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Home My WebLink About224-148STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________MILNE PT UNIT R-144 JBR 04/03/2025 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:2 Tested with 2-7/8" & 3-1/2" Test joints. F/P on K7, greased and passed retest, F/P on K8 swapped out, passed retest. N2 Precharge 1,043 PSI. Test Results TEST DATA Rig Rep:C. Greub / J. WerlingerOperator:Hilcorp Alaska, LLC Operator Rep:S. Heim / M. Heinz-Brown Rig Owner/Rig No.:Hilcorp ASR 1 PTD#:2241480 DATE:3/6/2025 Type Operation:WRKOV Annular: 250/2500Type Test:WKLY Valves: 250/2500 Rams: 250/2500 Test Pressures:Inspection No:bopJDH250307083441 Inspector Josh Hunt Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 6.5 MASP: 1415 Sundry No: 325-096 Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 0 NA Ball Type 2 P Inside BOP 1 P FSV Misc 0 NA 16 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 11"P #1 Rams 1 7' solid body NT #2 Rams 1 2-7/8" x 5-1/2 P #3 Rams 1 Blinds P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 2-1/16"P HCR Valves 1 2-1/16"P Kill Line Valves 3 2-1/16"P Check Valve 0 NA BOP Misc 2 2" Piper FP System Pressure P2900 Pressure After Closure P1850 200 PSI Attained P16 Full Pressure Attained P55 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P4@2,312 ACC Misc NA0 NA NATrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector 0 NAMS Misc Inside Reel Valves 0 NA Annular Preventer P15 #1 Rams NT0 #2 Rams P7 #3 Rams P5 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill NA0 9 9 9 9 9999 9 9 9 9 9 9 7HVWFKDUWVDWWDFKHG F/P on K7 F/P on K8 BOP Misc 2 FP2" Piper "0($$*OTQCPQKEI %23(7HVW+LOFRUS$65 038537' $2*&&,QVSERS-'+ $2*&&,QVSERS-'+ %23(7HVW+LOFRUS$65 038537' $2*&&,QVSERS-'+ Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 3/2/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250302 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# CLU 11 50133205590000 206058 2/19/2025 AK E-LINE CBL,CIBP CLU 11 50133205590000 206058 2/13/2025 AK E-LINE CIBP END 1-65A 50029226270100 203212 1/27/2025 HALLIBURTON COILFLAG END 2-56A 50029228630100 198058 2/6/2025 HALLIBURTON COILFLAG END 2-72 50029237810000 224016 2/2/2025 HALLIBURTON PPROF MPU F-29 50029226880000 196117 1/31/2025 HALLIBURTON MFC24 MPU L-02A 50029219980100 209147 2/17/2025 READ CaliperSurvey MPU L-36 50029227940000 197148 1/18/2025 HALLIBURTON MFC24 MPU R-144 50029238090000 224148 2/11/2025 HALLIBURTON WFL-TMD3D NCIU A-21 50883201990000 224086 2/18/2025 AK E-LINE Perf ODSN-25 50703206560000 212030 2/16/2025 READ MemoryLeakPoint PBU 06-05A 50029202980100 224115 1/15/2025 BAKER MRPM PBU 06-15A 50029204590200 224108 12/27/2024 HALLIBURTON RBT PBU 06-16B 50029204600200 223072 1/25/2025 BAKER MRPM PBU B-12B 50029203320200 224133 1/19/2025 BAKER MRPM PBU S-126B 50029233630200 224084 2/7/2025 HALLIBURTON RBT PBU V-105 50029230970000 202131 2/9/2025 HALLIBURTON IPROF PBU W-01A 50029218660100 203176 1/19/2025 AK E-LINE CBL PBU W-01B 50029218660200 224149 1/28/2025 HALLIBURTON RBT PCU 02A 50283200220100 224110 1/24/2025 AK E-LINE CIBP Please include current contact information if different from above. T40161 T40161 T40162 T40163 T40164 T40165 T40166 T40167 T40168 T40169 T40170 T40171 T40172 T40173 T40174 T40175 T40176 T40177 T40178 T40179 MPU R-144 50029238090000 224148 2/11/2025 HALLIBURTON WFL-TMD3D Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.03.03 10:15:14 -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, LTP Test 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): 15,310 NA Casing Collapse Conductor NA Surface 4,760psi Surface 3,090psi Tieback 5,410psi Liner 100 screens NA 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: 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 Taylor Wellman 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 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025509, ADL355018, ADL388235 224-148 C.O. 477.05 MILNE PT UNIT R-144 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23809-00-00 Hilcorp Alaska, LLC Length Size Proposed Pools: 4,198 15,309 4,198 1,415 SCHRADER BLUFF OIL Same 113' 113' 6.5# / L-80 TVD Burst 5,377 NA MD NA 7,240psi 3,538' 6,870psi 5,750psi 1,986' 4,124' 4,110' 2,037' 5,575' See Schematic 4,198'4-1/2" 113' 20" 9-5/8" 9-5/8" 2,037' 7"5,386' See Schematic 907-777-8449 twellman@hilcorp.com Operations Manager February 25, 2025 2-7/8" Perforation Depth MD (ft): MILNE POINT SLZXP LTP w/ DG Slips and NA 5,378' MD / 4,109' TVD NA 15,310' 5,386' 9,932' Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 325-096 By Gavin Gluyas at 7:46 am, Feb 21, 2025 Digitally signed by Scott Pessetto (9864) DN: cn=Scott Pessetto (9864) Date: 2025.02.20 18:24:35 - 09'00' Scott Pessetto (9864) MGR24FEB2024 SFD 2/24/2025 * BOPE test to 2500 psi. * OA MOASP to not exceed formation fracture pressure at casing leak at 1969' MD. * Compliance to CO 390A rule 1 to assure liner top packer providing barrier to fluid movement from below. * Notice to AOGCC if sudden breakthrough of SV2 water which could signal failure of liner top packer. DSR-2/24/25 10-404 *&: 2/24/2025Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.02.24 15:41:03 -09'00' RBDMS JSB 022525 RWO – LTP Barrier Well: MPU R-144 Date: 02/13/2025 Well Name:MPU R-144 API Number:50-029-23809-00-00 Current Status:SI – 9-5/8” Casing Leak Pad:R-Pad Estimated Start Date:02/25/25 Rig:ASR Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd:- Regulatory Contact:Tom Fouts Permit to Drill Number:224-148 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:241-00156.05 Job Type:RWO – LTP Barrier Current Bottom Hole Pressure:1,827 psi @ 4,135’ TVD Recently Drilled (02/04/25) |8.5 PPGE Kill Weight Brine: 8.7 PPGE to be used for RWO (ESP never unloaded wellbore) MPSP:1,415 psi (0.1 psi/ft gas gradient) Max Inclination: 92° @ 7,163’ MD (Reaches >70 deg at ±4,600’ MD) Brief Well Summary: MPU R-144 is a Schrader Oa production well that was drilled and completed on 11/26/2024. While drilling out the 9-5/8” stage tool, a casing leak was developed at ±1,968’ MD. This is due to a stabilizer in the string in the mill out BHA. A cement squeeze was attempted. Following the drillout of the cement squeeze a FIT was performed which indicated breakover at 577psi (12.44ppg). The lateral was drilled and the production screen completion was run. A test of the 7”x9-5/8” Liner Top Packer (LTP) was not performed. The 7” tie-back was run and tested to 1,500psi. The 2-7/8” ESP completion was run on 2/3/25. Objectives: Pull ESP completion / Set 4-1/2” Retrievable Plug / Pull 7” casing / Test LTP to Confirm Primary Barrier / Run 7” Casing / Pull 4-1/2” Plug / Run ESP Completion Notes Regarding Wellbore Condition: - 9-5/8” casing leak between 1,947’ – 1,992’ MD. Cmt squeeze pumped but broke over at 577psi. - 7” casing test to 1,500 psi on 02/01/2025 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. Pull the dummy valve from 4,531’ MD. 4. 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 8.7 PPG brine taking returns up the tbg and then the casing to 500 barrel returns tank. RWO – LTP Barrier Well: MPU R-144 Date: 02/13/2025 a.Note that 8.7 PPG brine to be used as this matches the completion fluid in the well. The ESP never unloaded the wellbore. 6. Line up to the OA and bullhead 8.7ppg brine down taking returns to the leak site at ±1,968’ MD. 7. Confirm well is dead. Contact operations engineer if freeze protection is needed prior to ASR arrival. 8. RD Little Red Services and reverse out skid. 9. 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 8.7 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” and 3-1/2” test joints. e. Test single solid ram on 7” test joint. f. 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 2-7/8” EUE 8 Rd thread. b. 2025 tubing PU weight on Doyon 14 (Block wt 40k) recorded as 77 kip. Slack off weight recorded as 68 kip. c. 2-7/8” L-80 EUE yield is 144 kip. 8. Confirm hanger free, lay down tubing hanger. 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. All tubing and jewelry to be re-used. c. Recorded Clamp Totals: i. Canon Clamps: 91 ii. Discharge Protectolizers: 1 iii. Seal to Pump Clamps: 1 iv. Seal Protecolizers: 1 v. Seal Clamps: 4 RWO – LTP Barrier Well: MPU R-144 Date: 02/13/2025 vi. Motor Protectolizers: 1 10. Lay Down ESP. 11. PU 3-1/2” workstring and TIH to set 4-1/2” retrievable bridge plug at ±5,500’ MD. a. There are 4 blank joints in the top of the liner from 5,404’ – 5,569’ MD. b. Close annular and pressure up 7” casing to 1,500psi to ensure plug set. 12. MU 7” landing joint and BOLDS. Close annular and strip up on the 7” casing until the circulation port on the seal assembly is exposed. a. Note: There is potential for the 7”x9-5/8” annulus to have diesel freeze protect that can’t be circulated out (bullheading through casing leak to be attempted in pre-rig steps) which could have an expected differential pressure of 200psi. Circulate out the diesel to ensure consistent fluid around wellbore. b. 2025 tubing PU weight on Doyon 14 (Block wt 40k) recorded as 142 kip. Slack off weight recorded as 125 kip. 13. Confirm hanger free, lay down tubing hanger. a. Contingency: RU casing jacks and utilize to offseat hanger. Pull 7” casing until ASR can take over on elevators. 14. POOH and lay down the 7” tie-back. 15. PU 3-1/2” workstring with 9-5/8” test packer. 16. TIH to ±2,040’ MD, set test packer and pressure test the 9-5/8”casing from ±2,040’ – 5,378’, the 7x9-5/8” liner top packer, 4 joints of 4-1/2” liner and the 4-1/2” retrievable bridge plug to 1,500psi for 30 min (charted). a. Contact OE: Taylor Wellman 907-947-9533 with results and troubleshooting as needed. 17. PU and RIH w/ 7”, 26#, L-80, TXP-BTC tie-back. a. Space out 7” casing to be ±2’ off the no-go landing ring. 18. Pressure test 7” casing to 1,500psi for30 min (charted). 19. PU workstring to TIH and pull 4-1/2” retrievable bridge plug from ±5,500’ MD. 20. RIH with new 2-7/8” 6.5# L-80 ESP completion to +/- 5,375’ 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. Nom. Size Length Item Lb/ft Material Notes 5.62 2 Centralizer 4 ±5,375’ 4.52 4 Intake Sensor 30 5.62 23 Motor - 360HP 80 5.13 9 Lower Tandem Seal (NEW)38 5.13 9 Upper Tandem Seal (NEW)38 5.38 8 Gas Separator 52 5.38 24 Pump – 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 RWO – LTP Barrier Well: MPU R-144 Date: 02/13/2025 2-7/8" Multiple 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" XN Nipple (2.205” No-GO)6.5 L-80 ±4,590’ MD 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" 1 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" GLM w/ DV installed 6.5 L-80 2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80 2-7/8" Multiple 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 21. Land tubing hanger and RILDS. Use extra caution to not damage cable. a. Test ESP electrically. 22. Lay down landing joint. 23. Set BPV. 24. 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. 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 2/6/2025 SCHEMATIC Milne Point Unit Well: MPU R-144 Last Completed: 2/4/2025 PTD: 224-148 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20"Conductor 129.5 / X56 / Weld N/A Surface 113’N/A 9-5/8"Surface 47 / L-80 / TXP 8.681 Surface 2,037’0.0732 9-5/8”Surface 40 / L-80 / TXP 8.835 2,037’5,575’0.0758 7”Tieback 26 / L-80 / TXP 6.276 Surface 5,386’0.0383 4-1/2”Liner 100ђ Screens 13.5 / L-80 / Hyd 625 3.920 5,378’15,310’0.0149 TUBING DETAIL 2-7/8"Tubing 6.5 / L-80 / EUE-8rd 2.441 Surface 5,377’0.0058 OPEN HOLE / CEMENT DETAIL 42”19 yds Cement 12-1/4"Stg 1 Lead – 444 sx / Tail – 400 sx Stg 2 Lead – 429 sx / Tail 270 sx 8-1/2”Uncemented Screened Liner WELL INCLINATION DETAIL KOP @ 450’ Max Hole Angle = 94° @7975’ TREE & WELLHEAD Tree FMC 11” x 4-1/2” TC-II Tubing Hanger x 2-7/8” EUE Wellhead 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs JEWELRY DETAIL No.Top MD Item ID 1 136’GLM: Patco 2-7/8” x 1” BK-2 w/ DPSOV 2.420” 2 4531’GLM: Patco 2-7/8” x 1 DV w/ BK Latch 2.450” 3 4588’XN Nipple, 2.313” w/ 2.205” No-Go 2.205” 4 5300’Pressure Discharge Sub 5 5301’Discharge Head 6 5301’Pump: 538, SJ2800 7 5325’Gas Separator / Intake: 538 8 5332’Upper Tandem Seal: 513 Series 9 5341’Lower Tandem Seal: 513 Series 10 5350’Motor: 562 Series, KMS2, 360HP / 3175V / 70A 11 5373’Motor Gauge: Summit 8K psi, SS, 2xtemp, 2xvib 12 5375’Centralizer: Anode, Triplate 13 5378’SLZXP LTP w/ DG Slips 6.180” 14 5390’7” H563 x 4-1/2” Hyd 625 3.850” 15 15,309’Shoe 4-1/2” SCREENS LINER Size Top (MD) Top (TVD) Btm (MD) Btm (TVD) 4-1/2”5569’4123’15271’4197’ GENERAL WELL INFO API: 50-029-23809-00-00 Completion Date: 2/4/2025 _____________________________________________________________________________________ Revised By: JNL 2/6/2025 PROPOSED SCHEMATIC Milne Point Unit Well: MPU R-144 Last Completed: 2/4/2025 PTD: 224-148 TD =15,310’(MD) / TD =4,198’(TVD) 4/5/6 20” Orig. KB Elev.: 50.59’ / GL Elev.: 16.7’ 7” 7/8/9 10 4 9-5/8” 1 Leak point @1,968’ 2 3 See Screen/ Solid Liner Detail PBTD =15,309’(MD) / PBTD = 4,198’(TVD) 9-5/8” Fidelis Cementer @ 2,020’ MD 4-1/2” 11 13 12 14 15 2-7/8”CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X56 / Weld N/A Surface 113’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,037’ 0.0732 9-5/8” Surface 40 / L-80 / TXP 8.835 2,037’ 5,575’ 0.0758 7” Tieback 26 / L-80 / TXP 6.276 Surface 5,386’ 0.0383 4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hyd 625 3.920 5,378’ 15,310’ 0.0149 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE-8rd 2.441 Surface 5,377’ 0.0058 OPEN HOLE / CEMENT DETAIL 42” 19 yds Cement 12-1/4"Stg 1 Lead – 444 sx / Tail – 400 sx Stg 2 Lead – 429 sx / Tail 270 sx 8-1/2” Uncemented Screened Liner WELL INCLINATION DETAIL KOP @ 450’ Max Hole Angle = 94° @7975’ TREE & WELLHEAD Tree FMC 11” x 4-1/2” TC-II Tubing Hanger x 2-7/8” EUE Wellhead 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs JEWELRY DETAIL No. Top MD Item ID 1 136’ GLM: Patco 2-7/8” x 1” BK-2 w/ DPSOV 2.420” 2 4531’ GLM: Patco 2-7/8” x 1 DV w/ BK Latch 2.450” 3 4588’ XN Nipple, 2.313”w/ 2.205” No-Go 2.205” 4 5300’ Pressure Discharge Sub 5 5301’ Discharge Head 6 5301’ Pump: 538, SJ2800 7 5325’ Gas Separator / Intake: 538 8 5332’ Upper Tandem Seal: 513 Series 9 5341’ Lower Tandem Seal: 513 Series 10 5350’ Motor: 562 Series, KMS2, 360HP / 3175V / 70A 11 5373’ Motor Gauge: Summit 8K psi, SS, 2xtemp, 2xvib 12 5375’ Centralizer: Anode, Triplate 13 5378’ SLZXP LTP w/ DG Slips 6.180” 14 5390’ 7” H563 x 4-1/2” Hyd 625 3.850” 15 15,309’ Shoe 4-1/2” SCREENS LINE Size Top (MD) Top (TVD) Btm (MD) Btm (TVD) 4-1/2” 5569’ 4123’ 15271’ 4197’ GENERAL WELL INFO API: 50-029-23809-00-00 Completion Date: 2/4/2025 Updated 8/25/2023 11” BOPE Shaffer 11'’-5000 CIW-U 4.30'Hydril GK 11" - 5000 2-7/8" x 5" VBR Blind 11'’- 5000 2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves HCRManualManual Stripping Head ManualManual 2-7/8" x 5" VBR Milne Point ASR 11” BOP w/ Jacks 05/17/2017 Milne Point ASR 11” BOP (Triple) 2023 7" Pipe Rams 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: 02/14/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL: WELL: MPU R-144 PTD: 224-148 API: 50-029-23809-00-00 FINAL LWD FORMATION EVALUATION + GEOSTEERING LOGS (01/11/2025 to 01/28/2025) x EWR-M5, AGR, ABG, DGR, ADR, Horizontal Presentation (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: Please include current contact information if different from above. 224-148 T40078 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.02.18 09:58:51 -09'00' From:Lau, Jack J (OGC) To:AOGCC Records (CED sponsored) Subject:FW: MPU R-144 (PTD 224-148) AOGCC Findings Date:Thursday, February 13, 2025 11:55:17 AM From: Lau, Jack J (OGC) Sent: Thursday, February 13, 2025 11:19 AM To: Taylor Wellman <twellman@hilcorp.com> Cc: Chmielowski, Jessie L C (OGC) <jessie.chmielowski@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: MPU R-144 (PTD 224-148) AOGCC Findings Taylor, The AOGCC has reviewed the risk assessment and associated data presented by Hilcorp, including the Oxygen Activation Evaluation Water Flow Detection report dated 2/12/2025, to evaluate the operability of well MPU R-144 (PTD 224-148). The commission’s findings are as follows: 1. There is insufficient verification to confirm the liner top packer as a barrier, consequently MPU R-144 is nonconformant with regulations set in 20 AAC 25.030(a) ensuring confinement of fluids to the wellbore, prevent migration of fluids between stratum, and protect significant hydrocarbon zones. 2. Regulation 20 AAC 25.015(b)(2) requires an approved Application for Sundry Approval for proposed changes to a PTD. Failure to perform the pressure test of the 9-5/8” x 7” annulus prescribed in step 17.21 of the approved PTD or receive approval to test the LTP by alternative means resulted in an untested barrier. 3. MPU R-144 is not approved for operation in its current state due to the lack of well barriers. Thanks, Jack Lau Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission (907) 793-1244 Office (907) 227-2760 Cell 1 Gluyas, Gavin R (OGC) From:Lau, Jack J (OGC) Sent:Friday, February 7, 2025 12:47 PM To:Taylor Wellman Cc:Rixse, Melvin G (OGC); McLellan, Bryan J (OGC); Nathan Sperry Subject:RE: [EXTERNAL] 20250119 1134 APPROVAL PTD 224-148 Hilcorp Well MPU R-144: C Taylor, We received and reviewed your summary of diagnostics, results, and proposed path forward. Based on the information presented, we do not find suƯicient verification to confirm the packer as a barrier. This well is not approved for operation due to the lack of any barriers. The AOGCC will continue to review any proposed plans designed to satisfactorily verify eƯective confinement and prevent fluid movement. Jack From: Taylor Wellman <twellman@hilcorp.com> Sent: Friday, February 7, 2025 9:57 AM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Nathan Sperry <Nathan.Sperry@hilcorp.com> Subject: FW: [EXTERNAL] 20250119 1134 APPROVAL PTD 224-148 Hilcorp Well MPU R-144: C Jack, Below is a summary of the diagnostics performed and the proposed path forward. Sorry for the delay in getting this to you but Phase 3 weather and digging out from it hindered our eƯorts. Please take your time to review and let me know if you’d like to discuss. Thank you, Taylor Summary of Diagnostics Performed Post Rig: - Freeze protect injected down the 7” casing. o 2/4/25: Initial T/I/O = 0/vac/90. OA was liquid packed. Built pressure to T/I/O = unrecorded/1000/90 psi at 0.4bpm. Not charted. - Attempted MIT-OA. o 2/5/25: MIT-OA attempted and failed. OA pressure increased from 90 psi to ~200 psi with 1-2 bbls of injection. Estimated leak rate of .15 bpm @ 200 psi. - Charted Drawdown Test of the LTP under IA Injection o 2/5/25: Initial T/I/O = 580/586/114. OA was liquid packed. Built pressure to T/I/O = 1175/1220/116 psi at 1.65bpm injecting down the IA. See attached chart. 1) OA Bleed o 2/6/25: Starting OA pressure = 100psi. Bleed OA to 30psi. OA built to 100 psi and looks to have stabilized. 2 Results - Injecting into the IA proved a repeatable method to establish ~800psi diƯerential pressure from below 7”x9-5/8” LTP. o Flowpath is down the 7” casing, out the screened liner and back up to underneath the 7”x9-5/8” LTP. o Lack of any pressure response on fluid packed OA while maintaining ~800 psi diƯerential from below for >10 min confirms integrity of the LTP and isolation of the OA from the reservoir.  The OA injection establishes at 200 psi. OA can be bled down and stabilized at 100 psi. OA MOASP can be set to alarm/detect OA pressure anomalies prior to establishing leakoƯ through hole in surface casing. Proposed Path: - OA MOASP will be set at 150 psi. Pressure alarm will be installed on the OA which will flag SCADA if exceeded. o If OA MOASP reached and not surface or thermally induced, then LTP drawdown test under IA injection will be performed per criteria below. o If OA pressurization confirmed to be from downhole, well to be shut in and plan to remediate LTP or casing leak initiated. - Perform yearly injection tests down the 7” casing to induce a minimum of 500psi diƯerential pressure across the 7”x9-5/8” LTP. o OA Fluid level to be taken prior to injection a. Duration of injection: 10 minutes with a min 500 psi IAxOA diƯerential o OA FL to be taken immediately following injection. o Passing Criteria:  OA FL movement less than 50’  OA pressure increase less than 10 psi o Failing Tests: Repeat. If repeated failing test, shut in well and prepare for RWO. o Tracking: This will be input into AKIMS (the same system that tracks and flags for annual tesƟng of injectors). - During next RWO perform one of the following: o Test the 7”x9-5/8” LTP to 1,000psi o Remediate the leak in the 9-5/8” casing and pressure test to 1,000psi Taylor Wellman Hilcorp Alaska, LLC: Wells Manager – Milne Point Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com From: Taylor Wellman <twellman@hilcorp.com> Sent: Wednesday, February 5, 2025 11:08 AM To: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Nathan Sperry <Nathan.Sperry@hilcorp.com> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] 20250119 1134 APPROVAL PTD 224-148 Hilcorp Well MPU R-144: C Jack, Thank you for talk yesterday. We are doing a couple of diagnosƟcs and then will be reaching back out with some more definiƟve numbers and plan on how to proceed with this well. -Taylor 3 Taylor Wellman Hilcorp Alaska, LLC: Wells Manager – Milne Point Office: (907) 777-8449 Cell: (907) 947-9533 Email: twellman@hilcorp.com From: Lau, Jack J (OGC) <jack.lau@alaska.gov> Sent: Tuesday, February 4, 2025 9:06 AM To: Nathan Sperry <nathan.sperry@hilcorp.com>; Taylor Wellman <twellman@hilcorp.com> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] 20250119 1134 APPROVAL PTD 224-148 Hilcorp Well MPU R-144: C Nathan, Taylor, As discussed, without the LTP being tested the well has zero proven well barriers, an untested primary and a failed secondary (casing leak). 20 AAC 25.030.a includes subsections regarding confinement and fluid migration. A holistic view of 20 AAC 25 stresses that barriers must be tested. An untested packer cannot be assumed to be sealing, which increases the risk of uncontrolled flow between the reservoir and the surface casing leak. API RP 90-1 (Annular Casing Pressure Management for Onshore Wells) stresses that well barriers must be tested and verified before being relied upon for pressure containment. As you explore options I recommend looking into API RP-90-1, as it provides guidance for impaired and untested barriers. What are your internal policies regarding barriers and testing? Jack From: Nathan Sperry <nathan.sperry@hilcorp.com> Sent: Monday, February 3, 2025 10:34 AM To: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Taylor Wellman <twellman@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: [EXTERNAL] 20250119 1134 APPROVAL PTD 224-148 Hilcorp Well MPU R-144: C Thanks Jack. The plan is to pump down the 2-7/8” x 7” annulus post-rig while monitoring the 7” x 9-5/8” annulus (in the direction of flow). Furthermore, OA pressure limit has been set at 450 psi in AKIMS. Nate Sperry Drilling Engineer Hilcorp Alaska, LLC From: Lau, Jack J (OGC) <jack.lau@alaska.gov> Sent: Monday, February 3, 2025 9:40 AM To: Nathan Sperry <nathan.sperry@hilcorp.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 4 Cc: Taylor Wellman <twellman@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: [EXTERNAL] 20250119 1134 APPROVAL PTD 224-148 Hilcorp Well MPU R-144: C Thanks Nathan. How do you plan to test the LTP? Jack From: Nathan Sperry <nathan.sperry@hilcorp.com> Sent: Monday, February 3, 2025 8:41 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Taylor Wellman <twellman@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: [EXTERNAL] 20250119 1134 APPROVAL PTD 224-148 Hilcorp Well MPU R-144: C Mel, Due to the hole in the casing, we would be unable to obtain an MIT-OA to verify the tieback integrity. We went ahead and made an additional run over the weekend with a 4-1/2” test packer after running the tieback. We set the test packer in the solid portion of the liner and performed a passing 1500 psi for 30 minutes. Please let me know if you have any questions or concerns. Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Tuesday, January 21, 2025 9:22 PM To: Nathan Sperry <nathan.sperry@hilcorp.com> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Taylor Wellman <twellman@hilcorp.com>; Joseph Lastufka <joseph.lastufka@hilcorp.com> Subject: [EXTERNAL] 20250119 1134 APPROVAL PTD 224-148 Hilcorp Well MPU R-144: C Nathan, Hilcorp is approved to proceed with drilling production hole on PTD 224-148 with an LOT of 14.6 ppge at 1919’ TVD. Please note that with this lower FIT Hilcorp will be required to maintain OA pressures at 1919’ TVD below the FIT value 14.6 ppge (or <572 psi with an 8.9 ppg annular fluid). If this is an impediment to production, I would urge another cement squeeze at the stage collar to possibly increase the maximum allowable annular pressure. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 5 Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 OƯice 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). cc. Jack Lau, Joe Lastufka, Taylor Wellman From: Nathan Sperry <Nathan.Sperry@hilcorp.com> Sent: Tuesday, January 21, 2025 8:14 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Taylor Wellman <twellman@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: [EXTERNAL] 20250119 1134 APPROVAL PTD 224-148 Hilcorp Well MPU R-144: Casing leak plan forward Mel, I’ve attached our FIT. The pressure started to break over at 572 PSI. Please note that I changed the Casing Setting Depth to the leak point depth. Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC From: Nathan Sperry <Nathan.Sperry@hilcorp.com> Sent: Sunday, January 19, 2025 12:26 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Taylor Wellman <twellman@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: [EXTERNAL] 20250119 1134 APPROVAL PTD 224-148 Hilcorp Well MPU R-144: Casing leak plan forward Mel, Annulus pressure limits are managed in our integrity management system, AKIMS. Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC 6 From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Sunday, January 19, 2025 11:35 AM To: Nathan Sperry <Nathan.Sperry@hilcorp.com> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov> Subject: [EXTERNAL] 20250119 1134 APPROVAL PTD 224-148 Hilcorp Well MPU R-144: Casing leak plan forward Nathan, Your plan forward below for drilling and completing this ESP SB well is approved. Can you refresh my memory how Hilcorp assures over the life of the well that the OA is never pressure tested above 1000 psi? By the way, I will be out of country starting on Wednesday for almost 3 weeks. Jack Lau will be covering for me, so I will copy him on this email and discuss the rationale on these issues. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 OƯice 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). cc. Jack Lau From: Nathan Sperry <Nathan.Sperry@hilcorp.com> Sent: Sunday, January 19, 2025 10:37 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: PTD 224-148 Hilcorp Well MPU R-144: Casing leak plan forward Good morning Mel, We have a 9-5/8” 47# L-80 casing leak between 1947’ and 1992’. We built up to ~1300 psi on our 2500 psi pressure test before pressure broke over. We propose the following plan forward: 2) Set a CIBP at 1992’ MD 3) Set a cement retainer at 1947’ MD. 4) Squeeze 50 bbls of 15.8ppg class G into the leak. 5) Wait until the cement develops 1000 psi compressive strength. 6) Drill out the retainer and CIBP. 7) Attempt a pressure test to 1,000 psi. a. If the test passes, we will proceed to bottom with the cleanout assembly and will drill up the shoetrack and perform an FIT. We will also reduce our assurance pressure test on our liner top packer from 1500 psi to 1000 psi. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 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. 7 b. If the test fails, we will plot up the pressure vs. strokes for an FIT and calculate the kick tolerance using the collar as the weak point. i. If the FIT does not provide 25 bbls kick tolerance, we will formulate a plan and will seek AOGCC approval. ii. If the FIT provides >25 bbls kick tolerance, we will proceed ahead with drilling out the shoetrack but will not perform another FIT. 1. 12.9ppg is needed for >25 bbls kick tolerance (389 psi). Kick Tolerance Assumptions  Leak point 1968’ MD / 1919’ TVD  8.46 ppg PP  9.0ppg test MW, 9.2 ppg drilling MW  8-1/2” hole, 200’ long 6-1/2” BHA w/ 5” DP  12.9ppg FIT provides 25.9bbls KT (minimum of 389 psi surface pressure during test required before breakover)  This is the 2nd of 3 wells in this current R-pad Schrader OA campaign and we have not encountered any PP/FG anomalies. There is no WAG/MI in the area. Additional information: MPU R-144 is the 4th well on R-pad in this pattern. Doyon 14 just moved oƯ R-143. The lateral of R-143 was drilled ~400’ away. There is no MI injection in the area. This is not a redevelopment. The expected pore pressure is 8.46ppg and we will be drilling ahead with MPD. R-144 has a planned tieback and be produced with an ESP. Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 8 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Lau, Jack J (OGC) To:AOGCC Records (CED sponsored) Subject:FW: [EXTERNAL] 20250119 1134 APPROVAL PTD 224-148 Hilcorp Well MPU R-144: C Date:Monday, February 3, 2025 9:42:31 AM From: Nathan Sperry <nathan.sperry@hilcorp.com> Sent: Monday, February 3, 2025 8:41 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Taylor Wellman <twellman@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: [EXTERNAL] 20250119 1134 APPROVAL PTD 224-148 Hilcorp Well MPU R-144: C Mel, Due to the hole in the casing, we would be unable to obtain an MIT-OA to verify the tieback integrity. We went ahead and made an additional run over the weekend with a 4-1/2” test packer after running the tieback. We set the test packer in the solid portion of the liner and performed a passing 1500 psi for 30 minutes. Please let me know if you have any questions or concerns. Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Tuesday, January 21, 2025 9:22 PM To: Nathan Sperry <nathan.sperry@hilcorp.com> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Taylor Wellman <twellman@hilcorp.com>; Joseph Lastufka <joseph.lastufka@hilcorp.com> Subject: [EXTERNAL] 20250119 1134 APPROVAL PTD 224-148 Hilcorp Well MPU R-144: C Nathan, Hilcorp is approved to proceed with drilling production hole on PTD 224-148 with an LOT of 14.6 ppge at 1919’ TVD. Please note that with this lower FIT Hilcorp will be required to maintain OA pressures at 1919’ TVD below the FIT value 14.6 ppge (or <572 psi with an 8.9 ppg annular fluid). If this is an impediment to production, I would urge another cement squeeze at the stage collar to possibly increase the maximum allowable annular pressure. 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). cc. Jack Lau, Joe Lastufka, Taylor Wellman From: Nathan Sperry <Nathan.Sperry@hilcorp.com> Sent: Tuesday, January 21, 2025 8:14 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Taylor Wellman <twellman@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: [EXTERNAL] 20250119 1134 APPROVAL PTD 224-148 Hilcorp Well MPU R-144: Casing leak plan forward Mel, I’ve attached our FIT. The pressure started to break over at 572 PSI. Please note that I changed the Casing Setting Depth to the leak point depth. Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC From: Nathan Sperry <Nathan.Sperry@hilcorp.com> Sent: Sunday, January 19, 2025 12:26 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Taylor Wellman <twellman@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: [EXTERNAL] 20250119 1134 APPROVAL PTD 224-148 Hilcorp Well MPU R-144: Casing leak plan forward Mel, Annulus pressure limits are managed in our integrity management system, AKIMS. Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Sunday, January 19, 2025 11:35 AM To: Nathan Sperry <Nathan.Sperry@hilcorp.com> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov> Subject: [EXTERNAL] 20250119 1134 APPROVAL PTD 224-148 Hilcorp Well MPU R-144: Casing leak plan forward Nathan, Your plan forward below for drilling and completing this ESP SB well is approved. Can you refresh my memory how Hilcorp assures over the life of the well that the OA is never pressure tested above 1000 psi? By the way, I will be out of country starting on Wednesday for almost 3 weeks. Jack Lau will be covering for me, so I will copy him on this email and discuss the rationale on these issues. 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 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. AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. Jack Lau From: Nathan Sperry <Nathan.Sperry@hilcorp.com> Sent: Sunday, January 19, 2025 10:37 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: PTD 224-148 Hilcorp Well MPU R-144: Casing leak plan forward Good morning Mel, We have a 9-5/8” 47# L-80 casing leak between 1947’ and 1992’. We built up to ~1300 psi on our 2500 psi pressure test before pressure broke over. We propose the following plan forward: 1. Set a CIBP at 1992’ MD 2. Set a cement retainer at 1947’ MD. 3. Squeeze 50 bbls of 15.8ppg class G into the leak. 4. Wait until the cement develops 1000 psi compressive strength. 5. Drill out the retainer and CIBP. 6. Attempt a pressure test to 1,000 psi. a. If the test passes, we will proceed to bottom with the cleanout assembly and will drill up the shoetrack and perform an FIT. We will also reduce our assurance pressure test on our liner top packer from 1500 psi to 1000 psi. b. If the test fails, we will plot up the pressure vs. strokes for an FIT and calculate the kick tolerance using the collar as the weak point. i. If the FIT does not provide 25 bbls kick tolerance, we will formulate a plan and will seek AOGCC approval. ii. If the FIT provides >25 bbls kick tolerance, we will proceed ahead with drilling out the shoetrack but will not perform another FIT. 1. 12.9ppg is needed for >25 bbls kick tolerance (389 psi). Kick Tolerance Assumptions Leak point 1968’ MD / 1919’ TVD 8.46 ppg PP 9.0ppg test MW, 9.2 ppg drilling MW 8-1/2” hole, 200’ long 6-1/2” BHA w/ 5” DP 12.9ppg FIT provides 25.9bbls KT (minimum of 389 psi surface pressure during test required before breakover) This is the 2nd of 3 wells in this current R-pad Schrader OA campaign and we have not encountered any PP/FG anomalies. There is no WAG/MI in the area. Additional information: MPU R-144 is the 4th well on R-pad in this pattern. Doyon 14 just moved off R-143. The lateral of R-143 was drilled ~400’ away. There is no MI injection in the area. This is not a redevelopment. The expected pore pressure is 8.46ppg and we will be drilling ahead with MPD. R-144 has a planned tieback and be produced with an ESP. Regards, Nate Sperry Drilling Engineer Hilcorp Alaska, LLC The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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 Sean McLaughlin Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU R-144 Hilcorp Alaska, LLC Permit to Drill Number: 224-148 Surface Location: 5236' FSL, 3834' FEL, Sec 07, T13N, R10E, UM, AK Bottomhole Location: 607' FNL, 827' FWL, Sec 36, T14N, R09E, UM, AK Dear Mr. McLaughlin: 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 1th day of December 2024. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.12.16 15:45:49 -09'00' Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2024.11.26 10:47:34 - 09'00' Sean McLaughlin (4311) By Grace Christianson at 1:32 pm, Nov 26, 2024 DSR-12/16/24 * BOPE pressure test to 3000 psi. Annular to 2500 psi. * Email casing test and FIT digital data upon completion to AOGCC. 224-148 50-029-23809-00-00 A.Dewhurst 05DEC24MGR05DEC2024*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.12.16 15:46:05 -09'00'12/16/24 12/16/24 RBDMS JSB 121824 Milne Point Unit (MPU) R-144 Application for Permit to Drill Version 1 11/25/2024 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 Diverter System ............................................................................................................... 11 11.0 Drill 12-1/4” Hole Section ....................................................................................................... 13 12.0 Run 9-5/8” Surface Casing ..................................................................................................... 16 13.0 Cement 9-5/8” Surface Casing ................................................................................................ 22 14.0 ND Diverter, NU BOPE, & Test ............................................................................................. 27 15.0 Drill 8-1/2” Hole Section ......................................................................................................... 28 16.0 Run 4-1/2” Screened Liner ..................................................................................................... 33 17.0 Run Tieback ............................................................................................................................ 37 18.0 Run Upper Completion – ESP ................................................................................................ 40 19.0 Doyon 14 Diverter Schematic ................................................................................................. 42 20.0 Doyon 14 BOP Schematic ....................................................................................................... 43 21.0 Wellhead Schematic ................................................................................................................ 44 22.0 Days Vs Depth ......................................................................................................................... 45 23.0 Formation Tops & Information.............................................................................................. 46 24.0 Anticipated Drilling Hazards ................................................................................................. 48 25.0 Doyon 14 Rig Layout .............................................................................................................. 51 26.0 FIT Procedure ......................................................................................................................... 52 27.0 Doyon 14 Rig Choke Manifold Schematic .............................................................................. 53 28.0 Casing Design .......................................................................................................................... 54 29.0 8-1/2” Hole Section MASP ...................................................................................................... 55 30.0 Spider Plot (NAD 27) (Governmental Sections) ..................................................................... 56 31.0 Surface Plat (As Built) (NAD 27) ............................................................................................ 57 Page 2 Milne Point Unit R-144 SB Producer PTD Application 1.0 Well Summary Well MPU R-144 Pad Milne Point “R” Pad Planned Completion Type ESP Target Reservoir(s) Schrader Bluff OA Sand Planned Well TD, MD / TVD 15,424’ MD / 4,175’ TVD PBTD, MD / TVD 15,424’ MD / 4,175’ TVD Surface Location (Governmental) 5236’ FSL, 3834’ FEL, Sec. 7, T13N, R10E, UM, AK Surface Location (NAD 27) X= 540745, Y=6033402 Top of Productive Horizon (Governmental)1017’ FSL, 69’ FEL, Sec. 1, T13N, R9E, UM, AK TPH Location (NAD 27) X= 539340, Y=6034455 BHL (Governmental) 607' FNL, 827’ FWL, Sec 36, T14N, R9E, UM, AK BHL (NAD 27) X= 534909, Y= 6043367 AFE Drilling Days 19 AFE Completion Days 4 Maximum Anticipated Pressure (Surface) 1397 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1808 psig Work String 5” 19.5# S-135 NC 50 Doyon 14 KB Elevation above MSL: 33.7 ft + 16.7 ft = 50.4 ft GL Elevation above MSL: 16.7 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Milne Point Unit R-144 SB Producer PTD Application 2.0 Management of Change Information Page 4 Milne Point Unit R-144 SB Producer PTD Application 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 12-1/4”9-5/8” 8.835” 8.679”10.625”40 L-80 TXP 5,750 3,090 916 9-5/8” 8.681” 8.525” 10.625” 47 L-80 TXP 6,870 4,750 1,086 Tieback 7” 6.276” 6.151” 7.656” 26 L-80 TXP 7,240 5,410 604 8-1/2”4-1/2” Screens 3.920” 3.795” 4.714” 13.5 L-80 Hydril 625 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” 3.25” 6.625” 19.5 S-135 DS50 36,100 43,100 560klb 5”4.276” 3.25” 6.625” 19.5 S-135 NC50 30,730 34,136 560klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Milne Point Unit R-144 SB Producer PTD Application 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. x Report covers operations from 6am to 6am x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. x Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates x Submit a short operations update each work day to sean.mclaughlin@hilcorp.com, nathan.sperry@hilcorp.com,and joseph.lastufka@hilcorp.com 5.3 Intranet Home Page Morning Update x 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 x Health and Safety: Notify EHS field coordinator. x Environmental: Drilling Environmental Coordinator x Notify Drilling Manager & Drilling Engineer on all incidents x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 5.6 Casing and Cement report x Send casing and cement report for each string of casing to nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Email Drilling Manager Sean Mclaughlin sean.mclaughlin@hilcorp.com Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com Completion Engineer Taylor Wellman 907.777.8449 twellman@hilcorp.com Geologist Graham Emerson 907.564.5242 Graham.emerson@hilcorp.com Drilling Env. Coordinator Adrian Kersten 907.564.4820 Adrian.kersten@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com _____________________________________________________________________________________ Revised By: JNL 11/26/2024 PROPOSED SCHEMATIC Milne Point Unit Well: MPU R-144 Last Completed: TBD PTD: TBD TD =15,424’(MD) / TD =4,175’(TVD) 4/5/6 20” Orig. KB Elev.: 50.4’ / GL Elev.: 16.7’ 7” 7/8/9 10 4 9-5/8” 1 2 3 See Screen/ Solid Liner Detail PBTD =15,423’(MD) / PBTD = 4,175’(TVD) 9-5/8” ‘ES’ Cementer @ ~2,500’ MD 4-1/2” 11 13 12 14 15 2-7/8”CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X56 / Weld N/A Surface 120’ N/A 9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,500’ 0.0732 9-5/8” Surface 40 / L-80 / TXP 8.835 2,500’ 5,520’ 0.0758 7” Tieback 26 / L-80 / TXP 6.276 Surface 5,370’ 0.0383 4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hyd 625 3.920 5,370’ 15,424’ 0.0149 TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE-8rd 2.441 Surface 5,300’ 0.0058 OPEN HOLE / CEMENT DETAIL 42” 19 yds Cement 12-1/4"Stg 1 Lead – 350 sx / Tail – 395 sx Stg 2 Lead – 673 sx / Tail 268 sx 8-1/2” Uncemented Screened Liner WELL INCLINATION DETAIL KOP @ 450’ Max Hole Angle = 94° @7975’ TREE & WELLHEAD Tree FMC 11” x 4-1/2” TC-II Tubing Hanger x 2-7/8” EUE Wellhead 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs JEWELRY DETAIL No. Top MD Item ID 1 151’ 2-7/8” x 1” BK-2 GLM w/ SOV 2.440” 2 4650’ 2-7/8” x 1” GLM Dummy Valve w/ BK Latch 2.440” 3 4710’ XN Nipple, 2.313”w/ 2.205” No-Go 2.205” 4 5224’ Discharge Sub 5 5225’ Discharge Bolt-On 6 5225’ Pump: 538, SJ2800 7 5249’ Pump Intake GS, 538 8 5256’ Upper Tandem Seal: 513 Series 9 5265’ Lower Tandem Seal: 513 Series 10 5274’ Motor: 562 Series, KMS2, 360HP 11 5298’ Sensor, 177C 8KPSI, 2x Press / Temp / Vib 12 5300’ Anode Centralizer: 13 5370’ SLZXP LTP w/ DG Slips 6.180” 14 5390’ 7” H563 x 5.5” EZGO HT XO 4.850” 15 15,424’ Shoe 4-1/2” SCREENS LINE Size Top (MD) Top (TVD) Btm (MD) Btm (TVD) 4-1/2” GENERAL WELL INFO API: TBD Completion Date: TBD Page 7 Milne Point Unit R-144 SB Producer PTD Application 7.0 Drilling / Completion Summary MPU R-144 is a grassroots producer planned to be drilled in the Schrader Bluff OA sand. R-144 is part of a multi-well program targeting the Schrader Bluff sand on R-pad The directional plan is 12-1/4” surface hole with 9-5/8” surface casing set in the top of the Schrader Bluff OA sand. An 8-1/2” lateral section will be drilled and completed with a 4-1/2” liner. The well will be produced with an ESP. Doyon 14 will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately January 7th, 2025, pending rig schedule. Surface casing will be run to 5,520’ MD / 4,116’ TVD and cemented to surface via a 2 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 then 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 Doyon 14 to well site 2. N/U & Test 21-1/4” Diverter and 16” diverter line 3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing 4. N/D diverter, N/U wellhead, NU 13-5/8” 5M BOP & Test 5. Drill 8-1/2” lateral to well TD 6. Run production liner 7. Run 7” tieback 8. Run Upper Completion 9. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Surface hole: No mud logging. Remote geologist. LWD: GR + Res 2. Production Hole: No mud logging. Remote geologist. LWD: GR + ADR (For geo-steering) Page 8 Milne Point Unit R-144 SB Producer PTD Application 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. x 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. x BOPs shall be tested at (2) week intervals during the drilling and completion of MPU R-144. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment will be to 250/3,000 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation 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. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements”. o Ensure the diverter vent line is at least 75’ away from potential ignition sources x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. x 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: x None Page 9 Milne Point Unit R-144 SB Producer PTD Application Summary of BOP Equipment & Notifications Hole Section Equipment Test Pressure (psi) 12 1/4”x 21-1/4” 2M Diverter w/ 16” Diverter Line Function Test Only 8-1/2” x 13-5/8” x 5M Hydril “GK” Annular BOP x 13-5/8” x 5M Hydril MPL Double Gate o Blind ram in btm cavity x Mud cross w/ 3” x 5M side outlets x 13-5/8” x 5M Hydril MPL Single ram x 3-1/8” x 5M Choke Line x 3-1/8” x 5M Kill line x 3-1/8” x 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3000 Subsequent Tests: 250/3000 Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air 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: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 10 Milne Point Unit R-144 SB Producer PTD Application 9.0 R/U and Preparatory Work 9.1 R-144 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 Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mud loggers WILL NOT be used on either hole section. 9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF). Page 11 Milne Point Unit R-144 SB Producer PTD Application 10.0 N/U Diverter System 10.1 N/U 21-1/4” Hydril MSP 2M Diverter System (Diverter Schematic attached to program). x N/U 16-3/4” 3M x 21-1/4” 2M DSA on 16-3/4” 3M wellhead. x N/U 21-1/4” diverter “T”. x Knife gate, 16” diverter line. x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). x Diverter line must be 75 ft from nearest ignition source x Place drip berm at the end of diverter line. 10.2 Notify AOGCC. Function test diverter. x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. x 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: x A prohibition on vehicle parking x A prohibition on ignition sources or running equipment x A prohibition on staged equipment or materials x Restriction of traffic to essential foot or vehicle traffic only. Page 12 Milne Point Unit R-144 SB Producer PTD Application 10.4 Rig & Diverter Orientation: x May change on location Page 13 Milne Point Unit R-144 SB Producer PTD Application 11.0 Drill 12-1/4” Hole Section 11.1 P/U 12-1/4” directional drilling assembly: x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x GWD will be the primary gyro tool. Take gyro surveys until MWD cleans up. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Drill string will be 5” 19.5# S-135. x 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. x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in conductor. 11.3 Drill 12-1/4” hole section to section TD in the Schrader OA sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. x Monitor the area around the conductor for any signs of broaching. If broaching is observed, stop drilling (or circulating) immediately notify the Drilling Engineer. x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100. x Hold a safety meeting with rig crews to discuss: x Conductor broaching ops and mitigation procedures. x Well control procedures and rig evacuation x Flow rates, hole cleaning, mud cooling, etc. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Keep mud as cool as possible to keep from washing out permafrost. x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure, or changes in hookload are seen. x Slow in/out of slips and while tripping to keep swab and surge pressures low. x Ensure shakers are functioning properly. Check for holes in screens on connections. x 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. x 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). x Perform gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled. x Gas hydrates are not expected. In MPU they have been encountered around 2,100’-2,400’ TVD (just below permafrost). Be prepared for hydrates: x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD x Monitor returns for hydrates, checking pressurized & non-pressurized scales Page 14 Milne Point Unit R-144 SB Producer PTD Application x 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. x 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. x Surface Hole AC: x There are no wells with a clearance factor of <1.0 11.4 12-1/4” hole mud program summary: x 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+ (For Hydrates if need based on offset wells) MW can be cut once ~500’ below hydrate zone x PVT System: 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. x Rheology: M-I 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. x Fluid Loss: DEXTRID and/or PAC UL should be used for filtrate control. Background LCM (10 ppb total) nut plug fine & medium, M-I-X II fine & medium can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. x Wellbore and mud stability:Additions of SCREENKLEEN 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 in the 8.5 – 9.0 range with caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action. x Casing Running:Reduce system YP with TANNATHIN / CF DESCO II as required 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). Page 15 Milne Point Unit R-144 SB Producer PTD Application System Type:8.8 – 9.2 ppg Pre-Hydrated M-I gel / freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp Surface 8.8 – 9.8 75-175 20 - 40 25-45 <10 8.5 – 9.0 70 F System Formulation: Gel + FW spud mud Product Concentration Fresh Water soda Ash M-I GEL caustic soda SCREENKLEEN MI WATE PAC-UL /DEXTRID LT ALDACIDE G 0.967 bbl 0.125 ppb 35 ppb 0.1 ppb (8.5 – 9.0 pH) as needed as required for 8.8 – 9.2 ppg if required for <10 FL 0.1 ppb 11.5 At TD, slowly rack back a stand at a time to avoid washing out the hole while CBU and pumping tandem sweeps. Ensure the mud is conditions prior to BROOH. 11.6 RIH to bottom, proceed to BROOH to HWDP x Pump at full drill rate (400-600 gpm), and maximize rotation. x Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions x Monitor well for any signs of packing off or losses. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.7 TOOH and LD BHA 11.8 No open hole logging program planned. Page 16 Milne Point Unit R-144 SB Producer PTD Application 12.0 Run 9-5/8” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U 9-5/8” casing running equipment (CRT & Tongs) x Ensure 9-5/8” TXP x NC50 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x R/U of CRT if hole conditions require. x R/U a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted to 8.5” on the location prior to running. x Note that 47# drift is 8.525” x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 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 9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’ 1 joint –9-5/8” TXP, 1 Centralizer mid joint with stop ring 9-5/8” HES Baffle Adaptor x Ensure bypass baffle is correctly installed on top of float collar. x Ensure proper operation of float equipment while picking up. x Ensure to record S/N’s of all float equipment and stage tool components. This end up. Bypass Baffle Page 17 Milne Point Unit R-144 SB Producer PTD Application 12.5 Float equipment and Stage tool equipment drawings: Page 18 Milne Point Unit R-144 SB Producer PTD Application 12.6 Continue running 9-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: x 1 centralizer every joint to ~ 1000’ MD from shoe x 1 centralizer every 2 joints to ~2,000’ above shoe (Top of Lowest Ugnu) x Verify depth of lowest Ugnu water sand for isolation with Geologist x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. x 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. 12.7 Install the Halliburton Fidelis Stage tool so that it is positioned at least 100’ TVD below the permafrost. x Install centralizers over couplings on 5 joints below and 5 joints above stage tool. x Do not place tongs on ES cementer, this can cause damaged to the tool. x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi. 9-5/8” 40# L-80 TXP Make-Up Torques: Casing OD Minimum Optimum Maximum 9-5/8”18,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs 9-5/8” 47# L-80 TXP MUT: Casing OD Minimum Optimum Maximum 9-5/8”21,440 ft-lbs 23,820 ft-lbs 26,200 ft-lbs Page 19 Milne Point Unit R-144 SB Producer PTD Application Page 20 Milne Point Unit R-144 SB Producer PTD Application 12.8 Continue running 9-5/8” surface casing x Centralizers: 1 centralizer every 3rd joint to 200’ from surface x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: o 1 centralizer every 2 joints to base of conductor 12.9 Ensure the permafrost is covered with 9-5/8” 47# from BPRF to Surface x Ensure drifted to 8.525” Page 21 Milne Point Unit R-144 SB Producer PTD Application 12.10 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.11 Slow in and out of slips. 12.12 P/U landing joint 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. 12.13 Lower casing to setting depth. Confirm measurements. 12.14 Have slips staged in cellar, along with necessary equipment for the operation. 12.15 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 22 Milne Point Unit R-144 SB Producer PTD Application 13.0 Cement 9-5/8” Surface Casing 13.1 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. x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. x 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 x Review test reports and ensure pump times are acceptable. x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 13.2 Document efficiency of all possible displacement pumps prior to cement job. 13.3 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. 13.4 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. 13.5 Fill surface cement lines with water and pressure test. 13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached. 13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. Estimated 1st Stage Total Cement Volume: Page 23 Milne Point Unit R-144 SB Producer PTD Application Cement Slurry Design (1st Stage Cement Job): 13.9 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 and continue with the cement job. 13.10 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. x Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.11 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug must be bumped. 13.12 Displacement calculation is in step 13.8 above. 80 bbls of tuned spacer to be left on top of stage tool so that the first fluid through the ES cementer is tuned spacer to minimize the risk of flash setting cement 13.13 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. 13.14 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. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool. 13.15 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, this is to ensure the stage tool is not prematurely opened. 13.16 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns 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 24 Milne Point Unit R-144 SB Producer PTD Application to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. 13.17 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. Page 25 Milne Point Unit R-144 SB Producer PTD Application Second Stage Surface Cement Job: 13.18 Prepare for the 2 nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety meeting. 13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.20 Fill surface lines with water and pressure test. 13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.22 Mix and pump cmt per below recipe for the 2 nd stage. 13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated 2nd Stage Total Cement Volume: Cement Slurry Design (2nd stage cement job): 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.25 After pumping cement, drop Fidelis closing plug and displace cement with spud mud out of mud pits. Lead Slurry Tail Slurry System ArcticCem HalCem Density 10.7 lb/gal 15.8 lb/gal Yield 2.88 ft3/sk 1.17 ft3/sk Mixed Water 22.02 gal/sk 5.08 gal/sk Page 26 Milne Point Unit R-144 SB Producer PTD Application 13.26 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.27 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. 13.28 Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips. 13.29 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump. Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 27 Milne Point Unit R-144 SB Producer PTD Application 14.0 ND Diverter, NU BOPE, & Test 14.1 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool. 14.2 NU 13-5/8” x 5M BOP as follows: x 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 x Double gate ram should be dressed with 4-1/2” x 7” VBRs in top cavity,blind ram in bottom cavity. x Single ram can be dressed with 2-7/8” x 5” VBRs x NU bell nipple, install flowline. x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 14.3 RU MPD RCD and related equipment 14.4 Run 5” BOP test plug 14.5 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min. x Test 4-1/2” x 7” rams with 4-1/2” and 7” test joints x Test 2-7/8” x 5” rams with the 2-7/8” and 5” test joints x Confirm test pressures with PTD x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.6 RD BOP test equipment 14.7 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.8 Mix 8.9 ppg FLOPRO NT fluid for production hole. 14.9 Set wearbushing in wellhead. 14.10 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole section. 14.11 Ensure 5” liners in mud pumps. Page 28 Milne Point Unit R-144 SB Producer PTD Application 15.0 Drill 8-1/2” Hole Section 15.1 If necessary, MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM) 15.2 TIH w/ 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool. 15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.4 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = ~2,875 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. 15.5 Drill out shoe track and 20’ of new formation. 15.6 CBU and condition mud for FIT. 15.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. x 12.0 ppg desired to cover shoe strength for expected ECD’s. A 9.9 ppg FIT is the minimum required to drill ahead x 9.9 ppg provides >25 bbls based on 9.5ppg MW, 8.46ppg PP (swab kick at 9.5ppg BHP) 15.8 POOH and LD cleanout BHA 15.9 PU 8-1/2” directional BHA. x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Ensure MWD is RU and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be 5” 19.5# S-135 NC50. x Run a 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 Page 29 Milne Point Unit R-144 SB Producer PTD Application 15.10 8-1/2” hole section mud program summary: x 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. x 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. x Rheology: Keep viscosifier additions to a minimum. 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 x Run the centrifuge continuously while drilling the production hole, this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x 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 System Formulation: Product- production ppb or (% liquids) Water 0.916 bbls/bbl Soda Ash 0.17 ppb FLO-VIS PLUS 0.5 –0.75 ppb FLO-TROL 6.0 ppb Potassium Chloride (KCl)10.7 ppb SCREENKLEEN 0.5% v/v SAFE-CARB 20 10 ppb SAFE-CARB 40 10 ppb SALT As needed Onyxide 200 2.1 gals/100 bbls Sodium Metabisulfite 0.25 ppb Page 30 Milne Point Unit R-144 SB Producer PTD Application 15.11 TIH with 8-1/2” directional assembly to bottom 15.12 Install MPD RCD 15.13 Displace wellbore to 8.9 ppg FloPro drilling fluid 15.14 Begin drilling 8-1/2” hole section, on-bottom staging technique: x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K. x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes 15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer. x Flow Rate: 350-550 GPM, target min. AV’s 200 ft/min, 385 GPM x RPM: 120+ x Include GWD in the BHA x 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. x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor torque and drag with pumps on every stand (confirm frequency with co-man) x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x 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. x Use ADR to stay in section. Reservoir plan is to stay in OA sand. x Limit maximum instantaneous ROP to < 250 FPH. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur. x Target ROP is as fast as we can clean the hole without having to backream connections x Schrader Bluff OA Concretions: 4-6% Historically x MPD will be utilized to monitor pressure build up on connections. x 8-1/2” Lateral A/C: x All wells have a clearance factor >1.0. 15.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons learned and best practices. Ensure the DD is referencing their procedure. x Patience is key! Getting kicked off too quickly might have been the cause of failed liner runs on past wells. x 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. x Attempt to lowside in a fast drilling interval where the wellbore is headed up. Page 31 Milne Point Unit R-144 SB Producer PTD Application x 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. x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ GPM) and rotation (120+ RPM). Pump tandem sweeps if needed x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum 15.17 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. 15.18 Displace 1.5 OH + Liner volume with viscosified brine. x 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 x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further discussion needed prior to BROOH. 15.15 Monitor the returned fluids carefully while displacing to brine. After 1 (or more if needed) BU, perform production screen test (PST). The brine has been properly conditioned when it will pass the production screen test (x3 350 ml samples passing through the screen in the same amount of time which will indicate no plugging of the screen). Reference PST Test Procedure 15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe x Circulate at full drill rate (less if losses are seen, 350 GPM minimum). x Rotate at maximum RPM that can be sustained. x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as dictated by hole conditions Page 32 Milne Point Unit R-144 SB Producer PTD Application x 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 15.20 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while BROOH. 15.21 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps. 15.22 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary. x 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 x If necessary, increase MW at shoe for any higher than expected pressure seen x Ensure fluid coming out of hole has passed a PST at the possum belly 15.23 POOH and LD BHA. 15.24 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit diameter is sufficient for future ball drops. Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any additional logging runs conducted. Page 33 Milne Point Unit R-144 SB Producer PTD Application 16.0 Run 4-1/2” Screened Liner NOTE: If an open hole sidetrack was performed, drop the centralizers on the lowermost 2-3 joints and run them slick. 16.1 Well control preparedness: In the event of an influx of formation fluids while running the screened liner, the following well control response procedure will be followed: x P/U & M/U the 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” screened liner. x Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW. x Proceed with well kill operations. 16.2 R/U liner running equipment. x Ensure 4-1/2” 13.5# Hydril 625 x NC50 crossover is on rig floor and M/U to FOSV. x Ensure all casing has been drifted on the deck prior to running. x Be sure to count the total # of joints on the deck before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 16.3 Run screened production liner x Use API Modified or “Best O Life 2000 AG”thread compound. Dope pin end only w/ paint brush. Wipe off excess. Thread compound can plug the screens x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Use lift nubbins and stabbing guides for the liner run. x Fill liner with PST passed mud (to keep from plugging screens with solids) x Install screen joints as per the Running Order (From Operations Engineer post TD). o Do not place tongs or slips on screen joints o Screen placement ±40’ x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint outside of the surface shoe. This is to mitigate difference sticking risk while running inner string. x Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm Page 34 Milne Point Unit R-144 SB Producer PTD Application 4-1/2” 13.5# L-80 Hydril 625 Torque OD Minimum Optimum Maximum 4-1/2 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs Page 35 Milne Point Unit R-144 SB Producer PTD Application 16.6. Ensure to run enough liner to provide for approx 150’ overlap inside 9-5/8” casing. Ensure hanger/pkr will not be set in a 9-5/8” connection. x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8” connection. 16.7. 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. 16.8. M/U Baker SLZXP liner top packer to liner. 16.9. 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. 16.10. 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. x Ensure 5” DP/HWDP has been drifted x 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. 16.11. 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. 16.12. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. 16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.15. Rig up to pump down the work string with the rig pumps. 16.16. 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 16.17. 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. Page 36 Milne Point Unit R-144 SB Producer PTD Application 16.18. Shut down pumps. Drop setting ball (ball seat now located in HRDE setting tool) down the workstring and pump slowly (1-2 BPM). Slow pump before the ball seats. Do not allow ball to slam into ball seat. 16.19. 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. 16.20. 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. 16.21. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted. 16.22. 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. 16.23. PU pulling running tool free of the packer and displace with at max rate to wash the liner top. Pump sweeps as needed. 16.24. 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 37 Milne Point Unit R-144 SB Producer PTD Application 17.0 Run Tieback 17.1 RU and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder to be used for tie-back space out calculation. If 4-1/2” x 7” rams have not been tested with a 7” test joint, RU testing equipment. PT to 250/3,000 psi with 7” test joint. RD testing equipment. 17.2 RU 7” casing handling equipment. x Ensure XO to DP made up to FOSV and ready on rig floor. x Rig up computer torque monitoring service. x String should stay full while running, RU fill up line and check as appropriate. 17.3 PU 7” tieback seal assembly and set in rotary table. Ensure 7” seal assembly has (4) 1” holes above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8” x 7” annulus. 17.4 MU first joint of 7” to seal assy. 17.6 Run 7”, 26#, L-80 TXP tieback tieback to position seal assembly two joints above tieback sleeve. Record PU and SO weights. 7”, 26#, L-80, TXP =Casing OD Torque (Min) Torque (Opt)Torque (Max)Torque (Operating) 7”13,280 ft-lbs 14,750 ft-lbs 16,230 ft-lbs 20,000 ft-lbs Page 38 Milne Point Unit R-144 SB Producer PTD Application Page 39 Milne Point Unit R-144 SB Producer PTD Application 17.7 MU 7” to DP crossover. 17.8 MU stand of DP to string, and MU top drive. 17.9 Break circulation at 1 BPM and begin lowering string. 17.10 Note seal assembly entering tieback sleeve with a pressure increase, stop pumping and bleed off pressure. Leave standpipe bleed off valve open. 17.11 Continue lowering string and land out on no-go. Set down 5 – 10K and mark the pipe as “NO- GO DEPTH”. 17.12 PU string & remove unnecessary 7” joints. 17.13 Space out with pups as needed to leave the no-go 1 ft above fully no-go position when the casing hanger is landed. Ensure one full joint is below the casing hanger. 17.14 PU and MU the 7” casing hanger. 17.15 Ensure circulation is possible through 7” string. 17.16 RU and circulation corrosion inhibited brine in the 9-5/8” x 7” annulus. 17.17 With seals stabbed into tieback sleeve, spot diesel freeze protection from 2,500’ TVD to surface in 9-5/8” x 7” annulus by reverse circulating through the holes in the seal assembly. Ensure annular pressure are limited to prevent collapse of the 7” casing (verify collapse pressure of 7” tieback seal assembly). 17.18 SO and land hanger. Confirm hanger has seated properly in wellhead. Make note of actual weight on hanger on morning report. 17.19 Back out the landing joint. MU packoff running tool and install packoff on bottom of landing joint. Set casing hanger packoff and RILDS. PT void to 3,000 psi for 10 minutes. 17.20 RD casing running tools. 17.21 PT 9-5/8” x 7” annulus to 1,500 psi for 30 minutes charted. Page 40 Milne Point Unit R-144 SB Producer PTD Application 18.0 Run Upper Completion – ESP 18.1 Perform BOP Test on the VBR’s and annular for running 2-7/8” tubing to 250/3500psi. 18.2 M/U production assembly and RIH to setting depth. TIH no faster than 90 ft/min. x Ensure wear bushing is pulled. x Ensure 2-7/8” EUE 8RD x NC-50 crossover is on rig floor and M/U to FOSV. x Ensure all tubing has been drifted in the pipe shed prior to running. x Ensure that the ESP Cable spooler is rigged up on the rig floor. x Be sure to count the total # of joints in the pipe shed before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. x Monitor displacement from wellbore while RIH. 2-7/8” EUE Make-Up Torques Casing OD Minimum Optimum Maximum Operating Torque 2.875” 1,690 ft-lbs 2,250 ft-lbs 2,810 ft-lbs 2-Ǭ” Upper Completion Running Order x Centralizer (OD = ±5.85”), Base at ±5,200’ MD x Intake Sensor x 360Hp 562 Motor (OD = 5.62”) x Lower Seal Section x Upper Seal Section x Intake / Gas Separator x Pump Section 3 x Pump Section 2 x Pump Section 1 x Discharge Head x Joints 2-7/8”, 6.5#, L-80, EUE 8rd tubing x XN Nipple 2-7/8”, 6.5#, L-80, EUE 8rd, ID = 2.25”, (+/-4,700’ MD - <70deg inclination) x 1 joint 2-7/8”, 6.5#, L-80, EUE 8rd tubing x ±10’ Pup Joint 2-7/8”, 6.5#, L-80, EUE 8rd x 2-7/8” GLM (Dmy GLV installed) Page 41 Milne Point Unit R-144 SB Producer PTD Application x ±10’ Pup Joint 2-7/8”, 6.5#, L-80, EUE 8rd x Joints 2-7/8”, 6.5#, L-80, EUE 8rd tubing x ±10’ Pup Joint 2-7/8”, 6.5#, L-80, EUE 8rd x 2-7/8” GLM (+/-140’ MD), LGLV installed x ±10’ Pup Joint 2-7/8”, 6.5#, L-80, EUE 8rd x 1 joint 2-7/8”, 6.5#, L-80, EUE 8rd tubing x 2-7/8”, 6.5#, L-80, EUE 8rd space out pups (if needed) x 1 joint 2-7/8”, 6.5#, L-80, EUE 8rd tubing x Tubing hanger with 2-7/8”, 6.5#, L-80, EUE 8rd pin down 18.3 Follow all service company procedures for handling, make up and deployment of the ESP system. x Typical clamping is every joint for the first 15 joints and then every other joint to surface. Make note of clamping performed in tally. x Perform electrical continuity checks every 2,000’ MD. 18.4 Land hanger. RILDs and test hanger. 18.5 Set BPV, ensure new body seals are installed each time. ND BOPE and NU adapter flange and tree. 18.6 Pull BPV. Set TWC. Test tree to 5000 psi. 18.7 Pull TWC. Set BPV. Bullhead tubing & IA freeze protect if/as needed. Contact Wells Foreman (670-3330) or Wellsite Supervisor (670-3387) for discussion. 18.8 Secure the tree and cellar. Page 42 Milne Point Unit R-144 SB Producer PTD Application 19.0 Doyon 14 Diverter Schematic Page 43 Milne Point Unit R-144 SB Producer PTD Application 20.0 Doyon 14 BOP Schematic Page 44 Milne Point Unit R-144 SB Producer PTD Application 21.0 Wellhead Schematic Page 45 Milne Point Unit R-144 SB Producer PTD Application 22.0 Days Vs Depth Page 46 Milne Point Unit R-144 SB Producer PTD Application 23.0 Formation Tops & Information TOP NAME TVD (FT) TVDSS (FT) MD (FT) Formation Pressure (psi) EMW (ppg) Base Permafrost 1868 1818 1938 822 8.46 SV1 2060 2009 2143 906 8.46 UG4 2387 2337 2486 1050 8.46 UG_MB 3723 3673 4094 1638 8.46 SB NA 3956 3906 4640 1740 8.46 SB OA 4110 4060 5448 1808 8.46 Page 47 Milne Point Unit R-144 SB Producer PTD Application L-Pad Data Sheet Formation Description (Closest & Most Analogous MPU Pad to R-Pad) Page 48 Milne Point Unit R-144 SB Producer PTD Application 24.0 Anticipated Drilling Hazards 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 hydrates have not been seen on R-pad. 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 ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPM’s 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 no known wells with a clearance factory <1.0. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Well Specific A/C: x There are no wells with a clearance factor of <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. Page 49 Milne Point Unit R-144 SB Producer PTD Application 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. Page 50 Milne Point Unit R-144 SB Producer PTD Application 8-1/2” Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up with appropriate screens 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. Maint. 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 are multiple planned fault crossings for R-144. Be prepared for additional ‘sub-seismic’ fault crossings as well. 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. 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: x All wells have a clearance factor > 1.0. Page 51 Milne Point Unit R-144 SB Producer PTD Application 25.0 Doyon 14 Rig Layout Page 52 Milne Point Unit R-144 SB Producer PTD Application 26.0 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. Page53Milne Point UnitR-144 SB ProducerPTD Application27.0 Doyon 14 Rig Choke Manifold Schematic Page 54 Milne Point Unit R-144 SB Producer PTD Application 28.0 Casing Design Page 55 Milne Point Unit R-144 SB Producer PTD Application 29.0 8-1/2” Hole Section MASP Page 56 Milne Point Unit R-144 SB Producer PTD Application 30.0 Spider Plot (NAD 27) (Governmental Sections) Page 57 Milne Point Unit R-144 SB Producer PTD Application 31.0 Surface Plat (As Built) (NAD 27) 6WDQGDUG3URSRVDO5HSRUW 1RYHPEHU 3ODQ0385ZS +LOFRUS$ODVND//& 0LOQH3RLQW 03W5DYHQ3DG 3ODQ0385 0385 075015002250300037504500True Vertical Depth (1500 usft/in)-1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500Vertical Section at 330.10° (1500 usft/in)MPU R-144 wp05 tgt7MPU R-144 wp05 tgt9MPU R-144 wp05 tgt11MPU R-144 wp05 tgt13MPU R-144 wp05 tgt15MPU R-144 wp06 tgt2MPU R-144 wp06 tgt5MPU R-144 wp07 tgt around F-09MPU R-144 wp10 tgt3MPU R-144 wp10 tgt19 5/8" x 12 1/4"4 1/2" x 8 1/2"500100015002000250030003500400045005000550060006500700075008000850090009500100001050011000115001200012500130001350014000145001500015424MPU R-144 wp11Start Dir 3º/100' : 450' MD, 450'TVDEnd Dir : 1162.56' MD, 1146.15' TVDStart Dir 3.5º/100' : 2084.96' MD, 2005.09'TVDEnd Dir : 4510.93' MD, 3911.94' TVDStart Dir 3.75º/100' : 4710.93' MD, 3980.34'TVDEnd Dir : 5213.87' MD, 4089.25' TVDBegin GeosteeringTotal Depth : 15423.96' MD, 4175.4' TSV5Base PermafrostSV1UG4ALA3UG_MBSB_NaSB_OaHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: MPU R-14416.70+N/-S+E/-WNorthingEastingLatittudeLongitude0.000.006033402.45540744.57 70° 30' 7.8830 N 149° 40' 0.2270 WSURVEY PROGRAMDate: 2024-10-18T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool33.70 5520.00 MPU R-144 wp11 (MPU R-144) GYD_Quest GWD5520.00 15423.96 MPU R-144 wp11 (MPU R-144) GYD_Quest GWDFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation1376.89 1326.49 1410.35 SV51868.40 1818.00 1938.18 Base Permafrost2059.51 2009.11 2143.13 SV12387.36 2336.96 2485.82 UG4A3424.34 3373.94 3641.40 LA33723.14 3672.74 4094.04 UG_MB3955.95 3905.55 4639.61 SB_Na4109.66 4059.26 5448.01 SB_OaREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU R-144, True NorthVertical (TVD) Reference:R-144 as built doyon14 @ 50.40usftMeasured Depth Reference:R-144 as built doyon14 @ 50.40usftCalculation Method: Minimum CurvatureProject:Milne PointSite:M Pt Raven PadWell:Plan: MPU R-144Wellbore:MPU R-144Design:MPU R-144 wp11CASING DETAILSTVD TVDSS MD SizeName4115.93 4065.53 5520.00 9-5/8 9 5/8" x 12 1/4"4175.40 4125.00 15423.96 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 33.70 0.00 0.00 33.70 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 0.00 Start Dir 3º/100' : 450' MD, 450'TVD3 1162.56 21.38 196.87 1146.15 -125.74 -38.14 3.00 196.87 -89.99 End Dir : 1162.56' MD, 1146.15' TVD4 2084.96 21.38 196.87 2005.09 -447.48 -135.73 0.00 0.00 -320.25 Start Dir 3.5º/100' : 2084.96' MD, 2005.09'TVD5 4510.93 70.00 329.00 3911.94 236.45 -1019.03 3.50 135.60 712.95 End Dir : 4510.93' MD, 3911.94' TVD6 4710.93 70.00 329.00 3980.34 397.55 -1115.82 0.00 0.00 900.86 Start Dir 3.75º/100' : 4710.93' MD, 3980.34'TVD7 5213.87 85.00 340.75 4089.25 840.62 -1321.98 3.75 38.87 1387.72 End Dir : 5213.87' MD, 4089.25' TVD8 5513.87 85.00 340.75 4115.40 1122.77 -1420.52 0.00 0.00 1681.43 MPU R-144 wp10 tgt19 5658.40 88.37 338.01 4123.76 1257.78 -1471.32 3.00 -39.13 1823.8010 6306.31 88.37 338.01 4142.22 1858.33 -1713.79 0.00 0.00 2465.2811 6416.68 89.74 335.00 4144.04 1959.52 -1757.77 3.00 -65.55 2574.9312 6716.68 89.74 335.00 4145.40 2231.41 -1884.56 0.00 0.00 2873.83 MPU R-144 wp06 tgt213 6822.04 90.57 337.50 4145.11 2327.84 -1926.99 2.50 71.63 2978.5814 7002.04 90.57 337.50 4143.32 2494.13 -1995.87 0.00 0.00 3157.0715 7302.04 90.57 330.00 4140.34 2762.99 -2128.45 2.50 -89.96 3456.2316 7496.29 90.50 325.14 4138.52 2926.89 -2232.58 2.50 -90.80 3650.2217 7819.67 90.50 325.14 4135.70 3192.24 -2417.39 0.00 0.00 3972.3818 7853.90 90.50 326.00 4135.40 3220.47 -2436.74 2.50 90.00 4006.50 MPU R-144 wp10 tgt319 7975.23 94.00 325.00 4130.64 3320.37 -2505.39 3.00 -15.92 4127.3320 8062.23 94.00 325.00 4124.57 3391.46 -2555.17 0.00 0.00 4213.7721 8213.89 91.27 328.64 4117.59 3518.24 -2638.06 3.00 126.78 4364.9922 8756.98 91.27 328.64 4105.56 3981.89 -2920.60 0.00 0.00 4907.7723 9103.37 86.74 338.00 4111.59 4290.92 -3075.90 3.00 115.86 5253.0824 9258.37 86.74 338.00 4120.40 4434.40 -3133.87 0.00 0.00 5406.36 MPU R-144 wp06 tgt525 9295.97 85.80 338.00 4122.85 4469.19 -3147.92 2.50 180.00 5443.5326 9415.97 85.80 338.00 4131.63 4580.15 -3192.76 0.00 0.00 5562.0727 9573.09 89.56 336.86 4137.99 4725.10 -3253.00 2.50 -16.81 5717.7528 10447.08 89.56 336.86 4144.69 5528.78 -3596.38 0.00 0.00 6585.6329 10561.88 89.73 334.00 4145.40 5633.17 -3644.10 2.50 -86.63 6699.91 MPU R-144 wp05 tgt730 10733.09 93.73 332.47 4140.24 5785.93 -3721.15 2.50 -20.98 6870.7631 10807.88 93.73 332.47 4135.38 5852.11 -3755.65 0.00 0.00 6945.3232 10960.97 90.00 333.34 4130.40 5988.30 -3825.34 2.50 166.79 7098.1233 11760.97 90.00 333.34 4130.40 6703.25 -4184.29 0.00 0.00 7896.84 MPU R-144 wp05 tgt934 11890.61 86.76 333.20 4134.06 6818.97 -4242.57 2.50 -177.46 8026.2135 12026.59 86.76 333.20 4141.74 6940.15 -4303.79 0.00 0.00 8161.7836 12156.10 90.00 333.21 4145.40 7055.69 -4362.15 2.50 0.24 8291.0337 13006.10 90.00 333.21 4145.40 7814.45 -4745.26 0.00 0.00 9139.78 MPU R-144 wp05 tgt1138 13159.78 93.83 333.55 4140.27 7951.74 -4814.07 2.50 5.03 9293.0939 13186.72 93.83 333.55 4138.47 7975.80 -4826.05 0.00 0.00 9319.9240 13378.60 89.04 333.24 4133.67 8147.26 -4911.93 2.50 -176.33 9511.3741 14078.60 89.04 333.24 4145.40 8772.20 -5227.07 0.00 0.00 10210.22 MPU R-144 wp05 tgt1342 14238.95 86.03 335.89 4152.29 8916.84 -5295.86 2.50 138.67 10369.9043 14318.97 86.03 335.89 4157.83 8989.71 -5328.46 0.00 0.00 10449.3244 14448.96 89.28 335.79 4163.15 9108.20 -5381.61 2.50 -1.81 10578.5445 15423.96 89.28 335.79 4175.40 9997.38 -5781.41 0.00 0.00 11548.66 MPU R-144 wp05 tgt15 Total Depth : 15423.96' MD, 4175.4' TVD -600 0 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 6600 7200 7800 8400 9000 9600 10200 South(-)/North(+) (1200 usft/in)-6600 -6000 -5400 -4800 -4200 -3600 -3000 -2400 -1800 -1200 -600 0 600 1200 1800 West(-)/East(+) (1200 usft/in) MPU R-144 wp10 tgt1 MPU R-144 wp10 tgt3 MPU R-144 wp07 tgt around F-09 MPU R-144 wp06 tgt5 MPU R-144 wp06 tgt2 MPU R-144 wp05 tgt15 MPU R-144 wp05 tgt13 MPU R-144 wp05 tgt11 MPU R-144 wp05 tgt9 MPU R-144 wp05 tgt7 9 5/8" x 12 1/4" 4 1/2" x 8 1/2" 250 1250 2000 2500300035003 7 5 0 4 0 0 0 4 1 7 5 M P U R -1 4 4 w p 1 1 Start Dir 3º/100' : 450' MD, 450'TVD End Dir : 1162.56' MD, 1146.15' TVD Start Dir 3.5º/100' : 2084.96' MD, 2005.09'TVD End Dir : 4510.93' MD, 3911.94' TVD Start Dir 3.75º/100' : 4710.93' MD, 3980.34'TVD End Dir : 5213.87' MD, 4089.25' TVD Begin Geosteering Total Depth : 15423.96' MD, 4175.4' TVD CASING DETAILS TVD TVDSS MD Size Name 4115.93 4065.53 5520.00 9-5/8 9 5/8" x 12 1/4" 4175.40 4125.00 15423.96 4-1/2 4 1/2" x 8 1/2" Project: Milne Point Site: M Pt Raven Pad Well: Plan: MPU R-144 Wellbore: MPU R-144 Plan: MPU R-144 wp11 WELL DETAILS: Plan: MPU R-144 16.70 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 6033402.45 540744.57 70° 30' 7.8830 N 149° 40' 0.2270 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: MPU R-144, True North Vertical (TVD) Reference:R-144 as built doyon14 @ 50.40usft Measured Depth Reference:R-144 as built doyon14 @ 50.40usft Calculation Method:Minimum Curvature 3URMHFW &RPSDQ\ /RFDO&RRUGLQDWH5HIHUHQFH 79'5HIHUHQFH 6LWH +LOFRUS$ODVND//& 0LOQH3RLQW 03W5DYHQ3DG 6WDQGDUG3URSRVDO5HSRUW :HOO :HOOERUH 3ODQ0385 0385 6XUYH\&DOFXODWLRQ0HWKRG0LQLPXP&XUYDWXUH 5DVEXLOWGR\RQ#XVIW 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Plan: MPU R-144, True NorthVertical (TVD) Reference:R-144 as built doyon14 @ 50.40usftMeasured Depth Reference:R-144 as built doyon14 @ 50.40usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2024-10-18T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.70 5520.00 MPU R-144 wp11 (MPU R-144) GYD_Quest GWD5520.00 15423.96 MPU R-144 wp11 (MPU R-144) GYD_Quest GWD0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 5400 5700Measured Depth (600 usft/in)MPU R-145 wp05MPU R-112 wp02MPU R-113 wp02MPU R-115 wp02MPU R-119 wp02MPU R-114 wp02MPU R-143 wp11MPU R-118 wp02MPU R-108 wp02MPU R-109 wp02NO GLOBAL FILTER: Using user defined selection & filtering criteria33.70 To 15423.96Project: Milne PointSite: M Pt Raven PadWell: Plan: MPU R-144Wellbore: MPU R-144Plan: MPU R-144 wp11Ladder / S.F. 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'LVWDQFH%HWZHHQ3URILOHV'LVWDQFH%HWZHHQ3URILOHV(OOLSVH6HSDUDWLRQ'LVWDQFH%HWZHHQFHQWUHVLVWKHVWUDLJKWOLQHGLVWDQFHEHWZHHQZHOOERUHFHQWUHV$OOVWDWLRQFRRUGLQDWHVZHUHFDOFXODWHGXVLQJWKH0LQLPXP&XUYDWXUHPHWKRG1RYHPEHU &203$663DJHRI 0.001.002.003.004.00Separation Factor5500 6050 6600 7150 7700 8250 8800 9350 9900 10450 11000 11550 12100 12650 13200 13750 14300 14850 15400 15950Measured Depth (1100 usft/in)MPF-01MPU R-145 wp05MPF-06MPF-82AMPU R-119 wp02MPU F-107MPU R-121 wp02MPU R-143 wp11MPF-90MPF-91MPF-85MPU R-120 wp02MPF-09MPU R-117 wp02MPU R-142MPU R-118 wp02MPU R-116 wp02MPF-79MPF-84No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU R-144 NAD 1927 (NADCON CONUS)Alaska Zone 0416.70+N/-S +E/-W Northing EastingLatittudeLongitude0.000.006033402.45540744.5770° 30' 7.8830 N149° 40' 0.2270 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU R-144, True NorthVertical (TVD) Reference:R-144 as built doyon14 @ 50.40usftMeasured Depth Reference:R-144 as built doyon14 @ 50.40usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2024-10-18T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.70 5520.00 MPU R-144 wp11 (MPU R-144) GYD_Quest GWD5520.00 15423.96 MPU R-144 wp11 (MPU R-144) GYD_Quest GWD0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)5500 6050 6600 7150 7700 8250 8800 9350 9900 10450 11000 11550 12100 12650 13200 13750 14300 14850 15400 15950Measured Depth (1100 usft/in)NO GLOBAL FILTER: Using user defined selection & filtering criteria33.70 To 15423.96Project: Milne PointSite: M Pt Raven PadWell: Plan: MPU R-144Wellbore: MPU R-144Plan: MPU R-144 wp11CASING DETAILSTVD TVDSS MD Size Name4115.93 4065.53 5520.00 9-5/8 9 5/8" x 12 1/4"4175.40 4125.00 15423.96 4-1/2 4 1/2" x 8 1/2" 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 SCHRADER BLUFF OIL MPU R-144 224-148 WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:MILNE PT UNIT R-144Initial Class/TypeDEV / PENDGeoArea890Unit11328On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2241480MILNE 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 poolYes5 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 120'18 Conductor string providedYes 9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40# to SB reservoir19 Surface casing protects all known USDWsYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.20 CMT vol adequate to circulate on conductor & surf csgYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.21 CMT vol adequate to tie-in long string to surf csgYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.22 CMT will cover all known productive horizonsYes 9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40# to SB reservoir23 Casing designs adequate for C, T, B & permafrostYes Doyon 14 rig 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 Halliburton collision scan shows no close approaches with HSE risk.26 Adequate wellbore separation proposedYes 16" Diverter27 If diverter required, does it meet regulationsYes All fluids overbalanced to expected pore pressure.28 Drilling fluid program schematic & equip list adequateYes 1 annular, 3 ram stack tested to 3000 psi.29 BOPEs, do they meet regulationYes 13-5/8" , 5000 psi stack tested to 3000 psi.30 BOPE press rating appropriate; test to (put psig in comments)Yes Doyon 14 has 14 x 3-1/8" manual gate valves, 1 x 3-1/8" manual choke and 1 x 3-1/16" remote hydraulic choke.31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownYes MPU R pad has no H2S history. Monitoring will be required.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 alarms.35 Permit can be issued w/o hydrogen sulfide measuresYes Anticipating normally pressured reservoir. MPD to mitigate any abnormal pressures.36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate12/5/2024ApprMGRDate12/5/2024ApprADDDate12/5/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 12/16/2024