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CO 720
CONSERVATION ORDER NO. 720 North Fork Field 1. November 11, 2015 CIE application for Pool Rules 2. November 13, 2015 Notice of Public Hearing, Affidavit of Publication, bulk mail list, email distribution list 3.---------------------- Division of Oil and Gas, North Fork Unit Fact Sheets 4. January 5, 2016 Public Hearing Transcript, CIE presentation, sign -in sheet CONSERVATION ORDER NO. 720 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF Cook Inlet Energy, LLC for an order for the classification of a new gas pool and to prescribe pool rules for development of the Undifferentiated Tyonek Gas Pool, North Fork Unit, onshore Kenai Peninsula Borough, Alaska Docket Number: CO-15-014 Conservation Order 720 North Fork Field North Fork Unit Tyonek Gas Pool Kenai Peninsula Borough, Alaska February 8, 2016 IT APPEARING THAT: 1. By application received November 12, 2015, Cook Inlet Energy, LLC (CIE), in its capacity as operator of the North Fork Unit, requested an order defining a new gas pool, the North Fork Unit Undifferentiated Tyonek Gas Pool (Tyonek Gas Pool), within the North Fork Unit (NFU) and prescribing rules governing the development and operation of the pool. 2. Pursuant to 20 AAAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) tentatively scheduled a public hearing for January 5, 2016. On November 13, 2015, 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, electronically transmitted the notice to all persons on the AOGCC's email distribution list, and mailed printed copies of the notice to all persons on the AOGCC's mailing distribution list. On November 16, 2015, the AOGCC published the notice in the ANCHORAGE DAILY NEWS. 3. The hearing commenced at 9:OOAM on January 5, 2016, in the AOGCC's offices located at 333 West 7`h Avenue, Anchorage, Alaska. 5. Testimony was received from representatives of CIE. 6. The record was closed at the end of the hearing. FINDINGS: 1. Operator: CIE is the operator of the NFU, which is located onshore within the southcentral portion of the Kenai Peninsula, approximately 10 miles north-northwest of the City of Homer and adjacent to the Village of Nikolaevsk. The NFU lies within the Kenai Peninsula Borough. 2. Affected Area: The Affected Area is coincident with the current NFU boundary. The Alaska Department of Natural Resources (DNR) currently defines one Participating Area (PA) currently within the NFU, and it is named the Gas Pool 1 PA (Figure 1, below). Conservation Order 720 • • February 8, 2016 Page 2 of 8 i T4S, I R14W Nikolaevsk North Fork Unit Gas Pool 1 PA 23-26 34-26 14-25 4 -35 32-35 ' 4 -35 22-35 T5S, R14W ! 0 1 mile Figure 1. Affected Area for the Proposed NFU Tyonek Gas Pool (enclosed by blue -colored line) 3. Landowners and Owners: The NFU comprises lands owned by the State of Alaska, the Kenai Peninsula Borough, and patented fee lands. CIE is the 100% working interest owner of all lands within the boundary of the NFU. 4. Exploration, Delineation and Production History: The U.S. Department of Interior, Bureau of Land Management (BLM) approved the formation of the NFU on May 27, 1965. At that time, the NFU comprised 640 acres. The NFU gas accumulation was discovered by NFU 41-35, an exploratory well that was drilled by Standard Oil Company of California (SOCAL) during 1965 to the Hemlock Formation. Instead of oil, the well encountered commercial gas accumulations within the Tyonek Formation (Tyonek). The well was completed as a dry gas producer that was shut-in awaiting infrastructure and favorable market conditions. A December 1965 press release from SOCAL announced NFU 41-35 was a new, dry -gas discovery that tested at a rate of about 3,370 thousand cubic feet per day from a sand at 8,005 feet measured depth (MD). 1 This map is provided for illustration purposes only. Please refer to the Affected Area legal description on pages 5 and 6 of this order for the precise representation of the proposed NFU Tyonek Gas Pool. For the current outline of the Gas Pool 1 Participating Area, please refer to the Alaska Department of Natural Resources, Division of Oil and Gas, Oil and Gas Unit Fact Sheet for the North Fork Unit(http://www.dop,.dnr.alaska.gov/Units/UnitMal)s.htm). Conservation Order 720 • February 8, 2016 Page 3 of 8 NFU Tyonek Gas Pool SP 01If.�. D.Pt a.4 P..." -- Sp 100 M1u 0 Gp to Gip <MD P-CXP LD) RIMCIM") z oH.en 200 i es G© z �.SA-sa rvess> N"NA) 0 DTCRan <MD - 50 US+F Sc 4000 5000 i000 6000 , U00 7000 j 8000 - 9000 -— -—=: -9000— 10000 11000 Figure 2. NFU 41-35 — Type Well Log for the Tyonek Gas Poole 2 Figure 2 is for illustration purposes only. Please refer to the well log measurements recorded in exploratory well NFU 41-35 for the precise representation of the proposed Tyonek Pool. The horizontal grid lines in this figure represent increments of one hundred feet measured depth. NFU 41-35 is a directionally drilled (slanted) well. The acronym TVDSS refers to true vertical depth subsea (true vertical depth below sea level). Conservation Order 720 • February 8, 2016 Page 4 of 8 In 2007, Armstrong Cook Inlet, LLC (ACI) became owner and operator of NFU and subsequently acquired 3D seismic data across the area. During 2010, ACI drilled two wells, NFU 14-25 and NFU 32-35, to establish the extent of the Tyonek gas accumulation. Both wells were completed as gas producers, facilities were installed, and regular production from the North Fork Undefined Gas Pool began in March 2011. During 2012 and early 2013, ACI drilled two and completed additional Tyonek gas producers, NFU 23-25 and NFU 22-35. On January 31, 2014, CIE became operator for the NFU. Since then, CIE has drilled and completed two additional Tyonek gas producers, NFU 24-26 and NFU 42-35, and has obtained Permits to Drill for two additional wells. 5. Previous AOGCC Orders: AOGCC has issued twelve separate Conservation Orders for the NFU. Eleven of these orders approved exceptions to statewide well spacing requirements. The twelfth order, Conservation Order 649, concerns regulation of sustained casing pressures in development wells. 6. Pool Identification: The proposed NFU Tyonek Gas Pool comprises the gas -bearing intervals common to, and correlating with, the interval between 4,840 and 10,797 feet MD in the NFU 41-35 well. 7. Geology: a. Stratigraphy: Within the NFU, the Oligocene- to Miocene -aged Tyonek is informally divided into upper, middle and lower members, which are 2,800 feet, 1,800 feet, and 1,700 feet thick, respectively. The proposed NFU Tyonek Gas Pool encompasses the upper and middle members only; the lower Tyonek is non -productive in this area. Reservoir sandstones in the upper and middle portions of the Tyonek are generally lenticular in cross-section and laterally discontinuous. These sandstones were deposited in river channels, stream channels, overbank flows, and crevasse -splays within basin -margin alluvial fans and within braided to meandering fluvial systems along the basin axis. In the proposed development area, individual Tyonek sandstones range from approximately 10 to 60 feet in thickness, and they are interspersed with layers of coal, shale, claystone, and siltstone that were deposited in low -relief marshes or swamps. b. Structure: Within the development area, the northeast -trending North Fork Anticline measures about 1-1/2 miles long and 1 mile wide, and it is bounded on the southeast by a high -angle reverse fault. Natural gas has accumulated along the crest of this anticline. Two northwest -trending normal faults divide the anticline into northern, central, and southern fault blocks, with the central fault block forming a graben that dips sharply to the east. To date, drilling and production been limited to the southern and central fault blocks, with the southern block being the most drilled and, therefore, the most prolific producer. c. Trap Configuration and Seals: Well log and seismic information indicate that the gas accumulations within the Tyonek reservoir sandstones are trapped by both structural and stratigraphic elements. These reservoir sandstones are encapsulated in, and separated by, layers of coal, shale, claystone, and siltstone. Conservation Order 720 • February 8, 2016 Page 5 of 8 d. Reservoir Compartmentalization: Presently, gas has been tested or produced from a total of twelve different sands within the NFU. The encapsulated, discontinuous nature of the alluvial and fluvial reservoir sands coupled with the northwest -trending normal faults indicate the proposed pool will be highly compartmentalized. 8. Reservoir Fluid Properties: A gas -sample laboratory analysis report from NFU 41-353 and formation -gas composition measurements recorded on mud logs4 indicate that Tyonek reservoirs within the North Fork Unit contain only dry natural gas that consists predominantly of methane with very small amounts of ethane and butane and traces of propane and pentane. 9. Waiver Request for Wellbore Survey Requirements for Permit to Drill Applications: CIE requests the requirements described in 20 AAC 25.050 (b) be waived for the proposed gas pool to relieve administrative burden. In lieu of requirements under 20 AAC 25.050(b), CIE proposes that permit to drill applications for deviated wells shall include a plat with a plan view, vertical section, close approach data, and a directional program description. CONCLUSIONS: 1. Pool Rules for the development of the North Fork Unit Tyonek Gas Pool within the North Fork Unit are appropriate. 2. The Tyonek contains discontinuous sandstone reservoirs that were deposited in braided to meandering rivers and streams, as overbank deposits, and in crevasse -splays and thus there is little lateral continuity between individual sandstone reservoirs within the proposed pool. 3. Correlative rights of landowners outside of the defined Affected Area will be protected. NOW THEREFORE IT IS ORDERED: This Conservation Order supersedes CO 649 dated June 21, 2011. The findings, conclusions and administrative record for CO 649 are adopted by reference and incorporated in this decision, except where inconsistent with this Conservation Order. The development and operation of the North Fork Unit Tyonek Gas Pool is subject to the following rules and the statewide requirements under 20 AAC 25 to the extent not superseded by these rules: 3 Laboratory analysis report from NFU 41-35 provided as Attachment 1 to CIE's Application for Pool Rules. 4 Mud log prints examined: NFU 41-35, NFU 34-26, NFU 32-35, NFU 23-25, NFU 22-35, NFU 24-26,and NFU 42- 35. Conservation Order 720 • • February 8, 2016 Page 6 of 8 Affected Area: Seward Meridian Townshi & Range Section Portions T. 4 S., R. 14 W. Section 23 SE1/4 Section 24 S1/2SW1/4 Section 25 NW1/4NE1/4, S1/2NE1/4, W1/2, N1/2SE1/4, SW1/4SE1/4 Section 26 NE 1 /4, S 1 /2NW 1 /4, S 1 /2 Section 27 SE1/4NE1/4, El/2SE1/4 Section 35 ALL Section 36 N1/2NW1/4, SW1/4NW1/4, NW1/4SW1/4 T. 5 S., R. 14 W Section 3 Lots 1-3 (which encompass the N 1 /2NE 1 /4 and the NE1/4NW1/4), SW1/4NE1/4, SE1/4NW1/4, E1/2SW1/4, NW1/4SE1/4 Rule 1 Field and Pool Name The field is the North Fork Field. Hydrocarbons underlying the Affected Area and within the interval identified in Rule 2, below, constitute the gas pool named the North Fork Tyonek Gas Pool. Rule 2 Pool defmition The North Fork Tyonek Gas Pool comprises the gas -bearing intervals common to and correlating with the interval between the measured depths of 4,840 and 10,797 feet MD recorded in the NFU 41-35 well. Rule 3 Well Spacing There shall be no restrictions as to well spacing except that no pay shall be opened in a well within 1,500' of an external property line where the owners and landowners are not the same on both sides of the line. Rule 4 Sustained Casing Pressure (Restated from CO 649) The operator shall conduct and document a pressure test of tubulars and completion equipment in each development well at the time of installation or replacement that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. 2. The operator shall monitor each development well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for Commission inspection. 3. The operator shall notify the Commission within three working days after the operator identifies a well as having (a) sustained inner annulus pressure that exceeds 2000 psig or (b) sustained outer annulus pressure that exceeds 1000 psig. Conservation Order 720 • February 8, 2016 Page 7 of 8 4. The Commission may require the operator to submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in paragraph 3 of this rule. The Commission may approve the operator's proposal or may require other corrective action or surveillance. The Commission may require that corrective action be verified by mechanical integrity testing or other Commission -approved diagnostic tests. The operator shall give the Commission at least twenty-four (24) hours notice for opportunity to witness diagnostic testing, refer to Industry Guidance Bulletin 10-001 for proper contacts. 5. If the operator identifies sustained pressure in the inner annulus of a development well that exceeds 45% of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45% of the burst pressure rating of the well's surface casing for outer annulus pressure, the operator shall notify the Commission within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before Commission approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The Commission may approve the operator's proposal or may require other corrective action. The Commission may also require that corrective action be verified by mechanical integrity testing or other Commission -approved diagnostic tests. The operator shall give the Commission at least twenty-four (24) hours notice for opportunity to witness diagnostic testing, refer to Industry Guidance Bulletin 10-001 for proper contacts. 6. For purposes of these rules, "inner annulus" means the space in a well between tubing and production casing; "outer annulus" means the space in a well between production casing and surface casing; "sustained pressure" means pressure that (a) is measurable at the casing head of an annulus, (b) is not caused solely by temperature fluctuations, and (c) is not pressure that has been applied intentionally. Rule 5 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 geosciences principles, and will not result in an increased risk of fluid movement into freshwater. Conservation Order 720 0 • February 8, 2016 Page 8 of 8 This order shall expire 5 years after the effective date shown below. DONE at Anchorage, Alaska and dated February 8, 2016. Alth�y"P. F derster Daniel T. Seamount, Jr. Chai , Commissioner Commissioner RECONSIDERATION AND APPEAL As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. • Singh. Angela K (DOA) From: Carlisle, Samantha 1 (DOA) Sent: Monday, February 08, 201611:03 AM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AKDCWellIntegrityCoordinator, Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Amanda Tuttle; Andrew Vanderlack; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Caleb Conrad; Carrie Wong; Cliff Posey; Colleen Miller, Crandall, Krissell; D Lawrence; Dave Harbour, David Boelens; David Duffy; David House; David McCaleb; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; Gordon Pospisil; Gregg Nady; gspfoff, Hyun, James J (DNR); Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jerry McCutcheon; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek, Houle, Julie (DNR); Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker; Louisiana Cutler, Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (ma rk.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Mealear Tauch; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Stephen Hennigan; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler, Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Caroline Bajsarowicz; Casey Sullivan; Diane Richmond; Don Shaw; Donna Vukich; Eric Lidji; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Jason Bergerson; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster; William Van Dyke Subject: Conservation Order 720 (North Fork Unit) Attachments: co720.pdf 0 • Please see attached. Samantha Carlisle Executive Secretary III Alaska Oil and Gas Conservation Commission 333 West 761 Avenue Anchorage, AK 99501 (907) 793-1223 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Samantha Carlisle at (907) 793-1223 or Samantha.Carhsle@alaska.eov. James Gibbs Jack Hakkila Bernie Karl K&K Recycling Inc. P.O. Box 1597 P.O. Box 190083 P.O. Box 58055 Soldotna, AK 99669 Anchorage, AK 99519 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Conrad Perry Richard Wagner Darwin Waldsmith Drilling Manager P.O. Box 60868 P.O. Box 39309 Cook Inlet Energy, LLC Fairbanks, AK 99706 Ninilchik, AK 99639 601 W. 5`h Ave., Ste. 310 Anchorage, AK 99501 �-@ �Ce�cUer�'�, 2a\CQ Angela K. Singh • 1 ALASKA OIL AND GAS CONSERVATION COMMISSION 2 3 Before Commissioners: Cathy Foerster, Chair 4 Daniel T. Seamount 5 In the Matter of the Application of ) 6 Cook Inlet Energy, LLC, for the ) 7 Establishment of Pool Rules Governing ) 8 Development of the Tyonek Gas Pool ) 9 in the North Fork Unit. ) 10 ) 11 Docket No.: CO 15-014 12 13 ALASKA OIL and GAS CONSERVATION COMMISSION 14 Anchorage, Alaska 15 16 January 5, 2016 17 9:00 o'clock a.m. 18 19 VOLUME I 20 PUBLIC HEARING 21 22 BEFORE: Cathy Foerster, Chair 23 Daniel T. Seamount, Commissioner 9 • 1 TABLE OF CONTENTS 2 Opening remarks by Chair Foerster 03 3 Remarks by Mr. Jones 4 Remarks by Mr. Kirkland 09 11 2 1 P R O C E E D I N G S 2 (On record - 9:05 a.m.) 3 CHAIR FOERSTER: I'll call this hearing to 4 order. Today is January 5th, 2016, it's 9:05 a.m. 5 We're located at 333 West Seventh Avenue, Anchorage, 6 Alaska in the offices of the Alaska Oil and Gas 7 Conservation Commission. I'll introduce the bench. To 8 my left is Daniel Seamount and I'm Cathy Foerster. We 9 are the two Commissioners. To my right is Mr. Vacant. 10 We're meeting in regard to Docket Number CO 15- 11 014, for the Tyonek Gas Pool, North Fork Unit pool 12 rules. Cook Inlet Energy, LLC, by application dated 13 November 11, 2015, requests that the AOGCC establish 14 pool rules under AAC 25.520 to govern the development 15 of the Tyonek Gas Pool in the North Fork Unit. 16 Computer Matrix will be recording today's 17 proceedings and you can get a copy of the transcript 18 from them. 19 Okay. Cook Inlet intends to testify. Is there 20 anyone else intending to testify? 21 (No comments) 22 CHAIR FORESTER: The Commissioners will ask 23 questions during testimony. We may also take recess to 24 consult with staff to determine whether additional 25 information or clarifying questions are needed. If a N 0 0 1 member of the audience has a question that he or she 2 feels should be asked please submit that question in 3 writing to either Jody Colombie or Samantha Carlisle 4 who are giving the float wave. They will provide the 5 questions to the Commissioners and if we feel that 6 asking the question will assist us in making our 7 determination we will ask. 8 For those testifying please keep in mind that 9 you must speak into the microphones so that -- both of 10 them, so that people in the audience can hear you and 11 so that the court reporter can capture what you're 12 saying as well. Also please reference your slides 13 so that someone reading the public record 10 years from 14 now can follow along. For example refer to the slides 15 by their numbers if numbered or by their titles if not. 16 This is for -- sometimes we get an unruly crowd 17 so this next statement is not -- I hope it's not 18 applicable today. We have a few ground rules on what 19 is allowed relative to testimony. First of all 20 testimony must be relevant to the purpose of the 21 hearing that I outlined a few minutes ago and to the 22 statutory authority of the AOGCC. Anyone desiring to 23 testify may do so, but if the testimony drifts off 24 subject we will limit the testimony to three minutes. 25 Additionally if testimony -- additionally testimony may El 0 • 1 not take the form of cross examination. As I said 2 before the two Commissioners will be asking the 3 questions and finally testimony that is disrespectful 4 or inappropriate will not be allowed. 5 Dan, do you have anything to add for the good 6 of the order? 7 COMMISSIONER SEAMOUNT: I think you said it 8 all. 9 CHAIR FOERSTER: Okay. Well, then let's 10 proceed. I see we've got some gentlemen from Cook 11 Inlet teed up to testify. So let me swear you in. 12 Place -- raise your right hands. 13 (Oath administered) 14 MR. JONES: I do. 15 MR. KIRKLAND: Yes. 16 CHAIR FOERSTER: Okay. Does either one of you 17 wish to be recognized as an expert in a field, say 18 geology or engineering? 19 MR. KIRKLAND: Yes, ma'am. 20 CHAIR FOERSTER: Okay. For the record give me 21 your name. Let's make sure these things are turned on. 22 For the record give us your name, the area of expertise 23 that you wish to be recognized in and then the 24 credentials that warrant recognizing you as an 25 expert..... 5 9 0 1 MR. KIRKLAND: Yes, ma'am. 2 CHAIR FOERSTER: .....such as your experience 3 and your education. 4 MR. KIRKLAND: My name is Gregory Len Kirkland. 5 I am a geologist, petroleum geologist. I have 6 practiced petroleum geology continuously for the last 7 41 years, nearly 42. I would ask that -- I'll give you 8 some qualifications here and I'd ask that I be 9 recognized as an expert witness in this matter. 10 I received a bachelor of science from Lamar 11 University in Beaumont, Texas, May of 1974 and again 12 I've been continuously employed since that date. I 13 have been certified as a petroleum geologist by the 14 American Association of Petroleum Geologists, Division 15 of Professional Geologists for the last 33 years. I did 16 my first evaluation of the Cook Inlet in 1978 for Getty 17 Oil Corporation and I've been intimately involved with 18 the Cook Inlet since 2003, working for Forest Oil 19 Corporation and most recently for Cook Inlet Energy. 20 I'm currently employed as a senior geologist with the 21 company. I've previously been qualified to testify as 22 an expert witness in Louisiana, Oklahoma, North Dakota, 23 Montana and the Kingdom of Thailand. 24 I would ask the Commission that these be 25 accepted as qualifying me for testifying in this 2 0 0 1 matter. 2 CHAIR FOERSTER: All right. Commissioner 3 Seamount, do you have any questions? 4 COMMISSIONER SEAMOUNT: Mr. Kirkland, what 5 school did you go to in Beaumont? 6 MR. KIRKLAND: Lamar University. 7 COMMISSIONER SEAMOUNT: Lamar. Okay. And, 8 let's see. By the way I've got you beat in years, I 9 didn't realize that, by two years. Question -- this is 10 a personal question, has nothing to do so I got less 11 than three minutes to speak. 12 CHAIR FOERSTER: Exactly. And you're wasting 13 it right now. 14 COMMISSIONER SEAMOUNT: You worked for Getty 15 Oil Company, it was bought by Chevron, correct? 16 MR. KIRKLAND: Bought by Texaco. It was..... 17 COMMISSIONER SEAMOUNT: Oh. 18 MR. KIRKLAND: .....later acquired by Chevron. 19 COMMISSIONER SEAMOUNT: Okay. And did you 20 retire from them? 21 MR. KIRKLAND: No. I -- that was many years 22 ago. I most recently retired from Forest Oil 23 Corporation in 2012. I had been working for Cook Inlet 24 Energy doing night work free gratis for three years 25 prior to the retirement with the approval of Getty or 7 1 Forest Oil Corporation. And I came up in April of 2012 2 and went on the payroll as a full-time employee for 3 Cook Inlet Energy. 4 COMMISSIONER SEAMOUNT: Okay. My selfish 5 reason for asking the question was I worked for Unocal 6 which was bought by Chevron and they can't split out my 7 retirement between the two companies. 8 MR. KIRKLAND: Same problem..... 9 COMMISSIONER SEAMOUNT: We -- okay. 10 MR. KIRKLAND: .....believe me. 11 COMMISSIONER SEAMOUNT: That's all I have. Oh, 12 I have no -- I have no further questions and no 13 objections to considering Mr. Kirkland as an expert 14 witness in the field of petroleum geology. 15 CHAIR FOERSTER: Well, since my husband went to 16 Lamar for one year and one of my favorite nieces got 17 her chemical engineering degree from Lamar I have no 18 questions and no reservations either. Please proceed. 19 MR. KIRKLAND: Thank you, ma'am. 20 CHAIR FOERSTER: You can -- oh, and are you 21 going to testify as well? 22 MR. JONES: Yes, my name is Timothy Jones, I am 23 the senior landman for Cook Inlet Energy. I don't wish 24 to be recognized as an expert, but I'm the -- just kind 25 of, you know, assisting Greg here with our g • 1 presentation. We do have a presentation if you wish to 2 see it. If you have any questions about anything, you 3 know, feel free to interrupt as we go through it. 4 CHAIR FOERSTER: I think Commissioner Seamount 5 has several questions. But please proceed, we'll try 6 not to interrupt in the middle of the train of thought, 7 but sometimes that happens. But go ahead. And don't 8 forget to reference your slides for the record. 9 MR. KIRKLAND: Yes, ma'am. 10 CHAIR FOERSTER: Okay. 11 TIMOTHY JONES 12 previously sworn, called as a witness on behalf of Cook 13 Inlet Energy, LLC, stated as follows on: 14 DIRECT EXAMINATION 15 MR. JONES: This slide is current land status 16 and this is a land status map that will probably not 17 win any awards for map making skill, but this does show 18 the lease position for the North Fork Unit and also 19 some of the land status surrounding the North Fork 20 Unit. The North Fork Unit is made up of five leases 21 and the leases are all held 100 percent by Cook Inlet 22 Energy. And they also are 100 percent owned by the 23 Department of Natural Resources as the landowner. The 24 leases were first acquired by Cook Inlet Energy in 25 February of 2014 from Armstrong Cook Inlet and the 6 1 first leases were actually established back in 1954 so 2 this is an older unit within the Cook Inlet. There are 3 some surrounding leases, most notably there is one DNR 4 lease, ADL392664 which is owned by Wenda Kennedy and 5 that is to the northwest of the unit and to the 6 southeast of the unit. There's also some CIRI 7 surface/subsurface lands to the east and southeast of 8 the unit. And I believe Hilcorp has a lease on at 9 least part of that land. 10 CHAIR FOERSTER: What's the southern boundary 11 of the North Fork Unit? 12 MR. JONES: The southern boundary is ADL390603, 13 you can see it down there kind of in the center of the 14 map in section three and it borders the CIRI land to 15 the south. 16 CHAIR FOERSTER: Oh, is 390603 part of the 17 North Fork Unit or..... 18 MR. JONES: Yes, ma'am. Yeah, that piece..... 19 CHAIR FOERSTER: Okay. So the southern 20 boundary is the CIRI -- is the lower edge of the..... 21 MR. JONES: Correct, yes. 22 CHAIR FOERSTER: Okay. 23 MR. JONES: Yeah, the lease, ADL390603, that 24 kind jagged boundary on the map..... 25 CHAIR FOERSTER: Is part of it. 10 1 MR. JONES: .....is the border of the unit. 2 CHAIR FOERSTER: On the handout the..... 3 MR. JONES: On the -- on the east, yes. 4 CHAIR FOERSTER: .....the line didn't show up 5 very clearly. Thank you. Sorry for the interruption. 6 MR. JONES: Okay. We're going to go to the 7 next slide. 8 GREGORY L. KIRKLAND 9 previously sworn, called as a witness on behalf of Cook 10 Inlet Energy, LLC, stated as follows on: 11 DIRECT EXAMINATION 12 MR. KIRKLAND: This is a list of the existing 13 wells in the North Fork Unit. 14 CHAIR FOERSTER: And it's titled Current Well 15 Status? 16 MR. KIRKLAND: It is titled Current Well Status 17 North Fork Unit. There have been a total of eight 18 wells drilled within the unit. Again this is the 19 status of the North Fork Unit. Number 14-25 was a 20 discovery well, I believe it was drilled -- I believe 21 by Shell. It is currently producing gas. The only 22 well in the field that is currently off production is 23 the North Fork Unit 23-25. That well is not capable of 24 production, there's no tubing in the well. All of the 25 remaining wells are presently producing. Since 11 1 acquisition by Cook Inlet Energy we have drilled two 2 wells within the field, North Fork Unit number 24-26 3 and the North Fork Unit number 42-35. Both wells were 4 successful in varying degrees. 5 The next slide titled Structure Top of 6,700 6 Foot Sand, is a structural picture showing the major 7 components of the field. It also shows cumulative 8 production of the existing wells. As you look at the 9 slide you see three major structural faults there. The 10 field is bounded down to the southeast by a thrust 11 fault thrusting from northwest to southeast. The field 12 proper is situated in a hanging wall of that thrust 13 fault. It consists of a four way structure with a 14 southern down to the north, normal fault and a northern 15 down to the southwest normal fault bisecting the 16 structure. The bulk of the production to date has come 17 from the southwest quadroon of the field upthrown on 18 that down to the north normal fault. There's also a 19 graben in which several wells have been drilled. These 20 have been disappointing for the most part. And a 21 largely unexplored northern fault block up to the 22 northeast that we have future plans for establishment 23 of a separate pad and drilling of that portion of the 24 field. 25 On this slide the black contours again are 12 0 s 1 structural on top of the 6,700 foot sand. You can see 2 the well positions. If you will notice in the 3 northwestern portion of the map there are two dashed 4 lines. These are wells that are forecast to be 5 drilled, but have not been drilled to date. The eight 6 wells, existing wells, are shown. There's also a well 7 up to the northeast with a dash line, this is a future 8 potential wellbore. 9 Down in the southeastern portion of the field 10 are North Fork Unit 42-35 well. That well has been a 11 disappointment to date. We are looking at a potential 12 sidetrack for that well hoping to find better sands and 13 structurally gain a little bit of structure. 14 I will point out the red dash line around the 15 downdip portion of the reservoir in the southwest 16 quadrant. That is a lowest known gas. To date there 17 have not been any water levels established in the 18 field. It is a completion drive reservoir and again no 19 wet sands have been encountered within the productive 20 interval. 21 If there are no questions for this slide I'll 22 move on. 23 CHAIR FOERSTER: Do you have any questions? 24 COMMISSIONER SEAMOUNT: Where would the red 25 dashed line go on the central fault block? 13 9 • 1 MR. KIRKLAND: On the central fault block it 2 would be near the second contour. I apologize for not 3 having it on this slide, but it would be just updip of 4 the -- oh, the 14-25 well I believe it is. And again 5 in the northeastern fault block we have only seen the 6 very deepest objective section within the Tyonek east. 7 There were three sands penetrated there with good gas 8 shows that were interpreted as being potentially gas 9 productive, but we have not seen the major reservoirs 10 within the field proper in that upthrown fault block on 11 the down to the southwest fault. 12 CHAIR FOERSTER: Because they're not present or 13 because you haven't drilled deep enough? 14 MR. KIRKLAND: All of the wells that are in the 15 field to date with the exception of the 14-25 well have 16 been drilled from a single pad. I'll point it out the 17 Commissioners here. We have a single pad location 18 here..... 19 CHAIR FOERSTER: Okay. 20 MR. KIRKLAND: .....all of the wells have been 21 drilled from that -- that..... 22 COMMISSIONER SEAMOUNT: Does this help. 23 MR. KIRKLAND: Thank you, sir. 24 Typical well design has been to kick the wells 25 off fairly shallow and a reasonably grade angle, 35, 36 14 9 • 1 degrees, push the wells out and then drop back to near 2 vertical. But again all of the wells with the 3 exception of this one well here have been drilled from 4 that single pad. 5 CHAIR FOERSTER: Okay. So..... 6 MR. KIRKLAND: Again no downdip, believe 7 there's no downdip water levels have been established. 8 Some water is produced with the gas production, but 9 it's connate water, it builds up over a period of time, 10 we have to unload the wells and turn them back on. 11 CHAIR FOERSTER: So I'm going to ask my 12 question again. The well that didn't -- to the 13 northeast that didn't encounter the main sand, did it 14 not encounter the main sand because it wasn't drilled 15 deep enough, because the sand wasn't present or some 16 other reason? 17 MR. KIRKLAND: The well that penetrated that 18 fault block is the 23-25, North Fork Unit 23-25 well. 19 CHAIR FOERSTER: Uh-huh. 20 MR. KIRKLAND: Again it was drilled from that 21 central pad. 22 CHAIR FOERSTER: Okay. 23 MR. KIRKLAND: Most of the shallow -- the 24 primary objectives that we've seen in the field were 25 encountered either upthrown on the down to the 15 1 northeast fault or downthrown within the graben until 2 it penetrated this down to the southeast fault. One it 3 went upthrown on that down to the southeast fault the 4 sands that were encountered had gas shows, were 5 interpreted as gas productive. But again you didn't 6 cut this fault until you got down around the 8,000 7 foot..... 8 CHAIR FOERSTER: Okay. 9 MR. KIRKLAND: .....sand level. 10 CHAIR FOERSTER: So you were deeper than 11 the..... 12 MR. KIRKLAND: Yes, ma'am. 13 CHAIR FOERSTER: Okay. Gotcha. 14 MR. KIRKLAND: The potential that we saw was 15 upthrown on that down to the southwest fault. 16 CHAIR FOERSTER: Okay. All right. 17 MR. KIRKLAND: We cannot drill a well because 18 of the displacements necessary that will require..... 19 CHAIR FOERSTER: The geometry won't allow. 20 MR. KIRKLAND: .....a separate pad location to 21 stay upthrown on that fault to evaluate the primary 22 objectives within the field. 23 CHAIR FOERSTER: It's just too shallow to get 24 to? 25 MR. KIRKLAND: Yes, ma'am. 16 1 CHAIR FOERSTER: Okay. All right. Thank you. 2 MR. KIRKLAND: That's the major structural 3 components. In blue you will see the unit outline here 4 on that map. 5 COMMISSIONER SEAMOUNT: Bank when I worked for 6 Unocal I bugged them to do something with this field 7 and I was told by their engineers that there was only 8 half a bcf of gas and it wasn't worth going after. 9 which well were they talking about? I guess they based 10 it off of a depletion..... 11 MR. KIRKLAND: At that time..... 12 COMMISSIONER SEAMOUNT: .....curve. 13 MR. KIRKLAND: Excuse me. At that time there 14 was only one well in the field, this 14 dash -- 41-35 15 well..... 16 COMMISSIONER SEAMOUNT: Okay. 17 MR. KIRKLAND: .....the original discovery 18 well. 19 COMMISSIONER SEAMOUNT: And do you know was 20 that just one sand that had the..... 21 MR. KIRKLAND: There are several sands in 22 there. The -- the production downthrown in the graben 23 has been disappointing to date although the sands are 24 present. I'm not sure whether some of that might be 25 due to formation damage or just -- there's not been a 17 • 0 1 lot done with that well. It is a producing gas well 2 now. Cook Inlet Energy went in and did a workover and 3 perforated some of the additional uphole sands and that 4 well is on production now. It's only cumed about 1.4 5 bcf to date. 6 COMMISSIONER SEAMOUNT: Well, that's three 7 times as much as Unocal thought it would make. 8 MR. KIRKLAND: Slide number 3 is a type log 9 from the North Fork Unit. This is the first well that 10 Cook Inlet drilled, the North Fork Unit 24-26. It's a 11 very small scale log in order to get it all. The 12 shallow section is from the top of the Tyonek at the 13 base at around 9,700 feet measured depth, just below 14 that is the Hemlock. The interval we are asking for 15 the pooling on is between the top Tyonek and the 16 Hemlock the undifferentiated Tyonek gas pool. You'll 17 notice from the log I've actually shaded some of the 18 sands to give you a feel for the nature of the 19 reservoirs here. They're thin bedded sands, very 20 shaley in nature. A lot of interbedded coals as you'll 21 see from the desty (ph) log here, siltstones, 22 mudstones, but typically the sands are anywhere from 10 23 to as much as 60 feet thick, but again very shaley, v 24 shales up to 30, 33 percent metaphysically. But again 25 this gives you a flavor for the nature of the gas 18 0 0 1 reservoirs within the field. To date no wet sands 2 encountered in the Tyonek section that have been 3 identified as totally wet. Very fresh waters, anywhere 4 from three to 5,000 parts per million in the shallow 5 section, down to about 12,000 parts per million in the 6 deeper Tyonek. 7 CHAIR FOERSTER: And you produce these all as 8 one reservoir? 9 MR. KIRKLAND: The typical completion out here 10 had been monobore completions. Armstrong, the previous 11 operator, would go out, typically they perforated -- 12 you see some of the perfs in this particular well, they 13 would go out and perforate some of the deeper sands, 14 possibly as many as three sands within the -- in that 15 monobore and then produce and co -mingle. When we came 16 in, Cook Inlet Energy came in, and drilled the 24-26 17 and the 42-35, we sat numerous packers with sliding 18 sleeves so that we could individually test zones and 19 either co -mingle or produce them separately. That's 20 the types of completion to date. 21 CHAIR FOERSTER: And do you tend to produce 22 them all, some, are your sleeves open or closed? 23 MR. KIRKLAND: The most -- the sleeves right 24 now on most of the wells are open on the two wells 25 we've drilled. I think the maximum number of sands ILI 0 0 1 that we co -mingle are four to date. 2 COMMISSIONER SEAMOUNT: Well, it looked like 3 you have stack pay, do you see evidence of 4 stratigraphic trapping in any of those sands? 5 MR. KIRKLAND: I think there are stratigraphic 6 components. Again -- and I'll get into this a little 7 later, I have a slide. These are fluvial sands coming 8 in generally from the north/northeast, transport being 9 to the south/southwest. They are again very shaley in 10 nature, very thin. And again I've got isopachs that 11 I'll show you the -- the sand geometry further in the 12 presentation. They are very thin, very laminated sand 13 reservoirs, conventional type reservoirs. 14 CHAIR FOERSTER: Have you ever considered 15 hydraulically fracturing to hook up -- I like to call 16 it a chocolate chip cookie and get some of the chips 17 that aren't -- that the wellbore doesn't penetrate? 18 MR. KIRKLAND: Yes, ma'am. We have looked and 19 are continuing to look at possibly fracking some of the 20 zones. Again they're fairly thin in nature, but we've 21 looked at a number of things, conventional fracks with 22 water, we've looked at nitrogen fracks, we even 23 explored that potential hydrocarbon fracks where they 24 go in with butane and use butane as a frack fluid. 25 CHAIR FOERSTER: You know, frack is a four FM 1 letter word now that the environmental community 2 has..... 3 MR. KIRKLAND: Yes, ma'am. 4 CHAIR FOERSTER: .....has taken it away so we 5 say hydraulically fracture so that..... 6 MR. KIRKLAND: To date no fracks have been 7 attempted within the North Fork Unit, there have been a 8 number I believe in Happy Valley and maybe Ninilchik 9 and some of the other..... 10 CHAIR FOERSTER: Uh-huh. 11 MR. KIRKLAND: .....Tyonek gas fields within 12 the basin. 13 CHAIR FOERSTER: Okay. 14 COMMISSIONER SEAMOUNT: Do you see any 15 interference in production between wells? 16 MR. KIRKLAND: We've only seen interference in 17 once well. When we drilled the 24-26, this well 18 here..... 19 CHAIR FOERSTER: You're now on slide number? 20 MR. KIRKLAND: Slide -- I'm sorry, this is the 21 North Fork cross=section..... 22 CHAIR FOERSTER: Okay. 23 MR. KIRKLAND: .....I believe this is slide 24 number 4 if I'm correct. 25 CHAIR FOERSTER: The title is fine, you don't 21 0 0 1 need to number them. 2 MR. KIRKLAND: When we drilled the 24-26 we 3 went in and did an extensive test program within the 4 well. We did see some interference in one sand, we saw 5 about 900 to 1,000 feet of draw down in pressures 6 between this and I believe it was the 22-35 well. So 7 but that's the only zone that I'm familiar with that we 8 did see depletion. And the separation between the two 9 wells at the penetration points was something on the 10 order of 14 to 1,500 feet which basically conforms to 11 what we're asking for in the pool rules. We would have 12 a 1,500 setback from the unit boundaries. 13 This is a cross section again, North Fork Cross 14 Section slide. You can see the line of section up here 15 to the north going from A, A prime, northwest to 16 southeast. It's a cartoon mainly, but it does show the 17 multiplicity of sands that are present within the 18 field. The productive sands in these particular wells 19 are shown in purple. The potential zones that are as 20 yet un-perforated are the hatch or stars. 21 CHAIR FOERSTER: And you're drawing these sands 22 as if they correlate. Do they really correlate or is 23 -- are they just random layers that..... 24 MR. KIRKLAND: The sands in particular do 25 correlate across the field. 22 0 0 1 CHAIR FOERSTER: Okay. 2 MR. KIRKLAND: The coals correlate very well. 3 CHAIR FOERSTER: Okay. 4 MR. KIRKLAND: This is probably one of the 5 coaliest (ph) sections I've ever worked. But the sands 6 -- the intervals correlate. There's quite a bit of 7 stratigraphic variation in the individual reservoirs. 8 And I think when I showed the slide with the 9 anastomosing extremes we'll say that although the 10 intervals correlate they may, in fact, be separate 11 reservoirs because of the geometry of the sand 12 deposition. 13 CHAIR FOERSTER: Okay. Thank you. 14 MR. KIRKLAND: This is a slide titled North 15 Fork Unit, structure 5,600 Foot Sand, Isopach of the 16 5,600 Foot Sand and Depositional Environment cross 17 section consists of four separate panels, a structure 18 map of the 5,600 foot in the upper left quadrant, in 19 the center a net sand isopach. And the isopachs were 20 prepared with existing control of course, well control, 21 transport generally from the north/northeast to the 22 south/southwest. You've only got eight control points 23 here. The -- the third slide you're seeing here shows 24 the nature of the anastomosing extremes here. Some of 25 the control points that I'm mapping because this -- 23 1 this is really -- this one is potentially a half to 2 three-quarters of a mile wide which you don't see in 3 the modern environment, I mean, you see it in the 4 Matanuska, things like that, but typically you don't 5 get that extreme width with some of these sands. What 6 I'm saying is this is possibly a little bit optimistic, 7 I think that you -- there may be some of these 8 anastomosing streams coming through, we just can't 9 break them out as individual sand stringers or sand 10 bodies. But again that's the major components here. 11 As part of -- after Cook Inlet acquired this 12 from Armstrong I was commissioned to go in and do a 13 volumetric reserve study for the field. In the course 14 of that study I prepared structure maps, net sand 15 isopachs, combined the two, we came up with net pay 16 isopachs of 23 separate gas productive intervals within 17 the field either currently producing or interpreted 18 from petrophysical data as being capable of gas 19 production. So we have a total of 23 separate Tyonek 20 sands identified as either productive or potentially 21 productive within the unit. Again you may have a 22 reservoir here and a reservoir here that correlate 23 across the intervals, but they are not correlative 24 reservoirs, they are not the same reservoir. 25 The bottom panel here on the cross section is 24 9 0 1 another cross section showing the deviated nature of 2 these wells, typically kicked off very sharply at 3 shallow depths, the Beluga and Upper Tyonek and then 4 dropped to near vertical in the deeper sections. This 5 has all of the existing wells portrayed in the cross 6 section and again just to illustrate the stratigraphic 7 interval that we're involved with in this pooling 8 request. 9 This is a cross section -- the questions that 10 come up about the 23-25 and the graben here, this is a 11 slide, Major Productive Zones. This is three of the 12 wells, the 41-35, the straight hole we mention, the 14- 13 25 and the 23-25 that are within the graben. We have 14 actually gone in and done workovers in two of these 15 wells and gotten them back onto production since we 16 acquired the field. 17 The main point of this slide, you see the red 18 stars, those are existing perforations that are open in 19 the wells, possible adds in green. Some of these have 20 actually been opened up, this slide has not been 21 modified since we did some recent recompletions in the 22 field. And some major shows off of mud log that were 23 encountered in some of these wells. 24 CHAIR FOERSTER: And what are your percentages 25 on your recent adds? M • 0 1 MR. KIRKLAND: I'm sorry. 2 CHAIR FOERSTER: What are your percentages on 3 your recent adds, have they all been successful or..... 4 MR. KIRKLAND: Generally to date they have. We 5 have perforated several sands in each of the wells, 6 some we got minor response and a 5 psi increase in 7 pressure, others we've increased production several 8 hundred mcf. 9 Did you have a comment, Tim? 10 MR. JONES: Yeah, this is the last slide of the 11 non -confidential portion of the presentation. We do 12 have one confidential slide as well. 13 CHAIR FOERSTER: Okay. So I'm going to put the 14 monkey on Cook Inlet's back to turn around and identify 15 anyone who needs to leave the room. I would say that 16 AOGCC staff which appears to be the entire left side of 17 the room should stay and I'm only seeing one person 18 that we should ask to leave and I apologize because 19 she's one of my favorite people, but if you see anyone 20 else who needs to leave the room you need to identify 21 them now. 22 COMMISSIONER SEAMOUNT: Well, why is this slide 23 confidential? 24 MR. KIRKLAND: It depicts the reserve 25 categories in the field, it shows the pediapase (ph) 26 1 and proved unproducing, but it also shows the PUDS, the 2 probables and the possible locations within the field. 3 MR. JONES: And I agree -- we agree that 4 there's only one person that needs to leave the room 5 for this slide. 6 CHAIR FOERSTER: Okay. This is speculative, 7 it's their reserve estimates, not only their proven 8 reserve estimates, but their potential reserve 9 estimates and that's generally held confidential by a 10 company, but I don't know that we need to see it to 11 make our determination. 12 COMMISSIONER SEAMOUNT: Why would we need to 13 see it? 14 MR. KIRKLAND: It portrays our interpretation 15 of the additional potential that could be drilled 16 within the field. 17 CHAIR FOERSTER: But how will that impact 18 whether or not we see these as good pool rules, 19 if -- what we're driving at is if it's not going to 20 help us make our decision then we'd just as soon not 21 see it. 22 MR. KIRKLAND: Okay. The only way it would 23 impact -- and again generally -- let me go back to the 24 structure map here quickly and I think I can clear this 25 up. This one will do it. 27 1 As you see the field are the unit..... 2 CHAIR FOERSTER: You're back on the slide 3 called North Fork Unit? 4 MR. KIRKLAND: Yes. This is the North Fork 5 Unit slide that I previously showed consisting of four 6 panels. 7 CHAIR FOERSTER: Okay. 8 MR. KIRKLAND: The structure map in the upper 9 left-hand corner there is a structure map on the 5,600. 10 I'll use this to illustrate the reason that it could 11 impact. Some of the possible location -- the proven 12 locations are shown by the well spots, those are the 13 PUDS and the one proved not producing well. 14 Surrounding that you've got a layer of huds that have 15 been assigned that category by an independent reserve 16 auditor. Around that you have probable locations again 17 approaching the unit boundary. And the outermost band 18 of potential locations are the possibles. They -- 19 these have been -- what we did is we divided the field 20 into 80 acre drainage units. Again some of those 21 possibles do abut the unit boundary, but by the 22 application we have asked -- we are excluding the 1,500 23 foot boundary adjacent to that unit boundary. 24 COMMISSIONER SEAMOUNT: Now if you go back to 25 your slide number 2, Current Land Status, I see your 28 i 0 1 neighbor on -- to the east is Hilcorp. Is that a major 2 reason why you want to keep that last slide 3 confidential? 4 MR. KIRKLAND: That's part of it. I mean, we 5 think -- you're going downdip. Structurally you're 6 going downdip to the north/northeast, west/southwest, 7 you're bounded on the southeast by the thrust fault. 8 So you are in a downdip position. The thing is we have 9 not identified downdip limits for the gas accumulation. 10 At some future date, and we do have a well depicted 11 here, the 42-26 well, if that well does not find a 12 downdip limit there could be additional drilling closer 13 to the unit boundary. And again some of those are 14 presently classified as either potential -- probable or 15 possible locations. 16 COMMISSIONER SEAMOUNT: Okay. You've made your 17 case that you've got discontinuous and unticular (ph) 18 sands with one possible showing interference. I wonder 19 if before we get to that confidential slide if we even 20 get to it, if I could ask a few questions. 21 CHAIR FOERSTER: Of course you can. And while 22 he's doing that think about a way to characterize the 23 content of the confidential slides in a way that can be 24 given to the public because I under -- we understand 25 that the numbers themselves are confidential, but a 29 1 characterization of what they're trying to tell us and 2 how it relates to the pool rules needs to be in the 3 public record. 4 MR. KIRKLAND: Yes, ma'am. 5 CHAIR FOERSTER: Okay. But Commissioner 6 Seamount has some questions for you. 7 8 COMMISSIONER SEAMOUNT: Do you have your 9 application in front of you? 10 MR. KIRKLAND: Yes. 11 COMMISSIONER SEAMOUNT: Okay. Let's go to page 12 2 on your application. I'm kind of confused about 13 these prove, probably and possible reserves. I assume 14 that that's not confidential, it's not stamped 15 confidential. Your proved reserves are the ones that 16 have been drilled so far, correct? 17 MR. KIRKLAND: Yes, sir. 18 COMMISSIONER SEAMOUNT: Probable are reserves 19 that you see at wellbores, but you haven't tested? 20 MR. KIRKLAND: No, the probables have not been 21 drilled to date. By definition the probables or the 22 PUDS, I'm sorry, proved undeveloped reserves are 23 adjacent to productive 80 acre drainage units. And 24 beyond that you go into your probables and your 25 possibles, going outward from the existing production. 30 1 COMMISSIONER SEAMOUNT: Well, how did you come 2 up with your numbers up to the one -thousandths of a 3 bcf? 4 MR. KIRKLAND: I'm sorry, I'm not..... 5 COMMISSIONER SEAMOUNT: Your probable is 35.552 6 bcf. 7 MR. KIRKLAND: Oh, okay. The proved reserves 8 -- again we have divided this into 80 acre drainage 9 patterns, we have isopached 23 separate horizons. 10 Those were parameter, the petrophysical data was 11 applied and the engineering data and we calculated 12 volumetrically reserve numbers for the proven 80 acre 13 units. We did the same things for the probables or the 14 PUDS, not so much for the probables and possibles. 15 COMMISSIONER SEAMOUNT: Are the proved includes 16 within the probable or is the probable additional to 17 the proved? 18 MR. KIRKLAND: The probable is in addition to 19 the proved. 20 COMMISSIONER SEAMOUNT: And the possible is in 21 addition the proved and the probable? 22 MR. KIRKLAND: Yes, sir. 23 COMMISSIONER SEAMOUNT: And then I see a 24 combined total reserves of 118 bcf. Is that the 25 addition of proved, probable and possible then? 31 1 MR. KIRKLAND: Yes, sir. 2 COMMISSIONER SEAMOUNT: Okay. I didn't make 3 that addition in my head, it gave me a pain between my 4 ears. What's the proved productive area so far? 5 MR. KIRKLAND: You have eight 80 acre spacing 6 units. So 640 acres roughly, approximately..... 7 COMMISSIONER SEAMOUNT: Okay. 8 MR. KIRKLAND: .....one section. 9 COMMISSIONER SEAMOUNT: You mentioned within 10 your application the Hemlock formation had some oil 11 shows, slight oil shows, but it's got oil potential. I 12 mean..... 13 MR. KIRKLAND: To date two wells within the 14 field have penetrated the Hemlock section. We went -- 15 we entered this 41-35 well, went down to the Hemlock 16 section which consisted of about 20 feet of sand within 17 the Hemlock. We went into that zone, perforated it, 18 tested it separately from the uphole perforations that 19 had been opened. 20 (Whispered conversation) 21 MR. KIRKLAND: I stand corrected. The 14-25 22 well. We went into that well and tested the Hemlock 23 and tested a scum of oil the pits. We estimated 24 somewhere five to 10 gallons of oil coming out of the 25 Hemlock. The 14-25 had already been tested by a 32 1 previous operator and encountered basically the same 2 reserve, the same recoveries. It had a scum of oil 3 from the Hemlock. Right now we don't consider the 4 Hemlock as being a viable economic objective. 5 COMMISSIONER SEAMOUNT: Do you see any way it 6 might become viable, I mean, could you..... 7 MR. KIRKLAND: If oil went back to $130 a 8 barrel potentially, but again results today. Now the 9 nature of the tests that were run, these were not 10 exactly isolated DST type tests, they were really a 11 inefficient manner of testing. 12 COMMISSIONER SEAMOUNT: So there's still some 13 uncertainty until -- in its produceability. Do you -- 14 I mean, is there a potential to frack it into viability 15 or to get up structure or both? 16 MR. KIRKLAND: Again you're working with about 17 two data points and about 20 feet of sand maximum. The 18 cost of the fracking and all of that, economics are 19 pretty iffy at the current status. The nearest oil 20 production is probably Cosmo to this location. So, you 21 know, there's no nearby Hemlock potential to encourage 22 you. 23 COMMISSIONER SEAMOUNT: Okay. 24 MR. KIRKLAND: Again that's outside the limits 25 of our pooling application, we're..... W 9 • 1 COMMISSIONER SEAMOUNT: Right. Right. Okay. 2 MR. KIRKLAND: .....requesting between the 3 Beluga or the top Tyonek and the Hemlock..... 4 COMMISSIONER SEAMOUNT: Okay. I'll leave..... 5 MR. KIRKLAND: .....in our application. 6 COMMISSIONER SEAMOUNT: .....that alone for now 7 then. If we go back to page 2, a recent study of 8 volumetric showed there may be as much as 70 to 80 bcf 9 of original gas in place though recovery from this area 10 will likely be less than 30 bcf. Okay. That's a 11 pretty small percentage of recovery for a gas field and 12 yet on page 4 you're talking about all these 13 reservoirs, A through E, with recoveries of 75 to 80 14 percent. I'm kind of confused about that. How do you 15 go from 30 out of 80 bcf to a recovery factor of 75 to 16 80 percent? 17 MR. KIRKLAND: Well, results to date out here 18 have been really all over the page. You get some of 19 these sands, you go in petrophysically, they're just as 20 shaley in poor in nature as the other sands, they come 21 in great guns. Some of the original wells were 22 completed eight and a half to 9 billion cubic feet a 23 day here. We -- the two most recent wells that we 24 drilled, the 24-26 and a 42-35, were completed for 25 about 2 million cubic feet a day or the 24-26 and 200 34 9 • 1 mcf a day from the 42-35. 2 COMMISSIONER SEAMOUNT: Okay. So the sands A 3 through E are your best sands and they have recovery 4 factors of 80 percent. You've got -- if we go back to 5 page 2 78 to 80 bcf of original gas in place. How does 6 that -- I mean, how does that relate to a combined 7 total reserves of 118 bcf..... 8 MR. KIRKLAND: In looking at..... 9 COMMISSIONER SEAMOUNT: .....that's on page 2? 10 MR. KIRKLAND: .....in looking at this well 11 density of course is going to play a big part of the 12 recoverable reserves. We think we're draining -- Ryder 13 Scott, our outside auditor, assigned 77 acres, we've 14 used 80 acre drainage units in here. And again we've 15 gone -- some of those drainage units have overproduced, 16 they may be drawing from adjacent units, some have 17 underproduced. 42-35 to date, the best it's done is 18 about 200 mcf per day. We don't think it's draining a 19 large area. You get into some of the other wells like 20 the 34-26 shown on the map here, that well has been a 21 very good producer on the crest of the structure. It 22 is probably draining a larger area. You're probably 23 getting 70 to 80 percent recoveries in some of the 24 better developed sands in that well. 25 COMMISSIONER SEAMOUNT: Okay. 35 1 MR. KIRKLAND: The 22-35 well, this well I'm 2 pointing out here, same thing. You're getting some 3 very efficient recoveries in your major sands there. 4 Some of the thinner, shalier sands, you're not going to 5 get 80 percent recovery, you may get 15 or 20 percent. 6 Overall the 70 and 80 percent recoveries are specific 7 sands within the Tyonek. 8 COMMISSIONER SEAMOUNT: Okay. If you see 9 interference between the same sand and two wells are 10 you going to continue to produce those in both wells -- 11 that sand in both wells or just in one well? 12 MR. KIRKLAND: Well, without doing a major 13 workover, these are the two wells involved, the 24-26 14 here and the 22-35 well here. Again there was about a 15 1,500 foot separation, that's the interference we saw. 16 Without a major workover to go in and isolate those 17 perfs, yes, currently they are both open..... 18 COMMISSIONER SEAMOUNT: Okay. 19 MR. KIRKLAND: .....in the two wells. 20 COMMISSIONER SEAMOUNT: Okay. The answer's yes 21 then? 22 MR. KIRKLAND: Yes, sir. That's the only 23 instance we've seen of depletion in the sands 24 encountered to date. 25 COMMISSIONER SEAMOUNT: All right. Okay. Your 0 • 1 middle fault block is a graben I understand; is that 2 correct? 3 MR. KIRKLAND: Yes, that is correct. 4 COMMISSIONER SEAMOUNT: Okay. And you're not 5 happy with the production out of it? 6 MR. KIRKLAND: To date there -- there's really 7 only three wells that have encountered sands within 8 that graben. The 23-25 -- and I'm speaking to the 9 structure on top of the 6,700 foot map, slide number 3 10 I believe it is in the deck. In looking at that the 11 23-25 encountered most of the sands in a downdip 12 position. The 41-35, drilled as a straight oil many 13 years ago, has tested primarily in the deeper section. 14 And the 14-25 well here in kind of an intermediate 15 structural position. Again it has not tested all of 16 the sands encountered potentially productive within the 17 graben. The results to date have generally been from 18 the deeper sands, the 8,500 foot, some of those deeper 19 sands, and those traditionally have not been a high 20 efficiency or high productivity zones. 21 COMMISSIONER SEAMOUNT: Okay. The north/south 22 fault, would you consider that sealing or not sealing? 23 MR. KIRKLAND: This -- you're talking about 24 this fault? 25 COMMISSIONER SEAMOUNT: No, the north -- the 37 1 north/south. The -- between the -- no. 2 MR. KIRKLAND: This one? 3 COMMISSIONER SEAMOUNT: That one. 4 MR. KIRKLAND: It is sealing. The bulk of the 5 production to date has come to date has come from the 6 upthrown side of that fault. 7 COMMISSIONER SEAMOUNT: Okay. 8 MR. KIRKLAND: If I might add again we've 9 mapped 23 separate horizons within the field that we 10 think are productive. we think that by establishing 11 pool rules here we can efficiently design our drilling 12 program to drain the maximum number of reservoirs, 13 again trying to protect correlative rights, but also to 14 efficiently develop the reserves, the resource. 15 COMMISSIONER SEAMOUNT: Do you believe the 16 probable reserves are -- will be found in the thinner 17 sands or do you think there's some thicker sand still 18 left to be discovered? 19 MR. KIRKLAND: To date we have not found a 20 downdip limit in any sand in the field, any of the 23 21 sands that were evaluated. 22 COMMISSIONER SEAMOUNT: Okay. 23 MR. KIRKLAND: we think -- I mean, some of 24 those thinner, poorer sands may be encountered in a 25 position that they're very well developed and those 38 1 could turn out to be very good producers. Some of the 2 sands that we presently encounter may be in a position 3 such that they're thinner. I can -- I can kind of -- 4 well, I can't do it without the confidential slide. 5 I've got a slide that I superimposed the limits of the 6 20 or 19 of the 23 zones that we mapped that shows the 7 sand extents, but it's on that confidential slide with 8 the other category locations. 9 COMMISSIONER SEAMOUNT: Okay. I have one more 10 -- one or two more questions. What kind of shows do 11 you get out of the Beluga? 12 MR. KIRKLAND: To date we've not seen any good 13 mud logs shows. We have put on a mud logger at 500 14 feet in the previous two wells and really have not 15 encountered any Beluga shows in the field. 16 COMMISSIONER SEAMOUNT: Have you included the 17 Beluga in your probable or possible? 18 MR. KIRKLAND: No, sir. 19 COMMISSIONER SEAMOUNT: Okay. 20 MR. KIRKLAND: Strictly the Tyonek sands. 21 COMMISSIONER SEAMOUNT: Okay. Thank you, Mr. 22 Kirkland. That's all I have. 23 CHAIR FOERSTER: I think we should take a 24 recess and give Cook Inlet a chance to decide if 25 showing us the confidential portion is really necessary 39 1 and give us a chance to counsel with staff to see if 2 they feel that that information is necessary. And if 3 it -- and when we come back we can determine how to 4 proceed and whether or not Ms. Nelson needs to get up 5 and come back or not. 6 So it is five minutes until 10:00, we're going 7 to recess until 10:15. 8 (Off record - 9:55 a.m.) 9 (On record - 10:16) 10 CHAIR FOERSTER: We're back on the record at 11 10:16. And before we proceed Commissioner Seamount 12 remembered something that he needed to talk about. 13 COMMISSIONER SEAMOUNT: What was that? 14 CHAIR FOERSTER: He's already forgotten. 15 COMMISSIONER SEAMOUNT: No, I'm -- I'd like to 16 disclose that my wife is employed by Cook Inlet Energy. 17 And regardless of that fact I feel that I can make a 18 fair and impartial decision. 19 Did I say that correctly, Mr. Attorney General 20 Assistant? 21 MR. BALLANTINE: So far. 22 CHAIR FOERSTER: However, if Hilcorp feels that 23 there is -- oh, yeah, if we..... 24 COMMISSIONER SEAMOUNT: I don't -- if there's a 25 problem with this apparent conflict then we need to iO 0 0 1 know. 2 MR. JONES: We don't have any issue with that. 3 CHAIR FOERSTER: Okay. Okay. And we -- what 4 conclusions did you come to on the need to view 5 confidential information and then we'll tell you what 6 we feel. 7 MR. KIRKLAND: In looking at it it's not 8 necessary to our presentation. We can withdraw that 9 slide. 10 CHAIR FOERSTER: That's a good call because 11 that's what we determined as well. We..... 12 MR. KIRKLAND: Yes, ma'am. 13 CHAIR FOERSTER: .....feel we have sufficient 14 information, sufficient characterization of the 15 reservoir to make a decision. 16 All right. Is there anyone else who wishes to 17 testify? 18 (No comments) 19 CHAIR FOERSTER: Do you have any additional 20 statements, Commissioner Seamount? 21 COMMISSIONER SEAMOUNT: I have none other than 22 to thank Cook Inlet for coming in and making a good 23 presentation today. 24 CHAIR FOERSTER: I.... 25 MR. KIRKLAND: If it please the Commission I'd 41 0 0 1 like to just make a couple of summary comments in 2 closing. 3 CHAIR FOERSTER: That's fine. 4 MR. KIRKLAND: Okay. In filing for pooling for 5 the field, again we're asking for pooling of the 6 undifferentiated Tyonek between the base of the Beluga 7 and the Hemlock section. Again I think we've alluded 8 to the fact there's -- we've identified 23 separate 9 horizons within that interval that we think are 10 potentially gas productive. We believe that our 11 petition for pooling conforms to the State regulations. 12 Tim will amplify a bit, but to date we've had to apply 13 for exception locations on most of the wells drilled. 14 This could alleviate some of that administrative burden 15 on the Commission. We think it will protect 16 correlative rights. Again we've got a 1,500 foot 17 buffer around the unit, 3,000 feet between wells so we 18 don't believe there's any potential for draining off 19 the unit. We think it would prevent economic waste 20 which is -- in this environment is a big concern. We 21 realize that given the nature of the reservoir some of 22 the zones which may be 80 percent recoveries, some may 23 be 10 to 15. We realize that a large number of wells 24 are going to be required to develop the resource. We 25 think that with pooling and again giving the 42 0 0 1 multiplicity of pays, we can better design a 2 development program to capture the bulk of the 3 reserves, maximize our recoveries and yet do it 4 efficiently and economically. 5 Thank you. 6 MR. JONES: And I would add to that like Greg 7 mentioned that we've sort of been doing this, you know, 8 spacing aspect of the pooling rules that we've proposed 9 here on an ad hoc basis so far. You know, we've 10 requested or Armstrong before us and been granted by 11 the Commission, 10 conservation orders for spacing 12 exceptions already and, you know, we anticipate any 13 additional well that we may drill would probably 14 require another. And so it would definitely, you know, 15 reduce the burden on the Commission as well as on us 16 to, you know, not have to do that every time we want to 17 drill a well. And we, you know, as Greg also mentioned 18 do believe that this would definitely protect the 19 correlative rights of any of the surrounding 20 landowners. 21 CHAIR FOERSTER: I would have listed those in 22 reverse order because we don't -- while we do like to 23 have our burden -- our administrative burden reduced we 24 don't do it at the cost of any of the charges that we 25 have as a Commission. 43 0 1 MR. JONES: Right. 2 CHAIR FOERSTER: Okay. 3 MR. JONES: And I do want to thank you as well 4 for holding the hearing today and allowing us to come 5 and testify. 6 CHAIR FOERSTER: All right. Anything else? 7 COMMISSIONER SEAMOUNT: No. 8 CHAIR FOERSTER: And I have nothing to add. 9 And I do thank you for coming in. It was interesting, 10 you know, I go back to the -- takes me back to the days 11 when I used to get to play with wells and fields. 12 So with -- if there's no one else who has 13 anything to add then we are going to adjourn at 10:22. 14 (Adjourned - 10:22 a.m.) 15 (END OF PROCEEDINGS) 44 0 s 1 C E R T I F I C A T E 2 UNITED STATES OF AMERICA ) 3 ) ss 4 STATE OF ALASKA ) 5 6 I, Salena A. Hile, Notary Public in and for the 7 state of Alaska, residing in Anchorage in said state, 8 do hereby certify that the foregoing matter: Docket 9 No.: CO 15-014 was transcribed to the best of our 10 ability; Pages 01 through 45; 11 IN WITNESS WHEREOF I have hereunto set my hand 12 and affixed my seal this 15th day of January 2016. 13 14 15 Salena A. Hile 16 Notary Public, State of Alaska 17 My Commission Expires: 09/16/2018 18 45 0 0 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Public Hearing Docket Number: CO-15-014 Tyonek Gas Pool, North Fork Unit Pool Rules January 5, 2016 NAME AFFILIATION Testify (yes or no) nikk Gar); IfrvfeuVrl C- ' (! � -/ If / V/O Cook Inlet Energy_ �I AM QQ)rFA • • Current Well Status North Fork Unit NFU 14-25 Producing Gas NFU 23-25 Off Production NFU 24-26 Producing Gas NFU 34-26 Producing Gas NFU 22-35 Producing Gas NFU 32-35 Producing Gas NFU 41-35 Producing Gas NFU 42-35 Producing Gas 1] North Fork cross sectio .1 North Fork Unit Structure 5600' Sd — Isopach 5600' Sd — Depositional Environment— Major Productive Zones � * Major gas show >100u W Division of Oil & Gas vO A9RT~ENT pP Np JPP P�yo Oil and Gas Unit Fact Sheet North Fork Unit Status: Producing Operator: Cook Inlet Energy, LLC Working Interest: Cook Inlet Energy, LLC (100.00%) Current Total Acres: 6,602 First Production: 2011 FY14 Gas Production (mcf): 1,513,413 Recent Activity: Armstrong Cook Inlet, LLC interest purchased by Cook Inlet Energy, LLC. North Fork Gas Pool #1 Participating Area Status: Producing Discovery: 1965, Chevron North Fork Unit #41-35 Reservoir: Tertiary Tyonek Formation North Fork Annual Average Daily Combined Gross Gas Production Through June 2014 (MMCFD) io 0 U. V 1 2 0 l0 00 O N V w 00 O N 1. �O 00 O rV V t0 00 O N V t0 00 O N Q t0 t0 t1 11 n n n 00 00 00 00 W Ol O1 Q1 01 O1 O O O O O .-� c-1 c-1 01 Ol Ql Ol Ol in 01 m M M M m ai Ol m O m O O O O O O O O 11 1-1 -4 'A 11 c-I N N fV N N N N N --Cook Inlet Gas i)tviston or un & leas ,J Oil and Gas Unit Fact Sheet 13 14 24 rz North Forks Gas Pool Unit p* 1 2 s $ _ 3 i i { 05ac Vw � smaw North Fork Unit:, A North Fork Unit Boundary Leased State Tracts Cook Inlet Region I Gas Pool #1 PA Section Grid O 0 0.25 0.5 1 TaNnship Grid Miles p4j - aIasha.gov4AapAK bros.;ser id=1.194&set=map&9g id=4FC4EDCD5C92E5F14D64� Mineral Estate Map . State ofAlaska Natural Resources > IRM GPU > Alaska Mapper > Map Selection >I Mineral Estate Map(xA&) -- - xA Toots Layers X . 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XX - XX Yx Rk — X xxL _ 32 irk Artt±�c3."•1�i%�r.,...».,r`` _ — . x X Yi x- YYkNxx Y x.I X.Y KRxY 1 6 d�/C�lliizr z 24 u 12 xx u r Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Number: CO-15-014 Tyonek Gas Pool, North Fork Unit Pool Rules Cook Inlet Energy, LLC, by application received November 12, 2015, requests the Alaska Oil and Gas Conservation Commission (AOGCC) issue an order under 20 AAC 25.520, which establishes pool rules governing development of the Tyonek Gas Pool in the North Fork Unit. The AOGCC has tentatively scheduled a public hearing on this application for January 5, 2016, at 9:00 a.m. at 333 West 7t Avenue, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be fled with the AOGCC no later than 4:30 p.m. on December 7, 2015. 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 (907) 793-1221 after December 8, 2015. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 West 7th Avenue, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on December 28, 2015, except that, if a hearing is held, comments must be received no later than the conclusion of the January 5, 2016 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 (907) 793-1221, no later than December 29, 2015. Cathy . Foerster Chair, Commissioner STATE OF ALAS" ADVERTISING ORDER NOTICE TO PUBLISHER SUBMIT INVOICE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION WITH ATTACHED COPY OF ADVERTISMENT. ADVERTISING ORDER NUMBER AO-16-010 FROM: Alaska Oil and Gas Conservation Commission AGENCY CONTACT: Jody Colombie/Samantha Carlisle DATE OF A.O. 11/13/15 �(907) AGENCY PHONE: 793-1223 333 West 7th Avenue Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: 11/16/2015 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 CO-15-014 Initials of who prepared AO: Alaska Non -Taxable 92-600185 " " SUBMIT INVOICE $110WNGAPVERTISING. ::ORDE;RNOCERTIFIEII ;AFFIDAI!IT:OF:.!: ea s�Ieg�Ory:iTilgi rncii> ncoeY:Oi:;:; AIivRTlSnir NFT6 Department of Administration Division of AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Pa e 1 of 1 Total of All Pages $ REF Type Number Amount Date Comments I PVN ADN84501 2 Ao AO-16-010 3 4 FIN I AMOUNT SY Appr Unit PGM LGR Object FY DIST LIQ 1 16 021147717 3046 16 2 3 4 5 Porch g ho ' Na Title: Purchasing Authority's Signature Telephone Number 1. A.O. # and recc(vingAency name must appear on all invoices and documents relating to this purchase. 2. The state is regis Bred for tax free transactions under Chapter 32, IRS code. Registration number 92-73-0006 K. Items are for the exclusive use of the state and not for resale. AISI8(. T.. N............. .. . ......................................................................... ............ i .::::::::::::::::::: Division:.Fiscap;Or nal;AQ. ::: ::::::::::C. Pies;:T10.blisher:(fa:zed);:DiVis'ion:F;isealRece,y..g...................................... . Form:02-901 Revised: 11 /13/2015 270227 0001375609 $204.20 STATE OF ALASKA E E DECEIVED NOV 2 3 2015 AFFIDAVIT OF PUBLICATION AOGCC 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 Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on November 16, 2015 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 an sworn to before me this 17th day of November, 2015 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 Number: CO-15-014 Tyonek Gas Pool, North Fork Unit Pool Rules Cook Inlet Energy, LLC, by application received November 12, 2015, requests the Alaska Oil and Gas Conservation Commission (AOGCC) issue an order under 20 AAC 25.520, which establishes pool rules governing development of the Tyonek Gas Pool in the North Fork Unit. The AOGCC has tentatively scheduled a public hearing on this application for January 5, 2016, at 9:00 a.m. at 333 West 7th Avenue, 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 7, 2015. 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 l hold the hearing, call (907) 793-1221 after December 8, 2015. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 West 7th Avenue, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on December 28, 2015, except that, if a hearing is held, comments must be received no later than the conclusion of the January 5, 2016 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 (907) 793-1221, no later than December 29, 2015. Cathy P. Foerster Chair, Commissioner AO-16-010 Published: November 16, 2015 QRIrNFVaryPublr =u•..$,.. My Commiss o� EXf, a0 apS pN 4. Peres Aeb 19 Mj • James Gibbs Jack Hakkila Bernie Karl K&K Recycling Inc. P.O. Box 1597 P.O. Box 190083 Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Conrad Perry Richard Wagner Darwin Waldsmith Drilling Manager P.O. Box 60868 P.O. Box 39309 Cook Inlet Energy, LLC Fairbanks, AK 99706 Ninilchik, AK 99639 601 W. 5`h Ave., Ste. 310 Anchorage, AK 99501 Angela K. Singh 0 • Cook Inlet Energy_ A Wholly Owned Subsidiary of Miller Energy Resources November 11, 2015 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 W 7`h Avenue, Suite 100 Anchorage, AK 99501 RECEIVE NOV 12 2015 AOGCC Re: Application for Pool Rules — North Fork Unit Undifferentiated Tyonek Gas Pool Dear Commissioner Foerster: Cook Inlet Energy, LLC, as Operator and sole Working Interest Owner in the North Fork Unit, and in accordance with 11 AAC 25.520, hereby requests the Alaska Oil and Gas Conservation Commission approve the attached application for Pool Rules for the Undifferentiated Tyonek Gas Pool. Please find enclosed 3 printed originals and a compact disc containing an electronic version of the application. If you have any questions, please do not hesitate to contact me at 907-433-3811, or by email at fimjones@cookinlet.net. Sincerely, Conrad Drillingi Cc: Hak Dickenson, Unit Manager, DNR Attachment 601 W 51' Ave., Suite 310, Anchorage, AK 99501 • • NOV 12 2015 Application to the Alaska Oil and Gas Conservation Commission for the Establishment of Pool Rules for the North Fork Unit Undifferentiated Tyonek Gas Pool Purpose Cook Inlet Energy, LLC ("CIE"), as operator of the North Fork Unit ("NFU") and the sole working interest owner, submits this document to the Alaska Oil and Gas Conservation Commission ("Commission"). This document requests that the Commission issue a Pool Order under 20 AAC 25.520 for the North Fork Unit — Tyonek Undifferentiated Gas Pool ("NFU-TUGP") classifying the pool as a gas pool and prescribing rules to govern the proposed development and operation of the pool. CIE is confident that this document provides all necessary information for the Commission to process this request. The lands proposed for inclusion in the NFU-TUGP are the following Affected Area: Township, Range Description T. 4 S., R. 14 W. Section 23: SE1/4 Section 24: S1/2SW1/4 Section 25: NW1/4NE1/4, S1/2NE1/4, W1/2, N1/2SE1/4, SW1/4SE1/4 Section 26: NE 1 /4, S 1 /2NW 1 /4, S 1 /2 Section 27: SE1/4NE1/4, E1/2SE1/4 Section 35: ALL Section 36: N1/2NW1/4, SW1/4NW1/4, NW1/4SW1/4 T. 5 S., R. 14 W. Section 3: Lots 1-3, SW1/4NE1/4, SE1/4NW1/4, E1/2SW1/4, NW1/4SE1/4 Introduction The United States Department of the Interior Bureau of Land Management (`BLM") approved the formation of the NFU, covering 640 acres, effective May 27, 1965. The NFU #41-35 well was drilled and completed by Standard Oil Company of California in December, 1965 and that well was the discovery well for the North Fork gas accumulation. BLM approved the Gas Pool #1 Participating Area ("GPA") effective December 20, 1965. There were several changes of ownership of the NFU since 1970 and no further exploration or development activities occurred until 2007 when the leases comprising the NFU were acquired by Armstrong Cook Inlet ("ACI"). The NFU is located in the southeastern part of the upper Cook Inlet Basin on the southern Kenai Peninsula approximately 10 miles north-northwest of Homer. ACI undertook the development of the NFU and following the acquisition of 3D seismic over the area and the drilling of three additional wells, installation of production facilities, and the Page 1126 0 0 construction of a pipeline by an ACI subsidiary the field was brought into production in April, 2011. The NFU, following certain expansions and contractions, now consists of 2,601.84 acres with the GPA covering 800.00 acres. CIE acquired the leases comprising the NFU effective March 1, 2014 and became the Unit Operator. All wells currently producing from the proposed pool have been drilled and produced from a single pad with the exception of the original exploration well 41-35. CIE has undertaken additional development drilling at the NFU and at this time all wells in the current development phase and future wells under consideration planned to be drilled from the current pad location, with a pad expansion in the planning stages. CIE's SEC reserves for the NFU as of July 31, 2014 were: Proved — 23.995 BCF Probable — 35.552 BCF, and Possible — 58.841 BCF with a combined total Reserves of 118.388 BCF. Recovery efficiency varies depending on rock permeability, hydrocarbon viscosity and reservoir continuity. At North Fork, reservoir permeability is relatively low, however, since the produced hydrocarbons are gaseous, the flow capability is fair. Recovery factors in North Fork, given that it is a non -water drive reservoir, will range from 60-80% where reservoirs are continuous. The depositional environment at North Fork is not conducive to recovering gas from larger areas because this is a channelized fluvial system and drainage over a large area is not the norm. A recent study of volumetrics showed that there may be as much as 70-80 BCF of original gas -in - place, though recovery from this area will likely be less than 30 BCF of gas. This is due primarily to poor continuity and low permeability. Geolo The NFU is located is located in the Southern Kenai Peninsula region of South Central Alaska. Primary geographic features of the area are the Kenai Mountains located to the East Northeast and the Cook Inlet to the West. The field is situated in an area of low relief lightly vegetated surface which is populated by numerous bogs, ponds and lakes. Gas production in the NFU has been established from the Lwr Miocene — Oligocene Tyonek formation. Minor oil shows have also been tested but not produced from the Oligocene Hemlock Fm. Tyonek production consist of dry gas from numerous zones. Biogenic gas from the numerous coal beds in the section have charged existing reservoirs. Analysis of produced gas from the NFU 32-35 indicates a methane content of 98.158 moles and a BTU content of 988.32. Contaminants contained within the produced gas include Nitrogen at 1.077 moles and COE at .311 moles. (See attachment 1 for analysis) Sands in the field generally range in thickness from ten to as much as sixty feet in thickness. The thicker Tyonek sands were primarily deposited as meandering channel sands with thinner overbank and crevasse splay deposits also being present. Sands are commonly deposited as fining upward sequences although some blocky and coarsening downward sands are also observed. Interspersed with sand are numerous coal beds, shales, claystones and silts. Page 2126 GR TOTAL GAS Sterling Fm North Fork Unit • Mass' Thick Type Well Log • Massive porous sands ter • Non -productive Beluga Fm Productive gas interval • 3400' Thick Oil shows • Thin shaley sands Structural Mapping Datum • Prospective U Tyonek 4 -TYONEK 4900 SS Upper Tyonek Fm • 2800' Thick F-TYONEK 6000 SS • Multiple proven gas sands • Good reservoir quality 4WA M Tyone. Middle Tyonek Fm f-TYONEK 8000 SS • 1800' Thick • Multiple proven gas sands y 4 - TYONEK 8500 SS • Moderate reservoir quality �- �+_�r LTY'nns_F Lower Tyonek Fm • 1700' Thick _ • Non -productive Hemlock Fm • 60' Thick, oil potential k"�e o°o" 4 HEMLOCK NFU Type Log Depositional Environment Deposition in the field was fluvial in nature with sands, coals, claystones, shales and silts being deposited as members of an axial fluvial braided stream system across a low relief marshy plain. Depositional setting, as described by Hite, Swenson, Claypool and others, consisted of an areawide basinal setting of low -relief alluvial fans on the basin margins terminating in an axial braided fluvial system. These fluvial channels meandered across a low relief marshy and swampy setting. During periods when the channel system was largely inactive claystones and coals were largely deposited resulting in the interbedding seen today. Deposition across the field and basin in generally is extremely cyclical consisting of the above described members. Coal beds range in thickness from 1 to 25' thick occurring very frequently throughout the section. Field Reservoirs To date gas has been tested and/or produced from a total of twelve different sands within the field. Reservoir nomenclature established for the field has been depth related for the various Pa ge 3126 0 • productive sands. Producing gas reservoirs currently consist of the 4900', 4950', 5600', 6000', 7800', 7950', 8000', 8050', 8100', 8500' and 9200' zones. Numerous other sands evaluated by log analysis as capable of production have also been penetrated and remain untested behind pipe. The primary producing formation at North Fork is the Tyonek formation. There are several different intervals identified in the Tyonek formation, which are producing in different wells. On an average the recovery factor is about 80% for these reservoirs. An overall recovery up to 95% can be easily obtained using compression during the later life of the field. The estimated recovery factors for the various sand packages are as follows: Recovery Factor Reservoir (%) Upper Tyonek A 80 Upper Tyonek A Lower 80 Upper Tyonek B 80 Upper Tyonek C Upper 80 Upper Tyonek D Upper 80 Upper Tyonek E Basal 80 Middle Tyonek A 7,800' Sand 80 Middle Tyonek A 7,950' Sand 80 Middle Tyonek A 8,050' Sand 75 Middle Tyonek A 8,1800' Sand 75 Middle Tyonek A Basal Mbr 80 Petrophysical Characteristics Petrophysical characteristics observed for the various reservoirs generally are quite good. Log analysis is complicated to some extent by the complex lithologic nature of reservoir sands. Sands are generally quartz rich with large amounts of lithic fragments, silts, shales, coals and claystones. Varying amounts of disseminated carbonaceous material may also be present. Average porosities for field reservoirs range from 9 to 21 % and generally seem to average between 16-18 %. To date no cores have been taken in the field. Perms are estimated to range between .2 to as much as several hundred Md which is the common range observed for other area gas fields. Although the various reservoirs do tend to produce varying amounts of water, initial water saturations from log analysis are generally low and calculate in the 20-40 % range. To date no definitive information indicates an active water drive for the reservoirs. Produced water is generally considered to be interstitial water from time of deposition. Attachment 2 (Attached) is a study conducted by Schlumberger determining water salinity. Gas reservoirs can generally be characterized as low contrast type reservoirs. Observed resistivities may range between 12 to 60 ohms or higher in productive gas zones. Large amounts of volcanic material also affect log analysis primarily affecting the neutron and gamma ray curve values. Average petrophysical characteristics for the NFU 24-26 are shown below: Page 4126 0 9 PetrophysicaI Averages NFU 24-26 Zone Avg RT Avg Por Avg SW Ohms % % 4900' "A" Sd 23.3 16 Low 4900' "B" Sd 25.7 21 26.7 5300' Sd 21.0 16 Low Zone of Int 30.6 14 Low 5450' Sd 29.7 18 21.6 5600' Sd 32.4 20 20.9 5600' "B" Sd 36.0 17 10.0 6000' Sd 50.8 19 16.4 6100' Sd 19.9 18 21.5 6100' "B" Sd 22.3 17 19.8 6800' Sd 21.5 18 30.0 Zone of Int 16.8 19 39.0 8100' Sd 19.4 16 44.5 Zone of Int 18.8 16 43.0 8500' Sd 45.7 9 21.8 9000' Sd 36.4 15 34.7 9100' Sd 17.9 16 29.4 Individual sands generally correlate fairly well across the structure although considerable variation in thickness and appearance is evident. For those sands absent in an individual well, packages and or markers are apparent so that an equivalent interval is present. Individual coals generally correlate extremely well across the breadth of the field, although individual coals may be missing in specific wellbores. Structure The North Fork field is situated in the hanging wall of a Northeast Southwest trending high angle reverse fault. Production is associated with a faulted anticlinal high generally trending North South. The Northeastern portion of the field is situated in a graben formed by down -to -the - Southwest normal fault bounding to the North and a down -to -the -Northeast normal fault at the southern extreme. The bulk of production to date has come from reservoirs trapped against the upthrown side of the down to the Northeast normal fault. Over six hundred acres of closure are apparent from maps prepared on multiple horizons. To date eight wells have been drilled into these reservoirs with additional delineation wells slated to prove up the extent of gas accumulations. Cook Inlet's NFU 42-35 well provided additional information concerning the southern limits of accumulations and the planned NFU 22-26 well should help with the Northern limits. To date no clear water levels have been established for existing reservoirs. Because of surface limitations and to prevent economic waste, existing wells have been drilled from a common pad location. Proven reservoirs to date have extended from approximately 4500' TVD to depths drilled. Typical well design is to deviate at a shallow depth in order to achieve separation between wells for shallow zones. This is the primary reason that exception locations have been necessary for previously drilled wells. Geology of the field and the well geometry necessary preclude drilling wells capable of conforming to state spacing. Page 5126 • 0 Establishment of field rules will enable the drilling of wells at optimum locations for the most efficient field development. Once development begins for the graben, central, fault block drilling is planned to be done from the same pad area. Initial wells will be drilled in a Northeasterly direction into the downthrown fault block attempting to penetrate reservoir sands at the highest point possible structurally. Production from this central fault block has not been as prolific to date as production from wells in the Southern fault block. Wells planned to be drilled into the Northern fault block will require a separate pad site in order to be drilled into the highest structural position possible upthrown to the Down -to -the -Southwest O i 34-26 a 2' NFU-24-26 . ,. .., �J._r c 032-35 r58 22-35 S-, _/":ra? H Structure Map 6000' sand 11 0 Below are three cross sections depicting the section and productive sands across the field. Note that with additional drilling new potential gas pays are being encountered in addition to the existing field pays. During drilling of NFU 24-26, several very prospective sands were encountered. Although the major producing sands can generally be correlated across the field, due to the anastomosing nature of depositional system, new sands are a continuing possibility. NFU ,wx*� 22 35 NFU �o,ama 32-35 NF 3426 .K mw NFU 41.35 ar,ws P. a =U * PDP *PDNP " PROB Page 7126 NFU 22-35 NFU 32-35 •t 3!¢•, "'MO z I j NF 34-26 NFU 4 Y-35 hF ii D9 •964 &:A" - -._ ram. * PDP *PDNP PROB The three above cross sections depict the normal section including the shallowest current known field pay 4900' sand down through the 8500' Sand. Proposed Definition; NFU — TUGP The Tyonek Fin is that section lying below the Beluga Fin and overlying the Hemlock Fin. Within the North Fork Unit this interval is best illustrated by the original NFU 41-35 exploration well. The interval comprising the Tyonek Fin is correlated to be those sands, shales, claystones and coals lying below the Top of Tyonek which occurs at a depth of 4840' MD 4840' TVD (- 4060' SSTVD) and above the Hemlock Fin which occurs at a depth of 10797' MD, 10796' TVD, and (9801' SSTVD). In the field numerous productive and prospective reservoirs have been encountered. Among the zones shown to be productive are the 4900' Sd, 5600' Sd, 6000' Sd, 7800' Sd, 7950' Sd, 8000' Sd, 8050' Sd, 8100' Sd, 8500' Sd and the 9200' Sand. Numerous zones have been encountered in the various wells drilled to date that appear prospective for gas production but have not been tested. Among these are the 4900' `B" Sd, 5300' Sd, 5450' Sd, 6100' Sd, 8400' Sd and 9000' Sands. As new wells are drilled new zones capable of gas production are expected to be encountered suggesting that the above productive and prospective sands should not be considered all inclusive. Page 9126 Therefore, the NFU - TUGP is defined as the accumulations of gas common to and correlating to the interval found in the Armstrong NFU 41-35 well between the depths of 4,840' and 10,797' measured depth. Drilling, Completion, and Well Operations Background The NFU was originally developed by ACI. CIE purchased the leases comprising the NFU in 2014 and has completed two new wells. The production wells target the Tyonek gas sands. Generally, 12 '/4" surface hole is drilled to between 2,500' and 3,000' TVD. Most directional work is accomplished in this hole section building sufficient angle to reach the target locations. Shallow gas is not present in this interval, however, the first two wells have utilized a diverter system at the request of the AOGCC. 8 '/2" or 8 V hole for 7" casing is directionally drilled to the base of the Tyonek at around 10,000' TVD in most cases. Wells are S shaped with a drop to vertical or shallow angle after 5,000' TVD. Longer reach wells that are greater than 11,000' MD will require setting the 7" casing shallower and drilling 6 1/8" hole for 5" liner to final TD. Completion designs must be very flexible to optimally produce potential gas sands that occur over a 5,000' MD interval. Current well completions are either a mono -bore, with tubing the same size as the liner or a single zone and packer completion. Future wells may have 2 7/8" or 2 3/8" single selective completions where there are multiple zones isolated with production packers. Each zone is produced selectively through a sliding sleeve. Should log evaluation not be conclusive in determining producible zones, Drill Stem Testing prior to completion may be necessary. CIE Drilling Plan The NFU 24-26 well (first drilled by CIE) was directionally drilled to the East. The current well NFU 42-35 will be drilled to the south. Additional wells will be used to infill the current well spacing to effectively drain the reservoir. There are currently three remaining slots in the current double wide well row with 50' centers. Well row expansion is planned to the east on the other side of the production facilities should additional slots be required. 50' well centers will be maintained. Page 10126 0 WELL NFU 24 26 NAME: Well Information ENGINEER: Courtney Rust DATE: 16-Dec-14 Hole Max EMW Estimated Estimated Sizes Casing MD ft ( ) TVD ft ( ) ( Pore Frac Grad at Range -Mud g Mud T e Type Comments Size (in) (in) Pressure) Shoe Weight (ppg) - 16" -- -- -- -- Conductor pipe 12.25" 9 5/8" 2,933 2,750 8.4 13.6 8.8 9.2 WgM Normal gradient, no shallow gas 8.75" 7" 1- 12b Eastino lit) Page 12126 • Typical Single Selective Completion 12/18/2014 TRSSSV @ +/-349' 2 7/8" Chemical Injection mandrel @ +/- 2517' 8,803' to 8,812' 8,943' to 8,965' 9,154' to 9,186 All sleeves shift dow n to open and up to close. Sliding Sleeve @ 5,147' Zone #1 HB PHIL Hydraulic Set Packer @ 5,1 Sliding Sleeve @5,213' MD Y Block 2" guns 0 degree phase 5,261.89' to 5,279.89' 5,764.92'to 5,799.92' Zone #2 HB PHL Hydraulic Set Packer @ 5,8 Sliding Sleeve @5,897' MD Y Block 2" guns 0 degree phase 5,911.34' to 5,934.34' 5,990.57' to 6,004.57' Zone #3 OLG DHL Hydraulic Set Packer @ 8 XN Nipple @ 8,460' 4 5/8" TCP or 2" Wireline Guns 8,970' to 9,016' E TVD MD Future 8,494' to 8528' 8, 917' to 8, 932' Navigator 20" L80 120' TV D 120# BTC 120' MD 12 1/4" Hole 9 5/8" L80 2,750' TVD 40# SD BTC 2,870' MD 2 7/8" 6.5# L80 EUE-M Tubing Back to Too 8 3/4" hole 7" L80 9,379' TVD 26# GEOCON 9,725' MD Note: It is as tied into WLMw hich is 4' Shallower than tubing measurements 0' WLM = 4' Tubing measurements. Packer Details on next tab 13 1 26 All specifications for design and well control are in accordance with all 20 AAC 25 Articles. The 9 5/8" surface casing will be cemented to surface and will be set at 2,933' MD/2,750' TVD. The total depth of this well is planned for 10,366' MD/9,750' TVD and will be cased to surface with 7" casing. The cement plan for the 7" will set top of cement at +/-4,000' MD with 40% excess. Completion and perforation plans will be addressed at the time the logs are reviewed, however, CIE is preparing for a 3 zone completion similar to other wells in the field and will permit for such. The isolation would be provided by a retrievable hydraulic packer and sliding sleeve combination for each zone. Drilling and Logging Preliminary slot assignments for the next three wells and directional plans for the wells have been generated for the current phase of the development. Based on logging information gathered while drilling there are no shallow gas issues in the surface section down to 3,000' TVD. Diverter waiver requests will be submitted as diverters are unnecessary. Notional wells for future development have been planned, but the final development will be based on information gathered during the initial development and following the design of the North Fork pad expansion and facility placement. Close approaches and anti -collision scans show no major proximity issues. Assuming conservative build and turn rates of no more than 4 degrees/100', all targets are reached with intermediate hole tangent angles of less than 55 degrees. Directional profiles were used to spot check torque and drag, and hydraulics. Well modeling (torque, drag, casing running, hydraulics, hole cleaning) results showed no major risks to drilling the wells. Most of the drilling and completions of the North Fork gas wells can be accomplished with current designs and drilling practices; however, there are some extended targets that are being evaluated. CIE requests the requirements described in 20 AAC 25.050 (b) be waived for the proposed NFU - TUGP to relieve administrative burden. In lieu of requirements under 20 AAC 25.050(b), CIE proposes that permit(s) to drill deviated wells shall include a plat with a plan view, vertical section, close approach data and a directional program description. The planned logging for the well will include gamma ray for the 12 '/4" surface hole and LWD gamma ray, resistivity, density logs in the 8 3/4" production section to total depth. Additional logs may include image logs, sonic, and pressure tools. These logs will be obtained from logging - while -drilling and wireline tools. Page 14126 CIE requests that the mudlogging requirements of 20 AAC 25.071 (b) be waived for future wells ✓ from the current drillsite as there is already significant data from the previously drilled wells already on file. CIE will provide samples and mud log data should they be acquired. Allocation of Production The NFU is comprised entirely of State of Alaska lands and all activities are governed by the current Unit Agreement and Unit Operating Agreement. Allocation of production is currently determined by the allocation factors contained within Exhibit C to the Unit Agreement. Currently CIE is producing from six wells at the NFU with average daily production of approximately 9 MMcf. Future production will continue to be allocated in accordance with the allocation factors contained in the Exhibit C, or future changes approved by the State of Alaska Department of Natural Resources as the landowner and Unit Manager. Proposed Conservation Order for the North Fork Unit - Tyonek Undifferentiated Gas Pool Affected Area: Seward Meridian Township, Range Description T. 4 S., R. 14 W. Section 23: SE1/4 Section 24: Sl/2SW1/4 Section 25 : NW 1 /4NE 1 /4, S 1 /2NE 1 /4, W1/2, N1/2SE1/4, SW1/4SE1/4 Section 26: NE 1 /4, S 1 /2NW 1 /4, S 1 /2 Section 27: SE 1 /4NE 1 /4, E 1 /2 SE 1 /4 Section 35: ALL Section 3 6: N 1 /2NW 1 /4, S W 1 /4NW 1 /4, NW1/4SW1/4 T. 5 S., R. 14 W. Section 3: Lots 1-3, SW1/4NE1/4, SE1/4NW1/4, E1/2SW1/4, NW1/4SE1/4 15 1 26 Rule 1. Field and Pool Names The field is the North Fork Field. Hydrocarbons underlying the Affected Area and within the interval identified in Rule 2, below, constitute the North Fork Unit - Tyonek Undifferentiated Gas Pool (NFU-TUGP). Rule 2. Pool Definition The NFU-TUGP is the accumulations of gas within the Affected Area common to and correlating with the interval between the measured depths of 4,840 and 10,797 feet recorded in the NFU 41-35 well. Rule 3. Well Spacing There shall be no restrictions as to well spacing except that no pay shall be opened in a well within 1,500' to an external property line where the owners and landowners are not the same on both sides of the line. Rule 4. Drilling Waivers All permits to drill deviated wells within the NFU-TUGP shall include a plat with a plan view, vertical section, close approach data and a directional program description in lieu of the requirements of 20 AAC 25.050 (b). Rule 5. Well Logging and Sampling Requirements (a) A suite of petrophysical well logs including, at a minimum, gamma ray, resistivity, neutron porosity, and density porosity logs shall be acquired across the NFU-TUGP in one well from each drill site. The Commission may require additional wells to be logged using one or more petrophysical logging tools. (b) A mud log and cuttings samples shall be obtained from the base of the conductor through the NFU-TUGP in at least one well from each drill site. Rule 6. Reservoir Pressure Monitoring (a) A bottom -hole pressure survey shall be taken on each well prior to initial production or injection. (b) The operator shall obtain the pressure surveys needed to manage the hydrocarbon recovery processes effectively subject to the annual plan outlined in Rule 8, below. At a minimum a pressure survey shall be acquired from at least one well on each drill site each year. (c) The reservoir pressure datum will be-5,000' TVDSS. (d) Pressure surveys may consist of stabilized static pressure measurements at bottom -hole or be extrapolated from surface measurements (single phase fluid conditions), pressure fall- off measurements, pressure buildup measurements, multi -rate test results, drill stem test results, and open -hole formation tests or other methods approved by the Commission. (e) A Reservoir Pressure Report, Form 10-412, shall be utilized for all surveys; all relevant data shall be attached to the report. The data submitted shall include, at a minimum, rate, pressure, depth, fluid gradient, temperature, and all other well conditions necessary for a complete analysis of each survey being conducted. P age 16126 • (f) The results and data from any special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with paragraph (e) of this rule. Rule 7. Annual Reservoir Review (a) An annual reservoir surveillance report must be filed by April 1 st of each year and include future development plans, reservoir depletion plans, and surveillance information for the prior calendar year, including: i. The voidage balance, by month, of produced fluids and injected fluids and the cumulative status for each producing interval; ii. A reservoir pressure map at datum, and a summary and analysis of the reservoir pressure surveys within the pool; iii. The results and, where appropriate, an analysis of production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring; iv. A review of pool production allocation factors and issues over the prior year. v. A review of the progress of the enhanced recovery project; and vi. A reservoir management summary, including results of any reservoir simulation studies. (b) By June I` of each year, the operator shall schedule and conduct a technical review meeting with the Commission to discuss the annual reservoir surveillance report and items that may require action within the coming year. The Commission may audit the technical data and analyses relating to the surveillance report's conclusions and reservoir depletion plans. Rule 8. Annular Pressures (a) At the time of installation or replacement, the operator shall conduct and document a pressure test of tubulars and completion equipment in each development well that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. (b) The operator shall monitor each development well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or unavoidable circumstances. Monitoring results shall be made available for Commission inspection. (c) The operator shall notify the Commission within three working days after the operator identifies a well as having (i) sustained inner annulus pressure that exceeds 2,000 psig for all development wells, or (ii) sustained outer annulus pressure that exceeds 1,000 psig. (d) The Commission may require the operator to submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in paragraph (c) of this rule. The Commission may approve the operator's proposal or require other corrective action or surveillance. The Commission may require corrective action be verified by a mechanical integrity test or other approved diagnostic tests. The operator shall give the Commission sufficient notice of the testing schedule to allow the Commission to witness the tests. (e) If the operator identifies sustained pressure in the inner annulus of a development well that exceeds 45% of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45% of the burst pressure rating of the well's surface casing for outer annulus pressure, the operator shall notify the Commission within three working days and take corrective action. Unless well P a ge 17126 conditions require the operator to take emergency corrective action before Commission approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The Commission may approve the operator's proposal or require other corrective action. The Commission may also require corrective action be verified by mechanical integrity testing or other Commission approved diagnostic tests. The operator shall give the Commission sufficient notice of the testing schedule to allow the Commission to witness the tests. (f) Except as otherwise approved by the Commission under (d) or (e) of this rule, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree (I) that the inner annulus pressure at operating temperature will be below 2,000 psig, and (2) that the outer annulus pressure at operating temperature will be below 1,000 psig. A well subject to (c) but not (e) of this rule may reach an annulus pressure at operating temperature that is described in the operator's notification to the Commission under (c) of this rule, unless the Commission prescribes a different limit. (g) For purposes of this rule, i. "inner annulus" means the space in a well between tubing and production casing; I "outer annulus" means the space in a well between production casing and surface casing; and iii. "sustained pressure" means pressure that (A) is measurable at the casing head of an annulus, (B) is not caused solely by temperature fluctuations, and (C) is not pressure that has been applied intentionally. Rule 9. Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the Commission 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. Page 18126 • • Attachment 1 with a 41-35 Porosity of 18.4 percent and a water saturationof 40.7 percent. Permeability calculated from the flow test results is 22.57 md. The original Ml1CF gas -in -place is 4,520 PLMCF per 160 acres, or 9,041 for a 320-acre drainage area. The lower Tyonic sand has 16 feet If pay with a porosity of 18 percent, water saturation 50 percent, and a calculated permeability of 10.35 md. On 160-acre drainage, this interval has original gas -in -place of 2,296 KMCF and for 320 acres, 492 KMCF. Enclosure 3 summarizes other reservoir properties and reserve calculations. A wellhead sample of gas from the upper sand was analyzed with the following results: Mol M01 Methane 98.1 Nitrogen 1.2 Ethane 0.3 Argon Trace Propane 0.1 Hydrogen 0 Butane 0 Hydrogen Sulfide 0 Pentane 0 Carbon Dioxide 0.2 Hexane 0 Helium Trace Specific Gravity 0.56 Ultimate gas recovery was estimated using a computer simulation taking into account the specific deliverability of each of the two Tyonic sands, the original gas -in -place, and the economic limit. The following results were calculated: Perforations 8,005 - 8,046 Drainage Area, Acres 160 320 Recoverable Gas, MMCF [. 1Qr' o )o,) e j Attachment 2 Schlumberger, Formation Water Salinity Determination Company: Armstrong Cook Inlet, LLC Field: North Fork Well: North Fork #34-26 Country: USA Log Analyst: Douglas Hupp, P.E. Logged: 15-JUL-2008 Processed: 15 -JUL- 20 08 Reference: 12014324 Interval of Interest: 9.625 Casing Shoe 20 1 26 $cMumberlper TABLE OF CONTENTS 1. Introduction:. ....... ntroduction:.......................................................3 2. Interpretation: ............................................................................................................................. 3 2.1 Inputs: ................................................................................................................................ 3 2.2 Technique: ........................................................................................................................... 3 2.3 Interpretation:..................................................................................................................... 4 3. Conclusion.................................................................................................................................. 7 inWrp@fa1WN are op@gOrS 6aaed ariMeRn:@5!rp@dernrca�notMr measa'ema'•%^i :.. .•nit and eo-quaran'e@the Y^uraov or car-ro+ess of a—verm mt•cns an :ER@I!mLe@tepl in the[aee Mgloss xun±Nu71>egliq@Ps@Of-Wr pa^. to hate r..1 ___,. r.tr src _, s,yet, t .. iu •f�:l'rip m aM iMeryeetat�on madeWa,y of oul aMicels. agemaempleyst 'ee4'r . I!�,. .._..... r �. -: '. '. :..i. ,...n a fth@dole. Page 2 of 7 21 126 1 i ' 0 O 11 Schlumbepuur 1. Introduction: Formation Salinity Determination Report Armstrong Cook Inlet, LLC has requested that Schlumberger perform analysis to determine the formation water salinity using data from their North Fork Unit #34-26 well. The zone of interest is in the vicinity of the 9.625 in. casing shoe at 2489 ft MD. This analysis consists of Rwa determination using Schlumberger openhole well logs acquired on 15-1UL-2008. The purpose of this study was to determine formation water salinity relative to annular disposal permit being applied for with the AOGCC. 2. Interpretation: 2.1 Inputs: Determination of water salinity in Armstrong well North Fork Unit #34-26 was performed using the Schlumberger openhole data acquired on 15-JUL-2008. The well logs used are listed in the table below; Input Log Data Description RHOZ Bulk density from the Platform Express tool. AF90 AIT 4 ft resistivity 90 2.2 Technique: The interpretation technique utilized in this study is refered to as a Rwa analysis. The apparent formation water resistivity is calculated based on openhole measurements. This technique relies on Archie water saturation equation which used porosity and resistivity inputs. If the formation porosity is filled with water, the calculated Rwa value should allow determination of water salinity. Below are the equations used for this analysis: Sr - JaxRii i,• _ 0'" x Rt Sit, = Formation {Pater Saturation a =1 orrnositr Factor in = Cementation _ F_a f)oneni n = Saturation _ Exponent Riv = Formation Rater Resistivity 0 = Porosity Rt = Formation Resistivin- By assuming that Sw is equal to i the above equation can be re -arranged to the following format by solving for Rw: " Rfru = 0 xRt a Porosity is derived using the density log with the following equation: Paae 3 of 7 22 1 26 Schlumberger Formation Salinity Determination Report P- - PIS P .«' -Pm„e ,o_,;, =.Matrix_ Densirh, p, = Log _ Density PO w = Fluid _ Density As can be seen by the equaitons above, this technique depends on various assumptions as described below. Factor Value Used a 0.62 m 2.15 n 2 2.65 Pfkw 1 The values used for a, m, and n are typical of clastic formations found in this area. In this section of this well, sand formations are difficult to distinguish from shales but intervals indicating permeability by the spread on the resistivity logs, sand intervals can be identified. Salinity is next determined using Rwa and borehole temperature with Schlumberger Chart Gen-6, included in this report. Note that the logged interval contains several coal intervals. These intervals were not used to determine Rwa in this analysis. 2.3 Interpretation: The figure below presents the calculated Rwa values for this well over the interval from 2500 ft to 2700 ft MD in log format. Page 4 of 7 23 1 26 14 Schtumberger Formation Salinity Determination Report "Al ICKf•�II �i_i.eM:f.�.. FF?L'Ai70t/6d_lrkt� • r 62 �y,� •o• as aF:w.sa>_u.e:: PM aFec AFso�woi twt�i • ;�,q1 ^ea e2 MD GTEM GTEMOAscil-Load, t..(,. Ids AKL ♦FfbFrfp7f �/a•:�� Ofowawpbc+c !an.�r! RAai•1• "F) 4 c2 m, al• of oa NRW) o aW,2500 cam. ' j t _ r { now th- as tM AtT MOS*-ft top 1 indk ednwbnMr king j Rwa me 2M The log presented includes the following data: Troa Curves — — — --Description 1 Gamma Ray Caliper Borehole Temperature Borehole Temperature plotted every 50 ft. 2 Depth 3 Resistivity 4 DensPorosity 5 Calculated Rwa 3 to 5 Coal Flag Shading indicates possible coal or bad hole sections based on a bulk density value less than 2.35 cc The lowest values of Rwa in this section of log that do not corespond to tight sections are 0.4 ohm-m at 96 degrees (measured borehole temperature). Using chart Gen-6, this corresponds to a salinity of 11500 ppm NaCl (see the figure below). Paae 5 01 7 24 1 26 Schlumberger Formation Salinity Determination Report rn.aef a� _� ._.. EMSo. .S g$�CC�G v� �•e�y� M:r`?i iNOW � �q�•����Y�Qis�iii' iibNiiiii�w'� 'i$gi�aGi_�'sz;'suu m '3iR;E`�`ceLe��:����� "119sITs I iF'� BCm' a 3R �i S i�s'�?i3 ggi irk y3Cs�asOZZU i �gCEZiki:f%—ZLaf'ta<`�,h, 4 tm:'a7d�a`!L ?��ia�itt$:3Et�fts:. ii.:CA 'ate '"ta *'RIM rsaziiEis'sisaaassr< miioeii;:^" Paoe 6 of 7 Page 25126 Schlumberger Formation Salinity Determination Report 3. Conclusion The Rwa analysis from the openhole density and resistivity logs in North Fork Unit 34-26 indicates a water salinity of 11500 ppm in the vicinity of the casing shoe at 2489 ft MD. This analysis is based on using typical sandstone parameters in the density porosity and Rwa equations. Page 7 of 7 0 Roby, David S (DOA) From: Davies, Stephen F (DO,;, Sent: Wednesday, November 18, 201S 11:S3 AM To: Roby, David S (DOA) Subject: FW: North Fork Unit Pool Rules Application - Questions FYI — a corrected copy of the NFU application is on the way. From: Tim ]ones[ma ilto:Tim.]ones(d)cookinlet. net] Sent: Wednesday, November 18, 2015 9:02 AM To: Davies, Stephen F (DOA) Subject: RE: North Fork Unit Pool Rules Application - Questions Steve, I had a conversation with our reservoir engineer on this and it appears we used incorrect terminology in this section. You are correct that the 1P, 2P and 3P categories are cumulative. We should have used the terms Proved, Probable and Possible to note the various categories broken out. I made the change in the document and have submitted a corrected copy electronically to Samantha. I will drop off paper copies of the corrections to her later today. If you have any other questions or notice any other issues, please let me know. Tim From: Davies, Stephen F (DOA)[mailto:steve.davies@alaska.gov] Sent: Tuesday, November 17, 201S 10:46 AM To: Tim Jones <Tim.Jones@cookinlet. net> Subject: North Fork Unit Pool Rules Application - Questions I'm reviewing CIE's application for Pool Rules for the North Fork Unit, and I have an initial question. On page 2, the application states the CIE's SEC reserves for the NFU as of July 31, 2014 were: 1P — 23.99S BCF 2P — 3S.SS2 BCF, and 3P — 58.841 BCF With a combined total of 1P, 2P and 3P Reserves of 118.388 BCF. maybe i-m misunderstanding CIE's terminology here, but I thought that: • 1P Reserves are proved reserves, • 2P Reserves are proved plus probable reserves, and • 3P Reserves are proved reserves plus probable reserves plus possible reserves. So, to combine the totals of 1P plus 2P plus 3P reserves would be incorrect. Or am I mistaken? I checked and my understanding seems to match the "Resource Uncertainty Categories" section on page 9 of the SFE_' Guidelines for the Evaluation of Petroleum Reserves and Resources. Please let me know if I've missed something here. Regards, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 AOGCC: 907-279-1433 Fax: 907-276-7542 333 West 7'n Avenue, Suite 100 Anchorage, AK 99501 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 Steve Davies at 907-793-1224 or steve.davies@alaska.gov.
