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Home My WebLink About224-024Nolan 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: 2/10/2026 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20260210 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 224-34T 50283202050000 225044 1/30/2026 AK E-LINE Perf T41349 CLU 11RD 50133205590100 225013 1/24/2026 AK E-LINE Perf T41350 CLU 11RD 50133205590100 225013 1/27/2026 AK E-LINE Plug/Perf T41350 KU 24-07RD2 50133203520200 225126 1/14/2026 AK E-LINE CBL T41351 KU 24-07RD2 50133203520200 225126 1/20/2026 AK E-LINE IPFOF T41351 MPI 2-74 50029237850000 224024 1/25/2026 AK E-LINE Whipstock T41352 MPU 1-36 50029236770000 220047 2/1/2026 AK E-LINE Packer T41353 MPU R-110 50029238260000 225085 10/24/2025 YELLOWJACKET RCBL T41354 NFU 14-25 50231200350000 210111 12/29/2025 YELLOWJACKET CBL T41355 SDI 3-15 50029217510000 187094 1/23/2026 AK E-LINE Whipstock T41356 SRU 214A-27 50133101580100 225133 2/4/2026 YELLOWJACKET SCBL T41357 SRU 231-33 50133101630100 223008 7/31/2025 YELLOWJACKET PLUG-PERF T41358 SRU 242-16 50133204050000 188157 1/24/2026 YELLOWJACKET PLUG-PERF T41359 SU 43-10 50133207390000 225107 1/19/2026 YELLOWJACKET GPT-PLUG- PERF T41360 SU 43-10 50133207390000 225107 12/31/2025 YELLOWJACKET SCBL T41360 Please include current contact information if different from above. MPI 2-74 50029237850000 224024 1/25/2026 AK E-LINE Whipstock Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.02.10 14:51:05 -09'00' Suspended Well Inspection Review Report Reviewed By: P.I. Suprv Comm ________ JBR 01/26/2026 InspectNo:susGDC251220160753 Well Pressures (psi): Date Inspected:12/20/2025 Inspector:Guy Cook If Verified, How?Other (specify in comments) Suspension Date:6/7/2024 Tubing:950 IA:580 OA:140 Operator:Hilcorp Alaska, LLC Operator Rep:Steve Soroka Date AOGCC Notified:12/18/2025 Type of Inspection:Initial Well Name:DUCK IS UNIT MPI 2-74 Permit Number:2240240 Wellhead Condition The wellhead is in good condition with the typical suface rust. The well is currently protected from the elements by a wellhouse. Surrounding Surface Condition Unknown due to snow and ice covering the pad. Condition of Cellar Dry gravel/dirt with absorbent and flagging tape present. There appears to be some old signs of hydrocarbons as well. Comments The surrounding area will need to be inspected next spring when snow and ice are not present. Location was verified by a pad map. Supervisor Comments fPhotos (10). Approved Sundry 325-742 for reenter suspended well and set whipstock in prep for redrill 2-74A (approved 1/2/2026) Suspension Approval:Completion Report Location Verified? Offshore? Fluid in Cellar? Wellbore Diagram Avail? Photos Taken? VR Plug(s) Installed? BPV Installed? Monday, January 26, 2026                2025-1220_Suspend_DIU_MPI_2-74_photos_gc Page 1 of 5 Suspended Well Inspection – DIU MPI 2-74 PTD 2240240 AOGCC Inspection Rpt # susGDC251220160753 Photos by AOGCC Inspector G. Cook 12/20/2025 2025-1220_Suspend_DIU_MPI_2-74_photos_gc Page 2 of 5 2025-1220_Suspend_DIU_MPI_2-74_photos_gc Page 3 of 5 Tree Cap Pressure Gauge SVS Hydraulic Panel 2025-1220_Suspend_DIU_MPI_2-74_photos_gc Page 4 of 5 IA Pressure Gauge OA Pressure Gauge 2025-1220_Suspend_DIU_MPI_2-74_photos_gc Page 5 of 5 Absorb material in the well cellar Hilcorp Alaska, LLC Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.12.05 11:37:14 - 09'00' Sean McLaughlin (4311) 325-742 By Grace Christianson at 12:04 pm, Dec 05, 2025 DSR-12/5/25 10-407 *Variance as per 20 AAC 25.112(i): Approved for alternate abandonment plug placement on parent well contingent upon fully cemented liner on upcoming sidetrack. *Window milling on service coil not approved on 10-403, refer to sidetrack PTD for approval. Open hole window milling not to exceed 15'. A.Dewhurst 11DEEC25 J.Lau 1/2/25JLC 1/2/2025 01/02/26 To: Alaska Oil & Gas Conservation Commission From:Ryan Ciolkosz Drilling Engineer Date: December 4, 2025 Re:2-74 Sundry Request Sundry approval is requested to set a whipstock and mill a window in the 2-74 wellbore as part of the drilling and completion of the proposed END 2-74A CTD lateral. Proposed plan for END 2-74A Producer: See END 02-74 Sundry request for complete pre-rig details - Slickline/E-line previously set a DSSSV, tested C&B, pulled the DSSSV, set a patch, performed an MIT-IA to 3715 psi, and pulled the patch to confirm integrity for the upcoming CTD sidetrack. Prior to drilling activities, screening will be conducted to drift for whipstock. E- line will set a 4-1/2" whipstock. Coil or E-line will mill the XN nipple out to 3.80". If unable to set the whipstock or mill the window pre-rig, the rig will perform that work. A coil tubing drilling sidetrack will be drilled with the Nabors CDR2/CDR3 rig. The rig will move in, test BOPE and kill the well. If unable to pre-rig, the rig will set the 4-1/2" whipstock and mill a dual string (4-1/2"x7") 3.80" window + 10' of formation. The well will kick off drilling in the HRZ and top set the Shublik B with a 3-1/4" pre-perforated liner. The rig will mill out the 3-1/4" aluminum shoe with a 2.74" mill. A 3.25" lateral will be drilled through the upper and lower Ivishak. The proposed sidetrack will be completed with a 2-3/8 13Cr solid liner, cemented in place and selectively perforated post rig (will be perforated with rig if unable to post rig). This completion will completely isolate and abandon the parent perfs. The following describes the work planned. A wellbore schematic of the current well and proposed sidetrack is attached for reference. Pre-Rig Work: Reference 2-74 Permit submitted in concert with this request for full details. 1. Eline Mill XN Nipple, Set 4-1/2" Packer Whipstock at 14,515 MD at 180 degrees ROHS 2. Valve Shop : Bleed wellhead pressures down to zero. 3. Valve Shop : Bleed production, flow and GL lines down to zero and blind flange. 4. Operations : Remove wellhouse and level pad. Rig Work: (Estimated to start February 25, 2025) 1. MIRU and test BOPE 250 psi low and 4000 psi high (MASP 3660 psi). 2. Mill 3.80 Dual String 4-1/2x7 Window. 3. Drill 4.25 OH to Top of Shublik, ~111 (12 deg DLS Planned) 4. Run 3-1/4 pre-perforated Liner with aluminium bullnose shoe. 5. Secure well and swap to 2-3/8" to 2" Coil/BOPE Rams. Test BOPE 250 psi low and 4000 psi high (MASP 3660 psi). Give AOGCC 24hr notice prior to BOPE test. 6. Mill out aluminium shoe with 2.74" mill. 7. Drill Build section: 3.25" OH, ~395' (16 deg DLS planned). 8. Drill production lateral: 3.25" OH, ~1567' (12 deg DLS planned). Swap to KWF for liner. 9. Run 2-3/8 13Cr solid liner with 3.70 deployment sleeve. 10. Pump primary cement job*: 20 bbls, 15.3 ppg Class G, 1.24 (ft3/sk), TOC at TOL. Volume to completely fill 2-3/8" and 3-1/4" outside annuli. If high losses are encountered during cement job and it is deemed necessary, a cement down squeeze from TOL to loss zone will be performed with the rig or service coil (if performed by service coil see future sundry). 11. Freeze protect well to a min 2,200' TVD. 12. Close in tree, RDMO. Post Rig Work: 1. Valve Shop : Valve & tree work 2. Service Coil : RPM Log. Perforate ~1000 w/ 1.56 Guns. 3. Slickline : Set Memory pressure gauge in SVLN @ 1557 MD. Set LTP (if necessary). Set live GLVs. 4. Ops : Flow Under-Evaluation with AL for up to 14 days 5. Slickline : Set live GLVs. Set Nipple-Reducer w/2.313 X-Lock in X-nipple @ 14,276 MD. Drift for patch. 6. E-line/FB : Set K-valve with dome set between 300 and 600 psi in the SVLN @ 1557 MD. (Gauge readings from flowing the well will inform exact pressure setting. The main production header at Endicott operates at 260psig, so pressure should be set above header pressure. To test the valve, the well choke will be opened to drop the wellhead pressure to main production pressure. To reset the valve, the well will be pressured up to above the trip pressure then gradually reopened to the normal operating range.) See attached K-Valve Testing Procedure and Regulations. 7. E-Line : Set 13CR NS patch ME @ 730 and 740. Use caliper log of 7/13/25 for tie-in. The caliper clearly shows the collar leak @ 735 MD.Note there is ~20 discrepancy between the caliper, schematic, and the tubing tally, so use the caliper for tie-in to ensure the leak is straddled by the patch. Tag the K-valve and count collars using the caliper to tie-in to setting depth. 8. Ops : Perform TIFL to validate the patch. Conduct a SVS test within 5 days after stabilized flow. Ryan Ciolkosz CC: Well File Drilling Engineer Joe Lastufka 907-244-4357 _____________________________________________________________________________________ Revised By: GP 10/28/2025 SCHEMATIC Duck Island Unit Well: END 2-74 Last Completed: 6/7/2024 PTD: 224-024 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status GENERAL WELL INFO API: 50-029-23785-00-00 Completion Date: 6/7/2024 TD =18,322(MD) / TD =10,005(TVD) 4 20 Obstruction / Buckled Liner @14530 Orig.KB Elev.:40.3/ GL Elev.:13.7 7 8 5 4 10 9-5/8 9 1 9-5/8 ES Cementer @ 2,029 2 3 PB1: 14,609 14,942 PBTD =18,248(MD) / PBTD =9,985(TVD) Whipstock set @ 14,515 13,14 Coil Fish: 11.7 long parted 1.69 motor w/ 2.13 tapered mill @ Unknown MD 7 5 12 4-1/2 3 2 4-1/2 7 11 6 TREE & WELLHEAD Tree Cameron 3-1/8" 5M w/ 3-1/8 5M Cameron Wing Wellhead FMC 11 Tubing Hanger Assy, 4-1/2 TCII OPEN HOLE / CEMENT DETAIL 24 x Driven 5 cu yds Cement 12-1/41st Lead 540 sx / Tail 400 sx 2nd Lead 661 sx / tail - 270 sx 8-1/2 116 sx Class G 6-1/8 418 sx Class G CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X56 / Weld N/A Surface 174 N/A 9-5/8 Surface 47 / L-80 / TXP 8.679 Surface 2,012 0.0758 9-5/8 Surface 40 / L-80 / TXP 8.679 2,012 6,151 0.0758 7 Intermediate 29 / L-80 / VT 6.184 Surface 14,551 0.0371 4-1/2 Production Liner 12.6# / CR13 / JFE-B 3.958 14,378 18,322 0.0086 TUBING DETAIL 4-1/2" Tubing 12.6# / CR13 / JFE-B 3.958 Surface 14,380 0.0152 JEWELRY DETAIL No. MD Item ID 1 1,557 SSSV XXO, Set DSSSV 2.60 ID on 9-14-2025 2.60 2 5,108 GLM #1: 4.5x1 BK, Dummy, 9/13/2025 3.910 3 7,636 GLM #2: 4.5x1 BK, Dummy, 9/13/2025 3.900 4 9,728 GLM #3: 4.5x1 BK, Dummy, 9/13/2025 3.900 5 11,341 GLM #4: 4.5x1 BK, Dummy 3.900 6 12,650 GLM #5: 4.5x1 BK, Dummy 3.900 7 14,130 GLM #6: 4.5x1 BK, Dummy 3.900 8 14,192 X Nipple 3.813 9 14,211 4-1/2 HES TNT Production Packer 3.856 10 14,276 X Nipple 3.813 11 14,333 XN Nipple 3.725 12 14,343 WLEG Btm @ 14,380 3.965 13 14,370 ZXHD Liner Top Packer 5.250 14 14,378 HRDE Liner Setting Sleeve 4.190 WELL INCLINATION DETAIL KOP @ 306 52° -54° Hole Angle @ 2,630 14,552 99° Max Hole Angle @ 16,538 Set DSSSV 2.60 ID @ 1,557 _____________________________________________________________________________________ Revised By: GP 12/1/2024 PROPOSED SCHEMATIC Duck Island Unit Well: END 2-74A Last Completed: TBD PTD: TBD PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status GENERAL WELL INFO API: 50-029-23785-01-00 Original Completion Date: 6/7/2024 CDR2 A ST - TBD TD =16588(MD) / TD =9,867(TVD) 4 20 Orig.KB Elev.:40.3/ GL Elev.:13.7 7 85 4 10 15 9-5/8 9 1 9-5/8 ES Cementer @ 2,029 2 3 TOL/TOCat 14,300 PBTD =16525(MD) / PBTD =9,8664(TVD) 13,14 7 5 12 4-1/2 3 2 4-1/2 7 11 6 Whipstock at 14,515 Top Protection String at 14,407 3-1/2 X 2- 3/8 XO at 14,330 2-3/8 Solid Liner at 16,588 3-1/4 Pre- Perforated Liner (Protection String) at 14,626 TREE & WELLHEAD Tree Cameron 3-1/8" 5M w/ 3-1/8 5M Cameron Wing Wellhead FMC 11 Tubing Hanger Assy, 4-1/2 TCII OPEN HOLE / CEMENT DETAIL 24 x Driven 5 cu yds Cement 12-1/41st Lead 540 sx / Tail 400 sx 2nd Lead 661 sx / tail - 270 sx 8-1/2 116 sx Class G 6-1/8 418 sx Class G CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X56 / Weld N/A Surface 174 N/A 9-5/8 Surface 47 / L-80 / TXP 8.679 Surface 2,012 0.0758 9-5/8 Surface 40 / L-80 / TXP 8.679 2,012 6,151 0.0758 7 Intermediate 29 / L-80 / VT 6.184 Surface 14,551 0.0371 4-1/2 Production Liner 12.6 / CR13 / JFE-B 3.958 14,37814,5150.0086 3-1/4 Protection SLTD Liner 6.6 / 13Cr / TCII 14,407 14,650 3-1/2x2-3/8 Liner 9.2x4.6 / 13Cr / STLxH511 14,300 16,588 TUBING DETAIL 4-1/2" Tubing 12.6# / CR13 / JFE-B 3.958 Surface 14,380 0.0152 JEWELRY DETAIL No. MD Item ID 1 1,557 SSSV XXO 3.813 2 5,108 GLM: 4.5x1 Bellows 16/64 3.910 3 7,636 GLM: 4.5x1 Bellows 16/64 3.900 4 9,728 GLM: 4.5x1 Orifice 26/64 3.900 5 11,341 GLM: 4.5x1 BK Dummy 3.900 6 12,650 GLM: 4.5x1 BK Dummy 3.900 7 14,130 GLM: 4.5x1 BK Dummy 3.900 8 14,192 X Nipple 3.813 9 14,211 4-1/2 HES TNT Production Packer 3.856 10 14,276 X Nipple 3.813 11 14,333 XN Nipple Milled to 3.80 pre-rig 3.800 12 14,343 WLEG Btm @ 14,380 3.965 13 14,370 ZXHD Liner Top Packer 5.250 14 14,378 HRDE Liner Setting Sleeve 4.190 WELL INCLINATION DETAIL KOP @ 306 52° -54° Hole Angle @ 2,630 14,552 99° Max Hole Angle @ 16,538 Well Date Quick Test Sub to Otis - Top of 7" Otis 0.0 ft Distances from top of riser Excluding quick-test sub Top of Annular CL Annular Bottom Annular CL Blind/Shears CL Coiled Tubing Pipe / Slips Kill Line Choke Line CL BHA Pipe / Slip CL Coiled Tubing Pipe / Slips TV1 TV2 T1 T2 Flow Tee Master Master LDS IA OA LDS Ground Level CDR#-AC BOP Schematic CDR Rig's Drip Pan Fill Line Normally Disconnected HP hose to Micromotion LP hose open ended to Flowline (optional) Hydril 7 1/16" Annular Blind/Shear CT Pipe/Slips 2 3/8" Pipe/Slips 2 3/8" Pipe/Slips 7-1/16" 5k Mud Cross CT Pipe/Slips BHA Pipe / Slips nneeeeeceeeeeeeeeeeeeeeeeeeeeeeeeeeeeee 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: 10/16/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20251016 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# END 2-36 50029220140000 190024 9/17/2025 BAKER SPN T40994 END 2-74 50029237850000 224024 9/22/2025 HALLIBURTON PATCH T40995 KU 12-17 50133205770000 208089 9/23/2025 YELLOWJACKET TEMP-CALIPER T40996 KU 24-7RD 50133203520100 205099 9/24/2025 YELLOWJACKET TEMP-CALIPER T40997 M-25 50733203910000 187086 8/31/2025 YELLOWJACKET CALIPER T40998 MPC-22A 50029224890100 195198 10/4/2025 READ CaliperSurvey T40999 MPF-61 50029225820000 195117 9/27/2025 READ CaliperSurvey T41000 MPU H-16 50029232270000 204190 10/6/2025 HALLIBURTON COILFLAG T41001 NIK SI17-SE2 50629235120000 214041 9/23/2025 HALLIBURTON IPROF T41002 NS-19 50029231220000 202207 9/8/2025 HALLIBURTON COILFLAG T41003 NS-19 50029231220000 202207 9/15/2025 HALLIBURTON COILFLAG T41003 ODSN-26 50703206420000 211121 10/7/2025 HALLIBURTON MFC24 T41004 PBU 01-25A 50029208740100 225056 9/13/2025 BAKER MRPM T41005 PBU 01-25A 50029208740100 225056 9/13/2025 HALLIBURTON RBT-COILFLAG T41005 PBU 01-31A 50029216260100 225070 9/22/2025 BAKER MRPM T41006 PBU 01-31A 50029216260100 225070 9/23/2025 HALLIBURTON RBT-COILFLAG T41006 PBU 05-09A 50029202540100 199014 9/18/2025 READ ArcherVIVID T41007 PBU 07-16A 50029208560100 201153 9/20/2025 HALLIBURTON RBT T41008 PBU 07-23C 50029216350300 225043 7/4/2025 BAKER MRPM T41009 PBU 13-24B 50029207390200 224087 9/18/2025 HALLIBURTON RBT T41010 PBU 15-11C 50029206530300 210163 9/6/2025 HALLIBURTON RBT T41011 PBU 15-49C 50029226510300 215129 9/10/2025 HALLIBURTON RBT T41012 PBU H-07B 50029202420200 225064 9/30/2025 HALLIBURTON RBT-COILFLAG T41013 PBU P19 L1 50029220946000 212056 10/3/2025 HALLIBURTON RBT T41014 PBU S-14A 50029208040100 204071 9/25/2025 HALLIBURTON RBT T41015 PBU V-105 50029230970000 202131 9/30/2025 HALLIBURTON RMT3D T41016 Please include current contact information if different from above. END 2-74 50029237850000 224024 9/22/2025 HALLIBURTON PATCH Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.10.20 13:17:06 -08'00' 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: 09/12/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250912 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 223-34T 50283202060000 225059 8/28/2025 AK E-LINE Perf BRU 224-34T 50283202050000 225044 8/19/2025 AK E-LINE CIBP BRU 224-34T 50283202050000 225044 8/17/2025 AK E-LINE Perf BRU 224-34T 50283202050000 225044 8/22/2025 AK E-LINE Perf BRU 224-34T 50283202050000 225044 8/27/2025 AK E-LINE Perf BRU 241-23 50283201910000 223061 8/20/2025 AK E-LINE Plug/Perf GP 11-13RD 50733200260100 191133 8/29/2025 AK E-LINE Perf KALOTSA 6 50133206850000 219114 8/14/2025 AK E-LINE PPROF MGS ST 17595 06 50733100730000 166003 8/19/2025 AK E-LINE Drift MGS ST 17595 06 50733100730000 166003 8/26/2025 AK E-LINE Drift MGS ST 17595 11 50733200130000 167017 8/17/2025 AK E-LINE CBL MGS ST 17595 20 50733203770000 185135 8/21/2025 AK E-LINE CBL MPI 1-61 50029225200000 194142 8/19/2025 AK E-LINE Patch NCIU A-21A 50883201990100 225075 8/23/2025 AK E-LINE Perf END 1-23 50029225100000 194128 7/14/2025 HALLIBURTON MFC40 END 2-74 50029237850000 224024 7/12/2025 HALLIBURTON MFC40 END 3-07A 50029219110100 198147 7/13/2005 HALLIBURTON COILFLAG END 3-15 50029217510000 187094 7/15/2025 HALLIBURTON MFC24 NS-20 50029231180000 202188 9/2/2025 HALLIBURTON COILFLAG PBU 01-13A 50029202700100 225052 8/18/2025 HALLIBURTON RBT-COILFLAG PBU 07-24A 50029209450100 225045 8/3/2025 HALLIBURTON RBT-COILFLAG PBU C-34C 50029217850300 225068 8/25/2025 HALLIBURTON RBT SD-07 50133205940000 211050 8/14/2025 HALLIBURTON TMD3D ODSK-14 50703206100000 209155 9/8/2025 READ CaliperSurvey Please include current contact information if different from above. T40874 T40875 T40875 T40875 T40875 T40876 T40877 T40878 T40879 T40879 T40880 T40881 T40882 T40883 T40884 T40885 T40886 T40887 T40888 T40889 T40890 T40891 T40892 T40893 END 2-74 50029237850000 224024 7/12/2025 HALLIBURTON MFC40 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.09.12 14:33:03 -08'00' 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: 2/8/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240208 Well API #PTD #Log Date Log Company Log Type BCU 09A 50133204450100 224113 11/13/2024 YELLOWJACKET GPT-PERF BCU 09A 50133204450100 224113 10/30/2024 YELLOWJACKET GPT BCU 11A 50133205210100 224123 11/9/2024 YELLOWJACKET SCBL BCU 25 50133206440000 214132 11/2/2024 YELLOWJACKET SCBL END 2-74 REVISED 50029237850000 224024 12/5/2024 HALLIBURTON MFC24 HVA 10 50231200280000 204186 11/13/2024 YELLOWJACKET GPT-PERF KU 23-07A 50133207300000 224126 11/23/2024 YELLOWJACKET SCBL NCIU A-21 50883201990000 224086 11/29/2024 AK E-LINE CaliperSurvey PAXTON 6 50133207070000 222054 11/7/2024 YELLOWJACKET PERF PBU 01-37 50029236330000 219073 11/23/2024 BAKER MRPM PBU 06-15A 50029204590200 224108 12/26/2024 BAKER MRPM PBU 06-19B 50029207910200 224095 12/10/2024 BAKER MRPM PBU 07-29E 50029217820500 213001 11/26/2024 BAKER SPN PBU 14-31A 50029209890100 224090 11/10/2024 BAKER MRPM PBU 14-41A 50029222900100 224076 11/9/2024 BAKER MRPM SRU 241-33B 50133206960000 221053 11/5/2024 YELLOWJACKET GPT-PERF Revision Explanation: Annotations added to processed log. Please include current contact information if different from above. T40053 T40053 T40054 T40055 T40056 T40057 T40058 T40059 T40060 T40061 T40062 T40063 T40064 T40065 T40066 T40067 END 2-74 REVISED 50029237850000 224024 12/5/2024 HALLIBURTON MFC24 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.02.07 13:25:23 -09'00' 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: 1/07/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240107 Well API #PTD #Log Date Log Company Log Type AOGCC Eset # END 2-72 50029237810000 224016 11/16/2024 HALLIBURTON TEMP END 2-74 50029237850000 224024 12/5/2024 HALLIBURTON MFC24 END 2-74 50029237850000 224024 8/13/2024 DarkVision HADES (Down hole camera) KGSF 1A 50133101600100 220063 12/5/2024 HALLIBURTON EPX-MFC40 MPU F-13 50029225490000 195027 12/22/2024 HALLIBURTON WFL-TMD3D PU F-40 50029222150000 191117 11/9/2024 READ CaliperSurvey MPU I-04A 50029220680100 201092 11/22/2024 HALLIBURTON COILFLAG MPU J-02 50029220710000 190096 12/22/2024 READ CaliperSurvey PBU L-04 50029233190000 206120 11/23/2024 HALLIBURTON WFL-TMD3D PBU L-221 50029233850000 208031 12/11/2024 HALLIBURTON WFL-RMT3D PBU Z-ϯϰ 50029234690000 212061 12/15/2024 HALLIBURTON WFL-RMT3D PBU Z-2ϯϱ 50029237600000 223055 9/24/2024 READ InjectionProfile PBU Z-ϮϮϯ 50029237200000 222080 11/24/2024 HALLIBURTON WFL-TMD3D SCU 42-05Y 50133205700000 207082 12/7/2024 HALLIBURTON EPX-MFC24 TBU D-16RD 50733201830100 180110 12/19/2024 READ CaliperSurvey TBU D-17RD 50733201680100 181023 12/21/2024 READ CaliperSurvey Please include current contact information if different from above. T39915 T39916 T39916 T39917 T39918 T39919 T39920 T39921 T39922 T39923 T39924 T39925 T39926 T39927 T39928 T39929 END 2-74 50029237850000 224024 12/5/2024 HALLIBURTON MFC24 END 2-74 50029237850000 224024 8/13/2024 DarkVision HADES (Down hole camera Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.01.07 15:26:55 -09'00' From:Rixse, Melvin G (OGC) To:Brenden Swensen; Joseph Lastufka Cc:Guhl, Meredith D (OGC) Subject:APPROVED 20241108 1628 DIU MPI 2-74 (PTD #224-024) Update Date:Friday, November 8, 2024 4:28:53 PM Brenden, Additional 45 days approved for submittal of 10-407. 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). From: Brenden Swensen <Brenden.Swensen@hilcorp.com> Sent: Friday, November 8, 2024 1:44 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Cc: Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Subject: RE: [EXTERNAL] RE: DIU MPI 2-74 (PTD #224-024) Update Mel, Due to internal review processes, the 2-74 coil tubing step to mill on the liner obstruction at 14,530’ MD to regain access to the wellbore has been delayed longer than expected. However, additional AFE spend was approved on 11/5 and a procedure has been submitted for prioritization and execution. We anticipate executing this work before the end of the year and would like to ask for an additional 45 days on the 10-407. For continuity, we still have an open 10-403 for an extended add perforation, sundry number 324-348. If we are able to get past the obstruction, I will follow up with any sundry revisions required for subsequent pertinent steps. If we are unable to get past the obstruction we will close out the 10-403 and 10-407 at that time. Thanks, CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Brenden Swensen AKI Operations Engineer 907-748-8581 From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Tuesday, September 24, 2024 12:02 PM To: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Cc: Brenden Swensen <Brenden.Swensen@hilcorp.com>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Subject: RE: [EXTERNAL] RE: DIU MPI 2-74 (PTD #224-024) Update Joe, Hilcorp is approved for an additional 45 days to submit the 10-407 data. 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). From: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Sent: Tuesday, September 24, 2024 11:32 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Brenden Swensen <Brenden.Swensen@hilcorp.com>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Subject: RE: [EXTERNAL] RE: DIU MPI 2-74 (PTD #224-024) Update Mel, I wanted to provide you with the recent update / status of DIU MPI 2-74 (PTD #224-024): We obtained an imaging log on 8/13/24 and received data on 8/19/24. A 1.5” coil tubing drift run was attempted on 8/31/24 and was not successful in getting past the restriction. A further CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. decision has been made to make an attempt to mill on the obstruction with coil tubing. Our team is working on the procedure and bottom hole assembly selection and anticipate executing the work in the next 30 days. I’d like to request to continue to delay the 10-407 Completion Report until after this last operation. If there are additional delays or issues with reaching perforating depth I will keep you posted. Please let me know if you have any questions. Thanks! Thanks, Joe Lastufka Sr. Drilling Technologist Hilcorp North Slope, LLC Office: (907)777-8400, Cell:(907)227-8496 From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Wednesday, August 21, 2024 1:41 PM To: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Cc: Brenden Swensen <Brenden.Swensen@hilcorp.com>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Subject: [EXTERNAL] RE: DIU MPI 2-74 (PTD #224-024) Update Joe, Submittal of the 10-407 completion report for MPI 2-74 is approved. Please provide an update within 30 days if the perforating is not completed. 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. Meredith, Brenden From: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Sent: Wednesday, August 21, 2024 1:08 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> 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. Cc: Brenden Swensen <Brenden.Swensen@hilcorp.com> Subject: DIU MPI 2-74 (PTD #224-024) Update Mel, Per our discussion, just to update you on DIU MPI 2-74 (PTD #224-024), we obtained an imaging log on 8/13/24 and received data on 8/19/24. After reviewing the data, we have elected to make 1 more attempt to access the production liner and achieve access to the initial perforating depth on sundry #324-348 to complete the well. We anticipate executing the drift sometime in the next 2-3 weeks. I’d like to request to delay the 10-407 Completion Report until after these initial perforations. If there are additional delays or issues with reaching perforating depth I will keep you posted. Please let me know if you have any questions. Thanks! Thanks, Joe Lastufka Sr. Drilling Technologist Hilcorp North Slope, LLC Office: (907)777-8400, Cell:(907)227-8496 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 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 the individual 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 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 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, 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 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. 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: 8/7/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240807 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# END 2-72 50029237810000 224016 6/27/2024 HALLIBURTON COILFLAG END 2-72 50029237810000 224016 7/18/2024 HALLIBURTON RBT END 2-72 50029237810000 224016 7/18/2024 HALLIBURTON TEMP END 2-74 50029237850000 224024 7/20/2024 HALLIBURTON MFC MPU B-24 50029226420000 196009 7/16/2024 HALLIBURTON MFC MPU E-19A 50029227460100 224010 6/22/2024 HALLIBURTON COILFLAG NS-10 50029229850000 200182 7/18/2024 HALLIBURTON MFC NS-10 50029229850000 200182 7/18/2024 HALLIBURTON TEMP NS-32 50029231790000 203158 7/16/2024 HALLIBURTON MFC NS-32 50029231790000 203158 7/15/2024 HALLIBURTON TEMP PBU H-13A 50029205590100 209044 7/23/2024 HALLIBURTON RBT PBU L-246 50029237650000 223078 7/23/2024 HALLIBURTON IPROF PBU R-26B 50029215470100 210025 7/5/2024 HALLIBURTON RBT PBU R-36 50029225220000 194144 6/21/2024 HALLIBURTON RBT PBU V-216 50029232160000 204130 7/11/2024 HALLIBURTON IPROF PBU V-217 50029233340000 206162 7/11/2024 HALLIBURTON IPROF Please include current contact information if different from above. T39365 T39365 T39365 T39366 T39367 T39368 T39369 T39369 T39370 T39370 T39371 T39372 T39373 T39374 T39375 T39376 END 2-74 50029237850000 224024 7/20/2024 HALLIBURTON MFC Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.08.07 13:19:30 -08'00' 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: ___________________ 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: ENDICOTT 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 18,322 NA Casing Collapse Structural Conductor 5,020psi Surface 3,090psi Intermediate 5,410psi Production 7,500psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16.Verbal Approval: Date: GAS WAG GSTOR SPLUG 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 4-1/2" HES TNT Production Packer, ZXHD LTP, SSSV XXO 14,211' MD (9,211' TVD), 14,370' MD (9,306' TVD), 1,557' MD (1,511' TVD) NA 18,322 14,550 3,944 NA 907-748-8581 brenden.swensen@hilcorp.com Operations Manager June 27, 2024 NA 4-1/2" Perforation Depth MD (ft): NA 10,0054-1/2" NA 20" 9-5/8" 148 7"14,550 6,151 1,530psi 5,750psi 148 4,422 9,414 148 6,151 12.6# / Cr13 TVD Burst 14,380 8,430psi MD 7,240psi Hilcorp Alaska, LLC Length Size Proposed Pools: 10,005 18,320 10,004 3,630 EIDER OIL Same STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0034633, ADL0034634 224-024 C.O. 449 DUCK IS UNIT MPI 2-74 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23785-00-00 PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Brenden Swensen 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: No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 4:03 pm, Jun 17, 2024 Digitally signed by Sara Hannegan (2519) DN: cn=Sara Hannegan (2519) Date: 2024.06.17 14:55:35 - 08'00' Sara Hannegan (2519) Perforate DSR-6/17/24SFD 6/18/2024MGR19JUN24 * BHA assembly length not to exceed 500'. 10-404 *&:JLC 6/19/2024 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.06.19 10:54:30 -08'00'06/19/24 RBDMS JSB 062024 Page 1 of 11 Extended Add Perf Well: END 2-74 PTD: 224-024 Well Name:END 2-74 API Number:50-029-23785-00-00 Current Status:New Drill Producer PTD #224-024 Estimated Start Date:6/27/2024 Rig:SL/EL/CT Reg.Approval Req’std?Yes Estimated Duration:7 days Regulatory Contact:Darci Horner 907-777-8406 (O) First Call Engineer:Brenden Swensen 907-748-8581 (M) Second Call Engineer:Ryan Thompson 907-301-1240 (M) Current Bottom Hole Pressure:4370 psi @ 10,000’ TVD (SBHPS 2-56A 6/30/2012) 8.41ppg EMW Maximum Expected BHP:4630 psi @ 10,000’ TVD (Original res pressure) 8.91ppg EMW Maximum Anticipated Surface Pressure:3630 psi (Based on 0.1psi/ft gas gradient) History Endicott 2-74 is a new drill Ivishak producer. This well is a replacement of the original 2-30A wellbore. During the cementing of the 4.5” liner, the rig lost circulation during the placement of cement. It is estimated that the top of cement is somewhere between 15,000’ and 16,000’ MD based on data observed during the operation. However, with the well being horizontal through the liner, it is possible that cement has slumped or migrated to different depths. A cement bond log (CBL) and pulsed neutron log (PNL) across the liner will be collected to determine top of cement, cement coverage depths, and confirm fluid contacts and saturations prior to perforating. These logs are non-sundried work and will be gathered prior to performing this extended add perf sundry. If the CBL or PNL results change perforation depths, a sundry revision will be submitted to AOGCC prior to perforating. Objective Perform coil tubing extended add perforation on service coil. Ivishak producer Page 2 of 11 Extended Add Perf Well: END 2-74 PTD: 224-024 Modeling Cerberus modelling suggests achieving target depth with 200’ gun run with multiple pipe sizes and friction factors. Wellbore Volume 280 bbls to TD (18,322’ MD) in 4.5” tubing and liner. 250 bbls to top perforation depth of 16,383’ MD. Well hits first 90 deg (horizontal) section at 16,100’ MD. 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This is generally done during the drift/logging run. This will provide guidance as to whether the well will be killed by bullheading or circulating bottoms up throughout the job. If pressure is seen immediately after perforating, it will either be killed by bullheading while POOH or circulating bottoms up through the same port that opened to shear the firing head. 1. After MU MHA and pull testing the CTC, tag-up on the CT stripper to ensure BHA cannot pull through the brass upon POOH with guns. 2. MU and RIH with ~3.25” nozzle and 2.875” GR/CCL drift to PBTD. At PBTD, circulate 9.1 ppg brine KWF and flow check well. Once circulation is complete, log from PBTD to above bottom GLV. It is important to get a long pass as this will be frequently referenced. Flag pipe for subsequent tie ins. a. Post drilling the wellbore is planned to have drilling mud from TD to lowest GLM, brine above the lowest GLM with a diesel FP to surface. b. Note the well should be a closed system at this point as no perfs have been added. 3. Contact OE/Geo/RE to verify perf depths. a. If the CBL or PNL results change perforation depths, a sundry revision will be submitted to AOGCC prior to perforating. b. Contact town OE or RE for final depth tie in. Tie in will be done to open hole logs. i. OE Brenden Swensen brenden.swensen@hilcorp.com 907-748-8581 ii. Geo Brock Rust brust@hilcorp.com 907-777-8394 iii. RE Gavin Dittman gavin.dittman@hilcorp.com 907-564-5246 4. Prepare for deployment of TCP guns. Total planned perf length is ± 310’ over multiple runs. 5. Confirm well is dead. Bleed any pressure off to return tank. Kill well w/ KWF, 9.1 ppg brine as needed. Maintain hole fill taking returns to tank until lubricator connection is re-established. Fluids man-watch must be performed while deploying perf guns to ensure the well remains killed and there is no excess flow. 6. *Perform drill by picking up safety joint with TIW valve and space out before MU guns. Review well control steps with crew prior to breaking lubricator connection and commencing makeup of TCP gun string. Once the safety joint and TIW valve have been spaced out, keep the safety joint/TIW valve readily accessible near the working platform for quick deployment if necessary. a. At the beginning of each job, the crossover/safety joint must be physically MU to the perf guns one time to confirm the threads are compatible. 7. Break lubricator connection at QTS and begin makeup of TCP guns per schedule below. Constantly monitor fluid rates pumped in and fluid returns out of the well. Fluids man-watch must be performed while deploying perf guns to ensure the well remains killed and there is no excess flow. planned perf length is ± 310’ over multiple runs Page 4 of 11 Extended Add Perf Well: END 2-74 PTD: 224-024 Procedure (Page 2 of 2) Coil Tubing (continued) Perf Schedule *Halliburton 2-7/8” Maxforce guns. 3.047” max swell. Weight 12.6 pound per foot loaded. Perf Interval Perf Length Gun Length Weight of Gun (lbs)Comments Run 1 ± 16,616 – ± 16,744’ ± 128’ ± 128’ 1,613 lbs Final lengths TBD at conclusion of CBL and PNL Run 2 ± 16,383 – ± 16,564’ ± 181’ ± 181’ 2,280 lbs Final lengths TBD at conclusion of CBL and PNL 8. RIH with perf gun and tie-in to coil flag correlation. Pickup and perforate interval per Perf Schedule above. a. Note any tubing pressure change in WSR. 9. After perforating, PUH to top of liner or into tubing tail to ensure debris doesn’t fall in on the guns and stick the BHA. Confirm well is dead and re-kill if necessary before pulling to surface. 10. Pump pipe displacement while POOH. Stop at surface to reconfirm well is dead. Kill well if necessary. 11. Review well control steps and Standing Orders with crew prior to breaking lubricator connection and commencing breakdown of TCP gun string. 12. Ensure safety joint and TIW valve assembly are on-hand before breaking off lubricator to LD gun BHA. 13. Repeat steps 4 – 12 for each additional run. 14. RDMO CTU. 15. FP well. Attachments: 1. Coil Tubing BOPE Schematic 2. Standing Orders for Open Hole Well Control during Perf Gun Deployment 3. Equipment Layout Diagram 4. Tie In Log 5. Current Wellbore Schematic 6. Proposed Schematic Page 5 of 11 Extended Add Perf Well: END 2-74 PTD: 224-024 Figure 1: Coiled Tubing BOPs Page 6 of 11 Extended Add Perf Well: END 2-74 PTD: 224-024 Figure 2: Standing Orders for Open Hole Well Control during Perf Gun Deployment Page 7 of 11 Extended Add Perf Well: END 2-74 PTD: 224-024 Figure 3: Equipment Layout Diagram Page 8 of 11 Extended Add Perf Well: END 2-74 PTD: 224-024 Figure 4: Tie In Log Halliburton At Bit Gamma (Page 1 of 2) Page 9 of 11 Extended Add Perf Well: END 2-74 PTD: 224-024 Figure 4: Tie In Log Halliburton At Bit Gamma (Page 2 of 2) _____________________________________________________________________________________ Revised By: JNL 6/7/2024 Page 10 of 11 SCHEMATIC Duck Island Unit Well: END 2-74 Last Completed: 6/7/2024 PTD: 224-024 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status GENERAL WELL INFO API: 50-029-23785-00-00 Completion Date: 6/7/2024 TD = 18,322’ (MD) / TD =10,005’(TVD) 4 20” Orig. KB Elev.: 40.3’ / GL Elev.: 13.7 7” 85 4 10 15 9-5/8” 9 1 9-5/8” ES Cementer @ 2,029’ 2 3 PB1: 14,609’– 14,942’ PBTD =18,320’ (MD) / PBTD =10,005’ (TVD) 13,14 7 5 12 4-1/2” 3 2 4-1/2” 7 11 6 TREE & WELLHEAD Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead FMC 11” Tubing Hanger Assy, 4-1/2” TCII OPEN HOLE / CEMENT DETAIL Driven 20” Conductor 12-1/4”1st Lead – 540 sx / Tail – 400 sx 2nd Lead – 661 sx / tail - 270 sx 8-1/2” 116 sx Class G 6-1/8” 418 sx Class G CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X56 / Weld N/A Surface 180’ N/A 9-5/8” Surface 47 / L-80 / TXP 8.679” Surface 2,012’ 0.0758 9-5/8” Surface 40 / L-80 / TXP 8.679” 2,012’ 6,151’ 0.0758 7” Intermediate 29 / L-80 / VT 6.184” Surface 14,551’ 0.0371 4-1/2” Production Liner 12.6# / CR13 / JFE-B 3.958” 14,378’ 18,322’ 0.0086 TUBING DETAIL 4-1/2" Tubing 12.6# / CR13 / JFE-B 3.958” Surface 14,380’ 0.0152 JEWELRY DETAIL No. MD Item ID 1 1,557 SSSV XXO with Isolation Sleeve Installed 3.813” 2 5,108’ GLM: 4.5”x1” Bellows 16/64” 3.910” 3 7,636’ GLM: 4.5”x1” Bellows 16/64” 3.900” 4 9,728’ GLM: 4.5”x1” Orifice 26/64” 3.900” 5 11,341’ GLM: 4.5”x1” BK Dummy 3.900” 6 12,650’ GLM: 4.5”x1” BK Dummy 3.900” 7 14,130’ GLM: 4.5”x1” BK Dummy 3.900” 8 14,192’ X Nipple 3.813” 9 14,211’ 4-1/2” HES TNT Production Packer 3.856” 10 14,276’ X Nipple 3.813” 11 14,333’ XN Nipple 3.725” 12 14,343’ WLEG – Btm @ 14,380’ 3.965” 13 14,370’ ZXHD Liner Top Packer 5.250” 14 14,378’ HRDE Liner Setting Sleeve 4.190” 15 18,320’ Shoe WELL INCLINATION DETAIL KOP @ 306’ 52° -54° Hole Angle @ 2,630’ – 14,552’ 99° Max Hole Angle @ 16,538’ _____________________________________________________________________________________ Page 11 of 11 PROPOSED SCHEMATIC Duck Island Unit Well: END 2-74 Last Completed: 6/7/2024 PTD: 224-024 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Status Size SPF Ivishak ± 16,383’ ± 16,564’ ± 9,883 ± 9,858 181 TBD TBD TBD 6 Ivishak ± 16,616’ ± 16,744’ ± 9,852 ± 9,830 128 TBD TBD TBD 6 GENERAL WELL INFO API: 50-029-23785-00-00 Completion Date: 6/7/2024TD = 18,322’ (MD) / TD =10,005’(TVD) 4 20” Orig. KB Elev.: 40.3’ / GL Elev.: 13.7 7” 85 4 10 15 9-5/8” 9 1 9-5/8” ES Cementer @ 2,029’ 2 3 PB1: 14,609’– 14,942’ PBTD =18,320’ (MD) / PBTD =10,005’ (TVD) 13,14 7 5 12 4-1/2” 3 2 4-1/2” 7 11 6 TREE & WELLHEAD Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead FMC 11” Tubing Hanger Assy, 4-1/2” TCII OPEN HOLE / CEMENT DETAIL Driven 20” Conductor 12-1/4”1st Lead – 540 sx / Tail – 400 sx 2nd Lead – 661 sx / tail - 270 sx 8-1/2” 116 sx Class G 6-1/8” 418 sx Class G CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X56 / Weld N/A Surface 180’ N/A 9-5/8” Surface 47 / L-80 / TXP 8.679” Surface 2,012’ 0.0758 9-5/8” Surface 40 / L-80 / TXP 8.679” 2,012’ 6,151’ 0.0758 7” Intermediate 29 / L-80 / VT 6.184” Surface 14,551’ 0.0371 4-1/2” Production Liner 12.6# / CR13 / JFE-B 3.958” 14,378’ 18,322’ 0.0086 TUBING DETAIL 4-1/2" Tubing 12.6# / CR13 / JFE-B 3.958” Surface 14,380’ 0.0152 JEWELRY DETAIL No. MD Item ID 1 1,557 SSSV XXO with Isolation Sleeve Installed 3.813” 2 5,108’ GLM: 4.5”x1” Bellows 16/64” 3.910” 3 7,636’ GLM: 4.5”x1” Bellows 16/64” 3.900” 4 9,728’ GLM: 4.5”x1” Orifice 26/64” 3.900” 5 11,341’ GLM: 4.5”x1” BK Dummy 3.900” 6 12,650’ GLM: 4.5”x1” BK Dummy 3.900” 7 14,130’ GLM: 4.5”x1” BK Dummy 3.900” 8 14,192’ X Nipple 3.813” 9 14,211’ 4-1/2” HES TNT Production Packer 3.856” 10 14,276’ X Nipple 3.813” 11 14,333’ XN Nipple 3.725” 12 14,343’ WLEG – Btm @ 14,380’ 3.965” 13 14,370’ ZXHD Liner Top Packer 5.250” 14 14,378’ HRDE Liner Setting Sleeve 4.190” 15 18,320’ Shoe WELL INCLINATION DETAIL KOP @ 306’ 52° -54° Hole Angle @ 2,630’ – 14,552’ 99° Max Hole Angle @ 16,538’ 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: 06/07/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL: WELL: DIU MPI 2-74 +PB1 PTD: 224-024 API: 50-029-23785-00-00 (2-74) 50-029-23785-70-00 (2-74PB1) FINAL LWD FORMATION EVALUATION + GEOSTEERING (04/26/2024 to 05/28/2024) x iCruise-ABG, AGR, DGR, BaseStar Gamma Ray x EWR-M5, ADR, StrataStar Resistivity x 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:g Please include current contact information if different from above. 224-024 MPI 2-74 T38879 MPI 2-74 PB1 T38880 T38879 T38880 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.06.07 13:11:09 -08'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Brooks, Phoebe L (OGC) To:Michael Menapace - (C) Cc:Regg, James B (OGC) Subject:RE: Hilcorp Innovation 5-2-24 BOP test Date:Monday, June 3, 2024 10:21:50 AM Attachments:Hilcorp Innovation 05-02-24.xlsx Sam, I made a minor revision, changing the date to 5/2/24 based on the finish date. Please update your copy. Thanks, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 CONFIDENTIALITY NOTICE:This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Michael Menapace - (C) <Michael.Menapace@hilcorp.com> Sent: Friday, May 3, 2024 4:12 AM To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Cc: Clint Montague - (C) <cmontague@hilcorp.com> Subject: Hilcorp Innovation 5-2-24 BOP test Regards, Sam Menapace Hilcorp Alaska, LLC Innovation DSM Contact # (907)670-3094 Cell # (907) 690-2812 Michael.Menapace@hilcorp.com I made a minor revision, changing the date to 5/2/24 based on the finish date. Please update your 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. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* Su bm it to :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner: Rig No.:Innovation DATE: 5/2/24 Rig Rep.: Rig Email: Operator: Operator Rep.: Op. Rep Email: Well Name: PTD #2240240 Sundry # Operation: Drilling: x Workover: Explor.: Test: Initial: x Weekly: Bi-Weekly: Other: Rams:250/4500 Annular:250/2500 Valves:250/4500 MASP:3627 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 1 P Permit On Location P Hazard Sec.P Lower Kelly 1 P Standing Order Posted P Misc.NA Ball Type 1 P Test Fluid Water Inside BOP 1 P FSV Misc 0 NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0 NA Trip Tank P P Annular Preventer 1 13-5/8" 5K P Pit Level Indicators P P #1 Rams 1 2-7/8"x5.5" 5K P Flow Indicator P P #2 Rams 1 Blinds P Meth Gas Detector P P #3 Rams 1 2-7/8"x5.5" 5K P H2S Gas Detector P P #4 Rams 0 NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA ACCUMULATOR SYSTEM: Choke Ln. Valves 1 3 1/8" 5K P Time/Pressure Test Result HCR Valves 2 3 1/8" 5K P System Pressure (psi)3000 P Kill Line Valves 2 3 1/8" 5K P Pressure After Closure (psi)1450 P Check Valve 0 NA 200 psi Attained (sec)23 P BOP Misc 0 NA Full Pressure Attained (sec)98 P Blind Switch Covers: All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.): 6 @ 2312 P No. Valves 15 P ACC Misc 0 NA Manual Chokes 1 P Hydraulic Chokes 1 P Control System Response Time:Time (sec) Test Result CH Misc 0 NA Annular Preventer 12 P #1 Rams 9 P Coiled Tubing Only:#2 Rams 9 P Inside Reel valves 0 NA #3 Rams 4 P #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:0 Test Time:4.0 HCR Choke 1 P Repair or replacement of equipment will be made within days. HCR Kill 1 P Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 4/30/2024 19:00 Waived By Test Start Date/Time:5/1/2024 23:00 (date) (time)Witness Test Finish Date/Time:5/2/2024 3:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Kam StJohn Hilcorp Tested w 5" test jt. Joel Sture Hilcorp Clint Montague END DUI MPI 2-74 Test Pressure (psi): inovationtoolpusher@hilcorp.com montague@hilcorp.com Form 10-424 (Revised 08/2022) 2024-0502_BOP_Hilcorp_Innovation_DIU_MPI_2-74 DATE:5/2/24 Finish Date/Time:5/2/2024 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:James Lott - (C) To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC) Subject:Diverter Hilcorp Innovation 4-26-24 Date:Friday, April 26, 2024 6:07:53 PM Attachments:Diverter Hilcorp Innovation 4-26-24.xlsx You don't often get email from jlott@hilcorp.com. Learn why this is important James Lott HILCORP Drilling Foreman HILCORP INNOVATION Rig PBU, North Slope Alaska 907-670-3094 (Office) 907-398-9069 (Cell) Harmony 1006 jlott@hilcorp.com jameslott352@yahoo.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Date: 4/26/2024 Development: X Exploratory: Drlg Contractor: Rig No. Innovation AOGCC Rep: Operator: Oper. Rep: Field/Unit/Well No.: Rig Rep: PTD No.: 2240240 Rig Phone: Rig Email: MISCELLANEOUS:DIVERTER SYSTEM: Location Gen.: P Well Sign: P Designed to Avoid Freeze-up? P Housekeeping: P Drlg. Rig. P Remote Operated Diverter? P Warning Sign P Misc: NA No Threaded Connections? P 24 hr Notice: P Vent line Below Diverter? P ACCUMULATOR SYSTEM:Diverter Size: 13 5/8 in. Systems Pressure: 3,000 psig P Hole Size: 12 1/4 in. Pressure After Closure: 1,950 psig P Vent Line(s) Size: 16 in. P 200 psi Recharge Time: 18 Seconds P Vent Line(s) Length: 260 ft. P Full Recharge Time:55 Seconds P Closest Ignition Source: 109 ft. P Nitrogen Bottles (Number of): 6 Outlet from Rig Substructure: 164 ft. P Avg. Pressure: 2350 psig P Accumulator Misc: NA Vent Line(s) Anchored: P MUD SYSTEM:Visual Alarm Turns Targeted / Long Radius: NA Trip Tank: P P Divert Valve(s) Full Opening: P Mud Pits: P P Valve(s) Auto & Simultaneous: Flow Monitor: P P Annular Closed Time: 25 sec P Mud System Misc: 0 NA Knife Valve Open Time: 14 sec P Diverter Misc: NA GAS DETECTORS:Visual Alarm Methane: P P Hydrogen Sulfide: P P Gas Detectors Misc: 0 NA Total Test Time: 0.5 hrs Non-Compliance Items: 0 Remarks: Submit to: jlott@hilcorp.com TEST DATA Matt Vanhoose phoebe.brooks@alaska.gov Hilcorp Tested with 5" Pipe Size. 0 James Lott 0 670-3094 TEST DETAILS jim.regg@alaska.gov AOGCC.Inspectors@alaska.gov Endicott MPI 2-74 STATE OF AL ASK A ALASKA OIL AND GAS CONSERVATION COMMISSION Divert er Sys tems Inspec tion Repo rt GENERAL INFORMATION WaivedHilcorp *All Divert er report s are due to the agency wi thi n 5 days of t est ing* Form 10-425 (Revised 04/2018) 2024-0426_Diverter_Hilcorp_Innovation_DIU MPI_2-74 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Monty M. Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Endicott Field, Eider Oil Pool, DIU MPI 2-74 Hilcorp Alaska, LLC Permit to Drill Number: 224-024 Surface Location: 3109' FSL, 2388' FEL, Sec. 36, T12N, R16E UM, AK Bottomhole Location: 1703' FSL, 1076' FEL, Sec. 28, T12N, R16E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced well. 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. Spacing exception granted by Conservation Order 813. 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, Brett W. Huber, Sr. Chair, Commissioner Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.04.12 15:29:51 -08'00' 12DATED this day of April 2024. Joe Engel for Monty Myers By Grace Christianson at 2:01 pm, Mar 22, 2024 Joseph Engel (2493) 2024.03.22 12:57:55 -08'00' Joseph Engel (2493) Spacing exception approved in CO 813 * BOPE pressure test to 4500 psi. Annular to 2500 psi. * FIT and casing test digital data to AOGCC upon performing FIT. * Surface casing shoe test (FIT) to 12.3 PPGE for 25 bbl KT. Notify AOGCC if less than 12.3 PPGE. 3 SFD 224-024 SFD 3/27/2024 50-029-23785-00-00 MGR28MAR24 12.0 DSR-4/12/24JLC 4/12/2024 Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr. Date: 2024.04.12 15:30:16 -08'00'04/12/24 04/12/24 Alaska Islands Team - Endicott (DIU) MPI 2-74 Permit to Drill Application Version 1 3/8/2024 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 ..................................................................................................... 11 10.0 N/U 13-5/8” 5M Diverter System ............................................................................................. 12 11.0 Drill 12-1/4” Hole Section ........................................................................................................ 14 12.0 Run 9-5/8” Surface Casing ...................................................................................................... 17 13.0 Cement 9-5/8” Surface Casing ................................................................................................. 21 14.0 ND Diverter, NU BOPE, & Test .............................................................................................. 26 15.0 Drill 8-1/2” Hole Section .......................................................................................................... 27 16.0 Run & Cement 7” Intermediate Casing .................................................................................. 30 17.0 Drill 6-1/8” Hole Section .......................................................................................................... 34 18.0 Run 4-1/2” Liner ...................................................................................................................... 38 19.0 Run Upper Completion/ Post Rig Work ................................................................................. 42 20.0 Innovation Rig Diverter Schematic ......................................................................................... 44 21.0 Innovation Rig BOP Schematic ............................................................................................... 45 22.0 Wellhead Schematic ................................................................................................................. 46 23.0 Tubular Data Sheets ................................................................................................................ 47 24.0 Days Vs Depth .......................................................................................................................... 51 25.0 Formation Tops & Information............................................................................................... 52 26.0 Anticipated Drilling Hazards .................................................................................................. 58 27.0 Innovation Rig Layout ............................................................................................................. 63 28.0 FIT Procedure .......................................................................................................................... 64 29.0 Innovation Rig Choke Manifold Schematic ............................................................................ 65 30.0 Casing Design ........................................................................................................................... 66 31.0 MASP ....................................................................................................................................... 67 32.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 69 33.0 Surface Plat (As-Built) (NAD 27) ............................................................................................ 70 Page 2 AKI - Endicott MPI 2-74 Producer Drilling Procedure 1.0 Well Summary Well 2-74 Pad Endicott MPI Planned Completion Type 4-1/2” Gas Lift Target Reservoir(s) Ivishak Planned Well TD, MD / TVD 19,298’ MD / 10,172’ TVD PBTD, MD / TVD 19,217’ MD / 10,156’ TVD Surface Location (Governmental) 3109' FSL, 2388' FEL, Sec 36, T12N, R16E, UM, AK Surface Location (NAD 27) X= 258,812.2, Y=5,982,252.2 Top of Productive Horizon (Governmental)929' FSL, 1933' FEL, Sec 27, T12N, R16E, UM, AK TPH Location (NAD 27) X= 248,811, Y= 5,985,681 BHL (Governmental) 1703' FSL, 1076' FEL, Sec 28, T12N, R16E, UM, AK BHL (NAD 27) X= 244,416, Y= 5,986,602 AFE Drilling Days 35 AFE Completion Days 3 Maximum Anticipated Surface Pressure (intermediate) 3470 psi Maximum Anticipated Surface Pressure (production) 3627 psi Maximum Anticipated Pressure (Downhole/Reservoir Intermediate) 4429 psig Maximum Anticipated Pressure (Downhole/Reservoir Production) 4629 psig Work String 5” 19.5# S-135 NC 50 & 4” 14# XT39 Innovation KB Elevation above MSL: 26.5 ft +13.7ft =40.2ft GL Elevation above MSL: 40.2 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 AKI - Endicott MPI 2-74 Producer Drilling Procedure 2.0 Management of Change Information Page 4 AKI - Endicott MPI 2-74 Producer Drilling Procedure 3.0 Tubular Program: Hole Section OD (in)ID (in) Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 20” 19.25”---X-52Weld 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 8-1/2” 7” 6.276 6.151 7.693 26 L-80 JFEBear 7240 5410 604 6-1/8 4-1/2” 3.958 3.833 5 12.6 13Cr JFE BEAR 8,430 7,500 288 Tubing 4-1/2” 3.958 3.833 5 12.6 13Cr JFE BEAR 8,430 7,500 288 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 & Intermediate 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 Production 4”3.34 2.688 4.875 14 S-135 XT-39 17,700 21,200 553klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 AKI - Endicott MPI 2-74 Producer Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellView. 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 mmyers@hilcorp, nathan.sperry@hilcorp.com, jengel@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 mmyers@hilcorp,com jengel@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 mmyers@hilcorp.com jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.7 Hilcorp Contact List: Title Name Work Phone Email Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com Completion Engineer Brenden Swenson 907.748.8581 brenden.swensen@hilcorp.com Geologist Brock Rust 907.777.8394 brust@hilcorp.com Reservoir Engineer Gavin Dittman 907.564.5246 Gavin.dittman@hilcorp.com EHS Manager Laura Green 907.777.8314 lagreen@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com _____________________________________________________________________________________ Revised By: JNL 3/21/2024 PROPOSED SCHEMATIC Duck Island Unit Well: END 2-74 Last Completed: TBD PTD: TBD GENERAL WELL INFO API: TBD Completion Date: TBD TD = 19,298’(MD) / TD =10,172’(TVD) 4 20” Orig. KB Elev.: 40.2’ / GL Elev.: 13.7 7” 85 4 10 9-5/8” 9 1 9-5/8” ES Cementer @ ~2,000’ 2 3 PBTD =19,217’(MD) / PBTD =10,156’(TVD) 12,137 5 12 4-1/2” 3 2 4-1/2” 7 11 6 TREE & WELLHEAD Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead FMC 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs OPEN HOLE / CEMENT DETAIL Driven 20” Conductor 12-1/4”1st Lead – 532 sx / Tail – 395 sx 2nd Lead – 578 sx / tail - 270 sx 8-1/2” 105 sx Class G 6-1/8” 589 sx Class G CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X56 / Weld N/A Surface 180’ N/A 9-5/8” Surface 47 / L-80 / TXP 8.679” Surface 2,000’ 0.0758 9-5/8” Surface 40 / L-80 / TXP 8.679” 2,000’ 6,072’ 0.0758 7” Intermediate 29 / L-80 / VT 6.184” Surface 14,657’ 0.0371 4-1/2” Production Liner 12.6# / CR13 / JFE-B 3.958” 14,500’ 19,298’ 0.0086 TUBING DETAIL 4-1/2" Tubing 12.6# / CR13 / JFE-B 3.958” Surface 14,500’ 0.0152 JEWELRY DETAIL No. MD Item ID 1 ~1,550 SSSV Nipple 3.813” 2 ~5,150’ 4.5”x1” GLM 3,800’ TVD 3.833” 3 ~7,580’ 4.5”x1” GLM 5,300’ TVD 3.833” 4 ~9,650’ 4.5”x1” GLM 6,550’ TVD 3.833” 5 ~11,275’ 4.5”x1” GLM 7,500’ TVD 3.833” 6 ~12,650’ 4.5”x1” GLM 8,400’ TVD 3.833” 7 ~14,330’ 4.5”x1” GLM – 1 full joint from x nipple 3.833” 8 ~14,370’ X Nipple 3.813” 9 ~14,400’ 4-1/2” HES TNT Production Packer 3.865” 10 ~14,430’ X Nipple 3.813” 11 ~14,460’ XN Nipple 3.725” 12 ~14,507’ Liner Hanger 4.890” 13 ~14,525’ Hanger Packer 6.180” WELL INCLINATION DETAIL KOP @ 250’ 52° Hole Angle @ 2,357’ – 14,309’ 96° Max Hole Angle @ 16,300’ Page 7 AKI - Endicott MPI 2-74 Producer Drilling Procedure 7.0 Drilling / Completion Summary MPI 2-74 is a grassroots producer planned to be drilled in the Ivishak sands. 2-74 is part of a multi-well program on Endicott MPI. The directional plan is 12-1/4” surface hole and 9-5/8” surface casing set in a shale above the SV4 Sand. 8- 1/2” intermediate hole will be drilled into the top of the Ivishak sand, with 7” casing ran and cemented. A 6- 1/8” lateral will be drilled in the Ivishak. A 4-1/2” cemented liner will be run in the open hole section, followed by 4-1/2” gas lift tubing. The Innovation Rig will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately April 6, 2024, pending rig schedule. Surface casing will be run to 6,071’ MD / 4384’ TVD and cemented to surface via a two 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 one of two locations: Primary: Prudhoe G&I on Pad 4 General sequence of operations: 1. MIRU Innovation Rig to well site 2. N/U & Test 13-5/8” 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” to section TD 6. Run and cement 7” casing 7. Drill 6-1/8” lateral to well TD 8. Run and cement 4-1/2” liner 9. Run Upper Completion 10. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Surface & Intermediate hole: No mud logging. Remote geologist. LWD: GR + Res 2. Production Hole: No mud logging. Remote geologist. LWD: GR + Res + Azimuthal Res April 6, 2024 Page 8 AKI - Endicott MPI 2-74 Producer Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that all drilling and completion operations comply with all applicable AOGCC regulations. Operations stated in this PTD application may be altered based on sound engineering judgement as wellbore conditions require, but no AOGCC regulations will be varied from without prior approval from the AOGCC. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. 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 DIU 2-74. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/4,500 psi & subsequent tests of the BOP equipment will be to 250/4,500 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)”. Page 9 AKI - Endicott MPI 2-74 Producer Drilling Procedure AOGCC Spacing Exception Approval: In accordance with Conservation Order 813, AOGCC granted Hilcorp a spacing exception to Rule 3 of Conservation Order 449, allowing for the drilling of MPI 2-74 within 500’ of the external boundary of the Eider Oil Pool, Duck Island Unit Page 10 AKI - Endicott MPI 2-74 Producer Drilling Procedure Summary of Innovation BOP Equipment & Test Requirements Hole Section Equipment Test Pressure (psi) 12-1/4”x 13-5/8” 5M CTI Annular BOP w/ 16” diverter line Function Test Only 8-1/2” & 6-1/8” x 13-5/8” x 5M Control Technology Inc Annular BOP x 13-5/8” x 5M Control Technology Inc Double Gate o Blind ram in btm cavity x Mud cross w/ 3” x 5M side outlets x 13-5/8” x 5M Control Technology 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: 250/4000 Subsequent Tests: 250/4000 Primary closing unit: Control Technology Inc. (CTI), 6 station, 3,000 psi, 220 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric triplex pump on a different electrical circuit 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 11 AKI - Endicott MPI 2-74 Producer Drilling Procedure 9.0 R/U and Preparatory Work 9.1 2-74 will utilize a 20” conductor on MPI. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Ensure PTD, COAs, 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 Innovation. 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). x Cold mud temps are necessary to mitigate hydrate breakout 9.10 Ensure 5” liners in mud pumps. x White Star Quattro 1,300 HP mud pumps are rated at 4,097 psi, 381 gpm @ 140 spm @ 96.5% volumetric efficiency. Page 12 AKI - Endicott MPI 2-74 Producer Drilling Procedure 10.0 N/U 13-5/8” 5M Diverter System 10.1 N/U 13-5/8” CTI BOP stack in diverter configuration (Diverter Schematic attached to program). x N/U 20” x 13-5/8” DSA x N/U 13 5/8”, 5M diverter “T”. x NU 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. x Utilized extensions if needed. 10.2 Notify AOGCC with 24 hour notice to witness. 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 30 seconds (API Standard 64 3rd edition March 2018 section 12.6.2 for packing element ID less than or equal to 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 13 AKI - Endicott MPI 2-74 Producer Drilling Procedure 10.4 Rig & Diverter Orientation: x May change on location Page 14 AKI - Endicott MPI 2-74 Producer Drilling Procedure 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 Consider running a UBHO sub for wireline gyro.GWD will be the primary gyro tool. 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 shale above the SV4 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 Drilling Engineer. x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 3 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 Directional plan starts at 3 to keep tangent inc down. If possible get ahead of build rates while still meeting tangent hold target. 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 9.5 at base of perm and at TD. x Perform gyro surveys until clean MWD surveys are seen. Take MWD surveys every stand drilled. x Take MWD and GWD surveys every stand until magnetic interference cleans up. After MWD surveys show clean magnetics, only take MWD surveys. Page 15 AKI - Endicott MPI 2-74 Producer Drilling Procedure x Surface Hole AC: x There are no wells that have a CF <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 9.5+ ppg. MW for free gas and hydrates based upon offset wells Depth Interval MW (ppg) Surface – Base Permafrost 8.9+ Base Permafrost - TD 9.5+ 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: Aquagel and Barazan D+ 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 L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs 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 CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok. 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 DESCO 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). System Type:8.8 – 9.8 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp Surface 8.8 –9.8 150-300 20 - 45 25-50 <10 8.5 –9.0 80 F System Formulation: Gel + FW spud mud Page 16 AKI - Endicott MPI 2-74 Producer Drilling Procedure 11.5 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem sweeps and drop viscosity. Observe well for flow. 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 wireline logging program planned. Page 17 AKI - Endicott MPI 2-74 Producer Drilling Procedure 12.0 Run 9-5/8” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Weatherford 9-5/8” casing running equipment (CRT & Tongs) x Ensure 9-5/8” BTC x NC50 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 8.75” on the location prior to running. x Top 2,000’ of casing 47# drift 8.525” x Actual depth to be dependent upon base of permafrost and stage tool 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” , 2 Centralizers 10’ from each end w/ stop rings 1 joint –9-5/8” , 1 Centralizer mid joint w/ stop ring 9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’ 1 joint – 9-5/8” , 1 Centralizer mid joint with stop ring 9-5/8” HES Baffle Adaptor x Ensure bypass baffle is coreclty 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. Page 18 AKI - Endicott MPI 2-74 Producer Drilling Procedure 12.5 Float Equipment and Stage tool equipment drawings Page 19 AKI - Endicott MPI 2-74 Producer Drilling Procedure 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 Bowspring Centralizers only x 1 centralizer every joint to ~ 1000’ MD from shoe x 1 centralizer every 2 joints to ~ 2,000’ above shoe 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. 9-5/8” 47# L-80 TXP Make-Up Torques: Casing OD Minimum Optimum Maximum 9-5/8”21,440 23,820 26,200 9-5/8” 40# L-80 TXP Make-Up Torques: Casing OD Minimum Optimum Maximum 9-5/8”18,860 20,960 23,060 12.7 Install the Halliburton Type H ES-II Stage tool at ~ 2000’ MD (~ 450’ TVD below base perm, actual depth based upon base of 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. 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 Page 20 AKI - Endicott MPI 2-74 Producer Drilling Procedure 12.9 Centralizers 1/jt for 5 joints above and below stage tool. x Confirm stage tool depth compatibility with cancellation plug, inclination sensitive 12.10 The last 2,000’ of 9-5/8” will be 47#, from 2,000’ to Surface x Actual length of 47# may change due to depth of permafrost as drilled x Ensure drifted to 8.525” 12.11 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 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 21 AKI - Endicott MPI 2-74 Producer Drilling Procedure 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 Cement Volume: Section Calculation Vol (bbl) Vol (ft3) Vol (sks) 12-1/4" OH x 9-5/8" Casing (6072'-1,000'-2,000') x 0.0558 bpf x 1.3 222.8 1249.7 Total Lead 222.8 1249.7 531.8 12-1/4" OH x 9-5/8" Casing 1000' x 0.0558 bpf x 1.3 = 72.5 406.8 9-5/8" Shoetrack 120' x 0.0758 bpf = 9.1 51.0 Total Tail 81.6 457.8 394.7 Le a d Ta i l Page 22 AKI - Endicott MPI 2-74 Producer Drilling Procedure 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 continu 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. a. 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. Displacement calculations have proven to be very accurate using 0.0625 bps (5” liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. 13.12 Displacement calculation: a. 2000’ x 0.0732 bpf + (6072’-120’-2000’) x .0758 bpf = b. = 446.1 bbls 80 bbls of tuned spacer to be left behind stage tool for preventing of contamination of cement in the annulus 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. 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 Mixed Water 13.92 gal/sk 4.95 gal/sk Page 23 AKI - Endicott MPI 2-74 Producer Drilling Procedure 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 to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. a. Ensure the free fall stage tool opening plug is available. This is the back-up option to open the stage tool if the plugs are not bumped. 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 24 AKI - Endicott MPI 2-74 Producer Drilling Procedure 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. a. Past wells have seen pressure increase while circulating through stage tool after reduced rate 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. Cement will continue to be pumped until clean spacer is observed at surface. Estimated 2nd Stage Total Cement Volume: Cement Slurry Design (2nd Stage): Lead Slurry Tail Slurry System Arctic Cem HalCem Density 11.0 lb/gal 15.8 lb/gal Yield 2.535 ft3/sk 1.16 ft3/sk Mixed Water 12.2 gal/sk 5.06 gal/sk 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. Section Calculation Vol (bbl) Vol (ft3) Vol (sks) 20" Cond x 9-5/8" Casing 110' x 0.26 bpf 28.6 160.4 12-1/4" OH x 9-5/8" Casing (1500' - 110) x .0558 x 3 232.6 1304.9 Total Lead 261.2 1465.4 578.1 12-1/4" OH x 9-5/8" Casing (2000 - 1500') x .0558 bpf x 2 55.8 313.0 Total Tail 55.8 313.0 269.9 Le a d Ta i l Page 25 AKI - Endicott MPI 2-74 Producer Drilling Procedure 13.26 Displacement calculation: 2000’ x 0.0732 bpf = 146.4 bbls mud 13.27 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. 13.28 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. 13.29 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. 13.30 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. Ensure slip tension is between 50-100klb 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 jengel@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 26 AKI - Endicott MPI 2-74 Producer Drilling Procedure 14.0 ND Diverter, NU BOPE, & Test 14.1 Give AOGCC 24hr notice of BOPE test, for test witness. 14.2 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool. 14.3 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 5-1/2” VBRs or 5” solid body rams 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. 14.4 RU MPD RCD and related equipment 14.5 Run 5” BOP test plug 14.6 Test BOP to 250/4,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min. x Test with 5” test joint and test VBR’s with 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 14.7 RD BOP test equipment 14.8 Dump and clean mud pits, send spud mud to G&I pad for disposal. 14.9 Mix 9.5 ppg mud to be used in intermediate hole 14.10 Set wearbushing in wellhead. 14.11 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole section. 14.12 Ensure 5” liners in mud pumps. Page 27 AKI - Endicott MPI 2-74 Producer Drilling Procedure 15.0 Drill 8-1/2” Hole Section 15.1 P/U 8-1/2” directional drilling assembly: x BHA will be an RSS 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 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 floats in the intermediate hole section. 15.2 TIH to TOC above the shoetrack. Note depth TOC tagged on morning report. 15.3 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.4 Drill out shoe track and 20’ of new formation. 15.5 CBU and condition mud for FIT. 15.6 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 provides >25 bbls based on 9.5ppg MW, 8.9 ppg PP (swab kick). x Email digital data for casing test and FIT to AOGCC upon completion – Melvin.rixse@alaska.gov x 15.7 Drill 8-1/2” hole section to to Above the Tuffs ~ 13140 MD. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. x Hold a safety meeting with rig crews to discuss: x Well control procedures x Flow rates, hole cleaning, etc. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 350-500 gpm. 120 rpm 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 Adjust MW and viscosity as necessary to maintain hole stability, x Survey frequency each stand, with more surveys taken as needed x Intermediate Hole AC: 11.9 for 25 bbl KT for a 0.5 ppg kick intensity utilizing 10.0 ppg drilling fluid at 8-1/2" OH TD. Page 28 AKI - Endicott MPI 2-74 Producer Drilling Procedure x There are no wells with CF <1.0 in the intermediate hole section 15.8 8-1/2” 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. Depth Interval MW (ppg) Surface shoe –Top Tuffs 9.5+ Top Tuffs – TD 10-10.5 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: Aquagel and Barazan D+ 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. Ensure 6rpm reading is 1-1.5x of hole diameter, 8.5-12.75 x Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs 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 CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok. 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 DESCO 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). System Type:8.8 – 10.8 ppg 3% Kcl LSND Properties: Section Density Viscosity Plastic Viscosity Yield Point MBT pH LGS Intermediate 9.5 –10.8 40-53 20 - 40 15-25 <15 9-10 6% Page 29 AKI - Endicott MPI 2-74 Producer Drilling Procedure 15.9 Once at 13140’ MD, ~200’ MD above Tuffs, CBU x3-4 at full rate and rpm 15.10 Perform a short trip to the surface casing shoe x BROOH if necessary 15.11 TIH to bottom 15.12 Install MPD RCD Element 15.13 Weight up to ~ 10.0ppg x MW to be finalized by Drilled ECDs, target ~ 11.5ppg EMW x Ensure black product has been added 15.14 Drill 8-1/2” hole section to TD in the Ivishak Sands to be called by geologist, ~ 14,657 x Flow Rate: 300-500 GPM x RPM: 120 x Utilizing MPD, maintain constant bottom hole pressure on connections, target ecd 11.5ppg EMW 15.15 At TD CBU x 3-4, full rate and rpm, not to exceed 11.5 ppg EMW, weight up to 10.5 ppg 15.16 POOH to above HRZ, then POOH or BROOH to surface casing shoe x Pump at full drill rate and maximize rotation, do not exceed 11.5 ppg EMW at HRZ x Ensure pulling speeds have been modeled to ensure swab pressures do not drop below 10.0ppg emw 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 If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 15.17 CBU at casing shoe 15.18 TOOH and LD BHA 15.19 No wireline logging program planned Page 30 AKI - Endicott MPI 2-74 Producer Drilling Procedure 16.0 Run & Cement 7” Intermediate Casing 16.1 R/U and pull wearbushing. 16.2 R/U 7” casing running equipment (CRT & Tongs) x Ensure 7” 26# JFEBear 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. 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. x Plan to land the 7” casing on a mandrel hanger. 16.3 P/U shoe joint, visually verify no debris inside joint. 16.4 Continue M/U & thread locking 120’ shoe track assembly consisting of: 7” Float Shoe 1 joint – 7”, 2 Centralizers 10’ from each end w/ stop rings 1 joint –7”, 1 Centralizer mid joint w/ stop ring 1 joint – 7”, 1 Centralizer mid joint with stop ring 7” Float Collar 16.5 Continue running 7” intermediate 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 ~ 500’ MD above HRZ 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. 7” 26# L-80 JFEBear Make-Up Torques: confirm Casing OD Minimum Optimum Maximum 7”11,800 ft-lbs 13,110 ft-lbs 14420 ft-lbs Page 31 AKI - Endicott MPI 2-74 Producer Drilling Procedure 16.6 Continue running 7” casing x Fill casing while running using fill up line on rig floor ~ 10jts x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. 16.7 Circulate BU at predetermined intervals, every ~ 2000’ MD to remove any thickened mud while out of the hole: x Surface Casing Shoe x ~8000’ MD x ~1000’ MD x ~12000’ MD x ~14000’MD 16.8 Ensure Running speeds have been modeled to avoid surging the wellbore above drilling ECDs, ~ 11.5ppg EMW. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.9 Do not circulate across HRZ 16.10 Slow in and out of slips. 16.11 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. 16.12 Lower casing to setting depth. Confirm measurements. 16.13 Have emergency slips staged along with necessary equipment for the operation. 16.14 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. 16.15 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 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. 16.16 Document efficiency of all possible displacement pumps prior to cement job. Page 32 AKI - Endicott MPI 2-74 Producer Drilling Procedure 16.17 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. 16.18 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. 16.19 Fill surface lines with water and pressure test. 16.20 Pump 60 bbls 11 ppg tuned spacer. 16.21 Mix and pump cmt per below recipe. 16.22 Cement volume based on annular volume + open hole excess (50%). Job will consist of tail, TOC brought to 500’ above Ivishak Sand x Prognosed Ivishak Top: 14,654’ MD, Planned TOC: 14,154’ MD Estimated Total Cement Volume: Cement Slurry Design (Single Stage Cement Job) 16.23 After pumping cement, drop top plug and displace cement with mud out of mud pits. x (14657-120)’ x .0371bpf = 539.3 bbl 16.24 Monitor returns closely while displacing cement. Adjust pump rate if necessary. 16.25 Land top plug and pressure up to 500 psi over bump pressure. Bleed pressure and check floats. If floats are not holding, shut in and hold 500 psi over bump pressure until cement builds compressive strength. 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, weight & type of displacing fluid Section Calculation Vol (bbl) Vol (ft3) Vol (sks) 8.5" OH x 7" (14,657 - 14154)' x 0.0226 bpf x 1.5 = 17.1 95.9 7" Shoetrack 120' x 0.0372 bpf = 4.5 25.2 Total Tail 21.6 121.2 104.5 Ta i l Tail Slurry System HalCem Density 15.8 lb/gal Yield 1.16 ft3/sk Mixed Water 5.06 gal/sk Page 33 AKI - Endicott MPI 2-74 Producer Drilling Procedure x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement, 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 time cement in place & calculated top of cement Send final “As-Run” casing tally & casing and cement report to jengel@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 34 AKI - Endicott MPI 2-74 Producer Drilling Procedure 17.0 Drill 6-1/8” Hole Section 17.1 MU 6-1/8” 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 4” 14# XT39 x Run a ported float in the production hole section. 17.2 TIH 17.3 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. 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. 17.4 Drill out shoe track and 20’ of new formation. 17.5 CBU and condition mud for FIT. 17.6 Conduct FIT to 11.0 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 11.0 ppg provides >25 bbls based on 9.5ppg MW, 8.9ppg PP (swabbed kick) x Email digital data for casing test and FIT to AOGCC upon completion – Melvin.rixse@alaska.gov 17.7 6-1/8” 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. Page 35 AKI - Endicott MPI 2-74 Producer Drilling Procedure x Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. 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:9.3 – 10.5 ppg 3% Kcl Baradril-N Properties: Interval Density PV YP LSYP Total Solids MBT HPHT Production 9.3 – 10.5 15-25 - ALAP 15 - 25 4-6 <8% <7 <11.0 System Formulation: Product Concentration Water KCL KOH N-VIS DEXTRID LT BARACARB 5 BARACARB 25 BARACARB 50 BARACOR 700 BARASCAV D X-CIDE 207 0.955 bbl 11 ppb 0.1 ppb 1.0 – 1.5 ppb 5 ppb 6 ppb 6 ppb 2 ppb 1.0 ppb 0.5 ppb 0.015 ppb 17.8 Install MPD RCD 17.9 Displace wellbore to 9.5 ppg Baradrill-N drilling fluid 17.10 Begin drilling 6-1/8” 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 Page 36 AKI - Endicott MPI 2-74 Producer Drilling Procedure 17.11 Drill 6-1/8” hole section as per Geologist and Drilling Engineer. x Flow Rate: 150-250 GPM, target min. AV’s 200 ft/min, x RPM: 120+ 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 MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection 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 MPD will be utilized to maintain constant bottom hole pressure (matching drilling ECD) x 6-1/8” Section A/C: x MPI 2-30A has a CF < 1.0 at 17400’ MD, 2-30A is an abandoned sidetrack (the current active well is 2-30B), the only risk is damage to the bit x MPI 2-30A PB2 has a CF < 1.0 at 16,100’ MD, 2-30A PB2 is an abandoned plugback (the current active well is 2-30B), there is no risk x MPI 2-56A PB1 has a CF <1.0 at 18,225’ MD, 2-56A PB1 is an abandoned plugback there is no risk x MPI 2-72 wp09 has a CF < 1.0, 2-72 wp09 is a well plan, if it is drilled 2-74 will be nudged to provide adequate separation 17.12 Once at TD, CBU 2-3, MW at TD 9.5ppg x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary 17.15 POOH with the drilling assembly to the 7” casing shoe x Ensure swab pressures do not drop below .5 ppg EMW at TD x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as dictated by hole conditions x If backreaming operations are commenced, continue backreaming to the shoe, maintinaing a constant bottom hole pressure 17.16 CBU minimum two times at 7” shoe and clean casing with high vis sweeps. 17.17 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary. x Wellbore breathing has been seen on past 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 17.18 POOH and LD BHA. Page 37 AKI - Endicott MPI 2-74 Producer Drilling Procedure 17.19 Rabbit DP on TOOH, ensure rabbit diameter is sufficient for future ball drops. x Only LWD open hole logs are planned for the hole section (GR + Res + Azimuthal Resistivity). There will not be any additional logging runs conducted. Page 38 AKI - Endicott MPI 2-74 Producer Drilling Procedure 18.0 Run 4-1/2” Liner 18.1 Well control preparedness: In the event of an influx of formation fluids while running the liner, the following well control response procedure will be followed: x P/U & M/U the 4” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 4-1/2” liner. x Slack off and with 4” DP across the BOP, shut in ram or annular on 4” DP. Close TIW. x Proceed with well kill operations. 18.2 R/U 4-1/2” liner running equipment. x Ensure 4-1/2” 12.6# 13Cr JFEBear x 4” dp 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. 18.3 Run 4-1/2” 12.6# 13cr JFE Bear x Use JFE approved thread compound. Dope pin end only w/ paint brush. Wipe off excess. 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 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm x Make Up Torque Table (See data sheets in section 23) x 4-1/2” 12.6# L-80 13Cr JFE Bear Make-Up Torques: Casing OD Minimum Optimum Maximum 4-1/2”4,860 5,400 5,940 18.4 Ensure to run enough liner to provide for setting the liner hanger at ~ 14507 MD x Confirm set depth with completion engineer. 18.5 Ensure hanger/pkr will not be set in a 7” 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 7” connection. 18.6 Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 18.7 M/U Baker SLZXP liner top packer to liner. Page 39 AKI - Endicott MPI 2-74 Producer Drilling Procedure 18.8 Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 18.9 RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. x Ensure 4” DP/HWDP has been drifted x Fill drill pipe on the fly. Monitor FL and if filling is required due to losses/surging. 18.10 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 18.11 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. 18.12 TIH to planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 18.13 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 18.14 With liner at TD Circulate and condition mud, 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. 18.15 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 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. 18.16 Document efficiency of all possible displacement pumps prior to cement job. 18.17 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. Page 40 AKI - Endicott MPI 2-74 Producer Drilling Procedure 18.18 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. 18.19 Fill surface lines with water and pressure test. 18.20 Pump 30 bbls 11 ppg tuned spacer. 18.21 Mix and pump cmt per below recipe. 18.22 Cement volume based on annular volume + open hole excess (50%). Job will consist of tail, TOC brought to the liner top inside the 7” casing shoe, 14507’ MD Cement Slurry Design (Single Stage Cement Job) 18.23 After pumping cement, drop dart and displace cement with mud out of mud pits. x (19,297’-120’-14507’) * .0143bpf + 14507’ * .0103 bpf (4” dp capacity) = 66.7 + 149.4 x = 216.2 bbls 18.24 Monitor returns and pump pressure closely while displacing, slow down pumps when dart latches onto liner wiper plug. 18.25 Land liner wiper plug and pressure up to 500 psi over bump pressure. Bleed pressure and check floats. If floats are not holding, shut in and hold 500 psi over bump pressure until cement builds compressive strength. 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, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement, 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 Section Calculation Vol (bbl) Vol (ft3) Vol (sks) 6.125" OH x 4-1/2" (19,297 - 14507)' x 0.0168 bpf x 1.5 = 120.7 677.1 4-1/2" Shoetrack 80' x 0.0143 bpf = 1.2 6.5 Total Tail 121.9 683.6 589.3 Ta i l Tail Slurry System HalCem Density 15.8 lb/gal Yield 1.16 ft3/sk Mixed Water 5.06 gal/sk Page 41 AKI - Endicott MPI 2-74 Producer Drilling Procedure x Note time cement in place & calculated top of cement Send final “As-Run” casing tally & casing and cement report to jengel@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. 18.26 Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the SLZXP 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. 18.27 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. 18.28 PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted. 18.29 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. 18.30 PU pulling running tool free of the packer and displace with at max rate to wash the liner top. Pump sweeps as needed. 18.31 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 42 AKI - Endicott MPI 2-74 Producer Drilling Procedure 19.0 Run Upper Completion/ Post Rig Work 19.1 RU to run 4-1/2”, 12.6# 13Cr, L-80 JFEBear tubing. x Ensure wear bushing is pulled. x Ensure 4-1/2”, L-80, 12.6#, JFEBear x NC50 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 Be sure to count the total # of joints in the pipe shed before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info. x Monitor displacement from wellbore while RIH. Make Up Torque Table (See data sheets in section 23) 4-1/2” 12.6# L-80 13Cr JFE Bear Make-Up Torques: Casing OD Minimum Optimum Maximum 4-1/2”4,860 5,400 5,940 19.2 PU, MU and RH with the following 4-1/2” completion jewelry (tally to be provided by Operations Engineer): x Tubing Jewelry to include: x X1 SSSV Nipple x X6 GLM x X1 X Nipple x X1 Production Packer x X1 X Nipple x X1 XN Nipple x 1x WLEG, set as close to 7” x 4-1/2” liner xo as possible *Note the packer setting and pressure testing procedure has been changed to reflect running TBG with live gas lift valve. Please consult the OE/DE if there are any questions before proceeding. 19.3 PU and MU the 4-1/2” tubing hanger. 19.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with band/clamp summary. 19.5 Land the tubing hanger and RILDS. Lay down the landing joint. 19.6 Install 4” HP BPV. ND BOP. Install the plug off tool. 19.7 NU the tubing head adapter and NU the tree. Page 43 AKI - Endicott MPI 2-74 Producer Drilling Procedure 19.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi. 19.9 Pull the plug off tool and BPV. 19.10 Forward circulate the well over to corrosion inhibited KCL follow by 160 bbls of diesel freeze protect for both tubing and IA to 5,000’ MD. 19.11 Drop the ball & rod and complete loading tubing and hydraulically set the packer as per Halliburton’s setting procedure 19.12 Pressure up and test the tubing to 3500 psi for MIT-T with 1000 psi on the IA. While holding pressure on the tubing pressure the IA up to 3,500psi. Test the IA to 3500 psi for CMIT-TxIA. Record and notate all pressure tests (30 minutes) on chart. 19.13 Bleed both the IA pressure to 0psi and tubing to 200 psi. 19.14 Rig up jumper from IA to tubing to allow freeze protect to swap. 19.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 19.16 RDMO Innovation i. POST RIG WELL WORK 1. Wireline a. Pull Ball & Rod, RHC Plug b. Perforate Well (Separate Sundry) c. Set SSSV 2. Well Tie in 3. Put well on production Page 44 AKI - Endicott MPI 2-74 Producer Drilling Procedure 20.0 Innovation Rig Diverter Schematic Page 45 AKI - Endicott MPI 2-74 Producer Drilling Procedure 21.0 Innovation Rig BOP Schematic Page 46 AKI - Endicott MPI 2-74 Producer Drilling Procedure 22.0 Wellhead Schematic Page 47 AKI - Endicott MPI 2-74 Producer Drilling Procedure 23.0 Tubular Data Sheets Surface Casing: 9-5/8” 47# Page 48 AKI - Endicott MPI 2-74 Producer Drilling Procedure Surface Casing 9-5/8” 40# Page 49 AKI - Endicott MPI 2-74 Producer Drilling Procedure Intermediate Casing 7” 26# Page 50 AKI - Endicott MPI 2-74 Producer Drilling Procedure Upper & Lower Completion 4-1/2” 13Cr 12.6# Page 51 AKI - Endicott MPI 2-74 Producer Drilling Procedure 24.0 Days Vs Depth Page 52 AKI - Endicott MPI 2-74 Producer Drilling Procedure 25.0 Formation Tops & Information Reference Plan: base perm Gravel-Sand-Clay-Wood Water 1469 1440 -1400 633 8.46 sv5 SS-sst-shale Minor coal seams Water like l 5820 4230 -4190 1861 8.46 sv4 SS-sst-shale Minor coal seams Water likel 6230 4480 -4440 1971 8.46 sv3 SS-sst-shale Minor coal seams Water likel 6639 4729 -4689 2080 8.46 sv2 SS-sst-shale Minor coal seams Water likel 6926 4904 -4864 2157 8.46 sv1 SS-sst-shale Minor coal seams Water likel 7666 5354 -5314 2355 8.46 UG-4 SS Water 8312 5748 -5708 2529 8.46 top west sak Water 9766 6633 -6593 2918 8.46 top seaebee Water 11323 7581 -7541 3335 8.46 top hue/tuffs Shale and Tuffs Tight 13341 8810 -8770 3876 8.46 BHRZ Shale Tight 14517 9518 -9478 4187 8.46 LWR-IVI SS-Congl Oil 14656 9587 -9547 4429 8.9 MID-IVI SS-Congl Oil 16750 9806 -9766 4531 8.9 MID-IVI SS-Congl Oil 17887 9878 -9838 4564 8.9 LWR-IVI SS-Congl Oil 18532 10018 -9978 4629 8.9 Comments ANTICIPATED FORMATION TOPS & GEOHAZARDS 2-74wp07 TOP NAME LITHOLOGY EXPECTED FLUID MD (FT) TVD (FT) TVDSS (FT) Est. Pressure Gradient Page 53 AKI - Endicott MPI 2-74 Producer Drilling Procedure Endicott MPI Pad Data Sheet Information: Surface Hole Page 54 AKI - Endicott MPI 2-74 Producer Drilling Procedure Intermediate Hole: Page 55 AKI - Endicott MPI 2-74 Producer Drilling Procedure Niakuk Pad Data Sheet Information Surface Hole Page 56 AKI - Endicott MPI 2-74 Producer Drilling Procedure Intermediate Hole Page 57 AKI - Endicott MPI 2-74 Producer Drilling Procedure Production Hole Page 58 AKI - Endicott MPI 2-74 Producer Drilling Procedure 26.0 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. 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: Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. x Surface Hole AC: x No Wells with CF < 1.0 Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. Page 59 AKI - Endicott MPI 2-74 Producer Drilling Procedure 8-1/2” Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up 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. Maintain circulation rate of > 385gpm, 200 ft/min AV, 120 rpm, 6 rpm reading of greater than hole diameter. 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: Crossing faults, known or unknown, can result in drilling into unstable formations that may impact future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared for accordingly. Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen. Gas Cut Mud Gas cut mud as been seen, ensure sufficient MW is used during hole section. Ensure gas detectors are always functioning. Watch swab effect. Shale Stability: Intermediate Hole will cross multiple shale formations, ensure black product is in the mud system, sufficient MW is used, MPD is used to maintain constant bottomhole pressure, and surge/swab pressures are modeled and kept in mind 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. 8-1/2” Section specific A/C: x There are no wells with CF <1.0 in the intermediate hole section Page 60 AKI - Endicott MPI 2-74 Producer Drilling Procedure 6-1/8” 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. 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: Crossing faults, known or unknown, can result in drilling into unstable formations that may impact future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared for accordingly. Abnormal Pressures and Temperatures: higher than normal in the Ivishak. Ensure LCM in the mud system and monitor well for flow. Utilize MPD to mitigate any abnormal pressure seen. Shale Stability: Production Hole could potentially cross multiple shale formations, ensure black product is in the mud system, sufficient MW is used, MPD is used to maintain constant bottomhole pressure, and surge/swab pressures are modeled and kept in mind 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. 6-1/8” A/C: x MPI 2-30A has a CF < 1.0 at 17400’ MD, 2-30A is an abandoned sidetrack (the current active well is 2-30B), the only risk is damage to the bit x MPI 2-30A PB2 has a CF < 1.0 at 16,100’ MD, 2-30A PB2 is an abandoned plugback (the current active well is 2-30B), there is no risk x MPI 2-56A PB1 has a CF <1.0 at 18,225’ MD, 2-56A PB1 is an abandoned plugback there is no risk x MPI 2-72 wp09 has a CF < 1.0, 2-72 wp09 is a well plan, if it is drilled 2-74 will be nudged to provide adequate separation Page 61 AKI - Endicott MPI 2-74 Producer Drilling Procedure Entire Hole Section H2S: Treat every hole section as though it has the potential for H2S. Endicott MPI has a history of H2S on wells in all reservoirs. Current H2S Data on Next Page. 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 62 AKI - Endicott MPI 2-74 Producer Drilling Procedure EntCode Test Date PPM EntCode Test Date PPM 1-01-H2S 2024-01-16 280 1-01-H2S 2011-01-20 780 1-03-H2S 2024-01-19 390 1-03-H2S 2013-10-06 820 1-05-H2S 2010-05-25 0 1-05-H2S 2010-05-25 0 1-09-H2S 2014-07-08 190 1-09-H2S 2011-08-21 300 1-17-H2S 2023-01-17 650 1-17-H2S 2023-01-17 650 1-19-H2S 2024-01-21 315 1-19-H2S 2008-05-22 880 1-21-H2S 2013-09-28 210 1-21-H2S 2010-03-15 270 1-25-H2S 2023-04-26 280 1-25-H2S 2022-01-05 880 1-27-H2S 2024-01-16 625 1-27-H2S 2023-01-02 650 1-29-H2S 2024-01-27 305 1-29-H2S 2011-08-02 800 1-31-H2S 2023-01-17 340 1-31-H2S 2010-12-30 400 1-33-H2S 2024-01-22 350 1-33-H2S 2010-10-19 400 1-35-H2S 2023-01-17 320 1-35-H2S 2012-03-22 325 1-37-H2S 2014-05-02 205 1-37-H2S 2014-05-02 205 1-39-H2S 2024-01-16 325 1-39-H2S 2012-06-04 500 1-45-H2S 2009-07-05 280 1-45-H2S 2009-06-27 400 1-47-H2S 2024-01-20 390 1-47-H2S 2004-12-12 400 1-49-H2S 2007-05-10 185 1-49-H2S 2007-04-05 200 1-55-H2S 2024-01-16 630 1-55-H2S 2007-02-14 1300 1-57-H2S 2024-01-16 295 1-57-H2S 2021-01-20 475 1-61-H2S 2024-01-16 410 1-61-H2S 2012-10-02 880 1-63-H2S 2024-01-16 400 1-63-H2S 2023-01-06 500 1-65-H2S 2024-01-16 340 1-65-H2S 2021-01-22 475 2-02-H2S 2012-04-07 120 2-02-H2S 2012-04-07 120 2-04-H2S 2024-01-16 330 2-04-H2S 2022-03-27 500 2-06-H2S 2014-07-08 500 2-06-H2S 2014-07-08 500 2-08-H2S 2024-01-16 575 2-08-H2S 2019-01-04 600 2-14-H2S 2023-01-09 210 2-14-H2S 2010-09-02 800 2-16-H2S 2024-01-16 80 2-16-H2S 2024-01-16 80 2-18-H2S 2024-01-16 300 2-18-H2S 2014-08-05 400 2-20-H2S 2024-01-16 290 2-20-H2S 2022-11-23 400 2-24-H2S 2010-02-04 270 2-24-H2S 2010-02-04 270 2-26-H2S 2019-04-14 300 2-26-H2S 2019-01-17 400 2-28-H2S 2024-01-16 395 2-28-H2S 2019-04-01 620 2-30-H2S 2014-07-03 250 2-30-H2S 2014-07-03 250 2-30B-H2S 2024-01-16 280 2-30B-H2S 2009-08-16 350 2-32-H2S 2024-01-16 300 2-32-H2S 2023-10-10 720 2-34-H2S 2012-06-08 400 2-34-H2S 2012-06-08 400 2-36-H2S 2024-01-16 400 2-36-H2S 2010-09-10 600 2-38-H2S 2024-01-16 425 2-38-H2S 2010-01-14 560 2-40-H2S 2023-01-17 300 2-40-H2S 2010-03-10 490 2-44-H2S 2024-01-16 310 2-44-H2S 2009-07-04 660 2-46-H2S 2024-01-16 380 2-46-H2S 2016-01-05 700 2-48-H2S 2024-02-14 500 2-48-H2S 2024-02-14 500 2-50-H2S 2014-02-20 180 2-50-H2S 2010-01-16 230 2-52-H2S 2024-01-19 430 2-52-H2S 2011-02-04 500 2-54-H2S 2010-07-07 170 2-54-H2S 2010-07-07 170 2-56-H2S 2024-01-16 325 2-56-H2S 2005-10-31 770 2-58-H2S 2022-01-09 300 2-58-H2S 2022-01-09 300 2-60-H2S 2023-01-06 500 2-60-H2S 2021-05-12 600 2-62-H2S 2024-01-29 320 2-62-H2S 2012-07-26 525 2-66-H2S 2020-01-08 260 2-66-H2S 2019-04-24 500 2-68-H2S 2024-01-19 220 2-68-H2S 2006-07-06 775 Most Recent Sample Highest Sample Page 63 AKI - Endicott MPI 2-74 Producer Drilling Procedure 27.0 Innovation Rig Layout Page 64 AKI - Endicott MPI 2-74 Producer Drilling Procedure 28.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 65 AKI - Endicott MPI 2-74 Producer Drilling Procedure 29.0 Innovation Rig Choke Manifold Schematic Page 66 AKI - Endicott MPI 2-74 Producer Drilling Procedure 30.0 Casing Design Page 67 AKI - Endicott MPI 2-74 Producer Drilling Procedure 31.0 MASP Page 68 AKI - Endicott MPI 2-74 Producer Drilling Procedure Page 69 AKI - Endicott MPI 2-74 Producer Drilling Procedure 32.0 Spider Plot (NAD 27) (Governmental Sections) Page 70 AKI - Endicott MPI 2-74 Producer Drilling Procedure 33.0 Surface Plat (As-Built) (NAD 27) 6WDQGDUG3URSRVDO5HSRUW 0DUFK 3ODQZS +LOFRUS$ODVND//& 'XFN,VODQG8QLW (QG03, 3ODQ -1000 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 Tr u e V e r t i c a l D e p t h ( 2 0 0 0 u s f t / i n ) 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 15000 Vertical Section at 284.97° (2000 usft/in) MPI 2-74 wp06 tgt01 MPI 2-74 wp02 tgt02 MPI 2-74 wp02 tgt03 MPI 2-74 wp02 tgt04 MPI 2-74 wp02 tgt05 MPI 2-74 wp02 tgt06 9 5/8" x 12 1/4" 7" x 8 1/2" 4 1/2" x 6 1/8" 5 00 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 6 0 0 0 6 5 0 0 7 0 0 0 7 5 0 0 8 0 0 0 8 5 0 0 9 0 0 0 9 5 0 0 1 0 0 0 0 1 0 5 0 0 1 1 0 0 0 1 1 5 0 0 1 2 0 0 0 1 2 5 0 0 1 3 0 0 0 1 3 5 0 0 1 4 0 0 0 14500 15000 15500 16000 16500 17000 17500 18000 18500 19000 19298 2-74 wp07 Start Dir 2º/100' : 250' MD, 250'TVD End Dir : 400' MD, 399.93' TVD Start Dir 3º/100' : 700.48' MD, 700'TVD End Dir : 2357.81' MD, 2122.56' TVD Start Dir 3º/100' : 14309.04' M D, 9400.29'TVD End Dir : 15192.72' M D, 9775.46' TV D Start Dir 3.5º/100' : 15342.72' M D, 9809.2'TV D End Dir : 15659.21' M D, 9850.29' TV D Start Dir 3.5º/100' : 16069.96' M D, 9864.2'TVD End Dir : 16310.32' M D, 9854.71' TVD Start Dir 2.5º/100' : 16653.53' M D, 9816.03'TV D End Dir : 17116.51' M D, 9808.74' TVD Start Dir 3º/100' : 17723.62' M D, 9858.2'TVD End Dir : 18001.96' M D, 9900.96' TVD Start Dir 3.5º/100' : 18244.19' M D, 9955.53'TV D End Dir : 18794.02' M D, 10072.78' TVD Total Depth : 19297.6' M D, 10172.08' TV D base perm sv5 sv4 sv3 sv2 sv1 UG-4 top west sak top seaebee top hue/tuffs BHRZ LWR-IVI MID-IVI MID-IVI MID-IVI LWR-IVI Hilcorp Alaska, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: Plan: 2-74 13.70 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 5982252.18 258812.12 70° 21' 7.6875 N 147° 57' 31.0184 W SURVEY PROGRAM Date: 2024-01-04T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 26.50 1100.00 2-74 wp07 (2-74) GYD_Quest GWD 1100.00 6072.00 2-74 wp07 (2-74) 3_MWD+IFR2+MS+Sag 6072.00 14657.00 2-74 wp07 (2-74) 3_MWD+IFR2+MS+Sag 14657.00 19297.60 2-74 wp07 (2-74) 3_MWD+IFR2+MS+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 1440.20 1400.00 1469.68 base perm 4230.20 4190.00 5818.90 sv5 4480.20 4440.00 6229.45 sv4 4729.20 4689.00 6638.34 sv3 4904.20 4864.00 6925.72 sv2 5354.20 5314.00 7664.70 sv1 5748.20 5708.00 8311.71 UG-4 6633.20 6593.00 9765.02 top west sak 7581.20 7541.00 11321.80 top seaebee 8810.20 8770.00 13340.02 top hue/tuffs 9518.20 9478.00 14516.30 BHRZ 9587.20 9547.00 14654.55 LWR-IVI 9806.20 9766.00 15329.38 MID-IVI 9878.20 9838.00 17885.48 MID-IVI 10018.20 9978.00 18528.99 LWR-IVI REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: 2-74, True North Vertical (TVD) Reference:2-74 as built rkb @ 40.20usft Measured Depth Reference:2-74 as built rkb @ 40.20usft Calculation Method:Minimum Curvature Project:Duck Island Unit Site:End MPI Well:Plan: 2-74 Wellbore:2-74 Design:2-74 wp07 CASING DETAILS TVD TVDSS MD Size Name 4384.00 4343.80 6071.47 9-5/8 9 5/8" x 12 1/4" 9588.35 9548.15 14657.00 7 7" x 8 1/2" 10172.08 10131.88 19297.60 4-1/2 4 1/2" x 6 1/8" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 26.50 0.00 0.00 26.50 0.00 0.00 0.00 0.00 0.00 2 250.00 0.00 0.00 250.00 0.00 0.00 0.00 0.00 0.00 Start Dir 2º/100' : 250' MD, 250'TVD 3 400.00 3.00 265.00 399.93 -0.34 -3.91 2.00 265.00 3.69 End Dir : 400' MD, 399.93' TVD 4 700.48 3.00 265.00 700.00 -1.71 -19.58 0.00 0.00 18.47 Start Dir 3º/100' : 700.48' MD, 700'TVD 5 2357.81 52.49 287.31 2122.56 203.10 -735.84 3.00 23.25 763.33 End Dir : 2357.81' MD, 2122.56' TVD 6 14309.04 52.49 287.31 9400.29 3023.72 -9786.28 0.00 0.00 10235.20 Start Dir 3º/100' : 14309.04' MD, 9400.29'TVD 7 15192.72 77.00 276.00 9775.46 3175.72 -10562.94 3.00 -25.35 11024.77 End Dir : 15192.72' MD, 9775.46' TVD 8 15342.72 77.00 276.00 9809.20 3191.00 -10708.30 0.00 0.00 11169.14 MPI 2-74 wp06 tgt01 Start Dir 3.5º/100' : 15342.72' MD, 9809.2'TVD 9 15659.21 88.06 276.65 9850.29 3225.53 -11019.71 3.50 3.37 11478.90 End Dir : 15659.21' MD, 9850.29' TVD 10 16069.96 88.06 276.65 9864.20 3273.05 -11427.46 0.00 0.00 11885.08 MPI 2-74 wp02 tgt02 Start Dir 3.5º/100' : 16069.96' MD, 9864.2'TVD 11 16310.32 96.47 276.75 9854.71 3301.02 -11665.78 3.50 0.67 12122.55 End Dir : 16310.32' MD, 9854.71' TVD 12 16653.53 96.47 276.75 9816.03 3341.08 -12004.44 0.00 0.00 12460.07 Start Dir 2.5º/100' : 16653.53' MD, 9816.03'TVD 13 16881.22 91.00 275.17 9801.20 3364.64 -12230.33 2.50 -163.91 12684.37 MPI 2-74 wp02 tgt03 14 17116.51 85.33 276.73 9808.74 3389.00 -12464.13 2.50 164.69 12916.53 End Dir : 17116.51' MD, 9808.74' TVD 15 17723.62 85.33 276.73 9858.20 3459.87 -13065.05 0.00 0.00 13515.37 MPI 2-74 wp02 tgt04 Start Dir 3º/100' : 17723.62' MD, 9858.2'TVD 16 18001.96 76.98 276.43 9900.96 3491.34 -13338.04 3.00 -177.99 13787.22 End Dir : 18001.96' MD, 9900.96' TVD 17 18244.19 76.98 276.43 9955.53 3517.76 -13572.56 0.00 0.00 14020.61 MPI 2-74 wp02 tgt05 Start Dir 3.5º/100' : 18244.19' MD, 9955.53'TVD 18 18794.02 78.63 296.05 10072.78 3667.50 -14085.70 3.50 87.24 14555.02 End Dir : 18794.02' MD, 10072.78' TVD 19 19297.60 78.63 296.05 10172.08 3884.30 -14529.25 0.00 0.00 15039.51 MPI 2-74 wp02 tgt06 Total Depth : 19297.6' MD, 10172.08' TVD -2400 -1600 -800 0 800 1600 2400 3200 4000 4800 5600 6400 7200 8000 So u t h ( - ) / N o r t h ( + ) ( 1 6 0 0 u s f t / i n ) -14400 -13600 -12800 -12000 -11200 -10400 -9600 -8800 -8000 -7200 -6400 -5600 -4800 -4000 -3200 -2400 -1600 -800 0 West(-)/East(+) (1600 usft/in) MPI 2-74 wp02 tgt06 MPI 2-74 wp02 tgt05 MPI 2-74 wp02 tgt04 MPI 2-74 wp02 tgt03 MPI 2-74 wp02 tgt02 MPI 2-74 wp06 tgt01 9 5/8" x 12 1/4" 7" x 8 1/2" 4 1/2" x 6 1/8" 500 1500 2000 225025002750 3000 3250 3500 375040004250450047505000 5250 5500 5750 6000625065006750 70007250 75007750 8000 8250 8500 8750 9000 9250 95009750 1000010172 2-74 wp07 Start Dir 2º/100' : 250' MD, 250'TVD End Dir : 400' MD, 399.93' TVD Start Dir 3º/100' : 700.48' MD, 700'TVD End Dir : 2357.81' MD, 2122.56' TVD Start Dir 3º/100' : 14309.04' MD, 9400.29'TVD Start Dir 3.5º/100' : 15342.72' MD, 9809.2'TVD End Dir : 15659.21' MD, 9850.29' TVD Start Dir 3.5º/100' : 16069.96' MD, 9864.2'TVD End Dir : 16310.32' MD, 9854.71' TVD Start Dir 2.5º/100' : 16653.53' MD, 9816.03'TVD End Dir : 17116.51' MD, 9808.74' TVD Start Dir 3º/100' : 17723.62' MD, 9858.2'TVD End Dir : 18001.96' MD, 9900.96' TVD Start Dir 3.5º/100' : 18244.19' MD, 9955.53'TVD End Dir : 18794.02' MD, 10072.78' TVD Total Depth : 19297.6' MD, 10172.08' TVD CASING DETAILS TVD TVDSS MD Size Name 4384.00 4343.80 6071.47 9-5/8 9 5/8" x 12 1/4" 9588.35 9548.15 14657.00 7 7" x 8 1/2" 10172.08 10131.88 19297.60 4-1/2 4 1/2" x 6 1/8" Project: Duck Island Unit Site: End MPI Well: Plan: 2-74 Wellbore: 2-74 Plan: 2-74 wp07 WELL DETAILS: Plan: 2-74 13.70 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 5982252.18 258812.12 70° 21' 7.6875 N 147° 57' 31.0184 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: 2-74, True North Vertical (TVD) Reference:2-74 as built rkb @ 40.20usft Measured Depth Reference:2-74 as built rkb @ 40.20usft Calculation Method:Minimum Curvature Endicott lease line 3URMHFW &RPSDQ\ /RFDO&RRUGLQDWH5HIHUHQFH 79'5HIHUHQFH 6LWH +LOFRUS$ODVND//& 'XFN,VODQG8QLW (QG03, 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2-56A PB1 2-56 2-56A 2-56A PB2 2-50 No-Go Zone - Stop Drilling Collision Avoidance Required Collision Risk Procedures Req. NOERRORS WELL DETAILS:Plan: 2-74 NAD 1927 (NADCON CONUS) Alaska Zone 03 13.70 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 5982252.18 258812.12 70° 21' 7.6875 N 147° 57' 31.0184 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: 2-74, True North Vertical (TVD) Reference: 2-74 as built rkb @ 40.20usft Measured Depth Reference:2-74 as built rkb @ 40.20usft Calculation Method: Minimum Curvature SURVEY PROGRAM Date: 2024-01-04T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 26.50 1100.00 2-74 wp07 (2-74) GYD_Quest GWD 1100.00 6072.00 2-74 wp07 (2-74) 3_MWD+IFR2+MS+Sag 6072.00 14657.00 2-74 wp07 (2-74) 3_MWD+IFR2+MS+Sag 14657.00 19297.60 2-74 wp07 (2-74) 3_MWD+IFR2+MS+Sag 0.00 30.00 60.00 90.00 120.00 150.00 180.00 Ce n t r e t o C e n t r e S e p a r a t i o n ( 6 0 . 0 0 u s f t / i n ) 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 15000 16000 17000 18000 19000 Measured Depth (2000 usft/in) 2-48 2-58 2-54 2-62 2-64 2-66 2-52 2-60 2-70 2-72 2-68 2-30A 2-56 2-50 2-46 GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference 26.50 To 19297.60 Project: Duck Island Unit Site: End MPI Well: Plan: 2-74 Wellbore: 2-74 Plan: 2-74 wp07 CASING DETAILS TVD TVDSS MD Size Name 4384.00 4343.80 6071.47 9-5/8 9 5/8" x 12 1/4" 9588.35 9548.15 14657.00 7 7" x 8 1/2" 10172.08 10131.88 19297.60 4-1/2 4 1/2" x 6 1/8" 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. 224-024 ENDICOTT Spacing exception granted by Conservation Order 813. DIU MPI 2-74 ENDICOTT, EIDER OIL WELL PERMIT CHECKLIST Company Hilcorp Alaska, LLC Well Name:DUCK IS UNIT MPI 2-74 Initial Class/Type DEV / 1-OIL GeoArea 890 Unit 10450 On/Off Shore On Program DEVField & Pool Well bore seg Annular DisposalPTD#:2240240 ENDICOTT, EIDER OIL - 220165 NA1 Permit fee attached Yes Surface Location lies within ADL0034633; Top Prod Int & TD lie within ADL0034634.2 Lease number appropriate Yes3 Unique well name and number Yes ENDICOTT, EIDER OIL - 220165 - governed by 449 & well governed by CO 8134 Well located in a defined pool No Spacing exception granted in CO 813.5 Well located proper distance from drilling unit boundary NA6 Well located proper distance from other wells Yes7 Sufficient acreage available in drilling unit Yes8 If deviated, is wellbore plat included NA9 Operator only affected party Yes10 Operator has appropriate bond in force No Spacing exception granted in CO 813.11 Permit can be issued without conservation order Yes12 Permit can be issued without administrative approval Yes13 Can permit be approved before 15-day wait NA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For serv NA15 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 driven to 180''18 Conductor string provided Yes 9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40# to 4384' TVD19 Surface casing protects all known USDWs Yes 9-5/8" fully cemented to surface. Two stage cement job through ported collar.20 CMT vol adequate to circulate on conductor & surf csg Yes 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 csg Yes22 CMT will cover all known productive horizons Yes 9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40 to 4834' TVD23 Casing designs adequate for C, T, B & permafrost Yes Innovation rig has adequate tankage and good trucking support24 Adequate tankage or reserve pit NA This is a grassroots well.25 If a re-drill, has a 10-403 for abandonment been approved Yes Halliburton collision scan shows 1 close approach in production hole with no HSE risk.26 Adequate wellbore separation proposed Yes 16" Diverter below BOPE27 If diverter required, does it meet regulations Yes All fluids overbalanced to expected pore pressure.28 Drilling fluid program schematic & equip list adequate Yes 1 annular, 3 ram stack tested to 3000 psi.29 BOPEs, do they meet regulation Yes 13-5/8" , 5000 psi stack tested to 3000 psi.30 BOPE press rating appropriate; test to (put psig in comments) Yes Innovation has 2-9/16" piper ball valves, 1 manual and 1 remote hydraulic choke.31 Choke manifold complies w/API RP-53 (May 84) Yes32 Work will occur without operation shutdown Yes Monitoring will be required.33 Is presence of H2S gas probable NA This well is a Oil Development well.34 Mechanical condition of wells within AOR verified (For service well only) No H2S is present in DIU wells.35 Permit can be issued w/o hydrogen sulfide measures Yes Slight overpressure expected in Ivishak (~8.9 ppg EMW). MPD will be utilized. Mud program appears sufficient36 Data presented on potential overpressure zones NA for anticipated pressures.37 Seismic analysis of shallow gas zones NA38 Seabed condition survey (if off-shore) NA39 Contact name/phone for weekly progress reports [exploratory only] Appr SFD Date 3/27/2024 Appr MGR Date 3/28/2024 Appr SFD Date 3/27/2024 Administration Engineering Geology Geologic Commissioner:Date:Engineering Commissioner:Date Public Commissioner Date JLC 4/12/2024