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Home My WebLink About221-026DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-883-20023-01-00Well Name/No. N COOK INLET UNIT A-04ACompletion Status1-GASCompletion Date11/6/2021Permit to Drill2210260Operator Hilcorp Alaska, LLCMD6317TVD5527Current Status1-GAS12/17/2021UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:LWD/MWD Logs, CBLNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF9/22/20212814 6317 Electronic Data Set, Filename: NCIU A-04A LWD Final.las35679EDDigital DataDF9/22/2021 Electronic File: NCIU A-04A LWD Final MD.cgm35679EDDigital DataDF9/22/2021 Electronic File: NCIU A-04A LWD Final TVD.cgm35679EDDigital DataDF9/22/2021 Electronic File: NCI A-04A - Definitive Survey Report.pdf35679EDDigital DataDF9/22/2021 Electronic File: NCI A-04A - DSR.txt35679EDDigital DataDF9/22/2021 Electronic File: NCI A-04A - DSR_GIS.txt35679EDDigital DataDF9/22/2021 Electronic File: NCI A-04A DSR Actual - Plan.pdf35679EDDigital DataDF9/22/2021 Electronic File: NCI A-04A DSR Actual - VSec.pdf35679EDDigital DataDF9/22/2021 Electronic File: NCI A-04A Final Surveys.xlsx35679EDDigital DataDF9/22/2021 Electronic File: NCIU A-04A LWD Final MD.emf35679EDDigital DataDF9/22/2021 Electronic File: NCIU A-04A LWD Final TVD.emf35679EDDigital DataDF9/22/2021 Electronic File: NCIU A-04A LWD Final MD.pdf35679EDDigital DataDF9/22/2021 Electronic File: NCIU A-04A LWD Final TVD.pdf35679EDDigital DataDF9/22/2021 Electronic File: NCIU A-04A LWD Final MD.tif35679EDDigital DataDF9/22/2021 Electronic File: NCIU A-04A LWD Final TVD.tif35679EDDigital Data0 0 2210260 N COOK INLET UNIT A-04A LOG HEADERS35679LogLog Header ScansDF11/22/20212270 2050 Electronic Data Set, Filename: NCI_A-04A_CBL_25-Oct-2021_(3549).las35966EDDigital DataDF11/22/2021 Electronic File: NCI_A-04A_CBL_25-Oct-2021_(3549).pdf35966EDDigital DataFriday, December 17, 2021AOGCCPage 1 of 2NCIU A-04A LWD Final.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-883-20023-01-00Well Name/No. N COOK INLET UNIT A-04ACompletion Status1-GASCompletion Date11/6/2021Permit to Drill2210260Operator Hilcorp Alaska, LLCMD6317TVD5527Current Status1-GAS12/17/2021UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Compliance Reviewed By:Date:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date: 11/6/2021Release Date:6/18/2021DF11/22/20216191 5827 Electronic Data Set, Filename: NCI_A-04A_Perf_06-Nov-2021_(3556).las35967EDDigital DataDF11/22/2021 Electronic File: NCI_A-04A_Perf_06-Nov-2021_(3556).pdf35967EDDigital DataFriday, December 17, 2021AOGCCPage 2 of 2M. Guhl12/17/2021 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 11/19/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL NCI A-04A (PTD 221-026) Perf 11/04/2021 Please include current contact information if different from above. 37' (6HW Received By: 11/22/2021 By Abby Bell at 1:26 pm, Nov 22, 2021 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 11/19/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL NCI A-04A (PTD 221-026) CBL 10/25/2021 Please include current contact information if different from above. 37' (6HW Received By: 11/22/2021 By Abby Bell at 1:23 pm, Nov 22, 2021 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7.Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval: 9.Ref Elevations: KB: 17.Field / Pool(s): North Cook Inlet Field GL: N/A BF: N/A Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 (ft MSL) 22.Logs Obtained: 23. BOTTOM 4-1/2" L-80 5,524' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate326 August 25, 2021 August 20, 2021 ADL017589 N/A N/A 2,810' MD / 2,572' TVD99 317' MD / 317' TVD 6,317' MD / 5,527' TVD LWD/MWD Logs, CBL Sr Res EngSr Pet GeoSr Pet Eng N/A N/A Oil-Bbl: Water-Bbl: 006230 Oil-Bbl: 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/A6230 Flowing *** Please see attached schematic for perforation data *** 0 Water-Bbl: PRODUCTION TEST 11/4/2021 Date of Test: 39 11/8/2021 24 Flow Tubing 0 12.6# 6,312' Gas-Oil Ratio:Choke Size: Per 20 AAC 25.283 (i)(2) attach electronic information DEPTH SET (MD) 2,678' MD / 2,471' TVD PACKER SET (MD/TVD) CASING WT. PER FT.GRADE 333524 334072 TOP SETTING DEPTH MD 2,678' SETTING DEPTH TVD 2587056 BOTTOM TOP 2,471' HOLE SIZE AMOUNT PULLED 50-883-20023-01-00 NCIU A-04A 332108 2586718 1473' FNL, 2509' FWL, Sec 6, T11N, R9W, SM, AK CEMENTING RECORD 2586484 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 1259' FNL, 1086' FWL, Sec 6, T11N, R9W, SM, AK 894' FNL, 1977' FEL, Sec 6, T11N, R9W, SM, AK 221-026 / 321-334 Tertiary Gas Pool 126.6' 6,220' MD / 5,449' TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas 6-1/8" 389 sx 2,694'4-1/2" Tieback Tbg SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, TUBING RECORD WINJ SPLUG Other Abandoned Suspended Stratigraphic Test No No (attached) No Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment By Meredith Guhl at 9:07 am, Nov 12, 2021 8/27/2021 )&8 RBDMS HEW 11/16/2021 Completion Date 11/6/2021 HEW GBJM 12/16/21 DSR-12/1/21DLB 11/29/2021 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD N/A N/A Top of Productive Interval 5,037' Bel A 4,534' 3,894' 3,522' 5,037' 4,534' 5,146' 4,621' 5,374' 4,797' 5,501' 4,895' 5,659' 5,015' 5,846' 5,160' 6,043' 5,314' Bel I 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Cody Dinger Contact Email:cdinger@hilcorp.com Authorized Contact Phone: 777-8389 General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: 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. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. 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). 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. 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. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). 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. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment, whichever occurs first. Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Formation at total depth: Bleuga C Wellbore Schematic, Drilling and Completion reports, Definitive Directional Surveys, Csg and Cmt Report. Signature w/Date: 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. INSTRUCTIONS 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. TPI (Top of Producing Interval). Yes No Well tested? Yes No 28. CORE DATA If yes, list intervals and formations tested, briefly summarizing test results. Attach separate pages to this form, if needed, and submit detailed test information, including reports, per 20 AAC 25.071. NAME Beluga G Beluga D Beluga A Beluga B Sterling 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. 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. If Yes, list formations and intervals cored (MD/TVD, 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. Authorized Name: Monty Myers Authorized Title: Drilling Manager Beluga E Beluga F Permafrost - Base 29. GEOLOGIC MARKERS (List all formations and markers encountered): FORMATION TESTS Permafrost - Top No NoSidewall Cores: Yes No Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment 11.12.2021Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2021.11.12 08:05:24 -09'00' Monty M Myers _____________________________________________________________________________________ Updated By: CJD11/11/21 SCHEMATIC Tyonek Platform Well: NCI A-04A Last Completed: 8/27/21 PTD:221-026 API: 50-883-20023-01-00 CASING DETAIL Size Wt Grade Conn ID Top Btm 30”Conductor Welded 29”Surf 390’ 16”65 H-40 Welded 15.25”Surf 576’ 10-3/4”51/45.5 J-55 BTC 9.794”Surf 2,410’ 7” 26/23 J-55 BTC 6.366” Surf 2,810’ (TOW) 4-1/2”12.6 L-80 DWC 3.958 2,678’6,312’ TUBING DETAIL 4-1/2”12.6 L-80 IBT 3.958 Surf 2,694’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 1 317’317’2.125 5.000 SSSV PN 21727-000-00002 WRDP-2-BAL-SSA-S Open Pressure 1987 2 1,423’1,412’3.833 5.984 GLM#2 BK Latch Profile (Arctic Lift Systems) 1'' Valve 3 2,568’2,388’3.833 5.984 GLM#1 BK Latch Profile (Arctic Lift Systems) 1'' Valve 4 2,628’2,433’3.813 5.020 X Nipple 3.813 GX Profile 5 2,678’2,471’ HRD-E-HD ZXP Liner Top Packer 5 Set Screws 25000# Shear 4.25 RS Profile (10.72, 5.25 Seal Bore) 6 2,683’2,475’3.950 5.720 No Go locator / Seal Assembly 7 2,810’2,572’Whipstock (TOW @2,810’ MD) PERFORATION DETAIL Zone Top (MD)Btm (MD)Top (TVD)Btm (TVD)FT Date Status Bel A 5,037'5,047'4,534’4,542’10'11/6/21 Open Bel A 5,122'5,138'4,602’4,615’16'11/6/21 Open Bel B 5,148'5,162'4,622’4,633’14'11/6/21 Open Bel B 5,182'5,187'4,648’4,652’5'11/6/21 Open Bel B 5,258'5,273'4,708’4,719’15'11/6/21 Open Bel B 5,333'5,348'4,766’4,777’15'11/6/21 Open Bel C 5,376'5,387'4,799’4,807’11’11/6/21 Open Bel C 5,464'5,484'4,867’4,882’20'11/5/21 Open Bel D 5,521'5,541'4,910’4,925’20'11/5/21 Open Bel D 5,604'5,619'4,973’4,984’15'11/5/21 Open Bel D 5,643’5,652'5,003’5,010’9'11/5/21 Open Bel E 5,692'5,707'5,040’5,052’15'11/5/21 Open Bel E 5,711'5,720'5,055’5,062’9'11/5/21 Open Bel E 5,746’5,756'5,082’5,090’10'11/5/21 Open Bel E 5,756'5,776'5,090’5,105’20'11/5/21 Open Bel E 5,785'5,802'5,112’5,125’17'11/4/21 Open Bel E 5,821'5,832'5,140’5,149’11'11/4/21 Open Bel E 5,832'5,846'5,149’5,160’14'11/4/21 Open Bel F 5,876’5,890’5,183’5,194’14'11/4/21 Open Bel G 6,028’6,038’5,302’5,310’10'11/4/21 Open Activity Date Ops Summary 7/16/2021 NCIU St 17589 1A P&A acitivity. Rig down and move off well. Rig released from well at 19:00, see NCIU St 17589 1A P&A report for details. Moving off well on slack tide at 18:42.;Maintain station with tugs Anna T, Bering Wind, Glacier Wind and Stellar Wind while raising legs to 45' over the sea floor. Begin moving west then north west, crossed pipeline with 37' clearance at 19:41. Start lowering legs at 19:46 and were 12' off bottom at 19:57.;The synthetic winch line from Stellar Wind to port stern broke at 20:02. Current was picking up and pushing the rig further NNE. Began raising legs at 20:12 to lessen effect from current and were 45' off bottom at 20:42.;Rig was out of the surveyed area and could not lower legs to pin and the incoming current was picking up. Stellar Wind connected to port stern with another winch line. Decision was made to hold rig in position with tugs.;Maintain position as best as possible with approximately 80% power from all tugs. Started at 2100' from the Tyonek and got within 500' as current lessened. Reduce power and maintain position while waiting on 00:36 slack high.;Begin lowering legs at 23:15 to 10’ above sea floor at 23:47. Orient rig at 323* heading and move in toward the Tyonek platform. High tide at 23:59.;Lower legs and tag bottom at 00:13. Commence final positioning at 00:29. Slack tide at 00:36. Pin stern and lower bow at 00:49. Continue to position and had to reposition the Glacier Wind from port to starboard bow at 1:30.;Fight 2 knot current attempting to position. Current increased to 4 knots and actually moved further away. The decision was made to continue final positioning at 06:40 low tide. Tyonek operations moved ESD out of the way on handrail.;Lower legs and pin rig. Unhooked tow lines from two up current tugs and two down current tugs remained attached. Wait on slack tide. 7/17/2021 Hooked up tugs, jacked the rig and was floating at 6:55. Low tide at 6:40 and slack at 7:59. Spartan 151 hard pinned at 8:30 with 1’ air gap at 8:45. Verify position, slight skew to rig of 1.18° = 13” lateral movement over 53’ of skid out - good. Release tugs at 9:30.;Offloaded PSOs to the Masco Endeavour. Jack rig up to 1' of air gap. Maintain 1' air gap until high tide is reached. Calculate pre-load. Lower deep well.;Perform Mesotech MS-1000 side scan sonar image of spud cans at 12:27 high tide (13:37 slack) – looked good. eTrac technicians rigged down equipment and departed on afternoon chopper.;Began filling ballast tanks with preload - fill P-01 and P-02.;Pull blind flanges on remaining pre-load tanks. Install wing decks on port side. Perform general rig maintenance while waiting on tide to come back to resume pre-load sequence.;Sand blasting personnel and equipment arrived on the Tyonek platform and were transferred to Spartan 151. Rig manager Donnie Durham and the driller toured Tyonek for electrical cable layout.;Filled pre-load tanks P-10-5 & P-10-6, bow pre-load complete. Hold pre-load for one hour - good.;Transfer ballast water from P-01 & P-02 to P-19-1 & P-19-2. 7/18/2021 Continue to transfer water from pre-load tanks P-01 and P-02 to P-19-1 and P-19-2.;Wait on high tide to pre-load stern legs. Cover all equipment under the rig floor to protect from sandblast dust. Move pump and lines to prepare for pre-load on stern legs. Install wing deck on starboard side of the rig. Scaffolding crew mobilizing and start building scaffolding to work on sub beams;Rig crew performed man overboard rescue drill with rescue boat.;Fill stern leg pre-load tanks 10-5 and 10-6. Continue to build scaffolding - (scaffold builders end of shift at 18:00). Disconnect hydraulic lines from skid unit to allow full access to sandblast beams. Connect 2" high pressure hose to mud pump. Cover shaker motors to protect from sandblast sand.;Rig crew performed man overboard rescue drill with rescue boat - both crews understand roles and responsibilities.;Pre-load completed at 00:15, hold for one hour to 01:15 - good. Release rig mover and marine surveyor. Rinse mud pits with ballast water. Continue general rig maintenance and clean main deck 7/19/2021 Continue rig maintenance. Utilize Tyonek crane to install gangplank between Spartan 151 and the Tyonek. Scaffolding crew and sandblasting crew resumed erecting scaffolding and installing tarps. Received 3 additional scaffolding crew for a total of 5.;Utilize Tyonek crane to install 2" high pressure hose from Spartan 151 sub to Tyonek well head room.;Verify pump stroke counters work - good. Flood lines to Tyonek injection well. Pressure test lines to 650 PSI low / 3300 PSI high - good. Begin injecting pit cleaning water at 0.7 BPM, 250 PSI. Increase rate and saw break over at 550 PSI. Continue up to 2.4 BPM, 2000 PSI.;Max rate for injection well is 2.4 BPM and 2500 PSI. Pressure began to climb to 2200, slowed to 1.7 BPM, 1900 PSI then increase to 2.0 BPM, 2050 PSI. After pumping 272 bbls, increased back to 2.4 BPM, 2200 PSI.;Held meeting with DSM, Tyonek foreman & lead, rig manager, OIM, Enterprise safety rep and medic to discuss emergency muster procedures while the Spartan rig is on the platform.;Scaffolding crew end of shift at 18:00 - 70% complete.;Continue to inject pit cleaning water at 2.4 BPM, 2150 PSI - 1915 bbls injected at 24:00. Perform general rig maintenance and housekeeping.;Continue to inject pit cleaning water at 2.4 BPM, 2150 PSI. 2775 total bbls injected at 06:00. Perform general rig maintenance and housekeeping. 7/20/2021 Continue to inject pit cleaning water at 2.4 BPM = 2150 psi. 3525 total bbls injected at 12:00. Continue to build scaffolding for sand blasters. Perform general rig maintenance and housekeeping.;Continue to inject pit cleaning water at 2.4 BPM = 2150 psi. 5252 total bbls injected at 12:00. Continue to build scaffolding for sand blasters. Perform general rig maintenance and housekeeping.;Shut down the pumps with 1,500 psi on the line and monitor pressure. Pressure bled to 0 psi in 30 minutes.;Begin stripping the pre-load tanks. Pump all excess water into the pits. Perform general rig maintenance and housekeeping. 7/21/2021 Finish stripping the pre-load tanks pumping all excess water into the pits. Inject 167 bbls water at 2.4 BPM = 2100 psi. Total water injected = 5419 bbls. Perform general rig maintenance and housekeeping. Continue to build scaffolding for sand blasters.;Continue to build scaffolding for sand blasters. Perform general rig maintenance and housekeeping;Continue to build scaffolding for sand blasters. Perform general rig maintenance and housekeeping. NU the BOP stack single, double and Tee in the rotating sub.;Jack up the rig 5' due to upcoming high tide.;Continue to NU up the BOP stack installing blind flanges. Perform general rig maintenance and housekeeping.;Perform general rig maintenance and housekeeping. Prep to NU the annular 7/22/2021 NU the annular. Perform general rig maintenance and housekeeping. Wrap equipment under the rig floor to protect from sandblasting.;Spot and RU sandblasting equipment. Perform general rig maintenance and housekeeping.;Continue to RU sandblasting equipment. Perform general rig maintenance and housekeeping.;Sandblast substructure in preparation for welding. Perform general rig maintenance and housekeeping.;Change out the actuator rollers on the top drive. Check pressures on the accumulator bottles. Perform general rig maintenance and housekeeping. 7/23/2021 Continue to sandblast the substructure in preparation for welding. Perform general housekeeping and maintenance.;Continue to sandblast the substructure in preparation for welding. Perform general housekeeping and maintenance.;Continue to sandblast the substructure in preparation for welding. Perform general housekeeping and maintenance.;Perform general housekeeping and maintenance. Change oilers on the mud pumps. Contractor AFE #: AFE $: Spartan 151 Job Name:211-00023 A-04A Drilling Spud Date: Well Name: Field: County/State: NCIU A-04A North Cook Inlet Hilcorp Energy Company Composite Report , Alaska n (LAT/LONG): evation (RKB): API #: 7/24/2021 Continue to sandblast the substructure in preparation for welding. Rain was getting into the sand hopper. Call over scaffolder's to build hooch over sandblasting equipment. Continue to sandblast. Perform general housekeeping and maintenance.;Continue to sandblast the substructure in preparation for welding. Perform general housekeeping and maintenance. Grease the choke manifold, draw works, crown and top drive. Function all the valves in the pump room and mud pits.;Continue to sandblast the substructure in preparation for welding. Perform general housekeeping and maintenance.;Continue to sandblast the substructure in preparation for welding. Perform general housekeeping and maintenance. Finished sandblasting the substructure at midnight.;Perform general housekeeping and maintenance. Perform PM's on the mud pumps. 7/25/2021 Review sandblasted areas with welding supervisor and determine it is sufficient for welding. Perform general housekeeping and maintenance.;Cleanup sandblasting debris. RD scaffolding. Perform general housekeeping and maintenance. Install new hydraulic skid lines.;Cleanup sandblasting debris. RD scaffolding. Perform general housekeeping and maintenance.;Cleanup sandblasting debris. RD scaffolding and sandblasting equipment. Perform general housekeeping and maintenance. Sandblaster's left the platform at midnight.;Cleanup sandblasting debris. Perform general housekeeping and maintenance. Prep for jacking the rig. PJSM for jacking up the rig. 7/26/2021 Jack up the rig to the Tyonek Platform.;PJSM. Skid the rig over the rotating sub on the Tyonek Platform. Install walkway from the rig to the platform.;RU scaffolding for the welders. Prep and mark area for welding. Install handrails and stairs where needed.;RU scaffolding for the welders. Prep and mark area for welding. Weld braces and gussets to substructure. Perform general housekeeping and maintenance.;Weld braces and gussets to substructure. Perform general housekeeping and maintenance. 7/27/2021 Weld braces and gussets to substructure. Perform general housekeeping and maintenance. RU deep well.;Weld braces and gussets to substructure. Perform general housekeeping and maintenance. Fill up bow and port leg hydraulic jacking units with hydraulic fluid.;Weld braces and gussets to substructure. Perform general housekeeping and maintenance. RU black water hose to the Tyonek platform.;Weld braces and gussets to substructure. Perform general housekeeping and maintenance. 7/28/2021 Weld braces and gussets to substructure. Perform general housekeeping and maintenance. Relocate the walkway between the platform and rig for easier welder access.;Weld braces and gussets to substructure. Perform general housekeeping and maintenance. Assist with craning in plate steel for the welders.;Weld braces and gussets to substructure. Perform general housekeeping and maintenance. Install bulk cement vent line.;Weld braces and gussets to substructure. Perform general housekeeping and maintenance. 7/29/2021 Weld braces and gussets to substructure. Perform general housekeeping and maintenance.;Weld braces and gussets to substructure. Perform general housekeeping and maintenance.;Weld braces and gussets to substructure. Perform general housekeeping and maintenance.;Weld braces and gussets to substructure. Perform general housekeeping and maintenance. 7/30/2021 Weld braces and gussets to substructure. Perform general housekeeping and maintenance.;Weld braces and gussets to substructure. Perform general housekeeping and maintenance.;Weld braces and gussets to substructure. Perform general housekeeping and maintenance.;Weld braces and gussets to substructure. Perform general housekeeping and maintenance. 7/31/2021 Weld braces and gussets to substructure. Perform general rig maintenance and housekeeping.;Weld braces and gussets to substructure. Perform general rig maintenance and housekeeping.;Weld braces and gussets to substructure. Perform general rig maintenance and housekeeping. Offload supplies and equipment from the work boat.;Weld braces and gussets to substructure. Perform general rig maintenance and housekeeping. Cut threads in 2" schedule 40 pipe for rig air line and MU hammer unions. 8/1/2021 Weld braces and gussets to substructure. Perform general rig maintenance and housekeeping. Unpin the cable rack from the rig and secure to the upper pipe rack. Remove the electric cables from the cable rack.;Weld braces and gussets to substructure. Perform general rig maintenance and housekeeping. Continue to remove the electric cables from the cable rack.;Weld braces and gussets to substructure. Perform general rig maintenance and housekeeping. Run 3" fuel hose from the rig to the Tyonek platform.;Weld braces and gussets to substructure. Perform general rig maintenance and housekeeping. RU the 3" fuel hose to the Tyonek platform. 8/2/2021 Weld braces and gussets to substructure. Perform general rig maintenance and housekeeping. Continue to remove the electric cables from the cable rack.;Weld braces and gussets to substructure. Perform general rig maintenance and housekeeping. Remove the cable rack from the port leg. Unpin the two sections and set down on the main deck. Move all electric cables down to the main deck.;Weld braces and gussets to substructure. Perform general rig maintenance and housekeeping.;Perform general rig maintenance and housekeeping. 8/3/2021 R/D scaffolding;Prep to skid the rig and align with the rotating sub. Cleanup welding debris.;Transverse 6’ to starboard and pickup BOP’s. Unbolt rotating sub and transverse 1’ to port. Set down BOPs and secure. Transverse rig floor back to center.;Cantilever rig floor into fully stowed position.;Lower jack up 30" on bow, 26" on starboard & 28" on port. Welders secured rotating sub after traversing and prepared top of rotating sub beam for welding to rig floor package.;Cantilever rig floor package out over rotating sub, too high. Cantilever back into stowed position. Lower jack up an additional 3" on bow, 4" on starboard & 1" on port. Cantilever out over rotating sub, transverse rotating sub to fine tune position. Drill new holes and secure rotating sub.;Raise rotating sub and install 2" of shims. Install 3" of shims on rotating sub jacks. Raise rotating sub and contact rig floor package. Transvers e rig floor package centered over rotating sub and secure.;Welding and construction crews houred out. Perform general maintenance and housekeeping. Chip paint on starboard tow bits, paint handrails on shaker house. Install gangway between Spartan 151 and the Tyonek. 8/4/2021 Shim gap between gussets and rotating sub extension as required. Erect scaffolding and build tarp enclosures to provide work platform for welders.;Weld rig floor module gussets to rotating sub extension: 7/8" PJP and 1" fillet welds. 60% complete. Welders houred out and will resume at 06:00. Remove electrical wires from wire tray on port side leg tower.;Paint yellow area on starboard aft main deck. Begin installing skid off access window in flow line trough. Perform general rig maintenance and housekeeping. 8/5/2021 Resumed welding rig floor module gussets to the rotating sub extension: 7/8" PJP and 1" fillet welds. Completed everything which was accessible.;Allow welds to cool prior to Magnetic Particle Inspection. Perform MPI - good. R/D scaffolding. Rig welder fabricate hand rails for upper pipe deck opening after rig floor is skidded off.;Total Safety mounted outdoor alarms in mud pits & at shakers and indoor alarm in the galley. Rigged up secondary H2S/LEL monitor in the control room. Installed 2 outdoor monitor antennas above control room. 30% of gas system installation complete.;PJSM. Jack up rotating sub. Remove bolts securing rig floor package to the cantilever beams. Raise rig floor package up off cantilever beams, remove guide bars and retract cantilever beams clear of the platform. Suspend BOP stack with bridge cranes.;Skid rig floor package / rotating sub assembly 16' south off leg #1 to allow access for welders to finish welding remaining gussets.;Install scaffolding. Finish 7/8" PJP and 1" fillet welds on last two gussets to rotating sub extension.;Allow welds to cool prior to final Magnetic Particle Inspection. 8/6/2021 Waiting on gussets welds to cool. While waiting skid rig cantilever beams back over platform so crane can have more deck space on Jack up. Also installed handrails on cement unit roof and installed walkway to the platform. Checked measurements for turning the rig on leg 3.;Found out that the drilling line spool hung down 2'8" to much to clear the oil cooling building on the platform. Made plans to remove the 3' top section of the oil cooler before turning the rig.;MPI gusset welds and remove scaffolding. Move equip from east side of the rig in prep for moving. Cut off old trolley rails.;Jack rig about 38' to the east and run into an issue with a cross beam only partially beveled. Push rig back a few inches, and swap jacks to the west side. While moving ja cks have welders bevel the beam. Jack rig to about 6' from east side.;Welders attempted to install new landings on east side skid extension. The landing didn't fit right so they had to make changes in the beams to make them fit. Welders finished landings at 19:30. Skid rig 4', 2' short of completely over leg #2.;Total Safety 40% complete on gas detection installation. Installed 7 conductor cable from control room to pump room and mud pits. Relocated mud pit alarm.;Bevel last skid beam prior to skidding last 2' east. Welders preparing to remove louvers and top 3' from oil cooler and removed spark arrestor lines and cut turbine exhaust stair frame down to clear rig. Welders houred out at 21:30.;Drop plumb bob off crane to check for interference with rig. Found that 800 crane walkway will interfere with rig. Call Brian Wilkes and discuss options. Decision made to cut 24" off crane walkway. Discuss with Tyonek Lead about cutting landing and agreed it was the best way to proceed.;Remove handrails from crane walkway.;Crane transformer also need to be removed to clear the rig. Wake up platform electrician and formulate plan. LO/TO power to crane, disconnect and remove transformer. Will reinstall after rig moves past crane.;Cut 24" off crane walkway to provide clearance for the rig.;Skid rig module east to leg #2 and align on N/S skid rails. Move jacking cylinders to north side of rig. Remove all tools and equipment from Tyonek crane. Install chainfall hoist on crane cab jib boom to facilitate re-installation of the walkway. 8/7/2021 Welders welding pad eyes on sub for guide pins and installing pad eyes on the oil cooler roof. Get sub squared up on skids. Move jacks so we can pull the rig toward leg 3. Pull roof off oil cooler.;Jack rig from leg 2 past the crane with only 1" of clearance at times. Total safety is continuing to rig up his gas alarm system.;Move jacks to other side of sub by crane. Install 2 earthquake clamps for safety. Jack upper section up and attempt to rotate the sub. Trouble shoot rotating system. Finally found 2 hoses that were crossed and got it working.;Rotate sub around into position. Had to move it ahead several times while rotating due to interference with production mud room and the crane. Set upper section back down in it's clamp down position.;Remove earthquake clamps and jack sub up next to production over leg 3. Had to bevel the last beam in order to get on it.;Total Safety installed 7 conductor cable from mud pit alarm to shaker alarm. Tie-in wire and relays to shaker, mud pit and outdoor alarms to control room. Planning for platform installation. 50% complete on rig up.;Install c-plates to hold down rotating sub - lower pre-drilled holes did not fit, had to torch cut to size. Cut off hand rails and clearance I-beam. Unload rig equipment from the Sovereign.;Skid rig last 2' over leg #3 and align with transverse skid beam. Move jacking cylinders to lateral beam. Transverse rig module 2.5' in line with A-04A. Skid rig package on rotating sub 1' back toward leg #2 to center on A-04A.;Remove jacking cylinders from lateral beams. Re-drill rotating sub hold down bolt holds and secure. Install two outboard earthquake / hurricane clamps.;Clear the platform deck to provide working room. Set rig mat, 1/2" x 12" x 10' flat bar and shaker tank. Set two 50' HAK pipe rack riser beams. Had to utilize two cranes to set beam nearest to 800 crane since it could not boom up enough. 8/8/2021 Finish installing 28.5' HAK pipe rack riser beams. Have scaffold builders build hutches for the welders. [rain and high winds] Welders welding down 50' X 5'6" beams for raising HAK racks. Install hand rails and put up roof supports on shaker pit. Remove old pipe stop off 428 slide.;Pi n earthquake clamps to rotating sub. Welders will need to make plates to bolt them down. Remove the hyd hoses used for moving rig to clear area for service lines. Got a couple picks off the boat and weather got a lot worse, so the boat headed for calmer waters to wait it out.;Set slide from jackup to platform for running service lines. Help production RU pumps to remove rain water off platform deck. Start running HP mud line from jackup. Have scaffold builders build scaffold so we can weld a flange on the flow line. Set shaker landing and shakers. Power drk lights.;Set up service line piping stands. Run and clamp dn 4" high press mud line up to rig. Clean and prep 16" flowline for welding. Weld on 16" flange. Bolt adaptors from 16" to 10" together for the flow line. Welders building bottom plate for Earthquake clamps.;Total Safety worked with platform electrician to install primary monitor & tie into platform system. Install wellhead room and shaker pit sensors & alarms. 70% complete for installation;Run 4" mud return line, two 3" seawater lines and 2" air lines on service line piping stands. Connect mud line to the rig floor. Remove scaffolding. Unload Sperry and mud shacks, shaker pit roof and rig pieces from the Sovereign. Welders begin building 10" flow line.;Install shaker tank suction manifold and secondary transfer pump. Finish install 3" seawater and 2" air lines on piping stands. Install shaker tank roof. W eld pad eyes on cuttings chute and install on shaker discharge. Clear platform deck for electrical cable tray installation. 8/9/2021 Have welders building the flowline to the shakers. Run the ramp they used at the dock for a cable tray to the platform. Have derrick hand replacing the rubber at the end of the shakers and working on other shaker issues. Start tying in service lines. Got Pason, 2 MWD, and Baroid hand in.;Work on cable trays and cables.;Have orientation meeting with both crews and service hands in galley of the Tyonek platform.;Move light above shakers for flowline access. Weld down center section of pipe rack beams. Production electricians wiring in shaker pit pump, pit lights, and shakers. Put cable tray on stand under pipe racks. string electric cables. Hang flowline . Put knee braces on shaker landings.;Welders continue to weld knee braces on shaker landings and secure shaker landing to shaker tank. Install kick plates on shaker landing. Install rubber guard on shaker dump. Remove 1 joint of 4" line and plumb shaker tank to 4" mud return line.;Finish installing rig utility lines between jack up and rig sub. Finished installing flow line. Total Safety 75% complete on gas system installation.;Welders continue to weld knee braces on shaker landings and secure shaker landing to shaker tank. Weld mud return transfer pump base to deck skid rail. Blow air through 2" hard air line to ensure clear. Secure flaps on shaker tank roof.;Plumb drill water from platform to rig floor. Building hand rail for shaker tank. Install 60 mesh screens on Derrick shakers. Install rubber splash guard on possum belly. Install double 8" king nipple to join two 8" shaker dump lines. 8/10/2021 Lay out wire trays. Pick first bundle of wires from jackup side and lay out on wire trays on the Tyonek. Get 2nd bundle and lay out the same. Production electrician wiring shaker pits. Welders getting water cleaned up and welding down the service line stands.;Have scaffold builders building temporary walkways across service lines. Rig welder modifying piping for mud shipping manifold.;Weld down shakers to the shaker tray. Finish welding service line stands to the Tyonek deck. Lay out 100' electrical cable extension on the deck and prepare for installation. Band cable extensions to cable tray;Hoist cable tray and cables with both Tyonek cranes. Hang cable tray off cable house and attempt to connect cables - 3' too short. Lay down cables and cable tray. The M/V Sovereign offloaded 217 bbls of drill water to the Spartan.;Unload two freestanding sections of the HAK pipe rack from the M/V Sovereign. Masco Endeavour unloading freight to the Spartan. Set 1st section of HAK pipe rack on extension beams and square up. Weld first pass on the four support columns. Release crane. Layout electrical cables for reinstallation.;Move rig vac and hoses from inside HAK rack sub extension. Unload center HAK pipe rack section from the Masco Endeavour. Verify measurements on center section and perform layout for setting 2nd HAK pipe rack section.;Set 2nd HAK pipe rack section, square up on extension beams and tack weld 1" on all corners of the four support columns. Test fit center section of HAK pipe rack - good fit. Continue to layout electrical cables.;Masco Endeavour continued to unload freight, 226 bbls drill water & 156 bbls potable water.;Welded first pass on 2nd HAK pipe rack support columns. Started welding the cap on all HAK pipe rack support columns. 8/11/2021 Finish welding HAK pipe rack support columns. Weld center 10' HAK pipe rack deck to outer sections - 6" skip weld every 48" across both side of 48' deck. Pull 100' electrical line extensions and hook up in cable house.;Finish welding HAK pipe rack deck. Continue to pull 100' electrical line extensions and hook up in cable house. Mix 400 bbls of 9.5 ppg LSND mud as per mud man.;Hold pre-spud meeting with both rig crews, Tyonek personnel, service personnel and drilling engineer.;Modify and install beaverslide from the Steelhead on Spartan 151. Install walkway and stairs from HAK pipe rack deck to the sub. Install stairs from HAK rack to Tyonek deck. Install stairs from HAK rack to Tyonek mud room roof. Cut & grind old stanchions from HAK rack deck.;Connect 100' cable extension to Spartan 151 cables. Udelhoven welders swaps to days. Rig welder building walkway for rig floor stairs to HAK rack walkway.;Install shaker mud chute guards. Install cat walk on HAK pipe rack. Install discharge hose on secondary shaker pit pump to shaker pit manifold. Measure HAK deck hand rail pockets. Pickup extra equipment and materials from construction. Perform cleaning up Tyonek deck and substructure.;Install walkway from Tyonek fin fan building to rig BOP deck. 8/12/2021 Continue hooking up electrical cables to rig and testing same (all good except troubleshoot & repair a blower mtr and rotary table cable to short (sourcing cable and plug for an extension) / Continue installing walk ways, landings, stairs and hand rails / continue build 9.5# WBM system / Work;Boat cargo and take on water / UOSS welders finished supports of shaker landing and stairs from drill deck to HAK pip rack cleanup and pack up tools / with access to rig floor total safety and pason continued r/up of equipment / No crew change today do to possible COVID of hand of on coming crew;Complete Crew taking PCR test and quarantining at hotel. Total Safety run and tie in cables to rig floor, cellar, shaker pit and well head room - total installation 95% complete. Pason installation 55% complete.;Install stair walkways over cable trays for access and protection. Remove excess equipment and materials from the Tyonek and store on Spartan 151. Spot vac unit on mud room roof. Mobilize Hawk Jaw and drill pipe handling equipment to the rig floor. Set cable trays & plywood over cable trays on deck.;Install king nipple and flange on 8" overboard line. Hang overboard line from shaker cuttings chute. Move electrical bang board to clear walkway. Spot Hawk Jaw power unit and run lines to rig floor. Unload MV Sovereign freight to Tyonek deck. 8/13/2021 Flush HP mud line to platform shaker pit / wire in back up centrifugal transfer pump, Hawk jaw HPU and check rotation and power mud lab / Continue r/up total safety and pason equipment / fabricate walk way and steps for pump end of platform shaker tank;Work boat and take on water / chk all pressures on A- 04A = 30" x 16" = 7.5 psi / 16" x 10-3/4" = 28 psi / 10-3/4" x 7" = 11 psi 7" x 4-1/2" tbg = zero / Tbg zero w/ visual fluid level +-20' down / Install TWC / production welder on board start re-purpose used hand rails to fit Hak pipe rack;Stage 10k choke and kill assy in cellar / house clean work areas / continue build 2nd batch of 9.5# WBM / continue flushing lines and prep test HP mud line / continue work crew over and and short handed / finished building 400 bbls mud - 800 bbls total built.;Pressure test high pressure mud line, leak at 2000 PSI. Repair 2" Demco valve. Pressure test to 5000 PSI - good test. Fill shaker tank to Spartan mud pit return line hose - pin hole leak. Replace hose. Circulate from shaker tank back to mud pits with primary pump - good. Test secondary transfer pump;Pump worked correctly, but starter sticking. Electrician will troubleshoot starter. R/U 110' of 2" Yellow Jacket cement hard line in piping support stands on the Tyonek deck. Test seawater cooling lines, found minor leaks on feed line threaded connections. Tighten connections and circulate good.;Production welder continue to work on HAK pipe rack hand rails and pipe stanchions. Testing Total Safety gas alarms. Pason 85% complete in installation, calibration and training. Install 140 screens on mud cleaner #1. Mobilize wear bushing, running tool & blanking sub to the rig floor. 8/14/2021 Electricians work on start /stop station of back up platform shaker tank transfer pump / work boat of cargo and some drill pipe / production welders continue to re-purpose used hand rails to fit HAK pipe rack / test and cal total safety gas system and continue pason r/up;Nip/dn dry hole tree and store in well room / install 13-5/8" 5k riser with XO spool / start to install stairs and walk way from jack up pipe rack to top of platform weld shop / continue w/ handrails and station of HAK pipe rack / work on platform gai-tronic for rig / attempt stab stack;Annular interference with sub beams need about 2" to center up ( sub not centered with well ) attempt pull riser over no/go / r/up jacks and loosen clamps / rig up hydraulic unit ,/ cut welds for stairs to HAK deck / disconnect flow line dresser sleeve;Skid rotating sub 3" outboard on transverse skid rail to center annular in rotating sub beams. Transverse rig package 4" inboard to center rotary table over BOPs. Remove jacking cylinders, R/D hydraulic unit and re-install earthquake clamps. Reconnect flowline dresser sleeve.;Weld stairs back to HAK. Production welders continue to work on HAK rack handrails.;Tighten adapter flange and riser bolts in the wellbay. N/U BOP stack and tighten BOP to riser. Remove upper BOP stack from mud cross. Rotate mud cross 90°. Remove 5K to 10K DSAs from mud cross. Install rotating 90°s. Install longer studs on5K to 10K DSAs and dress flange bolt holes on DSA.;Install DSAs on rotating 90°s. Set BOP stack on mud cross and hammer up bolts. N/U choke and kill line assemblies. 8/15/2021 Continue N/U choke and kill line assemblies / Open doors and inspect door seals and rams 2-7/" x 5" vbr's in btm blinds middle & install 4-1/2" hard rams in top / Plumb in and hook up koomey lines / Electrician's working on platform gai-tronic to Rig floor, pipe rack & shakers run cat 5;Cable to mud lab / production welders continue with Hand rail install on HAK pipe rack / rig welder work on stairs and landing / Held muster and abandon platform drill w/ both Toynek platform and jack up and held debriefing and go over issues;Continue nip/up / continue hand rail, walkway and stairs install continue wiring in communications / calibrate pason / hook up koomey lines / clean cellar / Prep to function test bope and build test jt;M/U blanking sub, XO, five foot 4.5" pup joint, full 4.5" joint, fifteen foot 4.5" pup joint for test joint assembly. M/U pump in sub, FOSV #1, FOSV #2 and top drive to test joint. R/U test pump. Attempt shell test, lower pipe ram body blind flanges leaking - tighten bolts.;Pressure up again, choke valve #15 leaking - function valve. Pressure up again, grease fitting on choke valve #16 leaking - replace fitting. Pressure up again, packing gland leaking on tubing hanger - tighten gland nut.;Obtain 250 PSI low / 2500 PSI high body test against annular, choke valves #13, 14, 15 & FOSV #1. Obtain 250 PSI low / 4500 PSI high body test against 4-1/2" upper pipe rams, choke valves #13, 14, 15 & FOSV #1.;Perform preliminary BOP test. All test performed with fresh water, against a blanking sub installed in the 4.5" hanger with a 4.5" test joint. Test performed to 250 PSI low / 5000 PSI high and held for 5 min each.;1) Lower 2-7/8"x5" VBR on 4.5" test joint 2) Upper 4-1/2" pipe rams on 4.5" test joint, FOSV #1, manual choke & kill 3) Upper 4-1/2" pipe rams on 4.5" test joint, FOSV #2, HCR choke & kill 4) Upper 4-1/2" pipe rams on 4.5" test joint, lower IBOP, valves #1, 17 & 18 (fail/pass - tighten choke flange);5) Upper 4-1/2" pipe rams on 4.5" test joint, upper IBOP, valves #3, 4 & 7 6) Upper 4-1/2" pipe rams on 4.5" test joint, FOSV #1, valves 2, 6, 11, 8 & 16 BOP testing continues into next report period;Load and strap 189 joints of 4-1/2" drill pipe on the pipe rack. 8/16/2021 Continue and finish Pre-Bope test as per regulations 250L/5000H 5/5 notified state Mr Jim Regg of good pre-test / discussed timing of state witnessed with Inspector Adam Earl planned for 8-17 -21 @ 09:30 / to finish r/up and p/up DP;Work boat / Continue weld extensions on 22" flow nipple w/ production welders 3 welds / re-tigten bolts on complete stack / calibrated Sperry block Hight and installed sensor on stand pipe goose neck / enterprise working through issues with 2nd attempt w/ crew change;Install backstop on beaverslide. Install bails and 4-1/2" elevators. Install new saddle on beaversli de mounting plate. Change top drive grabber dies from 5" to 4-1/2". Install sheave at derrick board to position tugger to pickup drill pipe.;Pick up drill pipe, make up stands in the rotary table and rack back in the derrick. Torque 4-1/2" CDS40 pipe to 20,800 ft/lbs torque with Hawk Jaw. 114 joints / 38 stands total.;Perform accumulator drawdown pre- test. 3075 system pressure, 1650 after closure, 21 seconds 200 PSI recovery, 130 second full recovery.;Pick up drill pipe, make up stands in the rotary table and rack back in the derrick. Torque 4-1/2" CDS40 pipe to 20,800 ft/lbs torque with Hawk Jaw. 123 joints / 41 stands total. 8/17/2021 P/up and install flow nipple / production welders working on re-install of back landing of south crane to a bolt on connection / Install 4-1/2" test jt / Adem Earl w/ AOGCC on board / orientation and tour of rig and fluid flow paths / test gas alarms / start testing BOPE;Test pump unable to get above 4950 psi with out pop- off bypassing re-plum pop-off / Continue testing Bopes as per regulations 250L/5000H 5/5. Perform accumulator draw down. Test Kelly hose & swivel packing to 4000 psi 250 5 min. Attempt high test swivel packing leaking.;Draw down- 3100 PSI Start, 1800 psi after shut in, 200 PSI increase 19 sec, Full charge 115 sec. 16 BTLS @ 2400 psi.;Change valve and gauge on test pump. Service swivel packing. Retest Kelley hose and swivel packing. Good. Break down TIW, Dart & L/D same. Back out test Joint. Test blinds to 250/ 5000 psi 5 min X 5 min. Good. RIH with Test joint & M/U same. Function BOPs from remote station. Good.;R/U to Pull hanger with 4 1/2 DP. M/U TD. PJSM, BOLD. Pull hanger free.;POOH L/D Pups & DP. L/D hanger and break out running tools. Pull 4 joints of IBT 4 1/2 tubing. Monitor for oil cap. Verified oil cap.;R/U line and 2'' pump from cellar to vac tote. R/U Pump and line from rig floor to pump off cap from well to vac tote. Lay out Dc. Strap tally and get FN. / Continue testing Bopes as per regulations 250L/5000H Adem Earl w/ pppp g g AOGCC on board / orientation and tour of rig and fluid flow paths / test gas alarms / start testing BOPE;gpg Pull 4 joints of IBT 4 1/2 tubing. 8/18/2021 Continue skim dirty water w/ diesel sheen off top of well to cuttings box / R/up to pump from annulus to production injection tank to skim diesel sheen off top of well / Production welders continue retro fitting back landing of south crane landing to Bolt on connection / finish working boat;Finish laying out and strapping HWDP and collars / Rih set wear ring;RIH open end two std and Pump dirty sheen water from annulus t/ production / pump clean water dn dp and re fill stack test and sheen test fluid repeat this 4 times w/ total 75 bbls pump and two passing sheen test / welders and elections continue repairs on south crane;Secure stack / remove catch tank from jack up for catch tank for rig floor drains / continue run 1502 cmt line to SLB unit / rig welder repairing hand rails on 151 sub / Production electricians hooking up transformer on south crane .;Production electricians continue hooking up transformer on south crane & Test same. Good. Spot rig floor drain tank and hook up lines. Transfer skimmer water from vac tote to production header. 12 bbl.;R/U lines and pump in wellhead room to suck out stack. Put away transfer lines and store.;PJSM, with production crane crew and drill crew. P/U WIS full gauge window mills as per WIS. 6 1/8 OD mills. M/U bit sub, 9- 4 3/4 DC & 21 4 1/2 HWDP T/ 930'. Take returns to TT.P/U 4.5 DP & RIH with clean out BHA to 2878'. 63 joints. RIH with stands from derrick to 3985'.;PJSM for first circulation and fluid transfer. Walk down lines and system with crew. Break circ and stage up pumps to 5 BPM at 300 psi with drill water. Test transfer from transfer pits to rig pits. Good. 8/19/2021 Continue circ at 5 BPM at 300 psi with drill water. Total 100 bbls circ around / dn pumps and flow chk (ok);Pooh w/ proper hole fill chk mills (ok) l/dn same;PJSM p/up sperry MWD and test same (ok) / p/up WBI 7" track master whip stock assy w/ expandable anchor Bha #2 / Rih slow w/ collars;Continue Rih slow w/ hwdp and DP t/2769';Fill pipe w/ drill water;Continue rih t/ 2829.52' btm of whip stock / Kelly up and pressure cycle #1 shoot tool face @ 128L Orentate to 153L. Work pipe and verify 153L. Perform 5 cycles on depth. TOW at 2810'. 300 GPM 1050 PSi. UP/DN 108/102;Perform the 6th cycle and saw pressure increasing to 3200 psi. Hold pressure while shutting in stand pipe. Set down to 85K. P/U to 125 twice. Set down to 75K and saw bolt shear. P/U and saw 5K over pull and pressure drop. P/U 5'. Open stand pipe and ROT at 60 RPM 175 GPM. Rot down at 2200 psi.;Saw pressure drop from 2500 si to 1050 psi when plug drilled up. P/U 5' above TOW. to 2805'. Prep for displacement and mud treatment.;Displace to 9.5 PPG 6% KCL mud. Cut mud back to 2% KCL with water and bring wt and properties back to 9.5 PPG. 260 GPM, 1527 psi. Current MW in and out 9.+. 8/20/2021 Continue circ and weight up system and properties back spec. 260 GPM, 1527 psi. Current MW in and out 9.3 PPG;Held platform/ Jack up joint drill / platform high gas alarm that turned into abandon Platform / drill crew dn pump and secured well and mustered @ there safe briefing area along with Jack up / then went to bucker and head count (had one drill hand went to wrong platform brucker );Chk pressure open well / Resume circ and weight up system and properties back spec. 260 GPM, 1527 psi. Current MW in and out 9.4+ PPG;Shut down finish hit list before window milling. Change bleeder needle valve on accumulator, Install fire water line to Sparten 151 from platform fire water. Test. Good. Prep shakers for mill cuttings.;Establish milling permeators. Take slow pump rates with #1 & #3 pump. #1 @ 20/30/40 110, 182, 284psi. #2 20/30/40 112/180/281 psi. Choke panel has 15K Gauges. Take readings from Totco.;Mill window ast 80 RPM, 3-5 K TQ, 200 GPm, 942 PSI. F/ 2810' T/ 2820'. 62# Metal back. MW 9.5 in and out. 44 vis.;Drill 20' New hole F/ 2820' T/ 2840'. 200 GPM, 1028 PSi 80 RPM, 6K TQ WOB 0-3;Ream through window at 100 RPM three times & Slid through to btm twice. Good. Pump 25 bbl HV sweep around.;Monitor well, 10 Min. R/U for FIT to 12 PPG. Perform FIT to 12.1 PPG, Monitored pressure for 10 Min. Good FIT. Bleed off pressure & R/D testing equipment. Prep for TOOH.;POOH F/ 2805' T/ 1396'. 8/21/2021 Continue POOH F/ 1396' T/ Bha w/ correct hole fill;Rack back collars and extra HWDP chk and l/dn Whip stock milling assy. (Btm two mills had 1/16" wear and top mill engage );Pull wear ring wash stack and flush choke and kill lines and re-install wear ring / also chg out koomey bleed valve again;P/up and M/up Bha #3 drilling bha #1 test mwd on first std HWDP ok finish running HWDP out of derrick t/ 951';Rih w/ Bha # 3 on dp out of derrick t/2434' filled pipe @ 2282' and oriented to window chk depth and recalibrated pason depth;Lost hose on Rigs HPU spill less then 1 cup to platform deck ( Mobil EAL 224H - Vegetable oil ) NO spill to inlet / wipe up same and replace hose / refill unit clean up drip pan and chk TDS pipe handler functions ok / Notification made;RIH F/ 2282' T/ 2750'. Orientate to window at 153L. Slow pump rates. #1, 20,30,40 183,259,370.#3 181,255,363psi. RIH Slide through window with no pumps at 2810- 2835' Clean. Take wt at 2835. 5' fill on btm. Wash & Ream down at 250 GPM F/ 2835- 2840'.;Drilling F/ 2840' T/ 2989' 250 GPM, 1150 Psi, 100-150 Dif on slides. 0-3K WOB @ 100-250 FPH. Shakers running wet. Slide 90-120L as per DD.;Take survey, Survey still dirty. Pump 25 BBL high vis sweep around with 0% Increase in cuttings. Orientate to window at 153L. Monitor well. Good. POOH on elevators F/ 2989' T/ 2805' through window with no over pulls observes. Proper hole fill. Monitor well. Static. pump slug. Prep for trip.;POOH on elevators F/ 2805' T/ 487'. Proper hole fill. Stand back 4 stands of HWDP with jars. Stand back NMFC and L/D MWD. Clean magnets and recover 26#. 110# Total.;While laying down DM collar 8' long. Floor hand unlatched the elevators before tugger could take the load out of the elevators releasing the DM collar to the floor. DM collar pin end was already sitting on the floor and the Lift sub end fell 6'. Sent floor hand to Pusher and medic for evaluation.;Operations were shut down. Floor hand hard tow boot was crushed and saved his foot. Only slight bruising. Conduct meeting with crew for lessons learned of the near miss. Driller assigned only one hand to unlatch elevators with verbal approval moving forward. Floor hand was evaluated by medic;Floor hand was evaluated by medic and released back to work. Operations were started back up.;Finish L/D MWD. Pull motor and bit and check bit and motor. Looked new. Clean and clear rig floor.;PJSM, Bring up Short BHA tools to rig floor. P/U BHA #4 as per dd. Kymera hybrid PDC KM322, Terra force motor, FS, DM , GM, ADR, ALD, Stab, CTN, PWD, HOC.;Scribe MWD to motor & carry offset. Up load MWD. M/U Stand of HWDP & test MWD before picking up Nuclear sources. Stand back HWDP & conduct nuclear source meeting.;Wellhead Pressures- 30X16'= 8 PSI, 16X10 3/4'= 36 PSi, 10 3/4 X 7'' =24 PSi y Set down to 75K and saw bolt shear. pp r;Continue rih t/ 2829.52' TOW at 2810' py btm of whip stock pyg Floor hand hard tow boot was crushed and saved his foot. Drilling F/ 2840' T/ 2989' 250 GPM, 1150 Psi, 100-1 vis.;Drill 20' New hole F/ 2820' T/ 2840'. gg Sent floor hand to Pusher and medic for evaluation.; pp Perform FIT to 12.1 PPG, Monitored pressure for 10 Min. Good FIT. MW 9.5 in and out. pp ;Mill window 8/22/2021 Continue working BHA #4;Rih w/ Bha #4 T/ 2779' fill pipe orient towards window and SPR / RIOH t/ 2971' / w/ no issues going through window;Wash dn f/ 2971' T/ Btm @ 2989' w/ no fill Drill 6-1/8" directional hole f/ 2989' t/ 3153' with slides as necessary to maintain WP#6 240-260 GPM 1250 Psi MW, 9.5 in and out, ECDS 10.7 WOB 2-4K, Limit ROP at 150 FPH, 60 RPM at 5-6K TQ UP/DN ROT, 112/100/100K;Continue drilling 6-1/8" directional hole w/ slides as necessary to maintain WP#6 F/ 3153' t/ 3528'. 240-260 GPM 1250 Psi WOB 2-4K, Limit ROP at 150 FPH, MW, 9.5 in and out, ECDS 10.7 60 RPM at 5-6K TQ UP/DN ROT, 112/100/100K Mad pasing slides @ 258 gpm @ 1300 psi 60 RPM;Could not break the TD out of the 4 1/2 Joint after Kelly dn. Turn up TQ and connection broke at the manual Kelly valve on the TD. Disassemble gripper and handler to change dies to be able to make or break the valve. unable to break out Saver sub and valve from joint in stump with rig tongs.;L/D joint in mouse hole with saver sub and lower Kelly valve still made up. Bring new saver sub and valve to rig floor. Install same and calibrate TD as needed for new valve. Install gripper block and dies for the 4 1/2 pipe again. Make and break Saver sub twice before starting.;Work pipe every 30 min 5-10' when we could. 15-20K over pull getting it moving each time after sitting up to one hr but nothing after initial movement.;P/U 4 1/2 joint to replace one removed from string. Bring pumps on line staging up warming up the mud. Wash and ream 30'. Make connection and go back to drilling.;Drilling 6-1/8" directional hole w/ slides as necessary to maintain WP#6 F/ 3528' t/ 3897'. (372') 75 FPH Average. Mad passing slides @ 258 gpm @ 1400 psi 60 RPM 240-260 GPM 1413 Psi MW, 9.5 in and out, ECDS 10.9 WOB 2-4K, Limit ROP at 150 FPH, 60 RPM at 5-6K TQ UP/DN ROT, 120/100/105K;Pump sweep around at 50 GPM, 60 RPM. Sweep came back 10 BBL late and 25% Increase in cuttings.;Monitor well, Static. Short Trip. POOH F/ 3897' T/ 3635' on elevators with 5-10 bobbles, Hole taking proper hole fill.;Wellhead Pressures- 30X16'= 8 PSI, 16X10 3/4'= 36 PSi, 10 3/4 X 7'' =24 PSi Max Gas 800 Units. 8/23/2021 Continue short Trip. POOH F/ 3635' T/ 2786' on elevators clean no issues w/ hole or window Hole took proper hole fill.;Clean rig floor from wet trip / service rig / Grease TDS, dwk & crown and chk levels in all equipment / monitor well on trip tank w/ > .25 BPH loss dn Trip tank;P/up jt w/ valve and saver sub / and attempt to brk/out same no-go / shut in well and heat connections and brk/out both (valve threads ok, saver sub threads Sharpe / monitor static well for seepage looses;R/up test equipment and test connection and lower valve on TDS 25L-5000H 5/5 on chart Good / Re-chk torque of IR,TDS and tongs against each other ( TDS high adjust to correct torque ) monitor static well for seepage loses None observed;Short trip Rih/ F/ 2786' t/ 3807' no issues w/ window or open hole / Kelly up wash and stage up pump rate and warm mud to btm @ 3897' no fill Max trip gas 114;Continue drilling 6-1/8" directional hole w/ slides as necessary to maintain WP#6 F/ 3897' ' T/ 4500' ( 603') @ 52 FPH av with back reaming full stands. 240-260 GPM 1500 Psi WOB 2-101K, Limit ROP at 150 FPH, MW, 9.5 in and out, ECDS 11 60 RPM at 5-6K TQ UP/DN ROT, 125/110/120K Max gas 114;Drilled in to the C1 at 4200' +/-. Saw good bit wt and harder drilling. No losses. Back reaming full stands.;Continue drilling 6-1/8" directional hole w/ slides as necessary to maintain WP#6 F/ 4500' T/ 4920' ( 420') @ 84 FPH av with back reaming full stands. 270 GPM 1900 Psi WOB 6-10K, Limit ROP at 150 FPH, MW, 9.5 in and out, ECDS 11.3 60 RPM at 6-8K TQ UP/DN ROT, 145/112/122K Max gas 98;Pump sweep at 4546', Came back 25% increase in cuttings and 178 STKS late. 8.6% calculated wash out. Last survey showing 3.77 High and .53 Right of plan, 3.81 Distance to plan.;Take survey, Pump 25 bbl high vis sweep & Circ hole clean for short trip. Monitor well.;Wellhead Pressures- 30X16'= 8 PSI, 16X10 3/4'= 38 PSi, 10 3/4 X 7'' =23 PSi Max gas 98 pypgppp drilling 6-1/8" directional hole w/ slides as necessary to maintain WP#6 F/ 3897' ' T/ 4500' ;Drilling 6-1/8" directional hole w/ slides as necessary to maintain WP#6 F/ 3528' t/ 3897'. @ Drill 6-1/8" directional hole f/ 2989' t/ 3153' gg drilling 6-1/8" directional hole w/ slides as necessary to maintain WP#6 F/ 4500' T/ 4920' 8/24/2021 25 bbl high vis sweep back 4 bbls late w/ 25% increase monitor well static / short trip pooh f/ 4920' t/ 3897' slick no issues w/ correct hole fill / Rih t/ 4830' again slick no issues fill pipe orient wash last std to btm w/ no fill;Resume drilling 6-1/8" directional hole w/ slides as necessary to maintain WP#6 F/ 4920' ' T/5199' ( 279') @ 50.7 FPH avg with back reaming full stands. WOB 2-10K, Limit ROP at 150 FPH, MW, 9.5 in and out, ECDS 11 268 GPM 1800 Psi 60 RPM at 5-6K TQ UP/DN ROT, 140/110/120K wiper gas 20;Pump high vis sweep. Resume drilling 6-1/8" directional hole w/ slides as necessary to maintain WP#6 F/ 5199' ' T/5428' ( 229') @ 50.8 FPH avg with back reaming full stands. 268 GPM 1900 Psi WOB 5-10K, Limit ROP at 150 FPH, MW, 9.5 in 9.6 out, ECDS 11.4 65 RPM at 7K TQ UP/DN ROT, 140/110/120;Pump 20 bbl High vis Sweep at 5390. Came Back with 20% Increase in cuttings & 7.2 bbl late. Saw good indication of ROP improving on sweeps.;Pump high vis sweep. Resume drilling 6-1/8" directional hole w/ slides as necessary to maintain WP#6 F/ 5428', T/5757' ( 329') @ 54 FPH avg with back reaming full stands. 275 GPM 2100 Psi WOB 8-10K, Limit ROP at 150 FPH, MW, 9.5+ in 9.6 out, ECDS 11.9 65 RPM at 7K TQ UP/DN ROT, 150/115/125;Pump 20 bbl High vis Sweep with 1 LB per bbl Condent at 5570. Came Back with 20% Increase in cuttings & 8 bbl late. Adjust pump rates to keep ECDs below 12 ppg. Back ream slower on connections to help ECDs also. Screen up Rig Shaker #1 & #2 to 170s.;Pump high vis sweep. Resume drilling 6-1/8" directional hole w/ slides as necessary to maintain WP#6 F/ 5757 ' T/6035 ' ( 278') @ 46 FPH avg with back reaming full stands. 230-250 GPM Psi WOB 8-10K, Limit ROP at 150 FPH, MW, 9.6 in 9.6 out, ECDS 11.9 65 RPM at 8K TQ UP/DN ROT, 150/115/130;Last survey Showing 3.42 Low, 1.82 Left & 3.87 Distance to plan. Screen up rig shakers to #2 to 200s # # shaker to 200/170. Change screens on platform shaker #1 to new 60S. Currently changing #2 to new 60s.;Wellhead Pressures- 30X16'= 8 PSI, 16X10 3/4'= 40 PSi, 10 3/4 X 7'' =25 PSi Max gas 98 8/25/2021 Pump high vis sweep. Resume drilling 6-1/8" directional hole w/ slides as necessary to maintain WP#6 F/ 6035 ' T/6317 ' ( 282') @ 62 FPH avg with back reaming full stands. 245 GPM 2015 Psi WOB 8-10K, Limit ROP at 150 FPH, MW, 9.5 in 9.6 out, ECDS 11.9 61 RPM at 8K TQ UP/DN ROT, 150/115/130;Ream std and take a final survey on bottom. Pump sweep with a fiber marker in it. Sweep came back on time w/ a 10 to 15% increase in cuttings. Circ untill hole cleaned up. Check flow.;Last Survey showing 15.88' Low, 6.18' Left & 17.04 distance to plan.;POH on elevators to csg shoe. Had a 20 k overpull when we first started off bottom after checking the flow. The rest of the trip was good. Hole took an extra 5 bbls to fill while POH, but we did pull wet!;Circ hole clean at shoe keeping the pipe moving up and dn and rotating at 12 RPM. Minimal cuttings back. Shut dn and Check flow. looked good!;RIH filling pipe 1/2 way in the hole . Continue RIH and wash last std to bottom with no fill. Clean Trip.;Pump 25 bbl high vis sweep around. Sweep came back on time with no increase in cuttings. stage up pumps keeping ECD below 12 ppg. Rot 40 RPM, 250 GPM 9.5 IN and out 42 Vis.;Monitor well. Static. POOH 5 stands monitoring Drag & hole fill. Good. Pump Slug & POOH F/ 6317' to 2786'. Pulled clean through open hole and window.;Monitor well, Static. Circ hole clean at shoe keeping the pipe moving up and dn and rotating at 12 RPM 250 GPM, MW 9.5 in and out.;RIH F/ 2786' T/ 3251'. Drop 2 3/8 Drift on wire. POOH F/ 3251' to BHA. 558'. Hole took Proper Fill. Recover Drift. 29 Stands drifted for liner run.;Stand back three stands of HWDP & Collars. L/D Jars. PJSM Remove nuclear sources. Down Load MWD. L/D MWD, LWD, Motor & Bit. or. Bit Grade- PDC- 2-3-BT-A-X-I-PN-TD Bit 1-1-WT-A-E-I-PN-TD;Clean & Clear rig floor.;Wellhead Pressures- 30X16'= 8 PSI, 16X10 3/4'= 40 PSi, 10 3/4 X 7'' =25 PSi Max gas 35. drilling 6-1/8" directional hole w/ slides as necessary to maintain WP#6 F/ 5199' ' T/5428' drilling 6-1/8" directional hole w/ slides as necessary to maintain WP#6 F/ 5757 ' T/6035 g drilling 6-1/8" directional hole w/ slides as necessary to maintain WP#6 F/ g 5428', T/5757' drilling 6-1/8" directional hole w/ slides as necessary to maintain WP#6 F/ 6035 ' T/6317 8/26/2021 Continue rigging up to run 4 1/2 DWC liner. Had issues getting the proper elevators due to the slim hole collars. Ended up using the slip type elevators and latching them in the door.;PU shoe track and check floats. MU landing collar jt. Baker locking first 2 connections. Went to MU 4th jt and safety latch on the power tongs broke.;Change out power tongs with spare set and test same.;Continue RIH w/ 4 1/2 liner f/ 169' t/ 2791' filling every jt and making sure pipe is topped off every 10 jts. {unload completion equip and mud products off boat.];RU head pin to circ and about 1 1/2 circ at the window. 40 spm , 175 psi. Install XOs and pups on cmt head while circulating.;RD circ equip and continue RIH PU 4 1/2 DWC liner F/ 2791' T/ 3590'.;Change handling equipment to P/U LT Packer. M/U HRD-E-HD-ZXP LT Packer & Hanger. Check pins. Good. 7 Pints in the hanger and 9 pins in the Packer setting tool. Mix Zan PLEX & Let sit 30 Min while L/D Stand of DC to recover 3.5 IF XO TO CDC-40.;Change Handling equipment to 4.5 Drill pipe. M/U First stand of 4.5 & Circ Liner volume. 3 BPM, Check ROT TQ @ 10& 20 RPM. 3800/4000. UP/DN 95/85.;RIH on 4.5 CDS-40 out of derrick F/ 3648' T/ 6220'. Fill pipe every 10 Stands. Wash down to btm staging up pumps to 4 BPM. 480 PSi Tag btm 3' Deep. 6320';Circ hole clean & Condition mud at 4 BPM, 480 PSI, UP/DN 150/100. P/U & TQ DP pup to cmt head. Prep for cmt job. R/U wash up line, Hang 100' hose in derrick for circ line. PJSM, Cmt job.;Shut down, L/D single, P/U & M/U cmt head & circ lines. Line up rig pumps and break circ. Good.;Line up to SLB & pump 5 bbl H20 to test lines. Pressure up to 500 psi, Good. Pressure up to 2300 & connection leaking from cmt unit. Fix leak. Pressure test 500/ 5000 psi. Good. Bleed off pressure. Line up to rig & Pump 25 bbl 12.5 ppg spacer.;Line up to slb & Mix & Pump 92 bbl of 15.3 ppg EasyBlock CMT. Shut down. SLB Wash up lines to rig floor with 20 bbl water. Line up down hole and pump 10 bbl 12.5 PPG Spacer. Use SLB & Chase with 91 bbl 9.5 ppg mud. Bump Plug. Saw good dart latch at 37.8 BBL away. 500 PSI increase. 3 BPM.;Slow to 1 BPM Last 10 bbl for bump. CIP at 05:51 Final Lift pressure at 1450 psi at 1 BPM. SLB bring pressure to 2300 psi to set hanger. Hold for 2 Min. Bring pressure to 2800 psi. Hold for 2 Min. Bring pressure to 4200 psi. Hold No indication of pusher tool on wt indicator. Set down to 50K. Good.;Bleed down and check Floats. Good. Bled back 1.5 bbl. P/U to 60K Over at 140K. No release. Slack back off to 50K. Pressure up with SLB to 4300 psi and saw indication on wt indicator. Bleed down and P/U to 78K. Free travel. Good Release. P/U with 1' of travel.;Wellhead Pressures- 30X16'= 8 PSI, 16X10 3/4'= 40 PSi, 10 3/4 X 7'' =24 PSi 8/27/2021 Close annular & test Liner top. Pump down kill line to 1000 psi. Hold 10 min. Good test. Bleed down. Open annular. Pressure up to 500 psi on DP with rig pumps. P/U until pressure started to drop. Bring on pumps to 8 BPM at 1000 psi & Circ out 25 bbl mud push & 35 BBL green cmt.;Shut down. Clean flow box, Flow line, Platform shakers. SLB wash up cmt unit. R/D Cmt head & Lines. Cmt head had to be turned upside down to get it broke down.;RU to LD DP. Pump dry job and POH laying dn 30 jts of DP.;Secure well and shut down laying dn DP. Unload completion equip off boat racking ,and strapping the 4 1/2 TBG. Cleaning rig shaker pit and pill pit while working boat.;Finish laying down the DP we ran the liner with. Lay dn liner setting tool. Dogs on tool were sheared so it set properly.;End of the drilling side we are swapping over to completion at 1800 hrs. Bump Pl pg Line up down hole and pump 10 bbl 12.5 PPG Spacer.pppp Use SLB & Chase with 91 bbl 9.5 ppg mud. test Liner top. Pump down kill line to 1000 psi. Hold 10 min. Good test. g RIH w/ 4 1/2 liner f/ 169' @ ;RIH on 4.5 CDS-40 out of derrick F/ Mix & Pump 92 bbl of 15.3 ppg EasyBlock CMT. Fill pipe every 10 Stands./ 3648' T/ 6220'. Wash down to btm staging up pumps to 4 BPM. 480 PSiggpp p ';Circ hole clean & Condition mud at 4 BPM, 480 PSI, UP/DN 150/100. g Tag btm 3' Deep. 6320'; P/U & TQ DP pup to cmt head. Prep for cmt job. R/U wash up line, Hang 100' hose in derrick for circ line. gp pp p j p PJSM, Cmt job.;Shut down, L/D single, P/U & M/U cmt head & circ lines.jg Line up rig pumps and break circ. Good.;Line up to ppgp Circ out 25 bbl mud push & 35 BBL green cmt. / 2791' Activity Date Ops Summary 8/27/2021 Working on Drilling Report Notified AOGCC of up upcoming MIT on A-04A. Test witness was waved by James Regg with AOGCC at 13:18 by email.,Pull Wear bushing & Flush stack with wash tool.,R/U Weatherford 4.5 Tubing equipment. P/U 4.5 Completion as per Tally & RIH with Baker ported Seal assembly T/ 2367' R/U Pollard Control line spooler & P/U SSSV. Pollard install control line on SSSV & pressure up to 5000 psi. Hold Pressure 10 min. Good test. Valve opened.,RIH with 4.5 Gaslift completion with baker seal assembly T/ 2686'. Run On SS band above each collar. Saw good drag with seals entering profile with 5K Drag. Tag no go with 10K Down. 8' Deep from liner tally. 2686'. L/D three joints, M/U 8.19 Pup & Make back up last joint of tubing.,Change handling equipment to 4.5 DP. M/U XO & hanger to landing joint. Make termination in to hanger with control line. Pressure up to 5000 psi and hold. RIH keeping seals above liner top profile. Blow mud out of choke and kill lines on rig floor.,Wellhead Pressures- 30X16'= 8 PSI, 16X10 3/4'= 42 PSi, 10 3/4 X 7'' =24 PSi 8/28/2021 Displace well to 2% KCL completion fluid. R/U & Drain stack. Land hanger and run in LDS. Landed hanger seeing good indication of seals engaged. 5K drag. Landed 2.17 off of no go. UP/DN 72/72. Block wt is 40k.,MIT, Test tbg, inner seals, and liner to 1500 psi for 30 min on a chart. good test!. Test annulus, outside of seals, and packer to 1500 psi for 30 min on a chart. Good test!,Blow down lines, Back out and pull landing jt. PU T bar and set TWC in hanger. LD T bar and Pollard tools,Break out LJ XOs and stand the stand back. Get permits for nipple down.,Nipple down BOPs. Pull master bushings, install rotary guard and nipple dn bell nipple.,Remove choke and kill hoses. Remove choke and kill line valves from stack. Break bolts on the bottom of the BOPs, PU the BOPs and trolley them over to the side. MU lifter on riser and unbolt riser.,Pull riser and L/D same. N/U Adaptor & Master Valve. Terminate control line. Test Void to 500/5000 psi for 5 min low & high with Vault Tec.,N/U Production tree as per production. Test Tree to 500/5000 psi 5min Low 5 Min high. Good. Test with Vault Tec. Remove 1502 X 2 9/16 Flange from IA.,Pull TWC. Hang choke and kill valves in sb to skid rig. Secure lines for skidding. Work on housekeeping.,Blow down Service lines to rig. Remove beaver slide. Prep Jack for installation to Push sub to A-03A . Cut welds on inner storm clamps. Install sub Jacks and Prep hydraulic unit.,Skid Lower sub to A-03A and check with Joint of DP from rig floor. Prep for skidding upper sub over A-03A. Swap Hydraulic hoses to upper jacks. Check Wellhead pressures on A-03A. 0 PSI on tubing and IA. 10/15/2021 MIRU. Stay on same permit as previous well. PT lubricator low/high.,Rih w/ 4 1/2 Gs w/ 9' prong to 318' kb, latch SSSV, pooh, ooh w/ sssv. Covered in tree grease. Rih w/ 3.75 G-ring to 2692' kb, set down in seal assembly. Pooh. Rih w/ 3" X 3.5 ' DD Bailer to 5800' kb, fall very slowly to 5978' kb, w/t pooh, ooh, ~ 1 cup of mud in bailer.,RDMO 10/16/2021 Move over from A-3 Stay on same PTW. MIRU. PT lubricator low/high.,Rih w/ 4 1/2 Gs w/ 4 1/2 AD-2 stop to 2590' kb, set Ad-2 stop, pooh, ooh sheared no stop. Rih w/ 4 1/2 Daniels KOT w/ 1 14 JDS to 2568' kb, latch dummy pooh, ooh no dummy valve. Rih w/ 4 1/2 Daniels KOT w/ jk w/ 1' bk 5/16" orifice to 2568' kb, set orifice pooh, ooh no valve. Rih w/ 4 1/2 GS to 2590' kb, latch Ad-2 stop pooh, ooh w/ stop. No valve.,RDMO. Depart platform. 10/24/2021 RU SLB CTU #1 on A-04A from A-03A. Perform BOP test 300/44750psi - Test good (AOGCC witnessed waived per Jim Regg on 10/21/21 at 8:46am),MU Quadco 3.65" milling BHA and RIH. Started seeing erratic RIH weights around ~6013' CTMD. Cleaned at well at 25 FPM pumping drill water at 1.7 BPM, worked mill down to 6,220' (RKB corrected). Pumped 5bbl gel sweep on bottom and chased to surface. POOH and layed down milling BHA. RD CT for the night,RU AK Wireline and run CBL in 4.5" liner, good cement up to liner hanger. RD E-line unit 10/25/2021 RU CTU, MU Nozzle BHA and RIH. Come online with N2 down coil and start blowing well down while RIH. Worked pipe down to 6,220', and got ~130bbls of returns back before fluid returns stopped. POOH and rig down coil. CBL reviewed and perforating approved by Bryan McLellan AOGCC 10/25 @ 17:46 11/3/2021 AKEL crew assembles and obtains permit. Warm up e-line equipment. Move riser from A-02 to A-04A. Make up weight bar and stab lubricator on well. Pressure test lubricator to 250 psi low / 2500 psi high. Lay down lubricator, secure location and SDFN. n (LAT/LONG): evation (RKB): API #: Well Name: Field: County/State: NCIU A-04A North Cook Inlet Hilcorp Energy Company Composite Report , Alaska Contractor AFE #: AFE $: Job Name:211-00023 A-04A Completion Spud Date: ,MIT, Test tbg, inner seals, and liner to 1500 psi for 30 min on a chart. good test! Displace well to 2% KCL completion fluid. R/U & Drain stack. Land hanger and run in LDS. CBL reviewed and perforating approved by Bryan McLellan AOGCC 10/25 @ 17:46 p 4.5 Completion as per Tally & RIH with Baker ported Seal assembly T/ 2367' Test annulus, outside of seals, and packer to 1500 psi for 30 min on a chart. Good test!, ()pgp ,RU AK Wireline and run CBL in 4.5" liner, good cement up to liner hanger. pp g Test witness was waved by James Regg with AOGCC at 13: 11/4/2021 AKEL crew assembles and attends morning meeting. Obtains permits.,Warm up equipment. Pick up lubricator and stage equipment. Arm and RIH with 10' 2- 7/8" HC gun. Correlate to open hole logs and send to town for correction. Correct depth (+1') and perforate Beluga G from 6028-6038'. Initial SITP 0 psi, stabilized at 338 psi. POOH.,Break off from riser and inspect gun, all shots fired. ARM 14' 2-7/8" HC gun and RIH. Correlate to open hole log and send to town for correction. Correct depth (+1') and perforate Beluga F Upper 2 from 5876-5890'. SITP 342 psi, stabilized at 344 psi. POOH.,Break off from riser and inspect gun, all shots fired. ARM 4' 2-7/8" HC gun and RIH. Correlate to open hole log and send to town for correction. On depth. Perforate Beluga F Upper 1 from 5859- 5863', pressure stable at 348 psi. POOH.,Break off from riser and inspect gun, all shots fired. ARM 14' 2-7/8" HC gun and RIH. Correlate to open hole log and send to town for correction. On depth. Perforate Beluga E Lower 2 (Bottom) from 5832-5846'. Pressure stable at 355 psi. POOH,Break off from riser and inspect gun, all shots fired. Install night cap and grease swab. Swab holding. Arm 11' 2-7/8" HC gun and RIH. Correlate to open hole log and send to town for correction. On depth. Perforate Beluga E Lower 2 (Top) from 5821-5832'. Pressure drops from 355 psi to 346 psi. POOH.,Break off from riser and inspect gun, all shots fired. Arm 17' 2-7/8" HC gun and RIH. Correlate to open hole log and send to town for correction. On depth. Perforate Beluga E Lower 1 from 5785-5802'. Pressure stable at 352 psi. POOH.,Break off from riser and inspect gun, all shots fired. Lost communications with gun gamma-ray tool, rope socket is bad. Spool off line and build new head. Arm and RIH with 20' 2-7/8" gun. Correlate to open hole log and send to town for correction. On depth. Perforate Beluga E Mid (Lower) from 5756-5776'. SITP static at 355 psi. POOH.,Break off from riser and inspect gun, gun did not fire. Lay down gun and break off firing head. Detonator went off but primacord did not reach top charge. Probably got some moisture into primacord during staging and arming process. Complete swab valve maintenance, rig down eline and have crew get alternate 20' gun for tomorrow morning ready. SDFN. 11/5/2021 AKEL crew attends morning meeting and obtains permits. Warm up e-line equipment.,Arm 20' 2-7/8" HC gun and suck into lubricator on deck. Pick up lubricator assembly and stab on well. RIH, correlate to open hole log and send to town for correction. On Depth. Perforate Beluga E Mid (Lower) from 5756-5776'. Well flowing 2.2 mmcf @ 293 psi. Pressure increased to 304 psi while POOH.,Break off from riser and inspect gun, all shots fired. Arm and RIH with 10' 2-7/8" HC gun. Correlate to open hole log and send to town for correction. Correct depth (+1') and perforate Beluga E Mid (Upper) from 5746-5756'. Well flowing 2.2mmcf @ 305 psi stable. POOH.,Break off from riser and inspect gun, all shots fired. Arm and RIH with 9' 2-7/8" HC gun. Correlate to open hole log and send to town for correction. On depth. Perforate Beluga E Upper 2 from 5711-5720'. Well flowing 2.1 mmcf @ 307 psi. Pressure increased to 310 psi. POOH.,Break off from riser and inspect gun, all shots fired. Arm and RIH with 15' 2-7/8" HC gun. Correlate to open hole log and send to town for correction. On depth. Perforate Beluga E Upper 1 from 5692-5707'. Well flowing 2.2 mmcf @ 311 psi. POOH.,Break off from riser and inspect gun, all shots fired. Arm and RIH with 9' 2-7/8" HC gun. Correlate to open hole log and send to town for correction. On depth. Perforate Beluga D Lower from 5643-5652'. Well flowing 2.0 mmcf @ 316 psi. POOH.,Break off from riser and inspect gun, all shots fired. Arm and RIH with 15' 2-7/8" HC gun. Correlate to open hole log and send to town for correction. On depth. Perforate Beluga D Mid from 5604-5619'. Well flowing 2.0 mmcf @ 315 psi. POOH.,Break off from riser and inspect gun, all shots fired. Arm and RIH with 20' 2-7/8" HC gun. Correlate to open hole log and send to town for correction. Make correction (-1') and perforate Beluga D Upper from 5521-5541'. Well flowing 2.0 mmcf @ 315 psi. POOH.,Break off from riser and inspect gun, all shots fired. Arm and RIH with 20' 2-7/8" HC gun. While correlating to open hole log got stuck across last set of perforations (5521-5541'). Unable to go up or down. Exercise cable closer and closer to max pull and pulled free at 3200#. Correlate to open hole logs and and send to town for correction. On depth. Perforate Beluga C Lower from 5464-5484'.,Well flowing 2.2 mmcf. Pressure increases from 317 to 327 psi. POOH. Break off from riser and inspect gun, all shots fired. Lay down lubricator and sheave wheel in preparation for crane maintenance tomorrow morning. Secure location and SDFN. 11/6/2021 AKEL crew attends morning meeting and obtains permits. Warm up e-line equipment. Build new head while waiting for crane service to complete.,Pick up lubricator, arm and RIH with 11' 2-7/8" HC gun. Correlate to open hole log and send to town for correction. On depth. Perforate Beluga C Upper from 5376-5387'. Well flowing 2.1 mmcf @ 311 psi. POOH.,Break off from riser and inspect gun, all shots fired. Arm and RIH with 15' 2-7/8" HC gun. Correlate to open hole log and send to town for correction. On depth. Perforate Beluga B Lower from 5333-5348'. Well flowing 2.1 mmcf @ 326 psi. POOH.,Break off from riser and inspect gun, all shots fired. Arm and RIH with 15' 2-7/8" HC gun. Correlate to open hole log and send to town for correction. On depth. Perforate Beluga B Mid from 5258-5273'. Well flowing 2.0 mmcf @ 337 psi, increased to 341 psi. POOH.,Break off from riser and inspect gun, all shots fired. Arm and RIH with 5' 2-7/8" HC gun. Correlate to open hole log and send to town for correction. On depth. Perforate Beluga B Upper 2 from 5182-5187'. Well flowing 2 mmcf @ 341 psi. POOH.,Break off from riser and inspect gun, all shots fired. Arm and RIH with 14' 2-7/8" HC gun. Correlate to open hole log and send to town for correction. On depth. Perforate Beluga B Upper 1 from 5148-5162'. Flowing 2 mmcf @ 340 psi. POOH.,Break off from riser and inspect gun, all shots fired. Arm and RIH with 16' 2-7/8" HC gun. Correlate to open hole log and send to town for correction. On depth. Perforate Beluga A Lower from 5122-5138'. Well flowing 2.1 mmcf @ 348 psi. Rate came up to 3 mmcf and pressure to 494 psi. Production choked well back to 2 mmcf and FTP stabilized at 513 psi. POOH.,Break off from riser and inspect gun, all shots fired. Arm and RIH with 10' 2-7/8" HC gun. Correlate to open hole log and send to town for correction. On depth. Perforate Beluga A Upper from 5037-5047'. Well flowing 2 mmcf @ 488 psi. POOH. Rig down off A-04A and rig 7" riser up on A-01A. Secure well and SDFN. pg Perforate Beluga B Upper 1 from 5148-5162' pg Perforate Beluga E Upper 2 from 5711-5720'. pg Perforate Beluga B Lower from 5333-5348' pp Perforate Beluga C Upper from 5376-5387' pg Perforate Beluga A Lower from 5122-5138'. pg Perforate Beluga E Lower 2 (Bottom) from 5832-5846' p e Beluga F Upper 1 from 5859-g 5863', Perforate Beluga B Mid pg from 5258-5273'. p Perforate Beluga C Lower from 5464-5484' pg Perforate Beluga E Lower 1 from 5785-5802' pg Perforate Beluga D Lower from 5643-5652' pg perforate Beluga F Upper 2 from 5876-5890' pg perforate Beluga D Upper from 5521-5541' pg Perforate Beluga B Upper 2 from 5182-5187' pgqp perforate Beluga G from 6028-6038' g p Perforate Beluga E Mid (Lower) from 5756-5776' p Perforate Beluga E Mid (Lower) from 5756-5776'. pg perforate Beluga E Mid (Upper) from 5746-5756' Perforate Beluga A Upper pg from 5037-5047'. 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('7. 7 %/8'. %$.'$8 $ 8%('$87 $7%'%/ % 78& .$$'($ ((( .( '$( $'&& $ 8(('(8 (<!,+ B+ 50%3 & 8.'// (8'&/ ('$% 7 (7'$8 %&$' $ 8&%'/$7 %%('77 % 78& .7%'& ((( ./ '%7 '&7 $ 8/.'&( (<!,+ B+ 50%3 & $8('(8 (.'%( %'/( 7 %%'.8 ( '$( $ .%'/87 %.&'(7 % 78& ..7'$ (( $ '.7 '&7 $ .%&'& (<!,+ B+ 50%3 & %//'8% (8'.( $'.$ 7 .&'%. ( 8'$7 $ . %'8/7 (&.'&& % 78/ (8'7( (( 77'&& '&( $ ./('8$ (<!,+ B+ 50%3 & ($/' (8'.( $'.$ 7 7%&'// (&&' / $ .7.'($7 '$ % 78/ 7&'&$ (( /%'(/ ' $ ..('%$ -)E1*1* 6=@6=@ @ Benjamin Hand Digitally signed by Benjamin Hand Date: 2021.08.31 09:56:55 -08'00'Chelsea Wright Digitally signed by Chelsea Wright Date: 2021.08.31 10:29:05 -08'00' TD Shoe Depth: PBTD: Jts. 1 1 87 Yes X No X Yes No Fluid Description: Liner hanger Info (Make/Model): Liner top Packer?:X Yes No Liner hanger test pressure:X Yes No Centralizer Placement: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg)Rate (bpm):Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp: X Yes No Casing Rotated? Yes X No Reciprocated?X Yes No % Returns during job Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: 2,717.03 2,678.20 EsyBLOK 389 1.33 4 3,508.14 6,225.17 2,717.03 ZXP 4 1/2 38.83 Casing 4 1/2 12.6 L-80 DWC3 6,226.32 Landing Collar 4 1/2 12.6 L-80 DWC 1.15 6,226.32 6,225.17 6,268.22 6,266.64 Casing 4 1/2 12.6 L-80 DWC 40.32 6,266.64 41.62 6,309.84 6,268.22 Float Collar 5 12.6 L-80 DWC 1.58 Casing 4 1/2 12.6 L-80 DWC www.wellez.net WellEz Information Management LLC ver_04818br 50 LSND 15.3 92 Type of Shoe:Float shoe Casing Crew: ZXP Baker Hughes Returns Bump Plug? 5:51 8/27/2021 2,678 6,312.006,317.00 6,225.00 CEMENTING REPORT Csg Wt. On Slips: 91.5/92 2300 35 2 Bump press 18 9.6 4 100 1450FIRST STAGE12.5MUD Push 25 DWC 2.16 6,312.00 6,309.84 Csg Wt. On Hook:100 Type Float Collar:Baker Hughes No. Hrs to Run: Grade THD Make Length Bottom Top Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.NCIU A-04A Date Run 27-Aug-21 1000 LSND CASING RECORD County State Alaska Supv.M Rogers / S.Sunderland Setting Depths Ft. Min.PPG9.5 Shoe @ 6312 FC @ Top of Liner 26786,266.00 Floats Held Casing (Or Liner) Detail Float Shoe 5 12.6 L-80 Rotate Csg Recip Csg Component Size Wt. From:McLellan, Bryan J (CED) To:Winston, Hugh E (CED) Cc:Guhl, Meredith D (CED) Subject:RE: [EXTERNAL] 10-407: NCIU A-04A Completion Date Date:Tuesday, November 16, 2021 4:02:07 PM Huey, Since the perfs were included in the completion Sundry 321-334, which called for the report of Sundry operations to be included in the 10-407, I would make the completion date when the last perforations were shot. Thanks 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: Winston, Hugh E (CED) <hugh.winston@alaska.gov> Sent: Friday, November 12, 2021 2:57 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Guhl, Meredith D (CED) <meredith.guhl@alaska.gov> Subject: FW: [EXTERNAL] 10-407: NCIU A-04A Completion Date Bryan, Can you please advise on how you would like the completion date on 10-407’s to be identified? If the completion date is to be considered the end of August, then the requirement for filing the 10- 407 within 30 days was missed. Thanks, Huey From: Cody Dinger <cdinger@hilcorp.com> Sent: Friday, November 12, 2021 1:05 PM To: Winston, Hugh E (CED) <hugh.winston@alaska.gov> Cc: Guhl, Meredith D (CED) <meredith.guhl@alaska.gov> Subject: RE: [EXTERNAL] 10-407: NCIU A-04A Completion Date Hi Huey, Could go multiple ways on this one. Historically, Guy asked me for the date completion tubing/tieback was run for that box. Which we ran on 8/27. If you guys want the first perf date(11/4/21 on NCIU A-04A) going in that box, let me know and I’ll do that going forward. Thanks, Cody Dinger Hilcorp Alaska, LLC Drilling Tech 907-777-8389 From: Winston, Hugh E (CED) <hugh.winston@alaska.gov> Sent: Friday, November 12, 2021 11:44 AM To: Cody Dinger <cdinger@hilcorp.com> Cc: Guhl, Meredith D (CED) <meredith.guhl@alaska.gov> Subject: [EXTERNAL] 10-407: NCIU A-04A Completion Date Hi Cody, Can you please verify the completion date for NCIU A-04A(ptd# 221-026)? It’s reported as being completed at the end of August but we are thinking it should possibly be in November when the perfs were shot. Thanks Huey Winston Statistical Technician Alaska Oil and Gas Conservation Commission hugh.winston@alaska.gov 907-793-1241 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. From:McLellan, Bryan J (OGC) To:Karson Kozub - (C) Cc:Juanita Lovett; Sean Mclaughlin Subject:RE: [EXTERNAL] RE: NCIU A-04A (PTD 221-026) Completion Sundry (321-334) Date:Friday, August 27, 2021 2:06:00 PM Sounds good. You can proceed with the changes as planned, with the CBL run in liquid. 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: Karson Kozub - (C) <kkozub@hilcorp.com> Sent: Friday, August 27, 2021 2:05 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com>; Sean Mclaughlin <Sean.Mclaughlin@hilcorp.com> Subject: RE: [EXTERNAL] RE: NCIU A-04A (PTD 221-026) Completion Sundry (321-334) Bryan, Thank you for catching that. We will run the CBL while there is still fluid in the well, but after the RIG 151 is gone. Regards, Karson KozubMobile: +1 (907) 570-1801kkozub@hilcorp.com From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Sent: Friday, August 27, 2021 1:48 PM To: Karson Kozub - (C) <kkozub@hilcorp.com> Cc: Juanita Lovett <jlovett@hilcorp.com>; Sean Mclaughlin <Sean.Mclaughlin@hilcorp.com> Subject: [EXTERNAL] RE: NCIU A-04A (PTD 221-026) Completion Sundry (321-334) Karson, The CBL won’t work in gas. You’ll need to run it before blowing down with N2. 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: Karson Kozub - (C) <kkozub@hilcorp.com> Sent: Friday, August 27, 2021 11:28 AM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com>; Sean Mclaughlin <Sean.Mclaughlin@hilcorp.com> Subject: NCIU A-04A (PTD 221-026) Completion Sundry (321-334) Hello Bryan, We are currently getting ready to run completion on NCIU A-04A. Attached is a copy of the approved sundry. The liner lap has been pressure tested and held, we will perform another liner lap pressure test in step 5 below. It will save us rig time to run our CBL later when we perforate. Also with the MIT requirements I believe it will be easier to run dummy valves in the GLM’s and pressure test without setting a plug in our x-nipple. With those changes our new procedure is below. Please let me know if you have any questions. Procedure: 1. ***Take over operations from the Drilling Sidetrack Program PTD 221-026*** 2. Test BOP’s every 14 days continued from last test date from PTD 221-026 Test to 250psi low/2,500psi high / 2,500 psi annular. (Note: Notify AOGCC 48 hours in advance of test to allow them to witness test). 3. Completion fluid will be KCL. BOP’s will be closed as needed to circulate the well. 4. ** If not already completed under PTD 221-026, Rig up E-Line and run gamma/ccl/cbl. 5. RIH with 4-1/2” tubing, SSSV nipple, X-nipple, and Gas Lift completion (see schematic for specific depths) Space out and land completion per proposed schematic Set plug in X-nipple at ± 2,580’ MIT-Tbg and sealbore to 1,500psi charted for 30min *Note provide 48hrs notice for AOGCC to witness pressure tests. Pressure test inner annulus to 1,500 psi for 30 min charted (this will pressure up the tubing also, live GLV’s)GLM’s will be dummied off *Note provide 48hrs notice for AOGCC to witness pressure tests Pull plug in X-nipple 6. Set BPV, ND BOPE, NU tree and test same 7. R/U Coil tubing unit 8. Perform BOPE pressure test 250psi low/2,500psi high (Note: Notify AOGCC 48hrs in advance to allow them to witness) 9. RIH and clean out to PBTD ±6,180’ 10. Blow well dry with Nitrogen to production header or non-enclosed open top tank. POOH, R/D Coil tubing. 11. RU E-line pressure test 250psi low/2,500psi high Run gamma/ccl/cbl perforate per program. Note: Deepest zone will be perforated as first. This zone will be tested. Contingency: If zone is unproductive, a CIBP w/cement will be placed above the open zone. E-line will perforate the next shallowest zone. This will be repeated until a productive zone is achieved. 12. Turn over to production. Schedule SVS testing with AOGCC as per regulations Regards, Karson KozubMobile: +1 (907) 570-1801kkozub@hilcorp.com 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. 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 deletethis 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. David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or fax to 907 564-4422. Received By: Date: Date: 9/22/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL NCIU A-04A (PTD 221-026) FINAL LWD FORMATION EVALUATION LOGS (08/21/2021 to 08/25/2021) x PCG, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Survey SFTP Transfer - Data Folders: Please include current contact information if different from above. Received By: 09/22/2021 37' (6HW By Abby Bell at 10:37 am, Sep 22, 2021 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Reviewed By: i3� P.I. Supry 'o1792-' BOPE Test Report for: N COOK INLET UNIT A -04A - Comm Contractor/Rig No.: Spartan 151 - PTD#: 2210260 " DATE: 8/17/2021 - Inspector Adam Earl Insp Source Operator: Hilcorp Alaska, LLC Operator Rep: Shane Hauck Rig Rep: Brian LaFleUr Inspector Test Pressures• Type Operation: DRILL Sundry No: Rams: Annular: Valves: MASP: Inspection No: bopAGE210824065243 Type Test: INIT 250/5000 250/2500 ' 250/5000- 721 Related Insp No: MISC. INSPECTIONS: TEST DATA MUD SYSTEM: P/F Location Gen.: P Housekeeping: P_ PTD On Location P Standing Order Posted P Well Sign _P Drl. Rig P Hazard Sec. P Misc NA TEST DATA MUD SYSTEM: BOP STACK: Visual Alarm Trip Tank P P - Pit Level Indicators P P - Flow Indicator P P ' Meth Gas Detector P P H2S Gas Detector P FP ✓ MS Misc 0 NA_ ACCUMULATOR SYSTEM: BOP STACK: Time/Pressure P/F System Pressure 3100 _ P Pressure After Closure 1800 '_ P 200 PSI Attained 19 ' _ P - Full Pressure Attained 115 - P - Blind Switch Covers: All Stations -_P ' Nitgn. Bottles (avg): 162277 P _ ACC Misc _ 0 NA FLOOR SAFTY VALVES: BOP STACK: CHOKE MANIFOLD: Quantity P/F Quantity Size P/F Quantity P/F Upper Kelly 1_ ._ P- Stripper 0 _ NA No. Valves 16 P _ Lower Kelly 1 P _ Annular Preventer 1 -135/8 _ P Manual Chokes I_ P ; Ball Type 2 P #1 Rams 1 -4 1/2 P Hydraulic Chokes 2 P Inside BOP 1 P #2 Rams I 'Blind P CH Misc 0 _ _ NA FSV Misc 0 NA #3 Rams 1 ' 2 7/8 X 5 1/2 P #4 Rams 0 NA #5 Rams 0 NA INSIDE REEL VALVES: #6 Rams 0 NA (Valid for Coil Rigs Only) Choke Ln. Valves 1 -3 1/16 P - Quantity P/F HCR Valves 2 '3 1/16 P - Inside Reel Valves ___ 0__ _ NA Kill Line Valves 2 - 3116- - P Check Valve 0 NA BOP Misc 0 NA Number of Failures: 1 / Test Results Remarks: H2S head in Cellar had to be Calibrated, passed re test. Test Time 12.5 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 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address: 3800 Centerpoint Drive, Suite 1400 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): North Cook Inlet Unit / Tertiary Gas Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): ±6,270 (proposed)N/A Casing Collapse Structural Conductor 630 psi Surface 2,090 psi Intermediate Production 3,270 psi Liner 7,500 psi 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 Contact Name: Contact Email:kkozub@hilcorp.com Contact Phone: (907) 777-8434 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 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 Authorized Signature: Operations Manager Karson Kozub PRESENT WELL CONDITION SUMMARY Length N Cook Inlet Unit A-04A COMMISSION USE ONLY Authorized Name: Size N/A TVD Burst N/A 4,360 psi 8,430 psi Tubing Size: MD 1,640 psi 3,580 psi 390' 576' 2,264' 576' 2,410' 390'390'30" 16" 10-3/4" 576' 2,410' Perforation Depth MD (ft): N/A ±2,750' (proposed) N/A Tubing Grade:Tubing MD (ft): N/A Perforation Depth TVD (ft): N/A 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. 7/15/2021 N/A Daniel E. Marlowe N/A ±3,620' (proposed) 4-1/2" (proposed) ±2,523' (proposed)7" ±6,270' (proposed) ±5,484' (proposed) ±2,750' (Proposed) Other: G/L Completion / N2 Operations CO 68A ±5,484' (proposed)±6,180' (proposed) ±5,415' (proposed) 721 psi 221-026 50-883--20023-01-00Anchorage, AK 99503 Hilcorp Alaska, LLC Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 3:20 pm, Jul 02, 2021 321-334 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.07.02 12:48:24 -08'00' Dan Marlowe (1267) Drilling BOP test to 2500 psi. CT BOP test to 2500 psi. MIT-T and MITIA to 1500 psi required - Provide 48 hrs notice for AOGCC to witness tests. See notes in procedure 10-407 DSR-7/6/21 X Variance to 20AAC25.265(c)(1) for having SSV on the horizontal run, flanged to the wing valve is approved. SFD 7/6/2021 X BJM 7/22/21 dts 7/22/2021 JLC 7/22/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.07.22 16:41:46 -08'00' RBDMS HEW 7/26/2021 Well Work Prognosis Well Name:NCIU A-04A API Number:50-883-20023-01-00 Current Status:Producer Leg:Leg #3 SE Corner Estimated Start Date:7/15/2021 Rig:Spartan 151/Coil/EL Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:221-026 First Call Engineer:Karson Kozub (907) 777-8434 (O) (907) 570-1801 (M) Second Call Engineer:Katherine O’Connor (907) 777-8376 (O) (214) 684-7400 (M) Current Bottom Hole Pressure: 1,213 psi @ 4,919’ TVD 0.247psi/ft (4.8 ppg) Beluga E sands expected Maximum Expected BHP:3,561 psi @ 6,857’ TVD 0.247psi/ft (4.8 ppg) Beluga E sands expected Maximum Potential Surface Pressure: 721 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Brief Well Summary NCIU A-04A is a Beluga producer that will be completed with gas lift. This new well was sidetracked from the current NCIU A-04, a shut-in plugged producer. This work will run completion, N2 blow dry and perforate. Timing will be based on timeliness of getting the well drilled. Last Casing Test: Casing and liner will be tested to 1,500psi under PTD 221-026 Waiver Request: Hilcorp requests a waiver to 20AAC25.265(c)(1). We request to locate the SSV on the tree wing allowing the SSV to remain in the production stream while providing concurrent wellbore access. Procedure: 1. ***Take over operations from the Drilling Sidetrack Program PTD 221-026*** 2. Test BOP’s every 14 days continued from last test date from PTD 221-026 x Test to 250psi low/2,500psi high / 2,500 psi annular. (Note: Notify AOGCC 48 hours in advance of test to allow them to witness test). 3. Completion fluid will be KCL. BOP’s will be closed as needed to circulate the well. 4. ** If not already completed under PTD 221-026, Rig up E-Line and run gamma/ccl/cbl. 5. RIH with 4-1/2” tubing, SSSV nipple, X-nipple, and Gas Lift completion (see schematic for specific depths) x Space out and land completion per proposed schematic x Set plug in X-nipple at ± 2,580’ x Pressure test inner annulus to 1,500 psi for 30 min charted (this will pressure up the tubing also, live GLV’s) x Pull plug in X-nipple 6. Set BPV, ND BOPE, NU tree and test same 7. R/U Coil tubing unit 8. Perform BOPE pressure test 250psi low/2,500psi high (Note: Notify AOGCC 48hrs in advance to allow them to witness) 9. RIH and clean out to PBTD ±6,180’ 10. Blow well dry with Nitrogen to production header or non-enclosed open top tank. x POOH, R/D Coil tubing. 11. RU E-line pressure test 250psi low/2,500psi high x perforate per program. Note: Deepest zone will be perforated as first. This zone will be tested. x Contingency: If zone is unproductive, a CIBP w/cement will be placed above the open zone. E-line will perforate the next shallowest zone. This will be repeated until a productive zone is achieved. 12. Turn over to production. 13. Schedule SVS testing with AOGCC as per regulations MIT-Tbg and sealbore to 1500 psi before setting plug. bjm Provide 48 hrs notice for AOGCC to witness test. 1213 psi @ 4919' TVD bjm Provide 48 hrs notice for AOGCC to witness test. If liner lap pressure test failed in the PTD, a liner top packer or remedial cement job is required to establish pressure integrity of the liner lap prior to running the completion. bjm Well Work Prognosis Attachments: 1. Well Schematic Current 2. Well Schematic Proposed 3. Wellhead Schematic 4. BOP Drawing – Spartan 151 5. BOP Drawing – Coil Tubing 6. Fluid Flow Diagram –Spartan 151 7. Choke Diagram – Spartan 151 8. Fluid Flow Diagram –Coil Tubing 9. Standard Well Procedure – Nitrogen operations 10. Sundry Revision Change Form _____________________________________________________________________________________ Updated By: JLL 6/25/21 SCHEMATIC Tyonek Platform Well: NCI A-04 Last Completed: 6/5/2021 PTD: 169-018 API: 50-883-20023-00 TD: 7,656‘MD TVD:6,412’ 16” RKB to TBG Head – 64.4’ 7” 8 9 10 11 Passed MITIA – 2,400 psi. (1/5/08) 10-3/4” 30” 12 13 14 15 Cement Plug @ 5,131’ Cement Plug @ 4,880’ Max Deviation 37.01 degrees @ 4,426’ Possible collapsed Casing @ 5184’. (6/27/94) Restriction of 3.725” ID @ 4,133’ RKB. (1/27/08) 16 17 18 19 20 21 Collapsed Casing @ 4,702 TOC 4,120’ Inflatable packer left @ 4,685’ RKB. (08/03/20) TOC 7” 2,600Ft CASING DETAIL Size Wt Grade Conn ID Top Btm 30” Conductor Welded 29” 41’ 390’ 16” 65 H-40 Welded 15.25” 41’ 576’ 10-3/4” 51/45.5 J-55 BTC 9.794” 41’ 2,410’ 7” 26/23 J-55 BTC 6.366” 39’ 7,618’ TUBING DETAIL 4-1/2” 12.6 J-55 IBT-M Surf 158’ GRAVEL PACK LINER DETAIL OD ID Top Btm 5.43” 3.428” 4,447.1’ 4,701.2’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 158’ 158’ Kill String 8 4,120’ 3,586’ Top of cement plug 4,402’ 3,810’ 6.366” Plug EZSV Cement retainer 9 4,447.1’ 3,845.9’ 4.000” PACKER, Baker SC-1 GP packer 10 4,451.8’ 3,849.7’ 4.892” UPPER EXTENSION 11 4,455.6’ 3,852.7’ 4.000” SLEEVE, Baker GP sliding sleeve 12 4,458.2’ 3,854.8’ 4.000” SBE, Baker 80-40 Seal bore 13 4,459.7 3,856.0’ 4.276” 5.000” LOWER EXTENSION, Baker 5” Lower Ext. 14 4,475.3’ 3,868.5’ 3.428” 5.500” XO REDUCING, XO sub 5-1/2” 17# SHLT box X 4” SHLT pin 15 4,476.8’ 3,869.7’ 3.000” KOIV, Baker KOIV 4” flapper 16 4,478.5’ 3,871.1’ 3.428” SOS, Baker Shear out safety sub 17 4,513.5’ 3,899.3’’ 3.428” 5.43” SCREENS, 5 Baker 4” Extruder screens 18 4,700.4’ 4,049.2’ 0.000” BULL PLUG, Baker 4” SHLT bull plug 19 4,828.0’ 4,154.3’ 0.000” PLUG, Cast Iron Bridge Plug (8/30/94 run date) 20 5,130.0 4,401.4’ 0.000” PLUG, EZSV Cement Retainer (8/29/94 run date) 21 5346.0’ 4,576.4’ 0.000” PLUG, EZSV Cement Retainer (8/28/94 run date) SCHEMATIC Tyonek Platform Well: NCI A-04 Last Completed: 6/5/21 PTD: 169-018 API: 50-883-20023-00 __________________ Updated By: JLL 6/25/21 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status CI-1.0 4,520’ 4,600’ 3,904.5’ 3,968.8’ 80’ 06/05/21 Isolate CI-2.0 4,620’ 4,690’ 3,984.9’ 4,048.9’ 80’ 06/05/21 Isolate CI-2.0 4,690’ 4,700’ 4,042’ 4,050’ 10’ 08/03/2020 Isolated CI-3.0 4,732’ 4,742’ 4,075.3’ 4083.5’ 10’ 08/03/2020 Isolated CI-4.0 4,764' 4,814’ 4,101.7’ 4,142.8’ 50’ 08/03/2020 Isolated CI-5.0 4,865’ 4,895’ 4,184.7’ 4,209.3’ 30’ 8/22/1994 Plugged-CIBP/Cement Plug RPERF 12 spf CI-5.1 4,908’ 4,918' 4,219.9’ 4,228.1' 10' 4/14/1969 Plugged-Cement Plug IPERF 4 spf CI-6.0 4,948’ 4,963' 4,252.8’ 4,265.1’ 15' 8/22/1994 Plugged – Cement Plug RPERF 12 spf CI-6.1 4,973' 4,980' 4,273.3’ 4,279.0’ 7' 8/22/1994 Plugged – Cement Plug RPERF 12 spf CI-9.0 5,184' 5,198' 4,445.3’ 4,456.7’ 14' 8/22/1994 Plugged – Cement Plug RPERF 12 spf CI-11.0 5,255' 5,285' 4,502.8’ 4,527.0’ 30' 8/22/1994 Blocked – Below Cement Plug RPERF 12 spf A-7 5,392' 5,405' 4,616.1’ 4,626.3’ 13' 8/22/1994 Blocked – Below EZSV RPERF 12 spf B-7 5,578' 5,584' 4,763.8’ 4,768.6’ 6' 8/22/1994 Blocked – Below EZSV RPERF 12 spf C-1 5,650' 5,655' 4,822.1’ 4,826.2’ 5' 8/22/1994 Blocked – Below EZSV RPERF 12 spf C-3 5,728' 5,745' 4,885.6’ 4,898.9’ 17' 8/22/1994 Blocked – Below EZSV RPERF 12 spf E-9 6,070' 6,080' 5,162.1 5,170.2’ 10' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-4 6,152' 6,162' 5,227.9’ 5,235.9’ 10' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,220' 6,250' 5,282.8’ 5,306.5’ 30' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,257' 6,262' 5,312.0’ 5,315.9’ 5' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,355' 6,380' 5,389.2’ 5,408.9’ 25' 8/22/1994 Blocked – Below EZSV RPERF 12 spf F-8 6,410' 6,425' 5,432.5’ 5,444.4’ 15' 8/22/1994 Blocked – Below EZSV RPERF 12 spf I-7 6,630' 6,640' 5,605.9’ 5,613.8’ 10' 4/14/1969 Blocked – Below EZSV IPERF 4 spf Q-4 7,515' 7,542’' 6,308.0' 6,239.7’ 27' 4/14/1969 Blocked – Below EZSV IPERF 4 spf _____________________________________________________________________________________ Updated By: JLL 06/29/21 PROPOSED Tyonek Platform Well: NCI A-04A Last Completed: Future PTD: 221-026 API: 50-883-20023-01-00 PBTD: ±6,180’ MD 16” RKB to TBG Head – 64.4’ 7” 2 3 4 5 10-3/4” 4-1/2” 130” TOC 7” 2,600Ft TD: ±6,270’ MD X CASING DETAIL Size Wt Grade Conn ID Top Btm 30” Conductor Welded 29” Surf 390’ 16” 65 H-40 Welded 15.25” Surf 576’ 10-3/4” 51/45.5 J-55 BTC 9.794” Surf 2,410’ 7” 26/23 J-55 BTC 6.366” Surf ±2,750 (KOP) 4-1/2” 12.6 L-80 ±2,650’ ±6,270’ TUBING DETAIL 4-1/2” 12.6 L-80 IBT-M Surf ±2,650’ 0 JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 1 ±290’ ±290’ SSSV 2 ±1,400’ ±1,390’ GLM 3 ±2,550’ ±2,371’ GLM 4 ±2,580’ ±2,394’ X Nipple 5 ±2,650’ ±2,447’ Baker Liner Hanger / Seal Bore PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status ±4,584' ±4,596' ±4,143’ ±4,154’ ±12' Future Proposed ±4,615' ±4,623' ±4,171’ ±4,178’ ±8' Future Proposed ±4,665' ±4,673' ±4,215’ ±4,222’ ±8' Future Proposed ±4,694' ±4,710' ±4,241’ ±4,255’ ±16' Future Proposed ±4,739' ±4,762' ±4,281’ ±4,302’ ±23' Future Proposed ±4,799' ±4,809' ±4,334’ ±4,343’ ±10' Future Proposed ±4,892' ±4,898' ±4,416’ ±4,421’ ±6' Future Proposed ±5,153' ±5,163' ±4,628’ ±4,636’ ±10' Future Proposed ±5,192' ±5,210' ±4,658’ ±4,672’ ±18' Future Proposed ±5,232' ±5,237' ±4,688’ ±4,692’ ±5' Future Proposed ±5,244' ±5,248' ±4,698’ ±4,701’ ±4' Future Proposed ±5,279' ±5,287'±4,724’±4,731’±8' Future Proposed ±5,348' ±5,355'±4,777’±4,783’±7' Future Proposed ±5,377' ±5,391'±4,799’±4,810’±14' Future Proposed ±5,409' ±5,416'±4,824’±4,829’±7' Future Proposed ±5,448' ±5,470'±4,854’±4,871’±22' Future Proposed ±5,554' ±5,562'±4,935’±4,941’±8' Future Proposed ±5,598' ±5,604'±4,969’±4,973’±6' Future Proposed ±5,611' ±5,622'±4,979’±4,987’±11' Future Proposed ±5,694' ±5,717'±5,042’±5,060’±23' Future Proposed ±5,769' ±5,772'±5,100’±5,102’±3' Future Proposed ±5,782' ±5,808'±5,110’±5,130’±26' Future Proposed ±5,816' ±5,825'±5,136’±5,143’±9' Future Proposed ±6,136' ±6,143'±5,381’±5,386’±7' Future Proposed ±6,186' ±6,205'±5,419’±5,434’±19' Future Proposed The motherbore must be indicated on the 10-407 wellbore diagram. This is not a packer. It is a hanger only. COIL TUBING BOP SWAB VALVE MASTER VALVE HilcorpMonopod Rig 56Flow Diagram Fluids Pumped Fluids ReturnedValve Open Valve ClosedGate Valve Ball ValveButterfly Valve Lo Torq ValveAutomatic Choke Manual ChokePressure Gauge Knife ValveChoke LineP PIT SYSTEM SucƟon SHAKER SHAKER CHOKE MANIFOLDGAS BUSTER Panic LineC12 C13 C15 C14 C16 A B C4 C5 C6 C7 C2 C10 C9 C11 C8 C3 P C1 C STANDARD WELL PROCEDURE NITROGEN OPERATIONS 09/23/2016 FINAL v-offshore Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Facility Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review 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 Nitrogen Tank. 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 supplier has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Tank. Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Rig Work Over Sundry ProcedureSubject: Changes to Approved Sundry Procedure for Well: N Cook Inlet Unit A-04A (PTD 221-026)Sundry #: XXX-XXXAny modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC 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 403Required?Y / NHAKPreparedBy(Initials)HAKApprovedBy(Initials)AOGCC WrittenApproval Received(Person and Date)Approval:Asset Team Operations Manager DatePrepared:First Call Operations Engineer Date Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Monty M. Myers Drilling Manager Hilcorp Alaska, Inc. 3800 Centerpoint Drive, Suite 400 Anchorage, AK 99503 Re: North Cook Inlet Field, Tertiary Gas Pool, NCIU A-04A Hilcorp Alaska, LLC Permit to Drill Number: 221-026 Surface Location: 1259' FNL, 1086' FWL, Sec 6, T11N, R9W, SM, AK Bottomhole Location: 26912' FNL, 1981' FEL, Sec 6, T11N, R9W, SM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced 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, Jeremy M. Price Chair DATED this ___ day of June, 2021. Jeremy Price Digitally signed by Jeremy Price Date: 2021.06.18 09:01:42 -08'00' 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2.Operator Name: 5. Bond: Blanket Single Well 11.Well Name and Number: Bond No. 3.Address: 6.Proposed Depth: 12.Field/Pool(s): MD: 6,270' TVD: 5,484' 4a. Location of Well (Governmental Section): 7.Property Designation: Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: Total Depth:9. Acres in Property:14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 132' 15. Distance to Nearest Well Open Surface: x-332108 y-2586718 Zone-4 N/A to Same Pool: 1186' to A-02 16. Deviated wells: Kickoff depth: 2750 feet 17.Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 40 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 6-1/8" 4-1/2" 12.6# L-80 TC II 3,620' 2,650' 2,448' 6,270' 5,484' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): 4,685' TVD 576' / 390' 2,264' 6,391' Hydraulic Fracture planned? Yes No 20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng NCIU A-04A North Cook Inlet Unit Tertiary Gas Pool 7/7/2021 7261' to nearest unit boundary Sean Mclaughlin sean.mclaughlin@hilcorp.com 907-223-6784 Total Depth MD (ft): Total Depth TVD (ft): 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 721 1413' FNL, 2455' FEL, Sec 6, T11N, R9W, SM, AK 912' FNL, 1981' FEL, Sec 6, T11N, R9W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp Alaska, LLC 1259' FNL, 1086' FWL, Sec 6, T11W, R9W, SM, AK ADL17589 5002 18. Casing Program: Top - Setting Depth - BottomSpecifications 1213 Cement Quantity, c.f. or sacks Cement Volume MDSize Plugs (measured): (including stage data) 528 ft3 4,685' 4,083' Conductor/Structural 16" / 30"576' / 390' 7,656'6,421' LengthCasing Multiple Authorized Signature: 2 stage - 517 sx / 735 sxProduction Liner 7,618' Intermediate Authorized Name: Monty Myers Authorized Title: Drilling Manager Commission Use Only See cover letter for other requirements. 4520' - 4690' 3904' - 4048' 7,618'7" 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft): GL / BF Elevation above MSL (ft): Perforation Depth MD (ft): 2,410' 545 sx / Driven 576' / 390' 2,410'10-3/4" 900 sx Effect. Depth MD (ft): Effect. Depth TVD (ft): Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) 5.10.2021 By Meredith Guhl at 8:20 am, May 11, 2021 X DSR-5/11/21 X DLB 05/11/2021 X X Minimum FIT or LOT of 12.0 ppg is required. Notify AOGCC before drilling 6-1/8" hole section if 12.0 ppg LOT is not achieved. BJM 6/16/21 XDLB XSubsequent BOP tests to 2500 psi. Variance to 20 AAC 25.030(e) approved. Test 7" casing to 1500 psi (34% of burst). MPSP is 721 psi. X Initial BOP test to Rated Working Pressure of BOP stack. T11N DLB 221-026 50-883-20023-01-00 dts 6/18/2021 6/18/21 Jeremy Price Digitally signed by Jeremy Price Date: 2021.06.18 09:02:43 -08'00' 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name: 5. Bond: Blanket Single Well 11.Well Name and Number: Bond No. 3. Address: 6.Proposed Depth: 12. Field/Pool(s): MD: 6,270' TVD: 5,484' 4a. Location of Well (Governmental Section): 7.Property Designation: Surface: Top of Productive Horizon: 8.DNR Approval Number: 13.Approximate Spud Date: Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 132' 15.Distance to Nearest Well Open Surface: x-332108 y- 2586718 Zone-4 N/A to Same Pool: 1186' to A-02 16. Deviated wells: Kickoff depth: 2750 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 40 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 6-1/8" 4-1/2" 12.6# L-80 TC II 3,620' 2,650' 2,448' 6,270' 5,484' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): 4,685' TVD 576' / 390' 2,264' 6,391' Hydraulic Fracture planned? Yes No 20.Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number: 50- Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Sr Pet Eng Sr Pet Geo Sr Res Eng 7261' to nearest unit boundary 7/7/2021 Authorized Name: Monty Myers Authorized Title: Drilling Manager Sean Mclaughlin sean.mclaughlin@hilcorp.com 907-223-6784 18. Casing Program: Top - Setting Depth - BottomSpecifications NCIU A-04A North Cook Inlet Unit Tertiary Gas Pool 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp Alaska, LLC 1259' FNL, 1086' FWL, Sec 6, T11W, R9W, SM, AK ADL17589 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 721 1413' FNL, 2455' FEL, Sec 6, T11N, R9W, SM, AK 912' FNL, 1981' FEL, Sec 6, T11N, R9W, SM, AK N/A 5002 1213 Total Depth MD (ft): Total Depth TVD (ft): Cement Quantity, c.f. or sacks Cement Volume MDSize Plugs (measured): (including stage data) 528 ft3 4,685' 4,083' Effect. Depth TVD (ft): Conductor/Structural 16" / 30"576' / 390' 7,656'6,421' Length 545 sx / Driven 576' / 390' 2,410'10-3/4" Production Liner Casing Multiple Intermediate 2,410' 7" Commission Use Only 900 sx Effect. Depth MD (ft): Authorized Signature: 2 stage - 517 sx / 735 sx See cover letter for other requirements. Perforation Depth MD (ft): 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft): GL / BF Elevation above MSL (ft): 4,520' - 4,690' 3,904 - 4,048' 7,618'7,618' Stratigraphic Test No Mud log req'd: Yes No No Directional svy req'd: Yes No Seabed ReportDrilling Fluid Program 20 AAC 25.050 requirements BOP SketchDrilling Program Time v. Depth Plot Shallow Hazard Analysis Single Well Gas Hydrates No Inclination-only svy req'd: Yes No Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal No No Form 10-401 Revised 3/2020 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) 5.7.2021 By Meredith Guhl at 8:13 am, May 10, 2021 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2021.05.07 21:32:32 -08'00' Monty M Myers DSR-5/10/21 SUPERSEDED NCI A-04A Permit to Drill Tyonek Sean McLaughlin Revision 0 April, 29 2021 NCI A-04A Permit to Drill Rev 0 Contents 1. Well Summary ..................................................................................................................................... 2 2. Management of Change Information ................................................................................................ 3 3. Tubular Program ................................................................................................................................ 4 4. Drill Pipe Information ........................................................................................................................ 4 5. Internal Reporting Requirements ..................................................................................................... 5 6. Planned Wellbore Schematic ............................................................................................................. 6 7. Drilling Summary ............................................................................................................................... 7 8. Mandatory Regulatory Compliance / Notifications ......................................................................... 8 9. R/U and Preparatory Work ............................................................................................................. 10 10. BOP N/U and Test ............................................................................................................................. 11 11. Mud Program and Density Selection Criteria ................................................................................ 12 12. Set Whipstock / Mill Window .......................................................................................................... 13 13. Drill 6-1/8” Hole Section ................................................................................................................... 14 14. Run 5” Production Liner.................................................................................................................. 15 15. Cement 5” Production Casing ......................................................................................................... 18 16. Wellbore Clean Up & Displacement ............................................................................................... 21 17. Run Completion Assembly ............................................................................................................... 21 18. RD ....................................................................................................................................................... 21 19. BOP Schematic .................................................................................................................................. 22 20. Wellhead Schematic .......................................................................................................................... 23 21. Days vs Depth .................................................................................................................................... 24 22. Geo-Prog ............................................................................................................................................ 25 23. Anticipated Drilling Hazards ........................................................................................................... 26 24. Rig Layout ......................................................................................................................................... 27 25. FIT Procedure ................................................................................................................................... 29 26. Choke Manifold Schematic .............................................................................................................. 30 27. Casing Design Information .............................................................................................................. 32 28. 8-3/8” Hole Section MASP ....................................................................Error! Bookmark not defined. 29. 6-1/8” Hole Section MASP ............................................................................................................... 33 30. Plot (NAD 27) (Governmental Sections) ......................................................................................... 34 31. Slot Diagram (As Built) (NAD 27) ................................................................................................... 35 32. Directional Program (wp11) ............................................................................................................ 36 Page 2 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 1. Well Summary Well NCI A-04A Pad & Old Well Designation Sidetrack of existing well A-04 (PTD#169-018) Planned Completion Type 4-1/2” 12.6# Liner, 4-1/2” Tubing GL Comp Target Reservoir(s) Beluga A-G Kick off point 2,750’ MD / 2,523’ TVD Planned Well TD, MD / TVD 6,270’ MD / 5,484’ TVD PBTD, MD / TVD 6,180’ MD / 5,420’ TVD Surface Location (Governmental) 1259' FNL, 1086' FWL, Sec 6, T11W, R9W, SM, AK Surface Location (NAD 27) X=332108 Y=2586718 Surface Location (NAD 83) Top of Productive Horizon (Governmental) 1413' FNL, 2455' FEL, Sec 6, T11N, R9W, SM, AK TPH Location (NAD 27) X=333588 Y=2586544 TPH Location (NAD 83) BHL (Governmental) 912' FNL, 1981' FEL, Sec 6, T11N, R9W, SM, AK BHL (NAD 27) X=334067 Y=2587037 BHL (NAD 83) AFE Number 211-00023.xx.xx.xx AFE Days 25 AFE Drilling Amount $5,465 MM Work String 4.5” 16.6# S-135 CDS40 RKB – AMSL 132’ MSL to ML 83’ BOP Equipment 13-5/8” 5M Hydril “GK” Annular BOP 13-5/8” 5M Cameron Type U Double Ram 13-5/8” 5M Cameron Type U Single Ram Page 3 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 2. Management of Change Information Date: April 8, 2021 Subject: Changes to Approved Permit to Drill for NCI A-04A File #: NCI A-04A Drilling Program Any modifications to NCI A-04A Drilling Program will be documented and approved below. Changes to an approved PTD will be communicated and approved by the AOGCC prior to continuing forward with work. Sec Page Date Procedure Change Approved By Approval: Drilling Manager Date Prepared: Engineer Date Page 4 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 3. Tubular Program Hole Section OD (in) Wt (#/ft) Coupl OD ID (in) Drift (in) Grade Conn Top Bottom 6-1/8” 4-1/2” 12.6 4.93” 3.958” 3.833 L-80 TCII 2,700’ 6,270’ **Condition B pipe from 2018 4. Drill Pipe Information Hole Section OD (in) ID (in) TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) 6-1/8” 4-1/2” 3.826 2.6875” 5.25” 16.6 S-135 CDS40 16,176 10,959 468k Page 5 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 5. Internal Reporting Requirements 1. Fill out daily drilling report and cost report on Wellez. x Report covers operations from 6am to 6am x 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. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. 2. Afternoon Updates x Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp.com, cdinger@hilcorp.com, sean.mclaughlin@hilcorp.com 3. EHS Incident Reporting x Notify EHS field coordinator. i. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don’t wait until an emergency to have to call around and figure it out!!!! ii. Leonard Dickerson: O: (907) 777-8317 C: (907) 252-7855 iii. Mark Tornai: O: (907) 283-1372 C: (907) 748-3299 iv. Thad Eby: O: (907) 777-8317 C: (907) 602-5178 x Spills: i. Keegan Fleming: C:907-350-9439 ii. Monty Myers: O: 907-777-8431 C: 907-538-1168 iii. Sean Mclaughlin x Submit Hilcorp Incident report to contacts above within 24 hrs 4. Casing Tally x Send final “As-Run” Casing tally to sean.mclaughlin@hilcorp.com and cdinger@hilcorp.com 5. Casing and Cmt report x Send casing and cement report for each string of casing to sean.mclaughlin@hilcorp.com and cdinger@hilcorp.com Page 6 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 6. Planned Wellbore Schematic Page 7 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 7. Drilling Summary A-04 is a non-producing gas production well planned to be sidetracked to the east towards A-02 BHL. The previous completion will be pulled and the wellbore abandoned to 4,390’ (separate sundry). At 2,750’ MD the parent wellbore will be sidetracked and new wellbore drilled to 6,270’. A 4-1/2” 12.6# L-80 TCII prod liner will be run, cemented, and perforated based on data obtained while drilling the interval. The well will be completed with a 4-1/2” gas lift completion. Drilling operations are expected to commence approximately July 7th, 2021. 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. Spartan 151 will MIRU over A-04 2. NU BOPE and test to 2500 psi. (MASP 721 psi) 3. Recover tubing hanger and kill string (2 joints) 4. RIH with whipstock and swap well to 9.5 ppg LSND mud 5. Set whipstock at 2750’ and 150L. Mill window with 20’ of new formation. 6. Perform LOT to 10.5 ppg EMW 7. PU 6-1/8” motor drilling assembly and TIH to window. 8. Drill 6-1/8” production hole to 6,270’ MD, performing short trips as needed 9. POOH w/ directional tools. RIH w/ 4-1/2” liner. Set liner and cement. Circ wellbore clean. 10. PU liner cleanout assembly and TIH to landing collar. 11. Circ liner clean. POOH laying down DP. 12. Run 4-1/2” completion. (Covered under separate sundry) 13. Land hanger and test. 14. ND BOPE, NU tree and test void Perform LOT or FIT to 12.0 ppg minimum. bjm Page 8 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 8. 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. x BOPs shall be tested at (2) week intervals during the drilling of A-04A. Ensure to provide AOGCC 48 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/2500 psi & subsequent tests of the BOP equipment will be to 250/2500 psi for 5/5 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. o The highest reservoir pressure expected is 1213 psi in the Beluga E sand (4919' TVDss). MASP is 721psi with 0.1psi/ft gas in the wellbore. x If the BOP is used to shut in on the well in a well control situation, we must test ALL BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system” x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements” x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. Variance Requests: o Hilcorp would like to request a variance to regulation 20 AAC 25.030(e) which states - “The casing must be tested to hold a minimum surface pressure equal to 50 percent of the casing internal yield pressure.”. The MASP will drilling A-04A is expected to be 721 psi. A casing test of 1500 psi is requested. pq p g The MASP will drilling A-04A is expected to be 721 psi. A casing test yp of 1500 psi is requested. Variance Requests: q)fp pf The highest reservoir pressure expected is 1213 psi in the Beluga E sand (4919' TVDss). M The 7" 23# J-55 Burst pressure = 4360 psi. 1500 psi is 34% of burst. Variance approved. - bjm Hilcorp would like to request a variance to regulation 20 AAC 25.030(e) w Initial BOP test to rated working pressure of BOP stack - bjm Page 9 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 6-1/8” x 13-5/8” Shaffer 5M annular x 13-5/8” 5M Shaffer SL Double gate x Blind ram in bottom cavity x Mud cross x 13-5/8” 5M Shaffer SL single gate x 3-1/16” 5M Choke Manifold x Standpipe, floor valves, etc Initial Test: 250/2500 (Annular 2500 psi) Subsequent Tests: 250/2500 (Annular 2500 psi) x Primary closing unit: Masco 7 station, 15 bottle, 3000 psi closing unit with two air pumps, a triplex electric driven pump Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 48 hours notice prior to spud. x 48 hours notice prior to testing BOPs. x 48 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Additional requirements may be stipulated on APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / (C): 907-250-9193 / Email: bryan.mclellan@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / Email: melvin.rixse@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Initial test to Rated Working Pressure-bjm Page 10 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 9. R/U and Preparatory Work 1. Separate sundries will be submitted that will include the following: x Pull tubing x P&A lower perfs with a cement plug x Running Completion 2. Mix WBM mud for 6-1/8” hole section. 3. Verify 5.5” liners installed in mud pump #1 and pump #2. (PZ-10’s) x Gardner Denver PZ-10’s Pumps are rated at 5000 psi (100%) with 5.5” liners and can deliver 355 gpm at 115 spm. x Ideal pump rate for drilling will be 280 gpm. This can be achieved with one or both pumps. Page 11 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 10. BOP N/U and Test 1. N/U 13-5/8” x 5M BOP as follows (top down): x 13-5/8” x 5M Shaffer annular BOP. x 13-5/8” Shaffer Type “SL” Double ram. (2-7/8” X 5” VBR in top cavity, blind ram in btm cavity) x 13-5/8” mud cross x 13-5/8” Shaffer Type “SL” single ram. (2-7/8” X 5” VBR) x N/U pitcher nipple, install flowline. x Install (2) manual valves on kill side of mud cross. Manual valve used as inside or “master valve”. x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 2. Run TWC (if not installed previously). x Test BOP to 250/2500 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. x Ensure to leave “A” section side outlet valves open during BOP testing so pressure does not build up beneath the TWC. Confirm the correct valves are opened!!! x Test VBRs on 4.5” test joint. x Ensure gas monitors are calibrated and tested in conjunction w/ BOPE. 3. Pull TWC 4. Continue mixing mud for 6-1/8” hole section. 5. Set wearbushing in wellhead. Ensure ID of wearbushing > 6-1/8”. Initial BOP test to Rated Working Pressure of the stack. - bjm Page 12 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 11. Mud Program and Density Selection Criteria 1. 6-1/8” Production hole mud program summary: x Primary weighting material to be used for the hole section will be barite to minimize solids. Ensure enough barite is on location to weight up the active system 1ppg above highest anticipated MW in the event of a well control situation. x 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, and Toolpusher office. System Type: 9.5-10 ppg LNSD WBM Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 2,750’- TD 9.5 – 10.0 40-53 6-15 13-24 8.5-9.5 11.0 System Formulation: 2% KCL/BDF-976/GEM GP Product Concentration Water KCl Caustic BARAZAN D+ DEXTRID LT PAC L BDF-976 GEM GP BARACARB 5/25/50 STEELSEAL 50/100/400 BAROFIBRE BAROTROL PLUS SOLTEX BAROID 41 ALDACIDE-G 0.905 bbl 7 ppb 0.2 ppb (9 pH) 1.0 ppb (as required 18 YP) 1-2 ppb 1 ppb 4 ppb 1.0% by volume 5 ppb (1.7 ppb of each) 5 ppb (1.7 ppb of each) 1.7 ppb 4.0 ppb 2 – 4 ppb as needed for 9.5 – 10.0 ppg 0.1 ppb 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. 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. 9.5 – 10.0 g MWE needed = 4.7 ppg in Beluga E DLB Page 13 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 12. Set Whipstock / Mill Window x BOP Test interval for this section is 14 days - To comply with state regulations, record mud weights in and out and ensure BOPE function test are recorded in WellEZ before the 7 day deadline. x Kick tolerance: Perform a LOT after drilling 20’ of new formation x A 10.0 EMW will provide an infinite kick tolerance with the planned 9.5 ppg mud weight in the hole. x Contact Drilling Engineer if 10.0 ppg is not achieved Operation Steps: 1. Make up the Baker 7” WindowMaster Hydraulic Whipstock G2 assembly with window mill, two string mills and flex joint. 2. TIH with DP to the whipstock setting depth. Exercise caution when RIH / setting slips with whipstock assembly ¾ Fill the drill pipe a minimum of every 20 stands on the trip in the hole with the whipstock assembly. ¾ Avoid sudden starts and stops while running the whipstock. ¾ Recommend running in the hole at a maximum of 90-120 seconds per stand taking care not to spud or catch the slips. Ensure running string is stationary prior to insertion of the slips and that slips are removed slowly when releasing the work string to RIH. These precautions are required to avoid any weakening of the whipstock shear mechanisms and / or to avoid part / preset on the packer. 3. Orient whipstock as directed by the directional driller. The directional plan currently has the top of whipstock at 150 deg LOHS. 4. Set the top of the whipstock at ~2,750’ MD 5. Mill window plus 30-50’ of new (DO NOT EXCEED 50’ OF NEW HOLE BEFORE RUNNING THE PLANNED FIT/LOT). ¾ Use ditch magnets to collect the metal shavings. Clean regularly. ¾ Ensure any personnel working around metal shavings wear proper PPE, including goggles, face shield and Kevlar gloves. ¾ Work the upper mill through the window to confirm the window milling is complete and circulate well clean (circulate a minimum of 1-1/2 bottoms up). Pump a high-vis super sweep to remove metal shavings and make every effort to remove all of the super sweep pill from the mud system as it is circulated to surface. 6. Pull starter mill into casing above top of whipstock, flow check the well for 10 minutes and conduct a LOT to 12.0 ppg for ECD management, but a minimum of 10.0 ppg is needed for kick tolerance. ¾ **Assuming the kick zone is at TD, a LOT of 10.0 ppg EMW gives an infinite Kick Tolerance with 9.5 ppg mud weight. Send LOT chart to Drilling Engineer immediately upon test conclusion. Kick tolerance is not infinite. Conduct a LOT or FIT to at least 12.0 ppg. Contact AOGCC before drilling 6-1/8" hole if less than 12.0 ppg EMW is achieved - bjm Contact AOGCC if 12.0 ppg EMW LOT is not achieved. Kick tolerance is not infinite. Page 14 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 7. POOH and LD milling assembly ¾ Once out of the hole, inspect mill gauge and record. ¾ Flow check well for 10 minutes to confirm no flow: ¾ Before pulling off bottom. ¾ Before pulling the BHA through the BOPE. 8. Flush the stack/lines to remove metal debris that may have settled out in these areas. Ensure BOP equipment is operable. 13. Drill 6-1/8” Hole Section 1. PU 6300’ of 4-1/2” CDS40 Drill pipe for drilling 6-1/8” hole section 2. P/U 6-1/8” Sperry Sun motor drilling assy w/ triple combo 3. Ensure BHA Components have been inspected previously. 4. Drift & caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 5. Ensure TF offset is measured accurately and entered correctly into the MWD software. 6. Have DD run hydraulics models to ensure optimum TFA. We want to pump at 250 - 450 gpm. 7. Production section will be drilled with a motor. Must keep up with 4 deg/100 DLS in the drop section of the wellbore. 8. Primary bit will be the Baker Hughes Kymera 6-1/8” HP414. Ensure to have a back up PDC bit available on location. 9. TIH to window. Shallow test MWD on trip in. 10. TIH through window ensure Baker Hughes MWD service rep on rig floor during this operation. 11. Circulate well with 9.5 ppg LNSD to warm up mud until good 9.5 ppg in and 9.5 ppg out. 12. Drill approx. 20’ rat hole to accommodate the drilling assembly. Ream shoe as needed to assure there is little or no drag. After reaming, shut off pumps and rotary (if hole conditions allow) and pass through shoe checking for drag. 13. Circulate Bottoms Up until MW in = MW out. Page 15 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 14. Drill 6-1/8” hole to 6,270’ MD using motor assembly. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. x Keep swab and surge pressures low when tripping. x See attached mud program for hole cleaning and LCM strategies. x Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. x Adjust MW as necessary to maintain hole stability. x Ensure mud engineer set up to perform HTHP fluid loss. x Maintain API fluid loss < 6. x Take MWD surveys every stand drilled. x Minimize backreaming when working tight hole 15. 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. 16. TOH with drilling assembly, handle BHA as appropriate. 14. Run 4-1/2” Production Liner 1. R/U Baker 4-1/2” liner running equipment. x Ensure 4-1/2” CDS-40 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill liner while running. x Ensure all liner has been drifted and tally verified prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 2. P/U shoe joint, visually verify no debris inside joint. 3. Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). x (1) Baker locked joint. x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x (1) Joint with landing collar bucked up. x No centralizers will be run on 4-1/2” liner Centralizers will be run on the liner. Page 16 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 x Ensure proper operation of float shoe & FC. Page 17 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 4. Continue running 4-1/2” production liner to TD x Fill liner while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Utilize a collar clamp until weight is sufficient to keep slips set properly. 5. Ensure to run enough liner to provide at least 100’ overlap inside 7” casing. Ensure hanger/pkr will not be set in a 7” connection. 6. 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. 7. 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. 8. RIH one stand and circulate a minimum of one liner volume. Note weight of liner. 9. 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. 10. M/U top drive and fill pipe while lowering string every 10 stands. 11. Set slowly in and pull slowly out of slips. 12. Circulate 1-1/2 drill pipe and liner volume at 7” shoe 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. 13. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 14. Continue to fill the string every 10 joints while running liner in open hole. Do not stop to fill casing. 15. P/U the cmt stand and tag bottom with the liner shoe. P/U 2’ off bottom. Note slack-off and pick-up weights. Record rotating torque values at 10, 20, & 30 rpm. 16. 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. 17. Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Ensure to run enough liner to provide at least 100’ overlap inside 7” casing. Page 18 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 15. Cement 4-1/2” Production Liner 1. Hold a pre-job safety meeting over the upcoming cmt operations. 2. Attempt to reciprocate the casing during cmt operations until hole gets sticky. 3. Pump 15 bbls 12.5 ppg spacer. 4. Test surface cmt lines to 4500 psi. 5. Pump remaining 10 bbls 12.5 ppg spacer. 6. Mix and pump 94 bbls of 15.3 ppg class “G” cmt per below recipe with 0.5 lbs/bbl of loss circulation fiber. Ensure cmt is pumped at designed weight. Job is designed to pump 50% OH excess but if fluid caliper dictates otherwise we may increase excess volumes. Cement volume is designed to bring cement to 2600’ TMD (TOL). 7. Displacement fluid will be drilling mud. ~37 bbls of displacement fluid in drill pipe and 56 bbls in liner. (4-1/2 DP (.0142*2600 =37), (4-1/2” Liner (.0152 * 3670 = 56)), Total 93 bbls Cement Calculations 6-1/8” OH x 4.5” Liner: (6270’ – 2600’) x 0.01677 x 1.5 = 92.3 bbls Shoe Track: 90’ x 0.0152 = 1.4 bbls Total Volume (bbls): 92.3 + 1.4 = 94 bbls Total Volume (ft3): 94 bbls x 5.615 ft3/bbl = 528 ft3 Total Volume (sx): 583 ft3 / 1.34 ft3/sk = 394 sx Verified cement calc. bjm Verified displacement vol. bjm Page 19 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 Slurry Information: System ExpandaCEM Density 15.3 lb/gal Yield 1.34 ft3/sk Mixed Water 5.879 gal/sk Mixed Fluid 5.879 gal/sk Expected Thickening 70 Bc at 05:00 hr:mn API Fluid Loss <25 mL in 30.0 min at 155degF / 1000 psi Additives Code Description Concentration G D046 D202 D400 D154 Cement Anti Foam Dispersant Gas Control Agent Extender 94 lb/sk 0.2% BWOC 1.5% BWOC 0.8% BWOC 8.0% BWOC 8. Drop DP dart and displace with 9.5 ppg WBM. 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 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. 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. 12. Slack off total liner weight plus 30k to confirm hanger is set. 13. Do not overdisplace by more than 1 bbls. Shoe track volume is 1.4 bbls. 14. Pressure up to 4200 psi to release the running tool (HRD-E) from the liner 15. Bleed pressure to zero to check float equipment. Page 20 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 16. P/U, verify setting tool is released, and expose setting dogs on top of tieback sleeve 17. Rotate slowly and slack off 50k downhole to set ZXPN. 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). 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. 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. 21. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 22. POOH, LDDP. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. Backup release from liner hanger: 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. 24. NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down to the setting tool. 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. Ensure to report the following on Wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid Page 21 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 x Note if liner is reciprocated or rotated during the job x Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Note: Send Csg & cmt report + “As-Run” liner tally to sean.mclaughlin@hilcorp.com 16. Wellbore Clean Up & Displacement x No cleanout planned. Service coil will cleanout, displace mud, and blow down well with N2 prior to perforating. 17. Run Completion Assembly 1. Run 4-1/2” tubing completion assembly as per separate Approved Completion Sundry 18. RD x Install BPV in wellhead. RILDs. x ND BOPE, NU tree, test void x Rig Down Steps below this point will be part of a separate Sundry. Note: Liner lap will need to be tested to 1500 psi as part of completion Sundry. - bjm Page 22 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 19. BOP Schematic Page 23 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 20. Wellhead Schematic (proposed) Unihead, OCT type 3, 16 3/4 5M BX-161 hub top X 16'’ LTC casing bottom, w/ 2- 2 LPO on lower section, 2- 2 1/16 5M SSO on middle section, 2- 2 1/16 5M SSO on upper section , IP internal lockpin assy 28'’ Starting head, OCT, 30 ½ 1M X 28'’ BW, w/ 2- 4'’ 1M EFO Tubing hanger, Cactus-EN- CCL, 11 x 4 ½ EUE 8rd lift and susp, w/ 4'’ type H BPV, 2- ¼ cont control line ports Tyonek Platform A-04 28 X 16 X 10 3/4 X 7 x 4 1/2 16'’ 10 ¾’’ 7'’ 4 ½’’ Tubing head attachment, Cactus, 11 5M FE X 16 3/4 5M BX-161 hub bottom Valve, Master, CIW-FLS, 4 1/16 5M FE, HWO, EE trim BHTA, Otis, 4 1/16 5M FE x 7.5 Otis quick union top Adapter, Cactus-EN-CCL, 11 5M stdd x 4 1/16 5M, w/ 2- 1'’ npt control line exits Valve, Master, CIW-FLS, 4 1/16 5M FE, HWO, EE trim Valve, Swab, CIW-FLS, 4 1/16 5M FE, HWO, EE trim Page 24 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 21. Days vs Depth 0 1000 2000 3000 4000 5000 6000 7000 1 2 3 4 5 6 7 8 9 10111213141516171819202122232425 Measured Depth (ft)Days Days vs Depth Page 25 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 22. Geo-Prog 4/30/2021 10:05 Well Name:NCI A-04 Survey Type RKB Field Name:North Cook Inlet Surface Hole:116 Pool Name:Tertiary Gas System Pool Bottom Hole:Spartan 151 State:Alaska 116 Field Location:Offshore Coord Ref Sys:NAD27 ASO Z4 101 County/Parish:Kenai Peninsula Borough Objective: Reference Plan: Top Sterling X Top Sterling X Depleted gas Top Sterling A Top Sterling A Water 1200 psi 0.44 psi/ft Top Sterling B Sterling B Water 1200 psi 0.44 psi/ft Base Sterling B Top CI 1 Sterling 1 Depleted gas 4,175 3,791.0 -3675 200-300 psi Base CI 1 Top CI 2 Sterling 2 Depleted gas 200-300 psi Base CI 2 Top Beluga B 5,142 4,611.0 -4495 2,586,562.32 333,510.18 1000 psi Base Beluga H 6,430 5,369.0 -5253 2,587,259.00 334,282 1200 psi = Reservoir Objectives = Possible Geo Hazards TARGET RADIUS Mud Logging: LWD Data: Frac Half-Length None SH Max Direction DATA COLLECTION REQUIREMENTS: Triple-combo. NCI A-04 is a shut-in gas well on the Tyonek platform. We have exhausted the up-hole abilities in this well and propose Fault Constraints 500 FT None NCI A-04A wp05ANTICIPATED FORMATION TOPS & GEOHAZARDS Geo Summary/ Justification: The Beluga formation consists of channelized sands and will require more well density to fully develop and effectively produce. This well will help do that. We will penetrate all Beluga zones (A through U). TOP NAME LITHOLOGY EXPECTED FLUID MD (FT) TVD (FT) TVDSS (FT)NORTHING EASTING Est. Pressure Gradient Water Depth: GEOLOGICAL PROGNOSIS As-Built x = 332,107.20 y = 2,586,720.40 TVD Ref Datum: TVD Ref Elevation: Planned Rig: Rig Height: x = 334,780.10 y = 2,584,000.60 8,500' MD 6,912' TVD Page 26 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 23. Anticipated Drilling Hazards Lost Circulation: Ensure 500 lbs of medium/coarse fibrous material, 500 lbs SteelSeal (Angular, dual-composition carbon-based material), & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ viscofier as necessary. Sweep hole w/ 20 bbls flowzan as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain programmed mud specs. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams. x Increase fluid density as required to control running coals. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. x Minimize swab and surge pressures x Minimize back reaming through coals when possible H2S: H2S is not present in this hole section. No abnormal temperatures or pressures are present in this hole section. Page 27 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 24. Rig Layout Jack up off leg 1 Skid Rig package across to leg 2, rotate and skid to leg 3 Page 28 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 Page 29 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 25. FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 30 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 26. Choke Manifold Schematic Page 31 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 Page 32 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 27. Casing Design Information Page 33 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 28. 6-1/8” Hole Section MASP Page 34 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 29. Plot (NAD 27) (Governmental Sections) Page 35 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 30. Slot Diagram Page 36 Revision 0 April, 2021 NCI A-04A Permit to Drill Rev 0 31. Directional Program (wp05) - Attached separately 6WDQGDUG3URSRVDO5HSRUW 0D\ 3ODQ1&,$$:3 +LOFRUS$ODVND//& 1RUWK&RRN,QOHW 1RUWK&RRN,QOHW8QLW 1&,8$ 3ODQ1&,$$ 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 5400 5700 6000 6300True Vertical Depth (600 usft/in)0 300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 Vertical Section at 79.91° (600 usft/in) A-04A wp03 Beluga B A-04A wp03 Beluga H 2 5 0 0 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 6 0 0 0 6 5 0 0 7 0 0 0 7 5 0 0 7 6 5 6 A-04 7' TOW 4 1/2" x 6 1/8" 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 6 0 0 0 6 2 7 0 NCI A-04A WP05 KOP : Start Dir 12º/100' : 2750' MD, 2522.86'TVD : 150° LT TF End Dir : 2767' MD, 2535.95' TVD Start Dir 4º/100' : 2787' MD, 2551.55'TVD End Dir : 3943.05' MD, 3572.82' TVD Start Dir 4º/100' : 4808.07' MD, 4342.51'TVD End Dir : 5130.98' MD, 4611' TVD Total Depth : 6270.48' MD, 5483.91' TVD Top CI 1 Top Beluga B Base Beluga H Hilcorp Alaska, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: NCIU A-04 Water Depth: 101.00 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2586718.580 332108.090 61° 4' 36.282 N 150° 56' 53.321 W SURVEY PROGRAM Date: 2021-05-06T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 447.00 2750.00 N COOK INLET UNIT A-04 (NCI A-04) 3_CB-Film-GSS 2750.00 3000.00 NCI A-04A WP05 (Plan: NCI A-04A)BMWD_Interp Azi+Sag 3000.00 6270.48 NCI A-04A WP05 (Plan: NCI A-04A) 3_MWD+IFR1+MS+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 3791.00 3675.00 4188.25 Top CI 1 4611.00 4495.00 5130.98 Top Beluga B 5369.00 5253.00 6120.48 Base Beluga H REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well NCIU A-04, True North Vertical (TVD) Reference:NCI A-04 @ 116.00usft Measured Depth Reference:NCI A-04 @ 116.00usft Calculation Method:Minimum Curvature Project:North Cook Inlet Site:North Cook Inlet Unit Well:NCIU A-04 Wellbore:Plan: NCI A-04A Design:NCI A-04A WP05 CASING DETAILS TVD TVDSS MD Size Name 2523.62 2407.62 2751.00 7 7' TOW 5483.91 5367.91 6270.48 4-1/4 4 1/2" x 6 1/8" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 2750.00 40.49 133.00 2522.86 -558.00 586.57 0.00 0.00 479.76 KOP : Start Dir 12º/100' : 2750' MD, 2522.86'TVD : 150° LT TF 2 2767.00 38.73 131.37 2535.95 -565.28 594.60 12.00 -150.00 486.38 End Dir : 2767' MD, 2535.95' TVD 3 2787.00 38.73 131.37 2551.55 -573.55 603.99 0.00 0.00 494.18 Start Dir 4º/100' : 2787' MD, 2551.55'TVD 4 3943.05 27.15 40.87 3572.82 -615.41 1073.80 4.00 -140.82 949.40 End Dir : 3943.05' MD, 3572.82' TVD 5 4808.07 27.15 40.87 4342.51 -316.90 1332.12 0.00 0.00 1256.01 Start Dir 4º/100' : 4808.07' MD, 4342.51'TVD 6 5130.98 40.00 43.32 4611.00 -185.12 1452.04 4.00 7.06 1397.16 A-04A wp03 Beluga B End Dir : 5130.98' MD, 4611' TVD 7 6120.48 40.00 43.32 5369.00 277.62 1888.41 0.00 0.00 1907.84 A-04A wp03 Beluga H 8 6270.48 40.00 43.32 5483.91 347.76 1954.56 0.00 0.00 1985.26 Total Depth : 6270.48' MD, 5483.91' TVD -1000-833-667-500-333-1670167333500667South(-)/North(+) (250 usft/in)667 833 1000 1167 1333 1500 1667 1833 2000 2167 2333 2500 2667 2833West(-)/East(+) (250 usft/in)A-04A wp03 Beluga HA-04A wp03 Beluga BA-04275030003 2 5 0350037504000425045004750500052505484NCI A-04A WP05KOP : Start Dir 12º/100' : 2750' MD, 2522.86'TVD : 150° LT TFEnd Dir : 2767' MD, 2535.95' TVDStart Dir 4º/100' : 2787' MD, 2551.55'TVDEnd Dir : 3943.05' MD, 3572.82' TVDStart Dir 4º/100' : 4808.07' MD, 4342.51'TVDEnd Dir : 5130.98' MD, 4611' TVDTotal Depth : 6270.48' MD, 5483.91' TVDProject: North Cook InletSite: North Cook Inlet UnitWell: NCIU A-04Wellbore: Plan: NCI A-04APlan: NCI A-04A WP05WELL DETAILS: NCIU A-04Water Depth: 101.00+N/-S +E/-W Northing Easting Latittude Longitude0.000.002586718.580 332108.09061° 4' 36.282 N150° 56' 53.321 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well NCIU A-04, True NorthVertical (TVD) Reference: NCI A-04 @ 116.00usftMeasured Depth Reference:NCI A-04 @ 116.00usftCalculation Method:Minimum CurvatureCASING DETAILSTVD TVDSS MD Size Name2523.62 2407.62 2751.00 7 7' TOW5483.91 5367.91 6270.48 4-1/4 4 1/2" x 6 1/8" 3URMHFW &RPSDQ\ /RFDO&RRUGLQDWH5HIHUHQFH 79'5HIHUHQFH 6LWH +LOFRUS$ODVND//& 1RUWK&RRN,QOHW 1RUWK&RRN,QOHW8QLW 6WDQGDUG3URSRVDO5HSRUW :HOO :HOOERUH 1&,8$ 3ODQ1&,$$ 6XUYH\&DOFXODWLRQ0HWKRG0LQLPXP&XUYDWXUH 1&,$#XVIW 'HVLJQ1&,$$:3 'DWDEDVH1257+86&$1$'$ 0'5HIHUHQFH1&,$#XVIW 1RUWK5HIHUHQFH :HOO1&,8$ 7UXH 0DS6\VWHP *HR'DWXP 3URMHFW 0DS=RQH 6\VWHP'DWXP866WDWH3ODQH([DFWVROXWLRQ 1$'1$'&21&2186 1RUWK&RRN,QOHW $ODVND=RQH 0//: 8VLQJ:HOO5HIHUHQFH3RLQW 8VLQJJHRGHWLFVFDOHIDFWRU 6LWH3RVLWLRQ )URP 6LWH /DWLWXGH /RQJLWXGH 3RVLWLRQ8QFHUWDLQW\ 1RUWKLQJ (DVWLQJ *ULG&RQYHUJHQFH 1RUWK&RRN,QOHW8QLW XVIW 0DS XVIW XVIW 6ORW5DGLXV 1 : :HOO :HOO3RVLWLRQ /RQJLWXGH /DWLWXGH (DVWLQJ 1RUWKLQJ XVIW (: 16 3RVLWLRQ8QFHUWDLQW\ XVIW XVIW XVIW:DWHU'HSWK 1&,8$ XVIW XVIW 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'LVWDQFH%HWZHHQ3URILOHV'LVWDQFH%HWZHHQ3URILOHV(OOLSVH6HSDUDWLRQ'LVWDQFH%HWZHHQFHQWUHVLVWKHVWUDLJKWOLQHGLVWDQFHEHWZHHQZHOOERUHFHQWUHV$OOVWDWLRQFRRUGLQDWHVZHUHFDOFXODWHGXVLQJWKH0LQLPXP&XUYDWXUHPHWKRG0D\ &203$663DJHRI 0.001.002.003.004.00Separation Factor2925 3150 3375 3600 3825 4050 4275 4500 4725 4950 5175 5400 5625 5850 6075 6300 6525 6750 6975Measured Depth (450 usft/in)A-04NCIU A-15No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:NCIU A-04 NAD 1927 (NADCON CONUS)Alaska Zone 04Water Depth: 101.00+N/-S +E/-W Northing Easting Latittude Longitude0.000.002586718.580332108.09061° 4' 36.282 N150° 56' 53.321 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well NCIU A-04, True NorthVertical (TVD) Reference:NCI A-04 @ 116.00usftMeasured Depth Reference:NCI A-04 @ 116.00usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2021-05-06T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool447.00 2750.00 N COOK INLET UNIT A-04 (NCI A-04) 3_CB-Film-GSS2750.00 3000.00 NCI A-04A WP05 (Plan: NCI A-04A) 3_MWD_Interp Azi+Sag3000.00 6270.48 NCI A-04A WP05 (Plan: NCI A-04A) 3_MWD+IFR1+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)2925 3150 3375 3600 3825 4050 4275 4500 4725 4950 5175 5400 5625 5850 6075 6300 6525 6750 6975Measured Depth (450 usft/in)NO GLOBAL FILTER: Using user defined selection & filtering criteria2750.00 To 6270.48Project: North Cook InletSite: North Cook Inlet UnitWell: NCIU A-04Wellbore: Plan: NCI A-04APlan: NCI A-04A WP05CASING DETAILSTVD TVDSS MD Size Name2523.62 2407.62 2751.00 7 7' TOW5483.91 5367.91 6270.48 4-1/4 4 1/2" x 6 1/8" 1 Carlisle, Samantha J (CED) From:Sean Mclaughlin <Sean.Mclaughlin@hilcorp.com> Sent:Tuesday, June 8, 2021 4:17 PM To:McLellan, Bryan J (CED) Subject:RE: [EXTERNAL] NCIU A-04 cementing question Thatisatypo.Centralizerswillberunonthecementedliner. Sean From:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov> Sent:Tuesday,June8,20214:06PM To:SeanMclaughlin<Sean.Mclaughlin@hilcorp.com> Subject:[EXTERNAL]NCIUAͲ04cementingquestion Sean, LookingovertheAͲ04PTDapplication. Onlyonequestion.Whyareyounotplanningtorunanycentralizersonyour4Ͳ1/2”productionlinerforthecement job? Thanks BryanMcLellan SeniorPetroleumEngineer AlaskaOil&GasConservationCommission Bryan.mclellan@alaska.gov +1(907)250Ͳ9193 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. 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Revised 2/2015 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: ____________________________ POOL: ______________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit No. _____________, API No. 50-_______________________. Production should continue to be reported as a function of the original API number stated above. Pilot Hole In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name (_______________________PH) and API number (50-_____________________) from records, data and logs acquired for well (name on permit). Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation order approving a spacing exception. (_____________________________) as Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for well ( ) until after ( ) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (________________________) must contact the AOGCC to obtain advance approval of such water well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (_______________________________) in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. 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