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Home My WebLink About223-004DATA SUBMITTAL COMPLIANCE REPORT API No.50-029-23742-00-00Well Name/No.PRUDHOE BAY UN ORIN L-233 Completion Status 1-OILCompletion Date 3/1/2023 Permit to Drill 2230040 Operator Hilcorp North Slope, LLC MD 14896 TVD 4258 Current Status 1-OIL 8/17/2023 UIC No Well Log Information: Digital Med/Frmt ReceivedStart Stop OH / CH Comments Log Media Run No Electr Dataset Number Name Interval List of Logs Obtained:EWR-M5, AGR, ABG, DGR, ADR MD & TVD NoNo YesMud Log Samples Directional Survey REQUIRED INFORMATION (from Master Well Data/Logs) DATA INFORMATION Log/ Data Type Log Scale DF 3/20/20237026 14858 Electronic Data Set, Filename: PBU L-233 ADR Quadrants All Curves.las 37562ED Digital Data DF 3/20/202398 14896 Electronic Data Set, Filename: PBU L-233 LWD Final.las 37562ED Digital Data DF 3/20/2023 Electronic File: PBU L-233 Geosteering EOW Log.emf 37562ED Digital Data DF 3/20/2023 Electronic File: PBU L-233 Geosteering EOW Log.pdf 37562ED Digital Data DF 3/20/2023 Electronic File: PBU L-233 Customer Survey.xlsx37562EDDigital Data DF 3/20/2023 Electronic File: PBU L-233 Geosteering End of Well Report.pdf 37562ED Digital Data DF 3/20/2023 Electronic File: PBU L-233 Post-Well Geosteering X-Section Summary.pdf 37562ED Digital Data DF 3/20/2023 Electronic File: PBU L-233 Geosteering EOW Log_High Res.tif 37562ED Digital Data DF 3/20/2023 Electronic File: PBU L-233 Geosteering EOW Log_Low Res.tif 37562ED Digital Data DF 3/20/2023 Electronic File: PBU L-233 LWD Final MD.cgm37562EDDigital Data DF 3/20/2023 Electronic File: PBU L-233 LWD Final TVD.cgm37562EDDigital Data DF 3/20/2023 Electronic File: L-233 definitive survey report.pdf37562EDDigital Data DF 3/20/2023 Electronic File: L-233 final surveys.xlsx37562EDDigital Data DF 3/20/2023 Electronic File: L-233_definitive survey.txt37562EDDigital Data DF 3/20/2023 Electronic File: L-233_GIS.txt37562EDDigital Data DF 3/20/2023 Electronic File: L-233_Plan.pdf37562EDDigital Data Thursday, August 17, 2023AOGCC Page 1 of 3 PBU L-233 LWD Final.las DATA SUBMITTAL COMPLIANCE REPORT API No.50-029-23742-00-00Well Name/No.PRUDHOE BAY UN ORIN L-233 Completion Status 1-OILCompletion Date 3/1/2023 Permit to Drill 2230040 Operator Hilcorp North Slope, LLC MD 14896 TVD 4258 Current Status 1-OIL 8/17/2023 UIC No Well Cores/Samples Information: ReceivedStart Stop Comments Total Boxes Sample Set NumberName Interval INFORMATION RECEIVED Completion Report Production Test Information Geologic Markers/Tops Y Y / NA Y Comments: Mud Logs, Image Files, Digital Data Composite Logs, Image, Data Files Cuttings Samples Y / NA Y Y / NA Directional / Inclination Data Mechanical Integrity Test Information Daily Operations Summary Y Y / NA Y Core Chips Core Photographs Laboratory Analyses Y / NA Y / NA Y / NA COMPLIANCE HISTORY Date CommentsDescription Completion Date:3/1/2023 Release Date: 1/24/2023 DF 3/20/2023 Electronic File: L-233_VSec.pdf37562EDDigital Data DF 3/20/2023 Electronic File: PBU L-233 LWD Final MD.emf37562EDDigital Data DF 3/20/2023 Electronic File: PBU L-233 LWD Final TVD.emf37562EDDigital Data DF 3/20/2023 Electronic File: PBU_L-233_ADR_Image.dlis37562EDDigital Data DF 3/20/2023 Electronic File: PBU_L-233_ADR_Image.ver37562EDDigital Data DF 3/20/2023 Electronic File: PBU L-233 LWD Final MD.pdf37562EDDigital Data DF 3/20/2023 Electronic File: PBU L-233 LWD Final TVD.pdf37562EDDigital Data DF 3/20/2023 Electronic File: PBU L-233 LWD Final MD.tif37562EDDigital Data DF 3/20/2023 Electronic File: PBU L-233 LWD Final TVD.tif37562EDDigital Data Thursday, August 17, 2023AOGCC Page 2 of 3 DATA SUBMITTAL COMPLIANCE REPORT API No.50-029-23742-00-00Well Name/No.PRUDHOE BAY UN ORIN L-233 Completion Status 1-OILCompletion Date 3/1/2023 Permit to Drill 2230040 Operator Hilcorp North Slope, LLC MD 14896 TVD 4258 Current Status 1-OIL 8/17/2023 UIC No Compliance Reviewed By:Date: Thursday, August 17, 2023AOGCC Page 3 of 3 M. Guhl 8/21/2023 PRUDHOE BAY FIELD / SCHRADER BLUFF OIL POOL, ORION DEV AREA 7" x 6-5/8" 553 1316 19 RBDMS JSB 032923 Completed 3/1/2023 JSB RECEIVED by James Brooks on 3/29/2023 at 10:10 AM GMGR02AUG2023MDG 3/31/2023 DSR-3/31/23 3.16.2023 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2023.03.16 16:00:19 -08'00' Monty M Myers CASING AND LEAK-OFF FRACTURE TESTS Well Name:PBW L-233 Date:2/20/2022 Csg Size/Wt/Grade:9.625" 40/47# L-80 Supervisor:Lott/ Amend Csg Setting Depth:7035 TMD 4368 TVD Mud Weight:9.2 ppg LOT / FIT Press =646 psi LOT / FIT =12.04 ppg Hole Depth =7065 md Fluid Pumped=1.2 Bbls Volume Back =0.8 bbls Estimated Pump Output:0.062 Barrels/Stroke LOT / FIT DATA CASING TEST DATA Enter Strokes Enter Pressure Enter Strokes Enter Pressure Here Here Here Here ->017 ->277 ->280 ->8182 ->4148 ->16 437 ->6214 ->24 629 ->8284 ->32 827 ->10 350 ->40 1022 ->12 417 ->48 1222 ->14 478 ->56 1432 ->16 532 ->64 1635 ->18 583 ->72 1838 ->20 628 ->80 2045 ->21 646 ->88 2460 -> ->90 2594 -> -> Enter Holding Enter Holding Enter Holding Enter Holding Time Here Pressure Here Time Here Pressure Here ->0646 ->02594 ->1574 ->12591 ->2530 ->22590 ->3512 ->32589 ->4492 ->42589 ->5481 ->52588 ->6469 ->10 2585 ->7462 ->15 2583 ->8455 ->20 2581 ->9448 ->25 2580 ->10 441 ->30 2579 -> -> -> -> -> -> 0 2 4 6 8 10 12 14 16 18 2021 2 8 16 24 32 40 48 56 64 72 80 88 90 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 0 102030405060708090100 Pr e s s u r e ( p s i ) Strokes (# of) LOT / FIT DATA CASING TEST DATA 646 574 530512492481469462455448441 259425912590258925892588 2585 2583 2581 2580 2579 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 0 5 10 15 20 25 30 Pr e s s u r e ( p s i ) Time (Minutes) LOT / FIT DATA CASING TEST DATA Activity Date Ops Summary 2/7/2023 Spot sub base over L-233, level and shim. Retract stompers and set in place with 500 psi. Spot cattle chute. Spot and set all remaining modules. Mobilize pusher camp to 'L' pad. Continue mobilizing auxiliary equipment. Cruz trucks released at 16:00. Rig up interconnects. Hook up steam, water and air. Connect generator power at 17:00. Work on rig acceptance checklist. Cont. with rig acceptance checklist. Install speed head and diverter 'T'. Pin wegiht buckets and geronimo line. Set and berm cuttings box. Spot break shack and envirovac. Re-assembly mud pump 2. Cont. working on rig acceptance checklist. C/O saver sub from 4" XT39 to 5" NC50. Change out bell guide, change grabber box dies to 5". Load pipe shed with 5" drill pipe. Change out stuffing box seals on mud pump #2. N/U diverter system. Install bridge crane on BOPE, disconnect chain binders. Remove MPD. Cont. working on rig acceptance checklist. 2/8/2023 N/U diverter system. Install bell nipple with spare air boots. Install knife valve and vent line. Torque dieverter stack and knife valve. Sim Ops weld up front kicker on pipe skate and chains in pits. Cont. installing stripper boxes on MP 2. Observe sub base settled due to subsidence. Loosen chains on stack. Pull back Mezz and catwalk chutes. Raise catwalk stairs, and loosen piping in interconnect. Jack up sub base and re-shim. Secure stack, tighten plumbing in mezz and extend chutes. SimOps: Finish welding crack on skate. Process pipe. Cont on rig acceptance check list. Obtain RKB's. Pump through both mud pumps, install short mouse hole. Process HWDP. Rig accepted at 19:30. Test diverter on 5" drill pipe, witnessed by AOGCC rep Austin McLeod. Knife open 6 seconds, annular close 9 seconds. Test gas alarms & PVT system. Accumulator drawdown: starting 3000 psi, after functioning 1900 psi. First 200 psi recharge 17 seconds, full 50 seconds. (6)N2 bottles 2308 psi average. Strap, pick up and rack back 54 stands of 5" drill pipe. Cont. to pick up and rack back total of 110 stands of 5" drill pipe, 9 stands HWDP/jars. Service rig: crown, blocks, RLA. check oil in rotary table and top drive. Bring BHA components to rig floor. Rig up tongs. Prep to pick up BHA. Daily disposal to PB G&I 0 bbls, total 0 bbls. Daily disposal to MP G&I 0 bbls, total 0 bbls. Daily water from Lake 2: 280 bbls, total 700 bbls. 2/9/2023 Complete pre-spud checklist. Shut drains to rig floor. Test airlines. Shut manuals on stack. Prep vac hose in pits for drag chain. Prime pumps through bleeder. Pre- spud meeting. M/U 12-1/4 Kymera bit to motor, XO and first stand HWDP. Flood stack and surface lines. PT surface lines to 3000 psi - good. RIH and tag at 105'. Spud well, drill down to 220' at 350 gpm, 320 psi, 30 rpms, 1500 ft-lbs. WOB 2-3K. CBU, backreaming first stand at 350 gpm, 320 psi, 30 rpms, 1500 ft-lbs. POOH to surface on elevators. Inspect bit - good. M/U remaining BHA: GWD collar, DM collar, EWR-M5 collar, TM collar. Measure RFO 174.45. Upload MWD. P/U (2) non-mag flex collars, 1 stand HWDP. Attempt to obtain a survey and noticed erratic pump pressure. Open fluid end of mud pump 1 and clear out gravel from pods 1, 2 &4. Drill 12-1/4" surface hole from 220' to 260' (total=40', AROP 20fph) at 400 gpm, 650 psi, ECD 9.0 ppg EMW with 8.7 ppg mud. P/U 56K, S/O 54K. Pump through bleeder and jetting flow line as needed, clear out drag chain. 100% sliding, KOP 220'. Dynamic losses 20 bph. Drill 12-1/4" surface hole from 260' to 471' (total=211', AROP 35fph) at 350-400 gpm, 630 psi, 40 rpms, 1400 ft-lbs, ECD 9.56 ppg EMW with 8.8 ppg mud. P/U 62K, S/O 58K ROTW 59K. Pump through bleeder and jetting flow line as needed, clear out drag chain. No losses. slide as needed for 3/100 build. Adjust flow rate/ROP to minimize clearing drag chain of gravel. Drill 12-1/4" surface hole from 471' to 909' (total=438', AROP 73 fph) at 425 gpm, 995 psi, 40 rpms, 2000 ft-lbs, ECD 9.5 ppg EMW with 8.8 ppg mud. WOB 5-10K. P/U 76K, S/O 73K ROTW 68K. Pump through bleeder, jet flow line as needed, clear out drag chain. No losses. slide as needed for 4/100 build. Daily disposal to PB G&I 266 bbls, total 266 bbls. Daily disposal to MP G&I 0 bbls, total 0 bbls. Daily water from Lake 2: 420 bbls, total 1120 bbls. Daily downhole losses 63 bbls, total 63 bbls. Distance to WP #5: 4.74', 4.2' Low, 2.21' Left. 2/10/2023 Drill 12-1/4" surface hole from 909' to 1,418' MD, 1,304 TVD (509', AROP 85 fph), 425 gpm, 1105 psi, 40 rpms, 5-6k Tq, ECD 10.1 ppg, MW 9.2 ppg, WOB 8-10K. P/U 82K, S/O 78K ROT 77K. Pump through bleeder, jet flow line as needed, Last Gyro @ 920'. No losses. slide as needed for 4/100 build. Drill 12-1/4" surface hole from 1,418' to 1,930' MD, (512', AROP 85 fph), 425 gpm, 1105 psi, 40 rpms, 5-6k Tq, ECD 10.1 ppg, MW 9.2 ppg, WOB 8-10K. P/U 82K, S/O 78K ROT 77K. Pump through bleeder, jet flow line as needed,. start tangent section at 1761'. Drill 12-1/4" surface hole from 1,930' to 2,406' MD, (476', AROP 79 fph), 450 gpm, 1230 psi, 80 rpms, 6k Tq, ECD 10.26 ppg, MW 9.4 ppg, WOB 6-10K. P/U 98K, S/O 72K ROT 83K. Pump through bleeder, jet flow line as needed. Maintenance slides as needed through tangent. Base of permafrost logged at 2147'. Observe gas hydrates at 2241' with max gas 3956u. Drill 12-1/4" surface hole from 2,406' to 2,989' MD, (583', AROP 97 fph), 350-450 gpm, 960-1260 psi, 80 rpms, 7k Tq, ECD 10.2 ppg, MW 9.5 ppg, WOB 4-9K. max gas 3312u. P/U 102K, S/O 76K ROT 84K. Pump through bleeder, jet flow line as needed. Maintenance slides as needed through tangent. Daily disposal to PB G&I 1083 bbls, total 1349 bbls. Daily disposal to MP G&I 114 bbls, total 114 bbls. Daily water from Lake 2: 840 bbls, total 1960 bbls. Daily downhole losses 0 bbls, total 63 bbls. Distance to WP #5: 3.99', 0.66' High, 3.94' Left. 2/11/2023 Drill 12-1/4" surface hole from 2,989' to 3,540' MD, (551', AROP 92 fph), 400-430 gpm, 1285 psi, 80 rpms, 8-9k Tq, ECD 10.4 ppg, MW 9.5 ppg, WOB 6-10K. max gas 4191u. P/U 118K, S/O 80K ROT 95K. Pump through bleeder, jet flow line as needed. Maintenance slides as needed through tangent. Drill 12-1/4" hole from 3,540' to 4068' MD (528', AROP 88 fph), 425 gpm, 1400 psi, 80 rpms, 9-12k Tq, ECD 10.32 ppg, MW 9.5 ppg, WOB 9-13K. max gas 4152u. P/U 124K, S/O 82K ROT 98K. Pump through bleeder, jet flow line as needed. Maintenance slides through tangent. Observe on shakers at 3963'. Drill 12-1/4" surface hole from 4,068' to 4,567' MD, (499', AROP 83 fph), 475 gpm, 1500 psi, 80 rpms, 10-12k Tq, ECD 10.29 ppg, MW 9.5 ppg, WOB 2-6K. max gas 3953u. P/U 138K, S/O 82K ROT 105K. Pump through bleeder, jet flow line as needed. Maintenance slides as needed through tangent. Drill 12-1/4" surface hole from 4,567' to 5,044' MD, (477', AROP 80 fph), 500 gpm, 1805 psi, 80 rpms, 12-15k Tq, ECD 10.35 ppg, MW 9.5 ppg, WOB 6-10K. max gas 2273u. P/U 140K, S/O 83K ROT 106K. Pump through bleeder, jet flow line as needed. Maintenance slides as needed through tangent. Daily disposal to PB G&I 912 bbls, total 2261 bbls. Daily disposal to MP G&I 171 bbls, total 285 bbls. Daily water from Lake 2: 1450 bbls, total 3410 bbls. Daily downhole losses 0 bbls, total 63 bbls. Distance to WP5: 2.05', 0.12' low, 2.04' right. 2/12/2023 Drill 12-1/4" surface hole from 5,044' to 5,362' MD, (318', AROP 71 fph), 500 gpm, 1905 psi, 80 rpms, 13-15k Tq, ECD 10.6 ppg, MW 9.5 ppg, WOB 10-14K. max gas 2273u. P/U 145K, S/O 84K ROT 107K. Pump through bleeder, jet flow line as needed. Maintenance slides as needed through tangent. Rack back stand and service rig. Grease blocks, RLA, link tilt, spinners while swapping out inverters on drawworks. Pump 220 gpm, 515 psi. Drill 12-1/4" surface hole from 5,362' to 5,424' MD, (62', AROP 62 fph), 500 gpm, 1875 psi, 80 rpms, 12-13k Tq, ECD 10.35 ppg, MW 9.5 ppg, WOB 6-10K. max gas 2273u. P/U 155K, S/O 87K ROT 107K. Pump through bleeder, jet flow line as needed. Start 4.5/100 build/turn at 5362'. Drill 12-1/4" surface hole from 5,424' to 5,828' MD, (404', AROP 67 fph), 475 gpm, 1730 psi, 80 rpms, 14-17k Tq, ECD 10.14 ppg, MW 9.5 ppg, WOB 3-6K. max gas 2882u. P/U 165K, S/O 86K ROT 119K. Pump through bleeder, jet flow line as needed. Slide for 4.5/100 build/turn. Drill 12-1/4" surface hole from 5,828' to 6,030' MD, (202', AROP 34 fph), 500 gpm, 1850 psi, 80 rpms, 16-18k Tq, ECD 10.07 ppg, MW 9.5 ppg, WOB 5-10K. max gas 2274u. P/U 167K, S/O 86K ROT 121K. Pump through bleeder, jet flow line as needed. Sliding ~70% for 4.5/100 build/turn. Decrease flow at 5828' due to oil blinding shakers, causing multiple motor stalls and slower ROP. Drill 12-1/4" surface hole from 6,030' to 6,376' MD, (346', AROP 58 fph), 550 gpm, 1975 psi, 80 rpms, 14-16k Tq, ECD 10.3 ppg, MW 9.5 ppg, WOB 6-12K. max gas 765u. P/U 175K, S/O 86K ROT 116K. Pump through bleeder, jet flow line as needed. Sliding ~70% for 4.5/100 build/turn. Daily disposal to PB G&I 1145 bbls, total 3406 bbls. Daily disposal to MP G&I 171 bbls, total 456 bbls. Daily water from Lake 2: 1160 bbls, total 4570 bbls. Daily downhole losses 0 bbls, total 63 bbls. Distance to WP5: 12.74', 12.21' High, 3.61' right. 50-029-23742-00-00API #: Well Name: Field: County/State: PBW L-233 Prudhoe Bay West Hilcorp Energy Company Composite Report , Alaska 2/9/2023Spud Date: 2/13/2023 Drill 12-1/4" surface hole from 6,376' to 6,675' MD, (299', AROP 49.8fph), 550 gpm, 2330 psi, 80 rpms, 14-15k Tq, ECD 10.5 ppg, MW 9.5 ppg, WOB 10-12K. max gas 3,569u. P/U 170K, S/O 83K ROT 116K. Pump through bleeder, jet flow line as needed. Sliding ~70% for 4.5/100 build/turn. Drill 12-1/4" surface hole from 6,675' to TD @ 7,045' MD, (370', AROP 92.5fph), 550 gpm, 2400 psi, 80 rpms, 14-20k Tq, ECD 10.47 ppg, MW 9.7 ppg, WOB 10-12K. max gas 3,569u. P/U 171K, S/O 81K ROT 115K. Pump through bleeder, jet flow line as needed. Sliding ~70% for 4.5/100 build/turn. Obtain final Survey. Rack back 1 stand. Pump hi vis Sweep (no increase 31 bbls late) and CBU x3 minumum racking back 1 stand every BTM Up. 550 gpm, 2000 psi, ECD 10.11 ppg, 80 rpms, 13Kft-lbs, max gas 3542u. P/U 172K, S/O 81K, ROT 115K. Monitor well, gas breaking out, but static. RIH on elevators from 6,823' to 7,045'. wash last 30'. BROOH from 7,045' to 5,702' at 550 gpm, 1950 psi, ECD 10.12, 80 rpms, 12-19Kft-lbs. P/U 178K, S/O 82K, ROT 120K. Pull 10-30 fpm as hole dictates. BROOH from 5,702' to 3,582' at 550 gpm, 1780 psi, ECD 10.2, 80 rpms, 10-12Kft-lbs. P/U 140K, S/O 73K, ROT 95K. Pull 25-30 fpm as hole dictates. At 3838' (top Ugnu UG4 @3825') observe erratic tq and partial pack-off. Cut flow rate to half and slack off entire stand. Stage pumps up and slow pulling. speed to 1-3fpm as hole dictates. Increase pulling spped to 10-15 fpm at 3705'. Daily disposal to PB G&I 850 bbls, total 4256 bbls. Daily disposal to MP G&I 0 bbls, total 456 bbls. Daily water from Lake 2: 870 bbls, total 5440 bbls. Daily downhole losses 0 bbls, total 63 bbls. Distance to WP5: 10.64', 9.8' low, 4.15' Right. 2/14/2023 BROOH from 3,582' to 1,110' at 500 gpm, 1120 psi, ECD 10.3, 80 rpms, 4-5Kft-lbs.MW 9.6, Dyn Loss @ 3-4 bph P/U 90K, S/O 65K, ROT 74K. Pull 25-30 fpm as hole dictates. CBU x1.5 @ 2071'. @ 1485' slow flow rate due to shakers running over. @ 1375' & 40 inc, slow RPM to 40. Max Gas 3785u. BROOH from 1,110' to 437' at 450 gpm, 930 psi, ECD 9.94, 40 rpms, 8-15Kft-lbs.MW 9.5, P/U 74K, S/O 69K, ROT 72K. Pull 25-30 fpm as hole dictates. Hole unload @ 850', sand, clay, wood at shakers. Attempt to pull on elevators @ 720', BROOH f/720 to 437'. POOH on elevators f/437' to 161'. Rack back 5" HWDP. B/D Top Drive. Pump through bleeder @ 13 bpm to clear flow line. L/D 2x flex collar, Plug in and Down load MWD. L/D remaining BHA. Bit grade 1-1-WT-A-E-I-TD PDC 1-1-CT-G-X-I-NO-TD. Clean and clear rig floor. PJSM Install 9.625" 250T side door elevators. P/U M/U 320T Volant CRT to top drive. P/U M/U 14.75 Star power tongs. Check all handling Equip W/ mandrel. Verify pipe count 189 joints, 60 ea solid body centralizers. Monitor well on TT, 3. bph seepage loss. PJSM M/U Shoe, slick and F.C jnt (BakerLoc) Pump through shoe track. Drop Bypass plug and check floats, good. P/U BFA (BakerLoc) Cont RIH 9.625" 40# L-80 TXP BTC Csg F/ 166' to 780' MD. Trq TXP 20,960 ft/lb. Fill every 5 jnts top off 10. Install centralizers as per tally. P/U 56k SLK 56k. Lost 2 bbl. PJSM Cont RIH 9.625" 40# L-80 TXP BTC Csg F/ 780' to 1,096' MD. F/ 1,096 to 1,113 MD started working string down W/ 20k. Break Circ and stage up to 6 bpm 80-110 psi. Worked string pulling 15k over and slack down 20k to maintain circulations. Seeing heavy sand/ wood at shakers. Max Gas 567u. At 984 MD 5.57 DLS, 1,047 MD 6.62 DLS & 1,111 MD 5.22 DLS. Cont washing down F/ 1,113 to 1,653 MD 6 bpm 90-145 psi cleaning up sand. Max Gas 647u. Run speed 10-25 ft/min as hole dictates. RIH on elevators F/ 1,653 to 1,861 MD. P/U 95k SLK 76k. Calc 29.5 bbls Actual 19.4 bbls Lost 10 bbls. Trq TXP 20,960 ft/lb. Fill every 5 jnts top off 10. Install centralizers as per tally. Daily disposal to PB G&I 684 bbls, total 4940 bbls. Daily disposal to MP G&I 144 bbls, total 570 bbls. Daily water from Lake 2: 580 bbls, total 6020 bbls. Daily downhole losses 102 bbls, total 165 bbls. 2/15/2023 Continue RIH 9.625" 40# L-80 TXP BTC Csg F/ 1,861' to 3,962' MD. Trq TXP 20,960 ft/lb. Fill every 5 jnts top off/break circulation every 10 jts, CBU every 1000', Install centralizers as per tally. CBU @ 2250' (Permafrost), CBU @ 3250'. P/U 181k SLK 86k. Max Gas 977, Lost 45 bbls. RIH 9.625" 40# L-80 TXP BTC Csg F/ 3,962' to 5,401' MD. Trq TXP 20,960 ft/lb. M/U ESCMTR between jts 114-115. RIH with 9 5/8 47# Vam-21 Csg, Trq t/31,550 ft/lbs, Fill every 5 jnts top off/break circulation every 10 jts, CBU every 1000', CBU @ 4,336', CBU 5,401'(End Tangent) 7 bpm/270 psi. P/U 185K, S/O 95K, Lost 30.8 bbls, Max Gas 655u. Cont RIH 9.625" 47# L-80 Vam 21 F/ 5,401' to 6,957' MD CBU at 6,301' MD stage pumps up to 7 bpm 290 psi. Wash down F/ 6,957' to 7,035' MD 6 bpm 285 psi. Max Gas 546u. Attempted to reciprocate prior to picking extra 9.625" Csg to tag bottom and appears collar snagging well head. Trq Vam 21 31,550 ft/. Filled every 5 top off 10. Run speed 20-30 ft/min. Installed total 66 centralizers and 20 jnts left in shed. P/U 274k SLK 109k. Calc 31.8 bbls Act -9.5 bbls Lost 41.3 bbs. Reciprocate F/ 7,035' to 7,018' MD 6 bpm 275 psi P/U 258k SLK 106k. Clean and clear 9.625" handling Equip F/ rig floor. Went to R/U black water line to ODS 4" ball valve on conductor and 4" valve broke off due to being frozen W/ ice plug. Was able to shut down and drain stack. Fix ice plug and replace 4" ball valve. Thaw out 4 ball valve on DS. Cont Reciprocate F/ 7,035' to 7,018' MD 7 bpm 280 psi P/U 276k SLK 85k. Condition Mud. Cont R/D Parker power tongs, elevators and bails. Install black water lines. Shut down, blow down top drive. R/U HP, 1502 and cement lines. Clean out dump valve in possum belly. Haul off excess mud from pits. Prep pits for cement job. Pump through bleed and clear flow line. Reciprocate F/ 7,035' to 7,015' MD. Pumping 7 bpm 492 psi P/U 280k SLK 87k. MW 9.65 ppg. Blow air through cement lines. PJSM, Wet lines w/ 5 bbls H2O (HES) and P/T low kick out 1169/ 3981 psi high. Pump 1st stage cement job as follows: 55 bbls 10 ppg Tuned spacer w/ 4# red dye & 5 ppb poly flake (1st 10 bbls) 3.9 bpm 226 psi. Release F/ Volant & drop bypass plug. HES pump Lead EconoCem Type I/II cmt 263 bbls (650 sx). 12 ppg, 2.347 yld, 4.3 bpm, ICP 362 psi FCP 292 psi. Tail HalCem Premium G cmt (Wet at 04:30) 82 bbls (400 sx) 15.8 ppg, 1.152 yld, 3.9 bpm, ICP 394 psi FCP 639 psi. Release F/ Volant & drop shutoff plug. Daily disposal to PB G&I 575 bbls, total 5515 bbls. Daily disposal to MP G&I 114 bbls, total 684 bbls. Daily water from Lake 2: 490 bbls, total 6510 bbls. Daily downhole losses 118 bbls, total 283 bbls. 2/16/2023 HES Pump 20 bbls FW, Rig disp w/ 318 bbls 9.5 ppg spud mud, 7.5 bpm, ICP 460 psi, FCP 510 psi @ 6 BPM, HES pump 80 bbls 9.4 ppg spacer, 4.7 bpm, 337 ICP, 631 FCP, Rig displace w/ 104.2 bbls Spud mud, 4.5 bpm, 700 ICP, Maintain 3 BPM to Bump with FCP 825. Bumped @ 522 bbls, 4 bbls over Calc 518 bbls. Hold 1300 psi (3 min). Bleed off psi, Check floats (good). Psi up, open stage tool 3 bpm, shift @ 2720 psi. CIP @ 07:45 hrs. Parked in tension 180k up. Lost 10 bbls during Displacement. CBU (2300 stks)x2 through Stage tool 4-5 BPM w/no Cmt back. stage up to 7 bpm/275 psi. @ 7200, 11,750, 12,000 Strokes, reduce rate to 2 bpm to clear flow line and stack of clabbered up mud. Dumped 130 bbls Spacer, 60 bbls Green Cmt, 678 contaminated mud. (868 bbls Total dumped). Continue to circulate and condition mud via stage tool (2308' MD) 5 bpm, 190 psi, 34% flow. Prep Pits for 2nd stage cement. PJSM Stage pumps up to 6 bpm 250 psi increase pumps to 8 bpm 453 psi every 0.5 hour for 5 min. Continue cleaning pits and surface Equip. Had to get into Pits 1 & 2 due to excessive clabber and cement. Round tripping SS & Vac trucks prepping for stage 2 cement job. Process 5" D.P. Clean cellar and. Prep for N/D. PJSM Cont Circ through ES 6 bpm 245 psi. cycling pumps 8 bpm every 0.5 hr. Cont cleaning pits and surface Equip. Prep for N/D. Blow through cement and H2O lines. Break out of Volant checking release. PJSM Pump 2nd stage cement job as follows: 53 bbls 10 ppg Tuned spacer w/ 4# red dye & 5 lb/bbl poly flake (1st 10 bbls) 4.5 bpm 178 psi. Lead ArcticCem Type I/II 387 bbls 10.7 ppg Lead cmt, 2.917 yld, (736 sx) 4 bpm, ICP 272/ FCP 251 psi. 180 bbls into cement saw poly flak at shaker. At 360 bbls. into cement saw 10.45 ppg spacer/cement at shakers. Pump Tail HalCem Premium G cement 56 bbls 15.8 ppg Tail cmt, 1.156 yld, (270 sx) 2 bpm, ICP 387/ FCP 122 psi. Release from CRT & drop closing plug. Displace w/ 20 bbls H2O (HES) 6.3 bpm 375 psi then turn over to rig. Rig disp 149.25 bbls. (Calc 169.96 bbls/ Actual 169.25 bbls) W/ 9.2 ppg spud mud, 6 bpm ICP 230 psi FCP 704 psi, reduce rate to 3 bpm 20 bbls away ICP 500 FCP 519 psi. ES Cementer shifted shut at 1,537 psi. Held 1,848 psi for 5 minutes, check plug - good. CIP 06:05 hrs. No losses. Dumped 339 bbls total: 60 bbls black. water & spacer, 279 bbls of green cement. Daily disposal to PB G&I 852 bbls, total 6367 bbls. Daily disposal to MP G&I 452 bbls, total 1136 bbls. Daily water from Lake 2: 1340 bbls, total 7850 bbls. Daily downhole losses 0 bbls, total 283 bbls. 2/17/2023 Flush stack and lines with Back water, flush Cmt line, Disconnect Knife Valve and function bagx3 flushing with black water. Blow down all surface equip, L/D Volant, R/D Cmt Equip. Off load fluid from pits, clean all surfae equip, Flush all pit surface Equip with black water. Start N/D Vent Lines, Install 9 5/8" Elevators and latch stump, Remove Black Water/Hole fill line, Pressure wash thick mud Cmt from diverter Tee, Loosen speed head from conductor, P/U Stack, Set E-Slips with 30K on slips. Remove 4" Conductor Valves. Set down Stack, break bolts on top of Diverter adapter & P/U Stack. Cut 9 5/8" Csg, L/D 29.30' cut jt. Set down stack, inflate air boots, send slips/elevators off rig floor. M/U Jonnie Wacker and jet stack @ 15 bpm/30 RPM. L/D Jonnie wacker and Jt. B/D Top Drive, grease upper IBOP. Pull bushings and Riser, Install Air boot protector. Remove Bell Nipple, Install studs on top of Annular. Hang RCD Head above cellar, P/U Stack and install RCD on top of Bag. Set back BOP on pedestal. Prep Casing Stub and install Wellhead. Test 3600 psi Good, Trq Slip loc connection and test to 3600 psi for 10 min. good. Install test plug in lower Wellhead Profile. SIMOPS Cont cleaning pits. PJSM Set DSA and BOP.Install chains and binders secure stack. Install choke and kill lines, accumulator hydraulics. Obtain RKB Ann 12.32', UPR 14.66' Blinds 18.37' LPR 19.98' ULDS 22.03' LLDS 22.32'. SIMOPS Cont cleaning pits, P/U split bushing and L/D master. P/U RCD riser. PJSM Break bolts and open UPR's. Change rams to 4.5" X 7" VBR's. Button up door. PJSM Break bolts and open LPR's. Change rams to 5" solid body. Button up door. PJSM Install drip pan and drain hoses. Flood lines and purge air for testing BOPE. Test RCD seal to 1,000 psi 5 min, good. Open clamp and remove RCD test plug. Install trip nipple and bushings. While flooding stack found O Ring seal for trip nipple leaking. Replace O Ring seal. PJSM P/U M/U 4.5" test jnt, 5" TIW, Dart & side entry. R/U HP test lines. Purge air from choke manifold. Perform shell test. Daily disposal to PB G&I 1578 bbls, total 7945 bbls. Daily disposal to MP G&I 0 bbls, total 1136 bbls. Daily water from Lake 2: 570 bbls, total 7420 bbls. Daily downhole losses 0 bbls, total 283 bbls. 2/18/2023 Perform Shell test. Perform BOPE test W/ 4.5", 5 & 7 to 250/3,000 PSI for 5 Min. (4.5" Test Jt: Bag, CMV 11, 12 ,13, 14 & 15, Mezz kill, Dart, UPR VBR's, CMV 7, 8, 9, & 10, TIW 5", HCR Kill, Man Kill, CMV 4, 5, 6. Blind Rams, CMV 1, 2, 3, ) (5" Test Jt: LPR 5'' Solid Body. Accumulator Test: Start 3000 psi, After close 1400 psi, 200 psi recharge 27 sec, Full recovery 105 sec. N2 Bottles 6@ 2316 psi. PJSM Cont testing BOPE/ Test 7" UPR's. Choke HCR (F/P Cycled) Manual Choke, CMV 1,2,3 (F/P Cycled & purge air) Lower IBOP, Manual Super Choke & Super Choke 2,000 psi, Blind Rams. C/O UPR IBOP (Rebuit) reuse LOW IBOP and installed new NC50 Saver Sub. Test UPR IBOP passed. Closing Time Ann 11, UPR 9, LPR 9, Choke & Kill HCR 1/1 sec. Tested 250/3000 psi for 5 min ea. Witnessed waived by AOGCC Rep Kam StJohn. Test W/ H2O. PJSM R/D test lines. INstall Trq ring on LOW IBOP and Saver Sub. Install alignment pin in back up wrench. Wire tie all bolts. SIMOPS Assist electrician trouble shoot Drawworks bypass pressure switch. Bypass switch until new switch gets here. PJSM R/D test cap on top drive. P/U 5" test jnt M/U running tool and pull test plug. Install Wear Ring (10 5/8" OD 9 1/16" ID 3.16' Lng) RILDS. L/D 5" Jnt. Blow down choke & kill lines. Blow down top drive to verify clear. Clean and clear rig floor. PJSM P/U M/U BHA 2 Cleanout. 8.5" XR+CPS Tricone RR (3X18, 1X16 jets, 0.9419 TFA) 6.75" 1.5 Motor TerraForce, 6 ea 5" 50# S-135 NC50 HWDP. 6.5" Hydra Jar and 11 ea 5" HWDP to 590.78' MD. PJSM Single in hole BHA 3 W/ 5" 19.5# S-135 NC50 D.P F/ 590' to x2,214' MD. Drift 3.125" OD. P/U 77k SLK 58k. Fill pipe and wash down F/ 2,214' to 2,277' MD 380 gpm 480 psi 40 rpm Trq 5-6k F/O 43% P/U 91k SLK 71k ROT 77k. Daily disposal to PB G&I 143 bbls, total 8088 bbls. Daily disposal to MP G&I 0 bbls, total 1136 bbls. Daily water from Lake 2: 275 bbls, total 8695 bbls. Daily downhole losses 0 bbls, Surface loss total 283 bbls. 2/19/2023 Wash and Ream down from 2,277', tag ESCMTR on depth @ 2308'. Drill ESCMTR/Plug 425 gpm, 606 psi, 40 rpm, 5-6 Trq, 3-5 wob. Pass through ESCMTR with and without pumps/rotary w/no issues. Wash and Ream to 2,397'. Blow down Top Drive. Continue to single in the hole picking up 5" DP from 2397' to 5706'. @ 5706' hang blocks. Cut and slip 18 wraps (113') Drill Line. Current Ton Miles 1511. Accum ton Miles 36,915. Left on Spool 1,143'. Check Drawworks Brakes. Tq Deadman clamp to 80 ft/lbs. Calibrate Blocks. SIMOPS: C/O damaged Hyd Hoses on pipe skate. Grease Top Drive and blocks. Inspect crown sheaves, perform crown and block sheave monthly EAM. Service Iron Roughneck. P/U 5" NC-50, 19.5# DP and single in hole from 5,708' to 5,994'. Drift size 3.125", P/U 182K, S/O 72K. RIH on Elevators from 5,994' to 6,758'. P/U 185K, S/O 70K. Fill pipe and wash down from 6,758' to 6,882', 350 gpm, 480 psi, 30 rpm, 15-17K Trq, P/U 185K, S/O 70K, Rot 112K. CBU prior to casing test while working pipe from 6,882' to 6,821'. 400 gpm, 860 psi, 30 rpm, 15-17 Trq, P/U 186K, S/O 70K, Rot 112K. PJSM AT 6,881' MD R/U test Euip. Break Circ down string and kill line purge air out of system. Close UPR's (4.5" X 7" VBR's). Flood choke manifold and purge air. Attempted to pressure test and replaced test pump sensator. Attempted multiple time's to pressure up again and appears pumps are at 65%. efficient comparing strokes to bbls pumps. Checked pump screen, clean. Opened MP 1 and found small rocks in Pod 1 suction valve. PJSM On MP 1 replaced Pod 1 & 2 Suction valve and seat. Pod 3 & 4 Discharge valve. Found sand in suction line and valves were etched from gravel. Started to disassemble MP 2,. PJSM Cont working on MP 2. Replaced Pod #1 suction and discharge valve & seats, Pod #2 Suction valve and seat. Pod #3 Discharge valve. Cleaned out suction lines and Pill Pit 1. PJSM Perform 9.625" Csg test to 2,594 psi after 30 min. pressure was 2,579 psi, good. Pumped 4.4 bbls bled 4.3 bbls all on chart. Used MP 1. PJSM R/D test Equip. Break down head pin and HP lines. Blow down top drive and all surface Equip. PJSM Wash down F/ 6,881' to 6,907' MD. Drill shoe track F/ 6,907' BFA (6,908' MD) and tag FC 6,950' MD on depth 450 gpm, 1,106 psi, 30 rpm, Trq 18-20k, WOB 3-5k F/O 33%. P/U 205K SLK 71k ROT 115k. Daily disposal to PB G&I 303 bbls, total 8391 bbls. Daily disposal to MP G&I 0 bbls, total 1136 bbls. Daily water from Lake 2: 260 bbls, total 8955 bbls. Daily downhole losses 0 bbls, Surface loss total 283 bbls. 2/20/2023 Cont drilling F/ 6,950' to 7,065' MD (4,368' TVD) drill FC (6,950') & Shoe (7,035') on depth. Drill 20' of new hole to 7,065' MD. Work string 3X Rot/Rec, 1X No pumps, no Rot. Displace on the fly. 450 gpm 1,123 psi 30 rpm Trq 18-20k WOB 3-5k P/U 205k SLK 71k ROT 115k. Displace Sud Mud to 9.2 ppg BaraDril N. Rot/Rec F/ 7,045' to 7,005' MD. Pump 40 bbl spacer chased W/ 9.2 ppg BaraDril N. Circ until 9.2 MW in/out. 450 gpm 755 psi 30 rpm Trq 15k F/O 37% P/U 173k SLK 76k ROT 110k. Monitor well 10 min, static. SPR's. PJSM At 7,008' MD M/U 5" TIW, 1502 head pin and HP test lines. Break Circ pumping through kill & choke lines. Close UPR's and flood choke manifold, purge air. Perform FIT W/ 9.2 ppg MW 12 EMW 636 psi for 10 min, good. All charted. Pumped 1.24 bbls bled 0.8 ppbs. PJSM Surface test GeoSpan as per DD. Pump 32 bbl 10.9 dry job. R/D test Equip. Blow down. Monitor well 10 min, static. POOH on elevators F/ 7,008' to 6,493' MD. P/U 194k SLK 77k. PJSM POOH on elevators F/ 6,493' to 590' MD. P/U 85k SLK 74k. PJSM L/D BHA. L/D 10 jnts 5" HWDP, rack back 4 stand HWDP/Jar. Drain mud motor. Break 8.5" TriCone and L/D motor. Bit grade 1-1-WT-A-E-I-NO-BHA. PJSM P/U 5" jnt and Johnny Whacker. Flush stack 15 bpm 30 rpm. L/D Johnny Whacker. Blow down. PJSM P/U M/U BHA 3 8.5" RSS. 8.5" TK66 PDC Bit (6X13 Jets 0.7777 TFA) 8.5" NRP, 7 5/8" Geo-Pilot 7600, 6.75" ADR, 8 3/8" ILS, 6.75" DGR, 6.75" PWD, 6.75" DM, 6.75" TM HOC, 8 3/8" Integal Blade, Down load MWD. Cont P/U 6.75" FS (Non ported/Plunger) 6.75" NMFC,6.75" FS (Non ported/Plunger) 6.75" NMFC). 4 jnts 5" HWDP, 6.5" Jar & 3 jnts 5" HWDP. 403.96'. PJSM Single in hole BHA 3 W/ 5" 19.5# S-135 NC50 D.P. F/ 403' to 2,501' MD. Drift 3.125" OD. P/U 83k SLK 62k,. PJSM Single in hole BHA 3 W/ 5" 19.5# S-135 NC50 D.P. F/ 2,501' to 2,946' MD. Drift 3.125" OD. P/U 83k SLK 62k, Break in GeoPilot. 400 gpm 715 psi RPM 5, 10, 30, 30, 40, 50, 60. Blow down. PJSM Cont RIH F/ derrick 5" D.P. F/ 2,946' to 6,940' MD. P/U 170k SLK 74k Fill pipe at 5,457' & 7,940' MD. PJSM INstall RCD bearing. Drain riser. Pull bushings and remove riser. Break stand, install stab cone and set bearing on stabbing stand. Lower cone through bearing. M/U stand to string. Pull bushing and lower to RCD. M/U grey clamp. Daily disposal to PB G&I 1180 bbls, total 9571 bbls. Daily disposal to MP G&I 0 bbls, total 1136 bbls. Daily water from Lake 2: 500 bbls, total 9455 bbls. Daily downhole losses 0 bbls, Surface loss total 283 bbls. 2/21/2023 Pump through MPD lines verify proper function of flow indicator and chokes. Test lines 250/ 1,250 psi, good. Blow down lines. Wash down F/ 6,940' to 7,065' MD. Drill 8.5" Production Hole F/ 7,065'' to 7,610' MD (4,367' TVD) Total 545, (AROP 99') 440 gpm/ MPD 436, 1,301 psi, 120 rpm, TRQ on 15-20k, TRQ off 14-16k, WOB 6-12k. ECD 10.46. Max Gas 1,825u. P/U 175k, SLK 60k, ROT 108k. MPD 100% open. Drill 8.5" Production Hole F/ 7,610' to 8,347' MD (4,364' TVD) Total 737' (AROP 123') 440 gpm/ MPD 435, 1,330 psi, 120 rpm, TRQ on 15-17k, TRQ off 13k, WOB 9-12k. ECD 10.5. Max Gas 1,930u. P/U 152k, SLK 77k, ROT 110k. MPD 100% open. Drilled out top at 7,816' and back in at 7,940' MD (124'). Drill 8.5" Production Hole F/ 8,347' to 9,114' MD (4,352' TVD) Total 767' (AROP 128') 500 gpm/ MPD 495, 1,590 psi on/ off 1,530, 120 rpm, TRQ on 16-18k, TRQ off 13-15k, WOB 8-12k. ECD 10.6. Max Gas 1,872u. P/U 152k, SLK 77k, ROT 110k. MPD 100% open. Back ream 60'. Drill 8.5" Production Hole F/ 9,114' to 9,744' MD (4,344' TVD) Total 630' (AROP 105') 500 gpm/ MPD 494, 1,813 psi on/ off 1,730, 120 rpm, TRQ on 16-18k, TRQ off 15-16k, WOB 8-12k. ECD 10.10.82. Max Gas 2,496u. P/U 158k, SLK 70k, ROT 103k. MPD 100% open. Back ream 60'. Distance to WP05: 33.68', 34.48' Low 3.71' Left undulating as per Geo in OBd sand. 40 concretions drilled, total footage of 161 (6.1% lateral). Footage in OBd=2,501. Out of zone: 124. Total footage: 2,625. Daily disposal to PB G&I 518 bbls, total 10089 bbls. Daily disposal to MP G&I 0 bbls, total 1136 bbls. Daily water from Lake 2: 780 bbls, total 10235 bbls. Daily Metal 7lb total 7lb. Daily downhole losses 0 bbls, Surface loss total 283 bbls. 2/22/2023 Drill 8.5" Production Hole F/ 9,744' to 10,513' MD (4,321' TVD) Total 769' (AROP 128') 500 gpm/ MPD 494, 1,905 psi on/ off 1,856, 120 rpm, TRQ on 17-19k, TRQ off 14-16k, WOB 8-12k. ECD 11.01. Max Gas 2299u. P/U 158k, SLK 65k, ROT 106k. MPD 100% open. Back ream 60'. Drill 8.5" Production Hole F/ 9,513' to 11,266' MD (4,296' TVD) Total 753' (AROP 125.5') 500 gpm/ MPD 494, 2,000 psi on/ off 1,980, 120 rpm, TRQ on 17-18k, TRQ off 14-16k, WOB 6-8k. ECD 11.19. Max Gas 1908u. P/U 142k, SLK 66k, ROT 100k. MPD 100% open. Back ream 60'. At 10,900' MD Dumped and diluted 290 bbls to control MBT. Drill 8.5" Production Hole F/ 11,266' to 11,881' MD (4,280' TVD) Total 615' (AROP 102.5') 500 gpm/ MPD 487, 2,080 psi on/ off 2,040, 120 rpm, TRQ on 15-18k, TRQ off 14-16k, WOB 9-14k. ECD 11.25. Max Gas 2079u. P/U 146k, SLK 57k, ROT 100k. MPD 100% open. Back ream 60'. At 11,.594' MD CBU 2X over 2 stands to control ECD's. Drill 8.5" Production Hole F/ 11,881' to 12,579' MD (4,271' TVD) Total 698' (AROP 116') 500 gpm/ MPD 486, 2,192 psi on/ off 2,154, 120 rpm, TRQ on 15-19k, TRQ off 15k, WOB 9-12k. ECD 11.59. Max Gas 1963u. P/U 152k, SLK 56k, ROT 98k. MPD 100% open. Back ream 60'. Distance to WP05: 31.09', 29.62' Low 9.44' Right undulating as per Geo in OBb sand. 60 concretions drilled, total footage of 245 (4.5% lateral). Footage in OBb=5,324'. Out of zone: 124'. Total footage: 5,448'. Daily disposal to PB G&I 1259 bbls, total 11348 bbls. Daily disposal to MP G&I 0 bbls, total 1136 bbls. Daily water from Lake 2: 1080 bbls, total 11315 bbls. Daily Metal 4lb total 11lb. Daily downhole losses 0 bbls, Surface loss total 283 bbls. 2/23/2023 Drill 8.5" Production Hole F/ 12,579' to 13,120' MD (4,261' TVD) Total 541' (AROP 90') 500 gpm/ MPD 486, 2,270 psi on/ off 2,202, 120 rpm, TRQ on 16-20k, TRQ off 13-15k, WOB 5-13k. ECD 11.7. Max Gas 1078u. P/U 150k, SLK 67k, ROT 96k. MPD 100% open. Back ream 60'. At 12,795' MD performed clean up cycle CBU 2X over 2 stands due to ECD's. Close approach L-200 at 12,667' MD CC 30.95' CF 0.18. Drill 8.5" Production Hole F/ 13,120' to 13,882' MD (4,255' TVD) Total 762' (AROP 127') 500 gpm/ MPD 485, 2,240 psi on/ off 2,200, 120 rpm, TRQ on 15-17k, TRQ off 14-16k, WOB 4-14k. ECD 11.37. Max Gas 1736u. P/U 151k, SLK 57k, ROT 96k. MPD 100% open. Back ream 60'. At 13,247' MD cump and diluted 290 bbls 9.2 ppg BaraDril N due to ECD's. ECD's came down F/ 11.8 to 11.37. Close approach L-207 at 13,558' MD CC 43.07'.95' CF 0.28 with good separation. Drill 8.5" Production Hole F/ 13,882' to 14,453' MD (4,261' TVD) Total 571' (AROP 95') 450 gpm/ MPD 431, 2,020 psi on/ off 1,950, 120 rpm, TRQ on 16-18k, TRQ off 15-17k, WOB 4-8k. ECD 11.54. Max Gas 1743u. P/U 149k, SLK 43k, ROT 97k. MPD 100% open. Back ream 60'. At 14,150' MD reduced flow rate F/ 500 to 450 gpm and control drill 150 ft/hr due to ECD's climbing to 11.83. Drill 8.5" Production Hole F/ 14,453' to 14,768' MD (4,260' TVD) Total 315' (AROP 105') 450 gpm/ MPD 436, 2,045 psi on/ off 1,996, 120 rpm, TRQ on 16-18k, TRQ off 15-17k, WOB 5-8k. ECD 11.5. Max Gas 861u. P/U 148k, SLK 49k, ROT 96k. MPD 100% open. Back ream 60'. Phase 2 weather conditions called at 01:09. Phase 3 was called at 02:50. Wait on weather. Rot & Rec F/ 14,768' to 14,705' MD. 425 gpm/ MPD 425, 1,800 psi, 120 rpm, TRQ 17-18k, ECD 11.31. Max Gas 220u. P/U 148k, SLK 49k, ROT 96k. SPR. 3-5 bph dynamic losses. Phase 2 operations called at 04:40. Cont Drill 8.5" Production Hole F/ 14,768' to 14,866' MD (4,258' TVD) Total 98' (AROP 65.3') 450 gpm/ MPD 434, 2,043 psi on/ off 2,000, 120 rpm, TRQ on 18-20k, TRQ off 15-17k, WOB 5-8k. ECD 11.5. Max Gas 58u. P/U 156k, SLK 42k, ROT 99k. MPD 100% open. Back ream 6. Distance to WP05: 10.30', 8.73' Low 5.5' Right undulating as per Geo in OBb sand. 75 concretions drilled, total footage of 274' (3.5% lateral). Footage in OBb= 7,615'. Out of zone: 124'. Total footage: 7,739'. Daily disposal to PB G&I 1186 bbls, total 12534 bbls. Daily disposal to MP G&I 0 bbls, total 1136 bbls. Daily water from Lake 2: 1136 bbls, total 12435 bbls. Daily Metal 3lb total 14lb. Daily downhole losses 0 bbls, Surface loss total 283 bbls. 2/24/2023 Drill 8.5" Production Hole F/ 14,863 to 14,895' MD (4,257' TVD) Total 32' (AROP 124') 450 gpm/ MPD 436, 2,105 psi on/ off 2053, 120 rpm, TRQ on 18-20k, TRQ off 15-17k, WOB 5-8k. ECD 11.68. Max Gas 810u. P/U 152k, SLK 47k, ROT 97k. MPD 100% open. Back ream 60'. Pump tandem sweeps at TD. Lo-vis 38 8.6ppg 40bbls/ Hi-vis 300+ 9.7ppg 45bbls. Sweeps back on time with 20% increase in cuttings. Rack back F/14895 T/14636' over 4x BU. 450GPM/MPD432, 2058psi, 120rpm, TRQ 18-19k P/U 150k SLK 48k ROT 99k. Ream to bottom F/14636' T/14895 450GPM/MPD432, 2050 psi, 120 rpm, TRQ 16-18k P/U 150k SLK NAk ROT 99K. PJSM, DISP to completion fluid. Rotate/Reciprocate while pumping SAPP train and displace well to 9.5PPG Quick-drill. 40bbl SAPP pill, 20bbl 9.5PPG Quick-drill, 40bbl SAPP pill then displace to 9.5PPG Quick-drill. 450 GPM/ MPD 430, 1880psi, 120 RPM, TRQ 18-20k, 5200 strks pumped (322bbls). Cont to displace to 9.5PPG Quick-drill. SAPP train came back on strks. 450 GPM/ MPD 430, 1425psi, 120 RPM, TRQ 18-20k, P/U-159K S/O-NA ROT-97K ECD's- 10.6PPG. Monitor well- static. Drop steel drift (2.39" OD, 20.25" long). BROOH f/14895' t/13056' at 25-35'/min 450 GPM/ MPD 400, 1475psi 120 RPM, TRQ 21k, ECD 10.7 MW IN/OUT 9.5/9.5 P/U 177k, SLK NA, ROT 96k. MPD 100% open. BROOH f/13056' t/9750' at 25-35'/min 450 GPM/ MPD 420, 1350psi 120 RPM, TRQ 16k, ECD 10.4 MW IN/OUT 9.5/9.5 P/U 158k, SLK 70, ROT 104k. MPD 100% open. F/12738' T/12674' observed 200psi pack offs. Slowed pull speed. Worked back through with no issue. BROOH f/9750' t/7311' at 25-40'/min 450 GPM/ MPD 420, 1350psi 120 RPM, TRQ 16k, ECD 10.4 MW IN/OUT 9.5/9.5 P/U 158k, SLK 70, ROT 104k. MPD 100% open. Distance to WP05: 11.14', 5.18' low 9.87' right. 75 concretions drilled, for a total footage of 274 (3.5%). Footage in OBb sand: 7615'. Out of Zone 124'. Total drilled 7739'. Daily disp to PB G&I 0 bbls, total 12534 bbls. Daily disp to MP G&I 2097 bbls, total 3233 bbls. Daily H2O Lake 560 bbls, total 12995 bbls. 2/25/2023 BROOH f/7311' t/7035' at 25-40'/min 450 GPM/ MPD 420, 1350psi 120 RPM, TRQ 16k, ECD 10.4 MW IN/OUT 9.5/9.5 P/U 158k, SLK 70, ROT 104k. MPD 100% open. Pump 30bbl of 9.5ppg Hi-Vis sweep. Sweep came back on time with 30% increase in cuttings. ROT/REC and CBU x2. 450 GPM/ MPD 434, 1209psi 60 RPM, TRQ 11-12k, P/U 160k, SLK 85, ROT 108k. MPD 100% open. Monitor well static. Pump 35bbl of 10.2ppg corrosion inhibited dryjob. Blow down TD and geospan. Drain stack, pull bushings, bowl saver and RCD bearing. Strip bearing off of jnt. Install trip riser and extra air boot. Flood stack and check for leaks. Blow down Beyond equipment. L/D 5" DP F/7007' t/4483'. P/U 133k, SLK 89k. Culling pipe for CAT 5 inspection as per tally. Inspecting hard bands in pipe shed. 19.6bbls over calc disp. L/D 5" DP F4483' T/403' P/U 56k. SLK 55k. Calc disp 36bbl, Act disp 45bbls. L/D directional BHA #3 as per Sperry reps. L/D 3jnts of HWDP, Jars and 4jnts of HWDP. L/D flex collars, drift recovered on top of the float sub. P/U and read MWD. Finish L/D BHA. Bit graded: 2-2-CT-A-X-I-WT-TD. Clean and clear rig floor of thread protectors, bit, and bit breaker. Rinse floor, put tongs away and take hydraulic elevators off. P/U and R/U Parker wellbore 6.625" handling equipment and tongs. M/U 5" saftey joint with 6.625" 563 x 4.5"IF XO on bottom and FOSV on top. Grease and inspect crown sheaves, block sheaves, TD, FH-80 and overhead spinners. Inspect derrick. Change out worn TD cradle padles. RIH w/ 6.625" 24# L-80 563 Wedge slotted liner F/Surface T/2415'. P/U 65k, SLK 60k. Calc disp 14bbls, Act 11bbls 3bbls lost. RIH w/ 6.625" L-80 563 Wedge slotted liner F/2415' T/8495'. P/U 7" 26# L-80 Wedge 563 jnt with XO to 6.625" wedge and 6.625" 24# L-80 pup jnt. Cont RIH w/ 7" 26# L-80 Wedge 563 T/9029'. P/U 132k, S/O 73k. Daily disp to PB G&I 115 bbls, total 12649 bbls. Daily disp to MP G&I 0 bbls, total 3233 bbls. Daily H2O Lake 0 bbls, total 12995 bbls. Daily Metal 4lb total 20lb. Daily downhole losses 29 bbls, Surface loss total 283 bbls. 2/26/2023 M/U 7"x 9-5/8" SLZXP Liner top packer. HST 6 ea 1/2" screws 1800psi, Neutralizer 10ea 1/2" screws 2710psi, shear screws 7ea set at 34,300lbs. RIH 1 stnd pump 3bpm 164psi. B/D TD and R/D Parker casing tongs. Swap elevators. Complete running and confirm w/ Baker. P/U 5" HWDP out of pipe shed. 26 jnts total. Drift on skate w/2.75" rabbit. P/U 172k, SLK 85K. TIH on elevators w/ 5" DP from the derrick F/9902' MD T/ 13876' MD. P/U 195k, SLK 58k. Calculated disp observed. 40- 50'/min running speed. Cont TIH on elevators w/ 5"DP from derrick F/13876'MD T/14894'MD. P/U 210k, SLK 56k. Calculated disp observed. 40-50'/min running speed. P/U working single and tag bottom w/10k on depth at 14895'. Dropped 1 1/8" phenolic ball 1160stks 2027psi set hanger/packer slack off ensure set. Cont to pressure up to 2794psi and release running tool. P/U to neutral weight ensure free. P/U 154k. R/U and test SLZXP packer top to 1500psi for 10min- test good. Pumped 2.3bbl bled back 2.1. Pressure up to 3850psi with test pump and shear ball seat. Release from liner. P/U 154k. R/D test equipment, get thread protectors to rig floor, install stripping rubbers. Pump 27bbl10.5ppg dry job. B/D TD and kill. Prep for L/D DP. Grease TD, inspect craddle, grease blocks, check oil level, steam/clean elevators, inspect air slips, inspect and service FH-80. POOH L/D 5" DP to pipe shed F/5844' t/839' P/U 149K SLK NA. Culling pipe for CAT 5 inspection. Inspecting hard bands in pipe shed. Calc disp observed. F/809' T/ Surface-L/D 26 jnts of 5" HWDP. Pull stripping rubbers and L/D Baker liner top packer running tool. Activity Date Ops Summary 2/26/2023 RIH w/ 5" DP from derrick F/ surface T/2523'MD. P/U 60k, SLK 60k. Calculated disp obeserved. RIH w/ 5" DP from derrick F/ 2523'MD T/3365'MD. P/U 78k, SLK 75k. Calculated disp obeserved. Cut and slip 12 wraps, 75' of drill line. 1068' of drill line left on spool. L/D 5" DP to pipe shed F/3365' T/Surface culling pipe for CAT 5 inspection per tally. Inspecting hard bands in pipe shed. Clean and clear rig floor. R/U Parker TRS 7" tongs and casing handling equipment on rig floor. 2/27/2023 Finish R/U 7" handling equipment. Inspect bullet seal assembly. RIH w/ 7" 29# L-80 VamTop F/ Surface T/ 4545'. Tq Connections to 9.4k. P/U 124k, SLK 96k. Calc disp 39bbls, Act disp 31bbls, 8 bbls lost. Cont RIH /7" 29# L-80 VamTop F/4545' T/5484' landed out on NO-GO. Tq Connections to 9.4k. P/U 150k, SLK 108k. Calc disp 57.6bbls, Act disp 44.3bbls, 13.3 bbls lost. Perform spaceout. P/U jnts 135 and 136 tag No-Go at 5848'MD. L/D 3 jnts M/U 5.86' and 9.87' pup. M/U pups on bttm of jnt134. M/U hanger, land out at 5847'MD 1.22' off No-Go, 72k on hanger. R/U XO and head pin to reverse circulate. Pressure up to 200psi and P/U exposing seal assembly circ ports. Reverse circ 92bbl of CI brine 3bbl min @ 110psi. Swap to LRS and pump 68bbls of 60 diesel @ 3bbl min -ICP=150psi, FCP=380psi. Land hanger on depth. Simops- L/D Parker Casing tongs, stage csg tongs for 4.5" tubing. P/U XO for tubing run. Blow down R/D circ equipment. L/D landing jnt, swap out elevators and P/U 5" jnt of HWDP M/U pack off running tool and run in pack off. RILDS as per Vault rep. R/U and PT void 500psi low 3000 psi high 10 minutes. Test good. L/D pack off running tool and 5" jnt of HWDP. R/U and test 9.625" x 7" annulus to 1500psi fort 30minutes. Initial pressure 1625psi, 15 minute 1595psi, final 1587psi. Pumped 1.5bbl, bled back 1.5bbl . Test Good. R/D test equipment. P/U and R/U 4.5" handling equipment, slips, elevators, and power tongs. M/U 4.5" JFE XO on 5" TIW. Simops- Clean connections to be baker locked, put completion jewlery in order. Set up 3rd party torq turn equipment. RIH as per 4.5" tally with 4.5" 12.6# L-80 VamTop tubing to 167'. Tq connections to 4440 ft/lbs verified by JAM system. P/U 40k, SLK 39k,Cont RIH as per 4.5" tally with 4.5" 12.6# L-80 VamTop tubing F/167' T/ 360'. Crossover to 4.5" JFEBear on top of GLM #1. Cont RIH F/360' T/2680' as per tally with 4.5" 12.6# L-80 JFEBear tubing. P/U 58k , SLK 53k,Daily disp to PB G&I 548 bbls, total 13197 bbls. Daily disp to MP G&I 0 bbls, total 3233 bbls. Daily H2O Lake 100 bbls, total 13095 bbls. Daily Metal 0lb total 20lb. Daily downhole losses 19.3 bbls, Surface loss total 283 bbls. Total DH Losses 464. 2/28/2023 Cont RIH as per 4.5" tally with 4.5" 12.6# L-80, JFE Bear tubing from 2707' to 6120'. Tq turn tubing to 5940 ft-lbs. P/U 82K, S/O 66K. Calc disp 29 bbls, actual 9 bbls. M/U hanger and landing joint. drain stack and land tubing on depth. RILDS. Break out landing joint. Rig up and reverse circulate in 125 bbls of 9.5 ppg corrosion inhibited brine, staging up to 4 bpm, 373 psi. M/U landing joint. Drop ball and rod. Fill lines, purge air from system. Rig up to set packer and MIT- T/IA,Pressure up to 3500 psi to set packer. MIT-T to 3500 psi, bleed tubing to 2000 psi, MIT-IA to 3500 psi. Bleed tubing and shear out GLM. Total fluid pumped 3.0 bbls, bled back 2.9 bbls. Verify communication through GLM. Set BPV. Flush stack and surface lines, blow down same. Clean and clear rig floor of handling equipment. Work on mud pump inspection, clean pits. Remove drip pan on stack. Hook up bridge crane to BOP stack. Remove MPD hardlines, bushings and trip nipple. Daily disp to PB G&I 0 bbls, total 13197 bbls. Daily disp to MP G&I 0 bbls, total 3233 bbls. Daily H2O Lake 140 bbls, total 13235 bbls. Daily Metal 0lb total 20lb. Daily downhole losses 20 bbls, Surface loss total 283 bbls. Total DH Losses 484. 3/1/2023 Unchain stack, bleed down accumulator and disconnect lines. N/D BOPE and rack back. Secure stack. Remove DSA. Clean ring grooves. Install tubing head adapter and dry hole trea. PT tubing head void 500/5000 10min each - good. PT tree to 500/5000 psi - good. Rig down testing equipment. RDMO 06:00. 50-029-23742-00-00API #: Well Name: Field: County/State: PBW L-233 Prudhoe Bay West Hilcorp Energy Company Composite Report , Alaska Rig up to set packer and MIT- T/IA,Pressure up to 3500 psi to set packer. MIT-T to 3500 psi, bleed tubing to 2000 psi, MIT-IA to 3500 psi. test 9.625" x 7" annulus to 1500psi fort 30minutes. Initial pressure 1625psi, 15 minute 1595psi, final 1587psi. Pumped 1.5bbl, bled back 1.5bbl . Test Good. TD Shoe Depth: PBTD: No. Jts. Returned RKB RKB to BHF RKB to THF Jts. 109 55 Yes X No X Yes No 4.4 Fluid Description: Liner hanger Info (Make/Model): Liner top Packer?: Yes No Liner hanger test pressure:X Yes No Centralizer Placement: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp:X Yes No Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp:X Yes No Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped: Cmt returned to surface: Calculated cement left in wellbore: OH volume Calculated: OH volume actual: Actual % Washout: 1.16 2/17/2023 Surface H2O/ Spud Mud EconoCem Type I/II 650 2.35 HelCem Premium G 400 1.15 4.3 2,290.61 X/O TXP X VAM 9 5/8 47.0 L-80 VAM Tenaris 40.44 2,290.61 2,250.17 2,310.99 2,308.17 Pup 9 5/8 47.0 L-80 TCP BTC Tenaris 17.56 2,308.17 17.75 2,328.74 2,310.99 ES Cementer 11 3/4 TCP BTC Halliburton 2.82 Pup 9 5/8 40.0 L-80 TCP BTC Tenaris 6,908.40 9.625 CSG 9 5/8 40.0 L-80 TCP BTC Tenaris 4,579.66 6,908.40 2,328.74 6,950.62 6,909.80 Baffle Adapter 10 3/4 TCP BTC Halliburton 1.40 6,909.80 1.39 6,952.01 6,950.62 9.625 CSG 9 5/8 40.0 L-80 TCP BTC Tenaris 40.82 Float Collar 10 3/4 TCP BTC Innovex 2 ea SB & 4 ea SR on shoe jnt, 1 ea SB on Blank Jnt and 1 SB & 2 SR FC jnt. 1 ea SB to jnt 25. Every other Jnt to Jnt 49. 5 ea SB before ES, 1 ea SB & 1 ea SR on ES Pups, 5 ea SB after ES. Every third jnt F/ jnt 132 to jnt 174. Total 8 stop rings and 66 Solid Body Centralizers. 9.625 CSG 9 5/8 40.0 L-80 TCP BTC Tenaris 81.22 7,033.23 6,952.01 www.wellez.net WellEz Information Management LLC ver_04818br 3.9 Ftg. Returned 714.00 Ftg. Cut Jt.29.30 Ftg. Balance No. Jts. Delivered 189 No. Jts. Run 169 20 Length Measurements W/O Threads Ftg. Delivered 7,749.00 Ftg. Run 7,035.00 26.80 RKB to CHF Type of Shoe:Conventional Casing Crew:Parker Wellbore 12 263 ES Closure OK 56 ArcticCem Type I/II Type HalCem Premium G 270 Tuned Spacer 736 2.92 Stage Collar @ 53 Bump press 100 339 7,035.007,045.00 CEMENTING REPORT Csg Wt. On Slips:30,000 Spud Mud 7:45 2/16/2023 2,308 2308 15.8 82 Bump press Mechanical Bump Plug? Y 2 9.2 6 169.25/169.5 522/518 1300 60 MP1 FI R S T S T A G E 10Tuned Spacer 55 15.8 519 9.65 5 1848 10 10.7 387 4 100 825 Bump Plug? Csg Wt. On Hook:305 Type Float Collar:Conventional No. Hrs to Run:26.5 9 5/8 47.0 L-81 VAM Tenaris 25.55 TCP BTC Innovex 1.77 7,035.00 7,033.23 2,224.62 2,250.17 Setting Depths Component Size Wt. Grade THD Make Length Bottom Top Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.PBW L-233 Date Run 14-Feb-23 CASING RECORD County State Alaska Supv.J Lott / C Montague 6,950.00 Floats Held 30 788 339 449 Spud Mud/ Tuned S Rotate Csg Recip Csg Ft. Min. PPG9.65 Shoe @ 7035 FC @ Top of Liner SE C O N D S T A G E MP 1 6:05 Returns to Surface 412 449 9 Casing (Or Liner) Detail Float Shoe 9.625 CSG RKB 10 3/4 100 2,308 Surface X Returns to Surface X 100 David Douglas Hilcorp North Slope, 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: Hilcorp North Slope, LLC Date: 03/17/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL : PBU L-233 PTD: 223-004 API: 50-029-23742-00-00 FINAL LWD FORMATION EVALUATION LOGS (02/09/2023 to 02/24/2023) EWR-M5, AGR, ABG, DGR, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs) Final Definitive Directional Survey Geosteering and EOW Report SFTP Transfer – Main Folders: PBU L-233 Final LWD Subfolders: PBU L-233 Final Geosteering Subfolders: Please include current contact information if different from above. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner:Rig No.:Innovation DATE:2/18/23 Rig Rep.:Rig Email:ontoolpusher@hilcorp.com Operator: Operator Rep.:Op. Rep Email: Well Name:PTD #2230040 Sundry # Operation:Drilling:x Workover:Explor.: Test:Initial:x Weekly:Bi-Weekly:Other: Rams:250/3000 Annular:250/3000 Valves:250/3000 MASP:1480 MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 1 FP 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 4-1/2" x 7"FP Flow Indicator P P #2 Rams 1 Blinds P Meth Gas Detector P P #3 Rams 1 5" SB 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 1 3 1/8 5K P Pressure After Closure (psi)1400 P Check Valve 0 NA 200 psi Attained (sec)27 P BOP Misc 1 NA Full Pressure Attained (sec)105 P Blind Switch Covers:All stations Yes CHOKE MANIFOLD:Bottle Precharge:1000 P Quantity Test Result Nitgn. Bottles # & psi (Avg.):6 @ 2316 P No. Valves 15 FP 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 11 P #1 Rams 9 P Coiled Tubing Only:#2 Rams 9 P Inside Reel valves 0 NA #3 Rams 5 P #4 Rams NA Test Results #5 Rams NA #6 Rams NA Number of Failures:3 Test Time:16.0 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 2/16/23, 16:37 Waived By Test Start Date/Time:2/18/2023 6:00 (date)(time)Witness Test Finish Date/Time:2/18/2023 22:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Kam StJohn Hilcorp Test on 4.5", 5", and 7" Pipe size. Fail on UIBOP. Change out and test w/Pass. FP on Low on CMV 1,2,& 3. Cycle/Service and Retest with Pass. Fp on High 4.5 x 7 VBR on 7" pipe size. Bleed Off, cycled Rams and Retest with Pass. Matt Vanhoose Hilcorp North Slope LLC James lott PBU L-233 Test Pressure (psi): jlott@hilcorp.com Form 10-424 (Revised 08/2022)2023-0218_BOP_Hilcorp_Innovation_PBU_L-233            J. Regg; 6/12/2023 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION DIVERTER Test Report for: Reviewed By: P.I. Suprv Comm ________PRUDHOE BAY UNIT L-233 JBR 03/31/2023 MISC. INSPECTIONS: GAS DETECTORS: DIVERTER SYSTEM:MUD SYSTEM: P/F P/F P/F Alarm Visual Alarm Visual Time/Pressure Size Number of Failures:0 Remarks:5" joint. TEST DATA Rig Rep:R. WoodsOperator:Hilcorp North Slope, LLC Operator Rep:Clint Montague Contractor/Rig No.:Hilcorp Innovation PTD#:2230040 DATE:2/8/2023 Well Class:DEV Inspection No:divSAM230208170130 Inspector Austin McLeod Inspector Insp Source Related Insp No: Test Time:1 ACCUMULATOR SYSTEM: Location Gen.:P Housekeeping:P Warning Sign P 24 hr Notice:P Well Sign:P Drlg. Rig.P Misc:NA Methane:P P Hydrogen Sulfide:P P Gas Detectors Misc:NA NA Designed to Avoid Freeze-up?P Remote Operated Diverter?P No Threaded Connections?P Vent line Below Diverter?P Diverter Size:13.625 P Hole Size:12.25 P Vent Line(s) Size:16 P Vent Line(s) Length:223 P Closest Ignition Source:91 P Outlet from Rig Substructure:208 P Vent Line(s) Anchored:P Turns Targeted / Long Radius:NA Divert Valve(s) Full Opening:P Valve(s) Auto & Simultaneous: Annular Closed Time:9 P Knife Valve Open Time:6 P Diverter Misc:0 NA Systems Pressure:P3000 Pressure After Closure:P1900 200 psi Recharge Time:P17 Full Recharge Time:P50 Nitrogen Bottles (Number of):P6 Avg. Pressure:P2308 Accumulator Misc:NA0 P PTrip Tank: P PMud Pits: P PFlow Monitor: NA NAMud System Misc:     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 North Slope, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Prudhoe Bay Field, Schrader Bluff Oil Pool, PBU L-233 Hilcorp North Slope, LLC Permit to Drill Number: 223-004 Surface Location: 2470' FSL, 4087' FEL, Sec. 34, T12N, R11E, UM, AK Bottomhole Location: 1574' FSL, 920' FWL, Sec. 21, T12N, R11E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Brett W. Huber, Sr. Chair, Commissioner DATED this ___ day of January, 2023. 24 Brett W. Huber. Sr. Digitally signed by Brett W. Huber. Sr. Date: 2023.01.24 14:56:20 -09'00' 1a. Contact Name:Joe Engel Contact Email:jengel@hilcorp.comAuthorized Name: Monty Myers Authorized Title:Drilling Manager Authorized Signature: Contact Phone:907-777-8395 Approved by:COMMISSIONER APPROVED BY THE COMMISSION Date: 5 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Drill Type of Work: Redrill Lateral 1b.Proposed Well Class:Exploratory - Gas 5 Service - WAG 5 1c. Specify if well is proposed for: Development - Oil Service - Winj Multiple Zone Exploratory - Oil Gas Hydrates Geothermal Hilcorp North Slope, LLC Bond No. 107205344 11.Well Name and Number: PBU L-233 TVD:14888'4253' 12. Field/Pool(s): MD: ADL 028239 & 047447 00-001 January 29, 2023 4a. Surface: Top of Productive Horizon: Total Depth: 2470' FSL, 4087' FEL, Sec. 34, T12N, R11E, UM, AK 1817' FSL, 1763' FWL, Sec. 27, T12N, R11E, UM, AK Kickoff Depth:250'feet Maximum Hole Angle: 92 degrees Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole:Surface:1915 1480 17.Deviated wells:16. Surface: x-y- Zone -582828 5978187 4 10. KB Elevation above MSL: GL Elevation above MSL: feet feet 73.4' 46.9' 15.Distance to Nearest Well Open to Same Pool: Cement Quantity, c.f. or sacks MD Casing Program: Surface Surface Surface 2006' Surface 4135' 19.PRESENT WELL CONDITION SUMMARY Production Surface Seabed Report Drilling Fluid Program 5 20 AAC 25.050 requirements Shallow Hazard Analysis 55 Commission Use Only See cover letter for other requirements: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No H2S measures Yes No Spacing exception req'd: Yes No Mud log req'd: Yes No Directional svy req'd: Yes No Inclination-only svy req'd: Yes No Other: Date: Address: Location of Well (State Base Plane Coordinates - NAD 27): 129.5# 6000'8888' 50- Intermediate Conductor/Structural Single Zone Service - Disp NoYesPost initial injection MIT req'd: NoYes 5 Diverter Sketch Comm. TVD API Number: MD Sr Pet Geo 1574' FSL, 920' FWL, Sec. 21, T12N, R11E, UM, AK Time v. Depth Plot555 5Drilling Program 8990' Stg 2 L - 672 sx / T - 268 sx (To be completed for Redrill and Re-Entry Operations) 8-1/2" 7" L-8026# / 20#7" x 6-5/8" 9-5/8" 4089' 12-1/4" 5900'Uncemented Tieback STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 Stratigraphic Test Development - Gas Service - Supply Coalbed Gas Shale Gas 2.Operator Name:5.Bond Blanket 5 Single Well 3. 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 6. Proposed Depth: 7. Property Designation (Lease Number): 8. DNR Approval Number:13.Approximate spud date: 9.Acres in Property: 14. Distance to Nearest Property: Location of Well (Governmental Section): 4b. 5120 60' 18.Specifications Top - Setting Depth - Bottom Casing Weight Grade TVDHole Coupling Length TVD (including stage data) 12-1/4" Tieback 9-5/8" 47# 40# 26# L-80 L-80 L-80 TXP TXP VamTop 2500' 4500' 5900' Surface 2500' Surface 2500' 7000' 14888' 2006' 4357' 4253' Stg 1 L - 606 sx / T - 395 sx Uncemented Slotted Liner Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured):Effect. Depth MD (ft): Effect. Depth TVD (ft):Junk (measured): Casing Length Size MD Liner Perforation Depth MD (ft):Perforation Depth TVD (ft): 20. Attachments Property Plat BOP Sketch Permit to Drill Number: Permit Approval Date: Reentry Hydraulic Fracture planned? Sr Pet Eng Sr Res Eng Cement Volume Comm. 127'127'Driven 20"X-52 80' Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval (20 AAC 25.005(g)) PRUDHOE BAY FIELD SCHRADER BLUFF OIL POOL, ORION DEVELOPMENT AREA VamTop/Hyd 563 1.17.2023 By Samantha Carlisle at 9:27 am, Jan 17, 2023 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2023.01.17 08:20:38 -09'00' Monty M Myers 1480 DLB 01/23/2023 *Gas lift on offset well PBU L-207 to remain off and IA purged while drilling L-233. 223-004 *BOPE test to 3000 psi. Annular to 2500 psi. X 029-23742-00-00 X X X X *Casing test and FIT digtal to AOGCC immediatly upon completion of performing FIT. X MGR20JAN2023 X DSR-1/17/23GCW 01/24/23 JLC 1/24/2023 1/24/23Brett W. Huber. Sr.Digitally signed by Brett W. Huber. Sr. Date: 2023.01.24 14:57:08 -09'00' RBDMS JSB 012523 Prudhoe Bay West (PBU) L-233 Drilling Permit Version 1 1/10/2023 Table of Contents 1.0 Well Summary ........................................................................................................................... 2 2.0 Management of Change Information ........................................................................................ 3 3.0 Tubular Program:...................................................................................................................... 4 4.0 Drill Pipe Information: .............................................................................................................. 4 5.0 Internal Reporting Requirements ............................................................................................. 5 6.0 Planned Wellbore Schematic ..................................................................................................... 6 7.0 Drilling / Completion Summary ................................................................................................ 7 8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8 9.0 R/U and Preparatory Work ..................................................................................................... 10 10.0 N/U 13-5/8” 5M Diverter System ............................................................................................. 11 11.0 Drill 12-1/4” Hole Section ........................................................................................................ 13 12.0 Run 9-5/8” Surface Casing ...................................................................................................... 16 13.0 Cement 9-5/8” Surface Casing ................................................................................................. 22 14.0 ND Diverter, NU BOPE, & Test .............................................................................................. 27 15.0 Drill 8-1/2” Hole Section .......................................................................................................... 28 16.0 Run 6-5/8” Liner ...................................................................................................................... 33 17.0 Run 7” Tieback ........................................................................................................................ 37 18.0 Run Upper Completion/ Post Rig Work ................................................................................. 40 19.0 Innovation Rig Diverter Schematic ......................................................................................... 44 20.0 Innovation Rig BOP Schematic ............................................................................................... 45 21.0 Wellhead Schematic ................................................................................................................. 46 22.0 Days Vs Depth .......................................................................................................................... 47 23.0 Formation Tops & Information............................................................................................... 48 24.0 Anticipated Drilling Hazards .................................................................................................. 50 25.0 Innovation Rig Layout ............................................................................................................. 54 26.0 FIT Procedure .......................................................................................................................... 55 27.0 Innovation Rig Choke Manifold Schematic ............................................................................ 56 28.0 Casing Design ........................................................................................................................... 57 29.0 8-1/2” Hole Section MASP ....................................................................................................... 58 30.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 59 31.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 60 Page 2 Prudhoe Bay West L-233 SB Producer Drilling Procedure 1.0 Well Summary Well PBU L-233 Pad Prudhoe Bay L Pad Planned Completion Type 4-1/2” Gas Lift Target Reservoir(s) Schrader Bluff OBb Sand Planned Well TD, MD / TVD 14,887’ MD / 4253’ TVD PBTD, MD / TVD 14,877’ MD / 4253’ TVD Surface Location (Governmental) 2,470' FSL, 4087' FEL, Sec 34, T12N, R11E, UM, AK Surface Location (NAD 27) X= 582,827.81, Y= 5,978,187.44 Top of Productive Horizon (Governmental)1817' FSL, 1763' FWL, Sec 27, T12N, R11E, UM, AK TPH Location (NAD 27) X=583,338.2, Y= 5,982,819.6 BHL (Governmental) 1574' FSL, 920' FWL, Sec 21, T12N, R11E, UM, AK BHL (NAD 27) X= 577,151, Y= 5,987,790 AFE Number 231-00012 AFE Drilling Days 21 AFE Completion Days 4 Maximum Anticipated Pressure (Surface) 1480 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1915 psig Work String 5” 19.5# S-135 NC 50 Innovation KB Elevation above MSL: 26.5 ft + 46.9 ft = 73.4 ft GL Elevation above MSL: 46.9 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Prudhoe Bay West L-233 SB Producer Drilling Procedure 2.0 Management of Change Information Page 4 Prudhoe Bay West L-233 SB Producer Drilling Procedure 3.0 Tubular Program: Hole Section OD (in)ID (in) Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 20” 19.25”---X-52Weld 12-1/4”9-5/8” 8.835”8.679”10.625”40 L-80 TXP 5,750 3,090 916 9-5/8” 8.681”8.525”10.625”47 L-80 TXP 6,870 4,750 1,086 Tieback 7” 6.276 6.151 7.565 26 L-80 JFE Bear 7,240 5,410 604 8-1/2” 6-5/8” 6.049 5.924 7.3980 20 L-80 H563 6090 3470 439 Tubing 4-1/2” 3.958 3.833 4.937 12.6 L-80 JFE Bear 8,430 7,500 288 4-1/2” 3.958 3.833 4.937 12.6 L-80 13Cr VAMTOP 8430 7500 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 & Production 5”4.276”3.25” 6.625”19.5 S-135 DS50 36,100 43,100 560klb 5”4.276”3.25” 6.625”19.5 S-135 NC50 30,730 34,136 560klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Prudhoe Bay West L-233 SB Producer Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. x Report covers operations from 6am to 6am x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. x Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates x Submit a short operations update each work day to 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 Wyatt Rivard 907.777.8547 wrivard@hilcorp.com Geologist Kevin Eastham 907.777.8316 keastham@hilcorp.com Reservoir Engineer Michael Mayfield 907.564.5097 mmayfield@hilcorp.com Drilling Env. Coordinator Keegan Fleming 907.777.8477 kfleming@hilcorp.com EHS Manager Laura Green 907.777.8314 lagreen@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com Page 6 Prudhoe Bay West L-233 SB Producer Drilling Procedure 6.0 Planned Wellbore Schematic Page 7 Prudhoe Bay West L-233 SB Producer Drilling Procedure 7.0 Drilling / Completion Summary PBU L-233 is a grassroots producer planned to be drilled in the Schrader Bluff OBb sands. L-233 is part of a multi-well program targeting the Schrader Bluff sand on PBU L-Pad The directional plan is 12-1/4” surface hole and 9-5/8” surface casing set into the top of the Schrader Bluff OBb sand. An 8-1/2” lateral section will be drilled. A 6-5/8” slotted liner will be run in the open hole section, followed by a 7” tieback and 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 January 29, 2023, pending rig schedule. Surface casing will be run to 7,000’ MD / 4,357’ TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, necessary remedial action will then be discussed with AOGCC authorities. All cuttings & mud generated during drilling operations will be hauled to one of two locations: Primary: Prudhoe G&I on Pad 4 Secondary: the Milne Point “B” pad G&I facility 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” lateral to well TD 6. Run 6-5/8” production liner 7. Run 7” tieback 8. Run Upper Completion 9. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Surface hole: No mud logging. Remote geologist. LWD: GR + Res 2. Production Hole: No mud logging. Remote geologist. LWD: GR + ADR (For geo-steering) Page 8 Prudhoe Bay West L-233 SB Producer Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling and completion of PBU L-233. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment will be to 250/3,000 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the well bore, AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements”. o Ensure the diverter vent line is at least 75’ away from potential ignition sources x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test pressure must show stabilizing pressure and may not decline more than 10 percent within 30 minutes. The results of this test and any subsequent tests of the casing must be recorded as required by 20 AAC 25.070(1)”. AOGCC Regulation Variance Requests: No variances requested at this time. Page 9 Prudhoe Bay West L-233 SB 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” 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: 250/3,000 Subsequent Tests: 250/3,000 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 and changing rams x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 10 Prudhoe Bay West L-233 SB Producer Drilling Procedure 9.0 R/U and Preparatory Work 9.1 L-233 will utilize a 20” conductor on L-Pad. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.3 Install landing ring. 9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each. 9.5 Level pad and ensure enough room for layout of rig footprint and R/U. 9.6 Rig mat footprint of rig. 9.7 MIRU 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 11 Prudhoe Bay West L-233 SB 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 – AOGCC Regulation requirement 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 12 Prudhoe Bay West L-233 SB Producer Drilling Procedure 10.4 Rig & Diverter Orientation: x May change on location Page 13 Prudhoe Bay West L-233 SB 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 Schrader OBb 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 < 6 deg / 100. x Hold a safety meeting with rig crews to discuss: x Conductor broaching ops and mitigation procedures. x Well control procedures and rig evacuation x Flow rates, hole cleaning, mud cooling, etc. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Keep mud as cool as possible to keep from washing out permafrost. x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. x There have been ‘directional dead zones’ noted in PBW. Directional plan has a build up in DLS from 2 – 4, to allow gradual build. 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 (pending MW increase due to hydrates). This is to combat hydrates and free gas risk, based upon offset wells. x Perform gyro surveys until clean MWD surveys are seen. Take MWD surveys every stand drilled. hydrates and free gas risk, based upon offset wells. ensure MW is at a 9.5 atjyy y, base of perm and at TD (pending MW increase due to hydrates). This is to combatp(pg DLB Page 14 Prudhoe Bay West L-233 SB Producer Drilling Procedure x Gas hydrates are not present at PBU L-Pad. But be prepared for gas hydrates. In PBW they have been encountered typically around 1660’ TVD (Base of Perm) to 2740’ TVD (Top Ugnu) and below. Be prepared for hydrates: x Keep mud temperature as cool as possible, Target 60-70*F. x Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as cold pre-made mud on trucks ready. x Drill through hydrate sands and quickly as possible, do not backream. x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD x Monitor returns for hydrates, checking pressurized & non-pressurized scales x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 fph MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well. MW will not control gas hydrates, but will affect how gas breaks out at surface. x Take MWD and GWD surveys every stand until magnetic interference cleans up. After MWD surveys show clean magnetics, only take MWD surveys. x Surface Hole AC, CF <1.0 : x L-207 – CF .79 @ 7,000’ MD, is a SB lateral in the Oba sand. We will have geologic separation between the wells 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+ (For Hydrates/Free Gas based on offset wells) 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. Minimum 8.46 ppg EMW needed. DLB as br Hydrates/Free Gaa Page 15 Prudhoe Bay West L-233 SB Producer Drilling Procedure 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 and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action. x Casing Running:Reduce system YP with 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 75-175 20 - 40 25-45 <10 8.5 –9.0 70 F System Formulation: Gel + FW spud mud Product Concentration Fresh Water soda Ash AQUAGEL caustic soda BARAZAN D+ BAROID 41 PAC-L /DEXTRID LT ALDACIDE G 0.905 bbl 0.5 ppb 15 - 20 ppb 0.1 ppb (8.5 – 9.0 pH) as needed as required for 8.8 – 9.2 ppg if required for <10 FL 0.1 ppb 11.5 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem sweeps and drop viscosity. 11.6 RIH to bottom, proceed to BROOH to HWDP x Pump at full drill rate (400-600 gpm), and maximize rotation. x Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions x Monitor well for any signs of packing off or losses. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.7 TOOH and LD BHA 11.8 No open hole logging program planned. Page 16 Prudhoe Bay West L-233 SB 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 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x R/U of CRT if hole conditions require. x R/U a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted to 8.75” on the location prior to running. x Top 2,500’ 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 correctly installed on top of float collar. x Ensure proper operation of float equipment while picking up. x Ensure to record S/N’s of all float equipment and stage tool components. This end up. Bypass Baffle Page 17 Prudhoe Bay West L-233 SB Producer Drilling Procedure 12.5 Float equipment and Stage tool equipment drawings: Page 18 Prudhoe Bay West L-233 SB 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 (Top of Lowest Ugnu) x Verify depth of lowest Ugnu water sand for isolation with Geologist x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. x Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 12.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below the permafrost (~ 2,500’ MD, 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. 9-5/8” 47# L-80 TXP Make-Up Torques: Casing OD Minimum Optimum Maximum 9-5/8”21,440 ft-lbs 23,820 ft-lbs 26,200 ft-lbs 9-5/8” 40# L-80 TXP MUT: Casing OD Minimum Optimum Maximum 9-5/8”18860 20960 23060 Page 19 Prudhoe Bay West L-233 SB Producer Drilling Procedure Page 20 Prudhoe Bay West L-233 SB Producer Drilling Procedure Page 21 Prudhoe Bay West L-233 SB Producer Drilling Procedure 12.8 Continue running 9-5/8” surface casing x Centralizers: 1 centralizer every 3rd joint to 200’ from surface x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: o 1 centralizer every 2 joints to base of conductor 12.9 The last 2,500’ of 9-5/8” will be 47#, from 2,500’ to Surface x Actual length of 47# may change due to depth of permafrost as drilled x Ensure drifted to 8.525” 12.10 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.11 Slow in and out of slips. 12.12 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.13 Lower casing to setting depth. Confirm measurements. 12.14 Have slips staged in cellar, along with necessary equipment for the operation. 12.15 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 22 Prudhoe Bay West L-233 SB 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 Total Cement Volume: Section Calculation Vol (bbl) Vol (ft3) Vol (sks) 12-1/4" OH x 9-5/8" Casing (7,000'-1,000'-2,500') x 0.0558 bpf x 1.3 253.8 1423.9 Total Lead 253.8 1423.9 605.9 12-1/4" OH x 9-5/8" Casing 1000' x 0.0558 bpf x 1.3 = 72.5 406.7 9-5/8" Shoetrack 120' x 0.0758 bpf = 9.1 51.1 Total Tail 81.6 457.8 394.6 Le a d Ta i l Page 23 Prudhoe Bay West L-233 SB Producer Drilling Procedure Cement Slurry Design (1st Stage Cement Job): 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. x Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 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. 13.11 Displacement calculation: 2500’ x 0.0732 bpf + (7,000’-120’-2500’) x .0758 bpf = = 515.2 bbls 80 bbls of tuned spacer to be left behind stage tool for preventing of contamination of cement in the annulus 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling Engineer. 13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 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. Lead Slurry Tail Slurry System EconoCem HalCem Density 12.0 lb/gal 15.8 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk Page 24 Prudhoe Bay West L-233 SB Producer Drilling Procedure 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. 13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. Page 25 Prudhoe Bay West L-233 SB 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. x 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 cement job): 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 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 (2000' - 110) x .0558 x 3 316.4 1775.0 Total Lead 345.0 1935.5 672.0 12-1/4" OH x 9-5/8" Casing (2500 - 2000' x .0558 bpf x 2 55.8 313.0 Total Tail 55.8 313.0 267.6 Le a d Ta i l Lead Slurry Tail Slurry System Arctic Cem HalCem Density 10.7 lb/gal 15.8 lb/gal Yield 2.88 ft3/sk 1.17 ft3/sk Mixed Water 22.02 gal/sk 5.08 gal/sk Page 26 Prudhoe Bay West L-233 SB Producer Drilling Procedure 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.26 Displacement calculation: 2500’ x 0.0732 bpf = 183 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. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to jengel@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 27 Prudhoe Bay West L-233 SB 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 250/3,000 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 3-1/2” test joint 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 injection. 14.9 Mix 8.9 ppg Baradrill-N fluid for production 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 28 Prudhoe Bay West L-233 SB Producer Drilling Procedure 15.0 Drill 8-1/2” Hole Section 15.1 MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM) 15.2 TIH w/ 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool. 15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.4 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = ~2,875 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.5 Drill out shoe track and 20’ of new formation. 15.6 CBU and condition mud for FIT. 15.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. Submit casing test and FIT digital data to AOGCC. x 12.0 ppg desired to cover shoe strength for expected ECDs. A 9.9 ppg FIT is the minimum required to drill ahead x 9.9 ppg FIT provides >>25bbls based on 9.5ppg MW, 8.46ppg PP (swabbed kick at 9.5 BHP) 15.8 POOH and LD cleanout BHA 15.9 PU 8-1/2” directional BHA. x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Ensure MWD is RU and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be 5” 19.5# S-135 NC50. x Run a ported float in the production hole section. Email casing test and FIT digital data to AOGCC promptly upon completion of FIT. email: melvin.rixse@alaska.gov Page 29 Prudhoe Bay West L-233 SB Producer Drilling Procedure Schrader Bluff Bit Jetting Guidelines Formation Jetting TFA NB 6 x 14 0.902 OA 6 x 13 0.778 OB 6 x 13 0.778 15.10 8-1/2” hole section mud program summary: x Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. x Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. x Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for sufficient hole cleaning x Run the centrifuge continuously while drilling the production hole, this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type:8.9 – 9.5 ppg Baradrill-N drilling fluid Properties: Interval Density PV YP LSYP Total Solids MBT HPH T Hardness Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100 Page 30 Prudhoe Bay West L-233 SB Producer Drilling Procedure 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 4 ppb 4 ppb 2 ppb 1.0 ppb 0.5 ppb 0.015 ppb 15.11 TIH with 8-1/2” directional assembly to bottom 15.12 Install MPD RCD 15.13 Displace wellbore to 9.2 ppg Baradrill-N drilling fluid x Density may change based upon TD of surface hole section 15.14 Begin drilling 8-1/2” hole section, on-bottom staging technique: x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K. x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes 15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer. x Flow Rate: 350-550 GPM, target min. AV’s 200 ft/min, 385 GPM x RPM: 120+ x 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 Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. x Use ADR to stay in section. Reservoir plan is to stay in OBd sand. x Limit maximum instantaneous ROP to < 250 FPH. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur. Page 31 Prudhoe Bay West L-233 SB Producer Drilling Procedure x Target ROP is as fast as we can clean the hole without having to backream connections x Schrader Bluff OBb Concretions: 4-6% Historically x MPD will be utilized to monitor pressure build up on connections. x 8-1/2” Lateral A/C, CF < 1.0: x L-200 L1: o CF .76 @ 9778’ MD, L-200 L1 is an abandoned lateral in the Obb. The only risk is damage to the bit o CF.54 @12625’ MD, L-200 L1 is an abandoned lateral in the Obb, the only risk is damage to the bit x L-200 L2: o CF .1 @10625’ MD, L-200 L2 is an abandoned lateral in the Oba. We will have geologic separation, the only risk is damage to the bit o CF .07 @ 12700’ MD, L-200 L2 is an abandoned lateral in the Oba. We will have geologic separation, the only risk is damage to the bit x L-207: CF .4-.6 @ 13600’ – 14375’ MD, L-207 is a lateral in the Oba sand, we will have geologic separation from this well. 15.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons learned and best practices. Ensure the DD is referencing their procedure. x Patience is key! Getting kicked off too quickly might have been the cause of failed liner runs on past wells. x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so we have a nice place to low side. x Attempt to lowside in a fast drilling interval where the wellbore is headed up. x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working string back and forth. Trough for approximately 30 minutes. x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ GPM) and rotation (120+ RPM). Pump tandem sweeps if needed x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary x If seepage losses are seen while drilling, consider reducing MW at TD 15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter cake and calcium carbonate. Circulate the well clean. Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being removed, including an increase in the loss rate. 15.18 Displace 1.5 OH + liner volume with viscosified brine. Page 32 Prudhoe Bay West L-233 SB Producer Drilling Procedure x Proposed brine blend (same as used on M-16, aiming for an 8 on the 6 RPM reading) - KCl: 7.1ppb for 2% NaCl: 60.9ppg for 9.4ppg Lotorq: 1.5% Lube 776: 1.5% Soda Ash: as needed for 9.5pH Busan 1060: 0.42ppb Flo-Vis Plus: 1.25ppb x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further discussion needed prior to BROOH. 15.15 Monitor the returned fluids carefully while displacing to brine. 15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe x Circulate at full drill rate (less if losses are seen, 350 GPM minimum). x Rotate at maximum RPM that can be sustained. x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as dictated by hole conditions x If backreaming operations are commenced, continue backreaming to the shoe 15.20 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while BROOH. 15.21 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps. 15.22 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary. x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise x If necessary, increase MW at shoe for any higher than expected pressure seen x Ensure fluid coming out of hole has passed a PST at the possum belly 15.23 POOH and LD BHA. 15.24 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit diameter is sufficient for future ball drops. x Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any additional logging runs conducted. Page 33 Prudhoe Bay West L-233 SB Producer Drilling Procedure 16.0 Run 6-5/8” Liner 16.1 Note: If there are any OHST performed, remove the centralizers on the first 3 joints 16.2 Well control preparedness: In the event of an influx of formation fluids while running the 6- 5/8” liner, the following well control response procedure will be followed: x P/U & M/U the 5” safety joint (with 6-5/8” crossover installed on bottom, TIW valve in open position on top, 6-5/8” handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 6-5/8” liner. x Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW. x Proceed with well kill operations. 16.3 R/U 6-5/8” liner running equipment. x Ensure 6-5/8” 24# H563 x NC50 crossover is on rig floor and M/U to FOSV. x Ensure all casing has been drifted on the deck prior to running. x Be sure to count the total # of joints on the deck before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 16.4 Run 6-5/8” slotted liner x Use API Modified or “Best O Life 2000 AG”thread compound. Dope pin end only w/ paint brush. Wipe off excess. Thread compound can plug the screens x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Use lift nubbins and stabbing guides for the liner run. x Install joints as per the Running Order (From Completion Engineer post TD). x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint outside of the surface shoe. x Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm 6-5/8” 20# H563 Torque – ftlbs OD Minimum Optimum Maximum Yield Torque 6-5/8 5900 7100 10300 36000 Page 34 Prudhoe Bay West L-233 SB Producer Drilling Procedure Page 35 Prudhoe Bay West L-233 SB Producer Drilling Procedure 16.6. Ensure to run enough liner to provide for sufficient overlap inside 9-5/8” casing for gas lift completion. Tentative liner set depth ~ 6,580’ MD x Confirm set depth with completion engineer. x 3-5 joints of 7” may be ran under the liner hanger for the production packer. Confirm with completion engineer. 16.7. Ensure hanger/pkr will not be set in a 9-5/8” connection. x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8” connection. 16.8. Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 16.9. M/U Baker SLZXP liner top packer to 6-5/8” liner. x Confirm with OE any 7” joints between liner top packer and 6-5/8” liner for GLM and packer setting depth 16.10. Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.11. RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. x Ensure 5” DP/HWDP has been drifted x There is no inner string planned to be run, as opposed to previous wells. The DP should auto fill. Monitor FL and if filling is required due to losses/surging. x Use HWDP as needed for running liner 16.12. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 16.13. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. 16.14. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. Page 36 Prudhoe Bay West L-233 SB Producer Drilling Procedure 16.15. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.16. Rig up to pump down the work string with the rig pumps. 16.17. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed 1,600 psi while circulating.Pusher tool is set at 2,100 psi with 5% shear screws but it should be discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker 16.18. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 16.19. Shut down pumps. Drop setting ball (ball seat now located in HRDE setting tool and not at the WIV) down the workstring and pump slowly (1-2 BPM). Slow pump before the ball seats. Do not allow ball to slam into ball seat. 16.20. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the SZXP liner hanger/packer to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi to release the HRDE running tool. 16.21. Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 RPM and set down 50K again. 16.22. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted. 16.23. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 16.24. PU pulling running tool free of the packer and displace with at max rate to wash the liner top. Pump sweeps as needed. 16.25. POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned, LD DP on the TOOH. Note: Once running tool is LD, swap to the completion AFE. Page 37 Prudhoe Bay West L-233 SB Producer Drilling Procedure 17.0 Run 7” Tieback 17.1 RU and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder to be used for tie-back space out calculation. 17.2 Notify AOGCC 24hrs prior to ram change 17.3 Install 7” solid body casing rams in the upper ram cavity. RU testing equipment. PT to 250/3,000 psi with 7” test joint. RD testing equipment. 17.4 RU 7” casing handling equipment. x Ensure XO to DP made up to FOSV and ready on rig floor. x Rig up computer torque monitoring service. x String should stay full while running, RU fill up line and check as appropriate. 17.5 PU 7” tieback seal assembly and set in rotary table. Ensure 7” seal assembly has (4) 1” holes above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8” x 7” annulus. 17.6 MU first joint of 7” to seal assy. 17.6 Run 7”, 26#, L-80 JFE Bear tieback to position seal assembly two joints above tieback sleeve. Record PU and SO weights. 17.7 Tieback to be Torque turned. 7”, 26#, L-80, JFE Bear =Casing OD Torque (Min) Torque (Opt)Torque (Max) 7”11800 13110 14420 Page 38 Prudhoe Bay West L-233 SB Producer Drilling Procedure 17.8 MU 7” to DP crossover. 17.9 MU stand of DP to string, and MU top drive. 17.10 Break circulation at 1 BPM and begin lowering string. 17.11 Note seal assembly entering tieback sleeve with a pressure increase, stop pumping and bleed off pressure. Leave standpipe bleed off valve open. 17.12 Continue lowering string and land out on no-go. Set down 5 – 10K and mark the pipe as “NO- GO DEPTH”. Page 39 Prudhoe Bay West L-233 SB Producer Drilling Procedure 17.13 PU string & remove unnecessary 7” joints. 17.14 Space out with pups as needed to leave the no-go 1 ft above fully no-go position when the casing hanger is landed. Ensure one full joint is below the casing hanger. 17.15 PU and MU the 7” casing hanger. 17.16 Ensure circulation is possible through 7” string. 17.17 RU and circulation corrosion inhibited brine in the 9-5/8” x 7” annulus. 17.18 With seals stabbed into tieback sleeve, spot diesel freeze protection from 2,500’ TVD to surface in 9-5/8” x 7” annulus by reverse circulating through the holes in the seal assembly. Ensure annular pressure are limited to prevent collapse of the 7” casing (verify collapse pressure of 7” tieback seal assembly). 17.19 SO and land hanger. Confirm hanger has seated properly in wellhead. Make note of actual weight on hanger on morning report. 17.20 Back out the landing joint. MU packoff running tool and install packoff on bottom of landing joint. Set casing hanger packoff and RILDS. PT void to 3,000 psi for 10 minutes. 17.21 RD casing running tools. 17.22 PT 9-5/8” x 7” annulus to 1,500 psi for 30 minutes charted. Page 40 Prudhoe Bay West L-233 SB Producer Drilling Procedure 18.0 Run Upper Completion/ Post Rig Work 18.1 RU to run 4-1/2”, 12.6#, 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. 18.2 PU, MU and RIH with the following 4-1/2” completion jewelry (tally to be provided by Operations Engineer): x Tubing Jewelry to include: x 1x X Nipple x 5x GLM x 1x X Nipple x 1x Production Packer i. Confirm packer set depth with OE for post rig wire line ball and rod retrieval. x 2x X Nipple x XXX joints, 4-1/2”, 12.6#, L-80, JFEBEAR x XX joints 4-1/2”, 12.6# 13cr VAMTOP x 1x WLEG Page 41 Prudhoe Bay West L-233 SB Producer Drilling Procedure Page 42 Prudhoe Bay West L-233 SB Producer Drilling Procedure 18.3 PU and MU the 4-1/2” tubing hanger. 18.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with band/clamp summary. 18.5 Land the tubing hanger and RILDS. Lay down the landing joint. 18.6 Install 4” HP BPV. ND BOP. Install the plug off tool. 18.7 NU the tubing head adapter and NU the tree. 18.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi. 18.9 Pull the plug off tool and BPV. 18.10 Reverse circulate the well over to corrosion inhibited source water follow by 85 bbls of diesel freeze protect for both tubing and IA to 2,500’ MD. 18.11 Drop the ball & rod and complete loading tubing and hydraulically set the packer as per Halliburton’s setting procedure Page 43 Prudhoe Bay West L-233 SB Producer Drilling Procedure 18.12 Pressure up and test the tubing to 3500 psi for MIT-T with 1000 psi on the IA. Bleed off the tubing to 2000psi. Test the IA to 3500 psi for MIT-IA. Bleed off the tubing and observe DCK shear. Confirm circulation in both directions thru the sheared valve. Record and notate all pressure tests (30 minutes) on chart. 18.13 Bleed both the IA and tubing to 0 psi. 18.14 Rig up jumper from IA to tubing to allow freeze protect to swap. 18.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 18.16 RDMO Innovation i. POST RIG WELL WORK 1. Slickline a. Change out GLV per GL ENGR b. Pull ball and rod and RHC 2. Well Tie in Page 44 Prudhoe Bay West L-233 SB Producer Drilling Procedure 19.0 Innovation Rig Diverter Schematic Page 45 Prudhoe Bay West L-233 SB Producer Drilling Procedure 20.0 Innovation Rig BOP Schematic Page 46 Prudhoe Bay West L-233 SB Producer Drilling Procedure 21.0 Wellhead Schematic Page 47 Prudhoe Bay West L-233 SB Producer Drilling Procedure 22.0 Days Vs Depth Page 48 Prudhoe Bay West L-233 SB Producer Drilling Procedure 23.0 Formation Tops & Information Reference Plan: COMMENTS SV5 Ice 1,779 1,557.4 -1484 685 8.46 BPRF Water 2,071 1,739.4 -1666 765 8.46 SV3 Gas Hydrates 2,563 2,045.4 -1972 900 8.46 Gas Hydrates expected SV3, SV2, & SV1 sands: 2340' - 3700' MD SV1 Gas Hydrates 3,354 2,538.4 -2465 1117 8.46 Ugnu 4A Heavy Oil 3,921 2,891.4 -2818 1272 8.46 Heavy Oil in Ugnu 4A: ~ 3955' - 4230' MD UG3 Water 4,461 3,227.4 -3154 1420 8.46 FAULT 80' Throw DTE N/A Ugnu LA Heavy Oil 5,276 3,734.4 -3661 Heavy Oil Lower Ugnu: 5325' - 5875' MD Ugnu MB Heavy Oil 5,590 3,925.4 -3852 1727 8.46 NB Schrader Bluff Water 5,988 4,129.4 -4056 1817 8.46 OA Schrader Bluff Water 6,337 4,259.4 -4186 1874 8.46 OBb Top (Heel) Schrader Bluff Oil 6,940 4,353.4 -4280 1915 8.46 OBb (Toe) Schrader Bluff Oil 14,887 4,253.4 -4180 1871 8.46 L-233 wp04ANTICIPATED FORMATION TOPS & GEOHAZARDS TOP NAME LITHOLOGY EXPECTED FLUID MD (FT) TVD (FT) TVDSS (FT)NORTHING EASTING Est. Pressure Gradient Page 49 Prudhoe Bay West L-233 SB Producer Drilling Procedure Page 50 Prudhoe Bay West L-233 SB Producer Drilling Procedure 24.0 Anticipated Drilling Hazards 12-1/4” Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates/Free Gas Gas hydrates have not been seen on PBU L Pad. Be prepared for them. They have been reported between 1660’ and 3140’ TVD across Prudhoe. MW has been chosen based upon successful trouble free penetrations of offset wells. x Be prepared for gas hydrates o Keep mud temperature as cool as possible, Target 60-70*F o Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as cold premade mud on trucks ready o Drill through hydrate sands and quickly as possible, do not backream. Remember that hydrate gas behaves differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud cut weight. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPM’s when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: There are no known wells with a clearance factory <1.0. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Well Specific A/C: x L-207 – CF .79 @ 7,000’ MD, is a SB lateral in the Oba sand. We will have geologic separation between the wells * L-207 is a producer, not an injector. Page 51 Prudhoe Bay West L-233 SB Producer Drilling Procedure Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for H2S. PBU L-Pad has a history of H2S on wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion Pool. 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 52 Prudhoe Bay West L-233 SB Producer Drilling Procedure 8-1/2” Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up 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 > 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: 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. H2S: Treat every hole section as though it has the potential for H2S. PBU L-Pad has a history of H2S on wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion Pool. 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 53 Prudhoe Bay West L-233 SB Producer Drilling Procedure Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. Well Specific A/C: x L-200 L1: o CF .76 @ 9778’ MD, L-200 L1 is an abandoned lateral in the Obb. The only risk is damage to the bit o CF.54 @12625’ MD, L-200 L1 is an abandoned lateral in the Obb, the only risk is damage to the bit x L-200 L2: o CF .1 @10625’ MD, L-200 L2 is an abandoned lateral in the Oba. We will have geologic separation, the only risk is damage to the bit o CF .07 @ 12700’ MD, L-200 L2 is an abandoned lateral in the Oba. We will have geologic separation, the only risk is damage to the bit x L-207: CF .4-.6 @ 13600’ – 14375’ MD, L-207 is a lateral in the Oba sand, we will have geologic separation from this well. n abandoned l n abandoned l n abandoned g n abandoned l * L-207 is a producer. Page 54 Prudhoe Bay West L-233 SB Producer Drilling Procedure 25.0 Innovation Rig Layout Page 55 Prudhoe Bay West L-233 SB Producer Drilling Procedure 26.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 56 Prudhoe Bay West L-233 SB Producer Drilling Procedure 27.0 Innovation Rig Choke Manifold Schematic Page 57 Prudhoe Bay West L-233 SB Producer Drilling Procedure 28.0 Casing Design Page 58 Prudhoe Bay West L-233 SB Producer Drilling Procedure 29.0 8-1/2” Hole Section MASP Minimum EMW required. DLB Page 59 Prudhoe Bay West L-233 SB Producer Drilling Procedure 30.0 Spider Plot (NAD 27) (Governmental Sections) Page 60 Prudhoe Bay West L-233 SB Producer Drilling Procedure 31.0 Surface Plat (As Built) (NAD 27) 6WDQGDUG3URSRVDO5HSRUW -DQXDU\ 3ODQ/ZS +LOFRUS1RUWK6ORSH//& 3UXGKRH%D\ / 3ODQ/ / -750 0 750 1500 2250 3000 3750 4500 5250 Tr u e V e r t i c a l D e p t h ( 1 5 0 0 u s f t / i n ) -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 Vertical Section at 330.04° (1500 usft/in) L-233 wp02 CP1 L-233 wp02 CP2 L-233 wp02 CP3 L-233 wp02 CP4 L-233 wp02 CP5 L-233 wp02 CP6 9 5/8" x 12 1/4" 4 1/2" x 8 1/2" 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 60 00 6500 7000 7500 8000 8500 9000 9500 100 00 10500 11000 11500 1200 0 12500 13000 13500 14000 14500 14888 L-233 wp04 Start Dir 3º/100' : 250' MD, 250'TVD Start Dir 4º/100' : 500' MD, 499.29'TVD End Dir : 1709.35' MD, 1513.9' TVD Fault #1: 80' throw DTE Start Dir 4.5º/100' : 5369.66' M D, 3792.67'TV D End Dir : 6790.74' M D, 4342.94' TVD Start Dir 3º/100' : 6940.74' M D, 4353.4'TVD End Dir : 7252.92' M D, 4360.3' TVD Start Dir 2º/100' : 7669.72' M D, 4349.6'TVD End Dir : 8001.65' M D, 4342.16' TVD Start Dir 2º/100' : 8768.47' M D, 4323.4'TVD End Dir : 8910.81' M D, 4320.9' TVD Start Dir 2º/100' : 9618.86' M D, 4313.4'TVD End Dir : 9839.66' M D, 4309.24' TVD Start Dir 2º/100' : 12090.76' M D, 4248.4'TV D End Dir : 12296.2' M D, 4245.92' TVD Total Depth : 14887.7' M D, 4253.4' TVD SV5 BPRF SV3 SV1 Ugnu 4A UG3 Ugnu LA Ugnu MB NB OA OBb Top (Heel) Hilcorp North Slope, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: Plan: L-233 46.90 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 5978187.440 582827.810 70° 21' 1.3960 N 149° 19' 39.0951 W SURVEY PROGRAM Date: 2023-01-05T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 26.50 1200.00 L-233 wp04 (L-233) GYD_Quest GWD 1200.00 7000.00 L-233 wp04 (L-233) 3_MWD+IFR2+MS+Sag 7000.00 14887.70 L-233 wp04 (L-233) 3_MWD+IFR2+MS+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 1557.40 1484.00 1779.21 SV5 1739.40 1666.00 2071.55 BPRF 2045.40 1972.00 2563.07 SV3 2538.40 2465.00 3354.96 SV1 2891.40 2818.00 3921.97 Ugnu 4A 3227.40 3154.00 4461.68 UG3 3734.40 3661.00 5276.06 Ugnu LA 3925.40 3852.00 5590.95 Ugnu MB 4129.40 4056.00 5988.22 NB 4259.40 4186.00 6337.53 OA 4353.40 4280.00 6940.74 OBb Top (Heel) REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: L-233, True North Vertical (TVD) Reference:L-233 as staked @ 73.40usft Measured Depth Reference:L-233 as staked @ 73.40usft Calculation Method:Minimum Curvature Project:Prudhoe Bay Site:L Well:Plan: L-233 Wellbore:L-233 Design:L-233 wp04 CASING DETAILS TVD TVDSS MD Size Name 4357.00 4283.60 7000.00 9-5/8 9 5/8" x 12 1/4" 4253.40 4180.00 14887.70 4-1/2 4 1/2" x 8 1/2" 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 3º/100' : 250' MD, 250'TVD 3 500.00 7.50 0.00 499.29 16.34 0.00 3.00 0.00 14.16 Start Dir 4º/100' : 500' MD, 499.29'TVD 4 1200.00 35.50 0.00 1144.12 270.34 0.00 4.00 0.00 234.23 5 1709.35 51.50 18.64 1513.90 610.67 64.38 4.00 45.93 496.94 End Dir : 1709.35' MD, 1513.9' TVD 6 5369.66 51.50 18.64 3792.67 3324.88 979.91 0.00 0.00 2391.34 Start Dir 4.5º/100' : 5369.66' MD, 3792.67'TVD 7 6790.74 86.00 319.10 4342.94 4513.55 659.58 4.50 -73.16 3581.16 End Dir : 6790.74' MD, 4342.94' TVD 8 6940.74 86.00 319.10 4353.40 4626.65 561.61 0.00 0.00 3728.08 L-233 wp02 CP1 Start Dir 3º/100' : 6940.74' MD, 4353.4'TVD 9 7252.92 91.47 311.49 4360.30 4848.22 342.29 3.00 -54.40 4029.56 End Dir : 7252.92' MD, 4360.3' TVD 10 7669.72 91.47 311.49 4349.60 5124.27 30.20 0.00 0.00 4424.58 Start Dir 2º/100' : 7669.72' MD, 4349.6'TVD 11 7944.92 91.11 306.00 4343.40 5296.41 -184.30 2.00 -93.69 4680.83 L-233 wp02 CP2 12 8001.65 91.40 304.90 4342.16 5329.30 -230.50 2.00 -75.09 4732.40 End Dir : 8001.65' MD, 4342.16' TVD 13 8768.47 91.40 304.90 4323.40 5767.94 -859.19 0.00 0.00 5426.37 L-233 wp02 CP3 Start Dir 2º/100' : 8768.47' MD, 4323.4'TVD 14 8910.81 90.61 307.64 4320.90 5852.13 -973.93 2.00 106.17 5556.61 End Dir : 8910.81' MD, 4320.9' TVD 15 9618.86 90.61 307.64 4313.40 6284.48 -1534.59 0.00 0.00 6211.17 L-233 wp02 CP4 Start Dir 2º/100' : 9618.86' MD, 4313.4'TVD 16 9839.66 91.55 311.95 4309.24 6425.75 -1704.17 2.00 77.66 6418.24 End Dir : 9839.66' MD, 4309.24' TVD 17 12090.76 91.55 311.95 4248.40 7930.11 -3377.68 0.00 0.00 8557.29 L-233 wp02 CP5 Start Dir 2º/100' : 12090.76' MD, 4248.4'TVD 18 12296.20 89.83 308.22 4245.92 8062.36 -3534.82 2.00 -114.63 8750.34 End Dir : 12296.2' MD, 4245.92' TVD 19 14887.70 89.83 308.22 4253.40 9665.61 -5570.84 0.00 0.00 11156.09 L-233 wp02 CP6 Total Depth : 14887.7' MD, 4253.4' TVD -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 So u t h ( - ) / N o r t h ( + ) ( 1 5 0 0 u s f t / i n ) -6750 -6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 West(-)/East(+) (1500 usft/in) L-233 wp02 CP6 L-233 wp02 CP5 L-233 wp02 CP4 L-233 wp02 CP3 L-233 wp02 CP2 L-233 wp02 CP1 9 5/8" x 12 1/4" 4 1/2" x 8 1/2" 1000 1500 1750 2000 2250 2500 2750 3000 3250 3500 3750 4000 4 2 5 0 425 3L-23 3 w p04 Start Dir 3º/100' : 250' MD, 250'TVD Start Dir 4º/100' : 500' MD, 499.29'TVD End Dir : 1709.35' MD, 1513.9' TVD Fault #1: 80' throw DTE Start Dir 4.5º/100' : 5369.66' MD, 3792.67'TVD End Dir : 6790.74' MD, 4342.94' TVD Start Dir 3º/100' : 6940.74' MD, 4353.4'TVD End Dir : 7252.92' MD, 4360.3' TVD Start Dir 2º/100' : 7669.72' MD, 4349.6'TVD End Dir : 8001.65' MD, 4342.16' TVD Start Dir 2º/100' : 8768.47' MD, 4323.4'TVD End Dir : 8910.81' MD, 4320.9' TVD Start Dir 2º/100' : 9618.86' MD, 4313.4'TVD End Dir : 9839.66' MD, 4309.24' TVD Start Dir 2º/100' : 12090.76' MD, 4248.4'TVD End Dir : 12296.2' MD, 4245.92' TVD Total Depth : 14887.7' MD, 4253.4' TVD CASING DETAILS TVD TVDSS MD Size Name 4357.00 4283.60 7000.00 9-5/8 9 5/8" x 12 1/4" 4253.40 4180.00 14887.70 4-1/2 4 1/2" x 8 1/2" Project: Prudhoe Bay Site: L Well: Plan: L-233 Wellbore: L-233 Plan: L-233 wp04 WELL DETAILS: Plan: L-233 46.90 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 5978187.440 582827.810 70° 21' 1.3960 N 149° 19' 39.0951 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: L-233, True North Vertical (TVD) Reference:L-233 as staked @ 73.40usft Measured Depth Reference:L-233 as staked @ 73.40usft Calculation Method:Minimum Curvature 3URMHFW &RPSDQ\ /RFDO&RRUGLQDWH5HIHUHQFH 79'5HIHUHQFH 6LWH +LOFRUS1RUWK6ORSH//& 3UXGKRH%D\ / 6WDQGDUG3URSRVDO5HSRUW :HOO :HOOERUH 3ODQ/ / 6XUYH\&DOFXODWLRQ0HWKRG0LQLPXP&XUYDWXUH /DVVWDNHG#XVIW 'HVLJQ/ZS 'DWDEDVH1257+86&$1$'$ 0'5HIHUHQFH/DVVWDNHG#XVIW 1RUWK5HIHUHQFH 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e p a r a t i o n F a c t o r 0 375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 4875 5250 5625 6000 6375 6750 7125 Measured Depth (750 usft/in) L-117 L-118 L-123 L-200 L-200L2 L-202 L-206 L-207 L-212 L-250 No-Go Zone - Stop Drilling Collision Avoidance Required Collision Risk Procedures Req. NOERRORS WELL DETAILS:Plan: L-233 NAD 1927 (NADCON CONUS)Alaska Zone 04 46.90 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 5978187.440 582827.810 70° 21' 1.3960 N 149° 19' 39.0951 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: L-233, True North Vertical (TVD) Reference: L-233 as staked @ 73.40usft Measured Depth Reference:L-233 as staked @ 73.40usft Calculation Method:Minimum Curvature SURVEY PROGRAM Date: 2023-01-05T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 26.50 1200.00 L-233 wp04 (L-233) GYD_Quest GWD 1200.00 7000.00 L-233 wp04 (L-233) 3_MWD+IFR2+MS+Sag 7000.00 14887.70 L-233 wp04 (L-233) 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 ) 0 375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 4875 5250 5625 6000 6375 6750 7125 Measured Depth (750 usft/in) L-206 L-212 L-100 NWE1-01 L-231 wp01 L-253 wp01 L-292 wp01 L-294 wp01 L-101 GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference 26.50 To 14887.70 Project: Prudhoe Bay Site: L Well: Plan: L-233 Wellbore: L-233 Plan: L-233 wp04 Ladder / S.F. Plots 1 of 2 CASING DETAILS TVD TVDSS MD Size Name 4357.00 4283.60 7000.00 9-5/8 9 5/8" x 12 1/4" 4253.40 4180.00 14887.70 4-1/2 4 1/2" x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e p a r a t i o n F a c t o r 6800 7225 7650 8075 8500 8925 9350 9775 10200 10625 11050 11475 11900 12325 12750 13175 13600 14025 14450 14875 Measured Depth (850 usft/in) L-200 L-200A L-200L1 L-200L2 L-206 L-207 L-211 L-211PB1 L-240 No-Go Zone - Stop Drilling Collision Avoidance Required Collision Risk Procedures Req. NOERRORS WELL DETAILS:Plan: L-233 NAD 1927 (NADCON CONUS)Alaska Zone 04 46.90 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 5978187.440 582827.810 70° 21' 1.3960 N 149° 19' 39.0951 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: L-233, True North Vertical (TVD) Reference: L-233 as staked @ 73.40usft Measured Depth Reference:L-233 as staked @ 73.40usft Calculation Method:Minimum Curvature SURVEY PROGRAM Date: 2023-01-05T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 26.50 1200.00 L-233 wp04 (L-233) GYD_Quest GWD 1200.00 7000.00 L-233 wp04 (L-233) 3_MWD+IFR2+MS+Sag 7000.00 14887.70 L-233 wp04 (L-233) 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 ) 6800 7225 7650 8075 8500 8925 9350 9775 10200 10625 11050 11475 11900 12325 12750 13175 13600 14025 14450 14875 Measured Depth (850 usft/in) L-200L-200A L-200L1 L-200L1 L-200L2 L-200L2 L-200L2 L-207 GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference 26.50 To 14887.70 Project: Prudhoe Bay Site: L Well: Plan: L-233 Wellbore: L-233 Plan: L-233 wp04 Ladder / S.F. Plots 2 of 2 CASING DETAILS TVD TVDSS MD Size Name 4357.00 4283.60 7000.00 9-5/8 9 5/8" x 12 1/4" 4253.40 4180.00 14887.70 4-1/2 4 1/2" x 8 1/2" Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME:______________________________________ PTD:_____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD:__________________________POOL:____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in nogreater 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. PBU L-233 X PBU X Schrader Bluff Oil (Orion Development Area) X 223-004 WELL PERMIT CHECKLIST Company Hilcorp North Slope, LLC Well Name:PRUDHOE BAY UNIT L-233 Initial Class/Type DEV / PEND GeoArea 890 Unit 11650 On/Off Shore On Program DEVField & Pool Well bore seg Annular DisposalPTD#:2230040 PRUDHOE BAY, SCHRADER BLUF OIL - 64013 NA1 Permit fee attached Yes2 Lease number appropriate Yes3 Unique well name and number Yes4 Well located in a defined pool Yes5 Well located proper distance from drilling unit boundary Yes6 Well located proper distance from other wells Yes7 Sufficient acreage available in drilling unit Yes8 If deviated, is wellbore plat included Yes9 Operator only affected party Yes10 Operator has appropriate bond in force Yes11 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 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 127'18 Conductor string provided Yes 9-5/8" surface casing fully cemented with shoe set in SB reservoir.19 Surface casing protects all known USDWs Yes Fully cemented with stage collar and excess.20 CMT vol adequate to circulate on conductor & surf csg Yes21 CMT vol adequate to tie-in long string to surf csg Yes Fully cemented from surface to the reservoir.22 CMT will cover all known productive horizons Yes 9-5/8" 47# L-80 from surface to BOPF, 9-5/8" 40# L-80 from BOPF to reservoir.23 Casing designs adequate for C, T, B & permafrost Yes Innovation has adequate tankage and good trucking support.24 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 recognizes PBU L-207 producer as close approach. L-207 is a lateral in the reserv.26 Adequate wellbore separation proposed Yes 16" Diverter line below 5000 psi BOPE27 If diverter required, does it meet regulations Yes All fluids overbalanced to pore pressure28 Drilling fluid program schematic & equip list adequate Yes 1 annular, 3 ram, 1 flow cross.29 BOPEs, do they meet regulation Yes 5M psi 13-5/8" stack, tested to 3000 psi.30 BOPE press rating appropriate; test to (put psig in comments) Yes31 Choke manifold complies w/API RP-53 (May 84) Yes32 Work will occur without operation shutdown Yes Monitoring will be required.33 Is presence of H2S gas probable NA This well is a producer.34 Mechanical condition of wells within AOR verified (For service well only) No PBU L-Pad, V-Pad, and W-Pad Schrader Bluff wells have measured H2S >20 ppm. H2S measures required.35 Permit can be issued w/o hydrogen sulfide measures Yes36 Data presented on potential overpressure zones NA37 Seismic analysis of shallow gas zones NA38 Seabed condition survey (if off-shore) NA39 Contact name/phone for weekly progress reports [exploratory only] Appr DLB Date 1/20/2023 Appr MGR Date 1/20/2023 Appr DLB Date 1/20/2023 Administration Engineering Geology Geologic Commissioner:Date:Engineering Commissioner:Date Public Commissioner Date JLC 1/24/2023