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Home My WebLink About201-0707. If perforating: 1. Type of Request: 2. Operator Name: 3. Address: 4. Current Well Class:5. Permit to Drill Number: 6. API Number: 8. Well Name and Number: 9. Property Designation (Lease Number):10. Field: Abandon Suspend Plug for Redrill Perforate New Pool Perforate Plug Perforations Re-enter Susp Well Other Stimulate Fracture Stimulate Alter Casing Pull Tubing Repair Well Other: Change Approved Program Operations shutdown What Regulation or Conservation Order governs well spacing in thes pool? Will perfs require a spacing exception due to property boundaries?Yes No 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): PRESENT WELL CONDITION SUMMARY Perforation Depth MD (ft): Perforation Depth TVD (ft):Tubing Size: Tubing Grade: Tubing MD (ft): Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 12. Attachments: 14. Estimated Date for Commencing Operations: 13. Well Class after proposed work: 15. Well Status after proposed work: 16. Verbal Approval: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approcal. Proposal Summary Wellbore schematic BOP SketchDetailed Operations Program OIL GAS WINJ WAG GINJ WDSPL GSTOR Op Shutdown Suspended SPLUG Abandoned ServiceDevelopmentStratigraphicExploratory Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: AOGCC USE ONLY Commission Representative: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Location ClearanceMechanical Integrity TestBOP TestPlug Integrity Other Conditions of Approval: Post Initial Injection MIT Req'd?Yes No Subsequent Form Required: Approved By:Date: APPROVED BY THE AOGCCCOMMISSIONER PBU NK-19A Update sundry 325 - 458 Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 201-070 50-029-22507-01-00 ADL 034630 & 034635 12372 Conductor Surface Intermediate Production Liner 10169 80 4186 7971 4475 10190 20" 10-3/4" 7-5/8" 4-1/2" 8578 33 - 113 33 - 4219 31 - 8002 7897 - 12372 2400 33 - 113 33 - 4106 31 - 7296 7207 - 10169 None 520 2470 4790 7500 1530 5210 6890 8430 9910 - 12140 4-1/2" 12.6# L-80 29 - 79128428 - 9963 Structural 4-1/2" Baker SABL-3 No SSSV 7852 / 7169 Date: Bo York Sr. Area Operations Manager Michael Hibbert michael.hibbert@hilcorp.com 907-903-5990 PRUDHOE BAY 10-1-2025 Current Pools: BROOKIAN UNDEFINED, NIAKUK & RAVEN OIL Proposed Pools: Suspension Expiration Date: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 Comm. Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Form 10-403 Revised 06/2023 Approved application is valid for 12 months from the date of approval.Submit PDF to aogcc.permitting@alaska.gov 10190 , 11022 , 11234 , 11950 By Grace Christianson at 9:23 am, Sep 26, 2025 Digitally signed by David Bjork (3888) DN: cn=David Bjork (3888) Date: 2025.09.25 16:12:34 - 08'00' David Bjork (3888) 325-583 10-404 DSR-9/26/25A.Dewhurst 26SEP25 Previous Sundry Approval 325-458. CDW BJM 10/3/25 CDW 09/26/2025 Include a PRV on OA or hold an open bleed on OA during fracture treatment. Test PRVs/Popoffs and pump trips to the set pressures detailed in the procedure except that the global Nitrogen PRV does not need to be retested if its a single use style. Variance to 20 AAC 25.283(a)(6)(A)(ii) approved. *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.10.06 10:26:44 -08'00'10/06/25 RBDMS JSB 100625 FRAC – Brookian UHRC Well: NK-19A PTD: 201-070 API: 50-029-22507-01 Well Name:NK-19A Permit to Drill:201-070 Current Status:Operable, Producer API Number:50-029-22507-01 Estimated Start Date:October 20th, 2025 Estimated Duration:7days IOR:Rig:Frac, coil, slickline, test AFE:242-01787 Regulatory Contact:Abbie Barker Sundry Number:325-458 First Call Engineer:Michael Hibbert (907) 903-5990 (M) Second Call Engineer:Leif Knatterud (907) 564-4667 (O)(432) 227-4342 (M) Program Revision:Rev 1 – Higher MITs, cement squeeze, re-perf, and updated treating pressure. Current Bottom Hole Pressure:4,401 psi @ 9,300’ TVDss Max Anticipated Surface Pressure:2,400 psi stacked out with lift gas Brookian KWF: 9.11 ppg Last SI WHP:1750 psi (4/17/2024) Min ID:3.725” @ 7,900’ - XN nipple Max Angle:60 deg @ 9,523’ MD Brief Well Summary: The Niakuk/Raven portions of the well were plugged with a CIBP and ~212’ of cement. The Brookian interval was perforated and temporarily flowed. A MIT-T passed to 2,532 psi and an CMIT-TxIA passed to 2,700 psi in Q4 of 2023.Updated MITs: MIT-T passed to 4,609 psi on 9/19/25 and MIT-IA passed to 3,607 psi on 9/19/25. Objective: Cement squeeze all current open perforations and re-perf for limited entry with 5’ of perforations. Frac Brookian sands in NK-19A – Tract Operation in an undefined pool POP via artificial lift via portable test separator Current Status: Operable Well Completion Information: Wellhead: FMC, 13-5/8” x 4-1/2” tubing hanger Recent Integrity: ¾12/18/2023 – MIT-T Passed to 2,532 psi ¾12/02/2023 – MIT-T Passed to 2,675 psi ¾10/27/2023 – MIT-T Passed to 2,600 psi ¾010/26/2023 – CMIT Passed to 2,700 psi ¾9/19/25 – MIT-T Passed to 4,609 psi ¾9/19/25 – MIT-IA Passed to 3,607 psi Rev 1 – Added updated MITs. CT cement squeeze all perforations and re-perf w/ 5’ of perfs. Update treatment pressures. FRAC – Brookian UHRC Well: NK-19A PTD: 201-070 API: 50-029-22507-01 Wellwork Procedure Slickline 1. Dummy GLVs –completed on 9/19/25 Coiled Tubing – Cement Squeeze 1. MIRU CTU 2. MU cementing nozzle w/o checks. RIH and tag CIBP at 10,190’. PU 10’. 3. Mix cement and pump the following down CT: a. 5 bbls freshwater spacer b. 15 bbls of 15.8 class (pump 10-25 bbls depending on final injectivity) c. 5 bbls freshwater spacer d. Displace with 1% KCL 4. Lay-in cement from 10,190’. Once all of cement is placed in the liner PUH to safety (~200-300’ above worst case top of cement). 5. Close in CTBS and squeeze cement into perforations. Target a squeeze pressure of 3500 psi. Hesitate if necessary. Build squeeze pressure in ~500 psi increments pausing at each step. Hold final squeeze pressure for 45-60 minutes. Bleed WHP down to ~500 psi. 6. Cleanout cement – Drop ball and circulate down PowerVis/contam pill to nozzle maintaining ~500 psi on CTBS. If substantial cement is left in liner after final squeeze pressure is obtained then consider reversing out cement. 7. Once ball lands at nozzle, jet remaining cement in the liner down to 10,190’. Circulate a bottoms up and POOH. 8. Lay-in freeze protect from 2500’. Leave 500 psi WHP on the well. 9. RDMO. Slickline 1. Drift for EL perforating. Use 3.5” drift. EL 1. Perforate 9,966’-9,971’ with frac flow charges (3-1/8” Frac flow charges or similar). a. See attached annotated log for tying in. b. Email tie-in log to Michael Hibbert and Joe Syzdek for confirmation. Slickline 1. Install SSSV protection sleeve @ 2,071’ Frac 1. Spot water tanks and fill with 3% KCL a. Heat water to 90-100 degF b. Minimum pumping temp for water: 90 degF 2. Pull water from each tank and have SLB lab test our water quality: a. pH - ~7 i. Higher pH delays the hydration of the gel and delays break b. Calcium/magnesium <500 mg/l i. Mg/Ca Negative side effects in the formation such as carbonate deposits, which tend to be insoluble c. Bicarbonate - <400 mg/l FRAC – Brookian UHRC Well: NK-19A PTD: 201-070 API: 50-029-22507-01 i. High bicarbonate levels will cause slow hydration times and elevated delay times with X- linking fluids. If we have elevated bicarbonate levels and have introduced delay agents, it could have an exponential effect in delay times. d. Chlorides-<10,000 mg/l i. This fluid system should be able to cope with elevated Chloride levels e. Iron (Fe+3) - <5 mg/l i. Elevated Iron concentrations exist, the ammonium persulfate (breaker) can have an accelerated effect. Can cause viscosity degradation in linear gels (especially if batch mixed). Also can interfere with X-linking b/c iron will tie up the X-linking sites. f. TDS – minimal/<5000 i. Effects depend on the solids that are dissolved in the fluid. 3. RU and set tree saver 4. Review approved frac application and procedure 5. RU SLB Frac 6. Ensure frac fluid QAQC has been agreed on with OE 7. Perform pressure tests prior to performing hydraulic fracture stimulation. a. Pressure test surface lines and tree saver to 8,316 psi. b. Pressure test pump kick outs to 6,580 – 6,950 psi. c. Pressure test IA Pop-Off system to ensure functioning properly. IA Pop-Offs to be set at 3,426 psi. d. Bring IA pressure up and hold at ~3,126 psi. 8. Pump the hydraulic fracture stimulation per the proposed pump schedule below. Maximum allowable treating pressure is 7,316 psi. 9. RDMO SLB frac and flowback equipment Pump Schedule FRAC – Brookian UHRC Well: NK-19A PTD: 201-070 API: 50-029-22507-01 Pressures MIT-T 4,609 psi MIT-IA 3,607 psi Maximum Anticipated Treating Pressure:5950 psi IA Pop-off Set Pressure (~95% of MIT-IA):3,426 psi Minimum Hold Pressure (Pop-off – 300 psi):3,126 psi Maximum Allowable Treating Pressure (MATP = Ann hold + MIT-T/1.1):7,316 psi w/ 3,126 psi on IA Stagger Pump Kickouts Between 90 – 95% of MATP:6,580-6,950 psi N2 POP-off set pressure (MATP):7,316 psi Treating Line Test Pressure (MATP + 1000 psi):8,316 psi OA Pressure:Monitor – Rigup open bleed Max Anticipated Proppant Loading:8 PPA Coil 1. Contingent Post Frac FCO Slickline 1. Pull SSSV protection sleeve 2. Install LGLVs 3. Install SSSV Testers: 1. MIRU per flowback diagram below, pressure test and POP. Flow well using a nearby well flowline. Key Contacts: Company Contact Phone Comment Hilcorp Slickline TBD TBD Hilcorp Testers TBD TBD Hilcorp OE Michael Hibbert (907) 903-5990 Hilcorp OE 2nd call Leif Knatterud (432) 227-4342 Attachments – Current Wellbore Schematic Frac RU Diagram Flowback RU Diagram Reference Log for Brookian Perforations Sundry Revision Change Form Max IA 3,279 psi CDW 09/26/2025 OK CDW 09/26/2025 FRAC – Brookian UHRC Well: NK-19A PTD: 201-070 API: 50-029-22507-01 Current Wellbore Schematic: FRAC – Brookian UHRC Well: NK-19A PTD: 201-070 API: 50-029-22507-01 Frac RU Diagram FRAC – Brookian UHRC Well: NK-19A PTD: 201-070 API: 50-029-22507-01 Flowback RU Diagram: E-34 E-34Artificial Lift FRAC – Brookian UHRC Well: NK-19A PTD: 201-070 API: 50-029-22507-01 Reference Log for Brookian Perforations: FRAC – Brookian UHRC Well: NK-19A PTD: 201-070 API: 50-029-22507-01 FRAC – Brookian UHRC Well: NK-19A PTD: 201-070 API: 50-029-22507-01 Perforate 9,966’ – 9,971’ FRAC – Brookian UHRCWell: NK-19APTD: 201-070API: 50-029-22507-01Sundry Revision Change Form:Changes to Approved Sundry ProcedureDate:Subject:Sundry #:Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC by the “first call” engineer. AOGCC written approval of the change is required before implementing the change.StepPageDateProcedure ChangeHAKPreparedBy(Initials)HAKApprovedBy(Initials)AOGCC WrittenApprovalReceived (Personand Date)Approval:Operations Manager DatePrepared:Operations Engineer Date BROOKIAN UNDEFINED, NIAKUK AND RAVEN OIL 10190, 11022, 11234, 11950 By Grace Christianson at 11:25 am, Aug 05, 2025 Digitally signed by Bo York (1248) DN: cn=Bo York (1248) Date: 2025.08.05 09:44:38 - 08'00' Bo York (1248) 325-458 JJL 8/21/25 10-404 CDW 08/19/2025 DSR-8/14/25 Include a PRV on OA or hold an open bleed on OA during fracture treatment. Test PRVs/Popoffs and pump trips to the set pressures detailed in the procedure except that the global Nitrogen PRV does not need to be retested if its a single use style. A.Dewhurst 26AUG25'tϬϴͬϮϳͬϮϬϮϱ Variance to 20 AAC 25.283(a)(6)(A)(ii) approved. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.08.27 08:33:58 -08'00' 08/27/25 RBDMS JSB 082725 FRAC –Brookian UHRC Well: NK-19A PTD: 201-070 API: 50-029-22507-01 Well Name:NK-19A Permit to Drill:201-070 Current Status:Operable, Producer API Number:50-029-22507-01 Estimated Start Date:September 1st, 2025 Estimated Duration:7days IOR: Rig:Frac, coil, slickline, test AFE:242-01787 Regulatory Contact:Abbie Barker Sundry Number: First Call Engineer:Michael Hibbert (907) 903-5990 (M) Second Call Engineer:Leif Knatterud (907) 564-4667 (O) (432) 227-4342 (M) Program Revision:0 Current Bottom Hole Pressure:4,401 psi @ 9,300’ TVDss Max Anticipated Surface Pressure:2,400 psi stacked out with lift gas Brookian KWF: 9.11 ppg Last SI WHP:1750 psi (4/17/2024) Min ID:3.725” @ 7,900’ - XN nipple Max Angle:60 deg @ 9,523’ MD Brief Well Summary: The Niakuk/Raven portions of the well were plugged with a CIBP and ~212’ of cement. The Brookian interval was perforated and temporarily flowed. A MIT-T passed to 2,532 psi and an CMIT-TxIA passed to 2,700 psi in Q4 of 2023. Objective: Frac Brookian sands in NK-19A – Tract Operation in an undefined pool POP via artificial lift via portable test separator Current Status: Operable Well Completion Information: Wellhead: FMC, 13-5/8” x 4-1/2” tubing hanger Recent Integrity: ¾12/18/2023 – MIT-T Passed to 2532 psi ¾12/02/2023 – MIT-T Passed to 2675 psi ¾10/27/2023 – MIT-T Passed to 2600 psi ¾010/26/2023 – CMIT Passed to 2700 psi Wellwork Procedure Slickline 1. Dummy GLVs 2. Install SSSV protection sleeve Frac 1. Spot water tanks and fill with 3% KCL a. Heat water to 90 degF b. Minimum pumping temp for water: 80 degF FRAC –Brookian UHRC Well: NK-19A PTD: 201-070 API: 50-029-22507-01 2. Pull water from each tank and have SLB lab test our water quality: a. pH - ~7 i. Higher pH delays the hydration of the gel and delays break b. Calcium/magnesium <500 mg/l i. Mg/Ca Negative side effects in the formation such as carbonate deposits, which tend to be insoluble c. Bicarbonate - <400 mg/l i. High bicarbonate levels will cause slow hydration times and elevated delay times with X- linking fluids. If we have elevated bicarbonate levels and have introduced delay agents, it could have an exponential effect in delay times. d. Chlorides-<10,000 mg/l i. This fluid system should be able to cope with elevated Chloride levels e. Iron (Fe+3) - <5 mg/l i. Elevated Iron concentrations exist, the ammonium persulfate (breaker) can have an accelerated effect. Can cause viscosity degradation in linear gels (especially if batch mixed). Also can interfere with X-linking b/c iron will tie up the X-linking sites. f. TDS – minimal/<5000 i. Effects depend on the solids that are dissolved in the fluid. 3. RU and set tree saver 4. Review approved frac application and procedure 5. RU SLB Frac 6. Ensure frac fluid QAQC has been agreed on with OE 7. Perform pressure tests prior to performing hydraulic fracture stimulation. a. Pressure test surface lines and tree saver to 7,206 psi. b. Pressure test pump kick outs to 5,585 – 5,896 psi. c. Pressure test IA Pop-Off system to ensure functioning properly. IA Pop-Offs to be set at 3,325 psi. d. Bring IA pressure up and hold at 3,025 psi. 8. Pump the hydraulic fracture stimulation per the proposed pump schedule below. Maximum allowable treating pressure is 6,206 psi. 9. RDMO SLB frac and flowback equipment FRAC –Brookian UHRC Well: NK-19A PTD: 201-070 API: 50-029-22507-01 Pump Schedule Pressures MIT-T 3500 psi MIT-IA 3500 psi Maximum Anticipated Treating Pressure: 5950 psi IA Pop-off Set Pressure (~95% of MIT-IA): 3325 psi Minimum Hold Pressure (Pop-off –300 psi): 3025 psi Maximum Allowable Treating Pressure (MATP = Ann hold + MIT-T/1.1): 6206 psi w/ 3025 psi on IA Stagger Pump Kickouts Between 90 –95% of MATP: 5585-5896 psi Global Kickout (95% of MATP): 5896 psi N2 POP-off set pressure (MATP): 6206 psi Treating Line Test Pressure (MATP + 1000 psi): 7206 psi OA Pressure: Monitor –Rigup bleed hose and/or PRV Max Anticipated Proppant Loading: 8 PPA Coil 1. Contingent Post Frac FCO FRAC –Brookian UHRC Well: NK-19A PTD: 201-070 API: 50-029-22507-01 Slickline 1. Install LGLVs 2. Pull SSSV protection sleeve and install SSSV Testers: 1. MIRU per flowback diagram below, pressure test and POP. Flow well using a nearby well flowline. Key Contacts: Company Contact Phone Comment Hilcorp Slickline TBD TBD Hilcorp Testers TBD TBD Hilcorp OE Michael Hibbert 907-903-5990 Attachments – Current Wellbore Schematic Frac RU Diagram Flowback RU Diagram Reference Log for Brookian Perforations Sundry Revision Change Form FRAC –Brookian UHRC Well: NK-19A PTD: 201-070 API: 50-029-22507-01 Current Wellbore Schematic: FRAC –Brookian UHRC Well: NK-19A PTD: 201-070 API: 50-029-22507-01 Frac RU Diagram FRAC –Brookian UHRC Well: NK-19A PTD: 201-070 API: 50-029-22507-01 Flowback RU Diagram: E-34 E-34Artificial Lift FRAC –Brookian UHRC Well: NK-19A PTD: 201-070 API: 50-029-22507-01 Reference Log for Brookian Perforations: FRAC–Brookian UHRCWell: NK-19APTD: 201-070API: 50-029-22507-01Sundry Revision Change Form:Changes to Approved Sundry ProcedureDate:Subject:Sundry #:Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC by the “first call” engineer. AOGCC written approval of the change is required before implementing the change.Step Page Date Procedure ChangeHAKPreparedBy(Initials)HAKApprovedBy(Initials)AOGCC WrittenApprovalReceived (Personand Date)Approval:Operations Manager DatePrepared:Operations Engineer Date NK-19A Fracture Stimulation PTD: 201-070 Date: July 29, 2025 Subject: NK-19A Brookian Undefined Pool Sandstone Fracture Stimulation From: Michael Hibbert C: (907) 903-5990 To: AOGCC Estimated Start Date: 9/1/2025 Attached is Hilcorp’s proposal and supporting documents to perform a fracture stimulation on well NK- 19A in the undefined Pool in the Niakuk area. NK-19A was recompleted from the Sag and Kuparuk formations up-hole to the Brookian interval. This interval is not in a defined pool and is therefore under state wide tract operations as per 20 AAC 25.517. The well was perforated and tested, and resulting diagnostics indicate sub-millidarcy formation permeability with high oil cuts and little to no water production. These diagnostics indicate that the well performance could improve with a hydraulic fracture stimulation. During this production test, the near wellbore region will see a pressure reduction which will cause the gas-oil ratio to increase, possibly above the current GOR limitations as defined by 20 AAC 25.240. Therefore, a waiver to the Gas-Oil Ratio requirement of 20 AAC 25.240 is requested. Well test data will be recorded at least once per month. If production is sustained, fluid samples will be obtained as per the requirements in 20 AAC 25.270. Hilcorp requests an exception to sections 20 AAC 25. 283, a, 3- 4 which require identification of fresh - water aquifers and a plan for base-water sampling, based on Area Injection Orders. Please direct questions or comments to Michael Hibbert. Therefore, a waiver to the Gas-Oil Ratio requirement of 20 AAC 25.240 is requested. During this production test, the near wellbore region will see a pressure reduction which will cause the gas-oil ratio to increase, possibly above the current GOR limitations as defined by 20 AAC 25.240. NK-19A Fracture Stimulation PTD: 201-070 SECTION 1 - AFFIDAVIT (20 AAC 25. 283, a, 1): Below is an affidavit stating that the owners, landowners, surface owners and operators identified on a plat within one-half mile radius of the current or proposed wellbore trajectory have been provided notice of operations in compliance with 20 AAC 25.283, a 1. NK-19A Fracture Stimulation PTD: 201-070 SIGNED AFFIDAVIT: NK-19A Fracture Stimulation PTD: 201-070 COPY OF NOTIFICATION SENT VIA EMAIL: NK-19A Fracture Stimulation PTD: 201-070 SECTION 2: PLAT IDENTIFYING ALL WELLS WITHIN 1/2 MILE – SURFACE (20 AAC 25. 283, a, 2, B): Wells within 1/2 mile radius at surface. NK-19A Fracture Stimulation PTD: 201-070 List of wells in Plat (20 AAC 25.283, a, 2, B) Approx 75 wells CDW 08/19/2025 NK-19A Fracture Stimulation PTD: 201-070 SECTION 3: EXEMPTION FOR FRESHWATER AQUIFERS (20 AAC 25. 283, a, 3): Well NK-19A is located in the same area as the Niakuk Oil Pool (AIO 14 A). This area was studied by the previous Operator and found that due to ‘the lack of fresh water and underground sources of drinking water in the Niakuk Injection Area obviates the need for an aquifer exemption. Hilcorp agrees with their assessment that there is no fresh water aquifers in the area and that no exemption is required. NK-19A Fracture Stimulation PTD: 201-070 SECTION 3: EXEMPTION FOR FRESHWATER AQUIFERS (20 AAC 25. 283, a, 3): Well NK-19A is located in the Eastern Operating Area of Prudhoe Bay (AIO 4G, 2015). In 1993 AIO 4 was amended to include the Pt. Mcintyre, Stump Island, and West Beach Oil pools in AIO 4A. Conclusion #10 (Area Injection Order 4A, August 12, 1993, Page 5) states that “No underground sources of drinking water (USDWs) are known to exist in the Eastern Operating Area of the Prudhoe Bay Unit and the Pt. McIntyre oil field.” Area Injection Order 4G, October 15, 2015, Page 3 states that “All information related to AIO 4, AIO 4A, AIO 413, AIO 4C, AIO 4D, AIO 4E and AIO 4F is hereby incorporated by reference into the record for this order.” Based on the Area Injection Order sections referenced above, Hilcorp requests exemption from 20 AAC 25. 283, a, 3- 4 which require identification of freshwater aquifers and establishing a plan for base-water sampling. Superseded by updated Section on Freshwater. -A.Dewhurst 26AUG25 NK-19A Fracture Stimulation PTD: 201-070Superseded by updated Section on Freshwater. -A.Dewhurst 26AUG25 NK-19A Fracture Stimulation PTD: 201-070Superseded by updated Section on Freshwater. -A.Dewhurst 26AUG25 NK-19A Fracture Stimulation PTD: 201-070 SECTION 4: PLAN FOR BASELINE WATER SAMPLING FOR WATER WELLS (20 AAC 25.283.a): There are no water wells located within one-half mile of the current or proposed wellbore trajectory and fracturing interval. A water well sampling plan is not applicable. NK-19A Fracture Stimulation PTD: 201-070 SECTION 5: DETAILED CEMENTING AND CASING INFORMATION (20 AAC 25. 283, a, 5): All casing is cemented in accordance with 20 AAC 25.52, b and tested in accordance with 20 AAC 25.030, g when completed. See current wellbore schematic for casing details: NK-19A Fracture Stimulation PTD: 201-070 SECTION 6: ASSESSMENT OF EACH CASING AND CEMENTING OPERATION TO BE PERFORMED TO CONSTRUCT OR REPAIR THE WELL (20 AAC 25.283, a, 6): Summary: NK-19 was drilled in October 1994 as a Niakuk producer. The 13-1/2” hole was drilled to 4233’ MD and 10-3/4” casing was run to 4,219’. The 10-3/4” casing was cemented to surface with good cement returns seen at surface. A 9-7/8” hole was drilled to 10,660’ and 7-5/8” casing was run to 10,648’. The 7-5/8” casing was cemented with 167 bbls of lead and 90 bbls of tail cement with an estimated TOC at 5,232’ MD and 4,957’ TVD. 6-3/4” hole was drilled to 11,226’ MD and 5-1/2” casing was run and cemented with 41 bbls of cement, liner passed a pressure test to 2,500 psi. PBTD was left at 10,356’ MD. The 4- 1/2” tubing was run and the packer was set at 9,912’ MD. NK-19A was sidetracked as a Sag and Kuparuk producer in 2002. The well has not had meaningful on time since 2006 and has not produced since 2013 due to low fluid rates. Open-hole gamma ray, resistivity, and porosity logs indicate possible pay in the Brookian formation. Mud logs from NK-02A, NK-04, and NK-05 also specify hydrocarbons are present. In the Greater Point Macintyre Area, the Brookian formation has been drill stem tested at P1-02 and Gull-02 and both wells flowed oil. The rotary sidetrack in January 2002 drilled a 6-3/4” hole to 12,372’ MD and 4-1/2” liner was run from 12,372’ to 7,907’ and cemented with 80 bbls of latex acid resistant class G cement (50% excess). 4-1/2” L80 tubing was run from 7,907’ Md to surface with the production packer set at 7,852’ MD. All casing is cemented in accordance with 210 AAC 25.030 and each hydrocarbon zone penetrated by the well is isolated. The top of cement was logged at 9,540’ behind the 4-1/2” liner during an SCMT log that was pulled on 1/22/2002. Hilcorp requests a variance to 20 AAC 25.283(a)(6)(A)(ii) to have less than 500’ MD of cement coverage. This top of cement would give 370’ of annular cement above our fracture initiation point. Fracture modeling indicates that the height growth up will be limited to 8340’ TVD which is 9,745’ MD. This will provide 200’ plus of additional cement protection from frac fluids/pressures reaching the uncemented portions of the 4-1/2” liner. Based on engineering evaluation of the wells referenced in this application, Hilcorp has determined that this well can be successfully fractured within well design limits. NK-19A Fracture Stimulation PTD: 201-070 SECTION 6: ASSESSMENT OF EACH CASING AND CEMENTING OPERATION TO BE PERFORMED TO CONSTRUCT OR REPAIR THE WELL (20 AAC 25.283, a, 6): Summary: NK-19 was drilled in October 1994 as a Niakuk producer. The 13-1/2” hole was drilled to 4233’ MD and 10-3/4” casing was run to 4,219’. The 10-3/4” casing was cemented to surface with good cement returns seen at surface. A 9-7/8” hole was drilled to 10,660’ and 7-5/8” casing was run to 10,648’. The 7-5/8” casing was cemented with 167 bbls of lead and 90 bbls of tail cement with an estimated TOC at 5,232’ MD and 4,957’ TVD. 6-3/4” hole was drilled to 11,226’ MD and 5-1/2” casing was run and cemented with 41 bbls of cement, liner passed a pressure test to 2,500 psi. PBTD was left at 10,356’ MD. The 4- 1/2” tubing was run and the packer was set at 9,912’ MD. NK-19A was sidetracked as a Sag and Kuparuk producer in 2002. The well has not had meaningful on time since 2006 and has not produced since 2013 due to low fluid rates. Open-hole gamma ray, resistivity, and porosity logs indicate possible pay in the Brookian formation. Mud logs from NK-02A, NK-04, and NK-05 also specify hydrocarbons are present. In the Greater Point Macintyre Area, the Brookian formation has been drill stem tested at P1-02 and Gull-02 and both wells flowed oil. The rotary sidetrack in January 2002 drilled a 6-3/4” hole to 12,372’ MD and 4-1/2” liner was run from 12,372’ to 7,907’ and cemented with 80 bbls of latex acid resistant class G cement (50% excess). 4-1/2” L80 tubing was run from 7,907’ Md to surface with the production packer set at 7,852’ MD. All casing is cemented in accordance with 210 AAC 25.030 and each hydrocarbon zone penetrated by the well is isolated. Based on engineering evaluation of the wells referenced in this application, Hilcorp has determined that this well can be successfully fractured within well design limits. Superseded by updated assessment. -A.Dewhurst 26AUG25 TOC at 5,232’ NK-19A Fracture Stimulation PTD: 201-070 SECTION 7 – PRESSURE TEST INFORMATION AND PLANS TO PRESSURE TEST CASINGS AND TUBING INSTALLED IN THE WELL (20 AAC 25.283, A, 7): As part of the well preparation pre-frac, the 7-5/8” x 4-1/2” annulus will be tested to 3,500psi and the 4- 1/2” tubing will be tested to 3,500psi. The 7-5/8” x 4-1/2” and the 10-3/4” x 7-5/8” annulus pressures will be monitored during the frac, if any change of pressure is seen outside of thermal expansion, the job will be flushed and the pressure source diagnosed before frac operations continue. Anticipated Pressures MIT-T 3500 psi MIT-IA 3500 psi Maximum Anticipated Treating Pressure: 5950 psi IA Pop-off Set Pressure (~95% of MIT-IA): 3325 psi Minimum Hold Pressure (Pop-off –300 psi): 3025 psi Maximum Allowable Treating Pressure (MATP = Ann hold + MIT- T/1.1): 6206 psi w/ 3025 psi on IA Stagger Pump Kickouts Between 90 –95% of MATP: 5585-5896 psi Global Kickout (95% of MATP): 5896 psi N2 POP-off set pressure (MATP): 6206 psi Treating Line Test Pressure (MATP + 1000 psi): 7206 psi OA Pressure: Monitor –Rigup bleed hose and/or PRV Max Anticipated Proppant Loading: 8 PPA NK-19A Fracture Stimulation PTD: 201-070 SECTION 8: PRESSURE RATINGS AND SCHEMATICS FOR THE WELLBORE, WELLHEAD, BOPE AND TREATING HEAD (20 AAC 25.283, A, 8): Wellbore Tubular Ratings Size/Name Weight Grade Burst, psi Collapse, psi 10-3/4” Surface Casing 45.5# NT80 5210 2470 7-5/8” Production Casing 29.7# NT80S 6890 4790 4-1/2” Production Tubing 12.6# L80 8430 7500 Wellhead FMC manufactured wellhead 11”x13”, rated to 5,000 psi. Tubing Spool: 11"x13-5/8” 5,000 psi w/ 2-1/16" side outlets Casing Spool: 11"x13-5/8” 5,000 psi w/ one 2-1/16" side outlet Tree: CIW 4-1/16" 5,000 psi A 10k psi rated Tree-Saver will be used during these fracturing operations.A 10k psi rated Tree-Saver NK-19A Fracture Stimulation PTD: 201-070 SECTION 9: DATA FOR FRACTURING ZONE AND CONFINING ZONES (20 AAC 25.283, A, 9): Formation MD Top MD Base TVDSS Top TVDSS Base TVD Thickness Frac Grad. Psi/ft Lithology Description Collville Mudstones (CM3)8024 9780 -7262 -8305 1,043 0.70 shale, silt Upper Hue Shale 9780 9913 -8305 -8377 72 0.71 shale Upper Hue A- Sand 9913 10083 -8377 -8469 92 0.66 sand, shale Upper Hue A- Shale 10083 10203 -8469 -8532 63 0.71 shale Upper Hue B- Sand 10203 10377 -8532 -8630 98 0.66 sand, shale Upper Hue B- Shale 10377 10573 -8630 -8746 116 0.71 shale Lower Hue Shale 10573 10878 -8746 -8935 189 0.71 shale, silt, carbonate HRZ 10878 11246 -8935 -9183 248 0.70 organic-rich shale Base HRZ (Kalubik)11246 11248 -9183 -9184 1 0.70 shale Kuparuk 11248 11480 -9184 -9353 169 0.63 sand NK-19A Fracture Stimulation PTD: 201-070 SECTION 10: LOCATION, ORIENTATION AND A REPORT ON MECHANICAL CONDITION OF EACH WELL THAT MAY TRANSECT CONFINING ZONE (20 AAC 25.283, a, 10): Plat of wells within one-half mile of NK-19A wellbore reservoir trajectory and location of faults. The plat shows the location and orientation of each well that transects the confining zone. Hilcorp has formed the opinion, based on the following assessments for each well, seismic, and other subsurface information currently available, that none of these wells will interfere with containment of the hydraulic fracturing fluid within the one-half mile radius of the proposed wellbore trajectory. NK-19A Fracture Stimulation PTD: 201-070 Casing and Cement assessments for all wells that transect the confining zone: NK-19A Fracture StimulationPTD: 201-070Casing and Cement assessments for all wells that transect the confining zone:Superseded by updated AOR table. -A.Dewhurst 26AUG25 NK-19A Fracture Stimulation PTD: 201-070 SECTION 11: LOCATION OF, ORIENTATION OF AND GEOLOGICAL DATA FOR FAULTS AND FRACTURES THAT MAY TRANSECT THE CONFING ZONES (20 AAC 25.283, A, 11): Hilcorp’s technical analysis based on seismic, well and other subsurface information available indicates that there are 4 mapped faults that transect the Hue interval and enter the confining zone within the 1/2 mile radius of the production and confining zone trajectory for NK-19A. Fracture gradients within the confining zone (Hue Shale and HRZ) will not be exceeded during fracture stimulation and would therefore confine injected fluids to the interval of interest. Faults 1-4 intersect the production interval and confining zone within the 1/2 mile radius of the planned frac. Their displacements, sense of throw, and zone in which they terminate upwards are given below. Maximum stress direction is estimated to be North – South plus or minus 15 degrees. The planned frac half-length of 180’ should not reach any of the mapped faults. Half-length is modeled using hydraulic fracture modeling software and is corroborated by what has been seen in other frac treatments in analogous intervals. Fault 3 is the closest to NK-19A, at 1,006’ away. If a sudden drop in treating pressure or increase in pump rate is seen during the stimulation that cannot be explained by fluids pumped or annular pressure monitoring, pumping operation will stop until a plan forward and explanation can be put forth. NK-19A Fracture Stimulation PTD: 201-070 SECTION 12: PROPOSED HYDRAULIC FRACTURING PROGRAM (20 AAC 25.283, a, 12): Proposed Procedure: 1. Conduct safety meeting, inspect location, and review 10-403. 2. Ensure all pre-frac well work has been completed, and the tubing & IA are freeze protected. 3. MIRU frac equipment and associated frac tanks. 4. Pressure test surface lines to at least 7,206 psi. 5. Test IA Pop-off system to ensure functioning properly. IA Pop-off to be set at 3,325 psi. 6. Bring IA pressure up to a hold pressure of 3,025 psi. 7. Pump the fracture stimulation per the proposed pump schedule below. Maximum allowable treating pressure is 6,206 psi. 8. RDMO frac equipment. Ensure tubing is freeze protected. 9. Return the well to production / flowback post slickline gas lift and contingent coiled tubing cleanout. Fracture Stimulation Pump Schedule ťÍČôώϭώ >īŪĖî ťÍČô «ĺīŪıô ϼČÍīϽ ŪıŪīÍťĖŽô «ĺīŪıôώϼČÍīϽώ Íťô Řĺŕϟ ĺĲèϟ ϼŕŕÍϽώ ŘĺŕŕÍĲťώbÍıô ŘĺŕŕÍĲ ťώϼϭϽ ͐ ͒͏ϭώ[ĖĲôÍŘ [ĺÍîώϳώ͐ϟ͑Ƅ ͗Ϡ͕͏͏ ͗Ϡ͕͏͏ ͔ϱ͐͏ ͑ ´>͐͒͏>īôƄ"ώϱώώ³ϱ[ĖĲħώ ťôŕώîĺſĲώťôŜť ͗Ϡ͕͏͏ ͖͐Ϡ͑͏͏ ͑ϱ͑͑ ēŪťώîĺſĲ ĺĲťĖĲČôĲťώF[ϯèĺŪŘϼ͖Ϡ͏͏͏ īæŜώ͐͏͏ώıôŜēϽ ͑Ϡ͏͏͏ ͐͘Ϡ͑͏͏ ͓͑ ώ͐͏͏ώıôŜē ώ͖Ϡ͏͏͏ ͒ ͑͏ϭώ[ĖĲôÍŘ iŽôŘώ>īŪŜē ͗Ϡ͕͏͏ ͖͑Ϡ͗͏͏ ͑͗ ēŪťîĺſĲ ͓ ´>͐͒͏>īôƄ"ώϱώώ³ϱ[ĖĲħώ Íî ͓͑Ϡ͏͏͏ ͒͑ ͔ ´>͐͒͏>īôƄ"ώϱώώ³ϱ[ĖĲħώ ͐ώ ͑Ϡ͏͏͏ ͒͑͐ϟ͏ώ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͑Ϡ͏͏͏ ͕ ´>͐͒͏>īôƄ"ώϱώώ³ϱ[ĖĲħώ ͑ώ ͒Ϡ͏͏͏ ͒͑͑ϟ͏ώ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͕Ϡ͏͏͏ ͖ ´>͐͒͏>īôƄ"ώϱώώ³ϱ[ĖĲħώ ͒ώ ͒Ϡ͏͏͏ ͒͑͒ϟ͏ώ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͘Ϡ͏͏͏ ͗ ´>͐͒͏>īôƄ"ώϱώώ³ϱ[ĖĲħώ ͒ϟ͔ώ ͓Ϡ͏͏͏ ͓͒͑ϟ͔ώ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͓͐Ϡ͏͏͏ ͘ ´>͐͒͏>īôƄ"ώϱώώ³ϱ[ĖĲħώ ͓ώ ͓Ϡ͏͏͏ ͓͒͑ϟ͏ώ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͕͐Ϡ͏͏͏ ͐͏ ´>͐͒͏>īôƄ"ώϱώώ³ϱ[ĖĲħώ ͓ϟ͔ώ ͓Ϡ͏͏͏ ͓͒͑ϟ͔ώ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͐͗Ϡ͏͏͏ ͐͐ ´>͐͒͏>īôƄ"ώϱώώ³ϱ[ĖĲħώ ͔ώ ͓Ϡ͏͏͏ ͔͒͑ϟ͏ώ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͑͏Ϡ͏͏͏ ͐͑ ´>͐͒͏>īôƄ"ώϱώώ³ϱ[ĖĲħώ ͔ϟ͔ώ ͓Ϡ͏͏͏ ͔͒͑ϟ͔ώ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͑͑Ϡ͏͏͏ ͐͒ ´>͐͒͏>īôƄ"ώϱώώ³ϱ[ĖĲħώ ͕ώ ͓Ϡ͏͏͏ ͒͑ ͕ϟ͏ώ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͓͑Ϡ͏͏͏ ͓͐ ´>͐͒͏>īôƄ"ώϱώώ³ϱ[ĖĲħώ ͕ϟ͔ώ ͓Ϡ͏͏͏ ͒͑ ͕ϟ͔ώ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͕͑Ϡ͏͏͏ ͔͐ ´>͐͒͏>īôƄ"ώϱώώ³ϱ[ĖĲħώ ͖ώ ͒Ϡ͔͏͏ ͒͑ ͖ϟ͏ώ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͓͑Ϡ͔͏͏ ͕͐ ´>͐͒͏>īôƄ"ώϱώώ³ϱ[ĖĲħώ ͖ϟ͔ώ ͒Ϡ͔͏͏ ͒͑ ͖ϟ͔ώ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͕͑Ϡ͔͑͏ ͖͐ ´>͐͒͏>īôƄ"ώϱώώ³ϱ[ĖĲħώ ͗ώ ͑Ϡ͔͗͏ ͒͑ ͗ϟ͏ώ ͑͏ϯ͓͏ώÍŘæĺ[Ėťô ͑͑Ϡ͗͏͏ ͐͗ ͑͏ϭώ[ĖĲôÍŘ >īŪŜē ͖Ϡ͐͗͏ ͒͑ Estimated Cumulative fluid volume: 104,830 gal (2,496 bbl) Estimated total proppant: 237,500 NK-19A Fracture Stimulation PTD: 201-070 There are two overpressure devices that protect the surface equipment and wellbore from overpressure. 1) Each individual frac pump has an electronic kickout that will shift the pumps into neutral as soon as the set pressure is reached. Since there are multiple pumps, these set pressures are staggered between 90% and 95% of the maximum allowable treating pressure. 2) There is a manual kickout that is controlled from the frac van that can shift all pumps into neutral. All three of these shutdown systems will be individually tested prior to high pressure pumping operations. Additionally, the treating pressure, IA pressure and OA pressure will be monitored in the frac van. Frac Dimensions: Frac #MD Location, ft TVDss top, ft TVDss Bottom, ft Frac Half-Length, ft 1 9,910’ ~-8,340 ~-8,450 ~180’ 2 9,946” ~-8,395 ~-8,545 ~150’ Frac Modelling: Maximum Anticipated Treating Pressure: ~5,950 psi Surface pressure and fracture dimensions were modeled using NK-19A logs Disclaimer Notice: This model was generated by a third party using commercially available modelling software and is based on engineering estimates of reservoir properties. Hilcorp is providing these model results as an informed prediction of actual results. Because of the inherent limitations in assumptions required to generate this model, and for other reasons, actual results may differ from the model results. ~5,950 psi NK-19A Fracture Stimulation PTD: 201-070 Pre-Job Anticipated Chemicals to be pumped: NK-19A Fracture Stimulation PTD: 201-070 NK-19A Fracture Stimulation PTD: 201-070 SECTION 13: POST FRACTURE WELLBORE CLEANUP AND FLUID RECOVERY PLAN (20 AAC 25.283, A, 13): After the fracture stimulation and potentially during the post frac coiled tubing fill cleanout, the well will be put on production through a portable well test unit. All liquids will be captured and either sent to production facilities or diverted to flowback tanks if proppant production is above the acceptable threshold. The initial flowback period is intended to produce back the treating fluid volume to tanks as quickly as possible. When production is less than 20% water cut and less than 0.5% solids the flowback will be routed to the LPC production facility. There will be a flowback tank farm on pad to store any produced fluids from flowback operations that do not meet the LPC facility specifications mentioned above. The fluids and proppant not suitable for LPC processing will be hauled to GNI for disposal. Hilcorp will work to separate and recover fluid that meets the facility specification for the flowback fluids. A fluid manifest form will be completed for each load trucked offsite. 1 Dewhurst, Andrew D (OGC) From:Michael Hibbert <michael.hibbert@hilcorp.com> Sent:Tuesday, 26 August, 2025 15:20 To:Dewhurst, Andrew D (OGC) Cc:Joseph Lastufka; Wallace, Chris D (OGC); Lau, Jack J (OGC); Joseph Syzdek Subject:RE: [EXTERNAL] PBU NK-19A Frac Sundry (325-458): Questions Attachments:NK-19A - Fracture Stimulation Application Revisions.pdf Hi Andy, Here are the replies to your questions below: Aquifer exemption question – x Yes, it is our current understanding that this area does not have an aquifer exemption order. Attached is documentation from AIO 14 A that states that “the lack of fresh water and underground sources of drinking water in the Niakuk injection area obviates the need for an aquifer exemption”. This is page 177 of AIO 14A. Also in exhibit M-1 on page 217 of AIO 14A it describes BPs methodology and well sampling to justify the determination that no freshwater aquifers are present in the area. NK-19A 4-1/2” cement top – x The top of cement was logged at 9,540’ behind the 4-1/2” liner during an SCMT that was logged on 1/22/2002. Hilcorp requests a variance to 20 AAC 25.283(a)(6)(A)(ii) to have less than 500’ MD of cement coverage. This top of cement would give 370’ of annular cement above our fracture initiation point. Fracture modeling indicates that our height growth up will be limited to 8340’ TVD which is 9,745’ MD. This will provide 200’ plus of additional cement protection from frac Ʋuids/pressures reaching the uncemented portions of the 4-1/2” liner. NK-12 uncemented 7-5/8” – x A portion of the 7-5/8” casing in the NK-12 parent bore is uncemented from 10,990’ MD up to the 10-3/4” surface casing shoe which is cemented from the shoe up to 4,672’ MD. The measured distance from the Hue Shale in NK-19A to the top of cement in NK-12 (at 10,990’ MD) is over 2400 feet away and fracture modeling shows a max frac length of 180’. The table is updated and justiƱcation added. 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 Pages 7, 10, and 12 have been updated and the original sundry application had pages 8 & 9 deleted that referred to AIO 4. Let me know if you have any further questions or want to discuss any of these subjects further. Thanks, Michael Hibbert LPC Operations Engineer 1-907-903-5990 From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Thursday, August 21, 2025 11:29 AM To: Michael Hibbert <michael.hibbert@hilcorp.com> Cc: Joseph Lastufka <joseph.lastufka@hilcorp.com>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Lau, Jack J (OGC) <jack.lau@alaska.gov> Subject: [EXTERNAL] PBU NK-19A Frac Sundry (325-458): Questions Michael, I am reviewing the PBU NK-19A frac sundry and have two questions: x Would you conƱrm that there is no Aquifer Exemption Order that covers this well location? AEO 1 covers PBU West, but I don’t believe this well is aƯected. If not, then you will need to identify any freshwater aquifers within a ½-mile radius of the well as per 20 AAC 25.283(a)(3). The conclusion referenced from AIO 4A (Section 3 of the sundry application) was based on salinity data from Point McIntyre and has limited relevance here. x Would you conƱrm that the TOC in the 4-1/2” production liner is ~9,500’ MD? If so, the Brookian HC zone has less than the 500’ MD cement coverage required by 20 AAC 25.283(a)(6)(A)(ii) and would require a variance with justiƱcation that the HC zone is properly isolated from the frac. Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 3 While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1 From:Lau, Jack J (OGC) Sent:Thursday, August 21, 2025 7:28 AM To:Michael Hibbert Subject:RE: [EXTERNAL] Well: NK-19A PTD: 201-070 Thanks Michael. Appears to be consistent with API RP 527 and 576. Here is my interpretation of the banding. 14373-01 Ҍ The valve serial number / shop job number. This ties back to the relief valve repair or test record in the PRV shop’s database. The “-01” often means the first valve in that work order. 10K Ҍ The set pressure rating, here 10,000 psi. That matches frac iron / treating iron service class. STD Ҍ Likely “STD” just to indicate “standard service” DD Ҍ This is shop-specific shorthand. Direct Discharge (conventional PRV, not pilot/balanced bellows) 02/26 Ҍ The test/recertiƱcation date, here the next due date RP Ҍ Abbreviation for Relief Pressure. “RP” to designate the device type as a certiƱed relief device Jack From: Michael Hibbert <michael.hibbert@hilcorp.com> Sent: Thursday, August 7, 2025 4:02 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Subject: RE: [EXTERNAL] Well: NK-19A PTD: 201-070 Jack, My understanding is that the PRV is not a resettable style that can be tested and then reset. When it POPs it has to be fully rebuilt. This is a piece of engineered equipment per API spec and has inspection/testing criteria. It is current in its certification. Attached is a picture of the banding that shows February 2026 is when it needs to be recertified. -Michael From: Lau, Jack J (OGC) <jack.lau@alaska.gov> Sent: Wednesday, August 6, 2025 2:28 PM To: Michael Hibbert <michael.hibbert@hilcorp.com> Subject: RE: [EXTERNAL] Well: NK-19A PTD: 201-070 Thanks Michael, how do you test the N2 PRV? From: Michael Hibbert <michael.hibbert@hilcorp.com> Sent: Wednesday, August 6, 2025 2:26 PM CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 2 To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Subject: RE: [EXTERNAL] Well: NK-19A PTD: 201-070 Hi Jack, We have switched to nitrogen PRV. The nitrogen PRV will be set to MATP and will be isolated during pressure testing to 1000 psi over MATP. Each pump has its own kickouts programmed as well between 90-95% of MATP. Anticipated Pressures MIT-T 3500 psi MIT-IA 3500 psi Maximum Anticipated Treating Pressure: 5950 psi IA Pop-off Set Pressure (~95% of MIT-IA): 3325 psi L2-25 Minimum Hold Pressure (Pop-off – 300 psi): 3025 psi Maximum Allowable Treating Pressure (MATP = Ann hold + MIT - T/1.1): 6206 psi w/ 3025 psi on IA Stagger Pump Kickouts Between 90 – 95% of MATP: 5585-5896 psi Global Kickout (95% of MATP): 5896 psi N2 POP-off set pressure (MATP): 6206 psi Treating Line Test Pressure (MATP + 1000 psi): 7206 psi OA Pressure: Monitor – Rigup bleed hose and/or PRV Max Anticipated Proppant Loading: 8 PPA I added the N2 POP-off, but missed pulling the global kickout out of this table on page 13 of the application. SLBs new frac pump do not use the global kickouts anymore. Let me know if you want to discuss further. -Michael From: Lau, Jack J (OGC) <jack.lau@alaska.gov> Sent: Wednesday, August 6, 2025 1:54 PM To: Michael Hibbert <michael.hibbert@hilcorp.com > Subject: [EXTERNAL] Well: NK-19A PTD: 201-070 Michael – Reviewing your frac program for NK-19A, do you intent to use a global or treating PRV in addition to the pump kick outs? Also need the test pressure for that. Usually is included in fracs. Thanks Jack Lau 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. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 3 Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission (907) 793-1244 Office (907) 227-2760 Cell The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU NK-19A (PTD No. 201-070; Sundry No. 325-458) Paragraph Sub-Paragraph Section Complete? AOGCC Page 1 August 26, 2025 (a) Application for Sundry Approval (a)(1) Affidavit Provided with application. A.Dewhurst 20AUG25 (a)(2) Plat Provided with application. A.Dewhurst 20AUG25 (a)(2)(A) Well location Provided with application. Well lies in Section 13 of T12N, R15E, UM. A.Dewhurst 20AUG25 (a)(2)(B) Each water well within ½ mile None: According to the Water Estate map available through DNR’s Alaska Mapper application, there are no wells are used for drinking water purposes are known to lie within ½ mile of the surface location. There are no subsurface water rights or temporary subsurface water rights within 19 miles of the surface location. A.Dewhurst 20AUG25 (a)(2)(C) Identify all well types within ½ mile Provided with application. A.Dewhurst 20AUG25 (a)(3) Freshwater aquifers: geological name; measured and true vertical depth None. The previous operator conducted a study of 4 wells and determined that there are no freshwater aquifers present. A.Dewhurst 26AUG25 (a)(4) Baseline water sampling plan None required A.Dewhurst 26AUG25 (a)(5) Casing and cementing information Provided with application. Schematic attached. CDW 08/19/2025 (a)(6) Casing and cementing operation assessment See (a)(6(B) below NK-19 10-3/4” surface casing cemented to surface with good returns. NK-19 For 7-5/8” volumetric calc shows TOC 5232 ft. NK-19A sidetrack mill out of bottom of 7-5/8” casing from whipstock. 4.5” tubing will be anchored with two packers one at 7852 ft and the liner top packer at 7907 ft. 4.5” liner was cemented. CDW 08/19/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU NK-19A (PTD No. 201-070; Sundry No. 325-458) Paragraph Sub-Paragraph Section Complete? AOGCC Page 2 August 26, 2025 Upper frac is 9910 ft perforations. No issues with cement for the upcoming stimulation. (a)(6)(A) Casing cemented below lowermost freshwater aquifer and conforms to 20 AAC 25.030 No freshwater aquifers present. (See Section (a)(3), above.) No. The targeted Brookian hydrocarbons have less than the required 500’ MD of cement above them. Variance has been requested. Recommend granting variance as planned frac height is still below TOC. A.Dewhurst 26AUG25 (a)(6)( B) Each hydrocarbon zone is isolated Yes. The hydrocarbons associated with the Brookian target amd both the Raven and Niakuk pools are isolated by the 4-1/2” production liner cement. A.Dewhurst 20AUG25 (a)(7) Pressure test: information and pressure-test plans for casing and tubing installed in well Provided with application. 3500 psi MITIA, 3500 psi MITT. CDW 08/19/2025 (a)(8) Pressure ratings and schematics: wellbore, wellhead, BOPE, treating head Provided with application. 10 or 15K psi treesaver. Maximum frac. Pressure anticipated as 5950 psi (MAWP of 6206 psi w 3025 psi IA hold). Pump knock out 5585-5896 psi and GORV 5896 psi., N2 popoff 6206, lines test 7206 psi. CDW 08/19/2025 (a)(9)(A) Fracturing and confining zones: lithologic description for each zone (a)(9)(B) Geological name of each zone (a)(9)(C) and (a)(9)(D) Measured and true vertical depths (a)(9)(E) Fracture pressure for each zone Upper confining zones: over 1,000’ TVD of shales and silts of Upper Hue Shale and Colville Mudstones (CM3). Fracture gradient of 0.71 psi/ft (13.7 ppg EMW). Fracturing Zone: 92’ thick zone of sands and shales of the Upper Hue A-sand between 9,913’ MD and 10,083’ MD. Fracture gradient expected to be about 0.66 psi/ft (12.7 ppg EMW). Lower confining zones: about 90’ TVD of Upper Hue A shales. Fracture gradient expected to be about 0.71 psi/ft (13.7 ppg EMW). A.Dewhurst 21AUG25 (a)(10) Location, orientation, report on mechanical condition of each well that It is highly unlikely that any of the wells or wellbores within a ½-mile radius will interfere with hydraulic fracturing fluids CDW 08/19/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU NK-19A (PTD No. 201-070; Sundry No. 325-458) Paragraph Sub-Paragraph Section Complete? AOGCC Page 3 August 26, 2025 may transect the confining zones and sufficient information to determine wells will not interfere with containment of hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory from this operation because of cement isolation and / or separation distance. Hilcorp has identified 75 wells within ½ mile of surface wellbore, and 9 wells within the ½ mile of confining zone penetration. Frac half length est 180 ft. Hilcorp provided cement details – indicating isolation of the Brookian frac. The PBU NK-12 offset well does not have isolation across the Brookian, though it is well beyond the planned frac half-length. A.Dewhurst 26AUG25 (a)(11) Faults and fractures, Sufficient information to determine no interference with containment of the hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory Yes. The operator has identified four faults within a ½-mile radius of the fracturing zone. It is unlikely that any faults will interfere with the containment of injected fracturing fluids; however, if there are indications that a fracture has intersected a fault or natural-fracture interval during frac operations, the operator will go to flush and terminate the stage immediately. Detailed descriptions are provided in the application. A.Dewhurst 26AUG25 (a)(12) Proposed program for fracturing operation Provided with application. CDW 08/19/2025 (a)(12)(A) Estimated volume Provided with application. 2500 bbl total dirty vol. 237K lb total proppant CDW 08/19/2025 (a)(12)(B) Additives: names, purposes, concentrations Provided with application. CDW 08/19/2025 (a)(12)(C) Chemical name and CAS number of each Provided with application. Schlumberger disclosure provided. CDW 08/19/2025 (a)(12)(D) Inert substances, weight or volume of each Provided with application. CDW 08/19/2025 (a)(12)(E) Maximum treating pressure with supporting info to determine appropriateness for program Simulation shows max surface pressure 2400 psi anticipated. Max. 6206 psi allowable treating pressure. Max pressure is 5585-5896 psi to Pump shutdown. With 3,025 psi back CDW 08/19/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU NK-19A (PTD No. 201-070; Sundry No. 325-458) Paragraph Sub-Paragraph Section Complete? AOGCC Page 4 August 26, 2025 pressure IA (IA popoff set 3,325 psi), max tubing differential should be2,881 psi. (a)(12)(F) Fractures – height, length, MD and TVD to top, description of fracturing model Provided with application. The anticipated half-lengths of the induced fractures are 150’-180’ according to the Operator’s computer simulation. Computer simulation indicates the anticipated height of the induced fractures will be 165’, so induced fractures may penetrate into, but should not penetrate through, the overlying confining zone. A.Dewhurst 26AUG25 (a)(13) Proposed program for post-fracturing well cleanup and fluid recovery Well cleanout and flowback procedure provided with application. Disposal options available. CDW 08/19/2025 (b)Testing of casing or intermediate casing Tested >110% of max anticipated pressure 3025 psi back pressure, tested to 3500 psi, popoff set as 3325 psi CDW 08/19/2025 (c) Fracturing string (c)(1) Packer >100’ below TOC of production or intermediate casing 4.5” tubing will be anchored with two packers one at 7852 ft and the liner top packer at 7907 ft. 4.5” liner was cemented. Upper frac is 9910 ft perforations. For 7-5/8” estimated TOC (volumetrics) of 5232 ft. No issues with cement for the upcoming stimulation. CDW 08/19/2025 (c)(2) Tested >110% of max anticipated pressure differential Tubing test of 3500 psi. Max pressure differential is estimated as 3181 psi (6206 with 3025 psi backpressure) so test of 3500 psi satisfies 110% CDW 08/19/2025 (d) Pressure relief valve Line pressure <= test pressure, remotely controlled shut-in device 7206 psi line pressure test, max. allowable treat pressure = 6206 psi, pump knock out 5585-5896 and 5896 global kickout and N2 popoff 6206 psi.. IA PRV set as 3325 psi. CDW 08/19/2025 (e) Confinement Frac fluids confined to approved formations Provided with application. CDW 08/19/2025 (f) Surface casing pressures Monitored with gauge and pressure relief device IA PRV set at 3325 psi. Surface annulus open. Frac pressures continuously monitored. CDW 08/19/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU NK-19A (PTD No. 201-070; Sundry No. 325-458) Paragraph Sub-Paragraph Section Complete? AOGCC Page 5 August 26, 2025 (g) Annulus pressure monitoring & notification 500 psi criteria During hydraulic fracturing operations, all annulus pressures must be continuously monitored and recorded. If at any time during hydraulic fracturing operations the annulus pressure increases more than 500 psig above those anticipated increases caused by pressure or thermal transfer, the operator shall: CDW 08/19/2025 (g)(1) Notify AOGCC within 24 hours (g)(2) Corrective action or surveillance (g)(3) Sundry to AOGCC (h) Sundry Report (i) Reporting (i)(1) FracFocus Reporting (i)(2) AOGCC Reporting: printed & electronic (j) Post-frac water sampling plan Not required (see Section (a)(3), above). A.Dewhurst 26AUG25 (k) Confidential information Clearly marked and specific facts supporting nondisclosure Non-confidential well. A.Dewhurst 26AUG25 (l) Variances requested Modifications of deadlines, requests for variances or waivers No plan for post fracture water well analysis. Commission may require this depending on performance of the fracturing operation. 7. Property Designation (Lease Number): 1. Operations Performed: 2. Operator Name: 3. Address: 4. Well Class Before Work:5. Permit to Drill Number: 6. API Number: 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): Susp Well Insp Install Whipstock Mod Artificial Lift Perforate New Pool Perforate Plug Perforations Coiled Tubing Ops Other Stimulate Fracture Stimulate Alter Casing Pull Tubing Repair Well Other: Change Approved Program Operations shutdown 11. Present Well Condition Summary: Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 16. Well Status after work: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. OIL GAS WINJ WAG GINJ WDSPL GSTOR Suspended SPLUG Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: PBU NK-19A Dump/ Bail Cmt Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 201-070 50-029-22507-01-00 12372 Conductor Surface Intermediate Production Liner 10169 80 4185 7982 4475 10190 20" 10-3/4" 7-5/8" 4-1/2" 8578 35 - 115 34 - 4219 33 - 8015 7897 - 12372 35 - 115 34 - 4106 33 - 7307 7207 - 10169 none 470 2480 4790 7500 10190, 11022 , 11234 , 11950 1490 5210 6890 8430 9910 - 12140 4-1/2" 12.6# L-80 32 - 7915 8428 - 9963 Structural 4-1/2" Baker SABL-3 , 7855 , 7172 7855 7172 Bo York Operations Manager Eric Dickerman Eric.Dickerman@hilcorp.com (907) 564-5258 PRUDHOE BAY / NIAKUK OIL , BROOKIAN UNDEFINED OIL Total Depth Effective Depth measured true vertical feet feet feet feet measured true vertical measured measured feet feet feet feet measured true vertical Plugs Junk Packer Measured depth True Vertical depth feet feet Perforation depth Tubing (size, grade, measured and true vertical depth) Packers and SSSV (type, measured and true vertical depth) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a.Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: Subsequent to operation: 15. Well Class after work: Exploratory Development Service StratigraphicDaily Report of Well Operations Copies of Logs and Surveys Run Electronic Fracture Stimulation Data Sundry Number or N/A if C.O. Exempt: ADL 0034635, 0034630 32 - 7222 0 0 0 0 0 0 1107 0 530 0 323-556 13b. Pools active after work:BROOKIAN UNDEFINED OIL STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS Sr Pet Eng: Sr Pet Geo: Form 10-404 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Sr Res Eng: Due Within 30 days of Operations No SSSV Installed By Grace Christianson at 3:40 pm, May 16, 2024 Digitally signed by Bo York (1248) DN: cn=Bo York (1248) Date: 2024.05.15 14:43:20 - 08'00' Bo York (1248) RBDMS JSB 052124 DSR-5/20/24WCB 8-29-2024 ACTIVITYDATE SUMMARY 10/26/2023 ****WELL S/I ON ARRIVAL**** (Perforating) SET 4 1/2" WHIDDON ON PX PLUG @ 7,876' MD PULLED OGLV & SET BEK FLOWSLEEVE IN ST #1 (7,761' MD) LRS LOADED TBG & IA w/ 350BBLS DIESEL LRS PERFORMED C-MIT(pass) ***CONTINUED ON 10/27/23 WSR*** 10/26/2023 T/I/O= 489/499/443 LRS 72 Assist Slickline (PERFORATING). Pumped 350 bbls Diesel down TBG, taking returns up IA to NK-65 FL. Perform CMIT - TxIA CMIT-TxIA: Pumped 3.6 bbls DSL to achieve MAP of 2750 psi. 2755/2755/445. TBG/IA lost 31/33 psi 1st 15 min, lost 1/1 psi 2nd 15 min. 2723/2721/445 CMIT-TxIA = PASSED Bled TBG/IA down to 524/526 psi (3.2 bbls) ***Job Continued to 10-27-2023*** 10/27/2023 ***Continue Job from 10-26-2023*** Assist Slickline (PERFORATING) Perform MIT-T MIT-T: 1145/913/439. Pumped 0.91 bbls Diesel to achieve MAP of 2750 psi. TBG lost 110 psi 1st 15min, lost 34 psi 2nd 15 min. 2607/1008/440 MIT-T = PASSED. Bled back .7 bbls to 1007/917/440 Freeze protect NK-65 FL w/ 5 bbls 60/40, pressured to 1500 psi. SL in control of well and DSO notified upon LRS departure. 10/27/2023 ***CONTINUED FROM 10/26/23 WSR*** PULLED FLOW SLEEVE & SET BK-OGLV IN ST #1 (7,761' MD) LRS PERFORMED MIT-T (Pass) PULLED EMPTY WHIDDON CATCHER FROM PX PLUG AT 7,879' MD PULLED PX-PLUG FROM X-NIP @ 7,879' MD DRIFTED WITH 36' x 3-3/8" DUMMY GUNS(w/ 3.66" swell rings) TO 11,500' SLM ****WELL LEFT S/I ON DEPARTURE, DSO NOTIFIED OF STATUS**** 11/15/2023 T/I/O=2400/1000/500 Temp=S/I (TFS Unit 4 Assist E-Line with Load and Test) Pumped 3 bbls of 60/40 followed by 39 bbls of DSL in attempt to load TBG. E-Line left in control of well upon departure. Final WHPS 2400/800/500 11/15/2023 T/I/O=2500/850/450 (Assist E-Line) TFS U-3, Pumped 8 bbls DSL assisting E-line. Pressure Tested CIBP to 3000 psi **PASS**. FWHP= 1000/825/400 EL still on well upon deparure. Daily Report of Well Operations PBU NK-19A ) Perform CMIT - TxIAg CMIT-TxIA: Pumped 3.6 bbls DSL to achieve MAP of 2750 psi. 2755/2755/445. TBG/IA lost 31/33 psi 1st 15 min, lost 1/1 psi 2nd 15 min. 2723/2721/445 CMIT-TxIA = PASSED (g) SET 4 1/2" WHIDDON ON PX PLUG @ 7,876' MD@ PULLED OGLV & SET BEK FLOWSLEEVE IN ST #1 (7,761' MD) LRS LOADED TBG & IA w/ 350BBLS DIESEL Passing combo as per Sundry 323-556. -WCB Daily Report of Well Operations PBU NK-19A 11/15/2023 **** WELL SHUT IN ON ARRIVAL ****** INITIAL T/I/O = 2420/1000/500 RIG UP TBIRD TO PUMP. PT TO 300 PSI LOW, HIGH 3500PSI. AFTER 39 BBL DIESEL AT 3200PSI AND 0.7 BPM DECIDE WELL IS FLUID PACKED. BLEED OFF THROUGH 1/2" HOSE FOR 10 MINS AND SEE NO GAS RETURNS. CLOSE IN BLEED RIH WITH 1-11/16" HEAD/3-1/8" GUN GAMMA/BAKER #10/PLUG (MAX OD 3.62") OAL: 15' HANGING WEIGHT: 200# AT 100 FPM PLUG BECAME STUCK WHILE PULLING CORRELATION LOG. AFTER WORKING AND MOVING IT SOME, DECIDED TO SET IN PLACE. SAT BACK DOWN TO FIND DEPTH OF PLUG AFTER GETTING FREE. SET PLUG AT 11234 FT. CCL TO SENTER PLUG: 11.3 FT. PT AGAINST PLUG TO 3000PSI FOR 10 MINUTES. BEGINNING PSI 3000/925/425; FINAL PSI 2900/925/425. BLEED DOWN TUBING TO 1000 PSI LAY DOWN LUBE FOR NIGHT. FINAL T/I/O = 1000/925/425 PSI **** JOB CONTINUED ON 16-NOV-2023 WSR ***** 11/16/2023 *** JOB CONTINUED FROM 15-NOV-2023 **** INITIAL T/I/O = 2000/1000/500 PSI RUN 30' X 2.5" BAILER WITH 6 GAL OR WATER TO DISPLACE SOME DIESEL AT DUMP DEPTH. RUN 30' X 2.5" BAILER WITH 6 GAL OF CEMENT (16 GAL TOTAL NEEDED TO ACHIEVE 25 FT ABOVE PLUG) RDMO LOCATION. FINAL T/I/O = 800/600/500 PSI *** JOB COTINUED ON 18-NOV-2023 ***** 11/18/2023 **** JOB CONTINUED FROM 16-NOV-2023 ***** INITIAL T/I/O = 2000/750/450 CONTINUED DUMPING CEMENT ON TOP OF PLUG. 2 ADDITIONAL RUNS OF 30' X 2.5" BAILER WITH 6 GAL OF CEMENT (16 GAL TOTAL TO ACHIEVE 25 FT OF CEMENT ABOVE PLUG) HEAD/2" 7' WB/ 3-1/8" CCL/ 30' 2.5" BAILER (HOLDS ~6 GAL OF CEMENT). DUMPED TOTAL 18 GAL CMT ABOVE PLUG RDMO LOCATION. FINAL T/I/O = 500/500/400 *** JOB COMPLETED*** RUN 30' X 2.5" BAILER WITH 6 GAL OR WATER TO DISPLACE SOME DIESEL AT DUMP DEPTH. RUN 30' X 2.5" BAILER WITH 6 GAL OF CEMENT (16 GAL TOTAL NEEDED TO ACHIEVE 25 FT ABOVE PLUG) DUMPED TOTAL 18 GAL CMT ABOVE PLUG CONTINUED DUMPING CEMENT ON TOP OF PLUG. 2 ADDITIONAL RUNS OF 30' X 2.5" BAILER WITH 6 GAL OF CEMENT (16 GAL TOTAL TO ACHIEVE 25 FT OF CEMENT ABOVE PLUG) SET PLUG AT 11234 FT Daily Report of Well Operations PBU NK-19A 11/25/2023 ***WELL S/I ON ARRIVALL*** DRIFT TO XN-NIP w/3.79'' G-RING @ 7895'SLM/7900'MD (+5' correction) PERFORMED AOGCC WITNESED CEMENT TAG, w/ 2.50'' S-BAILER TAG @ 11213'SLM / 11218'MD (RECOVERED CEMENT SAMPLE) CEMENT 9' SHY OF REQUIRED 25' ***WELL LEFT S/I ON DEPARTURE*** 11/27/2023 ***WELL SHUT IN ON ARRIVAL*** PT PCE 200LP-3000HP RIH with 1 7/16" Cable Head, 2" X 7' Weight Bar, 3 1/8" CCL, 3" X 30' Dump Bailer (Max OD = 3" , Max Lenth = 42') Tagged bottom with bailer @ 11,211' ***WELL SHUT IN ON DEPARTURE*** Job continued on 11/28/2023 11/28/2023 Job continued from 11/27/2023 ***WELL SHUT IN ON ARRIVAL*** PT PCE 200LP - 3000HP RIH with 1 7/16" CABLE HEAD, 2" WEIGHT BAR, 3 1/8 CCL, 3" x 30' DUMP BAILER (MAX OD = 3.125 , MAX LENTH = 42') DUMP BAIL CEMENT BAILER RUN #1 : TAGGED ELMD @ 11,211' AND DUMPED 2 CEMENT KITS ON BOTTOM. BAILER RUN #2 : STOPPED W/L ELMD @ 11,198' AND DUMPED 2 CEMENT KITS ABOVE PREVIOUS RUNS FILL. (5 GAL CMT / KIT = 20 GAL 15.8 ppg Class G CMT) RIG DOWN/MOVE OFF ***LEFT WELL SHUT IN ON DEPARTURE*** 12/1/2023 T/I/O = 1220/540/450. Temp = SI. T FL (pre AOGCC). Flowline & AL disconnected. T FL @ surface. SV, WV, SSV = C. MV = O. IA, OA = OTG. 06:30 12/1/2023 ***WELL S/I ON ARRIVAL*** RAN 3.80" G-RING TO 7,846' SLM, UNABLE TO WORK TOOLS PAST.(state rep is good with same unit correction from last week)(rep: Austin McLeod) RAN 5' x 2-1/4" DRIVE DOWN BAILER(msfb) TO 7,846' SLM. UNABLE TO WORK TOOLS PAST SPOT. LRS PERFORMED PASSING AOGCC WITNESSED MIT-T(see LRS log). MADE MULTIPLE 5' x 2-1/4" D.D. BAILER(msfb) & 5' x 3'' D.D. BAILER(msfb) FROM ~7889' SLM TO ~8190' SLM (recovered ~7gal cement, cont bailing on next day, see log) ***WSR CONT ON 12-02-23*** 12/1/2023 T/I/O = 516/638/446 ( ANN-COMM ) AOGCC MIT-T Witnessed by Austin Mcleod. Pumped 0.9 bbls crude down TBG @ 2760 psi, start test. After the fist 15 min TBG lost 64 psi @ 2696 psi. Second 15 min TBG lost 21 psi @ 2675 psi. Bled 1.5 bbls from TBG @ 1200 psi. FWHP = 1200/557/449 @() PERFORMED AOGCC WITNESED CEMENT TAG, w/ 2.50'' S-BAILER TAG @ 11213'SLM / 11218'MD (RECOVERED CEMENT SAMPLE)( CEMENT 9' SHY OF REQUIRED 25' LRS PERFORMED PASSING AOGCC WITNESSED MIT-T(see LRS log ( DUMP BAIL CEMENT BAILER RUN #1 : TAGGED ELMD @ 11,211' AND DUMPED 2 CEMENT KITS ON BOTTOM. BAILER RUN #2 : STOPPED W/L ELMD @ 11,198' AND DUMPED 2 CEMENT KITS ABOVE PREVIOUS RUNS FILL. Daily Report of Well Operations PBU NK-19A 12/2/2023 ***WSR CONT FROM 12-1-23*** RAN 5' x 3'' D.D. BAILER(msfb) WORK THRU 8191' SLM & 8288' SLM, WORK TIGHT SPOTS @ ~8620' SLM & ~8685' SLM, WORK MULTIPLE SPOT IN TBG (possibly cement stringers) S/D @ 11,188' SLM RAN 2' 1-7/8'' STEM, 4-1/2'' BLB, 3.80'' G-RING, TAG XN-NIP @ 7893' SLM' / 7900' MD (+7' CORR) RAN 2' 1-7/8'' STEM, 4-1/2'' BLB, 3.70'' G-RING WORK THRU MULTIPLE AREAS FROM 8300' SLM TO 9500' SLM ***WELL LEFT S/I ON DEPARTURE, DSO NOTIFED OF WELL STATUS*** 12/2/2023 ***WELL S/I ON ARRIVAL*** (Perforating) RAN 5'x2" DD BAILER, WORK THROUGH BRIDGES & TAG CEMENT AT 11,180' SLM (full of wet cement) RAN 3.65" GAUGE RING, WORK THROUGH BRIDGES TO TAG AT 11,172' SLM RAN 10'x3" PUMP BAILER TO 11,191' SLM (Full of wet cement) RAN 3.78" GAUGE RING TO TAG XN AT 7,882' SLM (7,900' MD, +18' CF) ***CONTINUED ON 12/3/23 WSR*** 12/3/2023 ***CONTINUED FROM 12/3/23 WSR*** (Perforating) BAILED CEMENT DOWN TO 11,201' SLM(11,219' MD)(Hard tag, recovered 5 gallons total) ***WELL S/I ON DEPARTURE*** 12/5/2023 ***WELL SHUT IN ON ARRIVAL*** PT PCE 200LP - 3000HP RIH with 1 7/16" CABLE HEAD, 2" WEIGHT BAR, 3 1/8" GR/CCL, 3" x 30' DUMP BAILER (MAX OD = 3.125 , MAX LENTH = 42') DUMP BAIL CEMENT & CASING CLEANER BAILER RUN #1: DUMPED 2 CASING CLEANER KITS @ELMD 11218 BAILER RUN #2 : DUMPED 2 CEMENT KITS @ ELMD 11205 (5 GAL CMT / KIT = 10 GAL 15.8 ppg Class G CMT) ***LEFT WELL SHUT IN ON DEPARTURE*** JOB CONTINUED ON 12-6-2023 12/6/2023 Job continued from 12-6-2023 ***WELL SHUT IN ON ARRIVAL*** PT PCE 200LP - 3000HP RIH WITH 1 7/16" CABLE HEAD, 2" WEIGHT BAR, 3 1/8" GR/CCL, 3" x 30' DUMP BAILER (MAX OD = 3.125 , MAX LENTH = 42') BAILER STOPPED 400' SHORT OF BOTTOM RIG DOWN/MOVE OFF ***WELL SHUT IN ON DEPARTURE*** 12/10/2023 ***WELL S/I ON ARRIVAL***(drift/bail) RAN 10' x 2.25" DRIVE DOWN BAILER TO 6,620' SLM, UNABLE TO WORK PAST (see log, recover approx 1/4 cup of hard cement) RAN 2.315" CENT, 10' x 1.75" DRIVE DOWN BAILER TO 6,620' WORK TOOLS TO 6,629' SLM.(broke thru stopped at cent) ***LDFN, CONT WSR ON 12/11/23*** (g) BAILED CEMENT DOWN TO 11,201' SLM(11,219' MD)(Hard tag, recovered 5 gallons total) Daily Report of Well Operations PBU NK-19A 12/11/2023 ***CONT WSR FROM 12/10/23***(drift/bail/clean out) RAN 8' x 1.5" STEM, 2.34" GAUGE RING, WORK THROUGH CEMENT BRIDGES, S/D @ 6,652' SLM RAN 8' x 1.5" STEM, 2.22" GAUGE RING, WORK THROUGH CEMENT BRIGES, S/D @ 11,180' SLM (see log) RAN 8' x 1.5" STEM, 2.48" GAUGE RING, S/D @ 11,180' SLM RAN 8' x 1.5" STEM, 3.5" STIFF BRUSH, 2.80" GAUGE RING, CLEAN UP RESTRICTION @ 6,620' SLM, S/D @ 11,180' SLM RAN 8' x 1.5" STEM, 4.5" BRUSH, 3.50" GAUGE RING, CLEAN UP TBG S/D @ 11,180' SLM (see log) ***WELL LEFT S/I ON DEPARTURE, TURNED OVER TO POLLARD SL*** 12/11/2023 ***WELL S/I ON ARRIVAL*** RAN 4-1/2'' BLB, 3.64'' G. RING WORK FROM 4,380' SLM TO 6,700' SLM, DRIFT TO 11,176' SLM ***WSR CONT. ON 12-13-2023*** 12/12/2023 ***WSR CONT. FROM 12-11-2023*** RAN 4-1/2'' BLB, 3.74'' G. RING TO WORK THROUGH TIGHT SPOTS FROM 4300' SLM TO 6800' SLM RAN MULTIPLE 2.50" P. BAILER RUNS, BAIL DOWN TO 11,204' SLM/11,209' MD RAN 5' x 2.25" DRIVE DOWN BAILER, TAGGED 11,204/11,209' MD, DROVE BAILER TO 11,209' SLM/11,214' MD(dirty cement) ***WELL LEFT S/I ON DEPARTURE, DSO NOTIFIED OF WELL STATUS*** 12/14/2023 SLB CTU #9 - 1.75" CT - 0.156WT. Job Scope: FCO, Cmt Plug MIRU CTU 9. MU slb 2.45" JSN BHA. RIH. Tag @ 11,188 ' CTM / 11,230' Mech. PUH start jetting 2.3 bpm. Cir out all Diesel. Cir out all the Gas. Tag hard same spot 11,188'. Pump 17 bbl sweep. Chase OOH. Reciprocate thru 7900' - 7800' & 6700' - 6550'. Cont' chase gel OOH. At surface, break down SLB JSN and RBIH w/ cementing BHA. Dry tag @ Elec = 11,198' / Mech = 11,221' (Weight back at 11,191' Elec). PU to 11,181' CTMD and prepare to pump cmt. PJSM. Pump 2 bbls 60/40 spear, 5 bbls Fresh Water, 4.1 bbls 15.8 ppg Class G Cement, 5 bbls Fresh Water and displace w/ Slick 1% KCl. ***Job In Progress*** 12/15/2023 SLB CTU #9 - 1.75" CT - 0.156WT. Job Scope: FCO, Cmt Plug Continue displacing 15.8 ppg Class G Cement w/ Slick 1% KCl. Lay-in 4.1 bbls cmt. PU to safety. Pump 27 bbls PowerVis to down CTBS for cmt contam and reverse clean out. PU to 10,950' CTMD and roll WB to DSL POOH. RDMO CTU 9. ***Job Complete*** 12/18/2023 *** WELL S/I ON ARRIVAL *** RAN 3" SAMPLE BAILER & 3.50" CENT S/D AT 11,006 SLM(no sample) RAN 1.75" SAMPLE BAILER & 2.50" CENT TAG CEMENT AT 11014' SLM + 29' RKB CORR = 11043' MD (STATE WITNESS- JOSH HUNT) LRS PERFORM MIT-T (2500PSI PASS) STATE WITNESS- JOSH HUNT) DRIFT 36' X 3.66" DUMMY GUN S/D AT 7620' SLM RIH W/ 30' X 3.16 DMY GUN DRIFT S/D @ 11,020'SLM = 11,049'MD *** WELL LEFT S/I ON DEPARTURE *** 12/18/2023 T/I/O=136/0/417 ***MIT-T PASSED TO 2532 PSI*** (Witnessed by AOGCC Inspector Josh Hunt) Pumped 2.9 bbls Crude into TBG to reach test pressure. Loss of 139 psi 1st 15 min. Loss of 39 psi 2nd 15 min for a total loss of 278 psi. during 30 min test. Bled back 2.8 BBLS. FWHP=1324/60/420 Casing valves OTG RAN 3" SAMPLE BAILER & 3.50" CENT S/D AT 11,006 SLM(no sample)() RAN 1.75" SAMPLE BAILER & 2.50" CENT TAG CEMENT AT 11014' SLM + 29' RKB CORR = 11043' MD (STATE WITNESS- JOSH HUNT) RAN MULTIPLE 2.50" P. BAILER RUNS, BAIL DOWN TO 11,204' SLM/11,209' MD RAN 5' x 2.25" DRIVE DOWN BAILER, TAGGED 11,204/11,209' MD, DROVE BAILER TO 11,209' SLM/11,214' MD(dirty cement) Daily Report of Well Operations PBU NK-19A 12/19/2023 ***WELL S/I ON ARRIVAL*** PT PCE 250LP-3000HP TOWN CONFIRMATION FOR CORRELATION PASS. PERFORATE FROM 10259' - 10290' MD WITH 2.75 X 31' GEO RAZOR GUN, 6 SPF, 60 DEG PHASED. CCL STOP DEPTH=10251.3' MD, CCL TO TS=7.7' PERFORATE FROM 10228' - 10259'' MD WITH 2.75" X 31' GEO RAZOR GUN, 6 SPF, 60 DEG PHASED. CCL STOP DEPTH=10220.3' MD, CCL TO TS=7.7' MD. PERFORATE FROM 10205' - 10228' MD WITH 2.75X 23' GEO RAZOR GUN, 6 SPF, 60 DEG PHASED. CCL STOP DEPTH=10196.1', CCL TO TS=8.9' NO CHANGE TO TUBING PRESSURE DURING PERFORATING. ***READY FOR SLICKLINE*** 12/19/2023 ***WELL S/I ON ARRIVAL*** ROUND UP TOOLS & TRAVEL. ***WSR CONTINUED ON 12-20-23*** 12/20/2023 ***WSR CONTINUED FROM 12-19-23*** RAN 3.50" CENT, AND 1.75" SAMPLE BAILER, TAGGED @ 11,022' SLM. SOFT CEMENT SAMPLE RECOVERED. SET DUAL SPARTEK GAUGES IN 106" OAL GAUGE CARRIER ASSY W/ 3 1/2" "FIT" G FISHNECK @ 11,043' MD MAKING 5 MINUTES STOPS ON THE WAY DOWN PER PROGRAM ***WELL S/I ON DEPARTURE*** ****** IF 3 1/2" GS IS USED TO PULL GAUGE CARRIER ASSY, SHORT CORE, AND "FIT" SKIRT FROM WLB ARE REQUIRED... STANDARD 3 1/2" GS WILL NOT SHEAR****** 12/21/2023 LRS Welltesting Unit #1. Begin WSR on 12/21/23. Unit Move to NK DS. NK-19 Brookian Well Test. IL NK-19, OL NK-65. Begin RU, SB for GC, Cont. RU, Continue WSR on 12/22/23. 12/22/2023 LRS Welltesting Unit #1. Continue WSR from 12/21/23. NK-19A Brookian Well Test. IL NK-19, OL NK-65. Continue RU, PT, SB for SSSV install. Pop. Continue WSR on 12/23/23. 12/23/2023 T/I/O = 320/1760/460. Temp = SI. T & IA FL (WT). PBGL SI @ CV. T FL @ 310' (5 bbls). IA FL @ 6772' (sta # 2 DMY). LRS in control of valves upon departure. 06:00 12/23/2023 T/I/O = 1920/1920/491. Temp = SI. T & IA FL (WT). PBGL online. T FL @ 6950' (3255' above perfs). IA FL @ 7761' (sta # 1 SO). LRS in control of valves upon departure. 21:00 12/23/2023 LRS Welltesting Unit #1. Continue WSR fro12/22/23. NK-19A Brookian Well Test. IL NK-19, OL NK-65. Continue to Stack well out and POP to tanks. Continue WSR on 12/24/23. 12/24/2023 LRS Welltesting Unit #1. Continue WSR from 11/23/23. NK-19A Brookian Well Test. IL NK-19, OL NK-65. Continue to Stack out well for drawdown. POP NK-19. S/I GL to bleed tubing and IA down to 250 psi for Fluid level shot. Continue WSR on 12/25/23. PBGL online. T PERFORATE FROM 10259' - 10290' MD PERFORATE FROM 10228' - 10259'' MD LRS Welltesting Unit #1. Begin WSR on 12/21/23. Unit Move to NK DS. NK-19g Brookian Well Test PERFORATE FROM 10205' - 10228' MD Daily Report of Well Operations PBU NK-19A 12/24/2023 T/I/O = 250/275/446. Temp = SI. TBG & IA FL's (WT). PBGL SI @ CV. 13:00 - TBG FL @ 7581', IA FL @ 7595'. 15:00 - TBG FL @ 7581', IA FL @ 7595'. 17:00 - TBG FL @ 7581', IA FL @ 7595'. LRS WT in control of well upon departure. 17:20 12/24/2023 T/I/O = 250/275/446. Temp = SI. T & IA FL's (WT). PBGL SI @ CV. IA FL @ 6696' (inflowed 1065' during IA bleed). T FL @ 7581' (2624' above perfs). LRS in control of valves upon departure. 11:00 Edit: 12/25/23 IA FL is actually @ 7595', initial IA shot was bad showing 6696', IA did not inflow 1065'. 12/25/2023 LRS Welltesting Unit #1. Continue WSR from 12/24/23. NKA-19 Brookian Well Test. IL NK-19, OL NK-65. Continue to flow Well to tanks and monitor for flow. No GL initiated, DHD to perform fluid shot, initiate GL to Stack out well and attempt to pop. Continue WSR on 12/26/23. 12/25/2023 ***ARRIVE ON LOCATION- WELL ON TEST** PULLED GAUGE CARRIER FROM 11,008' SLM. 12/25/2023 T/I/O = 780/810/450. Temp = SI. T & IA FL (WT & SL). PBGL SI @ BV. T FL @ 7520' (241' above sta # 1 SO). IA FL @ 7761' (sta # 1 SO). SL in control of valves upon departure. 20:30 12/25/2023 T/I/O = 0/250/440. Temp = SI. T & IA FL's (WT). PBGL SI @ CV. T FL @ 7275' (486' above sta# 1 SO). IA FL @ 7683' (98' above sta# 1 SO). LRS WT in conrol of valves upon departure. 12:00 12/26/2023 LRS Welltesting Unit #1. Continue WSR from 12/25/23. NKA-19 Brookian Well Test. IL NK019, OL NK-65. Repop failed, assist HL SL. STBY for E-line Continue WSR on 12/27/23. 12/26/2023 Assist Well Test Unit 1 LRS Unit 76 Freeze Protect Flowline NK-65/Outlet Well. Pumped 5 BBLS 60/40 down Flowline on NK-65. DSO notified of well status per LRS departure. 12/26/2023 ***WSR CONTINUED FROM DECEMBER 25TH 2023*** CONTINUED TO RIH TO PULL MEMORY GAUGES @ 11,008' SLM. RAN CENTRALIZER WITH SAMPLE BAILER. ***DEPART LOCATION- WELL SHUT IN*** 12/26/2023 ***WELL SHUT IN ON ARRIVAL*** PT PCE FROM 200LP - 3000HP RUN #1 - SET PLUG IN ZONE Plug Set Depth = 10,190' , CCL Offset = 11.1' , CCL Stop Depth = 10,178.9' RIG DOWN/MOVE OFF ***WELL SHUT IN ON DEPARTURE*** 12/27/2023 LRS Welltesting Unit #1. Continue WSR from 12/26/23. NKA-19 Brookian Well Test. IL NK-19, OL NK-65. Continue SB for SL. Continue WSR on 12/28/23. 12/28/2023 ***WELL SHUT IN ON ARRIVAL*** SPOT IN RIG UP MAKE READY FOR PERFORATIONS IN THE MORNING ***WELL LEFT SHUT IN ON DEPARTURE*** Job continued 12/29/23 12/28/2023 LRS Welltesting Unit #1. Continue WSR from 12/27/23. Brookian Well Test. IL NK- 19, OL NK-65. Continue SB for SL. Continue WSR on 12/29/23. RUN #1 - SET PLUG IN ZONE Plug Set Depth = 10,190' Daily Report of Well Operations PBU NK-19A 12/29/2023 Job continued from 12/28/2023 ***WELL SHUT IN ON ARRIVAL*** PT PCE 200LP - 3000HP RUN #1 - PERF #1 (30' Load) RIH with 1 7/16" Cable head, 3.125" GR/CCL, 2.75" Perf Guns (Max OD = 3.125' , Max Lenth = 44') Perf Shooting Depth = (10,016' - 10,046') , CCL Offset = 7.4' , CCL Stop Depth = 10,008.6' RUN #2 - PERF #2 (9' Load) RIH with 1 7/16" Cable head, 2" Weight bar, 3.125" GR/CCL, 2.75" Perf Guns (Max OD = 3.125' , Max Lenth = 22') Perf Shooting Depth = (10,007' - 10,016') , CCL Offset = 6.9' , CCL Stop Depth = 10,000.1 ***WELL LEFT SHUT IN ON DEPARTURE*** Job continued on 12/30/2023 12/29/2023 LRS Welltesting Unit #1. Continue WSR from 12/28/23. Bookian Well Test. IL NK-19, OL NK-65. Continue WSR for EL. Continue WSR on 12/30/23. 12/30/2023 ***WELL S/I ON ARRIVAL***(perforating) SET GAUGE CARRIER ASSEMBLY (3 1/2" "FIT" G-F.NECK, 106" oal) W/ GAUGE CARRIER & DUAL SPARTEC GAUGES ON CIBP @ 10,194' SLM **********STANDARD 3 1/2" GS WILL NOT SHEAR******** ***CONT WSR ON 12/31/23*** 12/30/2023 LRS Welltesting Unit #1. Continue WSR from 12/29/23. Brookian Well Test. IL NK- 19, OL NK-65. Continue SB for EL and SL. EL MIRU. EL RIH. EL RDMO. SL MIRU. SL RIH. Continue SB for SL. Continue WSR on 12/31/23. 12/30/2023 Job continued from 12/29/2023 ***WELL SHUT IN ON ARRIVAL*** PT PCE 200LP - 3000HP RUN #3 - PERF #3 (20' Load) RIH with 1 7/16" Cable head, 2" Weight bar, 3.125", GR/CCL, 2.75", Perf Guns (Max OD = 3.125' , Max Lenth = 42') Perf Shooting Depth = (9,960' - 9,980') , CCL Offset = 7', CCL Stop Depth = 9,953' RIG DOWN/MOVE OFF ***WELL SHUT IN ON DEPARTURE*** Job Complete RUN #3 - PERF #3 (20' Load) RIH with 1 7/16" Cable head, 2" Weight bar, 3.125", GR/CCL, 2.75", Perf Guns (Max OD = 3.125' , Max Lenth = 42') Perf Shooting Depth = (9,960' - 9,980') RUN #1 - PERF #1 (30' Load)() RIH with 1 7/16" Cable head, 3.125" GR/CCL, 2.75" Perf Guns (Max OD = 3.125' , Max Lenth = 44')) Perf Shooting Depth = (10,016' - 10,046') , RUN #2 - PERF #2 (9' Load)() RIH with 1 7/16" Cable head, 2" Weight bar, 3.125" GR/CCL, 2.75" Perf Guns (Max OD = 3.125' , Max Lenth = 22')) Perf Shooting Depth = (10,007' - 10,016') Daily Report of Well Operations PBU NK-19A 12/31/2023 ***CONT WSR FROM 12/30/23*** (perforating) RD HES 759 SLICKLINE UNIT ***WELL LEFT S/I UPON DEPARTURE, PAD OP NOTIFIED OF WELL STATUS*** ************MODIFIED GAUGE CARRIER ASSEMBLY W/ GAUGES IN WELL, NEEDS 3 1/2" FIT SKIRT W/ SHORT CORE FROM WLB TO PULL********************** 12/31/2023 LRS Welltesting Unit #1. Continue WSR from 12/30/23. Brookian WellTest. IL NK-19, OL NK-65. SL RU, SL RIH. Continue SB for SL. Pop well to tanks. Continue WSR on 01/01/24 1/1/2024 T/I/O=150/600/500 Assist Well Testers. Freeze Protect NK-19 TBG 40 bbls Crude. Freeze Protect NK-65 Flow Line 5 bbls 60/40 pressure up to 1500 psi. FWHP=303/600/500 Left well in Well Testers Control. Secure Tie In on Well Testers Pipe. 1/1/2024 LRS Welltesting Unit # 1. Continue WSR from 12/31/23. Brookian Well Test. IL NK- 19, OL NK-65. Flow liquid to tanks and Gas to Production. S/I NK-19 and 65 for FP. FP complete on NK-19 tubing, and NK-65 FL. GL S/I. BD, leave location. End WSR on 01/02/24. 1/8/2024 LRS Well testing unit #1, begin WSR 1/8/24. Flowback IL well NK-19 down OL well NK-65, Cont WSR 1/9/24 1/9/2024 LRS Test Unit #1. Continue WSR from 1/8/24. Flowback IL Well NK-19 Down OL Well NK-65. Continue WSR ON 1/10/24 1/10/2024 LRS Test Unit #1. Continue from 1/9/24 WSR. Flowback IL Well NK-19 / OL Well NK- 65. Continue to 1/11/24 WSR 1/11/2024 LRS Test Unit #1. Continue from 1/10/24 WSR. Flowback IL Well NK-19 / OL Well NK-65. Flow back well, BD,RD, Unit move, End WSR 1/16/2024 ** WEATHER STANDBY ** JOB CONTINUED ON 1-17-2024 1/17/2024 CONTINUED FROM 1-16-2024 *** WELL S/I ON ARRIVAL *** RIH W/ 3.5" GR W/ FIT SKIRT AND SHORT SKIRT TAG AND LATCH DH GAUGES @ 10,183'SLM, POOH. (off btm @ 11:38) RIH W/ 20' X 2 7/8 DMY GUNS TAG AND SD @ 10,148'SLM, POOH. *** WELL S/I ON DEPARTURE, DSO NOTIFIED *** Daily Report of Well Operations PBU NK-19A 3/24/2024 ***WELL S/I ON ARRIVAL*** OBJECTIVE: PERFORATE TWO INTERVAL W/2 7/8'' GEO RAZOR GUN 6 spf 60 DEG PHASE RIG UP YJ ELINE. PT PCE 300 PSI LOW /3000 PSI HIGH RUN #1 CH/2.75'' GUN GAMMA RAY CCL/ 2 7/8" X 12' GEO RAZOR GUN 6SPF 60 DEG PHASE TO PERFORATE INTERVAL 9995'-10007' CCL TO TOP SHOT 10.2' CCL STOP DEPTH 9984.8' RUN #2 CH/2.75'' GUN GAMMA RAY CCL/ 2 7/8" X 14' GEO RAZOR GUN 6SPF 60 DEG PHASE TO PERFORATE INTERVAL 9946'-9960' CCL TO TOP SHOT 9.2' CCL STOP DEPTH 9936.8' RUN #3 CH/2.75'' GUN GAMMA RAY CCL/ 2 7/8" X 14' GEO RAZOR GUN 6SPF 60 DEG PHASE TO PERFORATE INTERVAL 9932'-9946' CCL TO TOP SHOT 8.2' CCL STOP DEPTH 9923.8' GR-CCL CORRELATE TO AK-ELINE PERFORATING RECORD DATED 28-DEC- 2023 LAY DOWN FOR THE NIGHT ***CONTINUE JOB ON 3/25/24*** 3/25/2024 ***JOB CONTINUE FROM 3/24/2024*** OBJECTIVE: PERFORATE TWO INTERVAL W/2 7/8'' GEO RAZOR GUN 6 spf 60 DEG PHASE PT PCE 300 PSI LOW./3000 PSI HIGH RUN #4 CH/2.75'' GUN GAMMA RAY CCL/ 2 7/8" X 14' GEO RAZOR GUN 6SPF 60 DEG PHASE TO PERFORATE INTERVAL 9918'-9932' CCL TO TOP SHOT 9.2' CCL STOP DEPTH 9908.8' RUN #5 CH/2.75'' GUN GAMMA RAY CCL/ 2 7/8" X 8' GEO RAZOR GUN 6SPF 60 DEG PHASE TO PERFORATE INTERVAL 9910'-9918' CCL TO TOP SHOT 14.1' CCL STOP DEPTH 9895.9' GR-CCL CORRELATE TO AK-ELINE PERFORATING RECORD DATED 28-DEC- 2023 JOB COMPLETE ***WELL S/I ON DEPARTURE*** 3/25/2024 ***WELL S/I ON ARRIVAL***(set sbhps gauges, set wr-sssv) R/U HES-046 RIH W/ GAUGE CARRIER ASSEMBLY (3-1/2" "FIT G-FN, 106" oal) W/ DUAL SPARTEK GAUGES. ***CONT WSR ON 3-26-24*** RUN #2 CH/2.75'' GUN GAMMA RAY CCL/ 2 7/8" X 14' GEO RAZOR GUN 6SPF 60 DEG PHASE TO PERFORATE INTERVAL 9946'-9960' RUN #5 CH/2.75'' GUN GAMMA RAY CCL/ 2 7/8" X 8' GEO RAZOR GUN 6SPF 60 DEG PHASE TO PERFORATE INTERVAL 9910'-9918' RUN #4 CH/2.75'' GUN GAMMA RAY CCL/ 2 7/8" X 14' GEO RAZOR GUN 6SPF 60 DEG PHASE TO PERFORATE INTERVAL 9918'-9932' RUN #1 CH/2.75'' GUN GAMMA RAY CCL/ 2 7/8" X 12' GEO RAZOR GUN 6SPF 60 DEG PHASE TO PERFORATE INTERVAL 9995'-10007' All adperf depths are correctly shown on the WBS, below. -WCB RUN #3 CH/2.75'' GUN GAMMA RAY CCL/ 2 7/8" X 14' GEO RAZOR GUN 6SPF 60 DEG PHASE TO PERFORATE INTERVAL 9932'-9946' Daily Report of Well Operations PBU NK-19A 3/26/2024 ***CONT WSR FROM 3/25/24***(set dh sbhps guages/set ext-qos sssv) SET GAUGE CARRIER ASSEMBLY (3-1/2" "FIT G-FN, 106" oal) W/ DUAL SPARTEK GAUGES ON CEMENT @ 10,144' SLM RAN 4-1/2" BRUSH, 3.80" GAUGE RING, BRUSH TR-SVLN @ 2,071' MD PURGE 3 GAL HYDRO DOWN CONTROL LINE. ATTEMPT TO SET 4-1/2" X-LOCK, QOS EXT, 4-1/2" QOS IN HES CP2-TRSSSV (fall through trsssv, qos lih, see log) RAN 4-1/2" GS W/ 180' PRONG & PULLED QOS FROM 5727' SLM, UPPER STACK OF PACKING TORN, SMALL AMOUNT OF PARAFIN ON VALVE. BRUSHED TRSSSV @ 2,042' SLM (2,071' MD) FOR 45min. SET 4-1/2" QOS W/ EXT (SN: MQ405, 3 sets std pkg, 2nd lkdwn installed, control operated, oal lih = 179") IN TRSSSV @ 2,042' SLM (2,071' MD). GOT PASSING DRAW DOWN TEST ON SSSV. ***WELL LEFT S/I ON DEPARTURE, PAD OP NOTIFIED*** ****STANDARD 3-1/2" GS WILL NOT SHEAR, GET "FIT SKIRT AND SHORT CORE FROM WLB**** *****1.25" ROPE SOCKET (hes-046, H-2434), SOFT SET, DUAL SPARTEK SBHPS GUAGES PRGM FOR 1 SEC @ 30 DAYS -- BATTERY CONNECT TIME = 22:25 ON 3/25/24 ***** 3/30/2024 LRS Well Testing Unit #2. Begin WSR 03/30 /24, IL well NK-19A, OL NK-65 . RU,PT, Well Continue WSR on 03/31/24. 3/31/2024 LRS Well Testing Unit #2. Contiune WSR 03/31 /24, IL well NK-19A, OL NK-65 . RU,PT,POP Well Continue WSR on 04/1/24. 4/1/2024 LRS Well Testing Unit #2. Contiune WSR from 03/31/24, IL well NK-19A, OL NK-65 . FLow Well/Micromotion rate verification testing Continue WSR on 04/2/24. 4/2/2024 LRS Well Testing Unit #2. Contiune WSR from 04/1/24, IL well NK-19A, OL NK-65 . FLow Well/Micromotion rate verification testing Continue WSR on 04/3/24 4/3/2024 LRS Well Testing Unit #2. Contiune WSR from 04/2/24, IL well NK-19A, OL NK-65 . FLow Well/Micromotion rate verification testing Continue WSR on 04/4/24 4/4/2024 LRS Well Testing Unit #2. Contiune WSR from 04/3/24, IL well NK-19A, OL NK-65 . FLow Well/Micromotion rate verification testing Continue WSR on 04/5/24 4/5/2024 LRS Well Testing Unit #2. Contiune WSR from 04/4/24, IL well NK-19A, OL NK-65 . FLow Well/Micromotion rate verification testing Continue WSR on 04/6/24 4/6/2024 LRS Well Testing Unit #2. Contiune WSR from 04/4/24, IL well NK-19A, OL NK-65 . FLow Well/Micromotion rate verification testing Continue WSR on 04/6/24 4/7/2024 (PERFORATING) FP FL NK-65 for well testers outlet well. FP FL NK-65 pumped 5 BBLs of 60/40 preassured up to 1500 Psi secured well turned well over to DSO 4/7/2024 LRS Well Testing Unit #2. Contiune WSR from 04/6/24, IL well NK-19A, OL NK-65 . FLow Well/Micromotion rate verification testing, RD/ BD End WSR 4/7/24 Daily Report of Well Operations PBU NK-19A 4/17/2024 *** WELL S/I ON ARRIVAL *** PULLED EXTENED QOS SSSV FROM TRSSSV @2,071' MD PULLED SBHP GAUGES @ 10,144'SLM (OFF BTM 07:00AM) RUN READ 40 ARM CALIPER, TD 10,156' SLM, POOH 50'FPM TO SURFACE. *** WELL S/I ON DEPARTURE, DSO NOTIFIED *** 11043' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section:36 Township:12N Range:15E Meridian:Umiat Drilling Rig:N/A Rig Elevation:Total Depth:12,372 ft MD Lease No.:ADL 0034630 Operator Rep:Suspend:X P&A: Conductor:20"O.D. Shoe@ 115 Feet Csg Cut@ Feet Surface:10-3/4"O.D. Shoe@ 4219 Feet Csg Cut@ Feet Intermediate:O.D. Shoe@ Feet Csg Cut@ Feet Production:7-5/8"O.D. Shoe@ 8015 Feet Csg Cut@ Feet Liner:4-1/2"O.D. Shoe@ 12372 Feet Csg Cut@ Feet Tubing:4-1/2"O.D. Tail@ 7915 Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified Tubing Bridge plug 11,234 ft 11,014 ft 6.8 ppg Wireline tag Initial 15 min 30 min 45 min Result Tubing 2710 2571 2532 IA 0 0 0 OA 418 418 419 Remarks: Attachments: Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): December 18, 2023 Josh Hunt Well Bore Plug & Abandonment PBU NK-19A Hilcorp North Slope, LLC PTD 2010700; Sundry 323-556 Remarks and Photos Test Data: P Casing Removal: rev. 3-24-2022 2023-1218_Plug_Verification_PBU_NK-19A_jh              2023-1218_Plug_Verification_PBU_NK-19A_remarks_jh Page 1 of 2 Plug Verification Inspection – PBU NK-19A PTD 2010700; Sundry 323-556 Photos by AOGCC Inspector Josh Hunt 12/18/2023 Inspection Remarks – Tag and Test I traveled to location and met with Arvell Bass. We went over the plan for the job and the paperwork. We both went over the numbers and got on the same page with everything. Slickline picked up tools which included 13 feet of 2-1/8" weight bar, 5 feet of spangs & oil jars, a 3" diameter 2-foot long stabilizer, and a 3" bailer 3-ft long for a total of 23 feet and weighing estimated 250 lbs. They made the first run in and tagged up at 10,994 ft MD, beat down on it a few times and came up with top of cement at 10,994 ft MD. Pulled out of the hole and there was about a teaspoon of material with the appearance of liquid cement in the bailer. They decided to make a second run with a smaller 2.5" centralizer and a 1-3/4" bailer with a ball valve and mule shoe. This bailer also came back with little to nothing inside as well. I suggested adding another weight bar - they added another 5-foot, 1-7/8” weight bar and ran to bottom a third time. This time they spent a solid 20 minutes pounding it down and came up with the top of cement at 11,014 ft MD. The bailer came back packed full of soft cement with about an inch at the bottom being completely set up hard cement. This gives them a total of 220 feet of good cement on top of the plug. Rigged down slickline and performed a good MIT on the tubing. I added a picture of the plug schematic showing the coil unit’s top of cement which was 11,020 ft MD (6-foot difference between coil and slickline). Bailer for tagging plug Record of previous coil tubing tag of plug    2023-1218_Plug_Verification_PBU_NK-19A_remarks_jh Page 2 of 2 Materials recovered from bailer used to tag the cement plug MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section:36 Township:12N Range:15E Meridian:Umiat Drilling Rig:NA Rig Elevation:NA Total Depth:12,372 ft MD Lease No.:ADL 0034630 Operator Rep:Suspend:P&A:X Conductor:20"O.D. Shoe@ 115 Feet Csg Cut@ Feet Surface:10-3/4"O.D. Shoe@ 4219 Feet Csg Cut@ Feet Intermediate:O.D. Shoe@ Feet Csg Cut@ Feet Production:7-5/8"O.D. Shoe@ 8015 Feet Csg Cut@ Feet Liner:4-1/2"O.D. Shoe@ 12372 Feet Csg Cut@ Feet Tubing:4-1/2"O.D. Tail@ 7915 Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified Tubing Bridge plug 11,234 ft 11,208 ft 7.1 ppg Wireline tag Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: They ran in the hole with 8 feet of 2-1/8" weight pipe, 12' feet of 2-1/8" oil jars, and a 3-foot bailer with a mule shoe and a flapper valve installed (est. weight 175 lbs). 25 feet of hard cement is required on top of the bridge plug to proceed per regulaton; plug tagged at 11,208 ft MD (4 feet shy of the required of minumum). Several tags were made and they got a solid tag. Further operations were halted; they will get E-line out there to dump bail more cement. The bailer came back with some soft and contaminated cement towards the top and fairly solid cement at the bottom. November 25, 2023 Josh Hunt Well Bore Plug & Abandonment PBU Nk-19A Hilcorp North Slope, LLC PTD 2010700; Sundry 323-556 none Test Data: Casing Removal: Steve Soroka Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): rev. 3-24-2022 2023-1125_Plug_Verification_PBU_NK-19A_jh              7. If perforating: 1. Type of Request: 2. Operator Name: 3. Address: 4. Current Well Class:5. Permit to Drill Number: 6. API Number: 8. Well Name and Number: 9. Property Designation (Lease Number):10. Field: Abandon Suspend Plug for Redrill Perforate New Pool Perforate Plug Perforations Re-enter Susp Well Other Stimulate Fracture Stimulate Alter Casing Pull Tubing Repair Well Other: Change Approved Program Operations shutdown What Regulation or Conservation Order governs well spacing in thes pool? Will perfs require a spacing exception due to property boundaries?Yes No 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): PRESENT WELL CONDITION SUMMARY Perforation Depth MD (ft): Perforation Depth TVD (ft):Tubing Size: Tubing Grade: Tubing MD (ft): Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 12. Attachments: 14. Estimated Date for Commencing Operations: 13. Well Class after proposed work: 15. Well Status after proposed work: 16. Verbal Approval: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approcal. Proposal Summary Wellbore schematic BOP SketchDetailed Operations Program OIL GAS WINJ WAG GINJ WDSPL GSTOR Op Shutdown Suspended SPLUG Abandoned ServiceDevelopmentStratigraphicExploratory Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: AOGCC USE ONLY Commission Representative: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Location ClearanceMechanical Integrity TestBOP TestPlug Integrity Other Conditions of Approval: Post Initial Injection MIT Req'd?Yes No Subsequent Form Required: Approved By:Date: APPROVED BY THE AOGCCCOMMISSIONER PBU NK-19A Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 201-070 50-029-22507-01-00 ADL 0034635 12372 Conductor Surface Intermediate Production Liner 10169 80 4185 7982 4475 7879 20" 10-3/4" 7-5/8" 4-1/2" 7192 35 - 115 34 - 4219 33 - 8015 7897 - 12372 2400 35 - 115 34 - 4106 33 - 7307 7207 - 10169 none 470 2480 4790 7500 7879 , 11950 1490 5210 6890 8430 11246 - 12140 4-1/2" 12.6# L-80 32 - 79159236 - 9963 Structural 4-1/2" Baker SABL-3 No SSSV 7855 7172 Date: Bo York Operations Manager Eric Dickerman Eric.Dickerman@hilcorp.com 907.564.5258 PRUDHOE BAY 10/19/2023 Current Pools: NIAKUK OIL Proposed Pools: Undefined Suspension Expiration Date: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 Comm. Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Form 10-403 Revised 06/2023 Approved application is valid for 12 months from the date of approval.Submit PDF to aogcc.permitting@alaska.gov / Digitally signed by Torin Roschinger (4662) DN: cn=Torin Roschinger (4662), ou=Users Date: 2023.10.09 14:29:27 -08'00' Torin Roschinger (4662) , ADL0034630 SFD SFD 10/10/2023MGR11OCT23 2400 DSR-10/9/23 Regulation 20 AAC 25.055 SFD Approved for gas lift production if passing CMIT- TxIA to 2500 psi. Perforate New Pool Undefined *Brookian Undefined Oil Pool - New Code: 640132 SFD 10-404 * *&:JLC 10/12/2023 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.10.12 09:53:35 -08'00' RBDMS JSB 101323 NK-19A : Uphole recomplete to Brookian Page 1 of 9 Well Name:NK-19A API Number:50-029-22507-01 Current Status:Operable, Offline Permit to Drill Number:201070 Estimated Start Date:Oct 2023 Rig:SL/EL Regulatory Contact:Carrie Janowski Estimated Duration:3 days First Call Engineer:Eric Dickerman Cell Number:307-250-4013 Second Call Engineer:Dave Bjork Cell Number:907-440-0331 Brief Well Summary: NK-19A was sidetracked as a Sag and Kuparuk producer in 2002. The well has not had meaningful on time since 2006, and has not produced since 2013 due to low fluid rates. Openhole gamma ray, resistivity, and porosity logs indicate possible pay in the Brookian formation. Mud logs from NK-02A, NK-04, and NK-05 also specify hydrocarbons are present. In the Greater Point Macintyre Area, the Brookian formation has been drill stem tested at P1-02 and Gull-02 and both wells flowed oil. Objective: Isolate Kuparuk perforations. Test Brookian production. Sundry Documentation: The Brookian formation is not included in the Niakuk Oil pool. Therefore, it is planned to operate under a tract operation and thus statewide regulations. Pending production results, work towards defining a pool may be pursued after assembling a plan of reservoir development and operation as per 20 AAC 25.517. During this production test, the near wellbore region will see a pressure reduction which will cause the gas-oil ratio to increase, possibly above the current GOR limitations as defined by 20 AAC 25.240. Therefore, a waiver to the Gas-Oil Ratio requirement of 20 AAC 25.240 is requested. Well test data will be recorded at least once per month. If production is sustained, fluid samples will be obtained as per the requirements in 20 AAC 25.270. Brookian formation is not included in the Niakuk Oil pool NK-19A : Uphole recomplete to Brookian possible pay in the Brookian formation. Isolate Kuparuk perforations. Test Brookian production. NK-19A : Uphole recomplete to Brookian Page 2 of 9 Well Completion Information: Current Bottom Hole Pressure:4,401 psi at 9,300’ TVDss Max. Anticipated Surface Pressure:2,400 psi stacked out with lift gas Last Shut-in WHP:2,160 psi (WSR 1/25/2020) Min. ID:3.725” Max. Deviation:60.11 deg at 9,523’ md H2S Concentration:85 PPM (10/20/13) Well Integrity Information: Tbg: Passed 3,000 psi – 8/4/09 IA: Passed 3,000 psi – 7/28/09 OA: Passed 3,500 psi – 1/11/02 PPPOT-T: Passed 3,500 psi – 1/11/02 PPPOT-IC: Passed 3,000 psi – 10/28/01 Well Completion Information: Wellhead: FMC, 13-5/8” x 11”, 5M Tree: Cameron, 4-1/16”, 5M SSSV: 4-1/2”, Halliburton, CP-2, Locked out 9/17/06 Last insert: 4-1/2” QOS, 3 standard packing sets, control line operated. GLM: 4-1/2” Merla TMPDX, BK latch, 1” pocket Production Pkr: 7-5/8” x 4-1/2” Baker SABL-3, Permanent LTP: 7-5/8” x 5-1/2” Baker ZXP 85 PPM NK-19A : Uphole recomplete to Brookian Page 3 of 9 Wellwork Procedure: Slickline: 1. Pull PX plug from 7,879’. 2. Drift for bridge plug and dummy gun drift for 3-1/8” perf guns. a. Target bridge plug depth 11,205’. b. Max dog leg 10.8 deg at 8,021’. 3. RDMO Slickline. Eine with fullbore assist: 4. Load well with 215 bbl diesel. a. WBV to bottom perf = 175bbl. 5. Set 4-1/2” CIBP at 11,205’. Log off plug, then RBIH and tag to confirm in place. a. CIBP to be within 50’ of top of perforated interval as per 20 AAC 25.112.c.1.E. 6. Pressure test the bridge plug to 2,500 psi. 7. Dump bail 25’ of cement on top of bridge plug. a. As per 20 AAC 25.112.c.1.E. 8. Wait on cement 24 hrs. 9. Tag top of cement. AOGCC to witness. 10. Pressure test bridge plug and cement to 2,500 psi. AOGCC to witness. a. Plug depth 11,205’ md / 9,207’ TVD. b. 0.25 psi/ft * 9,207’ TVD = 2,302 psi. 11. Perforate the following intervals with 2-7/8” or 3-1/8”, 6 SPF perf guns. a. PPFG model shows a minimum expected pore pressure of 9.2 ppg and a maximum expected pore pressure of 10.6 ppg. Run #Top MD Bottom MD Length (ft) 1 10,263 10,290 27 2 10,211 10,241 30 3 10,205 10,211 6 12. Collect bottom hole pressure survey to satisfy 20 AAC 25.270.a. Submit form 10-412 to AOGCC within 45 days. Stops at: a. 10,238’ md / 8,550’ TVDss b. 10,142’ md / 8,500’ TVDss c. 10,047’ md / 8,450’ TVDss minimum expected pore pressure of 9.2 ppg and a maximum expected pore pressure of 10.6 ppg. CMIT-TXIA to 2500 psi. - mgr NK-19A : Uphole recomplete to Brookian Page 4 of 9 d. 9,955’ md / 8,400’ TVDss 13. RDMO eline. Hand well over to DSO to put on production. Operations: NOTE: The well cannot flow for greater than 14 total days before a wireline retrievable subsurface safety is required as per 20 AAC 25.265.j.1. 14. Put well on production and test to determine if lower perf interval will flow. 15. SVS system to be tested within 5 days of being placed in service. a. As per 20 AAC 25.265.h.4. Eine: 16. Perforate the following intervals with 2-7/8” or 3-1/8”, 6 SPF perf guns. Run #Top MD Bottom MD Length (ft) 4 10,016 10,046 30 5 10,007 10,016 9 6 9,960 9,980 20 17. RDMO eline. Hand well over to DSO to put on production. Operations: NOTE: The well cannot flow for greater than 14 total days before a wireline retrievable subsurface safety is required as per 20 AAC 25.265.j.1. This includes the production time from step 14. 18. Put well on production and test to determine if entire interval will flow. Slickline: 19. Set a 4-1/2” wireline retrievable subsurface safety valve at 2,071’ as required within the 14 day producing period as per 20 AAC 25.265.j.1. NK-19A : Uphole recomplete to Brookian Page 5 of 9 Current Wellbore Schematic: NK-19A : Uphole recomplete to Brookian Page 6 of 9 Proposed Wellbore Schematic: NK-19A : Uphole recomplete to Brookian Page 7 of 9 Reservoir Pressure Report – Form 10-412 NK-19A : Uphole recomplete to Brookian Page 8 of 9 NK-19A : Uphole recomplete to Brookian Page 9 of 9 • • ) BP Exploration (Alaska) Inc. Attn: Well Integrity Coordinator, PRB-20 ,f Post Office Box 196612 Anchorage, Alaska 99519-6612 July 6, 2011 JU 1_ 1 - 0)i Mr. Tom Maunder a,O Alaska Oil and Gas Conservation Commission 333 West 7 Avenue • [1 n Anchorage, Alaska 99501 0 1' - Subject: Corrosion Inhibitor Treatments of GPMA Niakuk Dear Mr, Maunder, Enclosed please find multiple copies of a spreadsheet with a list of wells from GPMA Niakuk that were treated with corrosion inhibitor in the surface casing by conductor annulus. The corrosion inhibitor is engineered to prevent water from entering the annular space and causing external corrosion that could result in a surface casing leak to atmosphere. The attached spreadsheet represents the well name, API and PTD numbers, top of cement depth prior to filling and volumes of corrosion inhibitor used in each conductor. As per previous agreement with the AOGCC, this letter and spreadsheet serve as notification that the treatments took place and meet the requirements of form 10-404, Report of Sundry Operations. If you require any additional information, please contact me or my alternate, Mehreen Vazir, at 659-5102. Sincerely, Gerald Murphy BPXA, Well Integrity Coordinator • • BP Exploration (Alaska) Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off Report of Sundry Operations (10.404) Niakuk Date: 05/15/11 Corrosion Initial top of Vol. of cement Final topof > Cement top off Corrosion inhibitor/ Well Name PTD # API # cement pumped cement date inhibitor sealant date ft bbls ft na gal NK -01A 1760280 500292015601 P&A 3/9/91 NA NA NA NA NA NK -02A 1780790 500292018001 P&A 3/13/91 NA NA NA NA NA NK-03 1780940 500292035000 P&A 4/14/80 NA NA NA NA NA NK-04 1842000 500292121700 P&A 4/14/96 NA NA NA NA NA NK-05 1850270 500292129000 P&A 4/15/96 NA NA NA NA NA NK-06 1852760 500292148600 P&A 4/15/98 NA NA NA NA NA NK -07A 2010830 500292241001 0.2 NA 0.2 NA 0.9 4/30/2011 NK-08A 2010290 500292249101 0.2 NA 0.2 NA 0.9 4/30/2011 NK-09 1941400 500292251800 2.1 NA 2.1 NA 17.0 4/30/2011 NK -10 1931840 500292242500 1.5 NA 1.5 NA 11.9 4/30/2011 NK -11A 2020020 500292278901 1.5 NA 1.5 NA 11.9 4/30/2011 NK -12C 2030550 500292241403 1.8 NA 1.8 NA 31.0 4/30/2011 NK -13 1961340 500292289300 2.3 NA 2.3 NA 22.1 5/4/2011 NK -14A 2060310 500292286801 1.8 NA 1.8 NA 17.0 5/4/2011 NK -15 1970320 500292274500 1.8 NA 1.8 NA 18.7 5/4/2011 NK -16 1940220 500292244700 2.5 NA 2.5 NA 20.4 5/4/2011 NK -17 1981650 500292270900 3 NA 3 NA 20.4 5/4/2011 NK -18 1931770 500292242100 2 NA 2 NA 17.0 5/6/2011 NK -19A 2010700 500292250701, 1.8 NA 1.8 NA 15.3 5/8/2011 N K -20A 2050400 500292242901 2.1 NA 2.1 NA 13.8 5/9/2011 NK -21 1940860 500292248700 2 NA 2 NA 22.1 5/15/2011 NK -22A 2012280 500292240201 1.5 NA 1.5 NA 11.9 5/11/2011 NK -23 1940350 500292245500 3.6 NA 3.6 NA 20.4 5/10/2011 NK -25 1970880 500292276000 2.5 NA 2.5 NA 15.3 5/11/2011 NK - 1940050 500292244000 2.9 NA 2.9 NA 17.0 5/11/2011 NK -27 1950210 500292254700 2.3 NA 2.3 NA 13.6 4/30/2011 NK -28 1980930 500292267800 Sealed Conductor NA Sealed Conductor NA NA NA NK -29 1961900 500292272400 1.7 NA 1.7 NA 10.2 4/30/2011 NK-38A 2042410 500292254001 3.1 NA 3.1 NA 13.6 5/8/2011 NK-41A 1971580 500292277801 9.1 NA 9.1 NA 54.0 5/9/2011 NK-42 1941080 500292249900 2 NA 2 NA 13.6 5/9/2011 NK-43 2010010 500292299800 1 NA 1 NA 5.1 5/9/2011 NK-61A 2060350 500292289301 14 NA 14 NA 110.5 5/15/2011 NK-62A 2030470 500292285201 1.3 NA 1.3 NA 13.6 5/4/2011 NK-65A 2050830 500292286901 1 NA 1 NA 8.5 5/6/2011 STATE OF ALASKA ALASKA AND GAS CONSERVATION COMMISSI. REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon ❑ Repair Well ❑ Plug Perforations ❑ Stimulate Other ❑ Performed: Alter Casing 0 Pull Tubing D Perforate New Pool 0 Waiver Time Extension ❑ Change Approved Program ❑ Operat. Shutdown ❑ Perforate El Re -enter Suspended Well ❑ 2. Operator BP Exploration (Alaska), Inc. 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development 0 Exploratory ❑ • 201 -0700 3. Address: P.O. Box 196612 Stratigraphic❑ Service ❑ 6. API Number: Anchorage, AK 99519 -6612 ° 50- 029 - 22507 -01 -00 8. Property Designation (Lease Number) : 9. Well Name and Number: ADLO- 034635 0 NK -19A 10. Field /Pool(s): PRUDHOE BAY FIELD / NIAKUK OIL POOL 11. Present Well Condition Summary: Total Depth measured 12372 feet Plugs (measured) 11950 feet true vertical 10169.36 feet Junk (measured) None feet Effective Depth measured 11950 feet Packer (measured) 7855 7897 feet true vertical 9794.47 feet (true vertical) 7172 7207 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 20" 91.5# H -40 35 - 115 35 - 115 1490 470 Surface 10 -3/4" 45.5# NT -80 34 - 4219 34 - 4106 5210 2480 Production 7 -5/8" 29.7# NT -80 33 - 8015 33 - 7307 6890 4790 Liner 4 -1/2" 12.6# L -80 7987 - 12372 7283 - 10169 8430 7500 Liner n Liner �t ,.._, �� Vint depth: Measured depth: SEE ATTACHED - ,` — True Vertical depth: _ — _ Tubing: (size, grade, measured and true vertical depth) 4-1/2" 12.6# L -80 32 - 7915 32 - 7222 Packers and SSSV (type, measured and true vertical depth) 4 -1/2" BKR SABL -3 PKR 7855 7172 5 -1/2" BKR ZXP PKR 78 7207 12. Stimulation or cement squeeze summary: AO O g ' Intervals treated (measured): *iot o a & fins C C Treatment descriptions including volumes used and final pressure: A01 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing pressure Prior to well operation: 143 0 629 495 Subsequent to operation: SI 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Exploratory Development 0 ti Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16. Well Status after work: Oil , 0 Gas ❑ WDSPL ❑ GSTOR ❑ WINJ ❑ WAG❑ GINJ ❑ SUSP❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: NA Contact Joe Lastufka Printed Na - , e Lastu .` ilk ( Title Data Manager M Signatur - Phone 564 -4091 Date 4/7/2011 Ir w Form 10-404 Revised 10 /201ORBDMS APR 41 20114_ y �,// i d, // Submit Original Only Le NK-19A 201 -070 PERF ATTACHMENT Sw Name Operation Date Perf Operation Code Meas Depth Top Meas Depth Base Tvd Depth Top Tvd Depth Base NK -19A 1/26/02 PER 12,120. 12,140. 9,944.75 9,962.57 NK -19A 2/7/02 BPS 11,950. 12,357. 9,794.47 10,156. NK -19A 2/9/02 APF 11,452. 11,472. 9,384.5 9,399.6 NK -19A 2/10/02 APF 11,422. 11,452. 9,362.18 9,384.5 NK -19A 3/19/02 APF 11,288. 11,304. 9,265.69 9,277.07 NK -19A 3/22/02 APF 11,268. 11,288. 9,251.48 9,265.69 NK -19A 3/23/02 APF 11,252. 11,272. 9,240.11 9,254.32 NK -19A 9/13/04 APF 11,439. 11,459. 9,374.78 9,389.76 NK -19A 6/15/08 APF 11,426. 11,466. 9,365.13 9,395.05 NK -19A 6/16/08 APF 11,246. 11,316. 9,235.84 9,285.63 NK -19A 6/16/08 APF 11,418. 11,426. 9,359.24 9,365.13 NK -19A 10/3/10 APF 11,352. 11,352.1 9,311.42 9,311.49 • NK -19A 3/28/11 APF siAm, peer 11,353. 11,353. 9,312.13 9,312.13 AB ABANDONED PER PERF APF ADD PERF RPF REPERF BPP BRIDGE PLUG PULLED SL SLOTTED LINER BPS BRIDGE PLUG SET SPR SAND PLUG REMOVED FCO FILL CLEAN OUT SPS SAND PLUG SET FIL FILL SQF SQUEEZE FAILED MIR MECHANICAL ISOLATED REMOVED SQZ SQUEEZE MIS MECHANICAL ISOLATED STC STRADDLE PACK, CLOSED MLK MECHANICAL LEAK STO STRADDLE PACK, OPEN OH OPEN HOLE • • • NK -19A DESCRIPTION OF WORK COMPLETED NRWO OPERATIONS EVENT SUMMARY 3/26/2011; * **WELL S/I ON ARRIVAL ** *(pre adperf) TAGGED 4 -1/2" HES QOS @ 2,046' SLM / 2,071' MD W/ 3.84" NO -GO CENT (No issues). ! PULL 4 -1/2" HES QOS (s /n = LOOS-403, c/I op, 3 -sets std pkg) FROM 2,071' MD. DRIFT TO 11,884' SLM (Target 11,353' md) W/ 3 -3/8" x 10' D -GUN, S -BLR (No sample). :CURRENTLY RIH W/ PDS 40 ARM CALIPER & PRESSURE/TEMP GAUGES. ** *JOB IN PROGRESS, CONTINUED ON 3/27/11 WSR * ** 3/27/2011 i ** *CONTINUED FROM 3/26/11 WSR ** *(pre adperf) IRAN PDS SBHPS, MADE ALL STOPS PER PROGRAM (Good data). RAN PDS 40 ARM CALIPER FROM 11,878' SLM TO SURFACE (No data, Tool ai ure IRE-RAN PDS 40 ARM CALIPER FROM 11,870' SLM TO SURFACE (Good data). ** *WELL S/I ON DEPARTURE, NOTIFIED DSO OF WELL STATUS * ** 6 1 � 3/28/2011 *' *WELL SHUT IN ON ARRIVAL * ** (E -LINE: ADPERF) INITIAL T /I /O = 950/675/150 PERFORATED WITH 2" HSD PJ OMEGA GUN AT 11353' WITH A SINGLE. CHARGE ORIENTED AT ZERO DEGREES ,API DATA: PENETRATION = 21.8 ", HOLE DIAMETER = 0.22" 'DSO NOTIFIED OF FINAL VALVE POSITIONS: WING, SWAB = CLOSED. SSV, MASTER = OPEN. CASING = OTG I FINAL T /I /O = 900/475/120 ** *JOB COMPLETE, WELL LEFT SHUT IN ON DEPARTURE * ** FLUIDS PUMPED BBLS 3 DIESEL 3 METH 6 TOTAL TREE _ 4- 1/16" 5M CNV SAFETY N.: WELL REQUIRES A SSSV. TRSV WELLHEAD = FMC N 1(1 9P DAMAG : ' /BROKEN FLAPPER@ 2071' (09/08/06) ACTUATOR BAKER KB. ELEV = 60.3' BF. ELEV = 24.9' KOP = 3150' Max Angle = 60 @ 9523' I 2071' I — 4 -1/2" HES CP -2 TRSSSV, ID = 3.813" Datum MD = 11270' LOCKED OUT (09/17106) Datum TV D = 9200' SS 10 -3/4" CSG, 45.5 #, 14T -80 BTC, ID = 9.950" I — I 4219' GAS LIFT MANDRELS ST MD ND DEV TYPE VLV LATCH PORT DATE 5 3809 3708 31 TMPDX DMY BK 0 01/12/02 4 4086 3943 32 TMPDX DOME BK 16 01/17/02 Minimum ID = 3.725" @ 7900' 3 5578 5197 32 TMPDX DOME BK 16 01/17/02 4 -1/2" HES XN NIPPLE 2 6772 6203 35 TMPDX DMY BK 0 01/12/02 1 7761 7039 33 TMPDX S/O BK 20 08/03/09 7831' I - 14 - 1/2" HES X NIP, ID = 3.813" I 1101:111 1�1 7852' J - 518" X 4 -1/2" BKR SABL -3 PKR, ID = 3.900" I 7879' H4 -1/2" HES X NIP, ID = 3.813" I 7900' 1-14-1/2" HES XN NIP, ID = 3.725" I I 7 -518 X 5 -1 /2" BKR ZXP PKR ID = 4.940 I " " H 7907' I �� 0321 I 4 -1/2" TBG, 12.6 #, L -80, .0152 bpf, ID = 3.958" I 7911' P 7912' -{4 -1/2" WLEG, ID = 3.958" I I7 -518" X 5 -1/2" BKR FLEX -LOCK HGR, ID = 4.810" H 7920' I 7929' H5-1/2" X 4 -1/2" XO, ID = 3.920" ( ITOP OF WHIPSTOCK H 8021' I 7 -5/8" CSG MILLOUT WINDOW 8002' - 8015' (OFF WHIPSTOCK) ■ • N 11149' I—I MARKER JTS (2) 39' TOTAL I PERFORATION SUMMARY REF LOG: SWS JEWELRY LOG ON 01/22/02 a,� ata� ANGLE AT TOP PERF: 45° @ 11246' "•""� ■ Note: Refer to Production DB for historical perf data /IAN/ 11950' —1 BAKER CIBP (02/07102) I SIZE SPF INTERVAL Opn /Sqz DATE P•••••••■•••• 2-7/8" 6 11246 - 11316 0 06/17/08 �!!!!!!!!!!!!!!!!!!!!/ 11976' I — I MARKERJTS (2) 39' TOTAL I 3 -3/8" 6 11251 - 11288 0 03/22/02 ► 3 -3/8" 6 11288 - 11304 0 03/19/02 ► 2" 1 11352 0 10/03/10 �!!!!!!!!!!!!!!!!!!!!1 4 \ 2" 1 11353 0 03/28/11 !!!!!!!!!!/ 2-7/8" 6 11418 11466 0 06/15/08 ►!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!i 3 -3/8" 6 11422 - 11472 0 02/10/02 • ! ! ! ! ! ! ! ! ! ! 1 3 -3/8" 6 12120 - 12140 C 01 /26/02 ►!!!!!!!!!!!!!!!!!!!1 /!!!!!N!!! ►!!!!!!!!! �. 17 -5/8" CSG, 29.7 #, NT -80S NSCC, ID = 6.875" I—I 10648' .1, l . 1 . 1 1 l . 1 . 11l . 1 i!� • I PBTD I 12357' '!*! I4 -1/2" LNR, 12.6 #, L -80, .0152 bpf, ID = 3.958" H 12372' I DATE REV BY COMMENTS DATE REV BY COMMENTS NIAKUK UNIT 10/31/94 ORIGINAL COMPL, (POOL 7) 03/31/11 SRD /PJC ADPERF (3/28/11) WELL: NK -19A 01/12/02 RIG SIDETRACK PERMIT No: ® 2010700 06/25/08 RRD /SV ADPERFS (06/15 &17/08) AR No: 50- 029 - 22507 -01 09/28/09 CJN/SV GLV C/O (08/03/09) SEC 36, T12N, R15E, 1434' NSL & 815' WEL 10/26/10 JMF /PJC PERF (10/03/10) 02/18/11 MB /JMD ADDED SSSV SAFETY NOTE BP Exploration (Alaska) • • BP closes site over loss in Slope rent dispute HEALD POINT: Oengas fight oil giant over rent for use of their land. By ELIZABETH BLUEMIN K 3( 30`A- ebluemink@adn.com �� 1 8 � �� Published: January 4th, 2011 . 10:09 PM \L` L \ 3 @ O k - COO Last Modified: January 4th, 201 l 10:09 PM��fN \ Do \ BP shut down a small portion of the Prudhoe Bay oil field last week after a judge ruled that federal regulators failed for years to get approval from the Inupiat Eskimo family that owns the land. C.0 f\ \ L� Nrt":Pt 1 k \d 3 mai toouon.r�+..�r 1 i e Ni t, k k .. • r Photo courtesy of BP Exploration (Alaska) Inc. Heald Point drill pad at Prudhoe Bay has been used to access oil from several oil pools, including Raven. The BIA told BP to suspend Raven production in late December due to a court ruling. Read more: http: / /www.adn.com /2011 /01 /04/v- gallery /1631936/bp- closes- site - over - loss- in- rent.html #ixzz 1 AB7r0Irl • • The shutdown affects less than 1 percent of production from the nation's largest oil field, but so far it's the most visible consequence of a significant legal victory for the Native family, which has battled lawyers for the federal Bureau of Indian Affairs and BP in federal court over the oil production from its land. Federal claims court judge Nancy Firestone ruled this fall that the Oenga family is owed millions in unpaid rent because the BIA improperly allowed BP to tap three offshore oil deposits from the family's allotment on the northern edge of the vast Prudhoe oil field. The BIA approved BP's expanded use of the allotment without the family's consent, in violation of the family's contract with BP, Firestone said in her 168 - page ruling on Nov. 22. A week ago, the BIA told BP to shut down production from Prudhoe's Raven unit, the only one of the three disputed offshore deposits that BP was still accessing from the allotment. BP shut down Raven, which produced about 25,000 barrels of oil in November, on Friday. BP is still legally tapping the Niakuk field from the allotment. The battle over unpaid rent and unauthorized land use involves a nondescript finger of land called Heald Point that extends into the Beaufort Sea. The Oenga family acquired its 40 -acre allotment at Heald Point decades ago for subsistence hunting. But in 1989, the family patriarch, Andrew Oenga, signed a contract with BP allowing the oil giant to use Heald Point as a right of way. Years later, believing that BP was giving the family annual rent payments much lower than the land's true value, eight of Oenga's heirs -- including two children, his grandchildren and great - grandchildren -- sued the BIA in 2005. The family said it had to go to court because it was unable to persuade the agency, which is in charge of collecting the family's rent from BP, to take action on its behalf. In an eight -day Lower 48 trial last July, the agency and the oil giant defended themselves against the Oengas' claims. BP argued in court filings that no additional money was owed to the family. The BIA argued that the family's claims for unpaid rent were exorbitant. • • The judge ruled for the family, saying the BIA owes it roughly $5 million for the unauthorized use of the land, but she also said that BP is paying too little for the land it is authorized to use. The judge is still taking briefings on the exact amount owed but it will be far below the $200 million the Oengas originally sought. BP Alaska spokesman Steve Rinehart said Tuesday the company is evaluating its best path forward on a potential appeal. He emphasized that Raven represented a fraction of Prudhoe's output. BIA's acting director in Alaska did not return a call for comment on Tuesday. In a written statement late week, Oenga family member Tony Delia said the family is willing to end the matter. "Earlier this month we made BP a fair offer -- pay what is owed and we will renegotiate the lease so they can use our land to produce from Raven and wherever else they want to drill. They haven't responded," he said. According to a written statement from the family's attorney, Ray Givens, the total amount owed the family is $15 million. That figure includes the Oenga family's calculation of how much additional money it is owed in unpaid rent for BP's authorized use of the land, which was not part of the this lawsuit. In her ruling, Firestone said evidence from the trial showed that BP withheld critical information about Heald Point's strategic value for oil development when it negotiated a contract with the family to use the land. "Clearly, (BP) did not wish to share much with the plaintiffs," she wrote. Find Elizabeth Bluemink online at adn.com /contact /ebluemink or call 257-4317. Read more: http://www.adn.com/ 2011 /01/04/1631936/bp- closes - site - over - loss -in rent.html#ixzz 1 AB73YsM3 STATE OF ALASKA ALA OIL AND GAS CONSERVATION COMMON REPORT OF SUNDRY WELL OPERATIONS ~~~ ~ ~ 20Q~ 1. Operations Abandon ~ Repair Well ~ Plug Perforations ~ Stimulate~~~~~~ ~~ °r'~ ~rs~, ~ ~iUi*~ Performed: Alter Casing ~ Pull Tubing Perforate New Pool ~ Waiver Time Ext~rr~ ~ ,.r Change Approved Program ~ Operat. Shutdown Perforate Q _ Re-enter Suspended Well 2. Operator BP Exploration (Alaska), Inc. 4. Current Well Class: 5. Permit to Drill Number: Name: Development ~~ Exploratory ~' 201-0700 3. Address: P.O. Box 196612 Stratigraphic Service ~ '. 6. API Number: Anchorage, AK 99519-6612 50-029-22507-01-00 7. KB Elevation (ft): 9. Well Name and Number: 53.05 KB - NK-19A 8. Property Designation: 10. Field/Pool(s): ADLO-034635 ~ PRUDHOE BAY Field/ NIAKUK OIL Pool 11. Present Well Condition Summary: Total Depth measured 12372 - feet Plugs (measured) 11950 true vertical 10169.36 - feet unk ( m easured) None J r ~ f lO Effective Depth measured 11950 - feet ~~sf~1tllY~D J V ~ ~ G 2~UtJ true vertical 9794.47 - feet Casing Length Size MD TVD Burst Collapse Conductor 80 20" 91.5# H-40 32 - 112 32 - 112 1490 470 Surface 4188 10-3/8" 45.5# L-80 31 - 4219 31 - 4106 5210 2480 Production 7972 7-5/8" 29.7# NT-80S 30 - 8002 30 - 7296 6890 4790 Liner 4460 4-1/2" 12.6# L-80 7912 - 12372 7220 - 10169 8430 7500 Perforation depth: Measured depth: SEE ATTACHED True Vertical depth: _ _ Tubing: (size, grade, and measured depth) 4-1/2" 12.6# L-80 29 - 7912 0 0 - Packers and SSSV (type and measured depth) Baker S-3 Packer 7852 7-5/8" Baker ZXP Top Packer 7907 0 0 0 0 12. Stimulation or cement squeeze summary: Intervals treated (measured): ~WfG~~ ~C~S~ ~rO~~C Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing pressure Prior to well operation: SHUT-IN Subsequent to operation: 28 0 62 773 14. Attachments: 15. Well Class after proposed work: Copies of Logs and Surveys Run Exploratory ~ Development ~ Service Fy Daily Report of Well Operations X 16. Well Status after proposed work: Oil ! Gas WAG ~ GINJ WINJ (~'? WDSPL ~"~ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: N/A Contact Gary Preble Printed Name Gary PrP Title Data Management Engineer Signature Phone 564-4944 Date 6/27/2008 Form 10-404 ised 04/200 C+ Qr1 ~~~ ~ ~ 208 ~ ~ '" `1 ~ °~,~~` ¢ ~° ~ ,! ~ ~ Submit Original Only NK-19A 201-0700 PERF ATTACHMENT • Sw Name Operation Date Perf Operation Code Meas Depth Top Meas Depth Base_~ Tvd Depth Top Tvd Depth Base NK-19A 1/26/02 PER 12,120. 12,140. 9,944.75 9,962.57 NK-19A 2/7/02 BPS 11,950. 12,357. 9,794.47 10,156. NK-19A 2/9/02 APF 11,452. 11,472. 9,384.5 9,399.6 NK-19A 2/10/02 APF 11,422. 1.1,452. 9,362.18 9,384.5 NK-19A 3/19/02 APF 11,288. 11,304. 9,265.69 9,277.07 NK-19A 3/22/02 APF 11,268. 11,288. 9,251.48 9,265.69 NK-19A 3/23/02 APF 11,252. 11,272. 9,240.11 9,254.32 NK-19A 9/13/04 APF 11,439. 11,459. 9,374.78 9,389.76 NK-19A 6/15/08 APF 11,426. 11,466../ 9,365.13 9,395.05 NK-19A 6/16/08 APF 11,246. 11,316. / 9,235.84 9,285.63 NK-19A 6/16/08 APF 11,418. 11,426. ~` 9,359.24 9,365.13 AB ABANDONED PER PERF APF ADD PERF RPF REPERF _ BPP BRIDGE PLUG P ULLED SL SLOTTED LINER BPS BRIDGE PLUG SET SPR SAND PLUG REMO VED FCO FILL CLEAN OUT SPS SAND PLUG SET FIL FILL SQF SQUEEZE FAILED MIR MECHANICAL ISOLATED REMOVED SQZ SQUEEZE MIS MECHANICAL ISOLATED STC __ STRADDLE PACK, CLOSED MLK MECHANICAL LEAK STO STRADDLE PACK, OPEN OH OPEN HOLE • • NK-19A DESCRIPTION OF WORK COMPLETED NRWO OPERATIONS EVENT SUMMARY ACTIVITYDATE SUMMARY 6/15/2008'iSHUT-IN ON ARRIVAL, 2500/1600/700. WING CLOSED AND SSV OPEN. 'ELINE RIG UP AND PERFORATE 2-7/8" HSD OMEGAJETS, 6 SPF, 60 ';DEGREE PHASE OVER INTERVAL 11,426-11,466 FT IN TWO RUNS. ***JOB IN PROGRESS AND CONTINUED ON 16-JUN-2008 WSR*** ~_ _ __ _ _. 6/16/20081***CONTINUED FROM 15-JUN-2008*"* (ELINE PEFORATING 2-7/8" HSD OMEGAJET, 6 SPF, 60 DEGREE PHASE ':OVER INTERVAL 11,418-11,426 AND 11.246-11.316 FT IN 5 RUNS. ***JOB IN PROGRESS AND CONTINUED ON 17-JUN-2008 WSR*** 6/17/2008'';'`*'`CONTINUED FROM 16-JUN-2008"'`'` '%RIG DOWN ELINE. 'FINAL T/I/O 2450/1620/700. ';,WELL LEFT SHUT-IN, ';TURNED OVER TO DSO. ***JOB COMPLETE""" FLUIDS PUMPED BBLS 1 diesel 1 Total e e r~ W;"sç. ,"c ~" 'IV,-,: ~'"_ .¡_~ MICROFILMED 07/25/06 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F:\LascrFiche\CvrPgs _Inscr1s\Microfilm _ Marker. doc 1. Operations Abandon 0 Repair Well 0 Performed: Alter Casing 0 Pull Tubing 0 Change Approved Program 0 Operat. Shutdown 0 2. Operator BP Exploration (Alaska), Inc. Name: '\ STATE OF ALASKA ) ALA__ A OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS o o o Plug Perforations Perforate New Pool Perforate 4. Current Well Class: Development 'r;? Stratigraphic ![ SE? 1 ,:}, ')005 ' ~,~) L~, .. Stimu~ate 00-1 . Œ~ ~It'?f~~'é~"'" .. Waiver Time Exten~lohL~i"ijt;" Re-enter Suspended Wè1111§kì:::{" 5. Permit to Drill Number: Exploratory C 201-0700 Service 6. API Number: 50-029-22507-01-00 9. Well Name and Number: P.O. Box 196612 Anchorage, AK 99519-6612 7. KB Elevation (ft): 3. Address: 53.05 KB NK-19A ADl-034635 11. Present Well Condition Summary: 10. Field/Pool(s): PRUDHOE BAY Field/ NIAKUK Oil Pool 8. Property Designation: Total Depth measured 12372 true vertical 10169.36 feet feet Plugs (measured) Junk (measured) 11950 None Effective Depth measured 11950 true vertical 9794.47 feet feet Casing Conductor Surface Production Liner length Size MD TVD Burst Collapse 80 20" 91.5# H-40 32 - 112 32 - 112 1490 470 4188 10-3/4" 45.5# l-80 31 - 4219 31 - 4106.35 5210 2480 7972 7-5/8" 29.7# NT-80S 30 - 8002 30 - 7295.78 6890 4790 4460 4-1/2" 12.6# l-80 7912 - 12372 7219.56 - 10169.36 8430 7500 Perforation depth: Measured depth: 11252 - 11288 11288 - 11304 11422 - 11472 12120 -12140 True Vertical depth: 9240.11 - 9265.69 9265.69 - 9277.07 9362.18 - 9399.6 9944.75 - 9962.57 Tubing: (size, grade, and measured depth) 4-1/2" 12.6# l-80 29 - 7912 Packers and SSSV (type and measured depth) Baker S-3 Packer 7-5/8" Baker ZXP Top Packer 7852 7907 12. Stimulation or cement squeeze summary: Intervals treated (measured): 11269-11285 err" ..;, :,,' f' IL}¡,·:\\~\\fE~..) ,> r. ;," \'..;~"t..;¡r'J \\~ ..\ 1/¡?ltJ~ RBDMS BFL fÆ~ "1 :¡ 2{)B5 »JP~ Treatment descriptions including volumes used and final pressure: Propellant Stimulation 13. Prior to well operation: Subsequent to operation: 14. Attachments: Copies of logs and Surveys Run Daily Report of Well Operations Oil-Bbl 170 148 Representative Daily Average Production or Injection Data Gas-Mcf Water-Bbl Casing Pressure o 65 450 79 66 400 15. Well Class after Droposed work: Exploratoryr Development µ 16. Well Status after proposed work: Oil~ Gas r WAG r Tubing pressure 780 1050 Service r x GINJr WINJr WDSPL r 17. I hereby certify that the foregoing is true and correct to the best of my knowledge, Sundry Number or N/A if C.O. Exempt: N/A Contact Sharmaine Vestal Signat~~~ Form 10-404 Revised 04/2004 / Title Data Mgmt Engr 7vi.Lr/o..fJ Phone 564-4424 OR\G\NAL Date 9/9/2005 Printed Name Sharmaine Vestal Submit Original Only ) ') SE.- p 1 ,Qi 20 ~'j:) '05 NK-19A DESCRIPTION OF WORK COMPLETED NRWO OPERATIONS EVENT SUMMARY I ACTIVITYDATE I SUMMARY I 7/30/2005 T/I/O=780/1075/450 Temp=cold TBG FL (For E-line) Well flowing on gas lift. 8/1/2005 Perform a Propellant Stimulation from 11269' - 11285'. Tied in using SLB jewlry log dated 01-22-02 FLUIDS PUMPED BBLS TOTAL '\ STATEOFALASKA') REC"'EmVE'D ALA... A OIL AND GAS CONSERVATION COMr\,.. .A,ION .J! "" ~ ,,' REPORT OF SUNDRY WELL OPERATIONS AUG 1 8 Z005 o Stimulate 0 A . Other 0 o WaiverD "~~ ¡QlIA~i:l[!:¡;[lns" t;ommjss~(m o Re-enter Suspended \ÁÍ6It~r.3ge 5. Permit to Drill Number: ExpIaatay [] 201-0700 SeNce C' 6. API Number: 50-029-22507 -01-00 9. Well Name and Number: ~¡; .' 1. Operations Abandon 0 Repair Well 0 Performed: Alter Casing 0 Pull Tubing 0 Change Approved Program 0 Operat. Shutdown 0 2. Operator BP Exploration (Alaska), Inc. Name: P.O. Box 196612 Anchorage, AK 99519-6612 7. KB Elevation (ft): 3. Address: 53.05 KB 8. Property Designation: ADl-034635 11. Present Well Condition Summary: Total Depth measured 12372 true vertical 10169.36 Effective Depth measured 11950 true vertical 9794.47 Casing Conductor Surface Production Liner Plug Perforations Perforate New Pool Perforate 4. Current Well Class: ~qJI1 at (;?]! Stratiga:tlic ,r NK-19A 10. Field/Pool(s): PRUDHOE BAY Fieldl NIAKUK Oil Pool feet feet Plugs (measured) Junk (measured) 11950 None feet feet length Size MD TVD Burst Collapse 80 20" 91.5# H-40 32 - 112 32 - 112 1490 470 4188 10-3/4" 45.5# l-80 31 - 4219 31 - 4106.35 5210 2480 7972 7-5/8" 29.7# NT-80S 30 - 8002 30 - 7295.78 6890 4790 4460 4-1/2" 12.6# l-80 7912 - 12372 7219.56 - 10169.36 8430 7500 Perforation depth: Measured depth: 11422 - 11472 True Vertical depth: 9362.2 - 9399.6 Tubing: (size, grade, and measured depth) Packers and SSSV (type and measured depth) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Prior to well operation: Subsequent to operation: 14. Attachments: Copies of logs and Surveys Run Daily Report of Well Operations Oil-Bbl 174 152 x 11288 - 11304 9265.7 - 9277.1 11252 -11288 SCAJ\H\'E-~--) t·y 200~ ,r",,~UG 1 { J 9240.1-9265.7 .. f:.... 4-1/2" 12.6# l-80 29 - 7912 Baker S-3 Packer 7-5/8" Baker ZXP Top Packer o o 7852 7907 o o RBDMS BFl AUG J 9 2005 Representative Daily Average Production or Injection Data Gas-Mcf Water-Bbl Casing Pressure o 65 480 82 66 400 15. Well Class after proposed work: ExpIactay r ~q::J I ert P' 16. Well Status after proposed work: 01 R' <?as r V\Jð..G r QNJ r Tubing pressure 780 1050 SeNce r WNJ r WDSPLr 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Sharmaine Vestal Printed Name Sharmaine Vestal ~ Sign~,\\ ~/L~..,c~ Form 10-404 Revised 04/2004 Sundry Number or NIA if C.O. Exempt: NIA Title Data Mgmt. Engr. Phone 564-4424 ~bRIG!NAL Date 8/12/2005 Submit Original Only ,.., ) ') I ACTIVITYDATE I SUMMARY 7/30/2005 T/I/O=780/1075/450 Temp=cold TBG FL (For E-line) Well flowing on gas lift. 8/1/2005 T/I/O=1040/1000/430 Temp=S/I TBG FL (For E-line). TFL=132' (2 bbls) 8/1/2005 Perform a Propellant Stimulation from 11269' - 11285'. Tied in using SLB jewlry log dated 01-22-02 ~ Co ~-~ ÀÒð ý. DATA SUBMITTAL COMPLIANCE REPORT 1/26/2004 Permit to Drill 2010700 Well Name/No. PRUDHOE BAY UN NIA NK-19A Operator BP EXPLORATION (ALASKA) INC Sf? r..I¿ -.J J /j 4 ~ ~ API No. 50-029'-22'5'Br:o-1-00 MD 12372 ./ ND 10169 ~ Completion Date 1/26/2002 -- Completion Status 1-01L Current Status 1-01L UIC N -- ------- ------ -------------------------------------~------ -------- ----------- -- ---~-------------- ------- ----- --------------- -------------------------~-------------- --------- -------- ------------------ ----------------------- ------------------------ ----- ---- REQUIRED INFORMATION Mud Log No Samples No Directional Survey ~_\)k -- - -- ------------- ----- -- ------------------- --------------------- --------- - DATA INFORMATION Types Electric or Other Logs Run: Well Log Information: (data taken from Logs Portion of Master Well Data Maint) { Log/ Electr Data Digital Dataset Type Med/Frmt Number Name ---.--------- C ----'t0628 GarnmaRay ---- 11561 See Notes -- - - - - - -- '1Í155 LlSVerificatlon. - - - - LI$\Ierification . Log Log Run Scale Media No 1 1 1 Interval OH / Start Stop CH Received Comments ----------.----- ------------- 7552 12441 Case 3/5/2002 7794 12372 Case 1/31/2003 Digital Well Logging Data 1 7794 7794 12317 Open 1 0/9/2002 12317 Open 1 0/9/2002 --------------- --- ~ --------- -- ------ -- -.-- -- -- -.------- -- ------ --- ----- ---- --- --- - ------- ---- - -- -- - - --- --- - - - ----- ------ Well Cores/Samples Information: Name Interval Start Stop Sent Received Sample Set Number Comments ADDITIONAL INFORMATION Well Cored? Y~ Chips Received? Yn~ Formation Tops ~N ~/N (, Daily History Received? Analysis Received? .~ -------_..----------- - -- - ------- .-------------------------------------- l::>:~\"~~ ~~ ~~'L \" ,,~D. I ?-òC{ ~ ~J~ f>" ~ ~ (-~ ~ ~ ~ ~) .('/..0-11.. Ý)"'l), ! ~ I':'.~ ~ ~~}... I \ \ ò~ - \ \ tQ l) Q ÚlJ.(,.~ (J k ~ ~ CMT ~ ~J~ ~ L ) }(Q)å..... ,~~ l '-\ ~(bL~~ ~~::~~~:~.::-::::~~~-;y ~~~~-=~:_-~ ~-----_._------- --=--~::_==~~~-------------- -------------- -------------.--------- ------~----------- ---------- Date:__~3---~ --~- ?M--i----- ,I WELL LOG TRANSMITTAL State of Alaska Alaska Oil and Gas Conservation COl11ß1. Attn.: Lisa Weepie 333 West 7th Avenue, Suite 100 Anchorage, Alaska 9950 ¡ To: RE: January 30, 2003 MWD Formation Evaluation Logs: NK-19A, AK-:M:M-11219 aO/-OfO ( 15éo { NK-19A: Digital Log Images 50-029-22507-01 1 CD ROllI PLEASE ACKNOWLEDGE RECEIPT "BY SIGNING AND RETlJRNING A COpy OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Sperry-Sun Drilling Services Attn: Rob Kalish 6900 Arctic Blvd. Anchorage, Alaska 995 I 8 Date: BP Exploration (Alaska) Inc. Petro-technical -Data Center LR2-1 900 E. Benson Blvd. Anchorage, Alaska 99508 RECEIVED JAN 3 1 2003 ÅJ8$ka Off 8. Gas Cons. CDmm' . Anchorage '_11 \,1 '- é)., 0/ -070 ! 1/5 S WELL LOG TRANSMITTAL To: State of Alaska Alaska Oil and Gas Conservation Comm. Attn.: Lisa Weepie 333 West 7ili Avenue, Suite 100 i\nchorage, Alaska October 2, 2002 RE: MWD Fonnation Evaluation Logs NK-19A, AK-MM-11219 1 LDWG fonnatted Disc with verification listing. API#: 50-029-22507-01 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COpy OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Sperry-Sun Drilling Services Attn: Rob Kalish 6900 Arctic Blvd. Anchorage, Alaska 99518 BP Exploration (Alaska) Inc. Petro-Technical Data Center LR2-1 900 E. Benson Blvd. Anchorage, Alaska 99508 ~ Sign~ --- --&~ Date: RECEIVED OCT 0 9 2002 Alaska on " Gas Cons. CoIßß1i88ion Anchorage , , ( ( STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: ADD PERFS 2. Name of Operator BP Exploration (Alaska), Inc. 3. Address P. O. Box 196612 Anchoraqe, AK 99519-6612 4. Location of well at surface Operation shutdown- Pull tubing Stimulate - Alter casing 5. Type of Well: Development _X Exploratory- Stratigraphic- Service 3846'FNL,815'FEL,Sec.36,T12N, R15E,UM At top of productive interval 5224'FNL,3790'FEL,Sec.30,T12N, R16E, UM At effective depth 4999'FNL,3429'FEL,Sec.30,T12N, R16E,UM At total depth 4856'FNL,3297'FEL,Sec.30,T12N, R16E,UM 12. Present well condition summary Total depth: measured true vertical (asp's 721745, 5979974) (asp's 723513, 5983930) (asp's 723867, 5984166) (asp's 723994, 5984313) 12372 feet 10169 feet Plugging - Periorate _X Repair well Other 6. Datum elevation (DF or KB feet) R KB 53 feet 7. Unit or Property name Naikuk Unit 8. Well number NK-19A 9. Permit number 1 approval number 201-070 10. API number 50-029-22507 -01 11. Field / Pool Niakuk Oil Pool Plugs (measured) CIBP set @ 11950' Effective depth: 11950 feet 9794 feet measured true vertical Junk (measured) Casing Conductor Length 80' 4179' Size 20" Cemented 260 sx AS (Approx) 1100 sx PF 'E', 375 sx Class 'G' 714 sx Class 'G' 456 sx Class 'G' Surface 10-3/4" 7-5/8" 4-1/2" Intermediate Liner 7964' 4475' Perforation depth: measured Open Perls 11251' -11304', 11422'-11472' Perls Below CIBP 12120' - 12140' true vertical Open Perls 9239' - 9277', 9362' - 9400' Perls Below CIBP 9945' - 9963' Tubing (size, grade, and measured depth) 4-1/2", 12.6#, L-80 TBG @ 7912'. Measured Depth 120' 4219' True Vertical Depth 120' 4106' 8002' 7897' - 12372' 7296' 7207' - 101691 RECE\VED APR 1 1 2001. AIaØa on " Gas Cons. CommissiOn - AnchoØJQe Packers & SSSV (type & measured depth) 7-5/8"x4-1/2" BKR SABL-3 PKR @ 7852' MD. 7-5/8"x5-1/2" BKR ZXP PKR @ 7907' MD. 4-1/2" HES CP-2 TRSSSV @ 2071' MD. 13. Stimulation or cement squeeze summary Intervals treated (measured) (see attached) Treatment description including volumes used and final pressure 14. Prior to well operation 03/20/2002 Representative Dailv Average Production or Injection Data Oil-Bbl Gas-Met Water-Bbl Well Shut-In Tubing Pressure Subsequent to operation 03/31/2002 15. Attachments Copies of Logs and Surveys run - Daily Report of Well Operations Oil X Gas 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. ff~ ~ J ~ TItle, Technical Assistant DeWavne R. Schnorr -t:7" ~ 484 49 16. Status of well classification as: Form 10-404 Rev 06/15/88 . Casing Pressure 0 573 Suspended Service Date April 03. 2002 Prepared bv DeWavne R. Schnorr 564-5174 "'~'- \':'~ ' SUBMIT IN DUPLlCAT~ " ~. f ( NK-19A DESCRI PTION OF WORK COMPLETED NRWO OPERATIONS 03/19/2002 RWO POST: PERFORATING 03/19/2002 RWO POST: PERFORATING 03/22/2002 RWO POST: PARAFFIN / ASPHALTENE REMOVAL 03/22/2002 RWO POST: PERFORATING 03/23/2002 RWO POST: PERFORATING 03/19/02 03/19/02 03/22/02 03/22/02 03/23/02 EVENT SUMMARY PUMP 80 BBLS OF 180 DEG CRUDE FOR E-LiNE. COMPLETED ONE OF THREE GUN RUNS. PERFORATED 161 OF 561 INTERVAL (112881-113041) W/ 3 3/811 HSD POWERJET GUN (6 SPF, 60 DEG PHASING). DIFFICULTY RUNNING IN HOLE DUE TO PARAFFIN- DIFFICULTY PULLING OUT OF WELL AFTER FIRING GUN- PULLED EXCESSIVE TENSION. NOTIFIED PAD OPERATOR OF WELL STATUS: LEFT SHUT IN. E-LiNE UNIT CALLED OUT TO A RIG JOB SO JOB IS SUSP - WILL RETURN IN NEAR FUTURE TO COMPLETE JOB & HOT OIL TBG PUMP DOWN WILL BE SCHEDULED. ASSIST E-LiNE. ATTEMPTED TO PERFORATE 401 INTERVAL (112481 TO 112881) W/3 3/8 POWERJETS @ 6 SPF. SHOT 201 INTERVAL (112681-112881). STUCK SECOND GUN WHILE LOGGING TIE-IN PASS. GUN STUCK @ 112481 CCL DEPTH, TOP SHOT @ 112521. ATTEMPTING TO PUMP DOWN WITH HOT OIL TO FREE GUN. CONTINUED ON NEXT DAY WSR. CONTINUED FROM PREVIOUS DAY WSR. UNABLE TO PUMP HOT OIL DOWN HOLE. TOOK 4 HOURS TO PUMP 45 BBL @ 3000PSI. SHOT 201 GUN WITH TOP SHOT @ 112511. GUN FREED UP AFTER SHOT, POOH. COMPLETED SHOOTING 371 INTERVAL (112511-112881) RATHER THAN THE REQUSTED 401 DUE TO THE STUCK GUN. GUNS WERE 3-3/811 PJ 6 SPF RANDOM ORIENTED 60 DEG PHASED GUNS. WELL WAS LEFT SHUT-IN. FLUIDS PUMPED BBLS 1 DI ESEL 3 METHANOL 86 CRUDE 100 HOT CRUDE 190 TOTAL ADD PERFS 03/19 & 23/2002 THE FOLLOWING INTERVAL WAS PERFORATED USING THE 3-3/811 PJ 6 SPF, 60 DEGREE PHASING, RANDOM ORIENTATION. 11 2511 - 113041 Page 1 t STATE OF ALASKA ( ALASKA ulL AND GAS CONSERVATION COMMI\:)SION WELL COMPLETION OR RECOMPLETION REPORT AND LOG ~ 1. Status of Well Classification of Service Well ŒaOil DGas D Suspended D Abandoned D Service 2. Name of Operator 7. Permit Number BP Exploration (Alaska) Inc. 201-070 3. Address 8. API Number P.O. Box 196612, Anchorage, Alaska 99519-6612 50- 029-22507 -01 4. Location of well at surface ~-,-~,..............~...,- .. 9. Unit or Lease Name : :,,"._tf":'~-~:,.'-I-_'~"~ 1434' NSL, 815' WEL, SEC. 36, T12N, R15E, UM 1 ~~r~-' '~-~'l Niakuk At top of productive interval 55' NSL, 1070' EWL, SEC. 30, T12N, R16E UM ,----. ~ 10. Well Number ¡~i" "",t!t At total depth ' "" ~~", ... ' 423' NSL, 1562' EWL, SEC. 30, T12N, R16E, UM ;..:...."~,..,,.:_,,~;...J"~~'~ ," :-,' NK-19A 11. Field and Pool 5. Elevation in feet (indicate KB, OF, etc.) 6. Lease Designation and Serial No. Niakuk Oil Pool KBE = 53.05' ADL 034635 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., Susp., or Aband. 15. Water depth, if offshore 16. No. of Completions 1/2/2002 1/7/2002 1/26/2002 N/ A MSL One 17. Total Depth (MO+ TVD) 18. Plug Back Depth (MD+ NO) 19. Directional Survey 20. Depth where SSSV set 21. Thickness of Permafrost 12372 10169 FT 11950 9794 FT Œa Yes DNo 2071' MD 1800' (Approx.) 22. Type Electric or Other Logs Run MWD, GR, RES, NEU, DEN, PWD, SCMT 23. CASING LINER AND CEMENTING RECORD CASING SETTING DEPTH HOLE SIZE WT. PER FT. GRADE Top BOTTOM SIZE CEMENTING RECORD AMOUNT PULLED 20" 94# H-40 Surface 80' 30" 260 sx Arctic Set (Approx.) 10-3/4" 45.5# NY80LHE 40' 4219' 13-1/2" 1100 sx PF 'E', 375 sx Class 'G' 7-5/8" 29.7# NT-80S 38' 8002' 9-7/8" 714 sx Class 'G' 4-1/2" 12.6# L-80 7897' 12372' 6-3/4" 456 sx Class 'G' 24. Perforations open to Production (MD+ TVD of Top and 25. TUBING RECORD Bottom and interval, size and number) SIZE DEPTH SET (MD) PACKER SET (MD) 3-3/8" Gun Diameter, 6 spf 4-1/2'" 12.6#, L-80 7912' 7852' MD TVD MD TVD 11422' - 11472' 9362' - 9400' 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Below CIBP Below CIBP DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED 11950' Set clap 12120' - 12140' 9945' - 9963' Freeze Protected with Hot Oil 27. PRODUCTION TEST Date First Production Method of Operation (Flowing, gas lift, etc.) January 29, 2002 Gas Lift Date of Test Hours Tested PRODUCTION FOR OIL-BBL GAs-McF WATER-BBL CHOKE SIZE GAS-OIL RATIO TEST PERIOD Flow Tubing Casing Pressure CALCULATED OIL-BBL GAs-McF WATER-BBL OIL GRAVITy-API (CORR) Press. 24-HoUR RATE 28. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit cR!CEIVED No core samples were taken. MAR '1 ,,~ .'~ ",~' ') .1 ~:') {~!:i,!, - A.\~ œ &. G:.aS oms. COmmission J~~~~lj!~lt:Cì~~r;\Ø Form 10-407 Rev. 07-01-80 OR G I ~~. RBDMS 8FL MAR Submit In Duplicate ¡ 8 2 I I' t\ L _002 ~ 29. Geologic Markers Marker Name Measured True Vertical Depth Depth Kuparuk 11242' 9233' Niakuk Kuparuk / Zone 2A 11242' 9233' Niakuk Kuparuk / Zone 28 11259' 9245' Niakuk Kuparuk / Zone 2C 11281' 9261' Niakuk Kuparuk / Zone 2D 113111 92821 Niakuk Kuparuk / Zone 2E 11342' 9304' Niakuk Kuparuk / Zone 3A 11348' 9309' Niakuk Kuparuk / Zone 38 11392' 9340' Niakuk Kuparuk / Zone 3C 11408' 9352' Niakuk Kuparuk / Zone 3D 11438' 93741 Niakuk Kuparuk / Zone 7 A 11468' 9397' Niakuk Kuparuk / Zone 78 11522' 9438' Kingak 11557' 9466' Sag River 12097' 9924' Shublik 12188' 100051 Sadlerochit 12259' 10069' 31. List of Attachments: Summary of Daily Drilling Reports, Surveys ~ 30. Formation Tests Include interval tested, pressure data, all fluids recovered and gravity, GOR, and time of each phase. ~'" '¡,.."r' " I~.. [r)'~ I¡~"'~'\ i :~ ii~ß, Ü II) n, ~/,:' 'L') 1,,1 i,'l! ,,:' ~~L,,'1,~¡I' ,.'1_,,1.., #\íaska Œ¡ &; G:tS COOS. Commission ;'\'t,."I!;~~,~,':!I".~, l'I,tU"",:¡¡¡.},Ô;:;It1> 32. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed Terrie Hubble ~ Title Technical Assistant Date 03.07.0 NK-19A Well Number 201-070 Permit No. / A roval No. INSTRUCTIONS Prepared By Name/Number: Terrie Hubb/e, 564-4628 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 cementing and the location of the cementing tool. ITEM 28: If no cores taken, indicate 'none', ITEM 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-In, Other-explain. Form 10-407 Rev. 07-01-80 " ' , " ,",',," "BPgXPLOR?\TION " '<,.." Page 1 of 1 " ,', Leélk~O.ffT~~t ~ U m ma'ry '- ".',< ,,',,' ", ~~~ ',',' Legal Name: NK-19 Common Name: NK-19A TesfType , Test Depth (mo) "" Test Date " ' Test Qep.tl1(1VD) AMW Sûtfâce Pressure Leak Off Pressure (BHP) EMW 1/1/2002 FIT 8,031.0 (ft) 7,320.0 (ft) 9.55 (ppg) 1,200 (psi) 4,831 (psi) 12.71 (ppg) - - ~~-. '-"- Printed: 1/14/2002 10:09:51 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date 12/29/2001 12/30/2001 12/31/2001 1/1/2002 (" ,( BP EXPLORATION Operations Summary Report NK-19 NK-19A REENTER+COMPLETE DOYON DOYON 14 From - To Hours Activity Code NPT 22:00 - 00:00 00:00 - 04:00 04:00 - 06:00 06:00 - 08:30 08:30 - 09:00 09:00 - 09:30 09:30 - 11 :30 11 :30 - 12:30 12:30 - 17:30 17:30 - 18:30 18:30 - 19:30 19:30 - 20:30 20:30 - 21 :00 21:00-21:30 21 :30 - 00:00 00:00 - 00:30 00:30 - 01 :00 01 :00 - 06:00 06:00 - 07:00 07:00 - 08:00 08:00 - 09:00 09:00 - 15:00 15:00 - 16:30 16:30 -17:00 17:00 -17:30 17:30 - 20:30 20:30 - 21 :30 21 :30 - 23:30 23:30 - 00:00 00:00 - 03:30 03:30 - 04:00 04:00 - 06:00 06:00 - 07:00 07:00 - 11 :30 11 :30 - 12:00 12:00 - 14:00 14:00 - 21 :30 21 :30 - 22:30 22:30 - 23:30 2.00 MOB 4.00 MOB P P 2.00 WHSUR P 2.50 KILL P 0.50 WHSUR P 0.50 WHSUR P 2.00 BOPSUF P 1.00 BOPSUF P 5.00 BOPSUF P 1.00 BOPSUF P 1.00 PULL P 1.00 PULL P 0.50 PULL 0.50 PULL 2.50 PULL 0.50 PULL 0.50 PULL P P P P P 5.00 PULL P 1.00 BOPSUF P 1.00 PULL P 1.00 CLEAN P 6.00 CLEAN P 1.50 CLEAN P 0.50 CLEAN P 0.50 CLEAN P 3.00 CLEAN P 1.00 CLEAN P 2.00 REST P 0.50 REST P 3.50 DHEQP P 0.50 DHEQP P 2.00 STWHIP P 1.00 STWHIP P 4.50 STWHIP P 0.50 STWHIP P 2.00 STWHIP P 7.50 STWHIP P 1.00 STWHIP P 1.00 STWHIP P Phase PRE PRE DECOMP DECOMP DECOMP DECOMP DECOMP DECOMP DECOMP DECOMP DECOMP DECOMP DECOMP DECOMP DECOMP DECOMP DECOMP DECOMP DECOMP DECOMP DECOMP DECOMP DECOMP DECOMP DECOMP DECOMP DECOMP DECOMP DECOMP DECOMP DECOMP WEXIT WEXIT WEXIT WEXIT WEXIT WEXIT WEXIT WEXIT Page 1 of 4 Start: 12/30/2001 Rig Release: 1/12/2002 Rig Number: Spud Date: 10/10/1994 End: 1/12/2002 Description of Operations Move rig from NK-22A to NK-19A. Continue to move rig from NK-22A to NK-19A. Spot rig over NK-19A. Cantilever rig floor. Hook up mud lines. Take on sea water. Accept rig at 04:00 12/30101. PU lubricator and pull BPV. RU to circulate. LD lubricator. Test lines to 3,500 psi. Displace diesel from tubing. Make complete circulation down tubing. Flow check. Well static. Install TWC. Test from below to 1,000 psi. ND tree. Check tubing hanger threads. NU BOPE. Rig up to test BOP. Test BOPE to 250 psi 1 5,000 psi as per AOGCC regulations and BP policy. Test witnessed by Chuck Sheave of AOGCC. RD BOP test equipment. Pull TWC with lubricator. MU landing joint. BOLDS. Work tubing free. Tubing broke loose at 210,000 Ibs. Pull tubing hanger to rig floor. Circulate bottoms up at 10 bpm, 680 psi. LD tubing hanger. LD 4 1/2" tubing with control line. LD tubing and control line. LD TRSSSV and control line spool. Recovered 56 of 56 SS bands. Continue to LD tubing. Set test plug and test bottom pipe rams to 250 psi / 5,000 psi as per AOGCC regs and BP policy. LD test joint and test plug. Install wear bushing. Clear rig floor. LD casing tools. PU BHA to rig floor. MU window milling assembly. RIH with DP 1x1 from pipe shed to 6,900'. TIH with 4" DP from derrick to top of 4 1/2" tubing stub at 8,395'. CBU. Slip and cut drilling line. POH. SLM, no correction. Stand back HWDP and DCs. LD mills. RU eline and bridge plug. Run bridge plug on eline. Continue RIH with bridge plug on eline. Tie in to GR on jet cutter log from 4/2001. Set bridge plug (center of element) at 8,028' WLM, 4 feet above a casing collar. POH. RD eline. Test casing to 3,900 psi for 30 minutes. MU window mills and MWD. Orient whipstock. MU whipstock. Load MWD. Flow test. RIH to 7,973'. Orient and set whipstock at 8,021', 84 degrees right of high side. Displace well bore to 9.6 ppg LSND drilling fluid. Mill window in 7 5/8" casing and 20' of new formation to 8,031'. Top of window 8,002', Bottom of window 8,015'. Circulate sweep. Pull into casing and perform FIT test to 12.7 ppg EMW. Pump dry job and blow down top drive. Printed: 1/14/2002 10:09:59AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date 1/1/2002 1/2/2002 1/3/2002 1/4/2002 1/5/2002 1/6/2002 1/7/2002 1/8/2002 t { Page 2 of 4 BP EXPLORATION Operations Summary Report NK-19 NK-19A REENTER+COMPLETE DOYON DOYON 14 From - To Hours Activity Code NPT 23:30 - 00:00 00:00 - 02:00 02:00 - 04:30 04:30 - 05:00 05:00 - 06:00 06:00 - 07:00 07:00 - 10:00 10:00 -12:00 12:00 - 00:00 00:00 - 12:00 12:00 - 17:00 17:00 -17:30 17:30 -18:30 18:30 - 19:30 19:30 - 20:30 20:30 - 00:00 00:00 - 00:00 00:00 - 10:00 10:00 - 11 :30 11 :30 - 17:00 17:00 - 18:00 18:00 - 18:30 18:30 -19:30 19:30 - 20:30 20:30 - 21 :00 21:00 - 21:30 21 :30 - 00:00 00:00 - 02:00 02:00 - 02:30 02:30 - 07:00 07:00 - 09:30 09:30 - 10:00 10:00 - 10:30 10:30 -12:00 12:00 - 14:30 14:30 - 00:00 00:00 - 12:00 12:00 - 00:00 00:00 - 01 :30 01 :30 - 03:30 0.50 SlWHIP P 2.00 SlWHIP P 2.50 SlWHIP P 0.50 SlWHIP P 1.00 DRILL P 1.00 DRILL P 3.00 DRILL P 2.00 DRILL P 12.00 DRILL P 12.00 DRILL P 5.00 DRILL P 0.50 DRILL P 1.00 DRILL P 1.00 DRILL P 1.00 DRILL P 3.50 DRILL P 24.00 DRILL P 10.00 DRILL P 1.50 DRILL P 5.50 DRILL P 1.00 DRILL P 0.50 DRILL P 1.00 DRILL P 1.00 DRILL P 0.50 DRILL P 0.50 BOPSU¡::; P 2.50 BOPSU¡:; P 2.00 BOPSU¡::; P 0.50 BOPSU¡:; P 4.50 DRILL P 2.50 DRILL 0.50 DRILL 0.50 DRILL 1.50 DRILL 2.50 DRILL P P P P P 9.50 DRILL 12.00 DRILL p p 12.00 DRILL P 1.50 DRILL 2.00 DRILL P P Phase WEXIT WEXIT WEXIT WEXIT PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 PROD1 Start: 12/30/2001 Rig Release: 1/12/2002 Rig Number: Spud Date: 10/10/1994 End: 1/12/2002 Description of Operations POH. POH to BHA. LD window milling BHA. Down load MWD. Upper water melon mill in gauge. MU stack washer and wash inside BOP. MU BHA. Adjust motor bend to 1.22 deg and orient to MWD. Load radio active source and flow test MWD. RIH to 7,740'. MAD pass from 7,740' to 8,022' for tie in to well bore. Drill 6 3/4" hole from 8,031' to 8,445'. Drill from 8,445' to 8,821'. AST=4.7, ART=3.0. Drill from 8,821' to 9,002'. Pump sweep and circulate bottoms up. Short trip to window at 8,002'. Slip and cut drilling line. TIH to 9,002'. Drill from 9,002' to 9,306'. Drill 6 3/4" hole from 9,306' to 10,390'. AST=8.75, ART=11.25. Drill from 10,390' to 10,746'. ART=6.25. AST=1.25. Pump sweep and circulate bottoms up. Flow check. Well static. POH to change bit and BHA. LD HWDP. Stand back DCs. Unload RA source and flush MWD and motor with water. Down load MWD and remove electronics from HOC. Break bit and LD mud motor. Pull wear bushing. RU to test BOPE. Test BOPE to 250 psi 1 5,000 psi as per BP policy and AOGCC regulation. Witness of test waived by John Crisp of AOGCC. Continue testing BOPE to 250 psi / 5,000 psi. Install wear bushing. MU BHA. PU mud motor, float sub, AGS, MWD tools. MU bit. Adjust motor bend to 1.22 deg. Orient motor to MWD. MU HOC. Upload to MWD. Test adjustable gauge stabilizer. PU DCs, load RA sources. PU jars and HWDP. Shallow test MWD. RIH with 4" DP to 6,091'. PU 12 joints of 4" DP and stand back. TIH to 7,913'. Slip and cut drilling line. Service top drive. TIH to 10,764'. Hole a little tight at 10,600' after check shot survey. Ream from 10,600' to 10,746'. No fill on bottom. Drill from 10,746' to 11,330'. AST=2.5, ART=4. Drill 6 3/4" hole from 11,330' to 11,773'. Open AGS when rotating and close AGS when sliding. AST=3.25, ART=3. Difficulty sliding. Wall hanging and serveral motor stalls. Increase lubtex concentration and sliding improved greatly. BHA had build tendency while rotating. Drill from 11,773' to TD at 12,372'. AST=O, ART=8.9. Rotate with AGS closed from 11,475' to TD. BHA had left hand walk and drop tendency while rotating. Circulate bottoms up, 3320 psi at 7 bpm Wiper trip from 12,372' to 10,506', wellbore good condition Printed: 1/14/2002 10:09:59 AM { !{ BP EXPLORATION Page 3 of 4 Operations Summary Report Legal Well Name: NK-19 Common Well Name: NK-19A Spud Date: 10/10/1994 Event Name: REENTER+COMPLETE Start: 12/30/2001 End: 1/12/2002 Contractor Name: DOYON Rig Release: 1/12/2002 Rig Name: DOYON 14 Rig Number: Date From - To Hours Activity Code NPT Phase Description of Operations 1/8/2002 03:30 - 05:30 2.00 DRILL P PROD1 Circulate sweep, 3200 psi at 6.5 bpm 05:30 - 06:30 1.00 DRILL P PROD1 Circulate liner running pill, 3200 psi at 6.5 bpm, flow check. POH recording up and down wts. every 1,500 ft. in open hole. 06:30 - 11 :30 5.00 DRILL P PROD1 Trip out with no adverse hole conditions to 7625', flow check, pump dry job, trip out to BHA 11:30 -15:00 3.50 DRILL P PROD1 UD BHA, PJSM, recover nuclear sources, download MWD, UD BHA 15:00 - 16:00 1.00 CASE P CaMP Rig up to run 4 1/2" Hydril 521 liner 16:00 - 00:00 8.00 CASE P CaMP PJSM, run liner as per program 1/9/2002 00:00 - 00:30 0.50 CASE P CaMP Circulate liner volume 1418', 320 psi at 5.6 bpm, 610 psi at 7.5 bpm 00:30 - 03:30 3.00 CASE P COMP Trip in liner from 1418' to 7844', 03:30 - 04:30 1.00 CASE P COMP Circulate bottoms up, 860 psi at 7 bpm 04:30 - 06:00 1.50 CASE P COMP Trip in liner from 7844' to 9857', tight wellbore 06:00 - 11 :00 5.00 CASE P CaMP Wash and rotate liner from 9857' to 10,238', 480 psi at 2.5 bpm 11 :00 - 12:30 1.50 CASE N RREP CaMP Rig repair, change out saver sub 12:30 - 14:00 1.50 CASE P CaMP Wash and rotate from 10,230' to 10,750', 500 psi at 2.8 bpm. Hole packing off and tight. Unable to pull out due to turbulators. 14:00 - 19:00 5.00 CASE P CaMP Circulate to clean up annulus, reciprocate from 10,750' to 10,790', 28 - 45 spm, 500 to 900 psi, 30 rpm, PU 185, SO 145, torque 6 - 8,000 19:00 - 00:00 5.00 CASE P COMP Wash, work and rotate liner from 10,790' to 12,372' 1/10/2002 00:00 - 03:00 3.00 CASE P CaMP Circulate wellbore with liner on bottom, max 1660 psi at 7 bpm, rotate and reciprocate liner with 5-20 RPM @ 7.000-8,000. 03:00 - 04:30 1.50 CASE P COMP Test lines, cement as per program wi Dowel 04:30 - 05:00 0.50 CASE P COMP Displace with rig pump, bump plug at calculated displacement. Pressure up to 3,500 to set hanger. (At app. 3,000 psi there was a sudden pressure drop of app. 500 psi. As the pressure was brought up to 3,500 no further losses were noted.) Slack off and pressure up to 4,000 to release from liner. Two attempts were required to release. 05:00 - 05:30 0.50 CASE P COMP Pick up out of hanger app. 6 ft. to engage packer setting dogs. Slack off 75K and noted a good bounce on wt, indicator. When an attempt was made to pick back up and repeat setting operation, there was a 50K overpull on string. Attempt to release by slacking back to string wt. and pick back up. Set down to string wt. and turn to the right with 4,500 torque App. 2.5 turns at surface. Did not rotate string. Pick up and pull free with 55K overpull. 05:30 - 06:30 1.00 CASE P COMP Circulate bottoms up from liner top, no cement, some perf pill 06:30 - 07:00 0.50 CASE P COMP Pressure test casing, not successful. 07:00 - 07:30 0.50 CASE P CaMP Rig down cement head and lines 07:30 - 11 :30 4.00 CASE P COMP Trip out drill pipe, lay down 1 x 1 to pipe shed 11 :30 - 13:00 1.50 CASE N DFAL COMP Trip out drill pipe to derrick by stands 13:00 - 14:00 1.00 CASE N DFAL COMP Slip and cut drilling line 14:00 - 14:30 0.50 CASE N DFAL COMP Trip out drill pipe to derrick by stands 14:30 -15:00 0.50 CASE N DFAL COMP Handle Baker setting tools, inspect same. All of running tool recovered. --.. Printed: 1/14/2002 10:09:59 AM ( ~I.. '. BP EXPLORATION Page 4 of 4 Operations Summary Report Legal Well Name: NK-19 Common Well Name: NK-19A Spud Date: 10/10/1994 Event Name: REENTER+COMPLETE Start: 12/30/2001 End: 1/12/2002 Contractor Name: DOYON Rig Release: 1/12/2002 Rig Name: DOYON 14 Rig Number: Date From - To Hours Activity Code NPT Phase Description of Operations 1/10/2002 15:00 -17:30 2.50 CASE N DFAL COMP Trip in to top of liner, 7897' 17:30 -18:00 0.50 CASE N DFAL COMP Set packer wi Baker supervisor 18:00 - 19:00 1.00 CASE N DFAL CaMP Pressure test casing, liner hanger, liner to 3500 psi for 30 minutes, OK 19:00 - 21:30 2.50 CASE P COMP Reverse circulate mud out to brine, 9.5 #/gal 21 :30 - 00:00 2.50 CASE P CaMP Trip out, lay down drill pipe to pipe shed 1/11/2002 00:00 - 04:00 4.00 CASE P COMP Trip out laying down drill pipe to pipe shed 04:00 - 04:30 0.50 RUNCa~ (P COMP Pull wear bushing 04:30 - 05:30 1.00 RUNCa~ (P COMP Rig up to run 4 1/2" completion tubing 05:30 - 12:00 6.50 RUNCor (p CaMP Run 4 1/2" competion tubing as per program 12:00 - 13:00 1.00 RUNCor (P CaMP Pick up and rig in Halliburton control line spool with tools, connect line, pressure test to 5000 psi 13:00 -16:30 3.50 RUNCor (P CaMP Run 41/2" completion tubing with SSSV control line.( 52 S.S. control line bands run in completion) 16:30 -17:30 1.00 RUNCor 'P CaMP Space out with pup joints. Tubing Wt. at time of landing ==90k up and 70k down. These values are do not include block wt. 17:30 - 18:30 1.00 RUNCor 'P COMP PU, MU, tubing hanger, test, land tubing. RI.L.D.S. and torque to FMC Specs. 18:30 - 20:30 2.00 RUNCa~ p COMP Rig up circulating manifold, displace 100 bbls inhibited seawater, 3 bpm at 210 psi 20:30 - 22:00 1.50 RUNCa~ p COMP Drop ball, pressure test tubing to 3500 psi, packer set at 1800 psi, hold for 30 minutes, bleed tubing pressure to 1500 psi, pressure test annulus to 3500 psi for 30 minutes, tubing pressure rose to 2200 psi, bleed down to shear RP valve 22:00 - 23:00 1.00 RUNCO~ P CaMP Rig down circulating manifold, lay down landing joint, set TWC, test to 3500 psi 23:00 - 00:00 1.00 RUNCa~ p COMP Change out top rams to 4 1/2" X 7" variable rams, change out saver sub on top drive 1/12/2002 00:00 - 02:00 2.00 WHSUR P COMP Nipple down BOPE, change out saver sub on top drive 02:00 - 04:00 2.00 WHSUR P COMP Nipple up tree and adapter flange, PT to 5000 psi for 10 minutes 04:00 - 04:30 0.50 WHSUR P COMP Rig up lubricator, pull TWC with DSM 04:30 - 05:00 0.50 WHSUR P COMP Rig up Little Red to freeze protect annulus 05:00 - 06:00 1.00 WHSUR P COMP Freeze protect with 109 bbls, 1450 psi at 2.5 bpm 06:00 - 07:00 1.00 WHSUR P COMP Allow wellbore to U - tube 07:00 - 07:30 0.50 WHSUR P COMP Pressure test SSSV to 1000 psi for 10 minutes on annulus 07:30 - 08:00 0.50 WHSUR P COMP Rig down hot oil unit 08:00 - 09:00 1.00 WHSUR P COMP Remove double valves on wellhead, install blind flanges, secure well, Rig released at 09:00 hrs Printed: 1/14/2002 10:09:59 AM ( " 'I ,t Well: Field: API: Permit: NK-19A Niakuk Oil Pool 50-029-22507 -01 201-070 Rig Accept: Rig Spud: Rig Release: DrillingB.g: 12/30/01 01 /02/02 01/12/02 Doyon 14 '-'---' "'---"""'---"""'-""'..--..--..-..-.....-.-........---'-""- .--_.",...-_."-._--"....",._,...-"..,-,------,, '" -"""'-'--""'" -'----.-,,---.-..- -""'--"--"-----"""-'-"'---_.' ""'-,,- '-'--'--""'--'-'-'--- ""...,_""",_""""-"-'-'-'--'- "",--"--"-"""""'-""""----"-"--'-""-'- -..." "...,.",,-,--...,--. POST - RIG WORK 01/17/02 PULL BALL & ROD I PULL STA # 1,3,4. SET NEW GLV DESIGN. PULL RHC, DRIFT TBG WI 3.5" DMY GUN TO 8230' SLM. TOOLS STOPED FALLING (SUSPECT MUD, HOLE ANGLE OF 32 DEG). 01/20/02 CIRC OUT, UNDER BALANCE, CTU #8, MIRU SPOT EQUIPMENT PT ALL. 01/21/02 CIRC OUT I UNDERBALANCE FOR PERF. RIH WITH 2" JSN, CIRC OUT FLO-PRO FROM LIGHT TAG OF 12340' CTD, CIRC IN 9.3# BRINE TO 10400' CTD, DIESEL FROM 10400' TO SURFACE. 01/22/02 COMPLETED SCMT WITH JEWLERY LOG. 01/23/02 ATTEMPTED US IT LOG TO CORRELATE WITH SCMT RAN PREVIOUS DAY. UNABLE TO GET TOOLS BELOW DOG LEG @ 8750'. JOB WAS ABORTED DUE TO WEATHER MINIMUMS & QUALITY OF SCMT LOG. 01/24/02 TAG TO W/ 33/8" D.G. @ 12,263' SLM. 01/26/02 COMPLETED PERFORATION. SHOT 20' INTERVAL (12120'-12140') WITH 3-3/8" SWS POWERJET 6 SPF GUNS (TWO GUN RUNS). WELL WAS SHOT UNDER BALANCED. WH PRESSURE AFTER FIRST GUN WAS 450# AND 750# AFTER SECOND SHOT. ATTEMPTED STATIC LOG AFTER PERFORATING. 01/27/02 ATTEMPTED STATIC SURVEY. PARKED TOOLS 30' ABOVE PERFS AND LOGGED FOR 5 HOURS. BOTTOM HOLE PRESSURE CONTINUED TO DROP AT A 20 PSI/HR RATE. JOB WAS ABORTED AFTER CONSULTING WITH TOWN. LEFT WELL SHUT-IN FOR SLlCKLINE STATIC AFTER WELL STABILIZES. 01/29/02 DRIFT, LOCATE "XN" NIPPLE FOR BHP SURVEY. PERFORM SIBHPS. PERFORM FBHPS. 01/30/02 CONTINUE FLOWING WELL. SHUT IN WELL. FREEZE PROTECT TUBING AND FLOW LINE. 01/31/02 POOH W /PETREDA T GAUGES. 02/07/02 SET CIBP AT 11950 FT. 02109/02 PERFORATE 11452'-11472' CORRELATED TO SWS SCMT LOG DATED 22-JAN-2002. CALCULATED PRESSURE DOWNHOLE PRIOR TO SHOT 3560 PSI. POH WITH GUN, FLOW WELL 30 MINUTES @ 850 PSI. S/I AND FREEZE PROTECT TBG/ FL. STANDBACK FOR NIGHT. ,~ " : ~ NK-19A, Post-Sidetrack Operatll.-...:i Page 2 (, 0211 0/02 PERFORATE INTERVAL: 11422'-11452'. LOG STATIC PRESSURE- 9200' SSTVD PRESSURE READING APPROX 4066 PSI. 02120/02 PUMP HOT CRUDE DOWN TUBING TO WARM WELLBORE/FREEZE PROTECT AOGCC 333 W. 7th Ave. Suite 100 Anchorage, AK 99501 Definitive Survey Re: Distribution of Survey Data for Well NK-19A Dear Dear Sir/Madam: Enclosed are two survey hard copies and 1 disk Tie-on Survey: 7,992.65' MD Window / Kickoff Survey 8,002.00' MD Projected Survey: 12,372.00' MD (if applicable) Please call me at 273-3545 if you have any questions or concerns. Regards, William T. Allen Survey Manager Attachment(s) RECEIVED FEB 2 0 2002 AIaD Oil & Gas Cons. CommÌ8liOn Anchorage ~,'1""I\:""";'."""",A,"","~'",,",'r\,,",',', ø'9'r~'c;..J" , \;...J 06-Feb-02 North Slope Alaska Alaska Drilling & Wells NIAKUK, Slot NK-19 NK-19A Job No. AKMM11219, Surveyed: 8 January, 2002 SURVEY REPORT 6 February, 2002 Your Ref: 500292250701 Surface Coordinates: 5979974.62 N, 721744.65 E (70020' 51.2046" N, 148011' 58.9968" W) Surface Coordinates relative to Project H Reference: 979974.62 N, 221744.65 E (Grid) Surface Coordinates relative to Structure: 5525.875, 5605.32 E (True) Kelly Bushing: 53.05ft above Mean Sea Level 5 pI!!"'" r" V-55 U f'1 CRI~L,..ING "IiiRVlc:e¡¡S A Halliburton Company \ '. DEFINITIVE I' ( Survey Ref: 5vy11096 ¿? . Sperry-Sun Drilling Services Survey Report for NK-19A Your Ref: 500292250701 Job No. AKMM11219, Surveyed: 8 January, 2002 Alaska Drilling & Wells North Slope Alaska NIAKUK Measured Sub-Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northlngs Eastlngs Northlngs Eastlngs Rate Section Comment (ft) (ft) (ft) (ft) (ft) (ft) (ft) (°/1 DOft) 7992.65 31.640 357.510 7234.77 7287.82 2524.40 N 218.90 W 5982491.44 N 721451.16 E 2072.69 Tie-on Point MWD Magnetic 8002,00 31.640 357.400 7242.73 7295.78 2529.30 N 219.12W 5982496.33 N 721450.79 E 0.617 2076.81 Window 8021.13 30.570 0.820 7259.11 7312.16 2539.18 N 219.28 W 5982506.20 N 721450.34 E 10.795 2085.27 ( 8053.47 31.780 6.450 7286.79 7339.84 2555.87 N 218.20 W 5982522.92 N 721450.92 E 9.754 2100.24 8083.92 32.930 11.530 7312.51 7365.56 2571.95 N 215.65 W 5982539.07 N 721453.00 E 9.691 2115.43 8116.66 34.710 16.700 7339.72 7392.77 2589.60 N 211.19 W 5982556.84 N 721456.94 E 10.331 2132.94 8148.68 35.320 20.510 7365.94 7418.99 2607.01 N 205.32 W 5982574.41 N 721462.28 E 7.087 2150.93 8179.44 36.140 22.800 7390.92 7443.97 2623.70 N 198.69 W 5982591.29 N 721468.42 E 5.099 2168.69 8211.11 37.170 25.550 7416.32 7469.37 2640.94 N 190.95 W 5982608.76 N 721475.65 E 6.119 2187.49 8243.27 38.360 28.830 7441.75 7494.80 2658.45 N 181.94W 5982626.52 N 721484.13 E 7.259 2207.15 8275.30 39.550 31 .440 7466.66 7519.71 2675.86 N 171.83W 5982644.23 N 721493.72 E 6.328 2227.29 8306.59 41.030 34.030 7490.53 7543.58 2692.87 N 160.88 W 5982661.55 N 721504.16 E 7.142 2247.50 8338.95 42.180 36.530 7514.73 7567.78 2710.41 N 148.47 W 5982679.45 N 721516.05 E 6.240 2268.89 8372.09 43.250 38.790 7539.08 7592.13 2728.20 N 134.74 W 5982697.64 N 721529.25 E 5.641 2291.18 8402.97 44.860 41.220 7561.27 7614.32 2744.64 N 120.93 W 5982714.48 N 721542.57 E 7.557 2312.33 8436.63 46.040 42.910 7584.88 7637.93 2762.44 N 104.86 W 5982732.75 N 721558.11 E 5.009 2335.80 8467.31 46.570 44.430 7606.08 7659.13 2778.49 N 89.54 W 5982749.24 N 721572.94 E 3.977 2357.36 8499.40 47.900 46.140 7627.87 7680.92 2795.06 N 72.80 W 5982766.30 N 721589.19 E 5.699 2380.10 8530.82 49.230 48.250 7648.66 7701.71 2811.06N 55.52 W 5982782.81 N 721605.99 E 6.577 2402.62 8562.63 50.930 49.600 7669.07 7722.12 2827.08 N 37.12 W 5982799.37 N 721623.90 E 6.257 2425.72 ( 8594.85 52.T10 51.380 7688.98 7742.03 2843.20 N 17.57 W 5982816.05 N 721642.96 E 7.175 2449.47 8626.73 54.370 52.870 7707.91 7760.96 2858.94 N 2.67 E 5982832.39 N 721662.73 E 6.271 2473.26 8658.17 56.200 54.510 7725.81 7778.86 2874.24 N 23.50 E 5982848.30 N 721683.10 E 7.229 2496.95 8690.59 t)7.!)50 56.270 7743.53 7796.58 2889.66 N 45.85 E 5982864.37 N 721704.98 E 6.165 2521.51 8721.62 58.240 57.480 7760.02 7813.07 2904.02 N 67.86 E 5982879.38 N 721726.56 E 3.982 2544.98 8754.86 58.250 57.800 7777.52 7830.57 2919.15 N 91.73 E 5982895.21 N 721749.97 E 0.819 2570.06 8849.90 58.890 60.400 7827.08 7880.13 2960.78 N 161.31 E 5982938.88 N 721818.29 E 2.429 2641.02 8947.32 58.740 60.260 7877.53 7930.58 3002.04 N 233.73 E 5982982.26 N 721889.45 E 0.197 2713.07 9042.92 58.760 59.910 7927.12 7980.17 3042.80 N 304.57 E 5983025.10 N 721959.06 E 0.314 2783.90 9139.99 58.500 58.510 7977.65 8030.70 3085.22 N 375.76 E 5983069~61 N 722028.97 E 1.260 2856.35 .-.-.....--..-....--"---'-' ---.----.---"."'--"'- -.,,----, '..-"'.-' , ..-""-'.--'--'----'-'------. 6 February, 2002 - 13:31 Page 2 of 5 '. DrillQuest 2.00.09.008 Sperry-Sun Drilling Services . Survey Report for NK-19A Your Ref: 500292250701 ~, Job No. AKMM11219, Surveyed: 8 January, 2002 Alaska Drilling & Wells North Slope Alaska NIAKUK Measured Sub-Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northlngs Eastlngs Northlngs Eastings Rate Section Comment (ft) (ft) (ft) (It) (It) (ft) (ft) (°/1 OOft) 9237.14 58.230 60.520 8028.61 8081.66 3127.18 N 447.04 E 5983113.66 N 722098.97 E 1.783 2928.44 9333.12 59.280 60.230 8078.40 8131.45 3167.75 N 518.37 E 5983156.32 N 722169.07 E 1.124 2999.35 9429.04 59.010 60.250 8127.59 8180.64 3208.62 N 589.85 E 5983199.29 N 722239.31 E 0.282 3070.61 9523.36 60.110 61.860 8175.38 8228.43 3247.97 N 661.01 E 5983240.72 N 722309.27 E 1.878 3140.38 ( 9619.83 59.960 61.240 8223.56 8276.61 3287.78 N 734.49 E 5983282.69 N 722381.54 E 0.578 3211.72 9714.96 59.460 62.170 8271.55 8324.60 3326.72 N 806.82 E 5983323.75 N 722452.69 E 0.994 3281. 73 9812.56 58.330 61.980 8321.97 8375.02 3365.85 N 880.66 E 5983365.06 N 722525.33 E 1.170 3352.66 9908.69 55.820 60.890 8374.21 8427.26 3404.42 N 951.52 E 5983405.70 N 722595.03 E 2.779 3421.61 10002.96 56.870 63.280 8426.46 8479.51 3441.14 N 1 020.86 E 5983444.46 N 722663.24 E 2.386 3488.20 10099.20 59.180 63.370 8477.42 8530.47 3477.79 N 1 093.80 E 5983483.25 N 722735.07 E 2.402 3556.53 10195.33 58.180 62.880 8527.39 8580.44 3514.91 N 1167.05 E 5983522.52 N 722807.19 E 1.128 3625.43 10292.10 55.710 61.370 8580.17 8633.22 3552.81 N 1238.75 E 5983562.53 N 722877.74 E 2.868 3694.22 10388.54 52.420 60.740 8636.76 8689.81 3590.59 N 1307.07 E 5983602.31 N 722944.91 E 3.452 3761.21 10484.67 54.400 60.490 8694.06 8747.11 3628.47 N 1374.32 E 5983642.16 N 723011.01 E 2.070 3827.75 10580.54 54.130 60.230 8750.05 8803.10 3666.95 N 1441.96E 5983682.63 N 723077.48 E 0.357 3895.00 10676.57 51 . 140 59.890 8808.33 8861.38 3705.03 N 1508.09 E 5983722.65 N 723142.46 E 3.126 3961 .16 10715.90 50.570 60.820 8833.15 8886.20 3720.12 N 1534.60 E 5983738.52 N 723168.51 E 2.337 3987.52 10813.90 51.750 65.010 8894.63 8947.68 3754.84 N 1602.54 E 5983775.23 N 723235.40 E 3.541 4051.68 10909.32 50.030 62.560 8954.83 9007.88 3787.53 N 1668.97 E 5983809.87 N 723300.82 E 2.687 4113.31 11006.03 49.300 63.920 9017.42 9070.47 3820.72 N 1734.78 E 5983845.00 N 723365.63 E 1.311 4175.08 11103.02 46.620 61.610 9082.37 9135.42 3853.65 N 1798.83 E 5983879.81 N 723428.67 E 3.281 4235.73 ( 11199.47 44.760 60.310 9149.74 9202.79 3887.14 N 1859.17 E 5983915.07 N 723488.00 E 2.156 4295.00 11293.74 44.690 59.970 9216.72 9269.77 3920.17 N 1916.70 E 5983949.78 N 723544.53 E 0.264 4352.46 11392.08 43.630 61.850 9287.27 9340.32 3953.48 N 1976.56 E 5983984.85 N 723603.37 E 1.713 4411.34 11487.99 40.010 64.090 9358.74 9411.79 3982.58 N 2033.49 E 5984015.62 N 723659.42 E 4.083 4465.10 11583.30 36.180 61.030 9433.74 9486.79 4009.60 N 2085.68 E 5984044.18 N 723710.79 E 4.479 4514.69 11678.24 34.840 56.380 9511.04 9564.09 4038.20 N 2132.79 E 5984074.15 N 723757.03 E 3.175 4563.08 11'774.80 32.570 52.900 9591.37 9644.42 4069.15 N 2176.50 E 5984106.39 N 723799.80 E 3.086 4611.80 11870.73 30.930 49.220 9672.95 9726.00 4100.84 N 2215.77 E 5984139.22 N 723838.12 E 2.645 4658.93 11966.11 29.300 47.540 9755.45 9808.50 4132.60 N 2251.55 E 5984172.03 N 723872.94 E 1.924 4704.37 \ ---."""-"---'___._n. "'-----.-'---."""--""'--'-"---.--"---...--..-..-......-.---------......- .---....,. --...-----..-----------. 6 February, 2002 - 13:31 Page 3 of 5 ,_. DrillQuest 2.00.09.008 North Slope Alaska Measured Depth (ft) 12062.03 12158.08 12253.26 12296.56 12372.00 26.960 27.060 26.740 27.050 27.050 Incl. Azim. Sperry-Sun Drilling Services Survey Report for NK-19A Your Ref: 500292250701 Job No. AKMM11219, Surveyed: 8 January, 2002 Sub-Sea Vertical Local Coordinates Global Coordinates Dogleg Depth Depth Northlngs Eastlngs Northings Eastings Rate (ft) (ft) (ft) (ft) (ft) (ft) (0/100ft) 9840.05 9893.1 0 4164.37 N 2283.70 E 5984204.73 N 723904.13 E 3.315 9925.62 9978.67 4196.45 N 2313.25 E 5984237.68 N 723932.73 E 0.320 10010.50 10063.55 4228.69 N 2341.80 E 5984270.74 N 723960.31 E 0.840 10049.12 10102.17 4243.57 N 2354.53 E 5984286.00 N 723972.59 E 0.786 10116.31 10169.36 4269.70 N 2376.77 E 5984312.77 N 723994.05 E 0.000 All data is in Feet (US) unless otherwise stated. Directions and coordinates are relative to True North. Vertical depths are relative to Well. Northings and Eastings are relative to Well. 42.970 42.330 40.710 40.400 40.400 Magnetic Declination at Surface is 26.757° (02-Jan-02) The Dogleg Severity is in Degrees per 100 feet (US). Vertical Section is from Well and calculated along an Azimuth of 30.160° (True). Based upon Minimum Curvature type calculations, at a Measured Depth of 12372.00ft., The Bottom Hole Displacement is 4886.65f1., in the Direction of 29.103° (True). Comments Measured Depth (ft) 7992.65 8002.00 12372.00 6 February, 2002 - 13:52 Station Coordinates TVD Northings Eastings (ft) (ft) (ft) 7287.82 7295.78 10169.36 Comment 2524.40 N 2529.30 N 4269.70 N 218.90 W 219.12W 2376.77 E Tie-on Point Window Projected Survey -'---------' Vertical Section 4747.99 4790.57 4832.79 4852.05 4885.82 . Alaska Drilling & Wells NIAKUK Comment Projected Survey ( ( Page 4 of 5 .~- ---..- .-.--..--..---..-...... ---. .....--...,. ."'--""-'.'-'.'.'" ...-.----,--.- -"-.. ...........--...-,.-,.....- '-.n_._. --..----_.._-- -'. DrillQuest 2.00.09.008 North Slope Alaska Survey tool program for NK-19A Fro m Measured Vertical Depth Depth (ft) (ft) 0.00 7992.65 0.00 7287.82 6 February, 2002 - 13:31 To Measured Vertical Depth Depth (ft) (It) 7992.65 12372.00 7287.82 10169.36 Sperry-Sun Drilling Services Survey Report for NK-19A Your Ref: 500292250701 Job No. AKMM11219, Surveyed: 8 January, 2002 Survey Tool Description Good Gyro (NK-19) MWD Magnetic (NK-19A) ., .-...--..--.'. Page 5 of 5 .~. . ., Alaska Drilling & Wells NIAKUK ( ( .-----....".--.---.--.'-------- --.......-... .----.. - ...-.-.----..-....-....-.---..---.....-.-.---...-.....-.-..-.. -.-..--...----. DrillQuest 2.00.09.008 02/19/02 Scblumberger NO. 1826 Alaska Data & Consulting Services 3940 Arctic Blvd, Suite 300 Anchorage, AK 99503-5711 ATTN: Sherrle Company: State of Alaska Alaska 011 & Gas Cons Comm Attn: LIsa Weeple 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Prudhoe Bay Well Job # Log Description Date Bluellne Sepia Color Prints CD (' \, J-17B ~DJ"~,:~' 22065 MCNL 01120/02 1 1 1 NK-19A dO/-OiO 22041 SCMT (PDC) 01122/02 2 1 D.S. 4-19A ~ D I-d.' '5t 22061 SCMT (PDC) 01110/02 2 1 . PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COpy EACH TO: BP Exploration (Alaska) Inc. Petrotectnlcal Data Center LR2-1 900 E. Benson Blvd. Anchorage, Alaska 99508 RECEIVED Schlumberger GeoQuest 3940 Arctic Blvd, Suite 300 Anchorage, AK 99503-5711 ATTN: Sherrie Rece~ C. Ckpli ) r'1J~R 0 5 2002 ~ Cons. Com~ Anchorage UllOi.JðUn Date Delivered: 02/21 /02 ScblllDberger NO. 1836 Alaska Data & Consulting Services 3940 Arctic Blvd, Suite 300 Anchorage, AK 99503-5711 ATTN: Sherrie Company: State of Alaska Alaska 011 & Gas Cons Comm Attn: LIsa Weeple 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Prudhoe Bay "" ~ Well Job # Log Description Date Bluellne Sepia Color Prints CD ( 8-07 I I (f'- ()O~ PRODUCTION PROFILE 02109/02 1 1 MPF-33A ~.Dì"'Dl;pw; STATIC PRESSURE SURVEY 02114/02 1 1 NK-19A ~{')I-DI{) STATIC PRESSURE SURVEY 02110/02 1 1 K-02C aO/-ri.' in 22064 MCNL PDC 01/21/02 1 1 1 D.S. 5-26A :J. () -J.;J 22048 MCNL PDC 01/14/02 1 1 1 NK-22A ~Ol- dd ~ 22060 SCMT PDt 01/08/02 2 1 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COpy EACH TO: BP Exploration (Alaska) Inc. Petrotectnical Data Center LR2-1 900 E. Benson Blvd. Anchorage, Alaska 99508 RECEIVED Schlumberger GeoQuest 3940 Arctic Blvd, Suite 300 Anchorage, AK 99503-5711 ATTN: Sherrie Date Delivered: r~1AR 0 5 2002 Alaska Oil & ~ Anchorage ff ReceivM,oa' (Å OQ~1"" ) ( aCl 'Of Ð I lito ..O(td r 02/06/02 Scblumberger NO. 1785 Alaska Data & Consulting Services 3940 Arctic Blvd, Suite 300 Anchorage, AK 99503-5711 ATTN: Sherñe Company: State of Alaska Alaska 011 & Gas Cons Comm Attn: Lisa Weeple 333 West 7th Ave, Suite 100 Anchorage, AK 99501 FIeld: Prudhoe Bay Well Job # Log Description Date Blueline Sepia Color Prints CD NK-19A PRESSUREITEMPERATURE 01/26/02 1 1 D.S. 15-46 22035 MCNUBORAX 12/28101 1 1 1 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COpy EACH TO: BP Exploration (Alaska) Inc. Petrotectnical Data Center LR2-1 900 E. Benson Blvd. Anchorage, Alaska 99508 Schlumberger GeoQuest 3940 Arctic Blvd, Suite 300 Anchorage, AK 99503-5711 ATTN: Sherrie Received~ (, ~~ RECEIVED Date Delivered: ~2 Alaska Oil & Gas Cons. Commission Anchorage ,I ~~~~Œ (ID~ ~~~~[K\~ ALAS KA. 0 IL AND GAS COlVSERVATI ON COMMISSION TONY KNOWLES, GOVERNOR 333 W. -¡rw AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Scott Kolstad Senior Drilling Engineer BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, Alaska 99519 Re: Niakuk NK-19A BP Exploration (Alaska) Inc Permit No: 201-070 Sur Loc: 1434' NSL, 815' WEL, Sec. 36, TI2N, RI5E, UM Btmhole Loc. 596' NSL, 3149' WEL, Sec. 30, TI2N, RI6E, UM Dear Mr. Kolstad: Enclosed is the approved application for permit to redrill the above referenced well. The permit to redrill does not exempt you from obtaining additional permits required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permitting determinations are made. Blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25 035. Sufficient notice (approximately 24 hours) must be given to allow a representative of the Commission to witness a test of BOPE installed prior to drilling new hole. Notice may be given by contacting the Commission petroleum field inspector on the North Slope pager at659-3607. Sincerely, Jtu,ÚJ M I ~ Julie M. Heusser Commissioner BY ORDER OF ~HE COMMISSION DATED this It' day of May, 2001 jjcÆnclosures cc: Department ofFish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. ii STATE OF ALASKA { ALASKA (¡II... AND GAS CONSERVATION COMMk,-,ION PERMIT TO DRILL 20 AAC 25.005 ~ &ß- ç¡.s- ~ // 1 a. Type of work 0 Drill a Redrill 0 Re-Entry 0 Deepen 2. Name of Operator BP Exploration (Alaska) Inc. 3. Address P.O. Box 196612, Anchorage, Alaska 99519-6612 4. Location of well at surface 1434' NSL, 815' WEL, SEC. 36, T12N, R15E, UM At top of productive interval 259' NSL, 3717' WEL, SEC. 30, T12N, R16E UM At total depth 596' NSL, 3149' WEL, SEC. 30, T12N, R16E, UM 12. Distance to nearest property line 13. Distance to nearest well ADL 034630, 1710' MD No Close Approach 16. To be completed for deviated wells Kick Off Depth 8070' MD Maximum Hole Angle 18. Casin9 Program Specifications Size Casino Weiaht Grade Couplina Lenath 4-1/2" 12.6# L-80 HYD 521 4490' 1 b. Type of well Hole 6-3/4" 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical Casing Structural Conductor Surface Intermediate Production Liner 11235 feet 1 0236 feet 1 0365 feet 9415 feet Length Size 80' 4179' 20" 10-3/4" 1 061 0' 7-5/8" 0 Exploratory 0 Stratigraphic Test a Development Oil 0 Service 0 Development Gas 0 Single Zone 0 Multiple Zone 5. Datum Elevation (DF or KB) 10. Field and Pool Plan RKB = 53.9' Niakuk Oil Pool 6. Property Designation ADL 034635 7. Unit or Property Name Niakuk 8. Well Number NK-19A 9. Approximate spud date 04/29/01 Amount $200,000.00 14. Number of acres in property 15. Proposed depth (MD and TVD) 2560 12410' MD / 10002' TVD 17. Anticipated pressure {see 20 AAC 25.035 (e) (2)} 0 58 Maximum surface 4320 psig, At total depth (TVD) 9751 / 5300 psig Setting Depth Top Bottom Quantitv of Cement MD TVD MD TVD (include staae data) 7920' 7227' 12410' 10002' 383 sx Class 'G' 11. Type Bond (See 20 AAC 25.025) Number 2S100302630-277 ",,-.,\ -,' ~, -. "",,- ",,'C, ','n,",'."""" ',',m" /11., ¡I ,. " ~\ \~, "'" , " 'r'Ll~~T~~1 V lL:u".."ji APR 1 2 2001 Plugs (measured) ,Alaska Oil & Gas Cons. Commissiol1 Anchorage Junk (measured) Cemented MD TVD 260 sx Arcticset (Approx.) 1100 sx PF 'E', 375 sx Class 'G' 80' 4219' 80' 4108' 714 sx Class 'G' 10648' 9688' true vertical 10048' - 10088', 10098' - 10108', 10108' - 10128', 10116' - 10136' Perforation depth: measured 9108' - 9147', 9156' - 9166', 9166' - 9185', 9174' - 9193' 20. Attachments a Filing Fee 0 Property Plat 0 BOP Sketch 0 Diverter Sketch a Drilling Program a Drilling Fluid Program 0 Time vs Depth Plot 0 Refraction Analysis 0 Seabed Report 020 AAC 25.050 Requirements 21. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed Dan Stone ~7-- ~ Title Senior Drilling Engineer Date'" J,' 10' :~ ;~;; ~~~ ~'~:!~~~~ :-~1' +mm~~P9~~;~?, J7 a, ~~~~:,~::~;~: e nts Conditions of Approval: Samples Required 0 Yes E No Mud Log Required 0 Yes 1S No Hydrogen Sulfide Measures ja Yes 0 No Directional Survey Required BYes 0 No Required Working Pressure for BOPE 0 2K 0 3K 0 4K '~5K 0 10K 0 15K 0 3.5K psi for CTU Other: '-l5O~ t>'>\ .-\( ~~, D~,~~\-~ ME:Ir'l KiY{ by order of ,....... OR~GINAIL S~Gu~¿J ti , , the comml'ssl'on AlJlJroved By D 1\11 .. Commissioner Form 10-401 Rev. 12-Ò1'-8Š" 'J 1-.),',' ~C~,,~~, ~ r\Jl\" ¡ \"j,\1 ...",i!tl\I(-"\~:'"" Contact Engineer Name/Number: Scott, Kolstad, 564-5347 Prepared By Name/Number: Terrie Hubble, 564-4628 ;',' Date c:-..j /. 0 I Submit In Triplicate ~( Ii \ I Well Name: I NK-19A Drill and Complete Plan Summary l.!ïPe of Well (service 1 producer 1 injector): I Producer Surface Location: X = 721,744.78 Y = 5,979,974.74 1,434' FSL 815'FEL T 12N, R 15E, S 36 Umiat Target Location: Kuparuk X = 723,580.59 Y = 5,984,136.6 Sands 259'FSL 3,717' FEL T 12N, R16 E, S30 Umiat Sag River Target X = 723,971.64 Y = 5,984,385.4 496' FSL 3,317' FEL T 12N, R 16 E, S30 Umiat Bottom Hole Location: X = 724,136.55 Y = 5,984,490.31 596'FSL 3,149' FEL T 12N, R 16E, S30 Umiat AFE Number: 5L0509 Kuparuk 5L0520 Sag River lB.!U Doyon 14 I Estimated Start Date: 14/29/2001 I lQperating days to complete: 118.6 I MD: 112,410' I I TVD: 110,003' GUMSL: 119.4' I I RKB: 153.9' I Well DesigB-(conventional, slim hole, etc.).J 6 3fit Sidetrack ~ective: I Kuparuk Reservoir and Sag River Reservoir Mud Program: 6-3/4" Intermediate 1 Production hole: Freshwater LSND Interval Density Viscosity YP PV Tauo pH API (ppg) (seconds) (lb/100ft2) Fi It rate Millinq 9.4 50 - 55 25 - 35 9 - 12 3-8 8.5 - 9.5 KOP to 9.4 - 9.6 40-50 20 - 25 1 0-15 4-7 8.5 - 9.5 <9 cc -200' above H RZ HRZ - TO 10.8 -10.9 45 - 60 20 - 25 12-18 4-7 8.5 - 9.5 <9 cc Di rectional: KOP: -8,070' MD Maximum Hole Angle: Close A roach Wells: 58° Tan ent All wells pass close approach guidelines NK-19A Permit to Drill Page 1 \( { Lo Drilling: MWD / GR / Res / Neu / Den / PWD Open Hole: None Cased Hole: None Formation Markers: Formation Tops M Dbkb TVDss Comments SV5 3,776' Not Penetrated SV4 4,060' " SV3 / T5 4,387' " SV2 4,572' " SV1 5,006' " UG4A 5,500' " UG3 5,869 WS2 6,539' " WS1 7,011' KOP -8,070' -7,300' KOP at base of WSK. 40' vertical uncertainty CM-3 8,070' 7,300' 30' vertical uncertainty TUFFS 9,911' 8,444' 30' vertical uncertainty HAl 10,873' 8,958' 30' vertical uncertainty Kuparuk 11 ,283' 9,177' 20' vertical uncertainty T KinQak 11,621 ' 9,387' 20' vertical uncertainty TSGA 12,131' 9,751' 20' vertical uncertainty TSAD 12,331' 9,894' 20' vertical uncertainty TD 12,410' 9,944' Casin Hole Conn Length Top Btm Size MDITVD MDITVD bkb 6-3/4" 12.6# L-80 HYD 4,490' 7,920'/ 12,410'/ 521 7,227' 10,003' Tubin 4 Y2" 12.6# L-80 IBTM 7,920' Surface 7,920' / 7,227' Size 4 ¥2" Liner Lead: None Lead TOe: NI A Tail: Based on TOe 1000' MD above top of Kuparuk formation with 50% excess and 82' shoe track. Tail TOe: 10,283' MD, 8,695' TVDbkb Total Cement Volume: Lead N/A Tail 80 bbls I 448 ft I 383 sks of Dowell Premium 'G' with latex at 15.8 and 1.17 disk. Cement Calculations: Casin Basis: NK-19A Permit to Drill Page 2 ! ~ if Well Control: For intermediate / production hole drilling, well control equipment consisting of 5000 psi working pressure pipe rams (2), blind/shear rams, and annular preventer will be installed and is capable of handling maximum potential surface pressures. Based upon calculations below BOP equipment will be tested to 4,500 psi BOPE and drilling fluid system schematics on file with the AOGCC. Production Interval- . Max. anticipated BHP (KUP): . Max. surface pressure (KUP): 2,500 psi @ 9,180' TVOss - Kuparuk Sands 1,582 psi @ surface (Based on BHP and a full column of gas from TD @ 0.10 psi/ft) 5,300 psi (10.4 ppg) @ 9,751' TVOss - Sag River Sands 4,320 psi @ surface 4,500 psi sea water (cased hole, no perfs) /3,300' of 6.8 ppg Diesel . Max. anticipated BHP (SGR): . Max. surface pressure (SGR): . Planned BOP test pressure: . Planned completion fluid: Dri II i ng Hazards/Conti ngencies: HYDROGEN SULFIDE - H2S . Heald Point Niakuk Pad is not designated as an H2S site, however Standard Operating Procedures for H2S precautions should be followed at all times. Highest level of H2S recently measured on NK Pad: 40 ppm from NK-14, 1/7/01. Closest surface location measured recently(-60' away): 40 ppm from NK-14, 1/7/01. Recent data from nearest BHL: 20 ppm from NK-29, 1/1/01. DRilliNG CLOSE APPROACH: . All wells pass BP close approach guidelines. Disposal: . No annular injection in this well. . . Cuttings Handling: Cuttings generated from drilling operations will be hauled to grind and inject at OS-04. . Fluid Handling: Haul all drilling and completion fluids and other Class II wastes to OS- 04 for injection. Haul all Class I wastes to Pad 3 for disposal. NK-19A Permit to Drill Page 3 ( :{ DRILL AND COMPLETE PROCEDURE SUMMARY Pre-RiQ Work: 1. P&A with CTU as per Sundry. 2. Cut tubing. 3. Circulate well to kill weight fluid. 4. Pressure test casing and tubing pack ofts. 5. Install BPV. 6. Install VR plug in NK-65 well head and remove annulus valve. 7. If necessary, level the pad and prepare location for rig move. 8. Ensure any required plugs and lor well shut-ins have been accomplished in nearby wells for rig move and close approach concerns. NK-19A RiQ Operations: 1. MIRU Doyon 14. 2. Circulate out freeze protection and displace well to sea water. Set TWC & test from below. 3. Nipple down tree. Nipple up and test BOPE. 4. Pull and lay down 4-1/2" tubing from E-line cut and above. 5. MU 7-5/8" window milling assembly and RIH to top of tubing stub. POOH. 6. RU E-line and set CIBP to place KOP in a clean sandstone at the base of the West Sak at -8,070' MD. To avoid cutting a casing collar, set the BP 2' - 3' above a collar. 7. RIH with 7-5/8" Baker bottom-trip anchor whipstock assembly. Orient whipstock -800 - 850 right of HS and set. Mill window in 7-5/8" casing. Perform FIT test. POOH \?t..~~ \..C"'t" I ç:.., \ 8. RIH with 6 3/4" drilling assembly to whipstock. Kick-off and drill to THRZ @ -58 degrees inclination. Drill through Kuparuk sands dropping angle to -440 inclination and continue drilling through the Kingak, Sag River, Shublik, and into the Ivishak to the OWC. 9. Spot liner running pill. POOH wI DP. 10. Run and cement a 4 ¥2", 12.6 # production liner. Displace cement wI viscosified fresh water perf pill followed by mud. Release from liner and displace well to sea water. POOH. After cement has gained compressive strength, test the casing and liner from the landing collar to surface to 3500 psi for 30 minutes 11. Install 4-1/2", 12.6# L80 tubing completion. 12. Drop baillrod & set packer and test the tubing to 3500 psi and annulus to 3500 psi for 30 minutes. 13. Nipple down the BOPE. Nipple up and test the tree to 5000 psi. 14. Freeze protect the well to -100' below the first GLM and secure the well. 15. Rig down and move oft. Post-RiQ Work: . . 1. Pull the ball and rod I RHC plug from below the new production packer. Install gas lift valves. 2. Perforate well. NK-19A Permit to Drill Page 4 :t { Job 1: MIRU Hazards and Contingencies ~ The center to center well head separation between NK-19 and NK-65 is 9.81'. An annulus valve on NK-65 will need to be removed prior to moving the rig to NK-19A. Use spotters and have radio communication between the spotter watching the NK-65 well head and the person driving the rig. Well NK-65 and NK-43 are located 9.81' and 14.85' from NK-19 respective.ly. Confirm that NK-19, NK-65, and NK-43 have been shut in and depressurized (including annulus and header lines) prior to moving the rig. Reference RPs .:. "Drilling/Work over Close Proximity Surface and Subsurface Wells Procedure" Operational Specifics . """" .. '" , " .."" " " , ,.." "" ..., .. .,.. , ... -~~-~..._~'" ,'"",, .~'"~,.~ Job 2: Decomplete Well Hazards and Contingencies ~ No hazards specific to this well have been identified for this phase of the well construction. Reference RPs .:. Operational Specifics . , " " "., ,~""_.~ """ """.,,"'~-- " , , Job 3: Run Whipstock Hazards and Contingencies ~ Cement is expected behind the casing at the window depth. The estimated minimum top of cement outside the 7 5/8" casing is 6,169' based on volumes pumped. However, to aid in kicking off the whipstock will be set -800 - 850 right of high side in a sandstone. Reference RPs .:. Operational Specifics . "'~"'-~,- NK-19A Permit to Drill Page 5 ~, "\, Job 4: DrillinQ Intermediate/Production Hole Hazards and Contingencies >- No faults are expected along the proposed well path. The proposed path does drill over the top of a fault and it is important not to let the well deviate too far below the line. >- Gas cut mud has been observed in the West Sak sands. This will be controlled with appropriate mud weights. A minimum of 9.2 ppg is recommended in the West Sak. >- The NK-19A well path will drill full sections of the Tuffs and HRZ and some Kingak shale. Each of these formations have been troublesome in the Niakuk area and have shown severe hole instability problems. Follow all shale drilling practices to limit high ECD's. We will also be using increased mud weights and shale stabilizers in the drilling fluid. >- The Kuparuk reservoir is expected to be under-pressured at the NK-19A bottom hole location. Because of the high mud weights required to drill the surrounding shale intervals, losses and differential sticking could be a problem. To be prepared for any potential lost circulation, a copy of the 'Recommended Lost Circulation Procedures' and the 'Lost Circulation Decision Tree' will be sent to the rig prior to drilling the production interval. >- Differential sticking will be a problem if the drill string or casing is left stationary for an extended period of time across the permeable West Sak, Kuparuk, Sag River, and Ivishak Sands. >- The kick tolerance for the 6 34t Kuparuk section would be infinite assuming an influx from the Kuparuk at -11,283' MD. The kick tolerance for the 6 34t Sag River section would be 52 bbls assuming an influx from the Sag River at -12,131' MD. This is a worst case scenario based on a 10.4 ppg pore pressure gradient, a fracture gradient of 12.5 ppg at the 7 5/8" window, and 10.9 ppg mud in the hole. Reference RPs .:. OperaüonalSpecifics . Job 5: Install 4 Y2" Production Liner' Hazards and Contingencies >- Long shale intervals will be exposed while running the liner. Rotation of the liner may be necessary if downward progress is not possible. >- Differential sticking could be a problem in the Kuparuk. The 10.9 ppg mud required for well bore stability of the HRZ and Kingak will be 3,378 psi over balanced to the Kuparuk formation. Minimize the time the pipe is left stationary while running the liner. >- Ensure the liner top packer is set prior to POOH. This may require going through the setting process twice. Slack off with rotation to the maximum allowable down weight to set the packer. Check with Baker for the maximum down weight. If the stinger is pulled out of the liner top prior to setting the packer, POOH to remove the stinger prior to setting the packer. NK-19A Permit to Drill Page 6 ..~ ..~ Reference RPs .:. Operational Specifics . , .. ..... .. Job 6: Run Completion Hazards and Contingencies ~ Diesel will be used to freeze protect the well. The diesel flash point is 100° F. Diesel vapor pressure is - 0.1 psia at 100° F. Reference RPs .:. Operational Specifics . "...".,~"',..."'"..... ......."...."" , U""""""""'.....",..."m.~.'..""""",, ",...............", ".... ., """,,.. ".m "'" ....,' .,... n.. ..".,. , Job 7: ND/NU/Release Ria Hazards and Contingencies ~ See hazards related to the close proximity of the NK-65 well head in the prior to moving the rig. Reference RPs .:. Operational Specifics . NK-19A Permit to Drill Page 7 TREE: 4-1/16" CIW WELLHEAD: FMC 13-5/8" UNIVERSAL ACTUATOR: BAKER ,{ '\ N K-1 9 "x" NIPPLE 9849' ( OTIS) (3.813" 10) 7-5/8" BAKER PACKER 9912' (SABL-3)(3.875"ID) "x" NIPPLE , I ( OTIS) (3.813" 10) 9945' IIXN" NIPPLE , I (OTIS) (3.725" 10) 9962' I I I WLEG 9974' I ELMO I 9961' I NOTE: WELL WAS DRILLED TO A DEPTH OF 11235' AND PLUGGED BACK TO 10356'. 10-3/4",45.5#, NT-80, BTC , 4219' KOP: 2776' MAX ANGLE: 32° @ 4056' 4-1/2", 12.6#/ft, NT-80, NSCT TUBING TUBING 10: 3.958" CAPACITY: .01522 BBUFT PERFORATION SUMMARY REFERENCE LOG: ATLAS BHCS 10-27-94 SIZE SPF INTERVAL OPEN/SOZ'D 33/8" 3318" 33/8" 27/8" 10048' -10088' 10098'-10108' 10108'-10128' 10116 - 10136' 6 6 6 6 OPEN OPEN OPEN OPEN 3/12/98 E-line TD = 10204' (3/12/98) PBTD I I 10356' 7-5/811,29.7#, NT95HS NSCC 10648' (i) ,,' ~, KB. ELEV = 60.3' GL. ELEV = 19.4' TRSV LANDING NIPPLE (OTIS CP-2)(3.813" ID) 2164' 4.5" GAS LIFT MANDRELS (MERLA TMPDX W 1" BK LATCH) NO. MDlBKB) TVDss. DEV. 6 2972' 2910' 0° 5 4268' 4088' 34° 4 6608' 6058' 32° 3 8161' 7372' 32° 2 9217' 8280' 34° 1 9822' 8831' 17° No Status ptro P 0 Orif. ,-'- " 6 Dumm II 5 Dummv 4 Dumm V 3 Dumm if 2 Dumm ,I DATE REV. BY COMMENTS NIAKUK 10-31-94 M.LlNDER ORIGINAL COMPLETION POOL7 WELL: NK-19 3/20/97 AGK ADD PERF API NO:50-029-22507 12-5-97 CHH ADD PERF 03-12-98 RATHERT ADD PERF BP Exploration (Alaska) { NK-19A Proposed Completion TREE: 4-1/16" - 5M CIW WELLHEAD: FMC 13 SIB" UNIVERSAL Actuator: Baker 103/4",45.5 #/ft, NT-80, BTC I 4219' I BAKER 7 SIB" x 4 1/2" Liner Tie Back Sleeve 1+/- 7,920' I. zXP Liner Top Packer . 'HMC or Flex Lock' Hydraulic Liner Hanger Window Milled from Whipstock ............ Top of Window at +1-8,070' MD " Bridge Plug set at +1-8,090' MD --- Pre-Rig Tubing Cut at +1-8,300' Top cement P&A plug at -9,874' MD WLEG 19,974' 1 110,356'1 PBTD 7-5/8",29.7 #/ft, NT95HS 110,648'1 NSCC Date 2/5/01 Rev By SRK Comments Proposed Completion GL. ELEV = 19.4' Doyon 14 RKB = 53.9' 4-1/2" Halliburton 'CP.2' tubing retrievable SSSV wi control line to surface. I 2164' I 4-1/2" Gas Lift Mandrels with handling pups installed. ¡ GAS LIFT MANDRELS ;--;-~-c-_m TVD------T------Size------~-- V~lve Type :----------~ --------- 1 2 3 4 TBD TBD TBD TBD ---""------------- -ï------------ 4112" x 1" I DV 41/2" x 1" RP Shear 41/2" x 1" DV I 41/2" x 1" DV i I ____1__.___----------..----- -- 4-1/2" 12.6# L-BO, IBT Tubing 4-1/2" 'X' Landing Nipple with 3.813" seal bore. 75/8" x 4-1/2" Baker 'S-3' Production Packer 4-1/2" 'X' Landing Nipple with 3.813" seal bore. 4-1/2" 'XN' Landing Nipple with 3.813" seal bore and 3.725" No-Go ID. 4-1/2" Wire Line Entry Guide spaced-out into liner top. Plug Back Depth I +/-12,328' I 4-1/2",12.6 #/ft, L-80, HYD 521 1 +/-12,410' 1 NIAKUK WEll: NK-19A API NO: 50-029-22507-01 BP ALASKA DRilliNG NK-19A Schlumberger Proposed Well Profile - Geodetic Report Report Date: Client: Field: Structure I Slot: Well: Borehole: UWI/API#: Survey Name I Date: Tort I AHD I DDII ERD ratio: Grid Coordinate System: Location LatiLong: Location Grid N/E Y/X: Grid Convergence Angle: Grid Scale Factor: April 10, 2001 Alaska Drilling & Wells Niakuk d MainPad/NK-19 "'ty stu ~~~~9~22507-01 Feasib. . NK-19A (P10) / April 10, 2001 124.2510/6024.18 ft/ 5.968 / 0.6o¿ NAD27 Alaska State Planes, Zone 04, US Fee1 N 70.34755715, W 148.1997202e N 5979974.740 ftUS, E 721744.780 ftUS +1.695476730 0.99995586 Survey I DLS Computation Method: Vertical Section Azimuth: Only Vertical Section Origin: TVD Reference Datum: TVD Reference Elevation: Minimum Curvature / Lubinski 55.0300 N 0.000 ft, E 0.000 ft KB 52.9 ft relative to Mean Sea Level Magnetic Declination: Total Field Strength: Magnetic Dip: Declination Date: Magnetic Declination Model: North Reference: Total Corr Mag North .> True North: Local Coordinates Referenced To: 26.9760 5750 nT 80.8730 April 11,2001 BGGM 2000 True North +27.0030 Well Head ( Station ID Geo ra hic Coordinates Latitude Longitude N 70.35445305 W 148.20149672 N 70.35456200 W 148.20151338 N 70.35456336 W 148.20151362 N 70.35458238 W 148.20151565 8095.00 33.13 359.29 7374.74 1296.37 2578.10 -221.20 0.00 5982545.05 721447.41 N 70.35460027 W 148.20151630 8100.00 33.16 359.84 7378.93 1297.92 2580.84 -221.22 6.00 5982547.79 721447.31 N 70.35460776 W 148.20151647 8200.00 34.18 10.51 7462.22 1333.60 2635.86 -216.17 6.00 5982602.93 721450.73 N 70.35475807 W 148.20147547 8300.00 36.07 20.42 7544.07 1377.90 2691.12 -200.75 6.00 5982658.62 721464.51 N 70.35490903 W 148.20135028 8400.00 38.70 29.31 7623.58 1430.35 2746.02 -175.15 6.00 5982714.25 721488.47 N 70.35505902 W 148.20114242 ( 8500.00 41.93 37.14 7699.87 1490.36 2799.96 -139.64 6.00 5982769.21 721522.37 N 70.35520638 W 148.20085410 8600.00 45.62 43.99 7772.11 1557.29 2852.35 -94.61 6.00 5982822.91 721565.83 N 70.35534950 W 148.20048846 8700.00 49.67 49.99 7839.50 1630.40 2902.61 -40.55 6.00 5982874.75 721618.37 N 70.35548681 W 148.20004950 8800.00 53.99 55.28 7901.32 1708.88 2950.20 21.94 6.00 5982924.16 721679.42 N 70.35561682 W 148.19954208 8882.56 57.72 59.23 7947.67 1777.12 2987.09 79.41 6.00 5982962.73 721735.78 N 70.35571760 W 148.19907542 9910.91 57.72 59.23 8496.90 2644.18 3431.91 826.39 0.00 5983429.44 722469.23 N 70.35693268 W 148.19300948 Tie-In Survey CM-3 Top of Window Base Whipstock KOP Crv 6/100 End Crv Top Tuffs NK-19A (P10) report. xis Page 1 of 2 4/10/2001-3:58 PM Station ID Top HRZ N 70.35806961 W 148.18733211 Top Kuparuk N 70.35855399 W 148.18491292 Drp 4/100 N 70.35856671 W 148.18484924 N 70.35857368 W 148.18481456 11400.00 53.48 59.23 9295.4 7 3897.55 4074.92 1906.18 4.00 5984104.08 723529.48 N 70.35868878 W 148.18423965 11437.04 52.00 59.23 9317.90 3926.95 4090.00 1931.51 4.00 5984119.91 723554.35 N 70.35872996 W 148.18403391 Kup Tgt 11476.94 50.40 59.23 9342.90 3957.97 4105.91 1958.23 4.00 5984136.60 723580.59 N 70.35877340 W 148.18381687 11500.00 49.48 59.23 9357.74 3975.57 4114.94 1973.39 4.00 5984146.07 723595.47 N 70.35879806 W 148.18369374 11600.00 45.48 59.23 9425.31 4049.06 4152.64 2036.71 4.00 5984185.63 723657.64 N 70.35890101 W 148.18317941 Top Kingak 11620.66 44.66 59.23 9439.90 4063.65 4160.12 2049.28 4.00 5984193.48 723669.99 N 70.35892143 W 148.18307731 l End Drp 11624.87 44.49 59.23 9442.90 4066.60 4161.63 2051.82 4.00 5984195.06 723672.48 N 70.35892556 W 148.18305668 J\ Top Sag 12130.89 44.49 59.23 9803.90 4420.23 4343.04 2356.49 0.00 5984385.40 723971.64 N 70.35942090 W 148.18058188 Top Sadlerochit 12331.34 44.49 59.23 9946.90 4560.32 4414.90 2477.18 0.00 5984460.79 724090.14 N 70.35961711 W 148.17960150 TD 14-1/2" Lnr pt 12409.83 44.49 59.23 10002.90 4615.18 4443.04 2524.44 0.00 5984490.32 724136.55 N 70.35969394 W 148.17921760 Leaal DescriDtion: Surface: 1433 FSL 815 FEL S36 T12N R15E UM Tie-In: 3958 FSL 1033 FEL S36 T12N R15E UM Target: 259 FSL 3717 FEL S30 T12N R16E UM BHL: 596 FSL 3149 FEL S30 T12N R16E UM Northina (y) rnUSl 5979974.74 5982491.25 5984136.60 5984490.31 Eastina (X) rftUSl 721744.78 721451.41 723580.59 724136.55 ( NK-19A (P10) report.xls Page 2 of 2 4/10/2001-3:58 PM I '. VERTICAL SECTION VIEW Client: Alaska Drilling & Wells Well: Field: Structure: NK-19A (P10) Niakuk Main Pad Schlumberger Section At: 55.03 deg Date: April 10, 2001 -2000 0 - Proposal - Survey 2000 ....,............................. ""ï" .......................,............ , ........................................................... - 0> > -0> ..... -J 0> 0> CtI - 0> O(f) a c: a CtI N 0> II ~ .S Q) ~ > _0 ..c:.c ..... CtI c..ì:: 0>0 00) -N ~L() -- - tea O>~ > .. o>ø 20:: I- > 0> UJ ..., ..... ..... ..... ...., ..... ..... ..... ,.... ...... ..... ..... ..... ..... ........................................................................................................................................ ....................................................... 4000 .....................,.......................................... 6000 I .........I...................................J.,. TIe-In Survey7993 MD 7288 TVD ! 31.64' 357.5" az 1267 departure I , ...,.. , 1 To~ ofWIndow8070 MD 7354 TVD i 31.~3' 356.60' az 1289 departure 1 -- "" I KOP Cry 6/1008095 MD 7375 tvD ]/33.13' 359.29' az 1296 departpre .'1 , End Cry 8883 MD 794~ TVD //57.72' 59.23' az 177~ departure , I - - - - ... - - - - ,- CM..13 3069 Mf) '13S3 TV(.) .,:... ..... ..... ..... ..... 8000 I Base Whlpslock8083 MD 73651TVD . '133:13'" 359:2~'až' '1293 âëjjartÙfë ....., Hold Angle 57.720 ""r'" Top'Tuffs 9911 MD 84HI! TVD , ..... '...., ..... ..... ....... .. ..... ,..... ....,TopIHRZ. 1087.3 .MDj)()J ~.TVD.... .... ....TopiKuparuk :1J283..MD. 9230..TVD..... ToPiKingak11G21 MD 9440 TVD , I ... 'fgg'~~~ðié1..j¿:~i1'" tì19.i:fPRfoT¥&47 , .tVb"" , ¡ I ..... ..... ..... . èïr¡;'¡ï10Ö ii294 MÒ ïi236 TiiÒ'" / 57.72' 59.23' az 3810 departure I ' ..... ..... ..... ¡'/'" .:'~~~~0~~15~~~~;'a~DJ~~~~je:~ure ... ..... "1':~: ,... ::,;~.:::;:~o",~.::; ..,. ., ,.,..,.~~.,."., Hold A~gle 44.49' 10000 .... ¡.... I I ..i... NK-19 TD 14-1/2" Lnr PI 12410 MD 10003 TVD 44.49' 59.23' az 4615departure. 12000 i I i I , . -2000 0 2000 4000 6000 Vertical Section Departure at 55.03 deg from (0.0, 0.0). (1 in = 2000 feet) J",~ .... I II MUlA .....l1l1I -1000 ," 't ( Well: Field: PLAN VIEW Client: Alaska Drilling & Wells Structure: Scale: Date: NK-19A (P10) Niakuk Main Pad 1 in = 1000 ft 10-Apr-2001 Schlumbergep 0 True North Mag Dee ( E 26.976° ) 5000 4000 ^ ^ ^ I I- Q: 0 Z 3000 2000 I I- ::> 0 C/) V V V 1000 0 -1000 ~ ~ - Proposal -Survey 1000 '~ ~~~ 'ô.~ ; ~~ ~o\Ò NK-19 2000 3000 TD 14.1/2",Lnr PI 12410 MD: 10003 TVD 44.49' 59:23' az ¡ Þ 4443N 2f4E !~~~. ~ I "'" ""':" "'11625MÖQ443TVD ;, 4162N 2052E " ; ; i , , l Kup Tgl ! Drp4/100i 11477MD 93~3TVD 11294MDi 9236TVD 50.40' 59.23'¡'z 57.72' 5~.23'az 4106N 1958~ 4030N 1631 E ¡ i ..,..,..,..........,.....¡,.................,.., ; """"""""""""".."","""""""""" ,..,......",..,..............................,..,.................. ".. End CN 8a83 MD 7948 TVD , 57.72' 59;23' az 2987 N 79 E ~"-,.-,, - "",." -"" KOp CN 6/100&095 MD 7375 TVD I"~ 1 33.13' 359.29'jaz2578N 221W \' "~I " Base Whlpslock8083 MD 7365 TVD I 33.13' 359,29' az 2572 N 221 W \ 1\ ; \!.,?",?I,\I\I,I,~~,?~,~q?q,~~..?~~~..TY.D.." ""1"".\ 31.63' 356.60' az 256~ N 221 W TIe-In SuNey7993 MD 728ß TVD 31.64' 357.51' az 2524 N i219 W ",...."....,¡.... ............,....,..............................,......................................,.. ....,..,................,.................................",......,..........................."...................,........ """"""""""""""""""',"" "',."'..""",........"'..',.................."......,.,..,""".."','..,..................."';""""""""""""""""""""""'1""""""""""""""""'" 0 «< WEST 1000 """""1""""""""""""""""""""""""""""""""""""""""""""""....,..,..".................,.........,.........."........,....,....",....,..,..,..,....................................,......................",...... .............,........,.., 2000 EAST »> 3000 -1000 5000 4000 3000 2000 1000 0 -1000 FW: NK-19NDoyon 14 schedule change 'I '\ Subject: FW: NK..19A1Doyon 14 schedule change Date: Thu, 19 Apr 2001 12:36:33 -0500 From: "Kolstad, Scott" <KoistaSR@BP.com> To: "Boyd Creig (E-mail)" <Creig.Boyd@bakeroiltools.com>, "Brad Musgrove (E-mail)" <musgrove@anchorage.oilfield.slb.com>, "Carey Perry (E-mail)" <carey.perry@halliburton.com>, "NSU, ADW Drlg Coord - 4003" <NSUADWDrlgCoord4003@BP.com>, "Earl Chauvin (E-mail)" <earLchauvin@halliburton.com>, "Eric Mickelson (E-mail)" <emickelson@smith-intLcom>, "John Burton (E-mail)" <burton4@anchorage.anadrill.slb.com>, "John Harris.. Nt (E-mail)" <harrisj@niedLcom>, "Ken Spoonts (E-mail)" <ken.spoonts@weatheñord.com>, "Hite, Kevin E (FMC)" <HiteKE@BP .com>, "Lowell Anderson .. Baker (E-mail)" <Iowell.anderson@bakeroiltools.com>, "Nate Rose (Anadrill) (E-mail)" <NRose1@anchorage.oilfield.slb.com>, "Sauvageau Pat (E-mail)" <Sauvageau@anchorage.reed-hycalog.slb.com>, "Scott Delapp (Anadrill) (E-mail)" <delapp@anchorage.oilfield.slb.com>, "Hubble, Terrie l" <HubbleTL@BP.com> CC: "Tom Maunder (E-mail)" <tom_maunder@admin.state.ak.us> All, Due to the drilling risks Dan outlines below along with anticipated sub optimal production for the first few months due to the low reservoir pressure, the NK-19A sidetrack will be postponed until the next Niakuk drilling season (40 2001). Scott Kolstad Drilling Engineer BP Alaska Drilling and Wells PH: (907) 564-5347 Fax: (907) 564.4040 > -----Original Message.---- > From: Stone, Dan M > Sent: Tuesday, AprH 17, 2001 1:51 PM > To: PBU, Orlg Rig 14 Toolpusher; PBU, Orlg Rig 14; Wesley, Dave E > (Sperry); Schmitz, Steve H (Fairweather); Smith, Phil G (FAIR) > Cc: Frazier, Randy B; Kolstad, Scott; PBU, Orlg Field £ngr; Young, Jim; > Pospisil, Gordon; Bunch, Anthony S; Cole, Mike D; PBU, Drlg Tool Serv; > Isaacson, William S; Doyon-Todd Driskill (E-mail) > Subject: NK-19A/Doyon 14 schedule change > > Due to operational risks identified with drilling NK-19A as scheduled > (following NK-O7 A), the next well for Doyon 14 after NK-O7 A will be Aurora > $-106. Current estimates would put $-106 spud approximately two (2) weeks > from today. > > NK-19A will be delayed unti/4Q when the drilling risk is lessened by 5-6 > months of injection into NK-18i to raise the Kuparuk reservior pressure at > the NK-19A target. Differential sticking across a current 5.2 ppg EMW > Kuparuk zone with 10.7 ppg mud weight is the identified risk. > 10f2 4123/01 2:32 PM DATE 02/21/01 CHECK NO, 00184353 H 184353 DATE INVOICE I CREDIT MEMO DESCRIPTION GROSS VENDOR DISCOUNT ALASKAOILA NET 00 012901 CKO12901N PYMT OMMENT5: HANDL NG INST: 100.00 100.00 Per it To Drill ee S/H - Terri Hubb e X4628 }J~ - \ CUt 'HE ATTACHED CHECK IS IN PAYMENT FOR ITEMS DESCRIBED ABOVE. TOTAL ~ " , :i!?P'§~FLq@AlI9~ (ALASKA)fdN~,. "'PO:BOX:196612"":",,'.'.,:.,. ',::.-:' .::,,: :, ,A'NdHO'FtA.GE"ALÅSKÃ:(99519-6612. "(..::;:: :..:(: <;"'.,.,' ..:::\ >::",.}:" ' " ,,;,:: ""., ""';""",',' """"., " ,,'" " , " ",' "," '¡;:iRSti4ATlo.NAL.:SANK:6F ASI!II:i:AND "iJ;¡::P 1œ~~' :rf;;..' No '::,H ".:,:;;¡8?~:3'~,,:3 co1~~~ ~~~~rr~~::;~ "':oørB4353';"'.' , , , "'" , " ,,' "" ,",',' ,,',' \);::, ;'i,i> ::.;y;:: :><:: ',':r:,:;::',:. ":, i':' " ,,' ,-- , ' PAY O~E:::"~u~bè,E6,;;::: &);,:Bb.¡ 1 oo**~~~.~~*~¡~*~~*~:~'*.*******~,**~~,*~'i;*~~* .':'Ú:~i::"DdLLAR' ,:.,,"" "',:::;:::;:\,:,: :'::i:«:i:':, :,,:'::',::(:::¡:'::::':,;'::':::':,,:":::,f,':::::: ::,:::::i?:',::"::,:::"::',:,.:,,:,::/::(:::",,:,::,:'ii/':::,,'.,:,::::?::;::""'" "'.:':'" ,',.i::,:::' :)::,:t: \:::':;::,'::::"::,.',:,'.,:,)i':',,,,::.,',:,,:'{:::"" ",/"',:'",':',:,' "', ,,',', ',.,:'::':: :'-"::" "::," ",,',',:.',',',",',",,',:":,A' M:'O'U'N'T' " ,;,':::" " ':':' ,',', ','o', ::::.',:: ""'.""'" DATE' ,,',' ",ø "',' r 02/21101r/ I $100.~°~:1 ,,',! ((::~h~:. :,~~~7~ '. ANCHORAGE AK 99501 III ~ a l. j 5 j III I: 0 l. ~ 2 0 j B g 51: 0 0 a l. a. ~ g III ... COMPANY WELL NAMEP):-/q/l INIT CLASS /JeA/ /"'ðJ/ 1.Pennitfeeattached....................... 2. Lease number appropriate. . . . . . . . . . . . . . . . . . . 3. Unique well name and number. .. . . . . . . . . . . . . . . . 4. Well located in a defined pool.. . . . . . . . . . . . . . . . . 5. Well located proper distance from drilling unit boundary. . . . 6. Well located proper distance from other wells.. . . . . . . . . 7. Sufficient acreage available in drilling unit.. . . . . . . . . . . 8. If deviated, is wellbore plat included.. . . . . . . . . . . . . . 9. Operator only affected party.. . . . . . . . . . . . . . . . . . 10. Operator has appropriate bond in force. . . . . . . . . . . . . 11. Penn it can be issued without conservation order. . . . . . . . 12. Pennit can.be issued without administrative approval.. . . . . 13. Can permit be approved before 15-day wait.. . . . . . . . . . 14. Conductor string provided. . . . . . . . . . . . . . . . . . . 15. Suñace casing protects all known USDWs. . ., . . . . . . . 16. CMT vol adequate to circulate on conductor & surf csg. . . . . 17. CMT vol adequate to tie-in long string to surf csg. . . . . . . . 18. CMT will cover all known productive horizons. . . . . '. . . . . 19. Casing designs adequate for C, T, B & permafrost. . . . . . . 20. Adequate tankage or reserve pit.. . . . . . . . . . . . . . . . 21. If a re-drill, has a 10-403 for abandonment been approved. . . 22. Adequate well bore separation proposed.. . . . . . . . . . . . 23. If diverter required, does it meet regulations. . . . . . . . . . 24. Drilling .fluid program schematic & equip list adequate. . . . . 25. BOPEs, do they meet regulation. . . . . . . . . . . . . . . . 26. BOPE press rating appropriate; test to 4SÖO-"sig. 27. Choke manifold complies w/API RP-53 (May 84). . . . .. . . 28. Work will occur without operation shutdown. . . . . . . . . . . 29. Is presence of H2S gas probable.. . . . . . . . . . . . . . . . 30. Pennit can be issued w/o hydrogen sulfide measures. . . . . 31. Data presented on potential overpressure zones. . . . . . . 32. Seismic analysis of shallow gas zones. . . . . . . . . . . . . ',tR ~/ ~: ~~~~:~ ~~~~~i~~o~~~~i ~~~~;~~~~~~s~ ~ep~rt~ {e~p/~r~t~;Y on ANNULAR DISPOSAL35. With proper cementing records, this plan . (A) will contain waste in a suitable receiving zone; . . . . . .' . (B) will not contaminate freshwater; or cause drilling waste. " to surface; . (C) will not impair mechanical integrity of the well used for disposal; Y N (D) will not damage producing formation or impair recovery from a Y N pool; and E will not circumvent 20 AAC 25.252 or 20 AAC 25.412. Y N GEOLOGY: ENGINEERING: UIC/Annular COMMISSION: ~~8AY¿ v\7rv1 ---- - 8~s rø; 51 s:- JMH J WELL PERMIT CHECKLIST FIELD & POOL ADMINISTRATION ~R ;ø~/ ENGINEERING .g¡~ GEOLOGY APPR DATE c:\msoffice\wordian\diana\checklist (rev. 11/01/100) PROGRAM: exp - dev GEOL AREA r¡: "1 d N . ~ f\' I/.. ~ /J "'... d. flo ,b I &-0/"-", Æ.i Jf Þ ~~ P L Of c:.- "- Y @)6. I' J & N drt;, ~ d:£ ~ L/p¿f :7 ~ Æ ~. .. ~ e- " J-II -. '..-/ p. Ý"l) ,~~i. I'[ N .I I L ~. 71 Y. N . í/J ¡/J; - //_~ ~ IJ"j - 11-- 4j~~) :< h~ ~¡ ~ Ay~¿ "J,,'/) NI / N Y N i,.~ 61 £1 In.. f :-r?t~ S-, -,~pLK ,~ 1bl JoJ.-/It ~~ Æ/~ ~'.)J rQ/?r-ø~,.l. /Ç ~;Â/ .lJ ~ ~ C7 ~ ß,;".'¿R N ~t~:;: (~~ . ~ \: ~ O. ~'. '-:. ..~ *~~Q<;.~&~ ~~ N . ~~~\-\X\~r~(f~"'\.'\~C1~ ~~~~ ftt<;.~~ ~~~4~~<5>\ N . N .. . Y @-~~~\(~t\~((: ~'? O~'x5>~ ~'\t> ~~\~~~(~~o t. YN CS2. Y Y serv wellbore seg _ann. disposal para req - II 6 So ON/OFF SHORE 0 *' . UNIT# c 0 Z 0 -I :E ::c (, - -I m - Z -I J: - en :Þ ::c m :Þ ( N-,~¡J, N Y N Y N Y N Comments/l nstructions: 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 infonnation. ~ I{ Sperry-Sun Drilling Services LIS Scan Utility $Revision: 3 $ LisLib $Revision: 4 $ Tue Sep 24 17:02:14 2002 Reel Header Service name............ .LISTPE Date.....................02/09/24 Origin...................STS Reel Name............... . UNKNOWN Continuation Number..... .01 Previous Reel Name...... . UNKNOWN Comments.................STS LIS Tape Header Service name............ .LISTPE Date.....................02/09/24 Origin...................STS Tape Name............... . UNKNOWN Continuation Number..... .01 Previous Tape Name...... . UNKNOWN Comments................ .STS LIS Physical EOF Comment Record TAPE HEADER Prudhoe Bay Unit - Niakuk Pool MWD/MAD LOGS # WELL NAME: API NUMBER: OPERATOR: LOGGING COMPANY: TAPE CREATION DATE: # JOB DATA JOB NUMBER: LOGGING ENGINEER: OPERATOR WITNESS: MWD RUN 2 AK-MM-11219 P. ROGER A. MADSEN # SURFACE LOCATION SECTION: TOWNSHIP: RANGE: FNL: FSL: FEL: FWL: ELEVATION (FT FROM KELLY BUSHING: DERRICK FLOOR: GROUND LEVEL: MSL 0) # WELL CASING RECORD Writing Library. Scientific Technical Services Writing Library. Scientific Technical Services NK-19A 500292250701 BP Exploration Sperry Sun 24-SEP-02 (Alaska), Inc. MWD RUN 3 AK-MM-11219 P. ROGER S. KOLSTAD 36 12 15E 1434 815 .00 53.05 19.40 OPEN HOLE CASING DRILLERS BIT SIZE (IN) SIZE (IN) DEPTH (FT) 7.625 8002.0 1ST STRING 2ND STRING 3RD STRING PRODUCTION STRING # REMARKS: 1. ALL DEPTHS ARE MEASURED DEPTHS (MD) UNLESS OTHERWISE STATED. 2. MWD RUN 1 IS DIRECTIONAL ONLY TO SET WHIPSTOCK AND MILL CASING AND IS NOT PRESENTED. ó?OJ-O/O {( /5 5 File Header ,I Ii, 3. MWD RUNS 2 & 3 ARE DIRECTIONAL WITH DUAL GAMMA RAY (DGR) UTILIZING GEIGER MUELLER TUBE DETECTORS, ELECTROMAGNETIC WAVE RESISTIVITY PHASE 4 (EWR4), COMPENSATED THERMAL NEUTRON POROSITY (CTN), AND STABILIZED LITH-DENSITY (SLD). 4. GAMMA RAY (SGRC) IS LOGGED BEHIND CASING FROM 7794' MD, 7120' TVD TO 8002' MD, 7296' TVD. 5. GAMMA RAY (SGRC) DATA FROM 7794' MD, 7120' TVD TO 7985' MD, 7281' TVD WAS OBTAINED ON A MADPASS BEFORE DRILLING MWD RUN 2 AND IS APPENDED TO MWD RUN 2 DRILLING DATA. 6. DIGITAL DATA AND LOG DATA IS DEPTH CORRECTED TO THE PDC GR LOG OF 01/22/02 WITH OFF POINT. THIS WELL KICKS OFF FROM NK-19 AT 8002' MD, 7296' TVD (TOP OF WHIPSTOCK). ALL MWD LOG AND HEADER DATA RETAINS THE ORIGINAL DRILLER'S DEPTH REFERENCES. KBE = 53.05' A.M.S.L. AT THE KICK 7. MWD RUNS 1 - 3 REPRESENT WELL NK-19A WITH API # 50-029-22507-01. . THIS WELL REACHED A TOTAL DEPTH OF 12372' MD, 10169' TVD. SROP = SMOOTHED RATE OF PENETRATION SGRC = SMOOTHED GAMMA RAY COMBINED SEXP = SMOOTHED PHASE SHIFT DERIVED RESISTIVITY ( EXTRA SHALLOW SPACING) SESP = SMOOTHED PHASE SHIFT DERIVED RESISTIVITY ( SHALLOW SPACING) SEMP = SMOOTHED PHASE SHIFT DERIVED RESISTIVITY ( MEDIUM SPACING) SEDP = SMOOTHED PHASE SHIFT DERIVED RESISTIVITY ( DEEP SPACING) SFXE = SMOOTHED SBD2 = SMOOTHED SCO2 = SMOOTHED BIN) SNP2 = SMOOTHED NEAR DETECTOR ONLY PHOTOELECTRIC ABSORPTION FACTOR (LOW-COUNT BIN) TNPS = SMOOTHED THERMAL NEUTRON POROSITY (SANDSTONE MATRIX, FIXED HOLE SIZE) CTNA = SMOOTHED AVERAGE OF NEAR DETECTOR'S COUNT RATE CTFA = SMOOTHED AVERAGE OF FAR DETECTOR'S COUNT RATE FORMATION EXPOSURE TIME BULK DENSITY (LOW-COUNT BIN) STANDOFF CORRECTION (LOW-COUNT ENVIRONMENTAL PARAMETERS USED IN PROCESSING THE NEUTRON LOG DATA: HOLE SIZE: 6.75" MUD WEIGHT: -10.5 PPG MUD FILTRATE SALINITY: CHLORIDES FORMATION WATER SALINITY: FLUID DENSITY: G/CC MATRIX DENSITY: G/CC LITHOLOGY: SANDSTONE 9.4 450 - 650 PPM 19,000PPM CHLORIDES 1. 00 2.65 $ II '\ Service name............ .STSLIB.OOI Service Sub Level Name... Version Number......... ..1.0.0 Date of Generation...... .02/09/24 Maximum Physical Record. .65535 File Type............... .LO Previous File Name..... ..STSLIB.OOO Comment Record FILE HEADER FILE NUMBER: EDITED MERGED MWD Depth shifted and DEPTH INCREMENT: # FILE SUMMARY PBU TOOL CODE GR RPX RPS RPM RPD NPHI NCNT FCNT FET RHOB DRHO PEF ROP $ 1 clipped curves; all bit runs merged. .5000 START DEPTH 7794.0 7994.0 7994.0 7994.0 7994.0 7994.0 7994.0 7994.0 8005.0 8008.5 8008.5 8008.5 8032.5 STOP DEPTH 12317.0 12324.0 12324.0 12324.0 12324.0 12268.5 12268.5 12268.5 12324.0 12285.0 12285.0 12285.0 12378.5 # BASELINE CURVE FOR SHIFTS: CURVE SHIFT DATA (MEASURED DEPTH) --------- EQUIVALENT UNSHIFTED DEPTH --------- BASELINE 7794.0 7803.0 7816.0 7824.0 7831.0 7842.5 7844.0 7849.0 7860.0 7898.5 7941.0 8008.5 8033.5 8044.0 8059.5 8083.0 8158.5 8163.5 8176.5 8183.5 8188.5 8196.5 8208.5 8213.0 8236.0 8256.5 8266.0 8290.0 8327.5 8384.5 8476.0 8483.0 8516.5 8549.5 8574.5 8649.0 8737.0 8744.0 8749.5 8752.5 DEPTH GR 7794.0 7803.0 7816.5 7824.0 7832.0 7839.5 7842.5 7848.5 7861.0 7896.0 7941.5 8006.0 8032.5 8043.5 8059.0 8083.5 8159.0 8163.5 8177.5 8181.5 8186.0 8191.5 8203.0 8206.0 8229.0 8250.5 8261.0 8284.0 8320.0 8379.5 8474.5 8480.5 8512.0 8546.0 8572.0 8645.0 8737.0 8743.5 8746.0 8748.0 8833.5 8939.0 8954.0 8963.0 8977.5 8983.0 9028.0 9447.5 9456.0 9459.5 9466.0 9484.5 9490.5 9495.5 9501.0 9513.5 9516.0 9528.0 9532.5 9548.5 9562.0 9568.0 9582.5 9622.5 9635.0 9664.5 9693.0 9745.0 9773.5 9784.0 9794.5 9798.5 9804.0 9813.0 9824.0 9831.5 9857.5 9880.0 9884.5 9894.0 9918.5 9924.0 9928.5 9938.5 9946.5 9949.5 9960.0 9964.5 9967.0 9970.0 9974.5 9978.0 9982.0 9988.0 9994.0 10001. 0 10004.0 10014.5 10020.5 10026.0 10039.5 10048.0 10063.0 10065.0 10068.0 10079.0 10105.5 10117.5 10137.5 10166.5 10179.5 10188.0 10218.0 10226.5 10228.5 10247.5 8826.0 8935.0 8953.5 8960.0 8974.5 8978.5 9023.0 9443.0 9454.5 9457.0 9465.0 9480.0 9486.5 9490.0 9497.0 9508.5 9511.5 9521. 0 9528.0 9543.5 9558.0 9562.5 9579.5 9616.0 9629.0 9661.5 9687.0 9739.0 9769.5 9777.0 9789.5 9793.5 9801. 0 9807.5 9817.5 9825.0 9850.5 9875.0 9879.5 9886.5 9912.0 9916.5 9924.0 9935.0 9942.0 9945.0 9956.0 9960.5 9962.5 9966.0 9969.0 9972.5 9977.0 9982.0 9989.0 9995.5 9998.0 10008.5 10015.0 10021. 0 10034.5 10043.0 10056.5 10059.0 10061. 5 10074.5 10099.5 10111.0 10131.5 10160.5 10173.5 10180.5 10212.0 10219.5 10222.5 10242.5 ,( 10251. 0 10256.5 10260.5 10266.0 10274.5 10278.5 10283.5 10288.5 10294.5 10304.0 10313.5 10331.0 10346.5 10351. 0 10364.5 10373.0 10419.0 10428.5 10431.5 10441.0 10444.0 10453.5 10456.5 10462.0 10464.0 10466.5 10470.5 10474.5 10477.0 10490.5 10495.5 10503.0 10519.5 10543.5 10552.0 10560.0 10563.5 10570.5 10577.5 10585.0 10588.5 10591.0 10605.0 10699.0 10702.0 10712.0 10721. 0 10725.0 10729.0 10733.0 10737.5 10740.5 10744.5 10748.0 10764.5 10772.0 10776.5 10786.5 10791. 5 10804.0 10807.5 10818.5 10831. 0 10839.0 10845.5 10863.5 10869.0 10874.5 10882.5 10904.0 10913.0 10919.5 10935.5 10945.5 10949.0 10952.0 10246.5 10250.0 10253.5 10260.0 10269.5 10273.0 10277.0 10281.0 10288.0 10297.5 10308.0 10324.5 10340.0 10345.0 10357.5 10366.0 10413.5 10423.0 10427.0 10437.0 10439.5 10447.5 10451. 0 10453.5 10458.0 10460.0 10464.0 10468.0 10470.0 10481. 5 10488.5 10496.5 10514.5 10538.5 10546.0 10553.0 10557.5 10564.0 10571. 5 10578.5 10582.0 10584.0 10599.0 10693.0 10698.5 10708.5 10717.0 10720.0 10724.0 10727.5 10731. 5 10734.0 10738.5 10742.5 10759.5 10766.0 10770.5 10783.0 10787.0 10800.0 10802.0 10812.5 10823.5 10834.0 10840.5 10858.5 10865.0 10868.0 10876.5 10898.5 10907.5 10914.0 10930.0 10939.5 10943.0 10947.0 10954.0 10971.5 10979.5 10984.0 10987.0 10988.5 10998.5 11008.0 11011.5 11018.5 11029.0 11031.0 11036.0 11043.0 11048.5 11059.5 11063.0 11065.0 11069.0 11076.5 11079.5 11095.5 11099.0 11108.5 11110.5 11132.5 11143.5 11146.0 11148.5 11151.5 11153.0 11165.0 11168.0 11185.5 11193.5 11196.5 11212.0 11226.5 11230.0 11241.0 11253.0 11256.0 11263.0 11285.0 11288.5 11305.0 11307.0 11310.5 11329.0 11331.0 11346.0 11351.5 11361.0 11369.0 11374.5 11388.0 11416.0 11420.0 11439.0 11453.5 11460.0 11467.0 11473.0 11487.5 11490.0 11512.5 11514.5 11522.0 11537.5 11551.0 11557.5 11632.0 11787.5 11798.5 11836.0 11851.0 10949.0 10965.5 10973.5 10977 . 5 10980.5 10982.5 10992.5 11001.5 11004.0 11012.5 11024.5 11026.5 11031. 5 11038.5 11044.5 11054.5 11057.5 11060.0 11064.0 11071.0 11074.0 11091.0 11094.5 11104.5 11106.0 11128.5 11138.5 11141.0 11143.0 11146.0 11148.0 11159.5 11162.0 11180.5 11187.0 11190.5 11207.0 11220.5 11224.0 11235.5 11247.5 11250.0 11257.0 11280.0 11283.5 11300.0 11302.5 11307.0 11326.5 11329.0 11342.5 11349.0 11358.0 11365.0 11370.0 11383.5 11412.0 11416.5 11434.0 11450.5 11456.5 11463.0 11469.0 11483.0 11485.0 11509.5 11511. 5 11519.0 11534.5 11545.5 11554.5 11627.5 11779.5 11792.0 11831.0 11846.0 j \ ! 11864.5 11906.5 11920.0 11999.0 12009.0 12017.5 12100.5 12107.0 12118.0 12126.5 12130.5 12150.0 12164.0 12192.5 12200.0 12203.0 12209.5 12214.0 12217.5 12221.5 12241. 0 12243.0 12247.0 12252.0 12257.0 12266.0 12275.0 12378.5 $ 11860.5 11901.5 11915.5 11994.0 12004.0 12012.5 12096.0 12101. 5 12112.5 12121. 5 12125.5 12145.0 12158.0 12186.5 12194.0 12196.5 12203.0 12207.5 12211. 0 12215.0 12235.0 12237.0 12241.0 12246.0 12250.0 12260.0 12268.5 12372 .0 # MERGED PBU MWD MWD $ DATA SOURCE TOOL CODE BIT RUN NO MERGE TOP 2 7794.0 3 10746.5 MERGE BASE 10746.0 12372.0 # REMARKS: MERGED MAIN PASS. $ # Data Format Specification Record Data Record Type.......... ........0 Data Specification Block Type.....O Logging Direction................ . Down Optical log depth units......... ..Feet Data Reference Point...... ....... .Undefined Frame Spacing.................... .60 .1IN Max frames per record... ......... .Undefined Absent value......................-999 Depth Units....................... Datum Specification Block sub-type. ..0 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD FT/H 4 1 68 4 2 GR MWD API 4 1 68 8 3 RPX MWD OHMM 4 1 68 12 4 RPS MWD OHMM 4 1 68 16 5 RPM MWD OHMM 4 1 68 20 6 RPD MWD OHMM 4 1 68 24 7 FET MWD HR 4 1 68 28 8 NPHI MWD PU-S 4 1 68 32 9 FCNT MWD CP30 4 1 68 36 10 NCNT MWD CP30 4 1 68 40 11 RHOB MWD G/CM 4 1 68 44 12 DRHO MWD G/CM 4 1 68 48 13 PEF MWD B/E 4 1 68 52 14 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 7794 12378.5 10086.3 9170 7794 12378.5 ROP MWD FT/H 0.11 1493.36 103.013 8693 8032.5 12378.5 GR MWD API 23.93 438.26 134.393 9047 7794 12317 RPX MWD OHMM 0.42 1330.09 6.15655 8661 7994 12324 RPS MWD OHMM 0.44 759.44 6.00883 8661 7994 12324 I ¡¡, I( RPM MWD OHMM 0.47 2000 9.58383 8661 7994 12324 RPD MWD OHMM 0.41 2000 10.7918 8661 7994 12324 FET MWD HR 0.19 31.33 1.46017 8639 8005 12324 NPHI MWD PU-S 3.48 52.57 30.035 8550 7994 12268.5 FCNT MWD CP30 120.32 3641.77 385.861 8550 7994 12268.5 NCNT MWD CP30 13747.5 49557.9 23233.2 8550 7994 12268.5 RHOB MWD G/CM 2.07 3.4 2.49988 8554 8008.5 12285 DRHO MWD G/CM -0.24 0.96 0.0601906 8554 8008.5 12285 PEF MWD B/E 2.05 11.59 4.15902 8554 8008.5 12285 First Reading For Entire File......... .7794 Last Reading For Entire File..... .... ..12378.5 File Trailer Service name............ .STSLIB.001 Service Sub Level Name... Version Number..... ..... .1.0.0 Date of Generation...... .02/09/24 Maximum Physical Record..65535 File Type..... ..... "'" .LO Next File Name....... ....STSLIB.002 Physical EOF File Header Service name............ .STSLIB.002 Service Sub Level Name... Version Number. ....... ...1.0.0 Date of Generation... ....02/09/24 Maximum Physical Record. .65535 File Type............. ...LO Previous File Name.... ...STSLIB.001 Comment Record FILE HEADER FILE NUMBER: RAW MWD Curves and log BIT RUN NUMBER: DEPTH INCREMENT: # FILE SUMMARY VENDOR TOOL CODE GR RPD NCNT FCNT RPM RPS RPX NPHI FET PEF DRHO RHOB ROP $ 2 header data for each bit run in separate files. 2 .5000 START DEPTH 7794.0 7992.0 7992.0 7992.0 7992.0 7992.0 7992.0 7992.0 8002.5 8006.0 8006.0 8006.0 8031. 5 # LOG HEADER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME): TD DRILLER (FT): TOP LOG INTERVAL (FT): BOTTOM LOG INTERVAL (FT): BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: MAXIMUM ANGLE: # STOP DEPTH 10699.5 10706.5 10662.5 10662.5 10706.5 10706.5 10706.5 10662.5 10706.5 10678.0 10678.0 10678.0 10746.0 05-JAN-02 Insite 4.05.5 66.37 Memory 10746.0 30.6 60.1 TOOL STRING (TOP TO VENDOR TOOL CODE DGR EWR4 CTN SLD $ BOTTOM) TOOL TYPE DUAL GAMMA RAY ELECTROMAG. RESIS. 4 COMP THERMAL NEUTRON STABILIZED LITHO DEN # BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER'S CASING DEPTH (FT): # BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S): MUD PH: MUD CHLORIDES (PPM): FLUID LOSS (C3): RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT): MUD AT MAX CIRCULATING TERMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: # NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): # TOOL STANDOFF (IN): EWR FREQUENCY (HZ): # REMARKS: $ # Data Format Specification Record Data Record Type....... """'" ..0 Data Specification Block Type.....O Logging Direction... """""'" . Down Optical log depth units..... ..... .Feet Data Reference Point... "" ..... ..Undefined Frame Spacing......... """"'" .60 .1IN Max frames per record............ .Undefined Absent value......... .........,.. .-999 Depth Units....................... Datum Specification Block sub-type...O 'I TOOL NUMBER PB02341GR4 PB02341GR4 PB02340NL4 PB02341GR4 6.750 LSND 10.30 44.0 9.3 450 3.0 2.400 1. 285 1. 850 3.200 70.0 136.6 70.0 70.0 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD020 FT/H 4 1 68 4 2 GR MWD020 API 4 1 68 8 3 RPX MWD020 OHMM 4 1 68 12 4 RPS MWD020 OHMM 4 1 68 16 5 RPM MWD020 OHMM 4 1 68 20 6 RPD MWD020 OHMM 4 1 68 24 7 FET MWD020 HR 4 1 68 28 8 NPHI MWD020 PU-S 4 1 68 32 9 FCNT MWD020 CP30 4 1 68 36 10 NCNT MWD020 CP30 4 1 68 40 11 RHOB MWD020 G/CM 4 1 68 44 12 DRHO MWD020 G/CM 4 1 68 48 13 PEF MWD020 B/E 4 1 68 52 14 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 7794 10746 9270 5905 7794 10746 ROP MWD020 FT/H 0.11 307.99 107.042 5430 8031. 5 10746 GR MWD020 API 30.09 325.36 127.807 5812 7794 10699.5 RPX MWD020 OHMM 0.89 1330.09 5.74855 5430 7992 10706.5 RPS MWD020 OHMM 0.91 759.44 5.52102 5430 7992 10706.5 RPM MWD020 OHMM 0.89 2000 11. 3129 5430 7992 10706.5 RPD MWD020 OHMM 0.96 2000 12.4524 5430 7992 10706.5 FET MWD020 HR 0.19 24.68 1. 20615 5409 8002.5 10706.5 I~ NPHI MWD020 PU-S 16.3 52.57 28.6327 5342 7992 10662.5 FCNT MWD020 CP30 120.32 735.15 391.751 5342 7992 10662.5 NCNT MWD020 CP30 13747.5 30962 23603.1 5342 7992 10662.5 RHOB MWD020 G/CM 2.12 3.4 2.50135 5345 8006 10678 DRHO MWD020 G/CM -0.12 0.96 0.0486174 5345 8006 10678 PEF MWD020 B/E 2.05 9.28 3.77472 5345 8006 10678 First Reading For Entire File.. ....... .7794 Last Reading For Entire File..... ..... .10746 File Trailer Service name........... ..STSLIB.002 Service Sub Level Name... Version Number.......... .1.0.0 Date of Generation...... .02/09/24 Maximum Physical Record..65535 File Type............... .LO Next File Name.......... .STSLIB.003 Physical EOF File Header Service name............ .STSLIB.003 Service Sub Level Name... Version Number.......... .1.0.0 Date of Generation..... ..02/09/24 Maximum Physical Record. .65535 File Type............... .LO Previous File Name...... .STSLIB.002 Comment Record FILE HEADER FILE NUMBER: RAW MWD Curves and log BIT RUN NUMBER: DEPTH INCREMENT: # FILE SUMMARY VENDOR TOOL CODE NPHI FCNT NCNT PEF RHOB DRHO GR RPM RPS RPD FET RPX ROP $ 3 header data for each bit run in separate files. 3 .5000 START DEPTH 10663.0 10663.0 10663.0 10678.5 10678.5 10678.5 10700.0 10707.0 10707.0 10707.0 10707.0 10707.0 10746.5 # LOG HEADER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME): TD DRILLER (FT): TOP LOG INTERVAL (FT): BOTTOM LOG INTERVAL (FT): BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: MAXIMUM ANGLE: # TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE DGR DUAL GAMMA RAY STOP DEPTH 12262.5 12262.5 12262.5 12278.5 12278.5 12278.5 12310.5 12317.5 12317 .5 12317.5 12317.5 12317.5 12372.0 08-JAN-02 Insite 4.05.5 66.16 Memory 12372.0 26.7 51.8 TOOL NUMBER PB02372HAGR4 I¡ \, EWR4 ELECTROMAG. RESIS. 4 PB02372HAGR4 CTN COMP THERMAL NEUTRON PB02340NL4 SLD STABILIZED LITHO DEN PB02340NL4 $ # BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): 6.750 DRILLER'S CASING DEPTH (FT): # BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S): MUD PH: MUD CHLORIDES (PPM): FLUID LOSS (C3): RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT): MUD AT MAX CIRCULATING TERMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: LSND 10.50 44.0 9.2 600 2.9 5.800 2.533 3.400 2.300 70.0 169.0 70.0 70.0 # NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): # TOOL STANDOFF (IN): EWR FREQUENCY (HZ): # REMARKS: $ # Data Format Specification Record Data Record Type................ ..0 Data Specification Block Type.....O Logging Direction....... ........ ..Down Optical log depth units. ....... ...Feet Data Reference Point........... ...Undefined Frame Spacing.................... .60 .1IN Max frames per record............ .Undefined Absent value......................-999 Depth Units....................... Datum Specification Block sub-type. ..0 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD030 FT/H 4 1 68 4 2 GR MWD030 API 4 1 68 8 3 RPX MWD030 OHMM 4 1 68 12 4 RPS MWD030 OHMM 4 1 68 16 5 RPM MWD030 OHMM 4 1 68 20 6 RPD MWD030 OHMM 4 1 68 24 7 FET MWD030 HR 4 1 68 28 8 NPHI MWD030 PU-S 4 1 68 32 9 FCNT MWD030 CP30 4 1 68 36 10 NCNT MWD030 CP30 4 1 68 40 11 RHOB MWD030 G/CM 4 1 68 44 12 DRHO MWD030 G/CM 4 1 68 48 13 PEF MWD030 B/E 4 1 68 52 14 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 10663 12372 11517 . 5 3419 10663 12372 ROP MWD030 FT/H 0.56 1493.36 96.224 3252 10746.5 12372 GR MWD030 API 23.93 438.26 146.385 3222 10700 12310.5 RPX MWD030 OHMM 0.42 368.61 6.86622 3222 10707 12317.5 RPS MWD030 OHMM 0.44 357.71 6.85733 3222 10707 12317.5 RPM MWD030 OHMM 0.47 1076.69 7.04202 3222 10707 12317 . 5 RPD MWD030 OHMM 0.41 1586.51 8.02631 3222 10707 12317.5 FET MWD030 HR 0.34 31.33 1. 85714 3222 10707 12317.5 NPHI MWD030 PU-S 3.48 51.65 32.3762 3200 10663 12262.5 FCNT MWD030 CP30 151. 44 3641.77 376.054 3200 10663 12262.5 NCNT MWD030 CP30 16282 49557.9 22609.4 3200 10663 12262.5 t RHOB MWD030 G/CM DRHO MWD030 G/CM PEF MWD030 B/E 2.49669 0.0795689 4.80594 2.07 -0.24 2.51 2.97 0.6 11.59 First Reading For Entire File...... ... .10663 Last Reading For Entire File.... ...... .12372 File Trailer Service name..... ....... .STSLIB.003 Service Sub Level Name... Version Number.... ..... ..1.0.0 Date of Generation...... .02/09/24 Maximum Physical Record..65535 File Type............... .LO Next File Name.... ...... .STSLIB.004 Physical EOF Tape Trailer Service name..... ....... .LISTPE Date.....................02/09/24 Origin...................STS Tape Name..... .... ..,.. ..UNKNOWN Continuation Number..... .01 Next Tape Name... ....... . UNKNOWN Comments........ ........ .STS LIS Writing Library. Reel Trailer Service name...... ..... ..LISTPE Date.....................02/09/24 Origin...................STS Reel Name....... ........ . UNKNOWN Continuation Number..... .01 Next Reel Name.......... . UNKNOWN Comments.................STS LIS Writing Library. Physical EOF Physical EOF End Of LIS File 3201 3201 3201 ,:I " 10678.5 10678.5 10678.5 12278.5 12278.5 12278 .5 Scientific Technical Services Scientific Technical Services