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Home My WebLink About181-089MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Tuesday, July 22, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Guy Cook P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL ConocoPhillips Alaska, Inc. 1B-07 KUPARUK RIV UNIT 1B-07 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 07/22/2025 1B-07 50-029-20616-00-00 181-089-0 W SPT 6226 1810890 1556 1716 1718 1702 1712 706 970 948 938 4YRTST P Guy Cook 6/13/2025 Testing completed with a Little Red Services pump truck and calibrated gauges. The OOA = 0 psi throughout the test. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:KUPARUK RIV UNIT 1B-07 Inspection Date: Tubing OA Packer Depth 875 2640 2510 2480IA 45 Min 60 Min Rel Insp Num: Insp Num:mitGDC250612101637 BBL Pumped:0.6 BBL Returned:0.6 Tuesday, July 22, 2025 Page 1 of 1            MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Wednesday, April 23, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Sully Sullivan P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL ConocoPhillips Alaska, Inc. 1B-07 KUPARUK RIV UNIT 1B-07 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 04/23/2025 1B-07 50-029-20616-00-00 181-089-0 W SPT 6226 1810890 1556 1381 1383 1384 1378 720 1120 1100 1100 INITAL P Sully Sullivan 3/26/2025 MIT-IA post RWO per Sundry #324-498 after a sealtite patch/repair per sundry #324-674 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:KUPARUK RIV UNIT 1B-07 Inspection Date: Tubing OA Packer Depth 190 2200 2145 2145IA 45 Min 60 Min Rel Insp Num: Insp Num:mitSTS250326194724 BBL Pumped:0.9 BBL Returned:0.9 Wednesday, April 23, 2025 Page 1 of 1 9 9 9 9 9 9 9 999 99 99 9 9 9 MIT-IA post RWO Sundry #324-498 sundry #324-674 James B. Regg Digitally signed by James B. Regg Date: 2025.04.23 12:34:16 -08'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Seal-Tite Repair Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 9625'feet None feet true vertical 6967' feet 9022', 9022', 9046'feet Effective Depth measured 9625'feet 8360', 8484', 8756'feet true vertical 6967' feet 6135', 6227', 6422'feet Perforation depth Measured depth True Vertical depth Tubing (size, grade, measured and true vertical depth) 3-1/2" L-80 8786' MD 6444' TVD Packers and SSSV (type, measured and true vertical depth) 8360' MD 8484' MD 8756' MD N/A 6135' TVD 6227' TVD 6422' TVD N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: Kuparuk River Oil Pool 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title:Contact Phone: 2846' 2633' Burst Collapse Production Tie-Back string 1900' 7646' 8451' Casing 1847' 6934' 5-1/2" 1927' 9570' 8451' 6203' 2816' 80'Conductor Surface tie-Back Prod 16" 10-3/4" 80' measured TVD 7" 7" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 181-089 50-029-20616-00-00 P.O. Box 100360 Anchorage, AK 99510 3. Address: ConocoPhillips Alaska, Inc. N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0025648 Kuparuk River Field/ Kuparuk River Oil Pool KRU 1B-07 Plugs Junk measured Length measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) ~ Gas-Mcf MD ~ Size 80' ~~~ INJECTOR ~~ ~ 324-674 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG ~ Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. N/A Packer: Bluepack Max RH Packer Packer: FHL Retrvbl Packer Packer: D Packer SSSV: None Shelby Sumrall Shelby.Sumrall@conocophillips.com (907) 265-6678Staff Well Integrity Engineer 8575-8650', 8670-8686', 8695-8702', 8880-8894', 8904-8914', 8922-8940' 6293-6347', 6361-6373', 6379-6384', 6509-6518', 6525-6532', 6537-6549' Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 9:17 am, Apr 22, 2025 Digitally signed by Shelby Sumrall DN: OU=Alaska, O=Conocophillips, CN=Shelby Sumrall, E=Shelby.Sumrall@conocophillips.com Reason: I am the author of this document Location: Anchorage Alaska Date: 2025.04.21 16:04:21-08'00' Foxit PDF Editor Version: 13.1.6 Shelby Sumrall DSR-4/24/255/8/25 RBDMS JSB 042525 DTTMSTART JOBTYP SUMMARYOPS 2/12/2025 ACQUIRE DATA (AC EVAL) : IC POT (PASSED), OC POT (PASSED), T DDT TO 0 PSI (IN PROGRESS), IA DDT TO 0 PSI (PASSED), OA DDT TO 0 PSI (IN PROGRESS) 2/15/2025 ACQUIRE DATA (AC EVAL) T-DDT TO 0 PSI (PASS) IA-DDT TO 0 PSI (PASS) OA-DDT TO 0 PSI (PASS) LLR-OA @ 1000 PSI (COMPLETE) LLR-OA @ 2000 PSI (COMPLETE) ESTABLISHED A LLR-OA OF 0.52 GPM @ 3000 PSI (COMPLETE) IC-POT (FAIL) OC-POT (FAIL) 2/21/2025 ACQUIRE DATA (AC EVAL) RE-ENERGIZE IC PO (COMPLETE) RE-ENERGIZE OC PO (COMPLETE) IC POT (PASS) IC PPPOT (PASS) OC POT (PASS) OC PPPOT (PASS) 3/6/2025 REPAIR WELL SET 3-1/2 CATCHER (OAL= 29'') ON TOP XX-PLUG @ 8392' RKB, PULL 1-1/2'' DMY @ 8300' RKB, JOB IN PROGRESS 3/7/2025 REPAIR WELL CIRC 160 BBLS NaCl DWN TBG, PUMP & DISPLACE SEALANT PILL, SET DMY VLV IN MANDREL @ 8300' RKB, PULL CATCHER @ 8389' RKB, EQUALIZE X PLUG @ 8391' RKB, FP TBG W/ 20 BBL DIESEL. JOB IN PROGRESS 3/7/2025 REPAIR WELL (AC EVAL) MIXED AND SPOTTED SEAL-TITE PILL (PER SEAL-TITE PROCEDURE). 3/8/2025 REPAIR WELL (AC EVAL) SEAL-TITE TREATMENT (IN PROGRESS). 3/8/2025 REPAIR WELL PULL 2.81'' XX- PLUG @ 8391' RKB, SET 2.81'' XX PLUG @ 8391' RKB, ATTEMPT CMIT TxIA TO 3300 PSI (FAIL DUE TO TBG PRESSURE) GET PASSING MITIA TO 3300 PSI, EQUALIZE & PULL 2.81'' XX PLUG @ 8391' RKB, SET 2.81''X X PLUG @ 8391' RKB, GET PASSING MIT-T TO 3300 PSI. READY FOR DHD. 3/9/2025 REPAIR WELL (AC EVAL) PRESSURED OA TO SPOT SEAT-TITE PILL IN PROGRESS. 3/12/2025 REPAIR WELL EQUALIZE & PULL XX PLUG @ 8391' RKB 3/16/2025 REPAIR WELL (MISC) MONITOR & BLEED OA FOR STABILIZATION WHILE WELL BOI POST OA SEAL-TITE TREATMENT (IN PROGRESS). 3/26/2025 ACQUIRE DATA (SW) MIT IA TO 2200 PSI (PASSED), WITNESSED BY SULLY SULLIVAN. 1B-07 Seal-Tite Repair Summary of Operations Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag:RKB (Est.12' of Rathole) 8,952.0 1B-07 6/9/2018 zembaej Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Pulled XX plug @ 8391' RKB 1B-07 3/12/2025 raineg Notes: General & Safety Annotation End Date Last Mod By NOTE: View Schematic w/ Alaska Schematic9.0 8/6/2010 ninam 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 16 15.06 29.3 80.0 80.0 62.50 H-40 WELDED SURFACE 10 3/4 9.95 29.3 2,845.6 2,632.9 45.50 K-55 BTC Tie-Back String Production Repair 7 6.28 27.3 1,927.0 1,847.5 26.00 L-80 HYD 563 Production 7 6.28 1,924.0 9,569.9 6,933.8 26.00 K-55 BTC Tie-Back String 5 1/2 4.95 0.0 8,451.2 6,202.9 15.50 L-80 HYD 563 Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 23.3 Set Depth … 8,269.5 Set Depth … 6,066.5 String Max No… 3 1/2 Tubing Description Tubing – Completion Upper Wt (lb/ft) 9.30 Grade L-80 Top Connection HYD 563 ID (in) 2.99 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) 23.3 23.3 0.00 Hanger 7.010 Cameron 7 1/16" x 3 1/2" CXS Tubing Hanger. EUE top thread. Camero n CXS 2.950 1,989.4 1,902.9 27.89 Nipple - X 4.272 3 1/2" x 2.813" X Nipple, HES X Nipple 2.813 8,170.3 5,990.7 40.07 Mandrel – GAS LIFT 4.733 3 1/2" x 1" KBG-2-9 GLM SLB KBG-2-9 2.818 8,228.1 6,034.9 40.14 Nipple - X 4.287 3 1/2" x 2.813" X Nipple, 8 HES X Nipple 2.813 8,249.2 6,051.1 40.25 Locator 4.500 Locator Baker Locator 2.992 8,249.7 6,051.4 40.25 Seal Assembly 3.500 80-40 GBH-22 Seal Assy (6' space out off No-Go) Baker GBH-22 2.992 Top (ftKB) 8,448.0 Set Depth … 8,786.4 Set Depth … 6,443.8 String Max No… 3 1/2 Tubing Description Tubing – Completion Lower Wt (lb/ft) 9.30 Grade L-80 Top Connection EUE8RDMOD ID (in) 2.99 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) 8,469.9 6,216.7 42.70 PBR 5.875 BAKER PBR w/ 10' STROKE 3.000 8,483.8 6,226.9 42.84 PACKER 6.062 PACKER FHL RETRIEVABLE PACKER 2.890 8,528.8 6,259.7 43.29 INJECTION 5.750 Camco MMM 2.920 8,574.7 6,293.0 43.75 BLAST JTS 3.500 STEEL BLAST JOINTS (OAL=147') 2.992 8,740.4 6,411.3 45.05 SLEEVE 3.250 CB-1 SLIDING SLEEVE Camco 2.260 8,753.0 6,420.2 45.15 XO Reducing 3.500 CROSSOVER 3.5 x 2.875", ID 2.441, 6.5#, J-55, EUE IPC 2.875 8,753.8 6,420.8 45.15 SEAL ASSY 3.250 LOCATOR SEAL ASSEMBLY Baker 2.375 8,755.8 6,422.3 45.17 PACKER 5.687 D PACKER Baker 3.260 8,774.6 6,435.5 45.31 NIPPLE 3.668 OTIS XN NIPPLE NO GO 2.250 8,785.8 6,443.4 45.39 SOS 3.750 SHEAR OUT SUB (SHEARED) Baker 2.441 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 25.3 25.3 0.00 EMERGENCY SLIPS 5 1/2" Tieback Emergency Slips Cameron 9/2/2024 5.500 27.3 27.3 0.00 EMERGENCY SLIPS Custom McEvoy Type SB-3 Emergency Slips 8/19/2024 7.000 8,190.0 6,005.8 40.03 LEAK - CASING SUSPECTED PC LEAK @ 8190' RKB IDENTIFIED ON VIVID/VIVID SEAL LDL (3000 PSI ON OA & ~3330 PSI HELD ON IA), ~0.2 GPM LLR TO FORMATION 10/26/2024 6.280 8,300.0 6,089.7 40.50 OTHER 3 1/2" x 1 1/2" MMG, GLM, DMY w/ RK Latch, SN# 24135 -06 8/31/2024 2.920 9,022.0 6,600.8 51.61 FISH Slip f/ Slip stop LOST 8/1/1993 8/31/1993 0.000 9,022.0 6,600.8 51.61 FISH TIW PKR & Tbg Tail LOST 6/16/1994 6/16/1994 0.000 9,046.0 6,615.6 51.73 FISH Vann Gun 428' long GUN LOST 9/20/1981 9/20/1981 0.000 Mandrel Inserts : excludes pulled inserts Top (ftKB) Top (TVD) (ftKB) Top Incl (°) St ati on No /S Serv Valve Type Latch Type OD (in) TRO Run (psi) Run Date Com Make Model Port Size (in) 8,170.3 5,990.7 40.07 1 GAS LIFT DMY BTM 1 9/7/2024 8,528.8 6,259.7 43.29 3 INJ DMY TGP 0.0 6/16/1994 0.000 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) 0.0 0.0 0.00 Parker 141 ORKB = 25.3', Nordic 3 RKB = 27.41' 0.000 Parker 141 ORKB = 25.3', Nordic 3 RKB = 27.41' 0.000 1B-07, 4/15/2025 4:44:41 PM Vertical schematic (actual) Production; 1,924.0-9,569.9 FISH; 9,046.0 FISH; 9,022.0 FISH; 9,022.0 IPERF; 8,922.0-8,940.0 IPERF; 8,904.0-8,914.0 PACKER; 8,755.8 IPERF; 8,695.0-8,702.0 IPERF; 8,670.0-8,686.0 IPERF; 8,575.0-8,650.0 INJECTION; 8,528.7 PACKER; 8,483.8 Tie-Back String; 0.0-8,451.2 OTHER; 8,300.0 Nipple - X; 8,228.1 LEAK - CASING; 8,190.0 Mandrel – GAS LIFT; 8,170.3 SURFACE; 29.3-2,845.6 Nipple - X; 1,989.4 Tie-Back String Production Repair ; 27.3-1,927.0 Intermediate String 1 Cement; 28.3 ftKB CONDUCTOR; 29.3-80.0 EMERGENCY SLIPS; 27.3 EMERGENCY SLIPS; 25.3 Hanger; 23.3 KUP INJ KB-Grd (ft) 32.48 RR Date 9/20/1981 Other Elev… 1B-07 ... TD Act Btm (ftKB) 9,625.0 Well Attributes Field Name KUPARUK RIVER UNIT Wellbore API/UWI 500292061600 Wellbore Status INJ Max Angle & MD Incl (°) 61.00 MD (ftKB) 4,200.00 WELLNAME WELLBORE1B-07 Annotation Last WO: End Date 6/16/1994 H2S (ppm) DateComment SSSV: WRDP 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) 8,257.5 6,057.4 40.29 SBR 5.020 80-40 SBR, 5" P x 4 1/2" B HYD521 P (SN#: HT- 965205 SN01) Baker 80-40 SBR 4.000 8,300.0 6,089.7 40.50 Mandrel – GAS LIFT 5.906 3 1/2" x 1 1/2" MMG, GLM, DMY w/ RK Latch, SN# 24135-06 SLB MMG 2.920 8,360.2 6,135.2 41.40 Packer 5.995 3 1/2" x 7" Bluepack Max RH Packer, VamTop, SN# C23P-1919 SLB Bluepack Packer 2.894 8,391.7 6,158.8 41.88 Nipple - X 4.287 3 1/2" x 2.813" X Nipple HES X Nipple 2.813 8,444.4 6,197.9 42.44 Overshot 5.990 7 x 3 1/2" PBOS (6.19' swallow, shear pins @ 3', 3' space out) Baker Poorboy Overshot 3.630 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 8,575.0 8,650.0 6,293.3 6,347.1 D, C-2, C-3, C-4, 1B-07 11/23/1981 4.0 IPERF Max angle across perf 44 8,670.0 8,686.0 6,361.4 6,372.8 C-1, UNIT B, 1B- 07 11/23/1981 4.0 IPERF 8,695.0 8,702.0 6,379.2 6,384.2 UNIT B, 1B-07 11/23/1981 4.0 IPERF 8,880.0 8,894.0 6,508.6 6,518.1 A-5, 1B-07 11/23/1981 4.0 IPERF 8,904.0 8,914.0 6,524.8 6,531.6 A-4, 1B-07 11/23/1981 4.0 IPERF 8,922.0 8,940.0 6,536.9 6,548.8 A-4, 1B-07 11/23/1981 4.0 IPERF Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 28.3 2,000.0 28.3 1,912.2 Intermediate String 1 Cement 8/19/2024 1B-07, 4/15/2025 4:44:41 PM Vertical schematic (actual) Production; 1,924.0-9,569.9 FISH; 9,046.0 FISH; 9,022.0 FISH; 9,022.0 IPERF; 8,922.0-8,940.0 IPERF; 8,904.0-8,914.0 PACKER; 8,755.8 IPERF; 8,695.0-8,702.0 IPERF; 8,670.0-8,686.0 IPERF; 8,575.0-8,650.0 INJECTION; 8,528.7 PACKER; 8,483.8 Tie-Back String; 0.0-8,451.2 OTHER; 8,300.0 Nipple - X; 8,228.1 LEAK - CASING; 8,190.0 Mandrel – GAS LIFT; 8,170.3 SURFACE; 29.3-2,845.6 Nipple - X; 1,989.4 Tie-Back String Production Repair ; 27.3-1,927.0 Intermediate String 1 Cement; 28.3 ftKB CONDUCTOR; 29.3-80.0 EMERGENCY SLIPS; 27.3 EMERGENCY SLIPS; 25.3 Hanger; 23.3 KUP INJ 1B-07 ... WELLNAME WELLBORE1B-07 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: Seal-Tite Repair 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: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 9625'9022', 9022', 9046' Casing Collapse Structural Conductor Surface Tie-Back Prod Production Tie -Back String Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. W ell Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. W ell 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: 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 265-6678 Staff Well Integrity Engineer KRU 1B-07 6967' 8392' 6159' 8392' N/A 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: Tubing Size: shelby.sumrall@conocophillips.com AOGCC USE ONLY Tubing Grade: Tubing MD (ft): 8484' MD and 6227' TVD 8756' MD and 6422' TVD 8360' MD and 6135' TVD N/A Shelby Sumrall STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025648 181-089 P.O. Box 100360, Anchorage, AK 99510 50-029-20616-00-00 Kuparuk River Field Kuparuk River Oil Pool ConocoPhillips Alaska, Inc. Length Size Proposed Pools: PRESENT WELL CONDITION SUMMARY Kuparuk River Oil Pool TVD Burst 8786' MD MD 80' 2633' 1847' 80' 2846' 6934'9570' 16" 10-3/4" 80' 7"1900' 2816' 1927' 8575-8650', 8670-8686', 8695- 8702', 8880-8894', 8904-8914', 8922-8940' 7646' 5-1/2" 6293-6347', 6361-6373', 6379- 6384', 6509-6518', 6525- 6532', 6537-6549' 7" Perforation Depth TVD (ft): 12/26/2024 8451'8451' 3-1/2" 6203' Packer: FHL Retrvbl Packer Packer: Baker D Packer Packer: SLB Bluepack Max RH Packer SSSV: None Perforation Depth MD (ft): L-80 Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Shelby Sumrall DN: OU=Alaska, O=Conocophillips, CN=Shelby Sumrall, E= Shelby.Sumrall@conocophillips.com Reason: I am the author of this document Location: Anchorage Alaska Date: 2024.11.26 15:13:32-09'00' Foxit PDF Editor Version: 13.0.0 Shelby Sumrall By Grace Christianson at 9:40 am, Nov 27, 2024 324-674 JJL 12/3/24 10-404X Injection subject to passing MITIA and maintained by AIO 002 rule 7. SFD 12/2/2024 DSR-12/16/24*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.12.16 16:01:15 -09'00'12/16/24 RBDMS JSB 121724 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 November 26, 2024 Commissioner Jessie Chmielowski Alaska Oil & Gas Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner Chmielowski, Enclosed please find the 10-403 Application for Sundry Approval for ConocoPhillips Alaska, Inc. well KRU 1B-07 (PTD 181-089) to repair a leak in the 7” casing at 8349’ MD with SealTite. If you need additional information, please contact us at 265-6678. Sincerely, Shelby Sumrall Well Integrity Specialist ConocoPhillips Alaska, Inc. Digitally signed by Shelby Sumrall DN: OU=Alaska, O=Conocophillips, CN=Shelby Sumrall, E= Shelby.Sumrall@conocophillips.com Reason: I am the author of this document Location: Anchorage Alaska Date: 2024.11.26 15:13:14-09'00' Foxit PDF Editor Version: 13.0.0 Shelby Sumrall Page 1 of 5 Proposed Procedure for ConocoPhillips Diagnostics and Repair of Casing Leak Prepared by Seal-Tite International Field: Kuparuk Well: 1B-07 Date: November 19, 2024 Objectives 1. Determine leak rate. 2. Cure the leak using Seal-Tite sealants and procedures. Mechanical Considerations The subject water alternating gas (WAG) injection well is completed with a 3-1/2” tubing string stung into a seal bore of the 5-1/2” x 3-1/2” tapered string. Production packer is set at 8360’ MD. In October 2024, the well was secured with a tubing plug (8392’ MD) in preparation for a thru-tubing leak detection log. The leak was located in the 7” casing lower connection of an external casing packer @ 8349’ MD approximately 11’ above the production packer. The leak rate was measured at 0.2 GPM (750 ml/min) at 3000 psi. The 5-1/2” x 7” Outer annulus bleeds to zero with no pressure build -up from the formation. The well passed a 3500 psi MIT-T and 3000 psi MIT-IA in Sept 2024.The IC hanger void area was successfully tested in April 2024. MIT-OA required test pressure is 3300 psi (3000 psi max injection pressure +10%). Inclination at 8360’ MD (packer depth) is 40 degs with a 6100’ TVD. Figure 1- Vivid Leak Detection Log Results Tubulars Tubing (0’ MD - 8250’ MD): 3-1/2” 9.3# J-55 EUE 8RD – 2.992” ID Tie-Back String (0’ MD – 8257’ MD): 5-1/2” 15.5# L-80 Hyd563 MS – 4.95” ID Production Casing (0’ MD – 8360’ MD): 7” 26# J-55 Buttress – 6.276” ID Capacities Tubing - 0.0097 bbls/ft x 6511’ MD = 63 bbls Upper Outer Annulus – 0.0089 bbls/ft x 8257’ MD = 74 bbls Lower Outer Annulus – 0.0264 bbls/ft x 103’ MD = 3 bbls Page 2 of 5 Figure 2: 5-1/2” tie-back completion Intended Diagnostic Procedure 1. Meet with field personnel; review field history and verify condition of well as matching information provided. 2. Perform Job Safety Analysis with all concerned personnel. 3. Record all tubing and casing pressures. 4. Locate the test port for subject casing hanger. The test port may access the void between primary and secondary seals for a conventional casing hanger, or between pack-off seals for a pack-off style casing hanger. Rig up pressure relief tool with gauge and bleeder valve to the test port fitting. Sting in to move check valve off seat, record pressure in the void, and compare with adjacent casing pressures. Bleed void pressure to zero. If possible, measure stable fluid flow rate from the test port. Shut in and monitor for pressure build up. 5. Bleed all well pressures to zero. Document return type and volume. 6. Rig up circulation manifold to tubing and Outer Annulus (OA). Pressure test same. Page 3 of 5 Note: 3-1/2” x 5-1/2” inner annulus will not be used for circulating as the leak site is in the 5-1/2” x 7” outer annulus. 7. Pressure test tubing and IA to 3000 psi and document results. Leave trapped pressure in both for the leak rate test. 8. Pressure test OA at three pressure intervals (1000 psi, 2000 psi, and 3300 psi) and measure leak rate at each interval. Record the volume to pressure up and volume to maintain pressure. 9. Bleed all pressures in preparation for circulating the well with brine. 10. Report leak rate data to office for evaluation and consent to proceed with the leak repair. Intended Repair Procedure 11. RIH and pull dummy GLV from SPM at 8300’ MD. If necessary, install circulation orifice (no check) to reduce SPM washout. 12. Circulate 9.6 ppg NaCl down tubing taking OA returns until all diesel has been removed and measured OA returns density = 9.6 ppg or heavier. 13. Load tubing with 30 bbls of diesel to create an underbalance that will be used to suck sealant into OA. 14. Rig up OA suction lines to Seal-Tite sealant blending tanks. 15. Using COP blending tank trailer, blend two 2.5 bbls batches of Flo-Seal pressure- activated sealant with fresh water. Each batch containing 15 Gals FS, 2.5 Gals Binder, and 90 Gals of 8.6 ppg ISW. 16. Slowly bleed and regulate diesel from the tubing until 5 bbls of sealant has been introduced to the OA. Sealant will be designed to float on the annulus fluid which equates to 560’ sealant column in the upper annulus. 17. Pump and displace sealant pill with 56 bbls of ISW followed by 18 bbls of diesel (freeze protect) into the OA taking brine returns from the tubing to spot the leading edge of sealant @ 8257’ WLM (end of 5-1/2” tieback string). 18. Slickine RIH and pull circulation valve from SPM @ 8300’ MD. Reinstall dummy GLV in same. 19. Perform MIT-T to 3000 psi to confirm dummy GLV integrity. Page 4 of 5 20. Slickline RIH and pull XX plug from nipple @ 8392’ MD. This will allow COP to bullhead diesel into the tubing for freeze protection. 21. Slickline RIH and set plug in nipple below the production packer. Pressure test the tubing and IA to 3000 psi. 22. Pressurize OA with diesel in 1000 psi increments and hold for 30 minutes at each step until reaching 3300 psi to squeeze sealant through the leak site and seal the leak. 23. Shut in OA test pressure of 3300 psi for a minimum of 2 hours to allow the sealant to cure. 24. Perform 3 pressure cycles from 0 psi to 3300 psi to verify the seal durability. Document fluid volume in and out. 25. Shut in OA test pressure of 3300 psi and allow seal to cure for 24 hours. 26. Bleed OA to 300 psi. Note: Recommendation is to leave the sealant in the Outer annulus across the leak site with 300 psi applied pressure for monitoring purposes. 27. Put well back on injection and monitor until at normal injection rate. 28. Rig down equipment and turn well over to COP. END – Chris Anderson Page 5 of 5 Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag:RKB (Est.12' of Rathole) 8,952.0 1B-07 6/9/2018 zembaej Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Set XX Plug 1B-07 10/19/2024 bworthi1 Notes: General & Safety Annotation End Date Last Mod By NOTE: View Schematic w/ Alaska Schematic9.0 8/6/2010 ninam 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 16 15.06 29.3 80.0 80.0 62.50 H-40 WELDED SURFACE 10 3/4 9.95 29.3 2,845.6 2,632.9 45.50 K-55 BTC Tie-Back String Production Repair 7 6.28 27.3 1,927.0 1,847.5 26.00 L-80 HYD 563 Production 7 6.28 1,924.0 9,569.9 6,933.8 26.00 K-55 BTC Tie-Back String 5 1/2 4.95 0.0 8,451.2 6,202.9 15.50 L-80 HYD 563 Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 23.3 Set Depth … 8,269.5 Set Depth … 6,066.5 String Max No… 3 1/2 Tubing Description Tubing – Completion Upper Wt (lb/ft) 9.30 Grade L-80 Top Connection HYD 563 ID (in) 2.99 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) 23.3 23.3 0.00 Hanger 7.010 Cameron 7 1/16" x 3 1/2" CXS Tubing Hanger. EUE top thread. Camero n CXS 2.950 1,989.4 1,902.9 27.89 Nipple - X 4.272 3 1/2" x 2.813" X Nipple, HES X Nipple 2.813 8,170.3 5,990.7 40.07 Mandrel – GAS LIFT 4.733 3 1/2" x 1" KBG-2-9 GLM SLB KBG-2-9 2.818 8,228.1 6,034.9 40.14 Nipple - X 4.287 3 1/2" x 2.813" X Nipple, 8 HES X Nipple 2.813 8,249.2 6,051.1 40.25 Locator 4.500 Locator Baker Locator 2.992 8,249.7 6,051.4 40.25 Seal Assembly 3.500 80-40 GBH-22 Seal Assy (6' space out off No-Go) Baker GBH-22 2.992 Top (ftKB) 8,448.0 Set Depth … 8,786.4 Set Depth … 6,443.8 String Max No… 3 1/2 Tubing Description Tubing – Completion Lower Wt (lb/ft) 9.30 Grade L-80 Top Connection EUE8RDMOD ID (in) 2.99 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) 8,469.9 6,216.7 42.70 PBR 5.875 BAKER PBR w/ 10' STROKE 3.000 8,483.8 6,226.9 42.84 PACKER 6.062 PACKER FHL RETRIEVABLE PACKER 2.890 8,528.8 6,259.7 43.29 INJECTION 5.750 Camco MMM 2.920 8,574.7 6,293.0 43.75 BLAST JTS 3.500 STEEL BLAST JOINTS (OAL=147') 2.992 8,740.4 6,411.3 45.05 SLEEVE 3.250 CB-1 SLIDING SLEEVE Camco 2.260 8,753.0 6,420.2 45.15 XO Reducing 3.500 CROSSOVER 3.5 x 2.875", ID 2.441, 6.5#, J-55, EUE IPC 2.875 8,753.8 6,420.8 45.15 SEAL ASSY 3.250 LOCATOR SEAL ASSEMBLY Baker 2.375 8,755.8 6,422.3 45.17 PACKER 5.687 D PACKER Baker 3.260 8,774.6 6,435.5 45.31 NIPPLE 3.668 OTIS XN NIPPLE NO GO 2.250 8,785.8 6,443.4 45.39 SOS 3.750 SHEAR OUT SUB (SHEARED) Baker 2.441 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 25.3 25.3 0.00 EMERGENCY SLIPS 5 1/2" Tieback Emergency Slips Cameron 9/2/2024 5.500 27.3 27.3 0.00 EMERGENCY SLIPS Custom McEvoy Type SB-3 Emergency Slips 8/19/2024 7.000 8,300.0 6,089.7 40.50 OTHER 3 1/2" x 1 1/2" MMG, GLM, DMY w/ RK Latch, SN# 24135 -06 8/31/2024 2.920 8,391.7 6,158.8 41.88 TUBING PLUG 2.81" XX PLUG, OAL 47" 10/19/2024 0.000 9,022.0 6,600.8 51.61 FISH Slip f/ Slip stop LOST 8/1/1993 8/31/1993 0.000 9,022.0 6,600.8 51.61 FISH TIW PKR & Tbg Tail LOST 6/16/1994 6/16/1994 0.000 9,046.0 6,615.6 51.73 FISH Vann Gun 428' long GUN LOST 9/20/1981 9/20/1981 0.000 Mandrel Inserts : excludes pulled inserts Top (ftKB) Top (TVD) (ftKB) Top Incl (°) St ati on No /S Serv Valve Type Latch Type OD (in) TRO Run (psi) Run Date Com Make Model Port Size (in) 8,170.3 5,990.7 40.07 1 GAS LIFT DMY BTM 1 9/7/2024 8,528.8 6,259.7 43.29 3 INJ DMY TGP 0.0 6/16/1994 0.000 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) 0.0 0.0 0.00 Parker 141 ORKB = 25.3', Nordic 3 RKB = 27.41' 0.000 Parker 141 ORKB = 25.3', Nordic 3 RKB = 27.41' 0.000 8,257.5 6,057.4 40.29 SBR 5.020 80-40 SBR, 5" P x 4 1/2" B HYD521 P (SN#: HT- 965205 SN01) Baker 80-40 SBR 4.000 1B-07, 10/20/2024 6:04:05 AM Vertical schematic (actual) Production; 1,924.0-9,569.9 FLOAT SHOE; 9,568.2-9,569.9 FLOAT COLLAR; 9,471.9- 9,473.6 FISH; 9,046.0 FISH; 9,022.0 FISH; 9,022.0 IPERF; 8,922.0-8,940.0 IPERF; 8,904.0-8,914.0 SOS; 8,785.8 NIPPLE; 8,774.6 PACKER; 8,755.8 SEAL ASSY; 8,753.8 SLEEVE; 8,740.3 IPERF; 8,695.0-8,702.0 IPERF; 8,670.0-8,686.0 IPERF; 8,575.0-8,650.0 INJECTION; 8,528.7 PACKER; 8,483.8 PBR; 8,469.9 Tie-Back String; 0.0-8,451.2 Overshot; 8,444.4-8,451.2 TUBING PLUG; 8,391.7 Nipple - X; 8,391.7-8,393.3 Packer; 8,360.2-8,366.4 ECP; 8,340.8-8,348.9 OTHER; 8,300.0 Mandrel – GAS LIFT; 8,300.0- 8,308.8 Tubing - XO reducing; 8,280.4- 8,290.1 SBR; 8,257.5-8,277.2 Locator; 8,249.2 Mandrel – GAS LIFT; 8,170.3 Annular Fluid - Saltwater/Brine; 2,500.0-8,445.0; 9/1/2024 Annular Fluid - Saltwater/Brine; 2,500.0-8,250.5; 9/1/2024 DV CASING TOOL; 5,236.0- 5,240.2 SURFACE; 29.3-2,845.6 FLOAT SHOE; 2,843.7-2,845.6 FLOAT COLLAR; 2,755.8- 2,757.7 Tie-Back String Production Repair ; 27.3-1,927.0 Collar - Stage; 1,910.4-1,913.5 Annular Fluid - Diesel; 27.3- 2,500.0; 9/1/2024 Annular Fluid - Diesel; 25.3- 2,500.0; 9/2/2024 Intermediate String 1 Cement; 28.3 ftKB CONDUCTOR; 29.3-80.0 HANGER; 29.3-33.7 EMERGENCY SLIPS; 27.3 EMERGENCY SLIPS; 25.3 Hanger; 23.3 KUP INJ KB-Grd (ft) 32.48 RR Date 9/20/1981 Other Elev… 1B-07 ... TD Act Btm (ftKB) 9,625.0 Well Attributes Field Name KUPARUK RIVER UNIT Wellbore API/UWI 500292061600 Wellbore Status INJ Max Angle & MD Incl (°) 61.00 MD (ftKB) 4,200.00 WELLNAME WELLBORE1B-07 Annotation Last WO: End Date 6/16/1994 H2S (ppm) DateComment SSSV: WRDP 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) 8,300.0 6,089.7 40.50 Mandrel – GAS LIFT 5.906 3 1/2" x 1 1/2" MMG, GLM, DMY w/ RK Latch, SN# 24135-06 SLB MMG 2.920 8,360.2 6,135.2 41.40 Packer 5.995 3 1/2" x 7" Bluepack Max RH Packer, VamTop, SN# C23P-1919 SLB Bluepack Packer 2.894 8,391.7 6,158.8 41.88 Nipple - X 4.287 3 1/2" x 2.813" X Nipple HES X Nipple 2.813 8,444.4 6,197.9 42.44 Overshot 5.990 7 x 3 1/2" PBOS (6.19' swallow, shear pins @ 3', 3' space out) Baker Poorboy Overshot 3.630 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 8,575.0 8,650.0 6,293.3 6,347.1 D, C-2, C-3, C-4, 1B-07 11/23/1981 4.0 IPERF Max angle across perf 44 8,670.0 8,686.0 6,361.4 6,372.8 C-1, UNIT B, 1B- 07 11/23/1981 4.0 IPERF 8,695.0 8,702.0 6,379.2 6,384.2 UNIT B, 1B-07 11/23/1981 4.0 IPERF 8,880.0 8,894.0 6,508.6 6,518.1 A-5, 1B-07 11/23/1981 4.0 IPERF 8,904.0 8,914.0 6,524.8 6,531.6 A-4, 1B-07 11/23/1981 4.0 IPERF 8,922.0 8,940.0 6,536.9 6,548.8 A-4, 1B-07 11/23/1981 4.0 IPERF Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 28.3 2,000.0 28.3 1,912.2 Intermediate String 1 Cement 8/19/2024 1B-07, 10/20/2024 6:04:06 AM Vertical schematic (actual) Production; 1,924.0-9,569.9 FLOAT SHOE; 9,568.2-9,569.9 FLOAT COLLAR; 9,471.9- 9,473.6 FISH; 9,046.0 FISH; 9,022.0 FISH; 9,022.0 IPERF; 8,922.0-8,940.0 IPERF; 8,904.0-8,914.0 SOS; 8,785.8 NIPPLE; 8,774.6 PACKER; 8,755.8 SEAL ASSY; 8,753.8 SLEEVE; 8,740.3 IPERF; 8,695.0-8,702.0 IPERF; 8,670.0-8,686.0 IPERF; 8,575.0-8,650.0 INJECTION; 8,528.7 PACKER; 8,483.8 PBR; 8,469.9 Tie-Back String; 0.0-8,451.2 Overshot; 8,444.4-8,451.2 TUBING PLUG; 8,391.7 Nipple - X; 8,391.7-8,393.3 Packer; 8,360.2-8,366.4 ECP; 8,340.8-8,348.9 OTHER; 8,300.0 Mandrel – GAS LIFT; 8,300.0- 8,308.8 Tubing - XO reducing; 8,280.4- 8,290.1 SBR; 8,257.5-8,277.2 Locator; 8,249.2 Mandrel – GAS LIFT; 8,170.3 Annular Fluid - Saltwater/Brine; 2,500.0-8,445.0; 9/1/2024 Annular Fluid - Saltwater/Brine; 2,500.0-8,250.5; 9/1/2024 DV CASING TOOL; 5,236.0- 5,240.2 SURFACE; 29.3-2,845.6 FLOAT SHOE; 2,843.7-2,845.6 FLOAT COLLAR; 2,755.8- 2,757.7 Tie-Back String Production Repair ; 27.3-1,927.0 Collar - Stage; 1,910.4-1,913.5 Annular Fluid - Diesel; 27.3- 2,500.0; 9/1/2024 Annular Fluid - Diesel; 25.3- 2,500.0; 9/2/2024 Intermediate String 1 Cement; 28.3 ftKB CONDUCTOR; 29.3-80.0 HANGER; 29.3-33.7 EMERGENCY SLIPS; 27.3 EMERGENCY SLIPS; 25.3 Hanger; 23.3 KUP INJ 1B-07 ... WELLNAME WELLBORE1B-07 C:\Users\grgluyas\AppData\Local\Microsoft\Windows\INetCache\Content.Outlook\R97USUAM\KRU_1B-07_25Oct24_VividSealAcousticLeakDetectLog_Transmittal.docx DELIVERABLE DISCRIPTION Ticket # Field Well # API # Log Description Log Date 22195 KRU 1B-07 50-029-20616-00 Vivid Seal Acoustic Leak Detect Log 25Oct24 DELIVERED TO Company & Address DIGITAL FILE # of Copies LOG PRINTS # of Prints CD’s # of Copies 1 AOGCC Attn: Natural Resources Technician 333 W. 7th Ave., Suite 100 Anchorage, Ak. 99501-3539 Delivered By: CPAI Sharefile ______________________________ _____________________________________ Date received Signature ______________________________ ______________________________________ PLEASE RETURN COPY VIA EMAIL TO: DIANE.WILLIAMS@READCASEDHOLE.COM READ CASED HOLE, INC., 4141 B STREET, SUITE 308, ANCHORAGE, AK 99503 PHONE: (907)245-8951 E-MAIL : READ-Anchorage@readcasedhole.com WEBSITE : WWW.READCASEDHOLE.COM 181-089 T39750 11/6/2024 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.11.06 08:10:42 -09'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Replace Tubing Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 9625'feet 8392'feet true vertical 6968' feet 9022', 9046'feet Effective Depth measured 8392'feet 8360', 8484', 8756'feet true vertical 6159'feet 6135', 6227', 6422'feet Perforation depth Measured depth True Vertical depth Tubing (size, grade, measured and true vertical depth) 3-1/2" 3-1/2" L-80 L-80 8270' 8786' 6067' 6444' Packers and SSSV (type, measured and true vertical depth)8360' 8484' 8756' 6135' 6227' 6422' 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: Kuparuk Oil Pool 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Contact Phone: 2846' 2633' Burst Collapse Tie-Back String Repair Tie Back 7646' 1900' Casing 6934' 1848' 9570' 1927' 8451' 6203' 2817' 80'Conductor Surface Production 16" 10-3/4" 51' measured TVD 7" 7" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 181-089 50-029-20616-00-00 P.O. Box 100360 Anchorage, AK 99510 3. Address: ConocoPhillips Alaska, Inc. N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0025648 Kuparuk River Field/ Kuparuk Oil Pool KRU 1B-07 Plugs Junk measured Length measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) N/A Gas-Mcf MDSize 80' Well Shut-In 324-295/324-498 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Packer: Blue Pack Packer: FHL Retrievable Packer: D Packer SSSV: None Cy Eller cy.eller@conocophillips.com (907) 265-6049 8575-8650',8670-8686', 8695-8702', 8880-8894', 8904-8914', 8922-8940' 6293-6347, 6361-6373', 6379-6384', 6509-6518', 6525-6532', 6537-6549' 8451' 5-1/2" Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov RWO/CTD Engineer By Grace Christianson at 11:37 am, Oct 01, 2024 Page 1/19 1B-07 Report Printed: 9/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 8/13/2024 12:00 8/13/2024 13:00 1.00 MIRU, MOVE MOB P Pull mats off of 1B-04. Clean up around well. Get environmental handover signed. 0.0 0.0 8/13/2024 13:00 8/13/2024 16:00 3.00 MIRU, MOVE MOB P Hang tree in cellar for 1B-07. Lay herculite & rig mats. Spot well head equipment behind cellar. 0.0 0.0 8/13/2024 16:00 8/13/2024 18:00 2.00 MIRU, MOVE MOB P Pull rig over well. Center & level rig. 0.0 0.0 8/13/2024 18:00 8/13/2024 20:00 2.00 MIRU, MOVE MOB P Berm in cellar. Spot cuttings tank. Move in support equipment mud shack & smoke shack. R/T tiger tank hand line. Safe out rig. Complete rig acceptance checklist. Attempt to open SSV. Would not open completely. Initial pressures T/I/O =, 700/700/0 Rig accepted @ 20:00 Hrs 0.0 0.0 8/13/2024 20:00 8/13/2024 22:30 2.50 MIRU, WELCTL COND P Take on 8.5 PPG seawater into pits. Build 35 Bbls heated vis deep clean pill. R/U circ manifold. Attempt to pump open SSV (only opened part way.) Called valve crew out to open valve could not get any further movement. Decision made to proceed w/ well kill. 0.0 0.0 8/13/2024 22:30 8/13/2024 23:00 0.50 MIRU, WELCTL PRTS P Purge circ hoses & tiger tank. PT circ & tiger tank lines T/ 3000 PSI. 0.0 0.0 8/13/2024 23:00 8/13/2024 23:30 0.50 MIRU, WELCTL WAIT P Wait on remaining seawater. 0.0 0.0 8/13/2024 23:30 8/14/2024 00:00 0.50 MIRU, WELCTL KLWL P Bleed free gas off TBG F/ 700 T/ 200. Bleed free gas off IA F/ 100 T/ 60. 0.0 0.0 8/14/2024 00:00 8/14/2024 02:45 2.75 MIRU, WELCTL KLWL P Kill well pumping 31 Bbls heated vis deep clean pill followed by 400 Bbls 8.5 PPG seawater. Clean 8.5 PPG returns to surface. 0.0 0.0 8/14/2024 02:45 8/14/2024 03:30 0.75 MIRU, WELCTL OWFF P OWFF - TBG dead. IA sputtered to nothing. 30 Min no flow 0.0 0.0 8/14/2024 03:30 8/14/2024 04:00 0.50 MIRU, WELCTL MPSP P Set HP BPV 0.0 0.0 8/14/2024 04:00 8/14/2024 04:30 0.50 MIRU, WELCTL PRTS P PT BPV from below T/ 1000 PSI for 10 Min. OA starting PSI = 20, At 1000 PSI on IA. OA PSI = 60. Stayed at 60 PSI throughout 10 Min test. After bleeding pressure off OA dropped back down to 20 PSI. 0.0 0.0 8/14/2024 04:30 8/14/2024 05:00 0.50 MIRU, WHDBOP RURD P B/D, RD circ equipment & tiger tank line. 0.0 0.0 8/14/2024 05:00 8/14/2024 06:30 1.50 MIRU, WHDBOP NUND P ND tree. Inspect hanger threads - Good. Thread 3 1/2 EUE 7 1/2 turns by hand. Function LDS's. Install test dart. 0.0 0.0 8/14/2024 06:30 8/14/2024 09:00 2.50 MIRU, WHDBOP NUND P NU 7 1/16 X 11" DSA. NU BOP stack. Install riser. Obtain new RKB's. Hook up trip tank 0.0 0.0 8/14/2024 09:00 8/14/2024 11:00 2.00 MIRU, WHDBOP OTHR P C/O lower pipe rams to 7" fixed rams 0.0 0.0 8/14/2024 11:00 8/14/2024 12:30 1.50 MIRU, WHDBOP BOPE T Fill stack purge air. Outer CPAI test spool 2 1/16 valve leaking by. Replace outer test spool valve 0.0 0.0 8/14/2024 12:30 8/14/2024 13:00 0.50 MIRU, WHDBOP BOPE T Fill stack / Purge air. Begin shell test on BOPE. Leak on kill HCR stem. 0.0 0.0 Rig: NORDIC 3 RIG RELEASE DATE 9/2/2024 Page 2/19 1B-07 Report Printed: 9/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 8/14/2024 13:00 8/14/2024 22:30 9.50 MIRU, WHDBOP BOPE P Change out kill HCR. Fill stack, Purge air. Shell test BOPE, Initial BOPE test, Tested BOPE at 250/3000 PSI for 5 Min each, Tested annular w/ 3 1/2 & 7" test joint. , UVBR's W/ 3 ½ test joint. Test LPR w/7" test joint. Test blinds rams. Choke valves #1 to #13, upper and lower top drive well control valves. Test 3 1/2" IF FOSV and IBOP. Test 3 ½ & 4 ½ EUE FOSV. Test 2" rig floor Demco kill valve MM #13. Test manual and HCR kill valves & manual and HCR choke valves. Test two ea 2 1/6" gate auxiliary valves below LPR. Test hydraulic and manual choke valves to 1500 PSI and demonstrate bleed off. Perform accumulator test. Initial pressure=3025 PSI, after closure=1600 PSI, 200 PSI attained =21 sec, full recovery attained =127 sec. UVBR's= 5 sec, Simulated LVBRs= 5 sec. Annular= 24 sec. Simulated blinds= 5 sec. HCR choke & kill= 1 sec each. 4 back up nitrogen bottles average =2025 PSI. Test gas detectors, PVT and flow show. Witness waived by AOGCC rep Adam Earl 0.0 8/14/2024 22:30 8/14/2024 23:00 0.50 MIRU, WHDBOP RURD P B/D, R/D testing equipment, Suck out stack. 0.0 0.0 8/14/2024 23:00 8/14/2024 23:15 0.25 MIRU, WHDBOP MPSP P Pull test dart & BPV. 0.0 0.0 8/14/2024 23:15 8/15/2024 00:00 0.75 COMPZN, RPCOMP PULL P M/U landing joint. K/U. Set 10K down. BOLDS. Pull hanger off seat. Pipe free @ 120K. Pull hanger to RF. PUW=105K. 8,448.0 8,415.0 8/15/2024 00:00 8/15/2024 01:15 1.25 COMPZN, RPCOMP CIRC P Circ STS @ 5 BPM, 460 PSI. Dumping contaminated fluid at surface. 8,415.0 8,415.0 8/15/2024 01:15 8/15/2024 01:45 0.50 COMPZN, RPCOMP PULD P L/D landing joint & hanger. B/D TD. OWFF - No flow. 8,415.0 8,415.0 8/15/2024 01:45 8/15/2024 09:30 7.75 COMPZN, RPCOMP PULL P L/D 3 1/2" completion F/ 8415', PUW=105K. Recovered 271 Jts, GLM w/2 pups, 14.72' cut joint 8,415.0 0.0 8/15/2024 09:30 8/15/2024 11:30 2.00 COMPZN, RPCOMP ELNE P E-line spotted up. Start rigging up. 0.0 0.0 8/15/2024 11:30 8/15/2024 12:30 1.00 COMPZN, RPCOMP ELNE P Trip in hole on E-line W/ CBL, CCL, Gamma tool 0.0 2,800.0 8/15/2024 12:30 8/15/2024 14:00 1.50 COMPZN, RPCOMP ELOG P 2800', Log up CBL, CCL to surface, 40 FPM, PUW=500Lbs 2,800.0 0.0 8/15/2024 14:00 8/15/2024 14:30 0.50 COMPZN, RPCOMP ELNE P At surface. Lay down tools send logs to town for interpretation. 0.0 0.0 8/15/2024 14:30 8/15/2024 15:00 0.50 COMPZN, RPCOMP ELNE P M/U Baker IBP to e-line 0.0 28.4 8/15/2024 15:00 8/15/2024 15:30 0.50 COMPZN, RPCOMP ELNE P RIH W/IBP 28.4 1,700.0 8/15/2024 15:30 8/15/2024 18:00 2.50 COMPZN, RPCOMP ELNE T CCL Tool lost power, POOH to trouble shoot. Tool started working @ 500' RIH. Continue in to 1100' tool failed. POOH. . Check E-line head. Call out back up CCL tool from baker 900.0 0.0 8/15/2024 18:00 8/15/2024 20:15 2.25 COMPZN, RPCOMP ELOG P RIH w/ IBP past set depth. Confirm CCL matched original run. Inflate IBP @ 2300'' COE. Top of IBP @ 2293'. BTM of IBP @ 2304'. Good indication of IBP sheared off. 0.0 2,304.0 Rig: NORDIC 3 RIG RELEASE DATE 9/2/2024 Page 3/19 1B-07 Report Printed: 9/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 8/15/2024 20:15 8/15/2024 20:45 0.50 COMPZN, RPCOMP ELNE P POOH. At surface. Stand back E-Line. 2,304.0 0.0 8/15/2024 20:45 8/15/2024 21:00 0.25 COMPZN, RPCOMP PRTS P PT IBP T/ 1000 PSI for 10 Min. Total .4 Bbls pumped. Release E-line. 0.0 0.0 8/15/2024 21:00 8/15/2024 21:15 0.25 COMPZN, RPCOMP RURD P B/D, R/D testing equipment. 0.0 0.0 8/15/2024 21:15 8/15/2024 21:30 0.25 COMPZN, RPCOMP ELNE P R/D & release E-line. 0.0 0.0 8/15/2024 21:30 8/15/2024 22:00 0.50 COMPZN, RPCOMP RURD P R/U DP handling equipment. 0.0 0.0 8/15/2024 22:00 8/15/2024 22:15 0.25 COMPZN, RPCOMP BHAH P M/U BHA #1 mule shoe T/ 4' 0.0 4.0 8/15/2024 22:15 8/15/2024 23:00 0.75 COMPZN, RPCOMP TRIP P RIH F/ 4' T/ 2195', PUW=70K, SOW=65K. 4.0 2,195.0 8/15/2024 23:00 8/16/2024 00:00 1.00 COMPZN, RPCOMP RURD P R/U circ equipment & sand hopper for dumping sand. 2,195.0 2,195.0 8/16/2024 00:00 8/16/2024 06:00 6.00 COMPZN, RPCOMP CIRC P Circ down DP through hopper w/ charge pump. Dumping 25 bags of sand = ~65'. Pulling returns from test spool with chugger pump. LRS heat truck load of seawater T/ 140*. 2,195.0 2,195.0 8/16/2024 06:00 8/16/2024 07:00 1.00 COMPZN, RPCOMP OTHR P 25 bags of sand dumped, Let sand settle 2,195.0 2,195.0 8/16/2024 07:00 8/16/2024 08:00 1.00 COMPZN, RPCOMP TRIP P Trip in hole to light tag @ 2232 2,195.0 2,232.0 8/16/2024 08:00 8/16/2024 08:30 0.50 COMPZN, RPCOMP TRIP P Trip out of well, PUW=73K 2,232.0 0.0 8/16/2024 08:30 8/16/2024 08:42 0.20 COMPZN, RPCOMP OWFF P Observe well for flow 0.0 0.0 8/16/2024 08:42 8/16/2024 10:30 1.80 COMPZN, RPCOMP NUND P Nipple down BOPE 0.0 0.0 8/16/2024 10:30 8/16/2024 11:00 0.50 COMPZN, RPCOMP NUND P Nipple down tubing head 0.0 0.0 8/16/2024 11:00 8/16/2024 12:30 1.50 COMPZN, RPCOMP RURD P Rig up Cameron grow and stretch 0.0 0.0 8/16/2024 12:30 8/16/2024 14:30 2.00 COMPZN, RPCOMP OTHR P Apply pressure to jacks applying down force to tubing head. Two lock down screws seized. Consult with M. Adams and DHD. Pull gland nuts. Lubricate and work. Get LDS loose 0.0 0.0 8/16/2024 14:30 8/16/2024 16:00 1.50 COMPZN, RPCOMP OTHR P Start growing 7 " casing. 5 cycles. total growth 25.875" 0.0 0.0 8/16/2024 16:00 8/16/2024 17:00 1.00 COMPZN, RPCOMP OTHR P R/D Cameron grow and stretch equipment, Remove TBG head. 0.0 0.0 8/16/2024 17:00 8/16/2024 17:15 0.25 COMPZN, RPCOMP BHAH P M/U BHA #2 7" spear. Engage 7". 0.0 0.0 8/16/2024 17:15 8/16/2024 17:45 0.50 COMPZN, RPCOMP CUTP P Pull 100K tension over blocks. 13" of stretch. OAL growth 38.875". Set 11" x 7" emergency slips. 0.0 0.0 8/16/2024 17:45 8/16/2024 18:00 0.25 COMPZN, RPCOMP BHAH P L/D BHA #2 spear. 0.0 0.0 8/16/2024 18:00 8/16/2024 19:45 1.75 COMPZN, RPCOMP CUTP P Cut 7" w/ WHACKS saw. Install pack off. RILDS. 0.0 0.0 8/16/2024 19:45 8/17/2024 00:00 4.25 COMPZN, RPCOMP NUND P N/U DSA & BOP. Install flow nipple. Connect trip hose. 0.0 0.0 8/17/2024 00:00 8/17/2024 00:30 0.50 COMPZN, RPCOMP BHAH P M/U BHA #2- 5 5/8" MSC T/ 5'. 0.0 5.0 8/17/2024 00:30 8/17/2024 01:30 1.00 COMPZN, RPCOMP TRIP P RIH F/ 5' T/ 2030'. PUW=65K, SOW=60K. 5.0 2,030.0 Rig: NORDIC 3 RIG RELEASE DATE 9/2/2024 Page 4/19 1B-07 Report Printed: 9/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 8/17/2024 01:30 8/17/2024 03:30 2.00 COMPZN, RPCOMP SLPC P Cut & slip 66' of drill line. 2,030.0 2,030.0 8/17/2024 03:30 8/17/2024 04:00 0.50 COMPZN, RPCOMP SFTY P Crew change out. Welcome back meeting. 2,030.0 2,030.0 8/17/2024 04:00 8/17/2024 05:00 1.00 COMPZN, RPCOMP CPBO P Obtain ROT parameters. 80 RPM, 1.1K free Tq. ROT=60K. P/U T/ 1981'. Pump @ 1 BPM, 82 PSI. Pump @ 5 BPM, 1030 PSI. Locate collar @ 1995.5'' pumping 1 BPM. P/U T/ 1949'. Locate collar @ 1954' pumping 1 BPM.. P/U T/ 1924', Cut CSG @ 1924', Pump 5 BPM, ROT 80 RPM. 2K Tq dropped T/ 1.1K. 160 PSI on OA. CSG cut. 2,030.0 1,924.0 8/17/2024 05:00 8/17/2024 06:30 1.50 COMPZN, RPCOMP DISP P P/U T/ 1921', close in annular. Disp arctic pack out OA w/ hot seawater @ 3 BPM. ICP=330. FCP=425PSI 1,924.0 1,924.0 8/17/2024 06:30 8/17/2024 06:45 0.25 COMPZN, RPCOMP OWFF P Shut down, OWFF, 1,924.0 1,924.0 8/17/2024 06:45 8/17/2024 07:00 0.25 COMPZN, RPCOMP CIRC P Pump last 20 BBls off truck 3BPM @ 425 PSI. Returns clean 1,924.0 1,924.0 8/17/2024 07:00 8/17/2024 08:00 1.00 COMPZN, RPCOMP TRIP P Trip out F/1924 to BHA, Lay down cutter 1,924.0 0.0 8/17/2024 08:00 8/17/2024 08:30 0.50 COMPZN, RPCOMP OWFF P Flow check well. / PJSM nipple down stack 0.0 0.0 8/17/2024 08:30 8/17/2024 09:30 1.00 COMPZN, RPCOMP NUND P Drain stack, Deflate air boot. Break stack at well head 0.0 0.0 8/17/2024 09:30 8/17/2024 10:30 1.00 COMPZN, RPCOMP WWSP P M/U BHA #3 spear. Spear in to 7" casing. P/U 80K, Pull casing slips, Pull casing pack off. Release spear from casing. Pull spear to floor 0.0 0.0 8/17/2024 10:30 8/17/2024 12:30 2.00 COMPZN, RPCOMP NUND P Nipple up stack, Set riser. Set air boot. R/U GBR for 7" casing pull 0.0 0.0 8/17/2024 12:30 8/17/2024 13:00 0.50 COMPZN, RPCOMP PULL P RIH w/ spear. Spear 7" casing. Pull to floor. PUW=80K Disengage spear and lay down BHA #3. 0.0 0.0 8/17/2024 13:00 8/17/2024 14:30 1.50 COMPZN, RPCOMP PULL P Reconfigure FOSV. Pull 7" casing string from cut @ 1924 1,924.0 1,524.0 8/17/2024 14:30 8/17/2024 15:30 1.00 COMPZN, RPCOMP PULL T Breaking pins on tongs. Change out tong 1,524.0 1,524.0 8/17/2024 15:30 8/17/2024 16:45 1.25 COMPZN, RPCOMP PULL P Continue pulling 7" casing 1524' T/ 725'. 1,524.0 725.0 8/17/2024 16:45 8/17/2024 17:15 0.50 COMPZN, RPCOMP SVRG P Service rig. Adjust link tilt bails. 725.0 725.0 8/17/2024 17:15 8/17/2024 19:15 2.00 COMPZN, RPCOMP PULL P L/D 7" CSG F/ 725' T/ surface. 46 full joints & 12.6' cut joint. Cut was flared T/ 7 5/8". 725.0 0.0 8/17/2024 19:15 8/17/2024 20:30 1.25 COMPZN, RPCOMP CLEN P Clean & clear RF & pipe shed. 0.0 0.0 8/17/2024 20:30 8/17/2024 21:30 1.00 COMPZN, RPCOMP RURD P R/D GBR casing equipment. Send CSG tongs off of rig. R/U DP handling equipment. 0.0 0.0 8/17/2024 21:30 8/17/2024 22:00 0.50 COMPZN, RPCOMP MPSP P Set 11" test plug. 0.0 0.0 8/17/2024 22:00 8/17/2024 22:30 0.50 COMPZN, RPCOMP RURD P R/U testing equipment. Fill stack with fresh water. 0.0 0.0 8/17/2024 22:30 8/17/2024 23:00 0.50 COMPZN, RPCOMP PRTS P PT stack breaks and choke & kill breaks 250/3000 PSI for 5 min each. 0.0 0.0 8/17/2024 23:00 8/17/2024 23:30 0.50 COMPZN, RPCOMP RURD P B/D, R/D testing equipment. Suck out stack. 0.0 0.0 8/17/2024 23:30 8/18/2024 00:00 0.50 COMPZN, RPCOMP MPSP P Pull test plug. Set wear bushing. ID 10". 0.0 0.0 Rig: NORDIC 3 RIG RELEASE DATE 9/2/2024 Page 5/19 1B-07 Report Printed: 9/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 8/18/2024 00:00 8/18/2024 01:30 1.50 COMPZN, RPCOMP RURD P Mobilize BHA #4 to pipe shed & RF. Process DC's 0.0 0.0 8/18/2024 01:30 8/18/2024 02:54 1.40 COMPZN, RPCOMP BHAH P M/U BHA #4 tandem 8 1/2" mills T/ 130', SOW=40K. 0.0 130.0 8/18/2024 02:54 8/18/2024 03:00 0.10 COMPZN, RPCOMP TRIP P RIH F/ 130' T/ 225' 130.0 225.0 8/18/2024 03:00 8/18/2024 03:30 0.50 COMPZN, RPCOMP SVRG P Service rig. Adjust link tilt bails. 225.0 225.0 8/18/2024 03:30 8/18/2024 04:30 1.00 COMPZN, RPCOMP TRIP P RIH F/ 225' T/ 1923'', PUW=70K, SOW=65K. Clean drift. 225.0 1,923.0 8/18/2024 04:30 8/18/2024 05:30 1.00 COMPZN, RPCOMP DISP P P/U T/ 1920'. Displace well to vis seawater @ 8 BPM, 260 PSI, Blow down top drive 1,923.0 1,920.0 8/18/2024 05:30 8/18/2024 06:30 1.00 COMPZN, RPCOMP RURD P Blow down top drive, Install wiper rubber, Swap fluid in trip tank 1,920.0 1,920.0 8/18/2024 06:30 8/18/2024 07:30 1.00 COMPZN, RPCOMP TRIP P Trip out 1920 to BHA 1,920.0 129.0 8/18/2024 07:30 8/18/2024 10:30 3.00 COMPZN, RPCOMP BHAH P Rack back 6 1/4" collars, Lay down balance of BHA, Load out BHA #4 down slide. Clear and clear rig floor, M/U BHA #5 Pilot mill 129.0 121.0 8/18/2024 10:30 8/18/2024 11:00 0.50 COMPZN, RPCOMP SVRG P Inspect and lube top drive and draw works 121.0 121.0 8/18/2024 11:00 8/18/2024 12:00 1.00 COMPZN, RPCOMP TRIP P Clear and clear rig floor, Trip in BHA #5 121.0 1,885.0 8/18/2024 12:00 8/18/2024 13:30 1.50 COMPZN, RPCOMP MILL P 1885', KU, PUW=69L, SOW=64K, Dry tag top of 7" @ 1923 w/5K down. P/U, Pumps on =3.5 BPM @ 163 PSI, 60 RPM @ 1450 free torque. RIH see torque increase @ 1923. Mill 1 foot 1,885.0 1,924.0 8/18/2024 13:30 8/18/2024 14:00 0.50 COMPZN, RPCOMP CIRC P Circ BU 8 BPM @ 522 PSI, Blow down top drive 1,920.0 1,920.0 8/18/2024 14:00 8/18/2024 14:30 0.50 COMPZN, RPCOMP TRIP P Trip out of well T/BHA 1,920.0 121.0 8/18/2024 14:30 8/18/2024 15:00 0.50 COMPZN, RPCOMP BHAH P Lay down Pilot mill.5 121.0 0.0 8/18/2024 15:00 8/18/2024 16:00 1.00 COMPZN, RPCOMP BHAH P M/U BHA #6, Dress off assembly, Clean floor 0.0 130.0 8/18/2024 16:00 8/18/2024 16:45 0.75 COMPZN, RPCOMP TRIP P RIH F/ 130' T/ 1920', PUW=69K, SOW=64K. 130.0 1,920.0 8/18/2024 16:45 8/18/2024 17:45 1.00 COMPZN, RPCOMP MILL P Obtain parameters pump 1 BPM, 100 PSI. 3 BPM, 120 PSI. ROT @ 60 RPM, 1.5K free torque. ROT=65K. Wash & ream over top of stump @ 1924'. @ 3 BPM. PSI increase T/ 170. Tq 4-5K. WOB = 2-3K. T/ 1928'. P/U of stump wash over no Rot. Saw PSI increase F/ 120 T/ 170 when swallowing stump. Swallow T/ 1930'. PSI inches to 180 PSI. Repeated. P/U swallow no pump no rotation F/ 1924' T/ 1930'. 1,920.0 1,930.0 8/18/2024 17:45 8/18/2024 18:45 1.00 COMPZN, RPCOMP CIRC P P/U T/ 1920. Circ STS @ 8 BPM, 270 PSI 1,930.0 1,920.0 8/18/2024 18:45 8/18/2024 19:30 0.75 COMPZN, RPCOMP TRIP P POOH F/ 1920' T/ 130'. PUW=69K. 1,920.0 130.0 8/18/2024 19:30 8/18/2024 21:00 1.50 COMPZN, RPCOMP BHAH P L/D BHA #6. 130.0 0.0 8/18/2024 21:00 8/18/2024 21:30 0.50 COMPZN, RPCOMP WWWH P Jet BOP stack. 0.0 0.0 8/18/2024 21:30 8/18/2024 22:00 0.50 COMPZN, RPCOMP RURD P Pull wear bushing. 0.0 0.0 8/18/2024 22:00 8/18/2024 23:15 1.25 COMPZN, RPCOMP CLEN P Clean & clear RF & pipe shed. 0.0 0.0 Rig: NORDIC 3 RIG RELEASE DATE 9/2/2024 Page 6/19 1B-07 Report Printed: 9/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 8/18/2024 23:15 8/19/2024 00:00 0.75 COMPZN, RPCOMP RURD P R/U GBR torque turn CSG equipment. Verify joint count & jewelry running order. 0.0 0.0 8/19/2024 00:00 8/19/2024 00:30 0.50 COMPZN, RPCOMP SFTY P PJSM w/ GBR & rig crew on running 7" tie back casing. 0.0 0.0 8/19/2024 00:30 8/19/2024 03:00 2.50 COMPZN, RPCOMP PUTB P Run 7", 26#, L-80 Hyd 563 tie back casing string swallowed CSG stump T/ 1927'. PUW=78K. SOW=70K. Set down 35K. P/U 50K over string weight. Good pull test on patch. Slack off to neutral. Set slips. Hyd 563 torque turned T/ 9400 Ft/lbs. Best 'O'Linfe Arctic grade dope used. Installed 23 total Arsenal 7" x 8,5" Centralizers on every other joint #1-#45. 0.0 1,927.0 8/19/2024 03:00 8/19/2024 03:45 0.75 COMPZN, RPCOMP RURD P M/U XO's on top of stump. R/U circ equipment. Purge circ hose. 1,927.0 1,927.0 8/19/2024 03:45 8/19/2024 04:00 0.25 COMPZN, RPCOMP PRTS P PT 7" casing patch T/ 2500 PSI for 10 Min. 1,927.0 1,927.0 8/19/2024 04:00 8/19/2024 04:45 0.75 COMPZN, RPCOMP RURD P B/D, R/D circ equipment. Break out XO's. Suck out stack. 1,927.0 1,927.0 8/19/2024 04:45 8/19/2024 06:00 1.25 COMPZN, RPCOMP NUND P N/D BOP stack, split & lift. 1,927.0 1,927.0 8/19/2024 06:00 8/19/2024 07:30 1.50 COMPZN, RPCOMP NUND P Install 11" x 7" custom SB-3 emergency slips. Nipple up stack TQ bolts 1,927.0 1,927.0 8/19/2024 07:30 8/19/2024 08:00 0.50 COMPZN, RPCOMP RURD P MIRU HES Cementers. P/U Cement head. Install on 7" casing. Load dart in lower station 1,927.0 1,927.0 8/19/2024 08:00 8/19/2024 08:12 0.20 COMPZN, RPCOMP SFTY P PJSM w/cementers. 1,927.0 1,927.0 8/19/2024 08:12 8/19/2024 09:12 1.00 COMPZN, RPCOMP DISP P Line uo OA to kill tank. Line up to pump 140 degree water down 7" to open ES cement valve. Valve opened @ 3200 PSI. 1,927.0 1,927.0 8/19/2024 09:12 8/19/2024 10:00 0.80 COMPZN, RPCOMP DISP P Line up returns to recover vis fluid to pits, Open LPRS Pump 140 BBls 140 degree water down 7 returns to pits. 5 BPM ICP=320 PSI FCP=285PSI 1,927.0 1,927.0 8/19/2024 10:00 8/19/2024 10:06 0.10 COMPZN, RPCOMP CMNT P HES Fill lines with 5 bbls fresh. S/D PT to 4000 PSI 1,927.0 1,927.0 8/19/2024 10:06 8/19/2024 11:00 0.90 COMPZN, RPCOMP CMNT P Online with 5 BBl fresh water w/ red dye. Initial cement wet @ 10;15. Online with 15.3 PPG cement down 7" returns out annulas to open top tank. ICP=784 @ 4 BBLs/Min. 1,927.0 1,927.0 8/19/2024 11:00 8/19/2024 11:15 0.25 COMPZN, RPCOMP CMNT P Red dye at open top tank, 185 BBls pumped, 4 BPM @ 802 PSI. Swap returns ro cuttings box 1,927.0 1,927.0 8/19/2024 11:15 8/19/2024 11:21 0.10 COMPZN, RPCOMP CMNT P 221.8 BBls cement pumped. Getting good 15.3 PPG Cement returns. Shut down cement. Launch dart. Pump 10 BBls fresh water tail. 1,927.0 1,927.0 8/19/2024 11:21 8/19/2024 12:00 0.65 COMPZN, RPCOMP CMNT P Rig pump take over displacing plug to ES valve. Slow to 2 BPM @ 55 BBLs in, Good 15.3 sample at OA. See plug bump @ 63 BBls / 1087 strokes. Pressure up to 2800 PSI. Bleed off. Knock line off cement head. Open up check for flow. None. No flow @ OH in cellar. 1,927.0 0.0 Rig: NORDIC 3 RIG RELEASE DATE 9/2/2024 Page 7/19 1B-07 Report Printed: 9/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 8/19/2024 12:00 8/19/2024 16:00 4.00 COMPZN, RPCOMP RURD P R/D cementers. Flush circ lines with contam pill. Blow down. R/U to pump contam pill down kill lineFlush all lines / BOPE. R/D cement head send down slide. Load and strap 57 Jts DP 0.0 0.0 8/19/2024 16:00 8/19/2024 17:00 1.00 COMPZN, RPCOMP NUND P PJSM, ND BOP stack, raise stack 0.0 0.0 8/19/2024 17:00 8/19/2024 18:30 1.50 COMPZN, RPCOMP CUTP P Set up Cameron equipment to cut 7" casing. Cut joint 18.12 0.0 0.0 8/19/2024 18:30 8/19/2024 20:30 2.00 COMPZN, RPCOMP NUND P Pull 7" out of stack. Rack back BOPE. Pull DSA, Set pack off. Install new new tubvig spool 0.0 0.0 8/19/2024 20:30 8/19/2024 21:00 0.50 COMPZN, RPCOMP PRTS P Test packoff 3000PSI / 15 min - Good 0.0 0.0 8/19/2024 21:00 8/20/2024 00:00 3.00 COMPZN, RPCOMP NUND P NU BOP stack. 0.0 0.0 8/20/2024 00:00 8/20/2024 00:30 0.50 COMPZN, RPCOMP MPSP P Set test plug. 0.0 0.0 8/20/2024 00:30 8/20/2024 01:30 1.00 COMPZN, RPCOMP NUND P Open LPR. Inspect for cement. Close LPR. 0.0 0.0 8/20/2024 01:30 8/20/2024 02:00 0.50 COMPZN, RPCOMP RURD P R/U testing equipment. Fill stack w/ fresh water. 0.0 0.0 8/20/2024 02:00 8/20/2024 02:30 0.50 COMPZN, RPCOMP PRTS P PT stack breaks T/ 250/3000 PSI. 0.0 0.0 8/20/2024 02:30 8/20/2024 02:45 0.25 COMPZN, RPCOMP RURD P B/D, R/D testing equipment. 0.0 0.0 8/20/2024 02:45 8/20/2024 03:00 0.25 COMPZN, RPCOMP MPSP P Pull test plug. 0.0 0.0 8/20/2024 03:00 8/20/2024 03:30 0.50 COMPZN, RPCOMP WWWH P Jet bop stack. 0.0 0.0 8/20/2024 03:30 8/20/2024 03:45 0.25 COMPZN, RPCOMP BOPE P Weekly function test of BOPE equipment. 0.0 0.0 8/20/2024 03:45 8/20/2024 04:15 0.50 COMPZN, RPCOMP RURD P Set wear bushing. ID = 6 7/16" 0.0 0.0 8/20/2024 04:15 8/20/2024 06:00 1.75 COMPZN, RPCOMP BHAH P M/U BHA #7 Roller cone bit T/ 214, SOW=42K. , 0.0 214.0 8/20/2024 06:00 8/20/2024 08:00 2.00 COMPZN, RPCOMP PULD P P/U DP F/ 214' T/ 1869', PUW=66K, SOW=61K. Tagged up on cement stringer. 214.0 1,869.0 8/20/2024 08:00 8/20/2024 12:00 4.00 COMPZN, RPCOMP DRLG P Obtain parameters. Pump @ 5 BPM, 300 PSI. Rot @ 90 RPM, 1.5K free Tq. ROT=63K. Wash & ream T/ plug top @ 1910'. Drill plug & cement down to sand top @ 2233'. WOB 5-10K. Tq =1.5-3K. Dry drill on sand top no pump 60 RPM, 1.8-2K Tq. P/U T/ 2158'. 1,869.0 2,158.0 8/20/2024 12:00 8/20/2024 12:15 0.25 COMPZN, RPCOMP CIRC P Circ BU @ 8 BPM, 570 PSI. 2,158.0 2,158.0 8/20/2024 12:15 8/20/2024 12:30 0.25 COMPZN, RPCOMP OWFF P OWFF, B/D TD. 2,158.0 2,158.0 8/20/2024 12:30 8/20/2024 13:15 0.75 COMPZN, RPCOMP TRIP P POOH F/ 2158' T/ 214'. PUW=66K. 2,158.0 214.0 8/20/2024 13:15 8/20/2024 14:30 1.25 COMPZN, RPCOMP BHAH P Rack back DC's, L/D BHA #7. 214.0 0.0 8/20/2024 14:30 8/20/2024 15:30 1.00 COMPZN, RPCOMP BHAH P M/U BHA #8 RCJB T/ 232'. SOW=42K 0.0 232.0 8/20/2024 15:30 8/20/2024 16:30 1.00 COMPZN, RPCOMP TRIP P RIH F/ 232' T/ 2179', PUW=74, SOW=63K 232.0 2,179.0 8/20/2024 16:30 8/20/2024 17:15 0.75 COMPZN, RPCOMP WASH P Obtain paramenters. Pump @ 8 BPM, 1500 PSI,. Rot @ 15 RPM, 1.5K free Tq. Wash of sand T/ 2239'. 2,179.0 2,239.0 Rig: NORDIC 3 RIG RELEASE DATE 9/2/2024 Page 8/19 1B-07 Report Printed: 9/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 8/20/2024 17:15 8/20/2024 18:00 0.75 COMPZN, RPCOMP CIRC P Pump 10 Bbls sweep around @ 8 BPM and 1555 PSI. Blowdown TD. 2,239.0 2,239.0 8/20/2024 18:00 8/20/2024 19:00 1.00 COMPZN, RPCOMP TRIP P TOOH w/ BHA #8 (RCJB #1). 2,239.0 232.0 8/20/2024 19:00 8/20/2024 19:45 0.75 COMPZN, RPCOMP BHAH P L/D BHA #8. Inspect RCJB. Recovered metal debris from milled up ES cementer and closing plug. 232.0 0.0 8/20/2024 19:45 8/20/2024 20:30 0.75 COMPZN, RPCOMP BHAH P MU BHA #9 (RCJB #2). 0.0 232.0 8/20/2024 20:30 8/20/2024 21:30 1.00 COMPZN, RPCOMP TRIP P TIH w/ RCJB to 2,239'. 232.0 2,239.0 8/20/2024 21:30 8/20/2024 22:30 1.00 COMPZN, RPCOMP WASH P Obtain parameters. 6.5 BPM @ 1140 psi. Rot @ 15 RPM. F.T. = 1.6K. Wash sand down to 2,261. 2,239.0 2,261.0 8/20/2024 22:30 8/20/2024 23:00 0.50 COMPZN, RPCOMP CIRC P Circ BU. Blowdown TD. 2,261.0 2,237.0 8/20/2024 23:00 8/21/2024 00:00 1.00 COMPZN, RPCOMP TRIP P TOOH w/ BHA #9. 2,237.0 232.0 8/21/2024 00:00 8/21/2024 00:45 0.75 COMPZN, RPCOMP BHAH P L/D BHA #9. Inspect RCJB. Recovered ES cementer metal debris and closing plug rubber chunks. 232.0 0.0 8/21/2024 00:45 8/21/2024 01:30 0.75 COMPZN, RPCOMP BHAH P MU BHA #10 (RCJB #3). 0.0 232.0 8/21/2024 01:30 8/21/2024 02:15 0.75 COMPZN, RPCOMP TRIP P TIH w/ BHA #10 to 2,261'. 232.0 2,261.0 8/21/2024 02:15 8/21/2024 02:30 0.25 COMPZN, RPCOMP WASH P Obtain parameters. 7 BPM @ 1102 psi. Free Torque = 1.6K. Wash sand down to 2271' 2,261.0 2,271.0 8/21/2024 02:30 8/21/2024 03:00 0.50 COMPZN, RPCOMP CIRC P Circ BU. Blow Down TD. 2,271.0 2,222.0 8/21/2024 03:00 8/21/2024 04:00 1.00 COMPZN, RPCOMP TRIP P TOOH w/ BHA #10 (RCJB #3). 2,222.0 232.0 8/21/2024 04:00 8/21/2024 04:45 0.75 COMPZN, RPCOMP BHAH P L/D RCJB #3. Inspect. Recovered ES cementer metal chunks. 232.0 0.0 8/21/2024 04:45 8/21/2024 05:30 0.75 COMPZN, RPCOMP BHAH P MU BHA #11, RCJB #4. Run 1 stand DP T/ 327, 0.0 327.0 8/21/2024 05:30 8/21/2024 06:00 0.50 COMPZN, RPCOMP SVRG P Service rig. Grease equipment. 327.0 327.0 8/21/2024 06:00 8/21/2024 07:15 1.25 COMPZN, RPCOMP TRIP P TIH w BHA #11 T/ 2257', PUW=74K, SOW=64K. 327.0 2,257.0 8/21/2024 07:15 8/21/2024 07:45 0.50 COMPZN, RPCOMP WASH P Obtain parameters. 8 BPM @ 1430 PSI. Free Torque =1.5K. Wash sand down to 2279'. P/U T/ 2257'. 2,257.0 2,257.0 8/21/2024 07:45 8/21/2024 08:15 0.50 COMPZN, RPCOMP CIRC P Circ 10 Bbls hi-vis pill around @ 8 BPM. L/D single B/D TD. 2,257.0 2,234.0 8/21/2024 08:15 8/21/2024 09:30 1.25 COMPZN, RPCOMP TRIP P TOOH F/ 2234' T/ 232', PUW=74K. 2,234.0 232.0 8/21/2024 09:30 8/21/2024 10:00 0.50 COMPZN, RPCOMP BHAH P L/D RCJB #4. Inspect. Clean, nothing in baskets. 232.0 0.0 8/21/2024 10:00 8/21/2024 10:30 0.50 COMPZN, RPCOMP BHAH P M/U BHA #12 IBP retrieval tool T/ 5'. 0.0 5.0 8/21/2024 10:30 8/21/2024 11:30 1.00 COMPZN, RPCOMP TRIP P RIH T/ 2229'. PUW=66K. SOW=61K. 5.0 2,229.0 8/21/2024 11:30 8/21/2024 11:36 0.10 COMPZN, RPCOMP WASH P Obtain parameters. Circ @ 8 BPM, 670 PSI. Wash down sand T/ 2288'. 2,229.0 2,288.0 8/21/2024 11:36 8/21/2024 12:00 0.40 COMPZN, RPCOMP DISP P CIrc 30 Bbls hi-vis pill followed by neat seawater. @ 8 BPM, 1000 PSI. 2,288.0 2,288.0 Rig: NORDIC 3 RIG RELEASE DATE 9/2/2024 Page 9/19 1B-07 Report Printed: 9/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 8/21/2024 12:00 8/21/2024 13:30 1.50 COMPZN, RPCOMP MPSP P Circ @ 1 BPM, wash down T/ plug top 2293' PSI increase F/ 60 T/90 PSI. Set 5K down P/U no over pull. Circ @ 2 BPM, wash done PSI increase F/ 100 T/ 200 PSI. Set down 10K, P/U 8K over. tool appeared to shift. Let sit for 15 Min. RIH took weight at same spot, set 10K down, P/U 10K over let sit for 5 MIn. RIH set down 10K. P/U 20K over. Let sit, weight fell off. RIH T/ 2300 past set depth. P/U T/ 2229'. PUW=67K. 2,288.0 2,229.0 8/21/2024 13:30 8/21/2024 15:00 1.50 COMPZN, RPCOMP TRIP P TOOH F/ 2229' T/ 5', PUW=67K. 2,229.0 5.0 8/21/2024 15:00 8/21/2024 15:30 0.50 COMPZN, RPCOMP BHAH P L/D BHA #12 & IBP. 5.0 0.0 8/21/2024 15:30 8/21/2024 15:45 0.25 COMPZN, RPCOMP CLEN P Clean & clear RF. 0.0 0.0 8/21/2024 15:45 8/21/2024 16:00 0.25 COMPZN, RPCOMP RURD P R/U testing equipment. 0.0 0.0 8/21/2024 16:00 8/21/2024 16:15 0.25 COMPZN, RPCOMP PRTS P PT 7" CSG down to Packer @ 8483' T/ 3000 PSI for 10 Min., 0.0 0.0 8/21/2024 16:15 8/21/2024 16:30 0.25 COMPZN, RPCOMP RURD P B/D, R/D testing equipment. 0.0 8/21/2024 16:30 8/21/2024 17:30 1.00 COMPZN, RPCOMP BHAH P M/U BHA #13 dress off, clean out run T/ 231'. 0.0 231.0 8/21/2024 17:30 8/21/2024 20:00 2.50 COMPZN, RPCOMP TRIP P TIH F/ 231' T/ 3500'. At approx. 3,500' driller noted acting like we are scraping the 7" casing ID with 6 1/8" OD tools. BHA chattering slightly during TIH. Clean PU and SO. Cleaned up. Cont. TIH to 8,300' 231.0 8,300.0 8/21/2024 20:00 8/21/2024 23:00 3.00 COMPZN, RPCOMP WASH P Obtain parameters. PUW = 125K. SOW = 115K. Pump Rate = 5 BPM @ 1225 psi. Rotary = 45 RPM. Free Torque = 7.8K. Wash and ream from 8,300' to 8,388'. Backream across same interval. SD rotary and pumps. Bleed off. MU stand #89. Screw in TD. Cont. to wash/ream down to 8,439'. Set 10K down. PUW =180K. Repeat set down. Not washing off. 8,300.0 8,439.0 8/21/2024 23:00 8/21/2024 23:30 0.50 COMPZN, RPCOMP WASH P PUH. Bring pumps on. 5 BPM @ 1,224 psi. Rotary = 30 RPM. Torque = 7.7K. Rot. WT = 120K. TIH washing down to tubing stub. See pressure indicator @ 8,449'. SD pumps and rotary. PUH. Repeat. Wash down to 8,449'. See press. indicator. SD pumps and rotary. Stalled. Release torque. 8,439.0 8,449.0 8/21/2024 23:30 8/22/2024 00:00 0.50 COMPZN, RPCOMP CIRC P PUH to 8,429'. Circ STS @ 7 BPM / 2257 psi. Circ out potential scale/debris. 8,449.0 8,429.0 Rig: NORDIC 3 RIG RELEASE DATE 9/2/2024 Page 10/19 1B-07 Report Printed: 9/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 8/22/2024 00:00 8/22/2024 00:30 0.50 COMPZN, RPCOMP WASH P Obtain parameters. Pump Rate = 4 BPM @ 732 psi. TIH w/ no rotary. Set down on Tbg stub @ 8,439'. PUH. Rotate 30 RPM. See pressure indicator (increase to 864 psi) when over stub. Cont TIH and swallow 10' of stub to 8,449'. Fully locate @ 8,449' (N3 RKB). Pressure up to 1,331 psi. No-Go approx. 10' shallower than expected based on original Tally. Repeat tubing stub swallow w/ no rotary. Set 10K down on top of stub again. Rotate slowly @ 3 RPM. Increased to 20 RPM briefly to capture stub. See 300 psi pressure indicator again. Swallow stub to 8,445'. Wash/Ream from 8,390' to 8,434' (5' above stump). 8,429.0 8,449.0 8/22/2024 00:30 8/22/2024 02:00 1.50 COMPZN, RPCOMP CIRC P Pump 30 bbl hi-vis pill. Circ pill out w/ neat SW. Load completions jewelry on ODS while circulating. 8,449.0 8,435.0 8/22/2024 02:00 8/22/2024 02:45 0.75 COMPZN, RPCOMP OWFF P OWFF. Finish loading jewelry. 8,435.0 8,435.0 8/22/2024 02:45 8/22/2024 09:30 6.75 COMPZN, RPCOMP PULD P LDDP F/ 8435' T/ 231', PUW=180K. 8,435.0 231.0 8/22/2024 09:30 8/22/2024 10:30 1.00 COMPZN, RPCOMP BHAH P L/D BHA #13 (dress off/cleanout). Inspect to confirm swallowed stub. 231.0 0.0 8/22/2024 10:30 8/22/2024 11:30 1.00 COMPZN, RPCOMP CLEN P Clean & clear RF & pipe shed. 0.0 0.0 8/22/2024 11:30 8/22/2024 12:00 0.50 COMPZN, RPCOMP RURD P Pull wear bushing. 0.0 0.0 8/22/2024 12:00 8/22/2024 12:30 0.50 COMPZN, RPCOMP RURD P R/U GBR torque turn equipment. Verify joint count and jewelry running order. 0.0 0.0 8/22/2024 12:30 8/22/2024 13:00 0.50 COMPZN, RPCOMP SFTY P PJSM w/ GBR, SLB on running 3 1/2" Hyd 563 completion. 0.0 0.0 8/22/2024 13:00 8/23/2024 00:00 11.00 COMPZN, RPCOMP PUTB P RIH w/ 3 1/2", 9.3#, L-80, Hyd 563 completion T/ midnight depth of 7,508'. Hyd 563 torque turned T/ 2900 Ft/lbs. Best'O'life 2000 Arctic grade dope used. 0.0 8/23/2024 00:00 8/23/2024 01:00 1.00 COMPZN, RPCOMP PUTB P RIH w/ 3 1/2", 9.3#, L-80, Hyd 563 completion T/ 8,424'. Hyd 563 torque turned T/ 2900 Ft/lbs. Best'O'life 2000 Arctic grade dope used. 0.0 8,424.0 8/23/2024 01:00 8/23/2024 02:00 1.00 COMPZN, RPCOMP WASH P MU Joint #268. Screw in TD. Obtain parameters. PUW = 110K. SOW = 70K. Pump Rate = 2 BPM @ 115 psi. Wash down over Tubing Stub @ 8,448' ORKB. See pressure indicator @ 8,444' (N3 RKB). SD pumps. Cont. swallow stub and see shear screws shear (7K down) @ 8,447'. Cont. swallow stub and fully locate @ 8,450'. Set 10K down. Repeat set down to confirm fully located. 8,424.0 8,450.0 8/23/2024 02:00 8/23/2024 03:00 1.00 COMPZN, RPCOMP HOSO P Mark Pipe. PUH and measure partial Joint #268 (26.18'). Calculate Space out pups required. L/D partial #268. L/D Full Joint #267 (31.44'). L/D Full Joint #266. M/U Space out pups (9.74', 9.72', 3.82'). Results in 3' space out. M/U last full joint #266, Tubing hanger w/ pup, and landing joint. 8,450.0 8,439.0 Rig: NORDIC 3 RIG RELEASE DATE 9/2/2024 Page 11/19 1B-07 Report Printed: 9/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 8/23/2024 03:00 8/23/2024 05:45 2.75 COMPZN, RPCOMP CIRC P RU head pin and hose to choke. Close bag. Pump 3 BPM @ 388 psi. Reverse circulate 260 bbls of 8.6# CI down IA taking Tubing returns out to tanks. Kick out left over 3 1/2" Tubing and Pups. Load test joints for next well. SD pumps. Bleed off. Open bag. 8,439.0 8,439.0 8/23/2024 05:45 8/23/2024 06:15 0.50 COMPZN, RPCOMP THGR P Land hanger. RILDS. Bottom on mule shoe @ 8451.2' ORKB. 8,439.0 8,451.2 8/23/2024 06:15 8/23/2024 07:30 1.25 COMPZN, RPCOMP RURD P B/D surface lines. Drop Ball and Rod. RU PT equipment (circ manifold on rig floor, hoses and isolation valves to Tubing and IA). 8,451.2 8,451.2 8/23/2024 07:30 8/23/2024 08:15 0.75 COMPZN, RPCOMP PACK P Pressure up on TBG 500 PSI increments holding for 1 MIn up T/ 2000 PSI. Cont pressure up T/ 3700. Hold for 30 Min good test. 8,451.2 8,451.2 8/23/2024 08:15 8/23/2024 11:30 3.25 COMPZN, RPCOMP PRTS T Bleed TBG T/ 2000 PSI. Attempt to PT IA T/ 3000 PSI. Steady bleed off 150 PSI in 15 min. Changed out isolation valve on testing equipment. Changed out sensator. Retest same results. Visual leak around hanger seen from RF. 8,451.2 8,451.2 8/23/2024 11:30 8/23/2024 12:30 1.00 COMPZN, RPCOMP HOSO T BOLDS. P/U 110K on sting pull hanger off seat. Flush TBG hanger w/ fresh water. Re land. RILDS. 8,451.2 8,451.2 8/23/2024 12:30 8/23/2024 13:30 1.00 COMPZN, RPCOMP PRTS T Pressure up on TBG T/ 2000 PSI. Attempt to PT IA T/ 3000 PSI. Same bleed trend. Still seeing fluid movement at hanger. 8,451.2 8,451.2 8/23/2024 13:30 8/23/2024 14:30 1.00 COMPZN, RPCOMP WAIT T Consult w/ town. Decision made to pull ball & rod. Run E-line to cut mandrel in SLB Bluepack Max RH to release packer. Pull completion. Call out slick line. 8,451.2 8,451.2 8/23/2024 14:30 8/23/2024 16:30 2.00 COMPZN, RPCOMP RURD T Spot slick line unit. R/U slick line to pull ball & rod. 8,451.2 8,451.2 8/23/2024 16:30 8/23/2024 18:45 2.25 COMPZN, RPCOMP SLKL T RIH w/ slick line pull ball & rod from RHC in lower X nipple. RD Slickline. 8,451.2 8,451.2 8/23/2024 18:45 8/23/2024 22:00 3.25 COMPZN, RPCOMP WAIT T Wait for E-line unit to arrive from 1Q and Welltec to arrive from Deadhorse. 8,451.2 8,451.2 8/23/2024 22:00 8/24/2024 00:00 2.00 COMPZN, RPCOMP ELNE T Spot in and RU E-line. Re-head. MU and function test Welltec Cutter. Confirm max cutter blade extension depth of 3.89" w/ custom stopper ring. 8,451.2 8,451.2 8/24/2024 00:00 8/24/2024 06:15 6.25 COMPZN, RPCOMP ELNE T Cont. to MU cable head. Took 4 attempts to get new head made up. Attempt to function test tools and identify electrical issue with logging unit. Troubleshoot wiring/electrical issue. Discuss with SLB Engineer @ 4AM. Ask SLB to get another logging unit out of Deadhorse while continuing to troubleshoot. Function test Wellhead tools in the ground. 8,451.2 8,451.2 8/24/2024 06:15 8/24/2024 08:15 2.00 COMPZN, RPCOMP ELNE T BOLDS. Pull tension on tubing string T/ 115K. R/U SLB. Function test Welltec tools. cutter extended T/ 3.875" on RF. Zero at RF. 8,451.2 8,451.2 8/24/2024 08:15 8/24/2024 11:15 3.00 COMPZN, RPCOMP ELOG T RIH w/ cutter. Tie into pup below packer @ 8371.93'. P/U 1.47' + 18' CCL to cutter. Set anchors. Cut @ 8370.46'. Release anchors. POOH. 8,451.2 8,451.2 Rig: NORDIC 3 RIG RELEASE DATE 9/2/2024 Page 12/19 1B-07 Report Printed: 9/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 8/24/2024 11:15 8/24/2024 12:00 0.75 COMPZN, RPCOMP ELNE T Pull tool string OOH. Measure cutter, blades extended T/ 3.875". Stand back E-line. Latch up on landing joint. P/U on string pipe free @ 147K. Pull hanger T/ RF. 115K w/ over pull 130K. 8,451.2 8,413.0 8/24/2024 12:00 8/24/2024 12:30 0.50 COMPZN, RPCOMP ELNE T R/D E-Line. OWFF - no flow. 8,413.0 8,413.0 8/24/2024 12:30 8/24/2024 13:00 0.50 COMPZN, RPCOMP PULD T L/D hanger & landing joint. Inspect hanger. No severe damage to hanger. Control line plugs were in place. Remove seal from hanger. horizontal split in hanger seal. 8,413.0 8,413.0 8/24/2024 13:00 8/24/2024 13:30 0.50 COMPZN, RPCOMP RURD T R/U circ equipment. 8,413.0 8,413.0 8/24/2024 13:30 8/24/2024 14:30 1.00 COMPZN, RPCOMP CIRC T Circ CI seawater out of well w/ neat seawater. Pump @ 3 BPM, 500 PSI, taking returns T/ open top tank. At 50 Bbls away DP pressure spiked T/ 4500 PSI. Line up to reverse circ. Reverse circ 25 Bbls @ 2 BPM, 275 PSI. Attempt to pull joint P/U 175K no pipe movement. R/U GBR tubing equipment. 8,413.0 8,413.0 8/24/2024 14:30 8/24/2024 16:00 1.50 COMPZN, RPCOMP PULD T M/U spare joint of TBG attempt to break over in down stroke. Broke over @ 50K. Worked pipe up T/ 195K back T/ down stroke. Pipe free. L/D spare joint of tubing. Attempt T/ pump down DP. Pressured up @ 2 BPM. 8,413.0 8,413.0 8/24/2024 16:00 8/24/2024 16:30 0.50 COMPZN, RPCOMP RURD T B/D, R/D circ equipment. OWFF. PJSM on racking back completion. 8,413.0 8,413.0 8/24/2024 16:30 8/25/2024 00:00 7.50 COMPZN, RPCOMP PULL T POOH racking back 3 1/2" completion in derrick F/ 8422' T/ 217' 8,413.0 217.0 8/25/2024 00:00 8/25/2024 00:30 0.50 COMPZN, RPCOMP PULL T Finish L/D 3 1/2" completion to surface. Inspect GLM and Cut Packer. SOV not sheared. Packer elements torn. Packer missing one slip. Slip carrier/profile damaged. Slip dimensions (T-shaped) = 4.8" tall x 2.4" wide (at top) x 1.2" wide (at bottom). Confirmed slips are magnetic. Packer collets bent and damaged. 217.0 0.0 8/25/2024 00:30 8/25/2024 01:00 0.50 COMPZN, RPCOMP RURD T Clean and clear rig floor. RD GBR. 0.0 0.0 8/25/2024 01:00 8/25/2024 02:00 1.00 COMPZN, RPCOMP PRTS T RU to PT casing. RU sensator to IA. Close Blinds. PT 7" casing to 3,000 psi thru kill line. First 15-minutes showed slight bleed off. Closed manual kill to double block. Last 15-min double blocked looked better. Bleed off. Open Blinds. Concerned large volume may be masking slow leak. Repeat 7" casing test after Hanger testing. 0.0 0.0 8/25/2024 02:00 8/25/2024 03:00 1.00 COMPZN, RPCOMP THGR T MU landing joint w/ XO and tubing hanger w/ BPV and blanking plug. Screw in TD. Open IA. Land Hanger. Set 10K down. RILDS. 0.0 0.0 8/25/2024 03:00 8/25/2024 04:30 1.50 COMPZN, RPCOMP PRTS T RU test hose to IA w/ sensator. PT tubing hanger from below to 3,000 psi for 10-min. Chart. Slow bleed off on chart. See bubbles coming up from under hanger. Bleed off IA. 0.0 0.0 Rig: NORDIC 3 RIG RELEASE DATE 9/2/2024 Page 13/19 1B-07 Report Printed: 9/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 8/25/2024 04:30 8/25/2024 05:00 0.50 COMPZN, RPCOMP THGR T Shut IA valves. Blowdown and R/D IA hose. Pull BPV/test dart. MU Landing Joint. Pull Tubing Hanger to rig floor. Inspect driller side of hanger for scaring/leak path. 0.0 0.0 8/25/2024 05:00 8/25/2024 11:00 6.00 COMPZN, RPCOMP PRTS T Close blinds. Repeat 7" casing test to 3,000 psi for 30-min to double verify casing/deep plug integrity. Slow bleed. Call out slick line for gauge run w/ magnets to clear packer slip. Changed sensator, function blinds, seal up gaps in cellar walls. Double block HCR w/ manuals. Re test. Still not meeting MIT criteria. Change out sensator hose. Re test still not meeting MIT criteria. 0.0 0.0 8/25/2024 11:00 8/25/2024 12:00 1.00 COMPZN, RPCOMP RURD T B/D, R/D testing equipment. Install mouse hole. Spot slick line unit. 0.0 0.0 8/25/2024 12:00 8/25/2024 13:00 1.00 COMPZN, RPCOMP SLKL T R/U slick line w/ 2ea. 3 1/2" magnets, 6 1/8" gauge ring, & 7" brush. 0.0 0.0 8/25/2024 13:00 8/25/2024 15:30 2.50 COMPZN, RPCOMP SLKL T RIH w/ slick line, Set down @ 1928' work through. Set down @ 2123' work through. Set down hard @ 5240'. POOH. 0.0 0.0 8/25/2024 15:30 8/25/2024 17:00 1.50 COMPZN, RPCOMP SLKL T Inspect slick line string. Metal shavings on magnets. Gauge ring showed signs of trauma. R/D slick line. Spank RHC plug into lower X nipple. Begin processing 3 1/2" DP string. Call out fishing package for clean out run. 0.0 0.0 8/25/2024 17:00 8/25/2024 21:00 4.00 COMPZN, RPCOMP RURD T Complete processing 3 1/2" DP. Kick out HWDP. Keep 6 DC's for RCJB run. Wait on Baker tools to arrive. 0.0 0.0 8/25/2024 21:00 8/25/2024 23:30 2.50 COMPZN, RPCOMP PRTS T RU to re-test 7" casing. Run 3 1/2" donut TJ with floor valve on top. Close UPR. Triple check to confirm blinds were not leaking on previous 7" casing tests. Held 1st test for 1-hour. Passed. Repear test for 30-min to confirm. Passed. Bleed off. Discuss Plan Forward with Town. Decide to set Storm Packer and swap Tubing Head before RCJB run. 0.0 0.0 8/25/2024 23:30 8/26/2024 00:00 0.50 COMPZN, RPCOMP RURD T Open UPR. L/D 3 1/2" donut test joint. Drain Stack. Set Wear Ring. 0.0 0.0 8/26/2024 00:00 8/26/2024 01:00 1.00 COMPZN, RPCOMP RURD T Load Baker tools. Finish setting Wear Ring. Close blinds. Re-test blinds and 7" casing. Passed. 0.0 0.0 8/26/2024 01:00 8/26/2024 03:00 2.00 COMPZN, RPCOMP BHAH T Load and MU BHA #14 (RCJB). 0.0 232.0 8/26/2024 03:00 8/26/2024 04:00 1.00 COMPZN, RPCOMP PULD T TIH w/ BHA #14 to 1,066' (20K hanging weight). 232.0 1,066.0 8/26/2024 04:00 8/26/2024 04:30 0.50 COMPZN, RPCOMP BHAH T Load and MU Storm Packer. 1,066.0 1,066.0 8/26/2024 04:30 8/26/2024 04:45 0.25 COMPZN, RPCOMP PULD T Single in with Storm Packer to 1,166'. 1,066.0 1,166.0 8/26/2024 04:45 8/26/2024 05:00 0.25 COMPZN, RPCOMP MPSP T Set Storm Packer @ 96' (COE, middle of 2nd full joint of 7" casing). Top @ 82'. 11 turns to the right to release. 1,166.0 82.0 8/26/2024 05:00 8/26/2024 05:15 0.25 COMPZN, RPCOMP PULD T L/D 2 joint and setting tools 82.0 0.0 Rig: NORDIC 3 RIG RELEASE DATE 9/2/2024 Page 14/19 1B-07 Report Printed: 9/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 8/26/2024 05:15 8/26/2024 06:00 0.75 COMPZN, RPCOMP PRTS T Close Blinds. RU sensator to IA. PT Storm Packer to 3,000 psi for 30-min. Chart. (7 strokes to pressure up. Deep plug tests took 65 strokes). Confirmed testing against shallow storm packer. 0.0 0.0 8/26/2024 06:00 8/26/2024 06:30 0.50 COMPZN, RPCOMP OWFF T OWFF for 30-min. 0.0 0.0 8/26/2024 06:30 8/26/2024 07:45 1.25 COMPZN, RPCOMP NUND T ND BOP. 0.0 0.0 8/26/2024 07:45 8/26/2024 08:00 0.25 COMPZN, RPCOMP NUND T Pull wear ring. 0.0 0.0 8/26/2024 08:00 8/26/2024 08:45 0.75 COMPZN, RPCOMP NUND T Inspect tubing head for damage. Two areas w/ vertical scaring across sealing surface in hanger profile. 0.0 0.0 8/26/2024 08:45 8/26/2024 11:00 2.25 COMPZN, RPCOMP NUND T ND old tubing head. NU new tubing head. Install secondary IA valve. 0.0 0.0 8/26/2024 11:00 8/26/2024 11:15 0.25 COMPZN, RPCOMP PRTS T PT pack off T/ 3000 PSI for 15 Min. 0.0 0.0 8/26/2024 11:15 8/26/2024 11:45 0.50 COMPZN, RPCOMP MPSP T Run hanger on landing joint to act as test plug. RILDS. 0.0 0.0 8/26/2024 11:45 8/26/2024 13:00 1.25 COMPZN, RPCOMP NUND T NU BOP. Verify RKB mesurements. Install flow nipple. R/U trip hose. 0.0 0.0 8/26/2024 13:00 8/26/2024 13:30 0.50 COMPZN, RPCOMP RURD T R/U testing equipment. Install landing joint. Fill stack w/ fresh water. 0.0 0.0 8/26/2024 13:30 8/26/2024 14:15 0.75 COMPZN, RPCOMP PRTS T PT breaks to 250/3000 psi against hanger. 0.0 0.0 8/26/2024 14:15 8/26/2024 14:30 0.25 COMPZN, RPCOMP RURD T B/D, R/D testing equipment. Suck out stack. 0.0 0.0 8/26/2024 14:30 8/26/2024 15:00 0.50 COMPZN, RPCOMP MPSP T BOLDS. Pull hanger. 0.0 0.0 8/26/2024 15:00 8/26/2024 15:30 0.50 COMPZN, RPCOMP RURD T Set wear bushing. 0.0 0.0 8/26/2024 15:30 8/26/2024 16:45 1.25 COMPZN, RPCOMP MPSP T M/U storm packer retrievial head. RIH. Equalize PSI. Release storrm packer. POOH. L/D storm packer & retrieval head. 0.0 1,066.0 8/26/2024 16:45 8/26/2024 21:00 4.25 COMPZN, RPCOMP PULD T PUDP F/ 1066' T/ 4858'. PUW = 106K. SOW =77K. 1,066.0 4,858.0 8/26/2024 21:00 8/26/2024 23:30 2.50 COMPZN, RPCOMP SLPC T Slip and Cut Drill Line 4,858.0 4,858.0 8/26/2024 23:30 8/27/2024 00:00 0.50 COMPZN, RPCOMP PULD T Cont. single in hole to 5,200'. 4,858.0 5,200.0 8/27/2024 00:00 8/27/2024 00:30 0.50 COMPZN, RPCOMP WASH T Obtain Parameters. PUW = 115K. SOW = 76K. Slowly TIH past 5,240' (slickline set down depth). Did not see any set down or indications of debris or restriction. 5,200.0 5,265.0 8/27/2024 00:30 8/27/2024 04:15 3.75 COMPZN, RPCOMP PULD T Cont single in hole to above tubing stub @ 8,423'. 5,265.0 8,432.0 8/27/2024 04:15 8/27/2024 04:45 0.50 COMPZN, RPCOMP WASH T Obtain Parameters. PUW = 184K. SOW = 90K. Pump rate = 4 BPM @ 1807 psi. Line up to take IA returns (8.6# CI) out to cuttings tank. Wash down to stump @ 4 BPM. Set down 3K @ 8,438'. PUH. Rotate string @ 30 RPM. TIH and swallow stub to 8,446', confirming backside is clear for PBOS. No press. indicator with RCJB. 8,434.0 8,434.0 8/27/2024 04:45 8/27/2024 06:45 2.00 COMPZN, RPCOMP CIRC T PU 5' above stub. Circ STS @ 4 BPM @ 1786 psi. 8,434.0 8,434.0 8/27/2024 06:45 8/27/2024 07:15 0.50 COMPZN, RPCOMP OWFF T OWFF. 8,434.0 8,434.0 Rig: NORDIC 3 RIG RELEASE DATE 9/2/2024 Page 15/19 1B-07 Report Printed: 9/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 8/27/2024 07:15 8/27/2024 11:30 4.25 COMPZN, RPCOMP TRIP T TOOH w/ BHA #14 (RCJB). 8,434.0 232.0 8/27/2024 11:30 8/27/2024 13:00 1.50 COMPZN, RPCOMP BHAH T L/D BHA #14 (RCJB). Inspect magnet and RCJB for debris. Recovered 3 small pieces of packer debris on magnets. Recovered packer rubber pieces and small metal pieces in RCJB. 232.0 0.0 8/27/2024 13:00 8/27/2024 15:00 2.00 COMPZN, RPCOMP PRTS T Close Blinds. RU sensator to IA. Line up to PT 7" casing through kill line. PT 7" casing to 3,000 psi. Double block HCR and manual kill. 0.0 0.0 8/27/2024 15:00 8/27/2024 15:15 0.25 COMPZN, RPCOMP CLEN T Clean and clear rig floor. 0.0 0.0 8/27/2024 15:15 8/27/2024 16:00 0.75 COMPZN, RPCOMP BHAH T MU BHA #15 (RCJB #2) 0.0 232.0 8/27/2024 16:00 8/27/2024 20:00 4.00 COMPZN, RPCOMP TRIP T TIH w/ BHA #15 to tubing stub @ 8,438'. 232.0 8,438.0 8/27/2024 20:00 8/27/2024 21:30 1.50 COMPZN, RPCOMP WASH T Drop 7/8" ball // Circulate ball on seat of venturi // Wash over stump T/ 84 // Dn Wt 150K Up Wt 140K // Pump 4 bpm @ 1600 psi // Pump high vis sweep SxS 8,438.0 8,445.0 8/27/2024 21:30 8/28/2024 00:00 2.50 COMPZN, RPCOMP PULD T Lay down drill pipe T/ 6,200' 8,445.0 6,200.0 8/28/2024 00:00 8/28/2024 05:00 5.00 COMPZN, RPCOMP PULD T Lay down drill pipe T/ 675'. T/S skate hydraulics. Cont. LDDP to 232' 6,200.0 232.0 8/28/2024 05:00 8/28/2024 07:30 2.50 COMPZN, RPCOMP BHAH T L/D BHA #15 (RCJB). Recover small rubber pieces. Pull Wear Ring. 232.0 0.0 8/28/2024 07:30 8/28/2024 08:00 0.50 COMPZN, RPCOMP WWWH T Jet/Flush stack to ensure no debris falls into tubing head sealing profile. 0.0 0.0 8/28/2024 08:00 8/28/2024 09:00 1.00 COMPZN, RPCOMP PULD T RU GBR pipe handling equip, and torque turn. Prep rig floor to run 3 1/2" HYD563 completions. Verify jewelry and run order. 0.0 0.0 8/28/2024 09:00 8/28/2024 15:30 6.50 COMPZN, RPCOMP PULD T Run 3 1/2" HYD563 Completions as per Tally to 8,429.7' 0.0 8,429.7 8/28/2024 15:30 8/28/2024 16:00 0.50 COMPZN, RPCOMP WASH T MU last full joint #268. Screw in TD. Obtain parameters. PUW = 105K. SOW = 70K. Pump rate = 2 BPM and 125 psi. Cont. TIH and swallow tubing stub. See press. indicator @ 8,444' (50 psi bump). SD Pumps. Cont. to swallow and see shear screws @ 8,447''. Cont swallow and fully locate @ 8,450'. Set 5K down. Mark pipe. 8,429.7 8,450.0 8/28/2024 16:00 8/28/2024 17:00 1.00 COMPZN, RPCOMP HOSO T L/D partial joint #268 and full joint #267. Measure both. Calculate space out pups required. MU space out pups (9.74', 6.09', 1.99'), last full Joint #266, hanger + pup, and landing joint. MU head pin, valve, chicksan, and hose to top of landing joint. 8,450.0 8,450.0 8/28/2024 17:00 8/28/2024 18:30 1.50 COMPZN, RPCOMP CIRC T Reverse circaulate 260 bbls 8.6# CI down backside, taking returns from tubing out to open top tank. SD pump. Bleed off. 8,450.0 8,450.0 8/28/2024 18:30 8/28/2024 19:30 1.00 COMPZN, RPCOMP THGR T Land Hanger. RILDS. Close UPR. MU sensator to test spool. Open IA. PT hanger from above to 3,000 psi. Bleed off. Drop Ball and Rod. 8,450.0 8,450.0 8/28/2024 19:30 8/28/2024 20:30 1.00 COMPZN, RPCOMP RURD T Rig up circulating equipment for setting packer 8,450.0 8,450.0 Rig: NORDIC 3 RIG RELEASE DATE 9/2/2024 Page 16/19 1B-07 Report Printed: 9/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 8/28/2024 20:30 8/28/2024 22:00 1.50 COMPZN, RPCOMP PACK T Come on line with pump tubing and IA moving together, ball and rod not on seat, pump 4 bpm 600 psi full returns, unable to get ball and rod on seat // Call slick line to chanse to x-nipple 8,450.0 8,450.0 8/28/2024 22:00 8/29/2024 00:00 2.00 COMPZN, RPCOMP SLKL T Rig up slick line, RIH chase ball and rod on seat, pooh stand back rig up circ equipment ensure ball and rod seated 8,450.0 8,450.0 8/29/2024 00:00 8/29/2024 01:00 1.00 COMPZN, RPCOMP SLKL T Ball and rod on seat // stand back check for ball and rod to hold pressure // rig down slick line 8,450.0 8,450.0 8/29/2024 01:00 8/29/2024 01:30 0.50 COMPZN, RPCOMP PACK T Set Packer per SLB rep. See initial shear @ 1,800 psi. Hold 3,500 psi for 30-min. Chart. Counts as MIT-T to 3,500 psi. 8,450.0 8,450.0 8/29/2024 01:30 8/29/2024 03:00 1.50 COMPZN, RPCOMP PRTS T Bleed Tubing to 2,000 psi. PT IA to 3,000 psi for 30-min. Chart. // Unable to get passing test 8,450.0 8,450.0 8/29/2024 03:00 8/29/2024 04:15 1.25 COMPZN, RPCOMP PACK T Drain pressure from IA // Pressure up down tubing setting packer 4000 psi. Hold for 1 hr. 8,450.0 8,450.0 8/29/2024 04:15 8/29/2024 06:45 2.50 COMPZN, RPCOMP PRTS T Re-test IA to 3,200 psi. Failed. Linear Leak off. RU double block w/ new 2x2 valve and tattle tail. Blowdown IA hose. Monitor tattle tail. No leaks at surface. Bump back up to 3,200 psi. Still leaking off. T/S tubing hanger. Close UPR. Trap 3,200 psi above Tubing Hanger. IA pressure still falling off. Tubing Hanger is not leaking. Call Town to discuss. Cont to T/S surface lines looking for leaks. 8,450.0 8,450.0 8/29/2024 06:45 8/29/2024 07:45 1.00 COMPZN, RPCOMP WAIT T Suspect Packer or Casing Leak. Wait on Town discussion to determine plan forward. 8,450.0 8,450.0 8/29/2024 07:45 8/29/2024 08:45 1.00 COMPZN, RPCOMP WWSP T Call out Cameron to re-test IC-PO to ensure OA is isolated. Confirmed OA pressure gauge is 0 psi. IC-PO tested to 3,000 psi. Passed. 8,450.0 8,450.0 8/29/2024 08:45 8/29/2024 11:15 2.50 COMPZN, RPCOMP PRTS T RU LRS. Perform MIT-IA to 3,000 psi. DHD on location to assist and monitor for leaks. MIT-IA failed. Pressure back up to estimate LLR. LLR estimated to be 1.0 GPM @ 3,200 psi. RD LRS. 8,450.0 8,450.0 8/29/2024 11:15 8/29/2024 16:45 5.50 COMPZN, RPCOMP SLKL T Call Slickline unit out. RU SL. Begin RIH @ 2PM. RIH to X-nipple @ 8,391'. Latch and pull B&R (1.375" Ext FN). POOH. L/D B&R. RIH and latch RHC plug. POOH. L/D RHC plug. RD Slickline. 8,450.0 8,450.0 8/29/2024 16:45 8/29/2024 18:45 2.00 COMPZN, RPCOMP PRTS T RU PT equipment. PT Tubing to 3,000 psi. Monitor IA pressure for build up. xxxxxxxxxxxxx If IA continues to build after Tubing is stable @ 3,000 psi, the Packer is leaking. If IA and Tubing are stable, Pressure up IA to 3,000 psi. Perform C- MIT to 3,000 psi for 30-min. If IA leaks off we have a casing leak above the SLB Packer.xxxxxxxxxxxxxxxxxxxxx Determined that casing was leaking and packer was holding see chart in Maxwell 8,450.0 8,450.0 Rig: NORDIC 3 RIG RELEASE DATE 9/2/2024 Page 17/19 1B-07 Report Printed: 9/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 8/29/2024 18:45 8/29/2024 19:15 0.50 COMPZN, RPCOMP RURD T Shear SOV and rig down circulating/testing equipment 8,450.0 8,450.0 8/29/2024 19:15 8/29/2024 19:45 0.50 COMPZN, RPCOMP MPSP T Set TWC , test 1000 psi 10 min 8,450.0 8,450.0 8/29/2024 19:45 8/29/2024 21:00 1.25 COMPZN, RPCOMP RURD T Flush stack, rig up test equipment for BOP test 8,450.0 0.0 8/29/2024 21:00 8/30/2024 00:00 3.00 COMPZN, RPCOMP BOPE T Bi-weekly BOPE test, Tested BOPE at 250/3000 PSI for 5 Min each, Tested annular w/ 3 1/2 & 5.5" test joint. , UVBR's W/ 3 ½ & 5.5" test joints. Test blinds rams. Choke valves #1 to #13, upper and lower top drive well control valves. Test 3 1/2" IF FOSV and IBOP. Test 3 ½ & 4 ½ EUE FOSV. Test 2" rig floor Demco kill valve MM #13. Test manual and HCR kill valves & manual and HCR choke valves. Witnessed by AOGCC rep Adam Earl 0.0 8/30/2024 00:00 8/30/2024 02:00 2.00 COMPZN, RPCOMP BOPE T Test two ea 2 1/6" gate auxiliary valves below LPR. Test hydraulic and manual choke valves to 1500 PSI and demonstrate bleed off. Perform accumulator test. Initial pressure=3050 PSI, after closure=1650 PSI, 200 PSI attained =22 sec, full recovery attained =124 sec. UVBR's= 5 sec, Simulated LVBRs= 5 sec. Annular= 17 sec. Simulated blinds= 5 sec. HCR choke & kill= 1 sec each. 4 back up nitrogen bottles average =2000 PSI. Test gas detectors, PVT and flow show. 0.0 0.0 8/30/2024 02:00 8/30/2024 02:30 0.50 COMPZN, RPCOMP RURD T Rig down testing equipment 0.0 0.0 8/30/2024 02:30 8/30/2024 03:00 0.50 COMPZN, RPCOMP MPSP T Pull BPV + TWC. 0.0 0.0 8/30/2024 03:00 8/30/2024 05:30 2.50 COMPZN, RPCOMP CIRC T Displace CI out of well to open top tank // pump 2 bpm @ 298 psi. RU E- line and Welltec while circ. out CI. 0.0 0.0 8/30/2024 05:30 8/30/2024 06:30 1.00 COMPZN, RPCOMP RURD T Drain Stack. MU Landing Joint. BOLDS. Pull 110K tensions into Tubing String. 0.0 0.0 8/30/2024 06:30 8/30/2024 10:45 4.25 COMPZN, RPCOMP ELNE T RU E-line. Function test cutter at surface to confirm max cutter blade extension. Max extension = 3.945". RIH and tie E-line CCL into 6' pup joint below Packer. Repeat log to confirm on depth. CCL to cutter = 18'. Activate Welltec cutter and cut inner mandrel of SLB BluePack Packer @ 8,364.92' (CCL parked @ 8,346.92'). POOH w/ Welltec cutter. Stand Back E- line. 0.0 0.0 8/30/2024 10:45 8/30/2024 11:30 0.75 COMPZN, RPCOMP PULL T Latch into Landing Joint. Pull 160K (55K over) and confirmed Packer is released. Wait 30-min for element to relax. Pull hanger to rig floor. RD E- line. L/D landing joint and hanger. 0.0 8,451.0 8/30/2024 11:30 8/30/2024 11:45 0.25 COMPZN, RPCOMP OWFF T OWFF 8,451.0 8,451.0 Rig: NORDIC 3 RIG RELEASE DATE 9/2/2024 Page 18/19 1B-07 Report Printed: 9/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 8/30/2024 11:45 8/30/2024 15:30 3.75 COMPZN, RPCOMP PULL T Pull Tubing from 8,451' to 5,336'. Pulled 20K over. Work packer through tight spot. Pulled 15K over. TBIH. Took 10K set down to move down. Discuss with Baker Fishing and SLB Packer rep. Last clean PUW = 77K. SOW = 55K. Bring pumps online to wash potential debris from packer backside. 3 BPM @ 120 psi. Pull up into tight spot @ 5,336'. 15K over pull. Cont. to work packer through tight spot. Rotate pipe 1 turn. Re-attempt. No Joy. Continue working pipe to pull packer through tight spot. Worked up to 5,326'. xxxxx 8,451.0 5,336.0 8/30/2024 15:30 8/30/2024 18:30 3.00 COMPZN, RPCOMP PULL T Cont. pull tubing from 5,336' to 2,5xx' (approx 20K hangoff weight). 5,336.0 2,500.0 8/30/2024 18:30 8/30/2024 19:15 0.75 COMPZN, RPCOMP BHAH T MU BHA #16 (7" Storm Packer). Set @ 96' COE end of completion 2600' // Test 1000 psi 10 min good test 2,500.0 2,600.0 8/30/2024 19:15 8/30/2024 21:45 2.50 COMPZN, RPCOMP NUND T Blow down lines, nipple down stack and tubing head 2,600.0 0.0 8/30/2024 21:45 8/31/2024 00:00 2.25 COMPZN, RPCOMP NUND T Nipple up 5.5" casing head and stream- flow adapter 0.0 0.0 8/31/2024 00:00 8/31/2024 03:00 3.00 COMPZN, RPCOMP NUND T Continue nipple up of casing head, stream flo and bop's // install trip tank line and riser // 0.0 0.0 8/31/2024 03:00 8/31/2024 07:00 4.00 COMPZN, RPCOMP PULL T PJSM with new crew and GBR, pick up 3 jts pull storm packer, continue racking back tubing in derrick. Pull last GLM, X- nipple, and Packer. Recovered all packer slips and most of rubber element. Packer collets were rolled and bent but mostly recovered. 2,600.0 0.0 8/31/2024 07:00 8/31/2024 12:00 5.00 COMPZN, RPCOMP RURD T Clean and clear rig floor. RU 5 1/2" GBR pipe handling equipment. Continue to load and process last 42 joints of 5 1/2" HYD563. Load 5 1/2" Jewelry. Measure 5 1/2" pup joints. 0.0 0.0 8/31/2024 12:00 8/31/2024 20:00 8.00 COMPZN, RPCOMP PUTB T PJSM. Verify tieback jewelry and run order. Confirm RHC plugs is in nipple, DMY valve is in GLM, and Shear Screws are in Poorboy Overshot. Run 5 1/2" Tieback liner as per Tally. 0.0 6,160.0 8/31/2024 20:00 8/31/2024 20:30 0.50 COMPZN, RPCOMP CIRC T Pipe not filling // Circulate tubing volume ensure pipe clear of debris // Circulate 1000 stks 6,160.0 6,160.0 8/31/2024 20:30 8/31/2024 23:30 3.00 COMPZN, RPCOMP PUTB T Continue running 5.5" Tie back liner per tally // top filling pipe in hole // shear set screws @ 8443" NG @ 8447' // Pu Wt 153K So Wt 95K 6,160.0 8,447.0 8/31/2024 23:30 9/1/2024 00:00 0.50 COMPZN, RPCOMP DISP T Reverse in 9.8# CI Brine // Pump 3 bpm @ 588psi 8,440.0 8,440.0 9/1/2024 00:00 9/1/2024 02:00 2.00 COMPZN, RPCOMP DISP T Reverse in 9.8# CI Brine // Pump 3 bpm @ 588psi. 8,440.0 8,440.0 9/1/2024 02:00 9/1/2024 02:30 0.50 COMPZN, RPCOMP OWFF T Empty stack and OWFF // Drop Ball and rod. 8,440.0 8,444.0 9/1/2024 02:30 9/1/2024 03:30 1.00 COMPZN, RPCOMP NUND T Break stack @ Casing head. 8,444.0 8,444.0 9/1/2024 03:30 9/1/2024 06:00 2.50 COMPZN, RPCOMP HOSO T Install emergency slips., cut 5 1/2" casing. Set packoffs. 8,444.0 0.0 9/1/2024 06:00 9/1/2024 11:00 5.00 COMPZN, RPCOMP NUND T Install reducer bushing. NU new Tubing Head. Test pack-offs to 3,000 psi. Set test plug. NU BOP. 0.0 0.0 Rig: NORDIC 3 RIG RELEASE DATE 9/2/2024 Page 19/19 1B-07 Report Printed: 9/26/2024 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 9/1/2024 11:00 9/1/2024 13:00 2.00 COMPZN, RPCOMP PRTS T Open IA. Close Blinds. Test BOP breaks to 250/3000 psi. Pull test plug. Close IA. Open blinds. 0.0 0.0 9/1/2024 13:00 9/1/2024 13:30 0.50 COMPZN, RPCOMP CIRC T RU LRS. Pump 25 bbls diesel down new OA (5 1/2" x 7") taking returns up stack and out to cuttings tank. RD LRS. Initial circ. 1 bpm at 550 psi. Final = 700 psi. 0.0 0.0 9/1/2024 13:30 9/1/2024 15:30 2.00 COMPZN, RPCOMP PACK T RU PT equipment to OA. Close blinds. Install sensator on new OA (5 1/2" x 7") to monitor backside. Pressure up and set packer as per SLB rep. Initial OA pressure after FP = 300 psi. Pressure up in 500 psi increments. At 2,000 psi, replace sensator. At 3,000 psi, bleed OA down to 500 psi to reduce final packer setting pressure. Cont. pressure up and hold 4,100 psi for 30-min. Chart. Pass. (counts as 5 1/2" Tieback test). 0.0 0.0 9/1/2024 15:30 9/1/2024 16:30 1.00 COMPZN, RPCOMP PRTS T Bleed 5 1/2" casing to 500 psi. PT IA to 2,500 psi. Monitor Tubing pressure for build up. Chart for 30-min. Passed. 0.0 0.0 9/1/2024 16:30 9/1/2024 18:30 2.00 COMPZN, RPCOMP RURD T RU GBR. Prep rig floor to run 3 1/2" HYD563 completions. 0.0 0.0 9/1/2024 18:30 9/2/2024 00:00 5.50 COMPZN, RPCOMP TRIP T Run 3 1/2" Completions as per Tally (87 stands already built in derrick) to x,xxx'. 0.0 8,260.0 9/2/2024 00:00 9/2/2024 01:30 1.50 COMPZN, RPCOMP HOSO T Circulate 1 bpm @ 98psi @ 8447' NG @ 8272' Calculate space out Up Wt 153K Dn Wt 95K // Make up 6.07 & 6.09 pups under last full jt // land hanger RILDS // 8,260.0 8,260.0 9/2/2024 01:30 9/2/2024 02:30 1.00 COMPZN, RPCOMP RURD T Rig up circulating equipment to PT TxIA 8,260.0 8,260.0 9/2/2024 02:30 9/2/2024 04:30 2.00 COMPZN, RPCOMP PRTS P PT tubing 3500 psi 30 min marginal tubing test bleed pressure tighten landing joint in hanger PT tubing 3500psi 30min // trap 2000 psi on tubing // PT IA 3000 psi 40 min good test 8,260.0 0.0 9/2/2024 04:30 9/2/2024 05:00 0.50 COMPZN, RPCOMP RURD P Rig down circulating equipment. 0.0 0.0 9/2/2024 05:00 9/2/2024 05:30 0.50 COMPZN, RPCOMP MPSP P Set BPV. Test from below to 1,000 psi. 0.0 0.0 9/2/2024 05:30 9/2/2024 09:30 4.00 COMPZN, WHDBOP NUND P ND BOP. NU Production Tree. Confirm orientation matches pre-rig pictures. 0.0 0.0 9/2/2024 09:30 9/2/2024 11:30 2.00 COMPZN, WHDBOP PRTS P RU LRS. PT tree and tubing head adapter to 5,000 psi. 0.0 0.0 9/2/2024 11:30 9/2/2024 14:30 3.00 DEMOB, MOVE FRZP P Line up to pump down IA, taking returns from Tubing out to tanks. Pump 50 bbls diesel FP. U-Tube for 1-hr. 0.0 0.0 9/2/2024 14:30 9/2/2024 16:00 1.50 DEMOB, MOVE RURD P Clean and clear cellar and tree. Prep rig for move from 1B to 1L. Rig release @ 16:00. 0.0 0.0 Rig: NORDIC 3 RIG RELEASE DATE 9/2/2024 Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag:RKB (Est.12' of Rathole) 8,952.0 1B-07 6/9/2018 zembaej Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Post RWO, Pull B&R, RHC, Set DV, pull catcher & RBP 1B-07 9/9/2024 fergusp Notes: General & Safety Annotation End Date Last Mod By NOTE: View Schematic w/ Alaska Schematic9.0 8/6/2010 ninam 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 16 15.06 29.3 80.0 80.0 62.50 H-40 WELDED SURFACE 10 3/4 9.95 29.3 2,845.6 2,632.9 45.50 K-55 BTC Tie-Back String Production Repair 7 6.28 27.3 1,927.0 1,847.5 26.00 L-80 HYD 563 Production 7 6.28 1,924.0 9,569.9 6,933.8 26.00 K-55 BTC Tie-Back String 5 1/2 4.95 0.0 8,451.2 6,202.9 15.50 L-80 HYD 563 Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 23.3 Set Depth 8,269.5 String Max No 3 1/2 Set Depth 6,066.5 Tubing Description Tubing Completion Upper Wt (lb/ft) 9.30 Grade L-80 Top Connection HYD 563 ID (in) 2.99 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) 23.3 23.3 0.00 Hanger 7.010 Cameron 7 1/16" x 3 1/2" CXS Tubing Hanger. EUE top thread. Camero n CXS 2.950 1,989.4 1,902.9 27.89 Nipple - X 4.272 3 1/2" x 2.813" X Nipple, HES X Nipple 2.813 8,170.3 5,990.7 40.07 Mandrel GAS LIFT 4.733 3 1/2" x 1" KBG-2-9 GLM SLB KBG-2-9 2.818 8,228.1 6,034.9 40.14 Nipple - X 4.287 3 1/2" x 2.813" X Nipple, 8 HES X Nipple 2.813 8,249.2 6,051.1 40.25 Locator 4.500 Locator Baker Locator 2.992 8,249.7 6,051.4 40.25 Seal Assembly 3.500 80-40 GBH-22 Seal Assy (6' space out off No-Go) Baker GBH-22 2.992 Top (ftKB) 8,448.0 Set Depth 8,786.4 String Max No 3 1/2 Set Depth 6,443.8 Tubing Description Tubing Completion Lower Wt (lb/ft) 9.30 Grade L-80 Top Connection EUE8RDMOD ID (in) 2.99 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) 8,469.9 6,216.7 42.70 PBR 5.875 BAKER PBR w/ 10' STROKE 3.000 8,483.8 6,226.9 42.84 PACKER 6.062 PACKER FHL RETRIEVABLE PACKER 2.890 8,528.8 6,259.7 43.29 INJECTION 5.750 Camco MMM 2.920 8,574.7 6,293.0 43.75 BLAST JTS 3.500 STEEL BLAST JOINTS (OAL=147') 2.992 8,740.4 6,411.3 45.05 SLEEVE 3.250 CB-1 SLIDING SLEEVE Camco 2.260 8,753.0 6,420.2 45.15 XO Reducing 3.500 CROSSOVER 3.5 x 2.875", ID 2.441, 6.5#, J-55, EUE IPC 2.875 8,753.8 6,420.8 45.15 SEAL ASSY 3.250 LOCATOR SEAL ASSEMBLY Baker 2.375 8,755.8 6,422.3 45.17 PACKER 5.687 D PACKER Baker 3.260 8,774.6 6,435.5 45.31 NIPPLE 3.668 OTIS XN NIPPLE NO GO 2.250 8,785.8 6,443.4 45.39 SOS 3.750 SHEAR OUT SUB (SHEARED) Baker 2.441 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 25.3 25.3 0.00 EMERGENCY SLIPS 5 1/2" Tieback Emergency Slips Cameron 9/2/2024 5.500 27.3 27.3 0.00 EMERGENCY SLIPS Custom McEvoy Type SB-3 Emergency Slips 8/19/2024 7.000 8,300.0 6,089.7 40.50 OTHER 3 1/2" x 1 1/2" MMG, GLM, DMY w/ RK Latch, SN# 24135 -06 8/31/2024 2.920 9,022.0 6,600.8 51.61 FISH Slip f/ Slip stop LOST 8/1/1993 8/31/1993 0.000 9,022.0 6,600.8 51.61 FISH TIW PKR & Tbg Tail LOST 6/16/1994 6/16/1994 0.000 9,046.0 6,615.6 51.73 FISH Vann Gun 428' long GUN LOST 9/20/1981 9/20/1981 0.000 Mandrel Inserts : excludes pulled inserts Top (ftKB) Top (TVD) (ftKB) Top Incl (°) St ati on No /S Serv Valve Type Latch Type OD (in) TRO Run (psi) Run Date Com Make Model Port Size (in) 8,170.3 5,990.7 40.07 1 GAS LIFT DMY BTM 1 9/7/2024 8,528.8 6,259.7 43.29 3 INJ DMY TGP 0.0 6/16/1994 0.000 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) 0.0 0.0 0.00 Parker 141 ORKB = 25.3', Nordic 3 RKB = 27.41' 0.000 Parker 141 ORKB = 25.3', Nordic 3 RKB = 27.41' 0.000 8,257.5 6,057.4 40.29 SBR 5.020 80-40 SBR, 5" P x 4 1/2" B HYD521 P (SN#: HT- 965205 SN01) Baker 80-40 SBR 4.000 8,300.0 6,089.7 40.50 Mandrel GAS LIFT 5.906 3 1/2" x 1 1/2" MMG, GLM, DMY w/ RK Latch, SN# 24135-06 SLB MMG 2.920 1B-07, 9/26/2024 10:25:44 AM Vertical schematic (actual) Production; 1,924.0-9,569.9 FISH; 9,046.0 FISH; 9,022.0 FISH; 9,022.0 IPERF; 8,922.0-8,940.0 IPERF; 8,904.0-8,914.0 PACKER; 8,755.8 IPERF; 8,695.0-8,702.0 IPERF; 8,670.0-8,686.0 IPERF; 8,575.0-8,650.0 INJECTION; 8,528.7 PACKER; 8,483.8 Tie-Back String; 0.0-8,451.2 OTHER; 8,300.0 Nipple - X; 8,228.1 Mandrel GAS LIFT; 8,170.3 SURFACE; 29.3-2,845.6 Nipple - X; 1,989.4 Tie-Back String Production Repair ; 27.3-1,927.0 Intermediate String 1 Cement; 28.3 ftKB CONDUCTOR; 29.3-80.0 EMERGENCY SLIPS; 27.3 EMERGENCY SLIPS; 25.3 Hanger; 23.3 KUP INJ KB-Grd (ft) 32.48 RR Date 9/20/1981 Other Elev 1B-07 ... TD Act Btm (ftKB) 9,625.0 Well Attributes Field Name KUPARUK RIVER UNIT Wellbore API/UWI 500292061600 Wellbore Status INJ Max Angle & MD Incl (°) 61.00 MD (ftKB) 4,200.00 WELLNAME WELLBORE1B-07 Annotation Last WO: End Date 6/16/1994 H2S (ppm) DateComment SSSV: WRDP 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) 8,360.2 6,135.2 41.40 Packer 5.995 3 1/2" x 7" Bluepack Max RH Packer, VamTop, SN# C23P-1919 SLB Bluepack Packer 2.894 8,391.7 6,158.8 41.88 Nipple - X 4.287 3 1/2" x 2.813" X Nipple HES X Nipple 2.813 8,444.4 6,197.9 42.44 Overshot 5.990 7 x 3 1/2" PBOS (6.19' swallow, shear pins @ 3', 3' space out) Baker Poorboy Overshot 3.630 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 8,575.0 8,650.0 6,293.3 6,347.1 D, C-2, C-3, C-4, 1B-07 11/23/1981 4.0 IPERF Max angle across perf 44 8,670.0 8,686.0 6,361.4 6,372.8 C-1, UNIT B, 1B- 07 11/23/1981 4.0 IPERF 8,695.0 8,702.0 6,379.2 6,384.2 UNIT B, 1B-07 11/23/1981 4.0 IPERF 8,880.0 8,894.0 6,508.6 6,518.1 A-5, 1B-07 11/23/1981 4.0 IPERF 8,904.0 8,914.0 6,524.8 6,531.6 A-4, 1B-07 11/23/1981 4.0 IPERF 8,922.0 8,940.0 6,536.9 6,548.8 A-4, 1B-07 11/23/1981 4.0 IPERF Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 28.3 2,000.0 28.3 1,912.2 Intermediate String 1 Cement 8/19/2024 1B-07, 9/26/2024 10:25:45 AM Vertical schematic (actual) Production; 1,924.0-9,569.9 FISH; 9,046.0 FISH; 9,022.0 FISH; 9,022.0 IPERF; 8,922.0-8,940.0 IPERF; 8,904.0-8,914.0 PACKER; 8,755.8 IPERF; 8,695.0-8,702.0 IPERF; 8,670.0-8,686.0 IPERF; 8,575.0-8,650.0 INJECTION; 8,528.7 PACKER; 8,483.8 Tie-Back String; 0.0-8,451.2 OTHER; 8,300.0 Nipple - X; 8,228.1 Mandrel GAS LIFT; 8,170.3 SURFACE; 29.3-2,845.6 Nipple - X; 1,989.4 Tie-Back String Production Repair ; 27.3-1,927.0 Intermediate String 1 Cement; 28.3 ftKB CONDUCTOR; 29.3-80.0 EMERGENCY SLIPS; 27.3 EMERGENCY SLIPS; 25.3 Hanger; 23.3 KUP INJ 1B-07 ... WELLNAME WELLBORE1B-07 Originated: Delivered to:12-Sep-24 Alaska Oil & Gas Conservation Commiss 12Sep24-NR ATTN: MeredithGuhl 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 CD2-58 50-103-20457-00-00 203-085 Colville River WL SBHPS-RBP FINAL FIELD 16-Aug-24 CD2-21 50-103-20504-00-00 204-245 Colville River WL Patch FINAL FIELD 18-Aug-24 CD2-467 50-103-20579-00-00 208-114 Colville River WL Patch FINAL FIELD 20-Aug-24 1B-07 50-029-20616-00-00 181-089 Kuparuk River WL MechCutter FINAL FIELD 24-Aug-24 2A-11 50-103-20057-00-00 186-003 Kuparuk River WL Isealate Patch FINAL FIELD 27-Aug-24 3F-11 50-029-21482-00-00 185-272 Kuparuk River WL IPROF FINAL FIELD 29-Aug-24 2A-20 50-103-20196-00-00 193-151 Kuparuk River WL IPROF FINAL FIELD 30-Aug-24 3F-20 50-029-22947-00-00 199-079 Kuparuk River WL IPROF FINAL FIELD 2-Sep-24 3J-18 50-029-22701-00-00 196-147 Kuparuk River WL Lee-PPROF FINAL FIELD 3-Sep-24 2U-12 50-029-21304-00-00 185-041 Kuparuk River WL PPROF FINAL FIELD 4-Sep-24 1D-39 50-029-22997-00-00 200-216 Kuparuk River WL Punch-Cut FINAL FIELD 9-Sep-24 2P-448A 50-103-20396-01-00 202-005 Kuparuk River WL Punch FINAL FIELD 10-Sep-24 2P-432 50-103-20420-00-00 202-091 Kuparuk River WL Punch FINAL FIELD 11-Sep-24 2P-434 50-103-20467-00-00 203-153 Kuparuk River WL Punch FINAL FIELD 11-Sep-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 T39555 T39556 T39557 T39558 T39559 T39560 T39561 T39562 T39564 T39565 T39566 T39567 T39668 T39563 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.09.13 08:31:59 -08'00' 1B-07 50-029-20616-00-00 181-089 Kuparuk River WL MechCutter FINAL FIELD 24-Aug-24 T39558 ORIGINATED TRANSMITTAL DATE: 9/4/2024 ALASKA E-LINE SERVICES TRANSMITTAL #: 5027 42260 Kenai Spur Hwy PO BOX 1481 - Kenai, Alaska 99611 FIELD Kuparuk River PH: (907) 283-7374 FAX: (907) 283-7378 DELIVERABLE DESCRIPTION TICKET # WELL # API # LOG DESCRIPTION DATE OF LOG 5027 1B-07 50029206160000 Hoist (with logs) 30-Aug-2024 RECIPIENTS ConocoPhillips Alaska, Inc. DIGITAL FILES PRINTS CD'S 1 0 0 0 USPS 0 0 0 0 Received By: Received By: Signature Signature AOGCC DIGITAL FILES PRINTS CD'S 1 ShareFile 0 0 USPS Attn: Natural Resources Technician II abby.bell@alaska.gov Alaska Oil & Gas Conservation Commision aogcc.data@alaska.gov 333 W. 7th Ave, Suite 100 - Anchorage, AK 99501 Received By: Received By: Signature Signature 181-089 T39514 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.09.04 10:10:05 -08'00' DNR DIGITAL FILES PRINTS CD'S 1 SharePoint Link 0 0 USPS Attn: Natural Resource Tech II DOG.Redata@alaska.gov 550 West 7th Ave, Suite #802 - Anchorage, AK 99501 Delivery Method: USPS Received By: Received By: Signature Signature Please return via e-mail a copy to both: AR@ake- line.com AKGGREDTSupport@ConocoPhillips.onmicrosoft.com STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________KUPARUK RIV UNIT 1B-07 JBR 10/16/2024 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:0 Good test. BOP Misc.: 2 each 2 1/16” 5K gate valves on test spool located on BOP stack below the lower rams. Choke Misc.: 3” Demco valve located on the downstream of the manifold. Test Results TEST DATA Rig Rep:Hansen/BezoldOperator:ConocoPhillips Alaska, Inc.Operator Rep:Wiese/Erdman Rig Owner/Rig No.:Nordic 3 PTD#:1810890 DATE:8/30/2024 Type Operation:WRKOV Annular: 250/3000Type Test:BIWKLY Valves: 250/3000 Rams: 250/3000 Test Pressures:Inspection No:bopAGE240904131243 Inspector Adam Earl Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time MASP: 2539 Sundry No: 324-295 Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 2 P Inside BOP 1 P FSV Misc 0 NA 12 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 1 PCH Misc Stripper 0 NA Annular Preventer 1 13 5/8"P #1 Rams 1 2 7/8 X 5 1/2"P #2 Rams 1 Blind P #3 Rams 1 7"NT #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3 1/8"P HCR Valves 2 3 1/8"P Kill Line Valves 1 3 1/8"P Check Valve 0 NA BOP Misc 2 2 1/16"P System Pressure P3050 Pressure After Closure P1650 200 PSI Attained P22 Full Pressure Attained P124 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P4@ 2000 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector 0 NAMS Misc Inside Reel Valves 0 NA Annular Preventer P17 #1 Rams P5 #2 Rams P5 #3 Rams NT0 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P1 9 9 9 9999 9 9 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: Kuparuk Oil Pool Kuparuk Oil Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 9625'2539 9022' 9046' Casing Collapse Conductor Surface Production 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: 907-265-6049 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 Kuparuk River Field Cy Eller cy.eller@conocophillips.com CTD/RWO Engineer Subsequent Form Required: Suspension Expiration Date: L-80 TVD 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 AOGCC USE ONLY Tubing Grade: Tubing MD (ft): 8484'MD/6227'TVD 8756'MD/6422'TVD Perforation Depth TVD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025648 181-089 P.O. Box 100360, Anchorage, AK 99510 50-029-20616-00-00 ConocoPhillips Alaska, Inc Proposed Pools: Burst 8786' MD 80' 2633' 80' 2846' 6934'7" 16" 10-3/4" 51' 2817' 9570' Perforation Depth MD (ft): 7/17/2024 3.5" x 2-7/8" FHL Retrievable Baker D Packer SSSV: None 8519'8952'6968' 6557' KRU 1B-07 8575-8650' 8670-8686' 8695-8702' 8880-8894' 8904-8914' 8922-8940' 9543' 6293-6347' 6361-6373' 6379-6384' 6509-6518' 6525-6532' 6537-6549' Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 324-498 By Grace Christianson at 1:05 pm, Aug 30, 2024 A.Dewhurst 30AUG24 Victoria Loepp on 8/30/2024 DSR-8/30/24 8/30/2024 10-404 VTL 9/3/2024 X X BOP test to 3000 psig Annular preventer test to 2500 psig X *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.09.03 16:35:29 -08'00' 09/03/24 RBDMS JSB 090524 1B-07 RWO Procedure Kuparuk Injector - RWO PTD #181-089 Page 1 of 3 General Well info: Wellhead type/pressure rating: McEvoy Gen 1 Retro to Gen IV Production Engineer: Banabas Dogah Reservoir Development Engineer: Cody Keith Estimated Start Date: 7/17/24 Workover Engineer: James Ohlinger (265-1102/ James.J.Ohlinger@conocophillips.com) Current Operations: This well is currently shut in. Well Type: Injector Scope of Work: Pull the existing 3-1/2” completion down to the pre-rig cut above the packer. A new 3-1/2” tubing string with a Poor-boy overshot and stack packer. A subsidence repair job will also be conducted on the 7” casing. A 5-1/2” tie-back liner will be installed before running the 3-1/2” completion. BOP configuration: Annular / Pipe Rams / Blind Rams / Mud Cross / Pipe Ram Following subject to change/be updated with pre-rig work: MIT results: MIT-T: Passed 12/06/23 MIT-IA: Passed 12/06/23. Failed 8/29/24 after running new completion. MIT-OA: Inconclusive as a leak is estimated at 1561’ RKB IC POT & PPPOT Passed – 8/24/2023 MPSP: 2539 psi using 0.1 psi/ft gradient Static BHP: 3183 psi / 6436’ TVD measured on 9/5/2018 Remaining Pre-Rig Work 1. IC-POT, IC-PPPOT, T-PPPOT and T-POT tests. 2. MIT-IA or CMIT-TxIA 3. MIT-OA 4. Open lowest GLM in upper completion 5. Cut the tubing at ~8448 RKB in the middle of the first full joint above the packer @ 8484’ RKB 6. Prepare well within 48 hrs of rig arrival. 1B-07 RWO Procedure Kuparuk Injector - RWO PTD #181-089 Page 2 of 3 Rig Work MIRU 19. MIRU Nordic 3 on 1B-07 (No BPV will be installed due to risk assessment done for MIRU/RDMO on N3 w/o BPV.) 20. Record shut-in pressures on the T & IA. If there is pressure, bleed off IA and/or tubing pressure and complete 30-minute NFT. Verify well is dead. Circulate KWF as needed. 21. Set BPV and confirm as barrier if needed, ND Tree, NU BOPE and test to 250/3,000 psi. Test annular 250/3,000 psi. Retrieve Tubing 22. Pull BPV, MU landing joint and BOLDS. 23. Pull 3-1/2” tubing down to pre-rig cut (~8448’ RKB). a. If not all tubing comes due to subsidence, then work additional steps below to clear buckled 7”, then pull remaining completion. b. *Depending on drifts, go to “Contingency for Subsidence on 7.0”. Subsidence on 7.0” 7” Casing is currently landed on a Mandrel Hanger. We don’t plan on stretching the 7” Casing as there is an estimated 69” of subsidence and a grow/stretch operation might not give enough length to remove the mandrel. Pull Subsided 7.0” Casing 24. Set storm packer or plug (with ~50’ sand) in 7” casing and PT to confirm as barrier. 25. ND BOPE. ND old tubing spool. NU BOPE and test flange break. 26. RU Eline and log 7.0” casing for OA cement 27. Cut 7.0” casing with cutter above OA cement. a. Circulate out Arctic Pack diesel/slurry if needed. 28. Pull 7.0” casing down to cut (~2000’). a. Make addition cut/pulls/BHA runs as necessary to remove 7”. b. Test 11” 3k flange to 3000 psig if not already done so. Bore out 10-3/4” and run 7.0” Tie-Back Subsidence Before Running 3.5” tubing 11. PU mills and bore out 10-3/4” as necessary to obtain drift for new 7.0” tie-back. a. As drift is regained, pull any additional 7.0” or 3.5” tubing as needed to get 7.0” removed down to cement in OA. 12. Run new 7.0” tie-back casing with overshot. 13. Test casing to 2500 psig. 14. Cement OA to surface. 15. Perform 30 minute no flow test, split stack and land slips, cut excess casing and install IC packoffs. Installed Tie- back spool and terminate 7.0”. Land stack and MU to casing flange. a. Test flange break to BOPE test pressure. 16. Mill plugs in cementer. 17. Circulate out sand on IBP or any lower plug. 18. Pull any lower plugs or remaining 3.5”. 19. Test casing to 3000 psi for 30 minutes. 1B-07 RWO Procedure Kuparuk Injector - RWO PTD #181-089 Page 3 of 3 Install in 3-½” Completion 20. MU 3 ½” completion with poor-boy overshot, nipple profiles, and GLM. RIH with completion. 21. Once on depth, circulate CI brine, space out as needed, land hanger, RILDS, drop B&R, and set packer. 22. Pressure test tubing to 3000 psi 3500 psi for 30 minutes and chart. 23. Pressure test inner annulus to 2500 psi 3000 psi for 30 minutes on chart. a. 3000 psi IA test failed. Pull 3-1/2” Completion 24. RU E-Line and cut the cut-to-release packer 25. TOOH Racking back 3-1/2” tubing. 26. On TOOH, MU and set storm packer and PT to confirm as a barrier. 27. ND BOPs, ND tubing head, NU casing head, NU BOPs, test flange breaks. 28. Release storm packer and continue to TOOH with remaining tubing. Run 5-1/2” Tie-Back 29. PU and RIH with 5-1/2” tie-back liner with non-sealing overshot and 3-1/2” x 7” packer. 30. Pump CI and land. RILDS. 31. Drop ball and rod and set packer. a. PT 5-1/2” casing against RBP at 8519’ RKB to 3000 psi. b. Shear SOV and pump diesel freeze protect down new OA. Run 3-1/2” Completion 32. Set 5-1/2” RBP and PT to confirm as a barrier. 33. ND BOPs, NU tubing head, NU BOPs, test flange breaks. 34. Pull 5-1/2” RBP. 35. RIH with 3-1/2” tubing from derrick making up new jewelry as needed. 36. Pump CI, locate seals, land tubing hanger, RILDS. 37. Pressure test tubing to 3500 psi for 30 minutes and chart. 38. Pressure test IA to 3000 psi for 30 minutes and chart. ND BOP, NU Tree 39. Confirm pressure tests, then shear out SOV with pressure differential. 40. Install BPV. 41. ND BOPE. NU tree. PT tree. 42. Pull BPV, freeze protect well at opportune time, and set BPV if necessary. 43. RDMO. Post-Rig Work 44. Install GLD. 45. Pull Ball and Rod 46. Pull any remaining plugs in well. 47. Turn over to operations. Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag:RKB (Est.12' of Rathole) 8,952.0 1B-07 6/9/2018 zembaej Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Added tubing cut @ 8448' RKB 1B-07 7/7/2024 jconne Notes: General & Safety Annotation End Date Last Mod By NOTE: View Schematic w/ Alaska Schematic9.0 8/6/2010 ninam 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 16 15.06 29.3 80.0 80.0 62.50 H-40 WELDED SURFACE 10 3/4 9.95 29.3 2,845.6 2,632.9 45.50 K-55 BTC PRODUCTION 7 6.28 27.3 9,569.9 6,933.8 26.00 K-55 BTC Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 25.3 Set Depth … 8,786.4 Set Depth … 6,443.7 String Max No… 3 1/2 Tubing Description TUBING WO 3.5 "x2.875" Wt (lb/ft) 9.30 Grade L-80 Top Connection EUE8RDMOD ID (in) 2.99 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) 25.3 25.3 0.00 HANGER 8.000 MCEVOY GEN IV HANGER 3.500 1,890.7 1,815.2 27.09 NIPPLE 4.500 CAMCO W LANDING NIPPLE 2.812 8,420.3 6,180.1 42.20 GAS LIFT 5.750 CAMCO MMM 2.920 8,469.9 6,216.6 42.70 PBR 5.875 BAKER PBR w/ 10' STROKE 3.000 8,483.8 6,226.8 42.84 PACKER 6.062 PACKER FHL RETRIEVABLE PACKER 2.890 8,528.7 6,259.7 43.29 INJECTION 5.750 CAMCO MMM 2.920 8,574.7 6,293.0 43.75 BLAST JTS 3.500 STEEL BLAST JOINTS (OAL=147') 2.992 8,740.3 6,411.3 45.05 SLEEVE 3.250 CAMCO CB-1 SLIDING SLEEVE 2.260 8,752.9 6,420.2 45.15 XO Reducing 3.500 CROSSOVER 3.5 x 2.875", ID 2.441, 6.5#, J-55, EUE IPC 2.875 8,753.7 6,420.8 45.15 SEAL ASSY 3.250 BAKER LOCATOR SEAL ASSEMBLY 2.375 8,755.8 6,422.2 45.17 PACKER 5.687 BAKER D PACKER 3.260 8,774.5 6,435.4 45.31 NIPPLE 3.668 OTIS XN NIPPLE NO GO 2.250 8,785.8 6,443.3 45.39 SOS 3.750 BAKER SHEAR OUT SUB (SHEARED) 2.441 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 8,448.0 6,200.5 42.48 CUT WELLTEC MECHANICAL TUBING CUT. TATTLE-TAIL INDICATED 3.6" BLADE EXTENSION WELLTE C MECHA NICAL 7/7/2024 2.992 8,510.0 6,246.1 43.10 CATCHER 2.29'' JUNK CATCHER/P2P STINGER(OAL 64'') 5/30/2024 0.000 8,519.0 6,252.6 43.19 PLUG - RBP PARRAGON RBP, 2.72'' OD, ( CPP35184 ) EQ VLV ( CPEQ35017 ) FILL EXT & BULL PLUG ( OAL = 8.53'') 9/12/2018 0.000 9,022.0 6,600.8 51.61 FISH Slip f/ Slip stop LOST 8/1/1993 8/31/1993 0.000 9,022.0 6,600.8 51.61 FISH TIW PKR & Tbg Tail LOST 6/16/1994 6/16/1994 0.000 9,046.0 6,615.6 51.73 FISH Vann Gun 428' long GUN LOST 9/20/1981 9/20/1981 0.000 Mandrel Inserts : excludes pulled inserts Top (ftKB) Top (TVD) (ftKB) Top Incl (°) St ati on No /S Serv Valve Type Latch Type OD (in) TRO Run (psi) Run Date Com Make Model Port Size (in) 8,420.3 6,180.1 42.20 1 GAS LIFT OPEN 1 1/2 5/30/2024 8,528.7 6,259.7 43.29 2 INJ DMY TGP 1 1/2 0.0 6/16/1994 0.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 8,575.0 8,650.0 6,293.3 6,347.1 D, C-2, C-3, C-4, 1B-07 11/23/1981 4.0 IPERF Max angle across perf 44 8,670.0 8,686.0 6,361.4 6,372.8 C-1, UNIT B, 1B- 07 11/23/1981 4.0 IPERF 8,695.0 8,702.0 6,379.2 6,384.2 UNIT B, 1B-07 11/23/1981 4.0 IPERF 8,880.0 8,894.0 6,508.6 6,518.1 A-5, 1B-07 11/23/1981 4.0 IPERF 8,904.0 8,914.0 6,524.8 6,531.6 A-4, 1B-07 11/23/1981 4.0 IPERF 8,922.0 8,940.0 6,536.9 6,548.8 A-4, 1B-07 11/23/1981 4.0 IPERF 1B-07, 7/7/2024 4:23:16 PM Vertical schematic (actual) PRODUCTION; 27.3-9,569.9 FLOAT SHOE; 9,568.3-9,569.9 FLOAT COLLAR; 9,472.0- 9,473.6 FISH; 9,046.0 FISH; 9,022.0 FISH; 9,022.0 IPERF; 8,922.0-8,940.0 IPERF; 8,904.0-8,914.0 SOS; 8,785.8 NIPPLE; 8,774.5 PACKER; 8,755.8 SEAL ASSY; 8,753.7 SLEEVE; 8,740.3 IPERF; 8,695.0-8,702.0 IPERF; 8,670.0-8,686.0 IPERF; 8,575.0-8,650.0 INJECTION; 8,528.7 PLUG - RBP; 8,519.0 CATCHER; 8,510.0 PACKER; 8,483.8 PBR; 8,469.9 CUT; 8,448.0 GAS LIFT; 8,420.3 ECP; 8,340.9-8,348.9 DV CASING TOOL; 5,236.0- 5,240.3 SURFACE; 29.3-2,845.6 FLOAT SHOE; 2,843.7-2,845.6 FLOAT COLLAR; 2,755.8- 2,757.7 NIPPLE; 1,890.7 CONDUCTOR; 29.3-80.0 HANGER; 29.3-33.7 HANGER; 27.3-31.9 HANGER; 25.3 KUP INJ KB-Grd (ft) 32.48 RR Date 9/20/1981 Other Elev… 1B-07 ... TD Act Btm (ftKB) 9,625.0 Well Attributes Field Name KUPARUK RIVER UNIT Wellbore API/UWI 500292061600 Wellbore Status INJ Max Angle & MD Incl (°) 61.00 MD (ftKB) 4,200.00 WELLNAME WELLBORE1B-07 Annotation Last WO: End Date 6/16/1994 H2S (ppm) DateComment SSSV: WRDP 1B-07 Proposed RWO Completion Injector COMPLETION INFO MD (ft RKB) TVD (ft RKB) OD (in) Nom. ID (in) Weight (lb/ft)Grade Thread (top) Conductor 80 80 16 15.06 62.5 H40 Welded Surface 2846 2633 10.75 9.95 45.5 K55 BTC Production 9570 6934 7 6.28 26 K55 BTC/HYD563 Tie-Back Liner 8448 6070 5.5 4.95 26 L80 HYD563 MS Tubing 8275 6444 3.5 2.99 9.3 L80 HYD563 PRODUCTION CASING REPAIR 7.0" , 26# L80 HYD563 casing from cut to surface 7" Cementing tool for IA 7" Sealing Overshot PROPOSED 5-1/2" TIE-BACK LINER 5-1/2" 15.5# L-80 HYD563 MS Casing to Surface PBR to recieve 80-40 seal assembly 3-1/2" x 1-1/2" GLM 3-1/2" x 7" Cut-to-release packer 2.813" X Nipple profile 3-1/2" Non-sealing Overshot PROPOSED COMPLETION 3-1/2" 9.3# L-80 HYD563 tubing to surface 3-1/2" x 1" gas lift mandrel 3-½" X landing (2.813" min ID) 80-40 Locator Seal Assembly REMAINING COMPLETION LEFT IN HOLE 3.5" x 7.0" FHL Packer @ 8484' RKB (2.89" ID) 3.5" Blast Joints 3.5" x 2.875" Crossover Surface Casing Production/Intermediate Casing Conductor A-sand perfs C-Sand Perfs PC leak. Unknown depth RBP @ 8519' RKB 1 Eller, Cy From:Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Sent:Friday, August 30, 2024 8:09 AM To:Eller, Cy Subject:[EXTERNAL]RE: 1B-07 RWO Sundry # 324-295 - 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. Cy, Approval is granted to proceed with this plan forward. Please submit a change of approved program 10- 403 sundry as soon as possible. Victoria Victoria Loepp Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Work: (907)793-1247 &ƌŽŵ͗ůůĞƌ͕ǇфǇ͘ůůĞƌΛĐŽŶŽĐŽƉŚŝůůŝƉƐ͘ĐŽŵх ^ĞŶƚ͗dŚƵƌƐĚĂǇ͕ƵŐƵƐƚϮϵ͕ϮϬϮϰϵ͗ϭϮWD dŽ͗>ŽĞƉƉ͕sŝĐƚŽƌŝĂd;K'ͿфǀŝĐƚŽƌŝĂ͘ůŽĞƉƉΛĂůĂƐŬĂ͘ŐŽǀх Đ͗,ŽďďƐ͕'ƌĞŐ^ф'ƌĞŐ͘^͘,ŽďďƐΛĐŽŶŽĐŽƉŚŝůůŝƉƐ͘ĐŽŵх͖EĞǌĂƚŝĐŬǇ͕WĞƚĞƌфW͘EĞǌĂƚŝĐŬǇΛĐŽŶŽĐŽƉŚŝůůŝƉƐ͘ĐŽŵх͖ŽďĞƌůǇ͕ :ŽŶĂƚŚĂŶф:ŽŶĂƚŚĂŶ͘ŽďĞƌůǇΛĐŽŶŽĐŽƉŚŝůůŝƉƐ͘ĐŽŵх͖ŽŵƉĂŶǇDĂŶ͕EŽ ƌĚŝĐϯ фEŽƌĚŝĐϯ͘ŽŵƉĂŶǇDĂŶΛĐŽŶŽĐŽƉŚŝůůŝƉƐ͘ĐŽŵх ^ƵďũĞĐƚ͗ϭͲϬϳZtK^ƵŶĚƌǇηϯϮϰͲϮϵϱͲWůĂŶ&ŽƌǁĂƌĚ Hi Victoria, Nordic 3 is currently performing a workover on KRU 1B-07 (Sundry #324-295). After completing the subsidence repair portion of this workover, we got a good PT of the 7” casing to 3000 psi for 30 minutes and began and running the new 3-1/2” completion. After setting the packer we got a good PT on the tubing, but when attempting to PT the IA we noticed a leak around the tubing hanger. We pulled the hanger o Ư seat, Ʋushed the tubing head, re-set the hanger and attempted to PT the IA again and had a leak in the same location around the tubing hanger. Without a way to inspect or remove the tubing hanger, we made the decision rig up E-Line and make a cut in the cut-to-release packer and pull the completion out of hole and rack it back in the derrick. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 With the completion out of the hole we inspected the tubing hanger, redressed it and set it in the tubing head proƱle and attempted to test it from above and below with no success. We then ND the BOPs and changed out the tubing head. We made two cleanout runs and got another passing test on the 7” casing against the deep set RBP at 8519’ RKB to 3000 psi for 30 minutes so we laid down our drillpipe and ran in hole with our completion from the derrick. We landed the tubing hanger and got a good test on it from above last night, so we dropped the ball and rod and set the packer. We got a passing PT on the tubing, but are still unable to get a passing PT on the IA. We rigged up slickline and pulled the ball and rod and PT’d the tubing and got a good test, but still could not get a good test on the IA. We are currently starting our bi-weekly BOP test. With the multiple failed IA tests, we believe that we have a PC leak, but the LLR is small (~1 gpm at 3200 psi) so we do not feel conƱdent in being able to locate the leak with a test packer. We believe that running a 5-1/2” tie-back liner gives us the highest chance of success for completing the intended scope of this workover. Attached is the proposed 5-1/2” tie-back schematic. We are seeking verbal approval to proceed with the plan forward as outlined below: Install in 3-½” Completion 1. MU 3 ½” completion with poor-boy overshot, nipple proƱles, and GLM. RIH with completion. 2. Once on depth, circulate CI brine, space out as needed, land hanger, RILDS, drop B&R, and set packer. 3. Pressure test tubing to 3500 psi for 30 minutes and chart. 4. Pressure test inner annulus to 3000 psi for 30 minutes on chart. (Failed) Pull 3-½” Completion 5. RU E-Line and cut the cut-to-release packer. 6. TOOH racking back 3-1/2” tubing 7. On TOOH, MU and set storm packer and PT to conƱrm as a barrier. 8. ND BOPs, ND tubing head, NU casing head, NU BOPs, test Ʋange breaks. 9. Release storm packer and continue to TOOH with remaining tubing. Run 5-1/2” Tie-back 10. PU and RIH with 5-1/2” tie-back liner with non-sealing overshot and 3-1/2” x 7” packer. 11. Pump CI and land. RILDS. 12. Drop ball and rod and set packer. a. PT 5-1/2” casing against RBP at 8519’ RKB to 3000 psi. b. Shear SOV and pump diesel freeze protect down new OA. Run 3-½” Completion 13. Set 5-1/2” RBP and PT to conƱrm as a barrier. 14. ND BOPs, NU tubing head, NU BOPs, test Ʋange breaks. 15. Pull 5-1/2” RBP. 16. RIH with 3-1/2” tubing from derrick making up new jewelry as needed. 17. Pump CI, locate seals, land tubing hanger, RILDS. 18. Pressure test tubing to 3500 psi for 30 minutes and chart. 19. Pressure test IA to 3000 psi for 30 minutes and chart. ND BOP, NU Tree 20. ConƱrm pressure tests, then shear out SOV with pressure di Ưerential. 21. Install BPV. 22. ND BOPE. NU tree. PT tree. 23. Pull BPV, freeze protect well at opportune time, and set BPV if necessary. 24. RDMO. I appreciate your consideration of this plan; I will follow up this email with a phone call in the morning. Thank you very much, 3 Cy Eller RWO/CTD Engineer ConocoPhillips Alaska OƯice: 907-265-6049 Cell: 907-232-4090 ORIGINATED TRANSMITTAL DATE: 8/26/2024 ALASKA E-LINE SERVICES TRANSMITTAL #: 5002 42260 Kenai Spur Hwy PO BOX 1481 - Kenai, Alaska 99611 FIELD Kuparuk PH: (907) 283-7374 FAX: (907) 283-7378 DELIVERABLE DESCRIPTION TICKET # WELL # API # LOG DESCRIPTION DATE OF LOG 5002 1B-07 50029206160000 Cement Bond Log 15-Aug-2024 RECIPIENTS Conoco DIGITAL FILES PRINTS CD'S 1 FTP Transfer 0 0 USPS Attn: NSK-69 tom.osterkamp@conocophillips.com 700 G Street Anchorage, AK 99503 Received By: Received By: Signature Signature AOGCC DIGITAL FILES PRINTS CD'S 1 SharePoint Link 0 0 USPS Attn: Natural Resources Technician II abby.bell@alaska.gov Alaska Oil & Gas Conservation Commision 333 W. 7th Ave, Suite 100 - Anchorage, AK 99501 Received By: Received By: Signature Signature 181-089 T39484 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.08.26 10:29:39 -08'00' DNR DIGITAL FILES PRINTS CD'S 1 SharePoint Link 0 0 USPS Attn: Natural Resource Tech II DOG.Redata@alaska.gov 550 West 7th Ave, Suite #802 - Anchorage, AK 99501 Delivery Method: USPS Received By: Received By: Signature Signature Please return via e-mail a copy to both: AR@ake- line.com tom.osterkamp@conocophillips.com ORIGINATED TRANSMITTAL DATE: 7/16/2024 ALASKA E-LINE SERVICES TRANSMITTAL #: 4916 42260 Kenai Spur Hwy PO BOX 1481 - Kenai, Alaska 99611 FIELD Kuparuk PH: (907) 283-7374 FAX: (907) 283-7378 DELIVERABLE DESCRIPTION TICKET # WELL # API # LOG DESCRIPTION DATE OF LOG 4916 1B-07 500292061600 Hoist (with logs) 7-Jul-2024 RECIPIENTS ConocoPhillips Alaska, Inc. DIGITAL FILES PRINTS CD'S 1 0 0 0 USPS 0 0 0 0 Received By: Received By: Signature Signature AOGCC DIGITAL FILES PRINTS CD'S 1 SharePoint Link 0 0 USPS Attn: Natural Resources Technician II abby.bell@alaska.gov Alaska Oil & Gas Conservation Commision 333 W. 7th Ave, Suite 100 - Anchorage, AK 99501 Received By: Received By: Signature Signature 181-089 T39216 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.07.16 11:56:13 -08'00' DNR DIGITAL FILES PRINTS CD'S 1 SharePoint Link 0 0 USPS Attn: Natural Resource Tech II DOG.Redata@alaska.gov 550 West 7th Ave, Suite #802 - Anchorage, AK 99501 Delivery Method: USPS Received By: Received By: Signature Signature Please return via e-mail a copy to both: AR@ake- line.com 0 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: Kuparuk Oil Pool Kuparuk Oil Pool 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 9625'2539 9022' 9046' Casing Collapse Conductor Surface Production 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: 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 Kuparuk River Field James Ohlinger james.j.ohlinger@conocophillips.com CTD/RWO Engineer Subsequent Form Required: Suspension Expiration Date: L-80 TVD 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 AOGCC USE ONLY Tubing Grade:Tubing MD (ft): 8484'MD/6227'TVD 8756'MD/6422'TVD Perforation Depth TVD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025648 181-089 P.O. Box 100360, Anchorage, AK 99510 50-029-20616-00-00 ConocoPhillips Alaska, Inc Proposed Pools: Burst 8786' MD 80' 2633' 80' 2846' 6934'7" 16" 10-3/4" 51' 2817' 9570' Perforation Depth MD (ft): 7/17/2024 3.5" x 2-7/8" FHL Retrievable Baker D Packer SSSV: None 8519'8952'6968'6557' KRU 1B-07 8575-8650' 8670-8686' 8695-8702' 8880-8894' 8904-8914' 8922-8940' 9543' 6293-6347' 6361-6373' 6379-6384' 6509-6518' 6525-6532' 6537-6549' m n P s 1 6 5 6 t g N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Contact Phone: 907-265-1102 By Grace Christianson at 9:43 am, May 16, 2024 Digitally signed by James J. Ohlinger DN: C=US, OU=ConocoPhillips, O=Wells - Coiled Tubing Drlling, CN=James J. Ohlinger, E=James.J.Ohlinger@ cop.com Reason: I am the author of this document Location: Date: 2024.05.16 09:07:42-08'00' Foxit PDF Editor Version: 13.0.0 James J. Ohlinger 324-295 X VTL 6/24/2024 DSR-5/20/23 X BOP test to 3000 psig Annular preventer test to 2500 psig. 10-404 SFD 5/17/2024 X *&:JLC 6/24/2024 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.06.24 15:21:10 -08'00'06/24/24 RBDMS JSB 062624 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 May 15, 2024 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: James J. Ohlinger Staff CTD/RWO Engineer CPAI Drilling and Wells ConocoPhillips Alaska, Inc. hereby submits an Application for Sundry Approval to work over KUP Injector 1B-07 (PTD# 181-089). Well 1B-07 was drilled and completed in September of 1981 by Parker 141 as a producer into the A-sands. The well was converted over to an injector in 1990. If you have any questions or require any further information, please contact me at +1 907-229-3338. The tubing above the packer will be pulled and replaced. A "subsidence" repair will be performed on the 7" casing. 1B-07 RWO Procedure Kuparuk Injector - RWO PTD #181-089 Page 1 of 3 General Well info: Wellhead type/pressure rating: McEvoy Gen 1 Retro to Gen IV Production Engineer: Banabas Dogah Reservoir Development Engineer: Cody Keith Estimated Start Date: 7/17/24 Workover Engineer: James Ohlinger (265-1102/ James.J.Ohlinger@conocophillips.com) Current Operations: This well is currently shut in. Well Type: Injector Scope of Work: Pull the existing 3-1/2” completion down to the pre-rig cut above the packer. A new 3-1/2” tubing string with a Poor-boy overshot and stack packer. A subsidence repair job will also be conducted on the 7” casing. BOP configuration: Annular / Pipe Rams / Blind Rams / Mud Cross / Pipe Ram Following subject to change/be updated with pre-rig work: MIT results: MIT-T: Passed 12/06/23 MIT-IA: Passed 12/06/23 MIT-OA: Inconclusive as a leak is estimated at 1561’ RKB IC POT & PPPOT Passed – 8/24/2023 MPSP: 2539 psi using 0.1 psi/ft gradient Static BHP: 3183 psi / 6436’ TVD measured on 9/5/2018 Remaining Pre-Rig Work 1. IC-POT, IC-PPPOT, T-PPPOT and T-POT tests. 2. MIT-IA or CMIT-TxIA 3. MIT-OA 4. Open lowest GLM in upper completion 5. Cut the tubing at ~8448 RKB in the middle of the first full joint above the packer @ 8484’ RKB 6. Prepare well within 48 hrs of rig arrival. 1B-07 RWO Procedure Kuparuk Injector - RWO PTD #181-089 Page 2 of 3 Rig Work MIRU 1. MIRU Nordic 3 on 1B-07 (No BPV will be installed due to risk assessment done for MIRU/RDMO on N3 w/o BPV.) 2. Record shut-in pressures on the T & IA. If there is pressure, bleed off IA and/or tubing pressure and complete 30-minute NFT. Verify well is dead. Circulate KWF as needed. 3. Set BPV and confirm as barrier if needed, ND Tree, NU BOPE and test to 250/3,000 psi. Test annular 250/3,000 psi. Retrieve Tubing 4. Pull BPV, MU landing joint and BOLDS. 5. Pull 3-1/2” tubing down to pre-rig cut (~8448’ RKB). a. If not all tubing comes due to subsidence, then work additional steps below to clear buckled 7”, then pull remaining completion. b. *Depending on drifts, go to “Contingency for Subsidence on 7.0”. Subsidence on 7.0” 7” Casing is currently landed on a Mandrel Hanger. We don’t plan on stretching the 7” Casing as there is an estimated 69” of subsidence and a grow/stretch operation might not give enough length to remove the mandrel. Pull Subsided 7.0” Casing 6. Set storm packer or plug (with ~50’ sand) in 7” casing and PT to confirm as barrier. 7. ND BOPE. ND old tubing spool. NU BOPE and test flange break. 8. RU Eline and log 7.0” casing for OA cement 9. Cut 7.0” casing with cutter above OA cement. a. Circulate out Arctic Pack diesel/slurry if needed. 10. Pull 7.0” casing down to cut (~2000’). a. Make addition cut/pulls/BHA runs as necessary to remove 7”. b. Test 11” 3k flange to 3000 psig if not already done so. Bore out 10-3/4” and run 7.0” Tie-Back Subsidence Before Running 3.5” tubing 11. PU mills and bore out 10-3/4” as necessary to obtain drift for new 7.0” tie-back. a. As drift is regained, pull any additional 7.0” or 3.5” tubing as needed to get 7.0” removed down to cement in OA. 12. Run new 7.0” tie-back casing with overshot. 13. Test casing to 2500 psig. 14. Cement OA to surface. 15. Perform 30 minute no flow test, split stack and land slips, cut excess casing and install IC packoffs. Installed Tie- back spool and terminate 7.0”. Land stack and MU to casing flange. a. Test flange break to BOPE test pressure. 16. Mill plugs in cementer. 17. Circulate out sand on IBP or any lower plug. 18. Pull any lower plugs or remaining 3.5”. 1B-07 RWO Procedure Kuparuk Injector - RWO PTD #181-089 Page 3 of 3 Install in 3-½” Completion 19. MU 3 ½” completion with poor-boy overshot, nipple profiles, and GLM. RIH with completion. 20. Once on depth, circulate CI brine, space out as needed, land hanger, RILDS, drop B&R, and set packer. 21. Pressure test tubing to 3000 psi for 30 minutes and chart. 22. Pressure test inner annulus to 2500 psi for 30 minutes on chart. ND BOP, NU Tree 23. Confirm pressure tests, then shear out SOV with pressure differential. 24. Install BPV. 25. ND BOPE. NU tree. PT tree. 26. Pull BPV, freeze protect well at opportune time, and set BPV if necessary. 27. RDMO. Post-Rig Work 28. Install GLD. 29. Pull Ball and Rod 30. Pull any remaining plugs in well. 31. Turn over to operations. Casing Strings Casing Description CONDUCTOR OD (in) 16 ID (in) 15.06 Top (ftKB) 29.3 Set Depth (ftKB) 80.0 Set Depth (TVD) … 80.0 Wt/Len (l… 62.50 Grade H-40 Top Thread WELDED Casing Description SURFACE OD (in) 10 3/4 ID (in) 9.95 Top (ftKB) 29.3 Set Depth (ftKB) 2,845.6 Set Depth (TVD) … 2,632.9 Wt/Len (l… 45.50 Grade K-55 Top Thread BTC Casing Description PRODUCTION OD (in) 7 ID (in) 6.28 Top (ftKB) 27.3 Set Depth (ftKB) 9,569.9 Set Depth (TVD) … 6,933.8 Wt/Len (l… 26.00 Grade K-55 Top Thread BTC Tubing Strings Tubing Description TUBING WO 3.5 "x2.875" String Ma… 3 1/2 ID (in) 2.99 Top (ftKB) 25.3 Set Depth (ft… 8,786.4 Set Depth (TVD) (… 6,443.7 Wt (lb/ft) 9.30 Grade L-80 Top Connection EUE8RDMOD Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Com Nominal ID (in) 25.3 25.3 0.00 HANGER MCEVOY GEN IV HANGER 3.500 1,890.7 1,815.2 27.09 NIPPLE CAMCO W LANDING NIPPLE 2.812 8,469.9 6,216.6 42.70 PBR BAKER PBR w/ 10' STROKE 3.000 8,483.8 6,226.8 42.84 PACKER PACKER FHL RETRIEVABLE PACKER 2.890 8,574.7 6,293.0 43.75 BLAST JTS STEEL BLAST JOINTS (OAL=147') 2.992 8,740.3 6,411.3 45.05 SLEEVE CAMCO CB-1 SLIDING SLEEVE 2.260 8,752.9 6,420.2 45.15 XO Reducing CROSSOVER 3.5 x 2.875", ID 2.441, 6.5#, J-55, EUE IPC 2.875 8,753.7 6,420.8 45.15 SEAL ASSY BAKER LOCATOR SEAL ASSEMBLY 2.375 8,755.8 6,422.2 45.17 PACKER BAKER D PACKER 3.260 8,774.5 6,435.4 45.31 NIPPLE OTIS XN NIPPLE NO GO 2.250 8,785.8 6,443.3 45.39 SOS BAKER SHEAR OUT SUB (SHEARED) 2.441 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Des Com Run Date ID (in) 8,519.0 6,252.6 43.19 PLUG - RBP PARRAGON RBP, 2.72'' OD, ( CPP35184 ) EQ VLV ( CPEQ35017 ) FILL EXT & BULL PLUG ( OAL = 8.53'') 9/12/2018 0.000 9,022.0 6,600.8 51.61 FISH Slip f/ Slip stop LOST 8/1/1993 8/31/1993 0.000 9,022.0 6,600.8 51.61 FISH TIW PKR & Tbg Tail LOST 6/16/1994 6/16/1994 0.000 9,046.0 6,615.6 51.73 FISH Vann Gun 428' long GUN LOST 9/20/1981 9/20/1981 0.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft )Type Com 8,575.0 8,650.0 6,293.3 6,347.1 D, C-2, C-3, C- 4, 1B-07 11/23/1981 4.0 IPERF Max angle across perf 44 8,670.0 8,686.0 6,361.4 6,372.8 C-1, UNIT B, 1B -07 11/23/1981 4.0 IPERF 8,695.0 8,702.0 6,379.2 6,384.2 UNIT B, 1B-07 11/23/1981 4.0 IPERF 8,880.0 8,894.0 6,508.6 6,518.1 A-5, 1B-07 11/23/1981 4.0 IPERF 8,904.0 8,914.0 6,524.8 6,531.6 A-4, 1B-07 11/23/1981 4.0 IPERF 8,922.0 8,940.0 6,536.9 6,548.8 A-4, 1B-07 11/23/1981 4.0 IPERF Mandrel Inserts St ati on N o/Top (ftKB) Top (TVD) (ftKB) Make Model OD (in) Serv Valve Type Latch Type Port Size (in) TRO Run (psi) Run Date Com 1 8,420.3 6,180.1 CAMCO MMM 1 1/2 GAS LIFT DMY TGP 0.000 0.0 7/11/1994 2 8,528.7 6,259.7 CAMCO MMM 1 1/2 INJ DMY TGP 0.000 0.0 6/16/1994 Notes: General & Safety End Date Annotation 8/6/2010 NOTE: View Schematic w/ Alaska Schematic9.0 Comment SSSV: WRDP 1B-07, 9/13/2018 7:29:39 AM Vertical schematic (actual) PRODUCTION; 27.3-9,569.9 FISH; 9,046.0 FISH; 9,022.0 FISH; 9,022.0 IPERF; 8,922.0-8,940.0 IPERF; 8,904.0-8,914.0 IPERF; 8,880.0-8,894.0 SOS; 8,785.8 NIPPLE; 8,774.5 PACKER; 8,755.8 SEAL ASSY; 8,753.7 SLEEVE; 8,740.3 IPERF; 8,695.0-8,702.0 IPERF; 8,670.0-8,686.0 IPERF; 8,575.0-8,650.0 INJECTION; 8,528.7 PLUG - RBP; 8,519.0 PACKER; 8,483.8 PBR; 8,469.9 GAS LIFT; 8,420.3 SURFACE; 29.3-2,845.6 NIPPLE; 1,890.7 CONDUCTOR; 29.3-80.0 HANGER; 25.3 Last Tag Annotation Last Tag:RKB (Est.12' of Rathole) End Date 6/9/2018 Depth (ftKB) 8,952.0 Last Mod By zembaej Last Rev Reason Annotation Rev Reason: Secure w/ RBP Plug End Date 9/12/2018 Last Mod By condijw KUP INJ KB-Grd (ft) 32.48 Rig Release Date 9/20/1981 Annotation Last WO: End Date 6/16/1994 1B-07 H2S (ppm) Date... TD Act Btm (ftKB) 9,625.0 Well Attributes Field Name KUPARUK RIVER UNIT Wellbore API/UWI 500292061600 Wellbore Status INJ Max Angle & MD Incl (°) 61.00 MD (ftKB) 4,200.00 1B-07 Existing Completion Injector COMPLETION INFO MD (ft RKB) TVD (ft RKB) OD (in) Nom. ID (in) Weight (lb/ft)Grade Conductor 80 80 16 15.06 62.5 H40 Surface 2846 2633 10.75 9.95 45.5 K55 Production 9570 6934 7 6.28 26 K55 Tubing 8786 6444 3.5 2.99 9.3 L80 Arctic Cement Diesel Pack BBLS BBLS 9/16/81 41 104 bbl/ft 0.0486 from surface footage 844.1 2141.0 EXISTING COMPLETION McEvoy Gen IV Hanger Camco W Landing Nipple @ 1891' RKB (2.812" ID) Camco 3-1/2" GLM @ 8420' RKB (5.75" OD) Baker PBR w/ 10' stroke @ 8470' RKB 3.5" x 7.0" FHL Packer @ 8484' RKB (2.89" ID) 3.5" Blast Joints 3.5" Camco CB-1 Sliding Sleeve @ 8470' RKB 3.5" x 2.875" Crossover @ 8753' RKB 2.875" x 7.0" D Packer @ 8756' RKB (2.375" ID) OTIS XN nipple @ 8775' RKB (2.25" ID) SOS @ 8786' RKB Surface Casing Production Casing Conductor A-sand perfs C-Sand Perfs RBP 2.72" OD Tubing Cut ~8448' RKB Est Subsidence = 68.8" / Shut in 4/30/2017 7" is on a mandrel 1B-07 Proposed RWO Completion Injector COMPLETION INFO MD (ft RKB) TVD (ft RKB) OD (in) Nom. ID (in) Weight (lb/ft)Grade Conductor 80 80 16 15.06 62.5 H40 Surface 2846 2633 10.75 9.95 45.5 K55 Production 9570 6934 7 6.28 26 K55 Tubing 8786 6444 3.5 2.99 9.3 L80 PROPOSED PRODUCTION CASING 7.0" , 26# L80 HYD563 casing from cut to surface 7" Cementing tool for IA 7" Sealing Overshot PROPOSED COMPLETION 3-1/2" 9.3# L-80 HYD563 tubing to surface 3-½" X landing nipple at xxxx' RKB (2.813" min ID) 3-1/2" Camco MMG gas lift mandrels @ TBD 3.5" x 7.0" Packer @ xxxx' RKB (4" ID) 3-½" X landing nipple at xxxx' RKB (2.813" min ID) 3-1/2" Non-sealing Overshot REMAINING COMPLETION LEFT IN HOLE 3.5" x 7.0" FHL Packer @ 8484' RKB (2.89" ID) 3.5" Blast Joints 3.5" x 2.875" Crossover 2.875" x 7.0" D Packer @ 8756' RKB (2.375" ID) OTIS XN nipple @ 8775' RKB (2.25" ID) SOS @ 8786' RKB Surface Casing Production/Intermediate Casing Conductor A-sand perfs C-Sand Perfs RBP 2.72" OD Tubing Cut ~8448' RKB RECEIVED • • \q -oA`I FEB 01 2018 WELL LOG TRANSMITTAL##904202423 AOGCC To: Alaska Oil and Gas Conservation Comm. January 26, 2018 Attn.: Makana Bender 333 West 7th Avenue,Suite 100 Anchora e Alaska 99501 DATA LOGGED g , 2i8i2oi� M K.BENDER RE: Leak Detect Log with ACX: 1B-07 Run Date: 8/1/2017 Re-Submit: E-Set# 28908 The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of: Fanny Sari,Halliburton Wireline &Perforating, 6900 Arctic Blvd.,Anchorage,AK 99518 FRS_ANC@halliburton.com 1B-07 Digital Data in LAS format,Digital Log file, Interpretation Report 1 CD Rom 50-029-20616-00 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Halliburton Wireline &Perforating Attn: Fanny Sari 6900 Arctic Blvd. Anchorage,Alaska 99518 Office: 907-275-2605 SCANNED FRS_ANC@halliburton.com Date: Signed: pj,,d....,e1) 6.eAteft • ft,o ‘ WELL LOG TRANSMITTAL#904203423 To: Alaska Oil and Gas Conservation Comm. November 7, 2017 Attn.: Makana Bender 333 West 7th Avenue, Suite 100 RECEIVED DATA LQGGE � itlC�zo11� Anchorage, Alaska 99501 M.K.BENDER DEC 2 2 2017 RE: Leak Detect Log: 1B-07 AOGCC Run Date: 8/1/2017 The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of: Chris Gullett, Halliburton Wireline & Perforating, 6900 Arctic Blvd., Anchorage, AK 99518 FRS_ANC@halliburton.com 1B-07 Digital Data in LAS format, Digital Log file, Interpretation Report 1 CD Rom 50-029-20616-00 Leak Detect Log (Processed Log) 1 Color Log 50-029-20616-00 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Halliburton Wireline &Perforating Attn: Chris Gullett 6900 Arctic Blvd. Anchorage, Alaska 99518 Office: 907-273-3527 SCANNED R l FRS_ANC@halliburton.com Date: Signed: 412I3_.eiøcee :t S Wallace, Chris D (DOA) From: NSK Well Integrity Supv CPF1 and 2 <n1617@conocophillips.com> Sent: Sunday,April 16, 2017 6:19 PM To: Wallace, Chris D (DOA) Cc: Senden, R.Tyler Subject: Report of failed MITIA 1B-07 (PTD 181-089)4-16-17 Attachments: MIT KRU 1B-07 Diagnostic 4-16-17.xlsx; 1B-07 schematic.pdf; 1B-07 90 day TIO 4-16-17 jpg Chris, KRU injector 1B-07 (PTD 181-089)failed an MITIA today due to what appears to be a slow linear leak. The test was being performed in preparation for the upcoming 4 yr pad testing. Communication to the OA was present during the test, indicating the MIT failure is due to a production casing leak. The tubing and inner casing packoff tests passed. The well will be shut in and freeze protected as soon as possible. Follow up diagnostics with DHD will be obtained after the well has cooled down and stabilized. Further pressure testing will be performed, including a combination MIT and MITOA. Further diagnostics with slickline and Eline will be pursued as needed. The well will remain shut in. Prior to return to injection, proper paperwork will be submitted. Let me know if you disagree with the path forward. Attached are the MIT data,schematic and 90 day TIO plot. Kelly Lyons/Brent Rogers Well Integrity Supervisor ConocoPhillips Alaska, Inc. G ` 1` Desk Phone(907)659-7224 SCANNW Mobile Phone (907)943-0170 1 Imag ect Well History File Cover e XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. Well History File Identifier RESCAN DIGITAL DATA OVERSIZED (Scannable) [] Color items: [] Diskettes. No, [] Maps: [] Grayscale items: [] Other, No/Type [] Other items scannable by large scanner [] Poor Quality Originals: OVERSIZED (Non-Scannable) [] Other: [] Logs of various kinds NOTES: [] Other Project Proofing BY; ~OBIN VINCENT SHERYL MARIA WINDY Scanning Preparation ~:~;~- x 30 = BY; BIN VINCENT SHERYL MARIA WINDY Production Scanning Stage I PAGE COUNT FROM SCANNED FILE: Stage 2 (SCANNING I$ COMPLETE AT THIS POINT UNLE~E ~PECIAL ATTENTION I$ REQUIRED ON AN INDI'~DUAL PAGE BA~IS DUE TO QUAUTY, GRAY$CALE OR CO{OR IMAGES) PAGE COU.T M^TC.ES.UM~ER'" SC^..,.G PREPARAT,O.: ~ YES .O BEVER~ V,.OE.T S.ERYL MAR,A W,NDY DATE:/-/~-~_~S' ~'~ YES NO IF NO IN STAGE 1, PAGE(S) DISCREPANCIES WERE FOUND: BEVERLY ROBIN VINCENT~ARIA WINDY DATE;/// /..' ~/S/''/) ReScanned (indivldual page [special at~e~ti~n] .~ca,ning completed) RESCANNEDBY: BEVERLY ROBIN VINCENT SHERYL MARIA WINDY DATE: Isl General Notes or Comments about this file: Quality Checked 12110/02Rev3NOTScanned.wpd • • Conoco Phillips r _k _ Aasa P.O. BOX 100360 ANCHORAGE, ALASKA 99510 -0360 June 27, 2011 :z >L 1¢. ►'.ate Commissioner Dan Seamount ` Alaska Oil and Gas Commission 333 West 7 Avenue, Suite 100 Anchorage, AK 99501 �• , k . Commissioner Dan Seamount: Enclosed please find a spreadsheet with a list of wells from the Kuparuk field (KRU). Each of these wells was found to have a void in the conductor. These voids were filled with cement and corrosion inhibitor, engineered to prevent water from entering the annular space. As per previous agreement with the AOGCC, this letter and spreadsheet serves as notification that the treatments took place and meets the requirements of form 10 -404, Report of Sundry Operations. The cement was pumped on 3/21, 5/9, 5/23 and 5/24, 2011. The corrosion inhibitor /sealant was pumped 6/18, 6/19, 6/20 and 6/21, 2011. The attached spreadsheet presents the well name, top of cement depth prior to filling, and volumes used on each conductor. Please call MJ Loveland or Martin Walters at 907 - 659 -7043, if you have any questions. Sincerely, / MJ L veland ConocoPhillips Well Integrity Projects Supervisor . 0 ConocoPhillips Alaska Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top -off Report of Sundry Operations (10 -404) Kuparuk Field Date 06/27/2011 1A,1B,1E,1L,1Q,1Y PAD Corrosion Initial top of Vol. of cement Final top of Cement top off Corrosion inhibitor/ Well Name API # PTD # cement pumped cement date inhibitor sealant date ft bbls ft gal 1A -03 50029206150000 1810880 16" N/A 23" N/A 1.7 6/20/2011 1A -04A 50029206210100 2001940 18" N/A 23" N/A 2.5 6/20/2011 1A -16RD 50029207130100 1820310 SF N/A 22" N/A 5 6/18/2011 1B-03 B -03 50029205880000 [ 1810560 SF N/A 23" N/A 5 6/21/2011 4 , 0 .....> 1B -04 50029205950000 1810650 18" N/A 18" N/A 2.5 6/21 /2011 1B -05 50029202370000 _ 1770010 _ 31" 6.40 2'9" _ 5/24/2011 6 6/21/2011 1B-07 1 50029206160000 1810890 72" 1.00 22" 5/92011 2.5 6/21/2011 1B-08A 50029206350100 1971120 18'8" N/A 29" N/A 4.5 6/21/2011 1B-09 50029206550000 1811340 SF N/A 23" N/A 5 6/20/2011 1B-10 50029206560000 1811350 SF N/A 23" N/A 6 6/21/2011 1B-12 50029223650000 _ 1930610 13'4" 2.00 24" _ 5/9/2011 6 6/21/2011 1B -101 50029231730000 2031330 _ 3" _ N/A 22" _ N/A _ 1.7 6/21/2011 18-102 50029231670000 2031220 11'2" 0.60 36" 5/9/2011 1.7 6/21/2011 1E -05 50029204790000 1800580 _ 19" N/A 19" _ N/A _ 1.7 6/19/2011 1E-22 50029208840000 1822140 _ 14" 1.75 17" _ 3/212011 _ 1.7 6/19/2011 1E-23 50029208580000 1821840 58' 10.75 2'5" 5/23/2011 3.4 6/19/2011 1E-30 50029208140000 1821390 15'5" 1.75 16" 3/21/2011 2.5 6/19/2011 1E -105 50029232430000 2050060 20" N/A 20" N/A 6 6/19/2011 1L-16 50029212020000 1841810 14'9" 2.00 35" 5/23/2011 6 6/20/2011 1L -18 50029221450000 1910350 SF N/A 18" N/A 2.5 6/19/2011 1Q-24 50029225840000 1951210 7'8" 1.00 12" 5/9/2011 5 6/18/2011 1Y-02 50029209410000 1830590 40'10" 5.00 41" ' 5/9/2011 8.5 6/18/2011 • MEMORANDUM 1'0: Jim Regg ~~g~ 7~ZZ~~ 1 P.L Supervisor ~j / «~ FROM: Jeff' JOrieS Petroleum Inspector ~ State of Alaska Alaska Oil and Gas Conservation Commission DATE: Monday, July 06, 2009 SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 1 B-07 KUPARiJK RIV UNIT 1B-07 Src: Inspector NON-CONFIDENTIAL Reviewed By: P.L Suprv ~~'~-- Comm Well Name: KUPARUK RIV iJNIT 1B-07 Insp Num: miUJ090706093709 Rel Insp Num: API Weil Number: 50-029-20616-00-00 Permit Number: 181-089-0 .~ Inspector Name: JeffJones Inspection Date: 6/24/2009 Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well 1B-07 Type Inj. W T~ 622~ ' jE, ]060 1750 :/ 1690 1670 '~ P.T.D 1810890 TypeTest SPT Test psi 1556.75 QA 130 130 130 130 ~ Interval 4YRTST P~ r Tubing 2z60 2260 2250 2243 j NOtes• 1.2 BBLS diesel pumped. 1 well inspected; 7 exceptions noted: 6 bolts not properly engaged on well head and swab valve is leaking at bonnet. - ~ Mr. Colee will address these items. E~yf ~ ~ a.~ i~~~~~t ~;~;'4,~ ~g'" ~~„~ ~: ~ Monday, July O6, 2009 Page 1 of 1 A{ STATE OF ALASKA i .,KA OIL AND GAS CONSERVATION COMMI N REPORT OF SUNDRY WELL OPERATIONS 1. operations Performed: Abandon · i~ '.Suspehd r-'l Operation Shutdow~ ' [~. Perforate r'-] Variance r-'l Annular Disp: [] .. . . . . . ....' · ' ;." ' · . 'i "' ' : .: .... · ': ' ' . .'. " ".. '"' ' . -~" . . .. .. . P. O. Box 100360 ~ . . 50-029-20616-00 7, KB Elevation (ft): 9. Well Name and Number: RKB 94' 1 B-07 8, Property Designation: 10. Field/Pool(s): Kuparuk River Unit Kuparuk Oil Pool 11. Present Well Condition Summary: Total Depth measured 9625' feet true vertical 6968' feet Plugs (measured) Effective Depth measured 9473 feet Junk (measured) true vertical 6874 feet Casing Length Size MD 'I'VD Burst Collapse Structural CONDUCTOR 80' 16" 80' 80' SUR. CASING 2752' 10-3/4" 2846' 2633' PROD. CASING 9476' 7" 9570' 6934' PerfOration depth: Measured depth: 8575-8940 true vertical depth: 6293 - 6549 Tubing (size, grade, and measured depth) 2-7/8", J-55, 8786' MD. Packeis & SSSV (type & measured depth) pkr= BAKER 'FHL' RETR.; BAKER 'D' pkr= 8484'; 8756' SSSV= NIP SSSV= 1891' .'' · '. '..' ' i .' = i. ~i.' · .t · ' · . .. ..' .' ... · . ". .. . . . :' '..... ':... : · .....'.. "..' ' · '' · . . . .'. .. '. ' ' ..'. ' '. :. · .' '.' ' ' ' L.. · ' '. ' . · ... · .. . .. . . ........' .' ... . .'. · ' · '= :==....:.=.~:':":" ..7','.:: '" ';.::..'..:"='~".~ · . ': .':.~";.':'~ . .'."~"..= · :..'""..:.'." '; · · ' =" ' : '" ' .... : '"'=: · ".'.'"'.'"' ' ..=' · :... ,, · ... .'.. ..~ ...'' .. .. . . . . · ...'."...~...... : ... · .. . . · .. , ~ · . .. · . . · .... .... ~.. .. .' :..... . = . =... ... .. . .'. · ............... :, · :. · . · ~.. .. .......... .... . = ............................... X' .. r . . '.~ '.' .'.... · . . . .'. . · . . .. . 17. I hereby ce~ify that the foregoing is true and correct to the best of my knowledge. ~ Sund~ Number or N/A if C.C. Exempt: . Contact Jeff Spencer ~ 659-722'6 .. ": "' ~ .... Printed Name'_ ~e~ D..O~istensen · ' ' · .. Title Production'Engineering Technician Form 10-404 Revised 2/2003 · 1 B-07 ( DESCRIPTION OF WORK COMPLETED SUMMARY Date Event Summary 09/12/o31Com.meh...ced ~WAG !'EOR.~!nje:~ti0'h':.' ' ' ' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Cammy O Taylorl~....~ Chairman DATE: June 16, 2002 P.I. Supervisor "~{'~ FROM: Chuck Scheve Petroleum Inspector NON- CONFIDENTIAL SUBJECT: Mechanical Integrity Tests Phillips 1 B Pad KRU Kuparuk WellI 1B-02I P.T.D.I 181-133 Notes: P.T.D.I 181-065 Notes: P.T.D.I 177-001 Notes: , ,,WellI 1B-07I P.T.D.I 1.81-089 Notes: P.T.D.I 197-112 Notes: P.T.D.I 181-134 Notes: P.T.D.I 193-061 Notes: Packer Depth Pretest Initial 15 Min. 30 Min. ] Type lnj.I F I T.V.D. 16109 I Tubing I 1450 11450 I 1450 I 1450 I lntervall 4 ] Type testI P I TestpsiJ 1527 ICasingj 150 J 19801 1930 J 1920j P/F J _p_Pi / Type lnj.[ F I T.V.D. I 6180 I Tub,ng 12400 12400 12400 12400 I,nterva, I 4 I Type testI P I Testpsil 1545 I CasingI 550 I 2050 I 2050 I 2050 I P/F I 13 t Type lnj.I F I T.V.D. I 6341 I Tubingl 2500 I 2500 I 2500 I 2500 I lntervall 4 Type testI P I Testpsil 1585 ICasingI 250 12O001195011925I P/FI!3 Type testI P I Testpsil 1557 ICasingI 1000 I 1950 I 1920 I 1920 I P/F I 13 Type,nj.I F i ~.v.~. 14837 I Tubing 12500 12500 oI,nterva, I 4 I TypetestI P ITestpsil 1209 I CasingI 0 I 20501 20001 20001 P/F I P I Typ~,nj.I F IT.V.D. J6~09 J Tubing12500 12S00 12500 12500 I,,te,v.,I 4 I TypetestI P ITestpsil 1527 I Casingl 550 I 2025 I 2000 I 2000 I P/F.I 131 Type lnj. J F I T.V.D. J 6094 ]Tubing I 1950 I 1950 I 1950 I 1950 I lntervall 4 I Type testI P I Testpsil 1524 ICasingI 0 I 2100 I 2050 I 2050 I P/F I 13 I Type INJ. Fluid Codes F = FRESH WATER INJ. G = GAS I NJ. S = SALT WATER INJ. N = NOT INJECTING Type Test M= Annulus Monitoring P= Standard Pressure Test R= Internal Radioactive Tracer Survey A= Temperature Anomaly Survey D= Differential Temperature Test Interval I= Initial Test 4-- Four Year Cycle V= Required by Variance W= Test during Workover O= Other (describe in notes) Test's Details I traveled to Phillips lB Pad in the Kuparuk River Field and witnessed the routine 4 year MITs on the above 7 wells. The pretest tubing and casing pressures on all wells was observed and found to be stable. The standard annulus pressure tests were then performed with all 7 wells demonstrating good mechanical integrity. t~.l.T.'s performed: _7 Attachments: Number of Failures: 0 Total Time during tests: 4 Hours cc: MIT report form 5/12/00 L.G. MIT KRU 1B Pad 6-16-02 CS.xIs 6/20/2002 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation Shutdown Pull tubing X Alter casing Stimulate __ Plugging Perforate _ ' ~'/~/ Repair well Other Pull Failed Pkr 2. Name of Operator ARCO Alaska, Inc. 3. Address P. O. Box 100360, Anchorage, AK 99510 5. Type of Well: Development _ Exploratory _ Stratigraphic _ Service X 4. Location of well at surface 500' FNL, 262' FEL, Sec. 9, T11N, R10E, UM At top of productive interval 1326' FSL, 1693' FEL, Sec. 10, T11N, R10E, UMR ~c~IV ~D At effective depth 651' FSL, 1612' FEE, Sec. 10, T11N, R10E, UM JU~ 2 7 994 At total depth 532' FSL, 1602' FEL, Sec. 10, T11N, R10E, I~l~Sk~ 0[[ & Gas Cons. Commission 12. Present well condition summary Anchorag= Total Depth: measured 9625' feet Plugs (measured) true vertical 6967' feet 6. Datum elevation (DF or KB) 94' RKI~ 7. Unit or Property name Kuparuk River Unit 8. Well number 1B-7 9. Permit number/approval number 81-89 10. APl number 50-029-20616 11. Field/Pool Kuparuk River Oil Pool None feet Effective depth: measured 9473' feet Junk (measured) true vertical 6874' feet Casing Length Size Cemented Structural 80' 1 6" 200 Sx PF Conductor Surface 281 4' 1 0-3/4" 1300 sx FONDU & 250 sx ASII Intermediate Production 8746' 7" 350 sx Class G Liner Perforation depth: measured 8575'-8650', 8670'-8686', 8922'-8940' Measured depth True vertical depth 80' md 80' tvd 2845' md 2632' tvd 9570' md 6933' tvd 8695'-8702',8880'-8894',8904'-8914' true vertical 6293'-6348', 6362'-6374', 6380'-6385', 6515'-6526', 6533'-6540', 6546'-6559' Tubing (size, grade, and measured depth) 3-1/2" 9.3# J-55 @ 8786' md Packers and SSSV (type and measured depth) Camco Landing Nipple @ 1891' md, Baker 'FHL' Rtr Pkr @ 8484', Baker Model 'D' Perm Pkr @ 8756' md 13. Stimulation or cement squeeze summary Intervals treated (measured) Treatment description including volumes used and final pressure 14. Prior to well operation Subsequent to operation Re.Dresentative Daily Average Production or Injection Data OiI-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure 15. Attachments Copies of Logs and Surveys run __ Daily Report of Well Operations X 16. Status of well classification as: Water Injector__ Oil M Gas Suspended Service Water Iniector 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Form 1~-~04 Rev'05~7/89 Title Area Drilling Engineer SUBI~IIT I1~ DUPLICATE ARCO ALASKA INC. DAILY OPERATIO~ PAGE: 1 WELL: BOROUGH: UNIT: FIELD: LEASE: API: PERMIT: APPROVAL: lB-07 NORTH SLOPE BOROUGH KUPARUK RIVER KUPARUK RIVER 50-103-20616 81-89 ACCEPT: 06/12/94 09:30 SPUD: RELEASE: 06/20/94 12:00 OPERATION: DRLG RIG: WO/C RIG: NORDIC 1 06/13/94 (1) NORDIC 1 TD: 9625 PB: 9474 06/14/94 (2) NORDIC 1 TD: 9625 PB: 9474 06/15/94 ( 3) NORDIC 1 TD: 9625 PB: 9474 NU BOP STACK MW:ll.6 NaC1 MOVE RIG F/lB-13 TO 1B-07 WORKOVER. ACCEPT RIG 0930 HRS 06/12/94. RU HARD LINE TO KILL TANK & lB PAD FLOWLINE. TAKE ON DRILLING MUD. PULL BPV-OPEN WELL-SITP=2000 PSI, SICP=2000 PSI. BULLHEAD 110 BBL DIESEL DN TBG. MONITOR PRESS. KILL WT PLUS 150 PSI OVER BALANCE=13.3 PPG EMW. WT UP DRILLING MUD RECEIVED FROM KCS YARD 12.0 PPG TO 13.3 PPG. KILL WELL BY PUMPING DN TBG, TAKING RETURNS TO lB PAD FLOW LINE. BULLHEAD 18 BBLS INTO FORMATION. MONITOR WELL-WELL DEAD-FLUID LOSS 31 BBLS/HR. SET BPV. ND MCEVOY GEN 1 TBG SPOOL ADAPTER & 3-1/8" TREE. HAD TO PULL 80 K WITH RIG BLOCK TO PULL TREE OFF OF TBG HGR NECK. NU 11" 3000# X 13-5/8" 5000 DSA. NU 13-5/8" BOP STACK. CUT MUD WT IN PITS TO 13.0 PPG & MIX VOL. POOH, LD TBG MW:ll.6 NaC1 CONT NU OF 13-5/8" BOP STACK. SET TEST PLUG. TEST BOP. TEST ALL RAMS, LINES & VALVES TO 3000 PSI. TEST CHOKE MANIFOLD TO 3000 PSI. TEST TIW & INSIDE BOP TO 3000 PSI-OK. BOLDS. PULL TBG HGR TO RIG FLOOR-80K TO PULL HGR FREE. STRING PU WT 64K. SBR APPEARED TO HAVE BEEN SHEARED. FILL HOLE WITH 13 BBLS FLUID. ATTEMPT TO CIRC 13.0 PPG FLUID AROUND. FLUID LOSS APPROX 50%-LOSS APPROX 196 BBLS WHILE CIRC. RETURNS 12.5 PPG WHEN SHUT DOWN. MIX HI VIS 13.0 PPG PILL & SPOT ON BTM. OUT OF MUD. BUILD 300 BBL OF NEW 12.8 PPG MUD IN PITS. FILL HOLE. HOLE FILL AFTER 10 HRS WAS 8 BBLS. POOH. LD TBG. FILL HOLE W/12.8 PPG MUD. CBU & COND MUD MW:ll.6 NaC1 SERV RIG. POOH. LD TBG. MIX & PMP SLUG. POOH. LD TBG. RECOVERED 7" PKR & TAIL ASSY, 36 SS BANDS. LOAD & STRAP 12 4-3/4" DC, RU FLOOR TO PU DC'S. TIH W/6-1/8" BIT & 7" SCRAPER. LOAD & STRAP DP. SLIP & CUT DRLG LINE 50 FT. TIH. PU 3-1/2" DP TO 9025' MD. TAG FILL. PU KELLY, CLEAN FILL TO NORDIC RKB 9033' MD TOP OF FISH. CBU & COND MUD. RECEIVED dUN 27 1994 A!~ska Oil & Gas Cons. Commission Anchorage WELL: lB-07 API: 50-103-20616 PERMIT: 81-89 PAGE: 2 06/16/94 ( 4) NORDIC 1 TD: 9625 PB: 9474 06/17/94 ( 5) NORDIC 1 TD: 9625 PB: 9474 06/18/94 ( 6) NORDIC 1 Tn: 9625 PB: 9474 POOH, LD DP MW: 11.6 NaCl SERV RIG. BLOWDOWN & STANDBACK KELLY, MONITOR WELL-OK. PMP SLUG. WORK THRU TIGHT SPOTS @ THE PERFS. POOH W/8 STDS TO 8500' CHECK HOLE FILL, MONITOR WELL, HOLE TAKING TOO MUCH FLUID TO SET STORM PKR, FIN POOH. STAND BY DC'S. LD BUMPER SUB, OIL JARS & 7" CSG SCRAPER. MU BP, RIH TO 8485', SET BP PLUG & TEST 7" CSG SCRAPER TO 2500 PSI F/15 MIN. LOST 25 PSI-OK. PULL 2 JTS. MU STORM PKR, SET @ 30', TEST TO 3000 PSI-OK. CHECK F/PRESS @ 10-3/4" X 7" ANN. BLEED OFF PRESS. ND BOPS & DSA. ND TBG SPOOL, C/O TBG SPOOL TO 7-1/16" F/3M TO 5M. TEST 3000 PSI-OK. NU BOPS, RISER, FLOWLINE, TEST BREAKS & CONN TO 3000 PSI-OK. INSTALL W.B.. PU 1 STD. RELEASE STORM PKR. POOH & LD. RIH TO BP, LATCH & RELEASE. CIRC AROUND. MONITOR HOLE-OK. PMP SLUG. POOH. LD DP. TIH W/TBG COMPLETION MW:ll.6 NaCl SERV RIG. POOH. LD 3-1/2" DP & 4-3/4" DC. CLEAR RIG FLOOR. RD FLOW NIPPLE, PULL WEAR BUSHING. RU SWS. TEST LUB TO 1000 PSI, RIH W/CCL, GR, 6.0 GR & JB TO 9000' WLM. MU WL. SET PKR, LOAD PIPE SHED W/TBG WHILE LOGGING. PU TIW PKR, RIH & SET PKR @ 8775' WLM. POOH. RD SWS. RU FLOWLINE. FIN LOADING & STRAPPING TBG. RU FLOOR TO RUN TBG ASSY. PU SEAL ASSY. RUN TBG PER TBG DETAIL. SET BAKER PKR, POOH MW:ll.6 NaCl SERV RIG. RIH W/TBG & COMPLETION, PMP SLUG DUE TO WET TBG, FOUND TIW PERM PKR @ 9000' MD. POOH, LD 8 JTS, SET TBG BACK IN THE DERRICK. MU BAKER MODEL 'D' PERM PKR & TAIL ASSY. ND FLOWLINE & RISER, RU SWS, TEST LUB TO 1000 PSI. RIH W/GR, JB. TAG FISH @ 8990' WLM, 47' RAT HOLE. MU BAKER MODEL 'D' PERM PKR, ON PKR SET TOOL. RIH TO 8740' WLM. SET PKR. POOH. RECEIVED JUN 2 7 1994 At~ska Oil & Gas Cons. Commission Anchorage WELL: lB-07 API: 50-103-20616 PERMIT: 81-89 PAGE: 3 06/19/94 ( 7) NORDIC 1 TD: 9625 PB: 9474 06/20/94 (8) NORDIC 1 TD: 9625 PB: 9474 CLEANING PITS MW:ll.6 NaC1 SET PKR, POOH. RD SWS. RU FLOW NIPPLE, RU FLOOR TO RUN TBG. MU SEAL ASSY, RIH W/3-1/2" 9.3# L-80 TBG. VERIFY SEALS, SPACE OUT, MU LANDING JT & TBG HGR, LAND TBG. PRESS TEST TBG TO 2500 PSI-OK. BOLDS, PU & SHEAR PBR @ 90K, RELAND TBG, & RILDS. TEST ANN & TBG TO 2500 PSI-OK. TEST TBG TO 3000 PSI-OK. SHEAR SOS @ 4800 PSI. RU CIRC HEAD, PULL LANDING JT, SET BACK PRESS VALVE. ND BOPS. CLEAN FLANGES, PREP HGR SEALS, NU TREE, TEST PACKOFF TO 5000 PSI-OK. TEST TREE TO 250/5000 PSI-OK. PULL BPV, RU DISPLACEMENT LINES. CIRC SW, DISPLACE MUD @ 2 BPM, SHUT IN WELL. PMP MODULE LEAK, REPLACE GASKET ON MODULE #3. TEST PMP TO 3500 PSI. FIN DISPLACE W/SW, DISPLACE SW W/DIESEL. GOOD DIESEL RETURNS, BLEED OFF ANN TO 0 PSI, 2000 PSI ON TBG. CHECK VALVE HOLDING. ATTEMPT TO DISPLACE TAIL PIPE. PRESS UP TO 3500 PSI-HOLDING. BLEED OFF PRESS TO 2000 PSI. MONITOR WELL, SECURE WELL, STARTED CLEANING PITS. RIG STACKED @ Y-PAD MW:ll.6 NaC1 CLEAN MUD PITS, FLUSH & BLOW DOWN ALL LINES, BLOW DOWN ALL EQUIP & FREEZE PROTECT. MOVE RIG TO Y-PAD. RIG RELEASED @ 1200 HRS 06/20/94. RIG IS STACKED ON SW CORNER OF Y-PAD. SIGNATURE: RECEIVED JUN 27 1994 Alaska Oil & Gas Cons. Commission Anchorage ~EP ~Lq ~g~ Og:~g~P1 KUPG4RUK PETROLEUM ENGINEERING ' Intern;~l' Correspondence (~ P. ^R3E)--;~275 1015 --.. 1015 1040 1045 1050 il00 LO~ ENTRY M]RU VECO PUMP TO 7" ANNULUS, P/T IN~~ON ~ TO 3500 PSI. _ ii - ii .... · START CUTTING INFECTION PRESSURE. 7" ANN, 2350~ ~, .... :a ~ o .,) -~' 2580 22OO 2540 , 1900 2410 ~11 ! in Iii .__ 1750 2350 ---i il i I Il .......... 1670 2270 _. 10.75" ANN. , [ .... · · ..... ItL_ · [mmmllmi ......... mm I1_1 ii , _ qlll I Ilml II II ....... III 4,80 ii . _. IIi ---- I 48O . . I I DIRECT COMMUNICATION EXIST BETWEEN 8EVF.2q INCH ANNULUS AND ' TUBING, GAS FREE ANNULUS WOULD NOT PRESS~ ABOV1/2500 i _. _ I __ · i WTI'H EIGHT BBLS OF DIF. SEL IN/ECrED, NOR TWILL ANNlfLUS BLEED BELOW ......... ._ 2000 PSI WITH TUBLNO IIV~ECTION PRESSURE RF.J)UCED TO IBOO PSI. .......... ~. r ............... iii .iLL mi ..--_22-,~i-__~ q NO COMMUNICATION WAS NOTED BETWEEN SEVEN INCH AND TEN & THREE ..................... '' - ..... "-' - ......... · ............. ii inl i ..... R/I) PUMP, RESTORE IN~urION PRESSUR~ TO 2350. TRACKS BACK UP TO 2540 PS:~-("~:"~"9-° ~ . n~l ,hi l SUMMARY: IIW 7" ANN. ~IATELY 1135 . __ Il I I I I .... I[ I .... Illlnl. I..I In l 1 I0 · 1630 ......... ~ 2~0 480 · ' I .~ Il'fi'? "" ., ..... ,,,,,, ,nnnp 1, nj_ ~ ..r I I Ill I Illl Ill IU _~ ii. m ! .... ' ....... . . CHECK 7" ANN, FOR OAS ltEAD, HYDI~ULIC TO SURFAC~. ,~SEP 23 '93 09:30RM KUPRRUK PETROLEUM EHGIHEERIHG P. 4,"4 WELL SERVICE REPORT WELt. K . ii i i i i i , , ,_ii_ i ii ii ...... · ,. i i i i . ~' GHECK THIS BLOCK IF .SUMMARY CONTINUED ON BACK , Willlt~~ iP I II I ii III I Ill t Iii I I llI I II I Ii ii ·--- .. _ -' --:--_'_:-- · APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon __ S,__~rspend_._ Operation Shutdown __ Re-enter suspended well Alter casing __ Repair well _ Plugging_ _ Stimulate __ Change approved program 2. Name of Operator ARCO Alaska. Inc. 3. Address P. O. Box 100360, Anchorage, AK 99510 4. Location of well at surface Pull tubing _ 5. Type of Well: Development _ Exploratory _ Stratigraphic _ 500' FNL, 1262' FWL, Sec. 9, T11N, R10E, UM At top of productive interval 1368' FSL, 1686' FEL, Sec. 10, T11N, R10E, UM At effective depth 651' FSL, 1613' FEL, Sec. 10, T11N, R10E, UM At total depth 532' FSLy 1602' FELt Sec. 10t T11Nt R10E~ UM 12. Present well condition summary Total Depth: measured 9 6 2 5 true vertical 6 9 6 7 O'eI$11V4' feet feet Time extension Variance X Perforate m Other __ 6. Datum elevation (DF or KB) RKB 98 7. Unit or Property name Kuparuk Rhter Unit 8. Well number 1B-07 9. Permit number 10. APl number S0-029-2061 6 11. Field/Pool Kuparuk River Oil Field/Pool Plugs (measured) None feet Effective depth: measured 9 4 7 3 feet true vertical 6780 feet Junk (measured) 428' long Vann Gun @ 9046' Structural Conductor Surface Intermediate Production Liner Perforation depth: Measured depth True vertical depth Length Size Cemented 80' 1 6" 200 Sx PF 80' 80' 2 81 2' 1 0 - 3 / 4" 1500 Sx Fondu & 2845' 2633' 250 Sx Prom G 9 5 3 8 7" 250 Sx Class G 9570' 6933' 676 Sx AS I measured 8575'-8650',8670'-8686',8695'-8702',8880'-8894',8904'-8914',8922'-8940' true vertical 6293'-6347',6365'-6374',6379'-6384',6507'-651 6',6525'-6531 ',6537'-6549' RECEIVED 'Tubing (size, grade, and measured depth) 3 1/2", 9.3#/ft., J-55 @ 8533' Packers and SSSV (type and measured depth) PKR: Baker 'FH' ~ 8460'; SSSV: Camco TRDP @ 1977' 13. Attachments Description summary of proposal X Continue water injection into well. :14. Estimated date for commencing operation October 1993/March 1994 Detailed operation program_ ~bP"sk~t(~l~'... AJaska 0il & Gas Cons. 15. Status of well classification as: Anchorage Oil __ Gas Suspended 16. If proposal was verbally approved I Name of approver Date approvedI Service 117. I her~/.~rt~y/~,at the f, oregj3in~g i_s true and correct to the best of my knowledge. Signed "~'~ ~ -~ Title Senior Engineeer FOR COMMISSION USE ONLY Water In!ector Conditions of approval: Notify Commission so representative may witness Plug integrity BOP Test _ Location clearance ~ Mechanical Integrity Test ~ Subsequent form require 10- OH~.~ ~?~ed By D..:::~ ,,.. ~ ¢ ~¥., dohnsto n ~,pproved by order of the Commission Form 10-405 Rev 06/15/88 IAppr?.val No. Approved Copy Returned Commissioner Date SUBMIT IN TRIPLICATE Attachment 1 Request for Variance Kuparuk Well 1B-07 As per Area Injection Order No. 2, Rule 7, ARCO Alaska is hereby notifying the Commission of pressure communication between the tubing and casing in Water Injection Well 1B-07. As set forth in the Rule 7, ARCO Alaska is requesting Commission approval to continue water injection into this well. As found in Area Injection Order No. 2, the aquifers described by a 1/4 mile area beyond and lying directly below the Kuparuk River Unit are exempted for Class II injection activities by 40 CFR 147.102(b) (3) and 20 AAC 25.440(c). As such, continued injection will not endanger any Underground Source of Ddnking Water (USDW). Well 1B-07 began injection on September 10, 1990 and is currently injecting approximately 3300 BWPD at an average surface injection pressure of 2340 psi. Diagnostic work indicates that the source of the communication is the packer located at 8460' WLM-RKB (Attachment 2). The well has passed an MIT on August 31, 1991, however, it failed an in.~.~useM_lT on August 17, 199_3. A summary of the failed MIT is as follows: Attempted to pressure test 7". Could only get 7" to 2500 psi after pumping 8 bbls of diesel. 7" pressure immediately dropped back when pump stopped. Failed in-house MIT. The wellhead pressure tested good on 8/19/93. The tubing pressure tested good on September 1, 1993; the tubing pressure went from 2990 psi to 2940 psi in 30 minutes. Spinner and temperature logs run in April, 12 1991 indicated that there are no external casing leaks in this injection well and injection fluids are confined to the Kuparuk River Sands. Casing and tubing pressures will continue to be monitored and reported as per Area Injection Order No. 2, Rule 4 to ensure that the casing pressure does not exceed 70% of the casing's minimum yield strength. Future plans for this well include evaluation of a workover to repair the suspected~ source of the tubing by 7" communication leak; the packer at 8460' WLM-RKB. RECEJVfE ............... STATE OF ALASKA · OILAND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Performed: Operation Shutdown Pull tubing Alter casing Stimulate __ Plugging Perforate _ Repair well Other X 2. Name of Operator ARCO Alaska. Inc, 3. Address P. O. Box 100360, Anchorage, AK 99510 5. Type of Well: Development -. Exploratory _ Stratigraphic Service X 4. Location of well at surface 500' FNL, 1262' FWL, Sec. 9, T11N, R10E, UM At top of productive interval 1368' FSL, 1686' FEL, Sec.10, T11N, R10E, UM At effective depth 651' FSL, 1613 FEL, Sec. 10, T13N, R10E, UM At total depth 532' FSL, 1602' FEL~ Sec. 10r T11N, R10E, UM 12. Present well condition summary Total Depth: measured 9625' feet true vertical 6967' feet Plugs (measured) 6. Datum elevation (DF or KB) RKB ~' 7. Unit or Property name Kuparuk River Unit 8. Well number 1B-07 Permit number/approval number 10. APl number 50-029-20616 11. Field/Pool Kuparuk River Oil Pool feet Effective depth: measured 9 4 7 3' feet true vertical 6780' feet Junk (measured) None Casing Length Size Structural Conductor 8 0' 1 6" Surface 2845' 10 Intermediate Production 9570' 7" Liner Perforation depth: measured 8575'-8650' 8922'-894~' true vertical 6293'-6347', 6537'-6549' Cemented 200 Sx Permafrost 3/4" 1500 Sx Fondue & 250 Sx AS II 250 Sx Class G 676 Sx AS I 8670'-8686', 8695'-8702', 6365'-6374', Tubing (size, grade, and measured depth) 3 1/2" J-55, TT @ 8533' Packers and SSSV (type and measured depth) Baker packers FH @ 8460', Camco TRDP @ 1977' "i3. Stimulation or cement squeeze summary Measured depth 80' 2845' 957O' 8880'-8894', Intervals treated (measured) 6379'-6384', 6507'-6516', RECEIVED True vertical depth 80' 2633' 6933' 8904'-8914' 6525'-6531', DEC 11 1990 Alaska 0il & Gas Cons. G0mmts~'~0~ AnGhorag8 Treatment description including volumes used and final pressure 14. Prior to well operation Subsequent to operation Representative Daily Averaae Production or Iniection Dat~ OiI-Bbl Gas-Mcr Water-Bbl Casing Pressure -0- -0- -0- 2200 -0- -0- 7000 2200 Tubing Pressure 3160 2350 15. Attachments Copies of Logs and Surveys run Daily'Report of Well Operations X 16. Status of well classification as: Water Injector X Oil _ Gas Suspended Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed ~' ,~ ~ Form 10-404 Rev 09/12/90 Title Date ~¢-..~. SUBMIT IN DUPLICATE KRU 1B-07 Water injection into 1B-07 began September 10, 1990 with an initial rate of 1750 bbl of produced water per day RECEIVED DEC 1 1 1990 AlasEa Oil & Gas Cons. Commission Anchorage GAS CONSERVATIONCOMMI ION 0 !{ I G IN A [ .... APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon _ Suspend _ Operation Shutdown _ Re-enter suspended well _ Alter casing _ Repair well _ Plugging _ Time extension _ Stimulate _ Change approved program X Pull tubing _ Variance _ Perforate _ Other _ 2. Name of Operator 5. Type of Well: 6. Datum elevation (DF or KB) Development _ ARCO Alaska. Inc. Exploratory _ RKB 98' feet 3. Address Stratigraphic _ 7. Unit or Property name P. O. Box 100360, Anchorage, AK 99510 Service ~ Kuparuk River Unit 4. Location of well at surface 8. Well number 500' FNL, 262' FEL, Sec. 9, T11N, R10E, UM 1B-07 At top of productive interval 9. Permit number 1368' FSL, 1686' FEL, Sec. 10, T11N, R10E, UM 80-89 At effective depth 10. APl number 651' FSL, 1613' FEL, Sec. 10, T11N, R10E, UM so-029-20616 At total depth 11. Field/Pool Kuparuk River Field 532' FSL~ 1602' FEL~ Sec. 10~ T11N~ R10E~ UM Kuparuk River Oil Pool 12. Present well condition summary Total Depth: measured 9 62 5' feet Plugs (measured) true vertical 6 9 6 7' feet Effective depth: measured 9473' feet Junk (measured) true vertical 6 7 8 0' feet None Casing Length Size Cemented Measured depth True vertical depth Structural Conductor 80' 1 6" 200 Sx Permafrost 80' 80' Surface 2 8 4 5' 1 0 3/4" 1300 Sx Fondue & 2 8 4 5' 2 6 3 3' Intermediate 250 Sx AS II Production 9 5 7 0' 7" 350 Sx Class G 9 5 7 0° 6 9 3 3' Liner Perforation depth: measured 8575'-8650' 8670'-8686', 8695'-8702', 8880'-8894', 8904'-8914', 8922'-894~' true vertical 6293'-6347', 6365'-6374', 6379'-6384', 6507'-6~1~,r,~-~1', 6537,-6549, I~Lk., L i V ~ I.~ Tubing (size, grade, and measured depth 3 1/2" J-55, TT @ 8533' AUG ! 0 1990 Packers and SSSV (type and measured depth) Baker packers FH @ 8460', Camco TRDP @ 1977' Alaska 0il .~ Gas Cons, C0mmissi0H 13. Attachments Description summary of proposal_ Detailed operation program _ j~l~~etch _ ProPose converting well from oil producer to water injector. 14. Estimated date for commencing operation 15. Status of well classification as: Aueust 15, 1990 Oil __ Gas _ Suspended _ -- 16. If proposal was verbally approved Name of approver Date approved Service Water Iniector 17. I hert ~y certify that the foregoing is true and correct to the best of my knowledge. Signed ~ J~,. ~, ~ Title ~~t;~'l~. O~ ~1~.~.,. Date FOR COMMISSION USE O~ILY O Conditions of approval' Notify Commission so representative may witness IApprov~l No. Plug integrity_Bo~ Test_ Location clearance__z ,v I (¢~'~ .., ~;~,~ Mechanical Integrity Test'~ Subsequent form require 10-z'~¢'/- ~,d 0o~3¥ t ed '.,- ~ ORIGINAL SIGNED BY ..~ Approved by the order Commission ,,~,m,l: C. SMITH Commissioner Date ~"' Form 10-403 Rev 5/03/89 SUBMIT IN TRIPLICATE ARCO Alaska, Inc. Date: March 24, 1989 Transmittal #: 7447 RETURN TO: ARCO Alaska, Inc. Attn: Brenda K. Miernyk Kuparuk Records Clerk ATO-1119 P.O. Box 100360 Anchorage, AK 99510-0360 Transmitted herewith are the following items. Please acknowledge receipt and return one signed copy of this transmittal. ~ 3 O- 16 Kuparuk Well Pressure Report I - 3 - 1 8 9 -,,- 3 O- 10 Kuparuk Well Pressure Report 2- 04 - 8 9 · -='- 3 O-13 Kuparuk Well Pressure Report 2 - 0 8 - 8 9 .=,~30-03 Kuparuk Well Pressure Report I-09-89 .i 3 O- 15 Kuparuk Well Pressure Report 3 - 04 - 8 9 ~ 2 G- 14 Kuparuk Fluid Level Report 3-11-89 ~ 2 G- 13 Kuparuk Fluid Level Report 3 - 11 - 89 -'~ 2G-09 Kuparuk Fluid Level Report 3-11- 89 ',,,,,i 1 E -03 Kuparuk Fluid Level Report 3 - 09 - 89 ~ I E-05 Kuparuk Fluid Level Report 3 - 0 9 - 8 9 3 O- 18 Kuparuk Fluid Level Report 3 - 09- 8 9 ~ 3 H, 10 Kuparuk Fluid Level Report 3 - 09 - 89 ~ 3 A- 03 Kuparuk Fluid Level Report 3 - 09 - 8 9 ~ 3 H- 04 Kuparuk Fluid Level Report 3 - 04 - 89 ~2B - 14 Kuparuk Fluid Level Report 3 - 1 3 - 89 '"'-~30-13 Sub-Surface Pressure Survey "2-08-89 e,i30.10 Sub-Surface Pressure Survey 2-04-89 ~ 30-16 Sub-Surface Pressure Survey 1 - 31 - 8 9 ~ 1 B- 0 7 Kuparuk Fluid Level Report 3 - 3 1 - 8 8 '"'"~1 B - 0 3 Kuparuk Fluid Level Report I - 2 7 -8 8 ~ 1 B - 0 5 Kuparuk Fluid Level Report 1 - 2 7 - 8 8 ~ B - 0 7 Kuparuk Fluid Level Report 4 - 2 7 - 8 8 ~1 B- 0 7 Kuparuk Fluid Level Report 1 - 2 7- 8 8 ~ 1 L- 0 8 Kuparuk Fluid Level Report 2 - 1 2 - 8 8 ~,,,,~1 L- 0 4 Kuparuk Fluid Level Report 2 - 1 2 - 8 8 ~'~3 H- 1 0 3- 1 7-89 "~,~3M-0 1 Sand 'A' Sand 'A' Sand 'A' Sand 'A' Tubing Tubing Tubing Tubing Tubing Casing Casing Casing Casing Casing #72665 #72655 #72655 Casing Tubing Tubing Tubing Tubing Tubing Tubing C Kuparuk Fluid Level Report _ .(j__a.,s,..ng.,..~i~-" Kuparuk Fluid Level Report Commission ~~ '- ~ch0rago ~ O- 09 Kuparuk Fluid Level Report 3 - 1 8 - 89 Casing '""~30-18 Kuparuk Fluid Level Report 3 - 1 8 - 89 Casing ~ O- 18 Kuparuk Fluid Level Report 3 - 1 7- 89 Casing '~~O-09 Kuparuk Fluid Level Report 3-1 7-89 Casing B - 13 Kuparuk Fluid Level Report 3 - 1 7- 89 Casing Receipt Acknowledged: ........................... Date: ............ DISTRIBUTION: D&M · State of Alaska SAPC Chevron Unocal Mobil ~ A~chorage / Drill Site lA Well No. "1A-4 "~1A-5 ',OlA_7 ~lA-9 ~1A-11 '~1A-12 '~1A-14 '~ 1A-15 ",,lA-16A~ ATTACHMENT II KUPARUK RIVER UNIT Production Loqs Log Date 7/6/83 10/29/83 517182/ 3/23/83 / ~ · 1/19/83') J- 3/21/83/ 3/8/82 4/1/82 6/5182 -. S/11/82,x. Dri 11 Site Wel 1 No. Log Date lB "~1B-1 12/26/81 ~1B-2 6/25/81 '~lB-3 11/16-18/81~'-7 '" 3/12/82 ./ ~-1B-6 11/18/81',,,. "~ 9/10/82/ ~1B-7 11/23/81 ~1B-8 12/28/81"~ ~ 814/82/ ~IB-g ~ 6/24/82,..-.~..), ~ 8/3/84" / · y ../ Drill Site 1C Wel 1 No. '""~1C- 1 '"'"1C-2 "1C-3 ',~1C-4 '"w,~',,,~lC- 5 .. "~1C-6 "~1C-7 '"'. 1C-8 Log-Date 5/9/8'1 5/8/81 7/13/81 11/8/81'~ 3/9/81/ 2/26/81 11/30/81 5/19/81 5/21/81 Drill Site 1D Well No. Log Date~ "~1D-1 1/80"~ ~ ~' 5/23/83./' · '"'"1D-3 8/5/80 "' '. 1D-4 ~7/30/80"~' ~ ~8/13/80/ -- ~ ~-~ 6/~/8~ .--'..'. ~1D-6 6/9/81 ': - ~1D-7 6/8/81 ' '--' ~1D-8 (US-8) 5/10/78' '~:"' -- '.: - - ...1~ - . '.:~:. ARCO Alaska, Inc. Post Office('' 100360 ' Anchorage, ~,aska 99510-0360 Telephone 907 276 1215 I-? E' T !.~ F:. i'--,' TO' i A- 3'"" i H-- 4,' i 1'",...O _ ,t./ ~,a i B-7 -- i E,.'-.2. ~ -. i Q .... ,o ~ iq-ii .. .I, ~. i ~---i i.- iQ--i i~ t i I.:.' .... iQ_o'- : · i o .... ~/' ,-.,F. CJ AL. ASr'A, INC,. AT'T'N: REC'.ORDS CLE:F::I< ATO-.i i i SB f:'~ 0. B'.:]X i 'S~07i::'.,0 ANr. H,qI::'Ar.;E, A!--:'. o°'-:i -'.'.~ I-I,.EF;'.EWITH ARE THE: FOI...I..OHIN[;. RETURN ONE .%Z(..';.i',!ED COI."Y OF STATIC BI-.IF' STATIC BI-.IF' STATIC BHF' STATIC BHF' .%TAT]:r' ,., BHF' STATIC BHF' ,.> OE,;STA 'f' I C STATIC .bHF SOE,/STATI C STATIC BHF' SOE/ $'F A T I C STATIC BHP 2 DE./2' TAT I,_.r' I, ~',TH I)ATA DATA D A I'"A DATA B I..t P DATA BHF' DATA BFIF' DATA ~'I. IF' STATIC BHP DATA ,?OE/'A' SAND F'BU STATIrt BHF' r;--.'r.-. ... .~. I-'l ~ I;"l ~ / ~-, T.'., I '~ 0 ,: ,' . .:, ,..I F'BU PATA ~TATIr..'. Bt..tF' I)ATA Y'T'ATIr: Bt-:P DATA ..?F!.F ,: .:?.. T:,' Hr-.' 'A' ~ ............. : %% F' E..' U DATA . $ 0 E / F' B U 'C' DATE' APRIL ':.~':-~ 'r R A i",~.',," H I T T A L NO' I l' E bi S,, F'!. E A S E T I--I I 2. 'r F;.: A i,,! $ H I T '1' A I.., 5t47 t ,." 2.!.'-t ¢ z '~: ..." t/26/~5 t /~'? /~'-" t/24/~''-o_, i/25/85 2/t f 2/i t/,: ,~:;' 1 0/85 '~ 0/8 ,:../i . , 5 a,'.. :' . . · -, ,3,:8= ../~ .;. ') /0 .~, .-' ¢ ,, ,...: .;' 2/':?/85 2/24 . .- (2 .. 2/o7/85.. .~. / ~'. I / ") /"]'? :0~--- I).,.'r £ T F::....'" _.T-" ;...t 1' I (] N · DR I I.. I._ .i: i".,!.,.'~ - I,,,l, F'ASHER , i! H ~'-.l....~. T ~''~ ~'-~ F: v v p ~j L. ,. · ..; .... ~.- ...... ,.--....,: ._, '. H (].g :.r. !.. F' H I I_ L I F'S (31 I... -'.]~" r'~ ~r..,!; j R~..~l-l..lf.i~:-l_t. I': b) ;'. ...' I... I... I \ I ~, ~. :.- Alaska, Inc. ii t Subsidiary of AllanticRichfieldCompany 4n,,., 6F'/,s, ,. "'~5'r. . ' · ' ~ "~iFll',', . D/',..i T !'2.: ..... ~ ......... [ ii...! .-[. ~ .... .... ! F' .~ : ....~=. ._.. ~.. ~ ~,.. ARCO Alaska, In~ Post Offic~ o~ 360 Anchorage, Alaska 99510 Telephone 907 277 5637 Date: 1/17/85 Transmittal No: 4981 RETURN TO: ARCO ALASKA, INC. ATTN: Records Clerk AT0-1115B P.0.~0~100360 ~/f~orage, AK 99510 · . ~.~__= --~--- -/T3z~nsmittedAherewith are the following items. and return one signed copy of this transmittal. OTIS PBU SURVEYS' Please acknowledge receipt 2w-8/' 1/08/85 IB'7~'?~'' 12/14/84 2F-12 1/06/85 2F-5 .... 1/02/85 2W-5 J'". 1/07/85 ~W-6 1/07/8 5. ~W-7~ ..... 1/07/85 i lA-1~' 12/31/84 lA-1 ~ 12/15/84 A-1''~' 12/23/84 0-5 .... 12/25/84 2F-3~' '12/31/84 2V-SA~ 12/16/84 2B-10' 12/17/84 1Y-9 ' 12/20/84 --lC-~2~ 12/10/84 2F-2 ~ 12/29./84 2F-15''~ 1/05/85 2F-14- 1/04/85 2F-9~ 1/02/85 2F-8-- 1/01/85 API 02 9-21228 '029-2D616 029-21097 029-21073 029-21220' -- 029-05900 029-20908 029-21128. 029-21084 029-21 063 029-21048 /~~/~ 029-21048 029-21.090 029-21077 CAMCO PBU SURVEYS 1E-12 ~ 12/14, 16/84 /cat Receipt Acknowledged: B. Currier Date:~ska Oil & G~S Co~ ~n~,,missJon Anchora~o DISTRIBUTION Drilling W. Pasher State of AK BPAE Chevron Geology Mobil G. Phillips Sohio Phillips Oil Union D&M NSK 0ps. J. Ratkmell Well Files ARCO Aleska. Inc. i,~ a subsidiary ol AtlanllcRichfieldCompany ARCO Alaska, Inc. Post Office Bo'' i!0 Anchorage, Ai~s'ka 99510 Telephone 907 277 5637 August 17, 1982 Mr. C. V. Chatterton Commissioner State'of Alaska Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 SUBJECT' Revised Well Completion Reports Dear Mr. Chatterton' Enclosed are revised well completion reports and gyroscopic surveys for the following wells' lB-6 '~,IB- 7 These reports are being resubmitted due to an RKB change. Sincerely, J. Gruber Associate Engineer JG' llm Enclosures ARCO Alaska. Inc. is a ,'~ubsidiary o! AtlanlicRichfieldComp;~ny · ' (' STATE OF ALASKA ALASKA . .L AND GAS CONSERVATION C(~ MISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of Well -- fE~'i.~/"~ -- Classification of Service Well OIL [~ GAS [] SUSPENDED [] ABANDONED [] SERVICE [] 2. Name of Operator 7. Permit Number ARCO Alaska, Inc. 81-89 3. Address 8. APl Number P. O. Box 360, Anchorage, AK 99510 5o- 029-20616 4. Location of well at surface 9. Unit or Lease Name 500' FNL, 262' FEL, Sec. 9, TllN, R10E, UM Kuparuk River Unit At Top Producing Interval 10. Well Number 1326' FSL, 1693' FEL, Sec. 10, TllN, R10F., L~ lB-7 At Total Depth 11. Field and Pool 532' FSL, 1602' FEL~ Sec. 10, TllN, R10F., L~4 Kuparuk River Field 5. Elevation in feet (indicate KB, DF, etc.) I 6. Lease Designation and Serial No. "Kupa~uk River 0il Pool 94' RKBI ADL 25648 ALK 466 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., Susp. or Aband. I 15. Water Depth, if offshore 116. No. of Completions 08/27/81 09/12/81 09/20/81I __ feet MSLI ] 17. Total Depth (MD+TVD) 18. Plug Back Depth (MD+TVD)19. DirectionalSurvey [ 20. Depth where SSSV set [ 21. Thickness of Permafrost 9625'MD,6967'TVD 19473'MD 6874'TV• YES~ NOD 1977' feetMD 1650' (2n~rn¥h ~ ., .b ~ '.~ 22. Type Electric or Other Logs Run DIL/SP/GR/BHCS, FDC/CNL/GR/Cai, CBL/~FDL. GR/CCL 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD CASING SIZE WT. PER FT. GRADE TOP BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 16" 65# H-40 Surf 80' Z4" zoo sw p~.rm,¢~o,t 10-3/4" 45.5# K-55 Surf 2845' 13-3/4" 1.~00 sw F~nd~ & 2_~ ~¥ A.~ 'rT 7" 26# K-55 Surf 9570' 8-3/4" 350 sw C.1~_~ "C," ~t 24. Perforations open to Production (MD+TVD of Top and Bottom and 25. '-" .' TUBING RECORD interval, size and number) SIZE DEPTH SET (MD) PACKER SET (MD) 3-1/2" 85.%~ ' R46fl ' S/A 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD} AMOUNT& KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production Method of Operation (Flowing, gas lift, etc.) N/A N/A Date of Test Hours Tested PRODUCTION FOR OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE GAS-OILRATIO TEST PERIOD ~ FI0w Tubing Casing Pressure CALCULATED OIL-BBL GAS~MCF WATER-BBL OIL GRAVITY-APl (corr) Press. 24-HOUR RATE: I1~ . ?, "' ~i'. ~ *~ I~ ~ 28. CORE DATA ~,~ ~, t.. ~ "' Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. , ¢~9/~ Form 10-407 Submit in duplicate Rev. 7-1-80 CONTINUED ON REVERSE SIDE 29. ~ 30. GEOLOGIC MARKERS FORMATION TESTS NAME Include interval tested, pressure data, all fluids recovered and gravitv, MEAS. DEPTH TRUE VERT. DEPTH GOR, and time of each phase. Top Kuparuk 8530 ' 6260 ' N/A Top lJpper Sand 8578' 6295' Base Upper Sand 8617' 6323' Top Lower Sand 8880' 6507' Base Lower Sand 8942' 6553' Base Kuparuk 9024' 6604 ' -- 31. LIST OF ATTACHMENTS Gyroscopic Survey (2 Copies) 32. I hereby certify that the foregoing is true and correct to the best of my knowledge ~ INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production-from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cement- ing and the location of the cementing tool. Item 27' Method of Operation' Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- jection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none" Form 10-407 KUPARUK ENGi~EERiNG TO: TRANSMITTAL Transmitted herewith are the following- PLEASE NOTE- BL - BLUELINE, S - SEPIA, F - FILM, T - TAPE RE. PT ACKNOWLEDGED.: /EASERETURN RECEIPT 'TO: ALASKA 'AND GAS CONSERVATION C WIISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of Well Classification of Service Well OIL I~ GAS [] SUSPENDED [] ABANDONED [] SERVICE [] 2. Name of Operator 7. Permit Number ARCO Alaska, Inc. 80-89 3. Address 8. APl Number P.O.Box 360, Anchorage, AK 99510 5o- 029-20616 4. Location of well at surface ~)~)U' I' NL, 762' I-kL, Eec N, ~'J 'iN, R'JOE, Ui~ 9. Unit or Lease Name Kuparuk At Top Producing lnterval 1368'FSL, 1686'FEL, Sec 10, TllN, R10EUH lO. Well Number 1B-7 At Total Depth 532'FSL, 1602'FEL, Sec 10, TllN, R10E UH 11. Field and Pool Kuparuk River Field 5. Elevation in feet (indicate KB, DF, etc.) I 6. Lease Designation and Serial No. 98' RKBI ADL 25648 ALK 466 Kuparuk River OiI Pool 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., Susp. or Aband. 115. Water Depth, if offshore 116. No. of Completions 8/27/81 9/12/81 9/20/81I -- feetMSLI 1 17. Total Depth (MD+TVD)9625, MD 18.Plug Back Depth (MD+TVD)9473, MDYES19' Directional Survey[~ NO [] I20' Depth where sSSV set1977' feet MD I21' Thickness Of PermafrOst1650' (approx) 22. Type Electric or Other Logs Run DIL/SP/GR/BHCS, FDC/CNL/GR/CAL, CBt/VDt, GR/CCL 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD CASING SIZE! WT. PER FT. GRADE TOP BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 1~'' 65~ H--40 Surf 80' ' 24" 200SX Permafrost I 10 3/4" 45,5# K-55 Surf 2845' 13 3/4 1300 sx Fondu & 250 sx AS II 7" 26# K-55 Surf 9570' 8 3/4" 350sx Class G Cmt .,, 24. Perforations open t6 P?6'duEtion (MD+TVD of Top and Bottom and 25. TUBING RECORD ' inrterval, size and number) SIZE DEPTH SET (MD) PACKER SET (MD) . 3 1/2" 8533' 8460' 8575' -8650' 8670'-8686' 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. - 8695t_8702' DEPTH INTERVAL (MD) AMOUNT& KIND OF MATERIAL USED 8880'-8894' .- N/A - 8904'-8914' , 8922',8940' w/4 SPF . .- 27. ' F;RoDUCTION TEST Date First Product on i Method of Operation (Flowing, gas lift, etc.) 12/13/81 Flowinc .. Date of Test Hours Tested PRODUCTION FOF~ OIL-BBL GAS-MCF WATER-BBL CHOKE SlZE GAS-OIL RATIO 11/23/81 14.6 TESTPERIQ.D I~ . 2905 1174 .... 88/64 398 . Flov~T.ub'i.ng Casing Pressure CALCULATED I~ 01'U-BBL . GAS[MCF WATER-BBL OIL GRAVITY-APl (corr) . Press. 370 . 24'HOj~R RATE'tV . 4674 :' .... . . .. . !860 .... .22 ,,7 r 28. CORE DATA . . Brief description of lithotogy, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core'chips. / . · . .... .°'--' O~l'& Form 10-407 Rev. 7-1-80 CONTINUED~ON REVERSE S. IDE Submit in duPlircate 29. 30. GEOLOGIC MARKERS FORMATION TESTS NAME Include interval tested, pressure data, all fluids recovered and gravity, MEAS. DEPTH TRUE VERT. DEPTH GOR, and time of each phase. Top Kuparuk River Form. 8530' " 6261' Base Kuparuk River Form. 9024' 6602' ,, 31. LIST OF ATTACHMENTS ,, 32. I hereby certify that the foregoing is true and correct to the best of mv knowledge Signed . , Title Area 0ps. En,qr. Date .... INSTRUCTIONS General' This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1' Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completio.,n), so state in item 16, and in item 24 sho~ the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21' Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). Item 23: A~tached supplemental records for this well should show the details of any multiple stage cement- ing and the location of the cementing tool. Item 27: Method of Operation' Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- jection, Gas Injection, Shut-in, Other-explain. Item 28' If no cores ta ~.l~l~; indicate "none". ~.?, Form 10-407 TS' NORTii SLOPE E[~GI;.IEERIi:G TRA[~SHITTAL ~ /~/ J. J. Pawelek/Ann Simonsen DAT-7_- ,- / -- Z. ?- ~ ~ WELL,,~,.F_-"'~"~-- Ira., .... lrted herewith affe the following' PL..~_.; HOTE' - BLUEL!~E, SEPIA, F - FILH, T - TAPE RECE '.,PT ACK;;O',.;LEDGE . ~, _ .-~._DATE' ':',"-~:. ,:r_iu..,~ RECE~.?T TO ARCO ALAS~t&, I!4C. ATT~I: A;;N SIMO;iSE~! - AFA/311 P.O. BO:< 360 RECEIVED ~ 0 ~ ~982 Gas Cons. Commi$~Io~ Anchorage NORTH ~LOPE E:~GINEERIi:G TO- ~~ ~'/~.,' /~..,~'~,~ FROM- J. J. Pawelek/Ann Simonsen DATE' /]- 2. ~ ~ ~ Z~ WELL NAME: TransmiSted here;.;ith are the following: PLEASE ~,0~: BL - BLUEL!~ S - SEPIA, F- FILM, T - TAPE RECET. PT AC.,~O,';L,:. . · P ......,',=,UP,,i [",ECE~?T TO' DATE: RECEIVED FEB, 0 11982 ARCO ALAS~CA, ATTr!- P.O. BOX 360 Anchorage, January.20, 1982 ~.~. Lonnie Smith State of Alaska Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Subject' Updated ~11 Completion Reports Dear Sir' Enclosed please find the updated ~11 Completion Reports for the following wells' DS 11-2 DS 14-16 DS'12-13 DS A-4 DS 13-5 DS A-5 DS 13-7 DS A-6 DS14-15 DS Sincere ly, G. L. Alvord Associate Engineer Enclosures GLA:ss JAN 2 d ]982 AlasKa Oil & Gas Cons, 'Anchorage WELL COMPLETION OR RECOMPLETION REPORT AND LOG -1. Status of Well Classification of Service Well OIL~ GAS [] SUSPENDED [] ABANDONED [] SERVICE [] 2. Name of Operator 7. Permit Number ARCO A1 aska, Inc. 81-89 3. Address 8. APl Number P.O. BOx 360, Anchorage, AK 99510 5o-029-20616 '4. Location of well at surface '~- 9. Unit or Lease Name 500' FNL, 262' FEL, Sec. 9, TllN, R10E, UN V~FmD Kuparuk At Top Producing Interval j Surf.~ 10. Well Number 1368' FSL, 1686' FEL, Sec. 10, TllN, RI0E, UM IB.H.~ B-7 At Total Depth-- ~ 11. Field and Pool 532' FSL, 1602' FEL, Sec. 10, TllN, R10E, UM Kuparuk River Field 5. Elevation in feet (indicate KB, DF, etc.)16.Lease Designation and Serial No. Kuparuk Ri ver 0i 1 Pool 98'RKBI ADL 25648 ALK 466 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., Susp. or Aband. 15. Water Depth, if offshore 116. No. of Completions :8/27/81 9/12/81 9/20/81 -- feetMSLI 1 17. TotalDepth(MD+TVD) 18. Plug Back Depth (MD+TVD, 19. DirectionalSurvey I 20. Depth where SSSV set ) 21. Thickness of Permafrost 9625'MD 6967'TVD 9473'MD 6876'TVE YESE~ NOi--] 1977' feetMD 1650' (approx) 22. Type Electric or Other Logs Run DIL/SP/GR/BHCS, FDC/CNL/GR/Cal, CBL/VDL, GR/CCL 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD CASING SIZE WT. PER FT. GRADE TOP BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 16" 65# H-40 Surf 80' 24" 200 sx Permafrost 10-3/4" 45.5# K-55 Surf 2845' 13-3/4" 1300 sx Fondu & 250 sx AS II 7" 26# K-55 Surf ..9570' 8,-3/4" 35Q sx Class· "G" cmt · 24. Perforations open· to Production (MD+TVD of Top and Bottom and ~ :25. TUBING RECORD .1 ..interval, size and number) · SIZE DEPTH SET (MD) PACKER SET (MD) 3-1/2" 8533' 8460' To be submitted ... · 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. - ~ DEPTH INTERVAL (MD) AMOUNT& KIND OF MATERIAL USED - N/A . , 27, PRODUCTI°N TEst .. Date ~i~st Production . . Method of Operation (Flowing, gas lift, etc.) N/A N/A : .:. Date of Test Hours Tested PRODUCTION FOR OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE GAS-OIL RATIO ' · TEST PERIOD m~ Flow :Tubing Casing Pressure CALCUL,ATED OIL-BBL GAs]'McF WATER-BBL OIL GRAVITY-APl (corr) mm~ Press . . 24-HOUR RATE , . ., .. 28. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. · : · · , . . JAN 2 O 198~ ~ , ,' Form 10-407 Submit in duplicate Rev. 7-1-80 CONTINUED ON REVERSE SIDE NAME Include interval tested, pressure data, all fluids recovered and gravity, MEAS. DEPTH TRUE VERT. DEPTH GOR, and time of each phase. Top Kuparuk 8530' 6260' Top Upper Sand 8578' 6295' N/A Base Upper Sand 8617' 6323' Top Lower Sand 8880' 6507' Base Lower Sand 8942' 6553' Base Kuparuk 9024' 6604' -. 31. LIST OF ATTACHMENTS 32. I hereby certify that the foregoing is true and correct to the best of my knowledge ~.~.~ F~:)~.- ~,/~.V,~J~'~_~,-J Title Dist. Drlg. Engr. Date Signed INSTRUCTIONS General' This form is designed for submitting a complete and correct well completion report and Icg on all types of lands and leases in Alaska. Item 1' Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5' Indicate which elevation is used as reference (where not otherwise Shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple Completion), so state iiq, item 16, and in.item 24 show the producing intervals for onlY the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21' Indicate whether from ground level (GL) or other elevation (DF, KB, etc.).. Item 23' Attached supplemental records fOr this well should show the details of any multiple stage cement- ing and the location of the cementing tool. Item 27' Method of Operation' Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- jection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Form 10-407 SLOP,E EiIGI .... ,o -tF HORTti TRAi!S:.IITTAL ~ /"~ ~9 ' FRO;,]' J.J. P~,..,,e]ek/Ann S~monsen Transmitted here'..:i th are the ~followisg' PLEASE HOTE' BL - BLUEL!HE, S - SEPIA, F - FILM, T - TAPE RECEIVED JAN- ~ 1982 Alask~ Oil & Gas Cons. Commissio~ ARCO ALAS~tA, I~C. ATT~I: A~;~; SI;.~O~iSE~ - AFA/311 P.O. BOX 360 ~,,,~,~,,~O~ coS1 0 ARCO Alaska, Inc. (' Post Office Bb,, 360 Anchorage, Alaska 99510 Telephone 907 277 5637 December 11, 1981 Mr. Hoyle H. Hamilton State of Alaska Oil & Gas Conservation Comm. 3001 Porcupine Drive Anchorage, Alaska 99504 Dear Mr. Hamilton: Attached please find subsequent reports Well lB-7, 1C-3, 1C-4, and 1E-3. Sincerely, J S Dayton Area Operations Engineer EAS/bl At t achment for Kuparuk RE£EIVEI) DEC 1 5 1981 Alsska 0il & Gas Cons. Commissior~ Anchorage ARCO Alaska, ~nc. is a subsidiary of AtlanticRichfieldCompany STATE OF ALASKA ~' ALASKA OIL AND GAS CONSERVATION COMMISSION SUNDRY NOTICES AND REPORTS ON WELLS 1. DRILLING WELL [] COMPLETED WELL OTHER [] 2. Name of Operator ARCO Alaska, Inc. 3. Address P.O. Box 360, Anchorage, 4. Location of Well Surface Location: AK 99510 500' FNL, 262' FEL Sec. 9, TllN, R10E, U.M. 7. Permit No. 81-89 8. APl Number 50- 029- 20616 9. Unit or Lease Name Kuparuk 25648 10. Well Number lB-7 11. Field and Pool Kuparuk Ri-ver Field 5. Elevation in feet (indicate KB, DF, etc.) I 6. lease Designation and Serial No. -- KB qR' I ADT. 756~g l~p~r~l~ River Oil Pool 12. ' - Check Appropriate Box :1:~) Indi~a~te-Nature of Notice, Report, or Other Data NOTICE OF INTENTION TO: SUBSEQUENT REPORT OF: (Submit in Triplicate) (Submit in Duplicate) Perforate [] Alter Casing [] Perforations ]~ Altering Casing [] Stimulate [] Abandon [] Stimulation [] Abandonment [] Repair Well [] Change Plans [] Repairs Made [] Other [] Pull Tubing [] Other [] Pulling Tubing [] (Note: Report multiple completions on Form 10-407 with a submitted Form 10-407 for each completion.) 13. Describe Proposed or Completed Operations (Clearly state all pertinent details and give pertinent dates, including estimated date of starting any proposed work, for Abandonment see 20 AAC 25.105-170). Began operations on 11/20/81. RU and ran dummy perforating gun to 8940' MD to check for obstructions. Perforated 8605'-8650' MD and flowed well for 2 hours. Well flowed an average of 5 1 B/D Perforated 8574'-8605' MD, 8670'-8686' MD, 8695'-8702'1 MD, ' 8880'-8894' MD, 8904'-8914' MD, and 8922'-8940' MD. All perforating was done with 2 1/8" OD tubing guns, 4 SPF, 0° phasing. Began drawdown test 11/23/81. Flowed well for l~fp__.hours on an 88/64" choke. Well flowed a stabilized rate of Q4674/)BOPD with a GOR of 398 SCF/Bbl and a trace B S & W. ISIBHP ~ 3212 psi, FFBHP was 2489 psi and FTP was 370 psi. The well was shutin for a 10.9 hour buildup test. FSIBHP was 3199 psi. Secured well 11/24/81. I~./'~",,,... DEC 1 5 1381 Abska Oil & (~as Co.s. ¢ommissJo~ /~cJlorags 14. I hereby certify that the foregoing is true and correct to the best of my knowledge. k~)~ ~~~ Area Operations Engineer Signed , , _ Title The space [~1ow for Commission/~e Conditions o'"f Approval, if any: ~/ Date By Order of Approved by. COMMISSIONER the Commission Date Form 10-403 Rev. 7-1-80 Submit "Intentions" in Triplicate and "Subsequent Reports" in Duplicate ~C STATE OF ALASKA O(M ALASKA ,L AND GAS CONSERVATION C MISSION SUNDRY NOTICES AND REPORTS ON WELLS 1. DRILLING WELL [] COMPLETED WELL OTHER [] 2. Name of Operator ARCO Alaska, Inc, 3. Address P.O.Box 360, Anchorage, AK 99510 4. Location of Well Surface Location: 500' FNL, 262' FEL Sec. 9, TllN, R10E, U.M. 5. Elevation in feet (indicate KB, DF, etc.) I 6. Lease Designation and Serial No. - KB=98' I ^DL 25648 12. Check Appropriate Box To Indicate Nature of Notice, Report, or NOTICE OF INTENTION T.O: 7. Permit No. 81-89 8. APl Number 50- 029-20616 9. Unit or Lease Name KuDaruk 25648 10. Well Number lB-7 11, Field and Pool Kuparuk River Field Vllm~r~lP P{v~r f~l_'! Pobl Other-b-a[a ............. SUBSEQUENT REPORT OF: (Submit in Triplicate) Perforate ~ Alter Casing [] Perforations Stimulate [] Abandon [] Stimulation Repair Well [] Change Plans [] Repairs Made Pull Tubing [] Other [] Pulling Tubing (Note: Report multiple completions on Form 10-407 with a submitted Form 10-407 for each completion.) (Submit in Duplicate) [] Altering Casing [] [] Abandonment [] [] Other [] 13. Describe Proposed or Completed Operations (Clearly state all pertinent details and give pertinent dates, including estimated date of starting any proposed work, for Abandonment see 20 AAC 25.105-170). ARCO Alaska, Inc. proposes to perfgrate the following depths in the Kuparuk Sand: 8574-8605, 8605-8650, 8670-8686, 8695-8702, 8880-8894, 8904-8914, 8922-8940, and 8947-8958. A 3000 psi lubricator _.will be used on all wireline work. All circulated and flowed fluids will be diverted to tankage on location. Expected start date.. November 10, 1981 NOV 1 6 19, ' 8-ab~eqnent V¢o~J( ~¢pc,~e~ ' Alaska 0il & Gas Cons. on Fora No. t6 qo3 Datedi~/~ ~ ~' Anchorage 14. I hereby,certify that the foregoing is true and correct to the best of my knowledge. ~~ ~f~~~ F Area Operations Engineer Signed 4~ Title ' The space below fo/Commissio~'us~'~''---~' ...... ~ Conditions of Approval, if any: Approved Copy Re~rned COMMISSIONER theCommissionBY Order of Form 10-403 Rev. 7-1-80 Submit "Intentions" in Triplicate and "Subsequent Reports" in Duplicate NORTH ~LOPE E[[GI?,~EERIi;G TO' /x~/~ ~~ ~ FP, CM: /,.., WELL Transmitted herewith are the following' PLEASE HOTE' - BLUEL!HE, - SEPIA, J. J. Pawelek/Ann Simonsen F - FILM, T - TAPE 'RECEIVED. OCT 2 C ~' "' - ~ .... ' ~ ,,~/¢ /kles~ Oil & ~s Co~s Co~i~ion ~PL~;.~= ~ETUO:I ~EC=;FT TO' ARCO ALAS:&, Ii~C. ~ '~ ' ~'I _ ATTH' A;'~H qI,~O~S~, AFA/311 P.O. BOX 360 A:iCHORAG2, AK 99510 ARCO Alaska, Inc. Post Office B"L;;. 'J60 Anchorage, Alaska 99510 Telephone 907 277 5637 October 9, 1981 Mr. Hoyle Hamilton State of Alaska Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Subject' Completion Gyroscopic Surveys Dear Sir' Enclosed please find the completion Gyroscopic./Survey for the following .wells' DS 12-12,~'DS 17-7~ DS 17-9, A-5f-'A-6, q~-6? an d' B:~?~'~ Sincerely, P. A. VanDusen District Drilling Engineer PAV:cm Enclosures ARCO Ala.~k,*, In(:. is a subsidiary of AllanlicRichfieldCompany ~ ARCO Alaska, Inc. ,. No~'th Slope 'L,,~.'~rict Post Office Box 360 Anchorage, Alaska 99510 Telephone 907 277 5637 907 263 4274 Les M. Sellers District Drilling Manager October 5, 1981 Mr. Hoy!e Hamilton State of Alaska Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Subject- DS 14-11 Kuparuk A-4 Kuparuk B-6 DS 14-16 Kuparuk A-5 ~ ...... ~ ....... DS 17-10 Kuparuk A-6 Kuparuk B-8 Dear S ir' Enclosed please find the following' 1) The Completed Well Reports for DS 14-11, DS 14-16; Kuparuk A-4, A-5, A-6, B-6, & B-7. 2) The Monthly Report for Kuparuk B-8. 3) The completed Gyroscopic Survey for DS 17-10. Sincerely, P, A. VanDusen District Dr.illing Engineer PAV'cm Enclosures RECEIVED?-, OCT 0 8 1981 Gas Cons. Commission Anchorag~ ARCO Alaska. Inc. is a subsidtary r,f Allan~.cPichf,e,'.;" mpany STATE OF ALASKA ALASKA ~.AND GAS CONSERVATION C ,¢IlSSION _ WELL COMPLETION OR RECOMPLETION REPORT AND''LOO ..... 1. Status of Well , Classification of Service Well OIL)~ GAS [] SUSPENDED [] ABANDONED [] SERVICE [] 2. Name of Operator 7. Permit Number ARCO Alaska, Inc. 81-89 3. Address 8. APl Number P.O Box 360 Anchorage, Alaska 99510 5o- 029-20616 4. Location of well at surface 9. Unit or Lease Name 500' FNL, 262' FEL, Sec 9, TllN, RiOE, UM Kuparuk At Top Producing Interval 10. Well Number To be Submitted B-7 At Total Depth 11. Field and Pool To be Submitted 5~! 'F£~, /~m~f:E~/ 5mc/o/ ~tr/V//~/C)~/~, Kuparuk River Field 5. Elevation in feet (indicate KB, DF, etc.) I 6. Lease Designation and Serial No. Kuparuk River 0i 1 Pool 98' RKBI ADL 25648 ALK 466 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., Susp. or Aband. ] 15. Water Depth, if offshore 116. No. of Completions 8/27/81 9/12/81 9/20/81I -- feet MSLI 1 17. TotalDepth(MD+TVD) 18. Plug Back Depth (MD+-I'VD) 19. DirectionalSurvey I 20. Depth where SSSV set I 21. Thickness of Permafrost )625'MD (~/~? ' 9473'MD YEs[~X NO[] 1977' feetMD 1650' (appr0x) 22. Type Electric or Other Logs Run DIL/SP/GR/BHCS, FDC/CNL/GR/Cal, CBL/VDL, GR/CCL 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD CASING SIZE WT. PER FT. GRADE TOP BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 16" 65# H-40 Surf 80' 24" 200 sx Permafrost 10 3/4" 45.5# K-55 Surf 2845' 13 3/4" 1300 sx Fondu & 250 sx AS II 7" 26# K-55 Surf 9570' 8 3/4" 350 sx Class "G" cmt 24. Perforations open to Production (MD+TVD of Top and Bottom and 25. TUBING RECORD , interval, size and number) SIZE DEPTH SET (MD) PACKER SET (MD) To be Submitted 3 1/2" 8533' 8460' ~ . .. 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. · DEPTH INTERVAL (MD) AMOUNT& KIND OF MATERIAL USED N/^ ~ B~illinm Niqfnrv 27. pRODUCTION TEsT Date Fir.st Production I Method of Operation (Flowing, gas lift, etc.) N/A] N/A Date of Test Hours Tested PRODUCTION FOR OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE IGAS-OILRATIO TEST PERIOD I~ Flow Tubing Casing Pressure CALCULATED.k OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY-APl (corr) "Press. 24-HOUR RATE I~ 28. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. RECEIVED OCT 0 8 1981 Alaska Oil & Gas Cons. Commission Anchorage Form 10-407 Submit in duplicate Rev. 7-1-80 CONTINUED ON REVERSE SIDE 29. 30. - GEOLOGIC MARKERS FORMATION 'i:ESTS NAME Include interval tested, pressure data, all fluids recovered and gravity, . · MEAS. DEPTH TRUE VERT. DEPTH GOR, and time of each phase. To be Submitted , 31. LIST OF ATTACHMENTS · 32. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed .~. ~~L.~~ Title Dist. Dr lg Engr. Date ~0/5/8~ · INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1' Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water..disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item l~;:.~and 24: If this well is completed for separate production 'irom more thar{ one interval (multiPle completion), so state in item 16, and in item 24 show the producing intervals for only the inte~al reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21 :. Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). Item 23' Attached supplemental records for this well should show the details of any multiple stage cement- ing and the location of the cementing tool, Item 27' Method of Operation' Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water in- jection, Gas Injection, Shut-in, Other-explain, Item 28: If no cores taken, indicate "none". Form 10-407 KUPARUK B-7 DRILLING HISTORY NU hydrill & diverter. Spudded well @ 0100 hrs, 8/27/81. Drld 13 3/4" hole to 2900' Ran multishot. Ran 68 jts 10 3/4" 45.5#, K-55 BTC csg w/shoe @ 2845'. Cmtd '10 3/4" csg w/1300 sx Fondu & 250 sx AS II. ND hydrill & diverter. Instld 10 3/4" pkoff & tstd to 2000 psi - ok. NU BOPE & tstd to 3000 psi - ok. Tstd csg to 1500 psi - ok. Drld FC & cmt. Tstd csg to 1500 psi - ok. Drld FS & 10' new form. Tstd form to 12.5 ppg EMW - ok. Drld 8 3/4" hole to 9255' Ran DIL/SP/GR/BHCS & FDC/CNL/GR/Cal. Drld 8 3/4" to 9625'. Ran 237 its 7~' 26# K-55 BTC csg w/shoe @ 9570'. Cmtd 7" csg w/350 sx Class "G" cmt. Instld 7" pkoff & tstd to 3000 psi - ok. Arctic packed 7" x 10 3/4" annulus w/300 bbls H~O, 250 sx AS II and 105 bbls Arctic Pak. Displace tbg to NaBr. Ran C~L/VDL. Tstd csg to 1500 psi - ok. Drld cmt to 9473' PBTD. Ran 3 1/2" per~~'~'o~pletion assy w/tail @ 8533' & pkr @ 8460'. Tstd tbg hngr & pkoff to 3000 psi - ok. Displace tbg & well w/diesel. Set pkr. Tstd tbg to 2930 psi & ann to 550 - ok. Displace tbg & well w/diesel. Set pkr. Tstd tbg to 2930 psi & ann to 550 - ok. ND BOPE. NU tree & tst to 3000 psi - ok. Dropped perf bar - guns did not fire. Fish firing bar. Ran CCL. Found obstruction @ No-Go above fishing head. Instl tree cap & tstd 3000 psi - ok. Secured well & released rig @ 0600 hrs, 9/20/81. RECEIVED OCT 0 8 IS8I ~aska Oil & Gas Cons. Comrnissior~ Anchorage ~l lEastman/ -Whipstockl)~ A PETROLANE COMPANY REPORT of SUB-SURFACE DIRECTIONAL SURVEY ARCO ALASKA, INC. COMPANY pad B~ Well ~?umber: 7 ,'i~,~ . , WELL NAME Kuparuk Field, North Slope, Alaska LOCATI ON JOB NUMBER A981G0017 TYPE OF SURVEy REfEIYED Gyro-Multi Shot OCT ! z~ ;98~ SURVEY BY Max Lund OFFICE Alaska DATE 16-Sep-81 Eastman Whipstock A PETROLANE COMPANY P. O. Box 4-1970/Anchorage, Alaska 99509/(907) 349-4617 October 7, 1981 ARCO ALASKA, INC. P.O. Box 1479 Anchorage, Alaska 99510 Well Number: B-7 Location: Kuparuk Field, North Slope,.Alaska Type of Survey: Gyro-Multi Shot Date: 16-Sep-81 Method of Computation: Radius of Curvature Surveyor: Max Lund Job Number: A981G0017 Attn: Bob Hines Dear Mr. Hines, I am enclosing the original and one copy of the Gyro-Multi Shot Survey run on the above mentioned well. We wish to take this opportunity to thank you for calling on our services and trust that we may continue to serve you in the future. Sin~lY, / ' Distric~urveyor AH/bb cc: file enclosure Directional Drillers/SubSurface Surveyors/Instrument & Tool Rentals/Sales/Worldwide ARCO ALASKA, INC+ F'A'D'B~' WEEL' NO,~ 7""'G'NS JOB KUF'ARUK FIELD, NORTH SL. OPE, ALASKA GMS, 0-9450 MI:l, SURVEYOR: ~iAX LUND RUN ]'lATE:; l&-SEP-81 CAMERA NO: 325~, 1488 GYRO NO; 30& 90 DEG A/U NO: 1121 RIG: PARKER 141 ........... PORES'I GHT~: WEST VERTICAL SECTION L:AI_CULATEI: IN FLAN OF:: FROF. OSAE~ :?! I/ , -. ~ i IRECTI lEG,: .~0 PtlN, E" '~' RECORD OF' SLIRVEY :'AD B, WELL NO; 7 GMS .]OB NO; A981G0017 TINE [;ATE ;~UF'ARUK--'FIELF_;,~ NORT"H SLOPE, 'A'I:ASKA ~ 13T30~'52 06-Al::'R-82 TRUE 4EASUREI:r~'DRIFT DRIFT ..... COURSE'--'-VER:TtCAL-VERT'ICAI" SUBSEA R E C T A-'N'6 U-L"A"R C L 0 S U R E DOGLEG DEPTH ANGLE DIREC'rlON LENGTH I)EF'TH SECTION TVI) C 0 0 R D I N A T E S DISTANCE DIRECTION SEVERITY FEET D H D H FEET FEET FEET FEET FEET FEET O. 0 0 0 0 O. 0.00 0.00 -94.00 0.00 0.00 0.00 100. 0 0 0 0 100. 100.00 0.00 6.00 0.00 0,00 0.00 ........... 200~ .............. 0 ........ 0 ......... 0 0 100~ .......... 200'~00 ........... 0~00 106~00 0.00 ........ 0~00 ..... 0.00 300. 0 0 0 0 100. 300.00 0.00 206.00 0.00 0.00 0.00' 400. 0 0 0 0 100. 400.00 0.00 306.00 0.00 0.00 0.00 500. 0 0 0 0 100. 500.00 0.00 406,00 0.00 0,00 0.00 D H DG/iOOFT 0 0 0.00 0 0 0.00 0 0 0.00 0 0 0.00 0 0 0.00 0 0 600. 3 30 S 60 0 E 100. 599.94 3.01 505.94 1.53 S 2.64 E 3.05 S 60 0 E ........... 700':~ ........ 5 15' S'67 O'E '100. 699,'64 .............. 10','45 605,64 4.93'S ......... 9'c4-7-E .... 10.67 S 62 30 E 800. 900. 1000. 11 0 S 67 0 E 1100. 13 15 S 50 0 E ..... ~200~ 15 30' S 40 0 E 1300. 20 0 S 39 0 E 1400. 24 45 S 38 0 E 1500. 27 0 S 38 0 E 1600. 27 15 S 49 0 E 7 0 S 77 0 E 100. 799.07 20.37 705.07 8.22 S 9 15 S 86 0 E 100. 898.06 32.49 804.06 10.31 S ..... I700. 28 0 S 56 0 E ' 100. t646,35 ........... 294~81 1552.35 1800. 28 0 S 60 0 E 100. 1734.65 341.36 1640.65 1900. 27 0 S 58 0 E 100. 1823.35 387.05 1729.35 19.60 E 33.56 E 100~ 996.o0 .............. 48.,24 90.-.o0 14.39 S 50.58 E . ~6::.,,,:,?:,,::::68.::~7 ........ :100022.~62 : 25 33 S 68 42 E 10 0'? ? 13 78 · 78 1 842~: :::::96 · 16 S 12 9 · 0 3 E 100. 1468.75 203+33 1374.75. :. 130.55 S 100~ 1557.75 248.49 1463.75 163.57 S 191.78 S 216.65 S 240.43 S 155.90 E 187.23 E 223.99 E 263.80 E 303.38 E 2000. 28 0 S 53 0 E 100. 1912.05 433.04 1818.05 266.57 S 2100. 26 0 S 61 0 E 100. 2001.14 478.12 1907.14 291.28 S ..... 2200~ ....... 25 0 S'51 0 E 100. ....... 209~.40 ........... 520~93 1997.40 3t5.32 S 2300. 24 45 S 53 0 E 100. 2182.12 562.99 2088.12 341.22 S 2400. 28 0 S 52 0 E 100. 2271.70 607.38 2177.70 368.26 S 2500. 31 15 S 46 0 E 100. 2358.62 656.76 2264.62 400.67 S 2600. 35 45 S 51 0 E 100. 2441.99 711.88 2347.99 437.22 S ---2700". ........ 38 ........ 0"S-'55 0 E 100+ "252'1-.,97 ......... 771.83 242'7.97 473.33 S 5~r O~E 100. 2671.82 903.59 2577.82 547.76 S 2900. 45 S ...................... 21.26 S 67 15 E 35.11 S 72 56 E 52.59 S 74 7 E: 72.96 S 69 41E 96.05 S 63 30 E 124.51 S 57 47 E 160.92 S 53 18 E 203.34 S 50 3 E 248.62 S 48 52 E 294.88 S 49 26 E: 341.36 S 50 36 E 387.10 S 51 36 E 341.42 E 433.16 S 52 1 E 379.46 E 478.37 S 52 29 E 415,11- E 521.29 S 52 47 E 448.25 E 563.35 S 52 43 E 483.49 E 607.76 S 52 42 E 520.78 E 657.07 S 52 26 E 562.09 E 712.11 S 52 7 E 610.00 E --'772.10 S 52 11E 662.69 E 835.93 S 52 27 E: 719.35 E 904.16 S 52 43 E 1.83 2.04 2.58 3.75 4.20- 3.34 4.51 4.77 2.25 5.02 3.33 1.88 2.52 4.14 4.41 0.88 3.28 4.40 5.28 3.29 3.56 3.25 t'AD B, WELL NO; 7 GMS ~.UFARUK FIEL[, NORYH SLOPE, ALASKA UOB NO; A981G0017 TIME DATE. 1S~30~52 06-APR-82 TRUE IEASURE'D'~DR~IFT ...... DRI'F'] COURSE'VERTICAL VERTICAl, SUBSEAR E C T A N G U L A R C L 0 S U R E DOGLEG iDEPTH ANGLE DIRECTION LENGTH DEF'TH SECTION TVD C 0 0 R D I N A T E S DISTANCE DIRECTION SEVERITY FEET D M D M FEET FEET FEET F'EET FEET FEET D M 3000, 45 30 S 56 0 E 100, 2742,38 974,14 2648,38 587,38 S 778,10 E 974,92 S 52 57 E S100, 48 15 S 56 0 E 100, 2810,7S 1046,81 2716,7S 628,19 S 8S8,61 E 1047,80 S 5S 10 E .... 3'200"+ .......... 51 ...... 30-S"56 0 E ............ l'O0-'~ ....... 2875"~'17 ..... 1122+93 ...... 2781"~'17 670'~ 95' S 901,99 E 1124'~"17 ..... S'-'53-21 E 3S00 53 0 S 56 0 E 100 29S6 S9 1201 65 .~84.~,S9 715,16 S 967 54 E 120S,16 S 5S S2 E S400, 54 0 S 56 0 E 100, 2995,87 1281,69 2901,87 760,11 S 10S4,18 E 1283,47 S 5S 41 E S500, 54 45 S 54 0 E 100~ S054,12 1S62~74 2960,12 806~7S S 1100~76 E 1S64,73 S 53 46 E S600~ 56 15 S 55 0 E 100~ Sl10,76 1444~96 S016,76 854,59 S 1167~85 E 1447~1S S 5S 48 E ~-S~-7'00~ 56 0"S 54 0 E 100, .......S1'66~50 1527,80 S072~50 ..... 902,80'-S I2~5,44 E 15S0;I5 S 53' 5I'E S800, 56 15 S 55 0 E 100~ S222,2S 1610,64 S128,2S 951,01 S 1SOS,0S E 161S,17 S 53 5S E S900+ 58 15 S 54 0 E 100+ 3276,S3 1694~55 S182,3S 999~85 S 1~71,50 E 1697~26 S 5S 54 E 4000, 60 15 S 53 0 E 100, ..... SS27,46 1780,S8 S2S3 46 1050 96 S 1440 58 E 178S 19 S 53 53 E 4100 60 0 S 53 0 E ~ 1103,15 S 1509,83 E 1869 90 S 53 51 E 4300, 60 0 S 53 0 E 100,'::::: :~475,75 1206 68 S 1649,75 E 2043J96 S 5~ 49 E 4400, 58 15 S 54 0 E 100'~ ~527,07 212~f59~ ~4~:[07: 1257'7~ S 1718,74 E 2129,78 S 5~ 48 E ~ 22 4500, 54 15 S 57 0 E 100, ~582,61 2209,42 ~488'61 1~04~81 S 1787,~:4 E -.12,87 S 5~ 52 E 4600, 52 15 S 5~ 0 E 100~ ~642,44 2289~29 ~548,44 1~50,76 S 1852,86 E ~.~,96 S 5~ 54 E ....... 4700* 51 30~S 54 0 E 100~ ~704,18 2~67,86 S610,18 1~97'55 S 1916~10 E 2371~62 S 5~ 54 E 4800, 51 0 S 56 0 E 100, ~766,77 2445,62 ~672,77 1442,28 S 1979,98 E 2449~59 S 5~ 56 E 4900, 51 15 S 57 0 .E 100, ~829,5~ ~,06 ~7~5~5~ 1485,25 S 2044,89 E 2527,~6 S 54 i E DG/IOOFT 0,75 2,75 1,50 1,00 1,7 1,71 0,87 0,87 2,17 2,18 0,25 1,33 1,33 1,95 4,71 3.78 1,09 1,64 o,~-~ 5000, 51 0 S 55 0 E 100, S892,S0 2600,57 S798,S0 1528,78 S 2109,4S E 2605,16 S 54 4 E 5100, 50 0 S 55 0 E 100, S955,90 2677,51 ~861,90 157~004 S 2172,64 E 26820~1 S 54 6 E · --5'200-~ ....... 50'-30 S'56" O-E ............ 100: .......... 40~9~85 ........ 275'4,1'S ~925~85 1616,59 S 22~6,00 E 2759,18 S 54 8 E 5~00, 50 ~0 S 52 0 E 100, 408~,46 28S1,14 ~989,46 1661,93 S 2298,41 E 28~6,~2 S 54 8 E 5400, 51 0 S 51 0 E 100, 4146,7S 2908,57 4052,7~ 1710,14 S 2~59,02 E 291S,68 S 54 4 E 5500, 51 0 S 52 0 E 100, 4209,66 2986,28 4115,66 17.58,52 S 2419,84 E 2991,~2 S 54 0 E 5600, 49 45 S 51 0 E 1000 427S,4~ ~06~,29 4J79,4~ 1806,46 S 2480,12 E ~068,27 S 5~ 56 E --~'5700~ .......... 49 .....O-'S 50 O'E 100', 4SS8,54' 31S9,19 4244,54' ' 1854,74 S 2538,68 E S144,04 S 53 51 E AUG 2 0 ~o~ 1,58 1,00 0,92 S,09 0,92 0,78 1,47 1,07 0,75 0.80 ;'~;r~ B~ WELL NO,~ 7 GMS JO~ NO; A981GO017 TZt4E [~ATE ~UP-ARU~(--Ft'ELT_r, ...... NORTH" SLOPE. .... AL:ASKA 1-3'~-30~52' 06-AF'R-82 TRUE ~ASURED~,~-DR-t-F,T ............ DR.tFT .......... COURSE-VERT"Z'CAL-VERTtCAIz SUBSEA R E C T A N G U-' L--A-R C L' 0 S ~DEF'TH ANGLE DIREECTION LENGTH DEPTH SECTION TVD C 0 0 R D I N A T E S DISTANCE FEET D M D M FEET FEET FEET FEET FEET FEET 6000. 48 30 S 51 0 E 100. 4535.36 3365.51 4441.~& 2002.77 S 270~.~7 E 336~.73 6100. 48 0 S 46 0 E 100. 4601.~5 3440.04 4507.~5 2052.1~ S 2765.83 E 3444.03 ....... 6200's ......... 46'""t5-'"S45 O'E 1'00~ ........ 4669",'98 ........351"S+02' 4575,'98 2103.55 S 2818,"10-E "35-16-.'62 6300. 46 0 S 44 0 E 100. 47~9.29 3584.69 4645.29 2154.97 S 2868.63 E 3587.88 6400. 45 0 S 46 0 E 100. 480~.~8 3655.66 4715.~8 2205.40 S 2~1~.06 E 3658.51 6500. 45 45 S 45 0 E 100. 487~.63 ~726.54 4785.63 2255~2~ S 2~67.82 E 372~.10 S 6600. 46 15 S 44 0 E 100. 4~4~.0~ 37~8.06 4855.0~ 2306.5~ S 3020.24 E 380002~ S ---&700~ ......... 48''3'0"S'4~ 0 E 100~ ...... 50&6,8'1 ~87t',-06 4922,81 '2559,96 S 3070",-88'-E ........ 38'72"~-95 S 6800. 51 0 S 4~ 0 E 100. 5081.42 3~46.&~ 4~87.42 2415.78 S 3122.~3 E 3~48.25 S &~00. 53 0 S 42 0 E 100. 5142.~8 4024.&~ 5048.~8 247~.87 S ~176.17 E 4025.~ S 7000. 55 0 S 44 0 E 7100. 54 0 S 42 0 E .... --7200.~ 53 ....O S 4S 0 E 7~00. 52 0 S 42 0 E 7400. 50 45 S 42 0 E 7500. 4~ 30 S 42 0 E 7600. 47 15 S 41 0 E .... 7700', 45 15 S 40 0 E 7800. 44 45 S 38 0 E 7~00. 42 0 S 37 0 E 100.:..5201.76 .... 4104.86 5107.76 2533.03 S 3231.34 E lOO:~ 525<7. .......... ~ ~-: ~- ~ 83: ===================== , 57 S 3286.85 E 100. 5506.71 4496.74 5412+:71':::2825.41 S 100. 557~.13 4570.5~ 547W.1~ 2881.~ S 100. 5642,'28 4641.62 5548.28' 2~6.~2 S 100. 5712.~ 4710.87 5618.~ 2~1.27 S 100. 5785.67 4777.7~ 56~1.67 S045.75 S 3447:.03 E U R E DOGLEG DIRECTIO~ SEVERITY D M DG/iOOFT 5~ S2 E 53 26 E 5~ 16 E 1.~0 5~ 5 E 0.76 52 56 E 1.74 52 47 E 1.('~' 52 38 E 008~ 52 27 E 52 17 E 2.50 52 5 E 2.15 8000. 41 O S S3 ' O' E 100. 5860.57 4841.52 8100. 40 15 S ~2 0 E 100+ 59~6.47 490~.~8 ...... 8~00~ ...... 40 .... 0"S"24 0 E 100,' -'6012'.'~'~ ...... 4962,80 8300. 40 30 S ~ 0 E 100. 6089._~5 5020.02 8400. 42 0 S 1~ O'E 100. 61&4044 5075.16 5766.57 3100.01S 5842.47 3154.~ S 5~18+'93 3211.78 S 5~5.25 S271.26 S 6070.44 ~4.07 S 4105.82 S 51 4186.27 S 51 4265.6~ S 51 434~.W9 S 51 4421.08 S 51 8500. 43 0 S 8 0 E 1000 62~8.16 5126.77 8600. 44 0 S 8 0 E 100. 6~10070 5177.B8 ...... 8'?00: ....... 44"-45""-S 8 0 E' 100. 63820t8 5228.81 8800. 45 ~0 S 8 0 E 100. 6452.7~ 5280.~1 8~00. 47 ~0 S 8 0 E 100. 6521.56 5~4.25 6144.16 ~400.48 S 6216.70 3468.64 S 6288~'18 3537.~0 S 6~58.73 3608.07 S &427.5~ ~67~.~0 S 34~8.~8 E 44~6.85 S 51 ~547.~1E 4570.57 S 50 3594.82 E 4641.6S S 50 ~6~.~2 E 4710.87 S 50 3681.12 E 477707~ S 50 54 E 2.57 44 E 1091 34 E 1.28 24 E: 1.28 14 E 1.25 4 E 1.25 55 E 2.~7 45 E 201~ ~5 E 1.50 24 E: 2~ ~71~012 E 4841.6~ S 50 11 E ~754.10 E 4~0~.76 S 49 57 E: 3784.'33'E ..... 49&~.54 S 49 41 E S809.58 E 5021.35 S 49 21 E S829.38 E 5077.42 S 48 57 E 3841.&9 E 5130.48 S 48 29 E 3851.27 E 5183.03 S 48 0 E 3861',01" E '5236080 S 47 30 E 3870.87 E 5291.67 S 47 i E 3880.96 E 5348.2~ S 46 31E 2.83 0,99 5.16 6.12 3.52 1.00 0°75 0.75 2.00 ~:'Ar~ B, WELL NO; 7 GMS ,]OB NO; A~781G0017 ~:UF"ARUK'--P~IEIzD,~ 'NORTH~ SLOPE, ALASKA ~ "~ TIPIE DATE . 1'3~30~52 06-APR-82 TRUE ~'E~ASURE'D""~DR'~'FT ................. DR'IPT COURSE VERTICAI~ V~RTI'CAL' SUBSEA R E C T A N G U L A ~DEPTH ANGLE DIRECTION LENGTH DEF'TH SECTION TVD C 0 0 R Ii I N A T E FEET D ~ D M FEET FEET FEET FEET FEET 9000. 51 30 S & 0 E 100. 6586.50 538~.24~ 6492.50 3755.35 S 3890.23 9100. 52 0 S 6 0 E 100. 6648.40 5445.09 6554.40 3833.45 S 3898.44 ~--9~00.~ .......~o~ 4~ .......................... S 6 0 E ~ .......................... iQ0. ~709.4~ ...... ~01.4~~ ~ ........... 66I~.4~ ....... ~ 3~I~.~~"~'~ ....... S 3906'7I' 9300. 53 0 S 5 0 E 100. 6769.81 5557.64 6675.81 3991.59 S 3914.36 9400. 54 0 S 8 0 E 100. 6829.29 5615.29 6735.29 4071.45 S 3923.46 9450. 52 0 S 5 0 E 50. 6859.38 5643,93 6765,38 4111.12 S 3927.98 R C'L 0 S S [IISTANCE FEET U R E [~OGLEG DIRECTION SEVERITY D M DG/iOOFT E 5407.08 S 46 I E 4.28 E 5467,46 S 45 29 E 0.50 E '5528~-82 S 44 58 E '-0.75 E 5590.62 S 44 26 E 0.84 E 5654.22 S 43 56 E 2.61 E 5685.97 S 43 42 E 6./''~-' ;'ROdECTED--'TO -TO ..... 9570-7" SHOE ................................... 9570. 52 0 S 5 0 E 120. 69:33.26 5710.01 6839.26 4205.32 S ?625 MI:; IS PRO,]ECTED SURVEY STATION ;~625 MI:i-- TD ...... 9625. '52 0 S 5 ' 0 E 3936.22 E 5760.08 S 43 6 E: 0,00 5794.24 S 42 51E 0,00 ......... FINAL"CLOSURE - DIRECTION; ' S 42 DEGS 50-'MINS ~3 SECS E DISTANCEI 5794.24 FEET ......................................... AUG 2 0 Oil a Gas Cons. CommJs~.ior~ ARCO ALASKA, INC. F'AD~'~B~ ........ WEbL--NO: ...... 7-GHS JOB~'NO': .... A~781GO017 KUPARUK FIEL[~, NORTH SLOPE, AI.ASKA GMS, 0-9450 MD, SURVEYOR: MAX LUND RUN DATE{ 16-SEP-81 CAMERA NO; ~259, 1488 GYRO NO: ~06 90 DEG A/U NO; 1121 RIG; PARKER 141 .............. F'ORES~"GHT~: ..... WEST ~:AD B, WELL NO: 7 GMS JOB NO; A981G0017 TIME ~UPARUK-'-'FI'ELD', ...... NORT~H~-SLOPE, AL'ASKA ~ 13: 35:44 O&-APR-82 MARKER ....... TRUE SUBSEA .... ~-= .................. ~-~COD'~ .............................. MEASURED''VERTICAL-"MD~TVD-"VERTICAI~-'R E C'T A N G U L A R C L 0 S U R E VERTICA~ NAME DEPTH DEPTH DIFF DEF'TH C 0 0 R D I N A T E S DISTANCE DIRECTION THICKNESS FEET FEET FEEl' FEEl' FEET FEET D M TOF' EUF' SANDS 8530.00 6259.92 2270.1 61&5.92 3420.93 S 3844.57 E 5146.21 S 48 20 E TOF' UPPER SANDS 8578.00 6294.74 228~.~ 6200.74 ~45J.65 S 5849.1& E 5171.44 S 48 & El :~BASE"'"UPF~ER-?'SANDS 86'~?'~'00 ........ 6S'22~'85"22V4s'l ....... &228'~'85 ......... 3480'~'4'2"'~S-'3852~V3E 51V2~I4 .... S'47'"'54E TOF' LOWER SANDS 8880.00 6507.80 2372.2 6413.80 3665.53 S 3878.94 E 5336.8~ S 46 37 E BASE LOWER SANDS 8942.00 6548.84 259J.2 6454.84 ~711.59 S ~884.85 E 5572.89 S 46 18 E BASE KUF' SANDS 9024.00 6601 ~5 ~ 6 6507 55 ~774.10 S ~892.20 E 5421.5~ S 45 55 E PLUGBACK TD 947~.00 687~.54 2599.5 6779.54 4129.17 S ~92~.5& E 5700.1~ S 45 ~5 E !NE. IJL -NO:i . ? ' .: -, ARCO ' 'PAD .- "I4ELJL ;Ni 7.G~S. ;; ORT~~ SL OI ;'-T'T ...... ~000 l )000~ .... SECT IbN;- :-' 300 ~ . Suggested form to lx i~%serted in each "Active" well folder to check for timely compliance with our regulations. ' '' ~Operato'r~, W~ll Nam~ and Number Reports and Materials to be received by: /~ '~ ~ -- g / Date Required. Date Received Remarks Cc~pletion Report Yes Well History Yes _s~s ~- ?~ ;- ........ v ............. ...... ., ~r~ ............. ~s /Yo~e Core Description ' .. ............... ~ ' ....... , Inclination Survey ,/~.~ Directional Survey ~ .i~._ .~>~ Drill' Stem Test Repo~cs ~/O,*a ...... ,' '--'----'--'' _C .t:" .. -:'~T" ,, ..~ .... , ,,. .... ~":~ .... 3~] #e2 ,371~-~ z ~.¢..~. , ~s ,..~' . ';::' :~. :}7 Yes ~, , , ~ ~, .~,~ Thru: ALASKA OIL AND GAS CONSERVATION COMMISSION Hoyle H. Hamilton/q~ . Chairman ~ Commissioner Be~n LeNorman Petroleum Inspector September 9, 1981 Witness BOPE Tests on Arco's Kuparuk B-7, Sec. 9, TllN, R10E, UM Kup.a.r....~..... _.Ri.vet Undefined .saturday August_ 29 - I departed my home at 4:35 p.m. for a 5:05 p.m. showup and 6z45 p.m. departure via Wien Flight #7 for Deadhorse arriving via Fairbanks at 9:20 p.m. ~U....nday AUguS~_ 30 - BOPE tests on Sohio's G-17 completed, the subject of a separate report. ~on_day_ Angust~..3!- Standing by on Arco's Kuparuk B-7. Tuesday_ September_ 1 - BOPE tests on Arco's Kuparttk B-7 began at 4':30 a.m. and Were completed at 6~15 a.m. BOPE inspection report is attached. Inspection of strainers and attempted reprogra_mming of computer at Pump Station #1 completed, the subject of a separate report. I departed Deadhorse via Wien Flight #10 at 7:30 a.m. arriving in Anchorage at 9:00 p.m. and at my home at 9:30 p.m. Saturday September 3 - Joe McInnis advised the kelly co6k and 'ioWer~ keiiy ~alVe-s'- Were ~repaired and tested to 5,000 PSIG. In summary, I witnessed a successful BOPE test on Arco's Kuparuk B-7. BLN:gh OC~ #4 a/s1 STATE OF ALAStiA ALASKA OI a -CAS COHSERVATION CC6~CLSSION B .0. P.E. Inspoction Report Da t e SE ~ 777. /, 1 ~/ Operator /~/~ O~O Representative,, Well /~u ;~ ~ U/~_ __~- ~ Permit # Location: Sec ~ T//A/R/D~M L///~ ~~asing Set Pril ling Contractor ~~/<t=-~- Rig # / ~/ Representative Location, General_ . dD/~ Wel 1 Sign (D/~ Cenera 1 Housekeeping ~.~. ~eserve pit . ~_/~_. BOPE Stack Annular Preventer Pipe ~ams Blind Rams . Choke Line Valves__ H.C.'R. Valve Kill Line Valves Check Valve Test Pres sure ACCUMULATOR SYSTEM Ful 1 Charge Pres sure ~ c~ ~,~ ps ig Pressure After Closure ~ ~/~--d) psig Pump incr. clos. pres. 200 psig min~-~sec. Full Charge Pressure Attained: _ ~ min~sec. N2 :~ ~ ~--~/~ / ~'dD,. ~ ~ O o/ ~t 2 ~-psig Controls: Master ~D/~_ R...__e!~__t_e_ O.~.~B~_.i_n.d_.s~__..s~..itch cover Kelly and Floor Safety Valves Upper Kel 1y Test Pressure Lover Kelly Test Pressure Test Results: Failures., Repair or Replacement of failed equipment to be made within.., Inspector/Ccmmission office notified. Remarks: 7~'~- ~~ . . Ball Type_ ~/~ ,Test Pressure Inside BOP ~P/~- Test Pressure · Choke Manifold No. Valves ~ No. flanges o.~ <11:) Adjustable Chokes. / Hydrauically operated choke Test Pressure days and Distribution orig. - AO&~CC cc - Ope ~ator cc - Supervisor Inspector June 26, 1981 Mr. P. A. VanDusen District Drilling Engineer ARCO Alaska, Inc. P. O. Box 360 Anuhor age, Alaska 99510 Re~ Kuparuk 25648 B-7 ARCO Alaska, Inc. Permit No. 81-89 Sur. Lo¢.t 500'FNL, 262~FEL, Sec 9, Tll}~, R10E, U~ Bottomhole Loc.~ ?48~FSL, 622~FEL, Sec 10, TI~/{, R10E, UM Dear ~r. VanDusen ~ Enclosed is the approved application for permit to drill the above referenced well. Well samples and a mud log are not required. A d!rect~nal survey is re~uired. I~ available, a tape containing the digitized lo9 information ~hall be submitted on all logs for copying except experi~enta! logs, velocity surveys and dipmeter surveys. Many rivers in Alaska and their drainage systems have been classified as important for the spawning or migration of anadromous fish. Operations in these areas are subject to AS 16.50.870 and the regulations promulgated thereunder (Title 5, Alaska Administrative Code). Prior to commencing operations you may be contacted by the Habitat Coordinator's office, Department of Fish and Game. Pollution of any waters of the State is prohibited by AS 46, Chapter 3, Article 7 and the regulations promulgated thereunder (Title 18, Alaska Administrative Code, Chapter 70) and by the Federal Water Pollution Control Act, as amended. Prior to Mr. P. A. VanDusen Kuparuk 25648 B-7 -2- June 26, 1981 cc~mencing operations you may be contacted by a representative of the Department of Environmental Conservation. To aid us in scheduling field work, we would appreciate your notifying this office within 48 hours after the well is spudded. We would also like to be notified so that a repre- sentative of the co~mission may be present to witness testing of blowout preventer e~uipment before surface casing shoe is In the event of suspension or abandonment, please give this office adequate advance notification so that we may have a witness present. Very truly yours, Hamilton Chairman of Alaska Oi! & Gas Conservation Commission F~nc lo sure cc'~ Department of Fish & Game, Habitat Section w/o encl. Department of Environmenta! Conservation w/o/encl. ARCO Alaska, I~ Post Offic~ jo~ ,~60 Anchorage, Alaska 99510 Telephone 907 277 5637 June 16, 1981 Mr. Hoyl e Hamil ton State of Alaska Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Hamilton: ARCO Alaska, 'Inc. proposes to drill a development well, Kuparuk B-7, commencing on approximately July 28, 1981. Attached please find: 1. A "Permit to Drill" application form. e A plat showing a) surface and target locations, b) vertical d i recti onal. pl anning. 3, A plat showing the proposed wellbore in relation to other wells within 200' and other wells on B pad. 4. A plat showing conductor locations on B pad. Be e A determination of maximum pressure .to which BOPE could be subjected. Diagrams and operational procedures for the 20" 2000 psi diverter stack and 13-5/8" 5000 psi RSRRA stack. Please feel free to contact us at 263-4270 if we can be of any assistance. Sincerely, P. A. VanDusen District Drilling Engineer PAV/ELP:sp Attachments ARCO Alaska, Inc. is a Subsidiary of AIlanticRichfieldCompany STATE Of ALASKA ('~' ALASI~,' ~,.L AND GAS CONSERVATION~,~,,,MISSION PERMIT TO DRILL 20 AAC 25.005 la. Type of work. DRILL REDRILL DEEPEN lb. Type of well EXPLORATORY [] DEVELOPMENT OIL ]~] DEVELOPMENT GAS [] SERVICE [] STRATIGRAPHIC [] SINGLE ZONE](] MULTIPLE ZONE [] .~.. 2. Name of operator ..,..~:,! · ARCO Alaska, Inc. 3. Address P.O. Box 360, Anchorage, AK 99510 '::::: .'- 4. Location of well at surface 500' FNL, 262' FEL, Sec 9, TllN, R10E, UR At top of proposed producing interval 1320' F~]L, 1320' FEL, Sec lO, TllN, RIOE, UR At total depth 748' FSL, 622' FEL, Sec 10, TllN, RIOE, UM 5. Elevation in feet (indicate KB, DF etc.) I 6. Lease designation and serial no. 63' Tundra/71' Pad/98' RKBI ADL 25648 ALK 466 9. Unit or lease name .' Kuparuk ~r~Y~ 10. Well number ' -.: #B-7 11. Field and pool Kuparuk River Field Kuparuk River 0il Pool 12. Bond information (see 20 AAC 25.025) Type Statewide surety and/or numberFed Ins. Co #8088-26-27 Amount $500,000 13. Distance and direction from nearest town 14. Distance to ne.arest pr. operty or lease line NW of Deadhorse 30miles @ TD 622' 'eet 16. Proposed depth (MD & TVD) 17. Number of acres in lease 7129'TVD - 9844'MD feet 2560 20. Anticipated pressures KICK OFF POINT 500 feet. MAXIMUM HOLE ANGLF-47' 72 (see 20 AAC 25.035 (c) (2) 19. If deviated (see 20 AAC 25.050) 15. Distance to nearest drilling or completed wenl20' @ surface feet 18. Approximate spud date 7~/28/81 ~,UU psig@ 600 SurfaCe ~psig@ 6~(~ Jt. TD (TVD) SIZE Hole I Casing72" 24" /16" 13-3/4 [10-3/4 8-3/4/ 7" Grade Coupling Length ted Cel] ar H-40 ~elded 80' K-55 ~BTC 3261'! K-55 [BTC I 9844' Weight Corruga 65# 45.5# 26# 22. Describe proposed program: Proposed Casing, Liner and Cementing Program SETTING DEPTH M D TOP TV D Surface Sur.~ace Surface Surface M D BOTTOM TV D 5' !5' ~ 3261 ' 12700' 9844' 17129' QUANTITY OFCEMENT (include stage data) Backfilled 250 s.x Arcticset II 1350sx Fondu, 250sx lO00sx possible stage collar 500' aboveUqn~, ARCO Alaska, Inc. proposes to drill a Kuparuk River Field development well to 9844'MD = 7129'TVD. Selected intervals will be logged and tested. A 20" 2000 psi annular diverter will be installed on the 16" conductor while drilling the surface hole. A 13-5/8" 5000 psi RSRRA BOP stack will be installed on the 10-3/4" surface pipe and tested upon installation and weekly to 3000 psi. The well will be completed with 3½" 9.2# J-55 BTC tbg and pkr. Non-freezing fluids will be left in uncemented annuli thru the permafrost interval. Selected intervals will be perforated within the Kuparuk formation and reported on subsequent report. A downhole safety valve will be installed w/the com- pletion string and shut and tested upon conclusion of job. 23. I hereby certify that the foregoing is true and correct to the best of my knowledge SIGNED bel~o.wfo~r,Co~~:N~-~,~.V~'~i~'~--'~TlTLE Dist. Drlg. Engineer The space DATE CONDITIONS OF APPROVAL Samples required Mud log required Directional Survey required APl number ~YES [~f,N O []YES [~NO J~.ES []NO 50- ~,~_ ~ ~ (~ ;f l~ Permit number Approval date ~1- ~ ~ 06/26/81 SEE COVER LETTER FOR OTHER REQUIREMENTS APPROVED BNi/ ~~i1~¢ ~ ,COMMISSIONER DATE J~l.e 26, 1981 by order of the Commission Form 10~,01 Rev. 7-1-80 Submit in triplicate TMD~3:~60. i. 50 i. DEG!.4 ! TRRGET "TVD=6308 TI',ID=8624 iDEF reP :LONER .:SRNDS?-JYtVD=6543 TPID~,8973' hEP=5717 TM KLIP ~RNDS !TVD--6668 THD=9t59 DEP=SeSS': THD=9359 DEP=6003i: =5459 ~~_'~oo..:;';-~ ........... ~ ..... : .... ~-'"'---:--'~'~ ...... ~ .......... ~'": ,' ', ~ I - . ........ ~ ....... -~~--.~ ........;-I .......... ~ ~-~ "~'- "~-~-k .... ~.~. ~ ~ ~ ..... ~..~_.~_.?~ .... ~_~ .......... _~ ............ ~.+4..~ ..... ~..~.... .......... r ........ ~ .......... ~--, ....... .._r I : ~ ~ '. ...... ~_ .~ .:..~. ._~_~ ......... ~-~-~-~ ...... ~ ........... ~ .... ~--.~ ........... ~.~ ........ ~ ............... ~ ........ ~:-~ :~::~~I____~RCO_.~L~SK~_,~NC~:. ·, .......~~ .... ;~__~:-~_--'-.~.-~ ...... ~ ......... ~ .... -~---i- ~ ~ ~-~'-~'~ ............. 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L-~~L.-~nn .--.~-: --i ............ .~ ..... ~. ........ i~,.~__4. ...... :.. .......... ~-.:,. ...... ;,-i--~-.:-:-~-I~-.~--:- ,. ~;.-~~ -..~ .... ~ ......... :4. .......... ~-~-.~.:.~.-.~ ........ ....... i--,--- ~-~--~-.-:- ~ ........ _._:.. ~ ........... ,~'+" ..... ...... ......... ~ ........... ~ ........... ~ ............... ~ ........... , ..... ~.~-~ ...........~---~ ...... ~ ...... - ....1 .........~- ....... ~'-~ ...... ~ ..... ~-+-~- ~-~ ..... : ...... ~ ~ ...... ~ .......... >--I ....... ~ ...... ~ .......... ~--~-~ ....... ~--~ ......... e--~-, + .... ~..~-..-i .............. ~ ..... ~ ...... ~ ......... t .... ~ ...... ,-:-:' ~-?-'t ..... ~' h'~-"-~ ....... ~_~_..~....:....~ .... ~ ........... ~ ...... L . ........ ~ ........ ~-~-.' .......~ ......... ~...~ ............ ~ ......... --~-~-~.../..- ~ ..... ~.4..-~--~-? ~-.-.~ ....... ~ ......... ~--~--~- .~-~- .... ~ ..... ~_ ~ ~_,.~._~_~_~.c..~ ...... :.-.~:..~-~-.:...I-~-~-----~---(--z ....... ~ ...... ~ ............ ~W~--~.--;,-~.~-~+.--~.-~--+,~-~.~-e~:.--,--. ............. ~-?-.9 .............. ~-.-~ ......... ,-~'--~ ..... - ....... ~ ........ ,-'~ ~ : .............. ~ ,'~. ~-'~ ?~,~ - , ~ ,~ : ~ · ........... ~-- ~ ......... ~ .............. ~ .................. ~ ........ t ............... + ..... ~ .......... ~- i~11 .............. ~"~-~- '~ ....... ~-~"'~-h'~-'~'-~ ..... ~ ....~-~'~ .... . ~ f : : , . . ~ . . ~ ' , , ~ , .. , , ~ '. '..~ ..... ~..~ ........~ ................... --.~..Z..i..:..~..--~..~-4--.r~- ' i ... ........... ~.~._9_ _~.._. ......... ~ .............. ~ ......... :_.~ .............. ~ ..... : .... ._~ ................. } ......... ~.4..-~-:..4....~... i .............. ~- ....... ~'-- l-il A A '3 WELL -:'1 Y : X = LAT = LONG OC ~,L_F. -. i": %00' 5,969,646o72 WELL ~'7 Y = 5,969,6~7o3l 549,457 40 X = 550 1 o ~ ?0°~:40o2~0'' LAT = ?O°~9~O.Z~ ~9°35~8o0S~'' LON~ ~ i WELL :":2 Y = 5,969,647.44 X : ', 549,577o73 LAT = 70°19~4Oo2q0'' LONG 149°35~c ' --- .,2.543' WELL -'-'8 Y : 5,969,646°98 X :. 550,297°7':3 LAT = 7OO19:40,237', LONG = 14a° ~ 35'31 o522" WELL ~3 Y : 5,963.646,.89 X = 549,697.~7 LAT -- 70°19'4Oo276'' LONG = 149°35'49.,O48'' WELL -~4 Y = 5,q69,647~3I X = 549,~17o62 LAT = 70°1j:4Oo272'' LONG = 149°3~'45~539'' WELL ~5 Y ~ 5,969,647°24 X : 54~,737o6~ LAT = 7001q'40,263'' LONG = 14735~42.O3['' WELL ?-6 Y : 5,']6.. ~,647'o3S X --- SSO,OS7.~5 LAT : 70° 1 ] ~ 40~ 25.-S'' tn.;,,-,: 14'10'~.-.,~8 .q',-:,, D.O. D, WELL6 1--8 ! HEREBY CERTIFY THAT ! AM '-- "' PROPERLY REGISTERED Al'ID LICENSED TO PRACTICE LAND SURVEYING IN THE STATE OF ALAS~ AND TttAT THIS PLAT REPRESENTS AND AS- BUILT SURVEY MADE BY ME, A:ND THAT ALL DIHENSIONS AND OTHER DETAILS ARE CORRECT, AS. 0,~: ~ ~ ,. ~., · DATE t/7/~'-O -'" .... :, ./...' .":. · ,~. · .,,-' ...,_. '.;:' . ..,:..'. iZ ~ .. ::'b.S".' ~ .': ~"?:~!::~i'~::?~ '-.-- . ' ~:: ' - .:: · el, - .,%: - --1 , I I I I I , I I Ill I I II LOCATIOk AS- 5UILT ........... ..... i .... AtlanticR'ichfieldCompany i ATE: DRAWING No- i I ;...,.,....;.-,,..-::., NORTH AMERICAN PRODUCING DIVISION 1 ALASKA DISTRICT-- KUPARUK . , " ANTICIPATED PRESSURES Expected reservoir pressure in the Kuparuk interval has been determined to be 3208 psig from RFT & pressure buildup date. This pressure @ 6210' SS = 6308' TVD will be balanced by 9.8 ppg mud wt. Normal drilling practice calls for a 10.4 ppg wt prior to penetration and during drilling of the Upper Kuparuk and remaining intervals. This will result in a 200 psi over- balance. It is anticipated the surface BOPE equipment could be subjected to a max- imum of 2688 psi during drilling operations. Derivation assumes a gas kick at'reservoir temperature and pressure (160°F, 3208 psi), gas migration to the surface w/o expansion, and cooling to 60°F summer cellar temperature, This is well below the 5000 psi BOPE working pressure and less than the 3000 psi weekly test pressure. Pi = pressure initial (reservoir) Ti = temperature initial (reservoir) Vi = volume initial (reservoir) PiVi = ,PfVf Ti Tf Pf = pressure final (surface) ~ temperature final (surface) volume final (surface) Since Vi = Vf ie no expansion Pi = Pf T i T-~ Then Pf = Pi Tf = (,3223 ps ia)(.60°F + 460.) Ti (160OF + 460) Pf = 2703 psia = 2688 psig Sur=ace gi';erter ~','s',~..-.. 1. t'6" Bra~enhe~_d. 2. 16" x 20"~C,S psi dcu~i:_ ~_',::aC.~ ar.~-~r._ ~_ 3. 20" ~nns psi drilling s~:s: ',.;/iS" side out~e~s 4. 10" ball valves, hyrauiicaiiy ~_~t'~a~ed, w/lO" lines ta reserve ~it. Val';es '~ open au~.,-.ati- cally u~on closure of annular ~reven~er. 5. 20" 20~0 psi annular preven=.er. 6. 20" bell nipple. 3. Close annular preventer in the event that gas or fluid flow to surface is "detected. If necessary, manUally over- ride and close ball valve to upwind diverter line..~.D__9_o not shut .in well under any, circumstances. 16" Conductor i PR--'.,.'=_:iTCR ) 5 ( [ ) I TBG HD 3 · 1. '-15" 2. lc .~3 FS~ x I0" 2C23 3. lO" .S(]~,~,~.~ ,°q;~. ~"bin~~u hea~ lO" 3n~ PS! x 13 adaz;er spool 5. l~-~/S''. 5000 ,~T i~.- 6. 1~ -'~'' ~-~zo 5GOO PS an~ kill i i 7. 13-5/8" 5000 PSi pi~=~- rams 8. 13-5/8" 5000 PSi blind rams 9. 13-5/8" 5000 PSi annular w/ch='4a 1. CHECK A:;D FILL~CC~.'~U~,~.~" .......... RESE?.':OiR ~0 ?ROFER LEVEL WiT:q HYDRAULIC FLU['3. 2. ASSURE THAT ACCU~ULATGR PRESSURE [S ~GCS PSI ~iT:q 1 500 PSI DOS;NSTR[AN OF THE REGULATOR. 3. OBSERVE TiHE THEN CLOSE ALL UNITS Si?.ULTAN~- OUSLY AND RECORD THE TIME AND PRESSURE INS AFTER, ALL UN[TS ARE C~S:D ~IITH CHARS~,,: PU;? OFF. 4. RECORD ON IADC REPORT. THE ACCE~TASLE LiMiT IS 45 SECONDS CLOSI~;G TIHE AND 12CO PSI RD,~,,I,,~ PRESSURE. 13-5/2" BOP STACK TEST ,.IMI ,~l 1. FiLL BOP STACK A;ID'' IFu_D WITH ARCTIC DIESEL. 2. CHECK THAT ALL HOLD DO',iN SCREWS ARE FULLY RE- TRACTED. PREDETEF, J.IINE DEPTH THAT TEST PLUG ~,-L~n:,~.D. RUN I~t LOC:< WiLL SEAT A~;D SEAT IN ' DOWN SCR2~,iS IN HEAD. 3. CLOSE A~;NUL~R PREVENTER AND CHOKES AND BYPg~S VALVES ON ~hlFOLD. . 4. TEST ~LL CCHPONENTS TO 250 PSi AND HOLD FOR ]0 HI~;UTES. 5. I~[CREASE PRESSURE TO 1800 PSI AND HOLD FC] lO NIT,UTES. BLEED TO ZERO PSI 6. OPEN AN~iULAR PREVENTER A~;D CLOSE TOP ~ET OF .~. 7 I,,~.:.~b~ PRESSURE TO 3000 PSI AND HOL~':~.~:R,~ lO 8. CLOSE VALVES DIRECTLY UPST~E~'.I OF CHO:<ES .... BLEED COW~ISTRE~.I PRESSURE TO ZERO PSI TO TEST?]' . ,,,' VALVES TEST RD1AINI~G UNTESTED ,...~,tlFCLD W.L','ES, tF ANY, HITH 3080 PSI UPSTRE~?.I C.F VF"~E AND Z[~O PSI DO~;;STREJR'I. SLEED SYSTEH TO ZERO PSI. 9. OPE:i TOP SET OF PIPE ~/.IS AND CLOSE SET OF PIPE ~S. 10. I;;CREASE FRESSURE TO 30C0 PSI AND HOLD FOR lO lqI:;UTES. BLEED TO ZERO PSI. 11. OPEN BOTTC:.I SET OF PIPE R,::.IS. ~ACK OFF RUN- NI:iS dO!TIT MID PULL OUT OF HOLE. CLOSE SLiND P~;;S AND TEST TO 3000 PSI FOR lO ;IiNUTES. BREED TO ZERO PSI. r ~ .... 12. OPEN BLI:;3 2,t:.~S AND R,C~.',-, TEST PLUG. SU.-qE :'!;,:IIFOLD A:iD LINES ARE FULL OF ARCTIC DIESEL AND ALL VALVES ARE SET IN C,qiLLiNS POS ! T I 13. TEST STA:JSP!PE VALVES TO :.COO PS!. 14. TEST KELLY CCC::S ;,.;;D I:;S::E -COP TO SC, CO PSI ',,'Ii,-.i KCC:t£Y PUHP. 15. "'" ..... =, ,"' IEST FC, T2! SIGN AND SE;;g TO C,~:LL::,S S'JP:..".- 16. FE.=,FC.--:I C~'IPLETE -COPE TEST O.',CE A '~EEK FC:;CTIGt;;LL'! CPERATE B,SPE CALL'/. CHECK LIST FOR NEW WELL PERMITS ITEM APPROVE DATE (2) Loc i?thr~ 8) (3) Admin ~f~- ~"L-f~1 (9~ thru 11) (4) ,Casg~J~Z~? (~ thru 20) (5) ,. BOPE (21 thru '24) me 3. 4. 5. 6. 7. 8. e 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. Company Lease & Well No. Is the permit fee attached ......................................... Is well to be located in a defined pool .................... Is well located proper distance from property line · Is well located proper distance from other wells Is sufficient undedicated acreage available in this pool Is well to be deviated and is well bore plat included ............... Is operator the only affected party ................................. Can permit be approved before ten-day wait .......................... Does operator have a bond in force .................................. Is a conservation order needed ...................................... Is administrative approval needed ................................... NO string provided ....................................... ~ Is conductor Is enough cement used to circulate on conductor and surface ...... Will cement tie in surface and intermediate or production strings Will cement cover all known productive horizons .................. 'Will surface casing protect fresh water zones .................... Will all casing give adequate safety in collapse, tension and burs Is this well to be kicked off from an existing wellbore .......... Is old wellbore abandonment procedure included on 10-403 ......... Is adequate well bore separation proposed ...................... ~ Is a diverter system required ..................... Are necessary diagrams of diverter and BOP equipment~p.~~psattached .. .~ ~. Does BOpE have sUfficient pressure rating - Test to . ' !~ Does the choke manifold comply w/API RP-53 (Feb.78),..--.--..- · g . · Additional requirements ............................................ Additional Remarks: REMARKS Geology: Engineering: HWK__ LCS BEW__ WVA JKT~RAD JALT~4~-- rev: 03/10/81 INITIAL I GEO. UNIT ' ON/OFF POOL CLASS STATUSi AREA NO. SHORE Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information, information, of this nature is accumulated at the end of the file under APPENDIX. .. No 'special'effort has been made to chronologically organize this category of informatiOn, .o VERIFICATION'~IS~ING LVP O09.HU5 VERIFICATION LISTING PAGE ** REEL HEADER SERVICE NAME :SERVIC DATE :SZ/U1/24 ' ORIGIN : REEL NAME :REEb ID CONTINUATION # PREVIOUS REEL COMMENTS :REEL COMMEN~S - ** TAPE HEADER SERVICE NAME :SERVIC DATE {82/U1/24 ORIGIN :F$1A TAPE NAME CONTINUATION # {01 PREVIOUS TAPE' COMMENTS {TAPE COMMENTS _ - ** f'ILg HEADER ** FIbE NAME {SERVIC,O01 SERVICE' NAM~ I ' VERSION #~ I ' DATE I - MAXIMUM LENGTH : 1024 FILE TYPE : - PREVIOUS FILE { INFORMATION RECORDS MNEM CONTENTS CN { WN : FN : RANG{ TOWN{ SECT: COUN:. STAT: CTR¥: MNEM ATLANTIC RICHFIELD KUPARUK KUPARUK IOE 9,- NORTH SLOPE ALASKA USA- CONTENT~ PRES: NED~T4E .. -- RECORD TYPE 047 ** UNI~ TYPE CATE SIZE CODE 000 000 018 065 000 000 0~2 065 000 000 00~ 065 000 000 OOJ 065 000 000 003 065 000 000 00~ 065 000 000 012 065 000 000 006 065 000 000 00~ 065 UNIT TYPE CAT~ $~Z~ CODE 000 000 007 06b bYP 009,HO5 YER~F~CATION LISTING **~ RECORD TYPE 047 ~* RECORD TYPE 047 ~* ** COMMENTS ** JOB # 10707,62161 DIb RUN #1, bOGGED BUTTOM LOG ~NTERVAb :, 9234 FT, TOP LUG-INTERVAb m~ 2841 FT, CASING'LOGGER =,284i BIT"S~ZE - = 8'75 IN. TYPE HOLE F&UID =~ XC'POLYMER DENSITY .... = 10.2 VISCOSITY =,42 P,-- · =~9.0 FLUID LOSS = 7'5 RM "~@ MEAM. TEMP. = 3.1 ,~' 71F RMC ~ SEAS. TEMP. = 3'75 @ 71F R~ @ OHT*~ = 1.389 ~ I67 F MATRIX SANDSTONE ************************************************ PAGE LVP O09,HO5 VERIF!CA?ION bIS?ING PAGE DATA FORMAT RECORD ENTRY BLOCKS DATUM SPECIFICATION BL MNEM SERVICE SERVICE IbM GR NPHI NUC RHOB NUC DRHO NUC NRAT NUC FCNb NUC NCNb NUC CAbI NUC GR "~ FDN E SIZh 9 0 1 OC UN OM OH Off US PU G! G/ KS IT APl APl bOG TYPE MM MM /r · ¢3 C3 0 0 0 0 0 7 0 0 0 0 0 0 0 0 42 IN GAP1 DEPT OP RHOB NCNb DEPT OP RHO~ NCNb DEPT SP RHOS NCNb SP RHOB NCNb ~. DEPT SP RHOB NCNb 9279,500 ''9.570 '99~.250 -~99.250 O0,OOO 9~14.219 "999,250 '~99,250 9100.000 '12.703 2.2B~ 2007.000 9000,000 '17,b41 2.297 2~22.00~ 8900,000 '20,18~ 2,~49 2272,000 SFLU GR - DRHO CAbZ srbu DRHO CALZ SFLU GR - DRHO CALI SFLU OR - DRHO CALl SFbU DRHO CAb~ REPR . _ CODE 66- 65 66 ENTRY 60 ,lIN 0 AP1 APl FILE SIZE PROCESS CLASS MOD NO, -' LEVEL 0 0 0 -0 4 ~-0 0 0 0 0 4 0 12 46 0 0 4 0 0 0 0 0 4 0 I 0 0 0 4 0 31 32 0 0 4 0 52 32 0 0 4 0 68 2 0 0 4 0 35 I 0 0 4 0 44 0 0 0 4 0 42 I 0 0 4 0 34 93 0 0 4 0 34 92 0 0 4 0 28 3 0 0 4 0 31 32 0 0 4 0 ~ - . 3,111 ILD 90.500 DT -999,250 NRAT -999,250 GR 3.127 ILD B3.938 DT -999.250 NRAT -999.250 GR 2,541 ILD 94,250 DT 0,069 NRAT 9.906 OR 3,498 ILD 78,625 DT 0,I18 NRAT 9.320 GR 3.b50 IbD 88.250 DT 0.196 NRAT 9.125 GR 3 000 94 ~88 -999 250 -999,250 064 1:7 o -999.250 -999.250 2.447 9~.75 9~,312 3,668 95.563 4,457 8~,375 3,164 76.063 NPHI FCNb NPHI NPH! FCNb FCNL -- ., IbM NPH! FUNk SAMPLE REPR CODE 68 ~8 68 68 ~ . 2.938 '999.250 '999,250 3,258 '999.250 -999,250 2 561 47168 ~O0!O00 3.813 37.500 b70,500 4,22J 36,52~ 682.500 bVP 009,H05 VERIFICATION bISTfNG DEPT 8800,000 SFbU SP -20,203 GE - RHOB 2,400 DRHO NCNb 2676,000 CAb/ DEPT 8700.000 $FbU SP '24'344 GR - RHOB 2'533 DRHO NCNb 2594,000 DEPT 8600.000 SP -50,000 NCNb 3! ,000 CAb/ DEPT 8SO0,.O00 5FbU RHOB 2.219 DRHD NCNb 1943.000 CAbI DEPT 8400.000 SFGU $P - '14,328 GR- RHOB 2,305 DEHO NCNb ~767,000 DEPT 8~00,000 $FbU SP ~i9,06~ GE RHOB 2,256 DRHO NCNb 1805'000 CAbI DEPT 8200,000 SFbU SP," ~-7,254 GR RHOB 2,168 DEMO NCNb 2046,000 CAbI 0 000 SFbU Sp · RHOB 2'~68 DRHO NCNb i~37'000 CAbI DEPT 8000,000 $FbU SP -II'156 GR RHOB 2'250 DRHO NCNb 2120.000 CAb/ DEPT 79~0,000 SFbU RHOB 2.23U DRHO NCNb 2292~000 D~PT 7~00,000 5rbU SP RHOB 2'17~ DRHO 5.105 6~'250 .071 9.391 · 5.699 57.094 ~0.097 9.539 11.672 46.250 0.125 9.055 763 ~ 0.047 10.070 2.412 102,375 0.105 9.828 -- . 2 951 172~375 0,074 9,703 1.782 196.875 0.0 i 9~2~4 ~ .. 2.891 157.750 ~-0 025 9:875 3,244 105.125 -0.006 9.992 4 -0.001 10,344 . . · 0'010 DT NRAT GR. DT NEAT NEAT GR NRA~ G~ ' IbD DT NEAT GE GR DT NEAT GR ' !LO DT NEAT GR NRAT 4,746 91,375 .000 56.906 8,000 90'000 2,715 43.2119 1,6<88 110.375 * 3.699 111.312 1.803 101"000 3,588 99.312 . - 2,396 . 3,750 11~.752 167.500 1.776 112.563 - 3.525 179.250 ,518 I2 ' 3,572 139.000 2.674 108'000 ' 3.428 100,312 3,361 105.563 ' 3.389 99.125 2,736 116.0!00 ' 3,990 NPH/ FCNb NPHI FCNb IbM NPHZ FCNb NPH/ IbM NPHI FCNU IbM NPHI FCNU NPHI FCNb NPHI FCN~ NPHI FCNb NPHI FCNb -- NPHI FCNb PAGE 4.941 31.~38 862.500 5,47~ 32.~20 ~43. O0 9,600 28"955 1094,000 .782 4 ,727 542.000 1.940 492. 0 2,539 46.240 487.500 1.803 41.50~ 576.500 2.646 42.773 501.000 2.742 39.990 576,500 _ 985 b89.500 ~_ 2,080 50,899 488,250 ~ - LVP O09,Hob VERIFICATION bISTING PAGE 5 ~o NCNb 1934,000 Ckbf DEPT 7700,U00 SfbU SP ' 8,930 GR RHOB 2.I?~ D~HO NCNb 225b,000 CAbi DEPT 7~00 O0O SrbU SP -22~40b GR .... RHOB 2.217 DRHO NCNb 1953.000 CALl DEPT 7500,000 SrbU SP *16,453 GR - RHOB 2,37~ DRHO NCNb 2168,000 Ckbi DEPT 7400,000 SFLU SP ~14.b80 GR RHOB 2.36b DRHO NCNb 2304,000 CAb! O0 SFbU SP - 8, 1 " RHOB 2 352 DRHQ NCNb 2550:000 CAbI .. DEPT 7~00,000 5FbU SP 11,629 OR RHOB 2,434 DRHO NCNb 2970,000 CAbl DEPT 7i00.000 SFbU SP '=4,008 GR - RHOB 2.3~7 DRHO NCNb 2660,0 0 CAb/ DEPT 7000,000 srbu SP -' =9,961 GR ' RHOB 2,Jl1 DRHO NCNb 2158.000 CAb~ DEPT 6900.00~ SFbU SP ' '11,08b GR ' RHOB 2,338 DRHO NCNb 226B,000 CAbl DEPT 6~00.000 SrbU SP --8,b9~ GR - RHOB 2,41~ DRHO NCNb 2396.000 CAbZ DEPT 6700,000 SFbU SP '=e,00~ GR "' 1, 114. 9, 3, 136. 0 165, lO, 4, 192, O, 8 2, 137. Oe 10. 3. 160, 2, 102. O, 2. 135. 484 375 125 OX OO2 000 3?$ OO7 320 ~ . OO2 836 018 012 889 ?5O 00~ ~02 OO8 '/77 00~ ?66 012 8?$ GR D~ NRAT GR D~ NRAT GR ibD NRAT GR D~ NRAT GR NRA~ GE ' ZbD NRAT GR" DT NRAT GR IbD DT NRAT NRAT OR DT NRAT GR DT 105,000 1,677 108,375 - 4,063 111,938 3,123 118,188 3,725 116.938 3,539 9b.375 1 ,500 3,279 141,875 3 213 95~.186 3,041 151,375 3 58 5,945 83,000 3'096 131,000 2.840 119,688 3,664 ~04,750 3,326 148,250 2,900 106,563 3,244 94,188 2,275 114,188 NPHi FCN~ _ - NPH~ FCNU -- -. NPH! FCNb NPHI FCN~ NPHI FCNb ~ _. IbM NPHI FCNb NPHI FCNb NPHI FCN~ NPHI FCNb IbM NPH! FCN~ NPH~ I 876 48i096 596 500 944'900 3.570 -- 3,979 b93,UO0 2 951 32i666 805 900 3~ .936 ,-~3~ 761'500 5,145 34.424 822"§00 2.832 42 383 3 b39 38!721 634 900 2,973 35.156 753,500 2,293 47.363 bVP 009.H05 VERIFICATION ~ISTING NCNb 2014,000 CALl DEP~ 6000,000 SFEU SP " -=2,027 GR RHO~ 2.31Z DRHO NCNb 2404,000 CAbZ DEPT 6600,000 SrbU SP .... =2,71J GR DEP~ 6400,000 $FbU $P - --0,741 OR - RHOB 2,289 DRHU NCNb 2J52,000 CAb2 0,000 $FLU DEPT 6~4,379 GR RHOB 2,256 DRHO NCNb 2452,000 CAbI DEPT 6ZO0,O00 SFLU SP '- ' 0,046 GR - RHOB 2,310 DRHO NCNb 2248,000 CAbI DEPT 6100,000 $FbU SP 3,055 GR - RHOB 2.254 DRHO NCNb 2412,000 CAbi DEPT booo,ooo srbu sp · =1,U40 GR - R~O~ 2 264 DRHO NCNb 2414~000 CAbI DEP~ 5~00,000 SrbU SP "-4,758 GR RHOB 2,289 DRHO NCNb 2626,000 CALZ DEPT 5~00,000 SFLU $P .... '4,~8~ OR - RHOB 2,258 DRHO NCNb 2184,000 CAb2 DEP~ 5700,000 $FLU SP --8,26b GE RHOB 2,~22 DRHO NCNb 2X98,000 CAL~ D~PT 5000,000 SFbU 0,020 11,688 _ _ 2,699 62 219 0~040 10,852 1.882 79.312 2,498 92,250 0 78 2.645 93.500 0 004 10~836 2.779 10~,063 '028 10,898 2 021 0 008 10~96I 4,027 77,063 0,002 11,078 4,695 72,813 '0,003 11,203 3,412 79,813 0,012 11,891 3,012 84.625 i~ ,010 ,789 3,141 NRA~ GR D~ NRA~ GR D~ NRA~ GR D~ NRAT OR ~LD O~ NRA~ GR ZbD D~ NRA~ GR D~ NRAT GR DT NRA~ GR D~ NRA~ GR iLO D~ NRA~ GR lbO - NRA~ 3,922 130,375 2,945 99,7150 -3,408 54'469 2,094 112,563 ' 3'563 78'250 · 0 ' 3,652 7~,875 2,8i91 107'563 - 3'582 85,875 9 875 3,393 20~,375 - ~,~I9 81'000 3,912 10~,000 ' 3,164 83,563 4,969 97'750 3'307 64,438 3,250 1.1~,i88 --3.529 68'188 ~.338 115,000 ~ 189 ~,844 FCNb NPHI FCN~ NPHI NPH~ FCNb NPHI FCN~ NPHZ FCNb NPHZ FCNb NPHI FCN~ NPHI FCNb NPHI FCNb NPHZ FCN~ PAGE 517,500 ~ 3,01~ 38,52~ 687,000 2,092 37,939 589,000 2,684 42,822 666,~00 2 ~04 41~50 622.500 3.166 37,402 725,000 3.334 35,400 720,000 3,857 34.033 732'500 5.00B 36,52~ 759,000 3.23U 40,234 e43,500 3,322 33,203 707.500 3,639 LiSTiNG PAGE 7 .. NCNb · DEP~ SP RHOB NCNb . DEPT RHOB NCNb .. . DEP~ RHOB NCNb DEPT BP NCNb _ DEPT SP RHO~ NCNb .... DEPT SP RH00 NCNb DEPT SP RHOB NCNb · DEPT $P RHO~ NCNb - DEPT $P RHOM NCNb DEPT SP RHOB NCNb -8,82U 2.275 DRHO 2284,000 CAbI . 5bO0,O00 SFbU ''8,109 GR 2,281 DRHO 2212.000 CAbZ 5400,000 SFbU ''6,570 GR - 2,254 ORHO 2156,000 CAbI 5~oo,ooo srbu '=5,25~ GR 2,lie DRHO 2222,000 CAbl 5gO0,O00 SFbU "10,85~ GR - 2,Z3~ 2574,000 CAbZ .... 5100,000 SFbU '"5,~67 GR - 2,Z46 DRHO 2052,000 CAb~ .. 5000,000 SFbU '8,88~ GR 2,$0~ DRHO 2942,000 CALl 4~00,000 ~9,094 GR 2.180 DRHO 2b04.000 CAbI 4800.000 '19,531 GR 2,296 DRHO 21~2,000 CAb~ 4700,000 $FbU '~9.672 GR - 2,230 DRHO 2306,000 CALl 4600,000 $gbU ~46,781 GR - 2 ~70 DRHO 2406:000 CAbI ...... 98, O, 12, 95, O, 12, 3, -0 2, 66, O, b, 77, O, 2, 65, O, 5, 66, O, 5, 65, O, 11, 5, 72, O, 6, 75, O, 10, 59, '"'0, 9, 563 007 641 895 938 026. 695 039 750 004 984 432 688 037 .1.02 949 688 0~0 875 859 375 016 695 145 625 0~! 086 1.95 813 019 523 129 688 028 609 .._ 098 625 013 992 258 594 009 508 .. DT NRAT GR D~ NRAT GR NRAT GR DT NRA~ G~ lbo NRAT GR DT NRAT GR O~ NRA~ GR NRA; G~ DT NRA~ GR D; NRA; GR DT NRA~ GR I12.750 5,199 113,375 ' 3,375 8&,312 3 586 - ,832 94,375 4,023 10~'188 " ,51~ 59,500 7,305 113,188 ~ 334 75~250 3 416 117:750 - 3,504 60,594 6,152 g7,750 3,037 55.500 5,766 117 50 61,438 ._ 5,664 1-17~000 3,529 70,375 7 O82 1201000 3,652 66,438 7 ~23:750 3,363 47,031 NPH! FCN~ FCNb NPMZ rcN~ NPHI NPHZ rCNb NPHZ FCNb _ NeHZ FCNb NPHI FCNb NPHI ._ NPHI FCNb NPHI FCNb _ 37.305 630*~00 5,145 38,~70 649, O0 3 47i 45:605 569.500 · 626.000 687,000 3 342 39!355 551 000 980,500 6,445 40,283 731,500 ._ 6,965 42,,I39 584.500 LVP 009.HO5 . VEEIF!CATION DEPT SP NCNb DEP~ Sp RHOB NCNb DEPT SP RHOB NCNb DEPT SP RHO~ NCNb DEPT SP R~OB NCNb DEPT SP RHOB NCNb DEPT SP RHOB NCNb DEPT SP RHOB NCNb DEPT SP RHO~ NCNb -- . DEPT SP · RHOB NCNb D~PT SP RHOB NCNb 4500.000 SFbU -47.b25 GR - 2,X62 DRHO 2432.000 CAbI 4600.000 SrbU -17.281 GR 2,326 DRHO 2312.000 CAbZ 4~00 000 SFhU 2o: oo 2'268 DEMO 1956.000 CAb% 4200.000 SFLU -21,57~ GR 2.197 DRHO 2124.000 CAL~ 4100,000 SFLU '12,359 GR 2,24S DEHO 203~'000 CAbi 4000.000 SFbU -25.46~ GR '- 2.268 DEHO 2b06,000 CABS. 3900.000 SFLU -40.b88 GE 2,UOa DRHU 2472,000 CAb~ 3~00,000 SFLU "25,734 GR .... 2.205 DRHO 2465,000 CALI 3700,000 SFbU '29,766 GR 2,19~ DRHO 2584,000 CAb! 3~00 000 SFLU '37:43B GR 2,080 DRHO 2544,000 CAL~ 3~00.000 srbu '21,828 GR 2,~72 DRHO 222~,000 CAL~ blSTING 11.430 49.563 '0 028 . . . 6.422 77 750 0:057 17,625 5 39 0,026 i~,523 6.746 57.375 -0.010 10'820 · 5,219 66,500 -0,007 11,828 9.953 7~438 '0,006 9,891 . 9,672 33.906 9,938 54,438 -0.01i 9.797 !1,000 50 625 -0:009 9.156 12.359 ~2 688 9,078 9,563 53,78~ -0'004 9,539 DT NRAT GR DT NRAT GR DT OR DT NRAT GR DT NRAT GE NRAT GE DT NRAT DT NRAT GR DT NRAT GR NRAT GR D~ NRAT GR 12,484 113'375 ' ,393 7,891 11~,750 '73 754 5:063. b 957 124:750 ''3,574 58'I88 129,3~5 -' 3'5 8 57,969 59'9~0 10.563 115,000 ' 3.396 68,938 10,523 ~40.0~0 10,219 123,.188 ' 3'342 48'469 ~ - 10,992 114,188 3.406 40,78I 10'906 138,12~ -'3,49 4~,J75 10,250 129,000 '~' 3,438 55.406 IbM NPHI FCNb NPHI FCNb NPHI FCNb -- NPHI FCNh NPHI FCNb NPMI FCNb NPHI FCN~ FCNb NPH! FCNb NPHI FCN~ NPHi FCNb PAGE 12.219 37.598 717.500 7.363 4t.553 617,500 .- b.74b 42'529 544:~00 6.941 43'701 577,500 6,414 47.461 b05,500 10,469 39,600 732,000 11.055 41,309 685.500 10,30b 39.941 b99,500 11.312 40.820 707.000 11.242 42.529 b92,000 I0.O7~ 40,86~ b34.~00 LVP O09,HU5 VERIFI,~ATION blBTING DEPT 3400.00U SFbU BP ~'b.88J RHO~ NCNb 2062,000 CAb/ ., DEPT 3jO0,O00 Sp --4,320 GR ' RHOB 2,I43 DRHO NCNb 2018,000 D~PT 3200.OOU BFbU BP RHO~ 2.I62 DRHO NCNb 1938,000 CAb! DEPT 3100,000 SFbU SP RHOB 2,21! DRHO NCNb 1911,000 DEPT 3000,000 BFLU BP -15,969 GR - RHOB 1,985 DRHO NCNb 218b,000 CALL DEPT 2900,000 BFbU BP -27,891 GR - RHOB 2'061 DRHO NCNb 1957,000 CALl DEPT 2813,000 BFLU SP -~9~.250 GR - RHOB - 2,051 DRHO NCNb 1412,000 CAb2 *~ FlUE TRAILER FILE NAME' :BERVIC,O01 SERVICE NAME ~ - VERSION #' I - DATE ~ - MAXIMUM LENGTH I 1024 FlUE TYPE : NEXT FIbE NAME · . . DATE :SZ ORIGIN IFB1A TAPE NAME' {BERVIC 7.523 063 DT 10,695 GR · , 4 14 IUD -0.006 NRAT 10.594 GR 5.551 76,438 DT -0.002 NRAT 11.938 GR 11.234 ILD 44,094 DT -0.005 NRAT 11,875 GR -- 9.266 49.813 DT' -0,02! NRAT 10.836. GR 6,418 IUD~ 55.156 D~ -0.013' NRAT 15'859 GR -999,250 -999,250 DX -0,507 NRA~ 10,023 GR .. 9,~89 50 988 70:375 &,934 149-.500 4,109 69,813 -- 13~,000 3,939 75,688 10,~77 151,000 - ~,893 4 ,875 10 352 ~' 3,96i 50,188 7 516 135:375 '54,~71 B,BLb =999, - &,355 40,844 IbM NPHI FCNb IbM NPHI FCNb IbM NPHI FCNb IbM NPHI FCNU IbM NPH! FCNb IbM NPHI FCNb FCNb PAGE 4~:445 507'250 6,105 5I-,~67 473,$0~ -- b 12b 47:852 497,25~ 9,594 43 555 488:250 9,883 48,48e b69'500 6,875 53,467 421,750 -- - -999,g5~.0 a126,000 LVP 009,H05 VERIFICATION LISTING PAGE CONTINUATION # :01 NEXT TAPE'NAME : A COMMENTS ~TAPE COMMENTS ** REEL TRAILER SERVICE NAME :SERVIC DATE :8Z1Ol12~ R~Eb NAME :REEk ID CONTINUATION NEXT REEL"~'NAME COMMENTS ~REEL COMMgNT$