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224-102
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: Convert Prod to Inj 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 Rendezvous Rendezvous 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 18138' 8489' 17671' 8467' 2900 N/A N/A Casing Collapse Structural Conductor Surface 4190 / 3980 Intermediate 9860 / 6560 Production 8947 Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Baker Seal Assembly 12909 - 12911 / 8324 - 8325 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:Dana Glessner Contact Email: glessd@conocophillips.com Contact Phone: 907-265-6478 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 8/1/2025 4 1/2" no SSSV Perforation Depth MD (ft): 10855' / 12940' 13459 - 17653 4798 8380 - 8466 4-1/2" 20" 13-3/8" x 13-5/8" 80 9-7/8" x 7-5/8"12888 3750 135' 3079' 7512' / 8332' 135' 3805' 8467' 17671' L-80 TVD Burst 12916 10690 MD 9090 / 7900 6540 / 6420 ConocoPhillips Alaska Inc Length Size Proposed Pools: no SSSV Perforation Depth TVD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 AA098885, AA081799, AA081800, AA081780 224-102 PO Box 100360, Anchorage AK 99510 50-103-20891-01-00 Tubing Size: PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY Tubing Grade: Tubing MD (ft): GMTU MT7-83 Staff Production Engineer Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Perforate Repair Wepair Well Exploratory Stratigraphic Development Service BOP TestMechanical Integrity Test No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Dana Glessner Digitally signed by Dana Glessner Date: 2025.05.09 09:00:28 -08'00' 325-291 By Grace Christianson at 9:37 am, May 09, 2025 DSR-5/9/25 X 10-404 CDW 06/11/2025 X A.Dewhurst 28JUL25 VTL 7/28/2025($8 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.07.28 15:51:08 -08'00'07/28/25 RBDMS JSB 073125 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 9 May 2025 Commissioners Alaska Oil & Gas Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Commissioners Chmielowski & Wilson, Enclosed please find the 10-403 Application for Sundry Approval for ConocoPhillips Alaska, Inc. well GMTU MT7-83 (PTD 224-102) to convert the well from Development – Oil to Service - WAG. GMTU MT7-83 was originally permitted as an injector but planned to preproduce for greater than 30 days. The well was first placed on production post drilling and completion on 11/14/2024 and is planned to be converted to injection in 2025. This sundry approval is needed to convert the well from a producer back to its original purpose, an injection well. Please contact me at 265-6478 if you have any questions. Sincerely, Dana Glessner Staff Production Engineer ConocoPhillips Alaska, Inc. .- .- .- 2 07 715(80 7 15(80 070707 0707 0707 07$07073%07 07$07 0707 07 3 + 0 7 3 % 07 07 07$07 07 07 07 07 07 07 07 $$ $$ $$ $65& $$ $$ $65& $$ k 07 37'0DS /HJHQG 2 3DG 2SHQ,QWHUYDO :HOO7UDMHFWRU\ 4XDUWHU0LOH5DGLXV ([LVWLQJ:HOO7UDMHFWRU\ .-3 $:HOO 5HQGH]YRXV3$ 7RZQVKLS 5DQJH $'15 6HFWLRQV $'15 .XXNSLN6XUI$65&6XEVXUI &3$, 3DWK 6 ?$1&?/RQJWHUP?$.*,6?:16?8VHUV?EPMDFRE?0DVWHU3URMHFW?0DVWHU37'DSU['HIDXOW*HRGDWDEDVH 6 ?$1&?/RQJWHUP?$.*,6?:16?'0?*07B:HOOV?07?07 ?07 B37'B0DS?07 B37'B0DSJGE 0LOHV Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag:MT7-83 11/3/2024 oberr Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Prep for Flowback MT7-83 11/13/2024 boehmbh Casing Strings Csg Des OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD) (ftKB)Wt/Len (lb/ft) Grade Top Thread Conductor 20 19.12 54.5 134.5 134.5 94.00 Welded Surface 13 5/8 12.38 54.8 3,804.9 3,079.3 88.00 L80-IC Hydril 563 Intermediate #1 Casing 9 7/8 8.63 52.4 10,854.9 7,512.0 62.80 L80 Hydril 563 Intermediate #2 Liner 7 5/8 6.77 10,675.4 12,940.0 8,331.6 33.70 L-80 TSH 523 Lower Completion Liner 4 1/2 3.96 12,873.3 17,671.0 8,466.5 12.60 P110S H563 Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 49.9 Set Depth (ftK 12,916.2 Set Depth (TV 8,326.2 String Max Nomin 41/2 Tubing Description Tubing – Completion Upper Wt (lb/ft) 12.60 Grade L-80 Top Connection Hyd563 ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB)Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 49.9 49.9 0.00 Hanger 13.625 FMC 4-1/2" Tubing Hanger Hydril HYD 563 HBPV W/5" Acme lift threads Min ID 3.90" FMC TC-1A-E MS 3.900 2,082.8 1,945.6 41.24 Nipple - DB, XN, DS, D 4.500 NIPPLE,LANDING,4 1/2","X",3.813" HES X Nipple 3.813 3,741.9 3,038.0 49.23 Mandrel 4.500 4-1/2" CAMCO KBG4-5 GLM BEK Latch w/ DCK-2 SOV (pinned 2000 IA to tubing shear) Camco KBG4-5 3.865 8,417.0 6,085.4 49.29 Mandrel 4.500 4-1/2"x1" CAMCO KBG4-5 GLM BK-2 Latch w/ DCK-2DMY Camco KBG4-5 3.865 11,994.5 8,060.9 66.43 Mandrel 4.500 4-1/2"x1" CAMCO KBG4-5 GLM BK-2 Latch w/ DCK-2DMY Camco KBG4-5 3.865 12,224.1 8,145.7 70.30 Gauge / Pump Sensor 4.500 Halliburton Opsis Mandrel w/ Downhole guage HES DHG 3.920 12,410.8 8,203.3 73.70 Nipple - DB, XN, DS, D 4.500 Landing nipple OSDB-6, 3.750" No-Go locator SLB DB-6 nipple 3.750 12,884.2 8,318.9 76.88 Locator 5.250 No-Go locator sub- 5.50" OD 30.17' from bottom Baker 3.880 12,909.0 8,324.5 76.87 Seal Assembly 4.730 Seal Sub Baker 3.880 12,910.1 8,324.8 76.87 Seal Assembly 5.640 Seal Sub Baker 3.870 12,911.1 8,325.0 76.87 Seal Assembly 4.500 Seal Sub Baker 3.910 12,912.2 8,325.2 76.87 Shoe - Mule 4.500 MULE SHOE, self-aligning HES self aligning 3.880 Mandrel Inserts : excludes pulled inserts Top (ftKB) Top (TVD) (ftKB) Top Incl (°) St ati on No Serv Valve Type Latch Type OD (in) TRO Run (psi)Run Date Com Make Model Port Size (in) 3,741.9 3,038.0 49.23 1 GAS LIFT OV BK 1 11/11/2024 Camco 0.406 8,417.0 6,085.4 49.29 2 GAS LIFT OV BK 1 11/12/2024 Camco 0.406 11,994.5 8,060.9 66.43 3 GAS LIFT OV BK 1 11/12/2024 Camco 0.406 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Item Des OD Nominal (in)Com Make Model Nominal ID (in) 12,873.3 8,316.4 76.89 PACKER 6.530 Liner Top Packer, HRDE SLZXP, w/11.15' x 5.75" SB 67' lap=12873 Baker SLZXP 5.750 13,047.2 8,353.1 81.36 Packer - Swell 4.500 REACTIVE PACKER,SWELL, 5.75", HYD563, P-110S 17 Reactive 3.958 13,108.4 8,360.6 84.01 Packer - Swell 4.500 REACTIVE PACKER,SWELL, 5.75", HYD563, P-110S 16 Reactive 3.958 13,459.7 8,380.1 87.11 Sleeve - Frac 4.500 AU Sleeve Pre-Open Nozzle Sleeve(Dissolvable seal) .2" 21 AU-nozzl esleeve 3.505 13,627.4 8,388.5 87.00 Sleeve - Frac 4.500 AU Sleeve Pre-Open Nozzle Sleeve(Dissolvable seal) .2" 20 AU-nozzl esleeve 3.505 13,711.7 8,392.8 87.04 Packer - Swell 4.500 REACTIVE PACKER,SWELL, 5.75", HYD563, P-110S 15 Reactive 3.958 13,814.5 8,398.2 86.99 Sleeve - Frac 4.500 AU Sleeve Pre-Open Nozzle Sleeve(Dissolvable seal) .2" 19 AU-nozzl esleeve 3.505 13,980.9 8,410.2 85.78 Sleeve - Frac 4.500 AU Sleeve Pre-Open Nozzle Sleeve(Dissolvable seal) .2" 18 AU-nozzl esleeve 3.505 14,062.4 8,415.3 87.24 Packer - Swell 4.500 REACTIVE PACKER,SWELL, 5.75", HYD563, P-110S 14 Reactive 3.958 14,372.8 8,424.1 89.01 Packer - Swell 4.500 REACTIVE PACKER,SWELL, 5.75", HYD563, P-110S 13 Reactive 3.958 14,472.7 8,427.7 87.01 Sleeve - Frac 4.500 AU Sleeve Pre-Open Nozzle Sleeve(Dissolvable seal) .2" 17 AU-nozzl esleeve 3.505 14,596.9 8,434.0 87.68 Sleeve - Frac 4.500 AU Sleeve Pre-Open Nozzle Sleeve(Dissolvable seal) .2" 16 AU-nozzl esleeve 3.505 14,723.1 8,438.1 87.51 Packer - Swell 4.500 REACTIVE PACKER,SWELL, 5.75", HYD563, P-110S 12 Reactive 3.958 14,784.6 8,441.0 87.18 Sleeve - Frac 4.500 AU Sleeve Pre-Open Nozzle Sleeve(Dissolvable seal) .2" 15 AU-nozzl esleeve 3.505 HORIZONTAL, MT7-83, 4/29/2025 1:51:21 PM Vertical schematic (actual) X O Lower Completion Liner; 12,873.3-17,671.0 Shoe; 17,666.2-17,671.0 Sleeve - Setting; 17,653.5-17,656.2 Sleeve - Frac; 17,558.9-17,560.8 Sleeve - Frac; 17,391.7-17,393.5 Sleeve - Frac; 16,894.2-16,896.0 Sleeve - Frac; 16,809.8-16,811.6 Sleeve - Frac; 16,704.8-16,706.7 Sleeve - Frac; 16,620.9-16,622.8 Sleeve - Frac; 16,289.7-16,291.5 Sleeve - Frac; 16,163.5-16,165.3 Sleeve - Frac; 15,876.2-15,878.0 Sleeve - Frac; 15,864.4-15,866.3 Sleeve - Frac; 15,449.6-15,451.5 Sleeve - Frac; 15,264.1-15,266.0 Sleeve - Frac; 15,137.9-15,139.8 Sleeve - Frac; 14,869.4-14,871.3 Sleeve - Frac; 14,784.6-14,786.5 Sleeve - Frac; 14,596.9-14,598.7 Sleeve - Frac; 14,472.7-14,474.5 Sleeve - Frac; 13,980.9-13,982.7 Sleeve - Frac; 13,814.5-13,816.4 Sleeve - Frac; 13,627.4-13,629.2 Sleeve - Frac; 13,459.7-13,461.5 Sub - Shear Out - SOS; 13,045.4-13,047.2 Intermediate #2 Liner; 10,675.4-12,940.0 Shoe; 12,936.8-12,940.0 Shoe - Mule; 12,912.2 Seal Assembly; 12,911.1 Seal Assembly; 12,910.1 Seal Assembly; 12,909.0 Seal Bore Extension; 12,895.7-12,916.3 Hanger; 12,889.9-12,895.7 Locator; 12,884.2 PACKER; 12,873.3-12,889.9 Collar - Landing; 12,778.5-12,779.5 Intermediate String 2 Cement; 12,013.0 ftKB Gauge / Pump Sensor; 12,224.0 Mandrel; 11,994.5 Intermediate #1 Casing; 52.4-10,854.9 Float Shoe; 10,850.8-10,854.9 Collar - Float; 10,765.3-10,767.9 Liner; 10,693.9-10,694.8 Liner; 10,685.4-10,693.9 Hanger; 10,681.1-10,685.4 PACKER; 10,675.4-10,681.1 Intermediate String 1 Cement; 7,351.0 ftKB Mandrel; 8,417.0 Annular Fluid - Brine; 1,207.0-12,693.0; 10/31/2024 Annular Fluid - Mud; 1,207.0-9,354.0; 9/23/2024 Surface; 54.8-3,804.9 Shoe - Float; 3,802.0-3,804.9 Mandrel; 3,741.9 Nipple - DB, XN, DS, D; 2,082.8 Surface String Cement; 54.8 ftKB Annular Fluid - Diesel; 54.4-1,207.0; 11/2/2024 Annular Fluid - Diesel; 54.4-1,207.0; 9/23/2024 XO Enlarging; 187.0-227.8 Conductor; 54.5-134.5 Conductor String Cement; 58.5 ftKB Casing Hanger; 52.4-53.4 Hanger; 49.9 WNS PROD KB-Grd (ft) 54.40 RR Date 11/3/2024 Other Elevatio MT7-83 ... TD Act Btm (ftKB) 18,138.0 Well Attributes Field Name RENDE Wellbore API/UWI 501032089101 Wellbore Status PROD Max Angle & MD Incl (°) 91.43 MD (ftKB) 16,599.84 WELLNAME WELLBOREMT7-83 Annotation End DateH2S (ppm) DateComment Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Item Des OD Nominal (in)Com Make Model Nominal ID (in) 14,869.4 8,445.1 87.53 Sleeve - Frac 4.500 AU Sleeve Pre-Open Nozzle Sleeve(Dissolvable seal) .2" 14 AU-nozzl esleeve 3.505 15,034.7 8,448.8 89.98 Packer - Swell 4.500 REACTIVE PACKER,SWELL, 5.75", HYD563, P-110S 11 Reactive 3.958 15,138.0 8,448.9 89.55 Sleeve - Frac 4.500 AU Sleeve Pre-Open Nozzle Sleeve(Dissolvable seal) .2" 13 AU-nozzl esleeve 3.505 15,264.1 8,451.6 89.21 Sleeve - Frac 4.500 AU Sleeve Pre-Open Nozzle Sleeve(Dissolvable seal) .2" 12 AU-nozzl esleeve 3.505 15,347.7 8,451.7 90.49 Packer - Swell 4.500 REACTIVE PACKER,SWELL, 5.75", HYD563, P-110S 10 Reactive 3.958 15,449.6 8,450.3 90.41 Sleeve - Frac 4.500 AU Sleeve Pre-Open Nozzle Sleeve(Dissolvable seal) .2" 11 AU-nozzl esleeve 3.505 15,574.7 8,449.8 90.51 Packer - Swell 4.500 REACTIVE PACKER,SWELL, 5.75", HYD563, P-110S 9 Reactive 3.958 15,719.8 8,448.4 90.56 Packer - Swell 4.500 REACTIVE PACKER,SWELL, 5.75", HYD563, P-110S 8 Reactive 3.958 15,864.5 8,447.0 90.43 Sleeve - Frac 4.500 AU Sleeve Pre-Open Nozzle Sleeve(Dissolvable seal) .2" 10 AU-nozzl esleeve 3.505 15,876.2 8,447.0 90.23 Sleeve - Frac 4.500 AU Sleeve Pre-Open Nozzle Sleeve(Dissolvable seal) .2" 9 AU-nozzl esleeve 3.505 15,960.4 8,447.6 89.00 Packer - Swell 4.500 REACTIVE PACKER,SWELL, 5.75", HYD563, P-110S 7 Reactive 3.958 16,102.4 8,450.0 89.08 Packer - Swell 4.500 REACTIVE PACKER,SWELL, 5.75", HYD563, P-110S 6 Reactive 3.958 16,163.5 8,451.0 89.00 Sleeve - Frac 4.500 AU Sleeve Pre-Open Nozzle Sleeve(Dissolvable seal) .2" 8 AU-nozzl esleeve 3.505 16,289.7 8,453.6 88.54 Sleeve - Frac 4.500 AU Sleeve Pre-Open Nozzle Sleeve(Dissolvable seal) .2" 7 AU-nozzl esleeve 3.505 16,374.4 8,455.4 89.68 Packer - Swell 4.500 REACTIVE PACKER,SWELL, 5.75", HYD563, P-110S 5 Reactive 3.958 16,517.8 8,454.3 90.58 Packer - Swell 4.500 REACTIVE PACKER,SWELL, 5.75", HYD563, P-110S 4 Reactive 3.958 16,621.0 8,452.3 91.36 Sleeve - Frac 4.500 AU Sleeve Pre-Open Nozzle Sleeve(Dissolvable seal) .2" 6 AU-nozzl esleeve 3.505 16,704.8 8,450.5 91.09 Sleeve - Frac 4.500 AU Sleeve Pre-Open Nozzle Sleeve(Dissolvable seal) .2" 5 AU-nozzl esleeve 3.505 16,748.1 8,449.8 90.94 Packer - Swell 4.500 REACTIVE PACKER,SWELL, 5.75", HYD563, P-110S 3 Reactive 3.958 16,809.8 8,448.9 90.78 Sleeve - Frac 4.500 AU Sleeve Pre-Open Nozzle Sleeve(Dissolvable seal) .2" 4 AU-nozzl esleeve 3.505 16,894.2 8,447.8 90.70 Sleeve - Frac 4.500 AU Sleeve Pre-Open Nozzle Sleeve(Dissolvable seal) .2" 3 AU-nozzl esleeve 3.505 16,978.6 8,446.8 90.69 Packer - Swell 4.500 REACTIVE PACKER,SWELL, 5.75", HYD563, L-80 2 Reactive 3.958 17,164.9 8,445.6 89.21 Packer - Swell 4.500 REACTIVE PACKER,SWELL, 5.75", HYD563, L-80 1 Reactive 3.958 17,391.7 8,454.4 87.48 Sleeve - Frac 4.500 AU Sleeve Pre-Open Nozzle Sleeve(Dissolvable seal) .2" 2 AU-nozzl esleeve 3.505 17,558.9 8,461.7 87.49 Sleeve - Frac 4.500 AU Sleeve Pre-Open Nozzle Sleeve(Dissolvable seal) .2" 1 AU-nozzl esleeve 3.505 17,653.5 8,465.8 87.72 Sleeve - Setting 5.610 Baker WIV Baker WIV 0.875 Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB)Des Com Pump Start Date 58.5 134.5 58.5 134.5 Conductor String Cement 4/14/2024 HORIZONTAL, MT7-83, 4/29/2025 1:51:21 PM Vertical schematic (actual) X O Lower Completion Liner; 12,873.3-17,671.0 Shoe; 17,666.2-17,671.0 Sleeve - Setting; 17,653.5-17,656.2 Sleeve - Frac; 17,558.9-17,560.8 Sleeve - Frac; 17,391.7-17,393.5 Sleeve - Frac; 16,894.2-16,896.0 Sleeve - Frac; 16,809.8-16,811.6 Sleeve - Frac; 16,704.8-16,706.7 Sleeve - Frac; 16,620.9-16,622.8 Sleeve - Frac; 16,289.7-16,291.5 Sleeve - Frac; 16,163.5-16,165.3 Sleeve - Frac; 15,876.2-15,878.0 Sleeve - Frac; 15,864.4-15,866.3 Sleeve - Frac; 15,449.6-15,451.5 Sleeve - Frac; 15,264.1-15,266.0 Sleeve - Frac; 15,137.9-15,139.8 Sleeve - Frac; 14,869.4-14,871.3 Sleeve - Frac; 14,784.6-14,786.5 Sleeve - Frac; 14,596.9-14,598.7 Sleeve - Frac; 14,472.7-14,474.5 Sleeve - Frac; 13,980.9-13,982.7 Sleeve - Frac; 13,814.5-13,816.4 Sleeve - Frac; 13,627.4-13,629.2 Sleeve - Frac; 13,459.7-13,461.5 Sub - Shear Out - SOS; 13,045.4-13,047.2 Intermediate #2 Liner; 10,675.4-12,940.0 Shoe; 12,936.8-12,940.0 Shoe - Mule; 12,912.2 Seal Assembly; 12,911.1 Seal Assembly; 12,910.1 Seal Assembly; 12,909.0 Seal Bore Extension; 12,895.7-12,916.3 Hanger; 12,889.9-12,895.7 Locator; 12,884.2 PACKER; 12,873.3-12,889.9 Collar - Landing; 12,778.5-12,779.5 Intermediate String 2 Cement; 12,013.0 ftKB Gauge / Pump Sensor; 12,224.0 Mandrel; 11,994.5 Intermediate #1 Casing; 52.4-10,854.9 Float Shoe; 10,850.8-10,854.9 Collar - Float; 10,765.3-10,767.9 Liner; 10,693.9-10,694.8 Liner; 10,685.4-10,693.9 Hanger; 10,681.1-10,685.4 PACKER; 10,675.4-10,681.1 Intermediate String 1 Cement; 7,351.0 ftKB Mandrel; 8,417.0 Annular Fluid - Brine; 1,207.0-12,693.0; 10/31/2024 Annular Fluid - Mud; 1,207.0-9,354.0; 9/23/2024 Surface; 54.8-3,804.9 Shoe - Float; 3,802.0-3,804.9 Mandrel; 3,741.9 Nipple - DB, XN, DS, D; 2,082.8 Surface String Cement; 54.8 ftKB Annular Fluid - Diesel; 54.4-1,207.0; 11/2/2024 Annular Fluid - Diesel; 54.4-1,207.0; 9/23/2024 XO Enlarging; 187.0-227.8 Conductor; 54.5-134.5 Conductor String Cement; 58.5 ftKB Casing Hanger; 52.4-53.4 Hanger; 49.9 WNS PROD MT7-83 ... WELLNAME WELLBOREMT7-83 Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB)Des Com Pump Start Date 54.8 3,804.9 54.8 3,079.3 Surface String Cement Perform surface cement job as per SLBG, pump 105 BBLS 10.9 PPG mud push @ 5 BPM while reciprocating, P/U 320K S/O 260K Drop bottom wiper plug and follow with 393 BBLS 11.0 PPG DeepCRETE Lead Cement, pump at average 5.4 BPM Follow with 66 BBLS 15.8 PPG G blend tail cement at 3.9 BPM Drop top wiper plug and chase with 20 BBLS water @ 5.7 BPM from cement unit Land hanger while mud push exiting casing shoe, pick up and reciprocate after interface clears shoe track Displace 528 BBLS 11 PPG Klashield with rig pumps ICP at 7 BPM 254 PSI, 7 BPM 664 PSI FCP Stop reciprocating casing at 325 BBLS into chase Bump plug at 528 BBLS 4542 STKS and build pressure to 1470 PSI and held for 5 minutes. Bleed pressure off and check floats, floats holding. Note: Lead cement wet at 4:26 AM, Tail cement wet @ 5:52 AM Note: Landed hanger 2850 STKS into displacement, CIP @ 07:45 HRS Note: Full returns during job, spacer back at 73 BBLS into chase, cement/interface back to surface at 325 BBLS pumped, good cement back to surface at 391 BBLS into chase, get back 137 BBLS good 15.8 PPG cement 9/13/2024 7,351.0 10,854.9 5,390.7 7,512.0 Intermediate String 1 Cement Perform 9 7/8" INT 1 cement job as per SLBG, pump 60 BBLS 12.5 PPG spacer, pump 134.1 BBLS 13 PPG class G cement, pump 107 BBLS 15.8 PPG class G tail cement, displace with 763.7 BBLS 10 PPG VersaClean NAF mud with rig pumps ICP at 4.5 BPM 152 PSI, 2.4 BPM 1305 PSI FCP Leave casing landed in well head See first plug land at 521 BBLS 4394 STKS, PSI up from 411 to 625 Bump plug at 763.7 BBLS 6434 STKS and build pressure from 1305 to 1850 PSI and held for 5 minutes. Bleed pressure off and check floats, floats not holding, pressure up to 1500 PSI hold for 25 min, bleed down to 500 PSI, wait on tail cement to reach 500 PSI compressive strength Note: Lead cement wet at 03:33 HRS, Tail cement wet at 04:15 HRS Note: CIP at 8:58 HRS Note: Full returns during job 9/21/2024 12,013.0 12,940.0 8,068.2 8,331.6 Intermediate String 2 Cement PJSM with all crew members for cement job. Flood surface lines with 3 bbl H2O. . Pressure test lines to 3500 psi. Pump 70 bbl 10 ppg KCL spacer at 2 BPM, 410 psi. Drop bottom dart. Cement wet at 14:10 hrs Pump 76 bbl 15.8# cement at 2 bpm, 626 to 114 psi. Drop top dart. Pump 10 bbl H2O at 2 bpm, 62 psi. Chase with 11 ppg VersaClean at 2 BPM 763 strokes into displacement drop BOZO plug, flag did not flip indicating that BOZO didn't drop. Bottom dart latched bottom LWP at 1516 strokes 351 psi. Continue displacing cement at 2 bpm 220 psi Top dart latch top LWP at 2223 strokes and shear at 1981 psi. Bottom LWP at landing collar at 2298 stokes and burst at 2058 psi. After Bottom LWP shear pump pressure increased to 880 to 900 PSI and partial to full losses are noted. Reduce pump rate to 1 bpm, and continue pumping at increased pressure. release surface back pressure. Attempt to rotate at 2350 stokes and unto rotate. 2410 strokes begin working pipe. Continue pumping and top LWP bump on landing collar at 3019 strokes with 1230 psi continue pumping until 1730 psi and hold pressure for 5 minutes. 79 bbls total losses during cement job. 10/10/2024 HORIZONTAL, MT7-83, 4/29/2025 1:51:21 PM Vertical schematic (actual) X O Lower Completion Liner; 12,873.3-17,671.0 Shoe; 17,666.2-17,671.0 Sleeve - Setting; 17,653.5-17,656.2 Sleeve - Frac; 17,558.9-17,560.8 Sleeve - Frac; 17,391.7-17,393.5 Sleeve - Frac; 16,894.2-16,896.0 Sleeve - Frac; 16,809.8-16,811.6 Sleeve - Frac; 16,704.8-16,706.7 Sleeve - Frac; 16,620.9-16,622.8 Sleeve - Frac; 16,289.7-16,291.5 Sleeve - Frac; 16,163.5-16,165.3 Sleeve - Frac; 15,876.2-15,878.0 Sleeve - Frac; 15,864.4-15,866.3 Sleeve - Frac; 15,449.6-15,451.5 Sleeve - Frac; 15,264.1-15,266.0 Sleeve - Frac; 15,137.9-15,139.8 Sleeve - Frac; 14,869.4-14,871.3 Sleeve - Frac; 14,784.6-14,786.5 Sleeve - Frac; 14,596.9-14,598.7 Sleeve - Frac; 14,472.7-14,474.5 Sleeve - Frac; 13,980.9-13,982.7 Sleeve - Frac; 13,814.5-13,816.4 Sleeve - Frac; 13,627.4-13,629.2 Sleeve - Frac; 13,459.7-13,461.5 Sub - Shear Out - SOS; 13,045.4-13,047.2 Intermediate #2 Liner; 10,675.4-12,940.0 Shoe; 12,936.8-12,940.0 Shoe - Mule; 12,912.2 Seal Assembly; 12,911.1 Seal Assembly; 12,910.1 Seal Assembly; 12,909.0 Seal Bore Extension; 12,895.7-12,916.3 Hanger; 12,889.9-12,895.7 Locator; 12,884.2 PACKER; 12,873.3-12,889.9 Collar - Landing; 12,778.5-12,779.5 Intermediate String 2 Cement; 12,013.0 ftKB Gauge / Pump Sensor; 12,224.0 Mandrel; 11,994.5 Intermediate #1 Casing; 52.4-10,854.9 Float Shoe; 10,850.8-10,854.9 Collar - Float; 10,765.3-10,767.9 Liner; 10,693.9-10,694.8 Liner; 10,685.4-10,693.9 Hanger; 10,681.1-10,685.4 PACKER; 10,675.4-10,681.1 Intermediate String 1 Cement; 7,351.0 ftKB Mandrel; 8,417.0 Annular Fluid - Brine; 1,207.0-12,693.0; 10/31/2024 Annular Fluid - Mud; 1,207.0-9,354.0; 9/23/2024 Surface; 54.8-3,804.9 Shoe - Float; 3,802.0-3,804.9 Mandrel; 3,741.9 Nipple - DB, XN, DS, D; 2,082.8 Surface String Cement; 54.8 ftKB Annular Fluid - Diesel; 54.4-1,207.0; 11/2/2024 Annular Fluid - Diesel; 54.4-1,207.0; 9/23/2024 XO Enlarging; 187.0-227.8 Conductor; 54.5-134.5 Conductor String Cement; 58.5 ftKB Casing Hanger; 52.4-53.4 Hanger; 49.9 WNS PROD MT7-83 ... WELLNAME WELLBOREMT7-83 Date Note Category MT7-83 Well Notes 11/13/2024 SLICK LINE PULLED FLAT BOTTOM CATCHER @ 12,410' SLM; OBTAIN SBHPS @ 12,389' RKB (MAX PSI: 3684, MAX TEMP: 188°). READY FOR FLOWBACK. 11/12/2024 SLICK LINE FMC OBTAINED PASSING PRESSURE TEST ON TREE. SET 2.77" FLAT BTM CATCHER @ 12,410' SLM. SET ST# 2 OV ( 13/32") @ 8417' RKB. PULLED ST#3 DMY @ 11,994' RKB. RESET OV ( 13/32") @ SAME. 11/11/2024 SLICK LINE SET BAITED CATCHER ON RCH @ 12,410 SLM. PULL SOV @ 3741' RKB SET 13/32 OV @ SAME. PULLED ST# 2 DMY @ 8417' RKB. PULLED CATCHER AND RHC @ 12,410' SLM. SWAB VLV AND MASTER STARTED LEAKING FROM STEM. PUMP GREASE AND PRESSURE TEST TO 2500# NO LEAKS. 11/3/2024 RIG RELEASE MT7-83 Well History MT7-83 Area of Review (AOR) An Area of Review plot shown below for MT7-83 Injector well path and offset wells. MT7-88 is the only well within the area of review. PTD API Well Name Status Top of Zone-of-Interest Isolating Stage TOC Method TOC Determination Losses Returns verified Zonal Isolation Comments 224-111 50103208930000 MT7-88 Online 14,375’ MD Alpine C Intermediate 1 Casing Cement And Intermediate 2Casing Cement 8,800’MD (INT1) 14,002’MD (INT2) Ultrasonic Log None (INT1) 64bbl (INT2) No Yes Lead: 90bbl 13.0ppg Class G Tail: 108bbl 15.8ppg Class G (INT1) 68bbls of 15.8ppg Class G (INT2) Lost returns during INT2 cement job. INT1 shoe set within confining zone with TOC behind INT1 casing. From:Loepp, Victoria T (OGC) To:Dewhurst, Andrew D (OGC) Cc:Davies, Stephen F (OGC); Wallace, Chris D (OGC) Subject:RE: GMTU MT7-83 Convert to Injector Sundry (325-291) Date:Monday, July 28, 2025 9:15:00 AM Attachments:RE EXTERNALAPPROVAL ConocoPhillips MT7-88 Intermediate 2 Cement and Proposed Plan Forward.msg Sundry_324-621_112524.pdf Andrew, My comments in red. Cement is not to regulation. We have granted variances for reasons outlined below. Let me know if we need to take a closer look at schematics. Victora Victoria Loepp Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Work: (907)793-1247 From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Wednesday, July 23, 2025 2:13 PM To: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: GMTU MT7-83 Convert to Injector Sundry (325-291) Victoria, Both the subject well and the one other well in the AOR have cement jobs that do not meet 25.030. We have CBLs for both. Subject well: GMTU MT7-83. Only 47' MD (11' TVD) of coverage over top of pool (Alpine D) See Sundry 324-621, a variance was granted with 22’ TVD of good cement above the intermediate 2 liner shoe and 130’ TVD of poor cement. Other factors to consider. The 500’ of poor cement would make it difficult to successfully squeeze. This is an Int 2 liner; The intermediate 1 casing was well cemented with containment interval at the top of the HRZ. A shoe test FIT on the int2 liner shoe was performed to 12.0. See schematic last page of sundry. AOR well: GMTU MT7-88: Only 183' MD (52' TVD) of coverage over top of pool (Alpine D) See attached schematic as part of the email. The int1 cement was good with the cement across the confining zone. The int2 cement was 183' MD (52' TVD). A shoe test FIT on the int2 liner shoe was performed to 12.0. Are they able to monitor pressures in the annulus behind the 7-5/8” liner? I wouldn’t think so. Only ~10’ (vs 250’ requirement) of isolation is small by any standard. Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 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: Replace Tubing 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?N/A Yes No 9. Property Designation (Lease Number): 10. Field: Rendezvous Oil Pool Rendezvous Oil Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 10756' 7486' 10756' 7486' None None Casing Collapse Conductor Surface Intermediate Intermediate 2 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: 907-263-4747 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 GMT MT7-83 None 8075' 7-5/8" None 12940'825' None 83312' N/A 2946' 10855' Perforation Depth MD (ft): 135' 3805' 7512'9-7/8" 20" 13-5/8" 74' Burst None MD 135' 3079' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 AA098885, AA081799, AA081800, AA081780 224-102 P.O. Box 100360, Anchorage, AK 99510 50-103-20891-01-00 ConocoPhillips Alaska, Inc Proposed Pools: AOGCC USE ONLY Tubing Grade: Tubing MD (ft): N/A Perforation Depth TVD (ft): Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Length Size Greater Mooses Tooth Matt Nagel Matt.B.Nagel@conocophillips.com Drilling Engineer Subsequent Form Required: Suspension Expiration Date: None TVD Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 324-621 By Grace Christianson at 9:36 am, Oct 31, 2024 VTL 11/25/2024 X X Initial BOP test to 5000 psig; subsequent BOP test to 4000 psig Annular preventer test to 2500 psig BOPE testing on a 21-day interval is approved with the attached conditions file with PTD 10-407X SFD 11/6/2024 SFD DSR-11/6/24($8 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.11.25 09:56:02 -09'00'11/25/24 RBDMS JSB 112624 ConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907-276-1215 October 29th, 2024 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Sundry for MT7-83 Operational Changes Dear Sir or Madam: ConocoPhillips Alaska, Inc hereby applies for Application for Sundry Approval to change the approved Permit to Drill for MT7-83 (PTD #: 224-102) an onshore MD from the intermediate 2 shoe. MT7-83 is a Alpine-C sand injection well. -- run and cemented to surface. The 12-- 9-8- x 9--D. A 7- c the intermediate 2 shoe. The production interval was comprised of a 6-1/2" horizontal hole that was geo-steered in the Alpine C-sand. The well will be completed as a injector with 4.5 placin 2 shoe. 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 10-403 2. A proposed drilling program 3. Current Wellbore Schematic 4. Proposed Wellbore Schematic 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: Matt Nagel, (907) 263-4747 & Matt.B.Nagel@conocophillips.com, Sincerely, cc: MT7-83 Well File / Jenna Taylor ATO 1560 David Lee ATO 1726 Chris Brillon ATO 1548 Matt Nagel Andy Mack Kuukpik Drilling Engineer Regarding variance request 1: Per Schlumberger's evaluation, very weak/poor, partial cement from 12,326' to 12,835' MD (509' MD) with good cement from 12,835' MD to top Alpine D reservoir at 12,882' MD (47' TVD). SFD 1.Well Name (Requirements of 20 AAC 25.005 (f)) ...................................................... 2 2.Location Summary (Requirements of 20 AAC 25.005(c)(2)) .................................... 2 Requirements of 20 AAC 25.050(b) ........................................................................................................ 2 3.Proposed Drilling Program (Requirements of 20 AAC 25.005 (c)(13)) ................. 3 4.Attachments ............................................................................................................. 3 Attachment 1 Curent Wellbore Schematic .............................................................................................. 3 Attachment 2 Proposed Abandonment Wellbore Schematic .................................................................. 3 1.Well Name (Requirements of 20 AAC 25.005 (f)) The well for which this application is submitted will be designated as MT7-83. 2.Location Summary (Requirements of 20 AAC 25.005(c)(2)) Location at Surface 1178' FSL, 2246' FWL, S32 T10N R2E, UM NAD27 Northings: 5915990 Eastings: 290329 RKB Elevation 54.6 Pad Elevation 100.7 Top of Productive Horizon (Heel) 2640' FNL, 324' FEL, S33 T10N R2E, UM NAD27 Northings:5917235 Eastings: 298351 Measured Depth, RKB: 12,641 Total Vertical Depth, RKB: 8,276 Total Vertical Depth, SS: 8,120 Total Depth (Toe) 1357' FSL, 2286' FEL, S3 T9N R2E, UM NAD27 Northings: 5910585 Eastings: 301507 Measured Depth, RKB: 20,009 Total Vertical Depth, RKB: 8,503 Total Vertical Depth, SS: 8,347 Requirements of 20 AAC 25.050(b) The Applicant is the only affected owner. 3.Proposed Drilling Program (Requirements of 20 AAC 25.005 (c)(13)) The proposed drilling program is listed below. Please refer to Completion Schematic. 1. Pick up and run in hole with 8-1/2 x 9- drilling BHA to drill intermediate 2. (LWD Program: GR/ RES) 2. Drill off kickoff plug and sidetrack wellbore. 3. Drill 8-1/2" x 9- hole to section TD with OBM. 4. Circulate wellbore clean and trip OOH. 5. Change upper ram to 7- 6. Pick up and run in hole with the 7-5/8 to section TD. 7. Circulate and condition mud in preparation for cementing. 8. Cement 7-5/8 . A variance to the cement top requirement is requested. Due to losses during the cement job Set liner top packer. Circulate excess cement from top of liner. POOH laying down drill pipe. Submit results to AOGCC as soon as possible. 9. Change out upper rams to 3-- 10. Pick up DP. Test BOPE to 250 psi low / 3,500 psi high. (24-48 hr. regulatory notice). 11. Pick up and RIH with 6-1/2 g assembly. (LWD Program: GR/Azimuthal RES, Neu/Den). 12. Chart casing pressure test to 3,500 psi for 30 minutes and record results. 13. Drill out and perform FIT to 13.5 ppg EMW. 14. Drill 6- horizontal hole to TD. 15. Circulate the hole clean, displace to vis brine, POOH. 16. Run 4- displace well to CI brine. POOH and laying down DP. 17. Run 4- the intermediate 2 shoe. DHG, GLMs and landing nipples. Locate and space out tubing. Terminate TEC wire and land tubing hanger. 18. Test tubing hanger seals from above to 2,500 psi for 15 mins. 19. Drop ball and rod. Pressure up to set production packer. 20. Pressure test tubing to 4,200 psi for 30 mins. Test IA to 3,500 psi for 30 mins. Shear SOV. 21. Install BPV, test same and tubing hanger seals from below to 2,500 psi. 22. Nipple down BOP, terminate TEC wire. 23. Install tubing head adaptor. Pressure test adaptor to 5,000 psi. 24. Install tree and test. 25. Pull BPV, freeze protect IA and tubing. 26. Secure well. Rig down and move out. 4.Attachments Attachment 1 Curent Wellbore Schematic Attachment 2 Proposed Abandonment Wellbore Schematic Per Schlumberger's evaluation: Very weak/poor, partial cement from 12,326' to 12,835' MD (509' MD); good cement from 12,835' MD to top Alpine D reservoir at 12,882' MD (47' TVD). SFD 20" 94 ppf H-40 Insulated Conductor 80 feet, cemented to surface MT7-83 As Drilled 10-22-24 ϭϬͬϮϮͬϮϬϮϰ 16" Surface Hole Surface Casing 13-3/8" 68# x 13-5/8" 88.2# L-80 Hyd563 Set at 3,805' MD / 3,079' TVD 8-½X 9-7/8" Intermediate 2 Hole Intermediate 2 Liner 7-5/8" 33.7# P110S HYD523 Shoe set @ 12,940' MD / 8,332' TVD 12-¼Intermediate 1 Hole Intermediate 1 Casing 9-5/8" 47# x 9-7/8" 62.8 L-80 HYD563 Set @ 10,855' MD / 7,512' TVD Top HRZ 10,948' MD / 7,7557' TVD 4-String Injector Schematic with Pilot Hole Planned INT1 TOC 7,351 MD / 5,390' TVD Top Kingak 12,308' MD / 8,330' TVD 8-½Intermediate Pilot Hole TD @ 12,491' MD / 8,426' TVD Top Sub Albian 93 7,851' MD / 5,717' TVD INT2 TOC 12,835' MD / 8,301' TVD Liner top at 10,675' MD / 7,428' TVD Top Kuparuk C 11,035' MD / 7,600' TVD Top Alpine D 12,240' MD / 8,293' TVD Top Alpine C 12,292' MD / 8,321' TVD Top HRZ 10,946' MD / 7,557' TVD Top Kuparuk C 11,031' MD / 7,599' TVD Top Alpine D 12,882' MD / 8,318' TVD Tubing / Liner Completion: 1) 4-½X Landing Nipple (3.813" ID) 2) 4-½x KBG 4-5 (3x) 3) HES Opsis Downhole Gauge 4) 4-½DB Landing Nipple (3.75" ID) 5) Baker Seal Assembly 4-½L-80/ P110S Hyd563 Liner w/ swell packers and AU sleeve MW: 8.8 Visc Brine 20" 94 ppf H-40 Insulated Conductor 80 feet, cemented to surface -Production Hole TD at 20,072' MD / 8,503' TVD Tubing 4-1/2" 12.6# L-80 Hyd563 MT7-83 Proposed y GLGL GLGL ϭϬͬϮϮͬϮϬϮϰ Baker Seal Assembly Baker SLVXP LH & Packer Downhole Gauge 16" Surface Hole Surface Casing 13-3/8" 68# x 13-5/8" 88.2# L-80 Hyd563 Set at 3,805' MD / 3,079' TVD 8-½X 9-7/8" Intermediate 2 Hole Intermediate 2 Liner 7-5/8" 33.7# P110S HYD523 Liner top at +/- 10,681' MD / 7,512' TVD Shoe set @ 12,940' MD / 8,332' TVD 12-¼Intermediate 1 Hole Intermediate 1 Casing 9-5/8" 47# x 9-7/8" 62.8 L-80 HYD563 Set @ 10,855' MD / 7,512' TVD Top HRZ 10,946' MD / 7,547' TVD 4-String Injector Schematic with Pilot Hole Planned INT1 TOC 7,351' MD / 5,390' TVD Top Alpine D 12,882' MD / 8,318' TVD 8-½Intermediate Pilot Hole TD @ 12,491' MD / 8,426' TVD t/s INT2 TOC 12,835' MD / 8,301' TVD From:Operations Engineer, Doyon 26 To:Loepp, Victoria T (OGC); Davies, Stephen F (OGC); Dewhurst, Andrew D (OGC) Cc:Hobbs, Greg S; Coates, David; WSC Rig Advisor; Drilling Supervisor, Doyon 26; Brillon, Chris L Subject:RE: [EXTERNAL]MT7-83 Update and Proposed Plan Forward APPROVED Date:Saturday, October 19, 2024 5:08:27 PM Attachments:image002.png image003.png Victoria, Thank you. We will get the 10-403 submitted. Thanks, WSC Operations Engineer – Doyon 26 Allen Eschete 26opseng@conocophillips.com 907.263.4552 (Office) From: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Sent: Saturday, October 19, 2024 4:53 PM To: Operations Engineer, Doyon 26 <Doyon26.OperationsEngineer@conocophillips.com>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Coates, David <David.Coates2@conocophillips.com>; WSC Rig Advisor <wscrigadvisor@conocophillips.com>; Drilling Supervisor, Doyon 26 <d26cm@conocophillips.com>; Brillon, Chris L <Chris.L.Brillon@conocophillips.com> Subject: [EXTERNAL]MT7-83 Update and Proposed Plan Forward APPROVED 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. Allen, I have reviewed the logs and interpretation submitted. Approval is granted to proceed as outlined in your plan forward including approval of the variances requested. Please submit a 10-403 change of approved program as soon as possible. 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. Victoria Victoria Loepp Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Work: (907)793-1247 From: Operations Engineer, Doyon 26 <Doyon26.OperationsEngineer@conocophillips.com> Sent: Saturday, October 19, 2024 2:02 PM To: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Coates, David <David.Coates2@conocophillips.com>; WSC Rig Advisor <wscrigadvisor@conocophillips.com>; Drilling Supervisor, Doyon 26 <d26cm@conocophillips.com>; Brillon, Chris L <Chris.L.Brillon@conocophillips.com> Subject: MT7-83 Update and Proposed Plan Forward Hello, We have completed the SonicScope logging run on drill pipe and have just finished performing the USIT and CBL logs on Eline for the intermediate 2 cement job. The SonicScope logs indicated no changes in the cement from the initial logs. Additionally, while we are still awaiting the field print and interpreted logs from Eline, the USIT and CBL logs appear to show cement in the same locations as the SonicScope logs with the same bond qualities. We propose proceeding with our contingency upper and lower completion design (attached below), which involves setting the lower completion packer at the midpoint of the well bonded cement and then stinging the upper completion into the lower with a seal bore. The production (injection liner) will also have two swell packers set near the intermediate liner shoe to provide increased standoff from injection pressure. As stated in our prior meeting, we are requesting a variance to the requirement to place our production liner top packer at a point fifty feet from the intermediate 2 liner shoe. We are also requesting a variance to the requirement of 250 feet TVD of cement coverage with the now confirmed placement of 152’ TVD cement coverage with the bottom 22’ TVD at the shoe having good bond and the 130’ above that poor bond. The sonic log evaluation is attached to this mail, field logs for the CBL and USIT will follow. Note that the lower portion of the USIT was impacted by heavy fluids in the wellbore and the CBL provided a better view of the bond in this section as deep as the tools would go. Given that the additional logging has taken longer than expected, our forecast indicates just enough time to set the lower completion before needing to test the BOPs. To be prudent, we plan to perform a full BOP test today to avoid having to do it with an open hole. We acknowledge that this is short notice and not within the required notification period but want to eliminate the risk of losses and the time of mitigation in the open hole section. After the BOP test, the plan forward is to drill out of the shoe, open 20’ of new hole section and perform a FIT to 12.0 ppg equivalent per our drilling program. Drilling would commence after successful passage of this test. Final logs, analyses and sundry applications (as needed) will follow on Monday. Thanks, WSC Operations Engineer – Doyon 26 Allen Eschete 26opseng@conocophillips.com 907.263.4552 (Office) T + 1 337.856-7201 1058 Baker Hughes Drive Broussard, LA 70518, USA Nov 11, 2024 AOGCC Attention: Natural Resources Technician 333 W. 7th Ave., Suite 100 Anchorage, Alaska 99501-3539 Subject: Final Log Distribution for ConocoPhillips Alaska, Inc. MT7-83 / MT7-83PH1 Greater Mooses Tooth API #: 50-103-20891-01/50-103-20891-00 Permit No: 224-101/ 224-102 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. MT7-83/ MT7-83PH1 are located in a federal oil and gas unit. Only with respect to the MT7-83/ MT7-83PH1 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 MT7-83 (PTD# 224-102): T39771 MT7-83PH1(PTD# 224-101):T39772 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.11.14 08:13:01 -09'00' MT7-83 MT7-83 (PTD# 224-102): T39771 MT7 83PH1(PTD# 224 101) T397 224-102 50-103-20891-01 / Originated: Delivered to:7-Nov-24 Alaska Oil & Gas Conservation Commiss 07Nov24-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 3S-03 50-103-20458-00-00 203-091 Kuparuk River WL IBC-CBL FINAL FIELD 10-Oct-24 2K-19A 50-103-20118-01-00 211-034 Kuparuk River WL Cutter FINAL FIELD 11-Oct-24 MT7-83 50-103-20891-01-00 224-102 Greater Mooses Tooth WL TTiX-USIT-CBL FINAL FIELD 19-Oct-24 1C-157 50-029-23754-00-00 223-038 Kuparuk River WL IBC-CBL FINAL FIELD 23-Oct-24 CD1-33A 50-103-20357-01-00 222-105 Colville River WL PERF FINAL FIELD 30-Oct-24 MT7-09 50-103-20837-00-00 222-011 Greater Mooses Tooth WL TTiX-Plug&Perf FINAL FIELD 1-Nov-24 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 T39755 T39756 T39757 T39758 T39759 T39760 MT7-83 50-103-20891-01-00 224-102 Greater Mooses Tooth WL TTiX-USIT-CBL FINAL FIELD 19-Oct-24 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.11.08 08:38:26 -09'00' t >>ED W/η^ Zs/ KZ Zη &/ >ED ^ Zs/ ^Z/Wd/KE >/s Z> ^Z/Wd/KE ddzW d >K'' K>KZWZ/Ed^ ͲĞůŝǀĞƌLJ3T-603 50-103-20887-00-00 224-074 KUPARUK RIVER MWD/LWD/DD VISION Service FINAL FIELD 4-Oct-24 1GMTU MT7-83 50-103-20891-01-00 224-102EATER MOOSES TOOMEMORY Top of Cement PROCESSED 20-Oct-24 1dƌĂŶƐŵŝƚƚĂůZĞĐĞŝƉƚͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺ yͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺWƌŝŶƚEĂŵĞ ^ŝŐŶĂƚƵƌĞ ĂƚĞWůĞĂƐĞƌĞƚƵƌŶǀŝĂĐŽƵƌŝĞƌŽƌƐŝŐŶͬƐĐĂŶĂŶĚĞŵĂŝůĂĐŽƉLJƚŽ^ĐŚůƵŵďĞƌŐĞƌ͘ďŚĂƚƚĂĐŚĂƌLJĂΛƐůď͘ĐŽŵ^>ƵĚŝƚŽƌͲdƌĂŶƐŵŝƚƚĂůZĞĐĞŝƉƚƐŝŐŶĂƚƵƌĞĐŽŶĨŝƌŵƐƚŚĂƚĂƉĂĐŬĂŐĞ;ďŽdž͕ĞŶǀĞůŽƉĞ͕ĞƚĐ͘ͿŚĂƐďĞĞŶƌĞĐĞŝǀĞĚĂŶĚƚŚĞĐŽŶƚĞŶƚƐŽĨƚŚĞƉĂĐŬĂŐĞŚĂǀĞďĞĞŶǀĞƌŝĨŝĞĚƚŽŵĂƚĐŚƚŚĞŵĞĚŝĂŶŽƚĞĚĂďŽǀĞ͘dŚĞƐƉĞĐŝĨŝĐĐŽŶƚĞŶƚŽĨƚŚĞƐĂŶĚͬŽƌŚĂƌĚĐŽƉLJƉƌŝŶƚƐŵĂLJŽƌŵĂLJŶŽƚŚĂǀĞďĞĞŶǀĞƌŝĨŝĞĚĨŽƌĐŽƌƌĞĐƚŶĞƐƐŽƌƋƵĂůŝƚLJůĞǀĞůĂƚƚŚŝƐƉŽŝŶƚ͘η^ĐŚůƵŵďĞƌŐĞƌͲWƌŝǀĂƚĞ224-074: T39712224-102: T39713Gavin GluyasDigitally signed by Gavin Gluyas Date: 2024.10.24 08:59:58 -08'00'GMTU MT7-8350-103-20891-01-00224-102EATER MOOSES TOOMEMORYTop of CementPROCESSED20-Oct-241224 074: T39712224-102: T39713 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 MT7-83 Conoco Phillips Alaska, Inc. Permit to Drill Number: 224-102 Surface Location: 1178' FSL, 2246' FWL, S32 T10N R2E, UM Bottomhole Location: 1357' FSL, 2286' FEL, S3 T9N 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 /Chmielowski Commissioner '$7('WKLV GD\RI$XJXVW 28 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.28 13:48:07 -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: 20,009 TVD: 8,503 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 8/22/2024 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 2994' to AA081781 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- 290329 y- 5915990 Zone- 4 100.7 to Same Pool: 4340' to MT7-91 16. Deviated wells: Kickoff depth: 10796 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 89 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 8-1/2" x 9-7/8"7-5/8" 33.70 L-80 Hyd523 1937 10646 7486 12583 8263 6-1/2" 4-1/2" 12.60 L-80 Hyd563 7576 12433 8228 20009 8503 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): NA TVD 80 3059 7486 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: Matt Nagel Chris Brillon Contact Email:matt.b.nagel@cop.com Wells Engineering Manager Contact Phone:907-263-4747 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 GMTU MT7-83 Greater Mooses Tooth Rendezvous Total Depth MD (ft): Total Depth TVD (ft): 59-52-180 Specifications 3848 Cement Quantity, c.f. or sacks Cement Volume MDSize Plugs (measured): (including stage data) 337sx 15.8 ppg STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 2997 2640' FNL, 324' FEL, S33 T10N R2E, UM 1357' FSL, 2286' FEL, S3 T9N R2E, UM 369446000, 93253400, 932535000, 932515000 P.O. Box 100360 Anchorage, Alaska, 99510-0360 ConocoPhillips Alaska Inc. 1178' FSL, 2246' FWL, S32 T10N R2E, UM AA098885, AA081799, AA081800, AA081780 1262,68, 5756, 2515, 5756 18. Casing Program: Top - Setting Depth - Bottom NA NA NA Conductor/Structural 2080 10756 7486 LengthCasing NA 80 Authorized Title: Authorized Signature: 10756 Production Liner 10756Intermediate Authorized Name: Commission Use Only See cover letter for other requirements. 372sx 13 ppg & 524sx 15.8 ppg9-5/8" / 9-7/8" 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft): GL / BF Elevation above MSL (ft): Perforation Depth MD (ft): 3727 Cement to surface with 10 yds 372713-3/8" / 13-5/8" 1131sx 11 ppg & 306sx 15.8 ppg Effect. Depth MD (ft): Effect. Depth TVD (ft): 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 2:46 pm, Jul 23, 2024 X SFD 8/12/20024 50-103-20891-01-00 Initial BOP test to 5000 psig; subsequent BOP test to 4000 psig Annular preventer test to 2500 psig BOPE testing on a 21-day interval is approved with the attached conditions Surface casing LOT and annular LOT to the AOGCC as soon as available VTL 8/27/2024 DSR-7/29/24 224-102 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.28 13:48:19 -08'00' 08/28/24 08/28/24 RBDMS JSB 082924 *07073+ 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 July 22, 2024 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Application for Permit to Drill MT7-83 Dear Sir or Madam: ConocoPhillips Alaska, Inc. hereby applies for a Permit to Drill an onshore Alpine C-Sand injector well from the MT7 drilling pad. The intended spud date for this well is 8/22/2024. It is intended that Doyon 26 be used to drill the well. MT7-83 will sidetrack below the intermediate 1 section shoe of MT7-83PH1 and drill an 8-1/2" x 9-7/8" intermediate 2 section that will be 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 injector with 4.5” liner with sleeves 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 Matt Nagel at 907-263-4747 (Matt.B.Nagel@conocophillips.com) or Greg Hobbs at 907-263-4794 (greg.s.hobbs@conocophillips.com). Sincerely, cc: MT7-83 Well File / Jenna Taylor ATO 1560 Dave Lee ATO 1552 Matt Nagel Chris Brillon ATO 1548 Drilling Engineer Andy Mack Kuukpik Corp Recommend approving requested variance from diverter waiver requirement. No evidence of shallow gas or hydrates in existing seismic or well data. SFD MT7-83 Saved: 22-Jul-24 MT7-83 Page 1 of 13 Printed: 22-Jul-24 MT7-83 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)) ............................................. 5 5. MASP Calculations ............................................................................................................................... 6 6. Procedure for Conducting Formation Integrity Tests (Requirements of 20 AAC 25.005 ©(5)) ....... 7 7. Casing and Cementing Program ......................................................................................................... 7 8. Drilling Fluid Program (Requirements of 20 AAC 25.005(c)(8)) ................................................................ 8 9. Abnormally Pressured Formation Information (Requirements of 20 AAC 25.005 (c)(9)) ....................... 9 10. Seismic Analysis (Requirements of 20 AAC 25.005 (c)(10)) ...................................................................... 9 11. Seabed Condition Analysis (Requirements of 20 AAC 25.005 (c)(11)) ..................................................... 9 12. Evidence of Bonding (Requirements of 20 AAC 25.005 (c)(12)) ............................................................... 9 13. Discussion of Mud and Cuttings Disposal and Annular Disposal ................................................... 9 (Requirements of 20 AAC 25.005 (c)(14)) ........................................................................................................... 9 14. Drilling Hazards Summary ................................................................................................................. 10 15. Proposed Completion Schematic ...................................................................................................... 12 16. Area of Review ................................................................................................................................... 13 MT7-83 Saved: 22-Jul-24 MT7-83 Page 2 of 13 Printed: 22-Jul-24 1. Well Name (Requirements of 20 AAC 25.005 (f)) The well for which this application is submitted will be designated as MT7-83 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) Location at Surface 1178' FSL, 2246' FWL, S32 T10N R2E, UM NAD27 Northings: 5915990 Eastings: 290329 RKB Elevation 54.6’ AMSL Pad Elevation 100.7’ AMSL Top of Productive Horizon (Heel) 2640' FNL, 324' FEL, S33 T10N R2E, UM NAD27 Northings:5917235 Eastings: 298351 Measured Depth, RKB:12,641’ Total Vertical Depth, RKB:8,276’ Total Vertical Depth, SS:8,120’ Total Depth (Toe) 1357' FSL, 2286' FEL, S3 T9N R2E, UM NAD27 Northings: 5910585 Eastings: 301507 Measured Depth, RKB:20,009’ Total Vertical Depth, RKB:8,503’ Total Vertical Depth, SS:8,347’ Please see attached well stick diagram for the current planned development of the pad. MT7-83 Saved: 22-Jul-24 MT7-83 Page 3 of 13 Printed: 22-Jul-24 Pad Layout Well Stick Diagram MT7-83 Saved: 22-Jul-24 MT7-83 Page 4 of 13 Printed: 22-Jul-24 MT7-83 Saved: 22-Jul-24 MT7-83 Page 5 of 13 Printed: 22-Jul-24 3. Proposed Drilling Program Transfer from MT7-83PH1 PTD to MT7-83 PTD 1. Pick up and run in hole with 8-1/2” x 9-7/8” drilling BHA to drill intermediate 2. (LWD Program: GR/ RES) 2. Drill off kickoff plug and sidetrack wellbore. 3. Drill 8-1/2" x 9-7/8” hole to section TD with OBM. 4. Circulate wellbore clean and trip OOH. 5. Change upper ram to 7-5/8” fix casing ram and test the same. 6. Pick up and run in hole with the 7-5/8” liner to section TD. 7. Circulate and condition mud in preparation for cementing. 8. 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. 9. Change out upper rams to 3-1/4” x 6-5/8” VBR. 10. Pick up DP. Test BOPE to 250 psi low / 3,500 psi high. (24-48 hr. regulatory notice). 11. Pick up and RIH with 6-1/2” drilling assembly. (LWD Program: GR/Azimuthal RES, Neu/Den). 12. Chart casing pressure test to 3,500 psi for 30 minutes and record results. 13. Drill out and perform FIT to 13.5 ppg EMW. 14. Drill 6-1/2” horizontal hole to TD. 15. Circulate the hole clean, displace to vis brine, POOH. 16. 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. 17. 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. 18. Test tubing hanger seals from above to 2,500 psi for 15 mins. 19. Drop ball and rod. Pressure up to set production packer. 20. Pressure test tubing to 4,200 psi for 30 mins. Test IA to 3,500 psi for 30 mins. Shear SOV. 21. Install BPV, test same and tubing hanger seals from below to 2,500 psi. 22. Nipple down BOP, terminate TEC wire. 23. Install tubing head adaptor. Pressure test adaptor to 5,000 psi. 24. Install tree and test. 25. Pull BPV, freeze protect IA and tubing. 26. 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. MT7-83 Saved: 22-Jul-24 MT7-83 Page 6 of 13 Printed: 22-Jul-24 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 3,797 / 3,059 14.5 1381 2001 9.625 / 9.875 10,796 / 7,486 16.5 3387 2913 7.625 12,583 / 8,263 12.5 3739 2997 4.5 20,009 / 8,503 12.5 3848 NA 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 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) = 1381 – (0.1 x 3051) = 1076 psi Drilling below 13.375” / 13.625” surface casing ASP = [(FG x 0.052) – 0.1] D = [(14.5 x 0.052) – 0.1] x 3059’ = 2001 psi OR ASP = FPP – (0.1 x D) = 3387 – (0.1 x 7486) = 2638 psi 2. Drilling below first 9.625” x 9.875” intermediate casing ASP = [(FG x 0.052) – 0.1] D = [(16.5 x 0.052) – 0.1] x 7486 = 5674 psi OR ASP = FPP – (0.1 x D) MT7-83 Saved: 22-Jul-24 MT7-83 Page 7 of 13 Printed: 22-Jul-24 = 3739– (0.1 x 8263’) = 2913 psi 3.Drilling below 7-5/8” intermediate 2 liner ASP = [(FG x 0.052) – 0.1] D = [(12.5 x 0.052) – 0.1] x 8263 = 4545 psi OR ASP = FPP – (0.1 x D) = 3848 – (0.1 x 8503) = 2997 psi (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 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 L-80 Hyd563 Cement to Surface 9.625 / 9.875” 12.25 47 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 13.375” x 13.625” Surface Casing run to 3,767’ MD /3,059’ TVD Cement Plan: Cement from 3,767’ MD to 3,267' (500’ of tail) with Deepcrete + Add's. @ 15.8 ppg, and from 3,267' to surface with 11.0 ppg DeepCrete. Assume 120% excess annular volume in permafrost and 50% excess below the permafrost (1001’ MD), zero excess in 20” conductor. Lead slurry from 3,134’ MD to surface with Arctic Lite Crete @ 11.0 ppg Total Volume = 2,172 ft3 => 1,131 sx of 11.0 ppg Deepcrete + Add's @ 1.92 ft 3 /sk Tail slurry from 3,767’ MD to 3,267’ MD with 15.8 ppg Deepcrete + Add's () 3848 – (0.1 x 8503) = 2997 psi MT7-83 Saved: 22-Jul-24 MT7-83 Page 8 of 13 Printed: 22-Jul-24 Total Volume = 355 ft3 => 306 sx of 15.8 ppg Class G + Adds @ 1.16 ft3/sk 9.625” x 9.875” Intermediate Casing run to 10,796’ MD / 7,486’ TVD Cement Plan: Primary cement job consists of 1500 ft 15.8 ppg tail slurry and top of 13.0 ppg lead slurry is designed to be at 7,400’ 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 9,296’ MD to 7,400’ MD with 13.0 ppg Class G + Add’s Total Volume = 706 ft3 => 372 sx of 13.0 ppg Class G + Add's @ 1.9 ft3 /sk Tail slurry from 10,796’ MD to 9,296’ MD with 15.8 ppg Class G + Add's Total Volume = 608 ft3 => 524 sx of 15.8 ppg Class G + Adds @ 1.16 ft3/sk 7-5/8” Intermediate Casing run to 12,583’ MD / 8,263’ TVD Cement Plan: Top of slurry is designed to be at 11,737’ MD, which is 500’MD or 250’ TVD above Alpine D. Assume 40% excess annular volume. Tail slurry from 12,583’ MD to 11,737’ MD with 15.8 ppg Class G + Adds Total Volume = 391 ft3 => 337 sx of 15.8 ppg Class G + Adds@ 1.16 ft3/sk 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 x 13.625 9.625 x 9.875 7.625 4.5 Density PPG 9.0 – 10.0 10.5 – 12.0 10.0 – 13.0 8.8 – 9.5 PV cP 13 10 40 15 YP lb./1 00 ft2 35-50 20 - 28 20 - 35 15 - 20 Funnel Viscosity s/qt. 200 40 - 50 70 - 90 60 - 80 Initial Gels lb./1 00 ft2 50 10 14 10 10 Minute Gels lb./1 00 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 MT7-83 Saved: 22-Jul-24 MT7-83 Page 9 of 13 Printed: 22-Jul-24 Surface Hole: A fresh water drilling fluid (KSI) will be used for the surface interval. Keep flow line viscosity at 200 sec/qt while drilling and running casing. Reduce viscosity prior to cementing. Maintain mud weight M10.0 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 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 11.5 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 11.5 targeting 13.0 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 8.8-9.5 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. 13. Discussion of Mud and Cuttings Disposal and Annular Disposal (Requirements of 20 AAC 25.005 (c)(14)) MT7-83 Saved: 22-Jul-24 MT7-83 Page 10 of 13 Printed: 22-Jul-24 Drill cuttings and drilling mud form the well will be disposed of by hauling to Alpine injection facility where they will be disposed by injecting to approved Class I or Class II Disposal wells. 14. Drilling Hazards Summary (To be posted in Rig Floor Doghouse Prior to Spud) 16" Hole / 13.375 x 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 / 9.625 x 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 MT7-83 Saved: 22-Jul-24 MT7-83 Page 11 of 13 Printed: 22-Jul-24 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 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. MT7-83 Saved: 22-Jul-24 MT7-83 Page 12 of 13 Printed: 22-Jul-24 15. Proposed Completion Schematic MT7-83 Saved: 22-Jul-24 MT7-83 Page 13 of 13 Printed: 22-Jul-24 16. Area of Review There are no active wells within the AOR. MT7-88 is a planned well. 10769 11000 11000 11500 11500 12000 12000 13000 13000 15000 15000 18000 18000 20009 MT7-83 wp04 Plan Summary MT7-83 wp04MT7-01 MT7-01PB1 MT7-03 MT7-03A RWO Redrill MT7-14MT7-14A MT7-15 MT7-91 MT7-92MT7-93 MT7-95 MT7-96 MT7-97 MT7-98 MT7-83PH1 wp03 MT7-84_E04_WP02_EXT MT7-88 wp01 SouthMT7-89 wp05 South 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 Casing 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] MT7-83PH1 wp03 0 5000 True Vertical Depth0 2000 4000 6000 8000 10000 12000 Vertical Section at 114.21° 13-3/8" Surface Casing 9-5/8" INT1 Casing 7-5/8" INT2 Casing 4-1/2" PROD Liner 0 50 100 Centre to Centre Separation0 3000 6000 9000 12000 15000 18000 21000 Measured Depth DDI 6.924 SURVEY PROGRAM Date: 2024-03-14T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 54.11 1000.00 MT7-83PH1 wp03 (MT7-83PH1)r.5 SDI_URSA1 1000.00 3767.00 MT7-83PH1 wp03 (MT7-83PH1) MWD+IFR2+SAG+MS 3767.00 10768.05 MT7-83PH1 wp03 (MT7-83PH1) MWD+IFR2+SAG+MS 10769.05 10796.05 MT7-83PH1 wp03 (MT7-83PH1) MWD+IFR2+SAG+MS 10796.05 10996.00 MT7-83 wp04 (MT7-83 Tied to PH1)INC 10996.00 12583.00 MT7-83 wp04 (MT7-83 Tied to PH1)MWD+IFR2+SAG+MS 12583.00 20008.79 MT7-83 wp04 (MT7-83 Tied to PH1) MWD+IFR2+SAG+MS Surface Location North / 5915734.35 East / 1430365.00Ground / 100.80 CASING DETAILS TVD MD Name 7485.91 10796.05 9-5/8" INT1 Casing 8262.96 12582.63 7-5/8" INT2 Casing 8502.91 20008.79 4-1/2" PROD Liner Mag Model & Date: BGGM2024 01-Sep-24 Magnetic North is 13.44° East of True North (Magnetic Declination) Mag Dip & Field Strength: 80.32° 57055.58nT SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Annotation 1 10796.05 61.96 102.94 7485.91 2455.00 6728.00 0.00 0.00 5129.33 Start 50.00 hold at 10796.05 MD 2 10846.05 61.96 102.94 7509.41 2445.12 6771.01 0.00 0.00 5172.61 Start DLS 3.50 TFO 125.00 3 10936.05 60.19 105.91 7552.94 2425.51 6847.29 3.50 125.00 5250.22 Start DLS 3.00 TFO 133.16 4 11196.49 55.03 112.86 7692.54 2352.96 7054.59 3.00 133.16 5469.04 Start 25.66 hold at 11196.49 MD 5 11222.15 55.03 112.86 7707.24 2344.80 7073.97 0.00 0.00 5490.06 Start DLS 3.00 TFO 65.10 6 12532.42 77.00 149.00 8251.66 1557.95 7931.28 3.00 65.10 6594.66 Start 50.00 hold at 12532.42 MD 7 12582.42 77.00 149.00 8262.91 1516.19 7956.37 0.00 0.00 6634.67 Start 50.00 hold at 12582.42 MD 8 12632.42 77.00 149.00 8274.16 1474.43 7981.46 0.00 0.00 6674.68 Start DLS 3.00 TFO 54.06 9 12896.56 81.72 155.48 8322.96 1244.85 8102.18 3.00 54.06 6878.93 Start 16.49 hold at 12896.56 MD 10 12913.05 81.72 155.48 8325.33 1230.00 8108.95 0.00 0.00 6891.20 Start DLS 3.00 TFO -19.63 11 13159.31 88.69 153.00 8345.91 1009.16 8215.56 3.00 -19.63 7079.00 Start 6849.48 hold at 13159.31 MD 12 20008.79 88.69 153.00 8502.91 -5092.19 11324.29 0.00 0.00 12416.52 TD at 20008.79 FORMATION TOP DETAILS TVDPath Formation 7455.91 HRZ 7548.91 LCU 8224.91 Top Alpine D 8275.91 38' From Top Alpine D 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 0300060009000True Vertical Depth (1500 usft/in)030006000900012000Vertical Section at 114.21° (1500 usft/in)MT7-83/MT7-83PH1 wp0313-3/8" Surface Casing9-5/8" INT1 Casing7-5/8" INT2 Casing4-1/2" PROD Liner1000200030004000500060007000800090001000011000120001300014000150001600017000180001900020000MT7-83/MT7-83 wp04Start Build 1.50Start Build 2.00Start DLS 2.50 TFO -1.17Start 6925.00 hold at 2416.06 MDStart DLS 3.00 TFO 79.09Start DLS 3.50 TFO 125.00Start DLS 3.00 TFO 133.16Start DLS 3.00 TFO 65.10Start DLS 3.00 TFO 54.06Start DLS 3.00 TFO -19.63TD at 20008.79Section View Project: Western North SlopeSite:GMT2 Rendezvous PadWell: MT7-83Wellbore: MT7-83 Tied to PH1Design: MT7-83 wp04 Plan View Project: Western North SlopeSite:GMT2 Rendezvous PadWell: MT7-83Wellbore: MT7-83 Tied to PH1Design: MT7-83 wp04-700007000South(-)/North(+) (3500 usft/in)-14000 -7000 0 7000 14000West(-)/East(+) (3500 usft/in)MT7-83 T01 Heel Rev2.0 1320ftMT7-83 T02 Toe Rev2.0 1320ftMT7-83 Int2 Shoe T01 Rev2.0MT7-01MT7-01PB1MT7-02MT7-03MT7-03A RWO RedrillMT7-04MT7-05MT7-06MT7-06AMT7-06PB1MT7-07MT7-08MT7-08PB1MT7-09MT7-11MT7-14MT7-14AMT7-15MT7-91MT7-92MT7-93MT7-94MT7-95MT7-96MT7-97MT7-98MT7-99MT7-83PH1 wp03MT7-10_wp04MT7-12_wp02_EXT_PetrelMT7-84_E04_WP02_EXTMT7-88 wp01 SouthMT7-89 wp05 South13-3/8" Surface Casing9-5/8" INT1 Casing7-5/8" INT2 Casing4-1/2" PROD Liner5 0 0100 015002000250030003500400045005000550060006500700075008000 85008503MT7-83 wp04 ! ! 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! , ! - ./ !"# $%&"# '( )0. - * + ,- - .+/0 1 2 !"# $%&"# '( ). - 0 , 3 (' - 12 34 ( ! --5(5*(4(*2 ! & - 6& / 7 #. !4 . ; -= $ !! ;<= ")!1 ;<= 98:& ; -= 0! ! ; -= . 4 4 ;<: -= 9': ; -= ?! ;<: -= ;<: -= *2 0! . ; -= + 5 9'= " = '= 2 '# 9#" ' "92' 29#"" =92 9 = '= 2 '# 9# = "92 " 29#"# 22 =9 ' 9#= " = '= 2 '# 9" ' # "92 = 29##" 2 =9 9' = ' # 9"" 2 "92' 2 " 29# =9 '' 2 9'2 '2 = " " =# 9"# ' "92# 2# " 29#2 # =9# " '" , 7 9'= " = ' " ' 9""2 '# "92" 22 " 29#2" " =9# 2' '# = 9 " ' "" 9"" = "9 # 29# ' =" =9' 2 # 2 "= 9 "= ' ' 9= "2 "9' ' 292 2 =9' 22 '' 2 =" 9'= #' "" 2 = 9='2 "# "9#=' # 29"2 '= 9 "# "' '# 2 92 "" 2 = 9='# "" "9# '2 29" " 9 " 2# 9222 " "" 2 = 9 2# "9#' = 29## 9 ' 9 "= # " #2 9" "9""# 2# 29 "# 92 "2 2 9# " # = 9 = "9= 2 292 "= 92 = ' ' 9" " = 2 9" ' "922 292 ' 92 ' #" ' 9= = 2# 9' ' "= "9 = 29' =" 9"2 "" "2 9 = ' 2 = 9'" "9' = 29 ' 9#2 2 "' 2 ' 9 = =2 #2 9 " "9'' 29 2 ' 9#'2 = =" 2 2 9' =" 2 = 9 #= = =9 =" 29 22 # 9""' = 2 # 29 = " 9 = ' =9" 9'" 2 9=2# " " 2 == 29 = = #2 92# " =92= ' 9' 9= ' ' 2 = 292 =' # '" 9"' =92 9' 2" 9# = 2 " 29 2 "= # # 9' = =9# # = 9## 2 9 = " 2 # 29# # #" #" = 92' =9# 9=== 9=2 22 ' 2 # 29#22 2 # #= ' 922# ' =9" " = 9=# 2 9# 22 ' 2 # " !. 29" = # 2# 92## 2 =9"= = 9"# 9'# " '2 2 29"2 #2 #' 92" == =9"'# == 9"" '" 9' 2 '# 2 " 29"2 #2 #' 92=2 ' =9=# = 9"= ' 9'"= 29= #' 92== = =9=# # 9" " 9'=" 2 29=2 #2 #' 92# = =9=# =' 9## # 9' #= 29=# 2" # #' 2 92" ' =9= '" 9#= 9'" = 2 #' @6 1 " !. 29 2 " = 92 = =92 9# = 9 # =2 2 # 29 ' ' " 9 = =9 = 2 9 " 9 = = ' 2 #" 29'= "= 2 "" # 922 '= =9 ' 92## " 9 2 2 # 29' 2 "" # 92 #" =9 #' 92# " 9 "' 29' " 2 "" # 92" =9' 2 92 9 '" 9 # "# = 9= =9'"= " 9" 9#" 2 9 " "' 9# = 9 9 =2 9 ' 2 9"' =' " 9#" ' 9 ' 9 ' = 92" "= 2 92 =' " 9#= # 9 '2 '2 92# 9 =' " 9#' 9 = # 92' # 9# =' " 9" # 92== "= '# = 92# 9" =' " 9" 2 9## #' " = 9 ' 9= =' " 9"= 9#22 # == = 9#" " 9 =' " 9" 9" # "2 " 9#= '= 9 =' " 9= = 9" 2= # #" 9" = " 9' =' " 9=2 ' 9="= ' #' 9"" #9 =' " 9=" 9# 2 2= 2' 9"' 2 #9 =' " 9= # 92 # 22 9=#2 " #92 =' " 9=' = 9' ' 2 # 9= ' ! ! , ! - ./ !"# $%&"# '( )0. - * + ,- - .+/0 1 2 !"# $%&"# '( ). - 0 , 3 (' - 12 34 ( ! --5(5*(4(*2 ! & - 6& / 7 #. !4 . ; -= $ !! ;<= ")!1 ;<= 98:& ; -= 0! ! ; -= . 4 4 ;<: -= 9': ; -= ?! ;<: -= ;<: -= *2 0! . ; -= #9 =' " 92 = 9'= ' = '# 9 2 #9# =' " 9# " 9 #" 2 '= 2 9 = #9" =' " 9= =# 92 " " ' 92# " #9= =' " 9 ' 92 = 2# 9=' ## #9 =' " 9 2 92' = = 2" 9'# 2 #9 =' " 9 "2 9" "2 #"2 9'= 2 #9' =' " 9" 9#" #" "# # '9 " = "9 =' " 9 9" = # '9 " ' "9 =' " 9' ' 9"' ' "= '9 '= "92 =' " 9'2 =' 9==' 2 =# '9# = "9 =' " 9'# ' 9# " ' '9 # "9# =' " 9' 2 92" '= ' '922 " "9" =' " 9'' "= 9' 9 " '92 '2 "9= =' " 9# " 9' ' 9=# '" '92 "9 =' " 9# # " '9 " = 92"# 2 '9= =' "9 =' " 9# = ## '9= 9# '9## "9' =' " 9# '92# 9#2 '9#"' #= =9 =' " 9# 2 '92'2 = 9"2 2= '9" # " =9 =' " 9# 2 '9 "= 9= # '9"" 2 =92 =' " 9#" = '9## #' 9='' # '9"'" =2 =9 =' " 9# ' '9"2= # 9 #' '9=# =9# =' " 9#2 ' '9= # # 9 " '9== ' =9" =' " 9#22 # '9=2 2= 9'== =" '9 =9= =' " 9#2# '9= ' 29 "" 2 '9 =9 =' " 9#2 '9 2 29## '922 "" =9 =' " 9#2' = '9'= # 292 '9= '# =9' =' " 9# =" '9'' ' 2922 '= '9' 2 9 =' " 9# '# 9 ' 29#2 '9'" 9 =' " 9#= 2# 9#' 2 29" 9 # 92 =' " 9# " 922 " 29"' ' 9 #' # 9 =' " 9## 2 9 " = 29=' 2 9 '# 9# =' " 9## 9 = 29= # 9# 2= 9" =' " 9##" # 9#= "2 29" #2 9" =# 9= =' " 9## 9"' #" 29'#= " 92 9 =' " 9##' '' 9= 9 " " 92= #2 9 =' " 9#"2 2 9='" 92# =" 92 9' =' " 9#"# " 9 2 92 9= ' 9 =' " 9#"= 9" " 9 2 9#2 " 9 =' " 9#"' = 9'2' 9' ' 9#" '= 92 =' " 9#= #" 9 9# ' 9" " 9 =' " 9#= # 9 # ' 9" # 9"# 9# =' " 9#== 9=2 = 9="' 2 9"'# 2 9" =' " 9#= 92# 9# 2 9=' " 9= =' " 9# =2 9 9 2 9=# ' 9 =' " 9#2 ' 9'= =# 9'2= " 9 2 9 =' " 9#" 2 9## "= #9 " # 9" = 9' =' " 9# " 9""2 #' #9 # " 92 " '9 =' " 9#' ' 9= # #9' "' 9== ## '9 =' " 9#2 9 # #922 == 9' '92 =' " 9## 9= 2= #9 # 9'" 2 '9 =' " 9#= == 9=# ' #9#= 2 9 2 = '9# =' " 9# '= 9'#2 2 #9"#' ' 9 # ' '9" =' " 9#' 2" 29 2 # #9= ' 9 ' '9= =' " 9#' "# 29 ' ' #92 " 9 = ! ! , ! - ./ !"# $%&"# '( )0. - * + ,- - .+/0 1 2 !"# $%&"# '( ). - 0 , 3 (' - 12 34 ( ! --5(5*(4(*2 ! & - 6& / 7 #. !4 . ; -= $ !! ;<= ")!1 ;<= 98:& ; -= 0! ! ; -= . 4 4 ;<: -= 9': ; -= ?! ;<: -= ;<: -= *2 0! . ; -= '9 =' " 9#'" 29" ' #9 9# # '9 =' " 9#' 2 292" 2 #9' = 2 922' " '9' =' " 9" #2 29 " #9''" 2 92# '2 2 9 =' " 9" 2 29# ' = "9 # = 92 2 9 ' =' " 9" 2 ' 29#= "2 "9 '2 ' 92# 2' 4'1 !:1! 4 0. ; -= ' !4 ; -= 8 !4 ; -= 9': ; -= 98:& ; -= . !44 , 4!,! .! "4 ;<= .! .!A ;<= .2, 92=2 ' "9'9 2' 9#9= 9"= ' 9'"= < >' #"0 "<> ' ,- ;+ - 6 42 9#" ' "9'=9"" 9#9= " 9 ' = 92" "= < ># "=0 "<>2' "'" ,- ;+ *-+ -( 92 % 2 42 9" 2 ' "9' 9 9##9"# "9 '2 ' 92# 2' <'># 0 "<">"' ,- ;+ *-+ -( 92 % 0! . ; -= . ; -= !4 .!1 ;!= + .!1 ;!='1 !4 ! ?A()+* -;9 " '#9= " = '"?A.0* -;9#" ' 9'= "' =2" 2 2" "?A.02* -;29"2 = " #?2A @ -2 9 '# " = " . ; -= 0! . ; -= .! .! ! ;<='1 ,! 42 .! ;<= 6 1! 92 2 6 :9#"" ' 9'2 '2 *89"# ' 29#22 2 -922# ' 29=# 2" >$ 5 -92" ' ! ! , ! - ./ !"# $%&"# '( )0. - * + ,- - .+/0 1 2 !"# $%&"# '( ). - 0 , 3 (' - 12 34 ( ! --5(5*(4(*2 ! & - 6& / 7 #. !4 . ; -= 0! . ; -= 98:& ; -= 9': ; -= , ! 11 " ! 9'= " 9#" ' 29#"" =92 " , '= " 9#= " 9" ' # 29##" 2 =9 " $@2" 9'= " 9""2 '# 29#2" " =9# 2' $@ = 9'= #' 9='2 "# 29"2 '= 9 "# "' 2" ==, '= #' 9222 " 9 2# 29## 9 ' $@=" 29"2 #2 92" == 9"" '" 9' 2 " , 2"2 #2 29"2 #2 92=2 ' 9"= ' 9'"= " , 2"2 #2 29=2 #2 92# = 9## # 9' #= $@"# = 29'= "= 922 '= 92## " 9 2 = #', 2'= "= 29' " 92" 92 9 '" $@' = 9"' 9#" ' 9 ' = 92" "= =#' #, "' 2 9 ' 9" 2 ' "9 '2 ' 92# 2' 2 ' ! ! "#$ %&'% #$()* #$()*$% + #$()*, -)% ./ / !" #$%%& '()*&$$ +,- . $)*&/$ 0$01./ 2 / !" #$%%& '()*&$$ +,- . $)*&/$ 0#1./12 345 3. / ! ./%&%% 0 3/ 5 ' # %/. / 4 2&%% 6 3/%&%% 0 . 5 3 7$1 5/8+ $ 3 900 + .16/ :%*4.. $01./ # %/ 1 6/ . 3#%/ # %/ 3./ 7 / 5& 3 ;3 3 5 9 1'9"' , '8< =6 303 > 06 + 5 2)&%% 0 $%?/@&%) 2%?%%&/ 0 A 3 0 $?@/&*/ 0 :%* - %5/ 6 6-'3' % / 2&/ 333 8 B 6# %/ 7 8. 9 '$6 1 $!'8 59 $ 8. 9 1 @C$C2%2* &) + = $ + = $ 6+ # 5 )-)*&$$ $?%%%&%% 7$ :% #7$- +( ,2( 1( 9 1 + ( ,2 ( 6 ( $?%%%&%% ?@&%% 7$ :% #7$- +( ,2( 1( 9 1 + ( ,2 ( 6 ( ?@&%% $%?@&%) 7$ :% #7$- +( ,2( 1( 9 1 + ( ,2 ( 6 ( $%?@/&%) $%?/@&%) 7$ :% #7$- #C30-$%?/@&%) $%?//@&%% :%* # 3 7$- +( ,2( 1( 9 1 + ( ,2 ( 6 ( $%?//@&%% $2?)&%% :%* # 3 7$- +( ,2( 1( 9 1 + ( ,2 ( 6 ( $2?)&%% 2%?%%&/ :%* # 3 7$- 4.. ) 5)16 . #% 1 8. 9 4.. #% 1 8. 9 : , 8. 9 : , 3 8. 9 7 6 ! 1 12 345 3 %2 %2 %2 9 0 6 %* 12 %* %*9 0 6 %@ %@ %@ 9 0 6 %@ %@ %@9 0 6 %@ %@"$ %@"$9 0 6 % % %9 0 6 % %"$ %"$9 0 6 $* $* $*9 0 6 $* $* $*9 0 6 9 +6? ? 8 ? ,? $% 0& + 8 7$ 7$ :% $%?)%&%% $%?)%&%% %&%$ /&//%&%%$ /$ /$ /$9 0 6 /2 /2 /2 9 0 6 / / /9 0 6 /) /) /)9 0 6 / / /9 0 6 // // //9 0 6 $% $% $% :%*9 0 6 $2 $2 $2 :%2 8D 9 0 6 * * * 8%* %2 8D $%?%&$ $?))%&%% $?%*&* /$$&* &@)@ ? 8 * * * 8%* %2 8D $$?*& $*?$)%&%% $?$)2&22 *//&@@ $&@@ ? , * * * 8%* %2 8D $$?))&@* $*?2)&%% $?$*&*@ )%& $&*/ :%$ $%?/&/2 2$?)&%% $?%*&$ &@% )&$) ? 8 :%$ $$?*$%&*) 2$?2%%&%% $?$@& *)%&)) $&@) ? , :%$ $$?)*&%% 2$?%)&%% $?$@/&%@ *)@&$ $&@*$ / / / :%) 9 0 6 3 56 ? , 0 ? 8 -)% ./ / !" #$%%& '()*&$$ +,- . $)*&/$ 0$01./ 2 / !" #$%%& '()*&$$ +,- . $)*&/$ 0#1./12 345 3. / ! ./%&%% 0 3/ 5 ' # %/. / 4 2&%% 6 3/%&%% 0 . 5 3 7$1 5/8+ $ 3 900 + .16/ :%*4.. $01./ % *%% %% $2%% $@%% % )%% %%% $%)%% $*%%% $)%% 2$%%% 3 + ' 33 ? 7$? 7$ :% B% *? *? * 8%* %2 8D B% ? ? :%$ B% ' 8 1 8 + 3 5 < 3 = $/? E * 13 56 0 < $&)/F 3 $)%F %G %&%%% 900 + 5 900 + 0 + 5 !" #$%%& '()*&$$ +,- . $)*& 3 56 ? , 0 ? 8 -)% ./ / !" #$%%& '()*&$$ +,- . $)*&/$ 0$01./ 2 / !" #$%%& '()*&$$ +,- . $)*&/$ 0#1./12 345 3. / ! ./%&%% 0 3/ 5 ' # %/. / 4 2&%% 6 3/%&%% 0 . 5 3 7$1 5/8+ $ 3 900 + .16/ :%*4.. $01./ %&%% &%% @&%% /&%% , % )%% %%% $%)%% $*%%% $)%% 2$%%% 3 + 9 +6 3 9 , ? 7$? 7$ :% B% *? *? * 8%* %2 8D B% ? ? :%$ B% ' 8 1 8 + 3 5 < 3 = $/? E * 13 56 0 < $&)/F 3 $)%F %G %&%%% 900 + 5 900 + 0 + 5 !" #$%%& '()*&$$ +,- . $)*& 3 56 ? , 0 ? 8 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Dupont, Hilda To:Davies, Stephen F (OGC) Cc:Dewhurst, Andrew D (OGC); Loepp, Victoria T (OGC); Nagel, Matt B Subject:RE: [EXTERNAL]RE: GMTU- MT7-83 (PTD 224-102) - Question Date:Monday, August 12, 2024 7:49:08 AM Good morning Steve, Yes, the plan is to pre-produce MT7-83. Thank you, Hilda Dupont | Drilling Engineer | ConocoPhillips O: 907.265.6675 | C: 661.577.7338 | 700 G Street, ATO-1554, Anchorage, AK 99501 From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Friday, August 9, 2024 2:00 PM To: Dupont, Hilda <Hilda.Dupont@conocophillips.com> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Nagel, Matt B <Matt.B.Nagel@conocophillips.com> Subject: [EXTERNAL]RE: GMTU- MT7-83 (PTD 224-102) - 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. Hilda, Per Matt Nagel’s out-of-office reply, I’m forwarding my question to you. Will CPAI’s planned MT7-83 injector be pre-produced, or will the well be briefly flowed back for clean up only? Thanks and Be Well, Steve Davies AOGCC 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 Steve Davies at 907-793-1224 or steve.davies@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. 224-102 GREATER MOOSES TOOTH GMTU MT7-83 RENDEZVOUS OIL WELL PERMIT CHECKLISTCompanyConocoPhillips Alaska, Inc.Well Name:GMTU MT7-83Initial Class/TypeSER / PENDGeoArea890Unit10750On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2241020GRTR MOOSES TOOTH, RENDEZV OIL - 2822NA1Permit fee attachedYesSurface Location lies within AA0098885; Top Productive Interval lies in AA0081800;2Lease number appropriateYesPortion of Productive Interval lies in AA0081799; TD lies in AA0081780.3Unique 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 waitYesArea Injection Order No. 43, issued July 13, 2021, governs Rendezvous Oil Pool.14Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForYesNone15All wells within 1/4 mile area of review identified (For service well only)YesWell will be pre-produced.16Pre-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)NA18Conductor string providedNA19Surface casing protects all known USDWsNA20CMT vol adequate to circulate on conductor & surf csgNA21CMT vol adequate to tie-in long string to surf csgNo22CMT 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 proposedNA27If diverter required, does it meet regulationsYesMax reservoir pressure is 3848 psig(8.7 ppg EMW); will drill w/ 8.8-13 ppg EMW28Drilling fluid program schematic & equip list adequateYes29BOPEs, do they meet regulationYesMPSP is 2997 psig; will test BOPs to 5000 psig initially and 4000 psig subsequently30BOPE 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; rig has sensors and alarms.35Permit can be issued w/o hydrogen sulfide measuresYesExpected pressure range is 0.433 to 0.453 psi/ft (8.3 to 8.7 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 zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate8/12/2024ApprVTLDate8/22/2024ApprSFDDate8/9/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateRecommend approving requested variance from diverter waiver requirement: Operator reports "Our geologist confirms that we haven't observed any evidence of shallow gas or gas hydrates in the surface section with either the seismic or development data or while drilling any of the MT7 wells." (See attached email dated 8/12/2024.) Corroborated by examining records from nearby wells MT7-96, MT7-98, MT7-93, MT7-92, and MT7-04. SFD*&:JLC 8/28/2024
