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Home My WebLink About218-054 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov April 3, 2023 Dan Marlowe Operations Manager Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 RE: No-Flow Verification Soldotna Creek Unit 344-33 PTD 2180540 Dear Mr. Marlowe: On March 16 and 17, 2023 an Alaska Oil and Gas Conservation Commission (AOGCC) Petroleum Inspector witnessed no-flow tests of Soldotna Creek Unit (SCU) 344-33 located within the Swanson River Field on the Kenai Peninsula. The AOGCC Inspector confirmed that the proper test equipment was rigged up prior to the test as outlined in Industry Guidance Bulletin 10-004. The test on March 16, 2023, attempted the pressure discharge method as described in AOGCC Industry Guidance Bulletin 21-001. The test failed. The AOGCC Inspector returned on March 17, 2023, for a second test, this time using the low-flow meter method. SCU 344-33 was shut in for three 1-hour pressure build-up periods each followed by a short duration flow period through the test equipment to an atmospheric tank. The maximum observed gas flow rate was 575 scf/hr during the three flow periods with no liquid flow to surface. SCU 344-33 may be produced without a subsurface safety valve. A fail-safe automatic surface safety valve system capable of preventing uncontrolled flow must be maintained in proper working condition in this well as required in 20 AAC 25.265. The subsurface safety valve must be returned to service if SCU 344-33 demonstrates an ability to flow unassisted to surface. Any cleanout, perforating or other stimulation work in this well will necessitate a subsequent no-flow test. Please retain a copy of this letter at a location readily available for AOGCC inspection. Sincerely, James B. Regg Petroleum Inspection Supervisor ecc: P. Brooks AOGCC Inspectors James B. Regg Digitally signed by James B. Regg Date: 2023.04.03 11:40:21 -08'00' 2023-0317_No-Flow_SCU_344-33_ae Page 1 of 3 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: 3-20-2023 P. I. Supervisor FROM: Adam Earl SUBJECT: No Flow Test Petroleum Inspector Soldotna Creek Unit 344-33 Hilcorp Alaska LLC. PTD 2180540 March 16, 2023: I traveled to Swanson River Field to witness a No-Flow Test on well SCU 344-33. Jason Yoeman was the Hilcorp-lead and Chase Corona was the field operator that conducted the test. Hilcorp used the pressure discharge method outlined in regulation and AOGCC’s Industry Guidance Bulletin 21-001 (3-hr build up, open well, pressure must discharge within 5 minutes to pass). Test results: pressure built to 14.4 psi in 3 hours; opened to atmosphere for 5 minutes; final pressure 0.6 psi – FAIL. March 17, 2023: I returned to SCU 344-33 for a second attempt of a No-Flow Test. Today’s test was conducted using the low-flow SCF/H meter method. The following table shows the 3/17/2023 test details: Time Pressures1 Flow Rate2 Remarks (psi) Gas – scf/hr Liquid – gal/hr 13:35 0/0/0 Shut well in 13:50 1.8/.4/0 14:05 3.4/.5/0 14:20 6/1/0 14:35 7.5/1/0 250 none Opened well; 250 scf/hr 14:40 6.8/1/0 Shut well in 14:55 8/1.4/0 15:10 8.9/2.2/0 15:25 9.3/2/0 15:40 10.1/2.2/0 15:45 9/2.1/0 400 none Opened well; 400 scf/hr 16:00 10.1/3/0 Shut well in 16:15 11.2/2.6/0 16:30 12.2/3/0 16:45 13.2/2.9/0 575 none Opened well; 575 scf/hr 16:50 11.4/3.4/0 Final SI pressures after 3rd bleed 1 Pressures are T/IA/OA 2 Gas flow not to exceed 900 scf/hr; Liquid flow not to exceed 6.3 gal/hr Attachments: Equipment Photos; Test Equipment Certifications        2023-0317_No-Flow_SCU_344-33_ae Page 2 of 3 No-Flow Test – SCU 344-33 (PTD 2180540) Photos by AOGCC Inspector A. Earl 3/17/2023  2023-0317_No-Flow_SCU_344-33_ae Page 3 of 3  CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Chad Helgeson Cc:Josh Allely - (C) Subject:RE: No Flow Test on SCU 344-33 Date:Thursday, December 22, 2022 4:36:00 PM Chad, A 14 day extension for the diagnostic period and NFT is granted to accommodate difficulties with the recent extreme snow and cold. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Thursday, December 22, 2022 2:51 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Josh Allely - (C) <Josh.Allely@hilcorp.com> Subject: No Flow Test on SCU 344-33 Bryan Per Sundry 322-498, we are required to perform no flow test on well SCU 344-33 (post tubing punch holes for gas lift). Swanson operations has been working to get this done but, due to the near -30F temps, they are encountering freezing issues with their bleed setup, which has been made more difficult by their inability to place larger tanks due to the large amount of recent snowfall. The well is currently shut-in per the requirements in the sundry. Our specific request is to get a 60-day extension on the diagnostic period and perform the no flow test when weather is more amenable. Attached is the sundry and production/pressure data for your reference. Thanks Chad Helgeson Operations Engineer 907-229-4824 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. Kyle Wiseman Hilcorp Alaska, LLC Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 11/28/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20221128 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# SD-06 50133205820000 208160 9/12/2022 Yellowjacket PERF SRU 32A-33 50133101640100 191014 9/21/2022 Yellowjacket PERF KBU 42-06Y 50133206340000 214089 9/26/2022 Yellowjacket GPT-PERF CLU 05RD2 50133204740200 222092 9/29/2022 Yellowjacket PERF SCU 344-33 50133202930100 218054 10/8/2022 Yellowjacket PERF-GPT Please include current contact information if different from above. By Meredith Guhl at 9:48 am, Nov 29, 2022 T37313 T37314 T37315 T37316 T37317 SCU 344-33 50133202930100 218054 10/8/2022 Yellowjacket PERF-GPT Meredith Guhl Digitally signed by Meredith Guhl Date: 2022.11.29 09:55:33 -09'00' Kyle Wiseman Hilcorp Alaska, LLC Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 11/21/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20221121 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# CLU 05RD2 50133204740200 222092 10/18/2022 AK E-Line Perf_GPT MGS S MGS Unit 11 50733201040000 168032 10/11/2022 AK E-Line LDL SRU 241-33 50133206630000 217047 8/29/2022 AK E-Line TTBP_Perf SRU 32A-33 50133101640100 191014 9/23/2022 AK E-Line GPT SCU 344-33 50133202930100 218054 9/11/2022 AK E-Line Punch BCU 18RD 50133205840100 222033 9/10/2022 AK E-Line GPT BCU 18RD 50133205840100 222033 9/18/2022 AK E-Line Stim BRU 233-23 50283201360100 222050 11/1/2022 AK E-Line Perf BRU 233-23 50283201360100 222050 9/12/2022 AK E-Line CIBP Please include current contact information if different from above. T37280 T37281 T37282 T37283 T37284 T37285 T37285 T37286 T37286 By Meredith Guhl at 2:54 pm, Nov 21, 2022 SCU 344-33 50133202930100 218054 9/11/2022 AK E-Line Punch Meredith Guhl Digitally signed by Meredith Guhl Date: 2022.11.21 14:55:38 -09'00' By Anne Prysunka at 2:47 pm, Oct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^Ͳϵϱ d^ ^ƵƌĨ͘ ϲ͕Ϯϱϵ͛ ϳ͟ WƌŽĚƵĐƚŝŽŶ Ϯϵ WͲϭϭϬ t ϲ͕ϬϬϬ͛ ϭϭ͕ϯϱϬ͛ ϮϬ͟ ϵϬ͛ ϭϯͲϯͬϴ͟ ϯ͕ϯϴϬ͛ ϳ͟ ϵͲϱͬϴ͟ ϲ͕Ϯϱϵ͛ :t>Zzd/> EK͘ ĞƉƚŚ / K /ƚĞŵ ϭ ϯϯϯ͛͛ ϯ͘ϴϭϯ͟ ϰ͘ϱ͟ yʹ>ĂŶĚŝŶŐEŝƉƉůĞ Ϯ ϲ͕ϬϬϬ͛ ϳ͟>ŝŶĞƌdŽƉWĂĐŬĞƌ ϯ ϭϬ͕ϲϰϭ͛ ϯ͘ϵϱϴ͟ ŶĐŚŽƌ>ĂƚĐŚ^ĞĂůƐƐĞŵďůǇ ϰ ϭϬ͕ϲϱϭ͛ ϱ͘Ϭ͟ ϱ͘ϱ͟ ^ĞĂůŽƌĞZĞĐĞƉƚĂĐůĞ ϱ ϭϬ͕ϲϱϳ͛ ϯ͘ϵϱϴ͟ ϳ͘Ϭ͟ WĞƌŵĂŶĞŶƚ,ǇĚƌĂƵůŝĐϳ͟ǆϰͲϭͬϮ͟WĂĐŬĞƌ ϲ ϭϬ͕ϲϲϲ͛ ϯ͘ϴϭϯ͟ ϰ͘ϱ͟ yʹ>ĂŶĚŝŶŐEŝƉƉůĞ ϳ ϭϬ͕ϲϳϳ͛ ϯ͘ϵϱϴ͟ ϰ͘ϱ͟ t>ŶƚƌǇ'ƵŝĚĞ y EĂŵĞ dŽƉ;DͿ ƚŵ;DͿ dŽƉ;dsͿ ƚŵ;dsͿ ĂƚĞ EŽƚĞƐ ,Ͳϯ ϭϬ͕ϴϯϬ͛ ϭϬ͕ϴϰϮ͛ ϭϬ͕ϯϮϭ͛ ϭϬ͕ϯϯϯ͛ ϭϮͬϭϳͬϭϴ KƉĞŶ ,Ͳϲ ϭϬ͕ϵϰϰ͛ ϭϬ͕ϵϱϵ͛ ϭϬ͕ϰϯϮ͛ ϭϬ͕ϰϰϳ͛ ϭϭͬϮϳͬϭϴ KƉĞŶ ,Ͳϳ ϭϬ͕ϵϳϴ͛ ϭϬ͕ϵϵϯ͛ ϭϬ͕ϰϱϵ͛ ϭϬ͕ϰϳϰ͛ ϭϬͬϭϲͬϭϴ KƉĞŶ ,Ͳϳ ϭϬ͕ϵϵϯ͛ ϭϭ͕ϬϬϴ͛ ϭϬ͕ϰϳϰ͛ ϭϬ͕ϰϵϱ͛ ϭϬͬϯϭͬϭϴ KƉĞŶ ϯϰ ,Ͳϳ tŝŶĚŽǁ ĐƵƚĂƚ ϲ͕Ϯϱϵ͛ ,Ͳϰ y ϭ hƉĚĂƚĞĚďǇ:>>ϬϴͬϭϴͬϮϮ WZKWK^ ^ǁĂŶƐŽŶZŝǀĞƌ&ŝĞůĚ tĞůů͗^hϯϰϰͲϯϯ Wd͗ϮϭϴͲϬϱϰ W/͗ϱϬͲϭϯϯͲϮϬϮϵϯͲϬϭͲϬϬ dсϭϭ͕ϯϴϭ͛DͬϭϬ͕ϴϲϬ͛ds Wdсϭϭ͕Ϯϭϳ͛DͬϭϬ͕ϲϵϵ͛ds DĂǆĞǀŝĂƚŝŽŶсϮϳ͘ϴΛϲ͕ϵϴϭ͛ '>͗ϭϮϱ͘ϱ͛D^> Z<ʹϭϴ͛'> dh/E'd/> ^ŝǌĞ dǇƉĞ tƚ 'ƌĂĚĞ ŽŶŶ / dŽƉ ƚŵ ϰͲϭͬϮ͟ dƵďŝŶŐ ϭϮ͘ϲ >ͲϴϬ /dD ϯ͘ϵϱϴ͟ ^ƵƌĨ ϭϬ͕ϲϳϳ͛ ϳ ϲ ϱ Ϯ ,Ͳϲͬ,Ͳϳ ^/E'd/> ^ŝǌĞ dǇƉĞ tƚ 'ƌĂĚĞ ŽŶŶ dŽƉ ƚŵ ϮϬ͟ ŽŶĚƵĐƚŽƌ Ͳ Ͳ Ͳ ^ƵƌĨ͘ ϵϬ͛ ϭϯͲϯͬϴ͟ ^ƵƌĨĂĐĞ ϲϴ <Ͳϱϱ d ^ƵƌĨ͘ ϯ͕ϯϴϬ͛ ϵͲϱͬϴ͟ ^ƵƌĨĂĐĞ ϰϳ ^Ͳϵϱ d^ ^ƵƌĨ͘ ϲ͕Ϯϱϵ͛ ϳ͟ WƌŽĚƵĐƚŝŽŶ Ϯϵ WͲϭϭϬ t ϲ͕ϬϬϬ͛ ϭϭ͕ϯϱϬ͛ ϮϬ͟ ϵϬ͛ ϭϯͲϯͬϴ͟ ϯ͕ϯϴϬ͛ ϳ͟ ϵͲϱͬϴ͟ ϲ͕Ϯϱϵ͛ :t>Zzd/> EK͘ ĞƉƚŚ / K /ƚĞŵ ϭ ϯϯϯ͛͛ ϯ͘ϴϭϯ͟ ϰ͘ϱ͟ yʹ>ĂŶĚŝŶŐEŝƉƉůĞ Ϯ ϲ͕ϬϬϬ͛ ϳ͟>ŝŶĞƌdŽƉWĂĐŬĞƌ ϯ ϭϬ͕ϲϰϭ͛ ϯ͘ϵϱϴ͟ ŶĐŚŽƌ>ĂƚĐŚ^ĞĂůƐƐĞŵďůǇ ϰ ϭϬ͕ϲϱϭ͛ ϱ͘Ϭ͟ ϱ͘ϱ͟ ^ĞĂůŽƌĞZĞĐĞƉƚĂĐůĞ ϱ ϭϬ͕ϲϱϳ͛ ϯ͘ϵϱϴ͟ ϳ͘Ϭ͟ WĞƌŵĂŶĞŶƚ,ǇĚƌĂƵůŝĐϳ͟ǆϰͲϭͬϮ͟WĂĐŬĞƌ ϲ ϭϬ͕ϲϲϲ͛ ϯ͘ϴϭϯ͟ ϰ͘ϱ͟ yʹ>ĂŶĚŝŶŐEŝƉƉůĞ ϳ ϭϬ͕ϲϳϳ͛ ϯ͘ϵϱϴ͟ ϰ͘ϱ͟ t>ŶƚƌǇ'ƵŝĚĞ y EĂŵĞ dŽƉ;DͿ ƚŵ;DͿ dŽƉ;dsͿ ƚŵ;dsͿ ĂƚĞ EŽƚĞƐ 'ͲϮdŚƌƵ,Ͳϵ цϭϬ͕ϲϴϯ͛ цϭϭ͕ϭϲϮ͛ цϭϬ͕ϭϳϳ͛ цϭϬ͕ϲϰϲ͛ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ ,Ͳϯ ϭϬ͕ϴϯϬ͛ ϭϬ͕ϴϰϮ͛ ϭϬ͕ϯϮϭ͛ ϭϬ͕ϯϯϯ͛ ϭϮͬϭϳͬϭϴ KƉĞŶ ,Ͳϲ ϭϬ͕ϵϰϰ͛ ϭϬ͕ϵϱϵ͛ ϭϬ͕ϰϯϮ͛ ϭϬ͕ϰϰϳ͛ ϭϭͬϮϳͬϭϴ KƉĞŶ ,Ͳϳ ϭϬ͕ϵϳϴ͛ ϭϬ͕ϵϵϯ͛ ϭϬ͕ϰϱϵ͛ ϭϬ͕ϰϳϰ͛ ϭϬͬϭϲͬϭϴ KƉĞŶ ,Ͳϳ ϭϬ͕ϵϵϯ͛ ϭϭ͕ϬϬϴ͛ ϭϬ͕ϰϳϰ͛ ϭϬ͕ϰϵϱ͛ ϭϬͬϯϭͬϭϴ KƉĞŶ ϯ ϰ ,Ͳϳ tŝŶĚŽǁ ĐƵƚĂƚ ϲ͕Ϯϱϵ͛ ,Ͳϰ y ϭ 'ͲϮ ƚŚƌƵ ,Ͳϵ dďŐ WƵŶĐŚ цϭϬ͕ϲϰϮ͛ hd/KE͗ǆƚĞƌŶĂůƐĞŶĚĞƌ͘KEKdŽƉĞŶůŝŶŬƐŽƌĂƚƚĂĐŚŵĞŶƚƐĨƌŽŵhE<EKtEƐĞŶĚĞƌƐ͘ )URP5\DQ5XSHUW 7R0F/HOODQ%U\DQ-2*& 6XEMHFW5(>(;7(51$/@5(6&837' 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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: Convert to Producer 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 11,381 feet N/A feet true vertical 10,856 feet N/A feet Effective Depth measured 11,350 feet See Schematic feet true vertical 10,830 feet See Schematic feet Perforation depth Measured depth 10,830 - 11,008 feet True Vertical depth 10,321 - 10,495 feet Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6 / L-80 10,677 (MD) 10,172 (TVD) Packers and SSSV (type, measured and true vertical depth)See schematic 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 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: 7,100psi 8,530psi 3,450psi 8,150psi 11,220psi Burst Collapse 1,950psi 90' 3,380' 6,258' 10,830' 6,259' 11,350'7" measuredPlugs Junk measured N/A Length 90' 3,380' Size Conductor Surface Intermediate 20" 13-3/8" 9-5/8" Production Liner 6,259' 5,350' Casing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 218-054 50133-20293-01-00 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: FEDA028990 / FEDA028997 Swanson River Field / Hemlock Oil Pool Hilcorp Alaska LLC 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Soldonta Creek Unit 344-33 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 080 0 2,424 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 90' 3,380' N/A 15 Structural TVD 321-406 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: Authorized Name and Digital Signature with Date: WINJ WAG 7,223 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 0 122 Ryan Rupert ryan.rupert@hilcorp.com (907) 777-8305Dan Marlowe, Operations Manager L G Form 10-404 Revised 10/2021 Submit Within 30 days of Operations By Samantha Carlisle at 12:45 pm, Nov 23, 2021 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.11.23 11:11:01 -09'00' Dan Marlowe (1267) DSR-11/23/2112/1/21 RBDMS HEW 11/24/2021 SFD 11/29/2021 Updated by JLL 11/22/21 SCHEMATIC Swanson River Field Well: SCU 344-33 PTD: 218-054 API: 50-133-20293-01-00 TD = 11,381’ MD / 10,860’ TVD PBTD = 11,217’ MD / 10,699’ TVD Max Deviation = 27.8° @ 6,981’ GL: 125.5’ AMSL RKB –18’ AGL TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 4-1/2” Tubing 12.6 L-80 IBTM 3.958” Surf 10,677’ 7 6 5 2 H-6/H-7 CASING DETAIL Size Type Wt Grade Conn Top Btm 20” Conductor - - - Surf. 90’ 13-3/8” Surface 68 K-55 BTC Surf. 3,380’ 9-5/8” Surface 47 S-95 BTS Surf. 6,259’ 7” Production 29 P-110 DWC 6,000’ 11,350’ 20” 90’ 13-3/8” 3,380’ 7” 9-5/8” 6,259’ JEWELRY DETAIL NO. Depth ID OD Item 1 333’’ 3.813” 4.5” X – Landing Nipple 2 6,000’ 7” Liner Top Packer 3 10,641’ 3.958” Anchor Latch Seal Assembly 4 10,651’ 5.0” 5.5” Seal Bore Receptacle 5 10,657’ 3.958” 7.0” Permanent Hydraulic 7” x 4-1/2” Packer 6 10,666’ 3.813” 4.5” X – Landing Nipple 7 10,677’ 3.958” 4.5” WL Entry Guide X PERFORATIONS New Name Old Name Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Notes H-4 H-1 10,830’ 10,842’ 10,321’ 10,333’ 12/17/18 Open H-6/H-7 H-5 10,944’ 10,959’ 10,432’ 10,447’ 11/27/18 Open H-7 H-5 10,978’ 10,993’ 10,459’ 10,474’ 10/16/18 Open H-7 H-5 10,993’ 11,008’ 10,474’ 10,495’ 10/31/18 Open 34 H-7 Window cut at 6,259’ H-4 X 1 Rig Start Date End Date NA 8/17/21 11/1/21 08/17/2021 - Tuesday SI injection. Start to prep well for conversion to producer. 08/19/2021 - Thursday RIG UP W/L - PT LUB 250/2,500 PSI - GOOD. RIH W/ 4-1/2 XX EQUALIZING PRONG TO 333'KB WT - WELL GAINS PRESSURE TO 2,100 PSI. RIH W/ 3.81" GAUGE RING TO 333'KB TAG TOP OF MCX - POOH. RIH W/ 4-1/2 GS TO 333'KB WT - LATCH - HAND SPANG FREE - POOH - TO 136'KB HANG UP. WT HAND SPANG FREE - POOH - OOH W/ MCX COVERED IN GREASE AND GRIT. RIG DOWN W/L - MOB TO SCU 322-C04. Temporary hardline piping and SSV installed. 08/27/2021- Friday 11/01/2021 - Monday Well unable to sustain constant production, but has shown a few promising short buildup/production periods. Talked to reservoir engineer, and no further evaluation needed. Can stay a cycle/milk producer for now. Got final approval. Brought on production. 08/31/2021 - Tuesday SSV tested and passed (State notification given, but no witness). Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name SCU 344-33 50-133-20293-01-00 218-054 - POOH - OOH W/ MCX COVERED IN GREASE AND GRIT. Temporary hardline piping and SSV installed. - WELL GAINS PRESSURE TO 2,100 PSI. 1 Guhl, Meredith D (CED) From:McLellan, Bryan J (CED) Sent:Monday, September 27, 2021 12:09 PM To:Todd Sidoti - (C) Subject:RE: [EXTERNAL] SCU 344-33 (PTD 218-054) 10-404 Todd, My apologies for the conflicting or confusing statements on the Sundry. You can perform the MIT‐IA to 2600 psi on 8/14/22, which is 4 years since the previous test as required by AIO 13 A. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Todd Sidoti ‐ (C) <Todd.Sidoti@hilcorp.com> Sent: Monday, September 27, 2021 11:49 AM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] SCU 344‐33 (PTD 218‐054) 10‐404 Hi Bryan, I guess that I might have interpreted your Sundry conditions incorrectly. My sundry stated “Passing MIT‐IA to 2500 psi on 8‐14‐18” and your comment was “Next MITIA due on 8‐14‐22”. I missed on the additional 100 psi to bring it up to 2600. Would you like me to perform a MIT‐IA on the well to 2600 psi immediately or wait until 8‐14‐22? I know that you guys want us to include MIT results in our 404s and have been working toward making that happen consistently. Thanks, Todd From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Sent: Monday, September 27, 2021 11:35 AM To: Todd Sidoti ‐ (C) <Todd.Sidoti@hilcorp.com> Subject: [EXTERNAL] SCU 344‐33 (PTD 218‐054) 10‐404 Todd, The 10‐404 for Sundry 321‐306 does not mention the MITA to 2600 psi having been done. Please send the MITIA test report to include with the 10‐404. Bryan McLellan Senior Petroleum Engineer 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: Convert to Injectorr 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 11,381 feet N/A feet true vertical 10,856 feet N/A feet Effective Depth measured 11,350 feet 6,000' ;10,657 feet true vertical 10,830 feet 5,999'; 10,152' feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# / L-80 10,677' MD 10,172' TVD 6,000 MD/5,999'TVD Packers and SSSV (type, measured and true vertical depth)Perm Hydraul Pkr; N/A10,657'MD/10,152'TVD 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: Taylor Wellman 777-8449 Contact Name:Todd Sidoti Authorized Title:Operations Manager Contact Email: Contact Phone:777-8443 WINJ WAG 0 Water-Bbl MD 90' 3,380' 0 Liner Top Pkr, Oil-Bbl measured true vertical Packer 7"11,350' 6,258' 10,830' measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Swanson River / Hemlock OilN/A measured TVD Tubing Pressure 1,0000 Soldotna Creek Unit (SCU) 344-33 N/A FEDA028990, FEDA028997 6,259' Plugs Junk STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 218-054 50-133-20293-01-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-306 2,348 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 7 Authorized Signature with date: Authorized Name: 14 Casing Pressure Liner 0 0 Representative Daily Average Production or Injection Data 90' 3,380' 6,259' 5,350' Conductor Surface Intermediate Production 8,530psi Casing Structural 20" 13-3/8" 9-5/8" Length 8,150psi 3,450psi Collapse 1,950psi 7,100psi todd.sidoti@hilcorp.com Senior Engineer:Senior Res. Engineer: Burst 11,220psi 90' 3,380' t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 8:39 am, Aug 18, 2021 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.08.17 15:41:25 -08'00' Taylor Wellman (2143) SFD 8/18/2021 RBDMS HEW 8/19/2021 DSR-8/18/21BJM 9/27/21 SFD 8/18/2021 Rig Start Date End Date 5/31/21 8/15/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name SCU 344-33 50-133-20293-01-00 218-054 08/15/2021 - Sunday Discussion with gas control, RE and Operations. Decision made to stop the gas flood pattern on 344-33 in order to put more gas into storage. 05/31/2021 -Monday Arrive on location. Sign into field and hold PJSM. Pressure test lubricator to 2,500 psi, good test. RIH with 2.83" GR to 11,191'. RIH with 3.85" GR to 61'. RIH with 3.81" GR to X nipple at 319'. RIH with Xline running tool and injection valve. Set injection valve in X nipple at 319'. RDMO. 07/08/2021 - Thursday Put well on gas injection at 2 mmscfd. Ramp up to 9 mmscfd. Note: MITIA not required until 8/14/22, 4 years after the previous MITIA. Note attached to wellfile to confirm. bjm Updated by DMA 08-17-21 SCHEMATIC Swanson River Field Well: SCU 344-33 PTD: 218-054 API: 50-133-20293-01-00 TD = 11,381’ MD / 10,860’ TVD PBTD = 11,217’ MD / 10,699’ TVD Max Deviation = 27.8° @ 6,981’ GL: 125.5’ AMSL RKB –18’ AGL TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 4-1/2” Tubing 12.6 L-80 IBTM 3.958” Surf 10,677’ 7 6 5 2 H-6/H-7 CASING DETAIL Size Type Wt Grade Conn Top Btm 20” Conductor - - - Surf. 90’ 13-3/8” Surface 68 K-55 BTC Surf. 3,380’ 9-5/8” Surface 47 S-95 BTS Surf. 6,259’ 7” Production 29 P-110 DWC 6,000’ 11,350’ 20” 90’ 13-3/8” 3,380’ 7” 9-5/8” 6,259’ JEWELRY DETAIL NO. Depth ID OD Item 1 328’ 3.813” 4.5” X – Landing Nipple with MCX Installed 2 6,000’ 7” Liner Top Packer 3 10,641’ 3.958” Anchor Latch Seal Assembly 4 10,651’ 5.0” 5.5” Seal Bore Receptacle 5 10,657’ 3.958” 7.0” Permanent Hydraulic 7” x 4-1/2” Packer 6 10,666’ 3.813” 4.5” X – Landing Nipple 7 10,677’ 3.958” 4.5” WL Entry Guide X PERFORATIONS New Name Old Name Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Notes H-4 H-1 10,830’ 10,842’ 10,321’ 10,333’ 12/17/18 Open H-6/H-7 H-5 10,944’ 10,959’ 10,432’ 10,447’ 11/27/18 Open H-7 H-5 10,978’ 10,993’ 10,459’ 10,474’ 10/16/18 Open H-7 H-5 10,993’ 11,008’ 10,474’ 10,495’ 10/31/18 Open 3 4 H-7 Window cut at 6,259’ H-4 X 1 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: Convert to Producer 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: Gas Injection 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): 11,381'N/A Casing Collapse Structural Conductor Surface 1,950psi Intermediate 7,100psi Production 8,530psi 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 N/A 7" Liner Top Packer, 7" x 4-1/2" Perm Packer ; N/A Perforation Depth TVD (ft): Tubing Size: 10,677' Length Size COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028990, FEDA028997 218-054 50-133-20293-01-00 Soldotna Creek Unit (SCU) 344-33 Swanson River / Hemlock Oil CO 123B Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY 10,856' 11,350' 10,830' 180 TVD Burst 11,220psi MD 8,150psi 3,450psi 90' 3,380' 6,258' 90' 3,380' 10,830'11,350' 20" 13-3/8" 90' 9-5/8"6,259' 3,380' 6,259' See Attached Schematic 5,350' Authorized Signature: August 27, 2021 4-1/2" 12.6 # / L-80 6,000' MD/5,999'TVD; 10,657'MD/10,152'TVD; N/A Perforation Depth MD (ft): todd.sidoti@hilcorp.comAuthorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. 7" wwnn amamm cececeee eee d ed ss No ss No Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 8:39 am, Aug 18, 2021 321-406 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.08.17 14:50:41 -08'00' Taylor Wellman (2143) BJM 8/27/21 DSR-8/18/21 10-404 SFD 8/18/2021 SFD 8/18/2021 JLC 8/27/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.08.27 15:06:34 -08'00' RBDMS HEW 8/30/2021 Well Prognosis Well: SCU 344-33 Date: 08/11/2021 1 Well Name: SCU 344-33 API Number: 50-133-20293-01-00 Current Status: Gas Injector Leg: N/A Estimated Start Date: 8/27/21 Rig: Slickline Reg. Approval Req’d? 10-403 Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-217 First Call Engineer: Todd Sidoti (907) 777-8443 (O)(907) 632-4113 (C) Second Call Engineer: Jake Flora (907) 777-8442 (O)(720) 988-5375 (C) AFE Number: Maximum Expected BHP: 1,210 psi @ 10,300’ TVD (Based on SITP plus 0.1 psi/ft) Max. Possible Surface Pressure (MPSP) 180 psi (BHP - 0.1psi/ft gradient) Brief Well Summary SCU 344-33 is a gas flood injector currently online. The purpose of this work is to temporarily convert SCU 344- 33 into a producer. This change is necessary in order to provide more gas volume into our storage reservoirs which are currently trending at lower volumes than previous years. Procedure: 1. RU temporary flowback equipment including horizontal SSV and choke. 2. MIRU SL and pressure test Lubricator to 250 psi low / 2,000 psi high. 3. RIH W/ Retrieving tool and pull Injection Valve from X-nipple @ 320’. RDMO SL. 4. Flow Well through high pressure header to Tank Setting 1-4. Test SSV within 5 days (Notify AOGCC 24 hours in advance to give them the opportunity to witness). Attachments: 1. Surface Configuration 2. Actual Schematic 3. Proposed Schematic Ensure SSV test procedure is modified as needed for the temporary piping setup. bjm. 218-054 SFD 8/18/2021 pp y in order to provide more gas volume into our storage reservoirs temporarily convert SCU 344-pyg 33 into a producer. Updated by DMA 08-17-21 SCHEMATIC Swanson River Field Well: SCU 344-33 PTD: 218-054 API: 50-133-20293-01-00 TD = 11,381’ MD / 10,860’ TVD PBTD = 11,217’ MD / 10,699’ TVD Max Deviation = 27.8° @ 6,981’ GL: 125.5’ AMSL RKB –18’ AGL TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 4-1/2” Tubing 12.6 L-80 IBTM 3.958” Surf 10,677’ 7 6 5 2 H-6/H-7 CASING DETAIL Size Type Wt Grade Conn Top Btm 20” Conductor - - - Surf. 90’ 13-3/8” Surface 68 K-55 BTC Surf. 3,380’ 9-5/8” Surface 47 S-95 BTS Surf. 6,259’ 7” Production 29 P-110 DWC 6,000’ 11,350’ 20” 90’ 13-3/8” 3,380’ 7” 9-5/8” 6,259’ JEWELRY DETAIL NO. Depth ID OD Item 1 328’ 3.813” 4.5” X – Landing Nipple with MCX Installed 2 6,000’ 7” Liner Top Packer 3 10,641’ 3.958” Anchor Latch Seal Assembly 4 10,651’ 5.0” 5.5” Seal Bore Receptacle 5 10,657’ 3.958” 7.0” Permanent Hydraulic 7” x 4-1/2” Packer 6 10,666’ 3.813” 4.5” X – Landing Nipple 7 10,677’ 3.958” 4.5” WL Entry Guide X PERFORATIONS New Name Old Name Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Notes H-4 H-1 10,830’ 10,842’ 10,321’ 10,333’ 12/17/18 Open H-6/H-7 H-5 10,944’ 10,959’ 10,432’ 10,447’ 11/27/18 Open H-7 H-5 10,978’ 10,993’ 10,459’ 10,474’ 10/16/18 Open H-7 H-5 10,993’ 11,008’ 10,474’ 10,495’ 10/31/18 Open 3 4 H-7 Window cut at 6,259’ H-4 X 1 Updated by DMA 08-17-21 PROPOSED SCHEMATIC Swanson River Field Well: SCU 344-33 PTD: 218-054 API: 50-133-20293-01-00 TD = 11,381’ MD / 10,860’ TVD PBTD = 11,217’ MD / 10,699’ TVD Max Deviation = 27.8° @ 6,981’ GL: 125.5’ AMSL RKB –18’ AGL TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 4-1/2” Tubing 12.6 L-80 IBTM 3.958” Surf 10,677’ 7 6 5 2 H-6/H-7 CASING DETAIL Size Type Wt Grade Conn Top Btm 20” Conductor - - - Surf. 90’ 13-3/8” Surface 68 K-55 BTC Surf. 3,380’ 9-5/8” Surface 47 S-95 BTS Surf. 6,259’ 7” Production 29 P-110 DWC 6,000’ 11,350’ 20” 90’ 13-3/8” 3,380’ 7” 9-5/8” 6,259’ JEWELRY DETAIL NO. Depth ID OD Item 1 328’ 3.813” 4.5” X – Landing Nipple 2 6,000’ 7” Liner Top Packer 3 10,641’ 3.958” Anchor Latch Seal Assembly 4 10,651’ 5.0” 5.5” Seal Bore Receptacle 5 10,657’ 3.958” 7.0” Permanent Hydraulic 7” x 4-1/2” Packer 6 10,666’ 3.813” 4.5” X – Landing Nipple 7 10,677’ 3.958” 4.5” WL Entry Guide X PERFORATIONS New Name Old Name Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Notes H-4 H-1 10,830’ 10,842’ 10,321’ 10,333’ 12/17/18 Open H-6/H-7 H-5 10,944’ 10,959’ 10,432’ 10,447’ 11/27/18 Open H-7 H-5 10,978’ 10,993’ 10,459’ 10,474’ 10/16/18 Open H-7 H-5 10,993’ 11,008’ 10,474’ 10,495’ 10/31/18 Open 3 4 H-7 Window cut at 6,259’ H-4 X 1 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: Convert to Injector 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6. API Number: Gas Injection 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): 11,381'N/A Casing Collapse Structural Conductor Surface 1,950psi Intermediate 7,100psi Production 8,530psi 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 180 N/A 7" Liner Top Packer, 7" x 4-1/2" Perm Packer ; N/A Perforation Depth TVD (ft): Tubing Size: 10,677' COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028990, FEDA028997 218-054 50-133-20293-01-00 Soldotna Creek Unit (SCU) 344-33 Swanson River / Hemlock Oil Length Size CO 123B Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY 10,856' 11,350' 10,830' TVD Burst 11,220psi MD 8,150psi 3,450psi 90' 3,380' 6,258' 90' 3,380' 10,830'11,350' 20" 13-3/8" 90' 9-5/8"6,259' 3,380' 6,259' See Attached Schematic 5,350' 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. 7" Authorized Signature: July 8, 2021 4-1/2" 12.6 # / L-80 6,000' MD/5,999'TVD; 10,657'MD/10,152'TVD; N/A Perforation Depth MD (ft): todd.sidoti@hilcorp.com Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 3:52 pm, Jun 22, 2021 321-306 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.06.22 15:35:16 -08'00' Taylor Wellman (2143) DSR-6/24/21 X MITIA to 2600 psi required before initiating injection and every 4 years thereafter, per AIO 13A. BJM 7/1/21 SFD 6/23/2021 10-404 X CDW 6/29/2021 dts 7/1/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.07.06 11:36:11 -08'00' RBDMS HEW 7/7/2021 Well Prognosis Well: SCU 344-33 Date: 06/11/2021 1 Well Name: SCU 344-33 API Number: 50-133-20293-01 Current Status: Gas Producer Leg: N/A Estimated Start Date: 7/8/21 Rig: Slickline Reg. Approval Req’d? 10-403 Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 218-054 First Call Engineer: Todd Sidoti (907) 777-8443 (O) (907) 632-4113 (C) Second Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) AFE Number: Maximum Expected BHP: 1210 psi @ 10,300’ TVD (Based Surf. Press. Plus 0.1 psi/ft grad.) Max. Potential Surface Pressure: 180 psi (0.1psi/ft gradient to 10,300ft TVD) Max. Possible Surface Pressure (MPSP) 180 psi (0.1psi/ft gradient to 10,300ft TVD) Brief Well Summary SCU 344-33 is a gas injection well which was temporarily converted to and used as a gas producer in 2020. The well is brought online periodically and makes ~10-50 mcf per cycle. The well will now be put back on injection. Gas will be injected into the H4, H6, and H7 sands within the Hemlock reservoir. The purpose of this work/sundry is to convert SCU 344-33 to an injector. Notes - Passing MIT-IA to 2500 psi on 08-14-18. - Well was previously on gas injection as approved by PTD 218-054. Area of Review Prior to the conversion of well SCU 344-33 from producer to gas injector, an Area of Review (AOR) was conducted. This AOR found six other wells (SCU 34-33, SCU 44-33, SCU 44B-33, SCU 41B-04, SCU 341-04 & SCU 41A-04) within ¼ mile of SCU 344-33’s entry point into the Hemlock Formation. See attached table Area of Review SCU 344-33 for annular integrity and zonal isolation of all wells within the AOR. Procedure 1. RU gas injection hard line on surface and remove SSV. 2. MIRU SL and pressure test Lubricator to 250 psi low and 1000 psi. 3. RIH and install MCX injection valve in X-nipple @ 10,666’. Attachments: 1. Actual Schematic 2. Proposed Schematic 3. AOR Table 4. AOR Map Passing MIT-IA to 2500 psi on 08-14-18. remove SSV. MITIA to 2600 psi required before initiating injection and every 4 years thereafter, per AIO 13A. Install SSV. Test Safety valve system within 5 days of return to injection. Next MITIA due on 8-14-22 bjm Gas injection header pressure = 3600 psi Area Injection order 13-A applies. Updated by DMA 10-16-19 SCHEMATIC Swanson River Field Well: SCU 344-33 PTD: 218-054 API: 50-133-20293-01 TD = 11,381’ MD / 10,860’ TVD PBTD = 11,217’ MD / 10,699’ TVD Max Deviation = 27.8° @ 6,981’ GL: 125.5’ AMSL RKB –18’ AGL TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 4-1/2” Tubing 12.6 L-80 IBTM 3.958” Surf 10,677’ 6 5 4 1 H-6/H-7 CASING DETAIL Size Type Wt Grade Conn Top Btm 20” Conductor - - - Surf. 90’ 13-3/8” Surface 68 K-55 BTC Surf. 3,380’ 9-5/8” Surface 47 S-95 BTS Surf. 6,259’ 7” Production 29 P-110 DWC 6,000’ 11,350’ 20” 90’ 13-3/8” 3,380’ 7” 9-5/8” 6,259’ JEWELRY DETAIL NO. Depth ID OD Item 1 6,000’ 7” Liner Top Packer 2 10,641’ 3.958” Anchor Latch Seal Assembly 3 10,651’ 5.0” 5.5” Seal Bore Receptacle 4 10,657’ 3.958” 7.0” Permanent Hydraulic 7” x 4-1/2” Packer 5 10,666’ 3.813” 4.5” X – Landing Nipple 6 10,677’ 3.958” 4.5” WL Entry Guide X PERFORATIONS New Name Old Name Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Notes H-4 H-1 10,830’ 10,842’ 10,321’ 10,333’ 12/17/18 Open H-6/H-7 H-5 10,944’ 10,959’ 10,432’ 10,447’ 11/27/18 Open H-7 H-5 10,978’ 10,993’ 10,459’ 10,474’ 10/16/18 Open H-7 H-5 10,993’ 11,008’ 10,474’ 10,495’ 10/31/18 Open 2 3 H-7 Window cut at 6,259’ H-4 Updated by TCS 6-10-21 SCHEMATIC Swanson River Field Well: SCU 344-33 PTD: 218-054 API: 50-133-20293-01 TD = 11,381’ MD / 10,860’ TVD PBTD = 11,217’ MD / 10,699’ TVD Max Deviation = 27.8° @ 6,981’ GL: 125.5’ AMSL RKB –18’ AGL TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 4-1/2” Tubing 12.6 L-80 IBTM 3.958” Surf 10,677’ 6 5 4 1 H-6/H-7 CASING DETAIL Size Type Wt Grade Conn Top Btm 20” Conductor - - - Surf. 90’ 13-3/8” Surface 68 K-55 BTC Surf. 3,380’ 9-5/8” Surface 47 S-95 BTS Surf. 6,259’ 7” Production 29 P-110 DWC 6,000’ 11,350’ 20” 90’ 13-3/8” 3,380’ 7” 9-5/8” 6,259’ JEWELRY DETAIL NO. Depth ID OD Item 1 6,000’ 7” Liner Top Packer 2 10,641’ 3.958” Anchor Latch Seal Assembly 3 10,651’ 5.0” 5.5” Seal Bore Receptacle 4 10,657’ 3.958” 7.0” Permanent Hydraulic 7” x 4-1/2” Packer 5 10,666’ 3.813” 4.5” X – Landing Nipple with MCX installed 6 10,677’ 3.958” 4.5” WL Entry Guide X PERFORATIONS New Name Old Name Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Notes H-4 H-1 10,830’ 10,842’ 10,321’ 10,333’ 12/17/18 Open H-6/H-7 H-5 10,944’ 10,959’ 10,432’ 10,447’ 11/27/18 Open H-7 H-5 10,978’ 10,993’ 10,459’ 10,474’ 10/16/18 Open H-7 H-5 10,993’ 11,008’ 10,474’ 10,495’ 10/31/18 Open 2 3 H-7 Window cut at 6,259’ H-4 API WELL STATUSTop of H1(MD)Top of H1(TVD)Base of H9(MD)Base of H9(TVD)CBL Top ofCement(MD)CBL Top ofCement(TVD) H1/H9 StatusAnnularIntegrityZonal Isolation50-133-10165-00-00 SCU 34-33 P&A 10308 10307 10720 10720 **8,017 7,860Plug &AbandonedN/ACBL malfunctioned. 2ndStage DV collar locatedat 8017ft md.50-133-20237-01-00 SCU 44-33 Suspended 11521 10285 12325 10698 9,250 8,990Perfs in H6, H7,H7L, and H9MIT-IA to 1500psi passed8/10/201750-133-10170-01-00 SCU 44B-33 Online 10591 10294 11266 10720 9,544 9,400Perfs in H1, H2,H3, H5, H7, andH9MIT-IA to 2000psi passed2/11/201950-133-10109-03-00 SCU 41B-04 Online 10399 10321 10859 10707 9,784 9,580Perfs in H1, H7,and H9MIT-IA passedto 3000 psi on1/29/201550-133-10109-00-00 SCU 341-04 P&A 10231 10231 10615 10615 5,820 5,650Plug &AbandonedN/A50-133-10109-02-00 SCU 41A-04 P&A 10252 10234 10668 10627 9,600 9,415Plug &AbandonedN/AArea Of Review for SCU 344-33 FlowlineDisconnectedInjection LineSCU 344-33 Tree DiagramSSV 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: Convert to Producer 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 11,381 feet N/A feet true vertical 10,856 feet N/A feet Effective Depth measured 11,350 feet 6,000' ;10,657 feet true vertical 10,830 feet 5,999'; 10,152' feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# / L-80 10,677' MD 10,172' TVD 6,000 MD/5,999'TVD Packers and SSSV (type, measured and true vertical depth)Perm Hydraul Pkr; N/A10,657'MD/10,152'TVD 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: Taylor Wellman 777-8449 Contact Name:Ted Kramer Authorized Title:Operations Manager Contact Email: Contact Phone:777-8420 WINJ WAG 0 Water-Bbl MD 90' 3,380' 0 Swell Packer, Oil-Bbl measured true vertical Packer 7"11,350' 6,258' 10,830' measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Swanson River / Hemlock OilN/A measured TVD Tubing Pressure 3,0750 Soldotna Creek Unit (SCU) 344-33 N/A FEDA028990, FEDA0-28997 6,259' Plugs Junk STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 218-056 50-133-20293-01-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-265 720 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 0 Authorized Signature with date: Authorized Name: 0 Casing Pressure Liner 4,126 0 Representative Daily Average Production or Injection Data 90' 3,380' 6,259' 5,350' Conductor Surface Intermediate Production 8,530psi Casing Structural 20" 13-3/8" 9-5/8" Length 8,150psi 3,450psi Collapse 1,950psi 7,100psi tkramer@hilcorp.com Senior Engineer:Senior Res. Engineer: Burst 11,220psi 90' 3,380' t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 1:16 pm, Nov 04, 2020 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.11.04 11:35:57 -09'00' Taylor Wellman SFD 11/5/2020 Convert to Producer SFD 11/5/2020 218-054 RBDMS HEW 11/5/2020 Gas DSR-11/4/202011/23/20 gls Rig Start Date End Date 5/25/20 10/15/20 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name SCU 344-33 50-133-20647-00-00 214-173 10/15/2020 - Thursday Discussed With AOGCC that there was never a 10-404 filed on this well. Researched how the trigger was not activated in our tracking. Found that this well was never placed in Well-Ez by the field. 06/25/2020 - Thursday CALL OUT RECEIVED - RETRIEVE EQUIPMENT - MOB TO LOCATION FROM PWL SHOP. ON LOCATION - TGSM - JSA - PERMIT. MOB TO WELL - RIG UP WL - PT LUB - FAIL - CHANGE OUT NEEDLE VALVE - RETEST - GOOD. RIH W/ XX EQUALIZING PRONG TO 338'KB WT - PRESSURE CLIMBS TO 1,200 PSI - POOH. RIH W/ 4-1/2 GS W/ 5' 1.5" PRONG TO 338'KB WT - CAN NOT LATCH - POOH - OOH W/ TOOLS. COVERED IN GREASE - CLEAN TOOLS - REMOVE PRONG. RIH W/ SAME TO 338'KB WT LATCH VALVE - ONE SPANG LICK - COME FREE - POOH - OOH W/ MXC. MOB TO 332-4 TO ASSIST PRODUCTION W/ CRANE SUPPORT. MOB TO 241-16. Daily Operations: pull MCX valve - POOH - OOH W/ MXC. Updated by DMA 10-16-19 SCHEMATIC Swanson River Field Well: SCU 344-33 PTD: 218-054 API: 50-133-20293-01 TD = 11,381’ MD / 10,860’ TVD PBTD = 11,217’ MD / 10,699’ TVD Max Deviation = 27.8° @ 6,981’ GL: 125.5’ AMSL RKB –18’ AGL TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 4-1/2” Tubing 12.6 L-80 IBTM 3.958” Surf 10,677’ 6 5 4 1 H-6/H-7 CASING DETAIL Size Type Wt Grade Conn Top Btm 20” Conductor - - - Surf. 90’ 13-3/8” Surface 68 K-55 BTC Surf. 3,380’ 9-5/8” Surface 47 S-95 BTS Surf. 6,259’ 7” Production 29 P-110 DWC 6,000’ 11,350’ 20” 90’ 13-3/8” 3,380’ 7” 9-5/8” 6,259’ JEWELRY DETAIL NO. Depth ID OD Item 1 6,000’ 7” Liner Top Packer 2 10,641’ 3.958” Anchor Latch Seal Assembly 3 10,651’ 5.0” 5.5” Seal Bore Receptacle 4 10,657’ 3.958” 7.0” Permanent Hydraulic 7” x 4-1/2” Packer 5 10,666’ 3.813” 4.5” X – Landing Nipple 6 10,677’ 3.958” 4.5” WL Entry Guide X PERFORATIONS New Name Old Name Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Notes H-4 H-1 10,830’ 10,842’ 10,321’ 10,333’ 12/17/18 Open H-6/H-7 H-5 10,944’ 10,959’ 10,432’ 10,447’ 11/27/18 Open H-7 H-5 10,978’ 10,993’ 10,459’ 10,474’ 10/16/18 Open H-7 H-5 10,993’ 11,008’ 10,474’ 10,495’ 10/31/18 Open 2 3 H-7 Window cut at 6,259’ H-4 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: Convert to Producer 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): 11,381'N/A Casing Collapse Structural Conductor Surface 1,950psi Intermediate 7,100psi Production 8,530psi 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: Ted Kramer Operations Manager Contact Email: Contact Phone: 777-8420 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: June 25, 2020 4-1/2"12.6 # / L-80 6,000' MD/5,999'TVD; 10,657'MD/10,152'TVD; N/A 11,350' Perforation Depth MD (ft): 6,259' See Attached Schematic 5,350'10,830'7" 20" 13-3/8" 90' 9-5/8"6,259' 3,380'3,450psi 90' 3,380' 6,258' 90' 3,380' TVD Burst 11,220psi MD 8,150psi 10,677' Length Size CO 123B 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 FEDA028990, FEDA028997 218-054 50-133-20293-01-00 Soldotna Creek Unit (SCU) 344-33 Swanson River / Hemlock Oil COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic tkramer@hilcorp.com 10,856'11,350'10,830'180 N/A Perforation Depth TVD (ft):Tubing Size: m n P 66 t r Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 8:53 am, Jun 16, 2020 320-265 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.06.16 07:38:20 -08'00' Taylor Wellman DSR-6/16/2020DLB 06/16/2020 X Convert to Producerr Service GAS gas injection 10-404 gls 6/16/20 Comm 6/17/2020 dts 6/17/2020 RBDMS HEW 6/18/2020 Well Prognosis Well: SCU 344-33 Date: 06/11/2020 1 Well Name: SCU_344-33 API Number: 50-133-20293-01 Current Status: Gas Injector Leg: N/A Estimated Start Date: 6/25/20 Rig: Slickline Reg. Approval Req’d? 10-403 Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 218-054 First Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) Second Call Engineer: Christina Twogood (907) 777-8443 (O) (907) 378-7323 (C) AFE Number: Maximum Expected BHP: 1,210 psi @ 10,300’ TVD (Based Surf. Press. Plus 0.1 psi/ft grad.) Max. Potential Surface Pressure: 180 psi (0.1psi/ft gradient to 10,300ft TVD) Max. Possible Surface Pressure (MPSP) 180 psi (0.1psi/ft gradient to 10,300ft TVD) Brief Well Summary SCU 344-33 is currently a Shut in gas injection well which injected into the H4, H6, and H7 sands within the Hemlock reservoir. The well was recently SI due to economic reasons. Field observations are that the well is bleeding down very slowly indicating that some gas is stored in some poorly connected, or non- connected intervals. The purpose of this work/sundry is to convert SCU_344-33 to a producer to bleed down any trapped gas. Procedure: 1. RU hard line on surface and install SSV as shown in the Wellhead sketch. 2. MIRU SL and pressure test Lubricator to 1,000 psi. 3. RIH W/ Retrieving tool and pull Injection Valve from X-nipple @ 10,666’. 4. Flow Well to Tank Setting. Test SSV within 5 days (Notify AOGCC 24 hours in advance to give them the opportunity to witness). Attachments: 1. Actual Schematic 2. Wellhead and SSV Sketch The purpose of this work/sundry is to convert SCU_344-33 to a producer to bleed down any trapped gas. Updated by DMA 07-18-19 SCHEMATIC Swanson River Field Well: SCU 344-33 PTD: 218-054 API: 50-133-20293-01 TD = 11,381’ MD / 10,860’ TVD PBTD = 11,217’ MD / 10,699’ TVD Max Deviation = 27.8° @ 6,981’ GL: 125.5’ AMSL RKB –18’ AGL TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 4-1/2” Tubing 12.6 L-80 IBTM 3.958” Surf 10,677’ 7 6 5 2 H-6/H-7 CASING DETAIL Size Type Wt Grade Conn Top Btm 20” Conductor - - - Surf. 90’ 13-3/8” Surface 68 K-55 BTC Surf. 3,380’ 9-5/8” Surface 47 S-95 BTS Surf. 6,259’ 7” Production 29 P-110 DWC 6,000’ 11,350’ 20” 90’ 13-3/8” 3,380’ 7” 9-5/8” 6,259’ JEWELRY DETAIL NO. Depth ID OD Item 1 328’ 3.813” 4.5” X – Landing Nipple (injection valve) 2 6,000’ 7” Liner Top Packer 3 10,641’ 3.958” Anchor Latch Seal Assembly 4 10,651’ 5.0” 5.5” Seal Bore Receptacle 5 10,657’ 3.958” 7.0” Permanent Hydraulic 7” x 4-1/2” Packer 6 10,666’ 3.813” 4.5” X – Landing Nipple 7 10,677’ 3.958” 4.5” WL Entry Guide X PERFORATIONS New Name Old Name Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Notes H-4 H-1 10,830’ 10,842’ 10,321’ 10,333’ 12/17/18 Open H-6/H-7 H-5 10,944’ 10,959’ 10,432’ 10,447’ 11/27/18 Open H-7 H-5 10,978’ 10,993’ 10,459’ 10,474’ 10/16/18 Open H-7 H-5 10,993’ 11,008’ 10,474’ 10,495’ 10/31/18 Open 1 X 3 4 H-7 Window cut at 6,259’ H-4 ** pull MCX valve to produce well. GATE 11/19/2019 Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician II 333 W 7th Ave Suite 100 Anchorage, AK 99501 CD: ®A SCU 344-33 PERF 12SEP18 SCU_344-33_PERF_12S€P1B_C onelation SCU_344-33_PERF _12SEP18_img SCU 341-33_PERF_12S€P78_Shooting 21 8054 31459 RECEIVED NOV 19 2019 AGGCC 11/14/20189:51AM PDFDocument 11/14/2016 4:51 AM LAS File 11/14/ 2018 9:51 AM TIFF File 11/14/20189:51 AM LAS File Please include current contact information if different from above. 873 KB 70 KB 1,164 KB 60 KB Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, SCU 344-33 Permit to Drill Number: 218-054 Sundry Number: 319-342 Dear Mr. York: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 w .aogcc.aloska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Z164eool Daniel T. Seamount, Jr. Commissioner DATED this /5day of August, 2019. RSDMS-""AUG 19 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION JUL 19 2019 APPLICATION FOR SUNDRY APPROVALS �+ g 20 AAC 25.280 A� 1QQQ 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑r • Other Stimulate ❑ Pull Tubing 21 Change Approved Program ❑ Plug for Reddll ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Convert to Producer ❑� 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development ❑ Strati ra hic ❑ g p ❑ Service � • 218-054 3. Address: 3800 Centerpoinl Drive, Suite 1400 6. API Number: Anchorage Alaska 99503 50-133-20293-01-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 1238 Will planned perforations require a spacing exception? Yes ❑ No Q Soldoma Creek Unit (SCU) 344-33, 9. Property Designation (Lease Number): 10. Field/Pool(s): FEDA0289907, FEDA028997 Swanson River/ Hemlock Oil it. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 11,381' 10,856' 11,350' 10,830' -1,770 psi ✓ N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 90' 20" 90' 90' Surface 3,380' 13-3/8" 3,380' 3,380' 3,450psi 1,950psi Surface 6,259' 9-5/8" 6,259' 6,258' 8,150psi 7,100psi Production 5,350' 7" 11,350' 10,830' 11,220psi 8,530psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (fl): See Attached Schematic See Attached Schematic 4-1/2" 12.6 # / L-80 10,677' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Liner Top Pkr, Perm Hydr Pur; N/A 6,000' MD/5,999'TVD; 10,657'MD/10,152TVD; N/A 12. Attachments: Proposal Summary Wellbore schematic 141 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch Exploratory ❑ Straligraphic ❑ Development ❑� • Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: August 1, 2019 • OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Bo York 777-8345 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramer hilcor .Com ' / �� Contact Phone: 777-8420 J Authorized Signatur . Date: �-( ( ov COMMISSION USE ONLY , t ^ Conditions of approval: Notify Commission so that a representative may witness�,/ Sundry Number: n I 0(I`,1 /✓^ 5 `sL` Plug Integrity BOP Test p� Mechanical Integrity Test L✓� Location Clearance ❑ /❑ Other: /CS'T�D %O 3 �Si' JJnh✓al2r �'o xSD�,�Si' (/ RBDMS-XAU6191019 Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No Subsequent Form Required:/6 _ Ye y AHE OVED BY MMISS C%// l Approved by: COMMISSIONER THE COMMISSION Date:?// ,./bin Form and Form 10-4 Revised 4/2 7 Approved appli i I 1 the ov data of appral. �/� �f' Attachmentss in Duplicate U Hil.,m Alaska. Lr: Well Prognosis Well: SCU 344-33 Date:07/18/2019 Well Name: SCU-344-33 API Number: 50-133-20293-01 Current Status: Gas Injector Leg: N/A Estimated Start Date: 08/1/19 Rig: Rig 401 - Reg. Approval Req'd? 10-403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 218-054 First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (C) Second Call Engineer: Taylor Nasse (907)777-8354(0) (907)903-0341(C) AFE Number: Maximum Expected BHP: 2,800 psi @ 10,300' TVD (Based on offset SBHP log) Max. Potential Surface Pressure: 1,770 psi (0.1psi/ft gradient to 10,300ft TVD) Max. Possible Surface Pressure (MPSP) 1,770 psi (0.1psi/ft gradient to 10,300ftTVD) Brief Well Summary SCU 344-33 is currently a gas injection well injecting into the H4, H6, and H7 sands within the Hemlock reservoir. Incremental production and injection volumes are directly supporting t� offset producers in the same sands. Ov The purpose of this work/sundry is to convert SCU_344-33 to a producer. We will pull the current 4.5in injection string, perforate the Hl -H3 and H9 Hemlock sands and run back in hole with a 3.5in gas lift 7 1Z �q completion string. Workover Rig Procedure: 1. Blow -down any pressure on the well and shoot fluid level (echometer) on casing. 2. MIRU Rig #401. 3. Pump casing volume of produced water down annulus and bleed pressure. 4. Set BPV. NDTree. 5. Notify AOGCC 24hrs in advance to conduct Rig Inspection. 6. NU BOPE. 7. Test BOPE to 250psi low/ 3,500psi High, annular to 250psi low/ 2,500psi High (hold each ram/valve and test for 10 -min). Record accumulator pre -charge pressures and chart tests. a. Perform Test. b. Notify AOGCC 24hrs in advance of BOP test. c. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 8. L/D BOP test equipment. 9. Pump PW down tubing and casing to ensure well is dead. 10. Pull tubing hanger. 11. Un latch and Pull out of hole with 4.5in tubing (12.6# L-80 IBT), anchor latch, and seal assembly. Number and label each joint. 12. Pick up and run in hole with seal assembly, anchor latch, 4.5in X 3.5in XO, X nipple, 3.5in production string, and GLM's to +/- 10,650ft md. 13. Land and set tubing hanger. Well Prognosis Well: SCU 344-33 lliknru Alaska, LL- �'�Date: 07/18/2019 14. Test casing to 3,OOOpsig for 30min on chart. 15. Set TWC, ND BOPE, NU Tree and test to 3,OOOpsig, and pull TWC. 16. RU e -line. a. PT lubricator to 200psig low, 3,500psig high. b. Perforate the below listed intervals: Sand Top MID (ft) Btm VID (ft) Top TVD (ft) Btm TVD (ft) 1-11-3 +/-10,780 +/-10,818 +/-10,272 +/-10,309 H9 +/-11,080 +/-11,115 +/-10,566 +/-10,600 17. Turn well over to production. Attachments: 1. Actual Schematic 2. Proposed Schematic 3. Bop Schematic 4. Wellhead drawing 5. RWO Change form L-� S 5V 2 20 90 13 - 3,3 Win( cut 6,2! GL: 12S.S' AMSL RKB -18' AGL TO =11,381' MD / 10,860' TVD PBTD =11,217' MD / 10,699' TVD Max Deviation = 27.8° @ 6,981' SCHEMATIC CASING DETAII Swanson River Field Well: SCU 344-33 PTD: 218-054 API: 50-133-20293-01 Size Type Wt Grade Conn Top Btm 20" Conductor - - L-80 Surf. 90' 13-3/8" Surface 68 K-55 BTC Surf. 3,380' 9-5/8" Surface 47 S-95 BTS Surf. 6,259' 7" Production 29 P-110 DWC 6,000' 11,350' TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 4-1/2" Tubing 12.6 L-80 IBTM 3.958" Surf 1 10,677' JEWELRY DETAIL NO. Depth ID OD Item 1 328' 3.813" 4.5" X- Landing Nipple (injection valve) 2 6,000' 10,321' 10,333' 7" Liner Top Packer 3 10,641' 3.958" 10,944' Anchor Latch Seal Assembly 4 10,651' 5.0" 5.5" Seal Bore Receptacle 5 30,657 3.958" 7.0" Permanent Hydraulic 7" x 4-1/2" Packer 6 10,666' 3.813" 4.5" X - Landing Nipple 7 10,677' 3.958" 4.5" WL Entry Guide PERFORATIONS New Name Old Name Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Notes H4 H-1 10,830' 10,842' 10,321' 10,333' 12/17/18 Open 1-1-6/1-1-7 H-5 10,944' 10,959' 10,432' 10,447' 11/27/18 Open H-7 H-5 10,978' 10,993' 10,459' 10,474' 10/16/18 Open H-7 H-5 10,993' 11,008' 10,474' 10,495' 10/31/18 Open Updated by DMA 07-18-19 20 90 132 3,3 Win( cut 6,2! 9-! 6,: K F10ooru Alaeka, LLC GL: 125.5AMSL RKB-18' AGL TD =11,381' MD / 10,860' TVD PBTD =11,217' MD / 10,699' TVD Max Deviation = 27.8° @ 6,981' PROPOSED SCHEMATIC CASING DETAIL Swanson River Field Well: SCU 344-33 PTD: 218-054 API: 50-133-20293-01 Size Type Wt Grade Conn Top Btm 20" Conductor Tubing - ±2,350 Surf. 90' 13-3/8" Surface 68 K-55 BTC Surf. 3,380' 9-5/8" Surface 47 S-95 BTS Surf. 6,259' 7" Production 29 P-110 DWC 6,000' 11,350' TUBING DETAIL Size Type Wt Grade Conn 1 Top Btm 3-1/2" Tubing - ±2,350 - 10,333' Surf. ±10,650 JEWELRY DETAIL NO. Depth ID OD Item 1 328' 3.813" 4.5" X- Landing Nipple (injection valve) 2 ±2,350 10,321' 10,333' GLM IPOC-1 3 ±4,199 ±10,780' GLM IPOC-1 4 ±5,400 Proposed TBD GLM IPOC-1 5 6,000' 10,959' 10,432' 7" Liner Top Packer 6 ±6,301 H-7 H-5 GLM IPOC-1 7 ±6,910 10,474' 10/16/18 GLM IPOC-1 8 ±7,591 10,993' 11,008' GLM IPOC-1 9 ±8,387 Open H-9 GLM IPOC-1 SO ±9,147 ±10,566' ±10,600' GLM IPOC-1 11 ±9,890 GLM IPOC-1 12 ±10,604 GLM IPOC-1 13 10,641' 3.958" Anchor Latch Seal Assembly 14 10,651' 5.0" 5.5" Seal Bore Receptacle 15 10,657' 3.958" 7.0" Permanent Hydraulic 7" x 4-1/2" Packer 16 10,666' 3.813" 4.5" X - Landing Nipple 17 10,677' 3.958" 4.5" WL Entry Guide PERFORATIONS New Name Old Name Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Notes H-4 H-1 10,830' 10,842' 10,321' 10,333' 12/17/18 Open H -1/H-3 ±10,780' ±10,818' ±10,272' ±10,309' Proposed TBD 1-1-6/1-1-7 H-5 10,944' 10,959' 10,432' 10,447' 11/27/18 Open H-7 H-5 10,978' 10,993' 10,459' 10,474' 10/16/18 Open H-7 H-5 10,993' 11,008' 10,474' 10,495' 10/31/18 Open H-9 ±11,080' ±11,115' ±10,566' ±10,600' Proposed TBD Updated by DMA 07-19-19 HILCORP ALASKA 7-1/16" 5M BOPE 7-1/16" 5M HYDRIL GK ANNULAR 32" TALL, FLANGE TO FLANGE 7-1/16" 5M LWS DBL GATE BOP DRESSED W/VARIABLE RAMS IN TOP DRESSED W/BLIND RAMS IN BOTTOM 26-3/4" TALL, FLANGE TO FLANGE 7-1/16" 5M DRILLING SPOOL W/2-1/16" 5M OUTLETS 18" TALL, FLANGE TO FLANGE ^77" TOTAL STACK HEIGHT ANNULAR STYLE BOP SPECS: - 3.30 gallon open chamber volume - 3.86 gallon close chamber volume GATE STYLE BOP SPECS: - 1.45 gallons to close per gate -1.18 gallons to open per gate - 5.45:1 closing ratio - 1.93:1 opening ratio H Ifilnnp Al. -La. 1,61; Swanson River Field SCU 344-33 Swanson River Tubing hanger, CIW-DC& SCU 344-33 FBB, 11 x4 K EUE 8rd lift x 13 3/8 X 9 S/8 X 41/2 4 K IBT cusp, w/ 4" type H BPV profile, 2-'/. non continuous control line, alloy material, 7" extended neck Tree cap, Bowen, 4 1/16 5M FE X 7" stub acme Bowen Quick Union O h ea Valve, Swab, CIW-FLS, 3jS4'XN 3�0 era" 41/16 SM FE, HWO, EE trim J�\$h Ja4 ' do kr4 3 `t' Valve, Upper Master, CIW-FLS, 41/16 SM FE, HWO, EE trim Valve, Master, CIW-FLS, 4 1/16 SM FE, HWO, DD trim Casing head, Cameron WF, 'u' ' "-+' - valve, CIW-F, 21/165M FF, 135/8 SM X133/850 W, HWO, AA trim W/ 2- 2 1/16 SM EFO Adapter, CIW-EN-2CL, 115M stdd X 11 SM stdd, w/ j 7" slick neck pocket and K npt chemical injection ports �' Tubing head, Cameron DCB -S, 13 5/8 5M K 115M, w/ 2- 21/16 SSO Valve, WKM-M, 2 1/16 SM FE, HWO, AA trim QTY 2 Casing head, Cameron WF, 'u' ' "-+' - valve, CIW-F, 21/165M FF, 135/8 SM X133/850 W, HWO, AA trim W/ 2- 2 1/16 SM EFO HHilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for Well SCU 344-33 (PTD 218-054) Sundry #: XXX -XXX Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) "first call' engineer. AOGCC written approval of the change is required before implementing the change. Sec Page Date Procedure Change New 403 Required? YIN HAK Prepared By Initials HAK Approved By Initials AOGCC Written Approval Received (Person and Date) Approval: Prepared: Asset Team Operations Manager Date First Call Operations Engineer Date Roby, David 5 (CED) From: Ted Kramer <tkramer@hilcorp.com> Sent: Wednesday, August 14, 2019 3:52 PM To: Roby, David S (CED) Subject: Sundry application for SCU 344-33 (PTD 218-054) Dave how could you (mess up my e-mail) In answer to your question, Hilcorp (Reservoir Engineer— Dan Taylor) has closely monitored the gas injection vs. oil production in this entire pattern since the start of gas injection in SCU 344-33. The simple truth is that the economic limit for injecting gas into SCU 344-33 to support the offset wells has been reached. That is not to say that these wells will not continue to produce albeit at a slightly lower rate. The incremental yield from gas flood does not provide enough uplift to overcome the value of lost sales gas (temporarily stranded within the Hemlock) and the cost of incremental compression. I hope this answers your question. If not please call me and we will get Dan on a conference call. Sincerely, Ted Kramer Sr. Operations Engineer Hilcorp-Alaska LLC Office — 907-777-8420 Cell — 985-867-0665 From: Roby, David S (CED) [mailto:dave.robv@alaska.eov] Sent: Tuesday, August 13, 2019 2:58 PM To: Ted Kramer <tkramer@hilcorp.com> Subject: [EXTERNAL] FW: Sundry application for SCU 344-33 (PTD 218-054) Oops, just notice I screwed up your email address on this. Dave Roby 907-793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOG CC), State of Alaska and is forth e 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 Dave Roby at 907- 793-1232 or dave.robv@alaska.eov. From: Roby, David S (CED) Sent: Monday, July 29, 2019 4:36 PM To: tkraner@hilcorp.com Cc: Schwartz, Guy L (CED) <Ruy.schwartz(c@alaska.gov>; Stephen F Davies <steve.davies@alaska.t;ov>; Wallace, Chris D (CED) <chris.wallace@alaska.eov> Subject: Sundry application for SCU 344-33 (PTD 218-054) Hi Ted, How's it going? In the referenced sundry application it says that as an injector the well currently supports two offset producers in the H4, H6, and H7 sands. The proposed work to convert the well to a producer from the 1-11-3 and H9 sands will remove this source of EOR support for the two producers. As part of the review process we review potential impacts to ultimate recovery from proposed work, as such can you provide more information on why Hilcorp wants to convert this will to a producer and what impacts that would have on recovery from the two producers being supported by this well? Thanks in advance, David Roby Senior Reservoir Engineer Alaska Oil and Gas Conservation Commission 907-793-1232 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 Dave Roby at 907- 793-1232 or dave.robyPalaska.gov. The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. 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DATA SUBMITTAL COMPLIANCE REPORT 4/17/2019 Permit to Drill 2180540 Well Name/No. SOLDOTNA CK UNIT 34433 MD 11381 TVD 10860 REQUIRED INFORMATION Completion Date 10/31/2018 Mud Log No Operator HILCORP ALASKA LLC Completion Status 1GINJ Current Status 1GINJ Samples No DATA INFORMATION ` List of Logs Obtained: ROP DGR ADR CTN ALD MD, DGR ADR CTN ALD TVD, CBL, CCL, Mudlogs Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Interval OHI Type Med/Frmt Number Name Scale Media No Start Stop CH ED C 29745 Digital Data 6235 11381 ED C 29745 Digital Data ED C 29745 Digital Data ED C 29745 Digital Data ED C 29745 Digital Data ED C 29745 Digital Data ED C 29745 Digital Data ED C 29745 Digital Data ED C 29745 Digital Data ED C 29745 Digital Data ED C 29745 Digital Data ED C 29745 Digital Data Log C 29745 Log Header Scans 0 0 Log C 29746 Log Header Scans 0 0 ED C 29746 Digital Data 6000 11490 ED C 29746 Digital Data ED C 29746 Digital Data AOGCC Page 1 of 10 API No. 50-133-20293-01-00 UIC Yes Directional Survey Yes Z (from Master Well Data/Logs) Received Comments 10/4/2018 Electronic Data Set, Filename: SCU 34433 Wednesday, April 17, 2019 DGR—ADR—ALD—CTN Final.las 10/4/2018 Electronic File: SCU 344-33 LWD Final MD.cgm 10/4/2018 Electronic File: SCU 344-33 LWD Final TVD.cgm 10/4/2018 Electronic File: SCU 344-33 - Definitive Survey Report.pdf 10/4/2018 Electronic File: SCU 34433 - Definitive Survey.txt 10/4/2018 Electronic File: SCU 34433 LWD Final MD.emf 10/4/2018 Electronic File: SCU 344-33 LWD Final TVD.emf 10/4/2018 Electronic File: SCU 344-33 LWD Final MD.pdf 10/4/2018 Electronic File: SCU 344-33 LWD Final TVD.pdf 10/4/2018 Electronic File: SCU 344-33 LWD Final MD.tif 10/4/2018 Electronic File: SCU 344-33 LWD Final TVD.tif 10/4/2018 Electronic File: Readme.txt 2180540 SOLDOTNA CK UNIT 34433 LOG HEADERS 2180540 SOLDOTNA CK UNIT 344-33 LOG HEADERS 10/4/2018 Electronic Data Set, Filename: SCU_344-33.1as 10/4/2018 Electronic File: SCU 344-33 Nabors AM Report 7- 20-2018.pdf 10/4/2018 Electronic File: SCU 34433 Nabors AM Report 7- 21-201 S.pdf Wednesday, April 17, 2019 DATA SUBMITTAL COMPLIANCE REPORT 4/17/2019 Permit to Drill 2180540 Well Name/No. SOLDOTNA CK UNIT 344-33 Operator HILCORP ALASKA LLC API No. 50-133.20293-01-00 MD 11381 TVD 10860 Completion Date 10/31/2018 Completion Status 1GINJ Current Status 1GINJ UIC Yes ED C 29746 Digital Data 10/4/2018 Electronic File: SCU 344-33 Nabors AM Report 7- 22-2018.pdf ED C 29746 Digital Data 10/4/2018 Electronic File: SCU 344-33 Nabors AM Report 7- 23-2018.pdf ED C 29746 Digital Data 10/4/2018 Electronic File: SCU 344-33 Nabors AM Report 7- 24-2018.pdf ED C 29746 Digital Data 10/4/2018 Electronic File: SCU 344-33 Nabors AM Report 7- 25-2018.pdf ED C 29746 Digital Data 10/4/2018 Electronic File: SCU 344-33 Nabors AM Report 7- 26-2018.pdf ED C 29746 Digital Data 10/4/2018 Electronic File: SCU 344-33 Nabors AM Report 7- 27-2018.pdf ED C 29746 Digital Data 10/4/2018 Electronic File: SCU 344-33 Nabors AM Report 7- 28-2018.pdf ED C 29746 Digital Data 10/4/2018 Electronic File: SCU 344-33 Nabors AM Report 7- 29-2018.pdf ED C 29746 Digital Data 10/4/2018 Electronic File: SCU 344-33 Nabors AM Report 7- 30-2018.pdf ED C 29746 Digital Data 10/4/2018 Electronic File: SCU 344-33 Nabors AM Report 7- 31-2018.pdf ED C 29746 Digital Data 10/4/2018 Electronic File: SCU 344-33 Nabors AM Report 8- 1-2018.pdf ED C 29746 Digital Data 10/4/2018 Electronic File: SCU 344-33 Nabors AM Report 8- 2-2018.pdf ED C 29746 Digital Data 10/4/2018 Electronic File: SCU 344-33 Nabors AM Report 8- 3-2018.pdf ED C 29746 Digital Data 10/4/2018 Electronic File: SCU 344-33 Nabors AM Report 8- 42018.pdf ED C 29746 Digital Data 10/4/2018 Electronic File: SCU 344-33 Nabors AM Report 8- 5-2018.pdf ED C 29746 Digital Data 10/4/2018 Electronic File: SCU 344-33 Nabors AM Report 8- 6-2018.pdf ED C 29746 Digital Data 10/4/2018 Electronic File: SCU 344-33 Nabors AM Report 8- 7-2018.pdf ED C 29746 Digital Data 10/4/2018 Electronic File: SCU 344-33 Nabors AM Report 8- 8-2018.pdf AOGCC Page 2 of 10 Wednesday, April 17, 2019 DATA SUBMITTAL COMPLIANCE REPORT 4/1712019 Permit to Drill 2180540 Well Name/No. SOLDOTNA CK UNIT 344-33 MD 11381 TVD 10860 EDC C 29746 Digital Data ED C 29746 Digital Data ED C 29746 Digital Data ED C 29746 Digital Data ED C 29746 Digital Data ED C 29746 Digital Data ED C 29746 Digital Data ED C 29746 Digital Data ED C 29746 Digital Data ED C 29746 Digital Data ED C 29746 Digital Data ED C 29746 Digital Data ED C 29746 Digital Data ED C 29746 Digital Data ED C 29746 Digital Data ED C 29746 Digital Data ED C 29746 Digital Data ED C 29746 Digital Data ED C 29746 Digital Data ED C 29746 Digital Data I ED C 29746 Digital Data ED C 29746 Digital Data Operator HILCORP ALASKA LLC API No. 50-133-20293-01-00 Completion Date 10/31/2018 Completion Status 1GINJ Current Status 1GINJ UIC Yes 10/4/2018 Electronic File: SCU 344-33 Nabors AM Report 8- 9-2018.pdf 10/4/2018 Electronic File: SCU344-33.dbf 10/4/2018 Electronic File: scu344-33.hdr 10/4/2018 Electronic File: SCU344-33.mdx 10/4/2018 Electronic File: scu344-33r.dbf 10/4/2018 Electronic File: scu344-33r.mdx 10/4/2018 Electronic File: SCU344-33 SCL.DBF 10/4/2018 Electronic File: SCU344-33 SCL.MDX 10/4/2018 Electronic File: SCU344-33_tvd.dbf 10/4/2018 Electronic File: SCU344-33 tvd.mdx 10/4/2018 Electronic File: SCU 344-33 Final Well Report.pdf 10/4/2018 Electronic File: SCU 344-33 - Sin Drilling Dynamics Log MD.pdf 10/4/2018 Electronic File: SCU 344-33 - Sin Drilling Dynamics Log TVD.pdf 10/4/2018 Electronic File: SCU-344-33 - 5in Formation Log MD.pdf 10/4/2018 Electronic File: SCU-344-33 - 5in Formation Log TVD.pdf 10/4/2018 Electronic File: SCU-344-33 - 5in Gas Ratio Log MD.pdf 10/4/2018 Electronic File: SCU-344-33 - 5in Gas Ratio Log TVD.pdf 10/4/2018 Electronic File: SCU-344-33 - 5m LW D Combo Log MD.pdf 10/4/2018 Electronic File: SCU-344-33 - 5in LWD Combo Log TVD.pdf 10/4/2018 Electronic File: SCU-344-33 - Drilling Dynamics Log MD.pdf 10/4/2018 Electronic File: SCU-344-33 - Drilling Dynamics Log TVD.pdf 10/4/2018 Electronic File: SCU-344-33 - Formation Log MD.pdf AOGCC Page 3 of 10 Wednesday, April 17, 2019 DATA SUBMITTAL COMPLIANCE REPORT 4/17/2019 Permit to Drill 2180540 Well Name/No. SOLDOTNA CK UNIT 344-33 Operator HILCORP ALASKA LLC API No. 50-133-20293-01-00 MD 11381 TVD 10860 Completion Date 10/31/2018 Completion Status 1GINJ Current Status 1GINJ UIC Yes ED C 29746 Digital Data 10/4/2018 Electronic File: SCU 344-33 - Formation Log TVD.pdf ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33 -Gas Ratio Log MD.pdf ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33 - Gas Ratio Log TVD.pdf ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33 - LWD Combo Log MD.pdf ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33 - LWD Combo Log TVD.pdf ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33 - 5in Drilling Dynamics Log MD.tiff.tif ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33 - Sin Drilling Dynamics Log TVD.tiff.tif ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33 - Sin Formation Log MD.tif ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33 - 5in Formation Log TVD.tif ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33 - 5in Gas Ratio Log MD.tiff.tif ED C 29746 Digital Data 10/4/2018 Electronic File: SOU -344-33 - 5in Gas Ratio Log TVD.tiff.tif ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33 - Sin LWD Combo Log MD.tiff.tif ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33 - Sin LWD Combo Log TVD.tiff.tif ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33 - Drilling Dynamics Log MD.tiff.tif ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33 - Drilling Dynamics Log TVD.tiff.tif ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33 - Formation Log MD.tiff.tif ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33 - Formation Log TVD.tiff.tif ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33 - Gas Ratio Log MD.tiff.tif AOGCC Page 4 of 10 Wednesday, April 17, 2019 DATA SUBMITTAL COMPLIANCE REPORT 4/17/2019 Permit to Drill 2180540 Well Name/No. SOLDOTNACK UNIT 344-33 Operator HILCORP ALASKA LLC API No. 50-133-20293-01-00 MD 11381 TVD 10860 Completion Date 10/31/2018 Completion Status 1GINJ Current Status 1GINJ UIC Yes ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33 - Gas Ratio Log TVD.tiff.tif ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33 - LWD Combo Log MD.tiff.tif ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33 - LWD Combo Log TVD.tiff.tif ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_09380'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_09410'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_09440'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_09470'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_09500'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_09515'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_09530'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_09560'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_09590'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_09620'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_09650'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_09680'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_09710'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_09740'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_09770'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_09800'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_09830'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_09860'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_09890'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_09920'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_09950'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_09980'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_10010'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_10640'.jpg AOGCC Page 5 of 10 Wednesday, April 17, 2019 DATA SUBMITTAL COMPLIANCE REPORT 4/17/2019 Permit to Drill 2180540 Well Name/No. SOLDOTNA CK UNIT 344-33 Operator HILCORP ALASKA LLC API No. 50-133-20293-01-00 MD 11381 TVD 10860 Completion Date 10/31/2018 Completion Status 1GINJ Current Status 1GINJ UIC Yes ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_10670'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_10700'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_10710'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_10730'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_10760'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_10776'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_10784'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_10795'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_10800'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_10820'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344.33_10850'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_10870'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_10880'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_10910'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_10920'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_10940'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_10970'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_10987'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_11000'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_11030'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_11060'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_11090'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_11120'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_11150'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_11165'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_11180'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_11195'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_11210'.jpg ED C 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_11225'.jpg AOGCC Page 6 of 10 Wednesday, April 17, 2019 DATA SUBMITTAL COMPLIANCE REPORT 4/17/2019 Permit to Drill 2180540 Well Name/No. SOLDOTNA CK UNIT 344-33 MD ED ED ED ED ED ED ED ED ED ED ED ED ED ED ED ED 11381 TVD 10860 Completion Date 10/31/2018 C C C C C C C C C C C C C C C C ED C ED C ED C ED C ED C ED C ED C AOGCC Operator HILCORP ALASKA LLC Completion Status iGINJ Current Status 1GINJ API No. 50-133-20293-01-00 UIC Yes 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_11235'.jpg 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_11255'.jpg 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_11271'.jpg 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_11275'.jpg 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_11283'.jpg 29746 Digital Data 10/4/2018 Electronic File: SCU _344-33_11300'.jpg 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_11304'.jpg 29746 Digital Data 10/4/2018 Electronic File: SCU _344-33_11310'.jpg 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_11320'.jpg 29746 Digital Data 10/4/2018 Electronic File: SCU _344-33_11330'.jpg 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_11340'.jpg 29746 Digital Data 10/4/2018 Electronic File: SCU _344-33_11350'.jpg 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_11360'.jpg 29746 Digital Data 10/4/2018 Electronic File: SCU _344-33_11370'.jpg 29746 Digital Data 10/4/2018 Electronic File: SCU_344-33_11381'.jpg 29746 Digital Data 10/4/2018 Electronic File: SCU 344-33 Show Report #1 7680-7721.pdf 29746 Digital Data 10/4/2018 Electronic File: SCU 344-33 Show Report #2 7870-7895.pdf 29746 Digital Data 10/4/2018 Electronic File: SCU 344-33 Show Report #3 10623-10670.pdf 29746 Digital Data 10/4/2018 Electronic File: SCU 344-33 Show Report #4 10671-10777.pdf 29746 Digital Data 10/4/2018 Electronic File: SCU 344-33 Show Report #5 10778-10880.pdf 29746 Digital Data 10/4/2018 Electronic File: SCU 344-33 Show Report #6 10881-10942.pdf 29746 Digital Data 10/4/2018 Electronic File: SCU 344-33 Show Report #7 10943-11078.pdf 29746 Digital Data 10/4/2018 Electronic File: SCU 344-33 Show Report #8 11079-11170.pdf Page 7 of 10 Wednesday, April 17, 2019 DATA SUBMITTAL COMPLIANCE REPORT 4/17/2019 Permit to Drill 2180540 Well Name/No. SOLDOTNA CK UNIT 344.33 Operator HILCORP ALASKA LLC MD 11381 ED C ED C ED C Log C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C TVD 10860 Completion Date 10/31/2018 Completion Status 1GINJ 29746 Digital Data 29981 Digital Data 29981 Digital Data 29981 Log Header Scans 30093 Digital Data 30093 Digital Data 30093 Digital Data 30093 Digital Data 30093 Digital Data 30093 Digital Data 30093 Digital Data 30093 Digital Data 30093 Digital Data 30093 Digital Data 30093 Digital Data 30093 Digital Data 30093 Digital Data 30093 Digital Data 5866 11232 0 0 -11 797 11 11 -35 10664 14 14 14 14 -27 911 916 714 858 -25 API No. 50-133-20293-01-00 Current Status 1GINJ UIC Yes 10/4/2018 Electronic File: SCU 344-33 Show Report #9 11171-11381.pdf 11/9/2018 Electronic Data Set, Filename: SCU 344-33 CBL 8-12-18.1as 11/9/2018 Electronic File: SCU 344-33 CBL 8-12-18.pdf 2180540 SOLDOTNA CK UNIT 344-33 LOG HEADERS 12/11/2018 Electronic Data Set, Filename: SCU 344- 33_ACX_12SEP 18_ProcessedLog.las 12/11/2018 Electronic Data Set, Filename: SCU_344- 33_ACX_12SEP18_Stop-797.Ias 12/11/2018 Electronic Data Set, Filename: SCU _344- 33_ACX_30AU G 18_ProcessedLog.las 12/11/2018 Electronic Data Set, Filename: SCU 344- 33_ACX _30AUG 18_ stop10650ft.las 12/11/2018 Electronic Data Set, Filename: SCU _344- 33_ACX_30AUG 18_ stopl0663ft.las 12/11/2018 44- Electronic Data Set, Filename: SCU _344- 33—PLUG-1 1SEP18—Correlation-dn.las 33PLUG_11SEP18_Correlation-dn.las 12/11/2018 Electronic Data Set, Filename: SCU 344- 33_PLUG_11 SE P18_Correlation-up.Ias 12/11/2018 Electronic Data Set, Filename: SCU _344- 33_PLUG_11 SEP18_Setting.las 12/11/2018 Electronic File: SCU 344- 33_ACX _12SEP 18_ Processedi-og.dlis 12/11/2018 Electronic File: SCU 344- 33_ACX _12SEP 18_ 5rocessedl-og.pdf 12/11/2018 Electronic File: SCU 344- 33_ACX _12S E P 18_Processedlog. of 12/11/2018 Electronic File: SCU _344- 33_ACX_12SEP18_Report _RevA.pdf 12/11/2018 Electronic File: SCU _344- 33_ACX _12S EP18_Stop-797.dlis 12/11/2018 Electronic File: SCU _344- 33_ACX_30AUG 18_ Processedl-og.dlis AOGCC Page 8 of 10 Wednesday, April 17, 2019 DATA SUBMITTAL COMPLIANCE REPORT 4/17/2019 Permit to Drill 2180540 Well Name/No. SOLDOTNA CK UNIT 344-33 MD 11381 TVD 10860 ED C 30093 Digital Data ED C 30093 Digital Data ED C 30093 Digital Data ED C 30093 Digital Data ED C 30093 Digital Data ED C 30093 Digital Data ED C 30093 Digital Data Completion Date 10/31/2018 Log C 30093 Log Header Scans Well Cores/Samptes Information: Name Cuttings INFORMATION RECEIVED Completion ReportYY Production Test Information Y NA Geologic MarkersJTops O COMPLIANCE HISTORY Completion Date: 10/31/2018 Release Date: 5/21/2018 Description Interval Start Stop 6259 11381 Operator HILCORP ALASKA LLC API No. 50-133-20293-01-00 Completion Status 1GINJ Current Status 1GINJ UIC Yes 12/11/2018 Electronic File: SCU_344 33_ACX _30AUG 18_ProcessedLog. pdf 12/11/2018 Electronic File: SCU 344 33_ACX _30AUG 18_ProcessedLog_img.tiff 12/11/2018 Electronic File: SCU_344- 33_ACX _30AUG18_Report _RevA.pdf; 12/11/2018 Electronic File: SCU_344 33_ACX _30AUG 18_stop 10650ft.dlis 12/11/2018 Electronic File: SCU 344- 33_ACX _30AUG 18_stop 10663ft.dlis 12/11/2018 Electronic File: SCU_344- 33_PLUG_11SEP18.pdf 12/11/2018 Electronic File: SCU_344- 33_PLUG_11 SEP18_img.tiff 0 0 2180540 SOLDOTNA CK UNIT 344-33 LOG HEADERS Sample Set Sent Received Number Comments 10/31/2018 1677 Directional / Inclination Data O Mud Logs, Image Files, Digital Dat e% NA Core Chips Y i�DIA) Mechanical Integrity Test Information Y / NA Composite Logs, Image, Data Files Y Core Photographs Y / Daily Operations Summary) Cuttings Samples oY / NA Laboratory Analyses Y / A Date Comments AOGCC Page 9 of 10 Wednesday, April 17, 2019 DATA SUBMITTAL COMPLIANCE REPORT 4/17/2019 Permit to Drill 2150540 Well Name/No. SOLDOTNA CK UNIT 344-33 Operator HILCORP ALASKA LLC MD 11381 TVD 10860 Completion Date 10/31/2018 Completion Status 1GINJ Current Status 1GINJ Comments: Compliance Reviewed By: _ f Date: API No. 50.133.20293-01-00 UIC Yes AOGCC Page 10 of 10 Wednesday. April 17, 2019 FOLD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION IAN 3 WELL COMPLETION OR RECOMPLETION REPORT AND LOG TRUE Oil ❑ Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ 20a 025.105 20AAC 25.110 GINJ ❑v - WINJ ❑ WAGE] WDSPL ❑ No. of Completions: 1 lb. Well Class: Development ❑ Exploratory ❑ Service ❑✓ Stratigraphic Test ❑ 2. Operator Name: Hilcorp Alaska, LLC 6. Date Comp., So s .I or Abend.: '�/�018 14. Permit to Drill Number/ Sundry: ' 218-054 / 318-326 - 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded July 1z 2018 15. 15. API Number: 50-133-20293-01-00 ' 4a. Location of Well (Governmental Section): Surface: 1465' FSL, 1657' FEL, Sec 33, T8N, R9W, SM, AK Top of Productive Interval: (Top injection pert) 151' FNL, 596' FEL, Sec 4, T7N, R9W, SM, AK Total Depth: 227' FNL, 550' FEL, Sec 4, T7N, R9W, SM, AK 8. Date TD Reached: August 6, 2018 16. Well Name and Number: SCU 344-33 9. Ref Elevations: KB: 143.5' GL:125.5' BF:125.5' 17. Field / Pool(s): Swanson River Field Hemlock Oil Pool 10. Plug Back Depth MD/TVD: • 11,217' MD / 10,699' TVD 18. Property Designation: FEDA028990 / FEDA028997 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 345991 y- 2462644 Zone- 4 TPI: x- 347032 y- 2461019 Zone- 4 Total Depth: x- 347076 y- 2460942 Zone- 4 11. Total Depth MDfTVD: • 11,381' MD / 10,860' TVD 19. DNR Approval Number: N/A 12. SSSV Depth MD/TVD: N/A 20. Thickness of Permafrost MD/TVD: N/A 5. Directional or Inclination Survey: Yes LJ (attached) No Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: N/A (ft MSL) 1 21. Re-drill/Lateral Top Window MD/TVD: 6,259' MD 16,258' TVD 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary N/A 23. CASING, LINER AND CEMENTING RECORD WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING FT TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 7" 32# L-80 6,000' 11,350' 5,999' 10,830 8-1/2" 700 sx 24. Open to production or injection? Yes F-41 No ❑ If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Pend): See attached schematic COMPLETION DATE o/ 9 1116 ((17: 1t5 el VERIFIED ( AAZ-T 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 4-1/2" 10,677' 10,657' MD / 10,152' TVD 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes No Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: NIA Method of Operation (Flowing, gas lift, etc.): NIA Date of Test: Hours Tested: Production for Test Period Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: Flow Tubing Press. Casinq Press: Calculated 124-HoOr Rate Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): Form 10-407 Revised 5/2017Do/1/11 ,� � 3.1�- (? CONTINUEPAGE RBDMS ^ I, �, J y''v 3 y 261 S 76 (IAL nJ'j 28. CORE DATA Conventional Core(s): Yes ❑ No ❑� Sidewall Cores: Yes ❑ No Q If Yes, list formations and intervals cored (MDTTVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑� If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base N/A N/A Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval H-7 10,978' 10,459' information, including reports, per 20 AAC 25.071. G1 10,646' 10,142' G2 10,670' 10,165- H1 10,774' 10,267- H2 10,791' 10,283- H3 10,818' 10,309- H4 10,842' 10,333' H5 10,860' 10,350- H6 10,937' 10,426- H7 10,970' 10,458- H8 11,059' 10,545' H9 11,082' 10,568' H10 11,193' 10,676' H11 11,269' 10,751' Formation at total depth: Hemlock 31. List of Attachments: Operations Summary, Schematic Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Bo York Contact Name: Taylor Nasse Authorized Title: Operations Manager Contact Email: tnasse@hilcorp.com Authorized Contact Phone: 907-777-8354 Signature: Date: 3 S 6.- -w % INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item 1 a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item tb: Well Class - Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 19: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY -123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Form 10-407 Revised 5/2017 Submit ORIGINAL Only Hilcorp Alaska, LLC Well Operations Summary Well Name Rig AN Number Well Permit Number Start Date End Date SCU 344-33 50-133-20293-01-00 1 218-054 11/26/18 1 1/17/19 Daily Operations: 11/26/2018 - Monday ARRIVE AT OFFICE JSA, PERMIT, TALK OVER JOB W/ BILLY & PRODUCTION. START EQUIPMENT, RIG UP .125 S/L. PRESSURE TEST TO 3500PSI, ORING LEAK, DRAIN LUB, C/O ORING RETEST 3500PSI TEST GOOD. CALL PRODUCTION TO SHUT OFF INJECTION ON WELL, 310OPSI INJECTION PRESSURE,RIH W/ 3.83" GRING TO 126'KB HIT DOWN SEVERAL TIMES POOH - METAL MARK. RIH W/ 3.80" GRING TO 328'KB POOH. OPEN LUB 2000PSI ON WELL CALL PRODUCTION TO PRESSURE UP WELL TO 2700PSI, SHUT OFF INJECTION, WELL BLEEDS DOWN TO 2300PSi. RIH W/ 4" PR W/ EQUALIZING PRONG TO 328'KB HIT DOWN SEVERAL TIMES WELL BLEEDS DOWN TO 2550PSI SPANG UP COMES FREE - OOH W/ INJECTION VALVE. RIH W/ 6' x 3" DD BAILER TO 11170'KB and Tag. POOH. Rig down and move to SCU 24313-04. 11/27/2018-Tuesday Sign in. Mobe to location. PTW and JSA. Spot and rig up lubricator. Pressure test to 250 psi low and 4000 psi high. Shut well in. RIH w/2-7/8x15' Connex, 6 spf, 60 deg phase and tie into log sent from town. Run correlation log and send to town. Was told to shift 0.5' up and perforate from 10,944' to 10,959'. Shifted log and perforated with 2143 psi on tubing. Tubing pressure fluctuated from 2143 to 2146' for 2 min and then settled at 2142 psi. After 5 min - 2140 psi, 10 min - 2138 psi and 15 min - 2138 psi. POOH. All guns fired. Rig down and turn well over to field. 12/11/2018-Tuesday Check on seeing about flow lines on SRU 14-15 and SCU 2438-04 for up coming perfjobs and wait on Pollard Slickline to set injection valve. Arrive SR, meet with Billy. JSA Permit, TGSM. Start, warm equipment. Drive to location. Rig up SL PT LUB 4,000psi - Good. RIH w/ 3.62" G-ring. 11,172' KB tag. POOH. RIH w/ 4-1/2" X-line running tool w/ HLB. Injection valve to 334' KB w/ tool, would not shear. POOH w/ valve, redress & re-pin. IH w/ same to same w/ tool, set valve, shear off. POOH. Valve set. RIH w/ 4-1/2", check set tool to 332' KB w/ tool. POOH. Good. Wait on change out to test. Injected into well and then bled tubing down from 2,800 psi to 1,800 psi and valve held. Rig down lubricator and equipment. 12/16/2018-Sunday On location - TGSM - JSA - permit talk job over with Billy. Retrieve equipment from bull rail - mob to pad. Rig up w/I - PT LUB3500 psi - good TP — 3,200 psi. RIH w/ 4-1/2 GS w/ 22" prong to 337'KB wt - inj gas - latch - POOH - OOH w/o valve. RIH w/ same to 337'KB wt inj gas - latch - hand spang - POOH - OOH w/ valve. Rig down w/I turn well back to field. Note: Pollard will take injector valve to their shop and re-dress it. Well is ready to perforate tomorrow morning. 12/17/2018 - Monday Sign in. Mobe to location. PTW and JSA. Spot and rig up lubricator. Pressure test to 250 psi low and 4,000 psi high. Shut well in. RIH w/ 2-7/8" x 12' Razor, 6 spf, 60 deg phase and tie into log sent from town. Run correlation log and send to town. Was told log was good to perforate from 10,830' to 10,842'. Spotted and fired shot with 2,194 psi (Scada) at 1129 hrs. After 5 min TP - 2,192 psi, 10 min - 2,187 psi, 15 min - 2,187 psi (12 Noon - 2,125 psi). POOH and all shots fired. Rig down equipment and lubricator. Turn well back over to field. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date SCU 344-33 50-133-20293-01-00 1 218-054 11/26/18 1 1/17/19 Daily Operations: 12/18/2018 -Tuesday Arrive @ SR. JSA/TGSM. RU. PT 3,500 psi. RIH w/ 4-1/2" injection valve on 4-1/2" Mine to 331KB W/T set valve. POOH. RIH w/ 4-1/2" check set to 331KB W/T POOH. Pin shead set good. OOH. Test injection valve (good). Injection and negative test passed. Start 3,200 psi and bled to 1,250 psi. Rig down, head to SCU 34-04. 1/17/2019 Decision made to hold off on additional proposed perforations by Reservoir Engineer and Geologist after analyzing and trending well tests in offset producers. 20 90 ]3 - 3,3 Winc cut 6,2� 9-5 6,2 GL: 125.5' AMSL RKS -18' AGL TD =11,381' MD / 10,860' TVD PBTD =11,217' MD / 10,699' TVD Max Deviation = 27.8° @ 6,981' SCHEMATIC r9r-CiI1rcII1AEli II Swanson River Field Well: SCU 344-33 PTD: 218-054 API: 50-133-20293-01 Size Type Wt Grade Conn Top Btm 20" Conductor - - - Surf. 90' 13-3/8" Surface 68 K-55 BTC Surf. 3,380' 9-5/8" Surface 47 S-95 BTS Surf. 6,259' 7" Production 29 P-110 DWC 6,000' 11,350' TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 4-1/2" Tubing 12.6 L-80 IBTM 3.958" Surf 10,677' JEWELRY DETAIL NO. Depth ID OD Item 1 328' 3.813" 4.5" X -Landing Nipple (injection wive) 2 6,000' 10,321' 10,333' 7" Liner top packer 3 10,641' 3.958" 10,944' Anchor Latch Seal Assembly 4 10,651' 5.0" 5.5" Seal Bore Receptacle 5 10,657' 3.958" 7.0" 7" x 4-1/2" Packer 6 10,666' 3.813" 4.5" X - Landing Nipple 7 10,677' 3.958" 4.5" WL Entry Guide PERFORATIONS New Name Old Name Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Notes H-4 H-1 10,830' 10,842' 10,321' 10,333' 12/17/18 Open H -6/H-7 H-5 10,944' 10,959' 10,432' 10,447' 11/27/18 Open H-7 H-5 10,978' 10,993' 10,459' 10,474' 10/16/18 Open H-7 H-5 10,993' 11,008' 10,474' 10,495' 10/31/18 Open Updated by DMA 01-30-19 SC(t 344--33 PTts 'Z150540 Regg, James B (DOA) From: Brooks, Phoebe L (DOA) Sent: Monday, December 24, 2018 11:47 AM \`' 1 Z'Z4 I s To: Daniel Faulk Cc: Regg, James B (DOA) Subject: FW: [EXTERNAL] RE: MIT Test Report Attachments: MIT SCU 344-33 11-12-18 Revised.xlsx; MIT SCU 43A-33 11-12-18 Revised.xlsx Daniel, Attached are revised reports as follows: • MIT SCU 344-33 11-12-18 — Packer TVD was changed to 10152' and the interval was changed to "I" (initial) • MIT SCU 43A-33 11-12-18— Interval was changed to "I" The volumes pumped/returned were left blank on both reports; please advise. Thank you, Phoebe Phoebe Brooks Statistical Technician 11 Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 Fax: 907-276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1.242 or phoebe.brooksOO alaska.gov. From: Regg, James B (DOA) Sent: Monday, December 24, 2018 9:35 AM To: Brooks, Phoebe L (DOA) <phoebe.brooks@alaska.gov> Subject: FW: (EXTERNAL) RE: MIT Test Report I think they are showing the MD of the packer on the MIT form. Well schematic from Sundry 318-469 attached (sundry form incorrectly shows NA in packer block). I calculate the Packer TVD as 10152 ft. Jim Regg Supervisor, Inspections AOGCC 333 W.Th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 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 AGGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or im.regg@alaska.gov. From: Ted Kramer<tkramer@hilcorp.com> Sent: Monday, December 24, 2018 8:59 AM To: Regg, James B (DOA) <lim.regg@alaska.gov> Cc: Taylor Malone <tmalone@hilcorp.com> Subject: FW: [EXTERNAL] RE: MIT Test Report Jim, Attached please find the Deviation Survey for the SCU 344-33. Sincerely, Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. O 907-777-8420 C 985-867-0665 From: Taylor Malone Sent: Sunday, December 23, 2018 7:34 AM To: Ted Kramer <tkramer@hilcorp.com> Cc: Daniel Faulk <dpaulk hilcorp.com> Subject: FW: [EXTERNAL] RE: MIT Test Report Hello Ted, As discussed earlier on the phone please see email from Jim Regg below. I am assuming he is looking for the definitive survey report that was performed by Haliburton. If this is the case let me know and I can forward that to him. Thanks, Taylor Malone From: Regg, James B (DOA) [mailto:iim.regg@alaska.gov] Sent: Thursday, December 20, 2018 10:10 AM To: Daniel Paulk <dpaulk@hilcorp.com>; Taylor Malone <tmalone@hilcorp.com> Cc: Brooks, Phoebe L (DOA) <phoebe.brooks@alaska.gov> Subject: [EXTERNAL] RE: MIT Test Report Please provide the directional survey for SCU 344-33 (PTD 2180540) so we can verify the packer TVD from the reported measure depths on Hilcorp's well schematic. Jim Regg Supervisor, Inspections AOGCC 333 W.Ph Ave, Suite 100 Anchorage, AK 99501 907-793-1236 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 Jim Regg at 907- 793-1236 or iim.regg0Dalaska.gov. From: Regg, James B (DOA) Sent: Wednesday, December 5, 2018 12:02 PM To: 'Daniel Paulk' <dpaulk@hilcorp.com> Cc: Brooks, Phoebe L (DOA) <phoebe.brooks@alaska.Qov> Subject: RE: MIT Test Report Also need directional survey for well 344-33. Jim Regg Supervisor, Inspections AOGCC 333 W.7'h Ave, Suite 100 Anchorage, AK 99501 907-793-1236 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 Jim Regg at 907- 793-1236 or lim.reggPalaska.gov. From: Regg, James B (DOA) Sent: Wednesday, December 5, 2018 10:59 AM To:'Daniel Paulk' <dpaulk hilcorp.com> Cc: Brooks, Phoebe L (DOA) <phoebe.brooks@alaska.eov_> Subject: RE: MIT Test Report volumes pumped/returned for tests? Jim Regg Supervisor, Inspections AOGCC 333 W.7�h Ave, Suite 100 Anchorage, AK 99501 907-793-1236 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 Jim Regg at 907- 793-1236 or iim.re a alaska.gov. From: Daniel Faulk <dpaulk@hilcorp.com> Sent: Saturday, December 1, 2018 4:42 PM I To: Regg, James B (DOA) <iim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay<doa.aogcc.prudhoe. bay@alaska.gov>; Brooks, Phoebe L (DOA) <phoebe. brooks @alaska.gov>; Wallace, Chris D (DOA) <chris.wallace@alaska.gov> Cc: Taylor Malone <tmalone@hilcorp.com> Subject: MIT Test Report Please see attachment the Report from the post injection MIT on 43A-33 and 344-33. Submit to: an reef®alaska.Pov. OPERATOR; FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Phoebe.brooksdalaska.Gov Swanson River FieNlSGldotna Creek Unit/ 344-33 Pad Taylor Malone ends wallaceityalaska.00v iAzAk(0 Well SCU 344-33 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2180540 1 Typelnj G Tubing 3192 3192 3192 3192 31 3 Type Test P Packer TVD 10,152' BBL Pump IA 1361 2574 2574 2573 Interval I Test psi turn OA 22 22 22 - 22 Result P Notes: Post Injection MIT Completed as per Sundry p 318-326,318-409. MIT test witness was waived by Jim Regg Well Pressures: Pretest Initial 15 Min. 30 Min, 45 Min. 60 Min. PTD Type lnj Tubing Test Is Pacr TVD ke BBL Pump IA Interval Test psi BBL Return OA Result Notes: WellPressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTO Typelnj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BOL Return OA Result Nota.: Well Pressures: Pretest Initial 15 Min. 30 Min, 45 Min. 60 Min. PTO Type Inj TubingTypa Tasf Packer WD BBL Pump IA Interval Test psi BBL Return OA Result Notts: WellPressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Typa Test Packer WD BBL Pump IA Interval Test psi JBBIL Return I I OA I I I I I Result Notes: WellPressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type lnl Tubing Type Tast Packer WD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTO Typelnj Tubing I Type Test Packer WD BBL Pump IA Interval Test psi BBL Return OA Result (Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer WD BBL Pump IA Interval Test psi BBL Return OA Result Notes: TYPE INJ Codes IN=water G=Ga. S=aWary I = Industrial wastewater N = Not Inj., TVrE TEST Co.. P- Pressure Teel O =OIFer (d..be in Notes) INTERVAL Coces 1=1nNal Teed 4 = Four Year Cycle V = Required 4 Vada - 0 =Corer (ees.nce or nmas) Form 10-026 (Revised 01/2017) MIT SCV 344-33 11-1218 Reviaed Revell Codes P=Pa. F = Fal I = Inwnduslve Data Collection Report Chassis Left Scale Right Scale Serial Number 476741 475325 688896 Datatype OA IA Units PSI G PSI G Lower —Psis —PM 344-33 - 12 -Nov -18, 02:59:07, 507 a ti Axis Title 5 ctc 34 33 p -,b 2160540 2600 2550 2500 2450 2400 2350 2300 2250 2200 2150 m 2100 5 c 2050 2000 1950 — 1900 1850 1800 1750 1700 1650 1600 1550 1500 ry�O 6�P bO 25 24.5 24 23.5 m 23 c 22.5 `v O 22 21.5 21 20.5 —Psis —PM 344-33 - 12 -Nov -18, 02:59:07, 507 a ti Axis Title 5 ctc 34 33 p -,b 2160540 2600 2550 2500 2450 2400 2350 2300 2250 2200 2150 m 2100 5 c 2050 2000 1950 — 1900 1850 1800 1750 1700 1650 1600 1550 1500 ry�O 6�P bO DATE 12/05/2018 Debra Oudean Hilcorp Alaska, LLL GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician II 333 W 7th Ave Suite 100 Anchorage, AK 99501 CD: .. ACX_30AUG18 i. PLUG_11SEP18 i. ACX 12SEP18 21 8054 30 09 3 RECEIVED DEC 1 1 2018 AOGCC 11/7/2018 3:34 PM File folder 11/7/2018 2:50 PM File folder 12/5/201810:41 A... File folder Please include current contact information if different from above. Please Received By: by sigWPig an&Nturning Ne copy of this transmittal or FAX to 907 777.8337 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG TRUE Oil ❑ Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended[—] 20AAC 25.105 20AAC 25.110 GINJ ❑✓ WINJ ❑ WAG[—] WDSPL ❑ No. of Completions: 1 ib. Well Class: Development ❑ Exploratory ❑ Service ❑✓ Stratigraphic Test ❑ 2. Operator Name: Hilcorp Alaska, LLC 6. Date Comp., Su I r Abend.: AV 10/2018 14. Permit to Drill Number / Sundry: 218-054 / 3»R ;,?j$ -40 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded: (3 '� 19• IG July '4' 2018 - 15. API Number. f 50-133-20293-01-00 4-1 4a. Location of Well (Governmental Section): Surface: 1465' FSL, 1657' FEL, Sec 33, T8N, R9W, SM, AK Top of Productive Interval: (Top injection peri) 151' FNL, 596' FEL, Sec 4, T7N, R9W, SM, AK Total Depth: 227' FNL, 550' FEL, Sec 4, T7N, R9W, SM, AK 8. Date TO Reached: August 6, 2018 • 16. Well Name and Number: SCU 344-33 ' 9. Ref Elevations: KB: 143.5' • . GL: 125.5' BF: 125.5' 17. Field / Pool(s): Swanson River Field Hemlock Oil Pool - 10. Plug Back Depth MD/TVD: 11,217' MD / 10,699' TVD 18. Property Designation: , FEDA028990 / FEDA028997 41b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 345991 - y-2462644 • Zone- 4 TPI: x- 347032 y- 2461019 Zone- 4 Total Depth: x- 347076 y- 2460942 Zone- 4 11. Total Depth MD/TVD: • 11,381' MD / 10,860' TVD 19. DNR Approval Number: N/A 12. SSSV Depth MD/TVD: N/A 20. Thickness of Permafrost MD/TVD: N/A 5. Directional or Inclination Survey: Yes ✓ (attached) No Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: N/A (ft MSL) 21. Re-drill/Lateral Top Window MD/TVD: 6,259' MD / 6,258' TVD 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary Drilling Dynamics Log 5"/2", Formation Log 5"/2", Gas Ratio Log 5"/2", LWD Combo Log 572", ROP DGR A11RCTN ALD MD LOG, DGITSDR CTN ALD TVD LOG / CBL CCL r1i g},,. 4,.b' .--- - LJ NOV 2 6 2018 23. CASING, LINER AND CEMENTING RECORD AOGGG WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING FT TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 7" 32# L-80 6,000' 11,350' 5,999' 10,830 8-1/2" 700 sx 24. Open to production or injection? Yes ❑✓ - No ❑ If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): 10,978' - 10,993' MD / 10,459' - 10,474' TVD 10/16/18 10,993'- 11,008' MD / 10,474' - 10,495' TVD 10/31/18 6 SPF, 2-7/8" guns COMPLETION DATE of -5 t // e, VERIFIED & 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 4-1/2" 10,677' 10,657' MD / 10,152' TVD 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes No ✓ Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: N/A Method of Operation (Flowing, gas lift, etc.): N/A Date of Test: Hours Tested: Production for Test Period Oil -Bbl.' Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: Flow Tubing Press. Casing Press: Calculated 24 -Hour Rate Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): Form 10-407 Revised 5/2017 �Z _�._`iCONTINUED PAGE R13DMS O Cw 1 9 2018 Submit ORIGINIAL onlv/i 28. CORE DATA Conventional Core(s): Yes ❑ No ❑Q ' Sidewall Cores: Yes ❑ No Q . If Yes, list formations and intervals cored (MD/ VD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑✓ If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base N/A N/A Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval H-7 10,978' 10,459' information, including reports, per 20 AAC 25.071. G1 10,646' 10,142' G2 10,670' 10,165' H1 10,774' 10,267' H2 10,791' 10,283' H3 10,818' 10,309- H4 10,842' 10,333- H5 10,860' 10,350- H6 10,937' 10,426' H7 10,970' 10,458' H8 11,059' 10,545' H9 11,082' 10,568- H10 11,193' 10,676' H11 11,269' 10,751' Formation at total depth: Hemlock 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Deflntive Directional Surveys, Csg and Cmt Report Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Monty Myers Contact Name: Cody Dinger Authorized Title: Drilling Manager Contact Email: cdinger@hilcorp.com Authorized Contact Phone: 777-8389 Signature: Date: ! Z (- • 1 INSTRUCTIONS General: This form and the required attachmen s provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item 1 a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1b: Well Class - Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 19: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY -123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Form 10-407 Revised 5/2017 Submit ORIGINAL Only n Hilcora Alaska, LLC 20" 90 13-3/8 3,380' r,. lt- as Window [r cut at � - 6,259' v' 9-5/8" 6,259' GL: 125.5' AMSL RKB -18' AGL SCHEMATIC L �Ya0 �jtafEe- 0. 10.& 5 7 Swanson River Field Well: SCU 344-33 PTD: 218-054 API: 50-133-20293-01 CASING DETAIL Size Type Wt Grade Conn Top Btm 20" Conductor Tubing 12.6 L-80 Surf. 90' 13-3/8" Surface 68 K-55 BTC Surf. 3,380' 9-5/8" Surface 47 5-95 BTS Surf. 6,259' 7" Production 29 P-110 DWC 6,000' 11,350' TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 4-1/2" Tubing 12.6 L-80 lBTM 3.958" Surf 10,677' JEWELRY DETAIL NO. Depth ID OD Item 1 328' 3.813" 4.5" X - Landing Nipple (Injection valve) 2 6,000' ±10,120' ±10,135' 7" Linertop packer 3 10,641' 3.958" ±10,859' Anchor Latch Seal Assembly 4 10,651' 5.0" 5.5" Seal Bore Receptacle 5 10,657' 3.958" TV 7" x4-1/2" Packer 6 30,666' 3.813" 4.5" X - Landing Nipple 7 10,677' 3.958" 4.5" WL Entry Guide H-4 H -4/H-5 H-5 H-5 H-7/11-8/1-1-9 H -9/H-10 7 a�` TD =11,381' MD / 10,860' TVD PBTD =11,217' MD / 10,699' TVD Max Deviation = 27.8° @ 6,981' PERFORATIONS New Name Old Name Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Notes H-4 H-1 ±10,843' ±10,859' ±10,120' ±10,135' TBD 318-326 H -4/H-5 H-2 ±10,859' ±10,882' ±10,135' ±10,156' TBD 318-326 H-5 H-3 ±10,882' ±10,903' ±10,156' ±10,175' TBD 318-326 HS H-4 ±10,903' ±10,942' ±10,175' ±10,212' TBD 318-326 1-1-6/1-1-7 H-5 ±10,942' ±10,978' ±10,212' ±10,459' TBD 318-326 H-7 H-5 10,978' 10,993' 10,459' 10,474' 10/16/18 Open H-7 H-5 I , 3 1 11,008' 10,474' 10,495' 10/31/18 Open H-7/9 8/H-9 H-7 ±11,028' ±11,096' ±10,293' ±10,358' TBD 318-326 H -9/H-10 H-9 ±11,148' ±11,253' ±10,409' ±10,513' TBD 318-326 U /L,j! -r Updated by TEK 11-08-18 Hilcorp Energy Company Composite Report Well Name: SRF SCU 344-33 (SCU 33-33 ST) Field: Swanson River County/State: Kenai, Alaska i (LAT/LONG): ovation (RKB): 18 API #: 50-133-20293-01-00 Spud Date: 7/132018 Job Name: 1812067D SCU 344-33 Drilling Contractor Rig 169 AFE #: AFE $: u✓%i, Ops StipalfyaR,r 7/1 212 01 8 MU 9 518" Gen 2 Whipstock with 45K shear bolt to starter mill, anchor set up with 3 screws and a 19K shear value.;TIH slowly from 21'to 6219' filling pipe every 15 stands. At 6219' up wt 119K, awn wt 119K. MU topdrive.;Fill pipe and cont to circ at 113 gpm-220 psi while RU Pollard a -line and Gyro Data tool string. Mud still cold but staying on shakers at this pump rate.;RIH with gyro tool on a -line down to UBHO sub at 6170'. Seat #1 = 218', Seat #2 = 215°, Seat #3 = 213°. Rotated string. Seat #4 = 38". Worked pipe. Seat #5 = 39°, Final survey = 38.24%LD Gyro Data tool string, RD Pollard e -line and released both ;PU single in hole from 6219'to 6281', up 119K, dwn wt 119K. Tag up on top of bridgeplug. Set down 20K and engage trip anchor, PU and pulled 10K over to verify anchor set. SO and set down 40K to shear bolt and release whipstock. POOH one stand, ran stand through Swaco MPD bearing and racked;back. Pulled two more stands and racked back. PU singled in hole 6 jnts. BHA length now 551.96' after setting whipstock. MU topdrive on drill string.;Pump through choke lines to clean and clear piping and poorboy degasser. Continue to circulate at 47spm 2.7 bbls min. Increase to 57spm 3.2 bbis min circulation rate limited due to mud loss over shakers.;Continue to shear mud at 3.7 bbls min . Change out 3 screens from 120 to 100. Increase Pump rate to 95spm 5.48bbis min. Pump rate @ 142spm 8.1 bbls min 675psi. Change all shaker screens to 100. Pump rate @ 180spm 10.3bbis min.;Begin Milling window at 6259, Up Wt 110 Din Wt. 110 , Rt. Wt. 110, TO 5700[p'Ell 435 gpm-882 psi Mill window frpm 62591 to 6266 md. Have recovered 139 lbs metal thus far. Started seeing cement at 6263'. 7/13/2018 Ponfinued milling 8 1/2" window in 9 5/8" casing, from 6266' to 6300' md/6299'tvd. Reamed through window twice rotating/pumping, shut down rotary and pumps, SO down through window to 6297', dwn wt 115K, I to 2k drag when upper mill exited window. Pull from 6297' back up through window, again 1k.;to 2k 1 when upper mill entered window. Cont to pull to 6251' and racked back one stand. Up wt 115K. Total metal recovered thus far= 297 lbs.;Pumped 20 bbl hi -vis nutplug sweep around at 7.5 bpm -535 psi. No real increase in cuttings or metal with sweep to surface.;Circ through kill line to purge air, RU test equipment and test chart, held PJSM, closed upper rams. Using mud pump, pressured upon wellbore/drillstring to 980 psi for an EMW of 12.5 ppg. Held 10 minutes and lost 29 psi. Using test pump pressured up to 1175 psi for an EMW of 13 ppg. Held 10 minutes;and lost 44 psi. Using test pump, pressured up to 1310 psi for an EMW of 13.5 ppg. Held 10 minutes and lost 44 psi. Notified Drilling Manager and Swace MPD Rep of test results. Bled off drillstring and wellbore. Pumped 2.75 bbls total, bled back 3 bbls. RD test equipment.; Monitor well for flow while serviced blocks and topdrive. Adjusted Kelly hose to avoid having to swing pipe around it. ;POOH i , �' / N' 5 stands from 6251' to 5942', hole fill looked good. MU topdrive and pumped dry job. Stage directional BHA tools on Iocafion.;Cont POOH from 5942'to HWDP at �/" J 573', rack back 8 stands HWDP, LD one single. Baker Rep on site to inspect and break down mill assembly. Bottom mill, window mill and upper mill were in gauge. Calculated hole fill = 46, actual hole fill = 51 bbls.;Clean clear rig floor, adjust torque tube to center over rotary table, clean and clear rig floor.;PlU and M/U 8 12" Directional BHA # 3 to 117'. RFO = 299.40°. 7/14/2018 Cont PU and MU 812" directional BHA to float sub at 123'.;Plug in and upload MWD, MU topdrive and perform shallow pulse test at 300 gpm-550 psi. (good), PJSM, load sources.;Cont MU remaining smart iron, HWDP and jars for a total BHA length of 748'.;PJSM, PU single in hole with 412" DP from 748'to 2142'. Held kick while tripping drill, 90 seconds to get TIW stabbed and closed.;MU topdrive and fill pipe. Re-routed bleed off line from standpipe manifold to shakers. Adjusted "T" bar and lower set of three turnbuckles on torque tube, to better center pipe in stack and rotary table.;Cont PU single in hole with 4 12" DP from 2142' to 3325'.;Cont PU single in hole with 4 1/2" DP from 3325'to 5408'.;Conl. RIH with 4 12 DP from derrick 5408-6150'.;PJSM: with rig crew, pollard and gyro data. MU XO and side entry sub in middle of stand.;Re-head E line and calibrate gyro tool. RIH with gyro tool on E -line , seat into UBOH sub TF reading 98deg. for 3 shots. Tighten Packing nut. Pump at 150spm 350gpm 1316psi. 7/152018 Work down through window, TOW 6259', BOW 6276' and exit window with bit. Start pumps and obtain SPR's. Increase pump rate to 435 gpm-1867 psi, ease down through open hole and tag bottom at 6309. Slide drill from 6309 to 630T. WOB 1 to 5K, 30 to 60 psi diff, MW 9.5/vis 54, 50 Whir ROP.;Side entry sub at rotary table, pulled up hole 30' and shut down pumps. Removed clamp and loosened gland nut on SES, pulled up hole with gyro tool on a -line. With tool at surface, broke out SES stand and topdrive, racked back SES stand. PU single off walk and RIH. MU SES stand and topdrive, RIH with;gyro tool on a -line and engage UBHO sub. Installed clamp on wire and tighten gland nut. Start pumps and slide from 6307'to 6340'. WOB 1 to 5K, 434 gpm-1760 psi, 70 to 100 psi diff, 50 Whir ROP, MW 9.6/vis 54, water on at 10 bph, increasing MW to 10.5 slowly, seeing some coal on shakers, had a max:20 units gas, pulled up hole to 6335'.;CBU one time at 421 gpm-1671 psi to clean up the hole prior to gyro tool tripping. Checked brake handle driveline bolts (fight) and greased draw -works during a -line pulling up hole.;Down pumps, remove clamp and loosened gland nut on SES, pulled up hole with gyro tool to surface. With tool at surface, broke out SES stand and topdrive, racked back SES stand. PU single off walk and RIH. MU stand DP and topdrive, pumped a 15 bbl nut plug marker pill and drilled ahead, rotating from;6340' to 6379'. Rotating wob 5 to 10K, 428 gpm-1973 psi, 30 rpm -6414 ftflbs on bolt torque, 110 ft/hr ROP. At 6379' attempted to obtain survey, bad survey. Sweep came back 1500 strokes early. Finished CBU, found pump displacement data had been entered incorrectly in Pason. LO top single off stand,;MU SES stand and topdrive, RIH with gyro tool on a -line and engaged UBHO sub, tightened clamp and gland nut. Drilled from 6379' to 6403'. Sliding wob 3 to 5K, 440 gpm-1680 psi, 175 psi diff. Removed clamp and loosened gland nut on SES, pulled up hole with gyro tool to surface.;With tool at surface, broke out SES stand and topdrive, racked back SES stand. PU single off walk and RIH. MU SES stand and topdrive, RIH with gyro tool on a -line and engage UBHO sub. Installed clamp on wire and tighten gland nut.;Slide Drill F-6403. to 6434' holding too face at 140 degrees 400 gpm 190spm 1550psi 2-5k on bit.;Pull out of hole with gyro tool on e4ine Break out SES stand and rack back Make up stand. Slide/ Drill 812 hole F 6434'to 6460' 425gpm 1960 psi. 40rpm 34k on bit 205- 300 diff. ROP 50fph 9.8 Mw. Pump 251abl. hi vis. sweep while rotating ahead Sweep ret as calculated w100% inc. in cuttings.;MU SES stand & Top Drive, rih with gyro tool on a -line engage UBHO sub. Tighten gland packing and nut. Slide drill 812 hole F-6460- 6465'. 425gpm 1960psi 23k on bit Rap 20fph Gas units max 1650units.;Mud in pits was gas cut F- 9.8+ down to 9.5 Stop and do a flow check saw flow shut well in and circulate through choke & poor boy separator after circulating 65bbls shut pump down and saw no pressure build up on casing or drill pipe. Bleed off pressure, open up annular no flow well static;Notf drilling manager, Decision made to Continue to Slide/ drill F- 6465 - 6457'taking gyro survey 425gpm 1965psi 2-10k on bit. Continue increasing mud weight to 10.5 Mud loggers seeing cement in samples. Unsure that we are tracking along casing.;Current gas 12 units. 7/16/2018 With gyro engaged in UBHO sub, drilled from 6467' to 6496' (29'). Sliding wob 4K, 425 gpm-1680 psi, 250 psi diff, MW 10.1 ppg/vis 50, BGG 12 units, cannot hold tool face, very erratic. Continue to circ at 6496' to cleanup hole for gyro trip. Down pumps.;Loosen clamp and gland nut on SES, pulled gyro tool up hole to surface on a -line. Broke out SES stand and racked back same. Latched stand from derrick and RIH bottom single, LO top single. MU SES stand and topdrive. RIH with gyro tool on a -line and engage UBHO sub.;Drilled from 6496' to 6511', time drilling at 10 ft/hr. Sliding wob 1 to 2K, then up to 10K, 438 gpm-1816 psi, 100 psi diff, 10 ft/hr ROP, MW 10.2 ppg/vis 50, BGG 12 units. Tool face still very erratic, still have slight cement in cuttings and metal shavings. Notified Drilling Manager, decision made;to POOH for cement string.;Finish CBU one time, 438 gpm-1800 psi.;Down pumps, loosen clamp and gland nut on SES, pulled gyro tool to surface on a -line, taking surveys every 30' up to top of window at 6259'. Broke out SES stand and racked back same. PU single and MU on stump to keep pipe tally in order.;Pulled up hole with drill string from 6490'. Up wt 135K. At 6490' pulled 5K over, at 6458' pulled 25K over. Worked string one time and cont pulling with no issue. Had no issue pulling remaining BHA through window. Parked string at 6148'.;Latched up SES stand, RIH to 6179', broke stand and LO gyro tools, RD Pollard a -line, LD both top and bottom joints of SES stand. Monitored well on trip tank (good), measured topdrive hoses for Rig Super. MU topdrive and pumped dry job.;POOH on elevators, inside casing, from 6152'to 3041' Correct hole fill on POOH.;Contmue POOH F- 3041 laying down drill pipe to allow room for BHA and picking up 3 112" tubing for cement stinger, hole fill as calculated.;POOH and lay down HWDP. Found damage to retainer ring on jars, lay same down. Stand back NMDC. 7/17/2018 Clean rig floor, held PJSM on source removal, Sperry Rep removed sources, PU plugged in and downloaded MWD. Cont pull OOH LD BHA. As motor came through rotary table, slick protector sleeve was found resting on top of PDC bit. Drained motor, removed bit. Bit graded a 1-6 and 1/4" under gauge. LD same;PU single joint, MU wear ring run tool, pulled wear ring. MU stack wash tool (diffuser) on single, MU topdrive. Functioned rams couple times each. Circulating through topdrive, flushed stack and ram cavities out real good. LD wash tool, MU test plug, drained stack, RIH and set test plug.;Drilling manager notified us AOGCC required the need for ram coverage on the =/- 800' of 3-1/2" cement stinger. Made arrangements to have 3 12" rams delivered to rig. Crew RU test equipment and 4 1/2" test joint. Opened annulus valve, flooded stack and choke line with water. Tested annular at 250;low, 3500 high for 5 minutes each. Lined up against auto choke on choke manifold, tested at 2000 psi. Good tests, all on chart. Rams on location. LD 4 12" test joint, drained stack, shut down/bled off koomey and opened up lower ram doors. Swapped lower rams to 31 /2". MU 31 /2" test joint. Tested;lower rams and annular at 250 low, 3500 high for 5 minutes each on chart. Good tests. RD test equipment. Pulled lest plug, drained stack, set wear ring. LD test joint. Weatherford on location at 14:30, Peak transferred their tongs onto location for RU.;Stage 312" elevators, slips and tongs on catwalk, sized dog collar for 312", installed XO on TIW for 31/2" 1 B tubing. RU Weatherford tubing tongs, CO elevators.;P/U defuser and RIH W/ 22jts 3 12" IBT tubing to 723' correct hole displacement. Rig down weatherford tubing tongs slips and elevators. R/U 4 1/2" elevators and slips.;Continue RIH with 4 12" 16.60 drill pipe from 723'to 3250' Correct hole displacement.;Circulate and condition mud @ 3250' 177spm 429gpm 400psi Mud wt 10.3 in and 10.3 out.;Move flex collar, RIH W/ 4 1/2" drill pipe and stinger assembly F 3250'- 6259' (top of window, Correct hole displacement.;Circulate and condition mud at 6259' mud weight in 10.3 out 10.30 + Circulate bottoms up 7550 stks mud wt. 10.3 in and out.;Wash down to 6511' @ 350gpm 660psi Tag bottom W/31< down no fill, Continue to circulate and condition mud at 6511', Pull up to 6243'.;Circulate and condition mud for cementjob 425gpm 660psi @ 6243' Mud weight 10.3 in and out, Rig up Halliburton cement manifold and lines while circulating. 7/182018 Finish circ at 10 bpm -700 psi, sitting at 6248'.;MU 15' pup int, then ease down through window 4 stands of DP stopping at 6508'. No issues exiting window or in open hole. Down wt 100K.;MU pump in sub on stump, MU topdrive on pump in sub. MU valve and Halliburton hardline to outlet on pump in sub. Idled rig pumps to circ on hole. Held PJSM with rig team and cementem.;Halliburton pumped 5 bbls water through pump truck, plumbing to manifold on rig floor, through wash up hose to cuttings box to clear and fluid pack lines. Halliburton pressure tested lines at 800 psi low, 4000 psi high. Good tests. Shut down rig pumps, closed lower IBOP on topdrive, lined up;cementem on hole. Halliburton prepped mix water and pumped 24.5 bbis 12.5 ppg spacer at 3.5 bpm -240 psi. Shutdown, broke topdrive from top of pump in sub, inserted wiper ball in drill string, MU topdrive. Halliburton mixed and pumped on the fly, 40 bbls 15.8 ppg Class G neat cement at 4 to 6 bpm ;317 psi. Shut down pump, broke topdrive from top of pump in sub, inserted wiper ball in drill string, MU topdrive. Halliburton pumped 5.5 bbis 12.5 ppg spacer followed with 74 bbis 10.3 ppg 6% KCL mud to displace, at 6 bpm -136 psi. Shut down pump, removed hardlineivalve from pump in sub, removed;pump in sub from stump. Halliburton started cleanup of pump unit to cuttings box. CIP at 09:30 firs on 7-1818. TOC calculated to be at 5954'.;Pulled drill string up hole at 30 R/min, from 6508' to 6245'. At 6245' LD 15' pup jnt, then continued to pull up hole at 30 ft/min from 6245' to 5867', up wt 92K.;At 5867' MU topdrive, CBU twice at 437 gpm-680 psi. Watching for spacer, at first bottoms up saw an increase in MW from 10.3 ppg to 10.7 ppg, PH increase to 11.8. At that point returns went overboard to cuttings box for a total of 34 bbls, then back to active system. No sign of cement at all.;RD Halliburton manifold and hardlines from rig floor. At second bottoms up, shut down, flow check= static, pumped 20 bbl 11.3 ppg dry job.;Cont POOH on elevators from 5867'to 3 12" tubing/XO at 724'. Crew held kick while trip drill.;RU Weatherford tongs, installed dog collar and 3 12" elevators. Derrickman greased crown sheaves. Peak prepped to vac wiper ball through tubing before loading same on traller.;POOH laying down Defuser and 22jts of 312 tubing stinger assembly. Last 5 joints had a skim coating of crusted cement recovered 5+ gallons of cement.;Lay down Weatrerford tools, clean clear rig floor. Pump through kill line to flush stack of any residual cement. Open IA valve.;Make up test jt. pull wear bushing set test plug open doors on lower ram BOP CIO 31 /2 pipe rams to 4 112 rams. Test to 250/3500. All passed. Pull test plug did not set wear bushing due to 1.83 bend in motor. ID of wear bushing is 8.875. Close IA valve.;Make up directional bha 81/2 mill tooth bit motor , MWD. P/U UBHO sub, flex collar. Pulse test mwd. p/u jars & hwdp RIH W 4 1/2 drill pipe to 104T;Class II Fluid Hauled to G&I = 103 bbls Total Hauled to G&I = 539 bbls Cuttings Hauled to G&I = 27 bbis Total Hauled = 51 bbis Daily Metal Recovered = 0 lbs Total Metal Recovered = 347 tbs 7/192018 Cont TIH on 4 W DP with 8 %" kick off assembly, from 1047' to 5867', filling pipe every 20 stands, down wt 110K.;At 5867' CBU 2 times at 433 gpm-1650 psi to fill pipe and condition for drilling rate. Saw no cement at shakem.;Start washing/reaming down from 586T watching for hard cement. 420 gpm-1579 psi, 30 rpm - 4000 ft/lbs torque. Started seeing cement on shakers at 6036 but no change in bit weight (1-2K) or diff psi. At 6061' started seeing diff psi increase and more weight on bit (10K). Drilled cement from 6061';down to top of whipstock at 6259'. 5-10K wob, 174 psi diff. Treating mud with citric acid to control PH. Up wt 112K, dwn wt 112K.;CBU one time at 440 gpm-1730 psi. Held PJSM with Pollard and rig crew on RU for a -line. Hung sheave in derrick. Obtained SPR's at 6259'.;PU singles off catwalk, PU side entry sub and build stand, RIH with gyro tools on E -Line and land out in UBOH sub. Take survey Tool Face at 132deg.Attempt to Circulate 400gpm 1450psi Pack off leaking adjust pack off unable to repair. POOH with gyro tool on E- Line break out SES stand and replace packing element RIH to 500' and test, packing good. Continue rih and land out in UBOH sub. Take survey 180 ff.;Slide drill F-6259- 6295' 425gpm 174spm 1850psi wob 4-10k Up wt. 115. on. wt.115 take slow pump rate 6259'10.3 mw Pump 1 47.sks. =283 psi 57 sks= 322 psi. Pump # 2 47 stk. = 281 psi 57stk. = 334 psi.;Make SES stand connection POOH with gyro tool on E -Line, rack back SES stand, P/U single off cat walk. Make up SES stand. RIH with gyro tool on E -Line and latch up to UBOH sub. Take tool face survey.;Slide drill F- 6295'- 6307'425 gpm 174 spm, 1850 psi wob 10-22k Up wt 118, On. wt. 118 We achieved Kick off 3.6 inclination at 6307' able to hold a toolface, Unable to take surveys casing interference.;Class 11 Fluid hauled to G&I =18 bbis Total hauled to G&1= 557 bbls. Cuttings hauled to G&I = 72 tools Total hauled = 123 bbls Daily metal recovered = 0 Total metal = 347 lbs. 7/20/2018 Slide from 63OT to 6330', wob 20K, 440 gpm-2067 psi, 228 psi diff, 51 ff/hr ROP, MW 10.5/vis 53, BGG 6 units.;PU off bottom 5' and CBU at 439 gpm-1913 psi. prior to pulling gyro to surface.;Remove clamp and loosen gland nut on SES. Pull gyro tool to surface on a-line. Rack back SES stand.;MU stand #92, drill in rotation from 6330' to 6356'. 15 to 20K wob, 438 gpm-1840 psi, 30 rpm-4800 to 5300 tt/Ibs on bott torque, 44 to 63 R/hr ROP, max BGG 30 units. At 6356', have a corrected inclination of 7.75°, projected to be 8° at bit. Obtained SPR's at 6356'.;Pull up hole and back into casing from 6356'to 6193', no issue pulling through window, up wt 118K. CBU one time at 440 gpm-1720 psi, BGG 2 units.;Latch up SES stand, break and LD down same, LD GyroData tool, RD Pollard and release both.;Pump 20 bbl dry job, POOH from 6193' to 1239. Total Safety tested and calibrated gas detection equipment at 13:30. Motorman checked torque on pump pods and discharge manifolds (all good) ;Cont POOH from 1236to BHA at 676. Racked back HWDP/jars and Flex collar w/ UBHO sub lay break out bit, lay down mwd and motor.;Flush out stack Open IA Make up tiw and dart valve to test jt. set test plug. Fill stack and lines. Perform BOP test. Test annular pipe and blind rams floor safety valves & Dart valve. Test all choke manifold kill and choke HCR manual Valves 25013500 f-5 min.;Preform accumulator Draw down test, 19sec 200psi recovery full system 93 sec. Test blind rams 250/3500. Test choke 1500. Witness waived BLM and AOGCC all bop components passed.;Class II Fluid hauled to G&I=45bbls Total hauled to G&1= 602 bbis. Cuttings hauled to G&I = 72 bbls Total hauled = 123 bbls Daily metal recovered = 11 Total metal = 358 lbs. 7/21/2018 RD BOP test equipment, set wear ring, closed annulus valve. Clean and cleaned rig floor while staging BHA. Brought in Peak trailer with singles of DP.;MU 81/2" directional BHA (#6), plugged in and uploaded MWD, shallow pulse tested ok, loaded sources. RFO = 169.06°. TIH with HWDP and jars from derrick to 759.;PJSM, spun elevators, PU singled in with 74 jnts CDS-40 drill pipe, cont TIH with DP from derrick to 3675'. Filled pipe every 40 jnts, then every 20 stands.;Filled pipe. Cont TIH from 3675'to 4918 Fill pipe. Cont. TIH to 6148, Fill pipe pulse test mwd having problems clean signal. Check pulsation dampers on mud pumps pressure at 1500 bleed off to 900psi signal cleaned up.;PJSM; Slip and cut 74' of drilling Iine.;Pason system down Trouble shoot and repair Re calibrate PVT , Block height and depth tracking. Pason replaced system hard drive;Wash down F- 6278 Tag 10' of fill at 6346 continue washing down 6356' 300gpm 1150psi 88 spm. Take slow pump rates at 6336' 10.5ppg mw. Pump 1-47stks.=391 .psi 59 spm.= 444psi Pump 2 46.spm. = 376psi 55spm = 424psi.;Directional drill 8 1/2 hole F- 6356 T - 6477'425 gpm 177 stks 1850 psi. wob 6-8k Tq 7-8k.;Class II Fluid hauled to G&I = Obbls Total hauled to G&1= 602 bbls. Cuttings hauled to G&I = 0 bbis Total hauled = 123 bbis Daily metal recovered = 0 Total metal = 358 lbs. 7/22/2018 Directionally drill from 6477' to 6742'. Sliding wob 7K, 436 gpm-1900 psi, 225 psi diff, 60 to 90 R/hr ROP. Rotating wob 5K, 437 gpm-1876 psi, 65 rpm-5600 ft/lbs on bott torque, 90 to 120 R/hr ROP. MW 10.5/vis 49, ECD's at 10.8 ppg, BGG 24 units. At 6648' Sperry getting good clean surveys.; Released GyroData and Pollard a-line equipment and crews. We are MaddPass Logging the slide sections at 225 R/hr.;Cont directional drilling 81/2" hole from 6742' to 6971'. Sliding wob 10 to 20K, 406 gpm-1660 psi, 120 to 300 psi diff, 30 to 90 Rlhr ROP. Rotating wob 8K, 406 gpm-1797 psi, 60 rpm-7300 R/Ibs on bott torque, 110 ft/hr ROP, MW 10.5/vis 50, ECD's at 10.8 ppg, BGG 18 units.;Cont directional drilling 8 1/2" hole from 6971'to 7147'. Sliding wob 5-15k, 406 gpm 1805 psi, 120-300psi diff, 25-90 fph, MW 10.5+, ECD's at 10.76ppg, BGG 11 units, up wt. 118, dn. wt. 112k, Mad pass logging at 225 fph. Coal gas 100 units.;Cont. directional drilling 8 1/2" hole F- 7147' to 7367'. Sliding wob 5-12k, 405 gpm, 1857 psi, 100- 225 psi diff, 25- 90 fph, MW 10.5, ECD 10.8, having to slide every stand, mad pass logging 225 fph. Up Wt. 122k, Dn. Wt. 118k, During mad pass torque 4k to 6k BGG= 43 units.;Class II Fluid hauled to G&I = 139 bbis Total hauled to G&1= 741 bbis. Cuttings hauled to G&I = 121 bbis Total hauled = 289 bbls Daily metal recovered = 5 Total metal = 3631bs. 7/2312018 Drilled 8 1/2" hole from 7367' to 7392'. Rotating wob 8 to 10K, 450 gpm-2168 psi, 65 rpm-6200 fdlbs on bolt torque, MW 10.5/vis 54, ECD's at 10.9 ppg, BGG 7 units., stopping just above the N_75-8 formation. Pumped a 20 bbl hi-vis nutplug sweep at 7374' prior to drilling stand down.;Confinued to circulate sweep out of hole while working pipe. 420 gpm-1817 psi, 60 rpm-5970ft/lbs off bottom torque. Sweep came back on time and with a 100% increase in cuttings. Circulated until clean at shakers. Obtained SPR's and a survey at 7392'.;Pulled up hole on elevators, from 7392' and into casing, parking bit at 6213'. Up weight 131 K. Trip went well, no issue pulling into window with BHA. Hole fill was good.;Serviced rig, topdrive, Eaton brake and checked saver sub. Replaced two turnbuckle bolts on upper and middle section with longer bolts, in attempt to move torque tube away from derrick and center up pipe in table/stack. Also shimmed subbase on carrier end to help with that.;TIH on elevators Rom 6213'to 7305' and set down 5 times solid, 10 to 20K. Also tried turning drill string with no luck. Filled pipe, brought pumps up to drilling rate and washed down seeing little or nothing at 7305'. Washed last stand to bottom at 7392'. 7305' is a transition f/ silt t/clay.;Resumed drilling 81/2" hole from 7392'to 7532'. Rotating wob 6 to 1OK, 453 gpm-2109 psi, 90 rpm-8000 R/Ibs on bott torque, 90 to 124 R/hr ROP, MW 10.5/vis 50, ECD's at 10.9 ppg, BGG 22 units. 4816 strokes into drilling ahead, hole unloaded a good amount of assorted coal chips and fine sand;(bott up = 6700 stks) Had a max of 738 units gas. At 7421' while rotating ahead, we pumped another 20 bbl hi-vis nutplug sweep. When sweep came back to surface we had a max of 261 units gas and 50% increase in cuttings.;Continued to drill 81/2" hole from 7532'to 7830' rotating- wob 6-12k 425gpm 2150psi 90rpm 75- 8500 Mbs on bottom torque 85-112rop Mw. 10.5/ vis 55 ECD 10.96ppg BGG 106. Max gas 800 units.;Cont. to drill 81/2 hale section F- 7830'-8123' Wob. 6-121k 425 gpm 2150 psi 90 rpm on bottom torque 8 -12 Nibs on bottom 95'-106' rop MW. 10.5/vis 55 ECD 11.0 BGG.;Pump Hi vis sweep at 7891' sweep returned as calculated with 50% increase in cuttings. Mad pass logging on every stand when sliding. Up wt. 138k. Dn wt. 122. Rt. wt. 125. Take SPR at 7890'# 1 mp 47 silks = 387psi. 57 stks=446psi. #2 mp 47 stks=380psi . 57stks=457psi BGG gas 74 units.;Class II Fluid hauled to G/I = 90 bbis Total hauled to G/I = 831 bbls Cuttings hauled to G/I = 90 bbls Total hauled= 379 bbis Daily metal recoverd = 5lbs. Total metal recovered = 365 lbs. 7/24/2018 Cont drilling 81/2' hole from 8123' to 8386, rotating wob 8 to 15K, 427 gpm-2126 psi, 85 rpm-8000 ft/lbs on bott torque, 23 to 115 fl/hr ROP, MW 10.5/vis 52, ECD's at 10.9 ppg, BGG 64 units.;Circulate surface to surface. Cleanup shakers. MW in/out 10.5 ppg. SPR's.;Line up to trip tank. Monitor well. Would not go static. 1/2 BPH flow rate.;Bring pumps back on line. CBU Max gas= 275 units. Non pressured MW=9.9 ppg on bottoms up. MW out 10.5 pressured. Weight up to 10.75 ppg. Monitor well, same flow rate 1/2 BPH.;Prejob with Swaco MPD crew and rig crew. Install bearing.;CBU 500 units max gas. Prejob on using the MPD system for tripping and drilling with Day crew. Line up to pump across the top holding 280 psi back pressure while tripping. Mimic .45 ppg EMW. Wellbore built up to 180 psi while shut in. Pore pressure calculated @ 11.17 ppg. @ 8152 TVD.;PJSM: Operation of MPD system for drilling and tripping. with night crew.;POH wiper trip F- 8385! to 7348' work pipe through tight spots at 7856' , 7835' Saw over pulls up to 20k various depths but did not stop. No rotation or pumping. MPD attempting to hold 280psi back pressure. MPD had some problems with system. Up WT. 145k Dn.Wt. 122k during wiper trip;Service rig. Crown , blocks , top drive and drawworks. Adjust torque setting on top drive to 18,OOOk.;RIH wiper trip F- 7348'to 8267' wash down F- 8267'to 8385' Tagged 10' fill on bottom. No problems on trip in hole( slick) Pump Hi vis nut plug sweep at 8385' Hole unloaded sand followed by 25% increase in cuttings with no excessive amount of coal. Sweep returned as calculated.;Drill 8 1/2 hole f- 8385'- 8432'@ 435gpm 2450 psi 181spm On bottom Torque 6-9k Rop. 15- 951uhr. Mw. 10.8 ECD=11.5 Holding 80psi back pressure MPD. Max gas on bottoms up 693 units.;Drill 8 1/2 hole F- 8342'- 8744' 447gpm = 2400psi 184spm Up.Wt. 150k Dn.Wt. 122k Rt. Wt 125k Torque 6 to 9000 tVlb Holding 80psi Back pressure MPD = 11.68ECD. BBG=33units Connection Gas 53 units @ 8447. 7/25/2018 Directional Drill from 8744'to 8955'. Utilizing managed pressure MI SWACO system. Hold 90 psi while drilling, 250 psi while making connections. 448 GPM, 2600 psi on / 2480 psi off PP, 150k up / 120k do / 130k rot weights, 70 RPM, 8500 ft/lbs TQ on bottom, 7k off, 10-15k WOB, Pump sweep @ 8820' MD.;Pump sweep @ 8820'. 22 bbl Hi Vis w/ nut plug. Came back on time, 25% increase in cuttings. MW =10.8 ppg, ECD 11.45 ppg. Conn gas 142 units @ 8695'.;Directional Drill from 8955'to 9080'. Utilizing managed pressure MI SWACO system. Hold 90 psi while drilling, 250 psi while making connections. 448 GPM, 2550 psi on / 2480 psi off PP, 156k up / 126k do / 134k rot weights, 70180 RPM, 9k ff4bs TO on bottom, 7.5k off, 20k WOB. ROP= 51'/hr.;Slide from 9080 to 9092' . 157hr rop slide interval. Sticky while sliding. PR rate deteriorated to 1.5 fph Attempt to rotate saw a pressure increase to 3750psi pressure bleed down to 2930psi @ 440gpm then pressure increased to 3250psi pulled up with no change .;Set bit on bottom and attemped to drill (rotate) psi increased to 3520 psi penetration rate 1.5fph. PIU bleed pressure off take slow pump rates at 9085'. Slow pump rate F-1 mp 47stks=696psi 57 stks = 763psi Increase from last SPR of 312 at 47 stks and 323 inc at 57stks taken at 8825.;Work pipe and attempt to clear no success pressure still 3150 to 3500psi. Decision make to take a 5 stand short trip and check pressures. Trouble shoot MPD system and found no problems. Suspect problems with plugged bit or motor.;Make short F- 9092' to 8770' maintaining 250psi with MPD No issues with short trip hole slick. Up.WT> 155k On Wt. 130k;Attempt to pump at 8770' with various rates but saw no drop in pressures while pumping . Close well in and monitor pressure build up F-10min well pressure increased from 0 to 40psi. Held meeting with Swaco MPD for procedure placing a mud cap.;POOH on elevators F-8770'to 5159' Maintaining 250psi with MPD on well bore. No problems on TOH, hole slick Mixing mud for mud cap while POOH ;Stop at 5589 Close well in and check pressure build up at the same time mix gel pill for spacer for Mud cap after 40 min pressure built up to 145psi.;Hauled 50 bbls solids to Gil Cumulative 546bb1s Hauled 50bbis class It fluid to Gil Cumulative 1034 Daily metals 1l Cumulative Metal 366lbs 7/26/2018 Build 20 BBL Hi-Vis 300+ pill. Move 80 barrels out of active system to Vac truck. Dust up mud cap pill to 14.6 ppg. Wellbore pressure built up to 270 PSI. Had slowed down to 9 psi per 10 minutes, Did not flat Iine.;Prejob meeting with all parties . Pumping viscosity pill followed by pulling out 300 feet.;Pump HI-Vis pill. 47 SPM, 430 PSI, chase with 1250 stokes. Hold 250 psi with MPD while pumping.;Strip out 5 stands, 300 feet to get above Hi-Vis pill. Hold 300 PSI w/ MPD. 5590' to 5283' MD.;Establish circulation. 68 SPM, 680 PSI. Hold 300 PSI W/ MPD. Pump 118 BBLS 14.6 PPG mud cap. Chase with 1180 strokes.;Line up to pump across top via kill line to MPD. Strip out keeping 120 PSi with MPD static, 180 psi pulling. From 5283'to 2550' MD. Good hole fill.;Lay down singles. from 2550' to 751' for a total of 56 singles. holding 80psi on well with MPD head/bearing. Good hole fII.;Pull rotating head bearing set flow nipple. Flow check on well showed 1 bbl per hr. after 30 min. flow at 1/4bbl per hr. then well static no flow.;POOH, stand back HWDP, Jars and Flex collar. Remove sources ff MWD troubleshoot problems with powering down MWD. Found Two floats open with coal wedged in them. Bit had 2 screws from motor cv boot blocking 2 jets.;Repair and replace 2 - 8" butterfly valves in pits 3 & 7 clean pits Found coal and sand and silt, heavy coal in pit #3. continue monitoring well no flow.;P/U and make up BHA # 7 8 1/2" Bit MM55, T' 1.5deg. mud motor, triple combo to TM collar, float sub XO to top drive. Up load MWD system.;Hauled 45bbls solids to Gil Cumulative 591 bbis Hauled 45bbls class II fluid to Gil Cumulative 1079bbis Daily down hole losses 0 Dailey Metal 0 7/27/2018 Pick up MWD system to float sub. Pulse check MWD tools. Good. Load sources.;TIH w/ HWDP. to 1st stand of DP. Pull trip nipple. Install new MPD bearing assembly. Close well in and monitor on MPD chokes.;Clean pits #1, 92. Remove mud with vac trucks, clean pits, pump mud over shakers and back in pits. Clean stack, rig up on Skim pit pad with pump to circulate stored mud in 400 bbl upright tank. Well pressure built to 150 psi.;Crew change. Train crew on MPD. Open chokes, line up to pump across top via kill line and hold back pressure with MPD. Service rig. All motors.;Single in hole. Pick up 33 joints, fill pipe. Maintain back pressure at 150 psi static, 100 psi dynamic.;Single in hole. Pick up 23 joints. From 1750' to 2500'. Tum elevators around. Begin running stands out of the derrick to 34801.;Fill pipe and circulate B/U at 3480' Mud weight in and out 10.9.;RIH F- 3489- 6280' 12 outside of window Maintain 210psi back pressure with MPD.;Fill pipe and circulate out 14.6 mud cap. No cap seen. Even mud weight out at 11.0 ppg. Circulate surface to surface. Max gas 635 units on Bottoms up. continue circulating total of 12456stks Pump outside window 156gpm . 300gpm in casing.;Trip in hole holding back pressure with MPD. Trip to 7045' Fill pipe. Wash through clay bed. Sat down w/ 20k two times, and cleaned up with pumps. Tripped to 7396' sat down 2 x s 20k wash down. 7/2 812 01 8 Trip in hole on elevators from 7697' to 7885'. Tag upon ledge. Set on 3 x's 30k. CBU w/430 GPM, 1900 PP, 50 RPM. Max gas 1150 units. Shakers remained loaded up with fines and some coal pieces. MW in 10.85, MW out 11.4. 124k up / 110k do / 121 k rot weights. Sweep brought out 50% increase.;Wash ream in the hole from 7885 to 9001'. W/ 400 GPM, 2000 PP, 7500 to 10,000 k TO, 50 RPM. Attempt to go back to elevators @ 8050', no go. Stay with reaming. Each coal bed had to be cleaned out. Worst Ledges seen @ 8111', 8120', 8180', 8215', 8385', 8665, 8690', 8885. 10-20k weight.;Held no back pressure while reaming, and closed in on connections. Record 10 to 11 BPH gain for last two hours. Take SPR's, pump sweep, 20 BBL Hi Vis. 25% increase in cuttings seen.;Wash and ream last stand to bottom. 450 GPM, 2630 PP, 7500 TO. 50 RPM, 165k up / 1251k do 11 40k rot. No fill seen on bottom. Drill out compression from last bit run. Attempted to pack off once.;Directional Drill from 9101' to 9212' MD. ROP 757hr. 450 GPM, 2750 PP on / 2550 PP off, 60 RPM, 7500 TO, MPD held 200 PSI while drilling, 380 PSI while making connection. Wellbore stopped giving Fluid while holding 11.7 ppg ECD equivalent.;Drill Rotate F- 9212'-9280 up. Wt. 165k Dn. Wt. 125K Rt. Wt. 139k 450gpm 185 stks 2640psi rop 60-90fph Tq 6-81k/Ibs. harmonic vibration setting up in drill string. Work pipe and back ream attempt to clean up. while holding 250 psi back pressure MPD. Attempt to drill, MPD bearing failed.;PJSM Replacing MPD Bearing: Pull and set stand back. Bleed down MPD pressure R/U and pull Bearing. Install new bearing. Monitor flow at shakers Well flowing @ 1.25 bbls per Hr.;Drill ahead F- 9280'-9621'. Up. Wt. 1551k On. Wt. 128k Rt. Wt. 132k Tq. 6-10k Harmonic vibration increasing Add lube to system. 1 %Continue to drill ahead. Pump 445gpm 2625psi Vibration Intermittent when rotating, vary bit weight and rotary speed. Pump Hi vis sweep at 9559' No gains or Iosses.;Hauled 95bbls of solids to Gil Cumulative 731 Hauled 95bbls of class II fluid to G/I Cumulative 1219 Down hole losses 0 Cumulative Metal 369 # 7/29/2018 Directional Drill from 9621' to 9869' MD. ROP 761hr. 450 GPM, 12 K WOB, 3050 PP on / 2750 PP off, 60 RPM, 9200 TO. MPD held 300 PSI while drilling, 380 PSI while making connection. Conn @ 9743' MD the pressure built from 380 psi to 600 psi. 12.1 PPG EMW.;Pit gain started @ 4 BPH at 900 his, 15 BPH @ 1000 hrs, then 10 BPH @ 1100 hrs. The connection @ 9806' the pressure built from 400 to 440 psi and then broke over to 420 psi. MW= 10.9 ppg, ECD with 300 psi held= 11.72 ppg.;Directional Drill from 9869MD to 10,056' MD.. ROP 757hr. 450 GPM, 3050 PP on /2750 PP off, 60 RPM, 9200 TQ, MPD held 300 PSI while drilling, 380 PSI while making connection. @ 10,056 MD the pressure built from 380 psi to 600 psi. 12.1 PPG EMW.;Circulate out sweep F-10,056' Sweep returned as caculated with no increase Gas on bottoms up 300units Take slow pump rates at 10,040' MD. # 1 MP 47 stks. = 330psi 57stks=340psi #2 MP 47stks 330 57stks= 360.;P00H on elevators (Wiper trip) F-10,056' to 9030' Holding 440 psi back pressure W/ MPD Up Wt. 190k Dn. Wt. 130. Hole slick no problems. Well flowing 6.6bbls per hr. Mud weight 10.8.;Service rig. Crown, blocks Drawworks top drive , and swivel. Change oil in drawworks motor and add gear lube to top drive inspect crown. Derrick and top drive.;RIH F-9030'to 999T Wash Rotate last stand down to 10,056' tag 3' of fill. Holding 350 back pressure with MPD. No problems with TIH.;Directional drill 81/2 F 10,056'- 10,237' 450gpm 3050psi Tq. 9k-11 k 60rpm Rop. 12-65 fph MPD holding 416psi. =11.8 ECD. B/U gas 1726 unfts.;Hauled 80bbls solids to G/I Cumulative 811bbls Hauled 801bbls class II Fliud to G/1 Cumulative 12991bbis Daily Metal 0 Total Metal 369lbs. 7/30/2018 Directional Drill from 10237'to 10367' MD. ROP 307hr. 450 GPM, 14 K WOB, 2938 PP on / 2668 PP off, 50 RPM, 10.5k TO, MPD held 320 PSI while drilling, 450 PSI while making connection. Conn @ 10244' MD the pressure built from 400 psi to 560 psi. 12 PPG EMW.;Following WP #7. Begin inclination drop from 29° to 10°. Slow sliding. Add lubricant to assist. 169k up / 133k do / 148 rot weights. MW=10.85 ppg, ECD held @ 11.78 to 11.85 ppg with MPD. Gaining 10 bph water.;Directional Drill from 10367' to 10,463' MD. ROP 20'/hr. 450 GPM, 11 to 16 K WOB, 3065 PP on / 2725 PP off, 50 RPM, 10.51k TO, MPD held 340 PSI while drilling, 450 PSI while making connection. Conn @ 10429' MD the pressure built from 440 psi to 570 psi. 12 PPG EMW.;Rotate and slide from 10,463' to 10,590' MD. 127' total (21.6' AROP) 440 GPM, 2,800-3000 PSI, 5-1 OK WOB, 50-70 RPM, 12K TRQ, P/U 185K, SLK 140K, ROT 150K. Drill ahead with MPD holding 350-400 PSI to control ECD while drilling.;Well flowing 4 to 10 bph of water. Mud weight in and out 10.75 ppg. ECD 11.75 ppg. BGG 90- 160U.;SPR @ 10,544' (10,042' TVD) MW 10.75 ppg. MP #1 47-319 PSI, 57- 377 PSI. MP #2 47-319 PSI, 57- 408 PSI.;Rotate and slide from 10,590' to 10,710' MD. 120 total (20' AROP) 450 GPM, 2,760 PSI, DIF 300 PSI, 10.3 to 11.2K WOB, 60 RPM, 9,800 TRQ, P/U 186K, SLK 140K, ROT 150K. Drill ahead with MPD holding 300 PSI to control ECO while drilling.;Well flowing 4 to 10 bph of water. Mud weight in and out 10.95 ppg. ECD 11.84 ppg. BGG 90U Max 160U. Distance from plan 15.68, 14.94' low, 4.75' left.;At 10,710' MD Circulate and reciprocate 230 GPM, 1,294 PSI, MPD 400 PSI, ECD 11.84 ppg. Shut down MP #2 and work on swab and Iiner.;Hauled 86 bbls solids to Gil Cumulative 896 bbls Hauled 175 bbls class II Fliud to Gil Cumulative 1,475 bbls Daily Metal 0 Total Metal 370 lbs. 7/31/2018 Pod #1 of Pump #2 leaking swab and liner gasket. Stand back one stand. Work string while changing out swab. Circ on one pump 220 GPM, 30 RPM, 1325 PP. Repair pump. Prejob for changing out leaking MPD RCD. Swap bearings out in 40 mins. Monitor well on TT, 27 BPH flow rate.;Gas peak at BU= 1512 units. Non pressured MW out cut to 9 ppg from 10.9 ppg. Gas spike from TY sand 80-3= 800 units. Hole has 10% washout.;Directional Drill from 10710' to 10744' MD. ROP 1571hr. Clay / Siltsone / Sands. 450 GPM, 14 K WOB, 3090 PP on / 2815 PP off, 50 RPM, 11.51k TO, MPD held 300 while drilling, Lost 200 psi PP. Pick up off bottom. Pump 2 pod 3 leaking.;Stand back one stand circulate w/ pump 1, GPM 220, 1300 PP, 50 RPM. Replace both liner gaskets in pod 3. Test run pump. Good. Trip in one stand.;Directional Drill from 10744'to 10772' MD. 10'R0P'/hr. Conglomerate @ 10760' MD. 440 GPM, 20 K WOB, 3090 PP on /2815 PP off, 70 RPM, 11.5k TO, MPD held 300 while drilling, 480 psi on connections. MW=10.9 ppg, ECD=11.82 ppg. Lost 200 psi PP.;Pick off bottom. Pump on one pump at a time. Clean out both suction screens, polymers, mud products. Rotate and reciprocate.;Directional Drill from 10772'to 10779' MD. 6/hr R0P. 440 GPM, 20 K WOB, 2900 PP on 12520 PP off, 70 RPM, 11.5k TO, MPD held 300 while drilling, MW=10.9 ppg, ECD=11.75 ppg. 186k up/ 1371kdo 1155k rot. Conglomeratic samples.;Drill ahead F/ 10,779'to 10,784' MD Adjust drilling parameters to increase ROP. Increased decreased RPM, WOB, pump rate and worked drill string several times. Pumped 28 bbl Nut Plug sweep with no sign of increased ROP. Sweep returned to surface as calculated.;Stopped rotary and tagged up to simulate slide. Increased weight to 15K and observed 40 PSI Diff with no tool face reactive torque. Decision was made to POOH. Distance to plan 13.33', 12.06' low, 5.69' Ieft.;Reduced surface volume and increase mud weight to 11.0 ppg. Check suction screens MP #1 & #2 due to pump pressure after moving fluid around in pits. Appeared mud was aired up due moving fluid around. Cont. working on increasing mud weight F/ 10.9 pp to 11.0 ppg.;Cont. to try and drill ahead without success. Finish weighting up F/ 10.9 ppg to 11.0 ppg mud weight.;SPR @ 10,785' MD (10,277' TVD) W/ 11.0 ppg MW. MP #147-308 PSI, 57-390 PSI. MP #2 47-305 PSI, 57-430 PSI.;Rack back one stand. Line up on Kill Line and Choke, idle pump #1 at 115 GPM, 445 PSI and hold 450 to 500 PSI with MPD. Pulled next stand with 62K over pull before breaking free. Cont. to POOH on elevators with no issue PIU 21 OK F/ 10,785' to 7,818' MD.;Hauled 85 bbls solids to G/I Cumulative 981 bbls Hauled 175 bbls class II Fliud to GA Cumulative 1,650 bbls Daily Metal 0 Total Metal 369 lbs. 8/1/2018 Trip out on elevators from 7818'to 7580'. Keeping 520 psi back pressure with MPD. 35k overpull, run in one stand. Establish circulation. Begin BROOH.;BROOH from 7580' to 7020'. 430 GPM, 2650 PP, 40 RPM, 6500k TQ. Dressed off the coal @ 7520', reamed depths where we saw overpull, 7371', 7330', 7300'. Shakers loaded up, cleaned hole up.;POOH on elevators wiping coal @ 6850', good hole conditions from there into the shoe. Stripping out with MPD keeping 530 psi.;Pre job. Slip and cut drilling line, service rig. Holding 550 psi with MPD pumping with one pump 47 spm via kill line. Gain 6 bbls first hour, Added 40 psi to back pressure, lost 4 the second hour.;Prejob with crew. Pumping spacer and weighted pills. CBU ;Pump 23 bbls of 14 ppg hi vis spacer. 47 SPM, 660 PSI, Strip out of the 5 stands to 5904' MD.;Pump 80 bbls 15.5 ppg mud cap 47 SPM, 775 PSI, Chase with 1411 stokes. Place in open hole. Follow pump schedule. ICP=520, fcp= 280 psi.;Strip out holding 300 PSI static, 380 PSI dynamic. From 5904'to 5706'. Crew change. Pumping in and out of pits 3 and 7. MW=11 ppg.;Cont. POOH with MPD 300 PSI static, 380 PSI dynamic. F/ 5,706' to 4,787' MD P/U 97K.;Lined up to pump mud cap and MPD head started leaking. Was unable to hold back pressure. Close Annular and line up through Choke Manifold. Well bore Press. climbed to 432 PSI over 45 Min.;Change out MPD bearing. Line back up on well to pump mud cap.;Pump 90 bbl 15.5 ppg mud cap at 47 spm followed by 66 bbl 11.0 ppg mud. While pumping performed a step down F/ 380 PSI back Press. to 103 PSI.;Line up to pump down Kill Line through MPD. POOH holding 100 PSI back Press. F/ 4,787' to 1,423' MD.;Swap over elevators and lay down singles F/ 1,423'to 769' MD.;Turn off pumps and bleed off Press. Monitor well flow. Hold PJSM on removing MPD head and set tripping nipple. Initial flow rate at 10 bph over 10 min. slowing to 6.7 bph after 45 Min.;Pull Bushings and remove MPD head. Stand back stand with head in Derrick. Install tripping nipple.;Cont. to rack back HWDP, Jars and flex Collars F/ 707' to 119' MD.;PJSM for removing nuclear source. Halliburton remove nuclear source. LID TM Collar. 8/2/2018 Continue to lay down BHA#7. Remove all components from rig floor. All tool safely retrieved from the well. Bit grade 8-8-LT-A-X-4-LM-PR. Clean and clear rig floor.;Clean and clear rig floor. Begin monitoring well in cellar. Open IA. 4.6 bph rate of flow. Wash stack after wet trip. Pump out cellar.;Drain stack, pull wear bushing, wash out stack, pump out cellar Set test plug. Rig up to test. Fill stack.;Flush mud out of MPD choke system. Chase air out of choke house. Open choke #1, twice and bleed small air volume out. Good shell test to 3500 psi. SIMOPS: Rebuild 4" Oteco valve on stand pipe. Clean out suction and discharge screens both pumps. Replace gaskets in pod 2 of pump 2.;Test BOPE. Test annular, solid 4.5" pipe rams upper and lower. floor safety valves & Dart valve. Test all choke manifold valves, kill and choke lines HCR and manuals, kill line valve on mezzanine. All tests held for 10 mins/ low and high. BLM required monthly test.;Perform accumulator Draw down test, 25sec 200psi recovery full system 106 sec. 2600 psi average for 4 nitrogen bottles. Test blind rams 250/3500. Test manual and Super choke to 1500, held pressure. Test with 4.5" TJ. BLM and AOGCC waived witness of test. Well flowing 5 bph through open IA.;Total safety calibrated and tested all gas alarms and systems.;R/D test tools and Equip. Pull test plug and set wear. ID 8.875".;Clear off Catwalk and load Motor #7 and bit.;P/U BHA #7 and break off 8.5" Bit, Float Sub and DM Collar. L/D all.;PJSM W/ all parties for new BHA. C/O Centralizer sleeve and bottom of motor as per DD. P/U IWU new Reed 8.5" Bit, new 6 3/4" StrataForce 617 - 6.0 stg motor, Float Sub, 6 3/4" OM Collar, 6 3/4" ADR Collar, 6 3/4" DGR, 6 3/4" PWD, 6 3/4" ALD Collar, Stab, 6 3/4" CTN Collar, 6 3/4" CTN Collar,;6 314" TM HOC.;Up load and link MWD tools. Shallow hole test MWD tools at 450 GPM, 1,300 PSI. PJSM W/ all parties for loading nuclear source. Halliburton load nuclear sources.;L/D source boxes. Turn around Elevators. At 02:15 During turning around elevators , elevators rotated out of bails and came in contact with floor hands left foot on floor. Shut down all operations. IP was taken for medical attention. All personnel filled out witness statements.;Cont. operations. Turn elevators around. RIH W/ 4.5" HWDP to 310' MD. Change out Jars.;Hauled 0 bbls solids to Gil Cumulative 1,017 bbls Hauled 161 bbls class II Fliud to GA Cumulative 2,149 bbls Daily Metal 0 Total Metal 369 lbs. 8/3/2018 Trip in the hole with HWDP to the first stand of DP.;Prejob. Install bearing. Wellbore flowing 12 BPH prior to installation of RCD.;Pressure test rebuilt 4" Oteco valve on rig floor stand pipe. 4600 psi. Good. Wellbore built pressure up to 290 in 35 mins and was still climbing when we began to trip in the hole.;Begin holding 210 dynamic and 300 static. RIH 10 joints. Well still flowing 12 BPH. Pinch in to 260 dynamic and 350 static. Single in 10 more joints. Gained 2 bbls.;TIH 1.5 mins per stand. 31 00'MD.;Circulate surface to surface. 113 GPM, 680 PP. MW in 11.3 ppg, MW out 11.4 ppg. Holding 450 psi back pressure.;Tnp from 3101 to 4724. 1.5 mins/stand. Holding 500 psi static, 400 psi going in. Gaining 8 BPH average. Fill pipe. MW=11.5 ppg.;Trip from 4724 to 6,210' MD. 1.5 mins/stand. Holding 500 psi static, 400 psi going in. Gaining 8 BPH average. MW=11.5 ppg. Gained 62 bbls from well over last 12 hours. 90 bbls while OOH. 150 BBLs total.;Circ. and condition mud at 114 GPM, 600 PSI, Reciprocate pipe. Mud weight out initially 11.9 ppg just before BU nud weight cut to 10.4 ppg. Stage up pumps to 250 gpm, 1,080 PSI to establish 11.8 ppg ECD holding 360 PSI back Press. W/ MPD. Condition mud until mud weight in and out 11.0 ppg.;Max Gas 708U.;RIH F/ 6,210' to 7,336' MD. Encountered tight spots at,7,010', 7,045' and 7,140'. At 6,636' and 7,280' had to wash through tight spots with 240 GPM, 990 PSI, 360 PSI back Press. holding 11.7 ppg ECD.;At 7,336' MD had to wash and ream to 7,386' MD. 300 GPM, 1,514 PSI, 30 RPM, 4-91< TRQ, P/U 126K, ROT 118K, WOB 1 OK. Holding 450 PSI back Press. W/ 11.84 ppg ECD.;During Washing and reaming encountered 1,4241-1 Gas and 8.7 ppg mud weight due to water cut. Started dumping and working on maintaining 11.0 ppg. Had to reduce Circ. to 256 GPM, 1,300 PSI, 360 PSI back Press, ECD 12.0 ppg to reduce influx of water and Gas. Gas dropping to 40U.;Working on getting mud weight in and out 11.0 ppg ;Hauled 28 bbls solids to G/I Cumulative 1,045 bbls Hauled 162 bbls class II Fliud to G/I Cumulative 2,311 bbls Daily Metal 0 Total Metal 369 lbs. 8/4/2018 7367' MD. Circulate and condition wellbore. 310 GPM, 1584 PP, 30 RPM, 7500 TO, MW=11 ppg iniout, ECD=11.84 ppg. Back pressure 600 psi static 1550 psi dynamic. Hole cleaned up. Dumped 160 bbls of water and watered back mud. Hauled to G&I. Trip in to 7428 tag up 3 x's 20k.;7428 to 8560'. Wash and ream in the hole. Sat down on all large coal beds. 380 GPM, 2020 PP, 40 to 70 RPM, 7500 to 18,000 TO, Siftstones with clay matrix swelled, 7460 to 7490, 7600 to 7680. 7883' hole unloaded sand and some coal pieces, 100% increase.. Coal bed @ 8402 to 8430 reamed 2Xs.;MW in 11 ppg, MW out 10.8. Still coming out cut 2/1 Oths. Back ground gas remained around 300 to 550 units. Back pressure held to 300 dynamic, 400 static. No loss or gain to pits holding 11.85 ECD. Shakers unloaded in waves with the 500 units of gas spikes. Wellbore flowing approx. 8 BPH.;8560 to 9746' MD. Wash and ream. 8550' to 8570' stalled rotary, 18k, 8780' 18k stall, 8840' 16k, swelled siltstones. Coal @ 9060', reamed into with 10k pulled 40k over to get out. Coal 9070', stalled 18k picked up 30k, 9303 pulled 60k over.;9350' sat 10k down pulled 30 k over to get out coal, 9456' sat down 10k pulled 30k over.;400 GPM, 2480 PP, 9 to 18k TO, 60 RPM, MW in i i ppg MW out 10.9.Maintain ECD @ 11.85. Back pressure 300 dynamic, 400 static. During connections wellbore pressure slowly builds to 500 or more. Added 3 drums NXS for vibration / harmonics. BG gas=300, Max gas=629.;Cont. to wash and ream F/ 9,746' to 10,785' MD 60 RPM, 400 GPM, 2,250 PSI, 8.5K TRQ, ROT 145K, Dynamic back Press. 320 PSI, Static 400 PSI Maintain 11.9 ppg ECD. Well bore flowing 2-4 bph. Encountered tight spots at 9,930' to 9,990',10,706' to 10,766' MD.;Sat down 10K with about 20K over pull. Max Gas 316U, BBG 60U.;Drill ahead 8.5" BHA #8 F/ 10,785' to 10,936' MD (10,438' TVD) total 151' (AROP 25.16') 425 GPM, 2,550 PSI, WOB 8-10K, 65 RPM, TRQ 3 -SK, P/U 200K, SLK 136K, ROT 158K. MW 11.05 ppg. Back Press 290 PSI dynamic, 400 PSI static. ECD 11.85-11.90 ppg.;Running 10 bph water. No gains from formation. BGG 60U. Distance from plan 9.3', 7.32' low and 5.74' left.;SLP at 10,923' (10,420' TVD) MW 11.0 ppg MP #1 47-340 PSI, 57-415 PSI MP #2 47344 PSI, 57-426 PSI Back Press. 420 PSI;Hauled 90 bola solids to G/I Cumulative 1,135 bbls Hauled 360 bbls class II Fluid to G/I Cumulative 2,671 bbls Daily Metal 0 Total Metal 369 lbs. 8/5/2018 Drill from 10936' to 10987'. 430 GPM, 8-10k WOB, 60 RPM, 9k TO off 111 k TO on. 2600 PP off / 2850 PP on, ECD=11.75 ppg, MW 11 ppg in/out. Hemlock top Ticked by ROP at 10,838'MD. 187K UP 1138K DN 1158K ROT WEIGHTS. 8 BPG flow from well. Back Pressure 250 Dynamic / 420 Static.;Saver sub broke under the top drive clamp on quill. Remove clamp install new saver sub with 5.40" OD. Replace dies in clamp. Torque clamp bolts to 255 ft/lbs. Torque 4" FH top to 25k. Reset torque for drill pipe to 19,500 ftllbs. Continue drilling ;Drill from 10987' to 11,049'. 430 GPM, 8-10k WOB, 60 RPM, 9k TO off/ 11 k TO on. 2600 PP off 12850 PP on, ECD=11.75 ppg, MW 11 ppg in/out. 187K UP / 138K DN / 158K ROT WEIGHTS. 8 BPG flow from well. Back Pressure 250 Dynamic 1420 Static.;Drill from I1,049'to 11,181.450 GPM, 8-1 ok WOB, 60 RPM, 9k TO off / 11k TO on. 2700 PP off 13000 PP on, ECD=11.78 ppg, MW 11 ppg in/out. 187K UP / 138K ON 1158K ROT WEIGHTS. 4 to 8 BPH flow from well. Back Pressure 325 Dynamic 1480 Static. Adding 15 BPH water.;Drill ahead 8.5" hole F/ 11,181'to 11,268' MD ( 10,749' TVD) total 87' (AROP 14.5' ) 450 GPM, 2,750 PSI, WOB 8K, 55-65 RPM, TRQ 10-12.5KK, P/U 190K, SLK 138K, ROT 160K. MW 11.0 ppg. Back Press 360 PSI dynamic, 480 PSI static. ECD 11.80 ppg.;Running 10 bph water. 4-7 bph gains from formation. BGG 45U.;Drill ahead 8.5" hole F/ 11,268' to 11,319' MD 110,801' TVD) total 51' (AROP 8.5' ) 440 GPM, 2,750 PSI, WOB 8K, 55-65 RPM, TRQ 10-12.5K, P/U 192K, SLK 140K, ROT 160K. MW 11.0 ppg. Back Press 360 PSI dynamic, 480 PSI static. ECD 11.80 ppg.;Running 10 bph water. 4-6 bph gains from formation. BGG 45U. Distance from plan 7.96, 6.77' high and 4.18' Ieft.;Hauled 36 bola solids to G/I Cumulative 1,171 bbls Hauled 144 bbls class II Fliud to G/I Cumulative 2,815 bbls Daily Metal 0 Total Metal 369 firs. 8/6/2018 Or 11 from 11.319'to 11,343'. 450 GPM, 8-12k WOB, 70 RPM, 9k TO off / 11 k TQ on. 2600 PP off 12850 PP on, ECD=11.8 ppg, MW 11 ppg in/out. 192K UP / 140K DN / 162K ROT WEIGHTS. 4-6 BPH flow from well. Back Pressure 350 Dynamic 1460 Static.;11,343: Pump two Liner and swab on pod 1 began leaking. Come off bottom, line up on pump 1, 220 GPM, 50 RPM, 1200PP, isolate pump 2. Replace swab and liner while working the drill string with one pump on the hole. Job complete.;Drill from 11,343' to 11,362'. 40 GPM, 8-12k WOB, 70 RPM, 9k TO off / 11 k TO on. 2600 PP off 12850 PP on, ECD=11.8 ppg, MW 11 ppg inlout. 192K UPI 140K DN / 162K ROT WEIGHTS. 4-6 BPH flow from well. Back Pressure 350 Dynamic 1420 Static.;11,381': Drill from 11,362'to 11,381 ✓ Called TD.'. 440 GPM, 8-12k WOB, 70 RPM, 9k TQ off 111 k TQ on. 2800 PP off /3025 PP on, ECD=11.8 ppg, MW 11 ppg in/out. 191 K UP / 145K DN / 162K ROT WEIGHTS. 43 BPH flow from well. Back Pressure 350 Dynamic 1420 Static.;11381' MD: TD Ream stand. Survey. Slow pump rates. Pump Hi -Vis sweep with nutplug STS. 191 k up, 145k dn, 162 rot weights. Rotate and reciprocate string. Hi Vis nutplug sweep came back showing 25% excess open hole size.;10920: Pump out of the hole from 11,381 to 10,920'. with 400 GPM, 2400 PP, 192k up weight, holding 400 while pulling and 500 psi static with MPD. Some differential sticking seen when pulling out of the slips. Up to 30k over to get traveling.;Continue to pump out of hole F. 10,920'-10,736' 400 gpm, 2380psi 190k up Holding 580psi back pressure and 450 psi static with MPD, Hole clean with various over pulls to I0k.;Cont. POH on elevators F-10,736'to 6203' At 9770' 7880' and 7669' Pulled 20k over. At 7596' and 7552' pulled 46k ( coals) over string weight. Hole was clean up into the window at 6259'. Holding 580 back psi while POOH static 450psi. Note: lay down 1 jt. 4 1/2 drill pipe .;Pump B/U at 6203 followed by Pumping 20bbls 14ppg Hi- Vis spacer at 6203'.;Pooh F- 6203 to 5904' Holding 430 psi back pressure with MPD.;Circulate and pump 100bbls of 15.5 mud cap 47spm 110gpm 740psi Followed by 80bbls of 11.0ppg mud. Adjust MPD pressure F- 495psi down to 280 psi. Hold 280psi While POOH.;POOH F- 5904'- 5241' Holding 430psi back pressure with MPD.;Hauled 52 bbls of solids ti G/I Cumulative 1223 Hauled 398 class II fluid to G/I Daily down hole losses 0 Daily metal 0 Total metal 369 lbs. 8/7/2018 After placing 100 bbis of 15.5 ppg mud cap in casing, cont POOH from 521T to 4475'.;At 4475', held pre -job on pumping 2nd mud cap. Pumped 67 bbis 15.5 ppg then chased with 1080 strokes down the drill string. Lined up to POOH on pits 3,7. Pumping via kill line across the top of hole while holding 100 psi back pressure.;Cont POOH holding 115 psi with MPD. 100 psi while string static in slips. TOOH to HWDP. Removed bearing on last stand DP. Installed trip nipple. Well flowing at 4.2 bph during bearing/trip nipple change. Removed well used bearing/sealing element from stand of DP.;Turned elevators and cont POOH LD HWDP. Peak using vac truck to clear mud from joints with wiper ball, then loading HWDP on trailer. Cont POOH LD directional BHA Remove sources. Download LWD/MWD data. Clean stack.;Clean/ clear rig floor,make up testjt, Remove wear ring, set test plug, open IA valve. Remove 41/2pipe rams from bottom ram. install T' casing rams . Fill stack with H2O. Purge lines. Test Annular and 7" casing rams 250/3500 Smin. Test good. Monitor well flowing 4.7bbls per hr.;Pull test plug, set wear ring RID test joint and tools. Well flowing .7-5bbis per hr.; old PJSM : R/U Weatherford casing tools tongs, elevators and slips. Lay down rig tongs to make more room on rig floor.;Hauled 0 bbis of solids to Gil Cumulative 1223 IJY/�iA,,J Hauled 0 bbis class 11 fluid to Gil j Cumulative 3213 bbis. Daily down hole losses 0 Total metal 369 His. 8/8/2018 Held PJSM with fresh crew, MU 7" shoe track, checked floats, cont PU single in hole with 7" 36# liner. At joint #7, Weatherford casing tongs failed.;RD double stack casing tongs. Replaced with single stack casing tongs. Hung off -side rig tongs for backups. Well flowing at 4 to 5 bph.;PU singled in a total 42 joints 7" 36# liner joints, then switched to T'29# liner. PU singled in to joint #73, our planned CBU depth. Up to this point we were getting pipe displacement plus 1 to 2 bbis over for every 10 joints ran. Last 20 joints started pushing mud away. Top filled on the fly.;Well flowing at 112 bph. At 3104', MU swedge and topdrive. Broke circ at 110 gpm-212 psi, then up to 212 gpm-145 psi. MW out started climbing and maxed out at 13.8 ppg, then tapered off to 11.5 ppg. Ran centrifuge and water to cut mud weight in active system during circ. Max gas 21 units.;Cont PU single in hole with 7" liner joints from 3104' to 5320'. Ran a total 123 full length joints and 4 pup joints. Last two joints in hole are 36# (6.094"ID). MU Baker 7" x 9.63" HRDE ZXHD liner top packer/Flex-Lock liner hanger assembly.;R/D Weatherford casing tools, RIU 4112 pipe handling tools. Remove flow nipple install MPD Bearing. Well flowing 4.7 to 5bbis per hr. Rig up Baker TD cement head and stand back in mast.;RIH w/ 7" liner on 4 112 drill pipe F/ 5320' to 6231' Well flowing at 5bbis per hr. Up Wt. 130k Dn. Wt. 126k Rt. Wt. 118 Torque @ 10 rpm =3870 fl/Ihs 20 rpm = 4010 fVlbs 30 rpm =4240 Nibs taken at 6231'.;Circulate and condition mud at 6231' Mud weight in 11.1 mud weight out 12.8 After B/U Mud weight in 11.1 out 11.4 Max gas 330 units.;Continue RIH with 7" liner F- 6231' to 9397' At 6596 well flow increased to 8.5bbls. per hour . Started holding 400- 540psi back pressure with MPD system. Well flow decreased to 3.7 to 4.7 hr. Work through tight hole at 7595' 45k dawn Wt. and 8053' 35k down weight. Did not pump or rotate.;Hauled 0 bbis of solids to Gil Cumulative 1223 Hauled 0 bbis class II fluid to G/1 Cumulative 3213 bbls. Total metal 369 lbs. 8/9/2018 TIH on 4 1/2" DP with 7" liner. At 9397' we set down hard to 45K, right at slip setting depth. Pulled to 260K with no movement. Shoe in siltstone/claystone. PU (� single off walk and MU topdrive. Broke circ at pump idle, 114 gpm320 psi, still holding 380 psi back pressure with MPD. Worked string a;dozen times with no rotation and broke through on down stroke. TIH on elevators to 10,775' and set down hard to 80K. MU topdrive, broke circ at 114 gpm-329 psi. Pulling to 280K, S/O to 80K. Increased pump rate to 146 gpm-344 psi, then to 201 gpm-185 psi with full open MPD. Seeing pressure spikes;during slack off. Parked string in up a stroke at 280K and CBU. Seeing little to no gain from water influx. Saw 10.3 ppg returns just prior to bottoms up and started overboard returns. MW dropped to j! 8.9 ppg then started climbing. With 10 ppg returns took returns back to active. Pump rate at 220 gpm-;650 psi. Shoe in sandstone/sand. Started working string, pulling to 31 OK, S/O to 80K. String broke loose on down stroke.;TIH on elevators to 10,850' and set down hard. MU topdrive and broke circ, staging pump rate to 224 gpm-547 psi. Pressure building, had to keep working pipe and bumping rotary, like packoff under liner hanger. Cont circ and work string through bottoms up. Had a good amount fins sand and coal chips;at bottoms up and a max of 340 units gas. String broke free on down stroke. TIH on elevators to last stand (#97) MU topdrive, filled pipe, SIO and set down hard 53' off bottom with pump at idle. Increased pump rate to 221 gpm-700 psi working string and rotary (stalling at 18K). CBU with very Iittle;sand or coal on shakers. During slack off pressure spiked quickly like shoe in fight hole. Worked string hard pulling to 320K, S/O to 40K. Worked stand down 30' to 11,350' but it took some doing. Made numerous attempts to work last single down with no luck. Notified Drilling Manager, decision made;to cement liner in place 30' off bottom. Notified Halliburton cementers (on location).;LD top single from stand #97, shoe at 11,350', MU Baker cement head and topdrive. CBU at 222 gpm-969 psi while cementers tied into water tank and MU hardline to rig floor. Water influx at 3.5 bph while circ. Gas holding at 420 units, MW 10.8/vis 40. Held PJSM with rig team/cementem.;Halliburton pumped 3 bbis water to flush lines, then 5 bbis to fill lines. Shut in at Baker cement head and PT lines at 540 psi low 5000 psi high. Good tests. MPD lined up on flowline, well flowing at 3.5 bph, holding no backpressure. Lined up Baker cement head to Halliburton, pumped 35 bbls;12.5 ppg spacer at 3 bpm -400 psi, Baker released 1 st plug followed with 160 bbis (700 sx) 15.3 ppg Class "G" Lead cement at 4 bpm, 292 to 275 psi, with full returns and shut down. Added 34 ppb LCM to cement. Baker released 2nd plug, Halliburton then displaced with 10.8 ppg 6% KCL mud at 5 bpm -183 psi;ICP. Saw both darts latch wiper plugs. With 10 bbis to go, reduced rate to 3 bpm -1600 psi and bumped plugnanding collar at 281 bbls into displacement (calculated at 279 bbis). FCP 1300 psi. Halliburton increased to and held 2800 psi (1500 overfcp) for 1 minute, then increased pressure to 4000 psi;for 1 minute. Bled back 4 bbls to truck and floats held. Slacked off on blocks from 140K to 50K, giving us a good indication hanger was set. CIP at 23:40 on 8- 9-18.;PU 5' to clear dogs from hanger top and had good indication we released liner string. SIO to 30K to set packer with good indication of shear. PU, rotated at 15 rpm, 4600 ftllbs torque, 510 and set down to 20K to ensure weight transfer to set packer. Top of liner hanger at 5,999.70', top of Ianding;collar at 11,217.85'. Closed annular, rig lined up on kill line and pressured up on annulus to 1650 psi and held for 5 minutes. Pressure holding, good indication HRDE ZXHD liner top packer is set. Bled off annulus pressure to 0 psi, and opened annular.;LD Halliburton steel lines. R/D baker TD cement head and stand back MU top drive and pressure up to 500psi pull out running tool from ZXP liner top packer After picking up 2' pressure dropped. Continue circ. as we picked up to 5980'and circ B/U 435gpm 750psi. No indication of cement at shakem.;Pull up to 591 Or drop drill pipe wiper ball and circulate B/U 750psi 435gpm. 5696stks.;Break down Baker TD cement head assembly and lay down. Remove MPD bearing install flow nipple.;POOH F- 5956'to 2716' with ZXP liner packer running tool.;Hauled: 34 bbis of solids to Gil Cumulative: 1284 Hauled 416 bbis class 11 fluid to G/1 8/10/2018 POOH from 2716' with liner run tool. Clean, inspected and LO tool. Broke off CDS 40 pup and XO from Baker cement head and LD same.;Cleaned and cleared rig floor. Cont hauling off mud from pits and top washing shakers and pits.;PU testjnt and run tool, pulled wear ring, set test plug, bled down koomey, opened bottom ram doors, changed lower rams back to 412", buttoned up doors. Removed test int and trip nipple, installed MPD test plug in their MPD head ;With pill pit clean, top off with fresh water. Lined up on rig pump and flushed through mud line, kill line, stack, MPD plumbing and rig choke manifold. Blow down same with air. Strap, OD/ID and number items for scraper run, stage on catwalk.;Pull MPD test plug, install test joint, purge air, test lower rams at 250/3500 psi for 5 minleach. Good test. RD test equipment, pull test plug, install wear ring. Bring in 20 more jnts 4 12" DP to allow reaching top of landing collar.;PJSM, MU 6" roller cone bit, bit sub, XO, MI Swaco 7" multiback combo scraper, XO's, cont TIH with 84 stands 4 1/2" DP, to 5242'. Cont. to clean pits and haul off fluids.;At 5224' P/U & MU Baker 9 5/8 scraper assembly # 1 . Cont. cleaning pits # 4,5,6,9 & 10.;Continue RIH with 7" and 9 5/8 Scraper assembly to 5900' Reduce running speed to enter liner top at 5999'. No issue upon entering liner top , Cont. RIH 5999 -to 8294' Cont . cleaning pits and hauling off fluids.;P/U & M/U 9 5/8 casing scraper assembly # 2 at 8294'. Complete cleaning pits # 4,5,6,9, and 10. Begin loading pits with 1-12o Cont. RIH F- 8294' 11188'.;Hauled: 37 bbls of solids to Gfl Cumulative: 1321 Hauled 1203 bbls class II fluid to GA Cumulative: 4985 bbis. 8/112018 Tagged up at 11,188' with cleanout assembly. Landing collar at 11,217'. Brought circ rate up to 453 gpm-2415 psi and washed down numerous times tagging up then PU off bottom. Made a couple feet of hole, rotated at 10 rpm -8900 to 9300 f llbs and 500 to 1000 on bit, drilled cemenUbarite down to;11,214' and started seeing wiper rubber on shakers. PU off bottom. Up v4185K, dwn wt 134K.;Circulated bottoms up 5' off bottom at 464 gpm-2380 psi, RU test chart for casing test, continue to bring in fresh water for displacement and load pits 45-6-9-10. Shut down pump.;Line up on kill line and ensure fluid packed for casing test. RU test pump on kill line and fluid pack test hoses through manifold in doghouse. PJSM, close upper rams. Run pump #1 up to 3000 psi on kill line and down pump, swap to test pump and pressure up;wellbore to 3500 psi. Test 9 5/8" x 7" casing/liner for 30 minutes on chart. Good test. Bleed off, RD test equipment, line up to resume circ.;Continue circulating 5' off bottom until all dirty trucks back on location and clean water truck full and standing by. Built 30 bbls hi -vis spacer in pill pit. Held PJSM with rig team on freshwater displacement.;Line up on pill pit and pumped 27 bbls hi -vis mud spacer with pump #1, flood pill pit with fresh water and chased 50 strokes, shut down pump. Line up both rig pumps on fresh water pit *4. Start displacement at 300 gpm-1441 ICP. Down pump #2 and cont displacement with pump #1;(wanted to flush #2 with water to clear any mud), FCP 634 psi. Up wt 200K, down wt 140K with water in wellbore. Topped off pill pit with water for hole fill on wiper trip.;Pull up hole from 11,209'to 8358'to upper most 9 5/8" scraper, filling hole every 5 stands with rig pump via kill line. Cont hauling off remaining mud and dirty water, cont bringing in fresh water to pits 4-5-6-9-10 for KCL brine. Mix 6% brine in those same pits.;Cut and slip 110' drill line. Upon removal of drum covers found 4 brake pads missing brass bolts.;Mechanic unpinned upper brake band and replaced 4 bolts in first pad of off -side brake band. Calibrate Pason, MID weight indicator and Block height.;TIH from 8358'to 11,209'. Continue to mix 6% KCL and Pill train in pits for displacement of well.;Displace well bore by pumping 25 bbls Caustic pill,38 bbls Barakleen and 25bbls hi vis sweep followed by 558 bbls 6%KCL at 443 gpm min 1500psi 180stks. While displacing well serviced rig.;Well U -tubing mix and pump KCL dry job ,POH laying down Drill Pipe F-11,109'to 8702' inspecting tool faces and hard banding for wear.;Hauled: 38 bbls of solids to GA Cumulative: 1359 Hauled 802 bbls class II fluid to G/I Cumulative: 5787 bbls 8112120111 POOH LD 4 1/2" DP from 8672' to 5256'. LD upper 9 5/8" scraper and XO's. Had to use rig tongs to make hall the breaks, over torqued pipe. Continued to haul off trash fluid from pits, cleaning pits and hauling off old mud from uprights at skim pit. Strap completion jewelry.;Cont POOH LO 4 12" DP, lower 9 5/8" scraper and XO's, 7" MI multiback combo scraper and 6" bit. Everything in good shape. Still saw over torqued pipe and had to use rig tongs on half the breaks. Rolling over o "Completions" phase in wellez at 1800 hrs. nHilcorp Energy Company Composite Report Well Name: SRF SCU 344-33 (SCU 33-33 ST) Field: Swanson River County/State: Kenai, Alaska (LAT/LONG): rvation (RKB): 18 API #: 50-13320293-01-00 Spud Date: Job Name: 1812067C SCU 344-33 Completion Contractor AFE#: 1812067C AFE $: $669,000 4.'Y 4afe j'„ ,,, Ops Summary 8/12/2018 LD remaining XO's, 7" scraper, and 6" bit. Set seals for racking tubing in yard. Cont pit cleaning and flush Ing .,PU test joint and run tool, remove marring. Pollard a -line on location spotting truck. Haul off last of 4 12" DP, bring in first trailer of 4 1/2" tubing.,Clean and clear rig floor, hang sheave in elevators, MU 7" log tool, RU lower sheave at rig floor. Pollard RIH with log tool. Rack and tally 4 1/2" tubing.,RIH With CBL tools on pollard a -line, Run CBL F-11206 WLM to 5900 WLM . POOH with CBL tools on E Iine.,Rig down Pollard E -Line sheaves and line. Move out.,Rlg up Weatherford 4 1/2 tubing handling tools.,Make up 7" x 4 12 Tri point packer RIH on 4 12 L-80 EZGO HTGT 12.6# Tubing to 300' Drift tubing to 3.833 M/U to 5500 ft/lbs tq. 8/132018 Cont to PU single in hole with 4 1/2" 12.6# EZGO HTGTTGT tubing hydraulic packer assembly from 300'to 3429', Had to lay down jnts #11, 136, 145 anter 149 due to nose seal damage inside couplers. Drift would not fit.,Cont PU single in hole from 3429'to 6525'. No issue entering liner top at 5999'. Had to lay down joints #178, 179,180 and 185 due to nose seal damage inside couplers. Drift would not ft. Cont cleaning pits and loading mud products on trailers.,Cont. Run 4 1/2 EZGO HTGH 12.6# L -80 Tubing F 6525'to 10676' Placing top of packer at 10651.22 WEG at 10676.16 X landing nipple at 327.23',Make up Tubing hanger and landing Jt. orient to well head install 1502 pump in sub on top of landing joint. Circulate corrosion inhibitor and spot on back side. Space out landing J. to set 25k. Down when setting packer. Pressure up on packer to 3800psi at 0600hrs. 8/14/2018 Cont holding 3800 psi on tubing, against rod/ball, to set Tri -Point permanent hydraulic isolation packer, lop set at 10,651.22'. Pressure held solid for 30 minutes. Bled off pressure. S/O landing hanger, then PU 25K over (125K) to verify packer set.,S/O and landed hanger, putting string 25K in compression. PU wt 100K, S/O wt 90K prior to setting packer. Wellhead Rep RILD's and injected packing to energize hanger seals.,With test pump RU on landing joint, pressured up to 4500 psi to test tubing, annulus valve open. Tested at 4500 psi for 30 minutes on chart. Lost 100 psi over 30 minutes, annulus cont to expel small stream of water. Checked all surface equipment, could find no leaks. Tested a second and third time with same results.,Notifled Completions Engineer. Decision made to attempt IA test. Shipped 10 trailer loads of tools and equipment.,RU test pump on IA, and with tubing open to atmosphere pressured up to 2500 psi and held for 30 minutes on chart. Good solid test. Notified Completions Engineer. RU on landing joint with test pump and tested tubing with psi gauge on annulus valve to monitor pressure. At 4500 psi on tubing, annulus is at 400 psi and climbed to 500 psi over 30 minutes.,Bled off tubing (not annulus) and tested Nice more with same results. Lost +/- 50 psi every 15 minutes on tubing, annulus gauge built from 40010 500 psi over 30 minutes, and bled back to 100 psi with tubing bleed off. Noted Completions Engineer, decision made to install BPV and NO BOP stack. Sent MIT form and chart to AOGCC.,Rig crew RD test equipment, LD landing joint. Rig down weatherford tongs and tools. Wellhead Rep installed BPV.,Removed 6" flowline from MPD orbit valve. Folded back beaver slide. Notified Total Safety and Pason Reps for RD in the am. Remove globe valves from MPD head. N/D MPD head and lay down. Remove armored 4" hoses from choke and kill lines. Remove koomy control lines from stack.,Continue N/D BOP. Remove 4 way blocks from choke and kill valves on mud cross. N/D BOP stack from well head and move out to front of sub. Remove spacer spool from top of wellhead.,P/U Dry hole tree NIU to wellhead . Test Hanger void to 250/ 5000 10 min. Pullback pressure valve set two way check, Test tree 250/5000 f 10 min test good.,Clean up and pack tools, subs. Prep for RID &M/O to Beaver Creek Release Rig to Beaver Creek at 0600hrs 8/15/18. 8/30/2018 Sign In. Mobe to location. Rig up lubricator, crystal gauges, tri plex and blow down trailer. PT lubricator to 250 psi low and 3500 psi high.,RIH w/Halliburton ACX tool down to plug at 10663'. Then Halliburton logged by their procedure up to surface keeping 3000 psi as best we could on tubing because of the slow leak. Open IA and let vent into blow down tank. Very little fluid was coming out of IA due to as small leak. Made some stops per procedure at plug and packer and a few slow passes thru packer. Logged at 25' per min all the way out of hole. Checking pup,jts and tubing hanger. Halliburton didn't see much. They told me that their guy in Anchorage will have approx. 95% more data than they can read in field..,Rig down equipment and secure well. 9/11/2018 Sign in, Mobe to location. PTW and JSA. Spot equip and rig up lubricator. PT to 250 psi low and 3500 psi high. TP - 120 psi,RIH w/Halliburton EVO Trieve with CCUGR and DPU (Timer). Set timer on 55 minutes. Correlated log on Halliburton leak detector log. Spotted and set plug at 800'. Lost 70 lbs of line tension when plug set. Picked up 30' and went back down and tagged plug. POOH. Everything,looked ok.,Rig down Halliburton.,Put crystal on both tubing and IA. Tubing had 0 psi on it and IA had 489 psi on it. Bled IA off to tank and left open to tank. Pressured up tubing to 3500 psi. Bled to 3460 psi with no return from IA. Pressured back up to 3540 psi on tubing and .1 on IA. When tubing pressure approx. 3480 psi and IA at 1.6 psi noticed IA started to leak into tank. It was just a dribble of water coming out but was still,coming out as we lost tubing pressure. At 3416 psi it was losing approx. i psi per minute with same amount of fluid coming out of IA. Called town and discussed. Will come back tomorrow, get reading and pull plug. 9/122018 Sign in, Mobe to location. PTW and JSA. Spot equip and rig up lubricator. PT to 250 psi low and 4000 psi high. TP - 3300 psi and small drip in cuttings tank from IA. After Halliburton rigged up and opened well to 3100 psi and pressured up to 3500 psi drip stopped.,RIH w/ACX tool with pressure at 3500. Tagged plug and tool displacement raised TP to 4100 psi with no leak from IA. Ran a lot of passes and stops with pressure from 3400 to 3800 psi on tubing. They logged into lub with 3390 psi. RIH to 26'. Bumped pressure up to 3518 psi for a stop. RIH to 140' pressure rose to 3650 psi and had a few drips come out of IA. Pressure rose to 3680' and drip stopped. That was the,only fluid that came out of IA. Finished stops and logs. They did tag the plug at 800'.,Rig down Halliburton and put crystal gauges back on well with IA closed. Put 3500 psi on tubing and will check pressures in the am. Also will pull plug at 800' 9/13/2018 ARRIVE S.R. MEET W/ BILLY JSA PERMIT DRIVE TO SCU 344J3 Pressure up tubing from 3166 psi to 4036 psi and IAwent from 4.9 psi to 6.9 psi. Tubing dropped 60 psi in an hour and IA gained 0.3 psi. (6.9 psi to 7.2 psi). Bled tubing to 300 psi and IAwent to 2.0 psi. Sent readings to town.,RIG UP SLICKLINE P/T LUB 1500PSI GOOD RIH W/ 2 3/8" GR TO 792' WLM LATCH PLUG SPANG DOWN PRESSURE FELL TO 0 SPANS UP 9/27/2018 Held Pre Spud safety meeting with rig crew, performed orientation,SICP = 0.0 PSI SITP = 0.0 PSI MIRU rig and support equipment and begin rigging up Laid out herculiner Spotted in rig and began rig up,Lunch,Resumed rigging up While standing up the derrick a hydraulic line to tugger winch broke and rig up operation had to be suspended to make repairs Morning safety meeting and JSA review,Continue with rig up and equipment repair 9/28/2018 Break for Iunch,Lunch,Continued with rig up and equipment repair Completed confined space non hazardous permit ci, 0 r Set 2 way check in well head, nippled down tree and nippled up BOPE VVV 9/29/2018 Gathered crew, performed JSA and safety review, discussed daily work plan,Filled BOP stack with test fluid, Made accumulator repairs, ran an hooked up accumulator hoses, complete BOPE nipple up, function tested HCR Valve, Function tested blind rams, function tested pipe rams, function tested annular all function tests complete made up test joint in preparation of BOPE test 'n/✓,', connected kill and choke lines L!/J inspected and prepped equipment for morning BOP testwith AOGCC,Performed general house keeping, check all engine fluid levels and topped off fuel Secured well head and location and released crew for the night 9/30/2018 ,Prep equipment and location for BOPE pressure test,Due to equipment related problems, we were unable to perform the pressure test on the BOP stack and chart the results,Perform equipment maintenance and equipment function tests in preparation for BOP She] Test and BOP Pre test,Performed BOP Shell lest and pre witness BOP Pressure Test, crew was able to identify several small leaks that would have caused test failure, but repaired those leaks. Crew was able to get pre BOP Pressure test to pass after leaks were repaired F,, nment , ready for ROP Witne,, test and wil I be performed on 10/2/2018 102/2018 ,Service, start and prep equipment to perform BOP Test,Perform rig and support equipment maintenance 10/3/2018 Gathered crew, reviewed JSA, Discussed daily work plan and associated hazards, discussed mitigation practices for those hazards,Sta I equipment, Rig Ounction test, all up and function test chart recorder, prep test pump and BOP stack for testing,Along with AOGCC Inspector, began BOP PressuPTWIS2 tests passed with minimal delay Found and fixed 2 small leaks, 1 H2S sensor failed but was replaced on site, test pump blew fuses mid way through test procesred and testing resumed once testing was finished corrective actions for minor deficiencies were corrected,pulled back pressure valve from hanger, no noted pressure present, well in a static state, make up landing joint to unland tubing string, back out lock down pins,Cleared rig floor and prepare to un land hanger, pulled up weight of 107,OOO,Picked up to calculated neutral weight 117,000, rotated tubing 14 turns to the right, slacked off on weight and was given back 1.5 turns, picked up to 130,000 and stopped did not get weight back while holding static, slacked off to 125,000 and rotated 6 turns to the right, tubing string gave weight back to 117,000 calculated neutral weight,Pulled hanger above the floor and laid down, pulled all landing joint components, laid down i pup joint from string Threads were galled and appeared to have been over torqued pipe dope was present and looked good no signs of dehydration, Installed TIW valve, closed 10/4/2018 Gathered crew, reviewed JSA, discussed with crew [he possible pinch and crush points while handling tubulars, discussed good communications and hazard assessment and mitigaflon,Start all equipment and set up work area to begin POCH w"th tuhinn POOH with tuh'nn insoertinn and marking every joint, every 20th joint attempted to torque up tubing with an average of 2500 PSI to initiate rotation, but same connection took 5500 PSI to initiate rotation, average torque to break connections was +/- 5200 PSI, Anomalies found were galled threads, Unable to visually locate the diamonds on threads, but the rain was at times very heavy and difficult to keep things dry,Pulled a total of 110 Joints laying all down, Shut down, install FSV and close, closed pipe rams, closed all valves, insured that the well and location were secure, serviced rig and support equipment in preparation for next days activities of resuming operations 10/512018 Reviewed procedure, discussed hazards associated with daily activities and their mitigations, reviewed JSA and discussed job assignments,Resume POOH and evaluate connections during break out, continued to mark tubing engagement at collar, every 20th joint attempted to torque up connection to determine torque required to initiate rotation continued POOH and laying down until noon,Break for lunch and review notes from morning activities,Resumed POOH with tubing, inspecting and evaluating while POOH, pulled and laid down a total of 151 joints today found 10 ioints with galled threads and found 8 joints that were under torqued. We were only checking torque make up on every 20th joint at start of process, but after a total combined joint count of 180 out we started to check torque make up every I Oth joint.,Out of the 13 joints torque make up was evaluated on the average was 3046 ft/lbs, one connection was taken to just under max torque 6000 flAbs, that joint took 3000ft1Ibs to initiate rotation and 12 tum from start of rotation to 6000 fulbs There is a total of 66 joints left to POOH,Shut down, stab FSV and close, close pipe rams and lock in, closed all valves on BOP stack and well head, serviced rig and support equipment, released crew for the night 10/62018 Reviewed JSA, Discussed Lifting and Line of Fire with picking up tubing string,Start rig and support equipment prepare to start POOH with tubing,Finish POOH with tubing and packer seal assembly, Transfer tubing from pipe racks to pipe bunks on trailers for transport to Tuboscope Kenai.,Transfer new tubing to pipe racks, tally and drift 1 row, make up BHA and prepare to start RIH with BHA and new tubing string,RIH with BHA and new tubing string, ran 37 joints (1138') shut down RIH and service equipment,Transfer tubing to pipe racks, tally and drift tubing, service and fuel rig and support equipment prepare for 10/7/2018 Reviewed JSA, discussed daily work plan and associated risks and mitigaflons,Start rig and support equipment prepare to RIH with production tubing,Start RIH with joint number 38, Continue RIH until time to strap row of tubing, strap 60 joints of tubing, break for Iunch,Finish lunch and prepare equipment to resume RIH,Resume RIH until time to strap row of tubing,Strap row tubing,Resume RIH ran a total of 116 Joints of tubing for a total of 153 joints, currently sifting at 4694',Stab FSV and close, close pipe rams, secure well and location, fuel and service equipment, fill tubing racks and strap, ready to begin RIH in morrina I 10/8/2018 Reviewed JSA, discussed daily work plan, reviewed hazards and mifigations,Start rig and support equipment, prepare to begin RIH with production staring,RIH with production tubing, had brake cooling issues, shut down to investigate,Draw works brakes were not cooling properly, shut down to investigate and found that there was freezing issues in a valve coming off the brake cooling water tank, thawed and added non freeze coolant to the brake cooling tank, Resumed RIH with production tubing,Tally full rack of tubing, break for Iunch,Lunch,Commission mud pump, found that liner washicoolant pump was not functioning, order necessary equipment and prepared to resume RIH with production tubing,RIH with production tubing, Ran a total of 107 Joints for an overall total of 260 Joints in hole. +1- 50 joints left to run.,Shut down, stab FSV, close pipe rams, secure well and location, service and fuel rig and support 10/9/2018 Reviewed JSA, Discussed daily work plan, completed permits,Starl equipment and prepare to begin RIH with tubing,Finish RIH with final full joints and X- Nipple until reaching Landing depth,Along with Tri Point Packer Hand, discussed and reviewed Tubing Tallies and Packer Depth, After careful review of measurements it was agreed on number of pup joints and placement to be able to reach landing depth and be able to set the Retch Latch packer in place„Proceeded to RIH to just above the Retch Latch seal bore assembly in order to be lined up and ready to pump our packer fluid down the back side, upon running into to desired depth, we stacked out early, approximately 13.6' early, picked back up but were latched in to the packer, we had to rotate the desired 11 turns to get released from the packer.,After marking the tubing joint at the top of the slips and knowing the depth of our hanger bowl, we laid the joint that we were RIH down to get to desired depth, we measured that joint from the mark made at slips to end and after reviewing the depths it was determined we were 13.8' off. That joint was laid down and pup joints were picked up to get us to the desired landing depth,After carefully reviewing all measurements it was felt that we would be 8' shy, so the string was picked up and additional pup joints were added, we reviewed all tallies and measurements and compare them to the known hanger depth and the known tag depth. It was determined that there is an +/- 8' discrepancy between original tubing tally and the current tubing tally,Once the team was all in agreement on depths and measurements, our Packer Fluid pill was pumped down the back side, we then switched to clean fluid and proceeded to RIH, we saw pressure increase at the precise measured mark on tubing that was discussed prior to RIH, pumping was shut down and we proceeded to RIH„Tubing was set down into the hanger bowl and string was slacked off, we then picked string weight up to 130,000, 13,000 over the buoyed weight of string to insure we were latched into the seal bore assembly, prior to setting into hanger bowl and seal bore assembly, we then set back down to neutral weight and we picked up the prescribed 2' in order to set hanger and tubing into 25,000 lbs. compression, landed tubing,Lock down pins, inject packing and test seal, shut down equipment, secured well and location and released crews 10/10/2018 Reviewed JSA, Discussed Daily Job Plan, reviewed hazards and mitigations,lnspect and start equipment, prepare for daily activities, Rig up pressure test equipment and prepare for Production Tubing pressure test, Perform Production Tubing pressure test, 250 PSI Low for 5 minutes, 4500 PSI High for 30 ri(\ minutes, had 2 different leaks on hammer unions that were repaired, on 3rd attempt to go to the high test, pressure held and test was successful. Test started \ at 4675 PSI and Ended at 4640 PSI,Prepare equipment to perform Tubing/Casing Annulus Pressure test at 2500 PSI, purge system of air and bring pressure up to 1000 PSI to check for leaks before going to the high test,Crew break for lunch, Prep equipment to go to high pressure test on the Tubing/Casing Annulus. Bring pressure on Tubing/Casing Annulus up to 2600 PSI, Hold for 30 minutes. Test was successful,Set 2 way check in tubing hanger, Nipple \� Down BOP Stack, Nipple up production Tree, start working on testing the tubing hanger void, shutdown equipment, secure well and location, release crews for the ni,ht 10/11/2018 Review JSA, Discuss daily work plan and hazards associated with job tasks,Start all equipment and prepare for the days operations,Finish NU of well head, prepare pressure testing equipment to pressure test well head,Pressure testwell head, 250 PSI Lowfor 5 minutes, 5000 PSI for 30 minutes, started bring pressure up on high test and had a needle valve leaking. fixed leak, brought pressure back up and found a leaking hammer union, repaired leak, brought pressure up and found a flange on well head leaking, repaired leak, brought pressure up to 5200 PSI, pressure stabilized at 5100 PSI, Test passed-Rig down rig and support equipment, start moving off of location, insured all equipment was clear of well head and surrounding area so that construction can I h.oin rk t. make connect ons with flow I nos 10/12/2018 ON LOCATION -TGSM- JSA -PERMIT,MOB TO LOCATION -RIG UP WIL -PT LUB 2500 PSI -GOOD RIH W12” JDC W/ 3.55” BELL GUIDE TO 10,669'KB WT LATCH - SPANGS LICKS - COME FREE, 200 PSI PRESSURE INCREASE - POOH - OOH W/ NO PRONG,RIH W/ SAME TO 10,669'KB WT LATCH PRONG POOH - OOH W/ PRONG RIH W/ 4" GS TO 10,673'KB WT (1300 LBS OIL JAR LICK) COME FREE POOH - HANG UPAT 320'KB WT (HAND SPANG) FOR 10 MINS - BEGIN OIL JAR LICKS 10 AT 1200 LBS - SHEAR OFF - POOH OOH W/ SHEARED GS,SUP CUT WIRE - TIE NEW ROPE SOCKET- STANDBY FOR TOOLS TOOLS ARRIVE - MAKE UP RS ACCELERATOR JARS 2.25"X 8' STEM OJ SJ RIH 4" GS TO 3201KB WT 20 X 1700 LBS OIL JAR LICKS - NO MOVEMENT - SHEAR OFF - POOH RIG DOWN .125" WIRE -PREP FORAM RIG UP OF .160 WIRE. TIE ROPE SOCKET- STAGE SHEAVES SECURE WELL- MOB TO OFFICE TO SIGN OUT- MOB TO PLANT TO CLOSE OUT PERMIT 10/1312018 ON LOCATION - TGSM -JSA- PERMIT RIG UP .160 WIRE - PT LUB 2500 PSI - GOOD RIH W/4" PR TO 320'KB WT LATCH - RHCP - WT OIL JAR LICKS - STARTING AT 1800 LBS AND WORKING UP TO 3000LBS - COME FREE ON LICK # 16 - POOH - OOH W/ PLUG - PACKING DAMAGED 10/141C2018 Sign In. Mobe to location. Rig up lubricator. PT lubricator to 250 psi low and 3500 psi high. TP - 0 psi,RIH w/2-718"x15' HC Max Force. 6 spf. 60 deg phase and fie into logs sent from town. Run correlation log and send to town. Get ok to perf from 10.978'to 10,993' with 0 psi on tubing. Tubing full of fluid. Spotted shot and perted with 0 psi. Heard fluid that sound like it was going down hole. Had 0 psi on tubing all the way out of hole and well had a vacuum on it when we pulled tools from well.,Rig down equipment, tum well over to field and move to SCU 41B-04 to start the PLT tomorrow. Halliburton figures it will take between 10 and 12 hus to run the PLT's 10/15/2018 PTW and JSA. Spot equip and rig up lubricator. PT to 250 psi low and 4000 psi high. TP — 3200 psi,RIH w/GPT tool and to into pert log. Found FL at 3732'. Went on down to 10,993' (Bottom Pert) and BHP was 6592 psi. Send log to town. Pulled up to 3650' with GPT. Bled TP down to 64 psi and re-checked FL which showed FL at 3714'. Fluid came up hole 18'. POOH,RIH w/2-7/8N15' Razor HC, 6 spf, 60 deg phase and tied into pert log dated 10-14-18. Ran correlation log and send to town. Get ok to pert. S otted shot from 10,978 to 10,993'w th 64 psi on well. Attempted to fire gun but gun didn't go off. Going to pull out of hole and dog it off until 8 am in the morning. Foun broken wire on detonator.,Rig for standby and secure well. Trouble shoot gun at their shop. TP 10/16/2018 PTW and JSA. Rig up lubricator. PT to 250 psi low and 4000 psi high. TP — 58 psi,RIH w/2-7/8"x15' HC, 6 spf, 60 deg phase to 2000'. Decision was made to run 3-318" big hole gun after finding out they had them in stock. POOH. Wait on getting gun to be built and brought out.,RIH w/3-3/8"x15' HC Razor Big Hole charge (.53 entrance hole, 47" penetration and 3.56" swell). 6 spf, 60 deg phase and tie into yesterday pert correlation log. Run correlation log and send to town. Get ok to pert. Spotted and fired gun with 58 psi on tubing. Lost 60 Ib line tension when fired and did not lose any pressure. Tools were weighing 200 Ibs heavier coming out of hole. I cracked needle valve on lubrication and,blew gas out. No Vac. Going in hole it looked like we splashed down on Fluid level at 3700'. Coming out of hole showed the same depth. Will be going back in with GPT tool, find fluid level and BHP. Also stay above perf while trying to inject. Fired gun at 1551 hrs.,RIH w/GPT tool and tie into pert log. Found fluid level at 3762". BHP - 3162 with tubing pressure at 56 psi. Pulled GPT tool right above Paris at 10947'. Field starting injecting gas and pressure kept building to 3200 psi and static out. With well static tubing pressure was 3200 psi BHP was 6467 psi and found fluid level at 4100'. When E-line got between 250' and 300'the well pressure overcame the tool weight and shot,150' of wireline out the top of the lubricator. Spooled up 150' of line which left approx. 115' of line in hole and lubricator. Called town and discussed. Decision was made to wait unfit morning and get manlift and have tank brought over to location to blow down well. Will close wireline valve and also leave a Pollard hand out on location. Checked swab valve and line was across ii-Close rams on wireline and secure well. 10/17/2018 PTW and JSA. TP 3144 psi. Field blew well down from 3144 psi to 0 psi back thru system.,Lubricator had some pressure above wireline valves. Blew pressure off. Unscrew bowen connection under wireline rams and picked up 5' and pullded wireline and tools out of hole by hand. Tools and lined weighed about 160 Iles and when we got tools above bottom master we closed master. Cut wire and pulled tools out of well. Tools looked ok. wire was balled up and stranded between grease tube and pack-off.,Rig rest of equipment down and secure well. Turn well back over to field. TP - 0 psi. Will be running a Halliburton PLT log on SCU 4413-33 tomorrow. 10/18/2018 PTW and JSA. Spot equipment. PT lubricator to 250 psi low and 3000 psi high. TP - 0 psi,RIH with 2.25"x5' DD bailer and tag at 11,203' KB. Get sample and POOH. Out of hale with bailer full of 13.9 drilling mud.,RIH with 3.6T' GR and found Fluid level at 4739' KB. POOH,Working on fluid sampler. Fix sampler. RIH with sampler down to 10,985'. Wait on timer. POOH. Get sample,Rig down Slickline.,Fill hot oil truck with 30 bbls of Xylene. Cruz Vac Truck mixing up 11 sacks of KCL and 65 bbls of fresh water. Rig up hot oil truck to wing. Pressure test 250/4500 psi. Good PT.,Initial WHP 0 psi. Well on Vac. Online with Xylene down tubing at 1.5 bbls/min 295 psi. Slick line found fluid level at 4739'. 72 bbls of void. Pumped 29.4 bbls of Xylene. Swapped to Vac Truck with 3% KCL. Pump tripped at 72 bbls away. Caught fluid level. Continue pumping at 1.4 bbls/min with 3 % KCL 2780 psi looked light slight break over. We are injecting. At 1.4 bbls/min pressure climbed to 2980 psi.,lncrease rate to 1.9 bbls/min to increase wellhead pressure to 3400 psi. Shut down and watch wellhead pressure drop. 82.5 bbls pumped. Continue pumping 3 % KCL 92.6 bbls pumped out of fluid. Mix up another i i sacks of KCL and fill with 65 bbls of fresh water.,Wait for Vac truck watch WHP.,While down on pump and well shut in we waited on vac truck to mix and fill. After one hour SITP went from 2980 psi to 0 psi. Online 2.7 bbis/min 3500 psi and climbing. Pressure stayed around 3750-3893 psi at 2.6 bbls/min for 65 bbls. Shutdown. Close in wing. 3800 psi SITP. Total fluid pumped 162.7 bbls Xylene is at the perfs.,Call pad operator to turn on gas injection. Close all high and low pressure valves on pump truck. Truck remains rigged up to wing. Data acquisition still installed on tree cap. Location secure. SDFN. Awaiting results of gas injection test to determine plan forward. 10/302018 PTW and JSA. Rig up lubricator. PT to 250 psi low and 4000 psi high. TP — 3297 psi,Shut well in. Test camera before and after putting on line. Run camera (While waiting on 4-1/2" wireline brush) to 328'. Record numerous places on the X nipple trying to find bad spots. couldn't really pin much down with what we saw. Ran on in hole and hit fluid at 10,591' (All depths are per schematic). Lens on camera went black due to grease or oil so we couldn't look at the X nipple at 10,666'. POOH. TP was 2000 psi.,Cleaned camera and filled lubricator up with 10 gals of diesel with 4-12" wire line brush to brush the x nipple at 328'. The diesel trailer was being used for dirty diesel and crude so we couldn't pump any diesel. RIH to 328' and brushed x nipple. We then pumped approx. 20 gals of methanol and it cleaned the diesel off the lens on the camera. Made numerous runs thru X nipple but still wuldn't verify much that was,wrong. Called town and discussed. POOH and turn well over to field. The field will bring well back on and we will be back out here at 8 am with 15' gun to perforate. 10/312018 PTW and JSA. Rig up lubricator. Arm gun. PT to 250 psi low and 4000 psi high.,RIH w/2 -7/8"x15' HC Razor. 6 spf,. 60 deg phase and tie Perf log. Run correlation log and send to town.Get ok to pert from 10,993'to 11.008'. Spot and fire gun with 2015 psi on tubing. After 5 min - 2014 psi, 10 min - 2012 psi and 15 min - 2010 psi. POO is was tren in9 on Scada). Out of hole and all shots fired. Gun was went. TP 1992 psi.,Rig down lubricator and equipment. Turn well over to field and they were aoing to brina well on. 11/5/2018 ARRIVE @ SR JSA/TGSM RIG UP PIT 3500PSI,RIH W13.80 SWEG TO 337KB WIT STICK POOH (showed a half ring mark on swedge that mic between 3.77" and 3.78" like a over torque collar on bottom of X nipple) RIH W/3.71 SWEG TO 3500KB NO TAG POOH (No problem) RIH W/3.64 INJECTION VALVE TO 337KB WIT SET POOH. Packing ring has a 3.79" OD on valve. Valve had been machined down on the NO GO and r the XO that basically is a NO GO from 3.805" to 3.65",RI W/4 1/2 CHECK SET TO 337KB W/T POOH CHECK PIN SHEADED CAP WELL J TEST VALVE GOOD Rig down,NOTE: 1. 3.80" Swedge showed a half ring mark on side of swedge that mic between 3.77" and 3.78" like a over torque collar on bottom of X nipple. 2. Packing has 3.79" OD Valve had been down NO GO XO basically is GO G7 ring a on valve. machined on the and the that a NO from 3.805" to 3.65". 3. The ID of the XO nipple will not allow an injection valve to be run and set in,the bottom X nipple. Bottom X nipple is Tri -Point 4. Also look at Pollard WSR dated 10-12-18 and 10-13-18 5. The new injection valve (Bean type) is stored at Pollard Slickline shop. Hilcorp Alaska, LLC Soldotna CK Unit SCU 33-33 SCU 344-33 501332029301 Sperry Drilling Definitive Survey Report 09 August, 2018 HALLIBURTON 5porry Drilling Halliburton Definitive Survey Report Company: Hiloorp Alaska, LLC Local Co-ordinate Reference: Well SCU 33-33 Project: Soldolna CK Unit TVD Reference: SCU 344-33 WP05 RKB @ 143.50usft (HEC 169) Site: SCU 33-33 MD Reference: SCU 344-33 WP05 RKB @ 143.50usft (HEC 169) Well: SCU 33-33 North Reference: True - Wellborn: SCU 344-33 Survey Calculation Method: Minimum Curvature Design: SCU 344-33 Database: Sperry EDM - NORTH US + CANADA -roject Soldotna CK Unit, Swanson River Field Nap System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Seo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Nap Zone: Alaska Zone 04 Using geodetic scale factor Well SCU 33-33 Well Position +N/.S +E/ -W Position Uncertainty 0.00 usft Northing: 2,462,644.03 usfi Latitude: 60" 44' 16.401 N 0.00 usft Easting: 345,991.06 usfi Longitude: 150° 51'38.008 W 0.00 usft Wellhead Elevation: 125.50 usfi Ground Level: 125.50 usft Wellbore SCU 344-33 Magnetics Model Name BGGM2017 Design SCU 344-33 Audit Notes: Version: 1.0 Vertical Section: Sample Date Declination Dip Angle (1) (1) 4/19/2018 15.81 Phase: ACTUAL Depth From (TVD) +N/S (usft) (usft) 18.00 0.00 Field Strength (nT) 73.71 55,389 Tie On Depth: 6,190.50 +EI•W Direction (usft) (1) 0.00 146.77 Survey Program Date 8/7/2018 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 90.50 6,190.50 Sperry Surwel Gyro SU3-16127 (SCU 332_CB-Film-GMS A022Ga: Film camera gyro multi -shot 10/25/1976 6,259.00 6,259.00 SCU 344-33 Gyrodata Rate Gyro Survey 2_Gyro-NS-GC_Drill coil: H029Ga: North seeking single shot in drill colla O6124/2018 6,320.54 6,419.35 SCU 344-33 MWD+InterpAZl+sag (SCU 2_MWD_Interp Azi+Sag H003Mb: Interpolated azimuth +sag correction 06/24/2018 6,485.17 11,341.20 SCU 344-33 MWD+IFRI+MS+sag (SCU 2_MWD+IFRI+MS+Sag A010M6: IFR dec & multi -station analysis +sal 07/23/2018 Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +E/•W Northing Easting OLS Section (usft) (I (I (usft) (usft) (usft) (usft) (ft) (ft) V11001) (ft) Survey Tool Name IB.00 0.00 0.00 18.00 -125.50 0.00 0.00 2,462,644.03 345,991.06 0.00 0.00 UNDEFINED 90.50 0.60 122.50 90.50 -53.00 -0.20 0.32 2,462,643.82 345,991.38 0.83 0.35 2_C13-Film-GMS(1) 190.50 0.47 129.83 190.49 46.99 -0.75 1.08 2,462,643.27 345,992.13 0.15 1.22 2_CB.Film-GMS(1) 290.50 0.40 134.01 290.49 146.99 -1.25 1.64 2,462,642.76 345,992.69 0.08 1.95 2_CB-Film-GMS(1) 390.50 0.40 140.30 390.49 246.99 -1.76 2.12 2,462,642.24 345,993.15 0.04 2.64 2 -CB -Film -GMS (1) 490.50 0.37 144.50 490.49 346.99 -2.30 2.53 2,462,641.70 345,993.56 0.04 3.31 2_CB-Film-GMS(1) 590.50 0.43 136.71 590.48 446.98 -2.83 2.97 2,462,641.16 345,993.99 0.08 4.00 2_CB-Film-GMS(1) 690.50 0.42 133.66 690.48 546.98 -3.36 3.49 2,462,640.63 345,994.51 0.02 4.72 2 -CB -Film -GMS (1) 790.50 0.60 134.86 790.48 646.98 -3.98 4.13 2,462,640.00 345,995.14 0.18 5.59 2 -CB -Film -GMS (1) 890.50 0.62 150.15 890.47 746.97 4.82 4.77 2,462,639.15 345,995.77 0.16 6.65 2_CB-Film-GMS(1) 990.50 0.65 152.64 990.47 846.97 -5.79 5.30 2,462,638.17 345,996.28 0.04 7.75 2 -CB -Film -GMS (1) 89/2018 12:48:30PM Page 2 COMPASS 5000.1 Build 81E Company: Project: Site: Well: Wellbore: Design: Survey 4,990.50 1.23 318.87 4,990.05 4,846.55 -21.18 -25.32 2,462,623.18 345,965.47 0.20 Vertical Section (ft) Survey Tool Name 8.92 2_CB-Film-GMS(1) 10.13 2_CB-Film-GMS(1) 11.26 2 -CB -Film -GMS (1) 12.33 2_CB-Film-GMS(1) 13.44 2_CB-Film-GMS(1) 14.55 2_CB-Film-GMS(1) 15.56 2 -CB -Film -GMS (1) 16.51 2_CB-Film-GMS (1) 17.45 2_CB-Film-GMS(1) 18.19 2 -CB -Film -GMS (1) 18.74 2 -CB -Film -GMS (1) 19.28 2_CB-Film-GMS(1) 19.70 2_CB-Film-GMS(1) 20.08 2_CB-Film-GMS(1) 20.54 2_CB-Film-GMS(1) 21.03 2_CB-Film-GMS(1) 21.50 2 -CB -Flim -GMS (1) 22.03 2_CB-Film-GMS(1) 22.60 2 -CB -Film -GMS (1) 23.06 2_CB-Film-GMS(1) 23.36 2_CB-Film-GMS(1) 23.52 2 -CB -Film -GMS (1) 23.64 2 -CB -Film -GMS (1) 23.74 2_CS-Film-GM8(1) 23.96 2_CB-Film-GMS(1) 24.19 2_CB-Film-GMS(1) 24.11 2_CB-Film-GMS (1) 23.65 2_CB-Film-GMS(1) 22.83 2_CB-Film-GMS(1) 21.78 2_CB-Film-GMS(1) 20.66 2_CB-Film-GMS(1) 19.34 2_CB-Film-GMS(1) 17.73 2_CB-Film-GMS(1) 15.91 2_CB-Film-GMS (1) 14.01 2 -CB -Film -GMS (1) 11.99 2 -CB -Film -GMS (1) 9.83 2_CB-Film-GMS(1) 7.81 2_CB-Film-GMS (1) 5.87 2 -CB -Film -GMS (1) 3.84 2_CB-Film-GMS (1) 8/92018 12:48:30PM Page 3 COMPASS 5000.1 Build 81E Halliburton Definitive Survey Report Hiloorp Alaska, LLC Local Co-ordinate Reference: Well SCU 33-33 Soldotna CK Unit TVD Reference: SCU 344-33 WP05 RKB @ 143.50usft (HEC 169) SCU 33-33 MD Reference: SCU 344-33 WP05 RKB @ 143.50usft (HEC 169) SCU 33-33 North Reference: True SCU 344-33 Survey Calculation Method: Minimum Curvature SCU 344-33 Database: Sperry EDM - NORTH US + CANADA (usft) (usft) 4,990.50 1.23 318.87 4,990.05 4,846.55 -21.18 -25.32 2,462,623.18 345,965.47 0.20 Vertical Section (ft) Survey Tool Name 8.92 2_CB-Film-GMS(1) 10.13 2_CB-Film-GMS(1) 11.26 2 -CB -Film -GMS (1) 12.33 2_CB-Film-GMS(1) 13.44 2_CB-Film-GMS(1) 14.55 2_CB-Film-GMS(1) 15.56 2 -CB -Film -GMS (1) 16.51 2_CB-Film-GMS (1) 17.45 2_CB-Film-GMS(1) 18.19 2 -CB -Film -GMS (1) 18.74 2 -CB -Film -GMS (1) 19.28 2_CB-Film-GMS(1) 19.70 2_CB-Film-GMS(1) 20.08 2_CB-Film-GMS(1) 20.54 2_CB-Film-GMS(1) 21.03 2_CB-Film-GMS(1) 21.50 2 -CB -Flim -GMS (1) 22.03 2_CB-Film-GMS(1) 22.60 2 -CB -Film -GMS (1) 23.06 2_CB-Film-GMS(1) 23.36 2_CB-Film-GMS(1) 23.52 2 -CB -Film -GMS (1) 23.64 2 -CB -Film -GMS (1) 23.74 2_CS-Film-GM8(1) 23.96 2_CB-Film-GMS(1) 24.19 2_CB-Film-GMS(1) 24.11 2_CB-Film-GMS (1) 23.65 2_CB-Film-GMS(1) 22.83 2_CB-Film-GMS(1) 21.78 2_CB-Film-GMS(1) 20.66 2_CB-Film-GMS(1) 19.34 2_CB-Film-GMS(1) 17.73 2_CB-Film-GMS(1) 15.91 2_CB-Film-GMS (1) 14.01 2 -CB -Film -GMS (1) 11.99 2 -CB -Film -GMS (1) 9.83 2_CB-Film-GMS(1) 7.81 2_CB-Film-GMS (1) 5.87 2 -CB -Film -GMS (1) 3.84 2_CB-Film-GMS (1) 8/92018 12:48:30PM Page 3 COMPASS 5000.1 Build 81E Map Map MD Inc Azi TVD TVDSS +NIS +EI -W Northing Easting OLS (usft) (1) r) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') 1,090.50 0.70 146.44 1,090.46 946.96 -6.80 5.90 2,462,637.15 345,996.87 0.09 1,190.50 0.70 159.52 1,190.45 1,046.95 -7.89 6.45 2,462,636.06 345,997.41 0.16 1,290.50 0.70 175.60 1,290.44 1,146.94 -9.07 6.71 2,462,634.88 345,997.65 0.20 1,390.50 0.68 172.27 1,390.44 1,246.94 -10.26 6.84 2,462,633.68 345,997.76 0.04 1,490.50 0.70 168.74 1,490.43 1,346.93 -11.45 7.04 2,462,632.49 345,997.95 0.05 1,590.50 0.70 173.45 1,590.42 1,446.92 -12.66 7.23 2,462,631.28 345,998.12 0.06 1,690.50 0.72 188.26 1,690.41 1,546.91 -13.89 7.21 2,462,630.05 345,998.08 0.18 1,790.50 0.73 188.42 1,790.41 1,646.91 -15.14 7.02 2,462,628.80 345,997.88 0.01 1,890.50 0.77 193.43 1,890.40 1,746.90 -16.42 6.77 2,462,627.52 345,997.62 0.08 1,990.50 0.78 212.84 1,990.39 1,846.89 -17.65 6.25 2,462,626.30 345,997.08 0.26 2,090.50 0.82 213.90 2,090.38 1,946.88 -18.81 5.48 2,462,625.15 345,996.29 0.04 2,190.50 0.77 213.60 2,190.37 2,046.87 -19.97 4.71 2,462,624.00 345,995.51 0.05 2,290.50 0.73 222.42 2,290.36 2,146.86 -21.00 3.91 2,462,622.99 345,994.69 0.12 2,390.50 0.80 218.94 2,390.35 2,246.85 -22.01 3.04 2,462,621.98 345,993.81 0.08 2,490.50 0.73 213.89 2,490.34 2,346.84 -23.08 2.24 2,462,620.92 345,993.00 0.10 2,590.50 0.60 209.24 2,590.34 2,446.84 -24.07 1.63 2,462,619.95 345,992.38 0.14 2,690.50 0.65 213.20 2,690.33 2,546.83 -25.00 1.07 2,462,619.02 345,991.80 0.07 2,790.50 0.67 204.89 2,790.32 2,646.82 -26.00 0.51 2,462,61802 345,991.23 0.10 2,890.50 0.65 209.65 2,890.32 2,746.82 -27.03 -0.02 2,462,617.01 345,990.69 0.06 2,990.50 0.58 213.49 2,990.31 2,846.81 -27.94 -0.58 2,462,616.10 345,990.12 0.08 3,090.50 0.52 223.91 3,090.31 2,946.81 -28.69 -1.17 2,462,615.36 345,989.51 0.12 3,190.50 0.43 228.16 3,190.30 3,046.80 -29.27 -1.76 2,462,614.79 345,988.91 0.10 3,290.50 0.65 230.20 3,290.30 3,146.80 -29.88 -2.48 2,462,614.19 345,988.19 0.22 3,390.50 0.58 232.30 3,390.29 3,246.79 -30.55 -3.32 2,462,613.52 345,987.34 0.07 3,490.50 0.68 219.57 3,490.29 3,346.79 -31.32 4.09 2,462,612.77 345,986.56 0.17 3,590.50 0.68 231.31 3,590.28 3,446.78 -32.15 3.94 2,462,611.95 345,985.70 0.14 3,690.50 0.70 249.18 3,690.27 3,546.77 -32.74 -5.97 2,462,611.38 345,984.66 0.22 3,790.50 0.77 266.32 3,790.27 3,646.77 -33.00 -7.21 2,462,611.13 345,983.42 0.23 3,890.50 0.92 274.33 3,890.25 3,746.75 32.98 -8.68 2,462,611.17 345,981.95 0.19 3,990.50 0.92 281.50 3,990.24 3,846.74 -32.76 -10.27 2,462,611.41 345,980.36 0.12 4,090.50 0.77 291.70 4,090.23 3,946.73 -32.35 -11.68 2,462,611.84 345,978.96 0.21 4,190.50 1.10 290.55 4,190.22 4,046.72 -31.77 -13.20 2,462,612.44 345,977.44 0.33 4,290.50 1.12 294.81 4,290.20 4,146.70 -31.02 -14.99 2,462,613.21 345,975.67 0.08 4,390.50 1.18 311.67 4,390.18 4,246.66 -29.92 -16.65 2,462,614.33 345,974.02 0.34 4,490.50 1.12 304.42 4,490.16 4,346.66 -28.69 -18.22 2,462,615.59 345,972.47 0.16 4,590.50 1.32 312.34 4,590.14 4,446.64 -27.36 -19.88 2,462,616.94 345,970.83 0.26 4,690.50 1.23 313.76 4,690.11 4,546.61 -25.84 -21.51 2,462,618.48 345,969.22 0.10 4,790.50 1.13 319.84 4,790.09 4,646.59 -24.34 -22.92 2,462,619.99 345,967.83 0.16 4,890.50 1.10 326.45 4,890.07 4,746.57 -22.79 -24.08 2,462,621.56 345,966.68 0.13 4,990.50 1.23 318.87 4,990.05 4,846.55 -21.18 -25.32 2,462,623.18 345,965.47 0.20 Vertical Section (ft) Survey Tool Name 8.92 2_CB-Film-GMS(1) 10.13 2_CB-Film-GMS(1) 11.26 2 -CB -Film -GMS (1) 12.33 2_CB-Film-GMS(1) 13.44 2_CB-Film-GMS(1) 14.55 2_CB-Film-GMS(1) 15.56 2 -CB -Film -GMS (1) 16.51 2_CB-Film-GMS (1) 17.45 2_CB-Film-GMS(1) 18.19 2 -CB -Film -GMS (1) 18.74 2 -CB -Film -GMS (1) 19.28 2_CB-Film-GMS(1) 19.70 2_CB-Film-GMS(1) 20.08 2_CB-Film-GMS(1) 20.54 2_CB-Film-GMS(1) 21.03 2_CB-Film-GMS(1) 21.50 2 -CB -Flim -GMS (1) 22.03 2_CB-Film-GMS(1) 22.60 2 -CB -Film -GMS (1) 23.06 2_CB-Film-GMS(1) 23.36 2_CB-Film-GMS(1) 23.52 2 -CB -Film -GMS (1) 23.64 2 -CB -Film -GMS (1) 23.74 2_CS-Film-GM8(1) 23.96 2_CB-Film-GMS(1) 24.19 2_CB-Film-GMS(1) 24.11 2_CB-Film-GMS (1) 23.65 2_CB-Film-GMS(1) 22.83 2_CB-Film-GMS(1) 21.78 2_CB-Film-GMS(1) 20.66 2_CB-Film-GMS(1) 19.34 2_CB-Film-GMS(1) 17.73 2_CB-Film-GMS(1) 15.91 2_CB-Film-GMS (1) 14.01 2 -CB -Film -GMS (1) 11.99 2 -CB -Film -GMS (1) 9.83 2_CB-Film-GMS(1) 7.81 2_CB-Film-GMS (1) 5.87 2 -CB -Film -GMS (1) 3.84 2_CB-Film-GMS (1) 8/92018 12:48:30PM Page 3 COMPASS 5000.1 Build 81E Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well SCU 33-33 Project: Soldotna CK Unit TVD Reference: SCU 344-33 WPO5 RKB @ 143.50usft (HEC 169) Site: SCU 33-33 MD Reference: SCU 344-33 WPO5 RKB @ 143.50usft (HEC 169) Well: SCU 33-33 North Reference: True Wellbore: SCU 344-33 Survey Calculation Method: Minimum Curvature Design: SCU 344-33 Database: Sperry EDM - NORTH US + CANADA Survey Map Map Vertical MD Inc Azi ND TVDSS +N/ -S +EI -W Northing Easting DLS Section (usft) (°) (I (usft) (usft) (usft) (usft) (ft) (ft) (-/100-) (ft) Survey Tool Name 5,090.50 1.10 329.56 5,090.03 4,946.53 -19.55 -26.51 2,462,624.83 345,964.30 0.25 1.82 2 -CB -Film -GMS (1) 5,190.50 1.17 341.71 5,190.01 5,046.51 -17.75 -27.32 2,462,626.64 345,963.51 0.25 -0.12 2_CB-Film-GMS(1) 5,290.50 1.23 336.32 5,289.99 5,146.49 -15.80 -28.07 2,462,628.60 345,962.79 0.13 -2.17 2_CS-Film-GMS(1) 5,390.50 1.28 347.23 5,389.96 5,246.46 -13.73 -28.75 2,462,630.68 345,962.14 0.24 4.27 2_CB-Film-GMS(1) 5,490.50 1.32 170.12 5,489.96 5,346.46 -13.77 -28.80 2,462,630.64 345,962.09 2.60 4.26 2-CB-Film-GMS(1) 5,590.50 1.42 348.41 5,589.95 5,446.45 -13.69 -28.85 2,462,630.72 345,962.04 2.74 4.36 2 -CB -Film -GMS (1) 5,690.50 1.52 350.26 5,689.91 5,546.41 -11.17 -29.32 2,462,633.25 345,961.60 0.11 -6.72 2_CB-Film-GMS (1) 5,790.50 1.68 0.58 5,789.87 5,646.37 -8.40 -29.53 2,462,636.02 345,961.42 0.33 -9.16 2_CB-Film-GMS(1) 5,890.50 1.78 5.70 5,889.83 5,746.33 -5.39 -29.36 2,462,639.03 345,961.63 0.18 -11.58 2_CB-Film-GMS(1) 5,990.50 2.00 5.60 5,989.77 5,846.27 -2.10 -29.04 2,462,642.31 345,962.00 0.22 -14.15 2-CB-Film-GMS(1) 6,090.50 2.15 4.36 6,089.71 5,946.21 1.50 -28.72 2,462,645.91 345,962.36 0.16 -17.00 2-CB-Film-GMS(1) 6,190.50 1.93 7.40 6,189.65 6,046.15 5.04 -28.37 2,462,649.44 345,962.77 0.25 -19.76 2_CB-Film-GMS(1) 6,259.00 2.94 18.75 6,258.08 6,114.58 7.85 -27.65 2,462,652.24 345,963.52 1.63 -21.72 2_Gym-NS-GC_DHII collar(2 6,320.54 7.79 42.44 6,319.34 6,175.84 12.43 -24.33 2,462,656.77 345,966.90 8.50 -23.73 2_MWD_Interp Azi+Sag(3) 6,359.80 8.28 56.78 6,358.22 6,214.72 15.94 -20.17 2,462,660.23 345,971.11 5.24 -24.38 2_MWD_Interp Azi+Sag(3) 6,419.35 7.88 69.38 6,417.18 6,273.68 19.73 -12.76 2,462,663.92 345,978.56 3.04 -23.49 2_MWD_Interp Azi+Sag(3) 6,485.17 7.46 76.94 6,482.42 6,338.92 22.28 -4.37 2,462,666.36 345,986.98 1.66 -21.03 2_MWD+IFR1+MS+Sag (4) 6,547.96 7.93 95.74 6,544.65 6,401.15 22.77 3.91 2,462,666.74 345,995.27 4.06 -16.90 2 MWD+IFR1+MS+Sag(4) 6,609.76 7.92 105.91 6,605.86 6,462.36 21.17 12.25 2,462,665.04 346,003.58 2.27 -11.00 2_MWD+IFR1+MS+Sag(4) 6,671.75 8.09 123.56 6,667.26 6,523.76 17.59 19.99 2,462,661.36 346,011.28 3.96 -3.76 2 MWD+IFRI+MS+Sag(4) 6,733.68 10.11 134.81 6,728.41 6,584.91 11.35 27.48 2,462,655.02 346,018.68 4.33 5.56 2_MWD+IFRI+MS+Sag(4) 6,795.57 12.17 143.53 6,789.14 6,645.64 2.27 35.21 2,462,645.84 346,026.29 4.29 17.39 2_MWD+IFRI+MS+Sag (4) 6,857.47 14.64 146.93 6,849.35 6,705.85 -9.53 43.36 2,462,633.93 346,034.29 4.19 31.73 2_MWD+IFR1+MS+Sag(4) 6,920.81 16.64 149.84 6,910.34 6,766.84 -24.08 52.28 2,462,619.27 346,043.02 3.39 48.79 2_MWD+IFRI+MS+Sag(4) 6,980.91 17.95 150.89 6,967.72 6,824.22 -39.61 61.11 2,462,603.62 346,051.64 2.24 66.62 2_MWD+IFRI+MS+Sag(4) 7,041.37 20.95 153.99 7,024.72 6,881.22 -57.47 70.39 2,462,585.65 346,060.68 5.25 86.64 2_MWD+IFRI+MS+Sag(4) 7,101.56 22.56 152.87 7,080.63 6,937.13 -77.42 80.37 2,462,565.57 346,070.40 2.76 108.80 2_MWD+IFRI+MS+Sag (4) 7,166.88 24.30 154.26 7,140.56 6,997.06 -100.68 91.92 2,462,542.16 346,081.65 2.79 134.59 2_MWD+IFRI+MS+Sag (4) 7,227.89 27.38 156.14 7,195.46 7,051.96 -124.82 103.05 2,462,517.88 346,092.46 5.22 160.88 2_MWD+IFRI+MS+Sag (4) 7,289.44 30.07 157.02 7,249.43 7,105.93 -151.97 114.80 2,462,490.58 346,103.85 4.42 190.03 2_MWD+IFR1+MS+Sag(4) 7,351.79 32.89 153.25 7,302.61 7,159.11 -181.47 128.52 2,462,460.90 346,117.18 5.51 222.23 2_MWD+IFR1+MS+Sag(4) 7,415.22 34.23 152.26 7,355.46 7,211.96 -212.64 144.58 2,462,429.53 346,132.83 2.28 257.10 2_MWD+IFRI+MS+Sag (4) 7,477.12 33.48 151.42 7,406.87 7,263.37 -243.05 160.85 2,462,398.91 346,148.70 '1.43 291.45 2_MWD+IFRI+MS+Sag (4) 7,538.64 33.20 151.71 7,458.26 7,314.76 -272.78 176.95 2,462,368.98 346,164.41 0.52 325.14 2_MWD+IFRI+MS+Sag (4) 7,601.55 33.03 151.33 7,510.95 7,367.45 -302.99 193.34 2,462,338.56 346,180.40 0.43 359.39 2_MWD+IFR1+MS+Sag(4) 7,663.11 34.35 150.00 7,562.17 7,418.67 -332.75 210.07 2,462,308.58 346,196.74 2.46 393.46 2_MWD+IFRI+MS+Sag(4) 7,725.13 36.13 149.31 7,612.83 7,469.33 -363.63 228.16 2,462,277.47 346,214.41 2.94 429.20 2_MWD+IFR1+MS+Sag(4) 7,786.90 35.64 149.46 7,662.87 7,519.37 -394.79 246.59 2,462,246.07 346,232.44 0.81 465.37 2_MWD+IFR1+MS+Sag(4) 7,848.94 34.95 149.14 7,713.51 7,570.01 -425.61 264.89 2,462,215.01 346,250.34 1.15 501.18 2_MWD+IFRI+MS+Sag (4) 7,910.62 34.35 148.30 7,764.25 7,620.75 -455.58 283.10 2,462,184.81 346,268.15 1.24 536.23 2_MWD+IFR1+MS+Sag (4) 852018 12:48:30PM Page 4 COMPASS 5000.1 Build 81E Company: Hilcorp Alaska, LLC Project: Soldotna CK Unit Site: SCU 33-33 Well: SCU 33-33 Wellbore: SCU 344-33 Design: SCU 344-33 Survey Halliburton Definitive Survey Report Local Co-ordinate Reference: Well SCU 33-33 TVD Reference: SCU 344-33 WPO5 RKB @ 143.50usft (HEC 169) MD Reference: SCU 344-33 WP05 RKB @ 143.50usft (HEC 169) North Reference: True Survey Calculation Method: Minimum Curvature Database: Sperry EDM - NORTH US + CANADA Map MD Inc Azi TVD TVDSS +NI -S +El -W Northing (usft) (1) (1) (usft) (usft) (usft) (usft) (ft) 7,973.12 35.89 147.92 7,815.37 7,671.87 -486.11 302.10 2,462,154.04 8,032.65 36.32 146.84 7,863.47 7,719.97 -515.65 321.01 2,462,124.25 8,097.25 35.83 146.59 7,915.68 7,772.18 -547.45 341.88 2,462,092.18 8,158.93 35.68 146.02 7,965.73 7,822.23 -577.44 361.88 2,462,061.94 8,222.35 35.25 145.66 8,017.39 7,873.89 -607.89 382.54 2,462,031.23 8,284.26 34.85 145.27 8,068.07 7,924.57 -637.18 402.69 2,462,001.68 8,345.70 34.16 145.39 8,118.70 7,975.20 -665.80 422.49 2,461,972.80 8,405.35 33.85 144.73 8,168.15 8,024.65 -693.15 441.60 2,461,945.21 8,469.57 33.36 144.16 8,221.64 8,078.14 -722.07 462.26 2,461,916.02 8,529.41 32.96 143.94 8,271.73 8,128.23 -748.56 481.48 2,461,889.28 8,590.30 32.26 144.81 8,323.02 8,179.52 -775.23 500.59 2,461,862.36 8,654.00 32.44 143.39 8,376.84 8,233.34 -802.84 520.58 2,461,834.49 8,717.25 31.82 142.16 8,430.40 8,286.90 -829.63 540.93 2,461,807.45 8,779.77 31.45 142.22 8,483.63 8,340.13 -855.54 561.03 2,461,781.28 8,841.43 30.96 142.88 8,536.37 8,392.87 -880.90 580.46 2,461,755.67 8,902.91 30.48 142.08 8,589.22 8,445.72 -905.81 599.58 2,461,730.51 8,965.55 30.30 141.05 8,643.26 8,499.76 -930.63 619.28 2,461,705.44 9,027.56 29.73 143.24 8,696.95 8,553.45 -955.11 638.32 2,461,680.71 9,085.42 30.24 145.59 8,747.07 8,603.57 -978.63 655.14 2,461,656.97 9,147.38 30.09 145.67 8,800.64 8,657.14 -1,004.33 672.71 2,461,631.05 9,208.50 29.65 146.46 8,853.64 8,710.14 -1,029.58 689.71 2,461,605.58 9,272.57 29.19 145.88 8,909.45 8,765.95 -1,055.72 707.23 2,461,579.21 9,333.29 29.72 148.00 8,962.32 8,818.82 -1,080.75 723.51 2,461,553.98 9,394.91 29.28 147.58 9,015.95 8,872.45 -1,106.42 739.68 2,461,528.09 9,456.22 29.08 147.98 9,069.48 8,925.98 -1,131.71 755.62 2,461,502.60 9,519.42 29.07 147.95 9,124.72 8,981.22 -1,157.74 771.91 2,461,476.36 9,581.73 28.94 147.36 9,179.21 9,035.71 -1,183.27 788.07 2,461,450.62 9,643.53 28.74 146.28 9,233.35 9,089.85 -1,208.22 804.39 2,461,425.46 9,705.03 28.61 145.77 9,287.30 9,143.80 -1,232.69 820.88 2,461,400.78 9,768.89 28.20 146.56 9,343.48 9,199.98 -1,257.92 837.79 2,461,375.33 9,830.66 27.82 147.04 9,398.01 9,254.51 -1,282.20 853.68 2,461,350.85 9,892.59 28.66 148.09 9,452.57 9,309.07 -1,306.93 869.39 2,461,325.92 9,955.20 29.29 149.21 9,507.34 9,363.84 -1,332.83 885.17 2,461,299.81 10,018.11 28.80 149.16 9,562.34 9,418.84 -1,359.06 900.81 2,461,273.38 10,079.59 29.12 149.24 9,616.13 9,472.63 -1,384.63 916.06 2,461,247.62 10,142.04 28.83 148.83 9,670.77 9,527.27 -1,410.57 931.62 2,461,221.47 10,204.29 26.68 146.85 9,725.85 9,582.35 -1,435.12 947.03 2,461,196.73 10,265.35 24.52 145.72 9,780.91 9,637.41 -1,457.07 961.67 2,461,174.59 10,327.91 22.77 146.97 9,838.22 9,694.72 -1,477.95 975.58 2,461,153.54 10,390.18 20.97 147.47 9,896.01 9,752.51 -1,497.45 988.14 2,461,133.88 Map Vertical Easting DLS Section (ft) (°1100') (ft) Survey Tool Name 346,286.74 2.49 572.17 2_MWD+IFRI+MS+Sag(4) 346,305.26 1.29 607.25 2_MWD+IFRI+MS+Sag (4) 346,325.72 0.79 645.29 2_MWD+IFRI+MS+Sa9(4) 346,345.31 0.59 681.32 2_MWD+IFRI+M8+8ag(4) 346,365.57 0.75 718.12 2_MWD+IFRI+MS+Sag (4) 346,385.34 0.74 753.66 2_MWD+IFRI+MS+Sag(4) 346,404.76 1.13 788.45 2_MWD+IFRI+MS+Sag(4) 346,423.51 0.81 821.80 2_MWD+IFRI+MS+Sag(4) 346,443.79 0.91 857.31 2_MWD+IFRI+MS+Sag (4) 346,462.66 0.70 890.01 2_MWD+IFRI+MS+Sag(4) 346,481.42 1.38 922.79 2_MWD+IFRI+MS+Sag(4) 346,501.04 1.23 956.84 2_MWD+IFRI+MS+Sag(4) 346,521.03 1.42 990.39 2_MWD+IFRI+MS+Sag (4) 346,540.79 0.59 1,023.08 2_MWD+IFRI+MS+Sag(4) 346,559.88 0.97 1,054.94 2_MWD+IFRI+MS+Sag (4) 346,578.68 1.03 1,086.26 2_MWD+IFRI+MS+Sag(4) 346,598.05 0.88 1,117.82 2_MWD+IFRI+MS+Sag(4) 346,616.76 1.99 1,148.73 2_MWD+IFRI+MS+Sag(4) 346,633.27 2.21 1,177.62 2_MWD+IFRI+MS+Sag (4) 346,650.51 0.25 1,208.74 2_MWD+IFRI+MS+Sag(4) 346,667.17 0.97 1,239.18 2_MWD+IFRI+MS+Sag(4) 346,684.34 0.84 1,270.65 2_MWD+IFRI+MS+Sag (4) 346,700.29 1.93 1,300.50 2_MWD+IFRI+MS+Sag(4) 346,716.13 0.79 1,330.84 2 MWD+IFRI+MS+Sag (4) 346,731.73 0.46 1,360.73 2_MWD+IFRI+MS+Sag(4)M 346,747.68 0.03 1,391.43 2_WD+IFRI+MS+Sag(4) 346,763.51 0.50 1,421.64 2_MWD+IFRI+MS+Sag(4) 346,779.49 0.90 1,451.45 2_MWD+IFRI+MS+Sag(4) 346,795.66 0.45 1,480.96 2_MWD+IFRI+MS+Sag(4) 346,812.24 0.87 1,511.34 2_MWD+IFRI+MS+Sag(4) 346,827.80 0.72 1,540.35 2_MWD+IFRI+MS+Sag (4) 346,843.19 1.58 1,569.64 2_MWD+IFRI+MS+Sag(4) 346,858.62 1.33 1,599.96 2_MWD+IFRI+MS+Sag (4) 346,873.92 0.78 1,630.47 2_MWD+IFRI+MS+Sag(4) 346,888.83 0.52 1,660.21 2_MWD+IFRI+MS+Sag(4) 346,904.05 0.56 1,690.44 2_MWD+IFRI+MS+Sag(4) 346,919.14 3.76 1,719.42 2_MWD+IFRI+MS+Sag(4) 346,933.48 3.63 1,745.80 2 MWD+IFRI+MS+Sag (4) 346,947.12 2.91 1,770.89 2_MWD+IFRI+MS+Sag (4) 346,959.42 2.91 1,794.08 2_MWD+IFRI+MS+Sag (4) 8/92018 12:48.30PM Page 5 COMPASS 5000.1 Build 81E Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well SCU 33-33 Project: Soldotna CK Unit TVD Reference: SCU 344-33 WP05 RKB @ 143.50usft (HEC 169) Site: SCU 33-33 MD Reference: SCU 344-33 WP05 RKB @ 143.50usft (HEC 169) Well: SCU 33-33 North Reference: True Wellbore: SCU 344-33 Survey Calculation Method: Minimum Curvature Design: SCU 344-33 Database. Sperry EDM - NORTH US + CANADA Survey Checked B fi°k..w ght@halllburt Approved B Mitch Laird By pP Y Date: 8/9/2018 8/912018 12:48:30PM Page 6 COMPASS 5000.1 Build 81E Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +EI -W Northing Easting DLS Section (usft) (I (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/700') (ft) Survey Tool Name 10,451.47 19.24 146.91 9,953.56 9,810.06 -1,515.15 999.55 2,461,116.02 346,970.60 2.84 1,815.15 2_MWD+IFRI+MS+Sag (4) 10,513.61 15.95 147.37 10,012.79 9,869.29 -1,530.93 1,009.75 2,461,100.12 346,980.59 5.30 1,833.93 2_MWD+IFRI+MS+Sag(4) 10,574.60 13.74 145.80 10,071.74 9,928.24 -1,543.98 1,018.34 2,461,086.96 346,989.01 3.68 1,849.55 2_MWD+IFRI+MS+Sag (4) 10,636.53 12.80 147.43 10,132.01 9,988.51 -1,555.84 1,026.17 2,461,074.99 346,996.68 1.63 1,863.77 2_MWD+IFRI+MS+Sag(4) 10,698.89 12.26 145.38 10,192.89 10,049.39 -1,567.11 1,033.65 2,461,063.62 347,004.01 1.12 1,877.29 2_MWD+IFRI+MS+Sag(4) 10,760.62 12.32 145.90 10,253.20 10,109.70 -1,577.96 1,041.06 2,461,052.68 347,011.28 0.20 1,890.43 2 MWD+IFRI+MS+Sag (4) 10,821.76 12.27 147.19 10,312.94 10,169.44 -1,588.82 1,048.24 2,461,041.73 347,018.32 0.46 1,903.45 2_MWD+IFR1+MS+Sag (4) 10,884.48 12.13 147.64 10,374.24 10,230.74 -1,599.99 1,055.38 2,461,030.47 347,025.31 0.27 1,916.70 2_MWD+1FRI+MS+Sag(4) 10,947.51 11.95 148.73 10,435.89 10,292.39 -1,611.16 1,062.31 2,461,019.21 347,032.09 0.46 1,929.85 2_MWD+IFR1+MS+Sag(4) 11,009.29 11.60 147.45 10,496.37 10,352.87 -1,621.86 1,068.97 2,461,008.42 347,038.61 0.71 1,942.45 2_MWD+IFRI+MS+Sag (4) 11,070.29 11.71 148.81 10,556.11 10,412.61 -1,632.33 1,075.48 2,460,997.87 347,044.98 0.49 1,954.77 2_MWD+IFRI+MS+Sag (4) 11,133.09 11.83 148.76 10,617.59 10,474.09 -1,643.28 1,082.12 2,460,986.83 347,051.47 0.19 1,967.57 2_MWD+IFRI+MS+Sag (4) 11,195.60 11.77 147.47 10,678.78 10,535.28 -1,654.14 1,088.87 2,460,975.89 347,058.08 0.43 1,980.35 2_MWD+IFRI+MS+Sag (4) 11,256.46 12.02 148.99 10,738.33 10,594.83 -1,664.80 1,095.47 2,460,965.14 347,064.54 0.66 1,992.89 2_MWD+IFR1+MS+Sag(4) 11,317.15 11.82 150.82 10,797.71 10,654.21 -1,675.64 1,101.76 2,460,954.22 347,070.69 0.70 2,005.40 2_MWD+IFRI+MS+Sag (4) 11,341.20 11.49 150.71 10,821.27 10,677.77 -1,679.88 1,104.13 2,460,949.95 347,073.00 1.38 2,010.25 2_MWD+IFRI+MS+Sag (4) 11,381.00 • 11.49 150.71 10,860.27 • 10,716.77 -1,686.80 1,108.01 2,460,942.98 347,076 79 0.00 2,018.16 PROJECTED to TO Checked B fi°k..w ght@halllburt Approved B Mitch Laird By pP Y Date: 8/9/2018 8/912018 12:48:30PM Page 6 COMPASS 5000.1 Build 81E Lease & Well No. County Hilcorp Energy Company CASING & CEMENTING REPORT SRF SCU 344-33 (SCU 33-33 ST) Date Run 8 -Aug -18 Kenai State Alaska Supv. R Pederson / J Nicholson CASING RECORD Liner TD 11,381.00 Shoe Depth: 11,350.25 PBTD: 11,217.85 No. As. Delivered 131 No. Jts. Run 123 No. Jts. Returned 8 Csg Wt. On Hook: 234,079 Type Float Collar: Antelope No. Hrs to Run: 36 Csg Wt. On Slips: Type of Shoe: Bullnose Casing Crew: Weatherford Rotate Csg Yes X No Recip Csg _ Yes X No Ft. Min. 10.8 PPG Fluid Description: 6% KCL Liner hanger Info (Make/Model): Baker / HRDE ZXPN Liner top Packer?: X Yes _ No Liner hanger test pressure: 1650 Floats Held X Yes _ No Centralizer Placement: Every other ioint up to window CEMENTING REPORT Shoe @ 11350.25 FC @ 11,264.36 Top of Liner 5999.7 lush (Spacer) .. Clean Spacer III Density (ppg) 12.5 Volume pumped (BBLs) 35 I Slurry .. Class GSacks: 700 Yield: 1.24 sity (ppg) 15.3 Volume pumped (BBLs) 160 Mixing / Pumping Rate (bpm): 4 Slurry Sacks: Yield: sity (ppg) Volume pumped (BBLs) Mixing / Pumping Rale (bpm): t Flush (Spacer) Density (ppg) Rate (bpm): Volume: Type: 6% KCL Density (ppg) 10.8 Rate (bpm): 5 Volume (actual / calculated): 281/279 FCP (psi): 1300 Pump used for disp: Halliburton Bump Plug? X Yes No Bump press 2800 Casing Rotated? _Yes X No Reciprocated? _Yes X No % Returns during job 100 Cement returns to surface? _Yes X No Spacer returns?_Yes X No Vol to Surf: 0 Cement In Place At: 23:40 Date: 8/9/2018 Estimated TOC: 6,000 ? Method Used To Determine TOC: CBL — C 13 L- ZEiz C C- kov' $z(ao — Post Job Calculations: Calculated Cmt Vol @ 0% excess: 151 Total Volume cmt Pumped: 160 Cmt returned to surface: 0 Calculated cement left in wellbore: 160 OH volume Calculated: 123 OH volume actual: Actual % Washout: 25 www.wellez.net WellEz Information Management LLC ver 04818br Casing (Or Liner) Detail Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top Shoe 73/4 DWC/C Antelope 2.01 11,350.25 11,348.24 2 Liner 7 32.0 L-80 DWC/C Tenaris 83.88 11,348.24 11,264.36 Float Collar 73/4 DWC/C Antelope 1.30 11,264.36 11,263.06 1 Liner 7 32.0 L-80 DWC/C Tenaris 41.81 11,263.06 11,221.25 Landing Collar 73/4 DWC/C Baker 3.40 11,221.25 11,217.85 2 Liner 7 32.0 L-80 DWC/C Tenaris 5,187.77 11,217.85 6,030.08 Liner Hanger 95/8 DWC/C Baker 30.38 6,030.08 5,999.70 Csg Wt. On Hook: 234,079 Type Float Collar: Antelope No. Hrs to Run: 36 Csg Wt. On Slips: Type of Shoe: Bullnose Casing Crew: Weatherford Rotate Csg Yes X No Recip Csg _ Yes X No Ft. Min. 10.8 PPG Fluid Description: 6% KCL Liner hanger Info (Make/Model): Baker / HRDE ZXPN Liner top Packer?: X Yes _ No Liner hanger test pressure: 1650 Floats Held X Yes _ No Centralizer Placement: Every other ioint up to window CEMENTING REPORT Shoe @ 11350.25 FC @ 11,264.36 Top of Liner 5999.7 lush (Spacer) .. Clean Spacer III Density (ppg) 12.5 Volume pumped (BBLs) 35 I Slurry .. Class GSacks: 700 Yield: 1.24 sity (ppg) 15.3 Volume pumped (BBLs) 160 Mixing / Pumping Rate (bpm): 4 Slurry Sacks: Yield: sity (ppg) Volume pumped (BBLs) Mixing / Pumping Rale (bpm): t Flush (Spacer) Density (ppg) Rate (bpm): Volume: Type: 6% KCL Density (ppg) 10.8 Rate (bpm): 5 Volume (actual / calculated): 281/279 FCP (psi): 1300 Pump used for disp: Halliburton Bump Plug? X Yes No Bump press 2800 Casing Rotated? _Yes X No Reciprocated? _Yes X No % Returns during job 100 Cement returns to surface? _Yes X No Spacer returns?_Yes X No Vol to Surf: 0 Cement In Place At: 23:40 Date: 8/9/2018 Estimated TOC: 6,000 ? Method Used To Determine TOC: CBL — C 13 L- ZEiz C C- kov' $z(ao — Post Job Calculations: Calculated Cmt Vol @ 0% excess: 151 Total Volume cmt Pumped: 160 Cmt returned to surface: 0 Calculated cement left in wellbore: 160 OH volume Calculated: 123 OH volume actual: Actual % Washout: 25 www.wellez.net WellEz Information Management LLC ver 04818br DATE 11/09/2018 Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician II 333 W 7th Ave Suite 100 Anchorage, AK 99501 Resubmitting CBL SCU 344-33 CBL 8-12-18.las SCU 344-33 CBL 8-12-18.pdf Please include current contact information if different from above. RECEIVE® NOV 0 9 2018 AOGCC 218054 29981 Please acknowledge receipt by signing ankreturnVg one copy of this transmittal or FAX to 907 777.8337 Date: DATE 11/06/2018 Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resource Technician II 333 W 7th Ave Suite 100 Anchorage, AK 99501 CBL SCU 344-33 CBL 8-12-18.las o SCU 344-33 CBL 8-12-18.pdf Please include current contact information if different from above. Data submitted improperly, resubmitted 11/09 R tiFcF/V dG a?o18F0 CC 21 8054 29981 Please acknowledge,PleceeApt by sigq)ng and r4ulming one copy of this transmittal or FAX to 907 777.8337 Received By: 0, I /J // „ _ A V Date: /I/oWiTz- DATE 10/26/2018 I Seth Nolan Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Meredith Guhl Petroleum Geology Assistant 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAI� SCU 344-33 5 boxes: Dry Cuttings .WELL SAMPLE INTERVAL SCU 344-33 6259-7370 SCU 344-33 7370-8360 SCU 344-33 8360-9500 SCU 344-33 9500-10790 SCU 344-33 10790-11381 Please include current contact information if different from above. SFO' o0T1F��0 OG,C long O Cc Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 iIlzlie5 THE STATE ALASKA GOVERNOR BILL WALKER Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, SCU 344-33 Permit to Drill Number: 218-054 Sundry Number: 318-469 Dear Mr. Helgeson: Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Main: 907.297.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Hollis S. French Chair 4t DATED this 2`l day of October, 2018. RBDMSIOCT 2 4 2018 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 /o/zIt//S' 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: CTCO w N2 ❑� 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: F. S7'/ibL Hilcorp Alaska, LLC Exploratory ❑ Development ❑ Strati ra hic g p ❑ Service ❑� 218-054 lK I% 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage Alaska 99503 50-133-20293-01-00 ` 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 1238 , Will planned perforations require a spacing exception? Yes ❑ No � ❑ Soldotna Creek Unit (SCU) 344-33 9. Property Designation (Lease Number): • 10. Field/Pool(s): FEDA028990, FEDA028997 'Swanson River! Hemlock Oil 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 11,381' 10,856' 11,350' 10,826' 4,000 N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 90, 20" 90' 90' Surface 3,380' 13-3/8" 3,380' 3,380' 3,450psi 1,950psi Surface 6,259 9-5/8" 6,259' 6,258' 8,150psi 7,110opsi Production 3,582' 7" 9,582' 9,179' 11,220psi 8,530psi Production 1,768' 7" 11,350' 10,826' 9,060psi 8,610psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 4-1/2" 12.6 # / L-80 10,677' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): NA NA 12. Attachments: Proposal Summary Q Wellbore schematic Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch Q Exploratory ❑ Stratigraphic ❑ Development ❑ Service ❑✓ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: October 23, 2017 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ Q Op Shutdown Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramer'a hllcof .Coni Contact Phone: 777-8420 Authorized Signature: Date: /C COMMISSION USE ONLY Conditions of approval: Notify Commission thata representative may witness Sundry Number: ^ ,r L✓, �l/1 /so Plug Integrity ❑ BOP est Mechanical Integrity Test ❑ Location Clearance ❑ Other: ob �� Post Initial Injection MIT Req'dd? Yes ❑ No ❑ u Spacing Exception Required? Yes E] No [SK Subsequent Form Required:' __ l a 1 APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: ( ed ZV (e, ('j11 f0•Z3'�5' II �� p !I q�� ,ai\0"403 Revised 4/2017 A © 1, 2Irt�rAi�pjtt 6i� OCT 2 4 Submit Form and Approved applicat i li r e Submit in Duplicate ,R Hilcora Alaska, LU Well Prognosis Well: SCU 344-33 Date: 10/17/2018 Well Name: SCU 344-33 API Number: 50-133-20293-01 Current Status: Gas injector Leg: N/A Estimated Start Date: 10/23/18 Rig: CTU Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 218-054 First Call Engineer: Ted Kramer (907) 777-8420 (0) (987) 867-0665 (M) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824 (M) AFE Number: 1812067C Current Surface Pressure: - 60 psi Maximum Expected BHP: - 6,180 psi @ 10,480' TVD (When firing Stim Gun) Max. Predicted Surface Pressure: -4,000 psi (While Pumping N2) Brief Well Summary SCU 344-33 is a newly drilled gas injection well. After initially perforating the well the well quit taking fluid. A re-perf was then attempted without success. The purpose of this work is to blow the well dry, attempt to flow the well back (negative test), then circulate clean fluid and spot a stimulation fluid package across the H-7 interval. The interval will then be re -perforated or Stim gunned. Notes Regarding Wellbore Condition • Well is currently off line. • Interval has been perforated twice. B Coiled Tubing Procedure: Al, , 1h Ir 1. MIRU Coiled Tubing, PT BOPE to 4,500 psi Hi 250 Low. 2. RIH w/ 1.75" coil w/ jet nozzle BHA. --moi a. Top of fluid was recorded to be @ 3,762'. Start Nitrogen and blow well dry to 11,350'. ( POOH. �— �� 3. Bleed down N2 pressure to attempt to get well to flow back to tank. z Ps • 4. If well flows back, set up flow line to flow reasonable volume to insure perfs have cleaned up. Shut in well and go to step 10. If well does not flow, go to step 5. 5. Spot 1,200 ft. of clean fluid (Xylene, Acid or Methanol) from 11,000 ft up to 9800'. 6. Pooh W/coil. E -line Procedure 7. MIRU E -line. PT lubricator to 200 low, 3,500 psi high. STIP 8. PU RIH W/ Perfguns and or Stim Guns placing top of gun at 10,978'. Awd� 9. Pressure up well with gas and /or nitrogen to 4,000 psi. Fire Stim gun. POOH W Stim gun. 10. Open up wing valve and place injection gas pressure on the well and begin injection. 11. Turn well over to production. U Hil.ap Aluskn, LU Attachments: 1. Current Schematic 2. Coil BOPE Schematic 3. Wellhead Diagram 4. Standard Well Procedure- Nitrogen 5. CT Flow Schematic (Forward) Well Prognosis Well: SCU 344-33 Date: 10/17/2018 K llil.rp Alaeka, LLC GL: 125.5' AMSL RKB-143.5' 20" - 9C' 13-3/8" 3,380' t F, } i Window cut at 6,259' t ' 9-5/8" 6,259' I H.4 H -4/H-5 H-5 H-5 H -6/H-7 H -7/H -8/H - H -9/11-10 7, TD =11,381' MD / 10,856' TVD PBTD =11,350' MD / 10,826' TVD Max Deviation = 27.8' @ 6,981' Swanson River Field Well: SCU 344-33 SCHEMATIC PTD: 218-054 API: 50-133-20293-01 CASING DETAIL Size Type Wt Grade Conn Top Btm 20" Conductor - - - Surf. 90' 13-3/8" Surface 68 K-55 BTC Surf. 3,380' 9-5/8" Surface 47 5-95 BTS Surf. 6,259' 7" Production 29 P-110 DWC 6,050' 11,350' TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 4-1/2" Tubing 12.6 L-80 IBTM 3.958" Surf 10,677' JEWELRY DETAIL NO. Depth ID OD Item 1 328' 3.813" 4.5" X- Landing Nipple (injection valve) 2 6,000' ±10,120' ±10,135' 7" Liner top packer 3 10,641' 3.958" ±10,859' Anchor Latch Seal Assembly 4 10,651' 5.0" 5.5" Seal Bore Receptacle 5 10,657' 3.958" 7.0" 7" x 4-1/2" Packer 6. 10,666' 3.813" 4.5" X - Landing Nipple 7 10,677' 1 3.958" 4.5" WL Entry Guide PERFORATIONS New Name Old Name Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Notes H-4 H-1 ±10,843' ±10,859' ±10,120' ±10,135' TBD 318-326 1-1-4/1-1-5 H-2 ±10,859' ±10,882' ±10,135' ±10,156' TBD 318-326 H-5 H-3 ±10,882' ±10,903' ±10,156' ±10,175' TBD 318-326 HS H-4 ±10,903' ±10,942' ±10,175' ±10,212' TBD 318-326 H-6 H-7 H-5 ±10,942' ±11,002' ±10,212' ±10,268' TBD 318-326 H-7 H-5 10,978' 10,993' 10,459' 10,474' 10/16/18 Open 1-1-7/H-8/1-1-9 H-7 ±11,028' ±11,096' ±10,293' ±10,358' TBD 318-326 H -9/H-10 H-9 ±11,148' ±11,253' ±10,409' ±10,513' TBD 318-326 Updated by DMA 10-17-18 R Hilo p AWL1.11: Coil Tubing BOP g HH580 Injector Head & Goosenec Weight = 12,8501bs 4-1116" 10K Conventional Stripper 51K C062 Lubricator .. 5K 0062 x 4-1116" 10K Flange 4-1116" 10K Combi TW Set: StirdlShear Sec dSet: Rpe'Si '-- 4.1116" 10K Flow Cross Manua 2)Q Valve 1: 2" 1502 x 2-1/16" tOK Range Manual 2x2 Valve 2:24116" 10K x 2-1/16" IOK Fla rge ,.A 2x2 Valve 3:2-1116" 10K x 2-1116" 10K Fla— Mm 2x2 Valve 4: 2"1502x2 -1116"10K Rale 4-1116" 10K x Wellhead Adapter Flange Wellhead H Hit.. VAI.A.,1.1.1: Swanson River SCU 344-33 133/8 X 95/8 X 41/2 Tree cap, Bowen, 41/16 SM FE X 7" stub acme Bowen Quick Union Valve, Swab, CIW-FLS, 41/16 SM FE, HWO, EE trim Valve, Upper Master, CIW-FLS, 41/16 SM FE, HWO, EE trim Valve, Master, CIW-FLS, 41/16 SM FE, HWO, DD trim Tubing head, Cameron DCB -S, 13 5/8 SM X 115M, w/ 2- 2 1/16 SM SSO Casing head, Cameron WF, 13 5/8 SM X13 3/8 SOW, w/ 2- 2 1/16 SM EFO Swanson River Field SCU 344-33 Proposed 07/26/2018 Tubing hanger, CIW-DCB- FBB, 11 x 4 Y. EUE 8rd lift x 4'h IST susp, w/ 4" type H BPV profile, 2- Y. non continuous control line, alloy material, 7" extended neck Adapter, CIW-EN-2CL, 115M stdd X 115M stdd, w/ 7" slick neck pocket and K npt chemical injection ports Valve, WKM-M, 21/16 SM FE, HWO, AAtrim - CITY CIW-F, 2 1/16 SM FE, HWO, AA trim STANDARD WELL PROCEDURE niIcogp Alaska. IAX NITROGEN OPERATIONS 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 02 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. 12/08/2015 FINAL vl Page 1 of 1 DATE 9/28/2018 Deura Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 FLOG and Mudlog digital data CD1: Elog digital data 2 9 7 4 5 -Log Viewers 9/28/201811:06 A... CGM 9/28/201811:07 A... Definitive Survey 9/28/201811:07 A... �.. EMF 9/28/201811:05 A... LAS 9/28/201811:05 A... �. PDF 9/28/201811:05 A... �,. TIFF 9/28/201811:06 A... CD2:Mudlog digital data k. Daily Reports 9/28/201810:25 A... ►. DML Data 9/28/201810:25 A... Final Well Report 9/28/201810:19 A. �. LAS Data 9/28/2018 10:19 A... �. Log PDFs 9/28/201810:20 A.. �. Log TIFFs 9/28/201810:24 A... Sample Photography 9/28/201810:25 A... f. Show Reports 9/28/201810:25 A... Please include current contact information if different from above File folder File folder File folder File folder File folder File folder File folder 2 180 54 29 74 5 RECEIVED OCT 042018 AOGCC File folder File folder File folder File folder File folder File folder File folder File folder Please acknowledge regeipt by signing an4 return4 one copy of this transmittal or FAX to 907 777.8337 Received By: /) ///� j^ Date: /^/O Vol j DATE 9/28/2018 Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 ELOG and Mudlog digital data digital data 2 9 7 4 5 CD1: Elog I _Log Viewers 9/28/201811:06 A... —9128/201811:07 { CGM A... Definitive Survey 9128/201811:07 A... 1.. EMF 9/28/201811:05 A... { LAS 9/28/201811:05 A... ( PDF 9/28/201811:05 A.- 1 TIFF 9128/201811:06 A... CD2:Mudlog digital data 29 74 6 1 Daily Reports 9/28/201810:25 A... J. DML Data 9/28/201810:25 A... ( Final Well Report 9/28/201810:19 A... LAS Data 9/28/201810:19 A... l Log PDFs 9/28/201810:20 A... Log TIFFS 9/28/201810:24 A... i. Sample Photography 9/28/201810:25 A... Show Reports 9/28/201810:25 A... Please include current contact information if different from above. File folder File folder File folder File folder File folder File folder File folder 2 180 54 29 74 6 RECEIVED OCT 0 4 2018 AOGCC File folder File folder File folder File folder File folder File folder File folder File folder Please acknowledge re0eipt by signing anN returninb one copy of this transmittal or FAX to 907 777.8337 Received By: / IMP P j/-\ / Date: V//,O//Y- /^/Q MEMORANDUM TO: FROM Jim Regg Kct i IDl ill P. I. Supervisor State of Alaska Alaska Oil and Gas Conservation Commission DATE Austin McLeod SUBJECT: Petroleum Inspector 9/30/2018 BOPE SCU 344-33 Hilcorp PTD 2180540; Sundry 318-409 9/30/2018: AOGCC received notice for initial blowout prevention equipment (BOPE) test on Hilcorp Rig 401 (formerly Moncla 401) on 9/26/2018 — rig workover. That test was to start on 9/28/2018. After several days of delays from the rig, I traveled to Soldotna Creek Unit 344-33 (Swanson River Field) for witness of the BOPE test. The rig has not worked in approximately 120 days. I witnessed tests of the gas detection equipment — all passes — then was told that they did not have the necessary equipment to start testing the BOP stack. I departed location and told Hilcorp representative Kenny McPherson to contact AOGCC Inspection Supervisor Jim Regg to reschedule witness. Attachments: none 2018-0930_BOP_Hi Icorp40I _SC U_344-33_am.docx Page I of 1 THE STATE °fALASKA GOVERNOR BILI. WALKER Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, SCU 344-33 Permit to Drill Number: 218-054 Sundry Number: 318-409 Dear Mr. Helgeson: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.olaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. DATED this a� of September, 2018. Sincerely, AIOO�X Cathy . Foerster Commissioner RBDMSM. SEP 2 0 10� STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 SEP 1819 `$ , GO C(; 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑Q Operations shutdown ❑ Suspend ❑ Perforate ❑Q Other Stimulate ❑ Pull Tubing Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Replace Tubing ❑✓ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development ❑ S[ratigraphic ❑ Service ❑� . 218-054 3. Address: 3800 Cente oint Drive, Suite 1400 rP 6. API Number: Anchorage Alaska 99503 50-133-20293-01-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 123B Will planned perforations require a spacing exception? Yes ❑ No Soldotna Creek Unit (SCU) 344-33 9. Property Designation (Lease Number): 10. Field/Pool(s): FEDA028990: FEDA028997 Swanson River / Hemlock Oil 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth ND: MPSP (psi): Plugs (MD): Junk (MD): 11,381' 10,856' 11,350' 10,826' 1,200psi N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 90' 20" 90' 90' Surface 3,380' 13-3/8" 3,380' 3,380' 3,450psi 1,950psi Surface 6,259' 9-5/8" 6,259' 6,258' 8,150psi 7,100psi Production 3,582' 7" 9,582' 9,179'11,220psi 8,530psi Production 1,768' 7" 11,350' 10,826' 9. 60psi 8,610psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 4.1/2" 12.6 # / L-80 10,67T Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): NA NA 12. Attachments: Proposal Summary ❑Q Wellbore schematic ❑Q 13. Well Class after proposed work: /. , Detailed Operations Program ❑ BOP Sketch ❑Q Exploratory ❑ Stratigraphic ❑ Development Service N/ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: September 27, 2018 OIL ❑WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑Q Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramer(CDhilcor .Com Contact Phone: 777-8420 Authorized Signature: Date: If COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: n I ONI Plug Integrity 17 BOP Test Mechanical Integrity Test LYl Location Clearance ❑ Other: 1t= 3 00 0 'P 5 L &P '(e- f 1` Post Initial Injection MIT Req'd? Yes No,�qq Spacing Exception Required? Yes No d Subsequent Form Required: �' 1 V 11(,J APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date:,? - / Approved /Y i C7l PSA L RBDMval. 0 2018 Submit Form and Form 10-403 Revised 4Y201 Approved applicatio s n r t e date of approval. ttachme sin Duplicate � V L H Hilmrp Alaska. LU Well Prognosis Well: SCU 344-33 Date: 9/18/18 Well Name: SCU 344-33 API Number: 50-133-20293-01 Current Status: Shut In Gas Injector Leg: N/A Estimated Start Date: 9/27/18 Rig: Rig 401 Reg. Approval Req'd? 10-403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 218-054 First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (C) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824 (C) AFE Number: 18120670 Maximum Expected BHP: — 2,200 psi @ 10,000' TVD (Based on well Geological Prognosis) Max. Potential Surface Pressure: — 1,200 psi (Based on 0.1 psi/ft gradient to surface) Max. Gas Injection Pressure (post well work): 3,500 psi @ surface (Based on Injection Line MAOP) Brief Well Summary SCU 344-33 is new Gas injection well that would not pass a tubing pressure test. There are no open perforations in the well. Objective: Pull and replace tubing string, perforate in the Hemlock formation. Notes Regarding Wellbore Condition The packer was set at 10,651'. Packer was pressure tested to 3,800 psi after setting the packer for 30 min. Plug is still in the packer (Ball and Rod). • Tubing is stabbed into a seal bore with a ratch latch on top. • Well is full of fluid. Rig Procedure: 1. MIRU Rig401. 2. ND Wellhead, NU BOP stack and test 250 psi Low/ 3,000 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 5 -min). Record accumulator pre -charge pressures and chart tests. a. Perform Test. b. Notify AOGCC and BUM 24 hrs in advance of BOP test. i c. Test VBR rams on 4-1/2" test joint. d. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 3. Unseat tubing anchor and pick up pipe to neutral position. Rotate Ratch latch out of the packer seal bore as per Manufacturers procedure. Note: Pull out of hole with pups and 4-1/2" EZGOHTGT tubing. Mark each joint - pin and coupling with connection number on each side and make a horizontal mark on the top of the thread connection to the box to show how much thread was exposed and how much was buried. Note: We will be laying down each joint. 4. Re -dress seals on location. Inspect Ratch Latch for re -running. 5. PU seals, Ratch Latch on 4-1/2" IBT tubing. RIH w/ same. U Hilwra Alaska, Lu Well Prognosis Well: SCU 344-33 Date: 9/18/18 6. RIH at slow to moderate speed. Space out packer at -10,650 to land tubing hanger. Stab into seal bore and rotate in ratch latch according to Manufactures procedure. 7. and tubing in hanger. lose the Space 8. RU Test tubing lto 4,5�si for 30minCw with chart lockdown pins. Z© AR` Z' .{ lL 9. Test annulus to psi for 30 min with chart. ppa 10. LD landing joint. Se�V. ND BOPE. NU Tree. Pull BPV. 11. Set TWC. Test hanger to 250/5,000 psi. Test Tree to 250/5,000 psi. Pull TWC. 12. RDMO Work over rig. ***A 10 -day notification must be made to AOGCC before gas injection into this well"" 13. RU Slickline. 14. RIH and pull plug from 4-1/2" x -landing nipple. POOH. LD plug. E -Line Procedure: A4 15. MIRU E -line, PT Lubricator to 4,000 psi Hi 250 Low for 10min. a. Tree connection is 4" Bowen. 16. RU 2-7/8" wireline guns. 17. RIH and perforate the following intervals: Zone Sands Top (MD) Btm (MD) FT Hemlock H-1 ±10,843' ±10,859' ±16 Hemlock H-2 ±10,859' ±10,882' ±23 Hemlock H-3 ±10,882' ±10,903' ±21 Hemlock H-4 ±10,903' ±10,942' ±39 Hemlock H-5 ±10,942' ±11,002' ±60 Hemlock H-7 ±11,028' ±11,096' ±68 Hemlock H-9 ±11,148' ±11,253' ±105 e. Proposed perf interval shown on the proposed schematic. Igf. Final perfs tie-in sheet will be provided to the field for exact perf intervals. Correlate using Cement Bond Log (pending Tie-in los). h. Use Gamma/CCL to correlate. L 18. RD E -line. )�I c1wt 19. Turn well over to production. 7 ./g.15 20. RU slickline, PT Lubricator to 4,000 psi Hi 250 Low for 10min. 21. MU injection valve. RIH and set injection valve in 4-1/2" x -landing nipple. POOH. RD slickline. Attachments: 1. Schematic 2. Proposed Schematic 3. BOPE Schematic 4. Current Wellhead Schematic 5. Blank RWO Procedure Change Form 2 70' 90 Wind cut 6,2E 9-5 6,2 Swanson River Field Well: S Well: CU 344-33 SCHEMATIC PTD: 218-054 EBeara Alaska, LLC API: 50-133-20293-01 GL: 125.5' AMSL RKB -143.5' TD =11,381' MD / 10,856' TVD PBTD =11,350' MD / 10,826' TVD Max Deviation = 27.8` @ 6,981' CASING DETAIL Size Type Wt Grade Conn Top Btm 20" Conductor - 12.6 - Surf. 90' 13-3/8" Surface 68 K-55 BTC Surf. 3,380' 9-5/8" Surface 47 S-95 BTS Surf. 6,259' 7" Production 29 P-110 DWC 6,050' 11,350' TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 4-1/2" Tubing 12.6 L-80 HTGT 3.958" Surf 10,677' JEWELRY DETAIL NO. Depth ID OD Item 1 328' 3.813" 4.5" X -Landing Nipple (injection valve) 2 6,000' TBD 318-326 7" Liner top packer 3 10,641' 3.958" ±10,156' Anchor Latch Seal Assembly 4 10,651' 5.0" 5.5" Seal Bore Receptacle 5 10,657' 3.958" 7.0" 7" x 4-1/2" Packer 6 10,666' 3.813" 4.5" X - Landing Nipple 7 10,677' 3.958" 4.5" WL Entry Guide PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Notes H-1 ±10,843' ±10,859' ±10,120' ±10,135' TBD 318-326 H-2 ±10,859' ±10,882' ±10,135' ±10,156' TBD 318-326 H-3 ±10,882' ±10,903' ±10,156' ±10,175' TBD 318-326 H-4 ±10,903' ±10,942' ±10,175' ±10,212' TBD 318-326 H-5 ±10,942' ±11,002' ±10,212' ±10,268' TBD 318-326 H-7 ±11,028' ±11,096' ±10,293' ±10,358' TBD 318-326 H-9 ±11,148' ±11,253' ±10,409' ±10,513' TBD 318-326 Updated by DMA 09-17-18 . n Ililoom Alaska, LLC GL: 125.5' AMSL RKB-143.5' 20" v,'' 9ff 13-3/8" 1 3,380' iI i+ A'1 1� Window cut at 6,259' 9-5/8" 6,259' 1 21 H-1 H-2 H-3 H-4 A' H-5 H-7 H9 TD =11,381' MD / 10,856' TVD PBTD = 11,350' MD / 10,826' TVD Max Deviation = 27.8° @ 6,981' PROPOSED SCHEMATIC ( Swanson River Field Well: SCU 344-33 PTD: 218-054 API: 50-133-20293-01 CASING DETAIL Size Type Wt Grade Conn Top Btm 20" Conductor - 12.6 - Surf. 90' 13-3/8" Surface 68 K-55 BTC Surf. 3,380' 9-5/8" Surface 47 S-95 BTS Surf. 6,259' 7" Production 29 P-110 DWC 6,050' 11,350' TUBING DETAIL Size Type Wt Grade Conn ID Top Btm 4-1/2" Tubing 12.6 L-80 IBTM 3.958" Surf 10,677 JEWELRY DETAIL N0. Depth ID OD Item 1 328' 3.813" 4.5" X -Landing Nipple Injection wlve 2 6,000' TBD 318-326 7" Liner top packer 3 10,641' 3.958" ±10,156' Anchor Latch Seal Assembly 4 10,651' 5.0" 5.5" Seal Bore Receptacle 5 10,657' 3.958" 7.0" 7" x 4-1/2" Packer 6 10,666' 3.813" 4.5" X - Landing Nipple 7 10,677' 3.958" 4.5" WL Entry Guide PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Notes H-1 ±10,843' ±10,859' ±10,120' ±10,135' TBD 318-326 H-2 ±10,859' ±10,882' ±10,135' ±10,156' TBD 318-326 H-3 ±10,882' ±10,903' ±10,156' ±10,175' TBD 318-326 H-4 ±10,903' ±10,942' ±10,175' ±10,212' TBD 318-326 H-5 ±10,942' ±11,002' ±10,212' ±10,268' TBD 318-326 H-7 ±11,028' ±11,096' ±10,293' ±10,358' TBD 318-326 H-9 ±11,148' ±11,253' ±10,409' ±10,513' TBD 318-326 Updated by TEK 09-18-18 HILCORP ALASKA 11" 5M BOPE 11" SM HYDRIL GK ANNULAR 47-7/8" TALL, FLANGE TO FLANGE 11" 5M CAMERON TYPE U DOUBLE GATE BOP DRESSED W/VARIABLE RAMS IN TOP DRESSED W/BLIND RAMS IN BOTTOM 54-1/2" TALL, FLANGE TO FLANGE 11" 5M DRILLING SPOOL W/2-1/16" & 4-1/16" 5M OUTLETS 24" TALL, FLANGE TO FLANGE —127" TOTAL STACK HEIGHT ANNULAR STYLE BOP SPECS: - 8.08 gallon open chamber volume - 9.81 gallon close chamber volume GATE STYLE BOP SPECS: - 3.4 gallons to open per gate - 3.5 gallons to close per gate - 7.3:1 closing ratio - 2.5:1 opening ratio L.lt: Swanson River SCU 344-33 13 3/8 X 9 5/8 X 41/2 Tree cap, Bowen, 41/165M FE X 7" stub acme Bowen Quick Union Valve, Swab, CIW-FLS, 41/16 SM FE, HWO, EE trim Valve, Upper Master, CIW-FLS, 41/16 SM FE, HWO, EE trim Valve, Master, CIW-FLS, 41/16 SM FE, HWO, DO trim Tubing head, Cameron DCB -5, 13 5/8 SM X 11 5M, w/ 2- 2 1/16 5M SSO Casing head, Cameron WF, 13 5/8 SM X13 3/8 SOW, w/ 2- 2 1/16 5M EFO Swanson River Field SCU 344-33 Proposed 07/26/2018 Tubing hanger, CIW-DCB- FBB, 11 x 4 % EUE 8rd lift x 4 h IBT susp, w/ 4" type H BPV profile, 2-X non continuous control line, alloy material, 7' extended neck Adapter, CIW-EN-2CL, SS SM stdd X 11 SM stdd, w/ 7" slick neck pocket and X npt chemical injection ports Valve, WKM-M, 2 1/16 5M 4. FE, HWO, AA trim OT' 2 CIW-F, 2 1/16 5M FE, HWO, AA trim UHilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for SCU 344-33 (PTD 218-054) Sundry #: XXX -XXX Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) "first call' engineer. AOGCC written approval of the change is required before implementing the change. Sec Page Date Procedure Change New 403 Required? Y / N HAK Prepared By Initials HAK Approved By initials AOGCC Written Approval Received (Person and Date) Approval: Prepared: Asset Team Operations Manager Date First Call Operations Engineer Date THE STATE °fALASKA GOVERNOR BILI. WALKER Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, SCU 344-33 Permit to Drill Number: 218-054 Sundry Number: 318-326 Dear Mr. Helgeson: 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 Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Hollis S. French 4l Chair DATED this 4 day of August, 2018. MM U6 0 8 2018 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 RECEIVED JUL 2 7 2018 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ A4&JjIp&j0&dn ❑ Suspend ❑ Perforate ❑Q ' Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Initial Completion ❑� 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development Stratigraphic ❑ Service Ey 218-054 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage Alaska 99503 A q,2' 50-133-20293-01-00 ' 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 1236 " ElNo 1Z Soldotna Creek Unit (SCU) 344-33 Will planned perforations require a spacing exception? Yes 9. Property Designation (Lease Number): 10. Field/Pool(s): FEDA028990, FEDA028997 - Swanson River I Hemlock Oil 1 t. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth ND (ft): Effective Depth MD: Effective Depth ND: MPSP (psi): Plugs (MD): Junk (MD): -11,385' -10,914' -11,294' -1,0825' 3,500psi N/A N/A Casing Length Size MD ND Burst Collapse Structural Conductor 90' 20" 90' 90' Surface 3,380' 13-3/8" 3,380' 3,380' 3,450psi 1,950psi Surface 6,250' 9-5/8" 6,250' 6,249 8,150psi 7,100psi Production -3,300 7" -9,800' -9,740 7,240psi 5,410psi Production -1,585 7" -11,385' -11245 8,160psi 7,020psi Perforation Depth MD (ft): Perforation Depth ND (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic Sae Attached Schematic NA NA NA Packers and SSSV Type: Packers and SSSV MD (ft) and ND (ft): NA NA 12. Attachments: Proposal Summary Q Wellbore schematic Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch Exploratory ❑ Stratigraphic ❑ Development Q Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: August 3, 2018 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ Q Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson 777-8405 Contact Name: Taylor Nasse Authorized Title: Operations Manager Contact Email: tnagSgGbilcoro cora Contact Phone: 777-8354 Authorized Signature: Date: 7 L COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: - L n - n �r ✓h L Plug Integrity ❑ BOP Test E Mechanical Integrity Test Location Clearance EllTJ Other: S5CO QS i B 0 1/Te�:st- Post Initi njection MIT Req'd? Yes 2(No ❑ �� Ii /V^fr-'tw- L/V➢ Spacing Exception Required? Yes❑ No .d Subsequent Form Required: 1 (' -- APPROVED BY (� I kA� Approved by: COMMISSIONER THE COMMISSION Date: C�I� V T app IGINA� ABDMS A� O 8 4iblMt Form and ^� Form 10-403 Revised 4/2017 Approved application is a oT "approval. hments in Duplicate U nilemp Ak ka, LU Well Prognosis Well: SCU 322C-04 Date: 7/27/18 Well Name: SCU 344-33 API Number: 50-133-20293-01 Current Status: Drilling in progress Leg: N/A Estimated Start Date: 8/3/18 Rig: Rig 169 Reg. Approval Req'd? 10-403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 218-054 First Call Engineer: Taylor Nasse (907) 777-8354 (0) (907) 903-0341(C) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824 (C) AFE Number: 1812067C Maximum Expected BHP: — 2,200 psi @ 10,000' TVD (Based on well Geological Prognosis) Max. Potential Surface Pressure: — 1,200 psi (Based on 0.1 psi/ft gradient to surface) Max. Gas Injection Pressure (post well work): 3,500 psi @ surface (Based on Injection Line MAOP) Brief Well Summary SCU 344-33 is a gas injection well currently being sidetracked from SCU 33-33 to target H1/1-12 gas injection in an effort to sweep production in this fault block. Based on recent drilling results, this zone does not appear to have been swept with the original gas flooding in Swanson River. Objective: Run gas injection completion and perforate in the Hemlock formation. �N Notes Regarding Wellbore Condition • Saxon 169 rigged up on well and currently drilling. • Pressure test 7" casing to 3,500 psig will be completed. • Continue BOP testing frequency from Drilling Program (PTD 218-054) through completion. • Well full of 6% KCL fluid. Rig Procedure: 1. ** Continue from SCU 344-33 (PTD 218-054) Drilling Program Step 18.1 2. MIRU E -line on drilling rig. 3. RIH and run Cement Bond Log from PBTD to "'6250' MD (top of 7" IinerL_ POOH. LD CBL tool. V a. Send logs to town for correlation log. -- ar j✓y'w-..wt it, b. Final pert depths will be based on CBL results. 4. RD E -line. 5. Install necessary BOP equipment for running the completion and test (if not previously installed). a. Double ram should be dressed with 4-1/2" ram (or 2-3/8" x 5" VBR) in top cavity, blind ram in btm cavity. b. Single ram should be dressed with 4-1/2" ram (or 2-3/8" x 5" VBR). c. Test any new BOP components to 250/3500 psi for 10/10 min. Test annular to 250/2500 psi for 10/10 min w/ 4-1/2" test joint. d. 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. 6. LD BOP test equipment. n Hiloora Alaska, I.0 Well Prognosis Well: SCU 322C-04 Date:7/27/18 7. PU 4-1/2" hydraulic packer and completion jewelry and RIH w/ completion on new 4-1/2" HTGT tubing. Minimize excess pipe dope when running completion. Circulate 6% KCI to surface, w/ inhibited fluid to be left on backside. Completion jewelry per proposed schematic: a. WL entry guide b. X -nipple (RHCP plug body loaded) c. 7" Packer d. Seal Bore Receptacle e. Anchor Latch Seal Assembly f. 4-1/2" X -nipple for injection valve g. 4-1/2" Tubing Hanger 8. RIH at slow to moderate speed. Space out packer at -10,650 to land tubing hanger approximately Top (MD) 30" high. Note: Approximately 24"-30" length plus distance between slack off and pick up weights FT to achieve 25,000 lbs compression when hanger is landed. (Packer must be set within 200' of the H-1 perforations per AOGCC regulations). 9. Drop setting bar/ball. 10. Pressure tubing to 3,800 psig to set the packer and hold for 15 minutes. Release pressure and slack ±10,859' off 25,000 lbs. and hold for 15 minutes. Pick up 25,000 lbs. over pick up weight to verify slips are `,EcW �i yf ``�XN J 11. set. Land tubing in hanger. Close the lockdown pins. H-3 ±10,882' U- 12. Test tubing to 4,500 psi for 30min with chart. F i �13. Test annulus t0psi7for 30 min with chart U,� 14. LD landing joint. Set BPV. ND BOPE. NU Tree. Pull BPV. 15. Set TWC. Test hanger to 250/5,000 psi. Test Tree to 250/5,000 psi. Pull TWC. 16. RD Saxon #169 Drill Rig. 17. Turn well over to Hilcorp Operations. 18. ***A 10 -day notification must be made to AOGCC before gas injection into this well' 19. RU Slickline. 20. RIH and pull plug from 4-1/2" x -landing nipple. POOH. LD plug. E -Line Procedure: 21. MIRU E -line, PT Lubricator to 4,000 psi Hi 250 Low for 10min. a. Tree connection is 4" Bowen. 22. RU 2-7/8" wireline guns. 23. RIH and perforate the following intervals: Zone Sands Top (MD) Btm (MD) FT Hemlock H-1 ±10,843' ±10,859' ±16 Hemlock H-2 ±10,859' ±10,882' ±23 Hemlock H-3 ±10,882' ±10,903' ±21 Hemlock H-4 ±10,903' ±10,942' ±39 Hemlock H-5 ±10,942' ±11,002' ±60 Hemlock H-7 ±11,028' ±11,096' ±68 Well Prognosis Well: SCU 322C-04 l ilwry Alaska. LL' Date: 7/27/18 Hemlock H-9 ±11,148' +11,253' ±105 a. Proposed pert interval shown on the proposed schematic. b. Final perfs tie-in sheet will be provided to the field for exact perf intervals. c. Correlate using Cement Bond Log (pending Tie-in log). d. Use Gamma/CCL to correlate. 24. RD E -line. 25. Turn well over to production. 26. RU slickline, PT Lubricator to 4,000 psi Hi 250 Low for 10min. 27. MU injection valve. RIH and set injection valve in 4-1/2" x -landing nipple. POOH. RD slickline. wi4 vLe s54' IVl l T /A " r `'� re Attachments: i �i Le y G C71 • ITti ✓.,� 1. Actual Schematic 2. Proposed Schematic 3. BOPE Schematic 4. Current Wellhead Schematic 8 �' 5. Blank RWO Procedure Change Form 3 K .P Alaska, LLC Rig 169 RKB: 143.50(/ GL Elev.: 125.5(Y mi 13-3/8' r �- .k. TD=11,395 (MD) / TD=10,914!") PBTD =11,294' (MD) / PB1D=10,825'M) SCHEMATIC Soldotna Creek Unit Well: SCU 344-33 API: 50-133-20293-01-00 PTD: 218-054 Casing Detail Size WT I Grade j Conn ID Top I Btm 20" Surface 90' 13-3/8"]29 8 K-55 BTC 12.415" Surface 3,380' 9-5/8"7 5-95 BTS 8.681" Surface ±6,250'(TOW) 7" 6 L-80 DWC 6.151" ±6,050' 9,800' 7" L-80 DWC 6.059" 9,800' 11,385' JEWELRY DETAIL OPEN HOLE / CEMENT DETAIL 141 bbls of 15.8 ppg VariCem WELL INCLINATION DETAIL KOP @±6,250' Window Max Hole Angle = 27.8 deg. @ 6,981' MD Updated by DMA 07-26-18 K Hil." Alaska, LLC GL: 125.5' AMSL RKB -143.5' 20' 90' 1 13.3/8„ „r 3.380' i l Window h 2 ' cut at 6,250' 9-5/8" 6,250' t 4 3 5 5 7 ' PROPOSED SCHEMATIC CASING DETAIL Swanson River Field Well: SCU 344-33 PTD: 218-054 API: 50-133-20293-01 Size Type Wt Grade Conn Top Btm 20" Conductor - - - Surf. 90' 13-3/8" Surface 68 K-55 BTC Surf. 3,380' 9-5/8" Surface 47 S-95 BTS Surf. 6,250' 7" Production 26 L-80 DWC 6,050' 11,385' TUBING DETAIL Size Type Wt Grade Conn I ID I Top Btm 4-1/2" Tubing 12.6 L-80 HTGT 1 3.958" 1 Surf 1 10,510' H-1 H-2 H-3 H-4 H-5 H-7 H-9 7„ 4 u TD =11,385' MD / 10,914' ND PBTD =11,294' MD / 10,825' ND Max Deviation = 27.8' @ 6,981' JEWELRY DETAIL NO. Depth ID OD Item 1 320' 3.813" 4.5" X- Landing Nipple (Injection valve 2 6,250' H-2 ±10,859' 7" Liner top packer 3 10,644' 3.958" H-3 Anchor Latch Seal Assembly 4 10,645' S.0" 5.5" Seal Bore Receptacle 5 10,650' 3.958" 7.0" 7" x 4-1/2" Packer 6 10,663' 3.813" 4.5" X - Landing Nipple 7 10,672' 3.958" 4.5" WL Entry Guide PFRF(IRATIf1NS Zone To (MD) Btm(MD) Top(ND) Btm(ND) Date Notes H-1 ±10,843' ±10,859' ±10,120' ±10,135' Proposed H-2 ±10,859' ±10,882' ±10,135' ±10,156' Proposed H-3 ±10,882' ±10,903' ±10,156' ±10,175' Proposed H-4 ±10,903' ±10,942' ±10,175' ±10,212' Proposed H-5 ±10,942' ±11,002' ±10,212' ±10,268' Proposed H-7 ±11,028' ±11,096' ±10,293' ±10,358' Proposed H-9 ±11,148' 1 ±11,253' 1 ±10,409' 1 ±10,513' Proposed Updated by TWN 07-27-18 • lit Iii lil lil lil ltl [11 ; ; al lil l l lil Ill III III lit lit lit Swanson River Field SCU 344-33 Proposed 07/26/2018 nim et..t.. t.fa: Swanson River SCU 344-33 13 3/8 X9 5/8 X 4 1/2 Tree cap, Bowen, 41/16 5M FE X 7" stub acme Bowen Quick Union Valve, Swab, CIW-FLS, 41/16 SM FE, HWO, EE trim Valve, Upper Master, CIW-FLS, 4 1/16 5M FE, HWO, EE trim Valve, Master, CIW-FLS, 41/165M FE, HWO, DD trim Tubing head, Cameron DCB -S, 13 5/8 5M X 11 5M, w/ 2- 2 1/16 5M SSO Casing head Cameron WF, 13 5/8 5M X13 3/8 SOW, w/ 2- 21/165M EFO Tubing hanger, CIW-DCB- FBB, 11 x4 % EUE 8rd lift x 4 % IBT susp, w/ 4" type H BPV profile, 2-Y. non continuous control line, alloy material, 7" extended neck h a Ja y�SE, y5J J\`oQ Adapter, CIW-EN-2C4 115M stdd X 115M stdd, w/ 7" slick neck pocket and X npt chemical injection ports Valve, WKM-M, 21/165M FE, HWO, AA trim Q. QTY 2 Valve, CIW-F, 21/16 5M FE, HWO,AAtrim W. 1\E A U d .0 3 L r�� 4,.- —_ -cc U c U (7 0 O O_ d CL (L dy _ CL m M Q dN 2 C m L L a M � V Z 30 d a) Z CD rn c R L U d 3 v (D V 0 a` d R d R a V d N 0 ZO 0 `d d c B C W N c 0 1pR `d CL O m U N LL 5ce2 344-33 PrD 'Z160540 Regg, James B (DOA) From: Rance Pederson - (C) <rpederson@hilcorp.com> Sent: Monday, July 16, 2018 8:40 PM To: Regg, James B (DOA) l Subject: Notice of BOP Closure on Hilcorp Rig 169 Attachments: Hilcorp Rig 169 Notice of BOP Use.docx Jim, please see the attached notice. We are currently at 6024' pulling out of hole for cement string. Appears we could not get away from casing with our directional BHA. Will test BOP components prior to trip in with cement string. Rance Pederson Drilling Foreman Soldotna Creek Unit Swanson River Field 907-776-6776 Notice of BOP Use • Date/Time: 7/16/2018 at 03:30 hrs. • Well: SCU 344-33 • Location: Swanson River Field, Pad 33-33 • PTD: 218-054 • Rig Name: Hilcorp 169 • Operator Contact: Rance Pederson at 907-776-6776 / rpederson@hilcorp.com • Operation Summary: Drilled 8 1/2" production hole to 6467' and with directional BHA, attempting to kick off after milling out window. Current mud weight was 9.8 ppg and in the process of being dusted up to 10 ppg for any anticipated Tyonek water flow. At 6467' gas units climbed to 1650 units then dropped down to 530 units. PVT showed 6 bbl gain over the course of 15-20 minutes. Driller picked up off bottom and shut down pumps to observe well. Slight flow was observed at flowline. DSM on tour made the decision to close the 11" annular and circulate through the auto choke and poorboy degasser, in case there would be another spike in gas. • Reason For BOPE Use: To circulate out any remaining gas, at or near surface. • Actions Taken: Driller closedannular, had crew open manual choke on mud cross, Driller opened choke HCR and pumped a total of 65 bbls taking returns at shakers via poorboy degasser, through fully open auto choke, and at kill rate of 47 spm/113 gpm. Vacuum degasser was turned on in pits to reduce any chance of re -circulating gas cut mud. After 65 bbls pumped, Driller shut down pumps and closed auto choke to monitor for any pressure build in casing or drill pipe. No pressure was observed. Auto choke was opened, no flow observed at shakers, annular was opened and no flow observed at wellbore. Driller then started pumps and crew continued to dust mud weight toward 10 ppg while sliding ahead, trying to get kicked off. Background gas dropped from 52 units to 15 units over the course of sliding 30' ahead. • Action To Be Taken: At this time, we are pulling out of hole for BHA change (cement string). Prior to tripping in hole with cement string, we will install test plug in wellhead and test 11" annular on our 4 %:" test joint at 250/3500 psi for 5 minutes each, then test our auto choke 2ta 50/1500. THE STATE °fALASKA GOVERNOR BILL WALKER Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission Re: Swanson River Field, Hemlock Oil Pool, SCU 344-33 Hilcorp Alaska, LLC Permit to Drill Number: 218-054 Surface Location: 1465' FSL, 1657' FEL, SEC. 33, T8N, R9W, SM, AK Bottomhole Location: 227' FNL, 553' FEL, SEC. 4, T7N, R9W, SM, AK Dear Mr. Myers: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax 907.276.7542 www.00gcc.olaska.gov Enclosed is the approved application for the permit to redrill the above referenced service well. 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 Hilcorp Alaska, LLC (Hilcorp) in the attached application, the following well logs are also required for this well: LWD triple -combo as specified in Hilcorp's geo-prog from kick-off points to total depth of the 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. 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, Hollis S. French 5 k Chair DATED this2-t day of May, 2018. ( STATE OF ALASKA ALA_,�A OIL AND GAS CONSERVATION COMMISa,ON PERMIT TO DRILL 20 AAC 25.005 AEIVED tAAY 0 3 2018 1 a. Type of Work: Drill ❑ Lateral ❑ Redrill ❑� • Reentry ❑ 11b. Proposed Well Class: Exploratory - Gas ❑ Stratigraphic Test ❑ Development -Oil ❑ Exploratory - Oil ❑ Development - Gas ❑ Service - WAG LJ Service - Disp ❑ Service- Ginj Q . Single Zone ❑� ' Service - Supply ❑ Multiple Zone ❑ 1c. Specify if well is proposed for: Coalbed Gas ❑ Gas Hydrates ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: Hilcorp Alaska, LLC 5. Bond: Blanket Q Single Well ❑ Bond No. 022035244 11. Well Name and Number: SCU 344-33 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 6. Proposed Depth: MD: 11,385' • TVD: 10,914' - 12. Field/Pool(s): Swanson River Field Hemlock Oil Pool - 4a. Location of Well (Governmental Section): Surface: 1465' FSL, 1657' FEL, Sec 33, T8N, R9W, SM, AK Top of Productive Horizon: 104' FNL, 633' FEL, Sec 4, T7N, R9W, SM, AK Total Depth: 227' FNL, 553' FEL, Sec 4, T7N, R9W, SM, AK 7. Property Designation: FEDA028990, FEDA028997 8. DNR Approval Number: N/A 13. Approximate Spud Date: 6/15/2018 ' 9. Acres in Property: 4960 Acres 14. Distance to Nearest Property: 4571'to nearest unit boundary 4b. Location of Well (Slate Base Plane Coordinates - NAD 27): Surface: x-345991 • y- 2462644- Zone -4 10. KB Elevation above MSL (ft): 143.5' GL / BF Elevation above MSL (ft): 125.5' 15. Distance to Nearest Well Open to Same Pool: 640'to SCU 41B-04 16. Deviated wells: Kickoff depth: 6,250 feet . Maximum Hole Angle: 27.8 degrees 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Downhole: 4693 Surface: 2401 11 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade I Coupling I Length MD TVD MD TVD (including stage data) 8-1/2" 7" 26# L-80 DWC/C 5,335' 6,050' 6,049' 11,385' 10,914' 792 ft3 W//.JDc+w P..' 2'SO KLA 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): 17,689' 17,660' N/A Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): 10,680' 10,678' 10,680' Casing Length Size Cement Volume MD TVD Conductor/Structural 90' 20" Driven 90' 90' Surface 3,380' 13-3/8" 1500 sx Class G 3,380' 3,380' Intermediate Production 11,350' 9-5/8" Slg 1 -1300 sx/Stg 2 - 2200 sx 11,350' 11,348' Liner Perforation Depth MD (ft): "See attached schematic for detail" Perforation Depth TVD (ft): "See attached schematic for detail** Hydraulic Fracture planned? Yes ❑ No ❑4 20. Attachments: Property Plat O BOP Sketch e Drilling Program Diverter Sketch Seabed Report 8 Time v. Depth Plot Drilling Fluid Program B Shallow Hazard Analysis 20 AAC 25.050 requirements B 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Monty Myers Authorized Name: Monty Myers Contact Email: mm ers(ftilcor .Com Authorized Title: Drilling Manager Contact Phone: 777-8431 Authorized Signature: Date: IS. 3.1 ) Commission Use Only Permit to Drill Number: �I(J "iiS 7` API Number: 7 / 5g_�gber �C Gz Permit Approval Date: _1 ee cover letter for other requirements. Conditions of approval: If box is checked, wmay not be used to explore for, test, or produce coalbed methane, as hydrates, or gas contained in shales : Other: rY, 3SGY) joi LW LeS� Samples req'd: Ye! ❑ No� Mud log req'd: Yes,❑No� 6„x,,1„ HzS measures: Yes V No ❑ Directional svy req'd: Yes LJv No ❑ C rJ (� ca. a. J �nSpacing exception req'd: Yes❑ No � Inclination -only svy req'dYes ❑ No Post initial injection MITreq'd: Yes�p/No ❑-)e- ':"'yQ LSoo�C0ca)(A)r� AG /f /f��/`` '11 '� �^+arv�f�l-o :�IiaM/ aAPPROVED BY 5 'Z e Approved by: COMMISSIONER THE COMMISSION Date: r lie, /'� �� Submit Form and ti rtn 10401 Revised 5 17 This permit i5 Valid for ,,p5 r t e royal per 20 0 g) Attachme_Oc Duplicate g /� ° R X 197 .rte szl iii I Hilcorp 5/3/2018 j Hilcorp Alaska, LLC Mont Myers P.O. Box 244027 Monty Anchorage, AK 99524-4027 Drilling Engineer Tel 907 777 8431 Email mmyers@hilcorp.com Commissioner Alaska Oil & Gas Conservation Commission 333 W. 71h Avenue Anchorage, Alaska 99501 Re: SCU 344-33 Dear Commissioner, SCU 344-33 is a gas injection well planned to be re -drilled in a North-easterly direction from the existing SCU 33-33 utilizing the existing casing program down to 6250' MD / 6249' TVD. At 6250' MD the parent wellbore will be sidetracked and new wellbore drilled penetrating several Hemlock targets. A 5135'x 8-1/2" open hole section is planned. A 7" 26# 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 2-7/8" production tubing string. Drilling operations are expected to commence approximately June 151h, 2018. - If you have any questions, please don't hesitate to contact myself at 777-8431 or Paul Mazzolini at 777-8369. Sincerely, Monty Myers Drilling Engineer Hilcorp Alaska, LLC Page 1 of 1 SCU-33-33 "'99010,399 II. d SCU_ 41 B-04 7o 9� SC _3iftI4 341 ,051 615 SCU 4. 3 � m _ U 4 33 7 a w J 41A-04 SCU-42-04 SCUr 14-34 �o �7 ' 'o U_12JS03 :U 12-03 U H&.,. Alnxke, I.LC / 10K, Hilcorp Alaska Swanson River SCU 343-33 Gas Injector 1/4 Mile Radius Map REMARKS Top of Hemlock Bench 1 in Red; base of Hemlock Bench 9 shown in Blue. All depths are in MD. o saa i ooa i s00 FEET Area of Review SCU 322C-04 o (= CBL Top of CBL Top of Tap of H3 Top of H3 Base of H9 Base of H9 Cement Cement PTD API WELL STATUS (MD) (TVD) (MD) (TVD) (MD) (TVD) Hl/H9 Status Zonal Isolation CBL malfunctioned. 2nd Perfed & 160-036 50-133-10165-00-00 SCU 34-33 P&A 10308 10307 10720 10720 »"8,017 7,860 Stage DV collar located at Abandoned 8017ft md. Perfs in H6, H7, 212-143 50-133-20237-01-00 SCU 44-33 Suspended 11521 10285 12325 10698 9,250 8,990 H7L, and H9 Perfs in H1, H2, 214-054 50-133-10170-01-00 SCU 448-33 Online 10591 10294 11266 10720 9,544 9,400 H3, H5, H7, and H9 Perfs in H1, H7, 214-177 50-133-10109-03-00 SCU 41B-04 Online 10399 10321 10859 10707 9,784 . 9,580 and H9 Perfed & 159-014 50-133-10109-00-00 SCU 341-04 P&A 10231 10231 10615 10615 5,820 5,650 Abandoned Perfed & 213-028 50-133-10109-02-00 SCU 41A-04 P&A 10252 10231 10668 10627 9,600 9,415 Abandoned o (= Please see below for reason to inject gas over water. ✓ The proposed gas flood within the AOR is targeting a combination stratigraphic / fault trap that didn't get effectively swept during the Swanson River gas flood resulting in high residual oil saturations. This area is connected to an extremely weak aquifer with diminishing rock quality going down dip thereby providing minimal energy to sweep the remaining oil. Both gas and water injection were evaluated for secondary recovery efficiency and gas injection was chosen for these reasons: 1) Good analog of historic gas flood at Swanson River resulting in >40% recovery factor in fault blocks with sufficient well density. 2) Technical analysis indicates that the swelling effect from gas contact recovers over 25% more oil than water. 3) Permeability is known to be decreasing down dip & injectivity of water is expected to be low. Gas injection in the lower perm rock will enable injection of sufficient reservoir barrels to support offset producers. 4) High pressure gas injection infrastructure is currently in place on pad resulting in minimal disturbance to the refuge. K Ililc.q, .Al.kn, LLA. 6.0 Planned Wellbore Schematic SCU 344-33 Drilling Procedure Rev 0 Soldotna Creek Unit Well: Well: SCU 344-33 Proposed SCHEMATIC API: TBD ... ... PTD: TBD Rig 169 RI®: 143.W/GLElev_ 175.50' Casing Detail Size WT Grade 1 Conn ID Top .Alin 20" - 5o ace 99 13.3/8 1 68 I K-55 I BTC 1 12.015 Surface 3,38 9-5/8" 47 5-95 BTS 8.681' So ace i6,2 OW T 1 26 1 L- DWC 1 6.151" ±6,059 11,385 JEWELRY DETAIL No. I Top MD I Item ID 1 I ±6,059 I rimer Top Packer 33 S OPEN HOLE /CEMENT DETAIL 8-1/2" 1 141bbIsof25.8ppgvaNCem WELL INCLINATION DETAIL / SOD p @o±.6f Wndw MMaHe27.8d 2g.@6,981'MD TSG � r 1%,yKT►7 TD=11,385 (MD) / TD =to91e(T W PBTD=11294'(MDJ /P8TD=3o,825TrWI Page 6 Revision 0 May 2018 Soldotna Creek Unit Well SCU 33Ra Completion n:2/13/16 SCHEMATIC PTD: 176-056 flilearo Alaska. LLC API: 50-133-20293-00 RKB: 153'/ GL: 125' MSL Orig RKB: 17'/ New RKB: 17.45' MAX HOLE ANGLE= 2 deg. @ 6,100' CASING DETAIL Size WT e Conn ID Top Btm 20" 16' 10,352' 10,508' 3-1/2" x 2-7/8" Crossover Surface 90' 13-3/8" 68 EK -55 BTC 415" [;8.681' Surface 3,380' 2.441" 47 2-7/8" SFO -1 GLM #1(w/ Orifice) BTS 2.441" Surface 6,295' 9 5/8 53.5 6.937" BTS 535" 6,295' 11,350' TUBING 2-7/8" 6.5 1 L-80 I 8RD EUE 1 2.441" 1 Surface 10,464' �w�ykt� JEWELRY DETAIL Depth ID OD Item 15' 2.441" 3.5" 3-1/2" Tubing Hanger 16' 10,352' 10,508' 3-1/2" x 2-7/8" Crossover 4,605' 2.441" 2.875" 2-7/8" SFO -1 GLM #3 (Live Valve) 8,018' 2.441" 2.875" 2-7/8" SFO -1 GLM #2 (Live Valve) 10,259' 2.441" 4.750" 2-7/8" SFO -1 GLM #1(w/ Orifice) 10,309' 2.441" 4.679" 2-7/8" Chemical Injection Mandrel (3/8" Control line to surface) 10,319' 2.441" 6.937" S-22 Snap Latch assembly (with seals) 10,321' 6.000" 8.218" Baker"F-1" 190-60 Retainer Production Packer (Set 10-03-11) 10,427' 2.313" 3.679" X Landing Nipple 10,464' 2.441" 3.679" WL Entry Guide SCt4 3&1K' 33 PERFORATIONS Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Comments Date 10,476' 10,510' 10,352' 10,508' 34' 4-5/8" Millennium 5spf 9/19/2011 10,476' 10,510' 10,352' 10,508' 34' 4.5/8" Millennium 5spf 10/2/1011 e 10,478' 10,510' 10,476' 10,508' 32' Re-perf 8/6/01 1/3/2001 e 10,510' 10,512' 10,508' 10,510' 2' Re-perf 8/6/01; 8/31/09 1/3/2001 e 10,512' 10,544' 10,510' 10,542' 32' 8/31/2009 10,553' 10,586' 10,551' 10,584' 33' 4-5/8" Millennium 5spf 9/29/2011 10,553' 10,586' 10,551' 10,584' 33' 4-5/8"Millennium Sspf 10/2/2011 10,562' 10,588' 10,560' 10,586' 26' Re-perf 2/20/86 1/29/1977 10,588' 10,602' 10,586' 10,586' 14' 8/31/2009 10,592' 10,624' 10,590' 10,622' 32' 4-5/8" Millennium 5spf 9/29/2011 10,592' 10,624' 10,590' 10,622' 32' 4-5/8" Millennium 5spf 10/2/2011 10,610' 10,628' 10,608' 10,626' 18' Re-perf 2/20/86 1/31/1977 10,638' 10,643' 10,636' 10,641' 5' 4-5/8" Millennium 5spf 9/29/2011 10,638' 10,643' 10,636' 10,641' 5' 4-5/8" Millennium 5spf 10/2/2011 10,640' 10,645' 10,638' 10,643' S. Re-perf 2/20/86 1/31/1977 5 10,648' 10,679' 10,646' 10,677' 31' 4-5/8" Millennium 5spf 9/29/2011 5 10,648' 10,679' 10,646' 10,677' 31' 4-5/8" Millennium 5spf 10/2/2011 10,651' 10,658' 10,649' 10,656' 7' Re-perf 2/20/86 1/31/1977 10,658' 10,665' 10,656' 10,663' 7' 2/20/1986 10,670' 10,680' 10,668' 10,678' 10' 2/20/1986 10,680' 10,702' 10,678' 10,700' 22' Re-perf 2/20/86 1/26/1977 10,702' 10,710' 10,700' 10,708' 1 8' 1 Re-perf 1/26/77; 2/20/86 1/17/1977 10,710' 10,712' 10,708' 10,710' 1 2' 1 Re-perf 2/20/86 1/17/1977 Downhole Revised: 2/16/16 Updated by DMA 06-17-16 Hilcorp Alaska, LLC SCU 344-33 (SCU 33-33 ST) Drilling Program Soldotna Creek R ro d by: M096E My s Revision 0 May 1, 2018 SCU 344-33 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 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 8-1/2" Hole Section...............................................................................................................19 15.0 Run 7" Production Liner..............................................................................................................22 16.0 Cement 7" Production Casing......................................................................................................25 17.0 Wellbore Clean Up & Displacement............................................................................................29 18.0 Run Completion Assembly...........................................................................................................30 19.0 RDMO............................................................................................................................................30 20.0 BOP Schematic..............................................................................................................................31 21.0 Wellhead Schematic......................................................................................................................32 22.0 Days vs Depth.................................................................................................................................33 23.0 Geo -Pro 24.0 Anticipated Drilling Hazards.......................................................................................................36 25.0 Rig Layout......................................................................................................................................37 26.0 FIT Procedure................................................................................................................................38 27.0 Choke Manifold Schematic...........................................................................................................39 28.0 Casing Design Information...........................................................................................................40 29.0 8-1/2" Hole Section MASP............................................................................................................41 30.0 Plot (NAD 27) (Governmental Sections)......................................................................................42 31.0 Surface Plat (As Built) (NAD 27).................................................................................................43 32.0 Surface Plat (As Built) (NAD 83).................................................................................................44 33.0 Directional Program(WP06)........................................................................................................45 K lfa.q AI.A., U.0 1.0 Well Summary SCU 344-33 Drilling Procedure Rev 0 Well SCU 344-33 Pad & Old Well Designation Sidetrack of existing well SCU 33-33 PTD# 176-056 Planned Completion Type 7" 26# L-80 Liner Target Reservoir(s) Hemlock H1 through H4 Injection Planned Well TD, MD / TVD 11385' MD / 10914' TVD PBTD, MD / TVD 11294' MD / 10825' TVD Surface Location (Governmental) 1465' FSL, 1657' FEL, Sec 33, T8N, R9W, SM, AK Surface Location (NAD 27) X=345991.06, Y=2462644.03 - Surface Location (NAD 83) X=1486013.96, Y=2462405.31 Top of Productive Horizon (Governmental) 104' FNL, 633' FEL, Sec 4, T7N, R9W, SM, AK TPH Location (NAD 27) X=346995.01, Y=2461067.02 TPH Location (NAD 83) X=1487017.90, Y=2460828.25 BHL (Governmental) 227' FNL, 553' FEL, See 4, T7N, R9W, SM, AK BHL AD 27 X=347073.98, Y=2460942.71 BHL AD 83) X=1487096.87, Y=2460703.94 AFE Number 1812067D AFE Drilling Das 30 AFE Drilling Amount $4.00 MM Work String 4-1/2" 16.6# S-135 CDS-40 RKB — AMSL 18' KB — 143.5' AMSL Ground Elevation 125.5' AMSL BOP Equipment 11" 5M Townsend Type 90 Annular BOP 11" 5M Townsend Type 82 Double Ram 11" 5M Townsend Type 82 Single Ram Page 2 Revision 0 May 2018 U nihorp U.A.. H.1: 2.0 Management of Change Information SCU 344-33 Drilling Procedure Rev 0 H ilcorp Hilcorp Alaska, LLC .C- -ft Changes to Approved Permit to Drill Date: May 2, 2018 Subject: Changes to Approved Permit to Drill for SCU 344-33 File #: SCU 344-33 Drilling Program Any modifications to SCU 344-33 Drilling Program will be documented and approved below. Changes to an approved APD will be communicated and approved by the AOGCC prior to continuing forward with work. Approval: Monty M Myers Drilling Manager Date Prepared: Drilling Engineer Date Page 3 Revision 0 May 2018 3.0 Tubular Program SCU 344-33 Drilling Procedure Rev 0 8-1/2" 1 7" 1 26 1 7.656" 1 6.276 6.15 1 DWC/C 6050 11385 1 I I I I 4.0 Drill Pipe Information Hole ,Section OD (in) ID (in) TJ ID TJ OD in Wt "t Grade Conn Burst (psi)(psi)(k-lbs) Ila e len"sion 8-1/2" 4-1/2" 3.826 2-11/16" 5-1/4" 16.6 5-135 CDS-40 17693 167 595k All easing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Revision 0 May 2018 H Ilff.,p AL.A., LIA: 5.0 Internal Reporting Requirements SCU 344-33 Drilling Procedure Rev 0 18.1 Fill out daily drilling report and cost report on Wellez. i. Report covers operations from 6am to 6am ii. 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. iii. Ensure time entry adds up to 24 hours total. iv. Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. 18.2 Afternoon Updates i. Submit a short operations update each work day to pmazzolinina hilcorp.com, mmyers@hilcoip.com and cdin er hilcorp.com 18.3 Intranet Home Page Morning Update i. 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. 18.4 EHS Incident Reporting i. 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 Outl I 1 I 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: 0:907-777-8477 C:907-350-9439 ii. Notify Drlg Manager 1. Monty M Myers: O: 907-777-8431 C: 907-538-1168 iii. Submit Hilcorp Incident report to contacts above within 24 hrs 18.5 Casing Tally i. Send final "As -Run" Casing tally to mmyersna hilcoM.com and cdinger@hilcorp.com 18.6 Casing and Cmt report i. Send casing and cement report for each string of casing to mm, ers 2 hilcoip.com and cdinizer@hilcgo.com Page 5 Revision 0 May 2018 U Oik.,p AWkn TAA[ 7.0 Drilling Summary SCU 344-33 Drilling Procedure Rev 0 SCU 344-33 is a gas injection well planned to be re -drilled in a North-easterly direction from the existing SCU 33-33 utilizing the existing casing program down to 6250' MD / 6249' TVD. At 6250' MD the parent wellbore will be sidetracked and new wellbore drilled penetrating several Hemlock targets. A 5135' x 8-1/2" open hole section is planned. A 7" 26# 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 2-7/8" production tubing string. Drilling operations are expected to commence approximately June 15s', 2018. 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. MOB Saxon Rig #169 to SCU 33-33. 2. Kill well, Set BPV ND tree, NU BOPE and test. 3. BOLDS, Pull hanger and LD 2-7/8" tubing completion. 4 4. RU E -line to set CIBP. RIH w/ CIBP and set at 6279' (5' above a collar) 5. RD E -line and test casing/CIBP to 3500 psi 6. PU 8.5" window milling assembly and DP and cleanout to CIBP 7. POOH standing back, PU Whipstock, and mills and TIH to CIBP 8. Orient whipstock and set at 4S deg azr. Mill 8-112" window and 2U' oI new Iorm 9. Perform FIT to 11.5 ppg 10. Drill 8-1/2" production hole from 6250' to 11385' MD. ',�✓ 11. Perform short trip and condition mud. POOH 12. LD Directional Tools. RIH w 7" liner. Set liner and cement. Circ wellbore clean. 1 13. POOH, laying down DP and liner running tools, 14. PU 7" casing scraper assembly and TIH to landing collar. 15. Circ casing clean. POOH laying down DP. 16. Run 2-7/8" upper completion. Land hanger and test. 17. ND BOPE, NU tree and test void 18. RDMO Page 7 Revision 0 May 2018 K nil~p Al.k., LIX SCU 344-33 Drilling Procedure Rev 0 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC 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. • BOPs shall be tested at (2) week intervals during the drilling of SCU 344-33. Ensure to provide AOGCC 24 Ins notice prior to testing BOPS. • 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. • 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. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system" • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements" • Ensure both AOGCC and BLM approved drilling permit is posted on the rig floor and in Co Man office. Variance Requests: • 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. The calculated MASP for this wellbore when completely evacuated to gas is 3601 psi. However, for Swanson River (Hemlock), we assume that the well can never flow 100% gas, due to the water in the reservoir. We reduce this MASP calculation to 2401 psi which assumes that only 2/3 of the wellbore is evacuated to gas and 1/3 to 8.3 ppg reservoir fluid. Page 8 Revision 0 May 2018 H Hilrvrp M.A., LLC Summary of BOP Equipment and Test Requirements SCU 344-33 Drilling Procedure Rev 0 Hole Section Equipment Test Pressure(psi)_ • 1 I" x 5M Townsend Annular BOP Initial Test: 250/3500 • 11" x 5M Townsend Double Ram (Annular 2500 psi) o Blind ram in hurt cavity • Mud cross 8-1/2" • 11" x 5M Townsend Single Ram Subsequent Tests: • 3-1/8" 5M Choke Line 25ar 500 • 2-1/16" x 5M Kill line (Annular 2500 psi) • 3-1/8" x 2-1/16" 5M Choke manifold • Standpipe,p floor valves, etc • Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). • Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: Well control event (BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPS. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Required BLM Notifications: • 48 hours before spud. Follow up with actual spud date and time. • 48 hours before casing running and cmt operations • 48 hours before BOPE tests • 48 hours before logging, coring, & testing • Any other notifications required in APD. Additional requirements may be stipulated on APD. Page 9 Revision 0 May 2018 n Ilil.p.Alarka, LLC Regulatory Contact Information: SCU 344-33 Drilling Procedure Rev 0 AOGCC Jim Regg / AOGCC Inspector / (0): 907-793-1236 / Email: jim.reglagalaska.gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: g_uy.schwartz@alaska.gov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / Email: melvin.rixse@alaska.gov Victoria Loepp / Petroleum Engineer/ (0): 907-793-1247 / Email: victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors cni alaska.eov Test/Inspection notification standardization format: hiip://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 / (0): 907-271-3266 (C): 907-538-2300 Email: aeajzle@blm.gov Mutasim Elganzoory / BLM Petroleum Engineer / (0): 907-271-4224 Email: melganzoory@blm.gov Use the below email address for BOP notifications to the BLM: BLM AK AKSO EnergySection Notifications nnblm.gov Page 10 Revision 0 May 2018 H Ililmrp Alaska, LIX 9.0 R/U and Preparatory Work SCU 344-33 Drilling Procedure Rev 0 9.1 A separate sundry will be submitted that will include the following: • P&A lower perfs with a cement plug • Pull tubing 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 Saxon Rig #169, 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 8-1/2" 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. • 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. Page 11 Revision 0 May 2018 H nil.q Alu.ku, LIX 10.0 BOP N/U and Test SCU 344-33 Drilling Procedure Rev 0 10.1 * BOPE was NU and tested on prior decompletion sundry. We will test BOPE on 7 day cycle ✓ until the window is milled, at that point we will switch to the 14 day test cycle. Continue on to step 11. 10.2 N/U 11"x 5M BOP as follows: • 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. • Double ram should be dressed with 2-7/8" x 5" VBR in top cavity, blind ram in btm cavity. • Single ram should be dressed with 2-7/8" x 5" VBR. • N/U bell nipple, install flowline. 10.3 Run BOP test assy, land out test plug (if not installed previously). • Test BOP to 25 /p 3�psi for 10/10 min. Test annular to 250/2500 psi for 10/10 min. p • Ensure to leave "A" section side outlet valves open during BOP testing so pressure does not 4�V / build up beneath the test plug. Confirm the correct valves are opened! ! ! • Test VBRs on 4-1/2" test joint. • Ensure gas monitors are calibrated and tested in conjunction w/ BOPE. 10.4 R/D BOP test assy. 10.5 Continue mixing mud for 8-1/2" hole section. 10.6 Set wearbushing in wellhead. Ensure ID of wearbushing > 8.5". Page 12 Revision 0 May 2018 H Inlmrp AI.A., LIA: 11.0 Mud Program and Density Selection Criteria 11.1 8-1/2" Production hole mud program summary: SCU 344-33 Drilling Procedure Rev 0 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 1 ppg 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: 9.5 ppg 6% KCl/PHPA fresh water based drilling fluid. Properties: r� MDDensity Viscosity Plastic Viscosity Yield Point pH API Fluid Loss 11335'kl 9.5-11.5 40-53 15-25 15-25 8.5-9.5 <-6.0 System Formulation: 6% KCI / EZ Mud DP Product Concentration Water 0.905 bbl KCl 22 ppb (29 K chlorides) Caustic 0.2 ppb (9 pH) BARAZAN D+ 1.25 ppb (as required 18 YP) EZ MUD DP 0.75 ppb (initially 0.25 ppb) DEXTRID LT 1-2 ppb PAC -L 1 ppb BARACARB 5/25/50 10-20 ppb BAROTROL PLUS 2 ppb SOLTEX 2 ppb (if needed) BAROID 41 as required for a 9.5 —10.5 ppg ALDACIDE G 0.1 ppb BARACOR 700 1 ppb BARASCAV D 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. Page 13 Revision 0 May 2018 12.0 Whipstock Running Procedure SCU 344-33 Drilling Procedure Rev 0 12.1 M/U window milling assembly and TIH w/ 4-1/2" DP off of pipe rack. • Use a 8-1/2" taper mill and a 8-1/2" string mill above to ensure whipstock assy will pass freely. • Ensure BHA components have been inspected previously. • Caliper and drift all BHA components before running them in the hole. • Drift DP prior to RIH. • Lightly wash and ream any tight spots noted. 12.2 TIH to CIBP (6279' 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 2500 psi / 30 min. Chart record casing test & keep track of the amount of fluid pumped. Stage up to 2500 psi in 500 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 Makeup mills on a joint of HWDP. 12.7 RIH & set in slips. 12.8 Make up float sub, install float. 12.9 Make up UBHO sub. 12.10 Orient UBHO to starter mill. 12.11 Leave assembly hanging in the elevators, and stand back on floor. 12.12 Bring Whipstock to rig floor on the pipe skate. Do not slam into bottom of Whipstock with pipe skate. 12.13 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 with (1) 35k mill shear bolt. Page 14 Revision 0 May 2018 H Ilil. ,p Alaska, LLC SCU 344-33 Drilling Procedure Rev 0 12.14 If needed, open BOP Blinds. 12.15 Run the Whipstock in the hole, install safety clamp as per Baker Rep, and install hole cover wrap. 12.16 Release pick up system at this point, Make up mills. 12.17 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. 12.18 The assembly can now be picked up to ensure that the shear bolt is tight. 12.19 Remove the handling system. 12.20 Slowly run in the hole as per Baker Rep. Run extremely slow through the BOP & wear bushing. 12.21 Run in hole at 1 Yz to 2 minutes per stand. 12.22 Fill every 30 stands or as needed, do not rotate or work the string unnecessarily. 12.23 Call for Baker Rep. 15 — 10 stands before getting to bottom. 12.24 Orient at least 30' — 45' above the CIBP. Ensure to have gyro personnel and equipment as well as a wireline unit R/U and ready. Page 15 Revision 0 May 2018 SCU 344.33 Drilling Procedure Rev 0 WindowMaster G2 System on TorqueMaster BTA b Window Master G2 Whipstock N'•• With Torque Master Bottom Trip Anchor BAKER NucHEs 9.625 53.5# Non Special Drift Casing Baker Oil Tools Retrieval BTA 1 7.13 Upper Watermelon Mill OD: 8 000 OD: 8.500 F8-500 Face Angle: F 6.25 Length: 6.25 WELL INFORMATION Flex Joint 77.08 FIELD 8.000 LEASE OD: 6.375 WELL NO. Length: 9.00 6.375 9.00 Lower watermelon Mill OD: 8 375 Length: 5.66 Window Mill 00 8.500 8.250 5.66 Length. 7.73 8.500 Retrieval BTA 1 7.13 Whipstock OD: 8 000 Length: 78.54 Face Angle: 0 WELL INFORMATION Face Length: 77.08 F-3 47 8.357 —► �— CONNECTIONS ON TUBULARS ARE SUBJECT TO CHANGE BHA'S SHOW SPECIFIC CONNECTIONS AS AN EXAMPLE ONLY Page 16 Revision 0 May 2018 Retrieval BTA OD: 8.357 Length: 3.41 0Overall length A -'Length: 44' —► WELL INFORMATION CUSTOMER FIELD 8.000 LEASE WELL NO. F-3 47 8.357 —► �— CONNECTIONS ON TUBULARS ARE SUBJECT TO CHANGE BHA'S SHOW SPECIFIC CONNECTIONS AS AN EXAMPLE ONLY Page 16 Revision 0 May 2018 H rril,u,p .Al.ka, LLC 13.0 Whipstock Setting Procedure SCU 344-33 Drilling Procedure Rev 0 13.1 With the bottom of the Whipstock 30 — 45' above the CIBP, measure and record P/U and S/O weights. We will orient Whipstock face using Gyro. Ensure that UBHO and gyro tool mate up properly before making up UBHO sub. 13.2 Orient Whipstock to desired direction by turning DP in'/4 round increments. P/U and S/O on DP to work all torque out (Being careful not to set BTA). Whipstock Orientation Diagram: 25 AZI 60 AZI Desired orientation of the Whipstock face is in 25 to 60 degrees azimuth. Hole Angle at window interval (6250' MD) is < 2 deg. The wellbore trajectory is also planned to 147 degrees azimuth. Highside of the casing at 6250' is negligible. 13.3 Once Whipstock is in desired orientation, 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). ri A 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 wl 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. Page 17 Revision 0 May 2018 H Ilil.o p Alaska, LI.0 13.10 Estimated metal cuttings volume from cutting window: SCU 344-33 Drilling Procedure Rev 0 9-5/8- 3'/z REG -P X MILL 47# N-80 Cuttings Weight Window 3'/= IF -13 X 3'/z REG -B 5.5 6.5 FLEX JOINT Length Casing Weight Min (Ibs) Avg (Ibs) Max (Ibs) 16 47# 290 300 321 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 11.5 ppg EMW. • (11.5 — 9.5) * 0.052 * 6249' tvd = 650 psi 13.14 Kick Tolerance • (11.5 -9.5) * (6249/10914)=1.15I� Note: Offset field test data predicts frac gradients at the window to be between 12 ppg and 15 ppg. A 11.5 ppg FIT results in a 1.15 ppg kick tolerance while drilling the interval with a 9.5 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 Un Mills Connection Length O.D. WINDOW MILL 3'/z REG -P X MILL 0.98 6.63 NEW LOWER WATERMELON MILL 3'/= IF -13 X 3'/z REG -B 5.5 6.5 FLEX JOINT 3'/z IF -B X V/2 IF -P 6.5 4.75 UPPER WATERMELON MILL 3'/i' IF -13 X V/2" IF -P 5.83 6.63 FLOAT SUB 3%" IF -B X 3'/" IF -P 3.00 4.75 XO sub and 30 'ts-HWDP 4'/z' CDS40-B X 3'/s' IF -P 900' 5.25 CONNECTIONS ON TUBULARS ARE SUBJECT TO CHANGE. BHA'S SHOW SPECIFIC CONNECTIONS AS AN EXAMPLE ONLY! Page 18 Revision 0 May 2018 N 110c q M.A.. LIA: 14.0 Drill 8-1/2" Hole Section SCU 344-33 Drilling Procedure Rev 0 14.1 Ensure that the managed pressure drilling (MPD) system is rigged up and functional prior to drilling through the high pressure Tyonek water sands in this area. We expect to encounter the sand at approximately 9,380' TMD (8,907' TVD). 14.2 P/U 8-1/2" directional drilling assy. 14.3 Ensure BHA Components have been inspected previously. 14.4 Drift & caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 14.5 Ensure TF offset is measured accurately and entered correctly into the MWD software. 14.6 Confirm that the bit is dressed with a TFA of 0.557 — 0.663 sgin. Have DD run hydraulics models to ensure optimum TFA. We want to pump at 300 - 450 gpm. 14.7 Motor AKO should be set at 1.2 deg. Must keep up with 4 deg/100 DLS in the build section of the wellbore. 14.8 Primary bit will be the HDBS 8-1/2" MM75DC PDC bit. Ensure to have a back up bit available on location. Page 19 Revision 0 May 2018 H IIihaq, 1l.Aa.. LIA: SCU 344-33 Drilling Procedure Rev 0 Cutter Type IADC Code Body Type Total Cutter Count Cutter Distribution Number of Small Nozzles Junk Slot Area (Sq in) Normalized Face Volume API Connection Recommended Make -Up Torque' Nominal Dimensions" Make -Up Face to Nose Gauge Length Shank Diameter Break Out Plate (Mat.#/Legacy#) Approximate Shipping Weight Select Cutter M422 MATRIX 65 13mm 16mm Face 0 46 Gauge 0 12 Up Drill 7 0 Special Features • EDL Tool Specific Gage • Carbide Impact Arrestor • Optimized Dual Row - "D" Feature • Combo Cutters on Gage Pads 7 12.75 41.24% 4-1/2 REG. PIN 12,461 —17,766 Ft -lbs 11.42 in - 290 mm Sin -76 mm 6in-152 mm 181954144040 180 Lbs. - 82 Kg. r�iL��g�i�iT IC! Material # 1033603 Page 20 Revision 0 May 2018 H llilc.q M.A., I.IA: 14.9 TIH to window. Shallow test MWD on trip in. SCU 344-33 Drilling Procedure Rev 0 14.10 TIH through window, ensure Halliburton MWD service rep on rig floor during this operation. • Do not rotate string while bit is across face of Whipstock. 14.11 Drill 8-1/2" hole to 11385' MD using motor assembly. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Utilize ECD while pumping to minimize waterflow from Tyonek sands • Utilize MPD to minimize Tyonek water flow • On trips spot weighted pills inside window and hi vis pills at TD to control waterflow • Try to keep waterflow below 10 bph while tripping • 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. • Keep swab and surge pressures low when tripping. • See attached mud program for hole cleaning and LCM strategies. • Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. • Adjust MW as necessary to maintain hole stability. • Ensure mud engineer set up to perform HTHP fluid loss. • Maintain API fluid loss < 6. • Take MWD surveys every stand drilled. • Minimize backreaming when working tight hole 14.12 Hilcorp Geologists will follow mud log closely to determine exact TD. 14.13 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. 14.14 TOH with drilling assembly, handle BHA as appropriate. Page 21 Revision 0 May 2018 15.0 Run 7" Production Liner SCU 344-33 Drilling Procedure Rev 0 15.1 R/U Weatherford 7" casing running equipment. • Ensure 7" DWC/C x 4-1/2" CDS-40 crossover on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • Ensure all casing has been drifted and tally verified prior to running. • Be sure to count the total # of joints before running. • Keep hole covered while R/U casing tools. • 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: • (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). • (1) Baker locked joint. • (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). • (1) Joint with landing collar bucked up. • Solid body centralizers will be pre-installed on shoe joint, FC joint, and LC joint. • Install solid body centralizers, one per joint, and leave centralizers free floating so that they can slide up and down the joint. • Ensure proper operation of float shoe & FC. 15.4 Continue running 7" production liner • Fill casing while running using fill up line on rig floor. • Use "API Modified" thread compound. Dope pin end only w/ paint brush. • Install solid body centralizers on every other joint to window. Leave the centralizers free floating. Utilize a collar clamp until weight is sufficient to keep slips set properly. 7" DWC/C NIX torques Casing OD Minimum Maximum Yield Torque 7" 19,200 ft -lbs 1 22,100 ft -lbs 25,000 ft -lbs Page 22 Revision 0 May 2018 Technical Specifications Connection Type: Size(O.D.): DWC/C Casing 7 in 2012 API SPEC 5CT COUPLING O.D. API Joint Strength (lbs.) Material L-80 Grade 80,000 Minimum Yield Strength (psi.) 95,000 Minimum Ultimate Strength (psi.) Maximum Uniaxial Bend Rating [degrees/100 ft] Pipe Dimensions 7.000 Nominal Pipe Body O.D. (in.) 6.276 Nominal Pipe Body I.D. (in.) 0.362 Nominal Wall Thickness (in.) 26.00 Nominal Weight (lbs./ft.) 25.69 Plain End Weight (lbs./ft.) 7.549 Nominal Pipe Body Area (sq. in.) Pipe Body Performance Properties 604,000 Minimum Pipe Body Yeld Strength (lbs.) 5,410 Minimum Collapse Pressure (psi.) 7,240 Minimum Internal Yield Pressure (psi.) 6,600 Hydrostatic Test Pressure (psi.) Connection Dimensions 7.875 Connection O.D. (in.) 6.276 Connection I.D. (in.) 6.151 Connection Drift Diameter (in.) 4.50 Make-up Loss (in.) 7.549 Critical Area (sq. in.) 100.0 Joint Efficiency (%) Connection Performance Properties SCU 344-33 Drilling Procedure Rev 0 Weight (Wall): 26.00 Ib/ft (0.362 in) 604,000 Joint Strength (lbs.) 16,590 Reference String Length (ft) 1.4 Design Factor 641,000 API Joint Strength (lbs.) 302,000 Compression Rating (lbs.) 5,410 API Collapse Pressure Rating (psi.) 7,240 API Intemal Pressure Resistance (psi.) 26.2 Maximum Uniaxial Bend Rating [degrees/100 ft] Approximated Field End Torque Values 18,300 Minimum Final Torque (ft.4bs.) 21,100 Maximum Final Torque (ft. -lbs.) 23,800 Connection Yield Torque (ftAbs.) -USA Grade: L-80 VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston, TX 77041 Phone: 713-479-3200 Fax: 713-479-3234 E-mail: VAMUSAsalesOvam-usa.com Page 23 Revision 0 May 2018 SCU 344-33 Drilling Procedure Rev 0 15.7 Ensure to run enough liner to provide for approx 200' overlap inside 9-5/8" casing. Ensure hanger/pkr will not be set in a 9-5/8" 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 9-5/8" 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 curt 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 24 Revision 0 May 2018 16.0 Cement 7" Production Casing SCU 344-33 Drilling Procedure Rev 0 • Cement will be mixed using batch mixer to ensure consistent density 16.1 Hold a pre job safety meeting over the upcoming cmt operations. 16.2 Attempt to reciprocate the casing during cmt operations until hole gets sticky. 16.3 Pump 15 bbls 12.5 ppg spacer. 16.4 Test surface curt lines to 4500 psi. 16.5 Pump remaining 10 bbls 12.5 ppg spacer. 16.6 Mix and pump 141 bbls of 15.3 ppg class "G" cmt per below recipe with 2 lbs/bbl of loss circulation fiber. Ensure curt is pumped at designed weight. Job is designed to pump 25% OH excess but if fluid caliper dictates otherwise we may increase excess volumes. Cement volume is designed to bring cement to 6,500' TMD in annulus between 7" casing and 8-1/2" hole. 16.7 Displacement fluid will be drilling mud. —83 bbls of displacement fluid Cement Calculations 8-1/2" OH x 7" Liner: (11385' — 6500') x 0.02259 x 1.25 = 138 bbls Shoe Track: 80' x 0.03715 = 3 bbls Total Volume (bbls): 138 + 3 = 141 bbls Total Volume (ft3): 141 bbls x 5.615 ft3/bbl = 792 ft3 Total Volume (sx): 792 113 / 1.34 ft3/sk =591 sx Page 25 Revision 0 May 2018 V/ U I &.q .Akuk,LIA: Slurry Information: SCU 344-33 Drilling Procedure Rev 0 System VariCEM Density 15.3 lb/gal Yield 1.34 ft3/sk w Mixed Water 5.879 gal/sk Mixed Fluid 5.879 gal/sk Expected Thickening 70 Be 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 9.5 ppg drilling mud. 16.9 Pump cement at max rate of 5 bbl/min. Reduce pump rate to 3 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''/2 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 Page 26 Revision 0 May 2018 H Ililmrp Aloka, I.IA: 16.15 Bleed pressure to zero to check float equipment. SCU 344-33 Drilling Procedure Rev 0 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 27 Revision 0 May 2018 U nil.rp Alaska, LIX. SCU 344-33 Drilling Procedure Rev 0 Ensure to report the following on Wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure • Note if pre flush or cement returns at surface & volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the successor problems during the cement job Note: Send Csg & cmt report+ "As -Run " liner tally to mmyers9,hilcorp.com Page 28 Revision 0 May 2018 n ❑ilrorp Alaska, LIA: 17.0 Wellbore Clean Up & Displacement SCU 344-33 Drilling Procedure Rev 0 17.1 M/U casing clean out assy complete with casing scraper assys for each size casing in the hole. • 6-1/8" bit or mill • Casing scraper & brush for 7" 26# casing • +/- 5244' 4-1/2" DP. • Casing scraper & brush for 9-5/8" 47# casing • (2000') 4-1/2" DP • Casing scraper & brush for 9-5/8" 47# casing • 4-1/2" DP to surface. 17.2 TIH & clean out well to landing collar (+/- 11,275' MD). • Circulate as needed on trip in if string begins to take weight. • Circulate hi -vis sweeps as necessary to carry debris out of wellbore. • Ensure 6-1/8" bit is worked down to the landing collar. • Space out the cleanout BHA so that the 6-1/8" bit reaches the 7" landing collar when crossover is +/- 30' above the 7" liner top. • The primary objective of the clean out run is to ensure the TCP assy will reach intended depth. y &4 U 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. • Catch drilling fluid in rain -for -rent tanks for use on a future well. • Circulate fresh water into wellbore until clean up is satisfactory. Do not recirculate fluid, • After a couple circulations using FW, short trip the assy to bring the upper 7" multi -back assy to surface. • RIH again & tag landing collar w/ 6-1/8" bit. Continue circulation as necessary until fluid cleans up. Make another short trip if necessary. • 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 4-1/2" work string. Page 29 Revision 0 May 2018 18.0 Run Completion Assembly 18.1 Run 2-7/8" tubing as per separate Approved Completion Sundry 19.0 RDMO 19.1 Install BPV in wellhead. RILDs. 19.2 ND BOPE, NU tree, test void 1C900:4 7b v 9 SCU 344-33 Drilling Procedure Rev 0 C at : Page 30 Revision 0 May 2018 U Iliho,p U. Aa, LIA: 20.0 BOP Schematic SCU 344-33 Drilling Procedure Rev 0 Page 31 Revision 0 May 2018 H tlilcorp Alaska, TAX 21.0 Wellhead Schematic SCU 344-33 Drilling Procedure Rev 0 Swanson River SCU 33-33 01/13/2016 ILI,..p V..l. IIS Swanson River Tubing hanger, Seaboard SCU 33.33 DCB tension, l l X 2 7/8 EVE 13 3/8 X 9 5/8 %2 7/8 lift CIM susp, W/ 2 1/2" type H BFV profile, 6 Y Extended neck, 3/8 control line Companion flange ,29116 SM FE X 2 7/8 EVE Sm box Valve, wing, WKM-M, Valve, wing, WKM-M, 21/165MFE, TWO, O U 21/165M FE, HWO, AAtrim AAtrim Riser spool 2 9/16 5M X 2 9116 SM Valve, master, WKM-M, 2 9/16 5M FE, HWO, AA Adapter, Seaboard, 115M FE X 2 9/16 SM sidd, w/ 6Kslkk nttkpocket aib no chemical infection port Tubing head, Cameron DCB -S, 13 5/8 5M X 115M, w/ 2- 2 1/16 5M $50 Valve, WKM-M,21/165M :a a FE, HWO, AA tdm CITY2 CaOnj135/ SM XB 3/8S WF, +Ne, CIW ,AAlrim FE, 13 5/8 SM%333/B SOW, �. +I�RU.�1EW7, HWO, AA tnm W/2-21/165MEFO •� to Page 32 Revision 0 May 2018 22.0 Days vs Depth r Y a 0 2000 4000 6000 SCU 344-33 Drilling Procedure Rev 0 Days Vs Depth � 8000 10000 12000 14000 0 5 10 15 20 25 30 Days Page 33 Revision 0 May 2018 I H Ililmrp .Ala ka, LLC 23.0 Geo-Prog SCU 344-33 Drilling Procedure Rev 0 Waterara6ent SR TY 71-3 - Sand(SlltlCoal Water 7048.1 7037.4 -6893.92 2462616-5 345919.9 3167 0.45 8.65 SR TY 72-3 San0/SIWC0al Water _ _ 7088.68 6,9345 -6934.47 2462615.7 345921.1 3121 0.45 8.65 SR TY 72.8 SwdfSll3Coal _ T Water 7131..23 6,9769 6976.93 2462613.9 345923.1 3140 045 8.65 SR -TY -73-6 Sand5191Coal Water _ 7196.19 7041.6 -7041.56 24626093 345927.4 3169 0.45 _ 8.65 SR_TY_74-5 Sand13117C9al _ Water 7285.65 7130.0 -7129.99 2462598.6 3459362_ 3208 0.45 _ SR_TY_75-3 Sand(SirdCoal T Water _; 7361.3' 7,203.9-720394 2462586.1 345945.9 3242 0_45 _8.65 SR TY 75-8 SandlSi8iC0al _ Water 7493.79 7331.1 -7331.08 24625565 345968.1' _ 3299 '_ 0_45 8.65 SR_TY_77-3 SandfSi@/Coal _ Water 7537.49 7,372.2 -73722 2462346.6 345976.8 _ 3317 045 8.65 SRT 774 SanNSHVCoal Water 762134 7,449.8 -7449.78 24625189 3459955 3352 0.45 8.65 SR_T%776 Smd'Silt/Coal _ Water _ 7722.79 7,5419 -7540.95 2462482.8 346021.4_ 3393 0.45 8.655 SR TY 75-1 SandISil6Coal _ -__Water 7857.72 7,656.9 -%M.BS 2462426.6 346061.3 3446 0.45 8.65 SR TY 90-3 SandlSilt/Coal _ Water _ _ 7908.94 7,699.2 -7699.19 2462403 346077-9 3465 0.45 8.65 SR L TYc 2 Sandl3ilGCoal Water 7996.83 7,771.3 -77713 24623619 366106.8 3497 0.45 8.65 COAL 25 Sand/SIIOCoaI Water 826749 7993.8 -799339 24622359 346195.8 3597 _ 0.45. 8.65 COAL_26 San05i8/Coal Water 858376 8,253.4 823291 246208L5 346299.8 3714 a45 8.65 BR San&StrdCoal Water 873653 8,378.7 -8378.27 2462016.1 346350.1 3770 0.45 8.65 -83-1 COAL 27 Sand/SiRtCoal Water 8393.45 8,507.5 -8507.03 2461942.8 346401.7 3828 0.45 8.65 COAL 2S Sand/SIWCoal Water 9001.4 8,596.1 -8595.61 24618923 346637.2 3868 _ 0.45 8.65 COAL_25 SandOttr_oal_ Water 9042.61 8,6709 -8670.45 2461849.7 346467.2 3902 0.45 8.65_ COALjO SandOrdCoal Water _ 9207.51 8,765.2 -9764.73 2461796 346503 _ 3944 _ 0.45 _8.65_ _ COAL 31 SandiSi0/Coal Water 9300.45 - 8641.4 , -884099 24E17523 346333.5 3979 0.45 8.65 _ CO9L32 O19 RATER ZONI7 Sand HP WATER 9380.54 8,907.2 -8906.71 7461715.1 3465619 6500 0.73 14_03 COAL 33 Sand HP WATER 9509.46 9,013.0 -9012.5 2461654.8 3466043 6500 0.72 13.87 COAL 34 SandtS08C0a1 HP WATER 9689.58 9,160.7 -916039 2461570.6 346663.5 5954 0.65 11_50 COAL.35 SandISOCoal_ HP WATER_ 9789.67 9,242.9 -9242.42 24615MS 346696.4 5546_ 0.6 _11_54 COAL 36 SandrSiwcoal _ Water _ 100C193 9,417.0 -941659 2461424.6 346766.2 5179_ 0.55 10_58 COAL 37 Sand/SWCoal '_ Water 10113.41 9,508.5 -9509.07 24613723 3468029 4944 0.52 10_00 COAL 38 Sand/SiWCoal Water lC200.4 9,579.9 -9579.45 2461331.9 3468315 4982 0_52 10_00 COAL N Sand1311tIC0al Water 10332.55 9,688.4 -9687.91 2461270.1 346875 _ 5038; 0.52 10.00.. Page 34 Revision 0 May 2018 K nil.,p Nv.ka, LII: SCU 344-33 Drilling Procedure Rev 0 COAL 40 Sanf9SnvCoal Water 10494.15 9,820.9 .9820.49 2461194.6 346928.1 5107 1152 _10.00 SE -TK -01 Shaley Sand GaSfOil 1070931. 10,000.9 -10000.94 24610925 346993.2 5200 0.52_ _. im-: gA n G2 Shaley Sand Gas1011 1072838 10,017.6 : -10017.6 2463089.5 34699a _ 5209 0.52 1 10.00 _ SR_81 Sand GaslOil 10843.11 10,120.2 -101201 2461044.4 347022.3-_2200 0.52 SR Fi_2 Sand Gas/Oil 1.0859.86 10,135.5 -10135.48 24610383 347025A 7200'_ 0.52 _ 417 SR 1;_3 Sand Gas/Oil 10882.4 10,156.2 -10156.18 24610301 347029.4'._ 2200 0.52 SR li_4 Sand Gasloil 10903.18 10,175.4 .1017538 2461023.1 347032-9 2200 _0.52_ SR_H 6 Sand Gas/Oil 10942.75 10,212.3 .1021215 24610103 3470393' 2200_ 0.52 SR_H 6 Shaley Sand Gas0l 11002.16 10,268.3 .1026831 2460992.7 347048.1 2200 0.52 Sfi FI7 Sand Gas/Oil 11028.54, 10293.5 .10293.46 2460983.6 347051.6 2200 0.52 4.11 9R_H -L Sand Gas/Oil 11096.54 10,3589 .10358.92 2460969.1 347059.8_ 2200 _ 0.52 4.08 _ 8R_H_8 Shale Gas/011 11120.76 10382.4 .10382.44 24609635 3470624 2200 0.52 4.07 SRH 9 Sand Gas/Oil 1114813 10,409.2 .1040912 24609585 347065.1: 2200 _ 0.52 4.06 2 H 10 Sand Water 11253." 10,513.3 .1051281 2460941.1 347073.8 5467 0.52 1 10.00 BPt,H 11 Sand Oil _ 11323.88 10,582.4 -10581.99 24609301 3470791 5503 _ 0.52 _ _ _ 10_00 S.R_Fi 12 Sand Oil 11365.33 10,623.3 -10622.8 2460923.7 347082.4 5524 0.52 _ _10.00 SR_H 13 Sand oil 114.24.48 10,681.5 -10681.06 2460914.5 347086-9 5554 0.52 10_00 TUBING SIZE OTHER COMMENTS NO INFORMATION CONCERNING THIS WELL IS TO BE RELEASED TO ANYONE EXCEPT THE EMPLOYEES OF HILCCRP OR THEIR PARTNERS. Page 35 Revision 0 May 2018 n Ilil.rp .Al.ka, 1.1A: SCU 344-33 Drilling Procedure Rev 0 24.0 Anticipated Drilling Hazards pcgti✓n Water Flow: The Tyonek water sands will be open. Ensure to treat the initial flow as gas. After we are confident we are only dealing with water from the sands we will utilize managed pressure drilling to control the flow '/111 of water while drilling. During trips we will use heavy pills and viscous pills to control the flow and trip in and out of the well. 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. • Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. • Use asphalt -type additives to further stabilize coal seams. • Increase fluid density as required to control running coals. • Emphasize good hole cleaning through hydraulics, ROP and system rheology. • Minimize swab and surge pressures • 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. \�_ _eo r' ' t'_> 4 c' f Page 36 Revision 0 May 2018 H llilc rp Alaska, I.I.0 25.0 Rig Layout SCU 344-33 Drilling Procedure Rev 0 Page 37 Revision 0 May 2018 U Ililruq, .AI.A., LLC 26.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: SCU 344-33 Drilling Procedure Rev 0 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. PIU 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 38 Revision 0 May 2018 H Irilcorp Alaska, r.1.0 27.0 Choke Manifold Schematic 1i1- A 9. ZlAlt T , SCU 344-33 Drilling Procedure Rev 0 tl� din./.t 1. lA1Qli YfM P G9FlS Page 39 Revision 0 May 2018 U Ilil.q, M.A., LU: 28.0 Casing Design Information SCU 344-33 Drilling Procedure Rev 0 Calculation & Casing Design Factors Kenai Team DATE: 5/3/2018 WELL: SCU 34433 FIELD: Swanson River DESIGN BY: Monty M Myers Criteria: Hole Size Mud Density: Hole Size 8-1/2" Mud Density: 9.5 ppg Hole Size Mud Density: Drilling Mode MASP: 2401 psi (See attached MASP determination & Production Mode MASP: 4693 psi (See attached MASP determination & calculation) Collapse Calculation: Section Calculation 1,2 Normal gradient external stress (0.43 psi/ft) and the casing evacuated for the internal stress Page 40 Revision 0 May 2018 Cas ng Section Calculation/Specification 1 2 3 4 Casing OD 7' Top (MD) 6,050 Top (TVD) 6,049 Bottom (MD) 11,385 Bottom (TVD), Length T 10,914 5,335 Weight (ppf) 26 Grade L-80 Connection DWC/C Weight w/o Bouyancy Factor (Ibs) 138,710 Tension at Top of Section (Ibs) 218,710 Min strength Tension (1000 Ibs) 604 Worst Case Safety Factor (Tension) 2.76 Collapse Pressure at bottom (Psi) 4,256 Collapse Resistance w/o tension (Psi) 5,410 Worst Case Safety Factor (Collapse) j 1.27 MASP (psi) 2,401 Minimum Yield (psi) 7,240 Worst case safety factor (Burst) 3.02 Page 40 Revision 0 May 2018 U Irilrnrp .Alaska, LLC 29.0 8-1/2" Hole Section MASP MaldmamAntidpated Surface Pressure Calailedon 8-1/2' Hole Section SCU341-33 Kemi, Alaska MD ND Planned Top: 62,0 6249 _ Planned TD: 11385 10914 Arradpated Fonnationsand Pnssmea- SCU 344-33 Drilling Procedure Rev 0 FomaOon ND rst Nessure Oil/Gas/Wet PPG Grad MAL _32(HP H2) $907 6500 Sand 14.0 0.73 COAL 33 9013 6500 Sand 13.9 M72 COAL 34 9,M 5954 Sand/Sih/Coal 12.5 Q65 COAL 3S 9,243 5546 Sand/silt/Cwl ILLS 0.6D COAL 36 9,417 5179 Sand/Sift/Coal 10.6 0.55 COAL 37 9,509 4944 SW4'Six/Coal 10.0 0.52 COAL 38 958D 4982 saM/Six/Coal 1Q0 0.52 COAL -39 91688 5038 Sand/Silt/Coal 1Q0 M52 COAL 40 9,821 I 5107 Sand/Sift/Coal ID.0 0.52 SR TY 61 1%001 5200 1 ShaleySand 10.0 0.52 SR T' G2 10,018 5209 Shaley Sand 10.0 0.52 SR H 1 A120 2200 Sand 4.2 0.22 SR N 2 1%135 220D sand 4.2 0.22 SR H 3 10,156 7810 Sand 4.2 0.72 S?, -1 4 10175 2210 Sand 4.2 022 SRH 5 1%212 2210 Sand 4.1 0.72 SR H 6 IOIM 22DD Shat Sand 4.1 Oil SRH 7 14293 22M sand 4.1 1 0.21 SR x 7L 1%359 2210 sand 4.1 0.21 SR H 8 M382 1 2210 1 Shale 4.1 0.21 SpIl-L9 409 2210 Sand 4.1 0.21 SR H 10 10513 5167 Sand 10.0 0.52 SR_H 11 10,582 5503 Sand 10.0 0.52 SR -H-12 12 10,673 5524 Sand 10.0 0.52 SR H 13 10,682 55M Sand 10.0 0.52 TD 10,914 5650 Sand 10.0 0.62 Offxtwell Mud Demid. Well MWrame Too MDI Bottom (TVD) Date SCIM&M 9.8- pg 9,400 149B 2914 SCU21-4 12 poll 0 14965 ]961 SCU4433 i13-12.5 PPg 9,216 10,747 71113 SCU43A-4 11.2ppg 9,300 10,807 2113 Assumplion: 1. Anticipated fracture gadent at 62W TMD (6249'ND)=0.7=13.4 ppg EMW 2. Maximum planned mud densityforthe&1/2" hole section is 9.5 ppg. 3. CaImlaUon assumes8.3 ppg reservoir mntaiiss 2/3 gas, 1/3 water. Frach m Pressure at window roruideringe full column organ from window tosurfam: 6249(ft)s0.7(psi/ft)= 4374 4374(psi)-[QI(Psi/ft)'6249(ft)l= 37x9 psi MASP from pore pressure: unknown gassed at TO, at 83 ppg(0.43pd/a) IM4(R)x043(psi/ft)= 4693psi Production MASP 4693psi-(.1.10914) 3601psi Drilling MASP 4WXPs1)-[(2/3)•Ml(psi/ft)'11914(ft)1x[(1/3)b.43(psi/ft)'10914(n)]= 2403 psi Alternate Drilling MASP some rir. 1. WASPwhiledrilring&1/2"holeisgovemedhyporepressureminm 2/3of wellbore evaanMd togas (remaining 1/3 remain water M 8.3 ppg) Page 41 Revision 0 May 2018 Dos�C�y�;q, SCU344-33 Drilling Procedure Rev 0 nilcerp Alaska. IIJA: 30.0 Plot (NAD 27) (Governmental Sections) 0 500 1.000 1.500 Soldotna Creek Unit Feet SCU 344c-33 Nasky sate Plane Zone 4. NAD27 A Ililw.p ANA., 1.1k. W P_06 Map Date: 5/112018 Page 42 Revision 0 May 2018 sRu�y R.. sFu a.t+.m RU33-33 SR— A028399 A028406 scu 0.0 B" scu31.1 ui, 1� i S008NO09W SCU 13 15HD ewasa3 R AO f scu3sm S ' S. S oa WNSO FIELD sa> aHU ^Ys BRIVER tee/ �------ _-- SCU 344-33 TPH SCU 344-33_BHL � = scu 41aw sw 418.aeP eNL SCUs=5M cuz+AOa v.a 318-00 BHuk scowl . i SCU_31� PBt BIM 1 I i \ I SCU_31Oi�HL� � GA02F997 S007NO09W IISSu3zZc.o1 Grey' �' /, ` y Legend /' ✓' 4/ SCU 344 -33 -SHL � sw z+Aasrelt xtn3z.w Bl�i • Other Surface Well Locations AFB B1S1i X SCU 344-33 TPH • Other Bottom Hole Locations SCU 344-33_BHL - Well Paths Boa T Oil and Gas Unit Boundary amo3 0 500 1.000 1.500 Soldotna Creek Unit Feet SCU 344c-33 Nasky sate Plane Zone 4. NAD27 A Ililw.p ANA., 1.1k. W P_06 Map Date: 5/112018 Page 42 Revision 0 May 2018 a Ilileorp Al.aks, LIA: 31.0 Surface Plat (As Built) (NAD 27) SCU 344-33 Drilling Procedure Rev 0 I SEC 33 T8N R9W SCU P� 33• vi �$5r FEL(Nrs 33 - AS -BUILT WELL SCU 33-33 N:345%1,.03 E:3459'"'I 06 LAT: 80'44'18.4005'N �v({ LONG: 150'5t'38.008M ASP ZONE 4 NAD27 F �fFEL - 65P L�(1.6 17 ' FSL=1 5' ' WTFSL(NTS) IV V y� ELEV = 125YrNAVM) y'� SECTION 33. TSN. R9W. SM, AK SECTION N5 CORNER I rr ��lii E -3470.70.77 (COMPUTED) — — — — — — —TSN R9W — — �jf,OT�py IN _ _ S33 SYt_ T7N R9'N NOT TO SCALE S4 S3 BASIS OF HORIZONTAL; NAD83 US FEET POSITION (EPOCH 2010) ID VERTICAL CONTROL (NAVOW) IS AN OPUS SOLUTION FROM IS STATIONS TBON, TSEA ANO ANC2 TO ESTABLISH CP -2. THE ASKA STATE PLANE COORDINATES NAD 83 ZONE 4 IN FEET ARE: / •..'."'� E = 1483669.444 M B) INAVFROM ELEV. CO = COMPUTED SECTION LINES SHOWN ARE COMPUTED FROM MONUMENT TIES ONG THE NORTH TOWNSHIP LINE OF TOWNSHIP 7N RANGE SW DATUM TRANSFORMATIONS (NAD83 ASPZ4 TO NAD27 ASPZ4) ERE DONE USING CORPSCON SOFTWARE VERSION 6.0.1, �....: // y S1FX�A'Y1N1E r // •�4 SCALE 'ro o mo coo FFILIL\��:` FEET -- RfP4ON . CFroFL4np Mc LGjeu7P Alaska, SWANSON RIVER FIELD WELL SCU WELL 33-33 AS BUILT SURFACE LOCATION NAD 27 F"IL 11°jp1 aw.onwnw.wmiw,mrw NgSC119 ,� SECTION 33 T08N R09W SEWARD MERIDIAN, ALASKA 1 Page 43 Revision 0 May 2018 a I li6orp Alaska, LLC 32.0 Surface Plat (As Built) (NAD SCU 344-33 Drilling Procedure Rev 0 NOTES 1. BASIS OF HORIZONTAL; NAD83 US FEET POSITION (EPOCH 2010) AND VERTICAL CONTROL (NAVDSS) IS AN OPUS SOLUTION FROM NGS STATIONS TBON, TSEA AND ANC2 TO ESTABLISH CP -2. THE ALASKA STATE PLANE COORDINATES HAD 83 ZONE 4 IN FEET ARE: N = 2458384.578 E = 1483669.444 ELEV. = 212.690 (RAvD88) 2. SECTION LINES SHOWN ARE COMPUTED FROM MONUMENT TIES ALONG THE NORTH TOWNSHIP LINE OF TOWNSHIP 7N RANGE 9W F At AkAliI // SIA.Am'.ANE — SCALE //i4 •�`4��,. FEET SWANSON RIVER FIELD wm u,vn» Leroaltinp lnc puvmar. ror WELL SCU WELL 3333 AS BUILT SURFACE LOCATION vNOEcr No. +Fn,E NAD 83 FAasEENN01 w1NK.. ]R.Ernc i rzelro SECTION 33 T08N R09W «.. wnA.4piwaoacw Ililcurp Alaska, I.I,r. SEWARD MERIDIAN, ALASKA Page 44 Revision 0 May 2018 SEC 33 T8N R9W Iw p D SCU PAD I- AS -BUILT WELL 33-33 2 SCU 3333 N:24.96 166T FEL (NTS) E:1486013SW13.96 1 LAT: 150 -Si -45.9% LONG: 150°51'45.9969"w : ASP ZONE 4 NAD63 FEL = 165T FSL = 1465' C ELEV - 12ST (NAVD88) SECTION 33, TON. R9W. SM. AK 1465' FSL (NTS) SECTION CORNER N.2460919. 18 E. 1487653.68 (C0AIPUTE0) T8N R9W — — — ---- --=TM I ISE S33 53a_ _ WN R9W NOT TO SCALE S4 S3 NOTES 1. BASIS OF HORIZONTAL; NAD83 US FEET POSITION (EPOCH 2010) AND VERTICAL CONTROL (NAVDSS) IS AN OPUS SOLUTION FROM NGS STATIONS TBON, TSEA AND ANC2 TO ESTABLISH CP -2. THE ALASKA STATE PLANE COORDINATES HAD 83 ZONE 4 IN FEET ARE: N = 2458384.578 E = 1483669.444 ELEV. = 212.690 (RAvD88) 2. SECTION LINES SHOWN ARE COMPUTED FROM MONUMENT TIES ALONG THE NORTH TOWNSHIP LINE OF TOWNSHIP 7N RANGE 9W F At AkAliI // SIA.Am'.ANE — SCALE //i4 •�`4��,. FEET SWANSON RIVER FIELD wm u,vn» Leroaltinp lnc puvmar. ror WELL SCU WELL 3333 AS BUILT SURFACE LOCATION vNOEcr No. +Fn,E NAD 83 FAasEENN01 w1NK.. ]R.Ernc i rzelro SECTION 33 T08N R09W «.. wnA.4piwaoacw Ililcurp Alaska, I.I,r. SEWARD MERIDIAN, ALASKA Page 44 Revision 0 May 2018 U 110.rp .AI.A., UA: 33.0 Directional Program (WP06) SCU 344-33 Drilling Procedure Rev 0 Page 45 Revision 0 May 2018 Hilcorp Alaska, LLC Soldotna CK Unit SCU 33-33 SCU 33-33 SCU 344-33 Plan: SCU 344-33 WP06 Standard Proposal Report 27 April, 2018 Sperry Drilling Services HALLIBURTON flpeery olilling 13 3/8" 3333 4500 5000 5500 6009_-95/8"TOW 6500 6500 ppp 7000 5pp 7500 ppp p 8000 O �p0 9000 p Op 1pppp 10000 No 0 SCU 344-33Wp06 11000 7"x81/2" '1385 SCU 344-33 wp05 Target �O 8000 7nnn 1 West( -)/East(+) (350 usWin) 350 525 700 875 1050 1225 1 SCU 33-3i 1 18333 170001 SCU 33-33 2 scu SCU 344-33 wp05 Target Project: Soldotna CK Unit Site: SCU 33-33 Well: SCU 33-33 Wellbore: SCU 344-33 Design: SCU 344-33 WPO6 CASING DETAILS TVD TVDSS MD o 6249.11 6105.61 6250.00 9 5/8" TOW 10914.28 10770.78 11384.79 7" x 8 In" 600 1000 1ss7 -� 1500 2000 13 3/8" 3333 4500 5000 5500 6009_-95/8"TOW 6500 6500 ppp 7000 5pp 7500 ppp p 8000 O �p0 9000 p Op 1pppp 10000 No 0 SCU 344-33Wp06 11000 7"x81/2" '1385 SCU 344-33 wp05 Target �O 8000 7nnn 1 West( -)/East(+) (350 usWin) 350 525 700 875 1050 1225 1 SCU 33-3i 1 18333 170001 SCU 33-33 2 scu SCU 344-33 wp05 Target "-- \YELL DET S: SCU 33-33 NAD 1927(NADCON COMS) Mmka7ne04 O .d Levee. 125.50 +NAS 'V -W N.Mir, Fasting Ladttude W gimde 0.00 0.00 2462644.03 345991.06 6W "'' 16.401 N 15V 51' 38.008 W CASING DETAILS TVD TVDSS MD Name 6249.11 6105.61 6250.00 9 5/8" TOW 10914.28 10770.78 11384.79 7" x 8 In" 0 1667 3333 5000 6667 8333 10000 11667 13333 15000 Vertical Section at 146.77° (2500 uslVin) 5000 5500 7000 _ _ - _ - SR_TY_71-8 c �n 7500 0 0 t 8000 0 U 8500 d F- onnn 10500 HALLIBLIRTON Hikorp Alaska, LLC REFERENCE INFORMATION EM Calculation Method: Minimum Curvature Longitude 3oordinate (N/E) Reference: Well SCU 33-33, True North Sperry Orilliog Error System: ISCWSA Scan Metlwd: Closest Approach 3D Error Surface: Elliptical Conic blaming Method: Error Ratio SURVEY PROGRAM Vertical QVD)Reference: SCU 344-33 WP05 RKB@ 143.50usg(HEC Measured Depth Reference. SCU 344-33 WPM RKB @ 143.50us8 (HEC Calrulalion Method : Minimum Curvature Project. Soldotna CK Unit Site: SCU 33-33 Depth To Survey/Plan SECTION DETAILS Well: SCU 33-33 Sec MD Inc Azi ND +N/ -S +E/ -W Dleg TFace VSecl Target Wellbore: SCU 344-33 Design: SCU 344-33 WP06 g 1 6250.00 2 6981.45 3 10544.76 1.91 7.36 6249.11 7.02 27.79 146.42 6953.56 -125.82 27.79 146.42 10105.91 -1509.82 -28.11 0.00 0.00 -21.28 69.91 4.00 141.31 143.56 988.80 0.00 0.00 1804.80 2_MWD+AX+Sag 4 10989.50 5 11318.54 6 11384.79 10.00 147.00 10525.00 -1629.54 10.00 147.00 10849.04 -1677.46 10.00 147.00 10914.28 -1687.11 1067.81 4.00 179.67 1948.24 1098.93 0.00 0.00 2005.37 SCU 344-33 wp05 Target 1105.20 0.00 0.00 2016.88 9050.50 5000 5500 7000 _ _ - _ - SR_TY_71-8 c �n 7500 0 0 t 8000 0 U 8500 d F- onnn 10500 5000 5500 6000 9 5/8" TOW - - KOR Start Dir 4°/100' : 6250' MD, 6249.11'ND : 141.31" RT TF 6500r500 End Dir :6981.45' MD, 6953.56' ND ppv 18pp 7500 8ppp COAL 25 8500 \55`o WELL DETAILS: SCU 3333 Ground Level: 125.50 Size +N/ -S +E/ -W Northing Easting LatittWe Longitude 0.00 0.00 2462644.03 345991O5 60° 44' 16,401 N 15W 51'38.008 10914.28 SURVEY PROGRAM 11384.79 Depth From Depth To Survey/Plan Tool 90.50 6250.00 Sperry Sumel Gyro SU3-06127 (SCU 3333) 2 -CB -Film -GMS 6250.00 6550.00 SCU 34433 WPM (SCU 34433) 2 MM IInterp An+ 6550.00 11384.79 SCU 34433 WP06(SCU 34433) 2_MWD+AX+Sag 5000 5500 6000 9 5/8" TOW - - KOR Start Dir 4°/100' : 6250' MD, 6249.11'ND : 141.31" RT TF 6500r500 End Dir :6981.45' MD, 6953.56' ND ppv 18pp 7500 8ppp COAL 25 8500 \55`o f 9000 COAL -32 (HP WATER ZONE) p8 COAL 35 9500100 p0 Start Dir4°/100': 10544.76'MD, 10105.9l'TVD COAL 39 .-SR TY G1 - _ - _ _ End Dir : 10989.5' MD, 10525' ND -. SR -H-1 _ SR -H 7 -SR _H_5- _ _ - _ _ _ 10500 _ _ _ _ _ 1000 "SR_H_9 SCU 344-33 Wp05 Targ 1 Total Depth :11384.79' MD, 10914.26' ND - - - - _ _ _ - _ _ - - _ - _ - _ . 1385 11000 7" x 8 1/2" SCU 344-33 WPO6 500 SCU 33-33 11500 1000 -500 0 500 1000 1500 2000 2500 3000 3500 4000 Vertical Section at 146.77' (1000 u6Win) 4500 5000 5500 6000 CASING DETAILS TVD TVDSS MD Size 6249.11 6105.61 6250.00 9 5/8" TOW 10914.28 10770.78 11384.79 7"x81/2" FORMATION TOP DETAILS TVDPath TVDasPath MDPath Formation 7037.50 6894.00 7076.34 SR_TY_71-8 8136.50 7993.00 8318.61 COAL 25 9050.50 6907.00 9351.76 COAL 32 (HP 9385.50 9242.00 9730.43 COAL_35 9831.50 988800 10234.58 COAL 39 10144.50 10001.00 10588.04 SR TY G1 10263.50 10120.00 10717.81 SR_H_1 10355.50 10212.00 10815.09 SR_H_5 10436.50 10293.00 10899.07 SR7 10552.50 10409.00 1101742 SR 1-19 10824.50 10681.00 11293.62 SR_H 13 f 9000 COAL -32 (HP WATER ZONE) p8 COAL 35 9500100 p0 Start Dir4°/100': 10544.76'MD, 10105.9l'TVD COAL 39 .-SR TY G1 - _ - _ _ End Dir : 10989.5' MD, 10525' ND -. SR -H-1 _ SR -H 7 -SR _H_5- _ _ - _ _ _ 10500 _ _ _ _ _ 1000 "SR_H_9 SCU 344-33 Wp05 Targ 1 Total Depth :11384.79' MD, 10914.26' ND - - - - _ _ _ - _ _ - - _ - _ - _ . 1385 11000 7" x 8 1/2" SCU 344-33 WPO6 500 SCU 33-33 11500 1000 -500 0 500 1000 1500 2000 2500 3000 3500 4000 Vertical Section at 146.77' (1000 u6Win) 4500 5000 5500 6000 C_ i WELL DETAnS: SCU 33-33 Lound Level: 125.50 +N/ -S +Ef-W Northing Essdng Lenttude Longiwde 0,00 0.00 2462644.03 34599106 60° 44' 16401 N 15V 51' 38.008 W REFERENCE INFORMATION CooNlnale (NAE) Re%mnce: Well SCO 33-33. Trve North WW.I CND) Reference: SCU 344-33 W 05 RKB @ 143.59usfi (HEC 159) Measured Depth Reference: 6CU 344-33 WP05 RKB @ 143 50usft (HEC 15W) calculerroo Me(nol: MlnMmn Culvalure West( -)/East(+) (300 u stun) MAWBURTON Project: Soldotna CK Unit Site: SCU 33-33 she, o1uD�a Well: SCU 33-33 Wellbore: SCU 344-33 FT�Plan: _ SCU 34433 WP06 C_ i WELL DETAnS: SCU 33-33 Lound Level: 125.50 +N/ -S +Ef-W Northing Essdng Lenttude Longiwde 0,00 0.00 2462644.03 34599106 60° 44' 16401 N 15V 51' 38.008 W REFERENCE INFORMATION CooNlnale (NAE) Re%mnce: Well SCO 33-33. Trve North WW.I CND) Reference: SCU 344-33 W 05 RKB @ 143.59usfi (HEC 159) Measured Depth Reference: 6CU 344-33 WP05 RKB @ 143 50usft (HEC 15W) calculerroo Me(nol: MlnMmn Culvalure West( -)/East(+) (300 u stun) Database: Sperry EDM - NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Soldolna CK Unit Site: SCU 33-33 Well: SCU 33-33 Wellbore: SCU 344-33 Design: SCU 344-33 WP06 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well SCU 33-33 SCU 344-33 WP05 RKB @ 143.50usft (HEC 169) SCU 344-33 WPO5 RKB @ 143.50usft (HEC 169) True Minimum Curvature Project Soldolna CK Unit, Swanson River Field Tie On Depth: 6,250.00 Map System: Geo Datum: Map Zone: US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Alaska Zone 04 +EI -W System Datum: Mean Sea Level Using Well Reference Point Using geodetic scale factor (usft) (usft) (usft) (`) 18.00 0.00 Site SCU 3333 (•) (°) (usft) Site Position: From: Position Uncertainty: Map 0.00 usft Northing: Easting: Slot Radius: 2,462,588.40 usft Latitude: 345,944.90usft Longitude: 133/16" Grid Convergence: 60° 44' 15.847 N 150° 51'38.922 W -0.75 ° 6,105.61 6,981.45 27.79 146.42 6,953.56 Well SCU 33-33 27.79 146.42 10,105.91 Well Position +NIS 0.00 usft +E/ -W 0.00 usft Northing: Easting: 2,462,644.03 usft Latitude: 345,991.06 usft Longitude: 60' 44' 16.401 N 150° 51' 38.008 W Position Uncertainty 0.00 usft Wellhead Elevation: 125.50 usft Ground Level: 125.50 usft Wellbore SCU 344-33 11,384.79 10.00 147.00 Magnetics Model Name Sample Date Declination Dip Angle Field Strength 0.00 EGGM2017 4/19/2018 15.81 73.71 55,389 i Design SCU 344-33 WPO6 Audit Notes: Version: Vertical Section: Phase: PLAN Tie On Depth: 6,250.00 Depth From (TVD) +N/S +EI -W Direction (usft) (usft) (usft) (`) 18.00 0.00 0.00 146.77 Plan Sections Dogleg Build Turn Measured +N/S +E/ -W Vertical TVD Depth Inclination Azimuth Depth System (usft) (•) (°) (usft) usft 6,250.00 1.91 7.36 6,249.11 6,105.61 6,981.45 27.79 146.42 6,953.56 6,810.06 10,544.76 27.79 146.42 10,105.91 9,962.41 10,989.50 10.00 147.00 10,525.00 10,381.50 11,318.54 10.00 147.00 10,849.04 10,705.54 11,384.79 10.00 147.00 10,914.28 10,770.78 4/272016 5:55:58PM Page 2 COMPASS 5000.1 Build 81E Dogleg Build Turn +N/S +E/ -W Rate Rate Rate Tool Face (usft) (usft) (°/10ousft) (°1100usft) (°1100usft) (•) 7.02 -28.11 0.00 0.00 0.00 0.00 -125.82 69.91 4.00 3.54 19.01 141.31 -1,509.82 988.80 0.00 0.00 0.00 0.00 -1,629.54 1,067.81 4.00 -4.00 0.13 179.67 -1,677.46 1,098.93 0.00 0.00 0.00 0.00 -1,687.11 1,105.20 0.00 0.00 0.00 0.00 4/272016 5:55:58PM Page 2 COMPASS 5000.1 Build 81E Halliburton Standard Proposal Report Database: Sperry EDM - NORTH US +CANADA Local Cc -ordinate Reference: Well SCU 33-33 Company: Hilcorp Alaska, LLC TVD Reference: SCU 344-33 WP05 RKB Q 143.50usft (HEC 169) Project: Soldotna CK Unit MD Reference: SCU 344-33 WP05 RKB (t7U 143.50usft (HEC 169) Site: SCU 33-33 North Reference: True Well: SCU 33-33 Survey Calculation Method: Minimum Curvature Wellbore: SCU 344-33 Depth Inclination Design: SCU 344-33 WP06 TVDss +NIS Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NIS +E/.W Northing Easting OLS Vert Section (usft) (°) (') (usft) usft (usft) (usft) (usft) (usft) .43.50 100.00 0.59 123.06 100.00 -03.50 -0.26 0.40 2,462,643.77 345,991.46 0.00 0.44 200.00 0.46 130.17 199.99 56.49 -0.80 1.14 2,462,643.22 345,992.19 0.14 1.29 300.00 0.40 134.01 299.99 156.49 -1.30 1.69 2,462,642.71 345,992.73 0.07 2.01 400.00 0.40 140.30 399.99 256.49 -1.82 2.16 2,462,642.19 345,993.19 0.04 2.70 500.00 0.38 143.65 499.99 356.49 -2.35 2.56 2,462,641.65 345,993.59 0.03 3.37 600.00 0.43 136.71 599.98 456.48 -2.86 3.02 2,462,641.11 345,994.04 0.07 4.07 700.00 0.44 133.82 699.98 556.48 -3.41 3.55 2,462,640.58 345,994.56 0.02 4.79 800.00 0.60 136.34 799.98 656.48 -4.05 4.20 2,462,639.92 345,995.21 0.16 5.69 900.00 0.62 150.15 899.97 756.47 -4.91 4.82 2,462,639.06 345,995.82 0.15 6.75 1,000.00 0.65 152.01 999.97 856.47 -5.89 5.35 2,462,638.07 345,996.33 0.04 7.86 1,100.00 0.70 147.67 1,099.96 956.46 -6.90 5.96 2,462,637.05 345,996.93 0.07 9.04 1,200.00 0.70 161.03 1,199.95 1,056.45 -8.00 6.49 2,462,635.95 345,997.44 0.16 10.24 1,300.00 0.70 175.60 1,299.94 1,156.44 -9.18 6.72 2,462,634.76 345,997.66 0.18 11.36 1,400.00 0.68 172.27 1,399.94 1,256.44 -10.38 6.85 2,462,633.57 345,997.78 0.04 12.44 1,500.00 0.70 169.19 1,499.93 1,356.43 -11.57 7.06 2,462,632.37 345,997.97 0.04 13.54 1,600.00 0.70 174.88 1,599.92 1,456.42 -12.77 7.24 2,462,631.16 345,998.13 0.07 14.65 1,700.00 0.72 188.26 1,699.91 1,556.41 -14.00 7.19 2,462,629.93 345,998.06 0.17 15.65 1,800.00 0.73 188.92 1,799.91 1,656.41 -15.26 7.00 2,462,628.68 345,997.86 0.02 16.60 1,900.00 0.77 195.27 1,899.90 1,756.40 -16.55 6.74 2,462,627.40 345,997.58 0.09 17.53 2,000.00 0.78 212.84 1,999.89 1,856.39 -17.76 6.18 2,462,626.20 345,997.00 0.24 18.24 2,100.00 0.82 213.90 2,099.88 1,956.38 -18.93 5.40 2,462,625.04 345,996.22 0.04 18.79 2,200.00 0.77 214.40 2,199.87 2,056.37 -20.07 4.64 2,462,623.90 345,995.43 0.05 19.33 2,300.00 0.74 222.06 2,299.86 2,156.36 -21.09 3.83 2,462,622.90 345,994.61 0.10 19.73 2,400.00 0.79 218.50 2,399.85 2,256.35 -22.11 2.96 2,462,621.88 345,993.73 0.07 20.12 2,500.00 0.72 213.52 2,499.84 2,356.34 -23.18 2.18 2,462,620.82 345,992.93 0.10 20.58 2,600.00 0.60 209.64 2,599.84 2,456.34 -24.15 1.58 2,462,619.86 345,992.33 0.12 21.07 2,700.00 0.65 212.39 2,699.83 2,556.33 -25.09 1.01 2,462,618.93 345,991.74 0.06 21.54 2,800.00 0.67 205.33 2,799.82 2,656.32 -26.10 0.46 2,462,617.92 345,991.18 0.08 22.09 2,900.00 0.64 209.98 2,899.82 2,756.32 -27.12 -0.07 2,462,616.92 345,990.64 0.06 22.65 3,000.00 0.57 214.38 2,999.81 2,856.31 -28.02 -0.63 2,462,616.02 345,990.06 0.08 23.09 3,100.00 0.51 224.25 3,099.81 2,956.31 -28.75 -1.23 2,462,615.30 345,989.45 0.11 23.38 3,200.00 0.45 228.44 3,199.80 3,056.30 -29.32 -1.82 2,462,614.74 345,988.86 0.07 23.53 3,300.00 0.64 230.38 3,299.80 3,156.30 -29.95 -2.56 2,462,614.12 345,988.11 0.19 23.65 3,370.50 0.59 231.84 3,370.29 3,226.79 -30.43 -3.15 2,462,613.65 345,987.51 0.07 23.72 13 318" 3,400.00 0.59 230.91 3,399.79 3,256.29 -30.61 -3.39 2,462,613.46 345,987.27 0.04 23.75 3,500.00 0.68 220.68 3,499.79 3,356.29 -31.41 -4.17 2,462,612.68 345,986.48 0.14 23.99 3,600.00 0.68 233.03 3,599.78 3,456.28 -32.22 -5.02 2,462,611.88 345,985.61 0.15 24.20 3,700.00 0.70 250.94 3,699.77 3,556.27 -32.78 -6.08 2,462,611.34 345,984.55 0.22 24.09 3,800.00 0.78 267.21 3,799.76 3,656.26 -33.01 -7.34 2,462,611.13 345,983.29 0.22 23.59 3,900.00 0.92 275.01 3,899.75 3,756.25 -32.97 -8.83 2,462,611.18 345,981.80 0.18 22.74 4,000.00 0.90 282.32 3,999.74 3,856.24 -32.73 -10.42 2,462,611.44 345,980.22 0.12 21.67 4,100.00 0.80 291.55 4,099.73 3,956.23 -32.30 -11.80 2,462,611.89 345,978.84 0.17 20.55 4,200.00 1.10 290.96 4,199.72 4,056.22 -31.70 -13.37 2,462,612.51 345,977.27 0.30 19.19 1 4,300.00 1.12 296.47 4,299.70 4,156.20 -30.94 -15.16 2,462,613.30 345,975.50 0.11 17.57 41272018 5:55:58PM Page 3 COMPASS 5000.1 Build 81E Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Alaska, LLC Project: Soldotns CK Unit Site: SCU 33-33 Well: SCU 33-33 Wellbore: SCU 344-33 Design: SCU 344-33 WP06 Planned Survey Measured Vertical Depth Inclination Azimuth Depth (usft) (") (1) (usft) Halliburton Standard Proposal Report Local Co-ordinate Reference: Well SCU 33-33 TVD Reference: SCU 344-33 WP05 IRKS @ 143.50usft (HEC 169) MD Reference: SCU 344-33 WP05 RKB @ 143.50usft (HEC 169) North Reference: True Survey Calculation Method: Minimum Curvature TVDss +NlS usft (usft) 4,400.00 1.17 311.01 4,399.68 4,256.18 -29.80 4,500.00 1.14 305.29 4,499.66 4,356.16 -28.58 4,600.00 1.31 312.47 4,599.63 4,456.13 -27.21 4,700.00 1.22 314.29 4,699.61 4,556.11 -25.70 4,800.00 1.13 320.45 4,799.59 4,656.09 -24.20 4,900.00 1.11 325.66 4,899.57 4,756.07 .22.64 5,000.00 1.22 319.78 4,999.55 4,856.05 -21.03 5,100.00 1.10 330.77 5,099.53 4,956.03 -19.39 5,200.00 1.18 341.17 5,199.51 5,056.01 -17.57 5,300.00 1.23 337.39 5,299.49 5,155.99 -15.61 5,400.00 1.03 346.88 5,399.46 5,255.96 -13.54 5,500.00 1.06 170.34 5,499.45 5,355.95 -13.97 5,600.00 1.43 348.60 5,599.44 5,455.94 -13.46 5,700.00 1.53 351.33 5,699.41 5,555.91 -10.92 5,800.00 1.69 1.09 5,799.37 5,655.87 -8.12 5,900.00 1.80 5.69 5,899.32 5,755.82 -5.09 6,000.00 2.01 5.47 5,999.27 5,855.77 -1.77 6,100.00 2.13 4.62 6,099.20 5,955.70 1.86 6,200.00 1.93 7.40 6,199.14 6,055.64 5.36 6,250.00 1.91 7.36 6,249.11 6,105.61 7.02 KOP: Start Dir 4°1100' : 6250' MD, 6249.11'TVD : 141.31° RT TF - 9 518" TOW 6,300.00 1.30 81.69 6,299.10 6,155.60 7.93 6,400.00 4.66 133.87 6,398.96 6,255.46 5.28 6,500.00 8.59 140.75 6,498.27 6,354.77 -3.33 6,600.00 12.56 143.32 6,596.55 6,453.05 -17.84 6,700.00 16.55 144.66 6,693.33 6,549.83 -38.19 6,800.00 20.54 145.50 6,788.11 6,644.61 -64.27 6,900.00 24.53 146.07 6,880.46 6,736.96 -95.97 6,981.45 27.79 146.42 6,953.55 6,810.05 -125.82 End Dir : 6981.45' MD, 6953.56' TVD 7,000.00 27.79 146.42 6,969.97 6,826.47 -133.03 7,076.34 27.79 146.42 7,037.50 6,894.00 A62.68 SR -TY -71-8 7,100.00 27.79 146.42 7,058.43 6,914.93 -171.87 7,200.00 27.79 146.42 7,146.90 7,003.40 -210.71 7,300.00 27.79 146.42 7,235.37 7,091.87 -249.55 7,400.00 27.79 146.42 7,323.83 7,180.33 -288.39 7,500.00 27.79 146.42 7,412.30 7,268.80 -327.23 7,600.00 27.79 146.42 7,500.77 7,357.27 -366.07 7,700.00 27.79 146.42 7,589.23 7,445.73 -404.91 7,800.00 27.79 146.42 7,677.70 7,534.20 443.75 7,900.00 27.79 146.42 7,766.17 7,622.67 -482.59 8,000.00 27.79 146.42 7,854.64 7,711.14 -521.43 8,100.00 27.79 146.42 7,943.10 7,799.60 -560.27 8,200.00 27.79 146.42 8,031.57 7,888.07 -599.11 100.48 Map Map 0.00 198.83 +El -W Northing Easting DLS Vert Section (usft) (usft) (usft) 4,256.18 292-07 -16.79 2,462,614.46 345,973.88 0.30 15.72 -18.37 2,462,615.70 345,972.31 0.12 13.84 -20.04 2,462,617.09 345,970.67 0.23 11.78 -21.65 2,462,618.62 345,969.08 0.10 9.63 -23.04 2,462,620.13 345,967.71 0.16 7.62 -24.19 2,462,621.71 345,966.58 0.10 5.68 -25.45 2,462,623.34 345,965.34 0.16 3.64 -26.60 2,462,624.99 345,964.21 0.25 1.64 .27.38 2,462,626.83 345,963.45 0.22 -0.31 -28.15 2,462,628.79 345,962.71 0.10 -2.37 -28.79 2,462,630.67 345,962.10 0.27 4.45 -28.76 2,462,630.44 345,962.12 2.09 -4.08 -28.90 2,462,630.95 345,961.99 2.49 4.57 -29.36 2,462,633.50 345,961.56 0.13 -6.95 -29.53 2,462,636.30 345,961.43 0.32 -9.39 -29.33 2,462,639.32 345,961.67 0.18 -11.81 -29.01 2,462,642.64 345,962.04 0.21 -14.41 -28.70 2,462,646.26 345,962.39 0.12 -17.28 -28.32 2,462,649.76 345,962.81 0.22 -20.00 -28.11 2,462,651.42 345,963.05 0.04 -21.28 -27.44 2,462,652.32 345,963.73 4.00 -21.67 -23.39 2,462,649.61 345,967.74 4.00 -17.23 -15.73 2,462,640.91 345,975.29 4.00 -5.84 4.50 2,462,626.25 345,986.32 4.00 12.45 10.24 2,462,605.72 346,000.80 4.00 37.55 28.42 2,462,579.40 346,018.63 4.00 69.34 49.96 2,462,547.42 346,039.75 4.00 107.65 69.91 2,462,517.31 346,059.31 4.00 143.56 74.69 2,462,510.04 346,063.99 0.00 152.21 94.38 2,462,480.14 346,083.29 0.00 187.80 100.48 2,462,470.87 346,089.27 0.00 198.83 126.26 2,462,431.70 346,114.54 0.00 245.45 152.05 2,462,392.53 346,139.82 0.00 292-07 177.84 2,462,353.36 346,165.09 0.00 338.69 203.63 2,462,314.18 346,190.37 0.00 385.31 229.42 2,462,275.01 346,215.64 0.00 431.93 255.20 2,462,235.84 346,240.92 0.00 478.55 280.99 2,462,196.67 346,266.19 0.00 525.17 306.78 2,462,157.50 346,291.47 0.00 571.79 332.57 2,462,118.32 346,316.74 0.00 618.41 358.35 2,462,079.15 346,342.02 0.00 665.03 384.14 2,462,039.98 346,367.29 0.00 711.65 4272018 5:55:58PM Page 4 COMPASS 5000.1 Build 81E Is Halliburton Standard Proposal Report Database: Company: Project: Site: Well: Wellbore: Design: Sperry EDM - NORTH US + CANADA Hilcorp Alaska, LLC Soldotna CK Unit SCU 33-33 SCU 33-33 SCU 344-33 SCU 344-33 WPO6 Local Co-ordinate Reference: Well SCU 33-33 TVD Reference: SCU 344-33 WP05 RKB @ 143.50usft (HEC 169) MD Reference: SCU 344-33 WP05 RKB @ 143.50usft (HEC 169) North Reference: True Survey Calculation Method: Minimum Curvature Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 7,976.54 8,300.00 27.79 146.42 8,120.04 7,976.54 -637.95 409.93 2,462,000.81 346,392.57 0.00 758.28 8,318.61 27.79 146.42 8,136.50 7,993.00 -645.18 414.73 2,461,993.52 346,397.27 0.00 766.95 COAL -25 8,400.00 27.79 146.42 8,208.50 8,065.00 -676.79 435.72 2,461,961.64 346,417.84 0.00 804.90 8,500.00 27.79 146.42 8,296.97 8,153.47 -715.63 461.51 2,461,922.46 346,443.12 0.00 851.52 8,600.00 27.79 146.42 8,385.44 8,241.94 -754.47 487.29 2,461,883.29 346,468.39 0.00 898.14 8,700.00 27.79 146.42 8,473.91 8,330.41 -793.31 513.08 2,461,844.12 346,493.67 0.00 944.76 8,800.00 27.79 146.42 8,562.37 8,418.87 -832.15 538.87 2,461,804.95 346,518.94 0.00 991.38 8,900.00 27.79 146.42 8,650.84 8,507.34 -870.99 564.66 2,461,765.78 346,544.21 0.00 1,038.00 9,000.00 27.79 146.42 8,739.31 8,595.81 -909.83 590.44 2,461,726.60 346,569.49 0.00 1,084.62 9,100.00 27.79 146.42 8,827.77 8,684.27 -948.67 616.23 2,461,687.43 346,594.76 0.00 1,131.24 9,200.00 27.79 146.42 8,916.24 8,772.74 -987.51 642.02 2,461,648.26 346,620.04 0.00 1,177.86 9,300.00 27.79 146.42 9,004.71 8,861.21 -1,026.35 667.81 2,461,609.09 346,645.31 0.00 1,224.48 9,351.76 27.79 146.42 9,050.50 8,907.00 -1,046.46 681.16 2,461,588.81 346,658.40 0.00 1,248.61 COAL (HP WATER ZONE) -32 9,400.00 27.79 146.42 9,093.18 8,949.68 -1,065.19 693.60 2,461,569.92 346,670.59 0.00 1,271.10 9,500.00 27.79 146.42 9,181.64 9,038.14 -1,104.04 719.38 2,461,530.74 346,695.86 0.00 1,317.72 9,600.00 27.79 145.42 9,270.11 9,126.61 -1,142.88 745.17 2,461,491.57 346,721.14 0.00 1,364.34 9,700.00 27.79 146.42 9,358.58 9,215.08 -1,181.72 770.96 2,461,452.40 346,746.41 0.00 1,410.97 9,730.43 27.79 146.42 9,385.50 9,242.00 -1,193.54 778.81 2,461,440.48 346,754.11 0.00 1,425.15 COAL -35 9,800.00 27.79 146.42 9,447.04 9,303.54 -1,220.56 796.75 2,461,413.23 346,771.69 0.00 1,457.59 9,900.00 27.79 146.42 9,535.51 9,392.01 -1,259.40 822.53 2,461,374.06 346,796.96 0.00 1,504.21 10,000.00 27.79 146.42 9,623.98 9,480.48 -1,298.24 848.32 2,461,334.88 346,822.24 0.00 1,550.83 10,100.00 27.79 146.42 9,712.44 9,568.94 -1,337.08 874.11 2,461,295.71 346,847.51 0.00 1,597.45 1 10,200.00 27.79 146.42 9,800.91 9,657.41 -1,375.92 899.90 2,461,256.54 346,872.79 0.00 1,644.07 10,234.58 27.79 146.42 9,831.50 9,688.00 -1,389.35 908.81 2,461,243.00 346,881.53 0.00 1,660.19 COAL -39 10,300.00 27.79 146.42 9,889.38 9,745.88 -1,414.76 925.69 2,461,217.37 346,898.06 0.00 1,690.69 10,400.00 27.79 146.42 9,977.85 9,834.35 -1,453.60 951.47 2,461,178.20 346,923.34 0.00 1,737.31 10,500.00 27.79 146.42 10,066.31 9,922.81 -1,492.44 977.26 2,461,139.03 346,948.61 0.00 1,783.93 10,544.76 27.79 146.42 10,105.91 9,962.41 -1,509.82 988.80 2,461,121.49 346,959.92 0.00 1,804.80 Start Dir 4°1100' : 10544.76' MD, 10105.91TN 10,588.04 26.06 146.44 10,144.50 10,001.00 -1,526.15 999.64 2,461,105.02 346,970.55 4.00 1,824.39 SR -TY -GI 10,600.00 25.58 146.45 10,155.26 10,011.76 -1,530.49 1,002.52 2,461,100.65 346,973.37 4.00 1,829.60 10,700.00 21.58 146.52 10,246.90 10,103.40 -1,563.83 1,024.61 2,461,067.02 346,995.01 4.00 1,869.60 10,717.81 20.87 146.53 10,263.50 10,120.00 -1,569.21 1,028.16 2,461,061.60 346,998.50 4.00 1,876.04 SR -H-1 10,800.00 17.58 146.61 10,341.10 10,197.60 -1,591.79 1,043.07 2,461,038.83 347,013.11 4.00 1,903.10 10,815.09 16.98 146.63 10,355.50 10,212.00 -1,595.53 1,045.53 2,461,035.05 347,015.52 4.00 1,907.58 SR -14-5 10,899.07 13.62 146.76 10,436.50 10,293.00 -1,614.05 1,057.70 2,461,016.38 347,027.44 4.00 1,929.73 SR -11-7 10,900.00 13.58 146.76 10,437.40 10,293.90 -1,614.23 1,057.82 2,461,016.20 347,027.56 4.00 1,929.95 4/27/2018 5:55:58PM Page 5 COMPASS 5000.1 Build 81E Halliburton Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well SCU 33-33 Company: Hiloorp Alaska, LLC Target Name TVD Reference: SCU 344-33 WP05 RKS @ 143.50usft (HEC 169) Project: Soldoms CK Unit -hit/miss target MD Reference: SCU 344-33 WP05 RKB ,@ 143.50usft (HEC 169) Site: SCU 33-33 Northing Easting North Reference: True (°) (") (usft) (usft) Well: SCU 33-33 (usft) SCU 344-33 wp05 Target Survey Calculation Method: Minimum Curvature 10,849.04 -1,677.46 Wellbore: SCU 344-33 - plan hits target center Design: SCU 344-33 WP06 Casing Points Measured Vertical Casing Hole Depth Depth Planned Survey Diameter Diameter (usft) (usft) Name () Measured 6,250.00 Vertical 9 5/8" TOW Map Map 12-1/4 11,384.79 Depth Inclination Azimuth Depth TVDss +N/.S +E/ -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 10,381.50 10,989.50 10.00 147.00 10,525.00 10,381.50 -1,629.54 1,067.81 2,461,000.76 347,037.35 4.00 1,948.24 End Dir : 11,000.00 10989.5' MD, 10525' TVD 10.00 147.00 10,535.34 10,391.84 -1,631.07 1,068.81 2,460,999.22 347,038.33 0.00 1,950.06 11,017.42 10.00 147.00 10,552.50 10,409.00 -1,633.61 1,070.45 2,460,996.66 347,039.94 0.00 1,953.08 SR -H-9 11,100.00 10.00 147.00 10,633.82 10,490.32 -1,645.63 1,078.26 2,460,984.53 347,047.59 0.00 1,967.42 11,200.00 10.00 147.00 10,732.30 10,588.80 -1,660.19 1,087.72 2,460,969.85 347,056.86 0.00 1,984.79 11,293.62 10.00 147.00 10,824.50 10,681.00 -1,673.83 1,096.58 2,460,956.10 347,065.53 0.00 2,001.05 SR -H-13 11,300.00 10.00 147.00 10,830.78 10,687.28 -1,674.76 1,097.18 2,460,955.16 347,066.12 0.00 2,002.15 11,318.54 10.00 147.00 10,849.04 10,705.54 -1,677.46 1,098.93 2,460,952.44 347,067.84 0.00 2,005.37 11,384.79 10.00 147.00 10,914.28 - 10,770.78 -1,687.11 1,105.20 2,460,942.71 347,073.98 0.00 2,016.88 Total Depth : 11384.79' MD, 10914.28' TVD 10,234.58 9,831.50 Targets - Target Name -hit/miss target Dip Angle Dip Dir. TVD +NI -S +E/ -W Northing Easting -Shape (°) (") (usft) (usft) (usft) (usft) (usft) SCU 344-33 wp05 Target 0.00 0.00 10,849.04 -1,677.46 1,098.93 2,460,952.44 347,067.84 - plan hits target center - Circle (radius 50.00) Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name () ( ) 6,250.00 6,249.11 9 5/8" TOW 9-5/8 12-1/4 11,384.79 10,914.28 7" x 8 1/2" 7 8-1/2 Formations Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (usft) (usft) Name Lithology 11,293.62 10,824.50 SR_H_13 9,351.76 9,050.50 COAL 32 (HP WATER ZONE) 10,588.04 10,144.50 SR_TY_G1 11,017.42 10,552.50 SR_H_9 10,899.07 10,436.50 SR_H_7 10,815.09 10,355.50 SR_H_5 7,076.34 7,037.50 SR_TY_71-8 10,717.81 10,263.50 SIR _H_1 9,730.43 9,385.50 COAL_35 8,318.61 8,136.50 COAL -25 10,234.58 9,831.50 COAL39_39 4/272018 5:55:58PM Page 6 COMPASS 5000.1 Build 81E Database: Sperry EDM - NORTH US + CANADA Company: Hilmrp Alaska, LLC Project: Soldotna CK Unit Site: SCU 33-33 Well: SCU 33-33 Wellbore: SCU 344-33 Design: SCU 344-33 WP06 Plan Annotations Measured Vertical Depth Depth (usft) (usft) 6,250.00 6,249.11 6,981.45 6,953.55 10,544.76 10,105.91 10,989.50 10,525.00 11 384 79 10 914.28 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well SCU 33-33 TVD Reference: SCU 344-33 WP05 RKB @ 143.50usft (HEC 169) MD Reference: SCU 344-33 WP05 RKB @ 143.50usft (HEC 169) North Reference: True Survey Calculation Method: Minimum Curvature Local Coordinates +NIS +EI -W (usft) (usft) 7.02 -28.11 -125.82 69.91 -1,509.82 988.80 -1,629.54 1,067.81 -1,687.11 1,105.20 Comment KOP: Start Dir 4'1100' : 6250' MD, 6249.11 -TVD : 14131° RT TF End Dir : 6981.45' MD, 6953.56' TVD Start Dir 40/100' : 10644.76' MD, 10105.91'TVD End Dir : 10989.5' MD, 10525' TVD Total Depth: 11384.79' MD, 10914.28' TVD 41272018 5:55:58PM Page 7 COMPASS 5000.1 Build 81E Hilcorp Alaska, LLC Soldotna CK Unit SCU 33-33 SCU 33-33 SCU 344-33 SCU 344-33 WP06 JJL'�tl iCP;C=t'Ji�C�:b Clearance Summary Anticollision Report 30 April, 2018 Closest Appmach 3D proalmlty $can On Current Sumey Data (NOM Releranca) Reference Deslgn: SCU 3343-SCU U43-SCU 34443-SCU 34443 W(HIB Well Coondi ses: 2,462,644.03 N. 345.991.06 E (80' "' 16AD" N. 15P 51' 38.01' W) Datum Height: SCU 34443 WPoS RKD @ 143.W usN (HEC 169) Snn Range: 6,250.00 to 11,364.79 ueR Measured Depth. Sun Radlus Is Unlimited. Clarence Factor cuWff Is Unlimited. Maa Ellipse Sepaotlen Is 1.500 DO uefl Deo Oo SWe Factor Applied V Ido: MDA WW: SIE Sun Type Sperry Grilling Setwleee Hilcorp Alaska, LLC Soldolna CK Unit 10YA11 Ai -=;0.i _b"m�\�l Anticollision Report for SCU 3333 - SCU 344-33 WP06 Closest Approach 3D Proximity Scan on Current Survey Daft (North Reinter) Reference Design: SCU 33413 -SCU 33-33 -SCU 344413 -SCU W-33 WP06 Seen Range. 4250.00 to 11,304.79 usft Measured Depth. Scan Radius is Upturned. Clearance FacterculOD Is Unlimited Max Ellipse Separation is 1,500.00 daft Measured Minimum iliMeaaured Ellipse QMeasured Clearance Summary Based on Separation blaming Site Name Depth Distance Depth Separation Depth Factor Minimum Comparison Well Name - Wellbore Nam. - Dcelgn (usft) (usft) (.SR) (usft) usft SCU 1434 Soldolna CK Unit 14-34-SCU 443-33-SCU 44[3413 11,178.30 624.76 11,178.30 396.41 11,40055 2.736 Centre Distance Pass - SoldolnaCKUnit 1434-SCU 445-33-SCU 44B-33 11,200.00 62699 113200.00 39618 11413.34 2131 Ellipse Separation Pass - SoYfotnaCKUnit 1634-SCU 44B-33-SCU 448-33 11.2250o 62583 11,225.00 396.59 11,428.23 2730 Clearance Factor Pass- SCU 21-04 Bodotni CK Unit 44-33 - SCU 44-33 - SCU 44-33 10,954.42 292.75 10,954.42 13923 12,098.67 1 90 Centre Distance Pasa- Boldface CKUnit 44-33-SCU 44-33-SCU 4433 11,000.00 294.52 11,00000 13].6] 12,12439 1.978 Clearance Factor Pass SCU 3333 6,550.00 30.94 4550.00 24.20 4557.43 4.589 Clearance Factor Pass- SCU 3133-SCU 3343-SCU 33-33 SCU 3433 Sudden. CK Unit 13414-SCU 13-34-SCU 13-34 7.650 00 806.79 7,850.00 555.21 7,638.81 3207 Cbarance Factor Pass - Bodices CKUnit 13414-SCU 1134-SCU 13-34 7,700.00 80477 7,70000 555.14 7.6037 3224 Ellipse Separation Pass- SoldotnaCKUnit 1334-SCU 1134-SCU 1334 ].]3523 004.34 7,735.23 555.93 7,60875 3.238 Centre Data. Pace - SoldotnaCKUnit 13-34-SCU 13-U PBI -SCU 13414 7.650.00 806.79 7,8500 55521 7,838.81 3.207 Clean. Factor Pass - Solitaire CK Unit 13-34 - SCU 13-34 P01-SCU 13-M ],]00.00 804.77 ],]00.00 555.14 7,660.37 3.224 Ellipse Separation Pass - Socotra CKUnit 13 -SCU 13414 PB1-SCU 13-M ],]35.23 80434 7,735.23 555.93 7,880.75 3.238 Centre Distance Pa55- 13-36 PB2-SCU 13416 7,650.00 .]9 ],fi5.0o 55521 7,838.81 3.25 Clearance Factor Pass - SOltlotna CK Unit 1334-SCU 555.14 ],660.3] 3.224 Ellipse Separation Pass - SoldotnaCKUnit 13-34-SCU 13-U PB2-SCU 1134 7.700.00 804.]] ,](q.00 SWdotnaCKUnit1334-SCU 13-M PB2-SCU 13-94 Soldotna CK Unit 3433-SCU 34413 -SCU 34413 ],]3523 006.34 ]35.23 555.93 7.681 3230 Cenhe Distance Pass- - - SoldotnaCKUnit34-33-SCU 34-33-SCU 3433 - Soldolna CK Unit U4 33 - SCU 34-33- SCU 3433 SCU 41-04 Soldotna CK Unit 341-04- SCU 341-04-SCU 341-04 11,384]9 919.99 11,384.79 810.33 10,951.29 8390 ClainS.Factor Pass - SoldotnaCKUnit 341-04-SCU 41A41-SCU 41 A44 10,630.33 1,076.49 10,630.33 977.66 10.00082 10,892 Centre Distance Pass- COMPASS 30 April. 2018 - fangs Pape 2 of B Hileorp Alaska, LLC Soldotna CK Unit Anticollision Report for SCU 33-33 - SCU 344-33 WP06 7,995.71 010.71 7,995]1 688.88 7,810.47 Clpsart Approach 3D Proximity Scen an CUMMM Survey Data (North Reference) Pass - SeldotnaCKUnit 34333-SCU 343-33-SCU 343.33 8,02500 810.86 8,025.00 68885 ReferenceDesign: SCU 3343 -SCU 3343 -SCU 34443 -SCU 3"63 WP66 Sal Ellipse Separation Pass- SaldotnaCKUnit 34333-SCU 34333-SCU 343-33 8.100.00 812.61 8,100.00 Scen Ranee: 6,25e.00 W 11,381 usff. Measured Depth. 7,89998 6,636 Closer. Factor Pass - Socotra CKUnit 34333-SCU 43A33-SCU 43A-33 7,995.71 010.71 Scan Radius Is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 urs 7,813.97 6.654 Centra Distance Pasr- SOIdWnaCKUnit 34333-SCU 43A-33-SCU 43A33 Measured Minimum ®Measured Ellipse @Measumd Clearance Summary Based on Pass - Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Wamin9 Coppadspn Well Name -Wellbore Name - Design (usR) nett) (usa) naa) usa Soldotna CK Unit 341-04-SCU 41A-04-SCU 41A -o4 10,6lliom 1,076.58 10,650.00 9861 10.02000 10.078 Blpse Sapaation Pass- SDldotnaCKUnit 341-04-SCU 41 A-04-SCU 41 A-04 11,384]9 1,145.90 11,384]9 1,035.14 10,759.70 10.345 Clearance Factor Pass - SoldmnaCKUnit 341-04-SCU 41 B-04-SCU 410-04 11,213.66 461.75 11,213.66 350.78 11,003.00 4.161 Ellipse Separation Pass - SoidotneCKUnit 341-04-SCU 41 B-04-SCU 41 B-04 11,225.00 461.89 11,225.00 360.78 11,003.00 4.157 Clearance Factor Paul. - Saltless CKUnit 341-04-SCU 41 B-04PBI-SCU 418 10,450.00 893.85 10,450.00 793.69 9,908.00 8.924 Clearance Factor Panic - SoldotnaCKUnit 341-04-SCU 418-04PB1-SCU 41B 10,W000 092.24 10.50900 792.61 9,90800 0.955 Ellipse Separation Pass - SoldotneCKUnit 341-04-SCU 4104MPB1-SCU 41B 10,503.87 892.23 10,503.07 792.65 9.90800 8.960 Centre Distance Pass- Soldotna CK Unit 341-04-SCU 42-00-SCU 42-04 10,750.00 980.01 10]50.00 876.75 10,217.11 9.491 Cleaance Factor Pass - SDIdoNaCKUnit 341-04-SCU 42-04-SCU 4244 10,,45.00 979.59 10,775.00 876.44 10,217.11 9,497 Ellipse Separation Form - SoldotnsCKUnit 341-04-SCU 42-04-SCU 42-04 10,775.11 979.59 10,775.11 876.44 10,217.11 9497 Centre Distance Pass - Sol CK Unit 4 3-SCU 34333-SCU 343-33 7,995.71 010.71 7,995]1 688.88 7,810.47 6.654 Centre Distence Pass - SeldotnaCKUnit 34333-SCU 343-33-SCU 343.33 8,02500 810.86 8,025.00 68885 7,835.78 Sal Ellipse Separation Pass- SaldotnaCKUnit 34333-SCU 34333-SCU 343-33 8.100.00 812.61 8,100.00 690.16 7,89998 6,636 Closer. Factor Pass - Socotra CKUnit 34333-SCU 43A33-SCU 43A-33 7,995.71 010.71 7,995.71 680.88 7,813.97 6.654 Centra Distance Pasr- SOIdWnaCKUnit 34333-SCU 43A-33-SCU 43A33 8,025.00 810.86 8,025.00 688.85 7,839.28 6.646 Ellipse Separation Pass - SdOotnaCKUnit 34333-SCU 43A-33-SCU 43A33 8,100.00 812.61 8,100.00 69916 7,903.48 6.636 Claaance Factor Pass - Survey tool orooram From To Su mywlan Survey Tool (ural (usa) 9050 6,250.00 2_CB-FlIrl 6,25000 6155900 SCU 34433 WPa6 2_MWD_m,Mp Aad+Sag 6,550.00 11,384]9 SCU 34433 WPD6 2MWD+AK+Sag 30 Al MIS - 16:06 Page lots COMPASS ISI•\Aw1=111Eii�1►�1 Anticollision Report for SCU 3333 - SCU 344-33 WP06 Ellipse enor terms ere nelated across survey tool neon p hln Calmtatad ellipses h,.ry ate euma¢ errors. Sepeafion is the actual disbnce b.Meen ellipsoids. Distance Between centres Is the stayht line distance between wellbore centres. Cleamn¢Fedor =Distance BeN en Profiles/(Distance Bery en Profiles- Ellipse Sepeation). NI staficn caokinates were rslwlated usa,p the MMmum Curvature method. Hilcorp Alaska, LLC Soldotna CK Unit SO APO, 2018 - 16:06 Peps 40/6 COMPASS REFEFENCE INFORMATION WELL DETAYS 3CU 3133 NAD19E](NNICWIC ) AIW+inzW Protect: Soltlotna CK Unit MALLIBLIRTON cro�^c lanai 13sso Site: SCU 3333 awm.. Dre P.M1,.nu.«1cu a: T,*x�u Coµ Iw D%Pabnrc.. Ma Q113.!..! 1 4vS aF/.W WMinB FenmB IeOXUEe IunFluEe 1W1I'38 WBW BPerry Oollli o Well: SCU 3333 ..... rh w: bCU^aM f�K}CSPY9®Ma.WuePpE.. O,W OW 2<6369GOJ ms93L03 ,° 16401N Wellbore: SCU 34433 G.p„�RNr W.o 8 NMMD tlMme Plan: SCU 344-33 WPO6 SURVEY PROIX2PM GLOBAL FILTER: UslU user Eofl s 1 19 6250.00 To 113 Depth Fmm 0e th To. su'poil Tool 07.50 635OW s 9uwlgwaV}ta�Ptaw sxss)2CBFIImGMS CASING DETA rc ® Ladder/S.F. Plots 0250.00 &550.03 SCU 34633 WP[9(SCU 344x3) 3MJel]_I^1ary Kh5a9 M,saD hm Slie N. 656000 11384,79 WIJM43VI (SCJM14 2MW TVD TVD33 6249.11 610561 6210.00 9-W 9n. TOW 1091426 1077076 11384,79 7 T sB in- 'SCU 34-33 removed from ladder plot* _zoo.00 c GG1133-33 0180.00 I m SGU 44-33 -tzDoO m m 80.00 v U 4000 y — ----T—--- SCU 3333 U 0.00 5250 5625 8000 6375 6750 7125 7070 7875 8250 8625 9000 9375 9750 10125 10500 10875 11250 11625 12000 Measured Depth (750 Usfilfin) 4.50 m 3,00— q c, Collision Ris4 Procedures Req. � ! Collision Avoidance Req. No -Go Zone -Stop Drilli g SCU 34.33 ! 0.00 52W 5600 6000 8400 6800 7200 7800 8000 8400 8000 9200 9600 10000 10400 10800 11200 11600 12000 Measured Depth Schwartz, Guy L (DOA) From: Monty Myers <mmyers@hilcorp.com> Sent: Thursday, May 10, 2018 7:18 AM To: Schwartz, Guy L (DOA) Cc: Davies, Stephen F (DOA) Subject: RE: SCU344-33 (PTD 218-054) Good morning Guy. The MPD system is the real deal. It will be MI Swaco's system that has been on rig 169 before when it drilled for Ahtna in Glennallen. We will use weighted mud caps inside the window while tripping and running liner to hold the flow back when we are open to atmosphere. We can definitely attempt to get a 12.5 ppg equivalent FIT. Thank you! Monty M Myers Drilling Engineer 907.538.1168 (c) 907.777.8431 (o) From: Schwartz, Guy L (DOA) [mailto:guy.schwartz@alaska.gov) Sent: Wednesday, May 9, 2018 2:04 PM To: Monty Myers <mmyers@hilcorp.com> Cc: Davies, Stephen F (DOA) <steve.davies@alaska.gov> Subject: RE: SCU344-33 (PTD 218-054) Monty, Couple more things. 1) You mention the Tyonek water flow zone is possible and using MPD to manage influx. So ... Is this a real MPD system with rotating head etc.?? 2) The planned FIT of 11.5 is a bit skinny if you have to weight up past 10 ppg with mud. Consider taking the FIT up to 12.5 or Leak off. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIAL(IY 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 Guy Schwartz at (907-793-1226 1 or (Cauy.schwartz@alaska aov). From: Schwartz, Guy L (DOA) Sent: Wednesday, May 09, 2018 11:54 AM To: mmyers@hilcorp.com Subject: SCU344-33 (PTD 218-054) Monty, Has the P & A sundry for the parent well SCU 33-33 been submitted yet? I am working on the ST PTD now. Make sure it includes up to milling the window. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIAUIY 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 Guy Schwartz at (907-7931226 ) or (Guv schwartz@alaska.aov). Kick Tolerance Calculations guy schwartz 5/9/2018 input in yellow areas only SCU 344-33 PTD 218-054 MW (ppg) 10 ppg LOT/FIT(ppg) 11.5 TVD Casing Shoe (ft) 6250 ft TVD If a formation deeper than the casing shoe is known to be weaker than the casing shoe (have a lower fracture gradient/LOT) then that weaker formations TVD and LOT can be used in place of the casing shoe information for more accurate calculations Kick Intensity (ppg) 0.5 ppg Formation Pore Pressure cannot be less than the MW to have a kick! 0.5 ppg kick tolerance over current MW is a standard assumption Assume that the kick is hydrocarbon gas (not all or water) TVD of Kick Influx (ft) 10900 ft TVD Gas Gradient (psi/ft) 0.1 psi/ft Change only if gas gradient is known to be different Hole Size (in) 8.5 inches Drill Pipe OD (in) 4.5 inches BHA OD (in) 6.75 inches Lenth of BHA (ft) 250 ft If the BHA is longer than the open hole, the kick will come to surface very quickly due to the smaller annular capacity 0.0505 bbl/ft Annular Capacity between OH and DP 0.0259 bbl/ft Annular Capacity between OH and BHA 487.5 psi Maximum Allowable Surface Pressure 283.4 psi Underbalance due to Kick Intensity 204.1 psi margin before casing shoe is broken down/fractured (or weakest formation below casing shoe) Height of Gas Kick 486.0 feet Volume of Gas Kick 12.6 bbl CASE 1 Assume Kick is only around the BHA (not the DP) at the influx depth Volume of Gas Kick 24.5 bbl Assume Kick is only around the DP (not the BHA) at shoe depth Volume at influx 15.4 bbl CASE 2 depth Conversion KICK TOLERANCE: 12.6 bbl Compare CASE 1 and CASE 2 volumes for the gas influx above. The smallest volume is selected to represent the maximum kick volume allowed without breaking down the shoe (or weakest formation) It is difficult to shut in a well with less than a 10 bbl kick volume Davies, Stephen F (DOA) From: Monty Myers <mmyers@hilcorp.com> Sent: Wednesday, May 9, 2018 12:35 PM To: Davies, Stephen F (DOA) Subject: RE: SCU 344-33 (PTD #218-054) - Questions Good afternoon Steve! Sorryit took me so long to reply. Please see below. 1. Does Hilcorp monitor H2S in Soldotna Creek Unit or Swanson River Field wells? If so, could Hilcorp please provide copy of the latest reported measurement for each well? Hilcorp does not monitor H2S on an as well basis. We only monitor at the field level where it comes in to the gathering station. However, we have identified a couple of wells where the H2S may be coming from, but we do not have H2S monitoring on these wells. 2. Will this well be pre -produced for 30 days or longer, or will it be flowed back for a short time for clean up only? This well will not be pre -produced to my knowledge. And if any flowback is performed to clean the well up, it will be only for a short amount of time. Monty M Myers Drilling Engineer 907.538.1168 (c) 907.777.8431 (o) From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska.gov) Sent: Monday, May 7, 2018 3:53 PM To: Monty Myers <mmyers@hilcorp.com> Subject: FW: SCU 344-33 (PTD #218-054) - Questions Monty, Compiling all of my questions into a single email: 1. Does Hilcorp monitor 112S in Soldotna Creek Unit or Swanson River Field wells? If so, could Hilcorp please provide copy of the latest reported measurement for each well? 2. Will this well be pre -produced for 30 days or longer, or will it be flowed back for a short time for cleanup only? Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.daviesPalaska.gov. Davies, Stephen F (DOA) From: Davies, Stephen F (DOA) Sent: Monday, May 7, 2018 3:53 PM To: Monty Myers (mmyers@hilcorp.com) Subject: FW: SCU 344-33 (PTD #218-054) - Questions Monty, Compiling all of my questions into a single email: 1. Does Hilcorp monitor H2S in Soldotna Creek Unit or Swanson River Field wells? If so, could Hilcorp please provide copy of the latest reported measurement for each well? 2. Will this well be pre -produced for 30 days or longer, or will it be flowed back for a short time for cleanup only? Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.daviesraalaska.aov. Remark: AOGCC PTD No. 218-054 - Coordinate Check 7 May 2018 INPUT Geographic, NAD27 OUTPUT State Plane, NAD27 5004 -Alaska 4, U.S. Feet SCU 344-03 1/1 Latitude: 60 44 16.40050 Northing/Y: 2462644.026 Longitude: 150 51 38.00810 Easting/X: 345991.060 Convergence: -0 45 02.72846 Scale Factor: 0.999926990 Corpscon v6.0.1, U.S. Army Corps of Engineers Furor P - i SUBMIT IN DUA' E' p, n D STATE OF ALASKA in nrrur in 11 Atr InnP 4 AP SI➢fER1CAL CO ' t fl`V CITY MIrIvi YI OIL AND GAS CONSERVATION COMMITTEE WELL COMPLETION OR RECOMPLETION REPORT AND LOG* a. TYPE OF WELL: ou. uAR O'NLI. lJ(1 WILL U DRY EJ bthPr b. TYPE OF COMPLETION: NEW jam• WORK r-1 DEEP. eLCO PIF" W'eLr, l.A� "'F'R " E.S ❑ DACK ❑ EERYD. Other t, SAME or OPERATOR CHEVRON U.S.A. 4. L,irAL10N of WELL (Report IOEDtWn mcu..y u.o .•• �•�- ----- ---- - - At aurtaee (400' N &1700' W from S.E. cor. of Sec. 33; T -8N, Ir SEC.. T., R., 11., (BOTTOM HOLE OWECTIVE) R -9W S.B. & M - SEC. 33; T -8N, R -9W At top prod. Interval reported below 84' North and 27' West of surface SIB, & M At total depth location. Not determined. a. PEwtnT No. a 7/23/76 12/9/76 2/14/77 153' K.B. ta. TOTAL DEPTH, mri &TVD 'J. PLVG, HACK RI 8: TY HOW MAN CO.•'R=L.. al'ROTARY TOOLS �t]-tE—Rt'AL�URIL—LED�a�Y rAtl IR TOOLS 17689'MD 17684'TVD `0LvG'MD 10664 'D 0 - 17689 l No IM. WAS DIRECTIONAL aa. PRODUCING INTERVAL(S'. OF THIS (AJh1PLET10N-TOP. BOTTOM, NAME lMD AND TVD)' 1 SURVEY MADE Top 10562' MD 10561' TVD HEMLOCK I Yes Bottom 10658'MD 10657'TVD 21. TYPE ELFCTitIC AND OTHER LOGS RUN DIL SONIC FDC/CNE dipmeter CBL, GRE, Velocity Survey a9. CASING RECORU 1 R�Vurl all Wing- act ), etU GASL L TLE \EIGHT LB PT IE GRADE 'D PPII SET (MD) I HOLE Z T CUa-NTING RECORD 1 A."IOVNT PULLED 1 1 1.1_1 /7D 1 rnn eYc "n," R097' r 2R, LINER RECORD i TUBING REZ0::D SIZE TOP (MD) EO'['1'OR9 IMDI SACKS CL'M�T• SCi.ELN rA:D) SIZE UEPI-H SET 1\:Dr 1 PACHCR SET (34D) N- PERFORATIONS OPEN TO PRODUGTIG Nntcrval, EIEC and r-umbOfl ''^J. ACID. 5'=. F;::: IsItE, CEALNT SOU=LZ ECC. 10562 - 10588' DMITI= I:N ERW-L (NIDI Ai,fOL'NT . ND Ii1NU OP Dl E? -AL USED 10610 - 10628' Three 1/2" holes per foot. 10640 - 10645' 10651 - 10658' —30 - - PROD, DATE FIRST PRUDVC.TION PRODUCTION MLIHO 2/13/77 1 F 9— PATE Or TEAT, I HOURS I ESTED ICIIOSE SIZE Flowln O, Iss lift. Dutn VinE-siu and t5 P, o[ yurt�+!� C �{� or / OATt: SIGNED .� TITLE --Aim-unCJtiteBP--- *( ee Instructions Gnd Spaces For Additional Data on Reverse Side) z�,- �n WELL SURVEY Pro -312 e r✓��i WELL NO. SCU 33-33 COUNTY OF Kenai CITY OF �J SECTION N0. 33 TOWNSHIP 8N RANGE 9W ® S.B.B. i M. 0 M.D.B. i M. TRACT NO. LOT NO. FIELD Swanson River 0 PROPOSED 1 1701 ft Westerly � right angles from ea -t hnnndary 0 PRELIMINARV } LOCATION Sec 33 and 1404 ft. Northerly at right angles from a FINAL 111 Southerly boundary Sec 33 T 8N R 941. ELEVATION: GROUND CONCRETE MAT DERRICK FLOOR A n R T I n Y LOCATION DE310MATION A - LOCATION COORDINATES - - _ MOVE REMAINS Final N 22-097 264-97 WEST E 2,023,111.70 F'L Position to existin y well "Christmas Tree" z "�71d ,11I[ICn UN KLMKRJ 0 FQ G)J f 33-33 0 M c ao F To we // SOUTH .1. 5Ru 23-33 RFrrw uARv tAe Tnn Snuth rim r.-M.P. cellar elevation 129-05 ft STATION MEANING DISTANCE SINE COSINE NORTH SOUTN-,„•.EAST WEST F'L y z "�71d Gary. Dra:k• C.C. DIV. ENGR. FILE SURVEYOR G Deo s k,; MAINT. FRMN. MAINT. SUPT. nl TF A �..: 1 I / 77 HTF nATF TRANSMITTAL LETTER CHZECKLIST WELL NAME: /i�� ✓ 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 The permit is for a new wellbore segment of existing well Permit LATERAL (Iflast two digits No. , API No. 50---- 0-=(If Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69 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 Pilot Hole name ( PH) and API number (50-= from records, data and logs acquired for well name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where sam les are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (ComName) must contact the AOGCC to obtain advance approval of such water well testing program. 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 ✓ (Company Name) in the attached application, the following well logs are also required for this well: L, �'r 14--6,Y".40 Af Well Logging /k,�b Ya., i / lco S (tea /-- Requirements ej�- e/a{� / q �0 o 7. /8 25.071, Per S to AS 31.05.030(dx2)(B) and Regulation 20 AAC composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, sus nsion or abandonment of this well. Revised 512013 WELL PERMIT CHECKLIST Field & Pool SWANSON RIVER, HEMLOCK OIL - 772100 Well Name: SOLDOTNA CK UNIT 344-33 Program SER Well bore seg ❑ PTD#:2180540 Company HILCORP ALASKA LLC Initial Class/Type SER / 1GINJ GeoArea 820 Unit 51950 On/Off Shore On Annular Disposal ❑ Administration 17 Nonconven, gas conforms to AS31,05.0300.1.A),0.2.A-D) .... .... ...... NA ........ . . . ...... 1 Permit fee attached - - _ - NA_ 2 Lease number appropriate. _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ Surface Location lies within FEDA028990: Top Prod Int & TD lie within FEDA028997, 3 Unique well. name and number _ - _ _ _ _ _ _ _ _ _ _ _ _ _ Yes 4 Well located in.a_defined pool _ _ _ _ _ _ _ _ .Yes _ _ _ Swanson River, Hemlock Oil Pool - 772100 governed by CO 1238.. 5 Well located proper distance from drilling unit boundary_ _ _ _ - _ Yes - _ _ CO 1238, Rule 5; There shall be no restrictions as to the wellspacingwithin the. Hemlock Oil Pool except. 6 Well located proper distance from other wells_ ...... Yes _ .. - that -no wellbore may. be open to test or regular production -in a well within 500' of the external property 7 Sufficient acreage available indrillingunit_ .... _ ..... Yes line of the Affected Area -where the owners and landowners are -not the same on -both -sides of the line.. As 8 If deviated, is wellbore platincluded_ _ - _ - _ _ _ _ _ _ _ _ _ Yes _ _ _ - _ planned, this well conforms to spacing requirements. 9 Operator only affected part- - - - - - - - - - - - - - - - - - - _ _ - - - - - - - Yes 10 Operator has. appropriate bond in force _ _ _ ..... Yes- Appr Date 11 Permit can be issued without conservation order _ _ _ _ _ _ _ _ _ _ _ _ - . Yes 12 Permit can be issued without administrative approval - _ - _ - - - _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ SFD 5/9/2018 ... 13 Can permit be approved before 15 -day wait ......... .. ....... Yes ....... _ 14 Well located within area andstrataauthorized by Injection Order # (put 10# incomments) (For - Yes _ _ _ _ - _ Swanson River, Hemlock Oil Pool r 772100 governed by AID 13A__ 15 All wellswithin114 mile area.of review identified (For service well only) .............. Yes ....... SCU 3433, SCU 433, SCU 448-33, SCU 418-04, SCU 341-04, SCU 41A-04_ 16 Pre -produced injector: duration of pre production less than 3 months (For service well only) _ - No 18 Conductor stringprovided- - - - - - - - -- - - - - - - - - - - - - - _ _ _ _ - - _ _ _ - _ --- --- NA . - _ - _ _ - Conductor and surface casing set in-motherbore. - ................ Engineering 19 Surface casing protects allknownUSDWS _ _ _ _ _ - _ _ _ _ _ _ _ _ NA 20 CMT vol adequate to circulate on conductor & surf csg ................. . . . .. . .NA 21 CMT vol adequate to tie-in long string to surf csg..... . ...................... NA .. _ ..... 22 CMT. will cover all known productive horizons_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes 23 Casing designs adequate for C, T, B & permafrost _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ - BTC supplied for liner. 24 Adequate tankage, cr reserve pit _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ Rig has steel tanks,., all Waste to approved disposal well of site. 25 If a_re-drill, has. a 10-403 for abandonment been approved ..... _ _ _ _ Yes _ _ _ . sundry 318-195to plug SCU 33-33 (PTD 176-056) 26 Adequate wellbore separation_ proposed _ _ _ - _ _ _ _ _ _ _ _ _ _ Yes _ _ Close approach to well SCU 34-33.. Will take appropriate measues 27 1f.diverter required, does it meet regulations _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA _ - Wellhead in place ... will use BOPS, Appr Date 28 Drilling fluid. program schematic.& equip list adequate _ . _ _ Yes _ _ _ _ - Max form pressure =.4693 psi (8,3_ ppg EMW). Will idrill with,MPD and -9.5-11.5 mud (FIT T012.5 ppg). GLS 5/21/2018 29 BOPEs,.do they meet regulation .... - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ Saxon 169 -has 11" 5000 psi BOPE . _ _ ... 30 BOPE-press rating appropriate; test to.(put psig in comments) .................... Yes .. _ .. MASP 2400 psi will test BOPE to 3500 psi ( using alllfluid gradient. 2/3 -gas column. 31 Choke manifold complies w/API RP -53 (May 84)- _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ Yes 32 .Work will occur without operation shutdown_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - Yes - _ _ _ - - need sudnry_for completion and perforating. -CBL is required for Gas injection well...... 33 Is presence of H2S gas probable. . .. . ...... . No .. H2S not expected but rig has sensors and. alarms............. 34 .Mechanical condition of wells within AOR verified (Fo(service well only) _ _ _ _ _ - _ _ _ _ _ Yes - - _ - - - 1/4 AOR completed.. Offset wells are cemented.above rejection zone and mechanically sound. 35 Permit can be issued w/o hydrogen sulfide measures ................... Yes _ .... H2S not reported from.Soldotna Creek Unit or Swanson River Field. Rig has sensors and alarms.. Geology 36 Data. presented on potential overpressure zones _ - - - - - - - - - - - - - - - - - - - - - - Yes . _ _ _ - - Under -pressured reservoir (4.0 to 4.2 ppg EMW) expected; will be drilled using 9.5 - 11.5 ppg mud.. Appr Date 37 Seismic analysis of shallow gas zones _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA - - - High-pressure Tyonek Water Sand 01.5-14.0 ppg) lies at about 9380'.MO/8900' TVD.. Hilcorp SFD 5/9/2018 38 Seabed condition survey (if off -shore) _ - - _ - _ _ NA _ _ _ - _ - weights up to -11.5 ppg and kills any flow with ECD while drilling, Before tripping, heavy pills are.. 39 Contact name/phone for weekly progress reports [exploratory only] _ _ _ _ _ _ - - _ NA _ _ _ _ spotted to stop any flow. Any flow is treated as gas unfit Hitcorp is certain that it is -NOT gas._ Geologic nglneering ti�n,�� Pu tic Gas injection well. SIT of SCU 33-33. gls Commissioner: Date: C mm' sio r: Date �'QQ � 5 ate I � kk \&\k 89 1lmmiFSCsi Zr