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Home My WebLink About202-007CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:AOGCC Permitting (CED sponsored) To:Brooks, James S (OGC); AOGCC Records (CED sponsored) Subject:FW: PBU S-17C (PTD #202-007) 10-403 Sundry #325-271 CANCELLATION Request Date:Monday, June 2, 2025 10:48:57 AM Attachments:HilcorpNS_PBU_S-17C_received_043025_review.pdf Hi James, Please see the cancellation request for: PBU S-17C sundry 325-271. Thank you, Grace Christianson Executive Assistant, Alaska Oil & Gas Conservation Commission (907) 793-1230 From: Abbie Barker <Abbie.Barker@hilcorp.com> Sent: Monday, June 2, 2025 10:32 AM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Torin Roschinger <Torin.Roschinger@hilcorp.com>; Hunter Gates <Hunter.Gates@hilcorp.com>; Tyson Shriver <Tyson.Shriver@hilcorp.com> Subject: PBU S-17C (PTD #202-007) 10-403 Sundry #325-271 CANCELLATION Request Hello, Please cancel approved 10-403 Sundry Request #325-271 for S-17C Fracture stimulation (attached for reference). Any future fracture stimulation will require a new 10-403. If you have any questions or need additional information, please let me know. Thank you, Abbie Abbie Barker Regulatory Tech, Prudhoe Bay West Team Hilcorp North Slope Email: Abbie.Barker@hilcorp.com Cell: (907)351-2459 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified 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 theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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 this 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 S-17C Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 202-007 50-029-21148-03-00 ADL 0028257, 0028258 10658 Conductor Surface Intermediate Liner Liner 8891 80 2634 8274 1415 2561 7990 20" x 30" 13-3/8" 9-5/8" 7" 3-1/2" x 3-3/16" x 2-7/8" 7491 30 - 110 29 - 2663 26 - 8300 8035 - 9450 8049 - 10610 4500 30 - 110 29 - 2663 26 - 7761 7530 - 8728 7542 - 8899 None 2670 4760 5410 10530 7990, 9400, 9440 5380 6870 7240 10160 7179 - 7247 4-1/2" 12.6# 13Cr80 24 - 7119, 7954 - 80846753 - 6816 Structural 4-1/2" HES TNT Packer 4-1/2" Otis HVT Packer 7039, 6626 8002, 7502 Date: Torin Roschinger Operations Manager Hunter Gates hunter.gates@hilcorp.com (907) 777-8326 PRUDHOE BAY 5/28/2025 Current Pools: Aurora Oil Pool Proposed Pools: Aurora Oil Pool 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 By Grace Christianson at 4:23 pm, Apr 30, 2025 Digitally signed by Torin Roschinger (4662) DN: cn=Torin Roschinger (4662) Date: 2025.04.30 13:03:26 - 08'00' Torin Roschinger (4662) 325-271 Include a PRV on OA or hold an open bleed on OA during fracture treatment. CDW 05/14/2025 A.Dewhurst 20MAY25 5/28/2025 DSR-5/1/15JJL 5/14/25 10-404 Variance request to 20 AAC 25.283(a)(6)(B) is granted. Frac to be confined to approved intervals. *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.05.21 04:24:54 -08'00'05/21/25 RBDMS JSB 052225 Kuparuk Frac Well: S-17C PTD: 202-007 Well Name:S-17C Permit to Drill:202-007 Current Status:Operable, Producer API Number:50-029-21148-03 Estimated Start Date:May 28, 2025 Estimated Duration:5days Regulatory Contact:Abbie Barker Sundry Number: First Call Engineer:Hunter Gates (907) 777-8326 (O)(215) 498-7274 (M) Second Call Engineer:Tyson Shriver (907) 564-4542 (O)(406) 690-6385 (M) Current Bottom Hole Pressure:3,509 psi @ 6,700’ TVDss Max Anticipated Treating Pressure:4,500 psi Last SI WHP: 998 psi on 3/18/2025 Min ID:3.813” @ 2,008’ MD X-Nipple Max Angle:30 deg @ 5,000’ MD Brief Well Summary: S-17C is a Kuparuk producer that is Operable but currently shut-in due to its inability to flow. This was a CTD sidetrack completed in early March 2002. A rig workover in May 2023 was performed as we performed an UHRC to the Kuparuk reservoir. The Ivishak was adequately P&A’d and 68’ of Kuparuk perforations were shot. Testers began flowback, but the well had issues with inflow and was just cycling gas lift gas. Well has been shut in since. Objective: Set dummy GLV’s. Pressure test. Perform hydraulic fracture stimulation to stimulate the Kuparuk C formation. Flow well back through portable test separator. Current Status: Operable Producer, Shut-In Recent Integrity: x 6/1/2023 – MIT-T passed to 3,695 psi x 6/1/2023 – MIT-IA passed to 3,500 psi Procedure: Slickline/Fullbore 1. MIRU SL. 2. Set plug in X-nipple at 7,065’. 3. Set catcher on top of the plug. 4. Pull LGLV’s. Install DGLV’s in Stations #2 thru #5 and a flow sleeve in Station #1. 5. Circulate wellbore to 1% KCl or Seawater and crude freeze protect. U-tube crude freeze protect. a. Total TBG & IA Volume down to Station #1: 106 bbls + 372 bbls = 478 bbls b. Freeze Protect volume to 2500’ in TBG & IA: 38 bbls + 134 bbls = 172 bbls 6. Pull flow sleeve from Station #1 and install DGLV. 7. Perform MIT-T to target 3,500 psi (max applied 3800 psi). 8. Perform MIT-IA to 3,500 psi (max applied 3800 psi). Hold 1000 psi on tubing during MIT-IA. 9. Pull plug and catcher. Kuparuk Frac Well: S-17C PTD: 202-007 Frac 1. MIRU frac spread and associated equipment/tanks. a. Heat water to 110 deg F, minimum pumping temp – 90 deg F 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. Perform pressure tests prior to performing hydraulic fracture stimulation. a. Pressure test surface lines to 5,500 psi. b. Pressure test pump kick outs to 4,050 psi and global kick outs to 4,275 psi. c. Function test IA Pop-Off system to ensure operating properly. IA Pop-Offs to be set at 3,325 psi. d. Bring IA pressure up to a hold pressure of 3,025 psi. 4. Pump the hydraulic fracture stimulation per the proposed pump schedule below. Maximum allowable treating pressure is 4,500 psi. Kuparuk Frac Well: S-17C PTD: 202-007 Anticipated Pressures: MIT-T 3,500 psi MIT-IA 3,500 psi Maximum Anticipated Treating Pressure:3,090 psi @ 25 BPM IA Pop-off Set Pressure (95% of MIT-IA):3,325 psi IA Minimum Hold Pressure (POP-off – ~300 psi):3,025 psi Maximum Allowable Treating Pressure (MATP = Ann hold + MIT-T/1.1): 4,500 psi (tree limited to 5,000 psi) Stagger Pump Kickouts Between 90 – 95% of MATP:4,050 – 4,275 psi Global Kickout (95% of MATP):4,275 psi N2 POP-off set pressure (MATP):4,500 psi Treating Line Test Pressure (MATP + 1000 psi):5,500 psi OA Pressure:Monitor Max Anticipated Proppant Loading:12 PPA 5. RDMO frac equipment. Freeze protect well. Coil Tubing (Pending) – FCO if early screenout occurs during frac or perfs are covered w/ proppant 1. MU BDJSN. a. Recommended to run without checks so reverse circulating can be performed. 2. RIH dry and tag top of proppant. 3. PU and establish circulation. a. Recommended to perform reverse FCO until returns are less than ~70% 4. FCO down to ~7,500’ MD. a. Once returns fall below ~70% pickup and circulate coiled tubing clean. Swap circulation to the long way and continue FCO with gel sweeps. Stage #Fluid Stage Prop Con (ppa) Rate (bpm) Volume (bbls) CUM Volume (bbls)Proppant Name Proppant (#) CUM Proppant (#) 1 FW w/ adds Injection Test 0 25 125 125 0 0 2 Shutdown 125 0 3 28# X-Link Pad 0.5 25 150 275 0 0 4 28# X-Link Scour 0 25 100 375 100 Mesh 2055 2055 5 28# X-Link Pad 0 25 150 525 0 2055 6 28# X-Link Flat 1 25 100 625 16-20 CarboBOND 4022 6077 7 28# X-Link Flat 2 25 50 675 16-20 CarboBOND 3859 9936 8 28# X-Link Flat 3 25 50 725 16-20 CarboBOND 5562 15498 9 28# X-Link Flat 4 25 50 775 16-20 CarboBOND 7137 22635 10 28# X-Link Flat 5 25 50 825 16-20 CarboBOND 8598 31233 11 28# X-Link Flat 6 25 50 875 16-20 CarboBOND 9957 41190 12 28# X-Link Flat 7 25 50 925 16-20 CarboBOND 11224 52414 13 28# X-Link Flat 8 25 100 1025 16-20 CarboBOND 24816 77230 14 28# X-Link Flat 9 25 100 1125 16-20 CarboBOND 27035 104265 15 28# X-Link Flat 10 25 100 1225 16-20 CarboBOND 29117 133382 16 28# X-Link Flat 11 25 100 1325 16-20 CarboBOND 31076 164458 17 28# X-Link Flat 12 25 100 1425 16-20 CarboBOND 32921 197379 18 FW w/ adds Flush 0 25 70 1495 197379 19 Diesel Freeze Protect 0 25 40 1535 197379 Kuparuk Frac Well: S-17C PTD: 202-007 b. If losses become unmanageable while forward circulating and perfs are still covered can attempt FCO with diesel. If losses are still unmanageable with diesel, coil will need to rig down for SL to install gas lift valves. Slickline 1. MIRU SL. Set LGLV design. Portable Testers 1. MIRU, pressure test 2. POP the well to LRS with 1-1.5 MMSCFD Lift gas at minimum choke, adjust GL rate as necessary to eliminate slugging. Flow the initial returns to the flowline as long as the shake-outs meet the returned fluid/solids management guidelines. a. If at any point, solids are >0.5%, divert returns to flowback tanks. 3. Limit flow to ~500 bpd 4. If solids are < 1%, after 1.5 wellbore volumes (177 bbls) increase the production rate to 750 BLPD. 5. Flow bottoms up and sample for solids production. If solids are still below 1%, increase flow to 1000 BFPD. 6. Flow bottoms up (~118 bbls) and sample for solids production. If solids are still below 1% continue to increase the flow rate in 250 BPD increments. The objective is to achieve maximum drawdown. Watch returns and do not continue to open choke if solids > 1%; allow well to clean up before choke is opened further. 7. Once at FOC, stabilize the well for 4 hrs. Obtain an 8 hr piggyback well test. Attachments: x Current Wellbore Schematic x Sundry Revision Change Form Kuparuk Frac Well: S-17C PTD: 202-007 Current Wellbore Schematic: Kuparuk FracWell: S-17CPTD: 202-007Sundry 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 ChangeHNSPreparedBy (Initials)HNSApprovedBy (Initials)AOGCC Written ApprovalReceived (Person andDate)Approval:Operations Manager DatePrepared:Operations Engineer Date S-17C Fracture Stimulation PTD: 202-007 Page 1 Date: April 24, 2025 Subject: S-17C Fracture Stimulation From: Hunter Gates O: (907) 777-8326 C: (215) 498-7274 To: AOGCC Estimated Start Date: 5/28/2025 Attached is Hilcorp’s proposal and supporting documents to perform a fracture stimulation on well S- 17C (PTD #202-007) in the Kuparuk reservoir of the Prudhoe Bay Unit. The objective of this program is to perform a single stage fracture stimulation to the existing Kuparuk perforations to improve well performance. A RWO was completed on S-17C to abandon the Ivishak formation and re-complete the well as a Kuparuk producer in May 2023. The well was POP’d post-RWO and showed favorable water cut values but struggled to sustain flow so was shut in. A hydraulic fracture stimulation is planned for the already perforated interval to increase well productivity. Hilcorp requests a variance to sections 20 AAC 25. 283, a, 3- 4 which require identification of fresh - water aquifers and a plan for base-water sampling. Please direct questions or comments to Hunter Gates. Hilcorp requests a variance to sections 20 AAC 25. 283, a, 3- 4 which require identification of fresh - water aquifers and a plan for base-water sampling. S-17C Fracture Stimulation PTD: 202-007 Page 2 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. S-17C Fracture Stimulation PTD: 202-007 Page 3 SIGNED AFFIDAVIT: S-17C Fracture Stimulation PTD: 202-007 Page 4 COPY OF NOTIFICATION SENT VIA EMAIL: S-17C Fracture Stimulation PTD: 202-007 Page 5 SECTION 2 - PLAT IDENTIFYING ALL WELLS WITHIN ½ MILE (20 AAC 25.283, a, 2): S-17C Fracture Stimulation PTD: 202-007 Page 6 LIST OF WELLS IN PLAT WITHIN ½ MILES ON SURFACE (20 AAC 25.283, a, 2, C): Sw Name Well Class Desc Well Status Desc Sw Name Well Class Desc Well Status Desc Sw Name Well Class Desc Well Status Desc S-01 Development Abandoned S-116APB2 Service Plugged Back For Redrill S-213 Development Abandoned S-01A Development Abandoned S-117 Development Oil Producer Gas Lift S-213A Development Oil Producer Gas Lift S-01B Development Abandoned S-118 Development Oil Producer Gas Lift S-213AL1 Development Oil Producer Flowing S-01C Development Oil Producer Gas Lift S-119 Development Abandoned S-213AL1-01 Development Oil Producer Flowing S-02 Development Abandoned S-119A Development Oil Producer Shut-In S-213AL2 Development Oil Well S-02A Development Oil Producer Gas Lift S-11A Service Abandoned S-213AL3 Development Oil Well S-02AL1 Development Oil Well S-11B Service Water Injector Injecting S-215 Service Water Injector Injecting S-02AL1PB1 Development Plugged Back For Redrill S-12 Development Abandoned S-216 Service Miscible Injector Operating S-02APB1 Service Plugged Back For Redrill S-120 Service Water Injector Injecting S-217 Service Miscible Injector Operating S-03 Development Oil Producer Gas Lift S-121 Development Oil Producer Gas Lift S-218 Service Water Injector Injecting S-04 Service Water Injector Shut-In S-121PB1 Development Plugged Back For Redrill S-22 Development Abandoned S-05 Development Abandoned S-122 Development Oil Producer Gas Lift S-22A Development Abandoned S-05A Service Water Injector Injecting S-122PB1 Development Plugged Back For Redrill S-22B Service Water Injector Injecting S-05APB1 Service Plugged Back For Redrill S-122PB2 Development Plugged Back For Redrill S-23 Development Oil Producer Gas Lift S-06 Service Water Injector Injecting S-122PB3 Development Plugged Back For Redrill S-24 Development Abandoned S-07 Development Abandoned S-123 Service Water Injector Injecting S-24A Service Abandoned S-07A Development Oil Producer Shut-In S-124 Service Water Injector Injecting S-24APB1 Service Plugged Back For Redrill S-08 Development Abandoned S-125 Development Oil Producer Gas Lift S-24B Service Water Injector Injecting S-08A Development Abandoned S-125PB1 Development Plugged Back For Redrill S-25 Development Abandoned S-08B Development Oil Producer Gas Lift S-126 Service Miscible Injector Operating S-25A Service Water Injector Injecting S-09 Service Abandoned S-128 Service Water Injector Injecting S-25APB1 Service Plugged Back For Redrill S-09A Service Water Injector Injecting S-128PB1 Service Plugged Back For Redrill S-26 Development Oil Producer Shut-In S-09APB1 Service Plugged Back For Redrill S-128PB2 Service Plugged Back For Redrill S-27 Development Abandoned S-09APB2 Service Plugged Back For Redrill S-129 Development Abandoned S-27A Development Abandoned S-09APB3 Service Plugged Back For Redrill S-129A Development Oil Producer Gas Lift S-27APB1 Development Plugged Back For Redrill S-10 Development Abandoned S-129PB1 Development Plugged Back For Redrill S-27B Development Oil Producer Shut-In S-100 Development Oil Producer Flowing S-129PB2 Development Plugged Back For Redrill S-28 Development Abandoned S-101 Service Miscible Injector Operating S-12A Development Abandoned S-28A Development Abandoned S-101PB1 Development Plugged Back For Redrill S-12B Development Oil Producer Shut-In S-28B Development Oil Producer Shut-In S-102 Development Abandoned S-13 Development Abandoned S-28BPB1 Development Plugged Back For Redrill S-102L1 Development Abandoned S-134 Service Water Injector Injecting S-29 Development Abandoned S-102L1PB1 Development Plugged Back For Redrill S-135 Development Oil Producer Gas Lift S-29A Service Water Injector Shut-In S-102PB1 Development Plugged Back For Redrill S-135PB1 Development Plugged Back For Redrill S-29AL1 Service Water Injector Shut-In S-102A Development Oil Producer Gas Lift S-135PB2 Development Plugged Back For Redrill S-30 Development Oil Producer Shut-In S-103 Development Oil Producer Gas Lift S-13A Development Oil Producer Gas Lift S-31 Development Abandoned S-104 Service Water Injector Injecting S-13APB1 Development Plugged Back For Redrill S-31A Service Water Injector Injecting S-105 Development Abandoned S-14 Service Abandoned S-32 Development Abandoned S-105A Development Oil Producer Gas Lift S-14A Service Water Injector Shut-In S-32A Development Oil Producer Shut-In S-106 Development Abandoned S-15 Service Miscible Injector Shut-In S-33 Development Oil Producer Gas Lift S-106A Development Oil Producer Gas Lift S-15PB1 Service Plugged Back For Redrill S-34 Service Water Injector Injecting S-106L1PB1 Development Plugged Back For Redrill S-16 Development Oil Producer Shut-In S-35 Development Oil Producer Gas Lift S-106L1 Development Abandoned S-16PB1 Development Plugged Back For Redrill S-36 Development Oil Producer Shut-In S-106PB1 Development Plugged Back For Redrill S-17 Development Abandoned S-37 Development Abandoned S-107 Service Miscible Injector Shut-In S-17A Development Abandoned S-37A Development Oil Producer Shut-In S-108 Development Oil Producer Shut-In S-17AL1 Development Abandoned S-37APB1 Development Plugged Back For Redrill S-109PB1 Development Plugged Back For Redrill S-17AL1PB1 Development Plugged Back For Redrill S-38 Development Oil Producer Shut-In S-10A Development Suspended S-17APB1 Development Plugged Back For Redrill S-40 Development Abandoned S-10APB1 Development Plugged Back For Redrill S-17B Development Abandoned S-400 Service Abandoned S-10APB2 Development Plugged Back For Redrill S-17C Development Oil Producer Shut-In S-400A Service Water Injector Shut-In S-11 Service Abandoned S-17CPB1 Development Plugged Back For Redrill S-401 Service Water Injector Shut-In S-110 Service Abandoned S-17CPB2 Development Plugged Back For Redrill S-401PB1 Service Plugged Back For Redrill S-110A Service Abandoned S-18 Development Abandoned S-40A Development Oil Producer Shut-In S-110B Service Water Injector Injecting S-18A Development Abandoned S-41 Development Abandoned S-111 Service Water Injector Injecting S-18B Development Oil Producer Shut-In S-41A Service Water Injector Injecting S-111PB1 Service Plugged Back For Redrill S-19 Development Oil Producer Shut-In S-41AL1 Service Water Injector Shut-In S-111PB2 Service Plugged Back For Redrill S-20 Service Abandoned S-41L1 Development Abandoned S-112 Service Water Injector Injecting S-200 Development Abandoned S-41PB1 Service Plugged Back For Redrill S-112L1 Service Water And Gas Injector S-200A Development Oil Producer Gas Lift S-42 Development Abandoned S-112L1PB1 Service Plugged Back For Redrill S-200PB1 Development Plugged Back For Redrill S-42A Development Oil Producer Gas Lift S-112L1PB2 Service Plugged Back For Redrill S-201 Development Abandoned S-42PB1 Service Plugged Back For Redrill S-113 Development Abandoned S-201A Service Miscible Injector Operating S-43 Development Oil Producer Gas Lift S-113A Development Abandoned S-201PB1 Development Plugged Back For Redrill S-43L1 Development Oil Producer Gas Lift S-113B Development Oil Producer Shut-In S-202 Development Oil Producer Gas Lift S-44 Development Abandoned S-113BL1 Development Oil Producer Shut-In S-202L1 Development Oil Well S-44A Development Oil Producer Flowing S-114 Development Abandoned S-202L2 Development Oil Well S-44L1 Development Abandoned S-114A Service Water Injector Shut-In S-202L3 Development Oil Well S-44L1PB1 Development Plugged Back For Redrill S-115 Development Oil Producer Gas Lift S-202L4 Development Oil Well S-504 Service Water Injector Shut-In S-116 Service Abandoned S-20A Service Water Injector Injecting M-200 Development Oil Producer Gas Lift S-116A Service Miscible Injector Operating S-21 Development Oil Producer Gas Lift S-116APB1 Service Plugged Back For Redrill S-210 Service Water Injector Injecting S-17C Fracture Stimulation PTD: 202-007 Page 7 SECTION 3 - EXEMPTION FOR FRESWATER AQUIFERS (20 AAC 25.283, a, 3): Well S-17C is in the West Operating Area of Prudhoe Bay. Per Aquifer Exemption Order No. 1 dated July 11, 1986 where Standard Alaska Production Company requested the Alaska Oil and Gas Conservation Commission to issue an order exempting those portions of all aquifers lying directly below the Western Operating Area and K Pad Area of the Prudhoe Bay Unit for Class II Injection activities. Findings 1- 4 state: 1. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit do not currently serve as a source of drinking water. 2. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit are situated at a depth and location that makes recovery of water for drinking water purposes economically impracticable. 3. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit are reported to have total dissolved solids content of 7000 mg/ I or more. 4. By letter of July 1, 1986, EPA- Region 10 advises that the aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit qualify for exemption. It is considered to be a minor exemption and a non-substantial program revision not requiring notice in the Federal Registrar. Per the above findings, " Those portions of freshwater aquifers lying directly below the Western Operating and K Pad Areas of the Prudhoe Bay Unit qualify as exempt freshwater aquifers under 20 AC 25. 440" thus allowing Hilcorp exemption from 20 AAC 25. 283, a, 3- 4 which require identification of freshwater aquifers and establishing a plan for base-water sampling. S-17C Fracture Stimulation PTD: 202-007 Page 8 SECTION 4 - PLAN FOR BASELINE WATER SAMPLING FOR WATER WELLS (20 AAC 25.283, a, 4): 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. S-17C Fracture Stimulation PTD: 202-007 Page 9 SECTION 5 - DETAILED CEMENTING AND CASING INFORMATION (20 AAC 25.283, a, 5): All casing is cemented and tested in accordance with 20 AAC 25.030, g when completed. See wellbore schematic for casing details: S-17C Fracture Stimulation PTD: 202-007 Page 10 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: Spudded 8/6/1984 with a 17-1/2” hole to 2,700’ where 13-3/8” surface casing was set and cemented at 2,663’ with 3,255 cuft (580 bbls) ASIII followed by 465 cuft (83 bbls) ASII followed by a 50 sx cement top job. The 13-3/8” casing was tested to 3,000 psi and the production hole was started. A leak off test of 0.68 psi/ft gradient was obtained. The production hole was directionally drilled to 9,507’ with a 12-1/4” bit. Openhole logs were run then 9-5/8” casing set at 9,488’ and cemented in place with 1,705 cuft (304 bbls) of 13.2 ppg Class G w/ 8% gel followed by a tail of 230 cuft (41 bbls) 15.8 ppg Class G neat. Cement job was pumped per program and no losses were indicated after cement reached the shoe. The 9-5/8” casing was subsequently tested to 3,000 psi. A CBL pulled in a 2023 workover showed a clear TOC at ~6,050’ MD. Finally, an 8-1/2” hole was drilled to 9,940’ where 7” production liner was run and cemented with 278 cuft (~50 bbls) 12.5 ppg Class G cement. While WOC, the OA was downsqueezed with another 279 cuft (~50 bbls) of ASII followed by Arctic Pack. After waiting on liner cement and performing a fill cleanout, the liner would not pressure test. A CBL revealed no cement around the liner. Another 204 cuft (~36 bbls) of cement was pumped through added perforation at 9,812’ followed by another FCO and a successful pressure test. The well was swapped over to NaCl and 4-1/2” production tubing was run and tested to 3,500 psi. S-17A was sidetracked out of the 9-5/8” production casing at ~8,800’ MD which does not affect cement isolation over the Kuparuk of the original S-17 production casing. S-17AL1 & S-17B were Ivishak CTD sidetracks that exited 7” production liner below the 9-5/8” production casing. S-17C CTD drilling kicked off in the Shublik and drilled to TD where liner was run to 10,610’. The liner was cemented with 18 bbls of cement. Cement was displaced within expected volumes, after cement in place, floats held. An RWO in May 2023 was performed to execute an up hole recomplete from the Ivishak reservoir to the Kuparuk reservoir. The 2-7/8” liner was isolated with a bridge plug and cement. The existing 4-1/2” tubing was cut pre-rig and pulled out of hole. A new 4-1/2” upper completion was run and set. 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. Hilcorp has identified shallow hydrocarbon zones in the Schrader Bluff and Ugnu that were not isolated during the primary cement job of the parent wellbore 9-5/8” casing. Hilcorp has requested a variance to this requirement (see attached emails for variance request). I recommend granting the variance as these zones are well isolated from the proposed frac. -A.Dewhurst 20MAY25 A CBL pulled in a 2023 workover showed a clear TOC at ~6,050’ MD. S-17C Fracture Stimulation PTD: 202-007 Page 11 SECTION 7 - PRESSURE TEST INFORMATION AND PLANS TO PRESSURE TEST CASINGS AND TUBING INSTALLED IN THE WELL (20 AAC 25.283, a, 7): On 6/1/2023, the tubing was pressure tested to 3,695 psi for a passing MIT-T On 6/1/2023, the casing was pressure tested to 3,500 psi for a passing MIT-IA Live gas lift valves were installed 6/11/2023 to flow test the well. Ahead of fracturing operations, live gas lift valves will be pulled and replaced with dummy valves. The tubing and casing will be pressure tested to the following: - MIT-T = 3,500 psi - MIT-IA = 3,500 psi The production casing annulus pressure 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 3,500 psi MIT-IA 3,500 psi Maximum Anticipated Treating Pressure:3,090 psi @ 25 BPM IA Pop-off Set Pressure (95% of MIT-IA):3,325 psi IA Minimum Hold Pressure (POP-off – ~300 psi):3,025 psi Maximum Allowable Treating Pressure (MATP = Ann hold + MIT-T/1.1): 4,500 psi (tree limited to 5,000 psi) Stagger Pump Kickouts Between 90 – 95% of MATP:4,050 – 4,275 psi Global Kickout (95% of MATP):4,275 psi N2 POP-off set pressure (MATP):4,500 psi Treating Line Test Pressure (MATP + 1000 psi):5,500 psi OA Pressure:Monitor Max Anticipated Proppant Loading:12 PPA S-17C Fracture Stimulation PTD: 202-007 Page 12 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 13-3/8” Surface Casing 72#L80 5,380 2,670 9-5/8” Production Casing 47#L80 6,870 4,760 7” Production Liner 26#L80 7,240 5,410 4-1/2” Production Tubing 12.6#L80 8,430 7,500 3-1/2” Production Liner 9.2#L80 10,160 10,540 2-7/8” Production Liner 6.5#L80 10,570 11,170 Wellhead: McEvoy manufactured wellhead, rated to 5,000 psi Tubing head adaptor: 13-5/8", 5,000 psi x 4-1/16", 5,000 psi Tubing Spool: 13-5/8" 5, 000 psi w/ 3-1/8" side outlets Casing Spool: 13-5/8" 5, 000 psi w/ 3-1/8" side outlets Tree: CIW 4-1/16" 5,000 psi. x No tree saver planned to be used. Anticipated surface treating pressure <4,500 psi. S-17C Fracture Stimulation PTD: 202-007 Page 13 SECTION 9 - DATA FOR FRACTURING ZONE AND CONFINING ZONES (20 AAC 25.283, a, 9): Formation*MD Top MD Bottom TVDss Top TVDss Bottom TVD Thickness Frac Grad psi/ft Lith. Desc. THRZ 7077 7169 -6593 -6677 84 0.7 Shale TKLB 7169 7177 -6677 -6685 8 0.7 Shale Top Kup/C interval 7177 7247 -6685 -6749 64 0.62 Silts/SS LCU/ Kuparuk B 7247 7299 -6749 -6796 48 0.64 Silts/SS Kuparuk A 7299 7368 -6796 -6859 63 0.66 Silts/SS Miluveach 7368 8181 -6859 -7589 730 0.7 Shale *Depths are taken from the S-17. S-17C Fracture Stimulation PTD: 202-007 Page 14 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 S-17C wellbore reservoir trajectory and location of faults. The blue line indicates the approximate fracture length and orientation of the frac’s. 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 and seismic, well 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. 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īĺŜôîŪıŕôîώ͒͘ώææīŜώĺċώ͐͑ϟ͔ώŕŕČώ[ĖťôŘôťôώèôıôĲťώÍŜώīôÍîώċĺīīĺſôîώæƅώ͕͒ώææīŜώĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜД@ДώťÍĖīώŜīŪŘŘƅϟώ͔͑ώææīŜώĺċώīĺŜŜôŜώſôŘôώĺæŜôŘŽôîϟώŪæťŘÍèťĖĲČώťēĖŜώ͔͑ώææīŜϠώ͐ώææīώŜēĺôώťŘÍèħŽĺīŪıôϠώÍĲîώÍŜŜŪıĖĲČώ͒͏҇ώſÍŜēĺŪťϠώťēÍťώſĺŪīîώŕŪťώĺŪŘώťĺŕώĺċώèôıôĲťώÍťώ͔Ϡ͒͗͑ДώſēĖèēώĖŜôƄÍèťīƅώſēôŘôώťēôώ͔ϱ͐ϯ͑ГώèÍŜĖĲČώèŘĺŜŜôŜώĺŽôŘώťĺώ͒ϱ͐ϯ͑ГϟaIϱώŕÍŜŜôîώťĺώ͐Ϡ͓͓͑ώŕŜĖώĺĲώ͐͏ϯ͐͗ϯ͑͏͑͏ϟŘôÍώĺċώôŽĖôſώώϱ͖͐ S-17C Fracture StimulationPTD: 202-007Page 16®ôīīώbÍıô " I "ĖŜťÍĲèôώϯώťÍťŪŜĺŕώĺċώiĖīώĺĺīϼXŪŕÍŘŪħϠώa"ϽĺŕώĺċώiĖīώĺĺīϼXŪŕÍŘŪħϠώ«"ŜŜϽĺŕώĺċώıťϼa"Ͻĺŕώĺċώıťϼ«"ŜŜϽ¾ĺĲÍīIŜĺīÍťĖĺĲĺııôĲťŜϱ͕͐͐ ͑͏͒ϱ͐͗͐ ͔͏ϱ͏͑͘ϱ͑͒͐͗͒ϱ͏͏ϱ͏͏͐Ϡ͓͑͏ДώϯώЭДîώċĺŘĖîôťŘÍèħ͖Ϡ͖͐͘Д ͕Ϡ͖͖͑Д ͒Ϡ͗͐͗Д ͒Ϡ͓͐͗Д īĺŜôîŪıŕôîώ͓͐͑ϟ͑ώææīŜώĺċώ͐͑ώŕŕČώ[ĖťôŘôťôώċĺīīĺſôîώæƅώ͓͒ώææīŜώĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДώÍŜώĖťŜώťÍĖīϟbĺώīĺŜŜôŜώſôŘôώĺæŜôŘŽôîϟώIĲèīŪîĖĲČώŜēĺôώťŘÍèħώŽĺīŪıôϠώèÍīèŪīÍťĖĲČώiώÍĲîώÍŜŜŪıĖĲČώ͒͏҇ſÍŜēĺŪťώæŘĖĲČŜώťĺŕώťĺώ͒Ϡ͓͐͗Дώa"ϟϱ͕͐͐ ͑͐͒ϱ͐͒͘ ͔͏ϱ͏͑͘ϱ͑͒͐͗͒ϱ͏͐ϱ͏͏͐Ϡ͓͑͏ДώϯώiŕôŘÍæīô®@ώIĲĤôèťĺŘ͖Ϡ͖͐͘Д ͕Ϡ͖͖͑Д ͒Ϡ͗͐͗Д ͒Ϡ͓͐͗Д īĺŜôîēĖŜώſôīīæĺŘôώŪťĖīĖƏôŜώťēôώŕÍŘôĲťώæĺŘôώĺċώϱ͕͐͐ϟÍŜŜôîώaIϱIώÍťώ͓͑͒͑ώŕŜĖώĺĲώ͔ϯ͘ϯ͑͏͑͑ϟϱ͕͐͐͐ ͑͐͒ϱ͐͒͘ ͔͏ϱ͏͑͘ϱ͑͒͐͗͒ϱ͏͐ϱ͏͏͐Ϡ͓͑͏ДώϯώЭДîώċĺŘĖîôťŘÍèħ͖Ϡ͖͐͘Д ͕Ϡ͖͖͑Д ͒Ϡ͗͐͗Д ͒Ϡ͓͐͗Д īĺŜôî ēĖŜώſÍŜώÍώŕīŪČæÍèħώĺċώťēôώϱ͕͐͐ώŜĖîôťŘÍèħϟϱ͕͐͐͑ ͑͐͒ϱ͐͒͘ ͔͏ϱ͏͑͘ϱ͑͒͐͗͒ϱ͏͐ϱ͏͏͐Ϡ͓͑͏ДώϯώЭДîώċĺŘĖîôťŘÍèħ͖Ϡ͖͐͘Д ͕Ϡ͖͖͑Д ͒Ϡ͗͐͗Д ͒Ϡ͓͐͗Д īĺŜôî ēĖŜώſÍŜώÍώŕīŪČæÍèħώĺċώťēôώϱ͕͐͐ώŜĖîôťŘÍèħϟϱ͖͐͐ ͑͏͒ϱ͏͐͑ ͔͏ϱ͏͑͘ϱ͖͑͒͐͒ϱ͏͏ϱ͏͏͑Ϡ͔͒͐ДώϯώiŕôŘÍæīôŘĺîŪèôŘ͖Ϡ͓͑͘Д ͕Ϡ͕͔͕Д ͒Ϡ͓͗͐Д ͒Ϡ͒͗͑Д īĺŜôîŪıŕôîώ͐͑͑ϟ͐ώææīŜώĺċώ͐͐ϟ͒ώŕŕČώīÍŜŜώД@ДώÍŜώīôÍîώċĺīīĺſôîώæƅώ͕͒ϟ͘ώææīŜώĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДťÍĖīώŜīŪŘŘƅϟώbĺώīĺŜŜôŜώſôŘôώĺæŜôŘŽôîϟώIĲèīŪîĖĲČώŜēĺôώťŘÍèħώŽĺīŪıôώÍĲîώèÍīèŪīÍťĖĲČώċĺŘώ͒͏҇ſÍŜēĺŪťϠώťēĖŜώæŘĖĲČŜώťēôώťĺŕώťĺώ͒Ϡ͓͗͐Дώa"ϟÍŜŜôîώèĺīîώI>[ώĺĲώ͐͑ϯ͑ϯ͑͏͑͏ϟϱ͐͐͗ ͑͏͒ϱ͑͏͏ ͔͏ϱ͏͑͘ϱ͑͒͐͗͗ϱ͏͏ϱ͏͏͐Ϡ͓͓͏ДώϯώiŕôŘÍæīôŘĺîŪèôŘ͕Ϡ͖͐͘Д ͕Ϡ͕͖͕Д ͒Ϡ͓͒͒Д ͒Ϡ͏͔͒Д 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͔͏ϱ͏͑͘ϱ͓͑͒͒͒ϱ͏͐ϱ͏͏͑Ϡ͖͔͑ДώϯώiŕôŘÍæīôŘĺîŪèôŘ͘Ϡ͗͗͑Д ͕Ϡ͖͕͘Д ͒Ϡ͔͗͏Д ͒Ϡ͓͔͏Д īĺŜôîŪıŕôîώ͔͑͐ώææīŜώĺċώ͐͐ϟ͔ώŕŕČώ[ĖťôŘôťôώÍŜώīôÍîώċĺīīĺſôîώæƅώ͔͑ϟ͖ώææīŜώĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДťÍĖīώŜīŪŘŘƅϟώ͔͗ώææīŜώĺċώīĺŜŜôŜώſôŘôώĺæŜôŘŽôîώſēĖīôώèôıôĲťĖĲČϟώ>ĺŘťŪĲÍťôīƅϠώÍώ[ϯIώīĺČſÍŜώŘŪĲώĺĲώ͐͑ϯ͐͏ϯ͑͏͐͘ώŕŘĺŽĖîĖĲČώÍώiώŕĖèħώÍťώ͒Ϡ͔͗͏Дώa"ϟÍŜŜôîώaIϱώÍĲîώaIϱIώÍťώ͕͓͒͑ώŕŜĖώÍĲîώ͕͕͒͘ώŕŜĖϠώŘôŜŕôèťĖŽôīƅώĺĲώ͐͑ϯ͖͑ϯ͑͏͐͘ϟϱ͐͑͐͘ ͑͐͏ϱ͐͒͑ ͔͏ϱ͏͑͘ϱ͓͑͒͒͒ϱ͏͏ϱ͏͏͑Ϡ͖͔͑ДώϯώЭДîώċĺŘĖîôťŘÍèħ͗Ϡ͖͕͗Д ͕Ϡ͖͖͏ ͒Ϡ͔͑͘Д ͒Ϡ͕͕͑Д īĺŜôî ēĖŜώſÍŜώÍώŕīŪČæÍèħώĺċώťēôώĖĲĖťĖÍīώϱ͐͑͘ώŕĖīĺťώēĺīôώîŘĖīīôîώŕŘĖĺŘώťĺώŘŪĲĲĖĲČώèÍŜĖĲČϟϱ͐͑͑͘ ͑͐͏ϱ͐͒͑ ͔͏ϱ͏͑͘ϱ͓͑͒͒͒ϱ͏͏ϱ͏͏͑Ϡ͖͔͑ДώϯώЭДîώċĺŘĖîôťŘÍèħ͗Ϡ͖͕͗Д ͕Ϡ͖͖͏ ͒Ϡ͔͑͘Д ͒Ϡ͕͕͑Д īĺŜôî ēĖŜώſÍŜώÍώŕīŪČæÍèħώĺċώťēôώĖĲĖťĖÍīώϱ͐͑͘ώŕĖīĺťώēĺīôώîŘĖīīôîώŕŘĖĺŘώťĺώŘŪĲĲĖĲČώèÍŜĖĲČϟϱ͓͐͒ ͑͏͘ϱ͏͗͒ ͔͏ϱ͏͑͘ϱ͓͑͒͐͒ϱ͏͏ϱ͏͏ ͖͔͗ДώϯώiŕôŘÍæīôώ®I ͖Ϡ͕͒͘Д ͕Ϡ͕͕͘Д ͒Ϡ͓͓͘Д ͖͒͗͒Д 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īĺŜôîēĖŜώſÍŜώÍώ"ώīÍťôŘÍīώſēôŘôώīĖĲôŘώſÍŜώŘŪĲæŪťώĲĺťώèôıôĲťôîϟώēôώXiώſÍŜώĖĲώťēôώÍČώĖĲώťēôϱ͖͐ώæĺŘôϟώēôŘôċĺŘôώĖťώÍīŜĺώŪťĖīĖƏôŜώťēôώŕÍŘôĲťώſôīīæĺŘôώĺċώϱ͖͐ϱ͖͐[͐͐ ͔͐͘ϱ͏͓͗ ͔͏ϱ͏͑͘ϱ͓͑͐͐͗ϱ͕͏ϱ͏͏͏ДώϯώЭДîώċĺŘĖîôťŘÍèħ͖Ϡ͖͕͐Д ͕Ϡ͖͔͐Д ͕Ϡ͏͔͏Д ͔Ϡ͖͒͗Д īĺŜôî ēĖŜώſÍŜώÍώŕīŪČώæÍèħώĺċώťēôώϱ͖͐ώ[͐ϟ S-17C Fracture StimulationPTD: 202-007Page 17®ôīīώbÍıô " I "ĖŜťÍĲèôώϯώťÍťŪŜĺŕώĺċώiĖīώĺĺīϼXŪŕÍŘŪħϠώa"ϽĺŕώĺċώiĖīώĺĺīϼXŪŕÍŘŪħϠώ«"ŜŜϽĺŕώĺċώıťϼa"Ͻĺŕώĺċώıťϼ«"ŜŜϽ¾ĺĲÍīIŜĺīÍťĖĺĲĺııôĲťŜϱ͖͐͐ ͐͐͘ϱ͐͐͘ ͔͏ϱ͏͑͘ϱ͓͑͐͐͗ϱ͏͐ϱ͏͏͏ДώϯώЭДîώċĺŘĖîôťŘÍèħ͖Ϡ͖͕͐Д ͕Ϡ͖͔͐Д ͕Ϡ͏͔͏Д ͔Ϡ͖͒͗Д īĺŜôî ēĖŜώſÍŜώÍώŕīŪČώæÍèħώĺċώϱ͖͐ϟϱ͖͐ ͑͏͐ϱ͓͔͐ ͔͏ϱ͏͑͘ϱ͓͑͐͐͗ϱ͏͑ϱ͏͏͏ДώϯώЭДîώċĺŘĖîôťŘÍèħ͖Ϡ͖͕͐Д ͕Ϡ͖͔͐Д ͕Ϡ͏͔͏Д ͔Ϡ͖͒͗Д īĺŜôîēĖŜώſÍŜώÍώ"ώŜĖîôťŘÍèħώĺċώϱ͖͐ώÍĲîώťēôώĺŕôĲώēĺīôώŜôèťĖĺĲώſÍŜώĲôŽôŘώèĺıŕīôťôîϟώēĖŜÍīŜĺώŪťĖīĖƏôŜώťēôώŕÍŘôĲťώſôīīæĺŘôώĺċώϱ͖͐ϟϱ͖͐ ͑͏͑ϱ͏͏͖ ͔͏ϱ͏͑͘ϱ͓͑͐͐͗ϱ͏͒ϱ͏͏͏ДώϯώiŕôŘÍæīôŘĺîŪèôŘώI͖Ϡ͖͕͐Д ͕Ϡ͖͔͐Д ͕Ϡ͏͔͏Д ͔Ϡ͖͒͗Д īĺŜôîēĖŜώſÍŜώÍώŘôîŘĖīīώĺċώϱ͖͐ώÍĲîώťēôŘôċĺŘôώÍīŜĺώŪťĖīĖƏôŜώťēôώŕÍŘôĲťώæĺŘôώĺċώϱ͖͐ϟώēĖŜώĖŜώťēôſôīīώťēÍťώťēĖŜώiώĖŜώŕŘôŕÍŘôîώċĺŘϟϱ͖͐͐ ͑͏͑ϱ͏͏͖ ͔͏ϱ͏͑͘ϱ͓͑͐͐͗ϱ͏͒ϱ͏͏͏ДώϯώЭДîώċĺŘĖîôťŘÍèħ͖Ϡ͖͕͐Д ͕Ϡ͖͔͐Д ͕Ϡ͏͔͏Д ͔Ϡ͖͒͗Д īĺŜôî ēĖŜώſÍŜώÍώŕīŪČώæÍèħώĺċώϱ͖͐ϟϱ͖͐͑ ͑͏͑ϱ͏͏͖ ͔͏ϱ͏͑͘ϱ͓͑͐͐͗ϱ͏͒ϱ͏͏͏ДώϯώЭДîώċĺŘĖîôťŘÍèħ͖Ϡ͖͕͐Д ͕Ϡ͖͔͐Д ͕Ϡ͏͔͏Д ͔Ϡ͖͒͗Д īĺŜôî ēĖŜώſÍŜώÍώŜôèĺĲîώŕīŪČώæÍèħώĺċώϱ͖͐ϟϱ͐͘ ͕͐͗ϱ͕͐͐ ͔͏ϱ͏͑͘ϱ͕͑͐͐͐ϱ͏͏ϱ͏͏͑Ϡ͔͒͐ДώϯώiŕôŘÍæīôŘĺîŪèôŘώI͖Ϡ͕͐͗Д ͕͕͕͗Д ͓Ϡ͖͖͐Д ͓Ϡ͕͔͒Д īĺŜôîŪıŕôîώ͒͏͔ϟ͓ώææīŜώĺċώ͐͒ϟ͔ώŕŕČώīÍŜŜώД@ДώÍŜώīôÍîώċĺīīĺſôîώæƅώ͓͐ώææīŜώĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДťÍĖīώŜīŪŘŘƅϟώbĺώīĺŜŜôŜώſôŘôώĺæŜôŘŽôîϟώIĲèīŪîĖĲČώŜēĺôώťŘÍèħώŽĺīŪıôώÍĲîώèÍīèŪīÍťĖĲČώċĺŘώ͒͏҇ſÍŜēĺŪťϠώťēĖŜώæŘĖĲČŜώťēôώťĺŕώťĺώ͓Ϡ͕͔͒Дώa"ϟώώ͓͘ϟ͖ώææīώîĺſĲŜŗŪôôƏôώĺċώ͔͐ϟ͖ώŕŕČώŘèťĖèώôťώIſÍŜώÍīŜĺώŕŪıŕôîϟÍŜŜôîώI>[ώĺĲώ͔ϯ͑ϯ͑͏͑͐ϟϱ͑͏ ͕͐͗ϱ͓͖͐ ͔͏ϱ͏͑͘ϱ͕͖͑͐͒ϱ͏͏ϱ͏͏͑Ϡ͕͓͏ДώϯώЭДîώċĺŘĖîôťŘÍèħ͕Ϡ͘͏͔Д ͕Ϡ͕͔͒Д ͓Ϡ͒͐͘Д ͓Ϡ͒͗͐Д īĺŜôîŪıŕôîώ͒͐͐ϟ͘ώææīŜώĺċώ͐͒ϟ͔ώŕŕČώīÍŜŜώД@ДώÍŜώīôÍîώċĺīīĺſôîώæƅώ͓͐ώææīŜώĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДťÍĖīώŜīŪŘŘƅϟώbĺώīĺŜŜôŜώſôŘôώĺæŜôŘŽôîϟώIĲèīŪîĖĲČώŜēĺôώťŘÍèħώŽĺīŪıôώÍĲîώèÍīèŪīÍťĖĲČώċĺŘώ͒͏҇ſÍŜēĺŪťϠώťēĖŜώæŘĖĲČŜώťēôώťĺŕώťĺώ͓Ϡ͒͗͐Дώa"ϟώώ͓͘ϟ͖ώææīώîĺſĲŜŗŪôôƏôώĺċώ͔͐ϟ͖ώŕŕČώŘèťĖèώôťώIſÍŜώÍīŜĺώŕŪıŕôîϟϱ͑͑ ͐͘͏ϱ͖͓͐ ͔͏ϱ͏͑͘ϱ͑͑͐͐͘ϱ͏͏ϱ͏͏͑Ϡ͒͏͔ДώϯώЭДîώċĺŘĖîôťŘÍèħ͖Ϡ͖͖͐Д ͕Ϡ͕͕͗Д ͓Ϡ͖͔͏Д ͓Ϡ͕͔͒Д īĺŜôîŪıŕôîώ͒͏͗ϟ͐ώææīŜώĺċώ͐͒ϟ͔ώŕŕČώīÍŜŜώД@ДώÍŜώīôÍîώċĺīīĺſôîώæƅώ͔͐ϟ͕ώææīŜώĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДťÍĖīώŜīŪŘŘƅϟώbĺώīĺŜŜôŜώĲĺťôîϟώĲώ[ώſÍŜώŘŪĲώĺĲώ͐͐ϯ͑ϯ͑͏͐͘ώŕŘĺŽĖîĖĲČώŘôÍŜĺĲÍæīôώèôıôĲťèĺŽôŘÍČôώťĺώæôČĖĲώÍŘĺŪĲîώ͓Ϡ͖͔͏Дώa"ϟϱ͑͑ ͐͒͘ϱ͐͏͔ ͔͏ϱ͏͑͘ϱ͑͑͐͐͘ϱ͏͐ϱ͏͏͑Ϡ͒͏͔ДώϯώЭДîώċĺŘĖîôťŘÍèħ͖Ϡ͖͖͐Д ͕Ϡ͕͕͗Д ͓Ϡ͖͔͏Д ͓Ϡ͕͔͒Д īĺŜôîēĖŜώŜĖîôťŘÍèħώħĖèħôîώĺċċώÍťώ͗Ϡ͓͔͒Дώa"ώſēĖèēώĖŜώæôīĺſώſēôŘôώiώĖŜώĖĲώťēôώŕÍŘôĲťώæĺŘôϟώ[ĖĲôŘſÍŜώĲĺťώŘŪĲώÍĲîώiFώŕīŪČŜώſôŘôώŕŪıŕôîώſĖťēώťĺŕώÍťώ͗Ϡ͔͑͏Дϟϱ͖͑ ͐͘͏ϱ͏͖͘ ͔͏ϱ͏͑͘ϱ͑͑͏͔͖ϱ͏͏ϱ͏͏͑Ϡ͔͑͑ДώϯώЭДîώċĺŘĖîôťŘÍèħ͖Ϡ͘͏͏Д ͕Ϡ͖͗͑Д ͓Ϡ͖͖͗Д ͓Ϡ͕͓͔Д īĺŜôîŪıŕôîώ͒͑͒ϟ͘ώææīŜώĺċώ͐͒ϟ͔ώŕŕČώīÍŜŜώД@ДώÍŜώīôÍîώċĺīīĺſôîώæƅώ͐͏͑ϟ͓ώææīŜώĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДťÍĖīώŜīŪŘŘƅϟώbĺώīĺŜŜôŜώſôŘôώĺæŜôŘŽôîϟώIĲèīŪîĖĲČώŜēĺôώťŘÍèħώŽĺīŪıôώÍĲîώÍŜŜŪıĖĲČώ͒͏҇ſÍŜēĺŪťϠώťēĖŜώæŘĖĲČŜώťēôώťĺŕώťĺώ͓Ϡ͕͓͔Дϟϱ͖͑ ͔͐͘ϱ͐͏͏ ͔͏ϱ͏͑͘ϱ͑͑͏͔͖ϱ͏͐ϱ͏͏͑Ϡ͔͑͑ДώϯώЭДîώċĺŘĖîôťŘÍèħ͖Ϡ͘͏͏Д ͕Ϡ͖͗͑Д ͓Ϡ͖͖͗Д ͓Ϡ͕͓͔Д īĺŜôî ēĖŜώŜĖîôťŘÍèħώħĖèħôîώĺċċώæôīĺſώťēôώ͘ϱ͔ϯ͗ГώŜēĺôώÍĲîώŪťĖīĖƏôŜώťēôώŕÍŘôĲťώæĺŘôώĺċώϱ͖͑ϟϱ͖͑͐ ͔͐͘ϱ͐͏͏ 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͐͑͘ϱ͐͏͑ ͔͏ϱ͏͑͘ϱ͑͑͑͒͘ϱ͏͏ϱ͏͏͑Ϡ͕͓͏ДώϯώiŕôŘÍæīôŘĺîŪèôŘώI͖Ϡ͕͖͐Д ͕Ϡ͖͓͐ ͔Ϡ͓͑͏Д ͔Ϡ͓͔͐Д īĺŜôîŪıŕôîώ͕͕͐ϟ͘ώææīŜώĺċώ͐͐ϟ͔ώŕŕČώīÍŜŜώД@ДώèôıôĲťώÍŜώīôÍîώċĺīīĺſôîώæƅώ͔͒ϟ͘ώææīŜώĺċώ͔͐ϟ͗ώŕŕČīÍŜŜώД@ДώÍŜώťÍĖīώŜīŪŘŘƅϟώēôƅώîĖîώĲĺťώæŪıŕώťēôώŕīŪČώÍĲîώťÍČČôîώèôıôĲťώÍťώ͗Ϡ͐͏͔Дώa"ώϼĺŘώ͒͒ϟ͓ææīŜώēĖČēϠώſēĖèēώĖŜώÍèèĺŪĲťôîώċĺŘώĖĲώťēôώŽĺīŪıôťŘĖèŜώÍīĺĲČώſĖťēώŜēĺôώťŘÍèħώŽĺīŪıôϽϟώώIīĺČČôîώĖĲώ͑͏͏͗ώĖîôĲťĖċĖôŜώèôıôĲťώċĺŪĲîώÍťώ͑Ϡ͖͏͏Дώa"ώæŪťώŽĺīŪıôťŘĖèÍīīƅώťēĖŜώĖŜώŪĲīĖħôīƅώÍĲîťēôώīĺČώĖŜώĲĺťώîĖċċôŘôĲťĖÍťĖĲČώæôťſôôĲώîŘĖīīĖĲČώıŪîώÍĲîώèôıôĲťϟώ"ôċÍŪīťĖĲČώťĺώťēôώŽĺīŪıôťŘĖèıôťēĺîώÍĲîώÍŜŜŪıĖĲČώ͒͏҇ώſÍŜēώĺŪťϠώťēĖŜώæŘĖĲČŜώťēôώťĺŕώťĺώ͔Ϡ͓͑͏Дώa"ϟŘôÍώĺċώôŽĖôſώώϱ͖͐ S-17C Fracture StimulationPTD: 202-007Page 18®ôīīώbÍıô " I "ĖŜťÍĲèôώϯώťÍťŪŜĺŕώĺċώiĖīώĺĺīϼXŪŕÍŘŪħϠώa"ϽĺŕώĺċώiĖīώĺĺīϼXŪŕÍŘŪħϠώ«"ŜŜϽĺŕώĺċώıťϼa"Ͻĺŕώĺċώıťϼ«"ŜŜϽ¾ĺĲÍīIŜĺīÍťĖĺĲĺııôĲťŜϱ͓͓ ͖͐͘ϱ͏͏͕ ͔͏ϱ͏͑͘ϱ͖͔͑͑͒ϱ͏͏ϱ͏͏͑Ϡ͏͐͏ДώϯώЭДîώċĺŘĖîôťŘÍèħ͕Ϡ͓͗͑Д ͕Ϡ͕͖͐Д ͒Ϡ͐͒͏Д ͒Ϡ͐͒͏Д 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zone trajectory for the S-17C well. Fracture gradients within the confining zone (Kalubik and HRZ) will not be exceeded during fracture stimulation and would therefore confine injected fluids to the pool. The HRZ and Kalubik in this area are predominately shale with some silts with an estimated fracture pressure of ~14ppg. Faults 1-5 intersect the production interval and confining zone within the ½ mile radius of the planned fracs. Their displacements, sense of throw, and zone in which they terminate upwards are given below. The wellbore trajectory is a slant well through the Kuparuk. Maximum stress direction is estimated to be ~30 deg W of N. The fracs should not reach any of the mapped faults. The frac is 450’ from fault #1, 1,370’ from fault #2, 1,860’ from fault #3, 1,750‘ from fault #4 and 2,390’ from fault #5. The maximum anticipated fracture half-length of ~200’ is well short of these distances. Half-length is modeled using hydraulic fracture modelling software and is corroborated by what has been seen in other frac treatments. The frac stage should have sufficient offset to faults #1, #2, #3, #4 and #5 and should not intersect. If a sudden drop in treating pressure or increase in pump rate is seen during the stimulation that cannot be explaining by fluids pumped or annular pressure monitoring, pumping operation will stop until a plan forward and explanation can be put forth. Fault Throw Direction Upwards Termination 1 30-70' DTW Colville 2 0-60' DTW Colville 3 50-120' DTW Schrader Bluff 4 0-40' DTSW Colville 5 30-60' DTS Colville S-17C Fracture Stimulation PTD: 202-007 Page 20 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 5,500 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 4,500 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 Schedule: Note: There are three 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) A primary pressure transducer in the treating line will trigger a global kickout that will shift all the pumps into neutral. 3) 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. Stage #Fluid Stage Prop Con (ppa) Rate (bpm) Volume (bbls) CUM Volume (bbls)Proppant Name Proppant (#) CUM Proppant (#) 1 FW w/ adds Injection Test 0 25 125 125 0 0 2 Shutdown 125 0 3 28# X-Link Pad 0.5 25 150 275 0 0 4 28# X-Link Scour 0 25 100 375 100 Mesh 2055 2055 5 28# X-Link Pad 0 25 150 525 0 2055 6 28# X-Link Flat 1 25 100 625 16-20 CarboBOND 4022 6077 7 28# X-Link Flat 2 25 50 675 16-20 CarboBOND 3859 9936 8 28# X-Link Flat 3 25 50 725 16-20 CarboBOND 5562 15498 9 28# X-Link Flat 4 25 50 775 16-20 CarboBOND 7137 22635 10 28# X-Link Flat 5 25 50 825 16-20 CarboBOND 8598 31233 11 28# X-Link Flat 6 25 50 875 16-20 CarboBOND 9957 41190 12 28# X-Link Flat 7 25 50 925 16-20 CarboBOND 11224 52414 13 28# X-Link Flat 8 25 100 1025 16-20 CarboBOND 24816 77230 14 28# X-Link Flat 9 25 100 1125 16-20 CarboBOND 27035 104265 15 28# X-Link Flat 10 25 100 1225 16-20 CarboBOND 29117 133382 16 28# X-Link Flat 11 25 100 1325 16-20 CarboBOND 31076 164458 17 28# X-Link Flat 12 25 100 1425 16-20 CarboBOND 32921 197379 18 FW w/ adds Flush 0 25 70 1495 197379 19 Diesel Freeze Protect 0 25 40 1535 197379 S-17C Fracture Stimulation PTD: 202-007 Page 21 Frac Dimensions: Frac #MD Location, ft TVDss top, ft TVDss Bottom, ft Frac Half-Length, ft 1 7179 -6685 -6800 ~200’ Frac Modeling: Maximum Anticipated Treating Pressure: ~3,090 psi Surface pressure is calculated based on a closure pressure of ~0.62 psi/ft or ~4,190 psi. Closure pressure plus anticipated net pressure to be built (500 psi) and friction pressure minus hydrostatic results in a surface pressure of 3,090 psi at the time of flush. 4,190 psi (closure) + 500 psi (net) + 3000 psi (friction) – 4,600 psi (hydrostatic) = 3,090 psi (max surface press) The difference in closure pressures of the confining shale layers determines height of the fracture. Average confining layer stress is anticipated to be ~0.70 psi/ft. Fracture half-length is determined from confining layer stress as well as leak-off and formation modulus. The modeled frac is anticipated to reach a half-length of ~200 ft with a height of ~115 ft TVD. Disclaimer Notice: This model was generated 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. 7179 S-17C Fracture Stimulation PTD: 202-007 Page 22 Pre-Job Anticipated Chemicals to be pumped: S-17C Fracture Stimulation PTD: 202-007 Page 23 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 coil fill cleanout, the well will be put on production through a portable well test separator. All liquids will be captured and either sent to production facilities or diverted to flowback tanks if solids percentage becomes too high for the production facility to manage. The initial flowback period is intended to produce back the fracture fluids to tanks as quickly as possible, until the well is producing less than 0.5% solids, at which time the produced fluids meet the GC2 acceptance criteria for start-up. There will be a tank farm on pad to store the produced fluids from flowback operations. The flowback fluids not suitable for GC2 processing will be hauled to another facility’s slop tanks for additional settling time and/or 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:Hunter Gates <Hunter.Gates@hilcorp.com> Sent:Tuesday, 20 May, 2025 12:18 To:Joseph Syzdek; Dewhurst, Andrew D (OGC) Cc:Lau, Jack J (OGC); Wallace, Chris D (OGC); Davies, Stephen F (OGC) Subject:RE: [EXTERNAL] PBU S-17C Frac Sundry (325-271): Question Morning Andy, Joe filled me in on the conversation yesterday discussing the request for variance. Please see below our written request. If you need anything else from me regarding this sundry, please let me know. I will be providing similar variance requests for the other two fracs, S-126B & S-32A. Hilcorp would like to request a variance to regulation 20 AAC 25.283 6B which states that cement isolation across all hydrocarbon bearing zones is required. For the S-17C Sundry (325-271), we are requesting the variance to this rule due to the fact that our cement does not extend up to the hydrocarbon bearing Schrader Bluff and Ugnu Formations. The identified cement behind the 9-5/8” casing is from the shoe at 9,488’ MD up to a cement top at 6,050’ MD. With the Kuparuk top being 7,176’ MD, this would provide 1,126’ of cement above the proposed stimulated zone (Kuparuk fm.) and across the competent confining layers above and below (Kalibuk and Miluveach Fm., respectively). This will effectively contain the fracture treatment to the Kuparuk Fm. and protect the overlaying hydrocarbon zones. Hunter Gates Operations Engineer I M & S Pads I Prudhoe Bay West Hilcorp Alaska, LLC Email: hunter.gates@hilcorp.com Cell: (215) 498-7274 Office: (907) 777-8326 From: Joseph Syzdek <Joseph.Syzdek@hilcorp.com> Sent: Monday, May 19, 2025 1:51 PM To: Hunter Gates <Hunter.Gates@hilcorp.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: RE: [EXTERNAL] PBU S-17C Frac Sundry (325-271): Question Andy, The Ugnu and Scharder are oil bearing sands in this location. The Ugnu has some contacts in some of the subzones (see 5,022’ MD) along with a few suspected coal beds. The coal beds are easily seen on offsets that have triple combo logs and are typically above the L series sands in the UG series. You are correct with water bearing sands above the Ugnu in Sv sands, which is completed in S-400A. Let me know if I can provide more details/information on this. we are requesting the variance to this rule due to the fact that our cement does not extend up to the hydrocarbon bearing Schrader Bluff and Ugnu Formations 2 Thanks, Joseph Syzdek Geologist | PBW – Aurora/Borealis/EWE Hilcorp Energy Company O: (907) 564-4419 | C: (224) 545-0022 | Joseph.Syzdek@hilcorp.com From: Hunter Gates <Hunter.Gates@hilcorp.com> Sent: Friday, May 16, 2025 3:39 PM To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Joseph Syzdek <Joseph.Syzdek@hilcorp.com> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: Re: [EXTERNAL] PBU S-17C Frac Sundry (325-271): Question The Ugnu should be the shallowest hydrocarbon bearing zone. Looping in my geologist to provide more information. Get Outlook for iOS From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Friday, May 16, 2025 3:35:53 PM To: Hunter Gates <hunter.gates@hilcorp.com> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: Re: [EXTERNAL] PBU S-17C Frac Sundry (325-271): Question Hunter, What is the shallowest hydrocarbon zone in the well? I'm trying to understand if there are any oil-filled sands from the Ungu ~3,650' MD down to ~3,900' MD, and various other depths such as ~4,300' to 5,050' MD. Are some of these freshwater sands, coals, etc? Thanks, Andy From: Hunter Gates <hunter.gates@hilcorp.com> Sent: Friday, May 16, 2025 11:17 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: RE: [EXTERNAL] PBU S-17C Frac Sundry (325-271): Question Morning Andy, Schrader Base = 5,650’ MD CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 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. 3 Schrader Top = 5,197’ MD Ugnu Top = 3,638’ MD Hunter Gates Operations Engineer I M & S Pads I Prudhoe Bay West Hilcorp Alaska, LLC Email: hunter.gates@hilcorp.com Cell: (215) 498-7274 Office: (907) 777-8326 From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Friday, May 16, 2025 8:40 AM To: Hunter Gates <hunter.gates@hilcorp.com> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: [EXTERNAL] PBU S-17C Frac Sundry (325-271): Question Hunter, I'm completing my review of the PBU S-17C frac sundry and have a question about some of the shallow geology. x What is the shallowest hydrocarbon zone in the S-17C well? I know that there are nearby water supply wells in the Prince Creek/Ugnu (PBU S-400, S-400A, and S-401), but would like to know your evaluation of the Ugnu and Schrader intervals. 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. 4 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 S-17C (PTD No. 202-007; Sundry No. 325-271) Paragraph Sub-Paragraph Section Complete? AOGCC Page 1 May 20, 2025 (a) Application for Sundry Approval (a)(1) Affidavit Provided with application. A.Dewhurst 15MAY25 (a)(2) Plat Provided with application. A.Dewhurst 15MAY25 (a)(2)(A) Well location Provided with application. Well lies in Section 35 of T12N, R12E, UM. A.Dewhurst 15MAY25 (a)(2)(B) Each water well within ½ mile None. There are no wells are used for drinking water purposes are known to lie within ½ mile of the surface location of PBU S-17C. There are no subsurface water rights or temporary subsurface water rights within 4.8 miles of the surface location of PBU S-17C. A.Dewhurst 15MAY25 (a)(2)(C) Identify all well types within ½ mile Provided with application. Hilcorp has identified 208 wells within ½ mile. A.Dewhurst 15MAY25 (a)(3) Freshwater aquifers: geological name; measured and true vertical depth None. This well lies within the Western Operating Area the of Prudhoe Bay Unit which is exempted under AEO 1. A.Dewhurst 15MAY25 (a)(4) Baseline water sampling plan None required. A.Dewhurst 15MAY25 (a)(5) Casing and cementing information Provided with application. Schematic attached. Multiple sidetracks and plug backs. CDW 05/13/2025 (a)(6) Casing and cementing operation assessment 13-3/8” casing cemented to surface required a top job. 9-5/8” casing cemented to program without losses. Post workover/pulled tubing 9-5/8” was logged (May 2023) with CBL showing TOC of 6050 ft. On file w AOGCC. S-17 7” liner run with bad cement job, liner wouldn’t test, redo cement job for a good test. S-17A Sidetracked out of 9-5/8” casing. Couple of sidetracks which were all plugged back to S-17C @ 9400 ft. No issues with cement for the upcoming stimulation. Top Kuparuk C 7177 ft MD at existing perf. CDW 05/13/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU S-17C (PTD No. 202-007; Sundry No. 325-271) Paragraph Sub-Paragraph Section Complete? AOGCC Page 2 May 20, 2025 (a)(6)(A) Casing cemented below lowermost freshwater aquifer and conforms to 20 AAC 25.030 Only exempt freshwater aquifers present. (See Section (a)(3), above.) A.Dewhurst 15MAY25 (a)(6)( B) Each hydrocarbon zone is isolated No. Hilcorp has identified shallow hydrocarbon zones in the Schrader Bluff and Ugnu that were not isolated during the primary cement job of the parent wellbore 9-5/8” casing. Hilcorp has requested a variance to this requirement. I recommend granting the variance as these zones are very well isolated from the proposed frac. The Kuparuk hydrocarbon zone is isolated by the parent wellbore 9-5/8” intermediate casing cement. TOC was measured by CBL at 6,050’ MD (over 1,000’ TVD above the Kuparuk C). The Ivishak hydrocarbon zone was also abandoned and is considered properly isolated. Variance request received and approved. 05/20/2025 A.Dewhurst 20MAY25/ CDW 05/20/2025 (a)(7) Pressure test: information and pressure-test plans for casing and tubing installed in well Provided with application. 3500 psi MITIA planned, 3500 psi MITT plan. CDW 05/14/2025 (a)(8) Pressure ratings and schematics: wellbore, wellhead, BOPE, treating head Provided with application. 5K psi wellhead (no tree saver) max. frac. Pressure 4500 psi. Pump knock out 4050 and GORV 4275 psi, 4500 psi N2 popoff, lines test 5500 psi. CDW 05/14/2025 (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 Upper confining zones: 92’ TVT of shales of the HRZ and Kalubik with fracture gradient of 0.7 psi/ft. Fracturing Zone: 175’ TVT of Kuparuk sandstones and siltstones with a fracture gradient of 0.62 psi/ft to 0.66 psi/ft. Lower confining zone: 730’ TVT of Miluveach shales with a fracture gradient of 0.7 psi/ft. A.Dewhurst 16MAY25 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU S-17C (PTD No. 202-007; Sundry No. 325-271) Paragraph Sub-Paragraph Section Complete? AOGCC Page 3 May 20, 2025 (a)(9)(E) Fracture pressure for each zone MD and TVD depths provided in application. (a)(10) Location, orientation, report on mechanical condition of each well that 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 There are 46 wells (and sidetracks and plugbacks) within ½ mile of PBU S-17C that penetrate the confining intervals. Hilcorp indicated that there were no wells with the Kuparuk C (fracturing interval) open (not isolated). AOGCC has not evaluated these wells, but accepts the summaries provided in the application. A.Dewhurst 16MAY25/ CDW 05/14/2025 (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 Hilcorp has identified 5 faults within the ½ mile of the proposed frac. Detailed descriptions for each are provided in the application. The closest fault is 450’ away. The anticipated fracture half-length is 200’. So, it is unlikely that any faults will interfere with containment of the 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 of the faults are included in the application. A.Dewhurst 16MAY25 (a)(12) Proposed program for fracturing operation Provided with application. CDW 05/14/2025 (a)(12)(A) Estimated volume Provided with application. 1535 bbl total dirty vol. 197K lb total proppant CDW 05/14/2025 (a)(12)(B) Additives: names, purposes, concentrations Provided with application. CDW 05/14/2025 (a)(12)(C) Chemical name and CAS number of each Provided with application. Schlumberger disclosure provided. CDW 05/14/2025 (a)(12)(D) Inert substances, weight or volume of each Provided with application. CDW 05/14/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU S-17C (PTD No. 202-007; Sundry No. 325-271) Paragraph Sub-Paragraph Section Complete? AOGCC Page 4 May 20, 2025 (a)(12)(E) Maximum treating pressure with supporting info to determine appropriateness for program Simulation shows max surface pressure 3090 psi. Max. 4500 psi allowable treating pressure. Max pressure is 4050 psi to 4275 psi to Pump shutdown, N2 popoff 4500 psi. With 3025 psi back pressure IA (IA popoff set 3325 psi), max tubing differential should be 1475 psi. CDW 05/14/2025 (a)(12)(F) Fractures – height, length, MD and TVD to top, description of fracturing model Provided with application. The anticipated half-length of the induced fractures is 200’ according to the Operator’s computer simulation. Computer simulation indicates the anticipated height of the induced fractures will be 115’ (top of about -6,685’ TVDSS and base of about -6,800’ TVDSS). A.Dewhurst 16MAY25 (a)(13) Proposed program for post-fracturing well cleanup and fluid recovery Well cleanout and flowback procedure provided with application. No disposal identified but Hilcorp has options. CDW 05/14/2025 (b)Testing of casing or intermediate casing Tested >110% of max anticipated pressure 3025 psi back pressure, plan to test to 3500 psi, popoff set as 3325 psi CDW 05/14/2025 (c) Fracturing string (c)(1) Packer >100’ below TOC of production or intermediate casing 4.5” tubing is anchored with a packer set at approx. 7039 ft with frac 1 top of 7177 ft. plugs set back to 9400 ft. 9-5/8” casing was logged with CBL showing TOC of 6050 ft which puts packer 989 ft below TOC so > 100 ft. No issues with cement for the upcoming stimulation. Top Kuparuk C 7177 ft MD at existing perf. CDW 05/14/2025 (c)(2) Tested >110% of max anticipated pressure differential Tubing test of 3500 psi. Max pressure differential is estimated as 1475 psi (4500 with 3025 psi backpressure) so test of 3500 psi satisfies 110% CDW 05/14/2025 (d) Pressure relief valve Line pressure <= test pressure, remotely controlled shut-in device 5500 psi line pressure test, pump knock out 4050-4275 psi with max. global kickout 4500 psi. IA PRV set as 3325 psi. CDW 05/14/2025 (e) Confinement Frac fluids confined to approved formations Provided with application. CDW 05/14/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist PBU S-17C (PTD No. 202-007; Sundry No. 325-271) Paragraph Sub-Paragraph Section Complete? AOGCC Page 5 May 20, 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 05/14/2025 (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 05/14/2025 (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 16MAY25 (k) Confidential information Clearly marked and specific facts supporting nondisclosure Non-confidential well. A.Dewhurst 16MAY25 (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. Nolan Vlahovich Hilcorp Alaska, LLC Geo Tech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 07/19/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230719 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# PBU 07-20C 50029209020300 218036 6/8/2023 HALLIBURTON RBT PBU 13-19 50029206900000 181180 6/8/232 HALLIBURTON WFL-RMT3D PBU 18-29C 50029223160300 209055 6/13/2023 HALLIBURTON CAST-CBL PBU L-213 50029233080000 206053 6/12/2023 HALLIBURTON IPROF PBU M-205 50029237330000 222127 6/6/2023 HALLIBURTON IPROF PBU S-17c 50029211480300 202007 5/29/2023 HALLIBURTON RBT Please include current contact information if different from above. T37859 T37860 T37861 T37862 T37863 T37864PBU S-17c 50029211480300 202007 5/29/2023 HALLIBURTON RBT Kayla Junke Digitally signed by Kayla Junke Date: 2023.07.19 13:22:09 -08'00' 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 S-17C Recomplete to Aurora Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 202-007 50-029-21148-03-00 10658 Conductor Surface Intermediate Liner Liner 8891 80 2634 8274 1415 2561 7990 20" x 30" 13-3/8" 9-5/8" 7" 3-1/2" x 3-3/16" x 2-7/8" 7491 30 - 110 29 - 2663 26 - 8300 8035 - 9450 8049 - 10610 29 - 109 29 - 2663 26 - 7761 7530 - 8728 7542 - 8899 None 2670 4760 5410 10530 7990, 9400, 9440 5380 6870 7240 10160 7179 - 7247 4-1/2" 12.6# 13Cr80 24 - 7119, 7954 - 8084 6753 - 6816 Structural 4-1/2" HES TNT Packer 7039, 6626 7039, 8002 6626, 7502 Torin Roschinger Area Operations Manager Brodie Wages David.Wages@hilcorp.com 907.564.5006 PRUDHOE BAY, Prudhoe Oil / Aurora Oil Pool 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 0028257, 0028258 24 - 6699, 7459 - 7573 9400 - 9440' in Liner Dump Bail 10-bbls 15.8-ppg Class G Cement 58 Well Not Online 1240 2783 1760 0 252 0 322-717, 323-220 13b. Pools active after work:Aurora Oil Pool 4-1/2" Otis HVT Packer 8002, 7502 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 By Grace Christianson at 10:44 am, Jun 19, 2023 Digitally signed by Torin Roschinger (4662) DN: cn=Torin Roschinger (4662), ou=Users Date: 2023.06.16 18:15:29 -08'00' Torin Roschinger (4662) DSR-6/'21/23 RBDMS JSB 120723 WCB 3-11-2024 ACTIVITY DATE SUMMARY 1/7/2023 T/I/O = 710/480/10. Temp = SI. Bleed IAP & OAP to 0 psi (pre RWO). No AL or flowline. IA FL @ 130' ( 7 bbls). TP & IAP tracking each other pound for pound. Bled TP/IAP from IA to BT from 480 psi to 300 psi in 2 hrs 30 min (gas/fluid, 1 bbl). IA FL @ surface. OAP decreased 10 psi during bleed. Monitored for 30 min. WHPs & IA FL unchanged. Final WHPs = 300/300/VAC. SV, WV, SSV = C. MV = O. IA, OA = OTG. 17:30 1/8/2023 T/I/O = 310/310/VAC. Temp = SI. Bleed IAP & OAP to 0 psi (pre RWO). No AL or flowline. IA FL near surface. Bled IAP to BT from 310 psi to 100 psi in 8 hrs (gas/fluid, 1 bbl). During bleed TP decreased 120 psi. IA FL @ surface. Monitored for 30 min. IAP increased 10 psi. IA FL unchanged. Final WHPs = 190/110/VAC. SV, WV, SSV = C. MV = O. IA, OA = OTG. 17:30 1/9/2023 T/I/O = 200/120/0. Temp = SI. Bleed IAP & OAP to 0 psi (pre RWO). No AL or flowline. IA FL near surface. Bled TP/IAP thru the IA to BT from 200 psi/120 psi to 4 psi/0 psi in 10 hrs (gas/fluid, 1 bbl). IA FL near surface. Monitored for 30 min. IAP increased 5 psi. TP increased 6 psi. IA FL unchanged. Final WHPs = 10/10/+0. SV, WV, SSV = C. MV = O. IA, OA = OTG. 17:30 1/10/2023 T/I/O = 10/10/0. Temp = SI. Bleed IAP & OAP to 0 psi (pre RWO). No AL or flowline. IA FL near surface. Bled TP/IAP thru the IA to BT from 10 psi/10 psi to 0 psi/0 psi in 5 hrs. IA FL near surface. Monitored for 30 min. IAP increased 1 psi. IA FL unchanged. Final WHPs = 0/0+/0. SV, WV, SSV = C. MV = O. IA, OA = OTG. 11:30 1/16/2023 T/I/O = SI/0/0, Pre-RWO, PPPOT-T (PASS) Functioned tubing hager LDS, 3 LDS stuck IN, 1 LDS stuck OUT, all other LDS functioned smoothly. Stung into THA test fitting, 0 psi, unable to back out SBS, removed 1" NPT x alemite test fitting, no buried check underneath, installed new 1" NPT x alemite test fitting. Pressured up on THA test void to 500 psi for 10 mins, no loss, pressure up to 5000 psi, lost 100 psi first 15 mins, lost 0 psi second 15 mins, PPPOT-T (PASS). Bleed all test psi and drain hyd fluid, RDMO. 1/18/2023 On the tubing head, free two of three stuck LDS, broke the third LDS just behind the flats at 3:30 position. Was able to rotate the LDS at 7:30 position but would not rotate all the way in it was left in the out position. 1/19/2023 T/I/O = SI/0/0 PPPOT-IC (passed). Open split bleeder screw 0 psi on void. Remove 1" bull plug, rig up internal check bleeder tool, 0 psi behind internal check, Remove internal check & instal test fitting. Rig up test equipment, pump hydraulic fluid across void. Test at 3500 psi. Test Passed. Did not function LDS. 4/11/2023 ***WELL S/I ON ARRIVAL*** SET 4 1/2" WHIDDON @ 7,990' MD PULL STA.# 1, T-2 S/O @ 7,961' MD ***CONTINUE 4/12/23*** 4/12/2023 T/I/O=205/258/0 (RWO CAPITAL) Pumped 5 bbls 60/40 spear down TBG. Circ-Out Down TBG up IA over to adjacent FL. Pumped 365 bbls 2%KCL. Pumped 5 bbls 60/40 spacer. Pumped 185 bbls diesel down TBG. FP'd hardline w/ 2 bbls DSL. U- Tube TBG/IA. *** Job continued to 4-13-2023 *** Daily Report of Well Operations PBU S-17C Daily Report of Well Operations PBU S-17C 4/12/2023 ***CONTINUE FROM 4/11/23*** PULL STA. 2 RM-DGLV @ 7,895' MD PULL STA. 3, 4 & 5 RM-LGLV'S SET RM-DGLV'S IN STA. 2, 3, 4 & 5 CIRC OUT W/ LRS, PUMP FREEZE PROTECT ON TUBING & IA ***CONTINUE 4/13/23*** 4/13/2023 ***CONTINUE FROM 4/12/23*** SET RM-DGLV IN STA.# 1 @ 7,961' MD ATTEMPT MIT-IA W/ LRS (TUBING TRACKING) RAN 4 1/2" D&D HOLEFINDER TO BELOW ST #1 @ 6,960' SLM (tbg holds 1,000psi, looks like a 1 way leak from ia to tbg) PERFORMED A PASSING CMIT TxIA TO 3,500PSI PULL WHIDDON CATCHER @ 7,969' SLM (empty) EQUALIZE 4 1/2" XX PLUG @ 7,990' MD PULL 4 1/2" XX PLUG @ 7,990' MD (missing packing) RUN 4 1/2" BLB, 3 1/2" BLB, 2.50" GAUGE RING (no recovery) CIBP DRIFT W/ 2.62" CENT. 1 3/4" SAMPLE BAILER, TAG XO @ 9,548' MD (9,540' SLM) ***CONTINUE ON 4/14/23*** 4/13/2023 *** Job continued from 4-12-2023 *** Asist SL. U-Tube TxIA. MIT-IA . Pumped .5 bbls to pressure TBG to 2000 psi. Pumped 6.4 bbls DSL into IA, TBG and IA showing communication. Bleed TBG to 1900 psi while IA had 2550 psi. IA immediatly started to fall, TBG and IA stabalized at 2308/2287 psi. Bled TBG and IA to 200 psi. Bled back 5 bbls. SL in control of well upon departure. FWHP's = 203/178/1 4/14/2023 ***CONTINUE FROM 4/13/23*** CALIPER TUBING FROM DEPLOYMENT SLEEVE TO SURFACE (GOOD DATA) ***WELL LEFT S/I, WALKED DOWN LOCATION W/ PAD OP*** 4/16/2023 ***ARRIVE LOCATION S-17 BEGIN RU***JOB SCOPE (SET NS EXTRA RANGE CIBP, DUMP 10 GALLONS OF 15.8 PPG CEMENT SLURRY) RIG UP YJ ELINE. PT PCE 300 PSI LOW /3000 PSI HIGH RUN #1 RIH W/ 1 11/16 WT BAR X 2, 1 11/16 CCL, MSST W/ PLUG, SET NS CIBP@ 9440'. CCL TO MID ELEMENT =10.4', CCL STOP DEPTH 9429.6' CCL LOG CORRELATED TO TBG TALLY DATED 2/26/2002 THUNDERBIRD PT PLUG TO 500 PSI. HOLD FOR 5 MIN. GOOD TEST RUN #2 RIH W/ 1 11/16" CCL, 2' SWIVEL, 30' X2.5'' EMPTY BAILER TO DRIFT AND TAG PLUG A 9440'. CCL TO BTM OF DUMP BAILER = 32'. RUN #3 RIH W/ 1 11/16" CCL, 2' SWIVEL, 2.5" X 30' BAILER W/ 5 GALLONS OF 15.8 PPG CEMENT SLURRY RUN #4 RIH W/ 1 11/16" CCL, 2' SWIVEL, 2.5" X 30' BAILER W/ 5 GALLONS 15.8 PPG CEMENT SLURRY ESTIMATE TOC @ 9410' JOB COMPLETE *** WELL S/I ON DEPARTURE*** 4/16/2023 T/I/O=0/0/0 ASSIST E-LINE Pumped 6 BBLS crude to pressure test plug, Bled well to 60 PSI. FWHP=60/0/0 The estimated TOC is 30-ft above the top of the plug, meeting the requirements of AAC 25.112(c)(E). -WCB RUN #4 RIH W / 1 11/16" CCL, 2' SWIVEL, 2.5" X 30' BAILER W / 5 GALLONS 15.8 PPG CEMENT SLURRY THUNDERBIRD PT PLUG TO 500 PSI. HOLD FOR 5 MIN. GOOD TEST SET NS CIBP@ 9440'. RUN #3 RIH W/ 1 11/16" CCL, 2' SWIVEL, 2.5" X 30' BAILER W / 5 GALLONS OF 15.8 PPG CEMENT SLURRY ESTIMATE TOC @ 9410' Daily Report of Well Operations PBU S-17C 4/18/2023 ***WELL S/I ON ARRIVAL*** TAG TOC @ 9,400' MD (9,387' SLM, 13' CORRECTION) RECOVERED 2 CUPS OF CEMENT PERFORM 2 FAILING MIT-T'S WITH THUNDERBIRD PERFORM PASSING COMBO CMIT T X IA 2500 PSI, W/ THUNDERBIRD ***CONTINUE 4/19/23*** 4/18/2023 T/I/O=0/0/0 (Assist Slickline) TFS U-3, Pumped 28 bbls of DSL assisting SL. MIT-T to target pressure of 2500 psi ***Failed***. CMIT-T/IA to target pressure of 2500 psi ***PASSED*** @ TBG=2682 psi, IA=2696 psi. 1st 15 min. TBG/IA lost (48/43) psi 2nd 15 min. TBG/IA lost (23/20) psi Total loss of TBG/IA in 30 min. test was (71/63) psi ***Job Cotinued on 4-19-23*** 4/19/2023 ***CONTINUE FROM 4/18/23*** BLEED TUBING & IA DOWN W/ THUNDERBIRD RIG DOWN POLLARD 59 ***WELL LEFT S/I*** 4/19/2023 ***Job Continued from 4-18-23*** (Assist Slickline) TFS U-3, Continue with bleed down of TBG and IA and then Rig down. 4/20/2023 T/I/O= 90/30/0. LRS 72 AOGCC (Kam St John) CMIT-TxIA to 2500 psi (2750 psi Max Applied Pressure). PASSED on the second attempt at 2708 psi. T/IA lost 20/19 psi during the first 15 minutes and 17/18 psi during the second 15 minutes. T/IA lost 37/37 psi during the 30 minute test. Pumped 9.5 bbls of 90*F diesel to achieve test pressure. Bled back 9 bbls to Final T/I/O= 90/80/0. 4/20/2023 ***WELL S/I ON ARRIVAL*** (rwo capital) PERFORMED STATE WITNESSED TAG TOC @ 9378' SLM / 9400' MD w/ 2.5" SAMPLE BAILER (cement in bailer) LRS PERFORMED STATE WITNESSED CMIT-TxIA **PASS** SET 3.81" PX PLUG w/ FILL EXT IN X NIP @ 7990' MD DUMP BAIL ~5 GALLONS SAND ON PX PLUG AT 7990' MD ***CONTINUE ON 4/21/23 WSR*** 4/21/2023 ***CONTINUED FROM 4/20/23 WSR*** (RWO Capital) DUMP BAIL ~7.5 GAL OF SAND (~12.5 gal total) ON PX PLUG AT 7,990' MD (~20' sand above plug) ***WELL S/I ON DEPARTURE*** 5/8/2023 ***WELL S/I ON ARRIVAL*** (TAG TOP OF SAND PLUG*** RIG UP YJ ELINE. PT PCE 300 PSI LOW /3000 PSI HIGH RIH W/CH/X2 1 11/16'' WB/ 2.75'' CCL TO TAG TOP OF SAND AT 7970' MD CCL LOG CORRELATED TO TBG TALLY DATED 10/14/91 JOB COMPLETE ***WELL S/I ON DEPARTURE*** The TOC tag of 9400' is 15-ft more than the minimum that AAC 25.1129(c)(E) requires. -WCBDUMP BAIL ~5 GALLONS SAND ON PX PLUG AT 7990' MD SET 3.81" PX PLUG w/ FILL EXT IN X NIP @ 7990' MD @ TAG TOC @ 9,400' MD RIH W/CH/X2 1 11/16'' WB/ 2.75'' CCL TO TAG TOP OF SAND AT 7970' MD () PERFORMED STATE WITNESSED TAG TOC @ 9378' SLM / 9400' MD w/ 2.5" SAMPLE BAILER (cement in bailer)() LRS PERFORMED STATE WITNESSED CMIT-TxIA **PASS** () DUMP BAIL ~7.5 GAL OF SAND (~12.5 gal total) ON PX PLUG AT 7,990' MD Daily Report of Well Operations PBU S-17C 5/12/2023 ***WELL S/I ON ARRIVAL*** CONTACT DSO ARRIVE TO LOCATION INTIATE PERMIT WITH DSO BEGIN R/U GAIN CONTROL 9/32" W/ CHD, WELL TECH MECHANICAL CUTTER S/O PT PCE 300 LOW 3000 HIGH PSI OPEN SWAB RIH W/ CHD, WELL TECH MECHANICAL CUTTER RUN CORRELATION PASS CCL DEPTH 7935.7', CCL TO CUTTER 18.3' CUTTER DEPTH 7954' BEGIN CUT OF TUBING WITH WELL TECH MECHANICAL CUTTER PRE CUT=TIO=200/0/0 POST CUT=300/350/0 WT PRE CUT= 1300 LBS POST=1145 LBS POOH, LAYDOWN TOOLS WELL TECH HAND DID MEASUREMENT I GOT CONFIRMATION THAT CUT WAS GOOD BEGIN R/D CONTACT DSO TO CLOSEOUT PERMIT ***WELL S/I UPON DEPARTURE*** 5/13/2023 T/I/O=120/100/0 (CMIT TxIA) to 2750 max PSI 2500 Target, Pumped 7 BBLS DSL to Reach Max PSI of 2753 for a CMIT-TxIA ***PASS***, 1ST 15 min TBG/IA lost (44/44)PSI, 2ND 15 min TBG/IA lost (21/21)PSI, Total loss of 65 PSI,***PASS*** FWHP=104/88/0 MV= Open SV, SSV= Closed IA, OA= OTG 5/15/2023 T/I/O=160/160/0 Circ Out Well (Pre RWO) Pump down TBG taking returns up IA to S- 135 FL w/ 10 bbls 60/40, 103 bbls Deep clean. Flush w/ 624 bbls 1% KCL. Freeze protect IA w/ 172 bbls Diesel, U-Tube FP into TBG. FWHP=0/0/0 5/23/2023 Dope & set 4" H TWC, profile felt scaley, had to work it in & out to make it up completely into profile, pull it back out, inspect threads, Looks perfect, clean TWC OD, re-dope, RIH, made up perfectly 6-1/2 LH, test TWC through tree to make sure H profile is sealed, 5000 psi/30 min, 100 psi loss, bleed off test psi., check void & (2) control lines for psi., bleed off, N/D tree, grind nose off of one LDS that was broken on outside, one other LDS was in the out position when I showed up, tried to function, seized up, but nose is clear of bowl ID, function all other LDS one at a time, re-torque each to 500 ft/lbs., M/U 4-1/2" TDS test sub to hanger lift threads 7-1/2 RH handy, B/O test sub, clean void & ring groove, install new BX-160, RDMO 5/24/2023 T/I/O=0/0/0 Assisted Vault with setting 4" "H" CIW TWC. Tested TWC through tree, 5 min... Pass. Removed tree and THA. Installed new ring gasket and BOP stack. Torqued to specs. Ensured shooting flange was secure on top with jewelry. Disconnected well S-202 and removed tree work platofrms for clearance issues.Removed well house and tree work platforms on S-135 for clearance issues. FWP's TWC/0/0. 5/27/2023 TB-1 RWO Job Scope: Recomplete from Ivishak to Kuparuk Rig down @ S-32 and move to S-17. Spot Rig in place. Adjust Pits and choke house for tight spacing. Slip & Cut Drill line. Transfer KCL into URT's. Cont RU process. RU test equipment and start filling stack for BOP shell test. ***Cont on WSR 5/28/31*** 5/28/2023 Pull 4" CIW H TWC w/ T-bar, make up 4-1/2" TDS landing joint 8-1/2 RH, mark landing joint @ top of flange of BOP, back out lock down screws (one LDS was broken & nose was ground off upon instalation of BOP on 5/23/23, and a second LDS was seized up in the out, clear bowl position), pull hanger, measure landing joint mark to upper lock down screw ramp on tubing hanger (12.92'), lay down scrap hanger, RDMO. BEGIN CUT OF TUBING WITH WELL TECH MECHANICAL CUTTER PRE CUT=TIO=200/0/0 POST CUT=300/350/0 WT PRE CUT= 1300 LBS POST=1145 LBS POOH, LAYDOWN TOOLS WELL TECH HAND DID MEASUREMENT I GOT CONFIRMATION THAT CUT WAS GOOD gj back out lock down screws (one LDS wasgj @ g ( broken & nose was ground off upon instalation of BOP on 5/23/23, and a second LDS g was seized up in the out, clear bowl position), pull hanger, TO CUTTER 18.3' CUTTER DEPTH 7954' Daily Report of Well Operations PBU S-17C 5/28/2023 TB-1 RWO Job Scope: Recomplete from Ivishak to Kuparuk BOP shell test. Test BOPE to Sundry. 250 low 3000 high. 4-1/2" Test joint. No failures AOGCC witness waived by Adam Earl. Pull TWC. Circulate.Rock out the diesel FP, 170 bbls. MU landing joint to the hanger. BOLDS. Pull hanger free at 95K, String wt 100K. Start POOH with 4-1/25" TDS tuning and dual control line. Pipe skate broke down, rig down wangler and send to town. Continue to pull completion and laydown tubing w/ tugger. ***Cont on WSR 5/29/23*** 5/29/2023 TB-1 RWO Job Scope: Recomplete from Ivishak to Kuparuk Continue pulling tbg @ Jt #47 of 201 and spooling control lines. Laying down tbg joints w/ tugger while laydown trailer is being repaired. Recovered All clamps and bands. Cont laying down 4-1/2" tubing to the ground w/ no skate. Total 202 joints and a cut joint. Cut joint 2.48' All Clamps and band recovered from Tally. Clean & clear rig floor. RU HES Eline and run CBL from 7995' to surface. TOC @ 2200'. Send to log to OE/AOGCC. ***Cont on WSR 5/30/23*** 5/29/2023 ***T-BIRD RIG ASSIST*** (RCBL) MIRU HES E-LINE RUN RADIAL BOND TOOL FROM 8007' TO SURFACE ESTIMATED TOC AT 2200' ***JOB CONTINUES ON 30MAY23 WSR*** 5/30/2023 TB-1 RWO Job Scope: Recomplete from Ivishak to Kuparuk OE recieved AOGCC approval of to proceed w/ completion. Unable to use ASR lay- down trailer. Call out NES welder to build beaver slide w/ used 4-1/2" tbg joints. E-line set 8.24" OD, 3.958" ID scoop guide w/ 5" GS profile (4" ID) @ 7933' WLM. Ran 3.5" centralizer and drift through scoop guide w/no issues, POOH, RD HES Eline. Fabricate beaver slide to run completion. Install beaver slide. Line up completion running order to Approved Tally. PJSM for Running completion with modified Beaver slide. RIH w/ 4-1/2" 12.6#, 13Cr Vam Top Completion per Tally. Torque Turn service by Thunderbird. ........Job Continued on 5/31/23 WSR 5/30/2023 ***JOB CONTINUES FROM 29MAY23 WSR*** (EL SET SCOOP GUIDE) RIH WITH E-LINE AND SET SET 6' SCOOP ENTRY GUIDE AT 7932' DRIFT AND TAG 3.5"CENT TO 7964' RDMO E-LINE ***READY FOR T-BIRD*** 5/31/2023 RWO Completion, T/I/O = 0/0/0 MU 13-1/2" x 4-1/2" TC-II McEvoy SSH tubing hanger in string, land hanger, verify landed through IA, RILDS, torque to 450, tighten gland nuts, stdby for packer set/test. 5/31/2023 ***ASSIST THUNDERBIRD RIG*** TAG BALL N ROD IN RHC @ 7,071' SLM W/ 3.6" BELL GUIDE & 2.3" LIB RIG ABLE TO PRESSURE UP TBG ***CONT WSR ON 06/01/2023*** gj gg Start POOH with 4-1/25" TDS tuning and dual control line. Pipe skategg broke down, rig down wangler and send to town. Continue to pull completion and g laydown tubing w/ tugger j y RU HES Eline and run CBL from 7995' to surface. TOC @ 2200'. Sendg to log to OE/AOGCC.g ***Cont on WSR 5/30/ gyg RIH w/ 4-1/2" 12.6#, 13Cr Vam Top Completion per Tally. TAG BALL N ROD IN RHC @ 7,071' SLM W / 3.6" BELL GUIDE & 2.3" LIB@ RIG ABLE TO PRESSURE UP TBG ( RIH WITH E-LINE AND SET SET 6' SCOOP ENTRY GUIDE AT 7932' Continue pulling tbg @ Jt #47 of 201 and spooling control lines. Laying down tbg gg@ g yg g joints w/ tugger while laydown trailer is being repaired. Recovered All clamps andjggyg bands. Cont laying down 4-1/2" tubing to the ground w/ no skate. Total 202 joints and a cut joint. OE recieved AOGCC approval of to proceed w/ completion MIRU HES E-LINE RUN RADIAL BOND TOOL FROM 8007' TO SURFACE ESTIMATED TOC AT 2200' Daily Report of Well Operations PBU S-17C 5/31/2023 TB-1 RWO Job Scope: Recomplete from Ivishak to Kuparuk Continue RIH w/ 4-1/2" 12.6#, 13Cr Vam Top Completion as per run tally. TTS by Thunderbird. M/U Hanger and land completion PUW 87k, SOW 74k. RILDS. Pumped 15 bbls 1% KCL w/ 1% EPT-3744. Displace w/ 110.5 bbls 1% KCL (Tbg x IA). Dropped Ball & Rod (6.3' OAL, 1-3/8" FN). Pressure up tubing to set packer, IA tracking. Reverse circulate 5 bbls to flush RHCM seat and attempt to pressure up tubing, IA tracking. Ball & Rod doesn't appear to be seated. MIRU HES Slickline. Drifted w/3.60" bellguide w/2.5" LIB inside. Tagged 7,071' slm, jarred down once, POOH. LIB shows double impression of 1-3/8" FN cap indicating likely tagged ball & rod higher in completion then a second time on seat. MIT-T to 3650 psi for 30 minutes charted, good indication of packer set. ........Job Continued on 6/1/23 WSR 6/1/2023 ***CONT WSR FROM 05/31/2023*** HES 759 R/D ***WELL TURNED BACK OVER TO RIG*** 6/1/2023 TB-1 RWO Job Scope: Recomplete from Ivishak to Kuparuk MIT-T to 3700 psi for 30 minutes charted. Bleed tubing to 2000 psi. MIT-IA to 3500 psi for 30 minutes charted. Bleed tubing and shear DCR valve in GLM # 5. Pumped 172 bbls of diesel down IA. U-tube diesel IA x Tbg. Set TWC. RDMO TB-1. 7-1/2 hr delay due to crew change w/ bridge outage. Continue rigging down pits, choke house, koomey, pump house, rig and support equipment. ........RWO Program Completed. 6/1/2023 RWO, T/I/O = 0/0/0 Set 4" H TWCV #712 with dry rod. Standby for RDMO. 6/3/2023 T/I/O = TWC/0/0. Post T-Bird. Removed BOPs. Intalled THA. THA PT by Vault Tech Josh Sandau, Passed. Installed Tree, PT Low (350 psi) passed. PT High (500 psi) Passed. Pulled TWC @ 125" FWP = 0/0/0 6/3/2023 RWO Completion T/I/O = TWC/0/0, PPPOT-T (PASS) Assist WS to remove BOPs and install THA and tree. Pressure test THA to 500 psi low, no loss, pressure test to 5000 psi, lost 100 psi first 15 mins, lost 0 psi second 15 mins, good tests. Bleed all test pressure. WS pressure tested tree. RDMO 6/9/2023 ***WELL S/I ON ARRIVAL*** PULLED BALL n ROD FROM RHC @ 7,063' SLM PULLED STA. # 5 RK-CIRC VLV 3,106 SLM PULLED STA. # 3 RK-DGLV FROM 5,784' SLM NOTICED WE LOST 2.60" ROLLER STEM WHEEL RATTLE MANDRELS DOWN TO RHCM @ 7,063' SLM W/ KJ, KJ, 2.25" CENT, 4- 1/2" BRUSH RAN KJ,KJ, 2.25" MAGNET TO RHCM @ 7,063' SLM (no recovery) ***CONTINUE ON 6-10-23 WSR*** 6/10/2023 ***CONTINUE ON FROM 6-09-23 WSR*** MAKE VARIOUS DIFFERENT RUNS TRYIING TO FISH 2.60" ROLLER STEM WHEEL STAND BY FOR HIGH WINDS ***CONTINUE ON 6-11-23 WSR*** (g Dropped Ball & Rod (6.3' OAL, 1-3/8" FN). Pressure up tubing to set packer, IA)()g tracking. Reverse circulate 5 bbls to flush RHCM seat and attempt to pressure up g tubing, IA tracking. Ball & Rod doesn't appear to be seated. MIRU HES Slickline.gg Drifted w/3.60" bellguide w/2.5" LIB inside. Tagged 7,071' slm, jarred down once, g gg j POOH. LIB shows double impression of 1-3/8" FN cap indicating likely tagged ball & gygg rod higher in completion then a second time on seat. MIT-T to 3650 psi for 30g minutes charted, good indication of packer set. PULLED BALL n ROD FROM RHC @ 7,063' SLM Continue RIH w/ 4-1/2" 12.6#, 13Cr Vam Top Completion as per run tally MIT-T to 3700 psi for 30 minutes charted. Bleed tubing to 2000 psi. MIT-IA to 3500 psi for 30 minutes charted. Daily Report of Well Operations PBU S-17C 6/11/2023 ***CONTINUE ON FROM 6-10-23 WSR*** PULL 1-1/2" RK-DMY GLV FROM STA's #4,1 & 2 SET 1-1/2" RK-LGLV (16/64" ports, 1777# tro) IN STA #5 @ 3,114' MD SET 1-1/2" RK-LGLV (16/64" ports, 1767# tro) IN STA #4 @ 4,911' MD SET 1-1/2" RK-LGLV (16/64" ports, 1740# tro) IN STA #3 @ 5,794' MD SET 1-1/2" RK-LGLV (16/64" ports, 1709# tro) IN STA #2 @ 6,448' MD SET 1-1/2" RK-OGLV (24/64" ports) IN STA #1 @ 6,490' MD PULL 4-1/2" RHC FROM X-NIPPLE @ 7,065' MD ***WELL LEFT S/I ON DEPARTURE, PAD OP NOTIFIED ON WELL STATUS*** 6/12/2023 ***WELL S/I ON ARRIVAL*** PRESSURE TEST PCE TO 200#LP-3,000#HP RIH W/ 1-7/16" CHD (1" FN), 1-11/16" GR/CCL, 2-3/4" PERF GUN (LOADED 29' W/ 15 GRAM RAZOR XDP CHARGES, 2-3/4" MAX OD, 38' OAL) CORRELATE LOG TO SLB PPROF DATED 18-JUNE-2002 GUN #1: PERF DEPTH=7,218'-7,247', CCL OFFSET=7.7', CCL STOP DEPTH=7,210.3' GUN #2: PERF DEPTH=7,189'-7,218', CCL OFFSET=7.7', CCL STOP DEPTH=7,181.3' GUN #3: PERF DEPTH=7,179'-7,189', CCL OFFSET=7.7', CCL STOP DEPTH=7,171.3' TREECAP INSTALLED & PRESSURE TESTED ***WELL LEFT S/I*** GUN #3: PERF DEPTH=7,179'-7,189 GUN #1: PERF DEPTH=7,218'-7,247', GUN #2: PERF DEPTH=7,189'-7,218', CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Rixse, Melvin G (OGC) To:Brodie Wages Cc:AOGCC Records (CED sponsored) Subject:20230530 0903 APPROVAL PTD202-007 Sundry 323-220 to proceed sundry work Date:Tuesday, May 30, 2023 9:09:16 AM Brodie, Hilcorp is approved to proceed work on Sundry 323-220 (PTD202-007) per estimated TOC ~6040’ MD from Halliburton Cement Bond Log 29-MAY-2023 @ 20:00. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Brodie Wages <David.Wages@hilcorp.com> Sent: Tuesday, May 30, 2023 12:10 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: Fwd: S-17C CBL Hello Mel, Please see attached the CBL run on S-17. On the log, top of Kuparuk is at 7200’. I’m seeing well over 1000’ of good cement over the Kuparuk interval, please advise if you agree and we will proceed to run the completion. Regards, David Wages Hilcorp - OE C. 713.380.9836 Typed on my phone, please excuse errors. Begin forwarded message: From: PB Wells RWO WSS <PBWellsRWOWSS@hilcorp.com> Date: May 29, 2023 at 11:55:36 PM AKDT To: Brodie Wages <david.wages@hilcorp.com> Subject: S-17C CBL Here’s the LOG. HAL called TOC 2200. Free pipe 4650 – 6000’. Light cement above/below this depth. Arvell The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section:35 Township:12N Range:12E Meridian:Umiat Drilling Rig:n/a Rig Elevation:n/a Total Depth:10658 ft MD Lease No.:ADL0028257 Operator Rep:Suspend:X P&A: Conductor:20" X 30"O.D. Shoe@ 110 Feet Csg Cut@ Feet Surface:13-3/8"O.D. Shoe@ 2663 Feet Csg Cut@ Feet Intermediate:9-5/8"O.D. Shoe@ 8300 Feet Csg Cut@ Feet Liner:7"O.D. Shoe@ 9450 Feet Csg Cut@ Feet Liner:3.5x3.18x2.88 O.D. Shoe@ 10610 Feet Csg Cut@ Feet Tubing:4-1/2 O.D. Tail@ 8084 Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified Tubing Bridge plug 9440 ft 9400 ft 7.2 ppg Wireline tag Initial 15 min 30 min 45 min Result Tubing 2745 2704 2681 2662 IA 2742 2704 2678 2659 OA 1 1 1 1 Initial 15 min 30 min 45 min Result Tubing 2748 2728 2711 IA 2745 2726 2708 OA 1 1 1 Remarks: Attachments: Plug for well repair. Top of cement was tagged at 9400 ft wireline measurement with +22-foot correction. Had really good cement in bailer. Combination MIT TxIA - first test was close but I considered a FAIL. Pumped back up for second try and pressure loss trend was below 2% over 30 min and was trending down - PASS. April 20, 2023 Kam StJohn Well Bore Plug & Abandonment PBU S-17C Hilcorp North Slope LLC PTD 2020070; Sundry 322-717 Photo of cement sample Test Data: F Casing Removal: Steve Soroka P Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): rev. 11-28-18 2023-0420_Plug_Verification_PBU_S-17C_ksj               Plug Verification PBU S-17C PTD 2020770 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 planned perforations require a spacing exception?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 ServiceDevelopmentStrastigraphicExploratory Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: AOGCC USE ONLY Commission Representative: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Location ClearanceMechanical Integrity TestBOP TestPlug Integrity Other: Post Initial Injection MIT Req'd? Spacing Exception Required?Yes Yes No No Subsequent Form Required: Approved By:Date: APPROVED BY THE AOGCCCOMMISSIONER Recomplete to Aurora Conductor Surface Intermediate Liner Liner 2670 4760 5410 10530 Structural Date: Current Pools:Proposed Pools: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Form 10-403 Revised 10/2022 Approved application is valid for 12 months from the date of approval.Submit PDF to aogcc.permitting@alaska.gov April 10, 2023 DSr-4/13/23SFD 5/4/2023 . 10-404 * State witness of MIT-T to 2500 psi and slick line tag (TOC ~9365' MD) of reservoir abandonment plug. * CBL to AOGCC upon completion. * BOPE test to 3000 psi. Annular to 2500 psi. MGR11MAY23 Recomplete to Aurorap JLC 5/12/2023 GCW 05/12/23 5/12/2023 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.05.12 10:39:25 -08'00' RBDMS JSB 051523 Recomplete to Kuparuk Well: S-17C PTD: 202-007 Well Name:S-17C API Number:50-029-21148-03 Current Status:Not Operable Producer due to failed MIT-T Estimated Start Date:5/18/23 Rig:Thunderbird 1 Sundry #322-717 / TBD Date Reg. Approval Rec’vd:01/17/23 / TBD Regulatory Contact:Abbie Barker Permit to Drill Number:202-007 First Call Engineer:Brodie Wages (907) 564-5006 (O)(713) 380-9836 (M) Second Call Engineer:Josh Stephens (970) 779-1200 (M) Current Bottom Hole Pressure:3471 psi @ 8782’ TVD 7.6 PPG | (3/30/2006 static) 8.0 PPG with 2500’ freeze protect Max. Anticipated Surface Pressure:2593 psi (Based on 0.1 psi/ft. gas gradient) Last SI WHP:0 psi (Taken on 11/3/2022) Min ID:2.377” X/O at 9548’ MD Max Angle:103 Deg @ 10,052’ MD 70 deg: 9800’ High DLS from 8417’ to 8900’ and again at 9300’ Formation Tops: Sag: 9450’ Sadlerochit: 9643’ MITs: CMIT-TxIA: 2369 psi on 2/10/2018 Brief Well Summary: The Ivishak reservoir no longer remains economically viable and the Kuparuk interval for S-17 motherbore is in a perfect location to test Kuparuk production. A RWO is planned to recomplete to Kuparuk to test production rates and water cuts at the Kuparuk interval. S-17: Spudded 8/6/1984 with a 17-1/2” hole to 2700’ where 13-3/8” surface casing was set and cemented at 2662’ with 3255 cuft ASIII and 698 cuft ASII followed by a 50sk cement top job. After testing BOPs, the casing tested to 3000 psi where the production hole was started and a leakoff test of 0.68 psi/.ft gradient was obtained. The production hole was directionally drilled to 9507’ with a 12-1/4” bit. Openhole logs were run then 9-5/8” casing set at 9488’ and cemented in place with 1705 cuft of class G w/ 8% gel followed by a tail of 230 cuft ClassG neat. The casing tested to 3000 psi. Finally, 8-1/2” hole was drilled to 9940’ where 7” production liner was run and cemented with 278 cuft. While WOC, the OA was downsqueezed with another 279 cuft of ASII followed by Arctic Pack. After waiting on liner cement and performing a fill cleanout, the liner would not pressure test, a CBL revealed no cement around the liner. Another 204 cuft of cement was pumped through added perforation at 9812’ followed by another FCO and a successful pressure test. The well was swapped over to NaCl and 4-1/2” production tubing was run and tested to 3500 psi. S-17C drilling: kicked off in Shublik, ROP slow to prevent stalling, remained slow to 10,008’, pumped a cement plug to sidetrack, after 10,300’ progress slow for differential sticking and shales, cemented with 18 bbls of cement, displaced within expected volumes, after cement in place, floats held. Notes Regarding Wellbore Condition 2/2001: GL Re-design 7/2001: Eline jewelry log, cut S-17A Liner in prep for coil sidetrack 8/2001: CTD sidetrack to S-17B, left fish in hole 8/2001: Service coil attempt to fish, unsuccessful a CBL revealed no cement around the liner. A recomplete to Kuparuk to test production 2593 psi Recomplete to Kuparuk Well: S-17C PTD: 202-007 2/2002: Squeeze off S-17B 3/2002: CTD drill S-17C 6/2002: Eline PPROF 3/2006: Slickline static,set down at 9811’, 10’x2” dmy gun SD @ 9803’ 9/2006: Heavy scale milled from surface to perfs, log and re-log, RDMO for Eline to perf who left perf tools DH @ 9742’, slickline able to fish out (guns had fired and split open 10/2006: Eline perf down to 9726’ 7/2013: PPROF finds gas entry in top set of perfs, set CIBP @ 9775’ 10/2014: SL Broach tubing open for scale 11/2014: Coil mill scale, slickline caliper, GLRD, Coil perform Organoseal Squeezecrete on all perforations and mill cement, did not complete mill at this time 12/2014: slickline attempt to pull LTP, Coil mill scale then pull LTP, mill to CIBP, unable to get passing MIT-T, milled cement (very difficult w/ organoseal plugging), mill to PBTD 7/2015: GLRD The most recent caliper performed 11/2014 shows an average wall loss around 10% with the interval around GLM5 showing up to 30% wall loss. This tubing should be re-usable, please discard joints 65 through 85. Objective: Recomplete to Kuparuk Sundry Procedure (Approval Required to Proceed) Pre-Rig –Complete 1/16/23 1. Obtain updated pressure tests on WH seals Slickline 1. Drift, broach scale as needed 2. Dummy GLVs 3. Load hole with 2% KCl + Freeze protect a. Total IA volume to St#1: 548 bbls b. Freeze protect volume to 2500’: 172 bbls 4. Obtain 3500 psi MIT-IA 5. Pull XX plug in nipple at 7900’ 6. Drift to deviation a. Must set CIBP above TSAD ~9450’ within the confining zone (mgr) b. 12 deg DLS @ 8574 c. 70 deg @ 9800’ Eline 1. Set CIBP @ ~9440’ MD (mgr) 2. Dump bail 25’ of cement on CIBP 3. AOGCC to witness slickline tag and pressure test to 2500 psi Slickline 1. Set plug in X nipple @ 7990’ 2. Dump bail 15-20’ of sand on lock. Recomplete to Kuparuk Well: S-17C PTD: 202-007 Eline 1. Cut tubing @ 7975’ a. Midway in pup below lowest GLM Pre-RWO: *Note: Depending on timing of rig move, well kill and BOP installation steps may be performed on rig rather than pre-rig. The well has been shut in since 2015, most recent static was obtained in 2014. This value should be accurate and ~1% KCl may be used as KWF. 1. Spot Pump Truck, RU and PT. a. Circulate in at least 380 bbls of 1% KCl through tubing cut b. Annular Volume to punch holes: 208 bbls c. Tubing Volume to punch holes: 121 bbls d. Total volume to punch holes: 329 bbls 2. RDMO pumpers 3. RD well house and flowlines. Clear and level area around well. 4. Set BPV w/insert (TWC) and test. ND Tree and THA. 5. NU BOPE configured top down: Annular, 2-7/8” x 5” VBRs, Blinds and integral flow cross. RWO Procedure: 1. MIRU Thunderbird 1 workover rig and ancillary equipment 2. Bleed TBG/IA pressures to ~0psi. Kill well w/1% KCl as needed. 3. Test BOPE to 250 psi Low/ 3,000 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Notify AOGCC 24 hours in advance of BOP test. b. Perform Test per “Thunderbird 1 Test Procedure” c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR ram and Annular on 4-1/2”and on 2-7/8”test joint. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 4. Pull TWC insert and BPV. a. Utilize lubricator for BPV removal if potential for trapped pressure exists. 5. MU landing joint or spear, BOLDS and PU on the tubing hanger. a. ~7975’ of 4-1/2” 12.6# tubing weighs ~ 88klbs (buoyed by 8.4 ppg fluid) b. If pulled up to 230 Klbs (80% of 4-1/2” yield strength) with no hanger movement, RU eline and perform 2nd tubing cut in cut window, discuss with OE. 6. POOH and lay down the 4-1/2” tubing. a. Save tubing if possible, discard joints 65 through 85 per 2014 caliper 7. RU Eline 8. Pull CBL from sand top @ ~7965’ to surface to verify cement quality over Kuparuk interval a. Send copy of log to David.wages@hilcorp.com b. Send copy of log with vendor TOC interpretation to AOGCC email Melvin.rixse@alaska.gov c. If no cement, work with OE for plan forward, very likely will run kill string Cut tubing @ 7975’ Recomplete to Kuparuk Well: S-17C PTD: 202-007 9. RIH w/2-7/8”workstring openended to ~7970’ 10. Dump 1500 lbs. of 20-40 sand on to of scoop guide/tubing stub a. 9-5/8” casing with no tubing inside fillup volume: 45 pounds 20-40/linear foot b. Packer to top of stub: 27’ = 1215 pounds of sand c. Will need to intermittently circulate in fluids to help sand fall d. Discuss with OE if we think slickling dump bailing might be more efficient 11. After dumping all the sand, tag top of sand to verify fillup, dump more sand as needed. POH a. Top of sand should be right at the tubing stub 12. MU scoop guide for 4-1/2” tubing stub in 9-5/8” casing 13. RIH and land scoop guide on tubing stub @ ~7975’, POH 14. PU new L-80 4-1/2” completion and run per S-17C Proposed Completion Running Order. a. Load IA with inhibited KWF brine b. Land tubing with mule shoe/WLEG @ ~7100’ a. Packer must be within 200’ of top perf. c. Ensure RHC plug body pre-installed in lowermost X profile 15. Land the tubing hanger and RILDS. Lay down landing joint. Note Pick-up and slack-off weights on tally. 16. Drop ball and rod and hydraulically set the packer per manufacturer’s setting procedure a. Conduct MIT-T to 3500 psi and MIT-IA to 3,500 psi for 30 mins (charted, state witnessed) 17. Shear circ valve in shallow GLM and circ freeze protect. 18. Bleed tubing pressure back to ~0 psi. Set BPV with TWC insert. 19. RDMO Thunderbird WO Rig and ancillary equipment. Move to next well location. 20. RU crane. ND BOPE. 21. NU the tubing head adapter and tree. Test tubing hanger void and tree to 500 psi low/5,000 psi high. 22. Pull BPV with TWC insert. 23. Replace wellhouse and gauge(s) if removed. Post-Rig Procedure: Slickline 1. Spot Slickline unit, RU and PT. 2. RIH and pull RHC plug from X profile at ±7100’ MD 3. Install LGLVs per GL engineer 4. RDMO and turn well over to operations. Eline 5. Perforate per geologist a. Charges will be 2-7/8” MaxForce or similar b. 6 SPF c. 60 deg Phasing Dump 1500 lbs. of 20-40 sand on to of scoop guide/tubing stub a.9-5/8” casing with no tubing inside fillup volume: 45 pounds 20-40/linear foot b. Packer to top of stub: 27’ = 1215 pounds of sand c.Will need to intermittently circulate in fluids to help sand fall d. Discuss with OE if we think slickling dump bailing might be more efficient 11. After dumping all the sand, tag top of sand to verify fillup, dump more sand as needed. POH a. Top of sand should be right at the tubing stub Recomplete to Kuparuk Well: S-17C PTD: 202-007 Operations 6. POP well 7. Obtain AOGCC witnessed SVS test within 5 days of putting well online. NOTE: A separate frac sundry and program will be submitted. This program only covers the RWO. Details to be included in future frac program that will require a frac sundry: 1. Slickline dummy GLVs, load hole with 2% KCl and freeze protect, obtain 3500 psi MIT-T and MIT-IA 2. Special Projects frac well 3. Contingent post frac coil FCO 4. Slickline install LGLVs 5. Well testers POP well for frac flowback 6. Handover to OPs Attachments: As Built Schematic Proposed Schematic Thunderbird 1 BOP Stack Sundry Change Form Recomplete to Kuparuk Well: S-17C PTD: 202-007 Current WBD: Recomplete to Kuparuk Well: S-17C PTD: 202-007 Proposed WBD: Recomplete to Kuparuk Well: S-17C PTD: 202-007 Thunderbird 1 BOP Schematic Hilcorp North Slope, LLCHilcorp North Slope, LLCChanges to Approved Rig Work Over Sundry Procedure 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 planned perforations require a spacing exception?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 ServiceDevelopmentStrastigraphicExploratory Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: AOGCC USE ONLY Commission Representative: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Location ClearanceMechanical Integrity TestBOP TestPlug Integrity Other: Post Initial Injection MIT Req'd? Spacing Exception Required?Yes Yes No No Subsequent Form Required: Approved By:Date: APPROVED BY THE AOGCCCOMMISSIONER PBU S-17C Recomplete to Aurora Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 202-007 50-029-21148-03-00 341J / 457B ADL 0028257, 0028258 10658 Conductor Surface Intermediate Liner Liner 8891 80 2634 8274 1415 2561 7990 20" x 30" 13-3/8" 9-5/8" 7" 3-1/2" x 3-3/16" x 2-7/8" 7491 30 - 110 29 - 2663 26 - 8300 8035 - 9450 8049 - 10610 2593 29 - 109 29 - 2663 26 - 7761 7530 - 8728 7542 - 8899 None 2670 4760 5410 10530 7990 5380 6870 7240 10160 No Perfs 4-1/2" 12.6# 13Cr80 24 - 8084No Perfs Structural 4-1/2" Otis HVT Packer No SSSV Installed 8002, 7502 Date: Stan Golis Sr. Area Operations Manager Brodie Wages David.Wages@hilcorp.com 907.564.5006 PRUDHOE BAY 2/1/2023 Current Pools: PRUDHOE OIL Proposed Pools: AURORA OIL 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 10/2022 Approved application is valid for 12 months from the date of approval.Submit PDF to aogcc.permitting@alaska.gov By Anne Prysunka at 1:14 pm, Dec 22, 2022 322-717 Digitally signed by Stan Golis (880) DN: cn=Stan Golis (880), ou=Users Date: 2022.12.21 16:33:00 -09'00' Stan Golis (880) DLB 12/23/2022 * BOPE test to 3000 psi. Annular to 2500 psi. * CBL results to AOGCC upon completion of logging. * State to witness slickline tag and pressure test of Ivishak isolation plug (TOC ~9415' MD) DSR-1/3/23 X 10-404 2593 MGR13JAN23 Brett W. Huber, Sr. GCW 01/17/23 JLC 1/17/2023 1/17/23 RBDMS JSB 011923 Recomplete to Kuparuk Well: S-17C PTD: 202-007 Well Name:S-17C API Number:50-029-21148-03 Current Status:Not Operable Producer due to failed MIT-T Estimated Start Date:Rig:Nordic 3 Sundry #Date Reg. Approval Rec’vd: Regulatory Contact:Abbie Barker Permit to Drill Number: First Call Engineer:Brodie Wages (907) 564-5006 (O)(713) 380-9836 (M) Second Call Engineer:Josh Stephens (970) 779-1200 (M) Current Bottom Hole Pressure:3471 psi @ 8782’ TVD 7.6 PPG | (3/30/2006 static) 8.0 PPG with 2500’ freeze protect Max. Anticipated Surface Pressure:2593 psi (Based on 0.1 psi/ft. gas gradient) Last SI WHP:0 psi (Taken on 11/3/2022) Min ID:2.377” X/O at 9548’ MD Max Angle:103 Deg @ 10,052’ MD 70 deg: 9800’ High DLS from 8417’ to 8900’ and again at 9300’ Formation Tops: Sag: 9450’ Sadlerochit: 9643’ MITs: CMIT-TxIA: 2369 psi on 2/10/2018 Brief Well Summary: The Ivishak reservoir no longer remains economically viable and the Kuparuk interval for S-17 motherbore is in a perfect location to test Kuparuk production. A RWO is planned to recomplete to Kuparuk to test production rates and water cuts at the Kuparuk interval. S-17: Spudded 8/6/1984 with a 17-1/2” hole to 2700’ where 13-3/8” surface casing was set and cemented at 2662’ with 3255 cuft ASIII and 698 cuft ASII followed by a 50sk cement top job. After testing BOPs, the casing tested to 3000 psi where the production hole was started and a leakoff test of 0.68 psi/.ft gradient was obtained. The production hole was directionally drilled to 9507’ with a 12-1/4” bit. Openhole logs were run then 9-5/8” casing set at 9488’ and cemented in place with 1705 cuft of class G w/ 8% gel followed by a tail of 230 cuft ClassG neat. The casing tested to 3000 psi. Finally, 8-1/2” hole was drilled to 9940’ where 7” production liner was run and cemented with 278 cuft. While WOC, the OA was downsqueezed with another 279 cuft of ASII followed by Arctic Pack. After waiting on liner cement and performing a fill cleanout, the liner would not pressure test, a CBL revealed no cement around the liner. Another 204 cuft of cement was pumped through added perforation at 9812’ followed by another FCO and a successful pressure test. The well was swapped over to NaCl and 4-1/2” production tubing was run and tested to 3500 psi. S-17C drilling: kicked off in Shublik, ROP slow to prevent stalling, remained slow to 10,008’, pumped a cement plug to sidetrack, after 10,300’ progress slow for differential sticking and shales, cemented with 18 bbls of cement, displaced within expected volumes, after cement in place, floats held. Notes Regarding Wellbore Condition x 2/2001: GL Re-design x 7/2001: Eline jewelry log, cut S-17A Liner in prep for coil sidetrack x 8/2001: CTD sidetrack to S-17B, left fish in hole 2593 psi -00 DLB Recomplete to Kuparuk Well: S-17C PTD: 202-007 x 8/2001: Service coil attempt to fish, unsuccessful x 2/2002: Squeeze off S-17B x 3/2002: CTD drill S-17C x 6/2002: Eline PPROF x 3/2006: Slickline static,set down at 9811’, 10’x2” dmy gun SD @ 9803’ x 9/2006: Heavy scale milled from surface to perfs, log and re-log, RDMO for Eline to perf who left perf tools DH @ 9742’, slickline able to fish out (guns had fired and split open x 10/2006: Eline perf down to 9726’ x 7/2013: PPROF finds gas entry in top set of perfs, set CIBP @ 9775’ x 10/2014: SL Broach tubing open for scale x 11/2014: Coil mill scale, slickline caliper, GLRD, Coil perform Organoseal Squeezecrete on all perforations and mill cement, did not complete mill at this time x 12/2014: slickline attempt to pull LTP, Coil mill scale then pull LTP, mill to CIBP, unable to get passing MIT-T, milled cement (very difficult w/ organoseal plugging), mill to PBTD x 7/2015: GLRD The most recent caliper performed 11/2014 shows an average wall loss around 10% with the interval around GLM5 showing up to 30% wall loss. This tubing should be re-usable, please discard joints 65 through 85. Objective: x Recomplete to Kuparuk Sundry Procedure (Approval Required to Proceed) Pre-Rig – Complete 9/2/2022 1. Obtain updated pressure tests on WH seals Slickline 1. Drift, broach scale as needed 2. Dummy GLVs 3. Load hole with 2% KCl + Freeze protect a. Total IA volume to St#1: 548 bbls b. Freeze protect volume to 2500’: 172 bbls 4. Obtain 3500 psi MIT-IA 5. Pull XX plug in nipple at 7900’ 6. Drift to deviation a. Must set CIBP @ 9600’ or deeper b. 12 deg DLS @ 8574 c. 70 deg @ 9800’ Eline 1. Set CIBP @ ~9610’ 2. Dump bail 25’ of cement on CIBP Slickline 1. Set plug in X nipple @ 7990’ 2. Dump bail 15-20’ of sand on lock. above TSAD ~9450' within the confining zone. 3. 9440' MD mgr AOGCC to witness slickline tag and pressure test to 2500 psi. mgr Recomplete to Kuparuk Well: S-17C PTD: 202-007 Eline 1. Cut tubing @ 7975’ a. Midway in pup below lowest GLM Pre-RWO: *Note: Depending on timing of rig move, well kill and BOP installation steps may be performed on rig rather than pre-rig. The well has been shut in since 2015, most recent static was obtained in 2014. This value should be accurate and ~1% KCl may be used as KWF. 1. Spot Pump Truck, RU and PT. a. Circulate in at least 380 bbls of 1% KCl through tubing cut b. Annular Volume to punch holes: 208 bbls c. Tubing Volume to punch holes: 121 bbls d. Total volume to punch holes: 329 bbls 2. RDMO pumpers 3. RD well house and flowlines. Clear and level area around well. 4. Set BPV w/insert (TWC) and test. ND Tree and THA. 5. NU BOPE configured top down: Annular, 2-7/8” x 5” VBRs, Blinds and integral flow cross. RWO Procedure: 1. MIRU Nordic 3 workover rig and ancillary equipment 2. Bleed TBG/IA pressures to ~0psi. Kill well w/1% KCl as needed. 3. Test BOPE to 250 psi Low/ 3,000 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Notify AOGCC 24 hours in advance of BOP test. b. Perform Test per “Nordic #3 Test Procedure” c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR ram and Annular on 4-1/2”and on 4”test joint. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 4. Pull TWC insert and BPV. a. Utilize lubricator for BPV removal if potential for trapped pressure exists. 5. MU landing joint or spear, BOLDS and PU on the tubing hanger. a. ~7975’ of 4-1/2” 12.6# tubing weighs ~ 88klbs (buoyed by 8.4 ppg fluid) b. If pulled up to 230 Klbs (80% of 4-1/2” yield strength) with no hanger movement, RU eline and perform 2nd tubing cut in cut window, discuss with OE. 6. POOH and lay down the 4-1/2” tubing. a. Save tubing if possible, discard joints 65 through 85 per 2014 caliper 7. RU Eline 8. Pull CBL from sand top @ ~7965’ to surface to verify cement quality over Kuparuk interval a. Send copy of log to David.wages@hilcorp.com b. Send copy of log with vendor TOC interpretation to AOGCC c. If no cement, work with OE for plan forward, very likely will run kill string email: melvin.rixse@AOGCC.com Risk assess for pressure under valve and possible lubrication of BPV. Recomplete to Kuparuk Well: S-17C PTD: 202-007 9. RIH w/ workstring openended to ~7970’ 10. Dump 1500 lbs. of 20-40 sand on to of scoop guide/tubing stub a. 9-5/8” casing with no tubing inside fillup volume: 45 pounds 20-40/linear foot b. Packer to top of stub: 27’ = 1215 pounds of sand c. Will need to intermittently circulate in fluids to help sand fall d. Discuss with OE if we think slickling dump bailing might be more efficient 11. After dumping all the sand, tag top of sand to verify fillup, dump more sand as needed. POH a. Top of sand should be right at the tubing stub 12. MU scoop guide for 4-1/2” tubing stub in 9-5/8” casing 13. RIH and land scoop guide on tubing stub @ ~7975’, POH 14. PU new L-80 4-1/2” completion and run per S-17C Proposed Completion Running Order. a. Load IA with inhibited KWF brine b. Land tubing with mule shoe/WLEG @ ~7100’ a. Packer must be within 200’ of top perf. c. Ensure RHC plug body pre-installed in lowermost X profile 15. Land the tubing hanger and RILDS. Lay down landing joint. Note Pick-up and slack-off weights on tally. 16. Drop ball and rod and hydraulically set the packer per manufacturer’s setting procedure a. Conduct MIT-T to 3500 psi and MIT-IA to 3,500 psi for 30 mins (charted, state witnessed) 17. Shear circ valve in shallow GLM and circ freeze protect. 18. Bleed tubing pressure back to ~0 psi. Set BPV with TWC insert. 19. RDMO Thunderbird WO Rig and ancillary equipment. Move to next well location. 20. RU crane. ND BOPE. 21. NU the tubing head adapter and tree. Test tubing hanger void and tree to 500 psi low/5,000 psi high. 22. Pull BPV with TWC insert. 23. Replace wellhouse and gauge(s) if removed. Post-Rig Procedure: Slickline 1. Spot Slickline unit, RU and PT. 2. RIH and pull RHC plug from X profile at ±7100’ MD 3. Install LGLVs per GL engineer 4. RDMO and turn well over to operations. Eline 5. Perforate per geologist a. Charges will be 2-7/8” MaxForce or similar b. 6 SPF c. 60 deg Phasing 4" work string. Recomplete to Kuparuk Well: S-17C PTD: 202-007 Operations 6. POP well 7. Obtain AOGCC witnessed SVS test within 5 days of putting well online. NOTE: A separate frac sundry and program will be submitted. This program only covers the RWO. Details to be included in future frac program that will require a frac sundry: 1. Slickline dummy GLVs, load hole with 2% KCl and freeze protect, obtain 3500 psi MIT-T and MIT-IA 2. Special Projects frac well 3. Contingent post frac coil FCO 4. Slickline install LGLVs 5. Well testers POP well for frac flowback 6. Handover to OPs Attachments: x As Built Schematic x Proposed Schematic x Nordic 3 BOP Stack x Sundry Change Form Recomplete to Kuparuk Well: S-17C PTD: 202-007 Current WBD: Recomplete to Kuparuk Well: S-17C PTD: 202-007 Proposed WBD: Bridge plug w/ TOC (25') ~9415' MD Recomplete to Kuparuk Well: S-17C PTD: 202-007 Nordic Rig 3 BOP Schematic Hilcorp North Slope, LLCHilcorp North Slope, LLCChanges to Approved Rig Work Over Sundry ProcedureDate: December 21, 2022Subject: Changes to Approved Sundry Procedure for Well S-17CSundry #:Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change.StepPageDate Procedure ChangeHNSPreparedBy (Initials)HNSApprovedBy (Initials)AOGCC WrittenApproval Received(Person and Date)Approval:Asset Team Operations Manager DatePrepared:First Call Operations Engineer Date 1 Rixse, Melvin G (OGC) From:Brodie Wages <David.Wages@hilcorp.com> Sent:Friday, January 13, 2023 11:04 AM To:Rixse, Melvin G (OGC) Subject:RE: [EXTERNAL] PTD 202-007, Sundry 322-717, S-17C Ivishak Abandonment HelloMel, Perourphoneconversation, TopofSag:9450’MD Wewillplanonsettingthereservoirabandonmentplugat9440’anddumping25’ofcementontopoftheplugviaEͲline dumpbailer. David“Brodie”Wages OpsEngineer C:713.380.9836 From:Rixse,MelvinG(OGC)<melvin.rixse@alaska.gov> Sent:Wednesday,January11,20234:36PM To:BrodieWages<David.Wages@hilcorp.com> Subject:RE:[EXTERNAL]PTD202Ͳ007,Sundry322Ͳ717,SͲ17CIvishakAbandonment Brodie, AOGCCstaffhasnoconfidencethatscoopguidewillbereͲenterableforfinalabandonmentandpermanentbarrierto theIvishak. PleaseconsidermovingCIBPtoahigherspotabovetheSAGRiverintotheconfiningzonesthatwouldprovide cementedbarriersacrossallannuliandsatisfypermanentabandonmentcriteria. Ifyousendthattome,Icaneditandapprovethissundry. MelRixse SeniorPetroleumEngineer(PE) AlaskaOilandGasConservationCommission 907Ͳ793Ͳ1231Office 907Ͳ297Ͳ8474Cell CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaskaOilandGasConservationCommission(AOGCC), StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmaycontainconfidentialand/orprivilegedinformation.Theunauthorizedreview,useor disclosureofsuchinformationmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutfirstsavingorforwardingit, and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactMelRixseat(907Ͳ793Ͳ1231)or(Melvin.Rixse@alaska.gov). CAUTION:Externalsender.DONOTopenlinksorattachmentsfromUNKNOWNsenders. 2 From:BrodieWages<David.Wages@hilcorp.com> Sent:Tuesday,December27,202211:30AM To:Rixse,MelvinG(OGC)<melvin.rixse@alaska.gov> Subject:RE:[EXTERNAL]PTD202Ͳ007,Sundry322Ͳ717,SͲ17CIvishakAbandonment HiMel, IhadMDintheprogrambutleftofftheTVDvalues,belowaretheMD/TVDpairs: TopSag:9450’MD,8728’TVD TopIvishak:9643’MD,8859’TVD, ApologiesfornotincludingTVDintheprogram David“Brodie”Wages OpsEngineer C:713.380.9836 From:Rixse,MelvinG(OGC)<melvin.rixse@alaska.gov> Sent:Friday,December23,20224:41PM To:BrodieWages<david.wages@hilcorp.com> Subject:[EXTERNAL]PTD202Ͳ007,Sundry322Ͳ717,SͲ17CIvishakAbandonment Brodie, WhatMD&TVDistheTSAGorTopofIvishakonthiswell? MelRixse SeniorPetroleumEngineer(PE) AlaskaOilandGasConservationCommission 907Ͳ793Ͳ1231Office 907Ͳ297Ͳ8474Cell CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaskaOilandGasConservationCommission(AOGCC), StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmaycontainconfidentialand/orprivilegedinformation.Theunauthorizedreview,useor disclosureofsuchinformationmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutfirstsavingorforwardingit, and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactMelRixseat(907Ͳ793Ͳ1231)or(Melvin.Rixse@alaska.gov). 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. 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STATE OF ALASKA RECEIVED < AL A OIL AND GAS CONSERVATION COMMI 1N • REPORT OF SUNDRY WELL OPERATIONS JAN 0 2015 • 1.Operations Abandon❑ Repair Well U Plug Perforations ❑ Perforate ID Other n'AaC Performed Alter Casing❑ Pull Tubing ❑ Stimulate-Frac ❑ Waiver Time Extension❑ eG Sv-LC 5,e___ Change Approved Program❑ Operat.Shutdown❑ Stimulate-Other El Re-enter Suspended WE 2 Operator 4 Well Class Before Work 5 Permit to Dnll Number BP Exploration(Alaska),Inc Name Development CI Exploratory❑ 202-007-0 3 Address P O Box 196612 Stratigraphic ❑ Service 6.API Number Anchorage,AK 99519-6612 50-029-21148-03-00 7 Property Designation(Lease Number) 8 Well Name and Number ADL0028258 PBU S-17C 9 Logs(List logs and submit electronic and printed data per 20AAC25 071) 10 Field/Pool(s) PRUDHOE BAY,PRUDHOE OIL 11 Present Well Condition Summary Total Depth measured 10658 feet Plugs measured None feet true vertical 8891.31 feet Junk measured None feet Effective Depth measured 9775 feet Packer measured See Attachment feet true vertical 8933 66 feet true vertical See Attachment feet Casing Length Size MD ND Burst Collapse Structural None None None None None None Conductor 80 20"x 30" 29.5-109 5 29 5-109 5 0 0 Surface 2633 83 13-3/8"72#L-80 29-2662.83 29-2662 79 4930 2670 Intermediate 8273 81 9-5/8"47#L-80 26.2-8300 01 26 2-7761 01 6870 4760 Production None None None None None None Liner See Attachment See Attachment See Attachment See Attachment See Attachment See Attachment Perforation depth Measured depth 9650-9668 feet 9672-9679 feet 9693-9710 feet 9714-9726 feet 9742-9750 feet 10292-10608 feet True Vertical depth 8863 16-8874 54 feet 8877 06-8881 41 feet 8889 89-8899 8 feet 8902 07-8908 79 feet 8917.46-8921 61 feet 8923.03-8899 53 feet Tubing(size,grade,measured and true vertical depth) 4-1/2"12 6#13Cr80 24 2-8083 92 24 2-7572 88 Packers and SSSV(type,measured and true vertical depth) See Attachment See Attachment See Attachment Packer None None None SSSV 12 Stimulation or cement squeeze summary. Intervals treated(measured) SEAMLfu [iti 9650'-9668',9672'-9679',9693'-9710',9714'-9726',9742'-9750' :2.1-‘1, o g •, I Treatment descriptions including volumes used and final pressure 24 Bbls 12%HCL,50 Bbls OrgaoSeal,40 Bbls SqueezeCrete, 1270 psi 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Pnor to well operation 55 235 2013 1167 209 Subsequent to operation 0 0 0 500 60 14 Attachments 15.Well Class after work Copies of Logs and Surveys Run Exploratory ❑ Development 0 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 0 Exempt N/A Contact Garry CatronEmail Garry.CatronaBP.Com Printed Name Garry Catron Title PDC PE Signature Phone 564-4424 Daterr II 1/19/2015 vri- 1/z g/i c RBDMS\.1 JAN 2 1 2015 ,. /ice( Form 10-404 Revised 10/2012 Submit Original Only Packers and SSV's Attachment ADL0028258 SW Name Type MD TVD Depscription S-17C PACKER 7999.69 7499.5 4-1/2" Otis HVT RETR Packer S-17C PACKER 8041.41 7535.87 3.7 Baker KB Liner Top Packer N a 0 0 cDC) 0 0 CO (.0 G .1" N I� U 00 00 L N LU co co • CO N co O -l- in m CO N- a0 O CO L) O CD CO N N- CO O CO L N N O CO N- O M N- CO CO M CO N j H N- N M C) • N in V7 O d7 N co N O N- if) M N N- CO C Q) OOOCOOM E O Ln NCO CO CO V' L (O CO CO O O 0) N CO C, p Q co O CO CO CO v- ON t O V N CO N 0 0 to N N = O M (O O O) .▪Q 0 CD ▪ Q O O Q' COCOp a M' co U J J J M C) v- �t � y Cr) *k co N CO N *k • N • N X (fl ' ti CO CU (i) _ % CO _ CO - C\j NN CO (fl LU (� _ r CO M N • M M M ' N- CO N d- O 0)O N- N M CO CO CO C 00 N CO L O CO O CD CO r '- N CO J w a w • U 111 CC CC CC Z z w w w w w m p 1 Z z z_ z_ J j Z J J J J U) • o a 0 C _ 0) O J a) (76 a. a w I- wo Q 2 . 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E U 0 c - { E e E § oE _ G0) ) U \ f m E 0 ƒ 33 $ / E / % / ,_ .0 \ / \ 0 § - > - s \ E - c O Ica ° - Co 2 2 c 2 E J CO ° _ m c 0 - = O - f 5 / $ = o = o 0 ° G % cob- E E a o \ \ f \\ 0 k / / CC 7 / G \ / CO » $ o £ a / 6 © 0 -- E Cn § R \ § F- 2 m w § / 0_ $ 5 m / = I E » ° 2 E _ © 2 b / m CO I E I C m b 2 w / % C - > R I i I c 3 ® t = o - m o ("Ni n 0 / _ = o g 0 2 = co / § %2 2 / C g ƒ k/ E ƒ / \ o o I o 0I o * o B m o 0 CD 9 c % $ O E E • 0 .- G - 0 / 0 2 ® \ ? ° E \ k 0 \ 2 %/ k E k / 'a f » _ g o m = m -.1 . 6 = a 7 Oco % 77E / / / O0 & $ % k = > E > CL NI > ± \ 8 a7c a 33iD \ t _c 0 o \ It E e O / ® 9 = G ® ° ° 9 0 * E t , ) E o O o 0 . 2 e_ n / �_ o \ O : @ a o \ = 2 - 3I- C = a P / / \ _ _ \ ?\ / o E o \ $ E \ \ _ _/ - / O / •C c o f _ ° w � a_ e 2 w 9 & w 9 O y w > _ ° ° / 0 = A G E 0 / 0 = / $ 2 w / 2 0 q / $ - 7 c O I c 0_ 2,.- e = e / SZ _C U r 3 r 2 \ m t I_ o m ,r = e = \ a _ \ g o o ƒ 2 0 / p - d Ti; o o - . > / E f i \ \ o \ CO \ $ _ > $ / / ® co- '0)=as % G © r / / $ - TS c>" & E E 0 E p \ e s a ® _ - c 2 - o o 0 = o b a / f * \ m 0 / .\_o & 0 ® C / 0 4 - 2 m o © .- ,, - 0 0 ± q # 2 Lo ® / 0m ° \ / § . 10 \ > ® ® S \ C / E 0 cmc9- o o Cl. R 2 c o \ ® � m = E / , \ .2 E C N 2 C ® 0 01 c e o E &_ - ® � _ .= a - e o / t o \ 0)7 / � '0E /O \ ƒ .7/ \ D \ \ \ - \ .5D00 CU \ D02ok Hot- o S e 9 R - o - H & 0 .2 0 6 =R - _ »- R - U -, c 2 = R : 022 (o : U ,- O = Eco a) 0 : 2 O t 0 : 2E : = --,* # # # o \ 7 n Lo,- » (N (N / CO & 6 ® (N CO 9 CO & (N & TREE= ` 4-1/16"CMI WH1J-EAD- MEEVOY S-17C SAI NOTE=5-1177AL11&S-1CHROME OTHH SIDETRACKED OFF ACTUATOR= BAKER SAME WHIPSTOCK AS S-17C tb 9445'. -INITIAL KB.81 67.5' :Hil I BF.ELEV= 38.83' KOP= 3100' ( 2111' —14-1/2"CAMOO BAL-O SSSVN D=3.812" Max Angle= 103"@ 10052 Datum MD= 9657' Debbi TVD= 8800'SS GAS LFT MANDRELS 13-3/8"CSG,72#,L-80,D=12.34T -I. 2662' ,ST MD TVD DEV TYPE VLV LATCH PORE DATE 5 3063 3061 10 OTIS DOME' RM r 16 12/07/14 4 5255 5042 30 OTIS SO RM 20 12/07/14 3 7182 6756 24 OTIS DMY T-2 ' 0 11/24/14 2 7895 7407 27 OTIS DMY RA ' 0 02/23/01 Minimum ID =2.370" @ 8052' 11 7961 '7466 28 M(OTIS OT-2 ' 0 11/24/14 BKR SEAL ASSY IN LTP 1 1 7990' H4-1/7 PARKERSWS PP,D=3.813" Z L 8002' -I9-5/8"X 4-1/7 OTIS IiVT R(R,3.880" 8035' H 9-5/8'X 7"BKR C-2 TEBK SLV,D=7.500' TOP OF 7'LNR --I 8036' — 8041' H 3.70"BKR KB LNR TOP R(R D=2.560' S 8042' H 9-5/8'X 7"BKR FLEXLOCK HGR,D=6.276' TOP OF 3-12" X 3-3/16"X 2-7/8"LNR H 8049' 8049' 3.70"BKR DEPLOY SLV,D=3.000' ' 8051' -14-1/7 PARKER SWS NP,D=3.813'(BEHIND LNR) _-. 8052' HUM OF BKR SEAL ASSY,D=2.370' II 8068' H 3-12"H C/WCO XN NP,D=2.750" 4-12'1BG,12.6#,13-CR.0152 bpf,D=3.958" H 8083' I-1....... 8072' H4-1/2'PARKER SON NP,MILLED TO 3.800"1 8084' H4-112'WLEG,D=3.958' BIND 8078' Hama TT LOGGED 10/19/91 CT LNR 9-5/8'CSG,47#,L-80,D=8.681' H 8300' 9-5/8'CSG MLLOUT WINDOW(5-17 ) 8300'-8380' ill' N I 3-12"LNR 9.3#,.0087 bpf,D=2.972' 9421' K I� �� 9421' �3 12'X 3-3/16"XO,D=2.786" 47"BKR W 'STOCK w/OUT RA TAG(XX/XX/XX) 9445' �t 7"LNR,26#,13-CR D=6.276' —f "9445 ',N, `+ T LNR MLLOUT WIDOW (S-17C)9450'-9456' lk s PERFORATION SIAMMRY \•t, ,, �► t REF LOG:SIAS VISION/RESISTNfTY ON 02/25/02 ; Co 9549' 3-3/16'X 2-7/8'X0,1)=2.377' ANGLE AT TOP PERF: 51'@9650' `••••• \• Vii, Note:Refer to Production DB for hisbrical pert data eV fel ��i ' • SIZE SR INTERVAL Opn/Sgz SHOT SQZ lkss%%% �•+%, 2' 6 9650-9668 S 10/12/06 11/27/14 !.1•2‘......•: i . 10251' H2-7/8'MARKER JT(4') 7 6 9672-9679 S 10/12/06 11/27/14 41.4, � 2" 6 9693-9710 S 10/12/06 1127/14 *,. A.`• 10256' —12-7/8"PERF'D PUP(4') 7 6 9714-9726 S 10/12/06 11/27/14 3-3/16"LNR, -1 9548' %••, 548' %•• `•ni 7 6 9742-9750 S 09/12/06 11/27/14 2-7/8" SLID 10292-10608 SLOT/C 03/02/02 .0076 bpf D=2.786" �V,, 114, •, J 2-7/8'SLTD LNR,6.5#,L-80,.0058 bpf,D=2.377' H 10610' • 10608' I P BTD DATE REV BY COM ENTS DATE REV BY CX)M ENTS PRUDHOE BAY IK 08/28/84 HF IMTIALL COMPLETION 12/12/14 SW/JMC GLV PO(12/07/14) WELL: S-17C 10/15/91 PAB SIDETRACK (S-17A) 01/06/15 ATO/JMO MLL®LNR CUT&CEP(12/25-27/14) PERMIT No: 202-0070 07/29/95 JAM CTD SIDETRACK (S-17AL1) AR No: 50-029-21148-03 08/18/01 CNIKAK CTD SIDETRACK (5-17B) SEC 35,T12N,T12E,2204'FNL&712'PAL 03102/02 CTD SIDETRACK (S-17C) 12/03/14 PJC REFORMAT WBS BP Exploration(Alaska) IIT)e Project Well History File Co{~' Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. &()~- 00 Well History File Identifier Organizing (done) R,CAN r Color items: o Grayscale items: o Poor Quality Originals: o Two-Sided 1111111111111111111 Rescan Needed 1111111111111111111 OVERSIZED (Scannable) I DIGJAL DATA V Diskettes, No·3 o Other, NofType o Maps: o Other items scannable by large scanner OVERSIZED (Non-Scannable) o Other: NOTES: o Logs of various kinds BY: BEVERLY ROBIN VINCENT SHERySWINDY Other BY: BEVERLY ROBIN VINCENT SHERYL@INDY DATE:l M 1111111111111111111 VVl Project Proofing Scanning Preparation -L x 30 = 30 + j I = TOTAL PAGES $- BY: BEVERLY ROBIN VINCENT SHERYL DATE: 4 (V1 Production Scanning Stage 1 PAGE COUNT FROM SCANNED FILE: Æ- ,/' // ~. PAGE COUNT MATCHES NUMBER IN SCANNING PREPARATION: / YES BY: . DATE: ~ÝO¥/SI Stage I IF NO IN STAGE 1, PAGE(S) DISCREPANCIES WERE FOUND: _ YES NO NO BY: BEVERLY ROBIN VINCENT SHERYL MARIA WINDY DATE: 151 (SCANNING IS COMPLETE AT THIS POINT UNLESS SPECIAL ATTENTION IS REQUIRED ON AN INDIVIDUAL PAGE BASIS DUE TO QUALITY , GRAYSCALE OR COLOR IMAGES) 1111111111111111111 ReScanned (im/ividual p,Jg'1[spaci.11 ,ltlwtíon] .scanning cpmpIOlû({) 1111111111111111111 RESCANNED BV: BEVERLY ROBIN VINCENT SHERYL MARIA WINDY DATE: /s/ General Notes or Comments about this file: Quality Checked (dOIl(') 1111111111111111111 1211 O/02Rev3NOTScanned. wpd STATE OF ALASKA C '" ' "` W W KAOILAND GAS CONSERVATION COMION AUG 0 9 20 REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon U Repair Well LJ Plug Perforations U Perforate U Other U Performed: Alter Casing ❑ Pull Tubing❑ Stimulate-Frac ❑ Waiver ❑ Time Extension❑ Change Approved Program ❑ Operat.Shutdown0 Stimulate-Other ❑ Re-enter Suspended WeIr 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: BP Exploration(Alaska),Inc Development/a Exploratory ❑ 202-007-0 t 3.Address: P.O.Box 196612 Stratigraphid Service ❑ 6.API Number: Anchorage,AK 99519-6612 50-029-21148-03-00 • 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0028258 PBU S-17C • 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): To Be Submitted PRUDHOE BAY,PRUDHOE OIL • 11.Present Well Condition Summary: Total Depth measured 10658 feet • Plugs measured 9775 feet true vertical 8891.31 feet Junk measured None feet Effective Depth measured 9775 feet Packer measured See Attachment feet true vertical 8933.66 feet true vertical See Attachment feet Casing Length Size MD TVD Burst Collapse Structural None None None None None None Conductor 81 20"x 30" 29-110 29-110 0 0 Surface 2635 13-3/8"72#L-80 28-2663 28-2662.96 4930 2670 Intermediate None None None None None None Production 8273 9-5/8"47#L-80 27-8300 27-7761 6870 4760 Liner See Attachment See Attachment See Attachment See Attachment See Attachment See Attachment Perforation depth Measured depth 9650-9668 feet 9672-9679 feet 9693-9710 feet 9714-9726 feet 9742-9750 feet 10292-10608 feet True Vertical depth 8863.16-8874.54 feet 8877.06-8881.41 feet 8889.89-8899.8 _feet 8902.07-8908.79 feet 8917.46-8921.61 feet 8923.03-8899.53 feet Tubing(size,grade,measured and true vertical depth) 4-1/2"12.6#13Cr80 26-8084 26-7572.95 Packers and SSSV(type,measured and true vertical depth) See Attachment See Attachment See Attachment Packer None None None SSSV 12.Stimulation or cement squeeze summary: SCANNED �j n Intervals treated(measured): NED NOV 20 13 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: 3 111 1162 1714 262 Subsequent to operation: 136 177 2894 1745 221 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run Exploratory❑ Development PI• Service❑ Stratigraphic ❑ Daily Report of Well Operations X 16.Well Status after work: Oil ® • 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: N/A Contact Nita Summerhays Email Nita.SummerhaYS(BP.com Printed Name Nita�Surpmerha Title Petrotechnical Data Technician Signatur r40:2 /4 ter- Phone 564-4035 Date 8/1/2013 ..�� f �1I�. !`,,°,tia YiF RBDMS AUG - 8 201 8J/57//3 Form 10-404 Revised 10/2012 / /X-7 Submit Original Only • • Daily Report of Well Operations ADL0028258 ACTIVITYDATE I SUMMARY VA promo• DRIFT W/2.25" CENT, 1.75" S. BAILER, S/D DUE TO DEVIATION @ 9821' SLM 6/25/2013 ***WELL LEFT S/I ON DEPARTURE*** ***JOB CONTINUED FROM 7/1/13***(E-LINE PPROF/CIBP) LOG GAS LIFT SURVEY. APPEARS GAS ENTRY AT TOP 2 STATIONS. LOG 40,80,120 FPM UP//DOWN PASSES. LOG STATIONS AT 9800, 9734, 9685, 9600'. WELL SLUGGING THROUGHOUT LOGGING SET BAKER HUGHES 2 7/8" CIBP ME SET DEPTH = 9775' CCL TO ME = 11.5' CCL STOP DEPTH = 9763.5' CORRELATED TO SLB MEMORY DEPTH CONTROL LOG DATED 6- SEP-2006 WELL SHUT IN ON DEPARTURE. DSO NOTIFIED. FINAL T/I/O = 2100/1850/0 PSI 7/2/2013 ***JOB COMPLETE*** T/I/O =1730/1732/16 Temp = SI Injectivity Test(Profile Modification) Pump 135 bbls 110* 1% KCL to load TBG. Achieve injection rate of 2.95 bpm at 1500 psi. Pump 38 bbls 50*diesel down TBG for freeze protect. 7/10/2013 FWHP=800/1730/22 SV, SSV, WV=CLOSED MV=OPEN CV's=OTG FLUIDS PUMPED BBLS 40 DIESEL 190 1% KCL 5 60/40 METH 235 TOTAL Casing / Tubing Attachment ADL0028258 Casing Length Size MD TVD Burst Collapse CONDUCTOR 81 20"x 30" 29 - 110 29 - 110 LINER 1379 3-1/2" 9.3#L-80 8041 - 9420 7535.52 - 8705.18 10160 10530 LINER 128 3-3/16" 6.2# L-80 9420 - 9548 8705.18 - 8799.8 LINER 1062 2-7/8"6.16# L-80 9548 - 10610 8799.8 - 8899.2 13450 13890 PRODUCTION 8273 9-5/8"47# L-80 27 - 8300 27 - 7761 6870 4760 SURFACE 2635 13-3/8" 72# L-80 28 - 2663 28 - 2662.96 4930 2670 TUBING 8058 4-1/2" 12.6# 13Cr80 26 - 8084 26 - 7572.95 8430 7500 • • • • Packers and SSV's Attachment ADL0028258 SW Name Type MD TVD Depscription S-17C PACKER 8002 7434.04 4-1/2"Otis HVT Packer S-17C PACKER 8041 7468.04 3.7 Baker KB Liner Top Packer(J ` TTY= 4-1/16"CM( 1111 SA NOTES: CHROME TBG(4-112")& LNR(7-112". 'ACTUATOR= BAKER 67.5' S-1 7C WELL ANGLE CK E 9445.NOTE* NO RAT TAG IN &S-17B BOTH MIAL KB.BF 67.5 SIDETRACKED OFF SAME WHIPSTOCK AS S-17C 0 BF.B.EV= 38.83 8445'.P8J1 NOT SHOWN ON OWGRAM. KOP= 3100' Max Angle= 103°r, 10052 Datum M3= 9657' D�umTVD= 8800 SS L 2111' H4 112"CAMCO BAL O SSSVN,D=3.812" 13-3/8'CSG,72#,L-80,D=12.347" 2662 GAS LIFT MANDRELS S H I ST MD TVI1 DEV TYPE VLV LATCH FORT DATE 0 5 3063 3061 10 OTIS DONE RA 16 03/08/02 4 5255 5042 30 OTIS DOME RA 16 03/08/02 3 7182 6756 24 OTIS DONE RA 16 03/08/02 Minimum ID=2.377" @ 9549' 2 7895 7407 27 OTIS DMY RA 0 02/23/01 3-3/16" X 2-7/8" LNR X-OVER 1 7961 7466 28 OTIS S10 RA 14 03/08/02 I I 7990' H 41/2"PARKER SWS NP,D=3.813" I M •M L 8002' 1-19-5/8'X 4-1/2"OTIS HVT PKR,3.880" I BKR C-2 TIEBACK SLEEVE,D=7.500" —I 8035' I I I9-5/8"X 7"BKR FLEXLOK LNR HGR,D=6.276" H 8042• 8041' I—{3.70'OD BKR KB PKR D=2.560' ii I 8049' H3.70"OD BKR DEPLOYMENT SLV,N3=3.000" BTM OF BKR SEAL ASSY,D=2.390' —I 8062' ' I 8061' 1-14-112"PARKER SWS NP,D=3.813" I I 8058' I-13-1/2"HOW CO XN NP,D=2.750• I 8072' H4-1/2'PARKER SWN N',MLLE?TO 3.800" I 4-1/2"TBG,12.6#,13-CR,.0152 bpf,D=3.958" H 8083' 8084' —14-112''/ LEG I 19-5/8"CSG,47#,L-80,D=8.681" I I 8078' I-�E MD TT LOGG®10/19191 9-5/8"CSG NLLOUT WIDOW 8300-8380' (SECTION NLL) 3-1/2"LNR,9.3#,.0087 bpf,D=2.972" 9420' VS Ov4• T LNR N� WPOOW ∎•4 X441 9450'-9455 44 441 I TOP OF WHPSTOCK H 9446' I ��•1 1��1 1 44 9421' H3-1/2"X 3-3116"LNR X0,D=2.786" I PERFORATION SUMMARY REF LOG:SWS VISION/RESISITVIN ON 02/25/02 I 9548' --I 3-3/16"LNR,6.2#,1-80,.0076 bpf,D=2.786' I ANGLE AT TOP PERF: 51*@ 9650' 9649• j--j3-3/16"X 2-7/8"LNR XO,D=2.377" I ♦v4TATA ♦ Note:Refer b Reduction DB for historical pert data 1414 4 4 411 SIZE SPF INTERVAL Opn/Sqz SHOT SQZ ■•4•4•4•4•4•4441 ` 9774' H2-7/8'BKR CBP(07/02/13) I 2" 6 9650-9668 0 10/12/06 4 4 414 4 4 4 2" 6 9672-9679 0 10/12/06 44..4.44 4* /� 10261•I-12-7/8"MARKER JT(4') I 2' 6 9693-9710 0 10/12/06 *4�4�4�4�4.4� ` r 10266' H2-7/7 PERM PUP(4') I 2" 6 9714-9726 C 10/12106 .444444444444441 I 2" 6 9742-9750 C 09/12106 444444444444441 10292' I—I TOP 2-7/S"SLID LNR 2-7/8" SLID 10292-10608 C 03/02/02 444444444444441 \ 1444444444444441 \ 17"LNR,26#,13-CR,13=6.276' H 10060' ( �1�4�4�4�1�14141 I PBTD -L 10608' I BIM OF 2-7/8'SLID LNR H 10608' I I2-7/8'SLID LNR,6.5#,L-80,.0058 bpi,D=2.37T —I 10610' I DATE REV BY CONVENTS DATE REV BY COM ENTS PRI.DHOE BAY UNT 08128184 HF OIIGINAL COMPLETION 03/08/02 RJTLH GLV UPDATE WELL: S-17C 1011519/ PAB RIG SIDETRACK(S-17A) 10/12/06 GIB/TLH PERFS PERMIT No: 202-0070 07/29/95 JAM CTD SIDETRACK (S-17AL1) 10/27/06 DLB/PIAG PEiF CORRECTIONS AR Pb: 5(-029-21148-03 08118/01 CWKAK CTD SIDETRACK (S-17B) 07/16/13 SET/JM) SET 2-7/8"CIBP(07/02/13) SEC 35,T12N,T12E,2204'FNL&712'PM. 03/02102 CTD SIDETRACK(S-17C) 0 CHTp CORRECTIONS BP Bcplorallon(Alaska) ~ BP Exploration (Alaska) Inc. Attn: Well Integrity Coordinator, PRB-20 Post Office Box 196612 Anchorage, Alaska 99519-6612 June 25, 2009 Mr. Tom Maunder Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Corrosion Inhibitor Treatments of S-Pad Dear Mr. Maunder, • ~ ~ ~ JuL a ~ zoog ~I~~~~ ~i~ ~ Gas ~~nsm Cammis~.~~n Rnc~~r~~~ ~~~~ ~~~ ~-17~. Enclosed please find a spreadsheet with a list of wells from S-Pad 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, 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 altemate, Anna Dube, at 659-5102. Sincerely, w~~~`~~~~~~'L+ ~%~i1L ~ (:' ~~1.~~ Torin Roschinger 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) Spad ~'I nm*R f~/25/2009 Well Name PTD # Initial top ot cement Vol. of cement um ed Final top of cement Cement top otf date Comosion inhibitor Corrosion inhibitod sealant date tt bbls it na al S-O7B 1952020 025 NA 025 NA 2.8 5/30/2009 S-02A 1941090 0.25 NA 0.25 NA 1.7 5/25/2009 S-03 1811900 1325 NA 1325 NA 92.65 5/20/2009 S-oa 1830790 0 NA 0 NA o.s 5/25/2009 S-OSA 1951890 0 NA 0 NA 0.9 5/26/2009 S-06 7821650 0 NA 0 NA 0.9 5/26l2009 S-07A 1920980 0 NA 0 NA 0.9 5/26/2009 S-088 2010520 0 NA 0 NA 0.85 5/27/2009 S-o9 1821040 1.5 NA 1.5 NA s.4 5/31/2009 S-10A 1911230 0.5 NA 0.5 NA 3.4 5/37I2009 S-11B 1990530 025 NA 025 NA 1.7 5/27/2009 S-~2A 1851930 0.25 NA 025 NA 7.7 6/1/2009 S-13 1821350 B NA 8 NA 55.3 6/i/2009 S-75 7840170 025 NA 025 NA 3 6/2/2009 S-17C 2020070 025 NA 025 NA 2.6 6/1/2009 S-18A 2021630 0,5 NA 0.5 NA 3 6/2/2009 S-19 1861160 0.75 NA 0.75 NA 22 5/19/2009 S-20A 2010450 025 NA 025 NA 1.3 5/19/2009 S-21 7900470 0.5 NA 0.5 NA 3.4 5/25/2009 5-228 1970510 0.75 NA 0.75 NA 3 5/19/2009 5-23 1901270 025 NA 025 NA 1.7 5/25/2009 S-24B 2031630 0.5 NA 0.5 NA 2.6 5/25/2009 S-25A 1982140 0.5 NA 0.5 NA 2.6 5/25/2009 5-26 1900580 0.75 NA 0.75 NA 3.4 5/26/2009 S-278 2031680 0.5 NA 0.5 NA 2.6 5/31l2009 5-288 2030020 0.5 NA 0.5 NA 2.6 5/31/2009 S-29AL7 1960120 0 NA 0 NA 0.85 5l27/2009 5-30 1900660 0.5 NA 0.5 NA 5.1 5/31/2009 S-31A 1982200 0.5 NA 0.5 NA 3.4 5/26/2009 S32 1901490 0.5 NA 0.5 NA 3.4 5/31/2009 S-33 1921020 0.5 NA 0.5 NA 4.3 5/26/2009 S-34 7921360 0.5 NA 0.5 NA 3.4 5/31/2009 5-35 1921480 0 NA 0 NA .e5in 5/31/2009 S-36 1921160 0.75 NA 0.75 NA 425 5/27/2009 S37 1920990 - 125 NA 125 NA 11.9 5/27/2009 S38 1921270 0.25 NA 025 NA 102 5/27/2009 5-41 7960240 1.5 NA 1.5 NA 11.1 5/30/2009 5-42 1960540 0 NA 0 NA 0.9 5/30/2009 S-43 1970530 0.5 NA 0.5 NA 1.7 5/28/2009 S-44 1970070 025 NA 025 NA 1.7 5/26/2009 5-100 2000780 2 NA 2 NA 213 5/29/2009 5-101 2001150 1.25 NA 125 NA 11.9 5/29/2009 5-102Lt 2031560. 725 NA 125 NA 71.~ 5/31/2009 S-103 2001660 1.5 NA 1.5 NA t1.9 5/18/2009 S-104 2001960 1.75 NA 1.75 NA 153 5/20/2009 S•105 2001520 4 NA 4 NA 32.7 5/20/2009 5-106 2010120 16.25 NA 1625 NA t14.3 6/2/2009 5-107 2011130 225 NA 225 NA 28.9 5/18/'2009 S-108 2011000 3.5 NA 3.5 NA 40 5/30/2009 5-109 2022450 2 NA 2 NA 21.3 5/30/2009 5-110 2017290 11.75 NA 11.75 NA 98.6 5/30/2009 S-171 2050510 2 NA 2 NA 19.6 5/30/2009 5-112 2021350 0 NA 0 NA 0.5 5/30/2009 5-~73 2021430 1.75 NA 1.75 NA 22.1 5/18/2009 S-114A 2021980 1.25 NA 125 NA 10.2 5/30/2009 5-115 2022300 2.5 NA 2.5 NA 272 5/29/2009 S-116 2031810 1.5 NA 1.5 NA 13.6 5/28/2009 5-7~7 2030120 1.5 NA 1.5 NA 15.3 5/29/2009 S-7ie 2032000 5 NA 5 NA 76.5 5/28/2009 5-119 2041620 1 NA 1 NA 52 5/30/2009 5-120 2031980 5.5 NA 5.5 NA 672 5/29/2009 S-121 2060410 4.5 NA 4.5 NA 53.8 5/28/2009 5-122 20508t0 3 NA 3 NA 21.3 5/29/2009 5-123 2041370 1.5 NA 1.5 NA 20.4 5/26/2009 5-724 2061360 1.75 NA 1.75 NA 71.9 5/26/2~9 5-725 2070830 225 NA 225 NA 20.4 5/28/2009 S-126 20710970 125 NA 125 NA 15.3 6/1/2009 5-200 1972390 125 NA 125 NA 14.5 5/28/2009 5-201 2001840 0 NA 0 NA 0.85 &19/2009 S-213A 2042130 2 NA 2 NA 13.6 5/29/2009 S-275 2021540 2 NA 2 NA 18.7 6/1/2009 5-276 200t970 4.75 NA 4.75 NA 51 5/29/2009 5-217 2070950 025 NA 025 NA 1.7 6!1/2009 S-400 2070740 2 NA 2 NA 9.4 5/28/2009 S-401 2060780 16 NA 16 NA 99.5 6/2/2009 5-504 0 NA 0 NA 0.85 5/28/2009 C~ Safety Valve & Well Pressures Test Report Reviewed $y~ i l P.I. Suprv ~ ~-- Z ZF7o ~ Comm Pad: PBU_s InspDt: 2/18/2008 L>tspected by John Crisp Interval InspNo svsJCr080221140934 Related Insp: Field Name PRUDHOE BAY Operator BP EXPLORATION (ALASKA) INC Operator Rep Rich Vincent Reason 180-Day `' Well Data.. ~ Pilots Well Permi[ Separ Set L/P Number Number PSI PSI Trip S-100 2000780 153 -i._ 125 i -125 ~ P ; P S-103 ; 2001680 ~ 153 125 120 I P I P _. ----- --a- - ~.-- i --- -- - 1 1 5-105 ! 2001520 153 125 i 110 P ~ P __ _ - 1_-- S-106 i 2010120 ! 153 125 40 ~ 30 P I I -__ ___S-108 _ _-2011000 i 153 ~ 125 125 P I - P _ S-109 _ ~ 2022450 j~153 125 ~ 125 P r P 1~._ ~_ -I--- - S 1! 3B _..r-_ 2021430 I 153 ~ _125 ! 125 P ~ P S-ll5 2022300 153 1125 ~ 120 P P S-117 I 2030120 153 ! 125 ~. 135 P P S-121 i 2060410 153 125 125 T P P S-122 2050810 153125 110 P P S-125 I 2070830 r 153 1125 115 P ~ P ---- ~~~ S-17C ~ 202W70 ~ 153 125 ~ t 10 P P _- - -: -------- - - -- --1--- - S-l8A ~ 2021630 i53 ~ 125 1100 P P 5-213A -i 2042130 ~ 153 125 125 P ~P_ S-44 I 1970060 153 ~25 100 P ~ P -l -- ---_ _ ~... .______.___-.__-J.__- _. ___L--_-_~_.--. ~.._~..-.-1-___ 11=V1L _~L...___._.~___-._._-.-_I_.._.-.._~____~1..--._._-___..-____..,_..-.___.__ Comments c~ _ ,~ , J P~~ ~~~~J ~ Co Performance ~"' (Wells Components Failures Failure Rate c~ C~ N~ti v<<~c~,- I /~ ~2~- le3~W~ , ' ~ o ---16 --- - 32- :-_.-_-1 - ---- 3.12 /o--- -- __-, ~ BAR ~ ~ 2oa$ • • Monday, February 25, 2008 Sre: Inspector __. ~ SSV SSSV Sf:utln Dt yi'ellType Well Pressures `Gas Lit Waiver G9rr[ments ~ Test Test Test Date SI OiI,WAG,GINJ, Inner Outer Tubing Code Code Code GAS,CYCLE, SI PSI PSI PSl Yes/No Yes/No · STATE OF ALASKA _ ALA OIL AND GAS CONSERVATION COM~ON OCT 1 7 2006 REPORT OF SUNDRY WELL OPERATIONika Oil 1. Operations Abandon 0 Repair Well 0 Plug Pertoratíons 0 Stimulate 0 Ot~r Q Pertormed: Alter Casing 0 Pull Tubing 0 Pertorate New Pool 0 Waiver 0 Time Extensio~D'ragl! Change Approved Program 0 Operat. Shutdown 0 Pertorate [2] Re-enter Suspended Well 0 2. Operator BP Exploration (Alaska), Inc. 4. Current Well Class: 5. Permit to Drill Number: Name: Development R' Exploratory 202-0070 3. Address: P.O. Box 196612 Stratigraphic Service 6. API Number: Anchorage, AK 99519-6612 50-029-21148-03-00 7. KB Elevation (ft): 9. Well Name and Number: RECEIVED 67.48 KB PBU S-17C ADLO-028258 11. Present Well Condition Summary: 10. Field/Pool(s): PRUDHOE BAY Field/ PRUDHOE OIL Pool 8. Property Designation: Total Depth measured 10659 feet Plugs (measured) None true vertical 8891.14 feet Junk (measured) None Effective Depth measured 10609 feet true vertical 8899.37 feet Casing Length Size MD TVD Burst Collapse Conductor 80' 20" 94# H-40 30' - 11 0' 30' - 110' 1530 520 Surtace 2635' 13-3/8"" 72# L-80 31' - 2663' 31' - 2663' 4930 2670 Production 8268' 9-5/8" 47# L-80 32' 8300' 32' - 7761' 6870 4760 Liner 2569' 3-1/2"x3-3/16"x2-7/8" 8041' - 1 061 0' 7536' - 8899' Pertoration depth: Measured depth: 9650' - 10608' True Vertical depth: 8863' - 8900' - - - - Tubing: (size, grade, and measured depth) 4-1/2" 12.6# NT13Cr80 33' - 8083' Packers and SSSV (type and measured depth) 9-5/8"X4-1/2" OTIS HVT PKR 3.70" OD BKR KB PKR o o 8002' 8041' o o 12. Stimulation or cement squeeze summary: Intervals treated (measured): . >, Ii. I\INJ;;51 "j;' 'l~' " .1\'..3" ....<~~ ..'~ ",', ....-...< Treatment descriptions including volumes used and final pressure: Prior to well operation: Subsequent to operation: 14. Attachments: Copies of Logs and Surveys Run Daily Report of Well Operations Oil-Bbl 362 345 Representative Daily Avèrage Production or Injection Data Gas-Met Water-Bbl Casing Pressure 788 5232 0 670 4938 0 15. Well Class after proposed work: Exploratory Development R' 16. Well Status after proposed work: Oil r;¡ Gas WAG Tubing pressure 239 255 13. :J. Service Contact Gary Preble WINJ WDSPL 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signature RBDMS BFL 0 CT 1 7 2000 Title Data Engineer Phone 564-4944 Date 1 0/16/2006 ORIGINAL Submit Original Only ~ . . S-17C DESCRIPTION OF WORK COMPLETED NRWO OPERATIONS EVENT SUMMARY 9/12/2006iATTEMPT TO PERFORATE FROM 9742' TO 9750' USING 2" HSD 2006 PJ OMEGA GUN, 6 SPF, 60 DEG PHASING. WELL PRODUCING UPON ARRIVAL, I SHUT WELL IN BEFORE RIH. EXPERIENCED 1.5 HOURS LOST TIME DUE TO ! TOOL FAILURE WHILE RIH ON FIRST RUN. SHOT FIRST FROM 9742' TO 9750', TOOL BECAME STUCK AFTER SHOOTING. CALLED FOR A PUMP TRUCK TO DISLODGE TOOL. JOB CONTINUED ON 13-SEP-2006 AWGRS. ,.............'.'......,._'__._._..._._____".,._..........._._,.......,.,.,.,.:.,.,..............,..,...,.,.,.,.,....._._........__..,.,.,.,.,.,.,.,............'....,.,.,.,.,.......................,.,.,.,.,.,...._.......'......,.,.,.,.,.,............'......,.,.,.,.,.,..._·_·_·.·.,...'..,·,·,·,·.·_·_·.·_·.·._....w,·_·___·_·_·_·_.._w.·.·_·_____·_·__·,,'..,·,·,·,·.·.·.·.·.·.·_""..,·,·,·,·,............'....,.,.,.,.,.,.,..............'."",.,.,..................',',.,.,.,.,.,.,.,............'.'.',.,.,.,.,.,............'.'.',',.,.,.,...,..............'".,."w_,______·_·_·__'·e"^'_____·___·,,___.·.·.·_·_·_·_·_·_·......,·,..·,·,·,·.·.·.·.·.·.·.__~___________....__·,wu_·_·.·.·_·.·.·...',',__m,·.·.·.·.·.'.·,·,·,·.·_________,,_ 9/12/2006IT/I/O = 1900/1980/120. ASSIST E-LlNE. Pump 5 bbls of neat methanol and 309 bbls of crude down the TBG.***WSR continues on 9/13/06*** 9/13/20061 PERFORATED FROM 9742' TO 9750' USING 2" HSD 2006 PJ OMEGA GUN, 6 'SPF, 60 DEG PHASING. WELL PRODUCING UPON ARRIVAL, SHUT WELL IN BEFORE RIH. EXPERIENCED 1.5 HOURS LOST TIME DUE TO TOOL FAILURE' WHILE RIH ON FIRST RUN. SHOT FIRST FROM 9742' TO 9750'. TOOL BECAME STUCK AFTER SHOOTING. CALLED FOR A PUMP TRUCK TO DISLODGE TOOL. TOOL LEFT DOWN HOLE. SEE FULL REPORT FOR FISHING INFORMATION. WELL LEFT SHUT IN. TURNED OVER TO DSO. 971's72ÔÔ61***WSRconiinuedfrom' 97127Ô6***AssisTE=i..:iNE.pump'iÔ¡;¡;¡s'ofcrudedown"· TBG. Final WHP= 50/1600/60. -<o"N -.-N_____________._._=__ 9/15/2006.*** WELL SHUT IN UPON ARRIVAL *** (fish perf guns) RAN 2.15 LIB TO 9718'SLM , IMPRESSION OF 1 3/8 FN . RAN 2" RS , LATCHED & JARRED ON FISH FOR 5 MIN AND SHEARED TOOL. ***CONTINUED ON 09/16/06 WSR*** 971672ÔÔ6!***cÖNTW,iÜEÖFRÖMÔ97157Ô6WsR**;w (fish perf gun) FISHED ELINE PERF GUN(OAL WAS 37'). GUNS HAD FIRED AND SPLIT OPEN. ¡***WELL TURNED OVER TO PAD OP ON DEPARTURE*** 9/20/20061**** WELL FLOWING ON ARRIVAL **** (PRE ADPERF) RAN 2.00" DUMMY GUN, DRIFTED TO 9830' SLM *** WELL SHUT IN ON DEPARTURE*** ____~N,"_________'______N_ _________u,,·· __ ___w,,^, __ __ __ ..~"',...... ....'.'.'""..... '.'.'.'.' '.""" __.'.'.'.'.""'" __ ......'...'.. ,... ·,·___________,__·.v w-·__________,__'··," "'...........'...'..,,, ',·..·_···_··_____w' .',,'·_···___________NP_________··.·'·', w...·.·.·.·.·.'.·.', ,',·..·_·_________'w·_·_·_____________······,·,,',',w_____......,., ,,',····_···___'__~N 10/7/2006 ATTEMPTED TO PERFORATE. GAMMA RAY FAILED AT 9100' RIH, NOTED IHIGH GR COUNTS IN TUBING DUE TO SCALE, SHUT DOWN DUE TO HIGH WINDS. WELL ON LINE. _______'_'N_·_·······__·_···'···""',,········'···"",,·,··_·___·_·__·________N,"·_·_·___·___________,_,·,..,____._._..__.___.....'.,'"..___._._____._......,.",'._._.________'_______.'...___.______._,-__,..','" 1 0/13/2006 i Completed perf job . Full report to follow.... ,,~~,_._,-__________,___,_,w_-__._______,__'^w-....________-_______,__v,·, -,~~,__.____________mw_" FLUIDS PUMPED BBLS I 1 DI ESEl 1 TOTAL . . MICROFILMED 07/25/06 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F:\LaserFiche\CvrPgs_Inserts\Microfilm _ Marker.doc I fJyJ ;t(\ I.) ,-( DATA SUBMITTAL COMPLIANCE REPORT 4/2/2004 5f1~ ¿, n r-;/~ ~ 2- Permit to Dri 2020070 Well Name/No, PRUDHOE BAY UNIT S-17C Operator BP EXPLORATION (ALASKA) INC API No. 50-029-21148-03-00 ((J Co çq ô2'r¡ 3/2/2002 ~ MD 40055- TVD ..8iæ Completion Date Completion Status 1-01L Current Status 1-01L UIC N REQUIRED INFORMATION Mud Log No Samples No Directional Survey ~. --- DATA INFORMATION Types Electric or Other Logs Run: (data taken from Logs Portion of Master Well Data Mainf Well Log Information: )) Electr Digital Dataset Log Log Run Interval OH/ Med/Frmt Number Name Scale Media No Start Stop CH Received Comments 5 Blu 1 3000 9580 Case 7/19/2002 with gas lift survey and Deft. Jewelry log C ÒKì695 2 9400 10392 Open 3/22/2002 PB2 5 Blu 1 3000 9580 Case 7/19/2002 with gas lift survey and Deft. Jewelry log 1-G9 5 Blu 1 3000 9580 Case 7/19/2002 with gas lift survey and I Deft. Jewelry log '.j;L} C UiJ694 2 9400 10392 Open 3/22/2002 PB1 ~ 5 Blu 1 3000 9580 Case 7/19/2002 with gas lift survey and , Deft. Jewelry log ~ 5 Blu 1 3000 9580 Case 7/19/2002 with gas lift survey and t.EÓ C Deft. Jewelry log LAû693 2 9400 10659 Open 3/22/2002 Well Cores/Samples Information )) Sample .' Interval Set Name Start Stop Sent Received Number Comments ADDITIONAL INFORMATION Well Cored? y~ Daily History Received? 0N Chips Received? ~ Formation Tops WN Analysis -y ¡ <j Received? Comments: DATA SUBMITTAL COMPLIANCE REPORT 4/2/2004 Permit to Dri 2020070 Well Name/No. PRUDHOE BAY UNIT S-17C Operator BP EXPLORATION (ALASKA) INC API No. 50-029-21148-03-00 MD 10655 TVD 8892 Completion Date 3/2/2002 Completion Status 1-01L Current Status 1-01L UIC N ~--- - ---- Po__ /\ -~ Compliance Reviewed By: Date: ~ ) } 6/02 07/ Sc~lunI~epger NO. 2230 Company: State of Alaska Alaska Oil & Gas Cons Comm Aftn: Lisa Weepie 333 West 7th Ave, Suite 100 Anchorage, AK 9950 Alaska Data & Consulting SeN/ces 3940 Arctic Blvd, Suite 300 Anchorage, AK 99503-5711 ATTN: Beth ) Field: Prudhoe Bay CD Color Prints Sepia Blueline I I I I I I I I I 1 I I 1 Date 06/23/02 06/19/02 06/13/02 06/28/02 06/16/02 06/20/02 06/14/02 06/24/02 06/05/02 06/18/02 06/17/02 06/18/02 06/17/02 Log Description CHFR CHFR STATIC PRESSITEMP SURVEY INJECTION PROFILE CHFR CHFR CHFR PROD PROFILE/DEFT PROD PROFILE/DEFT PROD PROFILE/DEFT PROD PROFILE/DEFT LEAK DETECTION LOG PUMP-IN TEMP SURVEY Job # Wel } Schlumberger GeoQuest 3940 Arctic Blvd, Suite 300 Anchorage, AK 99503-571 ATTN: Sherrie RECEIVED BP Exploration (Alaska) Inc. Petrotectnical Data Center LR2- 900 E. Benson Blvd, Anchorage, Alaska 99508 Received 2002 Alaska Œj & Gas Cons. Ccmmission Anchorage 19 JUL Date Delivered " .....- d ,;-..., ~ 'O,;~ l' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Revised TD by 4 Feet: OS/23/02 1. Status of Well Classification of Service Well a Oil DGas D Suspended D Abandoned D Service 2. Name of Operator 7. Permit Number BP Exploration (Alaska) Inc, 202-007 3. Address 8, API Number P.O, Box 196612, Anchorage, Alaska 99519-6612 50- 50-029-21148-03 4. Location of well at surface 9, Unit or Lease Name 2204' SNL, 712' EWL, SEC. 35, T12N, R12E, UM Prudhoe Bay Unit At top of productive interval 2299' SNL, 1926' WEL, SEC. 34, T12N, R12E, UM 10. Well Number At total depth S-17C 1764' SNL, 2712' WEL, SEC. 34, T12N, R12E, UM 5. Elevation in feet (indicate KB, DF, etc.) 6. Lease Designation and Serial No. 11. Field and Pool Prudhoe Bay Field / Prudhoe Bay Pool KBE = 67.48' ADL 028258 12. Date Spudded \13. Date T.D, Reached 14. Date Comp., Susp., or Aband. \15. Water depth, if offshore 16. No. of Completions 2/16/2002 2/25/2002 3/2/2002 N/ A MSL One 17. Total Depth (MD+TVD) 18. Plug Back Depth (MD+TVD)r\19. Directional Survey \20. Depth where SSSV se~121. Thickness of Permafrost 10659 8891 FT 10609 8899 FT aVes DNo (Nipple) 2111'MD 1900'(Approx.) 22. Type Electric or Other Logs Run MWD, GR, RES 23, CASING. LINER AND CEMENTING RECORD CASING SETTING DEPTH HOLE SIZE WT. PER FT. GRADE Top BOTTOM SIZE CEMENTING RECORD AMOUNT PULLED 20" x 30" Insulated Conductor Surface 110' 36" B cu vds Concrete 13-3/8" 72# L-80 Surface 2663' 17-1/2" 3255 cu ft AS III, 465 cu ft AS II 9-5/8" 47# L-80 Surface 8300' 12-1/4" 1935 cu ft Class 'G' 3-112' x 3-3116' 8.8# / 6.2# L-80 8041' 10610' 3-3/4" 101 cu ft Class 'G' x 2-718' 6.16# 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) 2-7/8" Slotted Liner 4-1/2",12.6#, NT13Cr80 8084' 8002' MD TVD MD TVD 10292' - 10609' 8923' - 8899' 26, ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED Freeze Protect with 32 Bbls MeOH 27. PRODUCTION TEST Date First Production Method of Operation (Flowing, gas lift, etc,) March 9, 2002 Gas Lift Date of Test Hours Tested PRODUCTION FOR Oll-BBl GAs-McF WATER-BBl CHOKE SIZE I GAS-Oil RATIO 3/12/2002 4 TEST PERIOD 964 896 4080 96° 929 Flow Tubing Casing Pressure CALCULATED Oll-BBL GAs-McF WATER-BBl OIL GRAVITY-API (CORR) Press. 24-HoUR RATE 24.7 28. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit c!>r~chips. .. ~ (¡ No core samples were taken. ¡ I: I' I " ij APR 4 1004 .--. RBDMSBfL -. \,,, ,'J I ~ , os l·,,","=> Form 10-407 Rev. 07-01-80 G~ Submit In Duplicate ,. -- /-\ ~ ". 11";'· 29. Geologic Markers 30. Formation Tests Marker Name Measured Depth True Vertical Depth Include interval tested, pressure data, all fluids recovered and gravity, GOR, and time of each phase. Sag River 9450' 8728' Shublik 9502' 8768' Shublik B 9585' 8823' Shublik C 9606' 8836' Sadlerochit 9643' 8859' 31. List of Attachments: Submitted 04/19/02: Summary of Daily Drilling Reports, Surveys 32. I ~erebY certify that the for;9oi~9 is true and correct to the best of my knowledge Signed Terrie Hubble ~~ ~ I ~ Title Technical Assistant Date OS·~3·Q;L S-17C Well Number 202-007 Permit No. / Approval No. Prepared By Name/Number: Terrie Hubble, 564-4628 INSTRUCTIONS GENERAL: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. ITEM 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. ITEM 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. ITEM 16 AND 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. ITEM 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). ITEM 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. ITEM 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-In, Other-explain. ITEM 28: If no cores taken, indicate 'none'. Form 10-407 Rev. 07-01-80 -~ ~ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of Well Classification of Service Well 181 Oil DGas D Suspended D Abandoned D Service 2. Name of Operator 7, Permit Number BP Exploration (Alaska) Inc. 202-007 3. Address 8. API Number P.O. Box 196612, Anchorage, Alaska 99519-6612 m&t 50-50-029-21148-03 .. 4. Location of well at surface¡-ëô~r: "1:";:;û;7'; 9. Unit or Lease Name 2204' SNL, 712' ~W~, SEC. 35, T12N, R12E, UM ~ ~í~':Œ h ¡ , .;Ç.,) r " Prudhoe Bay Unit At top of productive Interval I ~ ' i 'D V -:~hh .. 2299' SNL, 1926' WEL, SEC. 34, T12N, R12E, UM ¡ ;7~~ ¡ '~..kì~~ ~ 10. Well Number At total depth ( ~-" , S-17C 1766' SNL, 2709' WEL, SEC, 34, T12N, R12E, UM L:.-· "M.::::,::::J ~~~--_f·___ 5. Elevation in feet (indicate KB, DF, etc.) 6. Lease Designation and Serial No. 11. Field and Pool Prudhoe Bay Field / Prudhoe Bay Pool KBE = 67.48' ADL 028258 12. Date Spudded 113. Date T.D. Reached 14. Date Comp., Susp., or Aband. 115. Water depth, if offshore 16. No. of Completions 2/16/2002 2/25/2002 3/2/2002 N/ A MSL One 17, Total Depth (MD+ TVD) 18, Plug Back Depth (MD+ TVD) ,119, Directional Survey 120. Depth where SSSV se~121. Thickness of Permafrost 10655 8892 FT 10609 8899 FT I8IYes DNa (Nipple) 2111'MD 1900'(Approx,) 22. Type Electric or Other Logs Run MWD, GR, RES 23, -CASING, LINER AND CEMENTING RECORD CASING SETTING DEPTH HOLE SIZE WT, PER FT. GRADE Top BOTTOM SIZE CEMENTING RECORD AMOUNT PULLED 20" X 30" Insulated Conductor Surface 110' 36" 8 cu vds Concrete 13-3/8" 72# L-80 Surface 2663' 17-1/2" 3255 cu ft AS III, 465 cu ft AS II 9-5/8" 47# L-80 Surface 8300' 12-1/4" 1935 cu ft Class 'G' 3-1/2' x 3-3116' 8.8# / 6.2# L-80 8041' 10610' 3-3/4" 101 cu ft Class 'G' x 2·718' 6.16# 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) 2-7/8" Slotted Liner 4-1/2", 12.6#, NT13Cr80 8084' 8002' MD TVD MD TVD 10292' - 10609' 8923' - 8899' 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL MD) AMOUNT & KIND OF MATERIAL USED Freeze Protect with 32 Bbls MeOH 27, PRODUCTION TEST Date First Production Method of Operation (Flowing, gas lift, etc.) March 9, 2002 Gas Lift Date of Test Hours Tested PRODUCTION FOR OIL-BBL GAs-McF WATER-BBL CHOKE SIZE I 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. SUbmt{t e1: I V E LJ No core samples were taken. APF( 1 9 2002 Alaska ml & Gas Gens. CommiSSIOn AnchoraQe (""-, f", ¡ /". ! r. ¡ 11. , .,nn ,,_ Form 10-4 7 Rev. 07-01-80 l I ¡ " " j l..:::; §!(¡~it In Du licate o RBOMS BFl p ~ ~ 29. Geologic Markers 30. Formation Tests Marker Name Measured Depth True Vertical Depth Include interval tested, pressure data, all fluids recovered and gravity, GOR, and time of each phase. Sag River 9450' 8728' Shublik 9502' 8768' Shublik B 9585' 8823' Shublik C 9606' 8836' Sadlerochit 9643' 8859' RECEIVED ¡~p~( 1 9 2002 Alaska Oil & Gas Cons. CommisSion AnchoraaEl 31. List of Attachments: Summary of Daily Drilling Reports, Surveys 32, I hereby certify that the foregoing is true and correct to the best of my knowledge Signed Terrie Hubble Title Technical Assistant Date 0 ' c;.()~ S-17C Well Number 202-007 Permit No. / A roval No. Prepared By Name/Number: Terrie Hubble, 564-4628 INSTRUCTIONS GENERAL: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. ITEM 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. ITEM 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. ITEM 16 AND 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. ITEM 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). ITEM 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. ITEM 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-In, Other-explain. ITEM 28: If no cores taken, indicate 'none'. Form 10-407 Rev. 07-01-80 ~ ~ S-17C Prudhoe Bay Unite 50-029-21148-03 202-007 Rig Accept: Rig Spud: Rig Release: Drillin Ri : 02114/02 02/16/02 03/02/02 Nabors 3S PRE-RIG WORK 01120/02 DRIFT TUBING WI 3.625 DUMMY WHIPSTOCK, 01/21/02 DRIFT TUBING WI 3.65" DUMMY WHIPSTOCK TO 9435' WLM. LEFT WELL SHUT IN. 01/27/02 MITIA PASSED TO 3000 PSI. 02107/02 PRESSURE TEST SURFACE EQUIPMENT. PERFORM WEEKLY BOP TEST. MU AND RIH WITH PDS MEMORY GR/CCL. 02108102 RIH WITH MEMORY LOG TO 9410' CTMD. FLAG PIPE. POH AND LOG TO 7850'. FLAG PIPE. POH. VERIFY DATA. GOOD. MU AND RIH WITH 2 7/8" MOTOR, JARS AND 3.80" MILL. RIH. CORRECT AT FLAG, TAG OPEN HOLE KICKOFF TOOL AT 9467' (DN), 9462' (UP). POH. PU 3" COMBO NOZZLE. RIH. COOL DOWN @ 9000' WHILE MIXING CEMENT.INJECTIVITY: 0.8 BPM AT 180 PSI. LAY IN 26.5 BBLS 17 PPG CEMENT FROM 9460' TO 9138'. LOST 14 BBLS TO OH WHILE LAYING IN. PULL TO SAFETY AND HESITATE SQUEEZE. UNABLE TO MAINTAIN WHP ABOVE 250 PSI. CEMENT TOP AT APPROXIMATELY 9350'. POH. DID NOT CIRCULATE OUT DUE TO LOW SQUEEZE PRESSURE. FREEZE PROTECT COIL AND PRODUCTION TUBING WITH MEOH, RDMO. NOTIFY PAD OPERATOR THAT WELL IS TO BE LEFT SI. 02110/02 DRIFT W/3.25 CENT & SAMPLE BAILER, TAG CEMENT @ 9253' WLM (9284' CORRECTED). SAMPLE OF CEMENT. PRESSURE TUBING TO 1000# PSI TO TEST CEMENT. MONITOR FOR 30 MIN. GOOD TEST, RDMO. LEFT WELL SHUT IN. NOTIFIED PAD OPER. ,-..." ~ Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: S-17 S-17C REENTER+COMPLETE Start: 2/12/2002 Rig Release: Rig Number: Spud Date: 8/6/1984 End: 3/2/2002 2/14/2002 00:00 - 05:00 5,00 RIGU P PRE MIRU Nabors 3S. Accept rig at 0500 hrs 2-14-2002 PJSM NIU BOPE stack 05:00 - 06:30 1.50 RIGU P PRE N/U BOPE stack 06:30 - 06:50 0.33 RIGU P PRE Crew change PSJM on NIU of BOP stack 06:50 - 09:45 2.92 RIGU P PRE Continue N/U. Contact AOGCC 2hr notice for testing. Wavied by John Crisp 09:45 - 13:45 4.00 RIGU P PRE Test BOPE 5/min low 5/min high 13:45 -19:00 5.25 RIGU P PRE Rig up other equipment. Waiting on CTU held up at Deadhorse until 1400 hrs. Made it to location and the tractor dropped the rearend at 1530 hrs before being able to spot it. Placing uprights and filling. Hook-up hard line to opentop and T tank. Nabors crew working PM. 19:00 - 22:00 3.00 RIGU P PRE Spot DS CTU #4 and r/u same. Pull TWC. Bleed down casing. Anticipated 1000 psi but only 400. 22:00 - 23:30 1.50 STWHIP P WEXIT P/U injector.change out pack-off. M/U CTC. 23:30 - 00:00 0.50 STWHIP P WEXIT Pressure test CTC 3500 psi. Pull test to 35k. 2/15/2002 00:00 - 00:45 0.75 STWHIP P WEXIT Circulate meth out of coil. Function test remote BOP panel. 00:45 - 02:00 1.25 STWHIP P WEXIT PT inner reel valve smae time P/U BHA #1. 02:00 - 02:20 0.33 STWHIP P WEXIT PT MHA 02:20 - 06:00 3.67 STWHIP P WEXIT RIH to 2500' shallow test tools -ok - continue RIH to 9050' 06:00 - 08:45 2.75 STWHIP P WEXIT Start log tie-in (down) 9050'-9200' inconclusive data. 08:45 - 09:25 0.67 STWHIP P WEXIT RIH tag firm at 9292'. Drill cement to 9330'. Firmed up at 9310' drilled at 30-40'/hr. 09:25 - 10:00 0.58 STWHIP P WEXIT Log tie-in fl 9270-9330' bit depths. gr -29.8' behind bit depth. + 18' correction 10:00 - 16:00 6.00 STWHIP P WEXIT Drill cement f/9330' to 9451', pumping occasional 2 ppb bio sweeps. ROP 20-30 FPH. Grabby at 9451'. Numerous stalls. Took about an hour to get past here. Mill to 9455'. Stall here. Mill to 9461'. Ream old window. Dry tag clean. 16:00 - 18:45 2.75 STWHIP P WEXIT Swap well over to Flo-Pro mud. POOH 18:45 - 20:00 1.25 STWHIP P PROD1 LD BHA 20:00 - 20:50 0.83 STWHIP N SFAL PROD1 Repair leak on injector. 20:50 - 21 :30 0.67 DRILL P PROD1 MU BHA 21:30-22:15 0.75 DRILL P PROD1 Test Orienter 22: 15 - 22:30 0.25 DRILL P PROD1 RIH to 1,000'. Shallow hole test OK. 22:30 - 00:00 1.50 DRILL P PROD1 Continue to RIH. 2/16/2002 00:00 - 01 :20 1.33 DRILL P PROD1 Tie in log 9260 -9310. No correction. 01 :20 - 01 :35 0.25 DRILL P PROD1 RIH to 9460'. 01 :35 - 01 :45 0.17 DRILL P PROD1 Orient 90L 01 :45 - 02:45 1.00 DRILL P PROD1 Directionally drill to 9480'.2,6/2.6 bpm 2720 psi. 02:45 - 06:00 3.25 DRILL P PROD1 Drill and survey to 9580'. Getting more build than we can continue drilling with. Need to dial down. 06:00 - 08:30 2.50 DRILL P PROD1 POOH to reduce motor bend. 08:30 - 10:00 1.50 DRILL P PROD1 Change motor bend from 1.8 deg to 1.1 deg, swap M09 with DS49, add resistivity. 10:00 - 12:00 2.00 DRILL P PROD1 RIH. Shallow test good. 12:00 - 12:30 0.50 DRILL P PROD1 Log tie-in at 9260' GR spike. Correct depth (+1'). 12:30 - 12:45 0.25 DRILL P PROD1 RIH. 12:45 - 13:00 0.25 DRILL P PROD1 Orient left. 13:00 - 17:30 4.50 DRILL P PROD1 Drill Shublik slowly at about 10 FPH. Good motor differential (300 psi). Try to give it any more, and it stalls. Drill to 9642'. 17:30 - 17:45 0.25 DRILL P PROD1 Orient right. 17:45 - 19:40 1.92 DRILL P PROD1 Drill Shublik to 9660 top of Zone 4. Printed: 3/412002 10:29:40 AM ,.-." .~ Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: 8-17 8-17C REENTER+COMPLETE Start: 2/12/2002 Rig Release: Rig Number: Spud Date: 8/6/1984 End: 3/2/2002 2/16/2002 19:40 - 20:00 0.33 DRILL P PROD1 Driectionally drilling 2.7/2.7 bpm 3160 psi to 9,697'. 20:00 - 20:10 0.17 DRILL P PROD1 Orient I 20:10 - 20:30 0.33 DRILL P PROD1 Drill to 9725'. 20:30 - 20:40 0.17 DRILL P PROD1 Pump survey, 20:40 - 21 :20 0.67 DRILL P PROD1 Drill to 9762'. 21 :20 - 00:00 2.67 DRILL P PROD1 POH to dial up motor from 1.15 to 1.83. 2/17/2002 00:00 - 00:40 0.67 DRILL P PROD1 POH 00:40 - 02:00 1.33 DRILL P PROD1 Dial up motor from 1.15 to 1.83 degree per 100 02:00 - 03:50 1.83 DRILL P PROD1 RIH to 2200 shallow hole test. OK? Continue to RIH to 3,500' and retest ARC not communicating. With ARC inclination unavailable at 16+' MWD DI package inclination is 60+' up hole. 03:50 - 08:00 4.17 DRILL N DFAL PROD1 POOH. Suspect faulty MU of MWD to ARC. Switch probes. RIH. Problem with Nabors pump. Unable to do shallow test. Continue RIH dry while fixing pump. Shallow test at 6200'. 08:00 - 08:45 0.75 DRILL P PROD1 RIH 08:45 - 09: 15 0.50 DRILL P PROD1 Log tie-in. No correction. 09:15 - 09:30 0.25 DRILL P PROD1 RIH. 09:30 - 10:00 0.50 DRILL P PROD1 Orient high side. 10:00 - 11: 15 1.25 DRILL P PROD1 Drill to 9835'. ROP 70 - 100 FPH. 11:15-12:00 0.75 DRILL P PROD1 Pump up survey. Orient back to highside. Survey shows risk of getting deeper than 20' below the line. Will drill another 10' and check again. 12:00 - 14:00 2.00 DRILL P PROD1 Drill to 9850'. Survey. 26 deg DL. Drill another 15'. Survey. Drill to 9927'. Getting the desired DL's. 14:00 - 15:00 1.00 DRILL P PROD1 Wiper to window. 15:00 - 20:45 5.75 DRILL P PROD1 Drill. Hit brick wall at 9948', grunt to 9980' at < 10 FPH. Started losing 1.0 BPM here. Losses deteriorated to 2.5/0.5 by 9986'. Returns improved to 2.3/1.0 at 9995'. Drilling still very slow to 10005'. Unable to get MW after switching from 90R to 90L.Unable to drill. Hard bottom. Clean pickup. Unable to get motor work. 20:45 - 00:00 3.25 DRILL P PROD1 POH / While pulling out of hole at 8,520 noticed instantaneous 1,000 psi pressure loss. POH at slow pump rate. 2/18/2002 00:00 - 01 :30 1.50 DRILL P PROD1 POH 01 :30 - 01 :45 0.25 DRILL P PROD1 PJSM for coil cutting operation. 01 :45 - 02:30 0.75 DRILL N HMAN PROD1 Pipe damaged in reel sump. Strip off and cut 130' of coil. 02:30 - 02:45 0.25 DRILL P PROD1 LD BHA 02:45 - 03:00 0.25 DRILL N HMAN PROD1 Cut 90' of coil from reel. 03:00 - 03:30 0.50 DRILL N HMAN PROD1 MU coil connector 03:30 - 03:45 0.25 DRILL N HMAN PROD1 Pull test coil connector. 03:45 - 04:35 0.83 DRILL P PROD1 Circulate methanol out of coil. Pressure test failed. 04:35 - 04:55 0.33 DRILL N HMAN PROD1 Replace coil connector. 04:55 - 05:05 0.17 DRILL P PROD1 Test orientar. OK 05:05 - 05:20 0.25 DRILL N HMAN PROD1 PT MHA 05:20 - 07: 15 1.92 DRILL P PROD1 RIH 07:15 - 07:45 0.50 DRILL P PROD1 Lag tie-in. No correction. Not getting real time data from Arc tool. 07:45 - 08:00 0.25 DRILL P PROD1 RIH. Orient. Tag 10007'. 08:00 - 08:30 0.50 DRILL P PROD1 Drill 2.5/1.8/2100. Very slow getting started, stacking negative weight trying to get bite. Finally got in a groove and started seeing some ROP. Drill to 10037'. Returns improved to 2.5/2.1. Printed: 3/412002 10:29:40 AM ~. .~ Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: 8-17 S-17C REENTER+COMPLETE Start: 2/12/2002 Rig Release: Rig Number: Spud Date: 8/6/1984 End: 3/2/2002 2/18/2002 08:30 - 12:30 4.00 DRILL N DPRB PROD1 PUH to get survey. Overpull to 20k over with stalls 9990' - 10020'. Kinda ugly. Returns deteriorating again to 2.5/1.6. Ream and backream. Unable to get down past 10007'. Wiper to window while mixing 30 bbl Flo-Pro pill with one drum Lubetex. RIH pumping pill. Did not help slide. Unable to get past 10007', but sticky area above has cleaned up. 12:30 -14:30 2.00 DRILL N DPRB PROD1 Start drilling new hole, stacking little progress. Skipped into old hole. Drill 3' to 10040'. Pump up survey. Work back down to 10040' (struggle getting past 10008'). 14:30 -15:30 1.00 DRILL P PROD1 Drill to 10080' (100' past loss zone). Returns variable but avg about 2.5/1.8. 15:30 - 17:00 1.50 DRILL N DPRB PROD1 PUH to check conditions. Clean PUH. RIH. Sat down 10007' with stall. Attempt to work past. Kept tagging with bit. Overpulls to 20K over. Eventually got past, but took negative wt over most of BHA to get past. Backream slowly. Initially 2.4/1.3, slowly got worse. Got gardually worse to 2.4/1.0 across loss zone. Pulled heavy and stuck 9950' (never had hole problems here). No returns. Packed-off. Work free. Got returns back. 17:00 - 18:30 1.50 DRILL N DPRB PROD1 No improvement in hole conditions with repeated reaming. Will PUH and wait on batch mixer for Form-A-Plug pill. Backream to window 2.4/1.3. Pull heavy w/o MW and pack-off 9830'. Work free going down. Repeat numerous times. Made progress to 9820' but no further. Still packing off with no returns, getting free going down and then getting returns back 2.4/1.3. 18:30 - 19:00 0.50 DRILL P PROD1 Crew change safety meeting. 19:00 - 19:30 0.50 DRILL N DPRB PROD1 Mix 30 bbls Flo-Pro pill for lubricity (4 buckets flo-vis; one drum Lubetex).Circulate 8bbl out of BHA and POH 19:30 - 20:15 0.75 DRILL N DPRB PROD1 POOH. Tight at 9731. Pull tight at window. Orient at window 52LPull thru window. 20:15 - 21 :00 0.75 DRILL N DPRB PROD1 Circulate while waiting on delivery of Form A Plug 21 :00 - 21 :05 0.08 DRILL N DPRB PROD1 Perforn injectivity test at 2 bpm 300 psi wellhead pressure. 21 :05 - 23:00 1.92 DRILL N DPRB PROD1 Circulate while waiting on delivery of Form A Plug. DS batch mixer was tied up on a surface cement job. 23:00 - 00:00 1.00 DRILL N DPRB PROD1 Rig up cementers. 2/19/2002 00:00 - 00:30 0.50 DRILL N DPRB PROD1 RU cementers 00:30 - 01 :30 1.00 DRILL N DPRB PROD1 PJSM mix and pumping of Form A Plug LCM pill. 01 :30 - 01 :40 0.17 DRILL N DPRB PROD1 Pressure test cement lines to 4000 psi. 01 :40 - 02:48 1.13 DRILL N DPRB PROD1 With bit at 9430', pump 10 bbl Fresh water Flo Pro, 34 BBI Form A Plug, 5 bbl Flo Pro. Displace with 20 bbl KCL washup water. Pump FAP to bit at 1.3 BPM, SI backside, bullhead to fault at 500 psi WHP. Pressure climbed to 1100 psi with 22 bbls FAP away in fault. Slow down rate and BH last 6 bbls at 1000 psi max (about 1.0 BPM). Bullheaded 28 bbl away in fault and left 7 bbl in open hole. 02:48 - 02:55 0.12 DRILL N DPRB PROD1 Open choke and POOH to 9300. Switch to Nabor's pump. Coil plugged off. pressure to 4500 psi. No Go. Vac out hard lines. 02:55 - 06:00 3.08 DRILL N DPRB PROD1 POOH filling. LD BHA plugged with Form A Plug. Attempt ot circulate thru coil -- No Go. Remove coil connector. 2' slug of Form A Plug fell to floor with the consistency of Oat Meal. Stabbed on to well open ended and estabilshed circulation. 06:00 - 06:30 0.50 DRILL P PROD1 Crew change safety meeting. Printed: 314/2002 10:29:40 AM r"' .~ Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: S-17 S-17C REENTER+COMPLETE Start: 2/12/2002 Rig Release: Rig Number: Spud Date: 8/6/1984 End: 3/2/2002 2/19/2002 06:30 - 07:30 1.00 DRILL N DPRB PROD1 Install CTC. Pull and PT. 07:30 - 08:00 0.50 DRILL N DPRB PROD1 RU hose to BHA and circulate thru. No problems. Only tools plugged with FAP are MHA and orienter. LD resistivity tool. 08:00 - 09:00 1.00 DRILL N DPRB PROD1 MU drilling BHA. Test orienter. 09:00 - 11 :10 2.17 DRILL N DPRB PROD1 RIH. Shallow test. 2.5/2.5. 11:10 -11:45 0.58 DRILL N DPRB PROD1 Log tie-in at 9260' GR marker. Correct depth (-7'). 11 :45 - 13:00 1.25 DRILL N DPRB PROD1 Wash in hole 20 FPM 2.5/2.5. Little to no resistance. Ratty string wt w/o MW starting at about 9900'. Tag and stall 10007'. Skip thru. Wash to TD at 10076'. Full returns 2.5/2.5. Significant FAP over shakers, but nothing more solid than jello. Backream to 9900', started seeing losses 2.5/2.1. RIH. Hole in fair shape. 13:00 - 14:15 1.25 DRILL P PROD1 Start drilling. Losses increased to 2.5/1.6 but slowly improved to 2.5/2.0. Drill to 10155'. Stacking, no progress. 14:15 - 15:15 1.00 DRILL P PROD1 Wiper to window. Hole in good shape. 15:15 - 15:30 0.25 DRILL P PROD1 Orient 15:30 - 18:00 2.50 DRILL P PROD1 Drill 2.6/1.5 to 10255', negative string wt at end. Returns did not improve. Pump up survey. 18:00 - 19:00 1.00 DRILL P PROD1 Wiper trip to window. No problem areas, just a little ratty in the same spot 9990' - 10020' 19:00 - 22:00 3.00 DRILL P PROD1 Drill 2.6/1.5 to 10295' pumping 10 bbl Flo-Pro sweeps (about 100k LSRV) every coil volume. 22:00 - 23:00 1.00 DRILL P PROD1 PUH to survey, then have to orient. 23:00 - 00:00 1.00 DRILL P PROD1 Drill to 2.6/1.5 to 10315'. 2/20/2002 00:00 - 02:00 2.00 DRILL P PROD1 Drill with 40% losses to 10340', pumping Flo-Pro sweeps every coil volume. Slow drilling, not a lot of clean sand. 02:00 - 03:30 1.50 DRILL P PROD1 Wiper to window. Clean PUH. Struggle RIH at 10000' and 10250' shale 03:30 - 08: 15 4.75 DRILL P PROD1 Drill < 10 FPH. Unable to get past tough spot at 10387'. Try slick pill. No go. Can't get motor work with -15k. Also, ratty wt RIH in shale starting 10245'. 08: 15 - 09:00 0.75 DRILL P PROD1 Slow 80' backream. 09:00 -11:15 2.25 DRILL N DFAL PROD1 RIH. Ratty thru shale wlo motor work. Tag 10387' and got 350 psi MW, but no drill off. Clean PU. PUH, take a run at it 70 FPM. Took wt 10245', 10285', 10375' then tagged 10387' with motor work. Can't drill off. Pump larger pill -- 30 bbls Flo-Pro with 1.5 drums lubetex. No change. Been messing around for 4 hours wlo progress. Pull to check tools. 11:15-14:15 3.00 DRILL N DFAL PROD1 POOH. 14:15 - 14:45 0.50 DRILL N DFAL PROD1 LD BHA. Motor backed-off at bottom of stator adaptor. 14:45 - 17:00 2.25 DRILL N DFAL PROD1 Determine specs of fish. Gather-up fishing tools. Static losses about 45 BPH. 17:00 - 18:00 1.00 DRILL N DFAL PROD1 MU fishing BHA: 3-5/8" overshot and extensions to swallow rotor and grab 2-7/8" motor body below. 18:00 - 18:45 0.75 DRILL P PROD1 Crew change safety meeting. 18:45 - 23:00 4.25 DRILL N DFAL PROD1 Stab coil. RIH with fishing BHA. Clean thru window. RIH 2.5/1.8. Sat down 9650', skip thru to 9665'. Unable to work past. Try different speeds and rates without success. Overpulls to 15K over. POOH. 23:00 - 00:00 1.00 DRILL N DFAL PROD1 LD fishing BHA. FP coil. 2/21/2002 00:00 - 01 :00 1.00 DRILL P PROD1 Standback inj. Set TWC. 01 :00 - 01 :30 0.50 DRILL P PROD1 RU for BOP test. 01 :30 - 07:30 6.00 DRILL P PROD1 Perform weekly BOP test. Witnessed by AOGCC's Jeff Jones. Printed: 31412002 10:29:40 AM ~ ..~. Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: S-17 S-17C REENTER+COMPLETE Start: 2/12/2002 Rig Release: Rig Number: Spud Date: 8/6/1984 End: 3/2/2002 2/21/2002 01 :30 - 07:30 6.00 DRILL P PROD1 Signticant time locating leaks. 4 hrs just to ND and replace leaking kill line valves. Rebuild #4 valve on choke manifold. H2S detector in pits not working. Replace sensor. Twelve hours of Code 8 (rig repair) recognized. 07:30 - 19:30 12.00 DRILL N SFAL PROD1 NPT for BOP test. 19:30 - 20:30 1.00 DRILL P PROD1 RU BPV lubricator. Pull TWC. No pressure 20:30 - 21 :00 0.50 DRILL P PROD1 Fill hole -- 22 bbls. 21 :00 - 21 :30 0.50 DRILL P PROD1 Safety meeting: PU inj. 21 :30 - 23:30 2.00 DRILL N RREP PROD1 Repair main rig door for bringing inj to floor. 23:30 - 00:00 0.50 DRILL P PROD1 Displace methanol from coil. 2/22/2002 00:00 - 01 :30 1.50 STKOH N DFAL PROD1 MU drilling BHA #8 for OH sidetrack (1.83 deg motor; M09 bit). 01:30 - 03:15 1.75 STKOH N DFAL PROD1 RIH. 03:15 - 04:00 0.75 STKOH N DFAL PROD1 Log tie-in. Correct depth (-2'). 04:00 - 04:45 0.75 STKOH N DFAL PROD1 RIH. Slight weight loss in 10000' vicinity, otherwise hole in good shape. 04:45 - 06:00 1.25 STKOH N DFAL PROD1 Orient to 150R 06:00 - 08:45 2.75 STKOH N DFAL PROD1 Trough down 2.7/1.7 two times at 30 FPH from 10100' - 10130'. TF slipped from 140R to 170R during second down pass. 08:45 - 09: 15 0.50 STKOH N DFAL PROD1 Orient around. 09:15-10:30 1.25 STKOH N DFAL PROD1 Trough down 2.6/1.6 one more time at 30 FPH from 10100'- 10130'. TF slipped from 132R to 160R 10:30 -12:15 1.75 STKOH N DFAL PROD1 Start time drilling sequence. TF keeps shifting to 130L. Orient around four times. Can't get TF to settle in low right. 12:15 - 13:30 1.25 STKOH N DFAL PROD1 Time drill 3 FPH 10130' - 10133' with TF at 130L. TF shifted to 90L within the first foot. 13:30 - 15:30 2.00 STKOH N DFAL PROD1 Time drill 6 FPH 10133' - 10137' with TF at 90L. TF shifted to 50L near end. Not an ideal sidetrack, prefer more digging on lowside. Give it a push to see if new hole -- drill to 10142'. Yes, new hole established. 15:30 - 15:45 0.25 DRILL N DFAL PROD1 Orient. TF still not wanting to go low side. 15:45 - 17:45 2.00 DRILL N DFAL PROD1 Drill with 115L F to 10192' at 150 FPH. Lost all returns somewhere in the last 40'. PUH to orient. Stop at 10158' and stuck. Acts like differential; no motor work. SD pumps. Work pipe to 75k. Pulled free. PUH and check returns. No returns at 2.9 BPM. Wiper to 9900'. RIH. Drill with 170L TF at 180 FPH with 150 psi MW. Returns slowly coming back to 2.7/1.0. Drill to 10226' . 17:45 - 18:30 0.75 DRILL N DFAL PROD1 Orient for right turn. 18:30 - 19:15 0.75 DRILL N DFAL PROD1 Drill 200 - 250 FPH with 200 psi MW to 10300'. ROP decreased to about 80 FPH and MW increased to 500 psi last 10'. 2.710.8 19:15 - 23:15 4.00 DRILL N STUC PROD1 Orient lowside to backream junction, then wiper trip to window. Overpull wlo motor work 10165' and stuck (same stuck spot as before). SD pumps. Wait. Work pipe -15k to 80k. No go. Order crude. Pump 20 bbls crude. Pump 5 bbls out, let soak, work pipe -- nothing. Repeat. Bullhead KCI down BS at 3.0 BPM; 1000 psi WHP. Push negative wt and pull to 70k. No movement. SD pumping on backside. Start pumping last 30 bbls crude down coil. Only got 3 bbls in coil when BHA broke free in downward direction with string wt at +6k. 23: 15 - 00:00 0.75 DRILL N DFAL PROD1 RIH to 10200'. Wiper to window. Clean thru stuck area. Printed: 314/2002 10:29:40 AM I~ /-\ Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: S-17 S-17C REENTER+COMPLETE Start: 2/12/2002 Rig Release: Rig Number: Spud Date: 8/6/1984 End: 3/2/2002 2/22/2002 23:15 - 00:00 0.75 DRILL N DFAL PROD1 Returns have improved to 2.9/1.7 (got about 1.0 BPM back). 2/23/2002 00:00 - 00:15 0.25 DRILL N DFAL PROD1 Drill to 10307'. 00:15 - 01:45 1.50 DRILL N DFAL PROD1 Orient to 100R. 10 of 32. 01:45 - 03:15 1.50 DRILL N DFAL PROD1 Drill to 10324'. TF moved to 175L, no stall or increase in MW. PUH. TF moved to 94L. TF chasing it's tail. Orient -- getting anywhere from 30 deg to 120 deg per click. 03:15 - 05:30 2.25 DRILL N DFAL PROD1 POOH for failed orienter. 05:30 - 06:15 0.75 DRILL N DFAL PROD1 SB inj. 06: 15 - 06:45 0.50 DRILL N DFAL PROD1 Crew change safety meeting. 06:45 - 08:30 1.75 DRILL N DFAL PROD1 C/O and test orienter. PU 1.5 deg motor and DS49. 08:30 - 10:15 1.75 DRILL N DFAL PROD1 RIH. 10:15 - 11 :00 0.75 DRILL N DFAL PROD1 Log tie-in. Correct depth (-10'). Then depth bet! MWD and coil unit slipped 6'. 11 :00 - 11 :30 0.50 DRILL N DFAL PROD1 RIH. Sat down with motor work 9880',9985',10006'. Wt bobble wlo MW at 10135'. Tag TD 10338'. 11 :30 - 11 :45 0.25 DRILL N DFAL PROD1 Pump up survey. 11 :45 - 12:30 0.75 DRILL N DFAL PROD1 Orient. 12:30 - 15:00 2.50 DRILL N DFAL PROD1 Drill 2.6/1.4 very slow from the start (remember, ROP fell off at tail end of last run). Acts like that siltstone which we struggled with in the last wellbore. Drill90R to 10360'. Sticky from 10300' to bottom. Decide to drop down out of it instead of punching up thru it. Orient down. Drill 160L to 10380'. 15:00 - 16:00 1.00 DRILL N DFAL PROD1 Orient to low right. Very sticky from 10300' to TD, with and wlo MW. 16:00 - 18:00 2.00 DRILL N STUC PROD1 Stuck in shale off bottom 10356'. Work pipe, pump 20 bbls crude, didn't work, work pipe some more, got free going down, pull slow at 60k - 70k all the way thru the shale. 18:00 - 19:30 1.50 DRILL N DFAL PROD1 Wiper trip to window. RIH. Sat down 9990', but skipped thru. Clean to 10345', then ugly to 10360'. Try to clean-up shale with small bites. 65k - 70k overpulls. 19:30 - 20:30 1.00 DRILL N DFAL PROD1 Nearly stuck 10345' - 10360' a half dozen times, pulls to 80k with and w/o MW -- will not poke our nose back into it. 20:30 - 21 :00 0.50 DRILL N DFAL PROD1 Discuss second open hole sidetrack with area team and cost implications. Will sidetrack at 10050' and stay below siltstone until we know that we have a "completable" well (same strategy and directional plan as first OH sidetrack, but correctly executed this time). 21 :00 - 21 :30 0.50 STKOH N DPRB PROD1 Log tie-in. Correct depth +12'. 21 :30 - 22:00 0.50 STKOH N DPRB PROD1 RIH. Sat down in usual spot at 10000'. Work past. This area has not deteriorated since drilled 6 days ago. 22:00 - 22:30 0.50 STKOH N DPRB PROD1 Orient TF to low right for start of trough. Try 130R 22:30 - 00:00 1.50 STKOH N DPRB PROD1 Trough down twice 30 FPH 10040' - 10060' at 135R TF. 2.6/1.5 2/24/2002 00:00 - 01 :45 1.75 STKOH N DPRB PROD1 Trough down two more times 30 FPH 10040' - 10060' at 135R 2.7/1.6. 01 :45 - 05:00 3.25 STKOH N DPRB PROD1 Time drill 10060' - 10070' at 3FPH. 05:00 - 06:30 1.50 STKOH N DPRB PROD1 Time drill 10070' - 10085' at 10 FPH, stacked out. PUH. 06:30 - 07:00 0.50 STKOH P PROD1 Crew change safety meeting. 07:00 - 07:30 0.50 STKOH N DPRB PROD1 Try drilling. No bite, no pressure change, no wt loss by 10092'. Discuss. Will try one more time milling sequence starting at 1 0050' 07:30 - 11 :00 3.50 STKOH N DPRB PROD1 Time drill 1 0050' - 10056' at 3 FPH, 155R TF, 2.6/1.5. 11 :00 - 16:00 5.00 STKOH N DPRB PROD1 Time drill 10056' -10060' at 5 FPH, 160R TF. New hole Printed: 3/4/2002 10:29:40 AM ~ .~ Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: S-17 S-17C REENTER+COMPLETE Start: 2/12/2002 Rig Release: Rig Number: Spud Date: 8/6/1984 End: 3/2/2002 2/24/2002 11 :00 - 16:00 5.00 STKOH N DPRB PROD1 started. Drill to 10150'. 16:00 - 17:00 1.00 STKOH N DPRB PROD1 Orient. 17:00 - 17:40 0.67 DRILL N DPRB PROD1 Drill100R to 10190'. Losing a little more -- 2.7/1.0 17:40 - 18:15 0.58 DRILL N DPRB PROD1 Wiper to window. Pulled heavy with MW 9980' MD. Continue PUH. Pull heavy 9885', seeing some packing-off. Pop free RIH. PUH. Same result, same depth, no motor work. Ease into it again, stuck, packed-off, can't go down. Small shale in vicinity of CTC, but more likely debris in belly. 18:15 - 23:00 4.75 DRILL N STUC PROD1 Work pipe in downward direction. Pump 10 bbl slick pill. Continue working pipe down. No movement, no returns. Cycle pipe -15k to 70k with and without pumps. Pressure backside to 850 psi (stable at 1.0 BPM), then dump. Continue working pipe down. Pump 15 bbls slickpill followed by 20 bbls crude cown coil. Displace to bit. Work pipe. Nope. Stack to -18k. Pump 20 bbls crude down backside 2.0 BPM; 1100 psi WHP. Pump KCL down coil to heat up. Go back to pumping crude down backside at 500 psi WHP, got some weight back and popped free going down. PUH. Never saw tight spot again. 23:00 - 00:00 1.00 DRILL N DPRB PROD1 PUH to 9200'. BH crude away. 2/25/2002 00:00 - 00:40 0.67 DRILL N DPRB PROD1 Log tie-in. Correct depth (+4'). 00:40 - 01 :30 0.83 DRILL N DPRB PROD1 RIH. 01 :30 - 02:45 1.25 DRILL N DPRB PROD1 Drill to 10245'. Wiper with 10 bbl pill to 10080'. 02:45 - 04:30 1.75 DRILL N DPRB PROD1 Drill to 10300'. Wiper with 10 bbl pill to 10076'. 04:30 - 05:00 0.50 DRILL N DPRB PROD1 Drill to 10350'. 05:00 - 07:30 2.50 DRILL N DPRB PROD1 Wiper to window. Pulled heavy with packoff starting 9895' (in belly) and continuing to 9650'. Generally, start seeing very slight weight increase and it packs-off immediately with no returns; then, RIH and able to reestablish returns. Lots of up and down 9895' - 9650'. 07:30 - 08:00 0.50 DRILL N DPRB PROD1 Drill to 10380'. Back on productive time. 08:00 - 08:30 0.50 DRILL P PROD1 Drill to 10400'. 08:30 - 09:30 1.00 DRILL P PROD1 Wiper to window. The 10220' shale is starting to move on us now. Clean thru belly this time -- no pack-offs, no overpulls. 09:30 - 10:00 0.50 DRILL P PROD1 Orient. 10:00 - 11 :00 1.00 DRILL P PROD1 Drill 2.6/0.9 with 50L TF to 10460'. Orient right. Drill 2.6/1.2 with 70R TF to 10475'. Pumping 5 bbl flo-vis pill every 50 bbls. 11 :00 - 12:00 1.00 DRILL P PROD1 Wiper to window. Overpull1 01 00' wlo MW. Clean the rest of the way. RIH clean. 12:00 - 12:15 0.25 DRILL P PROD1 Orient high left 12:15 - 13:45 1.50 DRILL P PROD1 Drill to 10580'. 13:45 - 14:45 1.00 DRILL P PROD1 Wiper to window 2.6/1.2. Clean. 14:45 - 15:30 0.75 DRILL P PROD1 Orient. Discuss direction of last push. 15:30 - 17:30 2.00 DRILL P PROD1 Drill 100 -150 FPH, good slide, +10k weight to 10645'. Then lost a bunch of ROP, push negative wt. Drill to 10654'. 17:30 - 18:00 0.50 DRILL P PROD1 Should be in or near siltstone (if it's there). Decide to point it straight up and finish well. Orient. 18:00 - 19:00 1.00 DRILL P PROD1 Drill 2.5/1.3 slow, slow, slow, but not sticky -- yet. Drill to 10658'. 19:00 - 20:15 1.25 DRILL P PROD1 Wiper to window. 20:15 - 20:30 0.25 DRILL P PROD1 Start drilling 2.7/1.3 and 2700 FS. Lost 1000 psi CTP and MWD signal. 20:30 - 23:15 2.75 DRILL N DFAL PROD1 Pump Flo-Pro pill. Lay in on bottom. POOH 3.0/1.5 and 2000 psi CTP. Printed: 31412002 10:29:40 AM r---.. ~ Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: S-17 S-17C REENTER+COMPLETE Start: 2/12/2002 Rig Release: Rig Number: Spud Date: 8/6/1984 End: 3/2/2002 2/25/2002 23:15 - 23:30 0.25 DRILL N DFAL PROD1 At 500'. Pre-job meeting. 23:30 - 00:00 0.50 DRILL N DFAL PROD1 OOH. Coil had pulled out of CTC. 2/26/2002 00:00 - 06:00 6.00 FISH N DFAL PROD1 Gather-up fishing tools to spear CTC. 06:00 - 06:30 0.50 FISH N DFAL PROD1 Safety meeting. 06:30 - 07:30 1.00 FISH N DFAL PROD1 MU Baker CTC. Pull and PT. MU fishing BHA: 2.375" spear, circ sub, disconnect, jars, PH6, MHA. 07:30 - 09:40 2.17 FISH N DFAL PROD1 RIH. Generally clean thru OH. Sat down but fell thru 10240' CTM. WT check 10550' = 40k up. RIH and tag fish 10615' CTM (expected at 10600' corrected depth) at 1.3 BPM; 900 psi. Pressure increase to 1200 psi. PUH, and pressure fell off. 09:40 - 11: 15 1.58 FISH N DFAL PROD1 Attempt to get bite with spear with and without pumps and at various RIH speeds. Make use of the down jars, and get some hits down. Thought we had a bite with 2k increase in weight but CTP fell off and we didn't see any depth differences with overpulls and set downs in 10240' shale (if we had the fish, then we should see ratty hole RIH starting at about 10190' -- and we didn't). Continue working spear. 11:15-13:20 2.08 FISH N DFAL PROD1 POOH to check tools. Overpull10030' CTM. Pull to 60k. RIH free. Mix and pump 17 bbl LubtexlFlovis pill to help slip by. Let soak and try again unable to pull beyond 10030'. Spot 20 bbl crude around BHA let soak still unable to move. Pumped down backside with KCL @ 3 bpm 540 psi and pipe came free after pumping 34 bbls. 13:20 - 15:50 2.50 FISH N DFAL PROD1 Continue POH. Review of tight spots: 10345', 10180', 10040'-10030',10011'-9992' 15:50 - 17:15 1.42 FISH N DFAL PROD1 No fish. Spear grapples appear to have engaged CTC fully. (Talk to town and decide to leave fish in hole P/U drilling BHA and cleanout openhole to run liner) UD fishing BHA. 17:15-17:30 0.25 DRILL P PROD1 PJSM discuss with crews the plan foward 17:30 - 23:05 5.58 DRILL N SFAL PROD1 MIU new DS CTC and pull test to 37K failed PT test. MIU another CTC pull and PT okay.Tested orienter and CTC started leaking. MIU 3rd and it also leaked. CT is .040 out. Cut off 28' of pipe but still egged. M/U Baker CTC and PT and pull tested okay. 23:05 - 00:00 0.92 DRILL P PROD1 M/U BHA #11 53.99' 2/27/2002 00:00 - 02:00 2.00 DRILL P PROD1 RIH to 9260'. 02:00 - 02:50 0.83 DRILL P PROD1 Log tie-in -7' correction. 02:50 - 03:05 0.25 DRILL P PROD1 Orient to upper left to go through window 03:05 - 04:05 1.00 DRILL P PROD1 RIH tag at 10265' work through pumping Flo-Vis/Lubetex sweeps. RIH 2.5/0 RIH ok to 10610' (corrected) tag top of fish. 04:05 - 04:50 0.75 DRILL P PROD1 TOH to top of window no problems. Load coil with remainder pill and mix another 35 bbls. 04:50 - 07:30 2.67 DRILL P PROD1 RIH to bottom 2.5/1.5 tagged at 10610'. Lay in 70K+ LSRV flo-vis 1:1 back to window continue TOH paint EOP flag at 6800'. 07:30 - 08: 10 0.67 DRILL P PROD1 UD BHA#11 08:10 - 08:45 0.58 CASE P PROD1 Set back injector. RIU to circulate through coil to well at .5 bpm 08:45 - 09:05 0.33 CASE P PROD1 PJSM reviewing liner P/U procedures. 09:05 - 09:30 0.42 CASE P PROD1 Finish rigging to run liner. 09:30 -17:15 7.75 CASE P PROD1 P/U 2561' of 27/8" x 3 3/16" x 31/2" liner 17:15 - 18:05 0.83 CASE N WAIT PROD1 WO extra jt 3 1/2" 18:05 - 18:20 0.25 CASE P PROD1 Crew change PJSM handling liner. Printed: 31412002 10:29:40 AM r---. ~ Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: S-17 S-17C REENTER+COMPLETE Start: 2/12/2002 Rig Release: Rig Number: Spud Date: 8/6/1984 End: 3/2/2002 2/27/2002 18:20 - 19:20 1.00 CASE P PROD1 P/U remaining liner equipment. Check liner wts. Space out close 31/2" pipe/slip rams. Check setdown and plu confirm good set with rams. 19:20 - 20:00 0.67 CASE P PROD1 P/U injector, change out CTC to Baker 5 pitch 1.5" bore. Pull test and PT -ok. Stab on to well 20:00 - 21 :30 1.50 CASE P PROD1 RIH with liner to bottom 10610'md. No problems. TOL 8048'md 21 :30 - 22:00 0.50 CASE P PROD1 Up wt 50 K. Drop & pump down .625" ball. With ball on seat pressue up to 2400 psi. Confirm release from liner set down with 25K wt of CT. 22:00 - 22:15 0.25 CEMT P PROD1 PJSM w/ cementers and crews covering cement job parameters. 22: 15 - 23:20 1.08 CEMT P PROD1 Batch mix 18 pumpable bbl cement and 35 bbls 2% KCL w/ 2# bio for displacement. 23:20 - 00:00 0.67 CEMT P PROD1 Pump 5 bbls KCL ahead. PT lines to 4000 psi. Follow w/18 bbls cmt wI additives then 35 bbls KCL wI 2# bio then 35 bbls KCL water. 2/28/2002 00:00 - 00:15 0.25 CEMT P PROD1 Finish displ. cement CT wiper bumped at 51.5 bbls engaged and launched LWP at 2400 psi. followed with 18 bbls and landed LWP. Floats held. CIP at 0015 hrs. 00:15 - 02:30 2.25 CEMT P PROD1 With rig pump pressure up to 1000 psi and sting out of liner top. Wash top of liner with remaining 17 bbls bio/KCL left in CT rates 2.6/ <0.5 Continue TOH no returns. (preping 1 1/4" CSH for cleanout run) 02:30 - 03:00 0.50 CEMT P PROD1 UD CTLRT. Hole taking 60 bbllhr 03:00 - 04:15 1 .25 CLEAN P COMP Finish preparing 1 1/4" CSH work string to pick-up 04:15 - 04:30 0.25 CLEAN P COMP PJSM review handling CSH procedures 04:30 - 08:00 3.50 CLEAN P COMP P/U BHA #12 and 1 1/4" CSH tubing 08:00 - 10:30 2.50 CLEAN P COMP Stand back tubing. Called AOGCC recieved extension for BOP testing from Chuck Sheve 10:30 - 12:00 1.50 CLEAN P COMP P/U KB packer BHA. Stab on to well. 12:00 - 14:15 2.25 CLEAN P COMP RIH to top of liner 8048'. 14:15 -16:10 1.92 CLEAN P COMP Spaceout packer. Drop and pump down .625" ball over gooseneck, let fall on seat. Pressure up and set packer element. Fill backside with 28 bbls (est fluid level 2875') test backside to 2400 psi- ok. Bleed-off annulus, pump down coil shear at 3830 psi. Sting out of packer, wellbore pressure equalized to 1700 psi and held. 16:10 - 18:10 2.00 CLEAN P COMP TOH lid packer running tools. 18:10 - 19:00 0.83 CLEAN P COMP PT liner to 2500 psi for 30 min. No leak-off. Same time set back injector and rig to circulate. Also PJSM with crew change out prep to plu cleanout BHA. Bleed off annulus. 19:00 - 22:30 3.50 CLEAN P COMP P/U BHA #14 22:30 - 23:15 0.75 CLEAN P COMP P/U injector. TIH to 3200'. 23:15 - 00:00 0.75 CLEAN N HMAN COMP TOH realized we installed wrong dissconnect. 3/1/2002 00:00 - 00:30 0.50 CLEAN N HMAN COMP Change out disconnect 00:30 - 01 :30 1.00 CLEAN P COMP TIH at about 4000' notice hole taking fluid at +1- 40 bph rate continue through KB packer to 8400'. 01 :30 - 02:30 1.00 CLEAN N DPRB COMP POH above KB packer. Check for surface leaks -none. Shut-in and PT annulus unable to build pressure. IA and OA remain constant. Confer with town. Decide to go ahead with cleanout. 02:30 - 03: 15 0.75 CLEAN P COMP RIH tagged TOC at 10149'. 03:15 - 04:00 0.75 CLEAN P COMP Drill cement to landing collar at 10249'. 1.4 I 0.6 Sweep w/ 5 bbl 2# bio-zan Printed: 3/4/2002 10:29:40 AM ,~ ".-....., Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: S-17 S-17C REENTER+COMPLETE Start: 2/12/2002 Rig Release: Rig Number: Spud Date: 8/6/1984 End: 3/2/2002 3/1/2002 04:00 - 20:20 16.33 CLEAN P COMP Milling on CT & LW darts, landing collar 1.4 I 0.8. Adding bio-zan to entire circulating system avg 2#/bbl. Milled through shoe track at 1300 hrs. Milling cement from 10260' at 20-30'/hr making short wiper trips 1.5/1.1 to 10380'. Rate picking up to 50-60'/hr avg. drilled to 10474'. Lost pump. Notifed AOGCC of pending work schedule. BOP testing continued wavied by Chuck Sheve. 20:20 - 20:55 0.58 CLEAN N RREP COMP Nabors pump down. Oiler pump not working. Swap to Dowell pump. TIH 20:55 - 00:00 3.08 CLEAN P COMP Continue drilling cement from 10474' at 60+'/hr 1.31 0.9 to 10609' PSTD. Nabors pump back on line. Last 15' no cement. 3/2/2002 00:00 - 01 :45 1.75 CLEAN P COMP TOH to top of SHA #14 01 :45 - 03:00 1.25 CLEAN P COMP Set back injector and FP same. 03:00 - 06:30 3.50 CLEAN P COMP UD SHA #14. Well taking fluid @ +1- 20bph. Circulate across top of well 06:30 - 07:00 0.50 DEMOB P COMP Crew change. PJSM review outline of todays work. 07:00 - 08:15 1.25 DEMOB P COMP P/U injector bullhead 32 bbls methanol to well. 08: 15 - 09:00 0.75 DEMOS P COMP Set SPV thru lubricator. 09:00 - 09:30 0.50 DEMOS P COMP RIU N2 equipment. 09:30 - 10:15 0.75 DEMOS P COMP Slowdown reel wI N2 to Tiger Tank. 10:15 -16:00 5.75 DEMOS P COMP Rig down CTU #4 same time clean mud tanks, NID SOPE. DS CTU#4 released at 1800 hrs 3-2-3002 (back to Deadhorse) Nabors 3S released at 1600 hrs 3-2-2002 Printed: 31412002 10:29:40 AM ) ) ANADRILL SCHLUMBERGER Survey report 24-Feb-2002 10:23:12 Page 1 of 2 Client BP Exploration (Alaska) Inc. Field. Prudhoe Bay Well. . S-17c PB-1 Spud date... ............. 15-Feb-02 API number 50-029-21148-03 Last survey date...... ... 21-Feb-02 Engineer. . M. Brown Total accepted surveys... 20 MD of first survey....... 9442.00 ft RIG...... . Nabors 3S / Dowell # 4 MD of last survey..... ... 10392.00 ft STATE: . . . . Alaska ----- Survey calculation methods------------- ----- Geomagnetic data - - ------------------ Method for positions.. ...: Minimum curvature Magnetic model...........: BGGM version 2000 Method for DLS..... ... ...: Mason & Taylor Magnetic date............: 14-Feb-2002 Magnetic field strength..: 1149.74 HCNT ----- Depth reference ----------------------- Magnetic dec (+E/W -) . . . . . : 26.27 degrees Permanent datum.. ... .....: Mean Sea Level Magnetic dip.... .........: 80.80 degrees Depth reference..... .....: GR Tie-In @ 9260 ft GL above permanent. ......: 0.00 ft ----- MWD survey Reference Criteria --------- KB above permanent. ......: -50000.00 ft Reference G. .............: 1002.68 mGal DF above permanent... ....: -50000.00 ft Reference H........ ......: 1149.74 HCNT Reference Dip......... ...: 80.80 degrees ----- Vertical section origin---------------- Tolerance of G...........: (+/-) 2.50 mGal Latitude (+N/ S -) . . . . . . . . . : 0.00 ft Tolerance of H...........: (+/-) 6.00 RCNT Departure (+E/W-)........ : 0.00 ft Tolerance of Dip. ........: (+/-) 0.45 degrees ----- Platform reference point--------------- ----- Corrections --------------------------- Latitude (+N/S-).........: -999.25 ft Magnetic dec (+E/W-)..... : 26.27 degrees Departure (+E/W-)........ : -999.25 ft Grid convergence (+E/W-) .: 0.00 degrees Total az corr (+E/W-)....: 26.27 degrees Azimuth from rotary table to target 284.93 degrees (Total az corr magnetic dec - grid conv) Sag applied (Y/N : No degree: 0.00 c) 2002 Anadrill IDEAL ID6 lC 10 ) ANADRILL SCHLUMBERGER Survey Report 24-Feb-2002 10:23:12 Page 2 of 2 --- -------- ------ ------- -- ----- ------------- ------ ----- ------ -------- ------ ------- ------------- ------ ------ Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ tool qual - (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type type -- -------- ------ ------ ----- ------ ------- ---------------- ----- ----- ---- ----- ----- -------- ------ ------ ------ ------- ---------------- 1 9442.00 39.10 335.50 0.00 8654.74 2389.94 -170.98 -2519.03 2524.83 266.12 0.00 TIP 2 9450.00 39.12 334.90 8.00 8660.95 2393.17 -166.40 -2521.15 2526.63 266.22 4.74 MWD - 3 9523.39 45.49 304.45 73.39 8715.77 2433.18 -130.21 -2552.91 2556.23 267.08 29.01 SP 6-axis 4 9553.29 51. 03 297.02 29.90 8735.69 2454.63 -118.88 -2572.09 2574.84 267.35 26.19 SP - 5 9598.17 52.38 288.57 44.88 8763.53 2489.47 -105.28 -2604.52 2606.65 267.69 15.07 SP - 6 9665.99 50.55 284.42 67.82 8805.79 2542.48 -90.20 -2655.36 2656.89 268.05 5.49 SP 7 9703.07 54.58 287.85 37.08 8828.33 2571.90 -82.00 -2683.62 2684.87 268.25 13 .12 SP - 8 9738.09 57.50 290.85 35.02 8847.89 2600.85 -72.37 -2711. 01 2711.98 268.47 10.95 SP 9 9773.74 62.90 287.52 35.65 8865.61 2631.68 -62.23 -2740.22 2740.93 268.70 17.18 SP 10 9788.19 66.55 286.52 14.45 8871.78 2644.74 -58.41 -2752.72 2753.33 268.78 26.02 SP - 11 9823.22 75.00 288.20 35.03 8883.30 2677.75 -48.54 -2784.25 2784.67 269.00 24.54 SP - 12 9858.09 82.70 285.62 34.87 8890.04 2711.92 -38.61 -2816.96 2817.23 269.21 23.23 SP - 13 9907.31 93.67 286.52 49.22 8891.60 2761.03 -25.01 -2864.16 2864.27 269.50 22.36 MWD - 14 10051.88 102.70 294.25 144.57 8871. 00 2903.23 24.63 -2998.09 2998.20 270.47 8.18 SP - 15 10118.98 102.86 301. 86 67.10 8856.14 2966.91 55.38 -3055.80 3056.30 271.04 11.08 MWD - 16 10186.57 101.56 308.89 67.59 8841. 83 3028.76 93.60 -3109.62 3111.03 271.72 10.35 MWD - 17 10221.34 99.75 313.30 34.77 8835.40 3059.42 116.06 -3135.36 3137.51 272.12 13 .48 SP - 18 10265.41 97.05 317.10 44.07 8828.96 3097.06 146.98 -3166.07 3169.48 272.66 10.52 SP - 19 10326.20 95.60 322.02 60.79 8822.26 3146.76 192.95 -3205.25 3211.05 273.45 8.39 SP - 20 10392.00 95.60 322.02 65.80 8815.84 3199.00 244.57 -3245.55 3254.75 274.31 0.00 Projected ) ANADRILL SCHLUMBERGER of 2 1 Page 52 18 24-Feb-2002 15 Survey report Inc Alaska BP Exploration Prudhoe Bay Client Field ft ft 15-Feb-02 24-Feb-02 00 00 19 9442 10392 Spud date Last survey date Total accepted surveys MD of first survey MD of last survey S-17c PB-2 50-029-21148-03 M Brown Dowell # 4 1 number Engineer Well API ) data Geomagnetic model 3S Survey calculation methods for positions Minimum curvature for DLS Mason & Taylor Nabors Alaska RIG STATE 2000 BGGM version 14-Feb-2002 Magnetic Magnetic Magnetic Magnetic Magnetic Method Method HCNT degrees degrees 74 27 80 1149 26 80 strength +E/w- ) date field mGal HCNT degrees mGal HCNT degrees Criteria 1002.68 1149.74 80.80 2.50 6.00 0.45 +1- +1- +1- MWD survey Reference Reference G. .... : Reference H. . . . . Reference Dip... Tolerance of G.. Tolerance of H.. Tolerance of Dip dec dip ft Mean Sea Level GR Tie-In @ 9260 0.00 ft -50000.00 ft -50000.00 ft Depth reference Permanent datum Depth reference GL above permanent KB above permanent DF above permanent Vertical section origin---------------- Latitude (+N/S-) 0.00 ft Departure (+E/w- 0.00 ft ) 26.27 degrees 0.00 degrees 26.27 degrees - grid conv) degree: 0.00 Corrections Magnetic dec (+E/w-). Grid convergence (+E/w- Total corr (+E/W-) Platform reference point Latitude (+N/S-) : -999.25 ft Departure (+E/w- : -999.25 ft dec No magnetic corr (Y/N) az (Total az Sag applied degrees 284.93 from rotary table to target Azimuth ID6 lC 10 Anadrill IDEAL c)2002 ) ANADRILL SCHLUMBERGER Survey Report 24-Feb-2002 15:18:52 Page 2 of 2 --- -------- ------ ------- -- ----- ------------- ------ ----- -------- ------ ------- ------------- ------ Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ tool qual - (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type type -- -------- ------ ------ ----- ------ -------. --------------- ----- ----- ---- ----- ---- -------- ------ ------ ------ -------. --------------- 1 9442.00 39.10 335.50 0.00 8654.74 2389.94 -170.98 -2519.03 2524.83 266.12 0.00 TIP - 2 9450.00 39.12 334.90 8.00 8660.95 2393.17 -166.40 -2521.15 2526.63 266.22 4.74 MWD - 3 9523.39 45.49 304.45 73.39 8715.77 2433.18 -130.21 -2552.91 2556.23 267.08 29.01 SP 6-axis 4 9553.29 51. 03 297.02 29.90 8735.69 2454.63 -118.88 -2572.09 2574.84 267.35 26.19 SP - 5 9598.17 52.38 288.57 44.88 8763.53 2489.47 -105.28 -2604.52 2606.65 267.69 15.07 SP - 6 9665.99 50.55 284.42 67.82 8805.79 2542.48 -90.20 -2655.36 2656.89 268.05 5.49 SP - 7 9703.07 54.58 287.85 37.08 8828.33 2571.90 -82.00 -2683.62 2684.87 268.25 13 .12 SP - 8 9738.09 57.50 290.85 35.02 8847.89 2600.85 -72.37 -2711.01 2711. 98 268.47 10.95 SP - 9 9773.74 62.90 287.52 35.65 8865.61 2631.68 -62.23 -2740.22 2740.93 268.70 17.18 SP - 10 9788.19 66.55 286.52 14.45 8871.78 2644.74 -58.41 -2752.72 2753.33 268.78 26.02 SP 11 9823.22 75.00 288.20 35.03 8883.30 2677.75 -48.54 -2784.25 2784.67 269.00 24.54 SP - 12 9858.09 82.70 285.62 34.87 8890.04 2711.92 -38.61 -2816.96 2817.23 269.21 23.23 SP - 13 9907.31 93.67 286.52 49.22 8891. 60 2761.03 -25.01 -2864.16 2864.27 269.50 22.36 MWD - 14 10051.88 102.70 294.25 144.57 8871.00 2903.23 24.63 -2998.09 2998.20 270.47 8.18 SP - 15 10159.20 100.73 298.10 107.32 8849.21 3006.27 70.98 -3092.38 3093.19 271.31 3.97 MWD - 16 10219.40 97.95 278.91 60.20 8839.35 3065.26 89.70 -3148.44 3149.72 271. 63 31.78 MWD - 17 10270.55 95.38 295.22 51. 15 8833.37 3115.85 104.57 -3196.83 3198.54 271.87 32.06 SP 18 10310.97 93.85 300.22 40.42 8830.12 3155.12 123.31 -3232.48 3234.83 272.18 12.90 SP - 19 10392.00 93.85 300.22 81. 03 8824.68 3233.11 164.00 -3302.34 3306.41 272.84 0.00 Projected ) ANADRILL SCRLUMBERGER 1 of 2 Page 27-Feb-2002 05:22:45 Survey report Inc (Alaska BP Exploration Prudhoe Bay Client Field ) ft ft 15-Feb-02 27-Feb-02 26 9442.00 10659.00 Spud date Last survey date Total accepted surveys MD of first survey MD of last survey S-17C 50-029-21148-03 M Brown / Well .. API number Engineer 2000 RCNT degrees degrees mGal RCNT degrees mGal RCNT degrees BGGM version 14-Feb-2002 74 27 80 1149 26 80 Criteria 1002.68 1149.74 80.80 2.50 6.00 0.45 +/- +/- +/- Geomagnetic data Magnetic model........ Magnetic date......... Magnetic field strength Magnetic dec (+E/W-) Magnetic dip MWD survey Reference Reference G...... : Reference R...... Reference Dip. . . . Tolerance of G.. . Tolerance of H. . . Tolerance of Dip. Dowell # 4 ft Survey calculation methods for positions : Minimum curvature for DLS : Mason & Taylor GROUND LEVEL GR Tie-In @ 9260 0.00 ft -50000.00 ft -50000.00 ft 3S Nabors Alaska Depth reference Permanent datum... Depth reference. . . GL above permanent KB above permanent DF above permanent COUNTY STATE: Method Method ft ft 00 00 Vertical section origin---- Latitude (+N/S-). : 0 Departure (+E/W-) : 0 ) 26.27 degrees 0.00 degrees 26.27 degrees - grid conv) degree: 0.00 dec No magnetic Corrections Magnetic dec (+EjW-).. Grid convergence (+EjW- Total az corr (+EjW-) (Total az corr Sag applied (Y/N Platform reference point--------------- Latitude (+N/S-) -999.25 ft Departure (+E/W- -999.25 ft degrees 284.93 table to target from rot¡:¡.ry Azimuth ID6 IC 10 Anadrill IDEAL c)2002 ANADRILL SCHLUMBERGER Survey Report 27-Feb-2002 05:22:45 Page 2 of 2 --- -------- ------ ------- -- ----- ------------- --------------- ----- -------- ------ ------- ------------- --------------- Seg Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg / tool gual - (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type type --- -------- ------ ------- ----- ------ ------- --------------- ------ "------ ---- ---- -------- ------ ------- ------ ------- --------------- ------ .------ ----- 1 9442.00 39.10 335.50 0.00 8654.74 2389.94 -170.98 -2519.03 2524.83 266.12 0.00 TIP - 2 9450.00 39.12 334.90 8.00 8660.95 2393.17 -166.40 -2521.15 2526.63 266.22 4.74 MWD 3 9523.39 45.49 304.45 73.39 8715.77 2433.18 -130.21 -2552.91 2556.23 267.08 29.01 SP 6-axis 4 9553.29 51. 03 297.02 29.90 8735.69 2454.63 -118.88 -2572.09 2574.84 267.35 26.19 SP - 5 9598.17 52.38 288.57 44.88 8763.53 2489.47 -105.28 -2604.52 2606.65 267.69 15.07 SP 6 9665.99 50.55 284.42 67.82 8805.79 2542.48 -90.20 -2655.36 2656.89 268.05 5.49 SP ) 7 9703.07 54.58 287.85 37.08 8828.33 2571.90 -82.00 -2683.62 2684.87 268.25 13 .12 SP 8 9738.09 57.50 290.85 35.02 8847.89 2600.85 -72.37 -2711.01 2711.98 268.47 10.95 SP 9 9773.74 62.90 287.52 35.65 8865.61 2631.68 -62.23 -2740.22 2740.93 268.70 17.18 SP 10 9788.19 66.55 286.52 14.45 8871. 78 2644.74 -58.41 -2752.72 2753.33 268.78 26.02 SP 11 9823.22 75.00 288.20 35.03 8883.30 2677.75 -48.54 -2784.25 2784.67 269.00 24.54 SP 12 9858.09 82.70 285.62 34.87 8890.04 2711. 92 -38.61 -2816.96 2817.23 269.21 23.23 SP 13 9907.31 93.67 286.52 49.22 8891. 60 2761. 03 -25.01 -2864.16 2864.27 269.50 22.36 MWD 14 10051. 88 102.70 294.25 144.57 8871.00 2903.23 24.63 -2998.09 2998.20 270.47 8.18 SP 15 10119.31 94.20 299.70 67.43 8861.10 2968.37 54.87 -3057.45 3057.94 271.03 14.92 SP 16 10162.16 90.75 301.46 42.85 8859.25 3009.58 76.64 -3094.30 3095.25 271. 42 9.05 MWD 17 10198.36 88.95 306.37 36.20 8859.34 3043.80 96.83 -3124.33 3125.83 271.78 14.45 SP 18 10242.11 92.10 311.56 43.75 8858.94 3083.74 124.33 -3158.33 3160.77 272.25 13.88 MWD 19 10272.47 94.65 314.42 30.36 8857.15 3110.48 144.99 -3180.49 3183.80 272.61 12.61 SP 20 10322.72 94.93 319.60 50.25 8852.95 3152.89 181.60 -3214.63 3219.75 273.23 10.29 SP 21 10360.37 94.15 323.91 37.65 8849.97 3182.93 211. 07 -3237.85 3244.73 273.73 11. 60 MWD ) 22 10413.20 91.33 325.37 52.83 8847.45 3223.52 254.10 -3268.39 3278.25 274.45 6.03 SP 23 10477.87 93.40 321.69 64.67 8844.79 3274.00 306.05 -3306.78 3320.92 275.29 6.53 MWD 24 10525.50 93.12 319.82 47.63 8842.08 3312.56 342.88 -3336.87 3354.44 275.87 3.96 MWD 25 10590.25 99.47 317.88 64.75 8834.98 3365.93 391. 32 -3379.19 3401.77 276.61 10.25 MWD 26 10659.00 99.47 317.88 68.75 8823.67 3422.84 441.62 -3424.67 3453.03 277.35 0.00 Projected c)2002 Anadrill IDEAL ID6 1C 10 Date Delivered Alaska Oil & Gas Cons.Commision Anchorage BP Exploration (Alaska) Inc, Petrotectnical Data Center 900 E, Benson Blvd, Anchorage, Alaska 99508 LR2- r;~/.1p t" ~¡ 1)002 <I... L~ L RECEIVED ( r- o () \ ro o '1J PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY EACH TO: S-17C PB2 S-17C PB2 S-17C PB2 S-17C PB1 S-17C PB1 S-17C PB1 S-17C S-17C S-17C 22115 22115 22115 22114 22114 22114 22116 22116 22116 PP ARC DATA MD VISION RESISTIVITY TVD VISION RESISTIVITY PP ARC DATA MD VISION RESISTIVITY TVD VISION RESISTIVITY PP ARC DATA MD VISION RESISTIVITY TVD VISION RESISTIVITY t Well Job # Log Description Date Field: Prudhoe Bay Color Blueline Sepia Prints CD - 1 1 1 - 1 1 1 1 1 - 1 1 1 - 1 1 - 1 1 - - - - - - - - - - - Schlumberger GeoQuest 3940 Arctic Blvd, Suite 300 Anchorage, AK 99503-57 ATTN: Sherrie Received 02123/02 02123/02 02123/02 02120/02 02120/02 02120/02 02125/02 02125/02 02125/02 Company: State of Alaska Alaska Oil & Gas Cons Aftn: Lisa Weepie 333 West 7th Ave, Suite Anchorage, AK 99501 Anchorage, AK 99503-57 ATTN: Sherñe Alaska Data & Consulting Services 3940 Arctic Blvd, Suite 300 00 Comm Sc~lunI~ePgel' NO. 907 03/20/02 I"""' ,-.., MWD/LWD Log Product Delivery Customer BP Exploration (Alaska) Inc. Dispatched To: Lisa Weepie Well No S-17c PB-2 Date Dispatched: 1-Mar-02 Installation/Rig Nabors 3S / SLB CTU # 4 Dispatched By: Nate Rose Data No Of Prints No of Flo ies SUNeys 2 dca- 07 o .!~ 2002 Alaska Oil & Cons. James H. Johnson Received BP Exploration (Alaska) Inc. Petrotechnical Data Center (LR2-1) 900 E. Benson Blvd. Anchorage, Alaska 99508 Fax: 907-564-4005 e-mail address:johnsojh@bp.com LWD Log Delivery V1.1, Dec '97 ~. ~ MWD/LWD Log Product Delivery Customer BP Exploration (Alaska) Inc. Dispatched To: Lisa Wee pie Well No S-17c PB-1 Date Dispatched: 1-Mar-02 Installation/Rig Nabors 3S / SLB CTU # 4 Dispatched By: Nate Rose Data No Of Prints No of Flo ies Surveys 2 ac:a- OÎ RECE VED t'!AR 0 l~ 2002 Oil & Gas An . Commission Received By: James H. Johnson BP Exploration (Alaska) Inc. Petrotechnical Data Center (LR2-1) 900 E. Benson Blvd. Anchorage, Alaska 99508 Fax: 907-564-4005 e-mail address:johnsojh@bp.com LWD Log Delivery V1.1, Dec '97 ~. ."'" MWD/LWD Log Product Delivery Customer BP Exploration (Alaska) Inc. Dispatched To: Lisa Weepie Well No S-17c Date Dispatched: 1-Mar-02 Installation/Rig Nabors 3S / SLB CTU # 4 Dispatched By: Nate Rose Data No Of Prints No of Flo ¡es Surveys 2 dDd- ., RECEI ED t·1AP. 0 /~ 2002 a Oil & GasCon . Commission An Received By: James H. Johnson BP Exploration (Alaska) Inc. Petrotechnical Data Center (LR2-1) 900 E. Benson Blvd. Anchorage, Alaska 99508 Fax: 907-564-4005 e-mail address:johnsojh@bp.com LWD Log Delivery V1.1, Dec '97 --, ~ ~1f~1fŒ ffi)~ !A\~!A\~[{!A\ ALASKA. OIL AND GAS CONSERVATION COMMISSION TONY KNOWLES, GOVERNOR 333 W. 7'" AVENUE. SUITE 100 ANCHORAGE. ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Ted Stagg CT Drilling Engineer BP Exploration (Alaska), Inc. PO Box 196612 Anchorage AK 99519 Re: Prudhoe Bay Unit S-17C BP Exploration (Alaska), Inc. Permit No: 202-007 Sur Loc: 2204' SNL, 712' EWL, Sec. 35, T12N, R12E, UM Btmhole Loc. 2190' SNL, 2353' WEL, Sec. 34, T12N, R12E, UM Dear Mr. Stagg: 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. Annular disposal has not been requested as part of the Permit to Drill application for Prudhoe Bay Unit S-17C. Blowout prevention equipment (BOPE) must be tested in accordance with 20 MC 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 at 659-3607. Sincerely, /::;;;i2:í!;:;1~ Chair . BY ORDER OF THE COMMISSION DATED this 23rd day of January, 2002 jjc/Enclosures cc: Department ofFish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. / ,___ STATE OF ALASKA /____ ALASKA ... AND GAS CONSERVATION COMf\,. 310N PERMIT TO DRILL 20 AAC 25.005 J-M I{- t- 1/'Yi/ò'þ áÆzf 1ft" .... III? 1a. Type of work [J Drill 181 Redrill 11 b. Type of well o Exploratory o Stratigraphic Test II Development Oil ORe-Entry o Deepen o Service 0 Development Gas ¡:¡ Single zonej;þ 0 Multiple Zone 2, Name of Operator 5. Datum Elevation (DF or KB) 10, Field and Pool BP Exploration (Alaska) Inc. KBE = 67.48' Prudhoe Bay Field I Prudhoe 3. Address 6. Property Designation Bay Pool P,O, Box 196612, Anchorage, Alaska 99519-6612 ~~ ADL 028258"tP 4. Location of well at surface 7. Unit or Property Name 11. Type Bond (See 20 AAC 25.025) 2204' SNL, 712' EWL, SEC. 35, T12N, R12E, UM Prudhoe Bay Unit At top of productive interval 8. Well Number 2178' SNL, 1888' WEL, SEC. 34, T12N, R12E, UM S-17C Number 2S100302630-277 At total depth 9. Approximate spud date 2190' SNL, 2353' WEL, SEC. 34, T12N, R12E, UM 02/01/02 Amount $200,000.00 12. Distance to nearest property line 113. Distance to nearest well 14. Number of acres in property 15. Proposed depth (MD and TVD) ADL 028257, 2353' MD No Close Approach 2560 11295' MD I 8930' TVDss 16. To be completed for deviated wells 980 17. Anticipated pressure {see 20 MC 25,035 (e) (2)} Kick Off Depth 9450' MD Maximum Hole Angle Maximum surface 2244 psig, At total depth (TVD) 8800' I 3300 psig 18. Casing Program Specifications Setting Depth Quantitv of CAment C ize TID Bottom Hole Casino Weioht Grade CouDlino Lenath MD TVD MD TVD (jnclude staae data) 3-3/4" 3-1/2" x 8.8# I 6.2# L-80 ST-L/TCII 3250' 8045' 7562' 11295' 8930' 135 cu ft Class 'G' . 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured 10445 feet Plugs (measured) Set Open Hole Whipstock at 9475' (wI Cut 2-7/8" Liner true vertical 8882 feet below, S-17AL1, 9525'-10196'), 08/01 Effective depth: measured 10445 feet Junk (measured) true vertical 8882 feet Casing Length Size Cemented MD TVD Structural Conductor 110' 20" x 30" 8 cu yds Concrete 110' 110' Surface 2634' 13-3/8" 4000 cu ft Arcticset III & II 2663' 2663' Intermediate 8274' 9-5/8" 2214' cu ft Class 'G' 8300' 7761' Production Liner 1405' 7" 450 cu ft Class 'G' RECEIVË[)' - 9450' 7530' - 8728' Perforation depth: measured NIA JAN 0 9 2002 true vertical NIA Alaska Oil & Gas Cons. Commission Anchorage 20. Attachments 181 Filing Fee o Property Plat 181 BOP Sketch o Diverter Sketch 181 Drilling Program 181 Drilling Fluid Program 0 Time vs Depth Plot o Refraction Analysis o Seabed Report 0 20 AAC 25.050 Requirements Cooœ~E~mærNam~Numœ~ Ted Stagg, 564-4694 Prepared By Name/Number: Terrie Hubble, 564-4628 21, I hereby certify that the fOregOi~ and correct to the be~t of my kn~~'edge . Signed Ted Stagg i!i" -Þ Title CT Drilling Engineer Date J-? .,..e:?3-.- è:""g" ,~,,,/" '" 'ice'~" ~ ~'''''''~ Permit Number API Number ~PPJ v .\ te. í'1 See cover lett,er 2D :2 - 60/ 50- 50-029-21148-03 ' !T~tR\~e)J rJ---. for other reaUlrements Conditions of Approval: Samples Required DYes B1Jo Mud Log ffièquired 0 Yes ~NO Hydrogen Sulfide Measures a:<1es 0 No Directional Survey Required Wes 0 No Required Working Pressure for BOPE o 2K 03K 04K 05K 010K 0 15K '~3.5K psi for CTU otherOriginal Signed By by order of ' I ADD roved Bv Cammy Oechsli Commissioner the commission Date \J ;-;ç'1 h~ Form 10-401 Rev. 12-01-85 S ~bmit In Tri licate ORIGINAL p ,--. ,~ BPX S-17c Sidetrack Summary of Operations: Operations on S-17b were shut down on August 17, 2001 due to mechanical difficulties. This well will be re- entered and drilled to a new target located approx. 500 ft from the S-17b target. S-17b will become an abandoned open hole. Phase 1: Confirm integrity. Pump cement to isolate S-17b open hole. Planned for Jan. 21, 2002 · Pressure test tree, wing and master valves · Integrity test IA. · Drift well with dummy whipstock. · Use service coil to lay in and downsqueeze approx. 20 bbls 17 ppg cement to isolate the S-17b open hole and provide a kick off plug for S-17c. The window milled for S-17b will be salvaged and used for S-17c. Phase 2: Drill and Complete S-17c sidetrack: Planned for Feb. 1,2002 Drilling coil will be used to dress off cement just outside the existing window, kick off and drill 3 %" hole to the new S-17c BHL. The sidetrack will be completed with a fully cemented liner. Mud Program: · Phase 1: Seawater · Phase 2: Seawater and Flo-Pro (8.6 - 8.7 ppg) Disposal: · No annular injection on this well. · All drilling and completion fluids and all other Class II wastes will go to Grind & Inject. · All Class I wastes will go to Pad 3 for disposal. Casing Program: · 3 Y2", 8.8#, L-80, ST-L x 3 3/16",6,2#, L-80, TCII x 27/8",6.2#, L-80, ST-L, solid liner will be cemented from TD to approx. 8045' MD (7562' ss). This liner will be cemented with approx. 24 bbls of 15.8ppg class G cement to place TOC approx. 300 ft above the window. Well Control: · BOP diagram is attached, · Pipe rams, blind rams and the CT pack off will be pressure tested to 300 psi and to 3500 psi. · The annular preventer will be tested to 400 psi and 2200 psi. Directional · See attached directional plan · Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. Logging · An MWD Gamma Ray + Resistivity log will be run over the open hole section. Hazards H2S was measured at 30 ppm on May 20, 2001. Reservoir Pressure Res. press. is estimated to be 3300 psi at 8800ss. Max. surface pressure with gas (0,12 psi/ft) to surface is 2244 psi. TREE = WI3...LHEAD = AcrUt'-. TOR = KB. ELEV = BF. ELEV = KOP- Max Angle = Datum MD = DatumTVD - 4-1/16" CIW IIfcEVOY BAKER 67.5' 38.83' 3100' 93 @ 9757 9560' 8800' SS 13-3/8" CSG, 72#, L-80, ID = 12.347" ;---.. ~ 8-178 SAFETY NOTe:;: 4-1/2" a-IROM: lBG & 7' CI-ROME LNR WI3...L > 70 DEG @ 9633' Af\D > 90 DEG @ 9727'. . AN ALA-IA OÆNHOLE WHIPSTOCK WAS PREMATURELY SET@ 7733' DURING ClD SIDErRACK OPS ON 08/17101. Minimum ID = 3.75" @ 9450' OPENHOLE SDTRK WINDOW TOPOF BKR llEBACK SLV, ID = 7.5" 9-518" X 7" BAKER Llt-£R HANGER, ID = 6276" 4-1/2" TOO, 12.6#, 13CR, 0.0152 bpf, ID = 3.958" 8083' 19-518" CSG, 47#, L-80, ID= 8.681" H 8300' PERFORATION SUMMA. RY REF LOG: MND 10/11/91 & RADUSLOG 07/26/95 ANGLEA TTOP ÆRF: 68 @ 9620' 188 @ 9916' i'bte: Refer to A"oduction DB for historical rf data SIZE SPF INTERV AL Opn/Sqz ()6. TE S-17A 9620 - 9635 9641 - 9647 9650 - 9701 9705 - 9709 9711 - 9720 3-3/8" 3-3/8" 3-3/8" 3-3/8" 3-3/8" 1-9/16" 4 1-9/16" 4 1-9116" 4 6 6 6 6 6 5-17AL1 SDTRK 9916 - 9936 10030 - 10050 10170-10190 7" LNR 26#, NT80S,13CR, 0.0383 bpf, ID = 6.276" DATE 08/20/84 10/19/91 07/29/95 03/15/01 07107101 RBI BY HF PAB JAM SIS- M) RN/tlh COI\IMENTS ORIGINAL COMPLETON CTD SDETRACK COM'L. 2ND ClD SIDEr RACK FINAL CORRECTONS o o o o o 10120/91 10120/91 10120/91 10120/91 10120/91 o o o 08¡Q7/95 08¡Q7/95 08¡Q7/95 9981' 10060' ()6. TE 07/12m 08l02m 08l18m 08l29m 09l24m RBI BY RN/tih JKBITP CI-VKAK DDNiKK MOJiKK . 2111' 4-112" CAMOO SSSV NlP,ID - 3.813" ST MD TVD DEV TYÆ VLV L TCH POR )t\ TE 5 3063 2993 9 OTIS DV RA 0 07l19m 4 5255 4974 29 OTIS DV RA 0 07l19¡Q1 3 7182 6688 24 OTIS DV RA 0 07l19m 2 7895 7339 27 OTIS DV RA 0 07l19m 1 7961 7398 28 OTIS DV RA 0 7/19/2001 4-112" PA Rl<ER SWS NIP, ID = 3.813" 9-518" X 4-1/2" OTIS HVT PKR, 3.880" 4-1/2" PA Rl<ER SWS NIFPLE, ID = 3.813" 4-1/2" PARI<ER SWN NIP, MLLEÐ TO 3.800" 8084' 8078' 9-518" CSG MILLOUT WltlVON 8300' - 8380' (SECllON MLL ) NOTE: ffi&SIDETRAO< WELL BORE NOT SHOWN BELOW 9-518" CSG SEcrlON WINDOW. 7" LNR MLLOUT WIf\DON 9450' - 9456' (Whipstock @ 9445') 2-7/8" LNRS11JB FROM S-17AL1 3-3/4" OPEN HOLETD ( S-17B) COI\IMENTS CORRECllONS CI-EM CUT A TTE~ ClD SIDETRACK Pl1..L WHPSTOO< WS DEP1H OORREcrlON FRUDHOE BA Y UI\IT WI3...L: S-17B ÆRMrr No: 201-145 API i'b: 50-029-21148-02 2204' SNL & 712' EWL, Sec. 35, T12N, T12E BP EXploration (Alaska) TREE = 4" crvv Wa.LHEAD= McEVOY ~"~~~,~,~,~~~ ACTUA TOR= BAKER =~=,~~~~.~.=~"~~~ KB. a.EV = 67.5' BF:ma.Bt =~ 38.83' h,·~~,'.w.w,~,w,'=m,'~"~,=..,m'.'m~~'=m=~wm,m KOP = 2700 u""_.·.".'m.u.'u'.·,·~""",.u~u,·^_··, Max Angle = 93 @ 9757' '~m~=,"~=m=Nm=^=N Datum MD = 10104 -"m"w""~w=m"N..mmmmNuumNmmmmu Datum TVD= 8800' SS r-. ~\ S-17C PROPOSED CTD SIDETRACK . 2111' -j4-1I2" CAMCO SSSV NIP, ID = 3.813" 113-3/8" CSG, 72#, L-80, ID = 12.347" I 2663' ST MD TVD 5 3062 2993 4 5254 4974 3 7181 6688 2 7895 7339 1 7961 7398 GAS LIFT MANDRELS DEV TYÆ VLV LATCH SIZE DATE 9 OTIS RA 29 OTIS RA 24 OTIS RA 27 OTIS RA 28 OTIS RA 2nd Milled Window off Mech Whipstock H 9450' .9456'1 7989' --j4-1/2" PARKERSWS NIPPLE, ID= 3.813" 8002' --j OTIS RA TCH LATCH I 8002' --j 9-5/8" OTIS HVT PKR, ID = 3.880" 1 1 TOP OF 7" 13CR LNR I 8052' 8071' -j4-1/2" X NIPPLE, ID = 3.813" I -14-1/2" XN NIPPLE, Milled out, ID = 3.800" 14-112" 1BG, 12.6#, 13CR, 0.0152 bpf, ID = 3.958" 8083' -j4-1/2" W/LEG 1 H a.MD LOGGED 10/19/91 33/16" X 27/8" XO @ 9505 1 9445' I TOP OF WHIPSTOCK ÆRFORA TION SUMMARY REF LOG: Radius Log 7/26/1995 ANGLEATTOPÆRF: 88 @ 9916' Note: Refer to Production DB for historical perf data SIZE SPF INTERVAL Opn/Sqz DA TE 1-9/16" 4 9916 - 9936 0 08/05/95 1-9/16" 4 10030 - 10050 0 08/05/95 1-9/16" 4 10170 - 10190 0 08/05/95 3-3/4" OH 9475' H Open Hole Whipstock I 12-7/8" LNR, 6.16#, ST-L, .00579 bpf, ID=2.441" H 10196'1 17" LNR 26#, NT80S,13CR, 0.0383 bpf, 10 = 6.276" 1 DATE 08/20/84 10/19/91 07/29/95 03/15/01 07/07/01 REV BY HF PAB JAM SIS-MD RNItlh COMMENTS ORIGINAL COMPLETION CTD SIDETRACK COMPL. 2ND CTD SIDETRACK FINAL CORRECTIONS DATE 07/18/01 REV BY pcr COMMENTS S-17B Proposed Sidetrack PRUDHOE BAY UNIT Wa.L: S-17B Proposed ÆRMIT No: 95-048 API No: 50-029-21148-01 Sec. 35,T12N, T12E BP Exploration (Alaska) r--. .-..\ B.. .... ~TEQ ObP BP Amoco Baker Hughes INTEQ Planning Report Prudhoe Bay North Slope UNITED STATES Map System:US State Plane Coordinate System 1927 Goo Datum: NAD27 (Clarke 1866) Sys Datum: Mean Sea Level ¡Site: PB S Pad I TR-12-12 I UNITED STATES: North Slope I Site Position: Northing: 5980854.54 ft . From: Map Easting: 617919.92 ft I Position Uncertainty: 0.00 ft ~roun~Level:~~_~.__ 0.00__f!. . .____..__...._. . ~.__.~~-------~~-_.__.__.~--_._-------. I VVeU: S-17 I I VVell Position: +N/-S -1590.67 ft Northing: 5979279.00 ft I +E/-VV 940.24 ft Easting: 618885.00 ft i Position Uncertainty: 0.00 ft L____~.~________~._~______________~~_.___". Map Zone: Coordinate System: Model: Alaska, Zone 4 Well Centre BGGM2001 Field: i I -.J - I 70 21 7.358 N J 149 2 4.863 W ---- í-w-;iip~th~-- ~~i~~1~I~~------------------ ~~~~: ~:;::~ S-1~~50.00 ft I I Current Datum: 33 : 174/24/1995 00:00 Height 67.48 ft Above System Datum: Mean Sea Level I Magnetic Data: 1/7/2002 Declination: 26.30 deg I I Field Strength: 57486 nT Mag Dip Angle: 80.80 deg ! Vertical Section: Depth From (TVD) +N/-S +E/-VV Direction I l_-=-~-~.~~~~==~=~~-j~9.o..~-~=.....-~===~=·~=?~O-~==~~~~==~==--'27£~~ _-=---=-==---=-=_____J I-PI~~~---------PI~;;_#4-----·--·---·----------~--·-~------------- - -o;ï; Composed:---- 1/7/2002 I l Principal: ~::tical to Lamar's Plan #4 _______. ._____3~;~~;~___~_ ~rom: Definitive Path J Latitude: Longitude: North Reference: Grid Convergence: 70 21 23.002 N 149 2 32.343 W True 0.90 deg Slot Name: 17 Latitude: Longitude: Targets Polygon4.1 0.00 -199.71 -2498.66 5979039.69 616390.03 70 21 5.390 N 149 317.890 W ·Polygon 1 0.00 -199.71 -2498.66 5979039.69 616390.03 70 21 5.390 N 149 3 17.890 W -Polygon 2 0.00 -124.75 -2812.55 5979109.65 616075.02 70 21 6.126 N 149 3 27.064 W -Polygon 3 0.00 -76.21 -3036.83 5979154.62 615850.01 70 21 6.602 N 149 3 33.620 W -Polygon 4 0.00 421.40 -3514.09 5979644.56 615364.96 70 21 11.494 N 149 3 47.576 W -Polygon 5 0.00 378.37 -3639.80 5979599.54 615239.96 70 21 11.070 N 149 3 51.249 W -Polygon 6 0.00 -29.92 -4071.31 5979184.49 614815.02 70 21 7.053 N 149 4 3.855 W -Polygon 7 0.00 242.19 -4202.06 5979454.47 614679.98 70 21 9.728 N 149 4 7.681 W -Polygon 8 0.00 504.00 -3677.83 5979724.54 615199.94 70 21 12.306 N 149 3 52.363 W -Polygon 9 0.00 576.48 -3516.65 5979799.56 615359.94 70 21 13.019 N 149 3 47.653 W -Polygon 10 0.00 174.25 -3062.89 5979404.62 615819.98 70 21 9.065 N 149 3 34.385 W -Polygon 11 0.00 126.89 -2913.61 5979359.64 615969.98 70 21 8.600 N 149 3 30.021 W ·Polygon 12 0.00 130.28 -2493.46 5979369.69 616389.99 70 21 8.635 N 149 3 17.741 W Annotation 9442.01 8654.75 TIP 9450.00 8660.95 KOP 9460.00 8668.63 1 9640.00 8802.13 2 9892.06 8874.31 3 9942.06 8867.37 4 10092.06 8847.11 5 10372.06 8813.75 6 10543.92 8805.04 7 ~ ~ ..- ..... tNTE.Q ObP BP Amoco Baker Hughes INTEQ Planning Report Annotation 10943.92 8851.73 8 1295.00 8930.21 TO Plan Section Information 9442.01 39.10 335.50 8654.75 -170.19 -2518.14 0.00 0.00 0.00 0.00 9450.00 39.12 335.35 8660.95 -165.61 -2520.24 1.21 0.25 -1.88 281.88 9460.00 40.55 333.17 8668.63 -159.84 -2523.02 20.00 14.35 -21.75 315.00 9640.00 47.59 281.33 8802.13 -92.33 -2617.71 20.00 3.91 -28.80 261.00 9892.06 98.00 281.33 8874.31 -46.53 -2846.26 20.00 20.00 0.00 0.00 9942.06 97.94 274.26 8867.37 -39.81 -2895.29 14.00 -0.12 -14.14 270.00 10092.06 97.41 295.45 8847.11 -1.91 -3038.12 14.00 -0.35 14.12 90.00 10372.06 95.74 334.88 8813.75 191.48 -3230.16 14.00 -0.60 14.08 90.00 10543.92 90.00 311.48 8805.04 327.82 -3332.33 14.00 -3.34 -13.62 257.00 10943.92 77.61 256.40 8851.73 421.99 -3701.95 14.00 -3.10 -13.77 255.00 11295.00 78.19 206.06 8930.21 214.45 -3960.11 14.00 0.16 -14.34 265.00 KOP 1 MWD MWD 9525.00 40.25 313.06 8718.34 -126.50 -2548.00 5979112.10 616339.53 20.00 2537.44 270.45 MWD 9550.00 41.06 305.49 8737.32 -116.21 -2560.60 5979122.19 616326.78 20.00 2550.57 276.38 MWD 9575.00 42.34 298.22 8755.99 -107.46 -2574.71 5979130.72 616312.53 20.00 2565.14 282.13 MWD 9600.00 44.06 291.36 8774.22 -100.31 -2590.24 5979137.62 616296.90 20.00 2581.03 287.56 MWD 9625.00 46.16 284.95 8791.88 -94.81 -2607.06 5979142.85 616279.99 20.00 2598.12 292.57 MWD 9640.00 47.59 281.33 8802.13 -92.33 -2617.71 5979145.16 616269.30 20.02 2608.89 297.12 2 9650.00 49.59 281.33 8808.75 -90.85 -2625.07 5979146.52 616261.92 19.98 2616.32 0.04 MWD 9675.00 54.59 281.33 8824.10 -86.98 -2644.40 5979150.08 616242.53 20.00 2635.83 0.00 MWD 9700.00 59.59 281.33 8837.68 -82.86 -2664.97 5979153.88 616221.90 20.00 2656.60 0.00 MWD 9725.00 64.59 281.33 8849.38 -78.52 -2686.63 5979157.87 616200.18 20.00 2678.45 0.00 MWD 9750.00 69.59 281.33 8859.11 -73.99 -2709.20 5979162.04 616177.54 20.00 2701.24 0.00 MWD 9775.00 74.59 281.33 8866.80 -69.32 -2732.51 5979166.34 616154.16 20.00 2724.77 0.00 MWD 9800.00 79.59 281.33 8872.38 -64.54 -2756.40 5979170.75 616130.20 20.00 2748.88 0.00 MWD 9825.00 84.59 281.33 8875.82 -59.67 -2780.67 5979175.22 616105.86 20.00 2773.38 0.00 MWD 9850.00 89.59 281.33 8877.09 -54.77 -2805.14 5979179.74 616081.31 20.00 2798.08 0.00 MWD 9875.00 94.59 281.33 8876.18 -49.86 -2829.63 5979184.26 616056.75 20.00 2822.80 0.00 MWD 9892.06 98.00 281.33 8874.31 -46.53 -2846.26 5979187.32 616040.07 20.00 2839.58 359.97 3 9900.00 98.00 280.21 8873.21 -45.06 -2853.98 5979188.67 616032.33 13.97 2847.37 270.00 MWD 9925.00 97.97 276.68 8869.73 -41.42 -2878.47 5979191.92 616007.79 14.00 2872.02 269.84 MWD 9942.06 97.94 274.26 8867.37 -39.81 -2895.29 5979193.26 615990.95 14.02 2888.90 269.35 4 9950.00 97.94 275.39 8866.27 -39.15 -2903.12 5979193.80 615983.11 14.04 2896.76 90.00 MWD 9975.00 97.91 278.92 8862.83 -36.07 -2927.68 5979196.49 615958.50 14.00 2921.45 90.15 MWD 10000.00 97.86 282.45 8859.39 -31.48 -2952.01 5979200.69 615934.10 14.00 2946.00 90.64 MWD 10025.00 97.78 285.98 8855.99 -25.40 -2976.02 5979206.39 615910.01 14.00 2970.29 91.13 MWD 10050.00 97.66 289.51 8852.63 -17.85 -2999.61 5979213.57 615886.30 14.00 2994.26 91.61 MWD 10075.00 97.52 293.04 8849.33 -8.85 -3022.70 5979222.19 615863.07 14.00 3017.80 92.08 MWD 10092.06 97.41 295.45 8847.11 -1.91 -3038.12 5979228.89 615847.55 14.01 3033.57 92.54 5 10100.00 97.41 296.57 8846.09 1.54 -3045.20 5979232.23 615840.42 13.98 3040.83 90.02 MWD 10125.00 97.39 300.10 8842.87 13.31 -3067.01 ._.5~!~2_4~'~~__~~~~~~~__....!~~~C>._.~~~.2~0.14 MWD_J ------~---~..._.._----_._----------_._... .--- _._----~----_.-._-_.__.._~---------~_._---_...._---- ObP ",-..... .~ BP Amoco Baker Hughes INTEQ Planning Report ..~ INTE.Q fCompany: BP A;;'oco - Date: 1/8/2002 Time: 11:01:54 .. ... Page: T9 Ii Field: Prudhoe Bay Co..ordinate(NE) Reference: Well: S-17. True North I I Site: PB S Pad Vertical (TVD) Reference: System: Mean Sea Level I Well: $-17 Section (VS) Reference: Well (0.OON.0.00E,273.10Azi) l_~ellpa~ Pla!l#4 ~.~!!~ ___ _~~__. ______~______~urvey ~~cul~tion ~~~od: __ Mini.r!1um Curva_~,!__. Db: Ora~I!._J Survey --i¡:OO .::... ]63-~:766· N~640 - .¡o7n5~~406:ki6-"-ro~-3~~8T~~o ::;JJ 10175.00 97.26 307.16 8836.49 40.76 -3108.28 5979270.43 615776.72 14.00 3105.94 91.05 MWD i 10200.00 97.15 310.68 8833.35 56.33 -3127.57 5979285.70 615757.19 14.00 3126.05 91.50 MWD I 10225.00 97.02 314.21 8830.27 73.07 -3145.88 5979302.15 615738.62 14.00 3145.23 91.94 MWD 10250.00 96.86 317.73 8827.24 90.91 -3163.13 5979319.71 615721.09 14.00 3163.41 92.38 MWD II 10275.00 96.68 321.25 8824.30 109.78 -3179.25 5979338.32 615704.67 14.00 3180.54 92.80 MWD ! 10300.00 10325.00 10350.00 10372.06 10375.00 10400.00 10425.00 10450.00 10475.00 10500.00 10525.00 10543.92 10550.00 10575.00 10600.00 10625.00 10650.00 10675.00 10700.00 10725.00 10750.00 10775.00 10800.00 10825.00 10850.00 10875.00 10900.00 10925.00 10943.92 10950.00 10975.00 11000.00 11025.00 11050.00 11075.00 11100.00 11125.00 11150.00 11175.00 11200.00 11225.00 11250.00 11275.00 11295.00 96.47 96.24 95.98 95.74 95.64 94.84 94.03 93.20 92.35 91.50 90.65 90.00 89.78 88.87 87.97 87.08 86.20 85.33 84.47 83.64 82.83 82.04 81.28 80.55 79.86 79.21 78.59 78.02 77.61 77.54 77.27 77.04 76.87 76.75 76.68 76.65 76.68 76.76 76.89 77.07 77.30 77.57 77.90 78.19 - -~---'- -.-_.-'''--'- 324.77 328.28 331.79 334.88 334.48 331.06 327.65 324.24 320.84 317.44 314.05 311.48 310.66 307.27 303.89 300.50 297.11 293.71 290.30 286.89 283.46 280.02 276.56 273.10 269.62 266.12 262.61 259.08 256.40 255.54 251.96 248.38 244.79 241.20 237.60 234.00 230.41 226.81 223.22 219.63 216.05 212.48 208.91 206.06 8821.43 8818.67 8816.01 8813.75 8813.46 8811.18 8809.24 8807.67 8806.46 8805.61 8805.14 8805.04 8805.05 8805.34 8806.03 8807.11 8808.58 8810.42 8812.65 8815.24 8818.18 8821.48 8825.10 8829.05 8833.31 8837.85 8842.66 8847.73 8851.73 8853.04 8858.49 8864.05 8869.69 8875.40 8881.15 8886.92 8892.68 8898.43 8904.13 8909.76 8915.31 8920.75 8926.06 8930.21 129.62 150.34 171.87 191.48 194.12 216.26 237.70 258.36 278.18 297.08 314.98 327.82 331.81 347.53 362.07 375.38 387.40 398.10 407.43 415.36 421.86 426.90 430.47 432.55 433.13 432.22 429.81 425.92 421.99 420.55 413.72 405.46 395.78 384.73 372.35 358.68 343.77 327.69 310.48 292.22 272.98 252.81 231.81 214.45 -3194.19 -3207.89 -3220.31 -3230.16 -3231.41 -3242.80 -3255.50 -3269.47 -3284.66 -3301.00 -3318.44 -3332.33 -3336.91 -3356.35 -3376.67 -3397.80 -3419.66 -3442.18 -3465.26 -3488.83 -3512.78 -3537.04 -3561.52 -3586.11 -3610.73 -3635.30 -3659.71 -3683.87 -3701.95 -3707.70 -3731.12 -3754.05 -3776.39 -3798.08 -3819.01 -3839.13 -3858.35 -3876.60 -3893.82 -3909.93 -3924.88 -3938.62 -3951.08 -3960.11 5979357.91 5979378.41 5979399.74 5979419.19 5979421.82 5979443.76 5979465.00 5979485.44 5979505.01 5979523.64 5979541.26 5979553.88 5979557.80 5979573.21 5979587.42 5979600.39 5979612.07 5979622.41 5979631.37 5979638.92 5979645.04 5979649.69 5979652.87 5979654.56 5979654.75 5979653.45 5979650.66 5979646.38 5979642.17 5979640.64 5979633.44 5979624.81 5979614.78 5979603.39 5979590.68 5979576.69 5979561.49 5979545.12 5979527.64 5979509.13 5979489.65 5979469.27 5979448.08 5979430.58 --.--- -----~--------------------------------------- --- ,- -".---. 615689.42 615675.39 615662.64 615652.48 615651.19 615639.45 615626.41 615612.11 615596.62 615579.98 615562.26 615548.17 615543.52 615523.84 615503.29 615481.95 615459.90 615437.22 615414.00 615390.31 615366.26 615341.92 615317.40 615292.78 615268.15 615243.61 615219.24 615195.14 615177.13 615171.40 615148.09 615125.31 615103.12 615081.62 615060.88 615040.98 615022.00 615004.01 614987.07 614971.25 614956.61 614943.20 614931.07 614922.32 14.00 14.00 14.00 13.98 13.88 14.00 14.00 14.00 14.00 14.00 14.00 13.99 14.03 14.00 14.00 14.00 14.00 14.00 14.00 14.00 14.00 14.00 14.00 14.00 14.00 14.00 14.00 14.00 14.03 13.92 14.00 14.00 14.00 14.00 14.00 14.00 14.00 14.00 14.00 14.00 14.00 14.00 14.00 14.02 3196.53 3211.33 3224.89 3235.79 3237.17 3249.74 3263.59 3278.66 3294.89 3312.23 3330.62 3345.18 3349.97 3370.23 3391.30 3413.12 3435.61 3458.67 3482.22 3506.18 3530.45 3554.95 3579.58 3604.25 3628.87 3653.35 3677.59 3701.51 3719.35 3725.02 3748.03 377Q.48 3792.27 3813.32 3833.56 3852.91 3871.29 3888.65 3904.91 3920.01 3933.90 3946.52 3957.84 3965.91 93.22 MWD 93.62 MWD 94.01 MWD 94.31 6 256.25 MWD 256.96 MWD 256.65 MWD 256.38 MWD 256.17 MWD 256.00 MWD 255.89 MWD 255.81 7 255.04 MWD 255.00 MWD 255.04 MWD 255.13 MWD 255.28 MWD 255.48 MWD 255.73 MWD 256.03 MWD 256.39 MWD 256.79 MWD 257.25 MWD 257.75 MWD 258.29 MWD 258.89 MWD 259.52 MWD 260.20 MWD 260.93 8 264.95 MWD 265.19 MWD 265.97 MWD 266.76 MWD 267.57 MWD 268.39 MWD 269.22 MWD 270.05 MWD 270.88 MWD 271.71 MWD 272.52 MWD 273.33 MWD 274.13 MWD 274.91 MWD 275.74 TD -~~~~~Q-;~)--'1-l- T -- ~imuths to True ~o-;;~ ---------p,an: PI';;;-;¡ ¡S:-17/Plan#4 s-17ê;-~---' 5-17 (Plan'" S-17 I M Magnetic North' 2630' I &.17 (S-17) .. Created By: Brij Patois Date: 118/2002 ~ S-17 (S-17A) --"----- S-17 (S·17AL1) -----~ $-17 (8-17APB1) Contact Information: : S-17 (S-17BPB1) I' Plan#4 S-17e Plan #4 I I I I ! i I I I i I i I i I I I I I Direct: (907) 267-6613 E-mail: brij.potniS@inteq INTEQ: (907) 267-6600 Magnetic Field Strength: 57 486n T Di¡¡ Angle: 80.80' Date: 11712002 Model: BGGM2001 ----~-~--- ----T-- ... .... - I IINTEQ ObP BP Amoco WELLPATH DETAILS PIIIII#4 $o17C 100282114803 ,.,...tW.IIpId!I: $-17A TltOftMD: MlO.OO RIo' 33117 .t12411..' 00:00 e7A1.. Rtof.Þ.ttlm= V.sectiÞn O.~ ~~= ::::~ ..... 273.10' .... .... REFERENCE INFORMATION Co--ordinate (NÆ) Reference: Wen Centre: 8-17, True North Vertical (TVD) Reference: System: Mean Sea Level Mea~~~~~~ ~:~~~g:~ ~~o~ ;~~,iJ4~~9~·ggWO 67.48 Calculation Method: MinImum Cwvature _"noN DETAILS .., .. "" ... TV. .... ...... DLeø TF.çe v..c: T_øet 1 NG.01 D.10 335.50 8854.75 ·170.1. ·251L14 .... 0.00 2500..' 2 9450.00 '..12 331.35 86110..5 -165061 -252G.24 1.21 :M1." 2503.31 : == ::1: =:~; =~ ·1$8.$4 -2523.02 20.00 315.00 21Soe.47 082.33 -2617.71 20.00 26UIO 2e05.60 5 NU.08 ".00 281.33 8874.31 ...13 _2Uð._ 20.00 0.00 2838..3 · ØG.œ _UM 2T4.H au.7.S1' """1 .'U8L'ItS 14.00 21'0.00 2U6.00 7 10082.08 _7.41 "'.45 8847.11 -1.lIt -3038.12 14.00 80.00 3031." · 10372.08 _5.74 334.88 "'3.75 1111048 -Uso,18 ".00 00.00 3235.72 · 10543." H.OO 311.48 88os.04 327.82 -3332.33 14.00 257.00 3348..8 101OU3." 77..' 2811.40 8851.73 42t." 4701." 14.00 255.00 31'21." 11 1120"00 78.1. 2Oe.De ..:ao.U 214.45 _3CI8O.11 14.00 285.00 39$&.51 .com Hughes Baker ~~ 1000 900 ') ~7Ts:17Ä15B]] ,[§:ra~t·.!1~lllJ L_ª=.'!1~@~1.)J 800 700 600 .... C ~ 50~~ o 400 'I" -- _ 300 + :;: 20~~ 1:: . ;1100 - - . :;:0 .. g -100- CI) -200; ''''' ..."., TARQETOETAlLS TVD ON/oS +EI·W 000 .'GG,71-24!1S6G ,,- S.17CP~ -300 -400- -500-- -600; ANNOTATIONS TVD MD Allltobltioll n. KOP t Z · · · · 7 · TO 8900 ~!ln#4 $-17él . .fI!D I. 8950 9000 9050 -----".--.....-..-,- 2300 2350 2400 2450 2500 2550 2600 2650 2700 2750 2800 2850 2900 2950 3000 3050 3100 3150 3200 3250 3300 3350 3400 3450 3500 3550 3600 3650 3700 3750 3800 3850 3900 3950 4000 4050 4100 4150 4200 Vertical Section at 273.10' [50ft/in] -----1J8I-2-002--1~~00_-AM-~ ) -4400 -4300 -4200 -4100 -4000 -3900 -3800 -3700 -3600 -3500 -3400 -3300 -3200 -3100 -3000 -2900 -2800 -2700 -2600 -2500 -2400 -2300 -2200 -21 00 -2000 -1900 -1800 West(-)/East(+) [100ft/in] [fJ [§,fT fS-17BPB1j1 I I ì =-r-=i l!i 1854.75 H'G..' ......3 1"2.13 .174.11 '''7.17 11147.11 An.n 110..0.. A51.73 ..10.21 8300 8400 8450 'ë .- 8500 ~ 8550 ;. -- - i 8600 Do & 8650 D 8700 1: 8750 CD ~ 8800 ~ 8850 8350 / .,-. / or . {~ 35 CTD BOP Detail Methanol Injection Otis 7" WLA Quick Connect - 7-1/16" ID, 5000 psi working pressure Ram Type Dual Gate BOPE ~ Manual over Hydraulic ~ Flanged Fire Resistant Kelly Hose to Dual Choke Manifold 7-1/16" ID, 5000 psi working pressure Ram Type Dual Gate BO~ ~ Manual over Hydraulic XO spool as necessary Single Manual Master Valve (optional depending on RU) MOJ 5/21/01 - CT Injector Head --- Stuffing Box (Pack-Off), 10,000 psi Working Pressure ~ - 7" Riser Annular BOP (Hydril),7-1/16" ID 5000 psi working pressure I Blind/Shear I I 2 3/8" Pipe/Slip Fire resistant Kelly Hose to Flange by Hammer up 1/4 Turn Valve on DS Hardline to Standpipe manifold I 31/2" Combi Pipe/Slip I I 23/8" x 31/2" VBR seal rams 2 flanged gate valves 7" Annulus 9 5/8" Annulus / I I ./ ~ ~ H 202453 I DATE I 12/07/01 I CHECK N°'1 00202453 DATE INVOICE I CREDIT MEMO DESCRIPTION GROSS 100.00 VENDOR ALASKAO I LA DISCOUNT NET 00 120501 CK120501C PYMT OMMENTS: HANDL NG INST: 100.00 Per it to Drill ee S/H - Terrie Hub Ie X4628 RECE\ E.D JAN Û ~-\{V Alaska Oil & Gas C $, CommisslOr. Anchor TOTAL ~ THE ATTACHED CHECK IS IN PAYMENT FOR ITEMS DESCRIBED ABOVE. 100.00 100.00 BP EXPLORATION, (ALASKA) INC, P.O. BOX 196612 ANCHORAGE, ALASKA 99519-6612 FIRST NATIONAL BANK OF ASHLAND AN AFFIUATE OF NATIONAL CITY BANK CLEVELAND, OHIO No. H 202453 CONSOLIDATED COMMERCIAL ACCOUNT 56-389 4i2 00202453 PAY ONE HUNDRED & 00/100********************~**************** US DOLLAR DATE 12/07/01 I I AMOUNT $100.001 NOT VALID AFTER 120 DAYS To The ORDER Of ALASKA OIL AND GAS CONSERVATION COMMISSION 333 WEST 7TH AVENUE SUITE 100 ANCHORAGE AK 99501 n H__~. _ /J #, \\ I n /1 it ~ I I \,~~~~/~.."· ~-~ III 20 2 ~ 5 31111 I: 0 ~ . 20 31 B 9 5 I: 00 B ~ ~ . 9 III ~, ~ TRANSMIT AL LETTER CHECK LIST CIRCLE APPROPRIATE LEITERlPARAGRAPHS TO BEINCLUDEDINTRANSNDTTALLETTER WELL NAME $¿(·cd -/7C CHECK 1 CHECK WHAT APPLIES STANDARD LETTER ADD-ONS (OPTIONS) "CLUE" DEVELOPMENT MULTI LATERAL The permit is for a new wellbore segment of existing well ----' Permit No, API No. . (If api number last two (2) Production should continue to be reported as a fundion .of digits are between 60-69) the original API number stated above. DEVELOPMENT PILOT HOLE (PH) In accordance with 20 AAC 25.005(t), all records, data and REDRlLL JI logs acquired for the pilot hole must be clearly differentiated in both name (name on permit plus PH) and API number (50 -70/80) from records, data and logs acquired for well (name on permit). EXPLORATION ANNUL~SAL Annular disposal has not been requested. . . INJECTION WELL ANNULAR DISPOSAL Annular Disposal of drilling wastes will not be approved. . . <--) YES INJECTION WELL ANNULAR DISPOSAL Annular Disposal of drilling wastes will not be approved. . . REDRILL THIS WELL DISPOSAL INTO OTHER Please note that an disposal of fluids generated... . ANNULUS <--) YES + SPACING EXCEPTION Enclosed 15 the approved application for permitto,drill the above referenced well. The permit is approved . subJect to full compliance with 20 AAC 25.055. Approval to peñorate and produce is contingent upon issuan'ce of a conservation order approving a spacing exception. (Companv Name) will assume the liability of any protest to the spacing exception that may occur. . Templates are located m drive\jody\templates I' ) c o z o -of ~ :xl - -of m - z -of :x: - en )- :xl m » 7:'D, exp '¿¿ ÿVELL NAME.:5 - /7 (! PROGRAM ~ VL- GEOLAREA Permit fee attached. ..... Lease number appropriate:* . Unique well name and number. . Well located in a defined pool.. . . . . . . , . . . . . . Well located proper distance from drilling unit boundary. Well located proper distance from other wells. . Sufficient acreage available in drilling unit.. . . . . . If deviated, is wellbóre plat included.. . . . . . . . . Operator only affected party.. . . . . . . . . . . . . Operator has appropriate bond in force. . . . . . . . Permit can be issued without conservation order. . . Permit can be issued without administrative approval Can permit be approved before 15-day wait. . COMPANY '" WELL PERMIT CHECKLIST FIELD & POOL_ ADMINISTRA nON 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. sig. 14. Conductor string provided .. . . . . . . .. 15. Surface 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-<:lrill, 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 _ 27. Choke manifold complies w/API RP-53 (M¡ 28. Work will occur without operation shutdowl 29. Is presence of H25 gas probable.. . . . ~ DATE 11/ .L!2:,P y ENGINEERING 30. 31. 32. A~~ DATE 33. ~ 1'/S:~34. 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 (D) will not damage producing formation or impair recovery from a pool; and will not circumvent 20 AAC 25.252 or 20 ENGINEERING: Ó. 37.s-rs.i Y N Y N Y N Y N Y N Permit can be issued w/o hydrogen sulfide measures. Data presented on potential overpressure zones . . . Seismic analysis of shallow gas zones. . . . . . . . Seabed condition survey (If off-shore). . . . . . . . . Contact name/phone for weekly progress reports [explo GEOLOGY DATE APPR Com ments/lnstructions AAC 25.412. COMMISSION 11/01/100) c:\msoffice\wordian\diana\checklist (rev.