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DIO 025
DISPOSAL INJECTION ORDER 25 Sterling Unit Gas Field Sterling Unit No. 43-9 Well 1. November 2002 2. January 2003 3. February 7, 2003 4. February 25, 2003 5. March 10, 2003 6. March 17, 2003 7. April 30, 2004 8. September 27, 2004 9. June 1, 2006 10. June 25, 2007 11. June 20, 2008 12. June 17, 2009 13. June 1, 2010 14. February 28, 2011 15. March 4, 2011 16. -------------------- 17. April 11, 2011 Marathon's request for DIO Marathon's revised request Notice of public hearing, affidavit of publication, and mailings Letter to Thor Cutler and copy of application for review Letter from Tim Hamlin responding to our letter Letter from AOGCC to EPA in response to their letter Marathon's documentation in support of 10-404 Proposals to amend underground injection orders to incorporate consistent language addressing the mechanical integrity of wells Marathon's annual report of disposal operations 1/1/06 — 6/l/06 Marathon's annual report of disposal operations 2006 Marathon's annual report of disposal operations 2007 Marathon's annual report of disposal operations 2008 Marathon's annual report of disposal operations 2009 Marathon's annual report of disposal operations 2010 Email re: Marathon's Disposal Report Hilcorp's annual reports Marathon's request to change Rule 3 (DIO 25-001) ORDERS · e STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF Marathon Oil Company for disposal of Class II oil field wastes by underground injection in the Sterling Formation in the Sterling Unit No. 43-9 Well, Section 9, T5N, RI0W, S.M. IT APPEARING THAT: ) Disposal Injection Order No. 25 ) ) Sterling Unit Gas Field ) Sterling Unit No. 43-9 Well ) ) ) April 3, 2003 1. By correspondence dated January 24, 2003 to the Alaska Oil and Gas Conservation Commission ("AOGCC"), Marathon Oil Company ("Marathon") requested authorization to allow the underground injection of non-hazardous Class II oil field waste fluids into the Sterling Formation within the Sterling Unit No. 43-9 ("SU 43- 9") well bore. The SU 43-9 well is located in the Sterling Gas Field, Kenai Peninsula Borough, Alaska. 2. Notice of opportunity for public hearing was published in the Anchorage Daily News on February 7,2003 in accordance with 20 AAC 25.540. 3. The Commission did not receive any protest or a request for a public hearing. FINDINGS: 1. Location of adjacent wells (20 AAC 25.252 (c)(1) There are three wells with surface locations within a one-quarter mile radius of the SU 43-9 well, the Sterling Unit 32-9 and 41-15 production wells and a Marathon operated water well. There are 1,026 water wells 10cated in the 36 square miles of T5N, RI0W Seward Meridian. The average depth of these wells is 91' measured depth ("MD"), the minimum depth is 6' MD and the maximum depth is 451' MD. Disposal Injection Order 2_ Sterling Unit 43-9 April 3, 2003 e Page 2 of? 2. Notification of Operators/Surface Owners (20 AAC 25.252 (c)(2) and 20 AAC 25.252 (c)(3)) Marathon is the operator of the Sterling Unit. There are no other operators within a one-quarter mile radius of the proposed disposal injection well. The sole surface owner within a one-quarter mile radius of the SU 43-9 well is the Salamatof Native Association, Inc. The Salamatof Native Association, Inc. was provided with a copy of Marathon's application for disposal injection in the SU 43-9 well prior to February 4, 2002. 3. Geologic information on disposal and confining zones/ Potential impact on an adjacent producing well. (20 AAC 25.252 (c)(4)) Marathon proposes to conduct disposal operations in the SU 43-9 well in the Sterling Formation B-4 Sandstone interval between 5,015' subsea and 5113' subsea, (5262' and 5360' MD). The disposal interval is a depleted gas sand in the Pliocene aged Sterling Formation. The proposed B-4 sandstone disposal interval in the SU 43-9 well has estimated porosities of up to 35%, permeabilities in excess of 200 millidarcies and a net vertical thickness of 100'. The lithologies of the Sterling Formation were deposited in fluvial environments and are composed primarily of very permeable and porous, very fine to coarse-grained sandstones and conglomerates interbedded with coals, shales, and siltstones. Approximately 50' of confining lithologies (shale and siltstone) directly overly the proposed disposal zone in SU 43-9. Of the 1,000' of the Sterling Formation in the SU 43-9 well overlying the proposed disposal interval, approximately 40 percent is composed of laterally continuousconfining lithologies. An adjacent well, the SU 32-9 well is currently producing from the B-4 sandstone. The horizontal separation between the two wells in the B-4 sand is 1,700'. Marathon used reservoir simulation to assess the potential recovery impacts of disposal injection in the B-4 sandstone through SU 43-9 on the SU 32-9 well. The model incorporated all current subsurface information on the B-4 sand including historic production and pressure data. An acceptable history match was obtained. Marathon modeled a daily average of 500 barrels per day of disposal injection through the year 2016. Results indicate that water injected into the existing perforations in SU 43-9 falls rapidly through the reservoir and causes the overall gas-water contact to rise uniformly, rather than creating a piston-like waterflood displacement moving toward producer SU 32-9. The simulation indicates the proposed SU 43-9 disposal injection project will not have an appreciable impact on gas recovery from the Sterling Formation B-4 Sandstone. 4. SU 43-9 Logs (20 AAC 25.252 (c)(5)) The 10gs of the SU 43-9 well are on file at the AOGCC. Disposal Injection Order 2_ Sterling Unit 43-9 April 3, 2003 e Page 3 of? 5. Demonstration of Mechanical Integrity and Disposal Zone Isolation (20 AAC 25.252 (c)(6)) No cement quality log is available for SU 43-9. An injectivity test was conducted on the B-4 interval in 43-9 on February 25, 2000. The test employed a suite of logs designed to detect any significant out of zone leakage. These tools included; a borax activation log, an oxygen activation log, a temperature, and a pressure log. The test was conducted at 3.2 barrels per minute (over 4,000 barrels per day) a rate that exceeds anticipated disposal injection rates. The results of this test demonstrate the B-4 completion in SU 43-9 is appropriately isolated. The SU 43-9 well met the mechanical integrity requirements of 20 AAC 25.412 during a test witnessed by an AOGCC inspector on October 23,2002. Marathon has proposed a pressure testing procedure for SU 43-9 that will satisfy the mechanical integrity requirements of20 AAC 25.412. This procedure will be used for mechanical integrity testing after authorization is given for disposal injection. The test of October 23,2002 is sufficient to allow Marathon begin disposal service. 6. Casing Description Well SU 43-9 (20 AAC 25.252 (c)(6)(A)) There are two strings of casing as follows: . Surface Casing; 8 5/8", 24 pound per foot, J-55 casing, Shoe Depth; 1272', Cemented with 450 sacks, plus a 100 sack top job. · Production Casing; 5 W', 17 pound per foot, LTC casing, Shoe Depth; 5380', J-55 from 0-3755', N-80 from 3755-5380, Cemented with 550 sacks. 7. Disposal Fluid Type. Source. Volume and Compatibility with Disposal Zone (20 AAC 25.252 (c)(7») The primary disposal fluid planned for this well is produced water from the Sterling Unit. Additionally, Class II fluids "from other Marathon operated properties on the Kenai Peninsula will be injected. Typical Class II wastes planned for this disposal project are drilling, completion, workover and produced fluids, glycol dehydration wastes, rig wash, drilling mud slurries, tank bottoms, NORM scale, precipitation within containment areas, and other approved Class II wastes generated "from drilling, completion, workover, and production operations. Current projections estimate that a maximum of 1,000 barrels per day of fluid will be injected with daily average volume of less than 500 barrels. Compatibility of the proposed disposal fluids with the formation waters of this depleted portion of a gas reservoir is not likely to affect the storage capacity of the B-4 sandstone adjacent to well SU 43-9. Disposal Injection Order 2_ Sterling Unit 43-9 April 3, 2003 tit Page 4 of? 8. Estimated Injection Pressure (20 AAC 25.252 (c)(8)) The estimated average injection pressure will be 1,800 psig and the maximum injection pressure will be 3,000 psig. 9. Evaluation of Confining Zones (20 AAC 25.252 (c)(9)) A correlative interval in well SU 32-9 was evaluated to determine the fracture potential of the B-4 Sandstone in SU 43-9. Marathon drilled SU 32-9 in 1998 and obtained a modem petrophysical log suite. The B-4 interval lithology is similar in these wells that are approximately 1700' apart. The SU 32-9 data was used to estimate lithologic parameters such as Poisson's Ratio, Young's Modulus and closure stress used for fracture analysis. The lithologic parameters were adjusted to SU 43-9 thickness and depths. A commercial fracture model was used to evaluate the fracture potential of two operational scenarios representative of SU 43-9 disposal. The first simulation was assumed constant injection of 1,440 barrels per day of 4% KCL water with .10 pounds per gallon ("ppg") 1 OO-mesh solid load for one year. The inclusion of a small solid 10ad represents a realistic estimate for produced water disposal where small amounts of solids tend to plug permeable layers and cause fracture growth. The second simulation represented conditions observed during disposal of drilling mud and cuttings at Marathon's Kenai Gas Field. The simulation assumed 1,440 barrels per day of 4% KCL with 5.50 ppg 100-mesh solids load for two weeks. A 100-mesh solid load is a worst-case scenario where fine solids plug the formation and make fractures more likely to propagate. The simulation replicated conditions at the Marathon Kenai Field disposal operation where slurry injection is generally conducted in batches during periods when drilling is active. Batches of solids are injected over limited periods to allow fluids to leak off and fractures to heal. In both cases fractures were confined by the shale interval at the top of the B-4 Sandstone. 10. Standard Laboratory Water Analysis of the Disposal Zone (20 AAC 25.252 (c)(lO)) A 1995 laboratory water analysis of B-4 Sandstone formation water from well SU 43- 9 yielded 1,931 parts per million ("ppm") TDS and 1,615 ppm NaCl equivalent. 11. Freshwater Exemption (20 AAC 25.252 (c)(II)) Aquifer Exemption Order No.9, dated [huh? it hasn't been issued yet - need to fill in the correct date] exempts aquifers below 1750' MD and within Y4 mile of well SU 43- 9. Disposal Injection Order 2_ Sterling Unit 43-9 April 3, 2003 12. Mechanical Condition of Wells Penetrating the Disposal Zone within ~ Mile of SU 43-9 (20 AAC 25.252 (c)(12) e Page 5 of? There are three wells with surface locations within a one-quarter mile radius of the SU 43-9 well, the Sterling Unit 32-9 and 41-15 production wells and a Marathon operated water well. The Marathon operated water well does not penetrate the B-4 Sandstone. Wells SU 32-9 and 41-15 are directionally drilled and do not penetrate the B-4 sandstone within ~ mile of the SU 43-9 well. CONCLUSIONS: 1. The application requirements of20 AAC 25.252(c) have been met. 2. No wells penetrate the disposal zone within ~ mile ofthe SU 43-9 well. 3. Aquifer Exemption Order No. 9 exempts aquifers below 1750' MD and within ~ mile of well SU 43~9. 4. Waste fluids will be contained within appropriate receiving intervals by the confining lithologies in the Sterling Formation, cement isolation of the well bore and operating conditions. 5. Disposal injection operations in the SU 43-9 well will be conducted at rates and pressures below those estimated to fracture the confining zone. 6. Evaluation of surveillance and operational performance data will reasonably assure there is no fracturing of the confining zone. 7. Surveillance of disposal volumes, daily monitoring of operational parameters, and demonstration of mechanical integrity will reasonably ensure continued mechanical integrity of the well and that waste fluids are contained within the disposal interval. 8. Disposal injection of Class II wastes into well SU 43-9 will not cause waste, jeopardize correlative rights, or impair ultimate recovery. NOW, THEREFORE, IT IS ORDERED THAT: RULE 1: Authorized Iniection Strata for Disposal Injection of authorized fluids for purposes of underground disposal of oil field wastes is permitted into the Sterling Formation between 5260' and 5360' MD in the SU 43-9 well, in the Sterling Unit. Disposal Injection Order 2_ Sterling Unit 43-9 April 3, 2003 e Page 6 of7 Other disposal zones in the SU 43-9 may be approved for disposal following a demonstration that the requirements of 20 AAC 25.252(c) and Aquifer Exemption Order No. 9 have been satisfied. The Commission may suspend, revoke, or modify this authorization if injected fluids fail to be confined within the designated injection strata. RULE 2: Authorized Fluids Fluids authorized for injection in the SU 43-9 well are: 1. produced water 2. drilling, completion and workover fluids 3. drilling mud 4. Norm scale 5. tank bottoms 6. rig wash 7. glycol dehydration wastes 8. precipitation accumulating within contaimnent areas 9. Other fluids suitable for disposal in a Class II well and approved by the commission on a case-by-case basis. RULE 3: Demonstration of Tubinp/Casine: Annulus Mechanical Inte2rity Within 180 days of initiating disposal service, the Commission must be contacted to allow a representative of the Commission to witness an additional mechanical integrity test in SU 43-9. In addition to the requirements of 20 AAC 25.252 (d), mechanical integrity of the disposal well must be demonstrated at least once every two years. RULE 4 Well Intee:ritv Failure Whenever disposal rates and/or operating pressure observations or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, or a lack of disposal zone isolation, the operator must immediately notify the Commission, obtain Commission approval to continue injection and submit a plan for corrective action for Commission approval. RULE 5: Surveillance Operating parameters including disposal rate, disposal pressure, annulus pressures, step rate test results and volume of fluids and solids pumped must be monitored and reported according to requirements of 20 AAC 25.432(1). The operator shall obtain a baseline temperature 10g and a baseline step rate test prior to initial injection. An initial report of operations must be provided after one month of injection. An annual report for the calendar year evaluating the performance of the disposal operation must be submitted by July 1 of each year. Disposal Injection Order 2. Sterling Unit 43-9 April 3, 2003 e Page 7 of7 RULE 6: Notification of Improper Class II Iniection The operator must immediately notify the Commission if it learns of any improper Class II injection. Additionally, notification requirements of any other State or Federal agency remain the operators' responsibility. RULE 7: Administrative Action Unless notice and public hearing is otherwise required, the Commission may administratively waive the requirements of any rule stated above or administratively amend any rule as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. RULE 8: Other Conditions Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless specifically superseded by Commission order. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order may result in the revocation or suspension of this authorization. DONE at Anchorage, Alaska and dated April 3, 2003. <=- ~ sañiIïPãlìn:£hàlr Alaska Oil and Gas Conservation Commission ~ Daniel T. Seamount, Jr., Commissioner Alaska Oil and Gas Conservation Commission ~~ ~þ~ Randy Ruedrich, Commissioner Alaska Oil and Gas Conservation Commission AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the IO-day period. An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30-day period for appeal to Superior Court runs from the date on which the request is deemed denied 10th day after the application for rehearing was filed). \iJ' "/',.'( " \ \j V\ J~ Daniel Donkel 2121 North Bayshore Drive, Ste 1219 Miami, FL 33137 Jim Yancey Seal- Tite Intemational 500 Deer Cross Drive Madisonville, LA 70447 Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 Paul Walker Chevron 1301 McKinney, Rm 1750 Houston, TX 77010 David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 T.E. Alford ExxonMobilExploration Company PO Box 4778 Houston, TX 77210-4778 Chevron USA Alaska Division PO Box 1635 Houston, TX 77251 Shelia McNulty Financial Times PO Box 25089 Houston, TX 77265-5089 James White Intrepid Prod. Co.lAlaskan Crude 4614 Bohill SanAntonio, TX 78217 e SD Dept of Env & Natural Resources Oil and Gas Program 2050 West Main, Ste 1 Rapid City, SD 57702 Christine Hansen Interstate Oil & Gas Compact Comm Excutive Director PO Box 53127 Oklahoma City, OK 73152 Gregg Nady Shell E&P Company Onshore Exploration & Development PO Box 576 Houston, TX 77001-0576 G. Scott Pfoff Aurora Gas, LLC 10333 Richmond Ave, Ste 710 Houston, TX 77042 William Holton, Jr. Marathon 011 Company Law Department 5555 San Fecipe St. Houston, TX 77056-2799 Texico Exploration & Production PO Box 36366 Houston, TX 77236 Donna Williams Wor/dOIl Statistics Editor PO Box 2608 Houston, TX 77252 Shawn Suther/and Unocal Revenue Accounting 14141 Southwest Freeway Sugar Land, TX 77478 Doug Schultze XTO Energy Inc. 3000 North Garfield, Ste 175 Midland, TX 79705 e John Katz State of Alaska Alaska Govemor's Office 444 North Capitol St., NW, Ste 336 Washington, DC 20001 Alfred James 200 West Douglas, Ste 525 Wichita, KS 67202 Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Michael Nelson Purvin Gertz, Inc. Library 600 Travis, Ste 2150 Houston, TX 77002 G. Havran Gaffney, Cline & Associations Library 1360 Post Oak Blvd., Ste 2500 Houston, TX 77056 W. Allen Huckabay ConocoPhillips Petroleum Company Offshore West Africa Exploration 600 North Dairy Ashford Houston, TX 77079-1175 Corry Woolington ChevronT exaco Land-Alaska PO Box 36366 Houston, TX 77236 Chevron Chemical Company Library PO Box 2100 Houston, TX 77252-9987 Kelly Valadez Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 e e George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 John Levorsen 200 North 3rd Street, #1202 Boise,lD 83702 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 John F. Bergquist Babson and Sheppard PO Box 8279 Long Beach, CA 90808-0279 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Thor Cutler OW-137 US EPA egion 10 1200 Sixth Ave. Seattle, WA 98101 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 SeaWe, WA 98119-3960 Cammy Taylor Richard Mount Julie Houle 1333 West 11th Ave. State of Alaska State of Alaskan DNR Anchorage, AK 99501 Department of Revenue Div of Oil & Gas, Resource Eval. 500 West 7th Ave., Ste 500 550 West 7th Ave., Ste 800 Anchorage, AK 99501 Anchorage, AK 99501 Duane Vaagen Jim Arlington Susan Hill Fairweather Forest Oil State of Alaska, ADEC 715 L Street, Ste 7 310 K Street, Ste 700 EH Anchorage, AK 99501 Anchorage, AK 99501 555 Cordova Street Anchorage, AK 99501 Tim Ryherd William VanDyke Robert Mintz State of Alaska State of Alaska State of Alaska Department of Natural Resources Department of Natural Resources Department of Law 550 West 7th Ave., Ste 800 550 West 7th Ave., Ste 800 1031 West 4th Ave., Ste 200 Anchorage, AK 99501 Anchorage, AK 99501 Anchorage, AK 99501 Ed Jones Trustees for Alaska Mark Wedman Aurora Gas, LLC 1026 West 4th Ave., Ste 201 Halliburton Vice President Anchorage, AK 99501-1980 6900 Arctic Blvd. 1029 West 3rd Ave., Ste 220 Anchorage, AK 99502 Anchorage, AK 99501 Mark Dalton Jack Laasch Rob Crotty HDR Alaska Natchiq C/O CH2M HILL 2525 C Street, Ste 305 Vice President Government Affairs 301 West Nothern Lights Blvd Anchorage, AK 99503 3900 C Street, Ste 701 Anchorage, AK 99503 Anchorage, AK 99503 Mark Hanley John Harris Ciri Anadarko NI Energy Development Land Department 3201 C Street, Ste 603 Tubular PO Box 93330 Anchorage, AK 99503 3301 C Street, Ste 208 Anchorage, AK 99503 Anchorage, AK 99503 Schlumberger Baker Oil Tools Judy Brady Drilling and Measurements 4730 Business Park Blvd., #44 Alaska Oil & Gas Associates 3940 Arctic Blvd., Ste 300 Anchorage, AK 99503 121 West Fireweed Lane, Ste 207 Anchorage, AK 99503 Anchorage, AK 99503-2035 Arlen Ehm 2420 Foxhall Dr. Anchorage, AK 99504-3342 Rose Ragsdale Rose Ragsdale & Associates 3320 E. 41st Ave Anchorage, AK 99508 Jim Scherr US Minerals Management Service Resource Evaluation 949 East 36th Ave., Ste 308 Anchorage, AK 99508 Chuck O'Donnell Veco Alaska,lnc. 949 East 36th Ave., Ste 500 Anchorage, AK 99508 Barbara Fullmer ConocoPhillips Alaska, Inc. Legal Department A TO 2084 PO Box 100360 Anchorage, AK 99510-0360 Jordan Jacobsen Alyeska Pipeline Service Company Law Department 1835 So. Bragaw Anchorage, AK 99515 Jeanne Dickey BP Exploration (Alaska), Inc. Legal Department PO Box 196612 Anchorage, AK 99518 Bill Bocast PACE Local 8-369 c/o BPX North Slope, Mailstop P-8 PO Box 196612 Anchorage, AK 99519 Sue Miller BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, AK 99519-6612 Bob Shavelson Cook Inlet Keeper PO Box 3269 Homer, AK 99603 e Greg Noble Bureau of Land Management Energy and Minerals 6881 Abbott Loop Rd Anchorage, AK 99507 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Paul L. Craig Trading Bay Energy Corp 5432 East Northern Lights, Ste 610 Anchorage, AK 99508 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 Kristen Nelson IHS Energy PO Box 102278 Anchorage, AK 99510-2278 Robert Britch, PE Northern Consulting Group 2454 Telequana Dr. Anchorage, AK 99517 Jack Hakkila PO Box 190083 Anchorage, AK 99519 J. Brock Riddle Marathon Oil Company Land Department PO Box 196168 Anchorage, AK 99519-6168 BP Exploration (Alaska), Inc. Land Manager PO Box 196612 Anchorage, AK 99519-6612 Peter McKay 55441 Chinook Rd Kenai, AK 99611 e Jeff Walker US Minerals Management Service Regional Supervisor 949 East 36th Ave., Ste 308 Anchorage, AK 99508 Richard Prentki US Minerals Management Service 949 East 36th Ave., 3rd Floor Anchorage, AK 99508 Thomas R. Marshall, Jr. 1569 Birchwood Street Anchorage, AK 99508 Jim Ruud ConocoPhillips Alaska, Inc. Land Department PO Box 100360 Anchorage, AK 99510 Perry Markley Alyeska Pipeline Service Company Oil Movements Department 1835 So. Bragaw - MS 575 Anchorage, AK 99515 David Cusato 600 West 76th Ave., #508 Anchorage, AK 99518 Tesoro Alaska Company PO Box 196272 Anchorage, AK 99519 Kevin Tabler Unocal PO Box 196247 Anchorage, AK 99519-6247 Dudley Platt DA Platt & Associates 9852 Little Diomede Cr. Eagle River, AK 99577 Shannon Donnelly Phillips Alaska, Inc. HEST -Enviromental PO Box 66 Kenai, AK 99611 Kenai Peninsula Borough Economic Development Distr 14896 Kenai Spur Hwy #103A Kenai, AK 99611-7000 James Gibbs PO Box 1597 Soldotna, AK 99669 John Tanigawa Evergreen Well Service Company PO Box 871845 Wasilla, AK 99687 Cliff Burglin PO Box 131 Fairbanks, AK 99707 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 Lt Governor LOren Leman State of Alaska PO Box 110015 Juneau, AK 99811-0015 e Penny Vadla Box 467 Ninilchik, AK 99639 Claire Caldes US Fish & Wildlife Service Kenai Refuge PO Box 2139 Soldotna, AK 99669 Chartes Boddy Usibelli Coal Mine, Inc. 100 Cushman Street, Suite 210 Fairbanks, AK 99701-4659 Harry Bader State of Alaska Department of Natural Resources 3700 Airport Way Fairbanks, AK 99709 North Slope Borough PO Box 69 Barrow, AK 99723 e Marc Kovac PACE 8-369, Prudhoe Bay Vice-Chair PO Box 2973 Seward, AK 99664 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Bernie Kart K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 Kurt Olson State of Alaska Staff to Senator Tom Wagoner State Capitol Rm 427 Juneau, AK 99801 '. . STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF Marathon Oil Company for disposal of Class II oil field wastes by underground injection in the Sterling Formation in the Sterling Unit No. 43-9 Well, Section 9, T5N, R10W, S.M. IT APPEARING THAT: ) Disposal Injection Order No. 25 ) ) Sterling Unit Gas Field ) Sterling Unit No. 43-9 Well ) Originally issued ) April 3, 2003, and ) Corrected June 15,2004 1. By correspondence dated January 24, 2003 to the Alaska Oil and Gas Conservation Commission ("AOGCC"), Marathon Oil Company ("Marathon") requested authorization to allow the underground injection of non-hazardous Class II oil field waste fluids into the Sterling Formation within the Sterling Unit No. 43-9 ("SU 43- 9") well bore. The SU 43-9 well is located in the Sterling Gas Field, Kenai Peninsula Borough, Alaska. 2. Notice of opportunity for public hearing was published in the Anchorage Daily News on February 7,2003 in accordance with 20 AAC 25.540. 3. The Commission did not receive any protest or a request for a public hearing. 4. The original Disposal Injection Order No. 25 contained an omission. Finding No. 11 of the original order omitted the date that Aquifer Exemption No. 9 was issued and this corrected order is issued to clarify the omission. FINDINGS: 1. Location of adjacent wells (20 AAC 25.252 (c)(1) There are three wells with surface locations within a one-quarter mile radius of the SU 43-9 well, the Sterling Unit 32-9 and 41-15 production wells and a Marathon operated water well. There are 1,026 water wells located in the 36 square miles of Disposal Injection order. Sterling Unit 43-9 June 15,2004 . Page 2 of7 T5N, RlOW Seward Meridian. The average depth of these wells is 91' measured depth ("MD"), the minimum depth is 6' MD and the maximum depth is 451' MD. 2. Notification of Operators/Surface Owners (20 AAC 25.252 (c)(2) and 20 AAC 25.252 (c)(3)) Marathon is the operator of the Sterling Unit. There are no other operators within a one-quarter mile radius of the proposed disposal injection well. The sole surface owner within a one-quarter mile radius of the SU 43-9 well is the SalamatofNative Association, Inc. The Salamatof Native Association, Inc. was provided with a copy of Marathon's application for disposal injection in the SU 43-9 well prior to February 4, 2002. 3. Geologic information on disposal and confining zones/ Potential impact on an adjacent producing well. (20 AAC 25.252 (c)(4)) Marathon proposes to conduct disposal operations in the SU 43-9 well in the Sterling Formation B-4 Sandstone interval between 5,015' subsea and 5113' subsea, (5262' and 5360' MD). The disposal interval is a depleted gas sand in the Pliocene aged Sterling Formation. The proposed B-4 sandstone disposal interval in the SU 43-9 well has estimated porosities of up to 35%, permeabilities in excess of 200 millidarcies and a net vertical thickness of 100'. The lithologies of the Sterling Formation were deposited in fluvial environments and are composed primarily of very permeable and porous, very fine to coarse-grained sandstones and conglomerates interbedded with coals, shales, and siltstones. Approximately 50' of confining lithologies (shale and siltstone) directly overly the proposed disposal zone in SU 43-9. Of the 1,000' of the Sterling Formation in the SU 43-9 well overlying the proposed disposal interval, approximately 40 percent is composed of laterally continuousconfining lithologies. An adjacent well, the SU 32-9 well is currently producing from the B-4 sandstone. The horizontal separation between the two wells in the B-4 sand is 1,700'. Marathon used reservoir simulation to assess the potential recovery impacts of disposal injection in the B-4 sandstone through SU 43-9 on the SU 32-9 well. The model incorporated all current subsurface information on the B-4 sand including historic production and pressure data. An acceptable history match was obtained. Marathon modeled a daily average of 500 barrels per day of disposal injection through the year 2016. Results indicate that water injected into the existing perforations in SU 43-9 falls rapidly through the reservoir and causes the overall gas-water contact to rise uniformly, rather than creating a piston-like waterflood displacement moving toward producer SU 32-9. The simulation indicates the proposed SU 43-9 disposal injection project will not have an appreciable impact on gas recovery from the Sterling Formation B-4 Sandstone. 4. SU 43-9 Logs (20 AAC 25.252 (c)(5)) The logs of the SU 43-9 well are on file at the AOGCC. Disposal Injection Order. Sterling Unit 43-9 June 15,2004 . Page 3 of7 5. Demonstration of Mechanical Integrity and Disposal Zone Isolation (20 AAC 25.252 (c)(6)) No cement quality log is available for SU 43-9. An injectivity test was conducted on the B-4 interval in 43-9 on February 25, 2000. The test employed a suite of logs designed to detect any significant out of zone leakage. These tools included; a borax activation log, an oxygen activation log, a temperature, and a pressure log. The test was conducted at 3.2 barrels per minute (over 4,000 barrels per day) a rate that exceeds anticipated disposal injection rates. The results of this test demonstrate the B-4 completion in SU 43-9 is appropriately isolated. The SU 43-9 well met the mechanical integrity requirements of 20 AAC 25.412 during a test witnessed by an AOGCC inspector on October 23,2002. Marathon has proposed a pressure testing procedure for SU 43-9 that will satisfy the mechanical integrity requirements of20 AAC 25.412. This procedure will be used for mechanical integrity testing after authorization is given for disposal injection. The test of October 23,2002 is sufficient to allow Marathon begin disposal service. 6. Casing Description Well SU 43-9 (20 AAC 25.252 (c)(6)(A)) There are two strings of casing as follows: · Surface Casing; 8 5/8", 24 pound per foot, J-55 casing, Shoe Depth; 1272', Cemented with 450 sacks, plus a 100 sack top job. · Production Casing; 5 W', 17 pound per foot, LTC casing, Shoe Depth; 5380', J-55 from 0-3755', N-80 from 3755-5380, Cemented with 550 sacks. 7. Disposal Fluid Type. Source. Volume and Compatibility with Disposal Zone (20 AAC 25.252 (c)(7)) The primary disposal fluid planned for this well is produced water from the Sterling Unit. Additionally, Class II fluids from other Marathon operated properties on the Kenai Peninsula will be injected. Typical Class II wastes planned for this disposal project are drilling, completion, workover and produced fluids, glycol dehydration wastes, rig wash, drilling mud slurries, tank bottoms, NORM scale, precipitation within containment areas, and other approved Class II wastes generated from drilling, completion, workover, and production operations. Current projections estimate that a maximum of 1,000 barrels per day of fluid will be injected with daily average volume of less than 500 barrels. Compatibility of the proposed disposal fluids with the formation waters of this depleted portion of a gas reservoir is not likely to affect the storage capacity of the B-4 sandstone adjacent to well SU 43-9. Disposal Injection order. Sterling Unit 43-9 June 15,2004 . Page 4 of7 8. Estimated Injection Pressure (20 AAC 25.252 (c)(8)) The estimated average injection pressure will be 1,800 psig and the maxlmum injection pressure will be 3,000 psig. 9. Evaluation of Confining Zones (20 AAC 25.252 (c)(9)) A correlative interval in well SU 32-9 was evaluated to determine the fracture potential of the B-4 Sandstone in SU 43-9. Marathon drilled SU 32-9 in 1998 and obtained a modem petrophysical log suite. The B-4 interval lithology is similar in these wells that are approximately 1700' apart. The SU 32-9 data was used to estimate lithologic parameters such as Poisson's Ratio, Young's Modulus and closure stress used for fracture analysis. The lithologic parameters were adjusted to SU 43-9 thickness and depths. A commercial fracture model was used to evaluate the fracture potential of two operational scenarios representative of SU 43-9 disposal. The first simulation was assumed constant injection of 1,440 barrels per day of 4% KCL water with .10 pounds per gallon ("ppg") 1 OO-mesh solid load for one year. The inclusion of a small solid load represents a realistic estimate for produced water disposal where small amounts of solids tend to plug permeable layers and cause fracture growth. The second simulation represented conditions observed during disposal of drilling mud and cuttings at Marathon's Kenai Gas Field. The simulation assumed 1,440 barrels per day of 4% KCL with 5.50 ppg 100-mesh solids load for two weeks. A 100-mesh solid load is a worst-case scenario where fine solids plug the formation and make fractures more likely to propagate. The simulation replicated conditions at the Marathon Kenai Field disposal operation where slurry injection is generally conducted in batches during periods when drilling is active. Batches of solids are injected over limited periods to allow fluids to leak off and fractures to heal. In both cases fractures were confined by the shale interval at the top of the B-4 Sandstone. 10. Standard Laboratory Water Analysis of the Disposal Zone (20 AAC 25.252 (c)(lO») A 1995 laboratory water analysis of B-4 Sandstone formation water from well SU 43- 9 yielded 1,931 parts per million ("ppm") TDS and 1,615 ppm NaCl equivalent. 11. Freshwater Exemption (20 AAC 25.252 (c )(11) Aquifer Exemption Order No.9, dated April 3, 2003 exempts aquifers below 1750' MD and within ~ mile of well SU 43-9. Disposal Injection order. Sterling Unit 43-9 June 15,2004 . Page 5 of7 12. Mechanical Condition of Wells Penetrating the Disposal Zone within y.¡ Mile of SU 43-9 (20 AAC 25.252 (c)(12) There are three wells with surface 10cations within a one-quarter mile radius of the SU 43-9 well, the Sterling Unit 32-9 and 41-15 production wells and a Marathon operated water well. The Marathon operated water well does not penetrate the B-4 Sandstone. Wells SU 32-9 and 41-15 are directionally drilled and do not penetrate the B-4 sandstone within y.¡ mile of the SU 43-9 well. CONCLUSIONS: 1. The application requirements of20 AAC 25.252(c) have been met. 2. No wells penetrate the disposal zone within y.¡ mile of the SU 43·9 well. 3. Aquifer Exemption Order No.9 exempts aquifers below 1750' MD and within y.¡ mile of well SU 43-9. 4. Waste fluids will be contained within appropriate receiving intervals by the confining lithologies in the Sterling Formation, cement isolation of the well bore and operating conditions. 5. Disposal injection operations in the SU 43-9 well will be conducted at rates and pressures below those estimated to fracture the confining zone. 6. Evaluation of surveillance and operational performance data will reasonably assure there is no fracturing of the confining zone. 7. Surveillance of disposal volumes, daily monitoring of operational parameters, and demonstration of mechanical integrity will reasonably ensure continued mechanical integrity of the well and that waste fluids are contained within the disposal interval. 8. Disposal injection of Class II wastes into well SU 43-9 will not cause waste, jeopardize correlative rights, or impair ultimate recovery. NOW, THEREFORE, IT IS ORDERED THAT: RULE 1: Authorized Iniection Strata for Disposal Injection of authorized fluids for purposes of underground disposal of oil field wastes is permitted into the Sterling Formation between 5260' and 5360' MD in the SU 43-9 well, in the Sterling Unit. Disposal Injection order. Sterling Unit 43-9 June 15,2004 . Page 6 of7 Other disposal zones in the SU 43-9 may be approved for disposal following a demonstration that the requirements of 20 AAC 25.252(c) and Aquifer Exemption Order No. 9 have been satisfied. The Commission may suspend, revoke, or modify this authorization if injected fluids fail to be confined within the designated injection strata. RULE 2: Authorized Fluids Fluids authorized for injection in the SU 43-9 well are: 1. produced water 2. drilling, completion and workover fluids 3. drilling mud 4. Norm scale 5. tank bottoms 6. rig wash 7. glycol dehydration wastes 8. precipitation accumulating within containment areas 9. Other fluids suitable for disposal in a Class II well and approved by the commission on a case-by-case basis. RULE 3: Demonstration of Tubine/CasiBl~ Annulus Mechanical Inteeritv Within 180 days of initiating disposal service, the Commission must be contacted to allow a representative of the Commission to witness an additional mechanical integrity test in SU 43-9. In addition to the requirements of 20 AAC 25.252 (d), mechanical integrity of the disposal well must be demonstrated at least once every two years. RULE 4 Well Inte2:ritv Failure Whenever disposal rates and/or operating pressure observations or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, or a lack of disposal zone isolation, the operator must immediately notify the Commission, obtain Commission approval to continue injection and submit a plan for corrective action for Commission approval. RULE 5: Surveillance Operating parameters including disposal rate, disposal pressure, annulus pressures, step rate test results and volume of fluids and solids pumped must be monitored and reported according to requirements of 20 AAC 25.432(1). The operator shall obtain a baseline temperature log and a baseline step rate test prior to initial injection. An initial report of operations must be provided after one month of injection. An annual report for the calendar year evaluating the performance of the disposal operation must be submitted by July 1 of each year. Disposal Injection order. Sterling Unit 43-9 June 15,2004 . Page 7 of7 RULE 6: Notification of Improper Class II Injection The operator must immediately notify the Commission if it learns of any improper Class II injection. Additionally, notification requirements of any other State or Federal agency remain the operators' responsibility. RULE 7: Administrative Action Unless notice and public hearing is otherwise required, the Commission may administratively waive the requirements of any rule stated above or administratively amend any rule as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. RULE 8: Other Conditions Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless specifically superseded by Commission order. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order may result in the revocation or suspension of this authorization. ., DONE at Anchorage, Alaska and dated April 3, 20 Corrected June 15,2004 / o ~rman, Chair ~ Oil and Gas Conservation Commission Daniel T. Seamount, Jr., Commissioner Alaska Oil and Gas Conservation Commission AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the IO-day period. An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30-day period for appeal to Superior Court runs from the date on which the request is deemed denied (i .e., 10th day after the application for rehearing was filed). Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Kelly Valadez Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Ciri Land Department PO Box 93330 Anchorage, AK 99503 David Cusato 600 West 76th Ave., #508 Anchorage, AK 99518 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 . Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 . David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 John Levorsen 200 North 3rd Street, #1202 Boise, ID 83702 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Schlumberger Drilling and Measurements 3940 Arctic Blvd., Ste 300 Anchorage, AK 99503 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow, AK 99723 IlJlJlkc:G I } / & J / f¡ It) <-t Orders and Administrative Approvals It e ..................... ............ ........... ........ ......... ........... ......... .............. ....... .... ....... ....... ....., IIDIO 23.001.docfC~~t~nt- Type:---~~~li~~t-i~~msword, 10f2 6/16/20048:08 AM Orders and Administrative Approvals - e Content-Encoding: base64 i Content-Type: applicationlmsword . AI03.3.doc: . . Content-Encoding: base64 H .. .. .. ..... ... ..... ............ ...., I............. . ........ ........~ Content-Type: applicationlmsword Content-Encoding: base64 Content-Type: applicationlmsword Content-Encoding: base64 11 Content-Type: applicationlmsword DI025(Corrected).doc¡ . .1 Content-Encodmg: base64 20f2 6/16/20048:08 AM Re: Notice e e Subject: Re: Notice Date: 03 Apr 2003 16:05:36 -0900 From: Legal Ads Anchorage Daily News <legalads@adn.com> To: Jody Colombie <jody _ colombie@admin.state.ak.us> Hi Jody: Following is the confirmation information on your legal notice. Please let me know if you need anything further. Account Number: STOF 0330 Legal Ad Number: 760133 Publication Date(s): April 4, 2003 Your Reference #: AO-02314041 Total: $219.96 Thank You, Kim Kirby Anchorage Daily News Legal Classified Representative E-Mail: legalads@adn.com Phone: (907) 257-4296 Fax: (907) 279-8170 On Thursday, April 3, 2003, Jody Colombie <jody_colombie@admin.state.ak.us> wrote: > >Please publish in tomorrow paper if possible. > >Thank You. Jody 1 of 1 4/3/2003 4:05 PM A SEA SEAN PARNELL, GOVERNOR LASIEA®II� AIW��++QIIA333 W. 7th AVENUE, SUITE 100 tCONSSERVYAnONQOI}IQI��yI[O11I ANCHORAGE, ALASKA 99501-3539 PHONE (907)279-1433 FAX (907)276-7542 ADMINISTRATIVE APPROVAL NO. DIO 25.001 Mr. Kevin Skiba Regulatory Compliance Representative Marathon Alaska Production LLC P.O. Box 1949 Kenai, AK 99611 Re: Mechanical Integrity Test Time Interval Revision DID 25 — Sterling Unit 43-09 (16301 l0) Dear Mr. Skiba: Marathon submitted an Application for Sundry Approvals (Form 10-403) dated April 11, 2011 requesting the 2 -year Mechanical Integrity Test (MIT) interval in Rule 3 of Disposal Injection Order (DIO) 25 be changed to the standard 4 -year test interval contained in 20 AAC 25.252 (d). Since the MIT interval is set forth in a Commission order, Marathon's request cannot be granted via Sundry Approval. The Commission will treat the request as an application for administrative approval under Rule 7 of DIO 25. Marathon's request to change the MIT interval is GRANTED. This request is granted based upon Marathon's representation that no solids -laden fluids have been injected into the well to date and that it has no plans to inject solids into this well. In addition, the Commission has revised the text of Rules 3, 4 and 5 to conform to the integrity requirements incorporated into more recent injection orders. NOW, THEREFORE, as provided by Rule 7 of DIO 25, Rules 3, 4 and 5 are revised as follows: RULE 3: Demonstration of 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. After injection is commenced for the first time in a well, when injection conditions (temperature, pressure, rate, etc.) have stabilized, a Commission -witnessed MIT must be performed. Subsequent tests must be performed at least once every four years (except at least once every two years for a slurry injection well). The Commission must be notified at least 24 hours in advance to enable a representative to witness mechanical integrity tests. Unless an alternate means is approved by the Commission, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30 minute period. Results of mechanical integrity tests must be readily available for Commission inspection. DIO 25.001 May 31, 2011 Page 2 of 3 RULE 4: Well Integrity Failure and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by the injection rate, an operating pressure observation, a test, a survey, a log, or any other evidence, the operator shall immediately notify the Commission, obtain Commission approval to continue injection and submit a plan of corrective action on Form 10-403 for Commission approval. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating any well integrity failure or lack of injection zone isolation. RULE 5: Surveillance The operator shall run a baseline temperature log and perform a baseline step -rate test prior to initial injection. A subsequent temperature log must be run one month after injection begins to delineate the receiving zone of the injected fluids. Surface pressures and rates must be monitored continuously during injection for any indications of anomalous conditions. Results of daily wellhead pressure observations in the injection well must be documented and available to the Commission upon request. The conduct of subsequent temperature surveys or other surveillance logging (e.g., water flow; acoustic) will be based on the results of the initial and follow-up temperature surveys and injection performance monitoring data. A report evaluating the performance of the disposal operation must be submitted to the Commission by July 1 of each year. The report shall include data sufficient to characterize the disposal operation, including, among other information, the following: injection and annuli pressures (daily average, maximum and minimum); fluid volumes injected (disposal and clean fluid sweeps); injection rates; an assessment of fracture geometry; a description of any anomalous injection results; and a calculated zone of influence for the injection fluids. Except as otherwise specifically modified herein, the statutes and regulations of the Commission, as well as the provisions of DIO 25, remain in full force and^t. DONE at Anchorage, Alaska an Daniel T. Se ount, Jr. Chair, Co missioner 7 PilVir t t Cathy . Fo rater Co issioner DIO 25.001 May 31, 2011 Page 3 of 3 AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Fail ire to act on it within 10 -days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails. OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the dale on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration, As provided in AS 31.05.080(6), "[tlhe questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period, The last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.mon the next day that does not fall on a weekend or slate holiday. 0 0 Mary Jones David McCaleb Xf0 Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201-3557 Ft. Worth, TX 76102-6298 Houston, TX 77056 Jerry Hodgden Hodgden Oil Company 408 18" Street Golden, CO 80401-2433 Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 North Slope Borough Planning Department P.O. Box 69 Barrow, AK 99723 lack Hakkila P.O. Box 190083 Anchorage, AK 99519 Kenai National Wildlife Refuge Refuge Manager P.O. Box 2139 Soldotna, AK 99669-2139 Richard Neahring NRG Associates President P.O. Box 1655 Colorado Springs, CO 80901 CIRI Land Department P.O. Box 93330 Anchorage, AK 99503 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 Darwin Waldsmith P.O. Box 39309 Ninilchick, AK 99639 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Baker Oil Tools 795 E. 941h Ct. Anchorage, AK 99515-4295 Gordon Severson 3201 Westmar Circle Anchorage, AK 99508-4336 James Gibbs P.O. Box 1597 Soldotna, AK 99669 Cliff Burglin 319 Charles Street Fairbanks, AK 99701 9 Fisher, Samantha J (DOA) 0 From: Fisher, Samantha J (DOA) Sent: Thursday, June 02, 2011 10:04 AM To: Campbell, Rianne A (DOA); 'Aaron Gluzman'; 'Ben Greene'; Bruno, Jeff J (PCO); 'CA Underwood'; 'Dale Hoffman'; 'David Lenig'; 'Donna Vukich'; 'Elizabeth Bluemink'; 'Eric Lidji'; 'Gary Orr; Heusser, Heather A (DNR); 'Jason Bergerson'; 'Joe Longo'; King, Kathleen J (DNR); 'Lara Coates'; 'Lois Epstein'; 'Marc Kuck'; 'Marie Steele'; 'Mary Aschoff; 'Matt Gill'; 'Maurizio Grandi'; Ostrovsky, Larry Z (DNR); 'Patricia Bettis'; 'Richard Garrard'; 'Ryan Daniel', 'Sandra Lemke'; 'Talib Syed'; 'Wayne Wooster; 'Wendy Wollf; 'William Van Dyke'; '(michael.j.nelson@oonocophillips.com)'; '(Von. L. Hutchins@conocophillips.com)'; 'AKDCWellintegrityCoordinator; 'Alan Dennis'; 'alaska@petrocalc.com'; 'Anna Rafe; 'Barbara F Fullmer; 'bbritch'; 'Becky Bohrer;'Bill Penrose'; 'Bill Walker; 'Bowen Roberts'; 'Brady, Jerry U; 'Brandon Gagnon'; 'Brandow, Cande (ASRC Energy Services)'; 'Brian Havelock'; 'Bruce Webb'; 'Chris Gay'; 'Cliff Posey` 'Crandall, Krissell'; 'D Lawrence'; 'dapa'; 'Daryl J. Kleppin'; 'Dave Matthews'; 'David Boelens'; 'David House'; 'David Scott'; 'David Steingreaber; 'ddonkel@cfl.rr.com'; 'Dennis Steffy'; 'Elowe, Kristin'; 'Erika Denman'; 'eyancy; 'Francis S. Sommer; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Schultz (gary.schultz@alaska.gov)'; 'ghammons'; 'Gordon Pospisil'; 'Gorney, David L. ; 'Greg Duggin'; 'Gregg Nady'; 'gspfoff; 'Harry Engel'; 'Jdarlington Darlington@gmail.com)'; 'Jeanne McPherren'; 'Jeff Jones'; 'Jeffery B. Jones Deff.jones@alaska.gov)'; 'Jerry McCutcheon'; 'Jill Womack'; 'Jim White'; 'Jim Winegamer; 'Joe Nicks'; 'John Garing'; 'John Katz Oohn.katz@alaska.gov)'; 'John S. Haworth'; 'John Spain'; 'John Tower; 'Jon Goltz'; 'Judy Stanek'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles" 'Kelly Sperback'; 'Kim Cunningham'; 'Larry Ostrovsky'; 'Laura Silliphant (laura.gregersen@alaska.gov)'; 'Marilyn Crockett; 'Mark Dalton'; 'Mark Hanley (mark.hanley@anadarko.com)'; 'Mark Kovac'; 'Mark P. Worcester; 'Marquerite kremer (meg.kremer@alaska.gov)'; 'Michael Dammeyer; 'Michael Jacobs'; 'Mike Bill` 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'nelson'; 'Nick W. Glover; 'NSK Problem Well Supv'; 'Patty Alfaro'; 'Paul Decker (paul.decker@alaska.gov)'; 'Paul Figel'; 'PORHOLA, STAN T'; 'Randall Kanady'; 'Randy L. Skillem'; 'Rena Delbridge'; 'Renan Yanish'; 'rob.g.dragnich@exxonmobil.com'; 'Robert Brelsford'; 'Robert Campbell'; 'Rudy Brueggeman'; 'Ryan Tunseth'; 'Scott Cranswick'; 'Scott Griffith'; 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Steve Lambert'; 'Steve Moothart (steve.moothart@alaska.gov)'; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'tablerk'; 'Tamers Sheffield'; Taylor, Cammy O (DNR); 'Temple Davidson'; 'Teresa Imm'; 'Terrie Hubble'; 'Thor Cutler'; 'Tina Grovier; 'Todd Durkee'; 'Tony Hopfinger; 'trmjr1'; Vicki Irwin'; 'Walter Featherly'; 'Will Chinn'; Williamson, Mary J (DNR);'Yereth Rosen'; Aubert, Winton G (DOA) (winton.aubert@alaska.gov); Ballantine, Tab A (LAW); Brooks, Phoebe L (DOA) (phoebe.brooks@alaska.gov); Colombia, Jody J (DOA) Oody.colombie@alaska.gov); Crisp, John H (DOA) Oohn.cdsp@alaska.gov); Davies, Stephen F (DOA) (steve.davies@alaska.gov); Foerster, Catherine P (DOA) (cathy.foerster@alaska.gov); Grimaldi, Louis R (DOA) (lou.grimaldi@alaska.gov); Herrera, Matt F (DOA); Johnson, Elaine M (DOA) (elaine.johnson@alaska.gov); Jones, Jeffery B (DOA) Oeff.jones@alaska.gov); Laasch, Linda K (DOA) (linda.laasch@alaska.gov); Maunder, Thomas E (DOA) (tom.maunder@alaska.gov); McIver, Bren (DOA) (bren.mciver@alaska.gov); McMains, Stephen E (DOA) (steve.mcmains@alaska.gov); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA) (bob.noble@alaska.gov); Norman, John K (DOA) Oohn.norman@alaska.gov); Okland, Howard D (DOA) (howard.okland@alaska.gov); Paladijczuk, Tracie L (DOA) (tracie.paladijczuk@alaska.gov); Pasqual, Maria (DOA) (mada.pasquai@alaska.gov); Regg, James B (DOA) aim.regg@alaska.gov); Roby, David S (DOA) (dave.roby@alaska.gov); Saltmarsh, Arthur C (DOA) (art.saltmarsh@alaska.gov); Scheve, Charles M (DOA) (chuck.scheve@alaska.gov); Schwartz, Guy L (DOA) (guy.schwartz@alaska.gov); Seamount, Dan T (DOA) (dan.seamount@alaska.gov) Subject: dio25-001 Sterling Unit Attachments: dio25-001.pdf Sao a4,u0u.L I LNhk rc INDEXES 17 0 aMM Marathon .Alaska Production LLC April 11, 2011 Mr. Winton Aubert Alaska Oil & Gas Conservation Commission 333 W 7" Ave Anchorage, Alaska 99501 0 Marathon Alaska Production LLC Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 9071283-1371 Fax 9071283-1350 RECEIVED APR 13 2011 Make UA &fes Cent. CMMWW 9081 AP Reference: 10-403 Application for Sundry Approvals Field: Sterling Unit ` Well: Sterling Unit 43-9 JUN 4 2 2011 Dear Mr. Aubert: Submitted for your approval is the10-403 Application for Sundry Approvals for SU 43-9 well. Marathon request that the MIT test schedule be converted from its present 2 -year cycle to a 4 -year testing cycle keeping it consistent with requirements stated in Section -D of 20 AAC 25.252. Please contact me at (907) 283-1371 if you have any questions or need additional information. Sincerely, Kevin J. Skiba Regulatory Compliance Representative Enclosures: 10-403 Application for Sundry Approvals cc: AOGCC Current Well Schematic Houston Well File Summary of Proposal Kenai Well File KJS GI VE STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ApR 13 LUt'I s/1_41_15` APPLICATION FOR SUNDRY APPROVALS Alaska OA 8fas Cen all20 AAC 25 280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair well ❑ Ch a t ogram ❑ Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing ❑ S eci ime Extension Operational shutdown ❑ Re-enter Susp. Well ❑ Stimulate ❑ Alter casing El Co ve o -yr IT test cycle ❑✓ 2. Operator Name: Marathon Alaska Pr oduction LLC 4. Current Well Class: 5. Pe Drill umber. Development Exploratory F-1163-011 3. Address: PO Box 1949 Stratigraphic ❑ Service ❑ 6. A u er Kenai Alaska, 99611-1949 50-133-10011.00-00 7. If perforating, closest approach in pools) opened by this operation to nearest 8. Well Name and Nu property line where ownership or landownership changes: r. Spacing Exception Required? Yes ❑ No 0 erling Unit 43-9 9. Property Designation (Lease Number): 10. Feld/Pool(s): FED A-028063 S Ii glnit ndefined WDSP 11. PRESENT WELL CONDITION SUMM RY Total Depth MD (fl): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth ft): ( e ured): Junk (measured): 6,202' 6,201' 5,337' 5,336 5,337' NA Casing Length Size MD Burst Collapse Structural Conductor Surface 1,260' 8-5/8" 1,272' 1,272' 2,950 psi 1,370 si P Intermediate Production 3,743' 5-1/2" 3, 5' 3,754' 5,320 psi 4,910P si Production 1,625' 5.112" 3 5,379' 7,740 psi 6,290 psi Perforation Depth MD (ft): Perforation Depth ND (H): u 'n iz Tubing Grade: Tubing MD (ft): 5,262'-5,272' 5,261'-5,271' 8" J-55 5,250' Packers and SSSV Type: SSSV: NA ack nd S V MD (ft) and ND (ft): IST NA NA Packers: Baker N-1 52,41' 5,240' 12. Attachments: Description Summary of Proposal 0 3. Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ //orDevelopment ❑ Service ❑✓ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: Oil ❑ Gas ❑ WINJ ❑ GINJ ❑ WDSPL Q Suspended ❑ WAG ❑ Abandoned ❑ 16. Verbal Approval: Date: Commission Representative: GSTOR ❑ SPLUG El17. hereby certify that the foregoing is true and torr cl to the best of my knowledge. Contact Kevin Skiba (907) 283.1371 Printed Name Kevin J. Skiba Title Regulatory Compliance Representative Signaturea Date r (907) 283-1371 April 11, 2011 COMMISSION USE ONLY Oonditions of approval: Notify Com Sion so that a representative may witness SundryNumber: 'lug Integrity ❑ P Test ❑ Mechanical Integrity Test Q Location Clearance ❑ )thee subsequent For equired: 13Bf AAS JUN q� APPROVED BY approved by: O 2 7A' OMMISSIONER THE COMMISSION Date: ORIGINAL • April 8, 2011 Marathon Oil Corporation Field: Sterling Unit SU 43-9 Convert to 4 -year MIT Test Schedule Well Status: Class -2 Injection Well Obiective: Convert MIT test schedule from 2 -year to 4 -year test cycle History: The last MIT test was performed on May 13, 2009. Rule -3 of the DIO #25 states that an MIT test must be performed every two years as listed below. 20 AAC 25.252 states that an MIT test must be performed every four years. Disposal Injection Order No. 25 Correspondence dated January 24, 2003 to the Alaska Oil and Gas Conservation Commission Within 180 days of initiating disposal service, the Commission must be contacted to allow a representative of the Commission to witness an additional mechanical integrity test in SU 43-9. In addition to the requirements of 20 AAC 25.252 (d), mechanical integrity of the disposal well must be demonstrated at least once every two years. 20 AAC 25.252 Underground disposal of oil field wastes and underground storage of hydrocarbons (d) The mechanical integrity of a disposal or storage well must be demonstrated under 20 AAC 25.412 before disposal or storage operations are begun, after a well workover affecting mechanical integrity is conducted, and at least once every four years. Request: Marathon requests that the MIT test schedule, for SU 43-9, be converted to a 4 -year cycle from its present 2 -year cycle keeping it consistent with requirements stated in Section -D of 20 AAC 25.252. SU 43-9 is only used for the disposal of produced water. It has consistently past previously MIT tests confirming its integrity. Conversion to a 4 -years schedule would place the next MIT test date as May 13, 2013. 50.133-10011-00-00 163-011 11.7' Tree cxn = 2-3/8" EUE 8rd Tubing Detail: 2-3/8", 4.7 ppf, J-55, EUE 8rd tubing to 5,250' " Otis "A" sliding side -door @ 5,226' Otis S-1 nipple @ 5,238' Baker N-1 packer @ 5,241' `Tubing tail @ 5,250' E -line tagged fill at 5,336' MD (2/18/00) Cement plug 5,337'- 5,380' (7/2/63) SU 43-9 (Vertical Hole) 2,422'FSL,528'FEL Sec. 9, TSN, R10W, S.M. TD MD= 6,202' TVD = 6,201' 0 Surface Casino: 8-5/8", 24 ppf, J-55 casing @ 1272' Cmt w/ 450 sks plus 100 sk top -job Production Casing: 5-1/2", 17 ppf, LTC casing @ 5380' J-55: 0'- 3755' N-80: 3755'- 5380' Cmt w/ 550 sks Calculated cement top = 3,301' assuming 100% excess in 7-5/8" x 5- 1/2" annulus Perls: 5257'(squeezed) 5262'- 5272'(4 spf) 7.625" open hole below shoe @ 5,380' Well Name & Number: Sterling Unit 43.9 Lease: Sterling Unit County or Parish: Kenai Peninsula State: Alaska Country: USA Perforations: (MD). 5,262'-5,272' (TVD): 5,261'.5,271- ,261'-5,271'An Angle le @KOP and Depth: NA An le/Parts: I KOP TVD: NA Date Completed: Spud: June 19, 1963 RKB,j 11.7 Revised by: Kevin Skiba Last Revision Dale: 08/08111 16 Hilcorp Alaska, LLC 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone: 907-777-8300 Fax: 907-777-8580 June 30, 2022 Mr. Chris Wallace, Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Subject: 2021 Annual Disposal Report Sterling Unit 43-09 (DIO 25.001) Dear Mr. Wallace: In accordance with Disposal Injection Order (“DIO”) 25.001 Rule 5, Hilcorp Alaska, LLC hereby submits the annual disposal report for Sterling Unit 43-09 (PTD 163-011) for the year 2021. No disposal fluid was injected into SU 43-09 in 2021. Additionally, this well is currently in the process of being abandoned (Sundry 319-233) and has downhole cement plugs placed in accordance with the approved Sundry. Should you have questions, please contact Josh Allely at 777-8505. Sincerely, Josh Allely Well Integrity Engineer Hilcorp Alaska, LLC May 6, 2019 Mr. Chris Wallace, Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7h Avenue, Suite 100 Anchorage, Alaska 99501 RE: RULE 5, DID 25.001: SU 43-09 Dear Mr. Wallace: 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone: 907-777-8322 Fax: 907-777-8580 JUL 0 2 9019 AOGCC Attached please find the report required by Rule 5 of DIO 25.001 establishing the DIO for the Class II Water Disposal well SU 43-09 (PTD 163-011) for the calendar year of 2018. Surveillance Summary No fluid was injected into SU 43-09 within the year 2018. A passing mechanical integrity test was performed on the well on 4/4/2019 with the next MIT due in April 2023. Sincerely, Trudi Hallett Reservoir Engineer Hilcorp Alaska, LLC May 6, 2019 Mr. Chris Wallace, Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7`" Avenue, Suite 100 Anchorage, Alaska 99501 RE: RULE 5, DIO 25.001: SU 43-09 Dear Mr. Wallace: 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone: 907-777-8322 Fax: 907-777-8580 B :" IV ED MAY 0 8 2019 a e: f Attached please find the report required by Rule 5 of DIO 25.001 establishing the DIO for the Class II Water Disposal well SU 43-09 (PTD 163-011) for the calendar year of 2017. Surveillance Summary No fluid was injected into SU 43-09 within the year 2017. A passing mechanical integrity test was performed on the well on 4/4/2019 with the next MIT due in April 2023. Sincerely, tom" Trudi Hallett Reservoir Engineer Hilcorp Alaska, LLC January 30, 2017 MAR 31 2017 GL�Ztl� Ms. Cathy P. Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7"' Avenue, Suite 100 Anchorage, Alaska 99501 RE: RULE 5, DIO 25.001: SU 43-09 Dear Ms. Foerster: 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone:907-777-8322 Fax: 907-777-8580 Attached please find the report required by Rule 5 of DIO 25.001 establishing the DIO for the Class II Water Disposal well SU 43-09 (PTD 163-011) for the calendar year of 2016. Surveillance Summary No fluid was injected into SU 43-09 within the year 2016. A passing mechanical integrity test was performed on the well on 5/10/2016. Sincerely, N Trudi Hallett Reservoir Engineer Jim Young Reservoir Engineer Hilcorp Alaska, LLC 7/14/2016 Ms. Cathy P. Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 71h Avenue, Suite 100 Anchorage, Alaska 99501 RE: RULE 5, DIO 25.001: SU 43-09 Dear Ms. Foerster: RECEIVED JUL 18 2016 AOGCC 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone: 907-777-8321 Fax: 907-777-8580 dtaylor@hilcorp.com Attached please find the report required by Rule 5 of DIO 25.001 establishing the DIO for the Class II Water Disposal well SU 43-09 (PTD 163-011) for the calendar year of 2015. Injection and Annuli Pressures Injection volumes and annuli pressures are displayed on the plot in Figure 1. Daily data is included in Table 1. Fracture Geometry SU 43-09 disposes of Class II waste in the B-1 sand of the Sterling section in Sterling Gas Unit. The Sterling is composed of weakly consolidated sand sized grains with large shale and smaller coal breaks between sand packages. The Sterling 13-1 sand is ideal for cuttings injection because of the high porosity, high leak off of pad fluid, and bounding layers of softer shale and coals. Fracture orientation in SU 43-09 is expected to be vertical growing until the bounding layers are encountered above and below the injection strata. This has been proven by previous temperature logs and by openhole log derived rock mechanics properties. Surveillance Summary Rule 5 of DIO 25.001 calls for a description of injection results. No fluid was injected into SU 43-09 within the year 2015. A passing mechanical integrity test was performed on the well on 5/10/2015. Reservoir Engineer Kenai Asset Team Office: (907) 777-8321 Figure 1. SU 43-09 2015 daily monitoring Sterling Unit 43-009 - [50.0599.0003] - 1 600 500 1 400 1 300 1200 1 100 - DI Sterling Unit 43-009 12/2014 01/2015 02/2015 03/2015 04/2015 05/2015 06/2015 O7/2015 — Tubing — IA — OA 2001 1501 1001 50 1 0 08/2015 09/2015 10/2015 11/2015 12/2015 Well SU 43-09 Desc Shut -In Permit to drill 1630110 Admin Approval DIO #25 API 50-133-10011-00-00 Date Range 01/01/2015 - 07/11/2016 Date Tubing (psia) IA (psia) OA (psia) Gas Injection (Mcfd) 1/1/2015 0 255 0 0 1/2/2015 0 255 0 0 1/3/2015 0 255 0 0 1/4/2015 0 255 0 0 1/5/2015 0 255 0 0 1/6/2015 0 255 0 0 1/7/2015 0 255 0 0 1/8/2015 0 255 0 0 1/9/2015 0 255 0 0 1/10/201S 0 255 0 0 1/11/2015 0 255 0 0 1/12/2015 0 255 0 0 1/13/2015 0 255 0 0 1/14/2015 0 255 0 0 1/15/2015 0 255 0 0 1/16/2015 0 255 0 0 1/17/2015 0 255 0 0 1/18/2015 0 255 0 0 1/19/2015 0 255 0 0 1/20/2015 0 255 0 0 1/21/2015 0 254 0 0 1/22/2015 0 254 0 0 1/23/2015 0 250 0 0 1/24/2015 0 250 0 0 1/25/2015 0 251 0 0 1/26/2015 0 251 0 0 1/27/2015 0 250 0 0 1/28/2015 0 249 0 0 1/29/2015 0 251 0 0 1/30/2015 0 252 0 0 1/31/2015 0 253 0 0 2/1/2015 0 253 0 0 2/2/2015 0 252 0 0 2/3/2015 0 249 0 0 2/4/2015 0 248 0 0 2/5/2015 0 254 0 0 2/6/2015 0 251 0 0 2/7/2015 0 249 0 0 2/8/2015 0 249 0 0 2/9/2015 0 252 0 0 2/10/2015 0 257 0 0 2/11/2015 0 256 0 0 2/12/2015 0 257 0 0 2/13/2015 0 255 0 0 2/14/2015 0 257 0 0 2/15/2015 0 257 0 0 2/16/2015 0 258 0 0 2/17/2015 0 257 0 0 2/18/2015 0 256 0 0 2/19/2015 0 254 0 0 2/20/2015 0 257 0 0 2/21/201S 0 255 0 0 2/22/2015 0 255 0 0 2/23/2015 0 255 0 0 2/24/2015 0 255 0 0 2/25/2015 0 257 0 0 2/26/2015 0 252 01 0 2/27/2015 0 254 01 0 Well SU 43-09 Desc Shut -In Permit to drill 1630110 Ad m i n Approval D I O #25 API 50-133-10011-00-00 Date Range 01/01/2015 - 07/11/2016 Date Tubing (psia) IA (psia) OA (psia) Gas Injection (Mcfd) 2/28/2015 0 255 0 0 3/1/2015 0 254 0 0 3/2/2015 0 257 0 0 3/3/2015 0 255 0 0 3/4/2015 0 255 0 0 3/5/2015 0 256 0 0 3/6/2015 0 255 0 0 3/7/2015 0 254 0 0 3/8/2015 0 256 0 0 3/9/2015 0 252 0 0 3/10/2015 0 254 0 0 3/11/2015 0 251 0 0 3/12/2015 0 253 0 0 3/13/2015 0 250 0 0 3/14/2015 0 250 0 0 3/15/2015 0 251 0 0 3/16/201S 0 254 0 0 3/17/2015 0 258 0 0 3/18/2015 0 259 0 0 3/19/2015 0 258 0 0 3/20/2015 0 257 0 0 3/21/2015 0 257 0 0 3/22/2015 0 257 0 0 3/23/2015 0 257 0 0 3/24/2015 0 258 0 0 3/25/2015 0 258 0 0 3/26/2015 0 258 0 0 3/27/2015 0 260 0 0 3/28/2015 0 258 0 0 3/29/2015 0 258 0 0 3/30/2015 0 259 0 0 3/31/2015 0 260 0 0 4/1/2015 0 258 0 0 4/2/2015 0 261 0 0 4/3/2015 0 260 0 0 4/4/2015 0 258 0 0 4/5/2015 0 259 0 0 4/6/2015 0 260 0 0 4/7/2015 0 259 0 0 4/8/2015 0 259 0 0 4/9/2015 0 261 0 0 4/10/2015 0 256 0 0 4/11/2015 0 256 0 0 4/12/201S 0 256 0 0 4/13/2015 0 256 0 0 4/14/2015 0 256 0 0 4/15/2015 0 256 0 0 4/16/2015 0 258 0 0 4/17/2015 0 258 0 0 4/18/2015 0 260 0 0 4/19/2015 0 256 0 0 4/20/2015 0 255 0 0 4/21/2015 0 255 0 0 4/22/2015 0 258 0 0 4/23/2015 01 256 0 4/24/2015 21 255 0 4/25/2015 01 255 0 4/26/2015 01 255 1 0 Well SU 43-09 Desc Shut -In Permit to drill 1630110 Admin Approval DIO #25 API 50-133-10011-00-00 Date Range 01/01/2015 - 07/11/2016 Date Tubing (psia) IA (psia) OA (psia) Gas Injection (Mcfd) 4/27/2015 0 255 0 4/28/2015 0 255 0 4/29/2015 0 255 0 4/30/2015 0 5/1/2015 0 5/2/2015 0 5/3/2015 0 5/4/2015 0 0 5/5/2015 0 0 5/6/2015 0 0 5/7/2015 0 0 5/8/2015 0 459 1 0 5/9/2015 0 454 1 0 5/10/2015 0 448 1 0 5/11/2015 0 516 1 0 5/12/2015 0 517 1 0 5/13/2015 0 517 1 0 5/14/2015 0 516 1 0 5/15/2015 0 516 1 0 5/16/2015 0 516 1 0 5/17/2015 0 517 1 0 5/18/2015 0 517 1 0 5/19/2015 0 517 1 0 5/20/2015 0 517 1 0 5/21/2015 0 517 1 0 5/22/2015 0 517 1 0 5/23/201S 0 517 1 0 5/24/2015 0 517 1 0 5/25/2015 0 517 1 0 5/26/2015 0 517 1 0 5/27/2015 0 0 5/28/2015 0 0 5/29/2015 0 0 5/30/2015 0 0 5/31/2015 0 0 6/1/2015 0 0 6/2/2015 0 0 6/3/2015 0 0 6/4/2015 0 516 1 0 6/5/2015 0 516 1 0 6/6/2015 0 516 1 0 6/7/2015 0 516 1 0 6/8/2015 0 516 1 0 6/9/2015 0 516 1 0 6/10/2015 0 516 1 0 6/11/2015 0 516 1 0 6/12/2015 0 516 1 0 6/13/2015 0 516 1 0 6/14/2015 0 516 1 0 6/15/2015 0 516 1 0 6/16/2015 0 516 1 0 6/17/2015 0 516 1 0 6/18/2015 0 516 1 0 6/19/2015 0 516 1 0 6/20/2015 0 516 1 0 6/21/2015 0 516 1 0 6/22/2015 01 1 0 6/23/201S 01 1 1 0 Well SU 43-09 Desc Shut -In Permit to drill 1630110 Admin Approval DIO #25 API 50-133-10011-00-00 Date Range 01/01/2015 - 07/11/2016 Date Tubing (psia) IA (psia) OA (psia) Gas Injection (Mcfd) 6/24/2015 0 0 6/25/2015 0 0 6/26/2015 0 0 6/27/2015 0 0 6/28/2015 0 0 6/29/2015 0 0 6/30/2015 0 0 7/1/2015 0 0 7/2/2015 0 523 0 0 7/3/2015 0 525 0 0 7/4/2015 0 525 0 0 7/5/2015 0 525 0 0 7/6/2015 0 525 0 0 7/7/2015 0 525 0 0 7/8/2015 0 525 0 0 7/9/2015 0 525 0 0 7/10/2015 0 525 0 0 7/11/201S 0 526 0 0 7/12/2015 0 525 0 0 7/13/2015 0 525 0 0 7/14/2015 0 524 0 0 7/15/2015 0 525 0 0 7/16/2015 0 523 0 0 7/17/2015 0 524 0 0 7/18/2015 0 524 0 0 7/19/2015 0 524 0 0 7/20/2015 0 524 0 0 7/21/2015 0 524 0 0 7/22/2015 0 524 0 0 7/23/201S 0 524 0 0 7/24/2015 0 524 0 0 7/25/2015 0 524 0 0 7/26/2015 0 524 0 0 7/27/2015 0 524 0 0 7/28/2015 0 524 0 0 7/29/2015 0 524 0 0 7/30/2015 0 524 0 0 7/31/2015 0 526 0 0 8/1/2015 0 526 0 0 8/2/2015 0 526 0 0 8/3/2015 0 526 0 0 8/4/2015 0 526 0 0 8/5/2015 0 526 0 0 8/6/2015 0 526 0 0 8/7/2015 0 526 0 0 8/8/2015 0 S25 0 0 8/9/2015 0 525 0 0 8/10/2015 0 525 0 0 8/11/2015 0 525 0 0 8/12/2015 0 525 0 0 8/13/2015 0 0 8/14/2015 0 0 8/15/2015 0 0 8/16/2015 0 0 8/17/2015 0 0 8/18/2015 0 0 8/19/201S 0 O 8/20/2015 0 0 Well SU 43-09 Desc Shut -In Permit to drill 1630110 Admin Approval DID #25 API 50-133-10011-00-00 Date Range 01/01/2015 - 07/11/2016 Date Tubing (psia) IA (psia) OA (psia) Gas Injection (Mcfd) 8/21/2015 0 0 8/22/2015 0 0 8/23/2015 0 0 8/24/2015 0 0 8/25/2015 0 0 8/26/2015 0 0 8/27/2015 0 525 0 0 8/28/2015 0 525 0 0 8/29/2015 0 525 0 0 8/30/2015 0 525 0 0 8/31/2015 0 525 0 0 9/1/2015 0 525 0 0 9/2/2015 0 525 0 0 9/3/2015 0 525 0 0 9/4/2015 0 525 0 0 9/5/2015 0 525 0 0 9/6/2015 0 525 0 0 9/7/2015 0 525 0 0 9/8/2015 0 525 0 0 9/9/2015 0 525 0 0 9/10/2015 0 525 0 0 9/11/2015 0 525 0 0 9/12/2015 0 525 0 0 9/13/2015 0 525 0 0 9/14/2015 0 0 9/15/2015 0 0 9/16/2015 0 0 9/17/2015 0 525 0 0 9/18/2015 0 525 0 0 9/19/2015 0 525 0 0 9/20/2015 0 525 0 0 9/21/2015 0 525 0 0 9/22/2015 0 525 0 0 9/23/2015 0 525 0 0 9/24/2015 0 525 0 0 9/25/2015 0 525 0 0 9/26/2015 0 525 0 0 9/27/2015 0 525 0 0 9/28/2015 0 525 0 0 9/29/2015 0 525 0 0 9/30/2015 0 525 0 0 10/1/2015 0 525 0 0 10/2/2015 0 525 0 0 10/3/2015 0 525 0 0 10/4/2015 0 525 0 0 10/5/2015 0 525 0 0 10/6/2015 0 525 0 0 10/7/2015 0 525 0 0 10/8/2015 0 0 10/9/2015 0 0 10/10/2015 0 0 10/11/2015 0 0 10/12/2015 0 0 10/13/2015 0 0 10/14/2015 0 525 0 0 10/15/2015 0 525 0 0 10/16/2015 0 525 0 0 10/17/2015 0 5251 01 0 Well SU 43-09 Desc Shut -In Permit to drill 1630110 Admin Approval DIO #25 API 50-133-10011-00-00 Date Range 01/01/2015 - 07/11/2016 Date Tubing (psia) IA (psia) OA (psia) Gas Injection (Mcfd) 10/18/2015 0 525 0 0 10/19/2015 0 525 0 0 10/20/2015 0 525 0 0 10/21/2015 0 525 0 0 10/22/2015 0 525 0 0 10/23/2015 0 S2S 0 0 10/24/2015 0 525 0 0 10/25/2015 0 525 0 0 10/26/2015 0 525 0 0 10/27/2015 0 525 0 0 10/28/2015 0 525 0 0 10/29/2015 0 525 0 0 10/30/2015 0 525 0 0 10/31/2015 0 525 0 0 11/1/2015 0 525 0 0 11/2/2015 0 525 0 0 11/3/2015 0 525 0 0 11/4/2015 0 525 0 0 11/5/2015 0 525 0 0 11/6/2015 0 525 0 0 11/7/2015 0 525 0 0 11/8/2015 0 525 0 0 11/9/2015 0 525 0 0 11/10/2015 0 525 0 0 11/11/2015 0 525 0 0 11/12/2015 0 0 11/13/2015 0 0 11/14/2015 0 0 11/15/2015 0 0 11/16/2015 0 0 11/17/2015 0 0 11/18/2015 0 0 11/19/2015 0 525 0 0 11/20/2015 0 525 0 0 11/21/2015 0 525 0 0 11/22/2015 0 525 0 0 11/23/2015 0 525 0 0 11/24/2015 0 525 0 0 11/25/2015 0 525 0 0 11/26/2015 0 525 0 0 11/27/2015 0 525 0 0 11/28/2015 0 525 0 0 11/29/2015 0 525 0 0 11/30/2015 0 525 0 0 12/1/2015 0 525 0 0 12/2/2015 0 525 0 0 12/3/2015 0 525 0 0 12/4/2015 0 525 0 0 12/5/2015 0 525 0 0 12/6/2015 0 525 0 0 12/7/2015 0 525 0 0 12/8/2015 0 525 0 0 12/9/2015 0 525 0 0 12/10/2015 0 0 12/11/2015 0 0 12/12/2015 0 0 12/13/2015 0 0 12/14/2015 0 0 Well SU 43-09 Desc Shut -I n Permit to drill 1630110 Admin Approval DIO #25 API 50-133-10011-00-00 Date Range 01/01/2015 - 07/11/2016 Date Tubing (psia) IA (psia) OA (psia) Gas Injection (Mcfd) 12/15/2015 0 0 12/16/2015 0 0 12/17/2015 0 525 0 0 12/18/2015 0 525 0 0 12/19/2015 0 525 0 0 12/20/2015 0 525 0 0 12/21/2015 0 525 0 0 12/22/2015 0 525 0 0 12/23/2015 0 525 0 0 12/24/2015 0 525 0 0 12/25/2015 0 525 0 0 12/26/2015 0 525 0 0 12/27/2015 0 525 0 0 12/28/2015 0 525 0 0 12/29/2015 0 525 0 0 12/30/2015 01 5251 01 0 12/31/2015 01 5251 01 0 Hilcorp Alaska, LLC 6/30/2015 Ms. Cathy P. Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RE: RULE 5, DIO 25.001: SU 43-09 Dear Ms. Foerster: 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone: 907-777-8388 Fax: 907-777-8580 jmardambek@hilcorp.com JUL 0 1 2010 Attached please find the report asked for in RULE 5 of DIO 25.001 establishing the DIO for the Class II Water Disposal well SU 43-09 (PTD 163-011) for the calendar year of 2014 Injection and Anuuli Pressures Injection volumes and annuli pressures are included in Figure 1. Daily data is included in Table 1. Fracture Geometry SU 43-09 disposes of Class II waste in the B-1 sand of the Sterling section in Sterling Gas Unit. The Sterling is composed of weakly consolidated sand sized grains with large shale and smaller coal breaks between sand packages. The Sterling B-1 sand is ideal for cuttings injection because of the high porosity, high leak off of pad fluid, and bounding layers of softer shale and coals with higher stresses due the nature of the softer rocks. This is shown in Figure 2 where the stress difference in the rocks reflects the differences in the Poissons's ratio. The difference in Poissons's ratio is important when comparing the sands with the coals or the shale. Coals have the highest difference of Poisson's ratio with the difference upwards of 0.1 which at the stress regime translates to a stress difference of greater than 200 psi. Along with the high leak off of the B-2 sand, this difference in stresses is important in keeping the injections contained in the disposal strata. This difference is shown in the stress log in Figure 2. Fracture orientation in SU 43-09 is expected to be vertical growing until the bounding layers are encountered above and below the injection strata. This has been proven by previous temperature logs and by open hole log derived rock mechanics properties. The leak off of the B-1 sands is so high very little net pressure can be built at the rates attained by the low volumes injected during 2014. Alaska Oil and Gas Conservation Commission Sterling Field, SU 43-09 DIO Rule 5 Page 2 of 2 Zone of Influence Cumulative injection volume from 1/l/2014 through 12/31/2014 has been 13,200 bbls of formation water. Assuming a height of 90' between coal bounding layers, a porosity of 30%, and water saturation of 40%, the expected total area of influence is less than 0.2 acres. Assuming cylinder geometry the total radius of influence is 38ft. Figure I — Injection and Annuli pressures including daily average, daily max, & daily minimum and fluid volumes. Figure 2 — Expected stress log of Sterling B sands and bounding layers Rule 5 of DIO 25.001 calls for a description of any anomalous injection results but for the year 2014 there were no anomalous results. Sincerely, eremy Mardambek Reservoir Engineer (907)777-8388 Sterling Unit 43-009 - [50.0599.0003] 2000 � 1500 -i 1000 - 500 0� 01/2014 02/2014 03/2014 04/2014 05/2014 06/2014 07/2014 08/2014 09/2014 10/2014 11/2014 12/2014 — Tubing — IA — Water Injection 600 500 400 300 200 100 0 Well: SU 43-09 Desc: Disposal Permit to drill: 1630110 Admin Approval: DIO #25 API: 50-133-10011-00-00 Date Range: 01/01/2014 - 12/31/2014 Date Tubing IA Water Injection 12/31/201 0 255 0 12/30/201 0 255 0 12/29/201 0 255 0 12/28/201 0 255 0 12/27/201 0 255 0 12/26/201 0 255 0 12/25/201 0 255 0 12/24/201 0 255 0 12/23/201 0 255 0 12/22/201 0 255 0 12/21/201 0 255 0 12/20/201 0 255 0 12/19/201 0 255 0 12/18/201 0 255 0 12/17/201 0 255 0 12/16/201 0 255 0 12/15/201 0 255 0 12/14/201 0 255 0 12/13/201 0 255 0 12/12/201 0 255 0 12/11/201 0 0 12/10/201 0 0 12/9/2014 0 0 12/8/2014 0 0 12/7/2014 0 0 12/6/2014 0 0 12/5/2014 0 0 12/4/2014 0 0 12/3/2014 0 255 0 12/2/2014 0 255 0 12/1/2014 0 255 0 11/30/201 0 253 0 11/29/201 0 252 0 11/28/201 0 253 0 11/27/201 0 252 0 11/26/201 0 254 0 11/25/201 0 254 0 11/24/201 0 254 0 11/23/201 0 254 0 11/22/201 0 254 0 11/21/201 0 254 0 11/20/201 0 254 0 11/19/201 0 254 0 Date Tubing IA Water Injection 11/18/201 0 254 0 11/17/201 0 254 0 11/16/201 0 254 0 11/15/201 0 254 0 11/14/201 0 254 0 11/13/201 0 254 0 11/12/201 0 254 0 11/11/201 0 254 0 11/10/201 0 254 0 11/9/2014 0 254 0 11/8/2014 0 254 0 11/7/2014 0 254 0 11/6/2014 0 254 0 11/5/2014 0 254 0 11/4/2014 0 255 0 11/3/2014 0 255 0 11/2/2014 0 255 0 11/1/2014 0 255 0 10/31/201 0 254 0 10/30/201 0 253 0 10/29/201 0 255 0 10/28/201 0 255 0 10/27/201 0 255 0 10/26/201 0 255 0 10/25/201 0 255 0 10/24/201 0 255 0 10/23/201 0 255 0 10/22/201 0 255 0 10/21/201 0 255 0 10/20/201 0 255 0 10/19/201 0 255 0 10/18/201 0 255 0 10/17/201 0 255 0 10/16/201 0 255 0 10/15/201 0 255 0 10/14/201 0 0 10/13/201 0 0 10/12/201 0 0 10/11/201 0 0 10/10/201 0 0 10/9/2014 0 0 10/8/2014 0 256 0 10/7/2014 0 255 0 10/6/2014 0 256 0 10/5/2014 0 257 0 10/4/2014 0 258 0 10/3/2014 0 258 0 10/2/2014 0 258 0 10/1/2014 0 260 0 9/30/2014 0 260 0 9/29/2014 0 260 0 Date Tubing IA Water Injection 9/28/2014 0 260 0 9/27/2014 0 260 0 9/26/2014 0 260 0 9/25/2014 0 260 0 9/24/2014 0 260 0 9/23/2014 0 260 0 9/22/2014 0 0 9/21/2014 0 260 0 9/20/2014 0 260 0 9/19/2014 0 260 0 9/18/2014 0 260 0 9/17/2014 0 260 0 9/16/2014 0 260 0 9/15/2014 0 260 0 9/14/2014 0 260 0 9/13/2014 0 260 0 9/12/2014 0 260 0 9/11/2014 0 260 0 9/10/2014 0 260 0 9/9/2014 0 260 0 9/8/2014 0 260 0 9/7/2014 0 260 0 9/6/2014 0 259 0 9/5/2014 0 259 0 9/4/2014 0 261 0 9/3/2014 0 0 9/2/2014 0 0 9/1/2014 0 0 8/31/2014 0 0 8/30/2014 0 0 8/29/2014 0 0 8/28/2014 0 0 8/27/2014 0 0 8/26/2014 0 0 8/25/2014 0 0 8/24/2014 0 0 8/23/2014 0 0 8/22/2014 0 0 8/21/2014 0 0 8/20/2014 0 0 8/19/2014 0 0 8/18/2014 0 0 8/17/2014 0 0 8/16/2014 0 0 8/15/2014 0 0 8/14/2014 0 0 8/13/2014 0 262 0 8/12/2014 0 262 0 8/11/2014 0 262 0 8/10/2014 0 262 0 8/9/2014 0 261 0 Date Tubing IA Water Injection 8/8/2014 0 261 0 8/7/2014 0 261 0 8/6/2014 0 261 0 8/5/2014 0 261 0 8/4/2014 0 261 0 8/3/2014 0 261 0 8/2/2014 0 261 0 8/1/2014 0 261 0 7/31/2014 0 261 0 7/30/2014 0 261 0 7/29/2014 0 261 0 7/28/2014 0 261 0 7/27/2014 0 261 0 7/26/2014 0 261 0 7/25/2014 0 261 0 7/24/2014 0 261 0 7/23/2014 0 261 0 7/22/2014 0 261 0 7/21/2014 0 261 0 7/20/2014 0 261 0 7/19/2014 0 261 0 7/18/2014 0 261 0 7/17/2014 0 261 0 7/16/2014 0 261 0 7/15/2014 0 257 0 7/14/2014 0 257 0 7/13/2014 0 257 0 7/12/2014 0 257 0 7/11/2014 0 258 0 7/10/2014 0 257 0 7/9/2014 0 259 0 7/8/2014 0 259 0 7/7/2014 0 259 0 7/6/2014 0 259 0 7/5/2014 0 259 0 7/4/2014 0 259 0 7/3/2014 0 259 0 7/2/2014 0 259 0 7/1/2014 0 258 0 6/30/2014 0 250 0 6/29/2014 0 250 0 6/28/2014 0 250 0 6/27/2014 0 250 0 6/26/2014 0 250 0 6/25/2014 0 251 0 6/24/2014 0 253 0 6/23/2014 0 251 0 6/22/2014 0 251 0 6/21/2014 0 250 0 6/20/2014 0 253 0 6/19/2014 0 250 0 Date Tubing IA Water Injection 6/18/2014 0 249 0 6/17/2014 0 250 0 6/16/2014 0 249 0 6/15/2014 0 249 0 6/14/2014 0 251 0 6/13/2014 0 248 0 6/12/2014 0 247 0 6/11/2014 0 248 0 6/10/2014 0 248 0 6/9/2014 0 248 0 6/8/2014 0 248 0 6/7/2014 0 248 0 6/6/2014 0 249 0 6/5/2014 0 247 0 6/4/2014 0 249 0 6/3/2014 0 247 0 6/2/2014 0 245 0 6/1/2014 0 0 5/31/2014 0 0 5/30/2014 0 0 5/29/2014 0 0 5/28/2014 0 0 5/27/2014 0 0 5/26/2014 0 0 5/25/2014 0 0 5/24/2014 0 0 5/23/2014 0 0 5/22/2014 0 0 5/21/2014 0 244 0 5/20/2014 0 245 0 5/19/2014 0 244 0 5/18/2014 0 245 0 5/17/2014 0 249 0 5/16/2014 0 247 0 5/15/2014 0 244 0 5/14/2014 0 245 0 5/13/2014 0 244 0 5/12/2014 0 244 0 5/11/2014 0 245 0 5/10/2014 0 246 0 5/9/2014 0 243 0 5/8/2014 0 243 0 5/7/2014 0 245 0 5/6/2014 0 242 0 5/5/2014 0 242 0 5/4/2014 0 244 0 5/3/2014 0 244 0 5/2/2014 0 242 0 5/1/2014 0 242 0 4/30/2014 0 0 4/29/2014 0 0 Date Tubing IA Water Injection 4/28/2014 0 0 4/27/2014 0 0 4/26/2014 0 0 4/25/2014 0 0 4/24/2014 8 235 0 4/23/2014 35 235 0 4/22/2014 62 234 0 4/21/2014 101 234 0 4/20/2014 174 232 0 4/19/2014 255 229 0 4/18/2014 343 228 0 4/17/2014 454 228 0 4/16/2014 598 226 0 4/15/2014 778 224 0 4/14/2014 1133 221 0 4/13/2014 1971 213 53 4/12/2014 1913 197 115 4/11/2014 1815 198 116 4/10/2014 2030 206 127 4/9/2014 1927 210 98 4/8/2014 1837 212 73 4/7/2014 1909 213 115 4/6/2014 1944 213 138 4/5/2014 1694 211 162 4/4/2014 1654 223 143 4/3/2014 1961 206 146 4/2/2014 1729 107 154 4/1/2014 1935 143 3/31/2014 1624 163 3/30/2014 1808 147 3/29/2014 1775 164 3/28/2014 1961 162 3/27/2014 1815 161 3/26/2014 1904 184 92 3/25/2014 1744 185 98 3/24/2014 2030 181 104 3/23/2014 1968 181 104 3/22/2014 1995 180 108 3/21/2014 2248 186 90 3/20/2014 2045 201 162 3/19/2014 1978 581 3/18/2014 1978 0 3/17/2014 1418 263 3/16/2014 1899 75 3/15/2014 1899 186 155 3/14/2014 2213 173 156 3/13/2014 2086 187 156 3/12/2014 2333 183 155 3/11/2014 2183 189 44 3/10/2014 2158 185 77 3/9/2014 2206 181 77 Date Tubing IA Water Injection 3/8/2014 2053 181 76.5 3/7/2014 1883 183 32 3/6/2014 2092 224 84 3/5/2014 2127 76 3/4/2014 2226 141 3/3/2014 2065 147 3/2/2014 2086 118 3/1/2014 2229 123 2/28/2014 1774 139.5 2/27/2014 2091 112.2 2/26/2014 2085 173 125.8 2/25/2014 2120 172 120.4 2/24/2014 2147 171 137 2/23/2014 2144 183 145 2/22/2014 2010 260 158.3 2/21/2014 1988 243 142.1 2/20/2014 1937 239 151.2 2/19/2014 1909 242 146 2/18/2014 2094 242 146 2/17/2014 2135 234 147 2/16/2014 1921 231 128 2/15/2014 1978 232 133 2/14/2014 1963 235 151 2/13/2014 2080 229 140 2/12/2014 1710 228 155 2/11/2014 1899 229 107 2/10/2014 1971 226 145 2/9/2014 2097 225 133 2/8/2014 2019 225 135 2/7/2014 1868 226 143 2/6/2014 1845 222 138 2/5/2014 1891 132 2/4/2014 1940 145 2/3/2014 1847 135 2/2/2014 1923 149 2/1/2014 1811 132 1/31/2014 1906 140 1/30/2014 1872 148.8 1/29/2014 2058 224 145.1 1/28/2014 2014 226 138.4 1/27/2014 1848 227 159.7 1/26/2014 2007 219 146.6 1/25/2014 1834 214 149.9 1/24/2014 1737 218 145.3 1/23/2014 1800 215 140.1 1/22/2014 1681 215 125 1/21/2014 1652 217 110 1/20/2014 1650 218 108 1/19/2014 1684 213 123 1/18/2014 1604 123 1/17/2014 1624 212 98 Date Tubing IA 1/16/2014 1811 1/15/2014 1618 1/14/2014 1510 1/13/2014 1665 1/12/2014 1582 1/11/2014 1180 1/10/2014 1348 1/9/2014 1752 1/8/2014 1724 1/7/2014 2279 1/6/2014 1742 1/5/2014 1776 1/4/2014 1656 1/3/2014 1671 1/2/2014 1750 1/1/2014 1823 Water Injection 208 126 111 65 103 116 63 56.6 85 109 93 89 127 117 190 121.5 190 191 190 114.9 N N A L N W U A 3 O W L Y W N u A 41W 4?7C 4�07 0.30u Jo UAU pr Poisson's ratio (Psd _ Le) r 1 Page 1 of 1 • Maunder, Thomas E (DOA) From: Stebbins, Tiffany A. [tastebbins @marathonoil.com] Sent: Friday, March 04, 2011 1:36 PM To: Maunder, Thomas E (DOA) Subject: RE: SU 43 -09 (163 -011) Disposal Report Tom, a) The source of the water injected into SU 43 -9 in 2010 was a combination of: • SU water produced in 2009 that remained in the tanks until 2010; the tanks hold several hundred barrels • SU water produced in 2010 (a small amount) • Rinse water from cleaning production facilities b) The reason we had Tess injection at SU this year is because we had less water production at SU in 2010, and this is because we shut in wells that make considerable water. Thanks, 541. thg.,40, k0 Regulatory Compliance Representative Marathon Alaska Production, LLC Phone 907 -565 -3043 Cell 907 -529 -0522 Fax 907 -565 -3076 From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Wednesday, March 02, 2011 11:58 AM To: Stebbins, Tiffany A. Subject: SU 43 -09 (163 -011) Disposal Report Hi Tiffany, Thanks for submitting the 2010 report. After review, I have a couple of questions. 1. The disposal volume is greatly reduced from 2009 (290 bbls versus 91870 bbls). I suspect this is related just to the reduced production time. Is that the case? Are the 3 gas wells in the SU more or less being used for "swing production "? 2. From the production reporting volumes, 32 -09 shows 5 bw in May 2010. Our records do not show the remaining 285 bbls (injected in April 2010) in the production record from any of the 3 gas wells. Do you know the source of that water volume? Thanks in advance. Call or message with any questions. Tom Maunder, PE AOGCC 3/7/2011 X14 • Alaska Asset Team Alas 2 T • FE 8 iyi Marathon P.O. Box 196168 ka & & ss D C oi C ion u ka Production LLC Ancorage, AK 99519 -6188 Telephone 907/561 -5311 JinCtlorsge Fax 90715565.3076 February 28, 2011 Daniel T. Seamount, Jr., Commission Chair Alaska Oil & Gas Conservation Commission Attn: Tom Maunder 333 W. 7 Avenue, Suite 100 Anchorage, AK 99501 Reference: Report on Disposal Injection Operations Well Sterling Unit 43 -09, Sterling Unit Permit to drill #163 -011 Dear Mr. Maunder, Well Sterling Unit 43 -09 (SU 43 -9) is governed by Disposal Injection Order (DIO) No. 25, approved June 5, 2004. This report covers disposal injection operations for SU 43 -9 from January 1, 2010 until December 31, 2010. Fluids injected into SU 43 -9 typically come from well Sterling Unit 32 -9. No drilling mud slurries have been injected to date. The last mechanical integrity test on SU 43 -9 was conducted on May 13 2009 and the next test is due by May 13 2011. Attached are three graphs showing injection volume, injection pressure, and inner annulus pressure for SU 43 -9 in 2010. As shown from these graphs and the accompanying summary, injection volume for SU 43 -9 averaged <1 bwpd throughout 2010, for a total of 290 bbls of fluid injected during the calendar year. Please contact me with any questions at 907 - 565 -3043. Sincerely, i Tiffany Stebbins Compliance Representative cc: M. D. Dammeyer L. Ibele Well file Marathon Alaska Production LLC • February 28, 2011 Report on Disposal Injection Operations Page 2 of 4 Well SU 43 -09, Sterling Unit Injection pressures (daily average, maximum and minimum) Injection Injection Injection Year Pressure, Pressure, Pressure, Average (psig) Maximum (psig) Minimum (psig) 2010 69 1822 0 SU 43 -9 Injection Pressure (2010) 2000 — 1800 Tubing Pressure Average (psig) 1600 A Tubing Pressure Maximum (psig) '7 1400 - a a, 1200 L 3 N a 1000 -. a c 800 • u I °1 600 400 200 { 0 A_ 1 y 0 y 0 y 0 y 0 y 0 y 0 y 0 y 0 y 0 y 0 y 0 , , , . , , , , , , , , , >a � ye p ma c PQ � � >J � >�� PJ � �e9 O` er ° � O�° Marathon Alaska Production LLC February 28, 2011 Report on Disposal Injection Operations Page 3 of 4 Well SU 43 -09, Sterling Unit Annuli pressures (daily average, maximum and minimum) Inner Annulus Inner Annulus Inner Annulus Year Pressure, Pressure, Pressure, Average (psig) Maximum (psig) Minimum (psig) 2010 155 160 91 SU 43 -9 Annuli Pressure (2010) 200 180 ti. 160 a . ao 140 a 0 120 w 100 Annulus Pressure Average (psig) 80 Annulus Pressure Maximum (psig) a 60 40 20 0 , y 0 y 0 y 0 y 0 , y 0 y 0 y 0 y 0 y 0 0 , y 0 , ti 0 L O ti 0 ti 0 L O ti 0 , y 0 ti 0 , >a <<1C)' la PQ ,4\1:0 V-) P�v co< 0, -7 The outer annulus showed negligible pressure throughout 2010. Marathon Alaska Production LLC February 28, 2011 Report on Disposal Injection Operations Page 4 of 4 Well SU 43 -09, Sterling Unit Fluid volumes injected (disposal and clean sweeps) Year Fluid Volumes Injected, (bbl) 2010 290 SU 43 -9 Injection Volume (2010) 128,500 500 128,400 400 v _a Total Cummulative Injection Volume (bbl) E 128,300 Total Injection Volume, Month (bbl /month) 300 5 Z 0 > a p «. f 128,200 200 a .E E I 128,100 100 a� Q 128,000 — 0 O O O O O O O O O O O O Oti Oti Oti Oti Oti Oti Oti Oti Oti Oti Oti Oti c „ t c , � , Jam t 1, , �. ` 'L >'� ,e �Sa P �a �J > ,i„.)% ce O ` �° Oe X13 • Marathon MAM ®Alaska Production LLC June 1, 2010 ~~11/Et~ .~ li i~ 1 ~ 2010 Daniel T. Seamount, Jr., Commission Chair Alaska Oil & Gas Conservation Commission Attn: Jim Regg 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 Alaska AssetTeam P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/565-3076 Reference: Report on Disposal Injection Operations Well SU 43-09, Sterling Unit ~ ~3- ~L~ Dear Mr. Regg, Aioska qi# ~ ~~: Cam. Commission ~t!r#~~tt~#Q ~~ `~C, ~-. Well SU 43-09 in the Sterling Unit is governed by Disposal Injection Order (DIO) No. 25, approved June 5, 2004. This report covers the final disposal injection operations for SU 43-9 from January 1, 2009 until December 31, 2009 (including operations to date). Currently, wells SU 32-09, SU 41-15RD, and SU 43-9x produce the fluids injected via SU 43-09. Although permitted for injection of drilling mud slurries as well as other Class II production wastes, no drilling mud slurries have been injected to date in SU 43-09. The last mechanical integrity test was conducted on May 13th 2009 and the next test is due by May 13th 2011. Attached are four graphs showing injection volume, injection pressure, inner annulus pressure, and outer casing pressure for SU 43-9 in 2009 and YTD 2010. As shown from these graphs and accompanying summary, injection volume for SU 43-9 averaged 252 bwpd throughout 2009 for a total of 91,870 bbls of fluid injected during calendar year 2009. 2009 YTD 2010 (as of 6/1/10) Total In'ected Volume [bbl) 91,870 92,159 Avera a In'ected Dail Volume [bw ] 252 179 0 1 /1 /2009 2/1 /2009 3/1 /2009 4/1 /2009 5/1 /2009 6/1 /2009 7/1 /2009 8/1 /2009 $ 9/1/2009 ~ 10/1/2009 11/1/2009 12/1/2009 1/1/2010 2J1 /2010 3/1 /2010 4/1 /2010 5/1 /2010 v ~{ J J N 7 ~ C i W o m O ~ fD C1 0 ~o m _v, -~ 0 ~_ N j 1 N °o t° m ~ ~ " ^' b o ~ ~ 3 N A 0 0 c 3 co ~~~ ~~ w -o ~ Coo ~~ ~ WpD o y iv ~~ ~ ~ ~ m m~'~ ?. a C _. _. ~ O O r: 7 7 O~ m m ~. 0 y • c ~~ m ~ m 1 N N O O W O Injection Pressure (psig) cn o cn o cNn o °o °o °o °o °o °o r Marathon Alaska Production LL~ Report on Disposal Injection Operations Well SU 43-09, Sterling Unit June 11, 2010 Page 3 of 3 1000 ~ so0 , a 800 ~ 700 y d L 6~0 a 500 N 40C c 30G Q 200 d c ~ 100 0 rn w o w o w rn a7 rn o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N r C~ M ~ to Cp n ~ m O ~ (~ r a m V to Date Disposal Well Sterling Unit 43-09 Outer Annulus Pressure 1/1/2009 - 6/1/2010 100 rn 90 tN v- 80 y' 70 3 N y 60 i a 50 H 40 c 30 a d 20 .. p 10 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N r C~ M V ~ CO r a0 O) O Date Please contact me with any questions at 907-565-3043. Sincerely, Tiffany Stebbins Compliance Representative cc: M. D. Dammeyer Well file Disposal Well Sterling Unit 43-09 Inner Annulus Pressure 1/1/2009 - 6/1/2010 0 0 0 0 0 0 0 N N N N N N N ~ C~ r C~ M V in '.~12 I.J M Ma/r+a~t~hon MARATHON OII WN N Many June 17, 2009 Winton Aubert AOGCC 333 West 7t" Ave, Suite 100 Anchorage, AK 99501 Alaska Ass~Team ~~~ ~~ PO BOX 196168 ;~ c ~~N ~ '~ ~Q©~ Anchorage, AK 99519-~~~8` Q~l c4c ~',~ Telephone 907/561-5311 ~ ~®tts. ~~mrt-is Fax 907/565-3076 ArrchQr~~~ ~~°~~ Reference: 2008 Report on Disposal Injection Operations Well Sterling Unit 43-09, Sterling Unit Dear Mr. Aubert: This annual report of disposal injection operations covers the period of January 1St 2008 through December, 31St 2008 for the Sterling Unit 43-09. Disposal via this well is governed by Disposal Injection Order (DIO) No. 25 for the Sterling Unit Gas Field (approved June 15, 2004). Attached are four plots showing injection volume, injection pressure, inner casing pressure, and outer casing pressure for this well in the calendar year 2008. Although permitted for injection of drilling mud slurries as well as other Class II production wastes, no drilling mud slurries have been injected to date in SU 43-09. The last mechanical integrity test was conducted on May 13th 2009 and the next such test is due by May 13th 2011. As shown from the attached graphs, injection volumes in 2008 were consistent with average injection rates of 17 bwpd throughout the year. A total of 6,233 bbls of fluids were injected during calendar year 2008. Currently SU 32-09, SU 41-15RD, and SU 43-9x produce the accountable fluids that are injected via SU 43-09. In early 2009, Marathon began producing more fluid out of SU 43-9X. Consequentially, injection volumes to date in 2009 have increased in comparison to those in 2008. 2008 YTD 2009 as of 6/15/09 Total In'ected Volume [bbl 6,233 49,717 Avera a In'ected Volume bw d 17 299 Sincerely, (,1.. -~~ ~choffmann Operations Superintendent Marathon Oil Company Enclosures • Disposal Well Sterling Unit 43-09 Injection Volume 1 /1 /2008 -12/31 /2008 goo .~ soo Q ~_ 500 m E 400 ° > 300 c ° 200 a~ ~~ 100 0 - -- ~ • - - - • - - - ~o~' ,~~o~ ,~~o~ ,~~oo ,~~oo ,~~o~ Date Disposal Well Sterling Unit 43-09 Injection Pressures 1 /1 /2008 -12/31 /2008 2000 1800 N 1600 °~' 1400 a~ 3 1200 tl! aNi 1000 L a 800 rn ~ 600 ~ 400 200 0 •- - - - -- - ~ ~ ~ ~ - ~ ~ • ~ ~\~~oo ~\o~\o~ o\~oo rx~~\o~ o\~o~ o\~~o~ ~\~oo o~~\oo o~~\o~ ~o\~~o~ ~~\~~o~ ~~\~~o~ Date • 500 450 400 .Q 350 d 300 L w 250 m 200 a Q 150 100 50 0 '.\~\~~ Disposal Well Sterling Unit 43-09 Inner Annulus Pressures 1 /1 /2008 -12/31 /2008 O~ O~ O~ O~ O~ O~ O~ O~ O~ O`b O`b Date Disposal Well Sterling Unit 43-09 Outer Annulus Pressures 1 /1 /2008 -12/31 /2008 50 45 40 a 35 u i 30 N 25 a 20 Q 15 -- O 10 5 _ - - -- 0 ~\~\o~ ~\~~\o~ ~\~ow ~\~\o~ ~\~o~ ~\~\o~ ~\~o~ ~\~\ow ~\~\o~ ~o\~\o~ ~~\~\o~ ~~\~\ow Date ~~~ • Alaska Asset Team U.S. Production Operations ® Marathon MARATHON Oil Company June 20, 2008 Tom Maunder AOGCC 333 West 7t" Ave, Suite 100 Anchorage, AK 99501 Reference: Report on Disposal Injection Operations Well Sterling Unit 43-9, Sterling Unit Dear Mr. Maunder: P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/565-3076 .~~1N 2 ~ ?_0!J~ Afasi4a ~ii & C~~ ons, ~o~,nii,si~r~ ~s;:aui~c;~~e This annual report of disposal injection operations covers the period of January 1St 2007 through December, 31St 2007 for the Sterling Unit (SU) #43-9. Disposal via this well is governed by Disposal Injection Order (DIO) No. 25 for the Sterling Unit Gas Field (approved June 15, 2004). Attached are four plots showing injection volume, injection pressure, inner casing pressure, and outer casing pressure for this well in the calendar year 2007. Although permitted for injection of drilling mud slurries as well as other Class II production wastes, no drilling mud slurries have been injected to date in SU 43-9. The last mechanical integrity test was conducted on June 4th 2007 and the next such test is due by June 4th 2009. A total of 17,874 bbls of fluids were injected in 2007. As shown from the attached graphs, daily injection volumes varied throughout the year. This is due partly to occasional disposal of Kenai Gas Field produced fluids (as permitted in the DIO) and added fluids production from new wells at the Sterling Unit late in the year. Later in 2008, Marathon intends to produce SU #43-9X and this well will boost SU 43-9 injection rates and frequency. Currently SU 32-9 and SU 41-15rd produce low volumes of produced fluids, contributing to long periods between injection cycles. Sincerely, A. B. Schoffmann Operations Manager Marathon Oil Company L:\Sterling\Wells\SU 43-9 Pad\Regulatory\Sterling Unit 43-9 Annual Inj Rept - 06-2008.doc Enclosures Disposal Well Sterling Unit 43-9 Injection Volume Jan 1st 2007 to December 31st 2007 0 0 v 1000 900 800 700 600 500 400 300 200 100 0 • SU 43.9 .. - .r • ------------------------------------------------------------------------------- • ~ • •- • • • • • • p1 p1 01 01 p1 p1 p1 p1 p1 p1 p1 01 p1 ,~.~ao• 0,~.~`aO' ~~a~' ~Q~Q'~' ~~a~ ~~a~ o.~~o oo~~o` OQ~~ O~e,~. ~Op~~ ~ °~~ ~Oev. 3 O ti ti ti~ ti Disposal Well Sterling Unit 43-9 Injection Pressures Jan 1st 2007 to December 31st 2007 3000 2500 2000 1500 L 1000 • SU 43-9 ---------------------------------------------------------------- ~~~• A • • y • • • • 500 0 p1 p1 ~1 ~1 p1 ~1 ~1 ~1 01 p1 p1 ~1 p1 ,`,,a'~~ ~,`,,at`~ ~~a~. ~QQ~' ,\~2~ ~~a~ ~o~JO ~o.,~?~ ~Q~a' ~~~,Q. ~~04,~. 1~oJ, ,`Qev. ~ ti ti ti ti • Disposal Well Sterling Unit 43-9 Inner Casing Pressures Jan 1st, 2007 to Decen~er 31st 2007 300 250 a~ y 200 ai N 150 i d '~ 100 v 50 0 ~O~ ~'~a • SU 43-9 Note: Constant Monitoring via SCADA system commencing in June, 2007 '1~--- ~~~~ • ~' O'~ ~1 O,~ 0~ 0~ ~1 O'~ 0~ O'~ 01 ~1 O'~ • Disposal Well Sterling Unit 43-9 Outer Casing Pressures Jan 1st, 2007 to December 31st 2007 m .~ U • SU 43.9 Note: Constant Monitoring via SCADA system commencing in September, 2007. -- - ----- - ----- ----- --ir-,t ~~~~ a~~1 10.00 9.00 8.00 7.00 6.00 5.00 4.00 3.00 2.00 1.00 0.00 '~ 1 1 1 '~ 1 1 ~~~1 ~~~ a~~ ~~~ ~~~ ~~~ ~~~ e~~ ~~~ ti~ ~~~ ~~ ~~~ ~o'~ ~~,~ ~~,P ~~5 tiro oJ~~ e~~~ ~1~ X10 • • *10 . . Alaska Asset T earn RECEIVED JUN 2 8 2007 (.M.) Marathon MARATHON Oil Company PO BOX 196168 Alaska Oil & Gas Cons. Commission Anchorage, AK 99519-6168 Anchorage Telephone 907/561-5311 Fax 907/565-3076 F~ ])10 ..;2.5 June 25, 2007 Tom Maunder AOGCC 333 West ¡th Ave, Suite 100 Anchorage, AK 99501 Reference: Report on Disposal Injection Operations Well Sterling Unit 43-9, Sterling Unit Dear Mr. Maunder: This annual report of disposal injection operations covers the period of January 15t 2006 through December, 31 5t 2006 for the Sterling Unit (SU) #43-9. Disposal via this well is governed by Disposal Injection Order (010) No. 25 for the Sterling Unit Gas Field (approved June 15,2004). Attached are three plots showing injection volume, injection pressure and casing pressure forthis well in the calendar year 2006. Although permitted for injection of drilling mud slurries as well as other Class II production wastes, no drilling mud slurries have been injected to date in SU 43-9. The last mechanical integrity test was conducted on June 4th 2006 and the next such test is due by June 4th 2008. As shown from the attached graphs, injection volumes in 2006 were sporadic; less than 300 bbls of fluids were injected last year. In 2006 surface injection pressures averaged 1190 psig, due to the low produced fluid volumes from the sole gas well producers SU #32-9 and SU #41-15. Later in 2007, Marathon intends to drill two (2) new Sterling Unit wells: SU #41-15rd and SU #43-9X. Production from these wells could possibly boost the SU 43-9 injection rates and frequency in the coming year. Sincerely, ~~r, A. B. Schoffmann Operations Superintendent Marathon Oil Company L:\Sterling\Wells\SU 43-9 Pad\Regulatory\Sterling Unit 43-9 Annuallnj Rept - 05-2007.doc Enclosures 50 45 40 "'C c.. 3t 35 .c CD 30 s::::::: E :::s 25 - 0 :> 20 s::::::: 0 ....... 15 u CD o- s::::::: 10 5 0 ------- - - - - -- ----- ------ ------- - - - -- -- ~C() ~C() ro..C() ~ ~ ~'-J ~\~ ~~\~ f't;~~ Disposal Well Sterling Unit 43..9 Injection Volume Jan 1 st 2006 to December 31 st 2006 ------- -------- ----- ------ - - - - - - - - - . SU 43-9 ----- ------ --------- ------- -.----- -------- - - -- - - - - - - - - - ------ ------- ------ ------- ----------- --------- - - - - - - - - - - ------- - - - - - - - - - - - - - - - - - - - . . . . -- - - - -- - - - - -- -- -- - - - ------------- . . . ------- -------- - - . ----- ~ ~ ~ Þ F ~ ~ ~ ~ # ~ ~ ~ $ ~ ~ ~ ~ ~ ~ ~~ ~~~ ..~~ ~~ f'l..f::::; ro..~ ~"';J ~ A;;;:" (\N ~... ~ ;J ~ ~ ~ C),,' ~ 1600 1400 1200 æ UJ c.. ( ) 1000 .... :::s UJ UJ 800 ( ) ..... a.. s::: 0 600 ..... (.) ( ) o- s::: 400 200 Disposal Well Sterling Unit 43..9 Injection Pressures Jan 1st 2006 to December 31st 2006 ~ ~f\S ~~~ - - . SU 43-9 . . ----- -.----- ----- ----- ------ ----- ----- o S;)«) S;)«) f$ f$ ~~~ 'S~~ ~ ----- ----- -- - - - .- -. - - - - - .- ----- Þ ft ft $ # ~ ~ # þ p~ ~' ..."fb,.... ~.... .;:;." ~~ ..:::;.~ 'i::Jõ~ Ç)v ~ e'V ~ ~ ~ ¥ ~ ~ ~ ~ ¢ ~ en en c.. ( ) ... :::s en en ( ) ... c... en s::: en CI3 (.) 300 250 -.. 200 150 100 50 o S;)<O S;)I(:) ~ ~ ~~fti. ~~fti. ~ Disposal Well Sterling Unit 43-9 Casing Pressures Jan 1st, 2006 to December 31st 2006 ~~<o ~~fti. ------ .. --.---- . ~ ~ ~ þ ~ ~ ~ ~ ? # ~ ~ ~ ~. ~ ~ # ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ¢ ~ #9 e e Marathon Oil Company Alaska Asset Team Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/565-3076 June 1,2006 RECEIVED JUN 0 9 2006 Alaska Oil & Gas Cons. Corrmission ~. . Anchorage Winton Aubert State of Alaska Alaska Oil & Gas Conservation Commission 333 West ¡th Ave, Suite 100 Anchorage, AK 99501 Reference: Field: Well: 010 No. 25 Sterling Unit Gas Field Sterling Unit No. 43-9 Well Dear Mr. Aubert Enclosed please find documentation to fulfill requirements of Disposal Injection Order Number 25 for the Sterling Unit Gas Field, Sterling Unit Number 43-9 Well. This annual report of disposal operations covers the period of January 1, 2006 through June 1, 2006 Attached is a plot showing injection volume and injection pressure for this well in the calendar years 2004 -2006. Injection into SU #43-9 began on February 1, 2004 As shown from the attached graph, Injection was sparse in 2006, due to the low produced fluid volumes from the sole gas well producer SU #32-9. Average surface injection pressure for SU #43-9 in 2006 was about 1500 psig. Should you require further information, please contact John Ozcan at 713-296- 2388 or bye-mail atHozcan@MarathonOil.com. ø~ David Brimberry ABU Subsurface Team leader Enclosures: Monthly Injection Data 350 ò FIGURE 1 STERLING UNIT WELL 43-09 Historical Injection Rates and Pressures 300 -~~--~ .~--.~~--_. --- ..~~__~.._~__m_ . ____~___m__________~ __......__~___~m__.__~______~ ~--...--.._-----~--- --+- Injection rate --+- Casing Pressure Tubing Pressure 250 --- c a.. III ~ 200 -- « I:t: :z o ¡:: 150 (.) w ., :z - ~ ~ _~'m.,_._____··_~~__________,__·.,...__.._._______.._______,...___._~__,_...__________.,.._..____._,_ - ____._,......_._____.____,_____._._._~___....______________'__m___ ~<P .. ~ þ. .«{ : .~. þ " +- I 4'> ... 'f'It' 100 -- 50 o 1/14/2004 ,... . .. ~ . <P_____ . .. ~ ... ~ .. 0. 4'It 4 þ{ þ ~. '\ 1, ___.m......_______,__.___n_m 2500 2000 -- 1500 U) D.. W œ: :::J U) U) w - 1000 g: - 500 o 7/2/2006 #8 ) I rID ~ ~r' (i\ ~=;i:J ,i¡""! <~>,i f\ \ J ,II J;:J :~ù"', \ ,! .J-.-l\ \1 'II:! \,.;;...) J Uw U l..'::! (-, t~ :1(')1'1'¡ " .1· :1" , i- ~ 1 --.I 'WI'I'!i :,\.U,',!,! :.~ ' :~ (~ ',-1 j ¡ I , ¡ .¡ :~ .~, ~': ì;"\ ! ./;\ ',~\ /IJ \ LJ~"U~ FRANK H. MURKOWSKI, GOVERNOR '. '\. r~¡.J1 "...'.J 333 W. 7fH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 AIfASBA. OIL AND GAS CONSERVATION COMMISSION September 27, 2004 Proposals to Amend Underground Injection Orders to Incorporate Consistent Language Addressing the Mechanical Integrity of Wells The Alaska Oil and Gas Conservation Commission ("Commission"), on its own motion, proposes to amend the rules addressing mechanical integrity of wells in all existing area injection orders, storage injection orders, enhanced recovery injection orders, and disposal injection orders. There are numerous different versions of wording used for each of the rules that create confusion and inconsistent implementation of well integrity requirements for injection wells when pressure communication or leakage is indicated. In several injection orders, there are no rules addressing requirements for notification and well disposition when a well integrity failure is identified. Wording used for the administrative approval rule in injection orders is similarly inconsistent. The Commission proposes these three rules as replacements in all injection orders: Demonstration of Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (except at least once every two years in the case of a slurry injection well), and before returning a well to service following a workover affecting mechanical integrity. Unless an alternate means is approved by the Commission, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30 minute period. The Commission must be notified at least 24 hours in advance to enable a representative to witness mechanical integrity tests. Well Integrity Failure and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval. The operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the Commission. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. The following table identifies the specific rules affected by the rewrite. Injection Order "Demonstration of Mechanical Integrity" Affected Rules "Well Integrity Failure and Confinement" "Administrative Action" Area InJection Orders AIO 1 - Duck Island Unit AIO 2B - Kuparuk River Unit; Kuparuk River, Tabasco, Ugnu, West Sak Fields AIO 3 - Prudhoe Bay Unit; Western Operating Area AIO 4C - Prudhoe Bay Unit; Eastern Operating Area AIO 5 - Trading Bay Unit; McArthur River Field AIO 6 - Granite Point Field; Northern Portion AIO 7 - Middle Ground Shoal; Northern Portion AIO 8 - Middle Ground Shoal; Southern Portion AIO 9 - Middle Ground Shoal; Central Portion AIO lOB - Milne Point Unit; Schrader Bluff, Sag River, Kuparuk River Pools AIO 11 - Granite Point Field; Southern Portion AIO 12 - Trading Bay Field; Southern Portion AIO 13A - Swanson River Unit AIO 14A - Prudhoe Bay Unit; Niakuk Oil Pool AIO 15 - West McArthur 6 7 9 6 7 9 6 7 9 6 7 9 6 6 9 6 7 9 6 7 9 6 7 9 6 7 9 4 5 8 5 6 8 5 6 8 6 7 9 4 5 8 5 6 9 ) ,) / Affected Rules "Demonstration of "Well Integrity "Administrative Injection Order Mechanical Failure and Action" Integrity" Confinement" River Unit Ala 16 - Kuparuk River 6 7 10 Unit; Tarn Oil Pool 6 8 Ala 17 - Badami Unit 5 Ala 18A - Colville River 6 7 11 Unit; Alpine Oil Pool Ala 19 - Duck Island Unit; 5 6 9 Eider Oil Pool Ala 20 - Prudhoe Bay Unit; 5 6 9 Midnight Sun Oil Pool AIO 21 - Kuparuk River 4 No rule 6 Unit; Meltwater Oil Pool AIO 22C - Prudhoe Bay 5 No rule 8 Unit; Aurora Oil Pool 6 9 AIO 23 - Northstar Unit 5 AIO 24 - Prudhoe Bay Unit; 5 No rule 9 Borealis Oil Poo I AIO 25 - Prudhoe Bay Unit; 6 8 13 Polaris Oil Pool AIO 26 - Prudhoe Bay Unit; 6 No rule 13 Orion Oil Pool Disposal Injection Orders DIO 1 - Kenai Unit; KU No rule No rule No rule WD-l DIO 2 - Kenai Unit; KU 14- No rule No rule No rule 4 DIO 3 - Beluga River Gas No rule No rule No rule Field; BR WD-l DIO 4 - Beaver Creek Unit; No rule No rule No rule BC-2 DIO 5 - Barrow Gas Field; No rule No rule No rule South Barrow #5 DIO 6 - Lewis River Gas No rule No rule 3 Field; WD-l DIO 7 - West McArthur 2 3 5 River Unit; WMRU D-l DIO 8 - Beaver Creek Unit; 2 3 5 BC-3 DIO 9 - Kenai Unit; KU 11- 2 3 4 17 DIO 10- Granite Point 2 3 5 Field; GP 44-11 Affected Rules "Demonstration of "Well Integrity "Administrati ve Injection Order Mechanical Fail ure and Action" Integrity" Confinement" DIO 11 - Kenai Unit; KU 2 3 4 24-7 ora 12- Badami Unit; WD- 2 3 5 1, WD-2 010 13 - North Trading Bay 2 3 6 Unit; S-4 ora 14 - Houston Gas 2 3 5 Field; Well #3 010 15 - North Trading Bay 2 3 Rule not numbered Unit; S-5 010 16 - West McArthur 2 3 5 River Unit; WMRU 4D DIO 17 - North Cook Inlet 2 3 6 Unit; NCill A-12 010 19 - Granite Point 6 Field; W. Granite Point State 3 4 17587 #3 oro 20 - Pioneer Unit; Well 3 4 6 1702-150A wow ora 21 - Flaxman Island; 3 4 7 Alaska State A - 2 DIO 22 - Redoubt Unit; RU 3 No rule 6 Dl oro 23 - Ivan River Unit; No rule No rule 6 IRU 14-31 010 24 - Nicolai Creek Order exp ired Unit; NCU #5 oro 25 - Sterling Unit; SU 3 4 7 43-9 DIO 26 - Kustatan Field; 3 4 7 KFl Storage Injection Orders SIO 1 - Prudhoe Bay Unit, No rule No rule No rule Point McIntyre Field #6 S10 2A- Swanson River 2 No rule 6 Unit; KGSF # 1 S10 3 - Swanson River Unit; 2 No rule 7 KGSF #2 Enhanced Recovery Injection Orders Era 1 - Prudhoe Bay Unit; No rule 8 Prudhoe Bay Field, Schrader No rule Bluff Formation Well V-I05 Injection Order BIO 2 - Redoubt Unit; RU-6 ) "Demonstration of Mechanical Integrity" 5 ) / Affected Rules "Well Integrity Failure and Confinement" 8 "Administrati ve Action" 9 I 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO,FRM STATE OF ALASKA ADVERTISING ORDER SEe,$OTTOM FOR',INVCJlC:E Ä[)I)RESS NOTICE TO PUBLISHER ADVERTISING ORDER NO. INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO, CERTIFIED AO-02514016 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COpy OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE F AOGCC 333 West th Avenue, Suite 100 Plnchorage,AJe 99501 907-793-1221 AGENCY CONTACT DATE OF A.O. R o M lady {:olamhie September 77, 2004 PHONE PCI\J (907) 793 -1 771 DA TES ADVERTISEMENT REQUIRED: T o Journal of Commerce 301 Arctic Slope Ave #350 Anchorage, AK 99518 October 3, 2004 THE MATERIAL BETWEEN THE DOUBLE LINES M{)ST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: United states of America AFFIDAVIT OF PUBLICATION REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER A CERTIFIED COpy OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. ATTACH PROOF OF PUBLICATION HERE. division. Before me, the undersigned, a notary public this day personally appeared who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2004, and thereafter for _ consecutive days, the last publication appearing on the _ day of , 2004, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This _ day of 2004, Notary public for state of My commission expires Public Notices ) ) / 10f2 9/29/2004 1: 10 PM Public Notices <scott.cranswick@n1ffis.goV>, Brad McKim <mckimbs@BP.com> PJ..~ëtse find the attached Notice and Attachment for the pro1?o~ed amendment of tlIlderground injection orders and the Public Notice Happy Valley #10. Jody Colombie ! ... .. .... . ... . .. ... . . . i Cqutent- Type: application/msword i MechanIcal. IntegrIty proposal.doc : ......... .. ... .. .... ...... . t.. . 6..1.·.. . 'Content-Enco<img: uase ~ \".." jContent--Type: appIication/1hswo#d Mechanical.Irifegrity of Wells Notice.doc; . ........ ...... ................ ·····b 6·· I Content-Enco(jing: .. ase 4 I Content-Type: application/msword HappyV aUeyl0 _ HearingNotice.doc ¡' C()n.tent-Eµco~~:·hase64 . , .. .'.' ..~. '.~.. ,," -, .._~ ",""" ',".' ".~~ ...." '....",."_._"-~~ "~'....¥," "..' "~'--'~" ..-.....- . .., .'.-" ,., ...~".. , . ..... _...~"..".~... ... '......... .".-.,". ..~....,-,..... ...".... ,"". . .- '"' ~...,.,,,._.,,.. ~_.~....,...'-. ,,~~-,--'.."~ . ..~..."."...~.'.,..,,--,-_._" ,,---... . 2 of 2 9/29/2004 1: 10 PM · Public Notice ) ) / Subject: Public Notice From: Jody Colombie <jody_colombie@admin.state.ak.us> Date: Wed, 29 Sep2004 12:55:26 -0800 tø:·..·leg~l@~l~~~åjÓ,~~.cøtn Please publish the attached Notice on October 3, 2004. Thank you. Jody Colombie Content-Type: applicationlmsword . Mechanical Integrity of Wells Notice.doc Content-Encoding: base64 Content-Type: applicationJmsword Ad Order form.doc Content-Encoding: base64 1 of 1 9/29/2004 1: 10 PM Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 /'1cZlk:d ItJ/~~ David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Kelly Valadez Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 John Levorsen 200 North 3rd Street, #1202 Boise, ID 83702 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 David Cusato 200 West 34th PMB 411 Anchorage, AK 99503 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 Jack Hakkila PO Box 190083 Anchorage, AK 9951 9 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 James Gibbs PO Box 1597 Soldotna, AK 99669 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 North Slope Borough PO Box 69 Barrow, AK 99723 [Fwd: Re: Consistent Wording for Injection :þrs - Well Integrity ... ) ~ubject:[Fwd: Re: CotlsisteIltWor~in&for ~j~çtiotlOrder~ ..Well wt¢$fi!y'(R.~viseg)J F......r....:...o..m.,.·. :. J. 0. hn No. Im.' .an...... .. <.. J.·.·.o.... 00......:' ... n.... 0.:: nD....:..... an.· : :@.....:.. .acimin..s.·. tate.ak:.us. > Date: Fri, 01()ct20041I:ó9:26~0800 To: Jody JColo1!lbie <j~4Y ~q~~Öt%.&i~@~cii:nih.~tåt~.4l<~:uS? more -------- Original Message -------- Subject:Re: Consistent Wording for Injection Orders - Well Integrity (Revised) Date:Wed, 25 Aug 2004 16:49:40 -0800 From:Rob Mintz <robert l11intz(ã)law.state.ak.us> To:jim regg(ã)admin.state.ak.us CC :dan seamount(â}admin.state.ak. us, john nOffilan@admin.state.ak. us Jim, looks good, but I still think maybe it would be good to include the following sentence or something like it in the well integrity and confinement rule: "The operator shall shut in the well if so directed by the Commission." My thinking is that otherwise, an operator might argue that the Commission can only require the well to be shut in by going through an enforcement action, issuing an order after notice and opportunity for hearing, or meeting the strict requirements for an emergency order under the regulations. The proposed language makes clear that it is a condition of the authorization to inject, that the operator must shut in the well if directed by the Commission after a notification of loss of integrity, etc. »> James Regg ~jim regg@admin.state.ak.us> 8/25/2004 3: 15:06 PM »> Rob - Thanks for the review; here's a redraft after considering your comments. I have accepted most of the suggested edits; also attached is response to questions you pose (responses are embedded in the comments, using brackets [JBR - ...J to set apart from your questions). Jim Regg Rob Mintz wrote: Jim, I have some questions about the draft language, which are shown as comments on the first document attached. Based on my current guesses about what the answers will be to my questions, I also have some suggested edits, which are shown as redlines on the second document attached. »> James Regg <jim regg@admin.state.ak.us> 8/17/20044:33:52 PM »> Please delete previous version (email sent 8/9/04); I found another inconsistency in the injection orders regarding well integrity that I have integrated into the proposed fix. Attached is a proposal for consistent language in our injection orders addressing 3 rules related to well integrity: - "Demonstration of Tubing/Casing Annulus Mechanical Integrity" - "Well Integrity Failure" - "Administrative Actions". This proposal includes input from all Sr. staff (except Jack). If you agree with the approach, I'll work with Jody to prepare the public notice. Main points - Demonstration of Tubing/Casing Annulus Mechanical Integrity - standardizes the wording used for mechanical integrity demonstrations, and establishes abililty to grant alternate methods (e.g., temp survey, logging, pressure monitoring in lieu of pressure testing 10f2 10/2/2004 4:07 PM [Fwd: Re: Consistent Wording for Injection .~rs - \Vell Integrity ... - specific to AIO 2C for Kuparuk, there is wording that is more appropriately included in Well Integrity Failure (i.e., more frequent MITs when communication demonstrated) - establishes more frequent MIT schedule for slurry injection wells (every 2 yrs) which is consistent with our current practice (but not addressed in regulations) Well Integrity Failure - retitles to "Well Integrity Failure and Confinement"; inserted language regarding injection zone integrity (see DIO 25 and 26) - consistent language regardless of type of injection (disposal, EOR, storage); - eliminates requirement for immediate shut in and secure; allows continued injection until Commission requires shut in if there is no threat to freshwater; - eliminates delay in notifying Commission after detect leakage or communication ("i.e., "immediately notify"); - removes language about notifying "other state and federal" agencies; - requires submittal of corrective action plan via 10-403; - requires monthly report of daily injection rate and pressures (tubing and all casing annuli); this is a requirement we currently impose when notified of leak or pressure communication; - notice and action not restricted to leaks above casing shoe as stated in several DIOs Administrative Actions - adopts" Administrative Actions" title (earlier rules used" Administrative Relief"); - consistent language regardless of type of injection (disposal, EOR, storage); - uses "administratively waive or amend" in lieu of terms like "revise", "reissue", etc.; - adds geoscience to "sound engineering principles"; - language is more generic regarding fluid movement out of zone; existing versions mention varying combinations of protecting "freshwater", "aquifers", "USDWs"; "risk of fluid movement"; "fluid escape from disposal zone" Jim Regg John K. Norman <John Norman@admin.state.us> Commissioner Alaska Oil & Gas Conservation Commission 20f2 10/2/20044:07 PM [Fwd: Re: Consistent Wording for Injection )rs - Well Integrity... ) ~ubject: [Fwd: Re: ConsistentW ording for Injëction Orders ~ Well Ih:tegrity (R.evis~d)] From: John Nonnan <jºhri~norrnan@admiIl~state.ak:.tls> Dåte: 01 Oct 2004 11:08:55 -0800 please print all and put in file for me to review just prior to hearing on these amendments. thanx -------- Original Message -------- Subject:Re: Consistent Wording for Injection Orders - Well Integrity (Revised) Date:Thu, 19 Aug 2004 15:46:31 -0800 From:Rob Mintz <robert mintz@law.state.ak.us> To:dan seamount@admin.state.ak.us, jim regg@admin.state.ak.us, john norman@admin.state.ak.us Jim, I have some questions about the draft language, which are shown as comments on the first document attached. Based on my current guesses about what the answers will be to my questions, I also have some suggested edits, which are shown as redlines on the second document attached. »> James Regg <jim regg@admin.state.ak.us> 81l7/2004 4:33:52 PM »> Please delete previous version (email sent 8/9/04); I found another inconsistency in the injection orders regarding well integrity that I have integrated into the proposed fix. Attached is a proposal for consistent language in our injection orders addressing 3 rules related to well integrity: - "Demonstration of Tubing/Casing Annulus Mechanical Integrity" - "Well Integrity Failure" - "Administrative Actions". This proposal includes input from all Sr. staff (except Jack). If you agree with the approach, I'll work with Jody to prepare the public notice. Main points - Demonstration of Tubing/Casing Annulus Mechanical Integrity - standardizes the wording used for mechanical integrity demonstrations, and establishes abililty to grant alternate methods (e.g., temp survey, logging, pressure monitoring in lieu of pressure testing - specific to AIO 2C for Kuparuk, there is wording that is more appropriately included in Well Integrity Failure (Le., more frequent MITs when communication demonstrated) - establishes more frequent MIT schedule for slurry injection wells (every 2 yrs) which is consistent with our current practice (but not addressed in regulations) Well Integrity Failure - retitles to "Well Integrity Failure and Confinement"; inserted language regarding injection zone integrity (see DIO 25 and 26) - consistent language regardless of type of injection (disposal, EOR, storage); - eliminates requirement for immediate shut in and secure; allows continued injection until Commission requires shut in if there is no threat to freshwater; - eliminates delay in notifying Commission after detect leakage or communication ("i.e., "immediately notify"); - removes language about notifying "other state and federal" agencies; - requires submittal of corrective action plan via 10-403; - requires monthly report of daily injection rate and pressures (tubing and all casing annuli); this is a requirement we currently impose when notified of leak or pressure communication; - notice and action not restricted to leaks above casing shoe as stated in several DIOs Administrative Actions 1 of2 10/2/20044:07 PM [Fwd: Re: Consistent Wording for [njection rs - vV' ell [ntegrity ... - adopts "Administrative Actions" title (earlier rules used "Administrative Reliet"); - consistent language regardless of type of injection (disposal, EOR, storage); - uses "administratively waive or amend" in lieu oftenns like "revise", "reissue", etc.; - adds geoscience to "sound engineering principles"; - language is more generic regarding fluid movement out of zone; existing versions mention varying combinations of protecting "freshwater", "aquifers", "USDWs"; "risk of fluid movement"; "fluid escape from disposal zone" Jim Regg ; 10hnK. Nonnan <lohn Norman@admin.state.us> Commissioner Alaska Oil & Gas Conservation Commission Content-Type: applicationlmsword Injection Order language - questions. doc Content-Encoding: base64 Content-Type: app licationlmsword Injection Orders language edits.doc Content-Encoding: base64 20f2 10/2/2004 4:07 PM ) ) Standardized Language for Injection Orders Date: August 17, 2004 Author: Jim Regg Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, after a workover affecting mechanical integrity, and at least once every 4 years while actively injecting. For slurry injection wells, the tubing/casing annulus must be tested for mechanical integrity every 2 years. The MIT surface pressure must be 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, must show stabilizing pressure and may not change more than 10% during a 30 minute period. Any alternate means of demonstrating mechanical integrity must be approved by the Commission. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Well Integrity Failure and Confinement The tubing, casing and packer of an injection well must demonstrate integrity during operation. The operator must immediately notify the Commission and submit a plan of corrective action on Form 10-403 for Commission approval whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, or log. If there is no threat to freshwater, injection may continue until the Commission requires the well to be shut in or secured. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating pressure communication or leakage. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. Standardized Language for Injection Orders Date: August 17, 2004 Author: Jim Regg Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, at least once e'very four years thereaft~r (~xcept at least onc~ every two years in the case of a slurry injection \vcll), and before rcturnin,g a Vi/cìl to service fo!h.)\vin.Q: a.ft€.f a workover affecting mechanical integrity, and at least once every ,1 year~; while actively injecting. .For slurry injection \vells, th;; tubing/casing anl1ulw; tTIust bè te:stèd for mechanical integrity every 2 years. Unless an alternate lTIeaJ.1S is approved by the COlnn1ission, Inechanical integrity ITIUst be demonstrated by a tubin.Q: pressure test using a +fl..e MI+-surface pressure ofnlust be 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, that ffiH5-t-show~ stabilizing pressure that does::md 111ay not change more than 1 O~ percent during a 30 minute period. --:AH-ÿ altenlate nlcans of dernonstrating 111cchanÌcal integrity mu~~t be approved by the COl11.illission. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Welllntegrity Failure and Confinement Except as othenvíse provided in this rule, +!he tubing, casing and packer of an injection well must demonstrate ¡naintain integyity during operation. \Vhenever any pressure conlffiunication, leakage or lack of injection zone isolation is indicated by injection rate~ operating pressure observation, test, survey, log, or other evidence. t+he operatorffiì±St-shall immediately notify the Commission and submit a plan of corrective action on a Fonn 10-403 for Commission approval.: v;henever any pressure COlTIlnurÜcatiol1, leakage or lack of injection lone i~;olation is indicated by injection rate. operating pressure observation, test, survey, or log. The operator shall shut in the well if so directed bv the COlll111Ìssion. The operator shaU shut in the '.yell \vithout a\vaitin,g a response tì-orn the Comn1ission if continued operation \vould be unsafe or would threaten contamination of freshwaterIf there is no threat to fresl1\vater~ injection lnay continue until the COlìlln.ìssion requires the v:ell to be shut in or secured. Until corrective action is successfully cOlnplctcd, Aª monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating pressure communication or leakage. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. .. ~ [Fwd: Re: [Fwd: AOGCC Proposed WI Lan } for Injectors]] ) ~llbJect: [Fwd: Re: [Fwd: AOGCCProposed WI Language for Injectors]] From: Winton Aubert <winto~aubert@adrnin.state.ak.us> ~;~1~~.:1'~tl,1~qf:t3°?1R?:1~:?3~P§?q·. ....... ...... .......................... ....... lo.:;.J()c:lr JÇ()I,()rnJ~íe·:6ipªyS~Q}oÌr1bi~@að~in~$~(lt~~a.16tl~>·· .'. ". This is part of the record for the Nov. 4 hearing. WGA -------- Original Message -------- Subject: Re: [Fwd: AOGCC Proposed WI Language for Injectors] Date: Thu, 28 Oct 2004 09:41:55 -0800 From: James Regg <jim regg@admin.state.ak.us> Organization: State of Alaska To: Winton Aubert <winton aubert@admin.state.ak.us> References: <41812422.8080604@admin.state.ak.us> These should be provided to Jody as part of public review record Jim Winton Aubert wrote: FYI. -------- Original Message -------- AOGCC Proposed WI Language for Tue, 19 Oct 2004 13:49:33 -0800 Engel, Harry R <EngeIHR@BP.com> winton aubert@admin.state.ak.us Injectors Subject: Date: From: To: Winton... Here are the comments we discussed. Harry *From: * NSU, ADW Well Integrity Engineer *Sent: * Friday, October 15, 2004 10:43 PM *To: * Rossberg, R Steven; Engel, Harry R; Cismoski, Doug A; NSU, ADW Well Operations Supervisor *Cc: * Mielke, Robert L.; Reeves, Donald F; Dube, Anna T; NSU, ADW Well Integrity Engineer *Subject: * AOGCC Proposed WI Language for Injectors Hi Guys. John McMullen sent this to us, it's an order proposed by the AOGCC to replace the well integrity related language in the current Area Injection Orders. Listed below are comments, not sure who is coordinating getting these in front of Winton/Jim. Overall, looks okay from an Operations perspective. We do have a few comments, but could live with the current proposed language. Note the proposed public hearing date is November 4. ! The following language does not reflect what the slope AOGCC inspectors are I currently requiring us to do: "The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (except at least once every two years in the case of a slurry injection well), and * before* ** 1 of 3 10/28/2004 11 :09 AM [Fwd: Re: [Fwd: AOGCC Proposed WI Lan/:. : for Injectors]] returnj_ng a well to service following a workover affecting mechanical integrity." After a workover, the slope AOGCC inspectors want the well warmed up and on stable injection, then we conduct the AOGCC witnessed MITIA. This language requires the AOGCC witnessed MITIA before starting injection, which we are doing on the rig after the tubing is run. Just trying to keep language consistent with the field practice. If "after" was substituted for "before", it would reflect current AOGCC practices. It would be helpful if the following language required reporting by the "next working day" rather than "immediately", due to weekends, holidays, etc. We like to confer with the APE and get a plan finalized, this may prevent us from doing all the investigating we like to do before talking with the AOGCC. "Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall * immediately*_** notify the Commission" This section could use some help/wordsmithing: "A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation." Report content requirements are clear, but it's a little unclear what triggers a well to be included on this monthly report. Is it wells that have been reported to the AOGCC, are currently on-line and are going through the Administrative Action process? A proposed re-write would be: "All active injection wells with well integrity failure or lack of injection zone isolation shall have the following information reported monthly to the Commission: daily tubing and casing annuli pressures, daily injection rates." Requirements for the period between when a well failure is reported and when an administrative action is approved are unclear. This document states "the operator shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403". If we don't plan to do any corrective action, but to pursue an AA, does a 10-403 need to be submitted? The AOGCC has stated they don't consider an AA as "corrective action". Let me know if you have any questions. Joe -----Original Message----- From: Kleppin, Daryl J Sent: Wednesday, September 29, 2004 1:37 PM To: Townsend, Monte A¡ Digert, Scott Ai Denis, John R (ANC); Miller, Mike E¡ McMullen, John C Subject: FW: Public Notices FYI -----Original Message----- From: Jody Colombie [ mailto:jody colombie@admin.state.ak.us Sent: Wednesday, September 29, 2004 1:01 PM Subject: Public Notices Please find the attached Notice and Attachment for the proposed amendment of underground injection orders and the Public Notice Happy Valley #10. Jody Colombie «Mechanical Integrity proposal. ZIP» «Mechanical Integrity of Wells Notice.doc» 2 of3 10/28/2004 11 :09 AM #7 . #A.) Marathon ',MARATHON Oil Company . Alaska Region Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 April 30, 2004 Jim Regg State of Alaska Alaska Oil & Gas Conservation Commission 333 West ih Ave, Suite 100 Anchorage, AK 99501 Reference: Field: Well: DID No. 25 Sterling Unit Gas Field Sterling Unit No. 43-9 Well RECEIVED MAY 2 0 2004 Alaska Oil & Gas Cons. Commission Anchorage Dear Mr. Regg Enclosed please find documentation to fulfill requirements of Disposal Injection Order Number 25 for the Sterling Unit Gas Field, Sterling Unit Number 43-9 Well. A 10-404 Report of Sundry Operations is also included. Attachments include an initial Report of Operations, Step Rate Test and a baseline temperature survey which was performed February 25, 2000. A mechanical integrity test verified mechanical reliability of the casing-tubing annulus and was witnessed by Jeff Jones of the AOGCC on March 5, 2004. Should you require the data electronically or need further information, I can be reached at 907-283-1337 or bye-mail atDEEynon@MarathonOil.com. Sincerely, ~,N~ Donald Eynon Operations Engineer Enclosures: Report of Operations Temp-Press Survey Step Rate Test Results . Report of Operations: . Injection Facility: The injection facility construction was completed in late January 2004 with a final check out performed on the injection equipment January 30th, 2004. Safety features on the equipment include high / low pressure discharge alarm set points at the injection skid and tubing and casing pressure alarm set points. The alarms are present to notify personnel at our operations center on Kalifornsky Beach Road in the Kenai Gas Field (KGF). The KGF facility is manned 24 hours a day with performing gas well and pipeline surveillance ready respond to alarms. Anyone of the injection facility alarms will shut down the water injection pump and render it inoperable until the alarms are reset. A mechanical relief valve on the pump discharge is set to release at 2800 psi with injection fluid returning into the injection supply tank. The injection supply tank is a double walled 200 bbl tank inline with a 70 bbl suction tank equipped with low and high level switches. The system is automated to start and stop the injection equipment when the tank level reaches predetermined levels. On a typical day the unit will cycle through six injection periods as the produced water tank volume increases with daily production until the tank reaches a high level switch to start the injection equipment. As produced fluid is injectect the tank level lowers until reaching the low level shut down switch, at which time the production-injection cycle starts over. Injection Summary Injection operations began February 2nd, 2004 after a step rate test was conducted on January 30th, 2004. Unfortunately, communication to our historical database through our SCADA system was not functioning properly and the step rate data was lost. As a result the Step Rate Test was re-ran February 4th, 2004 with the data being stored successfully. The average daily injection volume for the first month was 173 bwpd, at a maximum well head pressure of 2090 psi. The maximum volume of produced water injected daily was 390 bbls with a minimum of 93 bbls. Injection equipment is set to start up at a daily rate of 880 bwpd. During the first month of operation 5,200 barrels of produced water was injected. MIT Test A Mechanical Integrity Test was performed on March 5th, 2004 with Jeff Jones of the AOGCC present as a witness. The casing was pressured to 1535 psi and held for 30 minutes. No communication to the tubing casing annulus has been observed during injection operations. step Unit Gas speed drive .19, .41, .58 and in 1. on 4, 2004, produced water for the test. A positive displacement pump to establish injection rates. pressure and rate versus 2000.00 1800.00 1600.00 ( 1400.00 ... ::3 III III 1200.00 ( ... - 0. .~ 1000.00 S 800.00 800.00 400.00 200.00 0.00 12:08:38 SU 43-9 Step Rate Test ···-0.9 __ _ __w______·m~ w__ 0.7 0.6 0.4 0.2 J.- 0.1 12:23:02 13:20:38 12:51:50 13:08:14 12:37:26 TIME (hrs:min:sec) - Casing Pressure -Injection Rate 1: Pressure and Rate versus casing the 2 3/8" 30.8 Baseline A Survey on date. and log survey was logged prior to performing 2000.00 U 43-9 Step Rate Test 1800.00 1600.00 1200.00 1000.00 800.00 600.00 400.00 200.00 0.00 _ ",,:_ r 0.9 0.8 0.7 0.6 0.5 0.1 o I SU 43...9 Step Rate Test 2500.00 2250.00 2000.00 11825 psi 1750.00 e- ~ ~ 1500.00 !I)~ e ~ Q. !I) 1250.00 c- o ~ ;.~ () !I) .~ Q. 1000.00 C- 750.00 500.00 250.00 0.00 o 0.1 0.3 0.4 0.5 0.6 0.7 0.8 - #6 :L~ n J' tÆ l1,u fÆ , AI/ASKA. OIL AND GAS CONSERVATION COMMISSION FRANK H. MURKOWSKI, GOVERNOR March 17, 2003 333 W. "JT" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Tim Hamlin Ground Water Protection Unit US EPA Region 10 1200 Sixth Avenue, OW-137 Seattle, WA 98101 Dear Mr. Hamlin: The Alaska Oil and Gas Conservation Commission ("Commission") is in receipt of your letter dated March 10, 2003 stating that an aquifer exemption below 1750 MD feet in the Sterling Unit 43-9 well was a minor modification of the Commission's program for the regulation of Class II injection wells under section 1425 of the Safe Drinking Water Act, as defined by Underground Injection Control (UIC) Program Guidance 34 and 40 CFR 145.32. In correspondence dated February 25, 2003 from Mr. Robert Crandall of this office to Mr. Thor Cutler in the Ground Water Protection Unit the Commission's critique of Marathon's application for aquifer exemption was presented. This document stated that while aquifers with salinities less than 3,000 ppm are present at depth in the 43-9 well, they are "situated at a depth or location that makes recovery of water for drinking purposes economically or technologically impractical". The Commission's analysis of this well did not specifically reference the distribution of gas other than in the currently perforated B-4 gas sand. This may be a minor point but to paraphrase your March 10, 2003 letter you imply that I have concluded that aquifers below 1750' MD in the 43-9 well contain natural gas. I'd like to clarify this point. Sporadic gas shows are present in a number of sands below 1750' MD and the top of the B-4 producing interval in the 43-9 well. This gas while common is not ubiquitous. We appreciate your concurrence and will issue this aquifer exemption using procedures described in 20 MC 25.440. ~~ Daniel T. Seamount Commissioner RC\DTS\ijc #5 ~ViÐ8tt~ . ft· is\ \"""L PR01f.V) UNITE~TESENVIRONMENTALPROTECTIO~NCY REGION 10 1200 Sixth Avenue Seattle. WA 981 01 RECEIVED Reply To Attn Of: OW-137 March 10, 2003 MAR 1 7 20û3 AIaaka or¡ & Gas Cons. Commìseìon Anchorage Mr. Daniel Seamount, Commissioner Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue, Suite 100 Anchorage, Alaska 99501 RE: Request for an Aquifer Exemption for the Sterling Unit 43-9 well, Sterling Gas Field Unit, Kenai Peninsula, Alaska - Seward Meridian, T5N, RIOW, Section 9. Dear Mr. Seamount: My staff has reviewed the application by Marathon Oil Company for an Aquifer Exemption of the Sterling Formation below 5000 feet measured depth (MD) in the vicinity of the Sterling Unit 43-9 Well in the on the Kenai Peninsula near Kenai, Alaska. The Alaska Oil and Gas Conservation Commission (AOGCC) permitted Class II disposal well is 10cated in Section 9, T5N, RlOW, Kenai Borough, Alaska. The Sterling 43-9 Well will be used to dispose of Class II oilfield waste fluids. As you know, aquifer exemptions are limited to only those areas related to a specific permit and for the intervals needed for injection. We understand that the injection will occur at approximately 1750 to 5000 feet MD. Injection will be into the Sterling Formation below a depth of 1750 feet MD and the injected fluids are to remain below that depth. Your íÏndings and our review indicate the Sterling Formation in the vicinity of the well contains fluids with a total dissolved solids (TDS) content of over 10,000 to 16,000 10,000 mglliter at depths exceeding 1,750 MD and contains zones that range from 16,000 to approximately 2000 mglliter with gas shows to depths of 5000 MD. The applicant has supplied information indicating the Sterling Well is 10cated approximately six (6) miles east of Kenai in the Sterling Gas Field. 1,026 water wells were located within T5N RlOW and the deepest well is 451 feet. 111 water wells were 10cated within T5N RlOW, Section 9 and the deepest well is 220 feet. You conclude that those portions of aquifers occurring below 1750 feet MD in the Sterling 43-9 Well contain fluids with TDS less than 10,000 mglliter. You also conclude that at these depths, the aquifers contain natural gas. Thus, o Printed on Recycled Paper , 2 . those portions of the aquifers within 1/4 mile radius of the well and below 1750 feet contain gas and are situated at a depth that makes recovery of water for drinking water purposes economically impractical. For these reasons these portions of the aquifer cannot reasonably be expected to serve as an underground source of drinking water. Evidence submitted by the applicant also shows the surface aquifers are commonly underlain by over 1000 feet of a claystone confining layer. The exemption is considered to be a minor modification of the AOGCC's program for the regulation of Class IT injection wells under Section 1425 of the Safe Drinking Water Act, as defined by Underground Injection Control (UIC) Program Guidance 34 and 40 CFR 145.32. Thank you for the opportunity to review and provide comments on this pmposal. If you have any questions regarding these comments, please contact Mr. Thor Cutler, at (206) 553-1673 or by email at cutler.thor@epa.gov. ~ "Tl~ , Man r Ground Water Protection Unit cc: M. Salazar, OGWDW David Allnutt, RlO-0RC Orin Wooley, ADEC, Kenai #4 -. , ~ ~ ~ E (ill} ~ ~!Æ ~ ~~ ~ / FRANK ~ MURKOWSKI, GOVERNOR AT,ASKAOnANDGAS / CONSERVATION COMMISSION / February 25,2003 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Mr. Thor Cutler Ground Water Protection Unit US EP A Region 10 1200 Sixth Avenue, OW-137 Seattle, W A 98101 Dear Mr. Cutler: Attached are applications for an Aquifer Exemption Order and a Disposal Injection Order for the Sterling Unit, Kenai Peninsula. These orders are necessary to convert a watered out Sterling Formation gas producer (Sterling Unit Well No. 43-9) to disposal service. The Sterling Unit was one of the early discoveries on the peninsula and has been producing for over forty years. Gas has been produced from the Sterling, Beluga and Tyonek Formations, through four (4) wells. The cumulative production to date for the field is slightly over three billion cubic feet. The field is one of the smaller to have been produced in this state. Two of the original four wells are either shut-in or suspended due to water production. Currently, Sterling Unit produced water must be trucked for disposal elsewhere. This expensive and difficult method of disposal is a significant drag on the economics of this small field. Approval of an on-site disposal well will allow increased recovery from the unit. The distribution of formation water salinities in the Sterling Unit warrant a few comments. The vintage of the data and the log suites acquired in these wells limit the salinity control in this area to SP calculations and a produced water sample. Fortunately the SPcurve in the subject well appears to be of good quality. We have calculated salinities using a generally more conservative method than Marathon, the results of this work are attached in the excel workbook titled "EP A SP Method.xls" and summarized in the graph below. The primary difference between the Marathon approach and that used by AOGCC is that we relied on zone averages in what appeared to be very clean (low shale volume) sand intervals over 10 feet thick. The Marathon estimate is based on point-by-point calculations, with the estimates shown below coming from maximum values within sands. In general our estimate will provide a lower bound, but in several spots the two techniques generate equivalent results. These are intervals with blocky responses over more than ten feet and include the water sample interval. Mr. Thor Cutler February 25,2003 Page 2 of3 . , Kenai Unit 43-9: Calculated TDS Concentration (EPA SP Method) vs Measured Depth 18000 16000 ~___--L I 14000 -----~- I 12000 -_.---~+ II J; 1 1 : \ : I i I I ! ! ! -~+---+-----r---t----+----+--~--+---..~ ! - I':: TOS Values legend r J._______.__~________~___________L.___. I i I : AOG:C i Iii, 1_ _j_____J___J~==[=--=l--~=::hon i ! - . ( : : Sample i -~+-~-.--"- ) î I KU'3-9w.t"_~·1 fn:m 5262' . 5272' MD: i -1931 ppm TOS , I 1615 ppm NaCI equiv. I !../ --t--------¡- # . 1??oo - TDS (ppm) I I 8000 -------+---- + - ,I I . ! ! I ' I ! 8000 ---- 1____L___L___--.J____-1 ! I i I i \ I i I I I 4000 . ------i'-----t---~-+---t----"¡-~---!-- i i I I, ! · 2000 - ----I--·--¡--·-------r--------i-----+~---·--~~~-- -~-- ; I j I i I ,I , ' (> o 1000 1500 2000 2500 3000 3500 4000 Measured Depth (Ft) 4500 5000 5500 6000 I feel the Sterling Unit salinities are accurately represented by these data. Salinity trends discussed here will betaken from the more conservative AOGCC generated values. The following generalities apply to the Sterling Unit Well No. 43-9 salinities: 1) Drinking water in the area comes from glacial sediments that are roughly 750' thick in this vicinity. 2) The 750'-3,750' md. interval contains intervals with TDS minor intervals with concentrations less than 10,000 ppm. 3) The boundary at 3750'md appears to be sharp and is evident on both sp and resistivity curves. 4) Below 4,000' md. intervals with less than 3,000 ppm are present. Our regulation 20 AAC 25.440 Freshwater Aquifer Exemption states that we can grant a aquifer exemption regardless of salinity if the aquifer "is situated at a depth or location that makes recovery of water for drinking purposes economically or technologically impractical". Based on all previous water well drilling experience in this area, this is a case, where formation waters of less than 3,000 ppm TDS are situated at a uneconomic depths. The deepest water well with the township in which SU 43-9 is located is 451 feet. Mr. Thor Cutler February 25,2003 Page 3 of3 . , The conservation implications of the SU 43-9 conversion are not trivial. Usable freshwater resources can be protected and ultimate recovery at the Sterling Unit enhanced by selecting an appropriate depth from which to exempt aquifers. This project could lead to the establishment of criteria to evaluate the economic and technical practicality of deeply buried formations to serve as sources of drinking water. Robert Crandall Sr. Geologist RC:\jjc Enclosure UNITED STATES POSTA\. SEJWIGE. First-Class Man Postage & Fees Paid USPS Permit No. G-10 . Sender: Please print your name, address, and ZIP+4 in this box · ::J(y{¿( v106('' (- Il ,c:;¡-¿ /00 '"2"':2 -.-, I...fLf ,7 ." ¡)€ <-.J ~.) ':) 4;J L.j¡·O~~b-(:~/ 141~ ./ ýC)ç-4I u.s. .. . .I,f· " . ~it\ ,~ ~'=1"ð' tífr~~Uß~~~t~~~ pro'v¡J~ðJ " .~ ~ , ,'h (" ~, ~ A.' ,__',," . JI ~ ~ SE~T~-:: .__~..~_J ,_UL~··__j·-'-·~---~~·ì ~.....9WJl _ _ .'___' . ,.-----1 OJ U1 Postage $ 9.45 ::r CI Certified F~e CI Return Receipt Fee CI lEndorMment Required) a Restricted Delivery Fee CI (Endorsement Required) CI $ lï.OO .-'1 Total Postage & Fees U" c::J Sent Tò OJ . "f,iéêêï: Apt -¡.¡õ:··········...·· --............................................... ............ o òr PO Box No. ~ "ai~'$íãié,¡:ïp+;¡--"""'''''' ·....................h......... ...u..·.h·h. ·~."."'I!ttl.I...~..".."...At" ~ett~II'IW~rI11~:.. COMPLETE THIS Sf:CTlON ON DELIVERY A. Signature ~ /j) () J 0e\ 0 Agent ~ 1<..e'.Y7..-t,~' ~ 0 Address~ e. Received by (Printed Name) 1 c. 'pat~, o! De~~ery "'T kc;:,( ~'-' 'T( <~- ~./ l¿ ) O. II; de(¡velY address different from item 1? 0 Yes . if YES. enter deiivelY addresl; below: 0 No · Complete items 1, 2, and 3. Also complete Item 4 if Restricted Delivery is desired. · Print your name and address on the reverse so that we ceen return the card to you. · Attach this card to the back of the mai/plece, or 011 the Ironl il space permits. 1. Article Addressed to: ·171 c /~ (í U) ¿ -(--fL~~ ¿ ( ç é- ¡:Jfi / ;?-c; c' 'S;./xtL 11th CI&J (;_ l3~7 ~ . :JE?~TT t. c¡ ÜJ;4- [sEiIDJ 2. Article Number (Transfer from service label) PS Form 3811, August 2001 RESTRICTED . · ~::.... Po[!:!y!RY G'1:téglstered 0 Return Receipt for Merchandise o Insured Mail 0 C.O.O. I 4. Restricted DefivelY? (Extra Fee) Mye:;" '" 7002 0510 0000 0452 4136 Domestic Retum Receipt 2AGPI'II-03·Z-o!Jß5 #3 STATE OF ALASKA ADVERTISING ORDER . NOTICE TO PUBLISHER .. ADVERTISING ORDER NO. INVO UST BE IN TRIPLICATE SHOWING ADVERTISING ORDER ~RTIFIED AO-02314030 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COpy OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE F AOGCC R 333 W 7th Ave, Ste 100 o Anchorage, AK 99501 M AGENCY CONTACT DATE OF A.O. Jody Colombie February 4. 2003 PHONE PCN ¿ Anchorage Daily News POBox 149001 Anchorage,AJ( 99514 (907) 793 -1 ?? 1 DATES ADVERTISEMENT REQUIRED: February 7,2003 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Type of Advertisement X Legal D Display Account #STOF0330 Advertisement to be published was e-mailed D Classified DOther (Specify) SEE ATTACHED PUBLIC HEARING REF TYPE 1 VEN 2 ARD 3 4 FIN AMOUNT 1 2 NUMBER AOGCC, 333 W. 7th Ave., Suite 100 Anchorage, AK 99501 AMOUNT DATE I TOTAL OF I PAGE 1 OF ALL PAGES$ 2 PAGES COMMENTS 02910 SY CC PGM LC ACCT FY NMR DIST LlO 03 02140100 73540 3 ':QUmlmNED r') Qßh~/ ID~:?:L<, ¥ 02-902 (Rev. 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: Sterling Unit Well No. 43-9 Sterling Gas Field Unit Disposal Injection Order Kenai Peninsula, Alaska Marathon Oil Company by letter dated January 24, 2003, has applied for a Disposal Injection Order for Sterling Unit Well No. 43-9 pursuant to 20 AAC 25.252. The Commission has tentatively set a public hearing on this application for March 11,2003 at 9:00 am at the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. A person may request that the tentatively scheduled hearing be held by filing a written request with the Commission no later than 4:30 pm on February 24, 2003. If a request for a hearing is not timely filed, the Commission will consider the issuance of an order without a hearing. To learn if the Commission will hold the public hearing, please call 793-1221. In addition, a person may submit written comments regarding this application to the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Written comments must be received no later than 4:30 pm on March 10,2003, except that if the Commission decides to hold a public hearing, written comments must be received no later than 9:00 am on March 11, 2003. If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing, please contact Jody Colombie at 793-1221 before February 28,2003. b ~.¥ Cammy echsli Taylor Chair Published Date: February 7, 2003 ADN AO#02314030 Clarion AO # 02314032 Fwd: Legal Notice e e Subject: Fwd: Legal Notice Date: 05 Feb 2003 11 :28:03 -0900 From: Legal Ads <legalads@adn.com> To: <jody _ colombie@admin.state.ak.us> Account Number: STOF 0330 Legal Ad Number: 708750 Run Dates: February 7, 2003 Total Amount: $173.43 Hi Jody: Above is the information regarding AO# 02314029, please let me know if you need further information. I also need to let you know that Amy has taken a position within the ADN and will no longer be placing your legal advertising. Please send all future legal ads to legalads@adn.com as Amy's email will be discontinured shortly. My name is Kim Kirby and you can reach me at the legal ads email address or by phone at 907-257-4296. Please do not hesitate to contact me with your questions or concerns. I look forward to working with you in the future. Thank You, Kim -------------------------------------- Date: Tuesday, February 4, 2003 From: Jody Colombie <jody_colombie@admin.state.ak.us> Amy: I am attaching two notices that need to be published on 2-7-03. Please confirm with e-mail. Jody ~-~-~~~ --~-~-~~,- Name: AEO _Sterling_020703.doc . ~AEO Sterling 020703.doc Type: WINWORD File (applicationlmsword) Encoding: base64 ""_"v~·~·,v,, ~...~~'..m~~.'.~~~'~"~.~._.~~._"_yy.-w~.-.-.-""w~~~..___.-.,,_ ~ "" __"w'_..m_·<~_,~",~" ... ,. ,._""_.\"-_.__"'*'.""~.~""__.~~._..."_'_""'~""'.__"~,,.'" ¡Name: DIO_Sterling_020703.doc I ~DIO Sterling 020703.doci Type: WINWORD File (applicationlmsword)I I Encoding: base64 I _w,~·~......~w"....". ,,,"''''_,,,,,,.'''..) "'VB', "".., , ,,,..,,. .''''''_~'''_.'''.,."~_..__<_."..f"'...,.v~''''~_,,.,_'''.'''_...... 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"..,'~"''''''''''~''' "",,,,,,,"v_,,,,,,'__''''''''' ¡ Name: ADNAd Order form1.doc II ~ADNAd Order form1.doc¡ Type: WINWORD File (applicationlmsword) ......_........... .....~...............J~~~~c!ï.J:l!E~~~~~~.. .. ...~..~.... .1 r·..···..__··-~~·m.. - ..··~····-···--··--r·· ¡ Name: ADNAd Order form2.doc I ~ADNAd Order form2.docl Type: WINWORD Pile (applicationlmsword)I ___...._m.____..J~1.lc~d~1.l~:.~~~~~ . m. 1 begin:vcard n:Colombie¡Jody tel¡fax:907-276-7542 tel¡work:907-793-1221 x-mozilla-html:FALSE adr: ¡ ¡ ¡ ¡ ¡ ¡ 10f2 2/5/20034:03 PM IChOrage Daily News Affidavit of Publication 'It 1001 Northway Drive, Anchorage, AK 99508 PRICE OTHER OTHER OTHER OTHER OTHER GRAND AD# DATE PO ACCOUNT PER DAY CHARGES CHARGES #2 CHARGES #3 CHARGES #4 CHARGES #5 TOTAL 708741 02/07/2003 02314030 STOF0330 $173.43 $173.43 $0.00 $0.00 $0.00 $0.00 $0.00 $173.43 STATE OF ALASKA THIRD JUDICIAL DISTRICT Kimberly A. Kirby, 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. /) 1 { ~'r ;; s;gnei/¡¡m(}~:f Jj;¿~ßjY Subscribed and s~orn to me bef~~ this date: dfÍ:f3 Notary Public in and for the State of Alaska. :::::on·I:::::AJ¢~5 \l ({(r \\\\,..\..\E 8. ~rt': ~'O#fJ,,· :.::.'" ~~ S~'+OTAIt~~~ ......... -.- .... '"' . . - .... , bo. 01". ' - ::: . "-uSL"-' . -- ~ '. ~ --;/;: jg~ -- . Jít . Iii..." ~~'~OF ,"!t..~ ~ . . f . . . __.d :\' ~~~ ExPre&~~" :III J}J}JJ)) \" Notice of Public Hearing STATE OF A~ASKA Alaska Oil and Gas Conservation Commission Re:Sterling Unit Welf No. 43-9 Sterling Gas Field Unit Disposal Injection Order Kenai Peninsula, Aloska Morothon Oil Componv by letter dated January 24, 2003, has applied for a Disposal Injection Order for Sterling Unit Well No. 43-9 pursuant to 20 AAC" 25.252. The Commission has tentativelY set a public. hearing on thi~ applica'i!?n for March 11, 2003 at 9:00 am at the Alaska Oil and Gas Conservation CommIssion at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99~1.A person may re- quest that the tentativelY scheduled hearing be held by f,hnga written request with the Commission no later than 4: 30 pm on February 24, 2003. If a request for a hearing isnot timely filed, the Co~misslon will consid!!.r the issuance of an order without a hearing. To learn If the Commission will hold the pUblic hearing, please calf 793-122l. In addition, a person may submit writt!!n comme~ts.regarding this applica- tion to the Alaska Oil and Gas Conservation CommissIon at 333 west 7th;AV- enue, Suite 100, Anchorage, Alaska 99501. Written co.mments mu~t ~e rece,.ved no later than 4:30 pm on March 10, '2003, except that If the CommissIon decl~es to hold a public hearing, written comments must be received no later than 9.00 am on MarCh 11, 2003. If you are a person with a disability w~o may. need a special modification in order to comment or to attend the pub! IC hearing, please contact Jody Co- lombie at 793-1221 before February 28, 2003. Isf: Cammy Oechsli Taylor, Chair Publish: February 7, 2003 STATE OF ALASKA ADVERTISING ORDER . NOTICE TO PUBLISHER . ADVERTISING ORDER NO. - INVO - UST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AO 02314030 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF - ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE F AOGCC R 333 West 7th Avenue, Suite 100 o Anchorage,AJ( 99501 M AGENCY CONTACT DATE OF A.O. ~ Anchorage Daily News POBox 149001 Anchorage, AJ( 99514 Jody Colombie Febm~ry 4, ?003 PHONE PCN (907) 793 -1 ?? 1 DATES ADVERTISEMENT REQUIRED: February 7,2003 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Account #STOF0330 United states of America AFFIDAVIT OF PUBLICATION REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. ATTACH PROOF OF PUBLICATION HERE. division. Before me, the undersigned, a notary public this day personally appeared who, being first duly sworn, according to law, says that helshe is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2003, and thereafter for _ consecutive days, the last publication appearing on the _ day of . 2003, 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 2003, Notary public for state of My commission expires 02-901 (Rev. 3/94) Page 2 AO.FRM PUBLISHER STATE OF ALASKA ADVERTISING ORDER . NOTICE TO PUBLISHER - ADVERTISING ORDER NO. INVO UST BE IN TRIPLICATE SHOWING ADVERTISING ORDER ~ERTIFIED AO-02314032 AFFIDAVIT OF PUBLICATION (PART2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE F AOGCC R 333 W 7th Ave, Ste 100 o Anchorage, AK 99501 M AGENCY CONTACT DATE OF A.O. Jody Colombie February 4, 2003 PHONE PCN T Peninsula Clarion o POBox 3009 Kenai AK 99611 (907) 793 -1 7?1 DATES ADVERTISEMENT REQUIRED: February 7,2003 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 X Legal o Display o Classified DOther (Specify) SEE ATTACHED PUBLIC HEARING REF TYPE 1 VEN 2 ARD 3 4 FIN AMOUNT NUMBER AOGCC, 333 W. 7th Ave., Suite 100 Anchorage, AK 99501 AMOUNT DATE I I TOTAL OF I PAGE 1 OF ALL PAGES$ 2 PAGES COMMENTS 02910 Sy CC PGM LC ACCT FY NMR DIST LID 1 03 02140100 2 3 .;QUmmONEDBY, c~ (I~. iJ 73540 I ilISIONAPP~ ~ 02-902 (Rev. 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: Sterling Unit Well No. 43-9 Sterling Gas Field Unit Disposal Injection Order Kenai Peninsula, Alaska Marathon Oil Company by letter dated January 24, 2003, has applied for a Disposal Injection Order for Sterling Unit Well No. 43-9 pursuant to 20 AAC 25.252. The Commission has tentatively set a public hearing on this application for March 11,2003 at 9:00 am at the Alaska Oil and Gas Conservation Commission at 333 West ih Avenue, Suite 100, Anchorage, Alaska 99501. A person may request that the tentatively scheduled hearing be held by filing a written request with the Commission no later than 4:30 pm on February 24,2003. If a request for a hearing is not timely filed, the Commission will consider the issuance of an order without a hearing. To learn if the Commission will hold the public hearing, please call 793-1221. In addition, a person may submit written comments regarding this application to the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Written comments must be received no later than 4:30 pm on March 10, 2003, except that if the Commission decides to hold a public hearing, written comments must be received no later than 9:00 am on March 11, 2003. If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing, please contact Jody Colombie at 793-1221 before February 28,2003. GhI.__ _ ~'¥ C~;8echsli Taylor Chair Published Date: February 7,2003 ADN AO# 02314030 Clarion AO # 02314032 " e e PUBLISHER'S AFFIDAVIT sworn, on oath deposes and says: r-------------------, NotIce of PublIc .......ng I STATE OF ALASKA I Alaska 011 and Gas Conservation Commission I Re: Sterling Unit Well No.43-9 I Sterling Gas Field Unit I Disposal Injection Order I Kenai Peninsula, Alaska I Marathon Oil Company by letter dated January 24, 2003, I has applied for a Disposal Injection Order for Sterling Unit Well I No. 43-9 pursuant to 20 AAC 25.252. I The Commission has tentatively set a public hearing on this I application for March 11, 2003 at 9:00 am at the Alaska Oil I and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. A person may request I that the tentatively scheduled hearing be held by filing a writ- I ten request with the Commission no later than 4:30 pm on I February 24, 2003. If a request for a hearing is not timely filed, the Commission will consider the issuance of an order without a hearing. To learn if the Commission will hold the public hearing, please call 793-1221. In addition, a person may submit written comments regard- ing this application to the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Written comments must be received no later That I am and was at all times hereiJ than 4:30 pm on March .10, 2003, except that if the Commission decides to hold a public hearing, written com- Supervisor of Legals of the Peninsula Clarion I ments must be received no later than 9:00 am on March 11, circulation and published at Kenai, Alaska, : 20~~?U ~re ~ person with a disability who may need a.special that the Disposal InJ' ection Order I ~Odlflcatlon In order to.comment or to attend the public hear- Ing, please contact Jody Colombie at 793-1221 before AO-02314032 I February 28,2003. I .. . . I Cammy Oechsli Taylor I a pnnted copy of whIch IS hereto annexed was I Chair I paper one each and every day ~~B~S~:~.:..2~~ _ _ _ _ _ _ _ _ _3:~~U successive and consecutive day in the issues on the following dates: February 7,2003 STATE OF ALASKA Ii 55: UNITED STATES OF AMERICA, .. Denise Reece x /j)//J./;'#-, /f'//r'ß ~ SUBSCRffiED AND SWORN to me before this 17th ~ ^ ,dar-4f r--J February "'-- JJ "-~ ~ ~ .y,--=- NOTARY PUBLIC in favor for the State of Alaska. My Commission expires 22-Jan-06 2003 STATE OF ALASKA ADVERTISING ORDER . NOTICE TO PUBLISHER & - ADVERTISING ORDER NO. INVOI UST BE IN TRIPLICATE SHOWING ADVERTISING ORDER ~RTIFIED AO-02 3140 32 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE F AGENCY CONTACT DATE OF A.O. AOGCC 333 West 7th Avenue, Suite 100 o Pu1chorage,AJ( 99501 M T Peninsula Clarion o POBox 3009 Kenai AJ( 99611 Jody Colombie FebruHry 4, 2003 PHONE PCN (907) 793 -1 ??1 DATES ADVERTISEMENT REQUIRED: February 7,2003 R THE MATERIAL BElWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: United states of America AFFIDAVIT OF PUBLICATION REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. ATTACH PROOF OF PUBLICATION HERE. division. Before me, the undersigned, a notary public this day personally appeared who, being first duly sworn, according to law, says that 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 2003, and thereafter for _ consecutive days, the last publication appearing on the _ day of . 2003, 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 2003, Notary public for state of My commission expires 02-901 (Rev. 3/94) Page 2 AO.FRM PUBLISHER Re: legal notices e Subject: Re: legal notices Date: Tue, 4 Feb 2003 15:59:15 -0900 From: "Denise Reece" <dreece@peninsulac1arion.com> To: "Jody Colombie" <jody_colombie@admin.state.ak.us> e Received your ads and have scheduled them to run on Friday. Thanks, Denise ----- Original Message ----- From: "Jody Colombie" <jody colombie@admin.state.ak.us> To: <dreece®peninsulaclarion.com> Sent: Tuesday, February 04, 2003 3:11 PM Subject: legal notices > Denise, > > Please publish on friday 2-7-03. E-mail confirmation. > > Thank you. Jody > 1 of I 2/4/2003 4:57 PM Daniel Donkel 2121 North Bayshore Drive, Ste 1219 Miami, FL 33137 Christine Hansen Interstate Oil & Gas Compact Comm Excutive Director PO Box 53127 Oklahoma City, OK 73152 Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 Paul Walker Chevron 1301 McKinney, Rm 1750 Houston, TX 77010 David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 T.E. Alford ExxonMobilExploration Company PO Box 4778 Houston, TX 77210-4778 Chevron USA Alaska Division PO Box 1635 Houston, TX 77251 Shelia McNulty Financial Times PO Box 25089 Houston, TX 77265-5089 James White Intrepid Prod. Co./Alaskan Crude 4614 Bohill SanAntonio, TX 78217 tit SD Dept of Env & Natural Resources Oil and Gas Program 2050 West Main, Ste 1 Rapid City, SD 57702 Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Gregg Nady Shell E&P Company Onshore Exploration & Development PO Box 576 Houston, TX 77001-0576 G. Scott Pfoff Aurora Gas, LLC 10333 Richmond Ave, Ste 710 Houston, TX 77042 William Holton, Jr. Marathon Oil Company Law Department 5555 San Fecipe St. Houston, TX 77056-2799 Corry Woolington ChevronTexaco Land-Alaska PO Box 36366 Houston, TX 77236 Donna Williams World Oil Statistics Editor PO Box 2608 Houston, TX 77252 Shawn Sutherland Unocal Revenue Accounting 14141 Southwest Freeway Sugar Land, TX 77478 Doug Schultze XTO Energy Inc. 3000 North Garfield, Ste 175 Midland, TX 79705 e John Katz State of Alaska Alaska Governor's Office 444 North Capitol St., NW, Ste 336 Washington, DC 20001 Alfred James 200 West Douglas, Ste 525 Wichita, KS 67202 Conoco Inc. PO Box 1267 Ponca City, OK 74602-1267 Michael Nelson Purvin Gertz, Inc. Library 600 Travis, Ste 2150 Houston, TX 77002 G. Havran Gaffney, Cline & Associations Library 1360 Post Oak Blvd., Ste 2500 Houston, TX 77056 W. Allen Huckabay ConocoPhillips Petroleum Company Offshore West Africa Exploration 600 North Dairy Ashford Houston, TX 77079-1175 Texico Exploration & Production PO Box 36366 Houston, TX 77236 Chevron Chemical Company Library PO Box 2100 Houston, TX 77252-9987 Kelly Valadez Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 e e George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 John Levorsen 200 North 3rd Street, #1202 Boise,lD 83702 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 John F. Bergquist Babson and Sheppard PO Box 8279 Long Beach, CA 90808-0279 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Thor Cutler OW-137 US EPA egion 10 1200 Sixth Ave. Seattle, WA 98101 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Julie Houle Robert Mintz Duane Vaagen State of Alaskan DNR State of Alaska Fairweather Div of Oil & Gas, Resource Eva!. Department of Law 715 L Street, Ste 7 550 West 7th Ave., Ste 800 1031 West 4th Ave., Ste 200 Anchorage, AK 99501 Anchorage, AK 99501 Anchorage, AK 99501 Jim Arlington Tim Ryherd Williams VanDyke Forest Oil State of Alaska State of Alaska 310 K Street, Ste 700 Department of Natural Resources Department of Natural Resources Anchorage, AK 99501 550 West 7th Ave., Ste 800 550 West 7th Ave., Ste 800 Anchorage, AK 99501 Anchorage, AK 99501 Cammy Taylor Richard Mount Ed Jones 1333 West 11th Ave. State of Alaska Aurora Gas, LLC Anchorage, AK 99501 Department of Revenue Vice President 500 West 7th Ave., Ste 500 1029 West 3rd Ave., Ste 220 Anchorage, AK 99501 Anchorage, AK 99501 Susan Hill Trustees for Alaska Mark Wedman State of Alaska, ADEC 1026 West 4th Ave., Ste 201 Halliburton EH Anchorage, AK 99501-1980 6900 Arctic Blvd. 555 Cordova Street Anchorage, AK 99502 Anchorage, AK 99501 Schlumberger Ciri John Harris Drilling and Measurements Land Department NI Energy Development 3940 Arctic Blvd., Ste 300 PO Box 93330 Tubular Anchorage, AK 99503 Anchorage, AK 99503 3301 C Street, Ste 208 Anchorage, AK 99503 Rob Crotty Jack Laasch Mark Dalton C/O CH2M HILL Natchiq HDR Alaska 301 West Nothern Lights Blvd Vice President Government Affairs 2525 C Street, Ste 305 Anchorage, AK 99503 3900 C Street, Ste 701 Anchorage, AK 99503 Anchorage, AK 99503 Baker Oil Tools Mark Hanley Judy Brady 4730 Business Park Blvd., #44 Anadarko Alaska Oil & Gas Associates Anchorage, AK 99503 3201 C Street, Ste 603 121 West Fireweed Lane, Ste 207 Anchorage, AK 99503 Anchorage, AK 99503-2035 Arlen Ehm 2420 Foxhall Dr. Anchorage, AK 99504-3342 Thomas R. Marshall, Jr. 1569 Birchwood Street Anchorage, AK 99508 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Richard Prentki US Minerals Management Service 949 East 36th Ave., 3rd Floor Anchorage, AK 99508 Kristen Nelson IHS Energy PO Box 102278 Anchorage, AK 99510-2278 Robert Britch, PE Northern Consulting Group 2454 Telequana Dr. Anchorage, AK 99517 Tesoro Alaska Company PO Box 196272 Anchorage, AK 99519 Kevin Tabler Unocal PO Box 196247 Anchorage, AK 99519-6247 Dudley Platt DA Platt & Associates 9852 Little Diomede Cr. Eagle River, AK 99577 Shannon Donnelly Phillips Alaska, Inc. HEST -Enviromental PO Box 66 Kenai, AK 99611 e Greg Noble Bureau of Land Management Energy and Minerals 6881 Abbott Loop Rd Anchorage, AK 99507 Jeff Walker US Minerals Management Service Regional Supervisor 949 East 36th Ave., Ste 308 Anchorage, AK 99508 Jim Scherr US Minerals Management Service Resource Evaluation 949 East 36th Ave., Ste 308 Anchorage, AK 99508 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 Jordan Jacobsen Alyeska Pipeline Service Company Law Department 1835 So. Bragaw Anchorage, AK 99515 David Cusato 600 West 76th Ave., #508 Anchorage, AK 99518 Bill Bocast PACE Local 8-369 c/o BPX North Slope, Mailstop P-8 PO Box 196612 Anchorage, AK 99519 BP Exploration (Alaska), Inc. Land Manager PO Box 196612 Anchorage, AK 99519-6612 Bob Shavelson Cook Inlet Keeper PO Box 3269 Homer, AK 99603 Kenai Peninsula Borough Economic Development Distr 14896 Kenai Spur Hwy #103A Kenai, AK 99611-7000 e Rose Ragsdale Rose Ragsdale & Associates 3320 E. 41st Ave Anchorage, AK 99508 Paul L. Craig Trading Bay Energy Corp 5432 East Northern Lights, Ste 610 Anchorage, AK 99508 Chuck O'Donnell Veco Alaska,lnc. 949 East 36th Ave., Ste 500 Anchorage, AK 99508 Jim Ruud Phillips Alaska, Inc. Land Department PO Box 100360 Anchorage, AK 99510 Perry Markley Alyeska Pipeline Service Company Oil Movements Department 1835 So. Bragaw - MS 575 Anchorage, AK 99515 Jeanne Dickey BP Exploration (Alaska), Inc. Legal Department PO Box 196612 Anchorage, AK 99518 J. Brock Riddle Marathon Oil Company Land Department PO Box 196168 Anchorage, AK 99519-6168 Sue Miller BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, AK 99519-6612 Peter McKay 55441 Chinook Rd Kenai, AK 99611 Penny Vadla Box 467 Ninilchik, AK 99639 James Gibbs PO Box 1597 Soldotna, AK 99669 John Tanigawa Evergreen Well Service Company PO Box 871845 Wasilla, AK 99687 Cliff Burglin PO Box 131 Fairbanks, AK 99707 North Slope Borough PO Box 69 Barrow, AK 99723 Lt Governor Loren Leman State of Alaska PO Box 110015 Juneau, AK 99811-0015 e Claire Caldes US Fish & Wildlife Service Kenai Refuge PO Box 2139 Soldotna, AK 99669 Charles Boddy Usibelli Coal Mine, Inc. 100 Cushman Street, Suite 210 Fairbanks, AK 99701-4659 Harry Bader State of Alaska Department of Natural Resources 3700 Airport Way Fairbanks, AK 99709 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 . Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 Kurt Olson State of Alaska Staff to Senator Tom Wagoner State Capitol Rm 427 Juneau, AK 99801 #2 Application for a Disposal Injection Order Sterling Gas Field Unit Sterling Unit 43-9 Well Kenai Peninsula, Alaska January 2003 REVISED Submitted by Marathon Oil Company Anchorage, Alaska , ,- M MARATHON . . . e Alaska BU.S Unit Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 January 24, 2003 Mr. Robert P. Crandall Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501-3539 RE: REVISED Disposal Injection Order Application Sterling Gas Field Unit, Kenai Peninsula, Alaska Township 5 North, Range 10 West, Section 9, SM Dear Mr. Crandall: Pursuant to 20 AAC 25.252, Marathon Oil Company (Marathon) submits the enclosed application, which requests approval to dispose of Class II oil field wastes by underground injection into the 8-4 Sand through· the Sterling Unit 43-9 well, The proposed injection interval would be from 5,020 feet SSrvD to 5,120 feet SSTVD. If you have any questions or require additional information, please contact me at (907) 564-6372 or ERWard~MarathonOil.com. Sincerely, (' ') {J L' 1. Ü 6>ir L. I ¿ '\P¿'L.¿~ Eric R. Ward HES Professional ERW:cdg By Certified Mail Enclosure: Application for a Disposal Injection Order cc: Mr. Jim Segura, President, Salamatof Native Association, Inc. Mr. Kirk McGee, CIRI, Vice President of Real Estate Kenai Gas Field R. J. Affinito J. G. Eller E. R. Ward File: CEF, SU 43-9, "H" e e · TABLE OF CONTENTS Application Application for a Disposal Injection Order Table Table 1. Sterling Gas Field Unit Well Information Figures Figure 1 . Cook Inlet regional map. Figure 2. Sterling Gas Field Unit with gas wells and MaC's water well. Figure 3. Topographical Map with wells. Attachments Attachment 1. Affidavit of Fact · Attachment 2. Sterling Water Disposal Model Summary Attachment 3. Mechanical Integrity Test for Well SU 43-9 Attachment 4. Injectivity Log Procedure for Sterling 8-4 on Well SU 43-9 Attachment 5. Injectivity Test Results for Sterling 8-4 on Well SU 43-9 Attachment 6. Construction of Well SU 43-9 Attachment 7 A. Hydraulic Fracturing Potential Simulation for Routine Disposal Fluids Attachment 78. Hydraulic Fracturing Potential Simulation for Drilling Muds and Cuttings Attachment 8. Water Analysis Report for Sterling 8-4 Sands Attachment 9. Wellbore Schematic for Well SU 32-9 Attachment 10. Wellbore Schematic for Well SU 41-15 Appendices Appendix A. Statute 20 MC 25.252: Underground Storage of Oil Field Wastes and Underground Storage of Hydrocarbons Appendix 8. WELTS Data for Water Wells · References O:\Sterli ng\43-9\U I C\2002 Applications\Disposal Injection \Contents-D I O. doc 1/22/2003 e e · APPLICATION FOR A DISPOSAL INJECTION ORDER STERLING GAS FIELD UNIT, SU 43-9 WELL OPERATED BY MARATHON OIL COMPANY This application was prepared in accordance with the requirements of Alaska Oil and Gas Conservation Commission (AOGCC) Statute 20 AAC 25.252, UNDERGROUND DISPOSAL OF OIL FIELD WASTES AND UNDERGROUND STORAGE OF HYDROCARBONS effective November 7,1999. Introduction Marathon Oil Company (Marathon) is applying for a disposal injection order to allow for the underground disposal of oil field wastes in the Marathon Sterling Gas Field Unit (Section 9, T5N, R10W, SM). The injection order would approve disposal of Class II oil field wastes via injection through the Sterling Unit (SU) 43-9 well into the Sterling B-4 Sand. The SU 43-9 well is a production well which will be converted to a Class II well suitable for the disposal of oil field wastes as defined in 40 C.F.R. 144.6(b) (USEPA, 1998). · Marathon has conducted well testing and modeling that demonstrates that the proposed disposal operation will not allow the movement of oil field wastes or hydrocarbons from the Sterling B-4 Sand into sources of freshwater. The design of the existing SU 43-9 well will isolate the disposal zone and protect freshwater resources. Marathon has also conducted testing which confirms the mechanical integrity of the production casing in well SU 43-9. SterlinQ Gas Field Unit The Sterling Gas Field Unit (SGFU) is located on the Kenai Peninsula approximately six miles east of the city of Kenai and three miles north of the city of Soldotna (see Figure 1). The 3,600-acre SGFU has produced gas from five completions since it's discovery in 1961 (see Figure 2). In addition, a water well drilled to a depth of 268 feet measured depth (MD) is in the SGFU to support drilling operations. Current production operations occur only at the Sterling Unit 43-9 Pad, which represents approximately 4.1 acres of the 3,600-acre unit, or just over 0.1 percent (0.1 %) of the area defined by the SGFU. Beginning in October 2000, gas production became intermittent due to the inability of wells to unload and dispose of water. Currently, two of the four completions on the 43-9 pad are shut-in due to water production, and current gas production is restricted to below the economic limit for this field. Table 1 summarizes the current status of the SGFU. · Application for a Dispos.ection Order - Marathon Oil Company (I Page 2 of 6 · Table 1. Sterling Gas Field Unit First Final Perforated Perforated 12/2001 12/2001 Current Well Prod. Prod. Interval Interval Cum Cum Current Rate Date Date MD SSTVD Gas Water Status MMCFGPD MMCFG MBO SU 32-9 March Active Sterling B-4 Sterling B-4 407 0.13 Active 1.0 1999 (5,679' - 5,686') (5,013' - 5,019') S U 43-9 Oct. Feb. Sterling B-4 Sterling B-4 2,165 2.75 Sldueto 0 1966 1998 (5,262' - 5,272') (5,026' - 5,036') water SU 23-15 May Oct. Sterling B-4 Sterling B-4 379 NA T&A'd 0 1962 1966 (5,250' - 5,254') (5,028' - 5,032') (Suspended) SU 41- April Active Beluga Beluga 53 0.37 Active 0.2 15S 1999 (9,440' - 10,026') (7,678' - 8,099') SU 41- April April Tyonek Tyonek 145 0.62 Sldueto 0 15L 1999 2001 (10,942' - 11,331 ') (8,828' - 9,164') water To have economic production of gas and conservation of resources, disposal of up to 1,000 barrels of produced water per day is necessary. Permit Application · The following summarizes the contents of the SU 43-9 well permit application as they apply to the application requirements found in 20 AAC 25.252 (c) (AOGCC, 1999). Complete language for 20 AAC 25.252 is included in Appendix A of this document. (1) Location plat. Figure 2 is a plat showing the boundaries of the Marathon Sterling Gas Field Unit, the location of the SU 43-9 well (which will be converted to a Class II disposal well) and the three other gas wells in the Marathon Sterling Gas Field Unit. There is also a Marathon water well (TWUP A98-25) that is 268 feet deep located approximately 111 feet north of the SU 43-9 well location. Figure 3 shows the surface locations of wells (Le., disposal and storage wells, abandoned or other unused wells, production wells, dry holes, or any other wells) within one-quarter mile of the SU 43-9 well. These wells include the Sterling 32-9 production well, Sterling 41-15 production well, and the Marathon water well. A comprehensive list of freshwater wells in the area is listed in Appendix B. (2) List of operators and surface owners. · Marathon Oil Company is the sole operator of the Marathon Sterling Gas Field Unit that encompasses the one-quarter mile radius around the SU 43-9 well. The sole surface owner within a one-quarter mile radius of the SU 43-9 well is the Salamatof Native Association, Inc. Sterling DIO Application_REVISED.doc 1/22/2003 Application for a Dispos.ection Order - Marathon Oil Company e Page 3 of 6 · (3) Notification of operators and surface owners. The attached affidavit (Attachment 1) certifies that the Salamatof Native Association, Inc., the sole surface owners within a one-quarter mile radius, have been provided a copy of this application for the disposal of Class" oil field wastes in the SU 43-9 well. (4) Geologic Data. The formation for which a disposal injection order has been requested is characterized by alternating fluvial sandstones and shales of the Tertiary age in the Sterling formation, with occasional coals that vary in thickness from a few feet to ten feet. Sand quality is excellent, with porosity typically ranging from 25 to 35 percent (25-35%). Permeability determined from a recent production test in the nearby Sterling Unit 32-9 well is in excess of 200 millidarcies. These test values compare favorably with estimates of permeability from wireline nuclear magnetic resonance logs obtained in the same well. This device was run only over the primary zones of interest. However, the similarity in permeability and porosity values make extrapolation of similar values to the shallower sands in the disposal interval a reasonable undertaking. See Application for an Aquifer Exemption Order, Sterling Gas Field Unit, Kenai Peninsula, Alaska, October 2002 (MOC, 2002). · The proposed injection interval is the 8-4 Sand of the Sterling Formation. This interval is a gas producing formation between 5,020 feet SSTVD and 5,120 feet SSTVD in the vicinity of the SU 43-9 well. The SU 32-9 well is a producer from the same 8-4 sand but will not be adversely impacted by the disposal of Class " wastes during its anticipated remaining life. Injection modeling into the 8-4 Sand through the SU 43-9 well demonstrate that the disposal of oil field wastes into this formation is expected to have an inconsequential effect on the gas production rate and reserve recovery for the SU 32-9 well (Attachment 2). (5) Logs. The logs of the SU 43-9 well are on file at the AOGCC. (6) Demonstrating mechanical integrity of casing and tubing. The SU 43-9 well met the mechanical integrity requirements of 20 AAC 25.412 during a test conducted on October 23, 2002, which was witnessed by the AOGCC. A copy of the report from that test is attached (see Attachment 3). The method proposed for testing the mechanical integrity of the casing and tubing after receiving the disposal injection order is provided in Attachment 3 as well. Notice will be made in advance of that mechanical integrity test to allow a representative of the Commission to witness the test prior to converting the well for the purpose of injection. · An injectivity test was conducted for the Sterling 8-4 interval on February 25, 2000, using an electric line log to verify zonal isolation. Specifically, the electric log suite included a borax activation log, stationary water flow measurements (i.e. oxygen activation log), and pressure and temperature logs. The procedure used to demonstrate that fluids would not move behind the casing beyond the approved disposal zone is provided in Attachment 4, along with technical data describing the logging method. An independent analysis of the findings Sterling DIG Application_REVISED.doc 1/22/2003 Application for a Dispos"ection Order - Marathon Oil Company e Page 4 of 6 · of the injectivity test is presented in Attachment 5. The test results shown in Attachment 5 confirm that injected fluids are confined to the sands in that interval even though the injectivity test was performed at an equivalent rate exceeding 4,000 barrels per day (3.2 BPM). As described in the independent analysis, stationary water flow measurements were taken immediately below the packer (5,247.8'), immediately above the packer (5,237.8'), and some distance above the packer (5,217.8'). Each of these stationary flow measurements, conducted while injecting fluid into the Sterling B4 perforations, demonstrates zero behind- pipe water flow. This data provides strong evidence that the injected fluids are fully contained in the vicinity of the Sterling B4 perforations and that adequate zonal isolation exists. The borax activation log demonstrates that the majority of injection fluid is confined in the vicinity of the Sterling B4 perforations (5,262' to 5,272' MD). There are, however, minor indicators of borax as high up as 5,223 feet MD. The magnitude of this indicator at 5,223 feet suggests that the borax source is likely to be residual borax inside the tubing string, and not evidence of behind-pipe movement of waters. Even though residual borax in the tubing is the most likely interpretation of the indicators at 5,223 feet MD, the borax log by itself is inconclusive regarding the possibility of behind-pipe fluid movement. · The temperature log demonstrates conclusively that no behind-pipe movement of fluids occurred below the perforations. Above the perforations the temperature profile is altered by the normal injection process, so the temperature log alone is inconclusive in determining behind-pipe movement of fluids above the perforations. In summary, all of the injection log data is consistent in support of a conclusion that the injection fluids are confined in the immediate vicinity of the Sterling B4 perforations. By themselves, the borax activation log and temperature log are inconclusive. But when all of the log data is considered, a consistent, technically justifiable conclusion can be reached that zonal isolation is adequate around the Sterling B4 perforations. The description of the construction of the SU 43-9 well, including the cement program used during its installation, is shown in Attachment 6. In accordance with 20 AAC 25.412(b), the 2% inch tubing used in well SU 43-9 is rated to a burst pressure of 7,700 psi, which is better than 2.5 times the maximum injection pressure of 3,000 psi. The packer is located at 5,241 feet MD, which is 21 feet above the top perforation of the disposal interval. (7) Description of oil field wastes to be injected. · This Class II well will be primarily used for the injection of formation fluids (produced water, natural gas condensates, etc.) from the other gas production wells. Marathon requests permission to dispose of approved Class II fluids from other Marathon operated fields as well. These fluids are completely compatible with fluids in this formation. Typical Class II wastes requested for injection include: drilling, completion, workover, and production fluids, glycol dehydration wastes, rig wash, drilling mud slurries, tank bottoms, NORM scale, precipitation within containment areas, and other approved Class II wastes. The above listed Class II wastes would be generated from drilling, completion, workover, and production operations. Current projections estimate that a maximum of 1,000 barrels per day of fluids will be injected. Sterling DiO Application_REViSED.doc 1/22/2003 Application for a Disposaection Order - Marathon Oil Company e Page 5 of 6 . (8) Estimated pressure. The estimated average injection pressure will be 1,800 psig and maximum injection pressure will be 3,000 psig. (9) Evaluation of confining zones. BJ Services was contracted to model the hydraulic fracture potential of the planned injection operation in the Sterling B-4 Sand. The fracture simulation duplicates injection conditions that are anticipated at the SU 43-9 well. The simulated disposal fluids include a small concentration of fine solids that are likely to accompany any disposal operation. These solids make the prediction of fracture height growth more realistic because the solids tend to plug permeable layers and enhance fracture height growth. The simulation was conducted assuming constant injection for over one year. The simulation predicts that at rates up to 1,440 barrels per day the injection fluid is almost immediately lost to leakoff in the formation, causing no sustained fracture growth. The simulation was run at injection rates exceeding Marathon's 1,000 barrels per day limit, yet the confining zones were adequate to prevent vertical fracture growth. This simulation clearly demonstrates that fractures will not initiate or propagate through the confining zones that might enable the oil field wastes or stored hydrocarbons to enter freshwater strata (see Attachment 7A). . A second simulation run was made to estimate the fracture dimensions that are created if drilling mud and associated drilling cuttings are disposed into the Sterling B4 Sand in well SU 43-9. The conditions of this simulation closely match the actual conditions used to dispose of drilling mud and cuttings in Marathon's nearby Kenai Gas Field. That is, the solids content in the disposed fluid will not exceed 25% of the volume of the slurry and the total injection period will last two weeks or less. The solids in the disposal fluids were modeled by assuming a solids content of 5.5 Ibs of 100-mesh sand added per gallon of fluid. The use of 100-mesh sand represents a worst-case scenario from a fracture growth standpoint, as 100-mesh sand tends to reduce leakoff into permeable layers and maximize potential for fracture height growth. Injection rate !S held at 1,440 barrels per day, and the maximum allowable injection pressure is 3000 psi. This high concentration of solids represents a worst-case scenario for the potential for fracture height growth. (See Attachment 7B.) This second simulation does show more fracture height growth than the original injection scenario which contained a low concentration of solids, but the fracture is still easily contained within acceptable bounds. This worst-case model demonstrates that fractures will not initiate or propagate through the confining zones that might enable the oil field wastes or stored hydrocarbons to enter freshwater strata. (10) Standard Laboratory water analysis. A laboratory water analysis of formation waters from the Sterling B-4 Sand obtained from the SU 43-9 well in 1995 yielded 1,931 mg/I TDS, and 1,615 mg/I NaCI equivalent (see Attachment 8). . Sterling DIO Application_REVISED.doc 1/24/2003 Application for a Dispos.ection Order - Marathon Oil Company e Page 6 of 6 · (11) Freshwater exemption. The freshwater aquifer exemption application prepared, in accordance with 20 AAC 25.440, was submitted to the AOGCC on October 17, 2002. (12) Well report for disposal zone. No wells penetrate the Sterling B-4 Sand within a one-quarter mile radius of the SU 43-9 well. The two Marathon natural gas production wells, SU 32-9 and SU 41-15, shown on the surface maps (See Figures 2 and 3) were directionally drilled. Because wells SU 32-9 and SU 41-15 were directionally drilled, they both penetrate the Sterling B-4 Sand more than one-quarter mile away even though they are both within 150 feet of the surface location of well SU 43-9. Well SU 32-9 penetrates the B-4 Sand at 0.32 miles west of SU 43-9. Well SU 41-15 penetrates the B-4 Sand at 0.33 miles southeast of well SU 43-9. The surface casing strings for wells SU 32-9 and SU 41-15 are both adequately cemented with full cement returns to the surface. Well SU 32-9 has 9% inch casing to 2,111 feet MD (1,836' SSTVD) and was cemented with 620 sacks of cement. Well SU 41-15 has 13% inch casing to 2,271 feet MD (2,034' SSTVD) and was cemented with 1,186 sacks of cement. Both of these wells were constructed in 1999, and the mechanical condition of both wells is excellent. Wellbore schematics for these wells are provided in Attachment 9 and Attachment 10. · Conclusion Marathon trusts that this application meets the requirements for a Disposal Injection Order as outlined in 20 AAC 25.252. · Sterling DiG Application_REViSED.doc 1/22/2003 I Figures Application for a Disposal Injection Order - Marathon Oil Company Figure 1 Figure 1. Cook Inlet regional map (ADNR, 1999). Application for a Disposal In' Marathon Acrnage Status of Wells SU Producing SU Shut-in SU41-15S:Active SU 41-151.: Shut-in SU 23-15: Temp. Abandonment o 112 . , MILE Order - Marathon Oil Company 2 :13 34 T6N _ R10vJ5 36 MARATHON OIL COMPANY ALASKA REGION COOK INLET. ALASKA 2. Sterling Gas Field with wells and MOC's well. Application for a Disposallnj Order - Marathon Oil Company 3 LniEND AND NOTES I} is based Ataska Stale Plane Coordiuuk' Systcll! (Zon1...· "I) 2) datum is on mean st:;a level pf 0.000 mch.'r~ J) An wdls within Ì/·t mik' üfStJ ,t3-0Q arc ~hnv\'n hen:on 4) ('on1nurs :;hÜWH hereon an.' at 5 nlt.'ter ink'r",;!' ·10(( Prepared By: Prepared F()r: C;-roup T estí"g iv1ara¡hnn Oil ('{)lnpany· Ala"};;,, Region P.O. ijn, 19h¡6~ Anchoragê. AK 9q5t{)~6ì6k Dnnvinµ: su439 pc-rnHuh\',!,! Figure 3. Map wells. I Attachment 1 · · · Application for a DisposallnjAn Order - Marathon Oil Company Attachment 1 Affidavit of Fact AFFIDAVIT OFF.ACT STATE OF ALASKA ) THIRD JUDlCAL DISTRICT ) 55 KNOW ALL MEN BY THESE PRESENTS J. Brock Riddle, first sworn, and states as fbllows: . Attachment 1 I. Affiant is the Land such capaeíty has Peninsula. thr Marathon Oíl (Marathon) Alaska Business Unit, and in of all Marathon activíties in the State of including the Kenai 2, Affiant is well. and acquainted wíth the Marathon Gas Unit located in T5N-RWW, Seward Meridian, and more specifically, Unit Well #43·9 located PSI. and 521.5' PEL ofSectÍon 9·5N·WW. within a 1!4-mile radins of the aforementioned well. is held by Salamatof Inc., whose primary contact is Mr. Jim President. 3. A 11 of the surfitce Native 4. Marathon is the only Operator ofoi! and gas activities within the same 1M-mile radius. 5. Affiant further states that Salamatof Native Ine. has been duly notified of Marathon's Application for Injeeti.on Wen affecting the Sterling Unit Well #43·9. FURTIIER AFFIANT SA YETH NOT bruary, 2002 State of Alaska ) ss Third Judicial District ) The Marathon Oil Instrumcnt was acknowledged before me by J. Brock Riddle. on this 4th of February, 2002. Public: My Commission Business Unit Land Attachment 2 Application for a Disposal Inj.>n Order - Marathon Oil Company . Attachment 2 Page 1 of 8 · Attachment 2 Sterling Water Disposal Model Summary L. C. Ibele 6/9/99 Updated 2/16/00 Purpose of Model The model was constructed by E&PT under a TSR from the Alaska Region for the purpose of evaluating water injection into the Sterling B-4 horizon in Well SU 43-9 to determine if any effect would occur on the B-4 gas production from new well, SU 32-9. The model work was completed in June, 1999. Model Summary Results of the model indicate that continuous water injection/disposal into the existing B-4 perforated interval of Well SU 43-9 at the maximum anticipated rate will have very inconsequential effect on gas production rate and reserve recovery from Well SU 32-9. · Model Set-up The model grid is an extra fine cartesian grid, using the Sterling B-4 structural map provided by O. L. Brimberry; constant porosity across the field. There are 16 permeability layers based on SU 32-09 CMR log interpretations by P. S. Gardner, with equivalent permeability calibrated by PBU results from Well 32-9. The fine gridding was specified to allow for sensitivity to water coning, and to permit future use of the model for horizontal well evaluation, if desired. Wells in the model include 23-15, 43-9, and 32-9. All historic production and pressure data were incorporated and a history match file was created. A VFP (vertical flow profile) table was created for the 32-9 completion using WAM. The WAM files were created using production test information and reservoir characteristics from Saphir analysis of the March pressure build-up test. Incorporating the VFP table into the model allowed use of tubing pressure values based on actual pipeline pressure to limit rates and recoveries. Therefore, the recoveries predicted by the model are based upon current conditions only; recoveries may be improved thru use of compression in the future. · Prediction Cases . Base cases were run using IP rates of 3 and 5 mmcfd from SU 32-9 (See Tables 1, 2 and 3) to determine the ultimate recoveries without water injection into the offset wellbore (SU 43-9). Production rates were varied to determine if gas recovery and potential water coning are rate dependent. . For the 5 mmcfd base case, the model was run with a water injection rate of 500 BPO. This figure was based on initial tests for 41-15L (Tyonek completion) which produced at water rates approaching 100 BPO, and model forecast results for the O:\Sterling\43-9\UIC\2002 Applications\Disposallnjection\Attachment 2.doc 1/22/2003 · · · Application for a Disposal Inj~m Order - Marathon Oil Company . Attachment 2 Page 2 of 8 32-09 Sterling B-4 completion which predicts future water rates approaching 300 BPD. The remainder allows for any water production from the 41-15s (Beluga) completion, should all three wells be produced simultaneously. Thus, the 500 BWIPD most likely represents the worst case water injection scenario. · In the model, Well 32-09 was produced with a 700 psi drawdown limitation, a 250 psi flowing tubing pressure limitation (note: compression will be required to produce at FTPs less than 700 psig), and a 100 psig flowing bottom hole pressure limitation. Run results indicate that the drawdown limit and the FTP limit do have an effect on production rates. Model Results · Attached are tables of output data from the two comparative model runs. Table 1 is the base case at an initial rate of 5000 MCFD from SU 32-9 with zero water injection into SU 43-9. Table 2 is the same case, only water injection into SU 43-9 is maintained at a constant rate of 500 BPD throughout the run. · Cumulative gas recovery for the period 6/1/99 through 1/1/2016 is 12.797 BCF for the base case (no water injection) vs. 12.384 BCF for the case with injection. The difference in recovery is 0.413 BCF or 3.2%. · The difference in cumulative recovery for this "worst case" injection scenario (500 BWPD throughout the model life) is considered negligible. · Attached are two graphs showing Cumulative Gas Production vs. Time (See Graph 1) and Daily Gas Production Rate versus Time (See Graph 2) for the two comparative cases. · "RESVIEW" software was used to visually analyze the movement of water in the reservoir. Results indicate that the water injected into the existing perforations of SU 43-9 falls rapidly through the reservoir (due to gravity) and causes the overall gas-water contact to rise uniformly, rather than creating a piston-like waterflood displacement moving toward producer SU 32-9. (See Figures 1 and 2). O:\Sterling\43-9\UIC\2002 Applications\Disposallnjection\Attachment 2.doc 1/22/2003 ,,' \ Application for a Disposal Injection Order - Marathon Oil Company Table 1. Attachment 2 Sterling Unit Model Results Page 3 of 8 (' Sterling Unit Model "sgffor211 Results, 5000 MCFD initial gas production rate (SU 32-9) with zero water injection (SU 43-9). ----------- ---.---- -----..----- ------ --------- ---------- ---- -------- ---...------ --------- ------ ..-...----- ----- -----..--- ------- -------- ------ ---------- ---------- ---- --------- SUMMAR'! RUN sgffor2 RUN sgffor2 RUN sgffor2 ----------- --------- ---------- ----------- --------- ----------- ------- ------ ---------- -- ----...------ ..---......-..-- ----- - -------- --------- ------ ------ ---------- ---------- -...------ ---.......------ ------------ DATE YEARS DAY MONTH YEAR FWSAT FWIP FGIP FWPR FGPR FPR FWCT FGPT FWPT FPPG WGPR WWPR WGPT WWPT WV\ÌI R WBHP WBHP WTHP WBP9 WBP9 WBP WBP YEARS STB MSCF STB/DAY MSCF/DA~ PSIA MSCF STB PSIA MSCF/DA~ STB/DAY MSCF STB STBIDAY PSIA PSIA PSIA PSIA PSIA PSIA PSIA *10*"3 *10**3 * 1 0**3 *10**3 43-09 32-09 43-09 32-09 32-09 43-09 32-09 43-09' 32-09 32-09 32-09 32-09 --------- -...------ --..----..-- ----------- ----------- -----...------ -----...----- ----------- ------------ ------- -------- --------- ---------- ---------- ----------- --------- ----------- - -~ -- ---------- ------......- --------- ...-------..----- ------------ -...-------- ------------- -----...----..-- 1-Jun-99 37.013 1 6 1999 0.863356 116342.5 15402.19 30.42762 5000 2039.971 1 2700.585 8351.95 2040.485 5000 30.42762 155 145.7989 0 1598.696 2035.847 1391.921 1998.572 2035.848 1983.551 0 1-Jul-99 37.09514 1 7 1999 0.863699 116340 15254.52 128.5119 4537.833 2026.887 1 2848.499 .10844.64 2027.399 4537.833 128.5119 302.9135 2638.489 0 1242.882 2022.119 1054.978 1971.963 2022.119 1945.118 0 1-Aug-99 37.18002 1 8 1999 0.86399 116335 15134.02 178.2521 3562.227 2016.294 1 2969.044 15904.99 2016.804 3562.227 178.2521 423.4585 7698.837 0 1220.325 2012.018 1022.388 1957.523 2012.018 1922.711 0 1-Sep-99 37.26489 1 9 1999 0.864227 116329.3 15031.3 187.02 3201.098 2007.092 1 3071.952 21604.02 2007.6 3201.098 187.02 526.3665 13397.87 0 1209.063 2003.205 1008.642 1948.166 2003.205 1911.59 0 1-0ct-99 37.34702 1 10 1999 0.864436 116323.6 14937.32 191.9515 3080.855 1998.573 1 3165.742 27303.311999.079 3080.855 191.9515 620.1567 19097.16 0 1200.214 1994.847 998.9012 1939.734 1994.847 1902.784 0 1-Nov-99 37.4319 1 11 1999 0.a64641 116317.5 14842.9 195.6548 3009.924 1989.985 1 3259.87 ·33321.93 1990.49 3009.924 195.6548 714.2847 25115.78 0 1191.615 1986.328 989.9657 1931.251 1986.328 1894.197 0 1-Dec-99 37.51403 1 12 1999 0.864834 116311.5 14753.3 198.7133 2959.199 1981.81 1 3349.254 39246.75 1982.312 2959.199 198.7133 803.6693 31040.59 0 1183.03 1978.175 981.2 1922.893 1978.176 1885.622 0 1-Jan-00 37.5989 1 1 2000 0.865029 116305.2 14662.24 201.2757 2914.55 1973.462 1 3440.174 45453.65 1973.963 2914.55 201.2757 894.5891 37247.5 0 1174.471 .1969.843 972.632 1914.468 1969.844 1877.067 0 1-Feb-00 37.68378 1 2 2000 0.865221 116298.9 14572.42 203.8267 2878.101 1965.197 1 3529.863 51739.5 1965.696 2878.101 203.8267 984.2774 43533.35 0 1165.8 1961.587 964.0739 1906.004 1961.587 1868.403 0 1-Mar-00 37.76318 1 3 2000 0.865397 116292.8 14489.44 206.1762 2845.21 1957.528 1 3612.766 57690.39 1958.025 2845.21 206.1762 1067.181 49484.25 0 1157.689 1953.921 956.0911 1898.107 1953.921 1860.3 0 1-Apr-00 37.84805 1 4 20QO 0.865584 116286.3 14401.75 208.6208 2811.427 1949.398 1 3700.357 64125.82 1949.893 2811.427 208.6208 1154.772 55919.67 0 1149.22 1945.794 947.765 1889.81 1945.794 1851.837 0 1-May-00 37.93018 1 5 2000 0.865763 116280 14317.82 210.8625 2780.298 1941.592 1 3784.148 70424.01 1942.085 2780.298 210.8625 1238.562 62217.86 0 1140.965 1937.99 939.7155 1881.771 1937.99 1843.589 0 1-Jun-00 38.01506 1 6 2000 0.865945 116273.4 14232.06 213.0347 2749.581 1933.587 1 3869.787 76999.88 1934.079 2749.581 213.0347 1324.202 68793.73 0 1132.644 1929.987 931.6377 1873.609 1929.987 1835.273 0 1-Jul-00 38.09719 1 7 2000 0.866119 116267 14150 215.104 2718.775 1925.899 1 3951.733 83427.53 1926.389 2718.775 215.104 1406.148 75221.38 0 1124.486 1922.3 923.7245 1865.68 1922.3 1827.124 0 1-Aug-00 38.18207 1 8 2000 0.866297 116260.2 14066.14 217.1369 2688.668 1918.019 1 4035.47 90132.45 1918.507 2688.668 217.1369 1489.885 81926.29 0 1116.314 1914.421 915.8206 1857.657 1914.421 1818.956 0 1-Sep-00 38.26694 1 9 2000 0.866473 116253.4 13983.21 219.0235 2660.729 1910.196 1 4118.308 96898.05 1910.683 2660.729 219.0235 1572.722 88691.9 0 1108.173 1906.599 908.0225 1849.674 1906.6 1810.822 0 1-0ct-00 38.34908 1 10 2000 0.866641 116246.8 13903.74 220.7111 2635.447 1902.674 1 4197.683 103498.7 1903.159 2635.447 220.7111 1652.098 95292.52 0 1100.324 18~9.076 900.5733 1841.982 1899.077 1802.98 0 1-Nov-OO 38.43395 1 11 2000 0.866813 116239.9 13822.45 222.4055 2609.713 1894.943 1 4278.923 110371 1895.426 . 2609.713 222.4055 1733.338 102164.8 0 1092.407 1891.345 893.0168 1834.156 1891.345 1795.066 0 1-Dec-00 38.51609 1 12 2000 0.666978 116233.1 13744.51 223.9015 2584.033 1887.506 1 4356.761 117069.8 1887.988 2584.033 223.9015 1811.176 108863.6 0 1084.716 1883.902 885.7104 1826.59 1883.903 1787.381 0 I( 1-Jan-01 38.60096 1 1 2001 0.867146 116226.1 13664.83 225.3615 2558.668 1879.873 1 4436.409 124036.9 1880.353 2558.668 225.3615 1890.824 115830.8 0 1077 1'876.26 878.4001 1818.922 1876.261 1779.669 0 1-Feb-01 38.68583 1 2 2001 0.867312 116219 13585.89 226.7069 2534.527 1872.291 1 4515.288 131047.7 1872.769 2534.527 226.7069 1969.702 122841.6 0 1069.286 ¡1868.676 871.1516 1811.275 1868.676 1771.959 0 1-Mar-01 38.76249 1 3 2001 0.867462 116212.6 13515.22 227.8276 2513.684 1865.482 1 4585.909 137414.1 1865.958 2513.684 227.8276 2040.324 129208 0 1062.332,1861.862 864.665 1804.393 1861.863 1765.01 0 1-Apr-01 38.84737 1 4 2001 0.867625 116205.4 13437.66 228.9545 2492.281 1857.986 1 4663.445 144497.1 1858.461 2492.281 228.9545 2117.86 136291 0 1054.751 1854.364 857.6494 1796.856 1854.364 1757.433 0 1-May-01 38.9295 1 5 2001 0.867782 116198.4 13363.22 230.0155 2472.013 1850.771 1 4737.854 151384.5 1851.243 2472.013 230.0155 2192.269 143178.3 0 1047.375 ,1847.145 850.8491 1789.556 1847.146 1750.062 0 1-Jun-01 39.01437 1 6 2001 0.867943 116191.2 13286.88 231.0236 2452.545 1843.353 1 4814.137 158533 1843.824 2452.545 231.0236 2268.551 150326.9 0 1039.906 1839.722 844.0054 1782.114 1839.723 1742.596 0 1-Jul-01 39.09651 1 7 2001 0.868098 116184.3 13213.58 231.9286 2433.836 1836.21 1 4887.383 165479.8 1836.679 2433.836 231.9286 2341.798 157273.7 0 1032.614 1832.577 837.3594 1774.892 1832.579 1735.308 0 1-Aug-01 39.18138 1 8 2001 0.868257 116177 13138.4 232.7944 2415.155 1828.866 1 4962.496 172685.2 1829.333 2415.155 232.7944 2416.91 164479.1 0 1025.2231825.229 830.6457 1767.529 1825.231 1727.92 0 1-Sep-01 39.26625 1 9 2001 0.868414 116169.8 13063.82 233.5876 2396.768 1821.557 1 5037.03 179916.3 1822.023 2396.768 233.5876 2491.445 171710.2 0 1017.824 1817.917 823.9593 1760.178 1817.919 1720.526 0 1-0ct-01 39.34839 1 10 2001 0.868565 116162.7 12992.18 234.2912 2379.523 1814.516 1 5108.628 185936.4 1814.981 2379.523 234.2912 2563.043 178730.2 0 1010.649 1810.872 817.5115 1753.069 1810.875 1713.356 0 1-Nov-01 39.43327 1 11 2001 0.86872 116155.4 12918.66 234.9718 2362.642 1807.274 1 5182.089 194211.7 1807.737 2362.642 234.9718 2636.504 186005.5 0 1003.371 1803.624 810.9949 1745.813 1803.627 1706.081 0 1-Dec-01 39.5154 1 12 2001 0.868869 116148.3 12848 235.6262 2346.545 1800.311 1 5252.685 201272.3 1800.772 2346.545 235.6262 2707.099 193066.2 o 996.2784 1796.662 804.6549 1738.783 1796.665 1698.993 0 1-Jan-02 39.60027 1 1 2002 0.86902 116140.8 12775.55 236.2767 2330.698 1793.179 1 5325.143 208588.4 1793.638 2330.698 236.2767 2779.557 200382.3 o 989.0941 ,1789.529 798.2269 1731.627 1789.532 1691.811 0 1-Jun-02 40.01369 1 6 2002 0.869743 116104.8 12429.18 239.0819 2258.49 1758.938 1 5671.304 244495.7 1759.389 2258.49 239.0819 3125.718 236289.5 o 954.4059 :1755.247 767.2899 1697.136 1755.25 1657.141 0 1-Sep-02 40.26557 1 9 2002 0.870173 116082.6 12223.25 240.5921 2218.203 1738.377 1 5877.116 266565 1738.823 2218.203 240.5921 3331.53 258358.9 o 933.5743 ,1734.667 748.8804 1676.425 1734.67 1636.318 0 1-Jan-03 40.59959 1 1 2003 0.870734 116053 11955.71 242.4321 2168.6571711.432 1 6144.526 296037.4 1711.871 2168.657 242.4321 3598.941 287831.2 o 906.2981 1707.698 724.9457 1649.29 1707.701 1609.053 0 1-Jun-03 41.013 1 6 2003 0.871416 116016 11632.57 244.1581 2113.01 1678.38 1 6467.609 33?787.8 1678.811 2113.01 244.1581 3922.024 324581.7 o 872.9665 1674.616 696.0583 1616.072 1674.619 1575.73 0 1-Sep-03 41.26489 1 9 2003 0.871826 115993.5 11439.71 245.0396 2079.488 1658.426 1 6660.363 355293.8 1658.852 2079.488 245.0396 4114.778 347087.7 o 852.8651 1654.649 678.738 1596.033 1654.651 1555.634 0 1-Jan-04 41.5989 1 1 2004 0.872362 115963.4 11188.57 246.0818 2037.659 1632.23 1 6911.376 385256.9 1632.65 2037.659 246.0818 4365.792 377050.8 o 826.5131 1628.431 656.1696 1569.743 1628.434 1529.289 0 1-Jun-04 42.01506 1 6 2004 0.873017 115925.8 10882.72 247.3355 1985.375 1600.008 1 7217.061 422758.9 1600.419 1985.375 247.3355 461'1.476 414552.7 o 794.07751596.185. 628.4177 1537.396 1596.187 1496.864 0 1-Sep-04 42.26694 1 9 20040.873404 115902.9 10701.53 248.0887 1953.075 1580.8 1 7398.142 44~550.9 1581.207 1953.075 248.0887 4852.557 437344.7 0 774.718 '1576.962 611.7812 1518.098 1576.963 1477.511 0 1-Jan-05 42.60096 1 1 2005 0.873909 115872.5 10465.82 249.1285 1910.635 1555.623 1 7633.719 475884.1 1556.023 1910.635 249.1285 5088.134 467677.9· o 749.3281 1551.763 589.9971 1492.795 1551.764 1452.13 0 1-Jun-05 43.01437 1 6 2005 0.874518 115834.7 10181.27 250.4325 1858.469 1524.919 1 7918.114 51,3603.8 1525.311 1858.469 250.4325 5372.528 505397.7 o 718.3518 1521.034 563.4824 1461.933 1521.035 1421.165 0 1-Jan-06 43.60027 1 1 2006 0.875358 115780.7 9790.943 252.8946 1789.634 1482.142 1 8308.233 567467 1482.524 1789.634 252.8946 5762.648 559260.8 (;) 674.9271 1478.216 526.4205 1418.778 1478.216 1377.759 0 1-Jun-06 44.01369 1 6 2006 0.875935 115742.3 9524.217 254.6471 1742.912 1452.431 1 8574.813 605789 1452.805 1742.912 254.6471 6029.228 597582.8 o 644.8243 '1448.479 500.867 1388.835 1448.479 1347.667 0 1-Jan-07 44.59959 1 1 2007 0.876726 115687.3 9158.269 257.3535 1677.1271411.121 1 8940.573 660576.1 1411.484 1677.127 257.3535 6394.988 652369.9 o 602.8821 1407.135 465.368 1347.156 1407.135 1305.744 0 1-Jun-07 45.013 1 6 2007 0.877268 115648.1 8908.536 259.4177 1630.579 1382.458 1 9190.177 6Q9597.1 1382.814 1630.579 259.4177 6644.592 691391 o 573.8026 1378.446 440.8255 1318.252 1378.445 1276.677 0 1-Jan-08 45.5989 1 1 2008 0.878011 115592.2 8566.42 262.3315 1566.718 1342.59 1 9532.063 7~$435.1 1342.935 1566.718 262.3315 6986.478 747228.9 o 533.3083 1338.547 406.8781 1278.026 1338.546 1236.202 0 1-Jun-08 46.01506 1 6 2008 0.878518 115552.1 8331.584 264.3611 1522.755 1314.866 1 9766.734 795470.6 1315.204 1522.755 264.3611 7221.149 787264.4 0 505.189 1310.801 383.4658 1250.08 1310.8 1208.096 0 1-Jan-09 46.60096 1 1 2009 0.879206 115495 8012.255 267.1291 1461 .562 1276.593 1 10085.87 852352.1 1276.92 1461.562 267.1291 7540.281 8441.45.9 o 466.3256 11272.501 351.1696 1211.483 1272.5 1169.252 0 1-Jun-09 47.01437 1 6 2009 0.879673 115454.5 7794.756 269.0433 1418.76 1250.155 1 10303.21 892834.9 1250.475 1418.76 269.0433 7757.629 884628.8 o 439.5774 ~246.052 329.00051184.878 1246.05 1142.517 0 1-Jan-10 47.60027 1 1 2010 0.880305 115396.4 7497.455 271.9104 1358.8991213.564 1 10600.29 95Q715.9 1213.875 1358.899 271.9104 8054.706 942509.8 o 402.4983 ~209.448 298.432 1148.023 1209.446 1105.462 0 1-Jan-11 48.59959 1 1 2011 0.881307 115295.9 70;20.391 276.3552 1256.35 1153.368 1 11077.02 1050946 1153.663 1256.35 276.3552 8531.436 1042740 o 343.2187 1149.234 250 1087.585 1149.233 1044.802 0 ( 1-Jan-12 49.5989 1 1· 2012 0.882207 115198.5 6587.88 257.5602 1121.2071097.493 1 11509~65 1148335 1097.773 1121.207 257.5602 8964.062 1140129 o 343.6995 '1093.438 250 1035.758 1093.437 995.9712 0 1-Jan-13 50.60096 1 1 2013 0.883031 115107.5 6199.545 239.4938 1005.576 1045.899 1 11898.07 1239210 1046.164 1005.576 239.4938 9352.486 1231004 o 344.0261 104'1.933 250 987.9817 1041.934 951.0002 0 1-Jan-14 51.60027 1 1 2014 0.883771 115023.1 5851.633 222.7026 904.8161 998.8827 1 12246.06 1323483 999.1353 904.8161 222.7026 9700.472 1315277 o 344.9604 995.0019 250 944.5115 995.001 910.1265 0 1-Jan-15 52.59959 1 1 2015 0.884447 114944.8 5538.387 207.0029 815.0916 955.6042 1 12559.35 1401838 955.8453 815.0916 207.0029 10013.77 1393632 o 346.3785 951.8284 250 904.571 951.8271 872.6024 0 1-Jan-16 53.5989 1 1 2016 0.884993 114883.5 5300.206 0 o 922.5056 o 12797.55 1463052 922.738 0 o 10251.96 1454846 o 920.2756 920.7666 o 920.2487 920.7653 920.2306 0 ! ,¡ It \ \ ~ Application for a Disposal Injection Order - Marathon Oil Company Table 2. Attachment: Sterling Unit Model Results Page 4 of ¿ f . Sterling Unit Model "sgfforS" Results, 5000 MCF:D initial gas production rate (SU 32-9) with 500 BPD water injection (SU .43-9). ----------- ------- - ----- -------- ----- ------ ------.......- ~----- ----- ------- --------- ...----...--- -----.. ------- ----------- ...------- ----------- ---------- ------------- SUMMAR" RUN sgfforS RUN sgfforS RUN sgfforS ------------- ------------ -...------...--- -------- ----------- ----------- ----- ------ ---- ----- . -------- ..---------- ------- --------... ---------- --------- ---...-......--- ------------ ------------- DATE YEARS DAY MONTH YEAR FWSAT FWIP FGIP FWPR FGPR FPR FWCT FGPT FWPT FPPG WGPR WWPR WGPT WWPT ·WWIR WBHP WBHP WTHP WBP9 WBP9 WBP WBP YEARS STB MSCF STB/DAY MSCF/DA) PSIA MSCF . STB· PSIA MSCF/DA) STB/DAY MSCF STB STB/DA Y PSIA PSIA PSIA PSIA PSIA PSIA PSIA *10**3 *10**3 *10**3 43-09 32-09 43-09 32-09 32-09 43-09 32-09 43-09' 32-09 32-09 32-09 32-09 ----------- -------- ----------- -----..---..---- ----------- --------- -..-----...--- ---------- ------------ --------- ---...----- -----..----- ------- --------- ----------.. ------------ ----------- -------------- ---------- -----..--- ----------..- ------------ ----------- ---------- --------- ------------- 1-Jun-99 37.013 1 6 1999 0.863443 116357.7 15402.5 28.86857 5000 2041.175 1 2700.585 8346.999 2041.69 5000 28.86857 155 140.848 500 1614.042 3549.465 1405.959 2000.063 2203.175 1985.031 0 1-Jul-99 37.09514 1 7 ,1999 0.863867 116370.2 15254.65 127.8479 4549.923 2029.162 1 2848.621 10822.66 2029.674 4549.923 127.8479 303.0355 2616.505 500 1245.578 3545.542 1057.468 1974.589 2197.937 1947.812 0 1-Aug-99 37.18002 1 8 1999 0.864242 116380.7 15133.92 177.8753 3574.166 2019.662 1 2969.475 15863.62 2020.172 3574.166 177.8753 423.8894 7657.474 500 1224.097 3541.674 1025.747 1961.233 2192.134 1926.48 0 1-Sep-99 37.26489 1 9 1999 0.864563 116390.5 15030.92 186.8979 3209.941 2011.541 1 3072.745 21557.08 2012.05 3209.941 186.8979 527.1596 13350.92 500 1213.871 3538.04 1012.79 1952.942 2186.736 1916.397 0 1-0ct-99 37.34702 1 10 1999 0.864852 116399.5 14936.98 191.869 3087.08 2004.041 1 3166.732 27253.85 2004.548 3087.08 191.869 621.1464 19047.7 500 1206:.013 3534.233 1003.852 1945.517 2180.833 1908.583 0 1-Nov-99 37.4319 1 11 1999 0.865141 116408.7 14842.49 195.5517 3016.54 1996.5 1 3261.062 33269.41 1997.006 3016.54 195.5517 715.4767 25063.26 500 1198.482 3530.223 995.8447 1938.093 2174.533 1901.064 0 1-Dec-99 37.51403 1 12 1999 0.865414 116417.5 14752.87 198.6746 2966.221 1989.347 1 3350.659 39191.66 1989.852 2966.221 198.6746 805.0739 30985.51 500 1191.024 3526.331 988.0339 1930.816 2168.383 1893.613 0 1-Jan-00 37.5989 1 1 2000 0.865691 116426.5 14661.81 201.42 2920.167 1982.063 1 3441.769 .45400.32 1982.566 2920.167 201 .42 896.184 37194.17 500 118~.374 3522.323 980.1429 1923.362 2162.04 1885.972 0 1-Feb-00 37.68378 1 2 2000 0.865967 116435.5 14571.96 204.1844 2882.604 1974.862 1 3531.615 51694.15 1975.363 2882.604 204.1844 986.0298 43488 500 1175.712 3518.337 972.3393 1915.928 2155.704 1878.317 0 1-Mar-00 37.76318 1 3 2000 0.866221 116443.8 14488.98 206.7805 2848.509 1968.189 1 3614.626 57659.55 1968.688 2848.509 206.7805 1069.041 49453.4 500 .1168~557 3514.594 965.0513 1909.002 2149.712 1871.17 0 1-Apr-00 37.84805 1 4 . 2000 0.866492 116452.6 14401.31 209.5333 2812.93 1961.123 1 3702.29 64119.03 1961.621 2812.93 209.5333 1156.705 55912.88 500 11611.092 3510.59 957.4281 1901.734 2143.267 1863.711 0 1-May-00 37.93018 1 5 2000 0.866751 116461.2 14317.48 212.2146 2778.441 1954.349 1 3786,069 70452.12 1954.847 2778.441 212.2146 1240.484 62245.97 500 1153.775 3506.757 949.9566 1894.675 2137.063 1856.404 0 1-Jun-00 38.01506 1 6 2000 0.867017 116469.9 14231.98 214.9892 2741.583 1947.421 1 3871.545 77080.63 1947.916 2741.583 214.9892 1325.96 68874.48 500 1146,388 3502.844 942.3544 1887.518 2130.694 1849.024 0 1-Jul-00 38.09719 1 7 2000 0.867272 116478.3 14150.27 217.5864 2705.352 1940.786 1 3953.'152 83576.15 1941.28 2705.352 217.5864 1407.566 75370 500 1139i185 3499.114 934.9567 1880.592 2124.599 1841.832 0 1-Aug-00 38.18207 1 8 2000 0.867532 116486.9 14066.97 220.0645 2671.669 1934.003 1 4036.404 90366.21 1934.495 2671.669 220.0645 1490.819 82160.06 500 1132~059 3495.297 927.6973 1873.635 2118.336 1834.712 0 1-Sep-00 38.26694 1 9 2000 0.86779 116495.4 13984.69 222.4733 2639.075 1927.284 1 4118.636 97231.95 1927.775 2639.075 222.4733 1573.051 89025.8 500 1124.976. 3491.511 920.5038 1866.723 2112.104 1827.637 0 1-0ct-00 38.34908 1 10 20000.868037 116503.4 13906.11 224.5072 2609.097 1920.842 1 4197.274 103942.7 1921.332 2609.097 224.5072 1651.689 95736.55 500 1118.182 3487.874 913.7063 1860.096 2106.09 1820.852 0 1-Nov-00 38.43395 1 11 2000 0.868289 116511.5 13825.91 226.2915 2581.262 1914.242 1 4277.651 110934.8 1914.731 2581.262 226.2915 1732.066 102728.7 500 1111~439 3484.168 907.0651 1853.427 2099.93 1814.113 0 1-Dec-00 38.51609 1 12 2000 0.868533 116519.6 13748.88 227.8758 2556.089 1907.903 1 4354.64~ 117751.7 1908.39 2556.089 227.8758 1809.058 109545.5 500 11 0~.85 3480.606 900.6589 1846.953 2093.979 1807.532 0 1-Jan-01 38.60096 1 1 2001 0.868783 116527.9 13670.03 229.3284 2532.419 1901.398 1 4433.452 124842.3 1901.883 2532.419 229.3284 1887.866 116636.2 500 1098.23 3476.953 894.2637 1840.389 2087.838 1800.916 0 ( 1-Feb-01 38.68583 1 2 ;ZOO 1 0.869033 116536.2, 13591.91 230.6156 2510.121· 1894.928 1 4511.549 131974.6 1895.412 2510.121 230.6156 1965.964 123768.5 500 1091~613 3473.087 887.9462 1833.838 2081.723 1794.304 0 1-Mar-01 38.76249 1 3 2001 0.869257 116543.6 13521.96 231.7375 2490.221 1889.115 1 4581:501 138450.4 1889.598 2490.221 231.7375 2035.919 130244.2 500 1085!639 3468.876 882.2596 1827.936 2076.207 1788.335 0 1-Apr-01 38.84737 1 4 2001 0.869503 116551.8 13445.16 232.8728 2468.789 1882.718 1 4658.313 145654.9 1883.199 2468.789 232.8728 2112.728 137448.7 500 10791127 3462.683 876.0946 1821.479 2069.996 1781.827 0 1-May-01 38.9295 1 5 2001 0.869741 116559.7 13371.41 233.8603 2448.872 1876.562 1 4732.02~ 152658.5 1877.042 2448.872 233.8603 2186.437 144452.4 500 1072.801 34~6.714 870.162 1815.23 2064.01 1775.507 0 1-Jun-01 39.01437 1 6 2001 0.869985 116567.9 13295.84 234.8348 2429.443 1870.237 1 4807.587 159925.7 1870.715 2429.443 234.8348 2262.002 151719.5 500 1 066.404 34~0.571 864.1855 1808.869 2057.849 1769.114 0 1-Jul-01 39.09651 1 7 2001 0:87022 116575.7 13223.3 235.7153 2410.991 1864.148 ·1 4880.143 166986.4 1864.625 2410.991 235.7153 ·2334.558 158780.3 500 1060,151'· 3444.655 858.3796 1802.691 2051.916 1762.866 0 1-Aug-01 39.18138 1 8 2001 0.870462 116583.8 13148.87 236.5424 2393.481 1857.888 1 4954.566. 174308.6 1858.364 2393.481 236.5424 2408.982 166102.5 500 1053.837 3438.571 852.5617 1796.402 2045.813 1756.556 0 1-Sep-01 39.26625 1 9 2001 0.'870703 116591.8 13074.98 237.3313 2376.528 1851.657 1 5028.458 181655.6 1852.131 2376.528 237.3313 2482.873 173449.5 500 1047.496 3432.506 846.7479 1790.109 2039.731 1750.219 0 1-0ct-01 39.34839 1 10 2001 0.870936 116599.6 13003.97 238.1122 2360.212 1845.653 1 5099.467·188789.3 1846.127 2360.212 238.1122 2553.882 180583.1 500 1041.339 3426.658 841.0948 1784.019 2033.866 1744.067 0 1-Nov-01 39.43327 1 11 2001 0.871175 116607.5 12931.15 238.8871 2344.044 1839.478 1 5172.343 196184.8 1839.949 2344.044 238.8871 2626.758 187978.6 500 1035.113 3420.634 835.3882 1777.814 2027.824 1737.843 0 1-Dec-01 39.5154 1 12 2001 0.871405 116615.3 12861.08 239.6015 2328.239 1833.526 1 5242.387. 203364.1 1833.997 2328.239 239.6015 2696.802 195157.9 500 1029.022 3414.827 829.8234 1771.785 2022.001 1731 .757 0 1-Jan-02 39.60027 1 1 2002 0.871643 116623.3 12789.18 240.3033 2312.513 1827.403 1 5314.28 210804.3 1827.872 2312.513 240.3033 2768.695 202598.2 500 1022.853 3408.852 824.1996 1765.635 2016.009 1725.59 0 1-Jun-02 40.01369 1 6 2002 0.872786 116661.7 12446.06 243.9116 2235.41 1797.995 1 5657;396 247371.8 1798.457 2235.41 243.9116 3111.81 239165.7 500 992.8892 3380.14 796.8109 1735.921 1987.213 1695.645 0 1-Sep-02 40.26557 1 9 2002 0.873469 116684.9 12242.58 246.0392 2189.807 1780.525 1 5860.84 269916.8 1780.984 2189.807 246.0392 3315.255 261710.6 500 975.033 33~3.041 780.4315 1718.236 1970.062 1677.802 0 1-Jan-03 40.59959 1 1 2003 0.874361 116715.4 11979.17 248.5876 2130.964 1757.736 1 6124:211 300c)97.7 1758.19 2130.964 248.5876 3578.626 291891.6 500 951.7834 3340.722 759.2203 1695.2 1947.677 1654.571 0 1-Jun-03 41.013 1 6 2003 0.875448 116752.8 11662.87 251.9619 2060.835 1730.079 1 6440:481 337883.7 1730.526 2060.835 251.9619 3894.896 329677.6 500 923.)502 3313.605 733.4183 1667.203 1920.478 1626.313 0 1-Sep-03 41.26489 1 9 2003 0.876101 116775.3 11475.27 254.4648 2019.27 1713.522 1 6628.018 3i31188.6 1713.964 2019.27 254.4648 4082.433 352982.4 500 906.ß29 3297.352 717.665 1650.316 1904.175 1609.157 0 1-Jan-04 41.5989 1 1 2004 0.876955 116804.7 11232.22 257.4684 1968.818 1691.82 1 6871.128 39"2428.2 1692.258 1968.818 257.4684 4325.544 384222.1 500 883.9þ28 3~76.031 697.223 1628.231 1882.789 1586.779 0 1-Jun-04 42.01506 1 6, . 2004 0.878009 116841 10937.65 261.1705 1908.85 1665.128 1 7165:625 431857.1 1665.56 1908.85 261 .1705 4620.04 423650.9 500 856.1463 3249.783 672.1658 1601.11 1856.464 1559.331 0 1-Sep-04 42.26694 .1 9 2004 0.878639 116862.7 10763.66 263.29 1874.635 1649.209 1 7339.577 4~5989.9 1649.637 1874.635 263.29 4793.992 447783.8 500 840.1218 3234:113 657.3612 1584.953 1840.748 1543.002 0 1-Jan-05 42.60096 1 1, 2005 0.879463 116891.1 10537.83 265.8433 1829.801 1628.368 1 7565.408, 488275.6 1628.791 1829.801 265.8433 5019.823 480069.5 500 818.8146 321'3.599 638.1498 1563.853 1820.177 1521.71 0 1-Jun-05 43.01437 1 6 2005 0.880469 116925.8 10265.83 269.0954 1774.635 1603 1 7837,436 528668.6 1603.416 1774.635 269.0954 5291.85 520462.5 500 792.8163 3188.618 614.7062 1538.134 1795.125 1495.731 0 1-Jan-06 43.60027 1 l' . ,2006 0.881862 116974.3 9894.634 273.9268 1695.982 1568.015 1 8208.508 586790.1 1568.423 1695.982 273.9268 5662.923 578583.9 500 756.8867 3154.149 582.2297 1502.627 1760.557 1459.833 0 1-Jun-06 44.01369 1 6 . 2006 0.882824 117007.9 9642.684 277.3583 1642.195 1543.946 1 8460.39å 6,28418.7 1544.348 1642.195 277.3583 5914.811 620212.5 500 732.2171 3130.419 559.9775 1478.233 1736.762 1435.186 0 1 ~Jan-07 44.59959 1 1 2007 0.884156 117054.5 9299.285 282.5147 1568.224 1510.687 1 8803.723· 688324.9 1511.08 1568.224 282.5147 6258.138 680118.7 500 698.0239 3097.599 529.1519 1444.456 1703.859 1401.027 0 1-Jun-07 45.013 1 6 ·2007 0.885075 117086.7 9066.696 286.3273 1514.355 .1487.789 1 9036.304 731"284.9 1488.177 1514.355 286.3273 6490.719 723078.8 .500 674.5637 3074.965 507.8836 1421.244 1681.169 1377.589 0 1-Jan-08 45.5989 1 1 2008 0.886346 117131.4 8750.756 290.7789 1441.214 1456.208 1 9352.?, 793067.9 1456.587 1441.214 290.7789 6806.615 784861.7 500 642.3~45 3043.754 478.7792 1389.3 1649.88 1345.37 0 1~Jun-08 46.01506 1 6 2008 0.887229 117162.8 8535.36 293.5687 1393.24 1434.411 1 9567.486 837484.8 1434.784 1393.24 293.5687 7021.901 829278.6 500 620.1,05 3022.207 458.9421 1367.282 1628.28 1323.175 0 1-Jan-09 46.60096 1 1 200ß 0.888441 117206.2 8244.262 297.3506 1328.893 1404.578 1 9858.469 900728.1 1404.944 1328.893 297.3506 7312.884 892521.9 500 589.5;27 2~92.704 431.8842 1337.103 1598.704 1292.698 0 1-Jun-09 47.01437 1 6 2009 0.889281 117236.4 8046.761 300.0282 1287.249 1384.006 1 10055.87 945830.8 1384.366 1287.249 300.0282 7510.287 937624.6 500 568.5 94 2972.339 413.4434 1316.298 1578.289 1271.713 0 1-Jan-10 47.60027 1 1 2010 0.890444 117278.5 7777.608 303.5251 1229.107 1355.581 1 10324.94 1010433 1355.933 1229.107 303.5251 7779.354 1002227 500 539.4~96 2944.229 388.054 1287.525 1550.109 1242.652 0 1-Jan-11 48.59959 1 1 2011 0.89236 117348.7 7345.475 308.3744 1140.926 1309.081 1 10756;95 1122138 1309.42 1140.926 308.3744 8211.364 1113932 500 492.1092 2898.226 346.4159 1240.555 1503.994 1195.302 0 1-Jan-12 49.5989 1 1 2012 0.89420~ 117417.3 6944.168 313.0781 1058.418 1264.766 1 11158.13 1235532 1265.094 1058.418 313.0781 8612.548 1227326 500 446.8956 2854.347 306.6486 1195.775 1460.007 1150.129 0 ( 1-Jan-13 50.60096 1 1 2013 0.895971 117484.2 6571.253 318.8545 979.8524 1222.618 1 11530.88 1351156 1222.935 979.8524 318.8545 8985.293 1342950 500 403.6088 2812.602 268.1552 1153.025 1418.158 1106.886 0 1-Jan-14 51.60027 1 1 2014 0.897658 117549.9 6228.775 314.5734 892.353 1183.025 1 11873.35 1467636 1183.331 892.353 314.5734 9327.762 1459429 500 387.0027 2773.439 250 1114.776 1378.897 1069.592 0 1-Jan-15 52.59959 1 1 2015 0.899278· 117619.9 5919.539 301.2658 805.9818 1146.855 1 12182.7 1579974 1147.151 805.9818 301.2658 9637.119 1571768 500 393.i¡J46. 2737.69 250 1081.56 1343.058 1038.521 0 1~Jan-16 53.5989 1 1 2016 0.90073 117725 5717.659 0 o 1126.517 o 12384.76 1657109 1126.807 0 o 9839.171 1648902 500 1124.654 2715.966 0 1124.595 1324.366 1124.581 0 ~, Application for a Disposal Injection Order - Marathon Oil Company Table 3. Attachment 2 Sterling Unit Model Results Page 5 of 8 ( Sterling Unit Model "sgffor2" Results, 3000 MCFD initial gas production . rate (SU 32-9) with zero water injection (SU 43-9). ----------- ...-------_. ------... ------- -------- ------ -------- ------- --- ------- -------- ------- -- ---...- ------ ------... ------- -------- ---------...-- ----------- SUMMAR~ RUN sgffor2 RUN sgffor2 RUN sgffor2 ------------- ..------- --------- -------.- ------- --------- ---------. -..------ ----- ------ --------- --------. - ... ------ ---- --. ------ ----- -_____ _________. _r.--___ ----------- ------------ DATE YEARS DAY MONTH YEAR FWSAT FWIP FGIP FWPR FGPR FPR FWCT FGPT FWPT FPPG WGPR WWPR WGPT WWPT WWIR WBHP WBHP WTHP WBP9 WBPS WBP WBP YEARS STB MSCF STB/DAY MSCF/DA~ PSIA MSCF STB PSIA MSCF/DA~ STB/DAY MSCF STB STB/DAY PSIA PSIA PSIA PSIA PSIA PSIA PSIA *10**3 *10**3 *10**3 *10**3 43-09 32-09 43-09 32-09 32-09 43-09 32-09 43-09' 32-09 32-09 32-09 32-09 ------- ----- -------- ------------. ---- --------- -------- ---......---- ----- ---------- ------- ---- -------- ------ - --------- ------- ---------- ------- ---- _______....__ ----______0 -....--..---- --..--------- ------------- 1-Jun-99 37.013 1 6 1999 0.863241 116342.7 15464.19 0 3000 2045.837 o 2638.585 8206.151 2046.353 3000 0 93 0 0 1975.82 2043.032 1740.806 2024.107 2043.033 2017.354 0 1-Jul-99 37.09514 1 7 1999 0.863456 116342.5 15374.22 16.49346 3000 2037.965 1 2728.585 8367.781 2038.479 3000 16.49346 183 161.6306 o 1783.202 2034.791 1564.411 2012.346 2034.791 2003.424 0 1-Aug-99 37.18002 1 8 1999 0.86368 116341.6 15281.23 37.33745 3000 2029.84 1 2821.585 9246.08 2030.353 3000 37.33745 276 1039.929 o 1672.507 2026.528 1458.553 2001 .122 2026.528 1990.384 0 1-Sep-99 37.26489 1 9 1999 0.863902 116339.9 15188.25 68.59422 3000 2021.648 1 2914.585 10921.16 2022.159 3000 68.59422 369 2715.01 o 1557.151 2018.253 1345.658 19&7.386 2018.253 1972.062 0 1-0ct-99 37.34702 1 10 1999 0.864112 116337.1 1.5098.26 108.1064 3000 2013.62 1 3004.585 13665.27 2014.129 3000 108.1064 459 5459.115 o 1450.036 2010.159 1238.402 1972.021 2010.159 1950.117 0 1-Nov-99 37.4319 1 11 1999 0.864322 116333.1 15005.34 142.2742 3000 2005.222 1 3097.585 17660.24 2005.73 3000 142.2742 552 9454.089 o 1363.405 2001.714 1152.276 1957.025 2001.714 1929.207 0 1-Dec-99 37.51403 1 12 1999 0.864521 116328.3 14915.36 168.1842 3000 1997.058 1 3187.585 22395.78 1997.564 3000 168.1842 642 14189.63 o 1276.072 1993.523 1069.606 1943.748 1993.523 1911.361 0 1-Jan~00 37.5989 1 1 2000 Q.864722 116322.6 14822.4 .187.5767 3000 1988.595 1 3280.585 27969~24 1.989.099 3000 187.5767 735 19763.09 o 1213.694 1985.014 1010.948 1931.564 1985.015 1895.971 0 1-Feb-00 37.68378 1 2 2000 0.86492 116316.5 14729.62 198.7268 2964.259 1980.107 1 3373.303 34022.33 1980.609 2964.259 198.7268 827.718 25816.18 0 1181.34 1976.483 979.835 1921.158 1976.484 1883.93 0 1-Mar-00 37.76318 1 3 2000 0.865102 116310.5 14644.55 201.9857 2905.925 1972.298 1 3458.192 39842.51 1972.799 2905.925 201.9857 912.6069 31636.36 o 1173.154 1968.683 971.19 ,1913.212 1968.684 1875.755 0 1-Apr-00 37.84805 1 4 2000 0.865293 116304.2 14555.08 204.986 2863.883 1964.059 1 3547.502 46158.74 1964.558 2863.883 204.986 1001.917 37952.59 o 1164.517 1960.455 962.44219p4.791 1960.456 1867.124 0 1-May-00 37.93018 1 5 2000 0.865475 116297.9 14469.72 207.728 2826.91 1956.161 1 3632.765 52356.7 1956.658 ' 2826.91 207.728 1087.181 44150.55 o 1156.105 1952.563 954.0228 ~18ß6.633 1952.563 1858.722 0 1-Jun-00 38.01506 1 6 2000 0.86566 116291.3 14382.66 210.3051 2792.153 1948.075 13719.767 58843.12 1948.57 2792.153 210.3051 1174.182 50636.97 o 1147.681 1944.482 945.6735 1888.384 1944.482 1850.303 0 1-Jul-00 38.09719 1 7 2000 0.865837 116284.9 14299.32 212.5664 2760.879 1940.311 1 3802.979 65192.54 1940.805 .2760.879 212.5664 1257.394 56986.38 o 1139.458 1936.721 937.6369 18eO.383 1936.722 1842.087 0 1-Aug-00 38.18207 1 8 2000 0.866017 116278.3 14214.18 214.7462 2729.126 1932.352 1 3887.996 71821.48' 1932.844 ,2729.126 214.7462 1342.411 63615.33 o 1131.162 1928.766 929.5552 1872.26 1928.766 1833.796 0 1-Sep-00 38.26694 1 9 2000 0.866195 116271.5 14130.07 216.8502 2697.696 1924.458 1 3972.028 78516.69 1924.948 ,2697.696 216.8502 1426.443 70310.53 o 1122.883 1920.874 921.5145 1864.174 1920.874 1825.525 0 1-0ct-00 38.34908 1 10 2000 0.866366 116264.9 14049.52 218.7537 2669.248 1916.877 1 4052.451 85056.09 1917.365 ,2669.248 218.7537 1506.866 76849.94 o 1114.907 1913.293 913.8347 1&56.39 1913.294 1817.557 0 1-Nov-00 38.43395 1 11 2000 0.866539 116258 13967.2 220.522 2643.202 1909.098 1 4134.724 91869.45 1909.584 '-2643.202 220.522 1589.139 83663.29 o 1106.915 1905.514 906.2231 1848.506 1905.515 1809.569 0 1-Dec-00 38.51609 1 12 2000 0.866706 116251.3 13888.27 222.2104 2617.97 1901.614 1 4213.578 98514.48 1902.099 2617.97 222.2104 1667.992 90308.33 o 1099.113 1898.031 898.8022 1840.854 1898.032 1801.774 0 1-Jan-01 38.60096 1 1 2001 0.866876 116244.4 13807.53 223.7781 2591.897 1893.924 1 4294.265 105431.7 1894.407 ;2591.897 223.7781 1748.68 97225.52 o 1091.272 1890.337 891 .3354 1833.092 1890.338 1793.936 0 1-Feb-01 38.68583 1 2 2001 0.867045 116237.4 13727.56 225.2406 2566.2 1886.282 1 4374.149 112395.1 1886.763·, 2566.2 225.2406 1828.564 104189 o 1083.475 1882.683 883.9462 1825.375 1882.684 1786.144 0 ( 1-Mar-01 38.76249 1 3 2001 0.867196 116231 13656.01 226.4908 2543.836 1879.424 1 4445.631 118722.7 1879.904 2543.836 226.4908 1900.046 110516.5 o 1076.462 1875.824 877.336 1818.439 1875.824 1779.136 0 i 1-Apr-01 38.84737 1 4 2001 0.867361 116223.9 13577.52 227.7379 2520.784 1871.876 1 4524.073· 125766.6 1872.354 2520.784 227.7379 1978.488 117560.4 o 1068.823 1868.273 870.1969 11810.849 1868.274 1771.501 0 1-May-01 38.9295 1 5 2001 0.86752 116216.9 13502.24 228.8472 2499.478 1864.614 1 4599.319 132618.4 1865.09 .,2499.478 228.8472 2053.735 124412.2 o 1061.389 1861.007 863.30611803.498 1861.007 1764.073 0 1-Jun-01 39.01437 1 6 2001 0.867683 116209.8 13425.06 229.9251 2478.883 1857.1.51 1 4676.432 139732 1857.625 ·,2478.883 229.9251 2130.847 131525.9 o 1053.872 1853.539 856.371 1 796.01 1853.539 1756.558 0 1-Jul-01 39.09651 1 7 2001 0.867839 116202.9 13350.97 230.9182 2459.537 1849.e65 1 4750.457 146647.4 1.850.438'2459.537 230.9182 2204.871 138441.2 o 1046.532 1846.349 849.6383 1788.743 1846.35 1749.224 0 1-Aug-01 39.18138 1 8 2001 0.867999 116195.7 13274.99 231.8434 2440.469 1842.577 1 4826.361 153822.8 1843.0482440.469 231.8434 2280.776 145616.7 0 1039.09 1838.955 842.8482 ;1781.328 1838.956 1741.782 0 1-Sep-01 39.26625 1 9 2001 0.868158 116188.4·13199.63 232.7245 2421.928 1835.225 ,1 4901.681 161026.1 1835.685 2421.928 232.7245 2356.095 152820 o 1031.647 1831.601 836.0868 "1773.933 1831.603 1734.345 0 1-0ct-01 39.34839 1 10 2001 0.86831 116181.4 13127.23 233.4966 2404.218 1828.144 1 4974.024 168021.6 1828.612·2404.218 233.4966 2428.439 159815.4 o 1024.434 1824.517 829.5693 !1766.783 1824.519 1727.136 0 1-Nov-01 39.43327 1 11 2001 0.868466 116174 13053 234.1966 2386.873 1820.86 1 5048.245 175272.9 1821.326 :2386.873 234.1966 2502.659 167066.8 o 1017.115 1817.228 822.9951 1759.484 1817.23 1719.817 0 1-Dec-01 39.5154 1 12 2001 0.868617 116167 12981.62 234.8672 2370.704 1813.841 1 5119.566 182311 1814.305 .2370.704 234.8672 2573.981 174104.8 o 1009.978 1810.204 816.6098 1752.406 1810.206 1712.687 0 1-Jan-02 39.60027 1 1 2002 0.868771 116159.7 12908.37 235.5247 2354.13 1806.62 1 5192.759 189603.8 1807.082::.. 2354.13 235.5247 2647.174 181397.6 o 1002.717 1802.977 810.1197 ~745.169 1802.979 1705.43 0 1-Jun-02 40.01369 1 6 2002 0.869502 116123.6 12558.65 238.4746 2279.507 1772.133 1 5542.273 225406.6 1772.587' 2279.507 238.4746 2996.688 217200.4 o 967.7831 1768.46 778.9168 1710.442 1768.463 1670.514 0 1-Sep-02 40.26557 1 9 2002 0.869935 116101.5 12350.83 239.9795 223.8.559 1751.471 1 5749.982 247419.5 1751.92 2238.559 239.9795 3204.397 239213.4 o 946.8634 1747.778 760.3979 11689.636 1747.781 1649.604 0 1-Jan-03 40.59959 1 1 2003 0.8705 116072 12080.87 241.8719 2187.515 1724.4 . 1 6019.796 276819.9 1724.842 2187.515 241.8719 3474.211 268613.8 o 919.4496 1720.682 736.2692 ,16.62.372 1720.665 1622.202 0 1-Jun-03 41.013 1 6 2003 0.871184 116035.2 11754.95 243.7982 2130.751 1691.299 1 6345.602 313502.5 1691.733 2130.751 243.7982 3800.017 305296.3 o 886.0187 1687.544 707.17461629.072 1687.547 1588.781 0 1-Sep-0341.26489 1 9 2003 0.871597 116012.6 11560.46 244.6996 2097.261 1671.257 ,1 6540.009 335976.5 1671.6862097.261 244.6996 3994.425 327770.4 o 865.8255 1667.492 689.7502 ;1608.945 1667.495 1568.593 0 1-Jan-04 41.5989 1 1 2004 0.872137 115982.6 11307.21 245.7851 2054.444 1644.95 1 6793.124 365901.2 1645.373·2054.444 245.7851 4247.539 357695 o 839.3482 1641.165 667.0142 ~582.538 1641.168 1542.123 0 1-Jun-04 42.01506 1 6 2004 0.872796 115945 10998.76 246.9882 2003.817 1612.577 1 7101.431 403355.7 1612.991 2003.817 246.9882 4555.846 395149.6 o 806.7946 1608.764 639.2361 \1550.053 1608.766 1509.578 0 1-Sep-04 42.26694 1 9 2004 0.873187 115922.2 10815.86 247.7561 1971.259 1593.233 1 7284.199 426116.9 1593.643 1971.259 247.7561 4738.613 417910.8 o 787.3049 1589.411 622.4772 153.0.628 1589.413 1490.095 0 1-Jan-05 42.60096 1 1 2005 0.873696 115891.8 10577.93 248.7617 1928.869 1567.923 1 7521.994 456407.2 1568.326 1928.869 248.7617 4976.409 448201 o 761.7881 1564.076 600.5732 1505.193 1564.078 1464.587 0 1-Jun-05 43.01437 1 6 2.005 0.874311 115854.1 10290.6 250.0468 1876.369 1537.046 1 7809.157 494072.4 1537.442 1876.369 250.0468 5263.571 485866.2 o 730.655 1533.174 573.8929 1474.167 1533.176 1433.465 0 1-Jan-06. 43.60027 1 1 2006 0.875157 115800.2 9896.562 252.3883 1806.553 1494.098 1 8202.984 547828.8 1494.483 .1806.553 252.3883 5657.398 539622.6 o 687.091 1490.181 536.6702 1430.858 1490.182 1389.92 0 1-Jun-06 44.01369 1 6 2006 0.875739 115761.8 9627.323 254.0867 1759.745 1464.227 1 8472.105 586071.1 1464.604 1759.745 254.0867 5926.52 577864.9 o 656.8434 1460.288 510.9724 1400.766 1460.288 1359.683 0 1-Jan-07 44.59959 1 1 2007 0.876537 115707 9257.78 256.7112 1693.907 1422.682 1 8841.446 640729.6 1423.048 1693.907 256.7112 6295.861 632523.4 o 614.6765 1418.709 475.2532 1358.857 1418.708 1317.535 0 1-Jun-07 45.013 1 6 2007 0.877083 115667.9 9005.471 258.7188 1647.535 1393.905 1 9093.611 679648.4 1394.264 1647.535 258.7188 6548.026 671442.2 o 585.4819 1389.9 450.5901 ~32.9~835 1389.899 1288.353 0 1-Jan-08 45.5989 1 1 2008 0.877834 115612.1 8659.853 261.6512 1582.871 1353.79 1 9439.026 735339 1354.138 1582.871 261.6512 6893.44 727132.8 o 544.7424 1349.759 416.356 '289.365 1349.758 1247.633 0 1-Jun-08 46.01506 1 6 2008 0.878347 115572.1 8422.577 263.6957 1538.625 1325.89 1 9676.132 775271.6 1326.23 1538.625 263.6957 7130.547 767065.4 o 516.4465 1321.836 392.7444 ~261.241 1321.835 1219.349 0 1-Jan-09 46.60096 1 1 2009 0.879042 115515.1 8099.89 266.498 1477.271 1287.402 1 9998.649 832011.8 1287.733 1477.271 266.498 7453.063 823805.6 0 477.365 1283.32 360.2618 1222.426 1283.318 1180.288 0 1-Jun-09 47.01437 1 6 2009 0.879515 115474.7 7880.017 268.3677 1434.532 1260.78 1 10218.37 872398.8 1261.103.1434.532 268.3677 7672.788 864192.6 o 450.4181 1256.684 337.9019 ~195.629 1256.683 1153.354 0 1-Jan-10 47.60027 1 1 2010 0.880156 115416.8 7579.368 271.1118 1374.956 1223.921 1 10518.79 930130.1 1224.235 1374.956 271.1118 7973.204 921923.9 o 413.0898 1219.809 307.1025 ~158.515 1219.807 1116.048 0 1-Jan-11 48.59959 1 1 2011 0.881173 115316.6 7096.532 276.3107 1271.998 1163.301 1 11001.26 1030082 1163.598 1271.998 276.3107 8455.672 1021875 0 35,1.623 1159.174 256.741 [1097.46 1159.173 1054.624 0 1-Jan-12 49.5989 1 1 2012 0.882088 115218 6656.25 260.8402 1140.368 1106.631 1 11441 .55 1128593 1106.913 1140.368 260.8402 8895.967 1120387 0 343.766 1102.579 250 1044.302 1102.579 1004.05 0 1-Jan-13 50.60096 1 1 2013 0.882923 115125.9 6261.272 242.5098 1022.349 1054.348 1 11836.64 1220626 1054.6.15 1022.349 242.5098 9291.06 1212420 o 344.0681 1050.373 250 995.8755 1050.373 958.4662 0 1-Jan-14 51 .60027 1 1 2014 0.883674 115040.5 5907.612 225.4288 918.7321 1006.69 1 12190.38 1305949 1006.945 918.7321 225.4288 9644.792 1297743 o 344.9342 1002.806 250 ~51.8299 1002.805 917.0525 0 1-Jan-15 52.59959 1 1 2015 0.884357 114961.1 5589.652 209.5577 827.1312 962.893 1 12508.39 1385276 963.136 827.1312 209.5577 9962.808 1377070 0 346.317 959.1099 250 911.4058 959.1087 879.0715 0 1-Jan-16 53.5989 1 1 2016 0.884975 114888.4 5306.455 0 o 923.3539 o 12791.62 1458023 923.5864 0 o 10246.03 1449817 o 917.6207 919.8122 o ~17.6542 919.8107 917.4758 0 I i I Application for a Disposal I ion Order - Marathon Oil Compa Attachment 2 6 8 L. C. ¡bele 12,000 ~ 10,000 ::E 8,000 6,000 4,000 e (š 2,000 4,500 - 4,000 3,500 3,000 2,500 2,000 1,500 1,000 500 - #1 Model Sterling WGPT-w/injection I WGPT-no injection -~- 07/24/98 04/19/01 01/14/04 10/10/06 07/06/09 04/01/12 12/27/14 09/22/17 Date Graph 1. Cumulative Gas Production versus Sterling 84 Model WGPR-w/injection :::,:'::::::::::::::::;::::~.:~ WGPR-no injection :-X-){--X-X-X WWPR-no injection WWPR-w/injection ~X~WW¡R 600 - 500 400 o 07/24198 04/19/01 01/14/04 10/10/06 07/06/09 04/01/12 12/27/14 09/22/17 Graph Daiiy Gas Production Rate versus Attach 2 2/16100 b-4 Application for a Disposal I Order - Marathon Oil Company Attachment 2 Page 7 of 8 are based on an cross-section between well SU_32-9 injector well horizon, same horizon from which gas is that are confined within closure the producing well. Application for a Disposal Inj Order - Marathon Oil Company Attachment 2 8of8 2. Illustration of injection migration of water per day. Results are on an southeast down on the same is Note that the confined within the closure of the structure, and are not produced at Attachment 3 . . . Application for a Disposal Injan Order - Marathon Oil Company e Attachment 3 Page 1 of 2 Attachment 3 Mechanical Integrity Test Well SU 43-9 MEMORANDUM State of Alaska Alaska on .and Gas Conservation Commission TO: Camille O. Taylor Chair DATE: October 2002 SUBJECT: Mechanical Integrity Tests Marathon Oil Co. SterlingF'ad SU 43·9 FROM: Jeff Jones Stèrling Unit Petroleum Inspector Sterting Gas Field NON· CONFIDENTIAL THRU: Tom Maunder F'.I. Supervisor Packer ~ p~~¡1 SU43'91;~::=~tl ~ IT:~~I conversion MIT. Type Test M= Annulus Monitor;ng P'" Standard Pressure Test R; Int"",a¡ Radioactive Tracer Survey A; Temperature Anomaty Survey (F= Differential Temperature Test Depth Pretést nitìaJ 15 Min. 30 Min. ~~16~;::1 4~11;~0 12511~:Qlln~;ª11 Type INJ. Fluid Codes F '" FREsH WATER INJ. G " GAS INJ. S '" SALT WATER INJ. N'" NOT INJECTING IntervaJ 1= Initial Test 4'" Four Year Cycle V", Requited by Varíance W= Test duríng Workover 0'" Other (describe In notes) Test's Details October 23, 2002: I traveled to Marathon on Co.'s Sterling Gas Field to witness an MIT on gas production well SU 43·9. Bill Wolf was the Marathon representative in charge of the today which he performed in a safe and proficient manner. The pre--test pressures were monitored for 15 minÙfes and found to be stable. The casing was then pressured up to 1650 PSI and monitored for thirty minutes with no significant passing the MIT. Mr. Wolf indicated Marathon's intent is to convert this gas production water disposal injection well for the Sterling Gas Field. Summary: I witnessed a successful MIT on Marathon Oil Co.'s Sterling Unit. Field well 43·9 in the Sterling M.LT.'s performed: 1 Number of Failures: º Attachments: Marathon circular pressure chart copy (i) Total Time during tests: 1.,& cc: 021023-MIT SU 43-9 JJ.xls 11/14/2002 . . . Application for a Disposal Inj.on Order - Marathon Oil Company e Attachment 3 Page 2 of 2 Attachment 3 Mechanical Integrity Test Procedure Well SU 43-9 Mechanical Integrity Test Procedure Well SU 43-9 Sterling Unit Objective: a mcchanital integrity test in well SU 43-9 to demonstrate casing and packer 1. Notify AOGCC téSt. to conduct MIT test on at least hours :in wel! SU pressures to 3. Tie into the with a high-pressure pump and pressure recording Prcssure test the casing annulus to 1500 psi 4. Shut off the pump and monitor casing pressure. 150 psi within 30 minutes, contact immediately. docs not stabilize or declines 5. Rig down Bleed pressure off of casing annulus as per Production instructions. SU 43-9 to Complete AOGCC fOTI11 10-406 to document of the MIT, including any witnesses of the test. Attachment 4 . . . Application for a DisposallnjAn Order - Marathon Oil Company e Attachment 4 Page 1 of 6 Attachment 4 Injectivity Log Procedure for Sterling 8-4 on Well SU 43-9 Injectivity Log Procedure Well SU 43-9 Sterling Unit AFE 0487000 Objective: Run an injection log across the Sterling B-4 interval of well SU 43-9 to confinn that injected fluids are confined in that sand. Procedure: 1. MIRU slickline on well SU 43-9. Test lubricator and BOPs to 2,000 psi using methanol. RIH with 10/4" impression block down to the top of the downhole choke at 5238' KB. Take impression of fishing neck and POOH. Record fluid level if observed. 2. RIH with retrieving tool. Retrieve downhole choke installed in S-1 nipple (ID = 1.875"1) at 5238' KB. POOH. ~: Choke includes a Baker equalizing device. Contact Gary Eller for more infonnation if needed.) 3. RllI with 1 W' gauge ring. Tag fill (estimated at 5272' KB). POOH, RDMO slickline. '\ 4. MIRU electric line unit. Test BOPs and lubricator to 2000 psig with methanol. RllI with TDT - Waterflow log to top of fill. Make tie-in pass. 5. MIRU pump truck on pump-in sub of electric line lubricator. Pressure up casing string to 1500 psig using separate pump. Blend 75 bbl of3% KCI with borax additive. Heat fluid as necessary to avoid freezing. Inject at least one tubing-volume of filtered KCl fluid down the tubing into the Sterling B-4 fonnation at a rate and pressure dictated by the onsite engineer. While injecting, make passes with the TDT-Waterflow log as necessary to detemìine whether the injected fluid is staying in zone. 6. When complete, POOH and RDMO electric line and pump truck. Haul remaining KCl fluid to Kenai Gas Field for disposal. JGE - January 13, 2000 N :\DRLG\STERLING\SU43-9\injectlog.wpd " . . . Application for a Disposal I_ion Order - Marathon Oil Company e Attachment 4 Page 2 of 6 NEUTRON - BORAX LOGGING Written By: Warren I Chambers 09/22/92 Reviewed By: Melvan / Whitlow 04-12-93 Reviewed By: G. Nordlander 01/14/99 Reviewed By: T. West 02/07199 Revised By: J. Rathert 01112/99 OBJECTIVE: NeutronIBorax logs are usually requested when a cement channel or other communication is suspected above or between perforations. When a channel is below perforations, a pump-in temperature survey, PITS, will usually provide the same infonnation as a NeutronIBorax log at substantially lower cost. Above or between perforations, a channel or leak is hard to distinguish from nonnal thennal effects, so the NeutronIBorax log is requested. Rwming both, on one trip is a cost effective procedure. As an additional bonus the two baseline porosity passes can be used to monitor GOC movement. In practice, baseline passes are made with the neutron tool, a borax solution is then injected into the fonnation, and repeat passes are made with the neutron tool. Borax has a high neutron capture cross section, so it is easily detected by the neutron log curve, fonnation sigma:E, overlay wherever it leaks off into the fonnation. Consequently the borax will show up in both open perforations and channels. Sometimes a PITS will show a gradual temperature change below the perforations which mayor may not represent a channel. Studies have indicated that a Neutron! Borax log is helpful in such situations in distinguishing short channels from temperature changes due to fluid mixing or conductivity effects, an example is shown in A-34 PNUÐorax-PITS 3/29/92 Telex. Poor results have been obtained in running NeutronIBorax logs in injection wells. Log output includes curves showing neutron capture cross section in both the wellbore and fonnation. Typically, Borax is detectable in the borehole, but not in the fonnation. It is suspected that this is because the Borax does not leak off into the rock matrix. Injection wells on the North Slope are fractured by the injected water and suspended solids in the injected water tend to plate off at the fonnation face. The remaining Borax in the fracture occupies too small a volume to activate the tool, so that no Borax response is seen, even where the bulk of injection water leaves the wellbore. Borax Jogging can be done using several types of tools and tool conveyance methods. The pulsed neutron tools, commonly called PNL, have to be run on e-line for wells with less than 60° deviation, or on coiled tubing E-line, CTEL, for high deviation wells. The reservoir saturation tool, RST TM, is the current tool used. Recently, memory compensated neutron logs, MCNL, have been run, for borax logging, on regular coiled tubing, CT, with a reasonable degree of success. The MCNL uses count rates to accomplish a similar, but not as clear cut, interpretation. NEUTRON BORAX Logging Page 1 . . . Application for a DisPOSallnj.on Order - Marathon Oil Company e Attachment 4 Page 3 of 6 The pulsed neutron tools require an e-line for the large amount of current to run the downhole neutron generator. They do not use a Radioactive Source. PNL tools also discriminate between the borehole and the formation signal thus the borehole fluid type, except gas, is of negligible importance. Sigma is the measured value, which is severely affected by borax, on these logs. This is the basis for borax logging. Memory compensated neutron tools, MCNL, require a Radioactive source. They measure, radially, the borehole, pipe and formation without any borehole discrimination. For this reason the borehole fluid must be consistent over the entire log interval, during all passes, to prevent another unknown. The base passes require water in the borehole and the borax passes require borax. This is critical to the success of the job. Total count rate measurements are used to determine borax effect With the memory tool you will be logging completely "in the dark" and must keep accurate accounting of the fluid locations to generate an effective log. Refer to the cru MEMORY GAUGE PRODUCTION LOGGING section for MCNIÆORAX logging. SAFETY Follow the E-LINE WELL ENTRY PROCEDURES and the E-LINE PRESSURE CONTROL sections in the PE Manual. The neutron tool used generates its own neutrons downhole only. No separate source is used. Due to the danger of radiation exposure, ensure that the neutron generator is not powered up, unless it is safely downhole. There should be no need to power up the neutron generator on the surface, at the job site, for any reason. It is specifically forbidden by the service company. Pressure control is not an unusual concern as the tool runs on 0.23" line. This is the standard single conductor line used on a regular basis. NEUTRONIBORAX PLANNING I. If the well is an injector, is on seawater and the zone of interest has not been taking fluid very long, there is a reasonable chance of success. Otherwise, alternative diagnostics should be considered. 2. Liquid pack the wellbore in order to get good PNL baseline passes. Refer to the PE Manual-FLUID PACKING section. Wells with WHSIP of 2000 or less can be shut in at 0100 on the day of the job to allow fluid to build up across the perfs,. Since it will be necessary to pump fluids anyway, it will probably be most economic to fluid pack any well making a substantial oil rate to minimize shut in time. 3. If a fluid pack is used, plan on pumping a 1 to 1.5 tubing volume into the formation ahead of the baseline passes. The larger fluid volume is for low PI wells, less than 2000 BFPD, which are slow to re-pressurize near the wellbore region. Have on hand and stage enough fluid, seawater - Borax - seawater, to be able to pump-in slowly at 0.25 to 0.5 bpm while logging the base passes without getting Borax prematurely into the formation. While logging, it is preferable to keep positive pressure on the wellhead by pumping at a low rate. However, this may not be always be possible without using massive quantities of seawater or Borax solution, especially if the well is on a vacuum. The reason for logging while pumping instead of shutting down and running passes is so that the Borax solution is continually forced into any channels and not just allowed to swap with the wellbore fluids and leak off into the formation. The Borax solution is usually spotted in the tubing during fluid packing. Using a 2 to 3 bbl MEOH spear before and after the Borax gives the fluid interface a sharper definition and prevents it from stringing out. Ensure that the leading edge of the Borax is well above NEUTRON BORAX Logging Page 2 . . . Application for a Disposal In.ion Order - Marathon Oil Company . Attachment 4 Page 4 of 6 the perforations when you shut down. This is so that a falling liquid level does not displace it into the-perforations before you are ready. The two baseline passes with the PNL must be completed before the Borax solution reaches the perforations. Estimate how far the liquid level will fall after pumping ends from the reservoir pressure. In low PI wells, it is worth looking at hydrostatics for reservoir pressure and for FBHP, since it will take a long time for the near wellbore region to re-pressurize. If lift gas is not available, consider displacing with diesel to assist in bringing the well back on. 5. Order the Borax solution. Volumes of about 70 bbl are generally used. The recommended fonnula consists of: Fresh water, approximately 100 to 120°F 7 ppb Borax 7 ppb NaCI salt Filtration of the final mixture to 3 nùcrons Use MI Drilling Fluids to supply the Borax. Use fresh water at 100 to 120°F mixed with 71bs/bbl ofNaCI and 7 Ibs/bbl of 5 molal Sodium-Tetra Borate-Penta Hydrate, NaBO, which is a technical grade and grind . It has the highest capture cross-section of the three. It is important to have a consistent concentration and mix of the Borax solution. Keep the solution warm in transit or the Borax will precipitate out. Mix Borax in a jet mixer to ensure uniform mixing. You will need a vac truck, with clean tanks to pick-up 70 bbls of fresh hot water, take it to the MI plant for addition of Borax and NaCl and mixing. Then it will be pumped back into the vac truck for delivery to the job site. Plan on 2.5 hours for this process. NOTE: Mixing and precipitation problems have been encountered when Borax was mixed in seawater or produced water. The precipitation is temperature sensitive. The produced water solution is subject to significant precipitation if allowed to cool. 6 Discuss the program with the service company engineer. 7. Make sure an approved pump-in sub is installed on top of the swab valve. The service companies should have an approved sub on their units. Ifnot, line up a BP pump-in sub from the wireline tool service building. These pump-in subs have flanged connections, no threaded connections, and are less likely to fail during pumping. Remember to support the hard line to the pump-in sub to prevent a failure due to the weight of the line and vibration during pumping. 8. Line up E-line unit, required fluids which are seawater, Borax, MEOH and/or diesel, filter skid, from PESO's or pump company, and pump truck. Remember to have a heater and MEOH in the winter. PRE-JOB PLANNING: General E-Line Checks: I. Check last TD tag in the telex file. Run a drift/tag if there is any doubt. 2. SSSY's have been permanently pulled in all producing wells as of 1-1-99. Injection valves ISSSY's remain in injector wells and will have to be pulled. 3. Check records for fish , tight spots and perforation intervals in the well. 4. Provide PCC with a tentative time schedule. 5. Call for a bleed tank, heater and 50-50 MEOH. NEUTRON BORAX Logging Page 3 . . . Application for a Disposalln.on Order - Marathon Oil Company . Attachment 4 Page 5 of 6 6. Keep FREEZE PROTECTION in núnd for all flowlines and the wellbore. JOB PROCEDURE: 1. Rig up service company lubricator, pump truck, filter, approved pump in sub and tools. Whenever practical, run the temperature tool in combination with the neutron tools for a PITS log on all passes. Pressure test hard line and lubricator to 3500 psi with pump truck. 2. RllI. Proceed to step 3 if optional flowing passes are not required. If flowing passes are required, tie-in to the BHCS/GR or CBUGR/CCL. Make the required passes, including the temperature, at 30 FPM, ftom TD to top of the Sag formation or as directed in the program. 3. Fluid packing is required prior to baseline passes. This can be done while RllI. The RST is 1 11/16" in diameter, so the risk to the tool string is minimal. Stage the fluids as described previously. Hang the tool above the top of the intended log interval to monitor borehole sigma and guard against over displacement as the leading edge of Borax approaches. Finish fluid pack with 1 to 1.5 tubing volumes of seawater into the formation. Reduce the pump rate to 0.25 to 0.5 BPM. Tie-into theBHCS/GR or CBUGR/CCL. 4. Make two baseline passes, without any Borax in the wellbore or formation, over the zone of interest as described in step 2. Log one pass at 30 FPM and one at 60 FPM. 5. Hang the tool at the top of the log interval, monitoring borehole sigma. Start pumping in to advance the Borax downhole and into the formation. When the Borax passes the tool increase the pump rate to maximum, considering the frac pressure, until 30 bbls plus the volume ftom the tool to the bottom of the perforations is pumped. The high rate will drive the Borax into any possible channels. Idle the pumps to 0.25 to. .5 BPM, RllI to bottom and make the I st Borax pass ftom ID up to 100' above the perforations or as directed in the program. Log at 60 FPM. 6. Hang the tool at the top of the last pass again. Pump-in 30 bbls of Borax into the formation at the highest safe pump rate. Idle the pump again. RllI. Log the 2nd Borax pass. Log at 60 FPM. 7. If a flush pass is required, optional, continue pumping at high rate until all the Borax is past the tool plus 30 bbls of seawater is into the formation. Make a flush log pass at 60 FPM. Be aware that if Borax is left in a permeable zone it will permanently alter the formation sigma for future neutron logging. POP the well as soon as the job is over. If that is not possible flush it with 30 bbls of seawater pumped at a high rate. If a PITS is not requested, POOH. It is a good idea to check your sigma overlays before POOH. 8. If a PITS is requested, hang the tools at the top of the log interval. Pump 1 tubing volume of cool seawater. Make the base temp pass to TD. Make down wannback log passes at 1, 3 and 5 hours after pumping was stopped. Always hang the tool at the top of the interval while waiting. The 5 hour pass may be eliminated if the answer is clear or a 6 hour pass may be required if not. After the temperature overlays are accepted, POOH. 9. Return the well to the Pad Operator and notify Production Control. Freeze protect as necessary. Notes: NEUTRON BORAX Logging Page 4 . . . Application for a Disposal In.on Order - Marathon Oil Company . Attachment 4 Page 6 of 6 ~ Th" SIGMA curve sees the Borax in permeable zones where the Borax fills the pore space close to the borehole contacted by a channel. It will fill the channels also. Borax will NOT be seen in non-permeable zones such as shales, the HOT, or even injection wells where thermal fracturing has occurred; even if there is a channel. The flowing PNL pass may indicate hydrocarbon or water entry points; even behind pipe. The flowing temp log will also be useful. The temperature passes are used to help identify channels below the perforations. LOG PRESENTATION: For the service company engineer In order, after the log heading labeled BORAX LOG or BORAX - PITS LOG, as the case may be. 1. Toolsketch 2. Job Comments - the last well production test information and operating steps in sequence, including volumes pumped and logging passes made, listed below the header comments. Make an attempt at interpretation and include on the comments. Someone should be able to determine and understand what went on while doing the job from the data presented on the log. 3. PITS- All passes. Temp Scale: scaled across Trles 2 & 3, 20 divisions, as appropriate. Scale the temperature from the lowest recorded to the highest recorded. Pick a scale, preferably even degrees/division to cover that range. 4. S,igma & Sigma borehole Overlay - Flowing, Shut-in, and Borax passes; scaled 40 - 0 across Trk. 2-3 and labeled clearly. Label suspected channels, etc. on the log. 5. Porosity Overlay - Flowing anCÌ Shut-In passes; scaled 60 - 0 across Trk.2-3 and labeled clearly. 6. All Standard Primary and Secondary Presentations for all stages: Flowing, Shut-In, Borax. Ensure that the far-near count rates are scaled so they are normalized during shut-in in a "clean water zone" for gas detection. Present count rate ratio, 3 to 1.5, on Trk.2; sigma, 40-0; porosity, 60-0, both on Trk.2-3. 7. Put all perfs, both open & squeezed, on all log passes. 8. Make sure that the 2 PNL baseline passes logged prior to Borax invasion are presented just as a normal PNL looking for GOC, etc. NEUTRON BORAX Logging Page 5 Attachment 5 . . . Application for a Disposal In.on Order - Marathon Oil Company e Attachment 5 Attachment 5 Injectivity Test Results for Sterling 8-4 on Well SU 43-9 . . . M MARATHON 4 e e Schl.bePgI. RST Borax Advisor Company field Well Date Logged Date Processed Reference Number API Number Log Analyst Marathon Oil Corporation Sterling Sterling Gas Unit 43-9 25-fEB-2000 04-DEC-2002 22522 50-133-10011-00 Douglas Hupp, P.E. Alaska Data and Consulting Services 3940 Arctic Blvd, Suite 300 Anchorage, Alaska 99503 (907) 273-1700 All 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 we shall not, except in the case of gross or willful negligence on our part, be liable or responsible for any loss, cost. damages or expenses incurred or sustained by anyone resulting from any interpretation made by any of our officers. agents or employees. These interpretations are also subject to clause 4 of our general terms and conditions as set out in our current price schedule. Marathon Oil Corporation Field: Sterlina Job Number 22522 e Log Date: 25-FEB-2000 Well: Sterlina Gas Unit 43-9 e . 1. Introduction: Marathon Oil Corporation well Sterling Gas Unit 43-9 was logged with an RST-A tool on 25-FEB-2000. The objective of this procedure was to evaluate the zonal isolation of the Sterling B-4 interval within this well. The RST tool was logged in Sigma mode before and after injecting a borax/fresh water mixture and stationary Water Flow mode (WFl). In addition, temperature and pressure data was recorded before and after the borax injection. Well Sterling Gas Unit 43-9 was completed with 5.5-in, 17-lB/ft casing cemented in a 7.625 in. borehole at 5380 ft (See attached well schematic). The tubing tail was set at 5250 ft with a Baker packer located at 5241 ft. The tubing size is 2.375 in. 4.7 lB/ft. Open perforations exist from 5262 ft to 5272 ft. Squeezed perforations are noted on the well schematic at 5257 ft. This report discusses the results of the RST logging operations performed on 25-FEB-2000. The data used in this report includes the RST Water Flow log/borax injection log, PSP Temperature and Pressure log, well schematic, and Daily Well Operational Report provided by Marathon Oil Corporation. . 2. Logging Operational Procedure: Based on the Daily Well Operations Report (DWOR) provided by Marathon Oil Corporation, the initial run in this well with the RST/Temp/Pressure tools identified fluid level in the vicinity of the perforations. At this point the well was loaded with fresh water pre-heated to 100 degF. Base RST /Temp/Pressure pass and repeat were made then a borax/fresh water mixture was pumped. The borax mixture was displaced with 20 BBl of fresh water. RST/TEMP/Pressure passes were then made over the interval 4800 ft to 5300 ft. Water Flow stations were made with the RST tool in WFl mode at three stations above the perforations while pumping fresh water to identify any up flow outside the casing or tubing. The DWOR is included in this report. 3. Discussion: Water flow stations were performed with the RST minitron neutron generator located at 5217.8 ft, 5247.8 ft, and 5237.8 ft. All stations were performed inside the tubing. The WFllog uses oxygen activation to detect water flow in the vicinity of the RST tool. The RST tool bombards oxygen atoms with a burst of neutrons. The oxygen then becomes radioactive having a half-life of 7.1 seconds. As the activated oxygen decays, it gives of gamma rays, which we measure at the detectors. If water is flowing past the RST tool during this process, the activated oxygen moves past the RST detectors and gamma ray detector allowing us to measure the velocity of the water. If there is no water flow, the detectors do not see the activated oxygen. The RST tool was configured to identify up flow with the detectors located above the neutron generator. None of the three stations indicated up flow at any of the detectors. . Overlays of the Borax passes with the Pre-Borax passes (Well loaded with fresh water) indicate that the borax entered the perforations. Borax has a high capture cross-section, resulting in a higher sigma measurement where it is present. The borax appears to be confined to the interval 5260 ft to 5275 ft. This is indicated by the separation between sigma in the borax and fresh water passes. The neutron porosity (TPHI) overlay indicates possible borax up to 5253 ft. e Marathon Oil Corporation Field: Sterlina Job Number 22522 e Log Date: 25-FEB-2000 Well: Sterlina Gas Unit 43-9 . The sigma overlay indicates slight separation from 5223 ft to 5260 ft. This separation does not appear to indicate a channel in this interval. The amount of separation is not great enough to be caused by significant volume or borax in the area of investigation by the RST detectors. A more likely source of this separation is smearing of the fresh water flush with the borax solution inside the tubing. The DWOR indicated the well was flushed with 20 BBL of fresh water after pumping the borax solution. This volume of water would only fill 5168 ft of tubing assuming an internal diameter of 1.995 in. as seen in the calculations below: Tubing _Size = 2.387in_4.7Ib/ ft _EUE _tubing Volume _ Fresh _ Water(BBL) = 20 Capacity(BBL / ft) = 0.00387 Fill_ Hight _ For _ 20BBL = 20 + 0.00387 Fill_Hight _For _20BBL = 5168ft Note: The capacity of the tubing is from Schlumberger's Field Data Handbook and calculations assume exact volume and length measurements. The above calculations suggest there may have been borax in the lower portion of the tubing and in the casing, affecting the RST measurements. The slight separation in the sigma overlay above the perforations may be due to borax inside the tubing. . The temperature log run after loading the hole with fresh water indicates no channel below the perforated intervals. This conclusion is based on observing that the temperature increases to what appears to be a normal temperature gradient directly below the perforations. 4. Conclusion: Based on analysis of the RST fluid injection appears to be confined to the Sterling B-4 sands. This is based on RST WFL stations and Sigma overlays before and after injection of a borax solution into the perforations. If you have any questions regarding this report, please contact Douglas Hupp, P.E. at (907) 273-1771. 5. Attachments: Attached to this report is the following documentation: 1. Schematic Well Sterling Unit 43-9 2. Daily Well Operation Report 3. RST Tool Figure 4. RST Fresh Water and Borax Solution Pass Overlay 5. Temperature Pass After Injecting Borax (Borax Pass 2) 6. Schlumberger Field Data Handbook Tubing Capacities . Marathon Oil Corporation Field: Sterlina Job Number 22522 log Date: 25-FEB-2000 Well: Sterlina Gas Unit 43-9 Attachment 1. Schematic Well Sterling Unit 43-9 Wen su 4' eUE al'l! tubing to B"K!"irN-1 . !i3:ì1O' W!I!! Nam& $, Nllf!!!)ef; su NfA AOOCC: Kß..Gl: IIrd @ 538( ' l l.æt Revl¡¡!ol1 Dam: e . Marathon Oil Corporation Field: Sterlina Job Number 22522 e log Date: 25-FEB-2000 Well: Sterlina Gas Unit 43-9 Attachment 2. Daily Well Operations Report MARATHON OIL COMPANY DAILY WELL OPERATIONS REPORT PAGE 1 OF 1 DATE: 2/25/2000 FIELD: Sterling Gas Field WELL #: SU 43-9 FILL DEPTH/DATE 5336' KB (2/18100) TUBING: 2-318" CASING: 5-1/2" DATE LAST WL WORK: 2/1812000 TREE CONDITION: WORK DONE: Pull choke,gauge run to bottom BENCHES OPEN: Sterling B-4 PRESENT OPERATION: Injectivity log to confirm B-4 Zonal Isolation OTHER: AFE 0487000 SUMMARY OF OPERATIONS 0700 MIRU Schlumberger on well SU 43-9. SITP = 1755 psia, CP = 40 psi. Held operations/safety meeting. Prepare to run RSTlTemp log; had to drop off centralizers because tool string too long. Pressure test lubricator to 3000 psi with methanol. 1500 RIH with RST/temp log. Tag bottom at 5300' KB, and tie into Halliburton log of 819/90. Difficult to accurately tie Into open-hole logs. Make a baseline log and repeat log from 5300' to 4900'. Fluid level is in the vicinity of the perfs. RIH to bottom. 1600 MIRU Dowell pump truck onto Schlumberger pump-in sub. Test lines to 3000 psig. Filled the tubing (20 bbl) with 100-deg fresh water, then pumped an additional 5 bbl at 3.2 bpm at 2300 psig. All fluids filtered to 3-m1crons. Shut down pumping, log from 5300' to 400'. Occasionally pumped small volumes of fresh water to keep the surface lines thawed. RIH to bottom when logging complete. 1930 Pump 20 bbl slug of fresh water mixed with 7 Iblbbl borax at 3.25 bpm with 2450 psig pump pressure. Displaced with 20 bblfresh water at same rate. Annulus pressure stead at 40 psi. After borax was displaced from the tubing, logged from 5300' - 4800' with RST/temp log while pumping at minimum rate. No sign of fluid channeling out of zone; clear indication of borax entering the Sterling B4 interval. Ran repeat log over same interval. . 0030 Made stationary oxygen-activation surveys at 5238', 5248', and 5218' KB while pumping at minimum rate (0.2 bpm) at 1200 psig pump pressure. No Indication of upward flow (I.e. behind pipe flow) at any of the stations. POOH, RDMO 5chlumberger and Dowell. Vendor Equipment 'pump truck borax hot shots, etc. vac truck, lights electric line, RSTlTemp iog Daily Cost $12,020 $600 $1,000 $1,600 $34,417 Cumulative Cost $12,020 $600 $1,000 $1,600 $34,417 Dowell M-I Drilling Fluids Misc. R&K Schlumberger CAlLY COST: $49,6áf~- CUM: $49,637 REPORTED BY: EllerlAffinito . e Marathon Oil Corporation Field: Sterlina Job Number 22522 . Attachment 3. Tool Figure DOWNHOLE EQUIPMENT MH-22 I 40.1 Mt+22 AH-38 . 38.6 SAH·G I 38.3 SAH-G 1130 EQF-43 36.9 EOF-43 TelStatu8 PSPT·A CTEM _30.9 30.9 ~~802 PS~2 PB 802 OR 10k ~hlre Mano _27.6 RTO" Tlièrmörfl8t8r OR 33094 CCl PBMS Well Temp ¿24.& Mànõmeter 24.4 CCL _23.8 . PBMS PSTC _23.0 RST-A 23.0 FISCH·A 100 ~A119 -ft.. 108 ·A 132 RSX'A 120 RSSA Far RSSA PNG RSSA Near /13.9 _13.4 T8n8loo 0 TOOL 2EAO MAXIMUM STRING DIAMETER 1.72 IN MEASUREMENTS RELATIVE TÖ TOOL ZERO ALL LENGTHS IN FEeT . e Log Date: 25·FEB·2000 Well: Sterlina Gas Unit 43-9 Marathon Oil Corporation Field: Sterlina Job Number 22522 log Date: 25-FEB·2000 Weil: SterlinaGas Unit 43·9 Attachment 4. RST Fresh Water and Borax Pass Overlay Marathon Oil Corporation field: Sterlina Job Number 22522 log Date: 25-FEB-2000 Well: Sterlina Gas Unit 43-9 Attachment 5. Temperature Pass After Injecting Borax (Borax Pass 2) e Marathon Oil Corporation Field: Sterlina Job Number 22522 e Log Date: 25-FEB-2000 Well: Sterlina Gas Unit 43-9 . Attachment 6. Schlumberger Field Data Handbook Tubing Capacities . . e e Schlumberger Field Data Handbook Section 300 . Dimensions and Capacities . DIMENSIONS AND CAPACITIES OF TUBING C.D. Lb.JFt. I.D. Cu. Ft./Ft. FUCu. Ft. BBUFt. FUBBL GaIJFt.* C.D. (mm) kg/m I.D. (mm) m3/m mlm3 1.050 REG 1.14 0.824 0.00370 270.270 0.00066 1515.152 0.02770 27 REG 1.70 20.93 0.0003 2906.98 1.050 EUE 1.20 0.824 0.00370 270.270 0.00066 1515.152 0.02770 27 EUE 1.79 20.93 0.0003 2906.98 1.050 1.20 0.824 0.00370 270.270 0.00066 1515.152 0.02770 27 1.79 20.93 0.0003 2906.98 1.050 1.50 0.742 0.00300 333.333 0.00053 1886.792 0.02246 27 2.23 18.85 0.0002 3703.70 1.315 REG 1.70 1.049 0.00600 166.667 0.00107 934.579 0.04490 33 REG 2.53 26.64 0.0006 1792.03 1.315 EUE 1.80 1.049 0.00600 166.667 0.00107 934.579 0.04490 33 EUE 2.68 26.64 0.0006 1792.03 1.315 EUE 2.25 0.957 0.00500 200.000 0.00089 1123.596 0.03737 33 EUE 3.35 24.31 0.0005 2154.46 1.315 EUE 2.25 0.957 0.00500 200.000 0.00089 1123.596 0.03737 33 EUE 3.35 24.31 0.0005 2154.46 1.660 2.10 1.410 0.01084 92.251 0.00193 518.135 0.08111 42 3.13 35.81 0.0010 993.51 1.660 REG 2.30 1.380 0.01039 96.246 0.00185 540.541 0.07770 42 REG 3.42 30.05 0.0010 1036.47 1.660 EUE 2.40 1.380 0.01039 96.246 0.00185 540.541 0.07770 42 EUE 3.57 30.05 0.0010 1036.47 1.660 3.02 1.278 0.00891 112.233 0.00159 628.931 0.06664 42 4.49 32.46 0.0008 1205.96 1.900 2.40 1.650 0.01485 67.340 0.00264 378.788 0.11108 48 3.57 41.91 0.0014 726.32 1.900 REG 2.75 1.610 0.01414 70.721 0.00252 396.825 0.10576 48 REG 4.09 40.89 0.0013 760.90 1.900 EUE 2.90 1.610 0.01414 70.721 0.00252 396.825 0.10576 48 EUE 4.32 40.89 0.0013 760.90 1.900 3.64 1.500 0.01227 81.500 0.00219 456.621 0.09180 48 5.42 38.10 0.0011 675.56 2.063 3.25 1.751 0.01672 59.809 0.00298 335.570 0.12509 52 4.84 44.74 0.0016 643.45 2.375 REG 4.00 2.041 0.02272 44.014 0.00405 246.914 0.16996 60 REG 5.95 51.84 0.0021 473.45 . 2.375 EUE 4.10 2.041 0.02272 44.014 0.00405 246.914 0.16996 60 EUE 6.10 51.84 0.0021 473.45 2.375 REG 4.60 1.995 0.02171 46.062 0.00387 258.398 0.16239 60 REG 6.84 50.67 0.0020 495.47 2.375 EUE 4.70 1.995 0.02171 46.062 0.00387 258.398 0.16239 60 EUE 6.99 50.67 0.0020 495.47 2.375 REG 5.00 1.947 0.02068 48.356 0.00368 271.739 0.15467 60 REG 7.44 49.95 0.0019 521.05 2.375 5.30 1.939 0.02051 48.757 0.00365 273.973 0.15340 60 7.89 49.25 0.0019 525.34 2.375 REG 5.80 1.867 0.01901 52.604 0.00339 294.985 0.14222 60 REG 8.63 47.42 0.0018 565.63 2.375 EUE 5.95 1.867 0.01901 52.604 0.00339 294.985 0.14222 60 EUE 8.85 47.42 0.0018 565.63 2.375 6.20 1.853 0.01873 53.390 0.00334 299.401 0.14009 60 9.23 47.07 0.0017 574.09 2.375 7.70 1.703 0.01582 63.211 0.00282 354.610 0.11833 60 11.46 43.26 0.0015 679.96 2.875 REG 5.90 2.469 0.03325 30.075 0.00592 168.919 0.24872 73 REG 8.78 62.71 0.0031 323.62 2.875 REG 6.40 2.441 0.03250 30.769 0.00579 172.712 0.24311 73 REG 9.52 62.00 0.0030 331.13 2.875 EUE 6.50 2.441 0.03250 30.769 0.00579 172.712 0.24311 73 EUE 9.67 62.00 0.0030 331.13 2.875 7.90 2.323 0.02943 33.979 0.00524 190.840 0.22017 73 11.76 59.00 0.0027 365.93 2.875 REG 8.60 2.259 0.02783 35.932 0.00496 201.613 0.20821 73 REG 12.80 57.38 0.0026 386.59 2.875 EUE 8.70 2.259 0.02783 35.932 0.00496 201.613 0.20821 73 EUE 12.95 57.38 0.0026 386.59 2.875 9.50 2.195 0.02628 38.052 0.00468 213.675 0.19658 73 14.14 55.75 0.0024 409.72 2.875 10.70 2.091 0.02385 41.929 0.00425 235.294 0.17839 73 15.92 53.11 0.0022 451.59 2.875 11.00 2.065 0.02326 42.992. 0.00414 241.546 0.17398 73 16.36 52.45 0.0022 463.16 3.500 REG 7.70 3.068 0.05134 19.478 0.00914 109.409 0.38400 89 REG 11.46 77.93 0.0048 209.64 3.500 REG 8.50 3.068 0.05134 19.478 0.00914 109.409 0.38400 89 REG 12.65 77.93 0.0048 209.64 3.500 EUE 8.50 3.018 0.04968 20.129 0.00885 112.994 0.37162 89 EUE 13.24 76.66 0.0046 220.26 . 3.500 REG 9.20 2.992 0.04882 20.483 0.00870 114.943 0.36524 89 REG 13.69 76.00 0.0045 220.35 3.500 EUE 9.30 2.992 0.04882 20.483 0.00870 114.943 0.36524 89 EUE 13.83 76.00 0.0045 220.40 · FUGal. = 1 - Page 77 GaI.lFt. Attachment 6 Application for a Disposal Inj N-, n Order - Marathon Oil Company Attachment 6 Construction of Well SU 43-9 ,4 8cd tubing to taB fill Tree exn 2-3/8" EVE 8rd .... Calwlated cement lop excess If1 7-5/8' x 5- (451'1) Attachment 6 Page 1 of 2 · · · Application for a Disposal Inje. Order - Marathon Oil Company e Attachment 6 Page 2 of 2 Well SU 43·9 Sterling Unit Cement Calculations Assumptions Cement Yield :::: Openhole Washout:::: 1.15 cu. ftlsack 100% Knowns Cement Volume:::: 550 sacks Hole Size:: 7.62.5 inch Casing Size:: 5.5 inch Casing ID :::: 4.892 inch Shoe Depth:: 5380' MD Top of cement in csg :: 5337' MD Note: Maintained full circulation throughout cement jOb Calculations (1 ) Cement Volume:::: Sacks * Yield/5.615 112.6 bbl (2) Shoe Volume:::: CasinglD^2 * Length/1029,4 1.0 bbl (3) Annular Capacity:::: (Hole^2 - CasingOD^2)*(1 + Washout)/1029,4 0.054188 bbl/ft (4) Height of Cement:: (Cement Volume - Shoe Volume)/Annular Capacity 2060 feet (5) Top of Cement:::: Shoe - Height of Cement 3320' MD +------ Calculated top of cement Attachment 7 A & 8 · · · Application for a Disposall.ion Order - Marathon Oil Company e Attachment 7 A Page 1 of 7 Attachment 7 A. Hydraulic Fracturing Potential Simulation for Routine Disposal Fluids E£j 28,2002 My. Gary Eller Marathon Oil 3201 C St. Suite 800 AK 99519-6168 Mr. Eller, Enclosed you will find one Fmcpro PT fracture analysis reports for SU 43-9 disposal well. The log from the nearby SU 32-9 well was ustxl to determine fonnntion characteristics. The of this letter is to briefly explain the parameters used for the model and the results. After completion of the simulation run, there does not appear to be any conceru about the fra(;ture growing out of zone, to the modeL There appears to be a of a stress contrast between the sand and the shale and coal above the sand. Actual fracture length. may vary significantly depending on pumping rate, leak-off rate, and To detennine the input pannneters, data from the electronic log was broken down into above, through, and below the intL'TVal. such as layer thickness, Ratio, Young's Modulus closure stress were computed from log data and input into theITdCproPT IIK>deL A perforated interval to the B-4 Sand in we!! SU 43-9 with. 4 shots per fì.){)I: was selected becanseit is near the center of the sand for injection. The pore pressure gradient was assumed to be 0.44 psilft in all During the course of the simulation, expected surface treatmg pressure did not excee.d 1800 psi. Several simulations were run using various values forleak-ofl coefficients to evaluate their impact on the and detemlÍne if the fractures would break out of zone, A minimum leak-off value was selected (6.6 E-3 or 1 md) that provide a reasonable output but would not cause the simulator to fail obtaining values beyond which the simulator L'Ould reasonably process). Smaller values for relative permeability would cause the fracture to grow in length to a point difficult tor the simulator to complete in a reasonable period of time. The pump schedule tor the sm1U]ntor was 1.0 hpm for 370 days, during which 533,224 harrels of clean Huid with 0.1 ppg of l00-mesh sand = 2.65) added. ß¡ · · · Application for a Disposal I.ion Order - Marathon Oil Company e BJ Services has a good business with Marathon Oil and looks forward to a continued success. If you have any questions or would like further detail on the model process, feel free to call JJJe at our Pacific Region (907) 349-6518 or Andrew Pacific Region at our Technology 396-4441. Cc:Pacifiç File Attachment 7 A Page 2 of 7 · · · Application for a Disposal .tion Order - Marathon Oil Company e FracproPT 10.1 Hydraulic Fracture Analysis Date: Well Name: Location: Formation: Job Date: Filename: August 19, 2002 SU 43-9 Kenai Peninsula 8119/02 SU-43-9 Disposal Attachment 7 A Page 3 of 7 Fracture Geometry Summary .Fracture Half.-Length (ft) 1945 Propped Half-Length (ft) 0 Total Fracture Height (ft) 99 Total Propped Height (ft) 0 Depth to Fracture Top (ft) 5269 Max. Fracture Width (in) 0.06 Depth to Fracture Bottom (ft) 5368 Avg. Fracture Width (in) 0.04 Equivalent Number ofMulliplefracs 1.0.Avg. Proppsnt Concentration (lblIP) 0.00 Fracture Slurry E~ciency 0.00 All values reported are for a fracture Model has run until 53308£tOO min Fracture Conductivity Summary Åvg.Oonductivi~ (wlDamage) (rnrHt) 0.0 Avg. FracWidth (Closed on prop) (In) Dimensionless Conductivity . 0.00 Ref. Formation Permeability (mD) ProppantDamap.Facìor 0.50 'proppsnt Permeability (mD) All values are for a single fracture Fracture Pressure Summary Model Net Pressure (psi) Observed Net Pressure (psi) Hydrostatic Head (psi) 13H Fracture Closure Stress (psi) Closure Stress Gradient (psílft) :Surface Pressure (psi) 28 o 2375 Averages reported during Main Frac Total Clean Fluid Pumped (bbls) Total Slurry Pumped (bbls) Pad Volume (bbls) Pad Fraction (%) Main Fluid Operations Summary 533062 Total Proppent Pumped (klbs) .:rotal Proppent!n Fracture (klbs) Avg. Hydraulic Horsepower (l1p) Max. Hydraulic Horsepower (l1p) CMa.lnProppant o o 4% KCL reported Main Frac 0.00 1.ooe+00 2??oo 3936 0.741 1720 2228.5 0.0 42 42 1oo-Mesh 10.1 . . . Application for a Disposall.tion Order - Marathon Oil Company Fracture Dimensions End of Time Fracture (mm:$$) Half~Length (ft) 1 1945 Fracture Growth History Fracture Fracture Avg. Model Net Height Width at Fracture Pressure (ft) Well Width (psi) (in) (in) 99 0.061 0.040 28 All values reported are for a single fracture e Attachment 7 A Page 4 of 7 Slurry E.quivalÊmt Efficiency Numberof Multifracs 0.00 1.0 Proppant and Fluid Properties by Stage Proppant Distribution by Stage ProppantType ProppantStageDistance from Avg. ProppantAvg. Proppant Avg. Proppant Concentration WeUbore Concentration Conductivity Volume (ppg) (ft) (lblft2) (mD·It) Fraction 1 10o-Mesh 0.10 1827.2 0.00 0.0 0.000 1 100-Mesh 0.10 0.00 0.0 0.000 Stage ## Fluid Type 1 1 4% KCL 4% KCL . Stage Elapsed #; Time min.sec 4% 4% Design clean volume (kgal> Design slurry volume (kgal) Fluid Properties by Stage Slurry Rate (bpm) Distance from Wellbore (It) 1827.2 854.7 Avg. Fluid Temperature ("F) 140 140 1.00 1.00 Fluid Type Design Treatment SChedule Clean Prop stage Volume Cone Prop. (kgal) (ppg) (ldbs) 1.0 22289.2 0.102228.9 22289.2 22300.0 Avg. Fluid Viscosity (ep) Avg. Shear Rate (1/HC) 0.0 0.0 0.5 Slurry Rate (bpm) Proppant Type 1 100-Mesh Design proppant pumped (klbs) 2228.9 ') '" 10,1 . . . Application for a Disposal I.tion Order - Marathon Oil Company Leakoff Parameters type Filtrate to reservoir fluid perm. ratio, Kp/KI pore pressure (psi) Initial fracturing (psi) fluid compressibilíty (1/psi) Filtrate (cp) viscosity (cp) Reservoir temperature ("F) Depth to center of Perfs (ft) Perforated interval (ft) Inftíal frac depth (ft) layer j 1 2 3 " 5 6 7 8 9 10 11 Top of ì zone (ft) 0.0 1.7 5071.2 5160.8 5212.8 14 Stress (psi) 3759 3722 3896 3786 3862 4183 3878 4203 4054 4046 e Gas 10 2311 4436 4.33e-04 1.00 0.03 0.10 100.00 Reservoir Parameters Layer Parameters Top of zone (ft) 0.0 5011 5047.4 5071.2 5160.8 5212.8 5257.6 5271.2 Young's modulus (psi) 1.0e+06 6.5e+05 6.8e+05 6.5e+05 3.ge+05 6.5e+05 3.ge+05 6.8e+05 6.5e+05 6.8e+05 6.519+05 5467.3 6.5e+05 Poisson's ratio :1 0.25 0.36 0.36 0.36 0.36 0.36 0.39 0.36 0.39 0.36 0.36 0.36 0.36 0.36 0.36 140.00 5312 9 5312 Top of zone (ft) 0.0 5011.7 5047.4 5071.2 5160.8 5212.8 5225.6 5250.2 5257.6 5271.2 5453.7 5467.3 Total Ct (ftlminYz) 2.00519-04 6.S94e-03 .2.005e-04 6. 594e-03 2.085e-04 6.594&-03 2.085e-04 6. 594e-03 2.085e-04 6. 594e-03 Attachment 7 A Page 5 of 7 PoreFluid perm. (md). 1 1 .00&-03 1 1.ooe-03 1.00e+00 Looe-03 1.ooe+OO 1.00e-03 1.00e+00 1 1 1.00e+OO 1 1 .OOE":I+OO lO.t . . . Application for a Disposal In_ion Order - Marathon Oil Company Lithology Parameters Lithology Top of Fracture zone Toughness (ft) (ps¡'¡nY2) 0.0 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 1000 5271,2 5367.5 13 5394.8 14 5453.7 Shale 15 5467.3 Well bore and Perforated Intervals Top of zone (ft) 0,0 5011 ,7 Overburden Sandstone Shale Sandstone 1 2 3 4 5 6 7 8 9 10 11 5071,2 5160.8 5212.8 Sandstone Coal Coal .Shale Sandstone Shale 5047.4 5071.2 5160.8 5212.8 5225.6 5232.0 5250.2 5257.6 5271.2 5367.5 5394.8 length (ft) 5800 Casing Configuration Segment Casing 10 Casing 00 Type (in) (in) . Cemented 5.500 Casing Weight (I bitt) 17.000 Top of zone (ft) 0.0 5011.7 5047.4 5071.2 5212.8 5232.0 5250.2 5257.6 .2 5367.5 5394.8 5467.3 e Attachment 7 A Page 6 of 7 Composite layering Effect 0.00 1.00 1.00 1.00 1.00 1.00 1 1.00 1.00 1.00 1.00 1.00 1 1.00 1,00 Grade Surface Line and Tubing Configuration r length Segment Tubing 10 Tubing 00 Weight Grade (tt) Type (in) (in) (lbItt) 5600 Tubin~ 1.995 4.700 Unspec Total Irac string volume (bbls) down Perforated Intervals ~ TVO (ft) ~ TVO (ft) ~ MO (tt) Bot ~ MD (ft) Perforation Diameter (in) , of Perforations 24.2 Tubing Interval '1 5308 5710 5720 0.400 40 4 10.1 . 250 .""'.-Ó"~;:'" .:>~<~:: r:~~;~~ :,-;';:;y;. I ~~><X·/x ~~~~ (,«~: ~~~ (·~,,;x .~<,~. :X:X:f'~," :~,:~~~ YS!'.'5- ':"~'~"o(;¿, ;&~~ . SU -43-9 Disposal Well Fracture Size After 370 Days (Note: Vertical Scale is True Vertical Depth) 500 750 1000 1:250 1500 ""._-~,,--'".--~-. 1750 20001 ~ ~ 4500 4750 5000 5251) 5500 5750 SOO) -=.J . » '"0 ""!2. ë'f Q) - õ' ::J õ' .., Q) o ¡if '"0 o (J) Q2.. . õ' ::J o a. (1) ..... I :!':: Q) õ3 - ::J" o ::J º o o 3 '"0 Q) ::J '< e ~ "U6.i Q) C') IO::J" CD 3 .....~ 0- -~ .....» · · · Application for a Disposall.ion Order - Marathon Oil Company e Attachment 7B. Hydraulic Fracturing Potential Simulation for Drilling Muds and Cuttings Attachment 78 Page 1 of 8 · · · Application for a Disposal I.tion Order - Marathon Oil Company e Attachment 7B Page 2 of 8 FracproPT 10.1 Hydraulic Fracture Analysis Date: Well Name: Location: Formation: Job Date: Filename: January 3, 2003 SU-43-9 Kenai Peninsula 12/30/02 SU-43-9 revised 1-2003 Fracture Geometry Summary Fracture Half-Length (ft) 321 Propped Half-Length (ft) Total Fracture Height (ft) 97 Total Propped Height (ft) Depth to Fracture Top (ft) 5271 Max. Fracture Width (in) Depth to Fracture Bottom (ft) 5368 Avg. Fracture Width (in) Equivalent Number of Multiple 1.0 Avg. Proppant Concentration Fracs (lb/ft2) Fracture Slurry Efficiency 0.00 o o 0.05 0.04 0.00 All values reported are for a single fracture Model has run until 20160.00 min Fracture Conductivity Summary Avg. Conductivity (w/Damage) 0.0 Avg. Frac Width 0.00 (mD·ft) (Closed on prop) (in) Dimensionless Conductivity 0.00 Ref. Formation Permeability 1.00e+00 (mD) Proppant Damage Factor 0.50 Proppant Permeability (mD) 20000 All values reported are for a single fracture Fracture Pressure Summary Model Net Pressure (psi) 25 BH Fracture Closure Stress (psi) 3936 Observed Net Pressure (psi) 0 Closure Stress Gradient (psi/ft) 0.741 Hydrostatic Head (psi) 3104 Suñace Pressure (psi) 1020 Averages reported during Main Frac Application for a Disposal In.on Order - Marathon Oil Company e Attachment 78 Page 3 of 8 · Operations Summary Total Clean Fluid Pumped 20141 Total Proppant Pumped 3729.7 (bbls) (klbs) Total Slurry Pumped (bbls) 20141 Total Proppant in Fracture 0.0 (klbs) Pad Volume (bbls) 0 Avg. Hydraulic Horsepower 25 (hp) Pad Fraction (%) 0 Max. Hydraulic Horsepower 31 (hp) Main Fluid 4% KCL Main Proppant 100-Mesh Averages reported during Main Frac Fracture Dimensions Fracture Growth History End of Time Fracture Fracture Fracture Avg. Model Net Slurry Equivalent Stage # (mm:ss) Half-Length Height Width at Fracture Pressure Efficiency Number of (ft) (ft) Well Width (psi) Multifracs (in) (in) · 1 14:days 321 97 0.053 0.035 25 0.00 1.0 All values reported are for a single fracture Proppant and Fluid Properties by Stage Proppant Distribution by Stage Stage Proppant Type Proppant Stage Distance from Avg. Proppant Avg. Proppant Avg. Proppant # Concentration Well bore Concentration Conductivity Volume (ppg) (ft) (lb/ft2) (mD'ft) Fraction 1 100-Mesh 5.50 160.3 0.00 0.0 0.000 Fluid Properties by Stage Stage Fluid Type Slurry Rate Distance from Avg. Fluid Avg. Fluid Avg. Shear # (bpm) Well bore Temperature Viscosity Rate (ft) (OF) (cp) (1/sec) 1 4% KCL 1.00 160.3 140 0.5 0.0 · · · · Application for a Disposalln.on Order - Marathon Oil Company e Attachment 78 Page 4 of 8 Design Treatment Schedule Stage Elapsed Fluid Clean Prop Stage Slurry Proppant # Time Type Volume Cone Prop. Rate Type min.see (kgal) (ppg) (klbs) (bpm) Well bore Fluid 4% KCL 0.9 1 14:days 4% KCL 678.1 5.50 3729.4 1.00 100-Mesh Design clean volume (kgal) 678.1 Design proppant pumped (klbs) 3729.4 Design slurry volume (kgal) 846.7 Treatment Totals Proppant and Fluid Pumping Stage Material Quantity Unit s 16144.42 bbls 3729.36 klbs Water injection 4% KCL 100-Mesh Treatment Totals calculated from design schedule Fluid Parameters Fluid Name 4% KCL MISCELLANEOUS GENERAL 4% KCL WATER 0.480 1.000 1.002e-05 0.480 1.000 1.002e-05 1.02 0.0 0.0 10.00 1461.9 20.00 5080.3 40.00 17705.8 1.000 Vendor System Description Initial Viscosity (cp) Initial n' Initial k' (lbt·s^n/ft2) Viscosity @ 4.0 hours (cp) n' @ 4.0 hours k' @ 4.0 hours (lbt·s^n/ft2) Gel Density Spurt Loss (gal/ft2) Wall Building (ftImin%) Flowrate #1 (bpm) Fric Press #1 (psi/1000 ft) Flowrate #2 (bpm) Fric Press #2 (psi/1000 ft) Flowrate #3 (bpm) Fric Press #3 (psi/1000 ft) Wellbore Friction Multiplier All Fluid info is at a reservoir temperature of 140.0 CF) All Viscosities at Shear Rate of 511 (1/sec) Well bore Friction pressures shown are the interpolated values multiplied by the Well bore Friction Multiplier. Friction is displayed for longest well bore segment Application for a Disposalln.on Order - Marathon Oil Company e Attachment 78 Page 5 of 8 · Leakoff Parameters Reservoir type Gas Filtrate to reservoir fluid perm. ratio, Kp/KI 10 Reservoir pore pressure (psi) 2311 Initial fracturing pressure (psi) 4436 Reservoir fluid compressibility (1/psi) 4.33e-04 Filtrate viscosity (cp) 1.00 Reservoir viscosity (cp) 0.03 Porosity 0.10 Gas Leakoff Percentage 100.00 Reservoir Parameters Reservoir temperature (OF) 140.00 Depth to center of Perfs (ft) 5312 Perforated interval (ft) 9 Initial frac depth (ft) 5312 Layer Parameters Layer # Top of Stress Top of Young's Poisson's Top of Total Ct PoreFluid zone (psi) zone modulus ratio zone (ftImin%) perm. (ft) (ft) (psi) (ft) (mD) 1 0.0 4009 0.0 5.0e+06 0.25 0.0 2.085e-04 1.00e-03 2 5011 .7 3722 5011 .7 6.5e+05 0.36 5011 .7 6.594e-03 1 .00e+00 · 3 5047.4 3845 5047.4 6.8e+05 0.36 5047.4 2.085e-04 1 .00e-03 4 5071.2 3786 5071.2 6.5e+05 0.36 5071.2 6.594e-03 1.00e+00 5 5160.8 3942 5160.8 6.8e+05 0.36 5160.8 2.085e-04 1.00e-03 6 5212.8 3862 5212.8 6.5e+05 0.36 5212.8 6.594e-03 1.00e+00 7 5225.6 4183 5225.6 3. ge+05 0.39 5225.6 2.085e-04 1.00e-03 8 5232.0 3878 5232.0 6.5e+05 0.36 5232.0 6.594e-03 1 .00e+00 9 5250.2 4203 5250.2 3.ge+05 0.39 5250.2 2.085e-04 1 .00e-03 10 5257.6 4001 5257.6 6.8e+05 0.36 5257.6 2.085e-04 1.00e-03 11 5271.2 3936 5271.2 6.5e+05 0.36 5271.2 6.594e-03 1.00e+00 12 5367.5 4090 5367.5 6.8e+05 0.36 5367.5 2.085e-04 1 .00e-03 13 5394.8 4014 5394.8 6.5e+05 0.36 5394.8 6.594e-03 1.00e+00 14 5453.7 4150 5453.7 6.8e+05 0.36 5453.7 2.085e-04 1 .00e-03 15 5467.3 4046 5467.3 6.5e+05 0.36 5467.3 6.594e-03 1 .00e+00 · Application for a Disposal laion Order - Marathon Oil Company e Attachment 78 Page 6 of 8 . Lithology Parameters Layer # Top of Lithology Top of Fracture Top of Composite zone zone Toughness zone Layering (tt) (tt) (psi'in%) (ft) Effect 1 0.0 Overburden 0.0 1000 0.0 1.00 2 5011.7 Sandstone 5011 .7 1000 5011 .7 1.00 3 5047.4 Shale 5047.4 2000 5047.4 1.00 4 5071.2 Sandstone 5071.2 1000 5071.2 1.00 5 5160.8 Shale 5160.8 2000 5160.8 1.00 6 5212.8 Sandstone 5212.8 1000 5212.8 1.00 7 5225.6 Coal 5225.6 1000 5225.6 1.00 8 5232.0 Sandstone 5232.0 1000 5232.0 1.00 9 5250.2 Coal 5250.2 1000 5250.2 1.00 10 5257.6 Shale 5257.6 2000 5257.6 1.00 11 5271.2 Sandstone 5271.2 1000 5271.2 1.00 12 5367.5 Shale 5367.5 2000 5367.5 1.00 13 5394.8 Sandstone 5394.8 1000 5394.8 1.00 14 5453.7 Shale 5453.7 2000 5453.7 1.00 15 5467.3 Sandstone 5467.3 1000 5467.3 1.00 Wellbore and Perforated Intervals . Casing Configuration Length Segment Type Casing ID Casing OD Weight Grade (ft) (in) (in) (I bItt) 5600 Cemented 4.892 5.500 17.000 Unspec Casing Surface Line and Tubing Configuration Length Segment Type Tubing ID Tubing OD Weight Grade (ft) (in) (in) (I bItt) 5600 Tubing 1.995 2.375 4.700 Unspec Total frac string volume (bbls) 22.1 Pumping down Tubing Perforated Intervals Interval #1 Top of Perfs - TVD (ft) 5308 Bot of Perfs - TVD (ft) 5317 Top of Perfs - MD (ft) 5710 . Bot of Perfs - MD (ft) 5720 Perforation Diameter (in) 0.400 # of Perforations 40 . . . Application for a DisPOSalle¡On Order - Marathon Oil Company e moo 2000 ~~~f ~~~~L~fta~Sì) - - Slurry Rate (bpm) 8.00 1600 600 1200 400 800 2.00 400 000 o 0 10000 Time (min) 15000 20000 5000 Figure 1. Rate and Pressure for SU 43-9, Injection Rate and Pressure, 1/3/2003 25000 Attachment 78 Page 7 of 8 10.00 8.00 6.00 4.00 2.00 0.00 . -- ~xç;ç' "".,. <X'<' x' 50 fi"~ 1··",-· '....~,. " , . ~'!f;~.: ·x ';"'. . X (. . SU 43-9 Disposal Well Fracture Size after 2 Weeks 1/3/2003 (Note: Vertical Scale is True Vertical Depth) '100 . {..., '1~' , . ,.......\ ~ ~...~.. , . :......\...' :m ,_. l 200 , . , '~Q ,. . . ·4~1 ~ -5150- e -5200 -; - 5250 - -5300 - - -5350 - e -5400 - -5450- J ~ Attachment 8 Application for a DisPOSallnj.on Order - Marathon Oil Company e Attachment 8 · Attachment 8 Water Analysis Report For Sterling 8-4 Sands ·~t... Commercial Testing & Engineering Co. Environmental Laboratory Services rlllllllllllllllllllllllllllllll~ 5633 B Str! Anchorage. AK 99518-161 Tel: (907) 562-23. Fax: (907) 561-531 So;o.;.=k-iCI WATER ANALYSIS REPORT OPERATOR MARATHON WELL NO. 4 ~~g FIELD COUNTY 5T ATE DATE 1/18/95 LAB Ncß.5. 0122-0' LOCATION FORMATION S-\«-...\:,.,-..<>-, ~-~ 'S"'~).... INTERVAL S2.\~"'2..' - 5"il-z..: 5AMPLEFROM STERLING WELL 43-5 REMARKS & CONCLUSIONS BARIUM, MG/L 1.30 STRONTIUM, MG/L ND(0.50) TQTAT. IRON, MGIL 12.0 ~~ · Cations Sodium ... Potassium. Calcium. . _ Magnesium Iron..... . mg/l 698 '-OÓ ~ ~ meqll 30.36 2.56 1 .10 0.75 Total Cations 34.77 Total dissolyed solids, mgll NaCI equivalent, mg/l . _ . . Observed pH . . .. ... ... . .. 1931 1615 ~ 7.8 --~- Anions Sulfate. . . . Chloride. . . Carbonate. . Bicarbonate Hydroxide. mgll o 384 o 1460 o meq/l 0.00 10.83 0.00 23.94 o -- 'rota I Anions 34.773 -~-_..,-- Specific resistance @ 68° F Observed ......... Calculated ........ 2.96 3.97 , ohm-meters ohm-meters WATER ANALYSIS PATTERN Scale M EO per Unit ·::.:,i~:; ,L:: ;iW-t8.: Ii: : ¡::.:,.\ .,\ .'.......' N',:;i¡<[: ¡¡¡iii!,: i;,:!:i:r,;; .!,.; CI ".1.... ..,1 ." ..., "" ('.1 .,1. . Ca -':~; ~~!~ ;;;; ¡]~ ¡~j: ~;~; ';¡~; ~:¡; [ " , ,'j ',', ;'i ".." """ ..,.. ::¡: ¡I,: '::1 . II' I I .. 'I" " :::. II::::; :;!!: :':: ¡::i ::i: i i: I:;! Mg 'ili :1:: :¡:: II· III !: III: 1:11 I II ·::i so Fe ;',!!T::';!;i;,¡;::,I,i;':·:!:·::I;.;!!:;!;! ):::, CO. :, I:: :1::1::1: !II: I ::\iI:: ::::1::1:11: ! L::. . ::;: :'::1:::,: ¡:1: ! :' I!:: :::: :::;'1:: : !:,¡! '.: .:..., :1: ::::: :\i:': II;;,::.. :: ; :.:.1 ~,::' ":¡ ;!:~ ~ : ,::: :::~l:~',:::,:;,:";:,;¡:,, Sample,abòve described t '¡\~\'¡ j ji\ \ ?¡:¡;! j': \',I!:; \h '¡\\\\) I¡ \ u)\\ Ii \j'; \ ',~ . ". .... ,." ¡.' "II, ",,,.. '! Ii ' "; I · <N, 1,,' "I:\~J!:I:;l!tlkil,i, [ii!: CIKlo 10)( Ca :¡¡ ¡:: :!¡¡ !iL ¡~; Ii!: ¡:!!)!:; :~:¡: HCO,xlo ·::I::::I::~:::!i:::I!!i0!!!i! 1:li , .. i ; ; ;; : ~ :; .;;; I" (.,. : ¡; 'I; !' 'I i II::'¡::!:;',/, il·:'11 \ 'J(Mg , I!!! li¡¡, i,i,!!I"1, ¡ I !¡ii ! ;Î,: so. x I ::;: ::11 I!: I: I';·; II:: -,:!: ~ ¡ i::: i:!~ :~:: ~.:~ I ~¡¡! ¡ iLl . Fe li,I:: I ¡¡'I In ¡ r· i; ¡:¡i'! :I¡::,"II;: ¡:¡::'l'!,';::' !,I'!'U:lr· ¡ Ii: ir';: r! fi:;; !;::I co 1 tJllil·:: ;'¡. .:;' ::, ;: ':!I !:¡ :.;'. :::~ , : :: ! I : ~ :::: L:'! ! I!: 1:.1 I'! II! II !! I ! r I:: - .. . '. ',~.;. ~; : ' : ~ . , I : ~ i ~ :: ::' I : \ : : I : : : ~ II t : I I : : : . () 1 .... Y tJ. ~ (Ne 'e~u. in abo.. graphs ~"c~ud<ts Ne, K. and LI) NOTE: Mgt1 == M¡UI~'I'.1TIs p.er liter M~GII = MiHigrems equilfal111t p'!r titer Sodium Ch~orid. _quirt_tent = by Ounlap & H~w1nor:\<! c.lcyI8-ttQn lrom cQmponen~s · : ::1; : 1:;1. . :..... HCO , " ) @SGS . Member of the SGS Group (Société Gênéra;e de Surveillance) ENVIRONMENTAL ,CILlTIES IN ALASKA. COLORADO. FLORIOA. (LLlNOIS. MARYLAND. NEW JERSEY. OHIO. UTAH. WEST VIRGINI, Attachment 9 · · · Application for a Disposal Injan Order - Marathon Oil Company e Attachment 9 Attachment 9 Well bore Schematic for Well SU 32-9 r . . ... Nt 'MARATHON _ ~. 4 Sterling Field . Well SU 32-9, Pad 43-9 Marathon Oil Co., Alaska Region API: 50-133-20485 KB-GL: 29.71' KB-THF: 30.00' 2312' FSL, 449' FEL Sec. 9, TSN, RIOW, S.¥. ... CamcoKBUG-LTS chemical injection mandrel wI 114" (0.049" wall) injection line (â) 998' I" chemical injection valve installed 2/12/99 ... Tubing: 3-112", 9.3#, N-80, EVE 8rd,AB-Mod. (II jnts of 9.2# NU Butt., 660' - 992') J >< ><. x Isolated PerCoràtions Sterling 134: 5679' - 86' AIT (6 spf, 60· phased) ~~ -L ~ Electric line tagged PBID @ 6810' ELM(1114/98) ~C- (" -,-:'\....-" c.. ~'---' r --/ r '-' PBID = 6820' ID = 6858' Last Rev: JOE, 2120/99 13-318",68#, K-55 Drive Pipe@80' ¡. .. 9-518",47#, P-IIO, BTC Casing@2111' Cmt wI 620 sks of class G McMwry SMO-l Gas Lift Mandrel (â) 5521' (1 ~ dummy valve installed 2115/99) Halliburton PIlL Retrievable Packer @ 5573' Halliburton XU sliding sleeve @ 5630' wI X-profile (ID = 2.813") (opened 2/15/99) Locator sub @ 5877 Baker model F permanent packer @ 5871 wI 1 0' sealbore X Nipple (â) 5896' (ID = 2.813") Wireline Re-Entry Guide @ 5909' 7",29/1, L-80, BTC casing @ 6858' Cmt wI 690 sics of class G Attachment 10 · · · Application for a DisPOSallnj.on Order - Marathon Oil Company e Attachment 10 Attachment 10 Well bore Schematic for Well SU 41-15 r . , Nt MARATHON ~ . Sterling Field· Well SU 41-15, Pad 43-9 Marathon Oil Co., Alaska Region API 50-133-20484 KB-THF: 30.00' KB-GL: 29.71' 437'FEL,2327'FSL Seè. 9" T5N, RI0W, S.M. ... CMU Sliding Sleeve @ 8751' X w/ X-profile (lD = 2.313") ... (closed 211 5/99) Baker model GT Dual Packer @ 8820' Z ~ Z Z Beluga S and Perfs 9440' - 450' 9616' - 640' 9674' - 682' 9694' - 704' 9722' - 736' 9800' - 812' '003' - 01-4' ~ ; >17' - ój6' X-Nipple @ 9760' ID = 2.313 Re-Entry Guide @ 9770' ~ ¡Iz lIèluga pay from 9440' - 9812' was fracture stimulated with 74,500 Ibs . of 20/40 EconoProp on 1/9199. Note: Tagged fill at 9792' on shortstring (8/23/99) z ... x'x -1L ( Tyonek Sand Perfs 10,942' - 953' (4-5/8",6 spf, 5' StimGun) 11,034' - 044' (4-5/8",6 spf. 5' StimGun) 11,121' - 136' (4-5/8", 6 spf, 3' StimGun) 11,290' - 296' (4-S18",hpf, no Slim Gun) U,305' - 316' (4-5/8",6 spf, 5' SlimGun) \322' - 331' (4-5/8",6 spf,.6' StimGun) ~ ::---- -....) -,. '\~\ :::=--=:::: PBTD = 12,490' TD = 12,600' Last Rev: JGE, 6121/00 Halliburton TruGuide injection mandrels w/1I4" (0.049" wall) injection line SS @ 822' LS @ 944' I" injection valves installed 2/99 ... fO", [-55 Drive Pipe @ 58' ... 13-3/8",611, [-55, BTC Casing @ 2m' Cmt w/1186 sks of class G Tubing (Shortstring & Longstring) 2-7/8", 6.SI, L-80, AB-Mod EUB 8rd Steel Blast Joint (OD = 3.500") LS SS 9437'-455' 9436'-456' 9616'-643' 9611'-749' 9668'-739' 9795'-822' 9996'-033' 7" Liner Top @ 10108' w/ ZXP liner-top packer ... 9-5/8", BTC casing @ 10312' 0' - 3083': 53.51, P-110 3083' - 9866': 471, P-110 9866' - 10312': 47#, L-80 Cmt w/ 2284 sks of Class G Note: Apparent corkscrewed tubing at 10,040' Baker model "D" Packer @ 10847' Shock absorber @ 10865' X Nipple @ 10902' ID = 2.313" 15164" choke installed 317100. End of Tubing @ 10940' Þ " ïq~ tit\ ~ ,,~' 0\\3\\;100\ v) .~'5 f!l. Top of Fill: 11,993' (3/6/00) Fish: 402' of 4-5/8" TCP guns dropped to the bottom of the hole after perforating. 7",29#, L·80, BTC liner @ 10108' - 12590' Cmt w/ 708 sts Appendix A · · · Application for a DisPOSallnje.n Order - Marathon Oil Company e Appendix A Page 1 of 3 Appendix A Statute 20 AAC 25.252 Underground Storage of Oil Field Wastes and Underground Storage of Hydrocarbons (a) The underground disposal of oil field wastes and the underground storage of hydrocarbons are prohibited except as ordered by the commission under this section. In response to a letter of application for injection filed by an operator, the commission will issue an order authorizing the underground disposal of oil field wastes that the commission determines are suitable for disposal in a Class II well, as defined in 40 C.F.R. 144.6(b) as revised as of July 1,1998, which is adopted by reference, or the underground storage of hydrocarbons. An order authorizing disposal or storage wells remains valid unless revoked by the commission. (b) The operator has the burden of demonstrating that the proposed disposal or storage operation will not allow the movement of oil field wastes or hydrocarbons into sources of freshwater. Disposal or storage wells must be cased and the casing cemented in a manner that will isolate the disposal or storage zone and protect oil, gas, and freshwater sources. (c) An application for underground disposal or storage must include (1) a plat showing the location of all proposed disposal and storage wells, abandoned or other unused wells, production wells, dry holes, and any other wells within one-quarter mile of each proposed disposal or storage well; (2) a list of all operators and surface owners within a one-quarter mile radius of each proposed disposal or storage well; (3) an affidavit showing that the operators and surface owners within a one- quarter mile radius have been provided a copy of the application for disposal or storage; (4) the name, description, depth, and thickness of the formation into which fluids are to be disposed or stored and appropriate geological data on the disposal or storage zone and confining zones, including lithologic descriptions and geologic names; (5) logs of the disposal or storage wells, if not already on file, or other similar information; Application for a Disposal Injan Order - Marathon Oil Company e Appendix A Page 2 of 3 · (6) a description of the proposed method for demonstrating the mechanical integrity of the casing and tubing under 20 MC 25.412 and for demonstrating that fluids will not move behind casing beyond the approved disposal or storage zone, and a description of (A) the casing of the disposal or storage wells, if the wells are existing; or (B) the proposed casing program, if the disposal or storage wells are new; (7) a statement as to the type of oil field wastes to be disposed or hydrocarbons stored, their composition, their source, the estimated maximum amounts to be disposed or stored daily, and the compatibility of fluids to be disposed or stored with the disposal or storage zone; (8) the estimated average and maximum injection pressure; (9) evidence to support a commission finding that the proposed disposal or storage operation will not initiate or propagate fractures through the confining zones that might enable the oil field wastes or stored hydrocarbons to enter freshwater strata; · (10) a standard laboratory water analysis, or the results of another method acceptable to the commission, to determine the quality of the water within the formation into which disposal or storage is proposed; (11) a reference to any applicable freshwater exemption issued in accordance with 20 MC 25.440; and (12) a report on the mechanical condition of each well that has penetrated the disposal or storage zone within a one-quarter mile radius of a disposal or storage well. (d) The mechanical integrity of a disposal or storage well must be demonstrated under 20 MC 25.412 before disposal or storage operations are begun, after a well workover affecting mechanical integrity is conducted, and at least once every four years. To confirm continued mechanical integrity, the operator shall monitor the injection pressure and rate and the pressure in the casing-tubing annulus during actual disposal or storage operations. The monitored data must be reported monthly on the Monthly Injection Report (Form 10-406). (e) If an injection rate, operating pressure observation, or pressure test indicates pressure communication or leakage in any casing, tubing, or packer, the operator shall notify the commission by the next working day and shall implement corrective action or increased surveillance as the commission requires to ensure protection of freshwater. · (f) The commission will require additional mechanical integrity tests if the commission considers them prudent for conservation purposes or protection of freshwater. Application for a Disposal I.ion Order - Marathon Oil Company e Appendix A Page 3 of 3 · (g) Modifications of existing or pending disposal or storage operations will be approved by the commission, in its discretion, under 20 MC 25.507, upon application containing sufficient detail to evaluate the proposed modification. No modification will be approved unless the applicant proves to the commission that the modification will not allow the movement of fluids into sources of freshwater. (h) If wells, including freshwater wells or other borings, are located within a one-quarter mile radius of the disposal or storage well, are a possible means for oil field wastes or hydrocarbons to move into sources of freshwater, and are under the control of (1) the operator, the operator shall ensure that the wells are properly repaired, plugged, or otherwise modified to prevent the movement of oil field wastes or hydrocarbons into sources of freshwater; or (2) a person other than the operator, the commission will not issue an order under (a) of this section to the operator until the operator presents evidence to the commission's satisfaction that the person who controls the wells has properly repaired, plugged, or otherwise modified the wells to prevent the movement of oil field wastes or hydrocarbons into sources of freshwater. (i) The commission will publish notice of the disposal or storage application and will provide opportunity for a hearing in accordance with 20 MC 25.540. · U) If disposal or storage operations are not begun within 24 months after the approval date, the injection approval will expire unless an application for extension is approved by the commission. (k) The annular disposal of drilling wastes approved under 20 MC 25.080 is an operation incidental to drilling a well and is not a disposal operation subject to this section. (I) This section does not apply to underground disposal that is regulated under 40 C.F.R. 147.101 by the United States Environmental Protection Agency. History - Eff. 4/2/86, Register 97; am 11/7/99, Register 152 Authority - AS 31.05.030 · Appendix B · · · Application for a Disposal Injan Order - Marathon Oil Company e Appendix B Page 1 of 4 Appendix B WEL 18 Data for Water Wells Depth of Well in ft. Within T5N R10W SM, Adjacent to Section 9c 94 220 21 111 Within T5N R10W SM Average Maximum Minimum No. of Wellsb 91 451 6 1,026 Within 114 mile of the SU 43-9 well location (Includes Portions of Sections 9 and 10) N/A N/A N/A Od a Data are current as of March 20, 2002. bOnly wells with depths greater than zero were included in the statistics. CWithin T5N R10W SM, Sections 3, 4,5,8,9,10,15,16,17. dNo section information was available in WELTS for one well within Section 10 (Key No. 22335). Also, Marathon has a temporary water use permit (TWUP A98-25) for a water well associated with drilling activity that is located within % mile of the SU 43-9 well location. ) ) ) Application for a Disposal Injection Order Appendix B Hydrologic Survey of Water Wells Page 2 of 4 Appendix B. WELTS Data Department of Natural Resources Division of Min.ing, Land Water (WEL TS) KEY LAS OWNER DOC DEPTH MERID TWNSHP RANGE SECTION # in Section SECPRTS MAPNUM STATUS DRILLER REGION DOE PDESC TAGS REM1 REM2 REM3. REM4 MODDATE PDFNAME PDFDATE 1990 AMUNDSON, TOM 8/21/1981 97 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 MACKEY LAKE 61 FT SWL; 25 GPM YIELD. 12/23/1999 1992 MERRIT, BERNIE 10/4/1978 138 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 MACKEY LAKE RD 110 FT SWL; 8 GPM YIELD. 12/23/1999 1993 FAIR. STEPHEN 10/3/1978 103 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 MACKEY LAKf RD 85 FT SWL; 20 GPM YIELD. 12/2311999 2004 WAlTZ, BUD 6/29/1979 71 SB 5 10 0 U KRAXBERGER 21A 1/14/1992 MACKE"fLAKE RD 40 FT SWL; 40 GPM YIELD. 12/23/1999 2005 BIDWELL, LARRY 6/16/1979 71 SB 5 10 0 U KRAXBERGER 21A 1/14/1992 DENISELAKE MACKEY L RD 50 FT SWL; 25 GPM YIELD. 12/23/1999 2010 CATALANO BLDRS 81911979 102 SB 5 10 0 U KRAXBERGER 21A 1/14/1992 MACKEt( LAKE RD 82 FT SWL; 8 GPM YIELD. 12/23/1999 2017 HALL, TOM 2/3/1980 105 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 MACK~ LAKE RD 85 FT SWL; 20 GPM YIELD. 12/2311999 2017.pdf 4/3/2001 2018 HALE, DON 218/1980 190 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 STRAV\1J3ERRY RD 110 FT SWL; 40 GPM YIELD. 12/23/1999 2018.pdf 4/3/2001 2022 BARNES, LARRY 6/4/1980 30 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 BIG EDDY RD SOLDOTNA 10 FT SWL; 6 GPM YIELD. 12/23/1999 2022.pdf 316/2001 2034 DIXON, JIM 11/12/1980 78 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 STRAWBERRVRD 55 FT SWL; 10 GPM YIELD. 12/23/1999 2034.pelf 4/3/2001 2045 MATRANGA, BRIAN 11/10/1981 32 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 STRAW!aERRY RD 13. FT SWL; 6 GPM YIELD. 12/23/1999 2045.pdf 413/2001 2056 MCCLAIN,L~RENCE 7/27/1981 138 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 SOLDOTNA-HILL 116 FT SWL; 15 GPM YIELD. 12/23/1999 2056.pelf 4/3/2001 2063 MSP&G 11/16/1980 33 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 BIG EDDy RD 5 FT SWL; 10 GPM YIELD. 12/23/1999 2063.pdf 413/2001 2064 BROWN, LARRY 6/15/1981 137 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 BIG EDÐY RD· ARTESIAN. FLOW AT 30 GPM. 12/23/1999 2064.pelf 4/3/2001 2070 MADDOX, JACK 5/12/1981 96 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 EAST REDQIJE¡T AVE SOLDOTNA ARTESIAN, FLOWS 6 GPM. 12/27/1999 2070.pelf 4/3/2001 2078 DALKOVSKI, MITKO 7/23/1979 66 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 KENAI SPUR 25 FT SWL: 50 GPM YIELD. 12/27/1999 2078.pdf 413/2001 13753 DAHL, CURT 6120/1984 93 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 SOLDOTNA NR GOLF COURSE 70 FT SWL; 10 GPM YIELD. 2/10/2000 13753.pdf 11127/2001 16045 BILBY, MIKE/GALA 7/19/1986 140 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 SOLD01NA E REDOUBT AVE ARTESIAN AT 0.5 GPM; 100 GPM YIELD. 2/18/2000 16045.pdf 10/22/2001 16125 HILL. BILLY 3123/1984 30 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 RINEHART 12 FT SWL; 50 GPM YIELD. 2/22/2000 16125.pdf 1 0122/2001 16203 WATSON, KURT 11/18/1983 38 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 MACKEY LAKE 28 FT SWL; 20 GPM YIELD. 2/23/2000 16203.pdf 1012212001 16243 BAILEY, VERNON III 7/6/1983 230 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 HENIKIE L01 B2 ARTESIAN AT 3 GPM. 10/312001 16243.pdf 1 012212001 16260 NICKOLAS, CHARLIE 8/18/1983 76 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/1411992 STRAWB"ERRY RD 48 FT SWL; 30 GPM YIELD. 212412000 16260.pdf 10/2212001 16344 BOLES, WOODY 10125/1982 79 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 MACKEY LAKE RD 40 FT SWL; 25 GPM YIELD. 212812000 16344.pdf 10122/2001 16405 NYCE, GEORGE 9/16/1982 58 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 STRAWBERRY RD 40 FT SWL; 8 GPM YIELD. 3/1412000 16405.pdf 10/22/2001 16460 ROGERS, DON 5/7/1983 30 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 SOLDONTA KNIGHT DR 101212001 16460.pdf 1 0/22/200 1 18465 TORO 10/3/1984 77 SB 5 10 0 U NORTHLAND DRILLING 21A 1/14/1992 MACKEY LAKÈ DON DR 813/2001 18465.pdf 8122/2001 18466 TORO 8/30/1984 66 SB 5 10 0 U NORTHLAND DRILLING 21A 1/14/1992 MACKEY LAKE 8/312001 18466.pelf 8122/2001 18467 TORO 10/3/1984 77 SB 5 10 0 U NORTHLAND DRILLING 21A 1/14/1992 MACKEY LAKE DON DR 813/2001 18467.pdf 8122/2001 18468 ALDRIGE, ROYAL 5/12/1984 117 SB 5 10 0 U NORTHLAND DRILLING 21A 1/14/1992 MACKEY LAKE 813/2001 18468.pelf 8/22/2001 18588 NICKOLAS, PAT 11/18/1983 57 SB 5 10 0 U NORTHLAND DRILLING 21 1/14/1992 IRONS DR SOLDOTNA 81212001 18588.pelf 812212001 18907 C&O BLDRS 3120/1986 143 S8 5 10 0 U SMITH WELL DRILLING 21A 1/14/1992 EAST REDOUBT AVE SOLDOTNA 7/1912001 18907.pdf 8/22/2001 18992 McCOOL, JIM 10125/1984 136 S8 5 10 0 U SMITH WELL DRILLING 21A 1/14/1992 EAST REDOUBT AVE SOLDOTNA 7/1612001 18992.pdf 8/2212001 18997 SMITH, DON 9/1/1984 30 S8 5 10 0 U SMITH WELL DRILLING 21A 1/14/1992 EAST REDOUBT AVE SOLDOTNA 7/1612001 18997.pdf 8122/2001 19003 STROUD, HAROLD 1019/1984 106 S8 5 10 0 U SMITH WELL DRILLING 21A 1/14/1992 STRAWBERRY RD SOLDOTNA 7/1612001 19003.pdf 8/22/2001 21302 WILLIS, ZILLMAN 11123/1976 58 S8 5 10 0 35 U KRAXBERGER DRILLING 21A 6/2/1992 MACKEY LAKE: 6/1412001 21302.pdf 612512001 21705 CALER, RANDALL 4127/1970 31 SB 5 10 3 1 BABA U THORN DRILLING 21A 1119/1992 VALHALLA HEIGHTS L06 B7 NOWELL LOG. 14 FT SWL; 12-14 GPM YIELD. 12/13/1999 21705.pdf 612512001 16404 CHIVERS, LINDA 9/15/1982 58 S8 5 10 4 U KRAXBERGER DRILLING 21A 1/14/1992 EAGLE RD . 37 FT SWL; 40 GPM YIELD. 1 01212001 16404.pdf 1 0122/2001 ) \ 17426 MATSON, ROD 9/13/1989 216 S8 5 10 4 BDBD 1-Jan S KRAXBERGER DRILLING 21A 1/14/1992 EAGLE LAKEL05 B2 17426.pdf 9/1812000 20103 PITTS,DAN 6/17/1982 50 S8 5 10 4 CBDA 5-Jan S KRAX8ERGER DRILLING 21A 1/14/1992 E MACKEY LAKE N L05 B2 DUP OF 16390 9129/1992 20103.pdf 3/112001 22570 NIXON, TIM 217/1994 196 S8 5 10 4 MAC U KRAXBERGER DRILLING 21A 12/19/1994 CARVER3 Log B7 2/2/1995 22570.pdf 5/23/2001 23217 MAXWELL, LAURINE 10122/1995 173 S8 5 10 4 5 BBAD U KRAXBERGER DRILLING 21A 2/22/1996 EAGLE LAKE L05 B1 8 GPM. 140 FT SWL. 31511996 23217.pdf 413/2001 2032 CHAPPEL, CLINT 1119/1980 80 S8 5 10 5 AAB U KRAXBERGER DRILLING 21A 1/14/1992 CARVER 3 L14 B7 . 49 FT SWL; 20 GPM YIELD. 515/1998 2032.pdf 41312001 3889 SCHMIDT, DAVID 8123/1983 68 S8 5 10 5 BOCA 26-Jan S ECHO LAKE DRILLING 21A 1/14/1992 GIESLER SCIiMIDT D.M.S. L 1 8/18/1992 3889.pdf 5/2312001 8102 FORREST, 81LL 10/18/1984 164 S8 5 10 5 U ECHO LAKE DRILLING 21A 1/14/1992 CARVER L04 B7 10/21/1999 14113 3857 CARVER, KENNETH R. 5/1/1985 73 SB 5 10 5 ABBA 1-Jan S KENNY CARVER DRILLlN 21A 1/14/1992 CARVER 2 L23 B7 2/1711983 14113.pdf 812512000 16175 8ARNARD, DENNIS 1016/1983 83 S8 5 10 5 ABCC U KRAXBERGER DRILLING 21A 1/14/1992 CARVER.3L14B4 44 FT SWL; 30 GPM. SCREEN 78-83 FT. 7129/1998 16175.pdf 1 0122/2001 16187 NIBLACK, DENNIS 1125/1993 146 S8 5 10 5 AABB U DARC ENTERPRISES 21A 1/1411992 CARVER 2 L20 B7 123 FT SWL; 15 GPM. SCREENED AT 145.8 FT. 7/3011998 16187.pdf 10122/2001 16235 BAILEY, MARVIN 7/12/1983 58 S8 5 10 5 U KRAXBERGER DRILLING 21A 1/1411992 STRAWBERRY RD L 19 49 FT SWL; 15 GPM YIELD. 2/2412000 16235.pdf 10/22/2001 18532 STECKEL, JOHN 3/31/1987 70 SB 5 10 5 BCCB 5-Feb S ECHO LAKE DRILLING 21A 1/14/1992 MATRANGA 1 L1 B2 TR-1 12/2/1992 18532.pdf 11/112000 18733 HOUK, MONTE 1/1/1977 67 S8 5 10 5 COCO 9-Jan S NORTHLAND DRILLING 21A 1/14/1992 KNORR 1 L3A 4/13/1993 18733.pdf 1118/2000 18811 WASSON 29 S8 5 10 5 DC U NORTHLAND DRILLING 21 111411992 STRAWBERRY RD KENAI AREA 7/2412001 18811.pdf 8122/2001 18970 C&O 8LDRS 10/13/1985 178 S8 5 10 5 AABA 11-Jan S SMITH WELL DRILLING 21A 1/14/1992 CARVER L 1287 4121/1992 18970.pdf 111812000 19000 CHAPPELL, CLINT 10/15/1984 104 S8 5 10 5 AADC 15-Jan S SMITH WELL DRILLING 21A 1/14/1992 CARVER 3 L02 B4 412111992 19000.pdf 111812000 19171 RANEITZ, JEFFREY 9/16/1988 58 S8 5 10 5 ABDC 10-Jan S KRAXBERGER DRILLING 21A 1/14/1992 CARVER 3L 10 B4 19403 UNKNOWN 176 S8 5 10 5 AADB 13-Jan S UNKNOWN 21A 1/1411992 CARVER 3 L05 B7 148.4 FT SWL; 4.2 GPM YIE LD. NO LOG AVAILABLE. 1/12/1998 19404 JAMES, WALTER 7/1/1980 90 S8 5 10 5 BACA 21-Jan S KENNY CARVER DRILLlN 21A 1/14/1992 CARVER 2 Log B2 412111992 19405 FA81ANO, ANTHONY 9/1/1978 57 S8 5 10 5 ABCB 16-Jan S UNKNOWN 21A 1/1411992 CARVER 2 L04 B5 NO WELL LOG. 42.1 FT SWL. 6.1 GPM. 71911996 19406 UNKNOWN 45 S8 5 10 5 AB8C 14-Feb S UNKNOWN 21A 1/14/1992 CARVER 2 L02 B5 4121/1992 19408 McDERMOTT,CHESTER 1/1/1974 83 SB 5 10 5 8AAC 19-Jan S UNKNOWN 21A 1/14/1992 CARVER 1 L03.B2 4/21/1992 19410 McCARTHY, JOHN 1/1/1975 100 S8 5 10 5 BADC 25-Jan S GEORGE MATRANGA 21A 1/14/1992 CARVER 1 L02 83 4121/1992 19411 CHOAT, LOWELL 1/1/1976 173 S8 5 10 5 BAAD 20-Jan S UNKNOWN 21A 1/14/1992 CARVER ·IL01 B2 NO LOG. 45 FT SWL. 11/18/1996 19412 MORRIS, SID 1/1/1979 49 S8 5 10 5 AABB 12-Jan S UNKNOWN 21A 1/14/1992 CARVER 3 L14 B7 412111992 19414 BOWEN, JOHN W 1/1/1969 66 S8 5 10 5 BADB 24-Jan S UNKNOWN 21A 1/14/1992 CARVER L 12 B2 412111992 19415 JAMES, WALTER H 82 S8 5 10 5 BAAC 19-Feb S UNKNOWN 21A 1/14/1992 CARVER 1 LOS 82 412111992 19416 JAMES, WALT 6/12/1978 158 SB 5 10 5 ABCA 17-Jan S KRAXBERGER DRILLING 21A 1/14/1992 CARVER L06B5 4121/1992 19416.pdf 11/1612000 19418 UNKNOWN 1/1/1982 60 S8 5 10 5 8AC8 23-Jan S NORTHLAND DRILLING 21A 1/14/1992 CARVER 1 L 15 B1 412111992 19419 GATES, JAMES 8124/1983 36 S8 5 10 5 BAAB 18-Jan S WS&SCO 21A 1/1411992 CARVER 1 L04 B1 1/12/1993 19419.pelf 11/16/2000 19421 PRENTICE, MARK 28 S8 5 10 5 BABB 22-Jan S UNKNOWN 21A 1/1411992 CARVER 1 L09 B1 4121/1992 19422 LANDUA, JOHN 1/1/1974 62 S8 5 10 5 ABBe 14-Jan S UNKNOWN 21A 1/14/1992 CARVER 2 L03B5 NO LOG AVAILABLE. 312911996 19423 RICE,JODIE 6/17/1983 65 S8 5 10 5 BACB 23-Feb S PENINSULA DRILLING 21A 1/1411992 CARVER 1 L 14 B1 19 FT SWL. 10.8 GPM YIELD 7/16/1996 19423.pdf 11/1612000 19447 MACVIE, FREDERICK 65 S8 5 10 5 B U UNKNOWN 21A 1/1411992 BURTON-CARVER L05 B1 NO WELL LOG. 3/4/1998 19447 .pelf 8122/2001 19648 GRAY. SHARON 6/1/1966 96 S8 5 10 5 U UNKNOWN 21A 1/14/1992 SHAKEY ACRES L2 NO WELL LOG. 43 FT SWL. 3/4/1998 19648.pdf 8122/2001 19858 ENGLISH. DAN 11/8/1985 62 S8 5 10 5 COCB 28-Jan S KENNY CARVER DRILLlN 21A 1/14/1992 KNORR 1 L 1A 1012011994 19858.pdf 1181200 1 19859 JOHNSON, DALE 1/1/1977 57 S8 5 10 5 COCA 29-Jan S UNKNOWN 21A 1/1411992 KNORR L2-A RESUB OF L 1&2 11/7/1994 19861 HOKETT. DORIS 8/25/1984 71 S8 5 10 5 CDCD 9-Feb S PENINSULA DRILLING 21A 1/1411992 KNORR L?B 20 GPM 10117/1995 19861.pdf 118/2001 20729 GIESLER, JIM 104 S8 5 10 5 BDCD 1-Feb S UNKNOWN 21A 1/1411992 GIESLER PROPERTY.KRD BK42 10/12/1992 20747 UNKNOWN S8 5 10 5 SACA 21-Feb S UNKNOWN 21A 111411992 CARVER 1 LOS 82 1012011994 Depth = 0 feet 21692 WOOD. BILLY 1/1/1975 64 SB 5 10 5 BAAD U UNKNOWN 21A 11/5/1992 CARVER 1 L02 B2 NO WELL LOG. 38.7 FT SWL. 8 GPM PUMP RATE. 319/1998 21692.pdf 6125/2001 22208 DAVIS. KEVIN 1/1/1976 45 S8 5 10 5 BCCB U UNKNOWN 21A 6121/1993 MATRANGA .1.1 B1 NO WELL LOG. 35 FT SWL. 6 GPM PUMP RATE. 4/16/1998 22208.pdt 512312001 22209 NIKOLAS. V.J. 80 S8 5 10 5 BCDA U UNKNOWN 21A 6/21/1993 MATRANGA L7 B1 NO WELL LOG. 4/16/1998 22209.pdf 512312001 22210 SCHRADER, GLEN 1/1/1979 113 S8 5 10 5 BCOC U KENNY CARVER DRILLlN 21A 6121/1993 MATRANGA L5 B1 NO WELL LOG. 4/16/1998 22210.peIf 512312001 22211 MATRANGA, BRIAN 1/1/1977 21 S8 5 10 5 BCBC U KENNY CARVER· DRILLlN 21A ·6121/1993 MATRANGA 2 TR-1B B1 NO WELL LOG. 4/16/1998 22211.pdf 5/2312001 22332 PELLENGILL. FRANK 1/1/1972 132 S8 5 10 5 U UNKNOWN 21A 8/1711993 STERLING AREA NO WELL LOG. 4120/1998 22332.pdf 512312001 22472 OBERG. MARTY 9123/1992 140 S8 5 10 5 MBB U DARC ENTERPRISES 21A 12/8/1994 CARVER 2 L 19 B7 2/2/1995 22472.pdf 512312001 23045 PETTENGILL, FRANK 135 SB 5 10 5 C U UNKNOWN 21A 12/11/1995 N STRAWBERRY ROAD NO WELL LOG 2/2111996 23045.pdf 4/11/2001 23315 CHAPPELL, CLINT 8/24/1990 88 S8 5 10 5 A8DD U SMITH WELL DRILLING 21A 413011996 CARVER:' L09 B4 3.9 GPM. 60 FT SWL. 5/10/1996 23315.pelf 41312001 Appendix B WELTS spreadsheet.xls 11120/2002 ) ,) ) Application for a Disposal Injection Order Appendix B Hydrologic Survey of Water Wells Page 3 of 4 ) Appendix B. WEL 18 Data Department of Natu~al Resources Division of Mining, Land Water (WEL TS) KEY LAS OWNER DOC DEPTH MERlO TWNSHP RANGE SECTION # in Section SECPRTS MAPNUM STATUS DRILLER REGION DOE PDESC TAGS REM1 REM2 ' RENr:~ REM4 MODDATE PDFNAME PDFDATE 23515 LAS 20656 LANDUA, J 75 SB 5 10 5 46 ABBC U 21A 12/4/1996 CARVER 2 L03.B05 NO LOG AVAILABLE 12/4/1996 23515.pdf 1/4/2001 2129 RICHESON, RANDY 8/18/1981 104 SB 5 10 8 DBBC 14-Jan S KRAXBERGER DRILLING 21A 1/14/1992 REX EAGLE HOMESTEAD TR-D 4/13/1993 2129.pdf 5/21/2001 2273 COURT, HANK 1 0/15/1979 64 SB 5 10 8 BCCD 4-Jan S KRAXBERGER DRiLLING 21A 1/14/1992 HIGHLÁNDSL6B4 2273.pdf 5/21/2001 3314 CHURCH, WALT 71211981 78 SB 5 10 8 U KRAXBERGER DRiLLING 21A 1/14/1992 HIGHLA~DSTRL PRK(NR), T4 45 FT SWL; 15 GPM YIELD. 1/3/2000 3314.pdf 4/11/2001 3756 HOLT CONST, BOB 5/18/1983 69 SB 5 10 8 CBDB U ECHO LAKE DRILLING 21A 1/14/1992 LEO T OBER'fS 1 L 13 B1 10/20/1999 3756.pdf 5/23/2001 3894 OBERTS, STEVE 915/1983 69 SB 5 10 8 CBAD 12-Jan S ECHO LAKE DRILLING 21A 1/14/1992 LEO T QBERTS 1 L08 B1 A 47 FT SWL. 6.63 GPM. 719/1996 3894.pdf 5/21/2001 3895 BREWER, SHARON 9/15/1983 75 SB 5 10 8 CBDA 13-Jan S ECHO LAKE DRILLING 21A 1/14/1992 LEO T OBERTS 1 L07 B1 AL 8/3/1995 3895.pdf 5/21/2001 13607 WTIPIL, ROBERTA 1/1/1970 104 SB 5 10 8 U JESS SHELMAN 21A 1/14/1992 RIDGEi;!IEWESTL4 NO WELL LOG. 3121199813607.pdf 11/27/2001 15684 9888 EAGLE, DAVE 9/3/1986 110 SB 5 10 8 CMB 6-Jan S CARVER KENNY DRILLlN 21A 1/14/1992 REX EÀGLEHOMESTEAD TR- 4/28/1983 15684.pdf 8/29/2000 16309 ELSON, JASON 8/19/1983 58 SB 5 10 8 U KRAXBERGER DRiLLING 21A 1/14/1992 LEO T oeERTS ADD 1 L2 B1 46 FT SWL: 8 GPM YiELD. 212812000 16309.pdf 10/22/2001 18657 BROWN, JIM 70 SB 5 10 8 BC U NORTHLAND DRILLING 21 1/14/1992 HIGHLANDS L? B3 7/31/2001 18657.pdf 8/22/2001 19443 CRAWFORD REAL ESTATE 77 SB 5 10 8 BBDD 5-Jan S UNKNOWN 21A 1/14/1992 CAHILl:. rR"4 A 6 GPM. NO WELL LOG 11/28/1995 19652 ALBAUGH, JACK & YVON 5/1/1976 75 SB 5 10 8 CBBB U UNKNOWN 21A 1/14/1992 LEO T OBERTS TR-E 55 FT SWL: 4 GPM PUMP RAT E. NO LOG AVAILABLE. 1/12/1998 19652.pdf 8/22/2001 19862 KAKFA, RALPH 58 SB 5 10 8 BCDD 15-Jan S UNKNOWN 21A 1/14/1992 HIGHLANDS L9 B2 NO WELL LOG 11/22/1995 20111 ELSON,JASON 8/19/1983 58 SB 5 10 8 CBBA 8-Jan S KRAXBERGER DRILLING 21A 1/14/1992 LEO T OBERTS 1 L02 B1 9/23/1992 20111.pdf 3/1/2001 20112 LEACH,KIP 10/20/1982 79 SB 5 10 8 CBDD 11-Jan S B SPIRES DRILLING 21A 1/14/1992 LEO T OBERTS 1 L02 B2 62 FT SWL: 7.55 GPM PUMP RATE. 1/12/1998 20112.pdf 3/1/2001 20113 OWEN,MARK 5/27/1983 95 SB 5 10 8 CBM 10-Jan S UNKNOWN 21A 1/14/1992 LEO T OBERTS 1 L06 B1 9/23/1992 20114 HOLT CONSTRUCTION 5/1/1979 69 SB 5 10 8 CBDB 9-Jan S ECHO LAKE DRILLING 21A 1/14/1992 LEO T dBERTS 1 L 14 B1 9/29/1992 20114.pdf 3/1/2001 20115 RUCKMAN,DICK 9/15/1983 85 SB 5 10 8 CBAC 7-Jan S KRAXBERGER DRILLING 21A 1/14/1992 LEO T OBERTS· 1:.11 B1 9/23/1992 20115.pdf 3/1/2001 24121 GRAVES, GEOFFREY 7/15/1997 98 SB 5 10 8 19 BDAC U NORTHLAND DRILLING 21A 2/1111998 RIDGEVIEW EST ADD 1 TRCT A 72.5 FT SWL: 15 GPM. 2/12/1998 24121.pdf 1213/2000 18179 KEMPT, GENE 8/8/1989 85 SB 5 10 10 DADC 2-Jan S NORTHLAND DRILLING 21A 1/14/1992 MAOKE\'.LÄKENW L 17 12/2/1992 18179.pdf 1 01212000 18420 ST JOHN, BOB 9/10/1984 65 SB 5 10 10 DDDD 1-Jan S NORTHLAND DRILLING 21A 1/14/1992 MACKEY LAKE 1 L 15 B05 MACKAY LAKES?? 18420.pdf 10/10/2000 22186 RICHARDSON, ROCKY 30 SB 5 10 10 DACe; . U UNKNOWN 21A 6/21/1993 MACKEY LAKE NW L 13 B01 NO WELL LOG. 20 FT SWL. 4/15/1998 22186.pdf 5/23/2001 22201 BERNHARDSON, TONNIE 9/15/1983 51 SB 5 10 10 DDCC U UNKNOWN 21A 6/2111993 MACKEYLÄKE L22A B06 NO WELL LOG 1011711995 22201.pdf 5/23/2001 22335 ANDERSON, ERiC 1/1/1975 87 SB 5 10 10 U UNKNOWN 21A 8/17/1993 BLM L . . KENAI AREA NO WELL LOG. 4/20/1998 22335.pdf 5/2312001 22875 BERNHARDSON,GARY 9/24/1992 190 SB 5 10 10 6 DDCC U PENINSULA DRiLLING 21A 10/17/1995 MACKEY LAKE L22A B06 13GPM 11/21/1995 22875.pdf 5/23/2001 2795 SALTZ, CLYDE 9/18/1982 50 SB 5 10 15 ADBD 3-Jan S ECHO LAKE DRILLING 21A 1/14/1992 MACKE\" LAKE 1 L 16 B06 11/8/1983 2795.pdf 5/21/2001 8072 3062 GIBBONS, JOHN D 5/17/1984 120 SB 5 10 15 DDBA U ECHO LAKE DRILLING 21A 1/14/1992 GIBBONS L8'a2 48 FT SWL: 20 GPM YiELD. 5m1998 18920 McKENNA. JOHN 9/1/1986 67 SB 5 10 15 DD U SMiTH WELL DRILLING 21A 1/14/1992 GIBBONS TRA 7/19/2001 18920.pdf 8/2212001 20090 HISTAND,STAN 7/30/1982 55 SB 5 10 15 AAAD 6-Feb S DARC ENTERPRISES 21A 1/14/1992 MACKEY LAIŒ.1 P4 L03 B5 9/2911992 20090.pdf 3/1/2001 20091 BARTLETT,DAN 6/28/1977 58 SB 5 10 15 AAAD 6-Jan S KRAXBERGER DRILLING 21A 1/14/1992 MACKEY LAKE. 1 P4 L04 B5 6.7 GPM. 41.4 FT SWL. 4/29/1996 20091.pdf 3/1/2001 20092 YARMAK,ED 8/27/1982 220 SB 5 10 15 ADBB 4-Jan S KENNY CARVER DRILLlN 21A 1/14/1992 MACKEY LAKE 1 L 14 B06 1016/1992 20092.pdf 3/1/2001 20093 JONES, WENDELL 10/29/1976 45 SB 5 10 15 MCA 2-Feb S UNKNOWN 21A 1/14/1992 MACKEY LAKE 1 P5 TR7 17 FT SWL: 35 GPM YIELD. 1212111999 20093.pdf 3/1/2001 20094 FOSSE,BURTON 12/1/1979 44 SB 5 10 15 ADDC 5-Jan S LEO'S DRILLING 21A 1/14/1992 MACKEY LAKE 1 L03 B06 9/2911992 20094.pdf 3/1/2001 20095 WAITZ,BUD 3/1/1978 49 SB 5 10 15 ADDA 7 -Jan S ROCKING H DRILLING 21A 1/14/1992 MACKE't" LAKEJ P2 1:.17 B4 9/29/1992 20095.pdf 3/1/2001 21653 PARKS, MARITA 1/1/1970 65 SB 5 10 15 ADBA U UNKNOWN 21A 11/5/1992 MACKEY LAKE 1 L09 B06 NO WELL LOG. 17 FT SWL. 8 GPM YIELD. 3/511998 21653.pdf 6/25/2001 ) 22197 SALTZ, FLOYD 715/1979 47 SB 5 10 15 ADBA U ECHO LAKE DRILLING 21A 6/21/1993 MACKEY LA\<!: 1 1:.13 B06 18 FT SWL; 30 GPM. 219/1998 22197.pdf 5/2312001 22198 MACKEY, aOB SB 5 10 15 AACC U UNKNOWN 21A 8/21/1993 MACKEY LAKE 1 L 15 B08 NO WELL LOG. 4/15/1998 22198.pdf 5/23/2001 Depth = 0 feet 22199 GREEN. WILLIAM 10/28/1977 58 SB 5 10 15 MCD U UNKNOWN 21A 6/21/1993 MACKEY LAKE L 17 B06 NO WELL LOG. 4/15/1998 22199.pdf 5/23/2001 22200 JONES, WENDELL SB 5 10 15 14 AACA U UNKNOWN 21A 8/21/1993 MACKEY LAKE 1 P5 L20 B8 NO WELL LOG. 4/15/1998 22200.pdf 5/23/2001 Depth" 0 feet 8069 HAYS ELECTRIC 4m1984 34 SB 5 10 16 A U ECHO LAKE DRILLING 21A 1/14/1992 OLD KEIIJAI POWER PLANT 13 FT SWL; 10 GPM YIELD. 2/1/2000 21524 AK DNR AG 84 SB 5 10 16 2 ADBB 2-Jan S UNKNOWN 21A 7/16/1992 SOLDOTNAIOORNER RD. Q 4/13/1993 15762 ALA. HARRY 10/1/1976 160 SB 5 10 17 U LES CREARY 21A 1/14/1992 PINNACLE "'ILL L2 B1 NO WELL LOG. 3/3/1998 15762.pdf 10/2212001 15831 URBAN, DAVE 9/25/1984 97 SB 5 10 17 BBB U KRAXBERGER DRILLING 21A 1/14/1992 THOROUGHBRED ACRES L 1 76 FT SWL; 25 GPM. OPEN END. 7/23/1998 15831.pdf 10/2212001 16224 SOLDOTNAASMBLY/GOD 6/14/1983 131 SB 5 10 17 BACD 7-Jan S KRAXBERGER DRILLING 21A 1/14/1992 KELLYRARKL23B1 9.5 GPM. 4/29/1996 16224.pdf 8/31/2000 16300 EIGHMIE, RICHARD 8/24/1983 134 SB 5 10 17 BABD 8-Jan S KRAXBERGER DRILLING 21A 1/14/1992 KELLY PARK L06B1 . SW 102 FT LS, 40 GPM FULL CASE, SCREEN 129-134 FT NEW OWNI:R: EIGHMIE R 101312001 16300.pdf 8/31/2000 18144 JEFFERSON, JEFF SB 5 10 17 U UNKNOWN 21A 1/1411992 ROY WOODS ·fJOMESTEAD TR-2A NO WELL LOG. 3/4/1998 18144.pdf 8/22/2001 Depth Of 0 feet 18484 TACHICK, BOB 8/4/1988 127 SB 5 10 17 CB U KRAXBERGER DRILLING 21A 1/14/1992 LANCASHIRE RD SOLDOTNA 8/3/2001 18484.pdf 8/2212001 18877 DEES, AUBRA 10/4/1987 124 SB 5 10 17 BA U SMITH WELL DRILLING 21A 1/14/1992 KELLY PARK L 12 B1 7/20/2001 18877.pdf 8/2212001 19863 BETENBENDER, DANIEL 91611983 150 SB 5 10 17 DMC 9-Jan S C & M DRILLING 21A 1/14/1992 HIRIDGE L04 B1 11/4/1994 19863.pdf 1/8/2001 19864 COOPER, TIM 7/30/1985 134 SB 5 10 17 DABC 10-Jan S DARe ENTERPRISES 21A 1/14/1992 HIRIDGE L06AB1 11/4/1994 19864.pdf 11812001 19865 DOUGLAS, DON & LORI 8/12/1985 166 SB 5 10 17 DACD 11-Jan S DARC ENTERPRISES 21A 1114/1992 HIRIDGE L01B2 10/26/1994 19865.pdf 118/2001 21113 DONAHUE, CLAIRE 1/1/1979 30 SB 5 10 17 CDDA U UNKNOWN 21A 515/1992 WOODCREST EST L 14 B1 NO WELL LOG. 315/1998 21113.pdf 6/25/2001 21114 UNKNOWN SB 5 10 17 CDDa U UNKNOWN 21A 5/5/1992 WOODCREST EST .L 1381 NO WELL LOG. 3/5/1998 21114.pdf 8/25/2001 Depth" 0 feet 21115 DIXON, WILLIAM 129 SB 5 10 17 CDAB U UNKNOWN 21A 5/5/1992 WOODCRESTEST L 10 B1 NO WELL LOG. 3/5/1998 21115.pdf 6/25/2001 21116 ANDERSON, DENNIS 160 SB 5 10 17 CDAD U UNKNOWN 21A 5/5/1992 WOODCREsT EST L05 B1 NO WELL LOG. 315/1998 21116.pdf 6/25/2001 21117 KIMBELL, JIM 10/1/1981 166 SB 5 10 17 CDDD U BENNET,REX 21A 5/5/1992 WOODCREST EST L02 B1 NO WELL LOG. 315/1998 21117.pdf 6/25/2001 21118 GOODRICH, DAVID 6/5/1980 104 SB 5 10 17 CDDA U BENNET, REX , 21A 515/1992 WOODCREST EST 1 L03B1 NO WELL LOG. 140 FT SWL. 7 GPM YIELD. 315/1998 21118.pdf 6/25/2001 21131 SCHNEIDER, PAUL 144 SB 5 10 17 CDAB U UNKNOWN 21A 515/1992 WOODCRESTEST L08 B2 NO WELL LOG. 315/1998 21131.pdf 6/25/2001 21132 HOLDEN, PETE 146 S8 5 10 17 CDCA U UNKNOWN 21A 5/5/1992 WOODOREST EST L04 B2 NO WELL LOG. 315/1998 21132.pdf 6/25/2001 21133 POINT VIEW REAL TV 125 SB 5 10 17 CD DB U UNKNOWN 21A 5/5/1992 WOODCREST.EST 1 L03 B2 NO WELL LOG 11/21/1995 21133.pdf 6/25/2001 21134 FURLONG, PAM & JOHN SB 5 10 17 CDOC U UNKNOWN 21A 5/!5/1992 WOODCREST ÈST 1 L02 B2 5.85 GPM. NO WELL LOG. 3/5/1998 21134.pdf 6/2512001 Depth = 0 feet 21135 BLAYTON. HARVEY 158 SB 5 10 17 CDDC U UNKNOWN 21A 515/1992 WOODCREST EST L 1581 NO WELL LOG. 315/1998 21135.pdf 6/25/2001 22255 SHANAHAN, TOM 1/1/1978 160 SB 5 10 17 DDBD U UNKNOWN 21A 7/12/1993 HIRIDGE L 12 S1 NO WELL LOG. 137 FT SWL. 6.7 GPM YIELD. 4/17/1998 22255.pdf 5/23/2001 22960 MILLER. PAUL 8/24/1995 134 SB 5 10 17 BCCB U NORTHLAND DRILLING 21A 11/13/1995 HORN L01 20 GPM 11/21/1995 22960.pdf 5/2312001 23866 WATERBURY, ROCKY 9/20/1996 130 SB 5 10 17 24 BAAC U PENINSULA DRL 21A 10/23/1997 KELLY P,ð.RKL16B1 104.5 FT SWL: 17 GPM. 11/24/1997 23866.pdf 1213/2000 AVERAGE 152 'ec. 0 wells) DEPTH 93 ft 152 WeDs with Depth of 0 MINIMUM feet DEPTH 21 ft #/##1#### MAXIMUM 146 in statistics DEPTH 230 ft. AVERAGE 117 9 Section 9 DEPTH 94 ft. Wells with Depth of 0 MINIMUM feet DEPTH 21 ft. Use this data (March 20. 2002) MAXIMUM 111 in statistics DEPTH 220 ft. Appendix B WELTS spreadsheet.xls 11120/2002 Map with Adjacent Sections umber of Welts õ' ..... OJ o a. ro ...... I ~ OJ ... OJ g: o ::::¡ 2 References Application for a Disposa.ection Order - Marathon Oil Company . References · REFERENCES Alaska Department of Natural Resources, Division of Mining, Land and Water, n.d., Alaska Hydroloqic Survey, Well Loq Tracking System, <http://info.dec.state.ak.us/welts/>(March 20, 2002). Alaska Oil and Gas Conservation Commission, 1999, Requlations, Alaska Administrative Code, "20 MC 25.440," <http://www.state.ak.us/local/akpaqes/ADMIN/ oqc/art599.htm#440> (November 7,2001). Marathon Oil Company, 2002, Aquifer Exemption Order, Sterlinq Gas Field Unit. Kenai Peninsula, Alaska, October 2002. United States Environmental Protection Agency, 1998, Code of Federal Regulations, "40 CFR 144-148," Office of the Federal Register National Archives and Records Administration, Washington, D.C., pp. 614-833. · · O:\Sterling\43-9\UIC\2002 Applications\Disposallnjection\DIO References.doc 1/22/2003 #1 e . Application for a Disposal Injection Order Sterling Gas Field Unit Sterling Unit 43-9 Well Kenai Peninsula, Alaska November 2002 Submitted by Marathon Oil Company Anchorage, Alaska . , .M MARATHON ~ e Alaska BeSS Unit . Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 November 22, 2002 RECEIVED Mr. Robert P. Crandall Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West th Avenue, Suite 100 Anchorage, AK 99501-3539 RE: Disposal Injection Order Application Sterling Gas Field Unit, Kenai Peninsula, Alaska Township 5 North, Range 10 West, Section 9, SM Dear Mr. Crandall: :WV 22 2002 Alaska Oil & Gas Cons. Commission Anchorage . Pursuant to 20 MC 25.252, Marathon Oil Company (Marathon) submits the enclosed application, which requests approval to dispose of Class II oil field wastes by underground injection into the 8-4 Sand through the Sterling Unit 43-9 well. The proposed injection interval would be from 5,020 feet SSTVD to 5,120 feet SSTVD. If you have any questions or require additional information, please contact me at (907) 564-6372 or ERWard@MarathonOil.com. Sincerely, ~ML- rz.&~ Eric R. Ward HES Professional ERW:cdg By Certified Mail Enclosure: Application for a Disposal Injection Order cc: Mr. Jim Segura, President, Salamatof Native Association, Inc. R. J. Affinito J. G. Eller E. R. Ward File: CEF, SU 43-9, "H" . ORIGINAL e e . TABLE OF CONTENTS Application Application for a Disposal Injection Order Table Table 1. Sterling Gas Field Unit Well Information FiQures Figure 1. Cook Inlet regional map. Figure 2. Sterling Gas Field Unit with gas wells and MaC's water well. Figure 3. Topographical Map with wells. Attachments Attachment 1. Affidavit of Fact Attachment 2. Sterling Water Disposal Model Summary . Attachment 3. Mechanical Integrity Test for Well SU 43-9 Attachment 4. Injectivity Log Procedure for Sterling B-4 on Well SU 43-9 Attachment 5. Injectivity Test Results for Sterling B-4 on Well SU 43-9 Attachment 6. Construction of Well SU 43-9 Attachment 7 Hydraulic Fracturing Potential Simulation Attachment 8. Water Analysis Report for Sterling B-4 Sands Attachment 9. Wellbore Schematic for Well SU 32-9 Attachment 10. Wellbore Schematic for Well SU 41-15 Appendices Appendix A. Statute 20 MC 25.252: Underground Storage of Oil Field Wastes and Underground Storage of Hydrocarbons Appendix B. WELTS Data for Water Wells . References O:\Sterling\43-9\U I C\2002 Applications\Disposal I njection\Contents-DIO .doc 11/21/2002 e e . APPLICATION FOR A DISPOSAL INJECTION ORDER STERLING GAS FIELD UNIT, SU 43-9 WELL OPERATED BY MARATHON OIL COMPANY This application was prepared in accordance with the requirements of Alaska Oil and Gas Conservation Commission (AOGCC) Statute 20 AAC 25.252, UNDERGROUND DISPOSAL OF OIL FIELD WASTES AND UNDERGROUND STORAGE OF HYDROCARBONS effective November 7,1999. Introduction Marathon Oil Company (Marathon) is applying for a disposal injection order to allow for the underground disposal of oil field wastes in the Marathon Sterling Gas Field Unit (Section 9, T5N, R10W, SM). The injection order would approve disposal of Class II oil field wastes via injection through the Sterling Unit (SU) 43-9 well into the Sterling B-4 Sand. The SU 43-9 well is a production well which will be converted to a Class II well suitable for the disposal of oil field wastes as defined in 40 C.F.R. 144.6(b) (USEPA, 1998). . Marathon has conducted well testing and modeling that demonstrates that the proposed disposal operation will not allow the movement of oil field wastes or hydrocarbons from the Sterling B-4 Sand into sources of freshwater. The design of the existing SU 43-9 well will isolate the disposal zone and protect freshwater resources. Marathon has also conducted testing which confirms the mechanical integrity of the production casing in well SU 43-9. Sterlin~ Gas Field Unit The Sterling Gas Field Unit (SGFU) is located on the Kenai Peninsula approximately six miles east of the city of Kenai and three miles north of the city of Soldotna (see Figure 1). The 3,600-acre SGFU has produced gas from five completions since it's discovery in 1961 (see Figure 2). In addition, a water well drilled to a depth of 268 feet measured depth (MD) is in the SGFU to support drilling operations. Current production operations occur only at the Sterling Unit 43-9 Pad, which represents approximately 4.1 acres of the 3,600-acre unit, or just over 0.1 percent (0.1%) of the area defined by the SGFU. Beginning in October 2000, gas production became intermittent due to the inability of wells to unload and dispose of water. Currently, two of the four completions on the 43-9 pad are shut-in due to water production, and current gas production is restricted to below the economic limit for this field. Table 1 summarizes the current status of the SGFU. . Application for a DiSPoS.jection Order - Marathon Oil Company e Page 2 of 5 · Table 1. Sterling Gas Field Unit First Final Perforated Perforated 12/2001 12/2001 Current Well Prod. Prod. Interval Interval Cum Cum Current Rate Date Date MD SSTVD Gas Water Status MMCFGPD MMCFG MBO SU 32-9 March Active Sterling B-4 Sterling B-4 407 0.13 Active 1.0 1999 (5,679' - 5,686') (5,013' - 5,019') SU 43-9 Oct. Feb. Sterling B-4 Sterling B-4 2,165 2.75 SI due to 0 1966 1998 (5,262' - 5,272') (5,026' - 5,036') water SU 23-15 May Oct. Sterling B-4 Sterling B-4 379 NA T&A'd 0 1962 1966 (5,250' - 5,254') (5,028' - 5,032') SU 41- April Active Beluga Beluga 53 0.37 Active 0.2 15S 1999 (9,440' - 10,026') (7,678' - 8,099') SU 41- April April Tyonek Tyonek 145 0.62 Sldueto 0 15L 1999 2001 (10,942' -11,331') (8,828' - 9,164') water To have economic production of gas and conservation of resources, disposal of up to 1,000 barrels of produced water per day is necessary. Permit Application · The following summarizes the contents of the SU 43-9 well permit application as they apply to the application requirements found in 20 AAC 25.252 (c) (AOGCC, 1999). Complete language for 20 AAC 25.252 is included in Appendix A of this document. (1) Location plat. Figure 2 is a plat showing the boundaries of the Marathon Sterling Gas Field Unit, the location of the SU 43-9 well (which will be converted to a Class II disposal well) and the three other gas wells in the Marathon Sterling Gas Field Unit. There is also a Marathon water well (1WUP A98-25) that is 268 feet deep located approximately 111 feet north of the SU 43-9 well location. Figure 3 shows the surface locations of wells (Le., disposal and storage wells, abandoned or other unused wells, production wells, dry holes, or any other wells) within one-quarter mile of the SU 43-9 well. These wells include the Sterling 32-9 production well, Sterling 41-15 production well, and the Marathon water well. A comprehensive list of freshwater wells in the area is listed in Appendix B. (2) List of operators and surface owners. · Marathon Oil Company is the sole operator of the Marathon Sterling Gas Field Unit that encompasses the one-quarter mile radius around the SU 43-9 well. The sole surface owner within a one-quarter mile radius of the SU 43-9 well is the Salamatof Native Association, Inc. 0:\Sterling\43-9\UIC\2002 Applications\Disposal Injection\Sterling 010 Application.doc 11/21/2002 Application for a Dispos.ection Order - Marathon Oil Company e Page 3 of 5 . (3) Notification of operators and suñace owners. The attached affidavit (Attachment 1) certifies that the Salamatof Native Association, Inc., the sole surface owners within a one-quarter mile radius, have been provided a copy of this application for the disposal of Class II oil field wastes in the SU 43-9 well. (4) Geologic Data. The formation for which a disposal injection order has been requested is characterized by alternating fluvial sandstones and shales of the Tertiary age in the Sterling formation, with occasional coals that vary in thickness from a few feet to ten feet. Sand quality is excellent, with porosity typically ranging from 25 to 35 percent (25-35%). Permeability determined from a recent production test in the nearby Sterling Unit 32-9 well is in excess of 200 millidarcies. These test values compare favorably with estimates of permeability from wireline nuclear magnetic resonance logs obtained in the same well. This device was run only over the primary zones of interest. However, the similarity in permeability and porosity values make extrapolation of similar values to the shallower sands in the disposal interval a reasonable undertaking. See Application for an Aquifer Exemption Order, Sterling Gas Field Unit, Kenai Peninsula, Alaska, October 2002 (MOC, 2002). . The proposed injection interval is the 8-4 Sand of the Sterling Formation. This interval is a gas producing formation between 5,020 feet SSTVD and 5,120 feet SSTVD in the vicinity of the SU 43-9 well. The SU 32-9 well is a producer from the same 8-4 sand but will not be adversely impacted by the disposal of Class II wastes during its anticipated remaining life. Injection modeling into the 8-4 Sand through the SU 43-9 well demonstrate that the disposal of oil field wastes into this formation is expected to have an inconsequential effect on the gas production rate and reserve recovery for the SU 32-9 well (Attachment 2). (5) Logs. The logs of the SU 43-9 well are on file at the AOGCC. (6) Demonstrating mechanical integrity of casing and tubing. The SU 43-9 well met the mechanical integrity requirements of 20 AAC 25.412 during a test conducted on October 23, 2002, which was witnessed by the AOGCC. A copy of the report from that test is attached (see Attachment 3). The method proposed for testing the mechanical integrity of the casing and tubing after receiving the disposal injection order is provided in Attachment 3 as well. Notice will be made in advance of that mechanical integrity test to allow a representative of the Commission to witness the test prior to converting the well for the purpose of injection. . An injectivity test was conducted for the Sterling 8-4 interval on February 25, 2000, using an electric-line log to verify zonal isolation. The method used to demonstrate that fluids would not move behind the casing beyond the approved disposal zone is provided in Attachment 4. The test results shown in Attachment 5 confirmed that injected fluids are confined to the sands in that interval even though the injectivity test was performed at an equivalent rate exceeding 4,000 barrels per day (3.2 8PM). D:\Sterling\43-9\UIC\2002 Applications\Disposallnjection\Sterling DID Application.doc 11/21/2002 Application for a DisposAlaection Order - Marathon Oil Company e Page 4 of 5 · The description of the construction of the SU 43-9 well, including the cement program used during its installation, is shown in Attachment 6. In accordance with 20 AAC 25.412(b), the 2% inch tubing using in well SU 43-9 is rated to a burst pressure of 7,700 psi, which is better than 2.5 times the maximum injection pressure of 3000 psi. The packer is located at 5,241 feet MD, which is 21 feet above the top perforation of the disposal interval. (7) Description of oil field wastes to be injected. This Class II well will be primarily used for the injection of formation fluids (produced water, natural gas condensates, etc.) from the other gas production wells. Marathon requests permission to dispose of approved Class II fluids from other Marathon operated fields as well. These fluids are completely compatible with fluids in this formation. Typical Class II wastes requested for injection include: drilling, completion, work over, and production fluids, glycol dehydration wastes, rig wash, drilling mud slurries, tank bottoms, NORM scale, precipitation within containment areas, and other approved Class II wastes. The above listed Class II wastes would be generated from drilling, completion, workover, and production operations. Current projections estimate that a maximum of 1,000 barrels per day of fluids will be injected. (8) Estimated pressure. · The estimated average injection pressure will be 1,BOO psig and maximum injection pressure will be 3,000 psig. (9) Evaluation of confining zones. BJ Services was contracted to model the hydraulic fracture potential of the planned injection operation in the Sterling B-4 Sand. Their simulation predicts that at rates up to 1,440 barrels per day the injection fluid is almost immediately lost to leakoff in the formation, causing no sustained fracture growth. The simulation was run at injection rates exceeding Marathon's 1,000 barrels per day limit, yet the confining zones were adequate to prevent vertical fracture growth. This simulation clearly demonstrates that fractures will not initiate or propagate through the confining zones that might enable the oil field wastes or stored hydrocarbons to enter freshwater strata (see Attachment 7). (10) Standard Laboratory water analysis. A laboratory water analysis of formation waters from the Sterling B-4 Sand obtained from the SU 43-9 well in 1995 yielded 1,931 mg/l TDS, and 1,615 mg/l NaCI equivalent (see Attachment B). · O:\Sterling\43-9\UIC\2002 Applications\Disposallnjection\Sterling DIO Application.doc 11/21/2002 Application for a Dispos.ection Order - Marathon Oil Company e Page 5 of 5 · (11) Freshwater exemption. The freshwater aquifer exemption application prepared, in accordance with 20 AAC 25.440, was submitted to the AOGCC on October 17, 2002. (12) Well report for disposal zone. No wells penetrate the Sterling B-4 Sand within a one-quarter mile radius of the SU 43-9 well. The two Marathon natural gas production wells, SU 32-9 and SU 41-15, shown on the surface maps (See Figures 2 and 3) were directionally drilled. Because wells SU 32-9 and SU 41-15 were directionally drilled, they both penetrate the Sterling B-4 Sand more than one-quarter mile away even though they are both within 150 feet of the surface location of well SU 43-9. Well SU 32-9 penetrates the B-4 Sand at 0.32 miles west of SU 43-9. Well SU 41-15 penetrates the B-4 Sand at 0.33 miles southeast of well SU 43-9. The surface casing strings for wells SU 32-9 and SU 41-15 are both adequately cemented with full cement returns to the surface. Well SU 32-9 has 9% inch casing to 2,111 feet MD (1,836' SSTVD) and was cemented with 620 sacks of cement. Well SU 41-15 has 13% inch casing to 2,271 feet MD (2,034' SSTVD) and was cemented with 1,186 sacks of cement. Both of these wells were constructed in 1999, and the mechanical condition of both wells is excellent. Wellbore schematics for these wells are provided in Attachment 9 and Attachment 10. · Conclusion Marathon trusts that this application meets the requirements for a Disposal Injection Order as outlined in 20 AAC 25.252. · O:\Sterling\43-9\UIC\2002 Applications\Disposallnjection\Sterling DID Application.doc 11/21/2002 Figures Application for a DisposaHnjectionOrder - Marathon Oil Company Figure 1 Figure 1. Cook Inlet regional map (ADNR, 1999). Application for a Disposal Inj Order - Marathon Oil Company Figure 2 i5H ~~ Figure 2. Sterling Gas Field Unit with gas wells and MOC's water well. Application for a Disposal Inj Order - Marathon Oil Company Figure 3 Figure 3. Topographic Map with wells. IIIIIIIIIIIIIII Attachment 1 · · · Application for a Disposal Inj.on Order - Marathon Oil Company e Attachment 1 Attachment 1 Affidavit of Fact AFFmA VIT OF FACT STATE OF ALASKA ) THIRD JUDICAL DISTRICT ) 55 KNOW ALL MEN BY THESE PRESENTS 1. Brock Riddle, first duly sworn, deposes and states as follows: I. Amant is the Land for Marathon OíJ Company's (Marathon) Alaska Business and in such capacity has knowledge of aHMarathon activities in the State of Alaska, including the Kenai Peninsula. 2. Affiant is well and personally acquainted with the Marathon Sterling Gas Unit located in T5N·R lOW, Seward Meridian, and more specifically, Sterling Unit Well #43-9 located .7' FSL and 521.5' FBL of Section 9-5N-IOW. 3. All of the surface ownership within a J!4-mile radius offhe aforementioned well is held by Salamatof Native Association, Inc., whose primary contact is Mr. Jim President. 4. Marathon is the only Operator of oj] and gas activities within the same l!4-mile radius. 5. Affiant further states that Salamatof Native Association, Inc. has been duly notified of Marathon's Application for Well the SterHng Unit Well #43-9. FURTI IER AFFIANT SA YETII NOT State of Alaska ) ss Third Judicial District ) The Marathon Oil Instrument was acknowledged before me by J. Brock Riddle, Alaska Business Unit Land on this 4th of February, 2002. Notury Public: f(i My Commission October 9. 2005 Attachment 2 Application for a Disposal I_ion Order - Marathon Oil Company e Attachment 2 Page 1 of 8 · Attachment 2 Sterling Water Disposal Model Summary L. C. Ibele 6/9/99 Updated 2/16/00 Purpose of Model The model was constructed by E&PT under a TSR from the Alaska Region for the purpose of evaluating water injection into the Sterling B-4 horizon in Well SU 43-9 to determine if any effect would occur on the B-4 gas production from new well, SU 32-9. The model work was completed in June, 1999. Model Summary Results of the model indicate that continuous water injection/disposal into the existing B-4 perforated interval of Well SU 43-9 at the maximum anticipated rate will have very inconsequential effect on gas production rate and reserve recovery from Well SU 32-9. · Model Set-up The model grid is an extra fine cartesian grid, using the Sterling B-4 structural map provided by D. L. Brimberry; constant porosity across the field. There are 16 permeability layers based on SU 32-09 CMR log interpretations by P. S. Gardner, with equivalent permeability calibrated by PBU results from Well 32-9. The fine gridding was specified to allow for sensitivity to water coning, and to permit future use of the model for horizontal well evaluation, if desired. Wells in the model include 23-15, 43-9, and 32-9. All historic production and pressure data were incorporated and a history match file was created. A VFP (vertical flow profile) table was created for the 32-9 completion using WAM. The WAM files were created using production test information and reservoir characteristics from Saphir analysis of the March pressure build-up test. Incorporating the VFP table into the model allowed use of tubing pressure values based on actual pipeline pressure to limit rates and recoveries. Therefore, the recoveries predicted by the model are based upon current conditions only; recoveries may be improved thru use of compression in the future. · Prediction Cases . Base cases were run using IP rates of 3 and 5 mmcfd from SU 32-9 (See Tables 1, 2 and 3) to determine the ultimate recoveries without water injection into the offset wellbore (SU 43-9). Production rates were varied to determine if gas recovery and potential water coning are rate dependent. . For the 5 mmcfd base case, the model was run with a water injection rate of 500 BPD. This figure was based on initial tests for 41-15L (Tyonek completion) which produced at water rates approaching 100 BPD, and model forecast results for the O:\Sterling\43-9\UIC\2002 Applications\Disposallnjection\Attachment 2.doc 11/21/2002 · · · Application for a Disposal Inj.on Order - Marathon Oil Company e Attachment 2 Page 2 of 8 32-09 Sterling B-4 completion which predicts future water rates approaching 300 BPD. The remainder allows for any water production from the 41-15s (Beluga) completion, should all three wells be produced simultaneously. Thus, the 500 BWIPD most likely represents the worst case water injection scenario. · In the model, Well 32-09 was produced with a 700 psi drawdown limitation, a 250 psi flowing tubing pressure limitation (note: compression will be required to produce at FTPs less than 700 psig), and a 100 psig flowing bottom hole pressure limitation. Run results indicate that the drawdown limit and the FTP limit do have an effect on production rates. Model Results · Attached are tables of output data from the two comparative model runs. Table 1 is the base case at an initial rate of 5000 MCFD from SU 32-9 with zero water injection into SU 43-9. Table 2 is the same case, only water injection into SU 43-9 is maintained at a constant rate of 500 BPD throughout the run. · Cumulative gas recovery for the period 6/1/99 through 1/1/2016 is 12.797 BCF for the base case (no water injection) vs. 12.384 BCF for the case with injection. The difference in recovery is 0.413 BCF or 3.2%. · The difference in cumulative recovery for this "worst case" injection scenario (500 BWPD throughout the model life ) is considered negligible. · Attached are two graphs showing Cumulative Gas Production vs. Time (See Graph 1) and Daily Gas Production Rate versus Time (See Graph 2) for the two comparative cases. · "RESVIEW" software was used to visually analyze the movement of water in the reservoir. Results indicate that the water injected into the existing perforations of SU 43-9 falls rapidly through the reservoir (due to gravity) and causes the overall gas-water contact to rise uniformly, rather than creating a piston-like waterflood displacement moving toward producer SU 32-9. (See Figures 1 and 2). O:\Sterling\43-9\U I C\2002 Applications\Disposal I njection\Attachment 2.doc 11/21/2002 ) ) ) ') Application for a Disposal Injection Order - Marathon Oil Company Table 1 œ Attachment 2 Sterling Unit Model Results Page 3 of 8 ) Sterling Unit Model"sgffor2" Results, 5000 MCFD initial gas production rate (SU 32-9) with zero water injection (SU 43-9). -....-----------.. -----..------- --------..---- ----..---...-......- --------------- ....---------- --------- -........---...------ ------------- ------------- ----------.....--- ------------ --------- -----j------- -------...------- ------------- ------------- SUMMAR'I RUN sgffor2 RUN sgffor2 RUN sgffor2 --------------- ------------- ------------- -----------...- --------------- ------------ -........---...------ ------------- --------------- ------------ -...........-..--....--- ------------- ------------- DATE YEARS DAY MONTH YEAR FWSA T FWIP FGIP FWPR FGPR FPR FWCT FGPT FIN PT FPPG WGPR WWPR WGPT WWPT WWIR WBHP WBHP WTHP WBP9 WBP9 WBP WBP YEARS STB MSCF STBIDA Y MSCF/DA~ PSIA MSCF STB PSIA MSCFIDA~ STB/DAY MSCF STB STB/DA Y PSIA PSIA PSIA PSIA PSIA PSIA PSIA "10""3 "10""3 "10""3 "10""3 43-09 32-09 43-09 32-09 32-09 43-09 32-09 43-09' 32-09 32-09 32-09 32-09 ----..------- --------- ------------- ----..---------- ------------- ------..---...-- ------------- ...--........--...---.. ------...-....-..--- --...---..----- ----...---- ...--....---...---- ..........---..------ ------...-......--- ----..---------... ----------..- -....--.....--...--- ........----------..- ------------- -------.....---- --...---------- -------...----- 1-Jun-99 37.013 1 6 1999 0.863356 116342.5 15402.19 30.42762 5000 2039.971 1 2700.585 8351.95 2040.485 5000 30.42762 155 145.7989 0 1598.696 2035.847 1391.921 1998.572 2035.848 1983.551 0 1-Jul-99 37.09514 1 7 1999 0.863699 116340 15254.52 128.5119 4537.833 2026.887 1 2848.499 1 0844.64 2027.399 4537.833 128.5119 302.9135 2638.489 0 1242.882 2022.119 1054.978 1971.963 2022.119 1945.118 0 1-Aug-99 37.18002 1 8 1999 0.86399 116335 15134.02 178.2521 3562.227 2016.294 1 2969.044 15904.99 2016.804 3562.227 178.2521 423.4585 7698.837 0 1220.325 2012.018 1022.388 1957.523 2012.018 1922.711 0 1-Sep-99 37.26489 1 9 1999 0.864227 116329.3 15031.3 187.02 3201.098 2007.092 1 3071.952 21604.02 2007.6 3201.098 187.02 526.3665 13397.87 0 1209.063 2003.205 1008.642 1948.166 2003.205 1911.59 0 1-0ct-99 37.34702 1 10 1999 0.864436 116323.6 14937.32 191.9515 3080.855 1998.573 1 3165.742 27303.31 1999.079 3080.855 191.9515 620.1567 19097.16 0 1200.214 1994.847 998.9012 1939.734 1994.847 1902.784 0 1-Nov-99 37.4319 1 11 1999 0.864641 116317.5 14842.9 195.6548 3009.924 1989.985 1 3259.87 33321.93 1990.49 3009.924 195.6548 714.2847 25115.78 0 1191.615 1986.328 989.9657 1931.251 1986.328 1894.197 0 1- Dec-99 37.51403 1 12 1999 0.864834 116311.5 14753.3 198.7133 2959.199 1981.81 1 3349.254 39246.75 1982.312 2959.199 198.7133 803.6693 31040.59 0 1183.03 19i'8.175 981.2 1922.893 1978.176 1885.622 0 1-Jan-00 37.5989 1 1 2000 0.865029 116305.2 14662.24 201.2757 2914.55 1973.462 1 3440.174 45453.65 1973.963 2914.55 201 .2757 894.5891 37247.5 0 1174.471 1969.843 972.632 1914.468 1969.844 1877.067 0 1-Feb-00 37.68378 1 2 2000 0.865221 116298.9 14572.42 203.8267 2878.101 1965.197 1 3529.863 51739.5 1965.696 2878.101 203.8267 984.2774 43533.35 0 1165.8 19€i1.587 964.0739 1906.004 1961.587 1868.403 0 1-Mar-00 37.76318 1 3 2000 0.865397 116292.8 14489.44 206.1762 2845.21 1957.528 1 3612.766 57690.39 1958.025 2845.21 206.1762 1067.181 49484.25 0 1157.689 1953.921 956.0911 1898.107 1953.921 1860.3 0 1-Apr-00 37.84805 1 4 2000 0.865584 116286.3 14401 .75 208.6208 2811.427 1949.398 1 3700.357 64125.82 1949.893 2811.427 208.6208 1154.772 55919.67 0 1149.22 1945.794 947.765 1889.81 1945.794 1851.837 0 1-May-00 37.93018 1 5 2000 0.865763 116280 14317.82 210.8625 2780.298 1941.592 1 3784.148 70424.01 1942.085 2780.298 210.8625 1238.562 62217.86 0 1140.965 1937.99 939.7155 1881.771 1937.99 1843.589 0 1-Jun-00 38.01506 1 6 2000 0.865945 116273.4 14232.06 213.0347 2749.581 1933.587 1 3869.787 76999.88 1934.079 2749.581 213.0347 1324.202 68793.73 0 1132.644 1929.987 931.6377 1873.609 1929.987 1835.273 0 1-Jul-00 38.09719 1 7 2000 0.866119 116267 14150 215.104 2718.775 1925.899 1 3951 .733 83427.53 1926.389 2718.775 215.104 1406.148 75221.38 0 1124.486 1922.3 923.7245 1865.68 1922.3 1827.124 0 1-Aug-00 38.18207 1 8 2000 0.866297 116260.2 14066.14 217.1369 2688.668 1918.019 1 4035.47 90132.45 1918.507 2688.668 217.1369 1489.885 81926.29 0 1116.314 1914.421 915.8206 1857.657 1914.421 1818.956 0 1-Sep-00 38.26694 1 9 2000 0.866473 116253.4 13983.21 219.0235 2660.729 1910.196 1 4118.308 96898.05 1910.683 2660.729 219.0235 1572.722 88691.9 0 1108.173 1906.599 908.0225 1849.674 1906.6 1810.822 0 1-0ct-00 38.34908 1 10 2000 0.866641 116246.8 13903.74 220.7111 2635.447 1902.674 1 4197.683 103498.7 1903.159 2635.447 220.7111 1652.098 95292.52 0 1100.324 1899.076 900.5733 1841.982 1899.077 1802.98 0 1-Nov-00 38.43395 1 11 2000 0.866813 116239.9 13822.45 222.4055 2609.713 1894.943 1 4278.923 '110371 1895.426 2609.713 222.4055 1733.338 102164.8 0 1 092.407 1891.345 893.0168 1834.156 1891.345 1795.066 0 1-Dec-00 38.51609 1 12 2000 0.866978 116233.1 13744.51 223.9015 2584.033 1887.506 1 4356.761 117069.8 1887.988 2584.033 223.9015 1811.176 108863.6 0 1084.716 1883.902 885.7104 1826.59 1883.903 1787.381 0 ) 1-Jan-01 38.60096 1 1 2001 0.867146 116226.1 13664.83 225.3615 2558.668 1879.873 1 4436.409 124036.9 1880.353 2558.668 225.3615 1890.824 115830.8 0 1077 1876.26 878.4001 1818.922 1876.261 1779.669 0 1-Feb-01 38.68583 1 2 2001 0.867312 116219 13585.89 226.7069 2534.527 1872.291 1 4515.288 131047.7 1872.769 2534.527 226.7069 1969.702 122841.6 0 1069.286 1868.676 871.1516 1811.275 1868.676 1771.959 0 1-Mar-01 38.76249 1 3 2001 0.867462 116212.6 13515.22 227.8276 2513.684 1865.482 1 4585.909 137414.1 1865.958 2513.684 227.8276 2040.324 129208 0 1062.332 1861.862 864.665 1804.393 1861.863 1765.01 0 1-Apr-01 38.84737 1 4 2001 0.867625 116205.4 13437.66 228.9545 2492.281 1857.986 1 4663.445 144497.1 1858.461 2492.281 228.9545 2117.86 136291 0 1054.751 1854.364 857.6494 1796.856 1854.364 1757.433 0 1-May-01 38.9295 1 5 2001 0.867782 116198.4 13363.22 230.0155 2472.013 1850.771 1 4737.854 151384.5 1851.243 2472.013 230.0155 2192.269 143178.3 0 1047.375 1847.145 850.8491 1789.556 1847.146 1750.062 0 1-Jun-01 39.01437 1 6 2001 0.867943 116191.2 13286.88 231.0236 2452.545 1843.353 1 4814.137 158533 1843.824 2452.545 231 .0236 2268.551 150326.9 0 1039.906 1839.722 844.0054 1782.114 1839.723 1742.596 0 1-Jul-01 39.09651 1 7 2001 0.868098 116184.3 13213.58 231.9286 2433.836 1836.21 1 4887.383 165479.8 1836.679 2433.836 231.9286 2341.798 157273.7 0 1032.614 1832.577 837.3594 1774.892 1832.579 1735.308 0 1-Aug-01 39.18138 1 8 2001 0.868257 116177 13138.4 232.7944 2415.155 1828.866 1 4962.496 172685.2 1829.333 2415.155 232.7944 2416.91 164479.1 0 1025.223 1825.229 830.6457 1767.529 1825.231 1727.92 0 1-Sep-01 39.26625 1 9 2001 0.868414 116169.8 13063.82 233.5876 2396.768 1821.557 1 5037.03 179916.3 1822.023 2396.768 233.5876 2491.445 171710.2 0 1017.824 1817.917 823.9593 1760.178 1817.919 1720.526 0 1-0ct-01 39.34839 1 10 2001 0.868565 116162.7 12992.18 234.2912 2379.523 1814.516 1 5108.628 186936.4 1814.981 2379.523 234.2912 2563.043 178730.2 0 1010.649 1810.872 817.5115 1753.069 1810.875 1713.356 0 1-Nov-01 39.43327 1 11 2001 0.86872 116155.4 12918.66 234.9718 2362.642 1807.274 1 5182.089 194211.7 1807.737 2362.642 234.9718 2636.504 186005.5 0 1003.371 1803.624 810.9949 1745.813 1803.627 1706.081 0 1-Dec-01 39.5154 1 12 2001 0.868869 116148.3 12848 235.6262 2346.545 1800.311 1 5252.685 201272.3 1800.772 2346.545 235.6262 2707.099 193066.2 0 996.2784 1796.662 804.6549 1738.783 1796.665 1698.993 0 1-Jan-02 39.60027 1 1 2002 0.86902 116140.8 12775.55 236.2767 2330.698 1793.179 1 5325.143 208588.4 1793.638 2330.698 236.2767 2779.557 200382.3 0 989.0941 1789.529 798.2269 1731.627 1789.532 1691.811 0 1-J un-02 40.01369 1 6 2002 0.869743 116104.8 12429.18 239.0819 2258.49 1758.938 1 5671.304 244495.7 1759.389 2258.49 239.0819 3125.718 236289.5 0 954.4059 1755.247 767.2899 1697.136 1755.25 1657.141 0 1-Sep-02 40.26557 1 9 2002 0.870173 116082.6 12223.25 240.5921 2218.203 1738.377 1 5877.116 266565 1738.823 2218.203 240.5921 3331.53 258358.9 0 933.5743 1734.667 748.8804 1676.425 1734.67 1636.318 0 1-Jan-03 40.59959 1 1 2003 0.870734 116053 11955.71 242.4321 2168.657 1711.432 1 6144.526 296037.4 1711.871 2168.657 242.4321 3598.941 287831.2 0 906.2981 1707.698 724.9457 1649.29 1707.701 1609.053 0 1-Jun-03 41.013 1 6 2003 0.871416 116016 11632.57 244.1581 2113.01 1678.38 1 6467.609 332787.8 1678.811 2113.01 244.1581 3922.024 324581.7 0 872.9665 1674.616 696.0583 1616.072 1674.619 1575.73 0 1-Sep-03 41.26489 1 9 2003 0.871826 115993.5 11439.71 245.0396 2079.488 1658.426 1 6660.363 355293.8 1658.852 2079.488 245.0396 4114.778 347087.7 0 852.8651 1654.649 678.738 1596.033 1654.651 1555.634 0 1-Jan-04 41.5989 1 1 2004 0.872362 115963.4 11188.57 246.0818 2037.659 1632.23 1 6911.376 385256.9 1632.65 2037.659 246.0818 4365.792 377050.8 0 826.5131 1628.431 656.1696 1569.743 1628.434 1529.289 0 1-Jun-04 42.01506 1 6 2004 0.873017 115925.8 10882.72 247.3355 1985.375 1600.008 1 7217.061 422758.9 1600.419 1985.375 247.3355 4671 .476 414552.7 0 794.0775 1596.185 628.4177 1537.396 1596.187 1496.864 0 1-Sep-04 42.26694 1 9 2004 0.873404 115902.9 10701 .53 248.0887 1953.075 1580.8 1 7398.142 445550.9 1581.207 1953.075 248.0887 4852.557 437344.7 0 774.718 1576.962 611.7812 1518.098 1576.963 1477.511 0 1-Jan-05 42.60096 1 1 2005 0.873909 115872.5 10465.82 249.1285 1910.635 1555.623 1 7633.719 475884.1 1556.023 1910.635 249.1285 5088.134 467677.9 0 749.3281 1551.763 589.9971 1492.795 1551.764 1452.13 0 1-Jun-05 43.01437 1 6 2005 0.874518 115834.7 10181.27 250.4325 1858.469 1524.919 1 7918.114 513603.8 1525.311 1858.469 250.4325 5372.528 505397.7 0 718.3518 1521.034 563.4824 1461.933 1521.035 1421.165 0 1-Jan-06 43.60027 1 1 2006 0.875358 115780.7 9790.943 252.8946 1789.634 1482.142 1 8308.233 567467 1482.524 1789.634 252.8946 5762.648 559260.8 0 674.9271 1478.216 526.4205 1418.778 1478.216 1377.759 0 1-Jun-06 44.01369 1 6 2006 0.875935 115742.3 9524.217 254.6471 1742.912 1452.431 1 8574.813 605789 1452.805 1742.912 254.6471 6029.228 597582.8 0 644.8243 1448.479 500.867 1388.835 1448.479 1347.667 0 1-Jan-07 44.59959 1 1 2007 0.876726 115687.3 9158.269 257.3535 1677.127 1411.121 1 8940.573 660576.1 1411.484 1677.127 257.3535 6394.988 652369.9 0 602.8821 1407.135 465.368 1347.156 1407.135 1305.744 0 1-Jun-07 45.013 1 6 2007 0.877268 115648.1 8908.536 259.4177 1630.579 1382.458 1 9190.177 699597.1 1382.814 1630.579 259.4177 6644.592 691391 0 573.8026 1378.446 440.8255 1318.252 1378.445 1276.677 0 1-Jan-08 45.5989 1 1 2008 0.878011 115592.2 8566.42 262.3315 1566.718 1342.59 1 9532.063 755435.1 1342.935 1566.718 262.3315 6986.478 747228.9 0 533.3083 1338.547 406.8781 1278.026 1338.546 1236.202 0 1-Jun-08 46.01506 1 6 2008 0.878518 115552.1 8331.584 264.3611 1522.755 1314.866 1 9766.734 795470.6 1315.204 1522.755 264.3611 7221.149 787264.4 0 505.189 1310.801 383.4658 1250.08 1310.8 1208.096 0 1-Jan-09 46.60096 1 1 2009 0.879206 115495 8012.255 267.1291 1461.562 1276.593 1 10085.87 852352. 1 1276.92 1461.562 267.1291 7540.281 844145.9 0 466.3256 1272.501 351.1696 1211.483 1272.5 1169.252 0 1-Jun-09 47.01437 1 6 2009 0.879673 115454.5 7794.756 269.0433 1418.76 1250.155 1 10303.21 892834.9 1250.475 1418.76 269.0433 7757.629 884628.8 0 439.5774 1246.052 329.0005 1184.878 1246.05 1142.517 0 1-Jan-10 47.60027 1 1 2010 0.880305 115396.4 7497.455 271.9104 1358.899 1213.564 1 10600.29 950715.9 1213.875 1358.899 271 .9104 8054.706 942509.8 0 402.4983 1209.448 298.432 1148.023 1209.446 1105.462 0 1-Jan-11 48.59959 1 1 2011 0.881307 115295.9 7020.391 276.3552 1256.35 1153.368 1 11077.02 1050946 1153.663 1256.35 276.3552 8531.436 1042740 0 343.2187 1149.234 250 1087.585 1149.233 1044.802 0 1-Jan-12 49.5989 1 1 2012 0.882207 115198.5 6587.88 257.5602 1121.207 1097.493 1 11509.65 1148335 1097.773 1121.207 257.5602 8964.062 1140129 0 343.6995 1093.438 250 1035.758 1093.437 995.9712 0 1-Jan-13 50.60096 1 1 2013 0.883031 115107.5 6199.545 239.4938 1005.576 1045.899 1 11898.07 1239210 1046.164 1005.576 239.4938 9352.486 1231004 0 344.0261 1041.933 250 987.9817 1041.934 951.0002 0 1-Jan-14 51.60027 1 1 2014 0.883771 115023.1 5851.633 222.7026 904.8161 998.8827 1 12246.06 1323483 999.1353 904.8161 222.7026 9700.472 1315277 0 344.9604 995.0019 250 944.5115 995.001 910.1265 0 1-Jan-15 52.59959 1 1 2015 0.884447 114944.8 5538.387 207.0029 815.0916 955.6042 1 12559.35 1401838 955.8453 815.0916 207.0029 10013.77 1393632 0 346.3785 951 .8284 250 904.571 951.8271 872.6024 0 1-Jan-16 53.5989 1 1 2016 0.884993 114883.5 5300.206 0 0 922.5056 0 12797.55 1463052 922.738 0 0 10251.96 1454846 0 920.2756 920.7666 0 920.2487 920.7653 920.2306 0 ) ) ) ) Application for a Disposal Injection Order - Marathon Oil Company Table 2. Attachment 2 Sterling Unit Model Results Page 4 of 8 ) Sterling Unit Model II sgffo r5" Results, 5000 MCFD initial gas production rate (SU 32-9) with 500 BPD water injection (SU 43-9). .....----------- --------_...----- ..........--..------ .......------..--.. -...----------- --------------- ------------ -.._------ ------------- -...-.........-------- ------------.. -..------------- ---------.....- --------- ...oo--------...-"'-- _____________ ------------- SUMMAR'i RUN sgffor5 RUN sgffor5 RUN sgffor5 -..-----...----- ---------...----- ---..-----.........- ------------- ------------- -------..------- -----------... ....----..------ .....-....,.....------..- ...------..----- -------..-..----- -..---...............- --------------- ------------- --..-..-------- DATE YEARS DAY MONTH YEAR FWSA T FWIP FGIP FWPR FGPR FPR FWCT FGPT FWPT FPPG WGPR WWPR WGPT WWPT WWIR WBHP WBHP WTHP WBP9 WBP9 WBP WBP YEARS STB MSCF STB/DA Y MSCFIDA~ PSIA MSCF STB PSIA MSCF/DA~ STB/DAY MSCF STB STBIDA Y PSIA PSIA PSIA PSIA PSIA PSIA PSIA "10""3 "10""3 "10""3 43-09 32-09 43-09 32-09 32-09 43-09 32-09 43-09' 32-09 32-09 32-09 32-09 -.....--------- -------...... ------------- ---------...----- -----......------ ---..-------...- ------------- ...------------ -------..-..----- --.....--...---..... ---.......--... ---......------...- --.....----------- -------..----- -----...--------- ---------..-- --.....-..----...... ..-----------..-- --------..---- ------------- -------...----- ------....--..-... 1-Jun-99 37.013 1 6 1999 0.863443 116357.7 15402.5 28.86857 5000 2041.175 1 2700.585 8346.999 2041.69 5000 28.86857 155 140.848 500 1614.042 3549.465 1405.959 2000.063 2203.175 1985.031 0 1-Jul-99 37.09514 1 7 1999 0.863867 116370.2 15254.65 127.8479 4549.923 2029.162 1 2848.621 10822.66 2029.674 4549.923 127.8479 303.0355 2616.505 500 1245.578 3545.542 1057.468 1974.589 2197.937 1947.812 0 1-Aug-99 37.18002 1 8 1999 0.864242 116380.7 15133.92 177.8753 3574.166 2019.662 1 2969.475 15863.62 2020.172 3574.166 177.8753 423.8894 7657.474 500 1224.097 3541.674 1025.747 1961.233 2192.134 1926.48 0 1-Sep-99 37.26489 1 9 1999 0.864563 116390.5 15030.92 186.8979 3209.941 2011.541 1 3072.745 21557.08 2012.05 3209.941 186.8979 527.1596 13350.92 500 1213.871 3538.04 1012.79 1952.942 2186.736 1916.397 0 1-0et-99 37.34702 1 10 1999 0.864852 116399.5 14936.98 191.869 3087.08 2004.041 1 3166.732 27253.85 2004.548 3087.08 191.869 621 .1464 19047.7 500 1206.013 3534.233 1003.852 1945.517 2180.833 1908.583 0 1-Nov-99 37.4319 1 11 1999 0.865141 116408.7 14842.49 195.5517 3016.54 1996.5 1 3261.062 33269.41 1997.006 3016.54 195.5517 715.4767 25063.26 500 1198.482 3530.223 995.8447 1938.093 2174.533 1901.064 0 1- Dee-99 37.51403 1 12 1999 0.865414 116417.5 14752.87 198.6746 2966.221 1989.347 1 3350.659 39191 .66 1989.852 2966.221 198.6746 805.0739 30985.51 500 1191 .024 3526.331 988.0339 1930.816 2168.383 1893.613 0 1-Jan-00 37.5989 1 1 2000 0.865691 116426.5 14661.81 201 .42 2920.167 1982.063 1 3441.769 45400.32 1982.566 2920.167 201.42 896.184 37194.17 500 1183.374 3522.323 980.1429 1923.362 2162.04 1885.972 0 1-Feb-00 37.68378 1 2 2000 0.865967 116435.5 14571.96 204.1844 2882.604 1974.862 1 3531 .615 51694.15 1975.363 2882.604 204.1844 986.0298 43488 500 1175.712 3518.337 972.3393 1915.928 2155.704 1878.317 0 1-Mar-00 37.76318 1 3 2000 0.866221 116443.8 14488.98 206.7805 2848.509 1968.189 1 3614.626 57659.55 1968.688 2848.509 206.7805 1069.041 49453.4 500 1168.557 3514.594 965.0513 1909.002 2149.712 1871 .17 0 1-Apr-00 37.84805 1 4 2000 0.866492 116452.6 14401.31 209.5333 2812.93 1961 .123 1 3702.29 64119.03 1961.621 2812.93 209.5333 1156.705 55912.88 500 1161.092 3510.59 957.4281 1901.734 2143.267 1863.711 0 1-May-00 37.93018 1 5 2000 0.866751 116461.2 14317.48 212.2146 2778.441 1954.349 1 3786.069 70452.12 1954.847 2778.441 212.2146 1240.484 62245.97 500 1153.775 3506.757 949.9566 1894.675 2137.063 1856.404 0 1-Jun-00 38.01506 1 6 2000 0.867017 116469.9 14231.98 214.9892 2741.583 1947.421 1 3871.545 770.80.63 1947.916 2741.583 214.9892 1325.96 68874.48 500 1146.388 3502.844 942.3544 1887.518 2130.694 1849.024 0 1-Jul-00 38.09719 1 7 2000 0.867272 116478.3 14150.27 217.5864 2705.352 1940.786 1 3953.152 835.76.15 1941.28 2705.352 217.5864 1407.566 75370 500 1139.185 3499.114 934.9567 1880.592 2124.599 1841.832 0 1-Aug-00 38.18207 1 8 2000 0.867532 116486.9 14066.97 220.0645 2671.669 1934.003 1 4036.404 90366.21 1934.495 2671.669 220.0645 1490.819 82160.06 500 1132.059 3495.297 927.6973 1873.635 2118.336 1834.712 0 1-Sep-00 38.26694 1 9 2000 0.86779 116495.4 13984.69 222.4733 2639.075 1927.284 1 4118.636 97231.95 1927.775 2639.075 222.4733 1573.051 89025.8 500 1124.976 3491.511 920.5038 1866.723 2112.104 1827.637 0 1-0et-00 38.34908 1 10 2000 0.868037 116503.4 13906.11 224.5072 2609.097 1920.842 1 4197.274 103942.7 1921.332 2609.097 224.5072 1651.689 95736.55 500 1118.182 3487.874 913.7063 1860.096 2106.09 1820.852 0 1-Nov-00 38.43395 1 11 2000 0.868289 116511.5 13825.91 226.2915 2581.262 1914.242 1 4277.651 110é34.8 1914.731 2581.262 226.2915 1732.066 102728.7 500 1111 .439 3484.168 907.0651 1853.427 2099.93 1814.113 0 1-Dee-00 38.51609 1 12 2000 0.868533 116519.6 13748.88 227.8758 2556.089 1907.903 1 4354.643 117751.7 1908.39 2556.089 227.8758 1809.058 109545.5 500 1104.85 3480.606 900.6589 1846.953 2093.979 1807.532 0 ) 1-Jan-01 38.60096 1 1 2001 0.868783 116527.9 13670.03 229.3284 2532.419 1901.398 1 4433.452 124842.3 1901.883 2532.419 229.3284 1887.866 116636.2 500 1098.23 3476.953 894.2637 1840.389 2087.838 1800.916 0 1-Feb-01 38.68583 1 2 2001 0.869033 116536.2 13591.91 230.6156 2510.121 1894.928 1 4511 .549 13'1974.6 1895.412 2510.121 230.6156 1965.964 123768.5 500 1091.613 3473.087 887.9462 1833.838 2081.723 1794.304 0 1-Mar-01 38.76249 1 3 2001 0.869257 116543.6 13521.96 231.7375 2490.221 1889.115 1 4581.504 138450.4 1889.598 2490.221 231.7375 2035.919 130244.2 500 1085.639 3468.876 882.2596 1827.936 2076.207 1788.335 0 1-Apr-01 38.84737 1 4 2001 0.869503 116551.8 13445.16 232.8728 2468.789 1882.718 1 4658.313 14S654.9 1883.199 2468.789 232.8728 2112.728 137448.7 500 1079.127 3462.683 876.0946 1821.479 2069.996 1781.827 0 1-May-01 38.9295 1 5 2001 0.869741 116559.7 13371.41 233.8603 2448.872 1876.562 1 4732.022 152658.5 1877.042 2448.872 233.8603 2186.437 144452.4 500 1072.801 3456.714 870.162 1815.23 2064.01 1775.507 0 1-Jun-01 39.01437 1 6 2001 0.869985 116567.9 13295.84 234.8348 2429.443 1870.237 1 4807.587 159925.7 1870.715 2429.443 234.8348 2262.002 151719.5 500 1066.404 3450.571 864.1855 1808.869 2057.849 1769.114 0 1-Jul-01 39.09651 1 7 2001 0.87022 116575.7 13223.3 235.7153 2410.991 1864.148 1 4880.143 16G986.4 1864.625 2410.991 235.7153 2334.558 158780.3 500 1060.151 3444.655 858.3796 1802.691 2051 .916 1762.866 0 1-Aug-01 39.18138 1 8 2001 0.870462 116583.8 13148.87 236.5424 2393.481 1857.888 1 4954.566 174308.6 1858.364 2393.481 236.5424 2408.982 166102.5 500 1053.837 3438.571 852.5617 1796.402 2045.813 1756.556 0 1-Sep-01 39.26625 1 9 2001 0.870703 116591.8 13074.98 237.3313 2376.528 1851.657 1 5028.458 181655.6 1852.131 2376.528 237.3313 2482.873 173449.5 500 1047.496 3432.506 846.7479 1790.109 2039.731 1750.219 0 1-0et-01 39.34839 1 10 2001 0.870936 116599.6 13003.97 238.1122 2360.212 1845.653 1 5099.467 188789.3 1846.127 2360.212 238.1122 2553.882 180583.1 500 1041.339 3426.658 841.0948 1784.019 2033.866 1744.067 0 1-Nov-01 39.43327 1 11 2001 0.871175 116607.5 12931.15 238.8871 2344.044 1839.478 1 5172.343 19£>184.8 1839.949 2344.044 238.8871 2626.758 187978.6 500 1035.113 3420.634 835.3882 1777.814 2027.824 1737.843 0 1-Dee-01 39.5154 1 12 2001 0.871405 116615.3 12861.08 239.6015 2328.239 1833.526 1 5242.387 203364.1 1833.997 2328.239 239.6015 2696.802 195157.9 500 1029.022 3414.827 829.8234 1771.785 2022.001 1731.757 0 1-Jan-02 39.60027 1 1 2002 0.871643 116623.3 12789.18 240.3033 2312.513 1827.403 1 5314.28 210804.3 1827.872 2312.513 240.3033 2768.695 202598.2 500 1022.853 3408.852 824.1996 1765.635 2016.009 1725.59 0 1-Jun-02 40.01369 1 6 2002 0.872786 116661.7 12446.06 243.9116 2235.41 1797.995 1 5657.396 247371.8 1798.457 2235.41 243.9116 3111.81 239165.7 500 992.8892 3380.14 796.8109 1735.921 1987.213 1695.645 0 1-Sep-02 40.26557 1 9 2002 0.873469 116684.9 12242.58 246.0392 2189.807 1780.525 1 5860.84 269916.8 1780.984 2189.807 246.0392 3315.255 261710.6 500 975.033 3363.041 780.4315 1718.236 1970.062 1677.802 0 1-Jan-03 40.59959 1 1 2003 0.874361 116715.4 11979.17 248.5876 2130.964 1757.736 1 6124.211 30Q097.7 1758.19 2130.964 248.5876 3578.626 291891.6 500 951.7834 3340.722 759.2203 1695.2 1947.677 1654.571 0 1-Jun-03 41.013 1 6 2003 0.875448 116752.8 11662.87 251 .9619 2060.835 1730.079 1 6440.481 33i'883.7 1730.526 2060.835 251.9619 3894.896 329677.6 500 923.502 3313.605 733.4183 1667.203 1920.478 1626.313 0 1-Sep-03 41 .26489 1 9 2003 0.876101 116775.3 11475.27 254.4648 2019.27 1713.522 1 6628.018 361188.6 1713.964 2019.27 254.4648 4082.433 352982.4 500 906.329 329"1.352 717.665 1650.316 1904.175 1609.157 0 1-Jan-04 41.5989 1 1 2004 0.876955 116804.7 11232.22 257.4684 1968.818 1691.82 1 6871 .128 392428.2 1692.258 1968.818 257.4684 4325.544 384222.1 500 883.9328 3276.031 697.223 1628.231 1882.789 1586.779 0 1-Jun-04 42.01506 1 6 2004 0.878009 116841 10937.65 261.1705 1908.85 1665.128 1 7165.625 431857.1 1665.56 1908.85 261 .1705 4620.04 423650.9 500 856.463 3249.783 672.1658 1601.11 1856.464 1559.331 0 1-Sep-04 42.26694 1 9 2004 0.878639 116862.7 10763.66 263.29 1874.635 1649.209 1 7339.577 455989.9 1649.637 1874.635 263.29 4793.992 447783.8 500 840.1218 3234.113 657.3612 1584.953 1840.748 1543.002 0 1-Jan-05 42.60096 1 1 2005 0.879463 116891.1 10537.83 265.8433 1829.801 1628.368 1 7565.408 488275.6 1628.791 1829.801 265.8433 5019.823 480069.5 500 818.8146 3213.599 638.1498 1563.853 1820.177 1521.71 0 1-Jun-05 43.01437 1 6 2005 0.880469 116925.8 10265.83 269.0954 1774.635 1603 1 7837.436 528668.6 1603.416 1774.635 269.0954 5291.85 520462.5 500 792.8163 3188.618 614.7062 1538.134 1795.125 1495.731 0 1-Jan-06 43.60027 1 1 2006 0.881862 116974.3 9894.634 273.9268 1695.982 1568.015 1 8208.508 586790.1 1568.423 1695.982 273.9268 5662.923 578583.9 500 756.8867 3154.149 582.2297 1502.627 1760.557 1459.833 0 1-Jun-06 44.01369 1 6 2006 0.882824 117007.9 9642.684 277.3583 1642.195 1543.946 1 8460.396 628418.7 1544.348 1642.195 277.3583 5914.811 620212.5 500 732.2171 3130.419 559.9775 1478.233 1736.762 1435.186 0 1-Jan-07 44.59959 1 1 2007 0.884156 117054.5 9299.285 282.5147 1568.224 1510.687 1 8803.723 688324.9 1511.08 1568.224 282.5147 6258.138 680118.7 500 698.0239 3097.599 529.1519 1444.456 1703.859 1401.027 0 1-Jun-07 45.013 1 6 2007 0.885075 117086.7 9066.696 286.3273 1514.355 1487.789 1 9036.304 731284.9 1488.177 1514.355 286.3273 6490.719 723078.8 500 674.5637 3074.965 507.8836 1421.244 1681 . 169 1377.589 0 1-Jan-08 45.5989 1 1 2008 0.886346 117131.4 8750.756 290.7789 1441.214 1456.208 1 9352.2 793067.9 1456.587 1441.214 290.7789 6806.615 784861.7 500 642.3145 3043.754 478.7792 1389.3 1649.88 1345.37 0 1-Jun-08 46.01506 1 6 2008 0.887229 117162.8 8535.36 293.5687 1393.24 1434.411 1 9567.486 837.484.8 1434.784 1393.24 293.5687 7021.901 829278.6 500 620.1005 3022.207 458.9421 1367.282 1628.28 1323.175 0 1-Jan-09 46.60096 1 1 2009 0.888441 117206.2 8244.262 297.3506 1328.893 1404.578 1 9858.469 900728.1 1404.944 1328.893 297.3506 7312.884 892521.9 500 589.5927 2992.704 431.8842 1337.1 03 1598.704 1292.698 0 1-Jun-09 47.01437 1 6 2009 0.889281 117236.4 8046.761 300.0282 1287.249 1384.006 1 10055.87 945830.8 1384.366 1287.249 300.0282 7510.287 937624.6 500 568.5894 2972.339 413.4434 1316.298 1578.289 1271.713 0 1-Jan-10 47.60027 1 1 2010 0.890444 117278.5 7777.608 303.5251 1229.1 07 1355.581 1 10324.94 1010433 1355.933 1229.107 303.5251 7779.354 1002227 500 539.4996 2944.229 388.054 1287.525 1550. 1 09 1242.652 0 1-Jan-11 48.59959 1 1 2011 0.89236 117348.7 7345.475 308.3744 1140.926 1309.081 1 10756.95 1122138 1309.42 1140.926 308.3744 8211.364 1113932 500 492.1092 2898.226 346.4159 1240.555 1503.994 1195.302 0 1-Jan-12 49.5989 1 1 2012 0.894202 117417.3 6944.168 313.0781 1058.418 1264.766 1 11158.13 1235532 1265.094 1058.418 313.0781 8612.548 1227326 500 446.8956 2854.347 306.6486 1195.775 1460.007 1150.129 0 1-Jan-13 50.60096 1 1 2013 0.895971 117484.2 6571.253 318.8545 979.8524 1222.618 1 11530.88 1351156 1222.935 979.8524 318.8545 8985.293 1342950 500 403.6088 2812.602 268.1552 1153.025 1418.158 1106.886 0 1-Jan-14 51.60027 1 1 2014 0.897658 117549.9 6228.775 314.5734 892.353 1183.025 1 11873.35 1467636 1183.331 892.353 314.5734 9327.762 1459429 500 387.0027 2773.439 250 1114.776 1378.897 1069.592 0 1-Jan-15 52.59959 1 1 2015 0.899278 117619.9 5919.539 301.2658 805.9818 1146.855 1 12182.7 1579974 1147.151 805.9818 301.2658 9637.119 1571768 500 393.7446 2737.69 250 1081.56 1343.058 1038.521 0 1-Jan-16 53.5989 1 1 2016 0.90073 117725 5717.659 0 0 1126.517 0 12384.76 1657109 1126.807 0 0 9839.171 1648902 500 1124.654 2715.966 0 1124.595 1324.366 1124.581 0 ) ) ') ) Application for a Disposal Injection Order - Marathon Oil Company Table 3. Attachment 2 Sterling Unit Model Results Page 5 of 8 ) Sterling Unit Model "sgffor2" Results, 3000 MCFD initial gas production rate (SU 32-9) with zero water injection (SU 43-9). ------------- --------------. ------------- -----.................-- ----..,-------- ---------_.....- ----------...---. ----------..- --------- ------------- --..-----------. ------------.. ......-----......---- ------------- -----------...- --------------. ------------ ----.._--- ...------------ --------------. ---.......------- .........-----...--... ------------- SUMMAR) RUN sgffor2 RUN sgffor2 RUN sgffor2 ------...--...--- ----...---------. ------------- ------------- ------------- ------------- --------------. ------------ ----..---- ------------- --..-----------. ------------- ..------------ ---..------...-- ------------- --------------. ------------ ----..---- -------..-..--- -------------... ..---.....--...---.. .....-...-------.... -----------..- DATE YEARS DAY MONTH YEAR FWSAT FWIP FGIP FWPR FGPR FPR FWCT FGPT FWPT FPPG WGPR WWPR WGPT WWPT WWIR WBHP WBHP WTHP WBF)9 WBP9 WBP WBP YEARS STB MSCF STB/DAY MSCF/DA) PSIA MSCF STB PSIA MSCF/DA) STB/DAY MSCF STB STB/DAY PSIA PSIA PSIA PSIA PSIA PSIA PSIA * 1 0**3 *10**3 *10**3 *10**3 43-09 32-09 43-09 32-09 32-Ø9 43-09 32-09 43-09' 32-09 32-09 32-09 32-09 ------------ --------- ------------- -..------------. ------------- ------------- ------------- ----....------- ---..-----..----. ------------ --------- ------------- --------------. ------------- ------------ ---..--------- ------------- --------------. ------------ --------- ------------- ---------...----. --.....-...------- ..--..-------...- ------------- --....--------- 1-Jun-99 37.013 1 6 1999 0.863241 116342.7 15464.19 0 3000 2045.837 o 2638.585 8206.151 2046.353 3000 0 93 0 0 1975.82 2043.032 1740.806 2024.107 2043.033 2017.354 0 1-Jul-99 37.09514 1 7 1999 0.863456 116342.5 15374.22 16.49346 3000 2037.965 1 2728.585 8367.781 2038.479 3000 16.49346 183 161.6306 o 1783.202 2034.791 1564.411 2012.346 2034.791 2003.424 0 1-Aug-99 37.18002 1 8 1999 0.86368 116341.6 15281.23 37.33745 3000 2029.84 1 2821.585 9246.08 2030.353 3000 37.33745 276 1039.929 o 1672.507 2026.528 1458.553 2001.122 2026.528 1990.384 0 1-Sep-99 37.26489 1 9 1999 0.863902 116339.9 15188.25 68.59422 3000 2021.648 1 2914.585 10921.16 2022.159 3000 68.59422 369 2715.01 o 1557.151 2018.253 1345.658 1997.386 2018.253 1972.062 0 1-0ct-99 37.34702 1 10 1999 0.864112 116337.1 15098.26 108.1064 3000 2013.62 1 3004.585 13665.27 2014.129 3000 108.1064 459 5459.115 o 1450.036 2010.159 1238.402 1972.021 2010.159 1950.117 0 1-Nov-99 37.4319 1 11 1999 0.864322 116333.1 15005.34 142.2742 3000 2005.222 1 3097.585 17660.24 2005.73 3000 142.2742 552 9454.089 o 1363.405 2001.714 1152.276 1957.025 2001.714 1929.207 0 1-Dec-99 37.51403 1 12 1999 0.864521 116328.3 14915.36 168.1842 3000 1997.058 1 3187.585 22395.78 1997.564 3000 168.1842 642 14189.63 o 1276.072 1993.523 1069.606 1943.748 1993.523 1911.361 0 1-Jan-00 37.5989 1 1 2000 0.864722 116322.6 14822.4 187.5767 3000 1988.595 1 3280.585 27969.24 1989.099 3000 187.5767 735 19763.09 o 1213.694 1985.014 1010.948 1931.564 1985.015 1895.971 0 1-Feb-00 37.68378 1 2 2000 0.86492 116316.5 14729.62 198.7268 2964.259 1980.107 1 3373.303 34022.33 1980.609 2964.259 198.7268 827.718 25816.18 0 1181.34 1976.483 979.835 19:¿1.158 1976.484 1883.93 0 1-Mar-00 37.76318 1 3 2000 0.865102 116310.5 14644.55 201.9857 2905.925 1972.298 1 3458.192 39842.51 1972.799 2905.925 201.9857 912.6069 31636.36 o 1173.154 1968.683 971.19 1913.212 1968.684 1875.755 0 1-Apr-00 37.84805 1 4 2000 0.865293 116304.2 14555.08 204.986 2863.883 1964.059 1 3547.502 46158.74 1964.558 2863.883 204.986 1001.917 37952.59 o 1164.517 1960.455 962.442 19p4.791 1960.456 1867.124 0 1-May-00 37.93018 1 5 2000 0.865475 116297.9 14469.72 207.728 2826.91 1956.161 1 3632.765 52356.7 1956.658 2826.91 207.728 1087.181 44150.55 o 1156.105 1952.563 954.0228 1896.633 1952.563 1858.722 0 1-Jun-00 38.01506 1 6 2000 0.86566 116291.3. 14382.66 210.3051 2792.153 1948.075 1 3719.767 58843.12 1948.57 2792.153 210.3051 1174.182 50636.97 o 1147.681 1944.482 945.6735 1888.384 1944.482 1850.303 0 1-Jul-00 38.09719 1 7 2000 0.865837 116284.9 14299.32 212.5664 2760.879 1940.311 1 3802.979 65192.54 1940.805 2760.879 212.5664 1257.394 56986.38 o 1139.458 1936.721 937.6369 1880.383 1936.722 1842.087 0 1-Aug-00 38.18207 1 8 2000 0.866017 116278".3 14214.18 214.7462 2729.126 1932.352 1 3887.996 71821.48 1932.844 2729.126 214.7462 1342.411 63615.33 o 1131.162 1928.766 929.5552 1872.26 1928.766 1833.796 0 1-Sep-00 38.26694 1 9 2000 0.866195 116271.5 14130.07 216.8502 2697.696 1924.458 1 3972.028 78516.69 1924.948 2697.696 216.8502 1426.443 70310.53 o 1122.883 1920.874 921.5145 1864.174 1920.874 1825.525 0 1-0ct-00 38.34908 1 10 2000 0.866366 116264.9 14049.52 218.7537 2669.248 1916.877 1 4052.451 85056.09 1917.365 2669.248 218.7537 1506.866 76849.94 o 1114.907 1913.293 913.8347 1856.39 1913.294 1817.557 0 1-Nov-00 38.43395 1 11 2000 0.866539 116258 13967.2 220.522 2643.202 1909.098 1 4134.724 91869.45 1909.584 2643.202 220.522 1589.139 83663.29 o 1106.915 1905.514 906.2231 1848.506 1905.515 1809.569 0 1-Dec-00 38.51609 1 12 2000 0.866706 116251.3 13888.27 222.2104 2617.97 1901.614 1 4213.578 98514.48 1902.099 2617.97 222.2104 1667.992 90308.33 o 1099.113 1898.031 898.8022 1840.854 1898.032 1801.774 0 1-Jan-01 38.60096 1 1 2001 0.866876 116244.4 13807.53 223.7781 2591.897 1893.924 1 4294.265 105431.7 1894.407 2591.897 223.7781 1748.68 97225.52 o 1091.272 1890.337 891.3354 1833.092 1890.338 1793.936 0 1-Feb-01 38.68583 1 2 2001 0.867045 116237,4 13727.56 225.2406 2566.2 1886.282 1 4374.149 112395.1 1886.763 2566.2 225.2406 1828.564 104189 o 1083.475 1882.683 883.9462 1825.375 1882.684 1786.144 0 } 1-Mar-01 38.76249 1 3 2001 0.867196 116231 13656.01 226.4908 2543.836 1879.424 1 4445.631 118722.7 1879.904 2543.836 226.4908 1900.046 110516.5 o 1076.462 1875.824 877.336 1818.439 1875.824 1779.136 0 1-Apr-01 38.84737 1 4 2001 0.867361 116223.9 13577.52 227.7379 2520.784 1871.876 1 4524.073 125766.6 1872.354 2520.784 227.7379 1978.488 117560.4 o 1068.823 1868.273 870.1969 1810.$49 1868.274 1771.501 0 1-May-01 38.9295 1 5 2001 0.86752 116216.9 13502.24 228.8472 2499.478 1864.614 1 4599.319 132618.4 1865.09 2499.478 228.8472 2053.735 124412.2 o 1061.389 1861 .007 863.3061 1803.498 1861.007 1764.073 0 1-Jun-01 39.01437 1 6 2001 0.867683 116209:8 13425.06 229.9251 2478.883 1857.151 1 4676.432 139732 1857.625 2478.883 229.9251 2130.847 131525.9 o 1053.872 1853.539 856.371 1796.01 1853.539 1756.558 0 1-Jul-01 39.09651 1 7 2001 0.867839 116202.9 13350.97 230.9182 2459.537 1849.965 1 4750.457 146647.4 1850.438 2459.537 230.9182 2204.871 138441.2 o 1046.532 1846.349 849.6383 1788.743 1846.35 1749.224 0 1-Aug-01 39.18138 1 8 2001 0.867999 116195.7 13274.99 231.8434 2440.469 1842.577 1 4826.361 153822.8 1843.048 2440.469 231.8434 2280.776 145616.7 0 1039.09 1838.955 842.8482 1781.328 1838.956 1741.782 0 1-Sep-01 39.26625 1 9 2001 0.868158 116188'.4 13199.63 232.7245 2421.928 1835.225 1 4901 .681 161026.1 1835.695 2421.928 232.7245 2356.095 152820 o 1031.647 1831.601 836.0868 17;'3.933 1831.603 1734.345 0 1-0ct-01 39.34839 1 10 2001 0.86831 116181.4 13127.23 233.4966 2404.218 1828.144 1 4974.024 168021.6 1828.612 2404.218 233.4966 2428.439 159815.4 o 1024.434 1824.517 829.5693 1766.783 1824.519 1727.136 0 1-Nov-01 39.43327 1 11 2001 0.868466 116174 13053 234.1966 2386.873 1820.86 1 5048.245 175272.9 1821.326 2386.873 234.1966 2502.659 167066.8 01017.1151817.228822.9951 1759.484 1817.23 1719.817 0 1-Dec-01 39.5154 1 12 2001 0.868617 116167 12981.62 234.8672 2370.704 1813.841 1 5119.566 182311 1814.305 2370.704 234.8672 2573.981 174104.8 o 1009.978 1810.204 816.6098 175.2.406 1810.206 1712.687 0 1-Jan-02 39.60027 1 1 2002 0.868771 116159.7 12908.37 235.5247 2354.13 1806.62 1 5192.759 189603.8 1807.082 2354.13 235.5247 2647.174 181397.6 o 1002.717 1802.977 810.1197 1745.169 1802.979 1705.43 0 1-Jun-02 40.01369 1 6 2002 0.869502 116123.6 12558.65 238.4746 2279.507 1772.133 1 5542.273 225406.6 1772.587 2279.507 238.4746 2996.688 217200.4 o 967.7831 1768.46 778.9168 1710.442 1768.463 1670.514 0 1-Sep-02 40.26557 1 9 2002 0.869935 116101.5 12350.83 239.9795 2238.559 1751.471 1 5749.982 247419.5 1751.92 2238.559 239.9795 3204.397 239213.4 o 946.8634 1747.778 760.3979 1689.636 1747.781 1649.604 0 1-Jan-03 40.59959 1 1 2003 0.8705 116072 12080.87 241.8719 2187.515 1724.4 1 6019.796 276819.9 1724.842 2187.515 241.8719 3474.211 268613.8 o 919.4496 1720.682 736.2692 1662.372 1720.685 1622.202 0 1-Jun-03 41.013 1 6 2003 0.871184 116035.2 11754.95 243.7982 2130.751 1691 .299 1 6345.602 313502.5 1691.733 2130.751 243.7982 3800.017 305296.3 o 886.0187 1687.544 707.1746 1629.072 1687.547 1588.781 0 1-Sep-03 41 .26489 1 9 2003 0.871597 116012.6 11560.46 244.6996 2097.261 1671.257 1 6540.009 335976.5 1671.686 2097.261 244.6996 3994.425 327770.4 o 865.8255 1667.492 689.7502 160S.945 1667.495 1568.593 0 1-Jan-04 41 .5989 1 1 2004 0.872137 115982.6 11307.21 245.7851 2054.444 1644.95 1 6793.124 365901.2 1645.373 2054.444 245.7851 4247.539 357695 o 839.3482 1641.165 667.0142 1582.538 1641.168 1542.123 0 1-Jun-04 42.01506 1 6 2004 0.872796 115945 10998.76 246.9882 2003.817 1612.577 1 7101.431 403355.7 1612.991 2003.817 246.9882 4555.846 395149.6 o 806.7946 1608.764 639.2361 1550.053 1608.766 1509.578 0 1-Sep-04 42.26694 1 9 2004 0.873187 115922.2 10815.86 247.7561 1971.259 1593.233 1 7284.199 426116.9 1593.643 1971.259 247.7561 4738.613 417910.8 o 787.3049 1589.411 622.4772 1530.628 1589.413 1490.095 0 1-Jan-05 42.60096 1 1 2005 0.873696 115891.8 10577.93 248.7617 1928.869 1567.923 1 7521.994 456407.2 1568.326 1928.869 248.7617 4976.409 448201 o 761.7881 1564.076 600.5732 1505.193 1564.078 1464.587 0 1-Jun-05 43.01437 1 6 2005 0.874311 115854.1 10290.6 250.0468 1876.369 1537.046 1 7809.157 494072.4 1537.442 1876.369 250.0468 5263.571 485866.2 0 730.655 1533.174 573.8929 1474.167 1533.176 1433.465 0 1-Jan-06 43.60027 1 1 2006 0.875157 115800.2 9896.562 252.3883 1806.553 1494.098 1 8202.984 547828.8 1494.483 1806.553 252.3883 5657.398 539622.6 0 687.091 1490.181 536.6702 1430.858 1490.182 1389.92 0 1-Jun-06 44.01369 1 6 2006 0.875739 115761.8 9627.323 254.0867 1759.745 1464.227 1 8472.105 586071.1 1464.604 1759.745 254.0867 5926.52 577864.9 o 656.8434 1460.288 510.9724 1400.766 1460.288 1359.683 0 1-Jan-07 44.59959 1 1 2007 0.876537 115707 9257.78 256.7112 1693.907 1422.682 1 8841.446 640729.6 1423.048 1693.907 256.7112 6295.861 632523.4 o 614.6765 1418.709 475.2532 1358.857 1418.708 1317.535 0 1-Jun-07 45.013 1 6 2007 0.877083 115667.9 9005.471 258.7188 1647.535 1393.905 1 9093.611 679648.4 1394.264 1647.535 258.7188 6548.026 671442.2 o 585.4819 1389.9 450.5901 1329.835 1389.899 1288.353 0 1-Jan-08 45.5989 1 1 2008 0.877834 115612.1 8659.853 261.6512 1582.871 1353.79 1 9439.026 735339 1354.138 1582.871 261.6512 6893.44 727132.8 o 544.7424 1349.759 416.356 1289.365 1349.758 1247.633 0 1-Jun-08 46.01506 1 6 2008 0.878347 115572.1 8422.577 263.6957 1538.625 1325.89 1 9676.132 775271.6 1326.23 1538.625 263.6957 7130.547 767065.4 o 516.4465 1321.836 392.7444 1261.241 1321.835 1219.349 0 1-Jan-09 46.60096 1 1 2009 0.879042 115515.1 8099.89 266.498 1477.271 1287.402 1 9998.649 832011.8 1287.733 1477.271 266.498 7453.063 823805.6 0 477.365 1283.32 360.2618 1222.426 1283.318 1180.288 0 1-Jun-09 47.01437 1 6 2009 0.879515 115474.7 7880.017 268.3677 1434.532 1260.78 1 10218.37 872398.8 1261.103 1434.532 268.3677 7672.788 864192.6 o 450.4181 1256.684 337.9019 1195.629 1256.683 1153.354 0 1-Jan-10 47.60027 1 1 2010 0.880156 115416.8 7579.368 271.1118 1374.956 1223.921 1 10518.79 930130.1 1224.235 1374.956 271.1118 7973.204 921923.9 o 413.0898 1219.809 307.1025 1158.515 1219.807 1116.048 0 1-Jan-11 48.59959 1 1 2011 0.881173 115316.6 7096.532 276.3107 1271.998 1163.301 1 11001.26 1030082 1163.598 1271.998 276.3107 8455.672 1021875 0 351.623 1159.174 256.741 1097.46 1159.173 1054.624 0 1-Jan-12 49.5989 1 1 2012 0.882088 115218 6656.25 260.8402 1140.368 1106.631 1 11441.55 1128593 1106.913 1140.368 260.8402 8895.967 1120387 0 343.766 1102.579 250 1044.302 1102.579 1004.05 0 1-Jan-13 50.60096 1 1 2013 0.882923 115125.9 6261.272 242.5098 1022.349 1054.348 1 11836.64 1220626 1054.615 1022.349 242.5098 9291 .06 1212420 o 344.0681 1050.373 250 995.8755 1050.373 958.4662 0 1-Jan-14 51.60027 1 1 2014 0.883674 115040.5 5907.612 225.4288 918.7321 1006.69 1 12190.38 1305949 1006.945 918.7321 225.4288 9644.792 1297743 o 344.9342 1002.806 250 951.8299 1002.805 917.0525 0 1-Jan-15 52.59959 1 1 2015 0.884357 114961.1 5589.652 209.5577 827.1312 962.893 1 12508.39 1385276 963.136 827.1312 209.5577 9962.808 1377070 0 346.317 959.1099 250 911.4058 959.1087 879.0715 0 1-Jan-16 53.5989 1 1 2016 0.884975 114888.4 5306.455 0 o 923.3539 o 12791.62 1458023 923.5864 0 o 10246.03 1449817 o 917.6207 919.8122 o 91 ï .6542 919.8107 917.4758 0 Application for a Disposal I Non Order - Marathon Oil Compa GRAPH #1 Sterling 8-4 Model 12,000 t 10,000 :ïE -<t WGPT~w/injection WGPT ~no injection ¿ 8,000 --~.. u___~. o :¡:: g 6,000 ----- "C e Il. 4,000 E 8 2,000 ~^~------------_..- 07/24/98 04/19/01 01/14/04 10/10/06 07/06/09 04/01/12 12/27/14 09/22/17 Date Graph 1. Cumulative Gas Production versus time. GRAPH #2 Sterling 8-4 Model 5,000 4,500 - 4,000 3,500 o 3,000 ~ 2,500 :æ 2,000 1,500 1,000 - 500 __ WGPR-w/ínjection ";:::::;;;;:::~::~ì;;>O~ WGPR-no injection:_X-X_X-X____X .........0-- WWPR-no injection ............... WWPR-wlinjection -X-WWIR 600 - 500 400 300 - 200 100 o 07/24/98 04/19/01 01/14/04 10/10/06 07/06/09 04/01/12 12/27/14 09/22/17 Date Graph 2. Daily Gas Production Rate versus Time. L. C. Ibele Attach 2 sterling b-4 modeling.xls 2/16/00 Application for a Disposallnj Order - Marathon Oil Company Attachment 2 Figure 1. Illustration of injection migration after 16.5 ye.ars of injection at of water per day. Results are based on an Eclipse full field model. to east cross-section between well SU and inJector well SU 43-9. Sterling 8-4 horizon, the same horizon from which gasis being that the fluids are clearly confined within the closure of the structure, and the producing well. Application for a Disposal I n Order - Marathon Oil Company Figure 2. Illustration of injection migration after 16.5 years of injection of water per day. Results are based on an Eclipse full field model. Pictured isa view the southeast looking down on the structure. Injection is into the Sterling B~4horizon, same horizon from which gas being produced in SU 32~9. Note that the fluids are clearly confined within the closure of the structure, and are not produced at the producing well. Attachment 3 · · · Application for a Disposal I_tion Order - Marathon Oil Company e Attachment 3 Page 1 of 2 Attachment 3 Mechanical Integrity Test Well SU 43-9 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Camille O. Taylor Chair DATE: 2002 THRU: Tom Maunder P.I. Supervisor SUBJECT: Mechanical Integrity Tests Marathon Oil Co. Sterling Pad 43·9 FROM: Jeff Jones Petroleum Inspector Sterling Gas Field NON- CONFIDENTIAL Type Test M= Annulus Monitoring P= Standard Pre"sur.. T.."t R= Internal Radioactive Tracer SUrvey A= T "",perature Anomaly Survey D= Differential Temperature Test INJ. v"" w= 0"" Test's Details October 23, 2002: I traveled to Marathon 011 Coo's Ster1lng Gas Field to witness an MIT on gas production well SU 43--9. In charge of thé test which he performed in a safe and were monitored for 15 and found to be stable. and monitored minutes with no significant intent is to convert this gas production Summary: I witnessed a successful MIT 00 Marathon 011 Coo's Unit. Gas Field well 43·9 in the Sterling MJ.T.'sperrormed: 1 Number of Failures: º AttaGIYmeots: Marathol"l circular pre$$ure chart copy (1) Total Time duríngtests: cc: MIT report form 5/12/00 L.G. 021023-MIT SU 43·9 JJ.xls 11/1412002 . . . Application for a Disposal I.ion Order - Marathon Oil Company e Attachment 3 Mechanical Integrity Test Procedure Well SU 43-9 Mechanical Integrity Test Procedure Wen SU 43-9 Sterling Unit Perform a wen SU 43-9 to demonstrate casing and packer L AOGCC in test on 4. If pressure does contact Production 5. Attachment 3 Page 2 of 2 of Attachment 4 . . . Application for a DisPOSallnj.on Order - Marathon Oil Company e Attachment 4 Page 1 of 6 Attachment 4 Injectivity Log Procedure for Sterling 8-4 on Well SU 43-9 Injectivity Log Procedure Well SU 43-9 Sterling Unit AFE 0487000 Objective: Run an injection log across the Sterling B-4 interval of well SV 43-9 to confinn that injected fluids are confined in that sand. Procedure: 1. MIRV slickline on well SV 43-9. Test lubricator and BOPs to 2,000 psi using methanol. Rill with 1:y.¡" impression block down to the top of the downhole choke at 5238' KB. Take impression of fishing neck and POOH. Record fluid level if observed. 2. Rill with retrieving tool. Retrieve downhole choke installed in 8-1 nipple (ill = 1.875"?) at 5238' KB. POOH. (Note: Choke includes a Baker equalizing device. Contact Gary Eller for more infonnation if needed.) 3. Rill with 1%" gauge ring. Tag fill (estimated at 5272' KB). POOH, RDMO slickline. "", 4. MIRV electric line unit. Test BOPs and lubricator to 2000 psig with methanol. Rill with TDT - Waterflow log to top of fill. Make tie-in pass. 5. MIRV pump truck on pump-in sub of electric line lubricator. Pressure up casing string to 1500 psig using separate pump. Blend 75 bbl of3% KCl with borax additive. Heat fluid as necessary to avoid freezing. Inject at least one tubing-volume of filtered KCI fluid down the tubing into the Sterling B-4 fonnation at a rate and pressure dictated by the onsite engineer. While injecting, make passes with the TDT-Waterflow log as necessary to detemiine whether the injected fluid is staying in zone. 6. When complete, POOH and RDMO electric line and pump truck. Haul remaining KCI fluid to Kenai Gas Field for disposal. JGE - January 13, 2000 N:\DRLGISTERUNGISU43-9\injectlog.wpd ........ . . . Application for a Disposal InjAn Order - Marathon Oil Company e Attachment 4 Page 2 of 6 NEUTRON - BORAX LOGGING Written By: Warren / Chambers 09/22/92 Revised By: J. Rathert 01112/99 Reviewed By: Melvan I Whitlow 04-12-93 Reviewed By: G. Nordlander 01/14/99 Reviewed By: T. West 02/07199 OBJECTIVE: Neutron/Borax logs are usually requested when a cement channel or other communication is suspected above or between perforations. When a channel is below perforations, a pump-in temperature survey, PITS, will usually provide the same infonnation as a Neutron/Borax log at substantially lower cost. Above or between perforations, a channel or leak is hard to distinguish from normal thermal effects, so the Neutron/Borax log is requested. Rwming both, on one trip is a cost effective procedure. Ai> an additional bonus the two baseline porosity passes can be used to monitor GOC movement. In practice, baseline passes are made with the neutron tool, a borax solution is then injected into the formation, and repeat passes are made with the neutron tool. Borax has a high neutron capture cross section, so it is easily detected by the neutron log curve, formation sigma 1::, overlay wherever it leaks off into the formation. Consequently the borax will show up in both open perforations and channels. Sometimes a PITS will show a gradual temperature change below the perforations which mayor may not represent a channel. Studies have indicated that a Neutron! Borax log is helpful in such situations in distinguishing short channels from temperature changes due to fluid mixing or conductivity effects, an example is shown in A-34 PNUBorax-PITS 3/29/92 Telex. Poor results have been obtained in running Neutron/Borax logs in injection wells. Log output includes curves showing neutron capture cross section in both the wellbore and formation. Typically, Borax is detectable in the borehole, but not in the formation. It is suspected that this is because the Borax does not leak off into the rock matrix. Injection wells on the North Slope are fractured by the injected water and suspended solids in the injected water tend to plate off at the formation face. The remaining Borax in the fracture occupies too small a volume to activate the tool, so that no Borax response is seen, even where the bulk of inj ection water leaves the wellbore. Borax logging can be done using several types of tools and tool conveyance methods. The pulsed neutron tools, connnonly called PNL, have to be run on e-line for wells with less than 60° deviation, or on coiled tubing E-line, CTEL, for high deviation wells. The reservoir saturation tool, RST TM, is the current tool used. Recently, memory compensated neutron logs, MCNL, have been run, for borax logging, on regular coiled tubing, CT, with a reasonable degree of success. The MCNL uses count rates to accomplish a similar, but not as clear cut, interpretation. NEUTRON BORAX Logging Page 1 · · · Application for a DisposallnjAn Order - Marathon Oil Company e Attachment 4 Page 3 of 6 The pulsed neutron tools require an e-line for the large amount of current to run the downhole neutron generator. They do not use a Radioactive Source. PNL tools also discriminate between the borehole and the formation signal thus the borehole fluid type, except gas, is of negligible importance. Sigma is the measured value, which is severely affected by borax, on these logs. This is the basis for borax logging. Memory compensated neutron tools, MCNL, require a Radioactive source. They measure, radially, the borehole, pipe and formation without any borehole discrimination. For this reason the borehole fluid must be consistent over the entire log interval, during all passes, to prevent another unknown. The base passes require water in the borehole and the borax passes require borax. This is critical to the success of the job. Total count rate measurements are used to determine borax effect. With the memory tool you will be logging completely "in the dark" and must keep accurate accounting of the fluid locations to generate an effective log. Refer to the CTU MEMORY GAUGE PRODUCTION LOGGING section for MCNUBORAX logging. SAFETY Follow the E-LINE WELL ENTRY PROCEDURES and the E-LINE PRESSURE CONTROL sections in the PE Manual. The neutron tool used generates its own neutrons downhole only. No separate source is used. Due to the danger of radiation exposure, ensure that the neutron generator is not powered up, unless it is safely downhole. There shonld be no need to power up the neutron generator on the surface, at the job site, for any reason. It is specifically forbidden by the service company. Pressure control is not an unusual concern as the tool runs on 0.23" line. This is the standard single conductor line used on a regular basis. NEUTRONIBORAX PLANNING 1. If the well is an injector, is on seawater and the zone of interest has not been taking fluid very long, there is a reasonable chance of success. Otherwise, alternative diagnostics should be considered. 2. Liquid pack the wellbore in order to get good PNL baseline passes. Refer to the PE Manual-FLUID PACKING section. Wells with WHSIP of 2000 or less can be shut in at 0100 on the day of the job to allow fluid to build up across the perfs.. Since it will be necessary to pump fluids anyway, it will probably be most economic to fluid pack any well making a substantial oil rate to minimize shut in time. 3. If a fluid pack is used, plan on pumping a 1 to 1.5 tubing volume into the formation ahead of the baseline passes. The larger fluid volume is for low PI wells, less than 2000 BFPD, which are slow to re-pressurize near the wellbore region. Have on hand and stage enough fluid, seawater - Borax - seawater, to be able to pump-in slowly at 0.25 to 0.5 bpm while logging the base passes without getting Borax prematurely into the formation. While logging, it is preferable to keep positive pressure on the wellhead by pumping at a low rate. However, this may not be always be possible without using massive quantities of seawater or Borax solution, especially if the well is on a vacuum. The reason for logging while pumping instead of shutting down and running passes is so that the Borax solution is continually forced into any channels and not just allowed to swap with the wellbore fluids and leak off into the formation. The Borax solution is usually spotted in the tubing during fluid packing. Using a 2 to 3 bbl MEOH spear before and after the Borax gives the fluid interface a sharper definition and prevents it from stringing out. Ensure that the leading edge of the Borax is well above NEUTRON BORAX Logging Page 2 . . . Application for a Disposall.tion Order - Marathon Oil Company e Attachment 4 Page 4 of 6 the perforations when you shut down. This is so that a falling liquid level does not displace it into the-perforations before you are ready. The two baseline passes with the PNL must be completed before the Borax solution reaches the perforations. Estimate how far the liquid level will fall after pumping ends from the reservoir pressure. In low PI wells, it is worth looking at hydrostatics for reservoir pressure and for FBHP, since it will take a long time for the near wellbore region to re-pressurize. If lift gas is not available, consider displacing with diesel to assist in bringing the well back on. 5. Order the Borax solution. Volumes of about 70 bbl are generally used. The recommended fonnula consists of: Fresh water, approximately 100 to 120°F 7 ppb Borax 7 ppb NaCl saIt Filtration of the final mixture to 3 microns Use MI Drilling Fluids to supply the Borax. Use fresh water at 100 to 120°F mixed with 71bslbbl ofNaCl and 7lbs/bbl of 5 molal Sodium-Tetra Borate-Penta Hydrate, NaBO, which is a technical grade and grind . It has the highest capture cross-section of the three. It is important to have a consistent concentration and mix of the Borax solution. Keep the solution warm in transit or the Borax will precipitate out. Mix Borax in a jet mixer to ensure uniform mixing. You will need a vac truck, with clean tanks to pick-up 70 bbls of fresh hot water, take it to the MI plant for addition of Borax and NaCl and mixing. Then it will be pumped back into the vac truck for delivery to the job site. Plan on 2.5 hours for this process. NOTE: Mixing and precipitation problems have been encountered when Borax was mixed in seawater or produced water. The precipitation is temperature sensitive. The produced water solution is subject to significant precipitation if allowed to cool. 6 Discuss the program with the service company engineer. 7. Make sure an approved pump-in sub is installed on top of the swab valve. The service companies should have an approved sub on their units. Ifnot, line up a BP pump-in sub from the wireline tool service building. These pump-in subs have flanged connections, no threaded connections, and are less likely to fail during pumping. Remember to support the hard line to the pump-in sub to prevent a failure due to the weight of the line and vibration during pumping. 8. Line up E-line unit, required fluids which are seawater, Borax, MEOH and/or diesel, filter skid, from PESO's or pump company, and pump truck. Remember to have a heater and MEOH in the winter. PRE-JOB PLANNING: General E-Line Checks: 1. Check last 1D tag in the telex file. Run a driftltag if there is any doubt. 2. SSSV's have been permanently pulled in all producing wells as of 1-1-99. Injection valves ISSSV's remain in injector wells and will have to be pulled. 3. Check records for fish, tight spots and perforation intervals in the well. 4. Provide PCC with a tentative time schedule. 5. Call for a bleed tank, heater and 50-50 MEOH. NEUTRON BORAX Logging Page 3 . . . Application for a Disposal InjAn Order - Marathon Oil Company e Attachment 4 Page 5 of 6 6. Keep FREEZE PROTECTION in mind for all flowlines and the wellbore. JOB PROCEDURE: 1. Rig up service company lubricator, pump truck, filter, approved pump in sub and tools. Whenever practical, run the temperature tool in combination with the neutron tools for a PITS log on all passes. Pressure test hard line and lubricator to 3500 psi with pump truck. 2. Rlli. Proceed to step 3 if optional flowing passes are not required. If flowing passes are required, tie-in to the BHCS/GR or CBUGR/CCL. Make the required passes, including the temperature, at 30 FPM, from ID to top of the Sag formation or as directed in the program. 3. Flnid packing is required prior to baseline passes. This can be done while Rlli. The RST is 1 11/16" in diameter, so the risk to the tool string is minimal. Stage the flnids as described previously. Hang the tool above the top of the intended log interval to monitor borehole sigma and guard against over displacement as the leading edge of Borax approaches. Finish flnid pack with 1 to 1.5 tubing volumes of seawater into the formation. Reduce the pump rate to 0.25 to 0.5 BPM. Tie-into theBHCS/GR or CBUGR/CCL. 4. Make two baseline passes, without any Borax in the wellbore or formation, over the zone of interest as described in step 2. Log one pass at 30 FPM and one at 60 FPM. 5. Hang the tool at the top of the log interval, monitoring borehole sigma. Start pumping in to advance the Borax downhole and into the formation. When the Borax passes the tool increase the pump rate to maximum, considering the frac pressure, until 30 bbls plus the volume from the tool to the bottom of the perforations is pumped. The high rate will drive the Borax into any possible channels. Idle the pumps to 0.25 to. .5 BPM, Rlli to bottom and make the 1 II Borax pass from TD up to 100' above the perforations or as directed in the program. Log at 60 FPM. 6. Hang the tool at the top of the last pass again. Pump-in 30 bbls of Borax into the formation at the highest safe pump rate. Idle the pump again. Rlli. Log the 2nd Borax pass. Log at 60 FPM. 7. If a flush pass is required, optional, continue pumping at high rate until all the Borax is past the tool plus 30 bbls of seawater is into the formation. Make a flush log pass at 60 FPM. Be aware that if Borax is left in a permeable zone it will permanently alter the formation sigma for future neutron logging. POP the well as soon as the job is over. If that is not possible flush it with 30 bbls of seawater pumped at a high rate. If a PITS is not requested, POOH. It is a good idea to check your sigma overlays before POOH. 8. If a PITS is requested, hang the tools at the top of the log interval. Pump I tubing volume of cool seawater. Make the base temp pass to ID. Make down warmback log passes at I, 3 and 5 hours after pumping was stopped. Always hang the tool at the top of the interval while waiting. The 5 hour pass may be eliminated if the answer is clear or a 6 hour pass may be required if not. After the temperature overlays are accepted, POOH. 9. Return the well to the Pad Operator and notify Production Control. Freeze protect as necessary. Notes: NEUTRON BORAX Logging Page 4 · · · Application for a Disposal I.tion Order - Marathon Oil Company e Attachment 4 Page 6 of 6 ~ The SIGMA curve sees the Borax in permeable zones where the Borax fills the pore space close to the borehole contacted by a channel. It will fill the channels also. Borax will NOT be seen in non-permeable zones such as shales, the HOT, or even injection wèlls where thennal fracturing has occurred; even if there is a channel. The flowing PNL pass may indicate hydrocarbon or water entry points; even behind pipe. The flowing temp log will also be useful. The temperature passes are used to help identify channels below the perforations. LOG PRESENTATION: For the service company engineer In order, after the log heading labeled BORAX LOG or BORAX - PITS LOG, as the case may be. 1. Tool sketch 2. lob Comments - the last well production test information and operating steps in sequence, including volumes pumped and logging passes made, listed below the header comments. Make an attempt at interpretation and include on the comments. Someone should be able to determine and understand what went on while doing the job from the data presented on the log. 3. PITS- All passes. Temp Scale: scaled across Tries 2 & 3, 20 divisions, as appropriate. Scale the temperature from the lowest recorded to the highest recorded. Pick a scale, preferably even degrees/division to cover that range. 4. S,igma & Sigma borehole Over1ay - Flowing, Shut-in, and Borax passes; scaled 40 - 0 across Trk. 2-3 and labeled clearly. Label suspected channels, etc. on the log. 5. Porosity Overlay - Flowing and Shut-In passes; scaled 60 - 0 across Trk.2-3 and labeled clearly. 6. All StandardPriinary and Secondary Presentations for all stages: Flowing, Shut-In, Borax. Ensure that the far-near count rates are scaled so they are normalized during shut-in in a "clean water zone" for gas detection. Present count rate ratio, 3 to 1.5, on Trk.2; sigma, 40-0; porosity, 60-0, both on Trk.2-3. 7. Put all perfs, both open & squeezed, on all log passes. 8. Make sure that the 2 PNL baseline passes logged prior to Borax invasion are presented just as a normal PNL looking for GOC, etc. NEUTRON BORAX Logging Page 5 Attachment 5 · · · Application for a Disposalln.on Order - Marathon Oil Company e Attachment 5 Attachment 5 Injectivity Test Results for Sterling 8-4 on Well SU 43-9 MARATHON OIL COMPANY DAILY WELL OPERATIONS REPORT PAGE 1 OF 1 DATE: 2/25/2000 FIELD: Sterling Gas Field WELL #: SU 43·9 FILL DEPTH/DATE 5336' KB (2/18/00) TUBING: 2-3/8" CASING: 5-1/2" DATE LAST WL WORK: 2/18/2000 TREE CONDITION: WORK DONE: Pull choke, gauge run to bottom BENCHES OPEN: Sterling B4 PRESENT OPERATION: Injectivity log to confirm B-4 Zonal Isolation OTHER: AFE 0487000 SUMMARY OF OPERA nONS 0700 MIRU Schlumberger on well SU 43>9. SITP = 1755 psia, CP = 40 psI. Held operation$J¡¡afety meeting. Prepare to run RSTfTemp log; had to drop off centralizers because tool string too long. Pressure test lubricator to 3000 psi with methanol. 1500 RIH with RST/temp log. Tag bottom at 5300' KB, and tie into Halliburton log of 8/9/90. Difficult to accurately tie into open-hole logs. Make a baseline log and repeat log from 5300' to 4900'. Fluid level is in the vicinity of the perfs. RIH to bottom. 1600 MIRU Dowell pump truck onto Schlumberger pump·in sub. Test lines to 3000 psig. Filled the tubing (20 bbl) with 100-<1eg fresh water, then pumped an additional 5 bbl at 3.2 bpm at 2300 psig. All fluids filtered to 3-microns. Shut down pumping. log from 5300' to 400'. Occasionally pumped small volumes of fresh water to keep the surface lines thawed. RIH to bottom when logging complete. 1930 Pump 20 bbl slug of fresh water mixed with 7 Ib/bbl borax at 3.25 bpm with 2450 psig pump pressure. Displaced with 20 bbl fresh water at same rate. Annulus pressure stead at 40 psi. After borax was displaced from the tubing, logged from 5300' - 4800' with RST/temp log while pumping at minimum rate. No sign of fluid channeling out of zone; clear indication of borax entering the Sterling 84 interval. Ran repeat log over same interval. Made stationary oxygen-acUvation surveys at 5238', 5248', and 5218' KB while pumping at minimum rate (0.2 bpm) at 1200 psig pump pressure. No indication of upward flow (I.e. behind pipe flow) at 0030 any of the stations. POOH, RDMO Schlumberger and Dowell. Vendor Daily Cost Cumulative Cost Equipment pump truck borax hot shpls, elc. vac Iruck, lighls electric line, RSTfTemp log Dowell M-I Drìlilng Fluids Misc. R&K Schlumberger DAILY COST; CUM: REPORTED BY: Eller/Alfinito MARC BORE X ..5!~~~!~.~~1(,"<H~L.~........, (MARC FiST 8igma (810M) ^ (GAPO 100 REP) - 60 (CU) \/I o (----) 5 ......."........-. - . . . . . - . . . . . . . . - . . :··········Area·········; :: From .: . JSAl ROREX (BSAl REP) :~PSP/PERF~~ RST S'BF BOREX ~SIBF REP) RST Capture to Inelastic Ratio Far _.. . - .: 0 :.----- - -. 'CIRf flL) ·PPK) -50:: - ::100 ICU) 0---·---\:--------- :]NTERVAL:: \ 5 (----) 0 ~~ ICY to ~~ \:~:~::B~L{:) ~R_REP ~~rve (Q.R»~~~) '" ." _It... ¥a... It-If.... 4U............. ~:!!. t!!9!12 !I. ~9fl~ J~I~M~~~~ì«......... ... ............... (GA.P') 100 60 (CO) 0 !:!-!~§..X J.R!~~[r ,.,!1~1. _ r......... "..,.,........"....".."...,~!:?:I,!:'.~1)J.·.2:!!t.·..'\I,l {IE.tì:!l.,..",.._,"",_,__. _ CIRN.F ~"Q )RE;X tCIA",- RpU:f') (----) 25 ¡,!yg ,rlN·'1 (\2.5 (----) 0 :f....~9..~~>f .(~~gf ....~.1...~.'¥~).... ~ Rgy2.œ.S.!!L f!Qf!~PHI_REPL _ E,!!F .Jl!-~CLRgx JCJ.R.E-BI:..RE~ _ 1_.___.\ I"\e' \ """ -.. ...... ...-~ ~ ~"rehole Salinity (BSAL) (PPK) Minitron Arc 5 Detection RST Sigma Borehole Fluid (SIBF) . 0 (MARC) 100 (CU) o (----) 5 RST Capture to Inelastic Ratio Near o (CIRN FIL) 2.5 (__n) o J' - -- _.,.....~_... _. ~_., . ."C_(, . .' .~. -...-- .. , " ROOF. A ~'''~' ,);~.~..,: ,I1 s _ . .u;;.P d"'~""'" RSCt\ < ..""'r. .....;..r-ê;:..... "J. J -.,'. )=ree;: ,'~" '\' " RSCF ; ~s T ::~,.~i....·' ~".... ~ " .<I~'~.~. '"').' RSe _'=IS-~~" " . ,.J ] _:".:::P~'~~"> ,PIFL ~ ..- ~ ~~; ...-.t..~ ~ MARC R~P {t''é'... . , : . ~--"'J, " . ':> MARC- ,,-...~ . t . _'JI! - ... ,..~,,-:;~"" '. ">.!e'Þ b.!. ".'. <:.... " ) "ifl_ ruEif'". .: "".' ''',... \.. )} . .\ GR"" ~ <.:' f l "; ",;;.- /' a. _1: ..." .......:"4,. . '< .". . ~....... ': .".. ;...;:" J. ' , 5200 '.' ""'. .....~ '"$ ..... - . . <),' .~'_. ..~': "~..:f~ '\þ' .' ,...... II . <' \ : ";) I \ )..·i~Jù::í....~~ ?' )h.'.I...'....~ . .' .... (', ' =- ~"'~~ -. " . ~~rM~ ,." ~.~ ) I .~ .1''') ,~,.::.,.¡ . ) ~,.:r) j /'. ~ -,'';. '. ~ ..... ... ) 3- .... ....\ <.'.. _ ,'.' _ ........;.. ",......) ),. t , . _. . c-::-.· L \. " '+- .... -7'" .' ~.' :;-r ~. . ,~M"'- I . . ';' .;.,.......0:.. -:) ,:) _.._.... ._.f .. - .v;;ç-" ~, '. · ~. ..' '>' "'.I' f- ','" "; ',> J:", \ t ~.-- I ~:.. ~...... "'¡;... .-',; t ,". _ ..,1 ". .... :" . -'. . -.. :: ~..~' ~..:: "","' - .r . . ~',~ , '_, "c <" ~ .... \ . ^"'.'. .. j '''''~ :. I . '\ .., ~ .~.......,. ~,- d,,' t....... ..þ _____ ; ....t-". _ _____~L ' _, c _< ~-~ · - , · · · · · , , f SU 43-9 Borex Injection Log 2/25/2000 5300 e ,. SF ~-: .~ \. f \ ¡ ) I ~.'~. .~T~NS2:~~¡. "A J:tE~ ~~, ~?- ~ _ l~, I: .' . srGI!~~ i~ f1tt' : ~, : .-t' _ '¿~ . ~i. ~ \" . . f - ; )~. ; , . ,.., ~ .~" . 5\:) j ,,(~ IM~ FL AEP t'A~t -- l..... }'t:" .1A-_FL 1 . . w j " . , . J : 1 : CIR! R~r~ - : CI.rtN_ -F IL.~._ -.c.....P\~:~.~ J ~ · CIR FIÎ'~ : . . . ÇlçFI) ) , ft' : . ~ ~ ~ '-! It ~) ?~. \' i t .'. .~. \ : u '~",., ; "') : . I <.. .. _f.. . ,....~.... It{~' '. . 'I '" ..~ ~,.... . ,.# 'l q; k ~ I . ~. .. (: ~ Lr~ ,/«( ,.... /{.. ; ~, (~I/ ¿ . ~ , ~ . ) ...., \ ~~"(.. .~ ~, .~ - ~ I ". _ ...-.... . , . ~ . :í · i · · · · .. ~ ,....., ,.Q ~ V1 ~ Z ç.¡,'( :E = u < ~ ~ < Attachment 6 Application for a Disposal Inje Otis Otis TubIng tail FWHP: Order - Marathon Oil Company Attachment 6 Construction of SU 43..9 Well r J-55, BId tubing to 5241' fill at 5336' MO APt: AOGCC: 163-11 KB-GL: 11.1' 2422' FSL, 528' FEL Sec. 9, T5N, R10W, S.M. Tree cxn 2-318" EUE ard ... Calculated cement top 3301' excess in 7-518" x 5- (4 sp!) I TO 6202' I Attachment 6 Page 1 of2 Application for a DisPOSallnjea Order - Marathon Oil Company . Well SU 43-9 Sterling Unit Cement Calculations Assumptions Knowns Calculations (1 ) . (2) (3) (4) (5) . Cement Yield :: Openhole Washout:: 1.15 cu. ftJsack 100% Cement Volume:: 550 sacks Hole Size:: 7.625 inch Casing Size:: 5.5 inch Casing ID :: 4.892 inch Shoe Depth :: 5380' MD Top of cement in csg :: 5337' MD Note: Maintained full circulation throughout cement job Cement Volume:: Sacks * Yield/5.615 112.6 bbl Shoe Volume:: CasinglD^2 * Length/1029.4 1.0 bbl e Attachment 6 Page 2 of 2 Annular Capacity:: (Hole^2 - CasingOD^2)*(1 + Washout)/1029.4 0.054188 bbllft Height of Cement:: (Cement Volume - Shoe Volume)/Annular Capacity 2060 feet Top of Cement:: Shoe - Height of Cement 3320' MD +-- Calculated top of cement Attachment 7 . . . Application for a Disposall.tion Order - Marathon Oil Company e Attachment 7 Page 1 of 7 Attachment 7 Hydraulic Fracturing Potential Simulation WJ August 28, 2002 Mr. Gary Eller Marathon Oil Company 3201 CSt. Suite 800 Anchorage, AK 99519~6168 Mr. EUb'!, Enclosed you will find one Fracpro PT fracture analysis reports t{¡r SU 43~9 disposal well. The log from the nearby SU 32-9 well was used to detemline tbnnation characteristics. The purpose of this letter is to briefly explain the input parameters used fOl" the ¡nodel and the subse.quent results. Aft.er completion of the simulation run, there docs not appear to he any concern about the fracture out of zone, according to the model. There appears to be a significant stre8.'\\ contrast between the sand layer and the shale and coal layers above the sand. Actual fracture !ength may vary signitïcantly depending on pumping rate, !e.ak:-off rate, and start-stop operations. To dctcrmine the input parameters, data from the electronic log was broken down into through, and below the perfhrated interval. Data such as layer thickness, Poisson's Ratio, Young's Modulus and Closure stress were computed from log data and input into the Frru...'Pro PI mmlel. A perforated interval l,'orrelating to the 8-4 Sand in wen SU 43-9 with 4 shots per foot was selected because it is near the center of the sand layer target...,,} t{¡r inje(.,i:ion. TIle pore pressure gradient was assumed to be 0.44 psi/ft. in all layers. During tIle course· of the simulation, expected surface treating pressure did not exceed 1800 Several simulations were run using various values for leak-off coefficients to evaluate their inlpact on the model, and determine if the fractures would bre.ak: out of zone. A minimum !e.ak:-off value was selected (6.6 E-3 fì:lt11Ín¡/2 or I md) that provide a reasonable output but would not cause the simulator tofliil (i.e. obtaining values beyond which the simulator could reasonably process). Smaller values fì)r relative permeability would cause the fra(.,i:ure to grow in length to a point difficult for the simulator to complete in a reasonable JXorîod of tinle. schedule for the sinmlatélr was to bpm t()r 370 days, during which 533,224 of dean tluîd with 0.1 ppg of 1 ()()'Inesh sand (s.g. = 2.65) added. HI Services Company; tLS.A._· C, St.fü:t, Suite :H:O (99501)) . EO, Box 100379 " And\oragc; AK 99.510-0379 OŒœ: (907) 349·651S . Fax: (907) 349·1486 . . . Application for a Disposal InjAn Order - Marathon Oil Company e BJ Services Company has enjoyed a good business re1atiouship with Marathon Oil Company and looks forward to a continued success. If you have any questions or would like further detail on thell1ode1 process, p1ease fed free to call me at our Pacific Region Office, (907) 349-6518 or Andrew Katon,Pa.cif1c Region Engineer at our Teclmology Center, (661) 396-4441. Cc: Pacific Region File Attachment 7 Page 2 of 7 · · · Application for a Disposal Inj.n Order - Marathon Oil Company e FracproPT 10..1 Hydraulic Fracture Analysis Date: Well Name: Location: Formation: Job Date: Ftlename: August 19, 2002 SU 43-9 Kenai Peninsula 8119/02 SU-43-9 Disposal Attachment 7 Page 3 of 7 Fracture Geometry Summary Fracture Half-Length (ft) 1945 Propped Half-length (ft) 0 Total Fracture Height (ft) 99 Total Propped Height (ft) 0 Depth to Fracture Top (ft) 5269 Max. Fracture Width (in) 0.06 Depth to Fracture Bottom (ft) 5368 AV$). Fracture Width (in) 0.04 Equivalent Number ofMultipleFracs 1.0 Avg. Proppant Concentration (lbIft2) 0.00 Fracture SI",rry Efficiency 0.00 All values reported are for a single fracture Model has run until 533088.00 min Fracture Conductivity Summary Avg. Conductivity (wlDamage) (mD-ft) 0.0 Avg. Frac Width (Closed on prop) (in) Dimènslonl,*s Conductivity . O.oo'Rèf. Formation Pèrmeabllity (mD) Proppant Damage Factor O.50Proppant Permeability (mD) All values reported are for a single fracture . Model Net Pressure (psI) Obse.rved Net Pressure (psI) Hydrostatic Head (psi) Fracture Pressure Summary . 8H Fracture Closure stress (psi) "Closure Stress Gradient (psilft) -Surface Pressure (psi) 28 o 2375 Averages reported during Main Frac Total Clean Fluid Pumped (bbJs) Total Slurry Pumped (bbls) Pad Volume (bbls) Pad Fraction (0/..) Main Fluid Operations Summary 533062 Total Proppant Pumped (klbs) 533062 TotalProppant in Fracture (klbs) o Avg. Hydraulic Horsepower (hp) o Max. Hydraulic Horsepower (hp) 4% KCL cMain Proppant reported during Main Frac 0.00 1.00e+00 2??oo 3936 0.741 1720 2228.5 0.0 42 42 100-Mesh 10.1 . . . Application for a Disposal I.tion Order - Marathon Oil Company Fracture Dimensions End of Time Fracture Stage (mm:ss) Haff·length '# (ft) 1 370:days 1945 Fracture Growth History Fracture Height (ft) Fracture Width at Wen (in) 0.061 All values reported are for a single fracture 99 Avg. Fracture Width (in) 0.040 Model Net Pressure (psi) e Attachment 7 Page 4 of 7 Slurry Equivalent EffICiency Number of Multifracs 28 0.00 1.0 . Proppant and Fluid Properties by Stage . Proppant Distribution by Stage Stage ProppantType Proppant Stage Distance from Avg. Proppant Avg. Proppant Avg. Proppant # Concentration Wellbore Concentration Conductivity Volume (1'1'9) (ft) (lblft2) (mD-ft) Fraction 1 10o-Mesh 0.10 1827..2 0.00 0.0 0.000 1 100-Mesh 0.10 854.7 0.00 0.0 0.000 Stage # Fluid Type 1 1 4% KCL KCL Stage Elapsed '# Time min.see Wellbore Fluid 1 r 37'O:day, Fluid Type 4% KCL 4% KCL Design clean volume (kgal) Design slurry volume (kgal) Fluid Properties by Stage Slurry Rate (bpm) Distance from Wellbore (ft) 1827.2 854.7 Avg. Fluid Temperature (oF) 140 140 1.00 1.00 Design Treatment Schedule . . Clean Prop Volume Cone (k9al) (1'1'9) 1.0 22289.2 Stage Prop. (klbs) 0.10 2228.9 Design proppant pumped (klbs) 1.00 22289.2 22390.0 :2 Avg. Fluid Viscosity (cp) 0.5 0.5 Slurry Rate (bpm) Avg. Shear Rate (1Jsec) 0.0 0.0 Proppant Type 1 ~O-Mesh 2228.9 FracproPT 10.1 . . . Application for a Disposal Injetn Order - Marathon Oil Company Leakoff Parameters Reservoir type Filtrate to reservoir fluid perm. ratio, KplKl Reservoir pore pressure (psi) Initial fracturing pressure (psi) Reservoir fluid compressibility (1/psi) Filtrate viscosity (cp) Reservoir viscosity (cp) Porosity Gas Leakoff Percentage Reservoir temperature ("F) Depth to center of Perfs (ft) Perforated interval (ft) Initial frac depth eft) Layer # 1 2 3 4 5 8 1 8 9 10 11 12 13 14 15 Top of zone (ft) 0.0 5011 .7 5047.4 5071.2 5160.8 5212.8 5225.6 5232.0 5250.2 5257.6 5271.2 5367.5 5394.8 5453.7 5467.3 Stress (psi) 3759 3722 3896 3186 3994 3862 4183 3878 4203 4054 3936 4143 4014 4205 4046 Top of zone (ft) 0.0 5011.7 5047.4 5071.2 5160.8 5212.8 5225.6 5232.0 .2 5367.5 5394.8 5453.7 5467.3 Reservoir Parameters Layer Parameters Young's Poisson's modulus ratio (psi) 1.0e+06 0.25 6.5e+05 0.36 6.8e+05 0.38 6.51:11+05 0.38 6.8e+05 0.36 6.5e+05 0.36 3.ge+05 0.39 8.5e+05 0.36 3.96+05 0.39 6.8e+05 0.36 8.5e+05 0.36 8.8e+05 0.36 6.5e+05 0.36 6.8e+05 0.36 6.5e+05 0.36 3 Gas 10 2311 4436 4.33e-04 1.00 0.03 0.10 100.00 140.00 5312 9 5312 Top of zone (ft) 0.0 5011 .7 5047.4 5071.2 5160.8 5212.8 5225.6 5232.0 5250.2 5257.6 5271.2 5367.5 5394.8 5453.7 5467.3 e Total Ct (ftlminY2) 2.0858-04 6.5946-03 2.085e-04 6.5946-03 2.0856-04 6.5946-03 2.085e-04 6.5946-03 2.0856-04 6.594e-03 6.594e-03 2.0856-04 6. 594e-03 2.085e-04 6. 594e-03 Attachment 7 Page 5 of 7 PoreFluid perm. (rod) 1.00e-03 1.ooe+00 1.00e-03 1.ooEHoo 1.00e-03 1.ooe+00 1.ooe-03 1.00e+00 1.00e-03 1.00e+00 1.ooe+00 1.00e-03 1.00e+00 1.00e-03 1.00e+00 10.1 . . . Application for a Disposal I_ion Order - Marathon Oil Company lithology Parameters Layer Top of Lithology Top of Fracture zone zone Toughness (ft)(ft) (psj·jnY2) 0.0 'Overburden 0.0 1000 2 5011.7 Sandstone 5011.7 1000 3 Shale 5047.4 1000 4 5071.2 Sandstone 5071.2 1000 5 5160.8 Shale 5160.8 1000 6 5212.8 Sandstone 5212.8 1000 7 5225.6 Coal 5225.6 1000 8 5232.0 Sandstone 5232.0 1000 9 5250.2 Coal 5250.2 1000 10 5257.6 Shale 5257.6 1000 11 5271.2 Sandstone 5271.2 1000 12 5367.5 Shale 5367.5 1000 13 5394.8 Sandstone 5394.8 1000 14 5453.7 Shale 5453.7 1000 16 5467.3 Sandstone 5467.3 1000 Well bore and Perforated Intervals Casing Configuration length (ft) 5800 CasinglO CaslngOD (in) (in) 4.892 5.500 Weight (Ib/ft) 17 .000 Segment Type Cemented Casing Top of zone (It) 0.0 5011.7 5047.4 5071.2 5160.8 5212.8 5232.0 5250.2 5257.6 5271.2 5367.5 5394.8 5453.7 5467.3 Unspec Grade Surface line and Tubing Configuration length Segment Tubing ID Tubing 00 Weight Grade (ft) Type (in) (In) (lb/ft) 5600 TubinQ 1 2.375 4.700 Unspec Total frae string volume (bbls) Pumping down 24.2 Tubing Perforated Intervals Top of Perfs - TVO (It) Bot of Perfs - TVD (ft) Top of Perfs ~ MD (ft) Bot of Perfs - MD (It) Perforation Diameter (in) Perforations Interval i1 5308 5317 5710 5720 0.400 40 4 e Attachment 7 Page 6 of 7 Composite Layering Effect 0.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 10.1 . . . » \J "2- ~ õ· :J Õ' .., Q) o ëiï \J o en !!?. it o a. en .., I :¡: Q) .., Q) - ::r o :J 2 () o 3 "'0 Q) :J '< SU-43-9 Disposal Well Fracture Size After 370 Days (Note: Vertical Scale is True Vertical Depth) e ~ ~6) co(') en::r ...,,¡3 o en -~ ...,,¡ ...,,¡ ~ .!J 5fn 525D ~ 1750 750 250 .:' :.,. ',.:_ <.r ;>;;x '.{:;. o('ì.Jí.,,"t.;."!C~ ~~ ~~¥. t~:5S! ~7? .~~ ~2 :,~~:~ fJç~ ».} ;~~.~> :.~.~~~~ ;.- :1:;"-) .}>ÇS ~ ~~~~ .:;~ ~I<·~.·· :z \._ .,or: I Attachment 8 Application for a Disposallnjan Order - Marathon Oil Company e Attachment 8 · Attachment 8 Water Analysis Report For Sterling 8-4 Sands ·~t~ So",~for'Jc, Commercial Tes1ing & Engineering Co. Environmental Laboratory Services "11111111111.l111111.l111111.l11.l11~ 5633 B Str! Anchorage. AK 99518-16( Tel: (907) 562-23. Fax: (907) 561-53( WATER ANALYSIS REPORT OPERATOR M/l.R/I.'T'HON WELL NO. 4 i~q FIELD COUNTY STATE DATE 1/18/95 LAB Ncø.5.0122-0' LOCATION FORMATION c;-\......'\,""<>-. ~-brS"'~~ INTERV AL '=>2107-' - Si-n: SAMPLE FROM STERLING WELL 43-5 REMARKS & CONCLUSIONS BARIUM, MG/L 1.30 STRONTIUM, MG/L ND(0.50) TOTAT. IRON, MG /L 12.0 .0:;<.---" _.~-~ meq/l Anions mgll meqll 30.36 Sulfate. . . . 0 0.00 2.56 Chloride. . . 384 10.83 1.10 Carbonate. . 0 0.00 0.75 Bicarbonate 1460 23.94 Hydroxide. 0 _ --.9 34.77 rota I Anions 34.773 -".."._.---_._~ 1931 Specific resistance @ 6S" F 1615 ~ Observed ..... .... 2.96 ohm-meters 7.8 Calculated ........ 3.97 ohm·meters · Cations Sodium ... Potassium. Calcium. . . Magnesium Iron..... . mg/l 696 1"oó -.ll ~ Total Cations Total dissolved solids, mgJI NaCI equivalent, mg/l .... Observed pH . . . . . . . . .. . . . .. WATER ANALYSIS PATTERN · Sampleabóve described :l\':.,!.i:\;¡\~;, ::i::J':i,.\\.j::.;:.::\\::':,:\.,lq¡::\;:1.::.::\"; 'I"": l.~ :; :::: ~ :;:;IIJ.' I~.i; ~.~;:.!~;,:.~:~: ~ . "." "." .." ·..."1."1'.'" , I' .'.'" ,;.,.,' "Na .;:-¡ :::~~:::,.: ~::Y!::I:i::,~ ;;, :;:': I':,':,:, ,()" :: .::;, I::' ::;! ::;: 1,1, :."1' '"., CIK\\:> ,., I",., '." ,",. ,,,. 1{' "II' ,:··.···,1·".· .,. , ·,r. "1' "i .." .Ii' r ,.'f i :: ¡ :::¡ II:: :: '.I:!: ¡i;: ! I. ii;: ¡ I!'.,,! C '::: I:::; :'I;~!:I': 11,1 ,'I:: ,I" \0)( a I' I '0 .1.. ,I" I' .. I"· II" , " , HCO,1C 10 a:~;~ i:1 :~;; ~:~~ :;~¡ ;qj ¡::; ~~~! ~ :1:::: ¡ : ¡ ¡ ¡ I: : : ¡ ¡; ¡ i ¡ j ! :.ffifY: 'i; ¡ ¡ i ::: I '>/'Mg ::::: :1'1 i:': :::! ; ': "I'! !:II so. x I ;111: I 1::1 "II, ":11 II 'Ii:': i : : :! ; i I ¡: ¡! ! ¡ II :!:, I! 1 : , I : : ; ! ~'I " -I::;: ':I[ 1:': ::,~ :~:: ~~i: ,11 I: ! : !~: - ' , . ~ '," . I ' : I " ' ._. ,. . , ;_, I!;; ':' I ;. .!.. Fe I.::;:,: :'11;(.:'(" ¡,.::.:,: I(ii;'jl.l:ii.<'[i. ;:'I"I'!'::I:::¡I< i¡:,:iil:'¡;::: I';,:!" CO, ! ~ ~ t ~ ~ , : i! :;: It: :! :! ¡! '1. I I! ¡, I ! : I ! : : ; . "I II" .'.' I " 'I ''I' I·' I I" I "·1 II·"" I ' .~:~ ",: ~:;:I;;'; ,:,: '::;lt~~!'I:: ' :' :~l: .', ·:,1"': ;' :: ",;:i::: :::' ::!:I:,:II'!:'I::;, () I ">.- '): '! ~ . (Na value in ebeve grep/'1. !;.elude. No, K. end L1) HOTE: Mql1 = MHUqrams ~(lit4!( Mlltqll = MitHgr.ms .q:.rilfal"nt per liter Sodium Ch~ond. _qui.,.tent = by Oun'.p & H~w1hof'õ14 c.lc~I.1ion from components Scale M EO per Unit . .;. :\;;; J~:;: ¡ :.: i! Ii:: Ii; : :!: :.'.\.\ . ,,':. ':::: ::::':;:: : ::!::::;.;::, . , . , II· ..1 ,.. 'I' ¡ . I" , .." ,., " Na·[ :: :::, ::>::; ,}:}::¡¡, , :¡¡ :¡: ¡¡Ii :¡:¡¡¡::: ,::: ¡ ;~~ :::~ :;::1.1::: ;;~: : ., }: :):¡ :::y:; ::~: : :(.',:,:,:; :1::;; Ca :1:.:. CI ; I::: : 1::; : ¡::I. : ¡':T- HCO, ::¡¡ ::;, ,,', lì ;:d i¡~i : :~ ~¡:' ! :, I~:i Mg :;i: :::: ¡¡ ¡ii:I' :I,i!; ;;;1 i¡:: : I: I:!; so ,il..,:!'.:,: II "'1" '"l .,r. . .,':,' !.:,:.,: ':;; ;!;; ~: I:~! :¡:~ :~¡! ~;::: - - Fe ¡ ;;'·;::¡::I·:I'::::- ¡iii' ,1.0'1';;:;;;:.1;:;.1:<: :;:il CO, :;: :!::¡:;,: Iii; II:; ,,:: I::: [;i:I:;:: ,;:;. .", . I. .", ¡, , 'll: ';'! ".. . '. ...¡ ;,1;1 ,: :.::11; T: :;:: ¡it: ::::¡:::/,~:.::,~:: ., .~ ~6 .. Member of the SGS Group (Société Gênérale de Surveillance) ENVIRONMENTAL ,CILlTJES IN ALASKA. COLORADO. FLORIDA. ILLINOIS. MARYLAND. NEW JERSEY. OHIO. UTAH. WEST VIRGINI, Attachment 9 . . . Application for a Disposallnjan Order - Marathon Oil Company e Attachment 9 Attachment 9 Well bore Schematic for Well SU 32-9 . . AA 'MARATHON t .1 - . ~ Sterling Field Well SU 32~9, Pad 43-9 Marathon Oil Co., Alaska Region API: 5~133-20485 KB-GL: 29.71' KB-THF: 30.00' 2312' FSL, 449'FEL Sec. 9, TSN, RI0W, s.¥. .. Cameo KBUG-LTS chemical injection mandrel wI 1/4" (0.049" wall) injection line @ 998' .. I" chemical injection valve installed 2112199 Tubing: 3-112", 9.3##, N-80, EUE 8rd,AB-Mod. (11 jnts of9.2## NU Butt., 660' - 992') J >< ><. x Isolated Perforations Sterling 8-4: 5679' - 86' ArT (6 spf, 60· phased) ~ ï1 >< x / " Electric line tagged PBID @ 6810' ELM.(11/4198) ~C- r ~_~~"\ Co --..."-...J r ---' r 'v PBID = 6820' ID = 6858' Last Rev: JGE, 2120/99 13-318",68##, K-55 Drive: Pipe@80' iii.. iii.. 9-5/8",47#, P-llO, BTC Casing@2111' Cmt wI 620 sks of class G McMIIln' SMO-l Gas Lift Mandrel cæ 5521' (1 ~ dummy valve installed 2115/99) Halliburton PHI.. Retrievable Packer @ 5573' Halliburton XU sliding sleeve: @ 5630' wI X-profile: (ID = 2.813") (opened 2115/99) Locator sub @ 5877 Baker model F permanent packer @ 5877' wI I 0' sc:a1bore X Nipple @ 5896' (ill = 2.813") Wireline Re-Entry Guide @ 5909' 7",29#, L-80, BTC casing @ 6858' Cmt w/690 sks of class G Attachment 10 · · · Application for a DisposallnjAn Order - Marathon Oil Company e Attachment 10 Attachment 10 Well bore Schematic for Well SU 41-15 .. ~.~.. . ., ,#Ii MARATHON '" ... . Sterling Field· Well SU 41-15, Pad 43-9 Marathon Oil Co.'- Alaska Region API 50-133-20484 IB-THF: 30.00' IB-GL: 29.71' 437'FEL,2327'FSL Seè. 9,. T5N, RI0W, S.M. .... CMU Sliding Sleeve @ 8751' X wI X-profile (ID = 2.313') .... (closed 2/15199) Baker model OT Dual Packer @ 8820' Z ~ Z Z Beluxa Sand Perfs 9440' - 450' 9616' - 640' 9674' - 682' 9694' - 704' 9722' - 736' 9800' - 812' ~03' - 01-4' t / H 7' - QZ6' èluga pay from 9440' - 9812' was fracture stimulated with 74,500 Ibs . of 20/40 EconoProp on 1/9199. X-Nipple @ 9760' 1D=2,313 Re-Entry Guide @ 9770' ~ //z Note; Tagged fill at 9792' on shortstring (8/23/99) z .... x'~ -L ( Tyonek Sand Perfs 10,942' - 953' (4-5/8',6 spf, 5' StimGun) 11,034' - 044' (4·5/8',6 spf, 5' StimGun) 11,121' - 136' (4-5/8',6 spf, 3' StimGun) 11,290' - 296' (4·JIS·, lispf, no StimGun) 1l,305' - 316' (4-5/8', 6 spf, 5' StimGun) \322' - 331' (4-5/8',6 spf,.6' StimOun) ~ ::---- -'- ) ....f" '':'\ ¿- ----==--===::: PBTD = 12,490' TD = 12,600' Last Rev; 1GE, 6/21100 Halliburton TruGuide injection mandrels w11l4" (0.049" wall) iujection line SS @ 822' LS @ 944' I" injection valves installed 2/99 ... 20', 1·55 Drive Pipe @ 58' " 13-3/8',611, I-55, BTC Casing @ 2271' Cmt w/1186 sks of class G Tubing (Shortstrinx Be Lonxstrinx) 2-7/8', 6.5#, L-SO, AS-Mod EUE 8rd Steel Blast Joint (OD = 3.500') LS SS 9437'-455' 9436'-456' 9616'-643' 9611'-749' 9668'-739' 9795'·822' 9996'-033' 7· Liner Top @ fOl08' wI ZXP liner-top packer ... 9-5/8', BTC casing @ 10312' 0' - 3083': 53.5#, P-110 3083' - 9866': 47#, P-110 9866' - 10312'; 4711, L-80 Cmt wI 2284 sks of Class G Note: Apparent corkscrewed tubing at 10.D40' Baker model "D" Packer @ IOS47' Shock absorber @ IOS65' X Nipple @ 10902' ID = 2,313" IS/G4' ehoke instolled 3/7/00. End of Tubing @ 10940' IA _ .,..~ (=iI' ~ \\5'1,5' ()\\~\\~oO' ",!"',,as" ~ Top of Fill: 11,993' (3/6/00) Fish: 402' of 4-5/S' TCP guns dropped to the bottom of the hole after perforating. 7',2911, L-SO, BTC liner @ IOIOS' - 12590' Cmt w/ 70S sks Appendix A Application for a Disposal InjAn Order - Marathon Oil Company e Appendix A Page 1 of 3 . Appendix A Statute 20 AAC 25.252 Underground Storage of Oil Field Wastes and Underground Storage of Hydrocarbons (a) The underground disposal of oil field wastes and the underground storage of hydrocarbons are prohibited except as ordered by the commission under this section. In response to a letter of application for injection filed by an operator, the commission will issue an order authorizing the underground disposal of oil field wastes that the commission determines are suitable for disposal in a Class II well, as defined in 40 C.F.R. 144.6(b) as revised as of July 1, 1998, which is adopted by reference, or the underground storage of hydrocarbons. An order authorizing disposal or storage wells remains valid unless revoked by the commission. ) (b) The operator has the burden of demonstrating that the proposed disposal or storage operation will not allow the movement of oil field wastes or hydrocarbons into sources of freshwater. Disposal or storage wells must be cased and the casing cemented in a manner that will isolate the disposal or storage zone and protect oil, gas, and freshwater sources. . (c) An application for underground disposal or storage must include (1) a plat showing the location of all proposed disposal and storage wells, abandoned or other unused wells, production wells, dry holes, and any other wells within one-quarter mile of each proposed disposal or storage well; (2) a list of all operators and surface owners within a one-quarter mile radius of each proposed disposal or storage well; (3) an affidavit showing that the operators and surface owners within a one- quarter mile radius have been provided a copy of the application for disposal or storage; (4) the name, description, depth, and thickness of the formation into which fluids are to be disposed or stored and appropriate geological data on the disposal or storage zone and confining zones, including lithologic descriptions and geologic names; (5) logs of the disposal or storage wells, if not already on file, or other similar information; . (6) a description of the proposed method for demonstrating the mechanical integrity of the casing and tubing under 20 AAC 25.412 and for demonstrating that fluids will not move behind casing beyond the approved disposal or storage zone, and a description of (A) the casing of the disposal or storage wells, if the wells are existing; or . . . Application for a DisPOSallnje.n Order - Marathon Oil Company e Appendix A Page 2 of 3 (8) the proposed casing program, if the disposal or storage wells are new; (7) a statement as to the type of oil field wastes to be disposed or hydrocarbons stored, their composition, their source, the estimated maximum amounts to be disposed or stored daily, and the compatibility of fluids to be disposed or stored with the disposal or storage zone; (8) the estimated average and maximum injection pressure; (9) evidence to support a commission finding that the proposed disposal or storage operation will not initiate or propagate fractures through the confining zones that might enable the oil field wastes or stored hydrocarbons to enter freshwater strata; (10) a standard laboratory water analysis, or the results of another method acceptable to the commission, to determine the quality of the water within the formation into which disposal or storage is proposed; (11) a reference to any applicable freshwater exemption issued in accordance with 20 AAC 25.440; and (12) a report on the mechanical condition of each well that has penetrated the disposal or storage zone within a one-quarter mile radius of a disposal or storage well. (d) The mechanical integrity of a disposal or storage well must be demonstrated under 20 AAC 25.412 before disposal or storage operations are begun, after a well workover affecting mechanical integrity is conducted, and at least once every four years. To confirm continued mechanical integrity, the operator shall monitor the injection pressure and rate and the pressure in the casing-tubing annulus during actual disposal or storage operations. The monitored data must be reported monthly on the Monthly Injection Report (Form 10-406). (e) If an injection rate, operating pressure observation, or pressure test indicates pressure communication or leakage in any casing, tubing, or packer, the operator shall notify the commission by the next working day and shall implement corrective action or increased surveillance as the commission requires to ensure protection of freshwater. (f) The commission will require additional mechanical integrity tests if the commission considers them prudent for conservation purposes or protection of freshwater. (g) Modifications of existing or pending disposal or storage operations will be approved by the commission, in its discretion, under 20 AAC 25.507, upon application containing sufficient detail to evaluate the proposed modification. No modification will be approved unless the applicant proves to the commission that the modification will not allow the movement of fluids into sources of freshwater. . . . Application for a DisposallnjAn Order - Marathon Oil Company e Appendix A Page 3 of 3 (h) If wells, including freshwater wells or other borings, are located within a one-quarter mile radius of the disposal or storage well, are a possible means for oil field wastes or hydrocarbons to move into sources of freshwater, and are under the control of (1) the operator, the operator shall ensure that the wells are properly repaired, plugged, or otherwise modified to prevent the movement of oil field wastes or hydrocarbons into sources of freshwater; or (2) a person other than the operator, the commission will not issue an order under (a) of this section to the operator until the operator presents evidence to the commission's satisfaction that the person who controls the wells has properly repaired, plugged, or otherwise modified the wells to prevent the movement of oil field wastes or hydrocarbons into sources of freshwater. (i) The commission will publish notice of the disposal or storage application and will provide opportunity for a hearing in accordance with 20 MC 25.540. U) If disposal or storage operations are not begun within 24 months after the approval date, the injection approval will expire unless an application for extension is approved by the commission. (k) The annular disposal of drilling wastes approved under 20 MC 25.080 is an operation incidental to drilling a well and is not a disposal operation subject to this section. (I) This section does not apply to underground disposal that is regulated under 40 C.F.R. 147.101 by the United States Environmental Protection Agency. History - Eft. 4/2/86, Register 97; am 11/7/99, Register 152 Authority - AS 31.05.030 Appendix 8 · · · Application for a DisPOSallnj.n Order - Marathon Oil Company e Appendix B Page 1 of 4 Appendix B WELTS Data for Water Wells Depth of Well in ft. Within T5N R10W SM, Adjacent to Section 9c 94 220 21 111 Within T5N R10W SM Average Maximum Minimum No. of Wellsb 91 451 6 1,026 Within Y4 mile of the SU 43-9 well location (Includes Portions of Sections 9 and 10) N/A N/A N/A Od a Data are current as of March 20, 2002. bOnly wells with depths greater than zero were included in the statistics. CWithin T5N R10W SM, Sections 3, 4,5,8,9,10,15,16,17. dNo section information was available in WELTS for one well within Section 1 ° (Key No. 22335). Also, Marathon has a temporary water use permit (TWUP A98-25) for a water well associated with drilling activity that is located within ~ mile of the SU 43-9 well location. ) ) ) ) Appendix B. WELTS Data Hydrologic Survey of Water Wells Department of Natural Resources Division of Mining, Land Water (WELTS) Appendix B Page 2 of 4 Application for a Disposal Injection Order KEY LAS OWNER DOC DEPTH MERID TWNSHP RANGE SECTION # in Section SECPRTS MAPNUM STATUS DRILLER REGION DOE PDESC TAGS REM1 REM2 REM3 REM4 MODDATE PDFNAME PDFDATE 1990 AMUNDSON, TOM 8/21/1981 97 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 MACKEY LAKE 61 FT SWL: 25 GPM YIELD. 12/23/1999 1992 MERRIT, BERNIE 10/4/1978 138 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 MACKEY LAKE RD 110 FT SWL: 8 GPM YIELD. 12/23/1999 1993 FAIR, STEPHEN 10/3/1978 103 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 MACKEY LAKE RD 85 FT SWL: 20 GPM YIELD. 12/23/1999 2004 WAlTZ, BUD 6/2911979 71 SB 5 10 0 U KRAXBERGER 21A 1/14/1992 MACKEY LAKE RD 40 FT SWL: 40 GPM YIELD. 12/23/1999 2005 BIDWELL, LARRY 6/1611979 71 SB 5 10 0 U KRAXBERGER 21A 1/14/1992 DENISE LAKE MACKEY L RD 50 FT SWL; 25 GPM YIELD. 12/23/1999 2010 CATALANO BLDRS 8/9/1979 102 SB 5 10 0 U KRAXBERGER 21A 1/14/1992 MACKEY LAKE RD 82 FT SWL: 8 GPM YIELD. 12/23/1999 2017 HALL, TOM 213/1980 105 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 MACKEY LAKE RD 85 FT SWL: 20 GPM YIELD. 12/23/1999 2017.pdf 4/3/2001 2018 HALE, DON 2/8/1980 190 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 STRAWBERRY RD 110 FT SWL; 40 GPM YIELD. 12/23/1999 2018.pdf 4/3/2001 2022 BARNES, LARRY 6/4/1980 30 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 BIG EDDY RD, SOLDOTNA 10 FT SWL; 6 GPM YIELD. 12/23/1999 2022.pdf 3/6/2001 2034 DIXON, JIM 11/12/1980 78 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 STRAWBERRY RD 55 FT SWL; 10 GPM YIELD. 12/23/1999 2034.pdf 4/3/2001 2045 MATRANGA. BRIAN 11/10/1981 32 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 STRAWBERRY RD 13 FT SWL; 6 GPM YIELD. 12/23/1999 2045.pdf 413/2001 2056 MCCLAIN, L\MNRENCE 7/27/1981 138 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 SOLDOTNA-HILL 116 FT SWL; 15 GPM YIELD. 12/23/1999 2056.pdf 413/2001 2063 MSP&G 11/16/1980 33 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 BIG EDDY RD 5 FT SWL: 10 GPM YIELD. 12/23/1999 2063.pdf 413/2001 2064 BROWN, LARRY 6/15/1981 137 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 BIG EDDY RD ARTESIAN. FLOW AT 30 GPM. 12/23/1999 2064.pdf 4/3/2001 2070 MADDOX, JACK 5/12/1981 96 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 EAST REDOUBT AVE SOLDOTNA ARTESIAN, FLOWS 6 GPM. 12/27/1999 2070.pdf 413/2001 2078 DALKOVSKI, MITKO 7/23/1979 66 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 KENAI SPUR 25 FT SWL: 50 GPM YIELD. 12/27/1999 2078.pdf 4/3/2001 13753 DAHL, CURT 6/20/1984 93 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 SOLDOTNA NR GOLF COURSE 70 FT SWL: 10 GPM YIELD. 2/10/2000 13753.pdf 11/27/2001 16045 BILBY, MIKE/GALA 7/19/1986 140 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 SOLDOTNA E REDOUBT AVE ARTESIAN AT 0.5 GPM; 100 GPM YIELD. 2/18/2000 16045.pdf 10/22/2001 16125 HILL, BILLY 3/23/1984 30 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 RINEHART 12 FT SWL: 50 GPM YIELD. 2/22/2000 16125.pdf 1 0/22/2001 16203 WATSON, KURT 11/18/1983 38 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 MACKEY LAKF 28 FT SWL; 20 GPM YIELD. 2/23/2000 16203.pdf 1 0/22/200 1 16243 BAILEY, VERNON III 7/6/1983 230 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 HENIKIE L01 B2 ARTESIAN AT 3 GPM. 101312001 16243.pdf 1 0/22/2001 16260 NICKOLAS, CHARLIE 8/18/1983 76 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 STRAWBERRY RD 48 FT SWL: 30 GPM YIELD. 2/24/2000 16260.pdf 1 0/22/2001 16344 BOLES, WOODY 10/25/1982 79 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 MACKEY LAKE RD 40 FT SWL: 25 GPM YIELD. 2/2812000 16344.pdf 1 0/22/200 1 16405 NYCE, GEORGE 9/16/1982 58 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 STRAWBERRY RD 40 FT SWL; 8 GPM YIELD. 3/14/2000 16405, pdf 1 0/22/200 1 16460 ROGERS, DON 5/7/1983 30 SB 5 10 0 U KRAXBERGER DRILLING 21A 1/14/1992 SOLDONTA KNIGHT DR 10/2/2001 16460.pdf 1 0/22/200 1 18465 TORO 1013/1984 77 SB 5 10 0 U NORTHLAND DRILLING 21A 1/14/1992 MACKEY LAKE DON DR 8/3/2001 18465. pdf 8/22/2001 18466 TORO 8/30/1984 66 SB 5 10 0 U NORTHLAND DRILLING 21A 1/14/1992 MACKEY LAKE 813/2001 18466.pdf 8/22/2001 18467 TORO 10/3/1984 77 SB 5 10 0 U NORTHLAND DRILLING 21A 1/14/1992 MACKEY LAKE DON DR 8/3/2001 18467.pdf 8/2212001 18468 ALDRIGE, ROYAL 5/12/1984 117 SB 5 10 0 U NORTHLAND DRILLING 21A 1/14/1992 MACKEY LAKE 8/312001 18468.pdf 8/22/2001 18588 NICKOLAS, PAT 11/18/1983 57 SB 5 10 0 U NORTHLAND DRILLING 21 111411992 IRONS DR SOLDOTNA 8/2/2001 18588.pdf 8/22/2001 18907 C&O BLDRS 3/20/1986 143 SB 5 10 0 U SMITH WELL DRILLING 21A 1/14/1992 EAST REDOUI3T AVE SOLDOTNA 7/19/2001 18907.pdf 8/22/2001 18992 McCOOL, JIM 10/25/1984 136 SB 5 10 0 U SMITH WELL DRILLING 21A 1/14/1992 EAST REDOUBT AVE SOLDOTNA 7/16/2001 18992.pdf 8/22/2001 18997 SMITH, DON 9/1/1984 30 SB 5 10 0 U SMITH WELL DRILLING 21A 1/14/1992 EAST REDOUI3T AVE SOLDOTNA 7/16/2001 18997.pdf 8/22/2001 19003 STROUD, HAROLD 10/9/1984 106 SB 5 10 0 U SMITH WELL DRILLING 21A 1/14/1992 STRAWBERRY RD SOLDOTNA 7/16/2001 19003.pdf 8/22/2001 21302 WILLIS, ZILLMAN 11/23/1976 58 SB 5 10 0 35 U KRAXBERGER DRILLING 21A 6/2/1992 MACKEY LAKE: 6/14/2001 21302. pdf 6/25/2001 21705 CALER, RANDALL 4/27/1970 31 SB 5 10 3 1 BABA U THORN DRILLING 21A 1119/1992 VALHALLA HEiGHTS L06 B7 NOWELL LOG. 14 FT SWL; 12-14 GPM YIELD. 12/13/1999 21705.pdf 6/2512001 16404 CHIVERS, LINDA 9/15/1982 58 SB 5 10 4 U KRAXBERGER DRILLING 21A 1/14/1992 EAGLE RD 37 FT SWL: 40 GPM YIELD. 1012/2001 16404.pdf 10/2212001 ) 17426 MATSON, ROD 9/13/1989 216 SB 5 10 4 BDBD 1-Jan S KRAXBERGER DRILLING 21A 1/14/1992 EAGLE LAKE L05 B2 17426.pdf 9/1812000 20103 PITTS,DAN 6/17/1982 50 SB 5 10 4 CBDA 5-Jan S KRAXBERGER DRILLING 21A 1/14/1992 E MACKEY LAKE N L05 B2 DUP OF 16390 9/29/1992 20103.pdf 3/112001 ) 22570 NIXON, TIM 2/7/1994 196 SB 5 10 4 MAC U KRAXBERGER DRILLING 21A 12/19/1994 CARVER 3 LOg B7 212/1995 22570.pdf 5/2312001 23217 MAXWELL, LAURINE 10/22/1995 173 SB 5 10 4 5 BBAD U KRAXBERGER DRILLING 21A 2/22/1996 EAGLE LAKE L.05 B1 8 GPM. 140 FT SWL. 3/5/1996 23217.pdf 41312001 2032 CHAPPEL, CLINT 1119/1980 80 SB 5 10 5 AAB U KRAXBERGER DRILLING 21A 1/14/1992 CARVER 3 L 14 B7 49 FT SWL: 20 GPM YIELD. 5/511998 2032.pdf 41312001 3889 SCHMIDT. DAVID 8/23/1983 68 SB 5 10 5 BDCA 26-Jan S ECHO LAKE DRILLING 21A 1/14/1992 GIESLER SCH:v1IDT D.M.S. L 1 8/18/1992 3889.pdf 5/2312001 8102 FORREST, BILL 10/18/1984 164 SB 5 10 5 U ECHO LAKE DRILLING 21A 1/14/1992 CARVER L04 B7 10/21/1999 14113 3857 CARVER, KENNETH R. 5/1/1985 73 SB 5 10 5 ABBA 1-Jan S KENNY CARVER DRILLlN 21A 1/14/1992 CARVER 2 L2~: B7 2/17/1983 14113.pdf 8/2512000 16175 BARNARD, DENNIS 10/6/1983 83 SB 5 10 5 ABCC U KRAXBERGER DRILLING 21A 1/14/1992 CARVER 3 L 14 B4 44 FT SWL; 30 GPM. SCREEN 78-83 FT. 7/29/1998 16175.pdf 1 0/22/200 1 16187 NIBLACK. DENNIS 1/25/1993 146 SB 5 10 5 AABB U DARC ENTERPRISES 21A 1/14/1992 CARVER 2 L20 B7 123 FT SWL; 15 GPM. SCREENED AT 145.8 FT. 7/30/1998 16187.pdf 10/2212001 16235 BAILEY, MARVIN 7/12/1983 58 SB 5 10 5 U KRAXBERGER DRILLING 21A 1/14/1992 STRAWBERRY RD L 19 49 FT SWL; 15 GPM YIELD. 2124/2000 16235.pdf 1 0/2212001 18532 STECKEL, JOHN 3/31/1987 70 SB 5 10 5 BCCB 5-Feb S ECHO LAKE DRILLING 21A 1/14/1992 MATRANGA 1 L1 B2TR-1 1212/1992 18532.pdf 11/112000 18733 HOUK, MONTE 1/1/1977 67 SB 5 10 5 CDCD 9-Jan S NORTHLAND DRILLING 21A 1/14/1992 KNORR 1 L3A 4/13/1993 18733.pdf 11/812000 18811 WASSON 29 SB 5 10 5 DC U NORTHLAND DRILLING 21 1/14/1992 STRAWBERRY RD KENAI AREA 7/24/2001 18811.pdf 812212001 18970 C&O BLDRS 10/13/1985 178 SB 5 10 5 AABA 11-Jan S SMITH WELL DRILLING 21A 1/14/1992 CARVER L12 B7 412111992 18970.pdf 11/812000 19000 CHAPPELL, CLINT 10/15/1984 104 SB 5 10 5 AADC 15-Jan S SMITH WELL DRILLING 21A 1/14/1992 CARVER 3 L02 B4 4/2111992 19000.pdf 11/812000 19171 RANEITZ, JEFFREY 9/16/1988 58 SB 5 10 5 ABDC 10-Jan S KRAXBERGER DRILLING 21A 1/14/1992 CARVER 3 L10 B4 19403 UNKNOWN 176 SB 5 10 5 AADB 13-Jan S UNKNOWN 21A 1/14/1992 CARVER 3 L05 B7 148.4 FT SWL; 4.2 GPM YIE LD. NO LOG AVAILABLE. 1/12/1998 19404 JAMES, WALTER 7/1/1980 90 SB 5 10 5 BACA 21-Jan S KENNY CARVER DRILLlN 21A 1/14/1992 CARVER 2 L09 B2 4/2111992 19405 FABIANO, ANTHONY 9/1/1978 57 SB 5 10 5 ABCB 16-Jan S UNKNOWN 21A 1/14/1992 CARVER 2 L04 B5 NO WELL LOG. 42.1 FT SWL. 6.1 GPM. 7/911996 19406 UNKNOWN 45 SB 5 10 5 ABBC 14-Feb S UNKNOWN 21A 1/14/1992 CARVER 2 L02 B5 4/2111992 19408 McDERMOTT, CHESTER 1/1/1974 83 SB 5 10 5 BAAC 19-Jan S UNKNOWN 21A 1/14/1992 CARVER 1 L03 B2 412111992 19410 McCARTHY, JOHN 1/1/1975 100 SB 5 10 5 BADC 25-Jan S GEORGE MATRANGA 21A 1/14/1992 CARVER 1 L02 B3 412111992 19411 CHOAT. LOWELL 1/1/1976 173 SB 5 10 5 BAAD 20-Jan S UNKNOWN 21A 1/14/1992 CARVER 1 L01 B2 NO LOG. 45 FT SWL. 11/18/1996 19412 MORRIS, SID 1/1/1979 49 SB 5 10 5 AABB 12-Jan S UNKNOWN 21A 1/14/1992 CARVER 3 L14 B7 412111992 19414 BOWEN, JOHN W 1/1/1969 66 SB 5 10 5 BADB 24-Jan S UNKNOWN 21A 1/14/1992 CARVER L 12 B2 412111992 19415 JAMES. WALTER H 82 SB 5 10 5 BAAC 19-Feb S UNKNOWN 21A 1/14/1992 CARVER 1 L05 B2 4/2111992 19416 JAMES. WALT 6/12/1978 158 SB 5 10 5 ABCA 17-Jan S KRAXBERGER DRILLING 21A 1/14/1992 CARVER L06 B5 4/2111992 19416.pdf 11/1612000 19418 UNKNOWN 1/1/1982 60 SB 5 10 5 BACB 23-Jan S NORTHLAND DRILLING 21A 1/14/1992 CARVER 1 L 15 B1 412111992 19419 GATES, JAMES 8/24/1983 36 SB 5 10 5 BAAB 18-Jan S WS&SCO 21A 1114/1992 CARVER 1 L04 B1 1/12/1993 19419.pdf 11/16/2000 19421 PRENTICE, MARK 28 SB 5 10 5 BABB 22-Jan S UNKNOWN 21A 1/14/1992 CARVER 1 L09 B1 4/2111992 19422 LANDUA. JOHN 1/1/1974 62 SB 5 10 5 ABBC 14-Jan S UNKNOWN 21A 1/14/1992 CARVER 2 L03 B5 NO LOG AVAILABLE. 3/2911996 19423 RICE,JODIE 6/17/1983 65 SB 5 10 5 BACB 23-Feb S PENINSULA DRILLING 21A 1/14/1992 CARVER 1 L 14 B1 19 FT SWL. 10.8 GPM YIELD 7/16/1996 19423.pdf 11/1612000 19447 MACVIE. FREDERICK 65 SB 5 10 5 B U UNKNOWN 21A 1/14/1992 BURTON-CARVER L05 B1 NO WELL LOG. 3/411998 19447.pdf 8/22/2001 19648 GRAY. SHARON 6/1/1966 96 SB 5 10 5 U UNKNOWN 21A 1/14/1992 SHAKEY ACRES L2 NO WELL LOG. 43 FT SWL. 3/4/1998 19648.pdf 8/2212001 19858 ENGLISH. DAN 11/8/1985 62 SB 5 10 5 CDCB 28-Jan S KENNY CARVER DRILLlN 21A 1/14/1992 KNORR 1 L 1A 10/20/1994 19858.pdf 1/8/2001 19859 JOHNSON. DALE 1/1/1977 57 SB 5 10 5 COCA 29-Jan S UNKNOWN 21A 1/14/1992 KNORR L2-A. RESUB OF L 1&2 11/7/1994 19861 HOKETT. DORIS 8/25/1984 71 SB 5 10 5 CDCD 9-Feb S PENINSULA DRILLING 21A 1/14/1992 KNORR L2B 20 GPM 10/17/1995 19861.pdf 1/8/2001 20729 GIESLER. JIM 104 SB 5 10 5 BDCD 1-Feb S UNKNOWN 21A 1114/1992 GIESLER PROPERTY,KRD BK42 10/12/1992 20747 UNKNOWN S8 5 10 5 8ACA 21-Feb S UNKNOWN 21A 1/14/1992 CARVER 1 LOS 82 10/20/1994 Depth = 0 feet 21692 WOOD, BILLY 1/1/1975 64 SB 5 10 5 BAAD U UNKNOWN 21A 1115/1992 CARVER 1 L02 B2 NO WELL LOG. 38.7 FT SWL. 8 GPM PUMP RATE. 3/9/1998 21692.pdf 6125/2001 22208 DAVIS. KEVIN 1/1/1976 45 SB 5 10 5 BCCS U UNKNOWN 21A 6/21/1993 MATRANGA L 1 B1 NO WELL LOG. 35 FT SWL. 6 GPM PUMP RATE. 4/16/1998 22208.pdf 5/23/2001 22209 NIKOLAS. V.J. 80 SB 5 10 5 BCDA U UNKNOWN 21A 6121/1993 MATRANGA L 7 B1 NO WELL LOG 4/16/1998 22209.pdf 5/23/2001 22210 SCHRADER. GLEN 1/1/1979 113 SB 5 10 5 BCDC U KENNY CARVER DRILLlN 21A 6/21/1993 MATRANGA L::' B1 NO WELL LOG. 4/16/1998 22210pdf 5/23/2001 22211 MATRANGA. BRIAN 1/1/1977 21 SB 5 10 5 BCSC U KENNY CARVER DRILLlN 21A 6/21/1993 MATRANGA 2 TR-1B S1 NO WELL LOG. 4/16/1998 22211.pdf 5/23/2001 22332 PELLENGILL. FRANK 1/1/1972 132 SB 5 10 5 U UNKNOWN 21A 8/17/1993 STERLING AREA NO WELL LOG. 4/2011998 22332,pdf 5/23/2001 22472 OBERG. MARTY 9/23/1992 140 SB 5 10 5 AABB U DARC ENTERPRISES 21A 1218/1994 CARVER 2 L 19 B7 2/2/1995 22472.pdf 5/23/2001 23045 PETTENGILL. FRANK 135 SB 5 10 5 C U UNKNOWN 21A 12111/1995 N STRAWBERRY ROAD NO WELL LOG 2/21/1996 23045.pdf 4/11/2001 23315 CHAPPELL. CLINT 8124/1990 88 SB 5 10 5 ABDD U SMITH WELL DRILLING 21A 4/30/1996 CARVER 3 L09 84 39 GPM. 60 FT SWL. 5/10/1996 23315.pdf 413/2001 Appendix B WELTS spreadsheet.xls 11/2012002 ) ) ') ) Application for a Disposal Injection Order Appendix B Hydrologic Survey of Water Wells Page 3 of 4 ) Appendix B. WELTS Data Department of Natural Resources Division of Mining, Land Water (WEL TS) KEY LAS OWNER DOC DEPTH MERID TWNSHP RANGE SECTION # in Section SECPRTS MAPNUM STATUS DRILLER REGION DOE PDESC TAGS REM1 REM2 REM3 REM4 MODDATE PDFNAME PDFDATE 23515 LAS 20656 LAN DUA, J 75 SB 5 10 5 46 ABBC U 21A 12/4/1996 CARVER 2 L03 B05 NO LOG AVAILABLE 12/4/1996 23515.pdf 1/4/2001 2129 RICHESON, RANDY 8/18/1981 104 SB 5 10 8 DBBC 14-Jan S KRAXBERGER DRILLING 21A 1/14/1992 REX EAGLE HOMESTEAD TR-D 4/13/1993 2129.pdf 5/21/2001 2273 COURT, HANK 10/15/1979 64 SB 5 10 8 BCCD 4-Jan S KRAXBERGER DRILLING 21A 1/14/1992 HIGHLANDS 1.6 B4 2273.pdf 5/21/2001 3314 CHURCH, WALT 7/211981 78 SB 5 10 8 U KRAXBERGER DRILLING 21A 1/14/1992 HIGHLANDS TRL PRK (NR), T4 45 FT SWL: 15 GPM YIELD. 1/3/2000 3314.pdf 4/11/2001 3756 HOLT CONST, BOB 5/18/1983 69 SB 5 10 8 CBDB U ECHO LAKE DRILLING 21A 1/14/1992 LEO T OBERTS 1 L 13 B1 10/20/1999 3756.pdf 5/23/2001 3894 OBERTS, STEVE 9/5/1983 69 SB 5 10 8 CBAD 12-Jan S ECHO LAKE DRILLING 21A 1/14/1992 LEO T OBERTS1 L08 B1 A 47 FT SWL. 6.63 GPM. 71911996 3894.pdf 5/21/2001 3895 BREWER, SHARON 9/15/1983 75 SB 5 10 8 CBDA 13-Jan S ECHO LAKE DRILLING 21A 1/14/1992 LEO T OBERTS'1 L07 B1 AL 8/311995 3895.pelf 5/21/2001 13607 WTlPIL, ROBERTA 1/1/1970 104 SB 5 10 8 U JESS SHELMAN 21A 1/14/1992 RIDGEVIEW EST L4 NO WELL LOG. 3/2/1998 13607.pdf 11/27/2001 15684 9888 EAGLE, DAVE 9/3/1986 110 SB 5 10 8 CMB 6-Jan S CARVER KENNY DRILLlN 21A 1/14/1992 REX EAGLE HOMESTEAD TR- 4/2811983 15684.pdf 8/29/2000 16309 ELSON, JASON 8/19/1983 58 SB 5 10 8 U KRAXBERGER DRILLING 21A 1/14/1992 LEO T OBERTS ADD 1 L2 B1 46 FT SWL: 8 GPM YIELD, 2/28/2000 16309.pdf 1 0/22/200 1 18657 BROWN, JIM 70 SB 5 10 8 BC U NORTHLAND DRILLING 21 1/14/1992 HIGHLANDS L? B3 7/31/2001 18657.pdf 8/22/2001 19443 CRAWFORD REAL ESTATE 77 SB 5 10 8 BBDD 5-Jan S UNKNOWN 21A 1/14/1992 CAHILL TR-4 A 6 GPM, NO WELL LOG 11/28/1995 19652 ALBAUGH, JACK & YVON 5/1/1976 75 SB 5 10 8 CBBB U UNKNOWN 21A 1/14/1992 LEO T OBERTS TR-E 55 FT SWL; 4 GPM PUMP RAT E. NO LOG AVAILABLE. 1/12/1998 19652.pdf 8/22/2001 19862 KAKFA, RALPH 58 SB 5 10 8 BCDD 15-Jan S UNKNOWN 21A 1/14/1992 HIGHLANDS L9 B2 NO WELL LOG 11/22/1995 20111 ELSON,JASON 8/19/1983 58 SB 5 10 8 CBBA 8-Jan S KRAXBERGER DRILLING 21A 1/14/1992 LEO T OBERTS, 1 L02 B1 9/23/1992 20111 ,pdf 3/1/2001 20112 LEACH,KIP 10/20/1982 79 SB 5 10 8 CBDD 11-Jan S B SPIRES DRILLING 21A 1/14/1992 LEO T OBERTS 1 L02 B2 62 FT SWL; 7.55 GPM PUMP RATE. 1/12/1998 20112.pdf 3/1/2001 20113 OWEN,MARK 5/27/1983 95 SB 5 10 8 CBM 10-Jan S UNKNOWN 21A 1/14/1992 LEO T OBERTS 1 L06 B1 9/23/1992 20114 HOLT CONSTRUCTION 5/1/1979 69 SB 5 10 8 CBDB 9-Jan S ECHO LAKE DRILLING 21A 1/14/1992 LEO T OBERTS 1 L 14 B1 9/29/1992 20114.pdf 3/1/2001 20115 RUCKMAN,DICK 9/15/1983 85 SB 5 10 8 CBAC 7-Jan S KRAXBERGER DRILLING 21A 1/14/1992 LEO T OBERTS L 11 B1 9/23/1992 20115.pdf 3/1/2001 24121 GRAVES, GEOFFREY 7/15/1997 98 SB 5 10 8 19 BDAC U NORTHLAND DRILLING 21A 2/11/1998 RIDGEVIEW EST ADD 1 TRCT A 72.5 FT SWL: 15 GPM. 2/12/1998 24121.pdf 12/3/2000 18179 KEMPT, GENE 818/1989 85 SB 5 10 10 DADC 2-Jan S NORTHLAND DRILLING 21A 1/14/1992 MACKEY LAKf': NW L 17 12/2/1992 18179.pdf 10/2/2000 18420 ST JOHN, BOB 9/10/1984 65 SB 5 10 10 DDDD 1-Jan S NORTHLAND DRILLING 21A 1/14/1992 MACKEY LAKE 1 L 15 B05 MACKAY LAKES?? 18420.pelf 10/10/2000 22186 RICHARDSON, ROCKY 30 SB 5 10 10 DACe; U UNKNOWN 21A 6/21/1993 MACKEY LAKENW L 13 B01 NO WELL LOG. 20 FT SWL. 4/15/1998 22186.pdf 5/23/2001 22201 BERNHARDSON, TONNIE 9/15/1983 51 SB 5 10 10 DDCC U UNKNOWN 21A 6/21/1993 MACKEY LAKE L22A B06 NO WELL LOG 10/17/1995 22201.pelf 5/23/2001 22335 ANDERSON, ERIC 1/1/1975 87 SB 5 10 10 U UNKNOWN 21A 8/17/1993 BLM L KENAI AREA NO WELL LOG, 4/2011998 22335.pdf 5/23/2001 22875 BERNHARDSON, GARY 9/24/1992 190 SB 5 10 10 6 DDCC U PENINSULA DRILLING 21A 10/17/1995 MACKEY LAKE' L22A B06 13GPM 11/21/1995 22875.pdf 5/23/2001 2795 SALTZ, CLYDE 9/18/1982 50 SB 5 10 15 ADBD 3-Jan S ECHO LAKE DRILLING 21A 1/14/1992 MACKEY LAKE 1 L 16 B06 11/8/1983 2795.pdf 5/21/2001 8072 3062 GIBBONS, JOHN D 5/17/1984 120 SB 5 10 15 DDBA U ECHO LAKE DRILLING 21A 1/14/1992 GIBBONS L8t\2 48 FT SWL; 20 GPM YIELD. 5f7/1998 18920 McKENNA, JOHN 9/1/1986 67 SB 5 10 15 DD U SMITH WELL DRILLING 21A 1/14/1992 GIBBONS TR A 7/19/2001 18920.pdf 8/22/2001 20090 HISTAND,STAN 7/30/1982 55 SB 5 10 15 MAD 6-Feb S DARC ENTERPRISES 21A 1/14/1992 MACKEY LAKE 1P4 L03 B5 9/2911992 20090.pdf 3/1/2001 20091 BARTLETT,DAN 6/28/1977 58 SB 5 10 15 MAD 6-Jan S KRAXBERGER DRILLING 21A 1/14/1992 MACKEY LAKE: 1 P4 L04 B5 6.7 GPM. 41.4 FT SWL. 4/29/1996 20091.pdf 3/1/2001 20092 YARMAK,ED 8/27/1982 220 SB 5 10 15 ADBB 4-Jan S KENNY CARVER DRILLIN 21A 1/14/1992 MACKEY LAKE 1 L 14 B06 10/6/1992 20092.pelf 3/1/2001 20093 JONES, WENDELL 10/29/1976 45 SB 5 10 15 MCA 2-Feb S UNKNOWN 21A 1/14/1992 MACKEYLAKE,1 P5 TR7 17 FT SWL; 35 GPM YIELD. 12/21/1999 20093.pdf 3/1/2001 20094 FOSSE,BURTON 12/1/1979 44 SB 5 10 15 ADDC 5-Jan S LEO'S DRILLING 21A 1/14/1992 MACKEY LAKE, 1 L03 B06 9/2911992 20094.pdf 3/1/2001 20095 WAITZ,BUD 3/1/1978 49 SB 5 10 15 ADDA 7-Jan S ROCKING H DRILLING 21A 1/14/1992 MACKEY LAKE 1 P2 L 17 B4 9/2911992 20095.pelf 3/1/2001 21653 PARKS, MAR ITA 1/1/1970 65 SB 5 10 15 ADBA U UNKNOWN 21A 11/5/1992 MACKEY LAKE H09 B06 NO WELL LOG. 17 FT SWL. 8 GPM YIELD. 3/511998 21653,pelf 6/25/2001 22197 SALTZ, FLOYD 7/5/1979 47 SB 5 10 15 ADBA U ECHO LAKE DRILLING 21A 6/21/1993 MACKEYLAKE 1 L13 B06 18 FT SWL; 30 GPM. 21911998 22197.pdf 5/23/200 1 ) 22198 MACKEY, BOB SB 5 10 15 AACC U UNKNOWN 21A 6/21/1993 MACKEY LAKE 1 L 15 B06 NO WELL LOG. 4/15/1998 22198.pdf 5/23/2001 Depth = 0 feet 22199 GREEN, WILLIAM 10/28/1977 58 SB 5 10 15 MCD U UNKNOWN 21A 6/21/1993 MACKEY LAKE, L 17 B06 NO WELL LOG. 4/15/1998 22199.pdf 5/23/2001 22200 JONES, WENDELL 5B 5 10 15 14 AACA U UNKNOWN 21A 6/21/1993 MACKEY LAKE 1 P5 L20 B6 NO WELL LOG. 4/15/1998 22200.pdf 5/23/2001 Depth = 0 feet 8069 HAYS ELECTRIC 4f7/1984 34 SB 5 10 16 A U ECHO LAKE DRILLING 21A 1/14/1992 OLD KENAI POWER PLANT 13 FT SWL: 10 GPM YIELD. 2/1/2000 21524 AK DNR AG 84 SB 5 10 16 2 ADBB 2-Jan S UNKNOWN 21A 7/16/1992 SOLDOTNAlCORNER RD. 0 4/13/1993 15762 ALA. HARRY 10/1/1976 160 SB 5 10 17 U LES CREARY 21A 1/14/1992 PINNACLE HILL L2 B1 NO WELL LOG. 3/311998 15762.pdf 10/22/2001 15831 URBAN, DAVE 9/25/1984 97 SB 5 10 17 BBB U KRAXBERGER DRILLING 21A 1/14/1992 THOROUGHBRED ACRES L 1 76 FT SWL: 25 GPM. OPEN END. 7/2311998 15831.pdf 1 0/22/200 1 16224 SOLDOTNA ASMBL YIGOD 6/14/1983 131 SB 5 10 17 BACD 7-Jan S KRAXBERGER DRILLING 21A 1/14/1992 KELLY PARKL23 B1 9.5 GPM. 4/29/1996 16224.pdf 8/31/2000 16300 EIGHMIE, RICHARD 8/24/1983 134 SB 5 10 17 BABD 8-Jan S KRAXBERGER DRILLING 21A 1/14/1992 KELLY PARI<L06 B1 SW 102 FT LS, 40 GPM FULL CASE, SCREEN 129-134 FT NEW OWNER: EIGHMIE R 10/3/2001 16300.pelf 8/31/2000 18144 JEFFERSON, JEFF SB 5 10 17 U UNKNOWN 21A 1/14/1992 ROY WOODS HOMESTEAD TR-2A NO WELL LOG. 3/4/1998 18144.pdf 8/22/2001 Depth = 0 feet 18484 TACHICK. BOB 8/4/1988 127 SB 5 10 17 CB U KRAXBERGER DRILLING 21A 1/14/1992 LANCASHIRE RD SOLDOTNA 8/3/2001 18484.pdf 8/22/2001 18877 DEES, AUBRA 10/4/1987 124 SB 5 10 17 BA U SMITH WELL DRILLING 21A 1/14/1992 KELLY PARK1.12 B1 7120/2001 18877.pdf 8/22/2001 19863 BETENBENDER, DANIEL 9/6/1983 150 SB 5 10 17 DMC 9-Jan S C & M DRILLING 21A 1/14/1992 HIRIDGE L04,ß1 11/4/1994 19863.pdf 1/8/2001 19864 COOPER, TIM 7/30/1985 134 SB 5 10 17 DABC 10-Jan S DARC ENTERPRISES 21A 1/14/1992 HIRIDGE L06A 81 11/4/1994 19864.pdf 1/8/2001 19865 DOUGLAS, DON & LORI 8/12/1985 166 SB 5 10 17 DACD 11-Jan S DARC ENTERPRISES 21A 1/14/1992 HIRIDGE L01 82 10/26/1994 19865.pdf 1/8/2001 21113 DONAHUE, CLAIRE 1/1/1979 30 SB 5 10 17 CDDA U UNKNOWN 21A 5/5/1992 WOODCREST EST L 14 B1 NO WELL LOG. 3/5/1998 21113.pdf 6/25/2001 21114 UNKNOWN SB 5 10 17 CD DB U UNKNOWN 21A 5/5/1992 WOODCREST EST L13 B1 NO WELL LOG. 3/5/1998 21114.pdf 6/25/2001 Depth = 0 feet 21115 DIXON, WILLIAM 129 SB 5 10 17 CDAB U UNKNOWN 21A 5/5/1992 WOODCREST EST L 10 B1 NO WELL LOG. 3/5/1998 21115.pelf 6/25/2001 21116 ANDERSON, DENNIS 160 SB 5 10 17 CDAD U UNKNOWN 21A 5/5/1992 WOODCREST EST L05 B1 NO WELL LOG. 3/5/1998 21116.pelf 6/25/2001 21117 KIMBELL. JIM 10/1/1981 166 SB 5 10 17 CDDD U BENNET, REX 21A 5/511992 WOODCREST EST L02 B1 NO WELL LOG. 3/5/1998 21117.pelf 6/25/2001 21118 GOODRICH, DAVID 6/5/1980 104 SB 5 10 17 CDDA U BENNET, REX 21A 5/5/1992 WOODCREST EST 1 L03 B1 NO WELL LOG. 140 FT SWL. 7 GPM YIELD. 315/1998 21118.pdf 6/25/2001 21131 SCHNEIDER, PAUL 144 SB 5 10 17 CDAB U UNKNOWN 21A 5/5/1992 WOODCREST EST L08 B2 NO WELL LOG. 3/5/1998 21131.pelf 6/25/2001 21132 HOLDEN, PETE 146 SB 5 10 17 CDCA U UNKNOWN 21A 5/5/1992 WOODCREST EST L04 B2 NO WELL LOG. 3/5/1998 21132.pdf 6/25/2001 21133 POINT VIEW REALTY 125 SB 5 10 17 CDDB U UNKNOWN 21A 5/5/1992 WOODCREST EST 1 L03 B2 NO WELL LOG 11/21/1995 21133.pelf 6/25/2001 21134 FURLONG, PAM & JOHN 5B 5 10 17 CDDC U UNKNOWN 21A 5/5/1992 WOODCREST EST 1 L02 B2 5.85 GPM. NO WELL LOG. 3/5/1996 21134.pdf 6/25/2001 Depth = 0 feet 21135 BLAYTON, HARVEY 158 SB 5 10 17 CDDC U UNKNOWN 21A 5/5/1992 WOODCREST EST L 15 B1 NO WELL LOG. 3/5/1998 21135.pdf 6/25/2001 22255 SHANAHAN, TOM 1/1/1978 160 SB 5 10 17 DDBD U UNKNOWN 21A 7/12/1993 HIRIDGE L 12 61 NO WELL LOG. 137 FT SWL. 6,7 GPM YIELD, 4/17/1998 22255.pdf 5/23/2001 22960 MILLER. PAUL 8/24/1995 134 SB 5 10 17 BCCB U NORTHLAND DRILLING 21A 11/13/1995 HORN L01 20 GPM 11/2111995 22960.pdf 5/23/2001 23866 WATERBURY, ROCKY 9/20/1996 130 SB 5 10 17 24 BMC U PENINSULA DRL 21A 10/23/1997 KELLy PARK L 16 B1 104.5 FT SWL: 17 GPM. 11/24/1997 23866.pelf 12/3/2000 AVERAGE 152 ~ec. 0 wells) DEPTH 93 ft. 152 Wells with Depth of 0 MINIMUM feet DEPTH 21 fl. ######## MAXIMUM 146 in Statistics DEPTH 230 fl. AVERAGE 117 9 Section 9 DEPTH 94 fl. Wells with Depth of 0 MINIMUM feet DEPTH 21 fl. Use this data (March 20. 2002) MAXIMUM 111 in Statistics DEPTH 220 fl. Appendix B WEL T3 spreadsheet.xls 11/2012002 Appendix B Topographic Map with Adjacent Sections Indicating Number of Welts Wells » "0 "2.. ë')" Q) - õ· ::¡ ...., o ..., Q) o ür "0 o if) ~ o ..., a. ( ) ..., I $: Q) ..., Q) s: o ::¡ o () o 3 "0 Q) ::¡ '< "'tJ» Q)"o (Q "0 ( ) ( ) .¡::...::¡ a. 0-· ....,x .¡::...OJ References Application for a DiSPOajection Order - Marathon Oil Company e References · REFERENCES Alaska Department of Natural Resources, Division of Mining, Land and Water, n.d., Alaska Hydrologic Survey, Well Log Trackinq System, <http://info.dec.state.ak.us/welts/>(March 20, 2002). Alaska Oil and Gas Conservation Commission, 1999, Regulations, Alaska Administrative Code, "20 AAC 25.440," <http://www.state.ak.us/local/akpaqes/ADMIN/ oqc/art599.htm#440> (November 7,2001). Marathon Oil Company, 2002, Aquifer Exemption Order, Sterling Gas Field Unit, Kenai Peninsula, Alaska, October 2002. United States Environmental Protection Agency, 1998, Code of Federal Regulations, "40 CFR 144-148," Office of the Federal Register National Archives and Records Administration, Washington, D.C., pp. 614-833. · · O:\Sterling\43-9\UIC\2002 Applications\Disposallnjection\DIO References.doc 11/21/2002
