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Home My WebLink About222-020Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone: (907) 564-4891 01/12/2023 Mr. Mel Rixse Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Prudhoe Bay Surface Casing by Conductor Annulus Top-offs of Cement, Corrosion Inhibitor through 4Q 2022. Dear Mr. Rixse, Enclosed please find a copy of a spreadsheet with a list of Prudhoe Bay wells that were topped-off with cement, corrosion inhibitor in the surface casing by conductor annulus through the end of 4Q 2022. Cement top-offs are executed as needed to mitigate the void space left at surface by minor cement fallback during the primary surface casing by conductor cement job. The remaining void space between the top of the cement and the top of the conductor is filled with a heavier than water corrosion inhibitor to reduce the risk of external surface casing corrosion. The attached spreadsheets include the well names, API and PTD numbers, treatment dates and volumes. As per previous agreement with the AOGCC, this letter and spreadsheet serve as notification that the treatments took place and meet the requirements of form 10-404 Report of Sundry Operations. If you have any additional questions, please contact me at 564-4891 or oliver.sternicki@hilcorp.com. Sincerely, Oliver Sternicki Well Integrity Engineer Hilcorp North Slope, LLC By Samantha Carlisle at 3:53 pm, Jan 12, 2023 Digitally signed by Oliver Sternicki (4525) DN: cn=Oliver Sternicki (4525), ou=Users Date: 2023.01.12 14:52:49 -09'00' Oliver Sternicki (4525) DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-029-23417-01-00Well Name/No.PRUDHOE BAY UN ORIN V-227ACompletion StatusWAGINCompletion Date4/4/2022Permit to Drill2220200OperatorHilcorp North Slope, LLCMD9940TVD5113Current StatusWAGIN9/21/2022UICYesWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:ROP/GR/ADR, Cement EvaluationNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF4/12/20225480 9940 Electronic Data Set, Filename: PBU V-227A LWD Final.las36469EDDigital DataDF4/12/2022 Electronic File: PBU V-227A LWD Final MD.cgm36469EDDigital DataDF4/12/2022 Electronic File: PBU V-227A LWD Final TVD.cgm36469EDDigital DataDF4/12/2022 Electronic File: V-227A_Definitive survey report.pdf36469EDDigital DataDF4/12/2022 Electronic File: V-227A_Definitive survey report.txt36469EDDigital DataDF4/12/2022 Electronic File: V-227A_GIS.txt36469EDDigital DataDF4/12/2022 Electronic File: V-227A_Plan.pdf36469EDDigital DataDF4/12/2022 Electronic File: V-227A_Surveys.xlsx36469EDDigital DataDF4/12/2022 Electronic File: V-227A_VSec.pdf36469EDDigital DataDF4/12/2022 Electronic File: PBU V-227A LWD Final MD.emf36469EDDigital DataDF4/12/2022 Electronic File: PBU V-227A LWD Final TVD.emf36469EDDigital DataDF4/12/2022 Electronic File: PBU V-227A LWD Final MD.pdf36469EDDigital DataDF4/12/2022 Electronic File: PBU V-227A LWD Final TVD.pdf36469EDDigital DataDF4/12/2022 Electronic File: PBU V-227A LWD Final MD.tif36469EDDigital DataDF4/12/2022 Electronic File: PBU V-227A LWD Final TVD.tif36469EDDigital DataDF4/13/20220 9593 Electronic Data Set, Filename: V-227A_RBT_08APR22_FieldANDProcessedLog-V1.las36475EDDigital DataDF4/13/20229593 -12 Electronic Data Set, Filename: V-227A_RBT_08APR22_MainPass.las36475EDDigital DataWednesday, September 21, 2022AOGCC Page 1 of 3PBU V-227ALWD Final.las DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-029-23417-01-00Well Name/No.PRUDHOE BAY UN ORIN V-227ACompletion StatusWAGINCompletion Date4/4/2022Permit to Drill2220200OperatorHilcorp North Slope, LLCMD9940TVD5113Current StatusWAGIN9/21/2022UICYesWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYMud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NADF4/13/2022 Electronic File: V-227A_RBT_08APR22.pdf36475EDDigital DataDF4/13/2022 Electronic File: V-227A_RBT_08APR22_FieldANDProcessedLog-V1.dlis36475EDDigital DataDF4/13/2022 Electronic File: V-227A_RBT_08APR22_img.tiff36475EDDigital DataDF4/13/2022 Electronic File: V-227A_RBT_08APR22_MainPass.dlis36475EDDigital DataDF4/13/2022 Electronic File: V-227A_RBT_08APR22_ProcessedLog-V1.pdf36475EDDigital DataDF4/13/2022 Electronic File: V-227A_RBT_08APR22_ProcessedLog-V1_img.tiff36475EDDigital DataDF5/18/20220 9593 Electronic Data Set, Filename: PBU_V-227A_RBT_08APR22_FieldANDProcessedLog-V1.las36631EDDigital DataDF5/18/2022 Electronic File: PBU_V-227A_RBT_08APR22.pdf36631EDDigital DataDF5/18/2022 Electronic File: PBU_V-227A_RBT_08APR22_FieldANDProcessedLog-V1.dlis36631EDDigital DataDF5/18/2022 Electronic File: PBU_V-227A_RBT_08APR22_img.tiff36631EDDigital DataDF5/18/2022 Electronic File: PBU_V-227A_RBT_08APR22_ProcessedLog-V1.pdf36631EDDigital DataDF5/18/2022 Electronic File: PBU_V-227A_RBT_08APR22_ProcessedLog-V1_img.tiff36631EDDigital DataWednesday, September 21, 2022AOGCC Page 2 of 3 DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-029-23417-01-00Well Name/No.PRUDHOE BAY UN ORIN V-227ACompletion StatusWAGINCompletion Date4/4/2022Permit to Drill2220200OperatorHilcorp North Slope, LLCMD9940TVD5113Current StatusWAGIN9/21/2022UICYesComments:Compliance Reviewed By:Date:COMPLIANCE HISTORYDate CommentsDescriptionCompletion Date:4/4/2022Release Date:3/8/2022Wednesday, September 21, 2022AOGCC Page 3 of 3M. Guhl9/21/2022 Completed 4/3/2022 JSB By James Brooks at 8:51 am, Aug 02, 2022 RBDMS JSB 080322 G 0 DLB 09/19/2022MGR30AUG2022 DSR-8/3/22 7.29.2022Digitally 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: 2022.07.29 14:22:16 -08'00' Monty M Myers CASING AND LEAK-OFF FRACTURE TESTS Well Name:PBU V-277A Date:3/27/2022 Csg Size/Wt/Grade: Supervisor:Barber/Amend Csg Setting Depth:5495 TMD 3056 TVD Mud Weight:9.3 ppg LOT / FIT Press =222 psi LOT / FIT =10.70 ppg Hole Depth =5517 md Fluid Pumped=0.3 Bbls Volume Back =0.3 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 ->00 ->00 ->285 ->265 ->4 155 ->4230 ->6 231 ->6450 -> ->8590 -> ->10 720 -> ->12 830 -> ->14 1020 -> ->16 1200 -> ->18 1390 -> ->20 1580 -> ->22 1780 -> ->24 1990 -> ->26 2190 Enter Holding Enter Holding Enter Holding Enter Holding Time Here Pressure Here Time Here Pressure Here ->0 231 ->0 2190 ->1 190 ->1 2178 ->2 176 ->2 2176 ->3 170 ->3 2174 ->4 162 ->4 2173 ->5 156 ->5 2171 ->6 150 ->10 2170 ->7 145 ->15 2157 ->8 140 ->20 2150 ->9 136 ->25 2143 ->10 131 ->30 2136 -> -> -> -> -> -> 7" 26# L-80 FIT 0 2 4 6 0 2 4 6 8 10 12 14 16 18 20 22 24 26 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 0102030Pressure (psi)Strokes (# of) LOT / FIT DATA CASING TEST DATA 231 190176170162156150145140136131 219021782176217421732171 2170 2157 2150 2143 2136 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 30Pressure (psi)Time (Minutes) LOT / FIT DATA CASING TEST DATA Activity Date Ops Summary 3/20/2022 Move sub down well row onto matts in front of V-227A. Set down sub. Unhook, remove steering arm and rear tires. Rotate sub and stomp onto V-227A. Shim sub and set outriggers. Turn and retract stompers. Spot rig matts. Spot cattle chute & pipe shed. SIMOPS: Trouble shoot # 1 Cat overheating issues. Swapped out radiator fan computer Mod. Removed #4 Cat exhaust for repair and install. Remove #2 Cat exhaust components for repair. Function & test #1 Cat, good. PJSM Finish spotting pipe shed. Spot, shim gen & mud mod. SIMOPS: Cont. set sub outriggers. Retract & store Sub stompers. Release NES at 03:00. PJSM Spot, set, shim break shack, enviro vac & warm up shack. Lay Herculite and cutting box. Hook up all interconnects in utilidoors and mud lines in pits. Supply air & steam to pits, pump room and untilidoors. Begin working on rig acceptance checklist. Safe out stairs and walkways. Swap to gen power at 04:00. Daily Disposal to G&I = 61 bbls, total = 61 bbls. Daily H2O from Lake 2 = 0 bbls total = 0 bbls. Daily Metal: 0 lb. Total Metal 0 lb. 3/21/2022 PJSM Cont steam & H2O around rig. Scope up derrick and bridal down. Hang rig tongs & secure derrick. Install cellar grating and safe out well/ walking area around sub. Finish rig acceptance checklist. Spot Beyond MPD system & R/U. Load 4" D.P. in pipe shed. R/U MP's & Pits. Rig accepted at 10:30. PJSM P/U R/U HP hoses and 1502 components to Circ out Diesel FP through 3.5" 9.2# L-80 TCII Tubing out IA back to cutting box. Heat soap pill in pits. Check well Press Tub: 100 psi, IA 0 psi, OA psi. Fill choke line to Gas Buster U Tube. SIMOPS: Cont loading 4" D.P. PJSM Pump through bleeder on rig floor. Shut master valve on tree and test line to 250/1000 psi, good. Line up to pump down tubing and take returns to IA to Gas Buster. Pump 40 bbls heated BaraKlen pill followed by 201 bbls 9.3 ppg QuikDril 2 bpm ICP 34 psi stage up to 4 bpm FCP 88 psi. Shut down monitor well 10 min, Tub 0 psi, IA 0 psi OA 0 psi. Blow down lines. Clean out Gas Buster. PJSM Remove tree cap. Vault rep set BPV. Break flange bolts on tree. Remove tree and aside in cellar. Install CTS and tested to 4,000 psi as per Vault rep. Remove 1502 companion flange F/ choke line. PJSM Install DSA and 2' spacer spool. P/U stack and set on spacer spool. Install and Trq bolts on stack, DSA and spacer spool. Secure stack W/ chains and turn buckles. R/U Choke and kill lines. R/U Beyond 4" hard lines W/ Beyond rep. Install drip pan. SIMOPS Stage 4" handling Equip on rig floor. PJSM Line up on kill line and PT MPD Equip 250/ 1,250 psi, good. Open RCD grey clamp, pull MPD test cap and install RCD riser. Close and tighten grey clamp. Inflate air boot. PJSM R/U test Equip. Vac out stack. Mark Test jnts UPR & LPR. P/U M/U 4" Test jnt, X/O, side entry sub, 4" TIW & Dart. Flood surface Equip and purge air. Perform shell test 250/ 3,000 psi, good. PJSM Perform BOPE test W/ 4" test jnt to 250 PSI low and 3,000 PSI high for 5 Min. Tested Choke Manifold 1-3,11-15, 4" Dart, 4" TIW, Upper and lower IBOP, Mez Kill, HCR and manual Choke and Kill, Super Choke and manual to 2,000 PSI, Upper and lower VRB Rams (2.875" X 5.5") Blind Rams & Annular. Checked PVT sensors and return flow. Witnessed by AOGCC Rep Guy Cook. P/U M/U 3.5” test Jnt. Daily Disposal to G&I =0 bbls, total = 61 bbls. Daily H2O from Lake 2 = 580 bbls total = 580 bbls. Daily Metal: 0 lb. Total Metal 0 lb. 3/22/2022 PJSM Perform BOPE test W/ 3.5" test jnt to 250 PSI low and 3,000 PSI high for 5 Min. Tested Choke Manifold 4-10, 4" Dart, Upper and lower VRB Rams (2.875" X 5.5") Blind Rams & Annular. Test H2S 10-20 ppm, LEL 20-40%, PVT high/ low level alarms. Koomey draw drown Initial System 3,000 PSI, Manifold 1,550 PSI, Annular 1,250 PSI, after System 1,500 PSI, Man 1,500 PSI, Annular 1,200 PSI. 200 PSI increase 28 Sec, full charge 99 sec. Nitrogen 6 bottle average 2,325 PSI. Bled down Accumulator to 0 psi and verify bank bottles charged to 1,000 psi. Witnessed by AOGCC Rep Guy Cook. P/D test Equip. L/D 3.5" test jnt. Break out 4" TIW, 4" Dart, Side entry & X/O. Break out test sub to TD. Blow down all surface Equip. Stage Weatherford 3.5" handling Equip on rig floor. C/O elevators to 4" D.P.. PJSM P/U Tee Bar and remove CTS plug. Pull BPV as per Vault rep onsite. P/U 4" XT39 D.P. and M/U XT39 X 4.5" TCII X/O. M/U to hanger and top drive. BOLDS. Open annulus and unseat hanger. Observed no over pull and free with 52k hook load. P/U 5' and line up to Circ. Pump 34 bbls heated soap pill followed by 9.3 ppg brine 295 gpm 340 psi R/F 36%. Observed 646u gas at BU dropping to 49u BGG. SIMOPS Cont P/U R/U Weatherford 3.5" tools and Equip. Shut down and monitor well 10 min, static. Pull tubing hanger to rig floor L/D. Blow down. PJSM POOH L/D 3.5"9.2# L-80 TCII kill string F/ 3,070' to surface. P/U 46k SLK 48k. Lost 4 bbls for trip. PJSM R/D Weatherford tools & Equip. L/D power tongs. C/O Elevators to 4" D.P. Bring up scrapper and BHA components. PJSM P/U M/U 6- 1/8" Bit TirCone, 7" Scraper and Bit Sub (no float). X/O. PJSM Install Wear ring (7" ID, 10.75" OD, 12' Lgt) Single in hole Scrapper BHA W/ 4" 14# S-135 XT39 D.P. F/Surface to 5723' md, Drift 2.346" OD. P/U 90K, S/O 63K. Wash down at 2 bpm from 5710' md to 5723' md. Tag top of 3.5" tubing cut @ 5723' md, set down 5 K to confirm. Circulate out contaminated 9.0 ppg brine, displace well with 9.3 ppg brine. Stage pumps up to 300 gpm, 1180 psi while reciprocating pipe. Reciprocate scraper across CIBP setting depth from 5720' md to 5679' md. R/F = 34%, Max Gas = 548u. Dumped 93 bbl of contaminated 9.0 ppg brine/crude. BGG 89u. No losses while circulating. Monitor well for 10 min prior to pulling out of the hole (static). PJSM. Pump 20 bbl 9.8 ppg dry job. Blow down top drive. Pull out of the hole from 5679'md to 5615' md. P/U 90K, S/O 63K. Cont pull out of the hole from 5615'md to surface. P/U 90K, S/O 63K. Lay down casing scraper BHA. No wear observed on casing scraper. Service rig and perform derrick inspection. PJSM. Spot AK E-line unit. Rig up E-line sheaves to topdrive and beaver slide. Run E-line through sheaves. Make up CCL assembly on E-line. (1.6875" Wt bar, CCL/ TitanPerf 3.13" 11.08' Length) RIH W/ CCL at 350 ft/min to 5,100' ELM 140 ft/min to 5685' ELM. Log up at 80 ft/min 360# to 5,442' ELM. Log down 80 ft/min to 5,712' MD showing collar of 7". POOH. Daily Disposal to G&I =57 bbls, total = 118 bbls. Daily H2O from Lake 2 = 290 bbls total = 870 bbls. Daily Metal: 1 lb. Total Metal 1 lb. 50-029-23417-01-00API #: Well Name: Field: County/State: PBW V-227A Prudhoe Bay West Hilcorp Energy Company Composite Report , Alaska 3/27/2022 Job Name: 211-00077.04 PBW V-227A Drilling Spud Date: 3/23/2022 Cont. to pull out of the hole with CCL log to surface. Break down logging tool and rig down sheaves. P/U CIBP and X/O to 4" dp. RIH with the CIBP at 90 fpm per baker rep from surface to top of 3.5" tubing stub at 5723' md, P/U 84k, S/O 68K. Tag top of tubing stub with 2k. Set CIBP per Baker procedure. P/U stretch plus 5'. Rotate 10 turns to engage CIBP slips. S/O to setting depth at 5722' md. Top of CIBP at 5720' md. P/U 25K over to 109K to set CIBP. S/O 25K under to 40K to confirm set. P/U to 86K and rotate 10 turns to release from CIBP. Set back 1 stand to 5682' md and Pressure test top of CIBP to 500 psi for 5 min (Good). POOH from 5682' md to surface. lay down CIBP running tool. PJSM R/U Weatherford handling Equip. C/O elevators to 3.5" YC 75T. P/U M/U 3.5" L-80 EUE cement stinger Assy to 557' MD. Trq EUE 3,150 ft/lb. M/U X/O and Cont RIH W/ 4" D.P. F/ derrick F/ 557' to CIBP at 5,721' MD W/ 2k tag. P/U 80k SLK 67k. PJSM R/U 1502 & HP line to cement line. P/U string to 5,715' MD. Circ at 4 bpm 300 psi R/F 23%. Mas Gas 481u. P/U 80k SLK 67k. PJSM, Pump balanced plug. Wet lines w/ 5 bbls H2O (HES) and P/T low kick out 938/ 3,925 psi high. Wet cement at 22:50. Cement job as follows: 12 bbls 15.8 ppg Lead cmt, 1.53 yld (63sx) 1.45 bpm ICP 160 psi FCP 138 psi. Displace w/ 5 bbls H2O (HES) 1.7 bpm ICP 67 psi FCP 54 psi. Turn over to rig. Rig disp w/ 50.8 bbls 9.3 ppg Brine 3 bpm ICP 57 psi slowed to 1 bpm last 2 bbls FCP 81 psi. CIP 23:39 hrs. Full returns throughout job. Shut down open string and appears out of balance, bled back about 2.5 bbls. PJSM Verify no flow, static out of string. R/D cement lines & Equip. POOH L/D 2 jnts and rack back 4" D.P. F/ 5,715' to 5,223' MD Pull speed 7 ft/min. String started U Tubing appears to be out of balance. Circ Surf to Surf dumped 13.5 bbl contaminated brine. Break out and drop 4" wiper ball Circ Surf to Surf. 420 gpm 1,150 psi R/F 43%. Monitor well 10 min, static. PJSM POOH racking back 4" D.P. F/ 5,223' MD to 1,565' MD. Went to Phase 2 weather conditions at 03:14. Working at a reduced rate to reduce incident. Went to Phase 3 at 04:51. Shut down all operations due to weather. Daily Disposal to G&I =5 bbls, total = 123 bbls. Daily H2O from Lake 2 = 200 bbls total = 1070 bbls. Daily Metal: 1 lb. Total Metal 1 lb. 3/24/2022 Continue to wait on weather due to Phase 3 conditions. Perform hazard hunts. Work on hitchly paperwork/inspections. Phase 3 conditions lifted to Phase 2 field wide at 10:09. Continue to pull out of the hole with 4" DP from 1565' MD to the top of the 3.5" tubing cement stinger at 561' MD. Working at a reduced rate to reduce incident. Rig up Weatherford casing tongs and Lay down 3.5" tubing cement stinger from 561' MD to surface. Hole took proper displacement. R/D Weatherford casing equipment. Demob from floor. R/U 4" dp handling equipment. Clean and clear rig floor. M/U 6-1/8" Milltooth (Smith XR+PS, 3 x 14's), Bit sub (no float), XO sub. Single in with 6x jts 4" HWDP - Total length = 190.94'. Single in F/ 191' - T/ 4445' MD. Continue trip in out of derrick F/ 4445' - T/ 5358' MD. Wash down F/ 5358' to tag depth @ 5380' MD. 2x tags w/ 5k set dn. Drill cmt F/ 5380' - T/ 5600' MD. 300 gpm, 60 rpm, 4-5k torque, 3K WOB. P/U 90K, S/O 64K, ROT 70K. Circulate 1.5X bottoms up with 400 gpm, 1850 psi, 60 rpm, 4-5k torque. Ream up to 5484' MD while circulating. Monitor well for 10 min prior to pulling out of the hole (static). POOH from 5484' MD to surface. Break out bit, bit sub and crossover. Bit grade 1-0-WT-A-E-I-NO-LOG Rig up E-line sheaves and Packoff on 7-5/8" dutch riser. P/U E Line Perf BHA (3 7/8" Roller Boogey 2', Perf Carrier Perf Gun 2' 6 shots per ft 0.5" hole 3 1/8" OD 9', CRCCL 3.13" OD 5.03', 3 7/8" Roller Boogey 2' & Cable Head 1.44" OD 1.05') Shot placement CCL TOS 11.1', BOS 3.3'. PJSM RIH W/ E Line 33'0 ft/min to 4,800', 122 ft min to 5,300 ft/min slow to 60 ft min to TOC @ 5,592.4' ELM. P/U 485# SLK 65#. Correlate pass F/ 5,592' to 5,337.1' ELM 75 ft/min correlation adjustment 2' from prior CCL. RIH to 5,592.4' P/U to 5,568.9' CCL placing TOS at 5,580' BOS 5,582' ELM. P/U 445#. Discharge perf gun, no visual sign at surface. Monitor well 10 min on choke, no press. Open choke and monitor for flow static. 0 pressure observed on the OA. POOH W/ E Line F/ 5,568.9' at 330 ft/min. Lay down perf guns and stand back lubricator with packoff. All Perf guns discharged downhole. Fluid pack lines, close blind rams and open to choke manifold. Perform injection test. Pump at .5 bpm to 700 psi, observed slight breakover at ~450 psi, continue to pressure up to 700 psi. Shut down pump monitored pressure. Pressure decreased to 280 psi in 3 min. Beed pressure to 0. Attempt injection test again with .25 bpm. Observe slight breakover at ~450 psi, continued to pressure up to 800 psi. Shut down pumps and monitored pressure. Pressure decreased to 500 psi in 5 min. Bleed pressure to 0 and monitor well for 10 min (static). 0 Pressure observed on OA during inj tests. Rig down E-line dutch riser, packoff, and sheaves. Make up 7" cement retainer assembly on 4" DP. RIH from surface to 2500' MD. RIH at 90 fpm per Baker procedure. Daily Disposal to G&I =67 bbls, total = 190 bbls. Daily H2O from Lake 2 = 220 bbls total = 1290 bbls. Daily Metal: 0 lb. Total Metal 1 lb. 3/25/2022 RIH from 2500' MD to set depth at 5503' MD. RIH at 90 fpm per Baker procedure. Final P/U 108K, S/O 57K. Set cement retainer per Baker procedure. P/U 4'. Rotate 10 turns to engage retainer slips. S/O to setting depth at 5503' MD. Top of CIBP at 5501' MD. P/U 32K over to 140K to set CIBP. S/O 23K under to 35K. Work pipe between 140k and 35k 2 more times to confirm set. P/U to 78K and rotate 10 turns to release from retainer. Sting out of retainer, circulate at 3 bpm, 140 psi to confirm circulation and fluid pack lines. Pressure test top of retainer to 500 psi for 5 min (Good). Space out and install headpin in DP. Rig up cement lines to headpin. Establish injection with rig pumps. Pump at .25 bpm, observe pressure breakover at 764 psi, inject 1.2 bbl after breakover at .25 bpm max pressure 790 psi. PJSM with HES cementing crew. Unsting from retainer. Fluid pack lines. Pressure test cement lines to 970 psi low and 3900 psi high for 5 min each (test good). Line up to pump cement. Pump 5 bbl fresh water ahead 20 bbl of 15.8 ppg class G cement and 5 bbl fresh water behind 1.75bpm 168psi. Line up with rig pumps and displace with 28 bbl of 9.3 ppg brine at 3 bpm 110 psi. Wet cmt @ 10:29. Sting into cement retainer. Inject 22 bbl (15.2 bbls cement out perfs to open hole) at .25 bpm, observe pressure break over at 500 psi, pressure continued to climb slowly to 1640 psi. Observe hard break at 1640 psi after 5.6 bbls injected and pressure decrease to 1360 psi before stabilizing. Continue pumping @ .4 bpm, 1440 final psi. Shut down and allow psi to drop to 1015 psi before trend slowed over 3 min. P/U and dump psi while shifting retainer closed (well static). CIP @ 12:42. B/D cmt equipment. Pump out of hole @ 1/4 bpm, 6.5 fpm pulling speed laying 1 bbl cmt on top of retainer (~5475') Rack back 1x stand and L/D 10' pup jt to 5428' MD. Drop wiper ball and circulate 1-1/2 Btm's up @ 11.5 bpm, 1640 psi, 15 rpm, 4.5k tq. Observed residual cement back at surface, dumped 21 bbls. B/D top drive, monitor well (static). B/D kill and choke lines. POOH F/ 5428' - T/ surface. L/D retainer running tool. Clean and clear rig floor. Mob BHA tools to floor. M/U Cleanout BHA. 6.125" mill tooth tricone bit, bit sub, watermelon mill, and XO to 4" HWDP. RIH on 4" DP from top of BHA to 5236' MD. P/U 98K, SO 60K. Hold Well control trip drill and AAR with rig crew. Perform rig maintenance and inspections while WOC. Slip and cut drill line. Service rig. Wash down at 1 bpm, 30 psi from 5236' MD to 5463' MD. Tag TOC with 5K at 5463' MD. Increase flow rate to 300 gpm, 1100 psi and engage rotary at 50 rpm, 4.5k torque. Drill cement from 5463' MD to 5500' MD (1' above retainer) with up to 1K WOB. Circulate bottoms up. 415 gpm, 1990 psi. Observe slight amount of cement at shakers during bottoms up. Engage pumps at 1 bpm, Tag TOC with 10k. Line up and Pressure test cement X 7" casing to 2000psi for 30 min (Good test). Pump in 1.6 bbl / Bleed back 1.6 bbl. Tag TOC after pressure test with 10K. AOGCC rep Guy Cook on location to witness tag and test. Displace well to 9.25 ppg Baradril-N. 475 gpm, 2000 psi, 30 rpm, 4K torque. Obtain SPR's. Blow down standpipe and monitor well (static). POOH from 5500' MD to 3600' MD. P/U 97K, S/O 63K. Daily Disposal to G&I = 292 bbls, total = 482 bbls. Daily H2O from Lake 2 = 0 bbls total = 1290 bbls. Daily Metal: 0 lb. Total Metal 1 lb. 20 bbl of 15.8 ppg class G cement and 5 bbl fresh w Drill cmt F/ 5380' - T/ 5600' MD. Pump balanced plug. Tag TOC after pressure test with 10K. AOGCC rep Guy Cook on location to witness tag and test. Pressure test top of CIBP to 500 psi for 5 min (Good) Make up 7" cement retainer assembly on 4" DP. RIH from surface to 2500' MD. 3/26/2022 Continue to POOH from 3600' MD to surface. No wear observed on watermelon mill. Bit grade 1-0-WT-A-E-I-NO-BHA Clean and clear rig floor. M/U Whipstock assembly to total BHA length of 370' MD. P/U Joint of HWDP and M/U milling assembly. M/U TM, DM, Float sub and XO and scribe line. M/U whipstock with 25K shear bolt and anchor (11K shear on anchor). Scribe line and measure RFO = 4.25/1.32 = 110.11°. RIH with 7" whipstock and 6-1/8" window milling assembly on 4" DP from 370' MD to 5349' MD. RIH at 90 fpm per Baker rep. Shallow hole test MWD at 190' MD with 250 gpm, 535 psi (test good). Wash down F/ 5349' - T/ 5500' MD. 250 gpm, 930 psi, 30% F/O. 86k up, 60k dn. Orientate TF to 31° ROHS while washing down. Tag and set anchor on depth @ 5500' MD while holding 31° ROHS TF (TOW 5482', BOW 5495'). Saw bobble while slacking of to blk wt, indicate anchor set. Pick up to 100k with no break over to confirm anchor set (set good). Slack off to blk wt and P/U observing lug shear mills from whipstock. Free up wt 85k, 59k dn. Obtain parameters and begin milling operations F/ 5482' - T/ 5417' MD. 300 gpm, 1220 psi, 38% flow out, 100 rpm, 5.2k tq. 3 fpr F/ 5,482' to 5,495' MD observed minimal amount of cement at surface. Ream through BOW 5,495' to TOW 5,482' MD 2X Trq swing 3-8k first pass, smooth the second pass. Pump 25 bbl 9.3 ppg 250 vis sweep surf to surf, on time W/ ~3 lbs metal. Control drilling 8 ft/hr F/ 5,495' to 5,517' MD while milling with second 6.175" upper mill across slide.. Max Gas 208u. BGG 90-150u. Drilled 22' of new hole. Seen crude at surface during drilling. Observe 10 psi on OA. Circulate hole clean with 300 gpm, 1170 psi, Pump 25 bbl 9.3 ppg 250 vis sweep surface to surface, on time. No increase in cuttings and 11lb of metal back at shakers. Drift window 2X at full rotary and pumps with no issues. Shut off rotary and drift window with pump only, observe slight packoff at 5484' MD with full pump rate. Reduce pumps to 84 gpm and drift window with no issues. Appears mill may be balled up. Monitor well (static). R/U to perform FIT to 10.7 ppg EMW. M/U head pin and high pressure hose. Line up down drill string and kill line. Mud weight 9.3 ppg in/out. 3056' TVD, Pump .3 bbl at .25 bpm to 231 psi, hold for 10 min. Bleed off pressure (.3 bbl back) and send test chart with spreadsheet to DE for approval. AOGCC approved original surface casing LOT of 12.7 ppg EMW. Monitor well (static) POOH with 6.125" window milling assembly from 5452' MD to top of BHA at 352' MD. Rack back HWDP and L/D 6.125" Window milling BHA from 352' MD surface. Window mill 3/8" under and balled up with clay and rock, Lower mill 1/4" under no balling, upper mill in gage (6.151") no balling. Daily Disposal to G&I = 413 bbls, total = 895 bbls. Daily H2O from Lake 2 = 0 bbls total = 1290 bbls. Daily Metal: 60 lb. Total Metal 61 lb. 3/27/2022 Clean and clear rig floor. Pull wear bushing. M/U Johnny Whacker and flush out BOPE stack (30 lbs of metal back at shakers). L/D Johnny whacker. Blow down top drive. Install wear ring (7" ID). Make up 6.125" Motor build BHA to total length of 425' MD. Smith 6.125" milltooth tricone bit to 1.5° AKO motor with float (non ported), DM / TM, Measure RFO 2.39/4.8 = 179.25°, Float sub (non ported), XO to 6 jts of 4" HWDP, jars, 3 jts of 4" HWDP. RIH on 4" DP from 425' MD to 4899' MD. Fill pipe and shallow pulse test MWD at 2630' MD, 250 gpm, 1040 psi (good test). Hold kick while tripping drill and AAR with rig crew. Service rig and top drive. Pull trip nipple, install MPD bearing. RIH from 4899' MD to 5517' MD. Fill pipe and orient motor to 30° ROHS. Trip through window without pumps observe 5- 7k drag at 5484' MD. No other issues tripping through window. ROT/SLD Drill 6 1/8" Hole F/ 5517' to 5904' MD (3208' TVD) Total 387’ (AROP 55 fph) 300 GPM/ MPD 290, 1670 psi, 60 RPM, TRQ on 6k, TRQ off 6k, WOB 5-14k. Max Gas 365u. P/U 103k, SLK 50k, ROT 63k. MPD 100% open. Back ream 30'. 1st clean survey at 5741' MD. Rot 2.46, Sld 2.37 hrs. Pump 25 bbl 9.2+ ppg / 250 vis sweep surface to surface (on time no increase) at 300 gpm, 1690 psi, 60 rpm, 5-6k torque, MPD F/O 290 gpm, Max gas 23u. Monitor well prior to pulling off bottom (static). POOH on elevators from 5904' MD to 5466' MD. P/U 110K, S/O 57K off bottom. Orient TF to 39° ROHS. Pull through window without pumps no drag observed pulling through window. Pull MPD bearing and install trip nipple. POOH from 5466' MD to top of the BHA at 425' MD. Monitor well (static) Rack back 4" HWDP, Jars, and Flex collars. Lay down Motor BHA from 425' MD to Surface. Clean and clear rig floor. Make up 6.125" RSS BHA to 96' MD. 6.125" PDC bit, Sperry iCruise RSS, Shallow test iCruise at surface with 250 gpm, 950 psi, 30 rpm (all pads functioning properly), DM Collar, Inline Stab, ADR, Inline Stab, TM Collar, Filter sub. Plug into ADR and download MWD. Distance to WP03: 46.70', 4.7' High, 46.50' Right Daily Disposal to G&I = 171 bbls, total = 1066 bbls. Daily H2O from Lake 2 = 290 bbls total = 1580 bbls. Daily Metal: 55 lb. Total Metal 116 lb. 3/28/2022 Finish downloading BHA #8 (Run 300). M/U 2x NM Flex DC's, 2x Float subs (non ported, plunger), XO and 5x stands HWDP w/ jars. Total length = 474.67'. Shallow pulse test MWD/Filter sub and ICruise as per onsite Sperry Rep. 250 gpm, 1015 psi (test good). B/D TDS. Trip in with 6-1/8" RSS assy F/ 474' - T/ 5385' MD. P/U 88k, S/O 52k. Hole took calculated displacement. Pull trip nipple and install MPD bearing. Pump thru without issue. RIH T/ 5447' MD. Grease crown, blocks, TDS, Wash pipe, Iron Roughneck, Standpipe manifold, Drawworks and spinners. Sim Ops - Flood Beyond Equipment and pump thru while servicing rig. 275 gpm, 1770 psi, 10.9 ECD. Trip in F/ 5447' - T/ 5533' MD. Encounter tight spot while passing ILS thru window. w/ 15k set down. Work down with moderated difficulty. P/U 102k, S/O 56k. Ratty @ 5484' (8-10k bobble). Continue working BHA out window F/ 5533' - T/ 5904' MD. Worked dn w/ 5-10k drag w/ 1st stabilizer just outside window. Saw 15k set downs and 10k overpulls with packoffs while working 1st stabilizer into open hole. Wash remaining BHA down 3 bpm, 560 psi. Worked 2nd stabilizer into open hole with same issues. Worked thru same. Increase flow rate to 5 bpm, 1200 psi and washed down F/ 5580' - T/ 5904' MD. Check shot @ 5845' bit depth. Drill 6 1/8" Hole F/ 5904' T/ 6270' MD (3365' TVD) Total 366’ (AROP 91.5 fph) 275 GPM/MPD 262, 1895 psi, 120 RPM, TRQ on 6- 7k, TRQ off 5-6k, WOB 3-6k. MW 9.3 ppg. Max Gas 23u. P/U 113k, SLK 53k, ROT 70k. MPD 100% open. Back ream 60'. Heavy crude observed at shakers. Drill 6 1/8" Hole F/ 6270' T/ 6837' MD (3636' TVD) Total 567’ (AROP 94.5 fph) 275 GPM/MPD 266, 1960 psi, 120 RPM, TRQ on 6-7k, TRQ off 6.5k, WOB 4-8k. MW 9.3 ppg. Max Gas 140u. P/U 118k, SLK 54k, ROT 71k. MPD 100% open. Back ream 60'. Floats are slightly leaking on connections. OA = 650 psi. Drill 6 1/8" Hole F/ 6837' T/ 7235' MD (3806' TVD) Total 398’ (AROP 66.3 fph) 275 GPM/MPD 267, 2015 psi, 120 RPM, TRQ on 6-9k, TRQ off 7-8k, WOB 3-6k. MW 9.3 ppg. Max Gas 36u. P/U 133k, SLK 51k, ROT 71k. MPD 100% open. Back ream 60'. 01:30 bleed OA from 650 psi to 200 psi, ~12 gal back. Distance to WP03: 42.76', 10.66' High, 41.41' Right Daily Disposal to G&I = 114 bbls, total = 1180 bbls. Daily H2O from Lake 2 = 290 bbls total = 1870 bbls. Daily Metal: 10 lb. Total Metal 126 lb. 3/29/2022 Drill 6 1/8" Hole F/ 7235' MD T/ 7594' MD (3972' TVD) Total 359’ (AROP 60 fph) 275 GPM/MPD 267, 2125 psi, 120 RPM, TRQ on 8.8k, TRQ off 8k, WOB 3-8k. MW 9.3 ppg. Max Gas 236u. P/U 138k, S/O 52k, ROT 74k. MPD 100% open. Back ream 60'. End 3°/100 at 7466' md. Drill 6 1/8" Hole F/ 7594' MD T/ 7907' MD (4113' TVD) Total 313’ (AROP 52 fph) 275 GPM/MPD 267, 2230 psi, 120 RPM, TRQ on 8-10k, TRQ off 8-9k, WOB 4-8k. MW 9.3 ppg. Max Gas 231u. P/U 144k, S/O 53k, ROT 75k. MPD 100% open. Back ream 60'. OA @ 14:47 = 280 psi (appears to be thermal expansion) Drill 6 1/8" Hole F/ 7,907' to 8,193' MD (4,239' TVD) Total 286’ (AROP 47.7 fph) 275 GPM/MPD 266, 2240 psi, 120 RPM, TRQ on 9-10k, TRQ off 8-9k, WOB 4-9k. MW 9.35 ppg. Max Gas 264u. P/U 146k, S/O 53k, ROT 78k. MPD 100% open. Back ream 60'. OA @ 23:30 = 425 psi (appears to be thermal expansion) Drill 6 1/8" Hole F/ 8,193' to 8,569' MD (4,405' TVD) Total 376’ (AROP 62.7 fph) 275 GPM/MPD 268, 2270 psi, 120 RPM, TRQ on 10-11k, TRQ off 9-10k, WOB 3-8k. MW 9.35 ppg. Max Gas 569u. P/U 158k, S/O 51k, ROT 81 k. MPD 100% open. Back ream 60'. OA @ 05:00 = 490 psi Distance to WP03: 4.81', 0.81' High, 4.74' Right Daily Disposal to G&I = 219 bbls, total = 1399 bbls. Daily H2O from Lake 2 = 200 bbls total = 2070 bbls. Daily Metal: 22 lb. Total Metal 148 lb. 3/30/2022 Drill 6 1/8" Hole F/ 8569' - T/ 8810' MD (4509' TVD) Total 241’ (AROP 40 fph) 275 GPM/MPD 268, 2345 psi, 120 RPM, TRQ on 10.5k, TRQ off 9-10k, WOB 3-9k. ECD 11.66 ppg, MW 9.3 ppg. Max Gas 79u. P/U 160k, S/O 51k, ROT 82 k. MPD 100% open. Back ream 60'. OA @ 11:00 = 550 psi Drill 6 1/8" Hole F/ 8810' - T/ 9051' MD (4621' TVD) Total 241’ (AROP 40 fph) 220-275 GPM/MPD 55-268, 1500 psi, 120 RPM, TRQ on 10.5k, TRQ off 9-10k, WOB 3-9k. ECD 11.3 ppg, MW 9.3 ppg. Max Gas 400u (btms up from loss zone). P/U 174k, S/O 53k, ROT 86 k. MPD 100% open. Back ream 60'. Observed severe losses @ 8877' MD / 4538' TVD. Went to 33% returns and gradually returned to 73% returns @ 225 gpm over 10 min. Depth correlated to top of NB sand. Continue drilling ahead at reduced rates. Drill 6 1/8" Hole F/ 9051' T/ 9357' MD (4786' TVD) Total 306’ (AROP 51 fph) 250 GPM w/ 80% returns, 1810psi, 120RPM, TRQ on 11-12k, TRQ off 10-11k, WOB 3-9k. MW 9.3 ppg. Max Gas 326u. P/U 174K, S/O 58K, ROT 88K. MPD 100% open. Back ream 60'. Observe breathing on connections. Drill 6 1/8" Hole F/ 9357' T/ 9700' MD (4977' TVD) Total 343’ (AROP 57 fph) 260 GPM 78-84% returns, 2010psi, 120RPM, TRQ on 11-12k, off 11-12k, WOB 3-9k. ECD 11.06 ppg, MW 9.3 ppg. Max Gas 571u. P/U 181K, S/O 59K, ROT 89K. MPD 100% open. Back ream 60'. Observe breathing on connections Distance to WP03: 9.71', 3.02' High, 9.22' Left Daily Disposal to G&I = 285 bbls, total = 1684 bbls. Daily H2O from Lake 2 = 580 bbls total = 2650 bbls. Daily Metal: 2 lb. Total Metal 150 lb. Daily DH Loss = 775 Total DH Loss = 775. TOW 5,482' MD 2X T 3/31/2022 Drill 6 1/8" Hole F/ 9700' to TD@9940' MD (5113' TVD) Total 240’ (AROP 60 fph) 260 GPM 78-84% returns, 2065psi, 120RPM, TRQ on 12.5k, off 11.5k, WOB 3- 10k. ECD 11.18 ppg, MW 9.3 ppg. Max Gas 745u. P/U 180K, S/O 59K, ROT 89K. MPD 100% open. B/R full stand. Observe breathing on connections Rot/Recip conditioning hole @ 9940' MD. 260 gpm, 215-230 gpm out, 2035 psi, 120 rpm, 12.5k Tq. 475u Max gas @ btms up dropping to 35u BGG. Pumped 33 bbl 30 vis / 86 ppg followed by 36 bbl 70 vis / 10.2 ppg tandem sweep (back on time w/ 50% increase). Circulate 2x btms up. Shut down and monitor. Well showed breathing flowing from 125 gpm to 16 gpm over 11 min and continually trending down. BROOH F/ 9940' - T/ 7531' MD. 205 gpm w/ 70-85% returns, 1225 psi, 120 rpm, 9.4k Tq, 10.63 ECD. Pulling 25-35 fpm, slow to 10 fpm every 1000' for 1 stand. Saw complete losses @ 7531' MD. Tripped back in to 7580' MD and re-established circulation. Circulate and condition healing up losses while working pipe from 7580' up to 7515' MD. Pumped 35 bbl hi vis sweep. Saw 250u gas bump @ btms up. Sweep showed little increase in cuttings. Returns continually increased to 98% at end of cleanup cycle w/ 3.5x Btms up. 120 rpm, 9.3k tq, ECD's trended up from 10.4 to max of 11 before dropping back to 10.3 @ end of cleanup cycle. Cont. to BROOH from 7515' to 6524' at 205 gpm w/ 70-85% returns, 1225 psi, 120 rpms, 9-11Kft-lbs. Max gas 140u. Pull 5-25 fpm as hole dictates. Slow to 10 fpm every 1000' for 1 stand. P/U 144K, S/O 54K, ROT 77K. Lost returns at 6480'. Shut down pumps, RIH to 6524' and observe returns. Circulate bottoms up at 205 gpm, 98% returns, 1185 psi, 120 rpms, 7-8Kft-=lbs. Max gas 40 U. ECD 10.7 ppg, reciprocating pipe. Cont. to BROOH from 6524' to 5580' at 205 gpm w/ 70-85% returns, 1175 psi, 120 rpms, 8-10Kft-lbs. Max gas 154u. Pull 2-15 fpm as hole dictates. Slow to 10 fpm every 1000' for 1 stand. P/U 120K, S/O 48K, ROT 87K. Shut down rotary and pull BHA through window to 5540'. Observe 2-5K as stabs pull though window and 5-10 as I-cruse and bit comes through the window. Packed off while pulling BHA through window, slack off and re-establish circulation. Pump high vis sweep (on time, 50% increase) and circulate hole clean at 205 gpm, 93-95%, 1140 psi, 60 rpms, 6Kft-lbs, ECD 10.67 ppg EMW. Shut down and monitor well, no flow. Shut in MPD, no pressure build in 5 minutes. Blow down top drive and Geo-span. Distance to WP03: 3.96', 2.64' High, 2.95' Left Daily Disposal to G&I = 57 bbls, total = 1741 bbls. Daily H2O from Lake 2 = 580 bbls total = 3230 bbls. Daily Metal: 0 lb. Total Metal 150 lb. Daily DH Loss = 559 Total DH Loss = 1334. 4/1/2022 PJSM, Drain stack. Pull RCD bearing and install trip nipple. Lineup hole fill. Static loss rate 4 bph w/ 9.3 mud. POOH F/ 5453' - T/ 474' MD laying down 4" dp. P/U 45k, S/O 43k. Lost 14 bbls for trip out. B/O and L/D HWDP w/ jars. L/D flex DC's. Read MWD, B/O and L/D MWD tools. Severe wear on both stablizers and on Push pads for "ICruise" RSS. B/O "ICruise" and Read separately while hanging. BIt graded 4,4,A,BT,X,I,ER,TD. 1x float was found in open position due to excessive amount of Baracarbs packed around guide pin RIH with excess drill pipe from derrick to 4913'. P/U 92, S/O 56. Calc displacement 28 bbls, actual 16 bbls. POOH laying down drill pipe from 4913' to surface. Calc 28 bbls, actual 42 bbls. Pull wear bushing. Clean and clear rig floor. Pick up 20' pup joint and M/U to TCII XO for landing joint. M/U 10' pup joint and XO on top of cement head. M/U 5' pup to bottom of cement head. L/D in shed. Rig up to RIH with 3-1/2 completion. C/O elevators. Pick up job box, power tongs and rig up Tq turn. Rig up fill up line. Bring centralizers, and pup joints to rig floor. Stage jewelry in shed. RIH with 3- 1/2, 9.2#, L-80, JBear injection completion string. M/U shoe track, BakerLok, check floats - good. Cont. to RIH with 3-1/2" completion string as per detail to 1147', installing 'X' nipples and Side pocket mandrels as per tally. P/U 44K, S/O 43K. Daily Disposal to G&I = 57 bbls, total = 1798 bbls. Daily H2O from Lake 2 = 0 bbls total = 3230 bbls. Daily Metal: 13 lb. Total Metal 163 lb. Daily DH Loss = 54 Total DH Loss = 1388. 4/2/2022 RIH with 3-1/2, 9.2#, L-80, JBear completion string F/ 1147' - T/ 4824' MD installing 'X' nipples and side pocket mandrels as per tally. Fill on the fly, top off 10 jts. 30 bbl loss for tour (4 bph static loss rate). 9.3 ppg MW. ~100 FPM running speed. 3.85k tq on connections. P/U 64k, S/O 48k. Cont. RIH with 3-1/2, 9.2#, L-80, JBear completion string F/ 4824' - T/ 5439' MD installing centralizers as per tally. Fill on the fly, top off 10 jts. (4 bph static loss rate). 9.3 ppg MW. ~100 FPM running speed. 3.85k tq on connections. P/U 70k, S/O 46K Circulate bottoms up, staging pumps up to 6 bpm, 540 psi. Cont. RIH with 3-1/2, 9.2#, L-80, JBear completion string F/ 5439' - T/ 6261' MD Fill on the fly, top off 10 jts. 9.3 ppg MW, 4 bph static loss rate. ~100 FPM running speed. 3.85k tq on connections. P/U 70k, S/O 46K. Set down at 5798', no overpull. Attempt to work jewelry through window setting 5-12K down. Establish circulation and pump down at 3 bpm, 250 psi to 6261'. Cont. RIH with 3-1/2, 9.2#, L-80, JBear completion string F/ 6261' - T/ 7664' MD. 9.3 ppg MW, 4 bph static loss rate. ~20-50 FPM running speed. 3.85k tq on connections. P/U 86k, S/O 48K. Set down every 2-4 joints, with same block height, no overpull. Appears centralizers hanging up in window. Attempt to work through, unable to. M/U XO and screw in when set down. Pump down at 3 bpm, 340 psi when needed (every 2-4 joints). Observe no drag while setting down. Cont. RIH with 3-1/2, 9.2#, L-80, JBear completion string F/ 7664' - T/ 8085' MD. 9.3 ppg MW, 4 bph static loss rate. ~20-50 FPM running speed. 3.85k tq on connections. P/U 86k, S/O 48K. Hang up on centralizers every 2-4 joints, pump down at 3 bpm as needed. Circulate surface to surface staging pumps up to 5.5 bpm, 740 psi. 20-30 bph loss rate. Cont. to RIH with 3-1/2", L-80, JBear completion string F/ 8085' - T/9907' MD. 9.3 ppg MW, ~25-40 FPM running speed. 3.85k tq on connections. P/U 112k, S/O 50K. Final drilling report. Swap to completion AFE. Daily Disposal to G&I = 57 bbls, total = 1855 bbls. Daily H2O from Lake 2 = 220 bbls total = 3450 bbls. Daily Metal: 3 lb. Total Metal 166 lb. Daily DH Loss = 87 Total DH Loss = 1475. F/ 9700' to TD@9940' MD (5113' TVD) T JBear completion string F/ 8085' - T/9907' Activity Date Ops Summary 4/3/2022 M/U 3.5" hanger (4.5" TC II top connection) w/ landing jt. RIH and M/U BOT rotating cement head. S/O and landout on depth (23.16' RKB) with final set depth 9934' MD. P/U 112k, S/O 50k.,P/U and clear hanger from wellhead profile. Establish circulation and condition mud while staging up to 6 bpm, 1180 psi, 32% F/O (~10-15 BPH dynamic loss and gradually decreasing). Circulate and total of 605 bbls. Sim Ops - R/D WOT and L/D tools. P/U 112k, S/O 55k. 367u max gas @ btms up, ~30u BGG.,Shut down and landout hanger on depth w/ 20k string wt on hanger. RILDS. R/U return line from IA. Establish circulation staging up to 4 bpm, 657 psi, 26% F/O. Final dynamic loss rate - 9 BPH. Circulated a total of 248 bbls.,PJSM, Turn over to HES cmtrs. Flood lines with H2O, PT 1100 / 5000 psi. Leaking plug valve, C/O and retest (test good). Batch @ 12:33 hrs. Pump 40 bbl, 10 ppg tuned spacer, 2 bpm, 350 psi. 54 bbls 15.3 ppg Lead, 2 bpm, 215 psi, 1.236 yld (no lcm) 245 sxs,108 bbls 15.3 ppg Tail, 3 bpm, 380 psi, 1.242 yld (Bridgemaker lcm) 488 sxs. Drop Top dart (confirmed release). Chase with 5 bbls 9.3 brine. HES pump 5 bbls to clear lines to floor then turnover to Rig. Displace with 9.3 CI Brine, MP#1, 5 bpm to catch psi then slowed to 3 BPM. Full returns until 48 bbls into displace. Saw significant drop in returns, reduce rate to 2 bpm and regain lift psi and good returns until 61 bbls,Reduce rate to 1 bpm, 490 psi with good lift psi and full returns. Bumped plug @ 1299 stks (1300 calc). 890 FCP. Psi up 1400 psi w/ 3 min hold. Check floats (floats held). CIP @ 14:33. 25 bbl loss,B/D TDS. R/U and test 3.5" JFE Bear, 9.3#, L-80 tubing to 1500 psi w/ 30 min hold (leaking plug valve). Isolate valve and retest (test good). Chart and record same. 1/2 bbl pumped, 1/2 bbl bled back.,Turnover to HES cmtrs. Flood lines with H2O. Psi up to 4047 psi and observed burst disc shear. Turnover to Rig, Stg up 5 bpm, 1105 psi, circulate via Defender sub @ 4888' MD taking returns from IA. Saw spacer back @ shakers 1550 stks, Trace of cmt @ shakers indicated by 12 PH@ btms up. Dumped total 61 bbls spacer/brine. 3 bbl loss initial then flatlined.,Rig down cement line, break out and L/D cement head. L/D landing joint. Break off XO and 10' pup from cement head. Install TWC.,Flush cement line, stand pipe, top drive and choke manifold. Blow down lines. Drain stack.,N/D BOPE. Pull trip niplle and install MPD cap on bearing. Rig down hole fill line. Bleed accumulator and remove lines. R/D choke and kill lines. Remove chain binders, break bolts on MPD head and BOPS. Rack back stack. Pull riser spool and DSA. Sim Ops: Swap bushings to masters. Remove all XT-39 subs and handling equipment from rig floor.,Clean off hanger and inspect as per wellhead hand. Pick up tree, orient and set on well head. TQ flanges. Test tubing hanger void 500/5000 psi for 10 min. 4/4/2022 Test tree 250/5000 psi. Pull TWC. Sim Ops: Clean pits, secure shop for move, inspect mud pumps,Rig up Little Red Service and reverse circulate 90 bbls diesel for freeze protect at 2 bpm ICP 236 psi, FCP 482 psi. Line up and allow to U-tube. Rig down circulating lines. Sim Ops: Cont. cleaning pits, mud pump inspection.,Rig down. Bridle up lines to top drive. Pull plugs on centrifugal pumps, empty po-boy box and finish MP inspections. Cont. cleaning pits. Start rigging down interconnects. RDMO 06:00. Hilcorp Energy Company Composite Report Pump 40 bbl, 10 ppg tuned spacer, 2 bpm, 350 psi. 54 bbls 15.3 ppg Lead, 2 bpm, 215 psi, 1.236 yld (no lcm) 245 sxs,108 bbls 15.3 ppg Tail, 3 bpm, 380 psi, 1.242 yld (Bridgemaker lcm) 488 sxs. Drop Top dart (confirmed release). Chase with 5 bbls 9.3 brine. HES pump 5 bbls to clear lines to floor then turnover to Rig. Displace with 9.3 CI Brine, MP#1, 5 bpm to catch psi then slowed to 3 BPM. Full returns until 48 bbls into displace. Saw significant drop in returns, reduce rate to 2 bpm and regain lift psi and good returns until 61 bbls,Reduce rate to 1 bpm, 490 psi with good lift psi and full returns. Bumped plug @ 1299 stks (1300 calc). 890 FCP. Psi up 1400 psi w/ 3 min hold. Check floats (floats held). CIP @ 14:33. 25 bbl loss,B/D TDS. R/U and test 3.5" JFE Bear, 9.3#, L-80 tubing to 1500 psi w/ 30 min hold (leaking plug valve). Isolate valve and retest (test good). Chart and record same. 1/2 bbl pumped, 1/2 bbl bled back.,Turnover to HES cmtrs. Flood lines with H2O. Psi up to 4047 psi and observed burst disc shear. Turnover to Rig, Stg up 5 bpm, 1105 psi, circulate via Defender sub @ 4888' MD taking returns from IA. ACTIVITYDATE SUMMARY 4/6/2022 ***WELL S/I ON ARRIVAL*** (post rig) RIH W/ 2.5" SAMPLE BAILER AND UNABLE TO FALL PAST 2650' (70 DEG DEV.), POOH AND ADDED MORE ROLLER STEM ISSUES WITH CRANE AND ANOTHER ONE NOT AVAILABLE TILL MORNING, SO SWAP CRANES WITH ANOTHER UNIT (POLLARD #60), SO THAT JOB CAN PROCEED ***CONTINUE ON 4/7/22 WSR*** 4/7/2022 ***CONTINUED FROM 4/6/22*** DRIFT TO 9,520' SLM W/ 2.50" SAMPLE BAILER (RECOVERED 2 CUPS OF CEMENT) MADE 2 RUNS w/ 2-1/2" PUMP BAILER TO 9,678' SLM (tight from 9,500', recovered 1/2 gallon cement) RAN 2.70" GAUGE RING w/ 3-1/2" BRUSH TO 9,691' SLM RAN 2-1/2" PUMP BAILER TO 9,696' SLM, (tight from 9,420', no recovery) MADE 3 RUNS W/ 1 3/4" X 10' PUMP BAILER (recovered 1 1/2 gallons cement) @ 9,705' SLM SHIFT HP DEFENDER SLIDING SLEEVE CLOSED (UP TO CLOSE) @ 4,889' MD CRANE SWAP ***CONTINUED ON 4/8/22*** 4/8/2022 T/I/O=1330/168/VAC TEMP= SI Assist SL as directed (SIDETRACK) ** PRE- AOGCC MIT- T to 3200 PSI ( 3400 MAX APPLIED)** PASS ** ( SEE LOG) CMIT- TX IA to 3200 PSI ( 3400 MAX APPLIED) **FAILED ** COULDN'T REACH TEST PRESSURE ( SEE LOG ) S/L IN CONTROL OF WELL UPON DEPARTURE 4/8/2022 ***CONTINUED FROM 4/7/22*** RAN HES CBL FROM 9,575' SLM TO SURFACE (Good Data) LRS PERFORMED PASSING MIT-T LRS PERFORMED FAILING CMIT-TxIA SHIFTED SLIDING SLEEVE OPEN (confirmed t x ia comm.) ***WELL S/I ON DEPARTURE, PAD OP NOTIFIED*** 5/9/2022 ***WELL S/I ON ARRIVAL, DSO NOTIFIED***(set plug) SET QUADCO 3-1/2" CPB MID-ELEMENT AT 4942'. CCL TO MID-ELEMENT OFFSET: 9'. CCL STOP DEPTH: 4933'. CORRELATED TO TUBING TALLY RECORD DATED 2-APR-22. ***WELL LEFT S/I, TURNED OVER TO DSO*** 5/17/2022 CTU #9 - 1.75" Coil Job Objective: IA Cement Downsqueeze MIRU CTU. MU BOT 2.50" HB-3 sleeve shifting BHA. RIH & tag 3-1/2" CBP at 4928'. Pump 92 BBL's of diesel down the IA / up CTB to circulate out 9.3 ppg brine. Pump 100 BBL's of 110* KCL down the coil / up the CTB to warm up the pipe. Pump 15 BBL 13 ppg FineCem / 15 BBL 15.8 ppg class "G" cement. Displace all cement behind the sleeve at 4889' and overdisplace by ~ 2 BBL's of fresh water. Spot 10 BBL gel pill on top of plug and across the sleeve. Pump 3 BBL's of gel from TBG to IA, and then pump 3 BBL's IA to TBG to flush sleeve of residual cement. PU and close the sleeve at 4889'. Chase remaining gel OOH. Freeze protect the well to ~ 2500' TVD with diesel. Pump 10 BBL gel pill through the coil and chase with KCL. Freeze protect the coil with diesel and start weekly BOP test. ...Job in Progress.... Daily Report of Well Operations PBU V-227A CMIT- TX IA to 3200 PSI ( 3400 MAX APPLIED) **FAILED * ( MIT- T to 3200 PSI ( 3400 MAX APPLIED)** PASS () Daily Report of Well Operations PBU V-227A 5/18/2022 CTU #9 - 1.75" Coil Job Objective: IA Cement Downsqueeze, Mill CBP Complete Weekly BOP test. Standby for Cement to build compressive strength. MIT IA Failed to 2000 psi. Established a LLR of 0.5 bpm at 2050 psi. Will proceed to pump a second squeeze. MIT T PASSED to 2300 psi. Lost 159 psi in 15 mins, lost 43 2nd 15 mins, lost 6 psi 3rd 15 mins for total loss of 199 psi in 45 mins. MU & RIH w/ HB-3 shifting tool. Shift slidiing sleeve open at 4885' ctm using slick 1% kcl. Circulate diesel bottoms up. ***Continued on 05/19/22*** 5/19/2022 CTU #9 - 1.75" Coil Job Objective: IA Cement Downsqueeze, Mill CBP Finish turning the well over to diesel. Pooh. Swap HB-3 direction so it is now up to close. RIH and tag CBP, and paint white TD flag 5' above weight back. Pick up 50' above sliding sleeve. Pump 18.5 bbls of 15.8 ppg Class G cement through sleeve. Lay in remaing 5 bbls in coil and perform hesitations so that the last 2.2 bbls was spotted in the IA and overdisplaced 2 bbls at approximately 40 Bc. Circulate 2 bbls of diesel from IA to tubing to clear sleeve. Pumped 20 gel sweep and chase with slick kcl. Freeze protect the well to 2500' TVD with diesel. Standby for cement to harden. Est TOC ~4965' in IA. ***Continued on 05/20/22*** 5/20/2022 CTU #9 - 1.75" Coil ***Continued from WSR 5-19-22*** Job Objective: IA Downsqueeze, Mill CBP Wait on Cement. Attempt MIT-IA to 2000 psi, fail. MIT-T to 2000 psi Pass. IA leak rates of 0.3 bpm at 1880 psi, 0.5 bpm at 2170 psi, 0.9 bpm at 3000 psi. Will attempt 3rd cement squeeze. Make up sleeve shifting BHA. RIH and shift sleeve open. Pooh. Lay down HB-3 and swap direction to shift up to close. Standby for cement to be loaded out and tested. ***Continued on 05/21/22*** 5/21/2022 CTU #9 - 1.75" Coil Job Objective: IA Downsqueeze, Mill CBP Waiting on cement blend results. Make up Sleeve shifting BHA and RIH. Tag CBP. PUH 50' above sleeve and bullhead 20 bbls of 1% KCL. Established leak rate of 0.7 bpm at 2850 psi. Standby for cementers. ***Continued on 05/22/22*** 5/22/2022 CTU #9 - 1.75" Coil Job Objective: IA Downsqueeze, Mill CBP With Sleeve shifting BHA made up. Pump 27 bbls of 15.8 cement with high yield point and fluid loss. Lay-in while squeezing cement through sleeve due to excessive circulating friction in the coil. Squeeze 15 bbls behind pipe at 3000 psi on the IA until it appeared to fracture and able to inject cement at 0.5 bpm and 2700 psi. With 20 bbls through the sleeve, and 7 bbls remaining in the tubing, shut down and allow fracture to heal. Able to achieve cement squeeze to 2100 psi on IA. Contaminate cement in tubing with powervis and circulate 2.5 bbls of diesel from IA to tubing to ensure sleeve is clear. Shift sleeve closed and PT to 2000 psi. Continue to circulate Powervis and Slick KCl to jet tubing. FP coil and tubing with diesel to 3500'. Lay down tools and stadby for cement compressive strength. Est TOC at ~4890' in IA. Crew going to CTU #6 to complete operations. ...Continued on WSR 5-22-22... 3rd cement squeeze. Attempt MIT-IA to 2000 psi, fail. MIT-T to 2000 psi Pass. MITy IA Failed to 2000 p Daily Report of Well Operations PBU V-227A 5/23/2022 CTU #9 - 1.75" Coil ***Continued from WSR 5-22-22*** Job Objective: IA downsqueeze, mill CBP Crew complete operations on CTU #6. Attempt MIT-IA to 2000 psi, Fail. Liquid leak rate of 1.6 gpm and pressure loss of 53 psi/minute consistently. Rig down CTU, hand over to Fullbore for future MIT when cement is at full compresive strength. ....Job Incomplete... 5/26/2022 T/I/O= 250/300/0 TEMP= SI (CEMENT SQUEEZE) MITxT Target psi of 3200 psi. Pumped a total of .3 bbls of DSL down TBG to achieve test pressure. 1st 15 min TBG lost 90 psi // IA gained 5 psi 2nd 15min Tbg lost 20 // IA gained 0 psi. Pumped a total of 3 bbls of DSL down IA to achieve test pressure of 2250 psi Bled ~.8 bbls. Unable to obtain test due to pressure loss. Estimated LLR of .98 gal per min. Tags hung. Pad op notifed of well status upon departure. Well shut in upon departure. CV's = OTG FWHP's= 50/225/0 7/20/2022 CTU #9 1.75: CT Job Objective: IA Downsqueeze, Mill CBP MIRU CTU. Pump 1.188" drift ball. Perform BOP test 250/4000psi. Make up and RIH with BOT HB-3 shifting tool with tempress, oriented down to open. ***Job Continued on 7/21/2022*** 7/21/2022 CTU #9 1.75: CT Job Objective: IA Downsqueeze, Mill CBP Continue to RIH with BOT HB-3 shifting tool with tempress, oriented down to open. Tagged CBP and corrected depth. Shifted sleeve open and confirmed injectivity/communication with the IA. POOH and re-configure BHA for cementing and closing the sleeve. RIH to flag, circulate in 5 bbls of Fresh water & 2 bbls of FineCem in IA. Close choke and squeeze 4.2 bbls in iA. Circulate 2.3 bbls of 15.8 ppg Class G cement into IA. Squeeze 0.4 bbls into IA. Lay in 3.6 bbls of Class G and PUH to safelty. Squeeze 0.3 bbls into IA to 2559 psi. Lost 146 psi in 45 mins. RIH, contaminate cement, tag CBP. Made four attempts to shift sleeve closed but unable to locate profile. Pumped two bottoms up. POOH to inspect tools pumping pipe displacement. Tool looked good and still functional. RBIH with same BHA, tag plug at 4927' ctm. Shift sleeve closed, confirmed sleve closed on second up pass. PT tubing to 2100 psi. Circulated 10 bbl gel pill off bottom. FP coil and tubing with diesel from 3500'. Lay down tools and wait for compressive strength. Est TOC ~4661 in IA. ***Job Continued on 7/22/2022*** 7/22/2022 CTU #9 1.75: CT Job Objective: IA Downsqueeze, Mill CBP Continue to wait for compressive strength. Perform Passing MIT IA to 2000 psi. Lost 38/17 psi on second test. Make up Baker 2-1/8' Milling BHA w/ 2.80" junk mill. Milled CBP and begin pushing plug to TD. ***Continued on 07/23/22*** Attempt MIT-IA to 2000 psi, Fail. : IA Downsqueeze, Circulate 2.3 bbls of 15.8 ppg Class Gg cement into IA. Squeeze 0.4 bbls into IA. Lay in 3.6 bbls of Class G and PUH toy safelty. Squeeze 0.3 bbls into IA to 2559 psi. L MIT IA to 2000 psi. Lost 38/17 psi on second test. Daily Report of Well Operations PBU V-227A 7/23/2022 CTU #9 1.75: CT Job Objective: IA Downsqueeze, Mill CBP Continue pushing plug to TD. Stop making progress at 5558. POOH and check mill. Swap to 2.77" less agressive mill. RIH and tag at 5562. Begin milling. Still could not make progress. POOH for venturi burnshoe. Lay down mill. Had wear on outer edges but nothing on face. . Make up 2.72" venturi/burnshoe. RIH and tag at 5562'. Had three stall. POOH to inpspect venturi. Recover 1 element and slivers of metal cuttings. Make up a 2.80" paraboilc speed mill. Tagged at 5562 and made progress down to 5614. Attempt to PT wellbore and will not hold. Overpulled at sliding sleeve coming out - sleeve was tagged while running in with mill and may have opened. Mill had nominal wear. Make up BO shifting tool BHA. ***Job Continued on 7/24/2022*** 7/24/2022 CTU #9 1.75: CT Job Objective: IA Downsqueeze, Mill CBP Make up and RIH with slickline 42 BO shifting tool. Tagged sleeve at 4885. Brought pump online and made it through. Pulled up hole dry repeatedly with no overpull. Jetted across sleeve and pulled back up to close again and still no response. POOH to inspect tools. Shifting tool not sheared. Make up and RIH with motor and 2.72" venturi/burnshoe. Tag at 5561', unable make any progress. POOH. Burnshoe and Venturi screen packed with cement. Decision made to RD and turn over to slickline. RIH with 2.50" nozzle and circulate in diesel freeze protect from 3500'. RDMOL. ***Job Incomplete*** TD Shoe Depth: PBTD: No. Jts. Returned RKB RKB to BHF RKB to THF Jts. Yes X No Yes X No 30 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: 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: Pup Joint Pup Joint Pup Joint Casing (Or Liner) Detail Float Shoe Pup Joint Tubing 5 1/2 9.2 L-80 120.15 10.5108.7 Rotate Csg Recip Csg Ft. Min. PPG9.3 Shoe @ 9934.04 FC @ Top of Liner9,833.35 Floats Held 125.5 162 0.1 137 Brine CASING RECORD County State Alaska Supv. Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.PBW V-227A Date Run 2-Apr-22 Setting Depths Component Size Wt. Grade THD Make Length Bottom Top IBT DHS 1.47 9,334.04 9,332.57 9,719.68 9,694.82 10.01 9,788.59 9,778.58 9,778.583 1/2 9.2 L-80 JFE Bear 58.90 JFE Bear 3 1/2 9.2 L-80 JFE Bear Baker Hughes 9,719.68 JFE Bear 28.93 3 1/2 9.2 3 1/2 9.2 L-80 tubing 3 1/2 9.2 L-80 9,682.75 24.86 L-80 JFE Bear e Pocket Mandrel 5 1/2 9.2 L-80 JFE Bear 9,642.60 L-80 9.98 9,653.823 1/2 9,632.61 9,694.82 9,687.67 4.92 9,687.67 9,682.75 9.99 9,643.84 7.15 1.24 Csg Wt. On Hook:55,000 Type Float Collar:Conventional No. Hrs to Run:32.5 L-80 JFE Bear Pup Joint 3 1/2 9.3 1 91 890FIRST STAGE10Tuned Spacer 40 3 1/2 90.5/90.6 1400 0.1 Rig 15.3 108 Bump press Returns after opening SS Bump Plug? 14:33 4/3/2022 4,888 9,934.049,940.00 9,833.95 CEMENTING REPORT Csg Wt. On Slips: Tubing Baradril L-80 JFE Bear 15.3 54 JFE Bear9.2 9.2 9,603.39 9,653.82 29.22 9,632.61 9,643.84 9,642.60 RKB to CHF Type of Shoe:Bullnose Casing Crew:Weatherford No. Jts. Delivered 340 No. Jts. Run 322 18 Length Measurements W/O Threads Ftg. Delivered Ftg. Run Ftg. Returned Ftg. Cut Jt. Ftg. Balance www.wellez.net WellEz Information Management LLC ver_04818br 3 2 per joint with stop ring in middle from 8775' to 4903' ('X' nipple #6 to sliding sleeve) Tubing 3 1/2 9.2 L-80 IBT 31.31 9,332.57 9,301.26 Float Collar 4 1/2 L-80 IBT DHS 1.14 9,901.26 9,900.12 Tubing 3 1/2 9.2 L-80 IBT 31.47 9,900.12 9,868.65 Crossover 3 1/2 9.2 L-80 JFE x Vam 33.42 9,868.65 9,835.23 Landing collar 4 1/2 9.2 L-80 VAM Baker Hughes 1.28 9,835.23 9,833.95 Crossover 3 1/2 9.2 L-80 VAM x JFE 4.92 9,833.95 9,829.03 Tubing 3 1/2 9.2 L-80 JFE Bear 29.22 9,829.03 9,799.81 Pup Joint 3 1/2 9.2 L-80 JFE Bear 9.98 9,799.81 9,789.83 Nipple 4 1/2 9.2 L-80 JFE Bear 1.24 9,789.83 9,788.59 Nipple 4 1/2 9.2 L-80 JFE Bear Type I/II 245 1.24 Type I/II 488 1.24 2 X 'HILQLWLYH6XUYH\5HSRUW $SULO +LOFRUS1RUWK6ORSH//& 3UXGKRH%D\ 9 9$ 3URMHFW &RPSDQ\ /RFDO&RRUGLQDWH5HIHUHQFH 79'5HIHUHQFH 6LWH +LOFRUS1RUWK6ORSH//& 3UXGKRH%D\ 9 'HILQLWLYH6XUYH\5HSRUW :HOO :HOOERUH 9 9$6XUYH\&DOFXODWLRQ0HWKRG0LQLPXP&XUYDWXUH $FWXDO#XVIW 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Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Rixse, Melvin G (OGC) To:AOGCC Records (CED sponsored) Subject:20220726 1143 INOPERABLE NOTE V-227A (PTD# 222-020) Milling Issues Date:Tuesday, July 26, 2022 2:56:52 PM From: Rixse, Melvin G (OGC) Sent: Tuesday, July 26, 2022 11:43 AM To: Wyatt Rivard <wrivard@hilcorp.com> Subject: RE: V-227A (PTD# 222-020) Milling Issues Wyatt, Approved to close out the existing sundry and 10-401. You should be able to include all in a 10- 407. Good luck with your remedial planning. As it stands. This well is inoperable. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Wyatt Rivard <wrivard@hilcorp.com> Sent: Tuesday, July 26, 2022 11:18 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: V-227A (PTD# 222-020) Milling Issues Hello Mel, We recently completed a successful remedial IA cement squeeze on new sidetrack V-227A (PTD 222- 020) under sundry #322-228 (attached). Following the passing MIT-IA to 2000 psi, we proceeded to mill out the CBP that had been set at 4943’MD for the squeeze. We found the CBP difficult to mill/establish torque but were able to get it moving. After we pushed it ~500’ we slowed down significantly and continued milling/pushing another 50’. Unfortunately at this point it appears we nicked/damaged the 3.5” liner. We established a leakoff rate of .5BPM where before we were able to MIT the entire 3.5” liner up to 3200 psi. With the slow milling progress and loss of 3.5” liner integrity, we decided to forgo trying to mill/push CBP to bottom and rigged down coil. At this point we’d like to go ahead and close out existing sundry and original 10-401. If we identify a plan to complete work and remediate leak, we will submit a new sundry that includes any testing/logging requirements from the Sundry # 322-228 conditions of approval. Please let me know if you have an questions. Thank You, Wyatt Rivard | Operations Engineer (PBU: J, Q, S, U, W pads)O: (907) 777-8547 | C: (509)670-8001 | wrivard@hilcorp.comHilcorp Alaska, LLC | Anchorage, AK 99503 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 05/17/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL PBU V-227A (PTD 222-020) RBT 04/08/2022 Please include current contact information if different from above. 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GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 4/13/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL V-227A (PTD 214-112) RBT 4/08/2022 with Record Please include current contact information if different from above. 222-020 T36475 Meredith Guhl Digitally signed by Meredith Guhl Date: 2022.04.13 15:01:15 -08'00' From:Rixse, Melvin G (OGC) To:AOGCC Records (CED sponsored) Subject:20220413 1030 Response V-227A (PTD #222-020) 3_5_ Completion Cement Job Report Date:Wednesday, April 13, 2022 10:32:08 AM Attachments:PBW_V-227A_Csg-Cmt_2.pdf PBW_V-227A_HEC_Composite_Completion.pdf From: Wyatt Rivard <wrivard@hilcorp.com> Sent: Wednesday, April 13, 2022 9:51 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Engel <jengel@hilcorp.com> Subject: FW: [EXTERNAL] RE: V-227A (PTD #222-020) 3.5" Completion Cement Job Report Mel, Please see the daily operations report for the entire day of 4/3/22 including the cement job along with our casing and cementing report attached. Please note that casing and cementing report’s estimated TOC of 4,888’ (Sliding Sleeve) was estimated based on volumes pumped, returned and circulated above sliding sleeve. This was picked prior to eline logging TOC at the window at ~5480’ MD. Thank You, Wyatt Rivard | Operations Engineer (PBU: J, Q, R, S, U, W pads)O: (907) 777-8547 | C: (509)670-8001 | wrivard@hilcorp.comHilcorp Alaska, LLC | Anchorage, AK 99503 From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Tuesday, April 12, 2022 5:07 PM To: Wyatt Rivard <wrivard@hilcorp.com> Cc: Joseph Engel <jengel@hilcorp.com> Subject: [EXTERNAL] RE: V-227A (PTD #222-020) 3.5" Completion Cement Job Report Wyatt, Do you have the rig operations report for this cement job? The Halliburton cementing report seems to only cover through the burst disk at 4047 psi. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. Joe Engel From: Rixse, Melvin G (OGC) Sent: Tuesday, April 12, 2022 3:50 PM To: Wyatt Rivard <wrivard@hilcorp.com> Cc: Joseph Engel <jengel@hilcorp.com> Subject: RE: V-227A (PTD #222-020) 3.5" Completion Cement Job Report Wyatt, Three questions: 1. Please explain why you have good cement bond from 1250’ MD to 4884’ MD. 2. Why would good cement bond of 3630’ MD allow a failed MIT-IA? 3. Have I made the correct assumption that the burst disk is in the sliding sleeve at 4889’ MD? Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Wyatt Rivard <wrivard@hilcorp.com> Sent: Monday, April 4, 2022 2:28 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Engel <jengel@hilcorp.com> Subject: RE: V-227A (PTD #222-020) 3.5" Completion Cement Job Report Mel, One correction to below. While pumping initial displacement rates of 2-3 bpm we did see some losses. We decreased displacement rate to ~ 1 BPM and regained full returns. Total loss was 25 bbls out of 162 bbls cement pumped. Thank You, Wyatt Rivard | Operations Engineer (PBU: J, Q, R, S, U, W pads)O: (907) 777-8547 | C: (509)670-8001 | wrivard@hilcorp.comHilcorp Alaska, LLC | Anchorage, AK 99503 From: Wyatt Rivard Sent: Monday, April 4, 2022 11:39 AM To: 'melvin.rixse@alaska.gov' <melvin.rixse@alaska.gov> Cc: Joseph Engel <jengel@hilcorp.com> Subject: V-227A (PTD #222-020) 3.5" Completion Cement Job Report Hello Mel, Per the V-227A (PTD #222-020) 10-401 conditions of approval please see attached cementing report from the cement job on the 3.5” completion for this well. Well service report also included below for reference. We had full returns throughout the job, bumped plug then successfully sheared out our sliding sleeve at ~4890’ MD, returning traces of cement. A follow-up CBL will be logged as part of slickline post rig work. Log and interpretation report will be provided as soon as we have it. 4/3/22 Cement Job Service Report Circulate hole clean staging up to 6 bpm. R/U cementers and continue circulating hole clean. Landout hanger, RILDS and rig up on IA. Establish circulation. PJSM, Pump 15.3 ppg cement as per proposed cement detail. CIP @ 14:30 hrs. Test 3.5” tubing to 1500 psi w/ 30 min hold (test good). Burst disc on circ sub, establish circulation and circulate out excess mud push and trace of cmt from IA Thank You, Wyatt Rivard | Operations Engineer (PBU: J, Q, R, S, U, W pads)O: (907) 777-8547 | C: (509)670-8001 | wrivard@hilcorp.comHilcorp Alaska, LLC | Anchorage, AK 99503 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Activity Date Ops Summary 4/3/2022 M/U 3.5" hanger (4.5" TC II top connection) w/ landing jt. RIH and M/U BOT rotating cement head. S/O and landout on depth (23.16' RKB) with final set depth 9934' MD. P/U 112k, S/O 50k.,P/U and clear hanger from wellhead profile. Establish circulation and condition mud while staging up to 6 bpm, 1180 psi, 32% F/O (~10-15 BPH dynamic loss and gradually decreasing). Circulate and total of 605 bbls. Sim Ops - R/D WOT and L/D tools. P/U 112k, S/O 55k. 367u max gas @ btms up, ~30u BGG.,Shut down and landout hanger on depth w/ 20k string wt on hanger. RILDS. R/U return line from IA. Establish circulation staging up to 4 bpm, 657 psi, 26% F/O. Final dynamic loss rate - 9 BPH. Circulated a total of 248 bbls.,PJSM, Turn over to HES cmtrs. Flood lines with H2O, PT 1100 / 5000 psi. Leaking plug valve, C/O and retest (test good). Batch @ 12:33 hrs. Pump 40 bbl, 10 ppg tuned spacer, 2 bpm, 350 psi. 54 bbls 15.3 ppg Lead, 2 bpm, 215 psi, 1.236 yld (no lcm) 245 sxs,108 bbls 15.3 ppg Tail, 3 bpm, 380 psi, 1.242 yld (Bridgemaker lcm) 488 sxs. Drop Top dart (confirmed release). Chase with 5 bbls 9.3 brine. HES pump 5 bbls to clear lines to floor then turnover to Rig. Displace with 9.3 CI Brine, MP#1, 5 bpm to catch psi then slowed to 3 BPM. Full returns until 48 bbls into displace. Saw significant drop in returns, reduce rate to 2 bpm and regain lift psi and good returns until 61 bbls,Reduce rate to 1 bpm, 490 psi with good lift psi and full returns. Bumped plug @ 1299 stks (1300 calc). 890 FCP. Psi up 1400 psi w/ 3 min hold. Check floats (floats held). CIP @ 14:33. 25 bbl loss,B/D TDS. R/U and test 3.5" JFE Bear, 9.3#, L-80 tubing to 1500 psi w/ 30 min hold (leaking plug valve). Isolate valve and retest (test good). Chart and record same. 1/2 bbl pumped, 1/2 bbl bled back.,Turnover to HES cmtrs. Flood lines with H2O. Psi up to 4047 psi and observed burst disc shear. Turnover to Rig, Stg up 5 bpm, 1105 psi, circulate via Defender sub @ 4888' MD taking returns from IA. Saw spacer back @ shakers 1550 stks, Trace of cmt @ shakers indicated by 12 PH@ btms up. Dumped total 61 bbls spacer/brine. 3 bbl loss initial then flatlined.,Rig down cement line, break out and L/D cement head. L/D landing joint. Break off XO and 10' pup from cement head. Install TWC.,Flush cement line, stand pipe, top drive and choke manifold. Blow down lines. Drain stack.,N/D BOPE. Pull trip niplle and install MPD cap on bearing. Rig down hole fill line. Bleed accumulator and remove lines. R/D choke and kill lines. Remove chain binders, break bolts on MPD head and BOPS. Rack back stack. Pull riser spool and DSA. Sim Ops: Swap bushings to masters. Remove all XT-39 subs and handling equipment from rig floor.,Clean off hanger and inspect as per wellhead hand. Pick up tree, orient and set on well head. TQ flanges. Test tubing hanger void 500/5000 psi for 10 min. Test tree 250/5000 psi. Pull TWC. Sim Ops: Clean pits, secure shop for move, inspect mud pumps,Rig up Little Red Service and reverse circulate 90 bbls diesel for freeze protect at 2 bpm ICP 236 psi, FCP 482 psi. Line up and allow to U-tube. Rig down circulating lines. Sim Ops: Cont. cleaning pits, mud pump inspection.,Rig down. Bridle up lines to top drive. Pull plugs on centrifugal pumps, empty po-boy box and finish MP inspections. Cont. cleaning pits. Start rigging down interconnects. Hilcorp Energy Company Composite Report TD Shoe Depth:PBTD: No. Jts. Returned RKB RKB to BHF RKB to THF Jts. Yes X No Yes X No 30 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: 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: Pup Joint Pup Joint Pup Joint Casing (Or Liner) Detail Float Shoe Pup Joint Tubing 5 1/2 9.2 L-80 120.15 10.5108.7 Rotate Csg Recip Csg Ft. Min.PPG9.3 Shoe @ 9934.04 FC @ Top of Liner9,833.35 Floats Held 125.5 162 0.1 137 Brine CASING RECORD County State Alaska Supv. Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.PBW V-227A Date Run 2-Apr-22 Setting Depths Component Size Wt.Grade THD Make Length Bottom Top IBT DHS 1.47 9,334.04 9,332.57 9,719.68 9,694.82 10.01 9,788.59 9,778.58 9,778.583 1/2 9.2 L-80 JFE Bear 58.90 JFE Bear 3 1/2 9.2 L-80 JFE Bear Baker Hughes 9,719.68 JFE Bear 28.93 3 1/2 9.2 3 1/2 9.2 L-80 tubing 3 1/2 9.2 L-80 9,682.75 24.86 L-80 JFE Bear Side Pocket Mandrel - 1"5 1/2 9.2 L-80 JFE Bear 9,642.60 L-80 9.98 9,653.823 1/2 9,632.61 9,694.82 9,687.67 4.92 9,687.67 9,682.75 9.99 9,643.84 7.15 1.24 Csg Wt. On Hook:55,000 Type Float Collar:Conventional No. Hrs to Run:32.5 L-80 JFE Bear Pup Joint 3 1/2 9.3 1 91 890FIRST STAGE10Tuned Spacer 40 3 1/2 90.5/90.6 1400 0.1 Rig 15.3 108 Bump press Returns after opening SS Bump Plug? 14:33 4/3/2022 4,888 9,934.049,940.00 9,833.95 CEMENTING REPORT Csg Wt. On Slips: Tubing Baradril L-80 JFE Bear 15.3 54 JFE Bear9.2 9.2 9,603.39 9,653.82 29.22 9,632.61 9,643.84 9,642.60 RKB to CHF Type of Shoe:Bullnose Casing Crew:Weatherford No. Jts. Delivered 340 No. Jts. Run 322 18 Length Measurements W/O Threads Ftg. Delivered Ftg. Run Ftg. Returned Ftg. Cut Jt.Ftg. Balance www.wellez.net WellEz Information Management LLC ver_04818br 3 2 per joint with stop ring in middle from 8775' to 4903' ('X' nipple #6 to sliding sleeve) Tubing 3 1/2 9.2 L-80 IBT 31.31 9,332.57 9,301.26 Float Collar 4 1/2 L-80 IBT DHS 1.14 9,901.26 9,900.12 Tubing 3 1/2 9.2 L-80 IBT 31.47 9,900.12 9,868.65 Crossover 3 1/2 9.2 L-80 JFE x Vam 33.42 9,868.65 9,835.23 Landing collar 4 1/2 9.2 L-80 VAM Baker Hughes 1.28 9,835.23 9,833.95 Crossover 3 1/2 9.2 L-80 VAM x JFE 4.92 9,833.95 9,829.03 Tubing 3 1/2 9.2 L-80 JFE Bear 29.22 9,829.03 9,799.81 Pup Joint 3 1/2 9.2 L-80 JFE Bear 9.98 9,799.81 9,789.83 Nipple 4 1/2 9.2 L-80 JFE Bear 1.24 9,789.83 9,788.59 Nipple 4 1/2 9.2 L-80 JFE Bear Type I/II 245 1.24 Type I/II 488 1.24 2 From:Rixse, Melvin G (OGC) To:AOGCC Records (CED sponsored) Subject:20220413 0909 CBL Interpretation from Hilcorp PTD222-020 Second Response Date:Wednesday, April 13, 2022 9:11:46 AM Attachments:image001.png V-227A_RBT_08APR22_ProcessedLog-V1-compressed.pdf V-227A (PTD#220-020) 3.5 Completion Cement Bond Log.msg From: Wyatt Rivard <wrivard@hilcorp.com> Sent: Wednesday, April 13, 2022 6:23 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Engel <jengel@hilcorp.com> Subject: RE: [EXTERNAL] RE: V-227A (PTD #222-020) 3.5" Completion Cement Job Report Mel, Please see my answers below in red. I can come by next week with the paper logs and go through the results in person if that is helpful for discussion. 1. Please explain why you have good cement bond from 1250’ MD to 4884’ MD. a. The intervals and bond value summary provided by our logging vendor (included in italics in attached email) only speaks to the interface in direct contact with the backside of the 3.5” tubing. The values do not quantify the overall bond between 3.5” tubing, cement and the 7” casing. Each radial sensor (shown individually on attached post processed log) detects an amplitude. When the majority of the radial sensors detect decreased amplitudes when compared to free pipe then they will assume that the pipe is bonded to and attenuated by cement regardless of how thick that cement is or if it’s bonded to the next casing/formation. The vendor confirmed that a cement sheath or cement contamination on the backside of the 3.5” could show up as a high bond index even if the cement is not bonded to the outer 7” casing. They reiterated that, to qualify the overall tubing- cement-casing bond, you have to evaluate the VDL image. VDL is the only reading that shows the portion of waveform that includes cement to casing/formation returns. The V-227A VDL (circled below) shows that there is little attenuation of the waveform as evidenced by the lack of “smearing ” above the vendor picked TOC of 5480’. Additionally the overall CBL amplitude is quite high above the TOC providing another data point that continuous tubing-cement-casing bond only exists below 5480’ MD. 2. Why would good cement bond of 3630’ MD allow a failed MIT-IA? a. The vendor’s description of “good bond cement” only refers to direct contact with the backside of the 3.5” tubing. It does not describe the overall tubing-cement- casing bond which is instead qualified by the VDL. We see minimal smearing/attenuation of the VDL tracks and an overall high CBL amplitude above the millout window. This indicates that, while there may be cement sheath/stringers on the backside of the 3.5”tubing, there is no continuous bond between the tubing, cement and casing above the millout window. 3. Have I made the correct assumption that the burst disk is in the sliding sleeve at 4889’ MD? a. That’s correct, the burst disk was in the sliding sleeve. After cementing and bumping the plug, the burst disk was sheared to circulate excess cement from above the sleeve. Slickline then shifted the sleeve closed post rig and obtained a pre MIT-T to 3200 psi before establishing an injection rate down the IA. Thank You, Wyatt Rivard | Operations Engineer (PBU: J, Q, R, S, U, W pads)O: (907) 777-8547 | C: (509)670-8001 | wrivard@hilcorp.com CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Hilcorp Alaska, LLC | Anchorage, AK 99503 From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Tuesday, April 12, 2022 3:50 PM To: Wyatt Rivard <wrivard@hilcorp.com> Cc: Joseph Engel <jengel@hilcorp.com> Subject: [EXTERNAL] RE: V-227A (PTD #222-020) 3.5" Completion Cement Job Report Wyatt, Three questions: 1. Please explain why you have good cement bond from 1250’ MD to 4884’ MD. 2. Why would good cement bond of 3630’ MD allow a failed MIT-IA? 3. Have I made the correct assumption that the burst disk is in the sliding sleeve at 4889’ MD? Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Wyatt Rivard <wrivard@hilcorp.com> Sent: Monday, April 4, 2022 2:28 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Engel <jengel@hilcorp.com> Subject: RE: V-227A (PTD #222-020) 3.5" Completion Cement Job Report Mel, One correction to below. While pumping initial displacement rates of 2-3 bpm we did see some losses. We decreased displacement rate to ~ 1 BPM and regained full returns. Total loss was 25 bbls out of 162 bbls cement pumped. Thank You, Wyatt Rivard | Operations Engineer (PBU: J, Q, R, S, U, W pads)O: (907) 777-8547 | C: (509)670-8001 | wrivard@hilcorp.comHilcorp Alaska, LLC | Anchorage, AK 99503 From: Wyatt Rivard Sent: Monday, April 4, 2022 11:39 AM To: 'melvin.rixse@alaska.gov' <melvin.rixse@alaska.gov> Cc: Joseph Engel <jengel@hilcorp.com> Subject: V-227A (PTD #222-020) 3.5" Completion Cement Job Report Hello Mel, Per the V-227A (PTD #222-020) 10-401 conditions of approval please see attached cementing report from the cement job on the 3.5” completion for this well. Well service report also included below for reference. We had full returns throughout the job, bumped plug then successfully sheared out our sliding sleeve at ~4890’ MD, returning traces of cement. A follow-up CBL will be logged as part of slickline post rig work. Log and interpretation report will be provided as soon as we have it. 4/3/22 Cement Job Service Report Circulate hole clean staging up to 6 bpm. R/U cementers and continue circulating hole clean. Landout hanger, RILDS and rig up on IA. Establish circulation. PJSM, Pump 15.3 ppg cement as per proposed cement detail. CIP @ 14:30 hrs. Test 3.5” tubing to 1500 psi w/ 30 min hold (test good). Burst disc on circ sub, establish circulation and circulate out excess mud push and trace of cmt from IA Thank You, Wyatt Rivard | Operations Engineer (PBU: J, Q, R, S, U, W pads)O: (907) 777-8547 | C: (509)670-8001 | wrivard@hilcorp.comHilcorp Alaska, LLC | Anchorage, AK 99503 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that anydissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual orentity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted bythe company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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 or fax to 907 564-4422. Received By: Date: Hilcorp North Slope, LLC Date: 04/12/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL:V-227A PTD: 222-020 API: 50-029-23417-01-00 FINAL LWD FORMATION EVALUATION LOGS (03/26/2022 to 03/31/2022) GM, ADR (2” & 5” MD/TVD Color Logs) Final Definitive Directional Surveys SFTP Transfer - Data Folders: Please include current contact information if different from above. 222-020 T36469 Meredith Guhl Digitally signed by Meredith Guhl Date: 2022.04.12 11:53:36 -08'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Rixse, Melvin G (OGC) To:AOGCC Records (CED sponsored) Subject:20220412 1212 CBL V-227A (PTD#220-020) 3_5_ Completion Cement Bond Log Date:Tuesday, April 12, 2022 3:01:58 PM Attachments:V-227A_RBT_08APR22_Optimized-compressed.pdf From: Wyatt Rivard <wrivard@hilcorp.com> Sent: Monday, April 11, 2022 12:11 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: V-227A (PTD#220-020) 3.5" Completion Cement Bond Log Hello Mel, We ran the newly drilled V-227A (PTD#220-020) cement bond log on Friday 4/8/22(attached). The bond log showed good cement across the entire injection interval all the way up to the 7” millout window at ~5500’ MD. Unfortunately TOC did not extend up into the 3.5”x7” annulus and we did not achieve a cement packer isolation. Subsequent pre AOGCC CMIT-TxIA failed at ~ 1BPM leak rate. It appears that we have the same issue as V-213A despite mitigations such as squeezing the window and increasing the cement lap. Please see service provider cement quality report as well as additional bond log interpretation below. Service Provider Cement Quality Report Cement quality from the bottom to the top: From the bottom-5482 ft: very good bond cement with 100% bond index throughout. 5368-5482 ft MD: good bond cement with average bond index of 73% 4884 (sliding sleeve depth) to 5368 ft MD: patchy cement bond with average of 30% bond in the patchy section. 2660-4884 ft MD: good bond cement with average bond index of 84% 1250-2660 ft MD: good bond cement with average bond index of 94% 520-1250 ft MD: good bond cement with average bond index of 71% 0-520 ft MD: mostly free pipe with some poor bond cement (bond index of 10-20%) Additional V-227A Bond Log Evaluation Isolation of Injection Fluids - Achieved The CBL confirmed excellent cement bond across and above the injection interval from top of injection at ~8820’ MD up to TOC at ~5480’ MD. In this instance excellent bond is attributed to CBL amplitudes <10 mv and heavy VDL attenuation and formation returns. There is no indication of channeling in the cement map/image. Monitorable Annulus - Achieved TOC picked at 5480’, ~490’ below the sliding sleeve confirms an uncemented, monitorable, annulus down to at least target depth of 4900’ MD. Subsequent CMIT-TxIA was performed following a passing MIT-T with sliding sleeve closed, confirming full 3.5”x7” annulus is in communication currently. Annular Isolation/Cement Packer –*Remediation Required* The CBL shows excellent bond from bottom to TOC picked at ~5480’MD. The 3.5”x7” annulus appears to have minimal/poor bond with near free pipe amplitudes from ~5480’ MD up to the sliding sleeve at ~4990’ MD. CMIT failed at ~1 BPM at 1000 psi confirming that we do not have annular isolation between 3.5”x7”. During the cement job we initially had losses (25 bbls total) during displacement rates of ~2-3 bpm before decreasing displacement to ~1 bpm and gaining full returns. We suspect that the initial losses combined with fluid interactions at the uncemented window resulted in our low TOC. Path forward I am preparing a CTU cement squeeze sundry that I will submit separately to straddle and squeeze cement through the sliding sleeve at 4900’ which should successfully remediate the cement packer isolation. Relogging the CBL along with additional bond log evaluation will be included in the remedial squeeze program. Based on V-213A and V-227A TOC challenges, there are no more cemented completions of this type planned. Please let me know if you have any questions or need any additional information. Thank You, Wyatt Rivard | Operations Engineer (PBU: J, Q, R, S, U, W pads)O: (907) 777-8547 | C: (509)670-8001 | wrivard@hilcorp.comHilcorp Alaska, LLC | Anchorage, AK 99503 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Rixse, Melvin G (OGC) To:AOGCC Records (CED sponsored) Subject:20220404 1428 V-227A (PTD #222-020) 3_5_ Completion Cement Job Report Date:Monday, April 4, 2022 2:35:16 PM Attachments:V-227A Cement Job Log.docx From: Wyatt Rivard <wrivard@hilcorp.com> Sent: Monday, April 4, 2022 2:28 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Engel <jengel@hilcorp.com> Subject: RE: V-227A (PTD #222-020) 3.5" Completion Cement Job Report Mel, One correction to below. While pumping initial displacement rates of 2-3 bpm we did see some losses. We decreased displacement rate to ~ 1 BPM and regained full returns. Total loss was 25 bbls out of 162 bbls cement pumped. Thank You, Wyatt Rivard | Operations Engineer (PBU: J, Q, R, S, U, W pads)O: (907) 777-8547 | C: (509)670-8001 | wrivard@hilcorp.comHilcorp Alaska, LLC | Anchorage, AK 99503 From: Wyatt Rivard Sent: Monday, April 4, 2022 11:39 AM To: 'melvin.rixse@alaska.gov' <melvin.rixse@alaska.gov> Cc: Joseph Engel <jengel@hilcorp.com> Subject: V-227A (PTD #222-020) 3.5" Completion Cement Job Report Hello Mel, Per the V-227A (PTD #222-020) 10-401 conditions of approval please see attached cementing report from the cement job on the 3.5” completion for this well. Well service report also included below for reference. We had full returns throughout the job, bumped plug then successfully sheared out our sliding sleeve at ~4890’ MD, returning traces of cement. A follow-up CBL will be logged as part of slickline post rig work. Log and interpretation report will be provided as soon as we have it. 4/3/22 Cement Job Service Report Circulate hole clean staging up to 6 bpm. R/U cementers and continue circulating hole clean. Landout hanger, RILDS and rig up on IA. Establish circulation. PJSM, Pump 15.3 ppg cement as per proposed cement detail. CIP @ 14:30 hrs. Test 3.5” tubing to 1500 psi w/ 30 min hold (test good). Burst disc on circ sub, establish circulation and circulate out excess mud push and trace of cmt from IA Thank You, Wyatt Rivard | Operations Engineer (PBU: J, Q, R, S, U, W pads)O: (907) 777-8547 | C: (509)670-8001 | wrivard@hilcorp.comHilcorp Alaska, LLC | Anchorage, AK 99503 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. HILCORP ALASKA LLC - EBUS For: SHANE BARBER Date: Sunday, April 03, 2022 V-227, Production SO: 907780134 Job Date: Sunday, April 03, 2022 Sincerely, Bret Smith Legal Notice Disclaimer: All information in this report is provided subject to the terms and conditions which govern the services provided by Halliburton. Halliburton personnel use their best efforts in gathering information and their best judgment in interpreting it, but any interpretation, research, analysis or recommendation furnished by Halliburton are opinions based upon inferences from measurements and empirical relationships and assumptions, which inferences and empirical relationships and assumptions are not infallible, and with respect to which professionals in the industry may differ. iCem 3D Displacement results are used to understand how fluids intermix during a cement job. Simulation and 3D displacement results are not intended as and should not be used as a replacement for bond logs in determining top of cement. Current 3D model calculations are known to model more volume than the input volume for standard cases due to known calculation improvements required. For rotational cases, the modeled volume will be impacted by the same calculations impacting the standard cases, as well as additional constraints imposed to make the calculation time required operationally feasible. Therefore, until further notice, 3D displacement results should not be used for replacement of a bond log, or used as an identifier of top of cement. HALLIBURTON IS UNABLE TO GUARANTEE THE ACCURACY OF ANY CHART INTERPRETATION, RESEARCH ANALYSIS, OR JOB RECOMMENDATION and any interpretation or recommendation is not for use of or reliance upon by any third party. The customer has full responsibility for any of its decisions which are based on the information provided in this report. © 2019 Halliburton. All rights reserved. Customer: HILCORP ALASKA LLC - EBUS V-227, Production SO: 907780134 Page 3 (v. 5.1.101.0) Created: Sunday, April 03, 2022 Table of Contents 1.0 Real-Time Job Summary ............................................................................................................................. 4 1.1 Job Event Log ................................................................................................................................................................................................................................ 4 2.0 Attachments .............................................................................................................................................. 7 2.1 Pressure Test.png ......................................................................................................................................................................................................................... 7 2.2 Pump Cement.png ........................................................................................................................................................................................................................ 8 2.3 Burst Discs.png ............................................................................................................................................................................................................................. 9 2.4 V-227, Production.png ................................................................................................................................................................................................................ 10 Customer: HILCORP ALASKA LLC - EBUS V-227, 3.5” Production SO: 907780134 Page 4 (v. 5.1.101.0) Created: Sunday, April 03, 2022 1.0 Real-Time Job Summary 1.1 Job Event Log Seq. No. Graph Label Date Time Pump B Pressure Dwnhole Density Cmb Pump Rate Cmb Stg Total Comments (psi) (ppg) (bbl/min) (bbl) 1 Call Out 4/3/2022 03:30:00 2 Pre-Convoy Safety Meeting 4/3/2022 04:45:00 3 Leave Yard 4/3/2022 05:00:00 4 Arrive at Location 4/3/2022 06:00:00 5 Site Assessment 4/3/2022 06:15:00 6 Spot Equipment 4/3/2022 06:30:00 7 Pre-Rig up Safety Meeting 4/3/2022 06:45:00 8 Rig Up 4/3/2022 07:00:00 9 Done 4/3/2022 08:00:00 10 Standby 4/3/2022 08:15:00 11 Pre-Job Safety Meeting 4/3/2022 10:30:00 12 Start Job 4/3/2022 11:27:30 14.50 0.11 0.00 0.02 13 Fill Lines 4/3/2022 11:28:51 39.08 8.49 0.84 0.36 5 BBL fresh water 1.8 BPM, 300 PSI 14 Low Pressure Test 4/3/2022 11:48:32 1086.84 8.30 0.00 0.72 1100 PSI 15 High Pressure Test 4/3/2022 11:54:48 4950.91 8.55 0.00 0.72 5000 PSI Customer: HILCORP ALASKA LLC - EBUS V-227, 3.5” Production SO: 907780134 Page 5 (v. 5.1.101.0) Created: Sunday, April 03, 2022 16 Pump Spacer 4/3/2022 12:15:59 338.07 9.92 2.03 1.00 40 BBL, 10 PPG, 1.27 CuFt/SK, 6.84 GAL/SK 2 BPM, 350 PSI Average 17 Cement Wet 4/3/2022 12:34:00 297.98 10.95 2.10 0.55 18 Pump Lead Cement 4/3/2022 12:36:16 329.95 14.43 2.12 5.39 54 BBL, 15.3 PPG, 1.236 CuFt/SK, 5.593 GAL/SK 2 BPM, 215 PSI Average No LCM 19 Pump Tail Cement 4/3/2022 12:58:00 213.44 15.26 2.15 51.83 108 BBL, 15.3 PPG, 1.242 CuFt/SK, 5.594 GAL/SK 3 BPM, 380 PSI Average 20 Shut Down 4/3/2022 13:44:00 49.61 15.28 0.00 110.86 21 Drop Plug (Baker Hughes Extended Wiper Plug) 4/3/2022 13:45:00 45.71 15.27 0.00 0.00 22 Pump Water Behind 4/3/2022 13:47:00 127.39 13.31 2.25 0.34 5 BBL fresh water 4 BPM, 300 PSI Average 23 Shutdown / Swap to Rig for Remaining Displacement 4/3/2022 13:48:00 191.52 8.48 3.97 4.17 83.6 BBL Stroke Factor: .062 24 End Job 4/3/2022 13:48:38 25 Bump Plug 4/3/2022 14:30:00 0.25 0.12 0.00 15.27 1299 Strokes + 5 BBL Stroke Factor: .062 26 Check Floats 4/3/2022 14:35:00 3.02 0.12 0.00 39.55 Floats hold 27 Begin Wash Up 4/3/2022 15:00:00 -1.91 0.11 0.00 83.06 Customer: HILCORP ALASKA LLC - EBUS V-227, 3.5” Production SO: 907780134 Page 6 (v. 5.1.101.0) Created: Sunday, April 03, 2022 28 Begin 30 Minute Pressure Test (Rig) 4/3/2022 15:24:00 -3.77 0.10 0.00 128.00 29 Fill Lines 4/3/2022 16:00:00 948.10 8.61 1.03 1.43 30 Burst Discs On Baker Tool 4/3/2022 16:00:43 4047.09 8.89 1.05 2.17 4047 PSI 31 Released to Rig Down 4/3/2022 16:04:00 -2.93 8.53 0.00 2.20 Trace cement to surface 32 Pre-Rig Down Safety Meeting 4/3/2022 16:05:00 33 Rig Down 4/3/2022 16:15:00 34 Done 4/3/2022 17:00:00 35 Pre-Convoy Safety Meeting 4/3/2022 17:45:00 36 Depart Location 4/3/2022 18:00:00 37 Arrive at Yard 4/3/2022 19:00:00 38 Equipment Used 4/3/2022 22:00:00 Bret: 12010175 Brian: 12251194 Tyler: 12203354 / 10297812 Aaron: 11748311 / 10025130 Sam: 11722177 / 10025132 39 Materials Used 4/3/2022 23:00:00 Citric Acid: 50 LB MMCR: 5 GAL D-Air: 5 GAL Customer: HILCORP ALASKA LLC - EBUS Job: SO: 907780134 Case: Case 1 Page 7 (v. 5.1.101.0) Created: Sunday, April 03, 2022 2.0 Attachments 2.1 Pressure Test.png Customer: HILCORP ALASKA LLC - EBUS Job: SO: 907780134 Case: Case 1 Page 8 (v. 5.1.101.0) Created: Sunday, April 03, 2022 2.2 Pump Cement.png Customer: HILCORP ALASKA LLC - EBUS Job: SO: 907780134 Case: Case 1 Page 9 (v. 5.1.101.0) Created: Sunday, April 03, 2022 2.3 Burst Discs.png Customer: HILCORP ALASKA LLC - EBUS Job: SO: 907780134 Case: Case 1 Page 10 (v. 5.1.101.0) Created: Sunday, April 03, 2022 2.4 V-227, Production.png From:Rixse, Melvin G (OGC) To:AOGCC Records (CED sponsored) Subject:20220310 1719 PARTIAL APPROVAL PBU V-227A (Sundry 322-079 & PTD: 222-020) Discussion Date:Monday, March 14, 2022 3:28:05 PM Attachments:HAK PBU V-227 (Sundry 322-079 & PTD 222-020) Window Squeeze Operatoins.pdf From: Rixse, Melvin G (OGC) Sent: Friday, March 11, 2022 5:21 PM To: Joe Engel <jengel@hilcorp.com> Cc: Aras Worthington <Aras.Worthington@hilcorp.com>; Taylor Wellman <twellman@hilcorp.com>; Monty Myers <mmyers@hilcorp.com> Subject: 20220310 1719 Partial Approval PBU V-227A (Sundry 322-079 & PTD: 222-020) Discussion Joe, Hilcorp has approval to squeeze cement behind 7” casing at the whipstock as described in the attached procedure. Hilcorp does not have approval to set a production packer above the cemented 3-1/2” X 7” cement packer. Current concerns by AOGCC is that the packer will mask a poor cement job as is currently realized on similar well V-213A. An unmonitorable annulus with a poor cement job would hide WAG injection into zones above the confining zones. As a reminder of the regulation: 20 AAC 25.412 Casing, cementing, and tubing of injection wells for enhanced recovery, disposal, and storage (a) A well used for injection must be cased and cemented in accordance with 20 AAC 25.030 to prevent leakage into oil, gas, or freshwater sources. (b) A well used for injection must be equipped with tubing and a packer, or with other equipment that isolates pressure to the injection interval, unless the commission approves the operator's use of alternate means to ensure that injection of fluid is limited to the injection zone. The minimum burst pressure of the tubing must exceed the maximum surface injection pressure by at least 25 percent. The packer must be placed within 200 feet measured depth above the top of the perforations, unless the commission approves a different placement depth as the commission considers appropriate given the thickness and depth of the confining zone. A variance was provided on V-213A and V-227A provided a good cement bonding is demonstrated. V-213A will require that as well as V-227A. Mel Rixse Senior Petroleum Engineer (PE) CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. Taylor Wellman, Monty Myers, Aras Worthington From: Joseph Engel <jengel@hilcorp.com> Sent: Friday, March 11, 2022 10:00 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: HAK PBU V-227A (Sundry 322-079 & PTD: 222-020) Discussion Followup Mel – Thank you for the phone call yesterday. Following up regarding V-227A: I wanted to confirm that you are ok with a 10.7 FIT as in step 11.22 on page 18 of the approved PTD Hilcorp would like to squeeze cement behind the 7” window depth before milling the window This is a learning from V-213A in an effort to mitigate any hydrate gas at the window depth Operational Steps attached All packer and whipstock depths would remain the same Hilcorp would like to add a packer at the TOC of the 3-1/2” long string, below the defender circ sleeve Packer depth ~ 4900’ MD, at the TOC To ensure integrity of the monitorable annulus, based upon V-213A Updated Schematic Attached This packer would be set prior to opening the defender circ sleeve Please let me know if you have any questions. Thank you for your time. -Joe Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 | Anchorage | AK | 99503 Office: 907.777.8395 | Cell: 805.235.6265 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. HAK V-227 P&A Sundry (#322-079) and V-227A PTD (#222-020) Window Squeeze Ops Addition Purpose of these additional operations is to perform a cement squeeze at the proposed window depth of V-227A to mitigate any potential hydrate gas outside the window. 1.1. Pump 12 bbls of 15.8 class g cement on top of CIBP set at ~ 5700’ MD  12bbls of cement is ~ 300’ of 7” casing volume  AOGCC Regulation 25.112(c)(e) requires 75’ of cement minimum  Plan will be to drill up cement to 5600’, leaving 100’ cement plug on top of CIBP before perforating and squeezing window depth 1.2. POOH with cement stinger to above TOC (~5500’), circulate at high rate and pump nerf ball to clean drill string 1.3. POOH, racking back 4” dp 1.4. MU cleanout BHA, tri cone bit, RIH and tag cement 1.5. Drill cement and dress off to ~ 5600’ MD 1.6. RU E-line with perf guns, RIH t/ ~ 5600’ MD 1.7. Perforate 7” casing 1.8. POOH with Eline 1.9. MU Cement Retainer on drillpipe and RIH t/ 5500’ MD, set cement retainer 1.10. RU and Pump 10bbl of cement beneath cement retainer and through perforations  V-227 has an uncemented 7” annulus at the planned window depth for V-227A. Cement to be squeezed behind window interval to mitigate any potential hydrate gas at window depth while drilling the sidetrack  Cement volume:  7” ID capacity: 5600-5500’ MD, 3.8bbl  8.5” x 7” annulus capacity, 5600 – 5400’MD, 1.4% excess, ~6.2bbl  If unable to pump all cement beneath cement retainer, unsting and lay remaining cement on top of cement retainer 1.11. POOH with cement stinger 1.12. MU cleanout bha, RIH and dress off cement on top of retainer 1.13. RU and Test 7” casing  Test 7” casing to 2000 psi, for 30 minutes, chart test. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001.  AOGCC to witness tag and pressure test Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Monty Myers Drilling Manager Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage, AK, 99503 Re: Prudhoe Bay Field, Schrader Bluff Oil Pool, PBU V-227A Hilcorp North Slope, LLC Permit to Drill Number: 220-020 Surface Location: 4900’ FSL, 1532’ FEL, Sec. 11, T11N, R11E, Umiat Bottomhole Location: 1045’ FSL, 25’ FEL, Sec. 01, T11N, R11E, Umiat Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jeremy M. Price Chair DATED this ___ day of March, 2022. Jeremy Price Digitally signed by Jeremy Price Date: 2022.03.08 14:17:44 -09'00' 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name: 5. Bond: Blanket Single Well 11.Well Name and Number: Bond No. 3.Address: 6.Proposed Depth: 12.Field/Pool(s): MD: 9,953' TVD: 5,103' 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon: 8. DNR Approval Number: 13.Approximate Spud Date: Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 79.3' 15.Distance to Nearest Well Open Surface: x-590767 y- 5970150 Zone- 4 52.8' to Same Pool: 880' 16.Deviated wells: Kickoff depth: 5,500 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 69 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 6-1/8" 3-1/2" 9.2# L-80 JFE Bear 9,953' Surface Surface 9,953' 5,103' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): 10,246' TVD 31' - 176' 31' - 3,028' 28' - 5,136' Hydraulic Fracture planned? Yes No 20.Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Joseph Engel Monty Myers Contact Email:jengel@hilcorp.com Drilling Manager Contact Phone:777-8395 Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng March 15, 2022 12,783' 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft): GL / BF Elevation above MSL (ft): Perforation Depth MD (ft): 5,386' 260 sx Arctic Set (Approx.) 31' - 176' 31' - 5,417'9-5/8" 422 sx Class 'G'Production Liner 10,304' Intermediate 9,226' - 10,032' Conductor/Structural 20"145' Authorized Title: Authorized Signature: Authorized Name: 829 sx AS Lite, 417 sx Class 'G' 10,340'5,141' LengthCasing 8,670', 10,117' Cement Volume MDSize Plugs (measured): (including stage data) 729 sx Class 'G' 8,670' 4,266' Effect. Depth MD (ft): Effect. Depth TVD (ft): 5029 18.Casing Program: Top - Setting Depth - BottomSpecifications 2118 Total Depth MD (ft): Total Depth TVD (ft): 107205344 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1556 1417' FSL, 830' FEL, Sec. 01, T11N, R11E, UM, AK 1045' FSL, 25' FEL, Sec. 01, T11N, R11E, UM, AK 00-001 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp North Slope, LLC 4900' FSL, 1532' FEL, Sec. 11, T11N, R11E, UM, AK ADL 028240 PBU V-227A Prudhoe Bay Field Schrader Bluff Oil Pool, Orion Development Area Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements.50-029-23417-01-00 4,535' - 4,962' 28' - 10,332'7" No No No No Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) 3.3.2022 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: 2022.03.03 14:22:31 -09'00' Monty M Myers REVISED NEW BOTTOMHOLE LOCATION 222-020 (Revised) By Meredith Guhl at 2:55 pm, Mar 03, 2022 SFD MGR07MAR2022 DSR-3/4/22 See conditions of approval on following page. SFD 3/3/2022 dts 3/8/2022 3/8/2022 Jeremy Price Digitally signed by Jeremy Price Date: 2022.03.08 14:18:12 -09'00' WdϮϮϮʹϬϮϬWhsͲϮϮϳŽŶĚŝƚŝŽŶƐŽĨƉƉƌŽǀĂů ϭ͘KWƚĞƐƚƚŽϯϬϬϬƉƐŝ͘ŶŶƵůĂƌƚŽϮϱϬϬƉƐŝ͘ Ϯ͘ĂƐŝŶŐƚĞƐƚĨƌŽŵ^ƵŶĚƌǇϯϮϮͲϬϳϵ͕ƐƚĞƉϮ͘ϭϵĂŶĚ&ŽƌŵĂƚŝŽŶ/ŶƚĞŐƌŝƚǇdĞƐƚĚŝŐŝƚĂůĚĂƚĂƚŽK' ŝŵŵĞĚŝĂƚĞůǇƵƉŽŶƉĞƌĨŽƌŵŝŶŐƚŚĞ&/d͘&/dƚŽďĞƌĞǀŝĞǁĞĚĂŶĚĂƉƉƌŽǀĞĚďǇK'ƐƚĂĨĨďĞĨŽƌĞ ƚŚĞĚƌŝůůŝŶŐŽĨĂĚĚŝƚŝŽŶĂůŶĞǁŚŽůĞĐŽŵŵĞŶĐĞƐ͘&/dсϭϮ͘ϳƉƉŐDtd͘ ϯ͘sĂƌŝĂŶĐĞƚŽϮϬϮϱ͘ϰϭϮ;ďͿŝƐŐƌĂŶƚĞĚďǇƚŚĞƵƚŝůŝǌĂƚŝŽŶŽĨĂĐĞŵĞŶƚƉĂĐŬĞƌŽĨĂƉƉƌŽǆŝŵĂƚĞůǇ ϲϯϬ͛ŝŶůĞŶŐƚŚĂŶĚĂŶĂƉƉƌŽǀĞĚĐĞŵĞŶƚĞǀĂůƵĂƚŝŽŶůŽŐĚĞŵŽŶƐƚƌĂƚŝŶŐƚŚĂƚŝŶũĞĐƚŝŽŶǁŝůůďĞ ůŝŵŝƚĞĚƚŽƚŚĞŝŶũĞĐƚŝŽŶŝŶƚĞƌǀĂůǁŝƚŚƚŚĞĨŽůůŽǁŝŶŐƐƚŝƉƵůĂƚŝŽŶƐ͗ Ă͘,ŝůĐŽƌƉǁŝůůƉƌŽǀŝĚĞĂĐĞŵĞŶƚũŽďƐƵŵŵĂƌǇƌĞƉŽƌƚƚŽK'ǁŚĞŶŝƚďĞĐŽŵĞƐĂǀĂŝůĂďůĞ͘ ď͘,ŝůĐŽƌƉǁŝůůƉƌŽǀŝĚĞĂǁƌŝƚƚĞŶĐĞŵĞŶƚďŽŶĚůŽŐĞǀĂůƵĂƚŝŽŶͬŝŶƚĞƌƉƌĞƚĂƚŝŽŶƚŽƚŚĞK' ĂůŽŶŐǁŝƚŚƚŚĞĐĞŵĞŶƚďŽŶĚůŽŐĂƐƐŽŽŶĂƐŝƚďĞĐŽŵĞƐĂǀĂŝůĂďůĞ͘dŚĞĞǀĂůƵĂƚŝŽŶŝƐƚŽ ŝŶĐůƵĚĞͬŚŝŐŚůŝŐŚƚƚŚĞŝŶƚĞƌǀĂůƐŽĨĐŽŵƉĞƚĞŶƚĐĞŵĞŶƚ;ĂŶĚůĞŶŐƚŚƐͿƚŚĂƚ,ŝůĐŽƌƉŝƐƵƐŝŶŐ ƚŽŵĞĞƚƚŚĞŽďũĞĐƚŝǀĞƌĞƋƵŝƌĞŵĞŶƚƐĨŽƌĂŶŶƵůĂƌŝƐŽůĂƚŝŽŶ͕ƌĞƐĞƌǀŽŝƌŝƐŽůĂƚŝŽŶ͕Žƌ ĐŽŶĨŝŶŝŶŐǌŽŶĞŝƐŽůĂƚŝŽŶĞƚĐ͘WƌŽǀŝĚŝŶŐƚŚĞůŽŐǁŝƚŚŽƵƚĂŶĞǀĂůƵĂƚŝŽŶͬŝŶƚĞƌƉƌĞƚĂƚŝŽŶŝƐ ŶŽƚĂĐĐĞƉƚĂďůĞ͘ Đ͘,ŝůĐŽƌƉǁŝůůƉĞƌĨŽƌŵĂŶĂŶŶƵĂůD/dͲdƚŽϯϮϬϬƉƐŝ;ŵĂǆŝŵƵŵŚĞĂĚĞƌŝŶũĞĐƚŝŽŶƉƌĞƐƐƵƌĞͿ ǁŝƚŚƉůƵŐƐĞƚŝŶyŶŝƉƉůĞũƵƐƚĂďŽǀĞƚŽƉƐŝĚĞƉŽĐŬĞƚŝŶũĞĐƚŝŽŶŵĂŶĚƌĞů͘ ϰ͘^ƚĂƚĞƚŽǁŝƚŶĞƐƐD/dͲdƚŽϯϮϬϬƉƐŝ͕;ƚŚĞĞƐƚŝŵĂƚĞĚĂǀĞƌĂŐĞĂŶĚŵĂǆŝŵƵŵŝŶũĞĐƚŝŽŶƉƌĞƐƐƵƌĞ ƉƌŽǀŝĚĞĚďǇ,ŝůĐŽƌƉͿďĞĨŽƌĞWƵƚKŶ/ŶũĞĐƚŝŽŶ;WK/Ϳ͘ ϱ͘^ƚĂƚĞƚŽǁŝƚŶĞƐƐD/dͲ/ƚŽϮϬϬϬƉƐŝ͕ŝĨƚŚĞǁĞůůǁŝůůďĞŽŶĐŽŶƚŝŶƵŽƵƐ/ƉƌĞƐƐƵƌĞŵŽŶŝƚŽƌŝŶŐ ǁŚĞŶŽŶŝŶũĞĐƚŝŽŶ͘/Ĩ/ŵŽŶŝƚŽƌŝŶŐŶŽƚĂǀĂŝůĂďůĞ͕ĂŶĂŶŶƵĂůD/dͲ/ƚŽϯϮϬϬƉƐŝǁŝůůďĞƌĞƋƵŝƌĞĚ͘ ϲ͘dŚŝƐĂƉƉƌŽǀĞĚƉĞƌŵŝƚƚŽĚƌŝůůǁŝƚŚĐŽŶĚŝƚŝŽŶƐŽĨĂƉƉƌŽǀĂůƚŽďĞĂǀĂŝůĂďůĞĂŶĚƵƚŝůŝǌĞĚĂƚƚŚĞǁĞůů ƐŝƚĞ͘ 612 71211V-01 V-02 V-03 -04 V-05 V-07 8 V-100101 -102 V-103 V-104 V-105 V-106 V-106APB1 V-107 V-109 V-111PB1 -112 V-114 V-114APB1 V-115 V-119 V-120 V-121 V-122 V-123 V-137 1 V-202 V-204 V-205 V-207 V-207L1 V-207L2 V-207L3 V-207L4 210 V-211 V-212 V-213 V-213PB1 V-215 V-216 V-217 V-218 V-219 V-220 V-221 V-222 V-223 V-224 V-225 V-227 V-229 V-227A_wp01 HILCORP NORTH SLOPE Greater Prudhoe Bay AOR MAP V-227A Injector (Proposed) FEET 05001,0001,500 POSTED WELL DATA Well Label WELL SYMBOLSLocation Shut In Oil INJ Well (Water Flood) Abandoned Injector P&A Oil/Gas J&A Temporarily Abandoned Active Oil Injector Location REMARKS Well Symbols at top of Schrader Bluff NB sand(uppermost injection target). Black dashed circle =1320' radius from top of NB in proposed V-227A injector November 5, 2021 PETRA 11/5/2021 3:44:25 PM Well Name PTD API StatusTop of Oil Pool(SB NB, MD)Top of Oil Pool(SB NB, TVD)Top of Cmt (MD) Top of Cmt (TVD)ZonalIsolationCommentsV-224 208-154 50-029-23400-00-00Online WAGInjector8882' 4549' 5276' 2994' Open 7" cemented with 125 bbls ofCmt in 8-3/4" hole. Est. TOCat 3351 ft.V-207 208-066 50-029-23390-00-00OnlineProducer8169' MD 4506' 4150' 2909' Open7-5/8" TOC logged with USITat 4150' MD on 8/11/2008.Casing cemented with 229bbls of Cmt in 9-7/8" hole.Est. Motherbore and OBeLateral.V-207L1 208-067 50-029-23390-60-00Online LateralProducerN/A* N/A* 4150' 2909' Open7-5/8" TOC logged with USITat 4150' MD on 8/11/2008.*OBd Lateral sidetracked frommotherbore below the top ofthe OA. Motherbore entersOA at 8572' MDV-207L2 208-068 50-029-23390-61-00Online LateralProducerN/A* N/A* 4150' 2909' Open7-5/8" TOC logged with USITat 4150' MD on 8/11/2008.*OBb Lateral sidetracked frommotherbore below the top ofthe OA. Motherbore entersOA at 8572' MDV-207L3 208-069 50-029-23390-62-00Online LateralProducerN/A* N/A* 4150' 2909' Open7-5/8" TOC logged with USITat 4150' MD on 8/11/2008.*OBa Lateral sidetracked frommotherbore below the top ofthe OA. Motherbore entersOA at 8572' MDV-207L4 208-070 50-029-23390-63-00Online LateralProducer9526' 4524' 4150' 2909' Open7-5/8" TOC logged with USITat 4150' MD on 8/11/2008.NB Lateral sidetracked frommotherbore above the NB,enters NB at 9526' MD.Area of Review PBU V-227ACement extends above the top of Ugnu MA sand in primary wells V-227, V-207 and V-224. SFD 3/3/2022? ` Prudhoe Bay West (PBU) V-227A Permit to Drill Application Version 2 3/3/2022 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 Current & Planned Wellbore Schematic .................................................................................. 6 7.0 Drilling / Completion Summary ................................................................................................ 9 8.0 Mandatory Regulatory Compliance / Notifications ................................................................ 10 9.0 MIRU & Test BOPE ................................................................................................................ 12 10.0 Pull Tubing String, Set CIBP .................................................................................................. 14 11.0 Set Whipstock, Mill 6-1/8” Window and Kick Off.................................................................. 16 12.0 Drill 6-1/8” Hole Section .......................................................................................................... 19 13.0 Run 3-1/2” Casing .................................................................................................................... 22 14.0 Cement 3-1/2” Production Casing ........................................................................................... 25 15.0 Innovation Rig BOP Schematic ............................................................................................... 28 16.0 Wellhead Schematic ................................................................................................................. 29 17.0 Days Vs Depth .......................................................................................................................... 30 18.0 Formation Tops & Information............................................................................................... 31 19.0 Anticipated Drilling Hazards .................................................................................................. 33 20.0 Innovation Rig Layout ............................................................................................................. 35 21.0 FIT Procedure .......................................................................................................................... 36 22.0 Innovation Rig Choke Manifold Schematic ............................................................................ 37 23.0 Casing Design ........................................................................................................................... 38 24.0 MASP ....................................................................................................................................... 39 25.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 40 26.0 Surface Plat (As-Built)(NAD 27) ............................................................................................. 41 Page 2 Prudhoe Bay West V-227A SB Injector PTD Application 1.0 Well Summary Well PBU V-227A Pad Prudhoe Bay V Pad Planned Completion Type 3-1/2” Cemented Injector Target Reservoir(s) Schrader Bluff NB, Oba, OBb, OBd, OBe Planned Well TD, MD / TVD 9,953’ MD / 5,103’ TVD PBTD, MD / TVD 9,833’ MD / 5,036’ TVD Surface Location (Governmental) 4900’ FSL, 1532' FEL, Sec 11, T11N, R11E, UM, AK Surface Location (NAD 27) X=590,767.5 , Y=5,970,149.9 Top of Productive Horizon (Governmental)1417' FSL, 830' FEL, Sec 1, T11N, R11E, UM, AK TPH Location (NAD 27) X= 596725.4, Y= 5972020.5 BHL (Governmental) 1045' FSL, 25' FEL, Sec 1, T11N, R11E, UM, AK BHL (NAD 27) X= 597535.0, Y= 5971659 AFE Drilling Days 12 AFE Completion Days 2 Maximum Anticipated Pressure (Production) 1556 psig Maximum Anticipated Pressure (Downhole/Reservoir) 2118 psig (OBE sand) Work String 4” 14# S-135 XT-39 Innovation KB Elevation above MSL: 26.5 ft + 52.8 ft = 79.3 ft GL Elevation above MSL: 52.8 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Prudhoe Bay West V-227A SB Injector PTD Application 2.0 Management of Change Information Page 4 Prudhoe Bay West V-227A SB Injector PTD Application 3.0 Tubular Program Hole Section OD (in)ID (in) Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 20” 19.25” - - - A-53 Weld - - - 12-1/4” 9-5/8” 8.835 8.679 10.625 40 L-80 BTC 5750 3090 916 8-3/4” 7” 6.276 6.151 7.656 26 L-80 BTC 7240 5410 604 6-1/8” 3-1/2” 2.992 2.867 3.883 9.2 L-80 JFE Bear 10160 10535 207 Comp 3-1/2” 2.992 2.867 3.883 9.2 L-80 JFE Bear 10160 10535 207 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) Production 4”3.34 2.688 4.875 14 S-135 XT-39 17,700 21,200 553klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Prudhoe Bay West V-227A SB Injector PTD Application 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. Report covers operations from 6am to 6am Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry. Ensure time entry adds up to 24 hours total. Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp, nathan.sperry@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.3 Intranet Home Page Morning Update Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting Health and Safety: Notify EHS field coordinator. Environmental: Drilling Environmental Coordinator Notify Drilling Manager & Drilling Engineer on all incidents Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally Send final “As-Run” Casing tally to mmyers@hilcorp,com jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.6 Casing and Cement report Send casing and cement report for each string of casing to mmyers@hilcorp.com jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.7 Hilcorp Prudhoe Bay 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 Carl Jones 907.777.8327 cajones@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com Page 6 Prudhoe Bay West V-227A SB Injector PTD Application 6.0 Current & Planned Wellbore Schematic Page 7 Prudhoe Bay West V-227A SB Injector PTD Application Cement on CIBP. _____________________________________________________________________________________ Revised By: JNL 3/3/2022 PROPOSED SCHEMATIC Prudhoe Bay Unit Well: PBU V-227A Last Completed: TBD PTD: TBD TREE & WELLHEAD Tree 4-1/16” CIW Wellhead FMC 11” 5K w/ Mandrel hanger, x2 2-1/16” outs OPEN HOLE / CEMENT DETAIL 42” 260 sx Arctic Set (Approx.) 12-1/4" 829 sx AS Lite, 417 sx Class ‘G’, 212 8-3/4” 295 sx Class ‘G’ 6-1/8” 729 sx Class ‘G’ Sidetrack Information A Sidetrack Window: 5,500’ – xxxx’ Whipstock @ 5,500’ JEWELRY DETAIL No. Top MD* Item ID 1 2,200 X Nipple 2.813” 2 4,870 3-1/2” HP Defender Sliding Sleeve 2.960” 3 8,750 X Nipple 2.813” 4 8,835 1” Side Pocket Injection Mandrel 2.960” 5 9,202 X Nipple 2.813” 6 9,240 1” Side Pocket Injection Mandrel 2.960” 7 9,264 1” Side Pocket Injection Mandrel 2.960” 8 9,288 X Nipple 2.813” 9 9,308 1” Side Pocket Injection Mandrel 2.960” 10 9,424 X Nipple 2.813” 11 9,510 1” Side Pocket Injection Mandrel 2.960” 12 9,530 1” Side Pocket Injection Mandrel 2.960” 13 9,584 X Nipple 2.813” 14 9,621 1” Side Pocket Injection Mandrel 2.960” 15 9,708 X Nipple 2.813” INJECTION STATIONS DETAIL # Top (MD) Rate Zone 78,835 TBD NB 69,240 TBD OBA 59,264 TBD OBA 49,308 TBD OBB 39,510 TBD OBD 29,530 TBD OBD 19,629 TBD OBE GENERAL WELL INFO API: 50-029-23417-01-00 Completion Date: TBD TD= 9,953’(MD)/ TD =5,103’ (TVD) 4 20” x 34” Whipsto ck @ 5,500’ Orig. KB Elev.: 79.3’ / GL Elev.: 52.8’ 14 8 15 3 1 13 2 9-5/8” 9 11 12 PBTD =9,833’(MD) / PBTD =5,036’ (TVD) 5 10 6 8 7 10 1 6 7”TOC@ ~7410’ 7 3-1/2” TOC @ ~4,870’ CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20” Conductor 129.45 / X-65 / Weld N/A Surface 110’ N/A 9-5/8" Surface 40/ L-80 / BTC 8.835 Surface 5,417’ 0.0758 7” Intermediate 26 / L-80 / BTC 6.276 Surface 5,500’ 0.0383 3-1/2” Production 9.2 / L-80 / JFE Bear 2.992 Surface 9,953’ 0.0087 WELL INCLINATION DETAIL KOP @400’ Max Hole Angle = 71° @3,048’ MD Page 9 Prudhoe Bay West V-227A SB Injector PTD Application 7.0 Drilling / Completion Summary PBU V-227A is a sidetrack injector planned to be drilled in the Schrader Bluff sands. V-227A is part of a multi well program targeting the Schrader Bluff sand on PBU V-pad. This well will not be pre-produced prior to injection. The parent bore, V-227, is an inoperable injector that targeted multiple lobes of Schrader bluff sand that was drilled in 2009. V-227’s reservoir was isolated in 2011 with tubing punch and cement pumped in the 4-1/2 tubing and 4-1/2” x 7” annulus, TOC tagged with coil tubing at 8670’ MD. A coil mill was stuck in 2012 and left in hole. Top of coil fish is 5749’ MD. The 4-1/2” tubing was jet cut at 5720’ MD in 2019 and removed from the well bore. A 3-1/2” killstring was ran. The directional plan is a single hole section 6-1/8” slant well. A 3-1/2” cemented water flood regulating completion will be run in the open hole section. The Innovation Rig will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately March 18, 2022, pending rig schedule. Production casing will be run to 9,953’ MD / 5,103’ TVD and cemented via a single stage cement job. TOC is planned to the sliding sleeve at ~4,870’ MD. 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” BOPE 3. Pull 3-1/2” killstring 4. Set CIBP 5. Set 7” whipstock 6. Mill 6-1/8” Window, perform FIT 7. Drill 6-1/8” Hole to TD 8. Run and Cement 3-1/2” casing 9. N/D BOPE, NU Tree, RDMO Reservoir Evaluation Plan: 1. Production Hole: No mud logging. On site geologist. LWD: GR + Res p s well will not be pre-produced , cement in place. jp m targeting the Schrader Bluff sand o Post Rig: CBL Page 10 Prudhoe Bay West V-227A SB Injector PTD Application 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that all drilling and completion operations comply with all applicable AOGCC regulations. Operations stated in this PTD application may be altered based on sound engineering judgement as wellbore conditions require, but no AOGCC regulations will be varied from without prior approval from the AOGCC. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. BOPs shall be tested at 1 week intervals prior to initiating window milling and at (2) week intervals during the drilling and completion of PBU V-227A. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. 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. If the BOP is used to shut in on the well in a well control situation or control fluid flow from the well bore, AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements”. o Ensure the diverter vent line is at least 75’ away from potential ignition sources Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test pressure must show stabilizing pressure and may not decline more than 10 percent within 30 minutes. The results of this test and any subsequent tests of the casing must be recorded as required by 20 AAC 25.070(1)”. AOGCC Regulation Variance Requests: Hilcorp requests a variance to 20 AAC 25.412 (b) for packer placement within 200’ of top of perforations since cement will be used in lieu of a production packer. TOC will be brought up to ~4,870’ MD, roughly 3850’ above the Schrader NB injection point. Page 11 Prudhoe Bay West V-227A SB Injector PTD Application Summary of Innovation BOP Equipment & Test Requirements Hole Section Equipment Test Pressure (psi) 6-1/8” 13-5/8” x 5M Control Technology Inc Annular BOP 13-5/8” x 5M Control Technology Inc Double Gate o Blind ram in btm cavity Mud cross w/ 3” x 5M side outlets 13-5/8” x 5M Control Technology Single ram 3-1/8” x 5M Choke Line 3-1/8” x 5M Kill line 3-1/8” x 5M Choke manifold 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: Well control event (BOPs utilized to shut in the well to control influx of formation fluids). 24 hours notice prior to spud. 24 hours notice prior to testing BOPs. 24 hours notice prior to casing running & cement operations. Any other notifications required in 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 12 Prudhoe Bay West V-227A SB Injector PTD Application 9.0 MIRU & Test BOPE Reservoir abandonment has already been completed in 2011. The following steps are duplicate from the prep for sidetrack sundry submitted for V-227 along with this PTD. 9.1 Ensure to review attached surface plat and well tags to make sure rig is over appropriate well. 9.2 Ensure PTD w/ COA’s and drilling program are posted in the rig office and on the rig floor. 9.3 Level pad and ensure enough room for layout of rig footprint and R/U. 9.4 Rig mat footprint of rig. 9.5 MIRU Innovation. Ensure rig is centered over wellhead to prevent any wear to BOPE or wellhead. 9.6 Mud loggers WILL NOT be used. 9.7 RU to pump down tubing and take returns from IA to a tank. Pump at least 1 truck of seawater w/ soap followed by spacer and 9.2ppg brine. 9.8 Flow check well to ensure fluids are balanced. 9.9 Install BPV, N/D the tree. Install test dart in the BPV. Verify lifting threads are good and check XO for landing joint. Count turns in to hanger. 9.13 NU 13-5/8” x 5M BOP as follows: BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13- 5/8” x 5M mud cross / 13-5/8” x 5M single gate Double gate ram should be dressed with 2-7/8” x 5-1/2” VBRs in top cavity,blind ram in bottom cavity. Single ram can be dressed with 2-7/8” x 5-1/2” VBRs NU bell nipple, install flowline. Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 9.14 RU MPD RCD and related equipment 9.15 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min. Test with 4-1/2” and 3-1/2” test joints Confirm test pressures with PTD Approved sundry 322-079 Page 13 Prudhoe Bay West V-227A SB Injector PTD Application Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 9.16 RD BOP test equipment. Pull test dart and BPV. 9.17 Mix 9.2 ppg fluid. 9.18 Set wear bushing in wellhead. 9.19 If needed, rack back as much 4” DP in derrick as possible to be used while drilling the hole section. Approved sundry 322-079 Page 14 Prudhoe Bay West V-227A SB Injector PTD Application 10.0 Pull Tubing String, Set CIBP 10.1 RU tubing handling equipment Tubing is 3-1/2” 9.2# L-80 TC-II Tubing depth: 3073’ MD 10.2 PU landing joint or spear and engage tubing hanger 10.3 Backout lock down screws 10.4 Pull tubing hanger with landing joint/xo to the rig floor, have appropriate protectors ready. 10.5 If necessary, circulate at least 1.5x BU after pulling the hanger to the floor. If desired, circulate a soap sweep surface-to-surface to clean the tubing. 10.6 POOH laying down 3-1/2” tubing 10.7 RD casing equipment. 10.8 The last V-227 Combo MIT test failed (7/23/19) with a .5 gallon per minute at 2600 psi. Suspect leak to be associated with the stuck coil mill bha. A CIBP will be run to isolate the leak, and cement pumped on top At the time of this PTD submission, 7” run tally has not been located. In order to determine casing collar location, a CCL will be needed. 10.9 RIH with cleanout assembly on 4” DP and cleanout to the tubing stub. 10.10 Assuming no CCL has been located, RU e-line and run GR/CCL to tubing stub. The CCL can be run on the same run as the CIBP if desired. Discuss with drilling engineer. 10.11 Run a Baker Hughes CIBP and set ~5’ above a casing collar, at ~5700’ MD. Confirm set depth with drilling engineer and whipstock company rep. CIBP can be run on DP or e-line. 3-1/2” tubing stub at 5720’ MD 10.12 RD e-line. 10.13 RIH with cement stinger on 4” DP 10.14 Pump 12 bbls of 15.8 class g cement on top of CIBP 12bbls of cement is ~ 300’ of 7” casing volume AOGCC Regulation 25.112(c)(e) requires 75’ of cement minimum Plan will be to drill up cement to window depth, leaving 200’ cement plug on top of CIBP Approved sundry 322-079 Page 15 Prudhoe Bay West V-227A SB Injector PTD Application 10.15 POOH with cement stinger to above TOC (~5400’), circulate at high rate and pump nerf ball to clean drill string 10.16 POOH, racking back 4” dp 10.17 MU cleanout BHA, tri cone bit, RIH and tag cement 10.18 Drill cement and dress off to ~ 5500’ MD 10.19 RU and Test 7” casing Test 7” casing to 2000 psi, for 30 minutes, chart test. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. * AGOCC to witness tag and pressure test to 2000 psi of cement plug ~5,500' MD. (Abandonment sundry) End of Sundry work for P&A, Sundry 322-079 Begin PTD222-020 Page 16 Prudhoe Bay West V-227A SB Injector PTD Application 11.0 Set Whipstock, Mill 6-1/8” Window and Kick Off Note: The following steps are covered under the PTD for V-227A The top of cement outside the 7” casing in V-227 was logged via USIT at 7,410’ MD (parent RKB reference). 11.1 Whipstock Set Depth Information: Planned TOW: ~5,500’ MD / 3057’ TVD WS should be set to avoid a collar. Drilling foreman, whipstock service hand, and drilling engineer to agree on the set depth. 11.2 MU 6-1/8” mill/whipstock assembly as per Baker Hughes tally Make up HWDP, storing magnets, and float sub Ensure magnets are in trough, under shakers and flow area to capture metal shavings circulated 11.3 Install MWD and orient. Rack back mill assembly. Ensure a dedicated MWD is available for orientation of the whipstock 11.4 Verify offset between MWD and whipstock tray, witnessed by Drilling Supervisor, MWD/DD and Baker Hughes rep. Document and record offset in well file 11.5 Slowly run in the hole as per fishing Rep. 11.6 Run in hole at 1 ½ to 2 minutes per stand, or per contractor rep. Ensure work string is stationary prior to setting the slips to avoid weakening the shear bolt and prematurely setting the anchor. 11.7 Shallow test MWD at first drill pipe fill up depth. 11.8 Stop at least 30-45’ above planned set depth (5,500’ MD), obtain survey with MWD. 11.9 Milling fluid will be 9.2 ppg LSND 11.10 With the bottom of the whipstock 30 – 45’ above the set depth, work torque out of string, measure and record P/U and S/O weights. Obtain good survey to orient whipstock face. 11.11 Orient whipstock to desired direction by turning DP in ¼ round increments. P/U and S/O on DP to work all torque out after oriented. (Being careful not to set trip anchor). Target orientation is 30 ROHS. Page 17 Prudhoe Bay West V-227A SB Injector PTD Application 11.12 Whipstock Orientation Diagram: Desired orientation of the whipstock face is 15R to 45R, target is 30 ROHS Hole Angle at window interval (5,500’ MD) is ~68°, Azimuth 55°. 11.13 Once whipstock is in desired orientation, set WS per Baker Hughes rep. 11.14 CBU and confirm 9.2 ppg MW in/out Ensure Mud properties are sufficient for transporting metal cuttings Visc: 40-60, YP: 18-20 11.15 Record P/U, S/O weights, and free rotation. Slack off to top of whipstock and with light weight and low torque. Mill window as per whipstock contractor representative. Pump high visc sweeps as necessary. 11.16 If possible, install catch trays in shaker underflow chute to help catch metal cuttings. 11.17 Clean catch trays and ditch magnets frequently while milling window. 11.18 Mill window until the uppermost mill has passed across the entire tray. Dress and polish window as needed. 11.19 With upper mill at the end of the tray, this will drill ~ 20’ of new hole. Be prepared for gas hydrates outside window 11.20 After window is milled but before POOH, shut down pumps and work milling assembly through window watching for drag. Dress and polish window as needed. After reaming, shut off pumps and rotary and dry drift window. 11.21 Circulate bottoms up until even MW in/out and hole is clean of metal shavings. Reduce mud properties for drilling. 45R 15R Be prepared for gas hydrates outside window Page 18 Prudhoe Bay West V-227A SB Injector PTD Application 11.22 Pull back into 7” casing and perform FIT to 10.7 ppg EMW. Chart Test. 10.7 ppg EMW provides a 15.7 bbl kick tolerance o Based upon 9.2 ppg MW, 8.19ppg EMW pore pressure and 9.2 ppg swabbed kick o 6-1/8” hole size, 62* inclination o Innovation rig PVT system allows for early kick detection o V-227 is a development well Note: Due to the uncemented annulus, use the surface casing shoe as the open hole weak point for the calculation (5417’ MD / 3028’ TVD). Ugnu formations are open to FIT test pressures 9-5/8” Shoe LOT 11/20/2009, 12.7 ppg EMW 11.23 POOH & LD milling BHA. Gauge mills for wear. If mills are under-gauge, consider a dress off run 11.24 PU stack washer and wash BOPE stack. Function all rams to clear any potential milling debris. * See conditions of approval. Casing test data from step 2.19 and FIT digital data to AOGCC. Page 19 Prudhoe Bay West V-227A SB Injector PTD Application 12.0 Drill 6-1/8” Hole Section 12.1 P/U 6-1/8” directional drilling kick off motor assembly: Ensure BHA components have been inspected previously. Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. Ensure TF offset is measured accurately and entered correctly into the MWD software. Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Planned jetting is 3x9s and 3x10’s. Drill string will be 4” 14# S-135 XT-39. Run a solid float in the surface hole section. 12.2 RIH with 6-1/8” BHA to top of whipstock. Shallow test MWD at the first fill up point. 12.3 Orient directional motor 30° right of high side and slide through window with no pumps or rotary. 12.4 Displace wellbore to 9.2 ppg Baradrill-N drilling fluid 12.5 Production hole section mud program summary: Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 6.125 (hole diameter) for sufficient hole cleaning Run the centrifuge continuously while drilling the production hole, this will help with solids removal. Dump and dilute as necessary to keep drilled solids to an absolute minimum. MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. Page 20 Prudhoe Bay West V-227A SB Injector PTD Application System Type:8.9 – 9.5 ppg Baradrill-N drilling fluid Properties: Interval Density PV YP LSYP Total Solids MBT HPHT Hardness Production 8.5-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100 12.6 Begin drilling 6-1/8” hole section following the on-bottom staging technique: Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K. Slowly begin bringing up rpm’s while monitoring stick slip and BHA vibrations If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU off bottom and restart the on-bottom staging technique. If stick slip continues, consider adding 0.5% lubes to increase lube concentration. 12.7 Drill 6-1/8” OH for ~ 500’, until confirm kicked off, clean surveys, and tangent angle reached 12.8 CBU and observe well for flow 12.9 POOH, orienting motor with whipstock, pulling through with no rotary or pumps 12.10 POOH, LD Motor BHA 12.11 MU RSS BHA 12.12 RIH with RSS BHA 12.13 Drill 6-1/8” hole section to section TD per Geologist and Drilling Engineer. Flow Rate: 200-300 GPM, target min. AV’s 200 ft/min, 250 GPM RPM: 120+ Ensure shaker screens are set up to handle this flowrate. Check for holes in screens on every connection. Minimize pipe movement with pumps off to help keep surge and swab pressures low Take MWD surveys every stand. Surveys can be taken more frequently if necessary (ex: concretion deflection) Monitor torque and drag (with pumps on) every 5 stands Monitor ECD’s, pump pressure, & hookload trends for indications of hole cleaning Good drilling and tripping practices are vital for avoiding 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. MPD will be utilized to monitor pressure build up on connections. Adjust MW as needed. Be prepared for gas hydrates at and below window. Gas hydrates seen on V pad at the Ugnu 4. Watch for gas hydrates on bottoms up, and while drilling ahead in mud returns. 6-1/8” A/C: Page 21 Prudhoe Bay West V-227A SB Injector PTD Application All wells pass with clearance factors >1.0. 12.14 At TD, CBU at least 2 times at 200 ft/min AV (250+ GPM) and rotation (120+ RPM). Pump tandem sweeps if needed Monitor BU for increase in cuttings. Given that this is a high angle slant well, more than 2X BU may be needed to clean the hole. Circulate more if necessary. 12.15 Observe well for flow 12.16 BROOH with the drilling assembly to the 7” window Circulate at full drill rate (lower rate and pulling speed if losses are seen). Rotate at maximum RPM that can be sustained. Target a pulling speed of 5 – 10 min/stand (slip-to-slip time, not including connections) but adjust as dictated by hole conditions If backreaming operations are commenced, continue backreaming to the shoe 12.17 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while BROOH. 12.18 CBU minimum two times at 7” shoe and clean casing with high vis sweeps. Watch for gas hydrates, they can be disturbed while BROOH, and show after flow checks. 12.19 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary. Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise If necessary, increase MW at shoe for any higher than expected pressure seen 12.20 Orient BHA with window orientation and pull through window with no pumps or rotary 12.21 POOH and LD BHA. Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any additional open hole logging runs conducted. Page 22 Prudhoe Bay West V-227A SB Injector PTD Application 13.0 Run 3-1/2” Casing 13.1 R/U and pull wearbushing. 13.2 R/U Weatherford 3-1/2” casing running equipment (CRT & Tongs) Ensure 3-1/2” JFE Bear x XT39 XO on rig floor and M/U to FOSV. Use JFE Bear approved thread compound. Dope pin end only w/ paint brush. R/U a fill up tool to fill casing while running if the CRT is not used. Ensure all casing has been drifted on location prior to running. Be sure to count the total # of joints on the location before running. Keep hole covered while R/U casing tools. Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 13.3 P/U shoe joint and visually verify no debris inside joint. 13.4 Continue M/U & thread locking 120’ shoe track assembly consisting of: 3-1/2” Float Shoe 1 joint – 3-1/2” , 2 Centralizers 10’ from each end w/ stop rings 1 joint –3-1/2” , 1 Centralizer mid joint w/ stop ring 1 joint – 3-1/2” , 1 Centralizer mid joint w/ stop ring 3-1/2” Float Collar 13.5 Continue running 3-1/2” casing Fill casing while running using fill up line on rig floor. Centralization: Do not centralize across or between the oval side pocket mandrels. Install 2 solid body centralizers every joint to TOC Stop rings in the middle Utilize a collar clamp until weight is sufficient to keep slips set properly. Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. Any packing off while running casing should be treated as a major problem. It is preferable to POOH with casing and condition hole than to risk not getting cement returns to the sliding sleeve. 3-1/2” 9.2# L-80 JFE Bear Make-Up Torques: Casing OD Minimum Optimum Maximum 3-1/2”3,500 ft-lbs 3,870 ft-lbs 4,240 ft-lbs Page 23 Prudhoe Bay West V-227A SB Injector PTD Application Page 24 Prudhoe Bay West V-227A SB Injector PTD Application 13.6 Continue running 3-1/2” casing. Circulate bottoms up before exiting the window and before entering SB sands. Watch for hydrate gas 13.7 Make up jewelry per Operations Engineer: 13.8 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 13.9 Slow in and out of slips. 13.10 Circulate and condition mud. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. 13.11 Land tubing hanger. RILDS. Page 25 Prudhoe Bay West V-227A SB Injector PTD Application 14.0 Cement 3-1/2” Production Casing 14.1 Hold a pre-job safety meeting over the upcoming cement operations. Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. Positions and expectations of personnel involved with the cementing operation. Prepare to take returns out the annulus valve since the tubing hanger will be landed. Review test reports and ensure pump times are acceptable. Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 14.2 Document efficiency of all possible displacement pumps prior to cement job. 14.3 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. 14.4 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. 14.5 Fill surface cement lines with water and pressure test. 14.6 Pump 40 bbls 10.0 ppg tuned spacer. 14.9 Drop bottom plug. 14.10 Mix and pump cmt per below recipe. a. Note: cement returns will be taken through annulus valves 14.11 Cement volume based on annular volume + 30% open hole excess. Job will consist of a single 15.3ppg slurry with TOC brought to the sliding sleeve. Estimated Total Cement Volume: Cement Slurry Design: Tail Slurry Density 15.3 lb/gal Yield 1.23 ft3/sk Mix Water 5.57 gal/sk Page 26 Prudhoe Bay West V-227A SB Injector PTD Application 14.12 After pumping cement, drop the top plug and displace with 9.2ppg brine (same density as final drilling MW). 14.13 Displacement calculation: (9,953’-120’) x 0.0087 bpf = 85.5 bbls 14.14 Monitor returns closely while displacing cement. Adjust pump rate if necessary. 14.15 Land top plug. Bleed pressure off to check floats. 14.16 Pressure test to 1500 psi for 30 charted minutes. Bump pressure up to burst HP defender sleeve burst disk. 14.17 Increase pump rate to ~ 5-7 BPM to flush excess IA cement from above the HP defender sleeve 14.18 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. 14.19 Install BPV. ND BOP. Install the plug off tool. 14.20 NU the tubing head adapter and NU the tree. 14.21 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi. 14.22 Pull the plug off tool and BPV. 14.23 Rig up jumper from IA to tubing to allow freeze protect to swap. 14.24 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 14.25 RDMO Innovation i. POST RIG WELL WORK 1. SL a. Shift SS closed. b. Drift for EL. 2. EL a. Run a cement evaluation log. Submit written evaluation from service provider to the AOGCC. 3. F a. An AOGCC opportunity to witness MIT-IA will need to be performed per AOGCC regulations.See conditions of approval. Page 27 Prudhoe Bay West V-227A SB Injector PTD Application Ensure to report the following on wellez: Pre flush type, volume (bbls) & weight (ppg) Cement slurry type, lead or tail, volume & weight Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid Note if casing is reciprocated or rotated during the job Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure Note if pre flush or cement returns at surface & volume Note time cement in place Note calculated top of cement Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to jengel@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 28 Prudhoe Bay West V-227A SB Injector PTD Application 15.0 Innovation Rig BOP Schematic Page 29 Prudhoe Bay West V-227A SB Injector PTD Application 16.0 Wellhead Schematic Page 30 Prudhoe Bay West V-227A SB Injector PTD Application 17.0 Days Vs Depth Page 31 Prudhoe Bay West V-227A SB Injector PTD Application 18.0 Formation Tops & Information Offset Injector Information: o Voidage Replacement Ratio in this fault block is less than 1 o V-219 ~2100’ away from V-227A target Pressures are from downhole gauges, high confidence OBe (highest) Pressure: 2178 psi / 8.65ppg emw This well is shut in, reducing reservoir pressures further History match shows injector pressure gauges falling close to reservoir pressure within 1 week in this fault block o V-224 ~1400’ away from V-227A target Pressures are from downhole gauges, high confidence OBe (highest) Pressure: 2059 psi / 8.07ppg emw This well is shut in, reducing reservoir pressures further History match shows injector pressure gauges falling close to reservoir pressure within 1 week in this fault block o V-227 (parent bore) Is 3730’ away from the V-227A target Pressures are from downhole gauges, high confidence OBe (highest) Pressure: 2030 psi / 8.04ppg emw This well is shut in, reducing reservoir pressures further History match shows injector pressure gauges falling close to reservoir pressure within 1 week in this fault block gg g OBe (highest) Pressure: 2178 psi / 8.65ppg emw gg,g OBe (highest) Pressure: 2059 psi / 8.07ppg emw gg,g OBe (highest) Pressure: 2030 psi / 8.04ppg emw Page 32 Prudhoe Bay West V-227A SB Injector PTD Application Page 33 Prudhoe Bay West V-227A SB Injector PTD Application 19.0 Anticipated Drilling Hazards 6-1/8” Hole Section: Tracking Casing: There is a risk that the BHA after milling the window will track casing. In order to mitigate this risk, a bent motor assembly will be used to kick off before the RSS drilling BHA. Take check shots as needed to ensure separation from the parent well. The top of cement outside the 7” casing in V-227 was logged via USIT at 7,410’ MD (parent RKB reference). Hydrates: Hydrates are present on V-Pad and have been seen as low as the Ugnu 4. Planned window depth is above the Ugnu 4. Be prepared for gas hydrates. Keep an eye on OA pressures. Circulate bottoms up before and after any trips through the window. Keep mud cool. 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 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 wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: No faults are expected. 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 V-pad has a history of H2S on wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Schrader / Orion Pool. . Be prepared for gas hydrates. K PBU V-pad has a history of H2S Page 34 Prudhoe Bay West V-227A SB Injector PTD Application 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Reservoir pressures are expected to be sub-normal. This is based upon offset injection downhole pressure gauges, reservoir modeling and voidage replacement ration less than 1. Abnormal pressure is not expected, however this fault block has a history of MI injection in the Schrader Bluff. Monitor well during connections. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. Well Specific AC: All wells pass AC with separation factors >1.0. p Reservoir pressures are expected to be sub-normal. Page 35 Prudhoe Bay West V-227A SB Injector PTD Application 20.0 Innovation Rig Layout Page 36 Prudhoe Bay West V-227A SB Injector PTD Application 21.0 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. 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DWWKLVSRLQWWKHSUHVVXUHZLOOFRQWLQXHWRULVHEXWDWDVORZHUUDWH7KHV\VWHPLVVKXWLQDQGSUHVVXUH PRQLWRUHGDVZLWKDQ),7 (QVXUHWKDWFDVLQJWHVWDQGVXEVHTXHQW),7WHVWVDUHUHFRUGHGRQWKHVDPHFKDUW'RFXPHQWLQFUHPHQWDO YROXPHSXPSHGDQGUHWXUQHGGXULQJWHVW 3DJH Prudhoe Bay West V-227A SB Injector PTD Application ,QQRYDWLRQ5LJ&KRNH0DQLIROG6FKHPDWLF 3DJH Prudhoe Bay West V-227A SB Injector PTD Application &DVLQJ'HVLJQ 3DJH Prudhoe Bay West V-227A SB Injector PTD Application 0$63 3DJH Prudhoe Bay West V-227A SB Injector PTD Application 6SLGHU3ORW1$'*RYHUQPHQWDO6HFWLRQV SUPERSEDED 3DJH Prudhoe Bay West V-227A SB Injector PTD Application 6XUIDFH3ODW$V%XLOW1$' 6WDQGDUG3URSRVDO5HSRUW )HEUXDU\ 3ODQ9$ZS +LOFRUS1RUWK6ORSH//& 3UXGKRH%D\ 9 3ODQ9 3ODQ9$ SUPERSEDED 25002750300032503500375040004250450047505000True Vertical Depth (500 usft/in)2750 3000 3250 3500 3750 4000 4250 4500 4750 5000 5250 5500 5750 6000 6250 6500 6750 7000 7250 7500Vertical Section at 79.42° (500 usft/in)V-227A wp01 tgt150005500600065007000750080008500900095001000010340V-2277" TOW4 1/2" x 6 1/8"5500600065007000750080008500900095001000010180V-227A wp02KOP : Start Dir 12º/100' : 5500' MD, 3057.54'TVD : 30° RT TFEnd Dir : 5517' MD, 3063.78' TVDStart Dir 3º/100' : 5537' MD, 3070.83'TVDEnd Dir : 7306.77' MD, 3830.27' TVDTotal Depth : 10180.19' MD, 5103.78' TVDUG3UG1NBOBAOBBOBDOBEHilcorp North Slope, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: V-227Ground Level: 52.80+N/-S +E/-WNorthingEastingLatitudeLongitude0.000.005970149.97590767.4570° 19' 41.442 N 149° 15' 49.899 WSURVEY PROGRAMDate: 2021-12-15T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool48.00 5500.00 Survey #7 (V-227) 3_Gyro-CT_Drill pipe5500.00 5950.00 V-227A wp02 (Plan: V-227A) 3_MWD_Interp Azi+Sag5950.00 10180.19 V-227A wp02 (Plan: V-227A) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation3050.30 2971.00 5480.93 UG4A3434.30 3355.00 6431.18 UG33986.30 3907.00 7658.83 UG14546.30 4467.00 8922.35 NB4747.30 4668.00 9375.87 OBA4787.30 4708.00 9466.12 OBB4900.30 4821.00 9721.08 OBD4971.30 4892.00 9881.28 OBEREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: V-227, True NorthVertical (TVD) Reference:V-227A RKB @ 79.30usftMeasured Depth Reference:V-227A RKB @ 79.30usftCalculation Method: Minimum CurvatureProject:Prudhoe BaySite:VWell:Plan: V-227Wellbore:Plan: V-227ADesign:V-227A wp02CASING DETAILSTVD TVDSS MD SizeName3057.92 2978.62 5501.00 7 7" TOW5103.78 5024.48 10180.19 4-1/2 4 1/2" x 6 1/8"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 5500.00 67.58 56.04 3057.54 2265.76 3134.95 0.00 0.00 3497.55 KOP : Start Dir 12º/100' : 5500' MD, 3057.54'TVD : 30° RT TF2 5517.00 69.35 57.13 3063.78 2274.46 3148.15 12.00 30.00 3512.12 End Dir : 5517' MD, 3063.78' TVD3 5537.00 69.35 57.13 3070.83 2284.62 3163.87 0.00 0.00 3529.44 Start Dir 3º/100' : 5537' MD, 3070.83'TVD4 7306.77 63.69 115.16 3830.27 2405.56 4687.98 3.00 108.01 5049.85 End Dir : 7306.77' MD, 3830.27' TVD5 9725.59 63.69 115.16 4902.30 1483.82 6650.59 0.00 0.00 6809.95 V-227A wp01 tgt16 10180.19 63.69 115.16 5103.78 1310.59 7019.45 0.00 0.00 7140.75 Total Depth : 10180.19' MD, 5103.78' TVD 12501500175020002250250027503000325035003750400042504500South(-)/North(+) (500 usft/in)2500 2750 3000 3250 3500 3750 4000 4250 4500 4750 5000 5250 5500 5750 6000 6250 6500 6750 7000 7250West(-)/East(+) (500 usft/in)V-227A wp01 tgt13 0 0 0 3 2 5 0 3 5 0 0375040004250V-2277" TOW4 1/2" x 6 1/8"3500375040004250450047505000V-227A wp02KOP : Start Dir 12º/100' : 5500' MD, 3057.54'TVD : 30° RT TFEnd Dir : 5517' MD, 3063.78' TVDStart Dir 3º/100' : 5537' MD, 3070.83'TVDEnd Dir : 7306.77' MD, 3830.27' TVDTotal Depth : 10180.19' MD, 5103.78' TVDCASING DETAILSTVDTVDSS MDSize Name3057.92 2978.62 5501.00 7 7" TOW5103.78 5024.48 10180.19 4-1/2 4 1/2" x 6 1/8"Project: Prudhoe BaySite: VWell: Plan: V-227Wellbore: Plan: V-227APlan: V-227A wp02WELL DETAILS: Plan: V-227Ground Level: 52.80+N/-S+E/-W NorthingEastingLatitude Longitude0.00 0.005970149.97 590767.45 70° 19' 41.442 N 149° 15' 49.899 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: V-227, True NorthVertical (TVD) Reference: V-227A RKB @ 79.30usftMeasured Depth Reference:V-227A RKB @ 79.30usftCalculation Method:Minimum Curvature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&203$663DJHRI 3UXGKRH%D\+LOFRUS1RUWK6ORSH//&$QWLFROOLVLRQ5HSRUWIRU3ODQ99$ZS(OOLSVHHUURUWHUPVDUHFRUUHODWHGDFURVVVXUYH\WRROWLHRQSRLQWV6HSDUDWLRQLVWKHDFWXDOGLVWDQFHEHWZHHQHOOLSVRLGV&DOFXODWHGHOOLSVHVLQFRUSRUDWHVXUIDFHHUURUV&OHDUDQFH)DFWRU 'LVWDQFH%HWZHHQ3URILOHV'LVWDQFH%HWZHHQ3URILOHV(OOLSVH6HSDUDWLRQ'LVWDQFH%HWZHHQFHQWUHVLVWKHVWUDLJKWOLQHGLVWDQFHEHWZHHQZHOOERUHFHQWUHV$OOVWDWLRQFRRUGLQDWHVZHUHFDOFXODWHGXVLQJWKH0LQLPXP&XUYDWXUHPHWKRG)HEUXDU\ &203$663DJHRI 0.001.002.003.004.00Separation Factor5500 5750 6000 6250 6500 6750 7000 7250 7500 7750 8000 8250 8500 8750 9000 9250 9500 9750 10000 10250Measured Depth (500 usft/in)V-227V-224V-121No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: V-227 NAD 1927 (NADCON CONUS)Alaska Zone 04Ground Level: 52.80+N/-S +E/-W Northing EastingLatitudeLongitude0.000.005970149.97590767.4570° 19' 41.442 N 149° 15' 49.899 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: V-227, True NorthVertical (TVD) Reference: V-227A RKB @ 79.30usftMeasured Depth Reference:V-227A RKB @ 79.30usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2021-12-15T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool48.00 5500.00 Survey #7 (V-227) 3_Gyro-CT_Drill pipe5500.00 5950.00 V-227A wp02 (Plan: V-227A) 3_MWD_Interp Azi+Sag5950.00 10180.19 V-227A wp02 (Plan: V-227A) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)5500 5750 6000 6250 6500 6750 7000 7250 7500 7750 8000 8250 8500 8750 9000 9250 9500 9750 10000 10250Measured Depth (500 usft/in)GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference5500.00 To 10180.19Project: Prudhoe BaySite: VWell: Plan: V-227Wellbore: Plan: V-227APlan: V-227A wp02CASING DETAILSTVD TVDSS MD Size Name3057.92 2978.62 5501.00 7 7" TOW5103.78 5024.48 10180.19 4-1/2 4 1/2" x 6 1/8" Revised 2/2015 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: ____________________________ POOL: ______________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit No. _____________, API No. 50-_______________________. Production should continue to be reported as a function of the original API number stated above. Pilot Hole In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name (_______________________PH) and API number (50-_____________________) from records, data and logs acquired for well (name on permit). Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation order approving a spacing exception. (_____________________________) as Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for well ( ) until after ( ) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (________________________) must contact the AOGCC to obtain advance approval of such water well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (_______________________________) in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. 222-020 Prudhoe Bay Schrader Bluff Oil Pool, Orion Development Area PBU V-227A :(//3(50,7&+(&./,67&RPSDQ\+LOFRUS1RUWK6ORSH//&:HOO1DPH358'+2(%$<8125,19$,QLWLDO&ODVV7\SH'(93(1'*HR$UHD8QLW2Q2II6KRUH2Q3URJUDP'(9)LHOG 3RRO:HOOERUHVHJ$QQXODU'LVSRVDO37'358'+2(%$<6&+5$'(5%/8)2,/1$ 3HUPLWIHHDWWDFKHG<HV (QWLUHZHOOOLHVZLWKLQ$'/ /HDVHQXPEHUDSSURSULDWH<HV 8QLTXHZHOOQDPHDQGQXPEHU<HV 358'+2(%$<6&+5$'(5%/8))2,/±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