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Home My WebLink AboutDIO 040DISPOSAL INJECTION ORDER 40 Sterling Formation Undefined waste disposal pool Beaver Creek Unit No. 3R.D Well Beaver Creek Unit 1. October 29, 2014 Hilcorp's DIO application 2. November 14, 2014 Notice of hearing, affidavit of publication, email distribution, mailings 3. January 6, 2015 Transcript, sign -in sheet, exhibit 4.-------------------- Emails: Request to Reactivate DIO 8 Using BCU 03RD 5.-------------------- Annual reports ORDERS STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 71h Avenue, Suite 100 Anchorage, Alaska 99501 Re: THE APPLICATION OF Hilcorp Alaska, LLC. for disposal of Class II oil field wastes by underground injection in the Sterling Formation in well Beaver Creek Unit No. 3RD, (PTD 2030440) Section 34, T7N, R10W, S.M. IT APPEARING THAT: Disposal Injection Order No. 40 Sterling Formation, Undefined waste disposal pool Beaver Creek Unit No. 3RD Well Beaver Creek Unit March 2, 2015 Hilcorp Alaska, LLC (Hilcorp) requested authorization for underground disposal of Class II oil field waste fluids into well Beaver Creek Unit No. 3 Re -drill (BCU 3RD) (PTD 2030440). Hilcorp's Application for Disposal Injection Order was received by the Alaska Oil and Gas Conservation Commission (AOGCC) on October 29, 2014. 2. Pursuant to 20 AAC 25.540, the AOGCC scheduled a public hearing for January 6, 2015. On November 17, 2014, the AOGCC published notice of the opportunity for that hearing on the State of Alaska's Online Public Notice website and on the AOGCC's website and electronically transmitted the notice to all persons on the AOGCC's email distribution list. On November 18, 2014, the notice was published in the ALASKA DISPATCH NEWS. 3. At the January 6, 2015 hearing Hilcorp provided testimony and presented evidence in support of its Application. The hearing record was left open for two weeks to allow Hilcorp to provide additional information requested by the AOGCC. Disposal Injection Order 40 Beaver Creek Unit No. 3RD March 2, 2015 FINDINGS: Page 2 of 9 The following are based upon the evidence submitted by Hilcorp, the testimony at the hearing, public records pertaining to Disposal Injection Order 4 (DIO 4), and Beaver Creek wells. 1. History of Wells BCU 3 and BCU 3RD During 1968, BCU 3 was drilled directionally to a measured depth (MD) of 6,387 feet and a true vertical depth (TVD) of 5,418 feet and completed as a development gas well in the Beaver Creek Unit Sterling Gas Pool. BCU 3 produced gas from September 1982 through October 1988. In December 1988, all perforations were squeezed with cement, and in November 1989 the well head was replaced with a dry -hole tree. On May 13, 1993, the AOGCC issued Disposal Injection Order No. 8 (DIO 8), which authorized disposal of Class II oil field fluids by underground injection in well BCU 3. In July 1994, the operator re-entered BCU 3, perforated the Sterling Formation B-IB sandstone from 5,910 to 5,940 feet MD (5,082 to 5,106 feet TVD), and re -completed the well as a Class II waste disposal injection well. BCU 3 was shut-in from July 1995 through May 2005; no injection volumes were reported for this well. During May 2003, the Sterling B-1B sand perforations in BCU 3 were plugged, the well was re -named BCU 3RD (PTD 2030440), re-entered, and deepened to 10,005 feet MD (8,713 feet TVD) to access gas reserves in the underlying Beluga Gas Pool. In June and July of 2003, BCU 3RD was perforated in several lower Beluga sandstone layers, fracture - stimulated, and completed as a development gas well. In April and May of 2005, a cast-iron bridge plug was set at 9,570' MD (7,969' TVD) to plug off the Beluga B28d sandstone, the suspected source of water, sand and coal production. Additional perforations were shot in the overlying B22 and B23 lower Beluga sandstones, and regular gas production began in June 2005. BCU 3RD was unable to sustain flow. The last reported regular gas production from BCU 3RD was during February 2006. BCU 3RD was shut-in in March 2006, with the single exception of 17,000 cubic feet of gas production reported in February 2013. Hilcorp proposes to convert BCU 3RD to a Class II disposal well by plugging back all Beluga perforations and perforating the shallower, Sterling Formation B 1 L and B2 sandstones between 5,804 and 5,945 feet MD (4,997 and 5,110 feet TVD). 2. Location of Wells BCU 3 and BCU 3RD BCU 3 and the redrill BCU 3RD have the same surface location, which is 1,227 feet from the north line and 1,501 feet from the west line of Section 34, Township 7 North, Range 10 West, Seward Meridian (SM). The top of the injection interval will lie about 700 feet from the south line and 1,700 feet from the west line of Section 27, Township 7 North, Range 10 West, SM. The proposed injection zone within BCU 3RD lies more than 1,850 horizontal feet from the nearest point on the Beaver Creek Unit boundary. Disposal Injection Order 40 Beaver Creek Unit No. 3RD March 2, 2015 Page 3 of 9 Location of Adjacent Wells (20 AAC 25.252(c)(1)) Beaver Creek Unit No. 18 is the only well that penetrates the proposed injection zone within a 1/4-mile radius of BCU 3RD. 3. Notification of Operators/Surface Owners (20 AAC 25.252(c)(2) and 20 AAC 25.252(c)(3)) Hilcorp is the only operator within a 1/4-mile radius of the proposed disposal well. Surface property owners within 1/4-mile radius of BCU 3RD are U.S Bureau of Land Management (BLM) and U.S. Fish and Wildlife Service (FWS). Hilcorp has provided a copy of the AOGCC Application for Sundry Approval to BLM. This Disposal Injection Order does not exempt Hilcorp from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting disposal injection operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the order in the event it was erroneously issued. 4. Geological Information on Disposal and Confining Zones (20 AAC 25.252(c)(4)) The proposed disposal injection operations will affect strata that are assigned to the Pliocene - aged Sterling Formation. The Sterling Formation consists of massively bedded, predominately coarse -grained, moderate to well -sorted, fluvial sandstone with minor amounts of conglomerate. Hilcorp plans injection within the permeable Sterling Formation B 1 L and B2 sandstones, which have calculated porosities of approximately thirty percent. These two sandstones are present within BCU 3RD from approximately 5,804 to 5,945 feet MD (4,997 and 5,110 feet TVD). Upper confinement for the proposed injection interval consists of numerous, laterally continuous layers of claystone, siltstone, and coal that lie within the Sterling Formation between 2,132 and 5,649 feet MD (2,024 and 4,873 feet TVD). These confining layers, which range in thickness from 3 to 28 true vertical feet, have a combined true vertical thickness of about 235 feet, and will serve as effective barriers to prevent vertical migration of injected fluids. Lower confinement will be provided by numerous, laterally continuous layers of claystone, siltstone and coal within the Sterling Formation between 5,945 and 6,250 feet MD (4,997' and 5,353' TVD). Structure maps provided by Hilcorp do not display any faults within 4,000 horizontal feet of the planned injection interval. 5. Evaluation of Fluid Confinement (20 AAC 25.252(c)(9)) The porous and permeable nature of the Sterling B 1 L and B2 sandstones allows injection of produced water at pressures that are lower than formation -fracture pressure. This has been observed in the existing BCU 2 Class II well, which has a cumulative injection total of 1.1 million barrels. Since prolonged injection of produced water will result in the accumulation of solids near the BCU 3RD wellbore, it will be occasionally necessary to fracture the injection interval to by-pass these solids by increasing injection pressure. Fracturing in this case is expected to remain within the injection interval. Disposal injection of produced water, drilling mud, slurried cuttings, and other Class II oil- field wastes will require pressure sufficient to fracture the Sterling Formation. Marathon Oil Disposal Injection Order 40 Beaver Creek Unit No. 3RD March 2, 2015 Page 4 of 9 Company (Marathon), the previous operator of the Beaver Creek Unit, planned to inject produced water and other Class II wastes into the same disposal interval. Marathon provided a three-dimensional hydraulic fracture model of the strata at Beaver Creek using lithology, stress variations, pore pressure, and rock elastic properties to simulate hydraulically induced fracture growth that will occur when drilling mud and slurried drill cuttings are injected above formation pressure. Under the "most likely" scenario, fracture growth height was limited to about 4,200 feet TVD within the middle Sterling which is about 2,550 true vertical feet below the top of the exempt aquifers (at 1,650 feet below ground surface). Under the "worst -case" scenario, fracture growth height extended to about 3,600 feet TVD, which is about 1,950 true vertical feet below the top of the exempt aquifers. Future wells within 1/4-mile must be constructed to ensure they do not serve as a conduit for fluid migration from the disposal zone. 6. Aquifer Exemption (20 AAC 25 252(c)(I IA Standard Laboratory Water Analysis of the Formation (20 AAC 25.252(c)(10)) The portions of aquifers at depths greater than 1,650 feet below the ground surface, extending one -quarter mile beyond and lying directly below the Beaver Creek Field are exempted pursuant to 40 CFR 147.102(b)(1)(ii). 7. Well Logs (20 AAC 25.252(c)(5)) Log data from BCU 3 and BCU 3RD are on file with the AOGCC. 8. Demonstration of Mechanical Integrity and Disposal Zone Isolation (20 AAC 25.252(c)(6)) Thirteen and 3/8-inch surface casing was set at 533 feet MD, cemented to surface and tested to 1000 psi. Intermediate 9 5/8-inch casing was set at 1,569 feet MD, cemented to surface and tested to 1,000 psi. The 7-inch production casing was set at 6,380 feet MD, cemented to approximately 3,300 feet MD and tested to 1,000 psi. Analysis of cement bond logs indicates casing strings have adequate cement behind casing to prevent vertical migration of disposal fluids. A casing mechanical integrity test will be performed in accordance with 20 AAC 25.412 prior to re -initiation of disposal operations. Hilcorp will perform mechanical integrity tests of the tubing and tubing -casing annulus (including packer) as part of the workover operations before injection recommences. Additional baseline assessments and subsequent evaluations may be necessary to confirm the well has the proper mechanical integrity for disposal injection as proposed. The operator will monitor the 7-inch casing by 3 1/2-inch tubing annulus pressure daily and report the results on the Monthly Injection Report. Disposal Injection Order 40 Page 5 of 9 Beaver Creek Unit No. 3RD March 2, 2015 9. Disposal Fluid Type Composition Source Volume and Compatibility with Disposal Zone (20 AAC 25.252(c Q Hilcorp requests approval to dispose of drilling, production, completion, workover wastes, and other associated wastes that are intrinsically derived from primary field operations. Hilcorp expects daily injection volumes of 1000 up to 7,200 barrels, with rates up to 6 barrels per minute, and slurry densities up to 10.5 pounds per gallon. Injected fluids are expected to be compatible with the lithology and resident water of the injection zone based on operating experience and performance (e.g., pressures, rates, and volumes) of the BCU 3RD well during previous disposal operations. There have not been any reported compatibility issues associated with disposal injection into the Sterling or Beluga Formation at this or other fields in the Cook Inlet area. 10. Estimated Injection Pressures (20 AAC 25.252(c)(8)) Hilcorp estimates that the average surface injection pressure will be between 1,600 prig for water disposal operations and 3,000 psig. The maximum surface injection pressure could reach 5,000 psig if sporadic plugging of perforations or fracture flow channels occurs, which is the maximum pressure rating of the casing head. 11. Mechanical Condition of Wells Penetrating the Disposal Zone Within a 1/4-Mile Radius of Kenai Loop #3 (20 AAC 25.252(c)(12)) BCU 18 is the only well to penetrate the proposed disposal injection zone within '/4-mile radius of BCU 3RD. Well construction records show that both the injection well and the BCU 18 are cased and cemented to prevent the movement of injected fluids beyond the well's confinement zones. Records documenting the drilling, casing, cementing, and testing of these wells are in the AOGCC's files. CONCLUSIONS: 1. The requirements of 20 AAC 25.252 for approval of an underground disposal application are met. 2. BCU 3 was drilled in 1968 as a Sterling Formation gas production well. BCU 3 was converted to an authorized disposal well in May 1993. BCU 3 was deepened in 2003, re- named BCU 3RD, and produced gas from the Beluga Formation. Hilcorp will isolate the lower portion of BCU 3RD and convert the well to disposal injection in the Sterling Formation. 3. Hilcorp's planned injection interval in BCU 3RD consists of the Sterling B I L and 132 sands that lie between 5,804 and 5,945 feet MD (4,997 and 5,110 feet TVD), an interval that is about 113 true vertical feet thick. 4. Upper confinement will be provided by a combined 235 true vertical feet of laterally continuous claystone, siltstone, and coal layers within the Sterling Formation. Disposal Injection Order 40 Page 6 of 9 Beaver Creek Unit No. 3RD March 2, 2015 5. Lower confinement and fracture arrest will be provided by 356 true vertical feet of laterally continuous layers of Sterling Formation claystone, siltstone, and coal. 6. No significant faults are present that could be affected by the proposed injection operations. 7. The portions of aquifers at depths greater than 1,650 feet below the ground surface, extending one -quarter mile beyond and lying directly below the Beaver Creek Field are exempted by 40 CFR 147.102(b)(1)(ii). 8. No compatibility concerns relating to the injected fluids and in -situ formation fluids have been identified in connection with the injection of a similar waste fluid streams into the Sterling Formation at this site and other locations within the Cook Inlet Basin. 9. Fracture modeling indicates that disposed waste fluids will be contained within the receiving interval by confining lithologies, cement isolation of the well bore, and planned operating conditions. Modeling of the most extreme injection conditions predicts that fractures will not penetrate the upper confining zone, or breach the lower confining zone. 10. Supplemental mechanical integrity demonstrations and the surveillance of injection operations —including baseline and subsequent temperature surveys, monitoring of injection performance (i.e., pressures and rates), and analyses of the data for indications of anomalous events —are appropriate to ensure that waste fluids remain within the disposal interval. 11. Actual performance information gained during injection and remedial well operations must be monitored during the life of the disposal project to ensure appropriate operation of the field. A requirement for formal review of the disposal injection performance every five years will ensure the findings, conclusions, and rules of this order remain valid. 12. Future wells within 1/4-mile of the injection interval in BCU 3RD must be constructed to ensure they do not serve as a conduit for fluid migration from the disposal zone. NOW, THEREFORE, IT IS ORDERED THAT disposal injection is authorized into the Sterling Formation within well Beaver Creek Unit No. 3RD subject to each of the following requirements: RULE 1: Iniection Strata for Disposal The underground disposal of Class II oil field waste fluids is permitted into the Sterling Formation within BCU 3RD in the interval from 5,804 feet to 5,945 feet MD (4,997 feet to 5,110 feet TVD). RULE 2: Authorized Fluids This authorization is limited to Class II oil field waste fluids generated during drilling, production, workover, or abandonment operations, specifically: Drilling fluids; drill cuttings; well workover fluids; stimulation fluids and solids; produced water; rig wash water; formation materials; naturally occurring radioactive materials; scale; tracer materials; glycol dehydration; reserve pit fluids; chemicals used in the well or for production processing at the surface (in direct contact with produced fluids); and precipitation accumulating in drilling and production impoundment areas. Disposal Injection Order 40 Page 7 of 9 Beaver Creek Unit No. 3RD March 2, 2015 AOGCC approval is required prior to initiating commercial Class II disposal injection in BCU 3RD. RULE 3: Iniection Rate and Pressure Injection pressures must be maintained such that the injected fluids do not fracture the confining intervals or migrate out of the approved injection stratum. Disposal injection is authorized at (a) rates that do not exceed 6 barrels per minute and (b) wellhead injection pressures that do not exceed 5,000 psig. RULE 4: Demonstration of Mechanical Integrity The mechanical integrity of BCU 3RD must be demonstrated before injection begins and before returning the well to service following a workover affecting mechanical integrity. An AOGCC- witnessed mechanical integrity test must be performed after injection is commenced for the first time in BCU 3RD, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent mechanical integrity tests must be performed at least once every two years after the date of the first AOGCC-witnessed test if the well injects solids laden slurries, and at least once every four years if the well only injects solids -free fluids. Mechanical integrity tests must be conducted in accordance with AOGCC Industry Guidance Bulletin No. 10-02A, "Mechanical Integrity Testing". The AOGCC must be notified at least 24 hours in advance of each such test to enable a representative to witness the test. The results of all mechanical integrity demonstrations and Hilcorp's interpretation of those results shall be provided to the AOGCC no later than the 5th calendar day of the month following the testing. RULE 5: 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 any other evidence, the Operator shall notify the AOGCC within 24 hours and submit a plan of corrective action on a Form 10-403 for AOGCC approval. The Operator shall immediately shut in the well if continued operation would be unsafe or threaten contamination of freshwater, or if so directed by the AOGCC. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC for BCU 3RD if the well indicates any well integrity failure or lack of injection zone isolation. RULE 6: 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 BCU 3RD must be documented and available to the AOGCC 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. Disposal Injection Order 40 Page 8 of 9 Beaver Creek Unit No. 3RD March 2, 2015 A report evaluating the performance of the disposal operation must be submitted to the AOGCC by April 1 of each year covering injection operations during the previous calendar year. The report shall include data sufficient to characterize the disposal operation, including, among other information, the following: injection and annuli pressures (i.e., daily average, maximum, and minimum pressures); fluid volumes injected (i.e., in disposal and clean fluid sweeps); injection rates; an assessment of the fracture geometry; a description of any anomalous injection results; and a calculated zone of influence for the injected fluids. An assessment of the applicability of the injection order findings, conclusions, and rules based on actual performance shall be included with the annual performance report. RULE 7: Notification of Improper Class II Injection Injection of fluids other than those listed in Rule 2 without prior authorization is considered improper Class II injection. Upon discovery of such an event, the operator must immediately notify the AOGCC, provide details of the operation, and propose actions to prevent recurrence. Additionally, notification requirements of any other State or Federal agency remain the operator's responsibility. If fluids are found to be fracturing through a confining interval or migrating out of the approved injection stratum, the operator must immediately shut in the well. Upon discovery of such an event, the operator must immediately notify the AOGCC, provide details of the operation, and propose actions to prevent recurrence. Injection may not be restarted unless approved by the AOGCC. RULE 8: Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater or outside of the authorized injection zone. RULE 9: Compliance Operations must be conducted in accordance with the requirements of this order, AS 31.05, and (unless specifically superseded by AOGCC order) 20 AAC 25. Noncompliance may result in the suspension, revocation, or modification of this authorization and other penalties. RULE 10: Reauthorization The Operator must apply to reauthorize disposal injection at intervals not exceeding five years from the effective date of this Order. The application shall include an assessment of the Order findings, conclusions, and rules taking into account actual injection performance. Disposal Injection Order 40 Beaver Creek Unit No. 3RD March 2, 2015 DONE at Anchorage, Alaska, and dated March 2, 2015. a�zj i1-�23,-� 4- Cathy P. Foerster Chair, Commissioner &/I�/ Daniel ySeamount, Jr. Commissioner TION AND APPEAL NOTICE Page 9 of 9 As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Singh, Angela K (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, March 03, 2015 9:11 AM To: Larry Greenstein (Ireenstein@hilcorp.com); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Gallagher, Mike (DOA); Guhl, Meredith D (DOA); Hunt, Jennifer L (DOA); Kair, Michael N (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AKDCWellIntegrityCoordinator; Alexander Bridge; Allen Huckabay; Andrew VanderJack, Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Bill Walker; Bob Shavelson; Brian Havelock, Burdick, John D (DNR); Carrie Wong; Cliff Posey, Colleen Miller, Crandall, Krissell; D Lawrence; Dave Harbour, David Boelens; David Duffy, David Goade; David House; David McCaleb; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Francis S. Sommer, Frank Molli; Gary Oskolkosf, George Pollock, ghammons; Gordon Pospisil; Greg Duggin; Gregg Nady; gspfoff, Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW); Jim Watt, Jim White; Joe Lastufka; news@radiokenai.com; John Adams; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek, Houle, Julie (DNR); Julie Little; Kari Moriarty; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker, Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt, Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; MJ Loveland; mjnelson; mkm7200; Morones, Mark P (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly, Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Sternicki, Oliver R; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler, Tim Mayers; Todd Durkee; Tony Hopfinger, trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Walter Featherly; yjrosen@ak.net; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater; Anne Hillman; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr, Smith, Graham O (PCO); Greg Mattson; Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; James Rodgers; Jason Bergerson; Jennifer Starck; jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey, King, Kathleen J (DNR); Laney Vazquez, Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pexton, Scott R (DNR); Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster; William Hutto; William Van Dyke Subject: AIO 5.006 Cancellation and DIO 40 Attachments: aio5-006 cancellation.pdf, dio40.pdf AIO 5-006 Cancellation - McArthur River Field (Hilcorp) DIO 40 - Beaver Creek Field (Hilcorp) Jody J. Colombie Special Staff Assistant Alaska Oil and Gas Conservation Commission 333 West 70, Avenue Anchorage, Alaska 99501 Jodu.Colombie(plaska.gov Office: (907) 793-1221 Fax: (907) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iody.colombie@alaska.gov James Gibbs Jack Hakkila Bernie Karl Post Office Box 1597 Post Office Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 Post Office Box 58055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. Post Office Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Richard Wagner Darwin Waldsmith Mr. Larry Greenstein Post Office Box 60868 Post Office Box 39309 Hilcorp Alaska, LLC Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 244027 Anchorage, AK 99524-4027 t "l k-6 fv%arcl"- -IL , 20l5 Angela K. Singh INDEXES Hilcorp Alaska, LLC 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone: 907-777-8300 Fax: 907-777-8310May 1, 2020 Ms. Jessie Chmielowski Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RE:RULE 6,DIO 40:BCU-03RD Dear Ms. Chmielowski: Attached please find the surveillance report required by Rule 6 of DIO 40 establishing the DIO for the Class II Water Disposal well BCU-03RD (PTD 2030440)for the calendar year of 2019. Injection and Annuli Pressures Injection volumes and annuli pressures are displayed on the plot in attachment 1. Maximum injection rates and pressures are well below those required by rule 3 and the injection index data indicates confinement of injection to the approved intervals. Last Mechanical Integrity test:April 4, 2019 When actively injecting,BCU-03RD disposes of water only and is therefore on a four year MIT cycle. The next MIT is due April 2023. Fracture Geometry BCU-03RD disposes of Class II waste in the B1L & B2 sands of the Sterling section in Sterling Gas Unit.Fracture orientation in BCU-03RD is expected to be vertical and confined by approximately over 200’ thick bounding layers above and below the injection strata. This has been proven by previous temperature logs and by openhole log derived rock mechanics properties. Sincerely, Trudi Hallett Reservoir Engineer Date Tubing IA OA OOA 1/1/2020 0 150 20 12/31/2019 0 150 20 12/30/2019 0 150 20 12/29/2019 0 150 20 12/28/2019 0 150 20 12/27/2019 0 150 20 12/26/2019 0 150 20 12/25/2019 0 150 20 12/24/2019 0 150 20 12/23/2019 0 150 20 12/22/2019 0 150 20 12/21/2019 0 150 20 12/20/2019 0 150 20 12/19/2019 0 150 20 12/18/2019 0 150 20 12/17/2019 0 150 20 12/16/2019 0 150 20 12/15/2019 0 150 20 12/14/2019 0 150 20 12/13/2019 0 150 20 12/12/2019 0 150 20 12/11/2019 0 150 20 12/10/2019 0 150 20 12/9/2019 0 150 20 12/8/2019 0 150 20 12/7/2019 0 150 20 12/6/2019 0 140 35 12/5/2019 0 140 35 Date Range: 01/01/2019 - 01/01/2020 Well: BCU 03RD Desc: Shut-In Permit to drill: 2030440 Admin Approval: DIO #40 API: 50-133-20124-01-00 12/4/2019 0 140 35 12/3/2019 0 140 35 12/2/2019 0 140 35 12/1/2019 0 140 35 11/30/2019 0 140 35 11/29/2019 0 140 35 11/28/2019 0 140 35 11/27/2019 0 140 35 11/26/2019 0 140 35 11/25/2019 0 140 35 11/24/2019 0 140 35 11/23/2019 0 140 35 11/22/2019 0 140 35 11/21/2019 0 140 35 11/20/2019 0 140 35 11/19/2019 0 140 35 11/18/2019 0 140 35 11/17/2019 0 160 35 11/16/2019 0 160 35 11/15/2019 0 160 35 11/14/2019 0 160 35 11/13/2019 0 160 35 11/12/2019 0 160 35 11/11/2019 0 160 35 11/10/2019 0 160 35 11/9/2019 0 160 35 11/8/2019 0 160 35 11/7/2019 0 160 35 11/6/2019 0 160 35 11/5/2019 0 160 35 11/4/2019 0 160 35 11/3/2019 0 160 35 11/2/2019 0 160 25 11/1/2019 0 160 25 10/31/2019 0 160 25 10/30/2019 0 160 25 10/29/2019 0 160 25 10/28/2019 0 160 25 10/27/2019 0 160 25 10/26/2019 0 160 25 10/25/2019 0 160 25 10/24/2019 0 160 25 10/23/2019 0 160 25 10/22/2019 0 160 25 10/21/2019 0 160 25 10/20/2019 0 160 25 10/19/2019 0 160 25 10/18/2019 0 160 25 10/17/2019 0 160 25 10/16/2019 0 160 25 10/15/2019 0 160 25 10/14/2019 0 170 25 10/13/2019 0 180 22 10/12/2019 0 180 22 10/11/2019 0 180 22 10/10/2019 0 180 22 10/9/2019 0 180 22 10/8/2019 0 180 22 10/7/2019 0 180 22 10/6/2019 0 180 22 10/5/2019 0 180 22 10/4/2019 0 180 22 10/3/2019 0 180 22 10/2/2019 0 180 22 10/1/2019 0 180 22 9/30/2019 0 180 22 9/29/2019 0 180 22 9/28/2019 0 180 22 9/27/2019 0 180 22 9/26/2019 0 180 22 9/25/2019 0 180 22 9/24/2019 0 180 22 9/23/2019 0 180 22 9/22/2019 0 180 22 9/21/2019 0 180 22 9/20/2019 0 180 22 9/19/2019 0 180 22 9/18/2019 0 180 22 9/17/2019 0 180 22 9/16/2019 0 180 22 9/15/2019 0 180 22 9/14/2019 0 180 22 9/13/2019 0 180 22 9/12/2019 0 180 22 9/11/2019 0 180 22 9/10/2019 0 180 22 9/9/2019 0 180 22 9/8/2019 0 180 22 9/7/2019 0 180 22 9/6/2019 0 180 22 9/5/2019 0 200 25 9/4/2019 0 200 25 9/3/2019 0 200 25 9/2/2019 0 200 25 9/1/2019 0 200 25 8/31/2019 0 200 25 8/30/2019 0 200 25 8/29/2019 0 200 25 8/28/2019 0 200 25 8/27/2019 0 200 25 8/26/2019 0 200 25 8/25/2019 0 200 25 8/24/2019 0 200 25 8/23/2019 0 200 25 8/22/2019 0 200 25 8/21/2019 0 200 25 8/20/2019 0 200 25 8/19/2019 0 200 25 8/18/2019 0 200 25 8/17/2019 0 200 25 8/16/2019 0 200 25 8/15/2019 0 200 20 8/14/2019 0 200 0 8/13/2019 0 200 0 8/12/2019 0 200 0 8/11/2019 0 200 0 8/10/2019 0 200 0 8/9/2019 0 200 0 8/8/2019 0 200 0 8/7/2019 0 200 0 8/6/2019 0 200 0 8/5/2019 0 200 0 8/4/2019 0 200 0 8/3/2019 0 200 0 8/2/2019 0 200 0 8/1/2019 0 200 0 7/31/2019 0 200 0 7/30/2019 0 200 0 7/29/2019 0 200 0 7/28/2019 0 200 0 7/27/2019 0 200 0 7/26/2019 0 200 0 7/25/2019 0 200 0 7/24/2019 0 200 0 7/23/2019 0 200 0 7/22/2019 0 200 0 7/21/2019 0 200 0 7/20/2019 0 200 0 7/19/2019 0 200 0 7/18/2019 0 200 0 7/17/2019 0 200 0 7/16/2019 0 200 0 7/15/2019 0 200 0 7/14/2019 0 200 0 7/13/2019 0 200 0 7/12/2019 0 200 0 7/11/2019 0 200 0 7/10/2019 0 200 0 7/9/2019 0 200 0 7/8/2019 0 200 0 7/7/2019 0 200 0 7/6/2019 0 200 0 7/5/2019 0 200 0 7/4/2019 0 200 0 7/3/2019 0 200 0 7/2/2019 0 200 0 7/1/2019 0 200 0 6/30/2019 0 200 0 6/29/2019 0 200 0 6/28/2019 0 200 0 6/27/2019 0 200 24 6/26/2019 0 200 24 6/25/2019 0 200 24 6/24/2019 0 200 24 6/23/2019 0 200 24 6/22/2019 0 200 24 6/21/2019 0 200 24 6/20/2019 0 200 24 6/19/2019 0 200 24 6/18/2019 0 200 24 6/17/2019 0 200 24 6/16/2019 0 200 24 6/15/2019 0 200 24 6/14/2019 0 200 24 6/13/2019 0 200 24 6/12/2019 0 200 24 6/11/2019 0 200 24 6/10/2019 0 200 24 6/9/2019 0 200 24 6/8/2019 0 200 24 6/7/2019 0 200 24 6/6/2019 0 200 24 6/5/2019 0 200 24 6/4/2019 0 200 24 6/3/2019 0 200 24 6/2/2019 0 200 24 6/1/2019 0 200 24 5/31/2019 0 200 24 5/30/2019 0 200 24 5/29/2019 0 200 24 5/28/2019 0 200 24 5/27/2019 0 200 24 5/26/2019 0 200 24 5/25/2019 0 200 24 5/24/2019 0 200 24 5/23/2019 0 200 24 5/22/2019 0 200 24 5/21/2019 0 200 24 5/20/2019 0 200 24 5/19/2019 0 200 24 5/18/2019 0 200 24 5/17/2019 0 200 24 5/16/2019 0 200 24 5/15/2019 0 200 24 5/14/2019 0 200 24 5/13/2019 0 200 24 5/12/2019 0 200 24 5/11/2019 0 200 24 5/10/2019 0 200 24 5/9/2019 0 200 24 5/8/2019 0 200 24 5/7/2019 0 200 24 5/6/2019 0 200 24 5/5/2019 0 200 24 5/4/2019 0 200 24 5/3/2019 0 200 24 5/2/2019 0 200 24 5/1/2019 0 200 24 4/30/2019 0 200 24 4/29/2019 0 200 24 4/28/2019 0 200 24 4/27/2019 0 200 24 4/26/2019 0 200 24 4/25/2019 0 200 24 4/24/2019 0 200 24 4/23/2019 0 200 24 4/22/2019 0 200 24 4/21/2019 0 200 24 4/20/2019 0 200 24 4/19/2019 0 200 24 4/18/2019 0 200 24 4/17/2019 0 200 24 4/16/2019 0 200 24 4/15/2019 0 200 24 4/14/2019 0 200 24 4/13/2019 0 200 24 4/12/2019 0 200 24 4/11/2019 0 200 24 4/10/2019 0 200 24 4/9/2019 0 200 24 4/8/2019 0 200 24 4/7/2019 0 200 24 4/6/2019 0 200 24 4/5/2019 0 200 24 4/4/2019 0 200 24 4/3/2019 0 200 24 4/2/2019 0 200 24 4/1/2019 0 200 24 3/31/2019 0 200 24 3/30/2019 0 200 24 3/29/2019 0 200 24 3/28/2019 0 200 24 3/27/2019 0 200 24 3/26/2019 0 200 24 3/25/2019 0 200 24 3/24/2019 0 200 24 3/23/2019 0 200 24 3/22/2019 0 200 24 3/21/2019 0 200 24 3/20/2019 0 200 24 3/19/2019 0 0 24 3/18/2019 0 0 24 3/17/2019 0 0 24 3/16/2019 0 0 24 3/15/2019 0 0 24 3/14/2019 0 0 24 3/13/2019 0 0 24 3/12/2019 0 0 24 3/11/2019 0 0 24 3/10/2019 0 0 24 3/9/2019 0 0 24 3/8/2019 0 0 24 3/7/2019 0 0 24 3/6/2019 0 0 24 3/5/2019 0 0 24 3/4/2019 0 0 24 3/3/2019 0 0 24 3/2/2019 0 0 24 3/1/2019 0 0 24 2/28/2019 0 0 24 2/27/2019 0 0 24 2/26/2019 0 0 24 2/25/2019 0 0 24 2/24/2019 0 0 24 2/23/2019 0 0 24 2/22/2019 0 0 24 2/21/2019 0 0 24 2/20/2019 0 0 24 2/19/2019 0 0 24 2/18/2019 0 0 24 2/17/2019 0 0 24 2/16/2019 0 0 24 2/15/2019 0 0 24 2/14/2019 0 0 24 2/13/2019 0 0 24 2/12/2019 0 0 24 2/11/2019 0 0 24 2/10/2019 0 0 24 2/9/2019 0 0 24 2/8/2019 0 0 24 2/7/2019 0 0 24 2/6/2019 0 0 24 2/5/2019 0 0 24 2/4/2019 0 0 24 2/3/2019 0 0 24 2/2/2019 0 0 24 2/1/2019 0 0 24 1/31/2019 0 0 24 1/30/2019 0 0 24 1/29/2019 0 0 24 1/28/2019 0 0 24 1/27/2019 0 0 24 1/26/2019 0 0 24 1/25/2019 0 0 20 1/24/2019 0 0 20 1/23/2019 0 0 20 1/22/2019 0 0 20 1/21/2019 0 0 20 1/20/2019 0 0 20 1/19/2019 0 0 20 1/18/2019 0 0 20 0 1/17/2019 0 0 20 1/16/2019 0 0 20 1/15/2019 0 0 20 1/14/2019 0 0 20 1/13/2019 0 0 20 1/12/2019 0 0 20 1/11/2019 0 0 20 1/10/2019 0 25 1/9/2019 0 25 1/8/2019 0 25 1/7/2019 0 25 1/6/2019 0 25 1/5/2019 0 0 25 1/4/2019 0 0 25 1/3/2019 0 0 25 1/2/2019 0 0 25 1/1/2019 0 0 25 Hilcorp Alaska, LLC March 21, 2019 Ms. Jessie Chmielowski Alaska Oil and Gas Conservation Commission 333 rest 7" Avenue, Suite 100 Anchorage, Alaska 99501 RE: RULE 6, DIO 40: BCU -03RD Dear Ms. Chmielowski: 3600 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone: 9D7-777-8300 Fax: 907-777-8310 RECEIVED APR 0 f 2019 AOGCC Attached please find the surveillance report required by Rule 6 of DIO 40 establishing the DIO for the Class II Water Disposal well BCU -03RD (PTD 2030440) for the calendar year of 2018. Injection and Annuli Pressures Injection volumes and annuli pressures are displayed on the plot in attachment 1. Maximum injection rates and pressures are well below those required by rule 3 and the injection index data indicates confinement of injection to the approved intervals. Last Mechanical Integrity test: April 9, 2015 When actively injecting, BCU -03RD disposes of water only and is therefore on a four year MIT cycle. The next MIT is due April 2019. Fracture Geometry BCU -03RD disposes of Class H waste in the BIL & B2 sands of the Sterling section in Sterling Gas Unit. Fracture orientation in BCU -03RD is expected to be vertical and confined by approximately over 200' thick bounding layers above and below the injection strata. This has been proven by previous temperature logs and by openhole log derived rock mechanics properties. Sincerely, r Trudi Hallett Reservoir Engineer 2000 1500. 1000 5OG BCU ID03RD WDW X00 0 J 131/2UIB 0t ly'l010312018 Z.A " 2 0, ea, ijsjq0 !-'S- .,-j �' C.. 1 2,01's J: --1. 4 — Tubing — TA — 0A — Water Injection Well: BCU 03RD Desc: Disposal Permit to drill: 2030440 Admin Approval: DIO #40 API: 50-133-20124-01-00 Date Range: 01/01/2018 -12/31/2018 Date Tubing IA OA Water Injection 12/31/201,' 0 0 25 0 12/30/201! 0 0 25 0 12/29/201 0 0 25 0 12/28/201 0 0 25 0 12/27/201 0 250 25 0 12/26/201 0 250 25 0 12/25/201 0 250 25 0 12/24/201 0 250 25 0 12/23/201 0 250 25 0 12/22/201; 0 250 25 0 12/21/201,' 0 250 25 0 12/20/201 0 250 25 0 12/19/201 0 250 25 0 12/18/201 0 250 25 0 12/17/2011 0 250 25 0 12/16/201 0 250 25 0 12/15/201,' 0 250 25 0 12/14/201 0 250 25 0 12/13/201,' 0 250 25 0 12/12/201 0 250 25 0 12/11/201 0 250 25 0 12/10/201 0 250 25 0 12/9/2018 0 250 25 0 12/8/2018 0 250 25 0 12/7/2018 0 250 25 0 12/6/2018 0 250 25 0 12/5/2018 0 250 25 0 12/4/2018 0 250 25 0 12/3/2018 0 250 25 0 12/2/2018 0 250 25 0 12/1/2018 0 250 25 0 11/30/201 0 250 25 0 11/29/201 0 250 25 0 11/28/201 0 250 25 0 11/27/201: 0 250 25 0 11/26/2011 0 250 25 0 11/25/201 0 250 25 0 11/24/201 0 250 25 0 11/23/201 0 250 25 0 11/22/2011 0 250 25 0 11/21/201; 0 250 25 0 11/20/201 0 250 25 0 11/19/201 0 250 25 0 11/18/201: 0 250 26 0 11/17/201 0 250 26 0 11/16/201 0 250 26 0 11/15/201 0 250 26 0 11/14/201 0 250 26 0 11/13/201 0 250 26 0 11/12/201 0 250 26 0 11/11/201 0 250 26 0 11/10/2011 0 250 26 0 11/9/2018 0 250 26 0 11/8/2018 0 250 26 0 11/7/2018 0 250 26 0 11/6/2018 0 250 26 0 11/5/2018 0 250 26 0 11/4/2018 0 250 26 0 11/3/2018 0 250 26 0 11/2/2018 0 250 26 0 11/1/2018 0 250 26 0 10/31/201 0 250 26 0 10/30/2011 0 250 26 0 10/29/201 0 250 26 0 10/28/201: 0 250 26 0 10/27/201 0 250 26 0 10/26/201 0 250 26 0 10/25/201 0 250 26 0 10/24/201 0 250 26 0 10/23/2011 0 250 26 0 10/22/201 0 250 26 0 10/21/2011 0 250 26 0 10/20/2011 0 250 26 0 10/19/2011 0 250 26 0 10/18/201 0 250 26 0 10/17/2011 0 250 26 0 10/16/2011 0 250 26 0 10/15/2011 0 250 26 0 10/14/2011 0 250 26 0 10/13/2011 0 250 26 0 10/12/2011 0 250 26 0 10/11/2011 0 250 26 0 10/10/201 0 250 26 0 10/9/2018 0 250 26 0 10/8/2018 0 250 26 0 10/7/2018 0 250 26 0 10/6/2018 0 250 26 0 10/5/2018 0 250 26 0 10/4/2018 0 250 26 0 10/3/2018 0 250 26 0 10/2/2018 0 250 26 0 10/1/2018 0 250 26 0 9/30/2018 0 250 26 0 9/29/2018 0 250 26 0 9/28/2018 0 250 26 0 9/27/2018 0 250 26 0 9/26/2018 0 250 26 0 9/25/2018 0 250 26 0 9/24/2018 0 250 26 0 9/23/2018 0 250 26 0 9/22/2018 0 250 26 0 9/21/2018 0 250 26 0 9/20/2018 0 250 26 0 9/19/2018 0 250 26 0 9/18/2018 0 250 26 0 9/17/2018 0 250 26 0 9/16/2018 0 250 26 0 9/15/2018 0 250 26 0 9/14/2018 0 250 26 0 9/13/2018 0 250 26 0 9/12/2018 0 250 26 0 9/11/2018 0 250 26 0 9/10/2018 0 250 26 0 9/9/2018 0 250 26 0 9/8/2018 0 250 26 0 9/7/2018 0 250 26 0 9/6/2018 0 250 26 0 9/5/2018 0 250 26 0 9/4/2018 0 250 26 0 9/3/2018 0 250 26 0 9/2/2018 0 250 26 0 9/1/2018 0 250 26 0 8/31/2018 0 250 26 0 8/30/2018 0 250 26 0 8/29/2018 0 250 26 0 8/28/2018 0 250 26 0 8/27/2018 0 250 26 0 8/26/2018 0 250 26 0 8/25/2018 0 250 26 0 8/24/2018 0 250 26 0 8/23/2018 0 250 26 0 8/22/2018 0 250 26 0 8/21/2018 0 250 26 0 8/20/2018 0 250 26 0 8/19/2018 0 250 26 0 8/18/2018 0 250 26 0 8/17/2018 0 250 26 0 8/16/2018 0 250 26 0 8/15/2018 0 275 26 0 8/14/2018 0 350 27 0 8/13/2018 0 350 27 0 8/12/2018 0 350 27 0 8/11/2018 0 350 27 0 8/10/2018 0 350 27 0 8/9/2018 0 350 27 0 8/8/2018 0 350 27 0 8/7/2018 0 350 27 0 8/6/2018 0 350 27 0 8/5/2018 0 350 27 0 8/4/2018 0 375 27 0 8/3/2018 0 375 27 0 8/2/2018 0 375 27 0 8/1/2018 0 375 27 0 7/31/2018 0 375 27 0 7/30/2018 0 375 27 0 7/29/2018 0 375 27 0 7/28/2018 0 375 27 0 7/27/2018 0 375 27 0 7/26/2018 0 375 27 0 7/25/2018 0 375 27 0 7/24/2018 0 375 27 0 7/23/2018 0 375 27 0 7/22/2018 0 375 27 0 7/21/2018 0 375 27 0 7/20/2018 0 375 27 0 7/19/2018 0 375 27 0 7/18/2018 0 375 27 0 7/17/2018 0 375 27 0 7/16/2018 0 375 27 0 7/15/2018 0 375 27 0 7/14/2018 0 375 27 0 7/13/2018 0 375 27 0 7/12/2018 0 375 26 0 7/11/2018 0 375 25 0 7/10/2018 0 375 25 0 7/9/2018 0 375 25 0 7/8/2018 0 375 25 0 7/7/2018 0 375 25 0 7/6/2018 0 375 25 0 7/5/2018 0 375 25 0 7/4/2018 0 375 25 0 7/3/2018 0 375 25 0 7/2/2018 0 375 25 0 7/1/2018 0 375 25 0 6/30/2018 0 375 25 0 6/29/2018 0 375 25 0 6/28/2018 0 375 25 0 6/27/2018 0 375 25 0 6/26/2018 0 375 25 0 6/25/2018 0 375 25 0 6/24/2018 0 375 25 0 6/23/2018 0 375 25 0 6/22/2018 0 375 25 0 6/21/2018 0 375 25 0 6/20/2018 0 375 25 0 6/19/2018 0 375 25 0 6/18/2018 0 375 25 0 6/17/2018 0 375 25 0 6/16/2018 0 375 25 0 6/15/2018 0 375 25 0 6/14/2018 0 375 25 0 6/13/2018 0 375 25 0 6/12/2018 0 375 25 0 6/11/2018 0 375 25 0 6/10/2018 0 375 25 0 6/9/2018 0 375 25 0 6/8/2018 0 375 25 0 6/7/2018 0 375 25 0 6/6/2018 0 375 25 0 6/5/2018 0 375 25 0 6/4/2018 0 375 25 0 6/3/2018 0 375 25 0 6/2/2018 0 375 25 0 6/1/2018 0 375 25 0 5/31/2018 0 375 25 0 5/30/2018 0 375 25 0 5/29/2018 0 375 25 0 5/28/2018 0 375 25 0 5/27/2018 0 375 25 0 5/26/2018 0 375 25 0 5/25/2018 0 375 25 0 5/24/2018 0 375 25 0 5/23/2018 0 375 25 0 5/22/2018 0 375 25 0 5/21/2018 0 375 25 0 5/20/2018 0 375 25 0 5/19/2018 0 375 25 0 5/18/2018 0 375 25 0 5/17/2018 0 375 25 0 5/16/2018 0 375 25 0 5/15/2018 0 375 25 0 5/14/2018 0 375 25 0 5/13/2018 0 375 25 0 5/12/2018 0 375 25 0 5/11/2018 0 375 25 0 5/10/2018 0 375 25 0 5/9/2018 0 375 25 0 5/8/2018 0 375 25 0 5/7/2018 0 375 25 0 5/6/2018 0 375 25 0 5/5/2018 0 375 25 0 5/4/2018 0 375 25 0 5/3/2018 0 375 25 0 5/2/2018 0 375 25 0 5/1/2018 0 375 25 0 4/30/2018 0 375 25 0 4/29/2018 0 375 25 0 4/28/2018 0 375 25 0 4/27/2018 0 375 25 0 4/26/2018 0 375 25 0 4/25/2018 0 375 25 0 4/24/2018 0 375 25 0 4/23/2018 0 332 25 0 4/22/2018 0 375 25 0 4/21/2018 0 375 25 0 4/20/2018 0 375 25 0 4/19/2018 0 375 25 0 4/18/2018 0 375 25 0 4/17/2018 0 375 25 0 4/16/2018 .0 375 25 0 4/15/2018 0 375 25 0 4/14/2018 0 375 25 0 4/13/2018 0 375 25 0 4/12/2018 0 375 25 0 4/11/2018 0 375 26 0 4/10/2018 0 375 26 0 4/9/2018 0 375 26 0 4/8/2018 0 375 26 0 4/7/2018 0 375 26 0 4/6/2018 0 375 26 0 4/5/2018 0 375 25 0 4/4/2018 0 375 25 0 4/3/2018 0 375 25 0 4/2/2018 0 375 25 0 4/1/2018 0 375 26 0 3/31/2018 0 375 26 0 3/30/2018 0 375 26 0 3/29/2018 0 375 26 0 3/28/2018 0 375 26 0 3/27/2018 0 375 25 0 3/26/2018 0 375 25 0 3/25/2018 0 375 25 0 3/24/2018 0 375 25 0 3/23/2018 0 375 25 0 3/22/2018 0 375 27 0 3/21/2018 0 375 27 0 3/20/2018 0 375 27 0 3/19/2018 0 375 27 0 3/18/2018 0 375 27 0 3/17/2018 0 375 27 0 3/16/2018 0 375 27 0 3/15/2018 0 375 27 0 3/14/2018 0 375 27 0 3/13/2018 0 375 27 0 3/12/2018 0 375 27 0 3/11/2018 0 375 27 0 3/10/2018 0 375 27 0 3/9/2018 0 375 27 0 3/8/2018 0 375 27 0 3/7/2018 0 375 27 0 3/6/2018 0 375 27 0 3/5/2018 0 375 27 0 3/4/2018 0 375 27 0 3/3/2018 0 375 27 0 3/2/2018 0 375 27 0 3/1/2018 0 355 25 0 2/28/2018 0 355 25 0 2/27/2018 0 355 25 0 2/26/2018 0 355 25 0 2/25/2018 0 355 25 0 2/24/2018 0 355 25 0 2/23/2018 0 355 25 0 2/22/2018 0 375 27 0 2/21/2018 0 375 27 0 2/20/2018 0 375 27 0 2/19/2018 0 375 27 0 2/18/2018 0 375 27 0 2/17/2018 0 375 27 0 2/16/2018 0 375 27 0 2/15/2018 0 375 25 0 2/14/2018 0 375 25 0 2/13/2018 0 375 25 0 2/12/2018 0 375 25 0 2/11/2018 0 375 25 0 2/10/2018 0 375 25 0 2/9/2018 0 375 27 0 2/8/2018 0 375 27 0 2/7/2018 0 375 27 0 2/6/2018 0 375 27 0 2/5/2018 0 375 27 0 2/4/2018 0 375 27 0 2/3/2018 0 375 27 0 2/2/2018 0 375 25 0 2/1/2018 0 350 25 0 1/31/2018 0 350 25 0 1/30/2018 0 350 25 0 1/29/2018 0 350 25 0 1/28/2018 0 350 25 0 1/27/201.8 0 350 25 0 1/26/2018 0 350 25 0 1/25/2018 0 375 27 0 1/24/2018 0 375 27 0 1/23/2018 0 375 27 0 1/22/2018 D 390 27 0 1/21/2018 0 375 27 0 1/20/2018 0 375 27 0 1/19/2018 0 350 27 0 1/18/2018 0 325 25 0 1/17/2018 1859 360 25 51.9 1/16/2018 0 360 25 0 1/15/2018 0 360 25 29.7 1/14/2018 0 360 25 0 1/13/2018 0 360 25 0 1/12/2018 0 360 25 0 1/11/2018 0 350 27 0 1/10/2018 0 375 27 0 1/9/2018 0 375 27 0 1/8/2018 0 375 27 0 1/7/2018 0 375 27 0 1/6/2018 0 360 27 0 1/5/2018 0 360 27 0 1/4/2018 0 350 26 0 1/3/2018 0 350 26 0 1/2/2018 0 350 26 0 1/1/2018 0 350 26 0 Hilcorp Alaska, LLC March 27. 2018 RECEDEC) APR 0 2 2013 #" OGCC Mr. Hollis S. French, Chair Alaska Oil and Gas Conservation Commission 333 West 7 1 Avenue, Suite 100 Anchorage, Alaska 99501 RE: RULE 6, DIO 40: BCU -03RD Dear Mr. French: 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone: 907-777-8322 Fax: 907-777-8310 Attached please find the surveillance report required by Rule 6 of DIO 40 establishing the DIO for the Class II Water Disposal well BCU -03RD (PTD 2030440) for the calendar year of 2017. Injection and Annuli Pressures Injection volumes and annuli pressures are displayed on the plot in attachment 1. Maximum injection rates and pressures are well below those required by rule 3 and the injection index data indicates confinement of injection to the approved intervals. Last Mechanical Integrity test: April 9, 2015 When actively injecting, BCU -03RD disposes of water only and is therefore on a four year MIT cycle. The next MIT is due April 2019. Fracture Geometry BCU -03RD disposes of Class II waste in the BIL & B2 sands of the Sterling section in Sterling Gas Unit. Fracture orientation in BCU -03RD is expected to be vertical and confined by approximately over 200' thick bounding layers above and below the injection strata. This has been proven by previous temperature logs and by openhole log derived rock mechanics properties. Sincerely, JWb �kd&-d— Trudi Hallett Reservoir Engineer 300 200 100 BCU 003RD - [50.0666.00031 01/2017 02/2017 03/2017 04/2017 06/2017 06/2017 07/2017 00/2017 0912017 10/2017 1112017 17!2017 — Tubing — IA — OA — Water Injection Well: BCU 03RD Desc: Disposal Permit to drill: 2030440 Admin Approval: DIO #40 API: 50-133-20124-01-00 Date Range: 01/01/2017 - 12/31/2017 Date Tubing IA OA Water Injection 12/31/201' 0 360 26 0 12/30/201 0 360 26 0 12/29/201' 0 360 26 0 12/28/201' 0 360 26 0 12/27/201' 0 350 27 0 12/26/201' 0 350 27 0 12/25/201 0 350 27 0 12/24/201' 0 350 27 0 12/23/201' 0 350 27 0 12/22/201 0 350 27 0 12/21/201 0 350 27 0 12/20/201' 0 350 28 0 12/19/201' 0 350 28 0 12/18/201' 0 350 28 0 12/17/201 0 350 28 0 12/16/201 0 350 28 0 12/15/201' 0 350 28 0 12/14/201' 0 350 28 0 12/13/201' 0 375 28 0 12/12/201' 0 375 28 0 12/11/201' 0 375 28 0 12/10/201' 0 375 28 0 12/9/2017 0 375 28 0 12/8/2017 0 375 28 0 12/7/2017 0 350 28 0 12/6/2017 0 360 26 0 12/5/2017 0 360 26 0 12/4/2017 0 360 26 0 12/3/2017 0 360 26 12/2/2017 0 360 26 12/1/2017 0 360 26 11/30/201' 0 350 28 11/29/201' 0 350 28 11/28/201' 0 350 28 11/27/201' 0 350 28 11/26/201' 0 350 28 11/25/201' 0 350 28 11/24/201' 0 350 28 11/23/201 0 350 28 11/22/201' 0 375 28 11/21/201' 0 375 28 11/20/201' 0 375 28 11/19/201" 0 375 28 11/18/201' 0 375 28 11/17/201 0 375 28 11/16/201' 0 375 28 11/15/201' 0 350 28 11/14/201 0 350 28 11/13/201' 0 350 28 11/12/201' 0 350 28 11/11/201' 0 350 28 11/10/201' 0 350 28 11/9/2017 0 350 28 11/8/2017 0 360 25 11/7/2017 0 360 25 11/6/2017 0 360 25 11/5/2017 0 360 25 11/4/2017 0 360 25 11/3/2017 0 360 26 11/2/2017 0 360 26 11/1/2017 0 360 29 10/31/201 0 360 29 10/30/201' 0 360 29 10/29/201 0 360 29 10/28/201 0 360 28 10/27/201 0 360 29 10/26/201' 0 360 29 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 0 0 0 10/25/2017 0 375 28 10/24/201 0 375 28 10/23/201 0 375 28 10/22/201' 0 375 28 10/21/201' 0 375 28 10/20/201' 0 375 28 10/19/201 0 375 28 10/18/201 0 375 30 10/17/201' 0 375 30 10/16/201' 0 375 30 10/15/201 0 375 30 10/14/201' 0 375 30 10/13/201' 0 375 30 10/12/201' 0 375 30 10/11/201' 0 375 30 10/10/201" 0 375 30 10/9/2017 0 375 30 10/8/2017 0 375 30 10/7/2017 0 375 30 10/6/2017 0 375 30 10/5/2017 0 375 30 10/4/2017 0 360 27 10/3/2017 0 360 27 10/2/2017 0 360 27 10/1/2017 0 360 27 9/30/2017 0 360 29 9/29/2017 0 360 28 9/28/2017 0 375 28 9/27/2017 0 375 28 9/26/2017 0 375 28 9/25/2017 0 375 28 9/24/2017 0 375 28 9/23/2017 0 375 28 9/22/2017 0 375 28 9/21/2017 0 375 28 9/20/2017 0 375 28 9/19/2017 0 375 28 9/18/2017 0 375 28 9/17/2017 0 375 28 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 0 0 0 9/16/2017 0 375 28 0 9/15/2017 0 375 28 0 9/14/2017 0 375 28 0 9/13/2017 0 360 28 0 9/12/2017 0 360 28 0 9/11/2017 0 360 28 0 9/10/2017 0 360 28 0 9/9/2017 0 360 28 0 9/8/2017 0 360 28 0 9/7/2017 0 360 28 0 9/6/2017 0 350 29 0 9/5/2017 0 350 29 0 9/4/2017 0 350 29 0 9/3/2017 0 350 29 0 9/2/2017 0 350 29 0 9/1/2017 0 350 28 0 8/31/2017 0 350 28 0 8/30/2017 0 360 28 0 8/29/2017 0 360 28 0 8/28/2017 0 360 28 0 8/27/2017 0 360 28 0 8/26/2017 0 360 28 0 8/25/2017 0 360 28 0 8/24/2017 0 400 30 0 8/23/2017 0 400 28 0 8/22/2017 0 400 28 0 8/21/2017 0 400 28 0 8/20/2017 0 400 28 0 8/19/2017 1 400 28 0 8/18/2017 1 400 28 0 8/17/2017 1 400 28 0 8/16/2017 1 400 30 0 8/15/2017 1 400 30 0 8/14/2017 1 410 31 0 8/13/2017 3 410 31 0 8/12/2017 22 410 35 844.2 8/11/2017 2 350 28 0 8/10/2017 2 350 28 0 8/9/2017 350 28 0 8/8/2017 350 28 0 8/7/2017 350 28 0 8/6/2017 350 28 0 8/5/2017 350 28 0 8/4/2017 350 28 0 8/3/2017 350 28 0 8/2/2017 350 28 0 8/1/2017 350 28 0 7/31/2017 350 28 0 7/30/2017 350 28 0 7/29/2017 350 28 0 7/28/2017 350 28 0 7/27/2017 350 28 0 7/26/2017 350 28 0 7/25/2017 2 350 28 0 7/24/2017 2 350 28 0 7/23/2017 2 350 28 0 7/22/2017 2 350 28 0 7/21/2017 2 350 28 0 7/20/2017 2 350 28 0 7/19/2017 2 350 28 0 7/18/2017 2 350 28 0 7/17/2017 2 350 28 0 7/16/2017 2 350 28 0 7/15/2017 2 340 28 0 7/14/2017 2 350 28 0 7/13/2017 2 350 28 0 7/12/2017 350 28 0 7/11/2017 350 28 0 7/10/2017 350 28 0 7/9/2017 350 28 0 7/8/2017 350 28 0 7/7/2017 350 28 0 7/6/2017 350 28 0 7/5/2017 350 28 0 7/4/2017 350 28 0 7/3/2017 350 28 0 7/2/2017 350 28 0 7/1/2017 350 28 21 6/30/2017 350 28 6/29/2017 350 28 6/28/2017 48 350 28 6/27/2017 48 350 28 6/26/2017 48 350 28 6/25/2017 48 350 28 6/24/2017 48 350 28 6/23/2017 48 350 28 6/22/2017 48 350 28 6/21/2017 50 350 28 6/20/2017 50 350 28 6/19/2017 50 350 28 6/18/2017 50 350 28 6/17/2017 50 350 28 6/16/2017 49 350 28 6/15/2017 50 350 28 6/14/2017 350 28 6/13/2017 350 28 6/12/2017 350 28 6/11/2017 350 28 6/10/2017 350 29 6/9/2017 350 28 6/8/2017 350 28 6/7/2017 360 28 6/6/2017 360 28 6/5/2017 360 28 6/4/2017 360 28 6/3/2017 360 28 6/2/2017 360 28 6/1/2017 360 28 5/31/2017 52 350 28 5/30/2017 51 350 28 5/29/2017 51 350 28 5/28/2017 51 350 28 5/27/2017 51 350 28 5/26/2017 51 350 28 5/25/2017 50 350 28 5/24/2017 50 350 30 5/23/2017 52 350 30 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 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10 360 30 2/19/2017 10 360 30 2/18/2017 10 360 30 2/17/2017 10 360 30 2/16/2017 10 360 30 2/15/2017 10 360 30 2/14/2017 10 360 30 2/13/2017 8 375 28 2/12/2017 8 375 28 2/11/2017 8 375 28 2/10/2017 8 375 28 2/9/2017 8 375 28 2/8/2017 9 375 28 2/7/2017 9 375 28 2/6/2017 9 375 28 2/5/2017 9 375 28 2/4/2017 9 375 28 2/3/2017 9 375 28 2/2/2017 9 375 28 2/1/2017 9 360 30 1/31/2017 9 360 30 1/30/2017 9 360 30 1/29/2017 9 360 30 1/28/2017 9 360 30 1/27/2017 9 360 30 1/26/2017 9 360 30 n 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 0 0 1/25/2017 9 354 29 1/24/2017 8 360 30 1/23/2017 8 360 30 1/22/2017 8 375 30 1/21/2017 7 375 30 1/20/2017 5 375 30 1/19/2017 4 360 30 1/18/2017 6 360 30 1/17/2017 6 360 30 1/16/2017 6 360 30 1/15/2017 6 360 30 1/14/2017 5 360 30 1/13/2017 6 360 30 1/12/2017 4 360 30 1/11/2017 4 350 30 1/10/2017 4 350 30 1/9/2017 4 350 30 1/8/2017 4 375 30 1/7/2017 4 350 30 1/6/2017 4 360 30 1/5/2017 5 360 30 1/4/2017 5 360 30 1/3/2017 5 360 30 1/2/2017 5 360 30 1/1/2017 5 360 30 D] 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Hilcorp Alaska, LLC �'�� 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 March 20, 2017 MAR 31 2017 AMCC Ms. Cathy P. Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7"' Avenue, Suite 100 Anchorage, Alaska 99501 RE: RULE 6, DIO 40: BCU-03RD Dear Ms. Foerster: Phone:907-777-8322 Fax: 907-777-8310 Attached please find the surveillance report required by Rule 6 of DIO 40 establishing the DIO for the Class II Water Disposal well BCU-03RD (PTD 2030440) for the calendar year of 2016. Injection and Annuli Pressures Injection volumes and annuli pressures are displayed on the plot in attachment 1. Maximum injection rates and pressures are well below those required by rule 3 and the injection index data indicates confinement of injection to the approved intervals. Last Mechanical Integrity test: April 9, 2015 Fracture Geometry BCU-03RD disposes of Class II waste in the B1L & B2 sands of the Sterling section in Sterling Gas Unit. Fracture orientation in BCU-03RD is expected to be vertical and confined by approximately over 200' thick bounding layers above and below the injection strata. This has been proven by previous temperature logs and by openhole log derived rock mechanics properties. Sincerely, IVA-14111 1 --+JJ4 Trudi Hallett Reservoir Engineer Jim Young Reservoir Engineer Wallace, Chris D (DOA) From: Larry Greenstein <Ireenstein@hilcorp.com> Sent: Monday, February 02, 2015 10:03 AM To: Wallace, Chris D (DOA) Subject: RE: Request to reactivate DIO #8 using BCU 03RD Attachments: BCU 3RD Question See if the attached e-mail from BLM answers your first question, Chris. They see no issues with the disposal plan and their approval of the well work will allow us to proceed. We have talked with them at length about the use of this well and they rely on the state for the DIO approval and USF&W as part of their sundry approval process. Figured you'd just build the MIT, step rate test, temp surveys requirements into the rules of the DIO approval, rather than wait to see our procedures on how we plan on complying with the newly written DIO. But in the meantime, we can get a write-up to you on these. Thanks Larry From: Larry Greenstein Sent: Monday, February 02, 2015 9:43 AM To: 'Wallace, Chris D (DOA)' Subject: RE: Request to reactivate DIO #8 using BCU 03RD Thanks Chris... I'll get these things moving. Believe the sundry to do the well work has been sent to you, but I'll confirm. Don't know if we'll get their `letter of non - objection' prior to you getting the DIO in place (ie they were kind of waiting for you to say the well can be used as a disposal well before they approved their own sundry for the conversion to a disposal well). But you could always make the DIO approval contingent upon BLM's approval of the conversion itself. I'll push this out to the folks that can get you the answers you need. Larry From: Wallace, Chris D (DOA)[mailto:chris.wallaceCabalaska.gov] Sent: Monday, February 02, 2015 9:16 AM To: Larry Greenstein Subject: RE: Request to reactivate DIO #8 using BCU 03RD Larry, We are progressing the disposal application and only have a few final questions: 1. Was there a notice to BLM or FWS on the restart? Can you get letters of non -objection from them on this? 2. Did we get to the point of seeing a proposed procedure? I need to confirm the parameters for a step rate test and confirm a plan for a baseline temperature log (followed by a temp log 1 month later)? Thanks and Regards, Chris Wallace Sr. Petroleum Engineer Wallace, Chris D (DOA) From: Eagle, Amanda <aeagle@blm.gov> Sent: Friday, January 16, 2015 1:25 PM To: Larry Greenstein Subject: BCU 3RD Question Hi Larry, Thanks again for meeting with me this morning, it helped me a lot to understand how complex the Swanson River Field is. I talked with Sharon about the sundries for the water disposal well BCU 3RD that we were talking about and she said there isn't anything additional that Hilcorp would need to do other than submit the normal sundries. When we receive them they will be passed on to Fish and Wildlife for comments before approval. Hopefully this helps answer your question. Have a great weekend, Amanda Eagle Petroleum Engineering Technician Anchorage Field Office / Alaska State Office p: 907-271-3266 Colombie, Jody J (DOA) From: Wallace, Chris D (DOA) Sent: Monday, January 12, 2015 11:15 AM To: Colombie, Jody J (DOA) Subject: FW: Request to reactivate DIO #8 using BCU 03RD Attachments: Map of Wells within quarter mile.pdf; BCU-18 Actual Schematic 12-05-14.xlsx; BCU 18 Cement Report.pdf; AREA OF REVIEW - BCU-3RD.docx; BCU Facility Map for BCU 03RD Disposal request.JPG Jody, This was sent in response to the hearing docket DIO 14-002. Thanks, Chris From: Larry Greenstein [mailto:lgreenstein@hilcorp.com] Sent: Friday, January 09, 2015 1:40 PM To: Wallace, Chris D (DOA) Cc: Jason Ewing; John Serbeck; Stan Porhola; David Duffy Subject: FW: Request to reactivate DIO #8 using BCU 03RD Hi Chris, Here's the information that was requested during the hearing to flesh out our proposal for disposal into the BCU 03RD well. As we discussed all the original findings and conclusions are still valid as we are essentially in the same wellbore as previously approved, except for finding #1 as there is now a single penetration within'/ mile radius of the BCU 03RD well and that is the BCU 18 well. For the AOR, attached is the map showing the'/ mile radius around the proposed disposal well, the BCU 18 schematic, cement records (as there wasn't a CBL run on the well) and a write-up summary of the mechanical integrity of the BCU 18 well. Also attached is the facility layout map for the produced water handling that would be required without the ability to use BCU 03RD as a disposal well. The use of BCU 03RD as a disposal well would allow a major portion of the produced water at Beaver Creek to be properly handled on the same location as it is being produced. As far as our request for approved fluids, your e-mail referenced two other recent DIOs that went into detail on the authorized fluids (DIO #37.001 — 4t" paragraph and DIO #38 Rule 2) that seem sufficient for our needs on this well. There doesn't seem to be any deal breakers hiding in the listed fluids as we have no intention of any commercial/3 d party type operation or grind and inject slurry injection in this well. Please let me know if we are missing any additional info that the commission will need to complete our request to reactivate DIO #8 and update it by adding the surveillance, testing and reporting rules to the order. Larry From: Wallace, Chris D (DOA)[mailto:chris.wallaceCcbalaska.gov] Sent: Thursday, October 30, 2014 11:23 AM To: Larry Greenstein Subject: RE: Request to reactivate DIO #8 using BCU 03RD Larry, This well probably should have had DIO 8 rescinded once the well status changed to 1-GAS - but it wasn't. This will probably be DIO 8A (see reference for AIO 21A recently updated Meltwater AIO). I agree it is a good candidate and I do not foresee any difficulties with your plan. Everyone here is looking at the outdated information of the order and especially with the rules (see DIO 38 and DIO 37), and so we feel a full refresh including opportunity for hearing etc. is the way to progress this. Please review DIO 38 and 37 rules and see what if anything would pose problems — as these would be a focus for the commission. It has been the commissions intent to complete a hearing for the record so I would expect a hearing would be held. Thanks and Regards, Chris Wallace Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1250 (phone) (907) 276-7542 (fax) chris.wallace@alaska.gov CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at 907-793-1250 or chris.wallaceCaalaska.gov. From: Larry Greenstein[mailto:lgreenstein@hilcorp.com] Sent: Wednesday, October 29, 2014 4:00 PM To: Wallace, Chris D (DOA) Subject: Request to reactivate DIO #8 using BCU 03RD Hi Chris, We talked a couple of weeks ago about this idea and the engineer has put together a presentation to explain the plan for you to peruse. We'd be glad to come over and discuss this concept with you. Basically, the BCU 03 well was deepened to became a gas producer, BCU 03RD. Now dead, we'd like to plug back the well and reperf into the originally approved disposal zones using the original DIO #8. We believe this would be acceptable to AOGCC as the well itself will become nearly identical to the original BCU 03 except for an additional casing string and more cement across the disposal zone (ie even better isolation and containment than originally in place). Please review the attachment and consider how best to approach this reactivation — maybe an Admin Approval DIO #8.001 for the new (same as the old) well or a DIO #8A for the new API and PTD?? What would be the cleanest plan forward to gain approval for this additional Class II disposal capacity at Beaver Creek?? Thanks and let me know what you think and if you have any follow-up questions Larry AREA OF REVIEW The mechanical condition for all wells within a % mile radius of Beaver Creek #3RD (203-044) was reviewed. The only well that penetrated either the disposal or confining zones, within this mile radius, was Beaver Creek #18 (PTD 208-185). Beaver Creek #18 The 20" conductor was set at 101' MD/TVD. The well was spudded on 1/18/2009 and the 16" surface hole was drilled to 2,107' MD/ 2,054' TVD. The 13-3/8" surface casing was ran to 2,097' MD/ 2,045' TVD and cemented to surface with 290 bbls of Type1 12.0 ppg cement, with 40 bbl of cement returns to surface. This casing was tested to 1,500 psi for 30 min successfully. The 12-1/4" intermediate hole section was drilled to 7,623' MD / 7,069' TVD. The 9-5/8" intermediate casing was ran to 7,612' MD / 7,058' TVD and cemented with 171 bbl of Class G 10.5 ppg lead cement and 45 bbl of Class G 15.8 ppg cement, with full returns thru the entire cement job, but no cement to surface. Estimated cement top is 4,925' MD / 4,558' TVD, assuming 40% openhole excess based on the openhole caliper ran 1/30/2009. No cement bond log was ran in the 9-5/8" casing. This casing was tested to 1,700 psi for 30 min successfully. The 8-1/2" production hole section was drilled to 9,244' MD / 8,689' TVD. The 3-1/2" production casing was ran to 9,230' MD / 8,675' TVD and cemented with 154 bbl of Class G 15.8 ppg cement, with full returns thru the entire cement job, but no cement to surface. A cement bond log was ran 2/11/2009 and found the top of cement at 6,860' MD / 6,317' TVD. This casing was tested to 5,000 psi for 30 min successfully. The top of the proposed disposal interval (Sterling B1-L sand) is located at 5,374' MD / 4,961' TVD in Beaver Creek #18. This zone is behind the 9-5/8" intermediate casing and below the estimated cement top of 4,925' MD. The existing condition of the 9-5/8" casing can be compared to the condition of the 9-5/8" casing from similar depths in offset wells Beaver Creek #12 (PTD 203-188), Beaver Creek #14 (PTD 204-086) and Beaver Creek #19 (PTD 208-123) that were drilled a just before or a few years before Beaver Creek #18 with similar casing and drilling fluids used in these wells. While pulling the 3-1/2" completions in the 9-5/8" casing for the #12, #14, and #19 wells in 2014, the condition of the outside walls of the pulled tubing showed it to be in excellent condition, with stencil markings still being visible on many joints. After the tubing was pulled in these wells, all 3 wells passed pressure tests of the 9-5/8" casing before sidetracking. The #12 and #19 wells were tested to 2,000 psi for 30 min. The #14 was tested to 2,500 psi for 30 min. Attached is the current wellbore schematic for Beaver Creek #18. llilcorp Alaska, LIX Permit #: 208-185 API #: 50-133-20584-00-S1 Prop. Des: A - 028083 KB elevation: 181' (21' AGL) Latitude: 600 39' 29.533" N Longitude: 151* 01' 11.195' W X: 317,475 (NAD 27) Y: 2,433,986 (NAD 27) Spud: 1/18/2009 04:00 hrs TD: 2/5/2009 13:30 hrs Rig Released: 2/12/2009 06:00 hrs PA #: 891008868A Tree cxn: 6-1/2" Otis TOC 9-5/8" Csg ESTIMATED - 5,100' TOC 3-1/2" Csg CBL (2/10/09) - 6,860' Excape System Details Module 1- no flapper Module 2-6 - reclosing flapper Flappers MD (RKB): Module 6 = 8,040' Module 5 = 8,130' Module 4 = 8,480' Module 3 = 8,579' Module 2 = 8,715' Module 1 = NA Chemical Injection Mandrel @ 8,174' MD (RKB) Tag @ 8,638' SLM (12/05/14) 2.25" DD Bailer Fish (77' of 3/8" capstring, 3/4" FCV, 3/4" sinker bar ***Fully Recovered 8/26/13*** Capillary Tubing 3/8" 2205 Stainless Steel Too_ Bottom MD 0' 0' TVD 0' 0' (***Pulled 04/08/2010***) BC-18 Pad 3 1,055' FNL, 1,628' FWL, Sec.34, T7N, R10W, S.M. TD PBTD 9,244' MD 9,193' MD 8,689' TVD 8,638' TVD ACTUAL SCHEMATIC Conductor 20" X56 129.25ppf Top Bottom MD 0' 101' TVD 0' 101' Surface Casino 13-3/8" K-55 68 ppf BTC Top Bottom MD 0' 2,097' TVD 0' 2,045' 16" Hole Cmt w/ 658 sks (290 bbis) of 12.0 ppg, Type 1 cmt , 91 sks (40 bbis) cmt returned to surface Intermediate Casing 9-5/8" L-80 40 ppf Butt Top Bottom MD 0' 7,612' TVD 0' 7,058' 12-1/4" Hole Cmt w/ 290 sks (171 bbis) of Class G Lead @ 10.5 ppg followed w/ 216 sks (45 bbis) of Class G Tail @ 15.8 ppg. 67 sks (40 bbis) returned to surface Production Tubing 3-1/2" L-80 9.3 ppf EUE Mod Top Bottom MD 0' 9,230' TVD 0' 8,675' 8-1/2" Hole Cmt w/ 737 sks (154 bbis) Class G @ 15.8 ppg, 100% returns, Did not bump Excape System Details 6 Excape modules placed along with 1 chemical injection mandrel Red contol line fires modules 2-6 Green control line fires Modules 1 & chemical injection mandrel The bottom @ 8,825' is open 8,190' Opens @ 9,545 psi Beluga Perfs MD (RKB): 2-1/2" 12 spf = 8,010'-8,020' (LB-20) (7/11/13) Module 6 = 8,020'-8,030' (LB-20) 2-1/2" 12 spf = 8,020'-8,030' (LB-20) (7/11/13) 2-1/2" 12 spf = 8,030'-8,037' (LB-20) (7/11/13) 2-1/2" 12 spf = 8,106'-8,110' (LB-21) (7/11/13) Module 5 = 8,110'-8,120' (LB-21) 2-1/2" 12 spf= 8,110'-8,120' (LB-21) (7/11/13) 2-1/2" 12 spf = 8,120'-8,140' (LB-21) (7/11/13) Module 4 = 8,460'-8,470' (LB-25) Module 3 = 8,559'-8,569' (LB-26) Module 2 = 8,695'-8,705' (LB-28) Module 1 = 8,825'-8,835' LB-29) Well Name & Number: Beaver Creek Unit #18 Lease: A - 028083 County or Parish: Kenai Peninsula Borough State/Prov: Alaska Country: USA Angle @KOP and Depth: 2.7° / 100 ft @ 941' Angle/Perfs: 2° Maximum Deviation: 29° @ 4,352' Date Completed: 04/06/09 Ground Level (above MSL): 160' 1 RKB (above GL): 21' Revised By: I Stan Porhola Downhole Revision Date: 12/5/20141 Schematic Revision Date: 1/6/2015 L7 BCU Facility Plot BCU has only one active disposal well, BCU 2, on SE side of field Hilcorp is testing the concept of developing strong bottom water drive gas sands (Sterling B4) with the BCU 25 horizontal well, located on Pad 3 BCU 25 tests a@ WGR of "1,000 bbl/MMscf (currently shut in, waiting on disposal capacity) Current disposal system needs major upgrades to test the BCU 25's full potential Current water injection system requires transfer of water from Pad 3 down to Pad 1A, then pressurized for disposal down to Pad 2 Conversion of BCU 3 to water disposal well will allow on -pad injection that will minimize environmental impact from facility upgrades Sec P KV 2.5 New %kCll BCU 038 Lover Pressure Transfer Svstem from Pad 3 to Pad 1A High Pressure Dispamw i from Pad 1A to Pad 2 500 N01� W k " � BCU 01 �ruww r DispWreek BeaveCf Un.1 Pad i rz Legend 0 Surface Welt Locabons OIL - GAS = O & G unit Boundary N1 ' Beaver Creek Unit Disposal Well a Fx: M MARATHON OIL COMPANY BC-18 2/2/2009: Continue running 9 5/8" casing in hole as per Marathon. Attach centralizers as per tally and fill every joint on way in. Run casing from 3213' to 3526'. Break circulation and fill pipe. Record 1 unit maximum gas. Continue running 9 5/8" casing in hole from 3526' to 7590'. Break circulation. Pick up and wash down from 7590' to landing depth of 7612'. Record 1 unit maximum gas while washing down. Remove slips and land hanger on load shoulder in multi -bowl wellhead. Drain stack and verify landing. Break circulation and continue to circulate and condition well. Circulate bottoms up and record 1.5 units of trip gas. Continue to circulate while BJ works on starting up their cold weather -affected cementing trucks and pressure testing the cementing van's internal lines. Cease circulating and blow down mud lines. Make up cementing head with top and bottom plugs pre -installed. Continue to circulate and condition mud with rig pumps prior to cement job. Hold pre -job meeting with BJ and all hands on procedures and safety for cement job. Continue circulating while 72 bbis of 10.5ppg lead cement is batch mixed . Finish batch mixing lead cement. Finish circulating with rig pumps. Blow air through cementing lines and valves to clear. Switch to BJ pumping unit. Pump 2.0 bbis of water and pressure test lines to 2921psi. Bleed off and line out to pump spacer. Open up bottom valve and drop first (bottom) plug. Mix and pump 20.3 bbis of 10.Oppg SealBond spacer (using 18.48 bbis of mix water), followed by 193.0 bbis of both pre -mixed and batched -in 10.5ppg lead cement slurry (327 sacks of Class G cement plus accelerator chemicals mixed with 98.08 bbls water to batch -up at 12.61 gal/sk and yield of 3.32 cu-ft/sk) and then 40.0 bbis of batched in 15.8ppg tail cement slung (191 sacks of Class G cement plus accelerator chemicals mixed with 22.59 bbis water to batch -up at 4.97 gal/sk and yield of 1.18 cu-ft/sk). Open top valve and close middle and bottom valve on circulating head. Drop second (top) plug. Pump 4.3 bbls of water to kick out the top plug. Switch over to rig pumps. Displace with 575.0 bbis (12334 strokes) of mud (and 579.3 bbis total displacement). Bump plug with 720psi over -pressure (and 1430psi total pressure). Bleed off. Check floats. Cement in place. Note 10t)% returns during displacement. Begin wait on cement. Flush down, blow down and rig down BJ cementing head and cement lines. Blow down Topdrive, mud lines and mud pumps. Back out and lay down casing hanger landing joint. Remove casing elevators, tong bails and pick up sling line. Install short bails. Remove and lay down Lafleur fill -up tool. Install drill pipe elevators. Move hanging sheave for breakout tongs to driller's side and Install correct tong head. Pull and lay down casing spider slips. Load off the casing spider slips, casing elevators, long bails and Lafleur fill -up tool. Fold up stabbing board. Clear and clean rig floor. Make up 9 5/8" pack -off and run in on 1 joint of HWDP. Energize seals and successfully test packoff to 5000psi for 10 minutes. Close blind rams. Change out upper 9 518" casing rams to 2 7/8" by 5 1/2" variable pipe rams. Swap tongs and rig up pipe spinner. Reset and realign torque tube. 2/3/2009: Finish readjusting torque tube. Finish rigging down stabbing board. Pump 300 bbis of old mud in pits over to Hanson Tank to make room for new Flo -Pro mud. Begin diluting mud in pits with 100 bbis of water and adding chemicals. Slip and cut drill line. Run in test plug. Rig up testing equipment. Test annular preventer to 250ps1 Low/3000psi High for 10 minutes. Observe freezing problems after first test. Suspend testing due to frozen lines. Prep and set up steam lines and MagTec hot air blowers. Begin thawing out choke line, rotary hose and Topdrive. Continue testing all BOPE to 250psi Low/3000psi High for 10 minutes (upper pipe rams, check valve, dart valve, upper Topdrive IBOP, floor valve, lower Topdrive IBOP, outside kill valve, inside kill valve, HCR; manual choke, CMVs 1-12, safety valve). Service CMV 7. Perform accumulator drawdown test. Test all gas alarms. Pull test plug. Rig down testing equipment. Set wear bushing. Clean rig floor and prep for casing test. Test casing to 1700psi for 30 minutes. Blow down all lines. Finish thawing kelly hose and reinstall to Topdrive. Pick up, make up and run in hole lower section of new directional assembly (bit, motor, NM stabilizer, pony NMDC, MWD). Orient MWD tools. Dress monel threads. Make up and run in hole remaining directional tools (2 NMCSDP flex joints, steel crossover). Make up crossover to first stand of 5" HWDP from derrick and run in hole with HWDP (plus jars) and 1 stand of 5" drill pipe to 869'. Test MWD pulse signal. Prep to pick up drill pipe. Pick up pre -staged, prepped and strapped joints of 5" drill pipe off of the catwalk/pipe racks, make up and run hole (to 11IT). CH 19 H EPO BCU 08 O -5,119 \ Di sposal isposal well v BCU-3 The U-3 is is the only Sterling B1-L or B2 sand penetration within 1/4 mile of the BCU-3RD well 0 - ,p�� Bcu 1 BCU-25 BCU 12 eCU BCU o,ecu,2A ',� O A Bcu f9 7g0 BCU 2 0 BCU-b9 BCU {4a� CO BCU 14A O 44 O B 01 �B�CU�1■ -4,811 BC 5 0� O i �p�CU 02' BCU 074 u07 �c t -4,872 h � o C, 1SQ Ir900 �9�0 - 5000 `11,050 �.._- ----- - Ali 0 � o � O o O � h � O Hilcorp Alaska ♦-- NORTH KENAI Beaver Creek Sterling 82 Sand l FEET OO FO LLMTA - X ; W LGI. ByJWB 1 ALASKA OIL AND GAS CONSERVATION COMMISSION 2 3 Before Commissioners: Cathy Foerster, Chair 4 Daniel T. Seamount 61 David Mayberry 6 7 In the Matter of Hilcorp Alaska, ) 8 LLC's Application for Authorization ) 9 for Disposal of Class II Oil Field ) 10 Waste by Injection into the Sterling ) 11 Formation of the Beaver Creek Unit ) 12 3RD Well. ) 13 ) 14 Docket No.: DIO 14-002 15 16 ALASKA OIL and GAS CONSERVATION COMMISSION 17 Anchorage, Alaska 18 January 6, 2015 19 9:00 o'clock a.m. 21 PUBLIC HEARING 22 BEFORE: Cathy Foerster, Chair 23 Daniel T. Seamount, Commissioner 24 David Mayberry, Commissioner TABLE OF CONTENTS 2 Opening remarks by Chair Foerster 03 3 Remarks by Mr. Ewing 04 1 P R O C E E D I N G S 2 (On record - 9:00 a.m.) 3 CHAIR FOERSTER: All right. I'd like to call 4 this hearing to order. Today is January 6, 2015, it's 5 9:00 a.m. We're at the offices of the Alaska Oil and 6 Gas Conservation Commission, 333 West Seventh Avenue, 7 Anchorage, Alaska. To my left is Commissioner Dan 8 Seamount, to my right is David Mayberry and I'm Cathy 9 Foerster. We're the three Commissioners of the AOGCC. 10 We're meeting today in reference to Docket DIO 11 14-002, the application of Hilcorp Alaska, LLC, for an 12 order authorizing the underground injection of class II 13 oil field waste at Beaver Creek field. Hilcorp is 14 requesting that the AOGCC issue an order under 20 AAC 15 25.252. This order would authorize the disposal of 16 class II oil field waste by injection into the Sterling 17 formation of the Beaver Creek unit 3RD well located at 18 1,227 feet from the north line, 1,501 line from the 19 west line of section 34, T7N R10W SM, whatever the hell 20 that means. 21 COMMISSIONER SEAMOUNT: Seward Meridian. 22 CHAIR FOERSTER: Ah. Thank you very much. 23 Computer Matrix will be recording the proceedings. You 24 can get a copy of the transcript from Computer Matrix. 25 Just a reminder for people testifying, be sure 3 1 the green light's on for both of the mics, try to speak 2 into both of the mics. One feeds the court reporter 3 and one feeds the back of the room. So we want to make 4 sure everybody gets what you're saying. And this will 5 be a permanent record in the AOGCC and 10 years from 6 now someone may want to look back on it and understand 7 what was said so as you refer to slides -- as you 8 introduce a new slide each time say, you know, slide 9 number 1 or the slide titled, something so that 10 10 years from now somebody reading the transcript can 11 actually follow and understand. 12 And let's see, we only have one person 13 testifying, okay, and the rest is the peanut gallery, 14 right? Okay. 15 MR. EWING: Yes. 16 CHAIR FOERSTER: But what we'll do is first 17 I'll swear you in so raise your right hand. 18 (Oath administered) 19 MR. EWING: I do. 20 JASON EWING 21 called as a witness on behalf of Hilcorp Alaska, LLC, 22 stated as follows on: 23 DIRECT EXAMINATION 24 CHAIR FOERSTER: All right. And so you have 25 the opportunity to be recognized as an expert in an 11. 1 area for example drilling or production engineering or 2 reservoir engineering or land or something like that. 3 Would you like to be recognized as an expert? 4 MR. EWING: Yes. 5 CHAIR FOERSTER: Okay. So what I'd like for 6 you to do is introduce yourself by your name, who you 7 represent, the area you'd like to be recognized as an 8 expert in and then what qualifies you as an expert, you 9 know, what your experience is, what your education is, 10 that sort of thing. 11 MR. EWING: My name's Jason Ewing, I work for 12 Hilcorp Alaska as a reservoir engineer. I've been a 13 reservoir engineer for the past four years with Hilcorp 14 and preceding roughly three years with Hess 15 Corporation. I graduated with a master's of petroleum 16 engineering degree in 2008. So..... 17 CHAIR FOERSTER: From where? 18 MR. EWING: Texas A&M. 19 CHAIR FOERSTER: Oh. Hmmm, that could be a 20 problem. Where did you get your bachelor's? 21 MR. EWING: Texas A&M as well. 22 (Off record comments) 23 CHAIR FOERSTER: No, I'm kidding. Please 24 proceed. 25 COMMISSIONER SEAMOUNT: We need to agree that 5 1 he's an expert. 2 CHAIR FOERSTER: No, no, no. I thought -- are 3 you finished with your qualifications? 4 MR. EWING: Yes, ma'am. 5 CHAIR FOERSTER: Okay. Commissioner Seamount, 6 do you have any questions? 7 COMMISSIONER SEAMOUNT: No, I think it's very 8 good he went to the better school. 9 CHAIR FOERSTER: Commissioner Mayberry, how 10 about you? 11 COMMISSIONER MAYBERRY: I have no questions. 12 CHAIR FOERSTER: All right. Nor do I. We 13 recognize you as an expert in reservoir engineering. 14 Please proceed with your testimony. 15 MR. EWING: Okay. So just to give you all an 16 overview of what we're here today, the BCU3 well at 17 Beaver Creek was initially permitted as a disposal well 18 back in 1983. And since then the well was deepened by 19 Marathon, the previous operator. The well was not 20 sidetracked per se, but it was deepened and so received 21 a different API number to access the Beluga formation 22 deeper. Beluga was largely uncommercial and the wells 23 have been idle ever since then and what Hilcorp is 24 proposing is that we come back up within the original 25 wellbore so the same level with -- within the BCU3, not on 1 the -- even though it's called the 3RD now and 2 reactivate the injection order 8 that was initially 3 approved back in 1993. 4 So that's the brief overview, I have a series 5 of slides that walks through the history of the well 6 that provide more detail and if you'd like I can start 7 going through those. 8 CHAIR FOERSTER: Okay. 9 MR. EWING: So the BCU3 was initially permitted 10 as a Sterling B1L. 11 CHAIR FOERSTER: And you're referring to the 12 slide..... 13 MR. EWING: I'm sorry. We're referring to the 14 request for overview slide..... 15 CHAIR FOERSTER: Okay. 16 MR. EWING: .....which is the second slide in 17 the slide deck. The BCU3 was permitted as a Sterling 18 B1L, B2 disposal well by the previous operator, 19 Marathon, in May, 1993. It was subsequently deepened 20 to 10,005 feet to access the Beluga interval. The 21 Beluga interval was tested, produced roughly 70 mcf of 22 gas, deemed un -- it was uncommercial, it's sitting 23 idle right now. Hilcorp proposes to isolate the Beluga 24 perforations by setting a plug at 9,000 feet and then 25 dump -- bailing 35 feet of cement per regulations. The 7 1 -- then we're requesting to reactivate the DIO number 8 2 to allow injection to the Sterling B1L, B2 zone at 3 5,804 to 5,945 feet. This is the -- we'll then request 4 to perforate the B1L and B2 sands at 5,804 feet to 5 5,945 feet at the same depth in the original BCU3 6 wellbore as previously permitted in DIO number 8. The 7 gas lift valve in the BCU3 wellbore will be dummied 8 (ph) off to allow for appropriate MIT testing. If we 9 cannot -- if the gas lift dummy fails for some reason 10 we'll pull that three and a half inch string out, run 11 back in with a three and a half inch tubing and packer 12 so we can ensure adequate isolation from the annulus. 13 Do you have any questions on that slide? 14 COMMISSIONER SEAMOUNT: Did -- do you know how 15 much the original injection -- the volume of the 16 original injection was? 17 MR. EWING: From the best I can tell there was 18 -- the well was never injected into, it was completed 19 as an injector for almost 10 years and then they just 20 let it sit idle. 21 COMMISSIONER SEAMOUNT: Okay. Thank you. 22 MR. EWING: So this is a copy of the wellbore 23 diagram from July, 1994. It's titled -- this is slide 24 number -- it should be slide number 3, titled BCU3 25 wellbore diagram, post B3, B3A abandonment and pre B2 n. 1 completion for disposal. I've annotated the 2 perforations that were added later that month. So this 3 diagram was what Marathon sent into the Commission to 4 show that they have adequately isolated the B3A, B3 -- 5 what they're calling B3A, the -- labeled as B3L sands. 6 And then they went back in and added perforations from 7 5,910 to 5,940 in July, 1994. So this is how the well 8 was initially set up as an injector back in July, 1994. 9 Going on to the next slide, it would be slide 10 4, it's labeled current schematic. This is where the 11 well is -- stands right now. The lower Beluga 22 12 through 30 perfs are open, I guess the lower section of 13 Beluga's been plugged off with some -- also some fill, 14 but Beluga is still open, you can see there's a three 15 and a half inch liner that ties back above the Sterling 16 sands so the initial perforation interval here in the 17 B2 sands at 5,910 to 5,940 has been lapsed by a three 18 and a half inch liner. So and you can see they drilled 19 out of the casing shoe for the initial BCU3 well, they 20 did not -- they didn't sidetrack the well up hole above 21 the Sterling, I mean, this was just simply -- it was a 22 decom procedure. 23 And what we would like to do is the next slide 24 so going on to the slide labeled proposed schematic, is 25 set this bridge plug down here at 9,000 feet and then 0 1 dump about 35 feet of cement on top of it and then 2 perforate the B1L and B2 sands here at 5,804 to 5,945 3 feet in the exact same location as they were, you know, 4 proposed in the initial injection order in DIO 8. And 5 so if anything else what we would have here is an extra 6 level of isolation with this liner, the three and a 7 half inch liner lapped across the Sterling interval. 8 And then it's tied directly into this seal bore 9 assembly up to this three and a half inch completion. 10 And you can see here the gas lift mandril and the 11 chemical injection mandril which will be dummied off if 12 that doesn't test then we'll go back and pull the three 13 and a half inch out of the seal bore, run back in with 14 a packer and -- to adequately isolate the production or 15 the intermediate casing in this case. 16 Going on -- do you have any questions on this 17 -- on this slide set? 18 (No comments) 19 MR. EWING: Going on to the next slide..... 20 CHAIR FOERSTER: What..... 21 MR. EWING: .....under BCU3 history. The next 22 two slides just kind of give you an overview of the, 23 you know, entire history of the well, when it was 24 drilled, what all was done to it and so I'll scroll 25 through this, please stop me if you have any questions. 10 1 So it was initially drilled in 1968 with a TD 2 of 6,387 feet. The seven inch (ph) facing was set at 3 6,380. It was cemented in two stages. There was a DV 4 tool at 2,033 feet so good return to pits (ph) on both 5 cement stages. The first stage we brought cement up to 6 3,000 feet, second stage took it from 2,000 feet across 7 the casing shoe at roughly 1,500 feet so casing shoe 8 has good cement. Then they tested the Sterling B3 and 9 B3L sands in August of 168, all the sands tested gas at 10 these depths. The well was shut-in until 1982. The 11 well was reactivated in September, 182 with a workover. 12 Updip production since wet -- some of B3L sands water 13 had encroached so they squeezed off all the open perfs 14 and re -perforated the upper B3 sand at 6,034 to 6,080 15 feet, produced from 182 up through -- you see in 187 16 they cleaned the well out due to some fill and they 17 also attempted some water shutoff procedures. In 188 18 they did a workover to shut off additional water and 19 then in December, 1988 they squeezed off all the perfs 20 and milled out cement. So at this point from 1982 21 through 1988 the Sterling had accumulated roughly 19.1 22 bcf of gas out of the B3 sand. 23 In May, 1993 DIO 8 was approved the AOGCC, 24 disposal authorized into Sterling B1L and B2 zones at 25 5,804 to 5,945 feet. In July, 194 it was re -completed 11 1 as a water disposal well, it's labeled injection, to 2 dispose of waste water in the Sterling B2 and it was 3 perforated at 5,910 to 5,940. The -- in October, 1999 4 the AOGCC allowed injection into the BCU2 and BCU3 so 5 this is DIO number 4 and DIO number 8, from fluids 6 originating outside of Beaver Creek. So this was a 7 letter Marathon requested to dispose of fluids from 8 outside of Beaver Creek so that was -- happened while 9 the well was still completed as an injector, as a 10 disposal well. 11 And so the next slide, BCU3 RD history 12 continued. The March, 2003, the permit to deepened 13 BCU3 is approved. BCU3 RD is CD'd in May, 2033 so they 14 just -- they deepened the initial 3 wellbore, they 15 perforated Beluga interval to pump frack jobs in July, 16 2003 and then in April in April, 2005 they ended up 17 setting a bridge plug at 9,570 to isolate some more 18 perfs, re-perfed some zones in the Beluga sands. In 19 May, 2005 they added additional perforations. Through 20 all this the Beluga only makes roughly 70 million cubic 21 feet of gas. So uncommercial completion, they 22 attempted -- they had water production, they attempted 23 to run a one and three-quarter inch flossy string to 24 help unload the water in December, 2005. In February, 25 2006 which is the last known Beluga production it may 12 1 have produced 70 million. In August, 2007 they removed 2 the one and three-quarter inch flossy string and the 3 well since -- sits idle now. 4 COMMISSIONER SEAMOUNT: So the Sterling made 19 5 bcf of gas? 6 MR. EWING: Out of this well, yes, sir. 7 COMMISSIONER SEAMOUNT: Okay. And then what 8 did you do, water out or..... 9 MR. EWING: Yes. 10 COMMISSIONER SEAMOUNT: .....complete? 11 MR. EWING: Yes. 12 COMMISSIONER SEAMOUNT: Okay. 13 MR. EWING: Water out. 14 CHAIR FOERSTER: Do you have questions? 15 COMMISSIONER MAYBERRY: No. 16 MR. EWING: This is the -- this concludes the 17 overview and I've brought a multitude of backup slides 18 if you have any additional questions on production 19 profiles. 20 COMMISSIONER SEAMOUNT: Do you have a map? 21 MR. EWING: Yes, sir, I do. So this is a 22 structure map of the B1L sands, sub TD structure map. 23 You can see the current water disposal well is the BCU2 24 down here in the lower right-hand edge of the screen. 25 This slide is labeled Beaver Creek field, Sterling B1L, 13 1 sub CTBD (ph). So the BCU2 is in the lower right-hand 2 part of the screen, the BCU3 is up here in the upper 3 right-hand, it's roughly on the strike to the BCU 2 4 although several miles away to the north. 5 COMMISSIONER SEAMOUNT: What's the scale on 6 that map? 7 MR. EWING: This is -- I have it down here, but 8 it's low resolution. You can see the section, this is 9 a section right here, this is one square mile from here 10 to here. 11 CHAIR FOERSTER: So a few of those wells are 12 within a quarter mile of the 3? 13 MR. EWING: These are the B1L penetrations and 14 so this pad right here, this pad we call pad 3, has 15 multiple directional wells that go from it to access 16 different Beluga targets that are farther off 17 structure. And so you see a bunch of penetrations to 18 the B1L sand very close together because it's before 19 the -- most of the directional work had been performed 20 to access those multiple Beluga targets. 21 CHAIR FOERSTER: So are any of the wells within 22 a quarter mile of the proposed disposal well? 23 MR. EWING: There are no complete -- there are 24 no completions within a quarter mile. So the..... 25 CHAIR FOERSTER: Any penetrations? 14 1 MR. EWING: There are penetrations. 2 CHAIR FOERSTER: Okay. Which ones are 3 penetrations that are within a quarter mile? 4 MR. EWING: You can -- we have the -- I'll have 5 to -- I need to go back in and double check the..... 6 CHAIR FOERSTER: Okay. 7 MR. EWING: .....distances for..... 8 CHAIR FOERSTER: And what is the mechanical 9 integrity of those penetrations would be the next 10 question. So if you don't know what the penetrations 11 are then I'm assuming you'd have to get back to us with 12 the mechanical..... 13 MR. EWING: I can get back to you with the 14 exact penetrations within a quarter mile with -- 15 with..... 16 CHAIR FOERSTER: And the mechanical integrity 17 of them. 18 MR. EWING: .....the mechanical integrity, 19 absolutely. 20 CHAIR FOERSTER: Okay. 21 COMMISSIONER SEAMOUNT: Looks like there might 22 be three. 23 CHAIR FOERSTER: Yeah. 24 MR. EWING: You got the 5R -- yeah, it's looks 25 like the 5RD -- I think the 25's probably okay, but 15 1 I'll -- we'll get back to you with the exact..... 2 CHAIR FOERSTER: So I understand that you guys 3 just want to reenact the old disposal order, but a lot 4 of requirements on disposal injection have changed 5 since that order was granted. And they've all been 6 changed for good oil field practices reasons, things 7 like requiring a description of the fluids you intend 8 to inject so that we can authorize those and only those 9 fluids. So we need that from you, do you have that? 10 MR. EWING: Not with me today. I can..... 11 CHAIR FOERSTER: Okay. That's..... 12 MR. EWING: .....I can get that to you. 13 CHAIR FOERSTER: .....that's part of the 14 complete application that we need from you. And 15 depending upon what those authorized fluids are we may 16 require more frequent well testing and a new -- an up 17 to date DIO would also require an annual surveillance 18 report and a sunset clause and the assurance of the 19 integrity of the surrounding wells. So those are some 20 things that have changed since the original DIO was 21 granted and the new DIO would not be granted without 22 that information. And so the application will be 23 complete when you provide that to us. 24 MR. EWING: Okay. So the previous DIO is no 25 longer..... 16 1 CHAIR FOERSTER: No, the -- it's no longer -- 2 the well was re -completed someplace else and so that 3 should have gone away and it was a paperwork glitch 4 that it didn't. 5 COMMISSIONER SEAMOUNT: The zone that made 6 what, 70,000 mcf, is that zone very productive in other 7 wells at..... 8 MR. EWING: Yes. Yeah, the Beluga sands are -- 9 the reservoir quality varies dras -- you know, it's a 10 very het..... 11 CHAIR FOERSTER: Heterogeneous. 12 MR. EWING: Heterogeneous sand. Thank you. 13 CHAIR FOERSTER: See we learned to say that at 14 the University of Texas. 15 MR. EWING: They don't teach us that at A&M. 16 (Off record comments) 17 COMMISSIONER SEAMOUNT: So that zone, other 18 wells are going to capture any reserves that are left 19 in that zone or did it water out? 20 MR. EWING: The -- it was essentially a 21 noncommercial completion, the zone was making it water, 22 but it -- it fracked the zone. I have a copy of the 23 production profile if you'd like to see it. 24 COMMISSIONER SEAMOUNT: No, that's okay. 25 MR. EWING: Okay. 17 1 COMMISSIONER SEAMOUNT: Unless you want to show 2 it..... 3 MR. EWING: Yeah. 4 COMMISSIONER SEAMOUNT: .....being a reservoir 5 engineer. 6 MR. EWING: Yeah, it -- the zone IP'd at low 7 rate and then it quickly teetered off and it wasn't 8 like a -- it wasn't like a sterling completion where 9 the ocean hit it, I mean, it was just nonproductive 10 rock. 11 COMMISSIONER SEAMOUNT: Okay. Just out of 12 curiosity why do you need a third disposal well? 13 MR. EWING: A third disposal well? 14 COMMISSIONER SEAMOUNT: Yeah, aren't there two 15 there already? 16 MR. EWING: No, we have -- we have one disposal 17 well, the BCU2. 18 COMMISSIONER SEAMOUNT: Okay. So why do you 19 need two then? 20 MR. EWING: So -- good question. The location 21 of the well is the main benefit. So we'll -- we have 22 since brought on a high water gas ratio, roughly 1,000 23 barrels per million. Strong well, we can produce 24 thousands of barrels a day at a thousand barrels per 25 million and the main issue is getting the water off the 1 pad, from pad 3, I just showed you that map. So the 2 well up here, this BC25, is a high water cut well and 3 we're currently having to transfer this water through 4 low pressure transfer line to pad lA and then from pad 5 lA send it through a high pressure line for almost a 6 mile to the BCU2 well. So it's a water transfer issue. 7 We -- if we don't get this BCU3 turned into a water 8 disposal well we're going to have to do substantial 9 pipeline..... 10 CHAIR FOERSTER: Uh-huh. 11 MR. EWING: .....and facility work and big 12 enough old flow lines and it's going to be a -- it'll 13 be a massive facility project and quite a bit of old 14 flow lines, you know, thousands of feet of old flow 15 lines being dug up. So..... 16 COMMISSIONER SEAMOUNT: If you find a well 17 within a quarter mile it -- well, it doesn't have 18 cement across the zone to be disposed of in, what would 19 you do to correct that? 20 MR. EWING: I'd have to consult with the 21 operations manager. 22 COMMISSIONER SEAMOUNT: Okay. Well, hopefully 23 you won't find one. 24 MR. EWING: Yeah, I think we're okay. Yeah, 25 the wells -- all the wells that were there I believe 19 1 were there when this order was initially approved. And 2 so..... 3 COMMISSIONER MAYBERRY: My -- I don't have 4 really any objection or issue and actually what you 5 just said is probably the most valuable bit of 6 information that I've received that is not in anything 7 that we've received thus far. And so actually having 8 that background and understanding of why you're doing 9 exactly what you're doing is very helpful. 10 MR. EWING: Okay. 11 COMMISSIONER MAYBERRY: And sort of my whole 12 take on this sort of thing is I appreciate wanting to 13 get things done in an expeditious manner. I think, and 14 I'm just trying to be helpful, an email that is very 15 efficient and gets to the point of a matter. Sometimes 16 it would be -- it's easy -- it would actually be easier 17 if you -- what we don't have is a complete application 18 conforming to our regulations at 20 AAC 25.252. And if 19 we had that information it actually would have -- would 20 expedite things more than what I think you're trying to 21 achieve with the way things were done initially. And 22 so, you know, this is great, what you just said about 23 having to -- you know, this is what we're doing, we 24 have this issue we're trying to deal with and 25 explaining that is very helpful. 20 1 MR. EWING: Okay. 2 COMMISSIONER MAYBERRY: And like, you know, the 3 slides and the email that we had, we opened a docket, 4 call it an application, it's really not a complete 5 application, we don't want to throw it back and say, 6 you know, we're not going to proceed, this is not 7 complete. And so I'm glad we're having the hearing, 8 this is all very helpful and I think we're 9 accomplishing what we need to accomplish. I -- this is 10 a long about way of just saying if we had just got an 11 application it would have expedited things perhaps more 12 than what we're trying to achieve. 13 MR. EWING: I understand. I was under the 14 impression that the old injection order could have been 15 simply reinstated because it was in the same -- 16 effectively the same wellbore. I..... 17 COMMISSIONER MAYBERRY: Yeah, and..... 18 MR. EWING: .....we did not approach this 19 thinking we were going to need a new injection order. 20 COMMISSIONER MAYBERRY: Yeah, and that's been 21 kicked around a little bit and frankly, you know, where 22 I come down, I don't know where my fellow Commissioners 23 are, basically the old injection order if you look at 24 it like the findings and descriptions of what that 25 order pertained to, really doesn't apply to the well in 21 1 its current state because it does not describe the well 2 in its current state. And so we're kind of -- you 3 know, it's like back to the future, you know, it -- I 4 don't know if it can quite be unwound just like that. 5 And so, you know, I appreciate where you guys are 6 coming from, but, you know, the last five years of what 7 I've heard has actually been about the most helpful 8 information that we've received. 9 MR. EWING: And we -- I mean, we can definitely 10 give you an overview of the facility kind of structure 11 and more detailed surface map versus a subsurface map 12 showing our water -- you know, why we want to inject up 13 here in addition to the BCU2 well. The -- our water to 14 the BCU25 that we just brought on here, it's shut-in 15 right now waiting for additional water handling 16 capacity. So it was shut-in production, the -- is on 17 pad with the BCU3 well. So being able to inject on the 18 same pad versus having to move the water several miles 19 to get to the injection well is further pushing that 20 system and its ultimate goal. 21 CHAIR FOERSTER: Well, we can leave the record 22 open so that you guys can provide additional 23 information and you can work with Chris to get it. But 24 right now if there aren't any other questions right 25 there I'd like to take a 10 minute recess and let the 22 1 technical folks suggest questions that we weren't smart 2 enough to think to ask ourselves. We'll reconvene at 3 20 to 10:00. We're recessed. 4 (Off record) 5 (On record) 6 CHAIR FOERSTER: We're back on the record at 7 9:39 a.m. So, Mr. Ewing, we -- just a few questions. 8 Your -- the -- regardless of how this order was treated 9 when the three of us weren't here, you're proposing 10 injecting into a producing reservoir or a formerly 11 producing reservoir. Are there updip wells that are 12 still producing from the interval that you propose to 13 inject into? 14 MR. EWING: No, ma'am. The..... 15 CHAIR FOERSTER: So the entire reservoir is 16 depleted and watered out? 17 MR. EWING: Yes. It was actually never a 18 productive completion in the B1L or the B2 primary 19 lobes. There was one or two completion in the B -- 20 what we call the B2L lobe, but the actual sands that we 21 had that were -- that were approved in the DIO 8 have 22 never been produced in any of the..... 23 CHAIR FOERSTER: Okay. 24 MR. EWING: .....wellbores. 25 CHAIR FOERSTER: Okay. So..... 23 1 COMMISSIONER SEAMOUNT: Have they been tested? 2 MR. EWING: Yes. 3 COMMISSIONER SEAMOUNT: In other wells? 4 MR. EWING: Yes. 5 COMMISSIONER SEAMOUNT: Okay. 6 MR. EWING: Yeah. 7 CHAIR FOERSTER: Okay. That helps. There's an 8 old letter about authorizing additional waste from 9 other fields. Is it Hilcorp's intention to use this 10 well commercially? 11 MR. EWING: As in..... 12 CHAIR FOERSTER: A waste disposal well from 13 other fields. 14 MR. EWING: Our primary intent is to dispose 15 off of pad 3 injection and having the opportunity to 16 bring other Hilcorp fields provides us some 17 flexibility, but our -- the primary intent is to 18 dispose of Beaver Creek..... 19 CHAIR FOERSTER: Okay. 20 MR. EWING: .....fluids. 21 CHAIR FOERSTER: Okay. Just be aware that if 22 you do decide to do -- turn it into a commercial 23 disposal well that will require separate action. 24 MR. EWING: And that would require -- I mean, 25 when you say commercial that would be a separate 24 1 Hilcorp field or would that also -- would that be from 2 a different operator? 3 CHAIR FOERSTER: It would be a different 4 operator. 5 MR. EWING: Okay. Yeah. No, then..... 6 CHAIR FOERSTER: Okay. 7 MR. EWING: .....the answer is no. 8 CHAIR FOERSTER: And don't forget we do need to 9 approve your -- we will need to approve the authorized 10 -- you know, you have to give us a list of the fluids 11 you intend to inject and we'll have to approve that. 12 MR. EWING: Yes, ma'am. 13 CHAIR FOERSTER: In -- oh, and are you aware 14 that you will need a -- an approved sundry to plug back 15 from the existing completion? 16 MR. EWING: Yes, ma'am. 17 CHAIR FOERSTER: Okay. And in the schematic 18 that you show you don't indicate that you're going to 19 squeeze off the open perfs below the bridge plug. Why 20 would you not do that because if -- for the ultimate 21 P&A of the well those perfs would need to be squeezed 22 so while you're in there why wouldn't you just pump 23 some cement before putting your bridge plug? 24 MR. EWING: I -- I'll have to confer with the 25 operations..... 25 1 CHAIR FOERSTER: Okay. 2 MR. EWING: .....staff to..... 3 CHAIR FOERSTER: Okay. And that might be a 4 requirement of the sundry. 5 MR. EWING: Yes, ma'am. 6 CHAIR FOERSTER: Okay. All right. 7 Commissioner Seamount, do you have anything for the 8 good of the order? 9 COMMISSIONER SEAMOUNT: Okay. This zone, was 10 it a poor producer because of permeability or water? 11 MR. EWING: I -- for -- as far as the Beluga or 12 the Sterling sand, sir? 13 COMMISSIONER SEAMOUNT: The proposed disposal 14 zone. 15 MR. EWING: It was wet, the zone was wet. 16 COMMISSIONER SEAMOUNT: Okay. 17 MR. EWING: It was never..... 18 COMMISSIONER SEAMOUNT: Is it wet..... 19 MR. EWING: .....it was never a productive 20 zone. 21 COMMISSIONER SEAMOUNT: It's wet throughout the 22 field then? 23 MR. EWING: The B1L and the B2 sand, yes, sir. 24 COMMISSIONER SEAMOUNT: Okay. Okay. So you 25 think it's got the permeability to be a good injection 26 1 zone? 2 MR. EWING: Yes, sir. 3 COMMISSIONER SEAMOUNT: Okay. 4 MR. EWING: Yeah, the Sterling sand -- the 5 Sterling sand in this area, the entire area tend to be 6 fairly high perm at least in the -- we found it's tens 7 of millidarcies or better. 8 COMMISSIONER SEAMOUNT: Good. Thank you. 9 CHAIR FOERSTER: Commissioner Mayberry, any 10 questions? 11 COMMISSIONER MAYBERRY: I have nothing further. 12 CHAIR FOERSTER: Okay. Is there anyone else or 13 do you have anything else you'd like to add or is there 14 anyone else from Hilcorp that has anything to add for 15 the good of order? 16 MR. EWING: No, ma'am. 17 CHAIR FOERSTER: Okay. Okay. Anybody else? 18 (No comments) 19 CHAIR FOERSTER: Alrighty then. Then I'm going 20 to adjourn this hearing. Thank you for your time. 21 We're adjourned. 22 (Off record) 23 (On record) 24 CHAIR FOERSTER: And how long is it going to 25 take you to get us the information that we need, a 27 1 week, two weeks? 2 MR. EWING: We intend to get it in the next 3 several weeks. 4 CHAIR FOERSTER: Okay. Well, we'll leave the 5 record open for two weeks from today. And now we're 6 adjourned again. 7 MR. EWING: Thank you. 8 (Adjourned - 9:45 a.m.) 9 (END OF PROCEEDINGS) 1 TRANSCRIBER'S CERTIFICATE 2 I, Salena A. Hile, hereby certify that the 3 foregoing pages numbered 2 through 29 are a true, 4 accurate, and complete transcript of proceedings of 5 January 6, 2015, Docket No.: DIO 14-002 transcribed 6 under my direction from an electronic sound recording 7 to the best of our knowledge and ability. 8 9 10 Date Salena A. Hile 11 29 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Public Hearing DIO-14002 Hearing Hilcorp Alaska LLC. January 6, 2015 at gam NAME AFFILIATION Testify (yes or no) �/ A X, �4octq, L 0 IlD &CC No <, < LJa ((a <_ e /4-0 C (_ c- A% 0 �21� ';� iaN 2 -" 0,oc-tc c )Q C-D BCU-3 Well History Sterling BlL / B2 Water Disposal Reactivation Jason Ewiv,, 10-15-1-16 Request Overview • BCU-3 was permitted as a Sterling 1311- / B2 disposal well by the previous operator, Marathon, in 05/93 • BCU-3 was subsequently deepened to 10,005' to access the Beluga interval • Hilcorp plans to isolate all Beluga perforations by setting a plug @ 9,000 ft then dump bailing 35 ft of cement • Hilcorp is requesting to re -activate DIO #8 to allow injection into Sterling 1311- / B2 Zone @ 5,804' — 5,945' • Hilcorp is requesting to perforate the Sterling 1311- / B2 sand @ 5,804' — 5,945' at the same depth in the original BCU-3 wellbore as previously permitted in DIO #8 • Gas lift valve in BCU-3RD wellbore will be dummied off to allow appropriate MIT testing • If GL valve leaks, Hilcorp will pull the tubing and run 3.5" tubing with packer down to —5,600' to satisfy state injection requirements BCU 3 WBD —Post B3/B3A Abandonment & Pre-132 Completion for Disposal (July-94) 4ARAT14UN OIL C0YP,*,'0 REAV R, CW6( spud Do te 1 "PI : D, 'vof PK S 16' abov¢ 11 colpo�etic. Dote Tap or 5555• AIV.e p p—, Q'e Through Stllq 3 A—Wo F(v& FW ./KCL cele,e,,c, Log 31' All "ieptl's are ;,<F 110 to top 0P eq.cent -FWE� qy T-77--T-T--f 7 MMM Sterling B2 Perforated @ (-W 519101 - 5,940' in 07-94 for Water Disposal 6 7 Old 133/133A Squeezed perforations are now isolated with 3.5" liner 7yo&^ Gas Producer P', :'ptvt;o. I FMC 1hq, 1,4�9' 2 ;Ype PPI) AB Nod) Flo. co.pt�o ko* On 3Ot:S 'XXD' S'SSV n;ppt¢ St 2 cr`e' 4 Flo* c—pi-g (500- OD77' S. 3-112', 9,3-. L-80, ePrl IS --j '.blq 6, Ors :� RH*hydloAtc let';elsoll 7.. Ots X' volv (V,<AS' P ot She D), t!aMl PaCke, M5 --%'a panned P AFPTH 527, 333' 5,161 5911, �832' 5,86e S'Sn- CB ifrG-R TUML 121A We oh t 13-318, 61 11�;" ORD CS9. 9-5/81 4 569' ST&C Cig 21 2 14 . S..l Loci, 26 ORD Csq 3-1/2' 9.3 EUE AS re.-. , BPD LIOSFv K? 'o top or I'l 3 N-PF'GRATION 28L6 laltryal Zone L! " 60SS:-6047' 9-3 IP 4 12/9/c9 Squeezed 6034 -6060* 8-3 60 60 -6080, 9-3 6104'-6146' S-3A 42 9/ /a, 152'- 6 6158� 2-3A 111831-6 84 3-71A RECOVID JUL C«-, P,on CTU Sqz Cons- ";T10 issw " 603-�' '-'ahed to &Cos 1157' -/2,70' nU. Anch()TV B-3 P-3A 5.000' Sub seo :U211P8 soke' Ned 'K• Re., �e--i P, NEc Ret. P0;i.71 DI'M Iq ... , , TSQZ & M410"I Re— 111;�"Sq r") = 63V, Current Schematic 0 n S-. 203.0" Lt 50 t33t2a-01 A0 wooA.024'1003 LOWOM 177 Q1' AOL 4 317,31a.w 2A33,90967 00' 3D 29 7 N laff: 151- v STY W p�O12L200r3 r o3r13+= 1 plftffigg 0120'2003 0 05.00 rv3 1 •a' 00 0.0ar -an cnmk-9 w'® "o. 11nrp 11M wwo manoM H t,50a' ' w cr*ck valve 0ai lAt MarlOret a , -,- �.... _ ... 3.910r.5.9WjSMr.5, tar T.'.71.. 6 W(TOWN) 9-2 6.Ct17'4.Oa3lS.1C7-S.it�TVt)1.a�ttlttRV47t &3 0.035'404r41tat-S.A97 r'. xvlivIMI O.k &3 a.03a'4ow 45,107-3,19C D1 atpr lonswl &3 8.05Q"4.OaD i52D1`dt21a' TYOt. a 1015"30w) 6.3 a.OW4 COD (s=-3216 Tv01, a w r312102i &3 a,tOt'.Qfaa'ts,S3f'-1..2T?TWI.saGt lEitsEQ> &3A C,10r4 "ff IS2W.3ZM TSDt. 41 WfW2107t 0-3A d.157.a;1',!O'(5277-S2ODTVD1.atp►tarlSOa) &3A e,i3w4 "iY i32W-52a1• TVC), a w%(925W) &3A s,tarafaris,30D-5301`TVDI,a40rtY2S02) &3A sl= eau won Srkipe Nup O 9 IT, D FM Ta0W 0 9 S99• KB WL3a . Cau tow M10se Nup O tlapt Type ■ LrrMp Cowar Q 4s3a' Float Coln c 9,9w eawoanCeq shoe a. shoe a 9.9w ll Beaver Creek 3 RD Pad 3 1.227- FNI. 1.501' FWL, Sec.34. WN. R10W. S.M. F ACTUAL SCHEMATIC 13.313' 01 ttr• J-W ar 533' c"VIM X0U �47E' a00� 1-55 BTC Q 1.709 1Wrr1491C %-*D Lt M 9f a.a.3a0' C,ro w t5 ceawo r t%l Vve. Cz rl W IM tS Cement � 2nl !g 0 3 W L 4 0 tv WW 'ft D 100 _.... ant t• PBA a 5.Ca3 I 1 trs�— r a3D (7,14W.137 rvDA a fps Q=) M22 ow (7.ns.7.7w, rm% a 1pr G900a) t&23 12r nil3&T.WDri%0 tO1(r50O) MM 5aa• JOA3. rdh 3 Wf'(2a0a36 faC=) LIS—Z C � ipas3.azn•Tvn1.31gc�crooaaaori2oaa) LB�x 577 $a 2CO' TVD) 19d:r'jow 3W 111,M41,310 TVDL 3 W1 iffQWX L.s-2W ??a' ta.sal A4W TWD1 3 wl *21431 L830 Peoducom L war. 3. 2' 92 Sct H1*$ W3 L-W "rare 5, 54M 993' cmro wv 1ca0 at 349 SRS G 12. 7 Wo xC too of V5 In a 137 Wo »t/D . nlsa lncunatlon s>r1r OoPaY: ! aarTVD ss.r�ass3• � >sr7anoaar� Proposed Schematic Beaver Creek 3 RD EASU 1,22T FNL. 1.501' FWL. Sec.34. TIN" R10W. S.M. mats 2 $G" " 30-fnvu4a1-00 Mmunew 1A mxt 131. 1' 177 W aswca] a 05100 ", 1w 00 WOW w" Ct:nacar Myecaan i tea wm nun" a41,39i' wvftell rate Oaf u n NirtArti a 3.ltT __....__._.......-... . 94d-19Wl3.66Y-31¢7TK!).atNI7!Oa94t &2 W-0,047 43.1a4 alav M), 4 w I11±20'67i &] p94'dW4' YS,iQ7-1/9p T"JDI, I ipr 111i20E71 6.1 W4.04T 43, 1417-3.197 TVDI, 4 Wt t11.MM Ba 0ae'A0w f3.tat'-021v TVDY, 41prfdl5106) 8-3 OW'440apt3.Z03'-32tOTVDI.itpr1971Q27 &] 104'.a.t4p i3.2T'-1270 TVD:kdlpt (tyt19a9 &]A ta7'4.1dp 41239''-3270 TVD1. 4 Wt F915WT &3A IW4lap t3.abp321!V TL91.4 VC I9125W) &3A 183".a tat tS,]04.13Qt" TVDI.4 WtW"SWI &3A SCM Cant Ron 8n60e PkV a 1.370' fM Tapac4 a 9,1W K8 Wtr cart ron Brow PON a SAW Type a Lwdm co8m a 11LOW fta41 Conan a 9.9w . cen+etono tnoa a lfat i l6ar 1670 t 1 ID »AWw a.71rTVD PROPOSED SCHEMATIC t 3.3fi 61 A� J-S3 at S]3" Crta � S66 v YML11tf01�ilQ Catl� 93a' ldipp 1SS BtC {] 1.StF7 Cr!tC we7W 1k1 Ceeae•e %i�GO91J' 7- '6 PP1 N40 Pw 9t" 3w C,[C wwo %(. cer ^ t n tY %CW Crla *11W" 7ti Ce"MI h .''ltl /ttaaee Tap of Barn 7. 7x>s PMOWr.4aKe 04XV r an0 315 03 J -3Sa Ci.a]0.8.110'0Ropoie4` 82t Ca4R ton Wbpe ftw a tooa" - = Dn1n0 Do 77 a1 ON w 47,743.7,717TAnaaW1am ul7= 47,774.7,?W TVCPA a a87Clp]Qi I &= 4f,a7E-7,�lpTV e%w W9 ta2YLa23pTvo� 31pfgoao]a$C... I ta.7ar 1a.242A2WTvDJ31p74�DO ,*,t42W5 t,s.2le 0.1034U i'TVIX3sf+4t7GCD).at07pOMDM 18 c ada0'TVD3 aOtA°i M (a,3Cd"6.?!£7 Tv� ] apf 8N2lIOl1 L&M la.saa-B.Np 1V1371 ] 1ar ia'2>m31 t8�30 naarwat unw.. 3.V2- 9 2 00Itlari 363 L. W '"M S 043-9.T9Y CmeC it low a1 349 %kn a 12.7 mg a' IM of 415 sis a 137 MG 9.9112 ND TVD tAa[k tloei.... .rrAOo0lea:._..__� fair ]eWa6.]!r " 3A7'naa'a0.s]r • Drilled in 1968 w/ TD of 6,387' BCU-3 History • 7" casing set @ 6,380' Cemented in 2 stages DV tool @ 2,033' Good return to pits on both stages • Tested Sterling B3 & 1331- Sands in 08/68 — Both zones tested gas — 6,034' — 6,080' and — 6,104' — 6,146' and — 6,152' — 6,158' and • Well left Shut In until 09/82 • Reactivated in 09/82 with workover — Perfs below 6,080' are squeezed off to isolate water — 6,034' — 6,080' are perforated • CTCO in 11/87 to clean out fill & attempt water shut off • 11/88 - workover to shut off water • 12/88 — workover to squeeze off all perfs & mill out cement — Cum Sterling Gas: 19,108 MMscf • 05/93 — DIO #8 approved by AOGCC — Disposal authorized into Sterling B11- / B2 zone @ 5,804' — 5,945' • 07/94 — Recomplete as a water injection well in Sterling B2 — Perforate 5,910' — 5,940' • 10/99 — AOGCC allows injection into BCU-2 (DIO #4) and BCU 3 (DIO #8) from fluids originating outside of Beaver Creek BCU-3RD History • 03/03 — Permit to deepen BCU-3 is approved • 05/03 — BCU-3RD is TD'd • 06/03 — Beluga interval is perforated — 9,768' — 78' — 9,588' — 95' — 9,547' — 55' — 9,526' — 44' — 9,512' — 22' • 07/03 — Pumped frac job on open Beluga Perfs • 04/05 — Set CIBP @ 9,570' to isolate lower perfs • 05/05 — Re-perf open intervals @: — 9,547' — 55' — 9,526' — 44' — 9,515' — 22' • 05/05 —Add perforations — 9,115' — 27' — 9,050' — 60' — 9,020' — 30' • 12/05 — Run 1.75" velocity string to help unload • 02/06 — Last known Beluga production — Cum Beluga Gas: 70MMscf • 08/07 —Remove 1.75" velocity string Support Docs Company: On Stream: 091011982 Field: BEAVER CREEK of Current Status: Abandoned lol- �g 6 F 4 a 3 a � p C 2 1.0 s a z I 103 kr Beaver Creek #3 STERLING Gp: 19108 6161sct lip: 0.00019stb %Vp:199.351 Mstb Ocond: 0.000 Mstb 0 Company: On Stream: NMI t2005 Field: BEAVER CREEK m' Current Status: Abandoned 103 1.0 Gp: 70 MMscf tip: 0.000 Mstb Beaver Creek #03RD Wp:0.047 P.1stb e�...�. Ocond: 0.000 R3stb BCU-3 7" Casing Cement Record 8/12 7" CasinR Detail Eff. From To - KB to top of casing 0 17.30 21 jts., 7", 23#1, N-80, Seal -lock 854.47 17.30 871.77 1 jt., 711, 23#, N-80, X-over 41.78 87.1.77 913.55 27 jts., 711, 26#, N-809 8RD 1,120.13 913.55 2,033.68 1 Halliburton DV Collar 2.05 2,033.68 2,035.73 105 jts., 7", 26#, N-80, 8RD 4,300.87 2,035.73 6,336.60 1 Halliburton Fill Collar 1.80 6,336.60 6,328.40 1 jt., 7", 26#, N-801 8RD 39.83 6,338.40 6,378.23 1 Halliburton Float Shoe 1.60 6,378.23 6,379.83 TD 60387' - Cemented 7" casing with 1ST stage - 650 sacks class "G" with 0.5 R5 and 1% D-19, mixing time 30 minutes, slurry weight - 14.2# per gal., plug down at 8:09 A.M., 8/12/68, mixing and final pressure - 2,100 PSI. opened DV tool and circulated 150 sx to pit. Waited on cement 2 hours. Cemented 2nd stage - 335 sx class ""G" with 2% CACL, mixing time 10 minutes. Slurry wt. - 15.1# per gallon, mixing and final pressure 2,300 PSI. Good returns throughout. Circulated 80 sx. to pit. Cement in place at 10:55 A.M., 8/12/68. Set 7" slips, cut off pipe and installed tubing hanger. Tested seals in hanger with 3,000 PSI for 15 minutes - CK. Nippled up. Tested 3V rams, blind rams and hydril with 1,500 PSI - GK. Picked up 3-�" drill pipe. BCU-3 09/82 ATTACHMENT BC 01 Workover was completed as follows: Reactivation 1. The well was killed w/ workover fluid and the 3-1/2" rhg was pulled and layed down. PU 3-1/2" DP 6 CO fill 6147-6319'. 2. RIH w/ inspected 3-1/2" tbg. Flow tested the Sterling B-3 and B-3A at 6.06 MMCFD, 845 BWPD and some sand. Flared 2539 MCF of gas. 3. Ran temp, noise and CCI. logs; PBTD @ 6309' CBL. Flow tested well at 6.2 MMCFD,550 BWPD and some sand during log. Flared 799 MCF of gas. 4. Pulled 3-1/2" tbg. Ran test pkr on DP. Flow tested B-3 perfs at 2.64 MMCF and 0 water. Flared 320 MCF of gas. 5. Perfd 6184'-6183' DIL w/ 4" csg gun, 4 HPF. Set cmt rtnr @ 6170' DIL. Squeezed 150 sx C1 G cmt into perfs, recovered 45 sx cmt. 6. Perfd B-3A 6107'-6146' DIL w/ 2-1/8" Enerjet, 4 HPF. 7. Flow tested B-3A at 4.93 MUD, 706 BWPD and some sand. 8. Flow tested lower B-3A, 6152'-6158' DIL, no flow. 9. Perfd 6158'-6160' DIL w/ 2-1/8" Hyperdome, 4 HPF to assurp holes in casing and flow tested. No flow. .0. Set cmt rtnr @ 6098'. Squeezed 150 sx Cl G cmt into perfs at 6104'- 6146', 6152'-6158', and 6158'-6160' DIL. Recovered 15 sx cmt. J. Reperfd B-3 6060'-6080' DIL w/ 4" Hyperjet II csg gun, 4 ILM Tagged PBTD @ 6091' CBL. L2. RIH w/ 3-1/2" tbg. Set pkr @ 5846'. Flow tested the well at 10.22 MMCFD, 0 BWPD. Flared 2654 MCF of gas. L3. SI the well. Total gas flared: 6312 MCF. B-3 Perforations: 6034'-6060' DIL, 4 HPF 6060'-6080' DEL, 8 HPF ....; D10 #S Conclusions CONCLUSIONS: 1. The approval of disposal injection operations at BCU 3 will not jeopardize correlative rights. 2. Permeable strata which reasonably can be expected to accept injected fluids at pressures less than the fracture pressure of the confining strata are present in the interval from 5804 to 5945 feet measured depth in BCU 3 3. Adequate confining zones exist above the receiving zone which assure injected fluids will not endanger USDWs. 4 Cement bond logs indicate the casing strings are adequately cemented to prevent vertical migration of disposal fluids behind casing 5. Disposal fluids injected at BCU 3 will consist exclusively of Class 11 waste generated from drilling. corrgletion and production operations. 8. BCU 3 was constructed in conformance with the requirements of 20 AAC 25.412. 7 Wen integrity must be demonstrated in accordance with 20 AAC 25.412 prior to initiation of disposal operations in BCU 3 B Operational parameters will be monitored routinely at BCU 3 for disclosure of possible abnormalities in operating conditions NOW. THEREFORE, IT IS ORDERED THAT Rule 1 Authorized Injection Strata for Disposal. Class N oil field fluids may be injected in conformance with Alaska Administrative Code Title 20. Chapter 25, for the purpose of disposal into the Sterling Formation interval from 5804 to 5945 feet measured depth in BCU 3. Rule 2 Demonstration of Tubing)Casing Annulus Mechanical Integrity Prior to initiating injection and at least once every four years thereafter, the tubingicasing annulus must be tested for mechanical integrity in accordance with 20 AAC 25 412. Rule 3 Well Integrity Failure Whenever operating pressure observations or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, the operator must notify the Commission on the first working day following the observation. obtain Commission approval of a plan for corrective action and obtain Commission approval to continue injection. Rule 4 Step Rate Test Prior to sustained injection the operator shall perform a step rate test to determine a formation fracture gradient and optimum injection pressure. Rule 5 Administrative Action Upon request, the Commission may administratively revise and reissue this order upon proper showing that any changes are based on sound engineering practices and will not result in an increased risk of fluid movement into an underground source of drinking water_ DONE at Anchorage, Alaska and dated May 13, 1993. David W. Johnston, Chairman Alaska CM and Gas Conservation Commission Russell A. Douglass, Commission Alaska Oil and Gas Conservation Comrission Permission to Transfer Class 2 Fluids to Beaver Creek & Dispose in BCU-2 / BCU-3 ALASKA OIL AND GAS CONSERVATION COMMISSION October 22. 1999 Lvndon lbele Marathon Oil Company PO Box 196168 Anchorage, AK 99516-6168 7ONYKNOWLES.GOVERNOR ?"WPOACUPINE CtIVE AUCHOPAGE.ALASKA 99?,51�1192 PHONE, (907} 279-1A00 Pax 907)276.11W Re: authorization to Inject Produced Water from the Wolf Lake Development Area into Beaver Creek Unit Disposal Wells Dear Mr. Ibele By letter dated October i. 1999 ,you have asked Commission for approval to inject produced water from future Wolf Lake area natural gas wells into two existing Beaver Creek Unit Class 11 disposal wells. Disposal Injection Order No. 4 limits injection in the Beaver Creek Unit +a2 (BCU-2) well to nonhazardous oil field waste fluids. Disposal Injection Order No. 8 authorizes the injection of Class 11 oil field fluids into the Beaver Creek #3 (BCU-3) well. Other than the requirement that infected fluids be Class I1 in nature. the disposal injection orders place no limitations on the source of the injected fluid. Commission regulations, Alaska Administrative Code Title 20. Chapter 25 also do not limit the source of injected fluid The Commission does not obiect to Marathon's request to transfer produced water from the Wolf Lake wells to the two permitted Class 11 disposal «ells at Beaver Creek Unit Marathon must maintain compliance with the conditions of the disposal injection orders and relevant Commission regulations at all times. Care must be taken to properly track and manifest waste material. Marathon should also ensure that adequate training is provided for any personnel handling waste prior to disposal The Commission must be notified immediately if Marathon learns of any injection of waste that is not Class 11 into either the BCU-2 or 11CU-3 wells Sfnv Robert N Christenson. P E. Chairman BCU-3 Request to Deepen • Marathon tpartrar Oil Company March 14, 2003 Sarah Patin Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West r Ave, Suite 100 Anchorage, AK 99501 Reference: Drilling Permit Application Field: Beaver Creek Field Well: Beaver Creek Unit BC-3RD Dear Ms. Palin Alaska Region Domestic Production P.o. Box 196168 Anchorage, AK 99519-6168 Telephone 9071561.5311 Fax 9071564-W9 Enclosed please find the PERMIT TO DRILL application, along with the associated attachments. The intent is to deepen the existing wellbore Beaver Creek Unit BC-3 and then complete the well in the Lower Beluga. If you require further information. I can be reached at 907-564-6310 or by e-mail at wjtank@ma rathon, com. Sincerely, �jlit �Cy�. Willard J. Tank Senior Drilling Engineer Enclosures DECEIVED MAR 14 2003 4v01 a.1& WS Cars. Camtti NIM Anchorage Permit to deepen BCU-3 ID ALASKA OIL AND GAS CONSERVATION COMUSSION W. J. Tank Senior Drilling Engineer Marathon Oil Company P. 0. Box 196168 Anchorage, Alaska 99519-6168 9 FRANK H. MURKOWSKI, GOVERNOR 333 IN 7- AVENUE, SUITE too ANCHOPAOF. ALASKA "501 -35n PHONE MM 279,1433 FAX MM 2MT542 Re: Beaver Creek Unit BC-3RD Marathon Oil Company Permit No: 203-044 Surface Location: 1227' FNL, 1501' FWL, St"C 34, T7N, RIOW, SM Bottomhoic Location: 2172'FSL, 413'FEI., SEC. 27, T7N, RIOW, SM Dear Mr. Tank: Enclosed is the approved application for permit to rcdrill the above development well. This permit to rcdrill does not exempt you from obtaining additional permits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. The permit is approved subject to full compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issuance of a conservation order approving a -pacing exception. Marathon Oil Company assumes the liability of any protest to the spacing exception that may occur. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the pennit. Picase provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's North Slope petroleum field inspector at 059-3607 (pager). Ran-dyZcdrich Commissioner BY ORDER OF T11F COMMISSION DATED IW� day of March. 2003 cc: Department offish & Game, Habitat Section win end Department of Environmental Consetva(ion win cnct Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket # DIO 14-002. The application of Hilcorp Alaska, LLC. (Hilcorp) for an order authorizing the underground injection of Class 11 oil field waste at the Beaver Creek Field. Hilcorp, by letter received October 29, 2014, requests the Alaska Oil and Gas Conservation Commission (AOGCC) issue an order under 20 AAC 25.252. This order would authorize the disposal of Class II oil field field waste by injection into the Sterling Formation of the Beaver Creek Unit 3RD well (1227' FNL, 1501' FWL, Sec. 34, T7N, R10W, S.M.). The AOGCC has tentatively scheduled a public hearing on this application for January 6, 2015, at 9:00 a.m. at 333 W. 7`h Ave., Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the AOGCC no later than 4:30 p.m. on December 4, 2014. If a request for a hearing is not timely filed, the AOGCC may consider the issuance of an order without a hearing. To learn if the AOGCC will hold the hearing, call 793-1221 after December 15, 2014. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 W. 7"' Ave., Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on December 20, 2014, except that, if a hearing is held, comments must be received no later than the conclusion of the January 6, 2015 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Jody Colombie, at 793-1221, no later than December 26, 2014. Cathy P Foerster Chair, Commissioner STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMIT INVOICE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION WUH ATTACHED COPY OFADVERTSMENT. ADVERTISING ORDER NUMBER AO-1 5-008 FROM: Alaska Oil and Gas Conservation Commission AGENCY CONTACT: Jody Colombie/Samantha Carlisle DATE OF A.O. 11/14/14 AGENCY PHONE: 1(907) 793-1221 333 West7th Avenue Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: Publish 11/18/14. FAX NUMBER: (907)276-7542 TO PUBLISHER: Alaska Dispatch News SPECIAL INSTRUCTIONS: PO Box 149001 Anchorage, Alaska 99514 TYPE OF ADVERTISEMENT: LEGAL DISPLAY CLASSIFIED OTHER (Specify below) DESCRIPTION PRICE D10 14-002 Initials of who prepared AO: Alaska Non -Taxable 92-600185 :SUBMIT AuYOxcE sf;VI NG:A Y] R7lsir? '..:O:RDERNO,;C:ER 1FIEDA.F.... I .......: .................................. ' EUBL:ICA3ION'WIiI[ ATI'ACIiED'COPY dF ADVEtt7t514iENT:TO; ::::::: : Department of Administration Division of AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Page 1 of 1 Total of All Pa es S REF Type Number Amount Date Comments I PvN ADN84501 2 Ao AO-15-008 3 4 FIN AMOUNT SY CC PGN1 LCR ACCT FY DIST I,IQ I 15 02140100 73451 15 2 3 4 5 Pur h ip i Na a Title: 4 / c thor' 's S' nature Telephone Number 0.1#an receiving agency\4Lajpe must appear on all invoices and docume la _,g to his purchase. he state is registered for tax free transactions under Chapter 32, IRS code R istration number 92-73-0006 K. Items are or the exclusive use of the state and not for sale. AISTRIBUTION . Division 'scA/Oki haIAO::« ::::::Ca`ies >Pulilisher:.fazed :Division F"tscal a2eceiviri::::::::......::::::::::.... . .1.... F;......! ...................P.,s:P b .....(.....� ..V ..........�........ g.......................................... Form:02-901 Revised: 11/14/2014 270227 0001353842 $ 199.22 N 0 V 21 2014 AFFIDAVIT OF PUBLICATION,AOGCC STATE OF ALASKA THIRD JUDICIAL DISTRICT Kayla Lavea being first duly sworn on oath deposes and says that he/she is a representative of the Alaska Dispatch News, a daily newspaper. That said newspaper has been approved by the Third Judlciai Court, P'%nc forage, 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 November 18, 2014 and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Signed Subscribed and sworn to before me this 18th day of November, 2014 Notary Public in and for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSION EXPIRES Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket # DIO 14-002. The application of Hilcorp Alaska, LLC. (Hilcorp) for an order waste at the authorizing the underground injection of Class II l Hilcorp, by letter received October 29, 2014, requests the Alaska oil and Gas Conservation Commission (AOGCC) issue an order under 20 AAC 25.252. This order would authorize the disposal of Class II oil field field waste by injection into the Sterling Formation of the Beaver Creek unit 3RD well (1227' FNL, 1501' FWL, Sec. 34, WN, R10W, S.M.). The AOGCC has tentatively scheduled a public hearing on this applicat' oon for January 6, 2015, at 9:00 a.m. at 333 W. 7th Ave., Anchorage, a 99501. To rethe tentative hearing be helld ka written requestuest mu that be filed with the AOGCC scheduledAOGCC later than 4:30 p.m. on December 4, 2014. If a request for a hearing is not timely filed, the AOGCC may consider the issuance of an order without a hearing. To learn if the AOGCC will hold the hearing, call 793-1221 after December 15, 2014. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 W. 7th Ave., Anchorage, Alaska 99501. Comments must be received no later than 4:30 P.M. on December 20, 2014, except that, if a hearing is held, comments must be received no later than the conclusion of the January 6, 2015 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Jody Colombie, at 793-1221, no later than December 26, 2014. AO-15-008 Published: November 18, 2014 Cathy P. Foerster Chair, Commissioner Singh, Angela K (DOA) From: Colombie, Jody J (DOA) Sent: Monday, November 17, 2014 11:16 AM To: AKDCWeIIIntegrityCoordinator, Alexander Bridge; Allen Huckabay; Andrew VanderJack; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Barron, William C (DNR); Bill Penrose; Bill Walker, Bob Shavelson; Brian Havelock, Burdick, John D (DNR); Carrie Wong; Cliff Posey; Colleen Miller, Corey Cruse; Crandall, Krissell; D Lawrence; Dave Harbour, David Boelens; David Duffy; David Goade; David House; David McCaleb; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAA); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Francis S. Sommer, Frank Molli; Gary Oskolkosf, George Pollock; ghammons; Gordon Pospisil; Greg Duggin; Gregg Nady; gspfoff, Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jones, Jeffery B (DOA); Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW); Jim Watt; Jim White; Joe Lastufka; news@radiokenai.com; John Adams; Easton, John R (DNR); John Garing; Jon Goltz; Jones, Jeffrey L (GOV); Juanita Lovett, Judy Stanek, Houle, Julie (DNR); Julie Little; Kari Moriarty; Keith Wiles; Kelly Sperback; Kiorpes, Steve T; Klippmann; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker, Louisiana Cutler, Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Michael Jacobs; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; MJ Loveland; mjnelson; mkm7200; Morones, Mark P (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Randy Redmond; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Sternicki, Oliver R, Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler, Tim Mayers; Tina Grovier (tmgrovier@stoel.com); Todd Durkee; Tony Hopfinger, trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Walter Featherly; yjrosen@ak.net; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; David Lenig; Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr, Smith, Graham O (PCO); Greg Mattson; Dickenson, Hak K (DNR); Hans Schlegel (hans.schlegel@ge.com); Heusser, Heather A (DNR); Holly Pearen; James Rodgers; Jason Bergerson; Jennifer Starck; jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey, King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Bettis, Patricia K (DOA); Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pexton, Scott R (DNR); Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, William Hutto; William Van Dyke; Ballantine, Tab A (LAW); Bender, Makana K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Hunt, Jennifer L (DOA); Kair, Michael N (DOA); Konkler, Stacey L (DOA); Loepp, Victoria T (DOA); Mayberry, David J (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, lames B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L To: (....,,); Seamount, Dan T (DOA); Singh, Angela , k,,OA); Skutca, Joseph E (DOA); Wallace, Chris D (DOA) Subject: Notice Scans Attachments: Notice of Public Hearing, CO-14-032.pdf, Notice of Public Hearing, DIO-14-002.pdf Bernie Karl James Gibbs Jack Hakkila K&K Recycling Inc. Post Office Box 1597 Post Office Box 190083 Post Office Box 58055 Soldotna, AK 99669 Anchorage, AK 99519 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. Post Office Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Larry Greenstein Richard Wagner Darwin Waldsmith Hilcorp Alaska, LLC Post Office Box 60868 Post Office Box 39309 Post Office Box 244027 Fairbanks, AK 99706 Ninilchik, AK 99639 Anchorage, AK 99524-4027 Q OVQ JI " % 2-0' -� Angela K. Singh Carlisle, Samantha J (DOA) From: Wallace, Chris D (DOA) Sent: Friday, November 07, 2014 11:36 AM To: Colombie, Jody J (DOA) Cc: Carlisle, Samantha J (DOA) Subject: FW: Request to reactivate DIO #8 using BCU 03RD Attachments: BCU 3 Water Disposal Info 10-16-14.pptx Jody, Please create a docket for this DIO reactivation application. It will probably be numbered as DIO 8A to indicate the updated findings, conclusions, and rules. The commission should notice and schedule a hearing. Thanks and Regards, Chris Wallace Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7t,, Avenue Anchorage, AK 99501 (907) 793-1250 (phone) (907) 276-7542 (fax) chris.waIlace@alaska.gov CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at 907-793-1250 or chris.wallaceCaalaska.gov. r From: Larry Greenstein[mailto:lgreensteinC@hilcorp.com] Sent: Wednesday, October 29, 2014 4:00 PM To: Wallace, Chris D (DOA) Subject: Request to reactivate DIO #8 using BCU 03RD Hi Chris, We talked a couple of weeks ago about this idea and the engineer has put together a presentation to explain the plan for you to peruse. We'd be glad to come over and discuss this concept with you. Basically, the BCU 03 well was deepened to became a gas producer, BCU 03RD. Now dead, we'd like to plug back the well and reperf into the originally approved disposal zones using the original DIO #8. We believe this would be acceptable to AOGCC as the well itself will become nearly identical to the original BCU 03 except for an additional casing string and more cement across the disposal zone (ie even better isolation and containment than originally in place). Please review the attachment and consider how best to approach this reactivation — maybe an Admin Approval DIO #8.001 for the new (same as the old) well or a DIO #8A for the new API and PTD?? What would be the cleanest plan forward to gain approval for this additional Class II disposal capacity at Beaver Creek?? Thanks and let me know what you think and if you have any follow-up questions. Larry BCU-3 Well History Sterling BlL / B2 Water Disposal Reactivation Jason Ewiv-,-- 10-15-1' Request Overview • BCU-3 was permitted as a Sterling 131L / B2 disposal well by the previous operator, Marathon, in 05/93 • BCU-3 was subsequently deepened to 10,005' to access the Beluga interval • Hilcorp plans to isolate all Beluga perforations by setting a plug @ 9,000 ft then dump bailing 35 ft of cement • Hilcorp is requesting to re -activate DIO #8 to allow injection into Sterling 131L / B2 Zone @ 51804' — 51945' • Hilcorp is requesting to perforate the Sterling 131L / B2 sand @ 5,804' — 5,945' at the some depth in the original BCU-3 wellbore as previously permitted in DIO #8 • Gas lift valve in BCU-3RD wellbore will be dummied off to allow appropriate MIT testing • If GL valve leaks, Hilcorp will pull the tubing and run 3.5" tubing with packer down to —5,600' to satisfy state injection requirements BCU 3 WBD —Post B3/B3A Abandonment & Pre-B2 Completion for Disposal (July-94) MARATHON OIL COMr^a`J'i i SPAVER CREEK UNI, { 1 LjiLl spud Date 7/26/68 GPI W 21 13J-?11!?, Or gmo? RK& 16' nheve GL Ccnp'.etfan Date- . /8/88 Tap of Ster'r,g: 5955' Ma-- Mole Angie ' P 29f.B` Angie ThrougH S`.rlt Annulus Ft.i& FW ./KCL Reference Log: DIL 11'_.r%,_ AU depth- are RKD MD to top of equlement. tEWELRY t 2 4 e Sterling B2 Perforated @ 51910' — 5,940' in 07-94 for Water Disposal 6 i R Old B3/B3A Squeezed perforations are now isolated with 3.5" liner-------- W&o Type fins Producer lrw � brkaver M R-cO pleti4a 1 FMC Tbg. Hng 'ype TC i)EN (3- EUc 8RD A3o Nd) 2, Ft.. coupling 1500" 7D 11 3 Otls 'kyO' SSSV nlpole 4. Flo. eoupano t5.00' O➢ °,'}:' 1➢:. 5. 3-If2', 9.3*, L-B0. 8RD Lu.nq E Ala M,Aui Tub. >. Otis 'RH' hydrau0c ret-i-able pnC§cr. 7. Otis 'Y' mpple l2.?5' I6) 8, Ot,s Shear Sub/Re-entry. ',,A, 14..51-,' Or, K ` 8B' 10). N3TEI Packer has stra._rt oa0 vear-P.?IoaSe pinned P 38,900v 527 5J6 5,91 5.8 32' 5.86 B' 5,301' rASIN"�,I!$jtI[r 13-2/6' 61 ,. 5* 'i �73. BRC. CsO, 9-5/8, 40 .-55 0 :.56`1 STBC Cxy. 23 ry-80 0 514' Seal L.c4 26 .r_8.n al a' Sv9r.: BRD Csg. 3-1/2, 9.3 L-90 0 `.906' BRD EUE AD Hcd bKJMi KB to tea of 13'3,'r. PERFORATION DATA I-teryal 74_n_C. F ; ',.^-_F. C"-tS 1,tyf.q-T.yDR 6035'-604" ➢•3 1? A. 12/9!88 Squeezed 6034'-6060` D-3 <'6' 4 :0/1S/89 ' 6060-6090` D-3 20' 8 ' 6104'-6146' B-3A 4c" 9 9/25/82 6I52'-6158, ?-3A , . 6193`-6164` --3A ' JUL Cm-, fron CTU Sqz �i aS Gaff$. I:➢n1n1i65101: @ 6035' reamed to 6C57' ./2.70' rill. v AnchMge D-3 9-3A Rr r_ka* ,000' Sub Sea ➢on:er Re,se:1 F" NEF Re t. P 6177,' DFH Re".a _:nn ^T'„ S6Z 8 t+Uout pl<-us Rrvls.en. 11f3/88 TD - 639" Current Schematic ud,,.,l, sr,-Ln. r l � 0-t0-133.4 533.2t712L.at.a6 _—cam ran seep. rw 0 tusk' Fi T4ppM O?.7M Its MIIJI Cal ran Bodge Plug O lWOJ T!'at ■ L.andN Ce sar 0 9.f3p' Fi t Colla- Z 9 40A ---- _J eetnnlMrp 0' a lk"a Beaver Creek 3 RD Pad 3 1.227' FNL, 1,501' FWL. Sec.34, WN. R10W. S.M. t .reds i 3J3f ACTUAL SCHEMATIC t3.313 B1 Pif 1-0 ig 33T CPO9 4maI �3ft m" a, r 23 ppl IV-+llt Trorn 0.974 r 2a PO 04-M ftw "".Ka Crete WM mks CM04 V 1st ItW Crmfl/ tM�33 sks Carrerd Rv 2n9 six= .__: Ttp ci Btker r Zfw i�aber. atd : PBFi a$ 5 643 9AI30aow 77.T43�7,7Y1 T/D'1 a s1ASxoll L8'.1' Mg ow (7,T74-7,lax T rvA a SP1 {"MY L8,22 9.1Iva 127 47xwf,0Yf Tom a 500,2M5-', Ls'n 9.51S-9.-W 40,21d-0.23L1• TlCty. 3 W 4�33a0 Sid d291f1'5) LBJ3a. 9 3M95" 40.242.82W TID',, 3 SPt;Z30 0 Wf 42D'd51 LB,*b 9.54r-9.5W 40,2WA27I' T DX 3 sO42'r M7 11 SO QDZ) LB-Ift Cpw 9.57v 4432W rM Met 4'2 M 9;500'-9391 4B.3M.6,3/U TVM 3SO`d'311131 LB,IM 9.7W-9. rM 40AWAA 9V TVD} 3 SO C621N31 LB-79 3"VT 9.2 WC Ht11a W3 L-00 Ram 3943.9,997 Cnfa W kffi of MR sks Q 127 PPp a71 tat d 415 Sky a 13.7 W0. t8! i Mu kvc0na0Orc On Dapkq: !,N! T11D 3GAr 0 &Mr S.s7-llap' a 0.433' Proposed Schematic FEil—p A6A., LIA `. I�atilw:� 299-0M �P11� 30-133-X12"1.00 BnW2bL= AA2=3 11g�1j�31T.31Q99' 173 i21' AGL} c C 2A33,90AW LaftgL W 39' 290 41 LMWMICi5vr5.79W Ian paYnaaik OV20am a W- rlls. Gas Lat Mwldm1 __V.—cam trod tirldQe twup Q l I �FM Tm" • 9.Na' M V" cat tray ■ed0a PM10l9.99� Tape n Und" COW ! &*W C"Werwnp at= a 1999` PROPOSED SCHEMATIC s�ata[! t 13-3Rr 3 3 ;d w Gml vom "offmoye Cal=m HTC +ip 1. J� C"" VAI" sks COME" r M aai NM fmm 0.91A' 7-M PO w-0o Sam 9M .MP GwM wwo fk, GaoeK.4f 1st nine, CMV vf= fits CM09 ti 2W SO= TuPd &doer T zw Padaer,9.kw Wqc i zw r Pw Q 7.643 _ Gast tort BrkW Pluo is' !_000' Dump tall 39 of cement Wr IR64W urn�e In axe • Drilled in 1968 w/ TD of 6,387' BCU-3 History • 7" casing set @ 6,380' Cemented in 2 stages — DV tool @ 2,033' Good return to pits on both stages • Tested Sterling B3 & B3L Sands in 08/68 — Both zones tested gas — 6,034' — 6,080' and — 6,104' — 6,146' and — 6,152' — 6,158' and • Well left Shut In until 09/82 • Reactivated in 09/82 with workover — Perfs below 6,080' are squeezed off to isolate water — 6,034' — 6,080' are perforated • CTCO in 11/87 to clean out fill & attempt water shut off • 11/88 - workover to shut off water • 12/88 — workover to squeeze off all perfs & mill out cement — Cum Sterling Gas: 19,108 MMscf • 05/93 — DIO #8 approved by AOGCC — Disposal authorized into Sterling B1L / B2 zone @ 5,804' — 5,945' • 07/94 — Recomplete as a water injection well in Sterling B2 — Perforate 5,910' — 5,940' • 10/99 — AOGCC allows injection into BCU-2 (DIO #4) and BCU 3 (DIO #8) from fluids originating outside of Beaver Creek BCU-3RD History • 03/03 — Permit to deepen BCU-3 is approved • 05/03 — BCU-3RD is TD'd • 06/03 — Beluga interval is perforated — 9,768' — 78' — 9,588' — 95' — 9,547' — 55' — 9,526' — 44' — 9,512' — 22' • 07/03 — Pumped frac job on open Beluga Perfs • 04/05 — Set CIBP @ 9,570' to isolate lower perfs • 05/05 — Re-perf open intervals @: — 9,547' — 55' — 9,526' — 44' — 9,515' — 22' • 05/05 — Add perforations — 9,115' — 27' — 9,050' — 60' — 9,020' — 30' • 12/05 — Run 1.75" velocity string to help unload • 02/06 — Last known Beluga production — Cum Beluga Gas: 70MMscf • 08/07 —Remove 1.75" velocity string Support Docs Company: On Stream:09l01l1982 Field: BEAVER CREEK Current Status: Abandoned 102 } 104 9 8 7 101 {9 a O 1.0 I 1 Beaver Creek #3 STERLING Gp:19108 P,7Mscf tip: 0.000 Mstb Wp: 199.351 M11stb Qcond: 0.000 Mstb `-i Gp: 70 NIMscf Up: 0.000 Mstb Beaver Creek #03RD Wp: 0.047 Mstb BELUGA Qcond:0.000 Mstb 102 Company: On Stream:0WOV2005 Field: BEAVER CREEK of Current Status: Abandoned 103 71 BCU-3 7" Casing Cement Record 8/12 7" Casing Detail Eff. From To KB to top of casing 21 jts., 7", 23#, 19-80, Seal -lock 854.47 0 17.30 17.30 871.77 1 jt., 7#% 23#, N-80, X-over 41.7,8 871.77 913.55 27 jts., 711, 26#, N-809 8RD 1,120.13 913.55 2,033.68 1 Halliburton DV Collar 2.05 2,033.68 2,035.73 105 jts., 7", 26#, N-80, 8RD 4,300.87 2,035.73 6,336.60 1 Halliburton Fill Collar 1.80 6,336.60 6.3-18.40 1 jt., 7", 26#, N-80, 8RD 39.83 60338.40 6,378.23 1 Halliburton Float Shoe 1.60 6,378.23 6,379.83 TD 60387' - Cemented 71" casing with 1ST stage - 650 sacks class ""G" with 0.57. R5 and 1% D-19, mixing time 30 minutes, slurry weight 14.2# per .gal., plug, down at 8:09 A.M., 8/12/68, mixing and final pressure - 2,100 PSI. Cpened DV tool and circulated 150 sx to pit. Waited on cement 2 hours. Cemented 2nd stage - 335 sx class ""G" with 2% CACL, mixing time 10 minutes. Slurry gat. - 15.1# per gallon, mixing and final pressure 2,300 PSI. Good returns throughout. Circulated 80 sx. to pit. Cement in place at 10:55 A.M., 8/12/69. Set 7 " slips, cut off pipe and installed tubing hanger. Tested seals in hanger with 3,000 PSI for 15 minutes - OK. Nippled up. Tested 3 V rams, blind rams and hydril with 1,500 PSI - OK. Picked up 3�" drill pipe. B C U- 3 09/82 ATTACHMENT BC 13 Workver was completed as follows: Reactivation killed fluid and the 3-1/2" tbg was pulled 1. The well was w/ workover and layed down. PU 3-1/2" DP & CO fill 6147'-6319'. 2. RIH w/ inspected 3-1/2" tbg. Flow tested the Sterling B-3 and B-3A at 6.06 MMCFD, 845 BWPD and some sand. Flaked 2539 14CF of gas. 3. Ran temp, noise and CCL logs; PBTD @ 6309' CBL. Flour tested well at 6.2 MMCFD.550 BWPD and some sand during log. Flared 799 MCV of gas. 4. Pulled 3-1/2" tbg. Ran test pkr on DP. Flow tested B-3 perfs at 2.64 MMCF and 0 water. Flared 320 11CF of gas. 5. Perfd 61841-6183' DIL wl 4" csg gun, 4 HPF. Set cmt rtnr () 6170' DTL. Squeezed 150 sx Cl C cmt into perfs, recovered 45 sx curt. 6. Perfd B-3A 6107'-6146' DIL w/ 2-1/8" Enerjet, 4 HPF. 7. Flow tested B-3A at 4.93 MMCFD, 706 BWPD and some sand. 8. Flow tested lower B-3A, 6152'-6158' DIL, no flow. 9. Perfd 6158-61601 DIL wl 2-1/8" Hyperdome, 4 HPF to assure holes In casing and flow tested. No flow. LO. Set cmt rtnr @ 6098. Squeezed 130 sx Cl G cmt into perfs at 61041- 6146', 6152'-6158', and 6158'-6160' DIL. Recovered 15 sx cmt. Ll. Reperfd B-3 6060'-6080' DIL w/ 4" Hyperjet 11 csg gun, 4 HPF- Tagged PBTD @ 6091' CBL. L2. RIH w/ 3-1/2" tbg. Set pkr @ 5846'. Flow tested the well at 10.22 MMCFD, 0 BWPD. Flared 2654 14CF of gas. D. Sl the well. Total gas flared: 6312 MCF. B-3 Perforations- 6034'-6060' DIL, 4 HPF 6060'-6080' DTL, 8 HPF DIC) #8 Conclusions CONCLUSIONS: 1. The approval of disposal Injection operations at BCU 3 will not jeopardize correlative rights. 2. Permeable strata which reasonably can be expected to accept injected fluids at pressures less than the fracture pressure of the confining strata are present in the interval from 5804 to 5945 feet measured depth in BCU 3. Adequate confining zones exist above the receiving zone which assure injected fluids wig not endanger USDWs. 4. Cement bond logs indicate the casing strings are adequately cemented to prevent vertical migration of disposal fluids behind casing. 5. Disposal fluids injected at BCU 3 will consist exclusively of Class g waste generated from drilling, completion and production operations. 8. BCU 3 was constructed in conformance with the requirements of 20 AAG 25.412, 7 Well integrity must be demonstrated in accordance with 20 AAC 25.412 prior to initiation of disposal operations in BCU 3, 8. Operational parameters will be monitored routinely, at BCU 3 for disclosure of possible abnormalities in operating conditions. NOW, THEREFORE, IT IS ORDERED THAT: Rule 1 Aulforized Injection Strata for Disposal. Class A oil field fluids may be injected in conformance with Alaska Administrative Code Title 20, Chapter 25, for the purpose of disposal Into the Sterling Formation interval from 5804 to 5945 feet measured depth in BCU 3, Rule 2 Demonstration of Tubing/Casing Annulus Mechanical integrity Prior to initialing injection and at least once every four years thereafter, the tubing/casing annulus must be tested for mechanical integrity in accordance with 20 AAC 25.412 Rule 3 Well Integrity Failure Whenever operating pressure observations or pressure tests indicate pressure communication or leakage of arty casing, tubing or packer, the operator must notify the Commission on the first working day following the observation, obtain Commission approval of a plan for corrective action and obtain Commission approval to continue injection. Rule 4 Step Rate Test Prior to sustained injection the operator shag perform a step rate test to determine a formation fracture gradient and optimum injection pressure. tle 5 Administrative Action Upon request, the Commission may administratively revise and reissue this order upon proper showing that any changes are based on sound engineering practices and wig not result in an increased risk of fluid movement into an underground source of drinking water. DONE at Anchorage, Alaska and dated May 13, 1991 David W. Johnston, Chairman Alaska Oil and Gas Conservation Commission Russell A Douglass, Commission Alaska 09 and Gas Conservation Commission Permission to Transfer Class 2 Fluids to Beaver Creek & Dispose in BCU-2 / BCU-3 t1LASKA OIL AND GAS CONSERVATION COMMMSSIO.N October 22, 1999 Lvndon Ibele Marathon Oil Company PO Box 196168 Anchorage, AK 99516-6168 TONY KNOWLES. GOVERNOR 'Dll PORCUPINE QRIbF A NCHOQA(',F, AUSK. 9%-)1-3192 PHONE i907)279-1433 F.AX. 9071276-7542 Re: authorization to Inject Produced Water from the Wolf Lake Development Area into Beaver Creek Unit Disposal Wells - Dear Mr. Ibele: By letter dated October 7, 1999 you have asked Commission for approval to inject produced water from future Wolf Lake area natural gas wells into two existing Beaver Creek Unit Class I disposal %veils. Disposal Injection Order No. 4 limits injection in the Beaver Creek Unit #2 (BCU-2M well to nonhazardous oil field waste fluids. Disposal injection Order No. 8 authorizes the injection of Class It oil field fluids into the Beaver Creek 43 (BCU-3) well. Other than the requirement that infected fluids be Class II in nature. the disposal injection orders place no limitations on the source of the injected fluid. Commission regulations, Alaska Administrative Code Title 20. Chapter 25 also do not limit the source of injected fluid. The Commission does not obiect to Marathon's request to transfer produced water from the Wolf Lake wells to the tvio permitted Class II disposal %%ells at Beaver Creek Unit Marathon must maintain compliance with the conditions of the disposal injection orders and relevant Commission reuulations at all times. Care must be taken to properly track and manifest waste material. Marathon should also ensure that adequate training is provided for any personnel handling waste prior to disposal. The Commission must be notified immediately if Marathon learns of any injection of waste that is not Class If into either the BCU-2 or BCt"-3 �� ells Sinc v Robert N Christenson. P.E. Chairman BCU-3 Request to Deepen 0 Mammon iraRor Oil Cwnpany March 14, 2003 Sarah Patin Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7" Ave, Suite 100 Anchorage, AK 99501 Reference: Drilling Permit Application Field: Beaver Creek Field Well: Beaver Creek Unit BC•3RD Dear Ms. Patin Alaska Region Domestic Production P.O. Box 196168 Anchorage, AK 99519.6168 Telephone 9071561.5311 Fax 9071564.6489 Enclosed please find the PERMIT TO DRILL application, along with the associated attachments. The intent is to deepen the existing wellbore Beaver Creek Unit BC-3 and then complete the well in the Lower Beluga. If you require further information, I can be reached at 907-564-6310 or by e-mail at v jtank@marathon.com. Sincerely, Willard J. Tank Senior Drilling Engineer Enclosures RECEIVED MAR 14 2003 A asks h, x Lsas Cws. Commi"M Mction" Permit to deepen BCU-3 ib S`ff6l(I� no IF #�I!JI3IYII^1 ALASKA OIL AND GAS CONSERVATION COMMISSION W. J. Tank Senior Drilling Engineer Marathon Oil Company P. O. Box 196168 Anchorage, Alaska 99519-6168 9 FRANK N. MURKOWSKI, GOVERNOR 333 W. 7-AVENUE. SOME 100 ANCHORAGE, ALASSKA 9950/ 753.9 PHONE (907t 279.1d,3 FAX (Wnt M,7542 Re: Beaver Creek Unit BC-3RD Marathon Oil Company Permit No: 203-044 Surface Location: 1227' M, 1501' FWL, SEC. 34, T7N, RIOW, SM Bottomhole Location: 2172' FSL, 413' FEL, SEC. 27, T7N. R I OW, SM Dear Mr. Tank: Enclosed is the approved application for permit to redrill the above development well. This permit to redrill does not exempt you from obtaining additional permits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. The permit is approved subject to full compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issuance of a conservation order approving a spacing exception. Marathon Oil Company assumes the liability of any protest to the spacing exception that may occur. Operations must be conducted in accordance with AS 3L05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness tmy required test. Contact the Commission's North Slope petroleum field inspector at 659-3607 (pager). Sincerely, �y taodrich Commissioner BY ORDER OF THE C.OMM1SSION DATED thm day of March, 2003 cc; Department of Fish & Game, Habitat Section w/o encl. Depanntcnt of Environntcntat Conservation w/o, encl.