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Home My WebLink About220-0631. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Remove Cap String Development Exploratory 3. Address:Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 6,650 feet N/A feet true vertical 6,637 feet N/A feet Effective Depth measured 6,511 feet 4,256'feet true vertical 6,497 feet 4,256'feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# / L-80 4,266' MD 4,266' TVD Baker ZXP Liner Top Pkr 4,256' MD 4,256' TVD Packers and SSSV (type, measured and true vertical depth)N/A N/A N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date:Contact Name: Contact Email: Authorized Title:Contact Phone: Scott Warner, Operations Engineer N/A Sr Pet Eng:Sr Pet Geo:Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 N/A scott.warner@hilcorp.com 907-564-4506 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 580 Size 31' 0 5600 0 32200 3342 Production Liner 4,489' 2,384' measured TVD 7" 4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 220-063 50-133-10160-01-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: FEDA 082931 Swanson River / Tyonek 64-5 Gas Storage Pool Swanson River KGSF #1A Plugs Junk measured LengthCasing Structural 4,489' 6,627' 4,489' 6,640' 31'Conductor Surface Intermediate 20" 11-3/4" 31' 2,032' 4,328psi 6,000psi 3,070psi 5,792psi 6,744psi 2,032'2,032' Burst Collapse 1,510psi p k ft t Fra O s 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Gavin Gluyas at 9:24 am, Feb 14, 2025 Noel Nocas (4361) Digitally signed by Noel Nocas (4361) Date: 2025.02.13 17:54:28 -09'00' BJM 4/14/25 DSR-2/18/25 RBDMS JSB 021925 Page 1/1 Well Name: SRF GS SRU KGSF #1A Report Printed: 1/27/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Jobs Actual Start Date:11/10/2023 End Date: Report Number 2 Report Start Date 9/2/2024 Report End Date 9/3/2024 Last 24hr Summary PTW, JSA. MIRU Hilcorp Capillary string truck. Load 3/8" spool. Pull 2154' of capillary tuibng due to being plugged and upcoming Eline Logging work. All line and footvalve recovered. Plan to rerun after wireline work completed. Report Number 3 Report Start Date 12/3/2024 Report End Date 12/4/2024 Last 24hr Summary PTW/PJSM. PT 250/4000, drift & tag @ 6410' W/ 2.80" JB Report Number 4 Report Start Date 12/5/2024 Report End Date 12/6/2024 Last 24hr Summary PTW/PJSM, Log 40 arm caliper & EPX log from 6408' - Surface. Report Number 5 Report Start Date 1/22/2025 Report End Date 1/22/2025 Last 24hr Summary Hydrate modeling and flow testing complete. No capstring is needed at this time. Field: Swanson River Sundry #: LOE State: Alaska Rig/Service:Permit to Drill (PTD) #:220-063Permit to Drill (PTD) #:220-063 Wellbore API/UWI:50-133-10160-01-00 Updated by DMA 09-11-24 Swanson River Unit Well KGSF 1A PTD: 220-063 API: 50-133-10160-01-00 SCHEMATIC TD @ 6,650’ MD / 6,637’ TVD PBTD @ 6,511’ MD / 6,497’ TVD PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Size Date Status TY 64-5 6,395’ 6,404’ 6,382' 6,391' 9’ 2-7/8” 6 SPF 11/13/20 Open CASING DETAIL Size WT Grade Conn ID Top Btm 20” - - - Surface 31’ 11-3/4” 47 - - 11” Surface 2,032’ 7” 23,26,29 N-80 BTC 6.059” Surface 4,489’ 4-1/2” (tieback) 12.6 L-80 VAM Top 3.833” Surface 4,266’ 4-1/2” (liner) 12.6 L-80 DWC/C-HT 3.833” 4,256’ 6,640’ 20” 11-3/4” 7” 4-1/2” shoe @ 6,640’ JEWELRY DETAIL No Depth ID OD Item 7” Window Detail TOW @ 4489’ 1 4,256’ 5.800” Liner Top Packer 2 4,266’ 5.250” - Tieback Mule Shoe 1 OPEN HOLE / CEMENT DETAIL 4-1/2” 41 BBL’s of cement in 6” hole. TOC @ TOL – ~4,256’ – 10.5 bbls to circulated to surface 7” TOC @ 3,675’ 64-5 2 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Monday, January 27, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Sully Sullivan P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC KGSF 1A SWANSON RIV UNIT KGSF 1A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 01/27/2025 KGSF 1A 50-133-10160-01-00 220-063-0 N SPT 4256 2200630 1500 2840 2840 2850 2850 40 40 40 40 4YRTST P Sully Sullivan 11/25/2024 No issues, Operator was very well prepared 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:SWANSON RIV UNIT KGSF 1A Inspection Date: Tubing OA Packer Depth 369 1738 1731 1731IA 45 Min 60 Min Rel Insp Num: Insp Num:mitSTS241206125929 BBL Pumped:0.5 BBL Returned:0.5 Monday, January 27, 2025 Page 1 of 1 9 9 9 9 9 9 9 999 9 9 99 9 9 *DVVWRUDJHZHOOSURGXFLQJ James B. Regg Digitally signed by James B. Regg Date: 2025.01.27 15:15:21 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 1/07/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240107 Well API #PTD #Log Date Log Company Log Type AOGCC Eset # END 2-72 50029237810000 224016 11/16/2024 HALLIBURTON TEMP END 2-74 50029237850000 224024 12/5/2024 HALLIBURTON MFC24 END 2-74 50029237850000 224024 8/13/2024 DarkVision HADES (Down hole camera) KGSF 1A 50133101600100 220063 12/5/2024 HALLIBURTON EPX-MFC40 MPU F-13 50029225490000 195027 12/22/2024 HALLIBURTON WFL-TMD3D PU F-40 50029222150000 191117 11/9/2024 READ CaliperSurvey MPU I-04A 50029220680100 201092 11/22/2024 HALLIBURTON COILFLAG MPU J-02 50029220710000 190096 12/22/2024 READ CaliperSurvey PBU L-04 50029233190000 206120 11/23/2024 HALLIBURTON WFL-TMD3D PBU L-221 50029233850000 208031 12/11/2024 HALLIBURTON WFL-RMT3D PBU Z-ϯϰ 50029234690000 212061 12/15/2024 HALLIBURTON WFL-RMT3D PBU Z-2ϯϱ 50029237600000 223055 9/24/2024 READ InjectionProfile PBU Z-ϮϮϯ 50029237200000 222080 11/24/2024 HALLIBURTON WFL-TMD3D SCU 42-05Y 50133205700000 207082 12/7/2024 HALLIBURTON EPX-MFC24 TBU D-16RD 50733201830100 180110 12/19/2024 READ CaliperSurvey TBU D-17RD 50733201680100 181023 12/21/2024 READ CaliperSurvey Please include current contact information if different from above. T39915 T39916 T39916 T39917 T39918 T39919 T39920 T39921 T39922 T39923 T39924 T39925 T39926 T39927 T39928 T39929 KGSF 1A 50133101600100 220063 12/5/2024 HALLIBURTON EPX-MFC40 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.01.07 15:26:55 -09'00' By Anne Prysunka at 3:48 pm, Sep 15, 2022 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Install Cap String Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 6,650 feet N/A feet true vertical 6,637 feet N/A feet Effective Depth measured 6,511 feet 4,256'feet true vertical 6,497 feet 4,256'feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# / L-80 4,266' MD 4,266' TVD Baker ZXP Liner Top Pkr 4,256' MD 4,256' TVD Packers and SSSV (type, measured and true vertical depth)N/A N/A N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Contact Name: Contact Email: Authorized Title:Contact Phone: 4,328psi 6,000psi 3,070psi 5,792psi 6,744psi Burst Collapse 1,510psi 31' 2,032' 4,489' 6,627' 4,489' 6,640'4-1/2" measuredPlugs Junk measured N/A Length 31' 2,032' Size Conductor Surface Intermediate 20" 11-3/4" 7" Production Liner 4,489' 2,384' Casing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 220-063 50-133-10160-01-00 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: FEDA 082931 Swanson River / Tyonek 64-5 Gas Storage Pool Hilcorp Alaska LLC 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Swanson River KGSF #1A measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 0 0433 0 2,408 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 31' 2,032' 0 Structural TVD 321-011 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: Authorized Name and Digital Signature with Date: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 0 2,893 Ryan Rupert, Operations Engineer ryan.rupert@hilcorp.com 907-777-8503Dan Marlowe, ASC Team Operations Manager, 907-283-1329 t Fra O 6. A PG , R Form 10-404 Revised 10/2021 Submit Within 30 days of Operations By Meredith Guhl at 2:24 pm, Dec 10, 2021 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.12.10 14:13:00 -09'00' Dan Marlowe (1267) BJM 01/14/22 SFD 12/15/2021 RBDMS HEW 12/13/2021 DSR-12/10/21 Rig Start Date End Date Cap String 1/22/21 1/22/21 01/22/2021 - Friday Fire Capillary tubing truck. PTW JSA. Spot up on KGSF#1. Install capillary spool on truck. Rebuild pack off assembly and foot valve. Foot valve set to 2200 psi. Stab 3/8" cap tubing into injector head and pack off assembly. Make up foot valve below pack off. Pull test foot valve swedge lock to 1200 lbs. Remove KGSF#1 night cap. Stab on well. Hook up field triplex pump to Pack off pump in sub. Confirm swab closed online with field triplex 250 low. Good test. 3580 high PT. Bleed down. Open well RIH . WHP 277 psi. IA 50 psi, OA 0 psi. Attempt to RIH. Stacking 1000 lbs. Not able to RIH. Close master and swab. Pop off well. Pry foot valve out of pack off wellhead adapter. Stab on well. RIH lightly tag swab valve. PU off valve 2". Apply pack off pressure to 3000 psi. Pressure test wellhead connection 250/3680 psi. Good test. Bleed down and open well. RIH. (Previous PT, the foot valve was pulled into rubber elements. When pressure tested it was pushed in further causing extra force when attempting to RIH.) Run 3/8" capillary tubing to 2560'. Pick up in tension and stop at 2500' MD. Close manual lock downs. Apply 3500 psi pack off pressure and block in. Install 3/8" cap string hanger ontop of pack off assembly. Perform push/pull to ensure hanger is engaged. Pin hanger to top sub. Pull injector plates and drop chain tension. Remove cap string from injector head. Pick injector head off pack off assembly and set on back deck. Pick Cap string spool and set next to wellhead. Rig down Cap string truck. Install wellhouse with SL crane. Location secure. SDFN. Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name SRU KGSF #1A 50-133-10160-01-00 220-063 Updated by DMA 12-10-21 Swanson River Unit Well KGSF 1A PTD: 220-063 API: 50-133-10160-01-00 SCHEMATIC TD @ 6,650’ MD / 6,637’ TVD PBTD @ 6,511’ MD / 6,497’ TVD PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Size Date Status TY 64-5 6,395’ 6,404’ 6,382' 6,391' 9’ 2-7/8” 6 SPF 11/13/20 Open CASING DETAIL Size WT Grade Conn ID Top Btm 20” - - - Surface 31’ 11-3/4” 47 - - 11” Surface 2,032’ 7” 23,26,29 N-80 BTC 6.059” Surface 4,489’ 4-1/2” (tieback) 12.6 L-80 VAM Top 3.833” Surface 4,266’ 4-1/2” (liner) 12.6 L-80 DWC/C-HT 3.833” 4,256’ 6,640’ 20” 11-3/4” 7” 4-1/2” shoe @ 6,640’ JEWELRY DETAIL No Depth ID OD Item 7” Window Detail TOW @ 4489’ 1 4,256’ 5.800” Liner Top Packer 2 4,266’ 5.250” - Tieback Mule Shoe 1 OPEN HOLE / CEMENT DETAIL 4-1/2” 41 BBL’s of cement in 6” hole. TOC @ TOL – ~4,256’ – 10.5 bbls to circulated to surface 7” TOC @ 3,675’ 64-5 2 Capillary String 01/22/21 3/8” Stainless Steel Installed to 2,500’ David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt and return one copy of this transmittal or FAX to 907 564-4422 Received By: Date: Hilcorp North Slope, LLC Date: 06/23/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL: FTP Folder Contents: Log Print Files and LAS Data Files: Well API # PTD # Date Log Type SRU 11-22 50133206120000 213055 11/3/2020 PERF GAMMA RAY SRU 12-15 50133101380000 183032 10/14/2020 SET PLUG SRU 12-15 50133101380000 183032 10/21/2020 PERF GAMMA RAY SRU 213-15 50133206520000 215100 6/25/2020 PERF GAMMA RAY/GPT SRU 241-16 50133205400000 204088 10/13/2020 PERF GAMMA RAY SRU 241-16 50133205400000 204088 3/30/2021 PERF GAMMA RAY KGSF 1A 50133101600100 220063 11/13/2020 PERF GAMMA RAY Please include current contact information if different from above. 06/28/2021 Received By: 37' (6HW By Abby Bell at 12:21 pm, Jun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REPORTAPI No. 50-133-10160-01-00Well Name/No. SWANSON RIV UNIT KGSF 1ACompletion StatusGSTORCompletion Date11/13/2020Permit to Drill2200630Operator Hilcorp Alaska, LLCMD6650TVD6637Current StatusGSTOR2/9/2021UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:CBL 11-6-20, MWD/LWDNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF11/4/20204478 6650 Electronic Data Set, Filename: KGSF 1A LWD Final.las34185EDDigital DataDF11/4/2020 Electronic File: KGSF 1A LWD Final MD.cgm34185EDDigital DataDF11/4/2020 Electronic File: KGSF 1A LWD Final TVD.cgm34185EDDigital DataDF11/4/2020 Electronic File: KGSF 1A - Definitive Survey Report.pdf34185EDDigital DataDF11/4/2020 Electronic File: KGSF 1A Definitive Surveys.xlsx34185EDDigital DataDF11/4/2020 Electronic File: KGSF 1A.txt34185EDDigital DataDF11/4/2020 Electronic File: KGSF 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Date11/13/2020Permit to Drill2200630Operator Hilcorp Alaska, LLCMD6650TVD6637Current StatusGSTOR2/9/2021UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Compliance Reviewed By:Date:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date:11/13/2020Release Date:9/28/2020Tuesday, February 9, 2021AOGCCPage 2 of 2M. 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Please update the 10‐407 to reflect this or I can send a revision if that’s best. Thank you! Cody Dinger Hilcorp Alaska, LLC Drilling Tech 907‐777‐8389 From: David Douglas Sent: Tuesday, February 9, 2021 1:21 PM To: Guhl, Meredith D (CED) <meredith.guhl@alaska.gov> Cc: Bell, Abby E (CED) <abby.bell@alaska.gov>; Cody Dinger <cdinger@hilcorp.com> Subject: RE: [EXTERNAL] KGSF 1A, PTD 220‐063, mudlogs ‐ (Confirmed ‐ No Mudlogs Were Run) Hi Meredith, I confirmed with the Geologist that no Mudlogs were obtained. I’ve cc’d Cody, so he can send you an approval email to remove the Mudlogs form the 10‐407 logs run list. David Douglas Geotechnician | Hilcorp Alaska, LLC O: (907) 777-8337 | C: (907) 887-6339 3800 Centerpoint Drive, Suite 1400 | Anchorage, AK 99503 david.douglas@hilcorp.com From: Guhl, Meredith D (CED) [mailto:meredith.guhl@alaska.gov] Sent: Tuesday, February 9, 2021 11:35 AM To: David Douglas <David.Douglas@hilcorp.com> Cc: Bell, Abby E (CED) <abby.bell@alaska.gov> Subject: RE: [EXTERNAL] KGSF 1A, PTD 220‐063, mudlogs ‐ (Not Required??) Hi David, Hilcorp tends to run mudlogs on wells they drill in Cook Inlet, even if the mudlog is not required by the permit to drill. I assume that’s because many of the wells in the area are old, so getting fresh data is worth it to Hilcorp. Regulations 2 state that any log run, at any time during the life of a well, must be supplied, unless experimental or seismic, so if mudlogs are collected, they must be supplied, whether or not required by the PTD. Alaska Admin Code (state.ak.us) On the 10‐407 form Cody noted “CBL 11‐6‐20, MWD/LWD, Mudlogs”, hence my request for the mudlogs to be supplied. The compliance review begins with what is listed on the 10‐407 form. I do see we have not received cuttings, which also lends credence to the thought that the mudlog was not completed. If a mudlog was not run, I will need an email from Cody requesting an update to the 10‐407 form to remove mudlogs from the list of logs run. Thanks, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl@alaska.gov Direct: (907) 793‐1235 CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Meredith Guhl at 907‐793‐1235 or meredith.guhl@alaska.gov. From: David Douglas <David.Douglas@hilcorp.com> Sent: Tuesday, February 9, 2021 11:25 AM To: Guhl, Meredith D (CED) <meredith.guhl@alaska.gov> Cc: Bell, Abby E (CED) <abby.bell@alaska.gov> Subject: RE: [EXTERNAL] KGSF 1A, PTD 220‐063, mudlogs ‐ (Not Required??) Hi Meredith, I seemed to recall when this well was finishing up checking into that and I saw on the 10‐401 Mudlogging was not required. We do not have a copy of any Mudlog or any indications of that activity. I can go ask the Geologist and Vendors but before I do that can you see if this well was exempted from running Mudlogs from the AOGCC perspective. I only saw Mudlogs “not being required” on the 10‐401 picture shown below. At this point I am assuming Mudlogs were not acquired. I’ll dig deeper into it after I get your reply (if I need to do so). 3 David Douglas Geotechnician | Hilcorp Alaska, LLC O: (907) 777-8337 | C: (907) 887-6339 3800 Centerpoint Drive, Suite 1400 | Anchorage, AK 99503 david.douglas@hilcorp.com From: Guhl, Meredith D (CED) [mailto:meredith.guhl@alaska.gov] Sent: Tuesday, February 9, 2021 10:58 AM To: David Douglas <David.Douglas@hilcorp.com> Cc: Bell, Abby E (CED) <abby.bell@alaska.gov> Subject: [EXTERNAL] KGSF 1A, PTD 220‐063, mudlogs Hi David, KGSF 1A, PTD 220‐063 is coming up on 90 days after well completion (Feb 13) and the AOGCC has not received the mudlog data yet. If you have a chance to send it this week, it would be much appreciated. The other two datasets reported on the 10‐407‐ LWD and a CBL have been provided, thank you. 4 Thanks, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl@alaska.gov Direct: (907) 793‐1235 CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Meredith Guhl at 907‐793‐1235 or meredith.guhl@alaska.gov. 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Received By: Date: Date: 11/17/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL KGSF 1A (PTD 220-063) FINAL ALASKA E-LINE SERVICES Segmented Cement Bond Log (11-06-2020) Files: Please include current contact information if different from above. Received by the AOGCC 11/18/2020 PTD: 2200630 E-Set: 34286 Abby Bell 11/18/2020 David Douglas Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or fax to 907 777-8510. Received By: Date: Date: 11/04/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL KGSF 1A (PTD 220-063) FINAL LWD LOGS (27-OCT-2020): PCG-K, ADR, ALD, CTN (MD/TVD) AND DEFINITIVE DIRECTIONAL SURVEY Data Folders: Received by the AOGCC 11/04/2020 PTD: 2200630 E-Set: 34185 Abby Bell 11/05/2020 # EM / 2 § \ 2 LU \ (no k2— /\ o 0) m m/0) o = q z® 30 \\ ^ƒ 0 0 >UJ \ $E \ 2 00 m &_ $ g @CL Cl.* -E ®\ 7k 0)�� 2 °0 $// 0 ®®f E\ ) 0 .2 0 @ ® p O± O E 7 « \ /\ 3 /f / 2 -j -j < /2LL k \cz < 0 Ewe $o �w �/ƒ ±EI �� O� m6 2 v LU cn z o / _ 2 0 / \ c % k .ek E J O 4 0 � & \ C> ° \ £ E \ > E 6 c = 2 7$ 2» f\ƒ R 0 \k/\k/§��% 7/ LU 2» c 1 — _ _ E _ Et G>I mE =f _ 0i 0 0 2 0 ° E= m & o = %. o o 0 m o 4 0 Ea- m±< E U 0 3& 2 z 0 ( « � \ _ _ § c } 0 \ 7 ? / 7 a) \ R E / $ ƒ ƒ m 0 \ 2 2 ° G ° � \ \ \ / / $ 3 z ° n E ± _ \ \ « [ 0 ƒ ƒ ƒ / c ƒ7 m \/ \ § \ [ \ \ \ m m f \ 0 / \ -0 \ 2 ) \ \ 7 0) < e m 25- \ \ — m .\ _ > § \ / ® 0 = J o & 0) _= e a y : b/\ g/ a/ e= U n m= 0 0 44<£n -i65 () I2±2±U m _ 0 w 2 « d U U) 2 rill "gym Q m F- L) LU � � 0 Q m � L � � � LL m R 2 LU � � 0 Q OD f / 1.Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Initial Completion, N2 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 7,000'N/A Casing Collapse Structural Conductor Surface 1,510psi Intermediate 4,328psi Production 6,000psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12.Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Todd Sidoti Operations Manager Contact Email: Contact Phone: 777-8443 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: October 15, 2020 N/A ~7,000' Perforation Depth MD (ft): ~4,300' See Attached Schematic ~2,700'~7,000'4-1/2" 20" 11-3/4" 31' 7"~4,300' 2,032'3,070psi 31' 2,032' ~4,300' 31' 2,032' N/A TVD Burst N/A 6,744psi MD 5,792psi Length Size SIO - 2A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA 028399 220-063 50-133-10160-01-00 Swanson River KGSF #1A Swanson River / Tyonek 64-5 Gas Storage Pool COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic todd.sidoti@hilcorp.com 7,000'7,000'7,000'3,282 N/A Baker ZXP Liner Top Packer; N/A ~4,300' MD, ~4,300' TVD ; N/A Perforation Depth TVD (ft): Tubing Size: Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 3:15 pm, Oct 08, 2020 320-428 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.10.06 13:01:14 -08'00' Taylor Wellman SFD 10/9/2020 Perforate gls 10/16/20 Initial Completion, N2 * 4000 psi BOPE test (CTU) FEDA 082931 CTU SFD 10/8/2020 DSR-10/12/2020 SFD 10/8/2020 X 10-407 gas storage * Submit CBL , MIT-IA and OH logs for AOGCC review prior to Perforating well. Comm. 10/20/2020 dts 10/20/2020 RBDMS HEW 11/12/2020 Well Prognosis Well: KGSF #1A Date: 9/30/2020 Well Name: KGSF #1A API Number: 50-133-10160-01-00 Current Status: Gas Storage Well Leg: N/A Estimated Start Date: October 15, 2020 Rig: 147 Reg. Approval Req’d? 10-403 Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 220-063 First Call Engineer: Todd Sidoti (907) 777-8443 (O) (907) 632-4113 (M) Second Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (M) AFE Number: 2013214C Bottom Hole Pressure: 3,981 psi @ 6985’ TVD (Based upon Estimated Bottom hole Storage Pressure) Max. Potential Surface Pressure: 3,282 psi (Based upon Max. Expected BHP minus 0.1 PSI/ft. gas gradient to surface Brief Well Summary: KGSF # 1A is a gas storage well that that Hilcorp sidetracked from the KGSF #1 gas storage well due to wellbore damage in the parent bore storage sand. The purpose of this Sundry is to complete the well for gas storage injection and production. Current Well Condition: x Well was sidetracked from KGSF #1 at ~4,500’. x 4-1/2” liner ran to ~7,000’ MD and cemented, liner top packer at ~4,300’. x 4-1/2” liner was cleaned out to TD, Pressure tested to 3500 psi, and well displaced to 6% KCL brine. x Follow BOP test schedule as outlined in Permit to Drill. Rig 147 (Continued from PTD 220-063) 1. Make up Baker Tandem Mill assembly to clean and dress 5.25” liner top seal bore per vendor recommendation. 2. RIH to ~6’ above PBR, rotate at 20 RPM at 2 BPM pump rate, slowly lower bottom mill into the PBR. 3. Dress PBR and liner top per vendor recommendation. 4. POOH and inspect mill assembly for wear mark on top dressing mill. 5. Make up Baker 5.25” bullet seal assembly to 4-1/2” VAM Top casing. 6. RIH with 4-1/2” tie back casing to +/-40’ above liner top extension. 7. Circulate at 1 BPM and slowly lower seals into seal bore – pump pressure will spike when seals engage in seal bore – shut off pump immediately and mark pipe. 8. Slack off to place the seals into the top of the PBR extension per vendor recommendation (~7’). 9. Pressure test tieback seal assembly to 1000 psi by pressuring down the tieback casing. 10. Pick up and pull tieback seal assembly out of the PBR extension. 11. Prep space out for landing hanger. 12. Displace annulus volume to corrosion inhibited fluid. 13. Pick hanger and land out tieback string. 14. Pressure test tieback seal assembly to 1000 psi by pressuring down the tieback casing. 15. Pressure test (MIT-IA) 4-1/2” x 7” annulus to 1500 psi charted for 30 minutes. a. Contact AOGCC 24 hours prior to performing test to allow for option to witness. 16. MIRU E-line and run CBL in 4-1/2” liner from TD to 300’ above liner top packer. a. Submit CBL log to AOGCC. (not spudded as of 10/16/20 gls) Proposed operations per PTD Need to see CBL log before allowing perforations .(Email PDF of CBL to AOGCC) Pressure tested to 3500 4 1/2" tieback tubing Pressure test (MIT-IA) 4-1/2” x 7” annulus to 1500 psi charted for 30 minutes. a.Contact AOGCC 24 hours prior to performing test to allow for option to witness. 16.MIRU E-line and run CBL in 4-1/2” liner from TD to 300’ above liner top packer. a.Submit CBL log to AOGCC. Well Prognosis Well: KGSF #1A Date: 9/30/2020 17. RDMO E-line. 18. ND BOPE & NU test tree. 19. RDMO location. Coiled Tubing Procedure 1. MIRU coiled tubing, PT BOPE to 250 psi low / 4000 psi high. a) Notify AOGCC 24 hrs in advance of BOP test to allow for option to witness. 2. MIRU N2 pumping unit. a) Review standard nitrogen pumping procedure with all personnel. 3. MU BHA including jet swirl nozzle. 4. RIH and come online with N2 and jet well dry. a) Estimated volume of displaced 6% KCl is ~170 bbls. (Based on estimated PBTD of +/-7,000’). 5. Once well is dry trap 3000 psi on the casing for perforating. 6. POOH. 7. RDMO coiled tubing. E-Line Procedure 1. MIRU E-line and pressure control equipment. PT lubricator to 250 psi low / 3600 psi high. Note that the well is pressurized with nitrogen. a) If necessary, bleed pressure down as requested by the OE. 2. PU RIH W/perf guns. Perforate each interval with 2-7/8” perf guns 6 SPF 60 degree phasing. 3. Proposed Perforated Intervals: Sand MD Top MD Bottom Total Footage (MD) TVD Top TVD Bottom Pressure TY 64-5 ~6,340' ~6,460’ ~120' ~6,170' ~6,275 3600 psi a) Proposed perforations are also shown on the proposed schematic in red font. b) Final Perforation tie-in sheet will be provided in the field for exact perforation intervals. c) Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer (Meredyth Richards), and Geologist (Jeff Nelson) for confirmation. d) Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures at 5, 10, and 15 minute intervals after firing gun. e) The listed Sand is governed by SIO 2A. Attachments: Current Schematic Proposed Schematic Coil Tubing BOP Schematic Standard Nitrogen Procedure 3600 TY 64-5 ~6,340'~6,460’ ~120'~6,170' ~6,275 (CT Nitrogen displacement) Review standard nitrogen pumping procedure with all personnel. Notify AOGCC 24 hrs in advance of BOP test to allow for option to witness. 2.MIRU Updated by DMA 09-16-20 SCHEMATIC Swanson River Field Well: KGSF #1 / PTD 161-008 API: 50-133-10160-00-00 Last Completed: 09-09-11 PBTD = 4,503’/ TD = 10,875’ MAX HOLE ANGLE = 1.25° @ 4,565’ RKB = 15’ CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. 20” - - - 15’ 31’ 11-3/4” 47 - - 11.00 Surface 2,032’ 7” 29 N-80 BTC 6.184 Surface 243’ 7” 26 N-80 BTC 6.276 243’ 883’ 7” 23 N-80 BTC 6.366 883’ 4,626’ 7” 26 N-80 BTC 6.276 4,626’ 6,470’ 7” 29 N-80 BTC 6.184 6,470’ 8,315’ 7” 29 P-110 8RD 6.184 8,315’ 10,875’ Tubing 3-1/2” 9.3 L-80 Hydril 503 2.992 surface 503’ 3-1/2” 9.3 L-80 Hydril 503 2.992 6,210 6,356’ JEWELRY DETAIL NO. Depth ID OD Item 1 4,503’ CIBP 9/10/20 2 6,167’ CIBP w/ 548’ cmt (TOC @ 5,619’) 9/10/20 3 6,244’ 2.870” 5.983” Baker Premier Packer 4 6,297’ 2.813” 3.940” X Nipple 5 6,356’ 2.992” 3.500” WLEG, Auto Release 6 ±6,507’ - 4.630” TCP Guns (length 32.76’) Gun release not verified PERFORATION HISTORY (Tyonek Perfs TDT Log Depth) Interval Accum. Date Zone Top Btm Amt spf Comments 9/8/2011 64-5 6,380' 6,388' 8' 5 Reperf 4-5/8" Millenium TCP guns, 5spf, 60 deg 12/3/1998 64-5 6,380' 6,388' 8' 4 1-11/16" Pivot, 180 deg. 7/26/1998 68-0 6,883' 6,911' 28' 4 Abandoned 6/20/1961 - 10,615' 10,616' 1' 5 Abandoned 6/21/1961 H-1 10,617' 10,631' 14' 4 Abandoned 6/21/1961 H-2 10,642' 10,656' 14' 4 Abandoned 6/21/1961 H-4/5 10,664' 10,752' 88' 4 Abandoned 6/20/1961 - 10,752' 10,754' 2' 5 Abandoned J D K F G H I Notes NO. Depth Item K 7,114’ 7” Stage Collar ABANDONMENT DETAIL NO. Depth ID OD Item A 6,615’ - - EZ Squeeze Packer w/ 75’ cement on top B 6,652’ - - Fish: 2 Baker K-1 Retainers C 6,850’ - - PosiSet Plug w/ 37’ Cement D 9,015’ - - Tubing cut at 9,015’ WLM. E 9,733’ - - Top of Cement Plug. Pressure tested to 2,500 psi. F 10,473’ - - Camco “MM” Mandrel with CEV Valve G 10,519’ - - Brown CC Safety Joint H 10,530’ - - Brown, 2-7/8” x 7”, Type HS-16-1 Packer I 10,600’ - - Camco “D” Nipple J ? - - Venturi Shoe D E C TOC @ 9,100’ TOC @ 6,813’ 1 5 6 TOC @ 3,675’ 11-3/4” 4 Top of fill @ 6,655’ 3 A TOC @ 6,540’ B 64-5 CIBP @ 4,503’ 9/10/20 3-1/2” tubing cut at 6,210’ 9/4/20 Fill tagged at 6,388’ 2 Updated by TCS 10-5-20 Swanson River Unit Well KGSF 1A PTD: 220-063 API: 50-133-10160-01-00 PROPOSED SCHEMATIC TD @ 7,000’ MD / 6,985’ TVD PBTD @ 6,880’ MD / 6,865’ TVD PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status TY 64-5 ±6,340’ ±6,460’ ±6,170' ±6,275' 120 Proposed Open CASING DETAIL Size WT Grade Conn ID Top Btm 20” - - - Surface 31’ 11-3/4” 47 - - 11” Surface 2,032’ 7” 23,26,29 N-80 BTC 6.059” Surface ±4,500’ 4-1/2” 12.6 L-80 VAM Top 3.833” Surface ±4,300’ 4-1/2” 12.6 L-80 DWC/C-HT 3.833” ±4,300’ 7,000’ 20” 11-3/4” 7” 4-1/2” shoe @ 7,000’ JEWELRY DETAIL No Depth ID OD Item 7” Window Detail TOW @ ±4,500’ 1 4,289’ 5.25” 11.23’ PBR 2 4,300’ 4.190” - 7” X 4-1/2” ZXP liner hanger 1 OPEN HOLE / CEMENT DETAIL 4-1/2” 45 BBL’s of cement in 6” hole. Est. TOC @ TOL – ~4,300’ (10% excess) 7” TOC @ 3,675’ 64-5 2 KGSF 1 P&A 4 1/2" tieback Coiled Tubing Services Pressure Category 1 BOP Configuration (0-3,500 psi) Client: Hilcorp Date: April 3rd, 2017 Drawn: Chad Barrett Revision: 0 Well Category: CAT I 4-1/16" 10K Combi BOP Top Set: Blind/Shear Second Set: Pipe/Slip Wellhead 4-1/16" 10K Conventional Stripper 4-1/16" 10K x Wellhead Adapter Flange 5K CO62 x 4-1/16" 10K Flange 5K CO62 Lubricator 4-1/16" 10K Flow Cross Manual 2x2 Valve 1: 2" 1502 x 2-1/16" 10K Flange Manual 2x2 Valve 2: 2-1/16" 10K x 2-1/16" 10K Flange Manual 2x2 Valve 3: 2-1/16" 10K x 2-1/16" 10K Flange Manual 2x2 Valve 4: 2" 1502 x 2-1/16" 10K Flange 21 3 4 WH PSI 2" 1502 x 2-1/16 10K Flanged Valve (Manual) 2-1/16 10K x 2-1/16 10K Flanged Valve (Manual) Kill Port Coiled Tubing HR580 Injector Head & Gooseneck Weight = 12,850 lbs Swanson River Field KGSF #1A 10/6/2020 STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Monty M Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Swanson River Field, Tyonek 64-5 Gas Storage Pool, KGSF 1A Hilcorp Alaska, LLC Permit to Drill Number: 220-063 Surface Location: 2193’ FSL, 518’ FEL, Sec 28, T8N, R9W, SM, AK Bottomhole Location: 2024' FSL, 511' FEL, Sec 28, T8N, R9W, SM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to redrill the above referenced service well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jeremy M. Price Chair DATED this ___ day of September, 2020. 28 Jeremy M. Price Digitally signed by Jeremy M. Price Date: 2020.09.28 12:15:04 -08'00' 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 7,000' TVD: 6,985' 4a. Location of Well (Governmental Section):7. Property Designation: Surface: Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date: Total Depth:9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 174' 15. Distance to Nearest Well Open Surface: x-347199 y- 2468635 Zone-4 155' to Same Pool: 125' KGSF 7A 16. Deviated wells:Kickoff depth: 4,500 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 12 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 6" 4-1/2" 12.6# L-80 DWC/C 2,700' 4,300' 4,300' 7,000' 6,985' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): 6,507' TVD 31' 2,032' 10,875' Hydraulic Fracture planned?Yes No 20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number:50- Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Sr Pet Eng Sr Pet Geo Sr Res Eng 2106' to nearest unit boundary 9/15/2020 Authorized Name: Monty Myers Authorized Title: Drilling Manager Monty Myers mmyers@hilcorp.com 777-8431 18. Casing Program:Top - Setting Depth - BottomSpecifications KGSF #1A Swanson River Unit Tyonek 64-5 Sand 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp Alaska, LLC 2193’ FSL, 518’ FEL, Sec 28, T8N, R9W, SM, AK A028399 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 3282 2024' FSL, 511' FEL, Sec 28, T8N, R9W, SM, AK 2024' FSL, 511' FEL, Sec 28, T8N, R9W, SM, AK N/A 1760 3981 Total Depth MD (ft):Total Depth TVD (ft): Cement Quantity, c.f. or sacks Cement Volume MDSize Plugs (measured): (including stage data) 265 ft3 6,507'6,507' Effect. Depth TVD (ft): Conductor/Structural 20"31' 10,875'10,875' Length 31' 2,032'11-3/4" Production Liner 10,875' Casing N/A Intermediate 2,032' 7" Commission Use Only 1290 sx Effect. Depth MD (ft): Authorized Signature: 10,875' See cover letter for other requirements. Perforation Depth MD (ft): 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft): GL / BF Elevation above MSL (ft): 6,380' - 6,388'6,380 - 6,388' 1800 sx es N ype of W L l R L 1b S Class: os N es No s N o D s s s D 84 o : well is p G S S 20 S S S es No s No S G E S es No s Form 10-401 Revised 3/2020 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) 8.21.2020 By Samantha Carlisle at 12:25 pm, Aug 21, 2020 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2020.08.21 11:58:22 -08'00' Monty M Myers SFD 8/25/2020 SIO 2A needs to be amended to authorize this well before injection can commence. Gas Storage Pool DSR-8/27/2020 220-063 50-133-10160-01-00 SFD 9/23/2020 X gls9 /25/20 + Rig inspection required before spudding well. +3500 psi BOPE test + Sundry required to run completion (CBL and MIT-IA required) Service - SupplyS 9/28/2020 9/28/2020Jeremy M. Price Digitally signed by Jeremy M. Price Date: 2020.09.28 12:16:29 -08'00' AA-082931 SFD 9/30/2020 Redacted 2/9/2021 M. Guhl Area of Review KGSF #1A TY 64-5PTD API WELL STATUSTop of Ty 64-5 (MD)Top of Ty 64-5 (TVD)CBL Top of Cement (MD)CBL Top of Cement (TVD)Ty 64-5 statusZonal Isolation204-081 50-133-20538-00-00 KGSF 7 P&A'd6,662' 6,369'2,107' (Plug)2,107' P&A'dP&A'd204-163 50-133-20538-01-00 KGSF 7A Active Gas Storage 6,366'6,366'1,950'1,950'OpenOpen in Ty 64-5161-008 50-133-10160-00-00 KGSF 1 Shut in Gas Storage6,370' 6,370' 3,675' 3,675' Open/Will be P&AdPerfs to be squeezed with cement as a part of the P&A to sidetrack the well.(per sundry 320-357) KGSF #1A (SRU 43-28 ST) Drilling Program Swanson River Revision 0 August 17, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 Contents 1.0 Well Summary ........................................................................................................................... 2 2.0 Management of Change Information ........................................................................................ 3 3.0 Tubular Program ....................................................................................................................... 4 4.0 Drill Pipe Information ............................................................................................................... 4 All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). 4 5.0 Internal Reporting Requirements ............................................................................................. 5 6.0 Planned Wellbore Schematic ..................................................................................................... 6 7.0 Drilling Summary ...................................................................................................................... 7 8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8 9.0 R/U and Preparatory Work ..................................................................................................... 11 10.0 BOP N/U and Test.................................................................................................................... 12 11.0 Mud Program and Density Selection Criteria ........................................................................ 13 12.0 Whipstock Running Procedure ............................................................................................... 14 13.0 Whipstock Setting Procedure .................................................................................................. 17 14.0 Drill 6” Hole Section ................................................................................................................ 19 15.0 Run 4.5” Production Liner ...................................................................................................... 20 16.0 Cement 4.5” Production Liner ................................................................................................ 23 17.0 Wellbore Clean Up & Displacement ....................................................................................... 27 18.0 Run Completion Assembly ...................................................................................................... 28 19.0 RDMO ...................................................................................................................................... 28 21.0 BOP Schematic ........................................................................................................................ 29 22.0 Wellhead Schematic ................................................................................................................. 30 23.0 Days vs Depth ........................................................................................................................... 31 24.0 Geo-Prog .................................................................................................................................. 32 25.0 Anticipated Drilling Hazards .................................................................................................. 34 26.0 Rig Layout ................................................................................................................................ 35 27.0 FIT Procedure .......................................................................................................................... 36 28.0 Choke Manifold Schematic ...................................................................................................... 37 29.0 Casing Design Information ...................................................................................................... 38 30.0 6” Hole Section MASP ............................................................................................................. 39 31.0 Plot (NAD 27) (Governmental Sections) ................................................................................. 40 32.0 Surface Plat (As Built) (NAD 27&83) ...................................................................................... 41 33.0 Directional Program (WP 03) .................................................................................................. 42 Page 2 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 1.0 Well Summary Well KGSF #1A (SRU 43-28 ST) Pad & Old Well Designation Sidetrack of existing well KGSF #1 (SRU 43-28) (PTD# 161-008) Planned Completion Type 4-1/2” 12.6# L-80 Liner Target Reservoir(s) Tyonek 64-5 Gas Storage Sand Planned Well TD, MD / TVD 7000’ MD / 6985’ TVD PBTD, MD / TVD 6880’ MD / 6865’ TVD Surface Location (Governmental) 2193’ FSL, 518’ FEL, Sec 28, T8N, R9W, SM, AK Surface Location (NAD 27) X=347199.28, Y=2468635.12 Surface Location (NAD 83) X=1487222.34, Y=2468396.50 Top of Productive Horizon (Governmental) 2024' FSL, 511' FEL, Sec 28, T8N, R9W, SM, AK TPH Location (NAD 27) X=347203.56, Y=2468472.69 TPH Location (NAD 83) X=1487226.61, Y=2468234.06 BHL (Governmental) 2024' FSL, 511' FEL, Sec 28, T8N, R9W, SM, AK BHL (NAD 27) X=347203.56, Y=2468472.69 BHL (NAD 83) X=1487226.61, Y=2468234.06 AFE Number 2013214D AFE Drilling Days 16 AFE Drilling Amount $3.00 MM Work String 4-1/2” 16.6# S-135 CDS-40 RKB – AMSL 18’ KB – 155.6’ AMSL Ground Elevation 155.6’ AMSL BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram (using rig 147 out of cold stack) Rig 147 will drill well. Coming out of cold stack. gls Page 3 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 2.0 Management of Change Information Page 4 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 3.0 Tubular Program Hole Section OD (in) Wt (#/ft) Coupl OD ID (in) Drift (in) Grade Conn Top Bottom 6” 4-1/2” 12.6 5.0” 3.918 3.833 L-80 DWC/C 4300 7000 4.0 Drill Pipe Information Hole Section OD (in) ID (in) TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) 6” 4-1/2” 3.826 2-11/16” 5-1/4” 16.6 S-135 CDS-40 17693 16769 595k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 5 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 5.0 Internal Reporting Requirements 19.1 Fill out daily drilling report and cost report on Wellez. 1. Report covers operations from 6am to 6am 2. Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry tab. 3. Ensure time entry adds up to 24 hours total. 4. Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. 19.1 Afternoon Updates 1. Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp.com, Frank.Roach@hilcorp.com, and cdinger@hilcorp.com 19.1 Intranet Home Page Morning Update 1. Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. Each rig will be assigned a username to login with. 19.1 EHS Incident Reporting 1. Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don’t wait until an emergency to have to call around and figure it out!!!! a. John Coston: O: (907) 777-6726 C: (907) 227-3189 b. Matt Hogge: O: (907) 777-8418 C: (907) 227-9829 2. Spills: Keegan Fleming: O:907-777-8477 C:907-350-9439 2. Notify Drlg Manager 1. Monty M Myers: O: 907-777-8431 C: 907-538-1168 3. Submit Hilcorp Incident report to contacts above within 24 hrs 19.1 Casing Tally 1. Send final “As-Run” Casing tally to mmyers@hilcorp.com, Frank.Roach@hilcorp.com, and cdinger@hilcorp.com 19.1 Casing and Cmt report 1. Send casing and cement report for each string of casing to mmyers@hilcorp.com, Frank.Roach@hilcorp.com, and cdinger@hilcorp.com Page 6 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 6.0 Planned Wellbore Schematic (7"WIndowat4500ft) KGSF 1 (P &A ) 320- 357 sundry approved Page 7 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 7.0 Drilling Summary KGSF #1A (SRU 43-28 ST) is a gas storage well planned to be re-drilled in a Southerly direction from the existing KGSF #1 utilizing the existing casing program down to 4500’ MD / 4500’ TVD. At 4500 ’ MD the parent wellbore will be sidetracked and new wellbore drilled penetrating several Tyonek sands. A 2500’ x 6” open hole section is planned. A 4-1/2” 12.6# L-80 DWC/C prod liner will be run, cemented, and perforated based on data obtained while drilling the interval. The well will be completed with 4-1/2” tieback string. Drilling operations are expected to commence approximately September 15th, 2020. All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. A separate sundry notice will be submitted to cover P&A and wellbore preparation for the sidetrack and for running the completion assembly General sequence of operations pertaining to this approved drilling procedure: 1. PU 6.059” window milling assembly and DP and cleanout to CIBP at ~4500’ 2. POOH standing back, PU Whipstock, and mills and TIH to CIBP 3. Set down and set whipstock. 4. Mill 6” window and 20’ of new formation at 4500’. 5. POOH and LD mills. PU directional BHA and TIH to window. 6. Swap well to 9.5 ppg drilling mud 7. Perform FIT to 12.5 ppg EMW 8. Drill 6" production hole from 4500’ to 7000’ MD, performing short trips as needed 9. Perform short trip and condition mud. POOH 10. LD Directional Tools. RIH w 4-1/2" liner. Set liner and cement. Circ wellbore clean. 11. POOH, laying down DP and liner running tools, 12. PU 4-1/2” casing scraper assembly and TIH to land ing collar. 13. Circ casing clean. POOH laying down DP. 14. Run 4-1/2” tieback completion. Land hanger and test. 15. ND BOPE, NU tree and test void 16. RDMO ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- (replacing KGSF #1) #320-357 plug for redrill sundry start sidetrack under PTD 220-063 Page 8 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC and BLM regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling of KGSF #1 ST (SRU 43-28 ST). Ensure to provide AOGCC 24 hrs notice prior to testing BOPs, and provide BLM 48 hours notice prior to testing BOPE. x The initial test of BOP equipment will be to 250/3500 psi & subsequent tests of the BOP equipment will be to 250/3500 psi for 10/10 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation, we must test ALL BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system” x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements” x Ensure both AOGCC and BLM approved drilling permit is posted on the rig floor and in Co Man office. Variance Requests: x Onshore Oil and Gas Order No. 1, Section III. D. 3. C. o Hilcorp requests approval to install a 2-1/16” 5M HCR valve on kill line in lieu of a check valve. Operator suspects a freeze plug risk associated with installation of a check valve in the kill line. o Hilcorp requests approval to utilize flexible choke and kill lines in lieu of hard piping. Page 9 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 6” x 11” x 5M Annular BOP x 11” x 5M Double Ram o Blind ram in btm cavity x Mud cross x 11” x 5M Single Ram x 3-1/8” 5M Choke Line x 2-1/16” x 5M Kill line x 3-1/8” x 2-1/16” 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3500 (Annular 2500 psi) Subsequent Tests: 250/3500 (Annular 2500 psi) x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Required BLM Notifications: x 48 hours before spud. Follow up with actual spud date and time. x 48 hours before casing running and cmt operations x 48 hours before BOPE tests x 48 hours before logging, coring, & testing x Any other notifications required in APD. Additional requirements may be stipulated on APD. Page 10 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov Guy Schwartz / Petroleum Engineer / (O): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email: victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) BLM Amanda Eagle / BLM Petroleum Engineer / (O): 907-271-3266 (C): 907-538-2300 Email: aeagle@blm.gov Mutasim Elganzoory / BLM Petroleum Engineer / (O): 907-271-4224 Email: melganzoory@blm.gov Use the below email address for BOP notifications to the BLM: BLM_AK_AKSO_EnergySection_Notifications@blm.gov Page 11 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 9.0 R/U and Preparatory Work 9.1 Separate sundries will be submitted that will include the following: x P&A lower perfs with a cement retainer and leaving 5 bbls cement on top of plug (Rig 401) x Set CIBP at ~4500’ TMD (5’ above nearest collar using CCL) 9.2 Level pad and ensure enough room for layout of rig footprint and R/U. 9.3 Layout Herculite on pad to extend beyond footprint of rig. 9.4 R/U Hilcorp Rig #147, spot service company shacks, spot & R/U company man & toolpusher offices. 9.5 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.6 Mix mud for 6” hole section. 9.7 Check wellhead for pressure 9.8 Load well with 8.4 ppg KWF 9.9 Set BPV 9.10 Nipple down tree 9.11 Set test Plug in wellhead prior to N/U BOP to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.12 Verify 5” liners installed in mud pumps. x HHF-1000 Pumps are rated at 3457 psi (80%) with 5” liners and can deliver 306 gpm at 120 spm. This will allow us to drill the 6” hole section with (1) mud pump. Kick off plug for Whipstock (#320-357) Page 12 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 10.0 BOP N/U and Test 10.1 N/U 11” x 5M BOP as follows: x BOP configuration from Top down: 11” x 5M annular BOP/11” x 5M double ram/11” x 5M mud cross/11” x 5M single ram. x Double ram should be dressed with 2-7/8” x 5” VBR in top cavity, blind ram in btm cavity. x Single ram should be dressed with 2-7/8” x 5” VBR. x N/U bell nipple, install flowline. 10.2 Run BOP test assy, land out test plug (if not installed previously). x Test BOP to 250/3500 psi for 10/10 min. Test annular to 250/2500 psi for 10/10 min. x Ensure to leave “A” section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. Confirm the correct valves are opened!!! x Test VBRs on 4-1/2” test joint. x Ensure gas monitors are calibrated and tested in conjunction w/ BOPE. 10.3 R/D BOP test assy. 10.4 Continue mixing mud for 6” hole section. 10.5 Set wearbushing in wellhead. Ensure ID of wearbushing > 7”. 3500 psi BOPE test Page 13 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 11.0 Mud Program and Density Selection Criteria 11.1 6” Production hole mud program summary: Primary weighting material to be used for the hole section will be Calcium Carbonate to minimize solids. We will have barite on location to weight up the active system 1ppg above highest anticipated MW in the event of a well control situation. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. System Type: 9.0 ppg 6% KCl/PHPA fresh water based drilling fluid. Properties: MD Density Viscosity Plastic Viscosity Yield Point pH API Fluid Loss 4500’ – 7000’ 9.0-10.5 40-53 15-25 15-25 8.5-9.5 6.0 System Formulation: 6% KCl / EZ Mud DP Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROTROL PLUS SOLTEX BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 10-20 ppb 2 ppb 2 ppb (if needed) as required for a 9.0 – 10.5 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 11.2 Program mud weights are generated by reviewing data from producing & shut in offset wells, estimated BHP’s from formations capable of producing fluids or gas and formations which could require mud weights for hole stabilization. 11.3 A guiding philosophy will be that it is less risky to weight up a lower weight mud than be overbalanced and have the challenge to mitigate lost circulation while drilling ahead. NOTE: Pason Mud weight contingency in event BHP > 10.5 9.0-10.5 Primar y weighting material to be used for the hole section will be Calcium Carbonate toyygg minimize solids. We will have barite on location to weight up the active system 1ppg abovegp highest anticipated MW in the event of a well control situation.nti Barite on location to allow weighting up to 11.5 ppg Page 14 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 12.0 Whipstock Running Procedure 12.1 M/U window milling assembly and TIH w/ 4-1/2” DP out of derrick. x Use a 6” taper mill and a 6” string mill above to ensure whipstock assy will pass freely. x Ensure BHA components have been inspected previously. x Caliper and drift all BHA components before running them in the hole. x Drift DP prior to RIH. x Lightly wash and ream any tight spots noted. 12.2 TIH to CIBP (~4500’ MD). Note that this was a wireline measurement so actual depth tagged may vary slightly. Keep up with the # of joints picked up so we know where we are. 12.3 Pressure test casing to 1600 psi / 30 min. Chart record casing test & keep track of the amount of fluid pumped. Stage up to 1600 psi in 200 psi increments. 12.4 CBU & circ at least (1) hi-vis sweep to remove any debris created by the clean out run. Anything left in the wellbore could affect the setting of the Whipstock. 12.5 TOH. 12.6 Make up mills on a joint of HWDP. 12.7 RIH & set in slips. 12.8 Make up float sub, install float. 12.9 Leave assembly hanging in the elevators, and stand back on floor. 12.10 Bring Whipstock to rig floor on the pipe skate. Do not slam into bottom of Whipstock with pipe skate. 12.11 Pick up Whipstock per Baker rep using the Baker Whipstock handling system using air hoist. Allow assy to hang while Baker Rep inspects and removes shear screws as needed and any safety screws. Note: Anchor should be pinned with 6 shear screws initially. Shear screws are rated for 6,630 lbs each. REMOVE 3 screws for a set down shear of 6,630 x 3 = 19,890 lbs. Note: Attach mills to Whipstock with (1) 35k mill shear bolt. 12.12 If needed, open BOP Blinds. 12.13 Run the Whipstock in the hole, install safety clamp as per Baker Rep, and install hole cover wrap. Page 15 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 12.14 Release pick up system at this point, Make up mills. 12.15 With the top drive, pick the assembly and position the starting mill to align with the hole in the slide. The Baker Rep will instruct the driller when the slot is lined up, the shear bolt then can be made up by the Baker Rep. 12.16 The assembly can now be picked up to ensure that the shear bolt is tight. 12.17 Remove the handling system. 12.18 Slowly run in the hole as per Baker Rep. Run extremely slow through the BOP & wear bushing. 12.19 Run in hole at 1 ½ to 2 minutes per stand. 12.20 Fill every 30 stands or as needed, do not rotate or work the string unnecessarily. 12.21 Call for Baker Rep. 15 – 10 stands before getting to bottom. Page 16 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 WindowMaster G2 System on TorqueMaster BTA 7” 29# Csg – WindowMaster G2 On BTATA BHA #1 Connection Length O.D. BOTTOM TRIP ANCHOR 3 ½ IF-Box X Bottom Guide 3.21’ 6.18” WINDOW MASTER WHIPSTOCK Shear Bolt X 3 ½ IF-Pin 14.6’ 6.00” WINDOW MILL 3-1/2 Reg-Pin X Mill 1.5’ 6.63” LOWER WATER MELON MILL 3-1/2 IF-Box X 3-1/2 Reg-Box 5.5’ 6.50” FLEX JOINT 3-1/2 IF- Box X 3-1/2 IF-Pin 6.6’ 4.75” UPPER WATER MELON MILL 3-1/2 IF- Box X 3-1/2 IF-Pin 5.8’ 6.63” 1 JT HWDP 3-1/2 IF-Box X 3-1/2 IF-Pin 30’ 5.25” MWD Survey Tool 3-1/2 IF-Box X 3-1/2 IF-Pin 3’ 4.75” UBHO 3-1/2 IF-Box X 3-1/2 IF-Pin 3’ 4.75” Bowen Lubricated Bumper Jar 3-1/2 IF-Box X 3-1/2 IF-Pin 15’ 4.75" 6 DRILL COLLARS 3-1/2 IF-Box X 3-1/2 IF-Pin 180’ 4.75” 30 JTS – HWDP 4-1/2 CDS40 Box X 4-1/2 CDS40-Pin 900’ 4.75” CONNECTIONS ON TUBULARS ARE SUBJECT TO CHANGE. BHA’S SHOW SPECIFIC CONNECTIONS AS AN EXAMPLE ONLY Page 17 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 13.0 Whipstock Setting Procedure 13.1 Note: Whipstock orientation is not critical on this well. 13.2 With the bottom of the Whipstock 30 – 45’ above the CIBP, measure and record P/U and S/O weights. 13.3 Slack off and tag CIBP to set Bottom Trip Anchor. 13.4 Set down 12-15K on anchor to trip, P/U 5-7K maximum overpull to verify anchor is set. The window mill can then be sheared off by slacking off weight on the Whipstock shear bolt. (25k shear value). 13.5 P/U 5-10’ above top of Whipstock. 13.6 Displace to 9.5 ppg 6% KCl/PHPA drilling fluid. 13.7 Record P/U, S/O weights, and free rotation. Slack off to top of whipstock and with light weight and low torque. Mill window. Utilize 4 ditch magnets on the surface to catch metal cuttings. 13.8 Install catch trays in shaker underflow chute to help catch iron. 13.9 Keep iron in separate bbls. Record weight of iron recovered on ditch magnets. 13.10 Estimated metal cuttings volume from cutting window: 7” 29# N-80 Cuttings Weight Window Length Casing Weight Min (lbs) Avg (lbs) Max (lbs) 13 29# 80 110 140 13.11 Drill approx. 20’ rat hole to accommodate the drilling assembly. Ream window as needed to assure there is little or no drag. After reaming, shut off pumps and rotary (if hole conditions allow) and pass through window checking for drag. 13.12 Circulate Bottoms Up until MW in = MW out. 13.13 Conduct FIT to 12.5 ppg EMW. ________________________________________________________________________________________________________ ___ (submit FIT data to AOGCC by email) Start Sidetrack FIT 12.5 ppg _ Page 18 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 x (12.5 – 9.0) * 0.052 * 4500’ tvd = 819 psi 13.14 Kick Tolerance x (12.5 -9.0) * (4500/6985) = 2.25 Note: Offset field test data predicts frac gradients at the window to be between 12 ppg and 15 ppg. A 12.5 ppg FIT results in a 2.25 ppg kick tolerance while drilling the interval with a 9.0 ppg fluid density. 13.15 Slug pipe and POOH. Gauge Mills for wear. 13.16 Should a second run be required pick up the following BHA. Back Up Mills Connection Length O.D. WINDOW MILL 3 ½ REG-P X MILL 0.98 6.63 NEW LOWER WATERMELON MILL 3 ½ IF-B X 3 ½ REG-B 5.5 6.5 FLEX JOINT 3 ½ IF-B X 3 ½ IF-P 6.5 4.75 UPPER WATERMELON MILL 3 ½” IF-B X 3 ½” IF-P 5.83 6.63 FLOAT SUB 3 ½” IF-B X 3 ½” IF-P 3.00 4.75 XO sub and 30 jts-HWDP 4 ½” CDS40-B X 3 ½” IF-P 900’ 5.25 CONNECTIONS ON TUBULARS ARE SUBJECT TO CHANGE. BHA’S SHOW SPECIFIC CONNECTIONS AS AN EXAMPLE ONLY! Page 19 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 14.0 Drill 6” Hole Section 14.1 P/U 6” directional drilling assy. 14.2 Ensure BHA Components have been inspected previously. 14.3 Drift & caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 14.4 Ensure TF offset is measured accurately and entered correctly into the MWD software. 14.5 Confirm that the bit is dressed with a TFA of 0.46 – 0.56 sqin. Have DD run hydraulics models to ensure optimum TFA. We want to pump at 150 - 250 gpm. 14.6 Motor AKO should be set at 1.2 deg. Must keep up with 3 deg/100 DLS in the build section of the wellbore. 14.7 TIH to window. Shallow test MWD on trip in. 14.8 TIH through window, ensure Halliburton MWD service rep on rig floor during this operation. x Do not rotate string while bit is across face of Whipstock. 14.9 Drill 6” hole to 7000’ MD using motor assembly. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. x Keep swab and surge pressures low when tripping. x See attached mud program for hole cleaning and LCM strategies. x Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. x Adjust MW as necessary to maintain hole stability. x Ensure mud engineer set up to perform HTHP fluid loss. x Maintain API fluid loss < 6. x Take MWD surveys every stand drilled. x Minimize backreaming when working tight hole 14.10 Hilcorp Geologists will follow mud log closely to determine exact TD. 14.11 At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for cement calculations. CBU, and pull a wiper trip back to the window. 14.12 TOH with drilling assembly, handle BHA as appropriate. Page 20 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 15.0 Run 4.5” Production Liner 15.1 R/U Weatherford 4.5” casing running equipment. x Ensure 4.5” DWC/C x 4-1/2” CDS-40 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill casing while running. x Ensure all casing has been drifted and tally verified prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 15.2 P/U shoe joint, visually verify no debris inside joint. 15.3 Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). x (1) Baker locked joint. x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x (1) Joint with landing collar bucked up. x No centralizers on shoe joint, FC joint, and LC joint. x Install centralizers, one per joint, and leave centralizers free floating so that they can slide up and down the joint. x Ensure proper operation of float shoe & FC. 15.4 Continue running 4.5” production liner x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound.Dope pin end only w/ paint brush. x Install solid body centralizers on every joint to window. Leave the centralizers free floating. x Utilize a collar clamp until weight is sufficient to keep slips set properly. 4.5” DWC/C HT M/U torques Casing OD Minimum Maximum Yield Torque 4-1/2” 5800 ft-lbs 6500 ft-lbs 7200 ft-lbs Page 21 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 Page 22 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 15.7 Ensure to run enough liner to provide for approx 200’ overlap inside 7” casing. Ensure hanger/pkr will not be set in a 7” connection. 15.8 Before picking up Baker ZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 15.9 M/U Baker ZXP liner top packer. Fill liner tieback sleeve with “Xanplex”, ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 15.10 RIH one stand and circulate a minimum of one liner volume. Note weight of liner. 15.11 RIH w/ liner on DP no faster than 1 min / stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 15.12 M/U top drive and fill pipe while lowering string every 10 stands. 15.13 Set slowly in and pull slowly out of slips. 15.14 Circulate 1-1/2 drill pipe and liner volume at 7” window prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure. 15.15 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 15.16 Continue to fill the string every 10 joints while running liner in open hole. Do not stop to fill casing. 15.17 P/U the cmt stand and tag bottom with the liner shoe. P/U 2’ off bottom. Note slack-off and pick-up weights. Record rotating torque values at 10, 20, & 30 rpm. 15.18 Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting pressure. Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling fluid by adding water and thinners. 15.19 Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 23 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 16.0 Cement 4.5” Production Liner 16.1 Hold a pre-job safety meeting over the upcoming cmt operations. 16.2 Reciprocate the casing during cmt operations until hole gets sticky. 16.3 Pump 5 bbls 12.5 ppg MUDPUSH II spacer. 16.4 Test surface cmt lines to 4500 psi. 16.5 Pump remaining 10 bbls 12.5 ppg MUDPUSH II spacer. 16.6 Mix and pump 45 bbls of 15.3 ppg class “G” cmt per below recipe with 1/4 lb/bbl of LCM fiber or Bridgemaker. Ensure cmt is pumped at designed weight. Job is designed to pump 10% OH excess but if fluid caliper dictates otherwise we may increase excess volumes. Cement volume is designed to give 200’ of cement inside window in annulus between 7” casing and 4-1/2” casing. Est TOC 4300’ TMD. 16.7 Displacement fluid will be drilling mud. Cement Calculations 7” x 4-1/2” Liner Overlap: (4500’ – 4300’) x 0.017 = 3.4 bbls 6” OH x 4-1/2” Liner: (7000’ – 4500’) x 0.0153 x 1.1 = 42 bbls Shoe Track: 80’ x 0.01522 = 1.8 bbls Total Volume (bbls): 3.4 + 42 + 1.8 = 47.2 bbls Total Volume (ft3): 47.2 bbls x 5.615 ft3/bbl = 265 ft3 Total Volume (sx): 265 ft3 / 1.34 ft3/sk = 197 sx 47.2 bbls Page 24 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 Slurry Information: System Easy BLOK Density 15.3 lb/gal Yield 1.34 ft3/sk Mixed Water 5.879 gal/sk Mixed Fluid 5.879 gal/sk Expected Thickening 70 Bc at 05:00 hr:mn API Fluid Loss <25 mL in 30.0 min at 155degF / 1000 psi Additives Code Description Concentration G D046 D202 D400 D154 Cement Anti Foam Dispersant Gas Control Agent Extender 94 lb/sk 0.2% BWOC 1.5% BWOC 0.8% BWOC 8.0% BWOC 16.8 Drop DP dart and displace with drilling mud. 16.9 Pump cement at max rate of 4 bbl/min. Reduce pump rate to 2 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re-zeroed at this point 16.10 If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. Reduce pump rate as required to avoid packoff. 16.11 Bump the plug and pressure up to up as required by Baker procedure to set the liner hanger (15% above nominal setting pressure. Hold pressure for 3-5 minutes. 16.12 Slack off total liner weight plus 30k to confirm hanger is set. 16.13 Do not overdisplace by more than ½ shoe track (~1 bbls). Shoe track volume is 1.8 bbls. 16.14 Pressure up to 4200 psi to release the running tool (HRD-E) from the liner 1.34 ft3/sk Page 25 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 16.15 Bleed pressure to zero to check float equipment. 16.16 P/U, verify setting tool is released, and expose setting dogs on top of tieback sleeve 16.17 Rotate slowly and slack off 50k downhole to set ZXPN. 16.18 Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 16.19 Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 16.20 Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re-tag the liner top, and circulate the well clean. 16.21 Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 16.22 POOH, LDDP. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. Backup release from liner hanger: 16.23 If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 16.24 NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down to the setting tool. 16.25 After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set-down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. Page 26 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 Ensure to report the following on Wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Note: Send Csg & cmt report + “As-Run” liner tally to mmyers@hilcorp.com Page 27 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 17.0 Wellbore Clean Up & Displacement 17.1 M/U casing clean out assy complete with casing scraper assys for each size casing in the hole. x 3-3/4” bit or mill x Casing scraper & brush for 4-1/2” 12.6# casing x +/- 2700’ 2-3/8” workstring. x Casing scraper & brush for 7” 29# casing x (2000’) 4-1/2” DP x Casing scraper & brush for 7” 29# casing x 4-1/2” DP to surface. 17.2 TIH & clean out well to landing collar (+/- 6,880’ MD). x Circulate as needed on trip in if string begins to take weight. x Circulate hi-vis sweeps as necessary to carry debris out of wellbore. x Ensure 3-3/4” bit is worked down to the landing collar. x Space out the cleanout BHA so that the 3-3/4” bit reaches the 4-1/2” landing collar when crossover is +/- 30’ above the 4-1/2” liner top. 17.3 After wellbore has been cleaned out satisfactorily using mud, test casing to 3500 psi / 30 min. Ensure to chart record casing test. 17.4 Displace drilling fluid in wellbore with a hi-vis pill followed by fresh water. x Catch drilling fluid in rain-for-rent tanks for use on a future well. x Circulate fresh water into wellbore until clean up is satisfactory. Do not recirculate fluid, x After a couple circulations using FW, short trip the assy to bring the upper 7” multi-back assy to surface. x RIH again & tag landing collar w/ 3-3/4” bit. Continue circulation as necessary until fluid cleans up. Make another short trip if necessary. x Pump a chemical train followed by 6% KCl completion fluid. 17.5 TOH w/ clean out assy. LDDP on the trip out. L/D the 2-3/8” work string. (forward test chart to AOGCC) Page 28 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 18.0 Run Completion Assembly 18.1 Run 4-1/2” tubing completion assembly as per separate Approved Completion Sundry 19.0 RDMO 19.1 Install BPV in wellhead. 19.1 RILDs.ND BOPE, NU tree, test void 19.1 RDMO 1. CBL required over the 4.5" liner 2. will require a witnessed MIT-IA on rig when tubing/packer is run . Page 29 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 21.0 BOP Schematic Rig 147 Page 30 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 22.0 Wellhead Schematic Page 31 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 23.0 Days vs Depth Page 32 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 24.0 Geo-Prog Well Name:KGSF-1A Survey Type RKB Field Name:Swanson River Surface Hole:83 Pool Name: Bottom Hole: 169 State:Alaska 18 Field Location:Onshore Coord Ref Sys:NAD27 AK Zone 4 65 County/Parish:Kenai Penninsula Borough Objective: Reference Plan: SR_UB_50-6 Sandstone Water 4571.47 4,415.3 -4397.33 2468660.49 347200.93 1979 0.45 SR_UB_50-8 Sandstone Gas/Water 4695.89 4,539.3 -4521.26 2468650.19 347203.19 2035 0.45 SR_LB_52-9 Sandstone Gas/Water 5217.72 5,050.4 -5032.38 2468545.72 347205.14 2265 0.45 TYONEK Sandstone Water 5319.94 5,150.7 -5132.71 2468526.19 347205.37 2310 0.45 SR_TY_54-1 Sandstone Water 5400.32 5,230.2 -5212.22 2468514.44 347205.51 2345 0.45 SR_TY_54-5 Sandstone Water 5443.28 5,272.9 -5254.91 2468509.63 347205.57 2365 0.45 SR_TY_55-4 Sandstone Water 5544.45 5,373.8 -5355.77 2468501.98 347205.66 2410 0.45 SR_TY_55-5 Sandstone Water 5585.03 5,414.3 -5396.32 2468500.41 347205.68 2428 0.45 SR_TY_56-9 Sandstone Water 5749.4 5,578.7 -5560.68 2468499.59 347205.69 2502 0.45 SR_TY_57-8 Sandstone Water 5810.77 5,640.1 -5622.05 2468499.59 347205.69 2530 0.45 SR_TY_61-0 Sandstone Gas/Water 5851.86 5,681.1 -5663.14 2468499.59 347205.69 2548 0.45 SR_TY_61-8 Sandstone Gas/Water 6040.23 5,869.5 -5851.51 2468499.59 347205.69 2633 0.45 SR_TY_62-3 Sandstone Water 6161.9 5,991.2 -5973.18 2468499.59 347205.69 2688 0.45 SR_TY_62-5 Sandstone Gas/Water 6225.4 6,054.7 -6036.68 2468499.59 347205.69 2717 0.45 TY_62-5_BASE Sandstone Gas/Water 6342.8 6,172.1 -6154.08 2468499.59 347205.69 2769 0.45 SR_TY_64-5 Sandstone Gas/Water 6380.16 6,209.4 -6191.44 2468499.59 347205.69 3600 0.58 SR_TY_64-5 BASE Sandstone Gas/Water 6419.79 6,249.1 -6231.06 2468499.59 347205.69 3600 0.58 SR_TY_64-8 Sandstone Water 6464.97 6,294.3 -6276.25 2468499.59 347205.69 2824 0.45 SR_TY_65-9 Sandstone Water 6574.7 6,404.0 -6385.98 2468499.59 347205.69 2874 0.45 TD Sandstone Water 6714 6,543.3 -6525.28 2468499.59 347205.69 2936 0.45 Ground Elevation: GEOLOGICAL PROGNOSIS Proposed x = 347,199.28 y = 2,468,635.12 TVD Ref Datum: TVD Ref Elevation: Planned Rig: Rig Height: x = 347,203.56 y = 2,468,472.69 7,000' MD 6,985' TVD EASTING Est. Pressure GradientEXPECTED FLUID MD (FT) TVD (FT) TVDSS (FT)NORTHING Target the 64-5 Storage Reservoir at Swanson River. Hagrid's Hut wp03ANTICIPATED FORMATION TOPS & GEOHAZARDS Geo Summary/ Justification: See Above TOP NAME LITHOLOGY Page 33 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 = Reservoir Objectives = Possible Geo Hazards TARGET RADIUS Mud Logging: LWD Data: Other Log Data: Coreing: Frac Half-Length SH Max Direction Surf. Inter. Prod. NOTES: ARTIFICIAL LIFT EQUIPMENT OD TUBING SIZE COMPLETION TYPE Monobore Fault Constraints 100 FT KOP to total depth, 30 ft samples, two sets of dry cut cuttings, chromatograph, show reports, pixler plots. DATA COLLECTION REQUIREMENTS: LWD Triple Combo PROSED PIPE SET DEPTHS Chance of Success & Anticipated Rate Page 34 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 25.0 Anticipated Drilling Hazards Lost Circulation: Ensure 500 lbs of medium/coarse fibrous material, 500 lbs SteelSeal (Angular, dual-composition carbon-based material), & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ viscofier as necessary. Sweep hole w/ 20 bbls flowzan as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain programmed mud specs. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams. x Increase fluid density as required to control running coals. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. x Minimize swab and surge pressures x Minimize back reaming through coals when possible H2S: H2S is not present in this hole section. No abnormal temperatures or pressures are present in this hole section. Geologic Prognosis indicates the expected pressure in the Tyonek 64-5 sand at about 6,380' MD is 3600 psi (gradient of 0.58 psi/ft, or 11.2 ppg EMW). SFD 9/1/2020 Page 35 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 26.0 Rig Layout RIG 147 Page 36 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 27.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 37 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 28.0 Choke Manifold Schematic Page 38 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 29.0 Casing Design Information Mud Density: 6"Mud Density:9.5 ppg Mud Density: 3282 psi (See attached MASP determination & calculation) 3981 psi (See attached MASP determination & calculation) Collapse Calculation: Section Calculation 1, 2 Normal gradient external stress (0.57 psi/ft) and the casing evacuated for the internal stress 1234 4-1/2" 4,300 4,300 7,000 6,985 2,700 12.6 L-80 DWC/C 34,020 34,020 288 8.47 3,981 7,500 1.88 1,714 8,430 4.92Worst case safety factor (Burst) DATE: 8/20/2020 WELL: KGSF #1A (SRU 43-28 ST) FIELD: Soldotna Creek Unit DESIGN BY: Monty M Myers Hole Size Hole Size Hole Size MASP: Production Mode Top (TVD) Minimum Yield (psi) Weight (ppf) Grade Connection Weight w/o Bouyancy Factor (lbs) Min strength Tension (1000 lbs) Collapse Resistance w/o tension (Psi) Worst Case Safety Factor (Collapse) MASP (psi) Worst Case Safety Factor (Tension) Collapse Pressure at bottom (Psi) Tension at Top of Section (lbs) Bottom (TVD) Length Bottom (MD) Drilling Mode Top (MD) Casing Section Design Criteria: Calculation & Casing Design Factors Swanson River Unit Calculation/Specification Casing OD MASP: 8.47 3,981 3282 psi 1.88 1,714 8,430 Worst case safet y factor (Burst)4.92 3981 psi Page 39 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 30.0 6” Hole Section MASP MD TVD Planned Top: 4500 4500 Planned TD: 7000 6985 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad SR_UB_50-6 4,571 1979 Water 8.3 0.43 SR_UB_50-8 4,695 2035 Gas/Water 8.3 0.43 TYONEK 5,306 2310 Water 8.4 0.44 SR_TY_54-1 5,386 2345 Water 8.4 0.44 SR_TY_55-5 5,570 2428 Water 8.4 0.44 SR_TY_56-9 5,735 2502 Water 8.4 0.44 SR_TY_57-8 5,796 2530 Water 8.4 0.44 SR_TY_61-0 5,837 2548 Gas/Water 8.4 0.44 SR_TY_64-5 6,365 3600 Gas/Water 10.9 0.57 SR_TY_64-5 BASE 6,405 3600 Gas/Water 10.8 0.56 SR_TY_64-8 6,294 2824 Water 8.6 0.45 SR_TY_65-9 6,560 2874 Water 8.4 0.44 TD 6,985 2936 Water 8.1 0.42 Offset Well Mud Densities Well MW range Top (TVD) Bottom (TVD) Date SCU 44-05 9.8 - 10ppg 9,400 10,925 2014 SCU 21-4 12 ppg 0 10,965 1961 SCU 44-33 11.3 - 12.5 ppg 9,216 10,747 2013 SCU 41A-4 11.2 ppg 9,300 10,807 2013 Assumptions: 1. Maximum planned mud density for the 6" hole section is 10.5 ppg. 2. Calculations assume reservoirs contain 100% gas (worst case). 3. Calculations assume worst case event is complete evacuation of wellbore to gas. 4. Anticipated fracture gradient at 6985' TVD = 12.5 ppg EMW Fracture Pressure at 6" window considering a full column of gas from window to surface: 4500 (ft) x 0.65(psi/ft)= 2925 2925 (psi) - [0.1(psi/ft)*4500(ft)]= 2475 psi MASP from pore pressure; entire wellbore evacuated to gas from TD 6985 (ft) x 0.57(psi/ft)= 3981 psi 3981(psi) - [0.1(psi/ft)*6985 (ft)]= 3282 psi Summary: 1. MASP while drilling 6" production hole is governed by fracture pressure at window Maximum Anticipated Surface Pressure Calculation 6" Hole Section KGSF #1A (SRU 43-28 ST) Kenai, Alaska Conflicts with values presented on 10-401 form. SFD 8/25/2020 MASP while drilling 6" production hole is governed by fracture pressure at window SR_TY_64-5 6,365 3600 Gas/Water 10.9 0.57 Maximum planned mud density for the 6" hole section is 10.5 ppg. Page 40 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 31.0 Plot (NAD 27) (Governmental Sections) Well will lie near the center of a single gas storage lease AA082931 (not shown on this map). SFD 9/23/2020 Page 41 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 32.0 Surface Plat (As Built) (NAD 27&83) KGSF #1 #7 Page 42 Revision 0 August, 2020 KGSF #1A (SRU 43-28 ST) Drilling Procedure Rev 0 33.0 Directional Program (WP 03) ! "# #$%& #$%&'() ( 4500 4650 4800 4950 5100 5250 5400 5550 5700 5850 6000 6150 6300 6450 6600 6750 6900 7050True Vertical Depth (300 usft/in)-150 0 150 300 450 600 750 900 1050120013501500165018001950 Vertical Section at 177.75° (300 usft/in) KGSF 1A wp03 tgt1 4500 5000 5500 6000 6500 7000SRU 43-28(KGSF #1) 1/2"[ 4500 5 0 0 0 5 50 0 6000 6500 7000 KGSF 1A wp03 KOP: Dir 12.75º/100' : 4500' MD, 4499.82'TVD : 116.75° RT TF End Dir : 4513.3' MD, 4513.12' TVD Start Dir 4º/100' : 4533.3' MD, 4533.11'TVD End Dir : 4819.82' MD, 4817.31' TVD Start Dir 3º/100' : 5233.99' MD, 5222.22'TVD End Dir : 5638.8' MD, 5624' TVD Total Depth : 7000' MD, 6985.2' TVD SR_UB_50-6 SR_UB_50-8 SR_LB_52-9 TYONEK SR_TY_54-1 SR_TY_54-5 SR_TY_55-4 SR_TY_55-5 SR_TY_56-9 SR_TY_57-8 SR_TY_61-0 SR_TY_61-8 SR_TY_62-3 SR_TY_62-5 TY_62-5_BASE SR_TY_64-5 SR_TY_64-5 BASE SR_TY_64-8 SR_TY_65-9 Hilcorp Alaska, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: SRU 43-28(aka KGSF #1) Ground Level: 159.00 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2468635.12 347199.28 60° 45' 15.553 N 150° 51' 15.275 W SURVEY PROGRAM Date: 2020-08-20T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 125.00 4500.00 INC Only (SRU 43-28(KGSF #1)) 3_INC-Only 4500.00 4800.00 KGSF 1A wp03 (Plan: KGSF #1) 3_MWD_Interp Azi+Sag 4800.00 7000.00 KGSF 1A wp03 (Plan: KGSF #1) 3_MWD+IFR1+MS+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 4571.33 4397.33 4571.55 SR_UB_50-6 4695.26 4521.26 4695.96 SR_UB_50-8 5206.38 5032.38 5217.80 SR_LB_52-9 5306.71 5132.71 5320.04 TYONEK 5386.22 5212.22 5400.41 SR_TY_54-1 5428.91 5254.91 5443.37 SR_TY_54-5 5529.77 5355.77 5544.54 SR_TY_55-4 5570.32 5396.32 5585.12 SR_TY_55-5 5734.68 5560.68 5749.48 SR_TY_56-9 5796.05 5622.05 5810.85 SR_TY_57-8 5837.14 5663.14 5851.94 SR_TY_61-0 6025.51 5851.51 6040.31 SR_TY_61-8 6147.18 5973.18 6161.98 SR_TY_62-3 6210.68 6036.68 6225.48 SR_TY_62-5 6328.08 6154.08 6342.88 TY_62-5_BASE 6365.44 6191.44 6380.24 SR_TY_64-5 6405.06 6231.06 6419.86 SR_TY_64-5 BASE 6450.25 6276.25 6465.05 SR_TY_64-8 6559.98 6385.98 6574.78 SR_TY_65-9 REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well SRU 43-28(aka KGSF #1), True North Vertical (TVD) Reference:SRU 43-28 OKB @ 174.00usft Measured Depth Reference:SRU 43-28 OKB @ 174.00usft Calculation Method:Minimum Curvature Project:Swanson River UnitSite:SRU 43-28 Well:KGSF #1 Wellbore:Plan: KGSF #1 Design:KGSF 1A wp03 Swanson River Unit SRU 43-28 SRU 43-28(aka KGSF #1) Plan: KGSF #1 KGSF 1A wp03 3.879 CASING DETAILS TVD TVDSS MD Size Name 6985.20 6811.20 7000.00 -1/2 1/2"[ SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 4500.00 0.00 0.00 4499.82 0.00 0.00 0.00 0.00 0.00 KOP: Dir 12.75º/100' : 4500' MD, 4499.82'TVD : 116.75° RT TF 2 4513.30 1.70 116.75 4513.12 -0.09 0.18 12.75 116.75 0.10 End Dir : 4513.3' MD, 4513.12' TVD 3 4533.30 1.70 116.75 4533.11 -0.35 0.70 0.00 0.00 0.38 Start Dir 4º/100' : 4533.3' MD, 4533.11'TVD 4 4819.82 12.14 179.32 4817.31 -32.51 4.86 4.00 70.01 32.67 End Dir : 4819.82' MD, 4817.31' TVD 5 5233.99 12.14 179.32 5222.22 -119.63 5.89 0.00 0.00 119.77 Start Dir 3º/100' : 5233.99' MD, 5222.22'TVD 6 5638.80 0.00 0.00 5624.00 -162.37 6.39 3.00 180.00 162.49 End Dir : 5638.8' MD, 5624' TVD 7 6388.80 0.00 0.00 6374.00 -162.37 6.39 0.00 0.00 162.49 KGSF 1A wp03 tgt1 8 7000.00 0.00 0.00 6985.20 -162.37 6.39 0.00 0.00 162.49 Total Depth : 7000' MD, 6985.2' TVD KGSF 1A wp03 -267 -240 -213 -187 -160 -133 -107 -80 -53 -27 0 27 53 80 South(-)/North(+) (40 usft/in)-133 -107 -80 -53 -27 0 27 53 80 107 133 West(-)/East(+) (40 usft/in) KGSF 1A wp03 tgt1 SRU 43-28(KGSF #1) 11 3/4" 1/2" x 6" 0250500750100012501500175020002250250027503000325035003750400042504500 4 7 5 0 5000 5250 5500 575060006250650067506985 KGSF 1A wp03 KOP: Dir 12.75º/100' : 4500' MD, 4499.82'TVD : 116.75° RT TF End Dir : 4513.3' MD, 4513.12' TVD Start Dir 4º/100' : 4533.3' MD, 4533.11'TVD End Dir : 4819.82' MD, 4817.31' TVD Start Dir 3º/100' : 5233.99' MD, 5222.22'TVD End Dir : 5638.8' MD, 5624' TVD Total Depth : 7000' MD, 6985.2' TVD Project: Swanson River Unit Site: SRU 43-28 Well: SRU 43-28(aka KGSF #1) Wellbore: Plan: KGSF #1 Plan: KGSF 1A wp03 WELL DETAILS: SRU 43-28(aka KGSF #1) Ground Level: 159.00 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2468635.12 347199.28 60° 45' 15.553 N 150° 51' 15.275 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well SRU 43-28(aka KGSF #1), True North Vertical (TVD) Reference:SRU 43-28 OKB @ 174.00usft Measured Depth Reference:SRU 43-28 OKB @ 174.00usft Calculation Method:Minimum Curvature CASING DETAILS TVD TVDSS MD Size Name 6985.20 6811.20 7000.00 -1/2 1/2" x 6" -267 -240 -213 -187 -160 -133 -107 -80 -53 -27 0 27 53 80 South(-)/North(+) (40 usft/in)-133 -107 -80 -53 -27 0 27 53 80 107 133 West(-)/East(+) (40 usft/in) KGSF-7 KGSF 1A wp03 tgt1 25 05 0 075 01 0 0 0125015001750 20 00 2250 2500 2750 KGSF-7 2 50 5 0 075 01 0 0 0125015001750 20 00 2 250 25002750 30003250350037504000 425045004 7 5 0 5 0 0 0 5 2 5 0 5 5 0 0 5 7 5 0 6 0 0 0 6250 6500 6530 KGSF-7A 025050075010001250150017502000225025002750300032503500375040004250450047505000525055005750600062506500675070007250750077508000825085008750900092509500975010000102501050010750 10874 SRU 43-28(KGSF #1) 11 3/4" 1/2" x 6" 0250500750100012501500175020002250250027503000325035003750400042504500 4 7 5 0 5000 5250 5500 57506000625065006750 6985 KGSF 1A wp03 WELL DETAILS: SRU 43-28(aka KGSF #1) Ground Level: 159.00 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2468635.12 347199.28 60° 45' 15.553 N 150° 51' 15.275 W * ! + , ! % - ./0 - 1 2 21 !"#$% & !"#$ ",! 34 '()() ) * +,$-.//)0 0 !"$ / 011*23 1 4 30 -* +,$-.//)0 5 4 - 5 !"#$% 2) 3 ,+ 0+ * 3 6 ,+0+ $6-78 )% 1 4$6-1 4*1*1% 9/ ' :50 :: 0 + #, 5 4 7 ! 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()(' ()(' () *)& +,%& ))-&.- +,.*&% -&/+,%&0 (' ()(' ()(' ()"&%-%,%-+&/"%&*.%,%)-&+"&"%"%,%-+&/0 (' ()(' ()(' ()")&+/,%%&"%&"/,%.&"&".%/,%%&0 ( 1+.(*2 3 ' 4"5( 1+.(*2' 4"5( *&*) +,*& & +,)-*&") +&"+,*& ( 1+.(*2 3 ' 4"5( 1+.(*2' 4"5( "/&+- /,-%& ""&/% /,-.%&/. .&//,-%&0 ( %" +(@" +( B) @"%& +,%&.670(8+,%& +,*& ' ". .69:6 ;! <+,*& ),& ' ". .69:!"!9 ! < = > ?8(& > @&0 > > $ &0 A $#2 $( 5& < @@ & > ><9=>=0> ? > =& 0.001.503.004.50Separation Factor4500 4650 4800 4950 5100 5250 5400 5550 5700 5850 6000 6150 6300 6450 6600 6750 6900 7050Measured DepthKGSF-7ASRU 43-28(KGNo-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORSWELL DETAILS:SRU 43-28(aka KGSF #1) NAD 1927 (NADCON CONUS)Alaska Zone 04Ground Level: 159.00+N/-S +E/-W Northing EastingLatittudeLongitude0.000.00 2468635.12 347199.28 60° 45' 15.553 N 150° 51' 15.275 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well SRU 43-28(aka KGSF #1), True NorthVertical (TVD) Reference:SRU 43-28 OKB @ 174.00usftMeasured Depth Reference:SRU 43-28 OKB @ 174.00usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-08-20T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool125.00 4500.00 INC Only (SRU 43-28(KGSF #1)) 3_INC-Only4500.00 4800.00 KGSF 1A wp03 (Plan: KGSF #1) 3_MWD_Interp Azi+Sag4800.00 7000.00 KGSF 1A wp03 (Plan: KGSF #1) 3_MWD+IFR1+MS+Sag0.0030.0060.0090.00120.00150.00Centre to Centre Separation (50.00 usft/in)4500 4650 4800 4950 5100 5250 5400 5550 5700 5850 6000 6150 6300 6450 6600 6750 6900 7050Measured DepthSRU 43-28(KGSF #1)GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference4500.00 To 7000.00Project: Swanson River UnitSite: SRU 43-28Well: SRU 43-28(aka KGSF #1)Wellbore: Plan: KGSF #1Plan: KGSF 1A wp03Ladder / S.F. 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/͛ǀĞďĞĞŶĂĚǀŝƐĞĚƚŚĂƚĂ^ƚŽƌĂŐĞ/ŶũĞĐƚŝŽŶKƌĚĞƌŝƐƚŚĞƉƌŽƉĞƌǁĂǇƚŽĚĞĨŝŶĞƚŚĞ^ǁĂŶƐŽŶZŝǀĞƌϲϰͲϱdǇŽŶĞŬ'ĂƐ^ƚŽƌĂŐĞ WŽŽů͘WƵďůŝĐŶŽƚŝĐĞĂŶĚƚŚĞŽƉƉŽƌƚƵŶŝƚǇĨŽƌƉƵďůŝĐŚĞĂƌŝŶŐǁŝůů ůŝŬĞůǇďĞŶĞĞĚĞĚ͘ dŚĂŶŬƐĨŽƌǇŽƵƌŚĞůƉ͕ ^ƚĞǀĞĂǀŝĞƐ ůĂƐŬĂKŝůĂŶĚ'ĂƐŽŶƐĞƌǀĂƚŝŽŶŽŵŵŝƐƐŝŽŶ;K'Ϳ KE&/Ed/>/dzEKd/͗dŚŝƐĞͲŵĂŝůŵĞƐƐĂŐĞ͕ŝŶĐůƵĚŝŶŐĂŶǇĂƚƚĂĐŚŵĞŶƚƐ͕ĐŽŶƚĂŝŶƐŝŶĨŽƌŵĂƚŝŽŶĨƌŽŵƚŚĞůĂƐŬĂKŝůĂŶĚ'ĂƐŽŶƐĞƌǀĂƚŝŽŶŽŵŵŝƐƐŝŽŶ ;K'Ϳ͕^ƚĂƚĞŽĨůĂƐŬĂĂŶĚŝƐĨŽƌƚŚĞƐŽůĞƵƐĞŽĨƚŚĞŝŶƚĞŶĚĞĚƌĞĐŝƉŝĞŶƚ;ƐͿ͘/ƚŵĂǇĐŽŶƚĂŝŶĐŽŶĨŝĚĞŶƚŝĂůĂŶĚͬŽƌƉƌŝǀŝůĞŐĞĚŝŶĨŽƌŵĂƚŝŽŶ͘dŚĞƵŶĂƵƚŚŽƌŝǌĞĚƌĞǀŝĞǁ͕ƵƐĞ ŽƌĚŝƐĐůŽƐƵƌĞŽĨƐƵĐŚŝŶĨŽƌŵĂƚŝŽŶŵĂǇǀŝŽůĂƚĞƐƚĂƚĞŽƌĨĞĚĞƌĂůůĂǁ͘/ĨǇŽƵĂƌĞĂŶƵŶŝŶƚĞŶĚĞĚƌĞĐŝƉŝĞŶƚŽĨƚŚŝƐĞͲŵĂŝů͕ƉůĞĂƐĞĚĞůĞƚĞŝƚ͕ǁŝƚŚŽƵƚĨŝƌƐƚƐĂǀŝŶŐŽƌĨŽƌǁĂƌĚŝŶŐ ŝƚ͕ĂŶĚ͕ƐŽƚŚĂƚƚŚĞK'ŝƐĂǁĂƌĞŽĨƚŚĞŵŝƐƚĂŬĞŝŶƐĞŶĚŝŶŐŝƚƚŽǇŽƵ͕ĐŽŶƚĂĐƚ^ƚĞǀĞĂǀŝĞƐĂƚϵϬϳͲϳϵϯͲϭϮϮϰŽƌƐƚĞǀĞ͘ĚĂǀŝĞƐΛĂůĂƐŬĂ͘ŐŽǀ͘ &ƌŽŵ͗ĂǀŝĞƐ͕^ƚĞƉŚĞŶ&;Ϳ ^ĞŶƚ͗dƵĞƐĚĂǇ͕^ĞƉƚĞŵďĞƌϭ͕ϮϬϮϬϳ͗ϯϯD dŽ͗DŽŶƚǇDǇĞƌƐфŵŵǇĞƌƐΛŚŝůĐŽƌƉ͘ĐŽŵх Đ͗ŽǇĞƌ͕ĂǀŝĚ>;ͿфĚĂǀŝĚ͘ďŽǇĞƌϮΛĂůĂƐŬĂ͘ŐŽǀх͖ZŽďǇ͕ĂǀŝĚ^;ͿфĚĂǀĞ͘ƌŽďǇΛĂůĂƐŬĂ͘ŐŽǀх͖^ĐŚǁĂƌƚǌ͕'ƵǇ> ;ͿфŐƵǇ͘ƐĐŚǁĂƌƚǌΛĂůĂƐŬĂ͘ŐŽǀх ^ƵďũĞĐƚ͗Z͗΀ydZE>΁Z͗<'^&ϭ;WdϮϮϬͲϬϲϯͿͲYƵĞƐƚŝŽŶƐ DŽŶƚǇ͕ /ŶĨŽůůŽǁƵƉƚŽŵǇĞŵĂŝůƐďĞůŽǁ͕/ǁĂƐƌĞͲƌĞĂĚŝŶŐƚŚĞ^ƚŽƌĂŐĞ/ŶũĞĐƚŝŽŶKƌĚĞƌƐĂŶĚ^ƉĂĐŝŶŐǆĐĞƉƚŝŽŶŽƌĚĞƌƐĂƐƐŽĐŝĂƚĞĚ ǁŝƚŚƚŚĞ^ǁĂŶƐŽŶZŝǀĞƌϲϰͲϱdǇŽŶĞŬ'ĂƐ^ƚŽƌĂŐĞWŽŽů͕ĂŶĚ/ŶŽƚŝĐĞĚƚŚĂƚ^/KϮ͘ϬϬϭĐŽŶĐůƵĚĞƐǁŝƚŚ͗ ͞ŶǇĨƵƌƚŚĞƌĞǆƉĂŶƐŝŽŶŽĨƚŚĞ<ĞŶĂŝ'ĂƐ^ƚŽƌĂŐĞ&ĂĐŝůŝƚǇǁŝůůƌĞƋƵŝƌĞĚĞĨŝŶŝƚŝŽŶŽĨĂŶĂĨĨĞĐƚĞĚĂƌĞĂĐŽƌƌĞƐƉŽŶĚŝŶŐ ƚŽƚŚĞĂƌĞĂůĞǆƚĞŶƚŽĨƚŚĞdǇŽŶĞŬϲϰͲϱƌĞƐĞƌǀŽŝƌĂŶĚĂǁĞůůƐƉĂĐŝŶŐƌƵůĞĨŽƌŐĂƐƐƚŽƌĂŐĞǁĞůůƐ͘͟ DǇƐĞĂƌĐŚƚŚƌŽƵŐŚK'͛ƐŽƌĚĞƌƐĚŝĚŶŽƚĨŝŶĚĂŽŶƐĞƌǀĂƚŝŽŶKƌĚĞƌĚĞĨŝŶŝŶŐƚŚĞdǇŽŶĞŬϲϰͲϱ'ĂƐ^ƚŽƌĂŐĞWŽŽů͘,ĂǀĞ/ ŽǀĞƌůŽŽŬĞĚƐŽŵĞƚŚŝŶŐ͍/ĨŶŽƚ͕ƉůĞĂƐĞƐƵďŵŝƚĂŶĂƉƉůŝĐĂƚŝŽŶƚŽĨ ŽƌŵĂůůǇĚĞĨŝŶĞƚŚĞƉŽŽůĂŶĚĞƐƚĂďůŝƐŚǁĞůůƐƉĂĐŝŶŐ͘ dŚĂŶŬƐĨŽƌǇŽƵŚĞůƉ͕ ^ƚĞǀĞĂǀŝĞƐ ůĂƐŬĂKŝůĂŶĚ'ĂƐŽŶƐĞƌǀĂƚŝŽŶŽŵŵŝƐƐŝŽŶ;K'Ϳ KE&/Ed/>/dzEKd/͗dŚŝƐĞͲŵĂŝůŵĞƐƐĂŐĞ͕ŝŶĐůƵĚŝŶŐĂŶǇĂƚƚĂĐŚŵĞŶƚƐ͕ĐŽŶƚĂŝŶƐŝŶĨŽƌŵĂƚŝŽŶĨƌŽŵƚŚĞůĂƐŬĂKŝůĂŶĚ'ĂƐŽŶƐĞƌǀĂƚŝŽŶŽŵŵŝƐƐŝŽŶ ;K'Ϳ͕^ƚĂƚĞŽĨůĂƐŬĂĂŶĚŝƐĨŽƌƚŚĞƐŽůĞƵƐĞŽĨƚŚĞŝŶƚĞŶĚĞĚƌĞĐŝƉŝĞŶƚ;ƐͿ͘/ƚŵĂǇĐŽŶƚĂŝŶĐŽŶĨŝĚĞŶƚŝĂůĂŶĚͬŽƌƉƌŝǀŝůĞŐĞĚŝŶĨŽƌŵĂƚŝŽŶ͘dŚĞƵŶĂƵƚŚŽƌŝǌĞĚƌĞǀŝĞǁ͕ƵƐĞ 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^ĞŶƚ͗dƵĞƐĚĂǇ͕^ĞƉƚĞŵďĞƌϭ͕ϮϬϮϬϭϭ͗ϭϭD dŽ͗DŽŶƚǇDǇĞƌƐфŵŵǇĞƌƐΛŚŝůĐŽƌƉ͘ĐŽŵх Đ͗ŽǇĞƌ͕ĂǀŝĚ>;ͿфĚĂǀŝĚ͘ďŽǇĞƌϮΛĂůĂƐŬĂ͘ŐŽǀх͖ZŽďǇ͕ĂǀŝĚ^;ͿфĚĂǀĞ͘ƌŽďǇΛĂůĂƐŬĂ͘ŐŽǀх͖^ĐŚǁĂƌƚǌ͕'ƵǇ> ;ͿфŐƵǇ͘ƐĐŚǁĂƌƚǌΛĂůĂƐŬĂ͘ŐŽǀх͖tĂůůĂĐĞ͕ŚƌŝƐ;ͿфĐŚƌŝƐ͘ǁĂůůĂĐĞΛĂůĂƐŬĂ͘ŐŽǀх ^ƵďũĞĐƚ͗Z͗΀ydZE>΁Z͗<'^&ϭ;WdϮϮϬͲϬϲϯͿͲYƵĞƐƚŝŽŶƐ DŽŶƚǇ͕ /͛ǀĞďĞĞŶĂĚǀŝƐĞĚƚŚĂƚĂ^ƚŽƌĂŐĞ/ŶũĞĐƚŝŽŶKƌĚĞƌŝƐƚŚĞƉƌŽƉĞƌǁĂǇƚŽĚĞĨŝŶĞƚŚĞ^ǁĂŶƐŽŶZŝǀĞƌϲϰͲϱdǇŽŶĞŬ'ĂƐ^ƚŽƌĂŐĞ WŽŽů͘WƵďůŝĐŶŽƚŝĐĞĂŶĚƚŚĞŽƉƉŽƌƚƵŶŝƚǇĨŽƌƉƵďůŝĐŚĞĂƌŝŶŐǁŝůů ůŝŬĞůǇďĞŶĞĞĚĞĚ͘ dŚĂŶŬƐĨŽƌǇŽƵƌŚĞůƉ͕ ^ƚĞǀĞĂǀŝĞƐ ůĂƐŬĂKŝůĂŶĚ'ĂƐŽŶƐĞƌǀĂƚŝŽŶŽŵŵŝƐƐŝŽŶ;K'Ϳ KE&/Ed/>/dzEKd/͗dŚŝƐĞͲŵĂŝůŵĞƐƐĂŐĞ͕ŝŶĐůƵĚŝŶŐĂŶǇĂƚƚĂĐŚŵĞŶƚƐ͕ĐŽŶƚĂŝŶƐŝŶĨŽƌŵĂƚŝŽŶĨƌŽŵƚŚĞůĂƐŬĂKŝůĂŶĚ'ĂƐŽŶƐĞƌǀĂƚŝŽŶŽŵŵŝƐƐŝŽŶ ;K'Ϳ͕^ƚĂƚĞŽĨůĂƐŬĂĂŶĚŝƐĨŽƌƚŚĞƐŽůĞƵƐĞŽĨƚŚĞŝŶƚĞŶĚĞĚƌĞĐŝƉŝĞŶƚ;ƐͿ͘/ƚŵĂǇĐŽŶƚĂŝŶĐŽŶĨŝĚĞŶƚŝĂůĂŶĚͬŽƌƉƌŝǀŝůĞŐĞĚŝŶĨŽƌŵĂƚŝŽŶ͘dŚĞƵŶĂƵƚŚŽƌŝǌĞĚƌĞǀŝĞǁ͕ƵƐĞ ŽƌĚŝƐĐůŽƐƵƌĞŽĨƐƵĐŚŝŶĨŽƌŵĂƚŝŽŶŵĂǇǀŝŽůĂƚĞƐƚĂƚĞŽƌĨĞĚĞƌĂůůĂǁ͘/ĨǇŽƵĂƌĞĂŶƵŶŝŶƚĞŶĚĞĚƌĞĐŝƉŝĞŶƚŽĨƚŚŝƐĞͲŵĂŝů͕ƉůĞĂƐĞĚĞůĞƚĞŝƚ͕ǁŝƚŚŽƵƚĨŝƌƐƚƐĂǀŝŶŐŽƌĨŽƌǁĂƌĚŝŶŐ ŝƚ͕ĂŶĚ͕ƐŽƚŚĂƚƚŚĞK'ŝƐĂǁĂƌĞŽĨƚŚĞŵŝƐƚĂŬĞŝŶƐĞŶĚŝŶŐŝƚƚŽǇŽƵ͕ĐŽŶƚĂĐƚ^ƚĞǀĞĂǀŝĞƐĂƚϵϬϳͲϳϵϯͲϭϮϮϰŽƌƐƚĞǀĞ͘ĚĂǀŝĞƐΛĂůĂƐŬĂ͘ŐŽǀ͘ &ƌŽŵ͗ĂǀŝĞƐ͕^ƚĞƉŚĞŶ&;Ϳ ^ĞŶƚ͗dƵĞƐĚĂǇ͕^ĞƉƚĞŵďĞƌϭ͕ϮϬϮϬϳ͗ϯϯD dŽ͗DŽŶƚǇDǇĞƌƐфŵŵǇĞƌƐΛŚŝůĐŽƌƉ͘ĐŽŵх Đ͗ŽǇĞƌ͕ĂǀŝĚ>;ͿфĚĂǀŝĚ͘ďŽǇĞƌϮΛĂůĂƐŬĂ͘ŐŽǀх͖ZŽďǇ͕ĂǀŝĚ^;ͿфĚĂǀĞ͘ƌŽďǇΛĂůĂƐŬĂ͘ŐŽǀх͖^ĐŚǁĂƌƚǌ͕'ƵǇ> ;ͿфŐƵǇ͘ƐĐŚǁĂƌƚǌΛĂůĂƐŬĂ͘ŐŽǀх ^ƵďũĞĐƚ͗Z͗΀ydZE>΁Z͗<'^&ϭ;WdϮϮϬͲϬϲϯͿͲYƵĞƐƚŝŽŶƐ DŽŶƚǇ͕ /ŶĨŽůůŽǁƵƉƚŽŵǇĞŵĂŝůƐďĞůŽǁ͕/ǁĂƐƌĞͲƌĞĂĚŝŶŐƚŚĞ^ƚŽƌĂŐĞ/ŶũĞĐƚŝŽŶKƌĚĞƌƐĂŶĚ^ƉĂĐŝŶŐǆĐĞƉƚŝŽŶŽƌĚĞƌƐĂƐƐŽĐŝĂƚĞĚ ǁŝƚŚƚŚĞ^ǁĂŶƐŽŶZŝǀĞƌϲϰͲϱdǇŽŶĞŬ'ĂƐ^ƚŽƌĂŐĞWŽŽů͕ĂŶĚ/ŶŽƚŝĐĞĚƚŚĂƚ^/KϮ͘ϬϬϭĐŽŶĐůƵĚĞƐǁŝƚŚ͗ ͞ŶǇĨƵƌƚŚĞƌĞǆƉĂŶƐŝŽŶŽĨƚŚĞ<ĞŶĂŝ'ĂƐ^ƚŽƌĂŐĞ&ĂĐŝůŝƚǇǁŝůůƌĞƋƵŝƌĞĚĞĨŝŶŝƚŝŽŶŽĨĂŶĂĨĨĞĐƚĞĚĂƌĞĂĐŽƌƌĞƐƉŽŶĚŝŶŐ ƚŽƚŚĞĂƌĞĂůĞǆƚĞŶƚŽĨƚŚĞdǇŽŶĞŬϲϰͲϱƌĞƐĞƌǀŽŝƌĂŶĚĂǁĞůůƐƉĂĐŝŶŐƌƵůĞĨŽƌŐĂƐƐƚŽƌĂŐĞǁĞůůƐ͘͟ DǇƐĞĂƌĐŚƚŚƌŽƵŐŚK'͛ƐŽƌĚĞƌƐĚŝĚŶŽƚĨŝŶĚĂŽŶƐĞƌǀĂƚŝŽŶKƌĚĞƌĚĞĨŝŶŝŶŐƚŚĞdǇŽŶĞŬϲϰͲϱ'ĂƐ^ƚŽƌĂŐĞWŽŽů͘,ĂǀĞ/ ŽǀĞƌůŽŽŬĞĚƐŽŵĞƚŚŝŶŐ͍/ĨŶŽƚ͕ƉůĞĂƐĞƐƵďŵŝƚĂŶĂƉƉůŝĐĂƚŝŽŶƚŽĨ ŽƌŵĂůůǇĚĞĨŝŶĞƚŚĞƉŽŽůĂŶĚĞƐƚĂďůŝƐŚǁĞůůƐƉĂĐŝŶŐ͘ dŚĂŶŬƐĨŽƌǇŽƵŚĞůƉ͕ ^ƚĞǀĞĂǀŝĞƐ ůĂƐŬĂKŝůĂŶĚ'ĂƐŽŶƐĞƌǀĂƚŝŽŶŽŵŵŝƐƐŝŽŶ;K'Ϳ KE&/Ed/>/dzEKd/͗dŚŝƐĞͲŵĂŝůŵĞƐƐĂŐĞ͕ŝŶĐůƵĚŝŶŐĂŶǇĂƚƚĂĐŚŵĞŶƚƐ͕ĐŽŶƚĂŝŶƐŝŶĨŽƌŵĂƚŝŽŶĨƌŽŵƚŚĞůĂƐŬĂKŝůĂŶĚ'ĂƐŽŶƐĞƌǀĂƚŝŽŶŽŵŵŝƐƐŝŽŶ ;K'Ϳ͕^ƚĂƚĞŽĨůĂƐŬĂĂŶĚŝƐĨŽƌƚŚĞƐŽůĞƵƐĞŽĨƚŚĞŝŶƚĞŶĚĞĚƌĞĐŝƉŝĞŶƚ;ƐͿ͘/ƚŵĂǇĐŽŶƚĂŝŶĐŽŶĨŝĚĞŶƚŝĂůĂŶĚͬŽƌƉƌŝǀŝůĞŐĞĚŝŶĨŽƌŵĂƚŝŽŶ͘dŚĞƵŶĂƵƚŚŽƌŝǌĞĚƌĞǀŝĞǁ͕ƵƐĞ ŽƌĚŝƐĐůŽƐƵƌĞŽĨƐƵĐŚŝŶĨŽƌŵĂƚŝŽŶŵĂǇǀŝŽůĂƚĞƐƚĂƚĞŽƌĨĞĚĞƌĂůůĂǁ͘/ĨǇŽƵĂƌĞĂŶƵŶŝŶƚĞŶĚĞĚƌĞĐŝƉŝĞŶƚŽĨƚŚŝƐĞͲŵĂŝů͕ƉůĞĂƐĞĚĞůĞƚĞŝƚ͕ǁŝƚŚŽƵƚĨŝƌƐƚƐĂǀŝŶŐŽƌĨŽƌǁĂƌĚŝŶŐ ŝƚ͕ĂŶĚ͕ƐŽƚŚĂƚƚŚĞK'ŝƐĂǁĂƌĞŽĨƚŚĞŵŝƐƚĂŬĞŝŶƐĞŶĚŝŶŐŝƚƚŽǇŽƵ͕ĐŽŶƚĂĐƚ^ƚĞǀĞĂǀŝĞƐĂƚϵϬϳͲϳϵϯͲϭϮϮϰŽƌƐƚĞǀĞ͘ĚĂǀŝĞƐΛĂůĂƐŬĂ͘ŐŽǀ͘ &ƌŽŵ͗DŽŶƚǇDǇĞƌƐфŵŵǇĞƌƐΛŚŝůĐŽƌƉ͘ĐŽŵх ^ĞŶƚ͗dƵĞƐĚĂǇ͕^ĞƉƚĞŵďĞƌϭ͕ϮϬϮϬϳ͗ϮϱD dŽ͗ĂǀŝĞƐ͕^ƚĞƉŚĞŶ&;ͿфƐƚĞǀĞ͘ĚĂǀŝĞƐΛĂůĂƐŬĂ͘ŐŽǀх Đ͗ŽǇĞƌ͕ĂǀŝĚ>;ͿфĚĂǀŝĚ͘ďŽǇĞƌϮΛĂůĂƐŬĂ͘ŐŽǀх ^ƵďũĞĐƚ͗Z͗΀ydZE>΁Z͗<'^&ϭ;WdϮϮϬͲϬϲϯͿͲYƵĞƐƚŝŽŶƐ 'ŽŽĚŵŽƌŶŝŶŐ^ƚĞǀĞ͘ DǇĂƉŽůŽŐŝĞƐ͕/ǁĂƐŽƵƚůĂƐƚǁĞĞŬĂŶĚŵŝƐƐĞĚǇŽƵƌĞŵĂŝů͘tŝůůŐĞƚǇŽƵƐŽŵĞĐůĂƌŝĨŝĐĂƚŝŽŶƚŽĚĂǇ DŽŶƚǇDDǇĞƌƐ ƌŝůůŝŶŐDĂŶĂŐĞƌ ϵϬϳ͘ϱϯϴ͘ϭϭϲϴ;ĐͿ ϵϬϳ͘ϳϳϳ͘ϴϰϯϭ;ŽͿ &ƌŽŵ͗ĂǀŝĞƐ͕^ƚĞƉŚĞŶ&;Ϳ΀ŵĂŝůƚŽ͗ƐƚĞǀĞ͘ĚĂǀŝĞƐΛĂůĂƐŬĂ͘ŐŽǀ΁ ^ĞŶƚ͗dƵĞƐĚĂǇ͕^ĞƉƚĞŵďĞƌϭ͕ϮϬϮϬϲ͗ϯϬD dŽ͗DŽŶƚǇDǇĞƌƐфŵŵǇĞƌƐΛŚŝůĐŽƌƉ͘ĐŽŵх 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WKHUHFLSLHQWVKRXOGFDUU\RXWVXFKYLUXVDQGRWKHUFKHFNVDVLWFRQVLGHUVDSSURSULDWH 1 Davies, Stephen F (CED) From:Davies, Stephen F (CED) Sent:Tuesday, September 1, 2020 7:33 AM To:Monty Myers Cc:Boyer, David L (CED); Roby, David S (CED); Schwartz, Guy L (CED) Subject:RE: [EXTERNAL] RE: KGSF 1A (PTD 220-063) - Questions Monty, Infollowuptomyemailsbelow,IwasreͲreadingtheStorageInjectionOrdersandSpacingExceptionordersassociated withtheSwansonRiver64Ͳ5TyonekGasStoragePool,andInoticedthatSIO2A.001concludeswith: “AnyfurtherexpansionoftheKenaiGasStorageFacilitywillrequiredefinitionofanaffectedareacorresponding tothearealextentoftheTyonek64Ͳ5reservoirandawellspacingruleforgasstoragewells.” MysearchthroughAOGCC’sordersdidnotfindaConservationOrderdefiningtheTyonek64Ͳ5GasStoragePool.HaveI overlookedsomething?Ifnot,pleasesubmitanapplicationtoformallydefinethepoolandestablishwellspacing. Thanksforyouhelp, SteveDavies AlaskaOilandGasConservationCommission(AOGCC) CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaskaOilandGasConservationCommission (AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmaycontainconfidentialand/orprivilegedinformation.Theunauthorizedreview,use ordisclosureofsuchinformationmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutfirstsavingorforwarding it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov. From:MontyMyers<mmyers@hilcorp.com> Sent:Tuesday,September1,20207:25AM To:Davies,StephenF(CED)<steve.davies@alaska.gov> Cc:Boyer,DavidL(CED)<david.boyer2@alaska.gov> Subject:RE:[EXTERNAL]RE:KGSF1A(PTD220Ͳ063)ͲQuestions GoodmorningSteve. Myapologies,Iwasoutlastweekandmissedyouremail.Willgetyousomeclarificationtoday MontyMMyers DrillingManager 907.538.1168(c) 907.777.8431(o) From:Davies,StephenF(CED)[mailto:steve.davies@alaska.gov] Sent:Tuesday,September1,20206:30AM To:MontyMyers<mmyers@hilcorp.com> Cc:Boyer,DavidL(CED)<david.boyer2@alaska.gov> Subject:[EXTERNAL]RE:KGSF1A(PTD220Ͳ063)ͲQuestions HiMonty, 2 I’mcheckingtoensureyoureceivedmyemail,below.IwouldliketokeepHilcorp’sPermittoDrillapplicationforKGSF 1AmovingthroughAOGCC’sreviewprocess. Thanksforyourhelp, SteveDavies AlaskaOilandGasConservationCommission(AOGCC) CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaskaOilandGasConservationCommission (AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmaycontainconfidentialand/orprivilegedinformation.Theunauthorizedreview,use ordisclosureofsuchinformationmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutfirstsavingorforwarding it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov. From:Davies,StephenF(CED) Sent:Tuesday,August25,202012:38PM To:MontyMyers(mmyers@hilcorp.com)<mmyers@hilcorp.com> Cc:Boyer,DavidL(CED)<david.boyer2@alaska.gov> Subject:KGSF1A(PTD220Ͳ063)ͲQuestions HiMonty, I’mreviewingHilcorp’sPermittoDrillapplicationforKGSFͲ1A,andIhaveafewquestions. Inoticethataspacingexceptionwasrequiredtodrill,complete,andoperateexistingwellKGSFͲ7A. x WillKGSF1Abelocatedwithin1500’ofanypropertylineswhereownershiporlandownershiparenotthesame onbothsidesoftheline?Whatisthedistancetothenearestpropertylinewhereownershiporlandownership changes? x WhyisitnecessarytoreͲdrillKGSF1Atoalocationthatislessthan3,000’fromKGSF7A?Whyisitnecessaryto placethebottomͲholelocationofKGSF1AsoneartothatofKGSF7A? x WhywillaspacingexceptionnotberequiredtoreͲdrill,complete,andoperatewellKGSFͲ1A? Won’ttheexistinggasstorageorderhavetobeamendedtoincludeKGSF1A?Ifso,whendoesHilcorpplantoapplyfor suchanamendment? Regards, SteveDavies SeniorPetroleumGeologist AlaskaOilandGasConservationCommission(AOGCC) CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaskaOilandGasConservationCommission (AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmaycontainconfidentialand/orprivilegedinformation.Theunauthorizedreview,use ordisclosureofsuchinformationmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutfirstsavingorforwarding it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Revised 2/2015 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: ____________________________ POOL: ______________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit No. _____________, API No. 50-_______________________. Production should continue to be reported as a function of the original API number stated above. Pilot Hole In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name (_______________________PH) and API number (50-_____________________) from records, data and logs acquired for well (name on permit). Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation order approving a spacing exception. (_____________________________) as Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for well ( ) until after ( ) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (________________________) must contact the AOGCC to obtain advance approval of such water well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (_______________________________) in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. 220-063 Swanson River Unit KGSF - 1A X Swanson River Tyonek 64-5 Gas Storage WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:SWANSON RIVER KGSF 1AInitial Class/TypeSER / PENDGeoArea820Unit51994On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2200630SWANSON RIVER, 64-5 TYNK GS ST - 772803NA1 Permit fee attachedYes Entire well in Federal gas storage lease FEDA082931.2 Lease number appropriateYes Replacement well for KGSF 1, drilled to a location roughly 140' to the south of the current KGSF 1 TD.3 Unique well name and numberYes4 Well located in a defined poolYes No requirements for gas storage wells. This well will be centrally located in gas storage lease AA082931.5 Well located proper distance from drilling unit boundaryNA No requirements for gas storage wells.6 Well located proper distance from other wellsNA No requirements for gas storage wells.7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For seNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)NA sidetrack….18 Conductor string providedNA19 Surface casing protects all known USDWsNA20 CMT vol adequate to circulate on conductor & surf csgNA (7" window at 4500 ft )21 CMT vol adequate to tie-in long string to surf csgYes 4.5" liner is planned to be fully cemented to liner hanger22 CMT will cover all known productive horizonsYes BTC calcs provided23 Casing designs adequate for C, T, B & permafrostYes Rig has steel tanks.24 Adequate tankage or reserve pitYes sundry 320-357 issued to plug for redrill. (using rig 401)25 If a re-drill, has a 10-403 for abandonment been approvedYes No issues with close crossing .26 Adequate wellbore separation proposedNA wellhead in place … BOPE will be utilized.27 If diverter required, does it meet regulationsYes Max form pressure = 3981 psi (10.9 ppg) drilling with 10.5 ppg with ability to go to 11.5 ppg28 Drilling fluid program schematic & equip list adequateYes Rig 147 has 5000 psi WP BOPE29 BOPEs, do they meet regulationYes MASP = 3200 psi (will test BOPE to 3500 psi )30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes sundry required to run tubing and complete well.32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableYes 1/4 mile review completed.34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not expected based on nearby wells.35 Permit can be issued w/o hydrogen sulfide measuresYes eologic Prognosis indicates the expected pressure in the Tyonek 64-5 sand at about 6,380' MD36 Data presented on potential overpressure zonesNA is 3600 psi (gradient of 0.58 psi/ft, or 11.2 ppg EMW); otherwise, pressure gradient is normal.37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate9/23/2020ApprGLSDate9/25/2020ApprSFDDate9/1/2020AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDatereplacement wellbore for KGSF 1 .glsJLC 9/28/2020Daniel T. Seamount, Jr.Digitally signed by Daniel T. Seamount, Jr. Date: 2020.09.28 10:15:45 -08'00'Jeremy M. PriceDigitally signed by Jeremy M. Price Date: 2020.09.28 13:10:49 -08'00'