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224-089
Originated: Delivered to:30-Jan-25 Alaska Oil & Gas Conservation Commiss 30Jan25-NR ATTN: Meredith Guhl 333 W. 7th Ave., Suite 100 600 E 57th Place Anchorage, Alaska 99501-3539 Anchorage, AK 99518 (907) 273-1700 main (907)273-4760 fax WELL NAME API # SERVICE ORDER #FIELD NAME SERVICE DESCRIPTION DELIVERABLE DESCRIPTION DATA TYPE DATE LOGGED MT7-89 50-103-20889-00-00 224-089 Greater Mooses Tooth WL TTiX-PPROF FINAL FIELD 5-Jan-25 1R-06A 50-029-21331-01-00 210-056 Kuparuk River WL Plug Setting FINAL FIELD 13-Jan-25 3T-612 50-103-20896-00-00 224-128 Kuparuk River WL TTiX-SCMT FINAL FIELD 17-Jan-25 3S-610 50-103-20875-00-00 223-126 Kuparuk River WL TTiX-PPROF FINAL FIELD 23-Jan-25 Transmittal Receipt ________________________________ X_________________________________ Print Name Signature Date Please return via courier or sign/scan and email a copy to Schlumberger. Nraasch@slb.com SLB Auditor - TRANSMITTAL DATE TRANSMITTAL # A Delivery Receipt signature confirms that a package (box, envelope, etc.) has been received. The package will be handled/delivered per standard company reception procedures. The package's contents have not been verified but should be assumed to contain the above noted media. # Schlumberger-Private T40040 T40041 T40042 T40043 MT7-89 50-103-20889-00-00 224-089 Greater Mooses Tooth WL TTiX-PPROF FINAL FIELD 5-Jan-25 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.01.31 08:15:00 -09'00' T + 1 337.856-7201 1058 Baker Hughes Drive Broussard, LA 70518, USA Oct 01, 2024 AOGCC Attention: Natural Resources Technician 333 W. 7th Ave., Suite 100 Anchorage, Alaska 99501-3539 Subject: Final Log Distribution for ConocoPhillips Alaska, Inc. MT7-89 / MT7-89PB1 Greater Mooses Tooth API #: 50-103-20889-00/50-103-20889-70 Permit No: 224-089 Rig: Doyon 26 The final deliverables were uploaded via https://copsftp.sharefile.com/ for the above well. Items delivered: MWD/LWD Digital Las Data, Graphic Images CGM/PDF and Survey Files. MT7-89/ MT7-89PB1 are located in a federal oil and gas unit. Only with respect to the MT7-89 and MT7-89PB1 Well Data, CPAI hereby waives its right to indefinite confidentiality, under 5 U.S.C. 552(b)(4) and (9). Nothing in this communication should be construed as a waiver of indefinite confidentiality on any other wells. Please note that for wells not on State land, a state agency should seek consent from the landowner prior to the release of well data by the state agency. See, e.g., AS 43.55.025(f)(2)(C)(i). Here, the landowner is the Bureau of Land Management (BLM) and/or Arctic Slope Regional Corporation (ASRC). Thank you. Signature of receiver & date received: Please return transmittal letter to: Benjamin Jacobi Benjamin.M.Jacobi@conocophillips.com Luis Arismendi Luis.arismendi@bakerhughes.com MT7-89: T39639 MT7-89PB1: T39640 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.10.09 08:05:02 -08'00' 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: Greater Mooses Tooth 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 13345 12200 Casing Collapse Structural Conductor Surface 2260 Intermediate 8260 Production Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name:Weifeng Dai Contact Email: Contact Phone: 907-265-6936 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Wells Engineering Manager Chris Brillon weifeng.dai@conocophillips.com Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior writte n approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Length Size TVD Burst AOGCC USE ONLY Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft):Perforation Depth MD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 AA098885, AA081800, AA081781 224-089 P.O. Box 100360 Anchorage, Alaska, 99501-0360 50-103-20899-00-00 ConocoPhillips Alaska. Inc. Proposed Pools: GMTU MT7-89 Rendezvous Rendezvous MD 8860 5020 120 3080 7477 120 4009 11652 20 13-3/8 80 9-5/8 / 9-7/811612 3959 8/8/2024 mmmm m wn nn P s 2 6 5 6 t y t __ o c N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 324-460 LSBy Grace Christianson at 9:22 am, Aug 09, 2024 X SFD 8/9/2024VTL 8/9/2024 Initial BOP test to 5000 psig; subsequent BOP test to 3500 psig Annular preventer test to 2500 psig Intermediate II cement evaluation may use SonicScope under the attached Conditions of Approval Surface casing LOT and annular LOT to the AOGCC as soon as available. BOP stack proposed approved while drilling the Int I(MPSP 1994 psig) Diverter waiver granted per 20 AAC 25.035(h) Approval is granted for a 21 Day BOPE test interval with the attached conditions.file w/ PTD 10-407X 8/8/2024 X Aug 09, 2024 plugback Victoria Loepp 8/8/2024 JLC 8/9/2024 Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.08.11 14:35:41 -08'00' 08/11/24 20889 JSB RBDMS JSB 081224 *0707 CPAI’s request to allow BOPE testing on a 21-day interval is approved with the following conditions: - CPAI must continue to implement the Between Wells Maintenance Program as approved by AOGCC. - The initial test after rigging up BOPE to drill a well must be to the rated working pressure as provided in API Standard 53. - CPAI is encouraged to take advantage of opportunities to test within the 21-day time limit. - CPAI must adhere to original equipment manufacturer recommendations and replacement parts for BOPE. - Requests for extensions beyond 21 days must include justification with supporting information demonstrating the additional time is necessary for well control purposes or to mitigate a stuck drill string. ConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907-276-1215 August 7th, 2024 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Sundry to Approved Program for MT7-89 Dear Sir or Madam: ConocoPhillips Alaska, Inc. hereby applies for a Sundry to Change Approved Program for MT7-89, an onshore producer well from the MT7 drilling pad currently being drilled with the Doyon 26 drilling rig. MT7-89 is planned to be a non-fracture stimulated horizontal producer within the Alpine C reservoir. The 16” surface hole has been drilled to planned TD with 13-3/8” casing run to 4,009’ MD / 3,080’ TVD. The 12-1/4” intermediate 1 hole was drilled to planned TD into the HRZ shales and tapered 9-5/8 / 9-7/8” casing was run to 11,652’ MD / 7,477’ TVD. The 8-1/2” x 9-7/8” int 2 hole was drilled into Alpine D as per plan to 11,345’ MD/ 8,329’ TVD, 7-5/8” liner was not able to reach set depth. The liner was pulled out of hole and a clean out run was performed and had issue starting at ~12,300’ MD due to collapsed shale . Current and upcoming operations are as follows: x Pull out of hole clean out BHA x Run cement stinger to tag bottom, spot hi-vis pill to 12,200’ MD. x Pump kick off plug from 12,200’ MD to 11,400’ MD (TOC 252’ inside 9-7/8” int 1 casing) x Pull out of hole cement stinger x Perform full BOP test x Pick up 8-1/2”x 9-7/8” int 2 drilling assembly and run in hole x Tag TOC with 10k WOB x Drill out cement plug and kick off x Continue to drill int 2 to section TD, offset from the original wellbore plan by +/- 70’ x Return to original PTD with int 2 liner operations followed by production section and completion operations to the original lateral end point of the approved TD Please find attached the information for your review. Pertinent information attached to this application includes the following: 1. A proposed schematic of plug back. 2. A proposed schematic of sidetrack. If you have any questions or require further information, please contact Weifeng Dai at 907-265-6936 (Weifeng.Dai@conocophillips.com) or Chris Brillon at 907-265-6120. Sincerely, cc: MT7-89 Well File / Jenna Taylor ATO 1560 David Lee ATO 1552 Chris Brillon ATO 1548 Weifeng Dai Staff Drilling Engineer ,, 7-5/8” liner was not able to reach set depth 20" 94 ppf H-40 Insulated Conductor 80 feet, cemented to surface MT7-89 Plug Back Proposed Schematic 8/7/2024 16" Surface Hole Surface Casing 13-3/8" 68# L-80 Hyd563 Set at 4,009' MD / 3,080' TVD 12-¼” Intermediate 1 Hole Intermediate 1 Casing 9-7/8" 62.8# L-80 HYD563 Set @ 11,652' MD / 7,477' TVD Plan Int1 TOC 9,077' MD / 5,444' TVD 8-½” x 9-7/8" ” Intermediate 2 Hole TD @ 13,345' MD / 8,329' TVD TOC @ 11,400' BOC @ 12,200' Collapsed shale Tubing / Liner Completion:1) 4-½” X Landing Nipple (3.813" ID)2) 4-½” x 1” KBG 4-5 (3x)3) HES Opsis Downhole Gauge4) Baker Premier Production Packer5) 4-½” DB Landing Nipple (3.75" ID)6) Baker Liner Top Packer / Hanger w/ Tie Back sleeve4-½” 12.6# L-80 Hyd563 Liner w/ swell packers and AU sleeveMW: 9.1 Visc Brine20" 94 ppf H-40 Insulated Conductor80 feet, cemented to surface6-1/2” Production Hole TD at 20,196' MD / 8,314' TVDTubing4-1/2" 12.6# L-80 Hyd563MT7-89A wp03 ProposedXGLGLGLGL8/7/2024Production Packer DQ Xpak LH & Packer Downhole Gauge16" Surface HoleSurface Casing13-3/8" 68# L-80 Hyd563 Set at 4,009' MD / 3,080' TVD8-½” X 9-7/8" Intermediate 2 HoleIntermediate 2 Liner7-5/8" 33.7# L80 HYD523Liner top at +/- 11,543' MD / 7,326' TVDShoe set @ 13,318' MD / 8,334' TVD12-¼” Intermediate 1 HoleIntermediate 1 Casing 9-7/8" 62.8# L-80 HYD563Set @ 11,652' MD / 7,477' TVDTop HRZ11,629' MD /7,450' TVD4-String Producer Schematic Top Alpine D13,245' MD / 8,313' TVDPlan Int1 TOC 9,077' MD / 5,444' TVDTop Alpine C13,450' MD / 8,344' TVD13,103' MD / 8,225' TVDAbandoned Int 2 TD13,345' MD /8,329' TVD -9750 -6500 -3250 0 3250 6500 9750 13000 16250 West(-)/East(+) (6500 usft/in)-9750-6500-3250032506500975013000South(-)/North(+) (6500 usft/in)MT7-01MT7-01PB1MT7-03MT7-03A RWO RedrillMT7-15MT7-83 wp04MT7-83PH1 wp03MT7-88 wp04 SouthMT7-89MT7-91MT7-92MT7-93MT7-94MT7-95MT7-96MT7-97MT7-98MT7-99MT7-84 wp00 SaverMT7-90 wp00 Saver9-5/8" INT1 Casing7-5/8" Intermediate Casing4-1/2" Production LinerMT7-89A wp03017503500525070008750True Vertical Depth (3500 usft/in)-9000 -7500 -6000 -4500 -3000 -1500 0 1500 3000 4500 Vertical Section at 330.00° (3000 usft/in)MT7-899-5/8" INT1 Casing7-5/8" Intermediate Casing4-1/2" Production LinerMT7-89A wp03Start DLS 2.50 TFO 100.00Start DLS 3.00 TFO 45.00Start DLS 3.00 TFO 90.00Start DLS 3.50 TFO -37.61Start DLS 3.50 TFO -59.47Start DLS 3.00 TFO -2.65Start DLS 1.00 TFO 95.98TD at 20196.16KalubikKuparuk_CLCU/MiluveachAlpine_DSECTION DETAILSSecMD Inc AziTVD+N/-S+E/-W Dleg TFaceVSect1 11619.33 41.77 9.24 7453.18 -3539.43 6370.95 0.00 0.00 -6250.722 11652.00 41.77 9.24 7477.55 -3517.95 6374.45 0.00 0.00 -6233.863 11712.00 41.51 11.46 7522.39 -3478.74 6381.61 2.50 100.00 -6203.484 11742.00 42.15 12.42 7544.74 -3459.16 6385.75 3.00 45.00 -6188.605 11792.00 42.15 14.65 7581.81 -3426.55 6393.60 3.00 90.00 -6164.286 11940.45 46.35 10.28 7688.16 -3325.45 6415.80 3.50 -37.61 -6087.827 11944.34 46.35 10.28 7690.84 -3322.68 6416.30 0.00 0.00 -6085.688 13238.16 77.00 331.39 8315.75 -2252.57 6185.83 3.50 -59.47 -5043.709 13288.16 77.00 331.39 8327.00 -2209.80 6162.50 0.00 0.00 -4994.9910 13318.16 77.00 331.39 8333.75 -2184.14 6148.50 0.00 0.00 -4965.7711 13777.97 90.78 330.75 8382.57 -1784.98 5927.85 3.00 -2.65 -4509.7612 14900.05 90.78 330.75 8367.30 -806.01 5379.71 0.00 0.00 -3387.8813 15095.22 90.58 332.70 8364.99 -634.15 5287.27 1.00 95.98 -3192.8314 19696.16 90.58 332.70 8318.73 3453.97 3176.87 0.00 0.00 1402.7915 20196.16 90.58 332.70 8313.70 3898.24 2947.53 0.00 0.00 1902.21Azimuths to True NorthMagnetic North: 13.47°Magnetic FieldStrength: 57058.0nTDip Angle: 80.32°Date: 8/5/2024Model: BGGM2024TMREFERENCE INFORMATIONCoordinate(N/E) Reference: Well MT7-89, True NorthVertical (TVD) Reference: Actual D26 (100.8PL+54.5DF) @ 155.30usft (Doyon 26)Section (VS) Reference: Slot - (0.00N, 0.00E)Measured Depth Reference: Actual D26 (100.8PL+54.5DF) @ 155.30usft (Doyon 26)Calculation Method: Minimum CurvatureMT7-89A wp03ConocoPhillips Alaska Inc_WNSProject:Western North SlopeWell: MT7-89Site: GMT2 Rendezvous PadWellbore: MT7-89ADesign: MT7-89A wp03MD Annotation11619.33 Start 32.67 hold at 11619.33 MD11652.00 Start DLS 2.50 TFO 100.0011712.00 Start DLS 3.00 TFO 45.0011742.00 Start DLS 3.00 TFO 90.0011792.00 Start DLS 3.50 TFO -37.6111940.45 Start 3.89 hold at 11940.45 MD11944.34 Start DLS 3.50 TFO -59.4713238.16 Start 50.00 hold at 13238.16 MD13288.16 Start 30.00 hold at 13288.16 MD13318.16 Start DLS 3.00 TFO -2.6513777.97 Start 1122.08 hold at 13777.97 MD14900.05 Start DLS 1.00 TFO 95.9815095.22 Start 4600.94 hold at 15095.22 MD19696.16 Start 500.00 hold at 19696.16 MD20196.16 TD at 20196.16SURVEY PROGRAMDepth From Depth To Survey/Plan Tool134.59 1007.69 Survey #1 (MT7-89 South) r.5 SDI_URSA11072.94 3930.78 Survey #2 (MT7-89 South) MWD+IFR2+SAG+MS4050.59 11619.33 Survey #3 (MT7-89 South) MWD+IFR2+SAG+MS11619.33 11719.00 MT7-89A wp03 (MT7-89A)r.5 MWD11719.00 13288.00 MT7-89A wp03 (MT7-89A) MWD+IFR2+SAG+MS13288.00 20196.16 MT7-89A wp03 (MT7-89A) MWD+IFR2+SAG+MSCASING DETAILSTVD MD Name Size7477.55 11652.00 9-5/8" INT1 Casing 9.6008326.96 13288.007-5/8" INT2 Casing7.6258313.70 20196.164-1/2" PROD Liner4.500LOCATION INFORMATION:Ground Level: 100.80Northing: 5915679.79Easting: 1430258.11Lattitude: 70° 10' 23.709 NLongitude: 151° 41' 30.731 WPROJECT DETAILS: Western North SlopeGeodetic System: US State Plane 1983Datum: North American Datum 1983Ellipsoid: GRS 1980Zone: Alaska Zone 4System Datum: Mean Sea LevelMT7-89A wp03 6060120120180180240240901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [200 usft/in]MT7-89SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect1 11619.33 41.77 9.24 7453.18 -3539.43 6370.95 0.00 0.00 -6250.722 11652.00 41.77 9.24 7477.55 -3517.95 6374.45 0.00 0.00 -6233.863 11712.00 41.51 11.46 7522.39 -3478.74 6381.61 2.50 100.00 -6203.484 11742.00 42.15 12.42 7544.74 -3459.16 6385.75 3.00 45.00 -6188.605 11792.00 42.15 14.65 7581.81 -3426.55 6393.60 3.00 90.00 -6164.286 11940.45 46.35 10.28 7688.16 -3325.45 6415.80 3.50 -37.61 -6087.827 11944.34 46.35 10.28 7690.84 -3322.68 6416.30 0.00 0.00 -6085.688 13238.16 77.00 331.39 8315.75 -2252.57 6185.83 3.50 -59.47 -5043.709 13288.16 77.00 331.39 8327.00 -2209.80 6162.50 0.00 0.00 -4994.9910 13318.16 77.00 331.39 8333.75 -2184.14 6148.50 0.00 0.00 -4965.7711 13777.97 90.78 330.75 8382.57 -1784.98 5927.85 3.00 -2.65 -4509.7612 14900.05 90.78 330.75 8367.30 -806.01 5379.71 0.00 0.00 -3387.8813 15095.22 90.58 332.70 8364.99 -634.15 5287.27 1.00 95.98 -3192.8314 19696.16 90.58 332.70 8318.73 3453.97 3176.87 0.00 0.00 1402.7915 20196.16 90.58 332.70 8313.70 3898.24 2947.53 0.00 0.00 1902.21101020203030404050506060707080809090100100901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [usft]1165011725118001187511950120261210212178122541233112408124851256312640127181279612874129521303113109131871326413339MT7-89Project: Western North SlopeSite: GMT2 Rendezvous PadWell: MT7-89Wellbore: MT7-89APlan: MT7-89A wp03ANTI-COLLISION SETTINGSInterpolation Method: MD, interval: 25.00Depth Reference: 11619.33 To 20196.16Results Limited By: Ellipse Separation: 1000.00Reference: MT7-89A wp03 (MT7-89/MT7-89A)REFERENCE INFORMATIONCalculation Method: Minimum CurvatureError System: ISCWSAScan Method: Trav. Cylinder NorthError Surface: Combined Pedal CurveWarning Method: Error Ratio11619 1179211792 1250012500 1350013500 1450014500 1550015500 1800018000 20196From Colour To MDDepth Range: 11619.33 To 20196.16MT7-89A wp03MT7-89A wp03Depth Range: 11619.33 To 20196.16SURVEY PROGRAMDepth From Depth To Survey/Plan Tool134.59 1007.69 Survey #1 (MT7-89 South)r.5 SDI_URSA11072.94 3930.78 Survey #2 (MT7-89 South) MWD+IFR2+SAG+MS4050.59 11619.33 Survey #3 (MT7-89 South) MWD+IFR2+SAG+MS11619.33 11719.00 MT7-89A wp03 (MT7-89A)r.5 MWD11719.00 13288.00 MT7-89A wp03 (MT7-89A) MWD+IFR2+SAG+MS13288.00 20196.16 MT7-89A wp03 (MT7-89A) MWD+IFR2+SAG+MS ! "# # $%!&'( ' ( " ) *+ , ----- ! "# # . ! # /!01 !"#$%!$&'($$!) * + ' 20 /!, -. . /01 3 4 !"#$%!$&'($$!) * + ' 0 /! 1 - 5! ( " /!2 34 # ..5 5, 4 +4 ! # " ' ' 1 6 )0 # 4 3 ) 03 5! 6 4 3037 ) 1 -5. 5) 1 - 81 - 87. 9 % "4 7 .: * . 7 .:: . * # ## 7 3 # .# . # ## 8!#4 ( "# 9 # )# +! 2 34 !$; # )! . $8$8$ ! * 8%) 8 ! * ! * ; < ! %1 $;%<) !)) 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his 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:Loepp, Victoria T (OGC) To:Dai, Weifeng Cc:Dewhurst, Andrew D (OGC); Hobbs, Greg S Subject:Re: MT7-89 (PTD 224-089) Int 2 Re-drill Date:Thursday, August 8, 2024 6:25:16 PM Weifeng, Verbal approval is granted to proceed as outlined. Please submit the sundry for a change of approved program through the normal permitting process as soon as possible. Thank you, Victoria Sent from my iPhone On Aug 8, 2024, at 4:09ௗPM, Dai, Weifeng <Weifeng.Dai@conocophillips.com> wrote: Good afternoon Victoria and Andy, The clean out run didn’t improve hole condition and we just made decision to pull out clean out BHA, pump kick off plug and sidetrack. Please refer to the attached sundry package application for reference. Based on current schedule, we are going to pick up cement stinger tonight or tomorrow morning. Your prompt response is highly appreciated. Any questions, please feel free to contact me or Greg. Weifeng Dai ConocoPhillips Alaska Staff Drilling Engineer Cell: 907-346-0324 From: Dai, Weifeng Sent: Wednesday, August 7, 2024 1:56 PM To: Loepp, Victoria T (DOA) <victoria.loepp@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: MT7-89 (PTD 224-089) Int 2 Re-drill Good afternoon Victoria and Andy, Want to give you a quick update that we were unable to reach set depth with 7- 5/8” int 2 liner, we pulled out the liner and are performing a clean out run that had issue starting ~12,300’ MD. We are putting together a plan to plug back into the int 1 casing shoe and redrill int 2. Based on current estimation, we shall run the cement stinger late tomorrow to spot the kick off plug. Current plan is: 1. Run cement stinger to ~12,300’ MD. 2. Pump kick off plug from ~12,300’ MD to 11,452’ (TOC 200’ inside int 1 casing) 3. Trip out cement stinger. 4. Perform full BOP test. 5. Pick up int 2 drilling assembly and run in hole. 6. Tag TOC with 10k WOB 7. Drill out cement and kick off, continue to drill int 2 section to TD (~70’ offset from original permit path). 8. Return to original PTD with int 2 liner operations followed by production section and completion operations to the original lateral end point of the approved TD. Please find the attached MT7-89A wellplan, MT7-89 plug back schematic and MT7-89A wp03 proposed schematic for reference. A sundry will be submitted with schematic, the attached directional plan and the work summary. Please let me know if you have any questions. Weifeng Dai ConocoPhillips Alaska Staff Drilling Engineer Cell: 907-346-0324 <MT7-89 Int 2 Redrill Sundry.pdf> STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________GMTU MT7-89 JBR 08/30/2024 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:0 5-7/8" and 7-5/8 Test joints Accumulator bottle precharge avg. 36 @ 996 psi Test Results TEST DATA Rig Rep:J. Newman / E FleagleOperator:ConocoPhillips Alaska, Inc.Operator Rep:K. Harding / K. Hinrichs Rig Owner/Rig No.:Doyon 26 PTD#:2240890 DATE:7/27/2024 Type Operation:DRILL Annular: 250/2500Type Test:BIWKLY Valves: 250/3500 Rams: 250/3500 Test Pressures:Inspection No:bopKPS240728121145 Inspector Kam StJohn Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 5.5 MASP: 3009 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 1 P Inside BOP 1 P FSV Misc 0 NA 16 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 18-3/4"P #1 Rams 1 5-1/2: x 7-5/8 P #2 Rams 1 Blinds/Shear P #3 Rams 1 3-1/2" x 6-5/8'P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3-1/8"P HCR Valves 2 3-1/16" & 3-1 P Kill Line Valves 2 3" & 3-1/16"P Check Valve 0 NA BOP Misc 0 NA System Pressure P3050 Pressure After Closure P1650 200 PSI Attained P25 Full Pressure Attained P94 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P10 @ 3600 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P19 #1 Rams P13 #2 Rams P13 #3 Rams P13 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P1 9 99 9 9999 9 7HVWFKDUWVDWWDFKHG MEU %23(7HVW'R\RQ *07807 37' $2*&&,QVSHFWERS.36 %23(7HVW'R\RQ *07807 37' $2*&&,QVSHFWERS.36 %23(7HVW'R\RQ *07807 37' $2*&&,QVSHFWERS.36 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 Chris Brillon Wells Engineering Manager Conoco Phillips Alaska, Inc. 700 G Street Anchorage, AK, 99501 Re: Greater Mooses Tooth Field, Rendezvous Oil Pool, GMTU MT7-89 Conoco Phillips Alaska, Inc. Permit to Drill Number: 224-089 REVISED Surface Location: 1121' FSL, 2141' FWL, SESW S32 T10N R2E, UM Bottomhole Location: 5018' FSL, 5101' FWL, SESE S32 T10N R2E, UM Dear Mr. Brillon: 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 day of July 2024. 12th Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.07.12 10:59:11 -08'00' 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 20,188 TVD: 8,313 4a. Location of Well (Governmental Section):7. Property Designation: Surface: Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date: 7/13/2024 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 262' to AA092341 4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 154.91 15. Distance to Nearest Well Open Surface: x-290222 y- 5915936 Zone- 4 100.8 to Same Pool: 1044' to MT7-91 16. Deviated wells:Kickoff depth: 500 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 90 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 42 20 94 H-40 Welded 80 40 40 120 120 16 13-3/8/13-5/8 68/88.2 L-80 Hyd563 4125 40 40 4165 3148 12-1/4" 9-5/8/9-7/8 47/62.8 L-80 Hyd563 11653 40 40 11693 7498 8.5" x 9-7/8"7.625" 33.70 L-80 Hyd523 1770 11543 7277 13313 8348 6-1/2" 4.5" 12.60 P-110 Hyd563 7004 13163 8155 20167 8313 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned?Yes No 20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Weifeng Dai Chris Brillon Contact Email:Weifeng.Dai@conocophillips.com Wells Engineering Manager Contact Phone:907-947-4323 Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Perforation Depth TVD (ft): GL / BF Elevation above MSL (ft): Perforation Depth MD (ft): 94 sx 15.8 ppg CG Uncemented liner w/frac sleeves & swell packers Effect. Depth MD (ft):Effect. Depth TVD (ft): Authorized Title: Authorized Signature: Authorized Name: LengthCasing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 18. Casing Program:Top - Setting Depth - BottomSpecifications 3840 3009 ConocoPhillips Alaska. Inc. 1121' FSL, 2141' FWL, SESW S32 T10N R2E, UM AA098885,AA081800, AA081781 1262.68, 2515, 5720 59-52-180 4305' FSL, 2879' FWL , SESW S4 T09N R2E, UM 5018' FSL, 5101' FWL, SESE S32 T10N R2E, UM 369446000, 932535000, 932516000 P.O. Box 100360 Anchorage, Alaska, 99510-0360 Cement Volume MDSize Plugs (measured): (including stage data) Cement to surface with 10 yds slurry 471 sx 13.0 ppg CG + 112 sx 15.8 ppg CG Total Depth MD (ft):Total Depth TVD (ft): 1372 sx 11.0 ppg CG + 217 sx 15.8 ppg CG MT7-89 Greater Mooses Tooth Rendezvous Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. ddd: Y: : Y:::::es yp l oooos N d: d: d:dddd:d YesYYYY No s N No Dril ssss ssssssss ssss T Dril t 0 o hahaaaaaaaaaaaaaaales: s p s G s S S 20 S d:dd:YeYs No No S s G y d:d:YYes No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) By Grace Christianson at 8:56 am, Jul 11, 2024 A.Dewhurst 11JUL24 GMTU 20,167 DSR-7/11/24 see emails -A.Dewhurst 11JUL24 50-103-20889-00-00 Initial BOP test to 5000 psig; subsequent BOP test to 3500 psig Annular preventer test to 2500 psig d Intermediate II cement evaluation may use SonicScope under the attached Conditions of Approval Surface casing LOT and annular LOT to the AOGCC as soon as available. BOP stack proposed approved while drilling the Int I(MPSP 1994 psig) Diverter waiver granted per 20 AAC 25.035(h) 224-089 X VTL 7/11/2024 Initial BOP test to 5000 psig; subsequent BOP test to 3500 psig Annular preventer test to 2500 psig Spacing exception req'd: Yes *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.07.12 10:59:28 -08'00'07/12/24 07//24 RBDMS JSB 071624 'DdDdϳͲ89 Conditions of Approval: Approval is granted to run the LWD-Sonic on upcoming well with the following provisions: 1. CPAI will provide a written log evaluation/interpretation to the AOGCC along with the log as soon as they become available. The evaluation is to include/highlight the intervals of competent cement that CPAI is using to meet the objective requirements for annular isolation, reservoir isolation, or confining zone isolation etc. Providing the log without an evaluation/interpretation is not acceptable. 2. LWD sonic logs must show free pipe and Top of Cement, just as the e-line log does. CPAI must start the log at a depth to ensure the free pipe above the TOC is captured as well as the TOC. Starting the log below the actual TOC based on calculations predicting a different TOC will not be acceptable. 3. CPAI will provide a cement job summary report and evaluation along with the cement log and evaluation to the AOGCC when they become available 4. CPAI will provide the results of the FIT when available. 5. Depending on the cement job results indicated by the cement job report, the logs and the FIT, remedial measures or additional logging may be required. ConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907-276-1215 July 10, 2024 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Application for Permit to Drill MT7-89 Dear Sir or Madam: ConocoPhillips Alaska, Inc. hereby applies for a Permit to Drill an onshore Alpine C-Sand producer well from the MT7 drilling pad. The intended spud date for this well is 7/13/2024. It is intended that Doyon 26 be used to drill the well. MT7-89 will utilize a 16” surface hole and will TD above the K3 sand and then 13-3/8" casing will be set and cemented to surface. The 12-1/4" intermediate 1 section will be drilled to the top of HRZ formation. A 9-5/8" casing string will be run and cemented in place with a 500’ MD or 250’ TVD column of cement above the highest hydrocarbon bearing zone per AOGCC regulation. If an additional hydrocarbon zone is present, a 2nd stage cement job will be performed to cover 50’ TVD above and below the interval. The 8-1/2" x 9-7/8" intermediate 2 section will be drilled and landed in the Alpine D. A 7-5/8” liner string will be set and cemented from TD to seccure the shoe and cover 500’ MD or 250’ TVD above any hydrocarbon bearing zone. The production interval will be comprised of a 6-1/2" horizontal hole that will be geo-steered in the Alpine C sand. The well will be completed as a producer with 4.5” liner and swell packers. The upper completion will include a production packer with GLM’s and tied back to surface. It is requested that a variance of the diverter requirement under 20 AAC25.035 (h)(2) is granted. At MT7 there has not been a significant indication of shallow gas or gas hydrates through the surface hole interval. Please find attached the information required by 20 ACC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following: 1. Form 10-401 APPLICATION FOR Permit to Drill per 20 ACC 25.005 (a) 2. A proposed drilling program 3. A proposed completion diagram 4. A drilling fluids program summary 5. Pressure information as required by 20 ACC 25.035 (d)(2) 6. Directional drilling / collision avoidance information as required by 20 ACC 25.050 (b) 7. Area of review Information pertinent to the application that is presently on file at the AOGCC: 1. Diagrams of the BOP equipment, diverter equipment and choke manifold lay out as required by 20 ACC 25.035 (a) and (b). 2. A description of the drilling fluids handling system. 3. Diagram of riser set up. If you have any questions or require further information, please contact Weifeng Dai at 907-265-6936 (Weifeng.Dai@conocophillips.com) or Greg Hobbs at 907-263-4794 (greg.s.hobbs@conocophillips.com). Sincerely, cc: MT7-89 Well File / Jenna Taylor ATO 1560 Dave Lee ATO 1552 Weifeng Dai Chris Brillon ATO 1548 Staff Drilling Engineer Andy Mack Kuukpik Corp Recommend approving requested diverter waiver.* SFD See emails dated 01-02 July 2024 associated with original PTD for details. -A.Dewhurst 11JUL24 It is requested that a variance of the diverter requirement under 20 AAC25.035 (h)(2) is granted * No significant surface-hole gas or gas-hydrates reported in daily ops summaries or observed in Totco gas-monitoring data recorded from nearest wells MT7-92 and -93 (located 600' and 1000' to southwest, respectively). SFD MT7-89 Saved: 10-Jul-24 MT7-89 Page 1 of 14 Printed: 10-Jul-24 MT7-89 Well Plan Application for Permit to Drill Table of Contents 1. Well Name (Requirements of 20 AAC 25.005 (f)) ........................................................... 2 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) ......................................... 2 3. Proposed Drilling Program ...................................................................................... 5 4. Diverter and BOP Information (Requirements of 20 AAC 25.005(c)(7)) .................. 6 5. MASP Calculations ................................................................................................... 6 6. Procedure for Conducting Formation Integrity Tests (Requirements of 20 AAC 25.005 ©(5)) ............................................................................................................... 8 7. Casing and Cementing Program ............................................................................. 8 8. Drilling Fluid Program (Requirements of 20 AAC 25.005(c)(8)) .................................... 9 9. Abnormally Pressured Formation Information (Requirements of 20 AAC 25.005 (c)(9)) ................................................................................................................................. 10 10. Seismic Analysis (Requirements of 20 AAC 25.005 (c)(10)) ........................................ 10 11. Seabed Condition Analysis (Requirements of 20 AAC 25.005 (c)(11)) ....................... 10 12. Evidence of Bonding (Requirements of 20 AAC 25.005 (c)(12)) ................................. 10 13. Drilling Hazards Summary ..................................................................................... 11 14. Proposed Completion Schematic ......................................................................... 13 15. Area of Review ....................................................................................................... 14 MT7-89 Saved: 10-Jul-24 MT7-89 Page 2 of 14 Printed: 10-Jul-24 1. Well Name (Requirements of 20 AAC 25.005 (f)) The well for which this application is submitted will be designated as MT7-89 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) Location at Surface 1121' FSL, 2141' FWL, SESW S32 T10N R2E, UM NAD27 Northings: 5915936 Eastings: 290222 RKB Elevation 154.91’ AMSL Pad Elevation 100.8’ AMSL Top of Productive Horizon (Heel) 4305' FSL, 2878' FWL , SESW S4 T09N R2E, UM NAD27 Northings:5913676 Eastings: 296185 Measured Depth, RKB: 13,454’ Total Vertical Depth, RKB: 8,344’ Total Vertical Depth, SS: 8,189’ Total Depth (Toe) 5018' FSL, 5101' FWL, SESE S32 T10N R2E, UM NAD27 Northings: 5919750 Eastings: 293276 Measured Depth, RKB: 20,167’ Total Vertical Depth, RKB: 8,313’ Total Vertical Depth, SS: 8,158’ Please see attached well stick diagram for the current planned development of the pad. MT7-89 Saved: 10-Jul-24 MT7-89 Page 3 of 14 Printed: 10-Jul-24 Pad Layout Well Stick Diagram MT7-89 Saved: 10-Jul-24 MT7-89 Page 4 of 14 Printed: 10-Jul-24 MT7-89 Saved: 10-Jul-24 MT7-89 Page 5 of 14 Printed: 10-Jul-24 3. Proposed Drilling Program 1. MIRU rig Doyon 26 onto well over pre-installed 20” insulated conductor. 2. Rig up and test riser, dewater cellar as needed. 3. Drill 16” hole to the surface casing point as per the directional plan. (LWD Program: GR/RES). 4. Run and cement new 13-3/8” + 13-5/8” surface casing to surface. Results of the cement operation will be submitted as soon as possible. 5. Install BOPE with the following equipment/configuration: 13-5/8” annular preventer, 3-1/2” x 6-5/8” VBR, blind ram and 3-1/2” x 6-5/8” VBR. 6. Test BOPE to 250 psi low / 5,000 psi high (24-48 hr. regulatory notice). 7. Pick up and run in hole with 12-1/4” drilling BHA to drill intermediate #1. (LWD Program: GR/RES). 8. Chart casing pressure test to 3,500 psi for 30 minutes. 9. Drill out shoe track and 20’ of new hole. 10. Perform LOT to maximum EMW of 18.5 ppg. 1. Send results to AOGCC as soon as available. 11. Displace well to 11.0 ppg Fresh water polymer WBM. 12. Drill 12-1/4” hole to the casing point. 13. Circulate wellbore clean and trip out of hole. 14. Send OH logs to AOGCC to review shallow hydrocarbon bearing sands as soon as available. 15. Change upper ram to 9-7/8” fixed casing ram and test. 16. Run 9-5/8” + 9-7/8” intermediate casing to TD. 17. Pump single stage cement job to isolate the casing shoe or 500’ MD above uppermost hydro-carbon bearing zone. A 2nd stage cement job will be performed to isolate reservoir quality sand if exists at shallower depth. Submit results of the cement operation to AOGCC as soon as possible. 1. There is potential for the presence of the Tusk sand, which may be hydrocarbon bearing and require a second stage cement job to place cement 50’ TVD above and below the interval. The required equipment and cement plans are prepared if this becomes necessary. 18. Change upper 9-5/8” fixed casing ram to 4-1/2” x 7-5/8” VBRs. Test BOPE to 250/3,500 psi. (24-48 hr. regulatory notice). 19. Pick up and run in hole with 8-1/2” x 9-7/8” drilling BHA to drill intermediate 2. Simops – perform 13-3/8” x 9-5/8” annulus LOT, flush and freeze protect with the ball mill. 20. Chart casing pressure test to 3,500 psi for 30 minutes. 21. Drill out shoe track and 20’ of new hole. 22. Perform FIT to max 14.0 ppg EMW. 23. Drill 8-1/2" x 9-7/8” hole to section TD with OBM. 24. Circulate wellbore clean and trip OOH. 25. Pick up and run in hole with the 7-5/8” liner to section TD. 26. Circulate and condition mud in preparation for cementing. 27. Cement 7-5/8” liner to required TOC. Set liner top packer. Circulate excess cement from top of liner. POOH laying down drill pipe. Submit results to AOGCC as soon as possible. 28. Change out upper rams to 3-1/2” x 6-5/8” VBR. Send OH logs to AOGCC to review shallow hydrocarbon bearing sands as soon as available. MT7-89 Saved: 10-Jul-24 MT7-89 Page 6 of 14 Printed: 10-Jul-24 29. Pick up DP. Test BOPE to 250 psi low / 3,500 psi high. (24-48 hr. regulatory notice). 30. Pick up and RIH with 6-1/2” drilling assembly. (LWD Program: GR/Azimuthal RES, Neu/Den). 31. Chart casing pressure test to 3,500 psi for 30 minutes and record results. 32. Drill out and perform FIT to 12.0 ppg EMW. 33. Drill 6-1/2” horizontal hole to TD. 34. Circulate the hole clean, displace to vis brine, POOH. 35. Run 4-1/2” liner on DP, set liner hanger and top packer. Test to confirm packer set. Release from hanger and displace well to CI brine. POOH and laying down DP. 36. Run 4-1/2” tubing with production packer, DHG, GLMs and landing nipples. Locate and space out tubing. Terminate TEC wire and land tubing hanger. 37. Test tubing hanger seals from above to 2,500 psi for 15 mins. 38. Drop ball and rod. Pressure up to set production packer. 39. Pressure test tubing to 4,200 psi for 30 mins. Test IA to 3,500 psi for 30 mins. Shear SOV. 40. Install BPV, test same and tubing hanger seals from below to 2,500 psi. 41. Nipple down BOP, terminate TEC wire. 42. Install tubing head adaptor. Pressure test adaptor to 5,000 psi. 43. Install tree and test. 44. Pull BPV, freeze protect IA and tubing. 45. Secure well. Rig down and move out. 4. Diverter and BOP Information (Requirements of 20 AAC 25.005(c)(7)) Please reference BOP and diverter schematics on file for Doyon 26. 5. MASP Calculations The following presents data used for calculation of anticipated surface pressure (ASP) during drilling of this well: Casing Size (in) Csg Setting Depth MD/TVD (ft) Fracture Gradient (ppg) Pore pressure (psi) ASP Drilling (psi) 20 115 / 115 10.9 52 54 13.375 + 13.625 4,165 / 3,148 14.5 1364 1065 9.625 + 9.875 11,693 / 7,498 16.5 3406 2059 7.625 13,313 / 8,348 12.5 3755 2920 4.5 20,167 / 8,313 12.5 3840 3009 PROCEDURE FOR CALCULATING ANTICPATED SURFACE PRESSURE (ASP) ASP is determined as the lesser of 1) surface pressure at breakdown of the formation casing seat with a gas gradient to the surface, or 2) formation pore pressure at the next casing point less a gas gradient to the surface as follows: 1) ASP = [(FG x 0.052) - 0.1]D Where: ASP = Anticipated Surface pressure in psi FG = Fracture gradient at the casing seat in lb/gal 0.052 = Conversion from lb/gal to psi/ft 0.1 = Gas gradient in psi/ft D = true Vertical depth of casing seat in ft RKB MT7-89 Saved: 10-Jul-24 MT7-89 Page 7 of 14 Printed: 10-Jul-24 OR 2) ASP = FPP – (0.1 x D) Where: FPP = Formation Pore Pressure at the next casing point FPP = 0.4525 x TVD 1. ASP CALCULATIONS 1. Drilling below 20” conductor ASP = [(FG x 0.052) – 0.1] D = [(10.9 x 0.052) – 0.1] x 115 = 54 psi OR ASP = FPP – (0.1 x D) = 1380 – (0.1 x 3148’) = 1065 psi Minimum MW needed = 8.7 ppg 2. Drilling below 13.375” surface casing ASP = [(FG x 0.052) – 0.1] D = [(14.5 x 0.052) – 0.1] x 3148’ = 2059 psi OR ASP = FPP – (0.1 x D) = 3406 – (0.1 x 7498) = 2656 psi Minimum MW needed = 8.8 ppg 3. Drilling below first 9.625” intermediate casing ASP = [(FG x 0.052) – 0.1] D = [(16.5 x 0.052) – 0.1] x 7498 = 5683 psi OR ASP = FPP – (0.1 x D) = 3755– (0.1 x 8348’) = 2920 psi Minimum MW needed = 8.7 ppg 4. Drilling below 7” production liner ASP = [(FG x 0.052) – 0.1] D = [(12.5 x 0.052) – 0.1] x 8313 = 4572 psi OR ASP = FPP – (0.1 x D) = 3840 – (0.1 x 8313) = 3009 psi Minimum MW needed = 8.8 ppg (B) data on potential gas zones; The well bore is not expected to penetrate any gas zones. (C) data concerning potential causes of hole problems such as abnormally geo-pressured strata, lost circulation zones, and zones that have a propensity for differential sticking; Please see Drilling Hazards Summary MT7-89 Saved: 10-Jul-24 MT7-89 Page 8 of 14 Printed: 10-Jul-24 6. Procedure for Conducting Formation Integrity Tests (Requirements of 20 AAC 25.005 ©(5)) Drill out casing shoe and perform LOT test or FIT in accordance with the Alpine LOT/FIT procedure that ConocoPhillips Alaska has on file with the Commission. 7. Casing and Cementing Program Casing and Cementing Program Csg/Tbg OD (in) Hole Size (in) Weight (lb/ft) Grade Conn. Cement Program 20 42 94 H-40 Welded Cemented to surface with 10 yds slurry 13.375 + 13.625 16 68/88.2 L-80 Hyd563 Cement to Surface 9.625 + 9.875 12.25 47/62.8 L-80 Hyd563 250’ TVD or 500’ MD, whichever is greater, above highest significant hydrocarbon bearing zone 7.625 8.5 x 9.875 33.7 L-80 Hyd523 250’ TVD or 500’ MD, whichever is greater, above highest significant hydrocarbon bearing zone 4.5 6.125 12.6 L-80 Hyd563 Uncemeneted open hole liner with frac ports and swell packers 13.625” Surface Casing run to 4,165’ MD /3,060’ TVD Cement Plan: Cement from 4,165’ MD to 3,665' (500’ of tail) with Deepcrete + Add's. @ 15.8 ppg, and from 3,665' to surface with 11.0 ppg DeepCrete. Assume 120% excess annular volume in permafrost and 50% excess below the permafrost (981’ MD), zero excess in 20” conductor. Lead slurry from 3,665’ MD to surface with Arctic Lite Crete @ 11.0 ppg Total Volume = 2,374 ft3 => 1,372 sx of 11.0 ppg Deepcrete + Add's @ 1.73 ft 3 /sk Tail slurry from 4,165’ MD to 3,665’ MD with 15.8 ppg Deepcrete + Add's Total Volume = 288 ft3 => 217 sx of 15.8 ppg Class G + Adds @ 1.33 ft3/sk 9.875” Intermediate Casing run to 11,693’ MD / 7,498’ TVD Cement Plan: Primary cement job consists of 500 ft 15.8 ppg tail slurry and top of 13.0 ppg lead slurry is designed to be at 9,077’ MD, which is 500’MD or 250’ TVD above the prognosis shallowest hydrocarbon bearing zone Albian Sub 93. If a shallower hydrocarbon zone of producible volumes is encountered while drilling, a 2nd stage cement job will be performed to isolate this zone. Assume 30% excess annular volume. Lead slurry from 11,193’ MD to 9,077’ MD with 13.0 ppg Class G + Add’s Total Volume = 792 ft3 => 471 sx of 13.0 ppg Class G + Add's @ 1.68 ft 3 /sk Tail slurry from 11,693’ MD to 11,193’ MD with 15.8 ppg Class G + Add's Total Volume = 188 ft3 => 112 sx of 15.8 ppg Class G + Adds @ 1.63 ft3/sk 9,077’ MD MT7-89 Saved: 10-Jul-24 MT7-89 Page 9 of 14 Printed: 10-Jul-24 7-5/8” Intermediate Casing run to 13,313’ MD /8,313’ TVD Cement Plan: Top of slurry is designed to be at 12,785 MD, which is 500’MD or 250’ TVD above Alpine D. Assume 40% excess annular volume. Tail slurry from 13,313’ MD to 12,785’ MD with 15.8 ppg Class G + Adds Total Volume = 157 ft3 => 94 sx of 15.8 ppg Class G + Adds@ 1.63 ft3/sk Centralizer Program Joint Type Centralizer Placement Surface 1,2,3 13.375” x 16” rigid 1 per joint 4 to surface 13.375” x 16” bow spring As necessary Intermediate 1 Shoe Track NA No centralizers Shoe Track to TOC 9.625” x 12.25” rigid 1 per joint TOC to Surface Shoe NA No centralizers 3 joints across surface shoe 9.625” x 12.25” rigid 1 per joint Remaining to surface 9.625” x 12.25” rigid 1 every other joint Intermediate 2 Flot shoe to 2 jts below liner hanger 7.625” x 9.5” Centek, Semi-regid 1 per joint, no centralizer in 90’ rat hole Production Flot shoe to 2 jts below liner hanger 4.5” x 6.125” rigid 1 per joint 8. Drilling Fluid Program (Requirements of 20 AAC 25.005(c)(8)) Surface Intermediate #1 Intermediate #2 Production Hole Size in. 16 12.25 8.5 x 9.875 6.125 Casing Size in. 13.375 + 13.625 9.625 + 9.875 7.625 4.5 Density PPG 9.0 – 10.0 11.0 – 12.0 10.0 – 11.5 8.5 – 8.8 PV cP 13 10 40 15 YP lb./100 ft2 35-50 20 - 28 20 - 35 15 - 20 Funnel Viscosity s/qt. 200 40 - 50 70 - 90 60 - 80 Initial Gels lb./100 ft2 50 10 14 10 10 Minute Gels lb./100 ft2 60 15 42 15 API Fluid Loss cc/30 min. N.C. – 15.0 10 N/A 4 HPHT Fluid Loss cc/30 min. n/a 8.0 – 12.0 5.0 10.0 pH 11.0 9.5 – 10.0 9.5 – 10.0 9.0 – 9.5 Surface Hole: A fresh water drilling fluid (KSI) will be used for the surface interval. Keep flow line viscosity at r 200 sec/qt while drilling and running casing. Reduce viscosity prior to cementing. Maintain mud weight 10.0 ppg by use of solids control system and dilutions where necessary. Intermediate #1: Fresh water polymer mud system. Ensure good hole cleaning by pumping regular sweeps and maximizing fluid annular velocity. Maintain mud weight from 9.4-12.0 ppg and be prepared to add loss circulation material. Good MT7-89 Saved: 10-Jul-24 MT7-89 Page 10 of 14 Printed: 10-Jul-24 filter cake quality, hole cleaning and maintenance of low drill solids (by diluting as required) will all be important in maintaining wellbore stability. Intermediate #2: The intermediate 2-hole section will be drilled with OBM weighted to 11.0 ppg. Ensure good hole cleaning by maximizing fluid annular velocity. There is a slight potential for lost circulation, particularly after the reservoir is penetrated. Ensure adequate LCM material is available on location and in the field to address any expected losses. Maintain mud weight will be 11.0 targeting 12.0 EMW using MPD. Good filter cake quality, hole cleaning and maintenance of low drill solids (by diluting as required) will all be important in maintaining wellbore stability. Note: Managed Pressure Drilling (MPD) will be utilized for adding backpressure during connections to mitigate shale instability and cycling. Production Hole: The horizontal production interval will be drilled with water-based mud drill-in fluid weighted to 8.8 ppg. MPD will be used to hold back pressure, keeping the well dynamically balanced. Diagram of Doyon 26 Mud System on file. Drilling fluid practices will be in accordance with appropriate regulations. 9. Abnormally Pressured Formation Information (Requirements of 20 AAC 25.005 (c)(9)) N/A - Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis (Requirements of 20 AAC 25.005 (c)(10)) N/A - Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis (Requirements of 20 AAC 25.005 (c)(11)) N/A - Application is not for an offshore well. 12. Evidence of Bonding (Requirements of 20 AAC 25.005 (c)(12)) Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. MT7-89 Saved: 10-Jul-24 MT7-89 Page 11 of 14 Printed: 10-Jul-24 13. Drilling Hazards Summary (To be posted in Rig Floor Doghouse Prior to Spud) 16" Hole / 13.625” Casing Interval Event Risk Level Mitigation Strategy Conductor Broach Low Monitor cellar continuously during interval. Well Collision Low First well on Pad, traveling cylinder diagrams Gas Hydrates Low If observed – control drill, reduce pump rates and circulating time, reduce mud temperatures Clay Balling Medium Maintain planned mud parameters and flow rates, Increase mud weight, use weighted sweeps, reduce fluid viscosity, control ROP Abnormal Pressure in Surface Formations Low Diverter drills, increased mud weight. Shallow hazard study noted minimal risk Lost Circulation Medium Reduce pump rates, mud rheology, add lost circulation material, use of low density cement slurries, port collar, control pipe running speeds 12.25” Hole / 9.875” Casing Interval Event Risk Level Mitigation Strategy Lost circulation Low Reduce pump rates, reduce trip speeds, real time ECD monitoring, mud rheology, add lost circulation material Hole swabbing on trips Medium Reduce trip speeds, condition mud properties, proper hole filling, pump out of hole, real time ECD monitoring, MPD stripping practices Abnormal Pressure in Overburden Formations Low Well control drills, check for flow during connections, increase mud weight. Shallow hazard study noted minimal risk Hole Cleaning Low Monitor ECD and torque/drag trends, control drill and use best hole cleaning practices 8.5x9.875” Hole / 7.625” Liner - Casing Interval Event Risk Level Mitigation Strategy Sloughing shale, Tight hole High MPD for shale stability, Steerable Drilling Liner, Increase mud weight, control ROP, connection and trip speeds, sweeps, and real time equivalent circulating density (ECD) monitoring, run casing as liner Lost circulation Low Reduce pump rates, reduce trip speeds, real time ECD monitoring, mud rheology, add lost circulation material Hole swabbing on trips Medium Reduce trip speeds, condition mud properties, proper hole filling, pump out of hole, real time ECD monitoring, Liner will be in place at TD Abnormal Reservoir Pressure Low Well control drills, check for flow during connections, increase mud weight Hydrogen Sulfide gas Low H2S drills, detection systems, alarms, standard well MT7-89 Saved: 10-Jul-24 MT7-89 Page 12 of 14 Printed: 10-Jul-24 control practices, mud scavengers 6.5” Hole / 4.5” Liner - Horizontal Production Hole Event Risk Level Mitigation Strategy Lost circulation Low Reduce pump rates, reduce trip speeds, real time ECD monitoring, mud rheology, add lost circulation material Hole swabbing on trips Medium Reduce trip speeds, condition mud properties, proper hole filling, pump out of hole, real time ECD monitoring Abnormal Reservoir Pressure Low Well control drills, check for flow during connections, increased mud weight Differential Sticking Low Uniform reservoir pressure along lateral, keep pipe moving, control mud weight Hydrogen Sulfide gas Low H2S drills, detection systems, alarms, standard well control practices, mud scavengers Well Proximity Risks: MT7 will be a multi-well pad, containing an original plan of 36 wells. Directional drilling / collision avoidance information is provided in the following attachments. Drilling Area Risks: Reservoir Pressure: Offset injection has the potential to increase reservoir pressure over predicted. Although this is unlikely, the rig will be prepared to weight up if required. Weak sand stringers could be present in the overburden. LCM material will be available to seal in losses in the intermediate section. Lower Shale Stability: HRZ/Kalubik/Miluveach in the pilot and intermediate #2 hole sections will require higher mud weights than historically used to enhance wellbore stability. Managed Pressure Drilling will be used in conjunction with a 4-string casing design to mitigate shale instability in the aforementioned formations. Standard LCM material and well bore strengthening pills are expected to be effective in dealing with lost circulation if needed. Good drilling practices will be stressed to minimize the potential of taking swabbed kicks. MT7-89 Saved: 10-Jul-24 MT7-89 Page 13 of 14 Printed: 10-Jul-24 14. Proposed Completion Schematic MT7-89 Saved: 10-Jul-24 MT7-89 Page 14 of 14 Printed: 10-Jul-24 15. Area of Review An Area of Review plot is show below of the MT7-89 planned wellpath and offset wells. MT7-91 and MT7- 15 are the offset wells from the planned MT7-89 producer. MT7-91 was successfully completed recently and MT7-15 is the well under construction at this moment and all the cement jobs performed successfully with no concern. Well Name Status Top of Alpine Pool (MD/TVD) TOC (MD/TVD) TOC – Determined By Reservoir Status Zonal Isolation Cement Operations Summary MT7-91 Shut in 11,558’ / 8,297’ 10,990’ / 8,148’ SonicScope Liner TOC and production Packer 67 bbls of 15.8 ppg Class G pumped with partial return MT7-15 Under construction, flow back for 2 weeks after 12,272’ / 8308 11,225’ / 8,069’ SonicScope Liner TOC and production Packer 62 bbls of 15.8 ppg Class G pumped with full return 54 500 500 1000 1000 1500 1500 2000 2000 2500 2500 3000 3000 5000 5000 10000 10000 15000 15000 20167 MT7-89 wp06 South MT7-08PB1 MT7-14MT7-14A MT7-15 MT7-91 MT7-92MT7-93 MT7-95 MT7-96 MT7-97 MT7-98 MT7-99 MT7-83 wp04 MT7-83PH1 wp03 MT7-88 wp04 South MT7-84 wp00 Saver MT7-90 wp00 Saver MT7-89 wp06 South Plan Summary 0 4 Dogleg Severity0 3000 6000 9000 12000 15000 18000 Measured Depth 13-3/8" Surface Casing 9-5/8" INT1 Casing 7-5/8" INT2 Liner 4-1/2" PROD Liner 50 50 100 100 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [100 usft/in] MT7-91 MT7-92 MT7-93 MT7-94 MT7-95 MT7-88 wp04 South MT7-84 wp00 Saver MT7-90 wp00 Saver 0 5000 True Vertical Depth-6000 -4500 -3000 -1500 0 1500 Vertical Section at 330.00° 13-3/8" Surface Casing 9-5/8" INT1 Casing7-5/8" INT2 Liner 4-1/2" PROD Liner 0 500 1000 Centre to Centre Separation0 15003000450060007500 Measured Depth Equivalent Magnetic Distance DDI 6.977 SURVEY PROGRAM Date: 2024-04-23T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 54.11 1000.00 MT7-89 wp06 South (MT7-89 South) r.5 SDI_URSA1 1000.00 4165.00 MT7-89 wp06 South (MT7-89 South) MWD+IFR2+SAG+MS 4165.00 11693.00 MT7-89 wp06 South (MT7-89 South) MWD+IFR2+SAG+MS 11693.00 13313.00 MT7-89 wp06 South (MT7-89 South)MWD+IFR2+SAG+MS 13313.00 20167.48 MT7-89 wp06 South (MT7-89 South)MWD+IFR2+SAG+MS Surface Location North / 5915679.79 East / 1430258.11Ground / 100.80 CASING DETAILS TVD MD Name 3147.39 4165.00 13-3/8" Surface Casing 7497.78 11693.00 9-5/8" INT1 Casing 8319.66 13313.00 7-5/8" INT2 Liner 8313.31 20167.48 4-1/2" PROD Liner Mag Model & Date: BGGM2024 14-Jul-24 Magnetic North is 13.50° East of True North (Magnetic Declination) Mag Dip & Field Strength: 80.33° 57060.09nT SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Annotation 1 54.11 0.00 0.00 54.11 0.00 0.00 0.00 0.00 0.00 2 500.00 0.00 0.00 500.00 0.00 0.00 0.00 0.00 0.00 Start Build 1.50 3 700.00 3.00 127.29 699.91 -3.17 4.16 1.50 127.29 -4.83 Start Build 2.00 4 1000.00 9.00 127.29 998.13 -22.16 29.10 2.00 0.00 -33.74 Start DLS 2.50 TFO 0.00 5 3135.96 62.40 127.29 2670.62 -750.22 985.24 2.50 0.00 -1142.33 Start 5605.09 hold at 3135.96 MD 6 8741.05 62.40 127.29 5267.53 -3759.43 4937.17 0.00 0.00 -5724.35 Start DLS 3.00 TFO -144.62 7 11626.14 41.49 8.03 7447.70 -3545.19 6371.55 3.00 -144.62 -6256.00 Start 100.00 hold at 11626.14 MD 8 11726.14 41.49 8.03 7522.60 -3479.59 6380.80 0.00 0.00 -6203.81 Start DLS 3.00 TFO -50.82 9 13246.31 77.00 333.39 8304.66 -2253.36 6104.74 3.00 -50.82 -5003.84 Start 50.00 hold at 13246.31 MD 10 13296.31 77.00 333.39 8315.91 -2209.80 6082.92 0.00 0.00 -4955.20 Start 50.00 hold at 13296.31 MD 11 13346.31 77.00 333.39 8327.16 -2166.24 6061.10 0.00 0.00 -4906.57 Start DLS 3.00 TFO 0.03 12 13795.82 90.49 333.40 8376.04 -1767.65 5861.46 3.00 0.03 -4461.55 Start 1050.64 hold at 13795.82 MD 13 14846.45 90.49 333.40 8367.14 -828.26 5391.03 0.00 0.00 -3412.81 Start DLS 3.00 TFO -82.70 14 14871.41 90.58 332.66 8366.91 -806.01 5379.71 3.00 -82.70 -3387.88 Start 4796.07 hold at 14871.41 MD 15 19667.49 90.58 332.66 8318.34 3453.97 3176.87 0.00 0.00 1402.79 Start DLS 0.00 TFO -130.32 16 20167.48 90.57 332.65 8313.31 3898.06 2947.18 0.00 -130.32 1902.23 TD at 20167.48 FORMATION TOP DETAILS TVDPath Formation 994.88 Permafrost 1103.40 C40 1438.48 C30 1669.31 C20 2024.95 C10 3041.36 K3 3678.28 Albian_97 3887.69 Albian_96 4086.12 Albian_95 5019.71 Albian_94 5533.55 Albian_93 5772.73 Top_Stareater 6304.90 Albian_92 6421.38 Albian_91 7449.70 HRZ 7623.26 LCU 8313.37 Alpine_D 8343.91 Alpine_C Top By signing this I acknowledge that I have been informed of all risks, checked that the data is correct, ensured it's completeness, and all surroundingwells are assigned to the proper position, and I approve the scan and collision avoidance plan as set out in the audit pack.I approve it as the basiis for the final well plan and wellsite drawings. I also acknowledge that unless notified otherwise all targets have a 100 feet lateral tolerance. Prepared by Checked by Accepted by Approved by Plan KB (100.8 PL+54.11 DF) @ 154.91usft (Doyon 26) 0300060009000True Vertical Depth (1500 usft/in)-9000 -6000 -3000 0 3000Vertical Section at 330.00° (1500 usft/in)13-3/8" Surface Casing9-5/8" INT1 Casing7-5/8" INT2 Liner4-1/2" PROD LinerMT7-89 wp06 SouthStart Build 1.50Start Build 2.00Start DLS 2.50 TFO 0.00Start 5605.09 hold at 3135.96 MDStart DLS 3.00 TFO -144.62Start 100.00 hold at 11626.14 MDStart DLS 3.00 TFO -50.82Start 50.00 hold at 13296.31 MDStart DLS 3.00 TFO 0.03Start 1050.64 hold at 13795.82 MDStart DLS 3.00 TFO -82.70Start 4796.07 hold at 14871.41 MDStart DLS 0.00 TFO -130.32TD at 20167.48Section View Project: Western North SlopeSite:GMT2 Rendezvous PadWell: MT7-89Wellbore: MT7-89 SouthMT7-89 wp06 South Plan View Project: Western North SlopeSite:GMT2 Rendezvous PadWell: MT7-89Wellbore: MT7-89 SouthDesign: MT7-89 wp06 South-700007000South(-)/North(+) (3500 usft/in)-14000 -7000 0 7000 14000West(-)/East(+) (3500 usft/in)MT7-89 T1_1320ftMT7-89 T2_1320ftMT7-89 Heel Rev1MT7-01MT7-01PB1MT7-02MT7-03MT7-03A RWO RedrillMT7-04MT7-05MT7-06MT7-06AMT7-06PB1MT7-07MT7-08MT7-08PB1MT7-09MT7-11MT7-14MT7-14AMT7-15MT7-91MT7-92MT7-93MT7-94MT7-95MT7-96MT7-97MT7-98MT7-99MT7-83 wp04MT7-83PH1 wp03MT7-88 wp04 SouthMT7-10_wp04MT7-12_wp02_EXT_PetrelMT7-84 wp00 SaverMT7-90 wp00 Saver13-3/8" Surface Casing9-5/8" INT1 Casing7-5/8" INT2 Liner4-1/2" PROD Liner5001000150020002500300035004000450050005500600065 00700075008000 8313MT7-89 wp06 South ! 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A% @? @ 3 C$? @ 9%* A% @? @C$? @C$ 9%@ A% ? ? 9%* A% $%? $%? $% 9%* A% $0? $0? $0 9%0 7D A% *? *? * 9%% 5 A% %? %? % 9%% 5 A% ' 7 2 7 + 3 5 ; 3 < $@? E * 23 56 / ; $&)F 3 $)%F %G %&%%% 8// + 5 8// + / + 5 !" #$%%& '()*&$$ +,- . $)*& 3 56 ? , / ? 7 1 Dewhurst, Andrew D (OGC) From:Zwarich, Nola R <Nola.R.Zwarich@conocophillips.com> Sent:Thursday, 11 July, 2024 12:05 To:Dewhurst, Andrew D (OGC) Cc:Dai, Weifeng; Hobbs, Greg S; Davies, Stephen F (OGC); Guhl, Meredith D (OGC); Roby, David S (OGC); Loepp, Victoria T (OGC) Subject:RE: [EXTERNAL]GMTU MT7-89 Revision (PTD 224-089): Question No problem. MT7-89 is a producer. There are no plans to fracture sƟmulate this well. From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Thursday, July 11, 2024 11:08 AM To: Zwarich, Nola R <Nola.R.Zwarich@conocophillips.com> Cc: Dai, Weifeng <Weifeng.Dai@conocophillips.com>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Subject: RE: [EXTERNAL]GMTU MT7-89 Revision (PTD 224-089): Question Nola, Thank you for the prompt reply. The PTD applicaƟon contains an Area of Review (AOR) sec Ɵon (SecƟon 15 in the PTD). This is required for injectors, but this well is being permiƩed as a producer. Would you please conĮrm that MT7-89 will be a producer? Finally, would you conĮrm that there are no future plans to fracture s Ɵmulate this well (as stated on 10-401 form). Thanks, Andy From: Zwarich, Nola R <Nola.R.Zwarich@conocophillips.com > Sent: Thursday, 11 July, 2024 10:19 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Dai, Weifeng <Weifeng.Dai@conocophillips.com >; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com >; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Subject: RE: [EXTERNAL]GMTU MT7-89 Revision (PTD 224-089): Question Morning Andrew, 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. 2 The major change for the rushed revision of the direcƟon plan is the heel locaƟon for the lateral has moved ~1700 Ō (NNW of previous heel) to avoid a fault and poor reservoir quality. o The SHL has not changed Correct o The BHL has not changed more than 500’ Correct o The proposed TD of the well is 20,167.48’ MD Correct Please let me know if you have any more quesƟons, Nola Zwarich P.Eng | Alaska Wells Chief Engineer | ConocoPhillips O: 907.263.4433 | M: 346.804.5195 | ATO-1568, Anchorage, AK, USA From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Thursday, July 11, 2024 9:30 AM To: Zwarich, Nola R <Nola.R.Zwarich@conocophillips.com > Cc: Dai, Weifeng <Weifeng.Dai@conocophillips.com >; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com >; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Subject: [EXTERNAL]GMTU MT7-89 Revision (PTD 224-089): Question CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. Nola, I Įrst sent this to Weifeng and Greg but saw that they both are out of the oĸce. We received a rushed revision to the GMTU MT7-89 PTD and I have one quesƟon below. x The revised applicaƟon we just received has an updated direcƟonal plan (wp06 South) with a TD of 20,167.48’ MD. This is diīerent than the proposed TD stated on the 10-401 form of 20,188’ MD. When I loaded the wp06 plan and used the 20,167’ TD, it appears to have the same BHL/target as the original wp04 wellbore. Would you please conĮrm the following: o The SHL has not changed o The BHL has not changed more than 500’ o The proposed TD of the well is 20,167.48’ MD 3 Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas ConservaƟon Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME:______________________________________ PTD:_____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD:__________________________POOL:____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in nogreater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. GMTU MT7-89 224-089 GRTR MOOSES TOOTH RENDEZVOUS OIL WELL PERMIT CHECKLISTCompanyConocoPhillips Alaska, Inc.Well Name:GMTU MT7-89Initial Class/TypeDEV / PENDGeoArea890Unit10750On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2240890GRTR MOOSES TOOTH, RENDEZV OIL - 2822NA1Permit fee attachedYesSurface Location lies within AA098885; Top Productive Interval lies in AA081781;2Lease number appropriateYesPortion of Productive Interval lies in AA081800; TD lies in AA098885.3Unique well name and numberYesGRTR MOOSES TOOTH, RENDEZV OIL - 282200 - governed by CO 7934Well located in a defined poolYes5Well located proper distance from drilling unit boundaryNA6Well located proper distance from other wellsYes7Sufficient acreage available in drilling unitYes8If deviated, is wellbore plat includedYes9Operator only affected partyYes10Operator has appropriate bond in forceYes11Permit can be issued without conservation orderYes12Permit can be issued without administrative approvalYes13Can permit be approved before 15-day waitNA14Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15All wells within 1/4 mile area of review identified (For service well only)NA16Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes80' conductor18Conductor string providedYesSC set at 4165' MD19Surface casing protects all known USDWsYes55% excess planned20CMT vol adequate to circulate on conductor & surf csgNo21CMT vol adequate to tie-in long string to surf csgNouncemented frac sleeves and swelll packers22CMT will cover all known productive horizonsYes23Casing designs adequate for C, T, B & permafrostYes24Adequate tankage or reserve pitNA25If a re-drill, has a 10-403 for abandonment been approvedYes26Adequate wellbore separation proposedYesDiverter waiver granted per 20 AAC 25.035(h)27If diverter required, does it meet regulationsYesMax reservoir pressure is 3840 psig(8.8 ppg EMW); will drill w/ 8.5-12.0 ppg EMW28Drilling fluid program schematic & equip list adequateYes29BOPEs, do they meet regulationYesMPSP is 3009 psig; will test BOPs to 3500 psig30BOPE press rating appropriate; test to (put psig in comments)Yes31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownYes33Is presence of H2S gas probableNA34Mechanical condition of wells within AOR verified (For service well only)YesH2S not expected based on nearby wells. Rig has sensors and alarms.35Permit can be issued w/o hydrogen sulfide measuresYesExpected pressure range is 0.431 to 0.61 psi/ft (8.3 to 11.8 ppg EMW). Operator's planned mud program36Data presented on potential overpressure zonesNAappears sufficient to control anticipated pressures and maintain wellbore stability.37Seismic analysis of shallow gas zonesNAMPD will be used to monitor and mitigate abnormal pressures encountered.38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprADDDate7/11/2024ApprVTLDate7/11/2024ApprADDDate7/11/2024AdministrationEngineeringGeologyGeologic Commissioner:GCWDate:Engineering Commissioner:JLCDatePublic CommissionerDateNOTE: Pressure ranging from 8.4 to 9.4 expected surface to top of HRZ shale. Pressure in HRZ to Alpine D jumps to 11.4 to 11.8 ppg. Alpine reservoir expected to be 8.8 ppg. See p. 15.*&:JLC 7/12/2024 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 Chris Brillon Wells Engineering Manager Conoco Phillips Alaska, Inc. 700 G Street Anchorage, AK, 99501 Re:Greater Mooses ToothField, Rendezvous Oil Pool, GMT MT7-89 Conoco Phillips Alaska, Inc. Permit to Drill Number: 224-089 Surface Location: 1121' FSL, 2141' FWL, SESW S32 T10N R2E, UM Bottomhole Location: 5018' FSL, 5104' FWL, SESE S32 T10N R2E, UM Dear Mr.Brillon: 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 AOGCCreserves 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 AOGCCspecifically 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 AOGCCorder, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, day of July 2024. *UHJRU\&:LOVRQ &ommissioner DATED this 3rd Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.07.03 11:23:26 -08'00' 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 23,388 TVD: 8,313 4a. Location of Well (Governmental Section):7. Property Designation: Surface: Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date: 7/15/2024 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 262' to AA092341 4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 155.3 15. Distance to Nearest Well Open Surface: x-290222 y- 5915936 Zone- 4 100.7 to Same Pool: 2140' to MT7-92 16. Deviated wells:Kickoff depth: 500 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 90 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 42 20 94 H-40 Welded 80 40 40 120 120 16 13-3/8/13-5/8 68/88.2 L-80 Hyd563 4127 40 40 4167 3060 12-1/4" 9-5/8/9-7/8 47/62.8 L-80 Hyd563 13005 40 40 13045 7448 8.5" x 9-7/8"7.625" 33.70 P-110S Hyd523 1843 12855 7277 14698 8348 6-1/2" 4.5" 12.60 P-110 Hyd563 8840 14548 8155 23388 8313 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned?Yes No 20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Weifeng Dai Chris Brillon Contact Email:Weifeng.Dai@conocophillips.com Wells Engineering Manager Contact Phone:907-947-4323 Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Perforation Depth TVD (ft): GL / BF Elevation above MSL (ft): Perforation Depth MD (ft): 100 sx 15.8 ppg CG Uncemented liner w/frac sleeves & swell packers Effect. Depth MD (ft):Effect. Depth TVD (ft): Authorized Title: Authorized Signature: Authorized Name: LengthCasing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 18. Casing Program:Top - Setting Depth - BottomSpecifications 3783 2956 ConocoPhillips Alaska. Inc. 1121' FSL, 2141' FWL, SESW S32 T10N R2E, UM AA098885,AA081800, AA081781 1262.68, 2525, 5720 59-52-180 2561' FSL, 3738' FWL , SESW S4 T09N R2E, UM 5018' FSL, 5104' FWL, SESE S32 T10N R2E, UM 369446000, 932535000, 932516000 P.O. Box 100360 Anchorage, Alaska, 99510-0360 Cement Volume MDSize Plugs (measured): (including stage data) Cement to surface with 10 yds slurry 476 sx 13.0 ppg CG + 125 sx 15.8 ppg CG Total Depth MD (ft):Total Depth TVD (ft): 1504 sx 11.0 ppg CG + 238 sx 15.8 ppg CG MT7-89 Greater Mooses Tooth Rendezvous Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. ddd: Y: : Y:::::es yp l oooos N d: d: d:dddd:d YesYYYY No s N No Dril ssss ssssssss ssss T Dril t 0 o hahaaaaaaaaaaaaaaales: ssG s S S 20 S d:dd:d:YeYYs No s No S s G y d:d:YYes No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) By Grace Christianson at 9:14 am, Jun 05, 2024 SFD 7/3/2024 7/4/2024 SFD 224-089 50-103-20889-00-00 Initial BOP test to 5000 psig; subsequent BOP test to 3500 psig Annular preventer test to 2500 psig Waiver for CPAI Rotary BOPE Test Frequency applies according to order OTH-21-018 extension attached Intermediate II cement evaluation may use SonicScope under the attached Conditions of Approval Surface casing LOT and annular LOT to the AOGCC as soon as available. BOP stack proposed approved while drilling the Int I(MPSP 1994 psig) Diverter waiver granted per 20 AAC 25.035(h) 3840 VTL 7/3/2024 3009 DSR-6/7/24 X &':IRU-/& Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.07.03 11:34:22 -08'00' 07/03/24 07/03/24 RBDMS JSB 070924 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: CRU Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): Colville River Unit MD: 23,388 TVD: 8,313 4a. Location of Well (Governmental Section):7. Property Designation: Surface: Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date: 7/15/2024 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 262' to AA092341 4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 155.3 15. Distance to Nearest Well Open Surface: x-290222 y- 5915936 Zone- 4 100.7 to Same Pool: 2140' to MT7-92 16. Deviated wells:Kickoff depth: 500 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 90 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 42 20 94 H-40 Welded 80 40 40 120 120 16 13-3/8/13-5/8 68/88.2 L-80 Hyd563 4127 40 40 4167 3060 12-1/4" 9-5/8/9-7/8 47/62.8 L-80 Hyd563 13005 40 40 13045 7448 8.5" x 9-7/8"7.625" 33.70 P-110S Hyd523 1843 12855 7277 14698 8348 6-1/2" 4.5" 12.60 P-110 Hyd563 8840 14548 8155 23388 8313 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned?Yes No 20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Weifeng Dai Chris Brillon Contact Email:Weifeng.Dai@conocophillips.com Wells Engineering Manager Contact Phone:907-947-4323 Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 1504 sx 11.0 ppg CG + 238 sx 15.8 ppg CG MT7-89 Greater Mooses Tooth Rendezvous Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. 2561' FSL, 3738' FWL , SESW S4 T09N R2E, UM 5018' FSL, 5104' FWL, SESE S32 T10N R2E, UM 369,446,000,932,535,000,000,000,000 P.O. Box 100360 Anchorage, Alaska, 99510-0360 Cement Volume MDSize Plugs (measured): (including stage data) Cement to surface with 10 yds slurry 476 sx 13.0 ppg CG + 125 sx 15.8 ppg CG Total Depth MD (ft):Total Depth TVD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 18. Casing Program:Top - Setting Depth - BottomSpecifications 3783 2956 ConocoPhillips Alaska. Inc. 1121' FSL, 2141' FWL, SESW S32 T10N R2E, UM AA098885,AA081800, AA081781 126325155720 59-52-180 LengthCasing Authorized Title: Authorized Signature: Authorized Name: 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Perforation Depth TVD (ft): GL / BF Elevation above MSL (ft): Perforation Depth MD (ft): 100 sx 15.8 ppg CG Uncemented liner w/frac sleeves & swell packers Effect. Depth MD (ft):Effect. Depth TVD (ft): d: Y Y YYYYYYYYYYYYYYYees ype of W l Class: os N d:Yeeees NNNNo s N NNNo Dril s s s T Dril 0 o haaleseseseeeeeeeeeeeeeeee: well is p G S S 20 S S S d:Yees NNNo Ns No S G y d:Yees NNNo s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) By Grace Christianson at 1:21 pm, Jun 04, 2024 461&34&%&% 'DdDdϳͲϭϱ Conditions of Approval: Approval is granted to run the LWD-Sonic on upcoming well with the following provisions: 1. CPAI will provide a written log evaluation/interpretation to the AOGCC along with the log as soon as they become available. The evaluation is to include/highlight the intervals of competent cement that CPAI is using to meet the objective requirements for annular isolation, reservoir isolation, or confining zone isolation etc. Providing the log without an evaluation/interpretation is not acceptable. 2. LWD sonic logs must show free pipe and Top of Cement, just as the e-line log does. CPAI must start the log at a depth to ensure the free pipe above the TOC is captured as well as the TOC. Starting the log below the actual TOC based on calculations predicting a different TOC will not be acceptable. 3. CPAI will provide a cement job summary report and evaluation along with the cement log and evaluation to the AOGCC when they become available 4. CPAI will provide the results of the FIT when available. 5. Depending on the cement job results indicated by the cement job report, the logs and the FIT, remedial measures or additional logging may be required. 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov March 2, 2023 Mr. Luke Lawrence Wells Manager ConocoPhillips Alaska 700 G Street Anchorage, AK 99501 Re: Docket Number: OTH-21-018 CPAI Rotary Rig BOPE Test Frequency Dear Mr. Lawrence: By letter dated January 12, 2023, ConocoPhillips Alaska, Inc. (CPAI) requested a continuance of the waiver granted under Docket OTH-21-018 allowing certain CPAI rotary drilling rigs to test blowout prevention equipment (BOPE) on a 21-day test schedule. The Alaska Oil and Gas Conservation Commission (AOGCC) grants CPAI’s request for a limited duration and scope. OTH-21-018 approved the 21-day test interval for a 1-year period which expired on January 25, 2023. The AOGCC approved an extension to the pilot program by electronic mail on February 6, 2023, to accommodate review of the July-December 2022 BOPE Between Wells Maintenance Report (received January 27, 2023, and revised February 3, 2023). AOGCC met with CPAI on February 22, 2023 to discuss the Between Wells Maintenance Report and BOPE performance of the CPAI-operated rigs during 2022 in considering the requested continuance.1 During the past year, CPAI-operated rigs Doyon 25 and Doyon 26 were authorized to participate in the pilot – the other rigs working for CPAI failed to meet the conditions for testing BOPE at 21- day intervals.2 CPAI’s request to continue the pilot project allowing BOPE testing on a 21-day interval is approved for drilling rigs Doyon 25 and Doyon 26, with the following conditions: - The pilot test duration is for ONE year from the approval date of this letter, subject to potential extension and expansion to include other CPAI operated rigs with at least 3 months of continuous rig work and AOGCC review of a rig’s BOPE system reliability. 1 AOGCC approval of the Between Wells Maintenance program has enabled CPAI workover rigs to extend the interval between BOPE tests from every 7 days to not exceeding 14 days and was also part of the justification for allowing certain rigs to test BOPE on a 21-day interval. CPAI data shows the BWM has reduced the number of component failures during BOPE testing by replacing components that indicate suspect integrity before those components fail during testing. 2 Doyon 26 has additionally been approved (Permit-to-Drill) to test BOPE on an event-basis instead of at pre- determined time intervals while drilling specific sections in an ultra-extended reach well. Docket Number: OTH-21-018 March 2, 2023 Page 2 of 2 - CPAI must continue to implement the BWM program as approved by AOGCC. - Development drilling wells only are included in this approval. - The initial test after rigging up BOPE to drill a well must be to the rated working pressure as provided in API Standard 53. - CPAI is encouraged to take advantage of opportunities to test. - CPAI must adhere to original equipment manufacturer recommendations and replacement parts for BOPE. - Requests for extensions beyond 21 days must include justification with supporting information demonstrating the additional time is necessary for well control purposes or to mitigate a stuck drill string. - 48-hour advance notice for a BOPE test shall be provided to AOGCC for opportunity to witness. If you have questions regarding this, please contact Jim Regg at (907) 793-1236. Sincerely, Brett W. Huber, Sr. Chair, Commissioner cc: Greg Hobbs (CPAI) Mike Kneale (CPAI) Victoria Loepp (AOGCC) AOGCC Inspectors (email) Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.03.02 11:09:23 -09'00' ConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907-276-1215 May 7, 2024 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Application for Permit to Drill MT7-89 Dear Sir or Madam: ConocoPhillips Alaska, Inc. hereby applies for a Permit to Drill an onshore Alpine C-Sand producer well from the MT7 drilling pad. The intended spud date for this well is 7/15/2024. It is intended that Doyon 26 be used to drill the well. MT7-89 will utilize a 16” surface hole and will TD above the K3 sand and then 13-3/8" casing will be set and cemented to surface. The 12-1/4" intermediate 1 section will be drilled to the top of HRZ formation. A 9-5/8" casing string will be run and cemented in place with a 500’ MD or 250’ TVD column of cement above the highest hydrocarbon bearing zone per AOGCC regulation. If an additional hydrocarbon zone is present, a 2nd stage cement job will be performed to cover 50’ TVD above and below the interval. The 8-1/2" x 9-7/8" intermediate 2 section will be drilled and landed in the Alpine D. A 7-5/8” liner string will be set and cemented from TD to seccure the shoe and cover 500’ MD or 250’ TVD above any hydrocarbon bearing zone. The production interval will be comprised of a 6-1/2" horizontal hole that will be geo-steered in the Alpine C sand. The well will be completed as a producer with 4.5” liner and swell packers. The upper completion will include a production packer with GLM’s and tied back to surface. It is requested that a variance of the diverter requirement under 20 AAC25.035 (h)(2) is granted. At MT7 there has not been a significant indication of shallow gas or gas hydrates through the surface hole interval. Please find attached the information required by 20 ACC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following: 1. Form 10-401 APPLICATION FOR Permit to Drill per 20 ACC 25.005 (a) 2. A proposed drilling program 3. A proposed completion diagram 4. A drilling fluids program summary 5. Pressure information as required by 20 ACC 25.035 (d)(2) 6. Directional drilling / collision avoidance information as required by 20 ACC 25.050 (b) 7. Area of review Information pertinent to the application that is presently on file at the AOGCC: 1. Diagrams of the BOP equipment, diverter equipment and choke manifold lay out as required by 20 ACC 25.035 (a) and (b). 2. A description of the drilling fluids handling system. 3. Diagram of riser set up. If you have any questions or require further information, please contact Weifeng Dai at 907-265-6936 (Weifeng.Dai@conocophillips.com) or Greg Hobbs at 907-263-4794 (greg.s.hobbs@conocophillips.com). Sincerely, cc: MT7-89 Well File / Jenna Taylor ATO 1560 Dave Lee ATO 1552 Weifeng Dai Chris Brillon ATO 1548 Staff Drilling Engineer Andy Mack Kuukpik Corp Recommend approving requested diverter waiver.* SFD requested that a variance of the diverter requirement under 20 AAC25.035 (h)(2) * No significant surface-hole gas or gas-hydrates reported in daily ops summaries or observed in Totco gas-monitoring data recorded from nearest wells MT7-92 and -93 (located 600' and 1000' to southwest, respectively). SFD MT7-89 Saved: 4-Jun-24 MT7-89 Page 1 of 17 Printed: 4-Jun-24 MT7-89 Well Plan Application for Permit to Drill Table of Contents 1. Well Name (Requirements of 20 AAC 25.005 (f)) ........................................................... 2 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) ......................................... 2 3. Proposed Drilling Program ...................................................................................... 5 4. Diverter and BOP Information (Requirements of 20 AAC 25.005(c)(7)) .................. 6 5. MASP Calculations ................................................................................................... 6 6. Procedure for Conducting Formation Integrity Tests (Requirements of 20 AAC 25.005 ©(5)) ............................................................................................................... 8 7. Casing and Cementing Program ............................................................................. 8 8. Drilling Fluid Program (Requirements of 20 AAC 25.005(c)(8)) .................................... 9 9. Abnormally Pressured Formation Information (Requirements of 20 AAC 25.005 (c)(9)) ................................................................................................................................. 10 10. Seismic Analysis (Requirements of 20 AAC 25.005 (c)(10)) ........................................ 10 11. Seabed Condition Analysis (Requirements of 20 AAC 25.005 (c)(11)) ....................... 10 12. Evidence of Bonding (Requirements of 20 AAC 25.005 (c)(12)) ................................. 10 13. Drilling Hazards Summary ..................................................................................... 11 14. Proposed Completion Schematic ......................................................................... 13 15. MT7-89 Intermediate 1 MPSP Review & Ram Configuration .............................. 14 16. Area of Review ....................................................................................................... 17 MT7-89 Saved: 4-Jun-24 MT7-89 Page 2 of 17 Printed: 4-Jun-24 1. Well Name (Requirements of 20 AAC 25.005 (f)) The well for which this application is submitted will be designated as MT7-89 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) Location at Surface 1121' FSL, 2141' FWL, SESW S32 T10N R2E, UM NAD27 Northings: 5915918 Eastings: 290186 RKB Elevation 54.6’ AMSL Pad Elevation 100.7’ AMSL Top of Productive Horizon (Heel) 2561' FSL, 3738' FWL , SESW S4 T09N R2E, UM NAD27 Northings:5919526 Eastings: 292219 Measured Depth, RKB: 14,698’ Total Vertical Depth, RKB: 8,348’ Total Vertical Depth, SS: 8,193’ Total Depth (Toe) 5018' FSL, 5104' FWL, SESE S32 T10N R2E, UM NAD27 Northings: 5910225 Eastings: 296637 Measured Depth, RKB: 23,388’ Total Vertical Depth, RKB: 8,313’ Total Vertical Depth, SS: 8,158’ Please see attached well stick diagram for the current planned development of the pad. MT7-89 Saved: 4-Jun-24 MT7-89 Page 3 of 17 Printed: 4-Jun-24 Pad Layout Well Stick Diagram MT7-89 Saved: 4-Jun-24 MT7-89 Page 4 of 17 Printed: 4-Jun-24 MT7-89 Saved: 4-Jun-24 MT7-89 Page 5 of 17 Printed: 4-Jun-24 3. Proposed Drilling Program 1. MIRU rig Doyon 26 onto well over pre-installed 20” insulated conductor. 2. Rig up and test riser, dewater cellar as needed. 3. Drill 16” hole to the surface casing point as per the directional plan. (LWD Program: GR/RES). 4. Run and cement new 13-3/8” + 13-5/8” surface casing to surface. Results of the cement operation will be submitted as soon as possible. 5. Install BOPE with the following equipment/configuration: 13-5/8” annular preventer, 9-5/8” fix casing ram, blind ram and 3-1/2” x 6-5/8” VBR. x See section 16 for ram configuration justification 6. Test BOPE to 250 psi low / 5,000 psi high (24-48 hr. regulatory notice). 7. Pick up and run in hole with 12-1/4” drilling BHA to drill intermediate #1. (LWD Program: GR/RES). 8. Chart casing pressure test to 3,500 psi for 30 minutes. 9. Drill out shoe track and 20’ of new hole. 10. Perform LOT to maximum EMW of 18.5 ppg. 1. Send results to AOGCC as soon as available. 11. Displace well to 11.0 ppg Fresh water polymer WBM. 12. Drill 12-1/4” hole to the casing point. 13. Circulate wellbore clean and trip out of hole. 14. Send OH logs to AOGCC to review shallow hydrocarbon bearing sands as soon as available. 15. Run 9-5/8” + 9-7/8” intermediate casing to TD. 16. Pump single stage cement job to isolate the casing shoe or 500’ MD above uppermost hydro-carbon bearing zone. A 2nd stage cement job will be performed to isolate reservoir quality sand if exists at shallower depth. Submit results of the cement operation to AOGCC as soon as possible. 1. There is potential for the presence of the Tusk sand, which may be hydrocarbon bearing and require a second stage cement job to place cement 50’ TVD above and below the interval. The required equipment and cement plans are prepared if this becomes necessary. 17. Change upper 9-5/8” fixed casing ram to 4-1/2” x 7-5/8” VBRs. Test BOPE to 250/3,500 psi. (24-48 hr. regulatory notice). 18. Pick up and run in hole with 8-1/2” x 9-7/8” drilling BHA to drill intermediate 2. Simops – perform 13-3/8” x 9-5/8” annulus LOT, flush and freeze protect with the ball mill. 19. Chart casing pressure test to 3,500 psi for 30 minutes. 20. Drill out shoe track and 20’ of new hole. 21. Perform FIT to max 14.0 ppg EMW. 22. Drill 8-1/2" x 9-7/8” hole to section TD with OBM. 23. Circulate wellbore clean and trip OOH. 24. Pick up and run in hole with the 7-5/8” liner to section TD. 25. Circulate and condition mud in preparation for cementing. 26. Cement 7-5/8” liner to required TOC. Set liner top packer. Circulate excess cement from top of liner. POOH laying down drill pipe. Submit results to AOGCC as soon as possible. 27. Change out upper rams to 3-1/2” x 6-5/8” VBR. OH logs to AOGCC to review shallow hydrocarbon bearing sands as soon as available MT7-89 Saved: 4-Jun-24 MT7-89 Page 6 of 17 Printed: 4-Jun-24 28. Pick up DP. Test BOPE to 250 psi low / 3,500 psi high. (24-48 hr. regulatory notice). 29. Pick up and RIH with 6-1/2” drilling assembly. (LWD Program: GR/Azimuthal RES, Neu/Den). 30. Chart casing pressure test to 3,500 psi for 30 minutes and record results. 31. Drill out and perform FIT to 12.0 ppg EMW. 32. Drill 6-1/2” horizontal hole to TD. 33. Circulate the hole clean, displace to vis brine, POOH. 34. Run 4-1/2” liner on DP, set liner hanger and top packer. Test to confirm packer set. Release from hanger and displace well to CI brine. POOH and laying down DP. 35. Run 4-1/2” tubing with production packer, DHG, GLMs and landing nipples. Locate and space out tubing. Terminate TEC wire and land tubing hanger. 36. Test tubing hanger seals from above to 2,500 psi for 15 mins. 37. Drop ball and rod. Pressure up to set production packer. 38. Pressure test tubing to 4,200 psi for 30 mins. Test IA to 3,500 psi for 30 mins. Shear SOV. 39. Install BPV, test same and tubing hanger seals from below to 2,500 psi. 40. Nipple down BOP, terminate TEC wire. 41. Install tubing head adaptor. Pressure test adaptor to 5,000 psi. 42. Install tree and test. 43. Pull BPV, freeze protect IA and tubing. 44. Secure well. Rig down and move out. 4. Diverter and BOP Information (Requirements of 20 AAC 25.005(c)(7)) Please reference BOP and diverter schematics on file for Doyon 26. 5. MASP Calculations The following presents data used for calculation of anticipated surface pressure (ASP) during drilling of this well: Casing Size (in) Csg Setting Depth MD/TVD (ft) Fracture Gradient (ppg) Pore pressure (psi) ASP Drilling (psi) 20 115 / 115 10.9 52 54 13.375 + 13.625 4,167 / 3,060 14.5 1364 1077 9.625 + 9.875 13,045 / 7,448 16.5 3406 1980 7.625 14,698 / 8,348 12.5 3755 2930 4.5 23,388 / 8,313 12.5 3840 2995 PROCEDURE FOR CALCULATING ANTICPATED SURFACE PRESSURE (ASP) ASP is determined as the lesser of 1) surface pressure at breakdown of the formation casing seat with a gas gradient to the surface, or 2) formation pore pressure at the next casing point less a gas gradient to the surface as follows: 1) ASP = [(FG x 0.052) - 0.1]D Where: ASP = Anticipated Surface pressure in psi FG = Fracture gradient at the casing seat in lb/gal 0.052 = Conversion from lb/gal to psi/ft 0.1 = Gas gradient in psi/ft D = true Vertical depth of casing seat in ft RKB MT7-89 Saved: 4-Jun-24 MT7-89 Page 7 of 17 Printed: 4-Jun-24 OR 2) ASP = FPP – (0.1 x D) Where: FPP = Formation Pore Pressure at the next casing point FPP = 0.4525 x TVD 1. ASP CALCULATIONS 1. Drilling below 20” conductor ASP = [(FG x 0.052) – 0.1] D = [(10.9 x 0.052) – 0.1] x 115 = 54 psi OR ASP = FPP – (0.1 x D) = 1380 – (0.1 x 3060’) = 1077 psi Minimum MW needed = 8.7 ppg 2. Drilling below 13.375” surface casing ASP = [(FG x 0.052) – 0.1] D = [(14.5 x 0.052) – 0.1] x 3060’ = 2001 psi OR ASP = FPP – (0.1 x D) = 3406 – (0.1 x 7448) = 2661 psi Minimum MW needed = 8.8 ppg 3. Drilling below first 9.625” intermediate casing ASP = [(FG x 0.052) – 0.1] D = [(16.5 x 0.052) – 0.1] x 7448 = 5646 psi OR ASP = FPP – (0.1 x D) = 3755– (0.1 x 8348’) = 2920 psi Minimum MW needed = 8.7 ppg 4. Drilling below 7” production liner ASP = [(FG x 0.052) – 0.1] D = [(12.5 x 0.052) – 0.1] x 8313 = 4572 psi OR ASP = FPP – (0.1 x D) = 3840 – (0.1 x 8313) = 3009 psi Minimum MW needed = 8.8 ppg (B) data on potential gas zones; The well bore is not expected to penetrate any gas zones. (C) data concerning potential causes of hole problems such as abnormally geo-pressured strata, lost circulation zones, and zones that have a propensity for differential sticking; Please see Drilling Hazards Summary MT7-89 Saved: 4-Jun-24 MT7-89 Page 8 of 17 Printed: 4-Jun-24 6. Procedure for Conducting Formation Integrity Tests (Requirements of 20 AAC 25.005 ©(5)) Drill out casing shoe and perform LOT test or FIT in accordance with the Alpine LOT/FIT procedure that ConocoPhillips Alaska has on file with the Commission. 7. Casing and Cementing Program Casing and Cementing Program Csg/Tbg OD (in) Hole Size (in) Weight (lb/ft) Grade Conn. Cement Program 20 42 94 H-40 Welded Cemented to surface with 10 yds slurry 13.375 + 13.625 16 68/88.2 L-80 Hyd563 Cement to Surface 9.625 + 9.875 12.25 47/62.8 L-80 Hyd563 250’ TVD or 500’ MD, whichever is greater, above highest significant hydrocarbon bearing zone 7.625 8.5 x 9.875 33.7 P-110s Hyd523 250’ TVD or 500’ MD, whichever is greater, above highest significant hydrocarbon bearing zone 4.5 6.125 12.6 L-80 Hyd563 Uncemeneted open hole liner with frac ports and swell packers 13.375” Surface Casing run to 4,167’ MD /3,060’ TVD Cement Plan: Cement from 4,167’ MD to 3,667' (500’ of tail) with Deepcrete + Add's. @ 15.8 ppg, and from 3,667' to surface with 11.0 ppg DeepCrete. Assume 120% excess annular volume in permafrost and 50% excess below the permafrost (981’ MD), zero excess in 20” conductor. Lead slurry from 3,667’ MD to surface with Arctic Lite Crete @ 11.0 ppg Total Volume = 2,602 ft3 => 1,504 sx of 11.0 ppg Deepcrete + Add's @ 1.73 ft3 /sk Tail slurry from 4,167’ MD to 3,667’ MD with 15.8 ppg Deepcrete + Add's Total Volume = 316 ft3 => 238 sx of 15.8 ppg Class G + Adds @ 1.33 ft3/sk 9.625” Intermediate Casing run to 13,045’ MD / 7,448’ TVD Cement Plan: Primary cement job consists of 500 ft 15.8 ppg tail slurry and top of 13.0 ppg lead slurry is designed to be at 10,582’ MD, which is 500’MD or 250’ TVD above the prognosis shallowest hydrocarbon bearing zone Albian Sub 93. If a shallower hydrocarbon zone of producible volumes is encountered while drilling, a 2nd stage cement job will be performed to isolate this zone. Assume 30% excess annular volume. Lead slurry from 12,545’ MD to 10,582’ MD with 13.0 ppg Class G + Add’s Total Volume = 799 ft3 => 476 sx of 13.0 ppg Class G + Add's @ 1.68 ft3 /sk Tail slurry from 13,045’ MD to 12,545’ MD with 15.8 ppg Class G + Add's Total Volume = 203 ft3 => 125 sx of 15.8 ppg Class G + Adds @ 1.63 ft3/sk MT7-89 Saved: 4-Jun-24 MT7-89 Page 9 of 17 Printed: 4-Jun-24 7-5/8” Intermediate Casing run to 14,698’ MD /8,248’ TVD Cement Plan: Top of slurry is designed to be at 14,100’ MD, which is 500’MD or 250’ TVD above Alpine D. Assume 40% excess annular volume. Tail slurry from 14,698’ MD to 14,100’ MD with 15.8 ppg Class G + Adds Total Volume = 167 ft3 => 100 sx of 15.8 ppg Class G + Adds@ 1.63 ft3/sk Centralizer Program Joint Type Centralizer Placement Surface 1,2,3 13.375” x 16” rigid 1 per joint 4 to surface 13.375” x 16” bow spring As necessary Intermediate 1 Shoe Track NA No centralizers Shoe Track to TOC 9.625” x 12.25” rigid 1 per joint TOC to Surface Shoe NA No centralizers 3 joints across surface shoe 9.625” x 12.25” rigid 1 per joint Remaining to surface 9.625” x 12.25” rigid 1 every other joint Intermediate 2 Flot shoe to 2 jts below liner hanger 7.625” x 9.5” Centak, Semi-regid 1 per joint, no centralizer in 90’ rat hole Production Flot shoe to 2 jts below liner hanger 4.5” x 6.125” rigid 1 per joint 8. Drilling Fluid Program (Requirements of 20 AAC 25.005(c)(8)) Surface Intermediate #1 Intermediate #2 Production Hole Size in. 16 12.25 8.5 x 9.875 6.125 Casing Size in. 13.375 + 13.625 9.625 + 9.875 7.625 4.5 Density PPG 9.0 – 10.0 11.0 – 12.0 10.0 – 11.5 8.5 – 8.8 PV cP 13 10 40 15 YP lb./100 ft2 35-50 20 - 28 20 - 35 15 - 20 Funnel Viscosity s/qt. 200 40 - 50 70 - 90 60 - 80 Initial Gels lb./100 ft2 50 10 14 10 10 Minute Gels lb./100 ft2 60 15 42 15 API Fluid Loss cc/30 min. N.C. – 15.0 10 N/A 4 HPHT Fluid Loss cc/30 min. n/a 8.0 – 12.0 5.0 10.0 pH 11.0 9.5 – 10.0 9.5 – 10.0 9.0 – 9.5 Surface Hole: A fresh water drilling fluid (KSI) will be used for the surface interval. Keep flow line viscosity at r 200 sec/qt while drilling and running casing. Reduce viscosity prior to cementing. Maintain mud weight 10.0 ppg by use of solids control system and dilutions where necessary. Intermediate #1: Fresh water polymer mud system. Ensure good hole cleaning by pumping regular sweeps and maximizing fluid annular velocity. Maintain mud weight from 9.4-12.0 ppg and be prepared to add loss circulation material. Good MT7-89 Saved: 4-Jun-24 MT7-89 Page 10 of 17 Printed: 4-Jun-24 filter cake quality, hole cleaning and maintenance of low drill solids (by diluting as required) will all be important in maintaining wellbore stability. Intermediate #2: The intermediate 2-hole section will be drilled with OBM weighted to 11.0 ppg. Ensure good hole cleaning by maximizing fluid annular velocity. There is a slight potential for lost circulation, particularly after the reservoir is penetrated. Ensure adequate LCM material is available on location and in the field to address any expected losses. Maintain mud weight will be 11.0 targeting 12.0 EMW using MPD. Good filter cake quality, hole cleaning and maintenance of low drill solids (by diluting as required) will all be important in maintaining wellbore stability. Note: Managed Pressure Drilling (MPD) will be utilized for adding backpressure during connections to mitigate shale instability and cycling. Production Hole: The horizontal production interval will be drilled with water-based mud drill-in fluid weighted to 8.8 ppg. MPD will be used to hold back pressure, keeping the well dynamically balanced. Diagram of Doyon 26 Mud System on file. Drilling fluid practices will be in accordance with appropriate regulations. 9. Abnormally Pressured Formation Information (Requirements of 20 AAC 25.005 (c)(9)) N/A - Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis (Requirements of 20 AAC 25.005 (c)(10)) N/A - Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis (Requirements of 20 AAC 25.005 (c)(11)) N/A - Application is not for an offshore well. 12. Evidence of Bonding (Requirements of 20 AAC 25.005 (c)(12)) Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. MT7-89 Saved: 4-Jun-24 MT7-89 Page 11 of 17 Printed: 4-Jun-24 13. Drilling Hazards Summary (To be posted in Rig Floor Doghouse Prior to Spud) 16" Hole / 13.375” Casing Interval Event Risk Level Mitigation Strategy Conductor Broach Low Monitor cellar continuously during interval. Well Collision Low First well on Pad, traveling cylinder diagrams Gas Hydrates Low If observed – control drill, reduce pump rates and circulating time, reduce mud temperatures Clay Balling Medium Maintain planned mud parameters and flow rates, Increase mud weight, use weighted sweeps, reduce fluid viscosity, control ROP Abnormal Pressure in Surface Formations Low Diverter drills, increased mud weight. Shallow hazard study noted minimal risk Lost Circulation Medium Reduce pump rates, mud rheology, add lost circulation material, use of low density cement slurries, port collar, control pipe running speeds 12.25” Hole / 9.625” Casing Interval Event Risk Level Mitigation Strategy Lost circulation Low Reduce pump rates, reduce trip speeds, real time ECD monitoring, mud rheology, add lost circulation material Hole swabbing on trips Medium Reduce trip speeds, condition mud properties, proper hole filling, pump out of hole, real time ECD monitoring, MPD stripping practices Abnormal Pressure in Overburden Formations Low Well control drills, check for flow during connections, increase mud weight. Shallow hazard study noted minimal risk Hole Cleaning Low Monitor ECD and torque/drag trends, control drill and use best hole cleaning practices 8.5x9.875” Hole / 7.625” Liner - Casing Interval Event Risk Level Mitigation Strategy Sloughing shale, Tight hole High MPD for shale stability, Steerable Drilling Liner, Increase mud weight, control ROP, connection and trip speeds, sweeps, and real time equivalent circulating density (ECD) monitoring, run casing as liner Lost circulation Low Reduce pump rates, reduce trip speeds, real time ECD monitoring, mud rheology, add lost circulation material Hole swabbing on trips Medium Reduce trip speeds, condition mud properties, proper hole filling, pump out of hole, real time ECD monitoring, Liner will be in place at TD Abnormal Reservoir Pressure Low Well control drills, check for flow during connections, increase mud weight Hydrogen Sulfide gas Low H2S drills, detection systems, alarms, standard well MT7-89 Saved: 4-Jun-24 MT7-89 Page 12 of 17 Printed: 4-Jun-24 control practices, mud scavengers 6.5” Hole / 4.5” Liner - Horizontal Production Hole Event Risk Level Mitigation Strategy Lost circulation Low Reduce pump rates, reduce trip speeds, real time ECD monitoring, mud rheology, add lost circulation material Hole swabbing on trips Medium Reduce trip speeds, condition mud properties, proper hole filling, pump out of hole, real time ECD monitoring Abnormal Reservoir Pressure Low Well control drills, check for flow during connections, increased mud weight Differential Sticking Low Uniform reservoir pressure along lateral, keep pipe moving, control mud weight Hydrogen Sulfide gas Low H2S drills, detection systems, alarms, standard well control practices, mud scavengers Well Proximity Risks: MT7 will be a multi-well pad, containing an original plan of 36 wells. Directional drilling / collision avoidance information is provided in the following attachments. Drilling Area Risks: Reservoir Pressure: Offset injection has the potential to increase reservoir pressure over predicted. Although this is unlikely, the rig will be prepared to weight up if required. Weak sand stringers could be present in the overburden. LCM material will be available to seal in losses in the intermediate section. Lower Shale Stability: HRZ/Kalubik/Miluveach in the pilot and intermediate #2 hole sections will require higher mud weights than historically used to enhance wellbore stability. Managed Pressure Drilling will be used in conjunction with a 4-string casing design to mitigate shale instability in the aforementioned formations. Standard LCM material and well bore strengthening pills are expected to be effective in dealing with lost circulation if needed. Good drilling practices will be stressed to minimize the potential of taking swabbed kicks. MT7-89 Saved: 4-Jun-24 MT7-89 Page 13 of 17 Printed: 4-Jun-24 14. Proposed Completion Schematic MT7-89 Saved: 4-Jun-24 MT7-89 Page 14 of 17 Printed: 4-Jun-24 15. MT7-89 Intermediate 1 MPSP Review & Ram Configuration Proposal Requesting approval to use a BOPE stack equipped with an annular preventer, fixed 9-5/8” solid body rams, blind/shear rams and, variable rams (4-1/2” x 7-5/8”) while drilling and running casing in the Intermediate 1 section of MT7-89. The Maximum Potential Surface Pressure (MPSP) is expected to be 1994 psi while drilling the 12-1/4” Intermediate 1 hole section with 5” drill pipe, satisfying 20 AAC 25.035.e.1.A. Please find the review below for more detail. 20 AAC 25.035.e.1.A: For an operation with a maximum potential surface pressure of 3,000 psi or less, BOPE must have at least three preventers, including: i. One equipped with pipe rams that fit the size of drill pipe, tubing or casing begin used, except that pipe rams need not be sixed to bottom-hole assemblies and drill collars. ii. One with blind rams iii. One annular type Proposed Configuration: x Annular Preventer (iii) x 9-5/8” Solid Body Rams x Blind/Shear Rams (ii) x 4-1/2” x 7-5/8” VBR’s (i) MT7-89 Saved: 4-Jun-24 MT7-89 Page 15 of 17 Printed: 4-Jun-24 Pore Pressure Assessment A Normal Compaction Trend (NCT) is defined using the Bowers Method on a calibration well with little/no erosion and global constants as a starting point. Both source rock and non-source rock NCTs are then defined. For a given unit/zone, deviations slower than NCT indicate overpressure and allow calculation of its magnitude. The NCT for individual wells is defined by modifying Bowers parameters to account for specific erosion amounts. The maximum estimated reservoir pressure in the Intermediate 1 section is 9.4 ppg. Interval TVD Top TVD Base Max PPG Note Surface to Permafrost Base 0 977 8.3 Hydrostatic Permafrost Base to C40 977 1079 9.1 Hydrostatic C40 to C30 1079 1405 9.2 Rendezvous-2 DT Estimate C30 to C20 1405 1642 8.45 Hydrostatic C20 to C10 1642 1986 8.475 Hydrostatic C10 to K3 1986 2999 9.3 Rendezvous-2 DT Estimate K3 to Albian_97 2999 3607 8.55 Hydrostatic Albian 97 to Albian 96 3607 3788 8.56 Hydrostatic Albian 96 to Albian 95 3788 3972 8.56 Hydrostatic Albian 95 to Albian 94 (Tusk Sand if present) 3972 4240 8.56 Hydrostatic Albian 94 to Albian 93 4240 4895 8.57 Hydrostatic Albian 93 to Albian 92 4895 6061 8.6 Hydrostatic Albian 92 to Albian 91 6061 6121 8.6 Hydrostatic Albian 91 to HRZ (Susitna Sand if present) 6121 7396 9.4 Offset Well DT/ Res Estimates HRZ to LCU 7396 7591 11.6 Offset Well DT/ Res Estimates LCU to Alpine D 7591 8237 11.75 Offset Well DT/ Res Estimates Alpine D to Alpine C 8237 8263 11.4 MT7-04 Res Est. Alpine C to UJU 8263 8359 8.8 Offset MDT’s MT7-89 Saved: 4-Jun-24 MT7-89 Page 16 of 17 Printed: 4-Jun-24 Maximum Potential Surface Pressure Surface Casing Point:4,167' MD/ 3,060' TVD Intermediate 1 Casing Point:13,045' MD/ 7448' TVD Max Anticipated Pore Pressure:9.4 ppg | Albian 91 > HRZ Surface Casing Shoe FG:14.5 ppg EMW | K3 Maximum Potential Surface Pressure (MPSP) is determined as the lesser of 1.) surface pressure at breakdown of the formation casing seat with a gas gradient to the surface, or 2.) formation pore pressure at the next casing point less a gas gradient to the surface as follows: Method 1 Method 2 Where: FG – Fracture gradient at the casing seat in lb/gal 0.052 – Conversion from lb/gal to psi/ft Gas Gradient –0.1 psi/ft TVD – True Vertical Depth of casing seat in ft RKB Where: FPP –Formation Pore Pressure at the next casing point MPSPCALCULATIONS: Method 1: MPSP = [(FG x 0.052) – Gas Gradient] x TVD MPSP = [(14.5 ppg EMW x 0.052) - 0.1 psi/ft] x 3060 TVD MPSP = 2001 psi Method 2: MPSP = FPP – (Gas Gradient x TVD) MPSP = (9.4 ppg x .052 x 7448‘ TVD) - (0.1 psi/ft x 7448’ TVD) MPSP = 2896 psi MT7-89 Saved: 4-Jun-24 MT7-89 Page 17 of 17 Printed: 4-Jun-24 16. Area of Review An Area of Review plot is show below of the MT7-89 planned wellpath and offset wells. MT7-91 and MT7- 15 are the offset wells from the planned MT7-89 producer. MT7-91 was successfully completed recently and MT7-15 is the planned well and scheduled to spud today, 6/4/2024. Well Name Status Top of Alpine Pool (MD/TVD) TOC (MD/TVD) TOC – Determined By Reservoir Status Zonal Isolation Cement Operations Summary MT7-91 Shut in 11,558’ / 8,297’ 10,990’ / 8,148’ SonicScope Liner TOC and production Packer 67 bbls of 15.8 ppg Class G pumped with partial return 54 500 500 1000 1000 1500 1500 2000 2000 4000 4000 7000 7000 11000 11000 15000 15000 20000 20000 23888 MT7-89 wp04 South MT7-01 MT7-02 MT7-03 MT7-03A RWO Redrill MT7-04 MT7-05 MT7-06 MT7-06AMT7-06PB1 MT7-07 MT7-08 MT7-08PB1 MT7-14MT7-14A MT7-91 MT7-92MT7-93 MT7-95 MT7-96 MT7-97 MT7-98 MT7-99 MT7-10_wp04 MT7-15 wp04 MT7-83 wp01 MT7-91_wp06 MT7-89 wp04 South Plan Summary 0 4 Dogleg Severity0 3500 7000 10500 14000 17500 21000 Measured Depth 13-3/8" Surface Casing 9-5/8" INT1 Casing 7-5/8" INT2 Liner 4-1/2" PROD Liner 50 50 100 100 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [100 usft/in] MT7-91 MT7-92 MT7-93 MT7-94 MT7-95 MT7-91_wp06 0 5000 True Vertical Depth-800 0 800 1600 2400 3200 4000 4800 Vertical Section at 37.09° 13-3/8" Surface Casing 9-5/8" INT1 Casing 7-5/8" INT2 Liner 4-1/2" PROD Liner 0 500 1000 Centre to Centre Separation0 1500 3000 4500 6000 7500 Measured Depth Equivalent Magnetic Distance DDI 7.193 SURVEY PROGRAM Date: 2024-04-23T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 54.11 1000.00 MT7-89 wp04 South (MT7-89 South) r.5 SDI_URSA1 1000.00 4167.00 MT7-89 wp04 South (MT7-89 South) MWD+IFR2+SAG+MS 4167.00 13045.00 MT7-89 wp04 South (MT7-89 South) MWD+IFR2+SAG+MS 13045.00 14799.00 MT7-89 wp04 South (MT7-89 South)MWD+IFR2+SAG+MS 14799.00 23387.61 MT7-89 wp04 South (MT7-89 South)MWD+IFR2+SAG+MS Surface Location North / 5915679.88 East / 1430258.02 Ground / 100.70 CASING DETAILS TVD MD Name 3059.81 4166.66 13-3/8" Surface Casing 7447.81 13044.91 9-5/8" INT1 Casing 8370.83 14798.90 7-5/8" INT2 Liner 8313.20 23387.61 4-1/2" PROD Liner Mag Model & Date: BGGM2024 10-Jul-24 Magnetic North is 13.51° East of True North (Magnetic Declination) Mag Dip & Field Strength: 80.33° 57060.48nT SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Annotation 1 54.11 0.00 0.00 54.11 0.00 0.00 0.00 0.00 0.00 2 500.00 0.00 0.00 500.00 0.00 0.00 0.00 0.00 0.00 Start Build 1.50 3 700.00 3.00 132.30 699.91 -3.52 3.87 1.50 132.30 -0.48 Start Build 2.00 4 1000.00 9.00 132.30 998.13 -24.62 27.05 2.00 0.00 -3.32 Start DLS 2.50 TFO 0.47 5 3381.50 68.54 132.73 2772.52 -990.51 1074.82 2.50 0.47 -141.85 Start 6571.09 hold at 3381.50 MD 6 9952.59 68.54 132.73 5176.87 -5140.43 5566.64 0.00 0.00 -742.99 Start DLS 3.00 TFO -147.57 7 12993.42 38.97 11.23 7407.78 -5169.09 7139.31 3.00 -147.57 182.64 Start 50.00 hold at 12993.42 MD 8 13043.42 38.97 11.23 7446.65 -5138.25 7145.43 0.00 0.00 210.93 Start 50.00 hold at 13043.42 MD 9 13093.42 38.97 11.23 7485.52 -5107.41 7151.56 0.00 0.00 239.23 Start DLS 3.00 TFO -52.48 10 14717.71 77.00 333.51 8352.56 -3819.60 6881.58 3.00 -52.48 1103.63 Start 50.00 hold at 14717.71 MD 11 14767.71 77.00 333.51 8363.81 -3775.99 6859.85 0.00 0.00 1125.30 Start 50.00 hold at 14767.71 MD 12 14817.71 77.00 333.51 8375.06 -3732.39 6838.12 0.00 0.00 1146.98 Start Build 3.00 13 15289.77 91.16 333.51 8423.61 -3313.21 6629.22 3.00 0.00 1355.35 Start 2801.76 hold at 15289.77 MD 14 18091.54 91.16 333.51 8366.81 -806.10 5379.80 0.00 0.00 2601.63 Start DLS 2.00 TFO -124.24 15 18143.48 90.58 332.65 8366.02 -759.79 5356.29 2.00 -124.24 2624.39 Start 4744.13 hold at 18143.48 MD 16 22887.61 90.58 332.65 8318.24 3453.88 3176.96 0.00 0.00 4671.08 Start 500.00 hold at 22887.61 MD 17 23387.61 90.58 332.65 8313.20 3897.98 2947.28 0.00 0.00 4886.78 TD at 23387.61 FORMATION TOP DETAILS TVDPath Formation 154.81 Alpine_D 154.81 HRZ 154.81 LCU 154.81 Top_Alpine 994.79 Formation 1 1103.31 Formation 2 1438.29 Formation 3 1668.29 Formation 4 2024.36 Permafros 3041.07 C40 3674.22 C30 3895.44 C20 4079.03 C10 5059.99 K3 5638.52 Albian_97 5821.51 Albian_96 6331.10 Albian_95 6443.65 Albian_94 7409.34 Albian_93 7634.74 Top_Stareater 8364.16 Albian_92 8390.86 Albian_91 By signing this I acknowledge that I have been informed of all risks, checked that the data is correct, ensured it's completeness, and all surroundingwells are assigned to the proper position, and I approve the scan and collision avoidance plan as set out in the audit pack.I approve it as the basiis for the final well plan and wellsite drawings. I also acknowledge that unless notified otherwise all targets have a 100 feet lateral tolerance. Prepared by Checked by Accepted by Approved by Plan KB (100.7 PL+54.11 DF) @ 154.81usft (Doyon 26) 0300060009000True Vertical Depth (1500 usft/in)-3000 0 3000 6000 9000Vertical Section at 37.09° (1500 usft/in)13-3/8" Surface Casing9-5/8" INT1 Casing7-5/8" INT2 Liner4-1/2" PROD LinerMT7-89 wp04 SouthStart Build 1.50Start Build 2.00Start DLS 2.50 TFO 0.47Start DLS 2.50 TFO 0.47Start 6571.09 hold at 3381.50 MDStart DLS 3.00 TFO -147.57Start DLS 3.00 TFO -52.48Start Build 3.00Start DLS 2.00 TFO -124.24TD at 23387.61Section View Project: Western North SlopeSite:GMT2 Rendezvous PadWell: MT7-89Wellbore: MT7-89 SouthMT7-89 wp04 South Plan View Project: Western North SlopeSite:GMT2 Rendezvous PadWell: MT7-89Wellbore: MT7-89 SouthDesign: MT7-89 wp04 South-400004000South(-)/North(+) (2000 usft/in)-4000 0 4000 8000 12000West(-)/East(+) (2000 usft/in)MT7-89 T2 1320ftMT7-89 T1 1320ftMT7-89 Heel Rev113-3/8" Surface Casing9-5/8" INT1 Casing7-5/8" INT2 Liner4-1/2" PROD Liner50010001500200025003000350040004500500055006000650 0700075008000 8313MT7-89 wp04 South Plan View Project: Western North SlopeSite:GMT2 Rendezvous PadWell: MT7-89Wellbore: MT7-89 SouthDesign: MT7-89 wp04 South-700007000South(-)/North(+) (3500 usft/in)-14000 -7000 0 7000 14000West(-)/East(+) (3500 usft/in)MT7-89 T2 1320ftMT7-89 T1 1320ftMT7-01MT7-01PB1MT7-02MT7-03MT7-03A RWO RedrillMT7-04MT7-05MT7-06MT7-06AMT7-06PB1MT7-07MT7-08MT7-08PB1MT7-09MT7-11MT7-14MT7-14AMT7-91MT7-92MT7-93MT7-94MT7-95MT7-96MT7-97MT7-98MT7-99MT7-12_wp02_EXT_PetrelMT7-10_wp04MT7-15 wp04MT7-83 wp01MT7-91_wp0613-3/8" Surface Casing9-5/8" INT1 Casing7-5/8" INT2 Liner4-1/2" PROD Liner50010001500200025003000350040004500500055006000650 0700075008000 8313MT7-89 wp04 South ! ! 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D * 23 56 / ; $&)E 3 $)%E %F %&%%% 8// + 5 8// + / + 5 !" #$%%& '()*&$$ +,- . $)*& 3 56 ? , / ? 7 From:Nagel, Matt B To:Davies, Stephen F (OGC) Cc:Lee, David L; Conklin, Amy A; Guhl, Meredith D (OGC); Dewhurst, Andrew D (OGC) Subject:RE: [EXTERNAL]GMTU MT7-89 (Permit 224-089) - Questions Date:Tuesday, July 2, 2024 4:44:29 PM Attachments:image001.png image002.png image003.png MT7-92 Log.pdf MT7-93 Log.pdf Hi Steve, Here are the TOTCO logs from the surface hole sections for both MT7-92 and MT7-93. Few things to note about the logs: These logs are from the NOV’s Gas Watch System condensed to show the entire surface drilling interval. These sensors are installed on both D26 and D25 flow lines as there is not the traditional rig “possum belly”. This location, along with the solids that come up during surface drilling, can pack off where the agitator is installed on the flow line and can prevent optimal gas readings. The TOTCO channel being displaced is looking at 2 types of gas, Methan and Propane, and the total combined of these two is what is being plotted for the “Total Gas”. A max reading of 10,000 ppm unit of gas is equivalent to 1% by volume. All the gas shows at surface were insignificant and momentary. At no point was there sustained gas to surface. These logs are typically used by COPAI as qualitive monitoring vs quantitative as there can be some variations in the actual measurements across wells / rigs. Let me know if you have any questions. Matt Nagel Drilling Engineer ConocoPhillips Alaska Office: 907-263-4747 Cell: 281-615-3922 Matt.B.Nagel@ConocoPhillips.com From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Tuesday, July 2, 2024 6:04 AM To: Nagel, Matt B <Matt.B.Nagel@conocophillips.com> Cc: Lee, David L <David.L.Lee@conocophillips.com>; Conklin, Amy A <Amy.A.Conklin@conocophillips.com>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: RE: [EXTERNAL]GMTU MT7-89 (Permit 224-089) - Questions Thanks again, Matt. I’m assuming the TOTCO logs show no significant gas, correct? If CPAI could please send images of (in .pdf format), or the measurement data from (in spreadsheet or table format), the TOTCO logs recorded in MT7-93 and MT7-92—the two nearest wells—that would provide support for CPAI’s diverter-waiver request. Providing similar data to be recorded in MT7-89 will facilitate waiver requests for future wells with casing shoes located further to the southeast and east. Thanks again for your help and be well, Steve Davies AOGCC From: Nagel, Matt B <Matt.B.Nagel@conocophillips.com> Sent: Monday, July 1, 2024 2:52 PM To: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Cc: Lee, David L <David.L.Lee@conocophillips.com>; Conklin, Amy A <Amy.A.Conklin@conocophillips.com>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: RE: [EXTERNAL]GMTU MT7-89 (Permit 224-089) - Questions Hi Steve, No, those logs are not submitted to the AOGCC. MT7-93 and MT7-92 were drilled by Doyon 25 so their setup is a bit different, but yes there are those TOTCO logs available. The note on MT7-93 unloading is from wellbore instability. On occasion we experience wellbore instability in the Seabee formations while drilling our surface section. This instability results in large cuttings and cavings that get brought to surface and can cause issues with some of our surface equipment packing off from the increase in cuttings volumes at surface. There is no gas associated with these events. Matt Nagel Drilling Engineer ConocoPhillips Alaska Office: 907-263-4747 Cell: 281-615-3922 Matt.B.Nagel@ConocoPhillips.com From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Monday, July 1, 2024 1:45 PM To: Nagel, Matt B <Matt.B.Nagel@conocophillips.com> Cc: Lee, David L <David.L.Lee@conocophillips.com>; Conklin, Amy A <Amy.A.Conklin@conocophillips.com>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: RE: [EXTERNAL]GMTU MT7-89 (Permit 224-089) - Questions Thanks for the additional information, Matt. You are correct, the distance between the existing and proposed surface casing shoes will be about 600’. My previous range of 800’ – 1000’ was a rough guesstimate made before I received the proposed directional survey data for MT7-92. Thanks for the description of the gas monitoring system for drilling surface hole. Are the Total Gas Watch system gas measurements plots submitted to AOGCC? If not, are those recorded for nearby wells MT7-92 and MT7-93 available? Reviewing the daily operations summaries for adjacent wells, I have another question. Could you please clarify the “hole unloading” described in the following excerpt from the MT7-93 daily ops summary? Was any associated gas observed, recorded, or reported? Thanks for your help, Steve Davies AOGCC From: Nagel, Matt B <Matt.B.Nagel@conocophillips.com> Sent: Monday, July 1, 2024 12:58 PM To: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Cc: Lee, David L <David.L.Lee@conocophillips.com>; Conklin, Amy A <Amy.A.Conklin@conocophillips.com>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: RE: [EXTERNAL]GMTU MT7-89 (Permit 224-089) - Questions Hi Steve, Doyon 26 has NOV TOTCO’s Total Gas Watch system installed on our flowline and can monitor gas during surface hole drilling. This is plotted on a depth basis. For a close offset we drilled MT7-92 earlier this year and I’m getting ~600’ from surface shoe to surface shoe: I’ve attached the drilling reports from both MT7-92 and Rendezvous 2 surface sections. There has been no shallow gas on the MT7 pad as a whole and neither MT7-92 nor Rendezvous 2 well experienced shallow gas. Please let me know if you have any other questions. Thank you Matt Nagel Drilling Engineer ConocoPhillips Alaska Office: 907-263-4747 Cell: 281-615-3922 Matt.B.Nagel@ConocoPhillips.com From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Monday, July 1, 2024 11:40 AM To: Nagel, Matt B <Matt.B.Nagel@conocophillips.com> Cc: Lee, David L <David.L.Lee@conocophillips.com>; Conklin, Amy A <Amy.A.Conklin@conocophillips.com>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: [EXTERNAL]GMTU MT7-89 (Permit 224-089) - Questions Thanks Matt. 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. Are you the back up for Weifeng for this well? If so, will gas be monitored in the surface hole during drilling operations? If so, how? If so, will the gas measurements be recorded versus depth? If not, what measures will be in place should shallow gas or gas hydrates be encountered? At surface casing point, this well lie outside of the cluster of surface casing shoes drilled to date from this pad, and it will be roughly 800’ to 1000’ east of the surface casing point in the nearest well drilled to date. Has there been any indication of shallow gas or gas hydrates in any of the wells drilled from this pad or in the nearby Rendezvous 2 exploratory well? If so, please discuss in detail. Thanks again for your help, Steve Davies AOGCC From: Nagel, Matt B <Matt.B.Nagel@conocophillips.com> Sent: Monday, July 1, 2024 11:26 AM To: Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Cc: Lee, David L <David.L.Lee@conocophillips.com>; Conklin, Amy A <Amy.A.Conklin@conocophillips.com> Subject: RE: [EXTERNAL]RE: GMTU MT7-89: Proposed Directional Survey Hi Meredith Here is the text file of the directional path for MT7-89. Matt Nagel Drilling Engineer ConocoPhillips Alaska Office: 907-263-4747 Cell: 281-615-39 From: Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Sent: Monday, July 1, 2024 10:09 AM To: Conklin, Amy A <Amy.A.Conklin@conocophillips.com>; Taylor, Jenna <Jenna.L.Taylor@conocophillips.com> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: [EXTERNAL]RE: GMTU MT7-89: Proposed Directional Survey CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. Hi Amy and Jenna, I received Weifeng’s out of office reply, but they didn’t leave an alternate contact. Can you please suggest who I should contact to get an excel or text version of the proposed directional survey? Thanks, Meredith From: Guhl, Meredith D (OGC) Sent: Monday, July 1, 2024 7:24 AM To: Dai, Weifeng <Weifeng.Dai@conocophillips.com> Cc: Conklin, Amy A <Amy.A.Conklin@conocophillips.com>; Taylor, Jenna <Jenna.L.Taylor@conocophillips.com>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: GMTU MT7-89: Proposed Directional Survey Hi Weifeng, Please provide the proposed directional survey for GMTU MT7-89 in either excel or text format. Minimum data needed is MD, Inclination, Azimuth. Please always include the AOGCC geology department on permit submission emails: Andrew Dewhurst, Steve Davies, and me. Thank you, Meredith Meredith Guhl (she/her) Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl@alaska.gov Direct: (907) 793-1235 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 Meredith Guhl at 907-793-1235 or meredith.guhl@alaska.gov. From:Nagel, Matt B To:Davies, Stephen F (OGC) Cc:Lee, David L; Conklin, Amy A; Guhl, Meredith D (OGC); Dewhurst, Andrew D (OGC) Subject:RE: [EXTERNAL]GMTU MT7-89 (Permit 224-089) - Questions Date:Monday, July 1, 2024 2:51:46 PM Attachments:image001.png image002.png image003.png Hi Steve, No, those logs are not submitted to the AOGCC. MT7-93 and MT7-92 were drilled by Doyon 25 so their setup is a bit different, but yes there are those TOTCO logs available. The note on MT7-93 unloading is from wellbore instability. On occasion we experience wellbore instability in the Seabee formations while drilling our surface section. This instability results in large cuttings and cavings that get brought to surface and can cause issues with some of our surface equipment packing off from the increase in cuttings volumes at surface. There is no gas associated with these events. Matt Nagel Drilling Engineer ConocoPhillips Alaska Office: 907-263-4747 Cell: 281-615-3922 Matt.B.Nagel@ConocoPhillips.com From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Monday, July 1, 2024 1:45 PM To: Nagel, Matt B <Matt.B.Nagel@conocophillips.com> Cc: Lee, David L <David.L.Lee@conocophillips.com>; Conklin, Amy A <Amy.A.Conklin@conocophillips.com>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: RE: [EXTERNAL]GMTU MT7-89 (Permit 224-089) - Questions Thanks for the additional information, Matt. You are correct, the distance between the existing and proposed surface casing shoes will be about 600’. My previous range of 800’ – 1000’ was a rough guesstimate made before I received the proposed directional survey data for MT7-92. Thanks for the description of the gas monitoring system for drilling surface hole. Are the Total Gas Watch system gas measurements plots submitted to AOGCC? If not, are those recorded for nearby wells MT7-92 and MT7-93 available? Reviewing the daily operations summaries for adjacent wells, I have another question. Could you please clarify the “hole unloading” described in the following excerpt from the MT7-93 daily ops summary? Was any associated gas observed, recorded, or reported? Thanks for your help, Steve Davies AOGCC 89 SFD From: Nagel, Matt B <Matt.B.Nagel@conocophillips.com> Sent: Monday, July 1, 2024 12:58 PM To: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Cc: Lee, David L <David.L.Lee@conocophillips.com>; Conklin, Amy A <Amy.A.Conklin@conocophillips.com>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: RE: [EXTERNAL]GMTU MT7-89 (Permit 224-089) - Questions Hi Steve, Doyon 26 has NOV TOTCO’s Total Gas Watch system installed on our flowline and can monitor gas during surface hole drilling. This is plotted on a depth basis. For a close offset we drilled MT7-92 earlier this year and I’m getting ~600’ from surface shoe to surface shoe: 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. I’ve attached the drilling reports from both MT7-92 and Rendezvous 2 surface sections. There has been no shallow gas on the MT7 pad as a whole and neither MT7-92 nor Rendezvous 2 well experienced shallow gas. Please let me know if you have any other questions. Thank you Matt Nagel Drilling Engineer ConocoPhillips Alaska Office: 907-263-4747 Cell: 281-615-3922 Matt.B.Nagel@ConocoPhillips.com From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Monday, July 1, 2024 11:40 AM To: Nagel, Matt B <Matt.B.Nagel@conocophillips.com> Cc: Lee, David L <David.L.Lee@conocophillips.com>; Conklin, Amy A <Amy.A.Conklin@conocophillips.com>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: [EXTERNAL]GMTU MT7-89 (Permit 224-089) - Questions Thanks Matt. Are you the back up for Weifeng for this well? If so, will gas be monitored in the surface hole during drilling operations? If so, how? If so, will the gas measurements be recorded versus depth? If not, what measures will be in place should shallow gas or gas hydrates be encountered? At surface casing point, this well lie outside of the cluster of surface casing shoes drilled to date from this pad, and it will be roughly 800’ to 1000’ east of the surface casing point in the nearest well drilled to date. Has there been any indication of shallow gas or gas hydrates in any of the wells drilled from this pad or in the nearby Rendezvous 2 exploratory well? If so, please discuss in detail. Thanks again for your help, Steve Davies AOGCC From: Nagel, Matt B <Matt.B.Nagel@conocophillips.com> Sent: Monday, July 1, 2024 11:26 AM To: Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Cc: Lee, David L <David.L.Lee@conocophillips.com>; Conklin, Amy A <Amy.A.Conklin@conocophillips.com> Subject: RE: [EXTERNAL]RE: GMTU MT7-89: Proposed Directional Survey Hi Meredith Here is the text file of the directional path for MT7-89. Matt Nagel Drilling Engineer ConocoPhillips Alaska Office: 907-263-4747 Cell: 281-615-39 From: Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Sent: Monday, July 1, 2024 10:09 AM To: Conklin, Amy A <Amy.A.Conklin@conocophillips.com>; Taylor, Jenna <Jenna.L.Taylor@conocophillips.com> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: [EXTERNAL]RE: GMTU MT7-89: Proposed Directional Survey CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. Hi Amy and Jenna, I received Weifeng’s out of office reply, but they didn’t leave an alternate contact. Can you please suggest who I should contact to get an excel or text version of the proposed directional survey? Thanks, Meredith From: Guhl, Meredith D (OGC) Sent: Monday, July 1, 2024 7:24 AM To: Dai, Weifeng <Weifeng.Dai@conocophillips.com> Cc: Conklin, Amy A <Amy.A.Conklin@conocophillips.com>; Taylor, Jenna <Jenna.L.Taylor@conocophillips.com>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: GMTU MT7-89: Proposed Directional Survey Hi Weifeng, Please provide the proposed directional survey for GMTU MT7-89 in either excel or text format. Minimum data needed is MD, Inclination, Azimuth. Please always include the AOGCC geology department on permit submission emails: Andrew Dewhurst, Steve Davies, and me. Thank you, Meredith Meredith Guhl (she/her) Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl@alaska.gov Direct: (907) 793-1235 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 Meredith Guhl at 907-793-1235 or meredith.guhl@alaska.gov. Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. 224-089 Greater Moose's Tooth GMTU MT7-89 Rendezvous Oil WELL PERMIT CHECKLISTCompanyConocoPhillips Alaska, Inc.Well Name:GMTU MT7-89Initial Class/TypeDEV / PENDGeoArea890Unit10750On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2240890GRTR MOOSES TOOTH, RENDEZV OIL - 282200NA1Permit fee attachedYesSurface Location lies within AA098885; Top Productive Interval lies in AA081781;2Lease number appropriateYesPortion of Productive Interval lies in AA081800; TD lies in AA098885.3Unique well name and numberYesGRTR MOOSES TOOTH, RENDEZV OIL - 282200 - governed by CO 7934Well located in a defined poolYes5Well located proper distance from drilling unit boundaryNA6Well located proper distance from other wellsYes7Sufficient acreage available in drilling unitYes8If deviated, is wellbore plat includedYes9Operator only affected partyYes10Operator has appropriate bond in forceYes11Permit can be issued without conservation orderYes12Permit can be issued without administrative approvalYes13Can permit be approved before 15-day waitNA14Well located within area and strata authorized by Injection Order # (put IO# in comments) (For servNA15All wells within 1/4 mile area of review identified (For service well only)NA16Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes80' conductor18Conductor string providedYesSC set at 4167' MD19Surface casing protects all known USDWsYes64% excess planned20CMT vol adequate to circulate on conductor & surf csgNo21CMT vol adequate to tie-in long string to surf csgNouncemented frac sleeves and swelll packers22CMT will cover all known productive horizonsYes23Casing designs adequate for C, T, B & permafrostYes24Adequate tankage or reserve pitNA25If a re-drill, has a 10-403 for abandonment been approvedYes26Adequate wellbore separation proposedYesDiverter waiver granted per 20 AAC 25.035(h)27If diverter required, does it meet regulationsYesMax reservoir pressure is 3840 psig(8.8 ppg EMW); will drill w/ 8.5-12.0 ppg EMW28Drilling fluid program schematic & equip list adequateYes29BOPEs, do they meet regulationYesMPSP is 3009 psig; will test BOPs to 3500 psig30BOPE press rating appropriate; test to (put psig in comments)Yes31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownYes33Is presence of H2S gas probableNA34Mechanical condition of wells within AOR verified (For service well only)YesH2S not expected based on nearby wells. Rig has sensors and alarms.35Permit can be issued w/o hydrogen sulfide measuresYesExpected pressure range is 0.431 to 0.61 psi/ft (8.3 to 11.8 ppg EMW). Operator's planned mud program36Data presented on potential overpressure zonesNAappears sufficient to control anticipated pressures and maintain wellbore stability.37Seismic analysis of shallow gas zonesNAMPD will be used to monitor and mitigate abnormal pressures encountered.38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate7/1/2024ApprVTLDate7/3/2024ApprSFDDate7/1/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateNOTE: Pressure ranging from 8.4 to 9.4 expected surface to top of HRZ shale. Pressure in HRZ to Alpine D jumps to 11.4 to 11.8 ppg. Alpine reservoir expected to be 8.8 ppg. See p. 15.
