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Home My WebLink AboutCO 231 ACONSERVATION ORDER 231A Docket Number: CO -20-009 1. May 21, 2020 Notice of hearing, affidavit of publication, email distribution, mailings 2. June 26, 2020 CINGSA Request for a hearing 3. August 3, 2020 Joint request from Hilcorp and CINGNA to cancel hearing 4. August 4, 2020 Transcript and sign -in sheet 5. August 12, 2020 Joint Request to Amend CO 231 and CO 231.001 6. August 27, 2020 Transcript and sign -in sheet ORDERS STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue Anchorage, Alaska 99501 Re: THE MOTION OF THE ALASKA ) Docket Number: CO 20-009 OIL AND GAS CONSERVATION ) Conservation Order 23 ] A COMMISSION to amend Conservation ) Kenai Gas Field Order 231 to revise well spacing requirements ) Cannery Loop Unit for the Beluga, Upper Tyonek, and Tyonek ) Beluga, Upper Tyonek, and "D" Gas Pools, Kenai Gas Field, Cannery ) Tyonek "D" Gas Pools Loop Unit, Kenai Peninsula Borough, Cook ) Kenai Peninsula Borough, Inlet Basin, Alaska. ) Cook Inlet Basin, Alaska IT APPEARING THAT: September 9, 2020 1. On its own motion, the Alaska Oil and Gas Conservation Commission (AOGCC) set a hearing to consider amending Conservation Order Number 231 (CO 23 1) to review whether a 1,500 - foot offset requirement is necessary for a vertical property line in the case of a segmented oil and gas lease. 2. Pursuant to 20 AAC 25.540, the AOGCC tentatively scheduled a public hearing for August 4, 2020. On May 19, 2020, the AOGCC published notice of the hearing on the State of Alaska's Online Public Notices website and on the AOGCC's website, and the AOGCC 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 May 21, 2020, the notice was published in the ANCHORAGE DAILY NEWS. 3. On June 26, 2020, the AOGCC received a request to hold the hearing. 4. The public hearing was convened August 4, 2020 and continued until August 27, 2020 in order to allow Hilcorp Alaska, LLC (Hilcorp) and Cook Inlet Natural Gas Storage Alaska, LLC (CINGSA) additional time to prepare testimony. 5. The public hearing was re -convened on August 27, 2020. Hilcorp and CINGSA provided testimony. The hearing record closed. 6. Hilcorp's and CINGSA's testimony and AOGCC public records are the basis for this order. FINDINGS: 1. Operators: Hilcorp is the operator of the CLU, which lies onshore within the Kenai Peninsula Borough, Cook Inlet Basin, Alaska. CINGSA is operator of the Sterling C Gas Storage Reservoir that also lies within the CLU. 2. Owners and Landowners: All leases in the CLU are owned 100% by Hilcorp except for State of Alaska lease ADL 391627, a vertical lease segment, with clearly defined lateral, top, and bottom boundaries. ADL 391627 is owned by CINGSA. The State of Alaska, Department of Natural Resources (DNR) and private parties are landowners. 3. Pool Definitions: The Cannery Loop Field contains one gas storage pool and three actively producing natural gas pools. They are, in descending stratigraphic order: Sterling C Gas Storage Pool, Beluga Gas Pool, Upper Tyonek Gas Pool, and Tyonek "D" Gas Pool. Storage CO 231A September 9, 2020 Page 2 of 9 Injection Order No. 9 (SIO 9) defines the Sterling C Gas Storage Pool I (Figure 1, below) and CO 231—the pool rules governing CLU development operations—defines the current Beluga, Upper Tyonek, and Tyonek "D" Gas Pools (Figures 2 and 3, below). 4. Structure: The geologic structure within the CLU is an anticline with four-way dip closure as demonstrated by structure maps provided by Hilcorp and Union Oil Company (former operator of the field) at the top of the Sterling C Gas Storage Pool and at the tops of the underlying Beluga and Tyonek Formations. 5. Confinement: Upper confinement for the Sterling C Gas Storage Pool is provided by siltstone and mudstone layers near the base of the Sterling B interval and by the B5 coal, which is 10 to 20 feet thick and laterally continuous across the CLU structure (Figure 1). Lower confinement is provided by a siltstone and mudstone interval at the base of the Sterling Formation and within the top of the Beluga Formation that is 30 to 55 feet in thickness and laterally continuous across the CLU structure. Fracture pressure, reservoir pressure, and production information demonstrate that these confining zones are effective reservoir seals. 6. Well Spacing Requirements: In the absence of an order to the contrary, 20 AAC 25.055, allows testing or regular production within 1,500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line. Rule 3 of CO 231 establishes drilling units of a quarter -quarter subdivision of a governmental section. Rule 4 of CO 231 prohibits regular gas production closer than 1,500 feet to the boundary of the Affected Area or closer than 500 feet to the boundary of the Participating Area established for that pool. CO 231.001 allows testing, completion, and production of CLU 13 provided the well is not opened to regular production closer than 1,500 feet to any property that is not committed to the CLU and the well is not opened within 1,500 true vertical feet of the base of the Sterling C Gas Storage Pool—a property line separating CINGSA's lease ADL 391627 from Hilcorp's underlying and overlying leases. 7. Operations Protocols: Hilcorp and CINGSA have jointly established a list of best protocols— including ongoing exchange of applications, reports, well and cement evaluation logs, flow and pressure data, and material balance analyses—as well as criteria for well -design and cementing to ensure integrity of both productive and storage reservoirs. Hilcorp testified that Hilcorp and CINGSA agree not to perforate within 50 true vertical feet of the base of the Sterling C gas reservoir. CONCLUSIONS: 1. Amending CO 231 for the Beluga, Upper Tyonek and Tyonek "D" Gas Pools is appropriate to clarify well spacing, well construction, and well integrity requirements. IAOGCC, 2010, SIO 9A, Rule 2: The Sterling C Gas Storage Pool consists of the interval within the Affected Area that is common to, and correlating with, the measured depths from 6690' to 6945' in well CLU No. 8. 2AOGCC, 1987, CO 231, Rule 2: a) The Beluga Gas Pool is defined as the accumulation of gas occurring within the affected area in sands stratigraphically equivalent to the interval between the measured depths of 6081' and 9171' in Cannery Loop Unit Well #1. b) The Upper Tyonek Gas Pool is defined as the accumulation of gas occurring within the affected area in sands stratigraphically equivalent to the interval between the measured depths of 9171' and 10,831' in Cannery Loop Unit Well #1. c) The Tyonek "D" Gas Pool is defined as the accumulation of gas occurring within the affected area in sands stratigraphically equivalent to the interval between the measured depths of 10,831' and 11,962' in Cannery Loop Unit Well #1. C0 231 A September 9, 2020 Page 3 of 9 2. Establishing consistent requirements will facilitate further development drilling and ensure greater ultimate resource recovery, but will not promote waste, jeopardize correlative rights, or result in an increased risk of fluid movement into freshwater aquifers. NOW, THEREFORE, IT IS ORDERED: The continued development and operation of the Beluga, Upper Tyonek and Tyonek "D" Gas Pools is subject to the following rules and the statewide requirements under 20 AAC 25, to the extent not superseded by these rules. This order supersedes Conservation Order 231 and Conservation Order 231.001. Affected Area (Restated from CO 231) Seward Meridian ownshi Range Sections 06N, Rl 1 W 32, 33, 34 05N, Rl 1W 3, 4, 5, 6, 7, 8, 9, 10, and 18 fTO5N, RI 1 W Those portions of Sections 16, 17, 19, and 20 lying north of the Cannery Loop Fault trace as depicted on Exhibit "C" of the July 8, 1987 Public Hearing Record. Rule 1 Pool Definitions (Restated from CO 231) The Beluga Gas Pool is defined as the accumulation of gas occurring within the affected area in sands stratigraphically equivalent to the interval between the measured depths of 6081' and 9171' in Cannery Loop Unit Well #1. The Upper Tyonek Gas Pool is defined as the accumulation of gas occurring within the affected area in sands stratigraphically equivalent to the interval between the measured depths of 9171' and 10,831' in Cannery Loop Unit Well #1. The Tyonek "D" Gas Pool is defined as the accumulation of gas occurring within the affected area in sands stratigraphically equivalent to the interval between the measured depths of 10,831' and 11,962' in Cannery Loop Unit Well #1. Rule 2 Well Snacine (Revised this order) There shall be no restrictions as to well spacing in horizontal directions within the Beluga, Upper Tyonek, or Tyonek "D" Gas Pools except that no hydrocarbon -bearing interval shall be opened in a well within 1,500 feet of a horizontal, external property line where the owners and landowners are not the same on both sides of the line. No hydrocarbon -bearing interval may be opened to a well within 50 true vertical feet of the Sterling C Gas Storage Pool. No hydrocarbon -bearing zone may be opened to a well between 50 and 100 true vertical feet of the Sterling C Gas Storage Pool without advance approval from the AOGCC. Each application to perforate within this interval must be accompanied by a cement evaluation log and statements CO 231A September 9, 2020 Page 4 of 9 1640140 501331001400 2253 ft J UNOCAL KENAI UNIT 13-08 1774 FSL 1034 FWL TWP: 5 N - Range: 11 W - Sec. 8 2040050 501332053400 MARATHON CANNERY LOOP UNIT 8 208 FSL 486 FEL TWP: 5 N - Range: 11 W - Sec. Figure 1. KU 13-08 and CLU -8 Reference Logs, Sterling C Gas Storage Pool3 from Hilcorp and CINGSA agreeing that log demonstrates good pipe -to -formation bond beginning within the Sterling C Gas Storage Pool and continuing uninterrupted beyond the planned open zone(s). If pipe -to -formation cement bond appears less than good quality to CINGSA or AOGCC, Hilcorp will provide AOGCC a written evaluation of pipe -to -formation cement bond from a qualified, third -party, professional engineer. 3 Figure 1 is for illustration purposes only. Refer. to well logs recorded in wells Kenai Unit No. 13-08 and Cannery Loop Unit No. 8 and Storage Injection Order No. 9 for a precise representation of the Sterling C Gas Storage Pool. CO 231 A September 9, 2020 Page 5 of 9 6 O 0- U) N N 0 Betug Tyo SP Carel n De h Ress PO.. SP... 1)0 MV . _...._CALL...... pD 30 IN Res00 LD RHOS 2 2 OHIAM 2000.65 GC3 26 GR TVOSS> DRHO GAP, 150 0.2 GIACC 0. RHG6 < I B GIC3 1 Bt NPOR(CNS 0 % ea DTCP(OT 5o us/ 5 aW. 10 -Sha St ding For ation - 6000 3100 sh gaForm on - Top 3200 6200 6300 5300 6400 -5400 6500 -5500 6600 -8600 ..:: 6700 -5700 t shoo -_ 6900 •seoo '= 7000 -5900 7100 6000 7200 3100 7300 6200 7400 6300 7500 7600 6400. 7700 6500 — 7800 -6600 _ 7900 6700 8000 6800 8100 69M 8200 7000 -- 8300 -7100 •- 8400 8500 -7200 - - .. 8600 -73M 8700 7400 . 8800 _7500 8900 -..`. 7600 9000 Format) -Base 9100 -7700., - 9 Figure 2. CLU -1 Reference Log, Beluga Gas Poo14 4 Figure 2 is for illustration purposes only. Refer to well logs recorded in Cannery Loop Unit No. 1 for a precise representation of the Beluga Gas Pool. CO231A September 9. 2020 Page 6 of 9 BeIL Tyol O O a f6 0 Y N C O H N CL CL D SP CORelatDn Depth Reds PO'O51 SP CALI AO ResDPLD) RHOS 2 OHIAA 2000165 G.Ca 265 170 MV 305 ll 25 GR T10SS> ORHO GAPI 1501 0.2 GI.vCC 0. OB < NPOR(CIJsj 19 G/C3 191 0 % OTCP(DT) 50 USF 5 SaM-5111-sial S s•• 8800 .7500 <<< j1 8900 7500 i '. -..E... 9000 a Forma n -Base 9100 -7700 ek Form n - .-. -.9 -7800 9300 .7900 �., 9400 e000 9500 9600 -8100 "_-- 9700 -8200 ..__ 9800 -8300 - ---- 9900 10000 -esa0 10100 t 10200 -moo -- 10300 -8700 10400 .8800 10500 8900 ---- 10600 -9000 —"' 10700 10800 -9100 — 10900 -9200 11000 -9300 11100 -9400 { 11200 -5500 11300 11400 -%� 11500 -9700 --. 11600 -9800 _ 1 11700 -saw - 11800 -10000 11900 _10100 Figure 3. CLU -1 Reference Log (Continued), Upper Tyonek and Tyonek "D" Gas Pools 5 Figure 3 is for illustration purposes only. Refer to well logs recorded in Cannery Loop Unit No. 1 for precise representations of the Upper Tyonek and Tyonek "D" Gas Pools. CO 231 A September 9, 2020 Page 7 of 9 Rule 3 Well Inteerity For all newly drilled wells, an intermediate casing string must be set more than 50 feet below the base of the Sterling C Gas Storage Pool and continuously cemented to a minimum of 250 vertical feet above the top of that pool. A cement evaluation log must be provided to CINGSA and AOGCC that demonstrates good quality pipe -to -formation bond across the gas storage pool. If pipe -to - formation cement bond appears less than good quality to CINGSA or AOGCC, Hilcorp will provide AOGCC a written evaluation of pipe -to -formation cement bond from a qualified, third - party, professional engineer. Rule 4 Administrative Action (Revised this order) Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater aquifers. DONE at Anchorage, Alaska and dated September 9, 2020. Jeremy kRlm,µ by oraz 0 M" M. Price�9.,e:3a-0 Jeremy M. Price Chair, Commissioner TION Digitally signed by Daniel T. Daniel T. Seamount• L. Seamount, Jr. Dat,zgzDO9.o9 t9sz:4s-w•oa• Daniel T. Seamount, Jr Commissioner Jessie L. Digitally signed by Janie L Chmlelowekl Chmielowski 11:z020 -w 10 08:41:58-08'00' Jessie L. Chmielowski Commissioner As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 INDEXES PUBLIC MEETING AOGCC 8/27/2020 ITMO: APPLICATION OF MLCORP AK FOR SUNDRY APPROVAL D VK Nn rn 1n. ALASKA OIL AND GAS CONSERVATION COMMISSION In the Matter of the Application of ) Hilcorp Alaska for Sundry Approval to ) Perforate Cannery Loop Wells 13C and 15C ) Which Pass Through the Sterling C Gas ) Storage Pool and Which are Within 1,500 ) Feet of the Vertical Property Line. ) Docket No.: CO 20-009 PUBLIC HEARING August 27, 2020 10:00 o'clock a.m. BEFORE: Jeremy Price, Chairman Jessie Chmielowski, Commissioner Daniel T. Seamount, Commissioner w.y..�, Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Awh. AK 99501 Fax: 907-243-1473 Email: sahileQgei.net PUBLIC MEETING AOGCC 8/272020 ITMO: APPLICATION OF NILCORP AK FOR SUNDRY APPROVAL DOCKET NO. CO 20-009 Computer Matrix, LLC Phone: 907-243-0668 135 Christemen Dr., Ste. 2., Arch. AK 99501 Fax: 907-243-1473 Emil: saWle@gci.net Page 2 1 TABLE OF CONTENTS 2 Opening remarks by Commissioner Seamount 03 3 Testimony by Cody Terrell 08 4 Testimony by Anthony McConkey 10 5 Testimony by Ben Siks 12 6 Testimony by Taylor Wellman 27 7 Testimony by Moria Smith 31 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Computer Matrix, LLC Phone: 907-243-0668 135 Christemen Dr., Ste. 2., Arch. AK 99501 Fax: 907-243-1473 Emil: saWle@gci.net PUBLIC MEETING A(x7C'C 827/2020 ITMO: APPLICATION OF HILCORP AK FOR SUNDRY APPROVAL D( KFT Nn I`D en nno Page 3 1 P R O C E E D I N G S 2 (On record - 10:05 a.m.) 3 COMMISSIONER SEAMOUNT: Good morning. I'll 4 call this meeting to order. This is docket number CO 5 20-009, considering the amendment of conservation order 6 231. This hearing is being held on the morning of 7 August 27th, 2020 at 10:05 a.m. This is the location 8 of the Alaska Oil and Gas Conservation Commission, 9 AOGCC. Our offices here are at 333 West 7th Avenue, 10 Anchorage, Alaska. Before we begin I'll introduce the 11 Commissioners. To my right is Commissioner Jessie 12 Chmielowski, Commissioner and Chair Jeremy Price is 13 attending telephonically and I'm Commissioner Dan 14 Seamount, 15 If any persons here or on the phone needs 16 special accommodations to participate in these 17 proceedings please contact Jody Colombie who you've 18 been listening to for a while, she's in the back there. 19 You can hand her a note or if you're listening 20 telephonically you can call her at 793-1221 and you can 21 relay your questions to her that way. She'll do her 22 best to accommodate you. 23 Computer Matrix is recording the proceeding. 24 Upon completion and preparation of the transcript 25 persons desiring a copy will be able to obtain it by °' L° ,`1 Phone: 907-243-0668 135 Chapman Dr_ Ste_ 2, Aiwh. AK 99501 Fax: 907-243-1473 Email: sahlle iugci.nel PUBLIC MEETING AOGCC 8/2712020 ITMO: APPLICATION OF HILCORP AN FOR SUNDRY APPROVAL DOCKET NO. CO 20-009 Page 4 1 contacting Computer Matrix. 2 This docket was first heard on August 4th, 3 2020. On August 3rd, 2020, Cook Inlet Natural Gas 4 Storage, known as CINGSA, requested that the August 5 4th, 2020 hearing be continued. Subsequently the 6 Commission granted the request. AOGCC went on the 7 record with all parties on August 4th, 2020 for g calendaring purposes and all parties agreed to the 9 continuance and the hearing was set for today. 10 Hilcorp submitted application for sundry 11 approval forms to perforate the Cannery Loop or CLU 13 12 and CLU 15 wells. Both the CLU 13 and the CLU 15 pass 13 through reservoir sands within CINGSA's Sterling C gas 14 storage pool. Because some of the intervals Hilcorp 15 seeks to perforate are within 1,500 feet of the 16 vertical property line of the gas storage pool, state 17 of Alaska lease ADL 39167 requires spacing exceptions 18 under rule 4 of conservation order CO 231 and possibly 19 regulation AAC 25.055. 20 As a result on its own motion AOGCC set this 21 hearing to consider amending CO 231. Specifically 22 AOGCC is reviewing whether a 1,500 foot offset 23 requirement is appropriate for a vertical property 24 line. 25 The notice of this hearing was published in the Computer Matrix, LLC Phone: 907-243-0666 135 Christensen Dr-, Ste. 2, Anch, AK 99501 Fax: 907-243-147} Email: saule(t9ganet PUBLIC MEETING AOGCC 8/2712020 ITMOI APPLICATION OF BILCORP AK FOR SUNDRY APPROVAL DOCkFT NO rn M nno Page 5 1 Anchorage Daily News on May 19th, 2020. It was also 2 posted on the state of Alaska Online Notices website 3 email distribution list as well as AOGCC's own website. 4 Subsequently CINGSA requested that this hearing 5 be held on June 26th, 2020. On August 12th, 2020 6 Hilcorp and CINGSA filed a joint response to each of 7 the questions that AOGCC asked them to clarify. 8 Let's see, how many people do we have to 9 potentially testify. I heard someone say that they 10 were there for questions, I don't know if they said yes 11 on this. But anyway it looks like one, two, three, 12 four, five, six, seven people say they're going to -- 13 I'm going to say potentially testify. I didn't know I 14 could count that high, but yeah, there's seven. It 15 appears that Hilcorp and CINGSA intend to testify. Are 16 there any other parties planning to testify? 17 (No comments) 18 COMMISSIONER SEAMOUNT: Okay. I will ask that 19 question one more time at the end of this hearing. 20 The Commissioners will ask questions during the 21 testimony. We will most likely take a recess to 22 consult with staff to determine whether additional 23 information or clarifying questions are necessary. 24 For those testifying please keep in mind that 25 you must speak into the microphone and the green light wuFu�o� mnu,x, �w Phone: 907-243-0666 135 Christensen D[, Ste, 2.. Amit. AK 99501 Fax: 907-243-1473 Email: suhile(iugci.net PUBLIC MFEI INC AOGCC 827/2020 11 MO. APPLICATION OF HILCORP AK FOR SUNDRY APPROVAL. DOCKET NO. CO 20-009 Page 6 1 needs to be shining bright. It'll be green when it's 2 dull, but it needs to be fish lure light. Please speak 3 in the microphone so that those in the audience and the 4 court reporter can hear. Also please remember to 5 reference your slides so that someone reading the 6 transcript or the public record can follow along. For 7 example refer to slides by their numbers if numbered or 8 their titles if not numbered. 9 We have a few ground rules on what is allowed 10 to -- for testimony. First of all all testimony must 11 be relevant to the purposes of the hearing that I 12 outlined a few minutes ago and to the statutory 13 authority of the AOGCC. Anyone desiring to testify may 14 do so, but if the testimony drifts off subject we will 15 limit the testimony to three minutes. Additionally 16 testimony may not take the form of cross examination. 17 As I said before the Commissioners will be asking the 18 questions. And finally testimony that is disrespectful 19 or inappropriate will not be allowed and I probably do 20 not even need to say that. 21 Commissioners Price or Chmielowski, do you have 22 anything to add, did I miss anything? 23 COMMISSIONER CHMIELOWSKI: Nothing to add, 24 sounds great. Thank you. 25 COMMISSIONER SEAMOUNT: Commissioner Price. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Aneh, AK 99501 Fax 907-243-1473 Email: sahile®gci.net PUBLIC MFFTING AOGCC 8'27,'2020 11 MO APPLICAI70N OF fill -CORP AK FOR SUNDRY APPROVAL 11OCV rT.n I- "I nnn Page 7 1 CHAIRMAN PRICE: Nothing for me, thanks. 2 COMMISSIONER SEAMOUNT: Okay. 3 CHAIRMAN PRICE: No. 4 COMMISSIONER SEAMOUNT: All right. We'll start 5 with the testimony, Who should we start with first, 6 CINGSA or Hilcorp? I see a finger pointed toward 7 Hilcorp. 8 Okay. Please identify yourself and your 9 qualifications and you may begin your testimony. 10 Oh, wait a minute, let me -- I'll swear you in 11 altogether. So please everyone testifying raise your 12 right hand including those I can't see that are on the 13 telephone. Go ahead, raise your right hands. 14 (Oath administered) 15 IN UNISON: Yes. 16 COMMISSIONER SEAMOUNT: I hear yeses. Okay. 17 Good. Okay. You may begin your testimony. Please 18 identify yourself. 19 MR. TERRELL: This is Cody Terrell. I am 20 landsman for Hilcorp Alaska, the Kenai team. 21 MR. McCONKEY: My name is Anthony McConkey. 22 I'm a reservoir engineer for Hilcorp. And just to go 23 back into the -- my expertise, I graduated from the 24 University of Alaska, Fairbanks in petroleum 25 engineering in 2011, I worked for BP for three years as "I Phone: 907-243-0668 135 Chnstensen Dr., Ste, 2. Aitch. AK 99501 Far 907-243-1473 Hmail'. sahile(rLgci.nel PUBLIC I MEETING AOGCC 827/2020 ITMO: APPLICATION OF IIJWORP AK FOR SUNDRY APPROVAL DOCKET NO. CO 20-009 Page 8 1 a production engineer and then I came over to Hilcorp 2 and have been working there for seven years as a 3 reservoir engineer. 4 MR. SIKS: My name is Ben Siks, I'm a geologist 5 for Hilcorp. I graduated in 2009 from University of 6 Texas with my master's degree, worked for BP for six 7 years and now I continue my work with Hilcorp. 8 COMMISSIONER SEAMOUNT: Okay. I -- I'm 9 terrible with names so every time you say something 10 please -- well, not every time, but if someone else 11 says something please identify yourself. 12 And, Cody, what was your last name? 13 MR. TERRELL: Terrell. 14 COMMISSIONER SEAMOUNT: Terrell, Cody Terrell. 15 okay. And you are a landsman. Okay. 16 Okay, Mr. Terrell, please do your presentation. 17 CODY TERRELL 18 previously sworn, called as a witness on behalf of 19 Hilcorp Alaska, testified as follows on: 20 DIRECT EXAMINATION 21 MR. TERRELL: Most of today will be covered by 22 Anthony and Ben. I just wanted to clarify a couple 23 things before we get started. 24 On the notice of public hearing for this 25 hearing today it says that both Cannery Loop 13 and Clompmer Matrix, IISPhone: 907-243-0668 135 Chostensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gcLw PUBLIC MEETING A000C &272020 11 MO: APPLICAT ]ON OF HILCORP AK FOR SUNDRY APPROVAL DOCKET NO CO 20-009 Page 9 1 Cannery Loop 15 require a spacing exception under rule 2 4 of conservation order 231 and under statewide 3 spacing, 20 AAC 25,055. I just wanted to clarify that 4 the Cannery Loop Unit is governed by conservation order 5 231 and not statewide spacing because field portals had 6 been established for Cannery Loop Unit. There is a 7 spacing exception that has been issued for Cannery Loop 8 13, conservation order 231.001, which does establish a 9 1,500 foot offset from Sterling C. But conservation 10 order 231 does not have a rule in place where there's a 11 1,500 foot offset from vertical boundaries, it only has 12 a -- rule 4 that's stated in the public hearing notice 13 has a 1,500 foot offset from the boundary of the 14 affected area and a 500 foot boundary of the 15 participating area established for the pool. 16 So a conservation order is not required for 17 Cannery Loop 15, but Cannery Loop 13 it would be 18 required under 231.001. And it has been advised by 19 AOGCC that we establish a rule or a -- to see if there 20 is a setback requirement for the vertical property line 21 for Sterling C. 22 And I'll turn it over to Anthony and Ben to go 23 over what we -- but I just wanted to clarify that there 24 is not a rule in place under the -- under conservation 25 order 231 for an offset from Sterling C. Coinpvter Matrix, LLC Phone:907-243-0668 135 Clnistensen ER, Ste. 2., Awh, AK 99501 Fax: 907-243-1473 Email: sahile(Ogi. t PUBLIC MEETING AOGCC 8/272020 ITMO: APPL.ICA'I ION OF HILCIORP AK FOR SUNDRY APPROVAL DOCKET NO. CO 20-009 Page 10 1 COMMISSIONER SEAMOUNT: Okay. Thank you. 2 ANTHONY McCONKEY 3 previously sworn, called as a witness on behalf of 4 Hilcorp Alaska, testified as follows on: 5 DIRECT EXAMINATION 6 MR. McCONKEY: Okay. So this is Anthony 7 McConkey speaking. Again I'm a reservoir engineer for 8 Hilcorp Alaska. I work Cannery Loop Unit which we'll 9 be talking about today. 10 We put together a small slide pack. The intent 11 of the slide pack was really to cover whether or not 12 it's reasonable to perf within 1,500 feet if we have 13 barriers within the reservoir. And then we're also 14 going to talk a little bit about what is our mechanical 15 isolation, so how would we isolate ourselves from the 16 Sterling C gas or sand. I'm -- I myself I personally 17 work the four storage reservoirs within Hilcorp so I 18 know the importance of maintaining isolation and we are 19 in absolute alignment with CINGSA that we do want to 20 ensure that we maintain isolation between the Beluga 21 sands and the Sterling C. 22 So I have moved to slide two, it's the contents 23 of what we'll be talking about today. So we're going 24 to start off, we're going to talk about the geologic 25 description of the confining zone. So, Ben Siks, our Computer Matrix, LLC Phone: 907-243-0668 135 Christemeu Or., Ste_ 2., Anch. AK 99501 Fax 907-243-1473 Email' sahileCogdnel PUBLIC MEETING AOGCC 827/2020 ITMO. APPLIC'A-CION OF HILCORP AK FOR SUNDRY APPROVAL DOCKET NO. CO 20-009 Page 11 1 geologist, he will describe the confining zones above 2 and below the Sterling C, what -- what contains that 3 gas in storage..... 4 MS. SMITH: Hey, Anthony, excuse me for 5 interrupting. Can you speak a little closer to the 6 microphone,..... 7 MR. McCONKEY: I'm sorry. 8 MS. SMITH: .....our experts on the phone are 9 having a hard time hearing. 10 Thanks. 11 MR. McCONKEY: I'm sorry. Okay. Sorry about 12 that. So okay, I will speak better in the microphone. 13 The next slide we'll -- few slides we'll talk 14 about is the Cannery Loop production history. I'm 15 going to show a production plot, I'm going to show 16 really just a timeline of the wells that were drilled 17 at Cannery Loop, what are the recent wells we've 18 drilled. After that I'll talk about Cannery Loop's 19 well completion styles. So there is a different style 20 in which we complete wells, we set casing over the 21 Sterling C with the intent to confine that gas storage 22 sand so we'll go into that. CLU 8 is a well that we 23 perfed particularly close to the storage reservoir, it 24 was about 85 feet TVD distance from that. So with that 25 we contacted CINGSA and AOGCC, we came up with a rate C'empuler Matrix, LLC Phone: 907-243-0668 135 Christensen Dc, Ste. 2., Anch. AK 99501 I'm 907-243-148 Email: sahile(o,iei.net PUBLIC MEETING AOGCC 8272020 ITMO: APPLICATION OF HILCORP AK FOR SUNDRY APPROVAL DOCKET NO. 0020-009 Page 12 1 and pressure monitoring system. And so we'll talk 2 about what we did there and the tools that we used for 3 that. And then lastly we'll -- we'll close it with the 4 resource size in the middle and upper Beluga sands, why 5 this is important to us to be able to perforate these 6 zones. 7 BEN SIKS 8 previously sworn, called as a witness on behalf of 9 Hilcorp Alaska, testified as follows on: 10 DIRECT EXAMINATION 11 MR. SIKS: All right. Make sure I get close to 12 the microphone here. Again my name's Ben Siks, I'm the 13 geologist that's working the Cannery Loop field. 14 So now we're on slide three. And just to kind 15 of orient everybody on the slide I have a reference map 16 with the unit outline for Cannery Loop with A to A 17 prime going through the wells that I'm displaying. On 18 the left is Cannery Loop 10, in the middle Cannery Loop 19 8, and on the far side Cannery Loop 15. So now we're 20 , talking about what's above the Sterling C, our 21 confining zones. And really this is in 100 percent 22 alignment with SIO -009 which is the injection order 23 forcing the injection into the Sterling sand. But 24 they're capped by a thick, laterally continuous coal 25 which is referred to as.the B5 coal. It's continuous Computer Manx, LLC Phone: 907-243-0668 135 Christensen Dc, Ste, 2., Aneh. AK 99501 Fax: 907-243-1473 Email sahile(a gei.net PUBLIC MEETING AOGCC 85272020 11 MO. APPLK A I ION OF HILCORP AK FOR SUNDRY APPROVAL DOCKET NO. CO 20-009 Page 13 1 over the crest of structure at Cannery Loop, 10 to 20 2 feet thick. The coal depth is approximately 4,900 feet 3 TVDSS and on the type log it is located at 6,670 feet 4 to 6,690 feet MD. So just kind of looking at the 5 confining pressures that were required, original 6 reservoir pressures were somewhere in the order of 7 2,206 PSI. The maximum injection pressure coming from 8 that SIO -009 is 2,483 PSI and then the leak -off test 9 arrived with the Sterling C sands from Cannery Loop 6 10 well showed a frac range from 29 to 3,400 PSI. So 11 they're operating well within the limits, that seal is 12 intact, it's across the whole structure so we're not 13 really having any issues with containment going above 14 it. 15 COMMISSIONER SEAMOUNT: Mr. Siks, on the -- I 16 assume that -- you said the type log was Cannery Loop 17 number 8..... 18 MR. SIKS: Yes. 19 COMMISSIONER SEAMOUNT: .....and the coal is 20 the high resistivity zone; is that correct? 21 MR. SIKS: It's usually marked by a high gamma 22 ray marker. So the logs going through that -- that 23 Cannery Loop 8 well are cased so they're getting a 24 little bit of noise attenuated in there, but it's a 25 very correlatable marker throughout the section. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste, 2., Audi AK 99501 Fax: 907-243-1473 Email: sahileLg ,t et PUBLIC MEETING AOGCC 8/272020 ITMO: APPLICATION OF HILCORP AK FOR SUNDRY APPROVAL DOCKET NO. CO 20-009 Page 14 1 COMMISSIONER SEAMOUNT: But it would -- it -- 2 there's a red..... 3 MR. SIKS: The red is total gas in place. 4 COMMISSIONER SEAMOUNT: Oh, total gas. 5 MR. SIKS: Yep. 6 COMMISSIONER SEAMOUNT: Okay. And that -- that 7 is the coal, correct? 8 MR. SIKS: Yes. 9 COMMISSIONER SEAMOUNT: And then below that 10 you've got the sand, your storage sand; is that 11 correct? 12 MR. SIKS: The storage sands are below that, 13 yes. 14 COMMISSIONER SEAMOUNT: Okay. Okay. And this 15 will be the type log? 16 MR. SIKS: Yes, it is the type log in SIO -009. 17 COMMISSIONER SEAMOUNT: Okay. Okay. Thank 18 you. 19 MR. SIKS: Yep. Moving to slide four. Again 20 now we're just talking about the underlying strata. So 21 the Sterling C base is defined again in Cannery Loop 8 22 at that 5,101 foot TVDSS marker, right here in the 23 middle of the slide deck. And moving to CO 231, the 24 pool of the upper Beluga is defined at that 5,147 25 marker. So that leaves a 50ish foot no man's land of Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: saM[e@gci.net PUBLIC MEETING AOGCC 8,272020 ITMO: APPLICATION OF HILCORP AK FOR SUNDRY APPROVAL DOCKET NO. CO 20-009 Page 15 1 shale that kind of is between the Sterling C base and 2 the top of where we have our pool in the upper Beluga. 3 And looking at that siltstone interval, you know, it's 4 a -- it's a -- again it's across the entire structure, 5 30 to 55 feet thick and where it's penetrated by the 6 wells the depth is approximately, you know, 51, 50 feet 7 TVDSS. You know, as structure changes that moves a 8 little bit, but again you're looking at similar 9 reservoir pressures because it's datum to the 4,966 10 coming from SIO -009 and because it's a little bit 11 shalier and not so much of a clay your density goes up 12 and thus your frac range estimate goes even higher. 13 We have also FITs which Anthony will go into in 14 these upper Beluga sands that show pressures up to 12 15 and a half pounds per gallon which would equate to, you 16 know, 31 to 3,300 PSI and showing no communication with 17 the overlying sand. So the seal on the bottom is very 18 much intact as well. 19 With that I'll hand it over to Anthony. 20 MR. McCONKEY: Okay. The slide we're looking 21 at now is slide number 5, titled CLU Field Production. 22 What I wanted to show with this slide is really just 23 the history of the drilled wells at Cannery Loop and at 24 what point was this storage injection order 9 put into 25 place. And up into 2010 when the storage injection Computer Matrix. LLC Phone: 907-243-0668 135 Christensen Dr, Ste. 2-, Ar& AK 99501 IF= 907-243-1473 Email: sAule,gg, net PUBLIC MEETING AOGCC 8'27/2020 ITMO: APPLICATION OF IHL( IORP AK FOR SUNDRY APPROVAL DOCKET NO. CO20-009 Page 16 1 order was put into place we had drilled 11 wells at 2 Cannery Loop and of those nine produced. At the time 3 when that storage injection order was put in place we 4 had multiple wells that were open within 1,500 feet and 5 at that time there was proof of isolation that was part 6 of the storage injection order application. So again 7 that in itself shows that there is a geologic isolation g component to this. 9 Going forward within Hilcorp we drilled four 10 wells, one of those being a sidetrack, CLU 13, we 11 sidetracked CLU 5RD and then drilled CLU 14 and 15. 12 One of the things we learned when we drilled CLU 13 is 13 -- and we'll talk a little bit more about this when we 14 get into the completion styles, but the Sterling C and 15 the Beluga sands are in the same string of pipe so then 16 you're relying on good cement bond in order to isolate 17 yourself. Now CLU 13 did not have the best cement bond 18 isolation near the Sterling gas sand, that was the 19 reason, at least I believe, for that exemption to or 20 the amendment to the conservation order. And as of 21 right now we don't have any further plans. We did, but 22 when we looked at it further and we looked at the CDL, 23 we currently do not have any plans to perforate any 24 zones below the Sterling C in CLU 13. 25 With CLU 5, CLU 14 and CLU 15 we came up with a Computer Matrix, LLC Phone- 907243-0668 135 Christensen Dr, Ste, 2.- Anch. AK 99501 Fax 907-243-1473 Email sahfle(a gcinet PUNIJ(MFEl7NGAOCICC 8272020 ITMO: APPLICATION OF lilt CORP AK FOR SUNDRY APPROVAI- DOCKET NO( 0 20-009 Page 17 1 different style, So in CLU 5 when that was sidetrack 2 it was milled out below the Sterling C and then we did 3 the thick test as has been mentioned to prove isolation 4 from Sterling C. And with CLU 14 and 15 we set an 5 intermediate casing string across the Sterling C with 6 the intent for isolation. 7 So looking at slide six we're looking at CLU 8 5RD's completion. And again on the right side is a 9 schematic, it's a picture of the well. And really what 10 1 just wanted to show is how this was sidetracked. So 11 the nine and five-eighths, we came out of the nine and 12 five-eighths, the mill out window was below the 13 Sterling C. After we went out we drilled down to 14 6,562, that was about 30 to 40 feet below the mill out 15 window, ran a formation integrity test which passed 16 proving isolation from that string to the intermediate 17 casing string which contains Sterling C. 18 In CLU 14, this is really the style wells that 19 we drilled in -- last year in 2019, this year with CLU 20 15 in 2020 and what we intend to do going forward which 21 is we intentionally set our intermediate casing string 22 across the Sterling C. Again we did that in this case, 23 we ran cement, we ran a CDL before drilling out and 24 then when we did drill out we drilled down to 6,855 25 measured depth, ran a formation integrity test which Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste- 2., Anch. AK 99501 Fax: 907-243-1471 Email sahile(Ngcl. net PUBLIC MEETING AOGC'C 6/27/2020 ITMO. APPI KATION OP HILCORP AK FOR SUNDRY APPROVAL DOCKET NO. CO 20-009 Page 18 1 passed proving isolation. 2 And lastly, again this is a little redundant, 3 but CLU 15 again same style, set intermediate string 4 below the Sterling C, pumped cement, got a CDL, ran a 5 formation integrity test that passed below that. And 6 this is -- this is slide eight. 7 So moving on to slide nine. So CLU 8 was 8 drilled in 2004 and this was an old escape completion 9 drilled by Marathon and at the time when they did this, 10 they set the intermediate casing string above the 11 Sterling C. So again now what you had is you had 12 cement that had to be pumped all the way up through the 13 Beluga sands and past the Sterling C sand. And when -- 14 when we went in last year and we went and we perfed a 15 sand that was above the shallowest perf, it was 16 approximately -- I have the depths on here, but it was 17 approximately 90 feet measured depth and 86 feet TVD 18 depth below the Sterling C. We brought that sand 19 online, it came on a little stronger than we thought. 20 So to ensure that we weren't actually producing any of 21 the Sterling C gas sands, Beau York was the operations 22 manager at the time and myself, we contacted AOGCC as 23 well as Enstar and CINGSA and we came up with a plan to 24 shut -- it was during a shut-in period for CINGSA, they 25 shut that in, we shut-in CLU 8 to compare pressures. Computer Matrix, LLC Phone: 907-243-0665 135 Christensen Dc, Ste, 2., Aoch. AK 99501 Fax: 907-243-1473 Email: sahileLgci.nel PUBLIC MEETING AOG('C 8/272020 ITMO. APPLICATION OF HILCORP AK FOR SUNDRY APPROVAL DOCKET NO. CO20-009 Page 19 1 We kept CLU 8 shut-in a period longer to see if we saw 2 any reaction in the pressures from bringing CINGSA back 3 online and then after that we agreed to flowing 4 material balances back to P/Z plots on a monthly basis. 5 Again just to continue to ensure that we weren't 6 producing that sand. 7 COMMISSIONER CHMIELOWSKI: Mr. McConkey, just 8 to clarify, you said 80 feet TVD, is it -- is it 9 actually 42 feet based on your depth there? Oh, you 10 have a different number on the slide than I have. 11 MR. McCONKEY: Yes, I apologize. So -- so we 12 did have a previous version and our definition of the 13 base of the Sterling C differed from that of the 14 storage injection order and that of CINGSA. So what we 15 did is we actually corrected this to fall in line with 16 what CINGSA refers to as the base of the Sterling C. 17 COMMISSIONER CHMIELOWSKI: Okay. 18 MR. McCONKEY: And so that is why that depth 19 changed. 20 COMMISSIONER CHMIELOWSKI: Okay. 21 COMMISSIONER SEAMOUNT: Mr. McConkey, in -- we 22 had a hearing in 2010 and someone testified, I believe 23 it was CINGSA, that there was no potential in CLU 8. 24 Did I read that wrong, that the Sterling was all shaled 25 out and the Beluga did..... Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr, Ste, 2.. Arch. AK 99501 Fax907-243-1473 Email: sahile(a itemiet PUBLICMEETING AOGCC 827.2020 ITMO: APPLICATION OF IIILCORP AK FOR SUNDRY APPROVAL DOCKET NO. CO 20 009 Page 20 1 MR. WALSH: Commissioner Seamount, this is Tom 2 Walsh with CINGSA. There may well have been testimony 3 about that. There was no potential in CLU 8 remaining 4 in the -- in the Sterling, it was depleted. I don't 5 recall testimony about the Beluga interval. 6 COMMISSIONER SEAMOUNT: Okay. Okay. 7 MS. SMITH: And, Commissioner Seamount, this is 8 Moria Smith with CINGSA. It's also possible that that 9 was testimony regarding CLU 6 which had depleted the 10 Sterling C sand. 11 COMMISSIONER SEAMOUNT: Yeah. I remember 8. 12 MS. SMITH: Okay. 13 COMMISSIONER SEAMOUNT: I wouldn't remember 6. 14 Not a major point. 15 MR. McCONKEY: Okay. All right. So moving on 16 -- this is Anthony McConkey. Moving on to slide 10, 17 again this just visualizes what we did. So we have our 18 intermediate casing set at 6,722, that's above the 19 Sterling C marker. The base of the Sterling C sand as 20 agreed upon between CINGSA and Hilcorp is 6,899, that's 21 about 5,100 or 5,101 feet TVD. Now the three bottom 22 green boxes that you see in that log, those were 23 existing perforations that were online and producing 24 since 2004, they were online and producing when the 25 storage injection order was approved and they've been Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Aneh. AK 99501 Fax:907-243-1473 Email sahile(rggci.nel PUBLK MMINGAO(1C'C 827-2020 I IMO_ APPLI(A NON OF III I CORP AK FOR SUNDRY APPROVAL DOCKET NO. CO 20 009 Page 21 1 online and producing to this day. What we did is we 2 perfed an interval that was approximately 20 feet above 3 the shallowest perf interval. And again because of the 4 proximity of that perf to the Sterling C, we 5 proactively contacted AOGCC and CINGSA to ensure that 6 there was no sign of breach of Sterling C isolation. 7 So this is CLU 8's production plot. The well 8 actually loaded up, it began seeing water in 2000 -- I 9 can't really read that chart..... 10 COMMISSIONER SEAMOUNT: Could you..... 11 MR. McCONKEY: .....but again..... 12 COMMISSIONER SEAMOUNT: .....could you identify 13 that slide number, please. 14 MR. McCONKEY: Oh, sorry. So I'm now looking 15 at slide 11. This is CLU 8's production history. And 16 up into February, 2019 the well began seeing water and 17 it actually loaded up and we lost the well in February, 18 2019. So it remained shut-in for most of 2019. In 19 September of 2019 was when we went and we perforated 20 that zone. We also at the same time we set a plug 21 actually below those three escape modules that you saw 22 in the previous slide, in slide 10. And those top 23 three sands, while they did show production early on, 24 they seemed to be depleted at the time we set that 25 plug. So any further production will likely mostly be Computer Matrix, IFc Phone: 907-243-0668 115 Christensen Dr.. Ste. 2., Aueh, AK 99501 Fax: 907-243-1473 Gmail_ sahile(ag rues PUNLICMEEIING AOGCC 8/27;2020 1'1MO. APPLICATION OF HILCORP AK FOR SUNDRY APPROVAL DOCKEINO, CO 20-009 5 CINGSA and AOGCC to confirm. 6 This is -- what we did is in October, it was 7 October 15th and 16th was when we had conversations 8 with AOGCC and CINGSA, we came up with a plan to shut 9 the well in, we did for seven days, we got our first 10 static which was about 1,550 PSI wellhead pressure and 11 we used the gauge at the wellhead to get that pressure. 12 The calculated bottomhole pressure from that is 1,760 13 PSI on that date. We continued producing the well, we 14 got another shut-in bottomhole Page 22 1 coming from that -- that new perf which was the UB -1. 2 You can see when we brought that online it came at 3 about 3, 3 and a half million a day, that was a little 4 higher than we expected which prompted us to contact P/Z plot 5 CINGSA and AOGCC to confirm. 6 This is -- what we did is in October, it was 7 October 15th and 16th was when we had conversations 8 with AOGCC and CINGSA, we came up with a plan to shut 9 the well in, we did for seven days, we got our first 10 static which was about 1,550 PSI wellhead pressure and 11 we used the gauge at the wellhead to get that pressure. 12 The calculated bottomhole pressure from that is 1,760 13 PSI on that date. We continued producing the well, we 14 got another shut-in bottomhole pressure on April 19th 15 of this year, of 2020, and that showed a much lower 16 pressure of 1,068 PSI. So again you can draw a P/Z 17 plot, this is a standard static P/Z plot and you can 18 see that this shows a volume of about .84 BCF original 19 gas in place. If you assume an 80 percent recovery 20 efficiency which is fairly standard in the industry, 21 that would give us an estimated EUR of about .70 BCF. 22 Now to further kind of confirm that this is a 23 decline curve analysis of -- oh, sorry, this is slide 24 13 I'm now looking at. And this is just a standard 25 decline curve analysis and what you're looking at is ('omputer Manna. LLC Phone: 907-243-0668 135 Christensen Dr_ Ste. 2., Aneh. AN 99501 Fax 907-243-1473 Email: sahfle6ag6 net PUBLIC MELFING AOGCC 8,27/2020 11 MO, APPLK A ION OF 1411,CORP AK FOR SUNDRY APPROVAL DOCKET NO. CO 20-009 Page 23 1 that first drop, that first decline was we had the well 2 in high pressure and what that is is we did not have it 3 going through a compressor, we had it going directly to 4 the sales line which was about 750 or 700 and -- yeah, 5 750 PSI. And then in May or June we started seeing 6 loading issues so we did put it into compression, we 7 brought that pressure down to as low as 150 PSI and 8 that is that second bump you see. And now that it's 9 sitting at 150 PSI wellhead pressure you're starting to 10 see that decline again, it's about a 90 percent 11 decline. But if you follow that decline out that gives 12 you about .66 BCF ultimate recovery in this well. 13 Again with that and the static P over Z we do not feel 14 that we are connected to the much larger Sterling C gas 15 storage sand. 16 MR. SIKS: Yeah, and this last is Ben Siks 17 speaking again on slide 14. Just kind of iterate what 18 1,500 feet TVD from the base of Sterling C looks like 19 for us at the Sterling, so again it's a cross section 20 going through the middle of the structure. And what I 21 have labeled here is the Sterling C at the top, the 22 upper Beluga, the middle Beluga and the lower Beluga 23 kind of broken up into chunks. And we're roughly 24 looking southwest to northeast. But really the volume 25 in place that we're talking about encompassed in the Computer Matnx, LIC Phone: 907-243-0668 135 Christensen Dr., Ste, 2., Aneh AK 99501 Fax: 907-243-1473 Email: mIuIe m ei.nei PUHIJC MEETING AOGCC' 8/27/2020 1 FMO: APPLICATION OF HILCORP AK FOR SUNDRY APPROVAL DOCKET NO. CO20-009 Page 24 1 upper and middle Beluga, P10, P90 ranges from 20 to 80 2 BCF remaining recoverable. So it's the -- it's the 3 bulk of our volume remaining at Cannery Loop sits in 4 these upper intervals. So the 1,500 feet is very 5 constraining from a future production standpoint. 6 COMMISSIONER SEAMOUNT: Ms. Recorder, do you 7 know who was speaking? 8 REPORTER: Yes. 9 COMMISSIONER SEAMOUNT: Okay. 10 MR. McCONKEY: Okay. So the first thing I do 11 want to mention, so the three wells that I talked about 12 early on CLU 5RD, CLU 14 and CLU 15, we do have 13 proposed perf intervals that are within that 1,500 foot 14 interval. The timing of those perforations, CLU 5RD 15 would likely come sooner, we'd like to do it as early 16 as the third quarter of this year, really dependent on 17 when we can get that spacing exemption. CLU 14 and 15, 18 those wells are doing pretty decent. We don't like to 19 open too many sands as once because it runs the risk 20 for water so those would likely be at later dates. CLU 21 14 might be towards the fourth quarter of this year 22 with CLU 15 being as late as first quarter of next 23 year. But again I just wanted to state that again to 24 give a timeline of when we're hoping to actually 25 perforate some of these sands. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste, 2., Anch. AK 99501 Fax907-243-1473 Email: sahiletugcinet PUBLIC MEETT ING AOGCC 827/2020 ITMO: APPLICATION OF HILCORP AK FOR SUNDRY APPROVAL DOCKET NO. CO20-009 6 taking note on. And that Page 25 1 And the last thing I just do want to mention 2 too is that again going back to we -- we came -- we 3 created a document and -- with CINGSA that we agreed 4 upon, but there is some verbiage that I do want to 5 bring up that I think is just worth the Commissioners 6 taking note on. And that has to do with having a 7 minimum of 50 feet below the Sterling C. So there -- 8 there's a line in here that says that -- there's a 9 couple lines, but one of them is that for any existing 10 intermediate wells if the casing is not set at least 50 11 feet below the Sterling C pool, CINGSA requires a 12 minimum of a hundred feet interval of good pipe to 13 formation bond of the primary casing stream below the 14 base of the Sterling C pool. 15 The reason why I bring this up is I'm going to 16 go back up to slide -- I'll go to slide seven which 17 shows CLU 14. Now in the case of these wells we did 18 set the casing at least 50 feet below the Sterling C 19 and we plan to do so for the most part. But in this 20 situation if we were not -- if we did not set it within 21 50 feet, but we had a passing formation integrity test 22 and the rule states that we have to have at least 100 23 feet below the base, what that would mean in this 24 scenario is that when you pump cement, you pump cement 25 from the bottoms up. And so what happens with that Computer Metrix, LLC Phone: 907-243-0668 135 Christensen Dc, Ste. 2., Anch_ AK 99501 Fax 907-243-1473 Email: sahile(N,gcinet PUHIJC MEETING ACHOCC 8/27/2020 TWO APPLICATION OF HILCORP AK FOR SUNDRY APPROVAL DOCKET NO CO20-009 Page 26 1 cement is as it comes up the hole it can mix with gas 2 that comes out, it could mix with the mud and as you 3 two probably well know your cement tends to have worse 4 integrity towards the top than the bottom. So if you 5 put that in as a rule what that would mean is that if 6 you have 4,000 or 5,000 feet of very good bond at the 7 bottom of your well, but you don't have that at the g very top, that would limit you from being able to perf 9 anything in the well. 10 So what I want to caution is to maybe reword it 11 in that we have a certain amount of cement isolation 12 between the proposed intervals and the Sterling sand 13 itself. And so if we have that and the depth of that 14 that we're proposing is either 100 feet or 200 feet TVD 15 based on your discretion, then we feel that that's 16 enough isolation and that we shouldn't need further 17 spacing exemptions for sands below that. And then I 18 also believe that the formation integrity test in these 19 situations do play a significant role as well. 20 And that's all I got. 21 COMMISSIONER SEAMOUNT: So you're talking about 22 commingling Beluga sands when you..... 23 MR. McCONKEY: That is correct. 24 COMMISSIONER SEAMOUNT: Okay. Any questions, 25 Commissioner Chmielowski? Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr, Ste. 2.- And). AK 99501 Fax 907-243-1473 Email: sahile@gci.net PUBIJC MELIING AC)G('C 8,27/2020 ELMO, APPLICATION OF III LCORP AK FOR SUNDRY APPROVAL DOCKET NO. CO 20-009 Page 271 1 COMMISSIONER CHMIELOWSKI: Yes. Just to 2 confirm, Mr. McConkey, does Hilcorp and CINGSA agree 3 not to perforate 50 feet TVD below Sterling C, is that 4 what you're saying? 5 MR. McCONKEY: That is correct. 6 COMMISSIONER SEAMOUNT: Okay. I'm curious to 7 know what type of tool will be used to evaluate the 8 cement in your CDL, are you planning sonic or 9 ultrasonic, what is the criteria? 10 MR. McCONKEY: So I'm going to let -- so Taylor 11 Wellman is our operations manager, I'm going to let him 12 answer those questions. 13 TAYLOR WELLMAN 14 previously sworn, called as a witness on behalf of 15 Hilcorp Alaska, testified as follows on: 16 DIRECT EXAMINATION 17 MR. WELLMAN: Yes. So this is Taylor Wellman 18 from -- the operations manager. Just to give a brief 19 description of my history as well that Anthony and Ben 20 did. I graduated in 2004 from Colorado School of Mines 21 and then I joined BP for about 10 and a half years and 22 then I've been with Hilcorp for the last six and in 23 this current role as operations manager for the Kenai 24 area. 25 So looking to that, Jessie or Commissioner Computer Matrix, LLC Phone: 907-243-0666 135 C161teasen Dr. Ste_ 2_ Aueh_ AK 99501 Fax: 907-243-1473 Email: aahile(wgei.aet PUBLIC MEETING AOGCC 8 27,2020 ITMO: APPLK AI JON OF HILCORP AK FOR SUNDRY APPROVAL DOCKET NO. CO20-009 Page 28 1 Chmielowski, it would really -- our base plan is a 2 radio bond log that would go in there. If we did need 3 to go to a different cement blend that was of lighter, 4 it would kick us into some of the other tools, kind of 5 like the cast M or a usage bond log just to be able to 6 make sure that that isolation is there due to the 7 densities of the cement. So the base plan is the -- is 8 the radio bond log that we would typically run in these 9 ones. 10 COMMISSIONER CHMIELOWSKI: Thank you, Mr. 11 Wellman. I had a second question. If the cement bond 12 log is questionable who makes the call on whether 13 perforating can proceed, is either of you -- either 14 party planning to hire a third party to review a 15 questionable cement bond log? 16 MR. WELLMAN: How -- how we'd kind of gone 17 through it before as well is we've been able to work 18 with the AOGCC's technical staff on multiple iterations 19 of other time frames where specially in a -- as an 20 example would be conversion from a producer to an 21 injector. So we work with the technical engineering 22 staff and Chris Wallace as well to determine if there 23 is proper isolation there or not, kind of go back and 24 forth and then that determination is made kind of 25 jointly in there. And I believe that you guys kind of Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr.. Ste. 2., Anch. AK 99501 Fax 907-243-1473 Email: Wiile(, gRd net PUBLIC M ELI ING AOGCC 8/27,'2020 ITMO: APPLI('ATION OF HIL('ORP AK FOR SUNDRY APPROVAI. DOCKET NO ('020-009 Page 29 1 or the AOGCC technical staff has final say on that, has 2 been so far. 3 MS. SMITH: And, Commissioner..... 4 COMMISSIONER CHMIELOWSKI: Chmielowski. 5 MS. SMITH: .....Chmielowski, excuse me. This 6 is Moria Smith for CINGSA. The letter says that CINGSA 7 and Hilcorp must jointly agree to the assessment. 8 CINGSA is very likely to rely on third party experts 9 such as PRA and our reservoir engineer, Rick Gentges. 10 COMMISSIONER CHMIELOWSKI: Okay. Thank you. 11 Another question, will there be tie-in oversight when 12 perforating close to the storage pool and have Hilcorp 13 considered placing something like an RA tag in new 14 wells to ensure correct tie-in? 15 MR. McCONKEY: We do place RA tags in new 16 wells, yes, we absolutely do that. But as far as -- I 17 don't know if you want to..... 18 MR. SIKS: Tying in with third party..... 19 MR. WELLMAN: We did discuss that and jointly 20 CINGSA and Hilcorp when we were discussing that we 21 talked about different ways to ensure that and 22 basically what it came down to that if we weren't going 23 to come anywhere near -- we felt it was an appropriate 24 depth away from it that we would not be coming into 25 contact that they felt -- you know, we jointly felt Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr_ Ste, 2., Aneh. AK 99501 Pax: 907-243-1473 Email sahfle(mp,%t PUBLIC MEETING AOG('C 8/272020 ITMO. APPLICATION OF HILCORP AK FOR SUNDRY APPROVAL DOCKET NO. (020-009 Page 30 1 that it wasn't needed to have joint tie-ins for that. 2 That is -- that is where we got to in our discussions. 3 COMMISSIONER CHMIELOWSKI: So when perforating 4 close to the storage pool there will be some sort of 5 oversight of tie-ins is what you're saying? 6 MR. WELLMAN: As long as we -- it had been 7 trying to determine if we were going to get really 8 close as in the case with CLU 8 which we don't plan to 9 do any further. So if we -- as long as we agree to 10 stay out of that buffer zone there was no joint tie-ins 11 needed. 12 COMMISSIONER CHMIELOWSKI: Okay. Just to 13 clarify you're saying if it's greater than 50 feet TVD 14 below the base of Sterling C there's no -- no need for 15 tie-in oversight between the parties? 16 MR. WELLMAN: That is correct. 17 COMMISSIONER CHMIELOWSKI: Okay. Thank you. 18 No further questions, Commissioner Seamount, at this 19 time. 20 COMMISSIONER SEAMOUNT: Chair Price, do you 21 have any questions? 22 CHAIRMAN PRICE: No questions for me at this 23 time. Thank you. 24 COMMISSIONER SEAMOUNT: Okay. With that we'll 25 turn it over to CINGSA. Please identify yourself. Computer Matrix. LLC Phone: 907-243-0668 135 Christensen Dr_ Ste. 2.. Anch, AK 99501 F.! 907-243-1473 Email: sahileQgci.net Pl1HLIC MEETING AOGCC 8272020 ITMO: APPLICATION OF HILCORP AK FOR SUNDRY APPROVAL DOCKET NO. CO 20-009 Page 31 1 MORIA SMITH 2 previously sworn, called as a witness on behalf of 3 CINGSA, testified as follows on: 4 DIRECT EXAMINATION 5 MS. SMITH: I will. Good morning, 6 Commissioners. My name is Moria Smith and I am the 7 vice president and general counsel of CINGSA. 8 CINGSA as you know is a commercial natural gas 9 storage reservoir, the only one in the state of Alaska, 10 and it was certificated by this Commission in SIO -009 11 issued on November 19, 2010. This Commission 12 subsequently amended CINGSA's storage injection order 13 in 2014 when CINGSA inadvertently exceeded its storage 14 pressure limitation. 15 CINGSA has four firm storage customers, Enstar 16 Natural Gas Company, Chugach Electric Association, 17 Municipal Light and Power and Homer Electric 18 Association. These four firm customers have contracted 19 for all 11 BCF of CINGSA's storage capacity and for all 20 150 million cubic feet per day of CINGSA's withdrawal 21 capacity. CINGSA also offers interruptible storage 22 service to customers throughout the inlet. 23 Hilcorp approached CINGSA in the spring of 2020 24 with a request for a letter of non -objection to its 25 request to amend CO 231. CINGSA understood that the Computer Matrix, LLC Phone: 907-243-0668 135 CIIMWns ' Dr., Ste- 2.. A.& AK 99501 Pax: 907-2434473 Email: saliile(a{gmnet PUBLIC MEETING AOGCC 8/27/2020 ITMO: APPLICATION OF IBLCORP AK FOR SUNDRY APPROVAL DOCKET NO. CO 20-009 Page 32 1 Commission had precluded any completion within 1,500 2 total vertical feet of the base of CINGSA's storage 3 reservoir. This was surprising because it was not 4 consistent with the agreement that had been reached 5 between the parties, Hilcorp's predecessor in interest, 6 Marathon, and CINGSA at the time that CINGSA acquired 7 the Sterling C reservoir from Marathon. It was also a 8 surprising interpretation of the regulation that had 9 been thought to apply horizontally and not vertically. 10 CINGSA was concerned at that point that as Hilcorp has 11 pointed out that certain of their.wells were completed 12 within 1,500 total vertical -- within 1,500 total 13 vertical depth of the base of CINGSA's reservoir. 14 After CINGSA issued a conditional letter of 15 non -objection on May 6, 2020, the parties began 16 extensive conversation regarding the appropriate path 17 forward. On May 21st, 2020 the Commission issued 18 public notice of a hearing and CINGSA notified the 19 Commission on June 27th, 2020 that it requested a 20 hearing. CINGSA understands that the Commission also 21 moved independently to have a hearing in this matter. 22 Following extensive deliberations the parties 23 reached an agreement that was submitted in the joint 24 request to amend 231(a) which was filed with the AOGCC 25 on August 3rd, 2020. This letter speaks for itself, Computer Mahix, LLC Pbow: 907-243-0668 135 Christensen Dr, Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC M Ee I JNG A0G( V 8272020 ITMO. APPLICATION OF I IILCORP AK FOR SUNDRIAPPROVAL DOCKET NO. CO 20-009 Page 33 1 but it includes several provisions to ensure that two 2 goals are met. First, that Hilcorp's drilling 3 operations and CINGSA's storage operations can co -exist 4 long into the future and second, that both parties make 5 every effort to mitigate the risk of any loss of 6 mechanical and functional integrity between the storage 7 reservoir and Hilcorp's lower reservoirs, most 8 importantly the Beluga sands. 9 To be clear the risk of a loss of wellbore 10 integrity would be dire for CINGSA, for Hilcorp and for 11 CINGSA's customers who serve almost all of the gas and 12 electric needs of southcentral Alaska. I'm a lawyer so 13 it's not hard for me to imagine the extensive, 14 expensive and time consuming litigation that would 15 follow if there were to be a loss of integrity 16 especially in a worst case scenario if the parties were 17 not able to quickly agree on an allocation scheme there 18 is a risk of a cessation of production and storage 19 operations while the lawyers figure it out. This would 20 be bad for wells, it would be bad for the hundreds of 21 thousands of Alaskans who rely on gas and electric 22 service and it would be bad for Hilcorp and CINGSA's 23 operations. And it could lead to waste which of course 24 is prohibited in our constitution. It's for this 25 reason we were thankful that the Commission took this Computer Matrix, LLC Phone_ 907-243-0668 135 Christensen Dr., Ste. 2., Anch, AK 99501 Fax: 907-243-1473 Finail: sahile(2gci.net PUBLIC MEETING AOGCC 8/27/1020 ITMO: APPLICATION OF mLCORP AK FOR SUNDRY APPROVAL DOCKET NO, CO 20-009 Page 34 1 seriously and took a hard look at this question. 2 Subsequent to the parties' agreement on the 3 terms that were included in the August 3rd letter, Mr. 4 Davies of the Commission sent CINGSA and Hilcorp four 5 questions to be addressed at this hearing. I'm going 6 to discuss each in turn. I think Hilcorp has covered 7 them in some detail, but I'll put just a bit of a finer 8 point on it. 9 First of all Mr. Davies asked about the 10 description of the confining zones that isolate the 11 Sterling C gas storage pool from Hilcorp's underlying 12 and overlying strata. I would refer the Commission to 13 rule 2 of FIO-9 which is the pool description. And I 14 would also refer the Commission to exhibit A, to the 15 August 12th, 2020 letter which includes certain 16 testimony and a Power Point from October of 2010 when 17 CINGSA applied for its storage injection order. I 18 believe that you will find the answer to that question 19 fully describe therein. And CINGSA and Hilcorp fully 20 agree on that. I 21 Second recommendations for minimum vertical 22 offset distance for perforations to ensure isolation of 23 the gas pool. This is answered in the August 3rd 24 letter and I'll just call out the relevant paragraph 25 for the record. As to all future wells CINGSA will Computer Metrix, LLC Phone: 907-243-0668 135 Clnistemen Dr., Ste. 2., Anch. AK 99501 Fac: 907-243-1473 Email: saMle@gci.net PUBLK MEETING AOGCC 8/27.'2020 ITMO: APPLICATION OF 111 LCORP AK FOR SUNDRY APPROVAL DOCKET NO. CO 20-009 Page 35 1 require the intermediate casing be set and cemented a 2 minimum of 50 feet below the base of the Sterling C gas 3 storage pool. The CDL must show good cement bond 4 across this entire 50 foot interval. CINGSA and 5 Hilcorp must jointly agree to this assessment and the 6 casing must pass the AOGCC mandated MIT/leak-off test 7 of the casing shoe. For any existing wells if 8 intermediate casing is not set at least 50 feet below 9 the Sterling C pool CINGSA requires a minimum 100 feet 10 of interval of good pipe to formation bond of the 11 primary casing string below the base of the Sterling C 12 pool. 13 Richard Gentges, Rick Gentges, who is on the 14 line is a reservoir engineer with almost 40 years of 15 underground natural gas storage experience and hers 16 available to address any questions that you have on 17 CINGSA on this particular provision including on 18 Hilcorp's discussion of that final sentence that they 19 raised today. 20 The third question is evaluation of the primary 21 cement to demonstrate isolation of the gas storage 22 pool. And this is addressed in the August 3rd and the 23 August 12th letter as well. Mr. Gentges is available 24 to answer any questions. 25 And finally initial and continuing surveillance Computer Matrix, LLC Phone: 907-243-0668 135CImslemsen D, Ste, 2., AueII.AK99501 Fax: 907-243-1473 email: saluleMgei.net PUBLIC MF,GLING AOGCC 8/272020 11MO: APPLICATION OI' HILCORP AK FOR SUNDRY APPROVAI. DOCKET NO. CO 20-009 Page 36 1 methods to prove fluids are not moving between the gas 2 storage pool and adjacent strata similarly addressed in 3 the August 3rd and 12th letters and Mr. Gentges is 4 available to address that question. I would say also I 5 would be remiss if I didn't mention that Mr. Walsh is 6 here and is obviously an expert geologist available to 7 answer any questions that Mr. Gentges hands off to him. 8 CINGSA and Hilcorp are in agreement and we've 9 worked pretty hard to get to the point where we're in 10 agreement as to an appropriate and rational way to 11 preserve what is in everyone's interest which is to 12 ensure the functional and mechanical integrity of the 13 wells and ensure no loss of integrity that would lead 14 to any commingling of production gas and storage gas. 15 So with that I appreciate your time and I 16 appreciate your consideration of our joint submission. 17 Thank you. 18 COMMISSIONER SEAMOUNT: Thank you, Ms. Smith. 19 Commissioner Chmielowski, do you have any questions? 20 COMMISSIONER CHMIELOWSKI: No. Thank you. 21 COMMISSIONER SEAMOUNT: Chair Price, do you 22 have any questions of Ms. Smith? 23 CHAIRMAN PRICE: No questions. Thank you. 24 COMMISSIONER SEAMOUNT: Mr. Walsh, do you have 25 anything to add? Computer Matrix, LLC Phone: 907-243-0668 135 Chnxtens n D[. Ste. 2_ Auer AK 99501 Fax: 907-243-1473 Email: sehile(,rgernet PUBLICMEETING AOG('C 827/2020 1'PMO. APPLICATION OF BILCORP AK FOR SUNDRY APPROVAL DOCKET NO. CO20-009 Page 37 1 MR. WALSH: I'm available for questions. I do 2 want to just comment that we are in agreement with the 3 containment issues as raised by Hilcorp and I do 4 believe very strongly that the design of the -- of the 5 wells and perforations are very adequate mitigation 6 against the issues that -- the risk posed by any string 7 going through this section. Obviously as Ms. Smith 8 pointed out we can't afford a risk to the integrity of 9 the storage unit or of the surrounding reservoir and 10 for my view the mitigation measures that have been 11 taken and agreed upon by both parties are very strongly 12 going to mitigate that -- the risk of that. 13 COMMISSIONER SEAMOUNT: Okay. Ma c,n; rt, .,,,,, 14 said a few things at the beginning. Is your 15 understanding of spacing exception based on aerial, 16 geographical spacing or on volumetrics, you know, we 17 talk about 1,500 feet vertical, was that what surprised 18 you? 19 MS. SMITH: Yes, Commissioner. It was out -- 20 and I'm now speaking for Mr. Walsh and Mr. Gentges so 21 I'll speak briefly and then allow them to respond. But 22 it was our understanding that that was a horizontal 23 spacing exemption and that Mr. Gentges commented to me 24 that in his experience in many other states working in 25 the storage field he hadn't seen a vertical exemption wmpWer Malnx, LLC Phone_ 907-243-0668 135 Chnstensen Dr., SR, 2, AnO. AK 99501 Pax: 907-243-1473 Email: n whileCwb'�' .,net PUBLIC ME1 I ING AOGCC 8/27!2020 ITMO- APPLICATION OF HILCORP AS FOR SUNDRY APPROVAL DOCKET NO. CO 20-009 Page 38 1 that was applied across the board in that way. 2 But, Mr. Gentges or Mr. Walsh, you're welcome 3 to jump in if I've misstated anything. 4 MR. WALSH: This is Mr. Walsh. Commissioner 5 Seamount, I agree with Ms. Smith and I was very 6 surprised to see the issue of a 1,500 foot vertical 7 spacing requirement and it certainly is counter to the 8 agreement between CINGSA and Marathon at the onset of 9 separating out the estate. That as pointed out by the 10 final slide presented by Hilcorp would preclude really 11 any significant production from the Beluga so I was 12 quite surprised to see that. 13 MS. SMITH: If I can add one more thing. When 14 -- when Mr. Walsh was talking about separating out the 15 estate, DNR has issued a segregation order segregating 16 the Sterling C pool out from the Cannery Loop Unit. 17 And again that I think that probably that 1,500 foot 18 spacing requirement is inconsistent with that because 19 the whole point of that was to carve out that vertical 20 section, deliver it to CINGSA, but allow Marathon to 21 continue production from the lower zones. 22 COMMISSIONER SEAMOUNT: Okay. As a rule are 23 you proposing that spacing exceptions will not be 24 required, but that you want to see workovers and 25 production from zones within what, 50 feet or 200 feet, Computer Matrix, LLC Phone: 907-243-0668 135 Chnswe ,t Dr, SW, 2, Aad, AK 99501 F. 907-243-1473 Email- sali le(NLmLnet PUBLIC MEETING AOGCC 1 would that be a rule? 8272020 IT MO_ APPLJCATION OF HILCORP AK FOR SUNDRY APPROVAL DOCKET NO. CO 20 009 Page 391 2 MS. SMITH: I would refer you to that paragraph 3 from the August 3rd letter where they're sort of -- I 4 think the rule that were seeking is -- in the amendment 5 is that intermediate casing be set for any -- a minimum 6 of 50 feet below the base of the storage pool and that 7 if intermediate casing is not set then we need a 8 hundred foot buffer. 9 COMMISSIONER SEAMOUNT: But if Hilcorp..... 10 MS. SMITH: That's any future wells. 11 COMMISSIONER SEAMOUNT: .....if Hilcorp wants 12 to go let's say 500 feet below would you want -- well, 13 you'd see that, it would be a public record, but would 14 you -- would you want to see a spacing exception on 15 something like that? 16 MS. SMITH: CINGSA does not require that, no. 17 COMMISSIONER SEAMOUNT: Okay. 18 MS. SMITH: What we have asked for and you'll 19 see that on page 2 of our letter is extensive and -- 20 and continuing on to page 3, is extensive data 21 exchange. So both parties are committing to extensive 22 data exchange in order to ensure that we have 23 integrity. 24 COMMISSIONER SEAMOUNT: Okay. Thank you. Do 25 the other two Commissioners have any questions before `,a , 1u. Phone: 907-243-0668 135 Christensen Dc, Ste 2., Arch, AK 99501 F..: 907-243-1473 Email: sahile(Wgci.nel PUBLIC MEM IN6 AOGCC 1 we take recess? 8272020 11 MO APPLICATION OF HILCORP AK FOR SUNDRY APPROVAL DOCKI I NO. C0 20 009 Page 401 2 COMMISSIONER CHMIELOWSKI: No. Thank you. 3 COMMISSIONER CHMIELOWSKI: I have a question 4 for -- I'm not sure if that was Ben or -- sorry, Mr. 5 Siks or Mr. McConkey was talking since I can't see 6 their faces, but you were talking about the schedule 7 attempting to perf in third quarter for CLU 8 I think 8 it was; is that correct? 9 MR. McCONKEY: No. So for CLU 5RD we've 10 recompleted..... 11 CHAIRMAN PRICE: 5RD. 12 MR. McCONKEY: .....the well, giving us access. 13 So originally we had a packer above the perfs that we 14 wanted to perforate so we did a rig workover, that gave 15 us access to shallower Beluga sands. When we went to 16 go sundry those perforations they were denied due to 17 the 1,500 feet spacing. So we would like to still go 18 perforate those zones. CLU 5RD at the moment is making 19 -- I don't know what the rate is today, but it's -- 20 it's a fairly low rate. So the sooner we can do it 21 really the better. And that's why I say we planned on 22 -- on really Q3, but it's -- it's whenever we get the 23 approval. 24 CHAIRMAN PRICE: Okay. Thank you. 25 COMMISSIONER CHMIELOWSKI: Okay. At this point Computer Matrix, LLC Phone: 907-243-0668 135 Chnstensen Dc, Ste, 2., Anch. AN 99501 Fax: 907-243-1473 Email: sahile(mgci.nel PUBLIC MEETING AOG(V 8272020 ITMO: APPLICATION OF HI LCORP AK POR SUNDRY APPROVAL DOCKET NO M9n_nno Page 41 1 we will take a 15 minute recess. It is 10:58 so we'll 2 be back at 11:13. Am I correct? 3 COMMISSIONER CHMIELOWSKI: Just say 15, yeah. 4 COMMISSIONER SEAMOUNT: Okay. We'll be back at 5 11:15 and we're always wrong on that. So we're taking 6 a recess. 7 (Off record - 10:58 a.m.) 8 (On record - 11:17 a.m.) 9 COMMISSIONER SEAMOUNT: Who turned it off? 10 MS. SMITH: And, Mr. Seamount or excuse me, 11 Commissioner Seamount, can I request our folks on the 12 phone just can't hear you. I don't know if it's 13 possible to get a little closer or..... 14 COMMISSIONER SEAMOUNT: Yes. I'm sorry. 15 MS. SMITH: Thank you. And my apologies. 16 COMMISSIONER SEAMOUNT: We're almost done. 17 That's one of my problems, I always lean back. 18 Okay. Can you hear me now? 19 (No comments) 20 COMMISSIONER SEAMOUNT: Okay. Are there any 21 questions from Commission Chmielowski? 22 COMMISSIONER CHMIELOWSKI: Yes, I have just one 23 question. I understand that Hilcorp has an outstanding 24 sundry to perforate well CLU 13. And did I hear 25 Hilcorp testify today that there are currently no plans - Phone: 907-243-0668 135 Christensen Dr.. Ste. 2., Anch.AK 99501 Fax:907-243-1473 Email: sehile(;gci.ncl PUBLIC MLETMO AOGCC 8'272020 FFMO: APPLICATION OF III LCORP AK FOR SUNDRY APPROVAL DOCKET NO. CO 20-009 Page 42 1 to do those perforations and does Hilcorp plan to 2 withdraw that sundry? 3 MR. McCONKEY: That is correct. 4 COMMISSIONER CHMIELOWSKI: Okay. Thank you. 5 That's all I have, Commissioner Seamount. 6 COMMISSIONER SEAMOUNT: Chair Price, do you 7 have any questions? 8 CHAIRMAN PRICE: No questions for me. Thank 9 you. 10 COMMISSIONER SEAMOUNT: Are there any comments 11 from anyone else including the public? 12 (No comments) 13 COMMISSIONER SEAMOUNT: Do I hear a motion to 14 adjourn? 15 COMMISSIONER CHMIELOWSKI: I move to adjourn. 16 COMMISSIONER SEAMOUNT: Do I hear a second? 17 CHAIRMAN PRICE: Second. 18 COMMISSIONER SEAMOUNT: Okay. This hearing is 19 adjourned. I don't think we have any outstanding 20 questions. Okay. We're adjourned. 21 (Hearing adjourned - 11:19 a.m.) 22 (END OF PROCEEDINGS) 23 24 25 Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2.. Anch AK 99501 Fax: 907-243-1473 Email. saluleCwgci.net PUBLIC MEETING AOGCC 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 8/27/2020 1TMO: APPLICATION OF HILCORP AK FOR SUNDRY APPROVAL DOCKET NO. CO 20-009 Page 431 TRANSCRIBER'S CERTIFICATE I, Salena A. Hile, hereby certify that the foregoing pages numbered 02 through 43 are a true, accurate, and complete transcript of proceedings in Docket No.: CO 20-009, transcribed under my direction from a copy of an electronic sound recording to the best of our knowledge and ability. DATE SALENA A. HILE, (Transcriber) Computer Mahnx, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email sahile@gci.nel STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Docket Number: CO -20-009 August 27, 2020 at 10:00 am AFFILIATION Testify (yes or no) "1 1CC) r- 2 C- (,l�� t` C/NGS V on ICS p/,o 1 12 -one CC no �� A A /)(f) August 12, 2020 AOGCC 333 West 71' Avenue Anchorage, AK 99501 Via Email and Federal Express Re: Request to Amend Conservation Orders 231 and 231.001 Dear Commissioners: AUG } 2 2020 AOGCC In connection with Conservation Order 231.001, the Alaska Oil and Gas Commission ("AOGCC") requested that Hilcorp Alaska, LLC ("Hilcorp") and Cook Inlet Natural Gas Storage Alaska, LLC ("CINGSA") provide information on four topics. Please find the joint response of Hilcorp and CINGSA below. AOGCC asked Hilcorp and CINGSA to provide the substance of any agreements regarding the same to the AOGCC. As noted in a joint letter dated August 3, 2020 to the AOGCC from both Hilcorp and CINGSA, Hilcorp and CINGSA provided direction and detail on the resolution of issues between the parties regarding the requested spacing exemption. Both Hilcorp and CINGSA ask that the AOGCC hearing on Conservation Order 231.001 be amended as such. Pursuant to the AOGCC's authority under Rule 6 of Conservation Order 231, the parties respectfully reiterate the request for the cancellation of the hearing, which is currently scheduled for August 27, 2020. Hilcorp and CINGSA ask that Conversation Order be amended in lieu of a hearing. In the alternative, Hilcorp and CINGSA respectfully request an earlier hearing date of August 14 or 21, 2020. In order to be fulsome and responsive to AOGCC's request on Conversation Order 231.001, please find below answers to the four topics requested by AOGCC. Descriptions of the confining zones that isolate the Sterling C Gas Storage Pool from Hilcorp's underlying and overlying strata (e.g., name, description, depth, thickness, and lateral extent). Please see the attached Exhibit A. 2. Recommendations for minimum vertical offset distances for perforations to ensure isolation of the gas storage pool. Hilcorp and CINGSA agreed to no further perforations within 50 feet of the Sterling C Gas Storage Pool. Page 1 of 3 3. Evaluation of primary cement to demonstrate isolation of the gas storage pool. Cement bond logs will be provided to 100 feet TVD below the Sterling C Gas Storage Pool for all current Hilcorp wells that penetrate those sands. For CLU -8, which is open within 50 feet, data will include the cement bond log as well as the perforation depth correlation log. For any future well that penetrates the same, as commercially and time practicable prior to perforating, cement bond logs will be provided to 100 feet TVD of the Sterling C Gas Storage Pool. The cement bond log must show good pipe to formation bond over an interval of at least 50 feet TVD below the base of the Sterling C as defined by the CLU -8 type log. And as stated in the parties' August 3 letter, if intermediate casing is not set at least 50 feet below the Sterling C Pool, CINGSA requires a minimum of 100 feet interval of good pipe to formation bond of the primary casing string below the base of the Sterling C Pool. 4. Initial and continuing surveillance methods to prove fluids are not moving between the gas storage pool and adjacent strata. Hilcorp and CINGSA agreed to provide (i) bottom hole pressure surveys with wells that are open within 100 feet of TVD, (ii) open hole log data for the CLU -8 to 100 feet TVD below the Sterling C Gas Pool, (iii) monthly casing and tubing pressures on all wells that penetrate the same, (iv) for so long as CLU -8 is open within 50 feet, daily flow and pressure data and monthly updates to CINGSA's material balance analysis. Additionally, the parties agreed to notify each other of any condition that might indicate a loss of integrity. Hilcorp and CINGSA both believe that the agreed upon protocols, data sharing and agreed upon actions, as outlined in their August 3, 2020 letter will avoid waste and are consistent with sound engineering and geoscience principles. Hilcorp and CINGSA appreciate the Commission's consideration of the request to timely amend Conservation Orders 231 and 231.001 and cancel the associated hearing, or revision of the hearing schedule to conduct it on an earlier date of August 14 or 21. Page 2 of 3 Sincerely, c1 ll�'" Denali Kemp el Hilcorp Alaska, LLC "Z�"/ k . 3t ---- Moira Smith CINGSA Page 3 of 3 ALASKA OIL AND GAS CONSERVATION COMMISSION Before Commissioners: Daniel T. Seamount, Chairman John K. Norman Cathy Foerster In the Matter of COOK INLET NATURAL ) GAS STORAGE ALASKA, LLC (CINGSA), has ) applied for an order authorizing natural ) gas storage in the Cannery Loop Unit, ) SIO -10-05 Kenai Peninsula Borough in conformance ) with 20 AAC 25.252 and 20 AAC 25.412 ) In the Matter of COOK INLET NATURAL ) GAS STORAGE ALASKA, LLC, (CINGSA), has ) applied for an order exempting ) AEO-10-02 freshwater aquifers in the Cannery Loop ) Unit, Kenai Peninsula Borough in ) conformance with 20 AAC 25.440 ) ALASKA OIL and GAS CONSERVATION COMMISSION Anchorage, Alaska October 19th, 2010 9:00 o'clock a.m. VOLUME I PUBLIC HEARING BEFORE: Daniel T. Seamount, Chairman Cathy Foerster, Commissioner Exhibit A Page 1 of 124 1 2011, although if things progress we may be in a position to 2 actually start a month earlier, so..... 3 Currently we're contemplating the initial injection into 4 the reservoir beginning of April of 2012 and then finishing up 5 construction of the withdrawal facilities during the summer of 6 2012 so that the field is fully commissioned and available for 7 withdrawals in November of 2012. 8 I want to talk just a minute here about some updates to 9 the injection order application so that Staff is aware of them 10 and the Commission is aware of these. (Slide 9) We had -- as 11 I mentioned up front, we'd previously provided Staff with 12 updates on these changes and just wanted to make sure we have 13 them noted on the record today. 14 In our application we had initially indicated we would be 15 installing subsurface safety valves..... 16 CHAIRMAN SEAMOUNT: Which slide is that, Mr. Gentges? 17 MR. GENTGES: I'm sorry, slide 9. 18 CHAIRMAN SEAMOUNT: Okay, it's a common mistake that 19 people make. 20 MR. GENTGES: In our application -- initial application we 21 had indicated we would be installing subsurface safety valves 22 on two and seven/eighths tubing. We are proposing to change 23 that now to a wireline seven inch subsurface safety valve. And 24 the reason for the difference is we know there are new 25 requirements coming out for subsurface safety valves on 17 Exhibit A Page 2 of 124 1 injection wells and from a practical standpoint in order to 2 meet the depth requirement a wireline set -- safety valve is -- 3 provides a more efficient way to set and retrieve those. 4 we are also proposing to complete one of the wells 5 initially configured so that we can use the annulus for 6 disposal of drilling mud. In our original application we had 7 considered the prospect of off site disposal of drilling mud 8 and cuttings and we have since revisit that issue and the plan 9 will be to complete the first well and configure it initially 10 so that we can use the annular space for disposal of drilling 11 mud only. 12 The plan will be to come back into that well after we're 13 done using it for that purpose and grout it with cement back to 14 surface. And we'll talk a little bit more -- one of the other 15 witnesses will talk a little bit more about those specific 16 plans when he's -- when he's up testifying. 17 We had initially submitted in our application a geologic 18 cross-section and type long that identified the top of the 19 Sterling C1 formation and we have since gone back and revisited 20 that with Marathon to identify what we both agree to be a more 21 definitive, consistent marker across the top of the reservoir. 22 It is a fairly thick coal at the base of the B5 coal formation. 23 It's consistent across the reservoir. 24 The way we had defined it initially left some ambiguity 25 subject to interpretation as to exactly where the top of the "Ll Exhibit A Page 3 of 124 1 Sterling formation is and so we wanted to submit this change to 2 basically get it in the record and ensure that there is no 3 ambiguity going forward in terms of the top of the reservoir. 4 And the last item I wanted to highlight for the Commission 5 is our plans to rework the Cannery Unit 13-8 well. In the 6 original application we had proposed to re-enter this well and 7 re -plug it. We have since had the opportunity to go in and do 8 a very detailed analysis on the well looking at its -- not only 9 the original drilling records associated with the well, the 10 condition in which it was left and all of the available records 11 associated with that well, in the context of production history 12 associated with not only the Cannery Loop Sterling formation, 13 but also the Beluga. And based on that very detail and 14 thorough analysis CINGSA has concluded that there is no need to 15 re-enter that well at this point in time, that it's adequately 16 plugged. 17 Having said that, to the extent that the Commission feels 18 the well needs to be re-entered and re -plugged, CINGSA is not 19 opposed to that. We just don't believe it's necessary based on 20 all the available data, so we've actually budgeted for it. We 21 had originally planned on it, but having gone through a very 22 detailed analysis we don't see a need to re-enter the well. 23 That concludes my potion of the testimony. I'm now going 24 to turn the presentation over to Mr. Tom Walsh who will testify 25 as to the geologic characteristics of the reservoir starting on 19 Exhibit A Page 4 of 124 1 COMMISSIONER FOERSTER: So is that going to impact my 2 ability to go down to -- drive down to the Kenai next summer, 3 is there going to be, you know, the typical summer construction 4 problems? 5 MR. GENTGES: It's one of the things we understand and 6 recognize and we'll have to contend with probably most 7 importantly during the dip netting season so..... 8 COMMISSIONER FOERSTER: Well, that's his problem. 9 MR. GENTGES: Yeah. So during the course of construction 10 yes, there will be, you know, additional traffic -- 11 construction traffic associated with the project. 12 Once the project is in service minimal impact in term of 13 day to day operation. The facility will in all likelihood be 14 staffed by three or four, maybe five people at most. 15 This is very similar to storage facilities that -- in my 16 past career I was involved with construction of -- as storage 17 facilities go it's a fairly simple design and a fairly small 18 one and obviously a fairly compact overall footprint between 19 the station and the well pad itself. There's only about 15 20 acres of actual facility construction so for a period of about 21 18 months the primary impact will be construction traffic. 22 Once it's in operation the facility will be highly 23 automated. In addition to being staffed, Realtime data will be 24 gathered not only on the compressor station, operations both 25 injections and withdrawals, Realtime pressure data, but also on 21 Exhibit A Page 5 of 124 1 the wells themselves, so all of that information will be fed 2 back to the station where it can be monitored on a Realtime 3 basis, as well as telemetered (ph) to Enstar's gas control room 4 where it can be monitored and controlled as well. 5 COMMISSIONER FOERSTER: Based on your many years of 6 experience in gas storage, what do you consider to be the 7 primary risks associated with placing a gas storage facility 8 adjacent to a city? 9 MR. GENTGES: Well, the primary risks are obviously 10 ensuring public safety. The facility will be designed and 11 constructed -- surface facilities will be designed and 12 constructed in accordance with all Federal DOT natural gas 13 storage facilities of 49 CFR part 192 if you're familiar with 14 those. 15 The station will include automatic shut downs and 16 emergency isolation protocols and equipment so that in the 17 event of an emergency gas -- all the gas piping will be 18 blocked, isolated and the gas will be vented through -- in a 19 controlled basis through a vent silencer. 20 The storage wells themselves will be constructed with 21 redundant safety valve systems both on the well head and 22 subsurface so that in the event of any sort of incident, a line 23 break, any sort of gas leak at all, both the wells at the 24 surface and downhole can be isolated and shut-in. So 25 subsurface safety valves will be set at a depth of 150 feet 22 Exhibit A Page 6 of 124 1 below ground level. Those are hydraulically activated and can 2 be activated either remotely, again, at the well pad there will 3 be a control panel, as well as a remote control panel at the 4 station to isolate those in the event of an emergency, so..... 5 In terms of the operation itself, the storage facility is 6 not fundamentally different than an oil or gas production 7 facility. It's basically used to inject gas into the reservoir 8 and then produce it back out so the equipment and facilities at 9 the station and at the well pad is very similar to a 10 conventional oil and gas production facility. 11 COMMISSIONER FOERSTER: Thank you for that very complete 12 answer. You actually answered a couple of my other questions, 13 so that helps. 14 On slide number 7 you say -- you show that there is 17 Bcf 15 total potential, what percentage of original gas in place does 16 that take you to? 17 MR. GENTGES: 17 Bcf with seven Bcf of working gas would 18 take it to a total inventory of about 24 Bcf, so 24 Bcf out of 19 an original gas in place of 26 and a half which is..... 20 COMMISSIONER FOERSTER: Okay, okay. 21 MR. GENTGES: .....about 90 percent, a little better than 22 90 percent of the original gas in place. 23 COMMISSIONER FOERSTER: Okay, okay. Is your new top of the 24 Sterling C consistent with Conservation Order 510? 25 MR. GENTGES: I'm going to defer that question to Mr. 23 Exhibit A Page 7 of 124 1 Walsh. I -- I believe it may be, but I ....... 2 COMMISSIONER FOERSTER: Yeah, I'll wait till..... 3 MR. GENTGES: .....Commissioner, I haven't looked at it in 4 detail. I did look over Conservation Order 510, but I didn't 5 have copies of the logs so I wasn't able to discretely 6 pick (ph). 7 COMMISSIONER FOERSTER: okay. I'll wait and let Mr. Walsh 8 answer that questions,..... 9 MR. GENTGES: Okay. 10 COMMISSIONER FOERSTER: .....but I do have one more for 11 you. When you were talking about the well that may or may not 12 need remediation, you said we'd go in and do a detailed 13 analysis, what did you mean by go in? 14 MR. GENTGES: Well, what I meant was we -- when we 15 originally filed our application we had not had the benefit of 16 going through a very detailed analysis of the original data on 17 the 13-A well. 18 COMMISSIONER FOERSTER: So you didn't go into the well. 19 MR. GENTGES: No, we did not..... 20 COMMISSIONER FOERSTER: Okay. 21 MR. GENTGES: .....go into well. No, ma'am. 22 COMMISSIONER FOERSTER: Okay, okay. That's all I had. 23 CHAIRMAN SEAMOUNT: For the record the construction will 24 not affect my dip netting at all because I take a different 25 route to the beach. 24 Exhibit A Page 8 of 124 1 CHAIRMAN SEAMOUNT: Okay. Do you have any objections to 2 the designation of expert witness? 3 COMMISSIONER FOERSTER: None. 4 CHAIRMAN SEAMOUNT: Okay. Mr. Walsh, you're designated as 5 an expert witness in Geology and Geophysics. 6 MR. WALSH: Thank you. My first slide is slide number 11 7 and it is simply a generalized stratigraphic column of the 8 reservoirs in the Cook Inlet Basin. And what I would like to 9 point out here is the reservoir that we are concerning 10 ourselves with today is the Sterling reservoir. 11 Up at the very top of this stratigraphic column it is the 12 shallowest commercial producing gas reservoir in Cook Inlet. 13 And the Sterling reservoir actually grades upwards into the 14 Quaternary with no distinguishable unconformities above that 15 upper tertiary to Quaternary unit. 16 And if we can go to the next slide please. Oh, is that 17 me. Darn, I'm used to -- I'm used to asking people to do that. 18 Pardon me. Slide number -- I didn't plan that. 19 Slide number 12 is a diagram of a depositional system that 20 is similar to Cook Inlet. It is fluvial system. The entire 21 Sterling Unit is characterized by a fluvial system with 22 channels, point bars, crevasse splays and so forth. This is 23 typical of the gas reservoirs in the Cook Inlet basin as they 24 are primarily nonmarine systems. An amalgamation of channels 25 and crevasse splays. The Sterling itself is fairly well E-] Exhibit A Page 9 of 124 1 connected internally, whereas others of the tertiary reservoirs 2 can be more isolated in terms of independent channels and 3 isolated gas zones. 4 The block diagram on the top is very difficult to see, but 5 this is really very similar to the Sterling formation with a 6 fluvial system provenance to the northeast as it is today up in 7 the upper Susitna area which is just an extension of Cook Inlet 8 and fluvial deposition down into that basin. And again as I 9 say, this is the system that was pervasive during the Sterling 10 deposition and has continued into the recent times. 11 This next diagram, diagram number 13, as I was able to 12 change my own slide there, is a type log. It's the Cannery 13 Loop Unit number 8 well. It is the'type log for the Sterling 14 reservoir, Sterling C Unit. And what I would like to point out 15 here are the limits of the pool and as Mr. Gentges reported in 16 his testimony we have slightly adjusted the top of the Sterling 17 A interval -- sorry, Sterling C interval to reflect a more 18 correlatable event that will make it more practical to pick 19 these markers as we are drilling these gas storage wells. And 20 the new top pick is also more representative of the top of the 21 gas zone that is associated with the Sterling C. 22 This is something that we, PRA, raised in the due 23 diligence effort on this project and Marathon was quick to 24 agree that this was a much better pick in terms of definition 25 of top of the Sterling interval. 29 Exhibit A Page 10 of 124 1 The base of the Sterling interval is the Upper Beluga down 2 here at the base of this log and I don't anticipate anyone can 3 actually interpret these logs from this distance. They're 4 difficult enough when they're right in front of you, but on the 5 wall it's even more challenging, but the Sterling C is 6 characterized by massive sands, fairly blocky sands that you 7 can see represented by the net pay intervals on this curve. 8 And we have the Sterling Cla, Clb, C2a and C2b are the 9 primary reservoir intervals. You can also see the interbedded 10 coals. Typically on the logs in this field the thicker coals 11 are at the top -- at the top of parasequence set basically 12 defining the top of that Sterling C Unit and then grading into 13 claystones and silts which provide the cap rock for the gas 14 storage interval. 15 Now, the next slide, number 14, is the reference to the 16 well cross-section and this is the exhibit that I will offer as 17 additional evidence as a hard copy. Again, you can see the -- 18 this is the..... 19 CHAIRMAN SEAMOUNT: Excuse me, Mr. Walsh, do you have any 20 objection, Commissioner Foerster, to entering this into the 21 record? 22 COMMISSIONER FOERSTER: None (ph). 23 CHAIRMAN SEAMOUNT: Okay. Cross-section -- well cross - 24 section AA prime hard copy is entered in the record. Did I do 25 that right, Mr. Assistant Attorney General? 30 Exhibit A Page 11 of 124 1 MR. BALLANTINE: (Inaudible response). 2 CHAIRMAN SEAMOUNT: Okay, thank you. 3 MR. WALSH: Thank you. There is an insert map down in the 4 lower right hand portion of this cross-section and that 5 indicates the orientation of the cross-section from northeast 6 to southwest through the Cannery Loop Unit wells. 7 And what I really would like to point out here again as in 8 the type section the top of the gas storage interval is really 9 very easily interpreted as the base of the B5 coal which is now 10 the defined top of the interval with stringy coals throughout 11 and these coals are obviously source rocks for this gas 12 interval having matured and generated and migrated gas locally. 13 The cross- section is hung on the new top of the Sterling 14 C interval and there's an extension of this on the lower 15 section extending down to the Cannery Loop Unit number 10 well. 16 You can see that a couple of my logs don't extend up to 17 the top of the Sterling C and that's really because often the 18 casing shoe is set right as you get into the Sterling C and the 19 wells that are being drilled to the Beluga interval and so 20 there's another logging run above this and we didn't have those 21 in our data base, so -- but what I was trying to point out here 22 is just the continuity of that coal at the top of the Sterling 23 C and refer to this as definition of the top of the Sterling C 24 gas storage interval. 25 The next slide, slide number 15, is a generalized depth 31 Exhibit A Page 12 of 124 1 structure map of the top of the Sterling C interval. And you 2 can see that the crest of the structure here at Cannery Loop 3 Unit is approximately 4,850 feet TVD subsea. These are 25 foot 4 contra intervals. 5 And what I wanted to point out on this is that this is a 6 very -- very non-complex anticline representing the top of the 7 Sterling C and you can see that there is an east west trending 8 Cannery Loop fault. We dont have the Kenai field proper to 9 the south on here on this map, but that is a fault that 10 separates those two fields. That is a buried fault. That is 11 not currently an active fault. And it is also outside the 12 bounds of the gas storage pool, so really not a factor, but it 13 is a fault that is in the area. 14 I will point out that Marathon has proprietary 3 15 dimensional seismic data over this field in the Kenai Unit and 16 have done a detailed mapping of this pool and this is really 17 what the structure looks like. It is a simple, elongated, 18 northeast to southwest anticline which is predominately 19 unfaulted and that is characteristic of many of the structures 20 that are associated with oil and gas in the Cook Inlet basin. 21 CHAIRMAN SEAMOUNT: Is this map the result of 3D seismic? 22 MR. WALSH: This map is a result of 3D seismic, yes. So 23 very important to point out that this is an uncomplex structure 24 with one fault to the south separating the two fields. It is 25 now a buried fault. Is not -- that fault does not extend to 32 Exhibit A Page 13 of 124 1 the surface and is therefore no longer active. This is very 2 common in seismic interpretation anywhere in Alaska or other 3 locations where you see evidence of faulting at depth, but at 4 the shallowest point at which those -- the strata is no longer 5 affected by those faults, that's the age at which that fault 6 became dormant. This fault does not extend to the surface. 7 Again I'll say, that is common in Cook Inlet fields. 8 The other thing I'd like to point out is these are 9 preliminary horizontal well directional surveys and we have 10 reworked this since this map was generated. we are doing 11 detailed design engineering now for the project and these 12 transects will change, but you can see that the target of the 13 activity is the crest of the field and really gets nowhere near 14 this fault even if it were an active fault. 15 There is no fault in the crest of the structure according 16 to the 3D seismic data. None of these wells will intersect an 17 active fault or even an inactive fault in the current mapping. 18 The next figure is just a table of reservoir properties. 19 (Slide 16). And really what I wanted to point out here is that 20 this is a great gas reservoir. This would not be a terribly 21 good liquids reservoir or oil reservoir. The porosities in 22 this reservoirs range from about 12 and a half percent to about 23 20 percent. Permeabilities from about 20 millidarcies to 200 24 millidarcies and water saturations are on the order of 50 to 60 25 percent. 33 Exhibit A Page 14 of 124 I Gas moves very readily within this reservoir within the 2 reservoir itself. There is good continuity between wells 3 within this field. However there is -- as Mr. Winslow will 4 point out in future testimony, there is very good containment 5 between reservoirs intervals in this field. So, again, it's a 6 very good gas field. It's an excellent choice in terms of the 7 overall size, the working volumes available for this project 8 and for the fact that it is -- the gas is dry gas. There is no 9 aquifer drive and it's a very high quality reservoir for gas 10 production and gas storage. 11 The next slide, slide number 17 addresses briefly the 12 issue of containment and well -- as I say, we'll be talking 13 about that further in testimony as we go forward. As we saw 14 from the structure map this is a four way dip closure. Again, 15 very characteristic, an anticlinal fold in the tertiary to 16 Quaternary that sets up the structural closure for this. 17 Top seal is provided by siltstones and shales at the base 18 of the Sterling B and top of the Sterling C. And as I said, 19 the Sterling C represents a parasequence set of fluvial 20 sediments that grades into coals and then into the lower 21 portion of the Sterling B interval which is characterized by 22 claystones, some siltstones and shale providing a every 23 effective top seal for this reservoir. And this reservoir has 24 obviously by the fact that there has been a thick (ph) gas 25 column there is capable of containing large volumes of gas at 34 Exhibit A Page 16 of 124 1 least up to 26 and a half Bcf of gas. 2 Bottom seal -- sorry, the B5 coal is present across the 3 Cannery Loop structure and is about 10 to 20 feet thick. That 4 is going to be a very significant marker in terms of 5 correlation and choosing our casing point and our kick -out for 6 the production hole. 7 Bottom seal is the base of the Sterling formation and top 8 of the Upper Beluga formation. The Upper Beluga has produced 9 in the Cannery Loop Unit and Mr. Winslow will address that 10 issue. The upper part of the Upper Beluga is a silty-shaley 11 interval. Again, providing competent sealing between the 12 Beluga and Sterling pools. And you'll see that there is 13 significance evidence to show that there is a competent seal 14 between those two reservoirs. 15 Historic production and pressure data show these reservoir 16 seals to be very effective and the geology and the reservoir 17 engineering are integrated to show how effective these seals 18 are. 19 Finally the -- another slide on the Sterling C containment 20 and this is slide 18. There were a set of leak -off test 21 performed. As 2 mentioned the nine and five/eighths casing 22 shoe is typically set in the base of the Sterling B or in the 23 upper most part of the Sterling C in wells that are being 24 drilled to the Beluga interval. And leak -off tests are 25 performed, a standard practice on those casing runs so we do 35 Exhibit A Page 78 of 124 1 have good evidence to show that the average fracture gradient 2 deduced from those formation integrity tests is about .684 3 gradient. 4 And the hydrostatic gradient which is also the initial 5 gradient for these gas reservoir is, of course, .44 (ph). So 6 the hydrostatic or initial pressure gradient which we do not 7 intend to exceed in operations here is about 73 percent of the 8 fracture gradient as determined from those formation integrity 9 tests. So very -- very solid information there showing a 10 containment at the top of the reservoir. 11 Slide number 19, Sterling C containment again. The 12 Sterling A and B appear to be water bearing in available 13 shallow well logs, CLU -1, 3 and 4 and there are limited wells 14 logs. Not all of the wells have logs in the intermediate 15 section. These wells have logs that go through that 16 intermediate section, (indiscernible) logs and density or sonic 17 logs that allow us to look at the reservoir characteristic of 18 the Sterling A and B. 19 And our petrophysicists, who is not here today, has done 20 detailed analysis of those well logs in the shallow section and 21 it is clear that the shallower Sterling units are water bearing 22 rather than gas bearing. That is also bourn out by the mud 23 logs that we can interpret in the shallow section. The base of 24 the Sterling B or that B5 coal, the thick coal at the base of 25 the Sterling B does seems to have generated some gas so there's Z Exhibit A Page 17 of 124 I some local gas at the base of the Sterling B, but really 2 nothing in a reservoir section above that. 3 And that concludes my testimony on the geoscience aspects 4 of the project and I'd be happy to answer any questions. 5 CHAIRMAN SEAMOUNT: Commissioner Foerster, questions? 6 COMMISSIONER FOERSTER: The only question I have is the 7 one that I asked before, is this new depth consistent with 8 Conservation Order 510? 9 MR. WALSH: It is. I will say it's not inconsistent with 10 it. It -- the problem is that the Sterling is -- initially is 11 undefined C -- or undefined Sterling formation and it is broken 12 down in the Kenai gas field as Sterling 5.1, 5.2 through 6. 13 Different nomenclature here where we're using Sterling A, B and 14 C. So we did go back and research this and we are satisfied 15 and I believe Staff that we've discussed this with are 16 satisfied that this is consistent. We are using the top of the 17 Beluga as the base of the Sterling C and the B5 coal as the top 18 of the Sterling C. 19 COMMISSIONER FOERSTER: Okay, okay, thanks. 20 CHAIRMAN SEAMOUNT: It seems that when you go to 21 structures to the west in Cook Inlet they're bounded by thrust 22 faults that look like they're -- or reverse faults that look 23 almost like they're blind thrust faults. And looking at 24 thickness variations of the unit across it looks like these 25 faults are still active and that seems to be a common structure 37 Exhibit A Page 18 of 124 1 Dallas with Garve (ph) and Associates for three years doing 2 reservoir simulation, all sorts of reservoir studies, decline 3 curve analysis, reserve auditing. 4 Spent the last nine years here in Alaska, six and a half 5 years with Forest Oil as their senior reservoir engineer in 6 charge of all the oil and gas fields with Forest Oil. The two 7 and a half years I've spent with Chevron and was in charge of 8 their gas fields on the east side Swanson River, Happy valley 9 and Ninilchik. And in addition was in charge of their three 10 gas storage reservoirs, two at Swanson and one at Pretty Creek. 11 CHAIRMAN SEAMOUNT: Do you have any questions, 12 Commissioner? 13 COMMISSIONER FOERSTER: I have none. 14 CHAIRMAN SEAMOUNT: I have none either. Do you have 15 objections to designating Mr. Winslow as an expert in reservoir 16 engineering? 17 COMMISSIONER FOERSTER: I have none. 18 CHAIRMAN SEAMOUNT: Okay. You are hereby designated an 19 expert in reservoir engineering. Please proceed. 20 MR. WINSLOW: Thank you, Commissioner. Okay. I'm going 21 to start on slide 20 and briefly go over reservoir integrity. 22 I'm going to look at some production and pressure history for 23 the Sterling C reservoir, briefly go over the gas storage 24 parameters which Mr. Gentges has already gone through. And 25 then spend a little bit of time looking over the Sterling and 40 Exhibit A Page 19 of 124 1 Beluga pressure isolation. 2 Slide 21, Sterling C production and pressure. The initial 3 reservoir pressure of the Sterling C was 2,206 psia. This is a 4 datum of 4,966 feet TVD. A couple things to note, this gas 5 storage project will not exceed this pressure, so we have no 6 plans -- CINGSA has no plans to exceed this pressure. The 7 facilities are not designed to exceed this pressure so it is 8 firm target. 9 Initial reservoir pressure gradient .44 (ph) psi per foot. 10 There have been three leak-off tests done at the top of the 11 Sterling C. Fracture gradients, average fracture gradient .684 12 psi per foot. 13 Just some other production history notes, original gas in 14 place for the Sterling C reservoir 26.5 Bcf. First production 15 occurred in October, 2009. Production from the Sterling C has 16 only occurred from the Cannery Loop Unit number 6 well. 17 Currently there have only been two wells at Cannery Loop that 18 have even been perforated in the Sterling C. All the 19 production came from the number 6 well. And also the Cannery 20 Loop number 10 well in 2009 was perforated and a pressure was 21 obtained. 22 Maximum production rate from the Cannery Loop number 6 23 well is just under 15 million cubic feet per day. Note the 24 number 6 wells is a near vertical well through the Sterling C 25 interval. 41 Exhibit A Page 20 of 124 1 Just to give you some perspective, I mean, we've talked 2 about the maximum planned rate of 150 million from five 3 horizontal wells, the reservoir is very good rock, produced 15 4 million, again, from a vertical well. Cum production to date 5 or through September is about 22.5 Bcf which leaves a remaining 6 gas in place of four Bcf. 7 Slide 22, gas storage parameters and, again, some of these 8 have been discussed previously. The initial phase on the gas 9 storage volume is planned for 18 Bcf which is seven Bcf of base 10 volume and 11 Bcf of working gas volume. Future expansion 11 could take the working volume up to 17 Bcf which would make the 12 total volume at that point 24 Bcf. 13 The initial number of development wells is five wells and 14 these -- again, these will be horizontal wells drilled from a 15 single pad or near horizontal. 16 Gas storage reservoir pressures and the initial phase, 17 again, the storage volume will fluctuate between seven Bcf and 18 18 Bcf. These equate to reservoir pressures of roughly 630 psi 19 up to 1,520 psi. Again, the initial reservoir pressure was 20 2,200 and six (ph) psi. If in future development CINGSA takes 21 the storage up to 24 Bcf, the average reservoir pressure will 22 be about just right around 2,000 psia. 23 Surface operating pressures are designed between 400 and 24 1,450 psig. These -- a simulation model was built over this 25 facility and was used in planning the initial wells, 42 Exhibit A Page 21 of 124 1 development wells. From the simulation model these operating 2 pressures it was found that the field could be operated at 3 surface pressures ranging from 400 to 1,450 psig. In actuality 4 due to reservoir heterogeneities it will probably be a little 5 bit higher than that. In the application we requested a 6 maximum injection pressure of 2,200 psig. 7 Note that at this maximum pressure of 2,200 psig this e corresponds to a bottom hole pressure gradient of .5 psi per 9 foot which is 73 percent of the fracture gradient which was 10 stated on the last slide at .684 psi per foot. And then once 11 again the initial phase is currently designed for a maximum 12 production and injection rate of 150 million cubic feet per 13 day. 14 Slide 23 I'm going to talk about four different good 15 indications that there has been pressure isolation of the 16 Sterling C reservoir. The most compelling evidence is the 17 material balance P/Z versus cum gas plot which I'll go over 18 shortly. Then I'll also look at production history, reservoir 19 pressures, initial pressures and current or 2009 reservoir 20 pressures which, again, indicate pressure isolation between the 21 reservoirs. 22 Slide 24, is a plot of bottom hole pressure divided by 23 natural gas compressibility factors so that's P/Z on the 24 vertical axis plotted against the cumulative produced gas on 25 the horizontal access. Looking at the data from, again, 43 Exhibit A Page 22 of 124 1 initial production was in October, 2000 and the latest data 2 point was taken in October of 2009. A very good, straight line 3 fit between all data points indicating a depletion drive 4 reservoir and also showing no evidence at all of either aquifer 5 support or outside influence whether it be leaking off or gas 6 migrating in from another source. If you had either of these 7 cases you would deviate from a straight line on the P/Z plot. 8 Also note this is attachment 8 in the storage injection 9 order application, so this data was previously provided. 10 Slide 25 is a plot of production monthly, production data. 11 It's actually its average daily gas data plotted on a monthly 12 basis for both the Beluga and Sterling reservoirs in the 13 Cannery Loop Unit. The blue curve is the Beluga production and 14 the red curve is Sterling C production, again, from the Cannery 15 Loop Unit number 6 wellbore. 16 A couple of things to note, when the Sterling C reservoir 17 was first perforated in October, 2009 and brought on the blue 18 curve, which is the production from the Beluga, you don't see a 19 change in the slope from the decline on the Beluga projection. 20 So first indications would be that the Sterling did not 21 influence the Beluga production when it was first brought on. 22 Even more compelling in 2004 the Beluga curve goes from 23 production -- average daily production between two and three 24 million cubic feet a day up to as high as 28 million cubic feet 25 a day. This was when they brought on -- when Marathon 44 Exhibit A Page 23 of 124 1 perforated the Upper Beluga in the Cannery Loop 7, 8 and 9 2 wells. 3 So they started producing the Upper Beluga, increased the 4 production from the Beluga tenfold and we don't see any change 5 in the slope on the Sterling production. And if there were 6 communication between the two reservoirs that big of an 7 increase in Beluga production I would expect to see an 8 influence on the Sterling production. I don't see any here. 9 It's not concrete, but it's good evidence that they are 10 isolated in communication. 11 Also, looking back a slide at that same date, 2004, so 12 back on slide 24 the plot -- the point right there in the 13 middle, June 8, 2004, again, falls right on the straight line 14 another good indication that there's pres- -- or isolation 15 between the reservoirs. 16 Slide 26 looks at the initial reservoir pressures for the 17 two reservoirs. I previously stated that the initial Sterling 18 reservoir pressure was 2,206 psia at a datum of 4,966. This is 19 a gradient .444 psi per foot. 20 The first bullet point the Beluga initial pressure was 21 2,310 psia at a datum of 5,175 TVD. Same initial reservoir 22 pressure gradient .446. That third place isn't significant. 23 A couple things to note, when the Sterling was first 24 produced in October of 2000 a total of 30 Bcf of gas had been 25 pulled from the Beluga reservoir in the Cannery Loop Unit. If 45 Exhibk A Page 24 of 124 1 there was communication between the two reservoirs I would have 2 expected to see a much lower initial reservoir pressure 3 gradient in the Sterling and yet we still saw the same initial 4 gradient which is very common throughout this area of Cook 5 Inlet. 6 The other thing to note, the Kenai Unit 13-8 wellbore, KU 7 13-8 wellbore, was drilled and abandoned in its current state 8 in 1964. So it's been present throughout the entire history of 9 both the Beluga and the Sterling production in its current 10 state. 11 Slide 27 looks at some 2009 pressures in both the Sterling 12 and Beluga reservoirs. Sterling C reservoir first of all in 13 October, on October 22nd, a bottom hole pressure was obtained 14 from the Cannery Loop Unit number 6 well. The well was 15 actually shut-in for an extended period and a reservoir 16 pressure of 424 psi was obtained. 17 During that same time period the Cannery Loop number 10 18 well was perforated. Cannery Loop Unit 10 was originally a 19 Beluga producers and produced for a short time in the Upper 20 Beluga and then was plugged off and the Sterling C shot in 21 October of 2009 very similar pressure, 465 psi, 41 pounds 22 different. 23 The note that the Cannery Loop number 10 well is on the 24 far south end of the field. The number 6 well is more on the 25 northern, northeastern crest part of the field. So very good 46 Exhibit A Page 25 of 124 1 communication, horizontal communication within the Sterling C 2 reservoir which is excellent for the storage project. 3 As reported to the State, to the AOGCC, the reservoir 4 properties at the end of 2009 for the Upper Beluga or for the 5 Beluga Pool were reported to be 1,371 psia, significantly 6 higher than the Sterling C pressure, so the Beluga is still at 7 a higher pressure than the Sterling C. 8 If, again, an indication if the reservoirs were in 9 communication they would have a tendency to equilibrate. I 10 have not seen any indication that this has happened. I think 11 that's all I wanted to say about that. 12 That concludes the talk on reservoir isolation. I'd be 13 happy to answer any questions that either of you may have. 14 CHAIRMAN SEAMOUNT: Commissioner Foerster, do you have any 15 questions? 16 COMMISSIONER FOERSTER: I have a couple I think you might 17 -- you may have not mentioned this or maybe I heard it wrong, 18 but on slide 21 and again on slide 25, the slide says the year 19 2000 and the words I heard coming out of your mouth for the 20 year 2009 for first production? 21 MR. WINSLOW: I'm sorry, first production is October, 22 2000. 23 COMMISSIONER FOERSTER: Okay, all right. 24 MR. WINSLOW: I may have misspoken. 25 COMMISSIONER FOERSTER: Or I may have misheard. Is two 47 Exhibit A Page 26 of 124 1 and seven/eighths inch tubing going to be adequate for 30 2 million cubic feet per day per well in 150 million? 3 MR. WINSLOW: This wells as will be discussed in the next 4 section will be completed with seven inch tubing, so..... 5 COMMISSIONER FOERSTER: Okay. So there's not going to be 6 -- on the earlier slide it says..... 7 MR. WINSLOW: And they're designed -- I mean, they're 8 designed to average 30 million. They actually can flow at 9 rates -- I mean, simulated rates were up to 50 million a day, 10 so..... 11 COMMISSIONER FOERSTER: So one last question, when did the 12 Beluga start producing from Cannery Loop? 13 MR. WINSLOW: 1988. 14 COMMISSIONER FOERSTER: 1988. And when did -- is that the 15 first production from the Cannery Loop? 16 MR. WINSLOW: I'm not sure, there may have been Tyonek 17 production before that. There's four pools in.Cannery Loop, 18 the Tyonek, the Tyonek D, the Beluga and then the undefined 19 Sterling Pool so I'm not sure, but I know the Beluga started in 20 1988. 21 COMMISSIONER FOERSTER: That's all I had. 22 CHAIRMAN SEAMOUNT: Am I correct to assume that the Upper 23 Beluga contains a number of thinner sands? It's not just one 24 sand, correct, or is it? 25 MR. WINSLOW: No, I think that's correct. Tom, if you 48 Exhibit A Page 27 of 124 1 have que- -- answer. 2 MR. WALSH: Can I answer that question? 3 CHAIRMAN SEAMOUNT: Yes, you may, Mr. Walsh. 4 MR. WALSH: The Upper Beluga is typically a couple of 15 5 foot sand stringers. 6 CHAIRMAN SEAMOUNT: Okay. And have they ever been tested 7 or produced separately or are they always perforated together? 8 MR. WINSLOW: There has been commingled production between 9 the lower part of the Beluga and the upper. When the seven -- 10 when the Cannery Loop 7, 8 and 9 wells were drilled they were 11 initially completed just in the Upper Beluga. 12 CHAIRMAN SEAMOUNT: Do you know if these sands form 13 separate reservoirs or are they are in communication? 14 MR. WINSLOW: I don't have detailed pressure data, that's 15 proprietary to Marathon. What's been reported to the State in 16 the Annual Reservoir Properties Report that's required by the 17 operators to fill out, shows that the average Beluga -- the 18 reported average Beluga pressure in 2004 was listed at 996 psi. 19 In 2005 the average reservoir pressure was listed at 1,960 psi. 20 So we increased just under 1,000 psi which tells me -- and if 21 you look at the production it would indicate it as well. 22 2004 was the first time Marathon perforated and produced 23 the Upper Beluga. That data would suggest to me that the Lower 24 Beluga and Upper Beluga are not in communication, but they are 25 separate because they see a big jump not only in production, 49 Exhibit A Page 28 of 124 I but the pressure went up by the end of the year, was still up 2 1,000 psi. 3 CHAIRMAN SEAMOUNT: Do you know if the Beluga if it 4 contains gas in the 13-8 well or contained gas at one time? 5 MR. WALSH: We have looked at that, Commissioner..... 6 COMMISSIONER FOERSTER: Name yourself. 7 MR. WALSH: Oh, sorry, this is Tom Walsh for the record. 8 We have looked at that. The logs in 13-8 are not a full suite 9 of logs as they are in many of the other production wells, so 10 it's not definitive, but the Beluga is quite ratty looking in 11 the 13-8 location and it's not clear that it's gas bearing. 12 CHAIRMAN SEAMOUNT: How bout the Sterling, is there any 13 gas in any part of the Sterling in the 13-8? 14 MR. WALSH: In the 13.8. Again, it's difficult to make a 15 credible comment on that. The Sterling sands are poor quality 16 in 13-8 location as well. And it's somewhat equivocal as to 17 whether there's actually any gas in 13-8. 18 CHAIRMAN SEAMOUNT: Is there a correlation between 19 structure and reservoir quality then or there's not enough 20 information to tell? 21 MR. WALSH: Well, it's -- there is -- I believe there is 22 gas in other well locations at greater depths than in the 13-8 23 location if that's what you're asking. 24 CHAIRMAN SEAMOUNT: That's close enough. 25 MR. WALSH: Okay. 50 Exhibit A Page 29 of 124 1 directional wells we might need the ability to shut the well 2 off deeper than that, but at present we've set the minimum 3 depth at 150 feet. And it will be a seven inch wireline 4 retrievable to give us full bore capability. 5 The casing design, again, is very typical in the Cannery 6 Loop field. The nine and five/eights 40 pound, seven inch 26 7 pound. we've done a bi-axel (ph) look at the casing design and 8 it appears to fit. We may change it, although the numbers are 9 very conservative as they stand depending on the directional 10 design. 11 COMMISSIONER FOERSTER: Are we on..... 12 MR. PERRY: On slide number 30, just wave at me, 13 Commissioner Foerster. 14 But -- and we will be using a lot of directional work in 15 the 12 and a quarter inch hole and using a three degree per 100 16 dog leg so until we have that basic directional design we won't 17 finish the full casing design. Of course this will all be 18 supplied in our permit to drill application. 19 The next slide which is slide 31, I think one of the 20 biggest safety features we have is that there's been several 21 recent wells drilled by Marathon in the field and I'm talking 22 about from 2004, that allows me to do a bunch of cross 23 referencing in what they've done and they've been very 24 successful in that drilling so I think being consistent with 25 the proven Cannery Loop drilling is one of our biggest assets. 56 Exhibit A Page 30 of 124 1 We have 13 offset wells. The drilling fluids that have 2 been used are going to be similar. We're expecting to use a PA 3 type flow pro (ph) system through system in both the 12 and a 4 quarter and in the production zones to prevent formation 5 damage. 6 Our expectation is the field is normally pressured until 7 we get to the Sterling C. Of course we'll be prepared in case 8 it isn't. we'll be drilling with full mud weight all the way 9 down. We did not be drilling with any exotic foam system or 10 underbalanced drilling system. We'll be just using an old mud 11 weight (ph) system for that. We expect no gas to the Sterling 12 B5 coal. 13 Casing design we talked about already, again, very 14 similar. The only difference is the most recent wells drilled 15 the Cannery Loop field they've been going with a slim hole. 16 Because of the high flow rates needed in our wells we're going 17 with the seven inch completion. The well head I've already 18 stated is similar. 19 One of the other aspects in a field like this that is 20 really critical to us is we have two operators drilling in a 21 similar field. We have Marathon on one side and us drilling 22 through the other so it's really critical that we get our plans 23 together and that we know where their wells are and they know 24 where our wells are. 25 So we're going to work very closely with them on that and 57 Exhibit A Page 31 of 124 1 we've already started some discussions. And we also plan on 2 using the same close approach criteria that they're currently 3 using so that our interference calculations will be on the same 4 basis. 5 We've anticipated, as I've said, the future AOGCC 6 regulations with installing a subsurface safety valve. And a 7 note, again, we are submitting all casing strings back to 8 surface which would not normally be required in an oil/gas 9 normal producing situation. 10 Moving on to slide number 32. More operationally, discuss 11 just a bit on how we're going to monitor these wells. There 12 will be a Realtime SCADA system so we'll have telemetry back 13 from the wells themselves back to the control room. We'll be 14 measuring daily pressure and rate. There's a flow meter on 15 each of the well flow lines. And, of course, monthly 16 production injection volumes as required by the State. 17 Of uniqueness in a gas storage production reservoir like 18 we're doing here, we have the ability at the end of the cycles, 19 after the end of the injection cycle and at the end of the 20 producing cycle to have a good shut-in pressures. This will 21 help us verify pressures and volumes and the integrity of our 22 reservoir and how we're doing with the gas. 23 Slide number 33, KU abandonment schematic. What I'd like 24 to discuss on the schematic is the abandonment as it was done 25 in 1964. It was drilled in December of that year. They AA Exhibit A Page 32 of 124 1 abandoned it as shown in this schematic and it's been sitting 2 dormant for over 46 years. 3 It has a cement plug very similar to what would be 4 required under current regulations. The eight and five/eighths 5 was cemented, not all the way back to surface. They calculated 6 at 190 foot measured depth top of cement. However, there's a 7 note in the well files that indicate it's at 350 feet. I don't 8 know where they came with that conclusion. There's no data to 9 back that up. 10 They did do a top job as shown in this so they have 11 cemented the 13 and three/eighths by the eight and five/eighths 12 annulus from the top. They then installed a surface plug in 13 the -- at the very top very of the well head and it was capped 14 with very little description on how that cap was done. 15 The -- one other thing I'd like to note is that they left 16 10.3 pound per gallon lignosul- -- chrome lignosulphonate mud 17 in the well. And this is a general water based mud that was 18 used at the time. It was a freshwater system. obviously as 19 cheap as they could get and extremely damaging with the 20 freshwater. They wanted to get as much gel (ph) use out as -- 21 as they could and very typical of that time. 22 All right. Moving on to slide number 34, we did an 23 analysis of KU 13-8. I won't go into the detail that Paul 24 Winslow did, but again, it was abandoned 46 years ago. There's 25 been no cross flow in the past 46 years. no; Exhibit A Page 33 of 124 1 There's no measurable depletion - virgin pressure in the 2 Sterling C and that's after significant Beluga production. No 3 visible change in the P/Z due to Beluga production. No visible 4 change in the Beluga production due to the Sterling C 5 production. And it is sufficiently isolated from the shoe to 6 surface. 7 Quickly moving on to slide number 35, Mechanical 8 Integrity. For the want of being repetitive we have not seen 9 any cross flow as stated previously from the Sterling C 10 reservoir. We did an evaluation on the mechanical integrity of 11 the wells penetrating the Sterling C formation in the Cannery 12 Loop field. In that analysis we found that there was cement 13 coverage across all but the 13-8 (ph) and a small gap in the 14 Cannery Loop wells Cannery Loop Unit 12 wells. 15 We determined that remedial work is needed on Cannery Loop 16 dash 6, Cannery Loop 10 and Cannery Loop 12 and discussion is 17 underway with Marathon on a program for those which I'll go 18 into detail in just a second on what's required. 19 The next slide, Cannery Loop Wells, number 36, lists the 20 wells in the field. For some reason we have Cannery Loop 21 number 2 which is listed in the field, but is actually not in 22 the Cannery Loop Unit. It was drilled several miles away. 23 Maybe they expected the reservoir to be much, much larger than 24 it was. 25 The next slide, (Slide 37), the remediation we're 60 Exhibit A Page 34 of 124 ALASKA OIL AND GAS CONSERVATION COMMISSION Before Commissioners: Daniel T. Seamount, John K. Norman Cathy Foerster In the Matter of COOK INLET NATURAL GAS STORAGE ALASKA, LLC (CINGSA), has applied for an order authorizing natural gas storage in the Cannery Loop Unit, Kenai Peninsula Borough in conformance with 20 AAC 25.252 and 20 AAC 25.412 In the Matter of COOK INLET NATURAL ) GAS STORAGE ALASKA, LLC, (CINGSA), has ) applied for an order exempting ) freshwater aquifers in the Cannery Loop ) Unit, Kenai Peninsula Borough in ) conformance with 20 AAC 25.440 ) SIO -10-05 AEO-10-02 ALASKA OIL and GAS CONSERVATION COMMISSION Anchorage, Alaska October 20th, 2010 9:30 o'clock a.m. VOLUME II PUBLIC HEARING BEFORE: Daniel T. Seamount, Chairman Cathy Foerster, Commissioner U-10-051 RECEIVED By the Regulatory Commission of Alaska on Nov 05, 2010 Chairman Exhibit A Page 35 of 124 1 CHAIRMAN SEAMOUNT: Are they the questions that you 2 submitted yesterday? 3 MR. GODDARD: Yes, um -hum. 4 CHAIRMAN SEAMOUNT: okay. Yeah, you can do that, but 5 they're already in the record so, I mean,..... 6 MR. GODDARD: Oh, okay. 7 CHAIRMAN SEAMOUNT: .....it's not entirely necessary go 8 through them, but you're more then welcome to. 9 MR. GODDARD: Well, I'll take advantage of the -- I'll try 10 and make it quick. 11 CHAIRMAN SEAMOUNT: Okay. 12 MR. GODDARD: Yeah. 13 COMMISSIONER FOERSTER: Did you enter them into the record 14 yet? 15 CHAIRMAN SEAMOUNT: I thought I did. 16 COMMISSIONER FOERSTER: All right. 17 CHAIRMAN SEAMOUNT: We'll make sure all these documents 18 are in the record at the end of this show. 19 MR. GODDARD: Okay. First question and this is -- these 20 aren't numbered slides, but they are numbered questions and 21 they correspond with the pages plus one 'cause the first 22 page..... 23 COMMISSIONER FOERSTER: (Simultaneous speech)..... 24 MR. GODDARD: .....was the title. 25 COMMISSIONER FOERSTER: That will work. 196 Exhibit A Page 36 of 124 1 MR. GODDARD: Upon what factual basis did CINGSA state to 2 DNR in Richard Gentges September 10th letter that there were no 3 earthquake faults within 40 miles of the Cannery Loop site? 4 How do they account for the fact that Middle Shoals and Granite 5 Point faults, confirmed active faults, are within 15 miles of 6 the Cannery Loop site? That's a combined 15 miles. Granite 7 Point is a little bit further. 8 Number two, upon what factual basis did CINGSA assert to 9 DNR in the same September 10th letter, that the depleted ga 10 reservoir in the Cannery Loop unit is not located across any 11 known fault line? Mr. Gentges' letter referenced the 2000 12 study by Dr. Haeussler which clearly indicates an approximately 13 20 mile fault line -- or it's actually what we're now calling a 14 fault cord anticline that cuts right through the Cannery Loop 15 reservoir. How does explain this misleading information that 16 was provided to DNR? 17 And then as a corollary to this, yesterday we did see a 18 further disclosure which showed an east/west running fault line 19 which is probably more of a formal fault as opposed to a fault 20 cored and that's -- actually I looked at the drawing. It's 21 less than a mile from the southern boundary of the gas zone as 22 they've defined it on their surface projection, so we'd like to 23 know how they explained this misleading information that was 24 provided to DNR. 25 Three, once CINGSA accepts the apparent fact that a local 197 Exhibit A Page 37 of 124 I fault line cuts through the Cannery Loops Sterling C reservoir, 2 how will CINGSA modify the project engineering and design 3 criteria? One response that I would like to see would be to 4 reduce the injection pressure. If the injection pressure is 5 above hydrostatic -- they're saying they want to do injection 6 pressure that's equals to .5 psi and we believe that will 7 contribute to gas migration through whatever faulting structure 8 exists inside the reservoir. 9 Four, CINGSA shows a very smooth, dome structure in the 10 surface projection maps. How has CINGSA developed this 11 information for the reservoir zone that is beyond the confines 12 of the configuration of wellbores that penetrate the reservoir 13 structure? 14 Now, this question was written and put into this before we 15 have the benefit of their presentation yesterday which said 16 that it is actually a very smooth, dome structure and that 17 they've gotten this information from Marathon, but it hasn't 18 been reviewed directly by the geologist that reported that he 19 had this information from Marathon and it hasn't been provided 20 to anybody else to review. So based on this I'd like a little 21 better explanation if we can of how they determined this 22 configuration since it's not indicated by the well log data 23 that they've also provided. 24 Number five, the smooth aspect to the dome structure 25 depicted in the surface projection map seems to be inconsistent 198 Exhibit A Page 38 of 124 I with both the north/south and east/west cross sections. How 2 does CINGSA explain this apparent inconsistency in their data? 3 And I might also say that to corollary it also is inconsistent 4 with the drawing that they provided showing the five wells and 5 the pay zones that those wells would intersect that shows a 6 wavy structure rather than a smooth, domed shaped anticline. 7 Six, how does CINGSA explain the apparent coincidence that 8 the discovery pressure gradient, .044 psi per foot, is the same 9 as hydrostatic pressure gradient essentially, 0.44 without 10 considering the likely corollary that the reservoir fault 11 structure leaked gas into higher structures under the gas 12 pressure reached stasis or equalized with hydrostatic pressure? 13 And, of course, what this would indicate then is that when 14 they use an injection pressure of 0.5 psi they could force gas 15 migration up whatever fault structure exists inside the 16 reservoir. 17 Seven, can CINGSA provide more information regarding the 18 cap that holds the reservoir gas in place? There is virtually. 19 no information provided in the project proposal documents or 20 the SIO Application. 21 And, once again, this was written before we had the 22 benefit of this wall chart here which is the first time we've 23 actually been able to see the thickness and variability in the 24 coal cap. And it does suggest to those that understand these 25 sorts of well cross sections, that the thickening and thinning im, Exhibit A Page 39 of 124 1 in the cap structure would suggest faulting or cracking such 2 that gas could escape if pressures exceed hydrostatic 3 pressures. 4 There's virtually no information other than this wall 5 chart in the project proposal documents or the SIO application. 6 Eight, how has CINGSA determined the horizontal dimensions 7 or lateral containment dimensions as depicted'in the storage 8 zone maps and diagrams? There is no well data outside the 9 confines of the configuration of wellbores that penetrate the 10 reservoir. 11 Once again, the answer to this may be the information that 12 they've received from Marathon and as a corollary to this 13 question if that is the source it would be appreciated if they 14 could make as much of that public and explain it better in a 15 written format. 16 Nine, without knowing the actual horizontal dimensions of 17 the reservoir, how can CINGSA guaranty that gas will not 18 migrated horizontally out of the reservoir zone? 19 Ten, without providing the geological structure of the 20 cap, including the localized pattern of faults that cut through 21 the reservoir, how can CINGSA guaranty that gas will not 22 migrate to areas above the reservoir structure, using the 23 available fault lines as migration conduits? 24 Eleven, what is the geological structure above the 25 reservoir cap? CINGSA has not provided any information about 200 Exhibit A Page 40 of 124 I the various structures above the reservoir. All of the well 2 logs that I've seen, seem to cut off at the Sterling C and 3 there's been no presentations about structures above the 4 Sterling C or above the Sterling B coal cap. 5 Twelve, how does CINGSA account for the presence of gas 6 above the Sterling C reservoir, Sterling B above) except by the 7 obvious conclusion that gas leaked into the Sterling B from the 6 Sterling C and lower formations in geologic time? 9 Now, Commissioner Seamount has suggested that it could 10 also be coal that's above the Sterling C that's also slowly 11 gasifying itself so that, that may be the case. If that is the 12 case, is that adequate for all of the gas or is it a 13 combination of gas moving up through the various geologic 14 structure to the various reservoirs? 15 Thirteen, and this really comes into play if in the future 16 CINGSA expands the reservoir total volume to 24 billion cubic 17 feet. The gas contained in the Cannery Loop Sterling C 18 reservoir has been reduced from 26 billion cubit feet to 4 19 billion cubic feet and the pressure has been reduced from 2,200 20 psi discovery pressure to about 400 psi current pressure. This 21 will tend to reduce the absorption capacity or available pore 22 space in any depleted reservoir due to pore space granular 23 collapse or subsidence. 24 Has CINGSA calculated the extent to which the absorption 25 capacity of the reservoir has been reduced? Any decrease in 201 Exhibit A Page 41 of 124 I Question number three, once CINGSA accepts the apparent 2 fact that a local fault cuts through the Cannery Loop 3 Reservoir, how will CINGSA modify the project engineering and 4 design criteria? CINGSA does not accept there's an active 5 fault or any fault line that cuts through the Cannery Loop 6 reservoir. There's no evidence from the drilling data 7 whatsoever or the geologic analysis that a fault exists through 8 the reservoir. 9 Mr. Walsh, I don't know if you want to comment further on 10 that. 11 MR. WALSH: I would just -- this is Mr. Walsh for the 12 record. I would also submit that the maps that have been 13 submitted by the operator of the Cannery Loop unit have all 14 shown simple anticlinal structure. Those maps were generated 15 using modern 3D seismic data and there are several maps 16 submitted to the State of Alaska, none of which show any faults 17 through the Sterling reservoir at Cannery Loop unit. 18 Yeah, and for the record, Conservation Order 231 contains 19 geologic data and structure maps for the Cannery Loop unit so 20 that is one place to find that in the public record. 21 CHAIRMAN SEAMOUNT: Which order was that? 22 MR. WALSH: 231. 23 CHAIRMAN SEAMOUNT: 231. 24 MR. WALSH: Um -hum. (Affirmative) 25 This is Mr. Walsh for the record. Question number four, 0111! Exhibit A Page 42 of 124 1 CINGSA shows a very smooth, dome structure in the surface 2 projection maps. How has CINGSA developed this information for 3 the reservoir zone that is beyond the confines of the 4 configuration of wellbores that penetrate the reservoir 5 structure? 6 And, again, the publicly available maps that are available 7 from AOGCC and DNR which have been submitted by the operator do 8 show the structural configuration of the reservoir. And, 9 again, I would submit that those maps are backed by high 10 quality 3D seismic data that is proprietary data owned by the 11 operator. 12 Again, Mr. Walsh for the record. Question number five, 13 the smooth aspect to the dome structure depicted in the surface 14 projection map seems to be inconsistent with the north/south 15 and east/west cross sections. How does CINGSA explain this 16 apparent inconsistency in their data. 17 We don't see any inconsistency there. The well cross 18 sections that have been generated from the well data tie the 19 tops that have been picked. The only inconsistency might be 20 associated with the fact that the top of the Sterling C 21 structure map has not been updated with the recently revised 22 pics that were agreed between CINGSA and Marathon to slightly 23 adjust the top of the reservoir container which has been 24 addressed in testimony yesterday. That's the only 25 inconsistency at all that would be shown between the map and rOM Exhibit A Page 43 of 124 I the cross sections. 2 I will point out that this cross section that's hanging on 3 the wall is not a structural cross section. It is hung on the 4 top of the Sterling C1 so that may -- may be causing some 5 confusion, I don't know, but if you map these out the well 6 penetrations with the depths, there is absolutely no 7 inconsistency with the structure map. g Oh, and again, the structure away from the well data is 9 projected using seismic data. 10 Yes, one more point for the record, the other issue that 11 was raised in testimony by Mr. Goddard and his expert was the 12 fact that there was faulting demonstrated in the well data. 13 This -- the environment of deposition as I testified yesterday 14 is a fluvial deltaic system, primarily fluvial dominated river 15 channels and it's difficult to correlate in that environment, 16 but there is absolutely no evidence in the well records of any 17 faulting have been intersecting by any of the wells in this 18 field. So I just want to make that clear that there is no 19 evidence of repeat section or missing section in those 20 wellbores, that could be possibly missed because of the 21 complexity of the environment, but there certainly is nothing 22 evident in the well records that have been interpreted so far. 23 MR. WINSLOW: Paul Winslow for the record. Question six, 24 how does CINGSA explain the apparent coincidence that the 25 discovery pressure gradient .44 psi per foot is the same as the 210 Exhibit A Page 44 of 124 1 hydrostatic pressure gradient without considering the likely 2 corollary that the reservoir fault structure leaked gas into 3 higher structures until the gas pressure reached stasis or 4 equalized with hydrostatic pressure? 5 The firs thing I'd like to say is my understanding of all 6 of the, what I'm calling shallow gas in Cook Inlet, gas from 7 Tyonek, Beluga and Sterling reservoir is all sourced from 8 coals. It's all biogenetic gas. I don't see it ever -- and 9 it's source from the coals and migrates directly into the 10 surrounding reservoir rock sandstone. If there's a seal it 11 stays in that rock. If there's not it migrates upwards until 12 it finds a seal and it will equal at the pressure of 13 hydrostatic, that's very typical in the Cook Inlet so I would 14 expect a normal pressure as we have seen in both these 15 reservoirs. 16 There is no evidence of leaking. If this were leak- -- if 17 the reservoir were leaking certainly over the history -- the 18 production history of the field you would see it on the 19 material balance plot. There would be an indication of gas 20 leaking off. There's no indications that I've looked at 21 whatsoever of any leaking whatsoever. Anything else you want 22 to say or..... 23 MR. WALSH: This is Mr. Walsh for the record. Question 24 number seven, can CINGSA provide more information regarding the 25 cap that holds the reservoir gas in place? There is virtually 211 Exhibit A Page 45 of 124 1 no information provided in the project proposal documents or 2 the SIO application? 3 I'd be happy to address that. I did address that in 4 testimony yesterday indicating that the clay stones, shales and 5 silt stones at the top of the Sterling C interval and at the 6 base of the Sterling B interval provide competent cap rock for 7 this reservoir. That is based on log analysis of the logs 8 available through the Cannery Loop unit penetrations of that 9 interval. And is also supported by the formation integrity 10 tests which I showed yesterday in my testimony indicating the 11 .684 gradient for -- fractured gradient for those particular 12 rocks. 13 I will also say that probably the best evidence for this 14 cap rock being a competent cap rock is the fact that it has 15 reservoired and contained 26 and a half billion cubic feet of 16 gas for millions of years. That's a pretty strong statement 17 for the capability of that cap rock to hold gas. 18 CHAIRMAN SEAMOUNT: How many years did you say? 19 MR. WALSH: Billions. 20 (Off record comments) 21 MR. WALSH: Question number eight. This is gain Mr. 22 Walsh. How has CINGSA determined the horizontal dimensions or 23 lateral containment dimensions as depicted in the storage zone 24 maps and diagrams? There is no well data outside the confines 25 of the configuration of wellbores that penetrate the reservoir. 212 Exhibit A Page 46 of 124 I The reservoir has been depicted as an anticline, simple 2 fold structure with four way dip closure. And, again, this 3 question has actually been answered before, but the definition 4 of that -- of the pool is defined by the pool maps as submitted 5 to the AOGCC and DNR and again those are supported by quality 6 -- high quality 3D seismic data. 7 MR. WINSLOW: This is Paul Winslow addressing question 8 number nine. Without knowing the actual horizontal dimensions 9 of the reservoir, how can CINGSA guaranty that gas will not 10 migrate horizontally out of the reservoir zone? 11 As stated when I was answering question six, this gas 12 being sourced from coals, migrates out of the coals into the 13 sandstone. If there's a trap it stays there and will fill up 14 that container until a spill point is reached and then it will 15 leak out on the spill point. This reservoir has demonstrated 16 that it contains 26 and a half Bcf of gas. That's a volume, 17 it's above the spill point. There's no evidence that it's 18 leaked at all. The seismic and geologic interpretation of the 19 structure does not show a spill point. 20 And again, the reservoir has held this volume of gas so 21 re -pressurizing to a pressure less than original discovery 22 pressure if we -- even in the second phrase if CINGSA takes it 23 up to 24 Bcf this reservoir has already demonstrated the 24 ability to contain that volume. I see no reason why it 25 wouldn't re -pressurize in up to 24 Bcf. It will be at a lower 213 Exhibit A Page 47 of 124 1 pressure than discovery pressure. 2 MR. WALSH: This is Mr. Walsh addressing question number 3 1o. Without providing the geological structure of the cap, 4 including the localized pattern of faults that cut through the 5 reservoir, how can CINGSA guaranty that gas will not migrate to 6 areas above the reservoir structure, using the available fault 7 lines as migration conduits? g That's a good question, but, you know, faults are known to 9 act as conduits. As we have stated on several occasions, we 10 feel that this is an unfaulted, simple anticline. And we 11 believe that the structure is as depicted in the maps and that 12 there are no faults that penetrate upward from the Sterling and 13 so there would be no migration pathway. 14 But the other issue there again, is if there were faults 15 that do penetrate the Sterling into the shallower section, the 16 gas would have migrated out already and it hasn't. So, I 17 think, history is the strongest evidence that faults are not 18 acting as a conduit into shallow sections. 19 Mr. Walsh, addressing question number 11. What is the 20 geological structure above the reservoir cap? CINGSA has not 21 provided any information about the various structures above the 22 reservoir. 23 We -- this injection order is -- application is addressing 24 injection into the Sterling C so I'm not sure what the need for 25 structure above the reservoir cap is, but be happy to address 214 Exhibit A Page 48 of 124 I that. 2 Our feeling on that is that the structures above the 3 Sterling C pool in the Cannery Loop unit will be conformable. 4 Typically sand, shales and coals bearing water with a 5 diminished amplitude of the structural folds going shallower in 6 the section and we -- we do know from the geologic literature 7 that the Sterling through the Quaternary is fairly -- is fairly 8 conformable. It's very difficult to distinguish the top of the 9 Sterling, but we do feel it would be conformable structures. 10 It would be an anticline that the amplitude would be 11 diminishing upward. 12 And, again, the sands and any conglomerates or any porus 13 medium in that section has been shown from well logs to be 14 water bearing unless they're adjacent to coal stringers which 15 might have provided some local gas. 16 And this is Mr. Walsh, I will also address question number 17 12. How does CINGSA account for the presence of gas above the 18 Sterling C reservoir, Sterling B and above, except by the 19 obvious conclusion that gas leaked into the Sterling B from the 20 Sterling C and lower formations in geologic time? How would 21 CINGSA account for this leaking of gas except through the fault 22 line that cuts through the reservoir? 23 We don't believe that there has been any leakage of gas. 24 We feel that the Sterling C is a very competent reservoir with 25 a competent capping mechanism. The well log and mud log 215 Exhibit A Page 49 of 124 1 information in the shallow section indicates little or no gas 2 in the Sterling A and B and what little trace gas we have seen 3 in those section after a thorough petrophysical analysis is 4 believed to have been locally sourced from coal stringers in 5 those sections. 6 MR. WINSLOW: This is Paul Winslow addressing question 13 7 and to save time I'm not going to read it. It's a long one. 8 The question basically addresses that having decreased the 9 reservoir pressure from 2,200 psi down to 400, the question is 10 has the pour space diminished due to absorption capacity and 11 have we taken that into account when we re -pressure putting the 12 volume of gas that we're talking about for this project back 13 in, has that been accounted for in the pressure. 14 First thing, having dealt with three gas storage fields 15 here in the Cook Inlet I have not seen any evidence of this. 16 They've been very consistent. When you plot the production and 17 injection cycles on material balance they move right up and 18 down the line. I have not seen where it looked like the volume 19 actually decreased so putting the same volume back in did not 20 result in a higher pressure. I understand your question. 21 The second thing would be if you're truly seeing a 22 shrinking volume as you were depleting the reservoir, again, 23 your material balance you would probably se- -- if it's any 24 substantial volume decrease, you would see it on your material 25 balance and all the data for the Sterling C shows a very 216 Exhibit A Page 50 of 124 1 certified professional involved in that team. 2 I personally believe that the work that has been done, I 3 would certainly stand behind it and think that it's quality 4 work. I would hope that has been reflected in the injection 5 order application and the aquifer exemption application. 6 And I will also say that all of the effort that has been, 7 all of the work that has been done on this has been supported 8 by -- by our team by publicly available data, data that is 9 available to Mr. Goddard and his expert. There's a wealth of 10 information that has gone into this and it's available in the 11 public record. 12 MR. GENTGES: This is Mr. Gentges responding to question 13 16. 20 AAC 25.252(h)(1) and (2) clearly requires that the 14 storage injection order applicant to properly repair, plug and 15 modify wells that require remediation before the Commission can 16 approve a storage injection order. When does CINGSA intend to 17 provide this prerequisite information to the Commission? 18 I think both in our original application to the Commission 19 and in subsequent exhibits that we filed on Friday with the 20 Commission we were very clear in identify the wells that we 21 believe require remediation to isolate the Sterling C and 22 address any potential for gas migration, so we believe we've 23 satisfied this request. 24 The application itself provided detail on every well that 25 penetrates the Sterling today. We included a complete summary 219 Exhibit A Page 61 of 124 1 of the conditions, the drilling and completion conditions of 2 each well, the logs that were available and from that 3 information identified wells that require remediation in order 4 to satisfy the requirements of the injection order, so we 5 believe we've satisfied this requirement. 6 And this is Mr. Gentges again on question 17. Why has 7 CINGSA refused to perform a seismic hazard analysis in 8 combination with a ground liquefaction study? 9 How does CINGSA square their refusal to perform a seismic 10 hazard/liquefaction study with their assertion that CINGSA's 11 proposed project will be designed and constructed to meet the 12 best practices for seismic issues? 13 I testified yesterday in my opening statements that the 14 design criteria for this facility will meet all applicable US 15 DOT Part 192 code requirements for the surface facilities. 16 That is the criteria that we have to meet with these facilities 17 being a natural gas transmission facility. So they will be 18 designed in accordance with DOT requirements. 19 We will also design the facilities to meet all applicable 20 building codes, international building codes in the seismic 21 zone in which the facility exists. So we are compliant with 22 all of the requirements of the building codes and all existing 23 regulations. And, in fact, I believe in our surface facility 24 design we will actually exceed those code requirements in some 25 instances. 220 Exhibit A Page 52 of 124 1 The same is true for the gas storage wells. They will be 2 constructed in accordance with all of AOGCC's regulations. 3 And, again, in our testimony yesterday I believe Mr. Perry 4 articulated our construction plans for the wells and in some 5 instances the criteria we will be constructing them to actually 6 exceed the criteria under the AOGCC regulations. 7 And I think the last question Mr. Goddard had was not in 8 his list, but he presented it verbally today and if I captured 9 it correctly -- and Mr. Goddard, correct me if I've 10 mischaracterize this, but I believe your question is, what is 11 the basis for the one percent probability of the wellbore, the 12 KW 13-8 well, acting as a vertical migration conduit, is that 13 correct? 14 MR. GODDARD: Yes. (Nods in the affirmative) 15 MR. GENTLES: Do you want to take this one? 16 MR. WALSH: Sure. This is Mr. Walsh for the record. 17 That, again, is a good question and actually there was no 18 statistical approach taken to that. It was more in line with 19 your comment that the risk is basically negligible and we 20 performed a decision tree analysis to look at the options 21 associated with mitigating any issues with that well or doing 22 nothing and we use the number one percent to plug in for that 23 risk analysis. 24 It is -- yeah, and I should point out that is a one 25 percent chance of cross flow between the Sterling and Beluga or 221 Exhibit A Page 53 of 124 Cook Inlet Natural Gas Storage Alaska Gas Storage Project Alaska Oil and Gas Conservation Commission October 19, 2010 Hearing Cannery Loop Sterling C Pool Injection Order Application Aquifer Exemption Permit Cook Inlet Natural"Gas Exhibit A Page 54 of 124 Technical Presentation Agenda • Project Overview — Richard Gentges • Geologic Analysis —Tom Walsh • Reservoir and Integrity Analysis — Paul Winslow is Detailed Drilling Plans — Conrad Perry • Aquifer Exemption —William Van Dyke • Seismic Risk — Mark Molinari Cook Inlet Natural ; Cas STORAQ a ,� Exhibit A Page 55 of 124 Project Overview • Description of Operation • Project Location • Storage Area Legal Description • Facility Design and Performance • Project Schedule • Updates to Injection Order Application Cook Inlet Natural'Gas STORAQ TP Exhibit A Page 56 of 124 Description of Operation • CINGSA proposes to convert the nearly depleted Cannery Loop Sterling C Pool (C I and C2 Sands) to underground natural gas storage service. • Drill and complete dedicated injection/withdrawal wells, install natural gas driven reciprocating compressors, measurement, and gas process facilities. • Storage gas will generally be injected during the summer months when gas demand is low and withdrawn during the winter to satisfy peak demand requirements for South Central Alaska. • Gas deliveries to/from the proposed storage facility will be via an interconnect with Marathon's KNPL 20 inch pipeline. • CINGSA is in negotiations with Marathon Alaska Production LLC (current operator) to acquire their leasehold interests in the Sterling C Pool • CINGSA has applied for a Gas Storage Lease with the ADNR Cook Inlet Natural; Cas STORAC,,7a . Exhibit A Page 57 of 124 Proiect Location Cook Inlet Natural.fi7as Exhibit STO RAQ ; v 6 Page 58 of 124 Storage Area Legal Description Cook Inlet Storage Field Boundary City of Kenai, Alaska Description Acreage SWI/4-SW1/4 of Section 4, Seward Meridian KN TSN, R1 1W 40 W1/2-SE1/4-SW1/4 of Section 4, Seward Meridian KN TSN, R1 1W 20 S3/4-NW1/4-SWI/4 of Section 4, Seward Meridian KN TSN, R1 IW 30 S1/2-SE1/4 of Section 5, Seward Meridian KN TSN, R11 W 80 S3/4-NE1/4-SE1/4 of Section 5, Seward Meridian KN TSN, R1 1W 30 S112-NW1/4-SE1/4 of Section 5, Seward Meridian KN TSN, R11 W 20 S1/2-NE1/4-NWI/4-SE1/4 of Section 5, Seward Meridian KN TSN, R1 1W 5 E1/2-SE/14-SW1/4 of Section 5, Seward Meridian KN TSN, R11 W 20 SE1/4-NE/14-SW1/4 of Section 5, Seward Meridian KN TSN, R11 W 10 E1/2-E1/2-SE1/4 of Section 7, Seward Meridian KN TSN, R11 W 40 E1/2 of Section 8, Seward Meridian KN TSN, R11 W 320 SW1/4 of Section 8, Seward Meridian KN TSN, R1 1W 160 S1/2-NW1/4 of Section 8, Seward Meridian KN TSN, R11 W 80 E1/2-NE1/4-NW1/4 of Section 8, Seward Meridian KN TSN, R11 W 20 SW1/4-NEI/4-NW1/4 of Section 8, Seward Meridian KN TSN, R11 W 10 SEI/4-NW1/4-NW1/4 of Section 8, Seward Meridian KN TSN, R11 W 10 W3/4-NW1/4 of Section 9, Seward Meridian KN TSN, R11 W 120 N/2-NW1/4-SW1/4 of Section 9, Seward Meridian KN TSN, R1 IW 20 SW1/4-NW1/4-SW1/4 of Section 9, Seward Meridian KN TSN, R1 1W 10 NW1/4-SW1/4-SWI/4 of Section 9, Seward Meridian KN TSN, R11 W 10 N3/4-W1/2-NE1/4 of Section 17, Seward Meridian KN TSN, R11 W 60 N3/4-W1/2-E1/2-NE1/4 of Section 17, Seward Meridian KN TSN, R11 W 30 N3/4-E1/2-NW1/4 of Section 17, Seward Meridian KN TSN, R11 W 60 NW1/4-NW1/4 of Section 17, Seward Meridian KN TSN, R11 W 40 NEI /4-SW1 /4-NW1 /4 of Section 17, Seward Meridian KN TSN, R11 W 10 N1/2-NW1/4-SW1/4-NW1/4 of Section 17, Seward Meridian KN TSN, R11 W 5 N El /4 -NE 1 /4-N E 1 /4 of Section 18, Seward Meridian KN TSN, R11 W 10 NEI /4 -SE 1 /4-N El /4-N E 1 /4 of Section 18, Seward Meridian KN TSN, R11 W 2.5 Total 1272.5 Cook Inlet Natural -Gas STORACQ F Exhibit A Page 59 of 124 Facility Design and Performance • Working Capacity I I BCF initially (17 Bcf potential) • Base Gas: Total of 7 BCF • Injection/Withdrawal Rate: 150 MMcf/d maximum • Engine -Compressor Units (2) 2500 BHp (Cat Model 3608) natural gas fired, reciprocating engine driving a two-stage reciprocating compressor • Injection/Withdrawal Wells Five (5) required for the initial design, directionally drilled from a single pad near the station. • Gathering System 2200 psi MAOP that connects the wells to the storage station Cook Inlet Natural Gas STORAQ, r :� Exhibit A Page 60 of 124 Project Schedule • Construction and environmental permitting • Site clearing • Compressor station /surface facility construction • Injection /withdrawal well drilling • Initial injection • Initial withdrawal (in-service) Cook Inlet Natural -Cas STORACA7a Jun. — Nov. 2010 Nov. 2010 May 2011 Sept. 2011 Apr. 2012 Nov. 2012 Exhibit A Page 61 of 124 Updates to Injection Order Application - • Sub -surface Safety Valve Design o 2 7/8" to 7" • Annular Disposal of Drilling Mud o First i/W well only vs. off-site disposal of drilling mud • Geologic pick for top of Sterling C Pool o formation Revised ti pick -coansistent across entire Poocoal • Remedial work plans for KU 13-8 well Detailed engineering d ed totre enter the well of cross flow Cook Inlet Natural Gas STORAQ., Exhibit A Page 62 of 124 Geologic Analysis • Generalized Stratigraphic Column • Cook Inlet Tertiary Depositional Setting • Sterling C —Type Log • Sterling C —Well Cross-section • Sterling C — Depth Structure Map • Sterling C — Reservoir Properties • Sterling C — Containment Cook Inlet Natural; Cas STORAQ., Exhibit A Page 63 of 124 Stratigraphic Column Cook Inlet Natural"Gas STORAQ, [rc Pei EPOch Mo.--- '�"�OC rn= .'� .. T:19 Eocen�I�. �orPL�rd PCA_2Y Srn7^nletri .,- - c' f I � - w J ;ir.. .i�••rrnc :.'P1 Cook Inlet Stratigraphic Column. From Thomas, et.al., 2004 64oExhibit A Page 64 of 124 Depositional System Tertlai-y Basin DepositionalLe Systems deposit 41 Channel•fill deposit m9no Channetdsp deposit $play Cook Inlet Natural, -Gas STORACQ a P- Tertiary Basin Depositional Systems (DNR) Exhibit A Page 65 of 124 CLU -8 Type Log waw ux _� - .. mb xMA tR BNI RR.glM9 _ vs_ '�mlQlms mxl+m. a ,m i az._ao also m® os , — U. o n o® m Cook Inlet Natural; Gas STORA1 '1116 Q.,. � The Cannery Loop Sterling C Pool is vertically defined as the underground formations comprising the C1 and C2 sands, bounded by the base of the B5 coal formation (C1 TOP) and the top of the Upper Beluga formation (UPPER BELUGA TOP). The Cannery Loop Sterling C Pool is vertically defined in the "Pool Type Log" Cannery Loop Unit (CLU) -8 well (API #50-133- 20534-00) as the interval between the depths of 6690 feet measured depth (MD) (4871 feet true vertical depth subsea [TVDSS)) and 6945 feet MD (5101 feet TVDSS). Exhibit A Page 66 of 124 Sterling C — Cross Section • Refer to large format plot Cook Inlet Natural ;'Gas STORACa s a Exhibit A Page 67 of 124 Sterling C I -Depth Structure Map Cannery Cook Inlet Natural'Gas STOKAQ ,,t I, Exhibit A Page 68 of 124 Reservoir Properties Well LMD (feet) TVD (feet) GRsa�d GRCI. 4(DN 4(pp (Dec (V/V) RciQy NTG (API) (API) (V/V) (V/V) (Alin) Top Base Top Base CLU -1 5814 6076 4985 5190 30 100 0.015 0.0 0.15 3.25 0.329 CLU -3 5344 5574 5060 5275 30 80 0.015 0.0 0.125 2.75 0.396 CLU -4 5212 5410 5070 5260 30 75 0.015 0.0 0.125 2.75 0.573 CLU -5 6090 6300 4935 5135 40 70 0.035 0.0 0.125 2.75 0.294 CLU -7 6090 6300 4925 5140 30 110 0.05 -0.02 0.20 3.0 0.394 CLU -8 6718 6945 4935 5140 30 100 0.035 0.0 0.15 3.0 0.373 CLU -9 5980 6195 4940 5145 30 100 0.035 0.0 0.125 3.0 0.651 CLU -10 5405 5614 4960 5165 30 100 0.0 0.0 0.15 3.0 0.386 CLU -11 6318 6537 4970 5170 30 105 0.045 0.0 0.15 3.0 0.405 CLU -12 7295 7522 5005 5215 30 105 0.03 -0.025 0.15 2.85 0.497 KU -13-8 4980 5200 4980 5200 - - - - - 3.0 0.123 Cook Inlet Natural ; -Cas STORAQQ6 Q -; Exhibit A Page 69 of 124 Sterling C — Containment • 4 -way dip closure • Top Seal is provided by siltstone and shales at the base of the Sterling B and top of Sterling C • The B5 coal is present across the Cannery Loop structure and is 10-20 ft thick. • Bottom seal is the base of the Sterling formation and top of the Upper Beluga formation. This is a silty-shaly interval providing competent sealing between Beluga and Sterling pools • Historic production and pressure data show these reservoir seals to be effective Cook Inlet Natural'Cas STO j'1 A Exhibit A 11{\J1 p.. M Page 70 of 124 a$ a _ b Sterling C — Containment Cannery Loop Unit 9 5/8" Casing Leak -off Test (LOT) Results Well Casing Shop Depth rn Casing Shoe Depth LOT Depth Ryd Mud Ild 1(psi) LOT Departure Pressure EW (at shoe) W41 Frdc Gradient a Departure Pressure (PSWIse CLUB 67Y 4940' 9.0] 1107 13.28 0.6916 3427 CLU -9 59EO' 4939' 2' 9.31 967 13.03 0,679 3362 CLU -10 53E9' 4942' d9Q'J 9.37 9ii7 1'.17 O.b�i 339 • All three leak -off tests indicate fracture gradient significantly higher than hydrostatic gradient (initial reservoir pressure) • Maximum injection gradient 73% of fracture gradient average Cook Inlet Natural'"Gas STORAQ .o -p Exhibit ab c, O Page 71 of 124 Sterling C — Containment •Sterling A and B appear to be water bearing in available (shallow) well logs: CLU -1, CLU -3, & CLUA •Mud gas logs indicate little or no gas above Sterling B-5 coal Cook Inlet Natural '-Gas STORACA7a Exhibit A Page 72 of 124 Reservoir Integrity Analysis • Sterling C — Production and Pressure History • Gas Storage Parameters • Sterling / Beluga Pressure Isolation Cook Inlet Natural; Gas STORAQ 73 of 124 QS Q Page 73 of 124 Sterling C — Production & Pressure • Initial Reservoir Pressure = 2,206 psia • at datum of 4,966' TVD • Storage project will not exceed this pressure • Facilities not designed to exceed this pressure • Initial Reservoir Pressure Gradient = 0.444 psi/ft • Fracture Gradient = 0.684 psi/ft (at top of Sterling) • O G I P = 26.5 Bcf • I st Production Oct. 2000 (CLU -6 well) • Max. Production Rate = ~ 15 MMcf/d (Dec.'01) • Cumulative Gas Produced = 22.5 Bcf (thru Sep.` 10) • Remaining GIP = 4.0 Bcf Cook Inlet Natural Gas STORACA7as a ., Exhibit A Page 74 of 124 Gas Storage Parameters • Gas Storage Volume (initial phase) = 18 Bcf 7 Bcf base volume I I Bcf working volume (initial phase) 17 Bcf working volume (max. future expansion) • Initial number of development wells = 5 • Gas Storage Reservoir Pressure: —630 psia (@ 7 Bcf GIP) 1,520 psia (@ 18 Bcf GIP) 2,000 psia (@ 24 Bcf GIP) • Surface Operating Press. = 400 — 1,450 psig (simulated) • Maximum Surface Injection Pressure requested = 2,200 prig - Corresponds to a BHP gradient of 0.5 psi/ft - 73% of Fracture Gradient • Max. Production & Injection Rate = 150 MMcf/d (initial phase) Cook Inlet Natural; Gas STO D A / Exhibit 4 11 lI�'L/-�1 \vl^,.I{7 � Page 75 of 124 QS Q a Sterling / Beluga Pressure Isolation i. Material balance (P/Z vs. Cum Gas) indicates closed Sterling "C" container. • Attachment 8 of SIO application • Pressure depletion -drive reservoir • No indications of aquifer drive 2. Production history (Beluga & Sterling) shows no signs of pressure communication. 3. Initial reservoir pressures from both the Beluga and Sterling formations indicate pressure isolation. 4. 2009 reservoir pressures in the Beluga and Sterling formations. Cook Inlet Natural"Gas STORAQ P 76 of 124 Page 76 of 124 as a Sterling C — Material Balance LOOP UNIT Sterling C Sand ICANNERY Material Balance Analysis 3000 -- October 28, 2000 I(� ♦CLU -6 2500 ♦ - - - 2000 ♦ - — ---- June 8, 2004 a N 1500 - - - x i Ca 1000 October 22, 2009 500 - --- - - 0 5,000 10,000 15,000 20,000 25,000 30,000 Cumulative Produced Volume, MMscf Cook Inlet Natural' 'Gas STORAQQ Exhibit A Page 77 of 124 Sterling C & Beluga — Production History STORAQ 78 of124 Page 78 of 12d (15 0 _r' Sterling C & Beluga — Initial Res. Pressures • Beluga Initial reservoir pressure gradient = 0.446 psi/ft (2,310 psi @ datum of 5,175' TVD) • Sterling Initial reservoir pressure gradient = 0.444 psi/ft (2,206 psi @ datum of 4,966' TVD) • 33 Bcf of gas had been produced from the Beluga before the Sterling formation was first produced (Oct. 2000) • Note that the KU 13-8 wellbore was drilled and abandoned in 1964 Cook Inlet Natural. -Gas �7Q STORA` s� Exhibit A Page 79 of 124 Sterling C & Beluga — 2009 Pressures • Sterling C reservoir pressure in 2009: • 424 psia in CLU -6 (Oct. 22, 2009) • 465 psia in CLU -10 (Oct. 24, 2009) • Upper Beluga reservoir pressure in 2009: • 1,371 psia (2009 annual reservoir properties report to AOGCC) • U. Beluga producing from CLU -7,8,9, & I I • Pressure differential along with continued straight line P/Z trend (Sterling C) is another good indication of pressure isolation between the Beluga and Sterling formations. • Sterling C pressure measured in CLU -10 (south end of Cannery Loop structure), indicates good lateral communication across the Sterling C reservoir. Cook Inlet Natura[Gas STO AQ Exhibit A K � M Page 80 of 124 a5 a .r Drilling Plans •Typical gas storage well schematic • Casing design • Storage well safety features • Pressure monitoring • KU 13-8 abandonment • Mechanical integrity of existing wells Cook Inlet Natural; -Gas STORACa `e Exhibit A Page 81 of 124 CINGSA Gas Storage Well Schematic Cook Inlet Natural; Gas STOKA4,� . CINGSA Typical Completion Schematic Wellhead - 13 5/8" 50004 Multibmvl - standard trim Tom. 7" 5000+t complete with SSV - standard trim 20" 1330 K55 down to 100 TVD/100' MD 7" Wireline Retrievable SSSV 66 150' TVD/150' MD 13 3/8" 688 K55 PTC Surface Casing QL. 2000' TVD 1 2400'MD I6" hole / Cemented to Surface 7" 268 L80 Vam Top Tubing 7" s 9 518" Liner Top Packer with 20' .cal hove..tensi�n 'ry 4825' TVD / 8950' MD 9 518" 4031-80 RTC Intermediate Casing Coi 4850' TVD 191 50'MD 12 1/4" hole 1 Cemented to Snrfncc H- 50V of4 - 6 SPP perfbm mvn 7" 204 LA0 Vam Top Production Liner from 4825' TVD / 8950' MD TOP to 5080' TVD / 10.950' MD TD A 112" hole/ Cemented Exhibit A CINGSA Casing Design Casing Size in ND ft) MD ft Weigh Ibs k ID In Ddk In Grada Connettion Hole She in API Patin To Bottom To Bottom T e 0.0. in Makeup Torque ft -lbs Burst si Collapse I Tension Ki s 1338" 0' 2,000' V 2,400' 68N 12.415" 12.259" K55 BTC 14.375" NA 16" 3450 1950 1069 958" 0' 4850' Or 9150' 40g 8.835" 8.679" Lao BTC 10.625" NA 1214" 5750 3090 916 7" 4825' Saw 9150' 10950' 26d 6.276" 6.151" LBO VAM 7.390"E7590 59D 81/2" 7240 5410 hoe 7"1 0' 4,825' 0' 9150' 26N 6.27W 6.151" LBO VAM 7.390" NA 7240 5410 604 - Mud Casing Weight Where Size in Set Casin Shoe Maximum Surhace Pressure Design Factors Frac. Grad. Formation Pressure Burst Collapse Tension 133/8" 9 15 8.60 2000 1.66 2.18 2.14 95/8" 10 13 8.54 2500 1.96 1.37 1.83 T' 10 13 8.54 3000 2.1 2.4 4.6 Cook Inlet Natural, -Gas STOAA,7as a , , .1 Exhibit A Page 83 of 124 Storage Well Safety Features Consistent with proven Cannery Loop Drilling Techniques - 13 Offset Wells - Drilling Fluids - Casing Design -Well Head - Close Approach Calculations • Anticipates future AOGCC regulations with Sub -Surface Safety Valves (SSSV) • Cement to surface on all casing strings Cook Inlet Naturat'Gas Exhibit A Page 84 of 124 CINGSA Pressure Monitoring • Real-time monitoring via Supervisory Control and Data Acquisition (SCADA) system • Daily pressure and rate (production Wor injection) recorded • Monthly production and injection volumes reported to the State • Annual Reservoir Performance review • Includes static reservoir pressures each production & injection cycle Cook Inlet Natural;Gas STOAACa s a at the end of Exhibit A Page 85 of 124 KU 13-8 Abandonment - Schematic Cook Inlet Natural .'Gas STOKACA7a6 a sr Exhibit A Page 86 of 124 KU 13-8 Condndor: 113 8': wt unknopm Ping=2: Set from 25 h MO to snrtace PLUG n Shoe: 75 ft. MD Cement Top Cl* 190 ft MO OnermeAlate Hole: 1214` Inteimedlate Cming: PLUG 858":2460 370 sx Clms A cement Pinp - 1: Setbonr 1270 ft to 1000 h MD Shoe: 1159 h. MD Pmduction Hole: It - - 758":Open Hole eawol ee aor: aatae w -'- Sterling C Pool pro°eb r •rMA Top tWu%:9t9iRM TD: 5506 ft. MD . lNot IoScalw. Diani.wittatit Cook Inlet Natural .'Gas STOKACA7a6 a sr Exhibit A Page 86 of 124 KU 13-8 Analysis • Well abandoned in December 1964 • No cross flow during the past 46 years • No measurable depletion - virgin pressure in Sterling C after significant Beluga production • No visible change in P/Z due to Beluga production • No visible change in the Beluga production due to Sterling C production • Cement isolation from casing shoe to surface Cook Inlet Natural.' as STORAC�as c �✓A Page 87of124 Mechanical Integrity • There has been no cross flow from or to the Sterling C reservoir • Evaluated the mechanical integrity of all 12 wells penetrating the Sterling C formation in the Cannery Loop field • Determined that remedial work is needed on CLU -6, CLU -10, and CLU -12. Discussions underway with Marathon on program. Cook Inlet Natural;Gas STO rl A� Exhibit 4 l�(' r- � � Page 88 of 124 DS � _a i Cannery Loop Wells Well Name API Number Original Operator Current O orator Patl Location Date Odlletl Data Completed MD feet TVD feet Formation Completed Current Status KU 13-8 50-133-101 UNOCAL Standalone Ndi Exploratory 5506 5506 None P5A(12/64) CLU 1 50-133-20323-00-00 UNOCAL MARATHON SW Pad Mar -79 Jun -79 10835 8698 Beluga 8 U. Tyonek P 8 A (9/03) CLU IRD 50-133-20323411-00 MARATHON MARATHON SW Pad Oct -03 Noi 10835 8698 U. Tyonek Producing CLU2 50-133-20333-00-00 UNOCAL Outside of field Feb -B1 Exploratory 10731 10731 None PSA CLU3 50-133-20340-00-00 UNOCAL MARATHON NE Pad May -81 Sep -81 11125 10564 Beluga Shut-in(12/88) CLU 4 50-133-20387-00-00 UNOCAL MARATHON NE Pad May -87 Jan -88 16500 15959 Beluga 8 U. Tyonek Shut-in (2/94) CLU 5 50-13320474-00-00 MARATHON MARATHON SW Pad Oct -96 Dec -96 11424 10238 Beluga 8 U. Tyonek Shut-in (4/06) CLU6 50-133-20492410-00 MARATHON MARATHON SW Pad Sep -00 Cot -00 8320 5278 SterlingC Producing CLU 7 50-133-2053140-00 MARATHON MARATHON SW Pad Dec -03 Feb -04 10864 7992 Beluga Producing CLU 8 50-13320534-00-00 MARATHON MARATHON SW Pad Jan44 Apr -04 9777 7941 Beluga Producing CLU 9 50-133-2054400-00 MARATHON MARATHON SW Pad Sep -04 No,04 9100 8042 Beluga Producing CLU 10 50-13120553-00-00 MARATHON MARATHON SW Pad Jul -05 Sep -05 8450 8002 Beluga Shut-in (3/06) CLU 11 5013120559-00-00 MARATHON MARATHON NE Pad Apr -06 Sep -06 9305 7914 Deluge Protlucing CLU 12 50133-201 MARATHON MARATHON NE Pad Au -06 10415 8084 1 None Suspended 9/06 Exhibit A Page 89 of 124 CLU -6 Schematic Open Sterling C Possible Monitoring Well Cannery Loop Unit #6 Pad CLV•1 113' FSL. 465' FEL. Sac. 7. TSN. R11W. S.M. 33-20/92-0040 AOL -60560 4 AOL. OWO L 425 QI'AGL) w1w000 cenwiw rb. `� YO Sr. N' r tI! DAMM eMb�. Ib x5H )vo xlr. i 41Y+r CTr �. br.b a)Y �-K /t5M `rM 1lr Berur Yp F 5]M NC b OS^ .T N+rCr�HrW I ..ImrlaaaH ripnrm p e.ew Aa LIM'MD s.x)r rvD bdm WNMM.M.•{�- C lenbUMa .p arA M Orr O.b .-'. ))N-).a1a )f .HY. A{)I aM )HIM SbNrv�';• M1 CJ'..n. )4ai-).Yf Q IJM.Ia>r a{V MaM �� [��I�y{1 Llmafi )laf•Y w, w Lalf•LaX N Lttf•La tow aq ay •N1 1HIM rr.i. >.. ' aaar•awr ar awr. Llw.r ar Lae{ 'ti I {1•bIN Mtl cenwiw rb. `� YO Sr. N' r tI! DAMM eMb�. Ib x5H )vo xlr. i 41Y+r CTr �. br.b a)Y �-K /t5M `rM 1lr Berur Yp F 5]M NC b OS^ .T N+rCr�HrW I ..ImrlaaaH ripnrm p e.ew Aa Exhibit A Page 90 of 124 LIM'MD s.x)r rvD a a0YIY0 slw�mm . WNMM.M.•{�- C lenbUMa l�rr C IMq VYr r rYnn yylNwW 14Y yh.1 Vlf~ .M d44 1$ .af a1D Mr O. -N• nM ntf tY [yr. tener.v DeWrr )!. TM rr.i. >.. Exhibit A Page 90 of 124 CLU -10 Schematic 50.1112055]-0009 AX one? 90']1'55 WN j� 1sT^1s Famw Tf2y7pdy Er.Ba99s eyg 1700+Ra d10700'i Cannery Loop 10 Pad 1 M' FSL. S29' FEL Sec.?. TSN. R11W. SO 109 i I AM v9ga,F,aw�pex9zctu --- AS19 R fro u'a 1 1JR1' T•.:1 xr F35 1»1R'! +a0 9011.}F M9 C 1IT TVD R liT 3.Y9' LA a FES RTC 111xLd0B]pp1 EVEMe�!9.TB'Meonb1eE Wb95 6MTVP&W.9.1,O9T-1905. TM 9a ND 5 1.BST TOC fe#:.!M JF..6Sr 1m. 5 1J 1t -I Cm.'FRe J. flow, Kara ter MW MX t.. S 9Ba5-rn999DR1 ter • l.ter IL AM v9ga,F,aw�pex9zctu --- AS19 R fro u'a 1 1JR1' T•.:1 xr F35 1»1R'! +a0 9011.}F M9 C 1IT TVD R liT 3.Y9' LA a FES RTC 111xLd0B]pp1 EVEMe�!9.TB'Meonb1eE Wb95 6MTVP&W.9.1,O9T-1905. TM 9a ND 5 1.BST VD 5 1J 1t -I Cm.'FRe J. flow, &elT.' Lda a0 B0+ bTL pp b MD a' Sur f .. TVD 5 A.eaT 1119 Fal. CFq.1 Ta FBb J St6 tBa- <b.. G S9W F tl DIIk Sd 1SA tei {f.N 9 b�' Open perforations in Sterling C Exhibit A Page 91 of 124 111xLd0B]pp1 EVEMe�!9.TB'Meonb1eE Wb95 6MTVP&W.9.1,O9T-1905. IL eBMA]-F.Da5-F 1M waa.x-et+s.ess Open perforations in Sterling C Exhibit A Page 91 of 124 CLU -12 Schematic 9o-,naosesm -._--• CLU 12 au It l V a a.ad. "1 � � 2` d"• �jyf M Ia (tl 9: A a eTf r b MIIe.Mb•. 91' I.N 2.M e81. 2 MS' IYM1 9< rw anw s v •� ep19 t Ce+MM+sl999tl' aYq Cemp.+M 12•te.AA, tw.+m+2 oow Gmnec x. cern eR �� pr.re+se goo s.e «en 2a9+' n r 2x' ce+,+e+ r.., ...,za+•< �9.±r+.. se' a n� �. a— •dewd awn i.Yv Ogaaa npt arc d'2u+M,P G�,r xda.dw.% eleegq 9+n Fnn.M+m owne .2M�9n ]dn Lla.a6 •. ra,r a •. ,on ... ...,�, r.•<� �,p2 uwcwld +se7 5w++.vr+ ter2' n , 9er �Iql GY G—,d +Se 9C9 sw l+n e9,r oa,w' jj•I��ypy� a +rr Iw sre a In.+s ua wM Mwwe l9.Ter. au It l V a a.ad. x.w MeeMre.. A— � MIIe.Mb•. ep19 MIT: Ce+MM+sl999tl' aYq Cemp.+M 12•te.AA, eR 1aa aMMM WM1 S.'16?%'B Un -cemented Gap between Upper Beluga and Lower Sterling C permeable sands Exhibit A Page 92 of 124 Aquifer Exemption • Area Requested • Strata and Depths Requested • Geologic Review • Groundwater Hydrology • Formation Water Salinity • Factors to Consider • Summary • Conclusion Cook Inlet Natural; Gas STOAAQQ `:1-A N' Exhibit A Page 93 of 124 Area Requested • T S N,R I IW,SM • Sec 4: SW 1/4 • Sec 5: S 1/2 • Sec 6:SE 1/4 • Sec 7: E '/2 • Sec 8 • Sec 9:W '/2 • Sec 16:W '/2 • Sec 17 • Sec 18: E '/2 • Totaling approximately 3,300 acres. Cook Inlet Natural Gas STORAQ., 1Y Exhibit A Page 94 of 124 Area Requested Cook Inlet Natural - G -as STORACQ6 a EXHIBIT 2 Exhibit A Page 95 of 124 y OTGNR1fW � E � 1 1 a....y �..r c Ilwie v `1 ■ 1 1 1 a�Rrmm 1 �� 1 1 1 Ifiai a s n roan Cook Inlet Natural - G -as STORACQ6 a EXHIBIT 2 Exhibit A Page 95 of 124 Strata and Depth Requested • This request is for those strata lying deeper than 1300 feet below ground level in the area identified on Exhibit 2 and in the text of the application. This request is consistent with the existing Kenai gas field Class II aquifer exemption in the adjoining area. • This request is similar to the aquifer exemptions granted for the nearby Swanson River, Sterling and Beaver Creek Fields. Cook Inlet Natural;Gas STORAQ 96 of 24 ¢ , � Page 96 of 124 QS Q _�...'I Geologic Review • Geologic Review presented by Mr.Tom Walsh. For the record, in the application: • Exhibit 4 is a type log • Exhibit 5 is a structure map drawn on the top of the Sterling C interval • Exhibit 6 is a north -south cross section • Exhibit 7 is an east —west cross section Cook Inlet Natural 'Gas STORAC a 9Exhibit A 7 of ,� Page 97 of 124 QS a Groundwater Hydrology • In the Cannery Loop area, drinking water is readily available from relatively shallow aquifers. Water wells as recorded with the State of Alaska range in depth from I I feet to 229 feet in the local area. No recorded wells exceed 229 feet in depth in the area. No recorded water wells in the area are drilled into the Sterling or deeper formations. • Exhibit 8 lists the water wells in the local area as taken from SOA Department of Natural Resources records. Cook Inlet Natural.'Gas STORA ;P Exhibit Page 98 of 124 as a Formation Water Salinity *Water samples available from the Sterling C interval. See Exhibit 9 • Log Analysis used to calculate water salinity from intervals above the Sterling C interval. See Exhibit 10 and Exhibit I I • Overall water salinity signature at Cannery Loop is consistent with known Kenai Peninsula geology Cook Inlet Natural:,Gas STORACQs a Exhibit A Page 99 of 124 Factors to Consider • Evidence of Hydrocarbons • The Sterling C interval is hydrocarbon bearing • Occurrences of methane gas in the Sterling C and deeper formations make them impractical, given the readily available alternatives, as sources of fresh drinking water, even if the salinity of the water in the Sterling formation is less than 3,000 mg/I TDS. Cook Inlet Natural"Gas STORACx7Q5 c, : r Exhibit A Page 100 of 124 Factors to Consider • Depth makes i for drinkina water nomically im ses • No recorded water wells in the local area are drilled deeper than 229 feet. Fresh water is readily available from the shallow Quaternary sands and gravel intervals. • The cost to drill a water well deeper than 1300 feet below the ground surface is prohibitively expensive relative to the cost of shallow wells, even if the water has salinities less than 3,000 mg/I TDS. Cook Inlet Natural, Gas STORAQ - s� Exhibit A Pagel 01 of 124 Factors to Consider • The Quality of the water is diminished • The water quality in the strata deeper than 1300 feet below ground surface is diminished relative to the fresh water in the shallow aquifers that serve as the source of fresh water. The cost of treating the water that contains between 300 and 5,000 mg/I TDS from the deeper strata to make it drinking water quality would make it uneconomic to do so, given the abundant fresh water readily available in the shallow aquifers. Cook Inlet Natural: Gas STORAQ Exhibit A Page 102 of 124 Summary The requested area and strata meet the following specific regulatory criteria: • 20 AAC 25.440(a)(1) --They do not currently serve as a source of drinking water and cannot now or will in the future serve as a source of drinking water because-- • 20AAC 25.440(a)(1)(A)—it is hydrocarbon producing or can be demonstrated by the applicant to contain hydrocarbons that considering their quantity and location are expected to be commercially producible. [Sterling formation and deeper formations only] Cook Inlet Naturall"Gas STORA / P 03ofi24 `/.{, ��rA-,-t{� ,� � Page 103 of 124 Q8 Q .r' Summary 2. The requested area and strata meet the following specific regulatory criteria: • 20AAC 25.440(a)(/) --They do not currently serve as a source of drinking water and cannot now or will in the future serve as a source of drinking water because— • 20AAC 25.440(a)(1)(B) —They are situated at a depth that makes recovery of water for drinking water purposes economically impractical. In addition, readily available sources of fresh drinking water are available from shallow strata in the local area. Cook Inlet Natural Gas STORAQ Exhibit A Page 104 of 124 Summary 3. The requested area and strata meet the following specific regulatory criteria: • 20AAC 25.440(a)(/) --They do not currently serve as a source of drinking water and cannot now or will in the future serve as a source of drinking water because - 20 AAC 25.440(a)(I)(C)—it is so contaminated that recovery of water for drinking water purposes is economically or technologically impractical Cook Inlet Natural-lGas STOKA ExhibifA .,;P Page 105 of 124 Q5 Q �'4 Conclusion • This request meets the criteria in 20 AAC 25.440 for the granting of the requested aquifer exemption. Cook Inlet Natural:,Gas STORAC,�a� A „ Exhibit A Page 106 of 124 Seismic Risk • South Central Alaska is situated along tectonic plate boundary —Aleutian megathrust • Pacific Plate is subducted beneath North American Plate at ~ 5.5 cm/yr • High rate of historical seismicity • 1964 Mw 9.2 earthquake (EQ) — 2nd largest historical EQ worldwide • Kenai area EQ risk is similar to other areas of Cook Inlet and Prince William Sound region Cook Inlet Natural; Gas STORAQ e /A ExhibitA SSSKKKQQQ • • Page 107 of 124 Tectonic Setting and Regional Fau Its ••... » MMM AMNIM PIN .. �� Mpmoea BIocR r F2 ��a p� Yakutat 9lock Kane1 LkleKnenl / rk Legend • CINGS S. tomes NrsMc Nom.. We Re�stvxM O. � Ouaremary R (�L �.� PxmePll" 'C4 ey Jt� rs0 m4( N / ` `1 I,-1; Late CMOZoic Faults In Southern Alaska ENsAR CINGSA Nerrm. Abs\a Exhibit A Page 108 of 124 -. Ne�ere 04"N _ prtRon of ryMe vFp ' - IAepallr[[[st srslem a'� Nrsprc 1 L.fe RFsta<m �.� PxmePll" 'C4 ey Jt� rs0 m4( N / ` `1 I,-1; Late CMOZoic Faults In Southern Alaska ENsAR CINGSA Nerrm. Abs\a Exhibit A Page 108 of 124 -. Historical Large Earthquake Ruptures Fipme]. Pcs re areas of large renhgoates in Alaska am the Aleutian Islands from 1903 m 2001 Source: USGS, 2007 Exhibit A Page 109 of 124 South Central Alaska EQ Sources - Interplate • Rupture on subduction zone interface between tectonic plates — 1964 EQ 1600 1500W Source: Christensen and Beck, 1994 Cook Inlet Natural Gas 60° N 56° STORAQ Page 110 of 10 of itA 12a 24 SSS IKKCQQa r � South Central Alaska EQ Sources - Interplate -- • Caused by release of compressive stress • M 9+ EQs recurrence ~ 500-950 yrs based on regional paleoseismology • Average recurrence ~ 700-800 yrs • Repeat of 1964 EQ has very low probability • Rupture from Cook Inlet to SW beyond Kodiak more likely but still low probability Exhibit A Page 111 of 124 1964 Tectonic Deformation T- %a A14ATION1 Iwn ,eORitllR sI1GY5W ]Wih i .luwGslluc'd( 1'.ifkli: ._. ' S ��/f6nllM n•S14 nY> RC5/!f'-( � rne6. LRM �.W: in:rrt4' , .I t"91Y 89god7LLe rm Mlecelss+la 4/N.JELLM etf�ut uaaWUR Nt«dR+re'•' •'�e'y':.: nT ILRWL sine eddgM aW,1.lE''�.� .?,i ^ !yKe€f .'tjui ahi•5 10 ' 'P.W`.+•u ib;AwJ.♦aafioe.� 6axL Aw 14y r n Jy( ov Sanaa: PIsNr. IYEe Map of 1984 Earthquake Tectonic N A Fp 5.2 and Subsidence ENSTAR CINOSA Kellet. AW Exhibit Page 112 of 124 South Central Alaska EQ Sources — Intraplate (Intraslab) • Caused by extensional stress is subducted plate slab • Historical Worldwide = M 7 to 8 • Site Region Historical EQs — Four M 7.0 to 7.7 since 1900 • All in Kodiak Island area • ~ 46 km (29 miles) beneath site Exhibit A Page 113 of 124 Cook Inlet Region Faults and Folds - � M O 11 M r>Y• S AL,Af EY 18A -.m4.7 rnw. +jO •IM p � $U QA1 nR INt lay�IRnl! 1 i5 a / tir Alt •I, aAmhnrapI fir• f� t< 7' -- e •_ EMANATION I 114 ,II„t• +L lj) �O I;mlts xllh NCnrrnc nr Y lir tin (hlalClTiQR ITMCMMI ' f1i14•r -as liff:i e L L Licosnf'SLcjinn Im +u 1: i�l.tre, c-� and 5-4 e Y j ° MSF 4Lcrl W mmlinv Fant! a Exhibit A Page 114 of 124 I I JfJ�f-� I t Source: Haeussler et al 2000 - � M O 11 M r>Y• S AL,Af EY 18A -.m4.7 rnw. +jO •IM p � $U QA1 nR INt lay�IRnl! 1 i5 a / tir Alt •I, aAmhnrapI fir• f� t< 7' -- e •_ EMANATION I 114 ,II„t• +L lj) �O I;mlts xllh NCnrrnc nr Y lir tin (hlalClTiQR ITMCMMI ' f1i14•r -as liff:i e L L Licosnf'SLcjinn Im +u 1: i�l.tre, c-� and 5-4 e Y j ° MSF 4Lcrl W mmlinv Fant! a Exhibit A Page 114 of 124 Post -1964 Deep Seismicity Edge of 1 %4 Eatthauake Northwest Rupture Zone Southeast CINGSA LShe La 20` Top of :` YVa�ataBenioff 46 kn1• ► Zone 40- 60- 80-1/.- 100- 0 80 '/100 • , 1934 120 0 20 40 60 80 100 120 Distance (km) Souze. V#Jeux a.M 00�, 200" Exhibit A Page 115 of 124 Post- 1964 Shallow Seismicity CINGSA K KI Site Southeast Northwest OW 0 1%---te- • ` • • • • • • • • •� • ti•s t�• • '/t•� • • • ` • • • ` • Top of ` • ` • • Wadab4Benioff w • • • Zona • ? • •~� �• •• t • • •• • • 0 20 ao so so 100 120 140 distance. km Souice- Fuses and Dow. 2005. Exhibit A Page 116 of 124 Fault Rupture Hazard • No AK criteria for active fault • CA and common criteria for active tectonic areas =Holocene (< 10- 11 k) •Closest known Holocene fault is Castle Mtn. • Closest potentially active fault =West Boundary fault in Cook Inlet • ~ 25 km (16 miles) from site Exhibit A Page 117 of 124 , Cannery Loop Geologic Structure • Cannery Loop fault and fold • No published evidence of Quaternary displacement or deformation • — 3 km (2 miles) from well head and compressors • Not intersected by planned directional wells • No fault rupture hazard to planned surface and subsurface facilities Exhibit A Page 118 of 124 EQ Ground Motion Hazard • Kenai area EQ risk is similar to other areas of Cook Inlet and Prince William Sound region • USGS probabilistic ground motion maps • Primary contribution at site is from future subduction zone earthquakes • Time independent — conservative since it isn't based on time since 1964 EQ • Similar risk as SoCal, and western WA and OR where gas storage facilities are located Exhibit A Page 119 of 124 USGS 475 -yr (10% in 50 yr) Horizontal PGA Map 350+ 255 Alaska 125 75 rE -170- -160' PGA, 10% in 50 years Exhibit A Page 120 of 124 USGS 2,475 -yr (2% in 50 yr) Horizontal PGA Map rE Alaska 350+ 255 125 %5 160' V PGA. 21% in 50 years Exhibit A Page 121 of 124 EQ Ground Motion Design • USGS estimates for rock are: 475 -yr = 0.36 g and 2475 -yr = 0.59 g • USGS values and soil factor accounted for in seismic design criteria per Alaska Building Code • Code is appropriate for above ground facilities and pipelines — higher design levels not warranted • No special criteria for subsurface well construction in AK or other western U.S. States • Unnecessary because ground shaking not a risk to properly constructed wells • Wells move with soil/rock and there is not differential displacement Exhibit A Page 122 of 124 Liquefaction and Lateral Spread • Typically occurs in loose, saturated, cohesionless soils (e.g. sands and silt/sand mixtures) at depths <50 ft • Loss of soil strength due to increased pore pressure from EQ shaking • No reported liquefaction or lateral spreading for site area in 1964 • No nearby slopes or free faces that could affect site by lateral spreading • Settlement for liquefaction, if any, can be accommodated by foundation design Exhibit A Page 123 of 124 Other Geologic and Seismic Hazards Evaluated No identified hazards at site associated with: • Tectonic and Local Subsidence • Tsunami • Flooding • Slope stability • Volcanic hazards • Volcanic ash fall is the only identified hazard that could impact operation — temporary impact potential Exhibit A Page 124 of 124 AOG(C 8/4/2020 IT MO: APPLICATION OF HILCORP AK FOR SUNDRY APPROVAL Docket No. 0TH -20-09 ALASKA OIL AND GAS CONSERVATION COMMISSION In the Matter of the Application of ) Hilcorp Alaska for Sundry Approval to ) Perforate Cannery Loop Wells 13C and 15C ) Which Pass Through the Sterling C Gas ) Storage Pool and Which are Within 1,500 ) Feet of the Vertical Property Line. ) Docket No.: 0TH 2O-009 PUBLIC HEARING August 4, 2020 10:00 o'clock a.m. BEFORE: Jeremy Price, Chairman Jessie Chmielowski, Commissioner Daniel T. Seamount, Commissioner Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr.. Ste. 2., Arch. AK 99501 Fax 907-243-1473 Email sahile(a)gci net AOGCC 8/4/2020 ITMO: APPLICATION OF HILCORP AK FOR SUNDRY APPROVAL Docket No. OTH-20-09 Page 2 1 TABLE OF CONTENTS 2 Opening remarks by Chairman Price 03 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK99501 Fax: 907-243-1473 Email: sahile@gci.net AOGC( 8/4/2020 ITMO- APPLICATION OF HIL(ORP AK FOR SUNDRY APPROVAL Docket No. 0 F 20-09 Page 3 1 P R O C E E D I N G S 2 (On record - 10:00 a.m.) 3 CHAIRMAN PRICE: Good morning. I'll call this 4 hearing to order. Thank you for going through this 5 exercise. This is I think just the second hearing that 6 we've done telephonically so appreciate everyone's 7 patience and interest in accommodating these new 8 procedures. 9 This is docket number OTH 2O-009, considering 10 the amendment of conservation order 231. This hearing 11 is being held on the morning of August 4th, 2020 at 12 10:00 a.m. The location is the Alaska Oil and Gas 13 Conservation Commission offices at 333 West 7th Avenue, 14 Anchorage, Alaska. Before we begin I'll introduce the 15 Commissioners. To my left is Commissioner Dan Seamount 16 and to my right is Commissioner Jessie Chmielowski, I 17 am Jeremy Price, Commissioner and Chair. If any 18 persons on the phone need special accommodations to 19 participate in these hearings -- in these proceedings, 20 sorry, please contact Jody Colombie and she will do her 21 best to accommodate you. 22 First I'd like to ask is there anybody who 23 can't hear me, is there any concern with the volume, do 24 I need to speak louder or are we okay? 25 (No comments) Compute[ Matrix, LLC Phone_ 907-243-0668 13501nstensenf),-Ste. 2., Anch. AK99501 Fax: 907-243-1473 Email: sahi1e(0,)gci. net AOGCC 84/1020 ITMO. APPLICATION OF HILCORP AK FOR SUNDRY APPROVAL Docket No. OTH-20-09 Page 4 1 CHAIRMAN PRICE: By that sound I guess we're 2 going to be all right unless you can't hear me at all 3 then we're going to have some troubles. But let's keep 4 moving, I'll try to speak loudly enough for everybody 5 to hear me. 6 Today Computer Matrix will be recording the 7 proceeding. Upon completion and preparation of the 8 transcript persons desiring a copy will be able to 9 obtain it by contacting Computer Matrix. 10 Recently Hilcorp Alaska, LLC or Hilcorp 11 submitted an application for sundry approval forms to 12 perforate the Cannery Loop Unit 13 and 15 wells. Both 13 CLU 13 and CLU 15 pass through reservoir sands within 14 Cook Inlet Natural Gas Storage Alaska, LLC or CINGSA's 15 Sterling C gas storage pool. Because some of the 16 intervals Hilcorp seeks to perforate are within 1,500 17 feet of the vertical property line of the gas storage 18 pool they require spacing exceptions under rule 4 of 19 conservation order 231 and 20 AAC 25.055 of the 20 Commission's regulations. 21 As a result on its own motion the AOGCC set a 22 hearing to consider amending conservation order 231. 23 The purpose of this hearing is to review whether a 24 1,500 foot offset requirement for such gas wells is 25 appropriate for a vertical property line or whether it Computer Matrix. LLC Phone: 907-243-0668 135Chdsleusen Dr-Ste.2-Anch AK99501 Fax907-243-1473 Email: sahile(aigm. net AOGCC 8 4, 2020 1 FMO: APPLICATION OF HILCORP AK FOR SUNDRY APPROVAL Docket No.OT11-20-09 Page 5 1 is appropriate to amend conservation order 231 to allow 2 perforations closer to the storage pool boundary. If 3 such perforations are allowed how close may those 4 perforations be placed to the pool boundary and what 5 methods Hilcorp and CINGSA can employ to demonstrate 6 that correlative rights will be protected. 7 On August 3rd, 2020 the two parties submitted 8 an agreement with a number of protocols in an effort to 9 ensure the integrity of each party's reservoir. This 10 letter is being reviewed at this time. CINGSA also 11 filed a request to continue today's hearing due to 12 logistical issues. The Commission has granted that 13 request and so today we are here to schedule that 14 hearing. 15 The Commission is continuing this hearing until 16 Thursday, August 27th at 10:00 a.m. Are there any 17 conflicts with this date from the parties? 18 MS. SMITH: CINGSA has no conflict with that 19 date. 20 Thank you, Commissioner. 21 CHAIRMAN PRICE: That's August 27th at 10:00 22 a.m. That's a Thursday. 23 MS. SMITH: Commissioner, this is Moira Smith 24 on behalf of CINGSA and we have no conflicts with that 25 date. Computer Matrix, LLC Phone907343 0668 135 Christensen Dr., Ste, 2., And, Ate 99501 Pax: 907-243-1473 Email- sahilept,ei.nel AOGcc 8/4/2020 ITMO: APPLICATION OF HILCORP AK FOR SUNDRY APPROVAL Docket No. OTH-20-09 1 Thank you. 2 CHAIRMAN PRICE: Thank you. Any concerns from 3 Hilcorp? 4 MR. McCONKEY: This is Anthony McConkey on 5 behalf of Hilcorp. We have no conflicts with that 6 date. 7 CHAIRMAN PRICE: Okay. Then we'll set the 8 hearing for Thursday, August 27th at 10:00 a.m. 9 Commissioners, any thoughts you'd like to 10 express at this time? 11 COMMISSIONER SEAMOUNT: Not at this time, Mr. 12 Chair. 13 COMMISSIONER CHMIELOWSKI: No. Thank you. 14 CHAIRMAN PRICE: Okay. Any questions from the 15 parties at this time? 16 MS. SMITH: This is CINGSA and we have no 17 questions at this time. 18 Thank you, Chair. 19 CHAIRMAN PRICE: Thank you. Any concerns from 20 Hilcorp at this time? 21 MR. McCONKEY: This is Anthony McConkey. No, 22 we don't have any questions at this time. 23 CHAIRMAN PRICE: Okay. Thank you, Then we 24 will reconvene at 10:00 a.m. on August 27th. Until 25 then this hearing is adjourned. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Lmaih saNle@gci.oet AOGCC 8,4/2020 FFMO: APPLICATION OF HILCORP A K FOR SUNDRYAPPROVAL Page 7 (Hearing adjourned - 10:09 a.m.) 2 F1 (END OF PROCEEDINGS) 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 r.. 135 Christensen Dr, Ste 2., Anch, AK 99501 Phone: 907-243-0668 Fax: 907-243-1473 Email: sahileGagcinel AO(,(( 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 9 4:2020 ITMO. APPL (CATION OF [if]]CORP AK FOR SUNDRY APPROVAL. Ducker N. OTH-20-09 TRANSCRIBER'S CERTIFICATE I, Salena A. Hile, hereby certify that the foregoing pages numbered 02 through 08 are a true, accurate, and complete transcript of proceedings in Docket No.: CO 20-009, transcribed under my direction from a copy of an electronic sound recording to the best of our knowledge and ability. DATE SALENA A. RILE, (Transcriber) Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dc, Ste. 2., Anch. AK 99501 Pax: 907-243-1473 Email: sahile(aigci. no STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Docket Number: CO -20-009 August 4, 2020 at 10:00 am NAME AFFILIATION Testify (yes or no) RECEIVED By Jody Coiombie at 10:42 am, Aug 03, 2020 August 3, 2020 AOGCC 333 W 7'h Avenue Anchorage, AK 99501 Re: Joint Request to Cancel August 4, 2020 Hearing and Joint Request to Amend CO 231.001 Dear Commissioners: Cook Inlet Natural Gas Storage Alaska, LLC ("CINGSA") and Hilcorp Alaska, LLC ("Hilcorp") hereby jointly request that the Commission cancel tomorrow's hearing regarding the above - referenced spacing exception. In lieu of a contested hearing, CINGSA and Hilcorp hereby jointly request that the Commission amend Conservation Order (CO) 231.001 to reflect the terms agreed to by the parties, as set forth herein. CINGSA and Hilcorp believe that amendment of CO 231.001 in accordance with the terms set forth in this letter is consistent with sound engineering and geoscience principles and will not jeopardize either party's correlative rights. This proposed amendment will also allow for maximum use of the vertical reservoirs in the Cannery Loop Unit for both production and storage purposes, thereby avoiding waste. Rule 3 of CO 231 established spacing requirements for wells within the Cannery Loop Unit. In 2014, Hilcorp applied for an exception to these spacing requirements for purposes of drilling the Cannery Loop 13 development gas well.' The Commission granted this exception in CO 231.001. The general 1,500 vertical spacing requirement, however, was reiterated by the Commission in that order: "...the spacing exception for Cannery Loop Unit No. 13 is limited to the Beluga and Upper Tyonek Gas Pools at locations that are more than 1,500' from any property that is not committed to the Cannery Loop Unit, including a set -back of 1,500 true vertical feet from the base of CINGSA's overlying Sterling C Gas Storage Pool, which corresponds to the lower boundary for oil and gas storage lease ADL -391627."' The Cannery Loop Unit has both productive and ' Docket Number CO -14-031. 2 CO 231.001, Conclusion ¶ 3 (internal citation omitted). August 3, 2020 Joint Hilcorp-CINGSA Letter to AOGCC Page 2 of 4 storage zones.3 Hilcorp owns all of the leases in the Cannery Loop Unit other than the Sterling C Gas Storage Pool. Between April 20 and May 13, 2020, Hilcorp filed Applications for Sundry Approvals related to planned drilling operations in CLUs SRD, 13 and 15. Because the proposed drilling operations would come within 1,500 true vertical feet of the CINGSA Sterling C Gas Storage Pool, on April 22, 2020, the AOGCC asked Hilcorp to obtain a letter of non -objection from CINGSA. Following this request, the two parties conferred regarding the best protocols to follow to ensure the integrity of each party's reservoirs. After conferring, the parties have agreed on the following protocols: The parties agree to exchange the following data: all sundry applications and approvals for new wells that penetrate the Sterling C Gas Storage Pool. all sundry applications and approvals for perforations of existing wells within 1500 feet of the Sterling C Gas Storage Pool. When drilling, provide logging while drilling (LWD) logs within 30 days after completion, but prior to any perforating work within 200 feet TVD of the Sterling C Gas Storage Pool. If LWD is not employed, within 30 days of completion, but prior to any perforating work within 200 feet TVD of the Sterling C Gas Storage Pool, provide a copy of all open -hole logs run across the Sterling C Gas Storage Pool and at least 100 feet into the Beluga formation. Only until drilling in Sterling C Gas Storage Pool is cased and cemented, provide Daily Drilling Reports within 48 hours of their creation. Cement bond logs (CBLs, or cement evaluation logs) to 100 feet TVD below the Sterling C Gas Storage Pool as defined in the CLU 8 type log (1) for all current Hilcorp wells that penetrate the Sterling C Gas Storage Pool and (2) for any future well that penetrates the Sterling C Gas Storage Pool, as commercially and time practicable, prior to any perforating work within 200 feet TVD of the Sterling C Gas Storage Pool, and as they become available. ' CO 231.001, Finding 7 (""Within the Cannery Loop Unit, the Beluga, Upper Tyonek, and Tyonek D Gas Pools lie beneath the Sterling C Gas Storage Pool that is located within State of Alaska lease ADL - 391627. Lease ADL -391627 and the Sterling C Gas Storage Pool are owned and operated by CINGSA. The Sterling C Gas Storage Pool is defined in, and governed by, Storage Injection Order Nos. 9 and 9A."). August 3, 2020 Joint Hilcorp-CINGSA Letter to AOGCC Page 3 of 4 • Provide bottom hole pressure surveys when run in CLU 8 or in any other well that is open within 100 feet TVD based on the CLU 8 type log of CINGSA's Sterling C Gas Storage Pool. • No future perforations within 50 feet TVD of CINGSA's Sterling C Gas Storage Pool as defined by the CLU 8 type log (adjusted for co -relative depth at the well in question). • Open hole log data for the CLU 8 well to 100 feet TVD below the Sterling C Gas Storage Pool as defined in the CLU 8 type log. • For so long as CLU -8 is open within 50 feet of CINGSA's Sterling C Gas Storage Pool, Hilcorp will continue providing CINGSA with daily flow and pressure data and monthly updates to their material balance analysis (the graphical plot which shows flowing pressure (P/Z) vs. cumulative production). • Monthly casing and tubing pressures on all wells that penetrate the Sterling C Gas Storage Pool. • Report any condition that may indicate a loss of integrity for "incidents" (as defined by 49 CFR 191.3) within one hour of "confirmed discovery." Confirmed Discovery means when it can be reasonably determined, based on information available at the time, that a reportable event has occurred, even if only based on a preliminary evaluation. For all other conditions, within 5 working days after the day a representative first determines that the condition exists. As to all future wells, CINGSA will require that intermediate casing be set and cemented a minimum of 50 feet below the base of the Sterling C Gas Storage Pool. The CBL must show good cement bond across this entire 50 foot interval (CINGSA and Hilcorp must jointly agree to this assessment), and the casing must pass the AOGCC mandated MIT/leak-off test of the casing shoe. For any existing wells, if intermediate casing is not set at least 50 feet below the Sterling C Pool, CINGSA requires a minimum of 100 feet interval of good pipe to formation bond of the primary casing string below the base of the Sterling C Pool. CINGSA requires a 50 foot minimum buffer below the base of the Sterling C Pool as correlated to the CLU -8 type log, within which no new perforations may be made. Both parties require notification for any perforation activity less than 1,500 feet (vertically) from the base of the Sterling C Pool. Completion and re -completion plans that include hydraulic fracturing require a 100 -foot buffer below the base of the Sterling C Pool, as correlated to the CLU -8 type log, within which no new perforations may be made. No perforations may be made within the 50 and 100 foot intervals referenced immediately above. August 3, 2020 Joint Hilcorp-CINGSA Letter to AOGCC Page 4 of 4 CINGSA and Hilcorp appreciate the Commission's attention to this request. Sincerely, Denali Kemppel Moira Smith Hilcorp Alaska, LLC CINGSA RECEIVED By Jody Colombie at 10:43 am, Aug 03, 2020 CINGSA and Hilcorp appreciate the Commission's attention to this request_ Sincerely, Denali Kemppel Moira Smith Hilcorp Alaska, LLC CINGSA Colombie, Jody J (CED) From: Colombie, Jody J (CED) Sent: Friday, June 26, 2020 3:20 PM To: Seamount, Dan T (CED); Chmielowski, Jessie L C (CED); Price, Jeremy M (CED); Davies, Stephen F (CED); Schwartz, Guy L (CED); Ballantine, Tab A (LAW) Cc: Colombie, Jody J (CED) Subject: FW: Docket Number: CO -20-009 Categories: Yellow Category From: Moira Smith <Moira.Smith@enstarnaturalgas.com> Sent: Friday, June 26, 2020 2:00 PM To: Colombie, Jody J (CED) <jody.colombie@alaska.gov> Cc: Denali Kemppel <dkemppel@hilcorp.com>; Matthew Federle <Matthew.Federle@cingsa.com>; John Sims <John.Sims@enstarnatura Igas.com> Subject: Docket Number: CO -20-009 Ms. Colombie, Please consider this CINGSA's formal request for a hearing in the above -referenced matter. Thank you, Moira Smith Vice President and General Counsel CINGSA Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION Re: Docket Numbers: CO -20-009 Amendment of Conservation Order 231 Hilcorp Alaska, LLC (Hilcorp) submitted Application for Sundry Approvals Forms to perforate the Cannery Loop Unit (CLU) 13 and 15 wells. Both CLU 13 and CLU 15 pass through reservoir sands within CINGSA's Sterling C Gas Storage Pool. Because some of the intervals Hilcorp seeks to perforate are within 1,500 feet of the vertical property line of the gas storage pool (State of Alaska Lease ADL 391627), they require spacing exceptions under Rule 4 of Conservation Order (CO) 231 and 20 AAC 25.055. As a result, on its own motion, the Alaska Oil and Gas Conservation Commission (AOGCC) is setting a hearing to consider amending CO 231. Specifically, AOGCC is reviewing whether a 1500 -foot offset requirement is appropriate for a vertical property line. The AOGCC has scheduled a public hearing on this subject for August 4, 2020, at 10:00 a.m. at 333 West 71 Avenue, Anchorage, Alaska 99501. If, due to health mandates issued as a result of the covid-19 virus, it becomes necessary to conduct the hearing telephonically, those desiring to participate or be present at the hearing should check with AOGCC the day before the hearing to ascertain if the hearing will be telephonic. If the hearing is telephonic, on the day of the hearing, those desiring to be present or participate should call 1- 800-315-6338 and, when instructed to do so, enter the code 14331. Because the hearing will start at 10:00 a.m., the phone lines will be available starting at 9:45 a.m. Depending on call volume, those calling in may need to make repeated attempts before getting through. 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 June 10, 2020. 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 June 27, 2020, except that, if a hearing is held, comments must be received no later than the conclusion of the August 4, 2020 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 July 30, 2020. Jessie L GMmklowAd Chmielowski ww 0 00 3110' �' a Jessie L. Chmielowski Commissioner STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMITINVOICE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVITOF PUBLICATION WITH ATTACHED COPY OF ADVERTISMENT. ADVERTISING ORDER NUMBER p 1 AO -08-20-025 FROM: AGENCY CONTACT: Jody Colombie/Samantha Carlisle Alaska Oil and Gas Conservation Commission DATE OF A.O. AGENCY PHONE: 333 West 7th Avenue 521/2020 907 279-1433 Anchors e, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: 7HONE NUMBER: ASAP FAX NUMBER: 907 276-7542 TO PUBLISHER: Anchorage Daily News LLC SPECIAL INSTRUCTIONS: PO Box 140147 Anchorage, Alaska 99514.0174 TYPE OF ADVERTISEMENT: FV LEGAL f— DISPLAY r CLASSIFIED r OTHER (Specify below) DESCRIPTION PRICE CO -20-009 Initials of who prepared AO: Alaska Non -Taxable 92-600185 SUBMIT INVOICE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVR OF PUBLICATION WITH ATTACHED COPY OF ADVERTISMENT TO: AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Pae I of I Total of All Pages S Type Number Amount Date Comments 1 PVN VCO21795 IREF 2 AO AO 8_20_025 3 4 FIN AMOUNT SY Act Tem lace PGM LGR Object FY DIST LIQ 1 20 AOGCC 3046 20 2 3 5 Pur g u ri Title: Purchasing Authority's Signature Telephone Number i. .O. # and receiving agency name must appear on all invoices and documents relating to this purchase. . The state is registered 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. DISTRIBUTION: Division Fiscal/Original AO Copies: Publisher (faxed), Division Fiscal, Receiving Form: 02-901 Revised: 5/212020 Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706