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Home My WebLink About224-1211. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: ESP Swap Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 21,369 feet N/A feet true vertical 3,940 feet N/A feet Effective Depth measured 21,367 feet 11,447'feet true vertical 3,940 feet 3,940'feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)2-7/8" 6.5 / L-80 / EUE 8rd 11,407' 3,938' Packers and SSSV (type, measured and true vertical depth)SLZXP LTP and N/A N/A See Above N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Wells Manager Contact Phone: 8,830psi 5,020psi 5,750psi 9,190psi 11,634' 3,957' Burst N/A Collapse N/A 2,260psi 3,090psi Liner Liner 2,114' 7,807' Casing Conductor 3,954' 4-1/2" 13,561' 21,368' 3,940' 11,591' 3,916'Surface Intermediate 20" 13-3/8" 9-5/8" 127' 3,870' measured TVD 9,020psi 5-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 224-121 50-029-23802-00-00 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Hilcorp Alaska LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL025509, ADL355018 & ADL388235 MILNE POINT / SCHRADER BLUFF OIL MILNE PT UNIT R-104 Plugs Junk measured Length measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 2,204 Gas-Mcf MD 127' 0 Size 127' 2,263' 0450410 0 00 385 324-679 Sr Pet Eng: 8,540psi Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. N/A Taylor Wellman twellman@hilcorp.com 907-777-8449 Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 11:26 am, Jan 16, 2025 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2025.01.16 10:20:36 - 09'00' Taylor Wellman (2143) JJL 2/7/25 RBDMS JSB 012825 SFD 2/10/2025 DSR-1/16/25 _____________________________________________________________________________________ Revised By: TDF 1/14/2025 SCHEMATIC Milne Point Unit Well: MPU R-104 Last Completed: 11/11/2024 PTD: 224-121 TD =21,369’(MD) / TD =3,940’(TVD) 4 20” Orig. KB Elev.: 63.75’ / GL Elev.: 16.8’ 9-5/8” 11/12 5 2/3/4 13 13-3/8” 10 1 5-1/2” 2 3 See Screen/ Liner Detail PBTD =21,367’(MD) / PBTD = 3,940’(TVD) PB1: 11850’ – 12082’ 9 8 5/6/72-7/8” 4-1/2” CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X56 / Weld N/A Surface 127’ N/A 13-3/8” Surface 68 / L-80 / CDC 12.415 Surface 3,916’ 0.1497 9-5/8” Intermediate 40 / L-80 / BTC 8.835 Surface 11,634’ 0.0758 5-1/2” Liner 100ђ Screens 20 / L-80 / EZGO HT 4.892 11,447’ 13,561’ 0.0222 4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hyd 625 3.920 13,561’ 21,368’ 0.0149 TUBING DETAIL 2-7/8" Tubing 6.5# / L-80 / EUE 8-Rd 2.441 Surface 11,438’ 0.0058 OPEN HOLE / CEMENT DETAIL 42” 20 yds 16" Lead – 1617 sx / Tail – 598 sx 12-1/4” Lead – 579 sx / Tail – 272 sx 8-1/2” Uncemented Screen Liner WELL INCLINATION DETAIL KOP @ 158’ 90° Hole Angle = @ 11,850’ TREE & WELLHEAD Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead FMC 13-5/8” 5K w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: 50-029-23802-00-00 Completion Date: 11/26/2024 JEWELRY DETAIL No. Top MD Item ID 1 151’ 2-7/8” x 1” BK-2 GLM w/ DPSOV 2.440” 2 11,329’ Discharge Sub – Vigilant 2-7/8” 3 11,329.6’ Discharge Bolt – on 2-7/8” 4 11,330’ Pump: 538, SJ2800 5 11,354’ Pump Intake GS, 538 TDM H2X (SS) 6 11,361’ Upper Tandem Seal: 513 Series 7 11,370’ Lower Tandem Seal: 513 Series 8 11,379’’ Motor: 562 Series, KMS2, 360HP / 3175V / 70A 9 11,403’ Sensor: 177C 8KPSI, 2x Pres, Temp, Vib 10 11,405’ Anode Centralizer – Btm @ 11,407’ 11 11,447’ SLZXP LTP / Liner Hanger Lap ~178’ 6.190” 12 11,469 7” H563 x 5.5” JFE Bear XO 4.870” 13 21,367’ Shoe 5-1/2” x 4-1/2” SCREEN LINER DETAIL Size Top (MD) Top (TVD) Btm (MD) Btm (TVD) 5-1/2” 11,598’ 13,561’ 3,955’ 3,954 4-1/2” 13,562’ 13,976’ 3,954’ 3,966’ 4-1/2” 14,138’ 16,856’ 3,967’ 3,953’ 4-1/2” 17,138’ 17,837’ 3,972’ 3,951’ 4-1/2” 17,959’ 21,329’ 3,951’ 3,940’ Well Name Rig API Number Well Permit Number Start Date End Date MP R-104 ASR 50-029-023802-00-00 224-121 12/9/2024 12/14/2024 12/6/2024 - Friday No operations to report. 12/4/2024 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 12/5/2024 - Thursday No operations to report. Completed BOPE testing w/ two fail/pass tests. Fill pits W/ KWF. Hang ESP sheave and elephant trunk. Pull CTS and BPV. BOLDS. Pull hanger to the floor. Connector tested bad. Cut cable. Cable test good, balanced phase to phase. Sensor showing downhole reading. POOH T/ 11,238'. L/D GLM and 1 joint. Load GLM w/ DPSOV. RIH T/ 11,359. P/U M/U hanger. Complete hanger splice. Land Hanger while testing cable as landed. RILDS. End of ESP = 11,406'. P/U Tee bar install BPV. Remove 9.0 ppg brine from pits. Begin rigging down. Layover derrick on headache rack. Scope in leveling jacks. Remove all fluid lines from rig. Pull rig off mudboat & stage for F-pad. Stage mud boat on F- pad. Secure accumulator lines. Remove catwalk & accumulator hose suitcase. Spot in crane. Fly spools & rig floor. Secure rig floor on transport trailer.Rig released from R-104 at 23:59 on 12- 11-2024. No operations to report. 12/7/2024 - Saturday Rig accepted at 20:30 on 12-09-2024Test BOPE as per approve sundry. Test to 250 psi low & 2,500 psi high for 5/5 charted mins. AOGCC waived witness to testing. *** Cont. WSR on 12-10-2024 *** 12/10/2024 - Tuesday 12/8/2024 - Sunday No operations to report. 12/9/2024 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP R-104 Wellhead 50-029-023802-00-00 224-121 12/9/2024 12/14/2024 12/13/2024 - Friday No operations to report. 12/11/2024 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary Land 13 X 4-1/2" ESP tubing hanger RILDS then set BPV, Rig Demobed off well Nipple up adapter and tree post ASR rig move. Tested adapter to 500 / 5000 PSI for 10 mins. Pulled BPV with dry rod. 12/12/2024 - Thursday No operations to report. No operations to report. MPU Well Support got well post RWO and Phase 3 weather. Tied well into process,PT'd surface lines and serviced wellhead. Released well to I&E Group for tie-in/FCO. 12/14/2024 - Saturday No operations to report. 12/17/2024 - Tuesday 12/15/2024 - Sunday No operations to report. 12/16/2024 - Monday 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. Received By: Date: Date: 12/18/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL: WELL: MPU R-104 + PB1 PTD: 224-121 API: 50-029-23802-00-00 (MPU R-104) API: 50-029-23802-70-00 (MPU R-104PB1) FINAL LWD FORMATION EVALUATION + GEOSTEERING (10/28/2024 to 11/23/2024) x ROP, BaseStar & ABG GR, ResiStar & StrataStar Resistivity (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Survey x Final Geosteering and EOW Report/Plots SFTP Transfer – Main Folders: FINAL LWD Subfolders: FINAL Geosteering Subfolders: g Please include current contact information if different from above. T39888 T39889 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.12.19 08:04:19 -09'00' 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ESP Swap 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): 21,369'N/A Casing Collapse Conductor N/A Surface 2,260psi Intermediate 3,090psi Liner 8,830psi Liner 8,540psi 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: Contact Email: Contact Phone: Authorized Title: Wells Manager 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 11,447 MD/ 3,942 TVD aqnd N/A Taylor Wellman twellman@hilcorp.com 907-777-8449 21,368' Perforation Depth MD (ft): 13,561' See Schematic 7,807' See Schematic 2-7/8" 3,940'4-1/2" 127' 20" 13-3/8" 9-5/8" 3,870' 5-1/2"2,114' 11,591' MD N/A 9,190psi 5,020psi 5,750psi 2,263' 3,957' 3,954' 3,916' 11,634' Length Size Proposed Pools: 127' 127' 6.5 / L-80 / EUE 8rd TVD Burst 11,438' 9,020psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025509, ADL355018 & ADL388235 224-121 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23802-00-00 Hilcorp Alaska LLC 477.005 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 12/10/2024 SLZXP LTP and N/A 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 MILNE PT UNIT R-104 MILNE POINT SCHRADER BLUFF OIL N/A 3,940' 21,367' 3,940' 1,230 N/A 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 Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2024.12.02 15:22:04 - 09'00' Taylor Wellman (2143) By Grace Christianson at 3:48 pm, Dec 02, 2024 324-679 * BOPE pressure test to 2500 psi. MGR02DEC24 10-404 12/10/2024 SFD 12/2/2024*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.12.06 08:31:45 -09'00'12/06/24 RBDMS JSB 121324 ESP Swap Well: MPU R-104 Date: 12/02/2024 Well Name:MPU R-104 API Number:50-029-23802-00-00 Current Status:SI – ESP Grounded Pad:R-Pad Estimated Start Date:12/10/24 Rig:ASR Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd:- Regulatory Contact:Tom Fouts Permit to Drill Number:224-121 First Call Engineer:Taylor Wellman (907) 777-8449 (O) (907) 947-9533 (M) Second Call Engineer:Todd Sidoti (907) 777-8443 (O) (907) 632-4113 (M) AFE Number:241-00152.05 Job Type:ESP Swap Current Bottom Hole Pressure:1,624 psi @ 3,942’ TVD Recently Drilled (11/30/24) |8.0 PPGE Kill Weight Brine: 9.0 PPGE to be used for RWO (ESP never unloaded wellbore) MPSP:1,230 psi (0.1 psi/ft gas gradient) Max Inclination: 94° @ 12,311’ MD (Reaches >70 deg at ±2,400’ MD) Brief Well Summary: MPU R-104 is a Schrader Oa production well that was drilled and completed on 11/26/2024. The ESP deployment went smoothly with no noted hangups encountered. The ESP electrical checks all passed every 2,000’ and when landed. Upon startup of the ESP, the drive shutdown after 20 minutes and then the ESP became grounded electrically downhole during the restart attempt. Diagnostics indicate a deep electrical fault at/near the motor. Objectives: Pull failed ESP completion, diagnose cause of failure and run new ESP completion. Notes Regarding Wellbore Condition: - 9-5/8” casing test to 1,500 psi on 11/24/2024 - 9-5/8” casing test to 3,000 psi on 11/15/2024 Pre-Rig Procedure (Non Sundried Work) Slickline 1. RU slickline, pressure test PCE to 250psi low / 2,500psi high. 2. Pull DPSOV and set dummy valve in upper GLM at 151’ MD. 3. RDMO. Pumping & Well Support 1. Clear and level pad area in front of well. Spot rig mats and containment. 2. RD well house and flowlines. Clear and level area around well. 3. RU Little Red Services. RU reverse out skid and 500 barrel returns tank. 4. Pressure test lines to 3,000 psi. 5. Circulate out freeze protect from the IA and the tubing by pumping 9.0 PPG brine taking returns up the tbg and then the casing to 500 barrel returns tank. a. Freeze protect volumes pumped: Tbg - 30 bbls / IA – 189 bbls. b.Note that 9.0 PPG brine to be used as this matches the completion fluid in the well. The ESP never unloaded the wellbore. ESP Swap Well: MPU R-104 Date: 12/02/2024 6. Confirm well is dead. Contact operations engineer if freeze protection is needed prior to ASR arrival. 7. RD Little Red Services and reverse out skid. 8. Set BPV. ND tree. NU BOPE. Brief RWO Procedure (Begin Sundried Work) 1. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines to 500 barrel returns tank. 2. Check for pressure and if 0 psi set CTS plug. If needed, bleed off any residual pressure off tubing and casing. a. If needed, kill well with 9.0 PPG brine prior to setting CTS. 3. Test BOPE to 250 psi low/ 2,500 psi high. Test annular to 250 psi low/ 2,500 psi high (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Perform test per ASR 1 BOP Test Procedure b. Notify AOGCC 24 hours in advance of BOP test. c. Confirm test pressures per the Sundry conditions of approval. d. Test VBR rams on 2-7/8” test joint. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 4. Bleed any pressure on casing to the returns tank. Pull CTS plug. Bleed any pressure off tubing to the returns tank. Kill well with produced water as needed. Pull BPV. a. If indications show pressure underneath BPV, lubricate out BPV. 5. Call out Summit for ESP pull. 6. RU spoolers to handle ESP cable. 7. MU landing joint or spear, BOLDS, PU on the tubing hanger. a. Tubing hanger is an FMC 11” x 4-1/2” TCII thread. b. 2024 tubing PU weight on Parker 273 (Block wt 45k) recorded as 62 kip. Slack off weight recorded as 58 kip. c. 2-7/8” L-80 EUE yield is 144 kip. 8. Confirm hanger free, lay down tubing hanger. a. Check the penetrator for damage and the ESP cable for electrical continuity. If the penetrator is deemed to be the failure point, contact OE Taylor Wellman for discussion 907-947-9533. Decision to replace and re-land may be made. 9. POOH and lay down the 2-7/8” tubing. a. Pulling speed to be reduced as per Summit recommendation to minimize chances for rupturing seals. b.High priority to inspect cable and MLE for damage. Note depths and description in report. If cable damage is found in top ±1,000’ MD (±1,000’ TVD of seals movement) of cable pulled, possibility to cut, splice and re-run ESP will be considered. c. All tubing to be re-used. d. Summit will direct which components need to be replaced and which will be re-run based on failure point identified and which test electrically. e. Recorded Clamp Totals: i. Canon Clamps: 191 ii. Pump Clamps: 6 ESP Swap Well: MPU R-104 Date: 12/02/2024 iii. Protectolizers: 3 iv. MLE Splice Clamp: 1 10. Lay Down ESP. 11. RIH with new 2-7/8” 6.5# L-80 ESP completion to +/- 11,438’ and obtain string weights. a. Check electrical continuity every 1000’. b. Note PU and SO weights on tally. c. Watch for any unanticipated weight changes and make note in the report. d. Install ESP clamps per Summit, and cross coupling clamps every joint. i.Contingency: If cable damage is observed and deemed to be the failure, use of multiple mid-joint clamps may be required from ±800 – 1,800’ MD. ii.Contingency: Backup pump set depth (bottom of ESP completion) at ±10,845’ MD. Nom. Size Length Item Lb/ft Material Notes 5.62 2 Centralizer 4 ±11,438’ 4.52 4 Intake Sensor 30 5.62 28 Motor - 360HP 80 5.13 9 Lower Tandem Seal 38 5.13 9 Upper Tandem Seal 38 5.38 8 Gas Separator 52 5.38 24 Pumps – 538 SJ2800 45 4.5 1.5 Ported Discharge Head 13 L-80 2.44 10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" 330 jts of 2-7/8" EUE 8rd Jt 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8"8 2-7/8" x 1" GLM, 1/4" OV 6.5 L-80 ±150’ 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" 90 2-7/8" EUE 8rd Jt 6.5 L-80 2-7/8" 10 Space out pup 6.5 L-80 2-7/8" 30 Tubing Hanger with full joint 6.5 L-80 12. Land tubing hanger and RILDS. Use extra caution to not damage cable. a. Test ESP electrically. 13. Lay down landing joint. 14. Set BPV. 15. RDMO ASR. Post-Rig Procedure: Well Support 1. RD mud boat. RD BOPE house. Move to next well location. 2. RU crane. ND BOPE, set CTS plug, and NU tree. 3. Test tubing hanger void to 500 psi low/5,000 psi high. Pull CTS and BPV. ESP Swap Well: MPU R-104 Date: 12/02/2024 4. Test ESP electrically. 5. RD crane. Move 500 bbl returns tank and rig mats to next well location. 6. RU well house and flowlines. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. BOPE Schematic _____________________________________________________________________________________ Revised By: JNL 12/2/2024 SCHEMATIC Milne Point Unit Well: MPU R-104 Last Completed: 11/26/2024 PTD: 224-121 TD =21,369’(MD) / TD =3,940’(TVD) 4 20” Orig. KB Elev.: 63.75’ / GL Elev.: 16.8’ 9-5/8” 11/12 5 2/3/4 13 13-3/8” 10 1 5-1/2” 2 3 See Screen/ Liner Detail PBTD =21,367’(MD) / PBTD = 3,940’(TVD) PB1: 11850’ – 12082’ 9 8 5/6/72-7/8” 4-1/2” CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X56 / Weld N/A Surface 127’ N/A 13-3/8” Surface 68 / L-80 / CDC 12.415 Surface 3,916’ 0.1497 9-5/8” Intermediate 40 / L-80 / BTC 8.835 Surface 11,634’ 0.0758 5-1/2” Liner 100ђ Screens 20 / L-80 / EZGO HT 4.892 11,447’ 13,561’ 0.0222 4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hyd 625 3.920 13,561’ 21,368’ 0.0149 TUBING DETAIL 2-7/8" Tubing 6.5# / L-80 / EUE 8-Rd 2.441 Surface 11,438’ 0.0058 OPEN HOLE / CEMENT DETAIL 42” 20 yds 16" Lead – 1617 sx / Tail – 598 sx 12-1/4” Lead – 579 sx / Tail – 272 sx 8-1/2” Uncemented Screen Liner WELL INCLINATION DETAIL KOP @ 158’ 90° Hole Angle = @ 11,850’ TREE & WELLHEAD Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead FMC 13-5/8” 5K w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: 50-029-23802-00-00 Completion Date: 11/26/2024 JEWELRY DETAIL No. Top MD Item ID 1 151’ 2-7/8” x 1” BK-2 GLM w/ DPSOV 2.450” 2 11,360’ Discharge Sub – Vigilant 2-7/8” 3 11,361’ Discharge Bolt – on 2-7/8” 4 11,361’ Pump: 538, SJ2800 5 11,385’ Pump Intake GS, 538 TDM H2X (SS) 6 11,392’ Upper Tandem Seal: 513 Series 7 11,401’ Lower Tandem Seal: 513 Series 8 11,410’ Motor: 562 Series, KMS2, 360HP / 3175V / 70A 9 11,434’ Sensor: 177C 8KPSI, 2x Pres, Temp, Vib 10 11,436’ Anode Centralizer 11 11,447’ SLZXP LTP / Liner Hanger Lap ~178’ 6.190” 12 11,469 7” H563 x 5.5” JFE Bear XO 4.870” 13 21,367’ Shoe 5-1/2” x 4-1/2” SCREEN LINER DETAIL Size Top (MD) Top (TVD) Btm (MD) Btm (TVD) 5-1/2” 11,598’ 13,561’ 3,955’ 3,954 4-1/2” 13,562’ 13,976’ 3,954’ 3,966’ 4-1/2” 14,138’ 16,856’ 3,967’ 3,953’ 4-1/2” 17,138’ 17,837’ 3,972’ 3,951’ 4-1/2” 17,959’ 21,329’ 3,951’ 3,885’ _____________________________________________________________________________________ Revised By: TDF 12/2/2024 PROPOSED Milne Point Unit Well: MPU R-104 Last Completed: 11/26/2024 PTD: 224-121 TD =21,369’(MD) / TD =3,940’(TVD) 4 20” Orig. KB Elev.: 63.75’ / GL Elev.: 16.8’ 9-5/8” 11/12 5 2/3/4 13 13-3/8” 10 1 5-1/2” 2 3 See Screen/ Liner Detail PBTD =21,368’(MD) / PBTD = 3,940’(TVD) 9 8 5/6/7 4-1/2” PB1: 11,850’ to 12,082’ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X56 / Weld N/A Surface 127’ N/A 13-3/8” Surface 68 / L-80 / CDC 12.415 Surface 3,916’ 0.1497 9-5/8” Intermediate 40 / L-80 / BTC 8.835 Surface 11,634’ 0.0758 5-1/2” Liner 100ђ Screens 20 / L-80 / EZGO HT 4.778 11,447’ 13,561’ 0.0222 4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hyd 625 3.920 13,561’ 21,368’ 0.0149 TUBING DETAIL 2-7/8" Tubing 6.5# / L-80 / EUE 8-Rd 2.441 Surface ±XX,XXX’ 0.0058 OPEN HOLE / CEMENT DETAIL 42” 20 yds 16" Lead – 1,617 sx / Tail – 598 sx 12-1/4” Lead – 579 sx / Tail – 272 sx 8-1/2” Uncemented Screen Liner WELL INCLINATION DETAIL KOP @ 215’ 90° Hole Angle = @ 11,700’ TREE & WELLHEAD Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead FMC 13-5/8” 5K w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: 50-029-23802-00-00 Completion Date: 11/26/2024 JEWELRY DETAIL No. Top MD Item ID 1 ±XXX’ 3-1/2” x 1” BK-2 GLM w/ 1” SOV 2.915” 2 ±XX,XXX’ Ported Pressure Sub: 3 ±XX,XXX’ Discharge Head: 4 ±XX,XXX’ Pump: 5 ±XX,XXX’ Gas Separator: 6 ±XX,XXX’ Upper Tandem Seal: 7 ±XX,XXX’ Lower Tandem Seal: 8 ±XX,XXX’ Motor: 9 ±XX,XXX’ Sensor, w/ Discharge 10 ±XX,XXX’ Centralizer / Anode: Bottom @ ±XX,XXX’ MD 11 11,447’ SLZXP LTP / Liner Hanger Lap ~178’ 6.190” 12 11,469 7” H563 x 5.5” JFE Bear XO 4.870” 13 21,368’ Shoe 5-1/2” x 4-1/2” SCREEN LINER DETAIL Size Top (MD) Top (TVD) Btm (MD) Btm (TVD) 5-1/2” 11,598’ 13,561’ 3,955’ 3,954 4-1/2” 13,562’ 13,976’ 3,954’ 3,966’ 4-1/2” 14,138’ 16,856’ 3,967’ 3,953’ 4-1/2” 17,138’ 17,837’ 3,972’ 3,951’ 4-1/2” 17,959’ 21,329’ 3,951’ 3,885’ Milne Point ASR 13-5/8” BOP 11/8/2024 13 5/8" 5M Hydril or Shaffer CIW or Sh affer 13 5/8" 5M 2 1/16" 5M Kill Valves Manual and M anual 2 1/16" 5M Choke Valves Manual and HCR 3 1/2" x 5 1/2" VBR Rams Blinds Spacer Spool 13 5/8" 5M x 13 5/8" 5M From:Rixse, Melvin G (OGC) To:AOGCC Records (CED sponsored) Subject:20241119 1623 Verbal Approval to Extend the TD MPU R-104 PTD 224-121 Date:Tuesday, November 19, 2024 5:07:58 PM Attachments:Hilcorp_MPU_R-104 Verbal Approval to Extend.pdf From: Rixse, Melvin G (OGC) Sent: Tuesday, November 19, 2024 4:23 PM To: Frank Roach <Frank.Roach@hilcorp.com> Subject: Verbal Approval to Extend the TD MPU R-104 PTD 224-121 Frank, See attached for approval to extend. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). By Grace Christianson at 9:18 am, Nov 12, 2024 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2024.11.11 14:36:02 - 09'00' Sean McLaughlin (4311) 324-646 Mel Rixse - Senior Petroleum Engineer 19-NOV-2024Yes SFD 11/12/2024 10-407 for the initial completion report. MGR12NOV24 DSR=11/19/24 * BOPE test to 3000 psi. Annular to 2500 psi. 1 Joseph Lastufka From:Frank Roach Sent:Monday, November 11, 2024 1:10 PM To:Rixse, Melvin G (OGC); Davies, Stephen F (OGC) Cc:Joseph Lastufka Subject:RE: [EXTERNAL] RE: MPU R-104 (PTD 224-121) Extension of TD Question aôīϠ ĲîôŘŜťĺĺîϟϙ®ôϙſĖīīϙŜŪæıĖťϙÍϙ͐͏ϱ͓͏͒ϙŜēĺŘťīƅϟϙĺϙŗŪĖèħīƅϙŜŪııÍŘĖƏôϙťēôϙŪŕèĺıĖĲČϙ͐͏ϱ͓͏͒ϡ ϱ FĖīèĺŘŕϙĖŜϙŘôŗŪôŜťĖĲČϙÍĲϙôƄťôĲŜĖĺĲϙĺċϙ"ϙťēôϙÍŕŕŘĺŽôîϙîĖŘôèťĖĺĲÍīϙŕīÍĲϙĖĲϙaϙϱ͐͏͒ϙϼ"ϙ͓͑͑ϱ͐͑͐Ͻϟ ϱ ēĖŜϙôƄťôĲŜĖĺĲϙŘôŗŪôŜťϙèĺıôŜϙÍċťôŘϙFĖīèĺŘŕϙÍŜŜŪıôîϙĺſĲôŘŜēĖŕϯĺŕôŘÍťĺŘŜēĖŕϙĺċϙ(bIЍŜϙbĖħÍĖťèēŪŗϙīôÍŜôŜ ĺĲϙ͐͐ϯ͐ϯ͓͑ϠϙſēĖèēϙæĺŘîôŘŜϙťēôϙaĖīĲôϙīôÍŜôŜϙſôϙÍŘôϙèŪŘŘôĲťīƅϙîŘĖīīĖĲČϟ ôČÍŘîŜϠ >ŘÍĲħϙ«ϙĺÍèē "ŘĖīīĖĲČϙ(ĲČĖĲôôŘ Hilcorp Alaska, LLC ͘͏͖ϟ͔͓͗ϟ͑͒͑͐ϙıĺæĖīô ͘͏͖ϟ͖͖͖ϟ͓͗͐͒ϙĺċċĖèô From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Friday, November 8, 2024 15:35 To: Frank Roach <Frank.Roach@hilcorp.com>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: [EXTERNAL] RE: MPU R-104 (PTD 224-121) Extension of TD Question >ŘÍĲħϠ ϙϙϙϙŪæıĖťϙÍϙ͐͏ϱ͓͏͒ϟ aôīϙĖƄŜô ôĲĖĺŘϙôťŘĺīôŪıϙ(ĲČĖĲôôŘϙϼ(Ͻ īÍŜħÍϙiĖīϙÍĲîϙ@ÍŜϙĺĲŜôŘŽÍťĖĺĲϙĺııĖŜŜĖĺĲ ͘͏͖ϱ͖͒͘ϱ͐͑͒͐ iƯĖèô ͘͏͖ϱ͖͑͘ϱ͓͖͓͗ϙϙôīī ib>I"(bI[I´ϙbiI(ϡϙēĖŜϙôϱıÍĖīϙıôŜŜÍČôϠϙĖĲèīŪîĖĲČϙÍĲƅϙÍťťÍèēıôĲťŜϠϙèĺĲťÍĖĲŜϙĖĲċĺŘıÍťĖĺĲϙċŘĺıϙťēôϙīÍŜħÍϙiĖīϙÍĲîϙ@ÍŜϙĺĲŜôŘŽÍťĖĺĲϙĺııĖŜŜĖĺĲ ϼi@ϽϠϙťÍťôϙĺċϙīÍŜħÍϙÍĲîϙĖŜϙċĺŘϙťēôϙŜĺīôϙŪŜôϙĺċϙťēôϙĖĲťôĲîôîϙŘôèĖŕĖôĲťϼŜϽϟϙIťϙıÍƅϙèĺĲťÍĖĲϙèĺĲċĖîôĲťĖÍīϙÍĲîϯĺŘϙŕŘĖŽĖīôČôîϙĖĲċĺŘıÍťĖĺĲϟϙēôϙŪĲÍŪťēĺŘĖƏôî ŘôŽĖôſϠϙŪŜôϙĺŘϙîĖŜèīĺŜŪŘôϙĺċϙŜŪèēϙĖĲċĺŘıÍťĖĺĲϙıÍƅϙŽĖĺīÍťôϙŜťÍťôϙĺŘϙċôîôŘÍīϙīÍſϟϙIċϙƅĺŪϙÍŘôϙÍĲϙŪĲĖĲťôĲîôîϙŘôèĖŕĖôĲťϙĺċϙťēĖŜϙôϱıÍĖīϠϙŕīôÍŜôϙîôīôťôϙĖťϠϙſĖťēĺŪťϙċĖŘŜť ŜÍŽĖĲČϙĺŘϙċĺŘſÍŘîĖĲČϙĖťϠϙÍĲîϠϙŜĺϙťēÍťϙťēôϙi@ϙĖŜϙÍſÍŘôϙĺċϙťēôϙıĖŜťÍħôϙĖĲϙŜôĲîĖĲČϙĖťϙťĺϙƅĺŪϠϙèĺĲťÍèťϙaôīϙĖƄŜôϙÍťϙϼ͘͏͖ϱ͖͒͘ϱ͐͑͒͐ϙϽϙĺŘ ϼaôīŽĖĲϟĖƄŜôЬÍīÍŜħÍϟČĺŽϽϟ Iibϡ (ƄťôŘĲÍīϙŜôĲîôŘϟϙ"iϙbiϙĺŕôĲϙīĖĲħŜϙĺŘϙÍťťÍèēıôĲťŜϙċŘĺıϙbXbi®bϙŜôĲîôŘŜϟ 104 SFD 2 From: Frank Roach <Frank.Roach@hilcorp.com> Sent: Friday, November 8, 2024 11:20 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: MPU R-104 (PTD 224-121) Extension of TD Question aôīϠ IЍıϙĲĺťϙŜŪŘôϙĖċϙťēĖŜϙēôīŕŜϙſĖťēϙťēôϙîĖŜèŪŜŜĖĺĲϠϙæŪťϙæôīĺſϙÍŘôϙÍϙèĺŪŕīôϙŜèŘôôĲŜēĺťŜϙĺċϙťēôϙÍŕŕŘĺŽôîϙŕīÍĲϙϼſŕ͏͓ϽϙÍĲî ťēôϙŕŘĺŕĺŜôîϙŕīÍĲϙϼſŕ͏͔ϽϙťēÍťϙæŘĖĲČŜϙ"ϙèīĺŜôŘϙťĺϙťēôϙīôÍŜôϙīĖĲôϙæôťſôôĲϙaĖīĲôϙÍĲîϙbĖħĖÍťèēŪŗϟ bĺťôϡϙ(ŽôŘƅťēĖĲČϙŪŕēĺīôϙĖŜϙĲĺťϙèēÍĲČĖĲČϟϙiĲīƅϙèēÍĲČôϙĖŜϙèĺĲťĖĲŪĖĲČϙŕÍŜťϙĺŪŘϙ"ϙŕĺĖĲťϙĖĲϙťēôϙÍŕŕŘĺŽôîϙŕôŘıĖťϟ ſŕ͏͓ϙϼ"ĖŘôèťĖĺĲÍīϙŕīÍĲϙÍŜϙŕÍŘťϙĺċϙťēôϙÍŕŕŘĺŽôîϙ"ϙ͓͑͑ϱ͐͑͐Ͻϡ ŘĺŕĺŜôîϙſŕ͏͔ϡ CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. iĲīƅϙèēÍĲČôϙĖŜϙèĺĲťĖĲŪĖĲČϙŕÍŜťϙĺŪŘϙ"ϙŕĺĖĲťϙĖĲϙťēôϙÍŕŕŘĺŽôîϙŕôŘıĖťϟ 3 "ϙôƄťôĲîŜϙæƅϙѹ͓͑͒Ѝϙa"ϟ ôČÍŘîŜϠ >ŘÍĲħϙ«ϙĺÍèē "ŘĖīīĖĲČϙ(ĲČĖĲôôŘ Hilcorp Alaska, LLC ͘͏͖ϟ͔͓͗ϟ͑͒͑͐ϙıĺæĖīô ͘͏͖ϟ͖͖͖ϟ͓͗͐͒ϙĺċċĖèô The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. 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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. 6WDQGDUG3URSRVDO5HSRUW 1RYHPEHU 3ODQ0385ZS +LOFRUS$ODVND//& 0LOQH3RLQW 03W5DYHQ3DG 5LJ0385 0385 -85008501700255034004250True Vertical Depth (1700 usft/in)3400 4250 5100 5950 6800 7650 8500 9350 10200 11050 11900 12750 13600 14450 15300 16150 17000 17850 18700 19550Vertical Section at 302.41° (1700 usft/in)R-104 wp04 tgt1R-104 wp04 tgt2R-104 wp04 tgt3R-104 wp04 tgt4R-104 wp04 tgt5R-104 wp04 tgt6R-104 wp04 tgt7R-104 wp04 tgt8R-104 wp04 tgt9R-104 wp04 tgt10R-104 wp04 tgt11R-104 wp04 tgt12R-104 wp04 tgt13R-104 wp04 tgt1R-104 wp05 tgt15 - textended t45004657MPU R-1049 5/8" x 12 1/4"4 1/2" x 8 1/2"500055006000650070007500800085009000950010000105001100011500120 00 12500 13000 13500 14000 14500 150001550016000165001700017500 1 8000185001900019500200002050021369MPU R-104 wp05Start Dir 0.08º/100' : 4656.74' MD, 2431.27'TVD : 94.29° RT TFEnd Dir : 9388.22' MD, 3523.86' TVDStart Dir 4º/100' : 11043.15' MD, 3909.42'TVDEnd Dir : 11258.53' MD, 3943.96' TVDBegin Geo-SteeringLA3UG_MBSB_NaSB_OaHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Rig: MPU R-10416.80+N/-S+E/-WNorthingEastingLatittudeLongitude0.000.006033332.39 540483.86 70° 30' 7.2079 N 149° 40' 7.9150 WSURVEY PROGRAMDate: 2024-09-12T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool215.39 3976.87 MPU R-104 GYD_Quest GWD Surface (MPU R-104) GYD_Quest GWD4034.72 4656.74 MPU R-104 Intermediate MWD (MPU R-104) 3_MWD+IFR2+MS+S4656.74 11535.00 MPU R-104 wp05 (MPU R-104) GYD_Quest GWD11535.00 21369.23 MPU R-104 wp05 (MPU R-104) GYD_Quest GWDFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation1391.75 1328.00 1476.66 MP_SV51881.75 1818.00 2386.96 Base Permafrost2067.75 2004.00 3120.75 MP_SV12355.75 2292.00 4323.09 UG4A3357.75 3294.00 8674.38 LA33569.75 3506.00 9585.21 UG_MB3831.75 3768.00 10709.77 SB_Na3957.75 3894.00 11416.74 SB_OaREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Rig: MPU R-104, True NorthVertical (TVD) Reference:MPU R-104 as built @ 63.75usftMeasured Depth Reference:MPU R-104 as built @ 63.75usftCalculation Method:Minimum CurvatureProject:Milne PointSite:M Pt Raven PadWell:Rig: MPU R-104Wellbore:MPU R-104Design:MPU R-104 wp05CASING DETAILSTVD TVDSS MD SizeName3967.90 3904.15 11535.00 9-5/8 9 5/8" x 12 1/4"3973.75 3910.00 21369.36 4-1/2 4 1/2" x 8 1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 4656.74 76.78 298.56 2431.27 1681.19 -2849.79 0.00 0.00 3306.96 Start Dir 0.08º/100' : 4656.74' MD, 2431.27'TVD : 94.29° R2 9388.22 76.53 302.42 3523.86 4016.42 -6816.13 0.08 94.29 7907.09 End Dir : 9388.22' MD, 3523.86' TVD3 11043.15 76.53 302.42 3909.42 4879.20 -8174.71 0.00 0.00 9516.48 Start Dir 4º/100' : 11043.15' MD, 3909.42'TVD4 11258.53 85.00 304.00 3943.96 4995.55 -8352.38 4.00 10.58 9728.84 End Dir : 11258.53' MD, 3943.96' TVD5 11508.53 85.00 304.00 3965.75 5134.81 -8558.86 0.00 0.00 9977.79 R-104 wp04 tgt16 11823.96 92.88 303.87 3971.57 5310.73 -8820.32 2.50 -0.97 10292.827 12390.82 92.88 303.87 3943.04 5626.22 -9290.41 0.00 0.00 10858.788 12521.49 90.00 305.40 3939.75 5700.45 -9397.87 2.50 151.99 10989.29 R-104 wp04 tgt29 12694.01 86.26 303.25 3945.38 5797.66 -9540.23 2.50 -150.14 11161.5810 12746.43 86.26 303.25 3948.80 5826.34 -9583.98 0.00 0.00 11213.8911 12898.25 90.00 303.90 3953.75 5910.24 -9710.38 2.50 9.88 11365.5712 13668.25 90.00 303.90 3953.75 6339.71 -10349.49 0.00 0.00 12135.31 R-104 wp04 tgt413 13687.63 90.48 303.90 3953.67 6350.51 -10365.57 2.50 0.10 12154.6714 14259.77 90.48 303.90 3948.83 6669.62 -10840.44 0.00 0.00 12726.6115 14279.29 90.00 303.96 3948.75 6680.51 -10856.63 2.50 173.0412746.1116 15084.29 90.00 303.96 3948.75 7130.19 -11524.32 0.00 0.00 13550.82 R-104 wp04 tgt617 15255.56 85.74 303.55 3955.12 7225.28 -11666.59 2.50 -174.56 13721.8918 15284.69 85.74 303.55 3957.28 7241.34 -11690.80 0.00 0.00 13750.9319 15452.15 89.90 304.00 3963.66 7334.35 -11829.86 2.50 6.13 13918.1820 16652.15 89.90 304.00 3965.75 8005.38 -12824.70 0.00 0.00 15117.72 R-104 wp04 tgt821 16813.68 85.86 304.03 3971.72 8095.66 -12958.47 2.50 179.58 15279.0522 16966.81 85.86 304.03 3982.77 8181.13 -13085.05 0.00 0.00 15431.7223 17132.42 90.00 303.90 3988.75 8273.57 -13222.28 2.50 -1.80 15597.12 R-104 wp04 tgt924 17216.95 92.11 303.87 3987.19 8320.69 -13292.44 2.50 -0.68 15681.6025 18081.41 92.11 303.87 3955.32 8802.20 -14009.68 0.00 0.00 16545.2026 18166.42 90.00 304.10 3953.75 8849.70 -14080.14 2.50 173.92 16630.1527 18266.42 90.00 304.10 3953.75 8905.77 -14162.95 0.00 0.00 16730.10 R-104 wp04 tgt1028 18358.31 87.70 304.12 3955.59 8957.29 -14239.01 2.50 179.40 16821.9429 18519.30 87.70 304.12 3962.05 9047.53 -14372.17 0.00 0.00 16982.7230 18590.81 89.48 303.93 3963.80 9087.53 -14431.42 2.50 -6.23 17054.1831 19686.81 89.48 303.93 3973.75 9699.27 -15340.76 0.00 0.00 18149.75 R-104 wp04 tgt1232 19831.47 93.10 303.96 3970.50 9780.01 -15460.71 2.50 0.45 18294.3033 19886.16 93.10 303.96 3967.54 9810.52 -15506.00 0.00 0.00 18348.8834 20034.45 89.39 304.05 3964.33 9893.42 -15628.89 2.50 178.58 18497.0635 20919.45 89.39 304.05 3973.75 10388.92 -16362.11 0.00 0.00 19381.65 R-104 wp04 tgt1436 20951.09 90.02 304.07 3973.91 10406.63 -16388.32 2.00 2.15 19413.2737 21369.36 90.02 304.07 3973.75 10640.97 -16734.78 0.00 0.00 19831.37 R-104 wp05 tgt15 - textended td Total Depth : 21369.36' MD, 3973.75' TVD 1700255034004250510059506800765085009350102001105011900South(-)/North(+) (1700 usft/in)-17850 -17000 -16150 -15300 -14450 -13600 -12750 -11900 -11050 -10200 -9350 -8500 -7650 -6800 -5950 -5100 -4250 -3400 -2550West(-)/East(+) (1700 usft/in)R-104 wp05 tgt15 - textended tdR-104 wp04 tgt14R-104 wp04 tgt13R-104 wp04 tgt12R-104 wp04 tgt11R-104 wp04 tgt10R-104 wp04 tgt9R-104 wp04 tgt8R-104 wp04 tgt7R-104 wp04 tgt6R-104 wp04 tgt5R-104 wp04 tgt4R-104 wp04 tgt3R-104 wp04 tgt2R-104 wp04 tgt122502431MPU R-1049 5/8" x 12 1/4"4 1/2" x 8 1/2"275030003250350037503974MPU R-104 wp05Start Dir 0.08º/100' : 4656.74' MD, 2431.27'TVD : 94.29° RT TFEnd Dir : 9388.22' MD, 3523.86' TVDStart Dir 4º/100' : 11043.15' MD, 3909.42'TVDEnd Dir : 11258.53' MD, 3943.96' TVDBegin Geo-SteeringCASING DETAILSTVDTVDSS MDSize Name3967.90 3904.15 11535.00 9-5/8 9 5/8" x 12 1/4"3973.75 3910.00 21369.36 4-1/2 4 1/2" x 8 1/2"Project: Milne PointSite: M Pt Raven PadWell: Rig: MPU R-104Wellbore: MPU R-104Plan: MPU R-104 wp05WELL DETAILS: Rig: MPU R-10416.80+N/-S+E/-WNorthing Easting Latittude Longitude0.00 0.006033332.39 540483.8670° 30' 7.2079 N149° 40' 7.9150 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Rig: MPU R-104, True NorthVertical (TVD) Reference:MPU R-104 as built @ 63.75usftMeasured Depth Reference:MPU R-104 as built @ 63.75usftCalculation Method:Minimum Curvature 3URMHFW &RPSDQ\ /RFDO&RRUGLQDWH5HIHUHQFH 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'LVWDQFH%HWZHHQ3URILOHV'LVWDQFH%HWZHHQ3URILOHV(OOLSVH6HSDUDWLRQ'LVWDQFH%HWZHHQFHQWUHVLVWKHVWUDLJKWOLQHGLVWDQFHEHWZHHQZHOOERUHFHQWUHV$OOVWDWLRQFRRUGLQDWHVZHUHFDOFXODWHGXVLQJWKH0LQLPXP&XUYDWXUHPHWKRG1RYHPEHU &203$663DJHRI 0.001.002.003.004.00Separation Factor5400 6300 7200 8100 9000 9900 10800 11700 12600 13500 14400 15300 16200 17100 18000 18900 19800 20700 21600Measured Depth (1800 usft/in)MPU R-105 wp03MPU R-102MPU R-102PB1MPU M-29MPU M-30MPU M-31MPU R-101MPU R-101 PB1MPU R-103MPU R-103PB1MPU R-106 wp02MPU R-107 wp02MPU R-108 wp02MPU R-104No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Rig: MPU R-104 NAD 1927 (NADCON CONUS)Alaska Zone 0416.80+N/-S +E/-W Northing EastingLatittudeLongitude0.000.006033332.39540483.8670° 30' 7.2079 N149° 40' 7.9150 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Rig: MPU R-104, True NorthVertical (TVD) Reference:MPU R-104 as built @ 63.75usftMeasured Depth Reference:MPU R-104 as built @ 63.75usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2024-09-12T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool215.39 3976.87 MPU R-104 GYD_Quest GWD Surface (MPU R-104) GYD_Quest GWD4034.72 4656.74 MPU R-104 Intermediate MWD (MPU R-104) 3_MWD+IFR2+MS+Sag4656.74 11535.00 MPU R-104 wp05 (MPU R-104) GYD_Quest GWD11535.00 21369.23 MPU R-104 wp05 (MPU R-104) GYD_Quest GWD0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)5400 6300 7200 8100 9000 9900 10800 11700 12600 13500 14400 15300 16200 17100 18000 18900 19800 20700 21600Measured Depth (1800 usft/in)NO GLOBAL FILTER: Using user defined selection & filtering criteria4656.74 To 21369.36Project: Milne PointSite: M Pt Raven PadWell: Rig: MPU R-104Wellbore: MPU R-104Plan: MPU R-104 wp05CASING DETAILSTVD TVDSS MD Size Name3967.90 3904.15 11535.00 9-5/8 9 5/8" x 12 1/4"3973.75 3910.00 21369.36 4-1/2 4 1/2" x 8 1/2" _____________________________________________________________________________________ Edited By: JNL 11/9/2024 PROPOSED SCHEMATIC Milne Point Unit Well: MPU R-104 Last Completed: TBD PTD: TBD TD =21,369’(MD) / TD =3,974’(TVD) 4 20” Orig. KB Elev.: 63.75’ / GL Elev.: 16.8’ 9-5/8” 11/12 5 2/3/4 13 13-3/8” 10 1 5-1/2” 2 3 See Screen/ Solid Liner Detail PBTD =21,368’(MD) / PBTD = 3,974’(TVD) 9 8 5/6/72-7/8” 4-1/2” CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X56 / Weld N/A Surface 127’ N/A 13-3/8” Surface 68 / L-80 / CDC 12.415 Surface 3,916’ 0.1497 9-5/8” Intermediate 40 / L-80 / BTC 8.835 Surface ~11,386’ 0.0758 5-1/2” Liner 100ђ Screens 20 / L-80 / EZGO HT 4.778 ~11,236’ ~12,949’ 0.0222 4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hyd 625 3.920 ~12,949’ ~21,369’ 0.0149 TUBING DETAIL 2-7/8" Tubing 6.5# / L-80 / EUE 8-Rd 2.441 Surface ~11,236’ 0.0058 OPEN HOLE / CEMENT DETAIL 42” 20 yds 16" Lead – 1617 sx / Tail – 598 sx 12-1/4” Lead – ~492 sx / Tail – 267 sx 8-1/2” Uncemented Screen Liner WELL INCLINATION DETAIL KOP @ 215’ 90° Hole Angle = @ 11,700’ TREE & WELLHEAD Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead FMC 13-5/8” 5K w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: TBD Completion Date: TBD JEWELRY DETAIL No. Top MD Item ID 1 TBD 3-1/2” x 1” BK-2 GLM w/ 1” SOV 2.915” 2 TBD Ported Pressure Sub 3 TBD Discharge Head: 513, MS1-015 4 TBD Pump: 513 Series 111 Stage SG2000 5 TBD Gas Separator: Tandem 400 Series 6 TBD Upper Tandem Seal: 513 Series 7 TBD Lower Tandem Seal: 513 Series 8 TBD Motor: 562 Series, KMS2, 300HP 9 TBD Sensor, Vigilant, 150C w/ Discharge 10 TBD Summit Centralizer / Anode: Bottom @ 5,466’ MD 11 TBD SLZXP LTP / Liner Hanger Lap ~178’ 6.190” 12 TBD 7” H563 x 4.5” H625 XO 3.850” 13 21,368’ Shoe 5-1/2” x 4-1/2”SCREENS LINER DETAIL Size Top (MD) Top (TVD) Btm (MD) Btm (TVD) 5-1/2” 4-1/2” 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: Milne Point Field, Schrader Bluff Oil Pool, MPU R-104 Hilcorp Alaska, LLC Permit to Drill Number: 224-121 Surface Location: 5167' FSL, 4095' FEL, Sec 07, T13N, R10E, UM, AK Bottomhole Location: 301' FNL, 545' FWL, Sec 34, T14N, R09E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. 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, Jessie L. Chmielowski Commissioner DATED this 19th day of September 2024. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.09.19 09:31:54 -08'00' Drilling Manager 09/06/24 Monty M Myers 8-1/2" By Grace Christianson at 10:05 am, Sep 06, 2024 224-121 50-029-23802-00-00 DSR-9/11/24A.Dewhurst 18SEP24MGR11SEP2024 * BOPE test to 3000 psi. Annular to 2500 psi. * Casing tests and FITs digital data to AOGCC upon completion of FIT. *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.09.19 09:32:07 -08'00' 09/19/24 09/19/24 RBDMS JSB 092424 Milne Point Unit (MPU) R-104 Drilling Program Version 0 9/1/2024 Table of Contents 1.0 Well Summary .......................................................................................................................... 2 2.0 Management of Change Information ....................................................................................... 3 3.0 Tubular Program:..................................................................................................................... 4 4.0 Drill Pipe Information: ............................................................................................................. 4 5.0 Internal Reporting Requirements ............................................................................................ 5 6.0 Planned Wellbore Schematic .................................................................................................... 6 7.0 Drilling / Completion Summary ............................................................................................... 7 8.0 Mandatory Regulatory Compliance / Notifications ................................................................. 8 9.0 R/U and Preparatory Work .................................................................................................... 10 10.0 N/U 21-1/4” 2M Diverter System ............................................................................................ 11 11.0 Drill 16” Hole Section ............................................................................................................. 13 12.0 Run 13-3/8” Surface Casing ................................................................................................... 16 13.0 Cement 13-3/8” Surface Casing .............................................................................................. 19 14.0 N/U BOP and Test................................................................................................................... 22 15.0 Drill 12-1/4” Hole Section ....................................................................................................... 23 16.0 Run 9-5/8” Intermediate Casing ............................................................................................. 27 17.0 Cement 9-5/8” Intermediate Casing ....................................................................................... 30 18.0 Drill 8-1/2” Hole Section ......................................................................................................... 34 19.0 Run 5-1/2” x 4-1/2” Production Liner (Lower Completion) .................................................. 39 20.0 Run 2-7/8” Tubing (Upper Completion) ................................................................................ 44 21.0 RDMO ..................................................................................................................................... 45 22.0 Parker 273 Diverter Schematic .............................................................................................. 46 23.0 Parker 273 BOP Schematic .................................................................................................... 47 24.0 Wellhead Schematic ................................................................................................................ 48 25.0 Days vs Depth .......................................................................................................................... 49 26.0 Formation Tops & Information.............................................................................................. 50 27.0 Anticipated Drilling Hazards ................................................................................................. 53 28.0 Parker 273 Layout .................................................................................................................. 58 29.0 FIT Procedure ......................................................................................................................... 59 30.0 Parker 273 Choke Manifold Schematic.................................................................................. 60 31.0 Casing Design .......................................................................................................................... 61 32.0 12-1/4” Hole Section MASP .................................................................................................... 62 33.0 8-1/2” Hole Section MASP ...................................................................................................... 63 34.0 Spider Plot (NAD 27) (Governmental Sections) ..................................................................... 64 35.0 Surface Plat (As-Built) (NAD 27) ........................................................................................... 65 Page 2 Milne Point Unit R-104 SB Producer Drilling Procedure 1.0 Well Summary Well MPU R-104 Pad Milne Point “R” Pad Planned Completion Type ESP Target Reservoir(s) Schrader Bluff Oa Sand Planned Well TD, MD / TVD 20,949’ MD / 3,964’ TVD PBTD, MD / TVD 20,949’ MD / 3,964’ TVD Surface Location (Governmental) 5,167' FSL, 4,095' FEL, Sec. 07, T13N, R10E, UM, AK Surface Location (NAD 27) X= 540,483.86 Y=6,033,332.39 Top of Productive Horizon (Governmental)344' FNL, 2,083' FEL, Sec 2, T13N, R9E, UM, AK TPH Location (NAD 27) X= 532,026.00 Y= 6,038,338.00 BHL (Governmental) 301' FNL, 545' FWL, Sec 34, T14N, R9E, UM, AK BHL (NAD 27) X= 524,067.00 Y= 6,043,631.00 AFE Drilling Days 34 days AFE Completion Days 4 days Maximum Anticipated Pressure (Surface) 1346 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1742 psig Work String 5” 19.5# S-135 XT-50 KB Elevation above MSL: 46.95 ft + 16.8 ft = 63.75 ft GL Elevation above MSL: 16.8 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Milne Point Unit R-104 SB Producer Drilling Procedure 2.0 Management of Change Information Page 4 Milne Point Unit R-104 SB Producer Drilling Procedure 3.0 Tubular Program: Hole Section OD (in)ID (in)Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 20” 19.25”---X-52Weld 16” 13-3/8” 12.415” 12.259” 14.375” 68 L-80 CDC 5,020 2,260 1,556 12-1/4” 9-5/8” 8.835” 8.679” 10.625” 40 L-80 BTC 5,750 3,090 916 8-1/2”5-1/2” Screens 4.780” 4.653” 6.000” 20.0 L-80 EZGO HT 9,190 8,830 466 4-1/2” Screens 3.960” 3.795” 4.714” 13.5 L-80 H625 9,020 8,540 279 Tubing 2-7/8” 2.441” 2.347” 3.688” 6.5 L-80 EUE 8RD 10,570 11,170 105 4.0 Drill Pipe Information: Hole Section OD (in) ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn M/U (Min) M/U (Max) Tension (k-lbs) Surface & Production 5”4.276” 3.500” 6.500” 19.5 S-135 XT50 44,000 52,800 712klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Milne Point Unit R-104 SB Producer Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. Report covers operations from 6am to 6am 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. Ensure time entry adds up to 24 hours total. Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates Submit a short operations update each work day to mmyers@hilcorp.com, frank.roach@hilcorp.com,nathan.sperry@hilcorp.com, and joseph.lastufka@hilcorp.com 5.3 Intranet Home Page Morning Update Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting Health and Safety: Notify EHS field coordinator. Environmental: Drilling Environmental Coordinator Notify Drilling Manager & Drilling Engineer on all incidents Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally Send final “As-Run” Casing tally to mmyers@hilcorp.com,frank.roach@hilcorp.com, nathan.sperry@hilcorp.com, and joseph.lastufka@hilcorp.com 5.6 Casing and Cement report Send casing and cement report for each string of casing to mmyers@hilcorp.com, frank.roach@hilcorp.com,nathan.sperry@hilcorp.com, and joseph.lastufka@hilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Email Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com Drilling Engineer Frank Roach 907.777.8413 frank.roach@hilcorp.com Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com Completion Engineer Taylor Wellman 907.777.8449 twellman@hilcorp.com Geologist Graham Emerson 907.564.5242 graham.emerson@hilcorp.com Reservoir Engineer Alan Abel 907.564.4621 alan.abel@hilcorp.com Drilling Env. Coordinator Adrian Kersten 907.564.4820 adrian.kersten@hilcorp.com EHS Director Greg Arthur 907.777.8509 greg.arthur@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com _____________________________________________________________________________________ Edited By: FVR 08/30/2024 PROPOSED SCHEMATIC Milne Point Unit Well: MPU R-104 Last Completed: TBD PTD: TBD TD =20,949’ (MD) / TD =3,964’(TVD) 4 20” Orig. KB Elev.: 63.75’ / GL Elev.: 16.8’ 9-5/8” 11/12 5 2/3/4 13 13-3/8” 10 1 5-1/2” 2 3 See Screen/ Solid Liner Detail PBTD = 20,949’ (MD) / PBTD = 3,964’ (TVD) 9 8 5/6/72-7/8” 4-1/2” CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X56 / Weld N/A Surface 80’ N/A 13-3/8” Surface 68 / L-80 / CDC 12.415 Surface 4,043’ 0.1497 9-5/8” Intermediate 40 / L-80 / BTC 8.835 Surface 11,386’ 0.0758 5-1/2” Liner 100ђ Screens 20 / L-80 / EZGO HT 4.778 11,236’ 12,949’ 0.0222 4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hyd 625 3.920 12,949’ 20,949’ 0.0149 TUBING DETAIL 2-7/8" Tubing 6.5# / L-80 / EUE 8-Rd 2.441 Surface 11,236’ 0.0058 OPEN HOLE / CEMENT DETAIL 42” 20 yds 16" Lead – 1560 sx / Tail – 595 sx 12-1/4” Lead – 492 sx / Tail – 267 sx 8-1/2” Uncemented Screen Liner WELL INCLINATION DETAIL KOP @ 450’ 90° Hole Angle = @ 11,600’ TREE & WELLHEAD Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead FMC 13-5/8” 5K w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: TBD Completion Date: TBD JEWELRY DETAIL No. Top MD Item ID 1 TBD 3-1/2” x 1” BK-2 GLM w/ 1” SOV 2.915” 2 TBD Ported Pressure Sub 3 TBD Discharge Head: 513, MS1-015 4 TBD Pump: 513 Series 111 Stage SG2000 5 TBD Gas Separator: Tandem 400 Series 6 TBD Upper Tandem Seal: 513 Series 7 TBD Lower Tandem Seal: 513 Series 8 TBD Motor: 562 Series, KMS2, 300HP 9 TBD Sensor, Vigilant, 150C w/ Discharge 10 TBD Summit Centralizer / Anode: Bottom @ 5,466’ MD 11 TBD SLZXP LTP / Liner Hanger Lap ~178’ 6.190” 12 TBD 7” H563 x 4.5” H625 XO 3.850” 13 20,949’ Shoe 5-1/2” x 4-1/2”SCREENS LINER DETAIL Size Top (MD) Top (TVD) Btm (MD) Btm (TVD) 5-1/2” 4-1/2” Page 7 Milne Point Unit R-104 SB Producer Drilling Procedure 7.0 Drilling / Completion Summary MPU R-104 is a grassroots producer planned to be drilled in the Schrader Bluff OA sand. R-104 is part of a multi well development program targeting the Schrader Bluff sand on R-pad. The directional plan is a horizontal well with 16” surface hole with 13-3/8” surface casing set in the SV1. A 12-1/4” intermediate hole with 9-5/8” intermediate casing set into the top of the Schrader Bluff sand. An 8- 1/2” lateral section will be drilled. A production liner will be run in the open hole section. The Parker 273 will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately October 7th, 2024, pending rig schedule. Surface casing will be run to ~4,043’ MD / 2,278’ TVD and cemented to surface via a single-stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, necessary remedial action will be discussed with AOGCC authorities. All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility. General sequence of operations: 1. MIRU Parker 273 to well site 2. N/U & Test 21-1/4” Diverter and 16” diverter line 3. Drill 16” surface hole to TD of surface hole section. Run and cement 13-3/8” surface casing 4. N/D diverter, N/U & test 13-5/8” x 5M BOP. Install MPD Riser 5. Drill 12-1/4” hole to TD of intermediate hole section. Run and cement 9-5/8” surface casing 6. Drill 8-1/2” lateral to well TD. 7. Run 5-1/2” x 4-1/2” production liner. 8. Run upper completion. 9. N/D BOP, N/U Tree, RDMO. Reservoir Evaluation Plan: 1. Surface Hole: No mud logging. On Site geologist. LWD: GR + Res 2. Intermediate Hole: No mud logging. On Site geologist. LWD: GR + Res 3. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering) Page 8 Milne Point Unit R-104 SB Producer Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that all drilling and completion operations comply with all applicable AOGCC regulations. Operations stated in this PTD application may be altered based on sound engineering judgement as wellbore conditions require, but no AOGCC regulations will be varied from without prior approval from the AOGCC. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. BOPs shall be tested at (2) week intervals during the drilling and completion of MPU R-104. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 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. If the BOP is used to shut in on the well in a well control situation or control fluid flow from the well bore, AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements”. o Ensure the diverter vent line is at least 75’ away from potential ignition sources Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test pressure must show stabilizing pressure and may not decline more than 10 percent within 30 minutes. The results of this test and any subsequent tests of the casing must be recorded as required by 20 AAC 25.070(1)”. AOGCC Regulation Variance Requests: None Page 9 Milne Point Unit R-104 SB Producer Drilling Procedure Summary of BOP Equipment & Notifications Hole Section Equipment Test Pressure (psi) 12 1/4”21-1/4” 2M Diverter w/ 16” Diverter Line Function Test Only 12-1/4” 13-5/8” x 5M Annular BOP 13-5/8” x Double Gate o Blind ram in btm cavity Mud cross w/ 3-1/8” x 5M side outlets 13-5/8” x Single ram 3” x 5M Choke Line 2” x 5M Kill line 3” x 5M Choke manifold Standpipe, floor valves, etc Initial Test: 250/3000 Annular: 250/2500 Subsequent Tests: 250/3000 Annular 250/2500 8-1/2” 13-5/8” x 5M Annular BOP 13-5/8” x Double Gate o Blind ram in btm cavity Mud cross w/ 3-1/8” x 5M side outlets 13-5/8” x Single ram 3” x 5M Choke Line 2” x 5M Kill line 3” x 5M Choke manifold Standpipe, floor valves, etc Initial Test: 250/3000 Annular: 250/2500 Subsequent Tests: 250/3000 Annular 250/2500 Primary closing unit: Sara Koomey Control Unit, 3,000 psi, 316 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an air-driven pump, and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: Well control event (BOP’s utilized to shut in the well to control influx of formation fluids). 24 hours notice prior to spud. 24 hours notice prior to testing BOPs. 24 hours notice prior to casing running & cement operations. Any other notifications required in PTD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 10 Milne Point Unit R-104 SB Producer Drilling Procedure 9.0 R/U and Preparatory Work 9.1 R-104 will utilize a newly set 20” conductor on R-Pad. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.3 Install landing ring. 9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each. 9.5 Level pad and ensure enough room for layout of rig footprint and R/U. 9.6 Rig mat footprint of rig. 9.7 MIRU Parker 273. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mud loggers WILL NOT be used on any hole section. 9.9 Mix spud mud for 16” surface hole section. Ensure mud temperatures are cool (<80 F). 9.10 Ensure 5-3/4” liners in mud pumps. NOV 12-P-160 1,600 HP mud pumps are rated at 5,085 psi, 466 gpm @ 120 spm @ 96% volumetric efficiency. Page 11 Milne Point Unit R-104 SB Producer Drilling Procedure 10.0 N/U 21-1/4” 2M Diverter System 10.1 N/U 21-1/4” Hydril MSP 2M Diverter System (Diverter Schematic attached to program). N/U 20” riser to BOP Deck N/U 20”, 5M diverter “T”. NU Knife gate & 16” diverter line. Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). Diverter line must be 75 ft from nearest ignition source 10.2 Notify AOGCC. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. Ensure that the annular closes in less than 45 seconds (API Standard 64 3rd edition March 2018 section 12.6.2 for packing element ID greater than 20”) 10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the vent line tip. “Warning Zone” must include: A prohibition on vehicle parking A prohibition on ignition sources or running equipment A prohibition on staged equipment or materials Restriction of traffic to essential foot or vehicle traffic only. Page 12 Milne Point Unit R-104 SB Producer Drilling Procedure 10.4 Rig & Diverter Orientation: May change on location Page 13 Milne Point Unit R-104 SB Producer Drilling Procedure 11.0 Drill 16” Hole Section 11.1 P/U 16” directional drilling assembly: Ensure BHA components have been inspected previously. Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. Use GWD until 1,500’ or MWD surveys clean up, whichever is deeper. Ensure TF offset is measured accurately and entered correctly into the MWD software. Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. Drill string will be 5” 19.5# S-135. Run a solid float in the surface hole section. 11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor. Consider using a trash bit to clean out conductor to mitigate potential damage from debris in conductor. 11.3 Drill 16” hole section to section TD, in the SV1. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100. If a DLS < 6 deg / 100 is measured, immediately backream stand to knock down severity. Hold a safety meeting with rig crews to discuss: Conductor broaching ops and mitigation procedures. Well control procedures and rig evacuation Flow rates, hole cleaning, mud cooling, etc. Pump sweeps and maintain mud rheology to ensure effective hole cleaning. Mud rheology is the primary method of transporting cuttings. Keep mud as cool as possible to keep from washing out permafrost. Pump at 400-600 gpm, staying between 400 and 450 gpm through the permafrost. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increases in pump pressure, or changes in hookload are seen Slow in/out of slips and while tripping to keep swab and surge pressures low Ensure shakers are functioning properly. Check for holes in screens on connections. Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off. Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2 minimum at TD (pending MW increase due to hydrates). Drill ahead using GWD. Take MWD surveys every stand drilled and swap to MWD when MWD surveys clean up or after 1,500’ (whichever is deeper). Page 14 Milne Point Unit R-104 SB Producer Drilling Procedure Be ready for the dead zone around base permafrost and the formation horizons at and just below base permafrost. Can be in 100% slide and still lose angle in the dead zone. However, BHA can deflect (ie. high DLS) when drilling through formation horizons. Remember, the intermediate hole section has minimal directional work until the last ~300’ so there’s plenty of footage to get back on plan. Gas hydrates have not been seen in previous R-Pad wells nor on pads adjacent to R-Pad (F- Pad and L-Pad). However, be prepared for them. In MPU they have been encountered typically around 2100’-2400’ TVD (just below permafrost). Be prepared for hydrates: Gas hydrates can be identified by the gas detector and a decrease in MW or ECD Monitor returns for hydrates, checking pressurized & non-pressurized scales Do not stop to circulate out gas hydrates – this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 fph MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well. MW will not control gas hydrates, but will affect how gas breaks out at surface. AC: All wells have a clearance factor greater than 1.0 in the surface interval. 16” hole mud program summary: Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg Depth Interval MW (ppg) Surface – Base Permafrost 8.9+ Base Permafrost - TD 9.2+ MW can be cut once ~500’ below hydrate zone PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. Rheology: MI-Gel should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. Fluid Loss: PolyPac Supreme UL should be used for filtrate control. Background LCM (10 ppb total) can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. Wellbore and mud stability:Additions of SKREENKLEEN are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH Page 15 Milne Point Unit R-104 SB Producer Drilling Procedure in the 8.5 – 9.0 range with caustic soda. Daily additions of BUSAN 1060 MUST be made to control bacterial action. Casing Running:Attempt to maintain mud rheology until casing is on bottom. Reduce system YP with DESCO and SAPP as last resort for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). System Type:8.8 – 9.2 ppg Pre-Hydrated MI-Gel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp Surface 8.8 –9.8 75-300 20 - 40 25-45 <10 8.5 –9.0 70 F System Formulation:Gel + FW spud mud Product- Surface hole Size Pkg ppb or (% liquids) M-I Gel 50 lb sx 25 Soda Ash 50 lb sx 0.25 PolyPac Supreme UL 50 lb sx 0.08 Caustic Soda 50 lb sx 0.1 SCREENCLEEN 55 gal dm 0.5 11.4 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps. 11.5 RIH to bottom, proceed to BROOH to HWDP Pump at full drill rate (400-600 gpm), and maximize rotation. Pull slowly, 5 – 10 ft / minute. Monitor well for any signs of packing off or losses. Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.6 TOOH and LD BHA Page 16 Milne Point Unit R-104 SB Producer Drilling Procedure 12.0 Run 13-3/8” Surface Casing 16.1 R/U Parker Wellbore 13-3/8” casing running equipment (CRT & Tongs) Ensure 13-3/8” CDC x XT50 XO on rig floor and M/U to FOSV. Use BOL 2000 thread compound. Dope pin end only w/ paint brush. R/U of CRT if hole conditions require. R/U a fill up tool to fill casing while running if the CRT is not used. Ensure all casing has been drifted to 12-1/4” on the location prior to running. Note that 68# drift is 12.259” Be sure to count the total # of joints on the location before running. Keep hole covered while R/U casing tools. Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 16.2 P/U shoe joint, visually verify no debris inside joint. 16.3 Continue M/U & thread locking 120’ shoe track assembly consisting of: 13-3/8” Float Shoe 1 joint – 13-3/8” CDC, 2 Centralizers 10’ from each end w/ stop rings 1 joint –13-3/8” CDC, 1 Centralizer mid joint w/ stop ring 1 joint – 13-3/8” CDC, 1 Centralizer mid joint w/ stop ring 13-3/8” Float Collar –Non-Rotating Ensure proper operation of float equipment while picking up. Ensure to record S/N’s of all float equipment components. 16.4 Continue running 13-3/8” surface casing Fill casing while running using fill up line on rig floor. Use BOL 2000 thread compound. Dope pin end only w/ paint brush. Centralization: 1 centralizer every joint to ~ 2500’ MD from shoe 1 centralizer every other joint to ~200’ below surface Utilize a collar clamp until weight is sufficient to keep slips set properly. Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 13-3/8” 68# L-80 CDC Make-Up Torques: Casing OD Minimum Maximum Yield 13-3/8” 17,000 ft-lbs 21,000 ft-lbs 73,900 ft-lbs Page 17 Milne Point Unit R-104 SB Producer Drilling Procedure Page 18 Milne Point Unit R-104 SB Producer Drilling Procedure 16.5 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.6 Slow in and out of slips. 16.7 P/U landing joint/hanger assembly and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 16.8 Lower casing and land hanger on landing ring to confirm depth. Confirm measurements. 16.9 Have emergency slips staged in cellar along with all necessary equipment for the contingency operation. 16.10 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 19 Milne Point Unit R-104 SB Producer Drilling Procedure 13.0 Cement 13-3/8” Surface Casing 17.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. Ensure adequate amount of water for mix fluid is heated and available in the water tanks. Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses Review test reports and ensure pump times are acceptable. Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 17.2 Document efficiency of all possible displacement pumps prior to cement job. 17.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 17.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 17.5 Fill surface cement lines with water and pressure test. 17.6 Drop first bottom plug – HEC rep to witness. Pump spacer. 17.7 Drop second bottom plug – HEC rep to witness. Mix and pump lead cement per below calculations, confirm actual cement volumes with cementer after TD is reached. 17.8 Drop third bottom plug – HEC rep to witness. Mix and pump tail cement per below calculations, confirm actual cement volumes with cementer after TD is reached. Cement volume based on annular volume + open hole excess (250% for lead above base permafrost and 40% for all cement below base permafrost). Job will consist of lead & tail, TOC brought to surface. Page 20 Milne Point Unit R-104 SB Producer Drilling Procedure Estimated Total Cement Volume: Cement Slurry Design: 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights. If the hole gets “sticky”, cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug – HEC rep to witness, and displace cement with spud mud out of mud pits. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. 13.11 Displacement calculation is in the Stage 1 Table in step 13.7. 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. Lead Slurry Tail Slurry System ArcticCem HalCem Density 11.0 lb/gal 15.8 lb/gal Yield 2.54 ft3/sk 1.16 ft3/sk Mix Water 12.22 gal/sk 4.98 gal/sk Page 21 Milne Point Unit R-104 SB Producer Drilling Procedure 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±9.0 bbls before consulting with Drilling Engineer. 13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 13.15 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. Ensure to report the following on wellez: Pre flush type, volume (bbls) & weight (ppg) Cement slurry type, lead or tail, volume & weight Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid Note if casing is reciprocated or rotated during the job Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure Note if pre flush or cement returns at surface & volume Note time cement in place Note calculated top of cement Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to frank.roach@hilcorp.com, nathan.sperry@hilcorp.com, and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 22 Milne Point Unit R-104 SB Producer Drilling Procedure 14.0 N/U BOP and Test 14.1 N/D the diverter T, knife gate, diverter line & N/U 13-5/8” x 13-5/8” 5M wellhead. 14.2 N/U 13-5/8” x 5M BOP as follows: BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13- 5/8” x 5M mud cross / 13-5/8” x 5M single gate Double gate ram should be dressed with 2-7/8” x 5” VBRs or 5” solid body rams in top cavity,blind ram in bottom cavity. Single ram can be dressed with 2-7/8” x 5” VBRs N/U bell nipple, install flowline. Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve 14.3 Install BOP test plug 14.4 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. Test 2-7/8” x 5” rams with the 2-7/8” and 5” test joints Confirm test pressures with PTD Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.5 R/D BOP test equipment 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix LSND fluid for production hole. Ensure LSND mud weight matches the weight at TD of surface hole. 14.8 Set wearbushing in wellhead. 14.9 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole section. 14.10 Ensure 5-3/4” liners in mud pumps. Page 23 Milne Point Unit R-104 SB Producer Drilling Procedure 15.0 Drill 12-1/4” Hole Section 15.1 M/U 12-1/4” Cleanout BHA (Milltooth Bit & 1.22° PDM) 15.2 TIH w/ 12-1/4” cleanout BHA to float equipment. Note depth TOC tagged on AM report. 15.3 R/U and test casing to 2500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5020 / 2 = ~2510 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.4 Drill out shoe track and 20’ of new formation. 15.5 CBU and condition mud for FIT. Pump at least one high vis sweep at maximum rate to surface to clean up debris. 15.6 Conduct FIT to 12.0 ppg EMW. Chart test. Ensure test is recorded on same chart as the casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. 12.0 ppg desired to cover shoe strength for expected ECD’s. A 10.6 ppg FIT is the minimum required to drill ahead 10.6 ppg provides >25 bbls based on 9.2 ppg MW, 8.46 ppg PP (swabbed kick at 9.2 ppg BHP) 15.7 POOH & LD Cleanout BHA 15.8 P/U 12-1/4” RSS directional BHA. Ensure BHA components have been inspected previously. Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. Ensure TF offset is measured accurately and entered correctly into the MWD software. Ensure MWD is R/U and operational. Ensure GWD is included in the BHA Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Drill string will be 5” 19.5# S-135 XT50. Run a non-ported float in the production hole section. * Email casing test and digital data upon completion of FIT.- mgr Page 24 Milne Point Unit R-104 SB Producer Drilling Procedure 15.9 12-1/4” hole section mud program summary: Density: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. Solids Concentration: Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. Rheology: Keep viscosifier additions reasonably low. Utilize sweeps (weighted, high vis, tandem) to inform hole cleaning efficiency. Ensure 6 rpm is > 12. (~hole diameter) for sufficient hole cleaning Run the centrifuge as needed while drilling the intermediate hole, this will help with solids removal. Dump and dilute as necessary to keep drilled solids to an absolute minimum. MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type:8.9 – 9.5 ppg LSND drilling fluid Properties: Interval Density PV YP API FL Total Solids MBT Hardness Intermediate 8.9-9.5 5-20 - ALAP 15 - 30 <8 <10% <8 <200 System Formulation: Product- intermediate Size Pkg ppb or (% liquids) Soda Ash 50 lb sx 0.17 PowerVIS 25 lb sx 1.5 –2.0 M-I Pac UL 50 lb sx 3.0 Hydrahib/Kla-Stop 55 gal dm 1.0 –1.5 KCl 50 lb sx 10.7 SCREENKLEEN 55 gal dm 0.25 M-I Wate 50 lb sx 56 (as needed for wt) Busan 1060 55 gal dm 2.1 15.10 TIH with 12-1/4” directional assembly to bottom Page 25 Milne Point Unit R-104 SB Producer Drilling Procedure 15.11 Displace wellbore to 8.9 ppg LSND drilling fluid 15.12 Begin drilling 12-1/4” hole section, on-bottom staging technique: Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k. Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes 15.14 Drill 12-1/4” hole section to section TD per Geologist and Drilling Engineer. Flow Rate: 700-900 gpm, target min. AV’s 148 ft/min, 750 gpm RPM: 120+ Utilize GWD surveys for entire 12-1/4” hole section Efforts should be made to minimize dog legs in the intermediate hole. Keep any directional work to DLS < 3 deg / 100. Any doglegs over 3 deg / 100 need to be addressed before drilling ahead. Pump sweeps and maintain mud rheology to ensure effective hole cleaning. Mud rheology is the primary method of transporting cuttings. Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection Monitor Torque and Drag with pumps on every 5 stands Monitor ECD, pump pressure & hookload trends for hole cleaning indication Surveys can be taken more frequently if deemed necessary. Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across sands for any extended period of time. Limit maximum instantaneous ROP to < 200 fph. The formations will drill faster than this, but if a concretion is hit closer to TD when drilling this fast, cutter damage can occur. Target ROP is as fast as we can clean the hole (under 200 fph) without having to backream connections. Hole cleaning is key. Note depths of the Ugnu coals for post-TD backreaming awareness A/C: All wells have a clearance factor greater than 1.0 in the surface interval. 15.15 At TD, CBU (minimum 5-7X, more if needed) at max rate and rotation (120+ rpm). Pump tandem sweeps if needed Rack back a stand at each bottoms up and reciprocate a full stand in between (while circulating the BU). Keep the pipe moving while pumping. Monitor BU for increase in cuttings. Cuttings in laterals will come back in waves and not a consistent stream so circulate more if necessary Page 26 Milne Point Unit R-104 SB Producer Drilling Procedure 15.16 BROOH with the drilling assembly to the 13-3/8” casing shoe. Circulate at full drill rate unless losses are seen. Rotate at maximum rpm that can be sustained. Target pulling speed of 5 – 10 min/std (slip to slip time, not including connections), but adjust as hole conditions dictate. Slow pulling speed when backreaming through coal depths seen when drilling. Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. Monitor returns during the backream for increase in cuttings. Cuttings in laterals will come back in waves and not a consistent stream so circulate more if necessary. 15.17 CBU minimum two times at 13-3/8” shoe and clean casing with high vis sweeps. 15.18 Monitor well for flow. 15.19 POOH and LD BHA 15.20 Change upper rams from 2-7/8” x 5” VBRs to 9-5/8” casing rams and test to 250 psi low, 3,000 psi high for 5/5 minutes with 9-5/8” test joint. Page 27 Milne Point Unit R-104 SB Producer Drilling Procedure 16.0 Run 9-5/8” Intermediate Casing 16.1 R/U Parker Wellbore 9-5/8” casing running equipment (CRT & Tongs) Ensure 9-5/8” BTC x XT50 XO on rig floor and M/U to FOSV. Use BOL 2000 thread compound. Dope pin end only w/ paint brush. R/U of CRT if hole conditions require. R/U a fill up tool to fill casing while running if the CRT is not used. Ensure all casing has been drifted to at least 8-1/2” on the location prior to running. Note that 40# API drift is 8.679” Be sure to count the total # of joints on the location before running. Keep hole covered while R/U casing tools. Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 16.2 P/U shoe joint, visually verify no debris inside joint. 16.3 Continue M/U & thread locking 120’ shoe track assembly consisting of: 9-5/8” Float Shoe 1 joint – 9-5/8” TXP, 2 Centralizers 10’ from each end w/ stop rings 1 joint –9-5/8” TXP, 1 Centralizer mid joint w/ stop ring 1 joint – 9-5/8” TXP, 1 Centralizer mid joint w/ stop ring 9-5/8” Float Collar 1 joint – 9-5/8” TXP, 1 Centralizer mid joint with stop ring 16.4 Continue running 9-5/8” surface casing Fill casing while running using fill up line on rig floor. Use BOL 2000 thread compound. Dope pin end only w/ paint brush. Centralization: 1 centralizer (locked mid-joint) every joint to ~ 3,000’ MD from 9-5/8” shoe 1 centralizer (locked mid-joint) every 2 joints to ~100’ MD below 13-3/8” shoe Utilize a collar clamp until weight is sufficient to keep slips set properly. Fill casing while running using fill up line on rig floor. Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk the cement job. 9-5/8” 40# L-80 BTC Make-Up Torques - Make up to Mark 10 jts Take Average: Casing OD Optimum 9-5/8” To Mark Page 28 Milne Point Unit R-104 SB Producer Drilling Procedure Page 29 Milne Point Unit R-104 SB Producer Drilling Procedure 16.5 CBU at 13-3/8” shoe, prior to entering open hole. 16.6 Continue to RIH with 9-5/8” intermediate casing to TD. Break circulation every 5 joints and wash down. Take special care when staging pumps up and down to avoid surging and breaking down the formation. 16.7 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.8 Slow in and out of slips. 16.9 P/U landing joint/hanger assembly and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 16.10 Lower casing and land hanger to confirm depth. Confirm measurements. 16.11 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible, reciprocate casing string while conditioning mud. Page 30 Milne Point Unit R-104 SB Producer Drilling Procedure 17.0 Cement 9-5/8” Intermediate Casing 17.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. Ensure adequate amount of water for mix fluid is heated and available in the water tanks. Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses Review test reports and ensure pump times are acceptable. Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 17.2 Document efficiency of all possible displacement pumps prior to cement job. 17.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 17.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 17.5 Fill surface cement lines with water and pressure test. 17.6 Drop first bottom plug – HEC rep to witness. Pump spacer. 17.7 Drop second bottom plug – HEC rep to witness. Mix and pump lead cement per below calculations, confirm actual cement volumes with cementer after TD is reached. 17.8 Drop third bottom plug – HEC rep to witness. Mix and pump tail cement per below calculations, confirm actual cement volumes with cementer after TD is reached. Cement volume based on annular volume + 65% open hole excess. Job will consist of lead & tail, TOC brought to ~345’ TVD above top of the Schrader NA +500’ MD. Page 31 Milne Point Unit R-104 SB Producer Drilling Procedure Estimated Total Cement Volume: Cement Slurry Design: 17.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, If the hole gets “sticky”, cease pipe reciprocation, land hanger on profile, and continue with the cement job. 17.10 After pumping cement, drop top plug and displace cement with spud mud out of mud pits. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 17.11 Ensure rig pump is used to displace cement. 17.12 Displacement calculation is in the Table in step 17.8. 17.13 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. 17.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling Engineer. 17.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. Lead Slurry Tail Slurry System EconoCem HalCem Density 12.0 lb/gal 15.8 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk Page 32 Milne Point Unit R-104 SB Producer Drilling Procedure 17.16 While unlikely, be prepared for cement returns to surface. Dump cement returns through the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may come in contact with cement returns. 17.17 Back off and LD landing joint. Install packoff and test per wellhead tech. 17.18 Freeze protect 13-3/8” x 9-5/8” casing annulus to ~3,200’ MD with dead crude or diesel after cement tests indicate cement has reached 500 psi compressive strength. Freeze protect with ~190 bbls of dead crude/diesel Establish breakdown pressure and inject 5 bbls past breakdown to confirm annulus is clear Ensure total injection volume injected down the annulus (including mud used to keep annulus open) doesn’t exceed 110% of the 13-3/8” x 9-5/8” annular volume. 17.19 Change upper rams from 9-5/8” casing rams to 2-7/8” x 5” VBRs and test to 250 psi low, 3,000 psi high with 2-7/8” and 5” test joints. Page 33 Milne Point Unit R-104 SB Producer Drilling Procedure Ensure to report the following on wellez: Pre flush type, volume (bbls) & weight (ppg) Cement slurry type, lead or tail, volume & weight Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid Note if casing is reciprocated or rotated during the job Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure Note if pre flush or cement returns at surface & volume Note time cement in place Note calculated top of cement Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to frank.roach@hilcorp.com, nathan.sperry@hilcorp.com, and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 34 Milne Point Unit R-104 SB Producer Drilling Procedure 18.0 Drill 8-1/2” Hole Section 18.1 M/U 8.5” Cleanout BHA (Milltooth Bit & 1.22° PDM) 18.2 TIH w/ 8-1/2” cleanout BHA to TOC above the float collar. Note depth TOC tagged on morning report. 18.3 R/U and test casing to 3000 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5750 / 2 = ~2875 psi. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 18.4 Drill out shoe track and 20’ of new formation. 18.5 CBU and condition mud for FIT. Pump at least one high vis sweep at maximum rate to surface to clean up debris. 18.6 Conduct FIT to 12.0 ppg EMW. Chart test. Ensure test is recorded on same chart as FIT. Document incremental volume pumped (and subsequent pressure) and volume returned. 12.0 ppg desired to cover shoe strength for expected ECD’s. A 10.1 ppg FIT is the minimum required to drill ahead 10.1 ppg provides >25 bbls based on 9.2ppg MW, 8.46ppg PP (swabbed kick at 9.2ppg BHP) 18.7 POOH & LD Cleanout BHA 18.8 P/U 8-1/2” RSS directional BHA. Ensure BHA components have been inspected previously. Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. Ensure TF offset is measured accurately and entered correctly into the MWD software. Ensure MWD is R/U and operational. Ensure GWD is included in the BHA Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. Drill string will be 5” 19.5# S-135 XT50. Run a non-ported float in the production hole section. Schrader Bluff Bit Jetting Guidelines Formation Jetting TFA NB 6 x 14 0.902 OA 6 x 13 0.778 OB 6 x 13 0.778 * Email casing test and FIT digital data to AOGCC upon completion of FIT. - mgr Page 35 Milne Point Unit R-104 SB Producer Drilling Procedure 18.9 8-1/2” hole section mud program summary: Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for sufficient hole cleaning Run the centrifuge continuously while drilling the production hole, this will help with solids removal. Dump and dilute as necessary to keep drilled solids to an absolute minimum. MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type:8.9 – 9.5 ppg FloPro drilling fluid Properties: Interval Density PV YP LSYP Total Solids MBT HPHT Hardness Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100 Page 36 Milne Point Unit R-104 SB Producer Drilling Procedure System Formulation: Product- production Size Pkg ppb or (% liquids) Busan 1060 55 gal dm 0.095 FLOTROL 55 lb sx 6 CONQOR 404 WH (8.5 gal/100 bbls)55 gal dm 0.2 FLO-VIS PLUS 25 lb sx 0.7 KCl 50 lb sx 10.7 SMB 50 lb sx 0.45 LOTORQ 55 gal dm 1.0 SAFE-CARB 10 (verify)50 lb sx 10 SAFE-CARB 20 (verify)50 lb sx 10 Soda Ash 50 lb sx 0.5 18.10 TIH with 8-1/2” directional assembly to bottom 18.11 Install MPD RCD 18.12 Displace wellbore to 8.9 ppg FloPro drilling fluid 18.13 Begin drilling 8-1/2” hole section, on-bottom staging technique: Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k. Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes 18.15 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer. Flow Rate: 350-550 gpm, target min. AV’s 200 ft/min, 385 gpm RPM: 120+ Utilize GWD surveys for entire 8-1/2” hole section Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection Monitor Torque and Drag with pumps on every 5 stands Monitor ECD, pump pressure & hookload trends for hole cleaning indication Surveys can be taken more frequently if deemed necessary. Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. Use ADR to stay in section. Page 37 Milne Point Unit R-104 SB Producer Drilling Procedure Limit maximum instantaneous ROP to < 200 fph. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur. Target ROP is as fast as we can clean the hole (under 200 fph) without having to backream connections Watch for higher than expected pressure. MPD will be utilized to monitor pressure build up on connections Schrader Bluff OA Concretions: 4-6% Historically AC: All wells have a clearance factor greater than 1.0 in the surface interval. 18.16 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons learned and best practices. Ensure the DD is referencing their procedure. Patience is key! Getting kicked off too quickly might have been the cause of failed liner runs on past wells. If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so we have a nice place to low side. Attempt to sidetrack low and right in a fast drilling interval where the wellbore is headed up. Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working string back and forth. Trough for approximately 30 minutes. Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 18.17 At TD, CBU (minimum 3X, more if needed) at 200 ft/min AV (385+ gpm) and rotation (120+ rpm). Pump tandem sweeps if needed Rack back a stand at each bottoms up and reciprocate a full stand in between (while circulating the BU). Keep the pipe moving while pumping. Monitor BU for increase in cuttings. Cuttings in laterals will come back in waves and not a consistent stream so circulate more if necessary If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum 18.18 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter cake and calcium carbonate. Circulate the well clean. Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being removed, including an increase in the loss rate. Page 38 Milne Point Unit R-104 SB Producer Drilling Procedure 18.19 Displace 1.5 OH + Liner volume with viscosified brine. Proposed brine blend (aiming for an 8 on the 6 RPM reading) - KCl: 7.1bbp for 2% NaCl: 60.9 ppg for 9.4 ppg Lotorq: 1.5% Lube 776: 1.5% Soda Ash: as needed for 9.5pH Busan 1060: 0.42 ppb Flo-Vis Plus: 1.25 ppb Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further discussion needed prior to BROOH. 18.20 BROOH with the drilling assembly to the 9-5/8” casing shoe. Note: PST test is NOT required. Circulate at full drill rate unless losses are seen (350 gpm minimum if on losses) Rotate at maximum rpm that can be sustained. Target pulling speed of 5 – 10 min/std (slip to slip time, not including connections), but adjust as hole conditions dictate. When pulling across any OHST depths, turn pumps off and rotary off to minimize disturbance. Trip back in hole past OHST depth to ensure liner will stay in correct hole section, check with ABI compared to as drilled surveys 18.21 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps. 18.22 Monitor well for flow. Increase mud weight if necessary Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise If necessary, increase MW at shoe for any higher than expected pressure seen 18.23 Pull RCD Bearing and install trip nipple. 18.24 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. Page 39 Milne Point Unit R-104 SB Producer Drilling Procedure 19.0 Run 5-1/2” x 4-1/2” Production Liner (Lower Completion) 19.1 Well control preparedness: In the event of an influx of formation fluids while running the production liner with screens, the following well control response procedure will be followed: With 4-1/2” joint across BOP: P/U & M/U the 5” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 4-1/2” liner. 19.2 Confirm VBR’s have been tested to cover 2-7/8” and 5” pipe sizes to 250 psi low/3000 psi high. 19.3 R/U 4-1/2” liner running equipment. Ensure 4-1/2” Hydril 625 x XT-50 crossovers are on rig floor and M/U to FOSV. Ensure the liner has been drifted on the deck prior to running. Be sure to count the total # of joints on the deck before running. Keep hole covered while R/U casing tools. Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 19.4 Run 4-1/2” production liner. Production liner will be a combination of screened and solid joints. Confirm with geologist and OE for any solid joint placement. Use API Modified or “Best O Life 2000 AG” equivalent thread compound. Dope pin end only w/ paint brush. Wipe off excess. Thread compound can plug the screens Utilize a collar clamp until weight is sufficient to keep slips set properly. Use lift nubbins and stabbing guides for the liner run. Centralization: 1 centralizer every joint to ~ 100’ MD from intermediate shoe Obtain up and down weights of the liner before picking up liner hanger assembly. Record rotating torque at 10 and 20 rpm Page 40 Milne Point Unit R-104 SB Producer Drilling Procedure 4-1/2” 13.5# L-80 H625 Casing OD Minimum Optimum Maximum Operating Torque 4.5” 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs Page 41 Milne Point Unit R-104 SB Producer Drilling Procedure 5-1/2” 20.0# L-80 EZGO HT Casing OD Minimum Make-up Torque Maximum Make-Up Torque Maximum Operating Torque 5.5” 6,997 ft-lbs 10,728 ft-lbs 20,145 ft-lbs Page 42 Milne Point Unit R-104 SB Producer Drilling Procedure 19.5 Ensure that the liner top packer is set ~150’ MD above the 9-5/8” shoe. AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8” connection. 19.6 Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 19.7 M/U Baker SLZXP liner top packer to 4-1/2” liner. 19.8 Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 19.9 RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. Ensure 5” DP/HWDP has been drifted There is no inner string planned to be run, as opposed to previous wells. The DP should auto fill. Monitor FL and if filling is required due to losses/surging. 19.10 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 19.11 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. 19.12 If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 19.13 TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 19.14 Rig up to pump down the work string with the rig pumps. 19.15 Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed 1,600 psi while circulating.Pusher tool is set at 2,100 psi with 5% shear screws but it should be discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker 19.16 Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 19.17 Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 BPM). Slow pump before the ball seats. Do not allow ball to slam into ball seat. Page 43 Milne Point Unit R-104 SB Producer Drilling Procedure 19.18 Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the SZXP liner hanger/packer to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi to release the HRDE running tool. 19.19 Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 RPM and set down 50K again. 19.20 PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted. 19.21 Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 19.22 PU pulling running tool free of the packer and displace at max rate to wash the liner top. Pump sweeps as needed. 19.23 POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned, LD DP on the TOOH. Note: Once running tool is LD, swap to the completion AFE. Page 44 Milne Point Unit R-104 SB Producer Drilling Procedure 20.0 Run 2-7/8” Tubing (Upper Completion) 20.1 M/U ESP assembly and RIH to setting depth. TIH no faster than 90 ft/min. Ensure wear bushing is pulled. Ensure 2-7/8” EUE 8RD x XT-50 crossover is on rig floor and M/U to FOSV. Ensure all tubing has been drifted in the pipe shed prior to running. Ensure that the ESP Cable spooler is rigged up to the rig floor. Be sure to count the total # of joints in the pipe shed before running. Keep hole covered while R/U casing tools. Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. Monitor displacement from wellbore while RIH. 2-7/8” 6.5# L-80 EUE 8RD Casing OD Minimum Optimum Maximum Operating Torque 2.875” 1,690 ft-lbs 2,250 ft-lbs 2,810 ft-lbs 2-” Upper Completion Running Order Centralizer (OD = ±5.85”), Base at ±12,000’ MD – Confirm final set depth with Operations Engineer Taylor Wellman,twellman@hilcorp.com or 907-947-9533. The ideal set depth of the ESP has a DSL less than 1.0 deg. Intake Sensor 360Hp 456 Motor (OD = 4.56”) Lower Seal Section Upper Seal Section Intake / Gas Separator Pump Section 3 Pump Section 2 Pump Section 1 Discharge Head Joints 2-7/8”, 6.5#, L-80, EUE 8rd tubing ±10’ Pup Joint 2-7/8”, 6.5#, L-80, EUE 8rd 2-7/8” GLM (+/-140’ MD) ±10’ Pup Joint 2-7/8”, 6.5#, L-80, EUE 8rd 1 joint 2-7/8”, 6.5#, L-80, EUE 8rd tubing Page 45 Milne Point Unit R-104 SB Producer Drilling Procedure 2-7/8”, 6.5#, L-80, EUE 8rd space out pups (if needed) 1 joint 2-7/8”, 6.5#, L-80, EUE 8rd tubing Tubing hanger with 2-7/8”, 6.5#, L-80, EUE 8rd pin down 20.2 Follow all service company procedures for handling, make up and deployment of the ESP system. Typical clamping is every joint for the first 15 joints and then every other joint to surface. Make note of clamping performed in tally. Perform electrical continuity checks every 2,000’ MD. 20.3 MU tubing hanger, install penetrator, and terminate ESP cable. Perform final continuity check. 20.4 RIH and land hanger. RILDS and test hanger. 20.5 Set BPV, ensure new body seals are installed each time. ND BOPE and NU adapter flange and tree. 20.6 Pull BPV. Set TWC. Test tree to 5000 psi. 20.7 Pull TWC. Set BPV. Bullhead tubing & IA freeze protect if/as needed. 20.8 Secure the tree and cellar. 21.0 RDMO 21.1 RDMO Parker 273 Page 46 Milne Point Unit R-104 SB Producer Drilling Procedure 22.0 Parker 273 Diverter Schematic Page 47 Milne Point Unit R-104 SB Producer Drilling Procedure 23.0 Parker 273 BOP Schematic Page 48 Milne Point Unit R-104 SB Producer Drilling Procedure 24.0 Wellhead Schematic Page 49 Milne Point Unit R-104 SB Producer Drilling Procedure 25.0 Days vs Depth Page 50 Milne Point Unit R-104 SB Producer Drilling Procedure 26.0 Formation Tops & Information TOP NAME TVD (FT) TVDSS (FT) MD (FT) Formation Pressure (psi) EMW (ppg) SV5 1,392 1,328 1,463 612 8.46 Base Permafrost 1,882 1,818 2,368 828 8.46 SV1 2,068 2,004 3,153 910 8.46 LA3 3,358 3,294 8,615 1477 8.46 UG_MB 3,570 3,506 9,512 1570 8.46 SB_Na 3,832 3,768 10,621 1686 8.46 SB_Oa 3,958 3,894 11,374 1741 8.46 Page 51 Milne Point Unit R-104 SB Producer Drilling Procedure L-Pad and F-Pad Data Sheets Formation Descriptions (Closest & Most Analogous MPU Pads to Moose Pad) Page 52 Milne Point Unit R-104 SB Producer Drilling Procedure Page 53 Milne Point Unit R-104 SB Producer Drilling Procedure 27.0 Anticipated Drilling Hazards 16” Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas hyrates have not been seen on Raven pad. However, be prepared for them. Remember that hydrate gas behaves differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud cut weight. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: There are a number of wells in close proximity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Well specific A/C: There are no wells with a CF < 1.0 Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. Page 54 Milne Point Unit R-104 SB Producer Drilling Procedure 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 55 Milne Point Unit R-104 SB Producer Drilling Procedure 12-1/4” Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas hyrates have not been seen on Raven pad. However, be prepared for them. While the likely depths for hydrates are in the surface interval, remain vigilant. Remember that hydrate gas behaves differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud cut weight. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: There are a number of wells in close proximity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Well specific A/C: There are no wells with a CF < 1.0 Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. Page 56 Milne Point Unit R-104 SB Producer Drilling Procedure 4. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 5. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 6. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 57 Milne Point Unit R-104 SB Producer Drilling Procedure 8-1/2” Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up appropriately to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There is one mapped fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a “ramp” in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed, we’ll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Abnormal (offset injection) pressure has been seen on R- Pad. Utilize MPD to mitigate any abnormal pressure seen. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. Well specific AC: There are no wells with a CF < 1.0 Page 58 Milne Point Unit R-104 SB Producer Drilling Procedure 28.0 Parker 273 Layout Page 59 Milne Point Unit R-104 SB Producer Drilling Procedure 29.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 60 Milne Point Unit R-104 SB Producer Drilling Procedure 30.0 Parker 273 Choke Manifold Schematic Page 61 Milne Point Unit R-104 SB Producer Drilling Procedure 31.0 Casing Design Page 62 Milne Point Unit R-104 SB Producer Drilling Procedure 32.0 12-1/4” Hole Section MASP Page 63 Milne Point Unit R-104 SB Producer Drilling Procedure 33.0 8-1/2” Hole Section MASP Page 64 Milne Point Unit R-104 SB Producer Drilling Procedure 34.0 Spider Plot (NAD 27) (Governmental Sections) Page 65 Milne Point Unit R-104 SB Producer Drilling Procedure 35.0 Surface Plat (As-Built) (NAD 27) Standard Planning Report 30 August, 2024 Plan: MPU R-104 wp03 Hilcorp Alaska, LLC Milne Point M Pt Raven Pad Plan: MPU R-104 MPU R-104 You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) -1000010002000300040005000True Vertical Depth (2000 usft/in)0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 15000 16000 17000 18000 19000Vertical Section at 302.41° (2000 usft/in)R-104 wp03 tgt6R-104 wp03 tgt9R-104 wp03 tgt14R-104 wp03 tgt2R-104 wp03 tgt13R-104 wp03 tgt5R-104 wp03 tgt12R-104 wp03 tgt10R-104 wp03 tgt11R-104 wp03 tgt7R-104 wp03 tgt4R-104 wp03 tgt1R-104 wp03 tgt3R-104 wp03 tgt813 3/8" x 16"9 5/8" x 12 1/4"4 1/2" x 8 1/2"5001000150020002500300035004000450050005500600065007000750080008500900095001000010500110001150012000125001300013500140001450015000155001600016500170001750018000185001900019500200002050020949MPU R-104 wp03Start Dir 3º/100' : 450' MD, 450'TVDStart Dir 4º/100' : 650' MD, 649.63'TVDEnd Dir : 2408.44' MD, 1891.78' TVDStart Dir 4º/100' : 10916.21' MD, 3901.39'TVDEnd Dir : 11135.76' MD, 3936.96' TVDBegin GeosteeringTotal Depth : 20948.55' MD, 3963.75' TVDMP_SV5Base PermafrostMP_SV1UG4ALA3UG_MBSB_NaSB_OaHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: MPU R-104Ground Level: 16.80+N/-S +E/-WNorthingEastingLatittudeLongitude0.000.006033332.390540483.860 70° 30' 7.208 N 149° 40' 7.915 WSURVEY PROGRAMDate: 2024-04-02T00:00:00 Validated: Yes Version:Depth From Depth To Survey/Plan Tool46.95 4116.00 MPU R-104 wp03 (MPU R-104) GYD_Quest GWD4116.00 11385.50 MPU R-104 wp03 (MPU R-104) GYD_Quest GWD11385.50 20948.55 MPU R-104 wp03 (MPU R-104) GYD_Quest GWDFORMATION TOP DETAILSTVDPath MDPath Formation1391.75 1462.69 MP_SV51881.75 2368.27 Base Permafrost2067.75 3153.40 MP_SV12355.75 4372.66 UG4A3357.75 8614.67 LA33569.75 9512.18 UG_MB3831.75 10621.37 SB_Na3957.75 11374.28 SB_OaREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU R-104, True NorthVertical (TVD) Reference:As-Built: MPR-104 @ 63.75usftMeasured Depth Reference:As-Built: MPR-104 @ 63.75usftCalculation Method: Minimum CurvatureProject:Milne PointSite:M Pt Raven PadWell:Plan: MPU R-104Wellbore:MPU R-104Design:MPU R-104 wp03CASING DETAILSTVD MD Name Size2295.12 4116.00 13 3/8" x 16" 13-3/83958.73 11385.50 9 5/8" x 12 1/4" 9-5/83963.75 20948.55 4 1/2" x 8 1/2" 4-1/2SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect TargetAnnotation1 46.95 0.00 0.00 46.95 0.00 0.00 0.00 0.00 0.002 450.00 0.00 0.00 450.00 0.00 0.00 0.00 0.00 0.00Start Dir 3º/100' : 450' MD, 450'TVD3 650.00 6.00 300.00 649.63 5.23 -9.06 3.00 300.00 10.45Start Dir 4º/100' : 650' MD, 649.63'TVD4 2408.44 76.34 300.89 1891.78 561.44 -942.05 4.00 0.92 1096.23End Dir : 2408.44' MD, 1891.78' TVD5 10916.21 76.34 300.89 3901.39 4805.35 -8036.61 0.00 0.00 9360.31Start Dir 4º/100' : 10916.21' MD, 3901.6 11135.76 85.00 302.35 3936.96 4918.85 -8220.90 4.00 9.59 9576.72End Dir : 11135.76' MD, 3936.96' TVD7 11385.76 85.00 302.35 3958.75 5052.11 -8431.29 0.00 0.00 9825.77 R-104 wp03 tgt1Begin Geosteering8 11698.18 92.63 304.00 3965.20 5222.90 -8692.52 2.50 12.23 10137.869 12431.46 92.63 304.00 3931.49 5632.53 -9299.79 0.00 0.00 10870.0810 12550.80 90.00 305.40 3928.75 5700.45 -9397.87 2.50 151.97 10989.29 R-104 wp03 tgt211 12650.37 87.55 304.95 3930.88 5757.79 -9479.23 2.50 -169.50 11088.7012 12804.33 87.55 304.95 3937.45 5845.91 -9605.31 0.00 0.00 11242.3813 12897.54 89.37 303.49 3939.95 5898.30 -9682.35 2.50 -38.76 11335.5014 13697.54 89.37 303.49 3948.75 6339.71 -10349.49 0.00 0.00 12135.31 R-104 wp03 tgt415 13866.65 93.55 304.15 3944.45 6433.77 -10489.92 2.50 8.91 12304.2716 13961.39 93.55 304.15 3938.59 6486.85 -10568.18 0.00 0.00 12398.7917 14113.93 89.74 303.92 3934.21 6572.17 -10694.51 2.50 -176.61 12551.1818 15113.93 89.74 303.92 3938.75 7130.19 -11524.32 0.00 0.00 13550.82 R-104 wp03 tgt619 15265.71 85.95 304.08 3944.46 7215.00 -11650.04 2.50 177.55 13702.4120 15310.81 85.95 304.08 3947.64 7240.21 -11687.30 0.00 0.00 13747.3821 15481.78 90.22 303.92 3953.36 7335.74 -11828.93 2.50 -2.18 13918.1522 16681.78 90.22 303.92 3948.75 8005.38 -12824.70 0.00 0.00 15117.72 R-104 wp03 tgt823 16783.00 87.69 304.03 3950.59 8061.93 -12908.62 2.50 177.41 15218.8824 17050.21 87.69 304.03 3961.35 8211.36 -13129.87 0.00 0.00 15485.7625 17198.62 91.40 303.90 3962.53 8294.27 -13252.94 2.50 -2.08 15634.0926 18148.62 91.40 303.90 3939.32 8823.97 -14041.21 0.00 0.00 16583.4927 18195.29 90.00 303.90 3938.75 8849.99 -14079.94 3.00 180.00 16630.1428 18295.29 90.00 303.90 3938.75 8905.77 -14162.95 0.00 0.00 16730.10 R-104 wp03 tgt1029 18399.25 86.89 304.13 3941.57 8963.90 -14249.07 3.00 175.74 16833.9730 18587.98 86.89 304.13 3951.81 9069.64 -14405.06 0.00 0.00 17022.3431 18665.94 89.22 303.93 3954.46 9113.24 -14469.63 3.00 -4.96 17100.2232 19715.94 89.22 303.93 3968.75 9699.27 -15340.76 0.00 0.00 18149.75 R-104 wp03 tgt1233 19835.04 92.79 303.96 3966.66 9765.76 -15439.52 3.00 0.48 18268.7734 19945.41 92.79 303.96 3961.28 9827.34 -15530.96 0.00 0.00 18378.9735 20048.55 89.70 304.05 3959.04 9885.00 -15616.43 3.00 178.33 18482.0336 20948.55 89.70 304.05 3963.75 10388.92 -16362.11 0.00 0.00 19381.65 R-104 wp03 tgt14Total Depth : 20948.55' MD, 3963.75'You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) -5000 -3750 -2500 -1250 0 1250 2500 3750 5000 6250 7500 8750 10000 11250 12500 13750 15000 South(-)/North(+) (2500 usft/in)-16250 -15000 -13750 -12500 -11250 -10000 -8750 -7500 -6250 -5000 -3750 -2500 -1250 0 West(-)/East(+) (2500 usft/in) R-104 wp03 tgt8 R-104 wp03 tgt3 R-104 wp03 tgt1 R-104 wp03 tgt4 R-104 wp03 tgt7 R-104 wp03 tgt11 R-104 wp03 tgt10 R-104 wp03 tgt12 R-104 wp03 tgt5 R-104 wp03 tgt13 R-104 wp03 tgt2 R-104 wp03 tgt14 R-104 wp03 tgt9 R-104 wp03 tgt6 13 3/8" x 16" 9 5/8" x 12 1/4" 4 1/2" x 8 1/2" 25012501750200022502500275030003250350037503964MPU R-104 wp03 Start Dir 3º/100' : 450' MD, 450'TVD Start Dir 4º/100' : 650' MD, 649.63'TVD End Dir : 2408.44' MD, 1891.78' TVD Start Dir 4º/100' : 10916.21' MD, 3901.39'TVD End Dir : 11135.76' MD, 3936.96' TVD Begin Geosteering Total Depth : 20948.55' MD, 3963.75' TVD CASING DETAILS TVD MD Name Size 2295.12 4116.00 13 3/8" x 16" 13-3/8 3958.73 11385.50 9 5/8" x 12 1/4" 9-5/8 3963.75 20948.55 4 1/2" x 8 1/2" 4-1/2 Project: Milne Point Site: M Pt Raven Pad Well: Plan: MPU R-104 Wellbore: MPU R-104 Plan: MPU R-104 wp03 WELL DETAILS: Plan: MPU R-104 Ground Level: 16.80 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 6033332.390 540483.860 70° 30' 7.208 N 149° 40' 7.915 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: MPU R-104, True North Vertical (TVD) Reference:As-Built: MPR-104 @ 63.75usft Measured Depth Reference:As-Built: MPR-104 @ 63.75usft Calculation Method:Minimum Curvature You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) Halliburton Planning Report Well Plan: MPU R-104Local Co-ordinate Reference:Database:EDM 5000.17 Single User Db As-Built: MPR-104 @ 63.75usftTVD Reference:Hilcorp Alaska, LLCCompany: As-Built: MPR-104 @ 63.75usftMD Reference:Milne PointProject: TrueNorth Reference:M Pt Raven PadSite: Minimum CurvatureSurvey Calculation Method:Plan: MPU R-104Well: MPU R-104Wellbore: MPU R-104 wp03Design: Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Milne Point, ACT, MILNE POINT Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Site Position: From: Site Latitude: Longitude: Position Uncertainty: Northing: Easting: M Pt Raven Pad Map Slot Radius:5.00 usft usft usft " 6,033,201.000 540,134.000 13-3/16 70° 30' 5.934 N 149° 40' 18.238 W Well Well Position Longitude: Latitude: Easting: Northing: +E/-W +N/-S Position Uncertainty Ground Level: Plan: MPU R-104 Wellhead Elevation:0.00 0.00 0.00 6,033,332.390 540,483.860 70° 30' 7.208 N 149° 40' 7.915 W 16.80 usft usft usft usft usft usft usft °0.31Grid Convergence: Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) MPU R-104 Model NameMagnetics BGGM2024 8/29/2023 14.59 80.80 57,274.90478460 Phase:Version: Audit Notes: Design MPU R-104 wp03 PLAN Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:46.95 302.410.000.0046.95 Depth From (usft) Plan Survey Tool Program RemarksTool NameSurvey (Wellbore) Depth To (usft) Date 8/30/2024 GYD_Quest GWD Gyrodata Stationary SPEAR MPU R-104 wp03 (MPU R-104)46.95 4,116.001 GYD_Quest GWD Gyrodata Stationary SPEAR MPU R-104 wp03 (MPU R-104)4,116.00 11,385.502 GYD_Quest GWD Gyrodata Stationary SPEAR MPU R-104 wp03 (MPU R-104)11,385.50 20,948.553 8/30/2024 11:43:14AM COMPASS 5000.17 Build 02Page 2 You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) Halliburton Planning Report Well Plan: MPU R-104Local Co-ordinate Reference:Database:EDM 5000.17 Single User Db As-Built: MPR-104 @ 63.75usftTVD Reference:Hilcorp Alaska, LLCCompany: As-Built: MPR-104 @ 63.75usftMD Reference:Milne PointProject: TrueNorth Reference:M Pt Raven PadSite: Minimum CurvatureSurvey Calculation Method:Plan: MPU R-104Well: MPU R-104Wellbore: MPU R-104 wp03Design: Inclination (°) Azimuth (°) +E/-W (usft) TFO (°) +N/-S (usft) Measured Depth (usft) Vertical Depth (usft) Dogleg Rate (°/100usft) Build Rate (°/100usft) Turn Rate (°/100usft) Plan Sections Target 0.000.000.000.000.000.0046.950.000.0046.95 0.000.000.000.000.000.00450.000.000.00450.00 300.000.003.003.00-9.065.23649.63300.006.00650.00 0.920.054.004.00-942.05561.441,891.78300.8976.342,408.44 0.000.000.000.00-8,036.614,805.353,901.39300.8976.3410,916.21 9.590.673.954.00-8,220.904,918.853,936.96302.3585.0011,135.76 0.000.000.000.00-8,431.295,052.113,958.75302.3585.0011,385.76 R-104 wp03 tgt1 12.230.532.442.50-8,692.525,222.903,965.20304.0092.6311,698.18 0.000.000.000.00-9,299.795,632.533,931.49304.0092.6312,431.46 151.971.17-2.212.50-9,397.875,700.453,928.75305.4090.0012,550.80 R-104 wp03 tgt2 -169.50-0.46-2.462.50-9,479.235,757.793,930.88304.9587.5512,650.37 0.000.000.000.00-9,605.315,845.913,937.45304.9587.5512,804.33 -38.76-1.571.952.50-9,682.355,898.303,939.95303.4989.3712,897.54 0.000.000.000.00-10,349.496,339.713,948.75303.4989.3713,697.54 R-104 wp03 tgt4 8.910.392.472.50-10,489.926,433.773,944.45304.1593.5513,866.65 0.000.000.000.00-10,568.186,486.853,938.59304.1593.5513,961.39 -176.61-0.15-2.502.50-10,694.516,572.173,934.21303.9289.7414,113.93 0.000.000.000.00-11,524.327,130.193,938.75303.9289.7415,113.93 R-104 wp03 tgt6 177.550.11-2.502.50-11,650.047,215.003,944.46304.0885.9515,265.71 0.000.000.000.00-11,687.307,240.213,947.64304.0885.9515,310.81 -2.18-0.102.502.50-11,828.937,335.743,953.36303.9290.2215,481.78 0.000.000.000.00-12,824.708,005.383,948.75303.9290.2216,681.78 R-104 wp03 tgt8 177.410.11-2.502.50-12,908.628,061.933,950.59304.0387.6916,783.00 0.000.000.000.00-13,129.878,211.363,961.35304.0387.6917,050.21 -2.08-0.092.502.50-13,252.948,294.273,962.53303.9091.4017,198.62 0.000.000.000.00-14,041.218,823.973,939.32303.9091.4018,148.62 180.000.00-3.003.00-14,079.948,849.993,938.75303.9090.0018,195.29 0.000.000.000.00-14,162.958,905.773,938.75303.9090.0018,295.29 R-104 wp03 tgt10 175.740.22-2.993.00-14,249.078,963.903,941.57304.1386.8918,399.25 0.000.000.000.00-14,405.069,069.643,951.81304.1386.8918,587.98 -4.96-0.262.993.00-14,469.639,113.243,954.46303.9389.2218,665.94 0.000.000.000.00-15,340.769,699.273,968.75303.9389.2219,715.94 R-104 wp03 tgt12 0.480.033.003.00-15,439.529,765.763,966.66303.9692.7919,835.04 0.000.000.000.00-15,530.969,827.343,961.28303.9692.7919,945.41 178.330.09-3.003.00-15,616.439,885.003,959.04304.0589.7020,048.55 0.000.000.000.00-16,362.1210,388.923,963.75304.0589.7020,948.55 R-104 wp03 tgt14 8/30/2024 11:43:14AM COMPASS 5000.17 Build 02Page 3 You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) Halliburton Planning Report Well Plan: MPU R-104Local Co-ordinate Reference:Database:EDM 5000.17 Single User Db As-Built: MPR-104 @ 63.75usftTVD Reference:Hilcorp Alaska, LLCCompany: As-Built: MPR-104 @ 63.75usftMD Reference:Milne PointProject: TrueNorth Reference:M Pt Raven PadSite: Minimum CurvatureSurvey Calculation Method:Plan: MPU R-104Well: MPU R-104Wellbore: MPU R-104 wp03Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Vertical Section (usft) Dogleg Rate (°/100usft) +N/-S (usft) Build Rate (°/100usft) Turn Rate (°/100usft) Planned Survey Vertical Depth (usft) 46.95 0.00 0.00 46.95 0.00 0.000.00 0.00 0.00 0.00 100.00 0.00 0.00 100.00 0.00 0.000.00 0.00 0.00 0.00 200.00 0.00 0.00 200.00 0.00 0.000.00 0.00 0.00 0.00 300.00 0.00 0.00 300.00 0.00 0.000.00 0.00 0.00 0.00 400.00 0.00 0.00 400.00 0.00 0.000.00 0.00 0.00 0.00 450.00 0.00 0.00 450.00 0.00 0.000.00 0.00 0.00 0.00 Start Dir 3º/100' : 450' MD, 450'TVD 500.00 1.50 300.00 499.99 0.65 3.000.33 -0.57 3.00 0.00 600.00 4.50 300.00 599.85 5.88 3.002.94 -5.10 3.00 0.00 650.00 6.00 300.00 649.63 10.45 3.005.23 -9.06 3.00 0.00 Start Dir 4º/100' : 650' MD, 649.63'TVD 700.00 8.00 300.23 699.26 16.54 4.008.29 -14.33 4.00 0.46 800.00 12.00 300.46 797.72 33.89 4.0017.07 -29.31 4.00 0.23 900.00 16.00 300.58 894.73 58.06 4.0029.35 -50.14 4.00 0.12 1,000.00 20.00 300.65 989.82 88.94 4.0045.09 -76.73 4.00 0.07 1,100.00 24.00 300.70 1,082.52 126.38 4.0064.19 -108.94 4.00 0.05 1,200.00 28.00 300.73 1,172.38 170.19 4.0086.58 -146.62 4.00 0.03 1,300.00 32.00 300.76 1,258.96 220.15 4.00112.13 -189.59 4.00 0.03 1,400.00 36.00 300.78 1,341.85 276.04 4.00140.73 -237.62 4.00 0.02 1,462.69 38.51 300.79 1,391.75 313.97 4.00160.16 -270.22 4.00 0.02 MP_SV5 1,500.00 40.00 300.80 1,420.64 337.57 4.00172.24 -290.50 4.00 0.02 1,600.00 44.00 300.81 1,494.94 404.44 4.00206.50 -347.96 4.00 0.01 1,700.00 48.00 300.82 1,564.39 476.33 4.00243.35 -409.73 4.00 0.01 1,800.00 52.00 300.84 1,628.66 552.89 4.00282.60 -475.49 4.00 0.01 1,900.00 56.00 300.85 1,687.42 633.74 4.00324.06 -544.94 4.00 0.01 2,000.00 60.00 300.86 1,740.41 718.50 4.00367.54 -617.73 4.00 0.01 2,100.00 64.00 300.86 1,787.34 806.74 4.00412.82 -693.51 4.00 0.01 2,200.00 68.00 300.87 1,828.01 898.05 4.00459.68 -771.90 4.00 0.01 2,300.00 72.00 300.88 1,862.21 991.96 4.00507.90 -852.54 4.00 0.01 2,368.27 74.73 300.88 1,881.75 1,057.35 4.00541.47 -908.68 4.00 0.01 Base Permafrost 2,408.44 76.34 300.89 1,891.78 1,096.23 4.00561.44 -942.05 4.00 0.01 End Dir : 2408.44' MD, 1891.78' TVD 2,500.00 76.34 300.89 1,913.41 1,185.16 0.00607.11 -1,018.40 0.00 0.00 2,600.00 76.34 300.89 1,937.03 1,282.30 0.00656.99 -1,101.79 0.00 0.00 2,700.00 76.34 300.89 1,960.65 1,379.43 0.00706.87 -1,185.18 0.00 0.00 2,800.00 76.34 300.89 1,984.27 1,476.57 0.00756.76 -1,268.57 0.00 0.00 2,900.00 76.34 300.89 2,007.89 1,573.71 0.00806.64 -1,351.96 0.00 0.00 3,000.00 76.34 300.89 2,031.52 1,670.84 0.00856.52 -1,435.35 0.00 0.00 3,100.00 76.34 300.89 2,055.14 1,767.98 0.00906.41 -1,518.74 0.00 0.00 3,153.40 76.34 300.89 2,067.75 1,819.85 0.00933.04 -1,563.27 0.00 0.00 MP_SV1 3,200.00 76.34 300.89 2,078.76 1,865.11 0.00956.29 -1,602.13 0.00 0.00 3,300.00 76.34 300.89 2,102.38 1,962.25 0.001,006.17 -1,685.52 0.00 0.00 3,400.00 76.34 300.89 2,126.00 2,059.39 0.001,056.05 -1,768.91 0.00 0.00 3,500.00 76.34 300.89 2,149.62 2,156.52 0.001,105.94 -1,852.29 0.00 0.00 3,600.00 76.34 300.89 2,173.24 2,253.66 0.001,155.82 -1,935.68 0.00 0.00 3,700.00 76.34 300.89 2,196.86 2,350.79 0.001,205.70 -2,019.07 0.00 0.00 3,800.00 76.34 300.89 2,220.48 2,447.93 0.001,255.58 -2,102.46 0.00 0.00 3,900.00 76.34 300.89 2,244.10 2,545.06 0.001,305.47 -2,185.85 0.00 0.00 4,000.00 76.34 300.89 2,267.72 2,642.20 0.001,355.35 -2,269.24 0.00 0.00 4,100.00 76.34 300.89 2,291.35 2,739.34 0.001,405.23 -2,352.63 0.00 0.00 8/30/2024 11:43:14AM COMPASS 5000.17 Build 02Page 4 You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) Halliburton Planning Report Well Plan: MPU R-104Local Co-ordinate Reference:Database:EDM 5000.17 Single User Db As-Built: MPR-104 @ 63.75usftTVD Reference:Hilcorp Alaska, LLCCompany: As-Built: MPR-104 @ 63.75usftMD Reference:Milne PointProject: TrueNorth Reference:M Pt Raven PadSite: Minimum CurvatureSurvey Calculation Method:Plan: MPU R-104Well: MPU R-104Wellbore: MPU R-104 wp03Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Vertical Section (usft) Dogleg Rate (°/100usft) +N/-S (usft) Build Rate (°/100usft) Turn Rate (°/100usft) Planned Survey Vertical Depth (usft) 4,116.00 76.34 300.89 2,295.12 2,754.88 0.001,413.21 -2,365.97 0.00 0.00 13 3/8" x 16" 4,200.00 76.34 300.89 2,314.97 2,836.47 0.001,455.12 -2,436.02 0.00 0.00 4,300.00 76.34 300.89 2,338.59 2,933.61 0.001,505.00 -2,519.41 0.00 0.00 4,372.66 76.34 300.89 2,355.75 3,004.19 0.001,541.24 -2,580.00 0.00 0.00 UG4A 4,400.00 76.34 300.89 2,362.21 3,030.74 0.001,554.88 -2,602.80 0.00 0.00 4,500.00 76.34 300.89 2,385.83 3,127.88 0.001,604.76 -2,686.19 0.00 0.00 4,600.00 76.34 300.89 2,409.45 3,225.01 0.001,654.65 -2,769.58 0.00 0.00 4,700.00 76.34 300.89 2,433.07 3,322.15 0.001,704.53 -2,852.97 0.00 0.00 4,800.00 76.34 300.89 2,456.69 3,419.29 0.001,754.41 -2,936.35 0.00 0.00 4,900.00 76.34 300.89 2,480.31 3,516.42 0.001,804.30 -3,019.74 0.00 0.00 5,000.00 76.34 300.89 2,503.93 3,613.56 0.001,854.18 -3,103.13 0.00 0.00 5,100.00 76.34 300.89 2,527.55 3,710.69 0.001,904.06 -3,186.52 0.00 0.00 5,200.00 76.34 300.89 2,551.18 3,807.83 0.001,953.94 -3,269.91 0.00 0.00 5,300.00 76.34 300.89 2,574.80 3,904.97 0.002,003.83 -3,353.30 0.00 0.00 5,400.00 76.34 300.89 2,598.42 4,002.10 0.002,053.71 -3,436.69 0.00 0.00 5,500.00 76.34 300.89 2,622.04 4,099.24 0.002,103.59 -3,520.08 0.00 0.00 5,600.00 76.34 300.89 2,645.66 4,196.37 0.002,153.48 -3,603.47 0.00 0.00 5,700.00 76.34 300.89 2,669.28 4,293.51 0.002,203.36 -3,686.86 0.00 0.00 5,800.00 76.34 300.89 2,692.90 4,390.64 0.002,253.24 -3,770.25 0.00 0.00 5,900.00 76.34 300.89 2,716.52 4,487.78 0.002,303.12 -3,853.64 0.00 0.00 6,000.00 76.34 300.89 2,740.14 4,584.92 0.002,353.01 -3,937.02 0.00 0.00 6,100.00 76.34 300.89 2,763.76 4,682.05 0.002,402.89 -4,020.41 0.00 0.00 6,200.00 76.34 300.89 2,787.38 4,779.19 0.002,452.77 -4,103.80 0.00 0.00 6,300.00 76.34 300.89 2,811.00 4,876.32 0.002,502.66 -4,187.19 0.00 0.00 6,400.00 76.34 300.89 2,834.63 4,973.46 0.002,552.54 -4,270.58 0.00 0.00 6,500.00 76.34 300.89 2,858.25 5,070.59 0.002,602.42 -4,353.97 0.00 0.00 6,600.00 76.34 300.89 2,881.87 5,167.73 0.002,652.30 -4,437.36 0.00 0.00 6,700.00 76.34 300.89 2,905.49 5,264.87 0.002,702.19 -4,520.75 0.00 0.00 6,800.00 76.34 300.89 2,929.11 5,362.00 0.002,752.07 -4,604.14 0.00 0.00 6,900.00 76.34 300.89 2,952.73 5,459.14 0.002,801.95 -4,687.53 0.00 0.00 7,000.00 76.34 300.89 2,976.35 5,556.27 0.002,851.84 -4,770.92 0.00 0.00 7,100.00 76.34 300.89 2,999.97 5,653.41 0.002,901.72 -4,854.31 0.00 0.00 7,200.00 76.34 300.89 3,023.59 5,750.55 0.002,951.60 -4,937.69 0.00 0.00 7,300.00 76.34 300.89 3,047.21 5,847.68 0.003,001.48 -5,021.08 0.00 0.00 7,400.00 76.34 300.89 3,070.83 5,944.82 0.003,051.37 -5,104.47 0.00 0.00 7,500.00 76.34 300.89 3,094.46 6,041.95 0.003,101.25 -5,187.86 0.00 0.00 7,600.00 76.34 300.89 3,118.08 6,139.09 0.003,151.13 -5,271.25 0.00 0.00 7,700.00 76.34 300.89 3,141.70 6,236.22 0.003,201.01 -5,354.64 0.00 0.00 7,800.00 76.34 300.89 3,165.32 6,333.36 0.003,250.90 -5,438.03 0.00 0.00 7,900.00 76.34 300.89 3,188.94 6,430.50 0.003,300.78 -5,521.42 0.00 0.00 8,000.00 76.34 300.89 3,212.56 6,527.63 0.003,350.66 -5,604.81 0.00 0.00 8,100.00 76.34 300.89 3,236.18 6,624.77 0.003,400.55 -5,688.20 0.00 0.00 8,200.00 76.34 300.89 3,259.80 6,721.90 0.003,450.43 -5,771.59 0.00 0.00 8,300.00 76.34 300.89 3,283.42 6,819.04 0.003,500.31 -5,854.98 0.00 0.00 8,400.00 76.34 300.89 3,307.04 6,916.18 0.003,550.19 -5,938.37 0.00 0.00 8,500.00 76.34 300.89 3,330.66 7,013.31 0.003,600.08 -6,021.75 0.00 0.00 8,600.00 76.34 300.89 3,354.29 7,110.45 0.003,649.96 -6,105.14 0.00 0.00 8,614.67 76.34 300.89 3,357.75 7,124.69 0.003,657.28 -6,117.38 0.00 0.00 LA3 8,700.00 76.34 300.89 3,377.91 7,207.58 0.003,699.84 -6,188.53 0.00 0.00 8,800.00 76.34 300.89 3,401.53 7,304.72 0.003,749.73 -6,271.92 0.00 0.00 8/30/2024 11:43:14AM COMPASS 5000.17 Build 02Page 5 You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) Halliburton Planning Report Well Plan: MPU R-104Local Co-ordinate Reference:Database:EDM 5000.17 Single User Db As-Built: MPR-104 @ 63.75usftTVD Reference:Hilcorp Alaska, LLCCompany: As-Built: MPR-104 @ 63.75usftMD Reference:Milne PointProject: TrueNorth Reference:M Pt Raven PadSite: Minimum CurvatureSurvey Calculation Method:Plan: MPU R-104Well: MPU R-104Wellbore: MPU R-104 wp03Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Vertical Section (usft) Dogleg Rate (°/100usft) +N/-S (usft) Build Rate (°/100usft) Turn Rate (°/100usft) Planned Survey Vertical Depth (usft) 8,900.00 76.34 300.89 3,425.15 7,401.85 0.003,799.61 -6,355.31 0.00 0.00 9,000.00 76.34 300.89 3,448.77 7,498.99 0.003,849.49 -6,438.70 0.00 0.00 9,100.00 76.34 300.89 3,472.39 7,596.13 0.003,899.37 -6,522.09 0.00 0.00 9,200.00 76.34 300.89 3,496.01 7,693.26 0.003,949.26 -6,605.48 0.00 0.00 9,300.00 76.34 300.89 3,519.63 7,790.40 0.003,999.14 -6,688.87 0.00 0.00 9,400.00 76.34 300.89 3,543.25 7,887.53 0.004,049.02 -6,772.26 0.00 0.00 9,500.00 76.34 300.89 3,566.87 7,984.67 0.004,098.91 -6,855.65 0.00 0.00 9,512.18 76.34 300.89 3,569.75 7,996.50 0.004,104.98 -6,865.80 0.00 0.00 UG_MB 9,600.00 76.34 300.89 3,590.49 8,081.80 0.004,148.79 -6,939.04 0.00 0.00 9,700.00 76.34 300.89 3,614.12 8,178.94 0.004,198.67 -7,022.42 0.00 0.00 9,800.00 76.34 300.89 3,637.74 8,276.08 0.004,248.55 -7,105.81 0.00 0.00 9,900.00 76.34 300.89 3,661.36 8,373.21 0.004,298.44 -7,189.20 0.00 0.00 10,000.00 76.34 300.89 3,684.98 8,470.35 0.004,348.32 -7,272.59 0.00 0.00 10,100.00 76.34 300.89 3,708.60 8,567.48 0.004,398.20 -7,355.98 0.00 0.00 10,200.00 76.34 300.89 3,732.22 8,664.62 0.004,448.09 -7,439.37 0.00 0.00 10,300.00 76.34 300.89 3,755.84 8,761.76 0.004,497.97 -7,522.76 0.00 0.00 10,400.00 76.34 300.89 3,779.46 8,858.89 0.004,547.85 -7,606.15 0.00 0.00 10,500.00 76.34 300.89 3,803.08 8,956.03 0.004,597.73 -7,689.54 0.00 0.00 10,600.00 76.34 300.89 3,826.70 9,053.16 0.004,647.62 -7,772.93 0.00 0.00 10,621.37 76.34 300.89 3,831.75 9,073.92 0.004,658.27 -7,790.74 0.00 0.00 SB_Na 10,700.00 76.34 300.89 3,850.32 9,150.30 0.004,697.50 -7,856.32 0.00 0.00 10,800.00 76.34 300.89 3,873.94 9,247.43 0.004,747.38 -7,939.71 0.00 0.00 10,900.00 76.34 300.89 3,897.57 9,344.57 0.004,797.27 -8,023.10 0.00 0.00 10,916.21 76.34 300.89 3,901.39 9,360.32 0.004,805.35 -8,036.61 0.00 0.00 Start Dir 4º/100' : 10916.21' MD, 3901.39'TVD 11,000.00 79.64 301.45 3,918.83 9,442.24 4.004,847.77 -8,106.72 3.95 0.68 11,100.00 83.59 302.12 3,933.41 9,541.15 4.004,899.87 -8,190.80 3.95 0.66 11,135.76 85.00 302.35 3,936.96 9,576.73 4.004,918.85 -8,220.90 3.95 0.65 End Dir : 11135.76' MD, 3936.96' TVD 11,200.00 85.00 302.35 3,942.56 9,640.72 0.004,953.09 -8,274.96 0.00 0.00 11,300.00 85.00 302.35 3,951.28 9,740.34 0.005,006.40 -8,359.12 0.00 0.00 11,374.28 85.00 302.35 3,957.75 9,814.34 0.005,045.99 -8,421.64 0.00 0.00 SB_Oa 11,385.50 85.00 302.35 3,958.73 9,825.52 0.005,051.97 -8,431.07 0.00 0.00 9 5/8" x 12 1/4" 11,385.76 85.00 302.35 3,958.75 9,825.77 0.005,052.11 -8,431.29 0.00 0.00 11,386.00 85.00 302.35 3,958.77 9,826.02 0.005,052.24 -8,431.50 0.00 0.00 Begin Geosteering 11,400.00 85.35 302.43 3,959.95 9,839.97 2.545,059.71 -8,443.28 2.49 0.54 11,500.00 87.79 302.96 3,965.93 9,939.78 2.505,113.62 -8,527.28 2.44 0.53 11,600.00 90.24 303.48 3,967.65 10,039.74 2.505,168.39 -8,610.92 2.44 0.53 11,698.18 92.63 304.00 3,965.20 10,137.86 2.505,222.90 -8,692.52 2.44 0.53 11,700.00 92.63 304.00 3,965.11 10,139.68 0.005,223.92 -8,694.03 0.00 0.00 11,800.00 92.63 304.00 3,960.52 10,239.53 0.005,279.79 -8,776.85 0.00 0.00 11,900.00 92.63 304.00 3,955.92 10,339.39 0.005,335.65 -8,859.66 0.00 0.00 12,000.00 92.63 304.00 3,951.32 10,439.25 0.005,391.51 -8,942.48 0.00 0.00 12,100.00 92.63 304.00 3,946.73 10,539.10 0.005,447.37 -9,025.29 0.00 0.00 12,200.00 92.63 304.00 3,942.13 10,638.96 0.005,503.23 -9,108.11 0.00 0.00 12,300.00 92.63 304.00 3,937.54 10,738.81 0.005,559.10 -9,190.92 0.00 0.00 12,400.00 92.63 304.00 3,932.94 10,838.67 0.005,614.96 -9,273.74 0.00 0.00 12,431.46 92.63 304.00 3,931.49 10,870.08 0.005,632.53 -9,299.79 0.00 0.00 8/30/2024 11:43:14AM COMPASS 5000.17 Build 02Page 6 You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) Halliburton Planning Report Well Plan: MPU R-104Local Co-ordinate Reference:Database:EDM 5000.17 Single User Db As-Built: MPR-104 @ 63.75usftTVD Reference:Hilcorp Alaska, LLCCompany: As-Built: MPR-104 @ 63.75usftMD Reference:Milne PointProject: TrueNorth Reference:M Pt Raven PadSite: Minimum CurvatureSurvey Calculation Method:Plan: MPU R-104Well: MPU R-104Wellbore: MPU R-104 wp03Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Vertical Section (usft) Dogleg Rate (°/100usft) +N/-S (usft) Build Rate (°/100usft) Turn Rate (°/100usft) Planned Survey Vertical Depth (usft) 12,500.00 91.12 304.81 3,929.25 10,938.54 2.505,671.24 -9,356.31 -2.21 1.17 12,550.80 90.00 305.40 3,928.75 10,989.29 2.505,700.45 -9,397.87 -2.21 1.17 12,600.00 88.79 305.18 3,929.27 11,038.42 2.505,728.87 -9,438.02 -2.46 -0.46 12,650.37 87.55 304.95 3,930.88 11,088.71 2.505,757.79 -9,479.23 -2.46 -0.46 12,700.00 87.55 304.95 3,933.00 11,138.24 0.005,786.20 -9,519.87 0.00 0.00 12,804.33 87.55 304.95 3,937.45 11,242.38 0.005,845.91 -9,605.31 0.00 0.00 12,897.54 89.37 303.49 3,939.95 11,335.50 2.505,898.30 -9,682.35 1.95 -1.57 12,900.00 89.37 303.49 3,939.98 11,337.96 0.005,899.66 -9,684.40 0.00 0.00 13,000.00 89.37 303.49 3,941.08 11,437.94 0.005,954.83 -9,767.80 0.00 0.00 13,100.00 89.37 303.49 3,942.18 11,537.91 0.006,010.01 -9,851.19 0.00 0.00 13,200.00 89.37 303.49 3,943.28 11,637.89 0.006,065.19 -9,934.58 0.00 0.00 13,300.00 89.37 303.49 3,944.38 11,737.86 0.006,120.36 -10,017.98 0.00 0.00 13,400.00 89.37 303.49 3,945.48 11,837.84 0.006,175.54 -10,101.37 0.00 0.00 13,500.00 89.37 303.49 3,946.58 11,937.82 0.006,230.71 -10,184.76 0.00 0.00 13,600.00 89.37 303.49 3,947.68 12,037.79 0.006,285.89 -10,268.16 0.00 0.00 13,697.54 89.37 303.49 3,948.75 12,135.31 0.006,339.71 -10,349.49 0.00 0.00 13,700.00 89.43 303.50 3,948.78 12,137.77 2.506,341.06 -10,351.55 2.47 0.39 13,800.00 91.90 303.89 3,947.61 12,237.73 2.506,396.53 -10,434.74 2.47 0.39 13,866.65 93.55 304.15 3,944.45 12,304.27 2.506,433.77 -10,489.92 2.47 0.39 13,900.00 93.55 304.15 3,942.38 12,337.55 0.006,452.46 -10,517.47 0.00 0.00 13,961.39 93.55 304.15 3,938.59 12,398.79 0.006,486.85 -10,568.18 0.00 0.00 14,000.00 92.58 304.09 3,936.52 12,437.33 2.506,508.47 -10,600.10 -2.50 -0.15 14,100.00 90.09 303.94 3,934.19 12,537.25 2.506,564.39 -10,682.96 -2.50 -0.15 14,113.93 89.74 303.92 3,934.21 12,551.18 2.506,572.17 -10,694.51 -2.50 -0.15 14,200.00 89.74 303.92 3,934.60 12,637.22 0.006,620.20 -10,765.94 0.00 0.00 14,300.00 89.74 303.92 3,935.06 12,737.18 0.006,676.00 -10,848.92 0.00 0.00 14,400.00 89.74 303.92 3,935.51 12,837.15 0.006,731.80 -10,931.90 0.00 0.00 14,500.00 89.74 303.92 3,935.96 12,937.11 0.006,787.61 -11,014.88 0.00 0.00 14,600.00 89.74 303.92 3,936.42 13,037.08 0.006,843.41 -11,097.86 0.00 0.00 14,700.00 89.74 303.92 3,936.87 13,137.04 0.006,899.21 -11,180.84 0.00 0.00 14,800.00 89.74 303.92 3,937.33 13,237.01 0.006,955.01 -11,263.82 0.00 0.00 14,900.00 89.74 303.92 3,937.78 13,336.97 0.007,010.82 -11,346.80 0.00 0.00 15,000.00 89.74 303.92 3,938.23 13,436.93 0.007,066.62 -11,429.78 0.00 0.00 15,100.00 89.74 303.92 3,938.69 13,536.90 0.007,122.42 -11,512.76 0.00 0.00 15,113.93 89.74 303.92 3,938.75 13,550.82 0.007,130.19 -11,524.32 0.00 0.00 15,200.00 87.59 304.01 3,940.76 13,636.83 2.507,178.27 -11,595.68 -2.50 0.11 15,265.71 85.95 304.08 3,944.46 13,702.41 2.507,215.00 -11,650.04 -2.50 0.11 15,300.00 85.95 304.08 3,946.88 13,736.60 0.007,234.17 -11,678.37 0.00 0.00 15,310.81 85.95 304.08 3,947.64 13,747.38 0.007,240.21 -11,687.30 0.00 0.00 15,400.00 88.18 304.00 3,952.21 13,836.41 2.507,290.07 -11,761.11 2.50 -0.10 15,481.78 90.22 303.92 3,953.36 13,918.15 2.507,335.74 -11,828.93 2.50 -0.10 15,500.00 90.22 303.92 3,953.29 13,936.36 0.007,345.91 -11,844.05 0.00 0.00 15,600.00 90.22 303.92 3,952.90 14,036.33 0.007,401.71 -11,927.03 0.00 0.00 15,700.00 90.22 303.92 3,952.52 14,136.29 0.007,457.51 -12,010.01 0.00 0.00 15,800.00 90.22 303.92 3,952.14 14,236.26 0.007,513.32 -12,092.99 0.00 0.00 15,900.00 90.22 303.92 3,951.75 14,336.22 0.007,569.12 -12,175.97 0.00 0.00 16,000.00 90.22 303.92 3,951.37 14,436.18 0.007,624.92 -12,258.95 0.00 0.00 16,100.00 90.22 303.92 3,950.98 14,536.15 0.007,680.73 -12,341.93 0.00 0.00 16,200.00 90.22 303.92 3,950.60 14,636.11 0.007,736.53 -12,424.91 0.00 0.00 16,300.00 90.22 303.92 3,950.22 14,736.08 0.007,792.33 -12,507.90 0.00 0.00 16,400.00 90.22 303.92 3,949.83 14,836.04 0.007,848.14 -12,590.88 0.00 0.00 16,500.00 90.22 303.92 3,949.45 14,936.01 0.007,903.94 -12,673.86 0.00 0.00 16,600.00 90.22 303.92 3,949.06 15,035.97 0.007,959.74 -12,756.84 0.00 0.00 8/30/2024 11:43:14AM COMPASS 5000.17 Build 02Page 7 You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) Halliburton Planning Report Well Plan: MPU R-104Local Co-ordinate Reference:Database:EDM 5000.17 Single User Db As-Built: MPR-104 @ 63.75usftTVD Reference:Hilcorp Alaska, LLCCompany: As-Built: MPR-104 @ 63.75usftMD Reference:Milne PointProject: TrueNorth Reference:M Pt Raven PadSite: Minimum CurvatureSurvey Calculation Method:Plan: MPU R-104Well: MPU R-104Wellbore: MPU R-104 wp03Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Vertical Section (usft) Dogleg Rate (°/100usft) +N/-S (usft) Build Rate (°/100usft) Turn Rate (°/100usft) Planned Survey Vertical Depth (usft) 16,681.78 90.22 303.92 3,948.75 15,117.72 0.008,005.38 -12,824.70 0.00 0.00 16,700.00 89.76 303.94 3,948.75 15,135.94 2.508,015.55 -12,839.82 -2.50 0.11 16,783.00 87.69 304.03 3,950.59 15,218.88 2.508,061.93 -12,908.62 -2.50 0.11 16,800.00 87.69 304.03 3,951.28 15,235.86 0.008,071.44 -12,922.69 0.00 0.00 16,900.00 87.69 304.03 3,955.31 15,335.74 0.008,127.36 -13,005.50 0.00 0.00 17,000.00 87.69 304.03 3,959.33 15,435.62 0.008,183.29 -13,088.30 0.00 0.00 17,050.21 87.69 304.03 3,961.35 15,485.76 0.008,211.36 -13,129.87 0.00 0.00 17,100.00 88.94 303.99 3,962.82 15,535.52 2.508,239.20 -13,171.13 2.50 -0.09 17,198.62 91.40 303.90 3,962.53 15,634.10 2.508,294.27 -13,252.94 2.50 -0.09 17,200.00 91.40 303.90 3,962.50 15,635.47 0.008,295.04 -13,254.08 0.00 0.00 17,300.00 91.40 303.90 3,960.05 15,735.41 0.008,350.79 -13,337.06 0.00 0.00 17,400.00 91.40 303.90 3,957.61 15,835.34 0.008,406.55 -13,420.03 0.00 0.00 17,500.00 91.40 303.90 3,955.17 15,935.28 0.008,462.31 -13,503.01 0.00 0.00 17,600.00 91.40 303.90 3,952.72 16,035.22 0.008,518.07 -13,585.99 0.00 0.00 17,700.00 91.40 303.90 3,950.28 16,135.15 0.008,573.83 -13,668.96 0.00 0.00 17,800.00 91.40 303.90 3,947.84 16,235.09 0.008,629.58 -13,751.94 0.00 0.00 17,900.00 91.40 303.90 3,945.39 16,335.03 0.008,685.34 -13,834.92 0.00 0.00 18,000.00 91.40 303.90 3,942.95 16,434.96 0.008,741.10 -13,917.89 0.00 0.00 18,100.00 91.40 303.90 3,940.51 16,534.90 0.008,796.86 -14,000.87 0.00 0.00 18,148.62 91.40 303.90 3,939.32 16,583.49 0.008,823.97 -14,041.21 0.00 0.00 18,195.29 90.00 303.90 3,938.75 16,630.14 3.008,849.99 -14,079.94 -3.00 0.00 18,200.00 90.00 303.90 3,938.75 16,634.85 0.008,852.62 -14,083.85 0.00 0.00 18,295.29 90.00 303.90 3,938.75 16,730.10 0.008,905.77 -14,162.95 0.00 0.00 18,300.00 89.86 303.91 3,938.76 16,734.81 3.008,908.40 -14,166.86 -2.99 0.22 18,399.25 86.89 304.13 3,941.57 16,833.97 3.008,963.90 -14,249.07 -2.99 0.22 18,500.00 86.89 304.13 3,947.04 16,934.53 0.009,020.35 -14,332.35 0.00 0.00 18,587.98 86.89 304.13 3,951.81 17,022.34 0.009,069.64 -14,405.06 0.00 0.00 18,600.00 87.25 304.10 3,952.42 17,034.34 3.009,076.37 -14,415.00 2.99 -0.26 18,665.94 89.22 303.93 3,954.46 17,100.22 3.009,113.24 -14,469.63 2.99 -0.26 18,700.00 89.22 303.93 3,954.92 17,134.26 0.009,132.25 -14,497.89 0.00 0.00 18,800.00 89.22 303.93 3,956.28 17,234.22 0.009,188.06 -14,580.85 0.00 0.00 18,900.00 89.22 303.93 3,957.64 17,334.17 0.009,243.88 -14,663.82 0.00 0.00 19,000.00 89.22 303.93 3,959.00 17,434.13 0.009,299.69 -14,746.78 0.00 0.00 19,100.00 89.22 303.93 3,960.37 17,534.09 0.009,355.50 -14,829.75 0.00 0.00 19,200.00 89.22 303.93 3,961.73 17,634.04 0.009,411.31 -14,912.71 0.00 0.00 19,300.00 89.22 303.93 3,963.09 17,734.00 0.009,467.13 -14,995.68 0.00 0.00 19,400.00 89.22 303.93 3,964.45 17,833.95 0.009,522.94 -15,078.64 0.00 0.00 19,500.00 89.22 303.93 3,965.81 17,933.91 0.009,578.75 -15,161.60 0.00 0.00 19,600.00 89.22 303.93 3,967.17 18,033.86 0.009,634.57 -15,244.57 0.00 0.00 19,700.00 89.22 303.93 3,968.53 18,133.82 0.009,690.38 -15,327.53 0.00 0.00 19,715.94 89.22 303.93 3,968.75 18,149.75 0.009,699.27 -15,340.76 0.00 0.00 19,800.00 91.74 303.95 3,968.04 18,233.77 3.009,746.20 -15,410.49 3.00 0.03 19,835.04 92.79 303.96 3,966.66 18,268.77 3.009,765.76 -15,439.52 3.00 0.03 19,900.00 92.79 303.96 3,963.49 18,333.63 0.009,802.00 -15,493.34 0.00 0.00 19,945.41 92.79 303.96 3,961.28 18,378.97 0.009,827.34 -15,530.96 0.00 0.00 20,000.00 91.16 304.01 3,959.40 18,433.51 3.009,857.83 -15,576.20 -3.00 0.09 20,048.55 89.70 304.05 3,959.04 18,482.03 3.009,885.00 -15,616.43 -3.00 0.09 20,100.00 89.70 304.05 3,959.31 18,533.46 0.009,913.81 -15,659.06 0.00 0.00 20,200.00 89.70 304.05 3,959.83 18,633.42 0.009,969.80 -15,741.92 0.00 0.00 20,300.00 89.70 304.05 3,960.35 18,733.38 0.0010,025.79 -15,824.77 0.00 0.00 20,400.00 89.70 304.05 3,960.88 18,833.34 0.0010,081.78 -15,907.62 0.00 0.00 20,500.00 89.70 304.05 3,961.40 18,933.29 0.0010,137.77 -15,990.48 0.00 0.00 20,600.00 89.70 304.05 3,961.93 19,033.25 0.0010,193.76 -16,073.33 0.00 0.00 20,700.00 89.70 304.05 3,962.45 19,133.21 0.0010,249.75 -16,156.19 0.00 0.00 8/30/2024 11:43:14AM COMPASS 5000.17 Build 02Page 8 You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) Halliburton Planning Report Well Plan: MPU R-104Local Co-ordinate Reference:Database:EDM 5000.17 Single User Db As-Built: MPR-104 @ 63.75usftTVD Reference:Hilcorp Alaska, LLCCompany: As-Built: MPR-104 @ 63.75usftMD Reference:Milne PointProject: TrueNorth Reference:M Pt Raven PadSite: Minimum CurvatureSurvey Calculation Method:Plan: MPU R-104Well: MPU R-104Wellbore: MPU R-104 wp03Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Vertical Section (usft) Dogleg Rate (°/100usft) +N/-S (usft) Build Rate (°/100usft) Turn Rate (°/100usft) Planned Survey Vertical Depth (usft) 20,800.00 89.70 304.05 3,962.97 19,233.17 0.0010,305.74 -16,239.04 0.00 0.00 20,900.00 89.70 304.05 3,963.50 19,333.13 0.0010,361.74 -16,321.89 0.00 0.00 20,948.55 89.70 304.05 3,963.75 19,381.65 0.0010,388.92 -16,362.12 0.00 0.00 Total Depth : 20948.55' MD, 3963.75' TVD 8/30/2024 11:43:14AM COMPASS 5000.17 Build 02Page 9 You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) Halliburton Planning Report Well Plan: MPU R-104Local Co-ordinate Reference:Database:EDM 5000.17 Single User Db As-Built: MPR-104 @ 63.75usftTVD Reference:Hilcorp Alaska, LLCCompany: As-Built: MPR-104 @ 63.75usftMD Reference:Milne PointProject: TrueNorth Reference:M Pt Raven PadSite: Minimum CurvatureSurvey Calculation Method:Plan: MPU R-104Well: MPU R-104Wellbore: MPU R-104 wp03Design: Target Name - hit/miss target - Shape TVD (usft) Northing (usft) Easting (usft) +N/-S (usft) +E/-W (usft) Design Targets LongitudeLatitude Dip Angle (°) Dip Dir. (°) R-104 wp03 tgt2 3,928.75 6,038,981.000 531,056.0005,700.45 -9,397.870.00 0.00 70° 31' 3.212 N 149° 44' 44.827 W - plan hits target center - Point R-104 wp03 tgt5 3,933.75 6,039,793.000 529,834.0006,519.17 -10,615.550.00 0.00 70° 31' 11.248 N 149° 45' 20.741 W - plan misses target center by 2.01usft at 14018.85usft MD (3935.75 TVD, 6519.03 N, -10615.70 E) - Point R-104 wp03 tgt6 3,938.75 6,040,399.000 528,922.0007,130.19 -11,524.320.00 0.00 70° 31' 17.243 N 149° 45' 47.550 W - plan hits target center - Point R-104 wp03 tgt10 3,938.75 6,042,160.000 526,274.0008,905.77 -14,162.950.00 0.00 70° 31' 34.661 N 149° 47' 5.413 W - plan hits target center - Point R-104 wp03 tgt3 3,938.75 6,039,118.000 530,861.0005,838.52 -9,592.140.00 0.00 70° 31' 4.567 N 149° 44' 50.557 W - plan misses target center by 2.45usft at 12789.37usft MD (3936.81 TVD, 5837.35 N, -9593.06 E) - Point R-104 wp03 tgt4 3,948.75 6,039,615.000 530,101.0006,339.71 -10,349.490.00 0.00 70° 31' 9.486 N 149° 45' 12.894 W - plan hits target center - Point R-104 wp03 tgt8 3,948.75 6,041,267.000 527,617.0008,005.38 -12,824.700.00 0.00 70° 31' 25.830 N 149° 46' 25.918 W - plan hits target center - Point R-104 wp03 tgt11 3,953.75 6,042,340.000 526,005.0009,087.25 -14,430.990.00 0.00 70° 31' 36.440 N 149° 47' 13.324 W - plan misses target center by 0.50usft at 18619.37usft MD (3953.26 TVD, 9087.21 N, -14431.03 E) - Point R-104 wp03 tgt7 3,953.75 6,040,544.000 528,705.0007,276.39 -11,740.550.00 0.00 70° 31' 18.678 N 149° 45' 53.929 W - plan misses target center by 2.46usft at 15375.42usft MD (3951.30 TVD, 7276.33 N, -11740.74 E) - Point R-104 wp03 tgt13 3,958.75 6,043,106.000 524,853.0009,859.59 -15,578.910.00 0.00 70° 31' 44.013 N 149° 47' 47.212 W - plan misses target center by 0.59usft at 20003.23usft MD (3959.34 TVD, 9859.64 N, -15578.88 E) - Point R-104 wp03 tgt1 3,958.75 6,038,338.000 532,026.0005,052.11 -8,431.290.00 0.00 70° 30' 56.847 N 149° 44' 16.325 W - plan hits target center - Point R-104 wp03 tgt9 3,963.75 6,041,533.000 527,218.0008,273.57 -13,222.280.00 0.00 70° 31' 28.460 N 149° 46' 37.650 W - plan misses target center by 0.62usft at 17161.63usft MD (3963.14 TVD, 8273.63 N, -13222.24 E) - Point R-104 wp03 tgt14 3,963.75 6,043,631.000 524,067.00010,388.92 -16,362.120.00 0.00 70° 31' 49.203 N 149° 48' 10.336 W - plan hits target center - Point R-104 wp03 tgt12 3,968.75 6,042,947.000 525,092.0009,699.27 -15,340.760.00 0.00 70° 31' 42.442 N 149° 47' 40.181 W - plan hits target center - Point 8/30/2024 11:43:14AM COMPASS 5000.17 Build 02Page 10 You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) Halliburton Planning Report Well Plan: MPU R-104Local Co-ordinate Reference:Database:EDM 5000.17 Single User Db As-Built: MPR-104 @ 63.75usftTVD Reference:Hilcorp Alaska, LLCCompany: As-Built: MPR-104 @ 63.75usftMD Reference:Milne PointProject: TrueNorth Reference:M Pt Raven PadSite: Minimum CurvatureSurvey Calculation Method:Plan: MPU R-104Well: MPU R-104Wellbore: MPU R-104 wp03Design: Vertical Depth (usft) Measured Depth (usft) Casing Diameter (") Hole Diameter (")Name Casing Points 13 3/8" x 16"2,295.124,116.00 13-3/8 16 9 5/8" x 12 1/4"3,958.7311,385.50 9-5/8 12-1/4 4 1/2" x 8 1/2"3,963.7520,948.55 4-1/2 8-1/2 Measured Depth (usft) Vertical Depth (usft) Dip Direction (°)Name Lithology Dip (°) Formations 1,462.69 MP_SV51,391.75 2,368.27 Base Permafrost1,881.75 3,153.40 MP_SV12,067.75 4,372.66 UG4A2,355.75 8,614.67 LA33,357.75 9,512.18 UG_MB3,569.75 10,621.37 SB_Na3,831.75 11,374.28 SB_Oa3,957.75 Measured Depth (usft) Vertical Depth (usft) +E/-W (usft) +N/-S (usft) Local Coordinates Comment Plan Annotations 450.00 450.00 0.00 0.00 Start Dir 3º/100' : 450' MD, 450'TVD 650.00 649.63 5.23 -9.06 Start Dir 4º/100' : 650' MD, 649.63'TVD 2,408.44 1,891.78 561.44 -942.05 End Dir : 2408.44' MD, 1891.78' TVD 10,916.21 3,901.39 4,805.35 -8,036.61 Start Dir 4º/100' : 10916.21' MD, 3901.39'TVD 11,135.76 3,936.96 4,918.85 -8,220.90 End Dir : 11135.76' MD, 3936.96' TVD 11,386.00 3,958.77 5,052.24 -8,431.50 Begin Geosteering 20,948.55 3,963.75 10,388.92 -16,362.12 Total Depth : 20948.55' MD, 3963.75' TVD 8/30/2024 11:43:14AM COMPASS 5000.17 Build 02Page 11 You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) 30 August, 2024 Anticollision Summary Report Hilcorp Alaska, LLC Milne Point M Pt Raven Pad Plan: MPU R-104 MPU R-104 MPU R-104 wp03 You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) Halliburton Anticollision Summary Report Well Plan: MPU R-104Local Co-ordinate Reference:Hilcorp Alaska, LLCCompany: As-Built: MPR-104 @ 63.75usftTVD Reference:Milne PointProject: As-Built: MPR-104 @ 63.75usftMD Reference:M Pt Raven PadReference Site: TrueNorth Reference:5.00 usftSite Error: Minimum CurvatureSurvey Calculation Method:Plan: MPU R-104Reference Well: Output errors are at 2.00 sigmaWell Error:0.00 usft Reference Wellbore MPU R-104 Database:EDM 5000.17 Single User Db Reference DatumReference Design:MPU R-104 wp03 Offset TVD Reference: Interpolation Method: Depth Range: Reference Error Model: Scan Method: Error Surface: Filter type: ISCWSA Closest Approach 3D Ellipsoid Separation NO GLOBAL FILTER: Using user defined selection & filtering criteria MD Interval 25.00usft Unlimited Maximum centre distance of 1,226.75usft MPU R-104 wp03 Results Limited by: SigmaWarning Levels Evaluated at:2.00 Added to Error ValuesCasing Method: From (usft) Survey Tool Program DescriptionTool NameSurvey (Wellbore) To (usft) Date 8/30/2024 GYD_Quest GWD Gyrodata Stationary SPEAR GWD tool in open ho46.95 4,116.00 MPU R-104 wp03 (MPU R-104) GYD_Quest GWD Gyrodata Stationary SPEAR GWD tool in open ho4,116.00 11,385.50 MPU R-104 wp03 (MPU R-104) GYD_Quest GWD Gyrodata Stationary SPEAR GWD tool in open ho11,385.50 20,948.55 MPU R-104 wp03 (MPU R-104) Offset Well - Wellbore - Design Reference Measured Depth (usft) Offset Measured Depth (usft) Between Centres (usft) Between Ellipses (usft) Separation Factor Warning Summary Site Name Distance M Pt Moose Pad SFMPU M-29 - MPU M-29 - MPU M-29 10,075.00 16,530.00 642.02 451.42 3.368 ESMPU M-29 - MPU M-29 - MPU M-29 10,125.00 16,530.00 636.34 448.37 3.385 CCMPU M-29 - MPU M-29 - MPU M-29 10,172.62 16,530.00 634.55 450.16 3.441 CCMPU M-30 - MPU M-30 - MPU M-30 10,387.45 17,035.00 330.30 225.72 3.158 ESMPU M-30 - MPU M-30 - MPU M-30 10,425.00 17,035.00 332.43 224.15 3.070 SFMPU M-30 - MPU M-30 - MPU M-30 10,475.00 17,035.00 341.71 228.79 3.026 CCMPU M-31- MPU M-31- MPU M-31 9,739.13 17,734.75 514.82 419.74 5.414 ESMPU M-31- MPU M-31- MPU M-31 10,100.00 18,075.05 549.60 395.10 3.557 SFMPU M-31- MPU M-31- MPU M-31 10,700.00 18,560.69 728.24 497.24 3.153 CCMPU M-32 - MPU M-32 - MPU M-32 9,018.06 17,466.50 626.46 534.10 6.783 ESMPU M-32 - MPU M-32 - MPU M-32 9,200.00 17,605.78 636.91 527.07 5.798 SFMPU M-32 - MPU M-32 - MPU M-32 9,825.00 18,113.43 781.44 605.80 4.449 CCMPU M-33 - MPU M-33 - MPU M-33 8,432.90 16,229.07 817.22 725.89 8.949 ESMPU M-33 - MPU M-33 - MPU M-33 8,550.00 16,307.53 822.02 722.03 8.221 SFMPU M-33 - MPU M-33 - MPU M-33 9,425.00 17,081.05 1,007.23 833.89 5.811 CCMPU M-62 - MPU M-62 - MPU M-62 7,824.74 16,635.07 987.36 894.96 10.686 ESMPU M-62 - MPU M-62 - MPU M-62 7,950.00 16,725.34 990.25 889.90 9.869 SFMPU M-62 - MPU M-62 - MPU M-62 8,950.00 17,547.30 1,212.24 1,043.98 7.204 8/30/2024 11:46:32AM COMPASS 5000.17 Build 02 CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page2 You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) Halliburton Anticollision Summary Report Well Plan: MPU R-104Local Co-ordinate Reference:Hilcorp Alaska, LLCCompany: As-Built: MPR-104 @ 63.75usftTVD Reference:Milne PointProject: As-Built: MPR-104 @ 63.75usftMD Reference:M Pt Raven PadReference Site: TrueNorth Reference:5.00 usftSite Error: Minimum CurvatureSurvey Calculation Method:Plan: MPU R-104Reference Well: Output errors are at 2.00 sigmaWell Error:0.00 usft Reference Wellbore MPU R-104 Database:EDM 5000.17 Single User Db Reference DatumReference Design:MPU R-104 wp03 Offset TVD Reference: Offset Well - Wellbore - Design Reference Measured Depth (usft) Offset Measured Depth (usft) Between Centres (usft) Between Ellipses (usft) Separation Factor Warning Summary Site Name Distance M Pt Raven Pad CCMPU R-101- MPU R-101- MPU R-101 684.45 665.97 204.57 199.05 37.053 ESMPU R-101- MPU R-101- MPU R-101 700.00 678.91 204.62 199.00 36.427 SFMPU R-101- MPU R-101- MPU R-101 20,725.00 20,560.00 1,216.18 859.17 3.407 CCMPU R-101- MPU R-101PB1 - MPU R-101PB1 684.45 665.97 204.57 199.05 37.053 ESMPU R-101- MPU R-101PB1 - MPU R-101PB1 700.00 678.91 204.62 199.00 36.427 SFMPU R-101- MPU R-101PB1 - MPU R-101PB1 4,775.00 4,541.00 494.70 384.72 4.498 CCMPU R-102 - MPU R-102 - MPU R-102 2,634.30 2,432.44 163.15 126.14 4.408 ESMPU R-102 - MPU R-102 - MPU R-102 2,675.00 2,469.59 163.59 125.47 4.291 SFMPU R-102 - MPU R-102 - MPU R-102 20,425.00 20,243.00 804.35 449.53 2.267 CCMPU R-102 - MPU R-102 PB1 - MPU R-102 PB1 2,634.30 2,432.44 163.15 126.14 4.408 ESMPU R-102 - MPU R-102 PB1 - MPU R-102 PB1 2,675.00 2,469.59 163.59 125.47 4.291 SFMPU R-102 - MPU R-102 PB1 - MPU R-102 PB1 2,950.00 2,734.81 180.28 135.98 4.069 CCMPU R-141- MPU R-141- MPU R-141 46.95 48.35 239.89 238.32 153.000 ESMPU R-141- MPU R-141- MPU R-141 275.00 274.36 240.26 237.20 78.676 SFMPU R-141- MPU R-141- MPU R-141 875.00 801.99 288.40 281.79 43.602 CCMPU R-142 - MPU R-142 - MPU R-142 406.53 406.80 27.40 23.90 7.829 ESMPU R-142 - MPU R-142 - MPU R-142 425.00 425.07 27.51 23.88 7.579 SFMPU R-142 - MPU R-142 - MPU R-142 450.00 449.67 28.11 24.30 7.373 CCPlan: MPU R-105 - MPU R-105 - MPU R-105 wp02 450.00 449.90 60.10 56.06 14.874 ESPlan: MPU R-105 - MPU R-105 - MPU R-105 wp02 475.00 474.90 60.22 56.00 14.285 Collision Avoidance RequPlan: MPU R-105 - MPU R-105 - MPU R-105 wp02 20,948.55 21,035.14 528.22 175.56 1.498 CCPlan: MPU R-106 - MPU R-106 - MPU R-106 wp02 300.00 299.90 119.92 116.93 40.070 ESPlan: MPU R-106 - MPU R-106 - MPU R-106 wp02 325.00 323.93 120.02 116.85 37.922 SFPlan: MPU R-106 - MPU R-106 - MPU R-106 wp02 20,948.55 20,822.09 891.27 490.33 2.223 CCPlan: MPU R-107 - MPU R-107 - MPU R-107 wp02 960.80 938.40 88.95 81.40 11.782 ESPlan: MPU R-107 - MPU R-107 - MPU R-107 wp02 975.00 951.64 88.97 81.35 11.667 SFPlan: MPU R-107 - MPU R-107 - MPU R-107 wp02 3,650.00 3,503.04 407.63 332.95 5.458 CCPlan: MPU R-108 - MPU R-108 - MPU R-108 wp02 450.00 449.90 90.10 86.06 22.298 ESPlan: MPU R-108 - MPU R-108 - MPU R-108 wp02 575.00 578.40 90.58 85.65 18.369 SFPlan: MPU R-108 - MPU R-108 - MPU R-108 wp02 3,500.00 3,494.16 489.06 415.33 6.633 CCPlan: MPU R-109 - MPU R-109 - MPU R-109 wp02 662.43 671.32 112.89 107.23 19.975 ESPlan: MPU R-109 - MPU R-109 - MPU R-109 wp02 700.00 709.49 113.08 107.13 19.021 SFPlan: MPU R-109 - MPU R-109 - MPU R-109 wp02 4,100.00 4,053.30 727.44 635.61 7.922 CCPlan: MPU R-110 - MPU R-110 - MPU R-110 wp02 300.00 299.90 59.92 56.92 20.020 ESPlan: MPU R-110 - MPU R-110 - MPU R-110 wp02 350.00 349.41 60.12 56.78 17.992 SFPlan: MPU R-110 - MPU R-110 - MPU R-110 wp02 4,100.00 3,894.47 764.36 676.85 8.734 CCPlan: MPU R-111- MPU R-111- MPU R-111wp02 759.20 755.18 27.98 21.78 4.511 ESPlan: MPU R-111- MPU R-111- MPU R-111wp02 775.00 770.63 28.02 21.71 4.444 SFPlan: MPU R-111 - MPU R-111 - MPU R-111 wp02 825.00 819.41 28.68 22.07 4.337 CCPlan: MPU R-112 - MPU R-112 - MPU R-112 wp02 563.83 570.27 144.98 140.06 29.469 ESPlan: MPU R-112 - MPU R-112 - MPU R-112 wp02 600.00 606.80 145.16 139.96 27.920 SFPlan: MPU R-112 - MPU R-112 - MPU R-112 wp02 4,100.00 3,901.01 1,062.21 975.60 12.264 CCPlan: MPU R-113 - MPU R-113 - MPU R-113 wp02 605.25 615.80 173.96 168.68 32.995 ESPlan: MPU R-113 - MPU R-113 - MPU R-113 wp02 625.00 635.89 174.01 168.57 32.025 SFPlan: MPU R-113 - MPU R-113 - MPU R-113 wp02 4,200.00 3,938.75 1,196.94 1,109.80 13.736 CCPlan: MPU R-114 - MPU R-114 - MPU R-114 wp02 613.90 630.56 263.51 258.14 49.102 ESPlan: MPU R-114 - MPU R-114 - MPU R-114 wp02 650.00 667.70 263.67 258.01 46.558 SFPlan: MPU R-114 - MPU R-114 - MPU R-114 wp02 3,850.00 3,606.82 1,218.35 1,141.95 15.946 CCPlan: MPU R-143 - MPU R-143 - MPU R-143 wp05 528.50 534.77 209.29 204.68 45.332 ESPlan: MPU R-143 - MPU R-143 - MPU R-143 wp05 575.00 583.17 209.52 204.56 42.286 SFPlan: MPU R-143 - MPU R-143 - MPU R-143 wp05 900.00 902.58 243.20 235.72 32.502 CCPlan: MPU R-144 - MPU R-144 - MPU R-144 wp04 1,025.00 1,090.78 223.00 214.78 27.122 ESPlan: MPU R-144 - MPU R-144 - MPU R-144 wp04 1,026.13 1,091.87 223.00 214.77 27.095 8/30/2024 11:46:32AM COMPASS 5000.17 Build 02 CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page3 You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) Halliburton Anticollision Summary Report Well Plan: MPU R-104Local Co-ordinate Reference:Hilcorp Alaska, LLCCompany: As-Built: MPR-104 @ 63.75usftTVD Reference:Milne PointProject: As-Built: MPR-104 @ 63.75usftMD Reference:M Pt Raven PadReference Site: TrueNorth Reference:5.00 usftSite Error: Minimum CurvatureSurvey Calculation Method:Plan: MPU R-104Reference Well: Output errors are at 2.00 sigmaWell Error:0.00 usft Reference Wellbore MPU R-104 Database:EDM 5000.17 Single User Db Reference DatumReference Design:MPU R-104 wp03 Offset TVD Reference: Offset Well - Wellbore - Design Reference Measured Depth (usft) Offset Measured Depth (usft) Between Centres (usft) Between Ellipses (usft) Separation Factor Warning Summary Site Name Distance M Pt Raven Pad SFPlan: MPU R-144 - MPU R-144 - MPU R-144 wp04 1,225.00 1,283.16 241.07 231.38 24.864 CC, ESRig: MPU R-103 - MPU R-103 - MPU R-103 100.00 100.00 149.81 148.02 83.847 SFRig: MPU R-103 - MPU R-103 - MPU R-103 225.00 100.00 195.11 190.98 47.284 CCRig: MPU R-103 - MPU R-103 - MPU R-103 wp04 400.00 400.00 149.81 146.02 39.536 Collision Avoidance RequRig: MPU R-103 - MPU R-103 - MPU R-103 wp04 20,948.55 20,862.80 407.18 63.53 1.185 8/30/2024 11:46:32AM COMPASS 5000.17 Build 02 CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page4 You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) 0.001.002.003.004.00Separation Factor0 1075 2150 3225 4300 5375 6450 7525 8600 9675 10750 11825 12900 13975 15050 16125 17200 18275 19350 20425Measured Depth (2150 usft/in)MPU R-102MPU R-102 PB1MPU R-103 wp04MPU R-101MPU M-29MPU M-31MPU M-32MPU R-101 PB1MPU R-105 wp02MPU R-106 wp02MPU R-111 wp02No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU R-104 NAD 1927 (NADCON CONUS) Alaska Zone 04Ground Level: 16.80+N/-S +E/-WNorthingEasting Latittude Longitude0.000.006033332.390540483.860 70° 30' 7.208 N149° 40' 7.915 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU R-104, True NorthVertical (TVD) Reference: As-Built: MPR-104 @ 63.75usftMeasured Depth Reference:As-Built: MPR-104 @ 63.75usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2024-04-02T00:00:00 Validated: Yes Version:Depth From Depth To Survey/PlanTool46.95 4116.00 MPU R-104 wp03 (MPU R-104) GYD_Quest GWD4116.00 11385.50 MPU R-104 wp03 (MPU R-104) GYD_Quest GWD11385.50 20948.55 MPU R-104 wp03 (MPU R-104) GYD_Quest GWD0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 1075 2150 3225 4300 5375 6450 7525 8600 9675 10750 11825 12900 13975 15050 16125 17200 18275 19350 20425Measured Depth (2150 usft/in)Project: Milne PointSite: M Pt Raven PadWell: Plan: MPU R-104Wellbore: MPU R-104Plan: MPU R-104 wp03CASING DETAILSTVD MD Name Size2295.12 4116.00 13 3/8" x 16" 13-3/83958.73 11385.50 9 5/8" x 12 1/4" 9-5/83963.75 20948.55 4 1/2" x 8 1/2" 4-1/2You created this PDF from an application that is not licensed to print to novaPDF printer (http://www.novapdf.com) Revised 7/2022 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 Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The 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-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot 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 this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a 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 the Operator 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 all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. MILNE POINT 224-121 SCHRADER BLUFF OIL MPU R-104 WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:MILNE PT UNIT R-104Initial Class/TypeDEV / PENDGeoArea890Unit11328On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2241210MILNE POINT, SCHRADER BLFF OIL - 525140NA1 Permit fee attachedYes ADL025509, ADL388235, and ADL3550182 Lease number appropriateYes3 Unique well name and numberYes MILNE POINT, SCHRADER BLFF OIL - 525140 - governed by CO 477, 477.0054 Well located in a defined poolNo BHL is outside Milne Point Unit5 Well located proper distance from drilling unit boundaryNA6 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)Yes 20" 129.5# X-52 grouted to 80'18 Conductor string providedYes 13-3/8" 68# L-80 to 2278' TVD 4043' MD19 Surface casing protects all known USDWsYes Lead and tail volumes adequate20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes Fully cemented surface casing, 9-5/8" int casing cemented from shoe to 345'' TVD above the NA reservoir22 CMT will cover all known productive horizonsYes 13-3/8" 68# L-80 adequate for support across the permafrost23 Casing designs adequate for C, T, B & permafrostYes Parker 273 has adequate tankage and good trucking support24 Adequate tankage or reserve pitNA This is a grassroots well.25 If a re-drill, has a 10-403 for abandonment been approvedYes No collision risk identified in Halliburton collision scan26 Adequate wellbore separation proposedYes 16" Diverter27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes 5M 13-5/8" stack 1 annular 1 flow cross, 3 ram stack29 BOPEs, do they meet regulationYes 5000 psi stack pressure tested to 3000 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 shutdownNo New pad with no production history.33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not anticipated; however, rig will have H2S sensors and alarms35 Permit can be issued w/o hydrogen sulfide measuresYes Anticipating normally pressured reservoir. MPD to mitigate any abnormal pressures36 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]ApprADDDate9/18/2024ApprMGRDate9/18/2024ApprADDDate9/18/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 9/19/2024