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Home My WebLink About224-161MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Tuesday, April 22, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Sully Sullivan P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp North Slope, LLC W-220A PRUDHOE BAY UN POL W-220A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 04/22/2025 W-220A 50-029-23432-01-00 224-161-0 W SPT 4947 2241610 1500 1478 1477 1476 1477 166 226 186 180 INITAL P Sully Sullivan 3/22/2025 Initial MIT-IA , well online 3-17-25 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:PRUDHOE BAY UN POL W-220A Inspection Date: Tubing OA Packer Depth 643 2200 2160 2148IA 45 Min 60 Min Rel Insp Num: Insp Num:mitSTS250323083934 BBL Pumped:3.7 BBL Returned:3.6 Tuesday, April 22, 2025 Page 1 of 1 9 9 9 9 9 9 9 999 99 9 9 9 9 9 James B. Regg Digitally signed by James B. Regg Date: 2025.04.22 15:11:32 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 4/10/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#2025010 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 211-26 50283201280000 208112 1/27/2025 AK E-LINE PPROF T40287 END 1-41 50029217130000 187032 3/13/2025 HALLIBURTON MFC40 T40288 END 2-14 50029216390000 186149 3/12/2025 HALLIBURTON MFC40 T40289 END 3-33A 50029216680100 203215 3/23/2025 HALLIBURTON COILFLAG T40290 GP AN-17A 50733203110100 213049 12/29/2024 AK E-LINE Perf T40291 KALOTSA 3 50133206610000 217028 3/3/2025 AK E-LINE PPROF T40292 KU 12-17 50133205770000 208089 1/28/2025 AK E-LINE Perf T40293 MPI 2-14 50029216390000 186149 2/17/2025 AK E-LINE Plug/Cement T40294 NCIU A-21 50883201990000 224086 3/28/2025 AK E-LINE Plug-Perf T40295 ODSN-25 50703206560000 212030 3/7/2025 HALLIBURTON CORRELATION T40296 PBU 02-08B 50029201550200 198095 3/17/2025 HALLIBURTON RBT T40297 PBU D-08B 50029203720200 225007 3/22/2025 HALLIBURTON RBT T40298 PBU J-25B 50029217410200 224134 3/10/2025 HALLIBURTON RBT T40299 PBU K-12D 50029217590400 224099 3/18/2025 HALLIBURTON RBT T40300 PBU K-19B 50029225310200 215182 3/27/2025 HALLIBURTON RBT T40301 PBU L1-15A 50029219950100 203120 3/27/2025 HALLIBURTON PPROF T40302 PBU M-207 50029238070000 224141 3/18/2025 HALLIBURTON IPROF T40303 PBU P1-04 50029223660000 193063 3/28/2025 HALLIBURTON PPROF T40304 PBU W-220A 50029234320100 224161 3/11/2025 HALLIBURTON RBT T40305 Revision explanation: Fixed API# on log and .las files Please include current contact information if different from above. T40305PBU W-220A 50029234320100 224161 3/11/2025 HALLIBURTON RBT Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.04.10 13:48:56 -08'00' Pr,cidwe R; LtA,� W-7�LOA PTA TZA Ko 10 Regg, James B (OGQ From: James Lott - (C) <jlott@hilcorp.com> Sent: Friday, March 28, 2025 9:01 AM To: Brooks, Phoebe L (OGC) Cc: Regg, James B (OGC) Subject: RE: [EXTERNAL] RE: PBU W-220A MIT-T / IA Attachments: PBU W-220A MIT-Tbg-IA.xlsx Phoebe good morning and apologies forthe late response to this. I was out on Medical. I have updated the MIT Form to reflect the Type Test/Interval/Result. Thank you From: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Sent: Monday, March 24, 2025 10:43 AM To: James Lott - (C) <jlott@hilcorp.com> Cc: jim.regg <jim.regg@alaska.gov> Subject: [EXTERNAL] RE: PBU W-220A MIT-T / IA ' CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Hi James, The Type Test/Interval/Result was missing from the report. Please resubmit. 60 ldin. Type Test InlemJ Result 60 Min. Type Test Interval Result Thank you, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas Conservation Commission Phone:907-793-1242 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake insending it to you., contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: James Lott - (C) <ilott@hilcorp.com> Sent: Sunday, February 23, 2025 2:10 PM To: Regg, James B (OGC) Clim_regg laska.Qov>; DOA AOGCC Prudhoe Bay<doa.aopcc_prudhoe.bav@alaska.gov_>; Brooks, Phoebe L (OGC) < hp oebe;brooks alaska.POv>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: PBU W-220A MIT-T/ IA 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. James Lott HILCORP Drilling Foreman HILCORP INNOVATION Rig PBU, North Slope Alaska 907-670-3094 (Office) 907-398-9069 (Cell) Harmony 1006 Mott@hilcorp.com iameslott3520yahoo.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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. CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.¢ov. From: James Lott - (C) <ilott@hilcorp.com> Sent: Sunday, February 23, 2025 2:10 PM 70: Regg, James B (OGC) <jim.reQe alaska.gov>; DOA AOGCC Prudhoe Bay <doa aoscc prudhoe bav@alaska.Rov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; Wallace, Chris D (OGC) <chris waIlace @alaska.gov> Subject: PBU W-220A MIT-T/ IA 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. James Lott HILCORP Drilling Foreman HILCORP INNOVATION Rig PBU, North Slope Alaska 907-670-3094 (Office) 907-398-9069 (Cell) Harmony 1006 jlott@hilcorp.com iamesIott352@yahoo.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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. James B From: James Lott - (C) <jlott@hilcorp.com> Sent: Friday, March 28, 2025 9:01 AM To: Brooks, Phoebe L (OGC) Cc: \ Regg, James B (OGC) Subject: RE: [EXTERNAL] RE: PBU W-220A MIT-T / IA Attachments: \ PBU W-220A MIT-Tbg-IA.xlsx Categories: \ Green Category Phoebe good morning and apol I have updated the MIT Form to Thankyou the late response to this. I was oelt on Medical. e Type Test/Interval/Result. From: Brooks, Phoebe L (OGC) <phoebe.brooks( Sent: Monday, March 24, 2025 10:43 AM To: James Lott - (C) <jlott@hilcorp.com> Cc: jim.regg <jim.regg@alaska.gov> Subject: [EXTERNAL] RE: PBU W-220A MIT-T/ IA ICAUTION: External sender. DO NOT open li s or atta h Hi James, The Type Test/Interval/Result was missing f m the report. Please 60 Min, Type Test Interval Result 60 Min. Type Test Interval Resutt Thank you, Phoebe Phoebe BrooI s Research Analyst Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 ments from UNKNOWN senders. 1 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to. amemnA.I.Si AOGCC Insoectareribalaska aov phoebebrooks®alarl dov OPERATOR: Hilcam North Slope LLC FIELD / UNIT I PAD: Prudhoe Bay I PBU W-220A DATE: 02/23125 OPERATOR REP: AOGCC REP: on. viallaceRelaska aov Well PBU W-220A Pressures'. Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2241610 Type Inl N Tubing 0 3626— 3525 ' 3511 Type Test P Packer TVD 4941 ' BBL Pump 2.2 ' Iq 0 148 149 149 Interval I Test psi 3500 IBBLRetuml 2.0 OA 1 200 _ 200 200 200 Result P Notes: Well PBU W-220A Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2241610 Type Inj N Tubing 0 fi60 710 701 Type Test P Packer 7VD 4941 BBL Pump 1 8.2 IA 0 3720 3648 3626 Interval I Test psi MO I BEL etuml SO I OA 1 200 200 1 220 210 Result P N.W. Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min, 60 Min. PTD Type lnj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Noes: Well Pressures: Pretest Initial 15 Min, 30 Min. 45 Min. W Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type lnj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Retum OA Result Noes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTO Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Retum OA Reault Notes: Well Pressures: Pretest Initial 15 Min. W Min. 45 Min. 60 Min. Type lnj Tubing Type Test ackPTD Per NO BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures'. Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type lnj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Relurr OA ResuN NNotein: TYPE INJ Coen TYPE TEST coal INTERVAL Cal ResuNOOOea W=worst P=Preeaure Test 1=Initial Test P=Pau G=Gas 0= One Nesc ion in NWes) 4=Four Year Cycle F=Fail s = s1wry V = RequirM by Val 1= lmmerGusrre I = ImJUWaaI Warr.or, O = Other triaxehe In neat N = Not INetlmg Form 10-426 (Revised 012017) PBV W-n0A MIT -TN -IA STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________PRUDHOE BAY UN POL W-220A JBR 03/21/2025 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:1 LEL sensor at bell nipple had to be calibrated. Good test Test Results TEST DATA Rig Rep:Vanhoose/LarsonOperator:Hilcorp North Slope, LLC Operator Rep:Montague/Yearout Rig Owner/Rig No.:Hilcorp Innovation PTD#:2241610 DATE:2/18/2025 Type Operation:DRILL Annular: 250/3000Type Test:BIWKLY Valves: 250/3000 Rams: 250/3000 Test Pressures:Inspection No:bopAGE250219092249 Inspector Adam Earl Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 4 MASP: 1787 Sundry No: Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 2 P Inside BOP 1 P FSV Misc 0 NA 15 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13 5/8"P #1 Rams 1 2 7/8 X 5 1/2"P #2 Rams 1 Blind P #3 Rams 1 9 5/8"NT #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3 1/8"P HCR Valves 2 3 1/8"P Kill Line Valves 2 3 1/8"P Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P1400 200 PSI Attained P23 Full Pressure Attained P104 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P6 @ 2283 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P FPMeth Gas Detector P PH2S Gas Detector 0 NAMS Misc Inside Reel Valves 0 NA Annular Preventer P11 #1 Rams P8 #2 Rams P9 #3 Rams P9 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P1 9 9 9 9 9999 9 9 9 9 LEL sensor at bell nipple Meth Gas Detector FP Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 4/02/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250402 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 19RD 50133205790100 219188 3/20/2025 YELLOWJACKET GPT-PERF BCU 19RD 50133205790100 219188 3/16/2025 YELLOWJACKET PLUG BRU 212-26 50283201820000 220058 3/21/2025 AK E-LINE Perf BRU 212-26 50283201820000 220058 3/15/2025 AK E-LINE Perf CLU 7 50133205310000 203191 1/22/2025 YELLOWJACKET PLUG IRU 11-06 50283201300000 208184 3/20/2025 AK E-LINE Perf KALOTSA 10 50133207320000 224147 3/1/2025 YELLOWJACKET GPT-PLUG-PERF KBU 22-06Y 50133206500000 215044 1/25/2025 YELLOWJACKET GPT-PLUG-PERF KU 13-06A 50133207160000 223112 3/18/2025 AK E-LINE CIBP MPE-20A 50029225610100 204054 3/13/2025 READ CaliperSurvey MPI 1-39A 50029218270100 206187 3/4/2025 YELLOWJACKET PERF MPU C-01 50029206630000 181143 1/30/2025 YELLOWJACKET PERF MPU K-17 50029226470000 196028 2/7/2025 AK E-LINE Caliper MPU S-53 50029238110000 224159 3/7/2025 YELLOWJACKET SCBL MRU A-15RD2 50733201050200 202019 3/10/2025 AK E-LINE TubingCut PBU 18-27E 50029223210500 212131 3/15/2025 YELLOWJACKET RCT PBU B-30A 50029215420100 201105 3/7/2025 READ CaliperSurvey PBU S-10A 50029207650100 191123 11/18/2024 YELLOWJACKET CBL-TEMP PBU W-220A 50029234320100 224161 2/22/2025 YELLOWJACKET SCBL Revision explanation: Fixed API# on log and .las files Please include current contact information if different from above. T40256 T40256 T40257 T40257 T40258 T40259 T40260 T40261 T40262 T40263 T40264 T40265 T40266 T40267 T40268 T40269 T40270 T40271 T40272PBU W-220A 50029234320100 224161 2/22/2025 YELLOWJACKET SCBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.04.02 12:55:27 -08'00' David Douglas Hilcorp North Slope, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Hilcorp North Slope, LLC Date: 03/07/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL: PBU W-220A PTD: 224-161 API: 50-029-23432-01-00 FINAL LWD FORMATION EVALUATION + GEOSTEERING (01/27/2025 to 02/15/2025) x ROP, AGR, ABG & BaseStar Gamma Ray, EWR-M5 and StrataStar Resistivity, LithoStar Density and Porosity, Invert Presentation (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Survey x Geosteering and EOW Report SFTP Transfer – Main Folders: PBU W-220A LWD Subfolders: PBU W-220A Geosteering Subfolders: Please include current contact information if different from above. 224-161 T40204 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.03.07 15:35:44 -09'00' 1 Gluyas, Gavin R (OGC) From:Lau, Jack J (OGC) Sent:Monday, March 3, 2025 10:27 AM To:AOGCC Records (CED sponsored) Subject:FW: PBU W-220A (PTD# 224-161) 9-5/8" Intermediate CBL Attachments:W-220 Cement Bond Log Final Log 2-22-2025.pdf; PBU W-220A Approved 10-401 1-14-25.pdf; PBW W-220A 9.625 Csg test-FIT 2-11-2025.pdf From: Tyson Shriver <Tyson.Shriver@hilcorp.com> Sent: Saturday, February 22, 2025 4:18 AM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Joseph Engel <jengel@hilcorp.com> Subject: PBU W-220A (PTD# 224-161) 9-5/8" Intermediate CBL Jack, Please see the attached CBL for the 9-5/8” intermediate casing on PBU W-220A (PTD# 224-161). The 9-5/8” intermediate cement job was completed 2/10/2025 with full returns and good lift pressure. Log results show TOC greater than 250’ TVD above the top of pool. I have also attached the approved PTD, 9-5/8” casing test and FIT for quick reference. Let me know if you need anything additional. Thank you, Tyson Shriver Hilcorp Alaska PBU GC2 OE (L, V, W, Z) o: 907-564-4542 c: 406-690-6385 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: 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. 5 M� ._ YELLOWACK CASING AND LEAK-OFF FRACTURE TESTS Well Name:PBW W-220A Date:2/11/2025 Csg Size/Wt/Grade:9.625" 40# L-80 Supervisor:Montague/LaFluer Csg Setting Depth:11,358 TMD 5249 TVD Mud Weight:9.2 ppg LOT / FIT Press =775 psi LOT / FIT =12.04 ppg Hole Depth =11388 md Fluid Pumped=2.3 Bbls Volume Back =2.3 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 ->0 0 ->15 332 ->4 95 ->30 636 ->8 172 ->45 940 ->12 259 ->60 1270 ->16 345 ->75 1598 ->20 434 ->90 1934 ->24 511 ->105 2267 ->28 593 ->120 2620 ->32 671 ->125 2702 ->36 749 -> ->38 775 -> -> -> -> -> -> -> Enter Holding Enter Holding Time Here Pressure Here Time Here Pressure Here ->0 775 ->0 2702 ->1 737 ->1 2668 ->2 725 ->2 2662 ->3 718 ->3 2657 ->4 713 ->4 2653 ->5 705 ->5 2650 ->6700 ->10 2635 ->7695 ->15 2623 ->8688 ->20 2612 ->9681 ->25 2602 ->10 678 ->30 2594 -> -> -> -> -> -> 0 4 8 12 16 20 24 28 32 3638 15 30 45 60 75 90 105 120 125 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 102030405060708090100110120130140Pressure (psi)Strokes (# of) LOT / FIT DATA CASING TEST DATA 775737725718713705700695688681678 270226682662265726532650 2635 2623 2612 2602 2594 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 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:Lau, Jack J (OGC) To:AOGCC Records (CED sponsored) Subject:FW: HAK PBU W-220A (PTD: 224-161) 13-3/8" Casing Test and FIT Date:Tuesday, January 28, 2025 11:02:23 AM Attachments:PBU W-220A 13.375 Casing Test & FIT.pdf From: Joseph Engel <jengel@hilcorp.com> Sent: Tuesday, January 28, 2025 10:08 AM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: HAK PBU W-220A (PTD: 224-161) 13-3/8" Casing Test and FIT Jack – Attached is the casing test and FIT for 13-3/8” casing on W-220A. Joe Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC 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, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CASING AND LEAK-OFF FRACTURE TESTS Well Name:PPB W W-220A Date:1/27/2025 Csg Size/Wt/Grade:13 3/8" 68#L-80 Supervisor:Jam es Lo tt Csg Setting Depth:2093 TMD 1886 TVD Mud Weight:9.4 ppg LOT / FIT Press =261 psi LOT / FIT =12.06 ppg Hole Depth =2135 md Fluid Pumped=1.2 Bbls Volume Back =0.9 bbls Estimated Pump Output:0.062 Barrels/Stroke LOT / FIT DATA CASING TEST DATA Enter Strokes Enter Pressure Enter Strokes Enter Pressure Here HHere Here HHere ->00 ->08 ->117 ->224 ->243 ->485 ->369 ->6 194 ->499 ->8 312 ->6 169 ->10 420 ->8 235 ->12 524 ->9 261 ->14 613 -> ->16 708 -> ->18 808 -> ->20 920 -> ->30 1517 -> ->40 2200 -> -> Enter Holding Enter Holding Enter Holding Enter Holding Time Here Pressure Here Time Here Pressure Here ->0 261 ->0 2183 ->1 226 ->5 2166 ->2 216 ->10 2158 ->3 208 ->15 2152 ->4 203 ->20 2150 ->5 197 ->25 2148 ->6 191 ->30 2146 ->7 186 -> ->8 184 -> ->9 182 -> ->10 179 -> -> -> -> -> -> -> 0 1 2 3 4 6 8 9 0 2 4 6 8 10 12 14 16 18 20 30 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 0 1020304050Pressure (psi)Strokes (# of) LOT / FIT DATA CASING TEST DATA 261 226216208203197191186184182179 2183 2166 2158 2152 2150 2148 2146 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 0 5 10 15 20 25 30Pressure (psi)Time (Minutes) LOT / FIT DATA CASING TEST DATA Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Sean McLaughlin Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Prudhoe Bay Field, Polaris Oil Pool, PBU W-220A Hilcorp North Slope, LLC Permit to Drill Number: 224-161 Surface Location: 4934' FSL, 1175' FEL, Sec 21, T11N, R12E, UM, AK Bottomhole Location: 1802' FNL, 1075' FWL, Sec 23, T11N, R12E, UM, AK Dear Mr. McLaughlin: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie L. Chmielowski Commissioner DATED this 14th day of January 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.01.14 14:37:41 -09'00' Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2024.12.27 09:34:23 - 09'00' Sean McLaughlin (4311) January 20, 2025 By Grace Christianson at 4:24 pm, Dec 27, 2024 JJL 1/10/2025 50-029-23432-01-00 SFD 1/10/2025 CDW 01/13/2025 Approve variance request for packer setting depth. Approve variance request to not run step-rate test or surveillance log (AIO 25A Rule 4). 224-161 DSR-1/8/25 Witnessed BOP Test to 3000 psi, Annular to 2500 psi. Witnessed MITIA pre and post-injection. CBL required for casing cement through confining interval per 25.412 (d) *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.01.14 14:39:03 -09'00' 01/14/25 01/14/25 RBDMS JSB 011625 115 2 115 2 W-220A -wp8 K221112 K241112 W-01 W-05W-06 W-07 W-08 W-17 19B W-20200 W-200PB1 W-201W-202 W-202L1 W-203 W-204 W-204PB1 W-205 W-205L1PB1 W- W-209 W-21 W-210 W-212 W-213 W-214 W-215 W-216 W-217 W-218 W-219 W-219PB2 W-22 W-220W-221 W-223 W-23 W-24 W-29 31A W-32 W-59 9PB1 W-220A_wp01 W-220A -wp8 HILCORP NORTH SLOPE Greater Prudhoe Bay W-220A AOR MAP W-220A Proposed Location FEET 0 500 1,000 1,500 POSTED WELL DATA Well Label WELL SYMBOLS INJ Well (Water Flood) P&A Oil/Gas J&A Active Oil Injector Location Shut in Injector REMARKS Well symbols at top of Schrader OBD sand. Purple circle and lines = 1320' radius from the completed OBDsand in W-220A. (OBD sand is top proposed sand for injection). By: BTR -2024 December 19, 2024 PETRA 12/19/2024 3:57:05 PM Well Name PTD API Distance / Status Top of Oil Pool (SB OBd, MD) Top of Oil Pool (SB OBd, TVDss) Top of Cmt (MD) Top of Cmt (TVDss) Zonal Isolation Comments PBU W-201 201-051 50-029-23007-00-00 70' / Producer 7472' 5118' 2874' 2591' Closed Pumped 72 bbls 13.0 ppg Class 'G' cement followed by 71.5 bbls 15.8 ppg Class 'G' cement. No losses reported. 7" TOC logged at 2874' MD with USIT on 6/3/2001. Passing CMIT-TxIA to 2390 psi 10/7/2019. PBU W-202 210-133 50-029-23434-00-00 934' / Producer 9770' 5125' 4650' 3647' Closed Pumped 124 bbls 15.8 ppg Class 'G' cement. No losses reported. 7-5/8" TOC logged at 4650' MD with USIT on 1/30/2001. Passing MIT-IA to 3410 psi 3/15/2011. PBU W-205 203-116 50-029-23165-00-00 840' / Producer 7494' 5093' 5265' 3955' Closed Pumped 122 bbls (566 sx) 15.8 ppg Premium Class 'G' cement. 7-5/8" casing was reciprocated during cementing operations and 100% returns achieved throughout job. Including shoe track volume, volumetric calculations place the TOC in the 7-5/8" x 9-7/8" annulus at 5265' MD when accounting for 30% washout. Passing CMIT-TxIA to 2500 psi 8/10/2022. PBU W-209 203-128 50-029-23170-00-00 493' / Injector 9950' 5189' 6970' 3813' Closed Pumped 78 bbls 15.8 Class 'G' cement. No losses reported. 7" TOC logged at 6970' MD with USIT on 10/18/2003. Passing MIT-IA to 1644 psi 8/12/2024. PBU W-223 211-006 50-029-23440-00-00 100' / Injector 9373' 5176' 5460' 3328' Closed Pumped 79 bbls 11.0 ppg LiteCrete followed by 39 bbls 15.8 ppg Class 'G' cement. No losses reported. 7" TOC logged at 5460' MD with USIT on 5/18/2011. Passing MIT-IA to 2338 psi 5/9/2024. Area of Review PBU W-220A Prudhoe Bay West (PBU) W-220A Drilling Program Version 1 12/15/2024 Table of Contents 1.0 Well Summary .......................................................................................................................... 2 2.0 Management of Change Information ....................................................................................... 3 3.0 Tubular Program:..................................................................................................................... 4 4.0 Drill Pipe Information: ............................................................................................................. 5 5.0 Internal Reporting Requirements ............................................................................................ 6 6.0 Pre-Window Plugged & Planned Wellbore Schematic ............................................................ 7 7.0 Drilling / Completion Summary ............................................................................................. 10 8.0 Mandatory Regulatory Compliance / Notifications ............................................................... 11 9.0 MIRU & Test BOPE ............................................................................................................... 14 10.0 Pull Tubing String, Cut & Pull 7” .......................................................................................... 16 11.0 Set Whipstock, Mill 12-1/4” Window ..................................................................................... 18 12.0 Drill 12-1/4” Hole Section ....................................................................................................... 21 13.0 Run 9-5/8” Intermediate Casing ............................................................................................. 24 14.0 Cement 9-5/8” Casing ............................................................................................................. 27 15.0 Drill 8-1/2” Hole Section ......................................................................................................... 30 16.0 Run & Cement 7” x 4-1/2” Injection Liner ............................................................................ 34 17.0 Run Upper Completion/ Post Rig Work ................................................................................ 41 18.0 Innovation Rig BOP Schematic .............................................................................................. 44 19.0 Wellhead Schematic ................................................................................................................ 45 20.0 Days Vs Depth ......................................................................................................................... 46 21.0 Formation Tops & Information.............................................................................................. 47 22.0 Anticipated Drilling Hazards ................................................................................................. 49 23.0 Innovation Rig Layout ............................................................................................................ 53 24.0 FIT Procedure ......................................................................................................................... 54 25.0 Innovation Rig Choke Manifold Schematic ........................................................................... 55 26.0 Casing Design .......................................................................................................................... 56 27.0 MASP ...................................................................................................................................... 57 28.0 Spider Plot (NAD 27) (Governmental Sections) ..................................................................... 59 29.0 Surface Location ..................................................................................................................... 60 Page 2 Prudhoe Bay West W-220A SB Injector Drilling Procedure 1.0 Well Summary Well PBU W-220A Pad Prudhoe Bay W Pad Planned Completion Type 4-1/2” Injection Target Reservoir(s) Schrader Bluff OBd Sand Planned Well TD, MD / TVD 19,255’ MD / 5255’ TVD PBTD, MD / TVD 19,245’ MD / 5255’ TVD Surface Location (Governmental) 4934' FSL, 1175' FEL, Sec 21, T11N, R12E, UM, AK Surface Location (NAD 27) X= 612,048.9, Y=5,959,910.7 Top of Productive Horizon (Governmental)306' FSL, 2442' FEL, Sec 10, T11N, R12E, UM, AK TPH Location (NAD 27) X= 615,959.8 , Y=5,965,902.1 BHL (Governmental) 1802' FNL, 1075' FWL, Sec 23, T11N, R12E, UM, AK BHL (NAD 27) X= 619,603, Y= 5,958,570.6 AFE Number 251-00006 AFE Drilling Days 32 AFE Completion Days 4 Maximum Anticipated Surface Pressure - Intermediate 1786 psig Maximum Anticipated Surface Pressure - Production 1787 psig Maximum Anticipated Pressure (Downhole/Reservoir) 2309 psig Work String 5” 19.5# S-135 NC 50 Innovation KB Elevation above MSL: 26.5 ft + 53.4 ft = 79.9 ft GL Elevation above MSL: 53.4 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Prudhoe Bay West W-220A SB Injector Drilling Procedure 2.0 Management of Change Information Page 4 Prudhoe Bay West W-220A SB Injector Drilling Procedure 3.0 Tubular Program: Hole Section OD (in)ID (in)Drift (in)Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 20” 19.124 - - - A-53 *17-1/2” 13-3/8” 12.415 12.259 14.375 68 L-80 BTC 5,020 2,260 1,556 12-1/4” 9-5/8” 8.835 8.679 10.625 40 L-80 TXP 5,750 3,090 916 8-1/2” 7” 6.276 6.151 7.656 26 L-80 563 7,240 5,410 604 4-1/2” 3.958 3.833 5.200 12.6 L-80 563 8,430 7,500 288 Tubing 4-1/2” 3.958 3.833 5.000 12.6 L-80 JFEBear 8,430 7,500 288 *Existing hole section and casing string Page 5 Prudhoe Bay West W-220A SB Injector Drilling Procedure 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) Intermediate & Production 5”4.276” 3.25” 6.625” 19.5 S-135 NC50 30,730 34,136 560klb Page 6 Prudhoe Bay West W-220A SB Injector Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. Report covers operations from 6am to 6am Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry. Ensure time entry adds up to 24 hours total. Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates Submit a short operations update each work day to mmyers@hilcorp, 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 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 Tyson Shriver 907.564.4542 tyson.shriver@hilcorp.com Geologist Ben Rickards 210.287.7711 benjamin.rickards@hilcorp.com Reservoir Engineer Tim Davis 907.564.4886 tidavis@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com Page 7 Prudhoe Bay West W-220A SB Injector Drilling Procedure 6.0 Pre-Window Plugged & Planned Wellbore Schematic Pre Rig, Post P&A Sundry Schematic Page 8 Prudhoe Bay West W-220A SB Injector Drilling Procedure Pre Window Schematic Page 9 Prudhoe Bay West W-220A SB Injector Drilling Procedure Proposed Schematic Page 10 Prudhoe Bay West W-220A SB Injector Drilling Procedure 7.0 Drilling / Completion Summary PBU W-220A is a sidetrack injector planned to be drilled in the Schrader Bluff OBd sands. W-220A is part of a multi-well program targeting the Schrader Bluff sand on PBU W-pad The parent bore, W-220, is a shut-in vertical injection well. The Schrader Bluff reservoir will be abandoned prior to the rig’s arrival on the well, operations covered on a separate sundry. The directional plan is 12-1/4” intermediate hole and 9-5/8” casing string set into the top of the Schrader Bluff OBd sand. An 8-1/2” lateral section will be drilled. An injection liner will be run and cemented in the open hole section, followed by 4-1/2” tubing. The well will not be pre-produced. The Innovation Rig will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately January 20, 2025, pending rig schedule. 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” Tubing, cut & pull 7” casing 4. Set 13-3/8” whipstock, mill 12-1/4” window 5. Drill 12-1/4” hole to TD 6. Run and cement 9-5/8” casing 7. Drill 8-1/2” lateral to well TD 8. Run and cement 7” x 4-1/2” liner 9. Run Upper Completion 10. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Intermediate hole: No mud logging. Remote geologist. LWD: GR + Res 2. Production Hole: No mud logging. Remote geologist. LWD: GR + ADR (For geo-steering), Neu/Den Page 11 Prudhoe Bay West W-220A SB Injector Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. BOPs shall be tested at (2) week intervals during the drilling and completion of PBU W-220A. 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”. 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)”. Page 12 Prudhoe Bay West W-220A SB Injector Drilling Procedure AOGCC Regulation Variance Requests: Hilcorp would like to request a variance from 20 AAC 25.412.(b) which states: “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.” In order to effectively produce this fault block, the current wellplan has the intermediate casing shoe landing at the OBd production interval at ~85 degrees inclination. In order to make the ball and rod we land to set the production packer slickline accessible, the X nipple in the tubing tail must be landed at less than 70 degrees inclination. The MD we currently have planned for 70 degrees is at ~10,200’ MD. The X-nipple below the production packer will be set at ~10,100’ MD and the production packer will be ~50’ MD above the X nipple which puts it at ~10,050’ MD / ~5042’ TVD. The intermediate casing shoe is planned at ~10,972’ MD / ~5167’ TVD which means the planned packer depth is ~922’ MD away. From a TVD standpoint, the production tubing packer is ~125’ TVD from the intermediate casing shoe. With the intermediate casing set in the Schrader Bluff sand, and the injection packer set inside the intermediate casing, injection fluids will be confined to the Schrader bluff sands. Hilcorp would like to request a variance from AIO 25A Rule #4 which states: “b. Within three months of start of injection in a new or converted injector, a step rate test and surveillance log must be run for detection of fluids moving out of the approved injection stratum.” The Polaris pool is unique among nearby Schraeder Bluff oil pools in its requirement to perform step-rate tests and surveillance logs on all new or converted injectors to justify the maximum injection pressures for a given well. The original justification for this change that was shared with the Commission in November 2003 were step-rate tests on W-212 and S-215 which indicated injection pressures up to 0.8 psi/ft caused no detectable migration of fluids outside of approved strata. To date, all step-rate tests performed on injectors in the Polaris oil pool have indicated that the established injection gradient of 0.8 psi/ft does not cause fluids to migrate out of zone. For W-220A, Hilcorp is requesting that 0.8 psi/ft be established as the injection limit for this well without conducting the step-rate test and surveillance log listed in AIO 25A Rule #4.CDW 01/13/2025 Approve variance request. For W-220A, Hilcorp is requestingjg p g ,pq that 0.8 psi/ft be established as the injection limit for this well without conducting the step-rate test andpj surveillance log listed in AIO 25A Rule #4. CDW 01/13/2025 Approve variance request. See additional detail/explanation in email from J. Engel to J. Lau dated 1/7/2025. Page 13 Prudhoe Bay West W-220A SB Injector Drilling Procedure Summary of Innovation BOP Equipment & Test Requirements Hole Section Equipment Test Pressure (psi) 12-1/4” 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 250/3,000 8-1/2” 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 and changing rams 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 14 Prudhoe Bay West W-220A SB Injector Drilling Procedure 9.0 MIRU & Test BOPE 9.1 W-220 will be the parent well for this sidetrack. Ensure to review the attached surface plat and make sure the rig is over appropriate well. 9.2 Ensure PTD 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 conductor to prevent any wear to BOPE or wellhead. 9.6 Mud loggers WILL NOT be used on either hole section. 9.7 Give AOGCC 24hr notice of BOPE test, for test witness. 9.8 Install BPV, ND tree and THA 9.9 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 4-1/2” x 7” VBRs in top cavity,blind ram in bottom cavity. Single ram can be dressed with 2-7/8” x 5-1/2” VBRs or 5” solid body rams 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. 9.10 RU MPD RCD and related equipment 9.11 Run 5” BOP test plug 9.12 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min. Test with 5” test joint and test VBR’s with 3-1/2” test joint Confirm test pressures with PTD Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech Page 15 Prudhoe Bay West W-220A SB Injector Drilling Procedure 9.13 RD BOP test equipment 9.14 Dump and clean mud pits, send spud mud to G&I pad for injection. 9.15 Mix 9.4 LSND for well work operations 9.16 Set wearbushing in wellhead 9.17 If needed, rack back as much 5” DP in the derrick as possible to be used when drilling future hole section. 9.18 Ensure 5” liners in mud pumps White Star Quattro 1,300 HP mud pumps are rated at 4,097 psi, 381 gpm @ 140 spm @ 96.5% volumetric efficiency. Page 16 Prudhoe Bay West W-220A SB Injector Drilling Procedure 10.0 Pull Tubing String, Cut & Pull 7” 10.1 RU tubing handling equipment Tubing is 3-1/2” 9.2# L-80 TCII with a 4-1/2” XO pup immediately below the tubing hanger Tubing cut depth: ~2,500’, confirm with pre rig well work report A 0.433” OD TEC line was run from surface to multiple gauge mandrels. A spooling unit will be needed to pull the TEC line with the pipe. Full cross-coupling clamps were installed on every joint for the top 36 joints and then every other joint thereafter. 3-1/2” tubing joints are R2 (~31.5’ long). 10.2 PU landing joint or spear and engage tubing hanger 10.3 Verify KWF and no pressure on tubing or annulus. Backout lock down screws 10.4 Pull tubing hanger with landing joint 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. RD tubing handling equipment 10.7 MU Baker or Yellowjacket mechanical cutter, RIH and cut 7” casing at ~2,250’ MD. 10.8 POOH and inspect mechanical cutter for wear. LD mechanical cutter If inspection indicates, RIH with backup cutter and repeat. 10.9 RU casing handing equipment Casing is 7” 26# L-80 VamTop HT 10.10 PU spear and engage casing hanger 10.11 Back out lock down screws 10.12 Pull casing free If casing does not pull free, contingent cutting and fishing operations will take place to pull the 7” casing. Any changes will be discussed with AOGCC prior to implementation. 10.13 Circulate at least 1.5x BU after pulling hanger to the floor. If desired, circulate a sweep surface to surface to clean the tubing. Fluid behind the 7” is dead crude from surface down to ~2370’ MD and 9.2 ppg LSND mud from ~2370’ MD to the 9-5/8” liner shoe at 6228’ MD. 10.14 POOH laying down the 7” casing 7” joints are documented to not have centralizers. g Fluid behind the 7” is dead crude from surface down to ~2370’ MD and 9.2 ppg LSND mud from ~2370’ MD to the 9-5/8” liner shoe at 6228’ MD. Per Joe Engel "When cutting the 7” casing, we will be lined up to take returns from the 13-3/8” x 7” annulus to a tank. We will be milling with 9.2ppg fluid, if any u-tubing does occur while or after cutting before the dead crude is circulated out it will be contained" Page 17 Prudhoe Bay West W-220A SB Injector Drilling Procedure 10.15 RD casing handling equipment Page 18 Prudhoe Bay West W-220A SB Injector Drilling Procedure 11.0 Set Whipstock, Mill 12-1/4” Window 11.1 MU 13-3/8” casing scraper assembly and RIH to top of 9-5/8” liner hanger 11.2 MU and RIH with 13-3/8” CIBP and set at top of 9-5/8” liner hanger, ~ 2190’ MD 11.3 RU casing testing equipment and PT 13-3/8” casing to 2000 psi for 30 min, chart test. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 11.4 Whipstock Set Depth Information Planned TOW: 2100’ WS should be set to avoid a collar while milling the window, casing tally available in O- Drive Drilling Foreman, Whipstock hand and drilling engineer to agree on the set depth 11.5 MU 12-1/4” mill/whipstock assembly as per WIS tally MU HWDP, string magnets and float sub Ensure magnets are in trough, under shakers and flow area to capture metal shavings circulated 11.6 Install MWD and orient. Rack back mill assembly Ensure a dedicated MWD is available for the orientation of the whipstock 11.7 Verify offset between WD, and the whipstock tray, witnessed by the Drilling Foreman, MWD/DD and WIS rep. Document and record offset in well file. 11.8 Slowly run in the hole as per fishing Rep. 11.9 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. 11.10 Shallow test MWD at first drill pipe fill up depth. 11.11 Stop at least 30-45’ above planned set depth, obtain survey with MWD. 11.12 Milling fluid will be 9.4 ppg LSND 11.13 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. 11.14 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 LOHS – Consult with milling hand Page 19 Prudhoe Bay West W-220A SB Injector Drilling Procedure 11.15 Whipstock Orientation Diagram: Desired orientation of the whipstock face is 15L to 45L, target is 30 LOHS Hole Angle at window interval (@ 2,100’, 50° inc, 33° azi). Sidetrack tangent section is 69 inclination and 17 azimuth 11.16 Once whipstock is in desired orientation, set WS per Baker Hughes rep. 11.17 CBU and confirm 9.4 ppg MW in/out Ensure Mud properties are sufficient for transporting metal cuttings Visc: 40-60, YP: 18-20 11.18 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. 11.19 If possible, install catch trays in shaker underflow chute to help catch metal cuttings. 11.20 Clean catch trays and ditch magnets frequently while milling window. 11.21 Mill window until the uppermost mill has passed across the entire tray. Dress and polish window as needed. 11.22 With upper mill at the end of the tray, this will drill ~ 20’ of new hole. 11.23 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. 11.24 Circulate bottoms up until even MW in/out and hole is clean of metal shavings. Reduce mud properties for drilling. 11.25 Pull back into 13-3/8” casing and perform FIT to 11.5 pg EMW, Chart Test 45L 15L Page 20 Prudhoe Bay West W-220A SB Injector Drilling Procedure 13-3/8” casing is cemented. Open hole weak point is the top of the window at ~ 2100’ MD, 1888’ TVD 11.5 Fit provides a > 25 bbl KT based upon 9.4 ppw MW, 8.46 PP (swabbed kick at 9.4 BHP) If 11.5 is not achieved, contact drilling engineer. 11.26 POOH & LD milling BHA. Gauge mills for wear. 11.27 PU stack washer and wash BOPE stack. Function all rams to clear any potential milling debris. Email digital data for FIT to AOGCC upon completion of FIT Page 21 Prudhoe Bay West W-220A SB Injector Drilling Procedure 12.0 Drill 12-1/4” Hole Section 12.1 P/U 12-1/4” motor drilling assembly: Ensure BHA components have been inspected previously. Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. Ensure TF offset is measured accurately and entered correctly into the MWD software. GWD will be used to confirm separation Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Drill string will be 5” 19.5# S-135. Run a solid float in the hole section. 12.2 RIH with 12-1/4” BHA, to top of whipstock. Shallow test MWD at the first fill up point 12.3 Orient directional motor same as whipstock orientation and slide through window with no pumps or rotary Confirm set orientation of whipstock, and have BHA match 12.4 Displace wellbore to 9.4 ppg LSND 9.4 ppg due to hydrates, free gas and potential for Cretaceous over pressure (although none has been see at W pad, be aware from 4500’ TVD and deeper) 12.5 Drill with motor assembly to ~ 3000’ MD This will confirm Kick off and build to tangent angle of ~ 70* GWd will be used for confirming separation 12.6 CBU and POOH Ensure motor is oriented and pulled through the window with no pumps or rotary 12.7 LD motor BHA and PU RSS BHA, RIH 12.8 Drill 12-1/4” hole section to section TD, in the Schrader OBd sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. Efforts should be made to minimize dog legs in the intermediate hole. Keep DLS < 6 deg / 100. Hold a safety meeting with rig crews to discuss: Well control procedures and rig evacuation Flow rates, hole cleaning, mud cooling, etc. Pump sweeps and maintain mud rheology to ensure effective hole cleaning. Keep mud as cool as possible to keep from over melting hydrates Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen Page 22 Prudhoe Bay West W-220A SB Injector Drilling Procedure Slow in/out of slips and while tripping to keep swab and surge pressures low Ensure shakers are functioning properly. Check for holes in screens on connections. Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off.Wood has been observed across shakers during the interval TVD. Gas hydrates are have been seen on W pad. In PBW they have been encountered typically around 1660’ TVD (Base of Perm) to 3400’ TVD (Top Ugnu) and below. Be prepared for hydrates: Keep mud temperature as cool as possible, Target 60-70*F. Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as cold pre-made mud on trucks ready. Drill through hydrate sands and quickly as possible, do not backream. Gas hydrates can be identified by the gas detector and a decrease in MW or ECD Monitor returns for hydrates, checking pressurized & non-pressurized scales Do not stop to circulate out gas hydrates – this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 fph MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well. MW will not control gas hydrates, but will affect how gas breaks out at surface. Intermediate Hole AC, CF <1.0 : W-220 & 220PB2 have CF less than 1 – 220 is the parent bore we are kicking out of and will have separation confirmed with GWD 12.9 12-1/4” hole mud program summary: Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. MW for free gas and hydrates based upon offset wells Depth Interval MW (ppg) Window - TD 9.4+ (For Hydrates/Free Gas based on offset wells and cretaceous injection mitigation) PVT System: PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the interval to prevent losses and strengthen the wellbore. Page 23 Prudhoe Bay West W-220A SB Injector Drilling Procedure Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action. Casing Running:Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). System Type:8.8 – 9.8 ppg LSND Properties: Section Density LSYP PV YP MPT API FL pH Temp Intermediate 8.8 –9.8 4-6 15 - 30 25-45 <8 <10 8.5 –9.0 70 F 12.10 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem sweeps and drop viscosity. 12.11 RIH to bottom, proceed to BROOH to window Pump at full drill rate (400-600 gpm), and maximize rotation. Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions Monitor well for any signs of packing off or losses. Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 12.12 CBU x2 at the 13-3/8” window and clean casing with high visc sweeps 12.13 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 window for any higher than expected pressure seen 12.14 Orient BHA and pull through window with no pumps or rotary 12.15 TOOH and LD BHA Page 24 Prudhoe Bay West W-220A SB Injector Drilling Procedure 13.0 Run 9-5/8” Intermediate Casing 13.1 Install 9-5/8” solid body casing rams in the upper ram cavity. RU testing equipment. PT to 250/3,000 psi with test joint. RD testing equipment. 13.2 R/U 9-5/8” casing running equipment (CRT & Tongs) Ensure 9-5/8” TXP x NC50 XO on rig floor and M/U to FOSV. Use BOL 2000 thread compound. Dope pin end only w/ paint brush. R/U of CRT if hole conditions require. R/U a fill up tool to fill casing while running if the CRT is not used. Ensure all casing has been drifted to 8.75” on the 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, visually verify no debris inside joint. 13.4 Continue M/U & thread locking 120’ shoe track assembly consisting of: 9-5/8” Float Shoe 1 joint –9-5/8” , 2 Centralizers 10’ from each end w/ stop rings 1 joint – 9-5/8” , 1 Centralizer mid joint w/ stop ring 1 joint –9-5/8” , 1 Centralizer mid joint with stop ring 9-5/8” Float Collar Ensure proper operation of float equipment while picking up. Ensure to record S/N’s of all float equipment 13.5 Continue running 9-5/8” intermediate casing Fill casing while running using fill up line on rig floor. Use BOL 2000 thread compound. Dope pin end only w/ paint brush. Centralization: Bowspring Centralizers only 1 centralizer every joint to ~ 1000’ MD from shoe 1 centralizer every 2 joints to TOC Verify depth of uppermost significant oil with Geologist 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. 9-5/8” 40# L-80 TXP MUT: Casing OD Minimum Optimum Maximum 9-5/8”18860 20960 23060 Page 25 Prudhoe Bay West W-220A SB Injector Drilling Procedure Page 26 Prudhoe Bay West W-220A SB Injector Drilling Procedure 13.6 Continue running 9-5/8” intermediate casing Fill casing while running using fill up line on rig floor. Use BOL 2000 thread compound. Dope pin end only w/ paint brush. 13.7 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 13.8 Slow in and out of slips. 13.9 Pick up casing hanger and landing joint. Lower casing to setting depth. Confirm measurements. 13.10 Have slips staged in cellar, along with necessary equipment if needed 13.11 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 27 Prudhoe Bay West W-220A SB Injector Drilling Procedure 14.0 Cement 9-5/8” Casing 14.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. How to handle cement returns at surface if seen. Ensure vac trucks are on standby and ready to assist. Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses Review test reports and ensure pump times are acceptable. Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 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 remaining 60 bbls 10.5 ppg tuned spacer. 14.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below calculations, confirm actual cement volumes with cementer after TD is reached. 14.8 Cement volume based on annular volume + 40% open hole excess. Job will consist of tail, TOC brought to 500’ above the Schrader Bluff Calculations based upon cement 500’ MD above Schrader NB Sand, 9,239’ MD, NB Top: 9,739’ MD. Note: TOC will be adjusted to 500’ above uppermost significant oil Estimated Total Cement Volume: Section Calculation Vol (bbl) Vol (ft3) Vol (sks) 12-1/4" OH x 9-5/8" Casing (11290-9239)' x 0.0558 bpf x 1.4 = 160.2 898.6 9-5/8" Shoetrack 120' x 0.0758 bpf = 9.1 51.0 Total Tail 169.3 949.6 818.6Tail Page 28 Prudhoe Bay West W-220A SB Injector Drilling Procedure Cement Slurry Design (Single Stage Cement Job): 14.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue with the cement job. 14.10 After pumping cement, drop top plug (Shutoff plug) and displace cement with mud out of mud pits Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 14.11 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 bps (5” liners) for the Quattro pump output. 14.12 Displacement calculation: = (11290’-120’) x .0758 bpf = = 846.6 bbls 14.13 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 14.14 Land top plug and pressure up to 500 psi over bump pressure. Bleed pressure and check floats. 14.15 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, before consulting with Drilling Engineer. 14.16 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held Tail Slurry System HalCem Density 15.8 lb/gal Yield 1.16 ft3/sk Mix Water 4.98 gal/sk Page 29 Prudhoe Bay West W-220A SB Injector Drilling Procedure 14.17 9-5/8” will be set on a hanger 14.18 CBL evaluation of intermediate cement job will be performed after production liner is set and cemented. This will allow sufficient time for cement to reach compressive strength 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 30 Prudhoe Bay West W-220A SB Injector Drilling Procedure 15.0 Drill 8-1/2” Hole Section 15.1 MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM) 15.2 TIH to TOC above the shoe track. Note depth TOC tagged on morning report. 15.3 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = ~2,875 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.4 Drill out shoe track and 20’ of new formation. 15.5 CBU and condition mud for FIT. 15.6 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. Submit casing test and FIT digital data to AOGCC. 12.0 ppg desired to cover shoe strength for expected ECDs. A 9.8 ppg FIT is the minimum required to drill ahead 9.8 ppg FIT provides >>25bbls based on 9.5ppg MW, 8.46ppg PP (swabbed kick at 9.5 BHP) 15.7 POOH and LD cleanout BHA 15.8 PU 8-1/2” directional BHA. Ensure BHA components have been inspected previously. Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. Ensure TF offset is measured accurately and entered correctly into the MWD software. Ensure MWD is RU and operational. Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. Drill string will be 5” 19.5# S-135 NC50. Run a solid float sub in the production hole section. Schrader Bluff Bit Jetting Guidelines Formation Jetting TFA NB 6 x 14 0.902 OA 6 x 13 0.778 OB 6 x 13 0.778 Email digital data of casing test, cementing summary, and FIT to AOGCC upon completion of FIT Page 31 Prudhoe Bay West W-220A SB Injector Drilling Procedure 15.9 8-1/2” hole section mud program summary: Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for sufficient hole cleaning Run the centrifuge continuously while drilling the production hole, this will help with solids removal. Dump and dilute as necessary to keep drilled solids to an absolute minimum. MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type:8.9 – 9.5 ppg Baradrill-N drilling fluid Properties: Interval Density PV YP LSYP Total Solids MBT HPH T Hardness Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100 System Formulation: Product Concentration Water KCL KOH N-VIS DEXTRID LT BARACARB 5 BARACARB 25 BARACARB 50 BARACOR 700 BARASCAV D X-CIDE 207 0.955 bbl 11 ppb 0.1 ppb 1.0 – 1.5 ppb 5 ppb 4 ppb 4 ppb 2 ppb 1.0 ppb 0.5 ppb 0.015 ppb Page 32 Prudhoe Bay West W-220A SB Injector Drilling Procedure 15.10 TIH with 8-1/2” directional assembly to bottom 15.11 Install MPD RCD 15.12 Displace wellbore to 9.2 ppg Baradrill-N drilling fluid Density may change based upon TD of prior hole section 15.13 Begin drilling 8-1/2” hole section, on-bottom staging technique: Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K. Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes 15.15 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer. Flow Rate: 350-550 GPM, target min. AV’s 200 ft/min, 385 GPM RPM: 120+ Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection Monitor Torque and Drag with pumps on every 5 stands Monitor ECD, pump pressure & hookload trends for hole cleaning indication Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. Use ADR to stay in section. Reservoir plan is to stay in OBd sand. Limit maximum instantaneous ROP to < 250 FPH. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur. Target ROP is as fast as we can clean the hole without having to backream connections Schrader Bluff OBd Concretions: 4-6% Historically MPD will be utilized to monitor pressure build up on connections. 8-1/2” Lateral A/C, CF < 1.0: There are no wells with a CF < 1.0 15.16 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons learned and best practices. Ensure the DD is referencing their procedure. Patience is key! Getting kicked off too quickly might have been the cause of failed liner runs on past wells. If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so we have a nice place to low side. Attempt to lowside in a fast drilling interval where the wellbore is headed up. Page 33 Prudhoe Bay West W-220A SB Injector Drilling Procedure Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working string back and forth. Trough for approximately 30 minutes. Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 15.17 At TD, CBU at least 4 times at 200 ft/min AV (385+ GPM) and rotation (120+ RPM). Pump tandem sweeps if needed Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary If seepage losses are seen while drilling, consider reducing MW at TD Increase lube % for liner run based upon prior wells 15.18 BROOH with the drilling assembly to the 9-5/8” casing shoe Circulate at full drill rate (less if losses are seen, 350 GPM minimum). Rotate at maximum RPM that can be sustained. Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as dictated by hole conditions If backreaming operations are commenced, continue backreaming to the shoe 15.19 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while BROOH. 15.20 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps. 15.21 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 15.22 POOH and LD BHA. 15.23 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit diameter is sufficient for future ball drops. Only LWD open hole logs are planned for the hole section. There will not be any additional logging runs conducted. Page 34 Prudhoe Bay West W-220A SB Injector Drilling Procedure 16.0 Run & Cement 7” x 4-1/2” Injection Liner 16.1 Note: If there are any OHST performed, remove the centralizers on the first 3 joints 16.2 Well control preparedness: In the event of an influx of formation fluids while running the 7” x 4-1/2” liner, the following well control response procedure will be followed: P/U & M/U the 5” safety joint with 4-1/2” crossover installed on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW. -OR- 7“ XO installed on bottom, TIW valve in open position on top, 7” handling joint above TIW. These joints shall be fully M/U and available prior to running the first joint of 4-1/2” liner or 7” liner, respectively. Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW. Proceed with well kill operations. 16.3 R/U liner running equipment. Ensure all casing has been drifted on the deck prior to running. Be sure to count the total # of joints on the deck before running. Keep hole covered while R/U casing tools. Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 16.4 Run 4-1/2” injection liner Use API Modified or “Best O Life 2000 AG”thread compound. Confirm pipe dope with TRS. Dope pin end only w/ paint brush. Wipe off excess. Thread compound can plug the screens Utilize a collar clamp until weight is sufficient to keep slips set properly. Use lift nubbins and stabbing guides for the liner run. Install jewelry as per the Running Order (From Completion Engineer post TD). o ~30 NCS Sleeves, 1 sleeve every ~250’MD Centralization: 1 per joint, solid body centralizers Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm Liner Torque – ftlbs OD PPF Connection Minimum Optimum Maximum Yield Torque 4-1/2 12.6 Hydril 563 3200 3700 5600 12600 7 26 Hydril 563 7800 9400 13700 39000 Page 35 Prudhoe Bay West W-220A SB Injector Drilling Procedure Page 36 Prudhoe Bay West W-220A SB Injector Drilling Procedure Page 37 Prudhoe Bay West W-220A SB Injector Drilling Procedure 16.5 RU 7” running equipment and run 7” 26# H563 section ~1,440’ total. TOL ~9,850’ MD Centralized ½ joints, bowspring centralizers 16.6 Ensure to run enough 7” liner is provide for sufficient overlap inside 9-5/8” casing tubing packer completion. Tentative liner set depth ~9,850’ MD. 7” will be ran under the liner hanger for the production packer. Confirm with completion engineer. 16.7 Ensure hanger/pkr will not be set in a 9-5/8” connection. AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8” connection. 16.8 Before picking up Baker Flex Lock liner hanger / ZXP packer assembly, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 16.9 M/U Baker Flex Lock liner hanger and ZXP liner top packer to liner. Confirm with OE any 7” joints between liner top packer and 4-1/2” liner for tubing packer setting depth Liner running tool extension will need to be ran so liner wiper darts are positioned at the 7” x 4-1/2” XO 16.10 Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.11 RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. Ensure 5” DP/HWDP has been drifted There is no inner string planned to be run, as opposed to previous wells. The DP should auto fill. Monitor FL and if filling is required due to losses/surging. Use HWDP as needed for running liner 16.12 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 16.13 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. 16.14 If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. Page 38 Prudhoe Bay West W-220A SB Injector Drilling Procedure 16.15 TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.16 Rig up to pump down the work string with the rig pumps. 16.17 Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed 1,600 psi while circulating. Confirm all pressures with Baker. 16.18 Plan is to set liner hanger and release running tool prior to cementing. Drop ball and wait for ball to land on seat. Pressure up to 2,600 psi to set the Flex lock liner hanger. Hold for 5 minutes. Slack off 20K lbs on the Flex Lock liner hanger to ensure the HRDE setting tool is in compression for release from the liner hanger/packer. Bleed pressure and release running tool. 16.19 Prior to proceeding with cement job, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 16.20 Circulate and condition mud for cement job 16.21 RU Lines for cement job if not already done so 16.22 Pump 30 bbls of 11ppg tuned spacer 16.23 Mix and pump cement as per plan 16.24 Cement volume based on OH annular volume + open hole excess (30%). Job will consist of single slurry, TOC brought to the 9-5/8” casing shoe, ~ 11,290’ MD TOC planned at casing shoe due to historical gauge hole, extended liner lap that exceeds regulatory minimum, decreased risk of excess cement impacting function of liner hanger/packer setting sequence Cement Slurry Design (Single Stage Cement Job) Section Calculation Vol (bbl) Vol (ft3) Vol (sks) 8-1/2" OH x 4-1/2" (19,255 - 11,290)' x 0.0505 bpf x 1.3 = 522.9 2933.5 4-1/2" Shoetrack 120' x 0.0152 bpf = 1.8 10.1 Total Tail 524.7 2943.6 1682.0Tail Tail Slurry System SoluCem Density 15 lb/gal Yield 1.75 ft3/sk Mixed Water 7.88 gal/sk Page 39 Prudhoe Bay West W-220A SB Injector Drilling Procedure 16.25 After pumping cement, drop dart and displace cement with mud out of mud pits. Displacement calculations are based upon 5” dp from surface to liner top (9,850’ MD) 2-7/8” liner running tool extension from liner top to 7” x 4-1/2” XO (11290’ MD) 2-7/8” 6.5# EUE Due to liner wiper plug effective diameter 4-1/2” from 7” x 4-1/2” XO to TD of 19255’ MD Displacement Calculation: 9850’ * .0171 bpf (5” dp capacity) = 168.4 bbl (DP volume) (11290 – 9850) * .0058bpf (2-7/8” capacity) = 8.4 bbl (19255’-120’-9850’) * .0152bpf (4-1/2” cap) = 141.2 bbl (Liner volume) = 318 bbl 16.26 Monitor returns and pump pressure closely while displacing, slow donw pumps when dart latches onto liner wiper plug and when plug lands 16.27 Land liner wiper plug and pressure up to 500 psi over bump pressure. Bleed pressure and check floats. If floats are not holding, shut in and hold 500 psi over bump pressure until cement builds compressive strength. Ensure to report the following on well report: 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, weight & type of displacing fluid Note if casing is reciprocated or rotated during the job Calculated volume of displacement , actual displacement, 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 time cement in place & calculated top of cement Send final “As-Run” casing tally & casing and cement report to jengel@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. 16.28 Continue pressuring up 4,000 psi to set the ZXP liner top packer and release the HRDE running tool. 16.29 Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 RPM and set down 50K again. 16.30 PU with running tool above Liner top packer and circulate bottoms up to remove any excess cement from around the running tool. ()p(py) (19255’-120’-9850’) * .0152bpf (4-1/2” cap) = 141.2 bbl (Liner volume) = 318 bbl ( =(19255'-120'-11290)*.0152 = 119.2 bbls296.1 bbls Page 40 Prudhoe Bay West W-220A SB Injector Drilling Procedure Ensure a minimum of 1 BU has been pumped prior to any pressure testing, this is to remove any cement around the running tool that could set up under pressure 16.31 Reengage liner running tool. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted. 16.32 Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 16.33 PU pulling running tool free of the packer and displace with at max rate to wash the liner top. Pump sweeps as needed. 16.34 POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned, LD DP on the TOOH. Note: Once running tool is LD, swap to the completion AFE. Page 41 Prudhoe Bay West W-220A SB Injector Drilling Procedure 17.0 Run Upper Completion/ Post Rig Work 17.1 RU Slickline and perform CBL from liner top (~9850’ MD) to 1000’ above calculated TOC of 9- 5/8” casing Calculated TOC on 9-5/8” with excess ~9239’ MD, w/o excess ~8,419’ MD 17.2 RU to run 4-1/2”, 12.6#, L-80 JFEBear tubing. Ensure wear bushing is pulled. Ensure 4-1/2”, 12.6#, L-80 JFEBear x NC50 crossover is on rig floor and M/U to FOSV. Ensure all tubing has been drifted in the pipe shed prior to running. Be sure to count the total # of joints in the pipe shed before running. Keep hole covered while RU casing tools. Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info. Monitor displacement from wellbore while RIH. 17.3 PU, MU and RIH with the following 4-1/2” completion jewelry (tally to be provided by Operations Engineer): Tubing Jewelry to include: 2x X Nipple 1x Production Packer i. Confirm packer set depth with OE for post rig wire line ball and rod retrieval. 1x X Nipple XXX joints, 4-1/2”, 12.6#, L-80 JFEBear WLEG Email CBL to AOGCC and gain approval before running completion. Required to have 500' MD of cement above NB (hydrocarbon zone). Page 42 Prudhoe Bay West W-220A SB Injector Drilling Procedure Page 43 Prudhoe Bay West W-220A SB Injector Drilling Procedure 17.4 PU and MU the tubing hanger. 17.5 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with band/clamp summary. 17.6 Land the tubing hanger and RILDS. Lay down the landing joint. 17.7 Install 4” HP BPV. ND BOP. Install the plug off tool. 17.8 NU the tubing head adapter and NU the tree. 17.9 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi. 17.10 Pull the plug off tool and BPV. 17.11 Reverse circulate the well over to corrosion inhibited source water follow diesel to freeze protect for both tubing and IA to 3,000’ MD. Open well at surface / rig up jumper and allow freeze protect to U-tube between tubing and IA. 17.12 Drop the ball & rod and complete loading tubing and hydraulically set the packer as per Halliburton’s setting procedure 17.13 Pressure up and test the tubing to 3500 psi for MIT-T with 1000 psi on the IA. Bleed off the tubing to 2000psi. Test the IA to 3500 psi for MIT-IA. Record and notate all pressure tests (30 minutes) on chart. Notify AOGCC 24hrs prior to test for opportunity to witness 17.14 Bleed both the IA and tubing to 0 psi. 17.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. Work with Ops Engineer and Well Integrity to complete 10-426 Form for the initial MIT-T and MIT-IA. This form must be completed regardless of AOGCC witness. 17.16 RDMO Innovation i. POST RIG WELL WORK Slickline o Pull B&R and RHC body Coil o Contingent: Pull B&R and RHC body if SL unable to o Shift injection sleeves open o Contingent: Pump 15% HCl to breakdown cement behind injection sleeve Ops o Put well on injection o AOGCC witnessed MIT-IA once injection is stable Page 44 Prudhoe Bay West W-220A SB Injector Drilling Procedure 18.0 Innovation Rig BOP Schematic Page 45 Prudhoe Bay West W-220A SB Injector Drilling Procedure 19.0 Wellhead Schematic Page 46 Prudhoe Bay West W-220A SB Injector Drilling Procedure 20.0 Days Vs Depth Page 47 Prudhoe Bay West W-220A SB Injector Drilling Procedure 21.0 Formation Tops & Information Reference Plan:COMMENTSBPRF Water1,842.9-1763 2,031 811 8.46SV5 Water1,942.8-1863 2,188 855 8.46SV3 Gas Hydrates2,588.9-2509 3,706 1139 8.46Gas Hydrates expected SV3, SV2, & SV1 sands: ~1970' - 3540' MDSV1 Gas Hydrates3,076.9-2997 5,080 1354 8.46Ugnu 4A Heavy Oil3,438.8-3359 6,099 1513 8.46Possible Heavy Oil in Ugnu 4A: ~4025' - 4210' MDUG3 Water3,716.9-3637 6,882 1635 8.46Ugnu MA Heavy Oil4,624.9-4545 9,174 2035 8.46NB Schrader Bluff Water4,908.9-4829 9,739 2160 8.46OA Top Schrader Bluff Oil5,054.9-4975 10,082 2224 8.46Oba Top Schrader Bluff Oil5,114.9-5035 10,254 2251 8.46Obc Top Schrader Bluff Oil5,193.9-5114 10,552 2285 8.46OBd Top (Heel) Schrader Bluff Oil5,246.9-5167 10,972 2309 8.46W-220A wp08ANTICIPATED FORMATION TOPS & GEOHAZARDSTOP NAMELITHOLOGYEXPECTEDFLUIDTVD(FT)TVDSS(FT)MD(FT)EASTINGEst.PressureGradient Page 48 Prudhoe Bay West W-220A SB Injector Drilling Procedure *Planned mud weight across Ugnu is about 9.6 - 9.7 ppg. SFD * Page 49 Prudhoe Bay West W-220A SB Injector Drilling Procedure 22.0 Anticipated Drilling Hazards 12-1/4” Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates/Free Gas Gas hydrates have been seen on PBU W Pad. Be prepared for them. They have been reported between 1800’ and 3140’ TVD across Prudhoe. MW has been chosen based upon successful trouble free penetrations of offset wells. Be prepared for gas hydrates o Keep mud temperature as cool as possible, Target 60-70*F o Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as cold premade mud on trucks ready o Drill through hydrate sands and quickly as possible, do not backream. Remember that hydrate gas behaves differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud cut weight. Isolate/dump contaminated fluid to remove hydrates from the system. Cretaceous Over Pressure: W-Pad does not have a history of over-pressure in the cretaceous interval (4500-5300’ TVD). However, as a precaution ensure MW is above 9.0. Be prepared while drilling this interval. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPM’s when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: There are no known wells with a clearance factory <1.0. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Well Specific A/C: No Wells with CF < 1.0 Page 50 Prudhoe Bay West W-220A SB Injector Drilling Procedure Wellbore stability (Permafrost, running sands and gravel Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Maintain mud parameters and increase MW to combat running sands and gravel formations. Stuck pipe, wood chunks over shakers and other hole stability issues are specific to W pad. Be prepared and review Pad Data Sheet. Bad see pad data sheet H2S: Treat every hole section as though it has the potential for H2S. PBU W-Pad has a history of H2S on wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion Pool. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. PBU W-Pad has a history of H2S ony wells in all reservoirs. Page 51 Prudhoe Bay West W-220A SB Injector Drilling Procedure 8-1/2” Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: Crossing faults, known or unknown, can result in drilling into unstable formations that may impact future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared for accordingly. H2S: Treat every hole section as though it has the potential for H2S. PBU W-Pad has a history of H2S on wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion Pool. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. PBU W-Pad has a history of H2S ony wells in all reservoirs. Page 52 Prudhoe Bay West W-220A SB Injector Drilling Procedure Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. Well Specific A/C: No wells with CF < 1.0 Page 53 Prudhoe Bay West W-220A SB Injector Drilling Procedure 23.0 Innovation Rig Layout Page 54 Prudhoe Bay West W-220A SB Injector Drilling Procedure 24.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 55 Prudhoe Bay West W-220A SB Injector Drilling Procedure 25.0 Innovation Rig Choke Manifold Schematic Page 56 Prudhoe Bay West W-220A SB Injector Drilling Procedure 26.0 Casing Design Page 57 Prudhoe Bay West W-220A SB Injector Drilling Procedure 27.0 MASP Page 58 Prudhoe Bay West W-220A SB Injector Drilling Procedure Page 59 Prudhoe Bay West W-220A SB Injector Drilling Procedure 28.0 Spider Plot (NAD 27) (Governmental Sections) Page 60 Prudhoe Bay West W-220A SB Injector Drilling Procedure 29.0 Surface Location Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. PRUDHOE BAY, POLARIS OIL 224-161 PBU W-220A PRUDHOE BAY WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UN POL W-220AInitial Class/TypeSER / PENDGeoArea890Unit11650On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2241610PRUDHOE BAY, POLARIS OIL - 640160NA1 Permit fee attachedYes Surface Location lies within ADL0028263; Top Productive Interval lies in ADL0028261; TD lies in ADL0047451.2 Lease number appropriateYes3 Unique well name and numberYes PRUDHOE BAY, POLARIS OIL - 640160 - governed by CO 484A4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitYes14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For servYes AOI 25A15 All wells within 1/4 mile area of review identified (For service well only)No16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 20" 90.5# driven to 108'18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitYes Yes25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedNA27 If diverter required, does it meet regulationsYes All fluids overbalanced to expected pore pressure.28 Drilling fluid program schematic & equip list adequateYes 1 annular, 3 ram stack tested to 3000 psi.29 BOPEs, do they meet regulationYes 13-5/8" , 5000 psi stack tested to 3000 psi.30 BOPE press rating appropriate; test to (put psig in comments)Yes Innovation has 10X 2-9/16"" manual gate valves, 1 x 3-1/8" manual choke and 1 x 3-1/8" remote hyd choke31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownYes Treat every hole section as though it has the potential for H2S.33 Is presence of H2S gas probableYes34 Mechanical condition of wells within AOR verified (For service well only)No H2S measures in procedure. W-Pad wells are known to be H2S bearing in all reservoris.35 Permit can be issued w/o hydrogen sulfide measuresYes Normal pressure gradient expected. MPD will be utilized. Materials will be onsite to weight up mud system36 Data presented on potential overpressure zonesNA 1 ppg above highest anticipated mud wt.37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate1/7/2025Appr DateApprSFDDate1/10/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJJL 1/14/2025*&:JLC 1/14/2025