maximum anticipated injection pressure Well CD4-26 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2090490 Type Inj W Tubing 2406 2406 2406 2406 Type Test P Packer TVD 7347 BBLPump 9.3 IA 940 3300 3240 3220 Interval O Test psi 3000 1 BBL Return 1 5.4 OA 709 715 714 714 Result P Notes: MITIA for waiver prep. Well CD4-27 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2111460 Type Inj W Tubing 2515 2516 2516 Type Test P Packer TVD 7412 BBLPump 1.5 IA 955 3300 2930 Interval V Test psi 3000 BBL Return OA 53 62 62 Result F Notes: MITIA per AIO 18C.008 to maximum anticipated injection pressure Well CD4-27 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2111460 Type Inj W Tubing 2516 2516 2516 2516 Type Test P Packer TVD 7412 BBLPump 0.2 IA 2930 3300 3080 2900 Interval V Test psi 3000 BBL Return1.2 OA 62 63 63 63 Result F Notes: MITIA per AIO 18C.008 to maximum anticipated injection pressure —Repressure IA for second test with 0.2 bbls of diesel Well CD4-209 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2060650 Typelnj W Tubing 2060 2063 2061 2061 1 Type Test P Packer TVD 6025 BBLPump 1.4 IA 570 3300 3250 3240 Interval V Test psi 3000 BBL Return 1.4 OA 568 804 801 808 Result P Notes: MITIA per AIO 28.003 to maximum anticipated injection pressure Well CD4-209 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2060650 Type Inj W Tubing 2060 2060 2061 2061 Type Test P Packer TVD 6025 BBLPump 0.6 IA 607 701 708 715 Interval V Test psi 1800 BBL Return 0.6 OA 580 2000 1835 1815 Result P Notes: MITOA per AIO 28,003 to 1800 psi. Well CD4-321 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2061420 Type Inj W Tubing 1909 1909 1907 1904 Type Test P Packer TVD 7128 BBLPump 5.5 IA 1070 4200 4180 4180 Interval V Test psi 4080 BBL Return 5.5 OA 0 0 0 0 Result P Notes: MITIA per AIO 18C.002 to maximum anticipated injection pressure Well CD4-322 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2071010 Type Inj N Tubing 1000 1090 1000 1000 Type Test P Packer TVD 7161 BBLPump 4.3 IA 460 3300 3280 3280 Interval V Test psi 3000 BBL Return 1 4.3 OA 32 54 54 1 54 Result P Notes: MIITA per AIO 18C.005 to maximum anticipated injection pressure TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Noes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Vanance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Form 10-426 (Revised 01/2017) MIT ALP C0417.26.27,209.321,32206-09-17.xlsx lode! !tame CD4-26 Notes Start Date 315?2017 Dais 90 Bleed History EDd Date 6431'2017 NELLJO TIME STR-PRES END-PRES DIF-PRES CASING SERVICE Annular Communication Surveillance CD4-26 6,9,2017 970 940 30 INNER S'•'',1 45 4fl 35 30 25 YI a 20 15 1 ®G F0 iG 10 20 0 GG BO 80 70 ao Feb-17 Mar-17 Apr-17 May-17 1�17 Jt417 3GG0 - 25G0 - Oct -MGI O 212 -P. m1500 --- SWI -BLPO 1G00 1500 G Feb-17 Ma-17 Apr-17 Ms-17 Jur17 A&IT Date - WHP GGG 500- 1 _ LAP _ OAP �R 1 1 G0 1 00 1 LL 00 g! '41 00 1 00 G 18 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 111h Day of June 2017 Commissioner Foerster Alaska Oil & Gas Conservation Commission 333 West 7"' Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner Foerster: RECEIVE JUN 13 Z017 ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 18, Rule 9, to apply for administrative approval allowing well CD2-18 (PTD# 203-151) to be online in water injection service only. Currently, the well displays TxIA communication only while injecting gas. If you need additional information, please contact Travis Smith or myself at 659-7126. Sincerely, Rachel Kautz Well Integrity Supervisor ConocoPhillips Alaska, Inc. ConocoPhillips Alaska, Inc. Alpine Well CD2-18 (PTD# 203-151) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc., proposes that the AOGCC approve this Administrative Relief request for Alpine injection well CD2-18, as per Area Injection Order 18, Rule 9, to allow water only injection due to known tubing by inner annulus communication during gas injection service. Well History and Status Colville River Unit well CD2-18 (PTD# 203-151) was drilled and completed in September 2003 as a service well for WAG injection. CD2-18 was first reported to the Commission on March 11, 2017 for an anomalous inner annulus (IA) pressure increase while on MI injection service. Follow-up diagnostics on March 14, 2017, including packoff tests and a MITIA (10-426 form attached), passed. However, the IA showed minor pressure build-up during a drawdown test. The well was subsequently put on an AOGCC approved MI monitor period during which the IA pressurization continued and did not appear connected to thermal changes. The well was WAG'd to water for an approved monitor period to confirm integrity on water injection. During this monitor, the well did not show signs of further IA pressurization. ConocoPhillips now requests an administrative approval (AA), which will allow continued water only injection into CD2-18 due to known tubing by IA communication while on gas injection. Barrier and Hazard Evaluation Tubing: The 4-1/2", 12.6 lb, L-80 tubing has integrity to the packer at 11235' MD based on a passing MITIA performed on 3/14/2017, and a 30-day monitor period on water injection that ended on 6/11/2017. Production casing: The 7", 26 lb, L-80 production casing has integrity to the packer @ 11235' MD based on the MITIA and monitor period described above. Surface casing: The well is completed with 9-5/8", 36 lb, J-55 surface casing with an internal yield pressure rating of 3520 psi. The surface casing is set at 3222' MD (2380' TVD). The surface casing maintains pressure integrity based on TIO trends. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Secondary barrier: The production casing is the secondary barrier should the tubing or packer fail. Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the completion it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. TIO trends are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. NSK Well Integrity Supervisor 6/11/2017 Approved 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 maximum anticipated injection pressure; 3. Allow operating IA pressure up to 2000 psi and allow operating OA pressure up to 1000 psi; 4. Submit monthly reports of daily tubing & IA pressures, injection volumes and pressure bleeds for all annuli; 5. Shut-in the well should diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC; 6. Anniversary date to be set on the 30th of June 2018 (last AOGCC witnessed test; June 13, 2014) to align the AOGCC witnessed testing with the UIC MIT permanent scheduled pad testing. NSK Well Integrity Supervisor 6/11/2017 2 .✓ WNS INJ CD2-18 ConocoPhillips Alaska. Inc. --- Well Attributes Max Angle & MD TD Wellbore APVUVA Pield Name Wellbore Statue 501032046600 ALPINE INJ net (°) MD (ttKBJ 95.85 17,978.94 Act at. (ftK8) 18.019.0 Comment H25 (ppm) Date SSSV: WRDP Annotation End Date Last WO: KB-Grd (ft) Riy R.I.— Date 43.56 9Y21120M CO2.16,42820164:57'.54 PM Verpcel sch...0, (actua) Annotation Depth(ftKB) End Date Last Tag: Annotation Last Mod By End Date Rev Reason: INJ VALVE C/O pproven 412712016 _...._.. ...__ HANGER, 32.8 CONDUCTOR; 37.0-109.0 VALVE, 2,636.1 NIPPLE 2.636.0 SURFACE: 36A.3,221.8— GAS LIFT; 11,121.3 PACKER', 11,235.2 NIPPLE; 11,317.2 WLEG; 11,326.3 PRODUCTION; 34.6-12,112.0— OPEN HOLE; 12,112.0-18.019.0 s Casing Strings Casing Description OD (In) CONDUCTOR 16 ID (In) 15.062 Top (ftK8) Set 37.0 Depth (ftKB) Set 109.0 Depth (TVD) 109.0 WULen 62.50 (I... Grade Top HAO WELDED Thread Casing Description OD (In) SURFACE 95/8 ID (In) 8.921 Top (ftKB) Set 36.8 Depth (ftKB) Set 3'221.8 Depth (TVD).. 2,3803 Will. 36.00 (I... Grade Top J-55 BTC Threatl escn Casing Dption OD (in) PRODUCTION 7 ID (in) 6.276 Top (ftKB) Set 34.6 Depth (ftK8) Set 12,112.0 Depth IrVD)... 7,292.3 Wt(L n 26.00 (I... Grade Top L-80 BTCM Thread Casing Description DD (In) OPEN HOLE 6 118 ID (In) 6.125 Top (ftKB) Set 12.112.0 Depth (ftKB) Set 18.019.0 Depth (TVD)... WULen (1... Grade Top Thread Tubing Strings Tubing Dascd Ptlon Siring Ma... ID tire) Top (ftKB) Set Depth (ft.. Set Depth (tVD) (... Wt (IbHt) Gratle Top Gonnedlan TUBING 4V2 3.958 328 11.329.E 7,110.2 12.60 L-80 IBTM Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°) It.. Des Com Nominal ID (In) 32.8 328 0.00 HANGER FMC TUBING HANGER 4.500 2,636.4 2,028.7 51.49 NIPPLE CAMCO DB SSSV 3,812 11,235.2 7,074.0 66.64 PACKER BAKER S-3 PACKER w/millout extension 3.875 11,317.2 7,105.E 68.23 NIPPLE HES XN NIPPLE 3.725 11,328.3 7,109.7 68.49 WLEG WIRELINE GUIDE 3.875 Other In Hole (VVireline retrievable plugs, valves, pumps, fish, etc.) Top(TVD) Top (ftKB) (KKB) Top Intl (°) Des Co. Rua Data to (in) 2,636.4 2.028.7 51.48 VALVE A-1 INJECTION VALVE (SIN: HSS-122) 4127r2016 1.250 Mandrel Inserts st ad on N Top(rtKB) Top (TVD) (ftKBI Make Model OD(In) Sere Valve Type Latch Type Port Size TRO (in) Run (Pal) Run Oat. Cam 1 11,121.3 7,027.6 CAMCO KBG-2 1 GAS LIFT DMY BK 0.000 0.0 1W1&2003 Notes: General & Safety End Date Annotation 2/3/2011 NOTE: VIEW SCHEMATIC w/Alaska Schematic9.0 15 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: iim.regg(dalaska.gov: AOGCC.Insoectors0alaska.gov: phoebe. brooks(cc@alaska.gov OPERATOR: ConocoPhillips Alaska Inc. FIELD / UNIT / PAD: Colville River Field/Colville River Unit/CD2 DATE: 03/14/17 OPERATOR REP: AOGCC REP: chds.wallaceRDalaska. gov Well CD2-18 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2031510 Type Inj G Tubing 4041 4039 4039 4039 Type Test P Packer TVD 7074 BBLPump 1.8 IA 1810 3000 2975 2975 Interval O Test psi 1769 BBL Return OA 435 540 550 550 Result P Notes: Diagnostic MITIA Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Retum OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBLPump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBLPump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBLPump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: TYPE [NJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance 1 = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Form 10-426 (Revised 01/2017) CD2-18 MITIA 3-14-17A. Well Name CD2-18 Notes. Start Date 31131 17 Days 90 End Date 1 611112017 450D 400D 350D 3DM N 2500 a 200D 15M 1D06 5D0 0 Feb-17 4000 3500 p 3D00 g 2500 m 200D 150D 1000 �D D Annular Communication Surveillance WHP -LAP OAP - WHT Bleed History WELL -10 TIME STR-PRES END-PRES DIF-PRES CASING SEI CD2-18 5114/2017 1700 1350 350INNER PWI CD2-18 4/13/2017 2015 700 1315INNER MIS 100 CD2-18 3/14/2017 1810 790 1020INNER MIS 15❑ 140 130 U20 91 "510 10D 00 30 70 50 Mar-17 Apr-17 May-17 Jt 17 AA-17 7 Feb-17 Mar-17 Apr-17 May-17 Juf17 Ad-17 Date 17 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 May 12, 2017 Commissioner Foerster Alaska Oil & Gas Conservation Commission 333 West 71h Avenue, Suite 100 Anchorage, AK 99501 Dear Ms. Foerster: RECEIVE® MAY 16 2017 AOCCC ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 18, Rule 9, to apply for administrative approval to allow CRU injection well CD2-78 (PTD 209-066) to remain in water only injection service. Currently the well has known tubing by inner annulus communication only while on miscible gas injection. If you need additional information, please contact us at your convenience. Sincerely, Rachel Kautz Well Integrity Supervisor, ConocoPhillips Alaska, Inc. Office phone: (907) 659-7126 Cell phone: (907) 943-0450 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Alpine Well CD2-78 (PTD 209-066) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this administrative relief request as per Area Injection Order 18, Rule 9, to continue water only injection for Colville River Unit injection well CD2-78 (PTD 209-066). The well displays tubing by inner annulus communication only while the well is on miscible gas injection. Well History and Status Colville River Unit well CD2-78 was completed in 2009. It was converted to WAG injection in 2011. CD2-78 was reported to the Commission on April 3, 2017 for a suspect inner annulus pressure increase while on miscible gas injection. Passing diagnostic tests including a MIT -IA and wellhead pack off tests were performed on April 12, 2017 (10-426 attached). An AOGCC approved monitor period on water injection took place following the diagnostic tests. During the water injection monitor period, no TxIA communication was observed. ConocoPhillips intends to pursue repairs if tubing by inner annulus communication develops while on water injection, however, at this point the well exhibits no indications of tubing by inner annulus communication while on water injection. ConocoPhillips requests an administrative approval (AA) which will allow for continued injection of water only. Barrier and Hazard Evaluation With only water injection, this well has all the harriers of a normal injection well Tubing: The 3 1/2", 9.3 lb, L-80 tubing (and approx. 89' of 4 %2", 12.6 lb, L-80 tubing in the upper tubing string) has integrity to the packer at 15,943' MD (7048' TVD), based on the passing diagnostic MIT -IA and TIO trends. Intermediate casing: The 7 5/8", 29.7 lb, L-80 intermediate casing has integrity to the packer at 15,943' MD (7048' TVD), based on the aforementioned MIT -IA and TIO trends. Surface casing: The 10 1/4", 45.5 lb, L-80 surface casing set at 3379' MD (2370' TVD) has an internal yield pressure rating of 5210 psi. The surface casing has integrity based on TIO trends. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Secondary barrier: The intermediate casing is the secondary barrier should the tubing fail. Tertiary barrier: The surface casing will act as a third barrier in the unlikely case that the first two normal barriers have failures. Well Integrity Supervisor 5/12/2017 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the completion it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. TIO trends are compiled, reviewed, and submitted to the AOGCC for review 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 maximum anticipated injection 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 diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC; 6. Anniversary date to be set on the 30th of June 2018 (last AOGCC witnessed test: June 14, 2014) to align the AOGCC witnessed testing with the UIC MIT permanent 4-year scheduled pad testing. Well Integrity Supervisor 5/12/2017 2 W N S I N J CD2-78 ConoeoPhiilips Alaska, Inc. Well Attributes IMaxAngle&MD JTD Wellkwre APIIDWI Field Name Wellbore Status 501032060100 ALPINE INJ ncl (°) MD (ftKB) 92.28 22,508.50 Act Btm (ftKB) 23,786.0 I Comment H2S (ppm) I Date SSSV: TRDP Annotation I End Date Last WO: I KB-Grd (n) I Rig Release Date 44,51 9/10/2009 HORIZONTAL- CD2.78, 9/131201495326 AM eraca sc emabc actua Annotation Depth (ftKB) Entl Date Last Tag: Annotation Last Mod By End Data Rev Reason: Notes Update lehallf 9/13/2014 Casing Strings Casing Description OD CONDUCTOR (in) 16 ID (in) 15.250 Top (ftKB) Set 34.0 Depth (ftKB) 11.50 ,0 Set Depth (TVD)... 114.0 WtlLen (I... 62 Grade Top H40 Thread .......... ............................"'"''"" HANGER; 306� ................ _..... _..... _... __..... _... __........... .. CONDUCTOR; 34.6114.0 SAFETY VLV; 2,196.5 SURFACE; 36.3-3,379.0 GAS LIFT; 6,175.0 GAS LIFT; 15,820.9 PACKER; 15,942.E NIPPLE; 16,022.3 W LEG', 17289 2 INTERMEDIATE; 34.1-17,444.5 OPEN HOLE; 17,444.523,7860 ...... IN Casing Description OD SURFACE (in) 10314 ID (in) 9.950 Top (ftKB) Set 36.3 Depth (ftKB) 3,379.0 Set Depth (TVD)... 2,370.1 WtlLen (I... 45.50 Grade Top L-80 BTCM Thread Casing Description OD INTERMEDIATE (In) 75/8 ID (in) 6.875 Top (ftKB) Set 34.1 Depth (ftKB) 17,444.5 Set Depth D VD)... 7.409.7 WtlLen (I... 29.70 Grade Top L-80 BTC-mod Thread Casing Description OD OPEN HOLE (in) 6.151 ID (in) Top (ftKB) Set 17,444.5 Depth (ftKB) 23,786.0 Set Depth (TVD)... WtlLen (I... Grade Top Thread Tubing Strings Tubing Description String Ma... ID (in) Top (ftKB) Set Depth (ft.. Set Depth (TVD) (... Wt (IblfI) Grade Top Connection TUBING 4.5"x3.5" 3 1/2 2.992 30.6 17,289.7 7,395.2 9.30 L-80 EUE 8 rd Completion Details Top (ftKB) Top (TVD) (ftKB) Top ]net (°) It.. Des Com Nominal ID (In) 30.6 30.6 0.00 HANGER TUBING HANGER 4.500 120.6 120.6 0.24 XO Reducing CROSSOVER 4.5" x3.5" 3.000 2.196.5 1,905.7 58.75 SAFETY VLV CAMCO TRMAXX-5E 2.812 15,942.6 7,047.6 67.97 PACKER BAKER PREMIER PACKER 2.890 16,022.3 7,077.5 68.01 NIPPLE HES'XN' NIPPLE w/2.75 NO GO 2.750 17,289.2 7,395.2 83.74 1 WLEG BAKER WIRELINE ENTRY GUIDE 2.990 Mandrel Inserts st at on N Top (ftKB) Top (TVD) (ftKB) Make Model �013(inj Sew Valve Type Latch Type TRO Run (psi) Run Date Com 6,175.0 3,413.1 CAMCO KBMG 1 GAS LIFT DMV BK �Ifln) 0.02/19/2011 2 15,820.9 7,002.5 CAMCO KBMG 1 GAS LIFTDMYBK 0.0 3/11/2012 Notes: General & Safety End Date Annotation 9/11/2009 NOTE: View Schematic w/ Alaska Schematic9.0 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: jim.reoo0alaska.aov: AOGCC.Insoectors0alaska.aov: ehoebe.brooks0alaska.gov OPERATOR: ConocoPhillips FIELD / UNIT / PAD: Alpine / Colville River Unit / CD2 DATE: 04/12/17 OPERATOR REP: AOGCC REP: chris. wallaceCrDalaska. gov Well CD2-78 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTO 2090660 Type Inj W Tubing 1980 1985 1985 1985 Type Test P Packer TVD 7048 BBL Pump 8.0 IA 1135 3000 2980 2980 Interval 0 Test psi 1762 BBL Return OA 660 670 670 670 Result P Notes: Diagnostic MITIA Well Pressures: Pretest Initial 15 Min, 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBLPumpJ IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Form 10-426 (Revised 01/2017) CD2-78 MITIA 4-12-17.xlsx Well Name CD2-78 Notes: Start Date 211i2017 Days 90 Bleed History End Date 511212017 WML_10 TIME STR-PRES END-PRES DIF-PRES CASING SERVICE Annular Communication Surveillance CD2-78 4+1712017 650 600 50 CUTER PWI CD2-78 411212017 1135 245 890INNER PWI WHP CD2-78 411012017 3/29/2017 1640 2002 1100 1437 540INNER 565INNER PWI MIS 45 — LAPCD2-78 Ica OAP 150 14D 35 730 30 120 LL 25 N F 11 1710 2000- 100 15 10 Be 70 eo u JarW Feb-17 hia-17 A r-17 May-17 Awn 17 3930 3030 -DGI -NGI 2900 m2070 SW1 G 1530 LL BLPO a Imo 503 0 Ja 17 Feb-17 Mar-17 Apr-17 "-17 J�17 Date 'UO 00 W 00 00 0n 16 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 71h Day of May, 2017 Commissioner Foerster Alaska Oil & Gas Conservation Commission 333 West 7t' Avenue, Suite 100 Anchorage, AK 99501 Commissioner Foerster, RECEIVED MAY 0 9 2017 AOGCC ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 18C, Rule 09, to apply for an amendment to administrative approval 18C.002, which would allow well CD4-321 (PTD 206-142) to be online in water and gas injection service after a rig workover installed gas -tight tubing in the well. Currently, the well displays a surface casing leak to atmosphere. If you need additional information, please contact myself or Travis Smith. Sincerely, Rachel Kautz Well Integrity Supervisor, ConocoPhillips Alaska Inc. Office:907-659-7126 Cell:907-943-0450 ConocoPhillips Alaska, Inc. Colville River Unit CD4-321B (PTD# 206-142-0, AA# 18C.002) Technical Justification for Request of Administrative Approval Amendment Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this amendment to Administrative Approval 18C.002, as per Area Injection Order 18C, Rule 9, to allow water alternating gas (WAG) injection into CRU CD4-321 after the rig workover installation of tubing with gas -tight threads. The well has a known surface casing leak to atmosphere. Well History and Status Colville River Unit well CD4-321 (PTD# 206-142) was drilled and completed in 2006 as a service well. CD4-321 was reported to the Commission on March 18, 2013 showing signs of a surface casing leak to atmosphere via the surface casing by conductor annulus. The OA has an open shoe and is highly deviated at the shoe depth making diagnostics difficult to pin point the leak location(s), however, recent diagnostics suggested a shallow leak. An excavation and surface casing repair was attempted to repair a leak found at 58" below the OA valve. When the repair was tested on March 4, 2017, it failed and surface casing leakage from below the excavated/patched depth was noted. It was then decided to pursue a workover, so no further efforts to repair the surface casing externally were attempted. ConocoPhillips later applied to the Commission for approval to regain WAG injection capability in this well by replacing the existing production tubing with gas -tight tubing during a workover. The sundry was approved and the workover subsequently completed on April 23, 2017. The rig performed a passing MITIA to 4200 psi on April 22, 2017. ConocoPhillips now requests an amendment to administrative approval (AA) 18C.002, which will allow WAG injection into CD4-321 with the newly installed gas -tight tubing and a known surface casing leak. Barrier and Hazard Evaluation Tubing: The 4-1/2", 12.6 ppf, L-80 tubing with Hydril 563 gas -tight connections has an internal yield pressure rating of 8430 psi (70% - 5901 psi) and a collapse pressure rating of 7500 psi (70% - 5250 psi). The tubing has integrity to the packer at 17,919' MD, based on the passing MITIA to 4200 psi performed on April 22, 2017 on the rig. Production casing: The 7", 26 ppf, L-80 production casing has an internal yield pressure rating of 7240 psi (70% - 5068 psi) and has integrity to the packer at 17,919' MD based upon the passing MITIA to 4200 psi mentioned above. Surface casing. The 9-5/8", 40 ppf, L-80 surface casing with an internal yield pressure rating of 5750 psi set at 3504' MD (2384' TVD) does not have integrity based upon the results of the surface casing leak detect (SCLD) on March 4, 2017. Well Integrity Supervisor 5/7/2017 Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the gas -tight production tubing down to the packer set at 17,919' MD. Second barrier: The secondary barrier to prevent a release from the well and provide zonal isolation is the production casing should the production tubing fail. Monitoring: Each well is monitored daily for wellhead pressure changes. Should a leak develop in the tubing or production casing, or should the surface casing leak appear active, it will be noted during the daily monitoring process. Pressure trends that indicate annular communication require investigation, Commission notifications, and corrective action, up to and including a shut-in of the well. T/I/O plots are compiled, reviewed, and submitted to the AOGCC for review monthly. Proposed Operating and Monitoring Plan 1. Well will be used for water and gas injection. 2. Perform a passing MITIA to maximum anticipated injection pressure every 2-years. 3. Allow operating IA pressure up to 2000 psi while injecting gas or water; operating OA pressure to be held as low as reasonably possible, not to exceed 100 psi. 4. Submit monthly reports of daily tubing, IA, and OA pressures, injection volumes and pressure bleeds for all annuli. 5. Shut-in the well should MIT, injection rates, or pressures indicate further problems with appropriate notification to the AOGCC. 6. Anniversary date to be set on the 301h of June 2017 (Last AOGCC witnessed MIT for current AA was the I Ith of November 2015) to align the AOGCC witnessed testing with the UIC MIT permanent 4-year scheduled pad testing. Well Integrity Supervisor 5/7/2017 2 WNS ConOCOPitllllpSW well Attrib Alaska, Inc.WellboreAPIYUH 501032053600 ... Comment SSSV'NIPPLE INJ CD4-321 es I Max Angle & MD ITD NANUQ KUPARUK -t Wn I d/7.R/7nl7 1 di 5Rl 1nl?F;IgnnR V.nical schematic actual Annotation Depth (ftKB) End Date Annotation Last Mod By End Date Last Tag: Rev Reason: RECOMPLETION jennalt 5/2/2017 asmg Strings HANGER; M 9 Casing Description OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD).., WtlLen (I... Grade Top Thread CONDUCTOR INS 34" 16 15.250 37.0 114.0 114.0 65.00 H-40 WELDED Casing Description OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD)... WtlLen (I... Grade Top Thread """""""""""""""""""""""""" "" '' '-''' SURFACE 95/8 ,835 36.6 3,504.0 2,385.2 40.00 L-80 BUTT Casing Description OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD)... WtlLen (I Grade Top Thread INTERMEDIATE 7 6.276 34.4 19,323.1 7,800.2 26.00 L-80 BTCM Tubing Strings Tubing Description String Ma... ID (in) Top (ftKB) Set Depth (ft.. Set Depth (TVD) (... Wt (IbKt) Grade Top Connection TUBING 41/2 3.958 30.9 18,055.2 7,173.2 12.60 L-80 Hydril 563 Gas Injection Completion Details Nominal ID Top (ftKB) Top (TVD) (ftKB) Top Inc] (°) Item Des Com (in) 30.9 30.9 0.06 HANGER FMC 4-1/2" Tubing Hanger 4.000 CONDUCTOR I14534" ; 37.0- 1140 2,289.7 1,958.5 58.55 NIPPLE DB-6 Landing Nipple, 4-1/2" X 3.812", L80, HYD563 BxP 3.813 17,875.6 7,114.0 70.99 SEAL ASSY Baker Seal Assy (1.89' from fully located) 3.875 17,888.4 7,118.2 70.96 SBR (Seal Baker PBR, 17.65' polish bore at 4.75" ID 4.750 Bore Receptacle) 17,918.8 7,128.1 70.86 PACKER Baker Premier Production Packer 3.880 17,983.E 7,149.4 70.64 NIPPLE X Landing Nipple, 3.813", L80, HYD563 BXPw1 RHC 3.812 Tubing Description String Ma... ID (in) Top (ftKB) Set Depth (ft.. Set Depth (TVD) (... WI: (b.)Grade Top Connection TUBING 41/2 3.958 31.5 18,194.2 7,219.5 12.60 L-80 IBTM Gas Injection Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Com Nominal l0 (in) SURFACE; 36.F3,504.0 31.5 31.5 0.06 HANGER FMC TUBING HANGER 4.500 2,290.2 1,958.7 58.57 NIPPLE CAMCO DB NIPPLE 3.812 17,907.9 7,124.5 70.90 SLEEVE BAKER PREMIER SLIDING SLEEVE CMD 3.810 17,993.5 7,152.7 70.61 GAUGE WEATHERFORD POD2 GAUGE CARRIER 3.958 18,077.0 7,180.4 70.66 PACKER BAKER PREMIER PACKER 3.875 18,181.9 7,215.4 1 70.35 NIPPLE HES NX NO GO NIPPLE 3.725 GAS LIFT; 17,818.5 18,192.8 7,219.1 70.32 1 WLEG I BAKER WIRELINE FLUTED GUIDE 3.875 § Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (TVD) Top Incl Top (ftKB) (ftKB) (°) Des Com Run Date ID (in) 17,981.0 7,148.6 70.65 Fish A glove was dropped down the IA while N/D the 4/22/2017 0.000 BOPE and not recovered. 18,282.0 7,248.8 70.75 PLUG 3.81" XN PLUG ASSY (LOCK,EQ SUB 1/18/2017 0.000 (3/16"PORTS) & FILL EXT/ DAL = 59") Perforations & Slots Shot Dens Top (TVD) Btm(TVD) (shots/ m PACKER 17,918.9 Top (ftKB) Bt. (ftKB) (ftKB) (ftKB) Zone Date ft) Type Com 18,434.0 18,450.0 7,299.8 7,305.3 11/20/2006 6.0 IPERF 18,450.0 18,470.0 7,305.3 7,312.3 11/20/2006 6.0 MERE Mandrel Inserts St ati N Top (ftKB) Top (TVD) (ftKB) Make Model OD (in) Se, Valve Type Latch Port Type Size (in) TRO Run (psi) Run Date Com 1 17,818.5 7,095.5 Camco BEK-5 0.0 GAS LIFT SOV I BEK-5 0.0001 0.0 4/24/2017 PACKER; 18,077.0 NIPPLE; 18,181.9 WLEG; 18,192.8 PLUG; 18,282.0 IPERF; 18, 434.0-18,450c IPERF; 18, 450.0-18,470.0- INTERMEDIATE; 344-19,323.1-� Well Name Start Date Days End Date CD4-321 2/6/2017 90 517,2017 Notes: Bleed History Annular Communication Surveillance WHIP 45 WELL —ID TIME STR-PRES END-PRES DIF-PRES CASING SERVICE 40 lea 150 140 30 130 25 120 LL 45 a M 010 15 1110 10 BQ 80 70 80 Jar 17 Feb-17 Mar-17 Apr-17 May-17 os Q o� o o? a Jar, 17 F.f -17 Ma 47 Apr 17 May-17 Date FOQ _ IAP OAP - YYFiT 00 00 m W W 0 —oct MGt -PA'1 -BLPO 15 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 March 26, 2016 Chris Wallace Alaska Oil and Gas Commission 333 West 70' 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 maybe 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 Notes Anniversary Date 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 213.049 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 A10 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. 113-08A AIO 2C.027 8/7/2015 7/12/2013 6/30/2017 1B pad due next June of 2017. Well to be tested early, on or before 6/30/17 to get on schedule. 16-11 AIO 26.060 7/6/2011 7/7/2015 6/30/2017 Well to be tested early, on or before 7/31/16 to get on schedule. 1D-38 AIO 2C.010 8/26/2014 8/26/2014 7/31/2016 ID 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 1E pad due next June of 2018. Well to be tested early, on or before 6/30/16 to get on schedule. 1E-15A AIO 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. 5E-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 AI0.26.080 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 1G pad due next July of 2019. This well will be tested by 6/28/16 and then on or before 7/31/17 to get on schedule. 1L-05 AIO 26.054 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 213.083 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 28.093 5/30/2014 7/9/2013 7/31/2017 1Q pad due next July of 2017. This well will be tested by 5/30/16 and then on or before 7/31/17 to get on schedule. 1Q-13 AIO 26.090 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 AIO 213.015 7/23/2006 7/8/2013 7/31/2017 3Y pad due next July of 2017. This well has been offline since 2/6/12. If the well is BO1 it will be tested post stabilization and then again on the earliest date to align with the schedule. 1Y-08 AIO 26.056 6/15/2010 2/15/2015 7/31/2017 This well will be tested by 6/15/16 and then on or before 7/31/17 to get on schedule. 1Y-09 AIO 26.051 5/20/2010 2/15/2015 7/31/2017 This well will be tested by 5/20/16 and then on or before 7/31/17 to get on schedule. 1Y-10 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. 26-06 AIO 2C.012 12/26/2014 12/26/2014 5/31/2016 2B pad due next May of 2016. Well to be tested early, on or before 5/31/16 to get on schedule. 26-07 NO 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 AIO 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 NO 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 NO 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. 2D-02 NO 26.052 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. 213-04 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 213.070 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 NO 213.074 6/7/2012 6/7/2014 7/31/2016 2F pad due next July of 2016. CPAI requests a delay of 2 months to allow the MIT to be performed on or before 7/31/16 to get on schedule. 2F-13 NO 26.039 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 NO 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 NO 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 NO 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 BO1 it will be tested post stabilization and then again on the earliest date to align with the schedule. 21-1-03 NO 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. 2H-13 AIO 213.076 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. CPA] requests a delay of 1 month to test on or before 6/30/17 to get on schedule. 2K-10 AIO 28.017 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. 21--305 AIO16.002 1/21/2012 1/19/2016 8/31/2016 2L pad due next August of 2018. Well to be tested early, on or before 8/31/16 to get on schedule. 2L-310 A]0 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 2113.001 8/31/2014 12/26/2014 8/31/2016 2P pad due next August of 2016. This well is on schedule. 2T-02 AIO 2C.001 11/9/2014 11/9/2014 6/30/2017 2T pad due next June of 2017. This well will be tested by 11/9/16 and then on or before 6/30/17 to get on schedule. 2T-10 AIO 26.092 10/2/2014 10/2/2014 6/30/2017 This well will be tested by 10/2/16 and then on or before 6/30/17 to get on schedule. 2T-18 AIO 2C.023 4/16/2015 6/1/2013 6/30/2017 CPAI requests a 3 month delay to allow the MIT to be performed on or before 6/30/17 to get on schedule. 2T-28 AIO 213.066 10/2/2011 9/25/2015 6/30/2017 Well to be tested early, on or before 6/30/17 to get on schedule. 2T-32A AIO 2C.007 11/9/2014 11/9/2014 6/30/2017 This well will be tested by 11/9/16 and then on or before 6/30/17 to get on schedule. 2U-05 AIO 28.084 1/12/2014 12/27/2015 8/31/2016 2U pad due next August of 2018. Well to be tested early, on or before 8/31/16 to get on schedule. 2V-02 AIO 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 2019. CPAI requests a delay of 1 week to allow the MIT to be performed on or before 6/30/17 to get on schedule. 2Z-16 AIO 26.002 9/25/2007 8/31/2017 2Z pad due next August of 2019. This well has been off line since 3/6/06. If the well is BO1 it will be tested post stabilization and then again on the earliest date to align with the schedule. AA did not stipulate anniversary date. 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 36-07 AIO 2C.028 6/18/2015 6/18/2015 6/30/2017 to get on schedule. CPAI requests a delay of 2 weeks to allow the MIT to be performed on or before 6/30/17 313-10 AIO 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 A1O 2C.025 6/27/2015 6/18/2015 6/30/2017 to get on schedule. 3F pad due next June of 2019. CPAI requests a delay of 1 month to allow the MIT to be 3F-04 AIO 26.063 6/5/2011 6/5/2015 6/30/2017 performed on or before 6/30/17 to get on schedule. 3F-08 AIO 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 26.089 1/27/2014 1/17/2016 6/30/2017 Well to be tested early, on or before 6/30/17 to get on schedule. 3G pad due next August of 2019. This well will be tested by 6/11/16 and then the 3G-15 AIO 2C.011 6/11/2014 8/30/2011 8/31/2017 following year by 8/31/17 to get on schedule. This well will be tested by 10/10/16 and then the following year by 8/31/17 to get on 3G-23 AIO 2C.004 10/10/2014 9/6/2014 8/31/2017 schedule. 3H pad due next June 2017. This well will be tested by 7/12/16 and then the following 31-1-06 AIO 2C.003 7/12/2014 11/19/2013 6/30/2017 year by 6/30/17 to get on schedule. 3H-07 AIO 2C.016 9/18/2014 9/18/2014 6/30/2017 This well will be tested by 9/18/16 and then the following year by 6/30/17 to get on 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 offline since 5/25/15. If the well is BOI it will be tested post stabilization and then again on the earliest date to align with 3K-11 AIO 213.061 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 26.013 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 26.072 12/7/2012 12/13/2014 8/31/2016 on schedule. Well to be tested early, on or before 8/31/16 to get on schedule. AA did not stipulate 3N-16A AIO 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 213.033 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. F3Qp'aJule.d due next August of 2016. This well will be tested on or before 8/31/16 to get on 3Q-01 AIO 2B.068 11/24/2011 11/13/2015 8/31/2016 3Q-05 AIO 26.019 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 08/31/16 to get on schedule. 311-25 AIO 26.012 4/27/2005 4/24/2015 8/31/2016 3111 pad due next August of 2016. Well to be tested early, on or before 8/31/16 to get on schedule. 3S-18 AIO 26.069 6/6/2012 6/6/2012 Alternating service and development well. Required to have witnessed MIT upon start of each injection cycle. Well currently on production. CD1-07 A1O 186.006 6/8/2008 6/11/2015 6/30/2017 CD3 pad due next June of 2017. CPAI requests a delay of 3 weeks to allow the test to be performed on or before 6/30/17. CD1-14 AIO 18C.006 9/1/2015 6/12/2013 6/30/2017 Well to be tested early, on or before 6/30/17 to get on schedule. CD1-21 A1O.1813.007 6/12/2013 6/11/2015 6/30/2017 CPAI requests a delay of 3 weeks to allow the test to be performed on or before 6/30/17 to get on schedule. CD1-46 AIO 18C.004 2/20/2015 6/12/2013 6/30/2017 CPAI requests a delay of 4 months to allow the test to be performed on or before 6/30/17 to get on schedule. CD3-123 AIO 30.005 2/23/2014 2/18/2016 2/28/2018 CD3 pad due next February 2018. CPA] 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. CPA] requests to change this to last day of June for precise database maintenance. CD4-209 AIO 28.003 11/28/2009 11/11/2015 6/30/2017 Well to be tested early, on or before 6/30/17 to get on schedule. CD4-213B AIO 18C.007 June 2017 6/12/2015 6/30/2017 New approved AA calls for anniversary date to be before or during month of June 2017. CPAI requests to change this to last day of June for precise database maintenance. CD4-321 AIO 18C.002 5/10/2013 11/11/2015 6/30/2017 CPAI requests a delay of 2 months to allow the MIT to be performed on or before 6/30/17 to get on schedule. CD4-322 AIO 18C.005 6/12/2015 6/12/2015 6/30/2017 CPAI requests a delay of 3 weeks to allow the test to be performed on or before 6/30/17 to get on schedule. ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 February 23, 2017 Chris Wallace Alaska Oil and Gas Commission 333 West 7f' 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 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". 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 213.011 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 2B.060 7/6/2011 7/7/2015 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 1D-38 AIO 2C.010 8/26/2014 8/7/2016 July 2018 1D pad next due July of 2018. Well to be tested on or before 7/31/18 to get on schedule. 1E-08A AIO 213.065 8/30/2011 8/27/2015 June 2018 lE 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 213.081 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 26.078 6/16/2013 1/8/2017 June 2018 Well to be tested on or before 6/30/18 to get on schedule. 1F-04 AIO 2C.006 9/16/2014 6/15/2016 June 2018 1F pad next due June 2020. Well to be tested on or before 6/30/18 to get on schedule. 1F-05 A1O.26.080 7/12/2012 6/15/2016 June 2018 Well to be tested on or before 6/30/18 to get on schedule. IF-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 26.093 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 2B: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 1R 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 lY pad next due July 2017. Well to be tested on or before 7/31/17 to get on schedule. 1Y-09 AIO 2B.051 5/20/2010 5/7/2016 July 2017 Well to be tested on or before 7/31/17 to get on schedule. 1Y-10 AIO 2C.014 8/29/2014 8/18/2016 July 2017 IWO 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. 26-07 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 213.073 2/14/2013 7/31/2016 May 2018 Well to be tested on or before 5/31/18 to get on schedule. 2C-03 AIO 26.085 2/5/2013 2/20/2016 August 2017 2C pad next due August 2017. Well to be tested on or before 8/31/17 to get on schedule. 2C-04 AIO 213.091 6/21/2014 6/21/2014 August 2015 This well has been offline since 3/31/16. If the well is 13O1 it will be tested post stabilization and then again on the earliest date to align with the schedule. 2C-07 AIO 213.007 2/5/2006 2/5/2012 August 2015 This well has been offline since 9/12/12. If the well is BO1 it will be tested post stabilization and then again on the earliest date to align with the schedule. 2C-08 A1O213.086 3/4/2014 2/20/2016 August 2017 Well to be tested on or before 8/31/17 to get on schedule. 2D-02 AIO 26.052 3/22/2011 3/22/2015 August 2017 2D pad next due August of 2017. CPAI requests a delay of up to 5 months to test on or before 8/31/17 to get on schedule. 2D-04 A10 2B.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 26.074 6/7/2012 7/9/2016 July 2018 Well to be tested on or before 7/31/18 to get on schedule. 2F-13 AIO 26.039 7/5/2008 7/9/2016 July 2018 Well to be tested on or before 7/31/18 to get on schedule. 2G-01 AIO 2C.019 1/11/2015 5/10/2016 May 2018 2G pad next due May of 2020. Well to be tested on or before 5/31/18 to get on schedule. 2G-05 AIO 2C.029 8/27/2015 5/1/2012 May 2016 Well has been shut in since 2/22/16. If the well is 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. 21-1-13 AIO 26.076 3/23/2013 5/10/2016 May 2018 Well to be tested on or before 5/31/18 to get on schedule. 21-1-15 AIO 2C.015 12/25/2014 5/10/2016 May 2018 Well to be tested early, on or before 5/31/18 to get on schedule. 2K-03 AIO 213.016 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 26.048 8/8/2009 8/4/2015 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 2K-20 AIO 2C.041 June 2017 11/13/2015 June 2017 No changes 2L-305 AIO 16.002 1/21/2012 2/14/2017 August 2018 2L pad next due August of 2018. Well to be tested on or before 8/31/18 to get on schedule. 2L-310 AIO 16.004 2/5/2014 2/14/2017 August 2018 Well to be tested on or before 8/31/18 to get on schedule. 2L-319 AIO 16.003 10/4/2012 9/30/2016 August 2018 IWO 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 26.004 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 13O1, the well will be tested post stabilization and then again on the earliest date to align with the schedule. 2M-19 AIO 2C.020 5/4/2015 6/3/2016 June 2018 Well to be tested on or before 6/30/18 to get on schedule. 2M-27 AIO 2C.021 5/5/2015 10/15/2016 June 2018 Well to be tested on or before 6/30/18 to get on schedule. 2N-306 AIO 16.006 August 2016 8/20/2016 August 2016 2N pad next due August of 2018. No changes 2N-325 AIO 16.001 12/30/2009 2/14/2017 August 2018 Well to be tested on or before 8/31/18 to get on schedule. 2P-447 AIO 2113.001 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 213.092 10/2/2014 9/30/2016 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 2T-18 AIO 2C.023 4/16/2015 6/1/2013 June 2017 Well to be tested on or before 4/16/17 and then again on or before 6/30/17 to get on schedule. 2T-28 AIO 213.066 10/2/2011 9/25/2015 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 2T-32A AIO 2C.007 11/9/2014 10/25/2016 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 2U-05 AIO 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 213.064 6/26/2011 6/10/2015 June 2017 2X pad next due June of 2019. Well to be tested on or before 6/30/17 to get on schedule. 2Z-16 AIO 26.002 9/25/2007 August 2015 2Z pad next due August of 2019. This well has been offline since 3/6/06. If the well is 13O1 it will be tested post stabilization and then again on the earliest date to align with the schedule. AA did not stipulate anniversary date. 313-01 AIO 2C.033 June 2017 6/18/2015 June 2017 3B pad next due June of 2019. No changes 36-05 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 213.067 6/19/2011 6/18/2015 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 313-12 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 26.063 6/5/2011 6/5/2015 June 2017 3F pad next due June of 2019. Well to be tested on or before 6/30/17 to get on schedule. 3F-08 AIO 26.087 2/13/2014 2/4/2016 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 3F-11 AIO 26.089 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.0407 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. 3H-07 AIO 2C.016 9/18/2014 9/26/2016 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 3J-08 AIO 2C.013 11/27/2014 7/5/2016 July 2018 31 pad next due July of 2020. Well to be tested on or before 7/31/18 to get on schedule. 3K-11 AIO 26.061 1 7/29/2011 4/30/2016 May 2017 3K pad next due May of 2017. Well to be tested on or before 5/31/17 to get on schedule. 3K-22A AIO 26.013 4/5/2005 4/14/2015 May 2017 CPAI requests a delay of up to 1 month to allow the MIT to be performed on or before 5/31/17 to get on schedule. 3N-11A AIO 213.072 12/7/2012 8/1/2016 August 2018 3N pad next due August of 2020. Well to be tested on or before 8/31/18 to get on schedule. 3N-16A AIO 213.057 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 26.042 9/25/2008 8/2/2016 August 2018 Well to be tested on or before 8/31/18 to get on schedule. 3Q-16 AIO 26.082 1/12/2014 8/2/2016 August 2018 Well to be tested on or before 8/31/18 to get on schedule. 3Q-21 AIO 26.005 4/25/2006 8/2/2016 August 2018 Well to be tested on or before 08/31/18 to get on schedule. 3R-25 AIO 213.012 4/27/2005 8/2/2016 August 2018 3R pad next due August of 2020. Well to be tested on or before 8/31/18 to get on schedule. 3S-18 AIO 26.069 6/6/2012 6/6/2012 Alternating service and development well. Required to have witnessed MIT upon start of each injection cycle. Well currently on production. 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 186.006 6/8/2008 6/11/2015 June 2017 CD1 pad next due June of 2017. Well to be tested on or before 6/30/17 to get on schedule. CD1-14 AIO 18C.006 9/1/2015 6/12/2013 June 2017 Well to be tested on or before 6/30/17 to get on schedule. CD1-21 A1O.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 BO1 on 2/21/17. The well will be tested when stable and then again on or before 6/30/17 to get on schedule. CD2-51 AIO 18C.010 June 2016 6/22/2016 June 2016 CD2 pad next due June of 2018. No changes CD3-112 AIO 30.007 February 2018 2/23/2014 February 2018 CD3 pad next due February of 2018. No changes CD3-123 AIO 30.005 2/23/2014 2/18/2016 February 2018 Well to be tested on or before 2/28/18 to get on schedule. CD3-128 AIO 18C.009 February 2018 2/23/2014 February 2018 No changes CD3-198 AIO 30.006 7/30/2015 1/28/2017 February 2018 Well to be tested on or before 2/28/18 to get on schedule. CD4-17 AIO 18C.003 5/6/2015 6/30/2011 June 2017 CD4 pad next due June of 2019. Well has been shut in since 5-3-15. If the well is 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 AIO 18C.002 5/10/2013 11/11/2015 June 2017 Well to be tested on or before 6/30/17 to get on schedule. CD4-322 AIO 18C.005 6/12/2015 6/12/2015 June 2017 Well to be tested on or before 6/30/17 to get on schedule. 14 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 14th Day of May 2016 Commissioner Foerster Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner Foerster: MAY 17 2016 ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 18, Rule 9, to apply for administrative approval allowing well CD2-51 (PTD# 202-249) to be online in water injection service only. Currently, the well displays TxIA communication only while injecting gas. If you need additional information, please contact myself, Dusty Freeborn or Jan Byrne. Sincerely, Rachel Kautz Well Integrity Engineer ConocoPhillips Alaska, Inc. Office phone: (907) 659-7126 Cell phone: (907) 943-0450 ConocoPhillips Alaska, Inc. CRU CD2-51 (PTD# 202-249) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this administrative relief request as per Area Injection Order 18, Rule 9, to continue water only injection for Alpine injection well CD2-51. The well displays tubing by inner annulus communication only while the well is on gas injection. Well History and Status Colville River Unit well CD2-51 (PTD# 202-249) was drilled and completed in May of 2003 as a service well. CD2-51 was initially reported to the Commission on the 13th of March 2016, for slow IA pressurization while on miscible injection (MI). On the 14th of March 2016, the well passed an MIT -IA, and tubing and inner casing pack off tests also passed in both the negative and positive directions. The well was brought online for MI for a 30 day AOGCC approved monitor period. During the monitor period the IA pressure initially appeared to be stable, but eventually began to increase slowly. At the end of the MI monitor period, the well was WAGed to water injection (WI) for a 30 day AOGCC approved monitor period to establish integrity while on WI. During the monitor period the IA stabilized and showed no signs of tubing by inner annulus communication, therefore, passing the long term IA draw down test while on water injection. ConocoPhillips intends to pursue repairs if tubing by inner annulus communication while on water is identified. However, at this point in time the well demonstrates tubing by inner annulus integrity while on water injection and ConocoPhillips requests an administrative approval (AA) which will allow water injection only. 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 at 12330' MD (6853' TVD), based on normal operating injection differential pressures and passing a diagnostic MIT -IA to 3000 psi on the 14th of March 2016. Production Casing: The 7" 26# L-80 production casing has integrity to the packer at 12330' MD (6853' TVD), based on the passing MIT -IA test outlined above, as well as the differential operating pressure maintained between tubing and inner annulus. 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 3121' MD (2410' TVD). Based on outer annulus pressure maintained and recorded on the TIO plot, the integrity of the surface casing has been proven. Well Integrity Supervisor 5/14/2016 Primary Barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Secondary Barrier: The production casing is the secondary barrier, should the tubing or packer fail. Tertiary Barrier: The surface casing will act as a third barrier from surface in the unlikely case that the first two normal barriers have failures. Monitoring: Each well is monitored daily for wellhead pressure changes. Should a leak develop in the tubing, production casing, or surface casing, it will be noted during the daily monitoring process. Pressure trends that indicate annular communication, commission notifications, and corrective action, up to and including a shut-in of the well will be handled appropriately. T/I/O plots are compiled, reviewed, and submitted to AOGCC for review on a monthly basis. Proposed Operating and Monitoring Plan 1. Well will be used for water injection only (no MI or gas injection allowed); 2. Perform a passing MITIA every 2-years to maximum anticipated injection pressure; 3. Allow operating IA pressure up to 2000 psi, 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/or pressures indicate further problems with appropriate notification to the AOGCC. 6. Anniversary date to be set on the 301h of June 2016 (last AOGCC witnessed test; 131h of June 2014) to align the AOGCC witnessed testing with the UIC MIT permanent 4 year scheduled pad testing. Well Integrity Supervisor 5/14/2016 Bleed Historg '/ off �MTN WMTM rITm Mw f WITM� ®®®®®®® ------- 11 to ------- -gyp IAP 1NFiT WNS INJ CD2-51 ConocoPhillip5 Well Attributes Max Angle & MD TD Inc. Wellbore APVUWI Field Name Wellbore Status 5'1032044100 ALPINE INJ ncl (°) MD (RKB) Act 100.80 1""1.11 Btm (ftKB) 17,320.0 .. Comment 1-12S (ppm) Date SSSV: NIPPLE Am .I.n End Date Last WO: 1026/2005 KB-Grd (R) Rig Release Date 43.40 5/3/2003 CDz51,g/3/20148:57:03 AM Vertical sc emahc actua Annotation Depth (RKB) End Date Annotation Last Mod By End Date Last Tag: Rev Reason: RESET INJ VLV hipshkf 9/2/2014 Casing Strings HANGER; 32.5-- Casing Description CONDUCTOR OD (in) ID (in) 16 15.051 Top (RKB) Set 37.0 Depth (RKB) 114.0 Set Depth (ND)... 114.0 WtlLen (I... 62.50 Grade H-40 Top Thread WELDED Casing Description OD (in) ID (in) Top (RKB) Set Depth (RKB) Set Depth (TVD)... WtlLen (I... Grade Top Thread SURFACE 95/8 8.921 36.6 3,121.1 2,410.1 36.00 J-55 BTC Casing Description OD (in) ID (in) Top (RKB) Set Depth IRKS) Set Depth (TVD)... WtlLen (I... Grade Top Thread - PRODUCTION 7 6.276 34.6 13,245.8 7,167.9 26.00 L-80 BTCM it 1; if Casing Description OD (in) ID (in) Top (ftKB) Set Depth (RKB) Set Depth (TVD)... WtlLen (I... Grade Top Thread OPEN HOLE 61/8 13,246.0 17,320.0 7,147.7 Tubing Strings Tubing Description String Ma... ID (in) Top (RKB) Set Depth (ft.. Set Depth (TVD) (... Wt (I Wft) Grade Top Connection TUBING 412 3.958 32.5 12,535.1 6,949.5 12.60 L-80 IBTM Completion Details Top (RKB) Top (TVD) (ftK8) Top Incl (°) Item Des Corn Nominal ID (in) CONDUCTOR; 37.0-114.0 32.5 32.5 0.00 HANGER FMC TUBING HANGER 4.500 2,416.8 2,010.6 55.43 NIPPLE CAMCO DB LANDING NIPPLE 3.812 12,329.8 6,853.0 61.95 PACKER BAKER PREMIER PACKER 3.875 12,435.2 6,902.7 61.80 NIPPLE HES'X'NIPPLE 3,810 VALVE; 2,416.8 NIPPLE; 2,416.e 12,529.1 6,946.7 62.57 OVERSHOT BAKER TUBING POORBOY OVERSHOT LANDED 4.41' OVER STUB 3.875 Tubing Description String Ma... ID (in) Top (RKB) Set Depth (R.. Set Depth (TVD) (... Wt (lb/ft) Grade Top Connection TUBING Original 41/2 3.958 12,524.5 12,625.8 6,989.3 12.60 L-80 IBTM Completion Details Nominal ID Top (RKB) Top (TVD) (WEI) Top Inc[ (°) Item Des Co. (in) 12,531.2 6,947.7 62.63 PACKER BAKER S-3 PACKER w/Millout Extension 3.875 12,613.3 6,984.1 64.76 NIPPLE HES XN NIPPLE 3,725 12,624.51 6,988.81 65.08 WLEG BAKER WIRELINE GUIDE 3.875 SURFACE; 36.6-3,121.1- Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (TVD) Top Incl Top (RKB) (RKB) I (°) Des Com Run Date ID (in) 2,416.9 2,010.E 55.43 VALVE 4.5" 2-6, 3.81" DB LOCK & 4.5" A-1 INJECTION 9/2/2014 1.250 VALVE (SIN: HYS461), 1.25" ORIFICE Mandrel Inserts GAS LIFT; 12,216A St ati C o^ No Top (RK8) Top(TVD) IRK Make Mode[ OD (in) S., Valve Type Latch Type Port S[ze (in) TRO Run (psi) Run Date 1 12,216.4 6,799.9 CAMCO KBG-2 1 GAS LIFT DMY BK-5 0.D 0.0 427/2005 Notes: General & Safety End Date Annotation - 4/30/2003 NOTE: TREE: FMC 4 1/16 5K - TREE CONNECTION: 7" OTIS 9/3/2010 NOTE: VIEW SCHEMATIC w/Alaska Schematic9.0 PACKER; 12,329.8 NIPPLE; 12,435.2 OVERSHOT; 12,529.1 PACKER; 12,531.2 NIPPLE; 12,613.3 WLEG; 12.624.4 PRODUCTION; 34.&13,245.8- OPEN HOLE; 13246.0-17,320.0 •' STATE OFALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: lim.repp(c_alaska.gov; AOGCC.Inspectorsoalaska.gov: phoebe.brooks(a_alaska.gov chris.wallace(a)alaska.gov OPERATOR: ConocoPhillips Alaska, Inc. FIELD / UNIT / PAD: Colville River Field/ CRU / CD2-51 DATE: 03/14/16 OPERATOR REP: Phillips AOGCC REP: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well CD2-51 I Type In'. I G TVD 1 6,853' Tubin 4,015 4,015 4,015 4,015 1 Interval O P.T.D. 2022490 I Type test I P Test psi 3000 Casing 2,150 3,000 2,990 2,990 1 P/FJJ P Notes: Diagnostic MITIA OA 690 690 690 1 680 Well I Type In'. TVD Tubing Interval P.T.D. I Type test I I Test psil CasingP/F Notes: OA Well I Type Inj. TVD Tubing Interval P.T.D. I Type test I Test psil Casing P/F Notes: OA Well I Type Inj. I TVD Tubing Interval P.T.D.1 I Type test I Test psi Casing P/F Notes: OA Well I Type In'. I TVD Tubing Interval P.T.D.1 I Type testl I Test psi I 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 Form 10-426 (Revised 11/2012) CD2-51 10-426.xls INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance O = Other (describe in notes) 13 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 April 17, 2016 Commissioner Foerster Alaska Oil & Gas Conservation Commission 333 West 71h Avenue, Suite 100 Anchorage, AK 99501 Dear Ms. Foerster: RGCEI Y E6 APR 19 2016 A®GCC ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 18C, Rule 11, to apply for administrative approval to allow CRU injection well CD3-128 (PTD 211-037) to remain in water only injection service. Currently the well has known tubing by inner annulus communication only while on miscible gas injection. If you need additional information, please contact us at your convenience. Sincerely, Jan Byrne/ Dusty Freeborn Problem Wells Supervisor ConocoPhillips Alaska, Inc. Office phone: (907) 659-7126 Cell phone: (907) 943-0450 �WELLS TEAM ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Alpine Well CD3-128 (PTD 211-037) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this administrative relief request as per Area Injection Order 18C, Rule 11, to continue water only injection for Colville River Unit injection well CD3-128 (PTD 211-037). The well displays tubing by inner annulus communication only while the well is on miscible gas injection. Well History and Status Colville River Unit well CD3-128 was completed as a development well in February of 2012 and converted to a WAG injector in October of 2013. CD3-128 was reported to the Commission on May 13, 2015 for a suspect inner annulus pressure increase while on miscible gas injection. Passing diagnostic tests including an MIT -IA and wellhead pack off tests were performed May 17, 2015 (10-426 attached). Due to an ice plug developing in the tubing of C133-128 and the remote location of CD3 pad diagnostics were delayed until the start of the 2015/16 ice road season. After the ice plug was removed additional passing diagnostic MITs were performed in January of 2016 (10-426 attached). An AOGCC approved monitor period took place subsequent the diagnostic MITS during which the well was on water and miscible gas injection. IA pressure build up data was captured while on miscible gas injection. No TxIA communication was observed while on water injection. ConocoPhillips intends to pursue repairs if tubing by inner annulus communication develops while on water injection, however, at this point in time the well exhibits no indications of tubing by inner annulus communication while on water injection, therefore ConocoPhillips requests an administrative approval (AA) which will allow for continued injection of water only. Barrier and Hazard Evaluation With only water injection, this well has all the barriers of a normal injection well Tubing: The 3-1/2" 9.3 lb L-80 tubing has integrity to the packer at 12,31 l' MD (6745' TVD), based on passing multiple diagnostic MITs and TIO trends. Production casing: The 7" 26 lb L-80 production casing has integrity to the packer at 12,311, MD (6745' TVD) based on the aforementioned MITs and TIO trends. Surface casing: The 9-5/8" 36 lb J-55 surface casing has an internal yield pressure rating of 3520 psi. The surface casing has integrity based on TIO trends. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Problem Wells Supervisor 4/17/2016 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Secondary barrier: The production casing is the secondary barrier should the tubing fail. Tertiary barrier: The surface casing will act as a third barrier in the unlikely case that the first two normal barriers have failures. Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the completion it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. TIO trends are compiled, reviewed, and submitted to the AOGCC for review 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 maximum anticipated injection 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 diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. 6. Anniversary date to be set on the 28th of February 2018 (last AOGCC witnessed test; February 23, 2014) to align the AOGCC witnessed testing with the UIC MIT permanent 4 year scheduled pad testing. Problem Wells Supervisor 4/17/2016 2 Well Name Start Date Days End Date CD3.128 1/1812016 90 4117/2016 Notes; Bleed Nistm Annular Communication Surveillance 450 — WHP IAP ©AP 40a 1WHT 3500 3000 2S00 a, 2000 15aa 1000 so IAI r Ir 0 000-15 Jan.16 Mar-16 Apr-16 May-16 160 1 S0 140 130 120 LL t 741D 100 sa 8a 70 60 WELL —ID TIME STR-PRES END-PRES DIF-PRES CASING SERVICE CD3-112 3/23J2016 2230 1S00 730 INNER 411S saga 49301.Qt31 4aaa asaa aaaa Ssaa :aaa M01 PNA OLP4 �_ i saa i aaa saa Osc-15 Jan-16 Pab•te Mar 16 Apr-16 May-16 Date /r'\ WNS INJ CD3-128 ConocoPhillips well Attributes jMaxAmqle&MD ITD Alaska, Ill(;. Welibore APVUWI Field Name Wellbore Status 501WI 032063800 FIORD NECHELIK INJ nd V) MD (ftKB)Act 91.79 1923D.70 Btm (ftKB) 20,387.0 Comment M25 (pp.) I Data SSSV: TRDP Annotation End Date Last WO: 2/21/2012 KB-Grd (k) Rig Release Date 36.80 4/30/2011 HORIZONTAL- CD3-128, 2/12I2016131:00 PM erficalacnemefic actual Annotation Depth (kKB) End Date Last Tag: SLM 12,822.0 8/14/2012 Annotation Rev Reason: PULL, PLUG, FISH, MILLED ICE Last Mod By End pproven Date 2/16/2016 ................ ...............HANGER. 3�.E; PLUG as ng r ngs Casing Description OD (in) CONDUCTOR Insulated 16 ID (in) 15.250 Top (ftKB) 36.8 Set Depth (ftKB) 114.0 Set Depth (TVD)... 114.0 Wt/Len (I... 62.50 Grade H-40 Top Thread WELDED 42" CONDUCTOR Insulated 42-; Casing Description OD (In) SURFACE 95/8 ID (in) 8.921 Top (ftKB) 36.4 Set Depth (ftKB) 2,989.0 Set Depth (TVD)... 2,451.1 WVLen (I... 36.00 Grade J-55 Top Threetl BTGM 36.8-114.0 Casing Description OD (In) PRODUCTION 7 ID (in) 6.276 Top (ftKB) 32.8 Set Depth (kKB) 13,009.0 Set Depth (TVD)... 6,980.4 Wt/Len (I... 26.00 Grade L-80 Top Thread BTGM Casing Description OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD)... WOLen (I... Grade Top Thread SAFETY VLV; 2,179.5 OPEN HOLE 6118 18,685.0 20,387.0 7,082.6 Casing Description 00 (In) LINER 4112 ID (in) 3.958 Top (ftKB) 12,694.7 Set Depth (kKB) 18,685.0 Sel Depth (iVDJ... 7,061.9 Wi/Len (I... 12.60 Grade L-80 Top Thread IBTM Liner Details SURFACE; 36.4-2,989.0-- A Nominal ID GAS LIFT; 5,097.5 Top (ftKB) Top (TVD) (ftKB) Top Intl (°) It.. Des Com (in) 12,694.7 6,912.4 70.90 SLEEVE HRD LINER SETTING SLEEVE 5.250 12,706.9 6,916.4 71.45 NIPPLE RS PACK -OFF SEAL NIPPLE 4.250 GAS LIFT; 9,972.E 12,709.5 6,917.2 71.56 HANGER DG FLEX -LOCK LINER HANGER 4.360 12,718.8 6.920.1 72.01 SBE SEAL BORE EXTENSION 4.000 GAS LIFT; 12,228.8 13,068.8 6,986.3 85.44 Swell Packer TAM FREECAP SWELL PACKER FSG11 w/ 5.875" OD CEMENTRALIZER 3.920 SEAL ASSY; 12,282.9 13,123.3 6,989.7 87.36 Swell Packer TAM FREECAP SWELL PACKER FSG11 w/ 5.875" OD CEMENTRALIZER 3.920 PBR; 12,287.8 Tubing Strings PACKER; 12,311.0 Tubing Description String Ma... ID (in) Top (ftKB) Set De (ft.. Set Depth (TVD) (... Wt (Ib/ft) Grade Top Co nnetli,n TUBING WO 3 1/2 2.992 30.E 12,738.5 6,926.0 9.30 L-80 EUE Mod NIPPLE; 12,353.6 Completion Details GAS LIFT; 12,396.2 Top (ftKB) Top (TVD) (ftKB) Top Inca (°) Item Des Com Nominal ID (in) 30.6 30.6 0.00 HANGER FMC TUBING HANGER 4.500 115.9 115.9 0.18 XO Reducing CROSSOVER 4.5 x 3.5, 9.3, L-80, EUE-MOD 3.500 RPERF; 12,476.0-12,496.0- 2,179.5 2,014.3 48.05 SAFETY VLV CAMCO TRMAXX-5E SAFETY VALVE w/ 2.813" X 2.812 PROFILE SLEEVE-C; 12,545.9 12,282.9 6,731.3 60.27 SEAL ASSY BAKER SEAL ASSEMBLY LOCATOR 3.000 12,287.8 6,733.7 60.29 PBR BAKER 20' 80-40 PBR 4.000 PACKER; 12,596.0 12,311.0 6,745,21 60.51 PACKER BAKER PREMIER PACKER 2.970 12,353.6 6,766.0 60.89 NIPPLE HES X NIPPLE 2.813 NIPPLE; 12,665.5 12,447.7 6,811.1 61.94 BLAST -RING SCC TUBING W BLAST RING INSTALLED, TOP 2.992 12,476.7 6,824.7 62.36 BLAST RING SCC TUBING w/ BLAST RING INSTALLED, BOTTOM 2.992 LOCATOR; 12,704.3 12,545.9 6,855.5 64.67 SLEEVE-C BAKER CMD SLIDING SLEEVE w/ 2.812" X PROFILE (CLOSED 5/25/2013)-ATTEMPTED TO OPEN SLEEVE, 2.810 4280 KEYS DID NOT ENGAGE; UNCERTAIN IF SEAL ASSY; 12,727.1 SLEEVE OPENED OR CLOSED (811312013) SEAL ASSY; 12,736.5 SHOE; 12,738.1 12,596.0 6,876.3 66.29 PACKER BAKER PREMIER PACKER 2.870 12,665.5 6,902.5 69.60 NIPPLE HES XN NO GO NIPPLE 2.750 12,704.3 6,915.5 71.33 LOCATOR GBH-22 LOCATOR SPACED OUT 2' ABOVE FULLY 2.960 LOCATED PRODUCTION; 32.8-13,000.0- 12,727.1 6,922.6 72.41 SEAL ASSY SPACER TUBE SEAL SUB 3.000 - 12,736.5 6.925.4 72.87 SEAL ASSY LOWER SEAL SUBS 3.000 12,738A 6,925.9 22.94 SHOE MULE SHOE 3.000 Perforations & Slots Shot Dens PERFP; 13,217.0-13,222.0 PERFP; 13,508.0-13,512.0 Top (ftKB) St. (ftKB) (ftKB) Top (TVD)t6,991.7 Zone Date (shotsM 0 Type Com 12,476.0 12,496.0 6,824.3 Kuparuk, -128 CD3 5/52011 12.0 RPERF 4 5/8" 39 gm, 60 deg phase 13,217-0 13,222.0 6,991.7 Nechelik, CD3 2/22/2012 1.0 PERFP 4.78' PERF PUPS PERFP; 13,875.0-13,880.0 -128 13,608.0 13,512.0 6,991.7 Nechelik, CD3 2/22/2012 1.0 PERFP 4.78' PERF PUPS 128 PERFP; 14,236.0-14,240.0 13,875.0 13,880.0 7,000.4 7,000.E Nechelik, CD3 2/22/2012 1.0 PERFP 4.78' PERF PUPS 128 PERFP; 14,811.0-14,616.0 14,236.0 14,240.0 7,007.4 7,007.5 Nechelik, CD3 2I22I2012 1.0 PERFP 4.78' PERF PUPS -128 PERFP; 14,975.0-14,980.0 14,611.0 14,616.0 7,014.2 7,014.2 Nechelik, CD3 2/222012 1.0 PERFP 4.78' PERF PUPS -128 PERFP; 15,342.0-15.347.0 14.975.0 14,980.0 7.015.6 7'015.6 Nechelik, CD3 2/222012 1.0 PERFP 4.78' PERF PUPS -128 PERFP; 15,705.0-15,7100 15,342.0 15,347.0 7,017.5 7,017.E Nechelik, CD3 2/222012 1.0 PERFP 4.78' PERF PUPS -128 PERFP; 16,070.0-16,075.0 15,705.0 15,710.0 7,023.3 7,023.4 Nechelik, CD3 2/22/2012 1.0 PERFP 4.78' PERF PUPS -128 PERFP; 16.440.0.16,445.0 16,070.0 16,075.0 7,023.8 7,023.9 Nechelik, CD3 2/22/2012 1.0 PERFP 4.78' PERF PUPS FRAC; 13,217.0 -128 PERFP; 16,804.0-16,808.0 16,440.0 16,445.0 7,034.3 7.034.4 Nechelik, CD3 2/222012 1.0 PERFP 4.78' PERF PUPS -128 PERFP; 17,172.0-17,177.0 16,804.0 16,808.0 7,042.3 7,042.3 Nechelik, CD3 2/22/2012 1.0 PERFP 4.78' PERF PUPS 128 PERFP; 17,541.0-17,546.0 17,172.0 17,177.0 7,044.3 7,044.3 Nechelik, CD3 2/22/2012 TO PERFP 4.78' PERF PUPS PERFP; 17,904.0-17,908.0 -128 PERFP; 18,286.0-1$270.0 17,541.0 17,546.0 7,046.4 7,046.5 Nechelik, CD3 2/22/2012 1.0 PERFP 4.78' PERF PUPS -128 PERFP; 18,633.0-18,637.0 17,904.0 17,908.0 7,049.1 7,049.2 Nechelik, CD3 21222012 1.0 PERFP 4.78' PERF PUPS -128 LINER; 12,894.7-18,685.0 OPEN HOLE; 18.885.0-20,387.0 :: r WNS INJ C®3-128 Conoci3 hillips , Alaska. inc. HORIZONTAL - CO3-128, 2112QO16 131-04 PM eM- ae mart ac ............................................................................................ HANGER; 30.6 _....___....._......._.._._..._._ _.... _ Perforations & Slots Shot _ ................................... ............ ...._......._ Dens Top (TVD) St. (TVD) tshotaH Top (ftKB) Btm (ftKB) (ftKB) (ftKB) Zone Date t) Type Com CONDUCTOR I—Ielad42'; 18,266.0 18,270-0 7,052.6 7,052.7 Nechelik, CD3 2/22/2012 1.0 PERFP 4.78' PERF PUPS 36.8-114.6 -128 18,633.0 18,637.0 7,061.5 7,061.6 Nechelik, CD3 2/22/2012 1.0 PERFP 4.78' PERF PUPS -128 SAFETY VLV; 2,179.5 Stimulations & Treatments Min Top Max Blm Depth Depth p(TVD) Ben(TVD) To SURFACE; 36.4-2,989.0— (ftKB) (ftKB) (ftKB) (ftKB) Type Date Com 13.217.0 20,387.0 6,991.7 7,082.6 FRAC 3/9/2012 Performed fracturing treatment, pumping five main GAS LIFT; 5,097.5 frac stages consisting of Ob ppa stages separated by four Bioball ball drop sequences. Pumped 220-bbl breakdown with 25-I1b lineargel, followed by main frac of 467,219-lbs of 16/20 Carbolite in 25# crosslink gel GAS LIFT; 9,972.6 (87 % design). During last frac stage, extended the 4- ppa stage to 420-bbl GAS LIFT; 12,228.E Mandrel Inserts St ali SEAL ASSV; 12,282.9 N Top (ftKB T (ftKB)D) Make Model OD (in) Sere Type Type Po(i Size T (D ) Run Date Com PSR; 12.287.8 1 6,097.5 3,401.2 CAMCO KBMG 1 GAS LIFT DMY BK 0.0001 0.0 11/l/2013 PACKER; 12,311.0 2 9,972.6 5,588.9 CAMCO KBMG 1 GAS LIFT DMY BK 0.000 0.0 11/12013 3 12,228.6 6,704.6 CAMCO KBMG 1 GAS LIFT DMY BK 0.000 0.0 11/52013 NIPPLE; 12,353.8 4 12,396.2 6,786.6 CAMCO KBMG 1 GAS LIFT HFCV BEK 0.000 0.0 8/13/2012 GAS LIFT; 12,396.2 Notes: General & Safety End Date Annotation 5/3/2011 NOTE: View Schematic w/ Alaska Schematic9.0 2/21/2012 NOTE: Well suspended after original drill/completion 2011; re-entered and drilled deeper, WO, 2012 RPERF; 12,478.0-12,496.0— 5/25/2015 NOTE: ICE PLUG AT 3691 SLIM SLEEVE-C; 12,545.9 PACKER; 12,596.0 NIPPLE; 12,665.5 LOCATOR; 12,704.3 SEAL ASSY; 12.727.1 SEAL ASSV; 12,736.5 SHOE; 12,738.1 PRODUCTION; 32.8-13,009.0— PERFP; 13,217.0-13,222.0 PERFP; 13,508.0-13,512.0 PERFP; 13,875.0-13,880.0 PERFP; 14,236.0-14,240.0 PERFP; 14,611.0-14,616.0 PERFP; 14,975.0-14,980.0 PERFP; 15,342.0-15,347.0 PERFP;15,705.0-15,710.0 PERFP; 16,070.0-16,075.0 PERFP; 16,440.0-16,445.0 FRAC; 13,217.0 PERFP; 16.804.0-16,808.0 PERFP; 17,172.0-17,177.0 PERFP; 17,541.0-17,546.0 PERFP; 17,904.0-17,908.0 PERFP; 18,266.0-18270.0 PERFP; 18,633.0-18,637.0 LINER; 12,694.7-18,685.0 OPEN HOLE; 18.685.0-20387.0 - STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: lim.regg(a)alaska.gov; AOGCC.Inspectors(a)alaska.gov; phoebe.brooks(aDalaska.gov chris.wallace(cDalaska.gov OPERATOR: ConocoPhillips Alaska, Inc. FIELD / UNIT / PAD: Kuoaruk / CRU / CD3-PAD DATE: 05/17/16 OPERATOR REP: Riley AOGCC REP: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well CD3-128 I Type Inj. I N TVD 1 6,745' Tubing 3,350 3,5 01 3,5501 3,550 1 1 Interval O P.T.D. 2110370 I Type test I P Test psi 1 1686.25 Casingl 2,280 3,0001 2,9801 2,975 P/F I P Notes: Diagnostic MITIA OAT 215 2251 2251 225 WeIll I Typelnj.1 I TVD I I Tubingl I I I Interval P.T.D.1 I Type testl I Test psi I I Casing P/F Notes: I OA WeIll Type Inj. I TVD I I Tubingl I I I I I Interval P.T.D.1 I Type test I Test psi I I Casing P/F Notes: I OA Welli I Typelnj.1 I TVD I I Tubingl I I I I Interval P.T.D.1 I Type testl I Test psi I I Casing P/F Notes: I OA WeIll I Type Inj. TVD I Tubingl I I I I Interval P.T.D.1 I Type testl I Test psi I I Casing P/F Notes: I OA TYPE INJ Codes TYPE TEST Codes D = Drilling Waste M = Annulus Monitoring G = Gas P = Standard Pressure Test I = Industrial Wastewater R = Internal Radioactive Tracer Survey N = Not Injecting A = Temperature Anomaly Survey W = Water D = Differential Temperature Test INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance O = Other (describe in notes) Form 10-426 (Revised 11/2012) MIT CRU diagnostic MITIA CD3-198 5-17-15.xls STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: jim.regg(coalaska.gov; AOGCC.Inspectorsaalaska.gov; phoebe.brooks(a)alaska.gov chris.wallaceCa)alaska.gov OPERATOR: ConocoPhillips Alaska, Inc FIELD / UNIT / PAD: Kuparuk / CRU / CD3 Pad DATE: 01 /25/16 OPERATOR REP: Condio AOGCC REP: 4- Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well CD3-128 Type Inj. N TVD 1 6,745' Tubing 1,700 3,000 2,950 2,950 Interval O P.T.D.2110370 Type test P Test psi 1 1686.3 Casing 1,580 1,620 1,620 1,620 P/F P Notes: Diagnostic MIT-T against plug at 12,353' RKB. CA 228 230 229 229 Well CD3-128 Type Inj. I N TVD 1 6,745' Tubing 1,650 1,660 1,660 1,660 Interval O P.T.D. 2110370 Type test I P Test psi 1686.25 Casing 1,600 2,550 2,490 2,475 P/F P Notes: Diagnostic MIT -IA. CA 228 244 243 243 Well I Type Inj. TVD Tubing Interval P.T.D. I Type test Test psi I Casing P/F Notes: CA Well I Type Inj. I TVD I Tubing Interval P.T.D. I Type test I Test psi Casing P/F Notes: CA Well I Type Inj. I TVD I Tubing Interval P.T.D. I Type test I Test psi Casing P/F Notes: CA--4- TYPE INJ Codes TYPE TEST Codes D = Drilling Waste M = Annulus Monitoring G = Gas P = Standard Pressure Test I = Industrial Wastewater R = Internal Radioactive Tracer Survey N = Not Injecting A = Temperature Anomaly Survey W = Water D = Differential Temperature Test INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance O = Other (describe in notes) Form 10-426 (Revised 11/2012) MIT CRU diagnostic MITTT and MITIA CD3-128 1-25-16.xls 12 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 301" day of March 2016 Commissioner Foerster Alaska Oil and Gas Conservation Commission 333 West 7t' Avenue, Suite 100 Anchorage, AK 99501 APR 04 2016 AOGCC RE: C134-213B (PTD #212-005-0) Request for cancellation of Administrative Approval A10 18C.007 Commissioner Foerster: ConocoPhillips requests cancellation of Administrative Approval AIO 18C.007 The approval, originally issued January 28, 2016, was for continued water injection in well CD4-21313 (PTD #212-005-0) with communication from the tubing to the inner annulus while injecting gas. A RWO to repair the communication was completed in March of 2016. A passing AOGCC witnessed MITIA was performed on the 301' of March 2016 (see attached MIT form). This request is to cancel the Administrative Approval and return the well back to normal injection operation. Please call Jan Byrne or myself at 659-7126 if you have any questions. Sincerely, za2L'a Dusty Freeborn / Jan Byrne Problem Wells Supervisor ConocoPhillips Alaska, Inc. Desk Phone (907) 659-7126 Pager (907) 659-7000 pgr. 123 WELLS TEAM p STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submitto: lim.regg(cDalaska.gov; AOGCC.Insoectors(a).alaska.gov; phoebe. brooks(a)alaska.gov chris.wallace2Dalaska.aov OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: ConocoPhillips Alaska, Inc. ALPINE/ CRU/ CD4 03/30/16 Miller / Sumrall Brian Bixby Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well CD4-213B I Type Inj. I G TVD 1 7,413' Tubing 3,455 3,455 3,455 3,455 1 1 Interval P.T.D.2120050 I Type test I P Test psi 1853.25 Casing 1,006 2,500 2,475 2,470 P/F P Notes: Initial State Witnessed MITIA post RWO OA 361 363 363 363 Well I Type Inj. TVD Tubing I I Interval P.T.D. I Type test I Test psi I Casing I I I I I I P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test I Test psi I Casing P/F Notes: OA TYPE INJ Codes TYPE TEST Codes D = Drilling Waste M = Annulus Monitoring G = Gas P = Standard Pressure Test I = Industrial Wastewater R = Internal Radioactive Tracer Survey N = Not Injecting A = Temperature Anomaly Survey W = Water D = Differential Temperature Test INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance O = Other (describe in notes) Form 10-426 (Revised 11/2012) MIT CRU CD4-2136 03-30-16.xls 11 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 March 19, 2016 Commissioner Foerster Alaska Oil & Gas Conservation Commission 333 West 7U' Avenue, Suite 100 Anchorage, AK 99501 Dear Ms. Foerster: RECEIVE[: MAR 2 2 20ib AOGCC ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 18C, Rule 11, to apply for administrative approval to allow CRU injection well C134-27 (PTD 211-146) to remain in water only injection service. Currently the well has known tubing by inner annulus communication only while on miscible injection. If you need additional information please contact us at your convenience. Sincerely, Jan yrne/ Dusty Freeborn Problem Wells Supervisor ConocoPhillips Alaska, Inc. Office phone: (907) 659-7126 Cell phone: (907) 943-0450 ' tELLS TEAM ccnx' Phillips ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Alpine Well CD4-27 (PTD 211-146) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this administrative relief request as per Area Injection Order 18C, Rule 11, to continue water only injection for Colville River Unit injection well CD4-27 (PTD 211-146). The well displays tubing by inner annulus communication only while the well is on miscible gas injection. Well History and Status Colville River Unit well CD4-27 was completed as a development well in April of 2012 and converted to as a WAG injector in August of 2012. CD4-27 was reported to the Commission on December 24, 2015 for a suspect inner annulus pressure increase while on miscible gas injection. Passing diagnostic tests including an MIT -IA and wellhead pack off tests were performed December 30, 2015 (see attached 10-426). An AOGCC approved diagnostic monitor period took place, during which the well was on water and miscible injection. IA pressure build up data was captured while on miscible injection. No TxIA communication was observed while on water injection. ConocoPhillips intends to pursue repairs if tubing by inner annulus communication develops while on water injection, however, at this point in time the well exhibits no indications of tubing by inner annulus communication while on water injection, therefore ConocoPhillips requests an administrative approval (AA) which will allow for continued injection of water only. 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 lb L-80 tubing has integrity to the packer at 12,796' MD (7412' TVD), based on passing a MIT -IA to 3500 psi on 12/30/15 and TIO trends. Production casing: The 7" 26 lb L-80 production casing has integrity to the packer at 12,796' MD (7412' TVD) based on the passing MIT -IA aforementioned and TIO trends. Surface casing: The 11-3/4" 60 lb L-80 surface casing has an internal yield pressure rating of 5830 psi. The surface casing has integrity based on TIO trends. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Secondary barrier: The production casing is the secondary barrier should the tubing fail. Problem Wells Supervisor 3/19/2016 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Tertiary barrier: The surface casing will act as a third barrier in the unlikely case that the first two normal barriers have failures. Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the completion it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. TIO trends are compiled, reviewed, and submitted to the AOGCC for review 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 maximum anticipated injection 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 diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. 6. Anniversary date to be set on the 30th of June 2017 (last AOGCC witnessed test; June 12, 2015) to align the AOGCC witnessed testing with the UIC MIT permanent 4 year scheduled pad testing. Problem Wells Supervisor 3/19/2016 2 Well Name CD4-27 Notes: Start Date 12.120/2015 Days 90 End Date 311912016 Annular Communication Surveillance 4E +' " 0 — '� P -- - - ------ — 160 _ CAP VJHT 1CI0 400 140 3=on 13D 3000 12D U. 2500 0 A 2000 - 100 1500 90 1000 sa 500 70 0 ---- 60 Nov 15 Dea15 Jan-16 Feb-16 1Aar-16 Apr-16 :zw» Saco 1Ff� — QGI j jrV. 3 <rYr — BLPD N ov-15 Dea15 Jan-16 Feb-16 14 ar-16 Apr-16 Date Bleed History 'JELL ID TIME STR-PRES END-PRES DIF-PRES CASING SERVICE CD4-27 21612016 21 29E -274 INNER SY6 CD4-27 2/4/2016 120 0 120 INNER SIA(I CD4-27 202016 293 64 229 INNER S11I CD4-27 V3112016 1023 210 Bill INNER SY0 CD4-27 1111201E 190 130 eo INNER 41Is CD4-27 12131/2015 1 1060 1 12B 932 1 INNER 1 41IS CD4-27 12i3012015 2290 2-5 204E INNER I.115 C04-27 1212612015 2400 1700 700 INNER I.Ils CD4-27 1212212015 2600 1-00 1000 INKIER GiIS WNS INJ C D4-27 ConocoPhillips " Well Attributes Max Angle & MD TD Alaska, IncWIC...."t Wellbore APU Wl Fluid Name 501032064400 ALPINE Wellbore Status INJ nel (°) MD (RKBI 94.63 13,2W.94 ActBtm (ftKB) 16.878.0 --- H251ppm1 Date SSSv: WRDP Annotation Entl Data KBLrO (tt) Last WO: Rig Release Date 4/28/2012 HORIZONTAL-CD4-27, 11PI712M 2W07 PM Vertical schematic aciuel Annotation Depth (ftKB) End DMa Annotation Last Mod By End Date Last Tag: Rev Reason: PULLED AND REPLACE INJ pproven 11l17/2015 HANGER; 22.1 VALVE asing ngs Casing Description DO (in) ID (In) Top (ftKB) Set Depth (ftKB) Set Depth (TVD)... WULen (I... Grade Top Thread CONDUCTOR 3W is 15.062 36.0 114.0 114.0 62.50 J-55 WELDED Insulated Casing Description OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD)... WdLen (1... Grade Top Thread SURFACE 11 314 10.772 36.7 3,227.8 2,377.5 60.00 L-80 BTCM Casing Deacrlptlon OD (In) ID (In) Top (1tICB) Set Depth (ftKB) Set Depth (TVD)... WULen (I... Grade Top Thread INTERMEDIATE 1 9M 8.835 3,067.0 10.905.0 6,448.7 40.00 L-80 Hyd.521 -- -- Casing Description OD (in) ID (In) Top (ftKB) Set Depth (ftKB) Set Depth (TVD)... WULen (I... Grade Top Thread --- INTERMEDIATE 2 7 6.276 33.8 13,064.0 7,529.0 26.00 L-80 BTCM CONDUCTOR 30" Insu41e4 Cueing Deecriptlon OD (In) ID (In) Top (ftKB) Set Depth (ftKB) Set Depth ITVD)... WULen (I Gretle Top Threat!36.0.114.0 OPEN HOLE 6. 151 15.179.0 16.878.0 Casing Description OD (in) ID (in) lop (ftKB) Set Depth (ftKB) Set Depth (TVD)... WULen (I... Grade Top Thread NIPPLE; 2AS7.5 VALVE. 2,3811.5 LINER 412 3.958 12]95.5 15,179.0 7,516.6 12.60 1-80 SLHT Liner Details Nominal 10 Top (ftKB) Top (TVD) (nK8) Top Ind (°) hem Des Co. (in) 12,795.5 7,412.2 60.21 PACKER BAKER HRD ZXP LINER TOP PACKER 5.500 12,821.3 7,425.0 60.25 HANGER BAKER FLEX LOCK HANGER 5.510 12,886.4 7,457.1 60.84 NIPPLE HES %N' NO GO NIPPLE 3.725 13,038.4 7,522.5 73.15 Swell Packer TAM SWELL PACKER FREECAP-1 FSC-14 3.960 13,596.9 TS19.7 92.72 Swell Packer TAM SWELL PACKER FREECAP-1 FSC-14 3.960 Tubing Strings SURFACE; 36.7-3,227.e Tubing Description String Ma... ID (in) Top (nKB) Sel Depth (h Set Depth (TVD) (... WI (Iblft) Grade Top Connection TUBING 4 12 3.958 221 12.814.5 7,421.6 12.60 L-80 HYD.563 - Completion Details Nominal ID GAS LIFT; 5.167.3 - Top (ftKB) Top (TVD) (ftKB) Top Intl (°) Item Des Com (In) 22.1 22.1 O.00 HANGER FMC TUBING HANGER 3.958 -- 2,381.5 1,944.0 59.48 NIPPLE BAL-0 LANDING NIPPLE 3.812 - 12,799.3 7,414.1 60.22 LOCATOR MECHANICAL COLLAR LOCATOR 3.850 12,800.1 7,414.5 60.22 SEAL ASSY BAKER BULLET TIEBACK SEAL ASSEMBLYwith 1/2 3.850 GAS LIFT; 9,313.5 MULE SHOE Other in Hole reline retrievable plugs, valves, pumps, fish, etc.) Top (TVD) Top Ines Top (ftKB) (ftKB) .;net I Des Com Run Date ID (In) 2,381.5 1.944.1 59.48 VALVE MOD A-1 [NJ VLV (SIN: HACS-0028r 1.25" 11/3/2015 1.250 ORIFICE! 3.84" BTM PACKING - 3.83" TOP/ CAL = 13.81" 75.761 13, 150.0 7,539.8 87.55 FISH LOST TX.875" PRONG BELOW 13147'SLM 11/2/2012 0.000 Perforations & Slots Shot Dens Top ITVD) elm (TVDI (shotslr Top (ftKB) Bt. (ftKB) (ftKB) (ftKB) Zone Date t) Type Com 13,742.0 14.866.0 7,511.6 7,507.0 4/24/2012 1 32.0 SLOTS SLOTTED LINER 15.149.0 15,179.0 7.515.4 7,516.E 4124/2012 I .0 SLOTS SLOTTED LINER INTERMEDIATE 1; 3.087.0- Mandrel Inserts o.eos.o at GAS LIFT: 12,730.E all on N Top IRKS) Top (TVD) (ftKB) Make Model OD(In) Sere Valve Type Latch Type Port Size (In) TRO Run (pal) Run Date Co. 1 5,167.3 3,395.0 CAMCO KBG-2 1 GA LIFT DMY BK 0.000 0.0 7/15/2012 2 9,313.5 5,609.2 CAMCO KBG-2 1 GAS LIFT DMY BK 0.000 0.0 7/15/2012 3 12,730.6 7,379.9 CAMCO KBG-2 1 GAS LIFT DMY BK 0,000 0.0 7l182012 Notes: General & Safety LOCATOR: 12.199.3 SEALASSY: 12.800.1 End Date Annotation RI' 4262012 NOTE: WELL SIDETRACKED, WINDOW III) 12938'wIORIGINAL API#, PULLED KILL STRING INTERMEOIATE 233.8- 13,064.0 FISH; 13,150.0 SLOTS; 13.742.0.14.565.0 SLOTS; 15,149.0.151179.0 LINER; 12,795b15.179.0 OPEN HOLE; 15,172.0-16,67&0 - - STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: iim.reaoC)a alaska.gov: AOGCC.Inspectors(a)alaska.gov phoebe. brooks(a)alaska.gov chris.wallace(o)alaska.aov OPERATOR: ConocoPhillips Alaska, Inc. FIELD / UNIT / PAD: Alpine / CRU / CD2 DATE: 12/30/15 OPERATOR REP: Paul Duffy AOGCC REP: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well CD4-27 Type Inj. N TVD 7,412' Tubing 3,020 3,020 3,020 3,020 Interval 0 P.T.D. 2111460 Type test P Test psi 1853 Casing 2,290 3,500 3,370 3,355 P/F P Notes: Diagnostic VITA OA 75 80 80 80 Well I Type Inj. I TVD I Tubing Interval P.T.D. I 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. I TVD Tubing Interval P.T.D. I Type test I Test psi I Casing P/F Notes: OA TYPE INJ Codes TYPE TEST Codes D = Drilling Waste M = Annulus Monitoring G = Gas P = Standard Pressure Test I = Industdal 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 CD4-27 diagnostic MITIA 12-30-15 .xls ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 12th Day of January, 2016 Commissioner Foerster Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner Foerster: JAN 19 2016 ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 018C, Rule 9, to apply for administrative approval allowing well CD4-21313 (PTD 212-005-0) to be online in water injection service only. Currently, the well displays TxIA communication only while injecting gas. If you need additional information, please contact myself or Jan Byrne. Sincerely, XV4�� Dusty Freeborn Problem Wells Supervisor ConocoPhillips Alaska, Inc. Office phone: (907) 659-7126 Cell phone: (907) 943-0450 ConocoPhillips Alaska, Inc. Kuparuk Well CD4-213B (PTD# 212-005-0) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this administrative relief request as per Area Injection Order 018C; Rule 9, to continue water only injection for Alpine injection well CD4-213B. The well displays tubing by inner annulus communication only while the well is on gas injection. Well History and Status Colville River Unit well CD4-21313 (PTD# 223-005-0) was originally drilled as CD4-213 which was completed in Dec of 2006 as a service well. The well has since been worked over and sidetracked with C134-21313 being completed on the 30th of June 2012. CD4-213B was initially reported to the Commission on the 18th of October 2015, for an unexplainable IA pressure increase while the well was injecting MI gas. The tubing and inner casing pack off tests passed in both the positive and negative direction and the well passed an MIT IA. However, the showed an IA pressure increase while performing the IA draw down test. The well was converted to produced water injection and monitored for a 30 day diagnostic period in which the IA stabilized and showed no signs of tubing by inner annulus communication therefore passing the long term IA draw down test. The fluid in the IA was replaced with fresh fluid and the well was converted back to MI injection for a 30 day monitor period. The IA once again showed a pressure increase indicating the well has a gas only tubing by inner annulus leak. ConocoPhillips intends to pursue repairs if tubing by inner annulus communication is identified. However, at this point in time the well demonstrates tubing by inner annulus integrity while on water injection and ConocoPhillips requests an administrative approval (AA) which will allow water injection only. 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 at 12,013' MD (7,315' TVD), based on normal operating injection differential pressures and passing a diagnostic MIT -IA to 3044 psi on the 8th of Dec 2015. Production casing: The 7" 26# L-80 production casing has integrity to the packer at 12,013' MD (7,315' TVD) based on the passing MIT -IA test outlined above as well as the differential operating pressure between the tubing and casing. Surface casing: The well is completed with 9-5/8" 40# L-80 surface casing with an internal yield pressure rating of 5750 psi. The surface casing is set at 2713' MD (2382' TVD). Based on differential operating pressure between the production casing and surface casing, integrity of the surface casing has been proven. 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. Well Integrity Supervisor 1/13/2016 Third barrier: The surface casing will act as a third barrier in the unlikely case that the first two normal barriers have failures. Monitoring: Each well is monitored daily for wellhead pressure changes. Should a leak develop in the tubing, production or the surface casing, it will be noted during the daily monitoring process. Pressure trends that indicate annular communication, commission notifications, and corrective action, up to and including a shut-in of the well will be handled appropriately. 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 injection only (no MI or gas injection allowed); 2. Perform a passing MITIA every 2-years to maximum anticipated injection pressure. 3. Allow operating IA pressure up to 2000 psi, 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/or pressures indicate further problems with appropriate notification to the AOGCC. 6. Anniversary date to be set on the 30th of June 2015 (Last AOGCC witnessed test; 121h of June 2015) to align the AOGCC witnessed testing with the UIC MIT permanent 4 year scheduled pad testing. Well Integrity Supervisor 1/13/2016 2 A�,, WNS INJ CD4-213B GonocoPhillips Alaska, if10. ... Well Attributes IMaxAngle&MD JTD Wellbore APINWI Field Name Wellbore Statue 501032054002 NANUO IN net (°) MD vm.) 69.24 12,268.90 Act Et. (ftK81 12:420.0 Comment I H25 (ppm) Date SSSV: NIPPLE Annolallon End Date Last WO: KO-Grd (TO Rig RNease Date 37.10 1/612007 HORIZONTAL -CD4-2139. 12A4M1511'59:45 AM vertical scnemeao (eauap Annotation Depth (HKB) End Date Annotation Last Tag: Rev Last Mad By End Data Reason: GLV C/O, INJ VLV C/O pproven 12/14/2015 HANGER; 31.1 - `e IF .....__..__._..________--._..._... - -Casing - -. CONDUCTOR; 36.a-114.0 NIPPLE; 503e VALVE; 503.E Wnlpstockl2,481.0 WINDOW; 2A91.0.2511.0 SURFACE; 36.7-2,713.I GAS LIFT; 3,310.1 GAS LIFT11,501.3 NIPPLE: 11,956.0 XO Threads; 11.995,2 SEAL ASSY; 11.996.E .� ._ '. X O" ', - INTERMEDIATE; 34.7-12,2035- PERFP;12,347.3-12,350.0 PERFP; 12,353.9-12,356.6 LINER; 12,012.7-12,413.0 asing Strings Caeing Description 00 CONDUCTOR (In) 16 ID (In) 15.260 Top (ftKB) Set 36.4 Depth (ftKB) 114.0 Set Depth (TVD)... 114.0 W[/Len (L.. 6,500 Grade Top H-40 Thread Descripton OD SURFACE (In) 95l8 ID (In) 8.835 Top (ftKB) Set 36.7 Depth (ftKB) 2,713.1 Set Depth (TVD)... 2,381.5 WWVV en 11... 40.00 Grade Top L-80 Thread Casing Description OD INTERMEDIATE (In) 7 ID (In) 6.276 Top (ftKB) Set 34.1 Depth (ftKB) 12,203.5 Set Depth ITVO)... 7,395.8 VMLen 11 26.00 Grade Top L-80 BTC-M Thread Casing Description OD WINDOW (In) 7 ID (in) 6.276 Top (ftKB) Set 2.491.0 Depth (ftKB) 2,511.0 Set Depth (TVD)... 2,242.0 Wt7Len (I... Grade Top Thread Casing Description OD LINER (in) 4 112 ID (In) 3.958 Top (ftKB) 12,012.7 Set Depth (HKB) 12.413.0 Set Depth ITVD)....Len 7,470.8 ll... 12,60 Grade Top L-80 Thread Hyd 563 Liner Details Top (1tI Top ITVD) gtKBl Top III [°) Item Des Con Nominal ID (in) 12,012.7 7,315.1 62.23 PACKER BAKER HRD-E ZXP LINER TOP PACKER 3.875 12,039.2 7,327.3 62.95 HANGER BAKER FLEX LOCK LINER HANGER 3.920 12,049.1 7,331.8 63.21 XO BUSHING BAKER XO BUSHING H521 X H563 3.958 12,091.2 7,360.4 64,44 NIPPLE XN NIPPLE NO-GO 3.725 12.249.2 7,412.6 68.86 1 SWELL PACKER TAM FREECAP II FSC-11 SWELL PACKER (T seal, water activated) Slip on 3.958 12,347.3 7,447.5 69.23 IF C SLEEVE BAKER PRESSURE ACTIVATED FRAC SLEEVE 3.890 12,353.9 7,449.8 69.23 FRAC SLEEVE BAKER PRESSURE ACTIVATED FRAC SLEEVE 3.890 12,360.4 7,452.2 69.23 VALVE BAKER WELLBORE ISOLATION VALVE 3,958 Tubing Strings Tubing Description String Me... ID (In) lop IItKB) set Depih Ift.. set Depth (TVD) (... WI [Ibflt) Grade Top Connection TUBING 41/2 3.958 31.1 12;021.4 7,319.1 12.60 L-80 IBTM Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl 11 It.. Des Core Nominal ID (in) 31.1 31.1 0.00 HANGER FMC TUBING HANGER 3.958 503.8 503.7 2.39 NIPPLE "X"NIPPLE PROFILE 3.813 11,966.0 7,288.0 60.91 NIPPLE "X" NIPPLE PROFILE 3.813 11,996.6 7,307.6 61.79 SEALASSY BAKER SEAL ASSY. BULLET 3.930 Other In Hole (Wlreline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVDI Top FhK0) (°) Incl Des Corr Run Date ID [1n) 503.8 503.6 2.39 VALVE Al INJ. VALVE, OAL=45" (SN: HAGS-0030) 12 WO15 1.250 2,491.0 2,227.7 44.32 I Whipstock Baker XL Gen II whipstock slide. Tagged bridge plug at 2516, set WS 50`R. TOW at 2491'. BOW at 2511' 1111&2014 Perforations & Slots Top (ftKB) Btm (HKB) Top (ND) St. IRKS) (TVD) (ftKBI Zone Dale Shot Dens (ehola/f f) Type Co. 12,347.3 12.350.0 7,447-5 7,448.4 12/12P2014 PERFP FRAC PORT 12,353.9 12.366.6 7,449.8 7,450.8 12)12l2014 PERFP FRAC PORT Cement Squeezes Top (ftKB) St. Top ITVD).. IRKS) (ftKB) BIm (TVD) (HNB) Das Start Date Cm 4,911.0 5,780.0 3,625.9 4,079.8 Cement Plug 9/1dr2014 Lay in 32 bbis of 15.&0 CIasS G cementfrom 5780'to 4945' Mandrel Inserts at all on N Top (HKB) Top (TVp) (11KB) Make Model oD (In) a" Valve Type Latch Port Type Size TRO (In) Run (pal) Run Date Com 1 3,310.1 2,757.3 CAMCO KBG-2 1 GAS LIFT DMY BK 0.000 0.0 1q/2015 DCK-2 2 17,901.3 7,261.1 CAMCO KBG-2 1 GAS LIFT DMY BK-5 0.000 0.0 112T712015 Notes: General & Safety EndDafe Annotation 11/12/2014 NOTE: SIDETRACK TO B STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submitto: jim.regg(cbalaska.gov; AOGCC.Inspectors(a).alaska.gov; phoebe.brooks(d_)alaska.gov chris.wallace(&alaska.aov OPERATOR: FIELD / UNIT / PAD DATE: OPERATOR REP: AOGCC REP: ConocoPhillips Alaska, Inc ALPINE/ CRU / CD4 Pad 12/08/15 LRS N/A Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well CD4-213 Type Inj. W TVD 7,413' Tubing 518 796 792 783 Interval 0 P.T.D. 2120550 Type test P Test psi 1827 Casing 265 3,044 3,009 3,000 P/F P Notes: Diagnostic MIT -IA OA 204 225 224 1221 Well Type Inj. TVD Tubing Interval P.T.D. Type test I Test psi Casing P/F Notes: OA Well I Type Inj. I TVD Tubing Interval P.T.D. I Type test Test psi Casing P/F Notes: OA Well I Type Inj. I TVD I Tubing Interval P.T.D. 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 I Casing P/F Notes: OA TYPE INJ Codes TYPE TEST Codes D = Drilling Waste M = Annulus Monitoring G = Gas P = Standard Pressure Test I = Industrial Wastewater R = Internal Radioactive Tracer Survey N = Not Injecting A = Temperature Anomaly Survey W = Water D = Differential Temperature Test INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance 0 = Other (describe in notes) Form 10-426 (Revised 11/2012) CD4-213 Diagnostic MIT -IA 8 Dec 15.xis STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: phoebe.brooks(cbalaska.gov chris.wallace(Malaska.gov OPERATOR: ConocoPhillips Alaska, Inc. FIELD / UNIT / PAD: Alpine / CRU / CD4 Pad DATE: 06/12/15 OPERATOR REP: Riley/Phillips/Byrne AOGCC REP: Johnnie Hill Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well CD4-03 I Typelnd N I TVD 1 7 382' T.binql 3,6251 3,6101 3.6101 3,6101 Interval 4 P.T.D. 2111130 I Typetestl P I Test psi 1 1845.5 Casinq 1 7211 2,3101 2,2761 2,2691 P/F I P Notes: OA 226 1276 1276 1275 Well CD4-12 I T e In'. G I TVD 1 7 044' Tubinal 3.8141 3,8621 3,8651 3,8641 Interval 4 P.T.D. 2100910 I Type test I P I Test Dsi 1 17611 Casingl 1,9991 2,8081 2,7831 2,7831 P/F1 P Notes: I OA 544 1550 1551 1552 Well CD4-24 I Type In'. I W I TVD 1 7 440' T.binQJ 2.6491 2,6191 2,6091 2,605 1 Interval 4 P.T.D. 2090970 I Type test I P I Test psi 1 1860 Casingl 1,3261 2,1081 2,0871 2,0851 P/F I P Notes: I OA 630 1632 1632 1632 Well CD4-26 I Type In'. I N I TVD 1 7 347' T.binql 3751 3751 3751 375 Interval 4 P.T.D. 2090490 I Type testl P I Test psi 1 1836.751 Casinql 9151 2,3121 2,2881 2,2831 PIFI P Notes: I OA 509 1514 1515 1515 Well CD4-27 I Type In'. I W I TVD 1 7 412' T.bingl 2.6151 2,6121 2,6091 2.6081 Interval 4 P.T.D. 2111460 I Type testl P I Test psi 1 18531 Casing 7011 2,1141 2,0761 2,0741 P/F I P Notes: I OA 0 195 185 183 Well CD4-213H T e In'. I W I TVD 1 7 413' Tubin 2.4751 2,4751 2.4751 2,4751 Interval 1 4 P.T.D. 2120050 I Typetestl P I Test psi 1 1853.251 Ca.inql 1,3651 3,3061 - 3,2681 3,2551 P/F I P Notes: I OA 390 1421 1403 1396 Well I CD4-214 I Type In'. I W I TVD 1 5.967-1 Tubing 2,6151 2,6121 2,6091 2,6081 Intervail 4 P.T.D. 12061450 1 Type test I P I Test psi 1 15001 Casingl 7011 2,1141 2,0761 2,0741 PIFJ P Notes: I OA 0 195 185 183 Well CD4-291 I Type In'.1 W I TVD 1 6,078-1 Tubingl 1,9211 1,9641 1,9701 1.9711 Interval 4 P.T.D. 2131100 I Typetestl P I Test psi 1 1519.51 Casinql 791 2,8101 2,7261 2,7151 P/F I P Notes: I OA 905 1960 1933 1926 Well CD4-302 I Typeind N I TVD 1 6.237-1 Tubinql 4001 4001 4001 400 Interval 4 P.T.D. 2070560 I Typetestl P I Test psil 1559.251 CasinQ1 2091 2,0211 1,9741 1,9651 P/F I P Notes: I OA 616 1826 1816 1812 Well CD4-306 I Tv..Ini.1 W I TVD 1 6 898' TubinqJ 1.8241 1,8351 1,8251 1,8231 Interval 4 P.T.D. 20709.- I Typetestl P I Test psi 1 1724.51 Casing 1,1821 2,8081 2,7711 2,7631 P/FJ P Notes: I OA 608 1749 1738 1738 Well CD4-319 I TvD.InJ N I TVD 1 6.907-1 Tubin 4801 4801 4801 4701 1 1 Interval 4 P.T.D. 2051480 I Typetestl P I Test DSi 1 1726.751 Casingl 7701 2,1541 2,0271 2,0161 P/F1 P Notes: I OA 601 1611 1610 1610 Well I CD4-321 I Type In'. I N I TVD 1 7,181-1 Tubin 100 1001 1001 1001 1 1 Interval V P.T.D. 2061420 I Tvpetestl P I Test Dsi 1 30001 Casingl 159 3,3101 3,2761 3,2671 P/F I P Notes: MITIA to maximum anticipated injection pressure I OA 0 12 11 11 per AIO 18C.002 Well CD4-322 T e In'. N TVD 7,1611 Tubin 150 150 150 150 Interval 4 P.T.D. 2071010 T e test P Testpsil 1790.251 Casingl 6341 2,5111 2,4771 2,4691 P/F Notes: I OA 0 1 1 1 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 0 = Other (describe in notes) Form 10-426 (Revised 11 /2012) MIT CRU C04PAD 08.12A5. ft Well Name Start Date Days End Date CD4-213B 10115/2015 90 1/1312016 Notes: #NIA #NIA MIA MIA Bleed History Annular Communication Surveillance 4EC _WHP ----.- -------- _ - _ OAP —WHT 1=C 1c,G 140 1�C 120 LL 1cG 90 RG 7c c"0 u WELL_11) TIME STR-PRES END-PRES DIF-PRES CASING SERVICE CC -21? 1012F12C15 1793 212 9?1 INNER Ps"iI CC:--21? 1012ZWE 192C 15ce 420 INNER P''M CCe-212 I0119r201` 1E00 9 5 015 INNER 11115 CC<-212 1C+19;2015 2400 1?zc 106? INNER MIS CC--21? 101171201E 2307 1=°1 70r, INNER HIS ?�CG NON 25CG 6 � r 20G0 15cc -- I 1cGG -- ECG G Sep-IE 0ct-15 Now15 Dec-15 Jan-1 FAGI O a ®6^ - P1PA " — BLPe �f Sep-15 C1 ct-1 E N a ',-15 Der -is Jan-16 Date ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 November 19, 2015 Commissioner Foerster Alaska Oil & Gas Conservation Commission 333 West 7t' Avenue, Suite 100 Anchorage, AK 99501 Dear Ms. Foerster: RECEIVED NOV 2 0 2015 A®GCC ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 18C, Rule 11, to apply for administrative approval to allow CRU Blackstart dry gas well CD1-14 (PTD 201-038) to remain in dry gas injection and production service with known tubing by inner annulus communication. If you need additional information please contact us at your convenience. Sincerely, Fne/Dusty '- Jan By Freeborn Problem Wells Supervisor ConocoPhillips Alaska, Inc. Office phone: (907) 659-7126 Cell phone: (907) 943-0450 WELLS 'TEAM ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Alpine Well CD1-14 (PTD 201-038) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this administrative relief request as per Area Injection Order 18C, Rule 11, to continue dry gas injection for Colville River Unit Blackstart injection well CD1-14 (PTD 201-038) with known tubing by inner annulus communication. Well History and Status Colville River Unit injection well CD1-14 was completed in May 2001 as a producer and then converted to a Blackstart injector in September 2001. CD 1-14 is an integral part of the Alpine Blackstart system which consists of two wells (CD 1-06 and CD1-14), a gas/liquid heat exchanger, and an enriching fluid knockout drum. When fuel gas which is traditionally supplied from the production train is unavailable due to plant outage, etc., the gas that was injected into the Blackstart wells is produced back to provide fuel gas for the continued operation of the electrical generation system. The water cut in well CD1-06 currently renders it as non operable as a Blackstart fuel source. Although CPAI is searching for other alternatives, at this time there are no viable candidates. In essence CD 1-14 is the only available Blackstart fuel gas source and the continued operation of the electrical generation system is critical for Alpine camp operations and process safety (heat, lights, instrument air, etc.) in the production facility. Additionally, electrical power is required to restart the production facility after a shut down. Furthermore, Blackstart gas enables continued operations of the Nuiqsut gas skid, which provides fuel gas to the Village of Nuiqsut. Blackstart fuel gas is used annually during the Alpine turnaround (4-30 days depending on the year), and during unplanned plant outages and upsets. CD1-14 was reported to the AOGCC on August 14, 2015 for a suspect IA pressure increase following a pressure bleed. Diagnostic testing was delayed until after the 2015 Alpine turnaround to allow for the use of fuel gas from CD1-14. On September 1, 2015 diagnostic testing including an MIT -IA and tubing and inner casing pack off tests passed. The IA pressure was bled down for a draw down test and exhibited slow linear build up confirming the TxIA communication. Subsequently an AOGCC approved production and injection diagnostic period was performed to prove the well has sufficient capabilities to continue as a Blackstart well. The well was monitored during the different cycles of operation and the IA pressure stabilized and did not exceed 2200 psi. ConocoPhillips intends to pursue repairs if further mechanical integrity issues or additional annular communication develop. However at this point in time, the tubing demonstrates some level of integrity based on the passing MIT -IA performed September 1, 2015 and the differential pressures between the tubing and IA during the production and injection test periods. The production casing integrity has been confirmed based on the aforementioned MIT -IA. ConocoPhillips conducted an internal Risk Assessment which reported a minimal increase in risk over normal gas injection wells. Based on the preceding information and the additional monitoring to be included in the proposed operating plan ConocoPhillips does not believe that the well's condition compromises overall well integrity so as to threaten human safety or the environment. ConocoPhillips requests an administrative approval (AA) which will allow for continued injection of gas with known tubing by inner annulus communication. The injection pressure will be limited to 4025 psi. This is based off 70% of the burst rating of the surface casing. In a worst case scenario of multiple barrier failures the pressure against the surface casing would still remain at or below 70% of the burst rating (as per AIO 18C, rule 4). The IA pressure will be allowed to operate at up to 2400 psi (33% of the burst rating of the production casing) during injection and production phases. This is to accommodate for thermal/rate changes and to minimize the differential pressure between the tubing and inner annulus. In addition to the injection pressure limit, transmitters will be installed on the annuli of CD 1-14 to provide real time monitoring and alert capabilities. The transmitters will bring improved utilization of ConocoPhillips new We11TRAK software to aid in calling attention to any potential communication issues. Barrier and Hazard Evaluation Tubing: The 4-1/2" 12.6 lb L-80 has a burst rating of 8403 psi (70% - 5901 psi). Although there is known TxIA communication the tubing has some amount of integrity based on the passing MIT -IA performed 9/1/15 and the differential pressures between the tubing an IA during well operation. Production casing: The 7" 26 lb L-80 has a burst rating of 7240 psi (70% - 5068 psi). The production casing has integrity from surface to the packer at 13,365' MD (6666' TVD) based on passing a MIT -IA to 2400 psi on 9/1/15 and differential pressures during well operation. Surface casing: The 9-5/8" 40 lb L-80 has a burst rating of 5750 psi (70% - 4025 psi). The surface casing has integrity based on differential pressures during well operation. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Secondary barrier: The secondary barrier to prevent a release from the well and provide zonal isolation is the production casing. Tertiary barrier: The tertiary barrier to prevent a release from the well is the surface casing. Problem Wells Supervisor 11/19/2015 2 Monitoring: Each well is monitored daily for wellhead pressure changes. Should additional leaks develop in the completion, it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. TIO trends are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. Proposed Operating and Monitoring Plan Well will be used for gas only injection during injection cycle. Injection pressure will be limited to 4025 psi max. Well will be used for Blackstart gas as required; 2. Perform a passing SW MITIA every 2-years to 3000 psi. 3. Allow operating IA pressure up to 2400 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 diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. 6. Install transmitters on IA and OA to provide real time monitoring capabilites. Problem Wells Supervisor 11/19/2015 3 Well Name Date Days End r.. r 812112015 .0 11119/2015 MIMI ®EMUM=E=P-T, M STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: jim.regg(cDalaska.gov; AOGCC.Inspectors@alaska,gov; phoebe. brooks(o)alaska.gov chris.wallace(aalaska.aov OPERATOR: ConocoPhillips Alaska, Inc. FIELD / UNIT / PAD: Alpine / CRU / CD1 Pad DATE: 09/01/15 OPERATOR REP: Manjarrez AOGCC REP: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well CD1-14 I Type Inj. I N I TVD 1 6,666' Tubing 3,700 3 77001 3,7001 3,7001 1 1 Interval O P.T.D. 2010380 I Type test I P I Test psi 1 1666.5 Casingl 1,7001 3,0001 2,9751 2,9701 1 1 P/F P Notes: Diagnostic MIT -IA 0AJ 9001 9001 9001 900 Well CD1-14 Type Inj. N I TVD 1 6,666'1 Tubingl 3,7001 3,7001 3,7001 3,76ol 3,7001 3,700 Interval 0 P.T.D. 2010380 Type test P I Test psi 1 1666.51 Casingl 2,9701 8001 8401 8501 8601 870 P/F I F Notes: diagnostic draw down test on the IA post MIT -IA I 0AJ 9001 9001 9001 9001 9001 900 WeIll I Type Inj. I TVD I I Tubingl I Interval P.T.D.1 Type test I Test psi I I Casing P/F Notes: I OA Well Type Inj. I TVD I I Tubingl I I I I I I Interval P.T.D.1 Type test I I Test psi I I Casing P/F Notes: I OA WellI Type Inj.1 I TVD I I Tubingl I I I I I Interval P.T.D. Type test Test psi I Casing P/F Notes: I 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 CD1-14 Diagnostic MIT -IA and Draw Down Test 9-1-15.x1s WNS INJ CD1-14 Conoc6Phillips tr "'" Well Attributes Max Angle & MD TD Alaska InC Wellbore APUUWI Field Name 1.1.2031100 ALPINE Wellb— Status INJ Inel (°) 95.01 MD INKS) 14,181.99 Act Elm (ftKB) 18,939.0 ... Comment 1126 (ppm) Dale SSSV:WRDP Annotation I End Date Last WO: KS-Grd (N) RIB Hot.— Date 43.70 5/11/2001 CW-14, 973o00157'59.26 AM Vertical schema4c (actual) Annotation Depth INKS) End Dale Annotation Last Tag: SLM 6/22Y2010 Rev Reason: Pull and Reset Plug Last Mod By pproven End Date 9l3012015 Casing Strings HANGER;32.4 Casing Descrlptlan CONDUCTOR OD (In) ID (In) 16 15.062 Top (ftKB) Set 37.0 Depth (ftKB) 115.0 Set Depth (TVD)... 115.0 Wt/Len'I 62.58 Grade H-40 Top Thread WELDED Casing Description SURFACE OD (In) 9578 ID (In) 8,921 Top (ftKB) Set 36.8 Depth (ftKB) 3,586.5 Set Depth (TVD)... 2,366.0 Wt/Len (I... 40.00 Grade L-80 Top Thread OTC -MOD feelrrg Description INTERMEDIATE OD (In) 10 (In) 7 6.276 Top (ftKB) Set 34.3 Depth (ftKB) 14.073.1 Set Depth (TVD)... 6,855.1 WVLen (1... 26.00 Grade L-80 Top Thread BTCM q Casing Description OPEN HOLE OD (in) 61,18 ID (In) Top INKS) Set 14.073.0 Depth (ftKB) 18.939.0 Set Depth (Pro)... 6,813.7 Wt/Len (1... Grade Top Thread Tubing Strings Tubing Deserlptlon Siring Ma... ID (In) Top (HKE) Sel Depth (N.. Set Depth (TVD) (... Wt (IbHt) Grade Top Connection TUBING 41/2 3.958 32.4 13,421.3 Q69D.8 12.60 L-80 IBTM Completion Details Nominal 10 Top (ftKB) Top (TVD) INKS) Top Incl (°) Item Des Com (in) 32.4 32.4 0.12 HANGER FMC TUBING HANGER 4.500 2,298.3 1,831.4 66.44 NIPPLE CAMCO BAL-O NIPPLE 3.812 13,365.1 6,666.0 63.49 PACKER BAKER S-3 PACKER 3.875 13,409.1 6,685.4 64.04 NIPPLE HES XN NIPPLE 3.725 I ALL 13,420.0 6,690.2 64.17 WL EC WIRELINE GUIDE 3.875 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) TOP(TVD) Top (fiKBj (ftKB) Topincl (°) Des Com Run Data ID (In) CONDUCTOR; 37.0-115.0 2,298.3 1.831.4 65.44 WRDP 3.81' DB LOCK ON WRDP-2 (HRS-274f3 pkg stacks 9/27/2015 1.125 & Special Inj Sub) Notes: General & Safety End Date Annotation 6/22/2010 NOTE: View Schematic w/Alaska Schemabc9.0 NIPPLE; 2,298.3 WRDP: 2,296.3 SURFACE; 36.8-3,586.5— PACKER, 13.365.1 NIPPLE; 13,409 1 W LEG; 13.420.0 INTERMEDIATE:34114,0731 OPEN HOLE, 14,073.0-18.939.0 ` • ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 September 11, 2015 Commissioner Foerster Alaska Oil & Gas Conservation Commission 333 West 7t' Avenue, Suite 100 Anchorage, AK 99501 Dear Ms. Foerster: SEP 15 2015 AOGCC ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 18C, Rule 11, to apply for administrative approval to allow CRU well CD4-322 (PTD 207-101) to remain in water only injection service with known outer annulus by atmosphere communication. If you need additional information please contact us at your convenience. Sincerely, 3 Jan Zyrne/usty Freeborn Problem Wells Supervisor ConocoPhillips Alaska, Inc. Office phone: (907) 659-7126 Cell phone: (907) 943-0450 IT 1111-�L .rt' Fri. 0 • ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Purpose Alpine Well CD4-322 (PTD 207-101) Technical Justification for Administrative Relief Request ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this administrative relief request as per Area Injection Order 18C, Rule 11, to continue water only injection for Colville River Unit injection well CD4-322 (PTD 207-101) with known outer annulus by atmosphere communication. Well History and Status Colville River Unit injection well CD4-322 was completed in August 2007 as a water injector. It was converted to a WAG injector in November of 2009. CD4-322 was reported to the Commission on June 25, 2015 for outer annulus by atmosphere communication. A surface casing leak detect was conducted and located the surface casing leak at approximately 12' below the OA valve. Prior to the discovery of the outer annulus by atmosphere communication a passing State witnessed MIT -IA was performed on June 12, 2015. Passing wellhead pack off tests were performed on June 26, 2015 CPAI is evaluating repair options of the surface casing leak in the future by excavation and patching. However until a repair is planned and implemented, ConocoPhillips requests an administrative approval (AA) which will allow for continued injection of water only. 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 lb L-80 tubing has integrity to the packer at 18,226' MD (7161' TVD), based on passing a state witnessed MIT -IA to 2511 psi on 6/12/15 and TIO trends. Production casing: The 7" 26 lb L-80 production casing has integrity to the packer at 18,226' MD (7161' TVD) based on the passing MIT -IA aforementioned and TIO trends. Surface casing: The 9-5/8" 40 lb L-80 surface casing has an internal yield pressure rating of 5750 psi. The surface casing has a known leak at approximately —12' below the OA valve. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Secondary barrier: The production casing is the secondary barrier should the tubing fail. Problem Wells Supervisor 9/11/2015 ConocoPh i I I i ps Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the completion it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. TIO trends are compiled, reviewed, and submitted to the AOGCC for review 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 maximum anticipated injection pressure; 3. Allow operating IA pressure up to 2000 psi, operating OA pressure to be kept as low as reasonably possible up to 100 psi; 4. Submit monthly reports of daily tubing & IA pressures, injection volumes and pressure bleeds for all annuli; 5. Shut-in the well should diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. Problem Wells Supervisor 9/11/2015 2 Well Name CD4-322 Notes: Start Date 6/13/2015 Days 90 End Date 9/11/2015 Annular Communication Surveillance 1600 WHIP 1 _ IAP _ OAP 0.9 1400 WHT 0.8 1200 0.7 1000 0.6 LL O.54) W C- 800 — C 0.4 600 0.3 400 0.2 200 0.1 0 0 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 0.9 0.1 G 0.1 m 0.6 - oo -Mai p 0.5 U 0.4 f 0.3 0.2 0.1 0 Jun-15 Jul-15 Aug-15 Sep-15 00-15 Date Bleed History • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: iim.reaa(cDalaska.gov: AOGCC.Inspectors(cbalaska.gov: phoebe.brooks(cDalaska.gov chris.wallace(Malaska.gov OPERATOR: ConocoPhillips Alaska, Inc. FIELD / UNIT / PAD: Alpine / CRU / CD4 Pad DATE: 06/12/15 OPERATOR REP: Riley/Phillips/Byrne AOGCC REP: Johnnie Hill Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well CD4-03 T e In'. N TVD I 7 382' Tubinal 3.6251 3,6101 3.6101 3.6101 Interval 1 4 P.T.D. 2111130 I Type te.tl P I Test psi 1 1845.5 Casingl 7211 2,3101 2,2761 2,2691 P/F I P Notes: OA 226 1276 1276 1275 Well CD4-12 I Type In'. I G I TVD 1 7,044'1 Tubing 3,8141 3,8621 3,8651 3,864 1 Interval 4 P.T.D. 2100910 I Type test I P I Test pri 1 17611 Ca.inal 1,9991 2,8081 2,7831 2,7831 P/F I P Notes: I OA 544 1550 1551 1552 Well CD4-24 I Type In'. I W I TVD 1 7,440-1 T.binql 2,6491 2,6191 2.6091 2,6051 Interval 1 4 P.T.D. 2090970 I Type test I P I Test psi 1 1860 Casingl 1,3261 2,1081 2,0871 2,0851 1 1 P/FJ P Notes: I OA 630 1632 1632 1632 Well CD4-26 Type In'. N I TVD 1 7,347-1 T.binql 3751 3751 375 3751 1 Interval 4 P.T.D. 2090490 I Type testl P I Test psi 1 1836.751 Casing 9151 2,3121 2,2881 2,2831 P/F I P Notes: I OA 509 1514 1515 1515 Well CD4-27 I Type In'. I W I TVD 1 7,412-1 T.binol 2.6151 2,6121 2,6091 2.6081 Interval 1 4 P.T.D. 2111460 I Type test I P I Test psi 1 18531 Casingl 701 2,1141 2,0761 2,0741 1 1 P/F1 P Notes: I OA 0 19.5 185 183 Well I CD4-213B I T e In'. I W I TVD 1 7 413' Tubin 2.4751 2,4751 2,4751 2,4751 Interval 4 P.T.D. 2120050 I Typetestl P I Te.tPsil 1853.251 Casinal 1,3651 3,3061 3,2681 3,2551 P/F P Notes: L OA 1390 1421 1403 1396 Well CD4-214 Type In'. W TVD 5 967' Tubing2.6151 2.6121 2,6091 2.6081 Interval 4 P.T.D. 2061450 1 Type test I P I Test psi 1 15001 Casing 7011 2,1141 2,0761 2,0741 1 PIFJ P Notes: I OA 0 195 185 183 Well CD4-291 I Typ.Ini.1 W I TVD 1 6 078' Tubin 1.9211 1,9641 1,9701 1,9711 intervail 4 P.T.D. 2131100 I Typetestl P I Test psi 1 1519.5 Casinal 791 2,8101 2,7261 2,7151 P/F I P Notes: L OA 905 1960 1933 1926 Well CD4-302 I Type In'. N I TVD 1 6 237' Tubin 4001 400 4001 4001 1 Interval 4 P.T.D. 2070560 I Typetestl P I Test psi 1 1559.251 Casing 2091 2,0211 1,9741 1,9651 PIFJ P Notes: I OA 616 1826 1816 1812 Well CD4-306 I Tvp.InJ W I TVD 1 6,898-1 Tubin 1.8241 1,8351 1.8251 1.8231 Interval 4 P.T.D. 2070940 I Typetestl P I Test psi I 1724.5 CasinQ1 1,1821 2,8081 2,7711 2,7631 P/F P Notes: I OA 608 1749 1738 1738 Well CD4-319 I Type In'. N I TVD 1 6,907'1 T.binal 4801 4801 4801 470 1 Interval 4 P.T.D. 2051480 I Tvp.testl P I Test psi 1 1726.751 Casing 7701 2,1541 2,0271 2,0161 P/F P Notes: L OA 601 1611 1610 1610 Well CD4-321 Type In'. N TVD 7 181' Tubin 100 100 100 100 Interval V P.T.D. 2061420 1 Type test I P I Test psi 1 3000 Casinql 1591 3,3101 3,2761 3,2671 P/F1 P Notes: MITIA to maximum anticipated injection pressure I OA 0 12 11 11 er AIO 18C.002 W.111 ell CD4-322 I TvDe In'. I N TVD 1 7,161-1 Tubing 1501 150 1501 1501 1 Interval 4 P.T.D. 12071010 1 Type test I P I I Test psi 1 1790.251 Casing 6341 2,5111 2,4771 2,4691 P/F Notes: 1 OA 0 11 11 11 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 INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance 0 = Other (describe in notes) Form 10-426 (Revised 1112012) MIT CRU CD4-PAD 06-12-15x1s WNS INJ C014-322 ANA ConoeoPhlllip$ )I Attributes Max Angle & MD TD QIBSka, Inc, Wellbore APIIUWI Field Name Wellbore Status MD (ftKB) Act Btm (ftKB) 501032055100 NANUQ KUPARUK INJ 73.08 5,100.31 19,452.0 ... Comment H2S (ppm) Date Annotation End Date KB-Grd ("I Rig Release Date DEVIATED -CD4-322.61920159.57t52AM SSSV: WRDP Last WO: 43.33 8/22/2007 I Ver—1 --re (acwap Annotation Depth (ftKB) End Date Annotation Last Mod By End Date Last Tag: Rev Reason: RESET INJ VLV hipshkf 6/9/2015 ......... ......._.................. ...... .. ..... _ sing Strings HANGER; 31.1 Casing Description OD (in) CONDUCTOR 1635.0 I4(�n)Top (ftKB) Set Depth (ftKB) 114.0 Set Depth (TVD)... 114.0 W/Len (I... Grade Top WELDED Thread Casing Description OD (in I (ftKB) Set Depth (ftKB) Set Depth (TVD)... Wt/Len (I... Grde Top Thread SURFACE 958835.9 3,580.2 2,385.3 40.00L-80 BTC Casing Description OD (in) I (ftKB) Set Depth (ftKB) Set Depth (TVD)... WVLen 0... Grade Top Thread INTERMEDIATE 734.2 19,436.E 7,728.3 26.00 L-80 BTCM Tubing Strings Tubing Description String Ma... ID (in) Top (ftKB) Set Depth (ft, Set Depth (TVD) (... W[ (Iblft) Grade Top Connection TUBING 41/2_ 3.958 3t1 78.299.2 7,1842 12_.60 L_80 fB FM Completion Details Nominal ID Top (ftKB) Top (TVD) (ftKB) Top ]net (°) Item Des Com (in) 31.1 31.1 0.00 HANGER FMC TUBING HANGER 3.958 2,288.9 1,9524 61.32 NIPPLE CAMCO DB NIPPLE 3.812 18,226.3 7,161.2 71.68 PACKER BAKER PREMIER PACKER 3.875 18,286.6 7,180.2 71.52 NIPPLE HES'XN' NIPPLE 3.725 18,297.7 7, 183.8 71,47 WLEG WIRELINE GUIDE 3.875 CONDUCTOR; 35.0.114.0 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top(TVD) Topincl Top (ftKB) (ftKB) C Des Co. Run Date ID (in) 2288.9 1 1,9524 1 61.32 1 VALVE A-1 INJECTION VALVE ON DB6 LOCK (HYS-442) 6/8/2015 1.125 NIPPLE; 2,288.9 Perforations & Slots VALVE; 2,288.9 Shot Dens Top(TVD) St. (TVD) (shotslf Top(ftKB) Stan (ftKB) (ftKB) (ftKB) Zone Date t) Type Com 18,538.0 18,558.0 7,263A 7,270,2 9/3/2007 6.0 IPERF 2 7/8" PJ OMEGA, 130 deg ph Mandrel Inserts St ati N Top (ftKB) Top (TVD) (ftKB) Make Mod 1 OD (in) Se, Valve Type Latch Type Port Size (in) TRO (psi) Run Run Date Com 11 18,118.71 7,127.E 1 CAMCO IKBG-7-1 1 GAS LIFT JDMY BK 1 .000 0.0 8/20/2007 SURFACE: 359-3,560.2— Notes: General. & Safe .. End Date Annotation 8/24/2008 NOTE: VIEW SCHEMATIC w/Alaska Schematic9.0 GAS LIFT; 18.118.7 PACKER; 18,226.3 NIPPLE; 18,286.E WLEG; 18,297.7 IPERF; 18,538.0-18,558 0 INTERMEDIATE; 34.2-19,436.6— • ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 August 23, 2015 Commissioner Foerster Alaska Oil & Gas Conservation Commission 333 West 7ch Avenue, Suite 100 Anchorage, AK 99501 Dear Ms. Foerster: r RECEIVED AUG 25 2015 AOGGC ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 18C, Rule 11, to apply for administrative approval to allow CRU well CD1-46 (PTD 204-024) to remain in water only injection service. Currently the well displays tubing by inner annulus communication only while injecting gas. If you need additional information please contact us at your convenience. Sincerely, Jan/Byrne/ Dusty Freeborn Problem Wells Supervisor ConocoPhillips Alaska, Inc. Office phone: (907) 659-7126 Cell phone: (907) 943-0450 4V+/ELI.S TEAM ps • ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Alpine Well CD1-46 (PTD 204-024) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this administrative relief request as per Area Injection Order 18C, Rule 11, to continue water only injection for Colville River Unit injection well CD1-46 (PTD 204-024). The well displays tubing by inner annulus communication only while the well is on miscible gas injection. Well History and Status Colville River Unit well CD 1-46 was completed in April 2004 as a WAG injector. CD 1-46 was reported to the Commission on February 19, 2015 for a suspect inner annulus pressure increase while on miscible gas injection. Passing diagnostic tests including an MIT -IA and wellhead pack off tests were performed February 20, 2015. Due to continued IA pressure increase the well was WAG'd to water and the well bore was circulated out with clean fluid. During the following AOGCC approved monitor period while on water injection the well exhibited no indications of tubing by inner annulus communication. ConocoPhillips intends to pursue repairs if tubing by inner annulus communication develops while on water injection, however, at this point in time the well exhibits no indications of tubing by inner annulus communication while on water injection, therefore ConocoPhillips requests an administrative approval (AA) which will allow for continued injection of water only. 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 lb L-80 tubing has integrity to the packer at 10,856' MD (6916' TVD), based on passing a MIT -IA to 3000 psi on 2/20/15 and TIO trends. Production casing: The 7" 26 lb L-80 production casing has integrity to the packer at 10,856' MD (6916' TVD) based on the passing MIT -IA aforementioned and TIO trends. Surface casing: The 9-5/8" 36 lb J-55 surface casing has an internal yield pressure rating of 3520 psi. The surface casing has integrity based on TIO trends. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Secondary barrier: The production casing is the secondary barrier should the tubing fail. Tertiary barrier: The surface casing will act as a third barrier in the unlikely case that the first two normal barriers have failures. Problem Wells Supervisor 8/23/2015 ConocoPh i I I i ps Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the completion it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. TIO trends are compiled, reviewed, and submitted to the AOGCC for review 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 maximum anticipated injection 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 diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. Problem Wells Supervisor 8/23/2015 2 WNS INJ a CD1-46 cmixxxe fillip Alaska. f• •• fl Attributes Wellbore ANIUWI Field Name Wcl l bore Status 501032048500 ALPINE INJ Max Angle & MD Incl (') MD(ftKB) 93.13 11,970.87 TD Act Btm ptKB) 15.187.0 Comment H2S (pp.) Date SSSV: WRDP Annotation End Date Last WO: KB-Grd (ft) Rig Release Date 36.52 4/272004 cD1-46, 7/z9rzols twos PM Vertica schematic (actual) Annotation Depth (ftKB) End Date Annotation Last Tag: Last Mod By End Data Rev Reason: RESET INJ VLV, GLV C/O hipshkf 9/6/2013 ................................... ........................_.......... ........................... HANGER; 32.5 CONDUCTOR; 37.0-114.0 • VALVE; 2,398.0 NIPPLE; 2,398.9 SURFACE; 36.5-2,994.4 GAS LIFT; 10.744.0 PACKER; 10,858.5 NIPPLE; 10,922 3 WLEG; 10,933.3 PRODUCTION; 34.7-11,334.5 OPEN HOLE; 11,334,515,187.0 _'Easing Strings Casing Description OD (in) CONDUCTOR 16 ID (in) 15,062 Top (ftKB) Set 37.0 Depth (ftKB) 114.0 Set Depth (TVD)... 114.0 Wt/Len 62.50 (I... Grade Top J-40 WELDED Thread Casing Description OD (in) SURFACE 95/8 ID (in) 8.921 Top (ftKB) Set 36.4 Depth (ftKB) 2'994.4 Set Depth (TVD)... 2,362.9 WULen 36.00 (I... Grade Top J-55 BTC Thread Casing Description OD (in) PRODUCTION 7 ID (in) 6.276 Top (ftKB) Set 34.7 Depth (ftKB) 11,334.5 Set Depth (TVD)... 7,073A WULen 26.00 (I... Grade Top L-80 BTCM Thread Casing Description OD (in) OPEN HOLE 61/8 ID (in) Top (ftKB) Set 11,334.5 Depth (ftKB) 15,187.0 Set Depth (TVD)... 7,089.7 WULen (I... Grade Top Thread Tubing Strings Tubing Description String Ma.. ID (in) Top (ftKB) Set Depth (ft.. Set Depth (TVD) (... Wt (Iblft) Grade Top Connection TUBING 41/2 3.958 325 10.934.8 6,9532 1260 L-80 IBTM Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Corn Nominal ID (i n) 32.5 32.5 0.00 HANGER FMC TUBING HANGER 4.500 2,398.9 2,004.1 53.97 NIPPLE CAMCO'DB' NIPPLE 3.812 10,868.5 6,916.4 59.48 PACKER BAKER S-3 PACKER w/MILLOUT EXTENSION 3.875 10,922.3 6,947.5 62.21 NIPPLE HES'XN' NIPPLE 3.725 10,933A 6,952.6 62.66 WLEG WIRELINE ENTRY GUIDE 3.875 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB) Top lncl (') Des Com Run Date ID (in) 2,398.0 2,003.5 53.99 VALVE 3.81 DB LOCK ON A-1 INJECTION VALVE (HWS- 379) 7/23/2015 1 1,250 Mandrel Inserts st ati on N Top (ftKB) Top (TVD) (ftKB) Make Model OD (in) Sam Valve Type Latch Type Port Size TRO (in) Run (psi) Run Date Com 10,744.0eret 6,854.3 CAMCO KBG-2 1 GAS LIFT DMY BK 0.000 0.0 7/232015 Notes:' enety End Date Annotation 4/27/2 002 NOTE: TREE: FMC 4-1/16 5K-TREE CAP CONNECTION: 7" OTIS 6/16/2009 NOTE: View Schematic w/ Alaska SchematiC9.0 Well Name CD1-46 Notes: Start Date 5/25/2015 Days 90 End Date 812312DI5 Annular Communication Surveillance _ 12a 45a6 — w 4'JHP t& P 4a0a OAP WHT 100 35aa 8a 3000 25oa .� cs u. sa O '� Zaaa as lsoa laoa 20 Sao a o 1.1 By-15 Jun-15 Jul-15 AUg-15 Sep-15 a xad -aua d t 6S0 t000 S00 M ay-15 Jun-15 Jul-15 Aug-15 Sep-15 Date STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: jim.regg(7g alaska.gov; AOGCC.Inspectors(@alaska.gov: phoebe.brooksaalaska.gov chris.wallaceCrDalaska.gov OPERATOR: ConocoPhillips Alaska, Inc. FIELD / UNIT / PAD: Alpine/CRU/ CD1 DATE: 02/20/15 OPERATOR REP: AOGCC REP: Richwine Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well CD1-46 I Type Inj. I G TVD 1 6,916' Tubingl 4,0001 4,0001 4,0001 4,000 1 1 Interval O P.T.D. 2040240 I Type test I P Test psi 1729 Casingl 2,1001 3,0001 2,9501 2,940 P/F I P Notes: Diagnostic MIT -IA 0AJ 5501 5501 5501 550 Well Type Inj. I TVD I I Tubingl I I I I I Interval P.T.D.1 I Type test I I Test psi Casing P/F Notes: I OA Well I Type Inj. I I TVD I I Tubingl I I I Interval P.T.D.1 I Type test I I Test psi I I Casing P/F Notes: I OA WeIll I Type Inj. I TVD I I Tubingl I I I Interval P.T.D.1 I Type testi I Test psi I I Casing P/F Notes: I OA Well Type Inj. I I TVD I I Tubingl I I Interval P.T.D. Type test Test psi I Casing P/F Notes: I OA Weill I Type Inj. I TVD I TubingI Interval P.T.D.1 I Type test I I Test psi I I Casing P/F Notes: I OA WeIll I Type Inj.1 I TVD I I Tubingl I I I I I I Interval P.T.D.1 I Type testl I Test psi I I Casing P/F Notes: I OA Well I Type Inj. I TVD I I Tubingl I I I Interval P.T.D. Type test Test psi Casing P/F Notes: I OA TYPE INJ Codes TYPE TEST Codes D = Drilling Waste M = Annulus Monitoring G = Gas P = Standard Pressure Test I = Industrial Wastewater R = Internal Radioactive Tracer Survey N = Not Injecting A = Temperature Anomaly Survey W = Water D = Differential Temperature Test INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance O = Other (describe in notes) Form 10-426 (Revised 11/2012) MIT CRUCDI-46diagnostic 02-20-15.xls ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 I" Day of June 2015 Commissioner Foerster Alaska Oil & Gas Conservation Commission 333 West 71h Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner Foerster: RECEIVED JLA032013 ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 018C, Rule 11, to apply for administrative approval allowing well CD4-17 (PTD 206-118) to be online in water injection service only. Currently, the well displays TxIA communication only while injecting gas. If you need additional information, please contact myself or Jan Byrne. Sincerely, Dusty Freeborn Problem Wells Supervisor ConocoPhillips Alaska, Inc. Office phone: (907) 659-7126 Cell phone: (907) 943-0450 ConocoPhillips Alaska, Inc. Kuparuk Well CD4-17 (PTD# 206-118) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this administrative relief request as per Area Injection Order 018C; Rule 11, to continue water only injection for Alpine injection well CD4-17. The well displays tubing by inner annulus communication only while on gas injection. Well History and Status Colville River Unit well CD4-17 (PTD# 206-118) was drilled and completed in October of 2006 as a service well. CD4-17 was initially reported to the Commission on the 3rd of May 2015, for an unexplainable IA pressure increase while the well was injecting MI gas. The tubing and inner casing pack off tests passed in both the positive and negative direction. The well also passed an MIT IA and an IA draw down was started on the 6th of May 2015. The well was WAGed to water injection and brought online for a 30 day AOGCC approved monitor period. During the monitor period the IA stabilized and showed no signs of tubing by inner annulus communication therefore passing the long term IA draw down test. ConocoPhillips intends to pursue repairs if tubing by inner annulus communication is identified. However, at this point in time the well demonstrates tubing by inner annulus integrity while on water injection and ConocoPhillips requests an administrative approval (AA) which will allow continued injection of water only. 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 at 11,753' MD (7,130' TVD), based on normal operating injection differential pressures and passing a diagnostic MIT -IA to 3000 psi on the 61h of May 2015. Production casing: The 7" 26# L-80 production casing has integrity to the packer at 11,753' MD (7,130' TVD) based on the passing MIT -IA test outlined above as well as the differential operating pressure between the tubing and casing. Surface casing: The well is completed with 9-5/8" 40# L-80 surface casing with an internal yield pressure rating of 5750 psi. The surface casing is set at 3,009' MD (2387' TVD). Based on differential operating pressure between the production casing and surface casing, integrity of the surface casing has been proven. 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 in the unlikely case that the first two normal barriers have failures. Well Integrity Supervisor 6/l/2015 1 Monitoring: Each well is monitored daily for wellhead pressure changes. Should a leak develop in the tubing, production or the surface casing, it will be noted during the daily monitoring process. Pressure trends that indicate annular communication, commission notifications, and corrective action, up to and including a shut-in of the well will be handled appropriately. 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 injection only (no MI or gas injection allowed); 2. Perform a passing MITIA every 2-years to maximum anticipated injection pressure. 3. Allow operating IA pressure up to 2000 psi, 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/or pressures indicate further problems with appropriate notification to the AOGCC. Well Integrity Supervisor 6/1/2015 2 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: iim.reggCrDalaska.gov; AOGCC.InspectorscEDalaska.ctov; phoebe. brooksCcoalaska.gov chds.wallace(Dalaska.gov OPERATOR: FIELD / UNIT / PAD DATE: OPERATOR REP: AOGCC REP: ConocoPhillips Alaska, Inc Alpine / CRU / CD4 Pad 05/06/15 Hollandsworth N/A Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well CD4-17 I Type Inj. I W TVD 1 7,130' Tubing 1,813 1,814 1,130 1,815 Interval p P.T.D. 206-118 Type test P Test psi 1782.5 Casing 1,107 3,000 2, 2,982 P/F P Notes: Diagnostic MIT -IA CIA 30 30 30 Well I Type Inj. TVD Tubing Interval P.T.D. I Type test 1 ng 1 P/F Notes: CA Well I Type Inj.1 I TVD I Tubing Interval P.T.D. I Type test I Test psi I Casing P/F Notes: CA Well I Type Inj. TVD Tubing Interval P.T.D. I Type test I Test psi Casing P/F Notes: CIA Well I Type Inj. I TVD Tubing Interval P.T.D. I Type test I Test psi I Casing P/F Notes: CA IIIIIIIIIIIIIIJIM! TYPE INJ Codes TYPE TEST Codes D = Drilling Waste M = Annulus Monitoring G = Gas P = Standard Pressure Test I = Industrial Wastewater R = Internal Radioactive Tracer Survey N = Not Injecting A = Temperature Anomaly Survey W = Water D = Differential Temperature Test INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance O = Other (describe in notes) Form 10-426 (Revised 11/2012) CD4-17 Diagnostic MIT -IA 5-6-15.xls WNS CD4-17 COiIOCOflllllp5 Na�'Inc'S01032053400 • Well Attributes ttrib RAazAt► 18,8°'Weell _ I Field Name Well Status ALPINE INJ Incl () 94.27 MD (ftKB 15,0�MDD Btm (ftKB) 17,975.0 Comment 1-12S (ppm) Date Annotation End Date KB-Grd (R) Rig Release Date _"' SSSV: WRDP Last WO: 37.17 10/4/2006 Well Confi -CD4-17 9/15/201210 O831 AM Schematc Actual .Annotation Depth Last Tag: (ftKB) End Date Annotation Rev Reason: SET INJ VALVE Last Mod ... ninam End Date 9/15/2012 Casing Strings Casing Description String 0... String ID ... Top (ftKB) Set Depth ... (f Set Depth (ND) ... String Wt... String ... String Top Thrd CONDUCTOR 36" 16 15.250 34.0 114.0 114.0 65.00 H-40 Insulated ` Casing Description String 0... String ID ... Top (ftKB) Set Depth (f... Set Depth (ND) ... String Wt... String ... String Top Third SURFACE 95/8 8.835 33.8 3,009.3 2,386.8 40.00 L-80 HANGER, 32 t Casing Description String 0... String ID ... Top (ftKB) Set Depth If... Set Depth (TVD) ... String Wt... String ... String Top Third w INTERMEDIATE 7 6.276 33.5 13,334.2 7,486.9 26.00 L-80 Casing Description String C... String ID ... Top (ftKB) Set Depth if... Set Depth (ND) .. String Wt... String ... String Top Third OPEN HOLE 6 1/8 13,334.0 17,975.0 Tubing Strings A "• Tubing Description String 0... String ID ... Top (ftKB) Set Depth (f... Set Depth (7VD) ... String WL.. String ... String Top Thrd Tubing - Water INJ 4112 3.958 31.7 11,825.E 7,163.3 1260 L-80 Completion Details _ Top Depth Too IftK81 (TV (ftKB) Top Incl V) Item Description Comment ID (in) CONDUCTOR 36' Insulated, 34-114 NIPPLE, 2,262 VALVE, 2,262 ` ' 11,753.0 7,130.2 61.90 PACKER KAKtK VKtMILK PACKtH 11,813.31 7,157.E 63.32 NIPPLE HES'XN' NIPPLE 11,824.31 7,162.71 63.58 WLEG WIRELINE ENTRY GUIDE Other In Hole Wireline retrievable plugs, valves, pumps, fish, etc. Top (ftKB) Top Depth (TVD) (ftKB) Top Incl (°) Description Comment - Run Date 2,262 1,981.E 55.49 VALVE 3.81" A-1 INJECTION VALVE (S/N: HRS-44) 9/2/2012 Notes; General & Safety End Date Annotation 10/3/2006 NOTE: TREE: FMC 4-1/16" / 5,000 psi - TREE CAP CONNECTION 7" OTIS 12/612009 1 NOTE: View Schematic w/ Alaska Schematic9.0 SURFACE, 34-3.009 GAS LIFT, 9,119 1 PACKER, 11.753 NIPPLE, 11,813 WLEG, 11,824 � 1 I.r .Mandrel Details Stn Top (ftKB) Top Depth (TVD) (ftKB) Top met V) Make Model _ OD (in) S— Valve Type Latch Type Port Size (in) TRO Run (psi) Run Date Com... 1 9 9,119.2 11 RA9 7 5,714.2 7 n7R R 57.52 FIT 07 CAMCO CAWO KBG-2 KR(;-7 1 1 GAS LIFT GAS LIFT IDMY DMY BK-5 BEK-2 10.0001 0.000 0.0 1 0.0 11/16/2007 11/16/2007 33-13,334 OPEN HOLE, _ Well Name CD4 17 Notes: 4 Year MITIA Start Date 311JI2015 Days 90 Bleed History End Date 61112015 Annular Communication Surveillance IVELLJD I �nl!VIE I ST R-PRE S I END-PRES I DIF.PRE S I CASING I SERVICE CD4-17 5412015 -522 335 187 ItANER PWI F7 CD4-17 515120 15 2000 1600 400 INNER PVVI 4 SO 40D NO 250 EL 200 150 100 so —WHP —AP OAP VJH' G Feb-15 Mar-15 Apr-15 E.Y-1 5 15 . . ............ ConocoPhillips March 30, 2015 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Attention: Commissioner Dan Seamount RE: 2014 Annual Disposal Well Performance Reports WD-02, CD1-19A and CD1-01A Undefined Disposal Pool, Colville River Field Dear Commissioner Seamount, Jack Walker Supervisor, WNS Production Engineering North Slope Operations & Development ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, AK 99510-0360 Phone: (907) 265-6268 RECEIVED MAR 31 2015 ConocoPhillips Alaska Inc., as operator and on behalf of the working interest owners of the Colville River Unit, submits the 2014 Disposal Well Performance Reports for the Undefined Disposal Pool in the Colville River Field. These reports are submitted in accordance with Area Injection Order No. 18C and the requirements of 20 AAC 25,432. Inquiries regarding these reports may be directed to Mr. Garrett McKee (670-4934) at this office. Sincerely, 0— "Z— Jack Walker Supervisor, WNS Production Engineering North Slope Operations and Development ConocoPhillips 2014 Annual Disposal Well Performance Report W D-02 API 50-103-20285-00-00 Undefined Disposal Pool Colville River Field March 30, 2015 2014 CRU Disposal Well Performance Report WD-02 INTRODUCTION This report is prepared in accordance with Rule 9 of Area Injection Order No. 18C, dated March 26, 2009, which requires the submission of an annual performance report for slurry injection wells, and the requirements of 20 AAC 25.432 (Report of Underground Injection). Well WD-02, which was drilled and completed in the Ivishak Formation (undefined disposal pool) as a Class I well in April 1999, continued to serve as the primary source of disposal for camp fluids in 2014. Field produced fluids were also occasionally pumped to WD-02 in 2014. CLASS I DISPOSAL WELL WD-02 Infection Volumes Fluid injection volumes for the 12-month period of January 2014 through December 2014 totaled 373,117 bbls. This represents a monthly average of 31,093 bbls. Cumulative injection into the Sadlerochit Group since the start of the project is 5,068,232 bbls. Injection volumes for WD-02 are summarized in both table and plot form as Attachments 1 and 2. Infection Rates The injection pumps operate on level controls located on upstream holding tanks. Alpine base camp effluent water was the primary fluid injected down WD-02 in 2014, hence injection volumes varied in response to field manpower and staffing. Field produced water was also injected for short durations during the year. The twin injection pumps are operated at 15 - 20 gpm each, up to the 3,200 psi allowable injection pressure. Infection Pressures Injection pressures are monitored and recorded continuously (Attachment 2). Normal wellhead pressure when the pump is offline ranges from 1,000 - 1,300 psi. With the pumps running at 20 - 60 gpm, injection pressure typically ranges from 1,000 - 1,500 psi. Annulus Pressures Annulus pressures are monitored and recorded continuously (Attachment 2). When produced formation fluids are disposed of into WD-02, the hot fluids expand and elongate the tubing 2014 CRU Disposal Well Performance Report WD-02 2 string, which impacts the annulus volume, increasing the annulus pressure. Plant operators bleed off fluid from the annulus as a precaution to avoid annulus pressures reaching the 1,500 psi operating limit. The annulus pressure averaged 776 psi during 2014. On March 7th, 2014, the annual EPA MIT was performed. Summary results are shown below: • EPA Witnessed (Thor Cutler) MIT -IA (Passed at 3,500 psi) Depth Tags Mechanical integrity work was aligned with the EPA integrity testing on CD1-01A. Fill was tagged on March 6th, 2014 at 9,866' md. Fracture Growth The surface fracture pressure of the Ivishak Formation, as measured during the step rate test conducted April 11, 1999, was 1,984 psi. This pressure coincides with an injection rate of 1.38 bpm, or 1,987 bpd. The associated bottomhole fracture pressure extrapolated from the step test data is 6,259 psi. This equates to a gradient of 0.66 psi/ft, or fluid equivalent of 12.7 ppg. With the exception of short-term injection periods, tubing tests, and miscellaneous data spikes, the injection pressures have not exceeded the surface fracture pressure for any extended period of time during 2014. Wellwork Event Summary W D-02 Date Event 3/5/2014 CALIPER LOG FROM 9864'MD TO SURFACE 3/6/2014 INJECTION PROFILE LOGGED, NO UPFLOW BEHIND PIPE, 80% OF INJECTION ENTERING PERFORATION SET FROM 9837'-9867' MD, 20% ENTERING FROM 9803'-9818' MD. TAG AT 9866' MD 3/7/2014 EPA WITNESSED (THOR CUTLER) MIT -IA (PASSED AT 3500 PSI) 2014 CRU Disposal Well Performance Report WD-02 3 ATTACHMENT 1: WD-02 2014 INJECTION SUMMARY TABLE January through December 2014 Injection Summary Well: WD-02 Disposal Order: 18 Field: Colville River Unit API No.: 50103202850000 Permit to Drill Pool: Alpine Oil Pool No.: 198-258 Pool Code: 120036 Days In Tubing Pressure Tbg Pressure Casing Pressure Csg Pressure Daily Average Monthly Total Cumulative Month Max Pressure Avg Pressure Max Pressure Avg Pressure Liquid Gas Liquid Gas Liquid Operation (psig) (psig) (psig) (bbls) (bbls) (bbls) January 31 1,680 1,409 851 700 1,071 0 33,199 0 33,199 February 28 1,673 1,443 876 729 1,192 0 33,373 0 66,572 March 29 3,761 1,375 2,231 716 1,069 0 33,351 0 99,924 April 30 1,651 1,427 777 697 1,185 0 37.178 0 137,102 May 31 1,633 1,340 776 695 892 0 27,656 0 164,757 June 30 1,749 1,392 1,063 833 980 0 29,676 0 194,433 July 31 1,660 1,406 995 855 994 0 30,801 0 225,235 August 31 1,662 1,389 971 814 958 0 29,691 0 254,925 September 30 1,681 1,407 935 847 953 0 28,603 0 283,528 October 31 1,661 1,389 911 839 936 0 29,014 0 312,542 November 30 1,656 1,394 868 797 923 0 27,682 0 340,224 December 1 31 1 1,682 1 1,452 1 859 1 786 1,061 1 0 1 32,893 1 0 373,117 Monthly Average 1 1.846 1 1,402 1,009 776 1,018 1 0 1 31.093 1 0 2014 CRU Disposal Well Performance Report WD-02 ATTACHMENT 2: WD-02 2014 INJECTION SUMMARY PLOT 2014 CRU Disposal Well Performance Report WD-02 5 ConocoPhillips 2014 Annual Disposal Well Performance Report CD1-19A API# 50-103-20294-01-00 Undefined Disposal Pool Colville River Field March 30, 2015 2014 CRU Disposal Well Performance Report CD1-19A 6 I INTRODUCTION This report is prepared in accordance with Rule 9 of Area Injection Order No. 18C, dated March 26, 2009, and the requirements of 20 AAC 25.432 (Report of Underground Injection). Disposal well CD1-19A was drilled and completed in May 2000 to provide a disposal source for Class II fluids generated during wellwork and drilling operations. It was converted to a Class I well in April 2008 and continued to serve as a disposal well for fluids generated during wellwork and drilling operations through May 12, 2012. The CD1-19A well was partially abandoned in May 2013 by placement of cement across the injection zone (Ivishak Formation). CD1-01 A was drilled, completed, and placed in service in November 2012. CLASS I DISPOSAL WELL CD1-19A Injection Volumes No fluids were injected into CD1-19A in 2014. Wellwork Event Summary No wellwork. CD1-19A Date Event No wellwork events in 2014 2014 CRU Disposal Well Performance Report CD1-19A 7 ConocoPhillips 2014 Annual Disposal Well Performance Report CD1-01 A API# 50-103-20299-01-00 Undefined Disposal Pool Colville River Field March 30, 2015 2014 CRU Disposal Well Performance Report CD1-01A i INTRODUCTION This report is prepared in accordance with Rule 9 of Area Injection Order No. 18C, dated March 26, 2009, and the requirements of 20 AAC 25.432 (Report of Underground Injection). CD1-01A was drilled and completed in September/October of 2012 as a replacement for CD1-19A. CD1- 01A was placed in service in November 2012. CLASS I DISPOSAL WELL CD-01 A Infection Volumes Fluid injection volumes for the 12-month period of January 2014 through December 2014 totaled 221,002 bbls. This represents a monthly average of 18,417 bbls. Cumulative injection into the Ivishak Formation since the start of the project is 486,921 bbls. Injection volumes for CD1-01A are summarized in both table and plot form as Attachments 1 and 2. Infection Rates Disposal operations for CID 1-01 A are recorded via Micromotion flow rate meter. Various trucks and rig units are utilized to transport and dispose of fluids into this well. Injection rates vary from 0.5 - 4 bpm. There is no permanent disposal pump or piping installed at this time. Disposed fluids primarily include spent wellwork and flowback fluids; additional disposal included drilling mud and cuttings. All fluid disposal reports and manifests are recorded and stored at Alpine. The data is displayed graphically in Attachment 2. Infection Pressures Injection pressures are monitored and recorded via MadgeTech pressure gauge transmitters. These reports are summarized in the data plot (Attachment 2). Normal wellhead pressures during disposal operations vary from 2,000 - 3,300 psi. Annulus Pressures Annulus pressures are manually recorded and reported, and displayed in graphical form on the well performance plot (Attachment 2). Inner annulus pressure averaged 768 psi during 2014 and remained stable during injection periods. 2014 CRU Disposal Well Performance Report CD1-01A 9 On March 8, 2014, the MITIA for CD1-01A was performed. Summary results from the Well Service Report are shown below: • EPA Witnessed (Thor Cutler) MIT -IA Passed @ 2,340 psi Depth Tags Mechanical integrity work was aligned with the EPA integrity testing after CD1-01A was commissioned in November 2012. Fill was tagged on March 2"d, 2014 at 9432' md. Fracture Growth During a step rate test on September 17, 2000, the formation fracture pressure was observed as 6,035 psi using a 9,062' column of 9.2 ppg brine and 1,700 psi on the wellhead. Using this data, a fracture gradient of 0.665 psi/ft was calculated for the reservoir. During normal operations, injection occurs above this fracture pressure, thus hydraulically fracturing the well. A pressure fall -off (PFO) test was performed on Alpine's Class II Disposal Well, CD1-19A, on June 19, 2004, after injecting 227,000 bbls of approved fluids for the purpose of estimating fracture growth. The complete test report was submitted on July 26, 2004. Referring to the square root of time plot from the June 2004 PFO, a fracture was observed to close at dt = 7.58 minutes and 6,492 psia, yielding a fracture gradient of 0.716 psi/ft. The elevated fracture gradient can most likely be attributed to poroelastic effects due to the long pumping period. Injection was assumed to enter the formation through the top two perforation sets, thus a fracture height of 35 feet was used in the early -time analysis. A regression fit to the early -time fall -off data resulted in a fracture half-length of 356 feet and a fluid efficiency of 1 percent. A Nolte -Smith plot from the injection data yielded a quarter slope, indicating a Perkins and Kern system, i.e. a wedge-shaped vertically contained fracture, which is growing in length. CD1-01A is of like reservoir quality and is expected to have similar fracture properties as demonstrated by CD1-19A above. 2014 CRU Disposal Well Performance Report CD1-01A 10 Well Work Summary CD1-01A Date Event 9/9/2014 TAGGED FILL AT 9736' MDRKB LOGGED INJECTION PROFILE, NO UPFLOW SEEN. 100% OF INJECTION 6/30/2014 ENTERING 9679'-9768' MDRKB PERFORM FCO TO 9786' MD, PERFORM INJECTIVITY TEST (4 BPM TO 2410 6/19/2014 PSI 3/8/2014 EPA WITNESSED (THOR CUTLER) MIT -IA PASSED @ 2340 PSI. LOGGED INJECTION PROFILE, NO UPFLOW SEEN. 100% OF INJECTION 3/8/2014 ENTERING TOP PERF SET 3/3/2014 PERFORMED CALIPER SURVEY FROM TAG AT 9416' MD TO SURFACE 3/2/2014 TAGGED FILL AT 9432' MDRKB Micromotion flow rate and MadgeTech pressure gauge transmitters are installed with an alarm system to detect excess injection pressures and rates. The well is monitored 24 hours a day during injection. The well operates at a maximum 4,200 psig wellhead pressure and an annulus pressure up to 2,000 psig. Continuous, recorded monitoring of volumes of hard piped waste streams are captured through the Alpine automation system. 2014 CRU Disposal Well Performance Report CD1-01A 11 ATTACHMENT 1: CD1-01A 2014 INJECTION SUMMARY TABLE January through December 2014 Injection Summary Well: CD1-01A Disposal Order: 18 Field: Colville River Unit API No.: 50103202990100 Permit to Drill Pool: Alpine Oil Pool No.: 212-099 Pool Code: 120036 Month Days In Operation Tubing Pressure Max Pressure (psig) Tbg Pressure Avg Pressure (psig) Casing Pressure Max Pressure (psig) Csg Pressure Avg Pressure si Daily Average Liquid (bbls) Gas Monthly Total Liquid (bbls) Gas Cumulative Liquid (bbls) January 12 3,939 2,422 1,459 1,254 1,499 0 17,985 0 17,985 February 22 1 3,371 3,126 1,325 1,063 1,464 0 32,205 0 50,189 March 21 4,054 3,177 1,407 740 1,666 0 34,995 0 85,184 April 12 4,128 3,148 1,065 821 1,453 0 17,434 0 102,618 May 20 4,181 3,379 1,192 844 1,207 0 24,138 0 126,756 June 8 4,017 2,566 1,444 960 1,036 0 8,290 0 135,046 July 6 2,892 1,555 1,168 703 976 0 5,859 0 140,905 August 11 2,727 1,554 1,074 779 1,164 0 12,809 0 153,713 September 14 2,970 1,288 1,141 569 1,112 0 15,569 0 169,282 October 6 4,904 834 3,881 462 992 0 5,954 0 175,236 November 12 3,324 1,171 1,278 538 1,663 0 19,955 0 195,191 December 21 3,255 1 1,542 1,317 478 1,229 0 25,810 0 221,002 Monthly Avera a 3,647 2,147 1,479 768 1,289 0 18,417 0 2014 CRU Disposal Well Performance Report CD1-01A 12 ATTACHMENT 2: CD1-01A 2014 INJECTION SUMMARY PLOT Ems 3500 — — - 3000 __ _ �r. ■ •—•— m 2500 -- ._...._ E o ' 2000 i. ML- o j ■ = 150000 10, - - - i 1000!._ w 0 49" Jan-14 Mar-14 I May-14 -—CD1-01A Daily Injection Total (BBLS) ■ CD1-01A Tubing Pressure (PSIG) + CD1-01A Inner Annulus Pressure (PSIG Jul-14 Sep-14 Nov-14 4,500 4,000 3,500 3,000 2,500 a 2,000 a ■ 1,500 1,000 l 500 - 0 Jan-15 2014 CRU Disposal Well Performance Report CD1-01A 13 #4 THE STATE Conservation Commission GOVERNOR SEAN PARNELL August 16, 2013 CERTIFIED MAIL — RETURN RECEIPT REQUESTED 7009 2250 0004 3911 5884 Mr. Jerry Dethlefs Well Integrity Director ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Amendment of Alternative MIT schedule for U1C injection Wells Dear Mr. Dethlefs: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 By a letter received on May 9, 2013 ConocoPhillips Alaska, Inc (CPAI) requested approval to amend the permanent Mechanical Integrity Test (MIT) schedule for Class II injection wells in fields operated by CPAI on the North Slope of Alaska. The Alaska Oil and Gas Conservation Commission (AOGCC) hereby APPROVES the requested amendment establishing the MIT due date for Kuparuk River Unit 1J-pad injection wells as May, and Colville River Unit pads CD3 as February and CD4 as June. AOGCC also APPROVES CPAI's request to allow for a test month for MITs in lieu of an anniversary date. No further action is deemed necessary regarding MITs in Area Injection Orders 213, 16, 18C, 21A, 28, 30 and 35. Should you have any questions, please contact Chris Wallace at 907-793-1250. P Cathy P. Poers er Chair, Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[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 he period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Postal ir- Service CERTIFIEDMAIL., RECEIPT jDoniestic Mail . .. Provided) For delivery Ln e. ra IF Postage $ M Cc,70'ed Fee d Return Receipt Fee Postmark Here Q (Endorsement Required) ♦2 Restricted Deiit ery Fee !: (EndorserrranI Requ"ned) to rU Total Postage rlJ Esent 70 Q Mr. Jerry Dethlefs O S`treet, 7pt No.G Well Integrity Director r� Of PO Bar. No. Conoco Phillips Alaska, Inc. City Siai®, ZiPie Post Office Box 100360 Anchors e AK 99510-0360 .r r a • Complete items 1, 2, and 3. Also complete item 4 if Restricted Delivery is desired. i Print your name and address on the reverse so that we can return the card to you. • Attach this card to the back of the mailpiece, or on the front if space permits. 1. Article Addressed to Mr. Jerry Dethlefs Well Integrity Director ConocoPhillips Alaska, Inc. Post Office Box 100360 Anchoraae, AK 99S10-0360 A. Sig ure X 0 Agent 0 Addressee . R aed by ( Printe ame) C. Date of Delivery 0—BS..c d /- *')�c _lam D. Is deliAy address different from item 1? ❑ Yes If YES, enter delivery address below: ❑ No 3. Ice Type lrCertified Mail 0 Express Mail 0 Registered 0 Return Receipt for Merchandise ❑ Insured Mail ❑ C.O.D. 4. Restricted Delivery? (Extra Fee) 13 Yes 2. Article Number 7009 2250 0004 0911 5884 (rransfer from service label) PS Form 3811, February 2004 Domestic Return Receipt 102595.02-M-1540 THE STATE ,,ALASKA Alaska Oil an d Gas GOVERNOR SEAN PARNELL 333 west Seventh Avenue Anchorage, 6,jaska 99501-3572 ;v;atn: 907.279.1433 Fox:907.27b.7542 August 16, 2013 AOGCC Industry Guidance Bulletin No. 10-02A Mechanical Integrity Testing The Alaska Oil and Gas Conservation Commission (AOGCC) provides the followings clarification of injection well mechanical integrity l�)ressure test (MIT) requirements set forth in 20 AAC 25.252 and 25.402. Injection orders supplement AOGCC regulations by providing additional operating and test1110 obligations. MIT Preparation - The AOGCC must be notified at least 24 hours in advance (48 hours for wells remote from the nearest AOGCC office) for an opportunity to witness the MIT; - Pumping into and bleeding pressures from annuli should be avoided for 24 hours prior to the MIT; if necessary, information should be available to document such activity; - The well's annulus must be fluid packed before the AOGCC Inspector arrives; - Calibrated pressure gauges with suitable range and accuracy must be installed on the tubing, inner (tubing by casing) annulus, and outer (casing by casing) annuli; current calibration should be evident with proper labels or other documentation; - Suitable flow measurement equipment should be available to determine the volume of fluids pumped into and returned from the tested space; - Other equipment (e.g., tanks, lines, bleed trailers, etc.) necessary for the safe pressure testing and suitable for the operating environment should be rigged up prior to AOGCC Inspector arrival at the location. The following information must be available at the location for AOGCC Inspector review: - Valid approved waivers, if any, relating to the integrity of the tested well; - Current well schematic; - Graph of tubing, inner annulus, and outer annulus pressures for the preceding 90 days. Equipment Pressure Rating Equipment subject to test pressure must have a rated working pressure that meets or exceeds the planned test pressure. API defines the rated working pressure of equipment to be the maximum internal pressure that the equipment is designed to contain or control. i Guidance Bulletin 10-02A Mechanical Intearity Testing Paize 2 of 3 Test Cycle After the initial MIT, Class 11 disposal wells injecting solid slurries (used muds, cuttings; produced sand; etc.) require an MIT once every 2 years; otherwise, MITs must be conducted once every 4 years. Injection wells used for enhanced recovery operations must be tested once every 4 years. The AOGCC may, in its discretion, approve an alternate MIT schedule. A 2- or 4-year MIT means the test must be performed not later than the 2- or 4-year anniversary of the test month, unless a specific anniversary date for the MIT has been established by AOGCC approval (e.g., Area Injection Order administrative approval). For example, a test due August 14, 2014 would — under the new "test month" approach - be allowed to be tested not later- than August 30, 2014. ge of operating efficiencies in scheduling groups of MITs, and Operators are encouraged to take advanta to initiate scheduling early in the month to increase inspector availability and allow time for retesting or unplanned events. The AOGCC must be provided the opportunity to witness the MIT for a test to establish a new test due date. The AOGCC may require a witnessed test to be rescheduled to accommodate workload priorities. A pre -injection MIT performed prior to demobilizing a drilling rig from a well should be documented on the AOGCC's MIT Form 10-426 and emailed to the AOGCC addressees noted on the test report form. Test Pressure Unless otherwise required by the AOGCC, an MIT of the inner annulus is required to a minimum pressure of 1500 psi or a pressure determined by multiplying 0.25 psi per foot times the true vertical depth of the packer — whichever is greater. A minimum pressure differential of 500 psi should be maintained between the tested annulus and tubing or adjacent annulus. The operator has the discretion to test to a higher pressure. A passing MIT will have no more than a 10 percent decline in pressure (based on the actual test pressure), a stabilizing pressure trend, and a final pressure that is at or above the required test pressure. For example, the operator may choose to start a required 1500 psi test at or above 1650 psi (additional 150 psi to allow for the 10 percent pressure decline over test duration). Reporting Unless otherwise required by the AOGCC, MIT results must be verified by an operator's designated 'h representative and submitted electronically using Form 10-426 to the AOGCC no later than the 5 calendar day of the month following the testing. • • Guidance Bulletin 10-021A Mechanical lntegrity Testing Pa(_,e ? of Shut-in Wells The AOGCC's preference is to witness an MIT while a well is actively injecting and wellborc conditions (rate and temperature) are stable. If the well is in a short -terror shut-in status when the MIT is due, the AOGCC should be notified and provided an alternate date for testing based on when injection will be recommenced. Injection wells that are shut in long-term (undetermined when injection will restart) need not be tested until they are ready to recommence injection. In lieu of an MIT for the long term shut-in well; the operator must provide to the AOGCC a quarterly graph of tubing, inner annulus and outer annulus pressures. Please share this Guidance Bulletin with all appropriate members of your organizations. Questions or discussion regarding this guidance bulletin should be directed to Chris Wallace at (907) 793-1250. Sincerely; Cathy P. oerster Chair, Commissioner • ConocoPhillips May 8, 20,9 Mr. Chris Wallace Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 R, F C E I V E?Jo Subject: Amendment of alternative MIT schedule for UIC injection wells Dear Mr. Wallace: Jerry Dethlefs Well Integrity Director ConocoPhillips Alaska, Inc 700 G Street Anchorage, AK Phone 907-265-1464 ConocoPhillips Alaska, Inc. (CPAI) requests approval to amend the permanent Mechanical Integrity Test (MIT) schedule for Class II injection wells in fields operated by CPAI on the North Slope of Alaska. The amendment is to include new pads installed since the original approval and to clarify the affected Area Injection Orders (AIO). On February 13, 2006, CPAI requested approval to adopt an alternate MIT schedule for their North Slope Class II injection wells so as to allow the majority of the wells to be tested during the summer months (schedule attached). On March 23, 2006, administrative approval was granted for the alternate schedule by the AOGCC (attached). The approval letter states "The requested schedule modification will allow for greater operating efficiency and will reduce risks to personnel and the environment. The Commission hereby APPROVES the requested modification." The alternative test schedule also complies with the AOGCC Industry Guidance Bulletin No. 10-002 Mechanical Integrity Testing. The section titled "Test Cycle" reads: "Injection wells used for enhanced recovery operations must be tested once every 4 years. The Commission may, in its discretion, approve an alternate MIT schedule. A 2- or 4-year MIT means the test must be performed not later than the 2- or 4-year anniversary of the most recent test date, unless a specific anniversary date for the MIT has been established by a Commission approval (e.g., Area Injection Order administrative approval)." ....."Operators are encouraged to take advantage of operating efficiencies in scheduling groups of MITs within the 2- or 4-year window"...... A key component of the 4-year testing program is that each pad is assigned a specific month to be tested every four years (see attached schedule). The number of pads and wells are divided over the four year period so that roughly one-fourth of the required MITs are performed each year. The specified month is the due date, rather than the specific day of the prior test, to eliminate schedule creep over time. All injection wells on a pad will be tested during the visit. This method was adopted and put into practice with the March 23, 2006 approval and has proven to work well. Please note that CD3, due to lack of summer road access, is scheduled for February by prior AOGCC approval. CPAI is requesting an amendment to incorporate new drillsites and clarify the affected AIOs. Drillsites 1J, CD3 and CD4 have been added to the list. The administrative approval regards Rule 6 in AIOs 2B, 16, 18C, 28, 30 and 35, and Rule 4 in 21A. The MIT schedule applies only to CPAI wells on the standard 4-year test frequency, with the exception of 2P (Meltwater) which is on a 2-year cycle due to recent changes in AIO 21A. Wells with specific approvals or variances on 2-year test cycles will continue to be tested on or before the exact 2-year anniversary date. Approval of this request at your earliest convenience is appreciated. Please call Brent Rogers or Kelly Lyons at 659-7224, or me at 265-1464 if you have any questions. Sincerely, Jerry Dethlefs Well Integrity Director cc: Jim Regg Cathy Forester Attachments E 0 ConocoPhillips Alaska, Inc. UIC MIT Permanent Test Schedule Revised May 7, 2013 Target 4-year Cycle: The following schedule repeats every 4 years Year 1 Kuparuk Alpine May 2A, 2B, 2G, 2H June 1 F, 1 L, 2M, 2V July 2E, 2F, 3J, 3M August 3N, 3Q, 3R, 2P* Year 2 May 3K June 1 B & WSW, 2T, 3H, 30 CD1 July 1Q, 1Y August 1 H, 2C, 2D, 3A, 3C Year 3 February CD3 May 1 C, 1 J June 1 E CD2 July 1 D August 2L, 2N, 2P*, 2U, 3S Year 4 May 1 R, 2W June 2K, 2X, 3B, 3F CD4 July 1A, 1G, 31 August 3G, 2Z Note: Year 1=2012 Revised 05-07-13 Contact: CPAI Problem Well Supervisor, 907-659-7224 • ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 February 13, 2006 Mr. Tom Maunder Alaska Oil & Gas Commission 333 West 7`h Avenue, Suite 100 Anchorage, AK 99501 Subject: Proposal for permanent MIT schedule on UIC injection wells Dear Mr. Maunder: On December 19, 2005, ConocoPhillips Alaska, Inc. (CPAI) requested approval to delay UIC 4-year Mechanical Integrity Tests (MIT) due in 2006 for a limited time beyond their due date so the tests could be performed during the summer months. The request was approved by the AOGCC on December 29, 2005, with the stipulation no further extensions would likely be granted for future years. CPAI is proposing an alternative test plan that should meet the objectives of both CPAI and AOGCC. The AOGCC position is that UIC MIT tests be performed no later than the exact due date of the previous 4-year test on each well, as specified in 20 AAC 25.412 and in Area Injection Orders 2B and 18B. The justification for this date enforcement is lack of precedent within the regulations for an Operator to alter the due date without specific approval from the AOGCC. Previously these tests had routinely been delayed to the summer months due to safety and spill potential issues and efficiency/cost savings associated with performing these tests during warm weather. CPAI is proposing a schedule for UIC MIT testing patterned after the AOGCC required program used for testing the Safety Valve System (SVS). In that program each pad is assigned to two specific months of the year for testing. To prevent schedule creep over time, there is some flexibility to perform the tests anytime during the assigned month. The pads are scheduled to roughly balance the workload from one month to the next. For 4-year UIC MIT testing, CPAI is proposing that each pad be assigned a specific month to be tested every four years. The number of pads and wells will be divided over the four year period so that roughly one-fourth of the required MITs will be performed each year. The specified month will be the due date, rather than the specific day of the prior test, to eliminate schedule creep over time. To implement this schedule E • Mr. Tom Maunder Page 2 of 2 02/13/06 CPAI will accelerate testing on a number of wells over the next few years. The proposed schedule and pad/month assignments are attached. There are a number of benefits to this proposal: • Each well will be tested close to the previous 4-year test if a small allowance is approved to prevent schedule creep. This should meet the "every 4-year" test frequency requirement in the UIC regulations. • All the injection wells on a given pad will be addressed during the same testing operation, regardless of when the last test was performed on a particular well. This will keep all the wells on the same schedule, results in efficiencies in time and reduces fluid handling risk. • Eliminates requests to "reset" the 4-year clock when tests are performed during the year, eliminating significant record keeping efforts. • The proposed months are in the May through August time period that meets the CPAI goal of testing during warmer weather. The AOGCC is specifically being requested in this proposal to approve the "due month" concept of this plan rather than the "exact due date" specified in the letter dated December 29, 2005. In addition, the proposal applies only to CPAI wells on the standard 4-year test frequency. Wells with specific approvals or variances on 2-year test cycles will continue to be tested on or before the exact 2-year anniversary date. Approval of this request at your earliest convenience is appreciated. Please call MJ Loveland, Marie McConnell, or me at 659-7224 if you have any questions. Sincerely, Jerry Dethlefs Problem Well Supervisor Attachment ConocoPhillips Alaska, Inc. Proposed UIC MIT Permanent Test Schedule Initial 4-year Cycle: Requires accelerating tests for all wells on a pad to be on same cycle Year 1: 2006 Total Wells Kuparuk Pads Alpine Pads Total Wells May 22 1 C - June 56 1 B, 3H, 30, 1 E July 54 1 D, 10, 1Y, 3F' August 48 1A-, 1 R', 2G', 2K', 2L, 2N, 2P, 2U, 2W, 2Z', 3G', 3S CD2 29 Total 180 Year 2: 2007 May 21- - 1 R. 2W June 53 2K, 2T, 2X, 36, 3F July 28 1 A, 1 G, 31 August 25 IF', 2D', 2F', 2H', 2M', 3G, 3M', 2Z Total 127 Year 3: 2008 May 23 2A, 2B, 2G, 2H June 38 IF, 1 L, 2M, 2V �- July 30 2E, 2F, 3J, 3M CD1' 2 August 24 3N, 3Q, 3R Total 115 _ Year 4: 2009 May 14 3K June 39 1 B, 2T, 3H, 30 July 19 1Q, tY August 35 1 H, 2C, 2D, 3A, 3C CD1 22 Total 107 Target 4- ear Cycle: The followinIq schedule repeats every 4 years Year 5 - May 22 1 C June 31 1E July 34 1D August 32 2L, 2N, 2P, 2Z, 3S CD2 29 Total 119 Year 6 May 21 1 R, 2W June 38 2K 2X, 313, 3F July 18 1 A, 1 G, 31 August 18 3G, 2Z Total 95 Year? May 23 2A, 2B, 2G, 2H June 38 1 F, 1 L, 2M, 2V July 30 2E, 2F, 3J, 3M August 24 3N, 3Q, 3R Total 115 Year 8 May 14 3K June 40 2T, 1 B, 3H, 30 July 27 1Q, 1Y August 35 1 H, 2C, 2D, 3A, 3C CD1 24 Total 116 Notes: 1)' Denotes pads to be accelerated prior to due -date for combining all wells on a pad to same test date 2) New pads will be added to the schedule as they are brought in service • AI.ASSA OIL AND GALS CONSERVATION COMUSSIOR 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: FRANK H. MURKOWSKI, GOVERNOR 333 W. 7'" AVENUE, SUfTE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX , (907) 276-7542 On February 13, 2006 ConocoPhillips Alaska, Inc ("CPAI") requested approval to modify the schedule for demonstrating mechanical integrity on their North Slope injection wells so as to allow the majority of the wells to be tested on a rotating schedule during the summer months. The requested schedule modification will allow for greater operating efficiency and will reduce risks to personnel and the environment. The Commission hereby APPROVES the requested modification. In order to allow opportunity for AOGCC Inspectors to witness the testing, CPAI is requested to provide the planned schedule for Summer 2006 as soon as practical. If you have any questions, please contact Jim Regg at 793-1236. As provided in AS 31.05.080(a), within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless reconsideration Jr4 been requested. Alaska and dated March 2.5, 2006 A "opean Dan T. Seamount, Jr. iairm Commissioner 4CathyFoerster Commissioner 11 • ConocoPhillips April 8, 201� �U Mr. Dan Seamount Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Jerry Dethlefs Well Integrity Director ConocoPhillips Alaska, Inc 700 G Street Anchorage, AK Phone 907-265-1464 s (C3 k�-, 0 ocl�t-*-A" 13 . I (o Subject: Administrative Approval for alternative MIT schedule for UIC injection wells (revised) Dear Mr. Seamount: ConocoPhillips Alaska, Inc. (CPAI) requests approval for a modified Mechanical Integrity Test (MIT) schedule for Class 11 injection wells in fields operated by CPAI on the North Slope of Alaska. A provision in AOGCC Industry Guidance Bulletin No. 10-002 Mechanical Integrity Testing, under "Test Cycle" states: "Injection wells used for enhanced recovery operations must be tested once every 4 years. The Commission may, in its discretion, approve an alternate MIT schedule. A 2- or 4-year MIT means the test must be performed not later than the 2- or 4-year anniversary of the most recent test date, unless a specific anniversary date for the MIT has been established by a Commission approval (e.g., Area Injection Order administrative approval)." CPAI is requesting administrative approval from Rule 6, Area Injection Orders 2B, 16, 18B, 27, 28, 30 and 35, and Rule 4, AIO 21, in order to "take advantage of operating efficiencies in scheduling groups of MITs within the 2- or 4-year window" (reference Bulletin 10-002). On February 13, 2006, CPAI requested approval to modify the MIT schedule for their North Slope Class II injection wells so as to allow the majority of the wells to be tested during the summer months (attached). On March 23, 2006, approval was granted for the modified schedule by the AOGCC (attached). The approval letter states "The requested schedule modification will allow for greater operating efficiency and will reduce risks to personnel and the environment. The Commission hereby APPROVES the requested modification." CPAI complied with the MIT schedule as approved until the AOGCC issued Industry Guidance Bulletin No. 10-002 Mechanical Integrity Testing. According to the AOGCC, as of the date of the Guidance Bulletin the administrative approval for the MIT test schedule was revoked. Although the Guidance Bulletin may meet the needs of other operators in the state, it also results in placing CPAI back to the point of the initial schedule modification request. Therefore, CPAI is again requesting approval to modify the MIT schedule by Area Injection Order administrative approval. The justification for the schedule change request has not altered since the original request in 2006. CPAI requests relief from the requirement in Bulletin 10-002: "A 2- or 4-year MIT means the test must be performed not later than the 2- or 4-year anniversary of the most recent test date, unless a specific anniversary date for the MIT has been established by a Commission approval (e.g., Area Injection Order administrative approval). " Ol 0 CPAI proposes a schedule for UIC MIT testing patterned after the AOGCC required program used for testing the Safety Valve System (SVS). In that program each pad is assigned to two specific months of the year for testing. To prevent schedule creep over time, there is some flexibility to perform the tests anytime during the assigned month. The pads are scheduled to roughly balance the workload from one month to the next. For 4-year UIC MIT testing, CPAI is proposing the same schedule as that approved in 2006; that each pad be assigned a specific month to be tested every four years (see attached schedule). The number of pads and wells are divided over the four year period so that roughly one-fourth of the required MITs are performed each year. The specified month is the due date, rather than the specific day of the prior test, to eliminate schedule creep over time. This method was adopted and put into practice with the March 23, 2006 approval and has proven to work well. Please note that CD3, due to lack of summer road access, is scheduled for February by prior AOGCC approval. There are a number of benefits to this proposal: • Each well will be tested close to the previous 4-year test if a small allowance is approved to prevent schedule creep. This should meet the "every 4-year" test frequency requirement in the UIC regulations. • All the injection wells on a given pad will be addressed during the same testing operation, regardless of when the last test was performed on a particular well. This will keep all the wells on the same schedule, results in efficiencies in time and reduces fluid handling risk. • Eliminates requests to "reset" the 4-year clock when tests are performed during the year, eliminating significant record keeping efforts. • The proposed months are in the May through August time period that meets the CPAI goal of testing during warmer weather to minimize risks regarding personnel safety and releases to the environment. The AOGCC is being requested to approve the "due month" concept of this plan rather than the "exact, due date" specified in Bulletin 10-002. In addition, the proposal applies only to CPAI wells on the standard 4-year test frequency. Wells with specific approvals or variances on 2-year test cycles will continue to be tested on or before the exact 2-year anniversary date. Approval of this request at your earliest convenience is appreciated. Please call Brent Rogers or Kelly Lyons at 659-7224, or me at 265-1464 if you have any questions. Sincerely, _ Jerry Dethlefs Well Integrity Director cc: Cathy Forester Jim Regg Attachments 0 • ConocoPhillips Alaska, Inc. UIC MIT Permanent Test Schedule Target 4-year Cycle: The following schedule repeats every 4 years Year 1 Kuparuk P� Alpine May 2A, 2B, 2G, 2H June 1 F, 1 L, 2M, 2V July 2E, 2F, 3J, 3M August 3N, 3Q, 3R Year 2 May 3K June 1B & WSW, 2T, 3H, 30 CD1 July 1Q, 1Y August 1 H, 2C, 2D, 3A, 3C Year 3 February CD3 May 1 C, 1 J June 1 E CD2 July 1 D August 2L, 2N, 2P, 2U, 3S Year 4 May 1 R, 2W June 2K, 2X, 3B, 3F CD4 July 1A, 1G, 31 August 3G, 2Z Note: Year 1=2012 Revised 04-05-12 Contact: CPAI Problem Well Supervisor, 907-659-7224 LJ ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 February 13, 2006 Mr. Tom Maunder Alaska Oil & Gas Commission 333 West 7ch Avenue, Suite 100 Anchorage, AK 99501 Subject: Proposal for permanent MIT schedule on UIC injection wells Dear Mr. Maunder: On December 19, 2005, ConocoPhillips Alaska, Inc. (CPAI) requested approval to delay UIC 4-year Mechanical Integrity Tests (MIT) due in 2006 for a limited time beyond their due date so the tests could be performed during the summer months. The request was approved by the AOGCC on December 29, 2005, with the stipulation no further extensions would likely be granted for future years. CPAI is proposing an alternative test plan that should meet the objectives of both CPAI and AOGCC. The AOGCC position is that UIC MIT tests be performed no later than the exact due date of the previous 4-year test on each well, as specified in 20 AAC 25.412 and in Area Injection Orders 2B and 18B. The justification for this date enforcement is lack of precedent within the regulations for an Operator to alter the due date without specific approval from the AOGCC. Previously these tests had routinely been delayed to the summer months due to safety and spill potential issues and efficiency/cost savings associated with performing these tests during warm weather. CPAI is proposing a schedule for UIC MIT testing patterned after the AOGCC required program used for testing the Safety Valve System (SVS). In that program each pad is assigned to two specific months of the year for testing. To prevent schedule creep over time, there is some flexibility to perform the tests anytime during the assigned month. The pads are scheduled to roughly balance the workload from one month to the next. For 4-year UIC MIT testing, CPAI is proposing that each pad be assigned a specific month to be tested every four years. The number of pads and wells will be divided over the four year period so that roughly one-fourth of the required MITs will be performed each year. The specified month will be the due date, rather than the specific day of the prior test, to eliminate schedule creep over time. To implement this schedule • 0 Mr. Tom Maunder Page 2 of 2 02/13/06 CPAI will accelerate testing on a number of wells over the next few years. The proposed schedule and pad/month assignments are attached. There are a number of benefits to this proposal: • Each well will be tested close to the previous 4-year test if a small allowance is approved to prevent schedule creep. This should meet the "every 4-year" test frequency requirement in the UIC regulations. • All the injection wells on a given pad will be addressed during the same testing operation, regardless of when the last test was performed on a particular well. This will keep all the wells on the same schedule, results in efficiencies in time and reduces fluid handling risk. • Eliminates requests to "reset" the 4-year clock when tests are performed during the year, eliminating significant record keeping efforts. • The proposed months are in the May through August time period that meets the CPAI goal of testing during warmer weather. The AOGCC is specifically being requested in this proposal to approve the "due month" concept of this plan rather than the "exact due date" specified in the letter dated December 29, 2005. In addition, the proposal applies only to CPAI wells on the standard 4-year test frequency. Wells with specific approvals or variances on 2-year test cycles will continue to be tested on or before the exact 2-year anniversary date. Approval of this request at your earliest convenience is appreciated. Please call MJ Loveland, Marie McConnell, or me at 659-7224 if you have any questions. Sincerely, Jerry Dethlefs Problem Well Supervisor Attachment OT AIASKA FRANK H. MURKOWSKI, GOVERNOR azarA KA OIL AND 9M 333 W. 7- AVENUE, SUITE 100 CONSERVATION COD' USSION � ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Mr. Jerry Dethlefs Problem Well Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 RE: North Slope MIT Schedule Dear Mr. Dethlefs: On February 13, 2006 ConocoPhillips Alaska, Inc ("CPAI") requested approval to modify the schedule for demonstrating mechanical. integrity on their North Slope injection wells so as to allow the majority of the wells to be tested on a rotating schedule during the summer months. The requested schedule modification will allow for greater operating efficiency and will reduce risks to personnel and the environment. The Commission hereby APPROVES the requested modification. In order to allow opportunity for AOGCC Inspectors to witness the testing, CPAI is requested to provide the planned schedule for Summer 2006 as soon as practical. If you have any questions, please contact Jim Regg at 793-1236. As provided in AS 31.05.080(a), within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless reconsiderationA been requested. Alaska and dated March 2�, 2006 1 Dan T. Seamount, Jr. Commissioner Cathy . Foerster Commissioner ConocoPhillips Alaska, Inc. Permanent UIC MIT Test Schedule Initial 4-year Cycle: Requires accelerating tests for all wells on a pad to be on same cycle Year 1: 2006 Total Wells Kuparuk Pads Alpine Pads Total Wells May 22 1 C June 56 1B & WSW, 1E, 3H, 30 July 54 1 D, 1 Q, 1 Y, 3F* August 48 1A*, 1R*, 2K*, 2L, 2N, 2P, 2U, 2W*, 2Z*, 3G*, 3S CD2 29 Total 180 Year 2: 2007 May 21 1 R, 2W June 53 2K, 2T, 2X, 3B, 3F July 28 1A, 1G, 31 August 25 1F*, 2D*, 2F*, 2G*, 2H*, 2M*, 3G, 3M*, 2Z Total 127 Year 3: 2008 May 23 2A, 2B, 2G, 2H June 38 1 F, 1 L, 2M, 2V CD1* 2 July 30 2E, 2F, 3J, 3M August 24 3N, 3Q, 3R Total 115 Year 4: 2009 May 14 1 J*, 3K June 39 1B & WSW, 2T, 3H, 30 CD1 22 July 19 1Q, 1Y CD4* 15 August 35 1 H, 2C, 21), 3A, 3C Total 144 , Target 4-year Cycle: The following schedule repeats every 4 years Year 5 _.. ------- --- -- - Feb C - Ma 37 1C, 1J - --- - -- --- June i 31 1E CD2 2 July i 34 1 D August 32 2L, 2N, 2P, 2U, 2Z, 3S Total 119 ___-_ _ _ Year 6-- May I 21 1R 2W --- --- - - -- ----- - -- June 38 2K, 2X, 3B, 3F CD4 18 July-- -- - 1A, 1G, 31 _ _ -- --- ---- August 18 ----. _ -- --- - - 3G 2Z __ -._._ - -_ Year 7 May 23 2A 26 2G 2H __.._. _..__.- June _ 38....._ 1F, 1L, 2M, 2V July 30 2E 2F, 3J 3M August 24 3N 3Q, 3R __....... Total 115 May 14 3K --- _ ._._.. 40 ---- Ju_ ne ------ - - ----- 16 &WSW, 2T--- -- - 3H, 30 CD1 24 _..__ y --1 Q, 1 Y .------- -..--- - --- --Jul August 35 1H 2C 2D,3A 3C Total 116 Notes: 1) * Denotes pads to be accelerated prior to due -date for combining all wells on a pad to same test date 2) New pads will be added to the schedule as they are brought in service; load leveling may be required Revised 08-16-06 z3 • L,. • • ConocoPhi 11 CI I 43 fC Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510 -0360 April 13, 2013 Mr. Dan Seamount Alaska Oil & Gas Commission 333 West 7 Avenue, Suite 100 Anchorage, AK 99501 Dear Mr. Seamount: ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 18C, Rule 9, to apply for Administrative Approval allowing well CD4 -321 (PTD 206 -142) to be online in water only injection service with OAxOOA communication. If you need additional information, please contact myself or Kelly Lyons at 659 -7224, or MJ Loveland / Martin Walters at 659 -7043. Sincerely, Brent Rogers Problem Wells Supervisor ConocoPhillips Alaska Inc. Cc: Working Well File, Legal Well File • Name of Recipient Page 2 of 2 04/13/13 • • ConocoPhillips Alaska, Inc. Colville River Unit CD4 -321 (PTD# 206 -142) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this Administrative Relief request as per Area Injection Order 18C, Rule 9, to continue injection with known annular communication for Alpine injection well CD4 -321. Well History and Status Colville River Unit well CD4 -321 (PTD 206 -142) was drilled and completed in 2006 as a service well. CD4 -321 was reported to the Commission on March 18, 2013 as showing signs of a surface casing leak to atmosphere via the surface casing by conductor annulus. The following pertinent operations have been completed to date: Date Operation Result Comment 03/17/13 MITIA Passed Following discovery of SC leak 03/17/13 SCLD NA Leak suspected @ —54' The surface casing leak is suspected to be too deep to excavate and repair with a welded sleeve. Repair of the surface casing leak would require an alternative sealant type repair or a rig workover. Repair options are under evaluation however CPAI requests to continue water injection in the interim. NSK Problem Well Supervisor 4/13/2013 • • Barrier and Hazard Evaluation Tubing: The 4 -1/2 ", 12.6 ppf, L -80 tubing has integrity to the packer @ 18,077' MD, based on the passing MITIA as outlined above. Production casing: The 7 26 ppf, L -80 production casing has an internal pressure yield � Y p g pp p g rating of 7240 psi and has integrity to the packer @ 18,077' MD (7181' TVD) based upon the passing MITIA as outlined above. Surface casing: The 9 -5/8 ", 40 ppf, L -80 surface casing with an internal yield pressure rating of 5750 psi set at 3504' MD (2384' TVD) does not have integrity based upon the results of the surface casing leak detect (SCLD). Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the production tubing. Second barrier: The secondary barrier to prevent a release from the well and provide zonal isolation is the production casing should the production tubing fail. Monitoring Each well is monitored daily for wellhead pressure changes. Should leaks develop in the tubing or production 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 /O 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 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. IA pressure not to exceed 2000 psi & OA pressure not to exceed 100 psi. 4. Submit monthly reports of daily tubing & IA pressures and injection volumes; 5. Shut -in the well should MIT's or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. NSK Problem Well Supervisor 4/13/2013 2 1 h WNS _ II CD4-321 ConocoPhillips I well Attributes _ Max Angle & M D TO xiHtir„t. ins Wellbore API/UWI Field Name Well Status Incl ( °) MD (ftKB) Act Btm (ftKB) cornaibilips 501032053600 NANUQ KUPARUK INJ 72.56 3,218.04 19,337.0 Comment H2S (ppm) Date Annotation End Date KB-Grd (ft) Rig Release Date Well Contra - CD4-321 11/30/2012 1243: 20 PM SSSV: WRDP Last WO: 43.58 10/26/2006 Schematic - Actual Annotation Depth (ftKB) End Date Annotation Last Mod ... End Date Last Tag: Rev Reason: WELL REVIEW osborl 11/30/2012 Casing Strings Casing Description 'String 0... String ID ... Top (kKB) Set Depth (t... Set Depth (TVD) ... String Wt... String ... String Top Thrd CONDUCTOR 16 15.250 37.0 114.0 114.0 65.00 H -40 WELDED Insulated 34" HANGER, 32 I <` • Casing Description String 0... String ID ... Top (ftKB) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd pp — SURFACE 95/8 8.835 36.6 3,504.0 2,384.1 40.00 L - 80 BUTT r Casing Description String 0... String ID ... Top (ftKB) Set Depth (f... Set Depth (TVD) ... String Wt.. String String Top Thrd N NTERMEDIATE 7 6276 34.4 19,3231 7,800.2 26 00 L 80 BTCM Tubing Strings Tubing Description String 0... String ID... Top (ftKB) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd TUBING 41/2 3.958 31.5 18,194.2 7,220.4 12.60 L-80 IBTM II P Gas Injection ' Completion Details Top Depth (TVD) Top Inc' Nomi... Top (ftKB) (MB) ( °) Rem Description Comment ID(in) CONDUCTOR 31.5 31.5 0.12 HANGER FMC TUBING HANGER 4.500 Insulated 37 - 114 ` 2,290.2 1,958.6 58.57 NIPPLE CAMCO DB NIPPLE 3.812 37 - 114 I 17,907.9 7,124.5 70.90 SLEEVE BAKER PREMIER SLIDING SLEEVE 3.810 NIPPLE, 2,2 `" 17,993.5 7,152.7 70.61 GAUGE WEATHERFORD POD2 GAUGE CARRIER 3.958 VALVE, 2,290 18,077.0 7,180.5 70.78 PACKER BAKER PREMIER PACKER 3.875 IL 18,181.9 7,215.4 70.35 NIPPLE HES NX NO GO NIPPLE 3.725 18,192.8 7,220.0 71.16 WLEG BAKER WIRELINE FLUTED GUIDE 3.875 Other In Hole ireline retrievable plugs, valves, pumps, fish, etc.) Top Depth (TVD) Top Inc' Top (ftKB) (RIM) (°) Description Comment Run Date ID (In) t' 1,958.6 58.57 VALVE A - 1 INJECTION VALVE (SIN: HSS - 163) 10/22/2012 1.250 SURFACE, _ ' 37 -3504 Perforations & Slots Shot Top (TVD) Btm (TVD) Dens Top (ftKB) Btm (ftKB) (RKB) (ftKB) Zone Date (.h... Type Comment . . 18,434.0 18,450.0 7,300.3 7,305.5 11/20/2006 6.0 IPERF 18,450.0 18,470.0 7,305.5 7,312.3 11/20/2006 6.0 IPERF SLEEVE, 17,908 GAUGE, 17,993 1. PACKER, 18,077 T It : NIPPLE, 18,182 WLEG, 18,193 1 M. IPERE. - — �+' 18.434 -18,450 = M. IPERF, - -_ 18,450.18,470 — - NTERMEDIATE, 3419,323 N . ' TD, 19,337 • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: jim.regat alaska.gov; AOGCC.Inspectorsalaska.gov; phoebe.brooks(rD.alaska.gov chris.wallace( talaska.gov OPERATOR: ConocoPhillips Alaska, Inc FIELD 1 UNIT / PAD: Alpine / CRU / CD4 pad DATE: 03/17/13 OPERATOR REP: Miller / Byrne AOGCC REP: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well CD4 -321 Type Inj. W TVD 7,181' Tubing 1,540 1,540 1,540 1,540 Interval 0 P.T.D. 2061420 Type test P Test psi 1795.25 Casing 867 3,000 2,980 2,980 P/F P Notes: Diagnostic MITIA OA 0 0 0 0 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 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 TYPE INJ Codes TYPE TEST Codes INTERVAL Codes D = Dnlling Waste M = Annulus Monitoring I = Initial Test G = Gas P = Standard Pressure Test 4 = Four Year Cycle I = Industrial Wastewater R = Internal Radioactive Tracer Survey V = Required by Variance N = Not Injecting A = Temperature Anomaly Survey 0 = Other (describe in notes) W = Water D = Differential Temperature Test Form 10 - 426 (Revised 11/2012) MIT CRU CD4 -321 diagnostic 03 -17 -13 xls �2 Roby, David S (DOA) From: Walker, Jack A [ Jack .A.Walker @conocophillips.com] Sent: Friday, November 05, 2010 10:20 AM To: Roby, David S (DOA) Subject: Colville River Field & Kuparuk River Field Water Comparison Attachments: ColvilleRiverWaterAnalyses.xis Dave, Enclosed is the comparison we discussed on the phone. The two charts show the range of dissolved solids for Colville produced water and seawater plotted with the average value for Kuparuk CPF -2 produced water which is basis for our belief that the CPF -2 water is compatible with the Colville River Field formations. I'll follow up with more background regarding the request for authorization to inject Kuparuk River Field produced water into the Colville River Field Oil Pools. Jack 1 Colville River Field and CPF -2 Produced Water Comparison 100000 10000 -r Q 1000 a i 0 J 100 ■ m ■ E ■ ■ +� 10 ■ • c E Q Q 1 a) M 0.1 0 - - - - - - -- OCRU Produced Water (Range) o ■ 0.01 ■ CPF -2 PW Average - Last 10 Samples 0.001 ■ ■ J . ' oC` J ' .,fl , f l \ jC` °� o � \ot `G�o � Gr a°��o a �o,� 5° ro�Qr 41 � 4 Colville River Field Seawater and CPF -2 Produced Water Comparison 100000 10000; x u w ■ 1000 100 IM E ■ ■ c 10 ■ 0 E 1 � ■ ■ ■ 0.1 ■Seawater (Range) ■ 0.01 ■ CPF -2 PW Average - Last 10 Samples F 0.001 ■ ■ \�� KIP G01, ° � 5 °a �� °a 01 SAMPLE NUM Date Time Location ravity @ 60 H 6298863 10/3/2010 22:33 Separator 1.0179 7.48 6298864 10/3/2010 22:27 Separator 1.0201 8.37 AB71202 7/4/2010 4:00 Drum 1.0204 7.81 AB71201 7/4/2010 4:00 Separator 1.0206 716 AB71200 7/4/2010 4:00 Separator 1.0188 8.59 AB68013 4/4/2010 2:50 Separator 1.0201 8.43 AB68012 4/4/2010 2:30 Separator 1.0208 7.63 AB64673 1/5/2010 3:00 Separator 1.0201 8.59 AB64672 1/5/2010 2:50 Separator 1.0198 7.58 AB61378 10/12/2009 15:00 Drum 1.0207 7.6 Seawater - AB42201 7/4/2008 Summer 1.0026 7.01 Seawater - AB36364 2/8/2008 Winter 1.0338 6.75 Specific Gravity @ 600 p PW Minimum 1.0179 7.48 PW Maximum 1.0208 8.59 Difference 0.0029 1.11 SW Minimum 1.0026 6.75 SW Maximum 1.0338 7.01 Difference 0.0312 0.26 SAMPLE NUM Date Time MPLE'POI ravi 60 pH CPF -2 Prod. Water Tank AB65778 2/6/2010 14:09 Outlet 1.0168 7.98 CPF -2 Prim. Sep. Water AB62075 11/4/2009 0:00 Outlet 1.0191 7.87 CPF -2 Prim. Sep. Water AB61846 10/29/2009 12:40 Outlet 1.0198 7.9 CPF -2 Prim. Sep. Water AB61525 10/21/2009 13:02 Outlet 1.0192 7.74 CPF -2 Prim. Sep. Water AB60990 10/5/2009 12:45 Outlet 1.0191 7.79 CPF -2 Prim. Sep. Water AB59666 9/5/2009 0:00 Outlet 1.0188 8.05 CPF -2 Prod. Water Tank AB59106 8/22/2009 13:40 Outlet 1.02 7.9 CPF -2 Prod. Water Tank AB50294 2/6/2009 0:00 Outlet 1.0188 7.98 CPF -2 Prod. Water Tank AB43457 8/10/2008 0:00 Outlet 1.0194 7.9 CPF -2 Prim. Sep. Water AB42709 7/17/2008 0:00 Outlet 1.0188 7.73 Min 1.0168 7.73 Max 1.02 8.05 Average 1.01898 7.884 I Previous 10 Samples Bicarbonate 1230 1140 1225 1223 1136 Carbonate 0 95 0 0 109 Chloride 15050 14620 15260 14960 14400 Sulfate 250 250 172 172 180 Sulfide Aluminum <0.1 <0.1 < 0.1 < 01 < 0.1 Boron 28.6 3.4 28 28 28 Barium 4.3 <1.0 8 3 13 Calcium 148.9 21.5 138 138 147 Chromium <0.2 <0.2 < 0.2 < 0.2 < 0.2 Iron 1.3 1.1 0.9 1.3 2.6 Potassium 67.6 7.9 55 58 56 Lithium 3.2 <0.5 2 2 2 Magnesium 621 7.7 57 57 58 Manganese 0.027 0.009 0.033 0.029 0.037 Sodium 11700 14600 10470 10330 10400 Phosphorus 0.9 0.1 0.6 1.1 0.3 Silicon 23.3 2.3 22 21 21 Strontium 15.3 1.9 16.4 15.9 16.2 Zinc 0.1 <0.1 < 0.1 < 0.1 < 0.1 Specific Gravity 60 degrees F 1.0179 1.0201 1.0204 1.0206 1.0188 pH 7.48 8.37 7.81 7.76 8.59 on uctivity micro-mhos/c icro -m os /cm 4 Notes: 1. Min / Max values taken from 10 most recent PW samples and typical summer / winter SW samples 2. Averages derived from 10 most recent CPF -2 PW samples. �ivity micro- Bicarbonate I Carbonate I Chloride Sulfate Sulfide Aluminum Boron 1230 0 15050 250 <0.1 28.6 1140 95 14620 250 <0.1 3.4 40100 1225 0 15260 172 < 0.1 28 40100 1223 0 14960 172 < 0.1 28 40100 1136 109 14400 180 < 0.1 28 34900 1108 97 14790 205 0.1 28.3 35700 1253 0 15180 228 < 0.1 30.4 28200 1178 185 15500 280 < 0.1 27.1 29800 1280 0 15600 290 < 0.1 28.4 30500 1403 0 15310 219 < 0.1 27 5960 100 0.001 1814 279 0.001 0 1 51900 140 0 24960 3580 0.001 0.1 4.9 I tivity micro Bicarbonate Carbonate Chloride Sulfate Sulfide I Aluminum Boron 28200 1108 0 14400 172 0 0.1 3.4 40100 1403 185 15600 290 0 0.1 30.4 11900 295 185 1200 118 0 0 27 5960 100 0 1814 279 0.001 0 1 51900 140 0.001 24960 3580 0.001 0.1 4.9 45940 40 0.001 23146 3301 0.0001 0.1 3.9 �tivity micro carbonate m arbonate m Chloride mg/l mg/l Sulfate m /I Sulfide m /l luminum mgl Boron m /l 35200 1515 0 12050 42 9.4 < 0.1 16.2 30000 1541 0 13920 34 5.9 < 0.1 16.8 29800 1571 0 14550 65 16 <0.1 15 29400 1585 0 14400 69 8.7 < 0.1 16 29700 1589 0 13750 42 8.5 < 0.1 19.6 29900 1538 0 13920 36 11.6 < 0.1 17 29300 1581 0 14700 59 7.2 < 0.1 15.5 32300 1880 0 13110 53 < 0.1 16,6 34400 1991 0 14590 49 12 < 0.1 16.1 33800 1929 0 13980 47 6.7 < 0.1 147 29300 1515 0 12050 34 5.9 0 14.7 35200 1991 0 14700 69 16 0 19.6 31380 1672 0.001 13897 49.6 9.55555556 0.001 16.35 Colville Minimum , (mglL) 1108 1253 1178 1280 1403 100 140 100.0 97 0 185 0 0 0.0 0.0 0.0 14790 15180 15500 15600 15310 1814 24960 1814.0 205 228 280 290 219 279 3580 172.0 0.0 0.0 0.0 0.1 < 0.1 < 0.1 < 0.1 < 0.1 0.0 0.1 0.0 28.3 30.4 27.1 28.4 27 1 4.9 1.0 11 2 5 4 67 0.0 1.0 0.0 185 192 121 132 133 54 515 21.5 < 0.2 < 0.2 < 0.2 < 0.2 < 0.2 0.0 0.2 0.0 2.4 2.5 0.6 1.8 0.9 0 0.5 0.0 104 143 54 65 68 44 609 7.9 2 2 2 2 2 0.0 0.5 0.0 82 83 52 57 58 124 1530 7.7 0.051 0.051 0.032 0.036 0.03 0.014 0.001 0.0 11280 11670 9560 9696 10400 509 13960 509.0 0.6 0.6 03 0.3 0.2 0 0.1 0.0 21 23 20 21 19 0 1 0.0 16.8 18 15.6 15.4 13 1 10.2 1.0 < 0.1 < 0.1 < 0.1 < 0.1 1< 0.1 0 1 0.0 1.0201 1.0208 1.0201 1.0198 1.0207 1.0026 1.0338 1.0 8.43 7.63 8.59 7.58 7.6 7.01 6.75 6.8 9 0 T5 5 U 2 8200 ----- T9W 30500 59601 51900 5960.0 Barium I Calcium I Chromium Iron Potassium I Lithium I Magnesium Man anew 4.3 148.9 <0.2 1.3 67.6 3.2 62.1 0.027 <1.0 21.5 <0.2 1.1 7.9 <0.5 7.7 0.009 8 138 < 0.2 0.9 55 2 57 0.033 3 138 < 0.2 1.3 58 2 57 0.029 13 147 < 0.2 2.6 56 2 58 0.037 11 185 < 0.2 2.4 104 2 82 0.051 2 192 < 0.2 2.5 143 2 83 0.051 5 121 < 0.2 0.6 54 2 52 0.032 4 132 < 0.2 1.8 65 2 57 0.036 67 133 < 0.2 0.9 68 2 58 0.03 0 54 0 0 44 0 124 0.014 1 515 0.2 0.5 609 0.5 1530 0.001 Barium Calcium I Chromium Iron Potassium Lithium Magnesium Man anew 2 21.5 0 0.6 7.9 2 7.7 0.009 67 192 0 2.6 143 3.2 83 0.051 65 170.5 0 2 135.1 1.2 75.3 0.042 0 54 0 0 44 0 124 0.001 1 515 0.2 0.5 609 0.5 1530 0.014 1 461 0.2 0.5 565 0.5 1406 0.013 Barium m /I Calcium m / hromium md Iron m /i totassium md Lithium m / a nesium m an anese m 29 135 < 0.2 < 0.5 87 2 98 0.018 43 105 < 0.2 < 0.5 66 2 101 0.015 36 93 0.2 0.3 56 1 95 0.03 28 97 < 0.2 1.3 62 2 104 0.025 34 112 < 0.2 < 0.5 96 2 107 0.011 43 91 <0.2 <0.5 61 2 100 <0.01 42 99.9 < 0.2 < 0.5 62.5 < 0.5 101 < 0.001 34 109 < 0.2 < 0.5 63 1 78 0.011 22 111 < 0.2 5.5 91 2 103 0.048 28 105 < 0.2 < 0.5 81 2 102 0.013 22 91 0.2 0.3 56 1 78 0.011 43 135 0.2 5.5 96 2 107 0.048 33.9 105.79 0.2 2.4 72.55 1.8 98.9 0.021375 River Field PW & SW Maximum Difference (mg /L) (mg7L) 1403.0 1303.0 1515.0 1541.0 1571.0 1585.0 1589.0 1538.0 185.0 185.0 0.0 0.0 0.0 0.0 0.0 0.0 24960.0 23146.0 12050.0 13920.0 14550.0 14400.0 13750.0 13920.0 3580.0 3408.0 42.0 34.0 65.0 69.0 42.0 36.0 0.0 0.0 9.4 5.9 16.0 8.7 8.5 11.6 0.1 0.1 < 0.1 < 0.1 <0.1 < 0.1 < 0.1 < 0.1 30.4 29.4 16.2 16.8 15.0 16.0 19.6 17.0 67.0 67.0 29.0 43.0 36.0 28.0 34.0 43.0 515.0 493.5 135.0 105.0 93.0 97.0 112.0 91.0 0.2 0.2 < 0.2 < 0.2 0.2 < 0.2 < 0.2 < 0.2 2.6 2.6 < 0.5 < 0.5 0.3 1.3 < 0.5 < 0.5 609.0 601.1 87.0 66.0 56.0 62.0 96.0 61.0 3.2 3.2 2.0 2.0 1.0 2.0 2.0 2.0 1530.0 1522.3 98.0 101.0 95.0 104.0 107.0 100.0 0.1 0.1 0.0 0.0 0.0 0.0 0.0 < 0.01 14600.0 14091.0 13700.0 9059.0 9780.0 9195.0 6625.0 9899.0 1.1 1.1 0.5 0.6 0.6 1.6 1.3 1.0 23.3 23.3 17.0 18.0 16.0 17.0 21.0 18.0 18.0 17.0 10.1 12.1 9.0 9.7 13.0 9.7 1.0 1.0 <0.1 <0.1 <0.1 <0.1 <0.1 0.4 1.0 0.0 1.0 1.0 1.0 1.0 1.0 1.0 8.6 1.8 8.0 7.9 7.9 7.7 7.8 8.1 4. 4 ---- fg7 - M - U 29900.0 Sodium I Phosphorus Silicon Strontium Zinc nde Solids 0 45 u mg /I 11700 0.9 23.3 15.3 0.1 92 14600 0.1 2.3 1.9 <0.1 32 10470 0.6 22 16.4 < 0.1 10330 1.1 21 15.9 < 0.1 10400 0.3 21 16.2 < 0.1 11280 0.6 21 16.8 < 0.1 109 11670 0.6 23 18 < 0.1 153 9560 0.3 20 15.6 < 0.1 80 9696 0.3 21 15.4 < 0.1 10400 0.2 19 13 < 0.1 509 0 0 1 0 13960 0.1 1 10.2 1 Sodium I Phosphorus Phosphorusl Silicon I Strontium i Zinc nde Solids 045 u mg /I 9560 0.1 2.3 1.9 0.1 32 14600 1.1 23.3 18 0.1 153 5040 1 21 16.1 0 121 509 0 0 1 0 0 13960 0.1 1 10.2 1 0 13451 0.1 1 9.2 1 0 Sodium rn /I osphorus ml Silicon m /l Otrontium mgj Zinc m /I Total Dissolved Solids 13700 0.5 17 10.1 < 0.1 9059 0.6 18 12.1 < 0.1 30096 9780 0.6 16 9 <0.1 9195 1.6 17 9.7 < 0.1 6625 1.3 21 13 < 0.1 9899 1 18 9.7 0.4 33700 9890 1.7 17 < 1 < 0.1 8044 1 18 9 < 0.1 9264 1.1 18 11.1 < 0.1 9599 0.4 18 11.9 < 0.1 6625 0.4 16 9 0.4 30096 13700 1.7 21 13 0.4 33700 9505.5 0.98 17.8 10.6222222 0.4 CPF -2 PW Average (mg /L) 1581.0 1880.0 1991.0 1929.0 1515.0 1991.0 1672.0 0.01 0.0 0.0 0.0 0.0 0.0 0.0 14700.0 13110.0 14590.0 13980.0 12050.0 14700.0 13897.0 59.0 53.0 49.0 47.0 34.0 69.0 49.6 7.2 12.0 6.7 5.9 16.0 9.6 < 0.1 < 0.1 < 0.1 < 0.1 0.0 0.0 0.0 15.5 16.6 16.1 14.7 14.7 19.6 16.4 42.0 34.0 22.0 28.0 22.0 43.0 33.9 99.9 109.0 111.0 105.0 91.0 135.0 105.8 < 0.2 < 0.2 < 0.2 < 0.2 0.2 0.2 0.2 < 0.5 < 0.5 5.5 < 0.5 0.3 5.5 2.4 62.5 63.0 91.0 81.0 56.0 96.0 72.6 < 0.5 1.0 2.0 2.0 1.0 2.0 1.8 101.0 78.0 103.0 102.0 78.0 107.0 98.9 < 0.001 0.0 0.0 0.0 0.0 0.0 0.0 9890.0 8044.0 9264.0 9599.0 6625.0 13700.0 9505.5 1.7 1.0 1.1 0.4 0.4 1.7 1.0 17.0 18.0 18.0 18.0 16.0 21.0 17.8 < 1 9.0 11.1 11.9 9.0 13.0 10.6 < 0.1 < 0.1 < 0.1 < 0.1 0.4 0.4 0.4 1.0 1.0 1.0 1.0 1.0 1.0 1.0 7.9 8.0 7.9 7.7 7.7 8.1 7.9 3230 0.01 34400.01 33800.01 29300.01 35200.0 31380.0 SAMPLE NUM 6298863 6298864 AB71202 AB71201 AB71200 Date 10/3/2010 10/3/2010 7/4/2010 7/4/2010 7/4/2010 Time 22:33 22:27 4:00 4:00 4:00 Inlet Separator Flash Inlet Separator Previous 10 Samples Separator Water Drum Separator Water Bicarbonate 1230 1140 1225 1223 1136 Carbonate 0 95 0 01 109 Chloride 15050 14620 15260 14960 14400 Sulfate 250 250 172 172 180 Sulfide Aluminum <0.1 <0.1 < 0.1 < 0.1 < 0.1 Boron 28.6 3.4 28 28 28 Barium 4.3 <1.0 8 3 13 Calcium 148.9 21.5 138 138 147 Chromium <0.2 <0.2 < 0.2 < 0.2 < 0.2 Iron 1.3 1.1 0.9 1.3 2.6 Potassium 67.6 7.9 55 58 56 Lithium 3.2 <0.5 2 2 2 Magnesium 62.1 7.7 57 57 58 Manganese 0.027 0.009 0.033 0.029 0.037 Sodium 11700 14600 10470 10330 10400 Phosphorus 0.9 0.1 0.6 1.1 0.3 Silicon 23.3 2.3 22 21 21 Strontium 15.3 1.9 16.4 15.9 16.2 Zinc 0.1 <0.1 < 0.1 < 0.1 < 0.1 Specific Gravity 60 °F) 1.0179 1.0201 1.0204 1.0206 1.0188 H 7.48 8.37 7.81 7.76 8.59 on uctivity - mhos /cm 40100 40100 40100 AB68013 AB68012 AB64673 AB64672 AB61378 4/4/2010 4/4/2010 115/2010 1/5/2010 #� 2:50 2:30 3:00 2:50 15:00 Colville River Field PW CPF -2 PW Separator Inlet Separator Inlet Flash Minimum Maximum Difference Average Water Separator Water Separator Drum (mg/L) (mg/l.) (mg/L) (mg/E) 1108 1253 1178 1280 1403 1108 1403 295 1672 97 0 185 0 0 0.0 185.0 185.0 0.001 14790 15180 15500 15600 15310 14400 15600 1200 13897 205 228 280 290 219 172 290 118 49,6 9.56 0.1 < 0.1 < 0.1 < 0.1 < 0.1 0.0 0.1 01 0.001 28.3 30.4 27.1 28.4 27 3.41 30,4 27.0 16.35 11 2 5 4 67 2.0 67.0 65.0 33.9 185 192 121 132 133 21.5 192 170.5 105.79 < 0.2 < 0.2 < 0.2 < 0.2 < 0.2 0 0 0.0 0.2 2.4 2.5 0.6 1.8 0.9 0.6 2.6 2.0 2.4 104 143 54 65 68 7.9 143 135.1 72.55 2 2 2 2 2 2.0 3.2 1.2 1.8 82 83 52 57 58 7.7 83 75.3 98.9 0.051 0.051 0.032 0.036 0.03 0.009 0.051 0.042 0.02 11280 11670 9560 9696 10400 9560 14600 5040 9505.5 0.6 0.6 0.3 0.3 0.2 0.1 1.1 1.0 0.98 21 23 20 21 19 2.3 23.3 21 17.8 16.8 18 15.6 15.4 13 1.9 18 16.1 10.62 < 0.1 < 0.1 < 0.1 < 0.1 < 0.1 0.1 01 0.0 0.4 1.0201 1.0208 1.0201 1.0198 1.0207 1.0179 1.0208 0.0029 1.01898 8.43 7.63 8.59 7.58 7.6 7.48 8.59 1.11 7.884 34900 35700 28200 29800 30500 28200 40100 119001 31380 Roby, David S (DOA) From: Davies, Stephen F (DOA) Sent: Friday, November 05, 2010 11:00 AM To: Roby, David S (DOA); Maunder, Thomas E (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA) Subject: RE: Colville River Field & Kuparuk River Field Water Comparison I'm not an very familiar with scale formation, but the sulfate content differs (PW = 172 -290 vs seawater = 279 - 3580), carbonate content differs (PW avg. = 0 -185 vs seawater = — 0- 0.001), and bicarbonate differs (PW = 1108 -1403 vs seawater = 100 -140), as does the pH (pw = 7.5 — 8.6 vs seawater = 6.75 -7.0). However, the amount of water proposed to be injected is insignificant compared with the volume of fluid injected into the Alpine Pool alone on a regular basis (3,163,281 bbls in Sept 2010), so I think that any formation damage would be minimal. From: Roby, David S (DOA) Sent: Friday, November 05, 2010 10:32 AM To: Maunder, Thomas E (DOA); Davies, Stephen F (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA) Subject: FW: Colville River Field & Kuparuk River Field Water Comparison Guys, attached as a comparison of CRU and CPF -2 produced waters as well as seawater. After a quick glance they look pretty similar to me. What do you guys think? Dave Roby (907)793 -1232 From: Walker, Jack A [mailto: Jack .A.Walker @conocophillips.com] Sent: Friday, November 05, 2010 10:20 AM To: Roby, David S (DOA) Subject: Colville River Field & Kuparuk River Field Water Comparison Dave, Enclosed is the comparison we discussed on the phone. The two charts show the range of dissolved solids for Colville produced water and seawater plotted with the average value for Kuparuk CPF -2 produced water which is basis for our belief that the CPF -2 water is compatible with the Colville River Field formations. I'll follow up with more background regarding the request for authorization to inject Kuparuk River Field produced water into the Colville River Field Oil Pools. Jack Roby, David S (DOA) From: Roby, David S (DOA) Sent: Friday, November 05, 2010 11:04 AM To: Davies, Stephen F (DOA); Maunder, Thomas E (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA) Subject: RE: Colville River Field & Kuparuk River Field Water Comparison They are aware of the possibility for scale creation when seawater and produced water mix and were planning on adding scale inhibitors. Dave Roby (907)793 -1232 From: Davies, Stephen F (DOA) Sent: Friday, November 05, 2010 11:00 AM To: Roby, David S (DOA); Maunder, Thomas E (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA) Subject: RE: Colville River Field & Kuparuk River Field Water Comparison I'm not an very familiar with scale formation, but the sulfate content differs (PW = 172 -290 vs seawater = 279 - 3580), carbonate content differs (PW avg. = 0 -185 vs seawater = — 0- 0.001), and bicarbonate differs (PW = 1108 -1403 vs seawater = 100 -140), as does the pH (pw = 7.5 — 8.6 vs seawater = 6.75 -7.0). However, the amount of water proposed to be injected is insignificant compared with the volume of fluid injected into the Alpine Pool alone on a regular basis (3,163,281 bbls in Sept 2010), so I think that any formation damage would be minimal. From: Roby, David S (DOA) Sent: Friday, November 05, 2010 10:32 AM To: Maunder, Thomas E (DOA); Davies, Stephen F (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA) Subject: FW: Colville River Field & Kuparuk River Field Water Comparison Guys, attached as a comparison of CRU and CPF -2 produced waters as well as seawater. After a quick glance they look pretty similar to me. What do you guys think? Dave Roby (907)793 -1232 From: Walker, Jack A [mailto:Jack.A.Walker @conocophillips.com] Sent: Friday, November 05, 2010 10:20 AM To: Roby, David S (DOA) Subject: Colville River Field & Kuparuk River Field Water Comparison Dave, Enclosed is the comparison we discussed on the phone. The two charts show the range of dissolved solids for Colville produced water and seawater plotted with the average value for Kuparuk CPF -2 produced water which is basis for our belief that the CPF -2 water is compatible with the Colville River Field formations. I'll follow up with more background regarding the request for authorization to inject Kuparuk River Field produced water into the Colville River Field Oil Pools. Jack 1 Roby, David S (DOA) From: Walker, Jack A [ Jack .A.Walker @conocophillips.com] Sent: Friday, November 05, 2010 12:28 PM To: Roby, David S (DOA) Subject: CRU Seawater P/L Follow Up Dave, To follow up the compositional analyses data for seawater, Colville River Field produced water, and Kuparuk produced water that I sent to you earlier for your consideration, this email describes our situation and reasons for requesting authorization to inject produced water from the Kuparuk River Field in the Alpine, Fiord, Nanuq and Qannik Oil Pools. Seawater from the Kuparuk River Unit Seawater Treatment Plant is normally supplied to the Colville River Field for enhanced oil recovery via a pipeline approximately 34.6 miles long. There was an unplanned shutdown of the seawater pipeline, and freeze protection was subsequently implemented by pumping warm Kuparuk River Field produced water into the pipeline to displace the cold seawater. This freeze protection will be good for a period, and within this period we expect resumption of normal seawater operations. When normal seawater operations are possible, the seawater will displace the Kuparuk produced water used for freeze protection toward the Alpine Central Facility. Two operational options exist for routing the freeze protection fluid at the Alpine Central Facility: (1) inject it into properly permitted Class I disposal wells, or (2) if AOGCC authorizes, inject it into WAG service wells in the Alpine, Fiord, Nanuq, and Qannik Oil Pools. Option (1) is feasible, but this operation will require significantly more time than Option (2) due to the disposal well system capacity. Option (1) has a minor risk of freezing the seawater pipeline due to the time required for the seawater to displace the freeze protect fluid. Option 2 is recommended because the Kuparuk produced water freeze protect fluid is compatible p O p p ( p ) p with the Colville River Field formations, because the freeze protect fluid can be beneficially used for enhance oil recovery, and because this displacement operation will require about one tenth of the time required for Option (1) resulting in less risk of freezing the seawater pipeline during the displacement of the freeze protect fluid. We expect normal seawater to be available as early as 6 p.m. tonight. Thank you for the time you have put into this. Jack Walker North Slope Development ConocoPhillips Alaska, Inc. 907 -265 -6268 office 907- 250 -1749 cell 1 ~~ Conoco hiliips Alaska, Inc. December 10, 2008 Commissioner Dan Seamount, Chairman Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Chris Wilson Supervisor, WNS Base North Slope Operations and Development, ATO 1762 700 G. ST. ANCHORAGE, ALASKA 99501 Telephone 907- 265-6573 E-mail Christopher.j.wilson@conocophillips.com RE: Request to Include Kuparuk Formation in the Alpine Pool and Expand the Alpine Pool Colville River Unit Area North Slope, Alaska Dear Commissioner Seamount, ConocoPhillips, Inc. as Unit Operator on behalf of the working interest owners of the Colville River Unit ("CPAI") respectfully requests that the Alaska Oil & Gas Conservation Commission ("Commission") approve administrative amendments to Conservation Order C0443A and Area Injection Order 18B to allow for the expansion of the Alpine Oil Pool ("AOP") and Alpine Area Injection Order ("AIO") to include the Kuparuk formation and new prospective lands in anticipation of future development for oil production. The proposed AOP, as described in subsequent paragraphs, overlaps the Kuparuk formation with the Nanuq Kuparuk oil pool. Therefore CPAI requests that the Commission amend the AOP to include the Nanuq Kuparuk oil pool and terminate the Nanuq Kuparuk Conservation Order No. 563 and Nanuq Kuparuk Area Injection Order No. 27, so as not to have two sets of rules for the same stratigraphic unit. CPAI requests the AOP and AIO modifications for two reasons: 1) seismic, drilling, well log, pressure, and production data indicate that the Kuparuk and Alpine intervals are in pressure communication at the Char No. 1 exploration well, CD1, and CD-4 areas, and 2) the AOP drilling program for the winter 2009 season and in the future is anticipated to expand the pool beyond the current AOP area. These reasons are discussed below. Technical Background Pressure communication within proposed AOP. Drilling, well log, pressure, and production log data indicate that the Kuparuk and Alpine intervals are in pressure communication. ConocoPhillips recently completed two wells in the Kuparuk sandstone (which lies stratigraphically above the Alpine sandstone) for production in the CD1 area and found elevated pressures of 4500-4600 psi in the Kuparuk formation, whereas 3200 psi is considered "normal" pressure. In addition, elevated pressures in the Kuparuk formation were found last winter in the Char No. 1 exploration well. Third, subtle pressure changes, indicating possible pressure communication in the CD-4 Kuparuk area, have been observed over the last two years with the commencement of testing and production out of the Nanuq Kuparuk oil pool. • • In the Alpine CD1 area, significant lost circulation encountered while drilling the Alpine C sand in the CD1-06 and CD1-14 wells resulted from natural fractures/faults associated with a nearby fault to the east. Water and gas injection in the Alpine C in the CD1-06 and CD1-14 wells is interpreted to have pressured up the overlying Kuparuk sand via natural fractures/faults at or near these injection wells (Attachment 1). However, there were no lost circulation or pressure "kick" incidences while drilling through the shallower Torok and K-2 sand intervals, implying that faults/fractures in the proposed expanded Alpine pool do not extend into overlying shallower sands. Furthermore, seismic in the CD1 area shows that the seismically-resolvable regional faults in the area are difficult to interpret through the Kuparuk formation, and do not propagate into the HRZ (Attachment 2). Additionally, even though CPAI has injected large volumes of gas in the Alpine C at CD1 since 2001, no wells drilled subsequently have encountered over pressure in zones above the Kuparuk. Pressure communication in the CD2/Char No. 1 well area is likely the result of the Alpine A/Kuparuk C sand-on-sand contact as observed in the "toe up" of the CD2-02 Alpine A injection well at TD. Additionally, there are no seismically-mappable faults in the area (Attachment 3). Normally pressured Kuparuk was measured in the Kuparuk in the Char No. 1 well area by the Iapetus #2, drilled in 2005. CD2-02 did not begin injection until months after Iapetus # 2 was drilled in 2005. Pressure communication outside of proposed AOP. There is no evidence of pressure communication between the existing AOP and the Nanuq-Kuparuk Oil Pool with shallower zones. Pressure monitoring of wells completed in the Nanuq turbidite (Torok Formation) in the Nanuq Oil Pool showed no evidence of pressure communication with the Alpine or Kuparuk Sands. Pressure measurements of wells completed in the Qannik Oil Pool in the Nanushuk Group also show no evidence of pressure communication with the Alpine or Kuparuk Sands. There is minimal in-situ measured data below the Alpine; however, those data available suggest that the Nuiqsut sand in the CD1 area is extremely tight. Alpine AIO 18B indicates that the Alpine sandstone is underlain by a think shale interval assigned to the upper Kingak Formation. Petrophysical analysis indicates the parting pressure of these shales is 700 to 800 psi greater than the Alpine sandstone. Therefore it is expected that fracture growth initiated by injection into the Alpine Sands will be arrested in the shales immediately below the Alpine Sands. Pressure monitoring. The properties and thickness of the rocks underlying and overlying the proposed expanded pool render it unlikely that natural or induced fracturing/faulting would cause fluids to move out of the expanded pool. Additionally, casing pressures will continue to be monitored for all wells and available to the Commission. If out of zone injection occurs, it may lead to sustained casing pressure particularly in the outer annuli of the injection well with out of zone injection, or in offset wells. Consequently, sustained casing pressures exceeding 2000 psi for inner annuli and 1000 psi for the outer annuli will be reported to the Commission in accordance with the Commission's orders. Injection volumes will continue to be monitored by continuous metering at each injection well. Producing wells will be tested at least twice per month to monitor reservoir withdrawal. Injection rates will be set on the basis of voidage ratio accounting for reservoir withdrawal and injection to maintain reservoir pressure near original. Reservoir pressures will be monitored and reported per Rule 6 of the Alpine Pool Rules (CO 443A), including a minimum of six bottom-hole pressure surveys annually. Voidage management coupled with reservoir pressure monitoring will indicate whether out of zone injection is occurring. In addition, initial pressures will be measured in all future wells, and pressures will also be measured in the existing completions as needed to effectively manage hydrocarbon recovery processes. Within the proposed AOP Area, there are presently 11 wells completed in the Kuparuk C Sand, 106 wells completed in the Alpine Sands, and no wells completed in both Kuparuk and Alpine Sands. • ~ Proposal for Expanded Alpine Oil Pool AOP Expanded stratigraphic Definition. The AOP is currently defined as the accumulation of hydrocarbons common to, and correlating with, the interval between the measured depths ("MD") of 6,876 feet and 6,976 feet as seen in the Bergschrund No.1 Well (Attachment 4A). CPAI proposes amending the AOP to be defined as the accumulation of hydrocarbons common to, and correlating with, the interval between the measured depths ("MD") of 6,980 feet and 7,276 feet in the Alpine No. 1 Well (API # 50-1 03-2021 1-00) (Attachment 4B). The proposed AOP interval includes the Alpine A, Alpine C, Kuparuk C, and Kuparuk D intervals. The Alpine No.1 well log is proposed as the type log in lieu of the Bergschrund No. 1 Well because the Alpine A sand is truncated (not present) in the Bergschrund No. 1 well but is present in the Alpine No. 1 well. Additionally, the Alpine No. 1 well has 5 feet of Kuparuk C sand represented in the log data whereas Bergschrund No. 1 well only has 2 feet of Kuparuk C, consequently it is difficult to determine representative logging tool response for the Kuparuk C sand with the Bergschrund No. 1 well log data due to logging tool resolution limitations and limited number of data points collected in the sandy interval. Additional Lands. The current AOP and Nanuq Kuparuk oil pool overlap aerially to a significant extent. In addition, wells planned to be drilled in the near future are planned to be located outside of the current AOP in the southwest corner (Attachment 5). The proposed AOP revision (Attachment 5) is intended to include both of the current Alpine and Nanuq Kuparuk oil pools, near-term future drilling locations, plus lands which CPAI and Anadarko Petroleum Company ("Anadarko") ultimately intend to develop. The proposed AOP, when expanded vertically as described above, also overlaps in the Kuparuk formation with the Nanuq Kuparuk oil pool. CPAI requests that the Commission amend the AOP to include the Nanuq Kuparuk oil pool. Alpine Conservation Order ("CO') and AIO Modifications. In addition CPAI requests that CO 443A be expanded to cover the revised AOP (see map and land description, Attachment 6) and be defined as encompassing the lands listed in Attachment 6. The rules stated in CO443A and AIO 18B would then also apply to the revised AOP lands and stratigraphic units. CPAI requests that the Commission terminate the Nanuq Kuparuk Conservation Order No. 563 and Nanuq Kuparuk Area Injection Order No. 27, so as not to have two sets of rules for the same stratigraphic unit. To include the current Nanuq Kuparuk oil pool under Alpine CO 443A and Alpine AIO 18B as proposed requires consideration to insure that Alpine CO and AIO rules are appropriate for Nanuq Kuparuk. A comparison of the Alpine and the Nanuq-Kuparuk conservation orders found the orders to be similar. CPAI believes that the existing Alpine pool rules with proposed changes (Attachment 7) will be appropriate to apply to the Nanuq Kuparuk and requests that the AOGCC approve the changes as shown in Attachment 7. It should be noted that by adopting the Alpine AIO 18B for the revised AOP, which would include the Nanuq Kuparuk, the more restrictive Rule 4 from AIO 27 currently in place for the Nanuq Kuparuk would no longer apply to the Nanuq Kuparuk. CPAI does not believe that Rule 4 of AIO 27 is necessary any longer based upon information gained since the AIO 27 was issued. Rule 4 of AIO 27 provides as follows: "Rule 4 Authorized Fluids for Enhanced Recovery Fluids authorized for injection are: a. source water from a sea water treatment plant; b. miscible gas obtained from the Alpine Central Facility with the condition that the reservoir pressure must be maintained to ensure the miscibility of the injectant; • • c. tracer survey liquid to monitor reservoir performance; and d. small amounts of other non-hazardous liquids: sump liquid, hydrotest liquid, rinsate from washing mud hauling trucks, excess well work liquids, and treated camp waste water. Prior to injection of any liquid other than seawater or any mixture of liquids, compatibility with the Nanuq-Kuparuk reservoir must be demonstrated and administrative approval to inject must be obtained from the Commission. Sampling, analysis and reporting protocols shall conform to those listed in AIO 186.002." Not including AIO 27 Rule 4 in the revised AIO 186 would allow CPAI to inject other fluids (including Colville River Unit produced water) in addition to the sea water, miscible gas, tracers, and miscellaneous liquids listed in the existing Nanuq Kuparuk AIO 27 Rule 4, above. The primary alternative fluid not listed in existing AIO 27 at Rule 4, but in use at the AOP, is Colville River Unit produced water. In support of this request to not restrict fluids allowed for injection under the proposed revised AIO 186, CPAI notes that the Kuparuk formation in the Nanuq Kuparuk oil pool is mineralogically similar to the Kuparuk composition in the Fiord oil pool; the main difference is the increased presence of siderite at Fiord (Attachment 8). CPAI has been injecting produced water into the Kuparuk formation in Fiord oil pool in accordance with AIO No. 30 and Administrative Approval No. AIO 30.002 without evidence of formation damage. Furthermore, there CPAI currently injects produced water into the Kuparuk (at Fiord), Alpine, Nechelik, and Qannik formations in the Colville River Unit, and has never seen any evidence of produced water incompatibility with these clastic rocks. Formation damage studies with core from the Qannik and Fiord pools have reinforced observations in the field that the formation is unlikely to be damaged from injection of produced water. Therefore CPAI concludes that all injected fluids allowable in Alpine AIO 186 are compatible with the Kuparuk and Alpine injection zones. CPAI believes the requested amendment approvals are based on sound engineering and geoscence principles, will increase ultimate field recovery, will not promote waste or jeopardize correlative rights, and will not result in an increased risk of fluid movement into freshwater. Please do not hesitate to contact me at (907) 265-6822 should you have any questions about this request. Sincerely, ris Wilson Supervisor, WNS Base • • Attachment 1: Top Alpine C structure and lost circulation incidences • • Attachment 2: Seismic E-W transect near CD-1 with mappable faults Stack W-E Transect CD1-14PB1 Attribute Extraction W-E CD1-14PB1 .. .:u+~r ~ ~: • • Attachment 3: CD2-02 to Char #1 well seismic transect Attachment 4A: Current AOP type log - Bergschrund 1 well ~~ BERGSCF~RUND 1 TYPE LOG 111 INE Attachment 4B: Proposed AOP type log -Alpine 1 well Alpine 1 • • ~~ Black line -Colville River Unit boundary Blue -Alpine oil pool boundary & wells Green - Nanuq Kuparuk oil pool boundary & wells Red -Planned well locations (2009-2012) Attachment 5: Colville River Unit -Current Alpine and Fiord Kuparuk oil pool map with CD1, CD2, and CD4 well locations • • Attachment 6: Land map and description of proposed Alpine Oil Pool expansion a 1 WLES .. 0. ;. CPN t o `', 1 's glO~iERS AYG1i n'. r:G .. ~a1 ¢~ ~/ ~y r .. Zvv .J 13 ]u .. 2.: ~ t , .. ..... (riPAl AFG ~~. - , 30 ` X11 ' <'- 3, APC CPN,h ~~0, .. N P .~... -- ~ .~ .r. ~~ .. .~.8 ~ ~ ~~~~~~,, AFC fPN APC. CPN PPC. CPN ! }A' !P,;:CPN N'C. CPN N'C. (.'PPI il: 7 APC.C 1a. ~z~ z: 2 '~` ~~• a v ~ ~ , ~- \ Y ~~ 33 i 34 3 .t[: 3' ~,bC, CPA4 ., _ APC,CP~ - ~,~ ~~~ ~! i it 1 1 : ~ a. ,- zs ', .. 3q ~ ' ,CP ~, 3+ RVCC ar ~a Awc FSIW A{lF~. (3 AOR D AW G P'rCG _ .it~lV J."iI'OF'.4 MNSYgP! 1G KO{40 iG WCA~I AVCP. Pvf.. 3< ~ ~ Pool Rules Areas APC ~PA~ ~ H~ Colville River Unit < - Few ~ A. 5-29-08 080a1901Pg1 • • Proposed AOP land description: UMIAT MERIDIAN Township /Range T10N, R5E Sections: 3, 4, 5, 6 T11 N, 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, 27, 28, 29, 30, 31, 32, 33, 34 T12N, R5E Sections: 13, 14, 15, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36 T10N, R4E Sections: 1, 2, 3, 4, 5, 6, T11 N, R4E 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, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36 T12N, R4E Sections: 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36 T10N, R3E Sections: 1 T11 N, R3E Sections: 1, 2, 11, 12, 13, 14, 23, 24, 25, 26, 36 T12N, R3E Sections: 25, 26, 35, 36 • • Attachment 7: Proposed Conservation Order and Area Injection Order Changes Conservation Order 443A Proposed Changes CO 443A Rule 2 (Pool Definition) Current: "The AOP is defined as the accumulation of hydrocarbons common to and correlating with the interval between the measured depths of 6,876 feet and 6,976 feet in the Bergschrund No. 1 well." Proposed: "The AOP is defined as the accumulation of hydrocarbons common to and correlating with the interval between the measured depths of 6980 feet and 7276 feet in the Alpine No. 1 well." CO443A Rule 3 (Well Spacing) Current: "Development wells may not be completed within 500 lineal feet of another AOP development well nor closer than 500 feet from the exterior boundary of the affected area." Proposed: "Development wells may not be completed closer than 500 feet to an external property line where lease interest ownership or fee land ownership changes." Area injection Order 18B Proposed Changes AIO 188 Rule 1 (Authorized Injection Strata for Enhanced Recovery) Current: "Within the affected area, fluids may be injected for purposes of pressure maintenance and enhanced recovery 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." Proposed: "Within the affected area, fluids may be injected for purposes of pressure maintenance and enhanced recovery into strata that are common to and correlate with the interval between the measured depths of 6980 and 7276 feet in the Alpine No. 1 Well." • • Attachment 8: Thin section point count data from Fiord #1 and Nanuq #1 wells. Kuparuk zone petrophysical summary Well Fiord #1 Fiord #1 Fiord #1 Fiord #1 Depth (core or log) 6907.53 6909 6909.8 6910.8 Nanuk #1 Nanuk #1 6975.0 6977.0 QUARTZ 56.7 51.0 50.0 52.7 56.3 63.9 FELDSPAR 0.0 0.0 0.0 0.0 0.3 0.7 CHERT 3.3 2.0 0.3 2.3 3.7 1.7 SRF 1.0 0.3 0.0 0.0 1.0 1.3 MRF 0.0 0.0 0.0 0.0 0.0 0.0 VRF 0.0 0.0 0.0 0.0 0.0 0.0 PRF 0.0 0.0 0.0 0.0 0.0 0.0 MICA 0.0 0.0 0.0 0.0 0.0 0.0 GLAUC 3.0 1.7 2.7 2.7 1.3 2.0 HVY MINERL 0.0 0.0 0.0 0.0 0.0 0.0 OTHER FRMWK 3.7 3.7 2.0 1.3 0.3 0.3 CLAY 11.0 6.3 6.0 18.3 6.3 6.0 SILICA CMT 0.0 0.0 0.7 0.0 2.0 1.0 FELD CMT 0.0 0.0 0.0 0.0 0.0 0.0 CARB CMT 4.3 34.0 34.0 19.7 6.0 0.0 OTHER CMT 0.0 0.0 0.0 0.0 0.0 0.0 TS_PORO 17.0 1.0 4.3 3.0 22.7 23.2 TOTAL 100.0 100.0 100.0 100.0 100.0 100.0