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Home My WebLink AboutAIO 032INDEX AREA INJECTION ORDER NO. 32 Redoubt Unit Redoubt Shoal Undefined Oil Pool 1. July 30, 2007 Forest Oil Corporation's AIO application 2. August 8, 2007 Commissioner Seamount Recusal from Decision 3. August 9, 2007 Notice of Public Hearing, Affidavit of Publication, email distribution, mailings 4. August 22, 2007 Follow-up questions to the applicant 5. September 12, 2007 Email re: Hearing 6. September 14, 2007 Follow-up questions to the applicant 7 - --------------------- Copies of administrative approvals extending ERIO No. 2 8. October 25, 2007 Email re: Order Status 9. March 9, 2009 Pacific Energy Resources, Ltd.'s Filing of Chapter l I Restructuring 10. March 9, 2015 — March 18, 2015 Emails between Cook Inlet Energy, LLC and AOGCC re: RU -6 Boiler Blowdown 11. December 18, 2017 CIE's Redoubt Unit 3A application (AIO 32.001) 12. ---------------------- CIE Monthly Reporting AIO 32.001 ---------------- 13. February 10, 2020 CIE's Request to cancel AIO 32.001 application (aio32.001 cancel) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: THE APPLICATION OF FOREST OIL CORPORATION for an order authorizing the underground injection of fluids for enhanced oil recovery in the Hemlock Formation, Redoubt Shoal Undefined Oil Pool, Redoubt Unit, Cook Inlet, Alaska IT APPEARING THAT: Area Injection Order No. 32 Redoubt Unit Redoubt Shoal Undefined Oil Pool January 30, 2008 1. By application dated and received by the Alaska Oil and Gas Conservation Commission ("Commission") on July 30, 2007, Forest Oil Corporation ("Forest"), operator of the Redoubt Unit ("RU") requested a Commission order authorizing, under 20 AAC 25.402, the underground injection of fluids for enhanced oil recovery ("EOR") in the Hemlock Formation ("Hemlock") of the Redoubt Shoal Undefined Oil Pool. 2. The Commission published notice of the opportunity for a public hearing in the Anchorage Daily News on August 8, 2007 and in the Peninsula Clarion on August 9, 2007. 3. On August 8, 2007, Commissioner Daniel T. Seamount, Jr. recused himself from this case. 4. By emails dated August 6 and 7, 2007, and September 12, 2007, the Commission requested additional information. Forest responded on August 22, 2007, and September 14, 2007. 5. No comments, protests or requests for a public hearing were received. FINDINGS 1. Operator Forest operates the Redoubt Shoal Undefined Oil Pool in the RU, Cook Inlet, Alaska. Area Injection Order 32 • January 30, 2008 isPage 2 2. Project Area and Proposed Enhanced Recovery Injection Interval Enhanced recovery injection is proposed for the Redoubt Shoal Undefined Oil Pool. This pool is compartmentalized by faulting into three fault blocks: the Northern, Central and Southern fault blocks. The Central and Southern fault blocks contain the majority of reserves in the pool. In the Central fault block, the injection zone is correlative with the interval from 14,140' to 14,945' measured depth ("MD") in the RU #1 well. In the Southern fault block, the injection zone is correlative with the interval from 14,365' to 15,222' MD in the RU #2 well. 3. Proposed Injection Area Forest has requested authorization to inject fluids for the purpose of enhanced recovery operations on RU land within T07N R13W and T07N R14W, Seward Meridian. Most of the wells affected by the proposed injection activities were drilled from the Osprey Platform, which is located approximately 1.5 miles southeast of West Foreland, offshore Cook Inlet. However, there are also four exploratory wells within the proposed injection area that, between 1967 and 1976, were drilled and then plugged and abandoned. 4. Operators/Surface Owners Notification Forest is the only operator and the State of Alaska is the only surface owner within one-quarter of a mile of the proposed injection area. Forest provided the State a copy of the application for enhanced oil recovery injection. 5. Description of Operation Injection will occur within the Hemlock Formation ("Hemlock"). The Redoubt Shoal Undefined Oil Pool is being developed under statewide regulations. It has not yet been defined in vertical or regional space. There are three active wells in the Central fault block. There is no production from the Southern fault block. Pilot waterflood enhanced recovery operations conducted in the Central fault block were authorized by Enhanced Recovery Injection Order No. 2 in August 2004. During those pilot operations, from March 2005 through September 2007, Forest utilized the RU 46 well to inject 1.3 million barrels of authorized fluids into the Hemlock and recovered 652,000 barrels of oil. The operator plans to progressively expand development within the RU, using new and re -drilled wells from the Osprey platform. However, development options will ultimately be determined by field performance and economic factors. To facilitate reservoir management and field development, surveillance data will be collected on an ongoing basis through static bottom -hole pressure surveys, production logging, injection logging and production well testing. 6. Hydrocarbon Recovery The estimated original oil in place ("OOIP") for the RU is 54 million barrels of oil ("MMBO"): 30 MMBO in the Central fault block and 24 MMBO in the Area Injection Order 32 • January 30, 2008 0 Page 3 Southern fault block. Primary recovery from the Hemlock within the RU is expected to be 6% of the OOIP. Results of the pilot project suggest that waterflood operations will increase recovery by an additional 5% to 7% of the OOIP. 7. Geologic Information The Hemlock reservoir within the RU resulted from fluvial deposition in meandering, coalescing stream channels. It consists of interbedded fine-grained to medium -grained sand, gravels, pebble conglomerates, dense silts and scattered thin coal beds. Conventional core analysis indicates that there are at least six lithofacies within the Hemlock. The Redoubt Shoal Undefined Oil Pool accumulated in a northeast -trending anticline that is bound to the west by east -dipping reverse faults. The anticline is transected by several southeast -trending, normal faults. Core data and well logs were used to estimate rock properties. Porosity is intergranular with well -cemented and competent rock. Clay volume ranges from 9% to 20% of rock volume and appears to be dispersed. Reservoir facies consist of pebble conglomerate (porosity 7% to 13%), pebble -gravel sandstone (porosity 10% to 16%), medium -grained to coarse-grained sandstone (porosity 10% to 16%) and fine-grained sandstone (porosity 12% to 14%). Permeability ranges from 0.1 millidarcy to several hundred millidarcies. The oil from the Hemlock at RU has a gravity of approximately 26.5° API, a gas - oil ratio of 250 standard cubic feet per stock tank barrel, and a bubble point pressure of 1,490 pounds per square inch absolute ("psia"). Upper confinement will result from an interval of tuffaceous siltstone and coal that lies at the top of the Hemlock. This interval is laterally continuous and ranges in thickness from 40' to 80'. Lower confinement will result from a series of laterally continuous, tuffaceous siltstone and claystone layers that lie at and near the base of the Hemlock. The aggregate thickness of these layers ranges from 40' to 50'. 8. Well Logs The RU well logs are on file with the Commission. 9. Mechanical Integrity and Well Design of Injection Wells The only injection well being used for EOR is RU #6, which has been injecting since March 2005 in accordance with Enhanced Recovery Injection Order 2 ("ERIO 2"). This well was converted from a producer to an injector in accordance with Commission regulations. There is no indication of any mechanical integrity issues with this well. Additional injection wells will be new or re -drilled wells. Area Injection Order 32 January 30, 2008 0 Page 4 10. Type of Fluid / Source Fluids requested for injection are the following: a. produced Hemlock RU water; b. treated sanitary waste; c. treated gray water from platform and camp living facilities; d. produced Hemlock water from the West McArthur River Oil Pool; e. storm water from secondary containment areas at the Kustatan Production Facility and the West McArthur River Production Facility; f. deck drainage from the Osprey Platform; and g. produced water from the gas wells in the West Foreland field. 11. Water Compatibility with Formation Injection performance data was collected during the pilot project authorized by ERIO 2. The compatibility information provided in conjunction with the ERIO 2 pilot project is incorporated by reference in this order. 12. Injection Rates and Pressures, Fracture Information Injection rates for the pilot injection project using the RU #6 well range from 700 barrels of water per day to 2,400 barrels of water per day. Injection rates will increase as more production is brought online and more injection wells are added. Injection pressure typically runs between 3,000 psi and 4,600 psi and is limited to 5,000 psi by the pump at the Kustatan Production Facility. The injection rate and pressure history for the RU #6 well indicate that injection is occurring below the fracture pressure of the Hemlock and, more importantly, the confining intervals. 13. Freshwater Exemption Six Hemlock water samples, from 4 wells, were collected and analyzed. The samples were collected from the RU #2, RU #5A, RU #6, and RU #7 wells. Total dissolved solids averaged 11,060 mg/l, with a range of 8,250 mg/1 to 15,800 mg/l. 14. Mechanical Condition of Adjacent Wells The mechanical integrity of each well in the Central fault block was analyzed. These analyses and the review of data gathered associated with ERIO 2 indicate that the mechanical integrity of these wells is acceptable. Injection performance data gathered during the operations authorized under ERIO 2 indicate no well mechanical integrity problems. There are two wells in the Southern fault block, both of which are shut in, and there is no indication of mechanical integrity issues with either well. The Southern fault block wells must be worked -over or side- tracked or new wells must be drilled to begin production and enhanced recovery operations in this fault block. In addition to the above active or shut in wells, five wells (three in the Central fault block, one in the Southern fault block, and one in the Northern fault block, which is outside the proposed project area) penetrate the Hemlock. These wells have been plugged back and are no longer open to the Hemlock, and no integrity issues have been identified with respect to them. Area Injection Order 32 Page 5 January 30, 2008 CONCLUSIONS 1. The application requirements of 20 AAC 25.402 are met. 2. Water injection will significantly improve recovery. 3. There are no known sources of freshwater in the area proposed for the development of the Redoubt Shoal Undefined Oil Pool. Therefore, a freshwater aquifer exemption is not required. 4. The proposed injection operations will be conducted in permeable strata, which can accept injected fluids at pressures below the fracture pressures of the confining strata. 5. Injected fluids will be confined within the receiving interval by impermeable lithology, cement isolation of the wellbore and operating conditions. 6. Compatibility testing and actual injection performance data obtained during the pilot project authorized by ERIO 2 demonstrate that the proposed injection fluids are compatible with the Hemlock. 7. Reservoir and well surveillance, coupled with regularly scheduled mechanical integrity tests, will help ensure the proper performance of the enhanced oil recovery project and disclose possible abnormalities. 8. The proposed injection fluids are compatible with the native fluids and rock properties of the Hemlock. NOW, THEREFORE, IT IS ORDERED that: The underground injection of fluids for pressure maintenance and enhanced oil recovery is authorized in the Hemlock within the Affected Area, subject to the following rules and the requirements of 20 AAC 25 (to the extent not superseded by these rules). Affected Area: Seward Meridian Township/Range Section Portions T07N R13W 7 SW/4 of SW/4 17 SWA; SW/4 of NW/4; W/2 of SE/4; SEA of SEA 18 W/2; SEA; W/2 of NEA; SEA of NEA 19 All 20 W/2; NE/4; W/2 of SE/4; NE/4 of SE/4 21 W/2 of NW/4; NEA of NW/4 29 W/2 of NW/4; NEA of NW/4; NW/4 of SWA Area Injection Order 32 January 30; 2008 0 Page 6 Rule 1: Authorized Injection Strata for Enhanced Recovery Authorized fluids may be injected for purposes of pressure maintenance and enhanced recovery within the Redoubt Shoal Undefined Oil Pool into strata that are common to, and correlate with, the interval from 14,140' to 14,945' MD in the RU #1 well in the Central fault block and the interval from 14,365' to 15,222' MD in the RU #2 well in the Southern fault block. Rule 2: Fluid Injection Wells The underground injection of fluids must be through a well that has been permitted for drilling as a service well for injection 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 and 20 AAC 25.412 Rule 3: Authorized Fluids for Enhanced Recovery The following fluids are authorized for injection: a. produced Hemlock RU water; b. treated sanitary waste; C. treated gray water from platform and camp living facilities; d. produced Hemlock water from the West McArthur River Oil Pool; e. storm water from secondary containment areas at the Kustatan Production Facility and the West McArthur River Production Facility; f. deck drainage from the Osprey Platform; and g. produced water from the gas wells in the West Foreland field. Rule 4: Authorized Injection Pressure for Enhanced Recovery a. Injection pressures must be maintained so that injected fluids do not fracture or migrate into the confining strata. b. If injected fluids fracture or migrate into the confining strata, the operator must immediately shut in the injection wells. Injection may not be restarted unless approved by the Commission. 30 31 All NW/4; NW/4 of NE/4 T07N R14W 13 E/2 of NEA; E/2 of SE/4; SW/4 of SE/4 23 SE/4 of SE/4 24 E/2; SW/4; SEA of NW/4 25 All 26 E/2; SWA; SEA of NW/4 34 E/2 of NE/4; NE/4 of SE/4 35 N/2; SE/4; N/2 of SW/4 36 N/2; SW/4; N/2 of SE/4; SW/4 of SE/4 Rule 1: Authorized Injection Strata for Enhanced Recovery Authorized fluids may be injected for purposes of pressure maintenance and enhanced recovery within the Redoubt Shoal Undefined Oil Pool into strata that are common to, and correlate with, the interval from 14,140' to 14,945' MD in the RU #1 well in the Central fault block and the interval from 14,365' to 15,222' MD in the RU #2 well in the Southern fault block. Rule 2: Fluid Injection Wells The underground injection of fluids must be through a well that has been permitted for drilling as a service well for injection 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 and 20 AAC 25.412 Rule 3: Authorized Fluids for Enhanced Recovery The following fluids are authorized for injection: a. produced Hemlock RU water; b. treated sanitary waste; C. treated gray water from platform and camp living facilities; d. produced Hemlock water from the West McArthur River Oil Pool; e. storm water from secondary containment areas at the Kustatan Production Facility and the West McArthur River Production Facility; f. deck drainage from the Osprey Platform; and g. produced water from the gas wells in the West Foreland field. Rule 4: Authorized Injection Pressure for Enhanced Recovery a. Injection pressures must be maintained so that injected fluids do not fracture or migrate into the confining strata. b. If injected fluids fracture or migrate into the confining strata, the operator must immediately shut in the injection wells. Injection may not be restarted unless approved by the Commission. Area Injection Order 32 • January 30, 2008 Page 7 Rule 5: Monitoring Tubing -Casing Annulus Pressure The tubing and casing annuli pressures of each injection well must be monitored at least daily, except if prevented by an extreme weather condition, emergency situation, or similar unavoidable circumstance. The results shall be made available to the Commission upon request. Rule 6: Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, and before returning a well to service following a workover affecting mechanical integrity. A Commission -witnessed mechanical integrity test must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. The Commission must be notified at least 24 hours in advance of each mechanical integrity test to enable a Commission representative to witness the test. Unless an alternate means is approved by the Commission, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure equal to the maximum anticipated injection pressure that shows stabilizing pressure and does not change more than 10 percent during a 30 - minute period. The results of all mechanical integrity tests must be provided to the Commission. Rule 8: Well Integrity Failure and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by an injection rate, operating pressure observation, test, survey, log, or other evidence, the Operator shall notify the Commission by the next business day and submit a plan of corrective action (on Form 10-403) for Commission approval. The Operator shall immediately shut in the well if continued operation would be unsafe, would threaten contamination of freshwater, or if so directed by the Commission. Monthly reports 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 a lack of injection zone isolation. Every five years from the effective date of this order, the operator shall analyze the mechanical integrity of all potentially affected wells and provide a report to the Commission. Rule 9: Notification of Improper Class II Injection The injection of fluids other than those listed in Rule 3 without prior Commission authorization is improper Class II injection. Upon discovering any such event, the operator must immediately notify the Commission, provide details of the event, propose actions to prevent a recurrence, and take any other action required by the Commission. Compliance with the notification requirements of any other State or Federal agency remains the operator's responsibility. Rule 10: Plugging and Abandoning Fluid Injection Wells An injection well within the Affected Area must not be plugged and abandoned unless such action is approved by the Commission in accordance with 20 AAC 25. Area Injection Order 32 • January 30, 2008 0 Page 8 Rule 11: Other conditions It is a condition of this authorization that the operator complies with all applicable Commission regulations. The Commission may suspend, revoke, or modify this authorization if any Rule is violated or injected fluids fail or might fail to be confined within the designated injection strata. Rule 12: Administrative Actions Upon application or its own motion, the Commission may, without notice and public hearing (unless such are otherwise required), administratively waive the requirements of any Rule or administratively amend this Order 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 out of the designated injection strata or into freshwater. DONE at Anchorage, Alaska, and dated January 31, Chairman Oil and Gas Conservation Commission Cathy P. oerster, Commissioner Alaska it and Gas Conservation Commission AS 31.05.080 provides that, within 20 days after written notice of the entry of an order, a person affected by the order may file with the Commission an application for reconsideration. To be timely filed, the application must be received by 4:30 p.m. on the 23`d day following the date of the order, or the next working day if the 23`d day is a state holiday or weekend. The Commission shall grant or refuse the application in whole or in part within 10 days after it is filed. The Commission can refuse the application by not acting on it within the 10 -day period. A person who submitted an application for reconsideration has 30 days from the date the Commission refused the application or mailed (or otherwise distributed) an order on reconsideration, both being the final order of the Commission, to appeal the decision to Superior Court. Where an application for reconsideration is denied by nonaction of the Commission, the 30 -day period for appeal to Superior Court runs from the date on which the application is deemed denied (i.e., 10`h day after the application for reconsideration was filed). • Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, January 31, 2008 9:08 AM Subject: C05326 (West Foreland #2), AIO 32 (Redoubt Unit),A1024B (Prudhoe Bay-Borealis), A1022D (Prudhoe Bay- Aurora) Attachments: aio32.pdf; co532b.pdf; aio22d.pdf; aio24b.pdf BCC:Cynthia B Mciver (bren.mciver@alaska.gov); 'Alan Birnbaum <""Alan J Birnbaum "> (alan.birnbaum@alaska.gov)'; 'Aleutians East Borough'; 'Anna Raff; Arion, Teri A (DNR); 'Arthur C Saltmarsh'; 'Arthur Copoulos'; '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'; 'Catherine P Foerster ; caunderwood@marathonoil.com; 'Charles O'Donnell'; 'Chris Gay'; 'Christian Gou- Leonhardt'; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David Brown'; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deanna Gamble'; 'Deborah J. Jones'; 'doug_schultze'; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gregg Nady'; 'gregory micallef; 'gspfoff; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James B Regg'; 'James M. Ruud'; 'James Scherr'; 'Janet D. Platt'; 'jdarlington'; 'jejones'; 'Jerry McCutcheon'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; johnny.aiken@north-slope.org; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; knelson@petroleumnews.com; 'Kristin Dirks'; 'Laura Silliphant'; 'Lois'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=Crockett@aoga.org'; 'mail=fours@mtaonline.net'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; 'marty'r 'Matt Rader'; 'mckay'; 'Meghan Powell'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro'; 'Paul Decker'; 'Paul Winslow'; Pierce, Sandra M (DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'rcrotty'; Rice, Cody J (DNR); 'rmclean'; rob.g.dragnich@exxonmobil.com; 'Robert Campbell'; 'Robert Province'; 'Roger Belman'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'stanekj'; 'Stephen F Davies'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; 'Thomas E Maunder'; 'Tim Lawlor'; 'Todd Durkee'; 'trmjrl'; 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier' Attachments:aio32.pdf;co532b.pdf;aio22d.pdf;aio24b.pdf; Jody Colombie Special Assistant Alaska Oil & Gas Conservation Commission Direct: 907-793-1221 Fax: 907-276-7542 *Note new email address 1/31/2008 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 John Levorsen Michael Parks Mark Wedman 200 North 3rd Street, #1202 Marple's Business Newsletter Halliburton Boise, ID 83702 117 West Mercer St, Ste 200 6900 Arctic Blvd. Seattle, WA 98119-3960 Anchorage, AK 99502 Baker Oil Tools Schlumberger Ciri 4730 Business Park Blvd., #44 Drilling and Measurements Land Department Anchorage, AK 99503 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99503 Anchorage, AK 99503 Ivan Gillian Jill Schneider Gordon Severson 9649 Musket Bell Cr.#5 US Geological Survey 3201 Westmar Cr. Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508-4336 Anchorage, AK 99508 Jack Hakkila Darvuin Waldsmith James Gibbs PO Box 190083 PO Box 39309 PO Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Richard Wagner Refuge Manager 399 West Riverview Avenue PO Box 60868 PO Box 2139 Soldotna, AK 99669-7714 Fairbanks, AK 99706 Soldotna, AK 99669-2139 Cliff Burglin Bernie Karl North Slope Borough PO Box 70131 K&K Recycling Inc. PO Box 69 Fairbanks, AK 99707 PO Box 58055 Barrow, AK 99723 Fairbanks, AK 99711 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 THE STATE °fALASKA GOVERNOR BILL WALKER Mr. David Pascal Production Manager Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 32.001 Cook Inlet Energy, LLC. 601 West 5"' Avenue, Suite 310 Anchorage, AK 99510 Re: Docket Number: AIO-17-044 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.cogcc.claska.gov Request for administrative approval to allow well Redoubt Unit 3A (PTD 2161700) to be online in water only injection service with a known tubing by inner annulus communication. Redoubt Shoal Unit (RSU) Redoubt Shoal Field, Osprey Platform Redoubt Shoal Undefined Oil Pool Dear Mr. Pascal: By letter dated December 18, 2017, Cook Inlet Energy, LLC (CIE) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 12 of Area Injection Order (AIO) 32.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CIE's request for administrative approval to continue water only injection in the subject well. CIE reported a potential Tubing (T) x Inner Annulus (IA) pressure communication to AOGCC on December 18, 2017 while the well was on water injection. CIE has performed diagnostics including a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on December 23, 2017 which indicates that RU 3A exhibits at least two competent barriers to the release of well pressure. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 32.001 December 28, 2017 Page 2 of 2 AOGCC's approval to continue water injection only in RU 3A is conditioned upon the following: 1. CIE shall record wellhead pressures and injection rate daily; 2. CIE 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. CIE shall perform a mechanical integrity test of the inner annulus every 2 years to the minimum of 2500 psi; 4. CIE shall install, maintain and operate automatic well shut-in equipment linked to the well's inner annulus (IA) pressure. The actuation pressure shall not exceed 2,500 psi for the inner annulus. 5. Testing of the shut in equipment shut -down valve and mechanical or electrical pressure device shall be performed in conjunction with production well pilots and safety valves. CIE shall provide to the commission the testing procedure that will be used to verify integrity of the well shut-in equipment linked to the inner annulus pressure; 6. CIE shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 7. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 8. The next required MIT is to be before or during the month of December 2019. The Commission must be provided the opportunity to witness the MIT for a test to establish a new test due date. DONE at Anchorage, Alaska and dated December 28, 2017. Hollis S. French Chair, Commissioner a P934— Cathy . Foerster 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 die 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 STAIT. "'ALASKA GOVERNOR BILL 1\'ALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 32.001 Mr. David Pascal Production Manager Cook Inlet Energy, LLC. 601 West 5s' Avenue, Suite 310 Anchorage, AK 99510 Re: Docket Number: AIO-17-044 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 oogcc.alaska.gov Request for administrative approval to allow well Redoubt Unit 3A (PTD 2161700) to be online in water only injection service with a known tubing by inner annulus communication. Redoubt Shoal Unit (RSU) Redoubt Shoal Field, Osprey Platform Redoubt Shoal Undefined Oil Pool Dear Mr. Pascal: By letter dated December 18, 2017, Cook Inlet Energy, LLC (CIE) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 12 of Area Injection Order (AIO) 32.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CIE's request for administrative approval to continue water only injection in the subject well. CIE reported a potential Tubing (T) x Inner Annulus (IA) pressure communication to AOGCC on December 18, 2017 while the well was on water injection. CIE has performed diagnostics including a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on December 23, 2017 which indicates that RU 3A exhibits at least two competent barriers to the release of well pressure. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 32.001 December 28, 2017 Page 2 of 2 AOGCC's approval to continue water injection only in RU 3A is conditioned upon the following: 1. CIE shall record wellhead pressures and injection rate daily; 2. CIE 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. CIE shall perform a mechanical integrity test of the inner annulus every 2 years to the minimum of 2500 psi; 4. CIE shall install, maintain and operate automatic well shut-in equipment linked to the well's inner annulus (IA) pressure. The actuation pressure shall not exceed 2,500 psi for the inner annulus. 5. Testing of the shut in equipment shut -down valve and mechanical or electrical pressure device shall be performed in conjunction with production well pilots and safety valves. CIE shall provide to the commission the testing procedure that will be used to verify integrity of the well shut-in equipment linked to the inner annulus pressure; 6. CIE shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 7. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 8. The next required MIT is to be before or during the month of December 2019. The Commission must be provided the opportunity to witness the MIT for a test to establish a new test due date. DONE at Anchorage, Alaska and dated December 28, 2017. //signature on file// Hollis S. French Chair, Commissioner //signature on file// Cathy P. Foerster Commissioner 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 father 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: Friday, December 29, 2017 8:23 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); 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); Regg, James B (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Erickson, Tamara K (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity; AKDCWellIntegrityCoordinator; Alan Bailey; Alex Demarban; Alicia Showalter; Allen Huckabay; Andrew VanderJack; Ann Danielson; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Ben Boettger, Bill Bredar; Bob Shavelson; Brandon Viator; Brian Havelock; Bruce Webb; Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Cody Gauer; Colleen Miller, Connie Downing; Crandall, Krissell; D Lawrence; Dale Hoffman; Danielle Mercurio; Darci Horner, Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David McCraine; ddonkel@cfl.rr.com; Diemer, Kenneth J (DNR); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Elwood Brehmer; Evan Osborne; Evans, John R (LDZX); Brown, Garrett A (DNR); George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff, Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jason Brune; Jdarlington Qarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Shine; Jim Watt; Jim White; Young, Jim P (DNR); Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); John Stuart; Jon Goltz; Chmielowski, Josef (DNR); Juanita Lovett; Judy Stanek, Kari Moriarty, Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Frank, Kevin J (DNR); Kruse, Rebecca D (DNR); Kyla Choquette; Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Michael Bill; Michael Calkins; Michael Moora; Michael Quick; Michael Schoetz; Mike Morgan; MJ Loveland; mkm7200; Motteram, Luke A; Mueller, Marta R (DNR); Nathaniel Herz; knelson@petroleumnews.com; Nichole Saunders; Nick Ostrovsky, NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan Yanish; Richard Cool; Robert Brelsford; Robert Warthen; Sara Leverette; Scott Griffith; Shahla Farzan; Shannon Donnelly; Sharon Yarawsky; Skutca, Joseph E (DNR); Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Tanisha Gleason; Ted Kramer, Teresa Imm; Tim Jones; Tim Mayers; Todd Durkee; Tom Maloney; trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Well Integrity; Well Integrity; Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andy Bond; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Corey Munk, Don Shaw, Eppie Hogan; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Keith Lopez; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Melonnie Amundson; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Rachel Davis; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); William Van Dyke Subject: AIO 32.001 (Redoubt Shoal) (CIE) Attachments: aio32.001.pdf See Attached. Re: Docket Number: AIO-17-044 Request for administrative approval to allow well Redoubt Unit 3A (PTD 2161700) to be online in water only injection service with a known tubing by inner annulus communication. Redoubt Shoal Unit (RSU) Redoubt Shoal Field, Osprey Platform Redoubt Shoal Undefined Oil Pool Jody J. Cotom6ie AOQCC SyeciaCAssist ant ACaska OiCandGas Conservation Commission 333 west 7'fi 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 aov. 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 THE STATE 01ALASKA 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.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 32.001 CANCELLATION Mr. David Pascal Production Manager Glacier Oil and Gas. 601 West 5`h Avenue, Suite 310 Anchorage, AK 99510 Re: Docket Number: AIO-20-004 Request to cancel Area Injection Order (AIO) 32.001 Redoubt Unit 3A (PTD 2161700) Redoubt Shoal Unit (RSU) Redoubt Shoal Field, Osprey Platform Redoubt Shoal Undefined Oil Pool Dear Mr. Pascal: By the request contained within the January 2020 AIO 32.001 Monthly Reporting dated February 10, 2020, Cook Inlet Energy, LLC (CIE) requested cancellation of administrative approval (AA) AIO 32.001. In accordance with Rule 12 of Area Injection Order (AIO) 32.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CIE's request to cancel the AA. CIE reported a potential Tubing (T) x Inner Annulus (IA) pressure communication to AOGCC on December 18, 2017 while the well was on water injection and on December 28, 2017 the AOGCC issued AIO 32.001. AOGCC determined that water only injection could safely continue if CIE complied with the restrictive conditions set out in AA AIO 32.001. The RU -3A well completed a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on December 23, 2019. This combined with two years of pressure monitoring showing no anomalous pressure fluctuations or need for any pressure bleeds indicates that RU -3A exhibits at least two competent barriers to the release of well pressure. AA AIO 32.001 is no longer necessary to the operation of RU -3A and is hereby CANCELLED. A10 32.001 Cancellation March 3, 2020 Page 2 of 2 DONE at Ay forage, Alaska and dated March 3, 2020. OIL"' VChaoDaniel T. Seamount, Jr. Je e L. Chmielowski missioner 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 one 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 data on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing aperiod 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. P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Penny Vadla 399 W. Riverview Ave. 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 12 By Samantha Carlisle at 11:51 am, Oct 20, 2020 By Samantha Carlisle at 2:32 pm, Sep 01, 2020 By Samantha Carlisle at 11:00 am, Aug 10, 2020 By Samantha Carlisle at 8:57 am, Jul 13, 2020 "#%#!%$ '&%!"# !) 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( $*( 2) $6('217+(0(&+$1,&$/,17(*5,7<,1)250$7,21$1'7:2<($56:257+2)326,7,9('$7$ 22.1/(71(5*<,65(48(67,1*7+(200,66,21725(&216,'(5 $1'$5(48(6772 5(7851721250$/23(5$7,216)257+(:(//$0$9$,/$%/($7<285&219(1,(1&(72',6&8667+,65(3257 253529,'($'',7,21$/,1)250$7,21$%2877+,65(48(67/($6(&217$&70($7 25$7 '3$6&$/*/$&,(52,/&20 ,1&(5(/< %" +,()3(5$7,1*)),&(5 22.1/(71(5*< /$&,(5,/$1'$6#+2//<:1('203$1< ###" " 3(5$7,2162*$< ,1&(5(/< %" +,()3(5$7,1*)),&(5 22.1/(71(5*< /$&,(5,/$1'$6#+2//<: & $%%'$ #% !& "' % ( $%%'$ #% "'$% ! "& $%%'$ #% "& "' ( $%%'$ #% !&"!$!#"$&) 188 W. Northern Lights Blvd. Suite 510, Anchorage, AK 99503 (907) 334-6745 Main | (907) 334-6735 Fax Page 1 of 2 May 5, 2020 Ms. Jessie Chmielowski Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: AIO 32.001 Monthly Reporting Dear Commissioner Chmielowski, As required by Area Injection Order No. 32.001 issued by the AOGCC on December 28th, 2017, the monthly report involving well pressures, injection rates and pressure bleeds for all annuli for the well RU-3A for the month of April 2020 is provided to the Commission for review. There were no bleeds conducted for the month. There has been a total of three bleed events since the order, amounting to a total of 0.5 bbl. and 409 psi, all occurred in January 2018. There haven’t been any bleeds on RU-3A since January 2018. Cook Inlet Energy is currently maintaining and operating well shut-in equipment linked to the RU-3A inner annular pressure as directed. The last test of the system was conducted on February 13, 2020. The next test will be conducted during the month of August 2020 The last successful mechanical integrity test of the well was conducted on December 23, 2019 in presence of an AOGCC inspector. The next MIT test will be performed before or during the month of December 2021 as required by the order. In addition to the above, CIE will be following all stipulations mentioned in the order 188 W. Northern Lights Blvd. Suite 510, Anchorage, AK 99503 (907) 334-6745 Main | (907) 334-6735 Fax Page 2 of 2 Based on the mechanical integrity information and two years worth of positive data, Cook Inlet Energy is requesting the Commission to reconsider AIO 32.001 and a request to return to normal operations for the well. I am available at your convenience to discuss this report or provide additional information about this request. Please contact me at (907) 433-3822 or at dpascal@glacieroil.com Sincerely, David Pascal Vice President, Operations Cook Inlet Energy A Glacier Oil and Gas Wholly Owned Company Attachments 1. RU-3A Operations Log, April 2020 Outer Annulus Date Wellhead Pressure (psi) Injected Volume (bbls) Avg. Pressure (psi) Bleed Time (Hours: Min) Total Pressure Bled (psi) Total Volume Bled (bbl) Avg. Pressure (psi) 4/1/20 4,341 2,966 459 0:00 0 0.0 30 4/2/20 4,313 2,994 459 0:00 0 0.0 30 4/3/20 4,321 2,980 460 0:00 0 0.0 30 4/4/20 4,335 2,966 463 0:00 0 0.0 30 4/5/20 4,324 2,975 464 0:00 0 0.0 30 4/6/20 4,309 2,890 462 0:00 0 0.0 30 4/7/20 3,320 542 546 0:00 0 0.0 30 4/8/20 3,099 330 641 0:00 0 0.0 30 4/9/20 3,090 364 671 0:00 0 0.0 30 4/10/20 3,586 975 612 0:00 0 0.0 30 4/11/20 4,247 2,759 492 0:00 0 0.0 30 4/12/20 4,308 2,886 487 0:00 0 0.0 30 4/13/20 4,363 3,019 490 0:00 0 0.0 30 4/14/20 4,381 3,015 494 0:00 0 0.0 30 4/15/20 4,397 3,002 499 0:00 0 0.0 30 4/16/20 4,407 2,995 502 0:00 0 0.0 30 4/17/20 4,414 2,974 505 0:00 0 0.0 30 4/18/20 4,422 2,988 506 0:00 0 0.0 30 4/19/20 4,421 3,009 507 0:00 0 0.0 30 4/20/20 4,439 3,077 508 0:00 0 0.0 30 4/21/20 4,480 3,104 517 0:00 0 0.0 30 4/22/20 4,364 2,781 506 0:00 0 0.0 30 4/23/20 4,344 2,777 504 0:00 0 0.0 30 4/24/20 4,356 2,796 506 0:00 0 0.0 30 4/25/20 4,357 2,773 509 0:00 0 0.0 30 4/26/20 4,359 2,753 514 0:00 0 0.0 30 4/27/20 4,356 2,788 518 0:00 0 0.0 30 4/28/20 4,362 2,793 523 0:00 0 0.0 30 4/29/20 4,355 2,743 528 0:00 0 0.0 30 4/30/20 4,374 2,802 534 0:00 0 0.0 30 RU 3A Injection Tracking Report April 2020 Inner Annulus 188 W. Northern Lights Blvd. Suite 510, Anchorage, AK 99503 (907) 334-6745 Main | (907) 334-6735 Fax Page 1 of 2 April 7, 2020 Ms. Jessie Chmielowski Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: AIO 32.001 Monthly Reporting Dear Commissioner Chmielowski, As required by Area Injection Order No. 32.001 issued by the AOGCC on December 28th, 2017, the monthly report involving well pressures, injection rates and pressure bleeds for all annuli for the well RU-3A for the month of March 2020 is provided to the Commission for review. There were no bleeds conducted for the month. There has been a total of three bleed events since the order, amounting to a total of 0.5 bbl. and 409 psi, all occurred in January 2018. There haven’t been any bleeds on RU-3A since January 2018. Cook Inlet Energy is currently maintaining and operating well shut-in equipment linked to the RU-3A inner annular pressure as directed. The last test of the system was conducted on February 13, 2020. The next test will be conducted during the month of August 2020 The last successful mechanical integrity test of the well was conducted on December 23, 2019 in presence of an AOGCC inspector. The next MIT test will be performed before or during the month of December 2021 as required by the order. In addition to the above, CIE will be following all stipulations mentioned in the order 188 W. Northern Lights Blvd. Suite 510, Anchorage, AK 99503 (907) 334-6745 Main | (907) 334-6735 Fax Page 2 of 2 Based on the mechanical integrity information and two years worth of positive data, Cook Inlet Energy is requesting the Commission to reconsider AIO 32.001 and a request to return to normal operations for the well. I am available at your convenience to discuss this report or provide additional information about this request. Please contact me at (907) 433-3822 or at dpascal@glacieroil.com Sincerely, David Pascal Vice President, Operations Cook Inlet Energy A Glacier Oil and Gas Wholly Owned Company Attachments 1. RU-3A Operations Log, March 2020 Outer Annulus Date Wellhead Pressure (psi) Injected Volume (bbls) Avg. Pressure (psi) Bleed Time (Hours: Min) Total Pressure Bled (psi) Total Volume Bled (bbl) Avg. Pressure (psi) 3/1/20 4,433 2,920 462 0:00 0 0.0 30 3/2/20 4,429 2,906 462 0:00 0 0.0 30 3/3/20 4,479 3,083 466 0:00 0 0.0 30 3/4/20 4,495 3,073 467 0:00 0 0.0 30 3/5/20 4,482 3,004 466 0:00 0 0.0 30 3/6/20 4,482 3,021 464 0:00 0 0.0 30 3/7/20 4,488 3,044 462 0:00 0 0.0 30 3/8/20 4,484 2,922 462 0:00 0 0.0 30 3/9/20 4,434 2,912 459 0:00 0 0.0 30 3/10/20 4,432 2,892 458 0:00 0 0.0 30 3/11/20 4,433 2,927 457 0:00 0 0.0 30 3/12/20 4,476 3,116 459 0:00 0 0.0 30 3/13/20 4,485 3,138 462 0:00 0 0.0 30 3/14/20 4,411 2,937 458 0:00 0 0.0 30 3/15/20 4,411 2,941 458 0:00 0 0.0 30 3/16/20 4,419 2,972 459 0:00 0 0.0 30 3/17/20 4,429 2,977 461 0:00 0 0.0 30 3/18/20 4,431 2,988 461 0:00 0 0.0 30 3/19/20 4,435 2,976 462 0:00 0 0.0 30 3/20/20 4,438 2,994 460 0:00 0 0.0 30 3/21/20 4,440 2,981 460 0:00 0 0.0 30 3/22/20 4,437 3,010 458 0:00 0 0.0 30 3/23/20 4,437 3,017 459 0:00 0 0.0 30 3/24/20 4,430 3,037 458 0:00 0 0.0 30 3/25/20 4,429 3,030 459 0:00 0 0.0 30 3/26/20 4,411 3,051 458 0:00 0 0.0 30 3/27/20 4,404 3,093 459 0:00 0 0.0 30 3/28/20 4,376 3,018 457 0:00 0 0.0 30 3/29/20 4,316 3,002 452 0:00 0 0.0 30 3/30/20 4,321 3,008 454 0:00 0 0.0 30 3/31/20 4,328 3,004 457 0:00 0 0.0 30 RU 3A Injection Tracking Report March 2020 Inner Annulus GLACIER March 9, 2020 Ms. Jessie Chmielowski Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: AIO 32.001 Monthly Reporting Dear Commissioner Chmielowski, {DECEIVED MAR 0 9 2020 AOGCC As required by Area Injection Order No. 32.001 issued by the AOGCC on December 28tH 2017, the monthly report involving well pressures, injection rates and pressure bleeds for all annuli for the well RU -3A for the month of February 2020 is provided to the Commission for review. There were no bleeds conducted for the month. There has been a total of three bleed events since the order, amounting to a total of 0.5 bbl. and 409 psi, all occurred in January 2018. There haven't been any bleeds on RU -3A since January 2018. Cook Inlet Energy is currently maintaining and operating well shut-in equipment linked to the RU -3A inner annular pressure as directed. The last test of the system was conducted on February 13, 2020. The next test will be conducted during the month of August 2020 The last successful mechanical integrity test of the well was conducted on December 23, 2019 in presence of an AOGCC inspector. The next MIT test will be performed before or during the month of December 2021 as required by the order. In addition to the above, CIE will be following all stipulations mentioned in the order 188 N'. Northcrn Lights BI A. Suite 510, Anchorage, AK 995113 (907)334-6745 Main J (907) 334-6735 Fax Page 1 of 2 Based on the recent mechanical integrity information and two years worth of positive data, Cook Inlet Energy is requesting the Commission to reconsider AIO 32.001 and a request to return to normal operations for the well. I am available at your convenience to discuss this report or provide additional information about this request. Please contact me at (907) 433-3822 or at dpascalna glacieroil.com Sincerely, D Id Pascal i e President, Operations Cook Inlet Energy A Glacier Oil and Gas Wholly Owned Company Attachments 1. RU -3A Operations Log, Feb 2020 2. SVS RD Shoal Osprey 02-13-20 Misc. HPP 188 N'. Northern Lights Bl%d. Suite 510, Anchorage, AK 995113 (907) 334-67451!lain : (9(17) 334-6735 Fax Page 2 of 2 RU 3A Injection Tracking Report Febuary 2020 Inner Annulus Outer Annulus Date Wellhead Pressure (psi) Injected Volume bbls) Avg. Pressure psi) Bleed Time (Hours: Min) Total Pressure Bled (psi) Total Volume Bled (bbl) Avg. Pressure (psi) 2/1/20 4,142 2,295 467 0:00 0 0.0 30 2/2/20 4,139 2,275 469 0:00 0 0.0 30 2/3/20 4,180 2,371 469 0:00 0 0.0 30 2/4/20 4,034 2,274 464 0:00 0 0.0 30 2/5/20 3,886 1,807 471 0:00 0 0.0 30 2/6/20 3,856 1,738 482 0:00 0 0.0 30 2/7/20 4,436 3,308 481 0:00 0 0.0 30 2/8/20 4,489 3,392 481 0:00 0 0.0 30 2/9/20 1 4,502 3,370 481 1 0:00 0 0.0 30 2/10/20 4,508 3,410 480 0:00 0 0.0 30 2/11/20 4,506 3,395 477 0:00 0 0.0 30 2/12/20 4,517 3,425 476 0:00 0 0.0 30 2/13/20 4,478 3,203 436 0:00 0 0.0 30 2/14/20 4,500 3,218 470 0:00 0 0.0 30 2/15/20 4,494 3,294 471 0:00 0 0.0 30 2/16/20 4.498 3,299 471 0:00 0 0.0 30 2/17/20 4,461 3,158 468 0:00 0 0.0 30 2/18/20 4,444 3,252 465 0:00 0 0.0 30 2/19/20 4,455 3,310 469 0:00 0 0.0 30 2/20/20 4,481 3,225 469 0:00 0 0.0 30 2/21/20 4,489 3,234 468 0:00 0 0.0 30 2/22/20 4,463 3,091 465 0:00 0 0.0 30 2/23/20 4,465 3,095 464 0:00 0 0.0 30 2/24/20 4,486 3,182 463 0:00 0 0.0 30 2/25/20 4,483 3,184 464 0:00 0 0.0 30 2/26/20 4,485 3,182 464 0:00 0 0.0 30 2/27/20 4,489 3,140 466 0:00 0 0.0 30 2/28/20 4,497 3,145 467 0:00 0 0.0 30 2/29/20 4,473 3,021 465 0:00 0 0.0 30 Alaska Oil and Gas Conservation Commission Safety Valve System Test Report Operator: Cook Inlet Energ Submitted By: David Pascal Date: 2/13/20 Operator Rep: Sean Sullivan Field/Unit/Pad: Osprey /Redoubt Shoal AOGCC Rep: Austin Mcleod Separator psi: LPS 77 HPS na Well Data Pilots ssvi SSSV Retest/SI Date Well Type Well Pressures Gas Lift Waiver Well Permit Separ Number Number PSI Set UP PSI Trip Test Test ode Code Test Date Passed Retest oH,wAG,Gana, Code Or Date Shut In GAs,CYCt.E,s1 Inner Outer Tubing Yes/No Yes/No PSI PSI PSI 3A 2161700 0 2500 2497 P NT NT 480 20 4306 no no Wells: 1 Components: 1 Failures: 0 Remarks: "0" entered in "Separ PSP' to count well. IA Failure Rate: set o.00% ❑ 90 Dv PLB 01/26/11 Page 1 of 1 SVS RD Shoal Osprey 02-13-20 Mist; HPP.xlsx GLACIER February 10, 2020 Ms. Jessie Chmielowski Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: AIO 32.001 Monthly Reporting Dear Commissioner Chmielowski, As required by Area Injection Order No. 32.001 issued by the AOGCC on December 281h, 2017, the monthly report involving well pressures, injection rates and pressure bleeds for all annuli for the well RU -3A for the month of January 2020 is provided to the Commission for review. There were no bleeds conducted for the month. There has been a total of three bleed events since the order, amounting to a total of 0.5 bbl, and 409 psi, all occurred in January 2018. There haven't been any bleeds on RU -3A since January 2018. Cook Inlet Energy is currently maintaining and operating well shut-in equipment linked to the RU -3A inner annular pressure as directed. The last test of the system was conducted on August 12, 2019. The next test will be conducted during the month of February 2020 The last successful mechanical integrity test of the well was conducted on December 23, 2019 in presence of an AOGCC inspector. The next MIT test will be performed before or during the month of December 2021 as required by the order. In addition to the above, CIE will be following all stipulations mentioned in the order RECEIVED FEB 11 2020 k, ti'- % ,t-•., - Lights Blvd. Suite SIU, Aneltorage, AK 99503 AOGCC (907) 334-6745 Main 1(907] 334-6735 Fox Page 1 of 2 Based on the recent mechanical integrity information and two years worth of positive data, Cook Inlet Energy is requesting the Commission to reconsider AIO 32.001 and a request to return to normal operations for the well. I am available at your convenience to discuss this report or provide additional information about this request. Please contact me at (907) 433-3822 or at dpascal@jzlacieroil.com Sincerely, D Pascal Vic President, Operations Co Inlet Energy A Glacier Oil and Gas Wholly Owned Company Attachments 1. RU -3A Operations Log, January 2020 1881'x'. Noilhero Lights Blvd. Suite 510, Anchorage, AK 99503 (9071334-6745 Maid 1 (9€37) 334-6735 Fax Page 2 of 2 RU 3A Injection Tracking Report January 2020 Inner Annulus Outer Annulus Date Wellhead Pressure psi Injected Volume bbis Avg. Pressure I Bleed Time Hours: Min Total Pressure Bled psi Total Volume Bled bbl Avg. Pressure i 111120 4,349 2,696 512 0:00 0 0.0 30 112120 4,339 2,713 509 0:00 0 0.0 30 113120 4,351 2,730 504 0:00 0 0.0 30 114120 4,361 2,739 498 0:00 0 0.0 30 115120 4,322 2,616 492 0:00 0 0.0 30 116120 4,276 2 689 480 0:00 0 0.0 30 117120 4,303 2 61 fi 479 0:00 0 0.0 30 118120 4,327 2,569 477 0:00 0 0.0 30 119120 4,329 2,579 474 0:00 0 0.0 30 1110120 4,337 2,615 474 0:00 0 0.0 30 1111120 4,338 2 599 472 0:00 0 0.0 30 1112120 4,335 2,583 469 0:00 0 0.0 30 1113120 4,340 2 598 468 0:00 0 0.0 30 1114120 4,337 2 575 468 0:00 0 0.0 30 1115120 4,337 2,562 467 0:00 0 0.0 30 1116120 4,405 2,987 456 0:00 0 0.0 30 1/17/20 4,467 3 233 448 0:00 0 0.0 30 1118120 4,462 3 111 446 0:00 0 0.0 30 1119120 4,439 3,074 444 0:00 0 0.0 30 1120120 4,440 3,081 445 0:00 0 0.0 30 1121120 4,434 3 057 445 0:00 0 0.0 30 1122120 4,423 3,049 444 0:00 0 0.0 30 1123120 4,415 3,113 446 0:00 0 0.0 30 1124120 4,440 2,842 468 0:00 0 0.0 30 1125120 4,439 2,733 482 0:00 0 0.0 30 1126120 4,444 2 799 474 0:00 0 0.0 30 1127120 4,427 2.815 468 0:00 0 0.0 30 1128120 4,427 2,841 467 0:00 0 0,0 30 1129120 4,411 2,799 466 0:00 0 0.0 30 1130120 4,234 2361 468 0:00 0 0.0 30 1131120 4,164 _=, 2,264 469 0:00 0 0.0 30 GLACIER January 13, 2020 Ms. Jessie Chmielowski Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: AIO 32.001 Monthly Reporting Dear Commissioner Chmielowski, JAN 13 2020 AOGCC As required by Area Injection Order No. 32.001 issued by the AOGCC on December 2811 2017, the monthly report involving well pressures, injection rates and pressure bleeds for all annuli for the well RU -3A for the month of December 2019 is provided to the Commission for review. There were no bleeds conducted for the month. There has been a total of three bleed events since the order, amounting to a total of 0.5 bbl. and 409 psi, all occurred in January 2018. There haven't been any bleeds on RU -3A since January 2018. Cook Inlet Energy is currently maintaining and operating well shut-in equipment linked to the RU -3A inner annular pressure as directed. The last test of the system was conducted on August 12, 2019. The next test will be conducted during the month of February 2020 The last successful mechanical integrity test of the well was conducted on December 23, 2019 in presence of an AOGCC inspector. The next MIT test will be performed before or during the month of December 2021 as required by the order. In addition to the above, CIE will be following all stipulations mentioned in the order 188 W. Northern Lights Blvd. Suite 510, Anchorage, AK 99.503 (907) 334-6745 Main � (907) 334-673.5 Fax Page 1 of 2 Based on the recent mechanical integrity information and two years worth of positive data, Cook Inlet Energy is requesting the Commission to reconsider AIO 32.001 and a request to return to normal operations for the well. I am available at your convenience to discuss this report or provide additional information about this request. Please contact me at (907) 433-3822 or at dpascal@glacieroil.com Sincerely, ¢re President, Operations )ok Inlet Energy Glacier Oil and Gas Wholly Owned Company Attachments 1. RU -3A Operations Log, December 2019 2. MIT RU -3A 12-23-2019 188 W. Northern Lights Blvd. Suite 510, Anchorage, AK 99503 (907) 334-6745 Main 1 (907) 334-6735 Fax Page 2 of 2 RU 3A Injection Tracking Report December 2019 Inner Annulus OuterAnnuius Date Wellhead Pressure (psi) Injected Volume (bbls) Avg. Pressure (psi) Bleed Time Total Total (Hours: Pressure Volume Min) Bled (psi) Bled (bbl) Avg. Pressure (psi) 12/1/19 4,392 3,544 394 0:00 0 0.0 30 12/2/19 4,390 3,803 401 0:00 0 0.0 30 12/3/19 4,460 3,681 399 0:00 0 0.0 30 1214/19 4,472 3,393 389 0:00 0 0.0 30 12/5/19 4,484 3,272 379 0:00 0 0.0 30 12/6/19 4,477 3,216 367 0:00 0 0.0 30 12/7/19 4,319 2,641 348 0:00 0 0.0 30 12/8/19 4,273 2,580 341 0:00 0 0.0 30 12/9/19 4,162 2,616 334 0:00 0 0.0 30 12/10/19 4,170 2,535 337 0:00 0 0.0 30 12/11/19 4,194 2,402 338 0:00 0 0.0 30 12/12/19 4,009 2,039 337 0:00 0 0.0 30 12/13/19 4,166 2,286 334 0:00 0 0.0 30 12/14/19 4,183 2,290 333 0:00 0 0.0 30 12/15/19 4,191 2,296 331 0:00 0 0.0 30 12/16/19 4,273 2,536 332 0:00 0 0.0 30 12/17/19 4,309 2,611 334 0:00 0 0.0 30 12/18/19 4,333 2,717 332 0:00 0 0.0 30 12/19/19 4,259 2,447 326 0:00 0 0.0 30 12/20/19 4,269 2,521 320 0:00 0 0.0 30 12/21/19 4,335 2,735 317 0:00 0 0.0 30 12/22/19 4,341 2,701 314 0:00 0 0.0 30 12/23/19 4,355 2.723 435 0:00 0 0.0 30 12/24/19 4,327 2,578 366 0:00 0 0.0 30 12/25/19 4,327 2,602 423 0:00 0 0.0 30 12/26/19 4,336 2,641 475 0:00 0 0.0 30 12/27/19 4,339 2,635 510 0:00 0 0.0 30 12/28/19 4,351 2,620 513 0:00 0 0.0 30 12/29/19 4,354 2,645 513 0:00 0 0.0 30 12/30/19 4,352 2,687 515 0:00 0 0.0 30 12/31/19 4,354 2,690 518 0:00 1 0 0.0 30 Sublet to: 'im.magOalaska.aov: OPERATOR: FIELD/ UNIT/ PAD: DATE: OPERATOR REP: AOGCC REP: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical integrity Test AOGCC insoectore(dalaska.cov: choebe.breok.Auaska.aoV ch i.,ailaveftlaske.cov Glacier Oil and Gas Osprey PlatfonpR doubt Unit Lance Anderson Well RLIi WTERVAL Coss Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. 4=ForYSC0e F=Fell PTD 2161700 Typelnj W Tubing 4340 4345 4345 4345 N=Nd lrgi Type Test P Packer rVD 5989 BBI -Pump 3.5 IA 304 2805 2605 2805 Interval O Test pan 2500 BBL Return 3.5 OA 30 30 30 30 Ressit P DGIm1 Test for adrrinistrative apprwel papei to 2500 psi every pro years per AD 32.001 note 3 Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Mi, PTD TypeInj Tubing Type Test Packer ND BBLPumpIA Interval Test psi BBL Retum OA Result bit=: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type InjTubing Type Test Packer ND BBLPump IA Interval Test psi BBL Return OA Result SAW WellPressures: Pretest Initial 15 Min. 30 Min. 45 Min. 80 Min. PTD Type Inj Tubing Type Test Packer ND BBLPump IA Interval Test psi BBL Return OA Result tloIew We0 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Int Tubing Type Test Packer ND BBL Pu 4j IA Interval Test psi BBL Realm OA Result Nall Well Pressures: Pretest Indial 15 Min. 30 Min. 45 Min. 60 Min. PTD Typelnj Tubing Type Test Packer ND BBLPump IA Interval Test psi BBL Return OA Result Dales: well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj TubingI Type Test Packer ND BBLPump IA Interval Test psi BBL Return OA Result UMea: Wall Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer ND BBLPump IA Interval Test psi BBL Return OA Result NOtw T WCo4n 7WETMCeMe WTERVAL Coss Result Codes W=Water P=R—i,. Tsl 1=1rtrW T. P=Pies G. Gia 0=0tl'a1M rirein Ntlea) 4=ForYSC0e F=Fell a- $in, V=11a7.trtl tyVen. I- Irewcli sw 1=1.IN WslsrvM O=Cex(deavlteinndes) N=Nd lrgi Fenn 10426 (Revised 011201 7) MIT Ru x 12-2. 20a.xlsx GLACIER Nov 11, 2019 Ms. Jessie Chmielowski Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: AIO 32.001 Monthly Reporting Dear Commissioner Chmielowski, RECEIVED t4OV 12 2019 AOGCC As required by Area Injection Order No. 32.001 issued by the AOGCC on December 28th, 2017, the monthly report involving well pressures, injection rates and pressure bleeds for all annuli for the well RU -3A for the month of October 2019 is provided to the Commission for review. There were no bleeds conducted for this month Cook Inlet Energy is currently maintaining and operating well shut-in equipment linked to the RU -3A inner annular pressure as directed. The last test of the system was conducted on August 12, 2019. The next test will be conducted during the month of February 2020 The last mechanical integrity test of the well was conducted on December 23, 2017 in presence of an AOGCC inspector. The next MIT test will be performed before or during the month of December 2019 as required by the order. In addition to the above, CIE will be following all stipulations mentioned in the order I am available at your convenience to discuss this report or provide additional information. Please contact me at (907) 433-3822 or at dpascalgylacieroil.com 188 W. Northern Lights Blvd. Suite 510, Anchorage, AK 99503 (907) 334-6745 Main I (907) 334-6735 Fax Pagel of 2 Sincerely, 1A `\ V�id Paseal Vi a President, Operations C ok Inlet Energy A Glacier Oil and Gas Wholly Owned Company Attachments 1. RU -3A Operations Log, October 2019 ISR M'. Northern Lighhs Blvd. Suite 51(j, Anchorage, AK 99563 (907) 334-6745 Main (907) 334-6735 fax Page 2 of 2 RU 3A Injection Tracking Report October 2019 Inner Annulus Outer Annulus Date Wellhead Pressure psi) Injected Volume (bbls Avg. Pressure psi Bleed Time (Hours: Min) Total Pressure Bled (psi) Total Volume Bled (bbl) Avg. Pressure (psi) 10/1/19 4,507 5,082 717 0:00 0 0.0 35 10/2/19 4,504 4,656 679 0:00 0 0.0 35 10/3/19 4,499 4,501 637 0:00 0 0.0 35 10/4/19 4,493 1 4,284 682 0:00 0 0.0 35 10/5/19 4,504 1 4,292 686 0:00 0 0.0 35 10/6/19 4,493 4,252 663 0:00 0 0.0 35 10/7/19 4,448 3,919 634 0:00 0 0.0 35 10/8/19 4,451 3,969 629 0:00 0 0.0 35 10/9/19 4,456 3,938 623 0:00 0 0.0 35 10/10/19 4,457 3,903 619 0:00 0 0.0 30 10/11/19 4,452 3,794 614 0:00 0 0.0 35 10/12/19 4,427 3,658 605 0:00 0 0.0 35 10/13/19 4,443 3,476 598 0:00 0 0.0 35 10/14/19 3,967 2,203 604 0:00 0 0.0 35 10/15/19 2,244 693 669 0:00 0 0.0 35 10/16/19 4,410 4,110 550 0:00 0 0.0 30 10/17/19 4,488 4,056 569 0:00 0 0.0 30 10/18/19 4,453 3,778 537 0:00 0 0.0 30 10/19/19 4,439 3,724 532 0:00 0 0.0 35 10/20/19 4,399 3,532 536 0:00 0 0.0 30 10/21/19 4,377 3,392 529 0:00 0 0.0 30 10/22/19 4,420 3,556 521 0:00 1 0 0.0 30 10/23/19 4,449 3,676 511 0:00 0 0.0 30 10/24/19 4,445 3,564 539 0:00 0 0.0 30 10/25/19 4,481 3,666 556 0:00 0 0.0 30 10/26/19 4,487 3,696 556 0:00 0 0.0 30 10/27/19 4,499 3 700 550 0:00 0 0.0 30 10/28/19 4,498 3,649 545 0:00 0 0.0 30 10/29/19 4,508 3,673 5490:00 0 0.0 30 10/30/19 4,513 3,653 551 0:00 0 0.0 30 10/31/19 4,259 2,684 559 0:00 1 0 0.0 30 GLACIER September 3, 2019 Ms. Jessie Chmielowski Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: AIO 32.001 Monthly Reporting Dear Commissioner Chmielowski, 7 - P' sem. �s SEP 09 S' As required by Area Injection Order No. 32.001 issued by the AOGCC on December 28", 2017, the monthly report involving well pressures, injection rates and pressure bleeds for all annuli for the well RU -3A for the month of August 2019 is provided to the Commission for review. There were no bleeds conducted for this month Cook Inlet Energy is currently maintaining and operating well shut-in equipment linked to the RU -3A inner annular pressure as directed. The last test of the system was conducted on August 12, 2019. The next test will be conducted during the month of February 2020 The last mechanical integrity test of the well was conducted on December 23, 2017 in presence of an AOGCC inspector. The next MIT test will be performed before or during the month of December 2019 as required by the order. In addition to the above, CIE will be following all stipulations mentioned in the order I am available at your convenience to discuss this report or provide additional information. Please contact me at (907) 433-3822 or at dpascal@21acieroil.com glacieroil.com I88 W. Not4hern Lights Blvd. Suite 510, Anchorage, AK 99503 (907) 334-6745 Main I (907) 334-6735 Fax Page] of 2 Sincerely„ Bb d Pascal 1 Vi e President, perations C ok Inlet Energy A Glacier Oil and Gas Wholly Owned Company Attachments 1. RU -3A Operations Log, Aug 2019 2. SVS RD Shoal Osprey 08-12-19 Mise HPP 188 W. Northern Lights BIN d. Suite 510, Anchorage, AH 99503 (907) 334-6745 Main 1 (907) 334-6735 fax Page 2 of 2 RU 3A Injection Tracking Report Aug 2019 Inner Annulus Outer Annulus Date Wellhead Pressure (psi) Injected Volume (bbls) Avg. Pressure (psi) Bleed Time (Hours: Min) Total Pressure Bled (psi) Total Volume Bled (bbl) Avg. Pressure (psi) 8/1/19 4,108 2,631 691 0:00 0 0.0 30 8/2/19 4,107 2,627 690 0:00 0 0.0 30 8/3/19 4,120 2,613 695 0:00 0 0.0 30 8/4/19 4,120 2,607 697 0:00 0 0.0 30 8/5/19 4,137 2,600 702 0:00 0 0.0 30 8/6/19 4,127 2,580 704 0:00 0 0.0 30 8/7/19 4,100 2,663 697 0:00 0 0.0 30 8/8/19 3,743 1,938 1 706 0:00 0 0.0 30 8/9/19 4,003 2,060 695 0:00 0 0.0 30 8/10/19 3,642 2,211 693 0:00 0 0.0 30 8/11/19 3,926 2,228 696 0:00 0 0.0 30 8/12/19 3,972 2,280 673 0:00 0 0.0 30 8/13/19 4,098 2,535 719 0:00 0 0.0 30 8/14/19 1 4,114 2,689 719 0:00 0 0.0 30 8/15/19 4,126 2,688 1 725 0:00 0 0.0 30 8/16/19 4,071 2,531 725 0:00 0 0.0 30 8/17/19 4,051 2,548 713 0:00 0 0.0 30 8/18/19 3,976 2,346 704 0:00 0 0.0 30 8/19/19 3,946 2,293 690 0:00 0 0.0 30 8/20/19 3,888 2,179 690 0:00 0 0.0 30 8/21/19 1 4,116 2,440 706 0:00 0 0.0 30 8/22/19 4,121 2,564 714 0:00 0 0.0 30 8/23/19 4,069 2,440 706 0:00 1 0 0.0 30 8/24/19 4,125 2,578 717 0:00 0 0.0 30 8/25/19 4,093 2,475 718 0:00 0 0.0 30 8/26/19 3,995 1,900 725 0:00 0 0.0 35 8/27/19 4,091 2,448 704 0:00 0 0.0 35 8/28/19 1 4,131 1 2,690 754 0:00 0 0.0 35 8/29/19 4,102 2,540 701 0:00 0 0.0 35 8/30/19 4,119 2,629 6910:00 0 0.0 35 8/31/19 4,108 2,641 682 0:00 0 0.0 35 Alaska Oil and Gas Conservation Commission Safety Valve System Test Report Operator: Cook InletBnerg Submitted By: David Pascal Daic: 8/12/19 Operator Rep: Sean Sullivan Field/Unit/Pad: Osprey /Redoubt Shoal AOGCCRep: Bob Noble Separatorpsi: LPS 83 IIPS na Well Data Pilots SSVISSSVI Retest/Sl Date Well Type Well Pressu I Gas Lit Waiver Well Permit Separ Number Number PSI Set L/P PSI Tri Test Test Code Code Test Code Date Passed Retest o�i,wnc.mya. Or Date Shut In GAS, CYCLE, Si Inner Outer Tubing Yes/No PSI PSI PSI Yes/N0 3A 21617001 01 25001 24991 NT 1 9631 321 38271 no I no Welts: I Components: 0 Failures: 0 Failure Rate., o.00%❑mDay Remarks: "0" entered in "Separ PSP' to count well. IA pilot set (al 2500psi, tripped (ail 2499psi (PASS AIO 32.001 PLB 01/26/11 Page 1 of 1 SVS RD Shoal Osprey 08-12-19 Misc HPP.xlsx GLACIER August 6, 2019 Ms. Jessie Chmielowski Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: AIO 32.001 Monthly Reporting Dear Commissioner Chmielowski, AUG`0 6 26119 AOGCC As required by Area Injection Order No. 32.001 issued by the AOGCC on December 2811 2017, the monthly report involving well pressures, injection rates and pressure bleeds for all annuli for the well RU -3A for the month of July 2019 is provided to the Commission for review. There were no bleeds conducted for this month Cook Inlet Energy is currently maintaining and operating well shut-in equipment linked to the RU -3A inner annular pressure as directed. The last test of the system was conducted on February 13, 2019. The next test will be conducted during the month of August 2019 The last mechanical integrity test of the well was conducted on December 23, 2017 in presence of an AOGCC inspector. The next MIT test will be performed before or during the month of December 2019 as required by the order. In addition to the above, CIE will be following all stipulations mentioned in the order I am available at your convenience to discuss this report or provide additional information. Please contact me at (907) 433-3822 or at pascal kglacieroil.com 188 W. Northern Lights Blvd. Suite 510, Anchorage, AK 99503 (907) 334-6745 N1nin I (907) 334-6735 Fax Page I of 2 Sincerely, `q D Pascal' Vite President, Operations Cook Inlet Energy A Glacier Oil and Gas Wholly Owned Company Attachments 1. RU -3A Operations Log, July 2019 188 W. Northern U-1its Blvd. Suite 5l U..4ndxn .��e, AK 99503 3:34_1-4z.1 i; c, '1107j 334-67135 Fax Page 2 of 2 RU 3A Injection Tracking Report July 2019 Inner Annulus Outer Annulus Date Wellhead Pressure psi) Injected Volume (bbls) Avg. Pressure psi) Bleed Time Hours: Min) Total Pressure Bled (psi) Total Volume Bled (bbl) Avg. Pressure psi 7/1/19 4,135 3,195 720 0:00 0 0.0 30 7/2/19 4,140 3,220 725 0:00 0 0.0 30 7/3/19 4,132 3,192 729 0:00 0 0.0 30 7/4/19 4,110 2,933 731 0:00 0 0.0 30 7/5/19 4,126 2,770 753 0:00 0 0.0 30 7/6/19 4,156 2,689 745 0:00 0 0.0 30 7/7/19 4,157 2,784 752 0:00 0 0.0 30 7/8/19 4,156 2,708 763 0:00 0 0.0 30 7/9/19 4,099 2,647 750 0:00 0 0.0 30 7/10/19 4,074 2,516 744 0:00 0 0.0 30 7/11/19 4,058 2,561 744 0:00 0 0.0 30 7/12/19 4,058 2,613 730 0:00 0 0.0 30 7/13/19 4,132 2,761 758 0:00 0 0.0 30 7/14/19 4,096 2,807 763 0:00 0 0.0 30 7/15/19 4,095 2,845 765 0:00 1 0 0.0 30 7/16/19 4,122 2,852 767 0:00 0 0.0 30 7/17/19 4,125 2,798 769 0:00 0 0.0 30 7/18/19 4,106 2,926 736 0:00 0 0.0 30 7/19/19 4,097 2,953 676 0:00 0 0.0 30 7/20/19 4,108 2,971 680 0:00 0 0.0 30 7/21/19 4,100 2,899 742 0:00 0 0.0 30 7/22/19 4,059 2,681 793 0:00 0 0.0 30 7/23/19 4,111 2,607 676 0:00 0 0.0 30 7/24/19 4,128 2,497 687 0:00 0 0.0 30 7/25/19 4,121 2,484 687 0:00 0 0.0 30 7/26/19 4,125 2,492 686 0:00 0 0.0 30 7/27/19 4,114 2,638 689 0:00 0 0.0 30 7/28/19 4,109 2,694 693 0:00 0 0.0 30 7/29/19 4,117 1 2,743 1 693 0700 0 0.0 30 7/30/19 4,120 2,677 673 0700 0 0.0 30 7/31/19 1 4,124 2,642 697 0:00 0 0.0 30 GLACIER July 3, 2019 Ms. Jessie Chmielowski Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: AIO 32.001 Monthly Reporting Dear Commissioner Chmielowski, RECE-N D JUL C 3 2019 AOGCC As required by Area Injection Order No. 32.001 issued by the AOGCC on December 28t1, 2017, the monthly report involving well pressures, injection rates and pressure bleeds for all annuli for the well RU -3A for the month of June 2019 is provided to the Commission for review. There were no bleeds conducted for this month Cook Inlet Energy is currently maintaining and operating well shut-in equipment linked to the RU -3A inner annular pressure as directed. The last test of the system was conducted on February 13, 2019. The next test will be conducted during the month of August 2019 The last mechanical integrity test of the well was conducted on December 23, 2017 in presence of an AOGCC inspector. The next MIT test will be performed before or during the month of December 2019 as required by the order. In addition to the above, CIE will be following all stipulations mentioned in the order I am available at your convenience to discuss this report or provide additional information. Please contact me at (907) 433-3822 or at dpascaigglacieroil com 188 W. Noithern Lights Blvd. Suite 510, Anchorage, AK 99503 (907) 334-6745 Main 1 (907) 334-6735 Fax Page 1 of 2 Sincerely, q x Dav d Pascal Vi President, Operations Co k Inlet Energy A Glacier Oil and Gas Wholly Owned Company Attachments 1. RU -3A Operations Log, June 2019 188 W. Northern Lights Blvd. Suite 510, Anchorage, UI 99503 (907) 334 -674 -Main (907( 339-6735 Fac Page 2 of 2 RU 3A Injection Tracking Report June 2019 Inner Annulus Outer Annulus Date Wellhead Pressure (psi) Injected Volume (bbls) Avg. Pressure (psi) Bleed Time Total Total (Hours: Pressure Volume Min) Bled (psi) Bled (bbl) Avg. Pressure (psi) 6/1/19 4,097 3,230 585 0:00 0 0 30 6/2/19 4,105 3,291 592 0:00 1 0 0 30 6/3/19 4,105 3,326 598 0:00 0 0 30 6/4/19 4,115 3,322 607 0:00 0 0 30 6/5/19 4,116 3,330 613 0:00 0 0 30 6/6/19 4,125 3,298 621 0:00 0 0 30 6/7/19 4,127 3,283 629 0:00 0 0 30 6/8/19 4,086 3,182 629 0:00 0 0 30 6/9/19 4,065 3,067 629 0:00 0 0 30 6/10/19 4,086 3,143 637 0:00 0 0 30 6/11/19 4,075 3,135 633 0:00 0 0 30 6/12/19 4,087 3,119 619 0:00 0 0 30 6/13/19 4,092 3,150 622 0:00 0 0 30 6/14/19 4,086 3,083 625 0:00 0 0 30 6/15/19 4,074 3,098 626 0:00 0 0 30 6/16/19 4,060 3,135 629 0:00 0 0 30 6/17/19 4,046 3,122 636 0:00 0 0 30 6/18/19 4,007 3,061 639 0:00 0 0 30 6/19/19 4,031 3,034 645 0:00 0 0 30 6/20/19 4,083 2,867 651 0:00 0 0 30 6/21/19 4,063 2,935 654 0:00 0 0 30 6/22/19 4,049 2,945 660 0:00 0 0 30 6/23/19 4,020 2,948 670 0:00 0 0 30 6/24/19 4,055 2,751 679 0:00 0 0 30 6/25/19 4,052 2,879 681 0:00 0 0 30 6/26/19 3,977 3,033 689 0:00 0 0 30 6/27/19 3,961 3,060 697 0:00 0 0 30 6/28/19 4,057 3,273 716 0:00 0 0 30 6/29/19 4,130 3,365 722 0:00 0 0 30 6/30/19 4,125 3,334 720 0:00 0 0 30 < . r q GLACIER June 5, 2019 Ms. Jessie Chmielowski Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: AIO 32.001 Monthly Reporting Dear Commissioner Chmielowski, ,G NE® juN 0 5 91019 As required by Area Injection Order No. 32.001 issued by the AOGCC on December 28th, 2017, the monthly report involving well pressures, injection rates and pressure bleeds for all annuli for the well RU -3A for the month of May 2019 is provided to the Commission for review. There were no bleeds conducted for this month Cook Inlet Energy is currently maintaining and operating well shut-in equipment linked to the RU -3A inner annular pressure as directed. The last test of the system was conducted on February 13, 2019. The next test will be conducted during the month of August 2019 The last mechanical integrity test of the well was conducted on December 23, 2017 in presence of an AOGCC inspector. The next MIT test will be performed before or during the month of December 2019 as required by the order. In addition to the above, CIE will be following all stipulations mentioned in the order I am available at your convenience to discuss this report or provide additional information. Please contact me at (907) 433-3822 or at dpascalna Qlacieroil.com 188 W. Northern Lights Blvd. Suite 510, Anchorage, AK 99503 (907)334-6745 Alain 1 (907) 334-6735 Fax Page 1 of 2 Sincerely, 6� D d Pascal Vic President, Operations Co k Inlet Energy A Glacier Oil and Gas Wholly Owned Company Attachments 1. RU -3A Operations Log, May 2019 tH8 W. Nori he rn Lights Blind. Suite 510, Anchora-le, AK 995113 Page 2 of 2 RU 3A Injection Tracking Report May 2019 Inner Annulus Outer Annulus Date Wellhead Pressure (psi) Injected Volume bbis) Avg. Pressure (psi Bleed Time Hours: Min Total Pressure Bled(psi) Total Volume Bled bbl(psi) Avg. Pressure 5/1/19 4,120 2,947 463 0:00 0 0 30 5/2/19 4.126 2.981 467 0:00 0 0 30 5/3/19 4,115 2,949 468 0:00 0 0 30 5/4/19 4,122 3,013 473 0:00 0 0 30 5/5/19 4,132 3,062 480 0:00 0 0 30 5/6/19 4,127 3,057 479 0:00 0 0 30 5/7/19 4,119 3 064 479 0:00 0 0 30 5/8/19 4,119 3.083 470 0:00 0 0 30 5/9/19 4,122 3,074 494 0:00 0 0 30 5/10/19 4,124 3,141 501 0:00 1 0 0 30 5/11/19 4,119 3,086 502 0:00 0 0 30 5/12/19 4,119 3,070 505 0:00 0 0 30 5/13/19 4,118 3.077 510 0:00 0 0 30 5/14/19 4,116 3,070 514 0:00 0 0 30 5/15/19 4,125 3,071 518 0:00 0 0 30 5/16/19 4,123 3,080 521 0:00 0 0 30 5/17/19 4,122 2,987 522 0:00 0 0 30 5/18/19 4,106 2,963 521 0:00 0 0 30 5/19/19 4,116 2.944 525 0:00 0 0 30 5/20/19 4,102 2,965 528 0:00 0 0 30 5/21/19 4,112 2,941 531 0:00 0 0 30 5/22/19 4,120 2,990 535 0:00 0 0 30 5/23/19 4,109 3,008 537 0:00 0 0 30 5/24/19 4,111 3,034 541 0:00 0 0 30 5/25/19 4,112 3.003 548 0:00 0 0 30 5/26/19 4,113 3,095 539 0:00 0 0 30 5/27/19 4,104 3,056 542 0:00 0 0 30 5/28/19 4,127 2 898 561 0:00 0 0 30 5/29/19 4,079 2-19-10- 567 0:00 0 0 30 5/30/19 4128 3139 577 0:00 0 0 30 5/31/19 4114 3191 580 1:00 0 7-1 30 GLACIER May 6, 2019 Ms. Jessie Chmielowski Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: AIO 32.001 Monthly Reporting Dear Commissioner Chmielowski, C BEV MAY 0 6 2019 AOGCC As required by Area Injection Order No. 32.001 issued by the AOGCC on December 28tH 2017, the monthly report involving well pressures, injection rates and pressure bleeds for all annuli for the well RU -3A for the month of April 2019 is provided to the Commission for review. There were no bleeds conducted for this month Cook Inlet Energy is currently maintaining and operating well shut-in equipment linked to the RU -3A inner annular pressure as directed. The last test of the system was conducted on February 13, 2019. The next test will be conducted during the month of August 2019 The last mechanical integrity test of the well was conducted on December 23, 2017 in presence of an AOGCC inspector. The next MIT test will be performed before or during the month of December 2019 as required by the order. In addition to the above, CIE will be following all stipulations mentioned in the order I am available at your convenience to discuss this report or provide additional information. Please contact me at (907) 433-3822 or at d ap scalkglacieroil.com 188 W. Northern Lights Blvd. Suite 510, Anchorage, AK 99503 (907) 334-6745 Main 1 (907) 334-6735 Fax Page 1 of 2 Sincerely, _ Datid Pascal Vice President, Operations Cook Inlet Energy A Glacier Oil and Gas Wholly Owned Company Attachments I. RU -3A Operations Log, April 2019 IRR M. Northern Lights Blvd. Suite 510, Auchorage, AK 99403 (907) 334-6745 :Main (907) 334-673.5 Fax Page 2 of 2 I RU 3A Iniection Tracking Report April 2019 1 Inner Annulus OuterAnnulus Date Wellhead Pressure (psi) Injected Volume (bbls) Avg. Pressure (psi) Bleed Time (Hours: Min) Total Pressure Bled psi Total Volume Bled (bbl) Avg. Pressure (psi) 4/1/19 4,052 3,306 383 0:00 0 25 25 4/2/19 4,065 3,292 384 0:00 0 25 25 4/3/19 4,082 3,236 386 0:00 0 30 30 4/4/19 4,082 3,188 387 0:00 0 30 30 4/5/19 4,096 3,226 388 0:00 0 25 25 4/6/19 4,122 3,310 394 0:00 0 30 30 4/7/19 4,107 3,256 395 0:00 0 30 30 4/8/19 4,110 3,278 400 0:00 0 30 30 4/9/19 4107 3,280 403 0:00 0 30 25 4/10/19 4,114 3,269 408 0:00 0 30 25 4/11/19 4,115 3,276 411 0:00 0 30 25 4/12/19 4,109 3,273 413 0:00 0 30 20 4/13/19 4,123 3,279 419 0:00 0 30 25 4/14/19 4,126 3,275 423 1 0:00 0 30 25 4/15/19 4,047 2,968 421 0:00 0 30 25 4/16/19 4,127 3,220 423 0:00 0 30 25 4/17/19 4,119 3,234 429 0:00 0 30 25 4/18/19 4,116 3,207 430 0:00 0 30 25 4/19/19 4,125 3,173 432 0:00 0 30 25 4/20/19 4,115 3,096 434 0:00 0 30 25 4/21/19 4,087 3,040 1 429 0:00 0 30 25 4/22/19 4,070 2,926 430 0:00 0 30 25 4/23/19 4,092 2,887 429 0:00 0 30 25 4/24/19 4,095 3,007 436 0:00 0 30 25 4/25/19 4,096 2,982 442 0:00 0 30 25 4/26/19 4,112 3,003 448 0:00 0 30 25 4/27/19 4,105 3,014 454 0:00 1 0 30 25 4/28/19 4,118 2,973 457 0:00 0 30 25 4/29/19 4,121 1 3,000 460 0:00 0 30 25 4/30/19 4,120 3,012 461 0:00 0 30 25 GLACIER April 9, 2019 Ms. Cathy Foerster Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: AIO 32.001 Monthly Reporting Dear Commissioner Foerster, APR 0 9 2019 AOGCC As required by Area Injection Order No. 32.001 issued by the AOGCC on December 281 2017, the monthly report involving well pressures, injection rates and pressure bleeds for all annuli for the well RU -3A for the month of March 2019 is provided to the Commission for review. There were no bleeds conducted for this month Cook Inlet Energy is currently maintaining and operating well shut-in equipment linked to the RU -3A inner annular pressure as directed. The last test of the system was conducted on February 13, 2019. The next test will be conducted during the month of August 2019 The last mechanical integrity test of the well was conducted on December 23, 2017 in presence of an AOGCC inspector. The next MIT test will be performed before or during the month of December 2019 as required by the order. In addition to the above, CIE will be following all stipulations mentioned in the order I am available at your convenience to discuss this report or provide additional information. Please contact me at (907) 433-3822 or at dpascal(c>> alacieroil.com 188 w. Northern Lights Blvd. Suite 510, Anchorage, AK 99.503 (907) 334-6745 Main 1 (907) 334-6735 Fax Page 1 of 2 Sincerely, 01) Vicq President, Operations Co Inlet Energy A Olacier Oil and Gas Wholly Owned Company Attachments 1. RU -3A Operations Log, March 2019 I8"S \i', iNorrheIII I-w4k lllod. Suite 510, Am ho h 99~113 (90-) 334-1,7145, NL,in (90-) 33.3-07, Page 2 of 2 RU 3A Injection Tracking Report March 2019 Inner Annulus OuterAnnulus Date Wellhead Pressure (psi) Injected Volume (bbls Avg. Pressure (psi) Bleed Time (Hours: Min Total Pressure Bled (psi) Total Volume Bled (bbl) Avg. Pressure (psi) 3/1/19 4,131 2,979 340 0:00 0 0.0 25 3/2/19 4,128 2,990 339 0:00 0 0.0 25 3/3/19 4,128 3,000 337 0:00 0 0.0 30 3/4/19 4,126 2,995 337 0:00 0 0.0 30 3/5/19 4,131 3,027 337 0:00 0 0.0 25 3/6/19 4,134 3,024 336 0:00 0 0.0 30 3/7/19 4,131 3,032 335 0.00 0 0.0 30 3/8/19 4,130 3,038 335 0:00 0 0.0 30 3/9/19 4,134 3,007 338 1 0:00 0 1 0.0 25 3/10/19 4,130 2,906 337 0:00 0 0.0 25 3/11/19 4,102 3,061 339 0:00 0 0.0 25 3/12/19 4,111 3,043 340 0:00 0 0.0 20 3/13/19 4,104 3,063 340 0:00 0 0.0 25 3/14/19 4,109 3,055 342 0:00 0 0.0 25 3/15/19 4,119 3,051 345 0:00 0 0.0 25 3/16/19 4,079 2,809 344 0:00 0 0.0 25 3/17/19 4,123 3,140 346 0:00 0 0.0 25 3/18/19 4,132 3,173 349 0:00 0 0.0 25 3/19/19 4,141 3,211 350 0:00 0 0.0 25 3/20/19 4,140 3,203 351 0:00 0 0.0 25 3/21/19 4,105 3,215 353 0:00 0 0.0 25 3/22/19 4,114 3,006 352 0:00 0 0.0 25 3/23/19 4,125 3,047 354 0:00 0 0.0 25 3/24/19 4,124 3,058 358 0:00 0 0.0 25 3/25/19 4,127 3,065 364 0:00 0 0.0 25 3/26/19 4,126 3,074 367 0:00 0 0.0 25 3/27/19 4,133 3,069 371 0:00 1 0 0.0 25 3/28/19 3,725 2,349 387 0:00 0 0.0 25 3/29/19 4,068 3,233 373 0:00 0 0.0 25 3/30/19 4,056 3,247 378 0:00 0 0.0 25 3/31/19 4,046 1 3,305 380 0:00 0 0.0 25 GLACIER March 5, 2019 Ms. Cathy Foerster Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: AIO 32.001 Monthly Reporting Dear Commissioner French, �-,_.: ,pot, —WE . n e t1 F svy� Gia �S Lm�' MAR C 7 2019 AOGCC As required by Area Injection Order No. 32.001 issued by the AOGCC on December 2811 2017, the monthly report involving well pressures, injection rates and pressure bleeds for all annuli for the well RU -3A for the month of February 2019 is provided to the Commission for review. There were no bleeds conducted for this month Cook Inlet Energy is currently maintaining and operating well shut-in equipment linked to the RU -3A inner annular pressure as directed. The last test of the system was conducted on February 13, 2019. The next test will be conducted during the month of August 2019 The last mechanical integrity test of the well was conducted on December 23, 2017 in presence of an AOGCC inspector. The next MIT test will be performed before or during the month of December 2019 as required by the order. In addition to the above, CIE will be following all stipulations mentioned in the order I am available at your convenience to discuss this report or provide additional information. Please contact me at (907) 433-3822 or at dpascal@placieroil.com 188 W. Northern Lights Blvd. Suite 510, Anchorage, AK 99503 (907) 334-6745 Main (907) 334-6735 Fax Page 1 of 2 Sincerely, vid Pascal Vice President, Operations Cook Inlet Energy A Glacier Oil and Gas Wholly Owned Company Attachments 1. RU -3A Operations Log, February 2019 2. RU -3A Inner Annulus Automatic Shutdown Test February 2019 188 W. Nart he rn Lights Blvd. Suite 510. Anchorage, AK 99503 (907) 334-6745 Main I (907) 334-6735 Psis Page 2 of 2 RU 3A Injection Tracking Report February 2019 Inner Annulus OuterAnnulus Date Wellhead Pressure (psi) Injected Volume (bbls) Avg. Pressure psi Bleed Time (Hours: Min Total Pressure Bled (psi) Total Volume Bled bbl Avg. Pressure (psi 2/1/19 4,140 1 2,973 344 0:00 0 0.0 30 2/2/19 4,135 2,940 342 0:00 1 0 0.0 30 2/3/19 4,139 2,955 340 0:00 0 0.0 30 2/4/19 4,128 2,907 339 0:00 0 0.0 30 2/5/19 4,126 2,908 338 0:00 0 0.0 30 2/6/19 4,124 2,920 337 0:00 0 0.0 30 2/7/19 4,128 2,918 338 0:00 0 0.0 30 2/8/19 4,099 2,869 490 0:00 0 0.0 30 2/9/19 4,125 2,907 337 0:00 0 0.0 30 2/10/19 4,127 2,913 337 0:00 0 0.0 30 2/11/19 4,127 2,917 340 0:00 0 0.0 25 2/12/19 4,131 2,939 342 0:00 0 0.0 25 2/13/19 4,090 2,816 340 0:00 0 0.0 25 2/14/19 4,117 3,148 340 0:00 0 0.0 25 2/15/19 4,115 3,144 340 0:00 0 0.0 25 2/16/19 4,126 3,175 338 0:00 0 0.0 25 2/17/19 4,106 3,140 335 0:00 0 0.0 25 2/18/19 4,111 3,158 334 0:00 0 0.0 25 2/19/19 4,130 3,139 335 0:00 0 0.0 25 2/20/19 4,133 3,109 336 0:00 0 0.0 25 2/21/19 4,137 3,097 335 0:00 0 0.0 25 2/22/19 4,143 3,066 337 0:00 0 0.0 25 2/23/19 4,132 2,978 337 0:00 0 0.0 25 2/24/19 4,130 2,978 336 0:00 0 0.0 25 2/25/19 4,133 2,984 335 0:00 0 0.0 25 2/26/19 4,134 2,970 336 0:00 0 0.0 25 2/27/19 4,128 2,991 338 0:00 0 0.0 25 2/28/19 4,125 3,004 340 0:00 0 0.0 25 Alaska Oil and Gas Conservation Commission Safety Valve System Test Report Operator: Cook Inlet Ener@ Submitted By: David Pascal Date: 2/13/19 Operator Rep: Lance Anderson Field/Unit/Pad: Osprey /Redoubt Shoal AOGCC Rep: waived Separator psi: LPS 83 HPS no Well Data Pilots SSV SSSV Retest/SI Date Well Type Well Pressures Gas Lit Waiver Well Permit Separ Number Number PSI Set UP Test PSI Trip Code Test Code Test Date Passed Retest 0iJ wAG,GtNJ, Inner Outer Tubing Yes/No Ves/No Code Or Date Shut In GAS,CYCLE,SI PSI PSI PSI 3A 2161700 0 2500 2499 NT NT NT 342 25 3833 no no Wells: 1 Components: 1 Failures: 0 Failure Rate. 0.00% ❑ so w Remarks: "0" entered in "Separ PSI" to count well. IA pilot set @ 2500psi tripped @ 2499psi (PASS AIO 32.001 PLB 01/26/11 Page 1 of 1 SVS RD Shoal Osprey 02-13-18 Misc.xlsx GLACIER Feb 12, 2019 Mr. Hollis French Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: AIO 32.001 Monthly Reporting Dear Commissioner French, "�X 0�L"E FEB 12 2m AOGCC As required by Area Injection Order No. 32.001 issued by the AOGCC on December 28th, 2017, the monthly report involving well pressures, injection rates and pressure bleeds for all annuli for the well RU -3A for the month of January 2019 is provided to the Commission for review. There were no bleeds conducted for this month. Cook Inlet Energy is currently maintaining and operating well shut-in equipment linked to the RU -3A inner annular pressure as directed. The last test of the system was conducted on August 14, 2018. The next test will be conducted during the month of February 2019 The last mechanical integrity test of the well was conducted on December 23, 2017 in presence of an AOGCC inspector. The next MIT test will be performed before or during the month of December 2019 as required by the order. In addition to the above, CIE will be following all stipulations mentioned in the order. I am available at your convenience to discuss this report or provide additional information. Please contact me at (907) 433-3822 or at doascalna glacieroil.com 601 w. 5"A\'enne, Suite 310, Anchmrige, AK 99501 (9n7) ;34-6741 M11�in I f907V334-6735 Fax Page 1 of 2 Sincerely, vi President, Operations Coo Inlet Energy A Glacier Oil and Gas Wholly Owned Company Attachments 1. RU -3A Operations Log, January 2019 Page 2 of 2 RU 3A Injection Tracking Report January 2019 Inner Annulus uter Annulus Date 1/1/19 Wellhead Pressure (psi) 4,094 Injected Volume (bbls) 2,998 Avg. Pressure (psi) 401 Bleed Time (Hours: Min) 0:00 Total Pressure Bled (psi) 0 Total Volume Bled (bbl) 0.0 Avg. Pressure (psi) 30 1/2/19 4,097 2,989 400 0:00 0 0.0 30 1/3/19 4,097 2,993 397 0:00 0 0.0 30 1/4/19 4,103 2,973 392 0:00 0 0.0 30 1/5/19 4,105 2,967 387 0:00 0 0.0 30 1/6/19 4,101 2,978 384 0:00 0 0.0 30 1/7/19 4,097 2,983 380 0:00 0 0.0 30 1/8/19 4,098 2,982 375 0:00 0 0.0 30 1/9/19 4,098 2,981 373 0:00 0 0.0 30 1/10/19 4,097 2,980 373 0:00 0 0.0 30 1/11/19 4,108 2,965 366 0:00 0 0.0 30 1/12/19 4,109 2,949 359 0:00 0 0.0 30 1/13/19 41107 2,964 328 0:00 0 0.0 30 1/14/19 41098 2,971 360 0:00 0 0.0 30 1/15/19 4,104 2,949 360 0:00 0 0.0 30 1/16/19 4,069 2,828 357 0:00 0 0.0 30 1/17/19 4,109 3,080 351 0:00 0 0.0 30 1/18/19 4,115 3,103 351 0:00 0 0.0 30 1/19/19 4,124 3,084 349 0:00 0 0.0 30 1/20/19 4,128 3,074 347 0:00 0 0.0 30 1/21/19 4,127 3,089 344 0:00 0 0.0 30 1/22/19 4,138 3,115 343 0:00 0 0.0 30 1/23/19 4,134 3,107 344 0:00 0 0.0 30 1/24/19 3,878 3,089 346 0:00 0 0.0 30 1/25/19 4,135 3,064 345 0:00 0 0.0 30 1/26/19 411201 113 344 0:00 0 0.0 30 1/27/19 4,139 3,050 345 0:00 0 0.0 30 1/28/19 4,116 3,058 344 0:00 0 0.0 30 1/29/19 4,123 3,080 342 0:00 0 0.0 30 1/30/ 9 1/31/ 9 4,134 4,130 3,113 3,036 342 345 0:00 0:00 0 0 0.0 0.0 30 30 GLACIER Jan 16, 2019 Mr. Hollis French Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: AIO 32.001 Monthly Reporting Dear Commissioner French, RECEIVE® JAN 16 2019 AOGCC As required by Area Injection Order No. 32.001 issued by the AOGCC on December 28`n 2017, the monthly report involving well pressures, injection rates and pressure bleeds for all annuli for the well RU -3A for the month of December 2018 is provided to the Commission for review. There were no bleeds conducted for this month Cook Inlet Energy is currently maintaining and operating well shut-in equipment linked to the RU -3A inner annular pressure as directed. The last test of the system was conducted on August 14, 2018. The next test will be conducted during the month of February 2019 The last mechanical integrity test of the well was conducted on December 23, 2017 in presence of an AOGCC inspector. The next MIT test will be performed before or during the month of December 2019 as required by the order. In addition to the above, CIE will be following all stipulations mentioned in the order I am available at your convenience to discuss this report or provide additional information. Please contact me at (907) 433-3822 or at dpascal aaglacicroil.com Page 1 of 2 Sincerely, er David ascal Vice P esident, Operations Cook Inlet Energy A Glacier Oil and Gas Wholly Owned Company Attachments 1. RU -3A Operations Log, December 2018 601 W. 5"' ANenue, Suite 310, Anchorage, AK 99501 (907) 334-6745 (Main 1(907) 334-6735 Fax Page 2 of 2 RU 3A Injection Tracking Report December 2018 Inner Annulus OuterAnnutus Date Wellhead Pressure psi Injected Volume bbls Avg. Bleed Time Pressure (Hours: psi Min Total Total Pressure Volume Bled psi Bled bbl Avg. Pressure psi 12/1/18 4,121 3,120 489 0:00 0 0.0 30 12/2/18 4116 3,133 485 0:00 0 0.0 30 12/3/18 4,106 3,164 484 0:00 0 0.0 30 12/4/18 4,100 3,181 480 0:00 0 0.0 30 12/5/18 4,112 3,171 477 0:00 0 0.0 30 12/6/18 4,118 3,159 478 0:00 0 0.0 30 12/7/18 4,124 3,153 1 477 0:00 0 0.0 30 12/8/18 4,127 3,146 476 0:00 0 0.0 30 12/9/18 4135 3,114 474 0:00 0 0.0 30 12/10/18 4,092 2,908 461 0:00 0 0.0 30 12/11/18 4,076 3,054 457 0:00 0 0.0 30 12/12/18 4,116 3,143 458 0:00 0 0.0 30 12/13/18 4,114 3,113 455 0:00 0 0.0 30 12/14/18 4,120 1 3116 446 1 0:00 0 0.0 30 12/15/18 4,080 3,019 434 0:00 1 0 0.0 30 12/16/18 4,110 3,145 435 0:00 0 0.0 30 12/17/18 4,120 3,159 436 0:00 0 0.0 30 12/18/18 4,141 3,126 432 0:00 0 0.0 30 12/19/18 4,122 3,050 425 0:00 0 0.0 30 12/20/18 4,115 3,035 419 0:00 0 0.0 30 12/21/18 4,110 3,039 1 417 0:00 0 0.0 30 12/22/18 4,121 3,046 414 0:00 0 0.0 30 12/23/18 4,128 3,034 417 0:00 0 0.0 30 12/24/18 4,121 3,048 417 0:00 0 0.0 30 12/25/18 4,131 3,036 413 0:00 0 0.0 30 12/26/18 4,131 3,028 412 0:00 0 0.0 30 12/27/18 4,100 2,987 412 0:00 0 0.0 30 12/28/18 4,097 2,963 412 0:00 0 0.0 30 12/29/18 4,110 2,945 408 0100 0 0.0 30 12/30/18 4,085 3,022 403 0:00 0 0.0 30 12/31/18 4,089 3,023 401 0:00 0 0.0 30 GLACIER Dec 7, 2018 Mr. Hollis French Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: AIO 32.001 Monthly Reporting Dear Commissioner French, W c tii ia'E OEC [ 7 2098 AOGCC As required by Area Injection Order No. 32.001 issued by the AOGCC on December 28th, 2017, the monthly report involving well pressures, injection rates and pressure bleeds for all annuli for the well RU -3A for the month of November 2018 is provided to the Commission for review. There were no bleeds conducted for this month Cook Inlet Energy is currently maintaining and operating well shut-in equipment linked to the RU -3A inner annular pressure as directed. The last test of the system was conducted on August 14, 2018. The next test will be conducted during the month of February 2019 The last mechanical integrity test of the well was conducted on December 23, 2017 in presence of an AOGCC inspector. The next MIT test will be performed before or during the month of December 2019 as required by the order. In addition to the above, CIE will be following all stipulations mentioned in the order I am available at your convenience to discuss this report or provide additional information. Please contact me at (907) 433-3822 or at dpascalkizlacieroil.com 601 \n' ! "� A veuu e, Sui(e 310, A acho rade, A% 99501 Page 1 of 2 Sincerely, David ascal \ Vice President, Operations Cook Inlet Energy A Glacier Oil and Gas Wbolly Owned Company Attachments I. RU -3A Operations Log, November 2018 Page 2 of 2 RU 3A Injection Tracking Report November 2018 Inner Annulus Outer Annulus Date Wellhead Pressure (psi) Injected Volume (bbls) Avg. Pressure (psi) Bleed Time Total Pressure Total Volume (Hours: Min) Bled (psi) Bled (bbl) Avg. Pressure (psi) 11/1/18 4,072 3,070 599 0:00 0 0.0 30 11/2/18 4,087 3,066 592 0:00 0 0.0 30 11/3/18 4,011 2,857 1 585 0:00 0 0.0 30 11/4/18 4,060 3,108 572 0:00 0 0.0 30 11/5/18 4,073 2,967 572 0:00 0 0.0 30 11/6/18 4,082 2,977 568 0:00 0 0.0 30 11/7/18 4,085 2,988 563 0:00 0 0.0 30 11/8/18 4,082 2,985 559 0:00 0 0.0 30 11/9/18 4,093 2,957 557 0:00 0 0.0 30 11/10/18 4,103 2,956 552 0:00 0 0.0 30 11/11/18 4,107 2,974 538 0:00 0 0.0 30 11/12/18 4,084 3,022 537 0:00 0 0.0 30 11/13/18 4,117 3,128 544 0:00 0 0.0 30 11/14/18 4,104 3,049 545 0:00 0 0.0 30 11/15/18 4,079 3,030 538 0:00 0 0.0 30 11/16/18 4,088 3,012 528 0:00 0 0.0 30 11/17/18 4,089 3,031 521 0:00 0 0.0 30 11/18/18 4,094 3,038 521 0:00 0 0.0 30 11/19/18 4,076 3,110 520 0:00 0 0.0 30 11/20/18 4,066 3,073 521 0:00 0 0.0 30 11/21/181 4,076 3,046 519 0:00 0 0.0 30 11/22/18 4,074 3,050 515 0:00 0 0.0 30 11/23/18 4,080 3,039 510 0:00 0 0.0 30 11/24/18 4,076 3,053 504 0:00 0 0.0 30 11/25/18 4,076 3,052 501 0:00 0 0.0 30 11/26/18 4,063 3,084 502 0:00 0 0.0 30 11/27/18 4,066 3,086 503 0:00 0 0.0 30 11/28/18 4,072 3,104 502 0:00 0 0.0 30 11/29/18 4,099 3,208 503 0:00 0 0.0 30 11/30/18 4,116 3,106 497 0.00 0 0.0 30 GLACIER Nov 8, 2018 Mr. Hollis French Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: AIO 32.001 Monthly Reporting Dear Commissioner French, RECEIVED NOV 0 8 2018 AOGCC As required by Area Injection Order No. 32.001 issued by the AOGCC on December 281, 2017, the monthly report involving well pressures, injection rates and pressure bleeds for all annuli for the well RU -3A for the month of October 2018 is provided to the Commission for review. There were no bleeds conducted for this month Cook Inlet Energy is currently maintaining and operating well shut-in equipment linked to the RU -3A inner annular pressure as directed. The last test of the system was conducted on August 14, 2018. The next test will be conducted during the month of February 2019 The last mechanical integrity test of the well was conducted on December 23, 2017 in presence of an AOGCC inspector. The next MIT test will be performed before or during the month of December 2019 as required by the order. In addition to the above, CIE will be following all stipulations mentioned in the order I am available at your convenience to discuss this report or provide additional information. Please contact me at (907) 433-3822 or at dnascalkglacieroil.com (Ot R.5'".A.cemre. S,Lwc 9I0, dnchmigxe. A 99501 '". P1::i❑ Il9I'/)'.--.- "'l.5 P�i)_ Page I of 2 Sincerely, D id Pascal Vice President, Operations Cook Inlet Energy A Glacier Oil and Gas Wholly Owned Company Attachments 1. RU -3A Operations Log, October 2018 Page 2 of 2 RU 3A Injection Tracking Report October 2018 Inner Annulus Outer Annulus Date Wellhead Pressure (psi) Injected Volume (bbls) Avg. Pressure (psi) Bleed Time (Hours: Min) Total Pressure Bled (psi) Total Volume Bled (bbl) Avg. Pressure (psi) 10/1/18 4,158 3,107 836 0:00 0 0.0 30 10/2/18 1 4,161 3,053 837 0:00 0 0.0 30 10/3/18 4,179 3,039 808 1 0:00 0 0.0 30 10/4/18 4,159 3,055 721 0:00 0 0.0 30 10/5/18 4,178 3,024 822 0:00 0 0.0 30 10/6/18 4,188 2,980 774 0:00 0 0.0 30 10/7/18 4,183 2,930 758 0:00 0 0.0 30 10/8/18 4,170 2,883 754 0:00 0 0.0 30 10/9/18 3,977 2,283 771 0:00 0 0.0 30 10/10/18 3,977 2,666 812 0:00 0 0.0 30 10/11/18 4,132 2,971 738 0:00 0 0.0 30 10/12/18 4,127 2,975 706 0:00 0 0.0 30 10/13/18 4,153 3,190 678 0:00 0 0.0 30 10/14/18 4,169 3,315 677 0:00 0 0.0 30 10/15/181 4,130 3,336 671 0:00 0 0.0 30 10/16/18 4,058 3,144 664 0:00 0 0.0 30 10/17/18 4,093 3,241 682 0:00 0 0.0 30 10/18/18 4,127 3,408 692 0:00 0 0.0 30 10/19/18 4,125 3,312 686 0:00 0 0.0 30 10/20/18 4,062 2,990 672 0:00 0 0.0 30 10/21/18 4,010 2,954 656 0:00 0 0.0 30 10/22/18 4,007 3,001 654 0:00 0 0.0 30 10/23/18 4,069 2,983 650 0:00 0 0.0 30 10/24/18 4,080 2,976 641 0:00 0 0.0 30 10/25/18 4,076 2,947 638 0:00 0 0.0 30 10/26/18 3,860 2,336 663 0:00 0 0.0 30 10/27/18 3,888 2,225 656 0:00 0 0.0 30 10/28/18 3,918 2,383 627 0:00 0 0.0 30 10/29/18 3,828 2,184 625 0:00 0 0.0 30 10/30/18 4,085 3,399 609 0:00 0 0.0 30 10/31/18 4,060 3,092 607 0:00 0 0.0 30 r; GLACIER Oct 10, 2018 Mr. Hollis French Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: AID 32.001 Monthly Reporting Dear Commissioner French, OCT i ��t As required by Area Injection Order No. 32.001 issued by the AOGCC on December 28`h, 2017, the monthly report involving well pressures, injection rates and pressure bleeds for all annuli for the well RU -3A for the month of September 2018 is provided to the Commission for review. There were no bleeds conducted for this month Cook Inlet Energy is currently maintaining and operating well shut-in equipment linked to the RU -3A inner annular pressure as directed. The last test of the system was conducted on August 14, 2018. The next test will be conducted during the month of February The last mechanical integrity test of the well was conducted on December 23, 2017 in presence of an AOGCC inspector. The next MIT test will be performed before or during the month of December 2019 as required by the order. In addition to the above, CIE will be following all stipulations mentioned in the order I am available at your convenience to discuss this report or provide additional information. Please contact me at (907) 433-3822 or at dpascalADglacieroil. coin 601 W. 5" Avenue, Suite 310, Anchorage, AK 99501 (907) 334-6745 Main (907) 334-6735 Fax Page 1 of 2 Sincerely, Dad Pascal Vic President, Operations Cook Inlet Energy A Glacier Oil and Gas Wholly Owned Company Attachments 1. RU -3A Operations Log, September 2018 601 W. 5'h Avenue, Suite 310, Anchorage, AK 99501 (907)334-6745 Main 1(907)334-6735 Fax Page 2 of 2 RU 3A Injection Tracking Report September 2018 Inner Annulus Duter Annulus Date Wellhead Pressure (psi) Injected Volume (bbls) Avg. Pressure (psi) Bleed Time (Hours: Min) Total Pressure Bled (psi) Total Volume Bled (bbl) Avg. Pressure (psi) 9/1/18 3,946 3,153 825 0:00 0 0.0 30 9/2/18 1 3,810 2,472 793 0:00 0 0.0 30 9/3/18 3,916 2,785 810 0:00 0 0.0 30 9/4/18 3,872 2,522 805 0:00 0 0.0 30 9/5/18 3,944 2,771 826 0:00 0 0.0 30 9/6/18 3,877 2,506 812 0:00 0 0.0 30 9/7/18 4,012 3,130 807 0:00 0 0.0 30 9/8/18 4,002 3,618 811 0:00 0 0.0 30 9/9/18 4,181 3,487 803 0:00 0 0.0 30 /10/18 4,185 3,396 804 0:00 0 0.0 30 /11/18 [C-9/1 4,183 3,314 805 0:00 0 0.0 30 /12/18 4,181 3,259 809 0:00 0 0.0 30 3/18 4,184 3,266 810 0:00 0 0.0 30 9/14/18 4,168 3,167 809 0:00 0 0.0 30 9/15/18 4,186 3,249 797 0:00 0 0.0 30 9/16/18 4,187 3,217 811 0:00 0 0.0 30 9/17/18 4,188 3,203 816 0:00 0 0.0 30 9/18/18 4,188 3,186 817 0:00 0 0.0 30 9/19/18 4,186 3,159 822 0:00 0 0.0 30 9/20/18 4,187 3,140 819 0:00 0 0.0 30 9/21/18 4,179 3,097 829 0:00 0 0.0 30 9/22/18 4,168 3,083 820 0:00 0 0.0 30 9/23/18 4,172 3,093 794 0:00 0 0.0 30 9/24/18 4,187 3,128 789 0:00 0 0.0 30 9/25/18 4,188 3,093 783 0:00 0 0.0 30 9/26/18 4,019 3,090 763 0:00 0 0.0 30 9/27/18 4,148 3,019 744 0:00 0 0.0 30 9/28/18 4,064 2,701 780 0:00 0 0.0 30 9/29/18 4,036 3,195 737 0:00 0 0.0 30 9/30/18 3,779 3,112 812 0:00 0 0.0 30 Cook Inlet Energy_ Oct 10, 2018 Mr. Hollis French, Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: Other Order 115 Monthly Reporting Dear Commissioner French, As required by Other Order 115 issued by the AOGCC on February 28'", 2017, the monthly report addressing the performance, sampling and maintenance of the multiphase flow meters for the month of August 2018 is provided to the Commission for review Certified Cook Inlet Energy employees performed the EPR, FPR, and transmitter calibrations on Sep 5" and Sep 61h on the Vx spectra at both locations. Throughout the month, the meters performed as expected, within the mandated ranges. Also, attached are the detailed gas analysis reports for both locations I am available at your convenience to discuss this report or provide additional information. Please don't hesitate to contact me at (907) 433-3822 or at dpascalgjzlacieroil.com Sincere fJ Davi ascal Vice resident, Operations Cook Inlet Energy 601 W. 51" Avenue, Suite 310, Anchorage, AK 99501 (907) 334-6745 Main 1 (907) 334-6735 Fax Page 1 of 1 Attachments 1. Redoubt Multiphase Meter Daily Log 2. Redoubt Multiphase Meter Event Log 3. Redoubt Multiphase Meter Daily Measurements 4. Redoubt Gas Analysis 5. Redoubt Multiphase Meter Calibration Report 6. WMRU Multiphase Meter Daily Log 7. WMRU Multiphase Meter Event Log 8. WMRU Multiphase Meter Daily Measurements 9. WMRU Gas Analysis 10. WMRU Multiphase Meter Calibration Report 601 W. 5'" Avenue, Suite 310, Anchorage, AK 99501 (907) 334-6745 Main 1 (907) 334-6735 Fax Page 2 of 2 Attachments 1. Redoubt Multiphase Meter Daily Log 2. Redoubt Multiphase Meter Event Log 3. Redoubt Multiphase Meter Daily Measurements 4. Redoubt Gas Analysis 5. Redoubt Multiphase Meter Calibration Report 6. WMRU Multiphase Meter Daily Log 7. WMRU Multiphase Meter Event Log 8. WMRU Multiphase Meter Daily Measurements 9. WMRU Gas Analysis 10. WMRU Multiphase Meter Calibration Report 601 W. V Avenue, Suite 310, Anchorage, AK 99501 (907) 334-6745 Main 1 (907) 334-6735 Fax Page 2 of 2 1. Redoubt Multiphase Meter Daily Log Redoubt MPFM Daily Log _ Cook Inlet Energy_ Date Operator Initials Wells Online Well Profile Verified Visual Completed Phase Triangle Comments Verified 1 -Sep Feagin DF •, 1 1.,12 1 •, s1 1,17 Yes Yes Yes 2 -Sep Feagin DF 1 M2 1 1415 1 1.117 Yes Yes Yes 3 -Sep Feagin DF •, 1 ., z 1 M s 1 F-1]7 Yes Yes Yes 4 -Sep Feagin DF 1 ., z 1 •, sI ,, 7 Yes Yes Yes S -Sep Feagin DIF •, 1 ., z 1 •, 5 1 Fj 7 Yes Yes Yes Monthly calibration 6 -Sep Feagin DIF •, 1 ,, z 1 1.,15 1 ,, 7 1 Yes Yes Yes 7 -Sep Feagin DIF •, 1 ., z 1 1.,15 ., 7 Yes Yes Yes 8 -Sep Feagin DF •, 1 ., 2 1 LIJ s ., 7 Yes Yes Yes 9 -Sep Feagin DF •, 1 ., z ., s ,, 7 Yes Yes Yes 10 -Sep Feagin DF •, 1 ., z 1 F15 ,, 7 Yes Yes Yes 11 -Sep Feagin DF •, 1 ., z ., s ,, 7 Yes Yes Yes 12 -Sep Ben Christianson BC •, 1 ,, z •, s ,, 7 Yes Yes Yes 13 -Sep Ben Christianson BC •, 1 ., z ., s ,, 7 Yes Yes Yes 14 -Sep Ben Christianson BC •, 1 ., z •, s ,, 7 Yes Yes Yes 15 -Sep Ben Christianson BC •, 1 ., z 1 F]5 1 F7,17 Yes Yes Yes 16 -Sep Ben Christianson BC •, 1 ,, z •, s F./17 Yes Yes Yes 17 -Sep Ben Christianson BC •, 1 ,, z 1 F]5 1 ,, 7 Yes Yes Yes 18 -Sep Ben Christianson BC •, 1 ., 2 •, s r7l 7 Yes Yes Yes 19 -Sep Ben Christianson BC 1 1411 ., z ., s F.117 Yes Yes Yes 20 -Sep Ben Christianson BC 1./11 ., z ., s ,, 7 Yes Yes Yes 21 -Sep Ben Christianson BC 1 •, 1 1 ., z ., s F11 7 Yes Yes Yes 22 -Sep Ben Christianson BC I./Il ., z ., s M 7 Yes Yes Yes 23 -Sep Ben Christianson BC •, 1 r7,1 z 1 L/j s 1 r7l7 Yes Yes Yes 24 -Sep Ben Christianson BC •, 1 ., z e s 4 7 Yes Yes Yes 25 -Sep Ben Christianson BC I I./Il F./j z 1 M s 1 F.117 Yes Yes Yes 26 -Sep Feagin F •, 1 ., z •, s r.,17 Yes Yes Yes 27 -Sep Feagin F •, 1 ., 2 •, s ,, 7 Yes Yes Yes 28 -Sep Feagin f •, 1 ., z •, s ., 7 Yes Yes Yes 29 -Sep Feagin F •, 1 ., z ., s ,, 7 Yes Yes Yes 30 -Sep Feagin F •, 1 ,, z 1 W s 1,, 7 Yes Yes Yes �vl Production Manager: 2. Redoubt Multiphase Meter Event Log _ Cook inlet Energy_ Redoubt MPFIVI Event Log Date Operator Initials Event Event Start Event End Remedial Action Taken Comments 9/5/18 Mykel Sorrels MS Monthly Meter Cal. 5:30:00 AM 2:00:00 PM cal done 0 cv l Production Manager: 3. Redoubt Multiphase Meter Daily Measurements Redoubt MPFM Daily Averages _ Cook Inlet Energy_ Date WLR GV F Nsi Diff. Pressure Diff. Pressure in Range Line Pressure Psi Line Temp F Total Mass Flow Rate Comments Ib da 9/1/18 63.5 20.7 7.7 TRUE 364.0 100.2 1149184.4 9/2/18 61.8 25.5 7.6 TRUE 357.1 100.2 1131668.1 9/3/18 61 23.2 7.8 TRUE 374.4 100.6 1131986.0 9/4/18 59.8 27.9 8.4 TRUE 357.6 101 1143929.3 9/5/18 59.8 25.7 8.21 TRUE 364.4 101.41 1145204.7 Meter Service 9/6/18 59.3 26.8 8.49 TRUE 356 101.3 1149715.6 9/7/18 59.2 26.5 8.46 TRUE 365.6 101.7 1151991 9/8/18 58.8 27 8.6 TRUE 364.8 102 156706.2 9/9/18 58.5 27.5 8.68 TRUE 365.2 101.9 1158417.4 9/10/18 58.4 28.2 8.7 TRUE 362.2 101.9 1155225.7 9/11/18 58.41 26.5 8.6 TRUE 366.7 102.1 1158058.5 9/12/18 58.31 28 8.9 TRUE 362.5 102.2 1165554.4 9/13/18 58.21 27.1 8.71 TRUE 367.4 102.31 1157622.7 9/14/18 581 27.8 8.7 TRUE 364.2 102.3 1156909.4 9/15/18 57.81 28 8.9 TRUE 362.2 102.2 1165091.4 9/16/18 57.91 27.5 8.8 TRUE 363.6 102.4 1164456.5 9/17/18 581 27.2 8.8 TRUE 367.8 102.3 1167218.0 9/18/18 57.91 27.5 8.8 TRUE 367.8 102.4 1161918.2 9/19/18 57.81 27.9 8.9 TRUE 365.8 102.8 1165473.8 9/20/18 57.81 27.3 8.9 TRUE 367.7 102.9 1169488.9 9/21/18 57.71 28.3 8.91 TRUE 361.9 103.11 1167899.2 9/22/18 57.61 28.8 8.9 TRUE 359.2 102.7 1161419.7 9/23/18 57.61 27.6 8.8 TRUE 362.6 102.6 1161406.1 9/24/18 57.71 27.2 8.8 TRUE 367.6 102.5 1162848.3 9/25/18 57.3 28.0 8.8 TRUE 366.4 102.6 1156831.6 9/26/18 57.6 27.7 8.7 TRUE 367.7 102.2 1158611.2 9/27/18 57.3 27.6 8.8 TRUE 365.9 102.3 1162692.7 9/28/18 57.6 27.5 8.7 TRUE 368.6 102.4 1161335.2 9/29/18 57.5 28.7 9.0 TRUE 362.8 102.3 1168120.4 9/30/18 57.7 28.8 8.8 TRUE 365.71 102.71 1162866.5 ex -O Production Manager: 4. Redoubt Gas Analysis GLACIER_MSNNA-REDOUBT OSPREY -09 -11 -18 -RUN 1 chandler Engineering Co. Model 292/2920 BTU Analyzer Test time: septll 18 15:53 Calibration #: 33 Test #:2 Location No. :4 Molar Mass = Relative Density = compressibility Factor = Gross Heating value = Standard/Dry Analysis saturated/wet Analysis 22.114 22.042 0.7658 0.7634 0.9966 0.9965 20049. Btu/lb 19778. Btu/lb Gross Heating value = 1168.6 Btu/CF 1149.2 Btu/CF Page 1 standard/Dry Analysis _ saturated/wet Analysis Mole% BTU* R.Den.* GPM** Mole% BTU* R.Den.'* (4 4 Methane,7o433 70.433 709.14 0.3901 -- 69.200 696.74 0.3833 C214(, Ethane .086)(2 8.870 156.48 0.0921 2.3588 8.715 153.75 0.0905 C 3 H$ Propane -01306 7.306 183.26 0.1112 2.0015 7.178 180.05 0.1093 ,i -Butane ,1.247 40.43 0.0250 0.4058 1.225 39.73 0.0246 Cy 11 to ,o2b35 -n-Butane � 1.388 45.15 0.0279 0.4352 1.364 44.36 0.0274 ,i -Pentane 0.302 12.03 0.0075 0.1097 0.296 11.82 0.0074 CS r+12 .00541 .n -Pentane 0.245 9.79 0.0061 0.0883 0.241 9.62 0.0060 ( c6+ ) oni" 0.166 8.39 0.0053 0.0711 0.163 8.24 0.0052 C6 6i4r Moisture 0.000 0.00 0.0000 -- 1.750 0.88 0.0109 NZ Nitrogen ,o583S9.835 0.00 0.0951 - 9.663 0.00 0.0935 X02_ C CO2) ,Dozog 0.208 0.00 0.0032 -- 0.204 0.00 0.0031 Ideal 100.00 1164.7 0.7635 5.4704 Inn.co * Uncorrected for compressibility at 60.OF & 14.65OPSIA. **: Liquid volume reported at 60.OF. Molar Mass = Relative Density = compressibility Factor = Gross Heating value = Standard/Dry Analysis saturated/wet Analysis 22.114 22.042 0.7658 0.7634 0.9966 0.9965 20049. Btu/lb 19778. Btu/lb Gross Heating value = 1168.6 Btu/CF 1149.2 Btu/CF Page 1 GLACIER_MSNNA_REDOUBT OSPREY -09 -11 -18 -RUN 2 chandler Engineering Co. Model 292/2920 BTU Analyzer Test time: septll 18 16:10 calibration #: 33 Test #:3 Location NO. :4 Standard/Dry Analysis _ saturated/wet Analysis mole% BTU* R.Den.* GPM** Mole% BTU* R.Den.* C Hy Methane. 7o S3o 70.530 710.13 0.3907 -- 69.296 697.70 0.3838 ;21+10 Ethane o87my 8.764 154.61 0.0910 2.3305 8.611 151.91 0.0894 C3 µa Propane .a73o(, 7.306 183.26 0.1112 2.0015 7.179 180.06 0.1093 ,i -Butane 1.245 40.36 0.0250 0.4051 1.223 39.65 0.0245 ,yNio.ozb3� n -Butane 1.394 45.32 0.0280 0.4369 1.369 44.53 0.0275 i -Pentane 0.316 12.61 0.0079 0.1149 0.311 12.39 0.0077 C 5 NiZ n-Pentane oo59b` 0.280 11.19 0.0070 0.1009 0.275 10.99 0.0069 6 µ1y + ( C6+ ) ,00213 0.213 10.76 0.0068 0.0913 0.209 10.57 0.0067 Moisture 0.000 0.00 0.0000 -- 1.750 0.88 0.0109 N 2 Nitrogen.D9i4$ 9.748 0.00 0.0943 -- 9.578 0.00 0.0926 C O L ( CO2 ) ,00203 0.203 0.00 0.0031 -- 0.199 0.00 0.0030 ja�� 0.44444 Ideal 100.00 1168.2 0.7648 5.4811 * : Uncorrected for compressibility at 60.OF & 14.65OPSIA. **: Liquid volume reported at 60.OF. Molar Mass = Relative Density = Compressibility Factor = Gross Heating value = standard/Dry Analysis saturated/wet Analysis 22.152 22.079 0.7672 0.7647 0.9966 0.9965 20076. Btu/lb 19805. Btu/lb Gross Heating value = 1172.2 Btu/CF 1152.7 Btu/CF Page 1 5. Redoubt Multiphase Meter Calibration Report.pdf Date: 6Se618 Meter Name: Osprey Va Swoa Source ID: AB 9967 Venturl Slre: 29mm E4Maif Distribubon: THIS SECTION TO BE COMPLETED BY INSTRUMENT TECH*CUuN DIFFERENTIAL PRESSURE CALIBRATION NOTES TRANJDIICER RANGE: Rana m Imerem [6500amkarj Soume Target Souse 0.9J0m8 ACFOUND BRAND. ABB Tal. Sauce An LEFT 1) TL checked ushg Amelel, Heal Sync 2) Checked Cailbraaon Rang" re0scURg P and T of openation 0 0.0 2000 200.0 0.0 2000.90 H-1Mrrr ./- t00lber J) Sar In Psi eonwreion 1" 4000 4009.0 5000 5000.0 3198.20 4808.10 -1-tOnlhar -1-10mbar 4) Atmospheric Pressure=14.7 ps1 4000 4005.0 200 2003.0 3989.80 107.60 ./-10mber a/. 10.1n r 6) D 0.0 0.0 .1-10 bar SLB Witness: NA AOGCC Wlb w - Ausen /Arleen InW..Technkisn: TOm HaB Opermar. Shawn S.Fan THIS SECTION TO BE COMPLETED BY OPERATOR FPR -ANALYTICAL DATA VALUE TEMP METHOD 00 DEN (kWm3f 801.200 10dee OIL VIS (cp) 15.289 I0DdN OIL KF (haclion) H2ODENft"3) 1013.30 Wood GASDENft"3) Comment: Equipment ID: Celibr. cls: 10 psi Range, 750PDB Pressure Module STATIC PRESSURE CALIBRATION TRANSDUCER RANGE: Ranee d Ireaear[ o u Burps] Source Targel Source 0.5000 WOUND BRAND: ABB TOT. Sauce Aa LEFT EPR-GAMMACALISRAIION LE HE 356 Toud COUNTRATES 26321 1 12118 1 25893 1 65132 DURATION(hn) /Hr331,01in 0 0.0 0.00 -1-725 d I I 30 302.0 299.70 k-725DS11 I 60 801.0 598.20 H-725ps1 900 905.0 902.00 */- 725psi 80 04.0 8(T.60 .1 725DA OIL WATER GAS Method FPR FPR COMP LE ABenuation 0.026734 0.036938 0.031996 HE AUwwwon 0.017623 0.011791 0.016627 356 Alien tabon 0.011973 0.011835 0.01 D947 300 361.0 299.60 HL 725psi 0 0.0 0.0 .4725 " Comme0c Adjust As Found Value fa Atmos hedc Pressure. See Note 4 Equipment 113: 11500 psig Calibr. Cycle, I Range. 70OP09 Presswe Module BIANNUAL VENTURI INSPECTION (June of Eesn Years) TEMPERATURE CALIBRATION INSP7 No NO INNER DIA SQE CONDRION HUB GL DATE Comment: TRANSDUCER RANGE: Source Ta e1 S.. -20 to 15OG As FOUND BRAND: ABEL Ta Soume As LEFT NOTES 70 700 7030 1) Calibrations on PLIDPITL were done With no Issues 120 120,0 119.70 IN 180.0 197,70 2) Changed "c: pressure Transducer range to 0-5000 on calibration street 12D 120.0 11880 70 70.0 69.60 3) Cammerna: 4) Openamr: Tam Hall Mike Muny Equipment ID: Calibr. C N: Ametek Heat Sync E4Maif Distribubon: GLACIER Empty Pipe Reference (EPR): Each step shall be initialed upon completion: �1. Isolate the Vx meter from the flow by opening the bypass valve and closing the meter ,1 inlet and outlet valves. FFl 2. De -pressurize the meter to ensure that the pressure in the meter has been bled to L atmospheric conditions. Remove the access blind flange and scrub the venturi and windows in the throat using on EPR brush with methanol, followed by a cloth swab until the swab is dry and. shows no evidence of oil or deposition. 4. Perform the meter checks: a. Check alarms a. Verify that alarms showing are due to the no -flow state b. Transmitter Checks: a. Ensure Cailbratlon is up to date b. Zero trim the Differential Pressure (DPV) and Line Pressure (PL) c. Verify temperature is reading close to.atmospheric temperature, and is stable. c. Source and Detectorchecks a. Check voltages and meter diagnostics (Gamma Tab) 1. .0!5 Chi.Square.< 2 2. 500 V' < HV Gain <800 V 3. HE Center = 200 ± 3 ,�jj 4. PHR < 25% �T # 5. once. the windows are clean and dry and the meter checks are complete, cover the access flange arid start theEPR. Select air, press the"Make Reference" button, and select pipe temperature to initiate an empty pipe reference session. A pop up box will appear displaying vacuum count rates for low energy counts, high energy counts, 356 counts, and the respective standard deviation percentage will be displayed. a. Visual Inspection b. Verify counts are close:to previous EPR via Excel sheet and "reference' tab c. Verifythe wipe testis up to date d. The acceptance criterion for an EPR is typically a standard deviation of less than .01% of the counts per second forany of the energy peaks. it should take approximately one to four hours to generate an EPR with this accuracy if all the required cleaning and drying steps are taken. 7. After 30 minutes of running the EPR, compare the values for Low Energy (LE, 32 MeV), high energy (HE, 81 MeV), 356 and the total counts to the previous EPR using the Excel spread sheet for Decay. 8. When the standard deviation has reached an acceptable level, press "End Reference" and then confirm with "Yes" to update the reference in the DAFC. Alternatively, press "Cancel" or "No" to discard the reference. If the reference is updated the DAFC will activate the new reference. / MduR Z 7 rN/A/u'T*7.S Empty Pipe Reference Counts Recorded Counts Expected Counts LE Counts 2 & 3 2 ) 2 6'-3 / T. 3 HE Counts /z if /Z ii G.7 356 Counts Z 5 8 39 25 81"-Z Total counts Ccs 13 z GCZ130. 3 f%72iat 10. Upon completion of the EPR; reviewthe temperature and pressure trends to verify relative stability throughout the reference. Review the count trends to verify no spikes,which could indicate something fal)ing Into the meter. a. Temperature does not fluctuate by more the 18 IF b. Pressure remains atmospheric IW (eM 11. Install the new EPR in the Vx as the reference for the next month. fW>2t'lk 12. Replace the blind flange on the access flange and line up the valves to properly return the meter to service if no fluid pipe references will be performed. Date Performed: Production Field Superintendent: fel N(t)=N,[exp(-k*At)] N(t) =number of counts at time t N, =initial number of courts at to Half life (sec) 33295/040 seelday 66400 It =In(2)/ha1f life time It 2.08E-09 t=Data/Time Currant EPR t, =Daterrime Lest EPR dt =t -to Comparison is only valid when all the following conditions are respected: Same source than previous EPR LS Source has not moved Same Venturi than previous EPR Some Detector than previous EPR Same Detector Stabilization Temperature selected Enter EPR date & cps v CALCULATED VALUES ; v OUTPUT Z v ACQUIRED EPR THEORETICAL VALUE RESULTS EPR Date LE HE 356 Total Abs Difference (Theoretical - Actual) +/•0.3% EPR Ratio L E HE Theoretical EPR Ratio LE.HE Ratio LE HE +t - 05% LE HE 356 Total Source AS -9537 Meter 30090 8111117 16:40 28248 13005 27768 69911 8125117 281779 12972.7 27699 1 69737.5 OK OK (W OK 2 172 n/2 We 8/25117 12:15 28174 12968 27680 69716 9122/17 28031.8 1 129025 275403 69364.1 OK OK OK OK 2 173 2 172 1162°4 9/22/1715:32 28027 12899 27547 69360 10/21117 27881.5 12832.0 27404.0 68999.9 OK OK OK OK 2173 2173 10/2112017 14:10 27879 12832 27401 68990 11/18117 277393 12767.7 27263.7 68644 3 0K 0K OK OK 2 173 2 173 11/18/2017 1227 27739 12766 27253 68644 12/16/17 27599 1 12700.6 271156 68297.8 OK OK OK OK 2 173 2 173 12/16/2017 15.00 27581 12705 27120 68281 1114/18 27437.8 126390 26979.2 67926.5 OK OK 0K 0K 2 171 2 173 #VALUE! 1/14/2018 13 30 27455 12636 26984 67951 2/10/18 27322.2 12574.9 26853.5 67622.3 0K OK UK OK 2.173 2171 #VALUE! 21101201812:30 27317 12574 26848 67604 3110/18 27179.9 12610.9 26713.2 67264.6 OK 0!t OK OK 2172 2173 #VALUEI 311012018 12 01 27176 12511 26725 67275 4110/18 27025.1 12441.5 26576.6 66901.5 OK OK OK OK 2172 2172 #VALUEI 4/10/2018 10 57 27028 12441 26571 66898 515/18 269064 12386.0 26451 5 66597.1 UK OK OK OK 2 172 2-172 #VALUEI 5/51201812:25 26910 12386 26447 66594 613118 26769.1 12321.1 26308.5 66245.3 OK OK OK OK 2173 2172 #VALUE! 6020181668 26759 12317 26311 66239 6130/18 26630.3 122678 261845 65920 5 OK OK OK OK 2 173 2 173 #VALUEI 6130/2018 26636 12260 26167 65927 8/3/18 26476.0 121864 26009 8 65531.0 OK OK OK OK 2.173 2 173 #VALUEI 813/2018 26476 12189 25993 65518 915118 26319.3 12116.9 258392 65130.3 OK OK OK OK 2 172 2 173 #VALUEI 9/5/2018 26321 12119 25839 65132 1 - 1 174ilr•A 2172 2172 #VALUEI #DIV/0! 4DIV/0! #DIV/01 #01V/01 #ON/01. 2172 #DIVIO! #DIV/0! #DIV/01 #DIV/01 #DIV/0! #DIV/0! #DIVIO! #DIV/O! #DIVIO! #DIV101 #DIV/01 #DIV/01 #DN/Ol #DIV/0! #DMO! #DIV/0! r #D! AI #DIV/0! #DNNI #DIVi01 #DIV/01 #DIV/0! GLACIER Fluid Pipe Reference (FPR): Each step shall be initialed upon completion: _Z+E' 1. Follow all. procedures listed for EPR. r 2.. Make sure the Pressure Transmitter is Zero Trimmed and make sure the Temperature Transmitter is reading the correct value. Zero. Trim the Pressure Transmitter with the venturl subjected to atmospheric conditions. 1%7 OU 3. Clean and dry the venture throat and. windows. MfZ AV 4. Change the 'Type of Water" and the 'Type of Oil" from "Live" to "Dead" for the fluid references. /Ve?M S. Input composition data a. Gas (from lab analysis): a_ Gas composition b. Specific Gravity b. Water (taken on site): a. Density c. Oil: a. Density eo& f. 2— b. viscosity 15.2 89 If two viscosities will be entered; change the "Oil Viscosity" drop down. from "Black oil" to "ASTM -D341". This will allow you to enter more than one viscosity point. Take care to enter the corresponding temperatures for the viscosities in the right order. —4 6. Insert the Calibration Tool and seat the O-ring in the:venturi throat with the holes aligned with the windows. a. Compare the counts to those of the EPR to verify the holes are aligned correctly and not. blocking the radioactive source. 7� 7, To perform the Water Reference, pour a sample of the prepared 100946 water sample into the top of the calibration toot (make sure if completely covers the nuclear windows:) Start the Insitu Reference Measurement by clicking the "Make Reference" button. a. Make sure no oil sheen is visible on the surface. If there is, run through`a filter prior to using for the reference. Y GLACIER b. Monitor DPV, the drain on bottom of meter and fluid at top of the reference tool while performing the FPR to make sure that the o - ring seal on the reference tool is holding. c. It should take approximately 20 minutes to generate the water reference. I N 8. When completed, press "End Reference" and "Yes" to update the reference in the DAFC. Alternatively, press "Cancel' or "No" to discard the reference. If the reference is updated the DAFC will activate the new reference. 9. Quality check the reference a. Upon completion of the FPR for water, tog for 5 minutes with the sample in place and verifythat WLR is close to 100%. TW 10. the reference tool and thoroughly clean and dry the meter and the reference tool - 114 -11. To perform the Oil Reference, pour a sample of the prepared 100% oil sample into the top of.the calibration tool (make,sure if completely covers the nuclear windows.) This shall be the same sample., the viscosity and density.measurements were collected from. Start the Insitu Reference Measurement by clicking the "Make Reference" button.. a. Monitor DPV, the drain on bottom of meter.and fluid at top of the reference tool while performing the FPR: to make sure that the o -ring seal on the reference. tool is holding. fi 12. Quality check the reference: a. Upon completion of the FPR for oil, log for 5 minutes with the sample in place and verify that WLR Is dose to 0%. 1413. Change the "Type:of Water" and the "Type of 011" from "Dead" to "Live" before flowing through the meter. .14. Replace.the blind flange on the access flange and line. up the valves to properly return the meter to service if no fluid pipe. references will be performed. Wells Online Well Profile: Mass Attenuations OII Water Gas LE 7 0.0,;b11 • V S HE ? Z3 .O 1 .77q 6liiie2 356 0,0 Iffts 0/0 Date -Performed: Production Field Superintendent: Anton Pear GmbH Anton-Paar-StraBe 20 8054 Graz Austria Anton Paar SVM 2001 - Measurement Results: Software version: 2.91.5841.209 SVM serial number: 82086572 instrument name: — Instrument location: -- Sample Information ► Unique Sample Id 568 ► Date: 9/4/2018 ► Time: 4:23:59 PM ► Sample Name: Osprey Oil 09/05/18 ► Measurement Mode: Repeated Mode • Master Condition: valid ► Sample Error State: no error Measurement Result. Sub unique Time Cell Dyn. KJ n. RDV Visc. Shear Shear Density RDD Measurement Sample Temp. Mac Viso Precision Rate Stress Number Id Density D2161 D2161 Precision Seyboft Saybo Univers-Vis. 11Cl rmpa-sl Imm'lsl r%I 11/31 [pal lo/crn% ro/cm°I 1 569 4:18:24 PM 37.778 15.168 17215 — Fast 415.6 6.3035 0.8811 — 2 570 4:21:11 PM 37.778 15.262 17.319 0.62 Fast 414.0 6.3183 0.8812 0.0001 3 571 4:23:59 PM 37.778 15.316 17.379 0.36 Fast 413.1 6.3267 0.8813 0.0001 averane 568 4:23:59 PM 37.778 15.289 17.349 0.36 Fesl 413.5 6.3225 0.8812 0.0001 std dev. 0.000000 0.061152 0.067751 1.033871 0.009591 0.000082 Density D2161 D2161 Precision Seyboft Saybo Tuesday, September 04, 2018 Page 3 of 3 Univers-Vis. Furd Vis. ISUSI ISFSI Fast 86.3 — FaM 86.7 — Fast 88.9 Fast 86.8 0.25 Tuesday, September 04, 2018 Page 3 of 3 Anton Paar GmbH Anton-Paar-StraBe 20 8054 Graz Austria Anton Paar SVM 2001 - Measurement Results: Software version: 2.91.5841.209 SVM serial number: 820136572 Instrument name: — Instrument location: -- Sample Information ► Unique Sample Id: ► Date: ► Time: ► Sample Name: ► Measurement Mode: ► Master Condition: ► Sample Error State: Measurement Result: Sub Unique Time Measurement Sample Number Id 561 9/U2018 3:42:51 PM Osprey Water 09/05/18 Repeated Mode valid no error cell Dyn. Km. RDV Viso Shear Shear Density RDD Temp. Viso, Viae. Precision Rate Stress rel fmPa'sl Imm'hl 1%1 [1/81 We] IWan9 Worn'l 1 552 3:40:09 PM 15.554 1.1213 1.1065 — Fast 984.5 1.1039 1.0133 — 0.001000 Density D2161 D2161 Precision Seybolt Saybolt Univers.Via Furol Ys. ISUSI ISFSI Fast 29.4 — Fast 29.4 Fast 29.4 0.OD Tuesday, September 04, 2018 Page 1 of 1 6. WMRU Multiphase Meter Daily Log WMRU MPFM Daily Log _ Cook Inlet Energy_ Date Operator Initials WeIlsOnline Well Profile Verified Visual Completed Phase Triangle Comments Verified 1 -Sep Doug Durst DD L•,j 2B 1,, s 1 L.-,]6 1 1.,1 sword Yes Yes Yes 2 -Sep Doug Durst DD L11 2 1Els 1 1./16 1 1•,1 sword Yes Yes Yes 3 -Sep Doug Durst DD •, 2B ., s 1 J.,16 1 1.,1 sword Yes Yes Yes 4 -Sep Sam Cox SC J 2B Els 1416 .,r sword Yes Yes Yes 5 -Sep Sam Cox SC •,I 2B Els 1 1 •,16 1 1.,1 sword Yes Yes Yes 6 -Sep Sam Cox SC ., 2B ., s 1 1 , 6 1 1.r1 sword Yes Yes Yes Calibrated Meter. 7 -Sep Sam Cox SC .,I 2B M s 1 1•, 6 1 1.,1 sword Yes Yes Yes 8 -Sep Sam Cox SC .,I 2B ,, s 1 1 •, 6 1 1•,1 sword Yes Yes Yes 9 -Sep Sam Cox SC J 2B F7,15 1 J.,16 1 1•,1 sword Yes Yes Yes 10 -Sep Sam Cox SC •, 2B ., s 1 1 •, J 6 1 1•,1 sword Yes Yes Yes 11 -Sep Sam Cox SC •, 2B ., s 1 1./16 1 1.,1 sword Yes Yes Yes 12 -Sep Sam Cox SC •, 2B M s 1 F41 s 1 1 ., 1 sword Yes Yes Yes 13 -Sep Sam Cox SC •, 2B ,, s 1 1 ,r 16 ., sword Yes Yes Yes 14 -Sep Sam Cox SC •, 2B ., s 1 J., 16 1 1•,1 Sword Yes Yes Yes 15 -Sep Sam Cox SC •, 2B ., s 1 1416 1 1•,1 Sword Yes Yes Yes 16 -Sep Sam Cox SC ., 2B F7,15 1 1./16 1 1•,1 Sword Yes Yes Yes 17 -Sep Sam Cox SC ., zB J s •, 6I I.,I sword Yes Yes Yes 18 -Sep Doug Durst DD •, 12B ,, s 1 J.,16 1 1.,1 sword Yes Yes Yes 19 -Sep Doug Durst DD J 2B ., s 1 1./16 1 1./ 1 sword Yes Yes Yes 20 -Sep Doug Durst DD 1.11 2B M s 1 Fj 6 1 1•,1 sword Yes Yes Yes 21 -Sep Doug Durst DD L -112B ,, s 1 J.,16 1 1•,1 sword Yes Yes Yes 22 -Sep Doug Du rst DD I ., I 2B F-715 I I •, 16 1 1.,1 sword Yes Yes Yes 23 -Sep Doug Durst DD 1., 1 2B M s 1 1•, 6 1 1.r1 sword Yes Yes Yes 24 -Sep Doug Durst DD ., 2B Fj s 1 1.116 1 1•,1 sword Yes Yes Yes 25 -Sep Sam Cox SC F,/1 s 1 J.,16 1 1•,1 sword Yes Yes Yes 26 -Sep Sam Cox SC •, 2B ,, s 1 1.116 1 1•,1 sword Yes Yes Yes 27 -Sep Sam Cox SC ., 2B ., s 1 1./16 1 1•,1 sword Yes Yes Yes 28 -Sep Sam Cox SC ., 2B ., s •, 6 ., sword Yes Yes Yes 29 -Sep Sam Cox SC •, 28 ., s •, 6 •, sword Yes Yes Yes 30 -Sep Sam Cox SC ., 2B ., s ., 6 •, Sword Yes Yes Yes 2B 5 1 LJ6 sword Production Manager: 0', 7. WMRU Multiphase Meter Event Log WMRU MPFM Event Log Cook Inlet Energy_ Date Operator Initials Event Event Start Event End Remedial Action Taken Comments 9/6/18 Sam Cox SC Calibrated VX Spectra Meter 9/6/187:05 9/6/1813:00 None Meter was offline during calibration Production Manager: 8. WMRU Multiphase Meter Daily Measurements .Cook Inlet Energy_ WMRU MPFM Daily Averages Date NWLR N (%) Diff. (millibar) Pressure Diff. Pressure psi Diff. Pressure in Range Line Pressure psi Line Temp Total Mass Flow Rate kgjs Total Mass Flow Rate Comments Ib da 9/1/18 79.6 11.8 246.0 3.57 3.84 3.46 3.50 3.75 3.70 3.75 3.61 3.57 3.76 3.66 3.54 3.54 3.58 3.51 3.67 3.71 3.78 3.72 3.75 3.90 4.00 3.91 3.89 3.93 3.88 4.02 4.05 4.18 4.08 TRUE TRUE TRUE TRUE TRUE TRUE TRUE TRUE TRUE TRUE TRUE TRUE TRUE TRUE TRUE TRUE TRUE TRUE TRUE TRUE TRUE TRUE TRUE TRUE TRUE TRUE TRUE TRUE TRUE TRUE 340.7 131.4 8.1 1537946 9/2/18 80.4 12.2 264.9 311.5 136.9 8.4 1597547 9/3/18 79.6 12.5 238.6 352.8 136.6 7.9 1511070 9/4/18 79.5 11.6 241.0 342.3 137.0 8.01 1527832 9/5/18 80.11 16.0 258.61 346.5 137.7 8.1 1546689 9/6/18 80.71 11.9 255.1 346.9 139.0 8.2 1570880 Meter service 9/7/18 79.21 16.1 258.6 347.1 138.1 8.1 1545356 9/8/18 79.01 15.9 248.9 347.6 136.8 8.0 1516689 9/9/18 78.91 14.5 246.0 348.3 137.7 8.0 1517737 9/10/18 79.01 15.5 259.1 326.1 137.8 8.1 1547261 9/11/18 79.01 16.4 252.4 347.9 137.3 8.0 1523832 9/12/18 78.71 15.0 243.9 346.8 137.9 7.9 1504784 9/13/18 78.71 16.0 244.0 345.3 137.3 7.9 1504784 9/14/18 79.01 16.8 246.8 346.9 137.6 7.9 1504784 9/15/18 79.01 13.6 242.1 347.1 136.6 7.9 1504784 9/16/18 79.21 15.3 253.3 348.3 137.0 8.1 1542880 9/17/18 79.21 14.4 256.0 347.5 138.0 8.1 1542880 9/18/18 79.61 15.5 260.6 347.6 137.7 8.2 1561928 9/19/18 79.51 14.1 256.3 347.0 138.0 8.2 1561928 9/20/18 79.11 15.6 258.7 345.5 137.0 8.1 1542880 9/21/18 79.61 15.2 268.9 346.1 137.8 8.3 1580976 9/22/18 80.11 15.6 275.6 330.1 137.3 8.4 1600024 9/23/18 79.71 15.9 269.8 345.5 137.1 8.3 1580976 9/24/18 79.71 14.1 268.1 345.4 134.7 8.4 1600024 9/25/18 79.8 15.2 270.7 345.4 137.8 8.3 1580976 9/26/18 80.0 13.9 267.8 346.3 137.9 8.4 1594690 9/27/18 80.1 15.8 276.9 342.4 137.4 8.4 1606881 9/28/18 79.9 14.6 279.1 342.3 138.6 8.5 1622310 9/29/18 80.3 15.3 288.5 325.0 139.3 8.6 1642691 9/30/18 80.0 15.3 281.3 342.5 138.91 8.5 1619072 Production Manager: 9. WMRU Gas Analysis GLACIER-MSNNA_WMRU_09-11-18_RUN 1 Chandler Engineering Co. Model 292/2920 BTU Analyzer Test time: Septll 18 16:51 Test #:1 Calibration #: 33 Location No. :3 Molar Mass = Relative Density = Compressibility Factor = Gross Heating value = Gross Heating value = Standard/Dry Analysis saturated/wet Analysis 22.597 22.517 0.7818 0.7791 0.9976 0.9975 15046. Btu/lb 14850. Btu/lb 895.3 Btu/CF 880.6 Btu/CF Page 1 Standard/Dry Analysis _ Saturated/wet Analysis Mole% BTU= R.Den.* GPM** Mole% BTU* R.Den.* CI}y methane 51j[.56 59.158 595.62 0.3277 -- 58.123 585.20 0.3219 �-2HI Ethane ,63837 5.837 102.97 0.0606 1.5522 5.735 101.17 0.0595 C 3a 8 Propane,045)y, 4.514 113.23 0.0687 1.2367 4.435 111.25 0.0675 'L441 D i-Butaneol 0.747 24.21 0.0150 0.2430 0.734 23.78 0.0147 858 n -Butane 1.141 37.11 0.0229 0.3577 1.121 36.46 0.0225 C50Q i -Pentane 0.223 8.91 0.0056 0.0812 0.219 8.75 0.0055 ooN i5 n -Pentane 0.192 7.68 0.0048 0.0693 0.189 7.55 0.0047 "-Lp ( c6+ ) ,00047 0.067 3.40 0.0021 0.0289 0.066 3.34 0.0021 Moisture 0.000 0.00 0.0000 -- 1.750 0.88 0.0109 N2 Nitrogen,2194Y 27.966 0.00 0.2705 -- 27.477 0.00 0.2658 Co2_ ( CO2 ) ,00��y 0.154 0.00 0.0023 -- 0.151 0.00 0.0023 Ideal 100.00 893.1 0.7802 3.5689 " Uncorrected for compressibility at 60.OF & 14.65OPSIA. **: Liquid volume reported at 60.0F. Molar Mass = Relative Density = Compressibility Factor = Gross Heating value = Gross Heating value = Standard/Dry Analysis saturated/wet Analysis 22.597 22.517 0.7818 0.7791 0.9976 0.9975 15046. Btu/lb 14850. Btu/lb 895.3 Btu/CF 880.6 Btu/CF Page 1 GLACIER_MSNNA_WMRU_09-11-18_RUN 2 Chandler Engineering Co. Model 292/2920 BTU Analyzer Test time: septil 18 17:07 Test #:2 calibration #: 33 Location NO. :3 Molar Mass = Relative Density = compressibility Factor = Gross Heating value = Gross Heating value = standard/Dry Analysis saturated/wet Analysis 22.601 22.520 0.7819 0.7792 0.9976 0.9975 15096. Btu/lb 14900. Btu/lb 898.4 Btu/CF 883.6 Btu/CF Page 1 standard/Dry Analysis _ saturated/wet Analysis Mole% BTU* R.Den.* GPM** Mole% BTU* R.Den.* Cg Methane ,6y28e, 59.280 596.85 0.3284 -- 58.243 586.41 0.3226 C2 H V Ethane .05825'5.825 102.77 0.0605 1.5491 5.723 100.97 0.0594 C3 H $ Propane ,p454y 4.547 114.04 0.0692 1.2455 4.467 112.05 0.0680 i - Butane /0.754 24.44 0.0151 0.2453 0.741 24.01 0.0149 C4hi° 1%0 �n-Butane'0` 1.156 37.60 0.0232 0.3624 1.136 36.94 0.0228 Pentane /0.226 9.01 0.0056 0.0821 0.222 8.85 0.0055 C5t112 \.- �2- n -Pentane 0.198 7.90 0.0049 0.0712 0.194 7.76 0.0048 CbAl.4 ( C6+ ), 060,?L 0.072 3.64 0.0023 0.0309 0.071 3.58 0.0023 Moisture 0.000 0.00 0.0000 -- 1.750 0.88 0.0109 W 2. Nitrogen . Mg027.790 0.00 0.2688 - 27.303 0.00 0.2641 Cot C CO2) gw53 0.153 0.00 0.0023 0.150 0.00 0.0023 '8.14\ 1,00001 Ideal 100.00 896.3 0.7803 3.5866 -106.00 1 - * uncorrected for compressibility at 60.OF & 14.65OPSIA. **: Liquid volume reported at 60.OF. Molar Mass = Relative Density = compressibility Factor = Gross Heating value = Gross Heating value = standard/Dry Analysis saturated/wet Analysis 22.601 22.520 0.7819 0.7792 0.9976 0.9975 15096. Btu/lb 14900. Btu/lb 898.4 Btu/CF 883.6 Btu/CF Page 1 10. WMRU Multiphase Meter Calibration Report Date: BSep-18 Meter Name: WMRU V. Spectra Source ID: Va777 Ventura Srz•_ 40mm E -Mail Distribution: THIS SECTION TO BE COMPLETED BY INSTRUMENT TECHNICIAN DIFFERENTIAL PRESSURE CALIBRATION NOTES TRANSDUCER RANGE: Range m mtereu 10.SOOOneai SaaeaTt Source D-50DDMB As FOUND BRAND: ABB Td. Sanee As LEFT 1) TL checked using Amarali Heat Syne 2) Checked CalibmUon Rartga9 relMc ting P and T of operation 0 2000 0.0 2004.0 0.00 3999.70 ./-t0mber +/-10mbar 3) Bar to PM converabn 14b 4000 5000 4005.0 5002.0 4001,40 5000.10 +1-10mbar */- 10mbar Amlmpherk Prasaura 14.7 p>I 4000 2000 4003.0 2003.0 4001.80 2003.90 +/-10mbar +/-10mbar 5( 0 D.0 0.00 H-10mbar SLB WiNeaa: NA AOGCC Witness: Aue n kHA•d insir.Tschnkian: Tan Hes Operator: Bred Bud THIS SECTION TO BE COMPLETED BY OPERATOR FPR -ANALYTICAL DATA VALUE TEMP METHOD OA DEN pgmi3) 891.800 100deg OIL 'AS (cp) 22.560 1DOdeg OIL KF (ballon) H2O DEN (kym3) 1021.700 60dep GAS DEN (k9dn3) Cammails Equipment ID: Caller. We: 100 psi. Ran e, 75OP06 Pressure Module F STATIC PRESSURE CALIBRATION TRANSDUCERRANGE: R.W of hWeat 1 O N 900pn7 Souse TaW Source 0-5000 As FOUND BRAND. ABB Td. S. Aa LEFT EPR -GUMMA CALIBRATION LE HE 356 Tdel COUNT RATES24995.0 11501.0 24192.0 61623 DURATION Ova) 1Hr43Min 0 OA 1 0.00 -1- 7.25pe 300 301.0 295.60 +/-7.Z 800 803.0 597.50 +6725psi 900 803.0 898.50 -1. 7.250si 600 803.0 598.50 +/-7.25 & OIL WATER GAB Method FPR FPR COMP LE A6enuabon 0.025644 0.038935 0.025712 HE Atlerwemn 0.017556 0.018100 0.018241 358 Atlenuatlon 0.011876 0.011747 0.012219 300 303.0 299.10 +/-7.2 D 0.0 0.00 +1.7.2 si Comments: Just As Found Value for Atmos hedc Pews me. See Note 4 Equipment iD: Calier. Dle: 1500 pa Range, 70OP09 Pressure Module &dWNUAL VF37TUW.816PEC7ION (Jorma ofEvemr Yesn) TEMPERATURE CALIBRATION INSP7 N• NO INNER DIA Sim CONDITION HUB GL DATE Comments: TRANSWCER Source Tame RANGE Saace -20 to 150C As FOUND BRAND: ABB Td. Sours As LEFT NOTES 70 72.0 72" 1) caiibrafion prefomred on PLIDPIFL with rN) Issues 120 120.0 119.800 180 160.0 179.000 2) Meter bypass 0500 to 1324 bra 120 120.0 119.700 70 12.0 1 71SW 3) Changed Static Pressure Transducer Range to 0-5000 psi Commenu: ArtCierd Tampeniture 0 72 Dees 4) OParalor. Tan Hall Mike Murry Equipment ID: Calibr. e: Ametek Heat Sync E -Mail Distribution: L GLACIER Empty Pipe Reference (EPR): Each step shall be initialed upon completion: 19 1. Isolate the Vx meter from the flow by opening the bypass valve and closing the meter inlet and outlet valves. De -pressurize the meter to ensure that the pressure in the. meter has been bled to II atmospheric conditions. 711 3. Remove the access blind flange and scrub the venturi and windows in the throat using an EPR brush with methanol, followed by a cloth swab until the swab is dry and shows no evidence of oil or deposition.. 4. Perform the meter checks: a. Check alarms a. Verify that alarms showing are due to the no -flow state b. Transmitter Checks: a. Ensure Calibration is up to.date ( b. Zero trim the Differential Pressure (DPV) and Une Pressure (PL) c. Verify temperature is reading close to atmospheric temperature; and is stable.. c. Source and Detector checks a. Check voltages and meter diagnostics (Gamma Tab) 1. .9:5 Vd Square .< 2 2. 500 V < HV Bain < 800 V 3. H& Center = 200 ± 3 4. PHR < 2Sa/a "T � 5. Once thewindowsare clean and dry and the meter checks are complete, cover the access flange and start the EPR. _T9 6. Select air, press the"Make Reference" button, and select. pipe temperature to initiate an empty pipe reference session. A pop up box will appear displaying vacuum count rates for low energy counts, high energy counts, 356 counts, and the respective standard deviation percentage will be displayed. a. Visual Inspection b. Verify counts are close to previous EPR via Excel sheet and "reference" tab c. Verify the wipe testis up to date GLACIER d. The acceptance criterion for an EPR is typically a standard deviation of less than .01% of the counts per second for any of the energy peaks. It should take approximately one to four hours to generate an EPR with this accuracy if all the required cleaning and drying steps are taken. MkfTt 7. After 30 minutes of running the EPR, compare the values for Low Energy (LE, 32 MeV), high energy (HE, 81 MeV), 356 and the total counts to the previous EPR using the Excel spread sheet for Decay. -T'98. When the standard deviation has reached an acceptable level, press "End Reference" and then confirm with "Yes" to update the reference in the DAFC. Alternatively, press "Cancel" or "No" to discard the reference. If the reference is updated the DAFC will activate the new reference. Empty Pipe Reference Counts Recorded Counts Expected Counts LE Counts 1 y9 HE Counts // 356 Counts / 2 2- lo. 7 Total Counts ! bZ-i 4/4.25.7 -T14- - 79- 10. Upon completion of the EPR, review the temperature and pressure trends to verify relative stability throughout the reference. Review the count trends to verify no spikes, which could indicate something falling into the meter. a. Temperature does not fluctuate by more the 18 °F b. Pressure remains atmospheric 11. Install the new EPR in the Vx as the reference for the next month. 12. Replace the blind flange on the access flange and line up the valves to properly return the meter to service if no fluid pipe references will be performed. Date Performed: 6 I $ Production Field Superintendence N(t)=Nolexp(-k*ot)] Nit) =number of counts at time t N, =initial number of counts at to Half life (sec) 332951040 seeiday 86400 It =in(2yhalf life time Comparison Is only valid when all the following conditions are respected: k 2.08E-09 Some source then previous EPR & Source has not moved t=Dste!fime Current EPR Same Venturi than previous EPR t,=Date.Time Last EPR Same Detector then previous EPR di =t -to . Same Detector Stabilization Temperature selected Enter EPR date & cps CALCULATED VALUES � v OUTPUT v ACQUIRED EPR THEORETICAL VALUE RESULTS Source UA -777 Meter 40168 EPR Date LE HE 356 Total Abs Ddference (Theoretical - Actual) +1.0 3%Ratio EPR Theoretical EPR Ratio LE HE Ratio LE HE +r - 0.5% LE HE LE HE 356 Total 17:58 27965 12888 27209 69000 4116117 273442 12601.9 26605.0 674682 OK OK OK OK 2.170 nla We _12/12116 4116117 13:26 27358 12597 26578 67502 611/17 271325 12493 1 26358.9 669456 OK OK OK OK 2.172 2 170 0.09116 6/1117 14 02 27133 12495 26350 66949 6128/17 27002.1 124347 26222.9 666261 OK OK OK OK 2.172 2.172 6/28/20171110 27008 12438 26232 66623 7/29/17 26858.0 12368.9 26086.3 66252.9 OK OK OK OK 2.171 2172 0.001." 7/29/2017 10:30 26861 12365 26067 66259 8/26117 26726.0 123029 25936 0 65926.1 OK OK OF, OK 2.172 2 171 0.041, 8/26/20171035 26721 12304 25944 65923 9./23/17 26566.7 122421 25813.6 65591.6 OK OK 0i' OK 2172 2.172 #VALUE1. 9123/2017 1103 26585 12242 25806 65584 10/22/17 26446.8 121783 25671.8 652430 OK OK OK OK 2 172 2 172 #VALUE1 10/22/2017 1042 26448 12181 25567 65246 11/19/17 263152 121198 25538 1 64918.4 OK OK OK OK 2 171 2-172 #VALUE! 11119f2017 10:25 26318 12120 25545 64927 12/17/17 26185 3 12058 9 254162 64599.5 OK OR OK OK 2.171 2 171 #VALUE! 12/17/2017 13 04 26201 12062 25418 64623 1113/18 26074.0 120035 25294 8 64309.7 OK OK OK OK 2 172 2 171 #VALUE1 1/1372018 13 30 26073 11999 25279 64307 201118 25937.9 11936.8 25148 0 63973 8 OK OK OK OK 2 173 2 172 #VALUE! 2711!2018 10 42 25943 11934 25148 63974 3111118 258127 11874.0 250217 63652.6 OK OK OK OK 2 174 2 173 #VALUE! 3/11/2018 10:45 26801 11876 25023 63645 417118 25675 7 11818 3 24901.5 63335 9 OK OK OK OK 2 173 2.174 #VALUE! 4/7/2018 12:15 25684 11819 24896 63332 5/6f18 25550.5 117576 24766.6 63002.9 OK OK OK OK 2.173 2.173 #VALUE! 5/612018 25549 11758 24768 63016 614118 25416.1 116968 246392 62687.3 OK OK OK OK 2.173 2 173 #VALUE! 614/2018 11:10 25419 11694 24637 62688 711118 25298.0 11638 3 24519.7 62389.5 OK OK OK OK 2.174 2 173 #VALUE! 7/112018 25298 11637 24511 62383 8/1118 25167.3 11572.3 24374.7 62036.1 OX OK OK OK 2174 2.174 #VALUE/ 8/1/2018 25167 11670 24368 62026 916118 24994-6 11495.3 24210.7 61625.7 OK OK OK K 2.174 2174 j#VALUEl 9/612018 24995 11601 24192 61623 Failed Failed Failed F; r 2.173 2 174 #VALUE! t GLACIER Fluid Pipe Reference (FPR): Each step shall be initialed upon completion: 10 . Follow all procedures listed for EPR. Make. sure the Pressure Transmitter is Zero Trimmed and make sure the Temperature Transmitter is reading the correct value. Zero Trim the Pressure Transmitter with the Venturi subjected to atmospheric conditions. Clean and dry the venture throat and windows. -T�4. Change the "Type of Water" and the "Type of Oil' from "Live" to "Dead" for the fluid references. _5. Input composition data a. Gas (from lab analysis): a. Gastomposition. b. Specific Gravity b. Water (taken on site): a. Density 1,9211, 7 c. Oil: a. Density b. Viscosity 2.Z. -SPO a If two viscosities will be entered; change the "Oil Viscosity" drop down from "Black Oil" to "ASTM -D341". This will allow you to enter more than one viscosity point. Take care to enter the corresponding temperatures for the viscosities 1n the right order. I it 6. Insert the Calibration Tool and seat the O-ring in the venturi throat with the holes aligned with the windows. a. Compare the counts to those of the EPR to verify the holes are aligned correctly '' !! and not blocking the radioactive source. To perform the Water Reference, pour a sample ofthe.prepared 100% water sample into the top of the calibration tool (make sure If completely covers the nuclear windows:) Start theJnsitu Reference Measurement by clicking the "Make Reference" button. a. Make sure no oil sheen.is visible on the surface. If there is, run through a filter priarto usingfor the reference. GLACIER b. Monitor DPV, the drain on bottom of meter and fluid at top of the reference tool while performing the FPR to make sure that the o -ring seal on the reference tool is holding. c. It should take approximately 20 minutes to generate the water reference. 7µ B. When completed, press "End Reference" and "Yes" to update the reference in the DAFC. Alternatively, press "Cancel" or "No" to discard the reference. If the reference is updated the DAFC will activate the new reference. 7 H 9. quality check the reference a. Upon completion of the FPR for water, log for 5 minutes with the sample in place and verify that WLR is close to 100%. T 10. Remove the reference tool and thoroughly clean and dry the meter and the reference tool. 11. To perform the Oil Reference, pour a sample of the prepared 100% oil sample into the top of the calibration tool (make sure if completely covers the nuclear windows.) This shall be the same sample the viscosity and density measurements were collected from. Start the Insitu Reference Measurement by clicking the "Make Reference" button. a. Monitor DPV, the drain on bottom of meter and fluid at top of the reference tool while performing the FPR to make sure that the o -ring seal on the reference tool is holding. rl 12. Quality check the reference: a. Upon completion of the FPR for oil, log for 5 minutes with the sample in place and verify that WLR is close to 0%. &I R At 13. Change the'Type of Water" and the "Type of oil' from "Dead" to "Live" before flowing through the meter. 14. Replace the blind flange on the access flange and line up the valves to properly return the meter to service if no fluid pipe references will be performed. Wells Online: S1V4I - 2 .f3 - S - G Well Profile: �d Mass Attenuations Oil I Water I Gas LE 0.0Z5fe44 1,0-0 38 35' 16,0257 r'2 HE O 1-7s54 10,0/ 0.0/8241 356 0.0 ie87&. 1P.O1747 10,0/2L/ 17 Date Performed: 4 /i Production Field Superintendent: L�YY Anton Pear GmbH Anton-Paar-Stra6e 20 8054 Graz Austria Anton Paar SVM 2001 - Measurement Results: Software version: 2.91.5841.209 SVM serial number: 82086572 Instrument name: -- Instrument location: --- Sample Information ► Unique Sample Id: ► Date: ► Time: ► Sample Name: ► Measurement Mode: ► Master Condition: ► Sample Error State: Measurement Result: Sub Unlgm Time Measurement Sample Number Id 576 9/6/2018 9:57:28 AM WMRU Oil 9/6/18 Repeated Mode valid no error Call Dyn. 10n. RDV V1 -. Shear Shear Density RDD Temp. Vier. Vis-. Pretision Rate Stress f Cl fmPa-sl fmmilsl I%1 f1/51 [Pal fda19 fNrm'I 1 577 9:52:06 AM 37.779 22.485 25.605 — Fast 319.6 7.1871 0.8816 — 2 578 9:54:21 AM 37.778 22.552 25.290 0.30 Fast 319.0 7.1935 0.8917 0.0102 Density D2161 D2161 Preasion Sayboil Saybolt Thursday, September 06, 2018 Page 1 of 1 Univers.Vis. Fuml Vis. fSUSI ISFSI Fast 121.6 — Fast 120.6 — Fast 120.7 Fast 120.7 0.45 Thursday, September 06, 2018 Page 1 of 1 Arlon Pear GmbH Anton-Paar-StraBe 20 8054 Graz Austria Anton Paar SVM 2001 - Measurement Results: Software version: 2.91.5841.209 SVM serial number: 82086572 Instrument name: — Instrument location: — Sample Information Unique Sample Id: Date: s Time: ® Sample Name: o Measurement Mode: . Master Condition: Sample Error State: Measurement Result: Sub unique Time Measurement Sample Number Id 572 9/6/2018 9:41:31 AM WMRU Water 916/18 Repeated Mode valid no error Cell Dyn. Fin. RDV Visa Shear Shear Density RDD Temp. Vim Vise Precision Rate Stress r°Cl ImPa-sl Imm4sl 1%1 It/sl (Pal Nang Io/an9 1 573 9:35:46 AM 15.554 1.1707 1.1459 — Fast 980.6 1.1480 1.0217 — 2 574 938:37 AM 15.553 1.1493 1.1344 -1.86 Fast 9824 1.1291 1.0132 -0.0085 Density D2161 D2161 Precision Saybolt Sayboll Thursday, September 06, 2018 Page 1 of 1 Univ .Vis. Furol Vis (Susi ISFSI Fast 29.6 — Fast 29.5 — Fast 29.6 Fast 29.8 6.05 Thursday, September 06, 2018 Page 1 of 1 GLACIER Sep 10, 2018 Mr. Hollis French Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: AIO 32.001 Monthly Reporting Dear Commissioner French, sp i Q 2019 As required by Area Injection Order No. 32.001 issued by the AOGCC on December 28th 2017, the monthly report involving well pressures, injection rates and pressure bleeds for all annuli for the well RU-3A for the month of August 2018 is provided to the Commission for review. There were no bleeds conducted for this month Cook Inlet Energy is currently maintaining and operating well shut-in equipment linked to the RU-3A inner annular pressure as directed. The last test of the system was conducted on August 14, 2018. The next test will be conducted during the month of February The last mechanical integrity test of the well was conducted on December 23, 2017 in presence of an AOGCC inspector. The next MIT test will be performed before or during the month of December 2019 as required by the order. In addition to the above, CIE will be following all stipulations mentioned in the order I am available at your convenience to discuss this report or provide additional information. Please contact me at (907) 433-3822 or at dpascalgglacieroil.com 601 "1. ," Avenue. Suits 310, Anchorage, AK 99501 (907) 334-6745 hTain 1 (907) 334-6735 Fax Page 1 of 2 Sincerely, Vice(President, Operations Cook Inlet Energy A Glacier Oil and Gas Wholly Owned Company Attachments 1. RU-3A Operations Log, August 2018 Page 2 of 2 RU 3A Injection Tracking Report August 2018 Inner Annulus Outer Annulus Date Wellhead Pressure (psi) Injected Volume (bbls) Avg. Pressure (psi) Bleed Time (Hours: Min) Total Pressure Bled (psi) Total Volume Bled (bbl) Avg. Pressure (psi) 8/1/18 4,213 3,139 930 0:00 0 0.0 30 8/2/18 4,212 3,140 934 0:00 0 0.0 30 8/3/18 4,216 3,148 936 0:00 0 0.0 30 8/4/18 4,228 3,165 954 0:00 0 0.0 30 8/5/18 4,227 3,202 958 0:00 0 0.0 30 8/6/18 4,219 3,226 948 0:00 0 0.0 30 8/7/18 4,214 3,240 956 0:00 0 0.0 30 8/8/18 4,200 3,187 958 0:00 0 0.0 30 8/9118 4,201 3,191 960 0:00 0 0.0 30 8/10/18 4,199 3,193 1 959 0:00 0 0.0 30 8/11/18 4,196 3,205 959 0:00 0 0.0 30 8/12/18 1 4,212 3,296 962 0:00 0 0.0 30 8/13/18 4,211 3,265 950 0:00 0 0.0 30 8/14/18 4,161 3,193 938 0:00 0 0.0 30 8/15/18 3,800 2,600 934 0:00 0 0.0 30 8/16/18 4,131 3,577 955 0:00 0 0.0 30 8/17/18 4,141 3,553 960 0:00 0 0.0 30 8/18/18 4,156 3,484 1 957 0:00 0 0.0 30 8/19/18 1 4,085 3,132 927 0:00 0 0.0 30 8/20/18 3,831 2,259 834 0:00 0 0.0 30 8/21118 3,906 2,641 830 0:00 0 0.0 30 8/22/18 4,095 3,302 833 0:00 0 0.0 30 8/23/18 4,130 3,297 823 0:00 0 0.0 30 8/24/18 4,154 3,316 804 0:00 0 0.0 30 8/25/18 4,170 3,320 1 802 0:00 0 0.0 30 8/26/18 1 4,186 3,348 800 0:00 0 0.0 30 8/27/18 4,209 3,579 805 0:00 0 0.0 30 8/28/18 4,239 3,579 812 0:00 1 0 0.0 30 8/29/18 3,119 1,297 843 0:00 0 1 0.0 30 8/30/18 1,662 0 942 0:00 0 0.0 30 8/31/18 2,561 1,570 917 0:00 0 0.0 30 GLACIER Aug 6, 2018 Mr. Hollis French Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: AIO 32.001 Monthly Reporting Dear Commissioner French, RECEIVED AUG 0 6 2018 AOGCC As required by Area Injection Order No. 32.001 issued by the AOGCC on December 28`h, 2017, the monthly report involving well pressures, injection rates and pressure bleeds for all annuli for the well RU -3A for the month of July 2018 is provided to the Commission for review. There were no bleeds conducted for this month, Cook Inlet Energy is currently maintaining and operating well shut-in equipment linked to the RU -3A inner annular pressure as directed. The last test of the system was conducted on February 14, 2018. The next test will be conducted during the month of August The last mechanical integrity test of the well was conducted on December 23, 2017 in presence of an AOGCC inspector. The next MIT test will be performed before or during the month of December 2019 as required by the order. In addition to the above, CIE will be following all stipulations mentioned in the order. I am available at your convenience to discuss this report or provide additional information. Please contact me at (907) 433-3822 or at dpascal(d,)glacieroil.com, 6111 AA.:" \v, I'm, : 10, .Anchmagc, AK 99501 1911"71 51467.}5 WIm 119071334-673 Fax Page 1 of 2 Sincerely, l'" g D d Pascal Vi e President, Operations Cook Inlet Energy A Glacier Oil and Gas Wholly Owned Company Attachments 1. RU -3A Operations Log, July 2018 Page 2 of 2 RU 3A Injection Tracking Report July 2018 Inner Annulus Outer Annulus Date Wellhead Pressure (psi) Injected Volume (bbls) Avg. Pressure (psi) Bleed Time (Hours: Min) Total Pressure Bled Total Volume Bled (psi) (bbl) Avg. Pressure (psi) 7/1/18 4,181 3,172 828 0:00 0 0.0 30 7/2/18 4,202 3,252 847 0:00 0 0.0 30 7/3/18 4,206 3,251 861 0:00 0 0.0 30 7/4/18 4,210 3,263 870 0:00 0 0.0 30 7/5/18 4,213 3,233 876 0:00 0 0.0 30 7/6/18 4,214 3,215 889 0:00 0 0.0 30 7/7/18 4,199 3,130 891 0:00 0 0.0 30 7/8/18 4,199 3,154 891 0:00 0 0.0 30 7/9/18 41199 3,161 882 0:00 0 0.0 30 7/10/18 4,201 3,144 876 0:00 0 0.0 30 7/11/18 4,202 3,153 875 0:00 0 0.0 30 7/12/18 4,207 3,129 881 0:00 0 0.0 30 7/13/18 4,211 3,140 888 0:00 0 0.0 30 7/14/18 4,209 3,135 887 0:00 0 0.0 30 7/15/18 41211 3,137 890 0:00 0 0.0 30 7/16/18 4,212 3,115 897 0:00 0 0.0 30 7/17/18 4,211 3,117 903 0:00 0 0.0 30 7/18/18 4,209 3,144 912 0:00 0 0.0 30 7/19/18 4,211 3,128 917 0:00 0 0.0 30 7/20/18 4,213 3,139 919 0:00 0 0.0 30 7/21/18 4,218 3,155 929 0:00 0 0.0 30 7/22/18 4,215 3,190 936 0:00 0 0.0 30 7/23/18 4,216 3,203 941 0:00 0 0.0 30 7/24/18 4,215 3,189 937 0:00 0 0.0 30 7/25/18 4,216 3,187 934 0:00 0 0.0 30 7/26/18 4,213 3,176 930 0:00 0 0.0 30 7/27/18 4,216 3,178 928 0:00 0 0.0 30 7/28/18 4,218 3,158 922 0:00 0 0.0 30 7/29/18 4,220 3,163 913 0:00 0 0.0 30 7/30/18 4,220 3,160 912 0:00 0 0.0 30 7/31/18 4,216 3,155 922 0:00 0 0.0 30 GLACIER RECEIVED July 2, 2018 JUL 0 2 2018 Mr. Hollis French AOGCC Chair, Commissioner A Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: AIO 32.001 Monthly Reporting Dear Commissioner French, As required by Area Injection Order No. 32.001 issued by the AOGCC on December 28`h 2017, the monthly report involving well pressures, injection rates and pressure bleeds for all annuli for the well RU -3A for the month of June 2018 is provided to the Commission for review. There were no bleeds conducted for this month Cook Inlet Energy is currently maintaining and operating well shut-in equipment linked to the RU -3A inner annular pressure as directed. The last test of the system was conducted on February 14, 2018. The next test will be conducted during the month of August The last mechanical integrity test of the well was conducted on December 23, 2017 in presence of an AOGCC inspector. The next MIT test will be performed before or during the month of December 2019 as required by the order. In addition to the above, CIE will be following all stipulations mentioned in the order I am available at your convenience to discuss this report or provide additional information. Please contact me at (907) 433-3822 or at dpascal(a)glacieroil.com 5111 AA. ;'i' 1�.m m-. "mlo 3111. Au'hol. . A1\ 99,n1 1111171334-67-hAIain f907;1334-673�1-L.v Page 1 of 2 Sincerely, Pioduction Manager Cook Inlet Energy A Glacier Oil and Gas Wholly Owned Company Attachments 1. RU -3A Operations Log, June 2018 Page 2 of 2 RU 3A Injection Tracking Report June 2018 InnerAnnu/us OuterAnnu/us Date Wellhead Pressure (psi) Injected Volume (bbls) Avg. Pressure (psi) Bleed Time (Hours: Min) Total Pressure Bled Total Volume Bled (psi) (bbl) Avg. Pressure (psi) 6/1/18 4,104 3,474 684 0:00 0 0.0 25 6/2/18 4,119 3,534 697 0:00 0 0.0 25 6/3118 4,133 3,535 703 0:00 0 0.0 25 614/18 4,141 3,538 708 0:00 0 0.0 25 6/5118 4,147 3,490 714 0:00 0 0.0 25 616/18 4,142 3,473 719 0:00 0 0.0 25 617/18 4,151 3,475 729 0:00 0 0.0 25 6/8/18 4,161 3,463 738 0:00 0 0.0 25 619/18 4,164 3,463 746 0:00 0 0.0 25 6/10/18 4,171 3,458 750 0:00 0 0.0 25 6/11/18 4,181 3,445 751 0:00 0 0.0 25 6/12/18 4,184 3,460 757 000 0 0.0 25 6/13/18 4,155 3,386 754 0:00 0 0.0 25 6/14/18 4,152 3,294 757 0:00 0 0.0 25 6115118 4,052 3,179 746 0:00 0 0.0 25 6/16118 4,160 3,425 764 0:00 0 0.0 25 6117/18 4,164 3,401 756 0:00 0 0.0 25 6118118 4,150 3,262 754 0:00 0 0.0 25 6/19/18 4,152 3,240 757 0:00 0 0.0 25 6/20/18 4,155 3,242 766 0:00 0 0.0 25 6/21/18 4,158 3,254 778 0:00 0 0.0 25 6/22/18 4,156 3,231 780 0:00 0 0.0 25 6/23/18 4,180 3,307 792 0:00 0 0.0 25 6/24/18 4,186 3,325 801 0:00 0 0.0 25 6125/18 4,177 3,250 801 0:00 0 0.0 25 6126118 4,172 3,217 803 0:00 0 0.0 25 6/27/18 4,172 3,215 806 000 0 0.0 25 6/28/18 4,189 3,282 814 0:00 0 0.0 25 6/29118 4,199 3,296 826 0:00 0 0.0 25 6/30/18 4,180 3,193 824 0:00 0 0.0 25 0 Cel�C�lI�:7 June 11, 2018 Mr. Hollis French Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: AIO 32.001 Monthly Reporting Dear Commissioner French, RECEIVED JUN 11 2018 AOGCC As required by Area Injection Order No. 32.001 issued by the AOGCC on December 281h, 2017, the monthly report involving well pressures, injection rates and pressure bleeds for all annuli for the well RU -3A for the month of May 2018 is provided to the Commission for review. There were no bleeds conducted for this month Cook Inlet Energy is currently maintaining and operating well shut-in equipment linked to the RU -3A inner annular pressure as directed. The last test of the system was conducted on February 14, 2018. The next test will be conducted during the month of August The last mechanical integrity test of the well was conducted on December 23, 2017 in presence of an AOGCC inspector. The next MIT test will be performed before or during the month of December 2019 as required by the order. In addition to the above, CIE will be following all stipulations mentioned in the order I am available at your convenience to discuss this report or provide additional information. Please contact me at (907) 433-3822 or at dpascal(�glacieroil.com LIII AA.;" V� c uuc, Aui1c 3116. Arc h.n'at;c. %1,99;111 VU iI :}-1-h74; Alain 119071 334-673; Pax Page 1 of 2 Sincerely, 1 Dd Pascal Prolduction Manager Cook Inlet Energy A Glacier Oil and Gas Wholly Owned Company Attachments 1. RU -3A Operations Log, May 2018 Page 2 of 2 Attachment 1: RU -3A May 2018 Operations Log RU 3A Injection Tracking Report May 2018 Inner Annulus Outer Annulus Date Wellhead Pressure (psi) Injected Volume (bbis) Avg. Pressure (psi) Bleed Time (Hours: Min) Total Pressure Bled (psi) Total Volume Bled (bbl) Avg. Pressure (psi) 5/1/18 4,179 3,001 530 0:00 0 0.0 25 5/2/18 4,173 3,037 537 0:00 0 0.0 25 5/3/18 4,174 3,024 544 0:00 0 0.0 25 5/4/18 4,178 3,030 546 0:00 0 0.0 25 5/5/18 4,175 3,049 549 0:00 0 0.0 25 5/6/18 1 4,174 3,080 558 0:00 0 0.0 25 5/7/18 4,194 3,120 573 0:00 0 0.0 25 5/8118 4,202 3,102 - 583 0:00 0 0.0 25 5/9/18 4,203 3,087 587 0:00 0 0.0 25 5/10/18 4,205 3,074 588 0:00 0 0.0 25 5/11/18 4,205 3,067 585 0:00 0 0.0 25 5/12/18 4,209 3,058 589 0:00 0 0.0 25 5/13/18 4,209 3,055 592 0:00 0 0.0 25 5/14/18 4,189 2,977 594 0:00 0 0.0 25 5/15/18 4,179 2,937 590 0:00 0 0.0 25 5116/18 4,177 2,954 589 0:00 0 0.0 25 5117/18 4,179 2,961 594 0:00 0 0.0 25 5/18/18 4,180 2,951 597 0:00 0 0.0 25 5/19/18 4,180 2,952 603 0:00 0 0.0 25 5/20/18 4,179 2,970 607 0:00 0 0.0 25 5/21/18 4,180 2,965 612 0:00 0 0.0 25 5/22/18 4,182 2,974 620 0:00 0 0.0 25 5/23/18 4,174 3,011 629 0:00 0 0.0 25 5/24/18 4,171 3,068 635 0:00 0 0.0 25 5/25/18 3,807 2,395 643 0:00 0 0.0 25 5/26/18 1,810 0 761 0:00 0 0.0 25 5127118 1,261 0 830 0:00 0 0.0 25 5/28/18 1,538 533 838 0:00 0 0.0 25 5/29/18 3,970 3,725 634 0:00 0 0.0 25 5/30/18 4,050 3,674 652 0:00 0 0.0 25 5/31/18 4,086 3,632 669 0:00 0 0.0 25 GLACIER May 9, 2018 Mr. Hollis French Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: AIO 32.001 Monthly Reporting Dear Commissioner French, EC NED MAY 002018 AOGCC As required by Area Injection Order No. 32.001 issued by the AOGCC on December 28t1, 2017, the monthly report involving well pressures, injection rates and pressure bleeds for all annuli for the well RU -3A for the month of April 2018 is provided to the Commission for review. There were no bleeds conducted for this month Cook Inlet Energy is currently maintaining and operating well shut-in equipment linked to the RU -3A inner annular pressure as directed. The last test of the system was conducted on February 14, 2018. The next test will be conducted during the month of August The last mechanical integrity test of the well was conducted on December 23, 2017 in presence of an AOGCC inspector. The next MIT test will be performed before or during the month of December 2019 as required by the order. In addition to the above, CIE will be following all stipulations mentioned in the order I am available at your convenience to discuss this report or provide additional information. Please contact me at (907) 433-3822 or at dpascalAglacieroil.com 601 N.5"' VNcu uc, Suity ;111, Anc h nr;l p, V. Uk 9'15111 (9117) 334.6745 Main 1 191171 334-6735 1'ac Page 1 of 2 Sincerely, David Pascal Production Manager Cook Inlet Energy A Glacier Oil and Gas Wholly Owned Company Attachments 1. RU -3A Operations Log, April 2018 Page 2 of 2 Attachment 1 RU 3A Injection Tracking Report April 2018 Inner Annulus Outer Annulus Date Wellhead Pressure (psi) Injected Volume (bbls) Avg. Pressure (psi) Bleed Time (Hours: Min) Total Pressure Bled Total Volume Bled (psi) (bbl) Avg. Pressure (psi) 4/1/18 4,235 2,896 467 000 0 0.0 25 4/2/18 4,232 2,863 468 0:00 0 0.0 25 4/3/18 4,209 2,773 464 0:00 0 0.0 25 4/4/18 4,211 2,790 461 0:00 0 0.0 25 4/5/18 4,211 2,765 459 0:00 0 0.0 25 4/6/18 4,217 2,773 468 0:00 0 0.0 25 4/7/18 4,228 2,789 485 0:00 0 0.0 25 4/8/18 4,212 2,734 494 0:00 0 0.0 25 4/9/18 41206 2,737 494 0:00 0 0.0 25 4/10/18 4,231 2,833 499 000 0 0.0 25 4/11/18 4,231 2,862 499 0:00 0 0.0 25 4/12/18 4,321 2,868 498 0:00 0 0.0 25 4/13/18 4,231 2,872 501 0:00 0 0.0 25 4/14/18 4,230 2,888 502 0:00 0 0.0 25 4/15/18 4,200 2,839 497 0:00 0 0.0 25 4/16/18 4,199 2,845 495 0:00 0 0.0 25 4/17/18 4,202 2,851 496 0:00 0 0.0 25 4/18/18 4,203 2,880 497 0:00 0 0.0 25 4/19/18 4,198 2,866 501 0:00 0 0.0 25 4/20/18 4,197 2,879 509 0:00 0 0.0 25 4/21/18 4,197 2,878 513 0:00 0 0.0 25 4/22/18 4,196 2,903 518 0:00 0 0.0 25 4/23/18 4,194 2,921 522 0:00 0 0.0 25 4/24/18 4,199 2,960 524 0:00 0 0.0 25 4/25/18 4,195 2,993 516 0:00 0 0.0 25 4/26/18 4,176 2,964 521 0:00 0 0.0 25 4/27/18 4,178 2,977 525 0:00 0 0.0 25 4/28/18 4,183 2,976 525 0100 0 0.0 25 4/29/18 4,181 2, 981 526 0:00 0 0.0 25 4/30/18 4,183 3,000 525 0:00 0 0.0 25 GLACIER April 2, 2018 Mr. Hollis French Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: AIO 32.001 Monthly Reporting Dear Commissioner French, As required by Area Injection Order No. 32.001 issued by the AOGCC on December 28`n 2017, the monthly report involving well pressures, injection rates and pressure bleeds for all annuli for the well RU -3A for the month of March 2018 is provided to the Commission for review. There were no bleeds conducted for this month Cook Inlet Energy is currently maintaining and operating well shut-in equipment linked to the RU -3A inner annular pressure as directed. The last test of the system was conducted on February 14, 2018. The next test will be conducted during the month of August The last mechanical integrity test of the well was conducted on December 23, 2017 in presence of an AOGCC inspector. The next MIT test will be performed before or during the month of December 2019 as required by the order. In addition to the above, CIE will be following all stipulations mentioned in the order I am available at your convenience to discuss this report or provide additional information. Please contact me at (907) 433-3822 or at dpascal(a)glacieroil.com 601 W. 5'" Avenue, Suite 310, Anchorage, AK 99501 (907) 334-6745 Main 1 (907) 334-6735 Fax Sincerely, CI 1d Pascal Pr duction Manager Cook Inlet Energy A Glacier Oil and Gas Wholly Owned Company Attachments 1. RU -3A Operations Log, March 2018 601 W. 5'" Avenue, Suite 310, Anchorage, AK 99501 (907) 334-6745 Main 1 (907) 334-6735 Fax RU 3A Injection Tracking Report March 2018 Inner Annulus Outer Annulus Date Wellhead Pressure (psi) Injected Volume (bbls) Avg. Pressure (psi) Bleed Time (Hours: Min Total Pressure Bled (psi) Total Volume Bled (bbl) Avg. Pressure (psi) 3/1/18 3,735 2,437 438 0:00 0 0.0 25 3/2/18 4,207 3,038 418 0:00 0 0.0 25 3/3/18 4,258 3,102 429 0:00 0 0.0 25 3/4/18 4,270 3,048 434 0:00 0 0.0 25 3/5/18 4,275 3,039 438 0:00 0 0.0 25 3/6/18 4,228 2,941 433 0:00 0 0.0 25 3/7/18 4,257 2,985 433 0:00 0 0.0 25 3/8/18 4,269 3,025 438 0:00 0 0.0 25 3/9/18 4,272 3,031 440 0:00 0 0.0 25 3/10/18 1 4,274 3,007 445 0:00 0 0.0 25 3/11/18 4,274 2,848 448 0:00 0 0.0 25 3/12/18 4,272 2,983 447 0:00 0 0.0 25 3/13/18 4,274 2,978 447 0:00 0 0.0 25 3/14/18 4,274 2,988 447 0:00 0 0.0 25 3/15/18 4,235 2,921 441 0:00 0 0.0 25 3/16/18 4,262 3,009 441 0:00 0 0.0 25 3/17/18 4,279 3,047 445 0:00 0 0.0 25 3/18/18 4,295 3,062 453 0:00 0 0.0 25 3/19/18 4,264 2,919 450 0:00 0 0.0 25 3/20/18 4,195 2,726 455 0:00 0 0.0 25 3/21/18 4,207 2,792 455 0:00 0 0.0 25 3/22/18 4,215 2,818 453 0:00 0 0.0 25 3/23/18 4,221 2,827 455 0:00 0 0.0 25 3/24/18 4,226 2,845 460 0:00 0 0.0 25 3/25/18 4,226 2,865 464 0:00 0 0.0 25 3/26/18 4,226 2,877 463 0:00 0 0.0 25 3/27/18 4,227 2,892 463 0:00 0 0.0 25 3/28/18 4,288 2,891 463 0:00 0 0.0 25 3/29/18 4,234 2,877 464 0:00 0 0.0 25 3/30/18 4,233 2,883 464 0:00 0 00 25 3/31/18 4,232 2,893 465 0:00 0 0.. 0 25 GLACIER March 5, 2018 Mr. Hollis French, Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: AID 32.001 Monthly Reporting Dear Commissioner French, RECEIVED MAR 0 5 2013 AOGCC As required by Area Injection Order No. 32.001 issued by the AOGCC on December 28`n 2017, the monthly report involving well pressures, injection rates and pressure bleeds for all annuli for the well RU -3A for the month of February 2018 is provided to the Commission for review. There were no bleeds conducted for this month Cook Inlet Energy is currently maintaining and operating well shut-in equipment linked to the RU -3A inner annular pressure as directed. The last test of the system was conducted on February 14, 2018 along with SVS testing for the platform and is attached for your reference. The next test will be conducted during the month of August The last mechanical integrity test of the well was conducted on December 23, 2017 in presence of an AOGCC inspector. The next MIT test will be performed before or during the month of December 2019 as required by the order. In addition to the above, CIE will be following all stipulations mentioned in the order I am available at your convenience to discuss this report or provide additional information. Please contact me at (907) 433-3822 or at dpascal aAglacieroil.com 601 W. 5'" Avenue, Suite 310, Anchorage, AK 99501 (907) 334-6745 Main 1 (907) 334-6735 Fax Sincerely, °U"' rg 3� Davi Pascal Production Manager Cook Inlet Energy A Glacier Oil and Gas Wholly Owned Company Attachments I. RU -3A Operations Log, February 2018 2. RU -3A Well Shut-in Test, February 14, 2018 601 W. 5'" Avenue, Suite 310, Anchorage, AK 99501 (907)334-6745 Main 1 (907) 334-6735 Fax RU 3A Injection Tracking Report Feb 2018 InnerAnnulus Outer Annulus Date Wellhead Pressure Injected Volume Avg. Pressure Bleed Time Total Pressure Bled Total Volume Bled Avg. Pressure (psi) (bbls) (psi) (Hours: Min) (psi) (bbl) (psi) 2/1/18 4,331 2,688 155 0:00 0 0.0 20 2/2/18 4,318 2,608 175 0:00 0 0.0 20 2/3/18 4,315 2,669 200 0:00 0 0.0 20 2/4/18 4,315 2,655 218 0:00 0 0.0 20 2/5/18 4,322 2,674 234 0:00 0 0.0 20 2/6/18 4,324 2,669 252 0:00 0 0.0 20 2/7/18 4,323 2,654 271 0:00 0 0.0 20 2/8/18 4,324 2,654 291 0:00 0 0.0 20 2/9/18 4,322 2,662 308 0:00 0 0.0 20 2/10/18 4,323 2,662 321 0:00 0 0.0 20 2/11/18 4,324 2,638 337 0:00 0 0.0 20 2/12/18 4,328 2,664 351 0:00 0 0.0 20 2/13/18 4,324 2,640 368 0:00 0 0.0 20 2/14/18 4,269 2,630 374 0:00 00.0 20 2/15/18 4,297 2,849 384 0:00 0 0.0 20 2/16/18 4,297 2,831 401 0:00 0 0.0 20 2/17/18 4,276 2,796 414 0:00 0 0.0 20 2/18/18 4,293 2,850 432 000 0 0.0 25 2/19/18 4,026 2,344 424 0:00 0 0.0 20 2/20/18 4,248 2,988 426 0:00 0 0.0 20 2/21/18 4,266 3,002 438 0:00 0 0.0 20 2/22/18 4,268 3,011 442 0:00 0 0.0 25 2/23/18 3,983 2,598 438 0:00 0 0.0 20 2/24/18 4,118 2,671 413 0:00 0 0.0 20 2/25/18 4,286 3,068 447 0:00 0 0.0 25 2/26/18 4,301 3,058 450 0:000 0.0 25 2/27/18 4,284 3,035 445 0:00 0 0.0 25 2/28/18 4,273 2,983 1 440 0:00 1 0 0.0 25 Alaska Oil and Gas Conservation Commission Safety Valve System Test Report Operator: Cook Inlet Energ Submitted By: David Pascal Date: 2/14/18 Operator Rep: Sean Sullivan Field/Unit/Pad: osprey/Redoubt Shoal AOGCC Rep: Waived Separator psi: LPS 88 HPS N/A Well Data I Well Permit Separ Number Number PSI 3A 2161700 0 Set UP PSI Trip 2500 2501 I SSV Test Test Code Code NT NT SSSV I Test Code NT Retese/SI Date Date Passed Retest Or Date Shut In Well Tye Well Pressures Gas Lift Waiver Oil, WAG, GING, Inner Outer Tubing Yes/No Yes/No GAs, CvcLE, si PSI PSI PSI 381 21 4287 no Wells: 1 Components: 1 Failures: 0 Failure Rate. 0.00% Q 90 Day Remarks: "0" entered in "Set PSP' to count well. IA pilot set @ 2500psi tripped @ 2501 psi (PASS) AIO 32.001 PLB 01/26/11 Page 1 of 1 2. RU -3A SVS IA pilot 2-14-18 .xlsx GLACIER Feb 8, 2018 Mr. Hollis French, Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: AIO 32.001 Monthly Reporting Dear Commissioner French, RECEIVED FEB 0 8 2018 AOGCC As required by Area Injection Order No. 32.001 issued by the AOGCC on Dec 28`n 2017, the monthly report involving well pressures, injection rates and pressure bleeds for all annuli for the well RU -3A for the month of Jan 2018 is provided to the Commission for review Cook Inlet Energy is currently maintaining and operating well shut-in equipment linked to the RU -3A inner annular pressure as directed. The last test of the system was conducted on Jan 10, 2018 and is attached for your reference. The next test will be conducted on Feb 14, 2018 in conjunction with regular SVS testing on the platform as required by the order The last mechanical integrity test of the well was conducted on Dec 23, 2017 in presence of an AOGCC inspector. The next MIT test will be performed before or during the month of Dec 2019 as required by the order. In addition to the above, CIE will be following all stipulations mentioned in the order I am available at your convenience to discuss this report or provide additional information. Please don't hesitate to contact me at (907) 433-3822 or at dpascalAglacieroil.com 601 W. 5`h Avenue, Suite 310, Anchorage, AK 99501 (907) 334-6745 Main 1 (907) 334-6735 Fax Sincerely, Dav d Pascal Production Manager Cook Inlet Energy A Glacier Oil and Gas Wholly Owned Company Attachments 1. RU -3A Operations Log, Jan 2018 2. RU -3A Well Shut-in Test, Jan 10, 2018 3. RU -3A MIT Test, Dec 23, 2017 601 W. 5'" Avenue, Suite 310, Anchorage, AK 99501 (907) 334-6745 Main 1 (907) 334-6735 Fax Attachment j RU 3A Injection Tracking Report Jan 2018 Inner Annulus Outer Annulus Date Wellhead Pressure (psi) Injected Volume Avg. Pressure (bbls) (psi) Bleed Time (Hours: Min) Total Pressure Bled (psi) Bleed Volume (bbl) Avg. Pressure (psi) 1/1/18 4,303 2,700 85 0:00 0 20 1/2/18 4,302 2,674 105 000 0 20 1/3/18 4,305 2,663 127 0:00 0 20 1/4/18 4,311 2,645 145 0:00 0 20 1/5/18 4,314 2,639 158 0:00 0 20 1/6/18 4,313 2,650 157 0:00 0 20 1/7/18 4,313 2,650 189 0:00 0 20 1/8/18 4,315 2,637 208 0:00 1 0. 20 1/9/18 4,317 2,635 222 0:00 0 20 1/10/18 4,307 2,639 231 0:00 0 20 1/11/18 4,328 2,687 241 0:00 0 20 1/12/18 4,306 2,618 92 2:40 197 0.0 20 1/13/18 4,312 2,630 76 0:00 0 20 1/14/18 1 4,307 2,629 96 0:00 020 1/15/18 4,332 2,740 113 0:00 0 20 1/16/18 4,370 2,758 127 0:00 0 20 1/17/18 4,364 2,714 148 0:00 0 20 1/18/18 4,341 2,613 154 0:00 1 0 20 1/19/18 4,308 2,551 58 1:15 112 0.0 20 1/20/18 4,339 2,680 79 0:00 0 20 1/21/18 4,363 2,724 101 0:00 0 20 1/22/18 4,356 2,697 117 0:00 0 20 1/23/18 1 4,353 2,689 134 0:00 0 1 20 1/24/18 4,353 2,686 148 0:00 0 20 1/25/18 4,343 2,659 160 0:00 0 20 1/26/18 4,262 2,435 160 000 0 20 1/27/18 4,244 2,425 163 0:00 1 0 20 1/28/18 4,291 2,564 184 0:00 0 20 1/29/18 4,327 2,672 117 1:00 100 0.5 20 1/30/18 4,346 2,721 131 0:00 0 0.0 20 1/31/18 4,249 2,730 145 0:00 0 0.0 20 Attachment 2 Alaska Oil and Gas Conservation Commission Safety Valve System Test Report Operator: Cook Inlet Energ Submitted By: David Pascal Date: 1/10/18 Operator Rep: Sean Sullivan Field/Unit/Pad: Osprey/Redoubt Shoal AOGCC Rep: Waived Separator psi: LPS 81 HPS N/A Well Data Pilots SSV SSSV RetesbSl Date Well Type Well Pressures Gas Lift Waiver Well Permit Separ Number Number PSI Set UP PSI Trip Test Test Code Code Test Date Passed Retest MWAG,GM, Inner Outer Tubing Yes/No Yes/No Code Or Date Shut In GAS, CYCLE, st PSI PSI PSI 3A 2161700 0 0 0 NT NT NT 222 20 4213 no Wells: 1 Components: 0 Failures: 0 Failure Rate: #DIVIOC] 90 Day Remarks: "0" entered in "Set PSP' to count well. IA pilot set @ 2500psi, tripped @ 2501 psi (PASS) AIO 32.001 PLB 01/26/11 Page 1 of I SVS RD Shoal Osprey 01-10-18 Misc revised(1).xis Attachment 3 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanlcal Integrity Test Submit Up: -im.rea0ftalaska.aw: ACGCC InspeclorsAalaslM.wvPhoebe mooks®alaska.aov OPERATOR Glacier Oilantl Gas FIELD / UNIT / PAD: osprey Platform -Redoubt Unit DATE lMN17 OPERATOR RER Lance Anderson AOGCC REP: Brien Bixby cbris.wellacaaabslue.n. Well RUSA e111met.c.ee Pressures: Pretest Initial 15 Min. 30 Min. 45 Min, W Min. <=Four Yem Cydo F=FN PTD 2161700 Type lnj W Tubing 1970 19701965 0=0swrleeanbin-.) 1965 N=Nd lryecllnp Type Test P Packer TVD 5989 BBLPump 35 IA 425 2810 2810 2810 1 1 Intmil 1 O Test psi 2500 BBL Return 3.5 OA 25 35 37 37 Result IP Nates: Teel br adminiAretive approval peperwmk b 3500 psi, Well Pressures: Pretest Insist 15 Min. 30 Min. 45Min. Whin. PTDTypelnj Tuts, Typa Test Packer TVO BBLPump IA Interval Test psi BBL Return OA ResuN N9ks: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. W Min. PTD Type by TubinType Test Packer TVD BBLPump IA Intmal Teat psi BEL R9tust OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45Min. Whin. PTDType lnj Turing Type Teal Packer TVD BBLPump IA Interval Test psi BBI -Rehm OA Result N9kE: Well Pressures: Pretest Initial 15 Min. 30 Min. 45Min. 60 Min. PTD Typalnj Tubing Type Test Packer TVD BBLPump IA Interval Test psi BBL Return OA Result Needs: well Pressures: Pretest Initial 15 Min. 30 Min. 45Min. WMin. PTD Type lnl Tubing Type Test Packer TVD 8 IA Interval Test psi BBLReWm OA Result Netea: Well Pressures: Pretest Initial 15Ms. WMin. 45Min. 6DMin. PTO TypelnjTubing Type Teal Packer TVD BBLPump IA internal Test psi BBL Reklln OA Res11N Nebo: WellPressures: Pretest Insist 15 Min. 30 Min. 45Min. 60 Min. PTD Type lnj Tubing I i i i i i Type Test Packer TVD BBLPump IA Inbrvai Test psi BBL Redeem OA Rssult Nebo: TWEWCO )YPETESTCe4N e111met.c.ee aeeWl Cod. W=Webr p=pmeue Tesl 1=WIIalT t P=Pea G=Gn 0=0Mer(be .in Nol®) <=Four Yem Cydo F=FN s=swm v=Req.. ey✓Manse 1=1n¢no . 1=Ntluslrialwxlwaly 0=0swrleeanbin-.) N=Nd lryecllnp Form 10426(R sed D12017) MNflu NtiZil)R9ebeO.tlu 11 GLACIER Dec 18, 2017 Mr. Guy Schwartz, Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: RU -3A Annular Pressure PTD: 216-170 API No: 50-733-20504-01-00 Dear Mr. Schwartz, We have noticed a possible tubing/annular communication in well RU -3A. The annulus pressure started to rise about 78 days after the well was completed. We bled it down several times as it approached 200 psi, but it would not go static. In order to confirm the communication, the annulus was shut-in and except for one 100 psi bleed down the pressue was allowed to build to 1,003 psi over 79 days (13 psi/day). The annulus was bled down to zero and 70 gallons of annular fluid was recovered. The annulus was again shut-in and monitored. The pressure on the annulus during this operation has built up to 474 psi (Dec 18) with a rate increase about 13.8 psi/day We have currently bled down the annulus pressure to 0 psi and will continue to do periodically, so that the pressure doesn't increase beyond 500 psi. At this point of time due to the small amount (-0.9 gal/day) it would be difficult to identify the source of the leak. If the rate of pressure increase exceeds 25psi/day, we would attempt to find the leak with a Sonic log. Glacier Oil and Gas requests the Commission that we continue to operate the well, as it is a critical injector to maintain reservoir pressure and resulting in GLACIER incremental reserves in the Redoubt field. If any additional information is needed, please contact me at dpascala glacieroil com or at (907) 433-3822 Sincerely, Pascal tion Manager Oil and Gas Attachments L Current Wellbore Diagram RU -03 2. Annular Pressure Trend Latest Build-up GLACIER RU -03A Wl - Current Completion Schematic 18112" HOIe 4 1/2" X 9 518' Liner Hanger TOL @ 7,500' MD Perforaliona MD ND ],700-],1100 8203-6,219 ],805-).010 6,223-6.233 Top of 7-5/11" x 9-518" Liner @ 9,103' MD 121/4" Moie 8112" Hole Pert a Slim Intervals PeW1�1�11217� SL.Gen ft MG IfMG 15)66-0565)85-157941582)-1585815862-156t W-15870 15920-15900 12202-12217 15925-15934 15840-15960 1221712233 15945-15954 16052-16W2 12304-12319 1665-16066 16076-16096 12323-12338 16081-16090 16144-16164 12376-12392 161WI6105 12393-12409 1619&16218 12419-12435 1625516275 1246512479 16260.16270 1627516295 12400-1249) 162)516287 1631516335 12518-12529 16328-163]5 16338-16346 12530-12538 16356-16376 1254612583 6 3/0" Hole PBTD: p.. Date: 5 -Jul -17 Version: Final Tubing hanger - 4.909" MCA box lop connection / 45" GeoConn Box am connection - ID 3.816" 30" 1 150#A-36260'MD ID -28" Welded 260'ND 4-1/2" 15.1# P110 Geoconn - ID 3,832- @ ]508' MD 13318" 1 68# L-80 3,50T MD ID -12.25" BTC 3,024'ND 95/8" 47# L-80 9.332' MO ID -8.50" BTC 7,416- WD "OC(CBQj 12,975- MID Window 7518" 29.7#140 14.1]6'MD ID -6.75" Hydril 521 1 10,962' ND 67' fish le0 in hole - 21' of lower gun, 1 couple0 37' gun and bull nose Obstruction tagged @ 16352' 52" fish left in hole - 6" of lower gun 1 caller. 36" gun and bull nose 4112" 15.1#P-110 16. P-1!0 ID -3.832" GeoConn 12,650- WD MIX 300 RU -3A Annular Pressure 100 0 11/L,.. 11/13/1t 11/20/17 11/28/17 12/5/17 Wallace, Chris D (DOA) k 0 From: Conrad Perry <cperry@glacieroil.com> Sent: Wednesday, December 27, 2017 1:08 PM To: Wallace, Chris D (DOA); David Pascal Cc: Schwartz, Guy L (DOA); Regg, James B (DOA); Leland Tate; pheobe.brooks@aogcc.gov; Zack Hundrup Subject: RE: Redoubt Unit 3A (PTD 2161700) Annular Pressure [Docket OTH-17-056] Chris, Glacier is in concurrence with your conditions/restrictions and have already started work on the annular pressure shut down logic and a pressure switch. We should be 100% compliant within two weeks. Is there anything else we need to supply the commission at this point? Can I presume it is ok to continue with injection until we are in receipt of the Admin Order? Thank -you again for working with us on a solution to this problem. Best Regards, Conrad Perry From: Wallace, Chris D (DOA)[mailto:chris.wallace@alaska.gov) Sent: Wednesday, December 27, 2017 11:08 AM To: David Pascal <dpascal@glacieroil.com> Cc: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov>; Regg, James B (DOA) <jim.regg@alaska.gov>; Leland Tate <Itate@glacieroil.com>; Conrad Perry <cperry@glacieroil.com>; pheobe.brooks@aogcc.gov Subject: RE: Redoubt Unit 3A (PTD 2161700) Annular Pressure [Docket OTH-17-0561 David, Examples of AIO's and Administrative Approvals are located on our website at http•//aogweb.state.ak usZwebapp/#/aio Conditions/restrictions AOGCC would look to impose on CIE for a water only administrative approval for TxIA are: 1. CIE shall record wellhead pressures and injection rate daily; 2. CIE 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. CIE shall perform a mechanical integrity test of the inner annulus every 2 years to the minimum of 2500 psi; 4. CIE shall install, maintain and operate automatic well shut-in equipment linked to the well's inner annulus (IA) pressure. The actuation pressure shall not exceed 2,500 psi for the inner annulus. 5. Testing of the shut in equipment shut -down valve and mechanical or electrical pressure device shall be performed in conjunction with production well pilots and safety valves. CIE shall provide to the commission the testing procedure that will be used to verify integrity of the well shut-in equipment linked to the inner annulus pressure; 6. CIE shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 7. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 8. The next required MIT is to be before or during the month of December 2019. The Commission must be provided the opportunity to witness the MIT for a test to establish a new test due date. Let me know if you are in agreement or propose changes to these conditions, and I can progress this. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7t" Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chrismallace(nlalaska.eov CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at 907-793-1250 or chris.wallace@alaska.aov. From: David Pascal [ma iIto: dpascal@glacieroil. corn Sent: Saturday, December 23, 2017 2:37 PM To: Wallace, Chris D (DOA) <chris.wa[lace @alaska.gov> Cc: Schwartz, Guy L (DOA) <guy.schwartzC@alaska.gov>; Regg, James B (DOA) <aim.regg@alaska.gov>; Leland Tate <Itate@glacieroil.com>; Conrad Perry <cperrv@glacieroil.com>; pheobe.brooks@aogcc.gov Subject: Re: Redoubt Unit 3A (PTD 2161700) Annular Pressure [Docket OTH-17-056] Chris, Please find form 10-426 that includes details on the successful MIT test on RU -3A conducted today, which was witnessed. Please let me know if further information is needed on the administrative approval process Thanks and Regards David Pascal From: David Pascal <dpascal@glacieroil.com> Date: Thursday, December 21, 2017 at 11:34 AM To: "Wallace, Chris D (DOA)" <chris.wallace@alaska.gov> Cc: "Schwartz, Guy L (DOA)" <guv.schwartz@alaska.Rov>, "Regg, lames B (DOA)" <iim.regg@alaska.gov>, Leland Tate <Itate@glacieroil.com>, Conrad Perry <cperrv@glacieroil.com> Subject: Re: Redoubt Unit 3A (PTD 2161700) Annular Pressure [Docket OTH-17-056] Chris, Right now with the 2,500 psi test we are already above the 0.25 psi/£t requirement. Even though the tubing is heavy wall and brand new the casing is older and putting such high pressures is not recommended since it is very close to 70% of the yield pressure of the casing. I can offer the Commission a way to automatically shut injection to the well if the casing pressure exceeds 2,500 psi if it helps with the administrative approval Thanks David From: "Wallace, Chris D (DOA)" <chris.waIlace @alaska.gov> Date: Thursday, December 21, 2017 at 9:38 AM To: David Pascal <dpascal@glacieroil.com> Cc: "Schwartz, Guy L (DOA)" <guv.schwartz@alaska.gov>, "Regg, James B (DOA)" <iim.regg@alaska.gov>, Leland Tate <Itate@glacieroil.com>, Conrad Perry <cperry@glacieroil.com> Subject: RE: Redoubt Unit 3A (PTD 2161700) Annular Pressure [Docket OTH-17-056] David, As per my previous email, an administrative approval for continued injection would require a max. injection test pressure which looks in the range of approx. 4200 to 4800 psi. This is to mimic a tubing/packer failure and injecting pressure being transferred to the IA. I am interested in why the 2500 psi and how this assists you in your efforts for continued water injection? Why is it not more like 4800 psi (maximum injection) test pressure? Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7" Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at 907-793-1250 or chris.wallace@alaska.aov. From: David Pascal [mailto:dpascal@glacieroil.com] Sent: Thursday, December 21, 2017 8:55 AM To: Wallace, Chris D (DOA) <chris.waIlace @alaska.gov> Cc: Schwartz, Guy L (DOA) <guv.schwartz@alaska.gov>; Regg, James B (DOA) <jim.regg@alaska.gov>; Leland Tate <Itate@Rlacieroil.com>; Conrad Perry <cperrv@glacieroil.com> Subject: Re: Redoubt Unit 3A (PTD 2161700) Annular Pressure [Docket OTH-17-056] Dear all, Please review the procedure for the MIT Test on RU -3A. Well -bore diagram is attached for your reference. The online notification was turned in yesterday for the MIT test . We will be ready to conduct the test at your convenience. Please let me know if anything else is needed Sincerely, David Pascal From: David Pascal <dpascal@glacieroil.com> Date: Wednesday, December 20, 2017 at 9:28 AM To: "Wallace, Chris D (DOA)" <chris.wallace@alaska.gov> Cc: "Schwartz, Guy L (DOA)" <guy.schwartz@alaska.gov>, "Regg, lames B (DOA)" <jim.reRR@alaska.gov> Subject: Re: Redoubt Unit 3A (PTD 2161700) Annular Pressure [Docket OTH-17-056] Thank you Chris for the prompt reply. Will get working on it David From: "Wallace, Chris D (DOA)" <chris.waIlace @alaska.gov> Date: Wednesday, December 20, 2017 at 9:27 AM To: David Pascal <dpascal@glacieroil.com> Cc: "Schwartz, Guy L (DOA)" <guv.schwartz@alaska.gov>, "Regg, James B (DOA)" <jim.regg@alaska.gov> Subject: RE: Redoubt Unit 3A (PTD 2161700) Annular Pressure [Docket OTH-17-056] David, In anticipation of AOGCC processing your request (December 18, 2017) for an Administrative Approval to authorize continued water only injection in a well experiencing Tubing x Inner Annulus pressure communication, Cook Inlet Energy will need to complete ASAP a passing AOGCC witnessed (or waived witness) MITIA with the test pressure being the greater of: 1. surface pressure of 1500 psi 2. surface pressure of 0.25 psi/ft multiplied by the true vertical depth of the casing shoe, or 3. the maximum injection pressure. For Cook Inlet, our inspector notification is 48 hours. 20 AAC 25.412 (c) states "Before injection begins, a well must be pressure -tested to demonstrate the mechanical integrity of the tubing and packer and of the casing immediately surrounding the injection tubing string. The casing must be tested at a surface pressure of 1,500 psig or at a surface pressure of 0.25 psi/ft multiplied by the true vertical depth of the casing shoe, whichever is greater, but the casing may not be subjected to a hoop stress that will exceed 70 percent of the minimum yield strength of the casing. The test pressure must show stabilizing pressure and may not decline more than 10 percent within 30 minutes." AOGCC Test Witness Notification is a web link http://doa.alaska.gov/ogc/farms/TestWitnessNotif.htmI AOGCC Industry Guidance Bulletin 10-02A Mechanical Integrity Testing http://doa.alaska.gov/ogc/bulletins/bul 10-02a.pdf Test pressure is detailed in this Bulletin and mentions "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." The MIT needs to be documented and sent to the AOGCC distribution as detailed on Form 10-426 which is available here. http://doa.alaska.gov/ogc/forms/forms.html Area Injection Order for Redoubt Unit AIO 32 http:/Jaogweb.state.ak.us/ogc/orders/aio/data/aio32.pdf 20 AAC 25.402 AOGCC regulations for Enhanced Recovery operations http://www.legis.state.ak.us/basis/aac.asp#20.25.402 Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7`h Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallacepalaska.¢ov CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at 907-793-1250 or chris.wallace@alaska.aov. From: David Pascal [mailto:dpascal@glacieroil.coml Sent: Tuesday, December 19, 2017 3:15 PM To: Wallace, Chris D (DOA) <chris.waIlace @alaska.gov> Cc: Schwartz, Guy L (DOA) <guv.schwartz@alaska.gov>; Regg, lames B (DOA) <lim.regg@alaska.Rov> Subject: Re: Redoubt Unit 3A (PTD 2161700) Annular Pressure [Docket OTH-17-056] Chris, Please see answers below in Red. Please let me know if you have any further questions David From: "Wallace, Chris D (DOA)" <chris.waIlace @alaska.xov> Date: Tuesday, December 19, 2017 at 11:15 AM To: David Pascal <dpascal@elacieroil.com> Cc: "Schwartz, Guy L (DOA)" <Ruv.schwartz@alaska.gov>, "Regg, James B (DOA)" <jim.reRR@alaska.aov> Subject: Redoubt Unit 3A (PTD 2161700) Annular Pressure [Docket OTH-17-0561 David, AOGCC has received your letter dated December 18, 2017 detailing a tubing/annular communication of RU -3A. It has prompted a review of this well, our regulations, and the Area Injection Order (AID) #32 that governs injection operations in this well. Our records do not show any mechanical integrity testing for this well? It looks like first injection was in the month of July 2017. Initial testing associated with a new well and additional testing with any mechanical integrity change to the well should have been completed, and once injection has commenced and stabilized as per the permit to drill, sundry applications, and AID 32 Rule 6. Do you have any information on MIT's completed, witnessed or not, rig or separately, and any explanation as to why AOGCC doesn't appear to have these records? MIT was performed on 26th March at 2,500 psi and successfully passed. Please see first attachment AIO 32 is available at http://aogweb.state.ak.us/ogc/orders/aio/data/aio32.pdf Rule 5 of AIO 32 details requirements of tubing and annuli pressures being monitored at least daily. Please provide the Tubing, Inner annuli, outer annuli pressures for the last 90 days. Please see second attachment for RU -3A injection and pressure data. Monitored hourly Rule 8 of AIO 32 details the notification requirements (next business day) when a pressure communication is indicated. Please provide when and how AOGCC was notified or if in fact this letter dated December 18, 2017 is the first AOGCC notification? Leak is minor (<0.9 gal/day) and was difficult to quantify/detect. AOGCC was notified as soon as we confirmed our suspicions via the test submitted Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at 907-793-1250 or chris.wallace@alaska.aov. 5 10 Wallace, Chris D (DOA) From: Wallace, Chris D (DOA) Sent: Wednesday, March 18, 2015 11:49 AM To: 'David Kumar' Subject: RE: AIO_32 for RU-6 (PTD 2022280) Boiler Blowdown Attachments: image001.png David, Thank you for the info. I will file this email into AIO 32 and Well file RU-6 (PTD 2022280) and you should keep for your records. No additional information is required from you. This is a non -issue for the AIO 32 and ERIO 2, and AOGCC considers this is not a miss -injection or unauthorized injection. AOGCC will not add the Osprey boiler blowdown to AIO 32 Rule 3 via Administrative Approval at this time. ERIO 2 and AIO 32 for enhanced recovery operations (EOR) has approvals for Osprey Deck Drainage. Annual reports have continued to show no adverse effects of the multiple fluids. We have on file compatibility test results for deck drain discharge mixed with produced water from 2/9/2005 and with the minimal volumes of these fluids in comparison to the produced water volumes being injected, it could be surmised that the Osprey deck drainage samples are inclusive and indicative of boiler blowdown compatibility. The authorization of the boiler blowdown as a Class I vs. Class II fluid for the FOR project is also a non -issue due to the fact the boiler blowdown and deck drainage are mixed with the produced fluid(s) prior to injection. Your boiler blowdown analysis shows it to be non -hazardous with no hazardous characteristics etc. - so no issue or concern. Thanks and Regards, Chris Wallace Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1250 (phone) (907) 276-7542 (fax) chris.wallace@alaska.gov CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at 907-793-1250 or chris.wallaceC-alaska.caov. From: David Kumar[mailto:David.Kumar@cookinlet.net] Sent: Tuesday, March 17, 2015 12:48 PM To: Wallace, Chris D (DOA) Subject: Re: AI032 for RU-6 (PTD 2022280) Boiler Blowdown Dear Mr. Wallace, Please see the answers to your questions below. Please let us know the path the Commission recommends. Thanks and Regards David Kumar From: <Wallace>, "Chris D (DOA)" <chris.waIlace @alasl<a.gov> Date: Wednesday, March 11, 2015 at 11:39 AM To: David Kumar <david.kumar@cookinlet.net> Subject: FW: A1032 for RU-6 (PTD 2022280) Boiler Blowdown David, Thank you for the notification. A few questions: 1. What is the estimated volume per day/month/year of the boiler blowdown? This table contains the amounts of boiler blowdown for your reference. Please note that we have been injecting in RU-6 since latter part of Dec 2014 when we were having issues with our primary disposal well RU-D1. There were only brief periods of injection over the years in RU-6 Date Boiler Blowdown (Gallons) 10/14/2013 100 10/15/2013 100 10/16/2013 100 10/17/2013 100 10/18/2013 125 10/19/2013 100 10/20/2013 100 10/22/2013 200 10/23/2013 100 10/24/2013 100 10/25/2013 100 10/28/2013 300 10/29/2013 100 10/30/2013 100 10/31/2013 100 Total October 2013 1,825 11/1/2013 100 11/2/2013 100 1.1/3/2013 100 3 100 100 Total November 2013 500 100 Total December 2013 100 Total 2013 2,425 1/ 1/ LUi4 100 Total January 2014 100 1/10/2015 80 1/11/2015 11 1/12/2015 12 13/2015 320 1 /2015 80 80 8no Total January 2015 1,383 2. Where exactly does this waste stream mix with the deck drain waste stream? Please see the attached schematic. Hot boiler blowdown water is cooled in a 3'X3'X3' box tank. Once it's cooled, the drain valve is opened, and it flows on the deck. The deck has a series of floor drains, the boiler blowdown commingles with the other deck drainage, and runs into a settling tank. Fluid is pumped off of top of the tank, (transfer pumps at automatic levels) to tank 105 for storage. The valve is opened to drain tank 105 back to the collection tank, the fluid then flows through filters and is injected into the well Was the blowdown always designed to mix with this waste stream? Yes When was this mixing first started? During the original configuration of the deck drain system dated 2005 Is there a filter in the boiler blowdown stream prior to mixing with the deck drain stream? No Is there a filter in the mixed (boiler + deck) prior to going downhole? Yes Has this boiler blowdown or mixture (boiler blow down plus deck drain) been analyzed for compatibility in the past? Yes I ask when was this mixing first started in the expectation that this mixed waste stream was potentially included in previously submitted water analysis under ERIO 2 or annual reporting since August 26, 2004? The system was designed to function as it does now and has always operated in this manner. Yes, the boiler blowdown has always been analyzed and reported as part of the desk drain injection Based on the answers above we can look at this further. An approval of an additional waste stream would need an application from Cook Inlet Energy and the generation of an administrative approval under Rule 12 of AIO 32 to modify the approved fluids in Rule 3 of A10 32. ER10 2 (data attached) shows the request format and more detailed compatibility analysis required for a determination of compatible/acceptable injection fluids. I appreciate the on -site testing completed but we would need a lab evaluation with absolute TDS before confirming compatibility. Thanks and Regards, Chris Wallace Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7tn Avenue Anchorage, AK 99501 (907) 793-1250 (phone) (907) 276-7542 (fax) chris.wallace@alaska.gov CONFIDENTIALITY NOTICE. This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at 907-793-1250 or chris.wallaceLa,alaska.t;ov. From: David Kumar[ma iIto: David. Kumar@cookinlet. net] Sent: Monday, March 09, 2015 1:32 PM To: Regg, James B (DOA) Subject: AI032 for RU-6 Dear Mr. Regg, We were having some icing problems with our injection well RU-D1 and were using RU-6 to inject fluids. On looking at the AIO list for the permitted fluids, deck drain is an authorized fluid for injection. Our boiler blowdown (very minimal) flows into the deck and is captured as part of the deck drain system. I wanted to make sure that the Commission is comfortable with this as this is not specifically listed on the AIO. I am attaching the latest fingerprint analysis of the boiler blowdown for your reference which shows it as non -hazardous. Please let us know if we have to make any amendments to our injection order Sincerely, David Kumar Production Manager Conk Inlet Eoe,gy Da�id. kggw asookin .nci wwwol WLLIM From: Saltmarsh, Arthur C (DOA) Sent: Monday, March 09, 2009 11:08 AM Subject: FW: Pacific Energy files chapter-11, it's official!!! FYI. PACIFIC ENERGY RESOURCES LTD. 111 West Ocean Blvd., Suite 1240 Long Beach, California 90802 U Telephone: (562) 628-1526; Fax: (562) 628-1536 Files for Chapter 11 to Facilitate a Restructuring LONG BEACH, CALIFORNIA, Monday, March 9, 2009 - -Pacific Energy Resources ltd. (the "Company")(TSX:PFE) announces today that it and its wholly owned subsidiaries have filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the District of Delaware. The filing was precipitated by the dramatic decrease in the market price of oil over the past five months. Combined with the Company's pre-existing level of debt related to past acquisitions and poor capital market conditions, the Company's liquidity and cash flow is insufficient to operate its business and invest in its oil producing assets to increase production. Faced with these constraints, the Company and its subsidiaries filed petitions for reorganization under chapter 11 to facilitate access to an immediate source of liquidity as it works to restructure its debt. In connection with the filing, the Company is seeking customary authority from the Bankruptcy Court that will enable it to continue operating its business in the ordinary course of business. The requested approvals include requests for the authority to make wage and salary payments and continue various benefits for employees. In addition, the Company has negotiated a commitment for $40 million in debtor-in-possession ("DIP")financing. The DIP facility wraps and replaces two of the Company's three asset-based credit facilities and is being provided by the lenders of the two credit facilities that are being replaced. Upon Court approval, the DIP financing combined with the Company's operating revenue will provide sufficient liquidity to fund working capital, meet ongoing obligations and ensure that normal operations continue without interruption during its restructuring. About Pacific Energy Resources Pacific Energy Resources Ltd. is an oil and gas exploration and production company based in Long Beach, California, U.S.A. Additional information relating to the Company may be found on SEDAR at www.sedar.com. The Company's web site is www.PacEnergy.com. ON BEHALF OF THE BOARD OF DIRECTORS PACIFIC ENERGY RESOURCES LTD. Pacific Energy Resources Ltd. 310 K. Street, Suite 700 Anchorage, AK 99507 Office: 907-258-8600 Fax: 907-258-8601 David Hall Alaska Operations Manager Main: 907-868-2133 Cell: 907-317-8239 dmhall(c~pacenerg~~com www.~acener~.com #8 Page 1 of 1 • • Maunder, Thomas E (DOQj From: Maunder, Thomas E (DOA) Sent: Friday, October 26, 2007 9:00 AM To: Roby, David S (DOA); Regg, James B (DOA) Cc: Jim Regg; 'Stephen F Davies' Subject: RE; Redoubt Unit AIO Dave, have reviewed the information submitted by Forest regarding well integrity for the field-wide FOR project. In addition to the well files, a Schlumberger report submitted with Forest's September 14 letter was used. Presently Forest is injecting in 1 well (RU #6) in the central fault block and without major well work, it appears that will be the extent of any enhanced recovery project for the near term. I performed an analysis in June 2004 regarding wells within the AOR of RU #6. There are 3 recent wells in the central block, RU #5, #7 and #1 and there are 3 "old" wells (R. Bay Unit#1, R. Shoal St. #1 and #2). I have re- examined the records on all the wells and did not identify an integrity issue. In the south fault block the available Hemlock penetrations are RU #2 and RU #5A. Neither of these wells is presently producing. In order to expand FOR operations to the southern fault block, Forest will need to accomplish some amount of well work. Examination of these well files did not identify any integrity issues. Of the remaining wells at Redoubt, RU #3 was drilled in the southern fault block, but was plugged back to shallower gas horizons. RU #4 was drilled in the northern fault block, but was plugged back and sidetracked. Neither of these wells was successful in the Hemlock. No integrity issues were identified. Let me know if you need anything further. Tom Maunder, PE AOGCC From: Roby, David S (DOA) Sent: Thursday, October 25, 2007 11:41 AM To: Maunder, Thomas E (DOA); Regg, James B (DOA) Subject: Redoubt Unit AIO Tom and Jim; I got a call earlier today from Paul Winslow with Forest asking about the status of their AIO request. Will we be able to complete action on their request by October 31St, or should we issue another extension to the ER{O? Please let me know so I can call Paul back and let him know the status. Thanks, Dave Roby Reservoir Engineer Alaska Oil and Gas Conservation Commission Phone: 907-793-1232 Fax: 907-276-7542 email: dave.roby@aaska.goy 10/26/2007 • • 188 2450080 24420Q ,0' 2434{ 39' r .. • Note To File • Re: Sundry Approval # 304-237 Redoubt Unit #6 PTD: 202-228 API #: 50-733-20519-00 Under separate cover, Forest Oil has applied for approval to initiate a pilot water flood of the Hemlock interval in the Redoubt Unit. RU#6, presently a producer, is proposed as the injection well. This document reviews the integrity determinations performed for the well and recommends approving Forest's application. RU#6 was completed in mid April 2003. 9-5/8" intermediate casing was set at 15085" and (11748' tvd) and 7-5/8" production liner was set at 16100' and (12570' tvd). Both strings were successfully cemented according to the reports available in the AOGCC well file. The cement volumes and fill heights were verified using an excel spreadsheet and sufficient cement was pumped on both strings to effect isolation. Both tubular strings were successfully pressure tested and a USIT cement evaluation log was run on the production liner. The log is available in the AOGCC file. The log indicates that the upper sections of the liner are cemented and isolated from the 9-5/8" casing shoe. As one descends deeper into the Hemlock, the cement quality decreases. Various benches of the Hemlock are not isolated from each other, but since the intervals are commingled, this isolation is not necessary. Sketchy information is available on the 9-5/8" cementing operation, however no remedial operations or problems are noted either before or after the intermediate hole reached TD. There was ,pc~E..arf plugged-back wellbore section in the intermediate hole. That interval is well above the ultimate 9-5/8" shoe depth and was satisfactorily abandoned. It is concluded the 7- 5/8" liner is sufficiently cemented to isolate injection water to that formation. Forest identified 2 wells within a 1-4 mile radius of RU#6. These include RU#7 and the 1967 exploration well Redoubt Shoa( State 26960 #2. Both well files were examined and it is concluded that RU#7 was satisfactorily cemented through the Hemlock interval and that 26960 #2 was satisfactorily cement and plugged through the Hemlock interval. No other wellbores were identified proximate to RU#6. Based on analysis of the available well information, it is recommended that Forest's application to convert RU#6 from a producer to an injector be approved. Forest will need to perform an MIT of the inner annulus after the well is completed and an area injection order will need to be in place prior to initiating injection. i'~~~(~ Tom Maunder, PE Sr. Petroleum Engineer June 30, 2004 G:\common\UIC File Reviews\2004-0630-RU #6 conversion.doc ~ 7 • ..«~,3 ~T.a. ,_w_., ~, .. m_, ,,~. ~~' SARAH PALIN, GOVERNOR 11~~T~~~--++ ~-711<L' ®uj~C7~u`~+ V*[t~1sT 333 W 7th AVENUE, SUITE 100 Cois-7E~QAli®LS L+®ri1~II~75'1®l~ ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL ERIO 2.006 Mr. Paul M. Winslow Reservoir Engineer Forest Oil Corporation 310 K Street, Suite 700 Anchorage, AK 99501 RE: Temporary Extension to Enhanced Recovery Injection Order 2 Dear Mr. Winslow: In accordance with Rule 9 of Enhanced Recovery Injection Order ("ERIO") 2, the Alaska Oil and Gas Conservation Commission ("Commission") hereby grants Forest Oil Corporation ("Forest") a temporary extension to the expiration date of this order from December 31, 2007, to January 31, 2008. On July 30, 2007, Forest applied to the Commission to convert ERIO 2 into a full-field area injection order or, alternatively, to extend the expiration date of ERIO 2 for 12 months. On August 6 and 7, 2007, the Commission asked Forest to provide additional information. The additional information was provided on August 22, 2007. On September 12, 2007, the Commission asked for further information regarding well integrity. This information was provided by Forest on September 14, 2007. The Commission is continuing its review of Forest's July 30, 2007, application and the supplemental information. The Commission anticipates completing this review prior to the January 31, 2008, expiration date established by administrative approval ERIO 2.005. Therefore, to ensure there are no disruptions in the ongoing injection operations authorized under ERIO 2 (i. e., should the review not be completed in time), the Commission is granting a 31-day extension to the expiration date of ERIO 2. Forest must continue to comply with all the other provisions of ERIO 2 and the subsequent administrative approvals. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is timely if it is received by 4:30 p.m. on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a state holiday or weekend. A person may not appeal this decision to Superior Court unless reconsideration has been requested. ska, and dated December 28, 2007. • y, __, ~~-; ~. SARAH PALIN, GOVERNOR r, ~ _, ~ ~, ~ ~ ~ , °.~ ~ ,~ ~_ ~- ~, ,~ ~~ ~-7~ OIL ~ ~ '' 333 W. 7th AVENUE, SUITE 100 COI~TSL'`RQA'I`IOI~T COMbIISSIOI~T y` ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL ERIO 2.005 Mr. Paul M. Winslow Reservoir Engineer Forest Oil Corporation 310 K Street, Suite 700 Anchorage, AK 99501 RE: Temporary Extension to Enhanced Recovery Injection Order 2 Dear Mr. Winslow: In accordance with Rule 9 of Enhanced Recovery Injection Order ("ERIO") 2, the Alaska Oil and Gas Conservation Commission ("Commission") hereby grants Forest Oil Corporation (``Forest'') a temporary extension to the expiration date of this order from November 30, 2007, to December 31, 2007. On July 30, 2007, Forest applied to the Commission to convert ERIO 2 into a full-field area injection order or, alternatively, to extend the expiration date of ERIO 2 for 12 months. On August 6 and 7, 2007, the Commission asked Forest to provide additional information. The additional information was provided on August 22, 2007. On September 12, 2007, the Commission asked for further information regarding well integrity. This information was provided by Forest on September 14, 2007. The Commission is continuing its review of Forest's July 30, 2007, application and the supplemental information. The Commission anticipates completing this review prior to the November 30, 2007, expiration date established by administrative approval ERIO 2.004. Nonetheless, to ensure there are no disruptions in the ongoing injection operations authorized under ERIO 2 (i. e., should the review not be completed in time), the Commission is granting a 31-day extension to the expiration date of ERIO 2. Forest must continue to comply with all the other provisions of ERIO 2 and the subsequent administrative approvals. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is timely if it is received by 4:30 p.m. on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a state holiday or weekend. A person may not appeal this decision to Superior Court unless reconsideration has hPen rerniecterl ka, and dated November 30, 2007. I ~~ ~. ~~ ~ ,' z Cathy P. Foerster Commissioner • • - -!> ? ; ~, ~ , SARAH PALIN, GOVERNOR _. as ~ ~:,~ ..~ ~ ~'~ ~~TT~+ ~-m7ia~AT 0~~7A~ ril 1Z0a~7T ,~ 333 W. 7th AVENUE, SUITE 100 C~l`S~j R~A-1101` COril'rIIs'S''~Ol` ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 ' FAX (907) 276-7542 ADMINISTRATIVE APPROVAL ERIO 2.004 Mr. Paul M. Winslow Reservoir Engineer Forest Oil Corporation 310 K Street, Suite 700 Anchorage, AK 99501 RE: Temporary Extension to Enhanced Recovery Injection Order 2 Dear Mr. Winslow: In accordance with Rule 9 of Enhanced Recovery Injection Order ("ERIO") 2, the Alaska Oil and Gas Conservation Commission ("Commission") hereby grants Forest Oil Corporation ("Forest") a temporary extension to the expiration date of this order from October 31, 2007, to November 30, 2007. On July 30, 2007, Forest applied to the Commission to convert ERIO 2 into a full-field area injection order or, alternatively, to extend the expiration date of ERIO 2 for 12 months. On August 6 and 7, 2007, the Commission asked Forest to provide additional information. The additional information was provided on August 22, 2007. On September 12, 2007, the Commission asked for further information regarding well integrity. This information was provided by Forest on September 14, 2007. The Commission is continuing its review of Forest's July 30, 2007, application and the supplemental information. The Commission anticipates completing this review prior to the October 31, 2007, expiration date established by administrative approval ERIO 2.003. Nonetheless, to ensure there are no disruptions in the ongoing injection operations authorized under ERIO 2 (i. e., should the review not be completed in time}, the Commission is granting a 30-day extension to the expiration date of ERIO 2. Forest must continue to comply with all the other provisions of ERIO 2 and the subsequent administrative approvals. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is timely if it is received by 4:30 p.m. on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a state holiday or weekend. A person may not appeal this decision to Superior Court unless reconsideration has been requested. and dated October 31, 2007. ~~ ,r'~ 1 c Cathy P. oerster Commissioner ~ ••wr~° ~~IrIV I :i~. ti~~..ti.~ • ~ ' ~ ~ ~ ~ i ~ ` °` SARAH PALIN, GOVERNOR 7~~ Ai~SR~~T OIL A1~TD ~.S 333 W. 7th AVENUE, SUITE 100 CO1tS~RQ~~Ols CO~SSIO„ ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL ERIO 2.003 Mr. Paul M. Winslow Reservoir Engineer Forest Oil Corporation 310 K Street, Suite 700 Anchorage, AK 99501 RE: Temporary Extension to Enhanced Recovery Injection Order 2 Dear Mr. Winslow: In accordance with Rule 9 of Enhanced Recovery Injection Order ("ERIO") 2, the Alaska Oil and Gas Conservation Commission ("Commission") hereby grants Forest Oil Corporation (``Forest") a temporary extension to the expiration date of this order from September 30, 2007, to October 31, 2007. On July 30, 2007, Forest applied to the Commission to convert ERIO 2 into a full-field area injection order or, alternatively, to extend the expiration date of ERIO 2 for 12 months. On August 6 and 7, 2007, the Commission asked Forest to provide additional information. The additional information was provided on August 22, 2007. On September 12, 2007, the Commission asked for further information regarding well integrity. This information was provided by Forest on September 14, 2007. The Commission is continuing its review of Forest's July 30, 2007, application and the supplemental information. The Commission anticipates completing this review prior to the September 30, 2007, expiration date in Rule 1 of ERIO 2. Nonetheless, to ensure there are no disruptions in the ongoing injection operations authorized under ERIO 2 (i. e., should the review not be completed in time), the Commission is granting the 31-day extension to the expiration date of ERIO 2. Forest must continue to comply with all the other provisions of ERIO 2 and the subsequent administrative approvals. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is timely if it is received by 4:30 p.m. on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a state holiday or weekend. A person may not appeal this decision to Superior Court unless reconsideration has been requested. :a, and dated September 20, 2007. ~- ~~-~ .s-- ~~ " 'J. ~ mi'l` j =:•~4- i.l I \ 1 \ ~11M ~ V }- ~ ~ ~ by P. F rster ~~~ ~ ~ ~~ ~ mmissioner ,, .;~ ~- . r.~. - -- ,~ ~; ~s .~ .~, s September 14, 2007 • r: Forest Oil Corporation 310 K Street, Suite 700 Anchorage, Alaska 99501 (907) 258-8600 Fax: (907) 258-8601 David Roby Alaska Oil and Gas Conservation Commission 333 West 7~' Avenue, Suite 100 Anchorage, AK 99501 Re: Follow up to the Area Injection Order Application, Redoubt Unit Dear Mr. Roby, ~~~ ~~~~~2001 ~l,~w~t3 (.lit Gas Gans. G~mmissi~~ Anchvrat~ This letter is in regards to your email dated 9-12-07 requesting additional information for Forest Oil Corporation's application for an Area Injection Order at Redoubt Unit. AOGCC email dated 9-12-07: 1. Please provide a 6 month pressure history (TIO plots) for all the wells in the Redoubt Unit that penetrate the Hemlock formation to demonstrate mechanical integrity. Attached to this letter are tubing and casing pressure history plots, covering the past 20 months, for RU #1, RU #5A and RU #7. Note that RU #2, RU #3, and RU #4A are all currently shut-in and are incapable of production from the Hemlock formation at this point. Forest is considering sidetracks of RU #2 and RU #5A, as well as possibly RU #3 and RU #4A. If and when these wells are sidetracked, cement evaluations will be performed and mechanical integrity insured (and witnessed by AOGCC personnel) prior to placing these wellbores on injection. 2. One of the goals of the pilot project was to establish an operating range for injection pressure. I can not find any information on the operating range in the application to expand the ERIO to a full-field AIO. Were you able to establish an operating range for injection pressure and if so what is it? The attached RU #6 injection history plot shows injection pressures ranging from 950 to 4,650 psia. Considering the predominant injection rate ranging from 700 to 2,400 bwpd, the corresponding injection pressure has remained between 3,000 and 4,600 psia. Note that the injected water is being pumped from Kustatan Production Facility and is limited by the 5,000 psi pump being used. It is anticipated that this injection pressure range of between 3,000 and 4,600 psia will be utilized throughout the full-field AIO. 3. A Schlumberger cement evaluation was provided for RU #6 with the ERIO application. Please provide cement evaluations for the remaining Redoubt Unit wells that penetrate the Hemlock injection zone. Attached is the Schlumberger cement evaluation for RU #2, RU #4, RU #5, RU #5A, and RU #6. I could not locate a cement evaluation for either RU #1 or RU #7, but those respective well's cement bond logs should be on file with the AOGCC. • • If you have any further questions regarding Forest's Redoubt Unit Area Injection Order application, please do not hesitate to contact me at 868-2131. Sincerely, Paul M. Winslow Reservoir Engineer Tubing and Casing Pressure (psia) ~ ~ ~ ~ ...1 Q Q Q ~ ~ ~ 0 Q Q Q Q 0 ~ Q 1 /1 /06 2/1/06 P • ~ ~ ~ c c 3/1 /06 ~ ~ v ~ cn v- 4/1 /06 o Q c c ~ ~ 5/1/06 m m ~ ~ ~ ~ m iu 6/1 /06 ~ ~ 7/1 /06 8/1 /06 ' ~ cc 9/1 /06 ~ fl. ~ n ~ 10/1/06 y ~ ~ ~ 11/1/06 a (p rt C ~ ~ -~ ~ 12/1/06 ~ ~ ~ ~ ~ _ • - ~ • cD 1/1/07 • • ~. O 2/1 /07 ~ 3/1 /07 ~ 4/1 /07 1 5/1 /07 6/1 /07 7/1 /07 8/1 /07 t ~ ® ~ • ~ _ -- -- -- -- - _J • • Tubing and Casing Pressure (psia) 0 0 0 0 °o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1 /1 /06 2/1 /06 3/1 /06 4/1 /06 5/1 /06 6/1 /06 7/1 /06 • ~ c Q ' 8/1 /06 ~ ca 9/1/06 Q. ~ n Q v ° 10/1 /06 i c ~' v v ~ ~ o; 11/1/06 ~ ~ ~ ~ = t#i~ 12/1 /06 D ~ ~ ., c~ 1/1/07 • • ~ O ~ 2/1 /07 3/1 /07 I 4/1/07 k~- ~ ~ ~ c c 5/1/07 ~ ~ ~ ~ ~ ~ D D C7 ~ ° ' 6/1/07 ~ ~, ~ ~ 5 cn ca ~ ~ 7/1/07 ~ ~ ~ m j c ~ u m 8/1/07 c f • Redoubt Unit #6 Tubing a nd Casing Pressure History 5000 ---~_. ___ _. . _ _ _ _____ _. • RU #6 Tubing Pressure 4500 • RU #6 Casing Pressure . ' • • ~ 4000 • • l • ~ •. ~• f ~ • a 3500 • • ~ m ~ ; N 3000 m a c 2500 'v~ ~a v ~ 2000 ea a~ 1500 H 1000 500 0 co cfl co cfl co co 0 0 0 0 0 0 co co 0 0 co co co c~ ~ r~ r~ ~ r~ ~ r~ t~ 0 0 0 0 0 0 0 0 0 0 0 0 ~ N M ~ U'1 (O I~ ~ O O ~ N ~ N M ~ ~ O ~ O ~ r ~ Date • Tubing and Casing Pressure (psia) ~ ...\ ~ ~ ~ N ~. O OD O N A O OD O O O O O O O O O O O O O O O O O O O 1/1/06 ~ • 2/1/06 c c ~ ~ 3/1 /06 n ~ w ~ ~' 4/1/06 ~ v 5/1/06 ~ N ~ ~ m m 6/1 /06 7/1 /06 i ~ c s ' 8/1 /06 ~ t~ a~ ~ 9/1 /06 Q. ~ C7 ~ Q. i 10/1/06 t n = ~ a- ~ ~ ~ rt ' C 11 / 1 /06 ~ ~ ~ ~ rr y y 12/1/06 = • ~ ~ Z 1/1/07 • » • rt O ~ 2/1 /07 3/1 /07 4/1 /07 5/1 /07 6/1 /07 7/1 /07 8/1 /07 • • Redoubt Unit #6 -Injection History - - - -- 5,000 -- _ --- _ ------- RU #6 -Water Injection 4,500 ~RU #6 -Injection Pressure 4 000 ~ , . N a L 3 500 , w N d 3 000 ~ ~ , i o a m 2 500 , c o ~ ~ 2 000 , • ~ d .. 1 500 ~ , i .~ ~ 1 000 , 500 ' 0 O~ O~ O~ O~ O~ O~ O~ O~ O~ O~ OHO OHO OHO OHO OHO OHO OHO OHO OHO OHO OHO OHO 01 O~ O~ O~ O~ O~ 01 ~ ~ ~ \ \ ~ \ ~ ~ \ ~ ~ \ ~ ~ ~ ~ \ ~ \ \ \ ~ ~ \ ~ ~ \ \ ~~'` 'L~'` ~~'` ~~'` 'l~'` ~~'` 'l~'` ~~'` `~~'` ~~'` ~~'` 'l~'` ~~'` ~~'` ~~'` ~~'` O~~ O~~ ~~~ O~~ O~~ O~^ O~~ O~~ O~~ ~~~ O~~ 0~+~ "~~'` ~ ~ ~ ~ ~ ~ Date • • • Sd~lumberger Cement Evaluation Redoubt Oil Field Company Field Wells Reference Number Log Analyst Forest Oil Corporation R~o1,~; ~~~ . Redoubt Unit 2 Redoubt Unit 4, Redoubt Unit 5, Redoubt Unit 5A, Redoubt Unit 6 23237 Douglas Hupp, PE ;r ro Alaska Data and Consulting Services 3940 Arctic Blvd, Suite 300 Anchorage, Alaska 99503 (907-273-1700 interpretations are opinions based on inferences from electrical or other measurements and we cannot, and do not guarantee the accuracy or correctness of any interpretations and shall not, except in the rase of gross or willful negligence on our part, be liable or responsible for any loss, cost, damages or expen~s incurred or sustained by anyone resulting n any interpretation made by any of our officers, agents or employees. These interpretations are also subject to clause 4 of our general terms and condftions as set out in our currer .e schedule. Forest Oil Corporation Job Number 23237 Cement Evaluation Logs Field: Redoubt Shoal Oil Field 1. Introduction: Forest Oil Corporation has acquired cement evaluation logs on their wells in the Redoubt Shoal Oil Field. This report is an evaluation of the cement quality based on selected wells. Logs available for this evaluation are outlined in Table 1. Table 1 AVallabla Cement t?valnatinn I nne Well Available Cement Evaluation Logs Redoubt Unit 2 USIT Redoubt Unit 4 CBT and USIT Redoubt Unit 5 CBT and USIT Redoubt Unit 5A CBT and USIT Redoubt Unit 6 CBT and USIT 2. Interpretation Inputs: Below is a discussion of the cement bond quality based on review of the cement evaluation logs for the Redoubt Shoal Oil Field wells. Redoubt Unit 2 ~~ \ --C `~ ~ ~ ~~ I ~5~1 Redoubt Unit 2 was logged with USIT and CBT tool on 28-MAY-2001. These tools were logged in combination over the interval 14126 ft to 15270 ft. Three centralizers were employed on the CBT tool and 2 on the USIT tool. The logs were recorded inside 5.5 in. 17 Ib/ft casing cemented in a 6.75 in. borehole. The cement bond appears to be in good condition based on the USIT well log data. Below 14690 ft the USIT log indicates excellent bond with only small isolated spots of poor bond. Average acoustic impedance ~AIAV) ranges from 4 Mray to 6 Mray. Above 14690, the USIT logs indicates sections with approximately 75% of the casing indicating good bond intermixed with sections with 100% good bond. The AIAV ranges from 2 Mray to 5 Mray. The exact location of the perforations is not known in this well. Possible channels are described in Table 2. ~r~o~~~©c.~ \yy~p _ ~~--~~~ Table 2 Possible Channels RedeuM unit 2 Depth - - _-__-_-- _ - Description 14250-14310 Spotty cement. 14580-14700 Channel occupying approximately 25% of the casing circumference. Figure 1 illustrates a channel located from 14580 ft to 14700 ft and Figure 2 is an example of good bond around 15000 ft. s c c ca -, a DRAFT ' • / Forest Oil Corporation Job Number 23237 Cement Evaluation Logs Field: Redoubt Shoal Oil Field Redoubt Unit 4 ~~-~ l - ~ ~ ~ ~~'~'~ j°%~-~~ Redoubt Unit 4 was logged with USIT and CBT tools on 07-APR-2002. These were logged over the in combination over the interval 18300 ft to 20000 ft. Three centralizers were employed on the CBT tool and 2 on the USIT tool. The logs were recorded inside 5.5 in. 7 Ib/ft casing cemented inside a 6.75 in. borehole. The cement bond appears to be in good condition across the interval logged in this well. Below 18440 ft, the USIT and CBT logs indicate excellent bond around the casing with AIAV ranging from 4 Mray to 8 Mray. The Variable Density display VDL) from the CBT tool clearly shows formation arrivals. Above 18440 ft both the CBT and USIT log indicate poorer bond with AIAV between 1.8 Mray and 3.5 Mray. The VDL display also shows casing arrivals. This section still indicates approximately 50% of the casing has cement around it from the USIT cement map. Figure 3 illustrates this transition. Redoubt Unit 5 ~ ~ ~- - '~~5 Redoubt Unit 5 was logged with USIT tool on 12-AUG-2002. This tool was logged over the interval 10260 ft ~- to 13750 ft. The logs were recorded inside XX in. XX Ib/ft casing cemented inside a XX in. borehole. `t~~< l3`~C~c~ TtjC.1~3~ ~~~'-c,.sQ.c~r~ 1~`~~-`~ S~s~~\y~~~\a.~srE~~~~ The USIT cement map indicates a channel or no cement across the entire logged interval in this well. Possible barriers to flow in a channel exist at 10710 ft to 10800 ft, 11420 ft to 11480 ft, and 11750 ft to 11760 ft. These barriers are not very thick and may not provide hydraulic seals. Figure 4 illustrates a possible barrier located at 11570 ft. Redoubt Unit 5A ~~ ~ ~ ~ b ~'~~ cr..~~~1 w`~~c ~~ ~~~ ~ t \~l'~~ Redoubt Unit 5A was logged with USIT and CBT tool on 14-OCT-2002. These tools were logged in combination over the interval 15135 ft to 16850 ft inside 5.5 in. 17 Ib/ft liner and 14480 ft to 15135 ft inside 7.625 casing. Three centralizers were employed on the CBT tool and 2 on the USIT tool. Q~r~~o~-~ \S3SC~ - 1~~ ~ The lower section (log in the 5.5 in liner) indicates good bond below 15700 ft with AIAV typically ranging from 5 Mray to 9 Mray. Above 15700 ft the bond is poor with the cement map from the USIT log indicating greater than 50% of the pipe either free or with partially set cement. The CBT VDL display confirms this interpretation of the cement quality with no casing arrivals noted below 15825 ft and strong formation signals. Above 15800 ft casing arrival is clear and formation signals are lost in the VDL display. Also, casing collars can be noted in the VDL display above 15820 ft. Table 3 describes the isolation of the perforated intervals in this well. Table 3 Perforated Interval Isolation Redoubt Onit 5A Zone Perforation Interval Description 1 15350-15385 Poor and intermittent cement across the entire perforated interval. 2 15410-15460 Poor and intermittent cement across the entire perforated interval. 3 15560-15600 Poor and intermittent cement aaoss the entire perforated interval. Almost no cement at bottom of this zone. 4 15615-15635 Almost no cement. 5 15765-15915 Good cement aaoss entire zone. 6 15950-15960 Good cement. 7 16020-16030 Good cement. 8 16170-16525 Good cement. N n a c~ c r~ DRAFT .~ i • Forest Oil Corporation Job Number 23237 Cement Evaluation Logs ' Field: Redoubt Shoal Oil Field 9 16645-16670 Good cement. Figure 5 displays the transition from well cemented to free pipe signal around 15800 ft. Redoubt Unit 6 ~ ~ ~-~~~ ~( ~ ~~,~ ~ -~~ Redoubt Unit 6 was logged with USIT and CBT tools on 05-APR-2003. These were logged over the in combination over the interval 14700 ft to 16000 ft. Three centralizers were employed on the CBT tool and 2 on the USIT tool. The logs were recorded inside 7.625 in. 29.7 Ib/ft casing cemented inside an 8.5 in. borehole. A swivel was included in the tool string to minimize tool rotation while logging. ~~~~Q~~ t~i3~ ~. I Ski,(:} The cement bond in this well in general improves towards the top of the logged interval. Above 15225 ft most of the casing is cemented. Below that depth there are sections with little to no cement mixed with sections with good cement. Isolation of individual perforated intervals in described in Table 4. Table 4 P81'fO~lnll ~IItRNRr ~enlR4inn RndnuM Ilea C Zone Perforation I~rterval -- --- --------• --_. _ ........................• v Description 1 15130-15164 The cement across this interval appears very good. A short section at the bottom (15162 ft to 15175 ft) contains poor cement but is isolated by good bond above and below. This zone appears to be well isolated above and below. 2 15192-15226 Most of this interval appears to be well bonded with a channel located below. The channel runs from 15225 ft to 15324 ft with a possible small barrier located at 15265 ft. This connects Zone 2, Zone 3, and Zone 4. 3 15252-15302 A channel appears to cover this perforated zone as noted above. 4 15316-15336 This interval is connected at the top to the channel described above. A channel exists below this zone to 15410 ft. 5 15418-15444 The top of this zone is well cemented but a channel extends below to 15466 ft. This channel connects Zone 5 and Zone 6 6 15458-15480 A channel is located both above and below this zone but cement at 15520 to 15525 ft separates this zone from Zone 7 7 15542-15630 This interval is characterized by poor cement across the interval. The poor cement extends down to 15686 ft, which connects Zone 7 and Zone 8. 8 15680-15760 Zone 8 is well bonded at the top with some un-bonded intervals towards the bottom. This zone is isolated below by good cement at 15765 ft. 9 15788-15812 Zone 9 is poorly bonded across the perforations but isolated above and below by good cement. 10 15856-15890 This bottom-perforated interval crosses a channel that extends from 15820 ft to 15920 ft. Spotty cement can be seen below 15920 ft. Figure 6 identifies a channel located from 15225 ft to 15324 ft. c c a DRAFT Forest Oil Corporation. Job Number • ' 23237 Cement Evaluation Logs Field: Redoubt Shoal Oil Field - 4. Summary: Cement quality varied from well to well in this study. In general, Redoubt Unit 2 and Redoubt Unit 4 had the best quality cement bond based on the available logs. Redoubt Unit 5A appears to be well bonded towards the bottom while Redoubt Unit 5 exhibited poor bond across the entire section. Redoubt Unit 6 had several channels interspersed throughout the logged interval. _s c 3 '~ c a DRAFT ~~ Page 1 of 1 Colombie, Jody J (DOA) From: Norman, John K (DOA) Sent: Thursday, September 13, 2007 11:06 AM To: Roby, David S (DOA) Cc: Colombie, Jody J (DOA) Subject: RE: Hearing for Forest's application to expand Redoubt Unit pilot FOR project to full field AIO Concur. From: Roby, David S (DOA) Sent: Wednesday, September 12, 2007 8:44 AM To: Norman, John K (DOA); Seamount, Dan T (DOA) Cc: Regg, James 8 (DOA); Davies, Stephen F (DOA); Maunder, Thomas E (DOA); Foerster, Catherine P (DOA) Subject: Hearing for Forest's application to expand Redoubt Unit pilot FOR project to full field AIO John and Dan, We currently are scheduled to have a hearing tomorrow morning at 9 AM to discuss Forest's (now Pacific Energy) application to expand ERIO 2 from a single well pilot FOR project to a full field AIO. Forest submitted their original application on July 30th and provided additional information on August 22~d. There are only a couple of items that need further clarification that deal with Forest providing the proof of mechanical integrity instead of just saying that the Commission has the information in our files already and that we can do the analysis. No one has requested that the hearing be held. I've discussed whether or not to hold the hearing with Cathy and she recommends that we hold the hearing unless Forest can answer the few remaining questions today. She asked that I check with you to see if you agree with this approach. Thanks, Dave Roby Reservoir Engineer Alaska Oil and Gas Conservation Commission Phone: 907-793-1232 Fax: 907-276-7542 email: d.ave.roby a~ala.s.ka.go_v_ 9/13J2007 ~4 -~ • ~ Forest ail Corporation 310 K Street, Suite 700 Anchorage, Alaska 99501 (907) 258-8600 Fax: (907) 258-8601 August 22, 2007 David Roby Alaska Oil and Gas Conservation Commission 333 West 7~' Avenue, Suite 100 Anchorage, AK 99501 Re: Follow up to the Area Injection Order Application, Redoubt Unit Dear Mr. Roby, au~ ~ 2 2ao7 4laska 0+I & Gas Cons. Commissial~ Anchorage This letter is in regards to your two emails (dated 8-6-07 and 8-7-07, respectively) requesting additional information for Forest Oil Corporation's application for an Area Injection Order at Redoubt Unit. AOGCC email dated 8-6-07; 1. Please provide a description of the area to be covered by the proposed AIO down to the'/4 %4 section. Please find attached (Attachment 1) a Hemlock top structure map of Redoubt Unit, with the proposed area outline (in red) for the Area Injection Order (AIO). Note that this area is the previously approved Redoubt Unit Hemlock Participating Area (RUHPA). The table following the structure map (Attachment 2) lists the proposed AIO acreage down to the %4 %4 section. 2. Since the potentially impacted area is changing, from a single well to a full field, you need to provide a new list of all operators and surface owners within a %4-mile of the project boundaries described above and also provide an affidavit showing that they have been provided a copy of your application. Attachment 3 is a signed affidavit verifying that copies of Forest's Redoubt Unit AIO application (as well as this application follow-up) have been sent to the State of Alaska, Department of Natural Resources, Division of Mining, Land & Water and State of Alaska, Department of Natural Resources, Division of Oil and Gas. Note that the State of Alaska, Department of Natural Resources is the sole surface or subsurface owner within %4 mile of the proposed AIO boundary. The only surface owner within cone-quarter mile radius of either the Osprey Platform, which is the surface location from which the full-field water injection will occur, or the boundary of the proposed Area Injection Order, is the State of Alaska. The surface owner's lands are managed by the Department of Natural Resources, Division of Mining, Land & Water while surface activities conducted pursuant to the State of Alaska oil and gas leases are managed by the Department of Natural Resources, Division of Oil and Gas. Forest is the only operator of any wells within cone-quarter mile radius of either the Osprey Platform or proposed AIO boundary. AOGCC email dated 8-7-07: 1. Please provide a more detailed discussion on the expected incremental hydrocarbon recovery, including lessons learned from pilot project, which you anticipate would occur if the project is expanded field wide. The discussion should give reserves and recoveries for both the Central and Southern fault blocks. • • The crude oil being produced at Redoubt Unit has an API gravity of 26.5 degrees, agas-oil-ratio (GOR) of 250 scf/STB, and a bubble point pressure of 1,490 psia. Initial reservoir pressure at Redoubt Unit was approximately 5,340 psia at a datum depth of 12,000' SSTVD. Recovery under primary depletion of this relatively dead oil, is estimated to be about 6% of the original oil-in-place (OOIP), from initial pressure down to the bubble point. The latest estimates for OOIP in Redoubt Unit are about 54 MMbbls of oil (30 MMbbls in the Central fault block and 24 MMbbls in the Southern fault block). Assuming a 6% primary recovery, 3.2 MMbbls of oil are expected to be recovered (1.8 MMbbls from the Central and 1.4 MMbbls from the Southern fault blocks, respectively). To date, a total of 2.19 MMbbls of oil have been produced from the Hemlock formation at Redoubt Unit. Broken down by fault block, 1.30 MMbbls of oil have been produced from the Central fault block and 0.89 MMbbls from the Southern fault block. This equates to a current recovery factor of 4.3% in the Central fault block and 3.7% recovery in the Southern block. The current production forecast for the Central fault block (no current production in Southern block), yields an expected ultimate recovery (EUR) from the Central block of roughly 1.74 MMbbls. This equates to an overall recovery of 5.8% of the OOIP in the Central fault block. Currently there are only three productive wells drilled in the Central fault block of Redoubt Unit and they are all located near the crest of the structure in the southern half of the block. In an effort to better quantify the results of the pilot waterFlood in the Central fault block, an estimate was made of the effective drainage area for the current three completions. Based upon the reservoir pressure depletion that was measured during the modular formation dynamics testing (MDT) performed on RU #6 and RU #7, and from the production/injection history, an average effective drainage area ranging from 200 - 245 acres was estimated for the current three completions (in the Central fault block). This drainage area range equates to a recovery factor from the existing completions within the Central fault block of 11 % to 13% of the OOIP from the effective drainage area. The pilot waterflood project at Redoubt Unit has demonstrated firstly that the Hemlock reservoir is capable of being flooded, secondly that the injection of fluids into the Central fault block has decreased the production decline rate for the surrounding wells, and thirdly that the recovery from these surrounding wells is expected to increase by 5 to 7%. Mechanical integrity was only discussed for RU#6 and RU#7 in the original pilot project application. Since you are now proposing to expand the project to a full field we will need a mechanical integrity review/confirmation for the remaining affected wells. Attached to this follow-up letter are the current well completion schematics for RU #1, RU #2, RU #3, RU #4A, and RU #5A (Attachments 4 - 8, respectively). The RU #6 and RU #7 well completions were previously discussed as a part of the Redoubt Unit pilot Enhanced Recovery Operation application. Of the remaining Redoubt wells, note that RU #1, RU #2, and RU #5A are all completed in the Hemlock formation. RU #3 was plugged back and completed in the G-0 gas sand and then later re-completed in a potential Tyonek gas sand. After the Tyonek sand tested wet, RU #3 was temporarily suspended. RU #4A was also temporarily suspended after suffering what appears to have been casing collapse while testing the Hemlock formation in the RU #4A sidetracked wellbore. Preliminary expansion plans for Redoubt Unit would call for a new well location on the eastern flank of the Southern fault block, which would likely become the first injection well in the Southern block. The well completion (as with all wells drilled at Redoubt) would be designed to have intermediate casing set just above the top of the Upper Hemlock, and a production liner cemented across the Hemlock completion intervals. Before any well is converted to injection, mechanical integrity tests will be conducted (and witnessed by AOGCC staff) and the proper sundries filed with the State. In addition to the seven (nine if counting sidetracks) Redoubt Unit wells drilled by Forest Oil Corporation (or by its predecessor Forecenergy), there are also four wells drilled in the 1960's and 1970's by various other operators, which lie within the proposed boundary for the AIO. These include: • • - Pan American Redoubt Shoal State 22064 #1 (drilled in 1967) - Pan American Redoubt Shoal State 29690 #1 (drilled in 1967) - Pan American Redoubt Shoal State 29690 #2 (drilled in 1968) - Redoubt Bay Unit #1 (drilled in 1976) State records indicate that all four of these wells have been plugged and abandoned as per State requirements. 3. ERIC) #2 was amended several times to allow different sources of fluid, other than just Hemlock produced water, to be injected during the pilot project. There is no discussion of these new sources in your current application. Please provide an update to the type of fluids/sources that would be injected in a full field project. The following fluid sources have been approved by the AOGCC for injection into the Hemlock formation, via the RU #6 weilbore. - Produced Hemlock formation water from Redoubt Unit (ERIO #2) - Treated sanitary waste (ERIO 2.001) - Treated gray water from platform and camp living facilities (ERIO 2.001) - Produced Hemlock formation water from the West McArthur River Oil Pool (ERIO 2.001) - Storm water from secondary containment areas at Kustatan and from the West McArthur Production Facility (ERIO 2.001) - Deck drainage from the Osprey Platform (ERIO 2.001A) - Produced water from the gas wells in the West Foreland field (ERIO 2.002) Compatibility testing (previously supplied to the commission) and actual injection history data has shown no adverse effects from the injection of these fluids into the Hemlock formation at Redoubt Unit. Therefore, Forest requests that these same fluids be permitted for injection in the full-field Area Injection Order. 4. Please provide a more detailed description of the proposed full field injection project. Forest Oil is currently in the planning process of carefully and progressively expanding the production at Redoubt Unit. As an initial phase of this expansion, Forest has identified four locations to add production and/or injection. The first two locations will involve sidetracks of the Southern fault block wells RU #2 and RU #5A (refer to the map included in the AIO application). Substantial production was lost from these two wells as a result of the ESP failures and subsequent wellbore issues. The sidetracks will be minimally offset up-structure and will likely only be completed in the Upper and Middle Hemlock in order to stay above apparent water sands in the Lower Hemlock. In addition to the sidetracks of RU #2 and RU #5A, two additional locations are under consideration, which could be reached by either sidetracking existing wellbores or by drilling new wells from available slots on the Osprey Platform. The first of these two locations is on the eastern flank in the Southern fault block (marked as RU #3A on the AIO application map). This well would initially be placed on production, but would later be converted to water injection to support pressure and recovery in both RU #2A and RU #5B. The fourth location currently being considered is in the central fault block, north of RU #1 (marked as RU #4B on the AIO map). There is a relatively large un-depleted area north of RU #1, which is relatively high on the Redoubt Shoals structure. Note that all future expansion plans at Redoubt will be contingent upon the current economics and will be dependent upon the success of drilling and production results of the previous work. 5. Please specify a type well within the Redoubt field and provide top and bottom footages in terms of measured depth and true vertical depth subsea within that type well for the Hemlock and for the proposed injection interval. • J Redoubt Unit #2 (RU #2) is a good type well in the Southern fault block of Redoubt Unit. Currently RU #2 is completed in the Upper, Middle and Lower Hemlock formations. The respective Hemlock intervals have the following depths in the RU #2 wellbore: - Top Upper Hemlock: 14,365' MD 11,697' SSTVD (Primary Injection zone) - Top Middle Hemlock: 14,685' MD 11,958' SSTVD (Primary Injection zone) - Top Lower Hemlock: 14,910' MD 12,147' SSTVD - Top West Foreland: 15,222' MD 12,424' SSTVD In the Central fault block, RU #1 is a good representative type well for the Hemlock formation. Currently RU #1, RU #6 and RU #7 are all completed in each of the Upper, Middle and Lower Hemlock formations. The respective Hemlock intervals in the RU #1 wellbore, have the following depths: - Top Upper Hemlock: 14,140' MD 11,643' SSTVD (Primary Injection zone) - Top Middle Hemlock: 14,440' MD 11,885' SSTVD (Primary Injection zone) - Top Lower Hemlock: 14,660' MD 12,064' SSTVD - Top West Foreland: 14,945' MD 12,322' SSTVD 6. The Commission needs a structure map for the order record. The map that accompanies the AIO application is not marked confidential, nor is confidentiality requested in the application letter. May we put this map in the public domain? If not, please provide a simplified version that can be place in the public domain. Forest Oil Corporation would prefer that the map included in the Redoubt Unit Area Injection Order application be held confidential. Attachment 1, which outlines the proposed area for the AIO is not marked confidential and may be placed in the public domain. 7. We did not see any information on oil-water contact or gas-oil contact (if any) footages or footage estimates for the field. If contacts vary between blocks, please provide measured and true vertical depth subsea footages for each block. Based on petrophysical analyses and upon well testing information gathered to date, the lowest known oil (LKO) and/or highest known water (HKW) by fault block and by Hemlock interval is summarized in Table 1 below. Note that the Hemlock formation is an under-saturated oil reservoir and as such, there is no gas-oil contact present at Redoubt Unit. Table 1 Hemlock Formation: Central Fault Block Southern Fault Block Upper Hemlock LKO 11,830' SSTVD (RU #1 DST) LKO 11,900' SSTVD (RU #2 DST) Middle Hemlock LKO 12,075' SSTVD (RU #1 DST) LKO 12,140' SSTVD (RU #2 DST) Lower Hemlock HKW 12,081' SSTVD (RU #1 DST) LKO ? 12,380' SSTVD (RU #2 DST) (from DST production log interpretation) (no producton log was run on DST) (cores indicate the Lower Hemlock is very tight) LKO =Lowest Known Oil HKW =Highest Known Water • • If you have any further questions regarding Forest's Redoubt Unit Area Injection Order application, please do not hesitate to contact meat 868-2131. Sincerely, Paul M. Winslow Reservoir Engineer • • Attachment Redoubt Unit Table of Acreage Included in the Redoubt Unit Hemlock Participating Area (RUHPA) and proposed for Redoubt Unit Area Injection Order (AIO) Tract &ADL Number 1 (ADL 378114) 2 (ADL 374002) 3 (ADL 381203) 4 (ADL 381003) 5 (ADL 381201) Township, Range & Section T.7N., R.13W., S.M Sec. 7 Sec. 17 Sec. 18 Sec. 19 Sec. 20 Sec. 21 Sec. 29 Sec. 30 Sec. 31 T.7N., R.14W., S.M Sec. 13 Sec. 23 Sec. 24 Sec. 25 Sec. 26 Sec. 34 Sec. 35 Sec. 36 Portions of Section Included in Participating Area SW/4 of SW/4 SW/4; SW/4 ofNW/4; W/2 of SE/4; SE/4 of SE/4 W/2; SE/4; W/2 of NE/4; SE/4 of NE/4 All W/2; NE/4; W/2 of SE/4; NE/4 of SE/4 W/2 of NW/4; NE/4 of NW/4 W/2 of NW/4; NE/4 of NW/4; NW/4 of SW/4 All NW/4; NW/4 of NE/4 E/2 of NE/4; E/2 of SE/4; SW/4 of SE/4 SE/4 of SE/4 E/2; SW/4; SE/4 of NW/4 All E/2; SW/4; SE/4 of NW/4 E/2 of NE/4; NE/4 of SE/4 N/2; SE/4; N/2 of SW/4 N/2; SW/4; N/2 of SE/4; SW/4 of SE/4 Tract Acreage Within RUHPA 960 2360 1920 1280 0 Attachment 2 6,s2o • • • ATTACHMENT 3 C, APPLICATION FOR AREA INJECTION ORDER -REDOUBT UNIT Before the Alaska Oil and Gas Conservation Commission In the Matter of the Application of Forest Oil Corporation for Redoubt Unit Area Injection Order Subject to the provisions of 20 AAC 25.402 VERIFICATION OF FACTS AND AFFIDAVIT OF JIM ARLINGTON Jim Arlington, being first duly sworn, upon oath, deposes and states as follows: 1. My name is JIM ARLINGTON. I am over 19 years old and have personal knowledge of the matters set forth herein. 2. I am the Land Manager for the operator of the Redoubt Unit, Forest Oil Corporation (FOREST). 3. I am acquainted with the facts associated with the application submitted by FOREST to the Alaska Oil and Gas Conservation Commission for an expansion of the existing Enhanced Recovery Injection Order ("ERI02") for the Redoubt Unit to afull-field Area Injection Order and/or a twelve month extension of the existing Enhanced Recovery Injection Order, ERI02. 4. The only surface owner within aone-quarter mile radius of either the Osprey Platform, which is the surface location from which the full-field water injection will occur, or the boundary of the Redoubt Unit Hemlock Participating Area ("RUHPA"), within which all water will be injected, is the State ofAlaska. The surface owner's lands are managed by the Department of Natural Resources, Division of Mining, Land & Water while surface activities conducted pursuant to the State of Alaska oil and gas leases are managed by the Department of Natural Resources, Division of Oil and Gas. 5. FOREST is the only operator of any wells within aone-quarter mile radius of either the Osprey Platform or the RUHPA. 6. On August 22, 2007, pursuant to 20 AAC 25.402 (c)(3), FOREST sent a copy of its application for an Area Injection Order by United States mail to the Division of Mining, Land & Water and the Division of Oil and Gas, both within the Alaska Department of Natural Resources, at 550 W. 7~' Avenue, Suite 1260, Anchorage, Alaska 99501. Subscribed and sworn to on August 22, 2007. o -a 1~, Jim Arlington r STATE OF ALASKA ss. THIRD JUDICIAL DISTRICT ~~, On this..7,,~ may of August 2007, before me, the undersigned, a Notary Public duly commissioned and sworn, appeared Jim Arlington, personally known to me, to be the person whose name is subscribed to within the Verification of Facts and Affidavit. Witness my hand an official seal. ~~ Notary Public ` -~---i ~ , ~' ~~~ r, ~', . REBEKAH J, HAYNES Notary ublic, tate of Al s a j State of Alaska My<C mmissio fires: <`~! 1' 7-~ 1Z> e °' + •8'~'' a My Commission Expires Mar. 9, 2010 ATTACHMENT 4 Redoubt Unit #1 Current Completion 8/15!2007 36", 150#, A-36, Welded Conductor @ 200'MDI200'TVD 13-3/8", 68#, L-80, BTC @ 1,831'MD/1,803'TVD 3 1/2" 9.3# P-110 Pup 34 jts 3 1/2" 9.3# P-110 Tubing 393 jts 3 1/2" 9.3# L-80 Tubing 3 1/2" 9.3# L-80 Pup ESP Assembly ,: TOL @ 6,712' MD ~~ 9-5/8", 47#, L-80, BTC @ 6,986'MD/5,988'ND i I i , Centrilift ESP Assembly (bottom of assy) @ 12,904' MD LLC valve set in Baker DB packer @ 13,070' MD r ~' Top offish: Tbg cut off @ 13,170'MD Possible collapsed casing at± 13,400'MD 1. Btm of fish: Centrilift ESP assembly @ 13,581'MD Perforations 14,182' -14,214' "~ ~ LLC valve set in Baker FA packer @ 13,662' MD 14,238'-14,254' 14,258'-14,272' - roL @ 13,74r MD 14,280'-14,298' 14,320'-14,344' 7-5/8", 29.7#, L-80, Hydril 521 @ 13,990'MD/11,616'ND 14,348'-14,364' 14,440'-14,455' 14,462'-14,478' - 14,482'-14,620' _ _ 14,630'-14,656' '° = Perforations 14,664'-14,772' - - 14,784'-14,850' 14,856'-14,880' - 1 , 14,890'-14,910' ~ 5-1/2", 17#, L-80, Hydril 521 @ 15,323'MD/12,742'ND 3 3/8" 6 SPF t331t"' L 2818 fiVp $t!* ST'G 321PMD ~^t S~sS~. ~9~~~ CIA ~~~~ f 'TC91.~Q14i12MD ~~[x~' 4,7B2" 14.84Q' i4,94f3' 14,974' 3 318". 3 7Cl" lk..iit1 pup 32~ 3112"' P-11E! i'utring 24 i`~S 3112" L-Bp'Iutmng 31t,~ L-80 pup 384 j!S 3 t/2" L~ i'r~bing 3112" L-80?vp ~~, 4 ~8" L-t8} 7534 i5t[) ~71* erc sn f ~Q ~~ ~ I~toQ~l FA Pater IU15 61A 7 5(8' L-BO tt7~8 T'1(p _ 29.7# 5.21 1432Q IdL} [!n"~1 ~ 15218 iJiU 5 ill" L-At} 12&113Vp 17 ~ Hydr,`~ 52t 15325 MD ATTACHMENT 6 RU #3 Propas~d Re-comRletlon - Fel~rwary 2005 i SSS~ ~ 271 MD 30" A-36 208 TYD # 150 # Vvelded 2{3D MO Ghemk~itnjectioh Part (fg 2983 MD 133/8" L-8D 302-0 TVD ' 88 # BTG 3507 MD 2 718" 8,5# L-80 Tubing l I Ti7L 9103 MD Tap of Tieback 14717 M Baker Production Packer 7,700' NfD Perior-aGons 7,78U' - 7,818' MD GIPB at 9,100' 9 5/8" L-80 7416 TVD 47 # I~TG 9382 MD GIPS a! 14,775' MD w124' cerneni an tap Perfara#ions 14803 MD -1-0860 MD 7 518" ~.-8G1 1 1381 ND 29.7 # Hydti! 521 15815 Mi? Cemeni Rerai~er @ ibB. I Laslflsh-1b768 MD to 160-08 MB 5112"' L-80 `13818 17 # riydril 521 16940 Mt) • ATTACHMENT 7 Redoubt #4A Casing Schematic -July 2003 TOL @ 5074 MD TOF 14,319' GLM 14,395' Tieback Stem 14,574' TOL 14,583' Pertorations 17,784' to 17,855' 30" 150 # 13 3/8" 68 # 9 5/8" 47 # ' 9.3# L-80 Tubing A-36 200 TVD Welded 200 MD L-80 2918 ND BTC 3530 MD L-80 7114 TVD BTC 10517 MD 7 5/8" L-80 9565 ND 29.7 # Hydril 521 14820 MD 5 1/2" L-80 12467 TVD 17 # Hydril 521 18082 MD .~' • ATTACHMENT 8 Forest Oil Corporation Redoubt Shoals -Osprey Platform Well # RU5q First completion 1/20/2003 Second completion 1/15/2005 Baker Centrilift ESP Type GC2900 ESP failed 1/6/07 after 32 starts Osprey Platform Leg #3 Slot #5 5 Jote: Two check valves -one in each Capilary line below the tbg hanger .0" 150#" Conductor pipe at 200' 3 3/8" L-80 68# at 3190' MD 2940' TVD i 5/8" 47# L-80 BTC set at 11,500' MD -10,065'TVD •22 Joints (?) of 3.5" 12.95# P-110 TSHD Production Tubing >liding Sleeves are both X Line profile 2.562" ~OL 11,290 ~ 5/8"shoe at 11,500' MD Aiding Sleeve at 13,150 Veatherford Hydrow II pkr at 13,203' liding Sleeve at 13,258 Bottom of ESP at 13,433' MD faker FA Packer at 14,988" •OL 15,118' MD 5/8 shoe at 11980' TVD -15,323' MD 7 5/8" L-80 29.7# Hydril 521 PBTD EZ dril at 16,575' MD 5 1/2" L-80 17# Hydril 521 set at 17,000' MD 12,830' TVD ~3 STATE OF ALASKA . NOTICE TO PUBLISHER ~ ADVERTISING ORDER NO. ADVERTISING ORDER INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE AO-02814007 SEE BOTTOM FOR INVOICE ADDRESS F R AOGCC 333 W 7th Ave, Ste 100 AGENCY CONTACT Jod Colombie DATE OF A.O. Au ust 6 2007 ° M Anchorage, AK 99501 907-793-1238 PHONE - PCN DATES ADVERTISEMENT REQUIRED: o Peninsula Clarion P.O. Box 3009 Kenai AK 99611 ~ August 9, 2007 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Advertisement to be published was e-mailed Type of Advertisement Legal® ^ Display Classif ied ^Other (Specify) SEE ATTACHED SEND INVOICE IN TRIPLICATE TO AOGCC, 333 W. 7th Ave., SUlte 100 Anchora e AK 99501 PAGE 1 OF 2 PAGES TOTAL OF ALL PAGES$ REF TYPE NUMBER AMOUNT DATE COMMENTS 1 VEN ~ ARD 02910 3 4 FIN AMOUNT SY CC PGM LC ACCT FY NMR oisT ua ~ OS 02140100 73451 2 3 4 3 REQUISITION BY:, DIVISION APPROVAL: , ~ • • Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Request for an Area Injection Order for the Hemlock Formation, Redoubt Unit Forest Oil Corporation (``Forest"), by letter and application dated and received July 30, 2007, requests that the Alaska Oil and Gas Conservation Commission ("Commission") issue an area injection order, in accordance with 20 AAC 25.460, authorizing the expansion of Enhanced Recovery Injection Order No. 2 ("ERI02") from a single-well pilot project to a full-field development to enhance oil recovery operations from the Hemlock Formation within the Redoubt Unit. Alternatively, Forest requests that the Commission grant atwelve-month extension of ERI02, from October 1, 2007 to September 30, 2008. The proposed development area is located within portions of T7N- R 13 W and T7N-R 14 W, Seward Meridian. A public hearing on Forest's application has tentatively been scheduled for September 13, 2007 at 9:00 a.m. at the Alaska Oil and Gas Conservation Commission at 333 West 7`" Avenue, Suite 100, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, file a written request with the Commission no later than 4:30 p.m. on August 27, 2007. If a written request for a hearing is not timely filed, the Commission may issue an order without a hearing. To learn if the Commission will hold the public hearing, call the Commission's Special Assistant, Ms. Jody Colombie, at 907-793-1221. In addition, a written protest or written comments regarding the application may be submitted to the Alaska Oil and Gas Conservation Commission at 333 West 7cn Avenue, Suite 100, Anchorage, Alaska 99501. Any written protest or comments must be received by 4:30 p.m. on September 10, 2007 .except that, if the Commission holds a public hearing, a written protest or comments must be received by the conclusion of the September 13, 2007 hearing. If, because of a disability, spec' ac ommodations may be needed to submit a written protest or comments the pu lic hearing, call Ms. Colombie at 907-793- 1221 before September 1 , 2007 ~ ,,~ • ~ PUBLISHER'S AFFIDAVIT UNITED STATES OF AMERICA, STATE OF ALASKA ss: Denise Reece being first duly sworn, on oath deposes and says: That I am and was at all times here in this affidavit mentions, Supervisor of Legals of the Peninsula Clarion, a news- paper of general circulation and published at Kenai, Alaska, that the Public He-wring -Forest Oil AO-2814007 a printed copy of which is hereto annexed was published in said paper one each and every daY for one successive and consecutive day in the issues on the following dates: Aueust 9.2007 x[1en.~.a~ ~.~~r~ SUBSCRIBED AND SWORN to me before ' 20th day of August 2007 NOTARY PUBLIC in favor for the State of Alaska. My Commission expires 26-Aug-08 1 NOTICE ~ PUBL~ HEARING 1 1 STATE OF ALASKA 1 1 Alaska Oifand Gas Conservation Commission 1 1 Re: Request for an Area Injection Order for the Hembck i 1 Formation, Redount Unft 1 Forest Oil Corporation ("Forest"), by letter and appllca-1 'lion dated and received July 30, 2007, requests that the ~ Alaska Oil and Gas Conservation Commisslon 1 ~ ("Commission") Issue an area injection order, in accour- ~ 1 dance with 20 AAC 25.460, authorizing the expansion of I I Enhanced Recovery Injection Order No. 2 ("ERI02") I I from a single-well pilot project to a full-field development I Ito enhance oil recovery operations from Hemlock) I Formation within the Redoubt Untt. Alternatively, Forest I I requests that the commision grant atwelve-month 1 (extension of ER102, from October 1, 2007 to l; I September 30, 2008. The proposed development area 1 1 fs located wthin portions of T7N-R13W and T7N-R14W,1 1 Seward Maridlan. 1 A public hearing on Forest's application has tentatively 1 1 been scheduled for September 13, 2007 at 9:00 a.m. at 1 the Alaska Oil and Gas Conservation Commission at 1 1333 West 7th. Avenue, Sute 100, Anchorage, Alaska 1 199501. To request that the tentatively scheduled hearing I 1 be held, file a written request with the Commission no; 1 later than 4:30 p.m. on August 27, 2007. i M a written request for haring is not timely. filed, the ~ 1 Commission may issue an order without a hearing. To I 1 darn 'rf the Commission will hid the public hearing, call I I the Commission's Special Assistant, Ms. Jody Colombie, I at 907-793-1221. 1 1 In addition, a written protest or written comments regard-1 1 ing the applicaRon may be submittd to the Alaska Oil and 1 1 Gas Conservation Commisslon at 333 West 7th Avenue,) 1 Suite 100, Anchorage, Alaska 99501. Any written 1 1 protest or comments must be received by 4:30 p.m. on 1 1 September 10, 2007 except that, 'rf the Commission 1 1 holds a public hearing, a written protest or comments 1 1 must be received by the concluson of the September 13. ; 12007 hearing. 1 If, becuse of a disability, special accommodations may 1 1 be needed to submft a written protest or comments or 1 1 attend the public hearing, call Ms. Colombie at 907-793-; 1 1221 before September t 1, 2007. ~ PUBLISH tl/9, 2007 ti013/2074 ~ i~~~~~~~~~~~~~~~~~~~~~J .,~~ .a -' --•~-- weuc ;~•........a Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Monday, August 06, 2007 3:27 PM To: Denise Reece Subject: Public Notice Attachments: AO Order Clarion form.doc; AIO_RU_Public_Notice.doc Thank you Page 1 of 1 8/6/2007 02-902 (Rev. 3/94) Publisher~inal Copies: Department Fiscal, Depart~eceiving AO.FRM STATE OF ALASKA NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED FFID VIT OF PUBLICATIO PART 2 OF HIS FO M WI H ATTACHED COPY OF AO-02814007 ORDER ) A A N ( T R T ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM FORiNVOICE ADDRESS F AOGCC AGENCY CONTACT DATE OF A.O. R 333 West 7th Avenue. Suite 100 ° Anch~rage_ AK 995(11 PHONE PCN M 907-793-1238 DATES ADVERTISEMENT REQUlREO: o Peninsula Clarion August 9 2007 , PO Box 3009 Kenai AK 99611 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ~ ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: AFFIDAVIT OF PUBLICATION United states of America REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. division. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. Before me, the undersigned, a notary public this day personally appeared ATTACH PROOF OF PUBLICATION HERE. who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2007, and thereafter for consecutive days, the last publication appearing on the day of 2007, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This day of 2007, Notary public for state of My commission expires 02-901 (Rev. 3/94) AO.FRM r~ i STATE OF ALASKA NOTICE TO PUBLISHER ~ ADVERTISING ORDER NO. ADVERTISING ORDER INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION (PART2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE AO-02814006 SEE'BOTTOM FOR INVOICE ADDRESS F R AOGCC 333 W 7th Ave, Ste 100 AGENCY CONTACT Jod Colombie DATE OF A.O. Au ust 6 2007 ° M Anchorage, AK 99501 907-793-1238 PHONE - PCN DATES ADVERTISEMENT REQUIRED: o Anchorage Daily News PO Box 149001 Anchora e AK 99514 g ~ August 8, 2007 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Advertisement to be published was e-mailed Type of Advertisement Legal® ^ Display Classif ied ^Other (Specify) SEE ATTACHED SEND INVOICE IN TRIPLICATE AOGCC, 333 W. 7th Ave., Suite 100 PAGE 1 OF TO Anchora e AK 99501 2 PAGEs TOTAL OF ALL PAGES$ REF TYPE NUMBER AMOUNT DATE COMMENTS 1 VEN s ARD 02910 FIN AMOUNT SY CC PGM LC ACCT FY NMR msT uo ~ 07 02140100 73451 REQUISITI E .,- - DIVISION APPROVAL: n ...~- - 02-9 2 (R .3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM • Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Request for an Area Injection Order for the Hemlock Formation, Redoubt Unit Forest Oil Corporation ("Forest"), by letter and application dated and received July 30, 2007, requests that the Alaska Oil and Gas Conservation Commission ("Commission") issue an area injection order, in accordance with 20 AAC 25.460, authorizing the expansion of Enhanced Recovery Injection Order No. 2 ("ERI02") from a single-well pilot project to a full-field development to enhance oil recovery operations from the Hemlock Formation within the Redoubt Unit. Alternatively, Forest requests that the Commission grant atwelve-month extension of ERI02, from October 1, 2007 to September 30, 2008. The proposed development area is located within portions of T7N- R13Wand T7N-R14W, Seward Meridian. A public hearing on Forest's application has tentatively been scheduled for September 13, 2007 at 9:00 a.m. at the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, file a written request with the Commission no later than 4:30 p.m. on August 27, 2007. If a written request for a hearing is not timely filed, the Commission may issue an order without a hearing. To learn if the Commission will hold the public hearing, call the Commission's Special Assistant, Ms. Jody Colombie, at 907-793-1221. In addition, a written protest or written comments regarding the application may be submitted to the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Any written protest or comments must be received by 4:30 p.m. on September 10, 2007 except that, if the Commission holds a public hearing, a written protest or comments must be received by the conclusion of the September 13, 2007 hearing. If, because of a disability, spec' ac ommodations may be needed to submit a written protest or comments the pu lic hearing, call Ms. Colombie at 907-793- 1221 before September 1 , 2007 ~ ,,~ Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Monday, August 06, 2007 3:23 PM To: Legal Ads Anchorage Daily News Attachments: AIO_RU_Public_Notice.doc; Ad Order ADN form.doc Revised 8/6/2007 GE,IVE® UG 1 3 2007 Anchorage Daily News ~~~~'~`Y' Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 A1aSk8 ~~' & 6aS Cons. ~ap(1USSjan Anchorage PRICE OTHER THER OTHER OTHER OTHER GRAND AD # DATE PO ACCOUNT PER DAY CHARGES CHARGES #2 CHARGES #3 CHARGES #4 CHARGES #5 TOTAL 302954 08/08/2007 02814006 STOF0330 $199.20 $199.20 $0.00 STATE OF ALASKA THIRD JUDICIAL DISTRICT Christine Clark, being first duly sworn on oath deposes and says that she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on the above dates and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Subscrl ed and s~w'6rn to me before this date: Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska , MY C MMISSION EXPIRES: ~lF ~ ~ ~~~~~ r ~ - '? ~ ,~a t t ! l,l t' I~'~., ~. ~ ~>", .,. ~, R ~ - ,.. .~ __ . .. ~, . ,~ , _e' ~~ 'j;'t F; 1.,~1 $0.00 $0.00 $0.00 $0.00 I __ ~~ Nodce of Public Hearing STATE OPALASi[tA Alaska Oil and Gas Conservation Commission Re: Request for an Area Injection Order for the Hemlock Formation, Redoubt Unit Forest Oil Corporation. ("Forest"), by letter and apptica-. tion dated and received July 30, 2007, requests that the Aleska'Oil and Gas Cnnseniarinn rnmmicc~..,, a twelve-month extension of ER102; from October 1; 2007 to September 30, 2008. The proppled deyelop- mentarea is locatedwithin portions ofT7N-R13W anal T7N-R14W, Sewall Meridian.: A public hearingg on Forest's application has tenta- tivelybeen scheduled for September 13; 2007 et 9:00 a.m. at the Alaska 0il attd Gas Conservation Commis- sion at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. To request that the tentativelysched- uled hearing be held, file a written request withthe Commission no later than 4;30 p.m: on August 27, 2007. If a written request for a hearing is not time)yy fite0. the commission may issue an order v~gthdut a hearing., To team if the Commission w(Il hold the pubNC hearng, call the Commission's Special Assistant, Ms. ~pdy.Co- Iombie,at 90Z-793-1221_° Ih addition, a written protestor written comments re- garding the application-may be submitted to the Alaska Od and Oas cpnservatwn Commission at 333 west 7th Avenue, Suite 100, Anchorage, Alaska 99501. Arry written protest Or commBMS. ~~utISt be re- . t ceived by a:3o p.m. on September 1p, 20A7 excepf that, if the Cprnmissionfiolds apublic hearing, a wrtt- I ten protest or'comments must be received by the conclusion of the SeptembeYl3, 2007 hearing,. If, because of a disabitity special accommodations may tieneeded to submit a written protest or com- , ments or attend the public hearing, call Ms. Colombie at 907-793-1221 before September 11, 2007. /S/f John K. Nomlan Chairman ; AO# 02814006 Publish:AUgUSt 8,.2007 $199.20 l ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED WITH ATTACHED COPY OF AFFIDAV T OF PUBLICATION PA T 2 OF THIS FORM AO-02814006 ORDER ( ) I R ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM FOR INVOICE ADDRESS F AOGCC AGENCY CONTACT DATE OF A.O. R 333 West 7th Avenue. Suite 100 Anchorage. AK 9951 PHONE PCN M 907-793-1238 - DATES ADVERTISEMENT REQUIRED: o Anchorage Daily News August 8 2007 , PO Box 149001 Anchora e AK 99514 E LINES MUST BE PRINTED IN E g , DATES SHOWN TS ENTIRETY ON T S SPECIAL INSTRUCTIONS: Account # STOF0330 AFFIDAVIT OF PUBLICATION United states of America REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. division. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. Before me, the undersigned, a notary public this day personally appeared ATTACH PROOF OF PUBLICATION HERE. who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2007, and thereafter for consecutive days, the last publication appearing on the day of 2007, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This day of 2007, Notary public for state of My commission expires Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Monday, August 06, 2007 3:31 PM To: McIver, C (DOA); 'Alan Birnbaum <""Alan J Birnbaum "> (alan.birnbaum@alaska.gov)'; 'Aleutians East Borough'; 'Anna Raff; 'Arthur C Saltmarsh'; 'Arthur Copoulos'; 'Barbara F Fullmer'; 'bbritch'; 'Bill Fowler'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'buonoje'; 'Cammy Taylor'; 'carol smyth'; 'Cary Carrigan'; 'Catherine P Foerster'; 'Charles O'Donnell'; 'Chris Gay'; 'Christian Gou-Leonhardt'; 'Christine Hansen'; 'Cliff Posey'; 'Cody Rice'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deanna Gamble'; 'Deborah J. Jones'; 'doug_schultze'; 'Evan Harness'; 'eyancy'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gregg Nady'; 'gregory micallef; 'gspfoff'; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James B Regg'; 'James M. Ruud'; 'James Scherr'; 'Janet D. Platt'; 'jdarlington ; 'jejones'; 'Jerry McCutcheon'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; 'Jon Goltz'; 'Julie Houle'; 'Karl Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kristin Dirks'; 'Laura Silliphant'; 'Lois'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=Crockett@aoga.org'; 'mail=fours@mtaonline.net'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; 'marty'r 'Matt Rader'; 'mckay'; 'Meghan Powell'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; 'Patty Alfaro'; 'Paul Decker'; 'Paul Winslow'; 'Randall Kanady'; 'Randy L. Skillern'; 'rcrotty'; 'rmclean'; 'Robert Campbell'; 'Roger Belman'; 'Rosanne M. Jacobsen'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'stanekj'; 'Stephen F Davies'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; 'Thomas E Maunder'; 'Tim Lawlor'; 'Todd Durkee'; 'Tricia Waggoner'; 'trmjr1'; 'Wafter Featherly'; 'Walter Quay'; 'Wayne Rancier' Subject: Public Notice Redoubt Unit; Admin Approvals Colville River Unit A10186-004 and DIO 18-001 Attachments: A1018B-004.pdf; D1018-001.pdf; Public Notice Redoubt Unit.pdf 8/6/2007 ~ i Mary Jones David McCaleb Mona Dickens 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 John Levorsen Michael Parks Mark Wedman 200 North 3rd Street, #1202 Marple's Business Newsletter Halliburton Boise, ID 83702 117 West Mercer St, Ste 200 6900 Arctic Blvd. Seattle, WA 98119-3960 Anchorage, AK 99502 Baker Oil Tools Schlumberger Ciri 4730 Business Park Blvd., #44 Drilling and Measurements Land Department Anchorage, AK 99503 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99503 Anchorage, AK 99503 Ivan Gillian Jill Schneider Gordon Severson 9649 Musket Bell Cr.#5 US Geological Survey 3201 Westmar Cr. Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508-4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs PO Box 190083 PO Box 39309 PO Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Richard Wagner Refuge Manager 399 West Riverview Avenue PO Box 60868 PO Box 2139 Soldotna, AK 99669-7714 Fairbanks, AK 99706 Soldotna, AK 99669-2139 Cliff Burglin Bernie Karl North Slope Borough PO Box 70131 K&K Recycling Inc. PO Box 69 Fairbanks, AK 99707 PO Box 58055 Barrow, AK 99723 Fairbanks, AK 99711 Williams Thomas Arctic Slope Regional Corporation Land Department ( PO Box 129 I Barrow, AK 99723 i 7 4 ~i ~~ .{ i ~2 ~ a STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue, Suite 100 Anchorage Alaska 99501 Re: APPLICATION OF FOREST OIL CORPORATION for an order authorizing the expansion of Enhanced recovery Injection Order No. 2. Conservation Order No. ~ Redoubt Unit ~ Hemlock Formation ~ July 30, 2007 Recusal from Decision Daniel T. Seamount, Jr., Commissioner hereby recused himself from the above entitled case. August 8, 2007 Date Commissioner ~1 .~~ .~u~... ~ 0 2aa~ iaska 0~I & Cas Cons. Ctrmmisson A~tchor~ • July 30, 2007 Mr. John Norman, Chair Forest Oil Corporation 310 K Street, Suite 700 Anchorage, Alaska 99501 (907) 258-8600 Fax: (907) 258-8601 Alaska Oil and Gas Conservation Commission 333 West 7~' Avenue, Suite 100 Anchorage, AK 99501 Re: Application for Area Injection Order -Redoubt Unit Dear Commissioner Norman: Forest Oil Corporation (Forest) is requesting from the Alaska Oil and Gas Conservation Commission (AOGCC), an expansion of the existing Enhanced Recovery Injection Order (ERIO2) at Redoubt Unit to a full-field Area Injection Order, and/or a twelve month extension of the existing Enhanced Recovery Injection Order. On June 14, 2004 Forest submitted an application to the AOGCC to initiate a pilot enhanced oil recovery project in the Hemlock formation at Redoubt Unit. Permission to inject fluids into the Redoubt Unit #6 (RU #6) wellbore was granted by the AOGCC on August 26, 2004 under Enhanced Recovery Injection Order No. 2 (ERIO2). Water injection into RU #6 was first initiated on March 7, 2005. The continuous injection of fluids into the Hemlock formation has proven to be beneficial in improving the oil recovery from the "Central" fault block of the Redoubt Unit. Taking into consideration Forest's plans to expand the production at Redoubt Unit, continued water injection will be required to optimize the oil recovery from the Hemlock formation. Expansion of the existing enhanced recovery injection order to a full- field area injection order will allow for continued waterflood and pressure support in the Central fault block and will also allow Forest to initiate waterflood and pressure support in the Southern fault block. Forest is currently in the process of evaluating/planning expanded development of the Hemlock formation at Redoubt Unit. Although the exact plans and well penetrations have not been finalized, future development will definitely hinge on waterflood operations (both in the Central and Southern fault blocks). Attached to this application is a production and injection analysis of the Hemlock formation at Redoubt Unit. The analysis includes production and injection plots, production forecasts, reservoir voidage volumes, and a current Redoubt Unit Hemlock structure map showing potential sidetrack locations. Also attached to this application is the pilot enhanced oil recovery application that Forest submitted in June of 2004. This application contains the Redoubt Unit data required under Alaska Administrative Code, Title 20 -Chapter 25, Article O5. More specifically the pilot enhanced oil recovery application conformed to the Enhanced Recovery Operations regulations specified by 20 AAC 25.402(c). The same information is applicable to this application for an Area Injection Order. • If there are any questions, please contact me at 868-2131. Sincerely, G~?~~_ ~~ Paul M. Winslow Reservoir Engineer cc: Leonard C. Gurule, Senior V.P. -Forest Oil Corporation James Regg, Petroleum Engineer - AOGCC Attachments: • • • • LIST OF ATTACHMENTS Attachment 1 -Redoubt Unit Production and Water Injection Analysis Attachment 2 -Forest Oil Corporation's Application for Enhanced Recovery Pilot Project -Redoubt Unit • • ATTACHMENT 1 Redoubt Unit Production and Water Injection Analysis • Redoubt Unit Production and Water Injection Analysis ~~ (July 30, 2007) • • • • • • Redoubt Unit -Production History: • 1St Redoubt Production in December 2002 • RU #1 1St Production: 12-14-02 • RU #2 1St Production: 12-14-02 • RU #5A 1St Production: 1-20-03 • RU #6 1St Production: 4-17-03 • R U #7 1 St Prod uc tion: 3-26-04 • Cumulative Oil Production (to date) = 2.19 MMSTBO • As of 7-24-07 , • Cumulative Water Production (to date) = 2.68 MMBW • Cumulative Water Injection (to date) = 1.15 MMBW • • • Daily Redoubt Oil 8 Water Production (BPD) -• o 0 0 0 0 0 0 0 0 12/1 /02 2/1 /03 4/1 /03 6/1 /03 8/1 /03 10/1 /03 12/1 /0 3 2/1 /04 4/1 /04 6/1 /04 /1 / 4 ~ 8 0 Q. 10/1 /04 ~ c 12/1 /04 a C 2/1 /05 ~ 4/1 /05 _ ~ v ° ' 6/1 /05 _ ~ ~ 8/1 /05 T cD 10/1 /05 Q- '~ 12/1 / 05 p 2/1 /06 ~ c~ 4/1 /06 p 6/1 /06 8/1 /06 10/1 /06 12/1 /06 2/1 /07 4/1 /07 6/1 /07 8/1 /07 10/1 /07 O c ~ N O O W O -P CJ~ O v W O O O O O O ~ O O 0 0 0 0 0 0 ~ ~ o O Water Cut • • - ~ - ~i- ~ ~ I I ~ ~ I ~ ' T- ,r c ~ c c ~ ~ c ~ v m ~ - m no~i - n ~ ~ ~ a *~: ~~ r o ~ c~n v C _ - - ~ -- - _ ~ ~ ~ -~ o rn _ - -- ~^' ~ ?. ~ ~ ~ ~ ~ _, N ,..t C ~n o ~ o ~ cn "~ ~ - _ _ ~`` ~ ' : -~ ~, • • • Redoubt Unit -Injection History: • First injection (into Hemlock Reservoir) in March 2005 i • RU #6 1St Injection: 3-7-05 • Continuous injection commenced 4/25/05 • Cumulative Water Injection (to date) =1.15 MMBW ~ • As of 7-24-07 ~ • • Redoubt Unit #6 -Injection History 5,000 - _ _ _.e_ ~ ._-- --- -- RU #6 -Water Injection i 4,500 ~-RU #6 -Injection Pressure ~ 4,000 ~f/! ~ ~I 3,500 3 Uf U1 d a ~ 3,000 D a m 2,500 c 0 «. m , 2,000 c L ~ 1,500 .~ G 1,000 500 ~ 0 \~ \~ ~~ \~~o \~~o \0 \~ro \~ ~~ro \~co ~~ ~~ ~ \~c~ \~c~ ~~ ~~'1 ~~'l ~~'l ~~'l ~~'l ~Oh ~~h ~0 ~0~ ~0 \~~ \~ ~ \~ ~ \~ ~\~ ~\~ ~\~ \~ \~ ~\~ \~ \~ ~\~ ~\~ \~ ~\~ ~\~ \~ ~~ \~ ~\~ ~\~ \~ \~ ~ ~\,~ ~\,~ ~\,~ 1~~ ~ ~ Date • • • • Daily Redoubt Oil 8~ Water Production (BPD) o 0 0 0 0 0 0 0 0 12/1 /02 2/1 /03 4/1 /03 6/1 /03 8/1 /03 10/1 /03 12/1 /03 2/1 /04 ~ a ~ 4/1 /04 0 1 / 4 Q 6/ 0 rt C 8/1 /04 rt 10/1 /04 v ~ 12/1 /04 ~'! 2/1 /05 cD ~ 4/1 /05 - v ~ 6/1 /05 ~ Q. 8/1 !05 n 10/1 /05 p 12/1 /05 ~ ~' 2/1 /06 ` ' 4/1 /06 c c n 6/1 /06 p ~ 8/1 /06 10/1 /06 12/1 /06 ~,r 2/1 /07 -~~.:.- 4/1 /07 6/1 /07 8/1 /07 10/1 /07 • i i I I ~ v m ~ ~ c c ~ c g o v m -~ - m' ~ ~ ~~ ~ o cn _ ~ _ ~ c~~ ~ ~ ., ~ rn 5 ~ .= .A _ c N ~ Ul O c b ~ ~ ini C] • • • - l,~~Jr.J:.Jr ..JJJJr J ~ J:^..1:..JJrJJJJ .~~ J~~./r^.~^^ ^ ^^.rr.+ .® Redoubt Unit Daily Fiel d Pro duction and Injection 10,000 D a m c 0 0 a `° 1,000 o~S O .. ~ I 0 m o: .~ 0 i 100 ~ n ~n ~n ~n ~n ~n co cn c 0 0 0 0 0 0 0 0 n c 0 o co c 0 0 o r~ r~ 0 0 0 ~ 0 ti 0 ~ 0 ~ 0 r M L(') f~ ~ r r M I r n ~ ~ r r M r Ln I ~ ~ ~ Dat e • ----- Star t continuous ------ ---------- - ---------- ---------- - ---------- - ---------- ---------- ---------- ---------- ---------- - ---------- - ---------- ---------- ---------- ---------- ---------- ---------- ---- --------- ---------- ----------- ------- Wa ter Injection ------ ------ ---------- ---------- ----------- ----------- ---------- - ---------- ---------- ---------- --------- --------- ---------- ----------- ------- into R U #6 (4-25-05 -- ----------- ---------- ----------- ---------- ----------- - - - ------- ---------- ----------- --- ~A ---------- -------- ' I i ' {+ I I I ~ I --- --- - --- --- --- ----- - -------- - ------- -- -- -- -- ---- ----- ----- ±, -- - ------- - - - - ~ r -------- ----------- ---------- ----------- ---- ----- •~RU Total Fluid --------- ---------- ----- ----- --- ---------- ------- - ------ - --- --------- ---------- ----- ~RU Oil ^~RU Water Water Injection Production Histo by Fault Block: ~: RU "Central" Fault Block: • RU #1 (12-14-02) Cum. Oil = 0.86 MMSTBO • RU #6 (4-17-03) Cum. Oil = 0.20 MMSTBO • RU #7 (3-26-04) Cum. Oil = 0.28 MMSTBO • RU #6 (3-7-05) Cum. Water Injection =1.15 MMBW RU "Southern' Fault Block: Cum. Oil = 0.52 MMSTBO Cum. Oil = 0.33 M M ST BO • No Water Injection into Southern fault block • • • • • Daily Redoubt Oil 8 Water Production (BPD) ..f 1 Q Q O 12/1 /02 211 /03 4/1 /03 6/1 /03 8/1 /03 10/1 /03 12/1 /03 2/1 /04 4/1 /04 6/1 /04 v~ ~• ~ 8/1 /04 ~ Q O 'r ~ 10/1 /04 ! cD ~ a 12/1 /04 C ~ ~ ~ 2/1 /05 O 4/1 /05 ~ ~ d 6/1 /05 N ~ 41 8/1 /05 ~ a = 10/1 /05 • 12/1 /05 ~ W rt C 2/1 /06 O n ~ ~ 4/1 /06 6/1 /06 8/1 /06 10/1 /06 ~ 12/1 /06 2/1 /07 4/1 /07 ~ 6/1 /07 ~ I 8/1 /07 I 10/1 /07 • • I ~ ~ ~ ~ ~, c c c m ~ O o -~ _ _ v ~ '- m - m' ~ T c o iz ~~ ~ ~ i ~-- C ~ ~ m .p m~ ~' _ ~~ N ,~, C "~ U1 p C ~ V1 O ~" 1 ,~ c ' n ~ ~ ~ ° ' ccc - _ ~ rn ~ ~ c W 0 in • • • Redoubt Unit Reservoir Voidage • • • • Hemlock Reservoir Voidage to date: • Cumulative Hemlock Production to date (7-24-07) = 4.87 MM STB (5.31 MM RB) 2.19 MM STBO (2.58 MM RB of oil) 2.68 MM STBW (2.73 MM RB of water) Hemlock Production prior to RU #6 injection = 3.22 MM STB (3.53 MM RB) • 1.57 MM STBO • 1.65 MM STBW (1.85 MM RB of oil) (1.68 MM RB of water) Hemlock Production after start RU #6 infection =1.65 MM STB (1.78 MM RB) • 0.62 MM STBO • 1.03 MM STBW (0.73 MM RB of oil) (1.05 MM RB of water) • • • • Hemlock Reservoir Voidage to date (cont.): • Cumulative Hemlock Production to date (7-24-07) = 4.87 MM STB ~ (5.31 MM RB) • RU #6 Injection Volume to date (7-24-07) =1.15 MM STBW (1.15 MM RB) • Hemlock Voidage to date (7-24-07) = 4.16 MM RB of fluid Note: Voidage Assumes average Bo =1.175 RB/STB & Bw =1.02 RB/STB • • • • U • • Cumulative Hemlock Production since 1St Injection ~ = 1.65 MM STB (1.78 MM RB) = 1.15 MM STBW (1.15 MM RB) a • Hemlock Voidage since 1 St Injection = 0.63 MM RB of fluid - 65% Volumetric Replacement - 0.62 MM STBO (0.73 MM RB of oil) - 1.03 MM STBW (1.05 MM RB of water) • Cumulative Hemlock Injection Hemlock Voidage since 1St Water Injection: 0 ~ ~ o PhNV_Oil m ~ ~ m V ~ ~ g n ~ ~ O Apri125, 2005 -Initiate Continuous Water Injection ~~ 0 Flatter production decline after start of water injection 0 0 0 ~ {~ ti o 0 o a+i ° ° 95 96 97 96 99 00 01 02 03 04 OS O6 07 OS 09 10 11 12 13 14 r YEAR • • • • Redoubt Unit ~ "Central" Fault Block Reservoir Voidage • • . • "Central" Fault Block Reservoir Voidage to date: • "Central" Cum. Production to date (7-24-07) = 2.15 MM STB ~ (2.40 M M RB) - 1.35 MM STBO (1.58 MM RB of oil) - 0.81 MM STBW (0.82 MM RB of water) - "Central" Production prior to RU #6 injection =1.29 MM STB (1.44 MM RB) • 0.76 MM STBO (0.89 MM RB of oil) • • 0.53 MM STBW (0.54 MM RB of water) - "Central" Production after start RU #6 infection = 0.86 MM STB (0.97 M M RB) • 0.59 MM STBO (0.69 MM RB of oil) • 0.28 MM STBW (0.28 MM RB of water) • • ~ "Central" Fault Block Reservoir Voidaae to date (cont.l: • "Central" Cum. Production to date (7-24-07) = 2.15 MM STB ~ (2.40 MM RB) • RU #6 Injection Volume to date (7-24-07) = 1.15 MM STBW (1.15 MM RB) • Hemlock "Central" Voidage to date (7-24-07) = 1.25 MM RB of fluid Note: Voidage Assumes average Bo =1.175 RB/STB & Bw = 1.02 RB/STB • • • • • • Cumulative "Central" Fault Block Production since 1 St Injection • = 0.86 M M STB (0.97 M M RB) - 0.59 MM STBO (0.69 MM RB of oil) - 0.28 MM STBW (0.28 MM RB of water) Cumulative "Central" Fault Block Injection =1.15 MM STBW (1.15 MM RB) ~ "Central" Fault Block Hemlock Voidage since 1 St Injection _ -0.18 MM RB of fluid - 119% Volumetric Replacement (since 1 St injection) - Injected Volume > Produced Volume "Central" Fault Block Voidage since 1St Water Injection: 0 ~ ~ o PMW_~il m ~ ~ m c? ~ ~ ~ " " ~ Fault Block Central d o ~ ~' RU #1, RU #6, & RU #7 Apri125, 2005 -Initiate Continuous Water Injection ~ r O C V + V O 6l ~~ O ction decline Fl r rod tt p a e u after start of water injection G o 0 0 0 o 0 0 O u O O G O $ ° ° 95 96 97 98 99 00 01 02 03 04 OS 06 07 08 09 10 11 12 13 14 f YEAR • • • • 1. Prior to water injection into RU #6, the total Redoubt Unit Hemlock oil production exhibited a very steep decline rate of ~54% (~51 % in just the "Central" fault block wells). ~ 2. During the first ~24 months after initiating water injection into RU #6, the Redoubt Unit Hemlock oil production decline rate dropped to ~14% (13% in the "Central" fault block wells. • 3. Hemlock oil production has dropped significantly over the past year, due in part to lost wells (ESP failures) and inflow issues. ~ • • 1. Water injection into the Hemlock formation at Redoubt Unit has significantly reduced the oil production decline rate. ~ 2. Water injection has had a definite positive effect on the oil recovery at Redoubt Unit. 3. Continued water injection is critical to optimize the oil recovery from the Hemlock formation. • 4. More water injection is needed, especially in the "Southern" fault block, to optimize oil recovery. • • • • • . ATTACHMENT 2 Forest Oil Corporation's Application for Enhanced Recovery Pilot Project Redoubt Unit .7 • CJ ~~~ ~ Forest Oil Corporation ~~ 310 K Street, Suite 700 ~l ~ ,n Anchorage, Alaska 99501 (907) 258-8600 Fax: (907) 258-8601 June 14, 2004 State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7~' Avenue, Suite 100 Anchorage, AK 99501 Re: Application for Enhanced Recovery Pilot Project Redoubt Unit Gentlemen: Enclosed is Forest Oil Corporation's Application for an Enhanced Recovery Pilot Project for Redoubt Unit. The application conforms to regulations specified under the Alaska Administrative Code, Title 20 -Chapter 25, Article O5. More specifically the application conforms to the Enhanced Recovery Operations regulations specified by 20 AAC 25.402(c). If there are any questions, please contact me at 868-2131. Sincerely, ~~~~ Paul M. Winslow Reservoir Engineer Forest Oil Corporation cc: Leonard C. Gurule, Senior V.P. -Forest Oil Corporation • ..~~. ~~ w i • .. FOREST OIL CORPORATION ~~o ~~~ ~~ 700 ~ ~~ o ~ Q ~ o ® ` ..~~ ~ CS~~ 9950 lUH.~4.04 a State of Alaska Department of Natural Resources Division of Mining, Land & Water 550 W. 7th Avenue, Suite 1070 Anchorage, Alaska 99501 Redoubt Unit Enhanced Recovery Operations Pilot Project Application Forest Oil Corporation June 14, 2004 • • 1) Location Plat 20 AAC 25.402(c) Enhanced Recovery Application • Attached are two plats showing the location of all of the wells currently drilled on the Redoubt Shoal structure. Eight (8) wells have been drilled by Forest Oil Corporation (Forest) and/or Forcenegy Inc., of which five (5) are currently producing from the Hemlock reservoir (RU #l, RU #2, RU #SA, RU #6 and RU #7). In addition to the five producing wells, there is one (1) disposal well (D-1), one (1) shut-in G-zero gas well (RU #3, which was re-completed up hole from the Hemlock), and one (1) suspended wellbore (RU #4A). Two (2) of the wells (RU #SA and RU #4A) are sidetrack locations, thus the total number of Hemlock penetrations by Forest/Forcenergy isnine (9) wellbores. In addition to the nine (9) Forest/Forcenergy Hemlock penetrations, there were three (3) more wells drilled directly on the Redoubt Shoal structure in 1967, 1968, and 1976 (Redoubt Shoal State 29690 #l, Redoubt Shoal State 29690 #2, and Redoubt Bay Unit #1, respectively) and two (2) additional wells drilled on the southwest flank or panhandle in 1967 (Redoubt Shoal State 22064 #1 and Tenneco State 36465 #1). All five (5) of these wells were plugged and abandoned, prior to drilling by Forest/Forcenergy. Note that all of the Redoubt Unit wells have been drilled directionally from the Osprey Platform, which is located approximately 1.5 miles west-northwest of the crest of the Redoubt Shoal Structure. • Redoubt Unit #6 (RU #6), located in the "Central Fault Block" of the Redoubt Shoal Structure, is the proposed injection well for the Enhanced Recovery Pilot Project. This is the only injection well proposed at this time. RU #6 is currently a Hemlock oil producing well, which will be converted to an injection well most likely in June or July, 2004. The conversion is likely to coincide (directly proceeding) with an electrical submersible pump (ESP) change-out on RU #2. This enhanced recovery application is being submitted in order to obtain approval for injection into RU #6 shortly after its conversion of service. There are two (2) wells with Hemlock penetrations within a 1/4 mile radius of the proposed injection interval in RU #6. The top Hemlock penetration point for RU #7 is approximately 1,310 ft from the top penetration point in RU #6. The bottom hole locations for these two wells are approximately 835 ft apart. Similarly, the top Hemlock penetration point for RU #6 is approximately 940 ft from the top penetration point for the abandoned Redoubt Shoal State 29690 #2 wellbore. The bottom hole locations are roughly 1,390 ft separated. • 29670 29630 29998 249501 245101 24470E 244302 • Z4390B 293900 293188 2927001 2423001 297900E 2419292 • • • • 200 000 205 000 210 000 215 000 a' 0 ° R14W R13W ~ ADL 378114 N ~ 12 7 8 c~ 0 0 0 Red ubt Unit Boundary ADL 381203 T7 N a, 0 rv 13 ~`; ~ Osprey 1 $ 1 7 p U D1 0 0 O Redoubt Boy U i RU 1 -RSU 2 RU 4 Re bt S St 29 1 RU 4A RU 6 N RU 7 4 °' 0 ~ RU 2 19 20 ~ 0 o 0 RU ADL 374002 RU 5A R doubt Sh St 22064 7 RU 3 N o ~ FOREST OIL CORPORATION 30 p Alaska Business Unit 29 °0 1:31680 ~ 0 F o sooo ° EET FEET .p Redoubt Unit O o .5 W e ~ ( Locations STATUTE MILES ~ •0 STATUTE MI S °" i" = 2640' °" LMS O°' 14~IUN 2004 Y1~' NAD27, ASP ZONE 4 -151 °40' -151 °38' -151°36' • • 2) Offset Surface Owners and Operators The only surface owner within aone-quarter mile radius of either the Osprey Platform, which is the surface location of the RU #6 well, or the bottom hole location of the RU #6 well is the State of Alaska. The surface owner's lands are managed by the Deparkment of Natural Resources, Division of Mining, Land & Water. Forest is the only operator of any wells within aone-quarter mile radius of either the Osprey Platform or the bottom hole location of the RU #6 well, into which the water injection will occur. 3) Affidavit Showing Notification of Other Operators and Surface Owners The following affidavit it provided to verify that a copy of this application has been sent to the State of Alaska, the Department of Natural Resources, Division of Mining, Land & Water, being the manager for the State of Alaska. • • • • TO THE ALASKA OIL AND GAS CONSERVATION COMMISSION Before the Alaska Oil and Gas Conservation Commission ) In the Matter of the Application of ) VERIFICATION OF FACTS AND Forest Oil Corporation for Injection ) AFFIDAVIT OF JIM ARLINGTON For Enhanced Recovery Operations ) Subject to the provisions of 20 AAC 25.402 ) Jim Arlington, being first duly sworn, upon oath, deposes and states as follows: 1. My name is JIM ARLINGTON. I am over 19 years old and have personal knowledge of the matters set forth herein. 2. I am the Land Manager for the well operator, Forest Oil Corporation (FOREST). 3. I am acquainted with the facts associated with the application of Forest Oil Corporation for an application for injection for enhanced recovery operations pursuant to the provisions of 20 AAC 25.402 as they pertain to the proposed enhanced recovery operation involving water injection in the Redoubt Unit #6 well. 4. The only surface owner within aone-quarter mile radius of either the Osprey Platform, which is the surface location of the RU #6 well, or the bottom hole location of the RU #6 well is the State of Alaska. The surface owner's lands are managed by the Department of Natural Resources, Division of Mining, Land & Water. 5. Forest is the only operator of any wells within cone-quarter mile radius of either the Osprey Platform, which is fhe surface location of the RU #6 well, or the bottom hole location of the RU #6 • well. 6. On June 14, 2004, pursuant to 20 AAC 25.402 (c), FOREST sent a copy of its application for injection by United States mail to the State of Alaska, the Department of Natural Resources, Division of Mining, Land & Water at 550 W. 7~' Avenue, Suite 1070, Anchorage, Alaska 99501. Subscribed and sworn to on June fZ, 2004. T , Jim Arlingto STATE OF ALASIG4 ) ss. THIRD JUDICIAL DISTRICT ) On this ~ ~~~day of June 2004, before me, the undersigned, a Notary Public duly commissioned and sworn, appeared Jim Arlington, personally known to me, to be the person whose name is subscribed to within the Verification of Facts and Affidavit. ~,~,~`i,t~t-tllfl~~~l~ Witness my hand and official seal. "~ ~~ '~ ! Notary Public, State of Alaska _U:Z ~ , • ~ ~~ ~ My Commission Expires: L ~ -~' 1 " ~~ ~ AvB~`~•~q'~ I • •~~ • • ~lt~~flt~~(i~~~~`` • • 4) Description of Operation for which Approval is being Requested The Redoubt Unit field presently consists of five (5} producing wells completed in the Hemlock formation. It is being proposed to convert one of these wells (RU #6) from a Hemlock producer to a Hemlock Injection well. RU #6 is located in the "Central" fault block of the Redoubt Shoal structure, Southeast and Northeast of RU #1 and RU #7, respectively. Water injection into the Hemlock formation in RU #6 will primarily influence the hydrocarbon recovery in RU # 1 and RU #7, but may also help support the pressure and hydrocarbon recovery in RU #2 as well. RU #2 is located South of RU #1 and RU #7, in the northern part of the "Southern" fault block. Due to the relatively small number of Hemlock wells at Redoubt Unit, it would be uneconomical to develop a more thorough injection pattern at this time. Depending upon the success of this Pilot Project, more injection and production wells will be drilled in the future. Just prior to the electrical submersible pump (ESP) going down in RU #2, the water produced rate from RU #1, RU #2, RU #SA, and RU #7) at Redoubt Unit was approximately 2,700 bwpd. The total fluid production rate for RU #1, RU #2, and RU #7 (the three wells likely to be effected by injection in RU #6) was approximately 2,400 bfpd. Thus it is expected that injecting the produced water at Redoubt Unit will equal or exceed the total fluid off-take from the surrounding three wells. Currently the produced water at Redoubt is disposed of in the Redoubt Unit D-1 disposal well, located on the Osprey Platform. RU D-1 is a 8,611' (TD) vertical well with an approved disposal zone in the • Tyonek formation at 8,216' - 8,450' ft SSTVD. This injection well will remain operational as a back- up for produced water disposal should RU #6 have mechanical problems. This application is requesting approval to initiate an enhanced recovery pilot prof ect to inj ect produced Redoubt water into the RU #6 well. 5) Pools to be Affected The Redoubt Unit Hemlock oil pool is the only pool which will be effected by this proposed enhanced recovery project. Injection into RU #6 is expected to support pressure and enhance the recovery from RU #l, RU #7, and possibly from RU #2. The nearest producing well to the proposed RU #6 injection well, is RU #7 which is completed in the Hemlock formation from 11,633' - 12,168' SSTVD. RU #1 is completed in the Hemlock formation from 11,680' -12,292' SSTVD. RU #6 is currently completed and producing from the Hemlock formation over the interval 11,696' -12,304' SSTVD. 6) Injection Formations The Hemlock formation is the only formation currently producing oil at Redoubt Unit and is the proposed formation for this enhanced recovery operation. The description, depth, and thickness of the Hemlock formation at Redoubt Unit and the appropriate geologic data including lithologic descriptions and geologic names have been previously submitted to AOGCC as a part of the "Redoubt • • • Unit Hemlock Participating Area" (RUHPA) application. Excerpts from the RUHPA application as well as a brief lithofacies description follows: Deposition and Stratigraphy of the Hemlock The Hemlock conglomerate unconformably overlies the West Foreland Fm. and was deposited in a much higher energy depositional environment. The Hemlock consists of interbedded fine to coarse grained sands and gravels, pebble to cobble conglomerates, dense silts and occasional thin coals. Although there is some disagreement as to the exact depositional environment of the Hemlock, it is still essentially fluvial in nature. As to whether it was deposited in conglomerate fans shedding off of structural highs, or was deposited in a wide band of anastomosing braided stream systems, is still open to interpretation. In fact, the truth probably lies in a mix of the two interpretations depending on where you are geographically in the Inlet. The Hemlock is the primary oil producing reservoir in the Inlet, having yielded over a billion barrels of oil since it's discovery. It is also the primary target reservoir in the Redoubt structure. The Hemlock conglomerates display porosities and permeabilities equivalent to those in the West Foreland Fm. At Redoubt, 520 ft. of conventional core was cut and recovered from the RU_2 well. This core displayed a much finer grain size than was expected and than what is found at McArthur River. Overall, there are no boulder- or cobble-sized conglomerates found in the core from RU-2. The grain size of the sandstones is fine to medium and the largest pebble found in the core was approximately 2 inches x 1 inch x 3/4 inches. The depositional environment appears to be more distal from the source • and have a great deal less energy than the fan-glomerates at McArthur River. The Hemlock appears more uniform in its grain size distribution. Overlying the Hemlock conglomerates is the Tyonek Formation. This section is characterized by decreasing energy within the depositional environment and more uniform lithologies than were found in the Hemlock. The Tyonek can be divided into two separate sections based on affinity for oil or gas. The lower section, the G-zone, consists of interbedded sands, gravels and pebble conglomerates, with some minor coal and silt interbeds present. The G-zone is an oil prone section on the west side of the Inlet and in the Redoubt area. The upper Tyonek section is the Grayling Gas Sands equivalent (McArthur River Field). This section consists of a series of stacked packages bounded by thick coals. These packages consist of fine to coarse grained sands, and gravels with some interbedded silts and coals. The coals within the major packages are thinner and discontinuous, with a great deal of lateral variation. The upper Tyonek section was deposited in an anastomosing stream channels system, with the typical overbank deposits and swampy areas associated with this type of system. The Tyonek section displays porosities ranging from 12-23% and permeabilities from SOmd to several hundred millidarcies. With less of a variation in the lithologies, the reservoirs act more continuous in terms of hydrocarbon flow. Hemlock Lithofacies There are approximately 6 identified lithofacies present in the Hemlock Formation at Redoubt Unit. This was determined from the conventional core recovered from the Redoubt Unit #2 well. Porosity • within the Hemlock is intergranular and the rocks are well cemented and competent. Each of the lithofacies displays dispersed clays ranging from 9% to as much as 20% of the rock volume. This has • • • a direct effect on the fluid flow within the reservoir. The lithofacies, from coarsest to finest are as follows: Reservoir Facies 1) Pebble conglomerate -These conglomerates range from clast supported to very sandy and matrix supported. Pebbles in this fades are well rounded, and moderately sorted, indicating a considerable transport distance from their source. Porosities are relatively uniform, ranging from 7- 13%. 2) Pebble /gravel sandstone -This lithofacies is more uniform in grain size and is entirely matrix supported. Porosities range from 10-16%. 3) Medium to coarse grained sandstone -Facies is moderately well sorted and is matrix supported. Porosities range from 10-16%. 4) Fine grained sandstones - Facies is well sorted. Porosities range from 12-14%. Non-Reservoir Facies 5) Siltstones -Facies is very fine grained, dense and generally non-permeable. Porosities are very low ranging from 1-4%. • 6} Carbonaceous claystones /Coals -Facies is non-permeable generally have low porosities. Cuttings within the claystones resemble coals, while log response does not. Actually coals give a characteristic coal response on logs and in cutting. Hemlock Reservoir Characterization The Hemlock Reservoir at Redoubt is very heterogeneous both vertically and horizontally as seen in the core form RU #2 and from wireline analysis. The Hemlock was deposited in a fluvial depositional setting, comprised of meandering and coalescing fluvial stream channels. The channels sands can anastomoze and stack, and are interbedded with the gravel sands, pebble conglomerates and overbank deposits represented by the claystones, siltstones and coals. The source of sediments for the Hemlock was from the west and north-west, with a depositional flow direction south and south-east. Porosities in the sandstone fades of the Hemlock are between 12-18% ,with some small sands displaying higher averages. This includes the medium and coarse sandstone and pebble conglomerate fades. Permeabilities in these same fades range from 0.1 to several hundred millidarcies. The siltstone and very fine grained sandstone display lower porosities and penneabilities. This contrast in porosities and permeabilities between the different reservoir fades can affect fluid flow within the Hemlock reservoir. C] • • 'n Logs of the Injection Well Logs are already on file at AOGCC for all producing wells at Redoubt Unit, including the proposed injection well, RU #6. In addition to all of the Redoubt Unit wells, the Commission also has on file logs from the original Redoubt Shoal wells (Redoubt Shoal State 29690 #1, Redoubt Shoal State 29690 #2, and Redoubt Bay Unit #1). 8) Casing Program and Mechanical Integrity Testing Attached are the current well completion schematics for RU #6 and RU #7. Both wells are completed in, and are currently producing from the Hemlock Formation. Once approval has been granted, RU #6 will be re-completed to allow injection into the Hemlock formation. The current completion intervals in RU #6 will be the same intervals injected into for the enhanced recovery pilot project. Note that the completion schematic for RU #7 has been included in this application due to its proximity of just under '/4 mile from the proposed injection well. Wellbore surveys suggest that the top Hemlock penetration point for RU #7 is approximately 1,310 $ from the top penetration point in RU #6. The bottom hole locations for these two wells are approximately 835 ft apart. In addition to the completion schematics, the cementing programs for both RU #6 and RU #7 are provided in the following pages. RU #6 currently has 3-1/2" P-110 and L-80 (47 and 418 joints, respectively) tubing in the hole. The • injection string being proposed is a 3-1/2" coated 9.3# TSHP-CR tubing string. Note that prior to injection into RU #6, a mechanical integrity test of the casing and tubing will be performed. Sufficient notice will be given to the AOGCC so that a witness may be present for this pressure test. • Redoubt Uni~ Completion - Apri12003 • 30" A-36 200 ND 150 # Welded 200 MD 13 318" L-80 2975 ND 68 # BTC 3480 MD 3 1/2" P-110 Pup 47jts 3 1/2" P-110 Tubing 418 jts 3 1/2" L-80 Tubing Centrilift ESP Assembly @ 14675 MD (bottom) • TOL @ 14779 MD 9 5/8" L-80 11748 ND 47 # BTC 15085 MD LLC-3 Valve set in Baker Model FA Packer @ 15030 MD • Perforations: 15,130 - 15,164' MD 15,192 - 15,226' 15,252 - 15,302' 15,316 - 15,336' 15,418 - 15,444' 15,458 - 15,480' 15,542 - 15,630' 15,680 - 15,760' 15,788 - 15,812' 15,856 -.15,890' ~erForations :Z Drill @ 15990 MD 7 5/8" L-80 12570 ND 29.7# Hydril 521 16100 MD Redou~CJnit #7 Completion March, 2004 36", 1 SO#, A 36, Welded Conductor @ 21 S' MD /2 1 S'TVD 13-3/8", 68#, L-80, BTC @ 3,528' MD / 3,088' TVD 431 jts 3-1/2", RTS, PH 6 Tubing Centrilift ESP assembly @ 13,445'NID LLC valve set in Baker Retrieva SC-1 packer @ 13,630' MD Top of 7" liner @ 13,708' NID / 11,262' TVD 9-S/8", 47#, L-80, BTC @ 14,049' NID / 11,528' TVD Perforations: 14,350' - 14,424' 14,442' - 14,SOS' 14,S3S' - 14,580' 14,610' - 14,635' 14,745' - 14,785' 14,840' - 14,9SS' h 5,100' - 15,123' 15,340' - 15,383' 1S,S90' - 15,667' 3-3/8" guns, 6 SPF 7", 32#, P-110, Hydril S21 @ 1S,9S0' NID / 12,332' TVD • 9) Type of Fluid to be Injected Filtered produced water from RU #1, RU #2, RU #SA, and RU #7 will be injected into the Hemlock formation in RU #6. Since the water's source is the same Hemlock formation as the injection destination, compatibility is not an issue. It is not known at this time what the maximum daily rate that can be injected into the Hemlock formation at RU #6. Initial injection rates are expected to be between 2,500 and 3,000 bwpd, which is the total produced water from the remaining four producing wells. This injection rate will match or exceed the total production rate for the wells likely to be effected by the water flood. 10) Injection Pressure The Hemlock fracture gradient is not currently known at Redoubt Unit. It is suspected that the fracture gradient is between 0.75 and 1.2 psi/ft, as demonstrated by other Cook Inlet Hemlock reservoirs. Assuming a fracture gradient of 0.75 psi/ft and an average reservoir injection depth of 12,090' T'VD, the maximum allowable surface injection pressure to avoid fracturing the Hemlock formation is approximately 3,800 psi (0.75 psi/ft x 12,090' - 0.436 psi/ft Hemlock water hydrostatic gradient x 12,090'). This maximum allowable surface injection pressure does not take into account tubing friction pressure loss. It is estimated that tubing friction pressure loss for an injection rate of 2,500 bwpd, will be on the order of 500 psi, thus raising the maximum surface injection pressure to 4,300 psi. Actual friction loss and maximum allowable injection pressure will be determined once the • injection string has been finalized. Note that the pumps currently installed at Kustatan Production Facility, which will be used to inject water into RU #6, discharge at 5,000 psi. Taking into a 200 psi pressure drop from Kustatan to the Osprey Platform, the maximum possible surface injection pressure will be 4,800 psi. This pump pressure will be choked back such that it does not exceed the fracture gradient of the Hemlock formation. 11) Protection of Freshwater Strata The casing and cementing program practiced at Redoubt Unit ensures that no injected water will be able to migrate above the Hemlock formation to contact any freshwater strata near the surface. All Redoubt Unit wells, including RU #6 (which is the proposed injection well), have intermediate casing set at or just above the top of the Hemlock Formation. This intermediate casing is cemented to isolate any upward movement of fluids on the back-side of the casing. Prior to drilling out the plug and drilling through the Hemlock formation, the cement is pressure tested. Once the Hemlock formation has been drilled through, a casing liner is hung and cemented across the entire Hemlock formation. Cement bond logs have been run in all wells and copies have been sent previously to AOGCC. Schlumberger's "Cement Evaluation" (attached) of the cement job in the RU #6 wellbore (across the Hemlock formation) shows cement across the entire Hemlock interval, with better cement bond at the top of the formation. Likewise, the cement bond interpretation in Redoubt #7, shows good to excellent bond across the Middle and Upper Hemlock (with poorer bond in the Forest Oil Corporation Job Number 23237 ~ Cement Evaluation Lo Field. Redoubt Shoal Oil Field 9s 9 16645-16670 Good cement Figure 5 displays the transition from well cemented to free pipe signal around 15800 ft. Redoubt Unit 6 Redoubt Unit 6 was logged with USIT and CBT tools on 05-APR-2003. These were logged over the in combination over the interval 14700 ft to 16000 ft. Three centralizers were employed on the CBT tool and Z on the USIT tool. The logs were recorded inside 7.625 in. 29.7 Ib/ft casing cemented inside an 8.5 in. borehole. A swivel was included in the tool string to minimize tool rotation while logging. The cement bond in this well in general improves towards the top of the logged interval. Above 15225 ft most of the casing is cemented. Below that depth there are sections with little to no cement mixed with sections with good cement. Isolation of individual perforated intervals in described in Table 4. Table 4 w_ •. .. _ _ _ _ _ • • n _~ Q n DRAFT Figure 6 identifies a channel located from 15225 ft to 15324 ft. • • Lower Hemlock). The cement quality in both of these wells coupled with the intermediate casing set just above the Hemlock formation will ensure that the shallow freshwater strata will be protected. 12) Water Analysis Water analyses of the produced water from RU #2, RU #SA, RU #6, and RU #7 are attached to this application. The following table summarizes the analyses that have been conducted on the produced water at Redoubt. Redoubt Unit Produced Water Analyses Sample Water Na K Ca Mg Ba Sr Fe CI HCO3 SO4 TDS TDS Well Date Point Cut (mgll) (mg/I) (mg/I) (mg/I) (mg/I) (mg/I) (my/I) (mg/I) (mg/I) (mg/1) Calc. Obs. RU #2 24-Mar-03 Separator 13% 2,590 87.2 712 5.85 3.42 16.3 - 5,100 300 52.6 9,730 RU #SA 19-Feb-03 Well Head 71% 2,817 78 1402 12 4 30.0 4 6,836 122 74 11,379 RU #SA 9-Aug-03 Wefl Head 79% 3,120 -- 1360 9.94 4.38 26.8 5.7 7,260 490 64.6 12,220 15,800 RU #6 MDT 28-Mar-03 MDT Tool 2,510 60.9 577 3.83 3.52 12.7 -- 4,700 583 48.2 8,187 8,250 RU #6 9-Aug-03 Well Head 62% 2,540 -- 616 6.39 3.57 13.4 10.6 4,860 560 46.8 8,363 10,100 RU #7 15-Apr-04 Well Head 95% 2,970 183 735 7.02 2.96 15.0 -- 5,520 605 75.7 9,854 11,100 Average: 2,758 102 900 7.51 3.64 19.0 6.8 5,713 443 60.3 9,656 11,060 Temp Resistivity • RU #5A 1.01 ' 7.02 75 ~RU #5A 1.0095 7.4 68 0.45 RU #6 MDT 8.09 68 RU #6 1.0064 7.2 68 0.67 RU #7 1.0063 6.6 68 0.55E • 4- 3-0.3; 4:50PM; ;907 5615301 * 2/ 3 ~~~~_ SGS Ref.# 1031591001 Client Name Forest Oil Corporation Project Nsmel# Redoubt Unit #2 Client Sample ID Redoubt Unit #7 Matrix Water (Surface, EfiF., Ground) All Dates/Times are Alaska Standard Time Printed Date/Time 04/03/2003 15.31 Collected Date/Time 03/24/2003 0:00 Received Date/Tlme 03/26/2003 8:30 Tecbnical Director St~eephe?n C~.~Ede~ Released ay ~ G ~ ~L~%-" Sample Remarks: EP 150.1 Sample was received after holding time had expired. SM2540 -Holding time expired 3-31-03. Samples set up an 3-3I-03. . Allowable Prep Analysis Parameter Results PQL Units Method Limits Date Date Init %Differcnce 039 % SM201030E 04!01/03 KAW Solids Total Suspended Solids 10.5 Routine Oilfield Water Analysis Alkalinity 300 • C03 Alkalinity 50.0 U HC03 Alkalinity 300 OH Alkalinity 50.0 U pH 7.25 Resistivity 0.625 Metals Dezpartmant Barium Calcium Iron Sodium Strontium Magnesium Metals by ICP/MS Potassium Waters D®parttaent Chloride Sulfate r 1.00 mg/L, EPA 160.2 03/28/03 KAP 50.0 mg/L SM20 2320B 03/28/03 KC 50,0 mg~L SM202320B 03/28/03 KC 50.0 mg/L SM20 2320B 03!28/03 KC 50.0 mg/L SM20 2320B 03/Z8/03 KC 0.100 pH units EPA 150.1 03/26/03 KC 0.0100 ohm-m SM19 2510A 03/26/03 KC 3.42 1.00 mg/L EPA 200.7 Dissolved 03/?A/03 04/0!/03 MTG 712 20.0 mg/L EPA 200.7 Dissolved 03/24/03 04/01/03 MTG 3.15 0.400 mg/L EPA 200.7 Dissolved 03/24/03 04/01/03 MTG 2590 200 mg/L EPA 200.7 Dissolved 03/24!03 04/01/03 MTG 16.3 1.00 mg/1. EPA 200.7 Dtssolved 03/24/03 04/01/03 MTG 5.85 2,p0 mg/L EPA 200.7 Dissolved 03/24/03 04/01/03 MTG 87200 500 ug/L EPA 200.8 Dissolved 03/24/03 03/31/03 KGF 5100 500 mg/L SM 17 45000L-B 03/26/03 KC 52.6 5.00 mg/L EPA 375.4 03/3!/03 1WD 4- 3-03; 4:SOPM; ;907 5615301 7f 3/ 3 • SGS Ref.# 103159I001 Client Name Forest Oil Corporation Project Name/# Redoubt Unit #2 Client Sample ID Redoubt Unit #7 Maw Water (Surface, Eff., Ground) All Dates~mes are Alaska Standard Time Printed Date/Tlme 04/03/2003 15:31 Collected Date~me 03/24/2003 0:00 Received Date/Time 03/26/2003 8:30 TecJ-nlcal Director Stephen C. Ede Allowable prep Analysis Parameter Results PQL Units Method Limits Date Date Init Waters bepartment Total Dissolved Solids 9730 100 mg/L SM20 254DC Oils Laboratory Density 1.0068 ASTM D-287 03/31/03 KC 44/01/03 JWD • uu-cc-us ua:acrx- rrcuxr~ie~ envircunx~n~ni am • ~ -- - -- SGS Ref./i 1035079001 Client Name Forest Oil Corporation ProjectName/# RU #SA/6 Client Sample ID RU #SA Matrix Water (Surface, Eff:, Ground) yui ~o~:rou~ n riau r.uL/ua r-oaa All DateslT'imes are Alaska Standard Time Printed DateYi'ime 08!22!2003 14:09 Collected Date/Time 08/09/2003 0:00 Received DatelTime 08113/2003 16:10 Technical Director Stephen jC_/E~de Released $y ~ ~ ~~iC~`-'" _.....~._ -~...T..-_ 150.1 -Sample was received after holding time had expired. Parameter Qualifiers Results PQL Units Difference 0.96 Routine oilfield Water Analysis Alkalinity 490 Chloride 7260 C03 Alkalinity 100 U HC03 Alkalinity ~ 490 OH Alkalinity 100 U pH ?.40 Resistivity 0.450 • Sulfate ~•b Metals Department Harium 4.38 Calcium 1360 Iron 0.400 U Sodium 3120 Strontium 26.8 Magnesium 9.94 Metals by ICP/MS :' j SMZO 1030E .. g 100 mg/1. !' SM20 2320E 20.0 mg/1. EPA 300.0 l 00 mg/L ~! SM20 2320B 100 rng/L SM20 23208 100 mg/L ! ~ SM20 23208 0.100 pH units; ~. EPA 150.1 0100 0 ohm-m ~ SM19 25IOA . 10.0 mg/L ~ ~ EPA 300.0 Allowable Analysis Container ID Limits Date Date !nit A 05/22/03 KAW A A A A A A A 0.100 mg/I. ~~ EP200.7 Dissolved A 2.00 - ~ mg/L. ~~ . EP200.7 Dissolved A 0.400 mg/L :l EP200.7 Dissolved A 200 ~; mg/L ;~N EP200.7 Dissolved A O.I00 mg/1. ~ 8P200.7 Dissolved A 2.00 mg/L ~ FJ'200.7 Dissolved A Potassium 20000D U 200000 ug/L ~ EP200.8 Dissolved A Waters Department Total Dissolved Solids 15800 800 mglL; SM20 2540C A 08/14/03 KC 08/21 /03 AB 08/14/03 KC 08/14/03 KC 08!14/03 KC 08/14/03 KC 08/14/03 KC 08/21/03 JJB 08/09/U3 08/18!03 HAG 08/09!03 08/18/03 BAG 08!09/03 08/18103 BAG 08/09/03 08/18/03 BAG 08/09/03 08/i8/03 BAG 08/09!03 08/[8/03 BAG 08/09/03 08/19/03 SCL 08/15/03 JS Oils Laboratory ;~: ~ ASTM D-28? A 08/14/03 GDti Density 1.0095 ;l. LAB-ZZ-03 04:43PM hKUM-(:Ibt tNVIKUNNkNIAI SKV • Roufiine ail Field Operator __ Well Number Field ___ County _ State Remarks and conclusions: • yur5st53ul +-rou P.ua/u5 F-645 - ~ --v r :~ ~. -naiysis Report pate '~ I: Chem- ~ b Ref. Number 1035079001 Approvr~ . sy Locatio~~ Sample; rom a~- ~ l ,; ;, ;t -- Cations ~ e -/L ' Sodium ................ 3334 145.03 Potassium .............. _ 61.8 1.58 Calcium ................ 1248 62.28 Magnesium ..... - - • - - • - . 11 0.90 Iron ................... 5.? 0.21 i Total Cations ............. 210.00 Total dissolved solids ...... 1222D mglL Spec~~ NaCI equivalent (chloride) ~ 12028 mg/L Observed pH ........... _ 7.4 G .... 4.49 mg/L Barium.....••-••••- Strontium .... • • • • - • • • - • • 27.30 mg/L Total Iron ............... 5.700 mg/L i Water Analysis Scale: Milfrgram equival~ ,~- is K nl !x ~a B' ao ~l } ° ~ f, ,fir Na ~t~~~ 1~ Ca~ iD~ ~.9Q Mg (x+~ ~~ Fe(x~~ Anions mQ/L Mea./L Sulfate ............ 64.6 1.34 Chooride.._........ 7260 204.73 Carbonate .......... ..... 0.00 Bicarbonate ........ 490 8.04 Hydroxide .. _ ....... 0 0.0 _ _ Total Anions ........ 214.112 tce @ 68° F.: ... _ , , ...... 0.45 ohm-meters ~ , , .. , ....... 0.58 ohm-meters per Unit v 8 ~a ~~ n/ /~ r; as I;X/ oo) C! ,4.0.5 tx+) soa ~,! (1ti)CO3 p.QD~ (Na value in above graphs includes Sium, Potassium and L1) ~: . NOTE: mg1L = MiAigrams per liter, Meq.ll.i: Milligram equivalent per liter. Soldium Chloride equivalent = by Dunlap & Hav~i~ome calculation from components. d. • U°-L L'UJ U4L4LYM fRVITI.IHC CI\VIRVIlMC1~IML JrtY • --_ _ _ SGS Ref.# 1035079002 Client Name Forest Oil Corporation Project Namei# RU #SA/b Client Sample ID RU #6 Matrix Water (Surface, Eff., Ground) J7UI:/OIJJUI ppa R. 1-1 :1U C. U3/UU f-U4~ All Dates~mes are Alaska Standard Time Printed Date/Time 08/22/2003 14:119 Collected Datell'ime 08109/2003 0:00 Received DatelTlme 08!1312003 16:10 Technltal Director 9tep6en C^.~E,de ~ Released Ay ~' ~~if/~~ Sample Remarks: '- ~ °. 150.1 -Sample was received after bolding time had expired. , ~ Parataeter Qualifirts Results PQL Difference 1.9 Routine Oilfield Water Analysis Alkalinity 860 Chloride 4860 C03 Alkalinity 100 U HC03 Alkalinity 560 OH Alkalinity 100 U p}l 7.20 Resistivity 0.670 • Sulfate 46.8 Metals Department Barium 3.57 Calcium 616 Iron 0.400 U Strontium 13.4 Magnesium 6.39 Metals by ICP/MS potassium 200000 U Sodium 2540000 Waters Department Total Dissolved Solids 10100 Oils Laboratory Density 1.0064 • I~ Units ; ~ Metbod "f~- g SM20 1030E Allowable prep Analysis Container ID Limits Date pie /nit A 08/22/03 KAW ! 00 mg/L ~: ~ SM20 2320E A 08/14/03 KC 10.0 mg/L ~ ~ EPA 300.0 A 08/21/03 JJB 100 tng/L ~ ~ SM20 2320E A 08/14/03 KC 100 mg/L ' SM20 2320E A 08/34!03 KC 100 mg/L ~ SM20 2320B A 08/14/03 KC 0.100 pH units;: : EPA 150.1 A 08/14/03 KC 0.0100 ohm-m ' SM1925IOA A 08//4/03 KC 10.0 mg/L ~:; , EPA 300.0 A 08/21/03 JJB 0.100 2.oa 0.400 0.100 2.00 200000 200000 800 ~; ,.. mg/L ~. EP200.7 Dissolved A mg/L ~ ; EP200.7 Dissolved A mg/L ; EP200.7 Dissolved A mg/L j': EP200.7 Dissolved A mg/L 1; EP200.7 Dissolved A ug/L i s EP200.8 Dissolved A ug/L ~ i EP200.8 Dissolved A . i ~` mglI:~ SM20 2540C A ~:y Jib 1 is . ASTM D-287 A ii ~: ~; i_ 08/09/03 08/18/03 BAG 08/09/03 08/18/03 BAG 08/09/03 08/18703 BAG 08!09/03 OS/IS/03 BAG 08/09/03 08/18/03 BAG USl09/03 08/19/03 SCL 08/D9/U3 08/19/D3 SCL 08/15/03 J`. 08/14/03 C3D' US-L'L-U3 U4:43NM hKUAR-l,l&t tflVIKUlY61tn1AL JKV 9Ul56153U1 t-!5U P.U5/05 F-645 ia~ ~6 i, e. ;:. ~. . ~; ~~ sis Re ort • Routine Oi! Field Water;: naly p ;: Operator Date ~~. Chem-L~.` Ref. Number 1035079002 Well Number _ Field ~ Approv ~- By County Locatiorja. State Sample rom r~ ~ ~: ~ ti I~ Remarks and conclusions: f ~~ - 3.~ ---"'T~r'~ _ Cat m4/L Meq./L ~ Anions m4/L Meq_/L 7, Sodium ................. 2545 110.71 ;; .Sulfate ............ 46.8 0.97 Potassium .............. 50.3 1.29 !_ :Chloride ........... 4861 137.08 - Ise. Calcium ................ 577 28.79 Carbonate ............... 0.00 Magnesium ............. 7.56 0.62 i° Bicarbonate . _ ...... 560 9.18 10.6 0.38 !~: Hydroxide ......... 0 0.0 tran ................... `t -.: Total Anions . _ ...... 147.238 Total Cations ............. 141.79 : ri t s° Total dissolved solids ...... 8363 mg/L Specifi ;Resistance @ 68° F.: NaCI equivalent (chloride} 8194 mglL ,served ............ 0.67 ohm-meters Observed pN ............ 7.2 ~Iculated ............ 0.84 ohm-meters • { Barium . ................ 3.72 mglL ~: :. Strontium .... - • - - - • • • - - - 13.50 mg/L :~. Tota{ Iron ............... 10.600 mg/L e Water Analysis Vattern Scale: Milligram equival` nts per Unit Jo ig i~ ~/ i7L io Y ~ y ~ U ~ b X ~o ~t i~ /6 /$.~ ~ ~~ Ca ~X/p~ ~b~ M9 (XI) Qi3$' Fe (X/~ o .918 !xr} soa ~q 7 } C03 add ~:. (Na value in above graphs includes .diem. Potassium and t_1} NOTE: mglL =Milligrams per fiter, Meq./h : Milligram equivalent per liter. Soldium Chloride equivalent = by Dunlap & Havhome calculation from components. I• ~N~ ~ iv~S ~ o vJ t~-az d co ~ 2.~~ :S Ref.# 1041806001 All Dates/Times are Alaska Standard Time lent Name Forest Oil Corporation Printed Date/Time 05/03/2004 11:08 ~oject Name/# Redoubt Unit #7 Collected Date/Time 04/15!2004 7:00 lent Sam le ID RU #7 P •~ Received Date/Time 04/1 6/2004 13.0 atrix Other Liquids Technical Director Stephen C. Ede Released By mple Remarks: EP I 50.1 -Sample was received after holding time had expired. EP 300.0 -Detectable amount of chloride in the method blank; concentration of chloride in the sample is I OX greater. 5/3/04 Revised report: Density - trrrroanded result is 1.0063 Allowable Prep Analysis ~ameter Results pQL Units Method Container ID Limits Date Date Imt Difference 1.2 % SM20 1030E A 0428/04 KAW ~utine Oilfield Water Analysis Alkalinity 605 50.0 mg/L SM20 2320B A 04!20/04 JMP Chloride 5520 25.0 mg/L EPA 300.0 A 04!20!04 JJB C03 Alkalinity 50.0 U 50.0 mg/L SM20 2320B A 0420/04 JMP ~ Alkalinity 605 50.0 mg/L SM20 2320B A 0420/04 JMP ~Ikalinity 50.0 U 50.0 mg/L SM20 2320E A 0420104 JMP pH 6.60 0.100 pH units EPA 150.1 A 04/19/04 KC Resistivity 0.556 0.0100 ohm-m SM192S10A A 04/19/04 KC Sulfate 75.7 1.00 mg/L EPA 300.0 A 0420104 JJB ~tals Department Barium 2.96 0.100 mgfL_ EP200.7Dissolved A 0422/04 0428/04 BAG Calcium 735 2.00 mg/L EP200.7 Dissolved A 0422/04 0428/04 BAG Iron ~ 0.0400 U 0.0400 mg/L EP200.7 Dissolved A 0422/04 0428/04 BAG Sodium 2970 200 mg/L EP200.7 Dissolved A 0422!04 04x28/04 BAG Strontium 15.0 0.100 mg/L EP200.7 Dissolved A 0422/04 0428/04 BAG Magnesium 7.02 2.00 mg(L EP200.7 Dissolved A 0422/04 0428104 BAG aal.s by ICP/IviS Potassium 183000 50000 ug/L EP200.8 Dissolved A 0422/04 0422/04 WAW .tars Department Total Dissolved Solids 11100 80,0 mg/L SM20 2540C A 04/19/04 KC r~ L J ~ i ~S Ref.# 1041806001 All DatesR'imes are Alaska Standard Time lent Name Forest Oil Corporation Printed Date/Time 05/032004 1 I :08 ~oject IYame/# Redoubt Unit #7 Collected Date/Time 04/152004 7:00 lent Sample ID RU #7 Received Date/Time 04/16/2004 13:30 atrix Other Liquids Technical Director .Stephen C. Ede Allowable Prep Analysis ratncter Results PQL Units Method Container ID Limits Datc Date lnit ~ls Laboratory Density l.al ASTM D-287 A 0421/04 BJA • L J • • 13) Freshwater Exemptions Currently Forest has an Aquifer Exemption Order (AEO 7) for RU D-1, which exempts injection below 3949' 1VID for aone-half mile radius around D-l. This AEO will need to be updated to include the proposed pilot project area (most likely expanded to encompass the Redoubt Unit Hemlock Participating Area). The Hemlock formation itself is not a freshwater strata, so the exemption should not be an issue. 14) Expected Incremental Increase in Ultimate Hydrocarbon Recovery The crude oil being produced at Redoubt Unit has an API gravity of 26.5 degrees, agar-oil-ratio (GOR) of 250 scf/STB, and a bubble point pressure of 1,490 psia. Initial reservoir pressure at Redoubt Unit was approximately 5,340 psia at a datum depth of 12,000' SSTVD. Recovery under primary depletion of this relatively dead oil, is estimated to be about 6% of the original oil-in-place (OOIP), from initial pressure down to the bubble point. The latest estimates for OOIP in Redoubt Unit are about 50 MMbbls of oil. Assuming a 6% recovery down to bubble point, the primary recovery is expected to be approximately 3.0 MMbbls. Other Hemlock reservoirs in the Cook Inlet which mature water floods have achieved recoveries of as much as 42% of the OOIP. Preliminary reservoir modeling shows that the Hemlock reservoir at Redoubt Unit maybe capable of 20+% recovery, given a sufficient injection pattern. The pilot project • of converting RU #6 to an injection well is being proposed to start gathering data on the responsiveness of the Hemlock formation at Redoubt, to water flood. 15) Well Status (Mechanical) There are two wells that have penetrated the Hemlock formation within 1/4 mile of the proposed injection well (RU #6). One of .these wells, RU #7, is currently producing from the Hemlock formation and the other well, Redoubt Shoal State 29690 #2, has been plugged and abandoned. The casing profile and cement program for RU #7 has been discussed previously in this application, so will not be addressed again. As for the Redoubt Shoal State 29690 #2, it was plugged and abandoned in September 1968. Records show that the abandonment of the well consisted of; 1) setting a 5" BP at 13,106' with 25 sacks of cement above, 2) setting a 7" BP at 11,525' with 25 sacks of cement above, 3) setting a 9-5/8" BP at 7,825' with 50 sacks of cement above, 4) setting a 9-5/8" BP at 2,037' with 50 sacks of cement above, and finally 5) setting a 80 sack cement plug at 180-400'. It is assumed that a surface plug was also set to abandon the well, but our records can not verify this. In a letter dated 7- 26-91, from Amoco Production Co. to AOGCC, Amoco made the same conclusion as to the status of this Redoubt Shoal well. • Forest Oil Corporation (~.~ 310 K Street, Suite 700 ~ .~:~~ Anchorage, Alaska 99501 ~ (907) 258-8600 Fax: (907) 258-8601 June 29, 2004 Jack Hartz State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7~' Avenue, Suite 100 Anchorage, AK 99501 Re: Follow up to the Application for Enhanced Recovery Pilot Project, Redoubt Unit Dear Jack, This letter is in regards to your email requesting additional information for Forest Oil Corporation's application for an Enhanced Recovery Pilot Project, at Redoubt Unit. 1. It would be helpful to add some comments about the confining layers above and below the Hemlock The bounding layers are important for containment of the injected water. • Directly above the Hemlock formation is a Tyonek section of dense siltstones, claystones and coals. This sequence is an impermeable barrier to upward flow of fluids and acts as a seal for the Hemlock oil reservoir. The siltstones and claystones have very low porosities and are non-permeable. The siltstones and claystone vary from 5 to 25 feet in thickness and the coals range between 2 and 10 feet in thickness. It has been an accepted practice to set our final casing string in this interval as we get good cement integrity and a good leak-off test. Directly below the Hemlock formation lies the West Foreland formation. The upper 300 feet of the West Foreland consists of interbedded siltstones, claystones and thin coals, with minor thin sandstones. This section is similar to the section above the Hemlock as it acts as an impermeable barrier to vertical flow of fluids. The siltstones and claystones have very low porosities and very low to no permeability. 2. Any information on mechanical properties of the confining layers such as fracture gradient or leak off test information to contrast with the Hemlock fracture gradient. Forest Oil Corporation (Forest) has no information that would suggest that the over-lying Tyonek intervals, nor the under-lying West Foreland intervals, have substantially different fracture gradients than the Hemlock formation at Redoubt. The Hemlock formation fracture gradient is not known at Redoubt Unit, but is suspected to be between 0.75 and 1.2 psi/ft (as demonstrated by other Cook Inlet Hemlock reservoirsl. r ~ ~.J • • 3. The Redoubt Unit Hemlock Participating Area application is not in our file. I think it probably was submitted to DOG. Attached to this letter is a copy of the Redoubt Unit Hemlock Participating Area application, which was filed with the Alaska Department of Natural Resources, Division of Oil and Gas (DO&G), on October 24, 2002. Pursuant to 20 AAC 25.537 (b) Forest hereby requests that information marked "Confidential" in its Redoubt Unit Hemlock Participating Area application submitted to the DO&G be kept confidential by the AOGCC. 4. A structural map showing any relevant faulting would be helpful. Attached to this letter are two current structure maps of the Hemlock formation at Redoubt Unit. The first map has only the Redoubt Unit wells drilled by Forcenergy/Forest, while the second map has ali wells drilled on the Redoubt Shoal structure. Pursuant to 20 AAC 25.537 (b) Forest would also request that the Redoubt Unit Hemlock structure maps marked "Confidential, be kept confidential by the AOGCC. If you or anyone else at AOGCC have any further questions regarding Forest's Enhanced Recovery application, please do not hesitate to contact me at 868-2131. Sincerely, Paul M. Winslow Reservoir Engineer Forest Oii Corporation • GLACIER December 5, 2019 Ms. Jessie Chmielowski Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 Subject: AIO 32.001 Monthly Reporting Dear Commissioner Chmielowski, DEC - 5 2019 AOGCC As required by Area Injection Order No. 32.001 issued by the AOGCC on December 28th 2017, the monthly report involving well pressures, injection rates and pressure bleeds for all annuli for the well RU -3A for the month of November 2019 is provided to the Commission for review. There were no bleeds conducted for this month Cook Inlet Energy is currently maintaining and operating well shut-in equipment linked to the RU -3A inner annular pressure as directed. The last test of the system was conducted on August 12, 2019. The next test will be conducted during the month of February 2020 The last mechanical integrity test of the well was conducted on December 23, 2017 in presence of an AOGCC inspector. The next MIT test will be performed before or during the month of December 2019 as required by the order. In addition to the above, CIE will be following all stipulations mentioned in the order I am available at your convenience to discuss this report or provide additional information. Please contact me at (907) 433-3822 or at dpascalAglacieroil.com t88 w. Northern Lights Blvd. Suite 510, Anchorage, AK 99503 (907) 334-6745 Main 1 (907) 334-6735 Fax Page I of 2 Sincerely, e Wee President, Operations Cool�Inlet Energy A Glacier Oil and Gas Wholly Owned Company Attachments 1. RU -3A Operations Log, November 2019 188 V\. Nm9hern Lights BIvd. Suite SIO. Anchorage. A K 99503 (9071 33@-6745 Slain 1 (907) 334-07.35 as Page 2 of 2 RU 3A Injection Tracking Report November 2019 Inner Annulus OuterAnnuius Date Wellhead Pressure (psi) Injected Volume (bbls) Avg. Pressure (psi Bleed Time (Hours: Min) Total Pressure Bled (psi) Total Volume Bled (bbl Avg. Pressure (psi) 11/1/19 4,340 3,100 553 0:00 0 0.0 30 11/2/19 4,488 3,580 548 0:00 0 0.0 30 11/3/19 4,494 3,280 540 0:00 0 0.0 30 11/4/19 4,468 3,048 516 0:00 0 0.0 30 11/5/19 4,441 3,013 508 0:00 0 0.0 30 11/6/19 4,425 2,928 524 0:00 0 0.0 30 11/7/19 4,481 1 3,121 516 0:00 0 0.0 30 11/8/19 4,497 3 214 498 0:00 0 0.0 30 11/9/19 4,498 3,190 496 0:00 0 0.0 30 11/10/19 4,496 3,171 493 0:00 0 0.0 30 11/11/19 4,484 3,105 483 0:00 0 0.0 30 11/12/19 4,479 3,128 480 0:00 0 0.0 30 11/13/19 4,481 3,129 477 0:00 0 0.0 30 11/14/19 4,481 3,143 472 0:00 0 0.0 30 11/15/19 4,492 3,203 466 0:00 0 0.0 30 11/16/19 4,487 3,181 461 0:00 0 0.0 30 11/17/19 4,487 3,190 457 0:00 0 0.0 30 11/18/19 4,494 3,206 452 0:00 0 0.0 30 11/19/19 4,497 3,254 442 0:00 0 0.0 30 11/20/19 4,494 3,229 439 0:00 0 0.0 30 11/21/19 4,494 1 3,242 439 0:00 0 0.0 30 11/22/19 4,498 3,256 438 0:00 0 0.0 30 11/23/19 4,497 3,240 433 0:00 0 0.0 30 11/24/19 4,500 3,239 427 0:00 0 0.0 30 11/25/19 4,500 3,242 419 0:00 0 0.0 30 11/26/19 4,494 3,202 411 0:00 0 0.0 30 11/27/19 4,481 3,158 400 0:00 0 1 0.0 30 11/28/19 4,489 3,212 393 0:00 0 0.0 30 11/29/19 4,497 3,247 364 0:00 0 0.0 30 11/30/19 4,499 3,233 398 0:00 0 0.0 30