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Home My WebLink About221-0511. 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:Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 6,630 N/A Casing Collapse Structural Conductor Surface 630psi Intermediate 2,090psi Production 4,320psi Liner 7,500psi 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 AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Eric Dickerman Contact Email:Eric.Dickerman@hilcorp.com Contact Phone:(907) 564-4061 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 2/6/2026 6,630'3,622' 4-1/2" 5,382' HRD-E-HD ZXP & WRDP 3,022 (MD) 2,739 (TVD) & 418 (MD) 418 (TVD) 3,209' Perforation Depth MD (ft): 2,519' 5,480 - 6,404 3,209' 4-1/2" 4,434 - 5,176 2,918'7" 30" 16" 384' 10-3/4"2,519' 612' MD 3,580psi 1,640psi 384' 612' 2,331' 384' 612' Length Size Proposed Pools: L-80 TVD Burst 3,030 4,980psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 / ADL0037831 221-051 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20020-01-00 Hilcorp Alaska, LLC N Cook Inlet Unit A-03A AOGCC USE ONLY 8,430psi Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Operations Manager Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Other: CTCO, N2 N/A North Cook Inlet Tertiary System Gas Same 5,382 6,435 5,204 575psi 6,435 No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2026.01.23 12:15:12 - 09'00' Dan Marlowe (1267) 326-046 By Grace Christianson at 1:34 pm, Jan 23, 2026 TS 1/26/26 DSR-1/27/26 X 10-404 BJM 2/6/26 BOP test to 3000 psi TWM 2/6/2026 02/06/26 Fill Clean Out Well: North Cook Inlet Unit A-03A Well Name:NCIU A-03A API Number:50-883-20020-01 Current Status:Online, Gas Well Leg:Leg #3 (SE corner) Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:221-051 First Call Engineer:Eric Dickerman (907) 564-4061 Second Call Engineer:Dan Marlowe (907) 283-1329 Maximum Expected BHP:1,093 psi at 5,176 TVD 0.22 psi/ft Calculated from SITP on 11/3/2021 Max. Potential Surface Pressure: 575 psi MPSP -0.1 psi/ft gas grad. to surface Field/Pool: North Cook Inlet Unit, Tertiary System Gas Pool Brief Well Summary: NCIU A-03A was completed in November 2021 in the Beluga Formation. The deeper intervals tested wet and were plugged. A flowing pressure and temperature survey from April 2024 tagged at 6,410 (uncorrected) and logged a fluid level at 6,355, which puts the bottom two perf intervals below fluid. A cleanout and N2 blowdown is proposed because the tag depth was right at the bottom perf interval in 2024 and is assumed to have moved shallower in the well since then. Additionally, lifting fluid off the lower perforations will provide them the best opportunity to contribute. Objective: Coiled tubing fill cleanout, N2 blowdown. Wellbore information: Well is completed with a wireline retrievable subsurface safety valve. North Cook Inlet Unit, Tertiary System Gas Pool top = Top of Sterling sands, at 3,576 md / 3,215 tvd. North Cook Inlet Unit, Tertiary System Gas Pool Bottom = Base of Beluga sands (below TD). Fill Clean Out Well: North Cook Inlet Unit A-03A Slickline: 1. MIRU Slickline. PT PCE 250 psi low / 2,500 psi high. 2. Pull SSSV from 418. 3. Drift and tag TD. Bail fill as directed. 4. RDMO. Coiled Tubing Cleanout: 5. MIRU Fox Offshore Coiled Tubing Unit #9 and pressure control equipment. 6. Pressure test BOP and PCE to 250 psi low / 3,000 psi high. a. Provide AOGCC with 48hr witness notification for BOP test. 7. MU cleanout BHA. Dry tag top of fill, then clean out to ± 6,435. b. Working fluid will be 6% KCl (8.6 ppg). c. Take returns to surface from the coiled tubing backside. d. Add foam and nitrogen as necessary to carry solids to surface. 8. RDMO CTU. Slickline: 9. MIRU Slickline. PT PCE 250 psi low / 2,500 psi high. 10. Drift and tag TD. 11. Perform Pressure/Temperature survey. 12. Set SSSV at 418. 13. RDMO. Operations: 14. Test SSSV within 5 days of production. a. Provide AOGCC with 48hr witness notification. Attachments: 1. Current Wellbore Schematic (no change proposed) 2. CT BOP Drawing 3. Nitrogen procedure ____________________________________________________________________________________ Updated by: JLL 02/21/2023 SCHEMATIC Tyonek Platform Well:NCI A-03A Last Completed: 09/17/21 PTD:221-051 API:50-883-20020-01-00 OPEN HOLE / CEMENT DETAIL 16"22 Hole: Pumped 610sxs 11.5ppg class G lead followed by 125sxs 14.4ppg class G tail cement. Cement returns to surface. 10-3/4"15 hole: Pumped 1120sxs (400bbls) 11.5ppg class G lead cement followed by 125sxs (24bbls) 15.5ppg tail cement. Good cement returns notes. Volumetrics suggest 50%+ excess.ToC to surface 7 9-5/8 hole: In A-03 parentbore (1969) Pumped 515sxs (191bbls) 12.9ppg class G cement. Stage collar at 5114 MD failed to open, so secondary job was aborted. Multiple squeezes were performed over four 1 perf intervals at 3,930, 4,100, 4,178, and 4,793. 91 total bbls placed behind pipe with these squeezes. Notes from the CBL run after squeezes on 3/17/69 noted good cement up to 3500.11/13/19 RCBL showed good cement from to 3,988 (PBTD at the time) up to 3,260.Patchy cement was present up to 2,736 with free pipe above 2,518. 4-1/26-1/8 hole: Pumped 90bbls of 15.3ppg cement. 54bbls losses during cement job. 10/22/21 CBL logged ToC at 4,184 MD. PBTD: 6,435 MD 30 RKB to MSL: 126.6 5 2 3 TOC 6,435 MD NCIU A-03 Motherbore 10-3/4 16 4-1/2 Beluga A-H 6 1 7 TD: 6,630 MD 4 TOC 4,184 X CASING DETAIL Size Wt Grade Conn ID Top Btm 30 Conductor 29.000 Surf 384 16 65 H-40 15.250 Surf 612 10-3/4 45.50 & 51 J-55 BTC 9.794 Surf 2,519 726 J-55 BTC 6.276 Surf 79 23 J-55 BTC 6.366 79 3,209 (TOW) 4-1/2 12.6 L-80 TC II 3.958 3,008 6,630 TUBING DETAIL 4-1/2 12.6 L-80 IBT 3.958 Surf 3,030 JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 1 418 418 2.125 5.220 SSSV PN 21727-000-00002 WRDP-2-BAL-SSA-S Open Pressure 1800-2000 2 2,976 2,716 3.810 5.020 X Nipple 3.813 GX Profile 3 3,022 2,739 4.170 6.060 HRD-E-HD ZXP Liner Top Packer 5 Set Screws 25000# Shear 4.25 RS Profile (10.92, 5.25 Seal Bore) 4 3,019 2,753 3.940 5.760 No Go locator / Seal assembly 5 3,209 2,918 - - Whipstock (TOW @ 3,209 MD / BOW @ 3,222 MD) 6 6,450 5,220 - - 4.5 CIBP GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 1,408 1,387 3.833 BK Latch Profile (Mana Completion)20 DOME 778 09/17/2021 2 2,926 2,673 3.833 BK Latch Profile (Mana Completion)20 ORIFICE 09/17/2021 ____________________________________________________________________________________ Updated By: JLL 02/21/2023 SCHEMATIC North Cook Inlet Well:NCI A-03A Last Completed: 09/17/21 PTD:168-099 API:50-883-20020-01 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Size Status Bel A 5,480 5,492 4,434 4,442 12 11/1/21 2-7/8 6 SPF Open Bel A 5,526 5,543 4,464 4,476 17 11/1/21 2-7/8 6 SPF Open Bel B 5,595 5,605 4,512 4,519 10 11/1/21 2-7/8 6 SPF Open Bel B 5,673 5,683 4,568 4,575 10 11/1/21 2-7/8 6 SPF Open Bel B 5,693 5,703 4,583 4,590 10 11/1/21 2-7/8 6 SPF Open Bel D 5,932 5,940 4,768 4,774 8 11/1/21 2-7/8 6 SPF Open Bel D 5,984 5,990 4,810 4,814 6 11/1/21 2-7/8 6 SPF Open Bel D 6,000 6,012 4,823 4,832 12 11/1/21 2-7/8 6 SPF Open Bel D 6,018 6,024 4,837 4,842 6 10/31/21 2-7/8 6 SPF Open Bel D 6,067 6,080 4,878 4,889 13 10/31/21 2-7/8 6 SPF Open Bel E 6,107 6,127 4,912 4,929 20 10/30/21 2-7/8 6 SPF Open Bel E 6,169 6,175 4,965 4,970 6 10/30/21 2-7/8 6 SPF Open Bel E 6,194 6,214 4,987 5,004 20 10/30/21 2-7/8 6 SPF Open Bel F 6,274 6,280 5,058 5,063 6 10/30/21 2-7/8 6 SPF Open Bel F 6,288 6,304 5,070 5,085 16 10/30/21 2-7/8 6 SPF Open Bel F 6,317 6,331 5,097 5,109 14 10/29/21 2-7/8 6 SPF Open Bel F 6,353 6,367 5,129 5,142 14 10/29/21 2-7/8 6 SPF Open Bel G 6,397 6,404 5,169 5,176 7 10/29/21 2-7/8 6 SPF Open Bel H 6,456 6,470 5,223 5,236 14 10/24/21 2-7/8 6 SPF Isolated Bel H 6,492 6,506 5,256 5,269 14 10/23/21 2-7/8 6 SPF Isolated 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. DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-883-20020-01-00Well Name/No. N COOK INLET UNIT A-03ACompletion Status1-GASCompletion Date9/17/2021Permit to Drill2210510Operator Hilcorp Alaska, LLCMD6630TVD5382Current Status1-GAS12/1/2021UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:CBL, LWD/MWD LogsNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF9/27/20213208 6630 Electronic Data Set, Filename: NCIU A-03A LWD Final.las35682EDDigital DataDF9/27/2021 Electronic File: NCIU A-03A LWD Final MD.cgm35682EDDigital DataDF9/27/2021 Electronic File: NCIU A-03A LWD Final TVD.cgm35682EDDigital DataDF9/27/2021 Electronic File: NCI A-03A - Definitive Survey Report.pdf35682EDDigital DataDF9/27/2021 Electronic File: NCI A-03A - DSR Actual - landscape_Plan.pdf35682EDDigital DataDF9/27/2021 Electronic File: NCI A-03A - DSR Actual -Portrait_VSec.pdf35682EDDigital DataDF9/27/2021 Electronic File: NCI A-03A - DSR GIS.txt35682EDDigital DataDF9/27/2021 Electronic File: NCI A-03A - DSR.txt35682EDDigital DataDF9/27/2021 Electronic File: NCI A-03A- Final Surveys.xlsx35682EDDigital DataDF9/27/2021 Electronic File: NCIU A-03A LWD Final MD.emf35682EDDigital DataDF9/27/2021 Electronic File: NCIU A-03A LWD Final TVD.emf35682EDDigital DataDF9/27/2021 Electronic File: NCIU A-03A LWD Final MD.pdf35682EDDigital DataDF9/27/2021 Electronic File: NCIU A-03A LWD Final TVD.pdf35682EDDigital DataDF9/27/2021 Electronic File: NCIU A-03A LWD Final MD.tif35682EDDigital DataDF9/27/2021 Electronic File: NCIU A-03A LWD Final TVD.tif35682EDDigital Data0 0 2210510 N COOK INLET UNIT A-03A LOG HEADERS35682LogLog Header ScansDF11/22/20212818 2646 Electronic Data Set, Filename: NCI_A-03A_CBL_22-Oct-2021_(3544).las35965EDDigital DataWednesday, December 1, 2021AOGCCPage 1 of 2NCIU A-03A LWD Final.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-883-20020-01-00Well Name/No. N COOK INLET UNIT A-03ACompletion Status1-GASCompletion Date9/17/2021Permit to Drill2210510Operator Hilcorp Alaska, LLCMD6630TVD5382Current Status1-GAS12/1/2021UICNoWell 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:9/17/2021Release Date: 8/2/2021DF11/22/20216518 6281 Electronic Data Set, Filename: NCI_A-03A_Perf Plug_22-Oct-2021_(3544).las35965EDDigital DataDF11/22/2021 Electronic File: NCI_A-03A_CBL_22-Oct-2021_(3544).pdf35965EDDigital DataDF11/22/2021 Electronic File: NCI_A-03A_Perf Plug_22-Oct-2021_(3544).pdf35965EDDigital DataWednesday, December 1, 2021AOGCCPage 2 of 2M. Guhl12/1/2021 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 Unit 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 5,382' 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 Rate 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 3,019'4-1/2" Tieback Tbg SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): 6-1/8" 431 sx STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 9/17/2021 1250' FNL, 1090' FWL, Sec 6, T11N, R9W, SM, AK 2323' FNL, 2121' FEL, Sec 1, T11N, R10W, SM, AK 221-051 / 321-435 Tertiary System Gas Pool 126.6' 6,435' MD / 5,204' MD HOLE SIZE AMOUNT PULLED 50-883-20020-01-00 NCIU A-03A 332109 2586728 2205' FNL, 1465' FEL, Sec 1, T11N, R10W, SM, AK CEMENTING RECORD 2585810 SETTING DEPTH TVD 2585702 BOTTOM TOP 2,745' CASING WT. PER FT.GRADE 329540 328882 TOP SETTING DEPTH MD 3,008' Per 20 AAC 25.283 (i)(2) attach electronic information DEPTH SET (MD) 3,022' MD / 2,758' TVD PACKER SET (MD/TVD) 12.6# 6,630' Gas-Oil Ratio:Choke Size:Water-Bbl: PRODUCTION TEST 10/29/2021 Date of Test: 144 11/5/2021 24 Flow Tubing 0 6601.6 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/A6601.6 Flowing *** Please see attached schematic for perforation detail *** 0 CBL, LWD/MWD Logs Sr Res EngSr Pet GeoSr Pet Eng N/A N/A Oil-Bbl: Water-Bbl: 00289 September 12, 2021 September 2, 2021 ADL 17589 / ADL 37831 N/A N/A 3,209' MD / 2,918' TVD101 418' MD / 418' TVD 6,630' MD / 5,382' TVD WINJ SPLUGOther 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 1:28 pm, Nov 10, 2021 Completion Date 9/17/2021 HEW RBDMS HEW 11/10/2021 GDSR-11/10/21BJM 12/1/21 DLB 11/10/2021 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD N/A N/A Top of Productive Interval Bel A 5,480' 4,434' 3,927' 3,431' 5,445' 4,403' 5,780' 4,644' 5,926' 4,759' 6,092' 4,898' 6,268' 5,163' 6,397' 5,171' 6,422' 5,194' Beluga 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: Beluga D 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 H Beluga E 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 F Beluga G 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 11.4.2021Digitally 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: 2021.11.04 15:02:28 -08'00' Monty M Myers ____________________________________________________________________________________ Updated by: KDK 12/1/21 SCHEMATIC Tyonek Platform Well:NCI A-03A Last Completed: 09/17/21 PTD:221-051 API:50-883-20020-01-00 PBTD: 6,435’ MD 30” RKB to MSL: 126.6’ 7” 3 4 5 TOC 6,435’ MD NCIU A-03 Motherbore 10-3/4” 16” 4-1/2” Beluga A-H 8 1 2 7 TD: 6,630’ MD 6 TOC 4,184’ X CASING DETAIL Size Wt Grade Conn ID Top Btm 30”Conductor 29.000”Surf 384’ 16”65 H-40 15.250”Surf 612’ 10-3/4”45.50 & 51 J-55 BTC 9.794”Surf 2,519’ 7”26 J-55 BTC 6.276”Surf 79’ 23 J-55 BTC 6.366”79’3,209’ (TOW) 4-1/2”12.6 L-80 TC II 3.958”3,008’6,630’ TUBING DETAIL 4-1/2”12.6 L-80 IBT 3.958”Surf 3,030’ PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Size Status Bel A 5,480’ 5,492’ 4,434’4,442’12’11/1/21 2-7/8” 6 SPF Open Bel A 5,526’ 5,543’ 4,464’4,476’17’11/1/21 2-7/8” 6 SPF Open Bel B 5,595’ 5,605’ 4,512’4,519’10’11/1/21 2-7/8” 6 SPF Open Bel B 5,673’ 5,683’ 4,568’4,575’10’11/1/21 2-7/8” 6 SPF Open Bel B 5,693’ 5,703’ 4,583’4,590’10’11/1/21 2-7/8” 6 SPF Open Bel D 5,932’ 5,940’ 4,768’4,774’8’11/1/21 2-7/8” 6 SPF Open Bel D 5,984’ 5,990’ 4,810’4,814’6’11/1/21 2-7/8” 6 SPF Open Bel D 6,000’ 6,012’ 4,823’4,832’12’11/1/21 2-7/8” 6 SPF Open Bel D 6,018’ 6,024’ 4,837’4,842’6’10/31/21 2-7/8” 6 SPF Open Bel D 6,067’ 6,080’ 4,878’4,889’13’10/31/21 2-7/8” 6 SPF Open Bel E 6,107’ 6,127’ 4,912’4,929’20’10/30/21 2-7/8” 6 SPF Open Bel E 6,169’ 6,175’ 4,965’4,970’6’10/30/21 2-7/8” 6 SPF Open Bel E 6,194’ 6,214’ 4,987’5,004’20’10/30/21 2-7/8” 6 SPF Open Bel F 6,274’ 6,280’ 5,058’5,063’6’10/30/21 2-7/8” 6 SPF Open Bel F 6,288’ 6,304’ 5,070’5,085’16’10/30/21 2-7/8” 6 SPF Open Bel F 6,317’ 6,331’ 5,097’5,109’14’10/29/21 2-7/8” 6 SPF Open Bel F 6,353’ 6,367’ 5,129’5,142’14’10/29/21 2-7/8” 6 SPF Open Bel G 6,397’ 6,404’ 5,169’5,176’7’10/29/21 2-7/8” 6 SPF Open Bel H 6,456’ 6,470’ 5,223’5,236’14’10/24/21 2-7/8” 6 SPF Isolated Bel H 6,492’ 6,506’ 5,256’5,269’14’10/23/21 2-7/8” 6 SPF Isolated JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 1 418’418’2.125 5.220 SSSV PN 21727-000-00002 WRDP-2-BAL-SSA-S Open Pressure 1800-2000 2 1,408’1,387’ 3.833 5.984 GLM #1 BK Latch Profile (Mana Completion Systems) 1'' Valve 3 2,926’2,673’ 3.833 5.984 GLM #2 BK Latch Profile (Manan Completion Systems) 1'' Valve 4 2,976’2,716’ 3.810 5.020 X Nipple 3.813 GX Profile 5 3,022’2,739’ 4.170 6.060 HRD-E-HD ZXP Liner Top Packer 5 Set Screws 25000# Shear 4.25 RS Profile (10.92, 5.25 Seal Bore) 6 3,019’2,753’ 3.940 5.760 No Go locator / Seal assembly 7 3,209’2,918’--Whipstock (TOW @ 3,209’ MD / BOW @ 3,222’ MD) 8 6,450’5,220’--4.5” CIBP ____________________________________________________________________________________ Updated by: CJD 11/4/21 SCHEMATIC Tyonek Platform Well: NCI A-03A Last Completed: 09/17/21 PTD: 221-051 API: 50-883-20020-01-00 PBTD: 6,435’ MD 30” RKB to MSL: 126.6’ 7” 3 4 5 TOC 6,435’ MD NCIU A-03 Motherbore 10-3/4” 16” 4-1/2” Beluga A-H 8 1 2 7 TD: 6,630’ MD 6 X CASING DETAIL Size Wt Grade Conn ID Top Btm 30”Conductor 29.000”Surf 384’ 16”65 H-40 15.250”Surf 612’ 10-3/4”45.50 & 51 J-55 BTC 9.794”Surf 2,519’ 7”26 J-55 BTC 6.276”Surf 79’ 23 J-55 BTC 6.366”79’3,209’ (TOW) 4-1/2”12.6 L-80 TC II 3.958”3,008’6,630’ TUBING DETAIL 4-1/2”12.6 L-80 IBT 3.958”Surf 3,030’ PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Size Status Bel A 5,480’5,492’4,434’4,442’12’11/1/21 2-7/8” 6 SPF Open Bel A 5,526’5,543’4,464’4,476’17’11/1/21 2-7/8” 6 SPF Open Bel B 5,595’5,605’4,512’4,519’10’11/1/21 2-7/8” 6 SPF Open Bel B 5,673’5,683’4,568’4,575’10’11/1/21 2-7/8” 6 SPF Open Bel B 5,693’5,703’4,583’4,590’10’11/1/21 2-7/8” 6 SPF Open Bel D 5,932’5,940’4,768’4,774’8’11/1/21 2-7/8” 6 SPF Open Bel D 5,984’5,990’4,810’4,814’6’11/1/21 2-7/8” 6 SPF Open Bel D 6,000’6,012’4,823’4,832’12’11/1/21 2-7/8” 6 SPF Open Bel D 6,018’6,024’4,837’4,842’6’10/31/21 2-7/8” 6 SPF Open Bel D 6,067’6,080’4,878’4,889’13’10/31/21 2-7/8” 6 SPF Open BelE 6,107’6,127’4,912’4,929’20’10/30/21 2-7/8” 6 SPF Open BelE 6,169’6,175’4,965’4,970’6’10/30/21 2-7/8” 6 SPF Open BelE 6,194’6,214’4,987’5,004’20’10/30/21 2-7/8” 6 SPF Open Bel F 6,274’6,280’5,058’5,063’6’10/30/21 2-7/8” 6 SPF Open Bel F 6,288’6,304’5,070’5,085’16’10/30/21 2-7/8” 6 SPF Open Bel F 6,317’6,331’5,097’5,109’14’10/29/21 2-7/8” 6 SPF Open Bel F 6,353’6,367’5,129’5,142’14’10/29/21 2-7/8” 6 SPF Open Bel G 6,397’6,404’5,169’5,176’7’10/29/21 2-7/8” 6 SPF Open BelH 6,456’6,470’5,223’5,236’14’10/24/21 2-7/8” 6 SPF Isolated BelH 6,492’6,506’5,256’5,269’14’10/23/21 2-7/8” 6 SPF Isolated JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 1 418’418’2.125 5.220 SSSV PN 21727-000-00002 WRDP-2-BAL-SSA-S Open Pressure 1800-2000 2 1,408’1,387’3.833 5.984 GLM #1 BK Latch Profile (Mana Completion Systems) 1'' Valve 3 2,926’2,673’3.833 5.984 GLM #2 BK Latch Profile (Manan Completion Systems) 1'' Valve 4 2,976’2,716’3.810 5.020 X Nipple 3.813 GX Profile 5 3,022’2,739’4.170 6.060 HRD-E-HD ZXP Liner Top Packer 5 Set Screws 25000# Shear 4.25 RS Profile (10.92, 5.25 Seal Bore) 6 3,019’2,753’3.940 5.760 No Go locator / Seal assembly 7 3,209’2,918’--Whipstock (TOW @ 3,209’ MD/ BOW @ 3,222’ MD) 8 6,450’5,220’--4.5” CIBP Superseded Estimated TOC = 4184' MD CBL 10/22/21 Activity Date Ops Summary 8/29/2021 Welders extending landings and install same. Skid top section of the rig and center over A-03A wellhead. [Had wellhead hand install TWC in A-03A, then released him.] Install 2" jumper hose in air line. Break bolts on A-03A dry hole tree. Install landings.;Skid upper sub over toward A-03A . Ran out of jacking room w/ 3' to go. Turn jacks around for pushing the sub and finish skidding rig in place over A-03A.;Rig dn hyd jacking hoses. Set earthquake clamps on bottom sub. Clamps hit on the rails where you cant get the bottom clamps on so we welded them down. Drill holes in upper section and bolt sub down. Install stairs on landing f/ HAK rack to rig.;Set slide and install landing next to slide. Hook up Mud, salt water, water, air, low press mud, and cmt lines.;Production Removing obstruction around wellhead. Finish nippling down dry hole tree and removing it from the cellar. Install blanking sub in hanger. Welder finished building flow line so its ready to install.;Set in and nipple up riser. Set BOPS on and nipple up to Riser. Role 90s on mud cross Roustabout crew Painting Upper sub beam stiffeners with Primer from previous welding.;Install Choke and kill valves on mud cross and tighten same. Roustabout crew Painting Upper sub beam stiffeners with Primer from previous welding.;Install Bell nipple on BOPs. Continue securing lines. Work on rig acceptance check list.;Wellhead Pressures- Tubing & IA- 0 PSI 8/30/2021 Finish working on rig acceptance check list. Finish hooking up flow nipple. Install mouse hole. LD PU slings. RU Hawkjaw.;PU and MU BOP test jt assem. Had issues with blanking sub and had to re-install. Also had a blockage in the choke line that finally got blown out.;Made one good test and the swivel flange connection on the kill line started leaking. Had to remove kill line hose and valves to replace ring gasket on mud X. Replaced gasket and got kill line back together.;Attempted to test again and the adaptor spool above the well head started leaking. Re-tighten bolts on the spool and do a shell test. tested good.;Test BOPs as per AOGCC to 250/3500 psi. Test annular to 250/2500 psi. Test Annular and pipe rams with 4.5 Test Joint. All Test performed against Blanking sub in hanger. Install flow line and stands.;Accumulator Draw down- 3100 PSI Starting Pressure 1980 PSI After Shut in 200 PSI Increase 22 sec Full Pressure 132 N2- 16 BTLS @ 2278 PSI Average;R/D Testing equipment. Prep for pulling the hanger. Run Lines in cellar to production header to pump to production.;Troubleshoot drillers console communication failure. Unable to use draw works/MP/TD. Lay out one bundle of DP & Strap for clean out run 8/31/2021 Continue working on power issues with drillers console. Found wire that had been stretched tight from the rig move. Repaired wire and made sure we had slack in all the wires.;Break out test equip and MU jt for pulling hanger [Waiting on Production to get gas to test alarms] Working on flow meter to make it more sensitive.;Production tested gas alarms. PU 9 jts of DP with air tuggers MU stands and stand them back in the derrick.;Back out LDS and pull hanger. Break out LD landing as we pull hanger. Pull hanger to the floor. Break out all the XOs and the hanger. LD 4 jts 3 1/2 tbg. Clear floor and prep wash tool.;With wash tool on the bottom of the stand wash down through stack while pumping from ann valve to production low press header. After getting washed to wellhead break off wash tool and run in about 15' in liner washing.;Pumped about 40 bbls taking it to production low pressure header. Mud man taking samples until we passed the sheen test.;M/U running tool and set 9" I.D. wear ring and mobilize clean out BHA tools to the rig floor. M/U CDS-40 to 3-1/2" IF XO, 6.151" O.D. upper mill, flex joint, bit sub and 6.125" Kymera bit to 19'. RIH w/ stand of 4.5" drill pipe and took weight at 55.8' - top of 26# 7" casing.;P/U and inspect bit - good. RIH and take weight again at 55.8', rotate string with chain tongs and bit rolled into 7" casing. TIH with stands and tag top of cement at 3282' with 8K WOB. Rack back stand to 3275'.;PJSM. Perform displacement from water to 9.5 ppg 2% KCl LSND mud. 255 GPM, 475 PSI ICP, 715 PSI FCP. Overboarded 127 bbls of water then take interface and mud back to shaker tanks. Pumped additional 210 bbls to fill shaker tanks. Perform flow check - static. Pump 15 bbls dry job.;POOH from 3275' racking back 4.5" drill pipe to 19'. L/D bit sub and bit. Bit graded 0-0-NO-A-X-I-NO-BHA.;M/U 6.125" window mill, 6.00" lower mill, flex joint, 6.151" upper mill, XO sub, one 4.5" HWDP, XO sub, whipstock valve (verified open), MWD DM & TM collar (measure MWD offset to whipstock highside 120.51°), XO sub to 86' then M/U stand of 4.5" drill pipe.;Dump cold mud from shaker tank then transfer mud from platform pits to provide room to pump. Pulse test MWD tools with 250 GPM, 710 PSI - good test. POOH and M/U whipstock and hydraulic anchor assembly 9/1/2021 Orientate to whipstock. RIH through wellhead w/ no issues.;RIH w/ whipstock filling pipe w/ fill up hose at about 1800' & continue RIH to 3143'.;Orientate tool to 26° left. Attempt to set whipstock w/ bottom of window at 3223' and top at 3208'. Made several attempts with no success. Baker consulted with his people in town and decided something on the tool was faulted.;Pump dry job and POH. Stand back BHA down to MWD tools. PU and remove whipstock. Lay down TM and DM collars. Break and LD window mill. Layout the rest of the mill assem together. Looks like the reason the whipstock wouldn't set is because;The whipstock valve didn't shift .;M/U Baker 7" mechanical set 3BB bridge plug and 3-1/2" IF x 4-1/2" CDS40 XO . TIH on 4-1/2" drill pipe to 3228'. Filled pipe once at 20 stands.;Place bridge plug on depth at 3228', 85K PU / 82K SO. Apply 11 rounds right hand turns & slack off - did not set. Continue to work string up to 15' high slacking off fast to work torque down and applying more right turns. Worked pipe 26 times and applied up to 50 right revolutions.;Fill pipe, caught pressure and pressure built and did not drop off. Bleed pressure off. Slack off, plug not set. P/U to 100K (pipe full now). Slack off to 60K, bridge plug set. P/U and set down to 60K twice more to verify set. P/U observe travel at 90K stop at 110K then S/O to 105K.;Apply right turn, saw release at 3 revolutions, but continued to 10 total turns. P/U with 95K free travel - verified release.;POOH with bridge plug running tool from 3226' and laydown running tool;M/U 6.125" window mill, 6.0" lower mill, flex joint, 6.151" upper mill, XO, one joint of 4.5" HWDP, XO, MWD DM and TM collars. Perform MWD to whipstock highside offset measurement - 268.66°. Shallow pulse test MWD w/ 235 GPM, 530 PSI - good test.;P/U bottom trip anchor and 7" whipstock assembly. Remove shipping screw and one anchor set screw. 5 remaining sets screws in anchor = 18K set. M/U mills to whipstock with 35K shear bolt.;Trip in hole with whipstock / milling assembly on none 4.75" drill collars, eighteen 4.5" HWDP and 4.5" drill pipe at 90'/min running speed to 2402'. n (LAT/LONG): evation (RKB): 50-883-20020-01-00API #: Well Name: Field: County/State: NCIU A-03A North Cook Inlet Hilcorp Energy Company Composite Report , Alaska Contractor AFE #: AFE $: Spartan 151 Job Name:211-00030 A-03A Drilling Spud Date: jgg Pull hanger to the floor. Break out all the XOs and the hanger. LD 4 jts 3 1/2 tbg. pgpg tag top of cement at 3282' with 8K WOB.gg g Perform displacement from water to 9.5 ppg 2% KCl LSND mud. gpg pp BOPs as per AOGCC to 250/3500 psi. Test annular to 250/2500 psi 9/2/2021 Finish RIH to 3148'. Bring pump on and stage up to 250 GPM. orientate whipstock to 35°L, Slack off and tag at 3226', Set dn 18k and anchor set, PU to 10k k over up wt, Slack off to 60k but seen pin shear at 40k, PU 10' and slack back off setting dn 5k.;PU 5' and get rotating parameters. At 60 rpm we had 5k torque, 260 GPM, 950 psi. Start milling window at 3209', Mill reached bottom of window at 3222'.;Dressing window with upper mill and drilling new hole f/3222' t/3244'. [Pumped high vis sweep at 3226' and 3244'];Circ hole clean with mud wt even all the way around. Also worked tools through window to ensure window is clean. 65# metal recovered during milling and circulating.;Pump through choke and kill lines and rig up to perform FIT to 14.7 ppg MWE. Pressure up to 795 psi taking pressures every stk.for 13 stks at full pressure. Monitor press every min for 13 min. Total pumped 1.17 bbls, got back .71 bbls. Sent press charts to town.;Blow dn lines and pump dry job.;POH racking back drill pipe, HWDP and drill collars. L/D Baker milling assembly. Normal wear on all mills and upper mill in gauge 6.16". Clean and clear rig floor.;Pull wear bushing. M/U Johnny Wacker on a stand of drill pipe and flush stack with 5 BPM. L/D Johnny Wacker and rack back stand. Re-install wear bushing. Recovered 5# metal after flushing stack = 70# total.;M/U BHA #3: 6-1/8" Kymera K5M323 bit, 4-3/4" mud motor, float sub, MWD DM & TM collars, XO, 2 jts HWDP and jars to 210'. TIH w/ stands of HWDP from the derrick to 487'.;Single in the hole with 4-1/2" CDS-40 drill pipe f/ 487' t/ 3086'. 9/3/2021 At 3180' orientate motor to 35°L, then slide down through window with no issues. tag bottom at 3244'.;Directional drill 6 1/8 hole f/ 3244' t/ 3457 76 RPM, 55k Tq 258 GPM , 1390 psi Bit wt 0 to 4k, Avg ROP 71' FPH, 213' drilled;Back ream std, take survey, Circ bottom up, Pump dry job .;POH to Sperry tools with no issues pulling through window.;LD DM and TM collars. PU and gauge bit, bit looked new. Check motor and it looked good. PU DM collar, DN Sonde, GM collar, ADR collar, ADL collar, CTN Collar, CTN insert, PWD, and TM HOC. PU and up load tools, Shallow test tools, and load nukes.;R/U single joint elevators and load 4-1/2" drill pipe on beaverslide. P/U 69 joints of 4-1/2" CDS-40 drill pipe from 558' to 2691'. RIH out of the derrick f/ 2691' t/ 3154'. Orient TF 30L then continue to TIH to 3435'. Wash down f/ 3435' t/ 3457' with 20L toolface. Offload cargo from M/V Sovereign;Drill 6-1/8" hole f/ 3457' t/ 3825', 368' drilled, 66.91'/hr AROP. 250 GPM, 1550 PSI, 60 RPM, 6K TQ, 1-5K WOB, 150'/hour ROP limit. MW 9.6 / Vis 41 / ECD 11.18 110K PU / 97K SO / 102K ROT;Last survey at 3669.11' MD / 3280.14' TVD, 47.90° INC, 245.18° AZM, 15.91' from plan, 15.86' low and 1.25' right. Backream stands and MAD pass slide intervals for ALD data. Pump 15 bbl sweep at 3743', back on time with no increase observed.;Offload four cement pods from M/V Sovereign and transfer to Spartan 151 bulk silos - 698 sxs total. Collected 17# of metal today on magnets for 87# total. 9/4/2021 Directional Drill 6-1/8" hole f/ 3825' t/ 4345', 520' drilled, 86.6'/hr AROP. 250 GPM, 1600 PSI, 60 RPM, 63K TQ, 1-5K WOB, 150'/hour ROP limit. MW 9.6 / Vis 41 / ECD 11.47 115K PU / 99K SO / 104K ROT Pumped sweeps every 250', on time & no increase in cuttings;Directional Drill 6-1/8" hole f/ 4345' t/ 4451', 106' drilled, 70.6'/hr AROP. 250 GPM, 1600 PSI, 60 RPM, 63K TQ, 1-5K WOB, 150'/hour ROP limit. MW 9.6 / Vis 41 / ECD 11.47 115K PU / 99K SO / 104K ROT Pumped sweeps every 250', on time & no increase in cuttings;Take survey. Pump high vis sweep. Check flow. Short trip to window. Had a couple quick 5k overpulls from 3900' to 3810'. No other overpulls. RIH to last std. Break circ and wash to bottom while orientating tool to dn side. Make connection.;Directional Drill 6-1/8" hole f/ 4451' t/ 4542, 91' drilled, 91'/hr AROP. 250 GPM, 1600 PSI, 60 RPM, 63K TQ, 1-5K WOB, 150'/hour ROP limit. MW 9.6 / Vis 41 / ECD 11.47 115K PU / 99K SO / 104K ROT;Directional drill 6-1/8" hole f/ 4542' t/ 4820', 278' drilled, 55.6'/hr AROP. 265 GPM, 1830 PSI, 65 RPM, 6-7K TQ, 4-6K WOB, 150'/hour ROP limit. MW 9.6 / Vis 41 / ECD 11.18 130K PU / 105K SO / 110K ROT;During a connection, the driller suspected flow, shut in the well with the annular and notified the company man and toolpusher. Initial 100 PSI observed on drill pipe and casing, but pressure was falling below 50 PSI. Bleed off pressure through the choke then shut choke - no pressure observed.;Open choke and no flow observed. Open annular and perform flow check - static. Over pull 30K. S/O and set down 10K. Establish circulation - normal. P/U with brief 30K overpull then free. Establish rotation and ream 30' & CBU - no gas. Shut down pumps and perform flow check- static. Resume drilling.;Directional drill 6-1/8" hole f/ 4820' t/ 5232', 412' drilled, 68.67'/hour AROP. 250 GPM, 1700 PSI, 60 RPM, 6-7K TQ, 1-8K WOB, 150'/hour ROP limit. MW 9.7 / Vis 44 / ECD 11.33 120K PU / 102K SO / 115K ROT Flow checks on connections had slight breathing/ballooning that slowed quickly and went static.;Began experiencing losses at 52 03' at 175 BPH loss rate after drilling through a hard interval. Pumped sweeps at 4686' & 5177', both back on time w/ no increase.;Last survey @ 5150.41' MD / 4216.18' TVD, 49.08° Inc, 243.02° Azm, 9.41' from plan, 6.46' low and 6.84' left. Pason system was losing connection from shaker UBJ to rig floor EDR. Found loose connection with some water in it. ;Drill 6-1/8" hole f/ 3457' t/ 3825', p Drill 6-1/8" hole f/ 4451' t/ 4542, Flow checks on connections had slight breathing/ballooning that slowed quickly and went static.;Began experiencing losses at 5203' at 175 BPH loss rate after drilling through a hard interval. g ;Directional drill 6-1/8" hole f/ 4820' t/ 5232', ;Directional drill 6 1/8 hole f/ 3244' t/ 3457 MW 9.6 Pressure up to 795 psi taking gg pressures every stk.for 13 stks at full pressure. Monitor press every min for 13 min. Total pumped 1.17 bbls, got back .71 bbls. During a connection, the driller suspected flow, shut in the well with the annular and notified the company man and toolpusher.gp py p Initial 100 PSI observed on drill pipe and casing, but pressure was falling below 50 PSI. Bleed off pressure through the choke then shut choke - no pressure observed.;O orientate whipstock to 35°L, Slack off and tag at 3226', Set dn 18k and anchor set, ]yg circulating.;Pump through choke and kill lines and rig up to perform FIT to 14.7 ppg MWE.gpg gpp ppg Drill 6-1/8" hole f/ 4345' t/ 4451', MW 9.6 pgggppq Start milling window at 3209', Mill reached bottom of window at 3222'.;Dressing window with upper mill and drilling new hole f/3222' t/3244'. 9/5/2021 At 5232' stopped drilling due to excessive losses. Looks like losses started when we drilled into a depleted zone at 5 203'. Lower pump rate and PU above loss zone. Mix a 40#/bbl LCM pull w/ fiber. Spot 15 bbl pill over lower section of hole.;Pull up above Loss zone and shut pump dn. Monitor well for 20 min. Had slight flow but DP side dry. Bring pump on at 150 GPM and wash to bottom. [350 bbls total losses];Drill ahead at lower rate f/ 5232' t/ 5286'. Pumping at 208 gpm 1143 Psi. Still lossing mud at 100 BPH. Mad pass and prep to spot LCM pill.;Pump and spot 20 bbl 40#/bbl LCM pill on bottom. Check flow. Looks like well is breathing.;Short trip to 4451' & run back in the hole with no tight spots. Hole did continue breathing during trip. Wash dn and orientate on last 60'.;Directional drill 6-1/8" hole f/ 5286' t/ 5564', 278' drilled, 43.4/hr AROP. 220 GPM, 1400 PSI, 65 RPM, 7K TQ, 3 - 6K WOB, 150'/hour ROP limit. MW 9.5+ / Vis 43 / ECD 10.9 130K PU / 105K SO / 110K ROT Our loss rate while pumping is 77 BPH When we shut the pump dn the well breaths or gives some back.;Stop drilling to build mud volume. Reciprocate pipe w/ 84 GPM, 15 RPM, continue losses. Slow to 70 GPM with 50 BPH losses, then 55 GPM. Losing 47 BPH. Shut down & observe well for 15 minutes with 14.7 bbls back. Breathing did slow considerable over the 15 minutes, did not wait for it to fully stop.;Resume reciprocating pipe with 30 GPM and 15 RPM. Losses at 27 BPH. Begin circulate 15 minutes @ 30 GPM with 15 RPM, then 15 minutes pumps off with reciprocation to minimize losses while building mud.;Transfer 250 bbls of new mud to active system. Pump 23.5 bbls 40 ppb LCM pill (7.5#/bbl BaraFiber, 11#/bbl SteelSeal 400 and 11#/bbl each of Baracarb 50 & 150) out the bit @ 1385 strokes then allow to soak for 30 min while reciprocating pipe. 1135.6 bbls lost downhole at 24:00.;Directional drill 6-1/8" hole f/ 5564' t/ 5660', 96' drilled, 96'/hour AROP. 185 GPM, 1050 PSI, 60 RPM, 6.5K TQ, 4-8K WOB, 150'/hr ROP limit. MW 9.5, Vis 41, ECD 10.97. 140K PU / 110K SO / 115K ROT Loss rate 118 BPH. Begin building 250 bbls of mud in pit #2.;Last survey at 5527.80' MD / 4465.55' TVD, 47.89° Inc, 256.7° Azm, 8.16' from plan, 7.89' low and 2.08' left.;While performing MAD pass of slide interval, pump and spot 30 bbl 40#/bbl LCM pill w/ 7.5#/bbl BaraFiber, 11#/bbl of SteelSeal 400 and 11#/bbl each of BaraCarb 50 & 150. Loss rate slowed to 64 BPH but at this point was volume was too low to continue drilling.;Mix 250 bbls of 9.5 ppg 2% KCl LSND mud in pit #2. Move the string to ensure free and also pump 3.5 bbls every 30 minutes. Well breathed back 29 bbls for initial 20 minutes and slowed. Well static after 2 hours with 35 bbls total back. 9/6/2021 Continue mixing 250 bbls of 9.5 ppg 2% KCl LSND mud in pit #2. Move the string to ensure free and also pump 3.5 bbls every 30 minutes. Well is static.;Directional drill 6-1/8" hole f/ 5660' t/ 5780, 120' drilled, 48'/hour AROP. 204 GPM, 1404 PSI, 66 RPM, 7K TQ, 4-8K WOB, 150'/hr ROP limit. MW 9.5, Vis 41, ECD 11.04 140K PU / 110K SO / 115K ROT Loss rate went up to 120 BPH after we made the connection;Shut pump down and PU off bottom. Gained 6 bbls back in about 15min then well went static. Stand this stand back and pull 1 more t/5653'. Pump 25 bbl LCM pill [Walnut hull 3 lbs/bbl, Barifiber course, Steel seal 400, Barifiber 400, and Barifiber 200] Had a 200 psi press increase when pill;through the tools. Shut well in and pump dn both sides. Pump 5 bbls 3 times w/ 5 min between with no press. Pump another 2.3 bbls and it press up to 60 psi. shut pump dn and it bled right off. Pump another 2.7 bbls with no press.;Open up well and RIH with the 2 stds pulled. Finish building 100bbl batch of mud.;Drill from 5780' t/5792'. Not getting back good returns. Shut dn and stroke pipe up with pump on, and down with no pump to get the mud to flow more freely. Attempt to drill again but loss rate was to high at 100 BPH, Decision was made to POH and set cmt plug.;Last survey at 5710.89' MD / 4595.92' TVD, 41.53° Inc, 259.29° Azm, 8.27' from plan, 8.07' low and 1.79' right. 4# metal recovered of ditch magnets, 98# total since window milled.;POOH w/ directional drilling assembly from 5792' to 558'. Rack back HWDP and drill collars to 124'. Remove logging sources and read MWD tools. All MWD data recovered and logs sent out. Rack back MWD tools & L/D mud motor and bit. Bit graded: 0-0-NO-A-E-I-NO-HP.;Two Schlumberger cementers and 6-18" bit arrived on 22:40 chopper.;Clear and clean rig floor. Service rig while removing jets from 6-1/8" bit. M/U 6-1/8" mill tooth bit (nozzles removed: three 32/32" ports), bit sub, 3x spiral drill collars, XO sub and 9x 4-1/2" HWDP to 372'. TIH with 4-1/2" drill pipe to 5162'.;R/U side entry sub, FOSV, 10' pup joint to top drive. PJSM for cement job. Pump 5 bbls water at 2.5 BPM, 320 PSI. Pressure test lines to 500 PSI low / 3500 PSI high - good. Repair air check valve to cement bulk tank.;Mix and pump 20 bbls of 15.3 ppg cement at 3.5 BPM, 600 PSI ICP / 450 PSI FCP. Pump 6.5 bbl water at 4.5 BPM, 350 PSI. Swap to rig pumps for displacement - squeeze continues into next report.;788 bbls daily losses, 1923.6 bbls total losses 9/7/2021 Displace cmt w/ 43.5 bls, Shut annular and squeeze 20 bbls cmt and 1.5 bbls water at 2 bbls/ min w/ a final pressure of 230 psi. CIP at 06:19. Press bled to 0 after 5 min. L/D cmt head and pull 5 stds to 4701';Pump 30 bbl nut plug pill to clean cmt out of the pipe. Swap to active and pump at 5 BPM. Had good returns to start with then at 104 bbls pumped returns started to fall off. At that point we had 51 bbls to complete the circ. Did complete the circ but had minimal returns.;Shut dn pumps and monitor well. Keep pipe moving and hole is staying full.;TIH f/ 4701' and began taking weight at 5194' and took 3K at 5221'. P/U to 5162' to place on depth for 2nd cement squeeze. R/U cement assy and line.;Schlumberger pumped 5 bbls water, test lines to 500 PSI low / 3000 PSI high. Mix and pump 20 bbls of 15.3 ppg cement at 3.5 BPM, 600 PSI ICP, 375 PSI FCP. Pump 6.5 bbls water at 4.5 BPM, 400 PSI. Swap to rig pump and displace with 9.5 ppg mud at 5 BPM. 12.6 bbls pumped = 100 PSI, 25.2 bbls = 134 PSI;37.8 bbls = 200 PSI and 43.5 bbls = 230 PSI. Shut pumps down and close annular. Squeeze 20 bbls of cement and 1.5 bbls of water. Began seeing pressure at 12.4 bbls away. 159 PSI final injection pressure. CIP at 10:26. Bleed off pressure, open annular & L/D cement assy;POOH f/ 5162' t/ 4701'. 120K PU / 105K SO. Pump 25 bbls nut plug sweep to clean drill pipe 185 GPM, 290 PSI with good returns Rack back stand to 4609' then increase to 225 GPM, 390 PSI with good returns. Mud pit level too low to clean out hole, circulate and wait on barite to arrive on boat @ 20:00.;POOH f/ 4609' t/ 3126' to slip and cut drilling line while waiting on barite. No overpull observed pulling into the 7" window. 120K PU / 105K SO.;Slip and cut 123' of drilling line. Adjust draw works brakes.;Mix and build 250 bbls of 9.5 ppg and offload additional mud product off of crew boat.;TIH f/ 3156' t/ 5204' with dumb iron assembly. Good displacement while running in. Stage up pumps at 4576' to establish circulation parameters: 140 gpm, 219 psi, 3.3% RF; 160 gpm, 272 psi, 4.3% RF; 185 gpm, 337psi, 5.4% RF; 200 gpm, 401 psi, 6.5% RF Tag cement at 5204' w/ 3K;Wash f/ 5204' t/ 5224'; 200 gpm, 390 psi. Tag cement stringer at 5224' w/ 5k. Wash and ream f/ 5224' t/ 5793': 225 gpm, 500 psi, 8% RF, 60-80 rpm, 5-6k trq, 130K PU / 105K SO / 120K ROT. No losses while reaming to bottom.;Circulate BU at 5793': 225 gpm, 510 psi, 60 rpm, 6.3K trq. MW in/out 9.5ppg;POOH f/ 5793' t/ 3600' with 6-1/8" dumb iron assembly. g Shut down & observe well for 15 minutes with 14.7 bbls back. Breathing did slow considerable over the 15 minutes, did not wait for it to fully stop.;R At 5232' stopped drilling due to excessive losses. ppg When we shut the pump dn the well breaths or gives some back. Attempting to heal losses. Displace cmt w/ 43.5 bls, Shut annular and squeeze 20 bbls cmt Attempting to heal losses. pg yg ggg R/U cement assy and line.;Schlumberger pumped 5 bbls water, test lines to 500 PSI low / 3000 PSI high. Mix pp and pump 20 bbls of 15.3 ppg cement a too low to continue drilling.;MLoss rate slowed to 64 BPH but at this point was volume was pp y Well breathed back 29 bbls for initial 20 minutes and slowed. Well static after 2 hours with 35 bbls total back. ;788 bbls daily losses, 1923.6 bbls total losses jp ;Mix and pump 20 bbls of 15.3 ppg cement 9/8/2021 POOH w/ BHA #6 f/ 3600' t/ 403'. Rack back HWDP and drill collars. L/D bit sub and bit. Bit graded 1-1-WT-A-E-I-NO-BHA. Clean and clear rig floor. Trip took 6.25 bbls over calculated displacement.;M/U rerun 6-1/8" K5M323 bit, mud motor &stand of MWD tools out of the derrick. C/O MWD pulser. Initialize MWD tools & pulse test good. Install logging sources then run drill collars & HWDP to 558'. TIH w/ 4-1/2" drill pipe f/ 558'. Orient motor through window at 3209'. TIH t/ 5792'.;Drill 6-1/8" production hole f/ 5792' t/ 5847', 55' drilled, 55'/hr AROP. 225 GPM, 1650 PSI, 65 RPM, 7.5K TQ, 2-9K WOB. 9.5 MW, 39 vis, 11.3 ECD. Hard slow drilling f/ 5807' t/ 5818'. Hole unloaded cuttings at bottoms up. Began seeing losses at 5833' at 225 BPH. Drill stand down with no improvement.;Rack stand back, start building 40#/bbls LCM pill. Reciprocate pipe. Observe 7 BPH static losses.;Drill 20' of 6-1/8" hole f/ 5847' t/ 5867' in 5' increments. 200 GPM, 950-1300 PSI, 65 RPM, 8K TQ, 5-10K TQ. 9.5 MW, 39 vis, 9.9 ECD. Losses at 205 BPH Note: Assembly took 25K weight at 5833' when working back to bottom, had to ream to bottom.;Pump and spot 20 bbl 40#/bbls LCM pill on bottom then pull up to 5757'. Pump above LCM pill at 4.8 BPM, 1100 PSI until 20 bbls lost. Dynamic loss rate ~300 bph. Shut down and allow LCM pill to soak while building additional mud volume. Continue to work pipe from 5757' to 5663'.;Static losses while allowing LCM pill to soak ~6 bph. Establish dynamic losses at minimum drilling rate prior to POOH to LD drilling assembly. 200 GPM, 1040 PSI lost 27 bbls over 5 min period, ~325 BPH dynamic loss rate. No change in static loss rate.;POOH w/ directional drilling assembly from 5757' to 558'. Rack back HWDP and drill collars to 124'. Remove logging sources and read MWD tools. Rack back MWD tools & L/D mud motor and bit. Bit graded: 0-0-NO- A-E-I-NO-HP Lost 129 bbls over trip out.;Clean and clear rig floor. Inspect handling equipment. Well static.;M/U 6-1/8" mill tooth bit (nozzles removed: three 32/32" ports), bit sub, 3x spiral drill collars, XO sub and 9x 4-1/2" HWDP to 372'. TIH with 4-1/2" drill pipe to 3156'. 9/9/2021 Wait for cementers at 3156' inside the 7" casing window. R/U cement head assembly and hoses. Build 250 bbls 9.5 ppg mud. Monitor well on trip tank - static.;R/U 2" hard line for cement in the derrick. Repair winch at derrick board and stabbing board. R/U 2" line for cement cleanup. R/U line from seawater deluge tank to shakers. Load 200 bbls screened Inlet water into pit #2. Build 250 bbls of 9.2 ppg mud.;Cementer assistant arrived at 12:00 and began getting equipment ready. Cementer arrived at 16:00 and finished preparing for cement job. Monitor well on trip tank - static.;TIH f/ 3156' t/ 5724' while monitoring well on trip tank. 135K PU, 110 K SO.;R/U cement head and high pressure hoses on rig floor. Hold PJSM with rig crew and SLB cementers . Schlumberger pumped 5 bbls water, test lines to 500 PSI low / 3000 PSI high.;While pressure testing lines for cement job, un-related hydraulic line on iron roughneck broke at a connection crimp on the rig floor. Shut down and bleed off pressure on cement lines, isolated hydraulics to iron roughneck and cleaned up rig floor. Replaced hydraulic hose for iron roughneck.;Estimate total hydraulic fluid release at 10 gallons. All fluid was contained on rig floor.;Schlumberger pumped 5 bbls water, test lines to 500 PSI low / 3000 PSI high. Mix and pump 30 bbls of 15.3 ppg cement w/ 2#/bbl CemNet in last 10 bbls at 3 BPM, 600 PSI ICP, 300 PSI FCP. Pump 6.5 bbls water at 4 BPM, 200 PSI.;Swap to rig pump and displace with 9.5 ppg mud at 5 BPM. Caught cement at 7.5 bbls away. Displace cement to bit with 41.15 bbls at 5 BPM, 230 PSI ICP, 415 PSI FCP. Close annular and squeeze 30 bbls of cement and 3 bbls of water at 5 BPM, final injection pressure 530 PSI. CIP at 22:10.;Bleed off pressure (205 PSI), open annular and L/D cement head assembly. POOH f/ 5724' t/5072'. 150K PU, 120K SO. Pump 25 bbl nut plug sweep to clean drill pipe; 231 GPM, 525 PSI with good returns. No cement or high pH at surface after cleaning up the hole.;Shut down pumps and monitor well on trip tank. Keep pipe moving and hole remained full.;TIH f/ 5072' t/5276' with 6-1/8" cement squeeze assembly. Break circulation and establish parameters: 94 GPM, 236 PSI, 1.9% RF, 140K PU, 110K SO.;Wash down f/ 5276' t/5826': 200 GPM, 520 PSI, 6% RF, MW in 9.6 ppg. Tag at 5795' w/ 4K, pick up and wash through. Tag at 5826' w/ 4-5K (2x). Wash and Ream f/ 5826' t/ 5867': 200 GPM, 550 PSI, 6% RF, 60 RPM, 6.7K tq, 140K PU, 110K SO, 120K ROT.;Circulate BU at 5867': 225 GPM, 525 PSI, 60 RPM, 7.5K tq. Treat high pH on surface at bottoms up. Total fluid lost while washing to bottom and CBU ~ 30 bbls.;Perform 15 min flow check to establish static loss rate prior to pulling off bottom - well static. POOH f/ 5826' t/ 2230' with 6-1/8" cement squeeze assembly. 9/10/2021 POOH f/ 2230' t/ 372' w/ cement squeeze BHA. Rack back HWDP and drill collars. L/D bit sub and bit. 4.5 bbls lost on trip out of the hole.;M/U bit, mud motor. MWD DM, GM and TM hang off collars (HOC) to 62'. RIH w/ stand of drill collars and pulse test MWD. MWD tool was not pulsing correctly, only see a pulse every 25 seconds.;Rack back stand of HWDP. L/D TM HOC and C/O pulser. M/U TM HOC and RIH with stand of HWDP. Pulse test MWD again -observe directional probe failure, high g-total. Decision made to C/O entire tool string.;L/D directional / gamma ray tool string from the hole. L/D full logging MWD toolstring from the derrrick. Utilize back up tools to M/U directional / gamma ray assembly. Pulse test tools - good test.;TIH with 6-1/8" drilling assembly t/ 5788'. Wash down f/ 5788' t/ 5867'; 200 GPM, 1100 PSI, 145K PU, 100K SO. Take SPRs and establish drilling parameters.;Drill per DD f/5867' t/5889'; 200 GPM, 1100 PSI, 60 RPM, 7.5K tq, 4-6K WOB, 150K PU, 110K SO, 120K ROT. Encountered significant losses after making connection at 5877'. Dynamic loss rate ~250- 280 BPH. PU to 5876' and establish static loss rate ~22 BPH. Total fluid lost while drilling ~265 bbls.;Trip out of the hole f/ 5876' t/ 4758' with 6-1/8" drilling assembly while transferring fluid and discussing plan forward, ~20 BPH loss rate while tripping.;RIH the f/4758' t/ 5889' with 6-1/8" drilling assembly with intent to drill an additional 20' of new hole with fluids on hand before tripping for cement squeeze assembly. No static losses after getting back to bottom.;Drill per DD f/5889' t/5927'; 200 GPM, 1130 PSI, 60 RPM, 7.5K tq, 4-8K WOB, 150K PU, 110K SO, 120K ROT. Dynamic loss rate ~250-280 BPH. Total fluid lost while drilling ~187 bbls. Distance from WP04: 9.34', 9.18' Low, 1.72' Right.;Trip out of hole f/ 5927' t/ 4200' with 6-1/8" drilling assembly. Static loss rate prior to pulling off bottom ~12 BPH. 9/11/2021 POOH f/ 4200' with 6-1/8" drilling assembly. Rack back BHA components. Bit graded: 0-0-NO-A-X-I-NO-HP. 24.5 bbls lost on trip out of the hole. Clear and clear rig floor. ***Notified AOGCC at 06:47 of upcoming BOP test for 13 Sept ***;M/U 6-1/8" bit with jets removed, bit sub, three spiral drill collars and 9 HWDP to 372'. TIH f/ 372' t/ 5817'. Laid down top single. 4 bbls lost in trip in.;R/U cement "head" and hoses. Fill pipe & obtain pressures - 4 BPM, 350 PSI & 5 BPM, 505 PSI. PJSM. Pump 5 bbls water then pressure test lines to 500 PSI low / 3000 PSI high. Mix 30 bbls of 15.3 ppg cement. Pump cement at 2.7 BPM, 375 ICP, 200 PSI FCP, 2#/bbl CemNET in last 10 bbls.;Pump 6.5 bbls water @ 2.8 BPM, 140 PSI ICP, 70 PSI FCP. Displace w/ rig pumps @ 5 BPM, 55 PSI. Shut annular with cement at bit. Squeeze 30 bbls cement & 1 bbl water @ 3 BPM, 45 PSI ICP, 375 PSI FCP. 190 PSI trapped at pumps off, bleed down to 126 PSI in 3 min. Bleed off pressure and R/D cement head.;Pull 8 stands f/ 5817' t/ 5072' with proper hole fill. Pump 25 bbl sweep with nut plug @245 GPM, 500 PSI 5.9% flow to clean drillpipe. Slow to 225 GPM, 375 PSI with nut plug out of pipe. 27 bbls. lost when cleaning pipe.;Monitor well on trip tank - 21 bbls back from well. Losses from cleaning pipe appear to be breathing.;TIH f/ 5072' t/5817' with 6-1/8" cement squeeze assembly. Break circulation and establish parameters: 87 GPM, 124 PSI, 140K PU, 105K SO. Tag cement at 5868' w/ 3-5K (2x).;Wash and ream down f/5817' t/5927'; stage up to 151 GPM, 321 PSI, 9.2 ppg MW, 60 RPM, 7K tq, 115K ROT. No mud losses and did not tag anything until bottom at 5927', set down 5K at 5927' to confirm bottom of hole. Pick up and stage up to 221 GPM, 400 PSI and monitor for 15 min - no losses.;Perform flow check, well static. POOH f/ 5927' to surface and lay down 6-1/8" cement squeeze assembly, monitoring well on trip tank.;MU and RIH with 6-1/8" drilling assembly t/5000'. 9/12/2021 TIH f/ 6-1/8" drilling assembly f/ 5000' t/ 5876'.;Stage pumps up to 180 GPM, 850 PSI and circulate a bottoms up. Then wash f/ 5876' t/ 5927'.;Drill 6-1/8" production hole f/ 5927' t/ 5970'. 200 GPM, 1200 PSI, 70 RPM, 7K TQ, 3-9K WOB. Began seeing 44 BPH losses at 5962' while drilling a hard interval with slow ROP. Return flow dropped off and stopped drilling.;Build 40#/bbl LC pill (10#/bbl each of walnut med, Barafiber course, Baracarb 150 & Steelseal 400). Pump 28 bbl pill & spot on the open hole. POOH f/ 5970' t/ 5228'. Circulate @ 180 GPM, 890 PSI with 48% return flow @ 192 BPH losses until 28 bbls lost.;Allow LCM pill to soak for an hour. Circulate at 180 GPM and observe losses had slowed to 45 BPH. TIH f/ 5228' t/ 5970'. Orient toolface for slide and obtain SPRs with lower mud weight.;Drill 6-1/8" production hole f/ 5970' t/ 6065', 95' drilled, 31.67'/hr AROP. 220 GPM, 1275 PSI, 65 RPM, 7.5K TQ, 9-11K WOB. 150K PU / 115K SO / 130K ROT 36 BPH losses. ***AOGCC inspector Jim Regg waived witness of testing at 18:02 ***;Drill 6-1/8" production hole f/ 6065' t/ 6340', 275' drilled, 45.83'/hr AROP. 225 GPM, 1580 PSI, 67 RPM, 8.5K TQ, 4-8K WOB. 150K PU / 110K SO / 130K ROT 30 BPH losses. Pumping 10 BBL 40 PPB LCM pills every connection.;Drill 6-1/8" production hole f/ 6340' to section TD at 6630', 290' drilled, 58'/hr AROP. 231 GPM, 1650 PSI, 67 RPM, 8.5K TQ, 7-11K WOB. 150K PU / 110K SO / 130K ROT 30 BPH losses. Pumping 10 BBL 40 PPB LCM pills every connection.;Distance from WP04 at TD: 1.84': 1.84' high, 0.13' right.;Circulate hole clean, obtain final survey and take SPRs at TD. 228 GPM, 1390 PSI, 54 RPM, 8.5K TQ gy p *Notified AOGCC at 06:47 of upcoming BOP test for 13 Sept p drilling f/ 5807' t/ 5818' Hard slow w d ;Drill 6-1/8" production hole f/ 5970' t/ 6065', ;Drill 6-1/8" production hole f/ 6065' t/ 6340'*AOGCC inspector Jim Regg waived witness of testing Losses at 205 BPH N ;Drill 20' of 6-1/8" hole f/ 5847't/ 5867' ~325 BPH dynamic loss yp ;Static losses while allowing LCM pill to soak ~6 bph. p ;Drill 6-1/8" production hole f/ 6340' to section TD at 6630' 9/13/2021 Pump and spot 40 bbl 40#/bbl LCM pill in the open hole - 10# each of walnut medium, Barafiber course, Baracarb 150 and Steelseal 400). Perform flow check, observe well ballooning but flow slowed over 5 min.;POOH f/ 6630' t/ 4939'. Observe fluid level dropping during first 2 stands. Put on trip tank and trip took 3 bbls over displacement. Perform flow check @ 4939' - dropping. Pump dry job. POOH f/ 4939' t/ 62'. L/D BHA. Bit graded: 0-1-LT-C-E-I-ER-TD. 18.5 bbls lost on trip out.;Platform electrician tested Total Safety gas alarm system (H2S & LEL) on both the platform and jack-up - no failures.;Clean and clear rig floor. Mobilize B/U Hawk Jaw to the rig floor. Disconnect Hawk Jaw (welded pin fell out of jaw) and install B/U unit. Test unit - had to adjust some controls to work correctly. Remove broken Hawk Jaw for repairs.;M/U running tool, pup joint and drill pipe then pull wear bushing. Pump out BOP stack. Make up test assembly. Install test plug, and 4-1/2" test joint. Flush and fill stack, riser and choke manifold with water.;Test BOP stack and related equipment 250/3500 psi for 5/5 charted min. Test annular to 250/2500 psi for 5/5 charted min. All tests with 4-1/2" test joint. Test witnessed by Toolpusher and DSM, AOGCC Jim Reg waived witness of testing at 18:02 on 9/13/2021.;Pull test plug and install wear bushing. Rig down and blown down test equipment. 9/14/2021 Mobilize BHA components to the rig floor. M/U 6-1/8" bit, motor, XO and MWD directional, gamma, resistivity, density and porosity tools to 124'. RIH t/ 1762'.;Work on and swap out hawk jaw units w/ total of 3 bbl static loss.;RIH F/ 1762 T/ 3159'.;Kelly up brk circ stage up rate warm mud and orient towards window.;RIH F/ 3159' T/ 5850' w/ no issues at window or open hole. Filled pipe @ 4558'.;Log open hole as per Geologist F/ 5855' To TD at 6630'. 190 GPM, 1050 PSI, 180 FPH, 40 RPM @ 8K TQ. No hole issues or losses observed.;Pump HV nut plug sweep & circ hole clean. Sweep came back 10 bbl late with no increase in cuttings. Spot 40 BBL 40 PPB LCM pill. Monitor well. Static. no Losses.;POOH on elevators F/ 6630' T/4000'. No overpulls observed. 9/15/2021 Continue POOH on elevators F/4000' T/3150' No overpulls observed.;Attempt circ and just pressured up t/ 1300 psi ( pipe plugged ) surge and shake pipe and regain full circ and circ csg clean / trip in hole 5 std t/ 3620' pump dry job and drop 2-5/8" drift w/ SL tail / monitor well static.;Resume pooh on elevators and change brks on DP and look for cmt rings w/ no issues or cmt noticed T/ Mwd @ 155'.;Dn load tools and finish L/D Bha. brk bit & grade same.;Clean & clear rig floor, Service Rig.;R/U Weatherford 4.5 Liner equipment. M/U Pups & Xo to Cmt head. R/D Hawk Jaw and send off floor.;PJSM, M/U Float equipment and baker loc Same. Check floats. Good. P/U 4.5 liner to window at 3200' & Take up & Dwn wts. 80/80. P/U liner to 3569'.;Change handling equipment to 3.5 to pick up the ZXP liner hanger. P/U & Check set screws with baker rep. Good. Change handling equipment back to 4.5. & RIH one stand. Break circ at 230 GPM at 160 PSI. Circ one liner volume. Take ROT WT & TQ at 10 & 20 RPM. 85/80K at 4K TQ.;RIH with 4.5 Liner on 4.5 Dp F/ 3700' T/5400'. Filling pipe every 1000'. 9/16/2021 RIH with 4.5 Liner on 4.5 Dp F/5400' T/6592' Filling pipe every 1000'. last 10 stands very sticky.;P/U single / brk circ and stage up rate to 4 BPM. Pump 1.5 BTM up total. Work pipe f/ 100k over to block weight t/ 6615' with improving hole conditions and no losses.;P/U cmt head and hoses & clear cmt plug from manifold. Break circ & stage up pumps to 3 BPM. Wash dn work pipe & tag btm @ 6633' / PJSM w/ all involved in cmt job.;SLB flush line and pump 5 bbls ahead and brk circ / Test lines 550L / 5000H ok. Rig pumped 25 bbls of 12.5 ppg mud push while SLB batched up. SLB pumped 90.4 bbls of 15.3 ppg Gas block cmt. ( 431 SX). Flushed cmt line to shakers and launched dart was able to reciprocate pipe to right after dart.;Work pipe f/ 100k over to block weight before we hung pipe @6630' attempted to free pipe while SLB was pumping 10 bbls 12.5 mud push and and 10 bbls of 9.3 mud w/ no luck. Good indication of wiper plug latch up and good lift pressure t/ 859 psi then lost full returns @ 80 bbls displacement away.;Slow pum to 1 BPM p but never regained returns. Bump plug @ 97 bbls (.4 bbls over max ). Saw aired up mud in displacement tanks during the job. 526 PSI final lift at 1 BPM. CIP at 1300.;Pressured up t/ 2300 psi and SO t/ 90k and set hanger / pressured up to 3950 psi and seen good indication of pins sheer and prk set / bleed off pressure 1.5 bbls floats held / P/up and chk release ok.;Lost a total of 54 bbls lost during cmt job / blow dn cmt line while closing top rams and pumping dn kill and preforming a 1500 psi 10 min test on prk ok / R/dn cmt lines Put 625 psi on dp and Pull pack off and circ @ 7 bpm w/ no Mud push or cmt noticed.;Finish r/dn cmt lines and l/dn cmt head.;Pooh with 4.5 DP standing back in derrick. L/D & inspect running tool Good.;P/U cmt head & break down pups & XO. L/D Same. Clean & Clear rig floor.;Pull wear bushing, M/U & Flush stack with wash tool. L/D Same.;Strap & tally tubbing. Swap to completion report at 1800. gqp ;RIH with 4.5 Liner on 4.5 Dp F/ 3700' T/5400' pppg pp we hung pipe @6630' attempted to free pipe while SLB was pumping 10 bbls 12.5 mud push and and 10 bbls of 9.3 mud w/ no luck. j pp SLB pumped 90.4 bbls of 15.3 ppg Gas block cmt. ( 431 SX). () gp p pg circ @ 7 bpm w/ no Mud push or cmt noticed. pgppy yy Work pipe f/ 100k over to block weight t/ 6615' with improving hole conditions and no losses. Lost returns after 80 bbls displacement, no cement returns observed after disconnecting from liner and circ bottoms up. gp p p ;Lost a total of 54 bbls lost during cmt job qp p /U 4.5 liner to window at 3200' g Good indication of wiper plug latch up and good lift pressure t/ 859 psi then lost full returns @ 80 bbls displacement away. gpp @ p pp p p g p p p AOGCC Jim Reg waived witness of testing at 18:02 on 9/13/2021. Bump plug @ 97 bbls (.4 bbls over max ppg p g p ;Slow pum to 1 BPM p but never regained returns. p floats held / Wash dn work pipe & tag btm @ 6633' pg Activity Date Ops Summary 9/16/2021 Working on drilling report.,P/U cmt head & break down pups & XO. L/D Same Clean & Clear rig floor. Pull wear bushing, M/U & Flush stack with wash tool. L/D Same. Strap & tally tubbing.,Finish strap and tally 4.5 IBT tubing. R/U Weatherford casing equipment. Prep for completion run.,PJSM, P/U Baker bullet seal assembly & Run as per tally to 2632'. Make up tubing to thread mark for reference. 4300-4800 TQ. P/U SSSV. Pollard start R/U control line at report time. Clean pits & start mixing 2% KCL brine. Empty upper pits for displacement. R/U Lines in wellhead room to drain stack & perform MIT IA. 9/17/2021 Continue run 4-1/2" gas lift completion / Finish dressing and testing SSSV opening pressure 800 psi fully open @ 1800-2000 psi continue rih and no go out @ 3022' / Space out / rih dress hanger t/ 3012' / PJSM / change over well t/ inhibited FIW w/ 2% KCL / Pump out stack to production / Land out @ 2.58' off no-go /RILDS total 17 SS bands ran on control line. 75K UP & DN.,R/up test dn tbg while monitoring open annulus T/ 3035 psi W/ slight bleed off bump up once (air) t/ 3100 psi good 30 min test on chart / R/up and test dn annulus monitoring open dp t/ 3120 psi had slight bleed off bump up once (air) 3100 psi good 30 min test on chart witness waived by Mr. Jim Regg 9-15-21 @ 16:05 hrs.,B/O landing jt / install TWC and start nip/dn. Pull pitcher nipple & L/D Same. R/D choke and kill lines and valves.,N/D Annular & install 5' 13 5/8 spool extension. Install Annular. N/D BOPS & hang out of the way. Pull riser. Prep hanger. Install adaptor & hanger. Break down Tree and orientate valves for production line up. Test Void 500/5000 10 min. Good. Prep for Tree test. R/D mud service lines. Remove flow line & beaver slide. Prep for rig move. Swap to A-01 at 0600. 9/18/2021 Continue testing tree 500psi LOW / 5000psi HIGH 10min/10min TEST GOOD. 10/15/2021 Slickline crew conduct JSA and approve PTW. PT lubricator low/high,Rih w/ 4 1/2 Psr w/ 9' prong to 378' wl cant latch pooh. Rih w/ 4 1/2 Gs w/ 9' prong to 378' wl, latch valve pooh, ooh w/ valve. Valve covered in thick sticky grease. Rih w/ 3.75 to 5000' kb, tool begin to fall slow, fall much slower till 6100' finally set down @ 6340' kb, Rih w/ 3" X 3.5' DD Bailer to 6340' kb, pooh. Ooh w/ bailer full of what looks like drilling mud. Switch to A-4 End ticket. 10/16/2021 MIRU. Stay on same permit from previous well. PT lubricator low/high,Rih w/ 4 1/2 GS w/ 4 1/2 AD-2 stop to 2971' kb, set stop pooh. Rih w/ 4 1/2 Daniels KOT w/ 1 1/4 JDS to 2931' kb, latch valve pooh, ooh w/ dummy valve. Rih w/ same w/ jk w/ 1" Bk latch 5/16" oriface to 2931 w/t pooh, ooh w/ oriface. Rih w/ same, hand spang down for 10 min, beat down w/ unit for 10 min, shear off pooh, ooh no valve. Rih w/ 4 1/2 Gs to 2971' kb, latch AD-2 stop pooh, ooh w/ stop no valve.,Move over to A-4 10/19/2021 Standby for boat hauling coil tubing equipment 10/20/2021 Standby for first boat to arrive with CTU equipment,Offload first load of CTU equipment, boat departed platform at 2:00pm. Rig up and then standby for second load of equipment. 10/21/2021 Standby for Titan supply ship to arrive with last load of CT equipment.,Titan on location at 11:30, offload CT equipment and rig up. Perform BOP test to 250/4000psi. AOGCC waived witness per Jim Regg by email 8-19-12 8:47am. 10/22/2021 SLB CTU #1: Stab pipe in injector, MU Quadco 3.65" nozzle BHA, Nipple up BOPs to well A-03A, Pressure test lubricator and surface lines/choke to 350/4200psi.,RIH with nozzle BHA. Came online with drill water 100' above previous SL tag at 6,340'. RIH washing down at 25 F PM until hitting a bridge at 6,481' CTMD. Slowly worked down to 6,493' CTMD and then stopped making any progress. Circulated 120bbls then shut down the pump. RIH and dry tagged at 6,493' CTMD, Picked up and got weight back at 6490'. RKB corrected depth of tag was ~6521.5'. POOH and rigged down CTU.,RU AK wireline, PT PCE to 350/3,500psi, RIH with CBL and Log 4.5" liner. Estimated TOP of cement is 4,184', corrected PBTD 6,506'. 10/23/2021 Make up 3.65" milling BHA on CT. Stab on well and pressure test lube to 350/4200psi.,RIH with milling BHA and dry tag at 6,484', cleaned out 33' mud/cement (estimated cleanout depth based on EL tag is 6539'). Pumped a gel sweep on bottom and chased up hole. Opened circ sub with a 5/8" ball then blew well dry with N2. Had a total of 110bbls of liquid returns after shutting down.,POOH with milling BHA and Rigged down CTU. CBL reviewed by Bryan McLellan from AOGCC and perforating approved 10/23 at 17:50,RU AK Wireline. MU GR/CCL, firing head and check tools. MU 2-7/8" Geo Razor perf gun w/6spf and 60 degree phasing. Verify 14' shot to shot loading. Strap CCL to TS at 8.25'. Stab on well and pressure test to 350/3500psi. Open well, initial T/I/Os = 850/25/0.,RIH with perf gun run #1. Tagged TD and log up to 5,400' for correlation pass. Made a -7' field correction, and sent logs to town for review. Res Engineer requested +1' correction. RBIH and tagged TD, logged up hole above perf interval to verify tie in. RBIH and tagged TD, PUH to 6483.75' to put top shot on depth (requested TS 6,492'- 8.25'=6483.75). Fired gun #1 to perforate interval 6492-6506.,POOH with gun #1. WHP increased ~25psi after shooting. Take periodic WHP reading while POOH. 10/24/2021 Continue POOH with perf gun run #1. Lay down guns and confirm all shots fired correctly.,MU new firing head and check tools. MU 2-7/8" Geo Razor perf gun w/6spf and 60 degree phasing. Verify 14' shot to shot loading. Strap CCL to TS at 8.25'. Stab on well and RIH,RIH with perf gun run #2. Tagged TD and log correlation pass. Tie into GR/CCL signature from last tie in run. Confirm tie in and perf interval with Res Engineer. RBIH and tagged TD, PUH to 6447.75' to put top shot on depth (requested TS 6,456'- 8.25'=6447.75). Fired gun #2 to perforate interval 6456-6470'. WHP did not change after firing guns.,POOH with gun #2. Lay down guns and inspect. Guns had a light layer of wireline grease but no signs of sand or water. RDMO E-line unit. 10/25/2021 Rig up Pollard slickline. RIH with 3" DD sample bailer and tag bottom at 6,491' SLM. POOH and saw fluid level at ~ 4675' SLM. Recovered what appears to be sand and perf debris contaminated with EL grease. Collected a fluid and fill sample. MU 3.84" gauge ring and tag SSSV nip. Had 37' correction based on TBG tally. Corrected bailer run tag is 6,528'. RDMO SL n (LAT/LONG): evation (RKB): 50-883-20020-01-00API #: Well Name: Field: County/State: NCIU A-03A North Cook Inlet Hilcorp Energy Company Composite Report , Alaska Contractor AFE #: AFE $: Job Name:211-00030 A-03A Completion Spud Date: gg p p Fired gun #1 to perforate interval 6492-6506. p t witness waived by Mr. Jim Regg P/U Baker bullet seal py g assembly & Run as per tally to 2632'. M MIT-T MIT-IA pg g RIH with CBL and Log 4.5" liner. p Corrected bailer run tag is 6,528'. p Fired gun #2 to perforate interval 6456-6470'. pp test dn tbg while monitoring open annulus T/ 3035 psi W/ slight bleed off b pg Estimated TOP of cement is 4,184', corrected PBTD 6,506'. ggpgp p / change over well t/ inhibited FIW w/ 2% KCL / p P/U SSSV. 3100 psi good 30 min test on chart g p pp ( ) test dn annulus monitoring open dp t/ 3120 psi had slight bleed off bump up once (air) 3100 psi good 30 min test ggp pg CBL reviewed by Bryan McLellan from AOGCC and perforating approved 10/23 at 17:50,RU AK Wireline. 10/27/2021 MIRU E-line, run GPT tool and found fluid level at 4,600'. Depress fluid level with N2, and confirmed it was below 6,500' with GPT. POOH, lay down logging tools and MU 4.5" CIBP. RIH and correlated to gun #1 perf record. Set bottom of CIBP at 6,450' (CCL to plug bottom =160", CCL set depth =6436.7', Plug OAL=14.76"). POOH and lay down setting tool.,MU cement bailer with 9 gallons of cement, RIH and tag plug, PU and dump 14' of cement, EST top of cement =6434.8' POOH and RD E-line. 10/29/2021 AKEL crew assembles and obtains permit. MIRU e-line equipment and get spotted over well. Pressure test lubricator to 250 psi low and 3500 psi high.,Arm and RIH with 7' 2-7/8" HC gun while bleeding well down. Correlate to open hole log and send to town for correction. Correct depth (+1') and perforate Beluga G sand from 6397-6404'. POOH. 150 psi on well when shot, 5 minute reading: 200 psi, 10 minute: 300 psi, 15 minute: 400 psi. Bleed well at surface and read high LELs.,Un-stab from riser and lay down gun, all shots fired. Lay down lubricator and change out grease tubes for smaller ones. Re-head.,Arm and RIH with 14' 2- 7/8" HC gun. Correlate to open hole log and send to town for correction. Correct depth (-1') and perforate Beluga F Lower sand from 6353-6367'. POOH. 410 psi on well when shot, 5 minute reading: 411 psi, 10 minute: 412 psi, 15 minute: 412 psi.,Un-stab from riser and lay down 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 F Mid sand from 6317-6331. POOH. 415 psi on well when shot, 5 minute reading: 416 psi, 10 minute: 416 psi, 15 minute: 416 psi.,Un-stab from riser and lay down gun, all shots fired. Lay down lubricator and SDFN. 10/30/2021 Crew attends morning meeting and obtains permits. Warm up equipment and discuss wind levels with crane operator, good to continue operations.,Arm and RIH with 16' 2-7/8" HC gun. Correlate to open hole log and send to town for correction. Correct depth (+1') and perforate Beluga F Upper 2 from 6288-6304'. Well flowing 1.5 mmscf @ 378 psi when shot, increased to 1.7 mmscf @ 381 psi. POOH.,Un-stab from riser and lay down gun, all shots fired. Arm and RIH with 6' 2- 7/8" HC gun. Correlate to open hole log and send to town for correction. On depth. Attempt to perforate but firing circuit is shorted. POOH.,Un-stab from riser and lay down gun. Troubleshoot and find detonator wires broke off at detonator bulkhead. Re-arm 6' 2-7/8" gun and RIH. Correlate to open hole log and send to town for correction. On depth. Perforate Beluga F Upper 1 from 6274-6280'. Well flowing 1.7 mmcf at 384 psi. Static response. POOH.,Un-stab from riser and lay down 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. Correct depth (+1') and perforate Beluga E Lower from 6194-6214'. Well flowing 1.75 mmcf at 386 psi. Static response. POOH.,Un-stab from riser and lay down gun, all shots fired. Arm and RIH with 6' 2- 7/8" HC gun. Correlate to open hole log and send to town for correction. On depth. Perforate Beluga E Mid from 6169-6175'. Well flowing 1.75 mmcf at 386 psi. Static response. POOH.,Un-stab from riser and lay down 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. On depth. Perforate Beluga E Upper from 6107-6127'. Well flowing 1.75 mmcf at 382 psi. Static response. POOH.,Un-stab from riser and lay down gun, all shots fired. Troubleshoot telemetry problem with gun-gamma. Tool will not power up and will have to be sent to shore. Lay down lubricator, put night cap on well and SDFN. 10/31/2021 Crew attends morning meeting and obtains permits. Warm up equipment and discuss plan with crane operator. High wind gusts and crew issues, stand by till daylight. Service tools and clean up location.,New crew arrives at facility. JSA for new crew on facility and job specifics. Arm 13' 2-7/8" gun and get ready to RIH. Swab valve is leaking. Service swab valve and valve is holding.,RIH with gun string and correlate to open hole log. Send pass to town for correction. On depth. Perforate Beluga D Lower from 6067-6080'. Well flowing 1.6 mmcf at 375 psi. Static response. POOH.,Un-stab from riser and lay down gun, all shots fired. Wait on crane to unload barge.,Arm 6' 2-7/8" gun and RIH. Correlate to open hole log and send to town for correction. Correct depth (+1') and perforate Beluga D Mid 3 from 6018-6024'. Well flowing 1.6 mmcf at 375 psi. Static response. POOH.,Un-stab from riser and lay down gun, all shots fired. Lay down gun and lubricator. Secure well and SDFN. 11/1/2021 Crew assembles, attends morning meeting and obtains permit. Warm up equipment and pick up lubricator.,Notify production and they pinched back well to 1.5 mmscf. Arm and RIH with 12' 2-7/8" HC gun. Correlate to open hole log and send to town for correction. On depth. Perforate Beluga D Mid 2 from 6000-6012'. Well flowing 1.55 mmcf @ 366 psi. After 5 minutes: 1.65 mmcf @ 375 psi, 10 minutes: 1.6 mmcf @ 377 psi, 15 minutes: 1.6 mmcf @ 375 psi. POOH.,Un-stab from riser and lay gun down. All shots fired. Arm and RIH with 6' 2-7/8" HC gun. Correlate to open hole logs and send to town f or correction. On depth. Perforated Beluga D Mid 1 from 5984-5990'. Well flowing 1.6mmcf @ 380 psi. Static response. POOH.,Un-stab from riser and lay gun down. All shots fired. Arm and RIH with 8' 2-7/8" HC gun. Correlate to open hole logs and send to town for correction. On depth. Perforated Beluga D Upper from 5932-5940'. Well flowing 1.6 mmcf @ 376 psi. After 5 minutes flowing 1.62 mmcf @ 378 psi. POOH.,Un-stab from riser and lay gun down. All shots fired. 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 B Mid 2 from 5693-5703'. Well flowing 1.62 mmcf @ 378 psi. Stabilized to 1.71 mmcf @ 397 psi. POOH.,Un-stab from riser and lay gun down. All shots fired. Arm and RIH with 10' 2-7/8" HC gun. Correlate to open hole logs and send to town for correction. On depth. Perforated Beluga B Mid 1 from 5673-5683', Well flowing 1.72 mmcf @ 398 psi. No change after perforating.,Un- stab from riser and lay gun down. All shots fired. Arm and RIH with 10' 2-7/8" HC gun. Correlate to open hole logs and send to town for correction. On depth. Perforated Beluga B Upper from 5595-5605', Well flowing 1.72 mmcf @ 398 psi. No change after perforating.,Un-stab from riser and lay gun down. All shots fired. Arm and RIH with 17' 2-7/8" HC gun. Correlate to open hole logs and send to town for correction. On depth. Perforated Beluga A Lower from 5526-5543'. Well flowing 1.7 mmcf @ 392 psi. No change after perforating. POOH.,Un-stab from riser and lay gun down. All shots fired. Arm and RIH with 12' 2-7/8" HC gun. Correlate to open hole logs and send to town for correction. Correct depth (-1') and perforate Beluga A Mid from 5480-5492'. Well flowing 1.7 mmcf @ 392 psi. No change after perforating. POOH,Un-stab from riser and inspect gun, all shots fired. Lay down lubricator, secure location and SDFN. 11/2/2021 Pollard slickline crew arrives at facility and obtains permit.,Spot slickline equipment. Pressure test lubricator to 250 psi low and 1000 psi high.,MU and RIH with 4" brush and work across SSSV nipple. Set up and RIH with WRSSSV and set in nipple. Good shear indicating tool is set. Wait for production to test valve. Pressure up to 4000 psi and pressure gradually bleeds to about 3700 psi then falls off. Repeat tests and pressure fall off gets worse each time. POOH with valve and redress packing.,RIH with WRSSSV and set in nipple. Good shear indicating tool is set. Production attempts to test valve again but will not hold pressure. Shear off valve and leave in profile overnight in hope that packing swells and seals. POOH. Lay down lubricator, secure well and SDFN. 11/3/2021 Crew attends morning meeting and obtains permit. Warm up equipment.,Pressure up on control line, still not holding. POOH with WRSSSV. Test tool on bench, good test. Re-pack tool and RIH. Set WRSSSV in nipple. Pressure up on control line to 4000 psi and pressure bleeds off slowly to 3700 psi. Keep pressuring up and purging lines to troubleshoot. Eventually system holds open solid at 4000 psi.,Operations flows well and bleeds pressure off control line, valve closes, good test. Shear off SSSV and POOH. Move over to A-02. p ,MU cement bailer with 9 gallons of cement, yg perforate Beluga A Mid from 5480-5492'. pg perforate Beluga G sand from 6397-6404'. pgg Shear off SSSV and POOH. g Perforate Beluga D Lower from 6067-6080'. p Set bottom of CIBP at 6,450' yg Perforate Beluga E Upper from 6107-6127' g perforate Beluga F Lower sand from 6353-6367'. Perforate Beluga F Upper 1 from 6274-6280'. yg Perforate Beluga E Mid from 6169-6175'. Perforated yg Beluga D Mid 1 from 5984-5990' g yg Perforated Beluga A Lower from 5526-5543' yg Perforate Beluga F Mid sand from 6317-6331. g perforate Beluga D Mid 3 from 6018-6024'. yg Perforated Beluga D Upper from 5932-5940'. W yg Perforated Beluga B Upper from 5595-5605', p yp Perforate Beluga D Mid 2 from 6000-6012'. pg p perforate Beluga F Upper 2 from 6288-6304'. yg Perforated Beluga B Mid 1 from 5673-5683', g EST top of cement ) =6434.8' POOH yg perforate Beluga B Mid 2 from 5693-5703'. y perforate Beluga Eg Lower from 6194-6214'. W !" !"# "$% &''% ()* * $+ * ,- * * .* .* !" !" /!+*#$$ %&'()("* &+&, 0* !" *-./ / * %&'()("* &+&, ! * 0 !" . / * 1 * () /2* * 1 &2'3*45 , &2'3* --, 6!7 #0 01 8 . .( 0 +* +* 30* !0* 435$. 4 5$ (# .!* !" !)!! !)!! ' +9( 3'9)"& ""' &!2)7" &!&)!!.!+3*3")!! !)+! (&:7;"()"332 &+!:+(;+")'2('0 . 678 9+ 0! 6,8 0 678 !" /+ /0 8 9<"!<'!'& &+)'9 3")2& ++ '(9)!!!!!!!! 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enjamin Hand Digitally signed by Benjamin Hand Date: 2021.09.15 08:44:38 -08'00'Chelsea Wright Digitally signed by Chelsea Wright Date: 2021.09.15 10:43:44 -08'00' TD Shoe Depth: PBTD: Jts. Yes 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? Yes X No Spacer returns?Yes X No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped: Cmt returned to surface: Calculated cement left in wellbore: OH volume Calculated: OH volume actual: Actual % Washout: Casing (Or Liner) Detail Shoe 5 12.6 L-80 60.2660.26 Rotate Csg Recip Csg Ft. Min.PPG9.3 Shoe @ 6630 FC @ Top of Liner 30226,584.00 Floats Held 1.5 90.4 0 90.4 Mud CASING RECORD County State Alaska Supv.Shane Hauck Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.NCIU A-03A Date Run 16-Sep-21 Setting Depths Component Size Wt.Grade THD Make Length Bottom Top TC-II Baker 1.80 6,630.00 6,628.80 9.2 4 71 526FIRST STAGE12.5Mud Push II 25 97/95.8 1000 133 SLB Bump press CBL Bump Plug? 13:00 9/16/2021 4,184 6,630.006,630.00 CEMENTING REPORT Mud 15.3 90.4 www.wellez.net WellEz Information Management LLC ver_04818br Every Joint Full Joint 4 1/2 12.6 L-80 TC-II 41.86 6,628.20 6,586.34 Float Collar 5 TC-II Baker 1.55 6,586.34 6,584.79 Full Joint 4 1/2 12.6 L-80 TC-II 41.59 6,584.79 6,543.20 Landing Collar 5 12.6 L-80 TC-II Baker 1.10 6,543.20 6,542.10 4.5 Pipe 4 1/2 12.6 L-80 TC-II 3,428.16 6,542.10 3,054.47 XO 5 1.99 3,054.47 3,054.47 Flex loc Packer 5 3/4 9.48 3,054.47 3,044.99 XO 5 1/2 Baker 1.00 3,044.99 3,043.99 ZXP packer 6 Baker 21.98 3,043.99 3,022.01 Gas Blok Cmt 431 1.34 4 From:McLellan, Bryan J (OGC) To:Karson Kozub - (C) Cc:Juanita Lovett; Cody Dinger Subject:Re: [EXTERNAL] RE: NCIU A-03A (PTD 221-051) Sundry 321-435 CBL Log Date:Saturday, October 23, 2021 5:45:57 PM Hi Karson Thanks for the info. You guys are approved to move ahead with the perfs. Bryan Sent from my iPhone On Oct 23, 2021, at 4:07 PM, Karson Kozub - (C) <kkozub@hilcorp.com> wrote: Bryan, Thank you for the quick reply. We do have a liner top packer in A-03A, we will get the schematic corrected. We have a Baker HRD-E-HD ZXP Liner Top Packer. We did get a passing MITIA on 9/17. IA was tested to 3,100psi and charted for 30 min. Witness was waived for the MITIA on 9/15, attached is the email waiving witness. Regards, Karson KozubMobile: +1 (907) 570-1801kkozub@hilcorp.com From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Sent: Saturday, October 23, 2021 3:58 PM To: Karson Kozub - (C) <kkozub@hilcorp.com> Cc: Juanita Lovett <jlovett@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com> Subject: [EXTERNAL] RE: NCIU A-03A (PTD 221-051) Sundry 321-435 CBL Log Jake, Cement looks good for the perfs you are planning. A couple questions before you get the go-ahead: 1. Do you have a liner-top packer in this well? The wellbore diagram in the Sundry only shows a liner hanger, in which case you would have to have cement across the liner lap to act as a production packer. 2. Did you get a AOGCC-witnessed passing MITIA to 2900 psi? 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: Saturday, October 23, 2021 3:24 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com> Subject: NCIU A-03A (PTD 221-051) Sundry 321-435 CBL Log Good Afternoon Bryan, Attached is the CBL for NCIU A-03A. Top of cement is at 4184’, the top of the liner is at 3020’. Our top shot for perforating is 5,480’. Cement is sufficient above our zones we will be perforating starting the evening of 10/24. We should have the CBL’s for A-01A and A-04A in the next couple days. I’ll send them over when I get them. 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 forthe 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 suchvirus and other checks as it considers appropriate. <mime-attachment> 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-03A (PTD 221-051) CBL Perf GPT Plug 10/22/2021 Please include current contact information if different from above. 37' (6HW Received By: 11/22/2021 By Abby Bell at 1:18 pm, Nov 22, 2021 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-03A (PTD 221-051) FINAL LWD FORMATION EVALUATION LOGS (09/02/2021 to 09/15/2021) 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 1:29 pm, Sep 22, 2021 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 System Gas Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): ±8,254 (proposed)N/A Casing Collapse Structural Conductor Surface 630 psi Intermediate 2,090 psi Production 4,320 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) 570-1801 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 ±2,909 (proposed)7" ±8,254 (proposed)±6,867 (proposed) 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. 9/15/2021 N/A Daniel E. Marlowe N/A N/A ±3,200 (proposed) N/A Tubing Grade:Tubing MD (ft): N/A Perforation Depth TVD (ft): 8,430 psi Tubing Size: ±5,154 (proposed) 10-3/4"2,519' 612' ±3,200 (proposed) Perforation Depth MD (ft): 2,519' 4-1/2" 384' 612' 2,329' 384' 612' 3,200' 30" 16" 384' N/A TVD Burst N/A 4,980 psi MD 1,640 psi 221-051 50-883-20020-01-00Anchorage, AK 99503 Hilcorp Alaska, LLC N Cook Inlet Unit A-03A N/A±6,867 (proposed)±8,164 (proposed)±6,785 (proposed)2,884 psi COMMISSION USE ONLY Authorized Name: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 / ADL0037831 Other: G/L Completion / N2 Operations Authorized Signature: Operations Manager Karson Kozub CO 68A PRESENT WELL CONDITION SUMMARY Length Size 3,580 psi Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 8:07 am, Aug 30, 2021 321-435 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.08.28 06:24:01 -08'00' Dan Marlowe (1267) Drlg Rig BOP test to 3500 psi. Annular test to 2500 psi. DSR-8/30/21 X CT BOP test to 3500 psi. 10-407 Pressure test tubing and IA to 2900 psi (MPSP). Provide 48 hrs notice for AOGCC to witness tests. SFD 8/30/2021BJM 9/1/21 X dts 9/1/2021 JLC 9/2/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.09.02 14:03:41 -08'00' RBDMS HEW 9/3/2021 Well Work Prognosis Well Name:NCIU A-03A API Number:50-883-20020-01-00 Current Status:Producer Leg:Leg #3 SE Corner Estimated Start Date:9/15/2021 Rig:Spartan 151/Coil/EL Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:221-051 First Call Engineer:Karson Kozub (907) 570-1801 (M) Second Call Engineer:Katherine O’Connor (907) 777-8376 (O) (214) 684-7400 (M) Current Bottom Hole Pressure: 3,571 psi @ 6,867’ TVD 0.520psi/ft (10.0 ppg) Beluga U sands expected Maximum Expected BHP:3,571 psi @ 6,867’ TVD 0.520psi/ft (10.0 ppg) Beluga U sands expected Maximum Potential Surface Pressure: 2,884 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Brief Well Summary NCIU A-03A is a Beluga producer that will be completed with gas lift. This new well was sidetracked from the current NCIU A-03, 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 2,180psi under PTD 221-051 Procedure: 1. ***Take over operations from the Drilling Sidetrack Program PTD 221-051*** 2. Test BOP’s every 14 days continued from last test date from PTD 221-051 x Test to 250psi low/3,500psi 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. 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 Pressure test tubing, liner, and sealbore to 1,500psi for 30 min charted x Pressure test inner annulus to 1,500 psi for 30 min charted 5. Set BPV, ND BOPE, NU tree and test same 6. RDMO Spartan 151 7. RU E-line pressure test 250psi low/3,500psi high x run gamma/ccl/cbl. 8. R/U Coil tubing unit 9. Perform BOPE pressure test 250psi low/3,500psi high (Note: Notify AOGCC 48hrs in advance to allow them to witness) 10. RIH and clean out to PBTD ±8,254’ 11. Blow well dry with Nitrogen to production header or non-enclosed open top tank. x POOH, R/D Coil tubing. 12. RU E-line pressure test 250psi low/3,500psi high x perforate per program. Note: Deepest zone will be perforated 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. 13. Turn over to production. 14. Schedule SVS testing with AOGCC as per regulations Attachments: 1. Well Schematic Current 2. Well Schematic Proposed 3. Wellhead Schematic Provide 48 hrs notice for AOGCC witness. PT tbg and IA to 2900 psi. bjm Well Work Prognosis 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 06/25/21 SCHEMATIC North Cook Inlet Well:NCI A-03 Last Completed: 06-08-21 PTD:168-099 API:50-883-20020-00 PBTD: 3,981’ TD: 7,480’ 11 30” RKB: 39’, RKB to MSL: 115.9’ RKB to Mudline: 235.9’ 7” CI-A A B C D E G TOC 3,260’ 7” Stage Collar 5,114” 10-3/4” 16” 10 15 H I J W Top of tubing 4,003’ V P O N M L K U T S R Q X EE Y CC Z BB AA DD CI-2.0 CI-1.0 CI-3.1 CI-4.0 CI-5.0 CI-6.0 CI-7.0 CI-7.1 CI-8.0 CI-8.2 CI-9.0 CI-10.0 CI-11.0 B-6 C-3 D-4 F-1, F-2, F-4 G-1, G-5 H-1, H-9 I-3 J-2 K-4 N-5 O-4 Q3, Q4 CI-B 8 9 16 17 7 CI-X CI-Stray 3 CI-Stray 1 CI-Stray 212 14 Tubing Punch @ 3,908’ – 3,911’ 13 Tubing Patches 3,788’- 3,809’ + 3,870’ – 3,882’ ID 1.875” TOC @ 3,265’Tubing cut @ 3,754’ F XN X XN X CASING DETAIL Size Wt Grade Conn ID Top Btm 30” Conductor 29.000 Surf 384’ 16” 65 H-40 15.250 Surf 612’ 10-3/4” 45.50 & 51 J-55 BTC 9.794 Surf 2,519’ 7” 26 J-55 BTC 6.276 Surf 79’ 23 J-55 BTC 6.366” 79’ 6,818’ 26 J-55 BTC 6.276” 6,818’ 7,475’ TUBING DETAIL 3-1/2” 9.2 L-80 IBT 2.992 Surf 166’ 2-7/8” 6.5 L-80 EUE 8 rnd 2.441 3,754 3,962’ 4-1/2” 12.60 J-55 EUE Mod 3.958 4,003’ 6,289’ 2-7/8” Gravel Pack Liner 6.40 L-80 SLHT 2.441 4,135’ 4,527’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 3,265’ 2,966’ 16 BBL Cement placed on top of packer –TOC @ 3,265’ 3,754’ 3,395’ Tubing cut 73,759’3,399’2.440” 5.970”Packer – MFH Hydraulic Retrievable straight pull release 30K shear 83,8723,496’2.310” 3.180”Sliding Sleeve - PetroQuip, APCV-II Model D (Opens Down) –CLOSED and Gas Cut. No Isolation 9 3,888’ 3,509’ 2.313” 3.670” X-Nipple 10 3,900’3,519’2.440” 5.970”Packer – MFH Hydraulic Retrievable straight pull release 30K shear 11 3,919’3,535’2.310” 3.180”Sliding Sleeve - PetroQuip, APCV-II Model D (Opens Down)SLEEVE CLOSED 12 3,935’ 3,548’ 2.313” 3.670” X-Nipple 13 3,939’ 3,552’ Tubing plug w/ top AA stop 14 3,954’3,564’2.440” 5.970”Packer – MFH Hydraulic Retrievable straight pull release 30K shear 15 3,961’ 3,570’ 2.205” 3.670” XN Nipple 16 3,962’ 3,571’ 2.450” 3.700” WLEG 17 3,988’ 3,592’ EZSV w/ 7’ of cement on top (TOC 3,981’) A 4,135’ 3,713' 2.500 Baker 40A-25 SC-1 GP Packer 4,139’ 3,716' 2.500 20-25 Mod S Gravel Pack Ext w/ Sliding Sleeve 4,146’ 3,722' 2.992 16 Ft Lower Extension 4,193’ 3,760' 2.441 2-7/8” Excluder 2000 Screen – Med (337’) B 4,198’ 3,764' 3.990 5.560 No Go Seal Assembly C 4,199’ 3,764' 4.000 5.870 Halliburton TWR Packer D 4,501’ 4,007' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed E 4,525’ 4,026' 3.990 5.560 No Go Seal Assembly F 4,526’ 4,027' N/A 2.875” Bull Plug G 4,527’ 4,028' 4.000 5.870 Halliburton TWR Packer & Millout Extension H 4,586’ 4,074' 3.813 5.560 Halliburton XD Sliding Sleeve – Closed (w/PX Plug) I 4,594’ 4,081' 3.990 5.560 No Go Seal Assembly J 4,595’ 4,081' 4.000 5.870 Halliburton TWR Packer & Millout Extension K 4,658’ 4,131' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed L 4,668’ 4,139' 3.990 5.560 No Go Seal Assembly M 4,669’ 4,140' 4.000 5.870 Halliburton TWR Packer & Millout Extension N 4,744’ 4,199' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed O 4,750’ 4,203' 3.990 5.560 No Go Seal Assembly P 4,751’ 4,204' 4.000 5.870 Halliburton TWR Packer & Millout Extension Q 4,825’ 4,262' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed R 4,831’ 4,267' 3.990 5.560 No Go Seal Assembly S 4,832’ 4,267' 4.000 5.870 Halliburton TWR Packer & Millout Extension T 4,885’ 4,309' 3.990 5.560 No Go Seal Assembly U 4,886’ 4,310' 4.000 5.870 Halliburton TWR Packer & Millout Extension V 4,929’ 4,343' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed W 4,935’ 4,348' 3.990 5.560 No Go Seal Assembly X 4,936’ 4,349' 4.000 5.870 Halliburton TWR Packer & Millout Extension Y 5,046’ 4,435' 3.813 5.560 Halliburton XD Sliding Sleeve –Open 12/13/2001 Z 5,105’ 4,481' N/A 4.500 Set 4.5” EZSV Bridge Plug AA 5,113’ 4,487' 3.990 5.560 No Go Seal Assembly BB 5,114’ 4,488' 4.000 5.870 Halliburton TWR Packer & Millout Extension CC 5,626’ 4,898' 3.813 5.560 Halliburton XA Sliding Sleeve - Closed DD 6,288’ 5,424' 3.725 5.560 Halliburton XN Landing Nipple EE 6,289’ 5,425' 3.980 Wireline Re-Entry Guide Notes: 12/07/2007 – Set TTGP on Top of fill @4,532’ (Tagged 15’ high) 01/20/2011 – 9.98’ difference in elevation is due to being set on Electric Log Depths ____________________________________________________________________________________ Updated By: JLL 06/25/21 SCHEMATIC North Cook Inlet Well:NCI A-03 Last Completed: 06/08/21 PTD:168-099 API:50-883-20020-00 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT SPF Date Status CI-X 3,790’ 3,806’ 3,427’ 3,439’ 16’ 6 06/07/21 Isolated CI-Stray 1 3,915’ 3,921’ 3,532’ 3,537’ 6’ 6 06/07/21 Isolated CI-A 3,930' 3,931' 3,544' 3,545' 1' 4 06/07/21 Cmt Sqz CI-Stray 2 3,933’ 3,937’ 3,547’ 3,550’ 4’ 6 06/07/21 Isolated CI-Stray 3 3,946’ 3,951’ 3,557’ 3,562’ 5’ 6 06/07/21 Isolated CI-A 3,964’ 3,979’ 3,572’ 3,585’ 15’ 6 06/07/21 Isolated CI-A 3,964' 3,979' 3,572' 3,585' 15' 12 3/14/1969 Isolated CI-B 4,000' 4,025' 3,602' 3,623' 25' 12 3/14/1969 Isolated CI-B 4,055' 4,070' 3,647' 3,660' 15' 4 3/14/1969 Isolated CI-B 4,100' 4,101' 3,684' 3,685' 1' 4 3/14/1969 Cmt Sqz CI-B 4,178' 4,179' 3,748' 3,748' 1' 4 3/14/1969 Cmt Sqz CI-1.0 4,205' 4,280' 3,769' 3,830' 75' 12 11/8/2007 Isolated CI-1.0 4,210' 4,280' 3,773' 3,830' 70' 12 9/1/1994 Isolated CI-1.0 4,281' 4,299' 3,831' 3,845' 18' 4 11/7/2007 Isolated CI-2.0 4,300' 4,375' 3,846' 3,907' 75' 12 11/7/2007 Isolated CI-2.0 4,376' 4,401' 3,907' 3,927' 25' 1 11/7/2007 Isolated CI-3.1 4,401' 4,427' 3,927' 3,948' 26' 1 11/7/2007 Isolated CI-3.1 4,428' 4,440' 3,949' 3,958' 12' 12 11/6/2007 Isolated CI-3.1 4,441' 4,453' 3,959' 3,969' 12' 1 11/6/2007 Isolated CI-4.0 4,453' 4,473' 3,969' 3,985' 20' 1 11/6/2007 Isolated CI-4.0 4,474' 4,494' 3,986' 4,002' 20' 16 11/6/2007 Isolated CI-4.0 4,495' 4,520' 4,002' 4,022' 25' 1 11/4/2007 Isolated CI-5.0 4,552' 4,582' 4,047' 4,071' 30' 12 9/1/1994 Isolated CI-6.0 4,630' 4,640' 4,109' 4,117' 10' 12 9/1/1994 Isolated CI-7.0 4,692' 4,697' 4,158' 4,162' 5' 12 9/1/1994 Isolated CI-7.1 4,730' 4,737' 4,188' 4,193' 7' 12 9/1/1994 Isolated CI-8.0 4,778' 4,788' 4,225' 4,233' 10' 12 9/1/1994 Isolated CI-8.2 4,810' 4,820' 4,250' 4,258' 10' 12 9/1/1994 Isolated CI-9.0 4,850' 4,875' 4,281' 4,301' 25' 12 9/1/1994 Isolated CI-10.0 4,900' 4,925' 4,321' 4,340' 25' 12 9/1/1994 Isolated CI-11.0 4,950' 4,995' 4,360' 4,395' 45' 12 9/1/1994 Isolated B-6 5,254' 5,261' 4,599' 4,605' 7' 12 9/1/1994 Isolated (EZSV Bridge Plug) B-7 5,279' 5,284' 4,619' 4,623' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) C-3 5,418' 5,423' 4,730' 4,734' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) D-3 5,565' 5,570' 4,849' 4,853' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) D-4 5,596' 5,603' 4,873' 4,879' 7' 12 9/1/1994 Isolated (EZSV Bridge Plug) F-1 & F-2 5,834' 5,844' 5,064' 5,072' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) F-4 5,870' 5,880' 5,092' 5,100' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) G-1 5,961' 5,971' 5,164' 5,172' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) G-5 6,043' 6,058' 5,229' 5,241' 15' 12 9/1/1994 Isolated (EZSV Bridge Plug) H-1 6,070' 6,080' 5,251' 5,259' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) H-9 6,227' 6,252' 5,375' 5,395' 25' 12 9/1/1994 Isolated (EZSV Bridge Plug) I-3 6,284' 6,289' 5,421' 5,425' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) J-2 6,414' 6,421' 5,525' 5,530' 7' 4 3/14/1969 Isolated (EZSV Bridge Plug) K-4 6,514' 6,529' 5,605' 5,618' 15' 4 3/14/1969 Isolated (EZSV Bridge Plug) N-5 6,898' 6,908' 5,917' 5,925' 10' 4 3/14/1969 Isolated (EZSV Bridge Plug) O-4 7,033' 7,040' 6,026' 6,032' 7' 4 3/14/1969 Isolated (EZSV Bridge Plug) Q-3 & Q-4 7,212' 7,237' 6,172' 6,193' 25' 4 3/14/1969 Isolated (EZSV Bridge Plug) ____________________________________________________________________________________ Updated by: JLL 08/27/21 PROPOSED North Cook Inlet Unit Well:NCI A-03A Last Completed: FUTURE PTD:221-051 API:50-883-20020-01-00 PBTD: ±8,164’ MD 30” RKB: 39’, RKB to MSL: 115.9’ RKB to Mudline: 235.9’ 7” 3 4 5 10-3/4” 16” 4-1/2” Beluga A-U 1 2 TD: ±8,254’ MD X CASING DETAIL Size Wt Grade Conn ID Top Btm 30” Conductor 29.000 Surf 384’ 16” 65 H-40 15.250 Surf 612’ 10-3/4” 45.50 & 51 J-55 BTC 9.794 Surf 2,519’ 7” 26 J-55 BTC 6.276 Surf 79’ 23 J-55 BTC 6.366” 79’ ±3,200’ (KOP) 4-1/2” 12.6 L-80 TC II ±3,100’ ±8,254’ TUBING DETAIL 4-1/2”Surf ±3,100’ PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status Beluga A-U ±5,400’ ±8,100’ ±4,372’ ±6,727’ ±2,700’ Future Proposed JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 1 ±370’ ±370’ SSSV 2 ±1,400’ ±1,380’ GLM 3 ±3,040’ ±2,771’ GLM 4 ±3,070’ ±2,797’ X Nipple 5 ±3,100’ ±2,823’ Baker Liner Hanger / Seal Bore Proposed Wellhead 04/01/2021 NCIU A-03 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-03 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 1. BOP Schematic 2. Choke Manifold Schematic Coiled 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-03A (PTD 221-051)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 From:McLellan, Bryan J (CED) To:Sean Mclaughlin Subject:RE: Change in A-03A fluids program Date:Tuesday, August 31, 2021 9:14:00 AM Sean, This sounds good. Your planned Mud weight is still above prognosed pore pressure, so you can proceed as planned below. Could you give me a status update of current operations on A-03A? 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: Sean Mclaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Monday, August 30, 2021 9:36 AM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Subject: Change in A-03A fluids program Bryan, The A-03A PTD stated the fluid weight would be 10.3 ppg for the entire hole section. An updated plan will more closely follow reservoir pressures. The revised fluids plan is below. Mill window with 9.5 ppg (0.44 psi/ft pressure gradient at window) 2910’ TVD and 8.5 ppg EMW Drill to the Beluga H with 9.5 ppg mud weight (0.44 psi/ft pressure gradient to the Beluga H/I) ~5,484’ TVD and 8.5 ppg EMW MASP – 1865 psi Kick Tolerance (14.7 ppg FIT and 0.5 ppg intensity) - 43 bbls Weight up to 10.3 ppg prior to drilling out of the Beluga H/I (same horizon A-04A was drilled to) Drill to TD in the Beluga U (0.52 psi/ft) No change to programed MASP or kick tolerance Regards, sean Sean McLaughlin Hilcorp Alaska, LLC Drilling Engineer Sean.McLaughlin@hilcorp.com Cell: 907-223-6784 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual 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 (CED) To:Sean Mclaughlin Subject:RE: Pulling A-03A kill string Date:Wednesday, August 25, 2021 5:52:00 PM Sean, Yes, as long as a 4-1/2” landing joint is used to unseat the kill string tubing hanger. Bryan 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: Sean Mclaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Wednesday, August 25, 2021 1:45 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Subject: Pulling A-03A kill string Bryan, The current BOPE test plan on A-03A is to test with a 4.5” test joint. There are 4 joints of 3.5” kill string in the well. The well has been plugged and tested. The current plan is to test BOPE then pull and recover the 4 joints without testing the VBR’s or annular to 3.5”. That operation wasn’t highlighted in the PTD. Is the AOGCC agreeable to the plan? Regards, sean Sean McLaughlin Hilcorp Alaska, LLC Drilling Engineer Sean.McLaughlin@hilcorp.com Cell: 907-223-6784 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual 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 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Monty M. Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: North Cook Inlet Field, Tertiary System Gas Pool, NCIU A-03A Hilcorp Alaska, LLC Permit to Drill Number: 21-051 Surface Location: 1250' FNL, 1090' FWL, Sec. 06, T11N, R09W, SM, AK Bottomhole Location: 2405' FNL, 2499' FWL, Sec. 01, T11N, R10W, SM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced 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 August, 2021. Jeremy Price Digitally signed by Jeremy Price Date: 2021.08.02 13:23:26 -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: 8,254' TVD: 6,867' 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: 5,139' 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10.KB Elevation above MSL (ft): 116.0'15.Distance to Nearest Well Open Surface: x-332109 y- 2586728 Zone- 4 N/A to Same Pool: 2,014' 16.Deviated wells: Kickoff depth: 3,200 feet 17.Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 50 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 5,154' 3,100' 2,824' 8,254' 6,867' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): None TVD 384' 612' 2,329' 6,388' 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: Sean McLaughlin Monty Myers Contact Email:sean.mclaughlin@hilcorp.com Drilling Manager Contact Phone:777-8401 Date: Permit to Drill API Number: Permit Approval Number: 50-883-20020-01-00 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 August 15, 2021 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): 612' Driven 384' 612'16" 735 sx Class 'G' Effect. Depth MD (ft): Effect. Depth TVD (ft): Authorized Title: Authorized Signature: 2,519' 1050 sx Class 'G'Production Liner 2,519' 7,475' Intermediate Authorized Name: None Conductor/Structural 30"384' 7,480'6,392' LengthCasing See Schematic Cement Volume MDSize Plugs (measured): (including stage data) 736 ft3 3,265' 2,966' 8328 18.Casing Program: Top - Setting Depth - BottomSpecifications 2884 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 1933 2254' FNL, 1668' FEL, Sec. 01, T11N, R10W, SM, AK 2405' FNL, 2499' FWL, Sec. 01, T11N, R10W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp Alaska, LLC 1250' FNL, 1090' FWL, Sec. 06, T11N, R09W, SM, AK ADL 017589 & 037831 NCIU A-03A North Cook Inlet Unit Tertiary System Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. 1245 sx Class 'G' 7,475'7" 10-3/4" Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) 7.15.2021 By Samantha Carlisle at 2:06 pm, Jul 15, 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: 2021.07.15 13:10:57 -08'00' Monty M Myers BJM 7/30/21 BOP Test to 3500 psi. Annular Test to 2500 psi. SFD SFD 221-051 SFD 7/16/2021 Pressure test Liner-lap to 2180 psi (50% burst of 7") - AOGCC witnessed Review FIT/LOT results with AOGCC before drilling sidetrack. DSR-7/15/21 dts 8/2/2021 JLC 8/2/2021 8/2/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.08.02 13:24:03 -08'00' NCI A-03A Well Program Tyonek Sean McLaughlin Revision 0 July 12, 2021 NCI A-03A PTD 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 .......................................................................................................................... 8 8. Mandatory Regulatory Compliance / Notifications ...................................................................... 9 9. R/U and Preparatory Work......................................................................................................... 11 10. BOP N/U and Test ....................................................................................................................... 12 11. Mud Program and Density Selection Criteria ............................................................................ 13 12. Set Whipstock / Mill Window ...................................................................................................... 14 13. Drill 6-1/8” Hole Section .............................................................................................................. 15 14. Run 4-1/2” Production Liner ....................................................................................................... 16 15. Cement 4-1/2” Production Liner ................................................................................................. 19 16. Wellbore Clean Up & Displacement ........................................................................................... 22 17. Run Completion Assembly .......................................................................................................... 22 18. RD ................................................................................................................................................ 22 19. BOP Schematic ............................................................................................................................ 23 20. Wellhead Schematic (current) ..................................................................................................... 24 21. Days vs Depth ....................................................................................Error! Bookmark not defined. 22. Geo-Prog ............................................................................................Error! Bookmark not defined. 23. Anticipated Drilling Hazards ...................................................................................................... 25 24. Rig Layout .........................................................................................Error! Bookmark not defined. 25. FIT Procedure.............................................................................................................................. 27 26. Choke Manifold Schematic ......................................................................................................... 28 27. Casing Design Information .......................................................................................................... 30 28. 6-1/8” Hole Section MASP ........................................................................................................... 30 29. Plot (NAD 27) (Governmental Sections) ..................................................................................... 32 30. Slot Diagram ................................................................................................................................ 33 31. Directional Program (wp05) - Attached separately .........................Error! Bookmark not defined. Page 2 Revision 0 July 12, 2021 NCI A-03A PTD Rev 0 1. Well Summary Well NCI A-03A Pad & Old Well Designation Sidetrack of existing well A-03 (PTD#168-099) Planned Completion Type 4-1/2” 12.6#Liner, 4-1/2” Tubing GL Comp Target Reservoir(s) Beluga B-U Kick off point 3,200’ MD / 2,909’ TVD Planned Well TD, MD / TVD 8,254’ MD / 6,867’ TVD PBTD, MD 8,164’ MD Surface Location (Governmental) 1250' FNL, 1090' FWL, Sec 6, T11W, R9W, SM, AK Surface Location (NAD 27) X=332109.43, Y=2586728.31 Surface Location (NAD 83) Top of Productive Horizon (Governmental) 2254' FNL, 1668' FEL, Sec 1, T11N, R10W, SM, AK TPH Location (NAD 27) X=329336.54 Y=2585765.06 TPH Location (NAD 83) BHL (Governmental) 2405' FNL, 2499' FWL, Sec 1, T11N, R10W, SM, AK BHL (NAD 27) X=328222.23, Y=2585630.55 BHL (NAD 83) AFE Number AFE Days 26 AFE Drilling Amount Work String 4.5” 16.6# S-135 CDS40 RKB –AMSL 116’ MSL to ML 101’ 3,200’ MD / 2,909’ TVD 8,254’ MD / 6,867’ TVD Page 3 Revision 0 July 12, 2021 NCI A-03A PTD Rev 0 2. Management of Change Information Date: July 12, 2021 Subject: Changes to Approved Permit to Drill for NCI A-03A File #: NCI A-03A Drilling Program Any modifications to NCI A-03A 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 July 12, 2021 NCI A-03A PTD 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 3,100’ 8,254’ **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 July 12, 2021 NCI A-03A PTD 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 when aggregating end of well reports. 2. Afternoon Updates x Submit a short operations update each work day to 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: C: (907) 252-7855 iii. Mark Tornai: C: (907) 748-3299 iv. Tyler Pruitt: C: (907) 513-9903 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 7 Revision 0 July 12, 2021 NCI A-03A PTD Rev 0 Planned Wellbore Schematic LTP is planned - bjm Liner-top packer is planned ____________________________________________________________________________________ Updated by: JLL 06/25/21 SCHEMATIC North Cook Inlet Well: NCI A-03 Last Completed: 06-08-21 PTD: 168-099 API: 50-883-20020-00 ____________ PBTD: 3,981’ TD: 7,480’ 11 30” RKB: 39’, RKB to MSL: 115.9’ RKB to Mudline: 235.9’ 7” CI-A Whipstock set @ 3,200’ A B C D E G TOC 3,260’ 7” Stage Collar 5,114” 10-3/4” 16” 10 15 H I J W Top of tubing 4,003’ V P O N M L K U T S R Q X EE Y CC Z BB AA DD CI-2.0 CI-1.0 CI-3.1 CI-4.0 CI-5.0 CI-6.0 CI-7.0 CI-7.1 CI-8.0 CI-8.2 CI-9.0 CI-10.0 CI-11.0 B-6 C-3 D-4 F-1, F-2, F-4 G-1, G-5 H-1, H-9 I-3 J-2 K-4 N-5 O-4 Q3, Q4 CI-B 8 9 16 17 7 CI-X CI-Stray 3 CI-Stray 1 CI-Stray 2 12 14 Tubing Punch @ 3,908’ – 3,911’ 13 Tubing Patches 3,788’- 3,809’ + 3,870’ – 3,882’ ID 1.875” TOC @ 3,265’ Tubing cut @ 3,754’ F XN X XN X __________________________________________________________API: 50 883 20020 00 CASING DETAIL Size Wt Grade Conn ID Top Btm 30” Conductor 29.000 Surf 384’ 16” 65 H-40 15.250 Surf 612’ 10-3/4” 45.50 & 51 J-55 BTC 9.794 Surf 2,519’ 7” 26 J-55 BTC 6.276 Surf 79’ 23 J-55 BTC 6.366” 79’ 6,818’ 26 J-55 BTC 6.276” 6,818’ 7,475’ TUBING DETAIL 3-1/2” 9.2 L-80 IBT 2.992 Surf 166’ 2-7/8” 6.5 L-80 EUE 8 rnd 2.441 3,754 3,962’ 4-1/2” 12.60 J-55 EUE Mod 3.958 4,003’ 6,289’ 2-7/8” Gravel Pack Liner 6.40 L-80 SLHT 2.441 4,135’ 4,527’ JEWELRY DETAIL No Depth (MD) Depth (TVD) ID OD Item 3,200’ 2,909’ Whipstock 3,265’ 2,966’ 16 BBL Cement placed on top of packer – TOC @ 3,265’ 3,754’ 3,395’ Tubing cut 7 3,759’ 3,399’2.440” 5.970” Packer – MFH Hydraulic Retrievable straight pull release 30K shear 8 3,872 3,496’2.310” 3.180” Sliding Sleeve - PetroQuip, APCV-II Model D (Opens Down) –CLOSED and Gas Cut. No Isolation 9 3,888’ 3,509’ 2.313” 3.670” X-Nipple 10 3,900’ 3,519’2.440” 5.970” Packer – MFH Hydraulic Retrievable straight pull release 30K shear 11 3,919’ 3,535’2.310” 3.180” Sliding Sleeve - PetroQuip, APCV-II Model D (Opens Down) SLEEVE CLOSED 12 3,935’ 3,548’ 2.313” 3.670” X-Nipple 13 3,939’ 3,552’ Tubing plug w/ top AA stop 14 3,954’ 3,564’2.440” 5.970” Packer – MFH Hydraulic Retrievable straight pull release 30K shear 15 3,961’ 3,570’ 2.205” 3.670” XN Nipple 16 3,962’ 3,571’ 2.450” 3.700” WLEG 17 3,988’ 3,592’ EZSV w/ 7’ of cement on top (TOC 3,981’) A 4,135’ 3,713' 2.500 Baker 40A-25 SC-1 GP Packer 4,139’ 3,716' 2.500 20-25 Mod S Gravel Pack Ext w/ Sliding Sleeve 4,146’ 3,722' 2.992 16 Ft Lower Extension 4,193’ 3,760' 2.441 2-7/8” Excluder 2000 Screen – Med (337’) B 4,198’ 3,764' 3.990 5.560 No Go Seal Assembly C 4,199’ 3,764' 4.000 5.870 Halliburton TWR Packer D 4,501’ 4,007' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed E 4,525’ 4,026' 3.990 5.560 No Go Seal Assembly F 4,526’ 4,027' N/A 2.875” Bull Plug G 4,527’ 4,028' 4.000 5.870 Halliburton TWR Packer & Millout Extension H 4,586’ 4,074' 3.813 5.560 Halliburton XD Sliding Sleeve – Closed (w/PX Plug) I 4,594’ 4,081' 3.990 5.560 No Go Seal Assembly J 4,595’ 4,081' 4.000 5.870 Halliburton TWR Packer & Millout Extension K 4,658’ 4,131' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed L 4,668’ 4,139' 3.990 5.560 No Go Seal Assembly M 4,669’ 4,140' 4.000 5.870 Halliburton TWR Packer & Millout Extension N 4,744’ 4,199' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed O 4,750’ 4,203' 3.990 5.560 No Go Seal Assembly P 4,751’ 4,204' 4.000 5.870 Halliburton TWR Packer & Millout Extension Q 4,825’ 4,262' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed R 4,831’ 4,267' 3.990 5.560 No Go Seal Assembly S 4,832’ 4,267' 4.000 5.870 Halliburton TWR Packer & Millout Extension T 4,885’ 4,309' 3.990 5.560 No Go Seal Assembly U 4,886’ 4,310' 4.000 5.870 Halliburton TWR Packer & Millout Extension V 4,929’ 4,343' 3.813 5.560 Halliburton XD Sliding Sleeve - Closed W 4,935’ 4,348' 3.990 5.560 No Go Seal Assembly X 4,936’ 4,349' 4.000 5.870 Halliburton TWR Packer & Millout Extension Y 5,046’ 4,435' 3.813 5.560 Halliburton XD Sliding Sleeve – Open 12/13/2001 Z 5,105’ 4,481' N/A 4.500 Set 4.5” EZSV Bridge Plug AA 5,113’ 4,487' 3.990 5.560 No Go Seal Assembly BB 5,114’ 4,488' 4.000 5.870 Halliburton TWR Packer & Millout Extension CC 5,626’ 4,898' 3.813 5.560 Halliburton XA Sliding Sleeve - Closed DD 6,288’ 5,424' 3.725 5.560 Halliburton XN Landing Nipple EE 6,289’ 5,425' 3.980 Wireline Re-Entry Guide PBTD:3,981’ TD:7,480’ Notes: 12/07/2007 – Set TTGP on Top of fill @4,532’ (Tagged 15’ high) 01/20/2011 – 9.98’ difference in elevation is due to being set on Electric Log Depths Page 6 Revision 0 July 12, 2021 NCI A-03A PTD Rev 0 Proposed Whipstock Schematic Superseded ____________________________________________________________________________________ Updated By: JLL 06/25/21 SCHEMATIC _______________________ North Cook Inlet Well: NCI A-03 Last Completed: 06/08/21 PTD: 168-099 API: 50-883-20020-00 ____________ PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT SPF Date Status CI-X 3,790’ 3,806’ 3,427’ 3,439’ 16’ 6 06/07/21 Isolated CI-Stray 1 3,915’ 3,921’ 3,532’ 3,537’ 6’ 6 06/07/21 Isolated CI-A 3,930' 3,931' 3,544' 3,545' 1' 4 06/07/21 Cmt Sqz CI-Stray 2 3,933’ 3,937’ 3,547’ 3,550’ 4’ 6 06/07/21 Isolated CI-Stray 3 3,946’ 3,951’ 3,557’ 3,562’ 5’ 6 06/07/21 Isolated CI-A 3,964’ 3,979’ 3,572’ 3,585’ 15’ 6 06/07/21 Isolated CI-A 3,964' 3,979' 3,572' 3,585' 15' 12 3/14/1969 Isolated CI-B 4,000' 4,025' 3,602' 3,623' 25' 12 3/14/1969 Isolated CI-B 4,055' 4,070' 3,647' 3,660' 15' 4 3/14/1969 Isolated CI-B 4,100' 4,101' 3,684' 3,685' 1' 4 3/14/1969 Cmt Sqz CI-B 4,178' 4,179' 3,748' 3,748' 1' 4 3/14/1969 Cmt Sqz CI-1.0 4,205' 4,280' 3,769' 3,830' 75' 12 11/8/2007 Isolated CI-1.0 4,210' 4,280' 3,773' 3,830' 70' 12 9/1/1994 Isolated CI-1.0 4,281' 4,299' 3,831' 3,845' 18' 4 11/7/2007 Isolated CI-2.0 4,300' 4,375' 3,846' 3,907' 75' 12 11/7/2007 Isolated CI-2.0 4,376' 4,401' 3,907' 3,927' 25' 1 11/7/2007 Isolated CI-3.1 4,401' 4,427' 3,927' 3,948' 26' 1 11/7/2007 Isolated CI-3.1 4,428' 4,440' 3,949' 3,958' 12' 12 11/6/2007 Isolated CI-3.1 4,441' 4,453' 3,959' 3,969' 12' 1 11/6/2007 Isolated CI-4.0 4,453' 4,473' 3,969' 3,985' 20' 1 11/6/2007 Isolated CI-4.0 4,474' 4,494' 3,986' 4,002' 20' 16 11/6/2007 Isolated CI-4.0 4,495' 4,520' 4,002' 4,022' 25' 1 11/4/2007 Isolated CI-5.0 4,552' 4,582' 4,047' 4,071' 30' 12 9/1/1994 Isolated CI-6.0 4,630' 4,640' 4,109' 4,117' 10' 12 9/1/1994 Isolated CI-7.0 4,692' 4,697' 4,158' 4,162' 5' 12 9/1/1994 Isolated CI-7.1 4,730' 4,737' 4,188' 4,193' 7' 12 9/1/1994 Isolated CI-8.0 4,778' 4,788' 4,225' 4,233' 10' 12 9/1/1994 Isolated CI-8.2 4,810' 4,820' 4,250' 4,258' 10' 12 9/1/1994 Isolated CI-9.0 4,850' 4,875' 4,281' 4,301' 25' 12 9/1/1994 Isolated CI-10.0 4,900' 4,925' 4,321' 4,340' 25' 12 9/1/1994 Isolated CI-11.0 4,950' 4,995' 4,360' 4,395' 45' 12 9/1/1994 Isolated B-6 5,254' 5,261' 4,599' 4,605' 7' 12 9/1/1994 Isolated (EZSV Bridge Plug) B-7 5,279' 5,284' 4,619' 4,623' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) C-3 5,418' 5,423' 4,730' 4,734' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) D-3 5,565' 5,570' 4,849' 4,853' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) D-4 5,596' 5,603' 4,873' 4,879' 7' 12 9/1/1994 Isolated (EZSV Bridge Plug) F-1 & F-2 5,834' 5,844' 5,064' 5,072' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) F-4 5,870' 5,880' 5,092' 5,100' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) G-1 5,961' 5,971' 5,164' 5,172' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) G-5 6,043' 6,058' 5,229' 5,241' 15' 12 9/1/1994 Isolated (EZSV Bridge Plug) H-1 6,070' 6,080' 5,251' 5,259' 10' 12 9/1/1994 Isolated (EZSV Bridge Plug) H-9 6,227' 6,252' 5,375' 5,395' 25' 12 9/1/1994 Isolated (EZSV Bridge Plug) I-3 6,284' 6,289' 5,421' 5,425' 5' 12 9/1/1994 Isolated (EZSV Bridge Plug) J-2 6,414' 6,421' 5,525' 5,530' 7' 4 3/14/1969 Isolated (EZSV Bridge Plug) K-4 6,514' 6,529' 5,605' 5,618' 15' 4 3/14/1969 Isolated (EZSV Bridge Plug) N-5 6,898' 6,908' 5,917' 5,925' 10' 4 3/14/1969 Isolated (EZSV Bridge Plug) O-4 7,033' 7,040' 6,026' 6,032' 7' 4 3/14/1969 Isolated (EZSV Bridge Plug) Q-3 & Q-4 7,212' 7,237' 6,172' 6,193' 25' 4 3/14/1969 Isolated (EZSV Bridge Plug) Page 8 Revision 0 July 12, 2021 NCI A-03A PTD Rev 0 6. Drilling Summary A-03 is a non-producing gas production well planned to be sidetracked to down space Beluga sands between A-03 and A-09 and step to the West. The previous completion will be pulled and the wellbore abandoned to 3,265’ slm (Sundry 321-160). At 3,200’ MD the parent wellbore will be sidetracked and new wellbore drilled to 8,254’. 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 August 15th, 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-03 2. NU BOPE and test to 3500 psi. (MASP 2875 psi) 3. Recover tubing hanger and 3-1/2” kill string (4 joints) 4. Make bit and Scrapper run to 3,250’. 5. Set whipstock at 3,200’ and 30L. Swap well to 10.3 ppg LSND mud. 6. Mill window with 20’ of new formation. 7. Perform FIT to 14.7 ppg EMW 8. PU 6-1/8” motor drilling assembly and TIH to window. 9. Drill 6-1/8” production hole to 8,254 MD, performing short trips as needed 10. POOH w/ directional tools. RIH w/ 4-1/2” liner. Set liner and cement. Circ wellbore clean. 11. PU liner cleanout assembly and TIH to landing collar. 12. Circ liner clean. POOH laying down DP. 13. Run 4-1/2” completion. (Covered under separate sundry) 14. Land hanger and test. 15. ND BOPE, NU tree and test void Perform FIT to 14.7 ppg EMW Page 9 Revision 0 July 12, 2021 NCI A-03A PTD Rev 0 7. 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-03A. Ensure to provide AOGCC 48 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3500 psi & subsequent tests of the BOP equipment will be to 250/3500 psi for 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 3571 psi in the Beluga U sand (6867' TVD). MASP is 2884 psi with 0.1psi/ft gas in the wellbore. o 7” casing tested to 2950 psi on 6/9/21 x Minimum required Rated Working Pressure (RWP) the BOPE must meet or exceed: 3000 psi x If the BOP is used to shut in on the well in a well control situation,ALL BOP components utilized for well control must be tested 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. Page 10 Revision 0 July 12, 2021 NCI A-03A PTD 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: 250/3500 (Annular 2500 psi) Subsequent Tests: 250/3500 (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 (N/A for sidetrack) 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) Page 11 Revision 0 July 12, 2021 NCI A-03A PTD Rev 0 8. 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 6” liners installed in mud pump #1 and pump #2. (PZ-10’s) x Gardner Denver PZ-10’s Pumps are rated at 4932 psi (98%) with 6” liners and can deliver 422 gpm at 115 spm. x Pump range for drilling will be 150-300 gpm. This can be achieved with one or both pumps. Page 12 Revision 0 July 12, 2021 NCI A-03A PTD Rev 0 9. 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 250/3500 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. to 250/3500 psi for 5/5 min. Test annular to 250/2500 psi p Test VBRs on 4.5” test joint. Page 13 Revision 0 July 12, 2021 NCI A-03A PTD Rev 0 10. 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:10.3 ppg LNSD WBM Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 3,200’- TD 10.3-10.5 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. 10.3 ppg LNSD WBM Page 14 Revision 0 July 12, 2021 NCI A-03A PTD Rev 0 11. 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. Operation Steps: 1. Pull hanger and 4 joints of 3-1/2”, L-80, IBT kill string. 2. Set wear bushing in wellhead. Ensure ID of wear bushing > 6-1/8”. 3. Make a bit and scrapper run to 3,250’ to ensure the whipstock setting area is clen. 4. Make up the BOT WindowMaster Hydraulic Whipstock. 5. TIH with DP to the whipstock setting depth. Exercise caution when RIH / setting slips with whipstock assembly ¾Fill the drill pipe a minimum of every 20 stands on the trip in the hole with the whipstock assembly. ¾Avoid sudden starts and stops while running the whipstock. ¾Recommend 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. 6. Orient whipstock as directed by the directional driller. The directional plan specifies 30 deg LOHS. 7. Set the top of the whipstock at ~3,200’ MD 8. Mill window plus 20’-50’ of new hole (DO NOT EXCEED 50’ OF NEW HOLE BEFORE RUNNING THE PLANNED FIT/LOT). ¾Use ditch magnets to collect the metal shavings. Clean regularly. ¾Ensure any personnel working around metal shavings wear proper PPE, including goggles, face shield and Kevlar gloves. ¾Work 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. 9. Pull starter mill into casing above top of whipstock, flow check the well for 10 minutes and conduct a FIT to 14.7 ppg. ¾**Assuming the kick zone is at TD, a FIT of 14.7 ppg EMW gives a Kick Tolerance volume of 24.8 bbls with 10.3 ppg mud weight. Send FIT chart to Drilling Engineer immediately upon test conclusion. Monitor OA pressure for signs of communication during FIT. Notify AOGCC if pressure communication is evident, as remedial cement job may be required to isolate OA during drilling. Review FIT results with AOGCC before proceeding with sidetrack. Minimum of 13.5 ppg LOT required. a FIT of 14.7 ppg EMW gives a Kick Tolerance volume of 24.8 bblsg with 10.3 ppg mud weight. Page 15 Revision 0 July 12, 2021 NCI A-03A PTD Rev 0 10. POOH and LD milling assembly ¾Once out of the hole, inspect mill gauge and record. ¾Flow check well for 10 minutes to confirm no flow: ¾Before pulling off bottom. ¾Before pulling the BHA through the BOPE. 11. Flush the stack/lines to remove metal debris that may have settled out in these areas. Ensure BOP equipment is operable. 12. Drill 6-1/8” Hole Section 1. PU 8300’ of 4-1/2” CDS40 Drill pipe for drilling 6-1/8” hole section 2. P/U 4-3/4” 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. Plan to pump at 150 - 300 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” KM322. 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 10.3 ppg LNSD to warm up mud until good 10.3 ppg in and 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. Sperry Sun triple combo (density, porosity, and resistivity) per S. McLaughlin. SFD 7/16/2021 ” Sperry Sun motor drilling assy w/ triple combo Page 16 Revision 0 July 12, 2021 NCI A-03A PTD Rev 0 14. Drill 6-1/8” hole to 8,254’ 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. 13. 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 Centralizers will be run on 4-1/2” liner x Ensure proper operation of float shoe & FC. Page 17 Revision 0 July 12, 2021 NCI A-03A PTD Rev 0 4. Continue running 4-1/2” production liner to TD Page 18 Revision 0 July 12, 2021 NCI A-03A PTD Rev 0 x Short joint run every 1000’ 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” window prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure. 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. Liner already in open hole, before making up DP. p Baker ZXP liner hanger / packer assy, Page 19 Revision 0 July 12, 2021 NCI A-03A PTD Rev 0 14. 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 131 bbls of 15.3 ppg EasyBLOK per below recipe with xx lbs/bbl of loss circulation fiber. Ensure cmt is pumped at designed weight. Job is designed to pump 50% OH excess but if wellbore conditions dictates otherwise we may increase excess volumes. Cement volume is designed to bring cement to 3100’ 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*3100 =44), (4-1/2” Liner (.0152 * 5064 = 77)),Total 121 bbls Cement Calculations 6-1/8” OH x 4.5” Liner:(8254’ – 3100’) x 0.01677 x 1.5 = 130 bbls Shoe Track:90’ x 0.0152 = 1.4 bbls Total Volume (bbls):92.3 + 1.4 = 131 bbls Total Volume (ft3):131 bbls x 5.615 ft3/bbl = 736 ft3 Total Volume (sx):736 ft3 / 1.34 ft3/sk = 549 sx Job is designed to pump 50% OH excess b Total 121 bbls 12.5 ppg spacer. Displacement volume verified - bjm Cement calcs verified - bjm cement to 3100’ TMD Page 20 Revision 0 July 12, 2021 NCI A-03A PTD Rev 0 Slurry Information: System EasyBLOK 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 10.3 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 21 Revision 0 July 12, 2021 NCI A-03A PTD 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 Verify the liner top packer r Page 22 Revision 0 July 12, 2021 NCI A-03A PTD 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 15. Wellbore Clean Up & Displacement x No cleanout planned. Service coil will cleanout, displace mud, and blow down well with N2 prior to perforating. x Test liner lap to 1500 psi after cement has reached 500 psi compressive strength. 16. Run Completion Assembly 1. Run 4-1/2” tubing completion assembly as per separate Approved Completion Sundry 17. RD x Install BPV in wellhead. RILDs. x ND BOPE, NU tree, test void x Rig Down y as per separate Approved Completion Sundry Pressure test liner lap to 2180 psi (50% burst of 7"). Provide 48 hrs notice for AOGCC to witness liner-lap pressure test. - bjm Page 23 Revision 0 July 12, 2021 NCI A-03A PTD Rev 0 18. BOP Schematic Page 24 Revision 0 July 12, 2021 NCI A-03A PTD Rev 0 19. Wellhead Schematic (current) Page 25 Revision 0 July 12, 2021 NCI A-03A PTD Rev 0 20. 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.10 ppg EMW prognosed pore pressure - bjm Page 26 Revision 0 July 12, 2021 NCI A-03A PTD Rev 0 21. Jack up position Page 27 Revision 0 July 12, 2021 NCI A-03A PTD Rev 0 22. 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 28 Revision 0 July 12, 2021 NCI A-03A PTD Rev 0 23. Choke Manifold Schematic Page 29 Revision 0 July 12, 2021 NCI A-03A PTD Rev 0 Page 30 Revision 0 July 12, 2021 NCI A-03A PTD Rev 0 24. Casing Design Information 25. 6-1/8” Hole Section MASP Page 31 Revision 0 July 12, 2021 NCI A-03A PTD Rev 0 Page 32 Revision 0 July 12, 2021 NCI A-03A PTD Rev 0 26. Plot (NAD 27) (Governmental Sections) Page 33 Revision 0 July 12, 2021 NCI A-03A PTD Rev 0 27. Slot Diagram 6WDQGDUG3URSRVDO5HSRUW -XO\ 3ODQ1&,$$ZS +LOFRUS$ODVND//& 1RUWK&RRN,QOHW 1RUWK&RRN,QOHW8QLW 3ODQ1&,8$ 3ODQ1&,$$ 2600 2925 3250 3575 3900 4225 4550 4875 5200 5525 5850 6175 6500 6825True Vertical Depth (650 usft/in)325 650 975 1300 1625 1950 2275 2600 2925 3250 3575 3900 4225 4550 4875 5200 Vertical Section at 253.40° (650 usft/in) A-03A wp01 Beluga B A-03A wp01 Beluga U 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 5 0 005 5 0 0 6 0 0 0 6 5 0 0 7 0 0 0 7 4 8 0 A-03 7" TOW 4 1/2" x 6 1/8"350040004500500055006 0 0 0 6 5 0 0 7 0 0 0 7 5 0 0 8 0 0 0 8 2 5 4 NCI A-03A wp03 KOP : Start Dir 12.3º/100' : 3200' MD, 2908.83'TVD : 30° LT TF End Dir : 3217' MD, 2923.35' TVD Start Dir 4º/100' : 3237' MD, 2940.27'TVD End Dir : 3702.1' MD, 3288.15' TVD Start Dir 3º/100' : 5225.6' MD, 4258.3'TVD End Dir : 6309.58' MD, 5091.33' TVD Total Depth : 8253.94' MD, 6867.43' TVD Top CI 1 Top Beluga B T Beluga U 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: Plan: NCIU A-03 Water Depth: 101.00 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 2586728.31 332109.43 61° 4' 36.378 N 150° 56' 53.296 W SURVEY PROGRAM Date: 2021-05-06T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 700.00 3200.00 N COOK INLET UNIT A-03 (NCI A-03) 3_CB-Film-GSS 3200.00 8253.94 NCI A-03A wp03 (Plan: NCI A-03A) 3_MWD+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 3791.00 3675.00 4491.76 Top CI 1 4526.20 4410.20 5622.13 Top Beluga B 6757.20 6641.20 8133.27 T Beluga U REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: NCIU A-03, True North Vertical (TVD) Reference:NCI A-03 @ 116.00usft Measured Depth Reference:NCI A-03 @ 116.00usft Calculation Method:Minimum Curvature Project:North Cook Inlet Site:North Cook Inlet Unit Well:Plan: NCIU A-03 Wellbore:Plan: NCI A-03A Design:NCI A-03A wp03 CASING DETAILS TVD TVDSS MD Size Name 2909.69 2793.69 3201.00 7 7" TOW 6867.42 6751.42 8253.94 4-1/2 4 1/2" x 6 1/8" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 3200.00 30.40 253.17 2908.83 -293.36 -1059.46 0.00 0.00 1099.12 KOP : Start Dir 12.3º/100' : 3200' MD, 2908.83'TVD : 30° LT TF 2 3217.00 32.23 251.20 2923.35 -296.07 -1067.87 12.30 -30.00 1107.95 End Dir : 3217' MD, 2923.35' TVD 3 3237.00 32.23 251.20 2940.27 -299.51 -1077.97 0.00 0.00 1118.61 Start Dir 4º/100' : 3237' MD, 2940.27'TVD 4 3702.10 50.45 245.40 3288.15 -415.12 -1360.88 4.00 -14.15 1422.76 End Dir : 3702.1' MD, 3288.15' TVD 5 5225.60 50.45 245.40 4258.30 -904.16 -2428.92 0.00 0.00 2586.00 Start Dir 3º/100' : 5225.6' MD, 4258.3'TVD 6 5606.36 45.00 259.00 4515.00 -991.24 -2695.41 3.00 122.89 2866.26 A-03A wp01 Beluga B 7 6309.58 24.01 262.95 5091.33 -1056.97 -3085.89 3.00 175.53 3259.25 End Dir : 6309.58' MD, 5091.33' TVD 8 8121.01 24.01 262.95 6746.00 -1147.39 -3817.47 0.00 0.00 3986.16 A-03A wp01 Beluga U 9 8253.94 24.01 262.95 6867.43 -1154.02 -3871.16 0.00 0.00 4039.51 Total Depth : 8253.94' MD, 6867.43' TVD -1633-1400-1167-933-700-467-233South(-)/North(+) (350 usft/in)-3733 -3500 -3267 -3033 -2800 -2567 -2333 -2100 -1867 -1633 -1400 -1167 -933 -700West(-)/East(+) (350 usft/in)A-03A wp01 Beluga UA-03A wp01 Beluga BA-037" TOW4 1/2" x 6 1/8"3 0 0 0 3 2 5 0 3 5 0 0 3 7 5 0 4 0 0 0 4 2 5 0 4 5 0 0 4 7 5 0 5 0 0 0 5 2 5 0 5 5 0 0 5 7 5 0 6 0 0 0 6 2 5 0 6 5 0 0 6 7 5 0 6 8 6 7NCI A-03A wp03KOP : Start Dir 12.3º/100' : 3200' MD, 2908.83'TVD : 30° LT TFEnd Dir : 3217' MD, 2923.35' TVDStart Dir 4º/100' : 3237' MD, 2940.27'TVDEnd Dir : 3702.1' MD, 3288.15' TVDStart Dir 3º/100' : 5225.6' MD, 4258.3'TVDEnd Dir : 6309.58' MD, 5091.33' TVDTotal Depth : 8253.94' MD, 6867.43' TVDProject: North Cook InletSite: North Cook Inlet UnitWell: Plan: NCIU A-03Wellbore: Plan: NCI A-03APlan: NCI A-03A wp03WELL DETAILS: Plan: NCIU A-03Water Depth: 101.00+N/-S +E/-W NorthingEastingLatitudeLongitude0.00 0.002586728.31332109.4361° 4' 36.378 N150° 56' 53.296 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: NCIU A-03, True NorthVertical (TVD) Reference: NCI A-03 @ 116.00usftMeasured Depth Reference:NCI A-03 @ 116.00usftCalculation Method:Minimum CurvatureCASING DETAILSTVD TVDSS MD Size Name2909.69 2793.69 3201.00 7 7" TOW6867.42 6751.42 8253.94 4-1/2 4 1/2" x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Procedures Req.WELL DETAILS:Plan: NCIU A-03 NAD 1927 (NADCON CONUS)Alaska Zone 04Water Depth: 101.00+N/-S +E/-W Northing EastingLatitudeLongitude0.000.002586728.31332109.4361° 4' 36.378 N150° 56' 53.296 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: NCIU A-03, True NorthVertical (TVD) Reference:NCI A-03 @ 116.00usftMeasured Depth Reference:NCI A-03 @ 116.00usftCalculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2021-05-06T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool700.00 3200.00 N COOK INLET UNIT A-03 (NCI A-03) 3_CB-Film-GSS3200.00 8253.94 NCI A-03A wp03 (Plan: NCI A-03A) 3_MWD+Sag0.0035.0070.00105.00140.00175.00Centre to Centre Separation (60.00 usft/in)3300 3600 3900 4200 4500 4800 5100 5400 5700 6000 6300 6600 6900 7200 7500 7800 8100 8400Measured DepthNO GLOBAL FILTER: Using user defined selection & filtering criteria3200.00 To 8253.94Project: North Cook InletSite: North Cook Inlet UnitWell: Plan: NCIU A-03Wellbore: Plan: NCI A-03APlan: NCI A-03A wp03Ladder / S.F. PlotsCASING DETAILSTVD TVDSS MD Size Name2909.69 2793.69 3201.00 7 7" TOW6867.42 6751.42 8253.94 4-1/2 4 1/2" x 6 1/8" 1 Davies, Stephen F (CED) From:Sean Mclaughlin <Sean.Mclaughlin@hilcorp.com> Sent:Friday, July 16, 2021 9:43 AM To:Davies, Stephen F (CED) Cc:Rixse, Melvin G (CED) Subject:RE: [EXTERNAL] NCIU A-03A (PTD 221-051) - Question Hi Steve, We will run the 4‐3/4” Sperry Sun triple combo (density, porosity, and resistivity). There was just a brief one liner on page 14 in the drilling section. Regards, sean From: Davies, Stephen F (CED) <steve.davies@alaska.gov> Sent: Friday, July 16, 2021 9:29 AM To: Sean Mclaughlin <Sean.Mclaughlin@hilcorp.com> Cc: Rixse, Melvin G (CED) <melvin.rixse@alaska.gov> Subject: [EXTERNAL] NCIU A‐03A (PTD 221‐051) ‐ Question Sean, I’m reviewing Hilcorp’s application to drill NCIU A‐03A. Maybe I’ve overlooked something, but I don’t recall seeing an open‐hole well logging program in the application. Could you please provide one? Thanks and stay safe, Steve Davies Alaska Oil and Gas Conservation Commission (AOGCC) CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Revised 2/2015 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: ____________________________ POOL: ______________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit No. _____________, API No. 50-_______________________. Production should continue to be reported as a function of the original API number stated above. Pilot Hole In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name (_______________________PH) and API number (50-_____________________) from records, data and logs acquired for well (name on permit). Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation order approving a spacing exception. (_____________________________) as Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for well ( ) until after ( ) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (________________________) must contact the AOGCC to obtain advance approval of such water well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (_______________________________) in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. 221-051 NCIU A-03A Tertiary System Gas Pool X North Cook Inlet Unit WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:N COOK INLET UNIT A-03AInitial Class/TypeDEV / PENDGeoArea820Unit11450On/Off ShoreOffProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2210510NORTH COOK INLET, TERTIARY GAS - 564570NA1 Permit fee attachedYes ADL 017589 Surface location; ADL 037831 top prod interval and TD.2 Lease number appropriateYes3 Unique well name and numberYes NORTH COOK INLET, TERTIARY SYSTEM GAS POOL – 564570, governed by CO 68A4 Well located in a defined poolYes As planned, this well conforms to CO 68A, Rule 2 (Well Spacing).5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For servNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)NA Sidetrack18 Conductor string providedYes Offshore well19 Surface casing protects all known USDWsNA Sidetrack below out of existing surface casing.20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitYes25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedNA27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes 5K pressure rating. (BOP test to 3500 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not expected in this gas production well.35 Permit can be issued w/o hydrogen sulfide measuresYes No abnormal temperatures or pressures are expected.36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate7/16/2021ApprBJMDate7/30/2021ApprSFDDate7/16/2021AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate-03JLC 8/2/2021